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167-070
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Daniel Taylor To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject:GP 44-11 (PTD: 167-070) MIT-IA Date:Friday, October 3, 2025 3:05:25 PM Attachments:MIT - GP 44-11 - 2025-10-01.xlsx Please see the attached MIT. Regards, Daniel Taylor, P.E. Well Integrity O: 907-777-8319 C: 907-947-8051 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. *UDQLWH3W6WDWH 37' Submit to: OOPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1670700 Type Inj N Tubing 178 178 177 177 Type Test P Packer TVD 4650 BBL Pump 0.2 IA 284 1752 1750 1750 Interval O Test psi 1750 BBL Return 0.2 OA 84 93 93 93 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: Hilcorp Alaska, LLC Granite Point Field/ Granite Point Unit /Granite Point Platform Waived - EPA Witnessed Fred Chase 10/01/25 Notes:Class I Disposal Well - Annual MIT with EPA witnessing. Test result: PASS. EPA requires test to 1750 psi. Notes: Notes: Notes: GRANITE PT ST 44-11 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Form 10-426 (Revised 01/2017)2025-1001_MIT_Granite_Pt_44-11 9 9 9 999 99 9 9 9 9 9 5HJJ Gir-e,&-Pe Pt 4-4-1( Regg, James B (OGQ P-4't� 167 v700 From: Casey Morse <Casey.Morse@hilcorp.com> Sent: Wednesday, October 23, 2024 9:08 AM To: Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject: MIT GP 44-11 (PTD 167070) Attachments: MIT GP 44-11 2024-10-22.xisx CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Please see attached report of successful EPA witnessed MIT performed on GP 44-11 (Class I Disposal Welt) on / 10/22/24. This test was performed per EPA Underground Injection Control Permit No. AK-11020-A and followed EPA test procedures. Thankyou, Casey Morse Well Integrity Engineer Hitcorp Alaska, LLC (907) 777-8322 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the Individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, k is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to 'im manor laska.aov: AOGCC. Insoectorsl@alaskeni phoebe.breok r0alaska. gov OPERATOR: Hilcorp Alaska LLC FIELD I UNIT / PAD: Granite Point FieMI Greater Point Unit /Granite Point Platform DATE: 10/22/24 OPERATOR REP: AOGCC REP: chris wallace0easka.aoy Wall GRANITE PT ST 44.11 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1670700 Type Inj N Tubing 156 - 156 157 155 ' Type Test P Pecker ND 4651 BBL Pump 1 ] IA d48 1783 1762 1781 Interval 0 Test psi 1500 fBBLRetumj I OA 1 437 -1 463 1 463 1 463 1 1 1 Result P Vohs: Class I Disposal Well -Annual MIT with EPA witnessing. Test result'. PASS. EPA requires starting test pressure greater than 1750 psi. BBL Realm was not mcortlatl as pan of the EPA test Well Pressures'. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing =P=Fj= Type Test Packer ND BBL Pump I IA I 11 Interval Test psi BBL Return OA Result Notes: Well Pressures'. Pretest Initial 15 Min, 30 Min. 45 Min, 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Nitrate: Well Pressures'. Pretest Initial 15 Min. W Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Internal Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min, 30 Min. 45 Min. 60 Min. PTD TYP I Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Nobs: Well Pressures: Pretest Initial 15 Min. W Min. 45 Min, 60 Min. PTD Type Inj Tubing Type Test Packer NO BBL Pump IA Interval Test psi BBLRatum OA Result Notes: Well Pressures: Pretest Initial 15 Min, 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Nobs: Well Pressures. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inl Tubing Type at Packer ND BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST colas INTERVAL CaOes Rssult Codes W=water P=Pressure Tere I - Inner TM P=Pass G=Car O e Other deserithe in Noteel a=Four Year Ord. F=Far 6=filar, V= Requtred or Vananoe 1=lneonessrve I = ewit wartewlter O =Other (daunte in mte n N=NCI Inletlire Form 10426 (Revised 0112017) Mn GP 4a-11=4.1pn 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,471 feet See schematic feet true vertical 11,612 feet N/A feet Effective Depth measured 7,591 feet 5,004 feet true vertical 6,947 feet 4,651 feet Perforation depth Measured depth 5,460 - 5,480 feet True Vertical depth 5,053 - 5,071 feet Tubing (size, grade, measured and true vertical depth) 3-1/2" L-80 5,081 (MD) 4,719 (TVD) 5,004 (MD) Packers and SSSV (type, measured and true vertical depth) "FH" 51A4 Pkr 4,651 (TVD) SSSV (N/A) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work:Undefined WDSP 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: 1050 324-310 Sr Pet Eng: 7,020psi 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. Casey Morse Casey.Morse@hilcorp.com 907 777-8322Operations Manager Pumped 10 bbls water, swapped to acid and pumped 40 bbls, flushed with 5 bbls water. Final Pressure: 150 psi. 310 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 310 5,460 - 5,480 395 Size 310 435 705 4570 0 540203 13-3/8" 8,160psi 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 167-070 50-733-20059-00-00 3. Address: Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0018761 Granite Pt / Undefined WDSP Granite Pt St 44-11 Plugs Junk measured Length measured TVD Production Liner 7,962 4,336 Casing Structural 7,283 7" 7,962 12,208 11,352 435 4,015 435Conductor Surface Intermediate 26" 18" 3,090psi 3,090psi 5,750psi 4,015 3,775 Burst Collapse 1,540psi Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 3:47 pm, Jul 01, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.07.01 13:03:54 - 08'00' Dan Marlowe (1267) Well Name:GPF GP 44-11 API #:50733200590000 Field:Granite Point Start Date:6/6/2024 Permit #:167070 Sundry #:324-310 End Date:6/9/2024 6/6/2024 6/9/2024 Well Operations Summary Staged 6 totes acid and water tank on top deck for gravity feed. Hooked up acid totes and water tank to manifold into suction side of platform injection pump (no change to high pressure lines). Pumped 10 bbls water @ 0.5 bpm @ max pressure 671 psi. Swapped to acid and pumped 40 bbls @ 0.75 bpm with max pressure 707 psi. Swap over to water. Pump 5 bbls to flush pump and surface lines. No change in IA pressure throughout. Shut down and let acid soak. Pumped 209 bbl FIW with platform disposal pump to flush out safe acid. Max tubing pressure 1003 psi, IA @ 458. Daily Operations: Page 1 of 1 _____________________________________________________________________________________ Updated By: JLL 06/13/19 SCHEMATIC Granite Point Field Well: GP 44-11 Last Completed: 06/29/1995 PTD: 167-070 API: 50-733-20059-00 PBTD:7,591 TD:12,471 26 KB Elevation: 105 7 3 4 5 6 7 8 DV Collar @ 2,227 13-3/8 9-5/8 1 2 TOC @ 5,000 Partial cement above to 2,700 Max Dev. = 28.3 deg @5,600 18 XInhibited Fluid (8.4 ppg) in tbg x csg annulusCASING DETAIL Size Wt Grade Conn ID Top Btm 26 Surf 310 18 70.59 B Vetco Surf 435 13-3/8 61 J-55 Butt 12.515 Surf 4,015 9-5/840 N-80 8 RD 8.835 Surf 5,263 43.5 N-80 8 RD 8.755 5,263 7,962 7 29 N-80 X-Line 6.184 7,872 12,208 TUBING DETAIL 3-1/2 9.2 L-80 SC-BTC 2.992 Surf 5,081 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Upper Tyonek D Sand 5,460 5,480 5,053' 5,071'20'Open Lower Tyonek C Sand (C6B)11,150' 11,151' 10,301' 10,302'1'Sqz Lower Tyonek C Sand (C6C)11,230' 11,245' 10,380' 10,395'15'Isolated Lower Tyonek C Sand (C6C)11,275' 11,290' 10,425' 10,440'17'Isolated Lower Tyonek C Sand (C6D)11,400' 11,401' 10,549' 10,550'1'Sqz Lower Tyonek C Sand (C7A)11,520' 11,610' 10,668' 10,758'90'Isolated Lower Tyonek C Sand (C7C)11,663' 11,705' 10,811' 10,852'37'Isolated JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 41 41 2.992 12.000 Hanger 1 5,004 4,651 3.000 8.452 Baker FH 51A4 Packer 2 5,048 4,690 2.813 4.250 X-Nipple 3 5,081 4,719 3.000 4.250 WLEG 4 7,591 6,947 Cement Plug 5 7,935 7,258 Bridge Plug 6 10,916 10,070 Cement Plug 7 11,330 10,480 Bridge Plug 8 12,148 11,293 Bridge Plug 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2.Operator Name: 4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool?N/A Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 12,471 N/A Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 3,090psi Liner 7,020psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Casey Morse Contact Email:Casey.Morse@hilcorp.com Contact Phone:(907) 777-8322 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 5/31/2024 12,208'4,336' 3-1/2" 11,352' Baker "FH" 51A4 Packer & N/A 5,004 (MD) 4,651 (TVD) & NA 7,962' Perforation Depth MD (ft): 5,460 - 5,480 7,962' 7" 5,053 - 5,071 7,283'9-5/8" 310' 26" 18" 13-3/8" 435' 4,015' MD 3,090psi 435' 3,775' 435' 4,015' Length Size Proposed Pools: 310' 310' L-80 TVD Burst 5,081 5,750psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018761 167-070 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20059-00-00 Hilcorp Alaska, LLC Granite Pt St 44-11 AOGCC USE ONLY 8,160psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Other: Oil Safe AR (Acid Soak) Granite Pt Undefined WDSP N/A 11,612 7,591 6,947 1,750psi See schematic No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 3:02 pm, May 24, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.05.24 12:31:11 - 08'00' Dan Marlowe (1267) 324-310 10-404 DSR-5/24/24 CDW 05/24/2024 BJM 5/30/24 SFD 5/30/2024*&: Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.05.31 08:16:03 -08'00'05/31/24 RBDMS JSB 060424 Well Work Prognosis Well: GP 44-11 Well Name:GP 44-11 API Number: 50-733-20059-00-00 Current Status:Class 1 Disposal Leg:1 Estimated Start Date:05/31/24 Rig:N/A Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:167-070 First Call Engineer:Casey Morse (907)-777-8322 (O) (603) 205-3780 (M) Second Call Engineer:Karson Kozub (907)-777-8434 (O) (907) 570-1801 (M) Maximum Expected BHP: ~ 4,000 psi @ 5,053’ TVD 1,750 psi pump pressure treating with water Max. Potential Surface Pressure:1,750 psi Max allowable per EPA Permit Brief Well Summary GP 44-11 is a Class 1 disposal well under EPA Permit AK1I020A. The injection zone is the Upper Tyonek D Sand. Biennial fluid movement and tubing inspection logs are required per Rule II.C(2)b(2) and II.C(2)b(3). During the tubing inspection log attempted on 5/19/24, scale deposits on the tubing prevented successful logging. Well Objective Hilcorp plans to pump an Oil Safe AR (safe acid) soak down the production tubing and across the perfs to clean up any scale deposition. Procedure: 1. MIRU pumping equipment. 2. Pressure test surface lines to ±2,000 psi. 3. Line up pumping down the tubing 4. Pump 6 totes (1,650 gal) of Oil Safe AR (Synthetic acid) – approximately 1 tubing volume. a. Do not exceed 1,750 psi pump pressure during treatment. 5. Displace surface lines with water to spot acid in tubing. Allow to soak overnight. 6. Slowly displace acid into perfs with 60+ bbls water. 7. RU slickline to drift and broach as necessary to enable caliper tools to pass through tubing. Attachments: 1. Current Well Schematic 2. Fluid Flow Diagram 3. Oil Safe AR – Technical Data Sheet _____________________________________________________________________________________ Updated By: JLL 06/13/19 SCHEMATIC Granite Point Field Well: GP 44-11 Last Completed: 06/29/1995 PTD: 167-070 API: 50-733-20059-00 PBTD: 7,591’ TD: 12,471’ 26” KB Elevation: 105’ 7” 3 4 5 6 7 8 DV Collar @ 2,227’ 13-3/8” 9-5/8” 1 2 TOC @ 5,000’ – Partial cement above to 2,700’ Max Dev. = 28.3 deg @5,600’ 18” XInhibited Fluid (8.4 ppg) in tbg x csg annulusCASING DETAIL Size Wt Grade Conn ID Top Btm 26” Surf 310’ 18” 70.59 B Vetco Surf 435’ 13-3/8” 61 J-55 Butt 12.515 Surf 4,015’ 9-5/8”40 N-80 8 RD 8.835 Surf 5,263’ 43.5 N-80 8 RD 8.755 5,263’ 7,962’ 7” 29 N-80 X-Line 6.184 7,872’ 12,208’ TUBING DETAIL 3-1/2” 9.2 L-80 SC-BTC 2.992 Surf 5,081’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Upper Tyonek D Sand 5,460’ 5,480’ 5,053' 5,071'20'Open Lower Tyonek C Sand (C6B)11,150' 11,151' 10,301' 10,302'1'Sqz Lower Tyonek C Sand (C6C)11,230' 11,245' 10,380' 10,395'15'Isolated Lower Tyonek C Sand (C6C)11,275' 11,290' 10,425' 10,440'17'Isolated Lower Tyonek C Sand (C6D)11,400' 11,401' 10,549' 10,550'1'Sqz Lower Tyonek C Sand (C7A)11,520' 11,610' 10,668' 10,758'90'Isolated Lower Tyonek C Sand (C7C)11,663' 11,705' 10,811' 10,852'37'Isolated JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 41’ 41’ 2.992 12.000 Hanger 1 5,004’ 4,651’ 3.000 8.452 Baker “FH” 51A4 Packer 2 5,048’ 4,690’ 2.813 4.250 X-Nipple 3 5,081’ 4,719’ 3.000 4.250 WLEG 4 7,591’ 6,947’ Cement Plug 5 7,935’ 7,258’ Bridge Plug 6 10,916’ 10,070’ Cement Plug 7 11,330’ 10,480’ Bridge Plug 8 12,148’ 11,293’ Bridge Plug Oil Safe AR® is a safe yet functional replacement for traditional hydrochloric acid treatments and other commonly used oilfield acid treatments. It is non-regulated by US DOT, Canadian TDG and carries a triple zero hazardous materials information system score. Oil Safe AR® biodegrades in10 days or less and is approved by the US EPA as a Designed for the Environment product. Our standard Oil Safe AR® formula includes iron control agents, de-mulsifiers and requires no organic acid additions or corrosion inhibitors under most conditions. FEATURES AND BENEFITS: xAn excellent choice for fracs, spearhead treatments, injection wells and dis- posal wells and annular soaks xRequires no organic acid additions to help retard reaction rates xStandard formula includes surfactant and de-mulsifier system xRequires no iron control agent addition for most applications xEPA DfE formula; biodegradable in 10 days or less; approved for direct dis- charge; made with Cleangredients and DfE ingredients approved by the EPA xSafe on most metals, piping and pumping equipment xNon toxic; non fuming; non mutagenic; no VOC’s xNo secondary containment required as per Chapter 62-761F.A.C. xEliminates foulants xAn excellent choice for work-over projects, bullhead treatments and cement remediation xRequires no additional corrosion inhibitor step for most applications x100% biodegradable, acid free and naturally inhibited TYPICAL PHYSICAL PROPERTIES: Appearance and Color Colorless to slight yellow liquid Initial Freeze Point -24.88ºF (-31.6ºC) Odor Odorless to mild soapy odor Solubility in water 100% Flashpoint None Specific Gravity 1.152 ± 0.04 DIRECTIONS FOR USE: Recommended Dilution Rates: 30-100% with H²O based on the severity of the build-up and the reaction rate required for the project. Note: Oil Safe AR® concentrate contains iron control agents and de-mulsifiers. No organic acid or corrosion inhibitors are required due to the power of our patented Syntech®. A typical ratio for an acid frac is one part Oil Safe AR® and one part H²O. Blending ratios may vary based on specific applications and recommendations from your consultants at Heartland Energy Group, Ltd. STORAGE AND HANDLING: Oil Safe AR® has a storage life of better than one year. Keep container closed when not in use. As with all chemical products and materials, take care as to where you store them. Safety glasses are suggested for use when handling this product. No special gloves or protective equipment are required when handling this product. When pumping this product, it is strongly recommended to use manufacturer approved hose couplings or fittings. DO NOT USE ALUMINUM FITTINGS. 316 Stainless Steel, polypropylene, polyethylene are recommended. PACKAGING: Oil Safe AR® is shipped in bulk tanker trucks from the manufacturing facility. Smaller packaging quantities are available upon request. Recommendations given in this data sheet are based on tests believed to be reliable. However, the use of the information is beyond the control of Heartland Energy Group, Ltd., and no guarantee, ex- pressed or implied is made to the results obtained if not used in accordance with directions or established safe practice. The buyer must assume all responsibility, including injury or damage from the misuse of the product as such, or in combination with other materials. This bulletin is not to be taken as a license to operate under or recommendation to infringe any patent. DISSOLVING PROPERTIES ACID TYPE % CaCO³ Oil Safe AR® 100% Solution 100.00% Oil Safe AR® 50% Solution 96.76% Oil Safe AR® 30% Solution 54.00 7 ½HCI 46.48% 15% HCI 87.39% 7½ HCI + 100 gpt of 85% Acetic Acid 75.08% 15% HCI + 100 gpt of 85% Acetic Acid 97.87% 10% Acetic Acid 21.00% 15% Acetic Acid 63.09% Each test above was conducted with 1 cubic inch of material placed in 50 ml of solution and allowed to soak for 8 hrs at 100ºF. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Some people who received this message don't often get email from robinson.james@epa.gov. Learn why this isimportant From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Cc:Brooks, Phoebe L (OGC) Subject:FW: Approval to Inject under AK-1I020-A at Granite Point Platform, Cook Inlet, Alaska (PTD 1670700) Date:Thursday, April 6, 2023 11:08:53 AM Attachments:SIGNED_AK1I020A Approval to Inject Letter.pdf From: Robinson, James <Robinson.James@epa.gov> Sent: Friday, January 27, 2023 8:19 AM To: apeloza <apeloza@hilcorp.com> Cc: Martinson, Mathew <martinson.mathew@epa.gov>; Osborne, Evan <Osborne.Evan@epa.gov>; Burgess, Karen <Burgess.Karen@epa.gov>; Thurmon, Clarke <Thurmon.Clarke@epa.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Zeigler, Nick R (DEC) <nick.zeigler@alaska.gov> Subject: Approval to Inject under AK-1I020-A at Granite Point Platform, Cook Inlet, Alaska Hi Amy, Please find the attached letter for approval to inject at GP 44-11 under AK-1I020-A. Feel free to reach out if you have any questions. Regards, James Robinson, PE, PG Physical Scientist/UIC Specialist U.S. EPA Region 10 Alaska Operations Office Phone: 907.271.6627 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGION 10 1200 Sixth Avenue, Suite 155 Seattle, WA 98101-3188 WATER DIVISION January 26, 2023 Ms. Amy Peloza Environmental Manager Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, Alaska 99524-4027 Re: Approval to Inject Under Underground Injection Control (UIC) Class I Permit AK-1I020-A at Granite Point Platform, Cook Inlet, Alaska Dear Ms. Peloza, The U.S. Environmental Protection Agency, Region 10 (EPA) has inspected well GP 44-11at the Granite Point Platform, witnessed mechanical integrity tests, and reviewed results of those tests submitted by Hilcorp. These tests and submittals satisfy the Requirements Prior to Commencing Injection in permit AK-1I020-A, Part II.C. Therefore, EPA grants approval to Hilcorp to commence injection into GP 44-11 in compliance with the aforementioned permit. If you have any questions, please contact me at (907) 271-6627 or robinson.james@epa.gov. Sincerely, Mathew J. Martinson CAPT, USPHS Chief, Permits, Drinking Water, and Infrastructure Branch cc: Mr. Christopher Wallace Alaska Oil and Gas Conservation Commission Mr. Nick Zeigler Alaska Department of Environmental Conservation 1 Regg, James B (OGC) From:Josh Allely - (C) <Josh.Allely@hilcorp.com> Sent:Wednesday, November 2, 2022 12:39 PM To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject:MIT - GP 44-11 (EPA Class I Disposal Well) - 10/19/2022 Attachments:MIT - GP 44-11 - 2022_10_19.xlsx Attached is the official report of the successful EPA witnessed MIT, performed on GP 44-11 (Class I Disposal Well) on 10/19/22. Test was conducted per EPA Underground Injection Control Permit No. AK-1I020-A and followed EPA test procedures. Josh Allely Well Integrity Engineer Kenai Hilcorp Alaska 907-777-8505 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1670700 Type Inj N Tubing 180 184 182 181 Type Test P Packer TVD 4650 BBL Pump 1.8 IA 381 1809 1806 1804 Interval O Test psi 1500 BBL Return 1.8 OA 139 152 151 152 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: Hilcorp Alaska, LLC Granite Point Field/ Granite Point Unit /Granite Point Platform Jimmy Madrid 10/19/22 Notes:Class I Disposal Well - Annual MIT with EPA witnessing (AOGCC witness waived). Test result: PASS. EPA requires test to 1750 psi. Notes: Notes: Notes: GRANITE PT ST 44-11 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Form 10-426 (Revised 01/2017)2022-1019_MIT_GranitePt_State_44-11 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 06/28/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL GP 44-11 (PTD 167-070) Caliper Survey 06/22/2022 Please include current contact information if different from above. PTD:167-070 T36736 Kayla Junke Digitally signed by Kayla Junke Date: 2022.06.29 10:41:57 -08'00' UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGION 10 1200 Sixth Avenue, Suite 155 Seattle, WA 98101 WATER DIVISION Reply to: Gross.Ryan@epa.gov DELIVERED BY E-MAIL Ms. Amy Peloza Environmental Manager Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, Alaska 99524-4027 Re: Aquifer Exemption Granted for Underground Injection Control (UIC) Class I Injection Well GP 44-11 at the Granite Point Platform in the Cook Inlet of Alaska Dear Ms. Peloza, This letter is in response to a request from Hilcorp Alaska LLC (Hilcorp) dated August 30, 2021, for an aquifer exemption in relation to Injection Well GP 44-11 at the Granite Point Platform in the Cook Inlet of Alaska. Pursuant to the U.S. Environmental Protection Agency’s (EPA) authority under the Safe Drinking Water Act, EPA Region 10 reviewed the request for the aquifer exemption and determined that it meets the criteria promulgated under federal regulations 40 CFR §144.7. By this letter, EPA grants the aquifer exemption as requested. The exemption applies to the portion of the Upper Tyonek D Sand at 4,868 to 5,411 feet true vertical depth and within a radius of 5,726 feet from the wellbore of well GP 44- 11. In processing the request, the EPA reviewed the site information, confirmed that the aquifer exemption meets the regulatory criteria, and provided the opportunity for public comment. Injection of fluids may begin only after the EPA issues an underground injection control permit and authorizes injection. EPA reviewed of the information provided by Hilcorp and determined that the portions of aquifers identified above meet the aquifer exemption criteria under 40 CFR §146.4. Specifically, the portions of the aquifers meet the criteria of: x 40 CFR §146.4(a): The portions of aquifers proposed for exemption are not used as a drinking water source. Hilcorp submitted a map and a list showing the location and depth of all drinking water wells within the aquifer exemption area. The map submitted by Hilcorp shows no private drinking water wells within the area of review for well GP 44-11. x 40 CFR §146.4(c): The total dissolved solids content of the ground water is more than 3,000 mg/L and less than 10,000 mg/L and it is not reasonably expected to supply a public water system. EPA issued UIC permit AK-1I020-A authorizing the operation of injection well GP 44-11 as a UIC Class I non-hazardous well. The permit was issued separately from this aquifer exemption. EPA provided notice for the proposed aquifer exemption and permit issuance to the public on November 9, 2021, for the required 30-day public comment period. The fact sheet for this permit provides details and 2 justification for the aquifer exemption. EPA Region 10 UIC permits are available online at https://www.epa.gov/uic/class-i-uic-permits-issued-epa-region-10. If you have any questions, please contact Ryan Gross of my staff at (206) 553-6293 or gross.ryan@epa.gov. Sincerely, Mathew J. Martinson CAPT, USPHS Chief, Permits, Drinking Water, and Infrastructure Branch cc: Christopher Wallace (chris.wallace@alaska.gov) Alaska Oil and Gas Conservation Commission, Anchorage, Alaska David Dehaan (david.dehaan@alaska.gov) Alaska Department of Environmental Conservation, Anchorage, Alaska Mathew Martinson Digitally signed by Mathew Martinson Date: 2022.01.03 09:20:02 -08'00' ISSUANCE DATE AND SIGNATURE PAGE U.S. ENVIRONMENTAL PROTECTION AGENCY UNDERGROUND INJECTION CONTROL PERMIT: CLASS I Permit Number AK-1I020-A In compliance with provisions of the Safe Drinking Water Act (SDWA), as amended, (42 U.S.C. 300f 300j 9), and attendant regulations incorporated by the U.S. Environmental Protection Agency (EPA) under Title 40 of the Code of Federal Regulations (CFR), Hilcorp Alaska, LLC (Permittee) is authorized to inject non-hazardous industrial waste utilizing underground injection control (UIC) Class I injection well GP 44-11 at the Granite Point Platform, located in the Cook Inlet, Alaska, in accordance with conditions set forth herein. This permit prohibits injection of hazardous waste as defined under the Resource Conservation and Recovery Act, as amended, (42 USC 6901) or radioactive wastes (other than naturally occurring radioactive material from pipe scale). EPA has exempted portions of the aquifer into which well GP 44-11 injects from protection as an underground source of drinking water (USDW) under the SDWA. EPA takes the aquifer exemption action concurrently with but separately from the permit issuance. The exempted portions of the aquifer are those that are within 5,726 feet of the GP 44-11 wellbore between 4,868 and 5,411 feet total vertical depth (TVD). This permit shall become effective at midnight on the issuance date below in accordance with 40 CFR § 124.15. This permit and the authorization to inject shall expire 10 years from the day it is signed at midnight, unless terminated on a prior date.The “application” referenced in this permit is the Granite Point UIC Class I Permit Application Revision 1 dated March 2021. Issuance date:-DQXDU\ Expiration date: -DQXDU\ Mathew J. Martinson CAPT, USPHS Branch Chief, Permits, Drinking Water, and Infrastructure U.S. Environmental Protection Agency Region 10 (M/S: 19-H16) 1200 Sixth Avenue, Suite 155 Seattle, WA 98101 Mathew Martinson Digitally signed by Mathew Martinson Date: 2022.01.03 09:15:52 -08'00' U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 2 TABLE OF CONTENTS ISSUANCE DATE AND SIGNATURE PAGE ........................................................................................... 1 PART I GENERAL PERMIT CONDITIONS ............................................................................................. 4 A. EFFECT OF PERMIT ...................................................................................................................................... 4 B. PERMIT ACTIONS ......................................................................................................................................... 4 1. Modification, Re-issuance or Termination ............................................................................................................... 4 2. Transfer of Permits ................................................................................................................................................... 4 C. SEVERABILITY .............................................................................................................................................. 4 D. CONFIDENTIALITY ...................................................................................................................................... 4 E. GENERAL DUTIES AND REQUIREMENTS ............................................................................................... 5 1. Duty to Comply ........................................................................................................................................................ 5 2. Penalties for Violations of Permit Conditions .......................................................................................................... 5 3. Continuation of Expiring Permits ............................................................................................................................. 5 4. Need to Halt or Reduce Activity Not a Defense ....................................................................................................... 5 5. Duty to Mitigate ....................................................................................................................................................... 5 6. Proper Operation and Maintenance .......................................................................................................................... 5 7. Property Rights ......................................................................................................................................................... 5 8. Duty to Provide Information ..................................................................................................................................... 6 9. Inspection and Entry ................................................................................................................................................. 6 10. Records ..................................................................................................................................................................... 6 11. Reporting Requirements ........................................................................................................................................... 7 12. Twenty-Four Hour Reporting ................................................................................................................................... 7 13. Other Noncompliance ............................................................................................................................................... 8 14. Reporting Corrections............................................................................................................................................... 8 15. Signatory Requirements ........................................................................................................................................... 8 F. PLUGGING AND ABANDONMENT ............................................................................................................ 9 1. Notice of Plugging and Abandonment ...................................................................................................................... 9 2. Plugging and Abandonment Report .......................................................................................................................... 9 3. Cessation Limitation ................................................................................................................................................. 9 4. Cost Estimate for Plugging and Abandonment ......................................................................................................... 9 G. FINANCIAL RESPONSIBILITY .................................................................................................................. 10 PART II WELL SPECIFIC CONDITIONS ................................................................................................ 11 A. CONSTRUCTION ......................................................................................................................................... 11 1. Casing and Cementing of Wells ..............................................................................................................................11 2. Tubing and Packer Specifications ............................................................................................................................11 3. New Wells in the Area of Review (AOR) ...............................................................................................................11 B. CORRECTIVE ACTION ............................................................................................................................... 12 C. WELL OPERATION...................................................................................................................................... 12 1. Requirements Prior to Commencing Injection .........................................................................................................12 2. Mechanical Integrity ................................................................................................................................................12 3. Injection Zone ..........................................................................................................................................................14 4. Injection Pressure Limitation ...................................................................................................................................14 5. Annulus Pressure Limitation ...................................................................................................................................15 6. Injection Fluid Limitation ........................................................................................................................................15 7. Waivers Granted for UIC Regulatory Requirements ...............................................................................................15 D. MONITORING .............................................................................................................................................. 16 1. General Monitoring Requirements ..........................................................................................................................16 2. Monitoring Continuous Waste Injection ..................................................................................................................16 3. Monitoring Batch Waste Injection ...........................................................................................................................16 4. Alarms and Operational Modifications ....................................................................................................................16 E. REPORTING REQUIREMENTS .................................................................................................................. 17 1. Quarterly Reports ....................................................................................................................................................17 2. Annual Reports ........................................................................................................................................................17 U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 3 3. Report Certification .................................................................................................................................................18 APPENDIX A REPORTING FORMS....................................................................................................... 19 U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 4 PART I GENERAL PERMIT CONDITIONS A. EFFECT OF PERMIT The Permittee is authorized to engage in underground injection in accordance with the conditions of this permit. Notwithstanding any other provisions of this permit, the Permittee must not conduct any underground injection activity in a manner that allows the movement of fluid containing any contaminant into a USDW, if the presence of that contaminant may cause a violation of any primary drinking water regulation under 40 CFR Part 141 or may otherwise adversely affect the health of persons. Any underground injection activity not specifically authorized in the permit is prohibited. Compliance with this permit during its term constitutes compliance for purposes of enforcement with Part C of the SDWA. Such compliance does not constitute a defense to any action brought under Section 1431 of the SDWA, or any other common or statutory law. Issuance of this permit does not authorize any injury to persons or property, any invasion of other private rights, or any infringement of State or local law or regulations. This permit does not authorize any above ground generating, handling, storage, or treatment facilities. B. PERMIT ACTIONS 1. Modification, Re-issuance or Termination This permit may be modified, revoked and reissued, or terminated for cause as specified in 40 CFR §§ 144.39 and 144.40. In addition, the permit can undergo minor modifications for cause as specified in 40 CFR § 144.41. The filing of a request for a permit modification, revocation and reissuance, or termination, or the notification of planned changes, or anticipated noncompliance on the part of the Permittee does not stay the applicability or enforceability of any permit condition. 2. Transfer of Permits This permit is not transferable to any person except after notice to the EPA Region 10 Water Division Director or Permitting, Drinking Water and Infrastructure Branch Chief (the Director) on APPLICATION TO TRANSFER PERMIT (EPA Form 7520-7) and in accordance with 40 CFR § 144.38. The Director may require modification or revocation and reissuance of the permit to change the name of the Permittee and incorporate such other requirements as may be necessary under the SDWA. Upon request, email submittal may be approved by an EPA authorized representative. C. SEVERABILITY The provisions of this permit are severable, and, if any provision of this permit or the application of any provision of this permit to any circumstance is held invalid, the application of such provision to other circumstances, and the remainder of this permit, shall not be affected thereby. D. CONFIDENTIALITY In accordance with 40 CFR Part 2 and 40 CFR § 144.5, any information submitted to EPA pursuant to this permit may be claimed as confidential by the submitter. Any such claim must be asserted at the time of submission in the manner prescribed in 40 CFR § 2.203 and on the application form or instructions, or, in the case of other submissions, by stamping the words “confidential” or “confidential business information” on each page containing such information. If no claim is made at the time of submission, EPA may make the information available to the public without further notice. If a claim is asserted, the validity of the claim will be assessed in accordance with the procedures in 40 CFR Part 2 (Public Information). EPA will deny claims of confidentiality for the following information: U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 5 1. The name and address of the Permittee. 2. Information which deals with the existence, absence, or level of contaminants in drinking water. E. GENERAL DUTIES AND REQUIREMENTS 1. Duty to Comply The Permittee must comply with all conditions of this permit. Any permit noncompliance constitutes a violation of the SDWA and is grounds for enforcement action; for permit termination, revocation and reissuance, or modification; or for denial of a permit renewal application; except that the Permittee need not comply with the provisions of this permit to the extent and for the duration such noncompliance is authorized in an emergency permit under 40 CFR § 144.34. 2. Penalties for Violations of Permit Conditions Any person who violates a permit requirement is subject to civil penalties and other enforcement action under the SDWA. Any person who willfully violates permit requirements may be subject to criminal prosecution. 3. Continuation of Expiring Permits a. Duty to Reapply: If the Permittee wishes to continue an activity regulated by this permit after the expiration date of this permit, the Permittee must apply for and obtain a new permit. To be timely, a complete application for a new permit must be received at least 180 calendar days before this permit expires. b. Permit Extensions: The requirements of an expired permit continue in force and effect, in accordance with 5 USC § 558(c), until the effective date of a new permit, if: (1) The Permittee has submitted a timely and complete application for a new permit; and (2) EPA, through no fault of Permittee, does not issue a new permit with an effective date on or before the expiration date of the previous permit. 4. Need to Halt or Reduce Activity Not a Defense It shall not be a defense for the Permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity to maintain compliance with the conditions of this permit. 5. Duty to Mitigate The Permittee must take all reasonable steps to minimize or correct any adverse impact on the environment resulting from noncompliance with this permit. 6. Proper Operation and Maintenance The Permittee must, at all times, properly operate and maintain all facilities and systems of treatment and control (and related appurtenances) which are installed or used by the Permittee to achieve compliance with the conditions of this permit. Proper operation and maintenance includes: effective performance, adequate funding, adequate operator staffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures. This provision requires the operation of back-up or auxiliary facilities or similar systems only when necessary to achieve compliance with the conditions of this permit. De-characterized waste may be appropriately disposed in a Class I non-hazardous well [refer to 40 CFR § 148.1(d)]. 7. Property Rights This permit does not convey any property rights or mineral rights of any sort, or any exclusive U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 6 privilege. 8. Duty to Provide Information The Permittee must provide to the Director any information that the Director may request to determine whether cause exists for modifying, revoking and reissuing, terminating this permit, or to determine compliance with this permit. The Permittee must also provide to the Director, upon request, copies of records, that are retained under the conditions of this permit. 9. Inspection and Entry The Permittee must allow the Director or an EPA authorized representative(s), upon the presentation of credentials and other documents as may be required by law, to: a. Enter upon the Permittee's premises where a regulated facility or activity is located or conducted, or where records are kept under the conditions of this permit; b. Have access to and copy, at reasonable times, any records (including logging data) that are retained under the conditions of this permit; c. Inspect and photograph, at reasonable times, any facilities, equipment (including monitoring and control equipment), practices, or operations regulated or required under this permit; and d. Sample or monitor, at reasonable times, for the purposes of assuring permit compliance or as otherwise authorized by SDWA, any substances or parameters at any location. 10. Records a. The Permittee must retain records and all monitoring information, including all calibration and maintenance records and all original strip chart recordings for continuous monitoring instrumentation, copies of all reports required by this permit and records of all data used to complete this permit application for a period of at least five years from the date of the sample, measurement, report or application. These periods may be extended by request of the Director at any time. The Permittee may retain these records in hard copy or electronic format. b. The Permittee must retain records concerning the nature and composition of all injected fluids for three years after the completion of plugging and abandonment. At the conclusion of the retention period, if the Director so requests, the Permittee must deliver the records to the Director. The Permittee must continue to retain the records after the three-year retention period unless the Permittee delivers the records to the Director or obtains written approval from the Director to discard the records. The Permittee may retain these records in hard copy or electronic format. c. Records of monitoring information must include: (1) The date, exact place, and time of sampling or measurements; (2) The name(s) of the individual(s) who performed the sampling or measurements; (3) The date(s) analyses were performed; (4) The name(s) of the individual(s) who performed the analyses; (5) The analytical techniques or methods used; and (6) The results of such analyses. d. Monitoring of the nature of injected fluids must comply with applicable analytical methods cited and described in 40 CFR § 136.3, in Appendix I of 40 CFR Part 261, or, in certain circumstances, by other methods that have been approved by the Director. U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 7 e. As part of the Completion Report for any new, sidetracked, or converted well, the Permittee must submit a Waste Analysis Plan (WAP) that describes the procedures to be carried out to obtain detailed chemical and physical analysis of representative samples of the waste including the quality assurance procedures used including the following: (1) The parameters for which the waste will be analyzed and the rationale for the selection of these parameters; (2) The test methods that will be used to test for these parameters; and (3) The sampling method that will be used to obtain a representative sample of the waste to be analyzed. At the request of the Permittee and upon approval by EPA, the WAP submitted with the permit application may be incorporated by reference to satisfy the WAP submittal requirement. f. The Permittee must require a written manifest for each batch load of waste received for injection of waste streams that are not hard-piped and continuous. The manifest must contain a description of the nature and composition of all injected fluids, date of receipt, source of material received for disposal, name and address of the waste generator, a description of the monitoring performed and the results, a statement describing whether the waste(s) is exempt from regulation as hazardous waste as defined by 40 CFR § 261.4, and any information on extraordinary occurrences. For waste streams that are hard-piped continuously from the source to the wellhead, the Permittee must retain: (1) Continuous measurement of the discharge rate, (2) A description of the nature and composition of all injected fluids, and (3) A hazardous waste determination as defined by 40 CFR § 261.4. g. The Permittee must note dates of most recent calibration or maintenance of gauges and meters used for monitoring required by this permit on the gauge or meter. The Permittee must keep earlier records of calibration and maintenance available through a computerized maintenance history database. 11. Reporting Requirements a. Planned Changes: The Permittee must give notice to the Director, as soon as possible, of any planned physical alterations or additions to the permitted facility or changes in type of injected fluid(s). b. Anticipated Noncompliance: The Permittee must give notice to the Director of any significant planned changes in the permitted facility or activity that may result in noncompliance with permit requirements at least 5 business days before the change is performed. The Permittee must send this notification by email. c. Compliance Schedules: The Permittee must submit reports of compliance or noncompliance with, or any progress reports on, interim and final requirements contained in any compliance schedule of this permit to the Director no later than 30 calendar days following each schedule date contained in the compliance schedule. 12. Twenty-Four Hour Reporting a. The Permittee must report to the Director or an EPA authorized representative any noncompliance that may endanger health or the environment within 24 hours from the time the Permittee becomes aware of the information, including the following: U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 8 (1) Indication or other information that any contaminant may cause an endangerment to a USDW or may otherwise adversely affect human health. (2) Noncompliance with a permit condition. (3) Malfunction of the injection system. b. The Permittee must provide to the Director or an EPA authorized representative a written submission (in electronic format for release to the public) within five calendar days of the time the Permittee becomes aware of the circumstances. The written submission must contain a description of the noncompliance and its cause(s); the period of noncompliance including exact date and times; the anticipated timeframe the noncompliance is expected to continue, and steps taken or planned to reduce, eliminate, and prevent recurrence of the noncompliance. The Permittee must provide email notice to affected stakeholders, such as Tribal Governments, if warranted as determined by the Director or an EPA authorized representative. 13. Other Noncompliance The Permittee must include in the monitoring reports information regarding all instances of noncompliance not otherwise reported. The reports must contain the information listed in Permit Condition Part I E.12.b. 14. Reporting Corrections When the Permittee becomes aware that it failed to submit any relevant facts or submitted incorrect information in a permit application or in any report to the Director, the Permittee must submit such facts and/or information to EPA within 10 calendar days. 15. Signatory Requirements a. All permit applications, reports required by this permit, and other information requested by the Director must be signed by a principal executive officer of at least the level of vice-president, or by a duly authorized representative of that person, in accordance with 40 CFR § 144.32. A person is a duly authorized representative only if: (1) The authorization is made in writing by a principal executive of at least the level of vice-president. (2) The authorization specifies either an individual or a position having responsibility for the overall operation of the regulated facility or activity, such as the position of plant manager, operator of a well or a well field, superintendent, or position of equivalent responsibility. A duly authorized representative may thus be either a named individual or any individual occupying a named position. (3) The written authorization record is retained on-site and a copy is submitted by email to the Director. Upon request, the original is submitted to the Director or an EPA authorized representative. b. Changes to Authorization: If an authorization under paragraph 15.a. of this section is no longer accurate because a different individual or position has responsibility for the overall operation of the facility, a new authorization satisfying the requirements of paragraph 15.a. of this section must be submitted to the Director. The Permittee may submit this authorization with any reports, information, or applications to be signed by an authorized representative. c. Certification: Any person signing a document under paragraph 15.a. of this section must make the following certification: U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 9 “I certify under the penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted. Based on my inquiry of the person or persons who manage the system, or those persons directly responsible for gathering the information, the information is, to the best of my knowledge and belief, true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment for knowing violations.” F. PLUGGING AND ABANDONMENT 1. Notice of Plugging and Abandonment The Permittee must notify the Director no later than 45 calendar days before conversion or abandonment of the well. 2. Plugging and Abandonment Report The Permittee must plug and abandon the well as provided in the Plugging and Abandonment Plan (7520-6 Attachment E) of UIC Class I Permit Application submitted by the Permittee, which is hereby incorporated as a part of this permit. Within 60 calendar days after plugging any well, the Permittee must submit a report to the Director in accordance with 40 CFR § 144.51(p). EPA reserves the right to change the manner in which the well will be plugged if the well is not proven to be consistent with EPA requirements for construction and mechanical integrity. The Director may require the Permittee to update the estimated plugging cost periodically. 3. Cessation Limitation After a cessation of operations of two years, the well is considered to be in temporarily abandoned status. The Permittee must permanently plug and abandon the well in accordance with the approved plan and 40 CFR § 144.52(a)(6) within one year of entering temporarily abandoned status, unless the Permittee: a. Provides notice to the Director no later than two years and one month after cessation of operations, and b. Provides information that, to the Director’s satisfaction, demonstrates the Permittee’s intent to use the well in the future; or c. Describes actions or procedures, satisfactory to the Director, which the Permittee will take to ensure that the well will not endanger USDWs during the period of temporarily abandonment. These actions and procedures must include compliance with the technical requirements applicable to active injection wells unless waived by the Director. 4. Cost Estimate for Plugging and Abandonment a. The Permittee is required in the permit application to estimate the per well cost of plugging and abandonment of the permitted Class I UIC well(s). Please refer to the permit application (7520-6 attachment E) for the per well plugging and abandonment cost estimates for the year the application is submitted. Such estimates must be based upon costs that a third party would incur to plug the well. b. The Permittee must submit financial assurance and a revised estimate prior to April 30 of each year. The estimate must be made in accordance with 40 CFR § 144.62. The Director or an EPA authorized representative may approve email submittal of this requirement provided the Permittee retains the original and submits the original upon request. c. The Permittee must keep the latest plugging and abandonment cost estimate at the Facility or at the Permittee’s central files in Alaska during the operating life of the Facility. U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 10 d. When the cost estimate changes, the Permittee must amend the financial assurance instrument submitted under condition G of this permit to ensure that appropriate financial assurance for plugging and abandonment is maintained continuously. G. FINANCIAL RESPONSIBILITY The Permittee must demonstrate and continuously maintain financial responsibility and resources sufficient to close, plug, and abandon the underground injection operation as provided in the Plugging and Abandonment Plans and consistent with 40 CFR §144 Subpart F, which the Director has chosen to apply. The Permittee must not substitute an alternative demonstration of financial responsibility for that which the Director has approved, unless it has previously submitted evidence of that alternative demonstration to the Director and the Director notifies the Permittee that the alternative demonstration of financial responsibility is acceptable. Consistent with 40 CFR § 144.63 and regarding incapacity of owners or operators, guarantors, or financial institutions, the Permittee must notify the Director by registered mail of the commencement of a voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. Code, naming the owner or operator as debtor, within 10 business days after the commencement of the proceeding. Furthermore, an owner or operator must notify the Regional Administrator by certified mail of the commencement of a voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. Code, naming the owner or operator as debtor, within 10 business days after the commencement of the proceeding. Prior to beginning construction of any new well, conversion to an injection well, or sidetracking of an existing injection well, the Permittee must demonstrate to EPA that financial responsibility has been established for such planned activity. The value of this financial assurance must meet the requirements in Part I.F.4 of this permit. The Permittee must not begin construction of any new well, conversion to an injection well, or sidetracking of an existing injection well without first receiving approval from the Director or an EPA authorized representative. U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 11 PART II WELL SPECIFIC CONDITIONS A. CONSTRUCTION 1. Casing and Cementing of Wells The Permittee must ensure that injection occurs only into the approved injection interval through wells that are cased and cemented (see Part II.C.3., below). The Permittee must install casing and cement in accordance with a casing and cement program approved submitted by the Permittee for approval by the Director and in accordance with EPA UIC Class I well construction practices (40 CFR § 146.12) and all applicable State of Alaska laws and regulations. For any future Class I wells to be drilled under this permit (including replacement or sidetrack wells), in addition to the above requirements, the Permittee must provide not less than 30-calendar days advance notice to the Director or an EPA authorized representative to witness all cementing operations. The Director or an EPA authorized representative may increase or decrease the duration of the advance notice requirement. The Permittee must cement the surface casing of each well back to the surface. If primary cement returns to surface are not observed, the Permittee must notify the Director or an EPA authorized representative as to the nature of any augmented testing proposed to ensure the integrity of the cement bond and adequacy of any Top Job procedure. The intermediate casing (i.e., long string casing) must be cemented from the casing shoe to at least 200 feet above the upper confining zone as identified in the Fact Sheet. During construction activities that involve the emplacement of cement, the Permittee must run Cement Bond/Ultrasonic Imaging or other logs and pressure tests (e.g., leak off test and/or formation integrity test) for both the surface and production casings to confirm zonal isolation and verify casing integrity. The Permittee must provide final logs to the Director or an EPA authorized representative with the Completion Report. The casing, cementing and well construction must comply with the procedures outlined in proposed well construction plan contained in the permit application. Should a change(s) be required to the previously approved casing and cementing program due to unanticipated conditions, the Permittee must notify the Director or an EPA authorized representative in writing (hard copy or email) as to the nature of the change(s) and the unanticipated conditions requiring the change. The Permittee must not construct the proposed change without approval from the Director or an EPA authorized representative. 2. Tubing and Packer Specifications The Permittee must inject fluids through wells containing tubing with a packer. The Permittee must install tubing and packer in accordance with the procedures in the well construction plan submitted by the Permittee to the Director or an EPA authorized representative. In the event that a packer needs to be set or reset at a revised depth at a later date, the Permittee must perform a mechanical integrity test, submit the necessary information as determined by an EPA authorized representative, and obtain authorization from the Director or an EPA authorized representative prior to resuming injection. The Permittee must set the packer no more than 200 feet measured depth above the top of the injection interval unless an alternative placement is specified and authorized by the Director or an EPA authorized representative. EPA hereby approves the packer placement in well GP 44-11 as of the issuance date of this permit. The packer in this well is placed at 5,004 feet measured depth. The top of the injection interval is at 5,320 ft measured depth. 3. New Wells in the Area of Review (AOR) EPA has set a 1,533 feet radius as the AOR for this Class I UIC permit. If any wells are drilled in the U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 12 future that penetrate the injection interval within the AOR, these wells must have casing cemented to the formation throughout the entire section from 200 feet TVD below to 200 feet TVD above the (proposed, revised or updated) injection zone as identified in the permit application. B. CORRECTIVE ACTION The Permittee identified four wells that may intersect the injection interval within the1,533 feet AOR of injection well GP 44-11. The Permittee provided records for wells in the AOR. These records show that casings of all of these wells are cemented to the formation through the injection zone. Therefore, EPA requires no corrective action to prevent injected fluids from moving above the confining zone. If the Permittee later discovers that a well or wells within the AOR require(s) corrective action to prevent fluid movement, then the Permittee must inform EPA upon such discovery and provide a corrective action plan for the Director or an EPA authorized representative to review and approve. If EPA or the Permittee discovers that fluids have moved above the upper confining zone along a wellbore within the AOR, then the Permittee must cease injection until the fluid movement problem can be diagnosed and corrected. C. WELL OPERATION 1. Requirements Prior to Commencing Injection Unless the well has previously (within the last 180 calendar days) fulfilled the requirements of Part II C.1. of this permit, prior to commencing injection into a newly constructed, converted, or sidetracked injection well, the Permittee must fulfill the requirements listed in parts Part II.C.1 (a), (b) and (c). a. The Permittee must submit the COMPLETION FORM FOR INJECTION WELLS (EPA Form 7520-18) with logging data; and either: (1) The Director or an EPA authorized representative will inspect or otherwise review the newly constructed, converted, or sidetracked injection well and find it complies with the conditions of the permit; or (2) The Permittee has not received notice from the Director or an EPA authorized representative of intent to inspect or otherwise review the new, converted, sidetrack or replacement injection well within 13 business days of receipt of the Completion Report (receipt must be confirmed by EPA), in which case EPA waives prior inspection or review. b. The Permittee must demonstrate that the well has mechanical integrity as described in Part II.C.2., to the satisfaction of the Director or an EPA authorized representative. The Permittee must notify EPA at least 10 business days prior to conducting the initial mechanical integrity test so that an EPA authorized representative may witness the test. c. The Permittee must conduct a step-rate injection test and submit to EPA a preliminary report that summarizes the results. Upon approval by the Director or an EPA authorized representative, the Permittee may submit the results of a previously conducted step-rate injection test to satisfy this requirement. EPA is waiving the prohibition against injecting at a pressure that may fracture the injection zone. Therefore, EPA waives the requirement to conduct a step-rate test for well GP 44-11. 2. Mechanical Integrity a. Standards The injection well must have and maintain mechanical integrity pursuant to 40 CFR § 146.8. b. Prohibition without Demonstration of Mechanical Integrity U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 13 This permit prohibits injection operations at the permitted well after the effective date of this permit unless the Permittee has demonstrated mechanical integrity by conducting the following tests and submitted the results to the Director: (1) The Permittee must demonstrate there is no significant leak in the casing, tubing or packer by conducting a mechanical integrity test of the tubing/casing inner annulus (MITIA). To start the test, the Permittee must bring the annulus to a starting pressure of at least 1,750 pounds per square inch (psi), but not to exceed 70% of the minimum yield strength of the casing. The Permittee must observe the pressure in the tubing, inner annulus, and (if present) outer annulus of the well for the duration of the test. The results of the test must satisfy either (i) or (ii) below: i. the inner annulus pressure does not decline by more than 10% of the starting pressure during the test period and the loss in the second half of the test period is less than 50% of the loss in the first half of the test period, or ii. the inner annulus pressure does not decline by more than 2% of the starting pressure during the test period and the loss in the second half of the test period is less than the loss in the first half of the test period. If the well fails to satisfy (i) or (ii) during the first 30-minute test period, the test may be extended by an additional 30 minutes to demonstrate stabilization. The Permittee must notify the Director or an EPA authorized representative 30 calendar days prior to commencement of the MITIA. After the initial test, the Permittee must conduct an MITIA annually if the well is active and once every two years if the well is inactive until expiration of the permit. The Director or an EPA authorized representative may extend the due date for the MITIA up to three months. Also, the Director or an EPA authorized representative may revise (either increase or decrease) the frequency with which the Permittee must conduct the MITIA. (2) The Permittee must conduct an approved fluid movement test to detect fluid migration outside of the permitted injection intervals at an injection pressure at least equal to the average continuous injection pressure observed at the well in the previous six months. Approved fluid movement test methods include, but are not limited to: tracer surveys, temperature survey logs (conducted after a 12-hour shut-in, at a minimum, unless otherwise authorized by an EPA authorized representative), noise logs, oxygen activation/water flow logs, borax pulse neutron logs, or other equivalent logs. The Permittee must notify the Director or an EPA authorized representative 30 calendar days prior to commencement of the fluid movement test and request approval for any testing procedure not previously used to satisfy this requirement. The Permittee must initially conduct a fluid movement test and submit the logs of this test upon completion of the well and prior to initiation of injection at a new, converted, sidetracked well. After the initial test, the Permittee must conduct a fluid movement test and submit test logs and results every two years while the well is active until expiration of the permit. The Director or an EPA authorized representative may extend the due date of this testing requirement up to three months. Also, the Director or an EPA authorized representative may revise (either increase or decrease) the frequency with which the Permittee must conduct a fluid movement test. (3) The Permittee must conduct tubing inspection tests to monitor condition, thickness, and integrity of the downhole tubing. The Permittee must notify the Director or an EPA authorized representative 30 calendar days prior to commencement of the tubing inspection test and request approval for any testing procedure not previously used to satisfy this requirement. The Permittee must conduct a tubing inspection test and submit test logs and results every two years while the well is active until expiration of the permit. The Director or an EPA authorized representative may extend the due date for the tubing inspection up to U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 14 three months. Also, the Director or an EPA authorized representative may revise (either increase or decrease) the frequency with which the Permittee must conduct the tubing inspection test. c. Terms and Reporting (1) The Permittee must submit a copy of the log(s) and a descriptive and interpretive report of the mechanical integrity tests identified in Part II. C. 2. b. (2) and (3) to EPA within 45 calendar days of completion in hard copy or electronic format, unless waived by an EPA authorized representative. Immediately after well logging activities, the Permittee must submit a copy of any log(s) to an EPA authorized representative, if requested. This includes logging events associated with construction activities and mechanical integrity testing. (2) The Permittee must demonstrate mechanical integrity by the MITIA in Part II. C. 2. b. (1) prior to resuming injection if, at any time, the tubing is removed from the well or a loss of mechanical integrity becomes evident during operation. The Permittee must report the results of such tests within 45 calendar days of completion of the tests. (3) The Director will notify the Permittee of the acceptability of the mechanical integrity demonstration within 10 business days of receipt of the results of the mechanical integrity tests. The Permittee may continue to inject during this review period. If the Director does not notify the Permittee within 10 business days, the Permittee may continue to inject. (4) In the event that the well fails to demonstrate mechanical integrity during a test or a loss of mechanical integrity occurs during operation, the Permittee must halt injection immediately and must not resume injection until the Director or an EPA authorized representative gives approval to resume injection. (5) The Director may, by written notice, require the Permittee to demonstrate mechanical integrity at any time. 3. Injection Zone The Permittee may only inject fluid into the designated injection zone for each permitted well. For well GP 44-11, the injection zone includes the Upper Tyonek Formation D Sand at 4,856-5,071 feet TVD (5,243-5,487 feet measured depth). These injection zones are described in the Fact Sheet and depicted in the Completion and Type Log in the permit application. The Permittee may not inject at a pressure that causes the propagation of fractures in the injection zone or the confining zones. EPA has exempted the portions of the aquifers in the injection zone of well GP 44-11 within 5,726 feet of the wellbore from protection as a USDW under SDWA. The aquifer exemption is issued separately from, but concurrent with, this permit issuance. 4. Injection Pressure Limitation a. The Permittee must not inject at a pressure that initiates new fractures or propagates existing fractures in the upper confining zone, as described in the Fact Sheet. b. According to application materials submitted by the Permittee, injection through well GP 44-11 will not initiate new fractures or propagate existing fractures into the upper confining zone if the pressure in the injection zone does not exceed 4,109 psi. The maximum allowable injection pressure (MAIP), measured at the wellhead (surface), is calculated using the following equation: MAIP = PIZ - [(PGWater x SGFluid) x DIZ] U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 15 Where: PIZ = Maximum pressure in the injection zone (4109 psi) PGWater = Pressure gradient of water (0.433 psi/ft) SGFluid = Specific gravity of injected fluid DIZ = Depth at injection zone in feet TVD When injecting fluids having a specific gravity of 1.02 or less, the Permittee must not inject at a wellhead (surface) pressure exceeding 1,750 psi. The Permittee must not exceed the MAIP except as follows: a. If a plant is shut-down or outage (unrelated to fluid injection activities) occurs. b. If a well stimulation is required. In such instances, the Permittee must notify the Director or an EPA authorized representative by telephone or email within 24 hours of the initial exceedance of the MAIP and must submit a written incident report not later than 10 calendar days thereafter. The Permittee must never inject above the working pressure for which the well components are rated. 5. Annulus Pressure Limitation The Permittee must fill the tubing-casing annulus with a corrosion inhibiting solution. The Permittee must not allow the positive surface pressure in the tubing-casing annulus to exceed 1500 psi. The difference between the annulus pressure and the injection pressure must be sufficient to easily detect pressure communication. EPA does not intend the authorization of up to 1,500 psi on the inner annulus to allow the Permittee to continue to injection in the event of a loss of mechanical integrity or if pressure communication exists between the inner annulus and the tubing or outer annulus. 6. Injection Fluid Limitation This permit authorizes the Permittee to inject only wastes identified in the permit application that are not characterized as hazardous. De-characterized waste must be disposed of appropriately (refer to 40 CFR § 148.1(d)). The Permittee may dispose of waste generated from construction, repair, operation and maintenance of Class I injection wells and associated injection well piping in this Class I non- hazardous injection well. This permit does not authorize injection of radioactive wastes, other than naturally occurring radioactive material (NORM) from pipe scale and/or radioactive tracer beads. If the Permittee accepts waste from a third party, the third party must certify the wastes are eligible for injection pursuant to the terms of this permit. This permit authorizes the Permittee to inject only common oil and gas industry-related wastes. The common oil and gas industry-related waste streams are listed in Exhibit 2 of the “GP 44-11 Class I Disposal Waste Analysis Plan (WAP)” submitted by Hilcorp with the UIC Class I permit application and in Appendix A of the Fact Sheet. The Permittee may not inject any waste stream that was not generated on the Granite Point Platform until the Permittee submits a request for approval to inject that waste stream to the Director and that request is approved by the Director or an EPA authorized representative. This request for approval must include an analysis of the waste stream and any other information the Director identifies as necessary. 7. Waivers Granted for UIC Regulatory Requirements EPA waives the following Class I UIC requirements. EPA has the authority to waive these U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 16 requirements under 40 CFR §144.16, as this well does not inject through, into, or above any USDW: a. Compatibility of Formation and Injectate [40 CFR §§ 146.12(e)(4)-(5) and 146.14(a)(8)]: EPA waives the requirement to sample and characterize formation fluids and the rock matrix to determine whether or not they are compatible with the approved injectate stream. EPA grants this waiver based on the remote location of the injection zone beneath Cook Inlet and the history of Class II injection at well GP 44-11. b. Injection Zone Fracturing [40 CFR § 146.13(a)(1)]: EPA waives the prohibition against injecting at a pressure that initiates new fractures or propagates existing fractures in the injection zone. The Permittee is prohibited from injecting at a pressure that initiates new fractures or propagates existing fractures in the confining zone or causes the movement of injection or formation fluids into an underground source of drinking water. The injection zone and confining zones are defined in the fact sheet. This waiver does not authorize the use of these injection wells for hydrocarbon production activities, and the Permittee must not inject for any purpose other than the emplacement of non-hazardous waste for permanent disposal. D. MONITORING 1. General Monitoring Requirements The Permittee must ensure that all wells authorized by this permit are monitored 24 hours per day by trained and qualified personnel while injection is occurring. Samples and measurements collected by the Permittee for the purpose of monitoring must be representative of the monitored activity. 2. Monitoring Continuous Waste Injection The Permittee must install, maintain, and use monitoring devices to continuously monitor injection pressure and rate for those waste streams that are hard-piped and continuous, and to monitor the pressure of non-freezing solution in the tubing-casing annulus. Calculated flow data or periodic monitoring are not acceptable except as a back-up system if the primary continuous injection rate device malfunctions or power outage occurs. 3. Monitoring Batch Waste Injection The Permittee must continuously staff and visually monitor batch waste injection operations at the well site. During these operations, the Permittee must maintain a chronological record of injected wastes, including the time and date, description of waste, volume, injection pressure, injection rate, waste generating company and location, transport company/driver, and Hilcorp official confirming Class I eligibility. 4. Alarms and Operational Modifications The Permittee must install, continuously operate, and maintain alarms to notify operators when injection or annular pressure is outside of the normal operating range. These alarms must be sufficient to alert operators in all operating spaces including, but not limited to, the control room. The Permittee must install and maintain an emergency shutdown system stop injection if there is a loss of mechanical integrity in the inner annulus. The Permittee must submit plans and specifications for the alarms to the Director or an EPA authorized representative prior to the initiation of injection. U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 17 E. REPORTING REQUIREMENTS 1. Quarterly Reports The Permittee must submit quarterly reports by email to the Director or an EPA authorized representative. The reports must include the following information: a. Monthly average, maximum, and minimum values for injection pressure, rate, and volume must be reported on INJECTION WELL MONITORING REPORT (EPA Form 7520-8). b. Daily or hourly monitoring data in electronic spreadsheet format approved by the Director or EPA authorized representative. This data must include average and maximum values for: injection pressure, inner annulus pressure, and injection rate. c. Graphical plots of continuous injection pressure, inner annulus pressure, and injection rate. d. Physical, chemical, and other relevant characteristics of the injected fluid. e. A list of all batch injections. The list must show time and date, description of waste, volume, waste generating company and location, and confirmation of Class I eligibility by a Hilcorp official. f. Descriptions of any well workover or other significant maintenance of downhole or injection- related surface components. g. Results of all mechanical integrity tests performed since the previous report, including any maintenance-related tests and practice tests. h. Reports of changes in annular pressures in any wells in the AOR that could be indicative of pressure communication between those wells and the UIC Class I injection wells authorized by this permit. This includes daily average annular pressure for the 9-5/8 inch by 13-3/8 inch annulus for the wells MUCI-2 and GP 31-14RD2 in electronic spreadsheet format approved by the Director or EPA authorized representative. i. Results of any other tests required by the Director. 2. Annual Reports The Permittee must submit to the Director an annual performance report for the period of October 1 through September 30. This report must be submitted by November 30 of each year. (For example, injection data from October 1, 2019, through September 30, 2020, should be reported by November 30, 2020). The annual performance report must include, but not be limited to: a. Rate and pressure performance. b. Surveillance logging and results. c. Fill depth. d. Volumetric analysis of the disposal storage. e. Annual or cumulative injection volumes. f. Estimated fracture growth in the event that solids injection takes place. g. Updates to fracture model analyses (if any). h. Indications of communication between the injection wells and other wells in the AOR. i. Updates of operational plans. U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 18 j. Results of annual well shut down for a time sufficient to conduct a valid observation of the pressure fall-off curve. Some information may not be available every year if those activities did not take place during the reporting period (e.g. surveillance logging, fill depth, and fracture model updates). 3. Report Certification All reports and notifications required by this permit must be signed and certified in accordance with Part I.E.15; stored and maintained in electronic format at the Permittee’s Facility or company headquarters; submitted by email to the Director or an EPA authorized representative; and, upon request by the Director or an EPA authorized representative, submitted as a hard copy to the following address: U.S. Environmental Protection Agency Region 10 Ground Water and Drinking Water Section, UIC Program (19-H16) 1200 Sixth Avenue, Suite 155 Seattle, Washington 98101-3140 U.S. EPA Underground Injection Control Class I Permit AK-1I020-A Page 19 APPENDIX A REPORTING FORMS PDF copies of following forms are available on the EPA web site at: https://www.epa.gov/uic/underground-injection-control-reporting-forms-owners-or-operators 7520-7 APPLICATION TO TRANSFER PERMIT 7520-8 INJECTION WELL MONITORING REPORT 7520-18 COMPLETION REPORT FOR INJECTION WELLS October 2021 US Environmental Protection Agency Page 1 of 13 Fact Sheet for Proposed Issuance of Underground Injection Control (UIC) Permit AK-1I020-A for the Granite Point Platform in Alaska WHAT ACTIONS DOES THIS FACT SHEET DESCRIBE? Hilcorp Alaska, LLC (Hilcorp), has applied for a permit to operate a Class I non-hazardous injection well at the Granite Point Platform in the Cook Inlet of Alaska. The U.S. Environmental Protection Agency (EPA) proposes to issue the requested permit. In this fact sheet, EPA describes the principal facts considered in issuing this permit. WHAT IS PROPOSED IN THE PERMIT? This permit would allow Hilcorp to inject waste into a geological formation beneath the Granite Point Field. Only waste determined to be non-hazardous under the Resource Conservation and Recovery Act (RCRA) may be injected. Wastes related to oil and gas exploration and production are exempt from classification under RCRA and may also be injected under this permit. WILL NEW WELLS BE DRILLED? No. Hilcorp has proposed to inject waste through an existing well that has been used to inject similar waste into the same geological formation for over 25 years. All previous injection was permitted by Alaska Oil and Gas Conservation Commission (AOGCC) under a UIC Class II permit. DOES THIS PERMIT ALLOW INJECTION INTO AN UNDERGROUND SOURCE OF DRINKING WATER? No. The aquifer into which this well injects will be exempted from status as an underground source of drinking water (USDW). Under the Safe Drinking Water Act (SDWA), EPA may exempt aquifers or portions of aquifers from status as a USDW if the aquifers do not currently serve as a source of drinking water and is not reasonably expected to serve as a source of drinking water in the future. The aquifer into which this well injects satisfies these criteria. DOES THIS ACTION ENDANGER DRINKING WATER OR ENVIRONMENTAL RESOURCES? No. The injection zone is located more than 4000 feet below the seafloor. It is separated from surface waters and other subsurface aquifers by several impermeable geological layers. These impermeable layers have trapped oil and gas for millions of years, demonstrating their ability to prevent the upward migration of fluids. WHAT WASTES WILL BE INJECTED? Injected waste will consist primarily of fluids generated during the operation and maintenance of the Granite Point Platform, including: produced water; storm water, domestic waste water, and drilling cuttings and muds. Waste streams from off-platform must be approved by EPA before injection. HOW CAN I COMMENT AND/OR REQUEST A HEARING? EPA will accept public comments and public hearing requests related to the proposed permit and aquifer exemption from November 16, 2021 at 9 AM Alaska Time to on December 17, 2021 at 5 PM Alaska Time. If you would like to make a comment or request a hearing, see the ‘Public Comment’ section at the end of this Fact Sheet or go to www.epa.gov/publicnotices. For more information, contact Ryan Gross (gross.ryan@epa.gov, 206-553-6293). Fact Sheet: UIC Class I Permit AK-1I020-A October 2021 US Environmental Protection Agency Page 2 of 13 Table of Contents A. Proposed Action ............................................................................................................................... 3 B. Regulatory Framework .................................................................................................................... 3 C. Background ...................................................................................................................................... 3 D. Project Overview ............................................................................................................................. 4 1. Injection Well Structure ................................................................................................................... 4 2. Well Operations and Waste Streams ................................................................................................ 4 3. Well Integrity Testing ...................................................................................................................... 5 4. Environmental Justice ...................................................................................................................... 6 5. Endangered Species ......................................................................................................................... 6 E. Geology ............................................................................................................................................... 6 1. Deposition/Lithology/Stratigraphy .................................................................................................. 6 2. Injection Zone .................................................................................................................................. 6 3. Confining Zones............................................................................................................................... 7 4. Subsurface Fracturing ...................................................................................................................... 7 5. Seismicity ......................................................................................................................................... 7 F. Subsurface Aquifers and Aquifer Exemption ...................................................................................... 8 G. Plugging and Abandonment Cost Estimate and Financial Assurance ............................................. 8 H. Specific Permit Conditions .............................................................................................................. 8 1. Financial Responsibility (Part I. G.) ................................................................................................ 9 2. Construction (Part II. A.) ................................................................................................................. 9 3. Corrective Action (Part II. B.) ......................................................................................................... 9 4. Well Operation (Part II. C.) ............................................................................................................. 9 5. Injection Fluid Limitation (Part II. C. 6.)......................................................................................... 9 6. Waivers Granted for UIC Regulatory Requirements (Part II. C. 7.) ............................................. 10 7. Monitoring and Record Keeping (Part II. D.) ................................................................................ 10 8. Reporting (Part II. E.) .................................................................................................................... 10 I. Public Comment ................................................................................................................................ 11 1. Aquifer Exemption......................................................................................................................... 11 2. UIC Class I Permit ......................................................................................................................... 11 Appendix A ............................................................................................................................................... 12 Fact Sheet: UIC Class I Permit AK-1I020-A October 2021 US Environmental Protection Agency Page 3 of 13 A. Proposed Action EPA proposes to issue UIC Permit AK-1I020-A to Hilcorp to operate one UIC Class I non-hazardous industrial waste injection well. The name of the injection well is GP 44-11. EPA also proposes to exempt a portion of the aquifer into which this well injects from status as a USDW under the SDWA. B. Regulatory Framework The EPA UIC program is authorized by Part C of the SDWA for the principal purpose of protecting USDWs from endangerment by injection wells. A USDW is an aquifer which currently or could in the future serve as a source of drinking water. It is defined in the Code of Federal Regulations (CFR) at 40 CFR §144.3. Primary responsibility for implementing the SDWA UIC program in Alaska is shared between EPA and AOGCC. EPA regulates Class I injection wells, which are used to dispose of hazardous or non-hazardous waste beneath the lowermost USDW. Class I non-hazardous wells may only inject waste defined as non-hazardous by RCRA and waste exempted from RCRA classification because it originates from oil and gas exploration and production. In Alaska, AOGCC regulates Class II wells, which are used to dispose of waste brought to the surface from oil and gas production operations, to enhance recovery of oil and gas, or to store hydrocarbons which are liquid at standard temperature and pressure (40 CFR § 144.6). Class II wells differ from Class I wells in the construction, operation, and monitoring requirements, as well as the range of waste streams that may be injected. Operators can only use Class II wells to inject waste that is associated with hydrocarbon production. Applicable regulations concerning injection well requirements can be found in 40 CFR §§144 and 146. Criteria and standards applicable to Class I wells are found at 40 CFR §146 Subpart B. For more information on injection well classes, see: www.epa.gov/uic/underground-injection-control-well-classes. C. Background The Granite Point Platform is in the Cook Inlet, located approximately 12 miles southwest of Tyonek, Alaska, and 16 miles north of Nikiski, Alaska. Underground injection at the Granite Point Field began in 1968. Since then, over 163 million barrels of fluid have been injected at the field. In 1984, EPA exempted the aquifer underlying the entire Granite Point Field (see Figure 3) from status as a USDW in the EPA regulations at 40 CFR §147.102. This exemption applies only to Class II injection into the aquifer. Figure 1. Area map. The Granite Point Platform is the southernmost of the three platforms in the Granite Point Unit. Fact Sheet: UIC Class I Permit AK-1I020-A October 2021 US Environmental Protection Agency Page 4 of 13 In 1995, AOGCC issued Disposal Injection Order 10, permitting Class II injection through well GP 44-11. Disposal Injection Order 10 required the permittee to test the mechanical integrity of the wells at least every four years. AOGCC witnessed the most recent mechanical integrity test in March 2019. This test successfully demonstrated mechanical integrity of well GP 44-11. Since 1995, well GP 44-11 has been used to inject more than 1.2 million barrels of produced water. Hilcorp applied to EPA on May 15, 2020, for a permit that would convert well GP 44-11 from a Class II disposal well into a Class I non-hazardous industrial waste injection well. The permit would allow Hilcorp to expand the types of wastes that could be injected through the well. Hilcorp actively injects waste through two Class II wells (permitted by AOGCC) on the Granite Point Platform, GP 44-11 and GP 24-13RD2. Hilcorp will continue to operate the well GP 24-13RD2 as a Class II well. D. Project Overview 1. Injection Well Structure The length of the wellbore in well GP 44-11 is 12,453 feet and deviates from top-hole to bottom-hole in a southeast-to-northwest direction. The well was previously plugged back to a depth of 6,947 feet true vertical depth (TVD) or 7,591 feet measured depth (MD). This well is constructed of three layers of casing pipe extending to different depths, as shown in Figure 2. The casing is cemented to the formation to prevent migration of fluid along the outside of the pipe. A packer is installed between the tubing and the casing at a depth of 4,651 feet TVD to prevent migration of fluid between the tubing and casing of the well. The injection zone for well GP 44-11 is in the Upper Tyonek formation. The well is perforated at the interval 5,053-5,071 feet TVD to allow the injected waste to enter the formation in a reservoir called the Upper Tyonek D Sands, found at 4,856-5,071 feet TVD. Additional geological information concerning this project is found in Section E, below. 2. Well Operations and Waste Streams Upon issuance of this permit, Hilcorp would be authorized to use well GP 44-11 to inject both produced water, as was previously injected under the Class II permit, and other exempt or non-hazardous waste streams. These non-hazardous waste streams are generated by common oil and gas industry activities, but not brought to the surface in connection with hydrocarbon production. These waste streams include but not limited to: liquids associated with the operation and maintenance of an oil and gas platform, storm water, domestic wastewater, drilling cuttings and muds, and produced water. Table 1 shows the volumes of major waste streams injected into well GP 44-11 in 2019, along with estimated future annual injection volumes for the period 2021-2041. Figure 2. Well schematic for GP 44-11 (not to scale). Fact Sheet: UIC Class I Permit AK-1I020-A October 2021 US Environmental Protection Agency Page 5 of 13 Table 1. Current and estimated future injection annual waste stream volumes for well GP 44-11. Waste Stream Annual Injected Volume (in Millions of Barrels) 2019 2021-2041 (Estimated) Produced Water 0.811 4.6 Domestic / Sanitary Wastewater (co-mingled w/ filtered seawater) - 6.1 Grey Water - 1.1 Tank/Vessel/Deck Rinsate/Stormwater - 0.11 Unused (Excess) Non-hazardous, Non-exempt, Drilling Fluids - 0.1 Misc. Non-hazardous, Non-exempt Waste Streams - 0.1 Total 0.811 12.11 This proposed permit would authorize only the disposal of waste which is RCRA non-hazardous or exempt from RCRA classification. This proposed permit would not allow the injection of hazardous wastes. All listed hazardous wastes must be collected, stored, and transported to a RCRA-approved hazardous waste treatment or disposal facility. Under this proposed permit, wastes that are hazardous due to a characteristic other than toxicity (i.e. ignitability, corrosivity, reactivity) may be treated to remove that characteristic, after which this waste can be injected into a Class I non-hazardous well. The only radioactive substance which may be injected under the proposed permit is naturally occurring radioactive material (NORM) from sludge or pipe scale (a mineral precipitate deposited during production). This proposed permit would authorize only the disposal of common oil and gas industry waste streams. The complete list of common oil and gas waste streams is included in the Waste Analysis Plan submitted by Hilcorp with its permit application and is found in Appendix A of this fact sheet. Upon issuance of the proposed permit, the permittee is authorized to inject any non-hazardous or RCRA-exempt waste stream that is listed in Appendix A. The permittee may not inject a waste stream that is not included in Appendix A unless EPA modifies the permit to include the proposed waste and publishes the modification for public notice and comment. The permittee must document all waste transported to the facility for injection on the Hilcorp Kenai- Cook Inlet Manifest. The permittee must maintain these manifests, according to the requirements of the permit, for at least three years after the well is plugged and abandoned. 3. Well Integrity Testing Regular testing of well integrity ensures that waste is injected only into the designated injection zone and does not enter any USDW. In this permit, EPA requires the permittee to conduct three types of tests: 1. The permittee must conduct a pressure test of the inner annulus every year to verify there are no leaks in the tubing, casing, packer, or wellhead. The inner annulus is the space between the tubing and production casing above the packer. 2. The permittee must conduct a fluid movement test every two years to verify that there is no migration of injected fluid outside of the approved injection zone along the outside of the casing. 3. The permittee must inspect the injection tubing every two years to verify that the injection tubing is in good condition and is not likely to develop a leak due to corrosion or erosion. EPA may grant an extension of up to three months to the annual testing date. Previously, AOGCC has witnessed mechanical integrity testing of the inner annulus in well GP 44-11 every four years. The well has never failed a mechanical integrity test. Fact Sheet: UIC Class I Permit AK-1I020-A October 2021 US Environmental Protection Agency Page 6 of 13 4. Environmental Justice EPA evaluated the impacts of this proposed permit action as it relates to environmental justice. This evaluation did not identify any disproportionately high and adverse human health or environmental effects on minority or low-income populations. 5. Endangered Species EPA evaluated the impacts of activities associated with this proposed permit action on species listed under the Endangered Species Act or on critical habitats on which those species depend. EPA determined that the impacts of the activities associated with this proposed permit will have no effect on the listed species or their habitats. E. Geology 1. Deposition/Lithology/Stratigraphy The Granite Point Unit, which includes the Granite Point Field, covers a surface area of approximately 15,301 acres. The Granite Point Unit produces primarily from the Lower Tyonek Formation of the Tertiary-aged Kenai Group. The unit is located on the west flank of the Cook Inlet Basin, a forearc basin associated with the subduction of the Pacific plate beneath the accreted terranes of Alaska. The Granite Point Unit is characterized by a north-north-east by south-south-west elongated sharp asymmetric fold bounded on the west by a reverse fault that is interpreted to extend into the basement. A number of seismically defined normal faults crosscut the field. The main phase of structural development occurred in the Middle to Late Miocene. The non-marine formations at the Granite Point Unit were deposited by fluvial systems that migrated across the basin, resulting in a thick section of interbedded sand, silt, mudstone, and coal. There is a broad spectrum of reservoir quality and continuity within these formations due to variations in provenance and location within the fluvial depositional systems. The members of the Kenai Group Geological Formations, which are present in the project area, are listed in Table 2. Table 2. Kenai Group geological formations with approximate depths. Formation Lithology Depth (feet) Thickness (feet) Alluvium Sandstone 0 - 550 550 Glacial Conglomerate 550 – 2,000 1,450 Beluga Interbedded sandstone, shale, coal 2,000 – 4,500 2,500 Upper Tyonek Interbedded sandstone, siltstone, shale, coal 4,500 – 7,200 2,700 Lower Tyonek Interbedded sandstone, siltstone, shale, coal, conglomerate 7,200 – 13,200 6,000 2. Injection Zone The injection zone for Well GP 44-11 is identified as the Upper Tyonek D Sand interval at 4,856-5,071 feet TVD (5,243-5,487 feet MD). Well GP 44-11 currently injects into the Upper Tyonek D Sand through perforations in the well casing at 5,053-5,071 feet TVD (5,460-5,480 feet MD). This reservoir is Fact Sheet: UIC Class I Permit AK-1I020-A October 2021 US Environmental Protection Agency Page 7 of 13 one of the more continuous sandstones in the Upper Tyonek formation. In the area around the wellbore, these sands have an average porosity of 22% and permeability of 4.33 mD. There are no known transmissive faults in the area around well GP 44-11 that would allow injected fluid to migrate upward out of the injection zone. EPA used the injection zone thickness and porosity and the predicted injection volume over the next 20 years to calculate that injected fluids are likely to fill an area in the reservoir with a radius of up to 5,726 feet from the wellbore. Hilcorp concurred with this calculation and used it as the basis for the size of the requested aquifer exemption. 3. Confining Zones The upper confining zone is above the injection zone and prevents upward migration of injected fluid. The bottom of the upper confining zone is at 4,856 feet TVD (5,243 feet MD). This zone is about 1,400 feet thick and is made up of impermeable interbedded siltstones, mudstones, coals, and discontinuous sandstone beds. The lower confining zone is below the injection zone and prevents downward migration of injected fluid. The top of the lower confining zone is at 5,418 feet TVD (5,874 feet MD). This zone is comprised of impermeable interbedded siltstones, shales, coals, and discontinuous sandstone beds. 4. Subsurface Fracturing The AOGCC Class II Permit, under which well GP 44-11 has been operated since 1995, allowed injection at pressures that caused fractures in the injection zone. The proposed EPA Class I permit would continue to allow injection that fractures the injection zone. Neither the Class II permit nor the proposed Class I permit allows injection at pressures that would fracture the confining zones. Hilcorp submitted a subsurface fracture modeling report to demonstrate that the injection proposed under this permit would not endanger USDWs or the Cook Inlet ecosystem. The modeling report was prepared by a consultant, Frac Diagnostics, LLC, on January 19, 2021. This model used a fracture propagation simulator, FRACPRO, to estimate fracture dimensions resulting from constant injection of 500 barrels of waste per day over a ten-year period. As the basis for this work, Frac Diagnostics developed a mechanical earth model using data from geological studies conducted in a well that is located close to and passed through the same formations as well GP 44-11. A “Base Case” model scenario was developed using permeability and porosity data derived from core samples from the area. To account for uncertainties in the subsurface environment, Frac Diagnostics simulated four additional scenarios. These scenarios used permeabilities that were 10%, 20%, 50% or 200% of the “Base Case” scenario. The subsurface fracture modeling report concluded that, in the most conservative scenario (permeability is 10% of Base Case), subsurface fractures would not extend outside of the interval 4,920-5,185 feet TVD vertically or 1,533 feet laterally from the wellbore. 5. Seismicity The Granite Point Field is in a very high seismic hazard area, according to the United States Geological Service. Earthquakes of a high magnitude occur in this region. Despite this seismic activity, oil wells are not frequently damaged. Deep injection wells have been linked to increased seismic activity in cases when the injection occurs at a depth near the top of the crystalline basement rock. In the Cook Inlet region, the top of the crystalline basement rock is estimated to be 25,000 feet deep. Therefore, there is not a high risk of increased seismicity associated with injection into this well. Fact Sheet: UIC Class I Permit AK-1I020-A October 2021 US Environmental Protection Agency Page 8 of 13 F. Subsurface Aquifers and Aquifer Exemption A USDW is defined as an aquifer which is currently serving as a potable water source or which, by its potential productivity and natural water quality, could serve as a public water supply (40 CFR § 144.3). Federal regulations at 40 CFR §§ 144.7 and 146.4 allow an aquifer to be exempted from status as a USDW if it does not currently serve as potable water source, if it contains water with over 3,000 mg/l total dissolved solids (TDS), and if it is not reasonably expected to supply a public water system. Under 40 CFR § 147.102(b)(2), the aquifer beneath Cook Inlet and below Granite Point Field was exempted from status as a USDW. However, this exemption only allowed injection into the aquifer through Class II injection wells. In this action, EPA proposes to modify the existing exemption for a portion of the aquifer underlying the Granite Point Field, specifically the interval between 4,868-5,411 feet TVD and within a 5,726 feet radius from the wellbore. The proposed modification, based on a request submitted by Hilcorp, would allow the aquifer to be used for the injection of Class I wastes. To demonstrate that the aquifer proposed for exemption is not currently used as a source of drinking water, Hilcorp submitted a map showing the location of the proposed exemption area under Cook Inlet. No drinking water wells are within 5,726 feet of the wellbore. Hilcorp also submitted information that demonstrated that the proposed exemption area contains water with over 3,000 mg/l TDS. The aquifer is not reasonably expected to supply a public water system due to its remote location under the Cook Inlet. G. Plugging and Abandonment Cost Estimate and Financial Assurance Federal regulations require that the permittee provide cost estimates for the plugging and abandonment from an independent entity capable of performing this work. In addition, the permittee must demonstrate it has the financial resources necessary for the plugging and abandonment of the permitted disposal wells. Hilcorp submitted cost estimates from ASRC Energy Services Alaska, Inc. and a Surety Performance Bond issued by Travelers Casualty and Surety Company of America. The bond is equal in value to the total estimate submitted for plugging and abandoning well GP 44-11. Hilcorp has also submitted an associated trust agreement. H. Specific Permit Conditions The following summary briefly describes the proposed permit conditions not discussed elsewhere in this fact sheet. These conditions, modeled on the federal UIC requirements established in 40 CFR §§ 144 and 146, are meant to protect USDWs from endangerment. Figure 3. Map of Granite Point Unit. Dotted lines show one- quarter mile and one-mile buffers. Fact Sheet: UIC Class I Permit AK-1I020-A October 2021 US Environmental Protection Agency Page 9 of 13 1. Financial Responsibility (Part I. G.) The permittee must meet the financial assurance requirements pursuant with 40 CFR § 144.52(a)(7). EPA has chosen to apply the criteria found at 40 CFR Part 144 Subpart F, and specifically 40 CFR §§ 144.63(a) and (c), in evaluating financial assurance instruments submitted in fulfillment of the financial responsibility requirement. Hilcorp submitted information in its permit application that satisfies these requirements. 2. Construction (Part II. A.) The permittee must notify the Director of the EPA Region 10 Water Division or an EPA authorized representative at least 30 days before starting any cementing operations. This notice allows EPA the opportunity to witness the construction procedures and determine regulatory compliance. A shorter notification period may be approved by EPA. 3. Corrective Action (Part II. B.) The area of review for well GP 44-11 is defined as the portion of the injection zone that lies within 1,533 feet of the wellbore. The permittee must submit information to EPA demonstrating that all wellbores within this area are properly cemented and will not conduct injected fluids out of the designated injection zone. EPA set this area in consideration of the fracture model submitted with the application and local aquifer use. Hilcorp identified four oil and gas production wells or injection wells that penetrate the area of review. Hilcorp submitted cementing records for all four wells. EPA reviewed the cementing records and verified that all wells that penetrate the area of review have been properly cemented. Therefore, no corrective action plan is required. 4. Well Operation (Part II. C.) EPA has set operational limits for the injection well in the proposed permit to ensure that the well operates in a safe and environmentally protective manner. The maximum allowable injection pressure is based on the results of the subsurface fracture modeling report submitted by Hilcorp. According to this report, injection at a bottom-hole pressure of less than 4,109 pounds per square inch (psi) will not induce fractures in the confining zone. When injecting fluids having a specific gravity of 1.02 or less, the maximum allowable injection pressure measured at the surface wellhead is 1,750 psi. When injecting fluids having a specific gravity higher than 1.02, the permittee must calculate a different maximum injection pressure using an equation provided in the permit. The maximum allowable annular pressure is 1,500 psi. This restriction allows for sudden and temporary pressure increases due to changes in the temperature of the injected fluid while not damaging the tubing, casing, or packer. At all times during operation of the injection well, the permittee must maintain a difference between the annular pressure and the injection pressure such that pressure communication between the injection tubing and the inner annulus can be easily detected. 5. Injection Fluid Limitation (Part II. C. 6.) This proposed permit limits injection to only those waste streams generated by common oil and gas activities. The complete list of common oil and gas waste streams is in the waste analysis plan submitted by Hilcorp with its permit application and is found in Appendix A of this fact sheet. Waste streams not generated on the platform must be approved by EPA before injection. If the permittee proposes to inject a waste stream that is not included in Appendix A, the permit must be modified to include the proposed waste and published for public notice and comment. Fact Sheet: UIC Class I Permit AK-1I020-A October 2021 US Environmental Protection Agency Page 10 of 13 6. Waivers Granted for UIC Regulatory Requirements (Part II. C. 7.) Hilcorp has requested that EPA, as authorized under 40 CFR § 144.16, waive certain regulatory requirements in this permit. EPA intends to grant this request. EPA has determined that these waivers do not endanger drinking water or environmental resources because of the remote location of the injection zone beneath the Cook Inlet and because the history of Class II injection at this well. The regulatory requirements that EPA intends to waive are: Compatibility of Formation and Injectate, 40 CFR §§ 146.12(e)(4)-(5) and 146.14(a)(8): EPA intends to waive the requirement to sample and characterize formation fluids and the rock matrix to determine if they are compatible with the approved injectate stream. Well GP 44-11has a history of successful injection, which demonstrates adequate compatibility. Injection Zone Fracturing, 40 CFR § 146.13(a)(1): EPA intends to waive the prohibition against injecting at pressures that would initiate new fractures or propagate existing fractures within the injection zone. It is still prohibited to inject at pressures that initiate or propagate fractures in the confining zones. This waiver enhances the permittee’s ability to inject drilling slurry, suspended solids, and other oilfield wastes. Well GP 44-11 has a history of injection at pressures that fracture the injection zone without any indication that the confining zones have been fractured. 7. Monitoring and Record Keeping (Part II. D.) EPA includes several permit conditions to assure that the permittee will monitor and characterize all injected waste prior to injection. The permittee must continuously monitor injection pressures and rates for those waste streams that are hard-piped and continuous. The permittee must also monitor the pressure of the annulus between the tubing and the casing above the packer. The permittee must characterize waste prior to injection to ensure that only wastes that are RCRA non- hazardous or exempt from RCRA characterization are injected. If injection operations exceed the limits of the permit, the permittee must notify the EPA verbally within 24 hours and in writing within five calendar days. For all waste streams that are not hard-piped and continuous, the permittee must require a manifest and a determination for each batch load of waste received that certifies the wastes are RCRA non-hazardous or exempt from RCRA characterization. 8. Reporting (Part II. E.) The permittee must submit quarterly and annual reports to EPA throughout the term of the permit. These reports allow EPA to detect non-compliance with regulations and permit conditions. Any non- compliance discovered by these reports or during regular site visits by EPA inspectors will be addressed in a way that returns the facility to compliance and minimizes damage to human health or the environment, which may involve enforcement measures. Quarterly reports submitted by the permittee must include injection pressure, injection rate, inner annulus pressure, a description of the injected materials, any well repairs or testing performed, and other information listed in the permit. To determine if injection into well GP 44-11 is resulting in movement of fluid through the upper confining zone, the permittee must also monitor and report the pressure in the annular space of two wells in the area of review, MUCI-2 and GP 31-14RD2. Fact Sheet: UIC Class I Permit AK-1I020-A October 2021 US Environmental Protection Agency Page 11 of 13 Annual reports must include various metrics of well performance and subsurface conditions, including injection rate and pressure, current well depth, updates to formation volumetric and fracture analyses, and operational plan updates. I. Public Comment 1. Aquifer Exemption Comments on this proposed aquifer exemption must be submitted during the public comment period beginning on November 9, 2021, at 9:00 AM Alaska Time and ending on December 9, 2021, at 5:00 PM Alaska Time. Because of the COVID-19 pandemic, access to the Region 10 EPA building is limited. Please submit all comments on EPA’s proposed aquifer exemption via email to gross.ryan@epa.gov. If you are unable to submit comments via email, please call 206-553-6293 between 1:00 PM and 4:00 PM, Monday through Friday, to discuss other options for submitting comments. EPA will hold a virtual hearing for this action. The hearing will be held on December 8, 2021, at 9:00 AM Alaska Time. To attend the meeting, please call 1-206-800-4483 and enter conference code 381 283 644# when prompted. To help ensure that enough phone lines are available, please register for the virtual hearing by contacting Ryan Gross at gross.ryan@epa.gov or 206-553-6293. Your registration should include your name and whether you would like to speak during the hearing. After the public comment period ends and all comments have been considered, the Director of the EPA Region 10 Water Division will make a final decision regarding this aquifer exemption. If no substantive comments are received, the aquifer exemption will become final, and the aquifer exemption will become effective upon issuance. If substantive comments are received, EPA will address the comments and determine whether to issue the proposed aquifer exemption. The aquifer exemption will become effective upon issuance unless an appeal is submitted. An aquifer exemption approved by EPA is a final agency action that may be challenged under Section 1448(a)(2) of the SDWA (42 USC300j-7(a)(2)). The statute of limitations for the right of appeal regarding any determination made related to the aquifer exemption request described above is controlled by 40 CFR § 23.7 in concert with SDWA Section 1448(a)(2). 2. UIC Class I Permit Comments on this proposed permit must be submitted during the public comment period beginning on November 9, 2021, at 9:00 AM Alaska Time and ending on December 9, 2021, at 5:00 PM Alaska Time. Because of the COVID-19 pandemic, access to the Region 10 EPA building is limited. Please submit all comments on EPA’s proposed permit via email to gross.ryan@epa.gov. If you are unable to submit comments for public hearings via email, please call 206-553-6293 between 1:00 PM and 4:00 PM, Monday through Friday, to discuss other options for submitting comments. EPA will hold a virtual hearing for this action. The hearing will be held on December 8, 2021, at 9:00 AM Alaska Time. To attend the meeting, please call 1-206-800-4483 and enter conference code 381 283 644# when prompted. To help ensure that enough phone lines are available, please register for the virtual hearing by contacting Ryan Gross at gross.ryan@epa.gov or 206-553-6293. Your registration should include your name and whether you would like to speak during the hearing. After the public comment period ends and all comments have been considered, the Director of the EPA Region 10 Water Division will make a final decision regarding permit issuance. If no substantive comments are received, the conditions in the proposed permit will become final, and the permit will become effective upon issuance. If substantive comments are received, EPA will address the comments and determine whether to issue the proposed permit. The permit will become effective upon issuance unless an appeal is submitted. Appeals regarding the SDWA UIC Class I permit should be submitted to the Environmental Appeals Board within 30 days of issuance pursuant to 40 CFR § 124.19. Fact Sheet: UIC Class I Permit AK-1I020-A October 2021 US Environmental Protection Agency Page 12 of 13 Appendix A Table 3. Common oil and gas industry waste streams that may be injected under the proposed UIC Class I permit. Waste Description Acid Used widely as cleaning fluid in well work and chemical process. Low pH. Air compressor condensation Fresh water vapor that is condensed from the compressor air intake. Boiler blowdown water Fresh water typically mixed with corrosion inhibitor used in boilers, commonly used to make steam for drilling rigs. It is collected when the boiler is taken out of service. Caustic fluid A wide range of high-pH materials normally generated by cleaning operations, as off specification chemical compounds, or as the result of chemical combinations. Clean-up fluids (washwaters) Predominantly water which has been contaminated in the process of washing down an area, engine, etc. Commercial product Products left over, spilled, outdated, off-specification, or no longer usable; drilling mud and additives that have not been circulated downhole, gel, barite, calcium carbonate, polymers; fresh or seawater rinsate with product residual. Contaminated snow/ponded water Water, possible traces of hydrocarbon or chemicals if there have been spills. Condensate Effluent from the normal process separation of oil, water, and gas. Collected from drain sumps, blow case discharge, and knockout pots. Diesel Diesel wastes may be generated as contaminated fuel, solvent, workover fluid, or freeze protection fluid. May be contaminated with small amounts of chemicals or water. Could be hazardous if not from downhole or other production related operations. Domestic wastewater Originally potable water; comes from the kitchen, showers, lavatories, laundry, toilets, and any camp floor drains. Drilling cuttings and muds Primary drilling and production operations, drilling rigs, well cellars, formation solids. Drilling fluids Excess non-hazardous fluids that were not used and did not go downhole. Facility wash water Water, possible traces of hydrocarbon, chemicals, detergent. Fire control test water Water used to test the fire water system. This includes pumps piping and if deemed necessary the sprinkler and manual hose and nozzle systems. Glycol / heat exchange media An alcohol that is widely used in circulating fluid systems to prevent freezing. May be contaminated with water, hydrocarbons, or solids. May also be used to dehydrate wet gas streams, etc. Glycol (triethylene glycol [TEG], propylene). Hydrotest fluid Water, glycol, possible product residual in existing lines, traces of chlorine or other biocide. Lubricating oils and hydraulic fluids Produced as wastes from engines and power transmission systems. Contain small amounts of metal and chemical additives to enhance their properties. Fact Sheet: UIC Class I Permit AK-1I020-A October 2021 US Environmental Protection Agency Page 13 of 13 Waste Description Methanol Light alcohol used widely as a freeze prevention fluid. May be used in combination with other materials, such as glycol. Can be hazardous if not used downhole or in relation to production operations Miscellaneous wastes Includes stormwater, snowmelt, and fresh water which are not considered as clean-up fluid. May contain small amounts of hydrocarbons and/or contaminants. Natural gas liquids Petroleum products (propane, butane, etc.) which are disposed of as wastes when they become contaminated with water, solids or some other hydrocarbon. Ignitable. Produced water Brine produced from the oil or gas reservoirs. Recovered during the production process. Production chemicals Broad category that includes chemicals used in production or transportation of crude to achieve certain desirable effects. Examples include corrosion inhibitors, emulsion breakers, foam suppressants, and proprietary compounds used in drilling fluids, muds, and cleaning products. Radioactive tracer Fluid containing a low-level, short half-life radioactive substance used downhole for periodic mechanical integrity tests. This process is not considered disposal - it is part of the well operation. Solvents A wide range of products that may be contaminated with grease, solids, and/or water. All solvents must be carefully evaluated for disposal options - only those classified as non-hazardous will be accepted for disposal. Source water Subsurface water produced from saline aquifers or alternately filtered sea water. Potentially used for making drilling mud and flushing the disposal well. Spill clean-up Water, snow, soil, with hydrocarbon or chemical products. Characterization depends on product spilled. Stimulation fluids Chemical compounds which are injected into producing or injector zones to enhance the productivity or injectivity of a well. May contain various chemicals to enhance its properties. Primarily from flowbacks. Sump fluids Water, grit, possible traces of hydrocarbon. Tank cleaning / drum rinsate Water, possible traces of hydrocarbons, chemical residues, glycol, unused drilling products Transformer oil Used as a non-conducting medium in electrical power transformers. Discarded when the equipment is abandoned. Turbine wash water Water, detergent, sometimes methanol. Used oil Hydrocarbon Workover fluids Wastes from the maintenance of a hydrocarbon production well. Predominantly water; may contain small amounts of chemicals and minor solids. Also present during well flowbacks. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] PTD 1670700 FW: Issuance of UIC Class I Permit AK-1I020-A,Granite Point Platform, Alaska Date:Tuesday, January 18, 2022 1:42:37 PM From: Josh Allely - (C) <Josh.Allely@hilcorp.com> Sent: Wednesday, January 12, 2022 8:57 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: apeloza <apeloza@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Chuck Wheat <cwheat@hilcorp.com> Subject: RE: [EXTERNAL] PTD 1670700 FW: Issuance of UIC Class I Permit AK-1I020-A,Granite Point Platform, Alaska Chris We have decided to have GP 44-11 (DIO 10) continue as a Class I and Class II well with dual reporting to the AOGCC and EPA. Let me know if you have any questions or need me to follow up with additional paperwork. Thanks Josh Josh Allely Well Integrity Engineer Kenai – Hilcorp Alaska 907-777-8505 From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Tuesday, January 4, 2022 1:33 PM To: Josh Allely - (C) <Josh.Allely@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com> Cc: Amy Peloza <apeloza@hilcorp.com> Subject: [EXTERNAL] PTD 1670700 FW: Issuance of UIC Class I Permit AK-1I020-A,Granite Point Platform, Alaska Josh, Oliver, We received this from EPA. Do you now wish to cancel DIO 10 and have this well entered in our database as only a Class I well or continue as a Class I and Class II well with dual reporting requirements to both AOGCC and EPA? CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Gross, Ryan <Gross.Ryan@epa.gov> Sent: Monday, January 3, 2022 2:06 PM To: apeloza <apeloza@hilcorp.com> Cc: 'Chuck Wheat' <cwheat@hilcorp.com>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Dehaan, David John (DEC) <david.dehaan@alaska.gov> Subject: RE: Issuance of UIC Class I Permit AK-1I020-A,Granite Point Platform, Alaska Dear Ms. Peloza, The U.S. Environmental Protection Agency (EPA) is issuing UIC Permit AK-1I020-A to Hilcorp Alaska, LLC. The permit and fact sheet are attached to this email. This permit authorizes Hilcorp Alaska to operate well GP 44-11 on the Granite Point Platform as a UIC Class I non-hazardous industrial injection well. The permit limits injection to only specified waste streams and into only specified geological intervals. This email constitutes service of notice under 40 CFR §124.19(a). The permit becomes effective on the date signed, January 3, 2022, and remains effective until January 3, 2032. Any appeal to this permit must follow the requirements of 40 CFR §124.19. Information about the administrative appeal process may be obtained at www.epa.gov/eab or by contacting the Clerk of the Environmental Appeals Board at 202-233-0122. EPA is also approving, concurrently but in a separate action, Hilcorp’s request to exempt portions of the aquifers in the injection zones surrounding this well. A letter describing the aquifer exemption is attached to this email. If you have questions about this permit or aquifer exemption, please contact me at gross.ryan@epa.gov or 206-553-6293. Sincerely, Ryan J. Gross 1 Bell, Abby E (CED) From:Wallace, Chris D (CED) Sent:Monday, June 28, 2021 1:27 PM To:Guhl, Meredith D (CED) Subject:Fwd: GP ST 44-11 (PTD 1670700) Cement Evaluation Logs Meredith, Can you please get this log and file in RBDMS and into the digilogs please? I noticed we had a mention of receiving it but couldn't find in the paper logs or digital. Thanks Chris From:JulieWellmanͲ(C)<Julie.Wellman@hilcorp.com> Sent:Monday,June28,2021,12:21PM To:Wallace,ChrisD(CED) Subject:RE:GPST44Ͳ11(PTD1670700)CementEvaluationLogs Chris, TheUSITlogforGPST44Ͳ11run24June1995hasbeenuploadedtotheHilcorpSFTPsiteintheAOGCCfolder–titled “507332005900_USIT_GP44Ͳ11”.Meredythshouldbeabletodownloaditforyou. Hilcorp’sinterpretationofthelogis: TOCat5000feetMD Partialcementupto2730feetMD Pleaseletmeknowifyouhaveanyquestionsorissuesgettingthelogoffthesharepointsite. Thankyou, Julie From:Wallace,ChrisD(CED)<chris.wallace@alaska.gov> Sent:Thursday,June24,202112:24PM To:JulieWellmanͲ(C)<Julie.Wellman@hilcorp.com> Subject:[EXTERNAL]FW:GPST44Ͳ11(PTD1670700)CementEvaluationLogs Julie, Uponreviewofthiswell,itwouldappearthereisarecordthatsaysacementevaluationlogwasrun6/23/1995to 6/25/1995. ThereisareceivingtransmittalnoteinLaserfichewellfilesayingCementevaluationlogtransmittedtoAOGCC1/3/1996 attherequestofBlairWondzell.Received1/10/1996byAOGCC. Icantseemtofindthis1995log.Apartfromaperforationlog,allotherlogsare1968. 37' (6HW By Abby Bell at 2:50 pm, Jun 28, 2021 2 Pleasereviewyourlogrecordsandsendmeanyrecordsrelatingtothecementevaluationlogsrunandany interpretationofthecementtopsforthiswell. ThanksandRegards, ChrisWallace,Sr.PetroleumEngineer,AlaskaOilandGasConservationCommission,333West7thAvenue,Anchorage,AK99501, (907)793Ͳ1250(phone),(907)276Ͳ7542(fax),chris.wallace@alaska.gov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Wallace, Chris D (CED) From: Julie Wellman - (C) <Julie.Wellman@hilcorp.com> Sent: Friday, February 5, 2021 3:50 PM To: Wallace, Chris D (CED) Subject: GPP 44-11 OA Pressure changes ?-FD 16 -7o -70o Hi Chris, Please see the attached 90 day TIO plot for GPP 44-11. The OA pressure responds by climbing a little over 100 psi at the end of a particularly long batch injection. The pressure stays high. We bled down the OA on 2/4/21 to create a bigger differential between the IA and the OA and to monitor for further buildup. The gauge was also changed when the OA was bled down as the old gauge was found to be reading 25 psi low. A slight increase over 24 hours of 20 psi was observed after the bleed and will be monitored. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg �/, P.I. Supervisor �� �,/t� I DATE: Friday, March 22, 2019 SUBJECT: Mechanical Integrity Tests HILCORP ALASKA LLC 44 -II FROM: Adam Earl GRANITE PT ST 44-11 Petroleum Inspector Sre: Inspector Reviewed By: P.I. Supry LIZ NON -CONFIDENTIAL Comm Well Name GRANITE PT ST 44-11 API Well Number 50-733-20059-00-00 Inspector Name: Adam Ear] Insp Num: mi[AGE190322091758 Permit Number: 167-070-0 Inspection Date: 3/21/2019 , Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well a4 -n Type Inj w TVD n Tubing 7i 2 1 172 - 172 172 172 PTD 1670700 Type Test SPT Test psi 1500 - IA 440 1600 - 1598 - 1595 1595 IB$L PUm ped: L2 ' i$BL Returned: 1'- i OA 380 393 793 393 393 InlerVal 4YRTST P/F P Notes: -- —_— — - Friday, March 22, 2019 Page I of I MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday,April 01,2015 TO: Jim Regg P.I.Supervisor i- e f i( 1191 ' SUBJECT: Mechanical Integrity Tests HILCORP ALASKA LLC 44-11 FROM: Johnnie Hill GRANITE PT ST 44-]I Petroleum Inspector Src: Inspector Reviewed By: P.I.Suprv:J-''= NON-CONFIDENTIAL Comm Well Name GRANITE PT ST 44-11 API Well Number 50-733-20059-00-00 Inspector Name: Johnnie Hill Permit Number: 167-070-0 Inspection Date: 3/26/2015 Insp Num: mitJWH150329190449 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 1 as-I1 - Type Inj r N ;TVD 4647 ' I Tubing-- 180 180 Iso Iso1 PTD _ 1670700 1-Type Test SPT Test psi! 1500 IA 475 1600 1600 - 1600 - Interval f4\ TST P/F P ✓ OA 480 500 500 - 500 Notes: SCANNED /-• V ' Wednesday,April 01,2015 Page 1 of 1 Page l of l • • Maunder, Thomas E (DOA) From: Greenstein, Larry P [Greensteinlp ©chevron.com] Sent: Tuesday, October 11, 2011 9:05 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: Lambert, Steve A Subject: 2011 September's GPP 44 -11 Monitoring Report Attachments: Master Well List TIO Report 2011 10 01.xis 1(1 _O Hi Tom & Jim, Here is September's GPP 44 -11 monthly pressure report based on DIO #10, Rule #4 requiring daily pressures be taken on three wells and reported monthly on the 10 -406 injection report. We did the tree servicing on the GPP 44 -11 disposal well and the diagnostic bleed down of the 13 3/8 ". The pressures have separated and remain stable indicating integrity between casing strings...whew! Apparently after the MIT, they just bled down the inner annulus to the same level as the outer annulus. The GPP31 -14RD2 well is still having problems getting the gas lift valves replaced. It remains shut -in. From the attached data, there isn't any indication that the ongoing batch injections into GPP 44 -11 have affected the pressures in either of the other two wells. Larry 10/11/2011 Plot Pressure "late vs Time - Well GP 44 -11 0 1200 . 1200 1000 1000 I � 9 5/8" I 13 3/8" i 20" 800 Tubing r 800 •Vol 44 -11 i i � d IIiI 600 I I� i� �IIi Ii i I 600m ' a 1111 400 _. I -.. 1 1 400 I 200 ' 1 r� zoo nil itt..........iii 0 CO O O • ( �a ' �! F ,1 N O O O Q O O Date 9 5/8" 13 3/8" 20" Tubing" Vol 44 -11 TIO Report 10/01/11 440 320 0 200 0 09/30/11 440 340 0 185 0 Data Sheet 09/29/11 440 340 0 200 0 09/28/11 440 340 - 0 200 0 09/27/11 440 340 0 200 o GP 44 -11 09/26/11 440 350. 0 200 0 09/25/11 430 350 0 200 0 09/24/11 430 350 0 200 o INJECTION 09/23/11 430 350 0 200 0 09/22/11 380 340 0 1020 254 09/21/11 380 340 0 200 o Permit # 1670700 09/20/11 450 340 0 200 0 09/19/11 450 340 0 200 0 09/18/11 450 340 0 200 o API # 50- 733 - 20059 -00 09/17/11 440 330 0 200 0 09/16/11 440 330 0 200 0 09/15/11 450 340 0 200 0 04/01/2011 to 10/01/2011 09/14/11 440 330 0 200 0 09/13/11 450 330 0 200 0 09/12/11 420 320 0 200 0 09/11/11 420 320 0 200 0 09/10/11 420 320 0 200 0 09/09/11 420 320 0 200 0 09/08/11 420 320 0 200 0 09/07/11 420 320 0 200 0 09/06/11 420 420 • 0 200 0 09/05/11 410 320 0 210 0 09/04/11 420 420 0 1019 461 09/03/11 450 310 0 190 0 09/02/11 450 300 0 190 0 09/01/11 430 420 0 180 0 08/31/11 430 420 0 190 0 08/30/11 420 420 0 180 0 08/29/11 420 420 0 180 0 08/28/11 420 420 0 190 0 08/27/11 420 420. 0 180 0 10/11/2011 10:48 AM - TIO Reports 7e.xls J J Dolan Master Well List TIO Report 2011 10 01.xIs GP 44 -11 • • Page 1 of / A Maunder, Thomas E (DOA) From: Greenstein, Larry P [Greensteinlp @chevron.com] Sent: Thursday, September 08, 2011 9:48 AM To: Maunder, Thomas E (DOA) Cc: Regg, James B (DOA); Lambert, Steve A Subject: RE: 2011 August's GPP 44 -11 Monitoring Report Not any good reason I know of, Tom. Turns out that after bleeding off the MIT pressures, the operators put some gas into both the casings to minimize any thermal pressure swings with the intermittent injection. These gas caps could easily have ended up with creating a similar pressure in the casings. That is why we are first going to confirm the tree is properly serviced and then bleed down the casing somewhat to create a separation in the two casing pressures and then monitor the pressures. We will get the results to you after completing these tasks. Larry From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Thursday, September 08, 2011 8:42 AM To: Greenstein, Larry P; Lambert, Steve A Cc: Regg, James B (DOA) Subject: RE: 2011 August's GPP 44 -11 Monitoring Report Larry and Steve, Is there any reason that the pressures should have equalized? Was the IA pressure just bled down to match the OA? Your plan for diagnostics is appropriate. We will look forward to the results. Tom Maunder, PE AOGCC From: Greenstein, Larry P [mailto :Greensteinlp @chevron.com] Sent: Wednesday, September 07, 2011 4:40 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: Lambert, Steve A Subject: : August's GPP 44 -11 Monitoring Report Hi Tom & Jim, Here is August's GPP 44 -11 month : essure report based on DIO ::. d, Rule #4 requiring daily pressures be taken on three wells and reported monthl the 10 -406 injecti. - eport. The pipeline pigging /cleaning has been complete a • uids are now going to the beach. The GPP 44 -11 well is not in much use again and won't be until the er sets in . • • most of the produced water has to be disposed of on the platform. After the recent MIT o, is well, the 9 5/8" an. - 3/8" annuli look like they have equalized. The tree is scheduled for service anS1. •. iagnostic bleed down will be pe ed to see if these pressures indicate a downhole issue or not. As w- " • out more, we will keep you informed. The shut -in well GPP. -14RD2 is having its gas lift valves redone to try to return the well • , oduction. They are having some trot• e with one valve in particular, but hopefully by next month's report this well m. be online again. 10/11/2011 • • Page 1 of 1 Maunder, Thomas E (DOA) From: Greenstein, Larry P [Greensteinlp @chevron.com] Sent: Wednesday, September 07, 2011 4:40 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: Lambert, Steve A Subject: 2011 August's GPP 44 -11 Monitoring Report Attachments: Master Well List TIO Report 2011 09 01.xis Hi Tom & Jim, Here is August's GPP 44 -11 monthly pressure report based on DIO #10, Rule #4 requiring daily pressures be taken on three wells and reported monthly on the 10 -406 injection report. The pipeline pigging /cleaning has been complete and all fluids are now going to the beach. The GPP 44 -11 well is not in much use again and won't be until the winter sets in and most of the produced water has to be disposed of on the platform. After the recent MIT on this well, the 9 5/8" and 13 3/8" annuli look like they have equalized. The tree is scheduled for service and a diagnostic bleed down will be performed to see if these pressures indicate a downhole issue or not. As we find out more, we will keep you informed. The shut -in well GPP31 -14RD2 is having its gas lift valves redone to try to return the well to production. They are having some trouble with one valve in particular, but hopefully by next month's report this well may be online again. From the attached data, there isn't any indication that the ongoing batch injections into GPP 44 -11 have affected the pressures in either of the other two wells. Larry 10/11/2011 , • • Plot Pressure & Rate vs Time - Well GP 44 -11 1200.. _ „a,. - . , 1200 1000 —1 -� - I 1000 800 800 i ,_. v 600 1 !i 600a, l I 400 400 I I I I I I . I is 200. , I n illllll � r 1 1111 ... _ _ \ \ O N N r. N CO o CO CO CO 0 O O 7 0 O 0 O O O Date + 5/8" 13 3/8" 20" Tu ii1 V0 - TIO Report 09/01/11 430 420 0 180 0 08/31/11 430 420 0 190 0 Data Sheet 08/30/11 420 420 0 180 0 08/29/11 420 420 0 180 0 08/28/11 : 420 420 0 190 0 GP 44 -11 08/27/11 420 420 0 180 0 08/26/11 410 410 0 190 0 08/25/11 420 420 0 180 0 INJECTION 08/24/11 420 420 0 180 0 08/23/11 'r 420 420 0 200 0 08/22/11 420 420 0 170 0 Permit # 1670700 08/21/11 420 420 0 190 0 08/20/11 420 420 0 190 0 08/19/11 420 420 0 180 0 API # 50- 733 - 20059 -00 08/18/11 420 420 0 180 0 08/17/11 420 420 0 200 0 08/16/11 " 420 420 0 200 0 03/01/2011 to 09/01/2011 08/15/11 430 430 0 200 0 08/14/11 430 440 0 200 0 08/13/11 430 440 0 200 0 08/12/11 j 440 430 0 220 0 08/11/11 425 430 0 210 0 08/10/11 425 430 0 1019 697 08/09/11 400 400 0 200 0 08/08/11 a 400 400 0 200 0 08/07/11 s; 410 420 0 1001 240 08/06/11 , _° 420 0 220 0 08/05/11 420 0 983 66 08/04/11 420 0 200 0 08/03/11 390 420 0 1030 81 08/02/11 420 420 0 200 0 08/01 /11 !' 400 420 0 1030 343 07/31/11 400 420 0 1020 517 07/30/11 400 420 0 200 0 07/29/11 400 420 0 1040 504 07/28/11 5 400 420 0 200 0 10/11/2011 10:51 AM - TIO Reports 7e.xls J J Dolan Master Well List TIO Report 2011 09 01.xIs GP 44 -11 le • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, June 28, 2011 TO: Jim Regg r- Ree P.I. Supervisor P.I. 7 / ( j 11 SUBJECT: Mechanical Integrity Tests UNION OIL CO OF CALIFORNIA 44 -11 FROM: Bob Noble GRANITE PT ST 44 -11 Petroleum Inspector Src: Inspector Reviewed By: P.I. Supry f NON - CONFIDENTIAL Comm Well Name: GRANITE PT ST 44 - 11 API Well Number: 50 733 - 20059 - 00 - 00 Inspector Name: Bob Noble Insp Num: mitRCN110628070848 Permit Number: 167 - 070 - Inspection Date: 6/27/2011 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 44-11 - Type Inj. N TVD 4647 . IA 60 1680 • 1680 1680 - P.T.D 1670700' TypeTest SPT Test psi 1500 - OA 570 600 600 600 _ _____ Interval 4YRTST p/F P , Tubing zoo 1— 200 200 200 Notes: I lit A,,N _ u i_ 2 .°N 20i: Tuesday, June 28, 2011 Page 1 of 1 . MEMORANDUM TO: Jim ReggÎ<e4V¡' 711~ 07 P.I. Supervisor ( FROM: Jeff Jones Petroleum Inspector Well Name: GRANITE PT ST 44-1 I Insp Num: mitJJ070702092036 Rei Insp Num: Packer Well ¡--¡¡¡¡-lType Inj. i N!TVD P. T.Di 1670700 iTypeTest ! SPT ¡ Test psi Interval 4YRTST P/F P -- State of Alaska . Alaska Oil and Gas Conservation Commission DATE: Tuesday, July 03, 2007 SUBJECT: Mechanical Integrity Tests UNION OIL CO OF CALIFORNIA 44-11 GRANITE PT ST 44-1 1 \~Î/01V Src: Inspector Reviewed By: P.I. Suprv (JE,t2- Comm NON-CONFIDENTIAL API Well Number: 50-733-20059-00-00 Permit Number: 167-070-0 Inspector Name: Jeff Jones Inspection Date: 6/2812007 Depth Pretest -~-----,- 5120 ,IA I 20 I ' 1500 I OA I 560 ì.//~ Tubing ¡ 150 Initial 15 Min. 30 Min. 45 Min. 60 Min. 1560 i 1550 ----rllio~ -+-- I I 600 I 600 i 600 I -r-;-:--~---r 145 . 145 r 145 ¡ i ~ I I -r---~.~~ I I -- Notes: Estimated I BBL water pumped. Platform appeared very clean and in good condition. //--. Tuesday, July 03, 2007 sCANNED JUL 2 0 2007 Page I of I Re: GP 44-11 (PTD #167-070) MIT Update, . Just so we are clear, this is not a substitute for the Commission's witnessed MIT. If you are still interested in performing an MIT early, please advise and I will schedule an inspector. Jim Regg AOGCC Buchanan, Wayne 0 wrote: Mr. Regg and Larry, Our well head technician from APRS just completed the maintenance on 44-11 and we charted the 9-5/8" pressure of 1500 PSIG for 2 hours. Please let us know if either of you would like us to complete anything else. Regards, Wayne Buchanan Granite Point Platform 907.776.6650 SCANNED MA'{ .(), 2, Z007 From: Greenstein, Larry P Sent: Thursday, April 26, 2007 5:05 PM To: 'James Regg' Cc: Buchanan, Wayne 0 Subject: RE: FW: GP 44-11 (PTD #167-070) MIT Jim, As a follow-up to the well maintenance issue with 44-11. The well was shut-in on 4/24/07 and will remain shut-in until the tree maintenance can be performed. This well is used very sparingly throughout the summer and more frequently during the winter months to handle the produced water from the GPP. During the summer months, the water can usually be sent to the beach for processing and doesn't need to be injected on the platform. Wanted you to know our plans for this well. Thanks Jim. Larry From: Greenstein, Larry P Sent: Wednesday, April 25, 20073:02 PM To: 'James Regg' lof3 4/30/2007 8:44 AM Re: GP 44-11 (PTD #167-070) MIT Update, . Subject: RE: FW: GP 44-11 (PTD #167-070) MIT . Thanks Jim, Never saw this one before. Guess the pipeline guys did one for pigging purposes and never let me know. I'll have the platform delay this well until next year. All looks good with the pressures on the well for now, so no need to test early and reset the clock. Along these lines, you requested us to use the Admin Approval date to time out the two year compliance temperature surveys for some of our wells. If we do the temp survey a month early and still use the AA date for the next test, the one month early test doesn't reset the clock for the AA wells. Can't we do something like this for the standard MIT wells also. Pick a date (like the last MIT) and if we do it a month or two early, it doesn't reset the clock, it just means we did it a little early for convenience sake. We can still use the first MIT date for the 4 year cycle. Both types of wells (AA and standard MIT) are getting daily monitoring, the only difference is that I send you a report once a month showing you the plots of the pressures on the AA wells. But both are being watched and would have immediate responses should any of the pressures or rates go awry. I'm just thinking out loud Jim. Let me know what you think when you get a chance. Larry From: James Regg [mailto:iim reqq@admin.state.ak.us] Sent: Wednesday, April 25, 20072:15 PM To: Greenstein, Larry P Cc: Buchanan, Wayne 0; Myers, Chris S; Waski, John; Dorman, Allen; Medley, Ted J; Lambert, Steve A; Louis R Grimaldi Subject: Re: FW: GP 44-11 (PTD #167-070) MIT Not a problem delaying the MIT until next month; our records show Lou witnessed a passing MIT on 10/3/2004 (attached) - that would make the next MIT due 10/3/2008. Jim Regg AOGCC Greenstein, Larry P wrote: Jim, The MIT for GP 44-11 (PTD# 167-070) is due in June of 2007. Since we had the inspector (Lou Grimaldi) out there doing some wellhead SVS work, we thought we'd get the MIT done a little ahead of time, if it fit into his schedule. Turns out, the guys wanted to do some tree maintanence prior to testing, so they asked Lou to skip the well on this visit and they'd schedule him out another time (next month) to complete the MIT. I'll bet Lou thought that this would then make the MIT late and wanted us to notify you of this. As you can see, the MIT will not be late even if it is done the month after next, but I wanted to honor Lou's request to the operators to make you aware of this change in plans. Let me know if you need anything else from us. 20f3 4/30/20078:44 AM Re: GP 44-11 (PTD #167-070) MIT Update, . Larry . From: Buchanan, Wayne 0 Sent: Wednesday, April 25, 2007 12:25 PM To: Greenstein, Larry P Cc: Myers, Chris S; Waski, John; Dorman, Allen; Medley, Ted J; Lambert, Steve A Subject: 44-11 Larry, Please write Jim Regg with the state at "iim reç ç (Q¿admìn.state.ak.us" and request a postponed MIT for 44-11. I spoke to Lew Grimaldi about our need to complete some well head maintenance this coming Fri., but Lew said J. Regg requires a request via e-mail asking for a delayed witnessed inspection. You mentioned some specific language to be included in the request............. All the 180 day witnessed well safeties passed this morning for the 8 producers. Thank you, Wayne Buchanan 30f3 4/30/2007 8:44 AM 3 ~1r 413tjò7 \ ~ó ~ ~ ------ r¿~ ...----:.......ç:e-t:: ~"\~~~~gt~J::+900 "/ " ./ :::-: /:: _ L--- ./ ~ _vL--t---1.--- " / ~ :::: ::::: :::l::::~c::: .-, 800 'y'X y;::::./ l-- ex y v;:::::=---l---C:: ~ t::t::~çt::: __100 ,~y t;:vt::¡..--I--- -,-/ e,>" " X ___ ---i:::L-- -, --, -r -y -X e X X' Y ---':::>--\-- ;:::600 ....,. 'Y yX X ___ t:: '-I- -I- ~~~y \2;::~~OO +d Y J(:ç>;, y yC \:: ~ TT ~ ~ J X 0,.;z~~ :.9Q /VVyyy'Y Ýv:::rr ~ ~~ V ~''kX y t CkO ~V--'" ^ '" < ~~.W6 ioi ÕT~~ "", "" ~<Þ cVX/> ">V >?;;><; ~ II -¡- --f.- 7--.t ~ ~ Y< \& ~V:;:v:;j'X5< >¿ zoO "'1fH j "'-.~6¿§i§:<'0 ~,,\ '( ~ \ \ O'~ .; > ' Y'Y'YV,?>X y-l" _ tfH >-I.1E7:7:r;J;ZY'X X'0 ""\ ~ '"' :» M" \, )O,~?)VVV:V~ ~ ~ %¿t> ~~~\M \~\ ~ \ N Ii "^ "F'" " t:h Y1 % 'b'é)< ~ "" # ~0® \ '\\ \ \c,1 .0 · "~~"':¿~ !5 '" ,'''" =/B"o." ~ ><" g:' ~\ ~ \\\\\'\' \\ \ 'f/'> (" '" -"- ~~, {o. 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T ~::L-----' _.-1yY'Y Y-. 'I- 009 T -\::::.-- ---....... 0°1,,; "-,( ~ c:::r:::¡:::::':::--- tg~ ::::\::::::t:C::-~ ::..-y·x"y R> J-I- ¡-1- L_J---I-':. .-- -- Y Y xo<::i ~/_ ~~~~~~'~~x 00& . t:c--vv7~'X')( ~ ~ --, :::::::~[:::::~::::: ~~J)b 00 .:t- --I f:3:::t T -- _¡::::..v v'~ y ~ . ' .~V~V~~ _ ~ ~ __ c~+ ,cO t: Sl::-¡:::t:{:;v cy, y b ..¡ ~ è!/ C:::l--/r/I-"Y~ /" ~ T ~~~~ ~ ~I\'~ 6 /~ c;. ôç,~~'>- íII, 9~ -=£=~= -=:6;: ~9 ,,"4 ! -' 9 . 6~ . :¡: ~ -..;;;: 9 ~ / +- ~ ~,~~ .~ ~~ ~6' ~ ~ , -+- 7' -I-. -.<... -..,<... -....,z -¡- ....,¿ "-j- ,-I- ¡- .:j:-:i- S> ·\9ú ~ -E:> ~-f J.. / VAIa 1fJ' ~\ :;c. .. "-X MEM 0 RAND UM State of Alaska Alaska Oil and Gas Conservation Commission TO: ~~s~:~sor ~~1IoHo~ DATE: Tuesday, October OS, 2004 SUBJECT: Mechanical Integrity Tests UNION OIL CO OF CALIFORNIA 44-11 GRANITE PT ST 44-11 FROM: Lou Grimaldi Petroleum Inspector Src: Inspector Reviewed By: P.I. Suprv ~£- IO Jl IJt\ Comm NON-CONFIDENTIAL Well Name: GRANITE PT ST 44-11 API Well Number: 50-733-20059-00-00 Inspector Name: Lou Grimaldi Insp Num: mitLG0410O4132852 Permit Number: 167-070-0 Inspection Date: 10/3/2004 Rei Insp Num: , Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 44-11 Type Inj. P TVD 5120 IA 70 1600 1590 1590 P.T.D 1670700 TypeTest SPT Test psi 1280 OA 370 400 410 410 Interval OTHER PIF P Tubing 110 110 110 110 Notes: Test required for pigging operations Tuesday, October OS, 2004 Page I of I ,. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Randy Reudrich '~'/?~ DATE: June 17, 2003 Commissioner --~ THRU= Jim ~Regg P. I. supervisor FROM: Jeff Jones Petroleum Inspector NON- CONFIDENTIAL SUBJECT: Mechanical Integrity Tests Unocal Granite Point Platform 44-11 Granite Point Field Packer Depth Pretest Initial 15 Min. 30 Min. I we,IIType, i.I N I T.v. .I I I 4I P.T.D.I 1670700 ITypetestl P ITestpsiI 1251 I Casingl 240 I 1600 I 4600 I 46001 P/F I _P I Notes: Produced water disposal well I j' Type INJ. Fluid Codes F = FRESH WATER INJ. G = GAS I NJ. S = SALT WATER INJ. N = NOT INJECTING Type Test M= Annulus Monitoring P= Standard Pressure Test R= Internal Radioactive Tracer Survey A= Temperature Anomaly Survey Interval I= Initial Test 4= Four Year Cycle V= Required by Variance W= Test during Workover D= Differential Temperature Test O= Other (describe in notes) Test's Details June 17, 2003: I traveled to Granite Point Platform in Cook Inlet to witness a Mechanical Integrity Test'(MIT) on Unocal's produced water disposal well 44-11 in the Granite Point Field. Stewart Allison was the Unocal representative for the test today, which was performed in a safe and proficient manner. The pre-test pressures were monitored and found to stable. The standard annulus pressure was then performed and well 44-11 met the AOGCC criteria for a successful MIT. Summary: I witnessed a successful MIT on Unocal's Granite Point Field disposal well 44-1 Ion the Granite Point Platform in Cook Inlet. M.I.T.'s performed: 1_ Number of Failures: 0 Attachments: 44-11 Wellbore Schematic (1) Total Time during tests: 2.5 hrs CC: MIT report form 5/12/00 L.G. 2003-0617_MIT_Granite Pt 44-1 lij.xls 7/9/2003 From: To: Jim Re~ Date: 6/20/03 Time: 11:01:12 PM , .....::.: :.:. :.....:.../?:" i' i.:'..' ';.'.' ::f;.'..:.?: :..:'.' :'. ?..::. :..:ili').:.~.~i~)~!~.~'~ ~qlS~:rc.';'.' :!.'/.,':'. ii! .:'/? : ;.f i'?.' '.'.:..:.' :'-.' '.: :': ..'.'. :':. '.' ':".': .'.';: :?' :..':..: :":"" :.' .:. '..: :.:::'.. i.'~)'i ~!i~.~ ;~:.:" ~ ~ ?,~ ~.~;:'e..¢~i ~.. i' '": :'. :'.'.. " ...... ' "':. 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'.:' ? x::i? ,:: ?; :. ::'.:. ::d: ::/: ::.L..?.: .. ?; i.!:"', i ?i.:..:'.:'.:::::'.::.'.~i {?i ::'i. i.i:'::::! ~....:.. :.:...:..:.....................:::.:. :...:......:.... :.:: :.:: ::..:~ ~.': ::.::..'..".:.':~:'.':.:?'.:'~':~.i;~,i':~,"i::'i!' i':' !.! :'. i'.::.:'i i"!.:::':: :":: :': ;'~'::!/::. :: i?;.:.~;{: }./:: ::: :'/:: :':'~ i'i ::;: :. :?:' ;:::: ::{: !i:::? :;/. ::' i:; :'. ;::':; ;:::!/: ?: ?::/:: ?;;::'; :.!'~i~: ;/i'i :: !i. i'..'.!' :~.i~:~:~:.~::~::~.:.:~:~:i~?.!:~:~i~::~:~...:....i.i!.~:~i~:~.~.~:.:..:....:..:.:~:~.:..:::.i~.~:~!~:~:/i~.~i~:~!~!:~!~i~:~!:~::~..:f~::.~.i~.!~....~.::~:~:.....:...~.::.:.....~:.!.~:....:~:.:~:.:..::.:.:?:?~:7:Z::~:::~:}?i:.:f~`!::::.::;:!/::.:!!i:;:?.!Zf::.!??/?:.!:.: ".::'i "":~g !, ,';<~nducto,, 2. I":'.i~ ~,~r,'~,,.-~0~ i DFiAWN: CL.L Page 2 of 2 Ji~N-13-98 TUE 16:11 UNOORL RSSET GR$ GRP · NO, 9072637874 t RPM ~ RPM - F. U2/U2 UI4d M,Ik. i, I S.! WO Iff t Llngl~: fl~lll¥ll WT. J~ilrlq ~ ........ COST I~lltlflt ~I._ - .... Unocal Corporation ! P.O. Box 196247 Anchorage, Alaska 99519 907-263-7676 UNOCAL G. Russell $chmidt Drilling Manager Wednesday, Janua~ 03,1996 Mr. Blair Wondzell AOGCC 3001 Porcupine Drive Anchorage, AK 99501 Dear Mr. Wondzell: GP 44-11 As requested, attached is one copy of the Cement Evaluation Log for the subject well. If you require further information, please call at 263-7676. Sincerely, G. Russell Schm~dt Drilling Manager Attachment GRS/leg cc: GP 44-11 Well File D20-15-95 FRI 02:49 PM UNOORL RNORORRGE !. . FRX NO, 907 263 7884 P, 02/08 ; .. OIL A~D ~ CONSERVATION COMI~,,~ON . "' .', REPORT .OF' S,'UND.RY WELL OPERATIONs. ____ 4: . &'l' , Pull ~ ..... N~r o~ing.~ . '~r ~l Pull ~ng,X ' ~er:... ' '. ' ',. ' 2'N~e'of OPerat~ .......... '5..TY~ ~WelJ~ ...... 6~ Datu'm ele~n (DF.or ~) 'Un~ Deve~p~.. . : : .... . ....... ~.... ~~ -. ~05' ~ ' ' ' feet _:_::.p,0, ~x 196247 A~ra~e, A~' 995 :4~:. ~nofw~ilatsu~ O~nlmPt, Pla~'Leg~l,~nd~r~ .. 8:Well'n~ .,..' . '" ' "23~ ~ & I~1' E F/NW ~rn, Sec,13, T10N, Ri 2W ~,M. , ~- 11 AD L i 876~ :.. Ai ~p Of prod~t~ i~e~ '. -'e.'Perm~ n'Um~/appr~l ~u~ber I.'. · ~7-701 ', ', ,, . " 5o-~3-~g, ~t'~l'de~ 11. Fiel~l: ' , , ',, ',,. Gr~ite ~, / M~dle' Ken~ , ..i"2:""~re~m w~l ~ndltion summ~ ............ . ...... . . .~.. Tqtal..depth: me~ured . 1~ . feet Plu~ (me~ur~ " . .. true ~al 1 l~a feet ' . .. ', '. . ~ .... Eff~t~e depth: me~ured ' '1.~16 feet Junk (me~ure~ TOO ~ 7591' '. . ..' . , ,. .. tr~ ve~c~ 1~55 feet ,. , .. ~lng Len~ S~e Oemen~ Me--uteri de~ :' TrUe ~Aiom de~h ,.'. ,' , , .' Structural "' . . .' ,', , '~nouotor 310~ ~ Dr~O~ed 310' 5: ': · ,, , , , , . ., ~u~e ~9' lg 5~ ~ ~' :. .. ', . . ,. ., '~.." l~rm~iate 40i9' ' 13-3/~" ~ 4019' ' ..' 3~0" ' P<duction 7962' 9-5/8" 1~ 796~' " '~28'0"' . . ' .' : '". Pe~ation depth: me~rod , '', . , . . , , true ~lc~. ' , . ,. ::' .~ ' ,' ', ~. , 'P~m ~d SS~ '.", ' , "~-<C 7~,,~ :'~3~' ~muiat~n or ~ement squeeze summ~ .............. ~-~?~.~,~ ~ ':'-::-- ," . . ~ t.;,~,~.~, ~ ~t,~,.,= ..... . , : ' , . . . '. ',, . ....... . , ' " :, ~4; R~mm~t~ D~ A~r~e Pmd~n or lnj~ D~ '" ' ' "' · , .. ' .P'r~r't0 well o~r~n " NA .. . ', ,. · . . . , . ' su~em ~pe~n ~ .. ' ~es ~ ~ ~u Su~ mn " : · .. : :.Form ..!0~-404 Rev06/15/88 ~ ~., · . "..N'UBMrTIN DUPLIGATE .. -. DE0-15-95 FRI 02:50 Pti FRX NO, 907 263 UNOCRL RNCHORRGE 7884 P, 03/08 26' Structural @ 310' ~ 8' Surface @ 43g' 71#, Grd-B, Vet¢o DV Collar @ ~2'/' 13-3/8' Irltermedh~e @ 4019' 61~', J-55 TOC @ 5000', partial cement above to. 2700'. 'Existing Perforations: 5480'-5480' DIL ~ 6 spf 90.deg. phasing Max Dev. = 28.3 d~g @ ,56O0' .' .... Cement Plug 7591'-7935' · 'BP @ 7935' Cl'M . ,, 11~-11~ ~ ~1~ .. Granite Point Fie{d;.Weli ¢44~.11 ~, API:SO-733-2Q05g; ADL 18761 Leg 1, Conductor 2, KB eiev-~105-'. ~. DisPOsaI Well Granite Pt. #44-11 I I UNOCAL ENERGY RESOURCES ALASKA' comple~ ,i~n Equipment: · i) 34'/2' 9.2.~ Leo sClC 2) Baker'FH' 51A4,Paeker @ 5004' ':~ ~ .Nip~ @ 5048' 4) W, imline entry guide @ 5081' DEO-15-95 FRI 02:50 PM UNOCAL ~NOHOR~%GE F~X NO, 907 263 7884 P, 04/08 GRANITE POINT HISTORY WELL 44- 11 .' ,, DAY 1 .'3 '(06/16/95 -;06/18/95} OFFLOAD..EQU!pMENT FOR WORKOVER. RIG UP COILED TUBING UNIT. REMOVED,ABANDONMENT FLANGE FROM WELLHEAD. INSPECTED SAME. NIPPLED UP ALL RISER EQUIPMENT AND 13 5/8' BOP'S:'SERVICE'D'AND INSTALLED ACCUMULATOR LINES. " FUNCTION.TESTED ALL GATE VALVES. INSTALLEDAND TESTED SHAKER :, DAY 4 (06/i9/95) ' . ",' M/U LANDING jOI, NT,AND DOWELL LINES. HELD SAFETY,:MEETING. ATTEMPTED TO TEST, 3 1/2" PIPE RAMS. NO TEST. PULLED TUBING HANGER AND RANN.EW HANGER WITH .TWO,WAY CHECK' VALVE IN PLACE.'PRESSURE TESTED ALL GATE VALVES. PULLED 'TUBING HANGER PRESSURE TESTED DOWELL COIL TUBING STACK' ON TEST RACK. STABBED COILED TUBING INJECTOR HEAD AND M/U CONNECTOR (WASH NO?TLE INSTALLED). SHUT DOWN FOR THE NIGHT.' " ' " ' ,, DAY 5 (06/20/95)': RU"1-314~ CT &,INJ HEAD. FILL TBG W/FIW &PRESS.TEST. STRIPPER& CONNECTIONS TO 1500 PSI,,OI~ RIH TO. 1000:, BRK ClRC AT 1.75 BP,,M & MONITOR RETURNS' OF 9 PPG 'BRINE. CONT RIH,WASHING DN TO 7950'. ClRC WELL & POOH. FLuID'RETURNS OF,10.5,PPG MUD.' CONT POOH, SECURE WELL & SUSPEND OPS AT 2100HRS. ' , '., DAY.6 (06/21195) . MU CT .CONNECTOR...& TEST SAME, NEG. CUT OFF & REDRESS SAME. RE-.TEST'CONNECTOR, Oi~ MU 8-1/2.". BIT & .9-5/8" CSG SCRAPER..RIH;TAG.TOL AT 7869' WHILE ClRC AT 2 'BPM.. ',POOH WHILE cIRC. 'SECURE WELL & SUSPEND OPS AT 2200'HRS; DAY 7 (,06/22/95) , RUscHLuMUNIT. 'WAIT ON USIT LOGGING TOOL.. TOOL IS BEING REPAIRED F/PREVIOUS JOB ELSEWARE. · . .. · · .. ... DEC-15-95 FRI 02: 50 PI1 UNOCAL ~NOHOR~GE FRX NO, 907 263 7884 P, 05/08 GPP WELL #44-d 1' PAGE 2 DAY 8"i0 (06/23-25/95) ; MU USIT TOOL & RIH; .LOG W/CSG INSPEC & C'MT EVAL F/7800" TO SURFACE. ,RU,ON WL W/5.7" GAUGE RING & JUNK BASKET. R!:H, TO 7940' WLM: · POOH. 'MU 7." BP ON WL, RIH & SET S. AME AT: 7935'.. POOH'::,i RIG DN SWS.'RU 1.75" COILED TBG &'iRIH TO '7935'.' M&P 25 BBLS CMTEQUALIZE SAME. ClP AT 1749 HRS,:ON 6-24-95.',,,POOH. WOC. :.RIH'W/CT TO 70.00'. PRESSURE TEST CSG TO 2000PSi F/30 MINS, OK RIHi TAGGED,TOC AT 7591'. POOH'TO 640,0'. DISP:L' WELL TO 8.4 PPG .FIW &'MONITOR SAME. RIG DN DS !NJ'HEAD, ' BOP & MISC EQUIP. ', " · . DAY 11'. (06/26/9,5) ,, · , , WAITED ON BOAT TO BACKLOAD EQUIPMENT.,.'DuE'T0.'BAD' WEATHER~. BACKLOADEDM/V MONARCH WITH DOWELL COIL'ED'i TUBING EQUIPMENT. COMPLETED BACKLOADING,AT24.00 HRS.," DAY 12 (06/27195) , ,. ' CLEARED WEST DRILLDECK. OFFLOADED DOwELL EQUIPMENT AND TUBING. BEGAN:'RIGGING UP DOWELL JACKING ·BASE. ', , ,, DAY 13.(06/28/95) ,, '., . . , . FINISHED RIGGING Up'DOWELL JACKING UNIT. SUBBASE AND JACKING UNIT,. PRESSURE TEST BOP'S. PJU .CASING RUNNING . EQUIPMENT, PREPARE TO RUN ,3-1/2" TUBING AND BAKER,.' ' EQUIPMENT. ,. .. DAY 14 (06 ./29/95)' ' · HELD SAFETY MEETING., RAN 3-1/2" TUBING COMPLETION ,,T©,. 5081'. 'TOP OF,PACKER AT 5004'. LAND HANGER AND SCREW TIE DOWN,PINS INTO HANGER. CIRCULATE AND SPOT A 20'BBil PILL OF BAKER CT9071 PACKER FLUID DOWN TUBING.',. SET 2, wAY' VALVEAND TEST HANGER SEALS TO 3000 PSI. M/IJ LANDING · JOINT AND DROp'BALL TO SET PACKER. PRESSURE,UP TO 3800' PSI, SHEAR OUT AND SET:PACKER AT 5004'. TEST PACKER TO., 3000 PSI AND START PJD EQUIPMENT. START BACKliOADING · EQUIPMENT TO BOAT.. ' ..' . · , .. · · ,_., ..., .~ .~" · . ,. D£O-16-95 FRI 02: 51 PM UNOOC~L ~NOHORRGE ' "! ".GPP WELL itf.44-11 ., ',"PAGE 3 DAY 15-16 (06/30,07102/95) FRX NO, 907 263 7884 REM DS EQUIP &.BOPE,.' NU 3't/8" 5M TREE. TEST HGR SEALS & TREE TO 5M, OK. PERFORM MIT ON ANNULUS TO 1':500, PSI, F/30' MINS, OK, RU SWS,,,TEST LUB TO 4M, OK. RIH W/CCL &,2~.1f8" ENERJET GUNS '(90 DEG PHASE AT 6 SPF). PERF 5460"54S0' 'D!L." POOH. RD SWS & R.U DS,PUMP. PERFORM INJ TEST W/FIW. aRK DN PERFS Wi1700 PSIAT 0.5 ,BPM. CONT INJ TEST,' TO'MAX RATE AT 4,5 BPM W/2490 PSI,:',RATE LIMITED TO PUMP SKID. SECURE WELL & RD.DO ,W, ELL. EQUIP.' OFFLOAD DOWELL EQUIP '& CLEAN. DRILL DECK, LAST REPORT. ,, -, ?, 06/08 DE0-15-95 FRI 02: 51 PYI UNOOt~L 6NOHORt~GE ; NO, 907 263 7884 P, 07/08 DEC- 15-95 FRI 02: 51 Pti UNOOt~L.¢NOHORi~GE FfiX NO, 907 262)7884 ,, ', ,, ,' , ,. ; , . ~, ~: ~ ...... ... ~ ~. ~ '~, ..... ' STATE OF ALASKA AL/-~~ OIL AND GAS CONSERVATION COMI, ",JiON\ REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown __ Stimulate __ Plugging __ Pull tubing __ Alter casing__ Repair wail __ 2. Name of Operator 15. Type of Well: Unocal I Developmen__ Exploratory __ 3. Address Stratigraphic__ P.O. Box 196247 Anchorage, AK. 99519 Service x _ 4. Location of well at surface Granite Pt. Platform Leg #1, Conductor #2 2360' S & 1261' E F/NW Corn. Sec.13, T10N, R12W S.M. At top of productive intenral At effective depth DUPLIOATE At total depth Perforate X Pull tubing X Other 6. Datum elevation (DF or KB) 105' KB feet 7. Unit or Property name Mobil-Union State #1 S. Well numbe~_.,~,J 44-11 ADL 18761 9. Permit number/approval number 67-70 / 95-070 10. APl number 50-133-20059 11. Field/Pool Granite Pt. / Middle Kenal 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Structural Conductor Surface Intermediate Production Liner Length 310' 439' 4019' 7962' 4336' Perforation depth: measured 12208 feet Plugs (measured) 11343 feet 10916 feet 10055 feet Junk (measured) TOC @ 7591' Size Cemented Measured depth 26" Driven/Grouted 310' 18" 540 sx 439' 13-3/8" 2400 sx 4019' 9-5/8" 1800 sx 7962' 7" 550 sx 12208' See a~achedschem~ic True vertical depth true vertk~al Tubing (size, grade, and measured depth) Packers and SSSV (type and measured depth) 3-1/2", 9.2#, L80 @ 5081' 3770' 7280' RECEf D JUL 1 7 1995 0il & 6as Cons. Commission Anchor~..;;~ 9-5/8" Baker "FH" @ 5004', No SSSV installed. 13. Stimulation or cement squeeze summary . Intervals treated (measured) See attached well history Treatment description including volumes used and final pressure 14. Prior to well operation Subsequent to operation Representative Daily Average Production or Injec~n Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure NA Tubing Pressure 15. Attachments Copies of Logs and Surveys run__ Daily Report of Well Operations x _ 16. Status of well classifK~ation as: Oil __ Gas __ Suspended 17. I hereb~pe~v that the forego'?g is true and correct to the best of my knowledge. , . Title "~tL.k.t ,-q~,. '~'~ A~C,~C--~ Form 10-404 Rev 06/15/88 SUBMIT IN DUPLICATE f, ~.26' Structural @ 310' 18 Surface @ 439' 71#, Grd-B, Vetco DV Collar @ 2227' 13-3/8' Intermediate @ 4019' 61#, J-55 Completion Equipment: 1) 3-1/2" 9.2# L80 SCB'i'C 2) Baker "FH" 51A4 Packer @ 5004' 3) 'X" Nipple @ 5048' 4) Wireline entry guide @ 5081' TOC @ 5000', partial cement above to 2700'. Existing Perforations: 5460'-5480' DIL @ 6 spf 90 deg.. phasing Max Dev. = 28.3 deg @ 5600' Cement Plug 7591'-7935' TOL 7' ~ 783'1' BP @ 7935' CTM e-s/a' O 7~ea' 4o-4a.~ Nlm. LTC ~ (40~ F/'/e'-SaS,3'; 4,3.S~ F/5253-7962') C4rne~ Plug 109t6'-11015' 111S0'-1115t' W'~IO 8QZ 11230'-11246' Peri 11275'-t 1290' Perf BP 0 11330' 11400'-1140t' YVSO 8QZ 11520'-11610' Per/ 11~8~'-11706' Pet/ !~ {} 12148' 7' 2~P LeO X4ne ~ 1220e' RECEIVED JUL 1 7 1995 N~s~ Oil & Gas Cons. Commission Granite Point Field; Well #44-11; APl 50-733-20059; ADL 18761 Leg 1, Conductor 2, KB elev= 105' Disposal Well Granite Pt. #44-11 UNOCAL ENERGY RESOURCES ALASKA DRAWN: CLL DATE: 7-5-95 FILE: GP4411B.drw GRANITE POINT HISTORY WELL 44- 11 DAY 1 - 3 (06/16/95 - 06/18/95) OFFLOAD EQUIPMENT FOR WORKOVER. RIG UP COILED TUBING UNIT. REMOVED ABANDONMENT FLANGE FROM WELLHEAD. INSPECTED SAME. NIPPLED UP ALL RISER EQUIPMENT AND 13 5/8' BOP'S. SERVICED AND INSTALLED ACCUMULATOR LINES. FUNCTION TESTED ALL GATE VALVES. INSTALLED AND TESTED SHAKER. DAY 4 (06/19/95) M/U LANDING JOINT AND DOWELL LINES. HELD SAFETY MEETING. ATTEMPTED TO TEST 3 1/2' PIPE RAMS. NO TEST. PULLED TUBING HANGER AND RAN NEW HANGER WITH TWO WAY CHECK VALVE IN PLACE. PRESSURE TESTED ALL GATE VALVES. PULLED TUBING HANGER PRESSURE TESTED DOWELL COIL TUBING STACK ON TEST RACK. STABBED COILED TUBING INJECTOR HEAD AND M/U CONNECTOR (WASH NOZZLE INSTALLED). SHUT DOWN FOR THE NIGHT. DAY 5 (06/20/95) RU 1-3/4' CT & INJ HEAD. FILL TBG W/FIW & PRESS TEST STRIPPER & CONNECTIONS TO 1500 PSI, OK. RIH TO 1000', BRK CIRC AT 1.75 BPM & MONITOR RETURNS OF 9 PPG BRINE. CONT RIH WASHING DN TO 7950'. CIRC WELL & POOH. FLUID RETURNS OF 10.5 PPG MUD. CONT POOH. SECURE WELL & SUSPEND OPS AT 2100 HRS. DAY 6 (06/21/95) MU CT CONNECTOR & TEST SAME, NEG. CUT OFF & REDRESS SAME. RE-TEST CONNECTOR, OK. MU 8-1/2' BIT & 9-5/8' CSG SCRAPER. RIH, TAG TOL AT 7869' WHILE CIRC AT 2 BPM. POOH WHILE CIRC. SECURE WELL & SUSPEND OPS AT 2200 HRS. DAY 7 (06/22/95) RU SCHLUM UNIT. WAIT ON USIT LOGGING TOOL. TOOL IS BEING REPAIRED F/PREVIOUS JOB ELSEWARE. R E ¢ ~ IV E D JUL 1 7 1995 At~s~ 0il & Gas Cons. Commission Anchor~ ? GPP WELL ~1.4-11 PAGE 2 DAY 8-10 (06/23-25/95) MU USIT TOOL & RIH. LOG W/CSG INSPEC & CMT EVAL F/7800' TO SURFACE, RU ON WL W/5.7" GAUGE RING & JUNK BASKET. RIH TO 7940' WLM. POOH. MU 7" BP ON WL, RIH & SET SAME AT 7935'. POOH. RIG DN SWS. RU 1.75" COILED TBG & RIH TO 7935'. M&P 25 BBLS CMT EQUALIZE SAME. CIP AT 1749 HRS ON 6-24-95. POOH. WOC. RIH W/CT TO 7000'. PRESSURE TEST CSG TO 2000 PSI F/30 MINS, OK. RIH, TAGGED TOC AT 7591'. POOH TO 6400'. DISPL WELL TO 8.4 PPG FIW & MONITOR SAME. RIG DN DS INJ HEAD, BOP & MISC EQUIP. DAY 11 (06/26/95) WAITED ON BOAT TO BACKLOAD EQUIPMENT DUE TO BAD WEATHER. BACKLOADED MN MONARCH WITH DOWELL COILED TUBING EQUIPMENT. COMPLETED BACKLOADING AT 24.00 HRS. DAY 12 (06/27/95) CLEARED WEST DRILLDECK. OFFLOADED DOWELL EQUIPMENT AND TUBING. BEGAN RIGGING UP DOWELL JACKING BASE. DAY 13 (06/28/95) FINISHED RIGGING UP DOWELL JACKING UNIT SUBBASE AND JACKING UNIT. PRESSURE TEST BOP'S. PJU CASING RUNNING EQUIPMENT. PREPARE TO RUN 3-1/2" TUBING AND BAKER EQUIPMENT. DAY 14 (06/29/95) HELD SAFETY MEETING. RAN 3-1/2" TUBING COMPLETION TO 5081'. TOP OF PACKER AT 5004'. LAND HANGER AND SCREW TIE DOWN PINS INTO HANGER. CIRCULATE AND SPOT A 20 BBL PILL OF BAKER CT9071 PACKER FLUID DOWN TUBING. SET 2 WAY VALVE AND TEST HANGER SEALS TO 3000 PSI. M/U LANDING JOINT AND DROP BALL TO SET PACKER. PRESSURE UP TO 3800 PSI, SHEAR OUT AND SET PACKER AT 5004'. TEST PACKER TO 3000 PSI AND START R/D EQUIPMENT. START BACKLOADING EQUIPMENT TO BOAT. JUL 1 7 ~995 k~,~,sk~ 0ii & Gas Cons. Commission Anchor~ :i., ~ GPP WELL #44-11 PAGE 3 DAY 15-16 (06/30-07/02/95) REM DS EQUIP & BOPE. NU 3-1/8" 5M TREE. TEST HGR SEALS & TREE TO 5M, OK. PERFORM MIT ON ANNULUS TO 1500 PSI F/30 MINS, OK. RU SWS, TEST LUB TO 4M, OK. RIH W/CCL & 2-1/8" ENERJET GUNS (90 DEG PHASE AT 6 SPF). PERF 5460'-5480' DIE POOH. RD SWS & RU DS PUMP. PERFORM INJ TEST W/FIW. BRK DN PERFS W/1700 PSI AT 0.5 BPM. CONT INJ TEST TO MAX RATE AT 4.5 ~BPM W/2490 PSI, RATE LIMITED TO PUMP SKID. SECURE WELL & RD DOWELL EQUIP. OFFLOAD DOWELL EQUIP & CLEAN DRILL DECK. LAST REPORT. JUL ] 7 't995 0il & Gas Cons, Commission Anchor~ ? PACR aux. P~essu~e mox: 1~ P~! ¢o~ 10 V ~X.2 moxtmMm : I~ ?0~ 1~ V =~x.2 minimum : · ~o~ 0 V volume ts com~uteO ?~om : Scan ~e~o~ (Sec) : RECEIVED ~'~ '=", JUL 1 7 1995 I '~taska Oit & Gas Cons. Commission Anchor~ ? I ! STATE OF ALASKA · I ~S ~ OIL AND GAS CONSERVATION C('' 'i~ISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of request: Abandon _ _ Suspend __ Operations shutdown __ Re-enter suspended wellX_ Alter casing__ Repair well __ Plugging ~ Time extension __ Stimulate __ Change approved program ~ Pull tubing_ _ Variance ~ Perforate m OtherX_ 2. Name of Operator 15. Type of Well: 6. Datum elevalion (DF or KB) Development _ UNION OIL COMPANY OF CALIFORNIA (UNOCAL) Exploratory __ KB 105 feet 3. Address Stratigraphic ~ 7. Unit or Property name P.O. BOX 196247 ANCHORAGE, AK 99519 Service X_ Union-Mobil State #1 4. Location of well at surface Granite Point Platform, Leg #1, Slot 2. 8. Well number 2360' S & 1261' E F/NW Corner Sec. 13, T10N, R12W,~ME (~ E ~V E D 44-11ADL-18761 At top of productive interval . 9. Permit number 67 -70 At effective depth APR'~ 0 '~995 10. APl number 50-133-20059 At total depth AJ~[~ 0il & Gas Cons. Commission 11. Field/Pool 3206' N & 2109' W of surface location ]l~ff, liora;~, Granite Pt._/Middl~..KeE~].,, ,.., - _~'"']i ;' '; : · - '' I ! 12. Present well condition summary ,, ,1 ,, ,, · -IL, Total depth:true measured vertical 1122081343 feet feet Plugs(measured) [~~L! GPNAL Effective depth: measured 10916 feet Junk (measured) TOO plug @ 10916' true vertical 10055 feet Casing Length Size Cemented Measured depth Structural Conductor 310' 26" Driven/Grouted 310' Surface 439' 18" 540 sx 439' True vertical depth Intermediate 4019' 13-3/8" 2400 sx 4019' 3770' Production 7962' 9-5/8" 1800 sx 7962' 7280' Liner 4336' 7" 550 sx 12208' 11350' Perforation depth: measured See attachment true vertical Tubing (size, grade, and measured depth) None in the well Packers and SSSV (type and measured depth) None in the well 13. Attachments Description summary of proposal X_ Detailed operations program_ _ BOP sketch X_ 14. Estimated date for commencing operation I15. Status of well classification as: June 1, 1995 16. If proposal was verbally approved Oil _ Gas __ Suspended __ Name of approver Date approved Service Injection of non-hazardous oil r~ld wastes 17. I her.eby certify that the foregoing, isi~rue and q. orrect to the best of my knowledge. Si~,......~/"G. Russell Schmid Title Drilling Manager Date March 31~ 1995 FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Plug Integrity m BOP Test Mechanical Integrity Test~,~," Approved by the order of the Commission I Approval ~.~. Location clearance S--~bsequent form required 1-~- I,?.~.~U~ o,~r ~~ ~~~ ~pproved Copy Jriginal Signed By Ret~rne~ W. Johnston ~m,,~,~,,~, Date Form 10-403 Rev 06/15/88 SUBMIT IN TRIPUCATE~ Granite Point Platform GPP ~44-11 Revised March 31, 199~ Objective: Convert well #44-11 from a temporally suspended shut-in well to a service well for injection and disposal of non-ha:mrdous oil field wastes (Class 11) associated with dri'lling, production and workover operations. Also to demonstrate tubing by casing annulus mechanical integrity. Background: This well was ori~nally drilled in 1968 to a depth of 12471', drill stem tests indicated the well was do'- hole and thus it was subsequently abandon and suspended as per the attached schematic. Recently, this year in March, efforts to determine mechanical integrity of the 9-5/8' as well as slickline gauge work was performed to gather data about the present status of the wellbore. Gauge ring runs were only able to work as deep as 4617' wlm, this is explained by the present of 11 ppg drilling mud leR in the hole since 1968'. It is believed that the mud has separated and dehydrated to point that water is on top with partially solid mud below. The 9-5/8' casing was pressure tested to 1500 psi at which point the wellhead/tree adapter seal flange leaked, efforts to repair the flange were unsuccessful. Also injection into the 13-3/8" x 9-5/8" was attempted, but was stopped once 1300 psi was achieved, a total of 10.75 bbls was placed into the Workover Procedure: Confirm well is dead, no pressures. Skid rig south to allow ao:e__ss to well through the drill deck. Remove 13-5/8' adapter seal flange. Set BPV as require& ~ 13-5/8" 5M riser (C1W btm x flange top), nipple up 13-5/8" double gate with 3-1/2" ram (btm) and blind ram (top). Test BOP per Unocal specifications. 2. RU 3-1/2' elevator to West crane. MU 3-1/2" landing joint, RIH and engage tubing hanger. POOH, recover tubing hanger and single joint of tubing below hanger. 3. RU Dowell coiled tubing unit (1.75"), test BOPE per Unocal specifications and complete Unocal pre-job checklist for coiled robing operations. 4. RIH with 1.75' CT, expect to tag dehydrated mud at ±4300', begin washing down and continue to ±7950' (depth of desired bridge plug). Note: Review nozzle selection, possible use of bits / underreamcrs and motors. Centrnli?er might by necessary to enter top of 7" liner. AH fluid returns are to be captured onboard, no discharge into the Inlet is allowed (mud con,ins 5-7% oil). Make up water for the operations should be Inlet water. 5. Once at 7950', displace the entire wellbore to Inlet water. POOH. . MU 9-5/8' casing scraper on coiled tubing, RIH (snub/push) with same to a minimum 7800', limitation on the amount to push the coil down will be established by Dowell. This step is necessary to assure that the US1T/GR tool can be ~ to evaluate cement and conditions. . RU Schlmnberger wireline. MU usrr/GR tool (cement & casing inspection). RIH to approximately 7800', log up to TOC in 9-5/8" (est. TOC is +4650'), continue to log to surface with casing inspection portion of the tool. RECEIVED APR 1 0 1995 Oil & Gas Cons. Commllslon ~oh0ra:? GPP g44-11 Procedurc 3/31/95 Page 2 Note: Transmit (fax) the log to Anchorage office ASAP for further review and evaluation, use fax number 263-7862. Pta'sue with Schlumberger to pre-program the internal yield for the 9- 5/8' casing strings, this will allow easier interpretation of revised internal yields based on remaining wall thickness. 8. RU gauge ring/junk basket for 7" 29#casing on wireline, verify gauge is larger than a permanent bridge plug OD. RIH with gauge ring to 7950' ETD. POOH. RU 1.75" CT, cement pumper, batch mixer, etc. Install predetermined BHA (BP or nozzle) and RIH to 7950'. M&P a cement balance plug from 7950'-7800' with :k9 bbls of 15.8 ppg flurry. Circulate coil clean and POOH. - 10. MU 9-5/8" bridge plug on wireline. RIH, set same at :k6350'. This step is optional, please discuss the situation with the office prior. 11. Pressure test the 9-5/8' casing to 3500 psi (60% ofyicld) for 30 minutes, achieve this pressure at 500 psi increments. Monitor all casing annulus for possible communication. Casing Size Yield Collapse N80, 40# 5750 3090 psi N80, 43.5# 6330 3810 J55, 61# 3090 1540 Note: Depending on the evaluation of the cement bond log, the above pressure test will likely be changed to a higher value. 12. Release CTU or move and begin RU of the Dowell Jacking Frame. 13. 14. MU 3-1/2" robing completion assembly (to be determined); wireline entry guide, tubing tail, profile, 9-5/8" packer, tubing as required and FMC tubing hanger (12" x 3-1/2' "B" with type "I-I" BPV. RIH with completion tail to :t:5070', land the tubing as required. Nipple down the BOPE and install the 3-1/8' 5M tree and test same to SM. Inhibit the tubing by casing annulus with Nalco packer fluid, take returns either on the casing annulus or tubing. Pressure up the tubing as required, to actuate and set the packer. RU to thc annulus and perform a mechanical integrity test (MID. The casing must be tested to a surface pressure of 1500 psi or 0.25 psi/fl x TVD depth of packer, or whichever is greater for 30 minutes, if the pressure declines more than 10% in 30 minutes contact the office to discuss. Note: Contact the AOGCC within 24 hours to witness the MIT. Additionally, RU two pin recorders (permanent installation), one to the 13-3/8" x 9-518" annulus and the other to the 9-5/8' x 3-1/2' annulus. 15. Rig down the jacking frame. 16. RU Schlumberger to perforate the intervals for injection, RIH with Encrjet 2.5' perforating gun assembly as required. Perforate the inmnvais as direct. GPP//44-11 Procedure 3/31/95 Page 3 17. RU to establish injection (rates and pressures) to satisfy solids/liquid injection requirements. 18. Secure well, RDMO. Total time r~quired + 10 days Filen~__me: Granite\OBMkproc001.doe RECEIVED APR 1 0 1995 ~aska Oil & Oas Cons. Commission 11 PPG Mud in welibore / v y y y 26' Structural @ 310' 18' Surface @ 439' ~, 71#, Grd-B, Vecto DV Collar @ ~PP7' 13-3/8' Intermediate @ 4019' 61~, ,I-55, BTC Est. TOC @ 4657' RECEIVED APR 1 0 1995 Alaska Oil & Gas Cons. Commission Anch0ra~:~_ 1123o'-1124B' IN~ 112'J'~'-11~ Pid' B~ellt~O' 114oo'-I 14o1' W'80 8(3Z 115~o'.11~1~ Granite Point Reid; Well #44-11; APl 50-733-20059; ADL 18761 Leg 1, Conductor 2, KB elev= 105' Spud 7-8-68, Last WO 10-7-68, Status: Shut-in dh/well UNOCAL ENERGY RESOURCES ALASKA DRAWN: CLL DATE: 3-16-95 FILE: GP4411A.drw X 1 · ::: 5::..: 5:::::::::::::::::: 2 :::::::.-.'5 ..:: .':.': 5:::::.. :-2 ::::::: ...'5::5: :::: :: ~, · ~26' Structural @ 310' Iiil~ 71 #, Grd-B, Vetco lil DV Collar @ ~'~'~7' £ Est. TOC @ 4657' Potential Injection Intervals (DIL); 5120'-5210'(90') 5255'-5315' (60') 5320'-5370'(50') 5420'-5485' (65') 5955'-6020' (651 6125'-6285' (1601 BP @ 6350' Cement Plug 7800'-7050' TOL ~ ~ 7~'/1' 9-5/e' ~ 79e2' 40.4~ NCO, LTC erd (40~ F~-52~': 48.5~ F/525~Tge2') 11150'-11151' WSO 8(2Z 11275'-11290' Pelf 11400'-1140'1' W~O ~QZ 11S~0'-1 le10' Completion Equipment: 1) 3-1/2' 9.2# L80 SCBTC 2) Packer @ 5030' 3) 'X' Nipple @ 5040' 4) Wireline entry guide @ 5070' Max Dev. = 28.3 deg @ 5600' RECEIVED APR 10 1995 Alaska Oil & Gas Cons. Commission Anchora? Granite Point Field; Well #44-11; APl 50-733-20059; ADL 18761 Leg 1, Conductor 2, KB elev=105' Proposed Conversion to Injection UNOCAL ENERGY RESOURCES ALASKA DRAWN: CLL DATE: 3-16-95 FILE: GP4411B.drw Flanged to Coiled Tubing BOPE or Wireline lubricator I BLIND RAMS 13-5/8" 5000 PSI PIPE RAMS 13-5/8" 5000 PS! I RISER 13-5/8" 5000 PSI Flanged to 13-5/8" "B" section of wellhead Granite Point Field; Well ~i~14-11; APl 50-733-20059; ADL 18761 Leg 1, Conductor 2, KB elev= 105' Proposed BOPE for #44-11 UNOCAL ENERGY RESOURCES ALASKA DRAWN: CLL DATE: 3-29-95 FILE: BOPE4411.drw ~ Re.an April 16, !990 Alaska Oil & Gas Conservation C=~--.ission 300! Porcupine Dr. Anckorage, All 99504 A~.n: Ms. Elaine Johnson Dear Ms. Johnson: I have attached surface surve,! locations cf the "Legs" "and conductors for the four platforms in t~ke Trading Bay Unit as well as t~he Union Oil-operated Monopod and Granite Poin= Platforms. I was unable to locate any plats from a registered surveyor but I hope this will meet your needs. Yours very truly, Regional Drilling Manager GRANITE POINT PLATFORM FROM NW CORNER OF SECTION 13, TION, R12W CONDUCTOR Leg#1: Leg#2: Leg#3' Leg#4: "Y" COOR. "X" COOR. WELL # FSU 2,544,566. O0 263,297.33 2,544,572.08 263,294.75 13-13 2371 2,544,572.41 263,299.33 44-14 2373 2,544,569.75 263,302.99 33-14 & RD 2371 2,544,565.34 263,303.99 31-23 2366 2,544,561.34 263,302.08 31-14 & RD 2362 t & 2 2,544,599.42 263,297.83 44-11 & RD 2360 2,544,560.67 263,293.33 Open 2,544,564.50 263,290.83 12-24 2363 2,544,569.00 263,291.42 32-23 & RD#2 2368 2,544,610.00 263,364.00 Compressors 2,544,543.33 263,408.00 '2,544,548.16 263,403.42 31-13 2382 2,544,549.91 263,407.59 22-13 ' 2379 2,544,548.66 263,412.00 MUC#I-1 2391 2,544,544.99 263,414.41 MUC#I-2' 2386 2,544,540.42 263,413.91 32-13, 33-13 2390 2,544,537.25 263,410.58 24-13 & RD 2392 2,544,537.00 263,406.09 42-23X, 31-23 2380 2,544,539.58 263,402.42 11-24 2383 2,544,544.08 263,401.42 11-13 2379 2,544,499.58 263,341.33 FEL 1267 1262 1258 1256 1258 1261 1269 '1269 1370 1375 1379 1381 1379 1376 1371 1368 1375 For ]~O-403 ,RE~. 1-10-73 SuDmlt "Intentions" in Triplicate & "SubseQuent Reports" in Duplicate STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen Use "APPLICATION FOR PERMIT--" for such proposals.) O,L IT-i GAS I--'1 WE LLI,~--I WE LL L....J OTHER ABANDONED 5. APl NUMERICAL CODE 50-133-20059 6. LEASE DESIGNATION AND SERIAL NO. ADL 18761 7. IF INDIAN, ALLOTTEE OR TRIBE NAME 2. NAME OF OPERATOR 8. UNIT, FARM OR LEASE NAME UNION OIL CO. OF CALIFORNIA UNION-MOBIL STATE #l 3. ADDRESS OF OPERATOR 9. WELL NO. P.O. BOX 6247, ANCHORAGE, ALASKA 99502 GPS 44-11 4. LOCATION OF WELL At Surface 2360' S & 1261' E from N.W. corner, Sec. ]3, TION, R12W, S. M.' 13. ELEVATIONS (Show whether DF, RT, GR, etc.) KB 95' above HSL Check Appropriate Box To Indicate Nature of ~Notice, Re 14. 10. FIELD AND POOL, OR WILDCAT GRANITE POINT FIELD- MIDDLE KENA: 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) Sec. ll, TION, R12W, S.M. 12. PERMIT NO. 67-70 )orr, or'Other Data NOTICE OF INTENTION TO: TEST WATER SHUT-OFF ~ PULL OR ALTER CASING ~ FRACTURE TREAT ~ MULTIPLE COMPLETE SHOOT OR ACIDIZE ~ ABANDON* REPAIR WELL ~ CHANGE PLANS (Other) CHANGE OF OPERATOR SUBSEQUENT REPORT OF.' WATER SHUT-OFF [~ REPAIRING WELL FRACTURE TREATMENT ALTERING CASING SHOOTING OR ACIDIZING ABANDONMENT* (Other) (NOTE: Report results of multiple completion on Well Completion or Recompletion Report and Log form.) 15. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly.state all Dertlnertt details, ancl give pertinent dates, including estimated date of starting any proposed work. FROM: TO' MOBIL OIL CORP. UNION OIL CO. OF CALIFORNIA RECEIVED OGT 2 0Nision 0! 0ti & B,~ 0~v::'tkn 16. I hereby certifY that the foregoing is true and correct (This sp~:e~To-~'~tate office use) DISTRICT DRILLING SUPT. DATE CONDITIONS OF/~PROVAL, I~= ANY: TITLE See Instructions On Reverse Side Approved Copy Returned : OF ALASKA ($ee~ ].l- rever~e ;~i;.) 5. APl N~[Ef~C~ COD~ ~ OIL AND GAS CONS'E2VATION COMMJ'fT~ 50-133-20059 . . 6. L~ASE D~!GN~T[ON AND SEKI.~ NO. WEI..L COMPLEi]ON OR RECOMPLETION REPORT AND LOG* State ADL 18761 WELL ~ WELL ~ var ~ Other ~. IF I.h'gl,~, ~'~ OR -. . .. b. TYPE OF C05[PLETION: ~:; , ~ WELL OVER ~ EN · ~ DACK~ ' RESVR.~ Other ' Union-Mobil State ~/1' ..... ..-.. ~.. ~, &DD2ESS 0F OPEgATO:[ . ~ - : P. 0.. Box 17'34 Anchorage, Alaska 99501' ': 4. LOCATION OF WELL (Report location c~eart~ and in accordance with any State rcqui~)* ........ ~t~u~'e2360~S ~ ~26~E from ~ Corner Sec. 13j T~ON, ~2N. . S.M. (Leg 1, Slot 6) '~ :" ' ~ ~ ~t total dep~ ~ ~ ~ _'? i Jj ~ 12. PERMIT KO. ~ 8A6~ff & 8~8~N fr SE cot. Sec 11, TZOff, R12~, ~.H, :, z~- - . .. ,L. .~. ' ' ; ' 67 -70 ............................................. . . . - . .7'-8-68 J 9-20-68 : '. J 10-7-68 Susp. ,L 105' KB' ~ ":' ].'+63 18. T~~ D~FH. 5iD A. TVD~'LCG BACK bid & ~'VD~O. ~ ~UL,TiPLE COA~L.. J 21. · iNTERVALS DRILLED B'Y ' ' ".-- ..... IDEH ' J ' ~O%V b~Y* · , J g0TABY TGoLS ~. .< ~ , - '~ CABLE 'TOOLS 12471~, [16U6 TVD I2 ~ ~h~__ _~14s~ ~2'293 r%pJ . ' ".-~!Surface to TD ~_ ~':. ~p~ODUCING IN%'~VAL(S) OF Tills CO~[F~TION--TOP BISCOM, N~[B (MD Ah'D ~)' ,. . J~, WAS ' .., - : ' '. ' ..: · ' -' '-;.'.' [ . SUrVeY ~ADE . Suspended "~ . ~ ~:,: x. : : .-. , j~. y s 9. Wii~I, Gran'ite Point State ~-~44-11 10. FIE/J3 A..~D POOL, 0}~ WILDCAT Granite Point Middle Kenai OBJECTIVE) -._ SE 1/4 of SE 1/4 of Sec. TION, R12W, S..M.. 'I'YP[; EL~TMC AND OTHER LOGS'Il, UN . : ._ .'-. : ,--, , -. . ..:" Dual induction, Sonic density, Dipmeter, Gamma-~ay Neutron, CBL- . '" - 'l-a-ss ~...; ' .... : ~~~o~ ......· · ._L . _ '~ . ·; '":, ' l.~" ' .' -~?~&~ '_ · : · SIZm_=. ~~__~-~' TOP (~'[D) ..... ~O~O~ (MD) I,,:S~CKS C~J~'T'. ~ , J, S~S~ (~'[D)_ J .......... S~Z~ ' J DS~d 8~' (MD) ~~ SET PErOrATIONS OPEN TO P~ODUfl'iO~ (interval, size and number) J 29. ACID S~OT F~C~'~~ C~-IEN'T SQUE~ ~C ,~ ~, ~ ..... 2H/f:t~-(Below bridge plug) , , ,,,.,,L., J- · '. · '" ' *Z' - ~z,oou I~i,~O) ~: "' ~ ' . ' J 11,t50" (WS0) '] Squeeze w/50 sex Class G ~ . . ~ . · ...... __- a .... . 1~,230/11,2~5 2HT{t~:~(Below cement plug)[ll,330~ . J Bridge Plug .' ~ ' . 1'1,275'/11,290'~ ~ ~ ~;~' " .~ ~'" 10~916/.11,0'15"-]23 sex plug in '~' liner. . ~%TE FIRST PRO~UCIXON J PI{ODUCTiO~ 5'IE'ii{OD (~lowh~g, gas 1if~. pump~g--size and %~pe of p~p) JlVELI, STATUS (Produc~g or ' ~ , ~'.: l' · ' .., :'~ '~aut-in) : - . I .,_'- ....- .. l l, - --> . I ' : I 1' _ ..... I ~2. LIS~ OF 4~rACHMENTS History DST Records ,Directional Survey,Mudlog,Electric Log "~--~' hereby c~rt[fy that the foregoing and attached information is compTe-te and correct as d~(ermlne-d '~r~m"al[-aX'a]]-~bl~-~:ecords f)~"/;'/"' "' 1:4//' ' . ... ~ , .; ,~ ~ .... SI~NgD j ~ , *(See Jnstrucfions-an~ Spciccs Jar AdditiormJ Data on /~ CO 5228(9-66) WELL COHPLETION REPORT ORIGINAL DRI LLING Mobil Oil Corporation OPER ATOR WELL '1~0o Granite Point State 44-11 FIELD Granite Point SEC. 13 _, T. ION , R. 12W S.M. STATE Alaska C0UHTY L0CATIOfl 2360'S & 1261'E from NW corner Sec. 13, TION, R!2W, . .... BHL = 3206'N & 2109'W of Surface Location LAND OFFICE ELEVATIONS 105'MLLW(K. B. ) ENGI.NEER LEASE tt0.18761 (MAT) GEOLOGIST J' Meyer & H. Hixson DATE November 6, 1968 TITLE Area Engineer COMMEN. CEO DRILLING 7-8-68 GEOLOGICAL MARKERS COHPLETED.DRILLII~G 9-20-68 TOTAL DEPTH 12,471 P'LUGGED DEPTH 1,0j916 .t~:0~ PLUGS: Bridge plug 1I ~330' C em_~e~l~_~p~ug 10,916 '/11,015 ' ON pRODucTIOI:{ Suspended ~, FLOWING/GAS LIFT/PO,PING k ...... /~CROSS OUT UNNECESSARY WORDS) ., , PRODUCTION' DATA DEPTH GRAVITY TOTAL CUT TUBING CASING GAS PRODUCTION, CLEAll OIL CLEAN OIL % BEAN SIZE PRESSURE PRESSURE MCF PER DAY INITIAL Susp. B/D , AFTER DAYS B / D i CASING RECORD (PRESENT HOLE) SIZE OF DEPTH TOP ' WEIGHT NEW OR SEAHLEss "'GRADE . ."~lZE OF ND.OF. SACKS 'DEPTH OF CEN. CA$1.NG(A.P.I..); OF SHOE OF CASING OF CASING SECONDHAND OR' LAF~ELD OF CASING ..HOLE DRILLED OF CEH. IF THRqJ PERFS. · 18 ' 435 +63 70.59 N S B 22 . 540 13 -3/8 4015 +63 61 N S J-55 16 .2400 9-5/8 8002 +63 . 40 & 43 5 N S N-80 12-1/4 1800 ,. 7 12208 7872 29 N S N-80 8-1/2 550 , PERFORATIONS · ._ SIZE FROH TO SIZE OF PERFS. HO.OF ROWS DISTANCE BET. METHOD OF PERFS. OF CAS I'tlG CENTERS ...... (intervals)" "' · ~ 7" 11230 11705 1/2" ~2/ft. ~c. hlumberger Hyper-Jet · . ... ELECTRIC LOG DEPTHS 4000 - TD Santa Fe Drilling Company DRILLED BY using R~g #72 MOBIL OIL CORPORATION HISTORY OF OIL OR GAS ¢~ELL OPERATOR Mobil Oil Corporation FIELD Granite Point WELL NO. Granite Point State 44-11 SEC. 13 T ION R 12W S. M, DATE 1968 7-8 to 7-9 7-9 7-10 to 7-16 7-16 to 7-2C 7-20 t'o 8-3 Noveller 6, 1'968 SIGNED C. C. Woodruff TITLE Area Engineer J~ILLING A MIDDLE KENAI ZONE WELL This well was drilled .by Santa Fe Drilling Company using rotary rig #72 ~0sitioned over conductor #'6, leg #1 of Mobil Oil Corporation's Granite Point ~latform. ~AlldePths refer to the Kelly.~bushing,105' above mean low low.water. ~..~H. to 22". 140'/290'; RUnhing. Sperry-Sun Survey; Drilling 12-1/4'.' hole 290/450. Spudded well on July 8, 1968. Ran a 22" H.'O. and C. O. to 290'. Ran a Sperry-Sun Gyro Survey 298' to surface. Went in with a 12-1/4" bit and drilled 290/.450. O.H. to 22" 290/4'50; R~nning & c'~ementing 18" casing @ 435' Opened 12-1/4,' hole 6o 22" 290'/450'. Ran 10 joints (439') of 18", 70.59#, Gr~ade "B" line pipe with Baker guide shoe and Duplex collar. Cemented shoe at 435' with 50 cu. ft. water followed by 592 cu. ft. Class "G" cement w/3% CaC12 - 116# slurry wt. C.O.C. to 435'; Drilled 12-1/4" Hole 450/4048; O.H. to 16" 450/2429_5- Fishing. C~O.C. to 435' and C.O. to 450'. C~anged Over to mud and drilled 12-1/4" 45'0/4048'. Made the following dynadrill runs: 998/1124, 2029'/2158', and 2372'/2457. Ran in and opened 12-1/4" hole to 16" 450'/2429'. Twisted off at 1468'. Ran 10-3/4" W.O. and tapped into fish. -Pulled and recovered entire, fish. O. H. to 16" 2429'/4048'; Running and_Cementing 13-3/8" Casing at 4015. Ran 98 joints - 4019' - of 13-3/8", 61~, J-55~ buttress casing with shoe at 4015", float .collar at 3958',~o and a D.V. collar at 2227'. Cemented first stage with 10 bbl. water followed by 735 cu. ft. Class "G" cement with 3/4% T.I.C.'- slurry weight 114-116#. Opened. D.V. collar at 2227' and pumped 10 bbl. sea water followed by 1900 cu. ft. Class "G" cement with 2% CaC12 slurry weight 116 to 118#. C.O.C..; Running Sperry-Sun Survey 4015/298; Drilling 12-1/4" Hole 4048/8061. · C.O. to 4048'; Ran Sperry-Sun Gyro Survey 4015/298; Ran in ~ith 12-1/4" bit on a regular drilling assembly and drilled 4048'/8061'. Made the following directional runs: Rebel Tool over~ interval 5933/6003, and Dynadrill' over the interval 6003/6064. ' MOBIL OIL CORPORATION HISTORY OF OIL OR GAS WELL OPERATOR Mobil Oil Corporation FIELD Granite Point WELL NO. Granite Point State 44-11 SEC. DATE November 6, 1968 13 T ION R 12W S.M. SIGNED C. C. Woodruff TITLE Area Engineer I-3 to 8-4 ~-4 to 8-6 8-6 to 8-21 3-21 ]-21 to 8-29 3-29 to 9-3 Running Sc~hlumberger Logs Ran the following Schlumberger wireline services: Dual Induction Log 8070'/4000'; Dipmeter - 8040/4000 Running and Cementing 9-5/8" Casing at 8002' Ran and cemented 7962' of 9-5/8" casing with details from bottom to top.~ as follows: ' 64 jts. - 2739' - N-80, 43.5~, LT & C 8 rd. including LarKin guide shoe @ 8001.70' and float collar @ 7912 '12,3 ji~s, - 5177' -.N-80, 40.0~/,, LT & C 8rd. 1 gauge it. 44'~- N-80, 43.5f/ LT & C. _O%C fluted hange~r ~' . Total 188 jts'. - 7962.40' Landed casing 39' below KB. Pumped in 400 bbl thin mud treated w/ll.0 .pH and 0.25 PPB peraformaldehyde followed by 10 bbl. seawater. Pumped in 1800 sax Class "G" cement treated w/0.75% TIC. Slurry weight 'for first 50 cu. ft. 105fi followed .w/ll8~ per cu. ~t. WOC 24 hours. ~.O.C, Running Sperry-Sun Survey; Drilling 8-1/2" Hole 8061/10764 C.O.C. to shoe and ran Sperry-Sun ~urvey 7970'/4000' D.O. shoe and C.O'. to 8061'. Ran in w/ an 8-1/2" bit oh a regular ~rilling assembly and drilled 8061'/10764'. Conditioned hole for logging. .. Running Schlumberger Logs Ran the following Schlubmerger wireline serv{ces: Dual Induction Log and Dipmeter 10761/8014. Driliing 8-1/2" Hole 10764'/11857 '; Running Schlumberger Logs Ran an 8-1/2" bit on a regular drilling-setup and drilled 10764'/11857'. Ran the following Schlumberger wireline services: Dual Induction Log. 11,838/10,000; Sonic Log .11834/10510; and Density Log 10848/10,500. Drilling 8-1/2" Hole 11857/12400; Running Schlumberger Logs Ran an 8-1/2".bit on a regular drilling set-up and d~rilled 11857/12400. Ran the following Schlumberger wireline services: Dual Induction Log, Sonic Log and Density Log 12379/11638. And Dipmeter 12384/9600. , MOBIL OIL CORPORATION HISTORY OF OIL OR GAS WELL Mobil Oil Corporation OPERATOR WELL NO. Granite Point State'44-11 DATE November' 6, 1968 FIELD Granite Point SEC. 13 T ION R 12W S.M. SIGNED C.C. Woodruff TITLE Area Engineer -3 to 9-6 -6 to 9-12 -12 to 9-17 to-9-29 .Drilling 8-1/2" Hole. 12 ~ 4.00..' /12 ~ 453,'; Fishing Stuck Pipe @ 12~453'. Ran .a 8-1/2" bit on a regular drilling set-Up and drii.!ed 12,400/124~53I~'. Stuck pipe on bottom while drilling backed off @ 12,289. Reamed and conditioned hole to 12,240o Ran open end D.P. to 12290 and .pumped 5'6 cu. ft. water followed by 70 sax Class "G" cement w/15% 12/20 sand. ConditiOned mud and hole to run 7"~ liner. Running and Cementing 7" liner @ ~.22p.8; Squeezing Lap~ Running Sper.ry- Sun Survey Ran 7" liner~with details from bottom to top as follows: 101 j~s. - 4336' -'29#, N-80 shoe at 12,~08 ~. float collar'@ 12,117 Top liner @ 7872 Cemented shoe at 12,208 with 550 sax Class "G" cement with 3/4% TIC. Ran in and tagged cement top at 10,472'. D.O.C. to 12088. Ran RTTS tool and set packer at 7581'. Squeezed liner lap with 56 cu. ft. water fOllowed by 150 sax Calss "G" cement mixed with 3/4% TIC. Ran in and tagged cement top at 7709'. C.O.C. 7709/7872. Ran RTTS tool and set packer at 7581. Pressure tested lap to 5000 psi-. D.O.C. and shoe at 1.2208. Polished off cement plug fro~ 12210 to 12230. Ran Sperry-Sun Survey 12,200'/7900! Attempting Kick off: 'Setting Cement P. lu~ #2. Ran in with Dynadrill on a 2° Kick sub and drilled 8-1/2" hole 12256/12274' soft cement. Pulled out leaving 3 cones in h'ole. Ran in and cleaned out to 12,290 hitting stub of fish. Ran in with open end drill pipe~ and pumpe~ 50 cu. ft. water followed by 50 sax Class "G" cement. Ran in and located top of cement at 12,090. C.O. to 12113. W.O.C. 32 hours.' .' Redrilling 8-1/2" Hole 12090'/12471'. Fishing Stuck Pipe at 12~471 .. C.O. hard cement to 12,220. Ran a Dynadrill with a 2~ Kick sub and drilled 12,220/12,294. Ran a 8-1/2, bit or a regular drilling set-up and drilled 12,294/12,471. Stuck pipe'on bottom while drilling. String parted while working pipe. Top of fish at 12,155. Ran overshot mnd jarred.-Fish parted at 12275'. Ran overshot and jarred. String parted at 12,367. Ran string shot and backed off at 12,401'. Washed over fish to 12439'. Ran string shot and bakced off at 12,435. Washed over fish to 12470. Attempted to jar fish without success. ' MOBIL OIL CORPORATION HISTORY OF OIL OR GAS WELL OPERATOR Mobil Oil Corporation FIELD Granite Point WELL NO. Granite Point State '44-11 SEC. 13 ' T ION R 12W S.M. ~.29 to 9-30 SIGNED C. C. Woodruff DATE Novembe~ 6, 1968. TITLE Area Engineer. / Running_ Schlumberger Logs: Set Bridge Plug @ 12~ 148' ._ . Changed mud over to-saltwater. Ran the following wireline services: Gamma~Ray Neutron Log 12,215/t0,200; and Cement bond Log 12,2.15/ 10,700 ~nd 8680/7850. Ran a 7" HOWCO bridge plug .on wireline and set in 7" casing at 12,148'. 9-30 ta 10-2 10-2 to 10-5 10-5 Testing and S~ueezing. WSO # 1 & 2. PErforated 4-1/2" holes at 11,400'. Ran HOWCO hydrospring tester, with packer set at 11,293. and tail to 11,315. Opened tool for a 2 hour test. recovering 8 bbl water. Ran squeeze packer on wire line.and set at 11,200. Pressured up. to 5000 psi, perforations would not take fluid. Perforated 4-1/2" holes at 11,150. Ran HOWCO hydrospring tester with packer set at 11.,066 and tail to 11,088. Opened tester for a two hour test. recovering 8 bbl water.-Ran. HOWCO f~re'i~able and ~et at I0,949'. Pressured up to 5000 psi and pumped away 10 cu. ft./min. Set tool at 10,859' and pumped 50 class "G" cement 116# slurry. Squeezed 25 sax at a final pressure 550~J. C.O. cement anR retainer and ran in to 12,140. Perforating and RunningDST #1 & #2 Jet perforated 2-1/2" holes Perf~ in the following intervals. 11,520/11,610 and 11,630/11,705 Ran. HOWCO hydroapring tester and s~t pa¢t~er at 11,293 with tail to 11,315. Opened tool for a 6 hour flow test,, recovering 56 bbl. water. Set a 7" bridge plug at 11,330'. Perfora'ted 2-1/2" holes per ft. in the following intervals: 11,230'/11,245'. and 11,2757/11,290'. Ran HOWCO hydrospring tester and set packer at 11,002 with tail to 11,025. Opened tool for a 4 hour flow test recovering 46 bbl. water.' settin~ Cement Plug a_nd_. Suspending We.Il Ran open end drill'pipe to 11,330 and displaced saltwater with mud. Pulled up-.to 11,015 and pumped in 23 sax Class "G" cement. Ran in and tagged cement top at 10~~--~ Released rig at 1:00~d suspended well. Mobil Oil Corporation Well - #44-11 WSO #1 @ 11,400' Date: 10-3-68 Witnessed by H. C. Hixson Ran HOWCO hYdrospring tester on 4220 of 3-1/2" DP and 7055 of 5" D. P. Set packer at 11,293' with tail pipe to 11,315'. Test tools included a dual closed in pressure valye followed by 2 joints of 3-1/2" DP to serve as a sample chamber. Also included were 24 hour inside recorder @ 11,283, ~.a 24 hour and 48 hour bottom outside recorder, @ 11,308 and 11,311 and a 578" choke. Opened tool @ ]10~:I0for a straight flow test. Had a light blow. Blead off blow dead in 10 min. Blow started again, v/weak displacing 1" of water after 45 min. 'Shut in @ JI2'flOAM Reversed out recovering water - tested 125,000 ppmC1. Recovered 10 gal. water from test tool - tested 140,000 ppm Ci~ Calculated recovery based on pressures: ~3# water = 50.86 #/sq.in/100' 590 psi ~ 50.86 psi x 100 = 1051 ft. rise. 1051' rise in 3-1/.2" DP x .00742 bbl/ft = 7.79 bbl recovery. Pressure Charts IH IF FSI FHS Top Inside 24 hr. 5127 47 -526 3822 5127 24 hour Bottom Outside Bottom Outside 48 hour 5164 5163 51-540 49-542 3815 3851 5164 5163 Mobil Oil Corporation Well 44-11 WSO #2 @ 11,150' Date 9-30-68 Witnessed by H. C. Hixson Ran HOWCO hydrospring tester on 4220 of 3-1/2" DP and 6828' of 5" DP. Set packer @ 11,066 with tail pipe to 11,088'. Test tools included a dual closed in pressure valve followed by 2 joints of 3-1/2" DP which serve as a sample chamber. Also o. included was a 24 hour top inside recorder @ 11,056' and a 24 hour and 48 hour bottom outside recorders @ 11,080' and 11,084', and a 5/8" choke..Opened tool @ 1:40 AM for a straight 2 hour flow test. Had a light blow that displaced approximately 5' of water in bucket. Bleed off through large valve for 5 minutes and killed blow. Attached bubble hose, blow Built up to 1" water displacement after 15 minutes, 4" displacement after 1-1/2 hour. Shut tool in at 3:40 AM, Reverse circulated, recovering water testing 135~000 to 145,000 ppmC1-. Recovered 5+ gal. of water from test tool 'sampler. The first sample of this water tested 113,000 ppmC1-, and samples from the middle and top of the fluid column tested 150,000 ppm. This indicates that there w as some fluid entry which may have diluted part of the rat hole fluid. 73# salt water = 50.86 psi/100' ~ 526 psi - 1034' rise 3-1/2"DP - 7.67 bbl recovery Pressure Charts Bo'tt6~ Bottom Top Inside Outside Outside 24 Hour 24 hour 48 hour IH 5075 IF 26 to 526 FSI 3170 FH 5070 5164 5178 25 to 556 25 to 566 3165 3183 5164' 5178 DST fJ 1 GRANITE POINT f~44-11 ) Ran 7" HOWCO hydrospring tester on 4219' of 3-1/2" DP and 7055' of 5" DP, dry. Set packer at 11,293' w/ tail extending to 11,315'. Test tools included one 24 hour inside recorder, one 24 hour outside recorder and one 48 hour outside re- corder. The tools also included 2 joints of 3-1/2" DP below the reversing sub for collecting an uncontaminated fluid sample. Opened tool at 1:32 AM lO-3-68'for'a 5 min. I.F. There was a faint blow increas- ing to a lfte blow. (hose in 5 gal. bucket) Shut-in @ l:37AM for ISIP. Opened tool at 3:~0 AM for a 6 hour {inal flow period. There was faint blow increasing to a lite-medium~ blow and then steady throughout..Blow in bucket would drop to faint and build up to lite-m~dium in 30 minutes after venting blow to atmosphere through 2''~ line for 15 seconds.- Shut in at 9:10 AM for a FSIP. Reverse circul- ated 56 bbls of water (Pit measurements) Collected nine water samples w/salinites as follows: ~. Sample 1 113,'500 ppm C1- 2 112,500 " 3 110,000 '" 4~! ~109,000 " 5 95,000 " 6 86,000 " 7 73,000 " 8 90,000 " ~ 115,000 " Pulled packer loose @ 6:00 PM and pulled tools to sample chamber. Recovered.water · samples testing f/1. 63,000 ppm C1- f/2. 61,000 ppm C1- f/3. 61,000 ppm C1- f/4. 62,000 ppm C1-. BHP Charts recorded as follows: Inside Outside Top 24 Hour 24 Hour Initial Hyd. 5153 5164 5178 First Flow IFP 23'6 253 246 FFP 289 303 296 ISIP 4553 4565 4569 Second Flow . IFP 526 530 517 FFP 2411 2439 2442 FSIP 4475 4465 4470 Outside Bottom 48 Hour Final Hyd. 5153 5164 5178 Witnessed by: J. Meyer GRANITE POINT #44-11 DST ~2 11~230'/11~245' & .11~275'/11,290' Set bridge plug on wire line @ 11,330 and perf'd' as above. Ran HOWCO hydroapring testor on 4220' of 3-1/2" DP and 6765' of 5" DP, dry. Set packer at 11,003' w/ tail extending to 11,025'' Test tools included one 24 hour inside recorder, one 24 hour outside recorder and one 48 hour outside recorder. The tools also in- cluded 2 joints of 3-1/2" DP below the reversing sub for collecting an uncontam- inated fluid sample. · . Opened to61 at 8:48AM 10-4-68 for a 7 minute IF. There was a weak blow throughout. Shut-in @ 8:55AM for a 2 hour ISIP. Opened tool @ 10:55AM for a 4 hour final flow Period. There was a weak initial blow slowly increasing to 'a light medium blow and then steady throughout. Shut-in @ 2:55PM for a 6 hour final shut-in period. Reversed out 46 bbls of water (pit measurements). Collected water samples w/ salinities as follows: 1. 119,000 ppm C1- 2. I10,000 3. 197,000 4. 77,000 5. 69,500 6. 72,000 7. 118,500 Pulled packer'loose @ 9:00 PM and ~iled tools to sample chamber. Recovered water sample testing as follows: 1. 64,500 Clear brown color ppm C1- 2. 63,500 " 3. 62,000 " 4. 63,000 " Initial Hyd. Inside Out side 24 Hour Top 24 Hour' '4997 ~ 5o4o Outside Bottom 48 Hour 5O49 First Flow IFP 2'6 25 25 FFP 237 253 246 ISI? 4475 4515+ 4520+ Second Flow IFP 263 303 297 FFP 2071 2088 2096 FSI? 4240 4290 4272 Final Hyd. 4997 5040 5049 Witnessed bye: J. MeYer NOBIL OIL CORPORATION GRANITE POINT STATE NO. 44-[1 OCTOBER 9, 1968 RECORD OF sURVEY ALL CALCULATIONS PERFORMED BY IBH ELECTRONIC COMPUTER TRUE MEAS, DRIFT VERTICAL SUB DRIFT TOTAL COORDINATES C L 0 S U R E S DEPTH ANGLE DEPTH SEA DIREC -DISTANCE ANGLE D N DEG. D H S DOG LEG SEVERITY OEG/IOOFT SECT[ON DISTANCE 0 0 0 0,00 -105,90 $ 0 E 0,00 $ 0,00 ' '75 0 0 75.00 "'30.'89 S 0 E 0.00 S O.O0. W [0;0 0 [5 99,99 -5,90 S ¢3 E 0,07 S 0,07 150 0 0 149,99 44,09 S 0 E 0.14 $ 0,I2 175' 0 15 174,99 69,09 $ 4 W 0,24 S O,ll 200 0 20 199,99 94,09 S 4 E 0,39 S 0.12 225 0 15 224e99 119e09 S 9 W 0,50 S 0,10 250 0 45 249e99 144e09 S 62 W 0,65 S 0.,17 2?5 I 45 274,98 169,08 S 63 W 1,00 S 0.85 306 I 15 305.97 200.07 N 88 W 0.98 $ 1.53 337 1 25 ~36,96 231.,06 N 88 ~ 0.95 S 2.~0 ~69 0 50 368.96 263.06 N 87 ~ 0.93 S 2.77 kO0 0 50 399.96 294.06 N 82 W 0.86 S 3.22 440 0 50 439,95 33~,05 N 86 W 0,82 $ 3,81 533 0 50 532,94 427e04 N 78 W 0,54 S 5,14 62~ 1 0 624e93 ~19,03 N 82 W 0.31S 6.7~ 718 1 0 717,91 612.01 N 73 ~ 0.15 N 8,28 810 1 10 809e89 703.99 N 60 W 1.10 N 9.92 0.00 $ 0 0 0 W 0,00 S 0 0 0 W 0.10 S. ~2 59 59 E 0,18 S 41 19 32 E 0,18 S 41 19 ~2 E 0.27 S 24 57 48 E 0.4'1S 17 39 21E 0.~1S 12 1D 30 E 0.68 $ 15 13 55 W 1.82 S 57 2~ 2 W 2.49 S 67.31 38 ~ 2.92 S 71 28 ~8 W 3.~4 S 74 57 33 W 3,90 S 77 4~ 13 W 5,17 S 83 ~8 41 ~ 6e74 S 87 17 7 W 8.28 N 88 55 38 W 9.98 N 8~.,~9 ~9 W 0.000 0.009 1,QO0 0,286 0,720 leO00 0,395 2,528 4.001 2,882 0.581 1.845 0.~6 0,147 0.126 0.187 0.169 0,00 0.00 -0.10 -0.18 -0,18 -0.26 -0,38 -0.4~ -0,~8 -0,,20 0,~5 0.77 1,09 1.84 2,92 ~.1~ 5,50 7.28 ABOVE SPERRY SUN GYRO SURVEY- FOLLOWING SPERRY SUN SU'3'16330 900 1 0 899,88 793,98 N 64 W 1000 2 0 999,82 893,92 N 47 W 1100 ? 0 1099,07 99~,17 N ~8 ~ 1200 8 30 1197,98 1092,08 N 3? ~ l~O0 9 45 1296e53 1190,6~ N ~7 W 1~00 10 30 1394.86 1288,96-N 32 ~ 1,79 N 11,34 ½.I7 N 13.89 13,77 N 21.39 25,~7 N 30,29 39,10 N 40.48 54.55 N ~0,13 11,48 N 81 1 30 W 14.50 N 73 17 17 W 25.44 N 57 13 36 W 56,28 N 45 59 33 W 74.09 N 42 35 0 W 0.217 1.08~ 1.506 1.2~0 1.155 8,72 12.19 39,12 56,02 74.04 1500 12 0 1492,67 1386,77 N 30 W 1600 13 0 1590,11 1484,21 N 28 W 1700 14 45 1685,81 1580,91 N 25 W lSO0 16 30 1782,?0 1676,80 N 21W 1900 19 0 1877,25 1771,35 N 24 W 2000 21 .0 1970,61 1864,71 N 27 W 2100 25 0 2061,24 1955,34 N 31 W 2200 28 15 2149,32 2043,42 N 38 W 2300 28 30 2237,21 2131,31 N 39 W 2400 28 0 2325,50 2219.60 N 42 W 250'0 26 30 2414,99 2309,09 N 51W 2600 26 45 2504,29 2398.39 N 51 W 2700 2? 0 2593,39 2487,49 N 51 ~ 2800 2? 0 2682,49 2576,59 N 50 W 2900 27 0 2771,59 2665,69 N 51W 3000 27 15 2860,50 2754.60 N 50 W 3i00 27 0 2949,60 2843,?0 N 48 W 3200 27 0 3038e?0 2932,80 N 49 W 3300. 26 45 3128,00 3022,10 N 49 W 3400 26 30 3217,49 3111,~9 N 46 ~ 3500 26 15 3~07,18 3201,28 N 48 W 3600 26 0 3397e06 ~291,16 N 47 W 3700 26 0 3~86,94 3381,04 N 45 ~ ~800 26 15 3576,62 3470,72 N ~6 W 3900 26 I5 ~666,31 3560,41 N 48 W 4000 26 0 3756,19 3650,29 N 46 W 72,56 N 60.~3 W 92,~2 N 71.09 W 115,50 N 81,85 W 1~2.01N 92e03 W ' 171,75 N. 105.27 W Z03,68 N 121.54 W 239,91 N 143.31 W 277,21N ~-'"172,~ W 31~.29 N 202,48 W 349.18 N 233,89 W 377,26 N 268,57 W 405,58 N ~03.55 W 434.15 N 338,83 W '463,3~ N 373,61 W 521,34 N ~/'443,96 W 551,72 N 477,70 W 581,50 N 511.96 W 611,03 N 545,93 W 642,03 N 578,03 W 671,62 N 610,90 W 701,52 N 642,96 W 732,51 N 673.96 W 763,2~ N 705,77 W 792.83 N 738.6~ W 823.29 N ~ 770,'17 W 94,49 N 39 50 9 W 116,60 N 37 34 5 W 141.56 N 35 19 31W 169,23 N 32 56 43 W 201,45 N 31 30 20 W 237.19 N 30 49 31W 279,45 N 30 51 6 ~ 326.47 N 31 53 8 W 373,87 N 32 47 28 W 463.09 N 35 26 ~8 W 506,60 N 36 48 42 W 550,72 N 37 58 10 ~ 595,20 N 38 52 50 W 68~.76 N 40 25 1W 7Z9,79 N ~0 53 1~ ~ 77~,76 N 41 21 ~0 ~ 819.39 N ~1 46 46 W 863.90 N 41 59 50 ~ 907,90 N 42 17 ~1 ~ 95t.59 N ~2 30 21W 995.39 N ~2 36 57 W 1039,5~ N ~2 45 35 ~ 1083,60 N ~2 ~8 2~ W 1127,37 N 43 5 ,27 ~ 1,550 1.090 1.892 2.05~ 2.661 2.247 ~.292 ~,512 0.537 1.505 ~.381 0.250 0.250 0.~5~ 0.~54 0.520 0,9~5 0,250 1.367 0.923 0.506 0.877 0.506 0.885 0,915 140.98 167.76 198,97 233.82 275.50 322.79 370.~9 ~61.29 505.55 550,19 59~,96 ~3~,60 68~,76 729.77 8Z9,19 863,60 907.~5 99~.71 1038,74 1082.59 112~.22 FOLLOWZNG 'SPERRY SUN 5U-3-16340 ~I0,0 27 0 38~5.29 3739.39 N ~5 W 4200 27, 15 3934,19 3828.29 N ~ W ~300 27 ~5 4023e09 3917.19 N 4~ W 4~00 27 30 ~llle?9 4005,89 N 43 W 4500 2? ~5 4200'29 ~09~.39 N 43 W 4600 28 15 4288.38 4182.48 N 43 W 4700 28 15 ~376.47 4270.57 N ~2 W 4800 28 . 0 k~64,77 4358,87 N ~2 W 4900 28 15 4552.85 ~46.95 N 41 W 5000 28 0 4641.~5 4535.25 N 41 W 510'0 ~8 0 4729*44 4623.5~ N 41W 5200 28 0 48~7.74 4711.84 N 40 W 5300 28 15 4905.83 4799.93 N ~0 W 5~00 28 25 4993,92' 4888.02 N mO W 5500 28 25 5082,01 4976,11 N 39 W 5600 ~8 30 5063*99 N 39 W 5700 28 30 ~51,87 'N 38 W 855.39 N 802,28 W 888,32 N 83~,08 W 921.26 N 865,89 W 955,03 N 897.38 W 989,08 N 929,13 W 1023.70 N 961,~1 W 1058.87 N 993.09 W 1093.76 N 1024.50 1129,49 N 1055,55 116~.92 N ~ 1086,35 1200,35 N 1117,15 1236,31N 1147,33 1272,57 N 1177,75 1308,83 N 1208,18 13.45,61N 1237,97 1382,69 N 1267,99 1~20,30 N 1297,37 1172,75 N %3 9 53 W 1218,53 N 43 11 46 W 1264,31N 43 13 31W 1310,~9 N 43 13 2 W 1357,05 N ~3 12 35 W 1~0~,38 N 43 12 10 W ~51.70 N ~3 9 ~9 W 1498,6~ N ~3 ? ~7 W 1592.8~ N 43 0 4 W 1639.78 N ~2 56 }8 W 1686.67 N 42 51 43 W 1733.94 N ~2 ~7 2 W 1781.22 N ~2 ~2 36 W 1~28,45 N 4.2 36 50 W 192~.65 N 42 2~ 36 W 1,095 0,520 0,000 0,523 0,250 0,500 0,473 0,250 0.534 0,250 0,000 0'~69 0,250 0,000 0.473 0.250 0,~77 1171,~8 1217,18 1262,88 1309.01 1355.53 1402.82 1~97,07 1544.40 1638,29 1688,23 1732.56 1779.89 1~27.2~ 187~.91 1922.58 5800 28 30 5'345,65 5239e75 5900 28 30 5633.53 5327,63 6000 28 30 5§21.4! 5415.51 6100 26 0 5611,29 5505.39 6200 27 45 5699,79 5593.89 6300 27 0 5788,89 5682'99 6400 27 k5 5877.39 5771.49 6500 27 0 5966.49 5'860.59 6600 26 45 6055.79 5949.89 6700 26 0 6145,67 6039,77 6800 25 15 6236,12 6130.22 6900 25 15 6326e56 6220.66 7000 26 0 6416.44 6310.54 7100 27 15 6505,34 6399.4& 7200 28 0 6593,64 6487.74 7300 27 ~5 6682.14 6576,24 7400 27 15 6771e04 6665,1~ 7500 27 0 6860e14 6?54,24 7600 26 15 69&ge83 6843.93 7700 25 45 7039,90 6934e00 7800 25 0 7130,53 7024,63 7900 24 30 7221,52 7115,62 FOLLOWING SPERRY SUN SU-3-~6368 1457,90 N 1326,75 1495.50 N 1356,12 1532.58 N ~1386.15 1563.03 'N 1417,69 1595.37 N 1~51.18 1626,91N 1~83.8~ 1659.26 N 1517.33 1691,91N 15~8,87 1724,29 N 1580,13 ~755,8~ N 1610,59 1786,51 N 1640,22 1818,21 N /i668,76 1884,81N 1728.73 1920,78 N 1758,91 1956,45 N 1788.8~ 1991,52 N 1818.27 2026,30 N 1847,45 2061,15 N 1874.68 2094,91 N 1902.02 2128,22 N 1928,04 2160,89 N 1953,57 1971.23 N 42 18 12 W 2018,8.1N 42 12 6 W 2066,45 N ~2 7 ~0 W 2110,19 N 42 12 30 W 2156e65 N 42 17 24 W 2201,96 N 42 21 59 W 22~8,43 N ~2 26 30 W 2293.81N ~2 28 2~ W 2338,81N ~2 30 7 W 2382,63 N 42 31 46 W 2425,27 N ~2 33 19 w 2467,93 N ~2 32 ~S W 2511,76 N 42 32 10 W 2557.55 N 42 31 36 ~ 2604.45 N a2 28 52 W 2650.97 N 42 26 15 ~ 2696,71N 42 23 46 W 2742,07 N 42 21 23 W 2786,18 N 42 17 15 ~ 2829,55 N ~2 14 13 ~ 2871,70 N 42 10 29 W 2913,06 N 42 6 55 W 8000 24 45 73~2,3~ 7'206,44 N 33 W 8100 24 15 7403.51 7297.61 N 32 W 82'00 25 1S 7493,96 7388.06 N 33 W 8300 24 30 7~84e95 7479,05 N 32 W 8400 23 45 7676,~9 7570.59 N 33 W 8500 24 0 7767.84 7&61,94 N 31W 8600 23 15 7859e72 7753.82 N 31 W 8700 22 45 7951,94 78~6.0~ N 29 W / 2196,01N" 1976.37 w 2230.84 N 1998,14 W 2266.61N' 2021.~? W 2301e78 N 2043.35 W 2335.56 N 2065.28 W 2370,~2 N 2086,23 W 2~0~,2'6 N 2106,56 W 2438,08 N 2125,31W 2954.41N 41 59 12 W 29'94.86 N 41 51 1W 3037.02 N 41 43 36 W 3077.90 N ~1 35 46 W 3117.73 N 41 29 8 W 3157.73 N 41 21 ~ W 3196.57 N 41 13 27 W ~234,38 N 41 4 ~4 W 8800 22 15 8044,49 7938,59 N 28 W 2471,51N 2143,09 W 3271.27 N 40 55 44 W 8900 21 30 8137,54 8032,64 N 27 W ' 2504.17 N /2159.72 W 3306.85 N 40 46 34 W 900.0 21 15 8230,74 8124,84 N 28 W _2536.17 N F._2J~_6_~ ~_ 3~42.21N ~0 38 19 W 9100' 20 45 8324,25 8218,35 N 23 W 2568,78 N 2190,58 W 3375.99 N 40 27 23 W 9200 19 ~0-.- 8418,5~ 8312,61 N 22 W 9'300 18 45 8513,2! 8407.31 N 17 W 9400 1,8 ~5 8607e90 8502,00 N 17 W 9500 19 0 8702.~5 8596,55 N ~5 W 9600 18 ~5 8797e~ 8691,24 N 15 W 9700 ~9 0 889.1e70 8785'e80 N 13 W 9800 ~8 30 8986'53 8880,63 N 12 W 9900 17 &5 '908~,77 8975,87 N 10 W ~0000 ~7 90 9~77,~ 907~.2~ N ~0 W 2599,73 N 2203,09 W 2630.47 N 2212,49 W 266'1,21 N 2221.88 W 2692.66 N 2230,31 W 2723,71 N 2238.63 W 2755.43 N 2245.95 W 2786.47 N 2252,55 W 2816.49 N 2257,84 W 2846,10 N~2263,07 W 3~07.67 N 40 16 44 W 3437.22 N '40 4 1W 3466.82 N 39 51 32 W 3496,39 N 39 38 4 W 352b,63 N 39 25 I ~ 3554,82 N 39 1~ 0 W 3583.07 N 38 57 6 W ~609,78 N 38 4~ 2 W 3636.18 N 38 29 23 W 0'000 0'000. 0.477 4.061 1,750 0.750 0.750 1.187 0'250 0.750 0.750 0,853 0.750 1.250 1.193 0.250 0.500' 0,250 1.169 0,665 0,86~ 0.500 2.098 0.650 1.084 0.'860 0,847 0.750 0.928 0.630 0.837 0,442 1.860 1,296 1.801 0.000 0.694 0,250 0,69~ 0o59~ 0,.974 0.250 1970.25 2017,92 2065.62 2109,25 215'5.60 2200,79 22~7.14 2292.45 2337.38 2381e13 2423.71 2~66,35 2510.18 2555.95 2602.89 2669.~5 2695,2~ 2740.64 278~.82 2828.25 2870.47 2911.90 ~'29~3.41 2994.03 3036.32 3077.34 3117.27 3t57.38 3196.32 3234.21 3271.18 3306.82 3342.20 3375.99 3407.65 3~37.12 3466.60 3495.99 3553.88 3581.76 3608.03 3633,94 9 10100 16 30 9273,02 9167.12 N 8 W 10200 15 15 9369.50 9263,60 N ? W 10300 14 0 9466.53 9360.63 N 4 W 10400 13 15 9563.87 9457.97 N ? W 10500 12 45 9661,40 9555.50 N 2 W 10600 12 0 9759,22 9653.32 N 1 E 10700 11 30 9857.21 9751.31 N 0 E 10800 11 0 9955,3? 9849,47 N 1W 10900 10 0 10053,85 9947,95 N 9 E 11000 ~ 30 10~2,48 10046,~8 N 22 E 1~100 9 15-~02~1,18 10145,28 N 27 E 11200 8 30 10350.08 10244.18 N 30 E 11300 T 30 10449,23 10343,33 N 31 E 11400 6 30' 10548,58 10442.68 N 37 E 11500 6 15 10647.99 10542,09 N 44 E 11600 6 0 107~T,4~ 10641,54 N 38 E 11700 5 45 10846.94 10741,04 N 36 E 11800 '5 45 10946,44 10840,54 N ~5 E 11900 '5 45 11045,93 1094'0,0~ N 42 E 12000 6 1S 11145,34 11039,4~ N 44 E 11100 ? 15 11244,54 11138,64 N ~3 E ABOVE SPERRY SUN SINGLE SHOT GYRO SURVEY 122,0.0 8 30 11343,44 11237,54 N 61 E 12239 8 45 11381,99 11276,09 N 64 E 12400 8 45 11541,11 I1435,21 N 60 g ABOVE SPERRY SUN MAGNETIC SINGLE SHOT 2874,23 N 2267,02 2900,34 N 1270,22 2924,47 N 2271.91 2947,22 N 2274.71 2969.28 N 2275.48 2990.06 N 2275.11 3010.00 N 2275,11 3029.08 N 2275.~5 3046.23 N 2272,73 3061,53 N~2266,55 3075.85 N 2259.25 3088.65 N 2251.86 3099.8~ N 2245,1~ 3108.88 N 2238.32 3116.72 N 2230.76 3124.95 N 2224.32 3133,06 N 2218.44 3141,26 N 2212.69 3148,71 N 2205,99 3164,14 N 2188.3~ 3171,30 N 2175,42 3173.90 N 2170,05 3186,15 N 2148.87 3660.68 N 38 15 51W 3683.19 N 38 3 6 W 3703,26 N 37 50 32 W 3722,96 N 37 39 41W 3740.91N 37 27 51W 3757,21N 37 16 1W 3773,10 N 37 5 1 W 3788,53 N 36 54 50 W 3800,63 N 36 ~3 33 W 3809e23 N 36 30 49 W 3816,~2 N 36 17 51W 3822.39 N 36 5 41W 3827.49 N 35 5~ ~3 W 3830.83 N 35 45 10 W 3832.78 N 35 35 34 W 3835.75 N 35 26 35 W 3838.95 N 35 18 4 W 3842.34 N '35 9 38 W 3844.58 N 35 O 54 W 3846.66 N 34 ~1 21W 3847.16 N 34 40 5 W 3845.73 N 34 26 56 W 384~.86 N 3~ 21 41W 38~3.07 N 33 59 50 W 1.158 1.280 1,461 1,030 1.230 0,988 0,540 0,537 2.075 2,252 0.852 0.881 1,010 1.238 0.816 0.687 0,323 0.100 0,701 0,542 1.453 1.660 1,320 0,378 3657.89 3679,83 3699,27 3718.39 3735,66 3751.23 3766,39 3781,11 3792,39 3800,01 3806.16 3811.10 3815.24 3817.69 3~18.73 3820.82 38Z3.16 38~5.~7 38~5.97 3828.02 3827.25 382~,30 3822,81 3818,35 BOTTOMHOLE CLOSURE 3~43,07 FEET AT N 33 59 50 W INTERPOLATED TRUE VERTICAL DEPTHS~ COORDINATES AND CLOSURES FOR GIVEN DEPTHS TRUE MEASURED VERTICAL DEPTH DEPTH TOTAL . COORDINATES CLOSURE DISTANCE ANGLE D M 5 SUB SEA 11000 10152,48 3061,5.3 N 2266,5'5 W 11225 10374,87 3091,45 N 2250,18 W 3809.23 N 3'6 30 49 W 100~6,58 3823,66 N ~6 2 59 W 10268.97 11515 10662,91 3117,95 N 2229,79 12150 11293*99 3167.72 N 2181.88 3833,23 N 35 34 13 W 10557,01 3846,43 N 34 33 30 W 11188,09 MEASURED DEPTH AND OTHER DATA FOR EVERY EVEN 100 FEET OF TRUE VERTICAL DEPTH. TRUE MEASURED VER:r I CAL MD-TVD VER T I CAL DEPTH DEPTH DIFFERENCE CORRECTION 100 100, O' 0 200 200, 0 0 300 300, 0 0 400 400, 0 0 500 500, 0 0 600 600, 0 0 700 700. 0 0 800 800, 0 0 900 900, 0 0 1000 1000, 0 0 1101 1100, I 1 1202 1200, 2 1 1304 1300, 4 2 1405 1400, 5 1 1508 1500, 8 3 1610 1600, 10 2 171~ 1700, 1818 1800, 1924 1900, 24 6 203'2 2000, 32 8 21~ - 2100. ~4 12 2258 2200, 58 2371 2300, 71 13 2~8~ 2~00, 83 12 2595 2500, 95 12 2707 2600, 107 12 2820 2700, 120 13 Z932 2800, 132 12 30~ 2900, 144 12 '~15.7 ~000, 157 13 ~2&9 3100, 169 12 3380 3200, 180 11 TOTAL COORDINATES 0 cO7 S 0,39 $ 0,98 S 0,86 S 0e64 S 0,37 S 0,06 N 1.00 N 1.79 N 4,18 N 13,88 N 25,85 N 55,50 N 74,05 N 94.78 N 119,1~ N 1~7 ,~5 N 179,53 N 215.~3 N 256.~2 N 298.59 N 3~9.10 N 372.~5 N 606.22 N 636.32 N 668.96 N 501.31 N 53~,81 N 568,56 N 601.77 N ~35,97 N 0.07 0.12 3,22 4,67 6,30 7,98 9.75 11,34 .'.13,90 '~21,47 30.50 ~0.SZ 50,68 72,19 83,25 94,45 109,24 128,60 ~56,13W 189,76 224,82 262,75 301,86 ~80,54 ~58.92 ~97,08 535,28 571,76 3492 3603 3715 3826 3937 4049 4162 4274 4387 4500 4613 4727 4840 4953 5067 5180 5293 5~07 5520 ~748 5862 6~ 6200 6313 6~25 6~9 6760 687~ 69~2 7207 7320 7~32 75~ 7656 7766 7876 7986 B096 8~07 83~6 8~26 8535 3300, 3400. 3500, 3600. 3700. 3800, 3900, ' 4000, 4100, 4200, 4300. 4400, 4500, 4600, 4700, 4800, 4900, 5000, 5100, 5200, 5300, 5400, 5500. 5600. 5700. 5800, 5900. 6000e 6100, 6200, 630'0 · 6400. 6500, 6600. 6700, 6800, 6900, 7000, 7100, 7200. 7300. 7400, 7500, 7600, 7700. 7800, 192 203 215 226 237 249 262 274 287 300 313 327 340 353 367 380 393 407 420 434 448 462 476 487 500 513 525 538 549 560 571 582 607 620 632 656 666 676 686 696 707 716 726 735 12 11 12 11 11 12 13 12 13 13 13 14 13 14 13 13 14 13 14 11 12 11 11 11 11 13 12 12 12 10 10 10 11 9 10 9 669,25 N 702,53 N 736,99 N 770,95 N 804,25 N 839,07 N 875,66 N 912,70 N 950,5~ N 988,97 N 1028,34 N 1068.17 N 1108,05 N 1148.40 N 1188.53 N 1229.08 N 1270.17 N 1311.37 N 1353,20 N 1395,58 N 1438.36 N 1481,15 N 1523,54 N 1559.20 N 1595,45 N 1630,97 N 1667.54 N ~704,Q6 N 1739,80 N 1774,25 N 1808.90 N 1844.83 N 1882,77 N 1923.34 N 1963,~9 N 2002,82 N 2041,79 N 20?9,96 N 2117,00 N 2153,16 N 2191,23 N 2229,49 N 2268.95 N 2307.33 N 2344,5~ N 2382.26 N 608.27 643.97 678.59 71~,34 750.46 785.96 821,85 857.62 893.19 929,03 965.59 1001,46 1036.92 1072,00 1106.88 1141.27 1175.74 1210,23 1244ell 1278.06 1311,49 1344,91 1378.83 1413.72 1451,25 1488,04 ~525.33 1560.60 ~595,11 1.628,38 1660.38 16~2.7~ 1726.89 1761.06 1794,75 1827.75 1859,55 1889.9~ 1919.~8 1973.28 1997,~0 2022.83 2046.95 2070.67 2093.35 866~ 7900, ~4 9 2419,03 N 211~.75 8752 8000, 752 8 2~55.44 N 213~,54 8860 8100. 760 8 2490.99 N 2153.01 8967 8200, 767 7 2525,61 N 2171.13 9074 8300. 774 7 2560.32 N 2186.99 9180 8400. 780 6 2593.65 N 2200.63 9286 8500. ?86 6 2626.18 N 2211.17 9392 8600. ?92 6 2658.65 N 2221.10 9697 8700. 797 5 2691.84 N 2230.09 9603 8800. 803 6 2724.66 N 2238.85 9?09 8900. 809 6 2758.15 N 2246.53 9814 9000. 81~ 5 2790.71 N 2253.30 9919 9100, 819 5 2822,15 N 2258.84 10024 9200. 824 5 2852.81N 226~e01 10128 9300, 828 4 2881.5~ N 2267.91 10231 9400, 831 3 2907.92 N 2270.75 103~4 ~ 9500e 834 3 29~2,29 N 2272.87 10637 9600. 837 3 29~.~9 N 2274.99 10539 9?00. 839 2 2977.48 N 22?5.33 10642 9800. 842 3 2998.~6 N 2275.11 10744 9900, 84~ 2 ~018.~2 N 2275,26 108~5 10000, 845 1 30~6,85 N 2274.21 10947 '10100, 847 2 305~,39 N 2269.84 11048 10200, 8~8 1 3068,43 N 2263.03 11149 10300, 849 1 ~081,17 N 2255.60 11E50 10~00, .850 1 3094,29 N 2248,47 11~51 10'500, 851 1 310~,46 N 22~i.65 11652 10600, 852 1 3112.93 N 2.234.~1 115~2 107'00, 852 0 3121.02 N 2227,~0 116~3 10800, 85~ 1 3129,2~ N 2221.~1 1'1753 10900. 853 0 3137.~3 N 2215.37 11854 11000, 854 1 31~5,27 N 2209.08 11951 11100. 854 0 t152.97 N 2201,87 12055 11200. 855 1 3160.73 N 2192.87 12156 11300, 856 I 3168.15 N ~181.t0 MEASURED DEPTHS FoR EVERY IOOFT DISTANCE OUT(PLANE OF BOTTOM HOLE CLOSURE MEASURED DISTANCE DEPTH OUT 1524 100,00 1895 200,00 21&~ 300,00 235'6 2584 28).0 3033 3256 3482 3710 3937 4159 4377 4590 ~802 5015 5228 5650 5860 6076 629E) 67~0 7 X90 74O7 7631 7868 ~llZ ~609 9175 9~12. 9863 1~83 ~089~ 400, O0 500 · O0 600,00 700,00 800,00 900.00 1000 · O0 1100,00 1200,00 1300,00 1400,00 1500,00 1600,00 1700.00 1800,00 19 O0 · O0 2000,00 2100,00 2200,00 2300,00 2400,00 2500,00 2600,00 2700,00 2800,00 29.00,00 3000,00 3100.00 3200 ~00 3300.00 3400,00 3500,00 3600 · O0 3700.00 3800 · O0 C Form REV. 9°30-6? Su~rnit "Intentions" in Triplicate & "Subsequent Reports" in Duplicate STATE O'F ALASKA OIL AND GAS CONSERVATION COMMITTEE SUNDRY NOTIC'ES AND ,REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen or plug back to a diffierent reservoir. Use "APPLICATION FOR PERA~IT--" for such proposals.) oil [] oas Dry Hole WELL WE~.'. [] OTHER 2. NAME OF Oi'ErcATOR Mobil Oil Corporation 3"- ADDRESS OF OPERATOR P. O. BoX 1734, Anchorage, Alaska 99501 4. LOCATION O,F At surface 2360'8 and 1261'E from NW Corner, Sec. 13, TION, R12W, S.M.'.(Leg 1, Slot 6) 13. ELEVATIONS (Show' whether DF, RT, GlO, etc. 105' (KB) above Mean Low Low Water AP1 NUMF2~CAL CODE 50-133-20059 6. LEASE DESIGNATION AND SERIAL NO. State ADL 18761 7. IF INDIA.N, ALLOTTEE OR TRIBE NA1VIE 8. UNIT, FA/~-VI OR LEASE NA!VIE Union-Mobil State #1 9. WELL NO. Granite Point State #44-11 10. FII~LD /hND POOL, OR WILD~&T .Granite Point - Middle Kenai · u. SEC.. T.. R., M., (BOT~O~ HOL~ OBJECTIVE) SE 1/2 of 8E 1/4 of Sec. 11, R12W, S. 'M. 12. PER1VIIT NO. 14. 67-70 Check Appropriate Box To I~n,d'i'ca~e I~at'ure of N~ofic, e, Report, or 'Other Data EUBEEQUENT REPORT OF: NOTICE OF INTENTION TO: FRACTURE TREAT I I MULTIPLE COMPI,ETE FRACTURE TREATMENT ALTERING CASING SHOOT OR ACIDIZE ABANDONS SHOOTING OR ACIDIZING C___J ABANDONMENTS I REPAIR WELL CHANGE PLANS (Other) ~ __ __ [ J (NOTE: Report results of multiple completion on Well (Oth_er) Temporarily Suspend. Completion or Recompletlon Report and Log form.) '15. DESCRIBE I'ROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, including estimated date of starting any proposed work. · This well was spudded 7-8-68. A total depth of 12471' was reached 9-20-68. TwO potential oil zones were tested - 11,520'/11,610' & 11,630'/11,705'; 11,230/11,245' and 11,275'/11,290'. Both zones produced water. A b~dge plug, separating the two zones, was set at 11,330'. A cement plug was set at 11,015' with 23 sax Class ~G" cement Top of plug at 10,916'. The well has been temporarily suspended, and no further work is proposed at this time. RECEIVED DIVISION OF MINES & MINEEALB ANCHORAGE 16. I hereby eertif= that-the fore~9~n~ is,~ue and c or Jet CO~DITION~ OF tPPROVi~, ~ i~: ~IT~ Area Engineer DATE DATE October 18, 1968 See ~nstrucfions On Reverse Side DIVISION OF OIL A573 GAS OCtober 30, 1968 Re: Granite Point State #44-11 >~obil Oil Corporation, operator Mr. C. C. WOodruff Area Engineer Mobil Oil Corporation P. O. Box 1734 A~chorage, Alaska 99501 Dear Sir: Enclosed is your approved copy of Sund~ ~otice for the ~ove referenced well. KLV;may Enclosure Karl L. Voz~derAhe Petroleum Engineer DIVISION OF OIL ANi;~ GAS October 22, 196~; ?.~: Granite Point State #44-11 Mobil Oil Corporation, operator ar, C. C. Woodruff Area ~giueer Hobtl Oil Corporation P. O. Box 17,~ Anchorage, Alaska 9950! Dear Sir: Enclosed is your approved copy of Sundry Notice (P-3) for the above referenced well, ~V:may gnclosure truly yours, L. VonderAhe ?etrole~ gn:gineer Form P--3 REV. 9o30~7 STATE ~ ALASKA Submit "Intentions" in Triplicate & "Subsequent Reports" in Duplicate OIL AND GAS CONSERVATION COMMITTEE SUNDRY NOTICES AND REPOR¥$ 'QN WE[.L5 fda not fi~ this form £0r proposais :to dj-ill '01' to d~e/~e'n '~r. Piug ~adk to a diffierent reservoir. Use "APPLICATION FOR PEILMIT~-" for such proposals.) 1. OIL Dry Hole NAME OF 'OPEI~ATOR Mobil 0il Corporation 3. ADDRESS OF OPERATOR P. 0. Box 1734, Anchorage, Alaska 99501 4. LOCATION O'F WELL ' At surface 2360'S and 1261'E from NW Corner, Sec. 13,-TION, R12W, S.M. (Leg 1, Slot 6) 13. ELEVATIONS (Show whether DF, RT, GR, etc. 105' (KB) above Mean Low Low Water 14. ~. API NU'ME, RIC.,'kL CODE 50-133- 20059 8.~'~EASE DE~xlGNATION ~ND SERIAL NO. State ADL 18761 7. IF INDiA. N, ALLOTT~ OR TRIE~E NA_M_~ 8. UNIT, FAPdVI OR LEASE NA_ME Union-Mobil State #1 9. WIlL NO. Granite Point State #44-11 10. FIELD A2~D POOL, OR %VILDCAT Granite Point - Middle Kenai 11. SEC,, T., R., 1%%., (BOTTOM HOLE; OBJECTIVE) SE 1/2 of SE 1/4 of Sec. ,R12W~ S. M. 12. PERMIT N'O. 67 -70 'Check :Appropriate Box ¥o Indicate Nature of Notice, Report, or Other Date 11, TI05 NOTICE OF INTENTION TO: FRACTURE TREAT MULTIPLE COMPLETE SHOOT OR ACIDIZE ABANDON$ REPAIR WELL CHANGE PLANS (Other) Temporarily Suspend. [~UBSEQUENT REPORT OF: FRACTURE TREATMENT ALTERING CASING SHOOTING OR ACIDIZINO ABANDONMEi~'T* (Gibe.r) NOTE: Report results of multiple completion on .Well ompletion or Recompletion Report and Log form.) _ 15. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clea,'ly state all pertinent details, and give pertinent dates, including estimated date of starting an? proposed work. This well was spudded 7-8-68. A total depth of 12471' was reached 9-20-68. Two potential oil zones were tested - 11,520'/11,610' & 11,630'/11,705'; 11,230/11,245' and 11,275'/11,290'. Both zones produced water. A bridge plug, separating the two zones, was set at 11,330'o A cement plug was set at 11,015' with 23 sex Class ~fG" cement Top of plug at 10,916'. The well has been temporarily suspended, and no further work is proposed at this time. RECEIVED .oci 21 19BB DIVISION OF MtNF:::S & MINEEAt.~ ANCHOEAGE ,! 16. I hereby certify that .the foregoing is true and correct SIGNED ' ;' ,." ." ' ' / / (This Ipace for State office use)~ APPROVED BY . _ Area Engineer October 18, 1968 TITLE DATE ' TITLE CONDXT~ONS OF APPROVAL, IF ANY: ~ell co. let:ion report:~ hist:ory~ and logs due 30 days fro~ dat:e-of placement of above pzug. See Instruct'ions On Reverse Side Fora ATo, 1=--4 RE-~v-, 9-30-6~ STATE O,F ALASKA O}L AND GAS coNsERVATION COMMITTEE SUBMIT IN DEPLICATE MONTHLY REPORT O!F ~DRILLING AND WOR'KOVER OPE:RATIONS WELL 0THE~ '~. NAME OF OP2R~TOR Mobil Oil Corporation 3. 'ADDI~ESS OF OPEI%ATOR 4. LOCA~ION ©,F WELL (Leg 1, Slot 6) 2360' S and 1261'E From NW Corner Sec. 1 TION, R12W. S.M. APl NUAIERICAL CODE 6. LEASE DESIGNATION AND SERIAL NO. State ADL 18761 T. IF INDIAN, ALOTTEE OR TRIBE NAAiE ~IT,FARA{ OR LEASE NAA[E Mobil-Union Granite Point 9. WELL NO. 44-11 10. FIELD A-ND POOL, OR WILDCAT Granite Point 11. SEC., T., R., M., (BOTTOM HOLE OBJqDCTIVE ) Sec. 1I, TION, R12W SM, Cook Inlet 12. PER/VIITNO. 67 -70 13. REPORT TOTAL DEPTH AT END OF MONTH, CHANGES IN HOLE SIZE, CASING AND CEMENTING JOBS INCLUDING DEPTH SET AND VOLUMES USED, PERFORATIONS, TESTS A_ND RESULTS, FISHING $OB~, JUNK IN HOLE A.ND SIDE-TRACKED HOLE AND AlXIY OTHER SIGNIFICANT ~{A.N[iES IN HOI~ CONDITIONS. September 1968 Continued drilling w/8-1/2" bti to 12,400'. Ran IES, Sonic, Deniity,,and dipmeter. Ran 8-1/2" bit and drilled from 12,400' to 12,453' when pipe stuck. Backed off drill pipe at 12,290' and pulled out of hole leaving top of fish at 12,290'~' Ran in with Open end drill pipe, set at 12,290', and cemented with 70 sax Class "G" cement mixed with 15% 12/20 sand. Reamed, circulated and conditioned mud and ran 7" liner. Set liner at 12,208' with top at 7871 and cemented with 550 sax Class "G" cement + 3/4% TIC. Ran 6" bit and cleaned out:cement 10,472' to 12,088'.Ran squeeze packer, set at 7581' and squeezed 7" - 9-5/8" lap with 150 sax Class "G" cement and 3/4% TIC. Ran 6" bit and cleaned out cement 7709'° te 7872. Pressure tested lap to 5000 psi OK. Ran 6" bit and drilled cement 12,088 to 12,193. Closed rams and tested casing to 3000 psi. OK Drilled through shoe at 12,208 and polished off cement plug 12,210 to 12,230. Set Dyna Drill at 12,230 and drilled to 12,256. Ran 6" bit and drilled from 12,256 to 12,290, through soft cement and hit stub of fish. Hung open end drill pipe at 12,290 and pumped in 50 sax Class "G" cement. Ran 6" bit and cleaned out hard cement 12,090 to 12,220. Set Dyna Drill at 12,220 and drilled to 12,294. Ran 6" bit and drilled. 12,294 to 12,471 when bit stuck. String parted leaving top of fish at 12,155. Made unsuccessful attampt to recover fish. Ran gamma ray meutron and cement bond logs and set bridge plug in 7" liner at 12,148'. Perforated 7" liner @ 11,400 3/4 - 1/2" holes. DST above perfs recovered net ruse of 1051'salt water. Ran squeeze packer, holes held 3500 psi for 45 minutes. Perf'd 7" liner @ 11,150' w/4 - 1/2 holes. DST on above perfs recovered net rise 1034' salt water. 10-1-68 RECE!V D Preparing to squeeze perfs at 11,150'. 0 c 2 $1968 DIVISION OF MINES & MINEI~t.B ANCHORAGE 14. I hereby certify that the foregoir;g is truiI and correc~ / · s,c.~'z~ C/~ .~ 'TJ~/~F~/--//~J"IJLd/LTZ.~' __Area Eng'lneer ~'=i October 18, 1968 ,., ..... ,.... . ._ /lq ..... NOTE--Report on this form is require~/fol;ach calendar month, regardless of the status of operations, an0 must ~ fileO in duplicate with the Division of Mines & Minerals by ~e l~th of the succeeding month, unless othe~ise dire~ed. ~orm N'o, I:--4 I:~"V. 9-30-67 STATE OF ALASKA O~L AND GAS CONSERVATION COMMITTEE MONTHLY RE!PORT OF DRILLING AND WORKOVER OPERATIONS OrL ~ GAS ~ OTH~t~ WELL ~ WELL 2. NAIVE OF O15EP~ATOR Mobil 0il Corporatinn 3. ADDa~:SS OP OPE~TOa P. 0. Box 1734 Anchora~e~ Alaska LOCATION OF Wl~,T.T. (Leg 1, Slot 6) 2360' S and 1261' E from NW Corner Sec. 13, TION, R12W~ S. M. SUBMIT IN DEPLICATE ~i AP~ N~,mmcxn CODE LEASE DESIGNATION AND SERIAL NO. State ADL 18761 7. IF INDIAN, ALOTTEE OR TRIBE NAAIE 8. U~'IT,FA~R~I OR LEASE N,~AIE Mobil-Union Granite Point 9. WELL NO ~) 44-11 10. z,'.I..liL,D AND POOL. OR WILDCAT Granite Point 11. SEC.. T.. R.. 1%{.. (BO/TOM HOLE OBJECTIVE) Sec. 11, TION, R12W, S. M. Cook Inlet 12. PERNIIT 1~0. 68-42 13. REPORT TOTAL DEPTH AT END OF MONTH, CHANGES IN HOLE SIZE, CASING A/ND CEMENTING JOBS INCLUDING DEPTH SET A/krO VOLUiVIES USED, PERFORATIONS. TESTS A!N-D RESULTS, FISHING JOBS. JU/~K IN HOLE A/~D SIDE-TIR~CKED HOLE AND A_NY OTHER SIGNIFICANT CPIA/~,~ES IN HOI.~ CONDITIONS. August - 1968 Drilled 12 1/4" hole to 8061'. Pulled for bit change and could not get below 8045'. Ran 1ES and dipmeter. Reamed hole to 8045' and ran and set 9 5/8" O. D? Casing at 8002'. Cemented casing with 1800 sax cement, first 50 cu. ft. treated w/0.75% TIC. C. O. Cement to 7972' and ran Sperry Sun~:C. O. hole to 8061'. and drilled 8 1/2" hole to 10,764'. Ran IES and dipmeter logs. Drilled 8 1/2" hole to 11, 857'. Ran IES~ Sonic and Density Logs. Cont. drilling 8 1/2" hole to 12110'. 9-1-68 Drilling 8 1/2" hole at 12110'. SIGNED TITLE DA'z'~ NOTE--Report on this forr~~ for each calendar month, regardless of the status of operations, aaa/must Oe file(! in duplicate with the Division of Mines & Minerals by the 15th of the succeeding month, unless otherwise directed. 1. STATE O'F ALASKA sum~rT n~ DZPLZC~T~ O~L AND GAS CONSERVATION ,COMMITTEE AND YV'OR~MOV~R OPERATiOn5 WELL ~ WZLL OTHER N.~,~E OF OPLR~kTOR Mobil Oil Corporation S. ~DDRESS OF OPL~q~TOi~ P. O. Box 1734 4. LOCATION OF %VELL Anchorage, Alaska (Leg 1 Slot 6) 2360'S & 1261'E from NM Corner Sec. 13, TION, R12W. S.M. 6. LF--~SE DESiGNATiON AND SERIAL NO. State ADL 18761 7 IF INDIAN. ,,%LXDI fEE OR TRIBE 8, L~'IT, F.~F~M OR LEASE .'qA_ME , Mobil Union Gran$6~ Point 9. WELL -'qO .... 44-11 FIELD A_ND POOL. OR WILDCAT Granite Point I1. SEC.. T.. R.. Afl,. (]~0~0,%% HOL~ OBJECTIVE ~ Sec. ll, TTON, R12~, S.M. Cook Inlet 12. PlrrRaMIT NO. REPORT TOTAL D~TH AT E/%'D OF MONTH, CliA~NGES iN ~tOLE SIJE. C~a~SING A/ND CL-~ENTING JOBS INCLUDING DEPTH SET A~q) VOLI/RIES USED, PEiLFORATIONS, TESTS A/NED I~ESULTS. FISHII~G JOTS. JUNK L~g HOLE A/~D SIDE-T1R~CKED HOLE ~.A~ ~N¥ O~i~i~ StGNIFICA2gT CtiA~OF~ IN HOL~ CONqDITIONS. Moved rig and spudded 7-8-68. Drilled 15" hole to 361'. Drilled 12 1,/4" hole to 450'. Opened t5" x 12 1/4" hole to 22" to 450'. Ran and set 18" casing to 435'. Cemented with 592 cu. ft'. cement plus 3% CaC12. CO cement to 450'. Drilled 12 1/4" hole to 4048'. Opened 12 1/4" hole to 16" to 2429'. Twist off. Top off fish at 1468'. Washed over and recovered fish. Reamed 16" hole from 2100' to 2429'. Continued opening 12 !/4" hole to 16" to 4048'. Ran and set 13 3/8" casing at 4015'. D.V. collar at 2227'. Cemented 1st stage with 735 cu. ft. of Class "G" cement plys 3/4% T.I.C. Cemented 2nd stage with 1900 cu. ft. (1583 sax) class "G" cement plus 2% CaCi2 mixed with sea water. C.O. cement to 4048'. Ran Sperry-Sun Gyro Survey 4015'. Drilled 12 i/4~' hole to 8026'. 8-1-68 Drilling 12 1/4" hole at 8026'. RECEIVED AUG 1 1968 DIVISION OF MINES & MINERALS ANCHORAGE hereDy C~i£)' .'.~% t)ue foregoing is %rue and c~:Tec% I /.: .. - / ./ ../ / / ~; .,- X/.-,.~ ..... ~/ ~ , /,./ '.' . ,~ f' / - , ' ,. / / , ~ D'~quired for each calendar month, regardless of the status of opera%ions, and must ~ fitea in duplicate NOTE--Report on this form with the Division of Mines & Mineral~ by the 15th of the succeeding month, unless othe~ise directed. Mobil Oil Corporation July 11, 1968 700 "G" STREET ANCHORAGE, ALASKA 99501 Director State of Alaska Department of Natural Resources Division of Lands 344 Sixth Avenue Anchorage, Alaska - MINgRALS BRANCH Date Chief ..................... Pomeroy .............. Dowling ....... ~,~ Assigned ,.-, ...... Secretary ---!--'---: Route in Branch ................ SPUD NEW WELL MOBIL- UNION gRANITE ~OINT STATE #44-~1 Dear Sir: This is to notify you that the subject well was spudded on State Lease ADL 18761 at 7:00 P.M. on July 7, 1968. The surface location of this well is 2360'S and 1261'E from the northwest corner of Section 13, T10N, R12W, S.M. We propose to directionally drill this well to a bottom hole location 660'N and 660'W from the southeast corner of Section 11, T10N, R12W, S.M. Sincerely, Area Engineer M.J.Meyer/pj c cc: State of Alaska Division of Mines & Minerals F.K. Krebill Pan American Petroleum ANCHORAGE FORM SA- lB 125.5M 8/67 MEMORANDUM tO: ~- l~ea a. ~ FROM: 'J'JMJllldl ]Jo ]JlBL~t~, JF. Petroleum Supervisor State of Alaska DATE : SUBJECT: 1967 ~Iobil 0tl Cerpo~rton, Opere~og FORM SA - ~ B 125.5M 8/67 MEMORANDUM TO: F- ~ A. ~ D~zeetor State of Alaska DXVXSXOI~ OF Iq~HES AHD ]~,JEBAI~ FROM: Ttmmm R. Hmrmhall, Jr. l~etrolou Supe~ DATE : SUBJECT: 1'967 Griu~te Point ~tat~ Nobtl O~ the amount of ~50.00 fac f~t.l~ fee. Tut/Jr Mobil Oil Corporation- 612 SOUTH FLOWER STREET LOS ANGELES, CALIFORNIA 90054 Northwest Producing Area P. O. Box 1734 Anchorage, Alaska 99501 November 9, 1967 State of Alaska Division of Mines & Minerals 3001 Porcupine Drive Anchorage, Alaska Attn: Mr. Thomas R. Marshall, Jr. Dear Sir: Enclosed are three copies of our application to drill Union-Mobil Granite Point State ~44-11 (State Form P-l), three location plats and our draft for $50.00. This well will be spudded after receipt of your approval· Please sign and return the yellow copy of the draft· Yours vp~~~ · . Woodruff ~ Il Area Engineer MJMEYER:sw Attachment: I ' ~ NOV 13 1967 ,~:~,~.~ ~'~. DIVi~ION OF MINES' &. M~E~ revers2~ ........ ~ AP1 ~! 50-133-20059 · ' . .~ve: Juiy i, ~9~ C~ A,~D GAS CONS~;iiVATION 3C.,~"b~ISSIO~ j 5. ~EASE os~z~*~zo~ .,~ ~¢~.~ ~o. '- State ADL 18TM /. . "'[.'~,T'~,.2'ION FOR.. PERMIT TO DRILL, DEEPEN, OR PLUG BACK .... ~' "'~"""~ ....... "::: &- DRILL M---q DEEPEN ['] ~:~ PLUG"BACK b. TYPE O~ ~r~L. OIL'-- OAS ~'~ SINOL~ .... MULTIPLE F- NAME OF OPERATOR Mobil Oil Corporation ADDRESS OF OPERATOR 4. P. 0. Box 17L4~ Anchorase~ ~OCATION OF W~LL (ReDo;": ~o':~a~lon clearly and In ~ccor~ce w~ .... ~te requirements.*) ~ts"~aC%L~g 1 Siou o) 2360'S & 226i'E from ".~ Corner Sec. 13, T/CY, 'Ri' W from the SE Corer Sec. ~, TION, K~ .~ S.M. DI6~'~NCE ~1%~ILE8 AND DIRDCTION FROM NEAREST TOWN OR POST OFFICE* Cook Iniet- ~,pprox. 11 miles South of Tyonek Village 10. I8. DISTANCE FROM PROPOSEDs ~OCATIO~ TO NE*~ST 660 ' PaoPEa~ oa LEAS~ LINE, FT. (Also tO nearest drlg. unit line, if any) DISTANCE FROM PROPOSED LOCATIONs TO NEAREST WELL, DRILLINO. COMPLETED, OR APPLIED FOR, ON THIS LEABE, j16.NO. OF ACRES IN LEASE j 5089 ( 160' ) ~..PROPOSED DEPT~ 2200' t i2'000~MD 17. NO. OF ACRES ~S~:/,~.>;',Cb TO THIS W,~LL Rot.' 21. R,~V&~ONS (Show whether DF, RT, OR, etc.) 106~ above MLLW (K.B.) 23. PROPOSED CASING AND CEMENT.i~G PROGRAM Well will be d:.:~.~c'rzonaily drilled approx. 350C', N30°W from the surfac~- iocz.:zon to total depth of 12,000'+MD (ll,000'+VD) in order to reach the objec~;..v.' the permanent 'platform. BOP Program: 600 ' 4000 ' to 4000' ' 20 3/4" Hydril '~SP" 2000 psi WaG to TD : 13 3/8" Hydrii '[;:iT' 560~' psi .WaG 13 3/8" Cameron 'L"' a~'~>.ple 5000 p~ IN ABOVE SPACg DgSCRIB~ PROPOSED ~.'~.Q,.,i;.~,'~: If proposal Is to deepen or plug back, give data on present productive zone zone. ~ Proposal is to drill or deeper, d~rectionally, give pertinent data on subsurface locations and measured and true ~ preventer program, ff any. 24. I hereb~e~fy ~t t,ae /'or,: .... ~ _~ '~r~e and C~rect (This space fe~ ~ede~ o~ ~te e~ee u~ / APPROVED BI ._ . · APPROV,~.. THOMAS R.. ~A~$HAtt, ~×ecutive Secretory Conservation Committee AP1 # 50-133-20059 *See Indructions On Reve,~¢ Side ,)906 ,..-. tept -. c.. 2.5 ~ I :30 2.9 II 12 ADL't S74Z I ' I~ 13H$ ~ 33'13 I I · I MOBIL. PL AT POR,,,'~ ~: ;Z63, :553' ~7 t 1 1 1 MOBIL OIL CORPORATION ,,, "· COOK INL ET ALASKA STATE., A DL..'18.'761 sc.au, ff:~ --.4ooo' · ~^¥[;]1-8-G',? _
