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Home My WebLink About212-143Suspended Well Inspection Review Report Reviewed By: P.I. Suprv Comm ________ JBR 09/09/2025 InspectNo:susSTS250724134600 Well Pressures (psi): Date Inspected:7/17/2025 Inspector:Sully Sullivan If Verified, How?Other (specify in comments) Suspension Date:4/3/2019 #319-112 Tubing:0 IA:0 OA: Operator:Hilcorp Alaska, LLC Operator Rep:Jesse Katzenberger Date AOGCC Notified:7/15/2025 Type of Inspection:Subsequent Well Name:SOLDOTNA CK UNIT 44-33 Permit Number:2121430 Wellhead Condition Clean with some rust. Valves turned easily and guages were installed. Flowline is disconnected Surrounding Surface Condition Clean and free of debris Condition of Cellar Clean and dry Comments Location verified by plot map Supervisor Comments Photos (4) attached Suspension Approval:Sundry Location Verified? Offshore? Fluid in Cellar? Wellbore Diagram Avail? Photos Taken? VR Plug(s) Installed? BPV Installed? Tuesday, September 9, 2025 9 9 9 9 9 9 9 9 9 9 2025-0717_Suspend_SCU_44-33_photos_ss Page 1 of 2 Suspended Well Inspection – SCU 44-33 PTD 2121430 AOGCC Inspect # susSTS250724134600 Photos by AOGCC Inspector S. Sullivan 7/17/2025 2025-0717_Suspend_SCU_44-33_photos_ss Page 2 of 2 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Suspended Well Inspection Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,425 feet 9,077 feet true vertical 10,746 feet N/A feet Effective Depth measured 7,037 feet 11,402 feet true vertical 7,036 feet 10,221 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth) 2-7/8" x 2-3/8" 6.5 # / L80 x 4.7# / L-80 11,440' MD 10,242' TVD Packers and SSSV (type, measured and true vertical depth)Tripoint DLH Hyd Ret; N/A 11,402' MD 10,221' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: Daniel Taylorr, Optimization Engineer N/A Sr Pet Eng: 7,500psi Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A dtaylor@hilcorp.com 907-947-8051 Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 0 Size 337' 0 00 0 00 0 8,430psi 7-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 212-143 50-133-20237-01-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA028399/FEDA028997 Swanson River Field / Hemlock Oil Soldotna Creek Unit (SCU) 44-33 Plugs Junk measured Length measured true vertical Production Liner 9,015' 3,658' Casing Structural 8,963' 4-1/2" 9,015' 12,423' 10,746' 337'Conductor Surface Intermediate 20" 10-3/4" 337' 3,408' TVD 3,400psi 3,130psi 6,020psi 3,408' 3,408' Burst Collapse 1,580psi measured Packer p k ft t Fra O s Ot 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 4:00 pm, Jul 30, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.07.28 16:04:53 - 08'00' Noel Nocas (4361) BJM 9/25/25 Updated by DMA 09-17-19 SCHEMATIC Soldotna Creek Unit Well SCU 44-33 PTD: 212-143 API: 50-133-20237-01 PBTD = 7,037 MD / 7,036 TVD TD = 12,425 MD / 10,746 TVD Max dev. 71.85 deg @ 10,180 MD 164.6 Above MSL KB-THF: 20 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20 Conductor - - - Surf 337' 10-3/4" Surf. Csg 40.5 J-55 Buttress 10.05 Surf 3,408' 7-5/8" Intermediate 33.7 N-80 Buttress 6.64" Surf 78' 26.4 N-80 Buttress 6.844 78' 4,621' 29.7 N-80 Buttress 6.75 4,621' 6,111' 33.7 N-80 Buttress 6.64 6,111' 7,117 33.7 P-110 Buttress 6.64" 7,117 9,015' 4-1/2" Prod Lnr 12.6 N-80 H-521 3.958" 8,765 12,423' Window Depths are 9,001(TOP) and 9,015(BOTTOM) 20 10-3/4 A 2 1 B C D 4-1/2 JEWELRY DETAIL No. Depth ID OD Item 1 7,037 CIBP - 04/05/19 2 7,400 CIBP with 271 cement TOC 7,129 04/03/19 3 7,500 2-7/8 tubing cut 04/01/19 A 9,067 1.90 3.750 2-3/8 GLM 8rd, T-1 Latch Mandrel (dummy) B 9,077 - 2.375 2-3/8 CIBP (Set 6/25/16) C 9,627 1.90 3.750 2-3/8 GLM 8rd, T-1 Latch Mandrel (dummy) D 10,572 1.90 3.750 2-3/8 GLM 8rd, T-1 Latch Mandrel (dummy) E 11,392 1.90 3.750 2-3/8 GLM 8rd, T-1 Latch Mandrel (dummy) F 11,402 1.94 3.750 Tri-point DLH Hydraulic Ret. Packer G 11,408 1.875 3.063 X Landing Nipple H 11,440 1.995 3.063 Pump out plug w/ WL re-entry guide 7-5/8 PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes H-6 11,822 11,830 10,444' 10,448' TCP 2-3/4 6spf 60 deg - Isolated H-7/8 11,857' 11,956' 10,462' 10,513' TCP 2-3/4 6spf 60 deg - Isolated H-9 12,013 12,032 10,542' 10,552' TCP 2-3/4 6spf 60 deg - Isolated H-10 12,088' 12,146' 10,581' 10,610' TCP 2-3/4 6spf 60 deg - Isolated 12,212' 12,232' 10,643' 10,653' TCP 2-3/4 6spf 60 deg - Isolated F E 3 G H Communciation with HP Tyonek Water Sand (~9,044 TVD ). Fill in annulus. No comm between annulus and tubing. June 2016 Fill to 9,084 TOC @ 7,129 04/03/19 SCU 44-33 S008N009W S007N009W SCU 12-04 Pad SCU 21-04 Pad SCU 34-33 Pad Sec. 33 Sec. 4 0 250 500 Feet Alaska State Plane Zone 4, NAD27 Legend Suspended Surface Hole Location (SHL) Quarter-Mile Radius around SHL Oil and Gas Unit Boundary Map Date: 4/24/2020 SWANSON RIVER SCU 44-33 Well 876' FNL, 2139' FWL, Sec 4, T7N, R9W, SM, AK Location Map Overview Kenai Homer Tyonek SewardNinilchik Anchorage HAK Petra Well Symbol Oil P&A SHUT-IN Suspended Q SCU 44-33 S008N009W S007N009W SWANSON RIVER FIELD SCU_13-34 SRU_24-33 SCU_13-03 SCU_33-33 SCU_243B-04 SCU_12-03 SCU_12A-03SCU_12-04 SCU_21-04SCU_21A-04 SCU_323-04 SCU_22-04 SCU_22-04PB SCU_332-04 SCU_341-04 SCU_42-04 SCU_43-04 SCU_43A-04 SRU_14A-33 SRU_14-33 SRU_32-33 SRU_32A-33 SCU_34-33 SCU_343-33 SCU_14-34 SCU_44-33 SCU_43A-33 SCU_41A-04 SCU_22B-04 SCU_44B-33 SCU_41B-04PB SCU_21C-04 SCU_31-04_PB1 SCU_31-04 SCU_41B-04 SCU_322C-04 SCU_31B-04 SCU_344-33 SCU_12A-04SCU_ 2 1 A- 0 4 SC U _43A-04S C U _ 4 1-0 5 S C U _1 3 -0 3 SRU_32A-33 S C U _4 4 B -3 3 SCU_332-04SCU_31B-04 S C U _4 4 -3 3 SCU 12-03 Pad SCU 12-04 Pad SCU 14-34 Pad SCU 21-04 Pad SCU 23-03 Pad SCU 23-04 Pad SCU 243-04 Pad SCU 33-33 Pad SCU 34-33 Pad SCU 41-04 Pad SCU 43-04 Pad SCU 43-33 Pad SRU 12-34 Pad SRU 23-33 Pad SRU 32-33 Pad Sec. 34Sec. 33 Sec. 3 Sec. 4 0 490 980 Feet Alaska State Plane Zone 4, NAD27 Legend Quarter-Mile Radius around Well Bore Oil and Gas Unit Boundary Map Date: 6/22/2020 SWANSON RIVER SCU 44-33 Suspended Well Location Map Overview Kenai Homer Tyonek SewardNinilchik Anchorage HAK Petra Well Symbol Other Oil AOil P&A Gas P&A P&A Oil SHUT-IN Suspended 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: Suspended Well Inspection 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 12,425 feet 9,077 feet true vertical 10,746 feet N/A feet Effective Depth measured 7,037 feet 11,402 feet true vertical 7,036 feet 10,221 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)2-7/8" x 2-3/8" 6.5 # / L80 x 4.7# / L-80 11,440' MD 10,242' TVD Packers and SSSV (type, measured and true vertical depth)Tripoint DLH Hyd Ret; N/A 11,402' MD 10,221' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: 8,430psi Burst 6,020psi 337' 3,408'3,130psi Collapse 1,580psi 7,500psi 3,400psi Casing Structural 20" 10-3/4" Length 337' 3,408' 9,015' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 0 Casing Pressure Liner 3,658' 0 10,746' 0 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A 0 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 212-143 50-133-20237-01-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 00 Soldotna Creek Unit (SCU) 44-33 N/A FEDA028399/FEDA028997 Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Swanson River Field / Hemlock OilN/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 7-5/8" 4-1/2" 9,015'8,963' WINJ WAG 0 Water-Bbl MD 337' 3,408' 12,423' 0 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 1:05 pm, Sep 23, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.09.23 08:46:22 -08'00' Taylor Wellman SFD 9/24/2020 gls 1/20/20 DSR-9/24/2020 RBDMS HEW 9/23/2020 Suspended Well Inspection KEN June 2020 Suspended Well Inspection Data Well: SCU 44-33 Surface Location: 876’ FLN, 2127’ FWL, Sec. 4, T7N, R9W, SM Permit to Drill: 212-143 API: 50-133-20237-01-00 AOGCC Inspection Date: 09/04/20 AOGCC Inspector: Lou Laubenstein Hilcorp Representative: Jake Paulk Size Pressure (psi) Tubing 7-5/8” 0 Casing 7-5/8” 0 0 *Note: Wellhead pressures to be recorded monthly at minimum. Other Notes: x Condition of Wellhead: Good x Condition of Surrounding Surface Location: Good x Follow Up Actions needed: None Attachments: x Current Well Schematic x Picture(s) x Plat - 1/4mile radius of wellbore Updated by DMA 09-17-19 SCHEMATIC Soldotna Creek Unit Well SCU 44-33 PTD: 212-143 API: 50-133-20237-01 PBTD = 7,037’ MD / 7,036’ TVD TD = 12,425’ MD / 10,746’ TVD Max dev. 71.85 deg @ 10,180’ MD 164.6’ Above MSL KB-THF: 20’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20” Conductor - - - Surf 337' 10-3/4" Surf. Csg 40.5 J-55 Buttress 10.05 Surf 3,408' 7-5/8" Intermediate 33.7 N-80 Buttress 6.64" Surf 78' 26.4 N-80 Buttress 6.844” 78' 4,621' 29.7 N-80 Buttress 6.75” 4,621' 6,111' 33.7 N-80 Buttress 6.64” 6,111' 7,117’ 33.7 P-110 Buttress 6.64" 7,117 9,015' 4-1/2" Prod Lnr 12.6 N-80 H-521 3.958" 8,765’ 12,423' Window Depths are 9,001’(TOP) and 9,015’(BOTTOM) 20” 10-3/4” A 2 1 B C D 4-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 7,037’ CIBP - 04/05/19 2 7,400’ CIBP with 271’ cement – TOC 7,129’ – 04/03/19 3 7,500’ 2-7/8” tubing cut – 04/01/19 A 9,067’ 1.90” 3.750” 2-3/8” GLM 8rd, T-1 Latch Mandrel (dummy) B 9,077’ - 2.375” 2-3/8” CIBP (Set 6/25/16) C 9,627’ 1.90” 3.750” 2-3/8” GLM 8rd, T-1 Latch Mandrel (dummy) D 10,572’ 1.90” 3.750” 2-3/8” GLM 8rd, T-1 Latch Mandrel (dummy) E 11,392’ 1.90” 3.750” 2-3/8” GLM 8rd, T-1 Latch Mandrel (dummy) F 11,402’ 1.94” 3.750” Tri-point DLH Hydraulic Ret. Packer G 11,408’ 1.875” 3.063” X Landing Nipple H 11,440’ 1.995” 3.063” Pump out plug w/ WL re-entry guide 7-5/8” PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes H-6 11,822 11,830 10,444' 10,448' TCP 2-3/4” 6spf 60 deg - Isolated H-7/8 11,857' 11,956' 10,462' 10,513' TCP 2-3/4” 6spf 60 deg - Isolated H-9 12,013’ 12,032’ 10,542' 10,552' TCP 2-3/4” 6spf 60 deg - Isolated H-10 12,088' 12,146' 10,581' 10,610' TCP 2-3/4” 6spf 60 deg - Isolated 12,212' 12,232' 10,643' 10,653' TCP 2-3/4” 6spf 60 deg - Isolated F E 3 G H Communciation with HP Tyonek Water Sand (~9,044’ TVD ). Fill in annulus. No comm between annulus and tubing. June 2016 Fill to 9,084’ TOC @ 7,129’ 04/03/19 CIBP - 04/05/19 2 7,400’CIBP with 271’ cement – TOC 7,129’ – 04/03/19 ' Y Q ' P QQ P Q' QP ¶ ,Q ' Q , Q Q '¶ Q Q Q ' ¶ Y ' ' ' ' ' ' ' ' ' 0 ' ' ! ! ! ! ! ! ! !! !!! !! !! !!! !!! !!! ! !! ! ! ! ! ! ! ! ! ! ! ! ! ! !! ! ! ! Q ' Y Q ' ' P QQ QQP Q' QP ¶,Q 'Q, QQ' Q '¶P QY Q ' Q ¶ Y ' '' ' ' '' ' ' ' Y Y SCU 44-33 S008N009W S007N009W SWANSON RIVER FIELD SCU_13-34 SRU_24-33 SCU_13-03 SCU_33-33 SCU_243B-04 SCU_12-03 SCU_12A-03SCU_12-04 SCU_21-04SCU_21A-04 SCU_323-04 SCU_22-04 SCU_22-04PB SCU_332-04 SCU_341-04 SCU_42-04 SCU_43-04 SCU_43A-04 SRU_14A-33 SRU_14-33 SRU_32-33 SRU_32A-33 SCU_34-33 SCU_343-33 SCU_14-34 SCU_44-33 SCU_43A-33 SCU_41A-04 SCU_22B-04 SCU_44B-33 SCU_41B-04PB SCU_21C-04 SCU_31-04_PB1 SCU_31-04 SCU_41B-04 SCU_322C-04 SCU_31B-04 SCU_344-33SCU_34-33SCU_12A-04S C U _ 1 2 A - 0 3SCU_ 2 1A - 0 4 SCU_43A-04SCU_33-33S C U _ 4 1 - 0 5 SCU_42-04SCU_41B-04SCU_24-34 SCU_23B-03SCU_13- 0 3SCU_22-04PBSCU_343-33SRU_32A-33 SCU_43A-33SRU_24-33SCU_44B-33 SRU_14 A-33SRU_14-33SCU_332-04SCU_22B-04S C U _ 3 4 4 - 3 3 SCU_31-04_PB1SCU_322C-04SCU_3 1 B - 0 4SCU_13-34SCU_44-33 SCU 12-03 Pad SCU 12-04 Pad SCU 14-34 Pad SCU 21-04 Pad SCU 23-03 Pad SCU 23-04 Pad SCU 243-04 Pad SCU 33-33 Pad SCU 34-33 Pad SCU 41-04 Pad SCU 43-04 Pad SCU 43-33 Pad SRU 12-34 Pad SRU 23-33 Pad SRU 32-33 Pad Sec. 34Sec. 33 Sec. 3 Sec. 4 0 490 980 Feet Alaska State Plane Zone 4, NAD27 ¯ Legend Quarter-Mile Radius around Well Bore Oil and Gas Unit Boundary Map Date: 6/22/2020 SWANSON RIVER SCU 44-33 Suspended Well ! ! ! !! ! Location Map Overview Coo k I nl et Kenai Homer Tyonek SewardNinilchik Anchorage HAK Petra Well Symbol'Other'Oil¶AOil,P&A Gas Q P&A¶P&A OilPSHUT-IN Y Suspended Suspended WellInspection Review ReDOrf !nspectNo: susL0L200908104342 Date Inspected: 9/4/2020 Inspector: Lou Laubenstein ' Type ofInspection Well Name: SULD0TNACKUNIT 44-33 ' Permit Number: 2121430 ' Suspension Approval: Sundry # 319-112* ' Suspension Date: 4/3/2019 ^ Location Verified? W |fVerified, How? GPS - Offshore? U Initial ' Date AOG[ZNotified: 8/25/2020 ' Operator: Hi|corpAlaska, LLC Operator Rep: Daniel Puu|k Wellbore Diagram Avail? Photos Taken? b� Well PresPressuresFh�id is (psi): Tubing: 0 ' n Cellar? W ' |A: 0 ' 8PV|nstoNed7 [] � DA: 0' VR Plug(s) installed'? [� VVeUhead[ondhion The wellhead was ingood condition with nosigns ofleaks orany other issues. Condition ofCellar The cellar was ingood condition, some water was there but itwas clean. - Surrounding Surface Condition The area surrounding the Wellhead was clean nfany debborcontamiation. - Comments 5upemisorCommen1s Friday, October 9'20Z0 M M 1 IV U r. U .b oa X U O b �I O O C1. M M U 'd Q N N 7 � � O O cV O N N bA p ccS c� a DATE 11/19/2019 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W 7th Ave Ste 100 CD: Anchorage, AK 99501 ANALYSIS FIELD -DATA 11/1 '20191:15 PKI Filefo[der 11/14r"20191:15PM Filefclder Please include current contact information if different from above. 217143 3 145 7 RECEIVED NOV 19 2019 AOGCC Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 STATE OF ALASKA ALASKA OIL ANn CTAS CnNISFRvnnnni rrnn SEP 17 2619 WE- OMPLETION OR RECOMPLETION REPORT ta. Well Status: Gas LJ SPLUG ❑ Other ❑ Abandoned ❑ Suspended0 zcanczJos p zonAc z5 .110 ❑ WINJ E] WAGE] WDSPL El No. of Completions: r '�'r r`-'�•= 2. Operator Name: HILCORP ALASKA, LLC 6. Date Comp., Susp., r Abend. : 3. Address: 3800 CENTERPOINT DRIVE, SUITE 1400 7. Date Spudded: ANCHORAGE, AK 99503 10/12/2012 ANMLiQG=- �(-- 1b. Well Class: - Development Q Exploratory EJGINJ Service ❑ Stratigraphic Test ❑ 14. Permit to Drill Number/ Sundry: 212-143 / 319-112 15. API Number: 50-133-20237-01-00 16. Well Name and Number: Soldotna Creek Unit (SCU) 44-33 4a. Location of Well (Governmental Section): Surface: 876' FNL, 2127' FWL, Sec. 4, T7N, R9W, SM Top of Productive Interval: Total Depth: • 112' FSL, 732 FEL, Sec. 33, TSN, R9W, SM 8. Date T -Reached : 10/25/2019 9. Ref Elevations: KB: 183.2 , 17. GL: 164.6 - BF: Field / Pool(s): , + Swanson River/ Hemlock Oil 10. Plug Back Depth MD/TVD: 18. 7,03T MD / 7,036' TVD • Property Designation: FED A028399 & FED A0289997 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 344457.3 y-2460328 Zone- 4 TPI: x- y- Zone- Total Depth: x- 347251.3 y- 2461327.6 Zone- 4 11. Total Depth MDfFVD: 19. 12,290 MD / 10,681 TVD DNR Approval Number: N/A 12. SSSV Depth MD7TVD: 20. N/A Thickness of Permafrost MDlfVD: N/A 5. Directional or Inclination Survey: Yes (attached) No Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: 21. N/A (ft MSL) I Re-drill/Lateral Top Window MD/TVD: N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING HOLE SIZE CEMENTING RECORD FT TOP BOTTOM TOP BOTTOM HOLE PULLED 20" Surf 337 Surf 337 10-3/4" 40.5 J-55 Surf 3,408 Surf 3,408 7-5/8" 33.7,25.4,29.7 N80 P110 Surf 9,018 $Urf 8,967 4-1/2" 12.6 N-80 8,767 12,423 8,734 10,747 6-1/8" 100 bbis 15.6 ppg 24. Open to production or injection? Yes ❑ No F�] If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): Note: The side track on this well has been delayed due to low oil price. Project will be revisited in 2020. SP OEEf6P!- D -�l VERIFIED 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes No 4 Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. - PRODUCTION TEST Date First Production: N/A Method of Operation (Flowing, gas lift, etc.): Date of Test: N/A Hours Tested: Production for Test Period Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Flow Tubing Press. Casing Press: II Calculated 24 -Hour Rate Oil -Bbl: II Gas -MCF: II Water -Bbl: Oil Gravity -API (Corr): Form 10-407 Revised 5/2017 /1r` g"7 CONTINUED ON PAGE 2 Submit ORIGINIAL onlyr� I //•ZG ,CONTINUED ARDMS� OCT 0 9 2019 11 tiF , _ 28. CORE DATA Conventional Core(s): Yes ❑ No 0 Sidewall Cores: Yes ❑ No Q If Yes, list formations and intervals cored (MDfTVD, Fromlro), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑✓ If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval information, including reports, per 20 AAC 25.071. Formation at total depth: 31. List of Attachments: Operations Summary, Schematic Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Bo York Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkratfler I111COr .Coat Authorized 7#,kl®P A,14&rP— Contact Phone: 907-777-8420 Signature: {a+ /jr> ,-,e Date: INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analysesare conducted. Item 1a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY -123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SCU 44-33 401 50-133-20237-01 212-143 1 3/27/19 9/17/19 Daily Operations: 03/27/2019- Wednesday Mobe crew to SRF office, orientate crew members.Layout for rig components, lay felt & liner, spot base beam, rig carrier & accessory eq. Stand & raise mast, install guy lines. 03/28/2019 - Thursday R/U: level derrick, install tq lines, assist elect hook up aux eq, install weight indicator, assemble BOPE on stump, install total safety gas detection system, spot accumulator, install landings & hand rails on carrier, install berming. 03/29/2019 - Friday Check well, install BPV, N/D tree, prep hanger, install blanking sub, N/U BOPE, install flow cross valves, choke & kill line, r/u circulating lines, install PVT system, wire accumulator unit, c/o fittings on same & r/u, spot remote on rig carrier, electrician troubleshoot & repair remote panel, install standpipe manifold. 03/30/2019 - Saturday Work on Air pumps on accumulator, unable to get all running, finished berming, repair remote panel for 2nd accumulator unit, run accumulator lines to other accumulator, function test same good, finish running circulating lines, function test mud pump, plumb & function test test pump, build & install support bracket for standpipe manifold. installed wind walls on rig floor & stairs. m/u 2-7/8" test joint, & install, fill stack & surface eq. shell test 250/3,000, repair leak on test manifold, cont. working on shell test found leak on upper ram door seal, blow down surface eq. shut down for night. 03/31/2019 -Sunday PJSM, warm up rig & rig eq. r/u 2-7/8" testjt, shell test 250/3,000, had failures on IBOP & kill line valve #3, replaced components, tested good, contacted AOGCC inspector to come out to witness test, continued working on r/u punch list. Test BOPE as per Hilcorp & AOGCC expectations, test witnessed By AOGCC inspector Bob Noble, BLM test witness waived by Amanda Eagle on 3-38-19 @5:15AM,. tested w/ 2-7/8" tj, 250/3000 psi, had FP on kill line valve K-1, serviced & tested good. R/D test eq. & blow down / secure well for night. 04/01/2019 - Monday Fire & warm up rig, check annulus bleed off 40 psi pressure, pull blanking sub, & BPV plug, bleed off tubing pressure Pull BPV, well static, r/u a -line test lubricator good, rih w/hole punch, punch holes @ 7,400' WLM, POOH, Circulate hole volume, (had issues with rod wash & lube pump,) Hine rih w/ jet cutter cut tubing @ 7,500', good indication of cut, POOH r/d a -line, r/u handling tools, blow down &secure well for night. 04/02/2019 -Tuesday Fire & warm up rig, verify no pressure build, r/u land ingit, back out I/d pins, Pull hanger free @ 42k, had 2" of free travel then over pull w/o pipe stretch, troubleshoot w/no luck, spread liner & r/u catwalk& pipe rack while discussing options. Pull landing it, install BPV, break stack off at well head, caliper & try to drift spacer spool with no joy, breakoff spacer spool, drift flow cross, n/u BOPE w/o spacer spool, pull BPV, install TWC, test break 250/3,000 good. Pull TWC, m/u landing it, pull hanger t/floor p/u 42k, POOH racking back in derrick f/7,500' t/ 3,0901 I/d GLM assy. SLM while POOH, blow down surface eq, secure well for night. I✓ IV Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SCU 44-33 401 50-133-20237-01 212-143 3/27/19 1 9/17/19 Daily Operations: 04/03/2019- Wednesday PJSM, Fire up and warm rig, POOH F/3,090' stand back 2 7/8" tubing,. R/U a -line, rih w/ 6.125" junk basket/gauge ring t/7,503' WLM, RIH set plug @ P/U CIBP, 7,400'. POOH. R/U Halliburton cast-m,tools on Pollard e -line rih for CBL, f/7,350' t/ 4,000' cont. POOH r/d a -line 04/04/2019 - Thursday PJSM, Flre up and warm rig. Prep for tripping pipe by creating trip tank, utilizing a diaphragm pump to move fluids from the rig choke to the sand trap in the pits. Issue getting diaphragm pump running properly. Unplug pump, trouble shoot, and repair. RIH w/ 2-7/8" tubing on doubles out of the derrick Monitor displacement via trip tank. Tag up on CIBP w TBG @ 7,376.53' -m - d. SOW 38k, set down 8k. L/D 2 joints to 7,315'. Install FOSV and head pin. Cement crew arrive on location shortly aer Sam. PJSM w/ Halliburton Cementers, Cruz Trucking, and AA Rig Crews. R/U cement equipment, PT lines to 3,000psi. Halliburton cementers pump 6.8bbls of 15.8 class G cement, chasing w/ 40bbls of freshwater off of Cruz trucking. Monitor gain/loss while pumping fluids, 1 for 1 returns throughout pump job. POOH from 7,315' to 6,746' to get TBG above cement plug. M/U FOSV, headpin and 2" hose to circulate tubing volume X 3 (120 BBLS). Pump 3 bbls/min @ 600 psi. Rig down circulation lines. POOH laying down singles from 6,746' to 6,114' Monitor hole fill @ trip tank. PUW 40KIbs. Install thread protectors on each joint and load on trailers. Blow down all lines. M/U FOSV and shut in. Close pipe rams and lock same. 04/05/2019 - Friday Fire up & warm up rig, verify no pressure on the TBG and IA. Open well and prepare to POOH. POOH sideways f/ 6,114'md to surface with 2-7/8" work string singles, laying down pipe and loading onto pipe bunks on float trailer. Pressure test plug and casing to 2,500psi f/ 30mins. Good Test. Bleed off pressure, open up well and prep for E -line run. R/U Pollar E -line, M/U gauge ring drift to 6.3" OD. RIH to TOC and tag @ 7,129'md ELMD uncorrected. POOH w/ gauge ring assembly logging gamma signature to utilize for CIBP tie-in. SIMOPS: Rig crew prep for move to SCU 32C-15. Perform triplex pump calibration prior to disposing of working fluids. M/U CIBP assembly and RIH. Issues correlating setting depth with gamma signature. Contact OE and acquire additional log to tie into. Set CIBP @ 7,037'md ELMD corrected to log SCU 44-33 sub a, from RE Dan Taylor. Note: 300lbs weight shift upon setting plug. P/U 50'md and C attempt to RIH, tag up on plug @ 7,037'md. POOH w/ E -line. R/D Pollard E -line, Close and lock blind rams, shut down equipment for the night. 04/06/2019 - Saturday Continue w/ R/D M/O process. Weaver Bros Trucking on location @ 7:00am. Load out float trailers w/ loader and bobtail all applicable loads f/ 44-33 to 32A-15. N/D BOPE and N/U dry hole tree. Release f/ 44-33 @ 12:00pm. 09/17/2019- Tuesday ote: The side track on this well has been delayed due to low oil price. Project will be revisited in 2020. M rorp Ale.ka, Llf. 164.6' Above MSL KB -THF: 20' 20" TOC @ 7,129' 04/03/19 2 SCHEMATIC CASING DFTAII Soldotna Creek Unit Well SCU 44-33 PTD: 212-143 API: 50-133-20237-01 Size Type Wt Grade Conn. ID Top Btm 20" Conductor - - H-7/8 - Surf 337' 10-3/4" Surf, Csg 40.5 1-55 Buttress 10.05 Surf 3,408' 7-5/8" Intermediate 317 N-80 Buttress 6.64" Surf 78' 26.4 N-80 Buttress 6.844" 78' 4,621' 29.7 N-80 Buttress 6.75" 4,621' 6,111' 33.7 N-80 Buttress 6.64" 6,111' 7,117' 33.7 P-110 Buttress 6.64" 7,117 9,015' 4-1/2" Prod Lnr 12.6 N-80 H-521 3.958" 8,765' 12,423' wmaow ueotns are 9.o01'ITOP,l and 9 015'(BOTTOM) Communciation with HP Tyonek Water Sand (-9,044' TVD). Fill in annulus. No comm between annulus and tubing. June 2016 1 7-5/8" I, r A Fill to 9,084' B C D Y E 1 F i G H 4-1/2^ A a PBTD = 7,037' MD / 7,036' TVD TD = 12,425' MD / 10,746' TVD Max dev. 71.85 deg @ 10,180' MD IMAIFI DV naTAII No. Depth ID OD Item 1 7,037' 11,822 11,830 CIBP - 04/05/19 2 7,400' H-7/8 11,857' CIBP with 271' cement -TOC 7,129'-04/03/19 3 7,500' TCP 2-3/4" 6spf 60 deg - Isolated H-9 2-7/8" tubing cut -04/01/19 A 9,067' 1.90" 3.750" 2-3/8" GLM 8rd, T-1 latch Mandrel (dummy) B 9,077' - 2.375" 2-3/8" CIBP (Set 6/25/16) C 9,627' 1.90" 3.750" 2-3/8" GLM 8rd, T-1 Latch Mandrel (dummy) D 10,572' 1.90" 3.750" 2-3/8" GLM 8rd, T-1 Latch Mandrel (dummy) E 11,392' 1.90" 3.750" 2-3/8" GLM 8rd, T-1 Latch Mandrel (dummy) 111,402' 1.94" 3.750" Tri -point DLH Hydraulic Ret. Packer G 11,408' 1.875" 3.063" X Landing Nipple HI 11,444 1.995" 3.063" 1 Pump out plug w/WL re-entry guide PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes H-6 11,822 11,830 10,444' 10,448' TCP 2-3/4" 6spf 60 deg- Isolated H-7/8 11,857' 11,956' 10,462' 10;513' TCP 2-3/4" 6spf 60 deg - Isolated H-9 12,013' 12,032' 10,542' 10,552' TCP 2-3/4" 6spf 60 deg- Isolated H-10 12,088' 12,146' 10,581' 10,610' TCP 2-3/4" 6spf 60 deg- Isolated 12,212' 12,232' 10,643' 10,653' TCP 2-3/4" 6spf 60 deg - Isolated Updated by DMA 09-17-19 _]/}E / § ®> 3:M (} \ %})7>M (D CD _ blEJ£ :/»} :5cu a7}/)2L )/j}\/}jJJ±Nsz ft/\ \ 2)))�a o (y) , 3\ /$: ®- a= ao Baa»~/\ 22t :a, J!9! m> _- C /6 -00� F- z {GJ #±/{// 0 k\\ =*=:z,�00 = e - z2]/±3//a& ±}K v Jf \j } - §/ _:\)$$\\(�c >) ><am Wpz0, //)atC-0 /2)232/ \ z z LU\ u \: /fƒ r/0 6� \2 d/G ƒW §) o co CO \§ CD \\ �§ )\/ )\ 2§ « C) \ _ ZE0 // _]/}E / § ®> 3:M (} \ %})7>M (D CD _ blEJ£ :/»} :5cu a7}/)2L )/j}\/}jJJ±Nsz ft/\ \ 2)))�a o (y) , 3\ /$: ®- a= ao Baa»~/\ 22t :a, J!9! m> _- C /6 -00� F- z {GJ #±/{// 0 k\\ =*=:z,�00 = e - z2]/±3//a& ±}K v Jf \j } - §/ _:$\($\\(�c >) ><am Wpz0, //)atC-0 /2)232/ \ z z LU\ u THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 44-33 Permit to Drill Number: 212-143 Sundry Number: 319-112 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 �.a ogcc.alaska.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, Daniel T. Seamount, Jr. Commissioner DATED this �Zday of March, 2019. jkBDOS-�- MaR 110 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MAR 0 b 200 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1 - n. 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 212-143 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 9 50-133-20237-01-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 1238 a Will planned perforations require a spacing exception? Yes ❑ No � ❑ Soldotna Creek Unit (SCU) 44-33 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA028399/FEDA028997 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): 12,425' 10,746' 9,077' 9,020' 100' 9,077' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 337' 20" 337' 33T Surface 3,408' 10-3/4" 3,408' 3,408' 3,130 psi 1,580 psi Intermediate Production 19,015' 7-5/8" 9,015' 8,963' 6,020 psi 3,400 psi Liner 3,658' 4-1/2" 12,423' 10,746' 8,430 psi 7,500 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 2-718" x 2-3/8" 6.59 x 4.7# / L-80 x L-80 11,440 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Tripoint DLH Hyd Ret; N/A 11,402' MD/ 10,221' TVD; N/A 12. Attachments: Proposal Summary ❑✓ Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic ❑ Development 12 Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: March 20, 2019 OIL ❑ WINJ ❑ WDSPL ❑ Suspended 10 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: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email:tk[amer@hilcorp com Contact Phone: 777-8420 Authorized Signature: Date: 316111 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: i/ �Iq—//Z � Plug Integrity BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: 3 (,V© � 2-<1 IZ c�) 1414-.s°/4 c,Ito �1�� h,,, Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required: u APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Z hlI'll''"` s rz 25 I� 1 RBDMS �Ls"MAR 1 3101 f'( I J' \' ubs Form and For 10-403 Revised 4/2017 Approved application a o "INRP.JI„IhhA thsyr date of approval. qttments in Duplicat '/l3�/,fj �•f� 3�8�/4 R [Iikarp Alaska, LU Well Prognosis Well: SCU 44-33 Date: 3/5/2019 Well Name: SCU 44-33 API Number: 50-133-20237-01 Current Status: SI Gaslift Oil Well Leg: N/A Estimated Start Date: March 20, 2019 Rig: 401 : icy Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 212-143 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Bo York (907) 777-8345 (0) (907) 727-9247 (C) AFE Number: Current Bottom Hole Pressure: — 1,982 psi @ 10,592' TVD (Based on static survey 4/08/14.) Maximum Expected BHP: — 3,950 psi @ 9,044' TVD (Based on data for Tyonek HP Water) Max. Potential Surface Pressure: — 100 psi (Based on 0.437 psi/ft Water gradient) MPSP from Tyonek HP Water Sands: — 100 psi (Based on 0.437 psi/ft gradient) Brief Well Summary The well was sidetracked using the Doyon Arctic Fox drilling rig in October 2012 as SCU 44-33. The William! #405 WO rig completed the well in November 2012 with perforations in the lower Hemlock, H-6 thru H-10. In April, 2016 slickline work was performed on the gas lift valves. While pulling a gas lift valve in the 2-3/8" tubing, solids flowed in the tubing. Fill was bailed over several days down to 2,663'. The purpose of this work/sundry is to de -complete the well for a side track. Notes Regarding Wellbore Condition • Wellbore is deviated with a maximum hole angle of 71.85° @ 10,180' MD. • New completion ran in November 2012. Min ID is 1.875" X -profile at 11,408' MD. • Well could have potential energy from Tyonek HP water sands. • CIBP Set in Tubing @ 9,077'(6/25/2016). /Hilcorp is requesting a variance from Alaska Admin Code 20 AAC 25.112.(c)(1)(E) Setting a mechanical bridge t/ plug no more than 50' above the top perforated interval (BLM -43 CFR 3160 III G (2)(i)) . Discussion: The high pressure water zone in this well bore is at 9,105' MD ( 9,044 TVD). The zone is currently isolated by the production packer below and fill and a CIBP inside of the tubing. Hilcorp believes that it is best to leave the packer in place to mechanically isolate the water zone and then cut and remove the tubing and place a place a CIBP above the interval with cement up across the 4-1/2" liner lap. His will ensure that the high pressure water is confined to its indigenous strata. Pre Sundry Work 1. MIRU Slick -line Unit. RIH W/ a 1.75" dump bailer and Tag the top of the CIBP @ 9077'. POOH 2. RDMO Slickline-line Unit. Rig 401 1. MIRURig401. 2. Notify AOGCC 24hrs and BLM 48hrs in advance of BOP Test. Well Prognosis Well: SCU 44-33 MCorp ` l"k'' Ids Date: 3/5/2019 3. Set BPV. ND Tree. 4. NU BOPE. 5. Test BOPE to 250 psi Low/ 3,000 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 10 -min). Record accumulator pre -charge pressures and chart tests. a. Confirm test pressures perthe Sundry Conditions of Approval b. Perform Test. c. Notify AOGCC 24 hrs in advance of BOP test. d. Test VBR rams on 2-3/8" test joint. e. Email completed 10-424 form to all AOGCC addresses listed on the form within 5 days of BOPE test. 6. L/D BOP test equipment. 7. Pump PW down tubing and up casing to ensure well is dead. Pump minimum of casing volume or bottoms up. 8. Pull tubing hanger free, LD hanger. 9. MIRU E -line Unit. Pressure test lubricator to 3,000 psi high / 250 low. a. PU RIH with free point tool. Determine depth of free pipe. POOH. Ul J b. PU Jet Cutter. RIH and let Cut pipe above free point. POOH. c. Stand Back E -line Unit. 10. RU Pump Truck. Circulate well with Kill Fluid and ensure the well is dead. 11. POOH With Production Tubing laying down GLM's and Standing back tubing in doubles. If Tubing Cut is below 7,000', go to step 12. Otherwise, PU WS, and fishing tools and begin fishing operation to recover pipe to 7,100'(+/-). 12. RU E -line unit. PU RIH W/ CIBP and Set above tubing cut. Pttzc. 13. PU CIBP on tubing. RIH With same to tubing cut. Set same. Un sting from plug, PU 5'. RU 1 fcementers and test lines. Place cement on top of plug up to Kick Off point. PU tubing 500' and fUoP cleanup pipe. POOH WOC. 14. RU Slickline. RIH and Tag TOC. (Need minimum of 75' of cement on top of CIBP) 1 D� 5�e vr6lr 15. RD Slickline. ',s r �� 2 16. RU E -line. RIH W/Cast M cement bond log. Run Bond log from top of cement plug up to 6,000'. POOH W/ E -line. 17. Place dry hole tree on well. 18. RDMO Rig 401. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. BOPE Schematic 4. Well head Drawing 5. Rig 401 Forward Flow 6. Rig Procedure Change Form K corp Alaska, LLC 164.6' Above MSL KB -THF: 20' 20" u I 7-5/8° F.11 to 9,084' 2 3 Communciation with HP Tyonek Water Sand (-9,044' TVD). Fill in annulus. No comm 4 between annulus and tubing. June 2016 10 11 C16P t 12 qD-7� 13 14 15 4-1/2" i [1 PBTD = 12,290' MD/10,681' TVD TD = 12,425' MD/10,746' TVD Max dev. 71.85 deg @ 10,180' MD Downhole Revised: 10/16/14 ACTUAL SCHEMATIC CASING DETAIL Soldotna Creek Unit Well SCU 44-33 Completion Date: 11/29/12 PTD: 212-143 API: 50-133-20237-01 Size Type Wt Grade Conn. ID Top Btm 20" Conductor - - 1.995 - Surf 337' 30-3/4" Surf. Csg 40.5 J-55 Buttress 10.05 Surf 3,408' 7-5/8" Intermediate 33.7 N-80 Buttress 6.64" Surf 78' 26.4 N-80 Buttress 6.844" 78' 4,621- 29.7 N-80 Buttress 6.75" 4,621' 6,111' 33.7 N-80 Buttress 6.64" 6,111' 7,117' 33.7 P-110 Buttress 6.64" 7,117 1 9,015' 4-1/2" Prod Lm- 12.6 N-80 H-521 3.958" 1 8,765' 12,423' Window Depths are 9.001'(TOP) and 9.015'(BOTTOM) TUBING DETAIL 2-7/8" Production 6.5 L-80 8rd EUE 2.441 Surf 9,028' 2-3/8" Production 4.7 L-80 8rd EUE 1.995 9,028' 1 11,440' JEWELRY DETAIL No. Depth ID OD Item 1 19' 2.44" - Tubing Hanger 2 1,912' 2.44" 4.750" 2-7/8" SFO -1 Mandrel 8RD 10 port (dummy) 3 3,484' 2.44" 4.750" 2-7/8" SFO -1 Mandrel 8RD 30 port (dummy) 4 4,800' 2.44" 4.750" 2-7/8" SFO -1 Mandrel 8RD 12 port (dummy) 5 5,991' 2.44" 4.750" 2-7/8" SFO -1 Mandrel 8RD 12 port (dummy) 6 7,019' 2.44" 4.750" 2-7/8" SFO -1 Mandrel 8RD 12 port (dummy) 7 7,795' 2.44" 4.750" 2-7/8" SFO -1 Mandrel 8RD 16 port (dummy) 8 8,508' 2.44" 4.500" 2-7/8" SFO -1 Mandrel 8RD 16 port (orifice) 9 8,709' 2.313" 3.688" X Landing Nipple 30 9,067' 1.90" 3.750" 2-3/8" GLM 8rd, T-1 Latch Mondrel (dummy) 11 9,077' - 2.375" 2-3/8" CIBP(Set 6/25/16) 12 9,627' 1.90" 3.750" 2-3/8" GLM 8rd, T-1 Latch Mandrel (dummy) 13 10,572' 1.90" 3.750" 2-3/8" GLM 8rd, T-1 Latch Mandrel (dummy) 14 11,392' 1.90" 3.750" 2-3/8" GLM 8rd, T-1 Latch Mandrel (dummy) 15 11,402' 1.94" 3.750" Tri -point DLH Hydraulic Ret. Packer 16 11,408' 1.875" 3.063" X Landing Nipple 17 11,440' 1.995" 3.063" Pump out plug w/ WL re-entry guide PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes H-6 11,822 11,830 10,444' 10,448' TCP 2-3/4" 6spf 60 deg H-7/8 11,857' 11,956' 10,462' 10,513' TCP 2-3/4" 6spf 60 deg H-9 12,013' 12,032' 10,542' 10,552' TCP 2-3/4" 6spf 60 deg 12,088' 12,146' 10,581' 10,610' TCP 2-3/4" 6spf 60 deg H-10 12,212' 12,232' 10,643' 10,653' TCP 2-3/4" 6spf 60 deg Updated by JEK 6-27-2016 Soldotna Creek Unit Well SCU 44-33 Date: FUTURE PROPOSED SCHEMATIC PTD: 212-143 Ink., ANA, LLC API: 50-133-20237-01 164.6' Above MSL KB -THF: 20' 20" Communciation with HP Tyonek Water Sand (-A,044' TVD). Fill in annulus. No comm between annulus and tubing. June 2016 o GtGI� a A ,3A1� B II Psi C 0 45 D E F G H 4-1/2" 1O 11 PBTD = 12,290' MD/10,681' TVD TD = 12,425' MD/10,746' TVD Max dev. 71.85 deg @ 10,180' MD Downhole Revised: 10/16/14 CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 20" Conductor - - H-7/8 - Surf 337' 10-3/4" Surf. Csg 40.5 J-55 Buttress 10.05 Surf 3,408' 7-5/8" Intermediate 33.7 N-80 Buttress 6.64" Surf 78' 26.4 N-80 Buttress 6.844" 78' 4,621' 29.7 N-80 Buttress 6.75" 4,621' 6,111- 33.7 N-80 Buttress 6.64" 6,111' 7,117' 33.7 P-110 Buttress 6.64" 7,117 9,015' 4-1/2" Prod Lnr 1 12.6 N-80 H-521 3.958" 8,765' 12,423' Window Depths are 9,001'(TOP) and 9,015'IBOTTOMI TUBING DETAIL 2-3/8" Production 4.7 1 L-80 I 8rd EUE 1 1.995 1 TBD 11,440' JEWELRY DETAIL No. Depth ID OD Item 1 H-6 11,822 11,830 TOC=CIBP-100' 2 TCP 2-3/4" 6spf 60 deg- Isolated H-7/8 11,857' CIBP-TBD 3 10,513' TCP 2-3/4" 6spf 60 deg- Isolated H-9 2-3/8" Tubing cut TBD by Freepoint 12,032' 10,542' 10,552' TCP 2-3/4" 6spf 60 deg- Isolated 12,088' 12,146' 10,581' 10,610' TCP 2-3/4" 6spf 60 deg- Isolated H-10 12,212' 12,232' 10,643' 10,653' TCP 2-3/4" 6spf 60 deg- Isolated A 9,067' 1.90" 3.750" 2-3/8" GLM 8rd, T-1 Latch Mandrel (dummy) B 9,077' - 2.375" 2-3/8" CIBP (Set 6/25/16) C 9,627' 1.90" 3.750" 2-3/8" GLM 8rd, T-1 Latch Mandrel (dummy) D 10,572' 1.90" 3.750" 2-3/8" GLM 8rd, T-1 Latch Mandrel (dummy) E 11,392' 1.90" 3.750" 2-31W GLM 8rd, T-1 Latch Mandrel (dummy) F 11,402' 1.94" 3.750" Tri -point DLH Hydraulic Ret. Packer G 11,408' 1.875" 3.063" X Landing Nipple H 11,440' 1.995" 1 3.063" Pump out plug W/ WL re-entry guide PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes H-6 11,822 11,830 10,444' 10,448' TCP 2-3/4" 6spf 60 deg- Isolated H-7/8 11,857' 11,956' 10,462' 10,513' TCP 2-3/4" 6spf 60 deg- Isolated H-9 12,013' 12,032' 10,542' 10,552' TCP 2-3/4" 6spf 60 deg- Isolated 12,088' 12,146' 10,581' 10,610' TCP 2-3/4" 6spf 60 deg- Isolated H-10 12,212' 12,232' 10,643' 10,653' TCP 2-3/4" 6spf 60 deg- Isolated Updated byJLL03/05/2019 HILCORP ALASKA 7-1/16" 5M BOPE 7-1/16" 5M HYDRIL GK ANNULAR 32" TALL, FLANGE TO FLANGE 7-1/16" 5M LWS DBL GATE BOP DRESSED W/VARIABLE RAMS IN TOP DRESSED W/BLIND RAMS IN BOTTOM FLANGE TO FLANGE 7-1/16" 5M DRILLING SPOOL W/2-1/16" 5M OUTLETS 18" TALL, FLANGE TO FLANGE —77" TOTAL STACK HEIGHT ANNULAR STYLE BOP SPECS: - 3.30 gallon open chamber volume - 3.86 gallon close chamber volume GATE STYLE BOP SPECS: -1.45 gallons to close per gate - 1.18 gallons to open per gate - 5.45:1 closing ratio - 1.93:1 opening ratio Swanson River SCU 44-33 103/4 X75/8 X 3'/ BHTA, Bowen, 31/8 5M FE Valve, swab, WKM, 3 1/8 5M FE, HWO Valve, Wing, WKM, 2 1/16 5M FE, HWO Valve, upper master, WKM, 31/8 5M FE, HWO Valve, master, WKM, 3 1/8 5M FE, HWO Tbg head, Cameron -N, 11 5M X 7 1/16" 5M, w/ 2- 2 1/16 5M SSO Casing head, Shaffer KD, 11 5M X 10 3/4 SOW, w/ 2- 2" LPO, 7 5/8" KD slips and packoff assy in head Swanson River SCU 44-33 12/08/2014 Tubing hanger, CIW-N-CL- FBB, 7 X 3 %EUE Srd Lift and susp, 3" Type H BPV profile, 318 control line prep Valve, Wing, WKM, 31/85M FE, HWO Qty 2 Valve, Wing,SSV, VG -M, 3 1/8 5M FE w/ Halliburton Hydraulic operator Adapter, CIW-FBB, 71/16 5M stdd X 3 1/8 SM stdd top, w/ 1/2 npt control line exit Valve, WKM, 2 1/16 5M FE, HWO, Qty 2 HHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well SCU 44-33 (PTD 212-143) Sundry #: XXX -XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call' engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By Initials HAK Approved By Initials AOGCC Written Approval Received (Person and Date) Approval: Prepared: Asset Team Operations Manager Date First Call Operations Engineer Date Sundry Application Plug for Re -drill Wells Work Flow This process is used to identify wells that are suspended for a very short time prior to being re - drilled. Those wells that are not re -drilled immediately are identified every 6 months and assigned a current status of"Suspended." Step I Task R 1 The initial reviewer will check to ensure that the "Plug for Redrill" box es onsuble Geologist in the upper left corner of Form 10-403 is checked. If the "Abandon" or J"Suspend" boxes are also checked, cross out that erroneous entry and �. initial it on both copies of the Form 10-403 (AOGCC's and operator's /8 /� 9 312119 copies). 2 If the "Abandon" box is checked in Box 15 (Well Status after proposed Geologist work) the initial reviewer will cross out that erroneous entry and initial then Jit on both copies of the Form 10-403 (AOGCC's and operator's copies). 31V Instead, check the "Suspended" box and initial that change. Drilling The drilling enginders will serve as quality control for steps 1 and 2. Engineer (QC) 3 When the Stat Tech receives a Form 10-403 with a check in the "Plug Stat Tech for Redrill" box, they will enter the Typ_Work code "IPBRD" into the ' History tab for the well in RBDMS. This code automatically generates a comment in the well history that states "Intent: Plug for Redrill." 4 When the Stat Tech receives any Form 10-407, they will check the Stat Tech History tab in RBDMS for the "Intent: Plug for Redrill" code (IPBRD). if present and there is no evidence that a subsequent re -drill has been COMPLETED, the Stat Tech will assign a status of SUSPENDED to the we11 bore in RBDMS no matter what status is listed on the 10-407. The Stat Tech will also change the status on the 10-407 form to SUSPENDED, and date and initial this change. If the Stat Tech does not see the "Intent: Plug for Redrill" comment or code, they will enter the status listed on the Form 10-407 into RBDMS. 5 When the Form 10-407 for the redrill is received,:thetat Tech will Stat Tech change the original well's status from SUSPENDo ABANDONED. 6 The first week of every January and July, the Stat Tech and one of the he Stat Tech Geologists will check the "Well by Type Work Outstanding" user Geologist in RBDMS to ensure that all of the Plug for Redrill wells have been handled properly. At this same time, they will also review the list of sus ended wells for accur-- . R (q • • Carlisle, Samantha J (DOA) From: Schwartz, Guy L(DOA) Sent: Tuesday, September 27, 2016 4:00 PM To: Carlisle, Samantha J (DOA) Subject: FW: Sundry Cancellation - Sundry#316-257 SCU 44-33 (PTD 212-143) Guy Schwartz N[��® FEB . 4 �ii? Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). From: Schwartz, Guy L(DOA) Sent: Monday, September 26, 2016 3:04 PM To: 'Donna Ambruz' Cc: Chad Helgeson; Joe Kaiser Subject: RE: Sundry Cancellation - Sundry # 316-257 SCU 44-33 (PTD 212-143) Donna, Sorry about delay. Sundry 316-257 for well SCU 44-33 will be retracted at per your earlier request. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). From: Donna Ambruz [mailto:dambruzCa1hilcorp.com] Sent: Monday, September 26, 2016 10:21 AM To: Schwartz, Guy L(DOA) Cc: Chad Helgeson; Joe Kaiser Subject: RE: Sundry Cancellation - Sundry # 316-257 SCU 44-33 (PTD 212-143) Hi Guy—Status please. Just checking. Thank you. Donna 1 RBDMS t,L'SEP 2 9 2016 ...__, From: Donna Ambruz Sent: Friday, August 05, 2016 9:08 AM To: Guy Schwartz (guv.schwartz@)alaska.gov) Cc: Chad Helgeson; Joe Kaiser Subject: Sundry Cancellation - Sundry # 316-257 SCU 44-33 (PTD 212-143) Guy, Please withdraw the above mentioned sundry. Thank you. Donna antiv wz 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 2 STATE OF ALASKA AL OIL AND GAS CONSERVATION COMIISION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon ❑ Plug Perforations Fracture Stimulate ❑ Pull Tubing J Operations shutdown __ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ 3rforate New Pool ❑ Repair Well ❑ Re-enter Susp Well Li Other: CTCO w/N2 ❑✓ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska, LLC Development Li Exploratory ❑ 212-143 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20237-01 7.Property Designation(Lease Number): 8.Well Name and Number: FEDA028399/FEDA028997 Soldotna Creek Unit(SCU)44-33 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River/Hemlock Oil 11.Present Well Condition Summary: RECEIVED Total Depth measured 12,425 feet Plugs measured 9,077 feet true vertical 10,746 feet Junk measured N/A feet JUL 1 2 ZO16 Effective Depth measured 9,077 feet Packer measured 11,402 feet 1 f"�(y( �`' true vertical 9,020 feet true vertical 10,221 feet P'1V�A v Casing Length Size MD TVD Burst Collapse Structural Conductor 337' 20" 337' 337' Surface 3,408' 10-3/4" 3,408' 3,408' 3,130 psi 1,580 psi Intermediate Production 9,015' 7-5/8" 9,015' 8,963' 6,020 psi 3,400 psi Liner 3,658' 4-1/2" 12,423' 10,746' 8,430 psi 7,500 psi Perforation depth Measured depth See Attached Schematic 4- ,,: tcr' AUG 1 0 2016 True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 2-7/8"x 2-3/8" 6.5#x 4.7#/L-80 x L-80 11,440'MD 10,242'TVD Tripoint DHL Packers and SSSV(type,measured and true vertical depth) Hyd Ret;N/A 11,402'MD 10,221'TVD N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A AUG1 C 2016 Treatment descriptions including volumes used and final pressure: N/A SCANNED G0 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 50 0 - Subsequent to operation: 0 0 0 560 100 14.Attachments(required per 20 AAC 25.070.25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory❑ Development❑✓ Service Li Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil Q Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP Li SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 316-294 Contact Joe Kaiser-777-8393 Email jkaiser@hilcorp.com Printed Name / Chad Helgeson Title Operations Manager Signature j� ler Phone 907-777-8405 Date 771z)) 6 7.2o/(i Form 10-404 Revised 5/2015 711/ 7/437a RBDMS GL-/ JUL 1 3 2016 Submit Original Only • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SCU 44-33 E-Line 50-133-20237-01 212-143 6/20/16 6/26/16 Daily Operations: 06/20/2016- Monday Obtain PTW. Hold safety meeting and discuss JSA. Lay pit liner. Spot in equipment. Confirm fluid in OT tank. 450 bbls of produced water on location. Rig up SLB CTU 12. Stab 1.5" CT pipe in injector head. Pick injector head. Stab 10' lubricator. Make up coil connector. Pull test to 20K. Start BOPE test. Test all rams and valves to 250 low 4 500 high for 5 minutes. One fail pass indicated. Inner reel valve not holding pressure. Replaced 1502 2"valve and retested. Indicated on state form as FP. 24 HR BOPE test witness notificatiion send 6/19/16 @ 12:08 PM. Witness waived by Jim Regg on 6/20/16 @ 12:32 AM. BOPE test complete and passed. Blow down stack. Pop off injector head. Rig back. 450 bbls of fluid on location and 1,100 gallons of N2. SDFN. Wellhead and ground iron secure. 06/21/2016-Tuesday Obtain PTW. Hold safety meeting. Review JSA and job procedure. Fire equipment. Pick injector head. Stab 10' lubricator. BHA: Coil connector, check valves, 2x stinger,jet swirl wash nozzle. OD 1.5" Length 8.6'. Pressure test BHA to 250/4,500 psi. Stab on well. Pressure test stack to 250/4,500 psi. Open master swab 20 turns. Initial WHP 0 psi. RIH. Seeing small returns to surface from pipe displacement at 440'. Stack weight at 2704'. Pick up 100' Clean pick up 6K. Start washing at 1.2 bbls/min 3,600 psi CT pressure. Notice small drip on Bowen o-ring. POOH to surface to swap o-ring. At surface master swab closed. Blow down stack. Pop off well change o-ring. Stab on well. Pressure test 250/4,500 psi. Bleed down to OT tank. Open master swab 20.5 turns. RIH 0 psi WHP. At 2,600' pump 1.2 bbls/min. Wash to 2,700'. Pump 5 bbls. Spacer and pick up 50' wiper trip. Seeing sands in returns. Continue IH. Washing at 30 ft'/min. No indication of weight stack. Looks like loose unconsolidated fill. 3,000' pump bottoms up. Returns clean up. RIH for another 1,000' continue IH to 4,000'. Circulate bottoms up of 14.4 bbls. RIH to 5,000', circulate 5 bbl spacer. Up weight 8,400 lbs. Continue IH. Stack 9K down at 6,015'. Looks like hard fill. No indication fill washing off. PU 50'. Run into fill at 50 ft/min and again at 65 ft/min. Stacking 10K down. Leave weight stacked. Watch for weight on break back. No weight breaking back. Continue to pick up and tun into fill. Stack 10K down on 6th attempt. 300 lbs of weight breaking back. Continue to push. Finally washing. Weight bobbles from 6,015' to 6,018'. Pick up 30'. RIH, no indication of obstruction at previous depth of 6,015'. After breaking through sand bridge at 6,015'-6,018' return micro motion showing increase in returns. Prior returns were 1:1. Pumping 1.2 bbls/min. Now returning 2.3 bbls/min. Continue IH washing to 9,100'. No indicatons of weight stack or overpulls during weight check. Parked at 9,100', start circulating 100 bbls or 3x bottoms up. Still good indication of solids/sands in returns. Wash up and down 4x while performing 100 bbl bottoms up treatment from 9,100' back to 9,000'. After 1.5 bottoms up start pinching in choke unitl return micro motion is 1/2 bbls/min. Pumping and returning 1:1. WHP 187 psi. Start chasing 100 bbl sweep OOH while pumping 1.2 bbls/min. at 8000'. Shut down pump. Wait 30 minutes. RIH and attempt dry tag fill or clean trip to 9,100'. No indication of fill. Stopped at 9,100'. Come back on line pumping 1.2 bbl/min. POOH to surface. Returns not cleaning up. Still getting sands from formation. No increase in IA or OA during intervention. • • IIHilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SCU 44-33 E-Line 50-133-20237-01 212-143 6/20/16 6/26/16 Daily Operations: POOH to surface. Tagged up at surface. Close choke. 900 psi on WHP. Close master and swab. Bleed down CT. Blow down. Pop off well. Tool string clean. Stack back Injector head. 610 bbls pumped for FCO. 721 bbls returned through micro motion. 111 bbls returned from formation. All ground valves closed. Wellsite secure. Crews off location. Pollard SL has been dispatched to attempt to set dummy valve. 06/22/2016-Wednesday SL arrive at swanson. Obtain permit,JSA. Check fluids. Fire equipment and travel to location. RU SL, get hot oil truck for PT lub and test casing. PT good @ 3,500 psi. RIH with 1.75" DD bailer to 8,769' KB fell to 8,896' KB then fell to 8,961' KB and down to 8,999' KB. Dropped down to 9,000' KB. POOH, empty bailer bottom full of hard clay. RIH with same to 9,006' KB, made it to 9,052' KB. POOH. Bailer full of silt. RIH with same to 9,019'. Bailed down to 9,081'. POOH, bailer half full. RIH with 2.25" centralizer and 1.75" DD bailer to 9,004' KB, set down on x over. RIH with 2.375" KOT with 1 latch dummy to 8,980' KB, sat down weight and wouldn't pass. POOH to check tool. RIH with same to 9,024' KB, locate and set down. Keeps slipping off. Tried 12 times. POOH. Lay down lubricator for the night. Well site secure. 06/23/2016-Thursday Obtain PTW. Hold safety meeting and review JSA. Pick up lubricator. Stab on well and PT to 250/3,500 psi. RIH with 2.375" Danials KOT w/ pocket brush to 8,860' KB, sat down W/T. POOH, wouldnt pass. Check tool. RIH with 1.75" DD bailer to 9,001' KB, hard to see spangs. POOH, full of mud and coal. RIH with same to 8,966', sat down. Lost spang action. POOH and change to 1.5" spangs. RIH with same to 8,875' KB. POOH. Pressure up the tubing to 2,700 psi at 1.5 bbls/min. RIH with same and tag fill at 9,001' KB, sat down wt. POOH. RIH with same to 9,045' KB, bail to 9,050'. POOH. RIH w/OK-1 KOT w/pocket brush to 9,027' KB to 9,040' KB, couldn't locate. POOH, no spang action. RIH with 1.75" DD bailer to 9,052' KB. POOH. RIH with 2" BL brush to 9,004' KB. Set down on XO . Made it down in 2.375", couldn't fall pump fluid. Made it to 9,050'. POOH. RIH with 2.375" OK-1 KOT, w/pocket brush to 9,033' KB, found mandrel. Could locate and sit down. Never got good overpull from brush. POOH. Lay down for night. Wellsite secure. 06/24/2016- Friday Obtain PTW. Hold safety meeting and review JSA. Start Equipment. Re-head and cut wire. PT lub to 3,500 psi. RIH with OK-1 and scratcher with 1-1/8" piece of brass locket at 9,042' KB. POOH, brass bent. RIH with same. KOT and valve to 9,042' KB, locate. POOH, note set packing is torn up, re-dress dummy valve. RIH with same to 9,042' KB. POOH, set dummy valve. Set crystal gauge on tubing. Bleed tubing down to 700 psi, record for 1/2 hour. RIH w/2-7/8" x-line and 2.31" X-lock with PX plug to 8,653' KB. POOH, plug set. RIH, w/2" RB w/prong to 8,653' KB, stay on prong, hook up crystal gauge. Stand by. Pull prong. RIH with 2-7/8" G to 8,653', latch up and pull plug. Rig down. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SCU 44-33 E-Line 50-133-20237-01 212-143 6/20/16 6/26/16 Daily Operations: 06/25/2016-Saturday Obtian PTW. Hold safety meeting. Discuss JSA. E-line and SL. MIRU Pollard E-line. Stab on well. PT stack to 250/3,500 psi. Leave 1,800 psi on lub. Equalize and open master swab. WHP 1,752 psi. RIH with BHA rope socket, rollers stem, RB, weight bar, roller boggey, weight bar, CCL. All 1-11/16". Worked down and sat weight at 9,092'. Log OOH and grab 2-7/8" x 2-3/8" X over, x nipple, and #8 GLM. Correct depth. Continue IH and make it to 9,128'. Log OOH and saw lower pup joint, GLM and upper pup joint. Number 10. Great readings on CCL. WHP bleed down to 0 psi. Looks like dummy valve holding. Make up CIBP and setting tool. Distance from CCL to center element is 8'. PT stack to 250/3,500 psi. Bleed down. Open swab. RIH with CIBP. Setting down weight at 9,084'. Log OOH at 40 ft/min to 8,400'. Good CCL on mandrel at 9,067'. RIH and get on depth. Center of element at 9 077.5'. Confirmed with town. Set CIBP. Pick up and RIH set down on CIBP. POOH to surface. At surface with E-line. Swab closed. Pop off. Confirmed CIBP not on tool string. Start rigging down E-line. Vac truck on location. Start filling annulus with produced water for PT. 30 bbls pumped previous day. 36 bbls pumped before pressure increase. 66 bbls total pumped to fill 2-3/8" x 7-5/8" annuli. Start 30 minute pressure test at 1430. 2,535 psi. End at 2,500 psi at 1500 hrs. Crystal gauge used to monitor IA and tubing pressure. Returned to download graphs. Bleed down. Secure IA valve and wing valves. Hot oil rigging down. Wellsite secure. 0 psi on tubing and IA. 06/26/2016-Sunday Obtain PTW. Hold safety meeting. Discuss JSA. Pick injector head. Stab 10' lubricator. Stab on reel. Cool down N2. Pump 1,500 scf/min for 15 minutes to blow reel dry. N2 bleeding down. Pop off well. Stack down injector head. RDMO CTU 12. Location secure. SLB off location. Fluid manifests in office for Rain for Rent. • Soldotna Creek Unit H Well SCU 44-33 ACTUAL SCHEMATIC Completion 212-143ate: 11/29/12 PTD eak"rp AiaAv,LLC API: 50-133-20237-01 164.6'Above MSL KB-THF:20' CASING DETAIL *, 1 .'` L Size Type Wt Grade Conn. ID Top Btm 44i., 20' J t - - 20" Conductor Surf 337' 10-3/4" Surf.Csg 40.5 1-55 Buttress 10.05 Surf 3,408' 33.7 N-80 Buttress 6.64" Surf 78' 4 Al . 26.4 N-80 Buttress 6.844" 78' 4,621' 10-3/4" 7-5/8" Intermediate 29.7 N-80 Buttress 6.75" 4,621' 6,111' a *j. 33.7 N-80 Buttress 6.64" 6,111' 7,117' t.' 2 ii 33.7 P-110 Buttress 6.64" 7,117 9,015' o A 4-1/2" Prod Lnr 12.6 N-80 H-521 3.958" 8,765' 12,423' i Window Depths are 9,001'(TOP)and 9,015'(BOTTOM) 4 44 i 3 I Communciation with HP Tyonek +"' Water Sand(9,044' TUBING DETAIL TVD).Fill in 2-7/8" Production 6.5 L-80 8rd EUE 2.441 Surf 9,028' , annulus.No comm 2-3/8" Production 4.7 L-80 8rd EUE 1.995 9,028' 11,440' *, 4 between annulus and wt^ tubing.June 2016 JEWELRY DETAIL 5 No. Depth ID OD Item i ." 1 19' 2.44" - Tubing Hanger a 2 1,912' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 10 port(dummy) 3 3,484' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port(dummy) 4 4,800' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port(dummy) `j 6 !e: ' i t 5 5,991' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port(dummy) 6 7,019' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port(dummy) 7 7,795' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 16 port(dummy) 4.1 7 VW i 8 8,508' 2.44" 4.500" 2-7/8"SF0-1 Mandrel 8RD 16 port(orifice) 8 9 8,709' 2.313" 3.688" X Landing Nipple i 41 ;% ar 10 9,067' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel(dummy) " i• an 9 11 9,077' - 2.375" 2-3/8"CIBP(Set 6/25/16) at 7-5/8" Al a . 12 9,627' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel(dummy) r < 10 13 10,572' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel(dummy) Fill to 9,084' = 11i ,1.?� 14 11,392' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel(dummy) 12 �tC 15 11,402' 1.94" 3.750" Tri-point DLH Hydraulic Ret.Packer • i 6 13 16 11,408' 1.875" 3.063" X Landing Nipple 4 m 17 11,440' 1.995" 3.063" Pump out plug w/WL re-entry guide '' ii si =4 15 ., 0 1 PERFORATIONS V 414 16 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes (i+17 �� H-6 11,822 11,830 10,444' 10,448' TCP 2-3/4"6spf 60 deg H-7/8 11,857' 11,956' 10,462' 10,513' TCP 2-3/4"6spf 60 deg t* 6. k., 6. H-9 12,013' 12,032' 10,542' 10,552' TCP 2-3/4"6spf 60 deg 12,088' 12,146' 10,581' 10,610' TCP 2-3/4"6spf 60 deg 4-1/2" a el H-10 PBTD=12,290'MD/10,681'TVD 12,212' 12,232' 10,643' 10,653' TCP 2-3/4"6spf 60 deg TD=12,425'MD/10,746'ND Max dev.71.85 deg @ 10,180'MD Downhole Revised: 10/16/14 Updated by JEK 6-27-2016 • • �OF T�� THE STATE Alaska Oil and Gas N�►v-�d�iA� o f /k T AsKik Conservation Commission �" s�1#� 333 West Seventh Avenue 2 7i-wily' GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 ASS' ' Fax: 907.276.7542 AL www.aogcc.alaska.gov Chad Helgeson Operations Manager SCANNED JAN 0 6.2017 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 44-33 Permit to Drill Number: 212-143 Sundry Number: 316-294 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. oerster � { Chair DATED this D day of June, 2016. RBDMS W JUN 1 0 2016 • • RECEIVED STATE OF ALASKA MAY 2 7 2016 • ALASKA OIL AND GAS CONSERVATION COMMISSION Orf /APPLICATION FOR SUNDRY APPROVALS AOG 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other. CTU Clean Out Q • 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: w/ to 4- Hilcorp Alaska,LLC Exploratory ❑ Development Q• 212-143 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 50-133-20237-01 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 123B Soldotna Creek Unit(SCU)44-33 ' Will planned perforations require a spacing exception? Yes ❑ No ❑✓ 9.Property Designation(Lease Number): 10.Field/Pool(s): FEDA028399/FEDA028997 . Swanson River Field/Hemlock Oil • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 12,425' - 10,746' • 12,290' . 10,681'• 923 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 337' 20" 337' 337' Surface 3,408' 10-3/4" 3,408' 3,408' 3,130 psi 1,580 psi Intermediate Production 9,015' 7-5/8" 9,015' 8,963' 6,020 psi 3,400 psi Liner 3,658' 4-1/2" 12,423' 10,746' 8,430 psi 7,500 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 2-7/8"x 2-3/8" 6.5#x 4.717:/L-80 x L-80 11,4.40 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Tripoint DLH Hyd Ret;N/A 11,402'MD/10,221'TVD;N/A 12.Attachments: Proposal Summary ❑✓ Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program Lf BOP Sketch ✓f Exploratory Li Stratigraphic U Development U. Service U 14.Estimated Date for 15.Well Status after proposed work: June 10,2016 ❑ ❑ ❑ Suspended DI Operations: OIL - WINJ WDSPL 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Joe Kaiser-777-8393 Email jkaiser( hilcorD.com Printed Name Chad Helgeson Title Operations Manager Signature � 7,r4 Phone 907-777-8405 Date 5 /Z-7fI tc, COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 3 "JZ - 2tf er Plug Integrity El BOP Test L Mechanical Integrity Test ❑ Location Clearance ❑ Other: 1-(>00 /'S c 5c)( 1 e-5-1- C c,--7) Post Initial Injection MIT Req'd? Yes ❑ No Spacing Exception Required? Yes ❑ No Subsequent Form Required: /2/ 1) di(JC l RBDMS Vc, JUN 1 0 2016 APPROVED BY 9 rL/� Approved by:6V47Ls__ COMMISSIONER THE COMMISSION Date: b 6-1-/G Submit Form and Form 10-403 Revised 11/2015 GRit I 14 4A1tor 12 months from the date of approval. Attachments in Duplicate • • Well Prognosis Well: SCU 44-33 Hikora Alaska,LL Date:6/3/2016 Well Name: SCU 44-33 API Number: 50-133-20237-01 Current Status: Gaslift Oil Well Leg: N/A Estimated Start Date: June 13th, 2016 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 212-143 First Call Engineer: Joe Kaiser (907)777-8393(0) (907)952-8897(M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907)229-4824(M) AFE Number: Current Bottom Hole Pressure: — 1,982 psi @ 10,592' TVD (Based on static survey 4/08/14.) Maximum Expected BHP: —3,950 psi @ 9,044'TVD (Based on data for Tyonek HP Water) Max.Potential Surface Pressure: —923 psi (Based on 0.1 psi/ft gradient) MPSP from Tyonek HP Water Sands: —34 psi (Based on 0.433 psi/ft gradient) Brief Well Summary The well was sidetracked using the Doyon Arctic Fox drilling rig in October 2012 as SCU 44-33.The Williams #405 WO rig completed the well in November 2012 with perforations in the lower Hemlock, H-6 thru H-10. In October 2014,a 3/8"capsting was installed to manage emulsion issues. In April, 2016 the capstring was removed to perform slickline work on the gas lift valves.While pulling a gas lift valve in the 2-3/8"tubing, solids flowed in the tubing. Fill was bailed over several days down to 2,663'. The purpose of this work/sundry is to perform a coil tubing cleanout to^'9,100', install a dummy GLV in the top 2-3/8"GLM,and perform casing pressure test. Notes Regarding Wellbore Condition • Wellbore is deviated with a maximum hole angle of 71.85°@ 10,180' MD. • New completion ran in November 2012. Min ID is 1.875"X-profile at 11,408' MD. • Fill is at-2,663'. • GLV in 2-3/8" GLM at 9,067' is not installed.An orifice valve is installed in the bottom 2-7/8"GLM. • Well could have potential energy from Tyonek HP water sands. Procedure: 1. MIRU 1.5" Coil Tubing, PT BOPE to 4,500 psi HI 250 Low for 5 min. 2. MU jet nozzle for washing down operations.Stab on well, PT lubricator and flowlines to 250/4,500 psi. 3. RIH with slick BHA.While RIH, pump PW down tubing and take returns to tank. Monitor returns for sand and tank levels in returns tank. If returns are not present, see attached Standard Well Procedure-Nitrogen Operations. 4. Wash down to approximately 9,100'.(Do not run deeper than 9,100'without Engineers approval). While at this depth circulate 3 annulus volumes (approximately 100 bbl.). Monitor return tank levels and return volume. Discuss returns with the Engineer. 5. Pull coil up to—8,000'. Stop circulating.Wait 30 minutes. RIH with coil pumping and tag bottom. If tag is above 9,100'(review results with Engineer),then repeat steps 4-6 until fill remains below this depth. POOH with coil. Unstab coil from well. Keep coil unit on standby incase fill in wellbore returns. 6. RU Slickline on Coil BOPE. 7. PT Equipment to 3,500 psig HI and 250 psi Low for 5 min. ' • • Well Prognosis • Well: SCU 44-33 Hilcorn Alaska,LL Date:6/3/2016 8. MU 1.75" GR and RIH.Tag Bottom. POOH. If fill is above 9,100' cleanout with coil again by following steps 2-8. 9. MU GLV setting tool. RIH with dummy valve. Set dummy in GLM at top of 2-3/8" string. (GLM at "9,067'). POOH. 10. MU tool to set plug in X-landing Nipple at "8,709'. RIH with plug body and set in 2-7/8"X-nipple. POOH. RIH with prong. Latch prong into plug body. POOH. 11. Perform casing pressure test(jug test)to 2,500psig for 30min w/chart. 12. Unseat prong in x-landing nipple. POOH. RIH and pull plug body from X-nipple. 13. RD Slickline. 14. RD Coil. 15. Turn well over to Operations. Attachments: 1. Actual Schematic 2. Coil Tubing BOPE 3. Standard Well Procedure-Nitrogen Operations 4. CT Flow Diagram—N2 Jetting • • Soldotna Creek Unit • Well SCU 44-33 ini Completion Date: 11/29/12 ACTUAL SCHEMATIC PTD: 212-143 Flileorr AIL .i.,.0 API: 50-133-20237-01 164.6'Above MSL KB-THF:20' CASING DETAIL J 8 1 l Size Type Wt Grade Conn. ID Top Btm 20"a �" r D 20" Conductor - - - Surf337' ,,, 10 3/4" Surf.Csg 40.5 J 55 Buttress 10.05 Surf 3,408' 33.7 N-80 Buttress 6.64" Surf 78' i, ?'.: 26.4 N-80 Buttress 6.844" 78' 4,621' 10-3/4" s� �',• 7-5/8" Intermediate 29.7 N-80 Buttress 6.75" 4,621' 6,111' j` 33.7 N-80 Buttress 6.64" 6,111' 7,117' :` 2 i W 33.7 P-110 Buttress 6.64" 7,117 9,015' I" INI 4-1/2" Prod Lnr 12.6 N-80 H-521 3.958" 8,765' 12,423' Window Depths are 9,001'(TOP)and 9,015'(BOTTOM) TUBING DETAIL w,, 111 iu 2-7/8" Production 6.5 L-80 8rd EUE 2.441 Surf 9,028' �. 2-3/8" Production 4.7 L-80 8rd EUE 1.995 9,028' 11,440' 4 'r, JEWELRY DETAIL 11114 UNo. Depth ID OD Item 5 i 1 19' 2.44" Tubing Hanger 2 1,912' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port � 3 3,484' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 10 port F* 4 4,800' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port i'k 6 5 5,991' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port 1 A, 6 7,019' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port 4 0 y 7 7,795' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 16 port In 7 i' 8 8,508' 2.44" 4.500" 2-7/8"SF0-1 Mandrel 8RD 16 port 0 V 31; b1 9 8,709' 2.313" 3.688" X Landing Nipple 8 i' ;iis 10 9,067' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel +? 9 fw' 11 9,627' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 04'!�V 12 10,572' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 7-5/8" f 10 cioli7 13 11,392' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 14 11,402' 1.94" 3.750" Tri-point DLH Hydraulic Ret.Packer Ili 11 15 11,408' 1.875" 3.063" X Landing Nipple 12 16 11,440' 1.995" 3.063" Pump out plug w/WL re-entry guide ' "-413 fi i A 14 1 I- 15 PERFORATIONS 16 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes V k,, H-6 11,822 11,830 10,444' 10,448' TCP 2-3/4"6spf 60 deg j a. ! H-7/8 11,857' 11,956' 10,462' 10,513' TCP 2-3/4"6spf 60 deg t", —4— H-9 12,013' 12,032' 10,542' 10,552' TCP 2-3/4"6spf 60 deg —s? 12,088' 12,146' 10,581' 10,610' TCP 2-3/4"6spf 60 deg 4-1/2" a� i H-10 PBTD=12,290'MD/10,681'TVD 12,212' 12,232' 10,643' 10,653' TCP 2-3/4"6spf 60 deg TD=12,425'MD/10,746'TVD Max dev.71.85 deg @ 10,180'MD Downhole Revised: 10/16/14 Updated by JEK 4-27-2016 H . BeeravCreek Unit •H COIL BOPE SCU 44-33 5-27-2016 Flilcmp lla.l.a.i.l.t: SCU 44-33 r 16X10'/<X75/8X4Y2 Coil Tubing BOP Lubricator to injection head s o r 1.75"Tandem Stripper _ 1 r 1/16 10 101111 Blind/Shear _ 111111Blind/Shear 11111111 il=11 Ell. MEM ill I I Blind/Shear = I Blind/Shead.'.'•! t � � — _ _ 0: --_— t-= Slip Slip = _ —. r -101110 Pipe MN _ Pipe MUd Cross . - 4 1/16 10M X 4 1/16 10M Outlet "- ' w/2- 2 1/16 1OM full opening FMC valves 11111110011 III 0 I 11111 la t 111. It c) ittoi poi Manual Manual Manual Manual 2 1/16 10M 2 1/16 10M 2 1/16 1OM 2 1/16 1OM Crossover spool 3-1/8" 5M X 2 9/16 5M Valve,swab, WKM, ... �� 3 1/8 5M FE, HWO C775'. Valve,Wing, WKM, 3 _n0 0 ^, 1/8 5M FE, HWO - p0i Qty 2 IIIIIIIIMIP � l i2. I � i / � I Il , o . . — iii„,' Valve, upper master, WKM, 3 1/8 5M FE, HWO -41.111 N. L•- Valve, master, WKM, 6 3 1/8 5M FE, HWO �'(c . l r1 • STANDARD WELL PROCEDURE IlileorpAlaska.LLC NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 Db ! .1 F k 13 m Q U y I 11 0 N ■ 1 J Z Q m 0 i 1 : Pd 11] a2 °p 1I C o0 � L ..4 i��i z +-' Y aaaa y • , , ►�, a N • • Z A A �i ►•4 0 a [ V u • C a i2 III� I lir II 1 Han � o M ' 3 Y C O H O. H N I g n a 8 O a ID (-ilia 0 II i ,,, os 8 • , . o if n c 0 0 n v 0 0_ 0 U z m 0 0 i r. k a i V OF Tji� • • 4$)* //7:,& THE STATE Alaska Oil and Gas F -s�� , of ee ccKA Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 O4'ALAe*P' Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager Hilcorp Alaska, LLC some 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 44-33 Permit to Drill Number: 212-143 Sundry Number: 316-257 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, ‘Yeity Cathy P. Foerster err Chair DATED this )I'"day of May, 2016. • RBDMS Lv MAY 1 1 2016 • • RECEIVED STATE OF ALASKA ' ALASKA OIL AND GAS CONSERVATION COMMISSION MAY 0 3 2016 APPLICATION FOR SUNDRY APPROVALS 0-5 (�'/".III 20 AAC 25.280 G C( 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. Re-run cap string_❑., ' 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number: Exploratory ❑ Development ❑✓ ' 212-143 ' 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,Alaska 99503 50-133-20237-01 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 123B Soldotna Creek Unit(SCU)44-33 Will planned perforations require a spacing exception? Yes ❑ No RI 9. Property Designation(Lease Number): 10.Field/Pool(s): FEDA028399/FEDA028997 Swanson River Field/Hemlock Oil ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 12,425' ' 10,746' ' 12,290' ' 10,681' ' 923 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 337' 20" 337' 337' Surface 3,408' 10-3/4" 3,408' 3,408' 3,130 psi 1,580 psi Intermediate Production 9,015' 7-5/8" 9,015' 8,963' 6,020 psi 3,400 psi Liner 3,658' 4-1/2" 12,423' 10,746' 8,430 psi 7,500 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 2-7/8"x 2-3/8" 6.5#x 4.7#/L-80 x L-80 11,440 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Tripoint DLH Hyd Ret;N/A 11,402'MD/10,221'TVD; N/A 12.Attachments: Proposal Summary ❑✓ Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑✓ Service ❑ 14. Estimated Date for 15.Well Status after proposed work: May 17,2016 Commencing Operations: OIL E • WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Joe Kaiser-777-8393 Email jkaiser@hilcorp.com Printed Name Chad HelgesonesTitle Operations Manager Signature [ j�� ,,�", Phone 907-777-8405 Date M1 f COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No IASubsequent Form Required: lc)--'-r 0/ RBDMS 1,1, MAY 1 2016 i6 1 APPROVED BY Approved by: T/� COMMISSIONER THE COMMISSION Date: s- L 64— s'�'i` ORI' p PttachSubmit Form and Form 10-403 R ised 11/2015 t for 72 months from the date of approval. ments in Duplicate T • • . HWell Prognosis Well: SCU 44-33 [Mean)Alaska,[IC Date:5/3/2016 Well Name: SCU 44-33 API Number: 50-133-20237-01 Current Status: Gaslift Oil Well Leg: N/A Estimated Start Date: May 17th, 2016 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 212-143 First Call Engineer: Joe Kaiser (907)777-8393 (0) (907) 952-8897 (M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824(M) AFE Number: Current Bottom Hole Pressure: — 1,982 psi @ 10,592' TVD (Based on static survey 4/08/14.) Maximum Expected BHP: — 1,982 psi @ 10,592' TVD (Based on static survey 4/08/14.) Max. Potential Surface Pressure: —923 psi (Based on 0.1 psi/ft gradient) Brief Well Summary The well was sidetracked using the Doyon Arctic Fox drilling rig in October 2012 as SCU 44-33.The Williams #405 WO rig completed the well in November 2012 with perforations in the lower Hemlock, H-6 thru H-10. In October 2014, a 3/8" capsting was installed to manage emulsion issues. In April, 2016 the capstring was removed to perform slickline work on the gas lift valves. The purpose of this work/sundry is to install a capstring to manage emulsion issues. Notes Regarding Wellbore Condition • Wellbore is deviated with a maximum hole angle of 71.85° @ 10,180' MD. • New completion ran in November 2012. Min ID is 1.875"X-profile at 11,408' MD. • Well does not have a SSSV system,only a SSV system. Capstring Procedure: 1. MIRU Cap String Truck, PT lubricator to 2,500 psi Hi 250 Low. 2. Install wellhead packoff. a. Current tree cap is 3.5" Bowen w/2-9/16" flanged connections. 3. PU 3/8" capillary string. RIH and set below gas lift orifice (8,508'to 11,392'). 4. Set spool of remaining line near well. 5. Rig down Cap String Truck. 6. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic • • Soldotna Creek Unit Well SCU 44-33 Comletion ACTUAL SCHEMATIC PTD:p212-143Date: TDp212-143ate. 11/29/12 Hi!orp Alaska,LLC API: 50-133-20237-01 164.6'Above MSL KB-THF:20' CASING DETAIL 20 !J ',, 1 '') L Size Type Wt Grade Conn. ID Top Btm " 1<' 20" Conductor Surf 337' l} 10-3/4" Surf.Csg 40.5 J-55 Buttress 10.05 Surf 3,408' a - �"� ° 33.7 N-80 Buttress 6.64" Surf 78' « 52 26.4 N-80 Buttress 6.844" 78' 4,621' 10-3/4" Yet ` , 7-5/8" Intermediate 29.7 N-80 Buttress 6.75" 4,621' 6,111' .. Mtj 33.7 N-80 Buttress 6.64" 6,111' 7,117' 2 Mg i '° 33.7 P-110 Buttress 6.64" 7,117 9,015' w 4-1/2" Prod Lnr 12.6 N-80 H-521 3.958" 8,765' 12,423' Window Depths are 9,0011TOP)and 9,0157BOTTOM) 3 Mg 1 ► TUBING DETAIL ar± i+ 2-7/8" Production 6.5 L-80 8rd EUE 2.441 Surf 9,028' 4 4 I # 2-3/8" Production 4.7 L-80 8rd EUE 1.995 9,028' 11,440' k ww JEWELRY DETAIL a No. Depth ID OD Item Nk ." 0 1 1 1 19' 2.44" - Tubing Hanger k 2 1,912' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port i u 4 3 3,484' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port * 4 4,800' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port 6 "` 5 5,991' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port 1 6 7,019' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port 7 7,795' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 16 port 1* 7 ' ," 8 8,508' 2.44" 4.500" 2-7/8"SFO-1 Mandrel 8RD 16 port �I re II 9 8,709' 2.313" 3.688" X Landing Nipple tol 8lo ' r' 10 9,067' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel to IP I. c 9 11 9,627' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 12 10,572' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel ` ,`u 7 5/8„ 7 ''.4 10 13 11,392' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel ' ilIt 90 14 11,402' 1.94" 3.750" Tri-point DLH Hydraulic Ret.Packer 44 ' i 11 15 11,408' 1.875" 3.063" X Landing Nipple 1 16 11,440' 1.995" 3.063" Pump out plug w/WL re-entry guide 12 4' 1 `4 13 lo 0 I, 1 `I 1 14 a ,,r ,e p" kil :1 I' 15 PERFORATIONS Ai i16 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes H-6 11,822 11,830 10,444' 10,448' TCP 2-3/4"6spf 60 deg y H-7/8 11,857' 11,956' 10,462' 10,513' TCP 2-3/4"6spf 60 deg 6 H-9 12,013' 12,032' 10,542' 10,552' TCP 2-3/4"6spf 60 deg 12,088' 12,146' 10,581' 10,610' TCP 2-3/4"6spf 60 deg 1/2" 4- a. r H-10 PBTD=12,290'MD/10,681'TVD 12,212' 12,232' 10,643' 10,653' TCP 2-3/4"6spf 60 deg TD=12,425'MD/10,746'TVD Max dev.71.85 deg @ 10,180'MD Downhole Revised: 10/16/14 Updated by JEK 4-27-2016 • • Soldotna Creek Unit • Well SCU 44-33 int • PROPOSED SCHEMATIC PTD:pletion 212-143ate:11/29/12 Hilrorp Alaska,1.1.€ API: 50-133-20237-01 164.6'Above MSL KB-THF:20' CASING DETAIL 44* Size Type Wt Grade Conn. ID Top Btm 20 1 20" Conductor - - Surf 337' 10-3/4" Surf.Csg 40.5 1-55 Buttress 10.05 Surf 3,408' 33.7 N-80 Buttress 6.64" Surf 78' 1 L 1,4 ta 26.4 N-80 Buttress 6.844" 78' 4,621' 10-3/4"41 7-5/8" Intermediate 29.7 N-80 Buttress 6.75" 4,621' 6,111' ti 33.7 N-80 Buttress 6.64" 6,111' 7,117' 2 Ili 33.7 P-110 Buttress 6.64" 7,117 9,015' 4-1/2" Prod Lnr 12.6 N-80 H-521 3.958" 8,765' 12,423' '$ 41 Window Depths are 9,001'(TOP)and 9,015'(BOTTOM) , TUBING DETAIL ► 2-7/8" Production 6.5 L-80 8rd EUE 2.441 Surf 9,028' ti; 04 2-3/8" Production 4.7 L-80 8rd EUE 1.995 9,028' 11,440' *+u 4 11111 T * JEWELRY DETAIL 1 No. Depth ID OD Item '..* 5 I 1 1 19' 2.44" Tubing Hanger 2 1,912' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 10 port ' I"I�:4 3 3,484' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 10 port ' h* 4 4,800' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port Il 6 5 5,991' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port A 1 2, 6 7,019' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port 7 7,795' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 16 port 7 l 8 8,508' 2.44" 4.500" 2-7/8"SFO-1 Mandrel 8RD 16 port * I M 9 8,709' 2.313" 3.688" X Landing Nipple '..„.'4, 8 ow il 10 9,067' 1.90" 3.750" 2-3/8"GLM 8rd,Ti- Latch Mandrel 0: +:4 .-"n9 11 9,627' 1.90" 3.750" 2-3/8"GLM 8rd,Ti- Latch Mandrel 2- ' 6 t "� 12 10,572' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel � 7-5/8" 11 1 1 10 13 11,392' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 14 11,402' 1.94" 3.750" Tri-point DLH Hydraulic Ret.Packer i`' i iii:*11 15 11,408' 1.875" 3.063" X Landing Nipple "ii, II 16 11,440' 1.995" 3.063" Pump out plug w/WL re-entry guide mi 12 t '"13 'i; I Capillary String Proposed to Install I 41 I 14 3/8" 2205 Stainless Steel(11,500'spool) Top Bottom MD 0' 11,405' aTVD 0' 10,222' 4 '_' 15 PERFORATIONS 1 16 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes V Iwo H-6 11,822 11,830 10,444' 10,448' TCP 2-3/4"6spf 60 deg H-7/8 11,857' 11,956' 10,462' 10,513' TCP 2-3/4"6spf 60 deg 4- + H-9 12,013' 12,032' 10,542' 10,552' TCP 2-3/4"6spf 60 deg 12,088' 12,146' 10,581' 10,610' TCP 2-3/4"6spf 60 deg 4-1/2" .. a H-10 PBTD=12,290'MD/10,681'TVD 12,212' 12,232' 10,643' 10,653' TCP 2-3/4"6spf 60 deg TD=12,425'MD/10,746'TVD Max dev.71.85 deg @ 10,180'MD Downhole Proposed Updated by JEK 5/3/16 STATE OF ALASKA itiIVitilaai tt; ALOA OIL AND GAS CONSERVATION COMWSION APR 2 9 2016 REPORT OF SUNDRY WELL OPERATIONS IC 1.Operations Abandon ❑ Plug Perforations ❑ Fracture Stimulate Li Pull TubingA J Operations shutdown Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ ?rforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: Pull Cap String_ ❑✓ 2.Operator 4.Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska,LLC Development ❑✓ Exploratory ❑ 212-143 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20237-01 7.Property Designation(Lease Number): 8.Well Name and Number: FEDA028399/FEDA028997 Soldotna Creek Unit(SCU)44-33 9. Logs(List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Swanson River/Hemlock Oil 11.Present Well Condition Summary: Total Depth measured 12,425 feet Plugs measured N/A feet true vertical 10,746 feet Junk measured N/A feet Effective Depth measured 12,290 feet Packer measured 11,402 feet true vertical 10,681 feet true vertical 10,221 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 337' 20" 337' 337' Surface 3,408' 10-3/4" 3,408' 3,408' 3,130 psi 1,580 psi Intermediate Production 9,015' 7-5/8" 9,015' 8,963' 6,020 psi 3,400 psi Liner 3,658' 4-1/2" 12,423' 10,746' 8,430 psi 7,500 psi Perforation depth Measured depth See Attached Schematic u q� True Vertical depth See Attached Schematic r !' � MA Tubing(size,grade,measured and true vertical depth) 2-7/8"x 2-3/8" 6.5#x 4.7#/L-80 x L-80 11,440'MD 10,242'TVD Tripoint DHL Packers and SSSV(type,measured and true vertical depth) Hyd Ret;N/A 11,402'MD 10,221'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: 46 140 161 1500 325 Subsequent to operation: 36 31 202 1320 250 14.Attachments(required per 20 AAC 25.070.25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations El Exploratory Development IA Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil 0 Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ 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 Joe Kaiser-777-8393 Email jkaiser(@.hilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature 6/. /4Phone 907-777-8405 Date � 5 "3i Form 10-404 Revised 5/2015 ` �14Submit Original Only RBDMS u- 1\;r.M 0 2 2016 • • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SCU 44-33 NA 50-133-20237-01 212-143 4/23/16 4/26/16 Daily Operations: 04/23/2016-Saturday Pump 67 BBLS hot oil down tbg. 04/26/2016-Tuesday Arrive on site. Perform 1SA. Move in pit liner and equipment to pad.Take 40 bbl crude to pad. Rig up PIT to 2,500 psig. Start pumping at 1.6 BPM @ 180 deg @ 250 psig. Well on vac at 15 bbl. Pumped total of 40 bbl down tubing. Rig down hot oil truck. Rig up and pull on coil, 2,000 lbs. Rig up sheaves and pull coil with spooling unit. POOH with 8,750' of the 3/8" coil. RDMO. • • Soldotna Creek Unit H Well SCU 44-33 ACTUAL SCHEMATIC Completion 212-1 Sate: 11/29/12 PTD Hikorp Alaska,LLC API: 50-133-20237-01 164.6'Above MSL KB-THF:20' CASING DETAIL 'i 1 " 41 L Size Type Wt Grade Conn. ID Top Btm 20" kt 20" Conductor Surf 337' 't' !y 10-3/4" Surf.Csg 40.5 J-55 Buttress 10.05 Surf 3,408' i 33.7 N-80 Buttress 6.64" Surf 78' 26.4 N-80 Buttress 6.844" 78' 4,621' 10-3/4" + ', 7-5/8" Intermediate 29.7 N-80 Buttress 6.75" 4,621' 6,111' ill'0 33.7 N-80 Buttress 6.64" 6,111' 7,117' 10 2 33.7 P-110 Buttress 6.64" 7,117 9,015' r'' 14-1/2" Prod Lnr 12.6 N-80 H-521 3.958" 8,765' 12,423' ''14. '.44 Window Depths are 9,001'(TOP)and 9,015'(BOTTOM) 0, r. TUBING DETAIL s 2-7/8" Production 6.5 L-80 8rd EUE 2.441 Surf 9,028' ++ 2-3/8" Production 4.7 L-80 8rd EUE 1.995 9,028' 11,440' 4 I A JEWELRY DETAIL No. Depth ID OD Item " 5 4' 1 19' 2.44" - Tubing Hanger a: .0 to 2 1,912' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port "i ",� 3 3,484' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 10 port ' I 4 4,800' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port 6 w 5 5,991' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port ' i 6 7,019' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 7 7,795' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 16 port 4,"' 7 I " 8 8,508' 2.44" 4.500" 2-7/8"SFO-1 Mandrel 8RD 16 port a t+ 9 8,709' 2.313" 3.688" X Landing Nipple ry 8 - *. 10 9,067' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel "it lir t + 9 11 9,627' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 4$1 12 10,572' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 7-5/8" G r al ;'u 10 13 11,392' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel ' 14 11,402' 1.94" 3.750" Tri-point DLH Hydraulic Ret.Packer i° ' i,`11 15 11,408' 1.875" 3.063" X Landing Nipple V; 1 1 16 11,440' 1.995" 3.063" Pump out plug w/WL re-entry guide ' 12 - ' i '*13 141#41 i, It,14 N11 4� -1 :r 15 PERFORATIONS 16 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes H-6 11,822 11,830 10,444' 10,448' TCP 2-3/4"6spf 60 deg H-7/8 11,857' 11,956' 10,462' 10,513' TCP 2-3/4"6spf 60 deg e 44 H-9 12,013' 12,032' 10,542' 10,552' TCP 2-3/4"6spf 60 deg ' 4-1/2" H-10 12,088' 12,146' 10,581' 10,610' TCP 2-3/4"6spf 60 deg PBTD=12,290'MD/10,681'TVD 12,212' 12,232' 10,643' 10,653' TCP 2-3/4"6spf 60 deg TD=12,425'MD/10,746'TVD Max dev.71.85 deg @ 10,180'MD Downhole Revised: 10/16/14 Updated by JEK 4-27-2016 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. eQj.c - 1_ 4.3 Well History File Identifier Organizing (done) ❑ Two-sided E Rescan Needed RESCAN: OVERSIZED: NOTES: 1� or Items: ❑ s: Ø'GrayscaleM Items: Logs: ❑ Poor Quality Originals: ❑ Other: ❑ Other: BY: AM Date: ! 4 /s/ we Project Proofing �y►/� I BY: Maria Date: i _Jd� 14 /s/ Y I/I Scanning Preparation t x 30 = ._O + /`! = TOTAL PAGES 135 (Count does not include cover sheet) 0 BY: Maria )4 / /s/Date: � u Production Scanning Stage 1 Page Count from Scanned File: l 3 Y0 (Count does include cov sheet) Pa.e Count Matches Number in Scanning Preparation: YES NO BY: eg. 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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: 392 53 184 1,420 160 Subsequent to operation: 378 0 232 1,420 180 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development Q Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil Q Gas ❑ WDSPL❑ GSTOR 0 WINJ ❑ WAG ❑ GINJ 0 SUSP p SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 314-497 Contact Stan Porhola Email sDorhola QchiIcorp.com Printed Name Stan Porhola Title Operations Engineer Signature Phone 907-777-8412 Date it/e V)I..( / RBE MS IINOV - 4zo14h Form 10-404 Revised 10/2012 G ' til'1 P O /4( Submit Original Only Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 44-33 50-133-20237-01 212-143 10/1/14 10/16/14 Daily Operations: 10/01/2014-Wednesday Rig Up Cap String Truck. Rig up lubricator and 2-7/8" 8RD adapter. Test to 3,000 psi -test OK. RIH w/3/8" capillary string. Unable to work deeper than 9,622'. Pick up and set capillary string @ 9,600'. String pre-loaded with DMO 7037. RDMO Cap String Truck. 10/16/14-Thursday Rig Up Cap String Truck. Rig up lubricator and 2-7/8" 8RD adapter. Test to 3,000 psi -test OK. Pull capillary string from 9,600'to 8,750' (out of the 2-3/8", up into the 2-7/8"). RDMO Cap String Truck. Soldotna Creek Unit Well SCU 44-33 • Completion Date: 11/29/12 ACTUAL SCHEMATIC PTD: 212-143 Hilcorp Alaska,tu: API: 50-133-20237-01 164.6'Above MSL KB-THF:20' CASING DETAIL JI 1 , Size Type Wt Grade Conn. ID Top Btm 20 a 20" Conductor Surf 337' r++ 10-3/4" Surf.Csg 40.5 J-55 Buttress 10.05 Surf 3,408' 33.7 N-80 Buttress 6.64" Surf 78' 26.4 N-80 Buttress 6.844" 78' 4,621' 10-3/4" u ? 7-5/8" Intermediate 29.7 N-80 Buttress 6.75" 4,621' 6,111' Rii�I 33.7 N-80 Buttress 6.64" 6,111' 7,117' 2 , 33.7 P-110 Buttress 6.64" 7,117 9,015' I. 4-1/2" Prod Lnr 12.6 N-80 H-521 3.958" 8,765' 12,423' Window Depths are 9,001'(TOP)and 9,015'(BOTTOM) 3 ` i rw4 Fv: TUBING DETAIL 2-7/8" Production 6.5 L-80 8rd EUE 2.441 Surf 9,028' 6 4 2-3/8" Production 4.7 L-80 8rd EUE 1.995 9,028' 11,440' f•1 i * v t I JEWELRY DETAIL No. Depth ID OD Item `, 5 1 19' 2.44" Tubing Hanger "/' /y 2 1,912' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port ;l 3 3,484' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port ' • 4 4,800' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port ill 6 5 5,991' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port N p 6 7,019' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port 4 +,, 7 7,795' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 16 port 78 8,508' 2.44" 4.500" 2-7/8"SF0-1 Mandrel 8RD 16 port 14 9 8,709' 2.313" 3.688" X Landing Nipple a 8 = 1 + 10 9,067' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 10 r 9 11 9,627' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel me 12 10,572' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 7-5/8" �- i , i 0 13 11,392' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 1 t3' f T 14 11,402' 1.94" 3.750" Tri-point DLH Hydraulic Ret.Packer IC v,11 15 11,408' 1.875" 3.063" X Landing Nipple 11 ii 16 11,440' 1.995" 3.063" Pump out plug w/WL re-entry guide a q 12 `A FFbb�°13 y, III Lo 5: /1. Capillary String Proposed to Install 1 I I#.114 3/8" 2205 Stainless Steel(11,500'spool) • R I Top Bottom MD 0' 8,750' TVD 0' 8,720' " • i� 15 PERFORATIONS I16 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes H-6 11,822 11,830 10,444' 10,448' TCP 2-3/4"6spf 60 deg 6 &le H-7/8 11,857' 11,956' 10,462' 10,513' TCP 2-3/4"6spf 60 deg H-9 12,013' 12,032' 10,542' 10,552' TCP 2-3/4"6spf 60 deg ti, 12,088' 12,146' 10,581' 10,61 TCP 2-3/4"6spf 60 deg 4-1/2" a► H-10 PBTD=12,290'MD/10,681'TVD 12,212' 12,232' 10,643' 10,653' TCP 2-3/4"6spf 60 deg TD=12,425'MD/10,746'ND Max dev.71.85 deg @ 10,180'MD Downhole Revised: 10/16/14 Updated by STP 10/20/14 OF Th, • 4,,PN1%%%s, THE STATE arke. GEE Of �- 333 Wesi Seventh Avenue ��_, GOVERNOR SLAM PARN1:1.i. Anchorage, AlasKa 99501-3572 Moir 907 279 1433 t LAS ray. 9(17 27. 7' 4: Stan Porhola Operations Engineer ^ t L-3 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, Soldotna Creek Unit 44-33 Sundry Number: 314-497 Dear Mr. Porhola: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, /J 72_z_074,‘___ athy P Foerster �, Chair DATED this `�'" day of September, 2014. Encl. RECEIVED STATE OF ALASKA SEP 0 2 2014 ALASKA OIL AND GAS CONSERVATION COMMISSION D51�'� SI 14I IIA APPLICATION FOR SUNDRY APPROVALS AOGCC 20 MC 25.280 1.Type of Request: Abandon❑ Plug for Redrill ❑ Perforate New Pool❑ Repair Well❑ Change Approved Program ❑ Suspend❑ Plug Perforations❑ Perforate❑ Pull Tubing❑ Time Extension ❑ Operations Shutdown❑ Re-enter Susp.Well ❑ Stimulate❑ Alter Casing❑ Other: Install Capsiring E• 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC Exploratory ❑ Development E . 212-143 • 3.Address: Stratigraphic ❑ Service ❑ 6.API Number. 3800 Centerpoint Drive,Suite 1400 Anchorage,Alaska 99503 50-133-20237-01 - 7.If perforating: 8.WeN Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 123B ' Will planned perforations require a spacing exception? Yes ❑ No ESoldotna Creek Unit(SCU)44-33 ' 9.Property Designation(Lease Number): 10.Field/Pool(s): FEDA028399/FEDA028997 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): 12425 10746 12290 10681 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 337' 20" 337' 337' Surface 3,408' 10-3/4" 3,408' 3,408' 3,130 psi 1,580 psi Intermediate Production 9,015' 7-5/8" 9,015' 8,963' 6,020 psi 3,400 psi Liner 3,658' 4-1/2" 12,423' 10,746' 8,430 psi 7,500 psi Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See attached schematic See attached schematic 2-7/8"x2-3/8" 6.5#x 4.7#/L-80 x L-80 11,440 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): Tripoint DLH Hyd Ret;N/A 11,402'MD/10,221'TVD;N/A 12.Attachments. Description Summary of Proposal ❑✓ 13.Well Class after proposed work. Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development❑✓ Service ❑ 14 Estimated Date for 15.Well Status after proposed work: 9/5/2014 Commencing Operations: Oil D• Gas ❑ WDSPL ❑ Suspended 0 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned 0 Commission Representative: GSTOR 0 SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhola Phone: 907-777-8412 Email snorholae.hilcorD.com Printed Name Stan Porhola Title Operations Engineer Signature c>, 9 Phone Date / � 907-777-8412 `fit/L t ✓ COMMISSION USE ONLY T Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ` _ i 4--kal Plug Integrity 0 BOP Test 0 Mechanical Integrity Test ❑ Location Clearance ❑ Other: Spacing Exception Required? Yes ❑ No i Subsequent Form Required: I U —Lfc,— APPROVED BY Approved by:CA fi942.&t...24,....._,. COMMISSIONER THE COMMISSION Date: q- i-/Submit Form and RBCMSF 1q-ao34R . 2 oi2q'2) q 5.1`1 App p�i t�is li 12 months from the date of approval. Attachments in Duplicate L I' Nl�__ I I ,fr Mit , .b r 3 // Well Prognosis Well: SCU 44-33 Hilcorp Alaska,LL' Date:9/02/2014 Well Name: SCU 44-33 API Number: 50-133-20237-01 Current Status: Gaslift Oil Well Leg: N/A Estimated Start Date: September 5th, 2014 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 212-143 First Call Engineer: Stan Porhola (907)777-8412 (0) (907) 331-8228 (M) Second Call Engineer: Paul Chan (907)777-8333 (0) (907)444-2881 (M) AFE Number: Current Bottom Hole Pressure: — 1,982 psi @ 10,592' TVD (Based on static survey 4/08/14.) Maximum Expected BHP: — 1,982 psi @ 10,592' TVD (Based on static survey 4/08/14.) Max.Allowable Surface Pressure: —0 psi (2,400 psi gaslift) (Based on actual reservoir conditions and min water cut of 25% (0.380psi/ft) Brief Well Summary Swanson River 24-33 was drilled as a grassroots well in 1972 to target H-1 thru H-5 and H-8 oil reserves in the middle and lower parts of the Hemlock formation.The H-8 was determined to be wet. In 1975, a workover was completed to replace tubing. Coil tubing was used in 1982 to clean out sand production.The wellbore was plugged back in 1993 to isolate the Hemlock. A 9.7 ppg brine was left in the hole.The kill string tubing was pulled in September 2012 and the well sidetracked using the Arctic Fox drilling rig in October 2012 as SCU 44- 33.The Williams#405 WO rig completed the well in November 2012 with perforations in the lower Hemlock, H-6 thru H-10. The purpose of this work/sundry is to install a capstring to manage emulsion issues. Notes Regarding Wellbore Condition • Wellbore is highly deviated with a maximum hole angle of 71.85° @ 10,180' MD. • New completion ran in November 2012. Min ID is 1.875"XN profile at 11,408' MD. Capstring Procedure: 1. MIRU Cap String Truck, PT lubricator to 3,000 psi Hi 250 Low. 2. Install new wellhead packoff. a. Current tree cap is 3.5" Bowen w/2-9/16"flanged connections. 3. PU 3/8" capillary string. RIH and set at+/- 11,405'. 4. Set spool of remaining line near well. 5. Rig down Cap String Truck. 6. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic • Soldotna Creek Unit Well SCU 44-33 SCHEMATIC Completion Date:11/29/12 PTD: 212-143 mi.,",Unaa.H.( API: 50-133-20237-01 164.6'Above MSL CASING DETAIL KB-THF:20' Size Type Wt Grade Conn. ID Top Btm 41 IV 1 - L� 20" Conductor - - - - Surf 337' 20 10-3/4" Surf.Csg 40.5 J-55 Buttress 10.05 Surf 3,408' k* w 33.7 N-80 Buttress 6.64" Surf 78' {"� s 26.4 N-80 Buttress 6.844" 78' 4,621' p , a: 7-5/8" Intermediate 29.7 N-80 Buttress 6.75" 4,621' 6,111' 10-3/4" or, 33.7 N-80 Buttress 6.64" 6,111' 7,117' ll e; q 33.7 P-110 Buttress 6.64" 7,117 9,015' 13' 2 ': i 4-1/2" Prod Lnr 12.6 N-80 H-521 3.958" 8,765' 12,423' L , Window Depths are 9,001'(TOP)and 9,015'007-TOM li3 MIKA TUBING DETAIL 3 � i 2-7/8" Production 6.4 L-80 8rd EUE 2.441 Surf 9,028' ii' 4 e! 2-3/8" Production 4.6 L-80 8rd EUE 1.995 9,028' 11,440' 4 r.11 .4, 4 ,= i 'I w; - v JEWELRY DETAIL „ilA til No. Depth ID OD Item 5 Ns i I 1 19' 2.44" - Tubing Hanger 4 o 2 1,912' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port i° ', 3 3,484' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port 4 4,800' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port i-" 5 5,991' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port it 6 ; .. 6 7,019' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 7 7,795' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 16 port •e s 7 8 8,508' 2.44" 4.500" 2-7/8"SF0-1 Mandrel 8RD 16 port y 9 8,709' 2.313" 3.688" X Landing Nipple or I 8 10 9,067' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 9 11 9,627' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 12 10,572' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 7-5/8IIIIC " 10 13 11,392' - 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel I14 11,402' 1.94" 3.750" Tri-point DLH Hydraulic Ret.Packer . k,11 15 11,408' 1.875" 3.063" X Landing Nipple ' U 16 11,440' 1.995" 3.063" Pump out plug w/WL re-entry guide i.i at II'12 X13 i i I $14 PERFORATIONS • F Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes " H-6 11,822 11,830 10,444' 10,448' TCP 2-3/4"6spf 60 deg `. H-7/8 11,857' 11,956' 10,462' 10,513' TCP 2-3/4"6spf 60 deg . 16 H-9 12,013' 12,032' 10,542' 10,552' TCP 2-3/4"6spf 60 deg i 12,088' 12,146' 10,581' 10,610' TCP 2-3/4"6spf 60 deg H-10 it 12,212' 12,232' 10,643' 10,653' TCP 2-3/4"6spf 60 deg s t. 4-1/2" A il. PBTD=12,290' TD=12,425/ND=10,746' Max dev.71.85 deg @ 10,180'MD Updated by TDF 12/27/12 Soldotna Creek Unit • Well SCU 44-33 PROPOSED SCHEMATIC PTDp212-1 3 Date: 11/29/12 Hilcorp Aleeka,I.I,c API: 50-133-20237-01 164.6'Above MSL KB-THF:20' CASING DETAIL '' 1 "1 L Size Type Wt Grade Conn. ID Top Btm 20" to 20" Conductor - - - Surf 337' • t• 10-3/4" Surf.Csg 40.5 1-55 Buttress 10.05 Surf 3,408' iF33.7 N-80 Buttress 6.64" Surf 78' 26.4 N-80 Buttress 6.844" 78' 4,621' 10-3/4" 7-5/8" Intermediate 29.7 N-80 Buttress 6.75" 4,621' 6,111' t 33.7 N-80 Buttress 6.64" 6,111' 7,117' "4 2 Mir r iki til 33.7 P-110 Buttress 6.64" 7,117 9,015' ' dth� 4-1/2" Prod Lnr 12.6 N-80 H-521 3.958" 8,765' 12,423' % fJ Window Depths are 9,001'(TOP)and 9,015YBOTTOM) ; t" rt TUBING DETAIL i 2-7/8" Production 6.5 L-80 8rd EUE 2.441 Surf 9,028' 2-3/8" Production 4.7 L-80 8rd EUE 1.995 9,028' 11,440' 'w' 4 fa i 4; L* JEWELRY DETAIL q No. Depth ID OD Item t,�', 5 1 19' 2.44" - Tubing Hanger 2 1,912' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port �.4 "A 3 3,484' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 10 port T' 4 4,800' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port' 5 5,991' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 6 i 6 7,019' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 7 7,795' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 16 port 7 aw ' ' 8 8,508' 2.44" 4.500" 2-7/8"SF0-1 Mandrel 8RD 16 port 4 i f 9 8,709' 2.313" 3.688" X Landing Nipple 8MR ' Oji 10 9,067' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel t.- 9 11 9,627' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel i12 10,572' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 7-5/8" 2/1" III ill!lt o. 10 13 11,392' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 14 11,402' 1.94" 3.750" Tri-point DLH Hydraulic Ret.Packer ft' p,,11 15 11,408' 1.875" 3.063" X Landing Nipple • 12 16 11,440' 1.995" 3.063" Pump out plug w/WL re-entry guide 4 i X413 !,I ' Capillary String Proposed to Install I 114 3/8" 2205 Stainless Steel(11,500'spool) Top Bottom MD 0' 11,405' i• III TVD 0' 10,222' d '`- PERFORATIONS i 15 16 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes k° } H-6 11,822 11,830 10,444' 10,448' TCP 2-3/4"6spf 60 deg H-7/8 11,857' 11,956' 10,462' 10,513' TCP 2-3/4"6spf 60 deg . 17F aA H-9 12,013' 12,032' 10,542' 10,552' TCP 2-3/4"6spf 60 deg 4-1/2°° H-10 12,088' 12,146' 10,581' 10,610' TCP 2-3/4"6spf 60 deg PBTD=12,290'MD/10,681'TVD 12,212' 12,232' 10,643' 10,653' TCP 2-3/4"6spf 60 deg TD=12,425'MD/10,746'TVD Max dev.71.85 deg @ 10,180'MD Downhole Proposed Updated by STP 9/02/14 Lar.,.on Ellison Hilcorp Alaska, LLC GeoTech II 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8339 Hiir,m Alawl.m_ Fax: 907 777 8510 E-mail: Jellison@hilcorp.com � R CE1 DATE 09/09/2013 Sip 0 9 20 To: Alaska Oil & Gas Conservation Commission AOGCG Howard Okland 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTA SRU 44-33 Prints: BestDT* SonicScope 475 5in MD BestDT* QC plot— SonicScope 475 5in MD CD: L, Hilcorp_SCU44-33_BestDT_Monopole_9500 12330.dlis 11/1/2012 10:58 AM DLIS File 189 KB Hilcorp_SCU 44-33_BestDT_Monopole_9500 12330 114/201210:57 AM LAS File 335 KB ▪ Hilcorp_SCU 44-33_BestDT_Monopole_9500 12330 9/6/2013 11:32 AM Adobe Acrobat D... 394 KB Hilcorp_5CU 44-33_BestDT_Monopole_9500 12330 11/1!2012 9:53 AM PDS File 528 KB ▪Hilcorp_SCU 44-33_QC_Monopole 9500_12330 9+6/201311:32 AM Adobe Acrobat D... 8,011 KB Hilcorp_SCU 44-33_QC_Monopole_9500_12330 11,11/2012 10:03 AM PDS File 3,530 KB Please include current contact information if different from above.1 Please acknowledge receipt by signing and returning one copy of this transmittal or� FAX to 907 777.8337 Received By n�/�. /, Date: I, J rte.• /1 •`�]L :013 � C4iDebra OudeanHilcorp Alaska, LLC � ( �GeoTech II 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 MAY 1 3 Tele: 907 777-8337 Fax: 7 E-mail: @h0ilcorp.com ffihnrp alnrku,1. A 212- 'V DATE 5/13/2013 To: AOGCC Makana Bender 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL SCU 44-33 Prints/CD Efflux)) SCU 44-33 2MD 4MPR jC 001.-.124Z5.1PDF Nikon) SCU 44-13 2fVD 4MPR TC 91X)1-124ZZPDF , Hiloorp SCU 44-33_4MPR_TC_91X1:1-:L242S.Jas Hilcorp SCU 44-33 :SMD4MPRJC 91X).1-:1242 PDF Hilcra39CU 44-:3.3_:5fV174MI4?_TC91X)L-.L242.5PDF Hilcorp_SCU 44-33, Final Survey 91X0.1-1.24Z5.pdf Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: 11Date: McMains, Stephen E (DOA) From: Paul Mazzolini [pmazzolini@hilcorp.com] Sent: Friday, January 11, 2013 4:02 PM To: McMains, Stephen E (DOA) Cc: Luke Keller Subject: FW: SCU 44-33 (PTD#: 212-143) Governmental Section Coordinates Steve, My apologies as you were inadvertently missed on the initial email. Please see email below with the corrected coordinates for top productive zone and BHL. Please contact me with any questions. Regards Paul From: Luke Keller Sent: Friday, January 11, 2013 2:34 PM To: steve.daviesOalaska.gov; Guy Schwartz (guv.schwartz(aalaska.gov) Cc: Paul Mazzolini; Kate Kaufman; Michael Anderson - (C); David Duffy Subject: SCU 44-33 (PTD#: 212-143) Governmental Section Coordinates Steve, There has been a correction to the "As-Built" coordinates for SCU 44-33. No change to surface location, but the TPI and BHL coordinates have been modified from what was originally submitted with the 10-407. The below calculations have been done by our in-house GIS Engineer(Michael Anderson)to the best of our ability. Revised coordinates are as follows: 4a. Location of Well(Governmental Section): Surface: 876'FNL,212T FWL, Sec 4,17N,R9W, SM Top of Productive Horizon: 85'FSL,868'FEL, Sec 33,T8N, R9W, SM,AK Total Depth: 154'FSL, 399'FEL,Sec 33,TBN,R9W,SM,AK 4b. Location of Well(State Base Plane Coordinates, NAD 27): Surface: x- 344467.3 y- 2460328 Zone- 4 TPI: x- 346761.9 y- 2461259.6 Zone- 4 Total Depth: x- 347232.23 y- 2461322.15 Zone- 4 18. Directional Survey: Yes 2- No 0- (Submit (Submit electronic and printed information per 20 AAC 25.050) Let me know if you would like the 10-407 resubmitted, or if you have any additional questions. Thanks Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 1 , " STATE OF ALASKA ALAbI.A OIL AND GAS CONSERVATION COMM-SION WELL COMPLETION OR RECOMPLETION REPORT AND LOG la.Well Status: Oil 0 • Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ lb.Well Class: 20MC 25 105 20MC 25.110 . Development 0 • Exploratory ID GINJ 0 WINJ 0 WAG 0 WDSPL 0 No.of Completions: E & Service ❑ Stratigraphic Test ❑ 2.Operator Name: 5.Date Com , usp.,or iv 12.Permit to Drill Number: lit/ca._ Hilcor Alaska,LLC Aband.:�1 2012 t-' 212143 • ,$ 6 p ID 3.Address: 6.Date Spudded: 13.API Number: eb2J 3800 Centerpoint Drive,Suite 100,Anchorage,AK 99503 10/12/2012 50-133-20237-01-00 • A'� 4a.Location of Well(Governmental Section): 7.Date TD Reached: 14.Well Name and Number: S Surface: 876'FNL,2127'FWL,Sec 4,T7N,R9W,SM 10/25/2012 SCU 44-33 • Top of Productive nzon: m 8.KB(ft above MSL): 183.2 15.Field/Pool(s): g56' 8 6 O ,^29CZ FEL,Sec's Y4ZN,R9W,SM IPS GL(ft above MSL): 164.6 Swanson River Field/ Total Depth: i51 f 39j 9.Plug Back Depth(MD+TVD): Hemlock Oil Pool 1.1,Z FSL,732'FEL,Sec 33,T8N,R9W,SM 12,290/10,681 4b. Location of Well(State Base Plane Coordinates,NAD 27): m 10.Total Depth(MD+TVD): 16.Property Designation: Surface: x- 344467.3 y- 2460328 1 4 Zone- 4 . 12,425/10,746 • FED A028399&FED A028997 6 TPI: x- 346761.9 y- 24612 Zone- 4 11.SSSV Depth(MD+TVD): 17.Land Use Permit: Total Depth: x- 3473- y- 24613 Zone- 4 N/A N/A 18.Directional Survey: Yes I] No 0 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: Mud Log,Gamma Ray,Resistivity,Density,Neutron,and Sonic logs(all LWD) 9,001 MD/8,950 ND 23. CASING,LINER AND CEMENTING RECORD WT.PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 20" Surf 337 Surf 337 10-3/4" 40.5 J-55 Surf 3,408 _ Surf 3,408 7-5/8" 33.7,26.4,29.7 N-80,P-110 Surf 9,018 Surf 8,967 • W kz,, 4,4 ter g 4-1/2" 12.6 N-80 8,767 12,423 8,734 10,747 6-1/8" 100 bbls 15.6 ppg • 24.Open to production or injection? Yes 0 No 0 25. TUBING RECORD If Yes,list each interval open(MD+TVD of Top and Bottom;Perforation Size and SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Number): 2-7/8" 9,028' Please see attached schematic for perforation data. 2-3/8" 11,440' 11,402710,222' 26. ACID,FRACTURE,CEMENT SQUEEZE,ETC. RECEIVEDWas hydraulic fracturing used during completion? Yes❑ No 0 DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED ; -- . JAN 022013 � �. AOGCC O _ 27. ' PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 12/1/2012 Flowing Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 12/19/2012 2.17 Test Period 124.5 87 2.5 N/A 698 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: •Oil Gravity-API(torr): Press. 180 1,200 24-Hour Rate - 1,379 963 28 34.9 @64"F 28. CORE DATA Conventional Core(s)Acquired? Yes 0 No 0 Sidewall Cores Acquired? Yes 0 No 0 If Yes to either question,list formations and intervals cored(MD+TVD of top and bottom of each),and summarize lithology and presence of oil,gas or water (submit separate sheets with this form,if needed).Submit detailed descriptions,core chips,photographs and laboratory analytical results per 20 AAC 25.071. RBDMS JAN 0 3 2014 G Form 10-407 Revised 10/2012 CONTINUED ON REVERSE v Z,S I3 Submit original only 0 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested?El Yes 0 No If yes, list intervals and formations tested,briefly summarizing test results.Attach separate sheets to this form, if GIST 11,318 10,177 needed,and submit detailed test information per 20 AAC 25.071. G2ST 11,377 10,208 HKT 11,519 10,284 Tested comingled fluids from Hemlock benches together. H2ST 11,604 10,329 H3ST 11,664 10,361 H4ST 11,706 10,383 H5ST 11,735 10,398 H6ST 11,821 10,443 H7ST 11,857 10,462 H9ST 12,012 10,542 HI OST 12,085 10,579 H11 ST 12,320 10,696 Hemlock 12,425 10,748 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: q1 07-777-B369 Email: pmazzolini@hilcorp.com Printed Name: Paul Mazzolini Title: Drilling Manager __Signature: �-�C../ '/ ` Phone: 907-777-8369 Date: 12/31/2012 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 ND for the top and base of permafrost in Box 28. Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift, Rod Pump,Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 10/2012 Soldotna Creek Unit II Well SCU 44-33 SCHEMATIC Completion Date: 11/29/12 PTD: 212-143 Hi!carp Alaska,LLC. API: 50-133-20237-01 164.6'Above MSL CASING DETAIL KB-THF:20' Size Type Wt Grade Conn. ID Top Btm 1 1•' 1 L 20" Conductor - - - Surf 337' 20' Q � il, 10-3/4" Surf.Csg 40.5 J-55 Buttress 10.05 Surf 3,408' .,1i:" ' 33.7 N-80 Buttress 6.64" Surf 78' "l i 26.4 N-80 Buttress 6.844" 78' 4,621' !; r, ). a 7-5/8" Intermediate 29.7 N-80 Buttress 6.75" 4,621' 6,111' 10-3/4" , ,',j 33.7 N-80 Buttress 6.64" 6,111' 7,117' 11 33.7 P-110 Buttress 6.64" 7,117 9,015' 2 1 4-1/2" Prod Lnr 12.6 N-80 H-521 3.958" 8,765' 12,423' I Window Depths are 9,001'(TOP)and 9,015'(BOTTOM) I,, ' 3 TUBING DETAIL '`? ,i 2-7/8" Production 6.4 L-80 8rd EUE 2.441 Surf 9,028' 4 i 2-3/8" Production 4.6 L-80 8rd EUE 1.995 9,028' 11,440' r; 1. 4 .4 i 5' 4.. JEWELRY DETAIL `, ii No. Depth ID OD Item I' 5 1 1 19' 2.44" - Tubing Hanger I. ., 1 2 1,912' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 10 port • 3 3,484' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 10 port k", 4 4,800' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port 5 5,991' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port ri! 6 +y i 6 7,019' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 12 port e el *1 7 7,795' 2.44" 4.750" 2-7/8"SFO-1 Mandrel 8RD 16 port `.(DpY ):t 7 e 8 8,508' 2.44" 4.500" 2-7/8"SFO-1 Mandrel 8RD 16 port h Oyq a L `, 9 8,709' 2.313" 3.688" X Landing Nipple "\0.5 a 8 • 10 9,067' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel ,t k9 11 9,627' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 7-5/V \le w' 5/8" / 12 10,572' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 10 13 11,392' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 14 11,402' 1.94" 3.750" Tri-point DLH Hydraulic Ret.Packer //��L ia 11 15 11,408' 1.875" 3.063" X Landing Nipple �f"� 16 11,440' 1.995" 3.063" Pump out plug w/WL re-entry guide KA 12 k 4 13 kR4 ?.b'� rI 14 PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes ri { erg H-6 11,822 11,830 10,444' 10,448' TCP 2-3/4"6spf 60 deg !a �-'13 H-7/8 11,857' 11,956' 10,462' 10,513' TCP 2-3/4"6spf 60 deg T4 16 H-9 12,013' 12,032' 10,542' 10,552' TCP 2-3/4"6spf 60 deg ii tlii 12,088' 12,146' 10,581' 10,610' TCP 2-3/4"6spf 60 deg " �j- H-10 !L —T+'✓L 12,212' 12,232' 10,643' 10,653' TCP 2-3/4"6spf 60 deg I. k -57 4-1/2" L PBTD=12,290' TD=12,425/ND=10,746' Max dev.71.85 deg @ 10,180'MD Updated by TDF 12/27/12 11 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 44-33(Sidetrack of SRU 24-33) 50-133-20237-01-00 212143 9/19/12 Daily Operations: 10/04/2012-Wednesday Rack topdrive in cradle,lower bottom torque tube,move frac tanks and pump.RD plumbing between modules.Peak crane and two trucks on location at noon,held PJSM with entire rig team,remove topdrive from rig floor,ship out topdrive gen set,lower centrifuge house and ship out,set down mud lab and ship out,lower roof caps over drawwork,ship out cuttings box,remove augers,ship rock washer,lay down degasser,swivel standpipe gooseneck,scope down derrick and lower mast. 10/05/2012-Thursday Secure derrick climber counter weight,secure kelly and cement hoses,chain c-section,disconnect electric lines,secure tong hanging lines, LD tongs,torque tube,trash cans, bails,stairs. Install I-beams, LD derrick, unbolt driveline, secure doghouse. Move modules to stage area, move mats to 44-33. Retract doghouse, lower doghouse, remove handrails, remove mud line, remove beaverslide, remove standpipe manifold,stage degasser,augers, boiler house,fuel tank,gen sets 1 &2, pump houses 1&2,stage pipeshed,stage pit modules.2nd crane on location at 20:00 hrs,prep cellar on 44-33.Set up light plants on 44-33,prep to lay liner and felt. 10/06/2012-Friday Lay felt and liner on 44-33 pad,lay matting,locate crew at 23B-22 to RU and remove derrick. PJSM with Peak operators.Set derrick on truck and road to 44-33.Move pipeshed to 44-33,move sub base to 44-33,move remaining mats to 44-33.Assemble sub base over well,spot pit modules,spot derrick,spot doghouse and water tank,spot pump modules,gen sets, boiler house and fuel tank. Hook up fuel and electric lines.Start gen set,cont RU,prep to raise mast,tie in equalizer lines,suction and discharge lines in pump modules. 10/07/2012-Saturday Raise mast,string blocks,scope up derrick,spot 4 pipeshed modules,spot degasser,spot rock washer,install augers,spot centrifuge,install lower torque tube,stage topdrive cradle on rig floor,RU topdrive,spot genshack for topdrive, install roof caps over draw-works,spot mud lab, load water tank,stage windwall section on pad,spot foreman shacks on pad,install HandyBerm.Clean and organize doghouse,change oil in topdrive, RU lower derrick ladder. Prep pits to take on mud from tank farm, install chains/binders on water tank, unload pipeshed, install choke line from choke house,clean pump rooms. 10/08/2012-Sunday Spot and level Foreman shacks, spot sewer and water tanks, RU new koomey unit,set windwalls with crane,set cattle chute over beaver slide, hang service loop, load 600 bbls 10.9 ppg mud in pits,function check surface lines. RU top drive gen set,function check topdrive. ND cap on well, NU 11" BOP stack, install steps and landings around rig, spot cuttings box, install koomey lines, bolt up choke and kill lines, install flow nipple, install flow paddle, install saver sub, MU kelly hose, centrifuge mud from 10.9 to 9.3 ppg, continue working on new koomey unit(control box issues). 10/09/2012-Monday Finish up NU BOP,install KatchKan on stack,rebuild 4"standpipe valve,offload mud products, RU test pump and manifold,install test plug, fill stack and choke manifold, MU TIW and dart on test joint, MU test tool on top drive. Shell test at 250/5,000 psi for 10/10 min. Test annular at 250/2500 psi, all other BOPE at 250/5000 psi for 10/10 min, replaced lower IBOP on topdrive, AOGCC Rep Jim Regg waived witness at 9:47 on 10/8/12, BLM Rep Justin Miller waived witness at 11:24 on 10/8/12. Racked and tallied 330 jnts 4" DP. RD test equipment, LD test jnt, pull test plug,stage baker tools on rig floor, MU BHA#1, 6" roller cone bit, bit sub,6 5/8"string mill,3 1/2" HWDP flex jnt,6 5/8" upper string mill,XO sub,18 jnts 4"HWDP.PU 4"DP from pipeshed and single in hole from 567'to 629',wear bushing ID is 6 5/16",mills are 6 5/8"so did not set wear bushing in well head. 10/10/2012-Tuesday Fill hole with 20 bbls w/produce water. Pick up singles& RIH t/700',work mill through spot @ 700' no drag, continue picking up pipe to 9,123',circulate bottoms up,pump sweep,circulate sweep out @ 400 GPM,2,270 psi,rotate and work pipe while circulating.Monitor well. Circulate and blance out fluid.Trip out of hole standing back.Service rig and topdrive.Trip out of hole @ 1,750'. Page 1of1 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 44-33(Sidetrack of SRU 24-33) 50-133-20237-01-00 212143 9/19/12 Daily Operations: 10/10/2012-Wednesday Fill hole with 20 bbls w/produce water. Pick up singles&RIH t/700',work mill through spot @ 700'no drag,continue picking up pipe to 9,123',circulate bottoms up,pump sweep,circulate sweep out @ 400 GPM,2,270 psi,rotate and work pipe while circulating.Monitor well.Circulate and balance out fluid.Trip out of hole standing back.Service rig and topdrive.Trip out of hole @ 1,750'. 10/11/2012-Thursday Trip out of hole.Wait on Pollard w/line. Rig and run collar locator gamma and CIBP tools,set CIBP @ 9,038',bolt stripe out of lower plate on CIBP instead of shearing,test casing @ 2,100 psi,test good.Wait on CIBP and E-Line unit,make up upper&lower string mills&mad. PJSM with E-line crew and rig up E-line. RIH with CIBP and set bridge plug @ 9,034'wlm,pooh and rig down wire line.P/U MWD,UBHO, xo and shallow test MWD @ 410 gpm. Pick up upper and lower string mill,and whip stock. RIH with whip stock assembly& mills,MWD tools and orient tools to whip stock.Trip in hole with whip stock on drill pipe from derrick @ 2 min per stand. 10/12/2012-Friday Trip in hole with whip stock to stand 134.M/U top drive on std 134,break circulation,orient whip stock @ 80 deg,tag CIBP @ 9,019',slack off 20K engage anchor,P/U 6K to confirm set,slack 40K and shear bolt,whipstock set @ 9,001.15.Displace well with 352 bbls 9.5 EZ-mud, get drilling parameters, p/u 150, s/o148. Mill window f/9,001 T/9,015, monitor well,well flowing @ 8/9 bbl/hr, shut well in.Shut in psi 1,270 on casing,1,220 on drill pipe,weight mud system up to 10.2,initial gain=10 bbls.Pump 10.2 kill weight mud @ 3 bbl/min,ICP 1,000 psi,continue pumping.Pumping kill rate F/7,800 stks,30bbl gain while pumping kill weight fluid,continue pump until 10.2 ppg @ surface. Monitor well through gas buster,slight flow.Open well and monitor well,well flowing,shut well in and record pressure,890 psi on drill pipe, 840 on csg, decision made to increase mud weight to 10.7. Build weight in mud pits to 10.7. Pump 10.7 kill weight mud through choke,following pump schedule @ 3 bbl minute. 10/13/2012-Saturday Circulate 10.7 mud around @ 210 gpm @ 1,130 psi 21%flow max gas=424 units,monitor well,well flowing,shut in and record pressure, SIDP=580, SICP=520.Circulate and increase mud weight F/10.7 T/10.9, @ 168gpm ICP 730, FCP 760 psi, max gas units 1,173 units, monitor well,well flowing,shut in and record psi,SIDPP=500-SICP=450,decision made to drill ahead. Mill/drill F/9,015 T/9,035,@ 250 gpm,1,370 off bot psi,1,420 on bot psi,100;rpm,off bottom torque 2.5K,on bottom torque.5.5,wob 14/15,flow 23%out max gas; @ bottoms up =1292 units. Monitor well,well flowing @ 2.8 bbls/hr,CBU @ 300 gpm,1,400 psi while polishing window,w/80 rpm,pass ` through window with no pump or rotation,ok. L/D single,monitor well on trip tank,rig up test pump and perform FIT test. EMW 12 ppg J,pr�J with 10.0 ppg test mud, @ 8963' tvd, @ 512 psi, chart test. Circulate and increase mud weight F/ 10.9 T/ 11.1 ppg, 2257 units gas @ bottoms up.Monitor well on trip tank,circulate amd increase mud weight F/11.1 to 11.3,gas units @ bottoms up=1639. qq 3 10/14/2012-Sunday Circulate and increase mud weight F/ 11.3 T/ 11.6, 1869 units gas @ bottoms up. Monitor well on trip tank, well flowing 1.8 bbl/hr. Circulate and condition mud,insure mud is balanced @ 11.6. Perform FIT test @ 13ppg EMW,PSI up to 652 psi,pressure bleed down to 554; psi= 12.8 EMW, rig down test equipment.Circulate bottoms up, @ 310 gpm, 1,500 psi, 770 units gas @ 5,100 stks, monitor well, well flowing @ 1 1/2 bbl hr.Trip out of hole F/8,998 T/5,000', hole taking proper displacement when pulling pipe, monitor well F/30 minute well flowing 1/2 bbl hr,blow down TD.Continue tripping out T/631',monitor well,well flowing 2 bbl/hr. Continue tripping out of hole,lay down milling assembly,strig mills in gauge,window mill 6.25.Install wear bushing,clean rig floor.PJSM,bring drilling tools to rig floor,pick up BHA,orient MWD tools.Down load MWD tools,m/u Slb sensor.PJSM with all hands,load nuke sources in tools.Trip in hole. 10/15/2012-Monday TIH F/777'T/8,989,fill pipe every 3,500',p/u 145k,s/o 115k.CBU @ 250 gpm,1,690 psi,24%flow,3,294 units gas @ 7,200 stks.Trouble shoot top drive robotics. (top drive not rotating). Drill F/9,035 T/9,050'.Trouble shoot top drive. Drill F/9,050 T/9,185, p/u 155k, s/o 144k,rot weight 148k,300 gpm,2,830 psi.ADT 6.4,AST 6hr,ART 0.Rotate and slide F/9,185 T/9,300,on bottom torque 3k,off bot 2k, diff 213 psi;P/u 155K,S/O 144k,rot weight 148k,2365 psi. 10/16/2012-Tuesday Drilling F/9,300 T/9,361,wob 15/20,rpm 45,torque.on bottom 3k,off bot 2.5k,p/u 162k,s/o 150k,spp 3640 psi,350 gpm,ADT 3.9 HR, ART 1.4 HR, AST 2.5 HR. Rotate and slide F/9,361 T/9,450,-89' @14.8 ft/hr, p/u 164k, s/o 148k, rtw 155. Rotate and slide F/9,450 T/ 9,530',p/u 164k,s/o 148, rtw 152k, 3150 psi on bottom, 3,050 psi off bottom,torque on bottom 3.4,torque off bottom 2.6,ADT 7.9hr ART 1.9 hr,AST 6 hr.Rotate and slide F/9,530 T/9,644,114'@ 19 ft/hr,3150 psi,torque on bottom 4k,torque off bottom,2.5 k,p/u 164k, s/o 148,rtw 152k. Page 1 of 1 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 44-33(Sidetrack of SRU 24-33) 50-133-20237-01-00 212143 9/19/12 Daily Operations: 10/17/2012-Wednesday Rotate and slide F/9,644 T/9,751,315 gpm,3260 spp,60 rpm,tq on bott 3.8k;tq off 3k,wob 15/20k,p/u 153k,s/o 145k,rwt 147k.Rotate &slide f/9,751 t/9,833.UP 155k,DN 145k,ROT 148k,7.6 bpm=3,300 psi OB.,12.5 ppg ECD,Ave ROP=16.4 fph,CBU.7.1 bpm=3,050 psi. Monitor Well. Well flowing @ 2.8 bpm (1.4 bbl gain in 30 min). Pump up final survey &CBU. 2,090 units of Gas @ BU. POOH f/9,833 t/8,540.Well took 1.1 bbls over calc.displ on trip out.Monitor well on the trip tank.Well flowing @ 3.4 BPH.TIH f/8,540 t/TD @ 9,833.CBU to clear gas influx from well bore. 7.5 bpm=3,250 psi. 3,572 units @ BU. Shut well in & record pressures, 342 on DP, 334 On annulas. Increase mud weight in surface volume F/11.6 T/11.9,DP psi @ 450 psi.Circulate 11.9 ppg KWM @ 3 bpm,ICP 1,260 psi. 10/18/2012-Thursday 11.9 ppg in&out.Shut down pumps.Well flowing.Shut in Well and monitor pressure build.SIDDP=310 psi,SICP=290 psi.Perform F.I.T prior to increasing mud weight.Test MW=11.9 ppg.ND=8950.Test pressure=993=14.0 ppg EMW.(good test)Bleed down pressure. Open well and CBU. Max Gas=604 units @ BU.POOH from 9,830'to 9,018'.UP 165k,DN 148k.(2.6 bbl under calc displ.).Orient to place bit @ 80 deg RT. Increase MW in suction pit to 12.2 ppg. Displace well bore to 9,018 with 12.2 ppg. Flow check well. (still flowing, but diminished) Increase MW t/12.5 ppg.Displace well bore to 12.5 ppg.3 bpm,850 psi.Monitor well,well ok.Continue to circ @ 3 bb/min& cut drilling line.Monitor well,trip out of hole. 10/19/2012-Friday BHA:L/D Jars,Std back Flex DCs,PJSM on RA Source. Remove Source. Drain&inspect Motor. Inspect&grade bit.4,3,WT,A,E,I,LT,Hrs.Clear rig floor of slip/trip hazards.R/U to test BOP. Test BOP and related equipment to 250L/4,000H.Test Annular to 250L/2,500H.Hold all tests f/10 min &chart record same. Perform Accumulator precharge test. R/D test equipment &clear floor. Install Wear Bushing(6 5/16" ID). Prep BHA components and stage in Pipe Shed. M/U BHA#4&orient mwd tools.Shallow test mwd tools,clean rig floor,prep for p/u drill pipe.Pick up 50 joints drill pipe.TIH w/BHA#4. 10/20/2012-Saturday TIH w/BHA#4 on 4"Dp to 8,980'.Well gave 4 bbls over calc displ.on TIH.CBU w/12.5 ppg @ 9,100'. Began getting gas and fluid cut mud after 96 bbls pumped.MW decreased to 11.4 ppg.2,250 units of gas.Chlorides diluted to 20,000 ppm. Shut in&circulate thru Buster to clear gas influx.Begin diverting 12.4 ppg to R4R tank.Divert to pits when weight decreased to 11.9.Recovered 382 bbls of weighted mud in R4R.Circulate&cond to treat mud.Treat mud w/circ @ 5 bpm, 1,650 psi while getting thru crew change(1st day back).TIH f/9,100'.Set down on obstruction @ 9,590'.Wash and ream thru same.Continue TIH to 9,833'.Break circ and record parameters.UP 158k,DN 142k.CBU @ 7 bpm,3,100 psi.12.7 ECD.2,250 units of gas @ BU.Slide/rotary drill for directional requirements f/9,832't/9,998'.7.6 bpm,3,200 psi, 330 gpm, 3,050 SPP, 3.1 tq off bott, 4 tq on, wob 8k, 50 rpm, p/u 160, s/o 146k, rwt 150k, 6.4 hrs on bit. Rotate and slide F/ 9,998' T/10,220',332 gpm,3,250 SPP.Bit Ave ROP=26.4 ft/hr. 10/21/2012-Sunday Drill slide/rotary f/10,200;t/10,288'. UP 165k, DN 148k, RT 150k,7.8 bpm,3225 psi.Slow P-rate(2-4 ft/hr)from 10,275'to 10,294'(6.2' TVD)Tuffaceous Claystone.Drill slide/rotary f/10,288't/10,508'34 ft/hr ave rop.Troubleshoot pump engine problems. Engine repeatedly dying.Drill slide/rotary f/10,508't/10,561'.Sheared die retainer plates in Grabber.Pull 1 std. Repair TD.P/u 1 stand,circulate out gas,166 units @ 310 gpm, 3,050 psi. Drill F/10,561'T/ 10,580', @ 310 gpm, 3050 psi, p/u 170,s/o 153, rot wt 152. Rotate and slide F/10,580' T/10,825'.41 ft/hr ave rop. 10/22/2012-Monday Drill slide/rotary f/10,285't/11,063'.Pumped sweep @ 11,025'. Solids increased f/25%to 75%by volume @ B/U.Drill slide/rotary f/11,063' t/11,175'.Circ.carbide sample In/out to gauge hole.Carbide returned to surface 14 bbl under calculated displacement.Trouble shoot top drive blower motor default.Rotate and slide F/11,175'T/11,295',p/u 180k,s/o 150k,rot,152,torq 5.1.Change out top drive blower motor power cable.Rotate and slide F/11,295'T/11,379',p/u 182k,s/o 152k,rot 154k,gpm 300 rpm,50,torq on 5.3,tq off 4.4,wob 6k. Circulate bottoms up @ 310 gpm,3,260 psi.Monitor well for 30 min,well flowing @ 7.8 bbl/hr. Repair top drive hydraulic lines on IBOP actuator. Safety stand down with rig crew on near miss incident.Circulate and increase mud weight F/11.4 T/11.6.Well flowing @ 2.4 bph.Begin short trip to window.Pull from 11,380't/11,000'. 10/23/2012-Tuesday Continue pulling short trip to window F/11,000'.Hole in good condition.CBU @ 275 gpm,2,400 psi,1412 units of gas.Trip in hole F/9,053' T/11,325',p/u 185k,s/o 138k CBU,3760 units gas.Rotate and slide F/11,395'T/11,510',300 gpm,3,400 SPP,50 rpm,5/8 wob. Rotate and slide F/11,510'T/11,592',p/u 188,s/o 152k,rot 158k,290 gpm,3140 PSI,ADT 5.5,AST.9,Bit hrs 41. Rotate and slide F/11,510'T/11,640', Gpm 290,torq on bottom 5.6,off 4.8, spp 3,025,rpm 50,p/u 188k,s/o 152,rtw 158. Page 1 of 1 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 44-33(Sidetrack of SRU 24-33) 50-133-20237-01-00 212143 9/19/12 Daily Operations: 10/24/2012-Wednesday Drill f/11,640 t/11,710. Confirmed top of Hemlock @ 11,519.Trouble slide drilling. UP 185k, DN 148k, ROT 160k, 7 bpm,3,250 psi, 11.3 ppg, 12.15 ECD,55 RPM, 5k tq. Pumped 22 bbl high vis sweep @ 11,665. 50%increase in cuttings when sweep returned. Drill f/11,710 t/11,778.Vary parameters to maximize P-rate. 11 ft/hr ave rop. Rotary Drill f/11,778 t/11,910.22 ft/hr ave rop. Drilling brk @ 11,801,95 ft/hr(coal).ROP below coal is 20 to 60 ft/hr.Rotary Drill 1/11,910 to 12,025.19.2 ft/hr ave rop.No losses to formation. 10/25/2012-Thursday Rotary Drill f/12,025 t/12,075. UP 190, DN 148, R165, RPM 55,TQ 6,000. CBU for short trip. Attempt to straight pull, but unable to brk over. Circ. 2nd circulation @ max rate. 7.8 bpm 3,750 psi. 80 RPM, 6.5 tq. Rot. and recip. throughout circ. Minimal increase in cuttings during circulation.Stop rotation while in upstroke. String stalled with overpull of 60k. Backream from 12,072 to 11,565. Free string with rotation each time out of slips.Crew change.CBU @ 7.5 bpm.415 units of gas.Straight pull f/11,565 to 11,240 to place bit above Tyonek G1.TIH 1/11,240 t/12,072.Set down on obstructions @ 11,591&11,760.Wash &Ream each. Differential sticking @ connections 11,820, 11,883, 11,946 & 12,009.; Forced to M/U TD and rotate off wall. String broke free easily w/7-8k tq. M/U TD, brk circulation and MWD /Survey @ 12,070'. Short trip produced 3,930 units of gas(prior to B/U). Mud Logger noted gas lag came from+/-9,100'. Drill 6 1/8"hole 1/1,2072 t/TD @ 12,425 as per Geologist. TD Well @ 04:10. Final survey placed TD 31.8' above & 15.27 right of planned target. Circ & Cond.,UP 190,DN 150,R 160,60 rpm,6-7k tq,7.5 bpm,3570 psi. 10/26/2012-Friday POOH Back-reaming f/12,425,t/11,196.60 rpm,6 bpm,2,400 psi.Unable to straight pull. Differential sticking each time out of slips. M/U TD and break free each time with rotation.(2-5k over normal torque).Wall sticking ceased abruptly once above 11,270. CBU @ 11,196 to clear cuttings from back-reaming.750 units @ B/U.Straight pull 1/11,196 t/9,750.UP 180k,no tight spots to report.CBU @ 9,750 to clear possible gas and water flow from Annulus. 7 bpm,2,880 psi, RPM 70.3604 units from B/U and diluted from 11.4 to 10.9. Pull additional 10 stands to place bit @ 9,110(window @ 9,015). Displace Well f/9,110 to surface w/12.6 ppg mud. Circulate thru 3/4 open choke to keep heavy mud from u-tubing when pumping slow. Monitor Well for 30 minutes(no flow).Mix and pump slug.POOH from 9,110 to BHA @ 784'. Flow check well +/- 2,500 & @ BHA(No flow). BHA: Std back HWDP &Jars. PJSM. Remove RA Source. Baker downloaded data f/MWD while suspended from blocks. 10/27/2012-Saturday BHA:Finish downloading data f/LWD. Inspect Motor and Bit. Motor Bearing was extruding 1/4".Bit was in good condition.0-1-ER-A-X-I-CT TD. Pull Wear Bushing. R/U to Test VBRs on 4 1/2"Test Joint.Test VBR(Upper Rams)to 250L/5,000H.Test annular t/250L/2,500H.10/10 ea.test. R/D test equipment and install wear bushing. MU BHA 5: RR HCC Insert, Mtr, NM Stab, NMDC,Stop Sub, MWD, BCPM, Sonic, Filter (2) NMDC, XO, (6) HWDP,Jar, (12) HWDP =757.94. Orient, upload MWD, surface test tools. RIH w/HWDP.TIH w/Dp from 758'to window @ 9,000. PJSM on fluid displacement. Nose bit out window t/9,022. Displ csg from 12.6 ppg to 11.4 ppg.4 bpm.940 psi. Blow down choke and mud lines.TIH 1/9,022 t/10,000. Fill pipe. Continue to TIH to 11,040. CBU @ 11,040 to clear annulus of influx prior to entering Hemlock.Rotate&reciprocate pipe.7.2 bpm,2,910 psi,60 rpm,3-7k tq.3,750 units @ B/U.TIH f/11,040 t/12,183.Wash&ream tight spot f/11,801 t/11,840. Begin getting differentially stuck each time in slips,starting 1/11,865. M/U TD on each stand and break free with rotation to enable lowering of stand. 10/28/2012-Sunday TIH f/12,183 t/12,425. Had to M/U top drive each stand and break free w/rotation.Circulate and condition for logging and liner job.2420 units on B/U.MADD PASS from 12,425.(12,313 sensor depth)to 11,985. Pull @ 300 ft/hr,logging with SLB Sonic tool. Back ream to break free. Rig transmission overheating form pulling slow,torque converter not locking up.Forced to backream each stand and then log down to avoid damage to transmission. Continue MADD PASS 1/11,985 to 10,728. Begin pumping out (no rot) f/11,270. 6 bpm. MADD PASS 1/10,728 to 9,950.Rotate through tight spot 1/10,650 to 10,660. 10/29/2012-Monday MADD PASS with SLB Sonic tool f/9,950 t/9,660.CBU 9,660 to clear gas and water influx from annulus.739 units @ B/U, POOH f/9,660 t/9,060. M/U TD and circulate while preparing for displacement. Displace Casing from 9,015 to surface with 12.5 ppg mud. Monitor Well for 30 min. (static) Pump slug. POOH f/9,015 to BHA @ 758. (8) bbls over calc displ on trip out. BHA: Stand back HWDP. L/D Jars and reminder of directional tools.Clear floor of excess tools. Pull wear bushing. Rig up Weatherford tools and stage equipment on rig floor. Had to re-locate power pack due to fumes. Install XO on safety valve. Make up Shoe Track. Bakerlock the first 3 connections. Test operation of Floats. P/U&RIH w/4 1/2 production liner. DWC/C-HT,12.6#, L-80,3.958 ID. Page 1 of 2 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 44-33(Sidetrack of SRU 24-33) 50-133-20237-01-00 212143 9/19/12 Daily Operations: 10/30/2012-Tuesday P/U & RIH with 4 1/2 DWC/C-HT, 12.6#, L-80 Production Liner. Verify operation of floats. 3,617.76 includes Shoe Track. (87) joints. Installed solid body centralizer on tube of first 37 joints. Installed centralizer on every other joint f/#38 to#87.Tq conn t/6,500 ft/lb. P/U Baker Flex-lock liner hanger/ZXP liner top packer.Wiper plug pinned f/1,600 psi,hanger pinned to set @ 2,560&release @ 3,300 psi.Mix and install Pal Mix&allow to set f/30 min. Liner wt 33,000#.M/U Std#1.Circ liner volume.R/D Weatherford equipment while circulating. TIH f/3,655'with 4 1/2"liner assembly on Dp. Drift each stand run w/2"drift. M/U TD on std#62.8090,CBU @ 4 bpm,500 psi.780 units of gas @ B/U.Continue TIH f/8,090 t/8,969.Drift each stand w/2"drift. M/U TD plug dropping head,XOs and(2)10'pups.Tq connections & lay do same. M/U top drive. Brk circulation. Record parameters. UP X138, DN 133, ROT 135. Establish rotation. 1OR 1.5 tq, 20R 1.5 tq, 30R 1.5 tq.ROT wt=135. Displace 12.6 ppg mud to 11.4 ppg.Take returns to R4R tank.TIH with 4 1/2 production liner on Dp f/8969 Page2of2 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 44-33(Sidetrack of SRU 24-33) 50-133-20237-01-00 212143 9/19/12 Daily Operations: 10/31/2012-Wednesday TIH with 4 1/2" production liner t/10,070'.Wash & ream thru tight spot to 10,227'. CBU @ 10,227', 20 rpm, 2,500 tq, 6 bpm, 1,100 psi. 3,880 units @ B/U. Continue to RIH f/10,227't/11,230'. Ream tight spots as necessary to pass. CBU @ 11,230'to clear annulus prior to entering hemlock.30 RPM, 3.5 tq,5 bpm, 1,090;continue to RIH.Wash &ream when necessary.Tight working through top of hemlock. Ream tight spots from 11,460'to 11,560'.Slide to 12,088'.Wash & ream to 12,360'. Circulate to clear gas from annulus prior to washing down final stand. (2,085 units) Wash & ream final stand to 12,413'. Make up pup jts and TD plug dropping head. Circ & condition f/cement job.UP 163, DN 152,ROT 160,5 bpm,835 psi,30 RPM,4,500 tq.Washed to 12,423',psi dropped from 835 to 530 psi at bottom, tagged bottom and set 20K on shoe with no psi change. PSI down to 400. Notified Drilling Engineer of possible washout,dropped carbide pill, had indication of gas 26.8 bbls away. Decision made to backream OOH looking for hole. Backream OOH at 65 spm (470 psi) 25 rpm from 12,423'to 11,158' (20 stnds). Dropped carbide pill with no indication of gas near surface, complete full circ at 65 spm-470 psi, max gas 1,745 units. Break off topdrive,close upper rams, line up kill line, press up to 200 psi on backside, looking for communication in DP, had no flow, press up to 400 psi, no flow in DP, bled off annulus, blew down choke,MU topdrive,circ @ 3 bpm,390 psi.Notified Drilling Manager of results.Agreement made to pump marker pill.Finish circ B/U to clear 2,820 units.Mix high vis pill w/nut plug marker. 11/01/2012-Thursday Circulate high vis nut plug marker pill in/out to verify flow path of circulation system. Pumped 33 bbl pill at 124 gpm-380 psi,chased with 11.5 mud at 210 gpm-910 psi. Rotated string at 10 rpm-3,200 ft./lbs torque, 9,356 stks had nutplug pill at surface. RIH 20 stands DP washing liner to bottom at 3 bpm-500 psi, 150K down weight.CBU at 4 bpm-740 psi, 30 rpm-5,500 ft./lbs torque, max gas 3,487 units. Held PJSM with Baker reps and rig team on MU cement head and pup jnts.MU head, MU topdrive,wash down at 3 bpm-470 psi,10 rpm- 4,000 ft/lbs torque,tag bottom at 12,425', PU and place shoe 2'off bottom at 12,423',up weight 175K.Held PJSM with Schlumberger,rig K/L team, Baker reps,AIMM drivers on cementing.SLB pumped 5 bbls water to fill lines, PT hardlines at 1,000 and 5,000 psi, rig pumped 24 • bblsl3ppg MudPush II at 3.5 bpm-700 psi,SLB began batching 12 bbls into MudPush. SLB pumped 100 bbls (416sx) 15.6 ppg cement at11"°°A- 3.9 39 bpm with full returns throughout job,rotated string at 23 rpm,555 units max gas.Shut in DP,washed up cement lines,dropped dart, lined up and SLB displaced with 11.3 mud from pits at 5 bpm-330 psi initially,saw dart latch wiper plug at 89.6 bbls into displacement, increased pump rate to 5 bpm-1,500 psi and stopped rotation of string,cut rate to 2.5 bpm-830 psi,bumped plug/landing collar at 144.2 bbls displaced,fcp 900 psi, held 1,420 psi (500 over fcp) f/1 minute, increased psi to 3,000 and held f/1 minute, bled back 1 bbl,floats holding,max gas 1,891 units at shut down.CIP 16:45 hrs.Set HRD ZXP liner top packer as per Baker,top of liner at 8,765.97',RD SLB.Press up DP to 500 psi, ease up out of packer and start pumping as psi dropped. Increase rate to 7 bpm-1,400 psi and CBU 1 x,drop 4"wiper ball and CBU 1 x, approx. 10 bbls cement to surf on first CBU. POOH 14 stands racking back in derrick from 8,765'to 7,830'.Slip and cut 110'drill line. Pump dry job,cont POOH from 7,830'to 6,585'. Hole fill incorrect. Performed flow check,well is flowing at 4.5 bph,CBU at 4 bpm-630 psi,394 units gas at bott up.Notified Drilling Manager,prep to load 12.5 mud in pits.TIH from 6,585'to 8,730'(30'above liner top),calculated displacement 11.35 bbls,actual displacement was 19.5 bbls(8 bbls over). MU topdrive,close upper rams and monitor for any pressure on DP and annulus. 11/02/2012-Friday Continue monitor DP and annular pressure with well shut in,transfer 12.5 ppg mud into pits from tiger tank. SIDP 20 to 427, SICP 0 to 408. Transferred 11.5 mud to rock washer tanks and tiger tank to make room for returns in rig tanks. Circ 12.5 mud around through choke and degasser at 3.5 bpm,held 200 psi back pressure,ICP 600 psi,FCP 570 psi with full open choke,max gas 1,191 units.Stop pump, open upper rams, monitor well 30 min,static. Blow down surf lines. Pump 18 bbl slug 1.5 ppg over, blow down topdrive and mud line. POOH from 8,730' to 5,300', hole fill good. Monitor well f/30 min while filling trip tank. Well static. Continue to POOH from 5,300' to surface,LD Baker HRD-E liner running tool.No damage or other issues found with running tool upon inspection. PU and break pup jnts off Baker cement head, LD same and remove from pipe shed. RU to test BOPE, MU test jnt, plug,TIW and dart valves, PJSM.Test BOPE at 250/5,000 psi,annular at 250/2,500,all tests at 10/10 min,test gas alarms,monitoring well in cellar through annulus valve(no flow).Had AOGCC Rep John Crisp on location to witness BOPE tests. Page 1 of 2 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 44-33(Sidetrack of SRU 24-33) 50-133-20237-01-00 212143 9/19/12 Daily Operations: 11/03/2012-Saturday Cont testing BOPE at 250/5,000 f/10&10, annular at 250/2,500 psi f/10&10 min.);lad 5 fail/pass tests due to psi drop on chart recorder. Changed plug seals, isolation needle valve on test manifold and leaking fitting on chart recorder. All fail/pass tests were re-done successfully. RD test equip, close annulus valve, pull test plug, install wear ring, blew down. MU Baker "TBR" dress and polish mill assembly and 7 5/8"scraper and XO's. RIH on 4" HWDP and DP to 8,752'(13'above liner top).CBU one time to get good 12.5 mud all the way around. Max gas 3442 units. 197 spm-8.5 bpm-2200 psi, rotating and reciprocating 40 rpm-2,600 ft/lbs torque. Reduce pump rate and rpm to 3 bpm and 10 rpm,ease down and locate liner top.PU increase rpm to 75,ease down and dress liner top f/10 min,3000 ft/lbs torque;on bott, 2200 ft/lbs off bott, 10K down wt on upper mill,460 psi on bott.CBU to clear any cuttings/cement from well bore and good 12.5 mud all around.Check for flow,pump 18 bbl dry job and blow down top drive/mud line.POOH from 8,765'to 2,000'. 11/04/2012-Sunday Cont POOH with polish mill/scraper assembly. Hole fill 6.75 bbls over calculated. Wait on rotating dog sub delivery. Service rig and topdrive,clean floor,grease crown sheaves,service boiler,CO grabber dies,pull wear bushing. MU 5.57"rotating dog sub&5.73"sleeve packoff+XO on HWDP, RIH to 8760'. Up weight 143K, down wt 137K with no pump or rotation. Ease into ZXP packer top with sleeve packoff,tag dog sub and set down 40K,had noticeable indication of shear,continued down to 50K down weight,PU and rotate at 60 rpm, slack off and set down to 90K(50K down wt) while rotating, PU /slack off to 75K(60K down wt). PU 5' and RU to test casing. Line up injection pump on kill line, press up on backside and test 4"x 7 5/8"for 15 minutes.Good test. Bleed off. Displace well to 11.5 mud. Had max gas of 2,698 units at bottoms up. Line up injection pump and test 7 5/8", liner lap and 4 1/2"casing at 2,100 psi for 30 minutes on chart.Good solid test. Bled off and RD injection pump.Check for flow, pump 18 bbl dry job 1.5 lbs over, blow down topdrive&mud line. POOH rack back stands to 3,444'.Lay down 4" DP and 18 jnts 4"HWDP. 11/05/2012-Monday Cont POOH from 559' LD HWDP and Baker rotating dog sub. RD hand tongs,4"elevators and spinner, RU to run 2 7/8"tubing,clean floor. MU Swaco scraper assembly, 3.75" bit, 113 jnts 2 7/8"tubing from pipeshed and 4" DP from derrick. Had no problem going into 4 1/2" liner top. MU topdrive and wash/reamed from 8,775'to 12,290'at 4 bpm-1,600 psi,40 rpm,encountered no cement.CBU 168 gpm-2,600 psi,40 rpm,2,400 ft/lbs torque,rotate and reciprocate string. 11/06/2012-Tuesday Continue CBU with 11.5 mud.at 12,288'. Rotate and recip 168 gpm-2,600 psi,40 rpm. Displace well to fresh water 2 full circs at 124 gpm- ICP 1,230 psi, FCP 800 psi.Did a walk through of the rig with Drilling Compliance Specialist and SLR Rep. Pump fresh water through choke manifold, kill line,choke line, blow down top drive, mud line,choke line and manifold. POOH on elevators from 12,288'to 7,858' (upper scraper), up wt 185K, down wt 155K; RIH from 7,858'to 12,288'. Displace well with clean fresh water,followed by pill train and 6% KCL. Blow down all hoses and pumps from tank battery,flush pump 2, blow down topdrive, mud lines and all 3 rig pumps. POOH LD 4" DP from 12,288 to 7,884,LD baker scraper. Page 2 of 2 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 44-33(Sidetrack of SRU 24-33) 50-133-20237-01-00 212143 9/19/12 Daily Operations: 11/07/2012-Wednesday Cont POOH, LD 4" DP from 7,884'to 3,560', LD Swaco scraper assembly. Cont POOH from 3,560', LD 2 7/8" HT PAC tubing. Cont injecting mud at G&I pad. Install tubing hanger w/TWC and test @ 1,000 psi. Rig down drip pan,flow line, koomey lines,choke&kill lines, nipple down BOPS.Install dead head tree,cleaning pits. Rig released @ 06:00 11/7/2012. Injected 933 bbls mud,75 bbls water 5 bbls diesel. Last drilling report. Well completion reports/activity to come. 11/08/2012-Thursday 11/09/2012-Friday 11/10/2012-Saturday 11/11/2012-Sunday 11/12/2012-Monday 11/13/2012-Tuesday Page 1 of 1 Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 44-33 50-133-20237-01 212143 9/18/12 Daily Operations: 11/14/2012-Wednesday Finished final RU.Tested BOPE, pulled two-way ck,Tested casing at 3,000psi for 15 mins.Set two-way ck, Installed additional winterization. 11/15/2012-Thursday Performed BOP testing with State rep. Walk thru Winterization Inspection w/State.Stand-by waiting on States approval before starting work 11/16/2012-Friday Still waiting on State approval to continue work. MIRU hammer unit to swab well,could not get down with cups, RDMO hammer unit. MIRU eline, Logged well from 12,290'to 7,000'. POOH, PU a 5'x 2-1/8" HC gun,6spf, 60deg phase& temp/psi. Perfed from 12,109'-12,114'. 11/17/2012-Saturday POOH w/perf gun, PU CBP& RIH.Set down at 10,130'start pumping&made it to 10,170'. Could not pump in formation. POOH. PU BP and TIH w/114 Its of 2-7/8" and 268 jts of 2-7/8" 11/18/2012-Sunday Set plug @ 12,070',Setting tool would not open to circluate through, POOH. RU E-line,tbg punch @ 10,112-15', MIRU SL, Swab well down to 2,000'at report time. 11/19/2012-Monday Continued swabbing tubing, made total of 47 swab runs. Recovered total of 76 Bbls. RDMO Swab equipment. 11/20/2012-Tuesday SOH W/268 jts of 2-7/8" and 113 joints of 2-3/8"WS. MIRU E-Line Unit. M/U CCL, Psi survey tool, &5' Perf Gun. RIH to bottom,tagged fluid at 3,360'wlm.Tagged plug at 10,091'wlm. Logged up to 11,000',correlated logs,set gun at desired depth. Perforated Upper H-10 from 12,025'-12,030'. Monitored wells BHP for 90 mins. Psi started at 3,250 and came up to 3,275 psi. POOH. RDMO E-Line.TIH W/81 stands of 2-7/8"WS, EOT @ 5,045'. Installed gas injection line to annulus, and Tbg to choke manifold. Pressured up on backside to 2,700 psi,started receiving returns to gas buster. Recovered 2 Bbls and stopped. MIRU Swab Unit. Made 3 swab runs.Tagged fluid at 300', made first run from 800', recovered 1.5 Bbls. Made 2nd run from 1,500', recovered 3 Bbls. Made 3rd run from 2,500'. Recovered 5 Bbls.Well started unloading on its own,well unloaded 34 Bbls. Recovered total of 43 Bbls before only seeing gas to gas buster. Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 44-33 50-133-20237-01 212-143 9/18/12 Daily Operations: 11/21/2012-Wednesday Finished Swabbing. RDMO Pollard swab unit. SOOH w/80 stands of 2-7/8" WS. MIRU Pollard E-Line Unit. RIH w/BH PSI/Temp survey tools, CCL and 5' Perf Gun. RIH,tagged plug @ 12,091' wlm. Logged up to 11,700'. Correlated logs,set tools at desired depth, perforated Upper H-10 from 12,025'-12,030'. Picked tools up to 12,000' and monitored pressures and temps for 3 hrs. H-10 built up 100 lbs over 3 hrs, also fluid level came up 320' over 3 hrs. RDMO Pollard E-Line Unit. MU 4.5 10K Composite Bridge plug and setting assembly. TIH, set plug at 12,000'. Loaded tbg w/31 bbls. Pressured up to 2,500 psi &sheared off plug. PU 1 stand. Sat back down on plug to ensure set. SOOH w/2-7/8" WS. LD setting tools. 11/22/2012-Thursday TBIH w/ 106 stands of 2-7/8" WS. Left EOT @ 7,563'. Installed gas injection line. Pressured backside up to 1,800 psi. MIRU Pollard Swab Unit. Started swabbing. Tagged fluid level @ 1,365', made 18 runs. Well started unloading. Recovered total of 110 bbls of fluid, 31 bbls of oil. Let flow to gas buster until all pressure off welbore. RDMO Swab Unit. 11/23/2012- Friday SOOH w/ 110 stands of 2-7/8" 8 RD WS. RU 2.5" Magnet on slickline w/rollers. RIH w/magnet, could not get past deviation @ 10,427'. POOH. RDMO Pollard SL unit. MIRU Pollard E-Line Unit. MU 2.5" magnet on bigger roller buggies and CCL. Sat down on setting tool left on plug @ 12,010' wlm. Attempted to free. POOH, recovered the piston from inside setting tool. MU CCL, BHP survey tools, and 5' perf gun (2- 1/8" HC gun, 6 spf 60 degree ph). Logged from plug @ 12,007' up to 11,700'. Positioned gun at desired depth. Perforated H-8 from 11,907'-11,912'. PU pressure/temp survey tools to 11,897'. Monitored wellbore for 3 hrs. POOH. RBIH w/2.5" magnet,tagged same depth. Attempted to pull free from plug. Could see 4-6,000 lbs over pull before magnet would come free. POOH. No recovery. MU 2.5" LIB. Pressure/temp survey tools and CCL. RBIH stroked LIB on top of fish. Logged up to 11,700'. Set tools back down to 11,987'. Ran survey for approx 2 hrs. POOH. LIB had no visible markings on face, only on one side. RDMO E-Line Unit. Started testing BOPs. 11/24/2012-Saturday Finished testing BOPs. MU 3-1/8" Box Tap, bumper jar, oil jar, 4 drill collars, accel jar. TIH w/ 112 jts of 2-3/8" and 264 jts of 2-7/8". PU and MU Power swivel,threaded box tap down onto top of fish. PU and pulled 10K over string weight, popped free. SOOH w/44 stands of 2-7/8", started pulling wet. Called Pollard E-line out to perforate tbg. MIRU Pollard E-line. RIH w/tbg punch/CCL. Logged and perfed joint above drill collars. RDMO Pollard. Continued SOH w/WS. LD perforated joint and fish. MU 3-1/8" 4 blade junk mill, on 1 oil jar, 4 drill collars. 11/25/2012-Sunday Continued TIH w/3-7/8" mill on WS. Tagged first plug @ 12,000'. MU Power swivel and milled plug up in 40 mins. Continued TIH,tagged 2nd plug @ 12,070'. Milled up plug in 75 mins. Continue TIH,tagged bottom @ 12,312'. Circulated 340 bbls of 6% Kcl. Recovered materials from plugs, recovered 110 bbls oil while circulating. LD Power swivel. LD 18 jts of 2- 7/8" 8 RD. SOOH w/80 stands 2-7/8". 11/26/2012- Monday No activity to report. 11/27/2012-Tuesday No activity to report. Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 44-33 50-133-20237-01 212-143 9/18/12 Daily Operations: 11/28/2012-Wednesday _ SOOH w/WS. LD Haliburton packer and tcp guns. MU 4-1/2" hydraulic FH packer w/ pump out sub, on prod string and GL mandrels. TIH to set packer @ 11,420'. MU tbg hander and landed in welhead. Dropped packer setting ball and attempted to pressure up on packer. Pump out sub gave up at 3,200 psi before setting packer. MIRU Pollard SL unit. Pumped a W- circulating plug down to x-nipple @ 11,587'wlm. Set in nipple. Attempted to pressure up on plug, walked up to 3,000 psi and plug blew thru nipple. Pulled plug thru nipple and reset. Walked psi up to 4,500 psi. Set packer @ 11,420'. After holding for 3-4 mins, pressure started falling off. Bled down. POOH Found plug had sheared setting tool. Re pinned setting tool. RBIH,tagged and latched plug. POOH. Found plug o-rings and seal were all gone. Redressed plug and TBIH. Pumped plug back down and set in 2-3/8" nipple. Walked pressure up to 3,000 psi. Started tbg test/chart. Charted for 18 mins and pressure started falling again. Bled psi off and POOH w/plug. RDMO Pollard SL unit. Started to ND Bops. 11/29/2012-Thursday Finished ND Bops. NU Welhead,tested void and wellhead connection,test good. Started rigging down winterization package and WOR. 11/30/2012 - Friday Finished rigging WOR and equipment down. Removed all equip from location. 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COCC09000Nr V NOONNMN'OCDCONnppMmom0- m6Co MM 60Y6 C/)OomNr M M COM V V N V OD ,O CO Cn Cn m6 0C0 V CO Co C=- 0)co m 0 6 m fo n n n CO O) o o m r r n m co O m co co ad 6o 0 2 0 0 0 CO CD CD CD CD CO CD CD CO CO CO CO to CO m CO CO Co Co Co NCD CO CO CO CD Cfi CD CO Co CD CD CD CD 000000000000•00•000O0•0•00 goee°000og 00000 00000 00000 000 8 . . . . . . . . . 0^ m6 NCOCD M�mn O MmOM�NCOMComm co 0CoCMCCNO Co 2� O m 0006 N 0cpmM 6CD Nm O n4Om Nm V n M88° VO n Co/LP) 0 O V N 0 0 0 0 0 0 0 0 0 • N M M N N m m n 00 m 6 N N N N N N N II CASING RUN IN TALLY WELL NAME: SCU 44-33 DATE: 11/01/12 CASING SIZE 4.500 WEIGHT 12.60 CASING ID 3.958 GRADE L-80 THREAD DWC/C-HT Tubing CAPACITY 0.0152 bbls/ft TORQUE - MAXIMUM=6,500 MIN=5,800 DISPLACEMENT 0.0046 bbls/ft SHOE DEPTH 12423.0 feet Coupling OD=5.03,Drift 3.833 HOLE TD 12425.0 feet MUD WT 11.04 ppg Joint Running Joint Depth BOUY FACTOR 0.83 Joint# Joint# Length Total Bottom Top REMARKS Bouyant Capacit}Displmt on Rack in hole feet feet feet feet weight bbls bbls Off Rntti,r, 2.00 Block Weight = 65,000 Weatherford Reamer Shoe,OD-5.75, A 2.25 2.25 12423.00 12420.75 SN-1779046713, 65,023 0.0 0.0 BakerLocked Joint Centrilizer w/stop ring 10' 101 41.47 43.72 12420.75 12379.28 from shoe 65,454 0.7 0.2 BakerLocked Joint Centrilizer w/stop ring 100 2 41.71 85.43 12379.28 12337.57 mid-joint Float Collar.BTC, B Fit Cir 1.35 86.78 12337.57 12336.22 SN-577436 65,469 0.7 0.2 Baker Locked Joint 99 3 41.81 128.59 12336.22 12294.41 w/Centralizer Mid-joint 65,903 1.3 0.4 Pup Joint W/Bakerlocked Pup 4.71 133.30 12294.41 12289.70 Coupling 65,952 1.4 0.4 Landing Collar,BTC, SN-53205, D LC 1.29 134.59 12289.70 12288.41 PO-4505554843 65,965 1.4 0.4 Short Joint vv/Centralizer 98 34.02 168.61 12288.41 12254.39 #4 66,319 1.9 0.6 97 5 41.80 210.41 12254.39 12212.59 Centralizer 5 96 6 41.78 252.19 12212.59 12170.81 Centralizer 6 66,753 2.6 0.8 95 7 41.66 293.85 12170.81 12129.15 Centralizer? 67,186 3.2 1.0 94 8 41.80 335.65 12129.15 12087.35 Centralizer 8 67,621 3.8 1.2 93 9 41.15 376.80 12087.35 12046.20 Centralizer 9 68,049 4.5 1.3 92 10 41.76 418.56 12046.20 12004.44 Centralizer 10 68,483 5.1 1.5 91 11 41.81 460.37 12004.44 11962.63 Centralizer 11 68,917 5.7 1.7 90 12 41.45 501.82 11962.63 11921.18 Centralizer 12 69,348 6.4 1.9 89 13 41.74 543.56 11921.18 11879.44 Centralizer 13 69,782 7.0 2.1 88 14 41.78 585.34 11879.44 11837.66 Centralizer 14 70,217 7.6 2.3 87 15 41.81 627.15 11837.66 11795.85 Centralizer 15 70,651 8.3 2.5 86 16 40.91 668.06 11795.85 11754.94 Centralizer 16 71,076 8.9 2.7 85 17 41.74 709.80 11754.94 11713.20 Centralizer 17 71,510 9.5 2.9 84 18 41.76 751.56 11713.20 11671.44 Centralizer 18 71,944 10.2 3.1 83 19 41.79 793.35 11671.44 11629.65 Centralizer 19 72,379 10.8 3.3 82 20 41.80 835.15 11629.65 11587.85 Centralizer 20 72,813 11.4 3.4 81 21 41.78 876.93 11587.85 11546.07 Centralizer 21 73,248 12.1 3.6 80 22 41.56 918.49 11546.07 11504.51 Centralizer 22 73,680 12.7 3.8 4 5 inch Production Liner SCU 44-33.xls 7"casing tally 12/31/2012 3:56 PM II CASING RUN IN TALLY WELL NAME: SCU 44-33 DATE: 11/01/12 CASING SIZE 4.500 WEIGHT 12.60 CASING ID 3.958 GRADE L-80 THREAD DWC/C-HT Tubing CAPACITY 0.0152 bbls/ft TORQUE - MAXIMUM=6,500 MIN=5,800 DISPLACEMENT 0.0046 bbls/ft SHOE DEPTH 12423.0 feet Coupling OD=5.03,Drift 3.833 HOLE TD 12425.0 feet MUD WT 11.04 ppg Joint Running Joint Depth BOUY FACTOR 0.83 Joint# Joint# Length Total Bottom Top REMARKS Bouyant Capacit;Displmt on Rack in hole feet feet feet feet weight bbls bbls 79 23 41.78 960.27 11504.51 11462.73 Centralizer23 74,114 13.3 4.0 78 24 41.55 1001.82 11462.73 11421.18 Centralizer 24 74,546 14.0 4.2 77 25 41.11 1042.93 11421.18 11380.07 Centralizer 25 74,973 14.6 4.4 76 26 41.45 1084.38 11380.07 11338.62 Centralizer26 75,404 15.2 4.6 75 27 41.75 1126.13 11338.62 11296.87 Centralizer27 75,838 15.9 4.8 74 28 41.79 1167.92 11296.87 11255.08 Centralizer 28 76,272 16.5 5.0 73 29 41.78 1209.70 11255.08 11213.30 Centralizer 29 76,707 17.1 5.2 72 30 41.77 1251.47 11213.30 11171.53 Centralizer30 77,141 17.8 5.3 71 31 41.78 1293.25 11171.53 11129.75 Centralizer 31 77,575 18.4 5.5 70 32 41.77 1335.02 11129.75 11087.98 Centralizer 32 78,009 19.0 5.7 69 33 40.47 1375.49 11087.98 11047.51 Centralizer33 78,430 19.7 5.9 68 34 41.76 1417.25 11047.51 11005.75 Centralizer 34 78,864 20.3 6.1 67 35 41.78 1459.03 11005.75 10963.97 Centralizer 35 79,299 20.9 6.3 66 36 41.77 1500.80 10963.97 10922.20 Centralizer 36 79,733 21.6 6.5 65 37 41.80 1542.60 10922.20 10880.40 Centralizer37 80,167 22.2 6.7 64 38 41.78 1584.38 10880.40 10838.62 Centralizer38 80,602 22.8 6.9 63 39 41.43 1625.81 10838.62 10797.19 81,032 23.5 7.1 62 40 41.82 1667.63 10797.19 10755.37 Centralizer39 81,467 24.1 7.3 61 41 40.03 1707.66 10755.37 10715.34 81,883 24.7 7.4 60 42 41.36 1749.02 10715.34 10673.98 Centralizer 40 82,313 25.3 7.6 59 43 41.81 1790.83 10673.98 10632.17 82,748 26.0 7.8 58 44 41.80 1832.63 10632.17 10590.37 Centralizer 41 83,182 26.6 8.0 57 45 41.81 1874.44 10590.37 10548.56 83,617 27.3 8.2 56 46 41.46 1915.90 10548.56 10507.10 Centralizer 42 84,048 27.9 8.4 55 47 41.81 1957.71 10507.10 10465.29 84,482 28.5 8.6 54 48 41.82 1999.53 10465.29 10423.47 Centralizer 43 84,917 29.2 8.8 53 49 41.48 2041.01 10423.47 10381.99 85,348 29.8 9.0 52 50 41.75 2082.76 10381.99 10340.24 Centralizer 44 - 30.4 9.2 51 51 41.78 2124.54 10340.24 10298.46 85,783 31.1 9.3 50 52 41.77 2166.31 10298.46 10256.69 Centralizer 45 85,783 31.7 9.5 49 53 41.78 2208.09 10256.69 10214.91 86,217 32.3 9.7 48 54 41.79 2249.88 10214.91 10173.12 Centralizer 46 85,783 33.0 9.9 47 55 41.81 2291.69 10173.12 10131.31 86,651 33.6 10.1 46 56 41.49 2333.18 10131.31 10089.82 Centralizer 47 85,783 34.2 10.3 45 57 41.75 2374.93 10089.82 10048.07 87,085 34.9 10.5 4 5 inch Production Liner SCU 44-33.xls 7"casing tally 12/31/2012 3:56 PM II CASING RUN IN TALLY WELL NAME: SCU 44-33 DATE: 11/01/12 CASING SIZE 4.500 WEIGHT 12.60 CASING ID 3.958 GRADE L-80 THREAD DWC/C-HT Tubing CAPACITY 0.0152 bbls/ft TORQUE - MAXIMUM=6,500 MIN=5,800 DISPLACEMENT 0.0046 bbls/ft SHOE DEPTH 12423.0 feet Coupling OD=5.03,Drift 3.833 HOLE TD 12425.0 feet MUD WT 11.04 ppg Joint Running Joint Depth BOUY FACTOR 0.83 Joint# Joint# Length Total Bottom Top REMARKS Bouyant Capacity Displmt on Rack in hole feet feet feet feet weight bbls bbls 44 58 41.80 2416.73 10048.07 10006.27 Centralizer 48 85,783 35.5 10.7 43 59 41.78 2458.51 10006.27 9964.49 87,520 36.1 10.9 42 60 41.18 2499.69 9964.49 9923.31 Centralizer 49 85,783 36.8 11.1 41 61 41.78 2541.47 9923.31 9881.53 87,954 37.4 11.3 40 62 40.60 2582.07 9881.53 9840.93 Centralizer 50 86,217 38.0 11.4 39 63 41.75 2623.82 9840.93 9799.18 88,388 38.7 11.6 38 64 41.58 2665.40 9799.18 9757.60 Centralizer51 86,651 39.3 11.8 37 65 41.18 2706.58 9757.60 9716.42 88,816 39.9 12.0 36 66 41.78 2748.36 9716.42 9674.64 Centralizer 52 87,085 40.6 12.2 35 67 40.80 2789.16 9674.64 9633.84 89,240 41.2 12.4 34 68 41.38 2830.54 9633.84 9592.46 Centralizer 53 87,520 41.8 12.6 33 69 41.78 2872.32 9592.46 9550.68 89,675 42.4 12.8 32 70 41.79 2914.11 9550.68 9508.89 Centralizer 54 85,783 43.1 13.0 31 71 41.78 2955.89 9508.89 9467.11 90,109 43.7 13.2 30 72 41.80 2997.69 9467.11 9425.31 Centralizer 55 85,783 44.3 13.3 I 29 73 40.38 3038.07 9425.31 9384.93 90,529 45.0 13.5 28 74 41.75 3079.82 9384.93 9343.18 Centralizer56 85,783 45.6 13.7 27 75 40.65 3120.47 9343.18 9302.53 90,951 46.2 13.9 26 76 40.79 3161.26 9302.53 9261.74 Centralizer 57 85,783 46.8 14.1 25 77 40.57 3201.83 9261.74 9221.17 91,373 47.5 14.3 24 78 41.49 3243.32 9221.17 9179.68 Centralizer 58 85,783 48.1 14.5 23 79 41.78 3285.10 9179.68 9137.90 91,807 48.7 14.7 22 80 41.59 3326.69 9137.90 9096.31 Centralizer 59 86,217 49.4 14.9 21 81 41.79 3368.48 9096.31 9054.52 92,242 50.0 15.0 20 82 41.78 3410.26 9054.52 9012.74 Centralizer 60 92,242 50.6 15.2 19 83 40.96 3451.22 9012.74 8971.78 92,667 51.2 15.4 18 84 41.61 3492.83 8971.78 8930.17 Centralizer 61 92,242 51.9 15.6 17 85 41.77 3534.60 8930.17 8888.40 93,102 52.5 15.8 16 86 41.37 3575.97 8888.40 8847.03 Centralizer 62 92,242 53.1 16.0 15 87 41.79 3617.76 8847.03 8805.24 93,536 53.8 16.2 Pup,XO,Baker Liner Hanger,ZXP Packer& 37.59 3655.35 8805.24 8767.65 PBR 93,536 54.4 16.4 6.57 3661.92 8767.65 8761.08 Running Tool 93,604 54.5 16.4 XO,HT-38 x 3 1/2 IF 1.50 3663.42 8761.08 8759.58 (BxP) 93,536 54.5 16.4 4 5 inch Production Liner SCU 44-33.xls 7"casing tally 12/31/2012 3:56 PM CASING RUN IN TALLY WELL NAME: SCU 44-33 DATE: 11/01/12 CASING SIZE 4.500 WEIGHT 12.60 CASING ID 3.958 GRADE L-80 THREAD DWC/C-HT Tubing CAPACITY 0.0152 bbls/ft TORQUE - MAXIMUM=6,500 MIN=5,800 DISPLACEMENT 0.0046 bbls/ft SHOE DEPTH 12423.0 feet Coupling OD=5.03,Drift 3.833 HOLE TD 12425.0 feet MUD WT 11.04 ppg Joint Running Joint Depth BOUY FACTOR 0.83 Joint# Joint# Length Total Bottom Top REMARKS Bouyant Capacit2 Displmt on Rack in hole feet feet feet feet weight bbls bbls 544.91 4208.33 8759.58 8214.67 (18) HWDP 99,269 62.8 18.9 8175.05 12383.38 8214.67 39.62 (118),Dp to surface 93,536 187.2 56.3 31.50 12414.88 39.62 8.12 Single from Pipe Shed 99,596 187.6 56.5 Make up 10'pup to single 10.00 12424.88 8.12 -1.88 and stage in Pipe Shed 93,536 187.8 56.5 Make up 15'pup to top of Cement Head Joints not run 14 88 41.53 13 89 41.79 12 90 40.83 11 91 41.75 10 92 41.77 9 93 41.59 8 94 41.23 7 95 41.31 6 96 41.38 5 97 41.81 4 98 41.78 3 99 41.79 2 100 41.58 1 101 41.35 102 Joint with 6 1/2" Reamer Shoe 4 5 inch Production Liner SCU 44-33.xls 7"casing tally 12/31/2012 3:56 PM Schlumberger .;ementing Job Report CemCATv1.3 Well SCU 44-33 Client Hilcorp Field Swanson River SIR No. Engineer Daniel Settle/Peter Cahill Job Type Liner Country United States Job Date 10-30-2012 Time Pressure Rate Density Messages 10/30/3012 13:51:10 I 14:10:51 � just had pre job saftey meeting j I i 14:26:00 Reset Total,Vol=6.58 bbl 14:41:00 l 5 bbls of FW ahead 5 bbls FW away down on the pump shutting in for Low PT — .� low pressure stall 14:56:00 rig floor has a leak bleed off pressure low pressure stall rig floor had a leak bled pressure off 15:11:00 11.111111111 ....- • Low pressure stall 121101111■ ^T low PT good High PT bleeding off pressure to reflood lines Rig rebuilt the manifold and we had air In 15:26:00 I I ( I FW ahead to flood lines down on pump rig shutting valve for PT High PT I I High PT good bleeding pressure off Reset Total,Vol=7.59 bbl j Reset Total,Vol=0.00 bbl I j• i I Rig to start pumping MUD PUSH 15:41:00 I Batch up cement 1 weight verified by mud balance on line with cement l I swap to silo 15:56:00 I I I Down on the pump ' 16:11:004 Line up to Ton the floor to clear lines 1-1 mud to displace • Reset Total,Vol=106.67 bbl dart launch confirmed by tattle tall 16:26:00 I 11111 1 slow rate for latch 89.6 bbls away latched 16:41:00 I slow rate to bump plug � I bumped plug IIIIIIIIIIIILmm bleed off check floats ibbl back I Ii I bring up pressure to 3000 psi 16:56:00 ; ' ' bring up pressure to 4,000 psi ' I i Bleed Off Pressure Stopped Acquisition I I l i j 17:11:00 i ' i I � � � r 1 . � `I 17:27:43 ! . . . • • I : ! I hh:mm:ss 0.00 1000 2000 3000 9000 5000 0.00 2.0 4.0 6.0 6.0 10.0 5.0 10.0 15.0 20.0 25.0 10/31/201217:27:43 PSI B/M LB/G 11/21/2012 10:59:18 $cblumberger Cementing Service I ort Customer Job Number Hilcorp Well Location(legal) Schlumberger Location Job Start SCU 44-33 Oct/30/2012 Field Formation Name/Type Deviation Bit Size Well MD Well TVD Swanson River County State/Province AK BHP BHST BHCT Pore Press.Gradient Well Master API/UWI Rig Name Drilled For Service Via Casing/Liner DOy0n Rig 1 Gas Land Depth, Size, Weight, Grade Thread Offshore Zone Well Class Well Type Old Development Drilling Fluid Type Max.Density Plastic Viscosity Tubing/Drill Pipe Depth, Size, Weight, Grade Thread Service Line Job Type Cementing Cement Liner Max.Allowed Tub.Press Max.Allowed Ann.Press WH Connection Perforations/Open Hole Top, Bottom, No.of Shots Total Interval Service Instructions Pump 98 bbls of 15.8 ppg cement Diameter Treat Down Displacement Packer Type Packer Depth Tubing Vol. Casing Vol. Annular Vol. Openhole Vol. Casing/Tubing Secured 0 1 Hole Vol.Circulated prior to Cement 0 Casing Tools Squeeze Job Lift Pressure Shoe Type Squeeze Type Pipe Rotated 0 Pipe Reciprocated El Shoe Depth Tool Type No.Centralizers Top Plugs Bottom Plugs Stage Tool Type Tool Depth Cement Head Type Stage Tool Depth Tail Pipe Size Job Scheduled For Arrived on Location Leave Location Collar Type Tail Pipe Depth Oct/30/2012 Oct/30/2012 Oct/30/2012 Collar Depth Sqz.Total Vol. Date Time Treating Flow Density Volume Stage Message 24-hr Pressure Rate LB/G BBL BBL clock PSI B/M 10/30/2012 13:43:10 Started Acquisition 10/30/2012 13:51:10 31 0.0 0.00 0.0 0.0 10/31/2012 11:19:10 -2 0.1 -0.00 0.0 0.0 10/31/2012 11:20:10 -2 0.1 -0.00 0.2 0.2 10/31/2012 11:21:10 -2 0.1 -0.00 0.2 0.2 10/31/2012 11:22:10 -1 0.1 -0.00 0.3 0.3 10/31/2012 11:22:20 priming pump 10/31/2012 11:22:20 -2 0.1 -0.00 0.4 0.4 10/31/2012 11:23:10 -2 0.0 -0.00 0.4 0.4 10/31/2012 11:24:10 -2 0.0 -0.00 0.5 0.5 10/31/2012 11:25:10 -1 0.0 -0.00 0.5 0.5 10/31/2012 11:26:10 -2 0.0 -0.00 0.5 0.5 10/31/2012 11:27:10 -2 0.0 -0.00 0.6 0.6 10/31/2012 11:28:10 -2 0.0 -0.00 0.6 0.6 10/31/2012 11:29:10 -2 0.0 -0.00 0.6 0.6 10/31/2012 11:30:10 -1 0.0 -0.00 0.6 0.6 10/31/2012 11:31:10 -2 0.0 -0.00 0.7 0.7 10/31/2012 11:32:10 -1 0.0 -0.00 0.7 0.7 10/31/2012 11:33:10 -3 0.0 -0.00 0.7 0.7 10/31/2012 11:34:10 -2 0.0 -0.00 0.7 0.7 10/31/2012 11:35:10 -1 0.0 -0.00 0.8 0.8 Page 1 of 8 ^Well Field Job Start Customer Job Number SCU 44-33 Swanson River Oct/30/2012 Hilcorp Date Time Treating Flow Density Volume Stage Message 24-hr Pressure Rate LB/G BBL BBL dock PSI B/M 10/31/2012 11:37:10 -1 0.0 -0.00 0.8 0.8 10/31/2012 11:38:10 -1 0.0 -0.00 0.8 0.8 10/31/2012 11:39:10 -2 0.0 -0.00 0.9 0.9 10/31/2012 11:39:20 frozen water take on pipe on 372.Getting a heater 10/31/2012 11:39:20 -1 0.0 -0.00 0.9 0.9 10/31/2012 11:40:10 -2 0.1 -0.00 0.9 0.9 10/31/2012 11:41:10 -2 0.0 -0.00 0.9 0.9 10/31/2012 11:42:10 -2 0.0 -0.00 1.0 1.0 10/31/2012 11:43:10 -2 0.0 -0.00 1.0 1.0 10/31/2012 11:44:10 -1 0.0 -0.00 1.0 1.0 10/31/2012 11:45:10 -1 0.0 -0.00 1.1 1.1 10/31/2012 11:46:10 -2 0.0 -0.00 1.1 1.1 10/31/2012 11:47:10 -1 0.0 -0.00 1.1 1.1 10/31/2012 11:48:10 0 0.0 -0.00 1.2 1.2 10/31/2012 11:49:10 -1 0.0 -0.00 1.2 1.2 10/31/2012 11:50:10 -1 0.0 -0.00 1.2 1.2 10/31/2012 11:51:10 -1 0.0 -0.00 1.2 1.2 10/31/2012 11:52:10 -1 0.0 -0.00 1.3 1.3 10/31/2012 11:53:06 heater thawed plug 10/31/2012 11:53:06 -1 0.0 -0.00 1.3 1.3 10/31/2012 11:53:10 -2 0.0 -0.00 1.3 1.3 10/31/2012 11:53:19 priming up pump 10/31/2012 11:53:19 -2 0.0 -0.00 1.3 1.3 10/31/2012 11:54:10 1 0.0 7.73 1.3 1.3 10/31/2012 11:55:10 -1 0.0 8.36 1.3 1.3 10/31/2012 11:56:10 1 0.3 8.09 3.7 3.7 10/31/2012 11:57:10 1 0.1 8.36 3.7 3.7 10/31/2012 11:58:10 1 5.2 8.34 6.6 6.6 10/31/2012 11:59:10 1 5.4 8.36 10.3 10.3 10/31/2012 12:00:10 1 0.0 8.37 12.1 12.1 10/31/2012 12:01:10 3 0.1 8.36 12.2 12.2 10/31/2012 12:02:10 3 0.0 8.37 12.2 12.2 • 10/31/2012 12:03:10 2 0.0 8.37 12.2 12.2 10/31/2012 12:04:10 1 0.0 8.36 12.2 12.2 10/31/2012 12:05:10 1 0.1 0.13 12.3 12.3 10/31/2012 12:06:10 3 0.0 8.21 12.3 12.3 10/31/2012 12:07:10 1 0.0 8.37 12.4 12.4 10/31/2012 12:08:10 -1 5.4 8.36 14.5 14.5 10/31/2012 12:09:10 1 5.5 8.37 19.3 19.3 10/31/2012 12:10:10 1 0.1 8.37 19.9 19.9 10/31/2012 12:11:10 0 0.1 8.37 19.9 19.9 10/31/2012 12:12:10 -0 0.0 8.36 22.1 22.1 10/31/2012 12:13:10 1 4.4 8.37 25.6 25.6 10/31/2012 12:14:10 1 0.1 8.36 29.5 29.5 10/31/2012 12:15:10 -0 0.0 8.36 29.5 29.5 10/31/2012 12:16:10 0 0.0 8.37 29.5 29.5 10/31/2012 12:17:10 -0 0.0 8.37 29.5 29.5 10/31/2012 12:18:10 0 0.4 8.37 29.5 29.5 10/31/2012 12:19:10 -0 3.1 8.37 32.0 32.0 10/31/2012 12:20:10 -0 3.1 8.37 35.0 35.0 10/31/2012 12:21:10 1 3.0 8.37 37.6 37.6 10/31/2012 12:22:10 1 3.0 8.37 40.6 40.6 10/31/2012 12:23:10 1 0.0 8.38 40.7 40.7 10/31/2012 12:24:10 1 0.0 8.37 40.7 40.7 Page 2 of 8 Well Field Job Start Customer Job Number SCU 44-33 Swanson River Oct/30/2012 Hilcorp Date Time Treating Flow Density Volume Stage Message 24-hr Pressure Rah LB/G BBL BBL clock PSI B/M 10/31/2012 12:24:49 2 0.0 8.37 40.7 40.7 10/31/2012 12:25:10 1 0.0 8.37 40.7 40.7 10/31/2012 12:25:56 Reset Total,Vol=40.70 bbl 10/31/2012 12:25:56 1 0.0 8.37 40.7 40.7 10/31/2012 12:26:10 1 0.0 8.37 0.0 0.0 10/31/2012 14:11:09 Just had pre job saftey meeting 10/31/2012 14:11:09 2 0.0 8.37 0.0 0.0 10/31/2012 14:11:10 3 0.0 8.37 0.0 0.0 10/31/2012 14:12:10 2 0.0 8.37 0.0 0.0 10/31/2012 14:13:10 3 0.0 8.37 0.0 0.0 10/31/2012 14:14:10 2 0.0 8.37 0.0 0.0 10/31/2012 14:15:10 1 0.0 8.38 0.0 0.0 10/31/2012 14:16:10 3 0.0 8.37 0.0 0.0 10/31/2012 14:17:10 0 0.0 8.37 0.0 0.0 10/31/2012 14:18:10 -0 0.0 8.37 0.0 0.0 10/31/2012 14:19:10 1 0.0 8.37 0.0 0.0 10/31/2012 14:20:10 7 0.0 8.37 0.0 0.0 10/31/2012 14:21:10 5 2.8 8.39 0.2 0.2 10/31/2012 14:22:10 5 4.6 8.37 3.2 3.2 10/31/2012 14:23:10 5 2.8 8.36 5.7 5.7 10/31/2012 14:24:10 5 0.0 8.37 6.6 6.6 10/31/2012 14:25:10 6 0.0 8.37 6.6 6.6 10/31/2012 14:26:10 4 0.0 8.37 6.6 6.6 10/31/2012 14:27:10 5 0.0 8.37 6.6 6.6 10/31/2012 14:28:10 5 0.0 8.37 6.6 6.6 10/31/2012 14:29:10 5 0.0 8.37 6.6 6.6 10/31/2012 14:30:10 5 0.0 8.36 6.6 6.6 10/31/2012 14:31:10 5 0.0 8.37 6.6 6.6 10/31/2012 14:32:10 5 0.0 8.36 6.6 6.6 i 10/31/2012 14:33:10 5 0.0 8.37 6.6 6.6 10/31/2012 14:34:10 5 0.0 8.37 6.6 6.6 10/31/2012 14:35:10 5 0.0 8.37 6.6 6.6 10/31/2012 14:36:10 5 0.0 8.37 6.6 6.6 10/31/2012 14:36:22 Reset Total,Vol=6.58 bbl 10/31/2012 14:36:22 6 0.0 8.37 6.6 6.6 I 10/31/2012 14:37:10 5 0.0 8.38 0.0 0.0I, 10/31/2012 14:38:10 3 0.0 8.37 0.0 0.0 10/31/2012 14:39:10 3 0.0 8.37 0.0 0.0 10/31/2012 14:40:10 3 0.0 8.35 0.0 0.0 I 10/31/2012 14:41:10 5 0.0 8.36 0.0 0.0 10/31/2012 14:42:10 5 0.0 8.35 0.0 0.0 10/31/2012 14:43:10 5 0.0 8.35 0.0 0.0 10/31/2012 14:44:10 6 0.0 8.35 0.0 0.0 10/31/2012 14:45:10 6 0.0 8.35 0.0 0.0 `. 10/31/2012 14:46:10 142 0.0 8.36 0.0 0.0 10/31/2012 14:46:14 5 bbls of FW ahead 10/31/2012 14:46:14 137 0.2 8.36 0.0 0.0 10/31/2012 14:47:10 254 0.9 8.37 0.9 0.9 10/31/2012 14:48:10 516 2.1 8.37 2.8 2.8 10/31/2012 14:49:10 256 1.0 8.37 4.8 4.8 10/31/2012 14:49:42 5 bbls FW away down on the pump 10/31/2012 14:49:42 109 0.0 8.37 4.9 4.9 10/31/2012 14:50:05 shutting in for Low PT 10/31/2012 14:50:05 106 0.0 8.37 4.9 4.9 Page 3 of 8 Well Field Job Start Customer Job Number SCU 44-33 Swanson River Oct/30/2012 Hilcorp Date Time Treating Flow Density Volume Stage Message 24-hr Pressure Rate LB/G BBL BBL clock PSI B/M 10/31/2012 14:51:10 110 0.0 8.37 4.9 4.9 10/31/2012 14:51:25 low pressure stall 10/31/2012 14:51:25 757 0.0 8.37 4.9 4.9 10/31/2012 14:52:10 70 0.0 8.37 4.9 4.9 10/31/2012 14:52:27 rig floor has a leak bleed off pressure 10/31/2012 14:52:27 22 0.0 8.37 4.9 4.9 10/31/2012 14:53:10 11 0.0 8.37 4.9 4.9 10/31/2012 14:54:10 11 0.0 8.36 4.9 4.9 10/31/2012 14:54:45 low pressure stall 10/31/2012 14:54:45 14 0.0 8.36 4.9 4.9 10/31/2012 14:55:10 756 0.0 8.36 5.0 5.0 10/31/2012 14:56:02 rig floor had a leak bled pressure off 10/31/2012 14:56:02 23 0.0 8.37 5.0 5.0 10/31/2012 14:56:10 17 0.0 8.37 5.0 5.0 10/31/2012 14:57:10 9 0.0 8.37 5.0 5.0 10/31/2012 14:58:10 12 0.0 8.36 5.0 5.0 10/31/2012 14:59:10 14 0.0 8.35 5.0 5.0 10/31/2012 15:00:10 14 0.0 8.36 5.0 5.0 10/31/2012 15:01:10 13 0.0 8.35 5.0 5.0 10/31/2012 15:02:10 13 0.0 8.35 5.0 5.0 10/31/2012 15:03:10 14 0.0 8.35 5.0 5.0 10/31/2012 15:04:10 14 0.0 8.35 5.0 5.0 10/31/2012 15:05:10 15 0.0 8.35 5.0 5.0 10/31/2012 15:06:10 14 0.0 8.35 5.0 5.0 10/31/2012 15:07:10 14 0.0 8.35 5.0 5.0 10/31/2012 15:08:10 15 0.0 8.35 5.0 5.0 10/31/2012 15:09:10 15 0.0 8.35 5.0 5.0 10/31/2012 15:10:10 16 0.0 8.35 5.0 5.0 10/31/2012 15:11:10 16 0.0 8.36 5.0 5.0 10/31/2012 15:12:10 16 0.0 8.36 5.0 5.0 10/31/2012 15:13:10 17 0.0 8.36 5.0 5.0 10/31/2012 15:14:10 Low pressure stall '. 10/31/2012 15:14:10 55 1.1 8.36 5.1 5.1 III 10/31/2012 15:15:10 960 0.0 8.37 5.2 5.2 10/31/2012 15:15:11 low PT good 10/31/2012 15:15:11 960 0.0 8.37 5.2 5.2 10/31/2012 15:15:22 High PT 10/31/2012 15:15:22 1208 0.1 8.37 5.2 5.2 10/31/2012 15:16:10 2661 0.0 8.37 5.2 5.2 10/31/2012 15:17:08 bleeding off pressure to reflood lines 10/31/2012 15:17:08 33 0.0 8.37 5.2 5.2 - / 10/31/2012 15:17:10 32 0.0 8.37 5.2 5.2 10/31/2012 15:18:10 17 0.0 8.37 5.2 5.2 10/31/2012 15:18:27 Rig rebuilt the manifold and we had air in the lines 10/31/2012 15:18:27 17 0.0 8.37 5.2 5.2 10/31/2012 15:19:10 11 0.0 8.37 5.2 5.2 10/31/2012 15:19:49 FW ahead to flood lines 10/31/2012 15:19:49 44 1.1 8.37 5.2 5.2 10/31/2012 15:20:10 633 1.4 8.37 5.7 5.7 10/31/2012 15:21:10 488 1.5 8.37 7.2 7.2 10/31/2012 15:21:54 down on pump rig shutting valve for PT 10/31/2012 15:21:54 162 0.0 8.37 7.6 7.6 10/31/2012 15:22:10 160 0.0 8.37 7.6 7.6 10/31/2012 15:23:10 160 0.0 8.37 7.6 7.6 Page 4 of 8 Well Field Job Start Customer lob Number SCU 44-33 Swanson River Oct/30/2012 Hilcorp Date Time Treating Flow Density Volume Stage Message 24-hr Pressure Rata LB/G BBL BBL clock PSI B/M 10/31/2012 15:23:27 160 0.0 8.37 7.6 7.6 10/31/2012 15:24:10 5274 0.0 8.37 7.6 7.6 10/31/2012 15:24:42 Hugh PT good bleeding pressure off 10/31/2012 15:24:42 31 0.0 8.37 7.6 7.6 10/31/2012 15:25:02 Reset Total,Vol=7.59 bbl 10/31/2012 15:25:02 37 0.0 8.37 7.6 7.6 10/31/2012 15:25:04 Reset Total,Vol=0.00 bbl 10/31/2012 15:25:04 37 0.0 8.37 7.6 0.0 10/31/2012 15:25:10 37 0.0 8.37 0.0 0.0 10/31/2012 15:25:35 Rig to start pumping MUD PUSH 10/31/2012 15:25:35 38 0.0 8.38 0.0 0.0 10/31/2012 15:26:10 39 0.0 8.38 0.0 0.0 10/31/2012 15:27:10 93 0.0 8.38 0.0 0.0 10/31/2012 15:28:10 92 0.0 8.38 0.0 0.0 10/31/2012 15:29:10 89 0.0 8.38 0.0 0.0 10/31/2012 15:30:10 87 0.0 8.38 0.0 0.0 10/31/2012 15:31:10 85 0.0 8.38 0.0 0.0 10/31/2012 15:32:05 Batch up cement 10/31/2012 15:32:05 82 0.0 8.37 0.0 0.0 10/31/2012 15:32:10 82 0.0 8.34 0.0 0.0 10/31/2012 15:33:10 81 0.0 7.93 0.0 0.0 10/31/2012 15:34:10 80 0.0 10.75 0.0 0.0 10/31/2012 15:35:10 77 0.0 14.43 0.0 0.0 10/31/2012 15:36:10 43 0.0 15.55 0.0 0.0 10/31/2012 15:37:10 36 0.0 15.71 0.0 0.0 10/31/2012 15:38:10 33 0.0 15.70 0.0 0.0 10/31/2012 15:38:58 weight verified by mud balance 10/31/2012 15:38:58 48 0.0 15.71 0.0 0.0 10/31/2012 15:39:10 68 0.0 15.69 0.0 0.0 10/31/2012 15:39:13 on line with cement 10/31/2012 15:39:13 68 0.0 15.68 0.0 0.0 10/31/2012 15:40:10 757 3.2 15.72 1.1 1.1 10/31/2012 15:41:10 781 3.9 15.83 4.8 4.8 10/31/2012 15:42:10 765 3.9 15.55 8.7 8.7 10/31/2012 15:43:10 844 3.9 15.65 12.6 12.6 10/31/2012 15:44:10 539 3.9 15.36 16.5 16.5 10/31/2012 15:45:10 60 0.5 13.35 18.8 18.8 10/31/2012 15:46:10 295 3.9 15.70 20.9 20.9 10/31/2012 15:47:10 433 3.9 15.86 24.7 24.7 10/31/2012 15:48:10 387 3.9 15.82 28.6 28.6 10/31/2012 15:49:10 428 3.9 15.63 32.5 32.5 10/31/2012 15:50:10 372 3.7 15.76 36.3 36.3 10/31/2012 15:50:55 swap to silo 10/31/2012 15:50:55 335 3.7 15.85 39.0 39.0 10/31/2012 15:51:10 397 3.8 16.06 40.0 40.0 10/31/2012 15:52:10 296 3.1 15.72 43.6 43.6 10/31/2012 15:53:10 269 3.7 15.77 47.0 47.0 10/31/2012 15:54:10 427 3.9 15.97 50.9 50.9 10/31/2012 15:55:10 295 3.9 15.77 54.7 54.7 10/31/2012 15:56:10 404 3.9 15.91 58.6 58.6 10/31/2012 15:57:10 337 3.9 15.93 62.5 62.5 10/31/2012 15:58:10 382 3.9 15.74 66.4 66.4 10/31/2012 15:59:10 359 3.9 15.98 70.3 70.3 10/31/2012 16:00:10 384 3.9 15.76 74.2 74.2 Page 5 of 8 Well Field Job Start Customer Job Number SCU 44-33 Swanson River Oct/30/2012 Hilcorp Date Time Treating Flow Density Volume Stage Message 24-hr Pressure Rab LB/G BBL BBL clock PSI B/M 10/31/2012 16:02:10 400 3.9 15.81 82.0 82.0 10/31/2012 16:03:10 428 3.9 15.66 85.8 85.8 10/31/2012 16:04:10 359 3.9 16.04 89.7 89.7 10/31/2012 16:05:10 318 3.9 15.66 93.6 93.6 10/31/2012 16:06:10 438 3.9 16.08 97.5 97.5 10/31/2012 16:07:07 Down on the pump 10/31/2012 16:07:07 43 0.0 0.49 100.2 100.2 10/31/2012 16:07:10 42 0.0 0.29 100.2 100.2 10/31/2012 16:07:26 Line up to Ton the floor to clear lines 10/31/2012 16:07:26 40 0.0 0.17 100.2 100.2 10/31/2012 16:08:10 39 0.0 0.11 100.2 100.2 10/31/2012 16:09:10 41 0.0 0.10 100.2 100.2 10/31/2012 16:10:10 269 4.2 8.41 102.0 102.0 10/31/2012 16:11:10 276 4.4 8.39 106.4 106.4 10/31/2012 16:12:10 26 0.0 8.45 106.7 106.7 10/31/2012 16:13:10 21 0.0 8.44 106.7 106.7 10/31/2012 16:14:10 23 0.0 8.44 106.7 106.7 10/31/2012 16:14:40 mud to displace 10/31/2012 16:14:40 24 0.0 8.44 106.7 106.7 10/31/2012 16:14:44 Reset Total,Vol=106.67 bbl 10/31/2012 16:14:44 36 0.0 8.44 106.7 106.7 10/31/2012 16:15:10 374 4.7 10.85 107.3 0.6 10/31/2012 16:15:22 dart launch confirmed by tattle tail 10/31/2012 16:15:22 328 4.6 11.19 108.2 1.5 10/31/2012 16:16:10 354 4.6 11.17 111.9 5.2 10/31/2012 16:17:10 349 4.6 11.12 116.5 9.8 10/31/2012 16:18:10 328 4.6 11.34 121.1 14.4 10/31/2012 16:19:10 311 4.6 11.33 125.7 19.0 10/31/2012 16:20:10 365 4.9 11.38 130.4 23.7 10/31/2012 16:21:10 377 4.9 11.36 135.3 28.6 10/31/2012 16:22:10 358 4.9 11.39 140.2 33.6 10/31/2012 16:23:10 339 4.9 11.39 145.2 38.5 10/31/2012 16:24:10 330 5.0 11.40 150.1 43.4 10/31/2012 16:25:10 307 5.1 11.40 155.2 48.5 10/31/2012 16:26:10 324 5.1 11.40 160.2 53.6 10/31/2012 16:27:10 363 5.1 11.40 165.3 58.6 10/31/2012 16:28:10 362 5.0 11.40 170.4 63.7 10/31/2012 16:29:10 359 5.1 11.40 175.4 68.8 10/31/2012 16:30:10 839 5.0 11.40 180.4 73.7 10/31/2012 16:31:10 967 5.0 11.40 185.4 78.7 (� 10/31/2012 16:31:27 slow rate for latch 10/31/2012 16:31:27 938 4.9 11.40 186.8 80.1 10/31/2012 16:32:10 245 3.0 11.41 188.9 82.2 10/31/2012 16:33:10 336 3.0 11.41 191.9 85.2 10/31/2012 16:34:10 468 3.0 11.41 194.9 88.3 10/31/2012 16:35:10 1181 4.9 11.41 198.3 91.7 10/31/2012 16:35:16 89.6 bbls away latched 10/31/2012 16:35:16 1158 5.0 11.41 198.8 92.2 10/31/2012 16:36:10 1206 4.9 11.41 203.3 96.6 10/31/2012 16:37:10 1313 4.9 11.41 208.2 101.5 10/31/2012 16:38:10 1349 4.9 11.41 213.1 106.4 10/31/2012 16:39:10 1414 4.9 11.41 218.0 111.4 10/31/2012 16:40:10 1402 4.9 11.41 222.9 116.3 10/31/2012 16:41:10 1475 4.9 11.41. 227.8 121.2 Page 6 of 8 Well Field Job Start Customer Job Number SCU 44-33 Swanson River Oct/30/2012 Hilcorp Date Time Treating Flow Density Volume Stage Message 24-hr Pressure Rate LB/G BBL BBL clock PSI B/M 10/31/2012 16:43:10 887 2.9 11.41 237.3 130.7 10/31/2012 16:43:15 slow rate to bump plug 10/31/2012 16:43:15 857 2.9 11.41 237.6 130.9 10/31/2012 16:44:10 912 2.9 11.42 240.2 133.5 10/31/2012 16:45:10 896 2.9 11.42 243.1 136.4 10/31/2012 16:46:10 870 2.9 11.42 246.0 139.3 10/31/2012 16:47:10 927 2.9 11.42 248.8 142.2 10/31/2012 16:48:10 1455 0.0 11.42 251.0 144.4 10/31/2012 16:48:48 bumped plug 10/31/2012 16:48:48 43 0.0 11.41 251.0 144.4 10/31/2012 16:49:10 23 0.0 11.40 251.0 144.4 10/31/2012 16:49:21 bleed off check floats lbbl back 10/31/2012 16:49:21 20 0.0 11.39 251.0 144.4 10/31/2012 16:50:09 bring up pressure to 3000 psi 10/31/2012 16:50:09 225 0.9 11.43 251.1 144.4 10/31/2012 16:50:10 195 0.9 11.43 251.1 144.4 10/31/2012 16:51:10 3148 0.0 11.43 252.3 145.6 10/31/2012 16:52:10 3220 0.0 11.44 252.3 145.6 10/31/2012 16:53:10 3247 0.0 11.44 252.3 145.6 10/31/2012 16:53:16 bring up pressure to 4,000 psi 10/31/2012 16:53:16 3376 0.6 11.42 252.3 145.6 10/31/2012 16:54:10 4058 0.0 11.44 252.6 145.9 10/31/2012 16:55:10 2995 0.0 11.43 252.6 145.9 10/31/2012 16:55:19 Bleed Off Pressure 10/31/2012 16:55:19 2216 0.0 11.43 252.6 145.9 10/31/2012 16:56:10 30 0.0 11.44 252.6 145.9 10/31/2012 16:57:10 19 0.0 11.42 252.6 145.9 10/31/2012 16:58:10 17 0.0 11.42 252.6 145.9 10/31/2012 16:59:10 16 0.0 11.41 252.6 145.9 10/31/2012 17:00:10 16 0.0 11.41 252.6 145.9 10/31/2012 17:01:10 16 0.0 11.41 252.6 145.9 10/31/2012 17:02:10 17 0.0 11.41 252.6 145.9 10/31/2012 17:03:10 18 0.0 11.41 252.6 145.9 10/31/2012 17:04:10 20 0.0 11.41 252.6 145.9 10/31/2012 17:05:10 19 0.0 11.41 252.6 145.9 10/31/2012 17:06:10 20 0.0 11.41 252.6 145.9 10/31/2012 17:07:10 19 0.0 11.40 252.6 145.9 10/31/2012 17:08:10 20 0.0 11.41 252.6 145.9 10/31/2012 17:09:10 21 0.0 11.36 252.6 145.9 10/31/2012 17:10:10 21 0.0 11.41 252.6 145.9 10/31/2012 17:11:10 20 0.0 11.42 252.6 145.9 10/31/2012 17:12:10 19 0.0 0.57 252.6 145.9 10/31/2012 17:13:10 18 0.0 0.59 252.6 145.9 10/31/2012 17:14:10 18 0.0 0.59 252.6 145.9 10/31/2012 17:15:10 19 0.0 0.60 252.6 145.9 10/31/2012 17:16:10 18 0.0 0.13 252.6 145.9 10/31/2012 17:17:10 21 0.0 12.72 252.6 145.9 10/31/2012 17:18:10 19 0.0 12.65 252.6 145.9 10/31/2012 17:19:10 19 0.0 10.85 252.6 145.9 10/31/2012 17:20:10 18 0.0 9.86 252.6 145.9 10/31/2012 17:21:10 18 0.0 9.70 252.6 145.9 10/31/2012 17:22:10 78 0.0 8.96 252.6 145.9 10/31/2012 17:23:10 246 4.4 8.38 255.0 148.4 10/31/2012 17:24:10 47 0.0 8.37 259.1 152.5 Page 7 of 8 Well Field Job Start Customer Job Number SOU 44-33 Swanson River Oct/30/2012 Hilcorp Date Time Treating Flow Density Volume Stage Message 24-hr Pressure Rate LB/G BBL BBL clock PSI B/M 10/31/2012 17:26:10 26 0.0 8.36 263.7 157.0 10/31/2012 17:27:10 22 0.0 8.37 263.7 157.0 Post Job Summary Average Pump Rates, Volume of Fluid Injected, Slurry N2 Mud Maximum Rate Total Slurry Mud Spacer N2 Treating Pressure Summary, Breakdown Fluid Maximum Final Average Bump Plug to Breakdown Type Volume Density Avg.N2 Percent Designed Slurry Volume Displacement Mix Water Temp Cement Circulated to Surface? ❑ Volume Washed Thru Perfs 0 To Customer or Authorized Representative Schlumberger Supervisor Circulation Lost ❑ Job Completed ❑ Mike Leslie Daniel Settle Page 8 of 8 SCU 44-33 {, U.4.,_,.�, Days Vs Depth �•��i. 8000 8500 - — 9000 _ -- 9500 10000 w C.) io 10500 co CQ) 11000 Plan 11500 Actual 12000 - 12500 13000 0 5 10 15 20 25 30 Days SCU 44-33 MW Vs Depth n0rarn 11.4..1.11: 6000 6500 - — 7000 7500 — — 8000 — 8500 MW vs Depth 9000 - - a+ a 9500 r rav i) 10000 10500 — —11000 11500 — — — 12000 12500 — 13000 , -- 8.0 8.5 9.0 9.5 10.0 10.5 11.0 11.5 12.0 12.5 13.0 Mud Density(ppg) II Debra Oudean Hilcorp Alaska, LLC GeoTech II 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8337 Hilrnrp Abeam.LU Fax: 907 777-8510 E-mail: doudean©hilcorp.com a ( - vt3 0� DATE 11/26/2012 To: AOGCC Makana Bender 333 W. 7th Ave. Ste#100 �� 0 Anchorage, AK 99501 ( `v DATA TRANSMITTAL .):)---537 SCU 44-33 Prints: SCU 44-33 Formation Log MD 2"=100 SCU 44-33 LWD Combo Log MD 2"=100 SCU 44-33 Gas Ratio Log MD 2"=100 SCU 44-33 Drilling Dynamics MD 2"=100 SCU 44-33 Final Well Report.doc SCU 44-33 Final Well Report.pdf CD: Final Well Data Z- 0 ? 0 DAILY REPORTS DML DATA Final Well Report LOG ASCII DATA LOG PDF'S LOG TIFF'S SHOW REPORTS Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: 1.4_0„.1t.....„Q ��"_ _ Date: ,,n -1-- /2 — l (---13 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg `,{� 1047- DATE: 11/25/2012 P. I. Supervisor /I FROM: Lou Grimaldi SUBJECT: Williams 405 Rig Winterization Petroleum Inspector SCU 44-33 - Hilcorp Alaska LLC PTD 2121430; Sundry 312-426 November 25, 2012: Performed an unannounced rig inspection of Williams 405 working in Soldotna Creek Unit (Swanson River Field), well SCU 44-33. This was a follow-up of previous inspections performed by AOGCC Inspectors on November 6 and 11, 2012ensure the rig was suitably equipped for winter operations. Pictures of the Williams 405 winterization are attached. Gas detection seemed to be adequate. They had the motors on the mud pump tarped separately from the pits although in the same area. Air flow tended to be drawing fresh air across the motor and toward the pits; not a perfect arrangement but showed they were thinking some about the risks of operations in enclosed areas, particularly potential sources of gas (from the mud pits). Summary: If they can keep this level of winterization up they should be fine for continuing activities. All in all a great effort on their part regarding the winterization of Williams Rig 405. Attachments: Photos (10) - 2012-1125 Rig Inspection Williams 405 lg Page 1 of 6 Williams 405 Rig Inspection —Winterization Photos by AOGCC Inspector L. Grimaldi 11/25/2012 Al s. ;;l �� i; y 'I 1 '',1. ri Yttii • 0. r# J� I rata—'c- _ • 4. 2012-1125 Rig Inspection Williams 405 lg Page 2 of 6 • . , , s 'I, ! a , . Al _, ,f. '.). . I • i I r ION.Alprand • ° , . • I • fV / 1 . ti. .. , ..., _ ... 4 .c „... iiic, 44*-t;;",i4: ammo . . .., • - or .. _ 4. 11 ,,.1 t7 ,t I,.,1. L • 1 I . , ....-4,, ,", ! ,. • I '1 ( .., ,_ 4 I,-fof • am.—....., - _ ...-- - _.. 2012-1125 Rig Inspection Williams 405 lg Page 3 of 6 • . 1 it it '.+ IA i A \ , rMlr� . I. N 2012-1125 Rig Inspection Williams 405 lg Page4of6 ,,,c , ..,.. I r / �- • ......;,>::-. ,. - • ! ' .._.., aq' . 1 iv 4,:. , .v I t {IA i 4 0 I 1 A i r 1 I1 + t� 1 _ lit vk ite00.........40 .x 2012-1125 012 25 Ri g Inspection Williams 405 Ig Page 5 of 6 140 111 fi r 2012-1125 Rig Inspection Williams 405 lg Page 6 of 6 s?. THE STATE Alaska Oil and Gas M �fALA Conservation Commission kit= GOVERNOR SEAN PARNELL 333 West Seventh Avenue O 1• Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Chad Helgeson Operations Engineer �✓ LE 3 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, Soldotna Creek Unit (SCU) 44-33 Sundry Number: 312-426 Dear Mr. Helgeson: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. This sundry authorizes the initial completion of well SCU 44-33 (PTD 212-143) but until the spacing exception is approved by the Commission no well testing or sustained production of the well can be initiated. 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 l day of November, 2012. Encl. tutet RECEIVED STATE OF ALASKA NOVO 72012 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 PoorJ Repair Wel❑ Change Approved Program❑ Suspend❑ Plug Perforations. ❑ Perforate❑✓ ' Pull Tubing] Time Extension❑ Operations Shutdown 0 Re-enter Susp.Well ❑ Stimulate❑ Alter Casinc0 Other: Complete Well Q • 2 Operator Name 4 Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development Q 212-143 ' 3 Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic ❑ Service El 6.API Number: Anchorage,Alaska 99503 50-133-20237-01 7 If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 123A Sddotna Creek Unit(SCU)44-33 • Will planned perforations require a spacing exception? Yes ❑ No 0 9 Property Designation(Lease Number): 10.Field/Pool(s) FEDA028997 • Swanson River Field/Hemlock Oil 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD(ft). Effective Depth ND(ft). Plugs(measured): Junk(measured): 12,425 10,746 12,290 10,681 N/A N/A Casing Length Size MD ND Burst CoNapss Structural - Conductor 337' 20" 337' 337' Surface 3,408' 10-3/4" 3,408' 3,408' 3,130 psi 1,580 psi Intermediate 9,018' 7-5/8" 9,018• 9,018' 6,020 psi 3,400 psi - Production Liner 3,660' 4-1/2" 12,425' 12,425' 8,430 psi 5,126 psi Perforation Depth MD(ft) Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): N/A N/A N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD(ft) and ND(ft): N/A;N/A N/A;N/A 12.Attachments: Description Summary of Proposal Q 13 Well Class after proposed work: Detailed Operations Program Q BOP Sketch ❑✓ Exploratory ❑ Strabgraphic0 Development❑✓ Service ❑ 14 Estimated Date for 15.Well Status after proposed work: Commencing Operations: 11/12/12 Oil Q Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Chad Helgeson Phone: 907-777-8405 Email cheluesonf8thilcoro.com Printed Name////Chad Helgeson Title Operations Engineer Signature C� �i iG Phone 907-777-8405 Date 11/7/2012 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. I I Plug Integrity ❑ BOP Test � Mechanical Integrity Test ❑ Location Clearance ❑ I--; /W� Other: -� * S iI EXCGp Os~ Epp 1^0V el -V 3 000 �5 ea' /c-s 1— , be Care, Proc�r<vE-,a Cewn,wwu'•�ccS 3L Z S"Q C f4 S!� A h rs� s f ��-n, Spacing Exception Required? Yes Q No 0 Subsequent Form Required. /0_4/07_ !!APPROVED BY Approved by:07.__ 2)...e.....*,7(,./.1v`---- COMMISSIONER T COMMISSION Date: 7/_/s_— /Z 7 RE4DMS NOV 1 - ~rte 6N /'� + `� �� /� /Z Sy�d Fo and 0 fPIivfio, i4L Approved application is valid for 12 months from the date f approval. Attacht#s i�f ��i `� Well Prognosis Well: SCU 44-33 Hi'cora Alaska,LLC Date:11/5/2012 Well Name: SCU 44-33 API Number: 50-133-20237-01 Current Status: New Cased Oil Producer Leg: N/A Estimated Start Date: November 12th, 2012 Rig: Williams 405 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts 777-8398 Permit to Drill Number: 212-143 First Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (M) Second Call Engineer: Luke Saugier (907)777-8395 (0) AFE Number: 1212791 Maximum Expected BHP: -2,800 psi @ 10,420 to 10,614' TVD in H6 to H10 sands Based on reservoir modeling of known ' nearby reservoir pressures) -5,756 psi @ 10,660' TVD in H-11 Sand This zone has not been perforated in nearby reservoirs to model the pressure, It is assumed to have potential virgin pressure @ 0.54 psi/ft. Max. Allowable Surface Pressure: -1065 psi Based on 6% KCI brine left in the well after perforating underbalanced before KW fluid is circulated through well. If Virgin pressure in the H-11 and no cross flow to H6-H10 sands. Brief Well Summary This well was sidetracked with the Doyon Arctic Fox in October/November 2012. The completion and following work is proposed to be completed with Williams Rig#405. Notes Regarding Wellbore Condition The well is cased with filtered 6% KCI brine. No open perforations. Casing pressure tested to 2,100 psi. Completion procedure: 1. RD Doyon Arctic Fox Rig. 2. RU E-line w/lubricator,test to 1500 psi 3. RIH with gamma/CCL&CBL tool, log up from bottom (approx. 12,290ft)to 7000ft. 4. POH and RD e-line unit 5. MIRU Williams 405 workover rig. 6. ND Tre- ;. 7" BOP stack, install winterization equipment/enclosures and test BOPE to 3000psi and r. : psi on annular. (notify AOGCC& BLM 24hr in advance of test) 7. Pull BPV, PU 2-3/8" 8rd (116 jts) and 2-7/8" PH-6 workstring. RIH with casing scraper. 8. Circulate and filter 6%KCI fluid through 10 micron filters. 9. POH and rack pipe back. 10. Swab well down to 3,000ft with slickline (braided line or sand line on rig) 11. RU e-line, PT lubricator to 1,500 psi. 12. RIH with 5ft gun (2-1/8" HC gun, 6 spf, 60deg phase)and Pressure/Temtool on roller boogies. 13. Fire gun in the H-10 lower sand at a depth of± 12,109-12,114'. (expected max BHP 2,800 psi) Well Prognosis Well: SCU 44-33 ' Hilcora Alaska,LLC Date: 11/5/2012 14. Monitor pressure and temperature until stabilizes (may take several hours). Check w/town to ensure have a good pressure. 15. POH and LD guns and PU 4-1/2" composite plug, RIH and set plug on a-line at± 12,070'. a. May have to fill hole and pump plug to get to depth. b. If plug does not get to depth w/a-line, set plug with pipe. c. If well is full of fluid after pumping plug, pressure test plug to 2000 psi. d. After the plug is tested, swab well down to 3,000ft fluid level. 16. RIH with 5ft gun (2-1/8" HC gun, 6 spf, 60deg phase), Pressure/Temp tool on roller boogies 17. Fire gun in the H-11_21.pper at a depth of± 12,025'-12,030'. (expected max BHP 2,800 psi) 18. Monitor pressure and temperature until stabilizes(may take several hours). Check w/town to ensure have a good pressure. 19. POH and LD guns and PU 4-1/2" composite plug, RIH and set plug on e-line at± 12,000'. a. May have to fill hole and pump plug to get on depth. b. If plug does not get to depth w/e-line, set plug with pipe. c. If well is full of fluid after pumping plug, pressure test plug to 2000 psi. d. After the plug is tested, swab well down to 3,000ft fluid level. 20. RIH with 5ft gun (2-1/8" HC gun, 6 spf, 60deg phase), Pressure/Temp tool on roller boogies 21. Fire gun in the H-8 sand at a depth of± 11,907-11,912'. (expected max BHP 2,800 psi) 22. Monitor pressure and temperature until stabilizes. Check w/town engineer to ensure well has a stable pressure. 23. POH and LD guns, RD e-line. 24. Depending on well reservoir tested pressures, adjust fluid weight if unexpected pressure is encountered during pressure tests to maintain KW fluid in well. 25. PU Mill,4ea drill collars and 2-3/8" and 2-7/8" tubing. 26. RIH and mill composite plugs, circulate clean 6% KCI fluid to surface,filter to 10 micron. Tag bottom at 12,290'.Circulate bottoms up with clean fluid. 27. POH and stand back tubing, LD BHA. 28. PU TCP completion a. Ensure a good strap/tally on all pipe and TCP equipment RIH. b. Lay out all guns in order from the bottom to the top. 29. Run TCP completion, 2-3/4" TCP guns (291ft total perfs (proposed), 416ft overall length), Firing head, 99 joints of 2-3/8" tubing, below packer vent, (fill tubing as RIH) 7-5/8" champ packer, Annular pressure XO, Big John Jars, 4ea joints of 2-7/8" workstring, RA marker sub, and 2-7/8" workstring to surface. �xr " a. RIH with annular pressure crossover closed b. Fill workstring to desired underbalanced pressure as RIH, (This to be determined by reservoir engineer, but plan is to be 10% underbalanced based on the pressures recorded in steps 14-22.) 30. Once close to depth, RU E-line to correlate guns on depth with gamma ray logs and RA sub. 31. RD E-line and reposition guns 32. Set Halliburton champ packer,Shoot fluid level with a sonic depth recorder on tubing 33. RU surface equipment(kelly valve, pump-in sub, pressure gauge and shot recorder) 34. Close Annular and pressure up on the annulus to fire guns and open vent. 35. Release pressure from annulus and monitor well. a. After 30 minutes shoot fluid level on well (if fluid level changed from prior to firing guns, wait 15 minutes and shoot FL again.) • Well Prognosis Well: SCU 44-33 'Mora Alaska,LLC Date: 11/5/2012 b. If fluid level is not rising. Strip through annular with work string to open the by-pass on the champ packer. Pressure will drop in annulus when bypass opens. c. Monitor fluid level and pressure for another 30 minutes, ensure fluid level is stagnant. Continue to monitor until fluid in tubing and annulus is stable. i. if well is flowing and well needs to be killed, MU necessary KW fluid. ii. Reverse out to fill tubing and kill well. 36. After ensuring no flow,TOH, laydown 2-7/8" workstring, necessary 2-3/8" tubing and TCP assembly a. Ensure all guns fired 37. RIH w/completion on new 2-7/8" 8rd EUE tubing and 2-3/8" tubing(hydraulic packer and gas lift valves as shown on proposed schematic), set packer at approx. 11,700ft. a. Land tubing in hanger. Close the lockdown pins. b. Set packer ball by dropping ball. Circulate till ball seats on pump out plug. c. Pressure up tubing to 2,500 psi to set packer(chart for 30 min). Once packer is set, test casing pressure to 2,100 psi (chart 30 min). After test pressure up to 3,000 psi on tubing to shear pump out sub. 38. Set BPV, ND BOP, NU Tree test(5,000 psi). 39. RDMO rig and equipment. 40. Pull BPV.Turn well over to production. 41. Flow well to production 42. Within 5 days of production, notify AOGCC 24hrs in advance of SSV testing. Attachments: 1. Existing Well Schematic(As left by Doyon work) 2. Proposed Schematic 3. Williams BOP Schematic 4. Example/Proposed TCP schematic Soldotna Creek Unit (AA-Pre-Al— AA- Well SCU 44-33 Completion Date: 11/03/12 SCHEMATIC PTD: 212-143 ua,•arp Alaska,HA' API: 50-133-20237-01 164.6'Above MSL KB-THF:20' 1 CASING DETAIL 20" del - Size Type Wt Grade Conn. ID Top Btm 20" Conductor - - - Surf 337' r 10-3/4" Surf.Csg 40.5 J-55 Buttress 10.05 Surf 3,408' 33.7 N-80 Buttress 6.64" Surf 78' 10-3/4" 26.4 N-80 Buttress 6.844" 78' 4,621' 7-5/8" Intermediate 29.7 N-80 Buttress 6.75" 4,621' 6,111' 33.7 N-80 Buttress 6.64" 6,111' 7,117' 33.7 P-110 Buttress 6.64" 7,117 9,018' 4-1/2" Prod Lnr 12.6 N-80 H-521 3.958" 8,765' 12,425' i4 f JEWELRY DETAIL No. Depth ID OD Item 10, .41 1 20' 2.44" - Tubing Hanger 7-5/8" r/76 5 t Y! • 1? N ( 11 40 7_114 t' xikt y, 1 'q11� I2-00b 2a �.}.te - 12.070 4 4-1/2"L, PBTD=12,290' TD=12,425/TVD=10,746' Max dev.71.85deg @ 10,180'MD Updated by DMA 11/06/12 Soldotna Creek Unit • Well SCU 44-33 PROPOSED Completion Date:11/03/12 PTD: 212-143 Ilikorp Alaska,LLC API: 50-133-20237-01 164.6'Above MSL CASING DETAIL KB-THF:20' Size Type Wt Grade Conn. . ID Top Btm 1 «- 1 s " l 20" Conductor Surf 337' 2Va 'd D ' 10-3/4" Surf.Csg 40.5 J-55 Buttress 10.05 Surf 3,408' 33.7 N-80 Buttress 6.64" Surf 78' 'y 26.4 N-80 Buttress 6.844" 78' 4,621' 7-5/8" Intermediate 29.7 N-80 Buttress 6.75" 4,621' 6,111' 10-3/4" i� 33.7 N-80 Buttress 6.64" 6,111' 7,117' t 't i 33.7 P-110 Buttress 6.64" 7,117 9,018' s,V, 2 Mg i le., 4-1/2" Prod Lnr 12.6 N-80 H-521 3.958" 8,765' 12,425' TUBING DETAIL ', d 2-7/8" Production 6.4 L-80 8rd EUE 2.441 Surf 8,950' 3am i, i; 2-3/8" Production 4.7 N-80 8rd EUE 1.995 8,950' 11,810' x# 5 JEWELRY DETAIL n 4 gm i, 4. •' No. Depth ID OD Item ► t`� 1 20' 2.44" - Tubing Hanger t b : 51on i 2 ±2,400' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port .: j• 3 ±4,400' 2.44" 4.750" 2-7/8"SF01 Mandrel 8RD 12 port a +� 4 ±6,000' 2.44" 4.750 2-7/8"SFO 1 Mandrel 8RD 12 port 1 V 5 ±7,200' 2.44" 4.750" 2-7/8"SFO 1 Mandrel 8RD 12 port If ^,. 6 i 6 ±8,100' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port 4r^ 'k. 7 ±8,650' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 12 port ,ae *, 't; y, 8 ±8,680' 2.313" 3.688" X-Nipple t4' 9 ±9,500' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel 4 7 i ✓ i al 10 ±10,500' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel �� 8 11 ±11,670' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch(orifice) 7-5/8"eill I , L1 1 0,i - ' 9 12 ±11,700' 1.978" 4.140" Tri-point FH Hydraulic packer 13 ±11,760' 1.81" 3.0" X-Nipple 10 Mi 14 ±11,790' 2.0" 3.0" Pump out plug w/WL re-entry guide , 411 l.{ ..' 12 ta PERFORATIONS `' Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes al H-6 ±11,822 ±11,831 TCP 2-3/4"6spf 60 deg t 13 H-8 ±11,857' ±11,987' ±10,462' ±10,530' TCP 2-3/4"6spf 60 deg 14 H-10 ±12,013' ±12,032' ±10,538' ±10,562' TCP 2-3/4"6spf 60 deg P H-30 ±12,087' ±12,179' ±10,580' ±10,614' TCP 2-3/4"6spf 60 deg IIH-11 ±12,197' ±12,238' ±10,642' ±10,660' TCP 2-3/4"6spf 60 deg ,a 4-1/2",L y PBTD=12,290' TD=12,425/TVD=10,746' Max dev.71.85deg @ 10,180'MD Updated by DMA 11/06/12 .IJ 4. Swanson River 2012 Williams Rig BOP mem,. %�. 07/31/2012I arl 3.07' --w. P ` Hydril Q GK 7 1116-5000 1 I I iiiii r' 1 e 1 IM Mali1TI [14i - e ` . _ \ c I CIW-U a3.68' H ( H ii E. I;11 ' I 1 14- 1 71/16-5000 i r, O, _ I lttl [ ]ft all t11 Choke and Kill Valves 2 1/16 10M 1 I i I # fes, 1 I 2.00' j 0 ' I °) i " ttjL ��°). HAL 7RTON / VANN SYSTEMS TOOL STK' SCHEMATIC Preparation Date: 11/5/2012 ..STONER: HILCORP ALASKA HALL I B U RTO N Prepared By: RICHARD PIKE CUSTOMER REP: WADE HUDGENS • CUSTOMER ENG: CHAD HELGESON ?// RIG NAME: WILLIAMS 405 Perforations: / l/ WELL NAME: SCU 44-33 JOB TYPE: TCP No. TOOL STRING DESCRIPTION ID" OD" LENGTH DEPTH il 14 2 7/8 Tubing 2.265 2.875 8598.380 8598.38 13 RA Marker Sub 2.265 2.875 2.210 8600.59 11 12 2 7/8 Tubing 2.265 2.875 124.00 8724.59 11 Crossover sub 2 7/8 EUE x 3 1/2 IF 2.440 5.000 2.00 8726.59 1.111 10 Safety Joint 2.5 5.000 3.77 8730.36 r17 9 Big John Jars 2.500 5.00 5.95 8736.31 8 Annular Pressure Crossover NA 5.00 2.10 8738.41 1 i 7iii e 7 7-5/8" CHAMP PACKER 2.400 6.35 9.46 874787 C'I' Below packer Vent na 5.00 o i 1.08 8748.95 NM 6 Crossover 3 1/2 IF BOX X 2 7/8 PIN 2.400 5.00 0.97 8749.92 MI 6 Crossover 2 7/8 EUE X 2 3/8 EUE 2.000 3.500 0.41 8750.33 I54 2-3/8" TUBING 2.04 3.125 3069.00 11819.330 1U 0 3 TDF firing head na 2.500 1.67 11821.00 N2 DCI Sub 2.750 1.0011822.00 44P 1 2 3/4 TCP Guns 2.750 416.00 12238 REMARKS: Example diagram on TCP assembly for underbalanced perforating in Swanson River. Approximate TCP completion. Page 1 of 2 • . 'Schwartz, Guy L (DOA) From: wade hudgens[awhudgens2406@gmail.com] Sent: Tuesday, November 13, 2012 6:42 PM To: Schwartz, Guy L (DOA) Cc: Chad Helgeson; Wade Hudgens-(C); Foerster, Catherine P (DOA); Regg, James B (DOA); doa.oagcc.prudhoe.bay@alaska.com Subject: Re: verbal approval for Sundry 44-33(PTD 212-143) We will be working on finalizing the winterization package for the Williams#405 tonight. I will send a email update in the morning on our progress and when we will be ready to preform the BOPE test. Thanks, Wade On Tue,Nov 13, 2012 at 3:23 PM, Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> wrote: Chad, You have verbal approval to move rig 405 onto location and rig up winterization and BOP Equipment. We will witness BOP Test and access winterization at that time. This verbal approval does not authorize entry into the well until inspection is completed and sundry is approved by commissioners . Regards, Guy Schwartz AOGCC Sent from my iPhone On Nov 13, 2012, at 2:21 PM, "Chad Helgeson" <chelgeson(&_,hilcorp.com>wrote: Guy, Can you provide a verbal approval to proceed with the well work with the Williams Rig 405 on the SCU 44-33 well. I understand that the approval is dependent on the winterization and BOP test witnesses by the state. 11/14/2012 Page 2 of 2 • We will post the submitted approvals at the rig. Wade's number at the rig is, 907-776-6778, cell # 903-331-6711. Chad Helgeson Operations Engineer Hilcorp Alaska, LLC Office: 907-777-8405 Mobile: 907-229-4824 11/14/2012 Page 1 of 1 Schwartz, Guy L (DOA) From: Luke Keller[Ikeller@hilcorp.com] Sent: Monday, November 05, 2012 4:09 PM To: Schwartz, Guy L (DOA) Subject: SCU &-33 7rID 2 ( Z -193 Guy, F' Wanted to give you an update regarding progress on SCU 44-33: After the packer setting tool had been inspected by the Baker service tech, it was observed that the packer setting dogs had never made contact with the packer setting sleeve,which led us to believe that the packer was not set(instead of being set but leaking). We changed our mind and instead of RIH w/ another packer,elected to run in the hole with a packoff+packer setting assy. We were able to set& test the packer in the well. We conducted a test to 2100 psi/10 min to confirm packer integrity,and then conducted a 30 min/2100 psi test of the entire wellbore. Today we have run into the well with the clean out/displacement assy and cleaned out to the landing collar at 12,290', displaced the wellbore to FW, and will displace to filtered 6%KCI completion fluid later tonight. Luke Kellert";‘it/t. 511 ir Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 11/7/2012 Page 1 of 1 Schwartz, Guy L (DOA) From: Luke Keller[Ikeller@hilcorp.com] Sent: Friday, November 02, 2012 8:20 AM To: Schwartz, Guy L(DOA) Subject: Hilcorp Drilling Update Guy, Below is an update on our(2)drill wells and what we expect to accomplish over the weekend: SCU 44-3 • Circulated 12.5 ppg mud from liner top(8765')to surface. Well dead. TOH,test BOPs. Upcoming ops: RIH and dress off PBR and liner top (pump 12.5 ppg mud). TOH, P/U diagnostic assy,TIH and determine leak path, If packer is confirmed to be the leak path,we have another one ready to go that we will run on top. When we circulated the 12.5 ppg mud into place,we saw 1191 units of gas on B/U which substantiates our belief that it is the liner top packer that is leaking. HV B-16: Ran and cemented 10-3/4"surface casing at 1050' MD. 106 bbls lead &40 bbls tail pumped. 20 bbls cmt to surface. Bumped plug,floats held. We are currently N/D diverter,and will be N/U and testing 11"x 5M BOPs over the weekend. Then P/U 9-7/8" directional drilling assy for the next hole section. Let me know if you have any questions. Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 11/7/2012 sect 4G-33 / ' Z{Z 1 430 Regg, James B (DOA) From: Rance Pederson -(C) [rpederson@hilcorp.com] Sent: Friday, November 02, 2012 10:45 AM -1 T II�ZIcv To: Regg, James B (DOA) l Cc: DOA AOGCC Prudhoe Bay Subject: BOP Closure on Doyon Rig#1 Date and Time BOP Used: 11-1-2012,05:45 am Well/Location/PTD Number: 44-33, Swanson River, 2121430 Rig Name: Doyon Rig 1 (Arctic Fox) Operator Contact: Rance Pederson, 907-776-6776 office, 907-398-4847 cell, rpederson@hilcorp.com Operations Summary: Had cemented 4%2" liner in place, circulated out cement, and started pulling out of hole from 8,765' to test BOPE as scheduled. At a depth of 6,585'the pit watcher notified Driller his actual vs calculated hole fill was incorrect. Driller notified DSM and team conducted a flow check. Well appeared to be flowing. Slug was circulated from string, another flow check made, and well was definitely flowing at a rate of 4 1/2 bbls per hour. DSM notified Drilling Manager and rig crew ran drill string back to bottom. Once on bottom upper rams were closed in, choke line opened to manifold and well was monitored for SIDP and SICP. BOPE Used: Upper pipe rams (variables) and Choke Manifold -Reason for BOPE Use: To shut in well and get SIDP and SICP to determine kill weight mud needed to stop influx. Actions Taken/To Be Taken: Well was displaced to 12.5ppg mud, checked for flow, was determined to be static, and rig crew resumed pulling out of hole for the scheduled full BOPE test. BOPE test began at 22:30 hrs on 11-1-2012 with AOGCC Rep John Crisp on location to witness. Next step in operations will be to run in hole with seal assembly and RTTS to determine if liner hanger packer is leaking. Rance Pederson Hilcorp DSM 907-776-6776 office 907-398-4847 cell From: Regg, James B (DOA) [mailto:jim.regg(aalaska.gov] Sent: Friday, November 02, 2012 10:18 AM To: Rance Pederson - (C) Subject: RE: SRU 44-33, 11-1-12 Please provide report that includes information listed in AOGCC Industry Guidance Bulletin 10-003 (Attached). Jim Regg AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 1 I • From: Rance Pederson - (C) [mailto:rpederson@hilcorp.com] Sent: Thursday, November 01, 2012 5:55 AM To: Regg, James B (DOA) Subject: SRU 44-33, 11-1-12 Jim, Well started flowing this morning despite liner being set and cemented.We've run back to bottom (just above liner hanger), closed the upper rams and are currently monitoring for any pressure build. I've been in contact with AOGCC Rep John Crisp for witnessing BOP test this morning, and will be calling him shortly to give him an update. Rance Pederson 776-6776 office 398-4847 cell 2 Page 1 of 1 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Thursday, November 01, 2012 10:00 AM To: 'Luke Keller Cc: Rance Pederson-(C); Paul Mazzolini Subject: RE: SCU 44-33 (PTD: 212-143) Luke, Per our phone discussion go ahead and do your diagnostics to determine if leak is liner lap or 4.5" shoe (not as likely) . Once you have the data let me know and we will determine a path forward regarding a completion modification. Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Luke Keller [mailto:lkeller@hilcorp.com] Sent:Thursday, November 01, 2012 9:29 AM To: Schwartz, Guy L (DOA) Cc:Rance Pederson - (C); Paul Mazzolini Subject: SCU 44-33 (PTD: 212-143) Guy, The 4-1/2" liner has been run&cemented on SCU 44-33. However, we are still in communication with the lower tyonek water flow. We suspect that the liner top packer is leaking. Our forward plan is as follows: 1. TIH with work string and displace 11.4 ppg mud to 12.5 ppg from liner top to surface. TOH. 2. P/U PBR polish mill assy,TIH, polish PBR,TOH 3. RIH w/test seal assy& RTTS pkr to isolate 4-1/2" ID from liner top and confirm leak path 4. If liner top confirmed leaking, RIH w/second isolation packer We are due for a BOP test today. But the test has been delayed a little until we can get the 12.5 ppg spotted from the liner top to surface and get out of the hole with the setting tool. I will give you a call to discuss. Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 11/1/2012 w wP'\or \ I//74.s9 THE STATE Alaska Oil and Gas S OfALA � Conservation Commission *h GOVERNOR SEAN PARNELL 333 West Seventh Avenue O P Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 October 23, 2012 Certified Mail Return Receipt Requested 7009 2250 0004 3911 3279 Mr. Paul Mazzolini Drilling Manager Hilcorp Alaska LLC P. O. Box 244027 Anchorage, AK 99524-4027 Re: Notice of Proposed Enforcement Action Failure to Notify of Changes to Approved Permit Failure to Test Blowout Prevention Equipment Soldotna Creek Unit 44-33 (PTD 2121430) Dear Mr. Mazzolini: Pursuant to 20 AAC 25.535, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby notifies Hilcorp Alaska, LLC. (Hilcorp)of a proposed enforcement action. Nature of the Apparent Violation or Noncompliance (20 AAC 25.535(b)(1)). The AOGCC considers that Hilcorp has violated the provisions of 20 AAC 25.015 ("Changes to a program in a permit to drill") and the provisions of 20 AAC 25.035 ("Secondary well control for primary drilling and completion") in its operation of Soldotna Creek Unit 44-33 (SCU 44- 33). Basis for Finding the Violation or Noncompliance(20 AAC 25.535(b)(2)). Hilcorp failed to follow the well drilling procedures in Permit to Drill (PTD) number 2121430, approved by AOGCC on October 3, 2012, failed to notify AOGCC of changes to the approved well procedure, and failed to test blowout prevention equipment (BOPE) after being used in well control. Pursuant to AS 31.05.030, the AOGCC promulgated regulations to establish requirements for drilling oil and gas wells. Regulation 20 AAC 25.005 mandates a permit to drill, redrill, or re- enter an abandoned well must be approved by AOGCC before commencing drilling operations. Regulation 20 AAC 25.015 requires that any changes to a program approved in a PTD must be Notice of Proposed Enforcement Action October 23,2012 Page 2 of 4 authorized by AOGCC before making the change. Regulation 20 AAC 25.033(b) requires the drilling fluid program to be designed to maintain the wellbore in an overbalanced condition. Regulation 20 AAC 25.035(e)(10)(C) requires that BOPE used to control fluid flow to surface must be tested before the next wellbore entry. Hilcorp commenced sidetrack drilling of SCU 44-33 at 1300 hours October 11, 2012 using Doyon Rig 1 (also known as Doyon Arctic Fox). A window was milled in the casing of suspended well SCU 24-33 (PTD 1720070) by the rig after well work was completed to prepare it for drilling operations'. A Notice of BOPE Use2 was provided to AOGCC on October 12, 2012. Receipt of the BOPE notice initiated a review of the approved drilling permit and a request for additional information. Hilcorp responded with the requested information by electronic mail on October 15, 2012. Daily Drilling Reports indicate the casing window was milled at a depth approximately 500 feet shallower than approved in PTD 2121430. The mud weight was not increased prior to milling the window as required by that permit. The Drilling Reports further document that the well began to flow after milling 15 feet of casing, requiring Hilcorp to close the upper pipe rams within the BOP stack, and weight up and circulate kill-weight fluid into the well. Reports indicate Hilcorp circulated increasingly heavier kill weight fluid as part of continuing milling operations from October 11 through October 13. There was no request for a change in the approved well drilling procedure allowing for the shallower casing window and lower drilling mud weight. Hilcorp drilling reports also indicate that the drilling assembly was tripped to surface on October 13, 2012 and re-run in the well on October 14, 2012. There is no record of a test of the blowout prevention equipment used during well control operations prior to re-running the drilling assembly into the well. Hilcorp performed the required BOPE test on October 18, 2012. Proposed Action (20 AAC 25.535(b)(3). The AOGCC proposes to order the following corrective actions by Hilcorp: (1) Within 2 weeks following the date of receipt of AOGCC's final decision, Hilcorp shall provide a detailed description of its regulatory compliance program and a copy of its written management-of-change procedures; (2) Within 2 weeks following the date of receipt of AOGCC's final decision, Hilcorp shall complete and provide AOGCC with the results of a root cause analysis addressing the violations. (3) Within 4 weeks following the date of receipt of AOGCC final decision, Hilcorp shall provide evidence that personnel responsible for drilling and workover rig management, and staff involved with permitting well operations (drilling and workovers) have been I Application for Sundry Approvals,Form 10-403,was approved by AOGCC allowing the well to be configured for sidetrack drilling of SCU 44-33;refer to Sundry Approval 312-353. 2 Refer to AOGCC Industry Guidance Bulletin 10-003 for information required in the BOPE Use notice. Notice of Proposed Enforcement Action October 23,2012 Page 3 of 4 trained in AOGCC drilling and workover regulatory requirements, including the process for making changes to approved activities, testing, and reporting requirements; (4) Beginning immediately upon receipt of AOGCC's final decision, BOPE testing on all drilling and workover operations must be performed when installed, repaired, or changed and at intervals not to exceed seven (7) days between tests unless otherwise approved by AOGCC. When used for well control or other equivalent purposes, or routine use may have compromised equipment effectiveness, BOPE used must be tested before the next wellbore entry. For violating 20 AAC 25.015, 25.033, and 25.035, the AOGCC intends to impose civil penalties on Hilcorp under AS 31.05.150 (a) as follows3: - $75,000 for the initial violation— failure to maintain the wellbore in an overbalanced condition by increasing the drilling fluid weight prior to milling the casing window as required in the PTD; - $7,500 for failing to notify AOGCC of change in well plans; specifically, using a lighter weight drilling fluid for milling and initial drilling operations than approved in the PTD; - $3,000 for failing to notify AOGCC of a change in well plans; specifically, milling the casing window at a shallower depth than approved in the PTD; - $7,500 for each day October 14 through October 17, 2012 for failing to test BOPE used in well control operations.4 The total proposed civil penalty is $115,500. The serious nature of violations relating to well control equipment and practices, and the actual or potential threat to public health or the environment, warrant penalties at the higher end of the scale. Hillcorp's disregard of the AOGCC's regulations and its aggressive approach to well work raise the potential for similar behavior with more serious consequences. Inadequacy in management-of-change protocols is an additional factor in the AOGCC's analysis. Rights and Liabilities (20 AAC 25.535(b)(4)). Within 15 days after receipt of this notification— unless the AOGCC, in its discretion, grants an extension for good cause shown — Hilcorp may file with the AOGCC a written response that concurs in whole or in part with the proposed action described herein, requests informal review, or requests a hearing under 20 AAC 25.540. If a timely response is not filed, the proposed action will be deemed accepted by default. If informal review is requested, the AOGCC will provide Hilcorp an opportunity to submit documentary material and make a written or oral statement. If Hilcorp disagrees with the AOGCC's proposed decision or order after that review, it may file a written request for a hearing within 10 days after the proposed decision or order is issued. If 3 AS 31.05.150(a)provides for not more than$100,000 for the initial violation and not more than$10,000 for each day thereafter on which the violation continues. a 4 days;BOPE used for well control purposes on October 11,2012;the drilling assembly was tripped to surface on October 13,2012(at surface 2230hrs);the drilling assembly was re-run into the well beginning 0330hrs October 4, 2012 without testing the BOPE components used for well control. BOPE were tested on October 18,2012. Notice of Proposed Enforcement Action October 23,2012 Page 4 of 4 such a request is not filed within that 10-day period, the proposed decision or order will become final on the 11th day after it was issued. If such a request is timely filed, the AOGCC will hold its decision in abeyance and schedule a hearing. If Hilcorp does not concur in the proposed action described herein, and the AOGCC finds that Hilcorp violated a provision of AS 31.05, 20 AAC 25, or an AOGCC order, permit or other approval, then the AOGCC may take any action authorized by the applicable law including ordering one or more of the following: (i) corrective action or remedial work; (ii) suspension or revocation of a permit or other approval; (iii) payment under the bond required by 20 AAC 25.025; and (iv) imposition of penalties under AS 31.05.150. In taking action after an informal review or hearing, the AOGCC is not limited to ordering the proposed action described herein, as long as Hilcorp received reasonable notice and opportunity to be heard with respect to the AOGCC's action. Any action described herein or taken after an informal review or hearing does not limit the action the AOGCC may take under AS 31.05.160. Sincerely, Cathy P. Foerster Chair, Commissioner 1Cc,t 44-3_3 2-4 2643 C Regg, James B (DOA) From: Mike Leslie [gleslie@hilcorp.com] Sent: Wednesday, October 17, 2012 4:52 PM Z?t,1 l i'v(1 To: Regg, James B (DOA) c Cc: Luke Keller; Paul Mazzolini; Jimmy Greco - (C) Subject: Emailing: SRF 44-33 FIT TEST 12.0 ppg, SRF 44-33 FIT TEST 12.8 ppg 10-13-12, F.I.T SCU 44-33, 10-17-12 Doyon Drlg Attachments: SRF 44-33 FIT TEST 12.0 ppg.xls; SRF 44-33 FIT TEST 12.8 ppg 10-13-12.xls; F.I.T SCU 44-33, 10-17-12 Doyon Drlg.xls Mr Regg, Here are the three F.I.T tests performed on SCU 44-33 to date. C 75-4`' cas,:.zl Regards, c� Mike Leslie Your message is ready to be sent with the following file or link attachments: SRF 44-33 FIT TEST 12.0 ppg SRF 44-33 FIT TEST 12.8 ppg 10-13-12 F.I.T SCU 44-33, 10-17-12 Doyon Drlg Note: To protect against computer viruses, e-mail programs may prevent sending or receiving certain types of file attachments. Check your e-mail security settings to determine how attachments are handled. .Lr - ( CASING AND LEAK-OFF FRACTURE TESTS Well Name: 5C-1( 44-33 (P7J6 212.44 3G) Date: 10/11/2012 Csg Size/Wt/Grade: 7 5/8 Supervisor: Csg Setting Depth: 9015 TMD 8963 TVD Mud Weight: 10.9 ppg LOT/FIT Press= 512 psi LOT/FIT= 12.00 ppg '' Hole Depth= 9035 and Fluid Pumped= 6.9 bbls Volume Back= 6.,0 bbls -11(.2_,'kUkk2✓ 0.042 Barrels/Stroke LOT I FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here 0 0 -> ' 0 0 100 115 -> 300 183 200 203 -> 650 T 500 300 287 -> 950 765 400 354 -> 1250 901 500 416 -> 1500 1000 600 468 -> 2000 1323 693 512 -> 2300 1503 -> 2600 1705 -> 2800 Y 1845 T -> 2900 _ 1950 -> 3050 2020 T -> 3150 2115 -> Enter Holding Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here 0 512 - -> 0 2100 - 5 512 -> 5 2100 10 512 -> 10 2100 G ilvAg 15 512 , -> 15 2100 60 6,4_ -> 20 2100 -> 25 2100 r. -> 30 2100 > Pale j oF3 44-'33 7-4 z_44-30) Cas I Ler' I 0/ll'1 -�-LOT/FIT DATA t CASING TEST DATA 2200 2100 -- - 2000 1900 1800 - 1700 1600 1500 693 1400 1300 600 1200 a _ 1100 a _ a _ I a 1000 - 560 900 400 800 300 700 600 500 200 693 .00 400 500 400 300 300 200 100 200 100 100 0 0 0 Strokes(#of) JL4- -33 L - (431 —0—LOT I FIT DATA -U—CASING TEST DATA 2200 2100 ■ ■ ■ ■ ■ ■ 2100 21i 0 2100 2100 2100 2100 21)0 2000 1900 1800 1700 1600 1500 1400 1300 1200 N z 1100 to N G1 a 1000 900 800 700 600 500 •` • 512 • 512 • 512 400 300 200 — 100 0 0 5 10 15 20 25 30 Time(Minutes) - . (it44 3> • • N 21z,t4-30 • • 4 io .� AOpO ____;_______H_____"_____:.- / --_____,,./___,,,..-7,--...<-''\<,; ___,,,..-7,--. \ a ///,/ • `--l ! r 25 t' --� `�\ \ N / // ,.--\'' / / / ././ , -- • ,,,....--- L, __.-----7-t----------,72--------,...„7:7' ..-....„, N.N\-\\>" ".\\ \ \ ''-\\ \ , / / ' ./ ii / .7 .// j /! \ \ / / i. i l A y '''--‘,/x\-, \ U, O �/ ! + / ! i, / / /' , 0 77 , L \-`r \ cf` \ 00.1;A__ r O n 1 j I \C ;_ \ 1� v 1 y �, e M 0 .>.' ' ''. ' I . ' ' a , OT oop A..\ C." 1 :\...,0.- ,\- .� ' � r � /7L/ t o , ___\___, ;\ \ �rO � U \,. n / % � ,O \ l \ om /C \ 7 `'- T ,\ \� W \ \ \ \ yN . f // / { � lA es ;7,..„,...2 . \ \ �. \ 00x1/ 1.--"' . // F f\/ l �\ �� ` 0052 ,, - / : / \\NN, ' 'N. '''''''. .----'-----. -- ""--- • -0() ''' - \ N N \ '`'� �=' — -0050 -'� / 'r /'/ 01 \\ `_—` o00ti - _ 0 f b�\ CASING AND LEAK-OFF FRACTURE TESTS Well Name: Xt( 44-33 (P146 Z 1 Z 14so) Date: 10/13/2012 Csg Size/Wt/Grade: 7 5/8 Supervisor: Csg Setting Depth: 9015 TMD 8963 TVD Mud Weight: 10.9 ppg LOT/FIT Press= 652 psi LOT/FIT= 12.8 ppg ,i Hole Depth= 9035 and Fluid Pumped= 6.9 bbls Volume Back= 6.,0 bbls 0.042 Barrels/Stroke LOT/FIT DATA CASING TEST DATA Enter Strokes Enter Pressure Enter Strokes Enter Pressure Here Here Here Here ,'° " , 0 0 0 �,,,, 100 115 „te `. 200 203 300 287 ': 400 354 500 416 600 468 693 512 725 556 784 600 r 844 650 tr=-4 Wit= Enter Holding Enter Holding Enter Holding Enter Holding Time Here Pressure Here Time Here Pressure Here Kg� 0 650 a -> 5 625 -> 1 £` 10 554 15 > _ 20 -> x fl-rA 25 -> 30 > I I 44144,;144A 1 „ > ,%e I o.t=3 Sc ,(C4 4--33 C 2 (30 C&s`J / -r (O t' (- LOT/FIT DATA f CASING TEST DATA 2000 1900 1800 - 1700 1600 1500 1400 1300 1200 1100 Q - 1000 - N N 900 - 800 700 844 600 784 25 500 693 600 400 500 400 300 _ 300 200 200 100 100 0 0 0 844 Strokes(#of) 1efZ z_ of-1 5Cu44-33 (ir. z14-3-6) • • Ca � � - 101,31« —•—•LOT/FIT DATA t CASING TEST DATA 2000 1900 1800 -- 1700 1600 1500 1400 1300 1200 1100 lv 1000 a. 900 800 700 41-650 25 600 554 500 400 300 200 100 — - 0 0 5 10 15 20 25 30 Time(Minutes) 8 Ma a o o V 8 o N e O O N fill _ / N 0 I n m 1 n 8 ei13 N iii E. E o j E > .0 z I., b M 8 N F N 0 a. a 8 8 0 a )istl)emaaeid )1sd)emeseid 1 O O O O O O O O O O O O O O O O O 0 0 0 0 0 0 0 0 0 0 ‘- c ... N M ' 11) (0 N- CO 0) O — N co 10 (o N- . , 1 ' ' , 0M N N N N N N co N 0- i: E 70a W C) '0 (n N N (n O U') v 1(') O O V < R < CO 0 O O0 O M N N 10 O M N-1n N 0 0 0 M >_ C N. M 0. V o' CO N. O < N. — -.0 n 0 Cc) `0 0) co co C N 0)N-O(o V CO �(�`` c M \ E N., M Ni. V h N. n n aD N 0 O� 0- 0) 0)0)0)O)0)a0 a0 a0 a0 a0 N V n y a N V d 7 10 O U H N 0) a)'0 (n 0 1n O h O N O (n O a) O u) O (n O (n 0. 0 (L 0 a0 E III 0.0 N a) N. O N 10 h. O CSI N. O CV (n N. O N E N 0 E a0 O O O — — — — N N N N CO M CO M V . . V �� E j 2 a.° 3 tstl p G a) y a m � •• N M O u1 �O N. CO P O N M V N �O P a� P 0 N N N N N N N CO 0.N V C V V c16i•• o) o o N c c c c c c c c c'E �_ -1 00))a)f (') oEEEEEEEEE0 0 \ 1—N M OO(oN.(O0)' Z g Z U w ? J 0. 4 0_ L~L L~L u_ LL 0 0 0 0_ 0. 0_ U LLL 0_Cl- .�^.. J m '.p J (0 co 0 N 1.- a 0 V) 0 0 I- CO CO O CO 0 =O V o) 0 0)in co 1n d Cl) N N 00 w ^ O CO h 0 C LL ci 1n 0) a0 0) o) x 0 0 .- O .- (o O T M d � 4- y" Y CO oQ _-w yFi w x x w F a 0 N } Q o Z 3 > U w W a a y a w (L LL J O v — V Q wwo � L0omX FCI- oo 11.1 2 � p waYp � • 22 LI- LWcoU. < 00W o)w N w W jQ w 101000J5 VMwO � f 00 00 LL 01.1. L1- 05 (/) Q0 - 001- 1- ll. 2 ? o. J J 1L w Y Y 00 Hilcorp Luke Keller Hilcorp Alaska, LLC Energy Company Drilling Engineer P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8369 10/15/2012 Email Ikeller@hilcorp.com a l 2\ l +3 Commissioner Alaska Oil & Gas Conservation Commission p ��++ 333 W. 7th Avenue R E li.+L J V D Anchorage, Alaska 99501 • +-• •- Re: Soldotna Creek Unit 44-33(Redrill of SRU 24-33). AOGCC 4U' Dear Commissioner, Enclosed for review and approval is a 10-403 "Change to Approved Procedure" to highlight the below jh J fps rL` (2)changes to the approved APD. ✓ — �,�v k17 Lti 1. The KOP has been moved up the hole from 9500' MD to 9001' MD. The KOP was moved to ` ,17 V allow for improved hole geometry and still hit the same geologic targets as originally planned. The modified KOP does not change the BHL of the wellbore. 'i. ;p ,` 2. The starting MW was reduced from 10.6 ppg to 9.5 ppg. The starting MW has been reduced to avoid being overly conservative and induce a lost returns incident. Reservoir pressures are expected to be reduced in the Southern-par of the field. 7 3. After milling the window, an 11.6 ppg water flow was ncountered from the lower tyonek. The MW was increased from 9.5 ppg to 11.6 ppg to stop the water flow and allow drilling operations to continue. Attached is the(P5)directional plan which reflects the new KOP. If you have any questions, please don't hesitate to contact myself at 777-8395. Sincerely, Luke Keller Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 hn EW ED STATE OF ALASKA OCT 19 2042 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOc Cc 20 AAC 25.280 1.Type of Request: Abandon 0 Plug for Redrill 0 Perforate New Pool 0 Repair Well 0 Changerfipproved Program Q. Suspend 0 Plug Perforations 0 Perforate❑ Pull Tubing 0 Time Extension 0 Operations Shutdown❑ Re-enter Susp.Well ❑ Stimulate 0 Alter Casing 0 Other: .°` 0 2.Operator Name. 4.Current Well Class: 5.Permit to/Drill Number. Hilcorp Alaska, LLC Exploratory 0 Development Q , / 212-143 ' 3.Address: Stratigraphic 0 Service El6.APY4lumber. 3800 Centerpoint Drive,Anchorage AK,99524 50-1 1-00 ' 7.If perforating 8-Well Name d Number. What Regulation or Convervation Order governs well spacing in this pool? /` SC _33 • Will planned perforations require a spacing exception? Yes ❑ No 0 \, 9.Property Designation(Lease Number): 10.Field/Pool(s): / C//J FED A028399& FED A028997. Swanson River Field/Hemlock Oil Pool 11 11. PRESENT WELL CONDITION SUMMARY / (v� /X Total Depth MD(ft). Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft):�/ P e se : \ Junk(measured): 9038 8983 9038 8983 r" 9038 T None Casing Length Size MD // Burst Collapse Structural , Conductor Surface 3408 10-3/4" 3408: c /c:;i 34! 3130 1580 Intermediate 1 Production 9038 7-5/8" 9e • ( \ �8 3 7240 5410 Liner r \O 1 Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Tubi \G�d Tubing MD(ft): N/A N/A I N/A /A N/A Packers and SSSV Type. a Packers and SSSV M i (ft) • TVD(ft): N/A I N/A 12.Attachments: Description Summary of Proposal r 13.Well Class after proposed work: . Detailed Operations Program ❑ BOP Sketch Exploratory ❑ Stratigraphic 0 Development Q Service 0 14.Estimated Date for 10/10/20 15.Well Status after proposed work: Commencing Operations: Oil Q Gas 0 WDSPL 0 Suspended 0 16.Verbal Approval: Date:/ WINJ 0 GINJ 0 WAG 0 Abandoned 0 Commission Representative: GSTOR/ 0 SPLUG 0 i 17.I hereby certify that the foregoing is true and orrect to the best of my knowledge. Contact vLe 1`e/`J er ti/e Email lr eller /k0p,COFI Printed Name / eler Title DP�iI,^ G • Signature 1.1 / Phone date�/ (9oy) 777-g39� o/i.S/ao)A COMMISSION USE ONLY Conditions of approval: Not: Commission so that a representative may witness Sundry Number: 612---410_,6- Plug _--16Plug Integrity ❑/ BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other / RBDMS FEB 0110; ' , . Sp' ing Exception Required? Yes 0 No ❑ Subsequent Form Required APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: n ^`) n Submit Form and �� 1'" erriit+Ati 10/2012) Approved application is valid for 12 months from the date of approval. Attach e is in Duplicate ^ /iz \r), In Ell W WO 333 w as 0 0• h O� "O M M N WI 14 W 0oo � W Ihill M' - 000 eriL O Nkr. F1/41 7-... ,' .' In M it a 0 0 0 O ~ O O C .�-+ .fir OMO OMO OMO M O Pm � � -,z00 g X . et•co 0 en M M as k A • oo racy., to .c .4 d ZZ _Z Q �'... ,' (�" d O O M d C 1 0 4. MK) 0 3� .71- C v. ;; v, v, .-4 E o _ a �.� `o °A � C) � o U _ o � N�- asC E a.) y O ; w > es CCO N O . .s C/) Cr, 0 � Ki es M M M M 3 c� " Lt. 4444 i s -, vea; o 0 0 Y Y Y V1 N 0 06 � g U U U Q O en M 0000 H H H 7 pi e,i NO 0 Q C10) 0 0z Cw Ifc. XU U U O O U U OO Q Q Q V1 V] O YO 'C i u 0 o t` il N � M M c=.' 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I I 7 § S a 7 _ . . . , ; ; ULlmiso!9a_± Page 1 of 2 Schwartz, Guy L (DOA) From: Luke Keller[Ikeller@hilcorp.com] Sent: Monday, October 15, 2012 10:46 AM To: Schwartz, Guy L (DOA) Cc: Paul Mazzolini Subject: RE: BOP incident-SCU 44-33 (PTD 212-143) Attachments: Hilcorp_Energy_Company_SRF_SC Drilling_10102012_10152012_report.pdf Guy, Attached are the drilling reports from 10/10 to 10/15. The influx was water, with a small amount of gas with it. SIDPP and SICP were always very close, and the suspected formation was the lower tyonek water flow, which was not believed to extend this far south. We were also not aware & negligent of Bulletin No. 06-01. We will be testing BOPs when we come out on our next bit trip, which should be tomorrow. I have to apologize for the (2) changes below that I did not make the AOGCC aware of. At the time, we felt 10.6 ppg was overly conservative and did not want to risk a lost returns event on this well as it is further south to SRU 32B-22 and lower pressures were expected. The kick-off point was moved 500' up the hole to allow for improved hole geometry. BHL was not moved from approved PTD. I will submit a 10-403 for these changes and will be more diligent in the future at making the AOGCC aware of deviations from the approved APD. Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 From: Schwartz, Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent: Monday, October 15, 2012 9:11 AM To: Luke Keller Cc: Regg, James B (DOA) Subject: BOP incident- SCU 44-33 (PTD 212-143) Luke, I saw the report that Doyon 1 had to close BOP's last Thursday after milling out the window for the sidetrack. Please provide the daily drilling reports for the days just before and after the event. What type of fluid was circulated out.... Gas or oil? The BOP use report didn't indicate when they were going to test the components that were used. See our guidelines for BOP reporting ... bulletins No. 10-03 and 06-01. http://www.doa.alaska.gov/ocic/bulletins/bulletindex.html The approved PTD (212-143) procedure stated that the drilling/milling fluid was going to be changed to 10.6 ( not 9.5 ppg) before milling the window and into OH. Also the window was specified in the PTD as being at 9500' not 9000' as reported. Can you explain these discrepancies with the approved PTD? 10/15/2012 Page 2 of 2 Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) 10/15/2012 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 44-33(Sidetrack of SRU 24-33) 50-133-20237-01-00 212143 9/19/12 Daily Operations: 10/31/2012-Wednesday TIH with 4 1/2" production liner t/10,070'. Wash & ream thru tight spot to 10,227'. CBU @ 10,227', 20 rpm, 2,500 tq, 6 bpm, 1,100 psi. 3,880 units @ B/U. Continue to RIH f/10,227't/11,230'. Ream tight spots as necessary to pass. CBU @ 11,230'to clear annulus prior to entering hemlock.30 RPM,3.5 tq,5 bpm, 1,090; continue to RIH.Wash &ream when necessary.Tight working through top of hemlock. Ream tight spots from 11,460'to 11,560'.Slide to 12,088'.Wash &ream to 12,360'. Circulate to clear gas from annulus prior to washing down final stand. (2,085 units) Wash & ream final stand to 12,413'. Make up pup jts and TD plug dropping head. Circ & condition f/cement job.UP 163,DN 152,ROT 160,5 bpm,835 psi,30 RPM,4,500 tq.Washed to 12,423',psi dropped from 835 to 530 psi at bottom, tagged bottom and set 20K on shoe with no psi change.PSI down to 400. Notified Drilling Engineer of possible washout,dropped carbide pill, had indication of gas 26.8 bbls away. Decision made to backream OOH looking for hole. Backream OOH at 65 spm (470 psi) 25 rpm from 12,423'to 11,158' (20 stnds). Dropped carbide pill with no indication of gas near surface,complete full circ at 65 spm-470 psi, max gas 1,745 units. Break off topdrive,close upper rams,line up kill line, press up to 200 psi on backside, looking for communication in DP, had no flow, press up to 400 psi,no flow in DP,bled off annulus, blew down choke, MU topdrive,circ @ 3 bpm,390 psi. Notified Drilling Manager of results.Agreement made to pump marker pill.Finish circ B/U to clear 2,820 units.Mix high vis pill w/nut plug marker. 11/01/2012-Thursday Circulate high vis nut plug marker pill in/out to verify flow path of circulation system. Pumped 33 bbl pill at 124 gpm-380 psi,chased with 11.5 mud at 210 gpm-910 psi. Rotated string at 10 rpm-3,200 ft./lbs torque, 9,356 stks had nutplug pill at surface. RIH 20 stands DP washing liner to bottom at 3 bpm-500 psi, 150K down weight. CBU at 4 bpm-740 psi, 30 rpm-5,500 ft./lbs torque, max gas 3,487 units. Held PJSM with Baker reps and rig team on MU cement head and pup jnts. MU head, MU topdrive,wash down at 3 bpm-470 psi, 10 rpm- 4,000 ft/lbs torque,tag bottom at 12,425', PU and place shoe 2'off bottom at 12,423',up weight 175K.Held PJSM with Schlumberger,rig team, Baker reps,AIMM drivers on cementing.SLB pumped 5 bbls water to fill lines, PT hardlines at 1,000 and 5,000 psi, rig pumped 24 bbls13ppg MudPush II at 3.5 bpm-700 psi,SLB began batching 12 bbls into MudPush. SLB pumped 100 bbls(416sx) 15.6 ppg cement at 3.9 bpm with full returns throughout job,rotated string at 23 rpm,555 units max gas.Shut in DP,washed up cement lines,dropped dart, lined up and SLB displaced with 11.3 mud from pits at 5 bpm-330 psi initially, saw dart latch wiper plug at 89.6 bbls into displacement, increased pump rate to 5 bpm-1,500 psi and stopped rotation of string,cut rate to 2.5 bpm-830 psi,bumped plug/landing collar at 144.2 bbls displaced, fcp 900 psi, held 1,420 psi (500 over fcp)f/1 minute, increased psi to 3,000 and held f/1 minute, bled back 1 bbl,floats holding,max gas 1,891 units at shut down.CIP 16:45 hrs.Set HRD ZXP liner top packer as per Baker,top of liner at 8,765.97',RD SLB.Press up DP to 500 psi,ease up out of packer and start pumping as psi dropped. Increase rate to 7 bpm-1,400 psi and CBU 1 x, drop 4"wiper ball and CBU 1 x,approx. 10 bbls cement to surf on first CBU. POOH 14 stands racking back in derrick from 8,765'to 7,830'.Slip and cut 110'drill line.Pump dry job,cont POOH from 7,830'to 6,585'.Hole fill incorrect. Performed flow check,well is flowing at 4.5 bph,CBU at 4 bpm-630 psi,394 units gas at bott up.Notified Drilling Manager,prep to load 12.5 mud in pits.TIH from 6,585'to 8,730'(30'above liner top),calculated displacement 11.35 bbls,actual displacement was 19.5 bbls(8 bbls over). MU topdrive,close upper rams and monitor for any pressure on DP and annulus. 11/02/2012-Friday Continue monitor DP and annular pressure with well shut in,transfer 12.5 ppg mud into pits from tiger tank. SIDP 20 to 427, SICP 0 to 408. Transferred 11.5 mud to rock washer tanks and tiger tank to make room for returns in rig tanks. Circ 12.5 mud around through choke and degasser at 3.5 bpm,held 200 psi back pressure, ICP 600 psi,FCP 570 psi with full open choke,max gas 1,191 units.Stop pump, open upper rams, monitor well 30 min, static. Blow down surf lines. Pump 18 bbl slug 1.5 ppg over, blow down topdrive and mud line. POOH from 8,730' to 5,300', hole fill good. Monitor well f/30 min while filling trip tank. Well static. Continue to POOH from 5,300' to surface,LD Baker HRD-E liner running tool.No damage or other issues found with running tool upon inspection.PU and break pup jnts off Baker cement head, LD same and remove from pipe shed. RU to test BOPE, MU test jnt, plug, TIW and dart valves, PJSM.Test BOPE at 250/5,000 psi,annular at 250/2,500,all tests at 10/10 min,test gas alarms,monitoring well in cellar through annulus valve(no flow).Had AOGCC Rep John Crisp on location to witness BOPE tests. Page 1 of 2 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 44-33(Sidetrack of SRU 24-33) 50-133-20237-01-00 212143 9/19/12 Daily Operations: 11/03/2012-Saturday Cont testing BOPE at 250/5,000 f/10&10, annular at 250/2,500 psi f/10&10 min. Had 5 fail/pass tests due to psi drop on chart recorder. Changed plug seals, isolation needle valve on test manifold and leaking fitting on chart recorder. All fail/pass tests were re-done successfully. RD test equip, close annulus valve, pull test plug, install wear ring, blew down. MU Baker "TBR" dress and polish mill assembly and 7 5/8"scraper and XO's.RIH on 4"HWDP and DP to 8,752'(13'above liner top).CBU one time to get good 12.5 mud all the way around. Max gas 3442 units. 197 spm-8.5 bpm-2200 psi, rotating and reciprocating 40 rpm-2,600 ft/lbs torque. Reduce pump rate and rpm to 3 bpm and 10 rpm,ease down and locate liner top.PU increase rpm to 75,ease down and dress liner top f/10 min,3000 ft/lbs torque; on bott, 2200 ft/lbs off bott, 10K down wt on upper mill,460 psi on bott.CBU to clear any cuttings/cement from well bore and good 12.5 mud all around.Check for flow,pump 18 bbl dry job and blow down top drive/mud line.POOH from 8,765'to 2,000'. 11/04/2012-Sunday Cont POOH with polish mill/scraper assembly. Hole fill 6.75 bbls over calculated. Wait on rotating dog sub delivery. Service rig and topdrive,clean floor,grease crown sheaves,service boiler,CO grabber dies, pull wear bushing. MU 5.57"rotating dog sub&5.73"sleeve packoff+XO on HWDP, RIH to 8760'. Up weight 143K, down wt 137K with no pump or rotation. Ease into ZXP packer top with sleeve packoff,tag dog sub and set down 40K,had noticeable indication of shear,continued down to 50K down weight,PU and rotate at 60 rpm, slack off and set down to 90K(50K down wt) while rotating, PU/slack off to 75K(60K down wt). PU 5' and RU to test casing. Line up injection pump on kill line,press up on backside and test 4"x 7 5/8"for 15 minutes.Good test. Bleed off. Displace well to 11.5 mud. Had max gas of 2,698 units at bottoms up. Line up injection pump and test 7 5/8", liner lap and 4 1/2"casing at 2,100 psi for 30 minutes on chart.Good solid test. Bled off and RD injection pump.Check for flow, pump 18 bbl dry job 1.5 lbs over,blow down topdrive&mud line. POOH rack back stands to 3,444'.Lay down 4"DP and 18 jnts 4"HWDP. 11/05/2012-Monday Cont POOH from 559'LD HWDP and Baker rotating dog sub.RD hand tongs,4"elevators and spinner,RU to run 2 7/8"tubing,clean floor. MU Swaco scraper assembly,3.75" bit, 113 jnts 2 7/8"tubing from pipeshed and 4" DP from derrick. Had no problem going into 4 1/2" liner top. MU topdrive and wash/reamed from 8,775'to 12,290'at 4 bpm-1,600 psi,40 rpm,encountered no cement.CBU 168 gpm-2,600 psi,40 rpm,2,400 ft/lbs torque,rotate and reciprocate string. 11/06/2012-Tuesday Continue CBU with 11.5 mud.at 12,288'.Rotate and recip 168 gpm-2,600 psi,40 rpm. Displace well to fresh water 2 Lull circs at 124 gpm- ICP 1,230 psi, FCP 800 psi.Did a walk through of the rig with Drilling Compliance Specialist and SLR Rep.Pump fresh water through choke manifold, kill line,choke line, blow down top drive, mud line,choke line and manifold. POOH on elevators from 12,288'to 7,858'(upper scraper), up wt 185K,down wt 155K; RIH from 7,858'to 12,288'. Displace well with clean fresh water,followed by pill train and 6% KCL. Blow down all hoses and pumps from tank battery, flush pump 2, blow down topdrive, mud lines and all 3 rig pumps. POOH LD 4" DP from 12,288 to 7,884,LD baker scraper. Page 2 of 2 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 44-33(Sidetrack of SRU 24-33) 50-133-20237-01-00 212143 9/19/12 Daily Operations: 10/17/2012-Wednesday Rotate and slide F/9,644 T/9,751,315 gpm,3260 spp,60 rpm,tq on bott 3.8k;tq off 3k,wob 15/20k,p/u 153k,s/o 145k,rwt 147k.Rotate &slide f/9,751 t/9,833.UP 155k,DN 145k,ROT 148k,7.6 bpm=3,300 psi OB.,12.5 ppg ECD,Ave ROP=16.4 fph,CBU.7.1 bpm=3,050 psi. Monitor Well. Well flowing @ 2.8 bpm (1.4 bbl gain in 30 min). Pump up final survey & CBU. 2,090 units of Gas @ BU. POOH f/9,833 t/8,540.Well took 1.1 bbls over calc.displ on trip out.Monitor well on the trip tank.Well flowing @ 3.4 BPH.TIH f/8,540 t/TD @ 9,833.CBU to clear gas influx from well bore. 7.5 bpm = 3,250 psi. 3,572 units @ BU. Shut well in & record pressures, 342 on DP, 334 On annulas. Increase mud weight in surface volume F/11.6 T/11.9,DP psi @ 450 psi.Circulate 11.9 ppg KWM @ 3 bpm,ICP 1,260 psi. 10/18/2012-Thursday 11.9 ppg in&out.Shut down pumps.Well flowing.Shut in Well and monitor pressure build.SIDDP=310 psi,SICP=290 psi. Perform F.I.T prior to increasing mud weight.Test MW= 11.9 ppg.TVD=8950.Test pressure=993=14.0 ppg EMW. (good test) Bleed down pressure. Open well and CBU. Max Gas=604 units @ BU.POOH from 9,830'to 9,018'.UP 165k, DN 148k. (2.6 bbl under calc displ.).Orient to place bit @ 80 deg RT. Increase MW in suction pit to 12.2 ppg. Displace well bore to 9,018 with 12.2 ppg. Flow check well. (still flowing, but diminished)Increase MW t/12.5 ppg. Displace well bore to 12.5 ppg.3 bpm,850 psi.Monitor well,well ok.Continue to circ @ 3 bb/min& cut drilling line.Monitor well,trip out of hole. 10/19/2012-Friday BHA: L/D Jars,Std back Flex DCs,PJSM on RA Source.Remove Source.Drain&inspect Motor. Inspect&grade bit.4,3,WT,A,E,I,LT,Hrs.Clear rig floor of slip/trip hazards.R/U to test BOP. Test BOP and related equipment to 250L/4,000H.Test Annular to 250L/2,500H.Hold all tests f/10 min &chart record same. Perform Accumulator precharge test. R/D test equipment&clear floor. Install Wear Bushing(6 5/16" ID). Prep BHA components and stage in Pipe Shed. M/U BHA#4&orient mwd tools.Shallow test mwd tools,clean rig floor,prep for p/u drill pipe.Pick up 50 joints drill pipe.TIH w/BHA#4. 10/20/2012-Saturday TIH w/BHA#4 on 4" Dp to 8,980'.Well gave 4 bbls over calc displ.on TIH.CBU w/12.5 ppg @ 9,100'.Began getting gas and fluid cut mud after 96 bbls pumped. MW decreased to 11.4 ppg.2,250 units of gas.Chlorides diluted to 20,000 ppm. Shut in&circulate thru Buster to clear gas influx.Begin diverting 12.4 ppg to R4R tank.Divert to pits when weight decreased to 11.9.Recovered 382 bbls of weighted mud in R4R.Circulate&cond to treat mud.Treat mud w/circ @ 5 bpm, 1,650 psi while getting thru crew change(1st day back).TIH f/9,100'.Set down on obstruction @ 9,590'.Wash and ream thru same.Continue TIH to 9,833'.Break circ and record parameters.UP 158k,DNI 142k.CBU @ 7 bpm,3,100 psi.12.7 ECD.2,250 units of gas @ BU.Slide/rotary drill for directional requirements f/9,832't/9,998'.7.6 bpm,3,200 psi, 330 gpm, 3,050 SPP, 3.1 tq off bott, 4 tq on, wob 8k, 50 rpm, p/u 160, s/o 146k, rwt 150k, 6.4 hrs on bit. Rotate and slide F/9,998' 1/10,220',332 gpm,3,250 SPP.Bit Ave ROP=26.4 ft/hr. 10/21/2012-Sunday Drill slide/rotary f/10,200;t/10,288'. UP 165k, DN 148k, RT 150k, 7.8 bpm, 3225 psi.Slow P-rate(2-4 ft/hr)from 10,275'to 10,294' (6.2' TVD)Tuffaceous Claystone. Drill slide/rotary f/10,288't/10,508'34 ft/hr ave rop.Troubleshoot pump engine problems. Engine repeatedly dying.Drill slide/rotary f/10,508't/10,561'.Sheared die retainer plates in Grabber.Pull 1 std. Repair TD.P/u 1 stand,circulate out gas, 166 units @ 310 gpm, 3,050 psi. Drill F/ 10,561'T/ 10,580', @ 310 gpm, 3050 psi, p/u 170, s/o 153, rot wt 152. Rotate and slide F/10,580' T/10,825'.41 ft/hr ave rop. 10/22/2012-Monday Drill slide/rotary f/10,285't/11,063'.Pumped sweep @ 11,025'. Solids increased f/25%to 75%by volume @ B/U.Drill slide/rotary f/11,063' t/11,175'. Circ.carbide sample In/out to gauge hole.Carbide returned to surface 14 bbl under calculated displacement.Trouble shoot top drive blower motor default.Rotate and slide F/11,175'T/11,295',p/u 180k,s/o 150k,rot,152,torq 5.1.Change out top drive blower motor power cable.Rotate and slide 1/11,295'T/11,379',p/u 182k,s/o 152k,rot 154k,gpm 300 rpm,50,torq on 5.3,tq off 4.4,wob 6k. Circulate bottoms up @ 310 gpm,3,260 psi. Monitor well for 30 min,well flowing @ 7.8 bbl/hr. Repair top drive hydraulic lines on IBOP actuator. Safety stand down with rig crew on near miss incident. Circulate and increase mud weight F/ 11.4 T/11.6.Well flowing @ 2.4 bph. Begin short trip to window.Pull from 11,380't/11,000'. 10/23/2012-Tuesday Continue pulling short trip to window F/11,000'.Hole in good condition.CBU @ 275 gpm,2,400 psi,1412 units of gas.Trip in hole F/9,053' 1/11,325',p/u 185k,s/o 138k CBU,3760 units gas.Rotate and slide F/11,395'T/11,510',300 gpm,3,400 SPP,50 rpm,5/8 wob. Rotate and slide F/11,510'T/11,592',p/u 188,s/o 152k,rot 158k,290 gpm,3140 PSI,ADT 5.5,AST.9,Bit hrs 41. Rotate and slide F/11,510'T/11,640', Gpm 290,torq on bottom 5.6,off 4.8, spp 3,025,rpm 50,p/u 188k,s/o 152,rtw 158. Page 1 of 1 it w 10 OF O �j� ,� THE STATE Alaska Oil and Gas � 0JALAS� Conservation Commission ktStf GOVERNOR SEAN PARNELL 333 West Seventh Avenue op. Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive Anchorage, AK 99524 Re: Swanson River Field, Hemlock Oil Pool, Soldotna Creek Unit 44-33 Hilcorp Alaska, LLC Permit No: 212-143 Surface Location: 876' FNL, 2127' FWL, SEC. 4, T7N, R9W, SM Bottomhole Location: 112' FSL, 732' FEL, SEC. 33, T8N, R9W, SM Dear Mr. Mazzonlini: 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, Cathy . Foerster Chair rct DATED this day of October, 2012. cc: Department of Fish 8v Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) r RECEIVED STATE OF ALASKA AL .A OIL AND GAS CONSERVATION COMM._ _ION PERMIT TO DRILL SEP 1 1 2012 20 AAC 25.005 1 a.Type of Work: lb.Proposed Well Class: Development-Oil ❑, Service- Winj ❑ Single Zone gaSki p �(3N�i�10 4�1R� erroPkfimisfn� Drill ❑ Redrill Q Stratigraphic Test ❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone ❑ Coalbed Aj/Hydrates [1- Re-entryExploratory _ ;' r a1 ❑ ❑ p ry ❑ Service WAG ❑ Service Disp ❑ tee Gas 2.Operator Name: 5. Bond: Blanket Q Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No.'L2?-'75-2`><'(.22655257 , '1U4-33 �j 3.Address: 6.Proposed Depth: /5�1.I,f j-12.Field/Pool s):,gi /3,4 3800 Centerpoint Dr,Anchorage,AK,99524 MD: 12,328 TVD: 10,723 I4dmlocfc°Ql Pool �l�,�L 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): /0 3'/L Surface: 876'FNL,2127'FWL,Sec 4,T7N,R9W,S FED A028399&FED A028997 Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 34'FNL,2062'FEL,Sec 4,T7N,R9W,S N/A 9/20/2012 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 112'FSL,732'FEL,Sec 33,T8N,R9W,S 4320 acres total(both properties) 34'From North Line 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL:183.2 feet 15.Distance to Nearest Well Open Surface: x-344467 y- 2460328 Zone-4 GL Elevation above MSL:164.6 feet to Same Pool: 73V(SCU 34-33) 16.Deviated wells: Kickoff depth: 9,500 feet 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 70 degrees Downhole: 3496 psig Surface: 2423 psig 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole _ Casing Weight Grade Conn Length _ MD ND MD ND (including stage data) 6" 4-1/2" 12.6 L-80 Hydril 521 3028' 9300 9200 12,328 10,723 385 ft3 at 15.3 ppg 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth ND(ft): Plugs(measured): Effect.Depth MD(ft): Effect.Depth ND(ft): Junk(measured): Casing Length Size Cement Volume MD TVD - Conductor/Structural Surface 3408 10-3/4" 1500 sx 3408 3408 Intermediate • Production 10635 7-5/8" 1000 sx 10635 10200 Liner Perforation Depth MD(ft): P&A'd Perforation Depth ND(ft): P&A'd 20. Attachments: Property Plat Q BOP Sketch Q Drilling Program ❑., Time v.Depth Plot Q Shallow Hazard Analysis❑ Diverter Sketch❑ Seabed Report ❑ Drilling Fluid Program ❑✓ 20 AAC 25.050 requirements Q 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. /Contact Printed Name ?MAL- /V I Ii c.I N ( Title -D442.1 L t./IU G MGR_ Signature�eeX..0/4121,0-2- / ;L.... Phone 907--777- 8369 Date OR/it/ix L Commission Use Only Permit to Drill 2 API Number: Permit Appro I See cover letter for other Number: Z�� f 50-i)�'' �371 Date: ��(� requirements. . .------- Conditions Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane, as hydrates,or gas contained in shales. I2( Other: 7r soot) r 1 O f f-i- 1 Samples req'd: Yes❑ No©' Mud log req'd: Yes ❑ No .' �p �Sa /lh+� rS T 1 -h) HZS measures: Yes❑ Nog Directional svy req'd: Yes E�No ❑ .e )' APPR ED BY THE COMMISSION DATE: 10 •" 3 / 2- • (L=-1 COMMISSIONER ORIGINAL 4f2- Form 10-401(Revised 7/2009) This permit Is valid for 24 months from the date of approval(20 AAC 25.005(g)) Submit in Duplicate Hilcorp Paul Mazzolini Hilcorp Alaska, LLC new,Company Drilling Manager P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8369 9/10/2012 Email pmazzolini@hilcorp.com Commissioner Alaska Oil& Gas Conservation Commission 333 W. 7th Avenue Anchorage,Alaska 99501 Re: Soldotna Creek Unit 44-33(Redrill of SRU 24-33). Dear Commissioner, Enclosed for review and approval is the application for the Permit to Drill the Soldotna Creek Unit 44- 33. SCU 44-33 is a development oil well planned to be re-drilled in an E direction from the parent wellbore SRU 24-33 utilizing the existing casing program down to 9,500' MD/9,403'TVD. SRU 24-33 has been plugged and abandoned to a depth of 10,120' MD. The original perforations were in the Hemlock formation from 10,661'to 10,862'. All perforated intervals have been previously • plugged and abandoned with a combination of cement and cement retainers. At 9,500' MD the parent wellbore will be sidetracked and a 6"x 2828'hole section drilled to a total depth of 12,328' MD/10,723'TVD. SCU 44-33 is a"Build& Hold"wellbore reaching a maximum of 70 deg inclination. • Drilling operations are expected to commence approximately Sept 20th, 2012 depending on the progress of SRU 23B-22. Prior to the commencement of drilling operations, the William 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 3-1/2"tubing. 3. Cleaning out wellbore. 4. Running a gyro from 10,120'to surface. 5. Set a CIBP @ 9520'&test casing to 2100 psi/30 min. A spacing exception determination is currently underway. Supporting documentation will be submitted to the State if a spacing exception is required. 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) Hilcorp Alaska, LLC Page 1 of 2 b. Potential target reservoirs and their predicted pore pressures are indicated in attached Well Design Summary. 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 44-33. 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. 22035257 • 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, Y Paul Mazzolini Drilling Manager Hilcorp Alaska, LLC Page 2 of 2 Swanson River Well SCU 44-33 Hilcorp Well Design Summary two comp SCU 44-33 Well Design Summary SCU 44-33 is a development oil well planned to be sidetracked out of 7-5/8" production casing in the existing SRU 24-33 wellbore. A 6" x 2828' open hole section is planned from 9500' MD / 9403' TVD to 12,328' MD / 10,723' 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 south of the E fault. High on structure, the H10 is the primary target. Reserves aren't recoverable in existing wellbores due to lack of take-points or mechanical condition of other existing wellbores in the fault block. SCU 44-33 is a deviated, "Build & Hold" wellbore reaching 70 degrees inclination in the tangent section and a total depth of 12,328' MD / 10,723' TVD. No H2S is expected to be encountered during the drilling & completion of v SCU 44-33. The well will be completed with a 4-1/2" production liner & 3-1/2" gas lift assy. y rtAIL.9mit- rc i 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 44-33 Estimated Spud Date: 9/20/2012 Field: Swanson River Productive Horizon: Hemlock Total Depth: 12,328' MD / 10,723' TVD 9/10/2012 Page 1 of 9 1 I Swanson River Well SCU 44-33 Hilcorp Well Design Summary Emma Comm", Well Coordinates: Surface Location: 876' FNL, 2127' FWL, Sec 4, T7N, R9W, S X=344467.3, Y=2460328, NAD27, ASP, Zone 4 X= 1484490, Y=2460089, NAD83, ASP, Zone 4 Top of Prod Horizon: 34' FNL, 2062' FEL, Sec 4, T7N, R9W, S X= 345567.5, Y= 2461155.97, NAD27, ASP, Zone 4 X= 1485589, Y= 2460917, NAD83, ASP, Zone 4 Planned BHL: 112' FSL, 732' FEL, Sec 33, T8N, R9W, S X= 346898.4, Y= 2461284.4, NAD27, ASP, Zone 4 X= 1486921, Y= 2461045, NAD83, ASP, Zone 4 Ground Elevation: 164.6' AMSL • KB elevation: 18.6' C13 Z '71141$4 0, .iv Existing SRU 24-33 Casing Design i•1 S�e O.D.le Weight Grade Conn Length Top MD/TVD Btm MD/TVD (in) (in) (lbs / ft) (ft) (ft) (ft) - 10-3/4 40.5 J-55 BTC 3408 WH 3408 - 7-5/8 33.7 N-80 BTC 78 WH 78 7-5/8 26.4 L-80 BTC 4543 78 4621 7-5/8 29.7 L-80 BTC 1490 4621 6111 7-5/8 33.7 L-80 BTC 1006 6111 7117 7-5/8 33.7 P-110 BTC 2383 7117 9500 Planned SCU 44-33 Casing & Tubing Design Hole Tube Weight Length Top Btm MD/TVD Size O.D. (lbs / ft) Grade Conn (ft) MD/TVD (ft) (in) (in) (ft) 6 4-1/2" 12.6 L-80 Hydril 3128 9300/9200 12,328' / 521 10,723' Tbg 3-1/2" 9.3 L-80 EUE 9200 WH 9200 All casing will be new,PSL 1 (100%mill inspected, 10%inspection upon delivery to TSA in Fairbanks) 9/10/2012 Page 2 of 9 i t Swanson River Well SCU 44-33 Hilcorp Well Design Summary foam Comppary Well Control Summary Hole Section Equipment Test Pressure (psi) • 11" 5M Hydril GK Annular BOP • 11" 5M Hydril Double ram (fixed pipe rams in top cavity, blind rams in bottom Test Pressures: 6" cavity) 250/5000 • 1 1" 5M drilling spool (3-1/8" outlets) (Annular 250/2500 psi) • 1 1" 5M Hydril Single ram (Casing rams in ram cavity) 41-5 mentis Test Pressures: 6" • 3-1/8" 5M Choke Manifold 250/5000 (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. 9/10/2012 Page 3 of 9 Swanson River Well SCU 44-33 Hilcorp Well Design Summary Dingy Cumpacy Anti-Collision Evaluation Summary SCu 44-33 will be sidetracked from the parent wellbore SRU 24-33 at 9,500'. • Other than the existing wellbore, there are no anti-collision issues with offset wellbores (SF > 1.3). SCU 44-33 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" window 9,403 FIT 10.6 13 1173 psi Note:Anticipated fracture gradient at the 7-5/8"window depth(9,403 TVD)is expected to be.728 psi/ft based on offset field test data. An FIT of 13 ppg was chosen to allow for a(2.4)ppg(or 1173 psi)kick margin while drilling with a 10.6 ppg fluid density. Casing Testing Fluid Density in Test String Casing Pressure Test Duration Casing Burst (PSI) 7-5/8" Casing _ 8.5 ppg 2100 30 min 6020 psi 4-1/2" Liner 10.6 ppg 2100 30 min 7500 psi All casing tests will be held for 30 min. If pressure declines more than 10%in 30 min,corrective action must be taken. 9/10/2012 Page 4 of 9 Swanson River Well SCU 44-33 Hilcorp Well Design Summary fineg'Comity Mud Program Summary Production Hole Section (6" hole, 4-1/2" liner to 12,328' 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 9500' to 10.4— z 40-53 10-24 18-26 <5 8.5-9.5 12,328' 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 12.5) Completion (3-1/2" Tubinci to 9,200' MD) System Type: 3% KCI Brine Properties: Density-8.4 ppg, Chlorides-25,000 ppm 9/10/2012 Page 5 of 9 Swanson River Well SCU 44-33 Hilcorp Well Design Summary Entegy Company Cementing Summary Production Hole Section (6" hole, 4-1/2" liner to 12,328' 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 7-5/8" window. Estimated total volume is as follows: Section Formula Volume 7-5/8" x 4" overlap: (200') x 0.029 = 5.8 bbls 7-5/8"x 4-1/2" overlap: 200' x 0.025 = 5 bbls 6"x 4-1/2" OH annulus: 2828' x 0.0153 x 1.3 = 56.3 bbls 4-1/2" Shoe Track: 90' x .0152 = 1.4 bbls Total Volume (bbls): 5.8 + 5 + 56.3 + 1 .4 = 68.5 bbls Slurry Information: Stage EasyBLOK Production Blend System Conventional Density 15.3 lb/gal Yield 1.35 ft3/sk Mixed Water 5.912 gal/sk Mixed Fluid 5.962 gal/sk Total Volume 68.5 bbl=385 ft3=285 sx Expected 100 Bc at 05:24 hr:mn Thickening Expected ISO/API 13 mL in 30.0 min Fluid Loss Code Description Concentration • G Cement 94 lb/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 D174 Expanding Agent 1.5%BWOB 9/10/2012 Page 6 of 9 Swanson River Well SCU 44-33 Hilcorp Well Design Summary I n,1 y l ompa-} Anticipated Formation Tops and Geohazards Top Name Formation Expected Fluid TVD Est Press PPG Kick Off Pt 9,500 9.0 G2 Tyonek G Oil None 10,228 2000 psi 3.8 _HKT_ Top Hemlock Oil Oil/Gas 10,298 1000 psi 1 .9 H3 Hemlock Oil Oil/Gas 10,368 1000 psi 1 .9 H5 Hemlock Oil Oil/Gas 10,412 1000 psi 1 .9 H7 Hemlock Oil Oil/Gas 10,484 3000 psi 5.5 H10 Lower Hemlock Oil/Gas 10,589 3000 psi 5.5 H12 Lower Hemlock Wet 10,717 3000 psi 5.4 TD 10,723 Formation Evaluation Summary Interval Evaluation Method Comments 9500' to 12,328' LWD Baker Hughes Dual Gamma Ray + Electro- v 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 44-33. 9/10/2012 Page 7 of 9 Swanson River Well SCU 44-33 Hilcorp Well Design Summary [now Company SCU 44-33 Drilling & Completion Summary 1 Prior to Mobilization of Doyon Arctic Fox to wellsite: a. MOB William pulling unit to wellsite. R; 1-to� b. N/D Tree, N/U and test BOP. c. Pull 3-1/2" prod tubing. d. Run gyro survey to 10,120' MD. e. Set CIBP @ 9520'. f. Install & test new tubing head g. Install & test dry-hole tree. h. Prep and level location for drlg rig. 2 Mobilize Doyon Arctic Fox to wellsite. . muza est gnP + Sow Ws) 3 Make drift run w/ 6" mill tooth bit & 6-5/8" string mill. Test csg to 2100 psi / 30 min. 4 Set Whipstock, displace to 10.6 ppg drilling fluid and mill 6-5/8" window from 9500' to 9516'. Drill 20' new formation below window to 9536'. 5 Conduct FIT to 13 ppg EMW. 6 TOH with milling assy, M/U and TIH w/ 6" directional assy. 7 Drill 6" hole using mud motor / MWD / LWD assy (GR + Res + Density + Porosity) to TD at 12,328' MD / 10,723' TVD. n.(� 8 Clean up hole as necessary, pull wiper trip to window. 9 TOH, L/D directional assy. --� C/o t�`ILA— 4 A4 s 1sl 10 Run 4-1/2" liner to 12,328'. Pump primary cement job, cmt from 4-1/2" liner shoe to TOL at 9300'. 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 7-5/8" & 4-1/2" casing. 14 Test 4-1/2" liner + 7" prod casing to 2100 psi / 30 min./GLu,,,f 15 Displace well to 3% KCI completion fluid. 16 TOH, LDDP 17 N/D BOP, N/U dry hole tree. 18 RDMO Dovon Arctic Fox. 19 Mob AWS rig #1 to wellsite a. Perforate well via TCP assy Ni b. Run 3-1/2" gas lift assy. Su Jrr c. Install production tree. 1 9/10/2012 Page 8 of 9 Swanson River Well SCU 44-33 Hhlcorp Well Design Summary Energy(mummy Anticipated Drilling Hazards: 6" 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 10ppb 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 v PLUS 4 ppb). • Increase fluid density as required to control the running coal. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb BAROTROL pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. 9/10/2012 Page 9 of 9 SRU 32A-33 BHL A028406 SCU 343-33 BHL A028399 • 1 SCU 13-34 BHL S008N009W gi) e20 /% I / A028990 :' ;SCU 33-33 BHL .../ o- lRU 14A-33 BHL , .4-? ' SRU 14-33 BHL ,' /' / / ' �� RU 24-33 BHL ' - �—� I �� -� ��'� SCU 44-33 BHL I r O • /� _ V a ° • n 0 0 0 0 0 0 0 °°0 00 0 0 0 °°° SCU 44-33 Top of Production Horizon SCU 41-04 BHL 4 SCU 21A- BHL 4 ..` CuS44-33 SHL? / ;• \ 1 /, . / + S. //• jSCU 42-04 BHL \ / \ / / \\ SCU 12-04 BHL / SCU 12-03 BHL • // SCU 12A-03 3HL w„ I SCU 12A-04 BHL / 4 A028997 SCU 22-04PB BHL // • 9 SCU 332-04 BHL S007N009W SCU 22-04 BHL is f /' i 1 ' I, // I/ SCU 43-04 BHL SCU 13-04 BHL r / • Ir- -\ Legend / SCU 13-03 BHL, 1 SCU 43A-04 BHL r' Surface Hole Location / SCU 44-33 Top of Production Horizon • Bottom Hole Location 0 SCU 44-33 Wellpath •S`` U 44-04 BHL 0 1,000 2,000 II Soldotna Creek Unit Feet SCU 44-33 N Alaska State Plane Zone 4,NAD27 Hilcorp Alaska,LLC September 10,2012 W I En 'f-0 ,,, ,,,1 c c o M a o 0 0 - 14 O - .MO-i © 00 G 0 OMO 00 00 O r g Z c o � to ®M M 21 u. v - u N A p. 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N u" 'r' W .. © O U E 0 00 U _x U z a q z � - � M a 21 L L.': W CC o W v OC O ¢ w w F z .• � ( r ..„,,,„ Hilcorp Alaska, LLC �� Location: Cook Inlet,Alaska(Kenai Peninsula) Slot: SRU44-33 BAKER Field: Soldotna Creek Unit Well: SCU44-33 HUGHES Facility: SCU 24-33(44-33) Wellbore: SCU44-33 I lileorp:Alaska.l.lA: Plot reference wellpath is SCU44-33 Version#2 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:183.1 feet Scale:True distance Mean Sea Level to Mud line(At Slot:SRU44-33):0 feet Depths are in feet _ Coordinates are in feet referenced to Slot Created by:jonethoh on 09-Sep-12 Easting(ft) 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 I 2015 w l000 H12(LowerHemlock) SCU44-33 H12(Lower Hemlock)8-Sep-1, End of r Build/Tum 750 Z Tie On/KOP o O- 500 7 ko 9 250 0 SRU44-33 -250 "9250— Tie On/KOP 9500— 9750— 7.00/10oft a 10000— ku End of r Build/Tum 0 m U_ 1= • 10250— 2 H A V. 7.625in Casing Intermediate 10500— H12(LowerHemlock) 10750— SCU44-33 H12(Lower Hemlock)8-Sep-12 4440 i AV. 5.5in Liner 11000— ii- 11250— 1 1 1 1 1 1 1 1 1 1 1 1 1 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 Vertical Section(ft) Azimuth 67.78°with reference 0.00 N,0.00 E Hilcorp Alaska, LLC BAKER Location: Cook Inlet,Alaska(Kenai Peninsula) Slot: SRU44-33 HUGHES Field: Soldotna Creek Unit Well. SCU44-33 Facility: SCU 24-33(44-33)IIWellbore: SCU44-33 I Iill•orp.%asks,HA Safelixdr•100R Easting(ft) -200 -150 -100 -50 0 50 100 150 200 250 300 350 400 450 I I I I I I I 11 I I I I I 4.0 Plot reference saedpath is SCU4433 Version a Tow vortical depths are referenced to Mak Fox(RTE) Grid SystemNFD27/TM Alaska SP,Zero 4(5004),US feet Jry Measured depths are referenced le MGic Fox(RTE) North Reference:True n0M 0 800— Modic Fax(RTE)to Moon Sea Level 187.1 feet Sale:True dfefena 0 —800 Moen Sea Level to Mud ino(Al Slot551144-33),0 Mt Depths are in feet Coordinates are in loot referenced to Slot Created by:One..en 10-Sep-12 750— —750 9800 1- 980' 700 700 650— —6550 600— —600 • 550— Tie On/KOP 9400 —550 500— —500 450— —450 Z cm 0 L 400— —400 1 0 Z _ 9000 350— —350 300— —300 250— s —250 7400 1f 6600 200— 10600 8600 —200 5800 150— 5400 —150 Sr 5000 J� / 4600 100— —100 8200 4200 3800 50— —50 7800 3400 7q 3000 -B6ii 1400 0— SRU44-33 —0 1000 000 SCU 21A-04 2•'h 3800 I I I I I I I I I I I I I I -200 -150 -100 -50 0 50 100 150 200 250 300 350 400 450 Scalp I inch=10On Easting(ft) Existing SRU 24-33 Wellbore Schematic • • • L SRU 24-33 20" @ 337' NOTE: All depths are KB reference. 9 7 PPG Original GL-KB is 20 ft. BRINE P&A CEMENT II FILL 10-3/4' @ 3408' `1983' CAMCO MM MANDREL 3612' CAMCO MM MANDREL 4961' CAMCO MM MANDREL 5028' CAMCO MM MANDREL 6728'CAMCO MM MANDREL 7234' CAMCO MM MANDREL TUBING CUT C& ioiw' 755T CAMCO MM MANDREL EST TOC io'. y' 10276' 3-1/2" x 2-3/8" CROSSOVER 5-1/2" LINER @ 10434' �'''= :'`: :i: CEMENT RETAINER x010580' r10590' XA SLEEVE TUBING PERFORATIONS 10610'-10615' CEMENT RETAINER 010620' �!► 10624' PACKER 7-5/8" @ 10635' ,10630' S NIPPLE ;:;• :'::• UNER PERFORATIONS { ' '` 't TUBING PERFORATIONS 10635'-10640' 10644 -10660' �:::.▪ � '• �:;:�• 10676'-10696' 10704'-10711' . •• ,�r ""' 10721'-10735' 1% RECEIVED V E D 10733' D NIPPLE MAS 31993 • i':;;;!•:4 Ion Alaska Oil&Gas Cons.Comm�ss 2-3/8" 4.6# @ 10754' ir 10738° FILL Anchorage 10763' TOP OF FISH 10765' PACKER UNER PERFORATIONS 10740'-10762' ' :: 10770'-10794' 10821' PBTD 5-1/2" 23# @ 11085' , , Planned Swanson River Unit II Well SCU 44-33 164.6'Above MSL Casing & Tubing KB-THF:20' Size Type Wt Grade Conn. ID Top Btm a 1 :.1 1 rrj l 20" Conductor - - - Surf 337' 20" �° D � 10-3/4" Surf.Csg 40.5 J-55 Buttress 10.05 Surf 3,408' 2 ,. 33.7 N-80 Buttress 6.64" Surf 78' 26.4 N-80 Buttress 6.844" 78' 4,621' 7-5/8" Intermediate 29.7 N-80 Buttress 6.75" 4,621' 6,111' 3 ' 10-3/4" 33.7 N-80 Buttress 6.64" 6,111' 7,117' 33.7 P-110 Buttress 6.64" 7,117 9,500' 4 4-1/2" Prod Lnr 12.6 N-80 H-521 3.958" 9300' 12,328' tst Tubing "41 3-1/2" Production 9.2 L-80 IBT IBT 2.441 Surf 9,200' 5 M1 it JEWELRY DETAIL • 6, �� No. Depth ID OD Item .,, 1 20' 2.44" - Tubing Hanger 2 1,300' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port ►t 3 2,400' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port 7i 4 3,500' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port 5 4,600' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port yl I1 6 5,200' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port 7 6,200' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port ,l 6 r 8 6,900' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port 10 I I 9 7,900' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port I lig II 9,160' 2.000" 6.5" On/Off Tool w/X Nipple f = ;-= 11 9,180' 1.978" 4.140" Arrowset Mechanical Packer 11 PA 12 9,200' - - WL Entry Guide w/X Nipple 7-5/8"211 12 Iiiii 4-1/2'L TD=12,328/TVD=10,723' SCU 44-33 Proposed Well Schematic 9-10-2012 Updated by LEK 9/10/2012 Maximum Anticipated Surface Pressure Calculation Hilcorp Soldotna Creek Unit 44-33 Kenai Peninsula,Alaska Offset Information Well Date Hemlock Pressure TVD Grad SRU 331-27 March, 2012 3140 10600 0.296 Assumptions: 1. Based on offset drilling&well test data, Hemlock pore pressure is anticipated at 3100-3500 psi. 2. 3500 psi @ 10,723' =0.326 psi/ft 2. Fracture gradient at 9,403' is estimated at 0.728 psi/ft based on field test data. Fracture Pressure at 7-5/8"window considering a full column of gas from window to surface: For 7-5/8"window at 9403'TVD: 9403(ft)x 0.728(psi/ft)= 6845 psi 6,845(psi) - [0.1(psi/ft)*9,403(ft)]= 5905 psi MASP from pore pressure Max pore pressure at TD (10,723'TVD) MASP (Wellbore evacuated to gas column) 10,723(ft)x 0.326(psi/ft)= 3496 psi SIBHP-gas gradient to surface: 3496(psi)- [0.1(psi/ft)*10,723(ft)]= 2423 psi Summary: 1. MASP while drilling 6" production hole is governed by SIBHP-gas gradient to surface. • 2. MASP during production life is governed by SIBHP-gas gradient to surface. us k mmv .co 0- --. k 5 0-- °Q Fa N co I- • §mow k` > § \ca ca§2/ Ln 0 Dix i To ��r20 §§ } _1 \°a rII E ! 0); 0 §r® k' / \ 0 0 U) k7' ■ D000 � \ ,z2-1E , 2LZ®� - ■ ! tee( o IL 000m° ® a• a c, ,_1-��v E0 CI - _ }k I k \$§f / CO 0 \§ ✓ k§ 0 ƒ §«�] m ® _ )$ O 2 st~ §= d TO k I- 3 $$ / §` `� U I k) II o 2 ;f { I ca M°� 5 \ 0 §§ CO \\ a 0 0 N (f • ` §" 2 37 oo)§ \k\ D § \)C )0 ); \\/ x §CD ) �; z O O ! § k <N- 4 0 777 o {�) )— N . ,a3A ! II Swanson River SCU 44-33 09/10/2012 I1.1.4.9,%1..\..I.It Swanson River SCU 44-33 103/4X75/8X3''A r �Ifil� f / �J Doyon Drilling 11"5M Hydril V BOP & 1 f le= 0 w Lir_ _ _ :_,._ __ _ .. = ..,a op,- * i :: . : InI I ! I I I: "` -ftI-ff�rffflff t -. „ ,.. ... ,, . .01 1 II '!-`, 1i • ., . ..• 11 1 1.1 0./Ai, _ ' -- fan, - *. = ,U i1.0 Crossover spool 11 5M X 7 1/16 5M I 1 di ill iii Iii ag Ay Lui ��i[®C, jl :ill,_IL,.-I _A 111 111 UI 1 III a ) iiiiim[0( LoTf Y 4 a o 0 Li Z '8o �� CO CC. PIA 0 flil OILI LL . 0 IAA V/ CI0 Ni \ IP Q m 1 \ ., 4 _ Lt)) or - 0 co - 4 O 1$11i) r IV 11._CC Olt (TM -' A ilik do raftr to d at liq 14 V. .' r1 tu O °i �o C9 1 J C tca A v W -5 � in Q M 2 M N M C 4.0 . \— 10 : „ ,_ , N 1L LL. O O H H SCU 44-33 Days Vs Depth 0 _ 2000 4000 --- -- F 6000 C. O 3 0) d i 8000 10000 12000 14000 0 5 10 15 20 25 30 Days 1 ( ■ 1 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. , 1 II Happy Valley SCU 44-33 Hilcorp Drilling Waste Plan p.v c Drilling Waste Plan All hole sections will be drilled with a water based drilling fluid. Cuttings will be hauled from the "B" pad to Emerald Technologies, Inc where they will be dried & inerted. Cuttings will be transported to Emerald as they are generated. There is no plan to store cuttings at the drilling site. Cuttings meeting regulatory requirements will be hauled to a land fill at the discretion of Emerald Technologies, Inc after appropriate drying & inerting. In the event Emerald Technologies cannot handle drilling waste from SCU 44-33, Aimm Technology, Inc will be utilized in the same capacity. 9/10/2012 Page 1 of 1 , ti Swanson River SCU—44-33 09/10/2012 Tubing hanger,CIW-N-CL- Planned Wellhead Schematic after Tubing head FBB,7 X 3'h EUE 8rd Lift change out and susp,3"Type H BPV profile,3/8 control line prep BHTA, Bowen,3 1/8 5M FE ill III all u, fiNiiiit Valve,swab,WKM, O� Valve,Wing,WKM, Valve,Wng,SSV, 3 1/8 5M FE,HWO r VG-M,3 1/8 5M FE .... o 3 1/8 5M FE, HWO 6--�® Qty 2 w/Halliburton -, Hydraulic operator ni 21/1Valve,MinFE HWO (o)® • ® I�I�119(°)+9 O ill1 65 ®� I�6 0 ® I \ 0 to Valve,upper master, 5„,,®ro�,' WKM,31/85MFE, 01-(19 HWO M s Valve,master,WKM, 0 0 3 1/8 5M FE, HWO E.'S,'o1 -- 18-6-40®m® imoi Adapter,CIW-FBB,7 1/16 5M min stdd X 3 1/8 5M stdd top,w/'A ',il; npt control line exit Tbg head,Cameron-N, �� ---7-- '�� 11 5M X 7 1/16"5M, :,J i i 1 �!u= w/2-21/165MSSO Ili 111 9 III[® / -,II� rw■ .:.. , , (.) I'I[ol / ]11 'wl... 2 1/16 5MIve WKM FE,HWO,Qty 2 lei in Casing head,Shaffer KD, 11 5M X 10 3/4 SOW,w/ 1111 IIIIm 2-2"LPO,7 5/8"KD slips III ' I and packoff assy in head S.- 0 • inii m1010.i Valve,McEvoy-C,2"LPO �j II Swanson River SRU 24-33 09/10/2012 Swanson River Tubing hanger, Shaffer T55- SRU 24-33 AJ,9 X 3 1/2 EUE 8rd lift and 103/4X75/8X31/2 3'IEUE 8rd susp,w/3" Cosasco BPV profile Existing wellhead/tree schematic. Note:The tubing head will be replaced with a 7- 1/16"5Mxll"5M. Mill ill I Valve upper master, PIMP( WKM-M 3 1/8 5M FE, 1.7,4) HWO,AA A ,r Valve lower master, O^` WKM-M 3 1/8 5M FE, E. OP% •)...... HWO,AA Adapter, Shaffer-AJ, Tubing head, Shaffer 9 5M stdd X 3 1/8 5M T55-LI, 11 5M X -.� 9 5M w/2-3 1/8 5M SSO, :Iiii lir:7 5/8"Type 1 secondary Iii , IllValve,WKM M , 3 1/8 5M seal in head �� FE, HWO, 4 �./o -I i I44)® -11 i Qty o , o -- [ 1. Casing head, Shaffer KD, 115MX103/4SOW,w/ 111 111 2-2" LPO, 7 5/8" KD slips I ® Valve, Gate, McEvoy C, and packoff assy in head ® �® 2" LPO III ON ©(9.j�llIV E 0 0 0 Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Monday, October 01, 2012 4:00 PM To: Luke Keller Cc: Schwartz, Guy L (DOA); Fisher, Samantha J (DOA); dduffy@hilcorp.com; Ferguson, Victoria L (DOA) Subject: RE: SCU 44-33 APD Luke, Legal won't be able to review the draft SCU 44-33 exception until later this week. I'll keep you informed. Thanks, Steve Davies AOGCC From: Ferguson, Victoria L (DOA) Sent: Friday, September 28, 2012 1:41 PM To: Luke Keller Cc: Schwartz, Guy L (DOA); Davies, Stephen F (DOA); Fisher, Samantha J (DOA); dduffv@ hilcorp.com Subject: RE: SCU 44-33 APD Luke, The spacing exception administrative approval conservation order is being reviewed internally by Legal. We will update you on the status on Monday, Oct 1, 2012. Thanx, Victoria Victoria Ferguson Senior Petroleum Engineer State of Alaska Oil&Gas Conservation Commission 333 W.7th Ave, Ste 100 Anchorage,AK 99501 Work (907)793-1247 victoria.ferguson a(2alaska.gov From: Luke Keller [mailto:lkeller©hilcorp.com] Sent: Friday, September 28, 2012 12:56 PM To: Schwartz, Guy L (DOA); Ferguson, Victoria L (DOA); Paul Mazzolini; Stephanie Klemmer Subject: SCU 44-33 APD Guy/Victoria, Just wanted to follow up on the SCU 44-33 APD (Sidetrack of SRU 24-33). We were planning on moving the Arctic Fox onto the well next week, but still have not received the approved APD from the AOGCC. There was evidently some miscommunication and a courier was sent over today, but was told the well had not been approved yet. 1 Is there anything the AOGCC requires trom Hilcorp? Let us know if there is anything we can do to expedite approval. The last communication you and I had on the matter is attached below. Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent: Thursday, September 20, 2012 9:46 AM To: Luke Keller Subject: RE: Hilcorp Drilling Permits Luke. HV-15 and HV-16 were mailed a week ago. SRU 44-33 should be approved any day.. Commissioners have it. Guy Schwartz Senior Petroleum Engineer AOGCC 793-1226 (office) 444-3433 (cell) From: Luke Keller[mailto:lkeller@hilcorp.com] Sent: Thursday, September 20, 2012 9:22 AM To: Schwartz, Guy L (DOA); Davies, Stephen F (DOA); Stephanie Klemmer; Paul Mazzolini Subject: Hilcorp Drilling Permits Guy/Steve, Just wanted to check on status of a few drilling permits we currently have submitted, but have not received approvals on. 1. HV B-15: Anticipated start date of 10/5/2012 2. HV B-16: Anticipated start date of 10/25/2012 3. SCU 44-33: Anticipated start date of 10/1/2012 Let me know if there is anything the AOGCC is waiting on from Hilcorp before granting approvals. Thank you. Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 2 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 NAME4-;/�es C<< ere_e_L. a2 PTD# 2/2-- /(13 / Development Service Exploratory Stratigraphic Test Non-Conventional Well FIELD: t.1--j---1-71-1 <17/v-c--crPOOL: 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 sutect to full compliance with 20 AAC EXCEPTION 25.055. Approval to roduce)'inject is contingent upon issuance of a c.opse7ation approving a spacing exception. t ( assumes the liability of any protest to the spa64ng exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non-Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. Rev:9/09/2011 To v) a) c)- N N a) `o m z c • Q ; 6 a v: al E 0 E y , , o: , , .y a o w, a) of -' a E 3 ' -•, I v a. a ofvi a)' rn o O. N: CIS' • Q ;o gyp: N: a: 0, l0 U. o, .O .. o y: a ': : 3: p : • 3, Ja 1—, N o L_ (0 y N' 3' 3' E c, 0: co � �, : a , o, C: . H Q! M a .E �: �: ° - m; °: °: > > O: o: v 0 E 3 a m: , 0 3, 2, ..0 o: 1N: . , w (N, - U O O O ' M� C. 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To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. SWANSON RIVER FIELD SCU 44-33 Kenai Borough, Alaska FINAL WELL REPORT MUDLOGGING DAT A Provided by: Approved by: Kevin Eastham Compiled by: Larry Resch Dan Hillegeist Dan Grunwald Distribution: 11/14/2012 T.D. Date: 10/25/2012 SCU 44-33 1 TABLE OF CONTENTS 1 MUDLOGGING EQUIPMENT & CREW .............................................................................................. 2 1.1 Equipment Summary .................................................................................................................... 2 1.2 Crew ............................................................................................................................................. 2 2 WELL DETAILS ................................................................................................................................... 3 2.1 Well Summary .............................................................................................................................. 3 2.2 Hole Data...................................................................................................................................... 3 2.3 Well Synopsis ............................................................................................................................... 3 2.4 Daily Activity Summary ................................................................................................................. 4 3 GEOLOGICAL DATA ......................................................................................................................... 10 3.1 Lithostratigraphy ......................................................................................................................... 10 3.2 Stratigraphic Summary ............................................................................................................... 11 3.3 Lithologic Details ........................................................................................................................ 23 3.4 Connection Gases ...................................................................................................................... 30 3.5 Sampling Program / Sample Dispatch ........................................................................................ 31 4 PRESSURE / FORMATION STRENGTH DATA ................................................................................ 32 4.1 Pore pressure evaluation ........................................................................................................... 32 5 DRILLING DATA ................................................................................................................................ 33 5.1 Directional Survey Data .............................................................................................................. 33 5.2 Bit Record ................................................................................................................................... 35 5.3 Mud Record ................................................................................................................................ 36 6 DAILY REPORTS .............................................................................................................................. 38 7 SHOW REPORTS ............................................................................................................................. 62 Enclosures: 2”/100’ Formation Log (MD/TVD) 2”/100’ Drilling Dynamics Log (MD/TVD) 2”/100’ LWD / Lithology Log (MD/TVD) 2”/100’ Gas Ratio Log (MD/TVD) Final Data CD SCU 44-33 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 Fl ow 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 System Failure All Data Several system wide failures from 30 minutes to 4 hours or more. 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 27 Daniel Hillegeist 1 22 Daniel Grunwald 4 12 Jessiah Johnson 1 18 Daniel Hillegeist 1 14 Steve Franzen 3 7 *1 Years experience as Mudlogger *2 Days at wellsite between spud and total depth of well SCU 44-33 3 2 WELL DETAILS 2.1 Well Summary Well: SCU 44-33 API Index #: 50-133-20237-01-00 Field: Swanson River Field Surface Co- Ordinates: 876’ FNL, 2127’ FWL, Sec. 4, T7N, R9W, SM County: Kenai Peninsula Borough Primary Target Depth: Hemlock Formation 12077’MD/ 10589’TVD State: Alaska TD Depth: 12425’MD/ 10746’TVD Rig Name / Type: Arctic Fox/ Double Suspension Date: (N/A) Primary Target: Hemlock Formation License: ADL 212143 Spud Date: October 11, 2012 Ground Elevation: 164.6’ AMSL Completion Status: Run 4-1/2” casing RKB Elevation: 183.2’ AMSL Classification: Development Secondary Target: Depth: Lower Tyonek Formation 11436’MD/ 10228’TVD TD Formation: Hemlock Formation TD Date: October 25, 2012 Days Drilling: 15 Days Testing: 0 2.2 Hole Data Hole Section Maximum Depth TD Formation Mud Weight (ppg) Dev. (oinc) Casing/ Liner Shoe Depth LOT (ppg) MD (ft) TVDSS (ft) MD (ft) TVDSS (ft) 7-5/8” Cased Hole 9019 -8784 Tyonek 9.2 26 whipstock in 7-5/8” casing 9015 -8963 12.8 6-1/8” 12425 -10565 Hemlock 11.4 66 4-1/2” 12423 -10563 N/A 2.3 Well Synopsis SCU 44-33 was drilled as a deviated well designed to target stranded oil in the Hemlock Formation. A whipstock was seated at 9019’MD inside the existing 7-5/8” casing from the abandoned SCU 24-33 wellbore. Drilling commenced with a planned build of 6 o/100ft up to a 70o inclination toward the northeast and holding 70o to total depth. Anticipated exploitation includes running a 4½” liner and utilizing a 3½” gas lift completion. Upon milling out a window in the casing, the formation pressures were higher than anticipated. Trip gases were consistently high (>3000 units), and despite raising the mud weight several times, flow checks often revealed gas influx into the well. Evaluation of connection gasses, wiper trip gasses and trip gasses indicate unusually high gas influx from the 9000’MD to 9100’MD horizon. Drilling was otherwise typical of the ash- rich sediments of the Cook Inlet Basin, steady through the Tyonek and uppermost Hemlock Formations, then extremely slow in the conglomerates and well indurated tuff and tuffaceous clays of the Hemlock Formation. SCU 44-33 4 2.4 Daily Activity Summary October 9, 2012 Load drill pipe in pipe shed; pick up BHA for clean -out run; pick up drill pipe and run in hole from 567 ft to 9123 ft; circulate bottoms-up and pump high viscosity sweep; monitor well - static; begin tripping out of hole - fluid returns; circulate to balance fluid; pull out of hole from 9123 ft to 8528 ft; service rig; miscellaneous mudlogging activity - arrive at wellsite and rig up mudlogging equipment.. October 10, 2012 Continue pulling out of hole from 8528 ft to 567 ft; monitor well - static; stand back 9 stands heavyweight drill pipe and lay down cleanout BHA; clean rig and install wind walls on rig floor and pits; rig up wireline and run in hole with bridge plug; set bridge plug at 9038', pull out of hole with wireline, and rig down wireline; load whipstock BHA in pipe shed and rig up high pressure lines; pressure test casing to 2100 psi for 30 minut es, and rig down pressure testing equipment; make up upper and lower string mills, laying down same in pipe shed, and make up MWD tools and float sub, racking back on heavyweight drill pipe in derrick; rig up wireline and run in hole with second bridge plu g; set bridge plug at 9034 ft and rig down wireline; pick up BHA with whipstock. October 11, 2012 Run in hole with whipstock, mills, and MWD tool; make up orienting sub and orient MWD tool; run in hole with 9 stands heavyweight drill pipe; run in hole with 4" drill pipe from 649 ft to 8987 ft; orient whipstock at 080 degrees, tag bridge plug at 9019 ft, and set whipstock with top at 9001.15 ft; displace production fluid with 9.5 ppg drilling mud; mill window in casing from 9001 ft to 9015 ft MD / 8963 ft T VD, 211 units gas maximum; monitor well - flowing at 8 to 9 bbl/hr; shut in well at 19:50 hours, SICP 1270 psi, SIDPP 1220 psi; weight up mud to 10.2 ppg and pump 7800 strokes kill mud at 3 bbl/min - 30 bbl gain; open choke fully and circulate at 4.5 bbl/min, maximum gas 719 units; miscellaneous mudlogging activity - mount secondary gas trap. October 12, 2012 Continue to circulate 10.2 ppg mud - 10.0 ppg mud weight out obtained; open rams and monitor well - slight flow; shut in well - SICP 840 psi, SIDPP 890 psi; weight up mud to 10.7 ppg and circulate at 121 gal/min - FSICP654 psi; open rams and circulate bottoms-up - maximum gas 424 units; monitor well - slight flow; shut in well - SICP 520 psi, SIDPP 580 psi; open rams - flowing at 3.6 bbl/hr; weight up mud to 10.9 ppg and circulate - maximum gas 1173 units; monitor well - slight flow; shut in well - SICP 450 psi, SIDPP 500 psi; open rams, blow down choke manifold, and mill/drill ahead from 9015 ft - 1292 units bottoms-up gas; monitor well - flowing at ~3 bbl/hr; continue to mill/drill ahead to 9035 ft; monitor well and polish window - flowing at ~3 bbl/hr; perform formation integrity test to 12.0 ppg EMW; blow down choke manifold and high pressure lines; build mud weight up to 11.1 ppg and circulate - maximum gas 2257 units; record slow pump rates and monitor well. October 13, 2012 Weight up drilling mud from 11.1 ppg to 11.3 ppg and displace well fluid with same - maximum gas 1639 units; monitor well - flowing at 2.4 bbl/hr; circulate bottoms-up - maximum gas 536 units; monitor well - flowing at 2.4 bbl/hr; weight up drilling mud to 11.6 ppg and displace well fluid with same - maximum gas 1869 units; monitor well - flowing at 1.8 bbl/hr; circulate bottoms-up - maximum gas 1399 units; perform leak- off test at 8998 ft MD/8963 ft TVD to 12.8 ppg EMW; circulate bottoms -up - maximum gas 784 units; monitor well - flowing at 1/2 bbl/hr; pull out of hole from 8998 ft to 7546 ft and monitor well - flowing at 1/2 bbl/hr; pull out of hole from 7546 ft to 5000 ft and monitor well - flowing at 1/2 bbl/hr; pull out of hole from 5000 ft to 631 ft and monitor well - flowing at 2.7 bbl/hr; pull out of hole from 631 ft to 104 ft and lay down BHA; pick up drilling BHA. SCU 44-33 5 SCU 44-33 6 October 14, 2012 Continue picking up BHA #3, shallow test MWD tools; run in hole from 200 ft to 777 ft with heavyweight drill pipe; run in hole from 777 ft to 8990 ft, filling pipe every 30 stands; circulate bottoms -up - maximum gas 3294 units; orient tool to 080 degrees and slide drill from 9035 ft to 9050 f t; troubleshoot top drive electronics and monitor well - flowing at 1.6 bbl/hr, 1672 units down time gas when drilling resumes; slide drill ahead from 9050 ft to 9185 ft as of midnight. October 15, 2012 Drill ahead from 9185 ft to 9530 ft, sliding as nece ssary to steer and build angle and pumping sweeps at 9241 ft and at 9360 ft to counter clay balling on bit. October 16, 2012 Drill ahead from 9530 ft to 9832 ft, sliding as necessary to steer and build angle; monitor well - flowing at 2.8 bbl/hr; circulate bottom sup - maximum gas 2019 units; pull out of hole from 9832 ft to 8548 ft - 0.7 bbl under correct displacement; monitor well - flowing at 3.5 bbl/hr; run in hole from 8548 ft to 9832 ft and circulate bottoms-up - maximum gas 3572 units; prepare to we ight up to 11.9 ppg. October 17, 2012 Monitor well pressure while building 11.9 ppg mud - SIDPP 450 psi, SICP 430 psi; circulate out gas at 3 bbl/min - maximum gas 331 units; pump 11.9 ppg mud at 4 bbl/min; monitor well - flowing; shut in well and monitor pressure - SIDPP 310 psi, SICP 290 psi; perform FIT to 14.0 ppg equivalent mud weight; pull out of hole from 9832 ft to 9052 ft; weight up mud system above window to 12.2 ppg - maximum gas 604 units; monitor well - flowing; shut in well and monitor pressu re while building 12.5 ppg mud - SIDPP 8 psi, SICP 35 psi; pump 12.5 ppg mud at 3 bbl/min - maximum gas 146 units; monitor well - static; circulate and condition mud at 3 bbl/min while slipping and cutting 75' of drill line; blow down choke and kill lines and pull out of hole from 9052 ft to 8800 ft; pump dry job and pull out of hole from 8800 ft to 7336 ft as of midnight. October 18, 2012 Continue to pull out of hole from 7336 ft to 5095 ft; monitor well - flowing at 1.2 bbl/hr; pull out of hole from 5095 ft to 777 ft; monitor well - flowing at 1/2 bbl/hour; pull out of hole from 777 ft and lay down BHA, racking back heavyweight drill pipe, drill collars and tools; test BOP stack and service top drive; monitor well - flowing at 1.2 bbl/hr; rig down test equipment, blow down choke and high pressure lines, and clear rig floor; pick up bit #2 and motor and run in hole with tools; shallow test MWD tools and run in hole with heavyweight drill pipe to 784 ft; pick up 4" drill pipe and run in hole to 1813 ft as of midnight. October 19, 2012 Continue to pick up 4" drill pipe and run in hole from 1726 ft to 2354 ft, then run in hole with drill pipe from derrick from 2354 ft to 8990 ft; circulate bottoms -up - maximum gas 2263 units; displace weighted fluid in casing with 11.9 ppg mud; run in hole from 9085 ft to 9809 ft, working through tight hole at 9595 ft and tagging bottom at 9834 ft; drill ahead from 9834 ft to 9998 ft as of midnight, sliding as necessary to steer and build angle - 3048 units trip gas on bottoms-up. October 20, 2012 Continue to drill ahead from 9998' to 10565'. Stand back one stand to 10504' for top drive repairs. Drill ahead 10565' to 10580'. October 21, 2012 Continue to drill ahead from 10580' to 11175'. Repaired top drive. Drilled from 11175' to 11295' then repaired top drive. Drilled from 11295' to 11379'. Circulating bottoms up and preparing for short trip. The connection gasses have been arriving on time from bottom of hole . SCU 44-33 7 October 22, 2012 Circulated bottoms up from 11379’ and monitore d well. Repaired top drive and weighted up mud from 11.4 to 11.6 lbs. Circulated bottoms up, 3760u gas, then drilled to 11592'. Bottoms up gasses are arriving on time. October 23, 2012 Continue to drill ahead from 11592'. TOTCO repaired while drilling. Co ntinued to drill ahead to 11910'. Connection gas continues to come in early. October 24, 2012 Continue to drill ahead from 11910' to 12072'. Short wiper trip to 11,300'. Drilled ahead from 12072' to 12316'. October 25, 2012 Drilled ahead from 12316' to 12425' TD. Circulated 2x bottoms up, then back reamed out to 11,170'. Started pulling out of hole from 11,170' to window then displaced mud with 12.5 mud then started pulling out of hole. Continue to pull out of hole as of 23:59. October 26, 2012 Laid down BHA. Tested annular and upper rams. Picked up BHA with new motor and old MX -R18DX motor, ran into hole to 8963'. Circulating out 12.5 lb mud cap, displacing it with 11.4 lb mud. October 27, 2012 Displaced 12.5 lb mud with 11.5 mud. Ran into hole from 902 2' to 10980'. Circulated bottoms up and recorded 3750 units of gas. Circulated gas out of mud and then ran to TD. Currently running sonic tool, MAD pass at 400' per hour to 11985'. October 28, 2012 Completed MAD pass from 10728' to 9594'. Circulated botto ms up, max gas 739 units. Pulled out of hole to 9083' and displaced mud from 11.4 lb to 12.6 lb mud cap. Pulled out of hole from 9083' to 957'. Laying Down BHA presently. October 29, 2012 Laid down BHA then rigged up to run 4.5" liner to 8026' and circula ted bottoms up, yielding 898 units of gas. Running in hole to 8400'. October 30, 2012 Continue to run 4.5" liner into hole from 8400' to 10227'. Circulated 3890 units gas out of hole. Continue to run in hole to 12360'. Circulated 2200 units of gas out of hole. Continued to run in hole to 12425'. Circulate to find possible washout. Carbide returns indicated washout at 700'. Pulled out of hole to 11158' but no washout found. Second carbide bomb dropped. Circulating and waiting for carbide returns. October 31, 2012 Continue to circulate out second carbide bomb at 11149' (failed). Shut in and pressured up annulus to 200 PSI on annulus and no flow back observed through the drill string. Pressured to 400 PSI and no flow back observed. Pump 40 barrel sweep/walnut flag, sweep returned at 9356 strokes (9113 strokes calculated), with 3365 units gas maximum. Run in hole from 11149' to 12407' and circulate bottoms up, with 3487 units of gas maximum. Run cement into hole. Bumped plug with 1450 PSI with 100% returns. Set hanger and circulate cement out, with 10 barrels cement returns to surface. Tripping out of hole.\ November 01, 2012 SCU 44-33 8 Continue to pull out of hole from 7083’ to 6585’. Observed gain in trip tank. Flowing 4.8 barrels per hour with a maximum of 394 units of gas. Run in hole with 4” drill pipe from 6585’ to 8730’ and circulate. Shut annular , open choke and monitor the pressure. Weight up mud and circulate 12.5 lb mud. Monitor well. Pulled out of hole to surface. Testing BOPs SCU 44-33 9 November 02, 2012 Test BOPs. Pick up polishing mill and 7 5/8" casing scraper then run into the hole to 8707'. Circulated bottoms up and got a maximum of 3442 units of gas. Ran polishing mill from 8767' to top of dressing mill. Continue wipe and polish of upper 8' of sealbore with 10RPM. Circulate and condition until mud reached 12.5 lb weight. Monitor well - ok, prepare to pull out of hole . November 03, 2012 Pull out of hole from 8769' to surface and lay down polishing mill. Run into hole with seal assembly to top of liner at 8777'. Stab into hanger and run test. Pressure up to 2100 PSI for 15 minutes. Displace well from 12.5 lb mud to 11.5 lb mud then rerun test. Good at 2100 PSI for 30 minutes. Pump dry job and pull out of hole to 8322'. SCU 44-33 10 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 9020 8969 -8785 9001 8950 -8767 Tyonek G1 11369 10180 -9996 11318 10177 -9993 Tyonek G2 11436 10228 -10044 11377 10208 -10024 Hemlock Formation 11584 10298 -10114 11519 10284 -10100 Hemlock H2 11604 10329 -10145 Hemlock H3 11690 10368 -10184 11664 10361 -10177 Hemlock H4 11706 10383 -10199 Hemlock H5 11735 10398 -10214 Hemlock H6 11821 10443 -10259 Hemlock H7 11896 10484 -10300 11857 10462 -10278 Hemlock H10 12077 10589 -10405 12013 10542 -10358 Hemlock H11 12308 10717 -10533 12208 10641 -10457 TD 12400 10764 -10580 12425 10748 -10564 SCU 44-33 11 3.2 Stratigraphic Summary Kick-Off Point to top of Tyonek G1ST Depth of Interval: 9015’ to 11318' MD (-8781' to -9993' SSTVD) Drilled Footage: 2303’MD, 208’TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 212 < 1 59.1 1766 1 87 Gas Peaks Depth Total Gas C1 C2 C3 iC4 nC4 iC5 nC5 9300 273 54652 9 2 0 0 0 0 9342 198 35794 93 30 0 0 0 0 9498 218 43763 66 18 0 0 0 0 9559 197 43244 81 27 0 0 0 0 9726 183 36711 94 30 0 0 0 0 10009 365 71788 124 32 0 0 0 0 10060 376 74033 140 22 0 0 0 0 10432 153 26204 87 27 0 0 0 0 10503 699 124066 300 60 0 0 0 0 10640 417 79733 146 0 0 0 0 0 10651 240 45908 85 0 0 0 0 0 10982 204 42839 102 0 0 0 0 0 11208 482 91913 328 0 0 0 0 0 11255 366 69879 237 0 0 0 0 0 11300 224 41469 400 53 0 0 0 0 11317 261 46615 1118 191 0 0 0 0 Interval Lithologic Percentages Lithology Percentage Lithology Percentage Sand 19.4 Tuffaceous Claystone 19.5 Sandstone 2.8 Tuff 0.5 Conglomeratic Sand 2.0 Carbonaceous Shale 3.2 Conglomerate 0.5 Coal 0.5 Tuffaceous Sandstone 34.7 Carbonaceous Material 0.8 Tuffaceous Siltstone 16.2 SCU 44-33 12 Tyonek G1ST Depth of Interval: 11318’ to 11377' MD (-9993' to -10024' SSTVD) Drilled Footage: 59’MD, 31’TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 224 4 83.3 455 88 128 Gas Peaks Depth Total Gas C1 C2 C3 iC4 nC4 iC5 nC5 11334 148 23218 914 166 0 0 0 0 11335 124 19581 758 139 0 0 0 0 11345 163 26001 838 183 6 0 0 0 Interval Lithologic Percentages Lithology Percentage Lithology Percentage Sand 3.3 Tuffaceous Claystone 7.5 Sandstone Tuff Conglomeratic Sand Carbonaceous Shale 10.0 Conglomerate Coal 0.8 Tuffaceous Sandstone 42.5 Carbonaceous Material Tuffaceous Siltstone 35.8 SCU 44-33 13 Tyonek G2ST Depth of Interval: 11377’ to 11519' MD (-10024' to -10100' SSTVD) Drilled Footage: 142’MD, 76’TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 261 3.3 95 499 82 153 Gas Peaks Depth T otal Gas C1 C2 C3 iC4 nC4 iC5 nC5 11388 453 80655 761 504 80 0 0 0 11398 220 39312 297 220 36 0 0 0 11512 500 87766 1501 1437 271 0 7 17 Interval Lithologic Percentages Lithology Percentage Lithology Percentage Sand 55.7 Tuffaceous Claystone 0.8 Sandstone Tuff Conglomeratic Sand Carbonaceous Shale 8.2 Conglomerate Coal 0.8 Tuffaceous Sandstone 32.8 Carbonaceous Material 1.6 Tuffaceous Siltstone SCU 44-33 14 Hemlock Formation to top of H2ST Depth of Interval: 11519’ to 11604' MD (-10100' to -10145' SSTVD) Drilled Footage: 85’MD, 45’TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 88 <1 25 516 107 135 Gas Peaks Depth Total Gas C1 C2 C3 iC4 nC4 iC5 nC5 11575 517 99457 313 241 28 0 0 0 11595 201 37036 129 72 0 0 0 0 Interval Lithologic Percentages Lithology Percentage Lithology Percentage Sand 30.0 Tuffaceous Claystone Sandstone Tuff Conglomeratic Sand 2.5 Carbonaceous Shale 27.5 Conglomerate Coal 7.5 Tuffaceous Sandstone 30.0 Carbonaceous Material 2.5 Tuffaceous Siltstone SCU 44-33 15 Hemlock H2ST Depth of Interval: 11604’ to 11664' MD (-10145' to -10177' SSTVD) Drilled Footage: 60’MD, 32’TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 137 7 17 265 93 64 Gas Peaks Depth Total Gas C1 C2 C3 iC4 nC4 iC5 nC5 11648 205 42951 546 399 67 0 1 0 11650 186 39090 460 343 59 0 1 0 11662 221 4732 294 275 55 0 8 0 11664 265 52522 279 280 59 0 11 0 Interval Lithologic Percentages Lithology Percentage Lithology Percentage Sand 25.7 Tuffaceous Claystone 12.9 Sandstone 7.1 Tuff 1.4 Conglomeratic Sand Carbonaceous Shale 11.4 Conglomerate Coal Tuffaceous Sandstone 34.3 Carbonaceous Material Tuffaceous Siltstone 7.1 SCU 44-33 16 Hemlock H3ST Depth of Interval: 11664’ to 11706' MD (-10177' to 10199' SSTVD) Drilled Footage: 42’MD, 22’TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 90 1 26 423 84 120 Gas Peaks Depth Total Gas C1 C2 C3 iC4 nC4 iC5 nC5 11665 423 83775 441 442 94 0 17 0 Interval Lithologic Percentages Lithology Percentage Lithology Percentage Sand 34.6 Tuffaceous Claystone Sandstone 9.6 Tuff 5.8 Conglomeratic Sand Carbonaceous Shale 3.8 Conglomerate Coal Tuffaceous Sandstone 42.3 Carbonaceous Material 3.8 Tuffaceous Siltstone SCU 44-33 17 Hemlock H4ST Depth of Interval: 11706’ to 11735' MD (-10199' to -10214' SSTVD) Drilled Footage: 29’MD, 15’TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 35 1 13.2 149 93 108 Gas Peaks Depth Total Gas C1 C2 C3 iC4 nC4 iC5 nC5 11707 145 28876 86 91 146 0 0 0 Interval Lithologic Percentages Lithology Percentage Lithology Percentage Sand 8.3 Tuffaceous Claystone 50.0 Sandstone 5.0 Tuff 6.7 Conglomeratic Sand 3.3 Carbonaceous Shale Conglomerate 3.3 Coal Tuffaceous Sandstone 23.3 Carbonaceous Material Tuffaceous Siltstone SCU 44-33 18 Hemlock H5ST Depth of Interval: 11735’ to 11812' MD (-10214' to -10259' SSTVD) Drilled Footage: 77’MD, 45’TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 110 2.5 23.9 209 93 115 Gas Peaks Depth Total Gas C1 C2 C3 iC4 nC4 iC5 nC5 11739 119 22579 193 198 39 0 0 0 11762 127 25191 98 79 3 0 0 0 11814 209 32540 1695 908 87 0 13 10 Interval Lithologic Percentages Lithology Percentage Lithology Percentage Sand 34.8 Tuffaceous Claystone 33.7 Sandstone 1.1 Tuff 7.9 Conglomeratic Sand 2.2 Carbonaceous Shale Conglomerate 1.1 Coal Tuffaceous Sandstone 13.5 Carbonaceous Material Tuffaceous Siltstone 5.6 SCU 44-33 19 Hemlock H6ST Depth of Interval: 11821’ to 11857' MD (-10259' to -10278' SSTVD) Drilled Footage: 36’MD, 19’TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 97 16 43 421 113 154 Gas Peaks Depth Total Gas C1 C2 C3 iC4 nC4 iC5 nC5 11823 188 29767 1377 761 77 0 11 8 11824 186 29483 1345 747 76 0 11 8 Interval Lithologic Percentages Lithology Percentage Lithology Percentage Sand 15.0 Tuffaceous Claystone 3.8 Sandstone Tuff Conglomeratic Sand Carbonaceous Shale 2.5 Conglomerate Coal Tuffaceous Sandstone 37.5 Carbonaceous Material Tuffaceous Siltstone 41.3 SCU 44-33 20 Hemlock H7ST Depth of Interval: 11857’ to 12013' MD (-10278' to -10358' SSTVD) Drilled Footage: 156’MD, 80’TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 93 <1 35 751 104 159 Gas Peaks Depth Total Gas C1 C2 C3 iC4 nC4 iC5 nC5 11857 119 19960 517 348 46 0 7 2 11870 182 31338 587 458 70 0 11 2 11881 230 40270 520 494 87 0 15 1 11889 751 137189 1455 1588 303 0 56 6 11909 256 45797 569 632 130 0 34 16 12012 146 25655 293 292 59 0 3 5 Interval Lithologic Percentages Lithology Percentage Lithology Percentage Sand 16.9 Tuffaceous Claystone 19.4 Sandstone Tuff 4.4 Conglomeratic Sand Carbonaceous Shale 1.9 Conglomerate Coal Tuffaceous Sandstone 41.9 Carbonaceous Material Tuffaceous Siltstone 15.6 SCU 44-33 21 Hemlock H10ST Depth of Interval: 12013’ to 12208' MD (-10358' to -10457' SSTVD) Drilled Footage: 195’MD, 99’TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 146 <1 33.7 448 87 140 Gas Peaks Depth Total Gas C1 C2 C3 iC4 nC4 iC5 nC5 12048 191 29475 1290 955 135 0 28 39 12135 250 42232 549 591 107 0 0 0 12147 209 31001 772 783 146 0 25 50 12151 256 39046 841 852 157 0 23 45 12201 449 72571 1425 1525 302 0 48 45 Interval Lithologic Percentages Lithology Percentage Lithology Percentage Sand 68.0 Tuffaceous Claystone 2.0 Sandstone 5.0 Tuff Conglomeratic Sand 5.5 Carbonaceous Shale 1.5 Conglomerate Coal 1.5 Tuffaceous Sandstone 12.5 Carbonaceous Material 0.5 Tuffaceous Siltstone 3.5 SCU 44-33 22 Hemlock H11ST to TD Depth of Interval: 12208’ to 12425' MD (-10457' to -10564' SSTVD) Drilled Footage: 217’MD, 107’TVD Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 100 2 37 410 82 120 Gas Peaks Depth Total Gas C1 C2 C3 iC4 nC4 iC5 nC5 12208 148 23591 500 539 108 0 20 19 12220 194 30347 726 793 162 0 36 33 12256 144 22059 249 276 67 0 7 6 12325 150 25078 135 97 24 0 0 0 12351 169 28381 136 93 30 0 0 0 12372 156 26346 113 75 30 0 0 0 Interval Lithologic Percentages Lithology Percentage Lithology Percentage Sand 22.7 Tuffaceous Claystone 25.0 Sandstone Tuff 2.7 Conglomeratic Sand 1.4 Carbonaceous Shale 1.8 Conglomerate Coal Tuffaceous Sandstone 16.8 Carbonaceous Material Tuffaceous Siltstone 29.5 SCU 44-33 23 3.3 Lithologic Details Sand/Tuffaceous Sandstone (9015' - 9150') = samples consist of a brownish gray slurry of loose sand with alternating conglomeratic and tuffaceous intervals; the sand is a poorly sorted; very fine to coarse grained quartz sand with subordinate lithics; very light gray translucent quartz and minor flakes of black shale are subangular to subrounded while rare dark gray and pale green sil iceous lithics are subrounded to rounded; sphericity is moderate on average; quartz grain surfaces are etched and pitted; intact sandstone is matrix supported in a soft white devitrified ash; minor lenses of brittle silica cement near the base of this inte rval; no oil indicators. Tuffaceous Siltstone (9150' - 9210') = light olive gray; rounded; clayey siltstone cuttings are soft and crumbly; an earthy dull to waxy luster is underlain by a smooth silty texture; bulk samples exhibit excellent cohesion but poor to fair plasticity; cuttings of interbedded sandstones are light gray and crunchy weakly bound by abundant volcanic ash and minor silica cement; no oil stain odor fluorescence or cut. Tuffaceous Sandstone (9210' - 9300') = samples consist of a light brownish gray slurry of loose; deconsolidated sand with scattered cuttings of very soft ash matrix sandstone; the sand is moderately sorted with grain sizes ranging from lower very fine to lower medium-grained; very light gray translucent quartz comprises the bulk of the sand; accompanied by subordinate darker lithics; grains are subangular with moderate sphericity on average; sandstone is matrix supported in abundant devitrified ash; no oil indicators. Tuffaceous Sandstone/ Tuffaceous Claystone (9300' - 9360') = very light gray; light gray with yellowish brown hues grayish white; very fine to lower fine grain; subrounded to subangular; subdiscoidal; poor to moderate sorting in part; very soft to slightly firm; generally matrix supported with clays and devitr ified ash; dominantly translucent and milky quartz; occasional dark gray to grayish black lithics; note fine carbonaceous clasts flakes thin coal; note well rounded pebble fragments up to 10mm with high impact fracture; no hydrocarbon indicators. Sandstone/ Tuffaceous Sandstone (9360' - 9450') = light gray to medium light gray light gray to grayish white with slight brownish hues; bimodal: lower coarse to upper medium grain; subprismoidal to subdiscoidal; moderate to well sorted; well consolidated; hard; n oncalcareous; tight; grain supported with very little visible matrix; conglomeratic in part; note loose well rounded pebble fragments to 7mm; tuffaceous sandstone continues as above; often grading towards an arenaceous tuffaceous claystone; Tuffaceous Siltstone/ Claystone (9450' - 9540') = olive gray; rounded; amorphous to wedge like cuttings of soft clayey siltstone grading into silty claystone; cuttings display an earthy dull to waxy luster underlain by a smooth texture; bulk samples exhibit excellent cohesion and fair plasticity; trace microscopic laminae of black shale are visible in more silty cuttings; minor interbedded ash matrix quartz sandstone and matte -textured black shales; no oil stain odor or fluorescence are detectable. Tuffaceous Claystone/ Siltstone (9540' - 9600') = brownish gray; rounded wedge like to vaguely tabular cuttings are soft and pliable exhibiting good cohesion and fair to good plasticity; a dull earthy to waxy luster is underlain by a smooth texture; prominent black shale with associated fine to very fine quartz sand in abundant white ash tuff; visible degassing on shale cuttings; no oil indicators. Tuffaceous Sandstone (9600' - 9690') = very light gray to grayish white light gray often with brownish hues; upper very fine to fi ne grain; subangular to subrounded angular in part; subdiscoidal; moderate to fair sorting; loose quartz and dark gray to grayish black lithics common; generally very soft to slightly friable; very tuffaceous; often grades towards an arenaceous claystone; noncalcareous; no visible porosity; note coal carbonaceous shale; no hydrocarbon indicators. SCU 44-33 24 SCU 44-33 25 Tuffaceous Claystone (9690' - 9780') = light gray to very light gray often with brownish hues also pale yellowish brown; firm to soft very soft in part; crumbly brittle pulverulent; amorphous to occasional nodular cuttings habit; dull; subsucrosic in part with increased fine quartz and dark gray and black lithic grains; often earthy; locally abundant fine carbonaceous detrital material as clasts and spikes; note fine laminae/ bedded carbonaceous material; note increased carbonaceous shale; hard vitreous coal 9750’-9780’ sample; no hydrocarbon indicators. Tuffaceous Claystone (9780' - 9834') = light gray often with slight brownish hues pale yellowish brown; firm to soft moderately hard in part; pulverulent to crumbly; irregular cuttings habit; dull often subsucrosic with abundant silt/ sand component; rarely subwaxy; noncalcareous; becoming very sandy as a tuffaceous sandstone; note dead oil stain; no fluorescence or cut. Tuffaceous Sandstone (9834' - 9900') = rounded vaguely wedge like cuttings of light gray sandstone are crumbly to pulverulent; well sorted; fine to very fine quartz sand is bound in a soft ashy matrix; pebble chips and 10% very dim fluorescence at base of sandstone. Tuffaceous Claystone (9900' - 9930') = light olive gray cuttings exhibit excellent cohesion and good plasticity; earthy luster; and a smooth texture. Tuffaceous Sandstone (9930' - 9990') = well sorted fine to very fine quartz sand with minor to trace dark lithics are weakly bound in a soft white devitrified ash matrix; grains are subangular to subrounded with moderate sphericity overall; interbedded black shale grades to coal; no oil indicators. Tuffaceous Sandstone (9990' - 10050') = light gray to medium light gray; upper medium to very fine sand; moderate to low sphericity; angular to subrounded; moderate sorting; light gray to white tuffaceous matrix; matrix supported; interbedded shale is medium dark gray to black with trace coal. Tuffaceous Siltstone (10050' - 10140') = olive gray to medium dark gray; poor induration; platy to nodular cuttings habit; clayey to silty texture; waxy and dull luster; cohesive and curdy; interbedded shale is medium dark gray; trace coal; trace microscopic laminae of black shale; 20 % tuffaceous sandstone is light gray; upper fine to very fine grain; moderately to well sorted; subangular to subrounded with moderate sphericity overall; no oil indicators. Tuffaceous Siltstone/ Sand/ Tuffaceous Sandstone (10140' - 10230') = light gray to very light gray with brownish hues pale yellowish brown to light brownish gray; moderate cohesion; poor adhesive properties; firm soft crumbly pulverulent; no definable fracture; generally tabular curved cuttings habit; non calcareous; siltstone is very argillaceous with abundant devitrified ash; extremely fine glass shards common in ashy deposits; grades from an arenaceous tuffaceous claystone to tuffaceous sandstone with increased very fine grain translucent and vitreous quartz grains; note locally abundant loose sand and sand grains well entrained in a mushy tuffaceous matrix; no hydrocarbon indicators. Sand/ Tuffaceous Sandstone; Tuffaceous Claystone (10230' -10320') = note abundant loose sand; firm cuttings are pale yellowish brown to light olive gray in part; firm to soft; crumbly to slightly friable; no definable fracture or cuttings habit; more argillaceous cuttings appear tabular and slightly curved; loose sand is very fine well rounded to subrounded quartz grains wit h minor dark gray to grayish black clasts; sandstone is fine grain; subangular; subdiscoidal to subprismoidal; moderate to well sorted in part; often grain supported; poor visible porosity; abundant primary tuffaceous/ ash matrix and secondary clay fill; noncalcareous; no hydrocarbon indicators. SCU 44-33 26 Sand/ Tuffaceous Sandstone (10320' - 10410') = note dominant loose sand in upper part of interval; becoming consolidated in abundant devitrified ash and well entrained in mushy; ashy; sometimes earthy argillaceous sediment; dark yellowish gray to pale yellowish brown; often with light gray overtones; very fine to lower fine grain; bimodal: well rounded and spherical to subdiscoidal; subrounded to subangular in part; subdiscoidal to subprismoidal; moderate sorting; firm to sub friable; crumbly in part with increased ash/ clay content; no visible porosity; noncalcareous; no hydrocarbon indicators. Tuffaceous Siltstone (10410' - 10470') = medium dark gray; no induration; flexible tenacity; platy to nodular; clayey to silty texture; waxy to earthy luster; cohesive and pliable; curdy; 10% tuffaceous sandstone is medium gray medium gray to olive gray; mushy light gray tuffaceous matrix; trace coal. Tuffaceous Claystone (10470' - 10530') = medium gray to light olive gray; no induration; malleable to crunchy tenacity; tabular to wedge like habit; clayey texture; waxy to dull in luster; cohesive and pliable; curdy to gelatinous and mushy; lenticular bedding; trace coal; trace loose quartz sand; white; low course to upper fine; subangular to rounded; moderate sphericity; poor sorting. Tuffaceous Siltstone (10530' - 10560') = medium gray to dusky yellowish brown; crunchy to pulverulent; tabular to wedge like; dull to earthy luster; cohesive; lenticular. Tuffaceous Sandstone (10560' - 10620') = light gray to medium gray; very fine to upper fine; moderate sphericity; subrounded to rounded; well sorted; unconsolidated; tuffaceous matrix supported; 10% siltstone is medium gray; poor induration; pulverulent; lenticular bedding; tr ace coal. Tuffaceous Sandstone (10620' - 10680') = medium dark gray to olive gray; upper fine to very fine grains; moderate to high sphericity; subrounded to rounded; moderate sorting; poor consolidation; tuffaceous matrix supported; 20% tuffaceous siltstone is medium gray; malleable; tabular habit; silty to gritty; dull earthy luster; trace coal. Sand/ Tuffaceous Sandstone (10680' - 10740') = medium gray to light gray; lower medium to lower fine grains; moderate sphericity; subangular to subrounded; mode rate sorting; friable; tuffaceous matrix; grain supported; poor visual porosity and permeability; loose sand is white to light gray; upper medium to upper fine; subangular to subrounded; moderate to low sphericity. Tuffaceous Sandstone (10740' - 10800') = light gray to medium light gray; lower medium to lower fine grains; moderate sphericity; subangular to subrounded; poorly sorted; unconsolidated to very poorly consolidated; noncalcareous; tuffaceous matrix; grain supported; trace shale is brownish black; well indurated; wedge like habit; silty to gritty texture; dull to earthy luster. Sand/ Tuffaceous Sandstone (10800' - 10920') = interval varies from 30-70% loose sand; 90% upper fine; 10% lower fine grain; subangular to subrounded in part; occasionally angular; dominantly subprismoidal prismoidal common; moderate to well sorted; 80 -90% grayish white to milky white opaque to translucent quartz transparent glass-like quartz clasts common; occasional upper fine glass shards; secondary lithics include dark gray to grayish black pale yellowish brown to very pale orange translucent pale green clasts; consolidated sand appears grayish white often with grayish and light yellowish brown hues; upper fine to upper very fine grain; subrounded to subangular; subdiscoi dal to subprismoidal; fair to poor sorting in part; soft; poorly cemented; noncalcareous; dominantly matrix supported with very soft pulverulent devitrified ash; grain supported common with abundant ash/ clay fill; no visible porosity; no hydrocarbon indic ators. SCU 44-33 27 Tuffaceous Siltstone/ Tuffaceous Sandstone (10920' - 11040') = light gray very light gray all with slight yellowish brown hues; tuffaceous sandstone is grayish white; firm; crumbly pulverulent; no definable fracture; irregular to tabular cuttings habit; generally gritty abrasive with increased quartz content; cuttings rolled between fingers are pulverulent with a slightly greasy feel; generally dull earthy luster occasionally sparkly to subsucrosic; the majority of the interval consists of devitri fied ash and grades locally from a sandy/ silty claystone to a very silty/tuffaceous sandstone; noncalcareous; note varying amounts of loose sand; no hydrocarbon indicators. Tuffaceous Siltstone (11040' - 11070') - pale yellowish brown to light gray; firm crumbly; moderate induration; no definable fracture; occasional tabular cuttings with higher ash content; dull earthy luster; sub sucrosic with increased quartz grains; no apparent bedding or structure; note shaley carbonaceous detritus; no hydrocarbon indicators. Tuffaceous Sandstone/ Sand (11070' - 11160') = grayish white with light yellowish brown hues; pale yellowish brown; fine grain; subround to rounded in part; discoidal; moderate to well sorted; 60% matrix/ 40% grain supported with abundant pulver ulent devitrified ash; noncalcareous; no visible porosity; consolidated sand decreases; becoming dominantly loose sand; no hydrocarbon indicators. Tuffaceous Sandstone/ Sand (11160' - 11220') = light gray to white; low medium to low fine grains; angular to rounded; prismoidal to spherical; moderately sorted; unconsolidated; mushy tuffaceous matrix; grain supported; trace carbonaceous siltstone and coal. Tuffaceous Sandstone/ Sand (11220' - 11250') = very light gray to yellowish gray; upper medium to upper fine grain sizes; prismoidal to subdiscoidal; very angular to subrounded; unconsolidated; tuffaceous matrix; 80% grain supported 20% matrix supported; estimated visual porosity and permeability is fair to good; tuff is white; poor induration; pulverulent; trace shale and coal. Tuffaceous Siltstone (11250' - 11340') = brownish black to olive black; poor induration; pulverulent; tabular and wedge like; silty and gritty texture; dull earthy luster; trace lenticular bedding; 40% tuffaceous sandstone; medium light gray to medium dark gray; very fine grains; moderate sphericity; subrounded to rounded; well sorted; friable; tuffaceous matrix; grain supported; trace shale. Tuffaceous Sandstone (11340' - 11370') = light gray to medium gray; very fine grains; moderate sphericity; subrounded to rounded; well sorted; friable; tuffaceous matrix; grain supported; tuffaceous siltstone; olive gray to grayish brown; pulverulent; tabular to wedge like habit. Sand/ Tuffaceous Sandstone (11370' - 11460') = samples vary from 40-70% loose fine to lower medium grain sand; subangular to subrounded angular in part; dominantly subprismoidal; fair sorting; predominantly milky white translucent matte and transparent quartz with abundant volcanic glass clasts; sandstone varies from grayish white to pale yellowish brown; generally matrix supported with devitrified ash; note occasional clean grain supported sandstone with abundant biotite; calcareous; NOTE RARE BLACK TO VERY DARK BROWN OIL STAIN; NO ODOR 40-80% DULL YELLOW FLUORESCENCE NO SOLVENT REACTION Sand/ Tuffaceous Sandstone (11460' - 11520') = light gray; low medium to upper fine grains; subangular to subrounded; subprismoidal to subdiscoidal; moderate sorting; unconsolidated; tuffaceous matrix; grain supported; good estimated porosity and permeability; 5% shale is brownish gray to brownish black; LIGHT OIL STAINS 50% TO 70% DULL YELLOW FLUORESCENCE MILKY YELLOW BLOOM CUT. SCU 44-33 28 Tuffaceous Sandstone (11540' - 11580') very light gray to yellowish gray; moderate sphericity; angular to subangular; moderate sorting; poorly consolidated; shale is medium gray to medium dark gray; very hard; massive habit; gritty to granular; luster is earthy to frosty; NO VISIBLE OIL; 70% TO 80% DULL FLUORESCENCE OBSERVED; NO ODOR; NO VISIBLE STAIN PRESENT; SOLVENT CUT DISPLAYED LIGHT MILKY FLUORESCENCE; NO VISIBLE CUT; MILKY YELLOW FLUORESCENT RESIDUE CUT MOVED OUT FROM SAMPLE QUICKLY; NO VISIBLE RESIDUE. Sand/ Tuff/ Tuffaceous Claystone (11610' - 11700') = note significant fine coal cavings in sample interval; top interval is loose sand; fine to medium grain becoming medium to lower coarse grain; subangular to angular in part occasionally subrounded; subprismoidal; poor to fair sorting; intermediate interval is sand and carbonaceous detrital clasts and fla kes well entrained in ash and tuff; bottom of interval is dominantly ash devitrified ash tuff tuffaceous sand; soft; poorly indurated cuttings contain glass shards carbonaceous detritus black streaks; < 20% YELLOWISH BROWN OIL STAIN; VERY SLIGHT HYDROCARBON ODOR; 30-60% PINPOINT BRIGHT YELLOW SAMPLE FLUORESCENCE; NO VISIBLE OR FLUORESCENT CUT; IMMEDIATE BLUISH WHITE CUT RING; VERY LIGHT STRAW VISIBLE RESIDUE RING. Sand/ Tuff/ Tuffaceous Claystone (11700' - 11780') = interval a/a; NO STAIN; NO ODOR; 30% BRIGHT YELLOW FLUORESCENCE; IMMEDIATE BLUISH WHITE CUT FOLLOWED BY THIN WHITE STREAMERS; BLUISH WHITE FLUORESCENT RESIDUE RING; DOWN INTERVAL BECOMES 25% AMBER STAIN; SLIGHT ODOR; 60-90% YELLOW TO GOLD FLUORESCENCE; SLOW MILKY YELLOW GLOBULAR FLUORESCENT CUT; NON-VISIBLE TO BRIGHT BLUISH WHITE FLUORESCENCE RESIDUE RING. Sand/ Tuffaceous Claystone/ Tuff (11780' - 11810') = white to yellow gray; poor induration; wedge like habit; smooth and clayey; greasy and waxy luster; pasty and mushy; 70% DULL YELLOW FLUORESCENCE; MILKY YELLOW FLUORESCENT CUT; BLUISH WHITE TO YELLOW FLUORESCENCE RESIDUE. Tuffaceous Sandstone/ Siltstone (11810' - 11880') = olive gray to medium gray; very fine grains; high sphericity; subrounded to rounded; well sorted; poor consolidation; tu ffaceous matrix; coal seen early then quickly disappears; 10% YELLOW FLUORESCENCE; NO STAIN; SLIGHT ODOR; SLOW BLOOM OF FAINT WHITE FLUORESCENT CUT; NO VISIBLE CUT; FAINT WHITE BLUE FLUORESCENT RESIDUE RING WITH NO VISIBLE RESIDUE. TUFFACEOUS SANDSTONE/ SAND (11880' - 11960') = very light gray to olive gray; upper fine to very fine grains; moderate to high sphericity; subrounded; moderate sorting; very poor consolidation; tuffaceous matrix; matrix supported; tuffaceous claystone is yellowish gray to light olive gray; poor induration; pulverulent; smooth and clayey; greasy to waxy luster; mushy and pasty; 30% DULL YELLOW FLUORESCENCE; CUT FLUORESCENCE DULL WHITE BLUE TO MILKY WHITE; NO VISIBLE CUT; NO VISIBLE RESIDUE; FLUORESCENCE RESIDUE QUICKLY SPREAD FROM SAMPLE AS A WHITE BLUE RING WITH SMALL AREAS OF YELLOW WHITE. Tuffaceous Sandstone (11960' - 12020') = yellowish gray to very pale orange; upper fine to very fine grains; subprismoidal to spherical; subangular to rounded; moderate sorting; very poorly co nsolidated; tuffaceous matrix; tuffaceous claystone is white to yellowish gray; poor induration; pulverulent and malleable; 30% DULL YELLOW FLUORESCENCE; CUT FLUORESCENCE DULL WHITE BLUE; NO VISIBLE CUT; FLUORESCENT RESIDUE LEAVING WHITE BLUE RING; NO VISIBLE RESIDUE. SCU 44-33 29 Sand/ Sandstone/ Tuffaceous Sand (12020' - 12280') = interval apparently consists of two somewhat distinct show zones. The upper varies from 30-60% loose sand; 10-30% sandstone; 40-80% tuffaceous sand; loose sand is fine grain; subrounded to subangular; subprismoidal; moderate to well sorted in part; dominantly milky white quartz grains and transparent volcanic glass clasts; note locally abundant very fine glass shards; sandstone appears medium light gray; fine grain; subrounded to subangul ar; subdiscoidal; moderate to well sorted; grain supported with minor clay fill; fair to good porosity; well cemented; noncalcareous; dominantly quartz with locally abundant carbonaceous detrital stain clasts spikes; tuffaceous sandstone is pale yellowish brown; fine grain; subangular to subrounded; quartz grains occasionally appear layered or oriented within a predominately tuffaceous matrix; more often matrix supported than grain supported; locally abundant yellowish gray to pale yellowish orange subwaxy tuff; lower zone is 80-90% loose fine to lower medium subrounded sand; note abundant carbonaceous material at base; Sand/ Tuffaceous Sandstone (12180' - 12230') = clear to frosted white; low medium to low fine grains; subangular to rounded; subprismoidal to spherical; moderate sorting; unconsolidated to poorly consolidated; tuffaceous matrix; 20% FLUORESCENCE; NO ODOR; CUT FLUORESCENCE DISPLAYS SLOW BLUE WHITE BLOOM; NO VISIBLE CUT; NO VISIBLE RESIDUE; FAINT BLUE WHITE RESIDUE FLUORESCENCE. Tuffaceous Siltstone (12230' - 12270') = light olive gray to olive gray; very poor induration; pulverulent to malleable; tabular habit; silty to gritty texture; dull earthy luster; mushy consistency; 20% FLUORESCENCE; NO VISIBLE STAIN; NO ODOR; SLOW BLOOM OF DULL YELLOW WHITE CUT FLUORESCENCE; NO VISIBLE CUT; NO VISIBLE RESIDUE; FAINT YELLOW RESIDUE RING. Tuffaceous Siltstone (12270' - 12350') = medium light gray to olive gray; very poor induration; pulverulent tenacity; tabular to wedge like habit; silty to gritty text ure; dull earthy luster; lenticular bedding; sand; tuffaceous sandstone; frosted white to clear; upper fine to very fine grains; angular to subrounded; prismoidal to spherical; tuffaceous matrix; trace carbonaceous shale; no fluorescence. Tuffaceous Siltstone (12350' - 12390') = medium light gray to brownish gray; poor induration; pulverulent to malleable; tabular to nodular habit; clayey up to a gritty texture; earthy dull luster; clumpy consistency; lenticular bedding; no fluorescence. Sand/ Tuffaceous Sandstone (12430' - 12425') = medium light gray to medium gray with clear to white grains; upper fine to lower fine grain size; moderate to high sphericity; subrounded to rounded; well sorted; unconsolidated; no fluorescence. SCU 44-33 30 3.4 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) 9115 -8869.39 50 10125 -9510.62 240 9175 -8923.19 140 10220 -9541.12 262 9240 -8980.32 120 10250 -9551.01 245 9300 -9031.85 173 10380 -9596.78 959 9330 -9057.11 132 10440 -9618.96 441 9365 -9086.18 396 10510 -9644.26 690 9390 -9106.55 447 10560 -9662.07 1675 9425 -9134.36 1292 10625 -9686.32 353 9455 -9157.42 550 10685 -9709.92 442 9490 -9183.61 487 10750 -9735.07 387 9520 -9205.36 350 10875 -9782.98 407 9550 -9226.27 315 10940 -9809.48 250 9585 -9249.63 415 11125 -9894.33 279 9615 -9268.92 320 11190 -9926.01 229 9645 -9287.61 264 11255 -9958.8 277 9675 -9305.84 541 11315 -9990.15 345 9710 -9326.56 320 11450 -10062.6 330 9740 -9343.71 297 11510 -10094.7 388 9770 -9360.31 447 11575 -10129.1 384 9805 -9379.06 390 11700 -10195.1 331 9875 -9413.59 104 11765 -10229.1 294 9935 -9439.57 340 11825 -10260.6 296 10000 -9465.48 285 11885 -10291.5 591 10060 -9488.26 255 SCU 44-33 31 3.5 Sampling Program / Sample Dispatch Set Type / Purpose Frequency* Interval Dispatched to A Washed and dried reference samples 30 ft 10 ft 9001 ft – 11400 ft 11400 ft – 12425 ft Hilcorp Alaska LLC 3800 Centerpoint Drive Suite #1000 Anchorage AK 99508 Attn.: Debra Oudean (907) 777-8337 B Washed and dried reference samples 30 ft 10 ft 9001 ft – 11400 ft 11400 ft – 12425 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. SCU 44-33 32 4 PRESSURE / FORMATION STRENGTH DATA 4.1 Pore pressure evaluation Formation Interval Primary Lithology (%) Secondary Lithology (%) Interval Tops Pore Pressure (EMW) Trend Indicators MD (ft) SSTVD (ft) Min (ppg) Max (ppg) Trend Tyonek to top G1 55% Sd/SS 20% Slst 15% Clyst - - 9.2 12.0 INCR BGG CG TG MW Tyonek G1 50% Slst 40% Sd/SS 11318 -9993 11.6 11.6 EVEN BGG CG MW Tyonek G2 75% Sd/SS 15% Slst 11377 -10024 11.5 11.6 EVEN BGG CG MW Hemlock 60% Sd/SS 35% Slst 11519 -10100 11.5 11.6 EVEN BGG CG MW Hemlock H2 45% Sd/ SS 25% Slst 25% Clyst 10604 -10145 11.3 11.6 DECR BGG CG MW Hemlock H3 60% Sd/ SS 25% Slst 15% Clyst 11664 -10177 11.3 11.35 EVEN BGG CG MW Hemlock H4 60% Sd/ SS 15% Cgl 15% Slst 11706 10199 11.3 11.35 EVEN BGG CG MW Hemlock H5 50% Sd/ SS 35% Clyst 15% Slst 11735 -10214 11.3 11.3 EVEN BGG CG,MW Hemlock H6 55% Sd/ SS 45% Clyst 11821 -10259 11.3 11.3 EVEN BGG CG,MW Hemlock H7 60% Sd/ SS 25% Clyst 15% Slst 11857 -10278 11.3 11.3 EVEN BGG CG,MW Hemlock H10 80% Sd/ SS 20% Clyst 12013 -10358 11.3 11.3 INCR BGG CG WTG Hemlock H11 To TD at 12425’MD 40% Sd/ SS 25% Clyst 35% Slst 12108 -10457 11.35 11.35 INCR BGG CG WTG Clyst = Claystone/Clay; Sd = Unconsolidated Sand; Slst = Siltstone; Sh = Shale; SS = Sandstone; Cgl = Conglomerate BGG = Background Gas; CG = Connection Gas; TG = Trip Gas; MW = Mud Weight SCU 44-33 33 5 DRILLING DATA 5.1 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) T*9001 25.79 7.61 8950.36 338.31 58.87 0.00 9114 25.41 29.31 9052.49 383.91 74.03 22.85 8.62 9177 27.42 44.08 9108.98 406.15 90.76 43.18 10.88 9238 29.67 55.50 9162.60 424.80 112.99 68.32 9.66 9301 31.95 59.39 9216.71 442.13 140.19 98.11 4.80 9332 33.50 61.12 9242.79 450.44 154.74 113.89 5.84 9346 34.19 62.38 9269.37 458.87 170.44 130.81 3.08 9396 36.66 63.90 9295.44 467.24 186.99 148.56 8.19 9425 38.92 63.93 9318.36 475.06 202.95 165.64 7.79 9457 40.59 64.83 9342.96 483.90 221.40 185.35 5.52 9489 42.61 66.18 9366.88 492.70 240.74 205.91 6.91 9520 44.45 66.80 9389.36 501.22 260.31 226.67 6.09 9552 47.19 66.69 9411.66 510.28 281.40 249.01 8.57 9583 49.10 66.59 9432.34 519.43 302.59 271.47 6.17 9615 50.84 67.20 9452.92 529.05 325.13 295.34 5.63 9646 52.14 66.27 9472.23 538.63 347.41 318.95 4.81 9678 53.08 67.45 9491.66 548.62 370.79 343.70 4.15 9710 54.50 67.90 9510.56 558.43 394.68 368.93 4.58 9741 55.79 69.18 9528.28 567.73 418.35 393.86 5.38 9771 57.08 69.94 9544.86 576.46 441.77 418.44 4.79 9800 57.81 71.02 9560.47 584.63 464.81 442.55 4.02 9831 59.81 71.63 9576.52 593.12 489.93 468.76 6.67 9865 61.98 71.83 9593.06 602.43 518.14 498.16 6.40 9901 64.15 73.32 9609.37 612.04 548.76 529.98 7.07 9928 65.93 72.97 9620.76 619.13 572.19 554.28 6.70 9991 66.77 75.02 9646.03 635.04 627.65 611.67 3.27 10054 68.18 75.00 9670.17 650.09 683.87 669.64 2.24 10117 71.11 75.15 9692.08 665.30 740.93 728.48 4.66 10180 71.85 75.62 9712.09 680.38 798.74 788.03 1.37 10242 70.14 78.47 9732.28 693.52 855.86 846.56 5.15 10306 69.98 78.59 9754.11 705.49 914.82 906.70 0.31 10369 68.00 79.32 9776.70 716.76 972.54 965.50 3.32 10432 68.46 79.29 9800.06 727.61 1030.03 1024.00 0.73 10495 68.95 79.74 9822.94 738.29 1087.74 1082.70 1.02 T tie-in point P projected SCU 44-33 34 Directional Surveys (continued) Measured Depth (ft) Incl. (o) Azim. (o) True Vertical Depth (ft) Northing (ft) Easting (ft) Vertical Section (ft) Dogleg Rate (o/100ft) 10556 69.50 80.01 9844.58 748.32 1143.89 1139.73 0.99 10621 66.83 80.38 9868.75 758.60 1203.34 1200.06 4.14 10683 66.85 79.61 9893.14 768.50 1259.48 1257.07 1.14 10744 67.52 80.01 9916.79 778.45 1314.82 1313.29 1.25 10806 67.77 80.06 9940.37 788.37 1371.29 1370.63 0.41 10867 67.14 79.64 9963.76 798.30 1426.75 1426.97 1.21 10930 65.32 79.80 9989.15 808.59 1483.47 1484.62 2.90 10993 63.35 79.32 10016.43 818.87 1539.32 1541.40 3.20 11056 61.82 78.22 10045.44 829.76 1594.17 1597.31 2.88 11120 61.35 77.46 10075.90 841.62 1649.19 1653.56 1.28 11183 60.43 77.94 10106.55 853.34 1702.97 1708.56 1.60 11244 59.45 77.80 10137.10 864.44 1754.59 1761.32 1.62 11302 58.12 77.35 10167.16 875.11 1803.03 1810.88 2.39 11378 57.20 77.65 10207.81 889.01 1865.72 1875.02 1.26 11440 57.49 79.12 10241.27 899.51 1916.85 1927.20 2.05 11503 57.86 79.93 10274.96 909.19 1969.20 1980.44 1.24 11565 58.12 80.90 10307.82 917.95 2021.03 2033.01 1.39 11628 58.07 80.81 10341.12 926.45 2073.84 2086.48 0.14 11688 58.30 80.21 10372.75 934.85 2124.12 2137.47 0.93 11748 58.53 80.49 10404.17 943.42 2174.51 2188.58 0.55 11810 58.56 81.26 10436.53 951.81 2226.73 2241.46 1.06 11875 58.80 80.67 10470.32 960.53 2281.57 2296.98 0.86 11936 58.98 81.40 10501.83 968.67 2333.16 2349.20 1.07 12003 59.17 81.00 10536.27 977.46 2389.96 2406.66 0.59 12048 59.01 81.46 10559.38 983.35 2428.11 2445.26 0.95 12108 59.66 81.39 10589.98 991.04 2479.15 2496.85 1.09 12172 60.09 81.38 10622.10 999.33 2533.88 2552.19 0.67 12250 60.45 81.83 10660.79 1009.22 2600.88 2619.90 0.68 12351 60.53 82.12 10710.54 1021.49 2687.92 2707.74 0.26 P*12425 60.53 82.12 10746.94 1030.32 2751.74 2772.12 0 T tie-in point P projected SCU 44-33 35 5.2 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 0* 6” HCC T72XY 3x16/ 0.589 9123’ 9123’ 0’ N/A -- -- -- -- Not Graded (mill) 6-5/8” HCC Window Mill/ 10127231 -- 9001’ 9035’ 20’ 9.8 4 24 0 1596 Not Graded 1 6-1/8” HCC MX- R18DX/ 5185181 3x14/ 0.451 9035’ 9832’ 797’ 34.4 28 26 0 1957 4-3-WT-A-E-I-LT-HR 2 6-1/8” HCC Q505FHX/ 7028065 5x12/ 0.5522 9832’ 12425’ 2593’ 77.7 58.5 8.7 49.6 3213 0/1-ER/A-X/I-CT/TD 3RR1 6-1/8” HCC MX- R18DX/ 5185181 3x14/ 0.451 12425’ 12425’ 0 0 -- -- -- - 0/1-ER/A-X/I-CT/TD *bit #0 used for clean-out run SCU 44-33 36 5.3 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) 10/09/2012 9000 9.70 50 13 18 6/8/10 5.2 1/2 7.0 0.3/90.0 0.10 8.7 35000 560 10/10/2012 9000 9.75 49 9 19 6/7/9 4.6 1/2 5.1 0.3/92.0 0.10 8.6 33000 440 10/11/2012 9015 10.2 52 9 21 6/7/8 5.0 1/2 6.3 0.3/91.0 0.10 9.2 31000 280 10/12/2012 9035 11.10 50 12 25 5/7/8 4.2 1/2 9.4 0.1/88.0 0.10 9.4 33000 200 10/13/2012 9035 11.60 47 11 24 9/12/13 4.7 1/2 11.7 0.0/86.0 - 9.4 31000 200 10/14/2012 9175 11.60 47 15 30 9/11/12 4.6 1/2 11.6 0.1/86.0 - 9.2 30500 200 10/15/2012 9527 11.60 47 16 30 8/11/13 3.8 1/2 11.7 0.1/86.0 - 9.1 30000 200 10/16/2012 9832 11.60 49 19 31 7/9/10 3.6 1/2 11.0 0.1/86.0 - 9.4 31000 160 10/17/2012 9832 12.50 47 19 27 6/7/9 3.8 1/2 15.0 0.1/83.0 - 9.2 26000 120 10/18/2012 9832 12.50 47 19 26 5/6/8 3.8 1/2 14.9 0.1/83.0 - 9.4 28000 80 10/19/2012 10001 11.70 47 17 26 6/7/8 4.0 1/2 12.0 0.1/85.5 - 9.3 32000 80 10/20/2012 10572 11.35 48 18 26 6/7/8 3.2 1/3 10.7 0.1/87.0 - 9.4 29000 140 10/21/2012 11379 11.40 48 20 23 6/7/9 3.4 1/3 10.5 0.1/87.0 - 9.7 32000 80 10/22/2012 11592 11.40 47 18 21 5/6/7 3.4 1/3 11.1 0.1/86.5 - 9.8 30500 80 10/23/2012 11857 11.35 51 23 25 8/11/13 3.6 1/3 11.0 0.1/86.5 - 9.8 31500 80 10/24/2012 12270 11.40 50 20 25 6/9/11 3.8 1/3 11.0 0.1/86.6 - 10.0 31000 80 10/25/2012 12425 12.50 55 21 26 7/9/11 3.8 1/3 15.4 0.1/82.3 - 9.0 31000 80 10/26/2012 12425 11.55 49 20 20 6/8/9 3.6 1/3 11.8 0.1/85.8 - 9.0 31000 80 10/27/2012 12425 11.55 51 18 21 6/8/9 3.8 1/3 11.9 0.1/85.8 - 9.3 30000 80 10/28/2012 12425 12.50 44 17 18 4/7/9 5.0 1/3 15.6 0.1/82.3 - 8.9 28500 80 10/29/2012 12425 11.50 47 17 17 5/7/9 5.0 1/3 11.8 0.1/86.0 - 9.2 28500 80 10/30/2012 12425 11.50 50 13 14 4/6/8 4.8 1/3 11.9 0.1/86.0 - 9.3 26500 80 10/31/2012 12425 11.50 50 13 14 4/6/7 4.8 1/3 11.9 0.1/86.0 - 9.0 26,500 80 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 37 Mud Record (continued) 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) 11/01/2012 12425 12.55 52 15 20 6/8/9 5.2 1/3 15.8 0.1/82.3 - 8.9 26,000 320 11/02/2012 12425 12.55 54 15 17 5/7/9 5.6 1/3 15.7 0.1/82.3 - 8.5 26,000 320 11/03/2012 12425 11.70 50 15 16 5/6/7 5.2 1/3 12.4 0.1/85.5 - 8.5 26,500 320 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 38 6 DAILY REPORTS SCU 44-33 62 7 SHOW REPORTS