Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation
Commission
HOME
EVENTS
DATA
Data List
Drilling
Production
Orders
Data Miner
Document Search
REPORTS
Reports and Charts
Pool Statistics
FORMS
LINKS
Links
Test Notification
Data Requests
Regulations
Industry Guidance Bulletins
How to Apply
ABOUT US
History
Staff
HELP
Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Home
My WebLink
About
169-050
Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/19/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250919 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 212-35T 50283200970000 198161 8/10/2025 AK E-LINE PPROF T40899 BRU 223-34T 50283202060000 225059 8/17/2025 AK E-LINE CBL T40900 BRU 234-27 50283202070000 225065 9/12/2025 AK E-LINE CBL T40901 BRU 242-04 50283201640000 212041 6/9/2025 AK E-LINE Perf T40902 KBU 11-08Z 50133206290000 214044 9/8/2025 AK E-LINE Perf T40903 MPU H-03 50029220630000 190088 9/9/2025 AK E-LINE SetPacker T40904 MPU H-11 50029228020000 197163 2/9/2025 AK E-LINE Caliper T40905 MPU M-62 50029237440000 223006 8/31/2025 AK E-LINE LDL T40906 NCIU A-06 50883200260000 169050 8/25/2025 AK E-LINE TubingCut T40907 NCIU A-21A 50883201990100 225075 8/26/2025 AK E-LINE Perf T40908 ODSK-33 50703205620000 207183 9/10/2025 READ Caliper Survey T40909 ODSN-01a 50703206480100 216008 9/8/2025 READ Caliper Survey T40910 ODSN-06 50703207150000 215098 9/9/2025 READ Jewelry Log T40911 PBU C-34C 50029217850300 225068 8/25/2025 BAKER MRPM T40912 PBU Q-06A 50029203460100 198090 8/21/2025 BAKER SPN T40913 TBU M-25 50733203910000 187086 8/31/2025 AK E-LINE Drift T40914 Please include current contact information if different from above. T40907NCIU A-06 50883200260000 169050 8/25/2025 AK E-LINE TubingCut Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.22 13:22:50 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:6 Township:11N Range:9W Meridian:Seward Drilling Rig:Hilcorp 151 Rig Elevation:53.4 ft RKB Total Depth:8045 ft MD Lease No.:ADL17589 Operator Rep:Suspend:NA P&A:X Conductor:16"O.D. Shoe@ 623 Feet Csg Cut@ NA Feet Surface:10-3/4"O.D. Shoe@ 2579 Feet Csg Cut@ NA Feet Intermediate:NA O.D. Shoe@ NA Feet Csg Cut@ NA Feet Production:7"O.D. Shoe@ 8016 Feet Csg Cut@ NA Feet Liner:NA O.D. Shoe@ NA Feet Csg Cut@ NA Feet Tubing:4-1/2"O.D. Tail@ 6279 Feet Tbg Cut@ 3860 Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Fullbore Retainer 3850 ft MD 3698 ft MD 8.6 ppg Drillpipe tag Initial 15 min 30 min 45 min Result Tubing NA NA NA IA 2280 2242 2226 OA 20 20 20 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Luke Moore Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): I traveled to location (Tyonek Platform) to witness the drill pipe conveyed tag and mechanical integrity pressure test (MIT) of a cement plug to plug off the motherbore of the well prior to redrill. The 4-1/2" tubing was cut at 3860 ft MD. A retainer was then set at 3850 ft MD in the 7" production casing. Per company man 70 barrels of cement was pumped below the retainer before un stinging and laying 7 to 8 barrels on top. With a tapered mill they tagged at 3698 ft MD with 6k lbs down for a hard tag. Pump pressure increase noticed. Closing in the well they then successfully got a passing MIT to a target of 2050 psi. Above bottom depth of plug is retainer depth. No issues. August 31, 2025 Austin McLeod Well Bore Plug & Abandonment N Cook Inlet Unit A-06 Hilcorp Alaska, LLC PTD 1690500; Sundry 325-399 none Test Data: P Casing Removal: rev. 3-24-2022 2025-0831_Plug_Verification_NCIU_A-06_am 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: 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: Same 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 8,045 N/A Casing Collapse Structural Conductor 630 Surface 2090 Intermediate Production 4320 Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: 907-223-6784 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 Sean Mclaughlin sean.mclaughlin@hilcorp.com Drilling Manager N Cook Inlet Unit A-06 North Cook Inlet Tertiary System Gas 6,892 6,380 5,503 2,034 4717' 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 AOGCC USE ONLY Tubing Grade:Tubing MD (ft): See Schematic Perforation Depth TVD (ft): STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 17589 / ADL 37831 169-050 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20026-00-00 Hilcorp Alaska, LLC Length Size Proposed Pools: 382'382' 12.75# / EUE 8RD / J-55 TVD Burst 6279' 4980 MD 1640 3580 623' 2,397' 623' 2,579' 6,866'7" 382'30" 16" 10-3/4" 623' 2,579' 8,016' Perforation Depth MD (ft): 4021 - 7010' 8,016' 3573'-6014' 8/1/2025 4-1/2" See Schematic m n P s 1 6 5 6 t _ N 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 3:37 pm, Jul 23, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.07.15 09:19:00 - 08'00' Sean McLaughlin (4311) 325-399 A.Dewhurst 01AUG25 DSR-7/23/25 Variance to 20 AAC 25.112(c) granted. * BOPE pressure test to 3000 psi. Annular to 2500 psi. 48 hour notice to AOGCC. * State to witness tag and pressure test of cement abandonment plug w/ TOC ~ 3650' MD. Pressure test to 2050 psi. 48 hour notice. MGR07AUG25 10-407 Variance to 20 AAC 25.112(c) granted. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.08.08 09:38:23 -08'00'08/08/25 RBDMS JSB 081225 Well Prognosis Well: NCIU A-06 Date: 7/2/25 Well Name:NCIU A-06 API Number:50-883-20026-00-00 Current Status:Plug For Redrill Estimated Start Date:8/1/25 Rig:Spartan 151 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:169-050 First Call Engineer:Sean Mclaughlin 907-223-6784 Second Call Engineer AFE Number: Attachments: 1.Current Schematic 2.Proposed Schematic 3.Proposed Operations 4.BOPE Schematic Updated By: JLL 10/10/24 SCHEMATIC Tyonek Platform Well:A-06 PTD:169-050 API:50-883-20026-00 Completed: 09/12/1994 Casing Detail SIZE WT GRADE CONN MIN ID TOP BTM 30”Conductor Welded 28.000 Surf 382’ 16”65#H-40 Welded 15.062 Surf 623’ 10-3/4”51#J-55 BTC 9.850 Surf 562' 45.5#J-55 BTC 9.950 562'2,579’ 7” 26#J-55 BTC 6.276 Surf 79' 23#J-55 BTC 6.366 79'6,966' 26#J-55 BTC 6.276 6,966'8,016’ Tubing Detail 4-1/2”12.75#J-5 EUE 8rd Mod 3.992 Surf 6,279’ Jewelry Details No Depth MD Depth TVD ID OD Item 41’41’4.500 FMC Tubing Hanger 1 295’295’3.813 Halliburton XXO SCSSV Nipple 2 3,903’3,478’3.950 Upper Body PBR Assembly 3,912’3,485’3.992 Ratch Latch 3,914’3,487’3.880 Halliburton VSR Packer 3 3,951’3,517’3.813 Halliburton X Nipple 4 4,233’3,743’3.950 Seal No-Go Unit 4,236’3,748’4.000 Halliburton TWR Packer 4,240’3,748’4.276 Millout Extension w/Tubing Adapter 5 4,405’3,881’3.813 Halliburton XD Sliding Sleeve (Open 1/31/2002) 6 4,409’3,885’3.950 Seal No-Go Unit 4,412’3,887’4.000 Halliburton TWR Packer 4,416’3,890’4.276 Millout Extension w/Tubing Adapter 7 4,493’3,952’3.813 Halliburton XD Sliding Sleeve (Open 1/31/2002) 8 4,501’3,959’3.950 Seal No-Go Unit 4,504’3,961’4.000 Halliburton TWR Packer 4,508’3,965’4.276 Millout Extension w/Tubing Adapter 9 4,547’3,997’3.813 Halliburton XC Sliding Sleeve (Open 1/31/2002) 10 4,559’4,007’3.950 Seal No-Go Unit 4,562’4,009’4.000 Halliburton TWR Packer 4,566’4,012’4.276 Millout Extension w/Tubing Adapter 11 4,636’4,070’3.813 Halliburton XD Sliding Sleeve (Open 1/31/2002) 12 4,646’4,078’3.950 Seal No-Go Unit 4,649’4,080’4.000 Halliburton TWR Packer 4,653’4,084’4.276 Millout Extension w/Tubing Adapter 13 4,729’4,146’4.000 Seal No-Go Unit 4,731’4,148’4.000 Halliburton TWR Packer 4,735’4,151’4.276 Millout Extension 14 4,751’4,164 PX Plug - (1/2002) 15 4,774’4,183’3.813 Halliburton XD Sliding Sleeve (Closed) 16 4,783’4,190’3.950 Seal No-Go Unit 4,785’4,192’4.000 Halliburton TWR Packer 4,789’4,196’4.276 Millout Extension w/Tubing Adapter 17 4,877’4,267’3.950 Seal No-Go Unit 4,879’4,269’4.000 Halliburton TWR Packer 4,884’4,273’4.276 Millout Extension w/Tubing Adapter 18 4,952’4,238’3.813 Halliburton XD Sliding Sleeve (Closed) 19 4,999’4,367’3.950 Seal No-Go Unit 5,002’4,370’4.000 Halliburton TWR Packer 5,006’4,373’4.276 Millout Extension w/Tubing Adapter 20 5,128’4,474’3.813 Halliburton XD Sliding Sleeve (Open 12/13/2001) 21 5,172’4,510’EZSV Bridge Plug 22 5,195’4,528’3.950 Seal No-Go Unit 5,197’4,531’4.000 Halliburton TWR Packer 5,202’4,534’4.276 Millout Extension w/Tubing Adapter 23 5,615’4,874’3.813 Halliburton XA Sliding Sleeve (Closed) 24 6,277’5,416’3.813 Halliburton XN Nipple 25 6,278’5,417’3.995 Wireline Re-Entry Guide DGL Packer Assembly No Depth MD Depth TVD ID OD Item A 3,865’3,448 2.375 374 Widepak Packer 3,891’3,469’2.240 2P Anchor Seal Latch 3,895’3,472’2.375 374 Widepak Packer 3,902’3,478’0.875 Stinger Rod w/DFCV 3,909’3,483’1.750 PBR Seal Bore 3,910’3,484’1.375 Torq-Thru Quick Connect 4,658’4,088’0.375 2.375” Dual Flapper Assembly SCHEMATIC Tyonek Platform Well:A-06 PTD:169-050 API:50-883-20026-00 Completed:09/12/1994 PERFORATION DETAIL Zone Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status CI Stray 4,021'4,031'3,573'3,581'10'9/12/1994 Open CI-A 4,055'4,080'3,600'3,620'25'9/12/1994 Open CI-B 4,102'4,107'3,637'3,641'5'9/12/1994 Open CI-B 4,112'4,162'3,645'3,685'50'9/12/1994 Open CI-1 4,325'4,380'3,816'3,860'55'9/11/1994 Open CI-1 4,388'4,398'3,867'3,875'10'9/11/1994 Open CI-2 4,420'4,490'3,893'3,950'70'9/11/1994 Open CI-3 4,509'4,519'3,965'3,974'10'9/11/1994 Open CI-3.1 4,540'4,550'3,991'3,999'10'9/11/1994 Open CI-4 4,564'4,614'4,010'4,051'50'9/11/1994 Open CI-5 4,660'4,700'4,089'4,122'40'9/7/1994 Open CI-5.1 4,711'4,716'4,131'4,135'5'9/7/1994 Open CI-6 4,733'4,753'4,149'4,165'20'9/11/1994 Open CI-7 4,792'4,822'4,197'4,222'30'9/11/1994 Isolated CI-7.1 4,832'4,852'4,230'4,246'20'9/11/1994 Isolated CI-8 4,880'4,890'4,260'4,277'10'9/11/1994 Isolated CI-8.2 4,912'4,927'4,298'4,307'15'9/11/1994 Isolated CI-9 4,963'4,983'4,337'4,353'20'9/11/1994 Isolated CI-10 5,004'5,014'4,371'4,379'10'9/11/1994 Isolated CI-11 5,031'5,076'4,393'4,430'45'9/11/1994 Isolated B-2 5,220'5,235'4,549'4,561'15'9/11/1994 Isolated B-5.5 5,302'5,308'4,616'4,621'6'9/11/1994 Isolated CI-6 5,327'5,332'4,626'4,640'5'9/11/1994 Isolated C-1 5,393'5,413'4,690'4,707'20'9/11/1994 Isolated C-2.5 5,444'5,448'4,732'4,736'4'9/11/1994 Isolated D-1 5,540'5,545'4,812'4,816'5'9/11/1994 Isolated D-5 5,665'5,680'4,915'4,927'15'9/11/1994 Isolated E-4 5,731'5,736'4,969'4,973'5'9/11/1994 Isolated E-8 5,793'5,797'5,020'5,023'4'9/11/1994 Isolated E-9 5,810'5,820'5,034'5,042'10'9/11/1994 Isolated F-1 5,842'5,847'5,060'5,064'5'9/11/1994 Isolated F-3 5,884'5,889'5,094'5,098'5'9/11/1994 Isolated F-4 5,895'5,915'5,103'5,120'20'9/11/1994 Isolated G-1 5,980'5,990'5,173'5,181'10'9/11/1994 Isolated H-1/H-1.1 6,084'6,094'5,258'5,266'10'9/11/1994 Isolated H-3 6,123'6,133'5,290'5,298'10'9/11/1994 Isolated H-4 6,136'6,141'5,301'5,305'5'9/11/1994 Isolated H-7 6,182'6,197'5,338'5,350'15'9/11/1994 Isolated H-9 6,236'6,261'5,382'5,403'25'9/11/1994 Isolated J-1 6,420'6,425'5,532'5,537'5'9/11/1994 Isolated K-3 6,520'6,525'5,614'5,618'5'9/9/1994 Isolated K-4 6,536'6,551'5,627'5,640'15'9/9/1994 Isolated L-2 6,587'6,592'5,669'5,673'5'9/9/1994 Isolated M-6 6,684'6,689'5,748'5,752'5'9/9/1994 Isolated M-9 6,734'6,739'5,789'5,793'5'9/9/1994 Isolated N-2 6,828'6,843'5,866'5,878'15'9/9/1994 Isolated O-4 6,995'7,010'6,002'6,014'15'9/9/1994 Isolated Cement Details 10-3/4”15” hole:Pumped 584sxs 11.5ppg class G lead followed by 125sxs 14.7ppg class G tail.Assumed ToC to surface 7” 9-5/8” Hole: Pumped 402sxs 11.0ppg class G primary stage. Second stage:Pumped 705sxs 14.3ppg class G second stage cement through stage collar at 5,111’ MD.5/28/69 CBL shows ToC at 2500’ MD. Squeezed from 4299-4300’ with 118 sxs Updated By: CJD 7/2/25 Proposed Schematic Tyonek Platform Well:A-06 PTD:169-050 API:50-883-20026-00 Completed: 09/12/1994 Casing Detail SIZE WT GRADE CONN MIN ID TOP BTM 30”Conductor Welded 28.000 Surf 382’ 16”65#H-40 Welded 15.062 Surf 623’ 10-3/4”51#J-55 BTC 9.850 Surf 562' 45.5#J-55 BTC 9.950 562'2,579’ 7” 26#J-55 BTC 6.276 Surf 79' 23#J-55 BTC 6.366 79'6,966' 26#J-55 BTC 6.276 6,966'8,016’ Tubing Detail 4-1/2”12.75#J-55 EUE 8rd Mod 3.992 3860’ (Cut)6,279’ Jewelry Details No Depth MD Depth TVD ID OD Item 1 ~3,318’3003’Whipstock 1a 3850’6.276 Cement Retainer w/ 8 bbls cmt on top 2 3,903’3,478’3.950 Upper Body PBR Assembly 3,912’3,485’3.992 Ratch Latch 3,914’3,487’3.880 Halliburton VSR Packer 3 3,951’3,517’3.813 Halliburton X Nipple 4 4,233’3,743’3.950 Seal No-Go Unit 4,236’3,748’4.000 Halliburton TWR Packer 4,240’3,748’4.276 Millout Extension w/Tubing Adapter 5 4,405’3,881’3.813 Halliburton XD Sliding Sleeve (Open 1/31/2002) 6 4,409’3,885’3.950 Seal No-Go Unit 4,412’3,887’4.000 Halliburton TWR Packer 4,416’3,890’4.276 Millout Extension w/Tubing Adapter 7 4,493’3,952’3.813 Halliburton XD Sliding Sleeve (Open 1/31/2002) 8 4,501’3,959’3.950 Seal No-Go Unit 4,504’3,961’4.000 Halliburton TWR Packer 4,508’3,965’4.276 Millout Extension w/Tubing Adapter 9 4,547’3,997’3.813 Halliburton XC Sliding Sleeve (Open 1/31/2002) 10 4,559’4,007’3.950 Seal No-Go Unit 4,562’4,009’4.000 Halliburton TWR Packer 4,566’4,012’4.276 Millout Extension w/Tubing Adapter 11 4,636’4,070’3.813 Halliburton XD Sliding Sleeve (Open 1/31/2002) 12 4,646’4,078’3.950 Seal No-Go Unit 4,649’4,080’4.000 Halliburton TWR Packer 4,653’4,084’4.276 Millout Extension w/Tubing Adapter 13 4,729’4,146’4.000 Seal No-Go Unit 4,731’4,148’4.000 Halliburton TWR Packer 4,735’4,151’4.276 Millout Extension 14 4,751’4,164 PX Plug - (1/2002) 15 4,774’4,183’3.813 Halliburton XD Sliding Sleeve (Closed) 16 4,783’4,190’3.950 Seal No-Go Unit 4,785’4,192’4.000 Halliburton TWR Packer 4,789’4,196’4.276 Millout Extension w/Tubing Adapter 17 4,877’4,267’3.950 Seal No-Go Unit 4,879’4,269’4.000 Halliburton TWR Packer 4,884’4,273’4.276 Millout Extension w/Tubing Adapter 18 4,952’4,238’3.813 Halliburton XD Sliding Sleeve (Closed) 19 4,999’4,367’3.950 Seal No-Go Unit 5,002’4,370’4.000 Halliburton TWR Packer 5,006’4,373’4.276 Millout Extension w/Tubing Adapter 20 5,128’4,474’3.813 Halliburton XD Sliding Sleeve (Open 12/13/2001) 21 5,172’4,510’EZSV Bridge Plug 22 5,195’4,528’3.950 Seal No-Go Unit 5,197’4,531’4.000 Halliburton TWR Packer 5,202’4,534’4.276 Millout Extension w/Tubing Adapter 23 5,615’4,874’3.813 Halliburton XA Sliding Sleeve (Closed) 24 6,277’5,416’3.813 Halliburton XN Nipple 25 6,278’5,417’3.995 Wireline Re-Entry Guide DGL Packer Assembly No Depth MD Depth TVD ID OD Item A 3,865’3,448 2.375 374 Widepak Packer 3,891’3,469’2.240 2P Anchor Seal Latch 3,895’3,472’2.375 374 Widepak Packer 3,902’3,478’0.875 Stinger Rod w/DFCV 3,909’3,483’1.750 PBR Seal Bore 3,910’3,484’1.375 Torq-Thru Quick Connect 4,658’4,088’0.375 2.375” Dual Flapper Assembly Proposed Schematic Tyonek Platform Well:A-06 PTD:169-050 API:50-883-20026-00 Completed:09/12/1994 PERFORATION DETAIL Zone Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status CI Stray 4,021'4,031'3,573'3,581'10'9/12/1994 Open CI-A 4,055'4,080'3,600'3,620'25'9/12/1994 Open CI-B 4,102'4,107'3,637'3,641'5'9/12/1994 Open CI-B 4,112'4,162'3,645'3,685'50'9/12/1994 Open CI-1 4,325'4,380'3,816'3,860'55'9/11/1994 Open CI-1 4,388'4,398'3,867'3,875'10'9/11/1994 Open CI-2 4,420'4,490'3,893'3,950'70'9/11/1994 Open CI-3 4,509'4,519'3,965'3,974'10'9/11/1994 Open CI-3.1 4,540'4,550'3,991'3,999'10'9/11/1994 Open CI-4 4,564'4,614'4,010'4,051'50'9/11/1994 Open CI-5 4,660'4,700'4,089'4,122'40'9/7/1994 Open CI-5.1 4,711'4,716'4,131'4,135'5'9/7/1994 Open CI-6 4,733'4,753'4,149'4,165'20'9/11/1994 Open CI-7 4,792'4,822'4,197'4,222'30'9/11/1994 Isolated CI-7.1 4,832'4,852'4,230'4,246'20'9/11/1994 Isolated CI-8 4,880'4,890'4,260'4,277'10'9/11/1994 Isolated CI-8.2 4,912'4,927'4,298'4,307'15'9/11/1994 Isolated CI-9 4,963'4,983'4,337'4,353'20'9/11/1994 Isolated CI-10 5,004'5,014'4,371'4,379'10'9/11/1994 Isolated CI-11 5,031'5,076'4,393'4,430'45'9/11/1994 Isolated B-2 5,220'5,235'4,549'4,561'15'9/11/1994 Isolated B-5.5 5,302'5,308'4,616'4,621'6'9/11/1994 Isolated CI-6 5,327'5,332'4,626'4,640'5'9/11/1994 Isolated C-1 5,393'5,413'4,690'4,707'20'9/11/1994 Isolated C-2.5 5,444'5,448'4,732'4,736'4'9/11/1994 Isolated D-1 5,540'5,545'4,812'4,816'5'9/11/1994 Isolated D-5 5,665'5,680'4,915'4,927'15'9/11/1994 Isolated E-4 5,731'5,736'4,969'4,973'5'9/11/1994 Isolated E-8 5,793'5,797'5,020'5,023'4'9/11/1994 Isolated E-9 5,810'5,820'5,034'5,042'10'9/11/1994 Isolated F-1 5,842'5,847'5,060'5,064'5'9/11/1994 Isolated F-3 5,884'5,889'5,094'5,098'5'9/11/1994 Isolated F-4 5,895'5,915'5,103'5,120'20'9/11/1994 Isolated G-1 5,980'5,990'5,173'5,181'10'9/11/1994 Isolated H-1/H-1.1 6,084'6,094'5,258'5,266'10'9/11/1994 Isolated H-3 6,123'6,133'5,290'5,298'10'9/11/1994 Isolated H-4 6,136'6,141'5,301'5,305'5'9/11/1994 Isolated H-7 6,182'6,197'5,338'5,350'15'9/11/1994 Isolated H-9 6,236'6,261'5,382'5,403'25'9/11/1994 Isolated J-1 6,420'6,425'5,532'5,537'5'9/11/1994 Isolated K-3 6,520'6,525'5,614'5,618'5'9/9/1994 Isolated K-4 6,536'6,551'5,627'5,640'15'9/9/1994 Isolated L-2 6,587'6,592'5,669'5,673'5'9/9/1994 Isolated M-6 6,684'6,689'5,748'5,752'5'9/9/1994 Isolated M-9 6,734'6,739'5,789'5,793'5'9/9/1994 Isolated N-2 6,828'6,843'5,866'5,878'15'9/9/1994 Isolated O-4 6,995'7,010'6,002'6,014'15'9/9/1994 Isolated Cement Details 10-3/4”15” hole:Pumped 584sxs 11.5ppg class G lead followed by 125sxs 14.7ppg class G tail.Assumed ToC to surface 7” 9-5/8” Hole: Pumped 402sxs 11.0ppg class G primary stage.Primary ToC at ?? Second stage:Pumped 705sxs 14.3ppg class G second stage cement through stage collar at 5,111’ MD.5/28/69 CBL shows second stage ToC at xx’ MD. Squeezed from 4299-4300’ with 118 sxs Well Prognosis Well: NCIU A-06 Date: 7/2/25 1. BOP N/U and Test 1. N/D Tree and adapter (BPV installed as part of pre-rig work), Install blanking plug 2. N/U to 16-3/4 5M clamp hub 3. N/U 13-5/8” x 5M BOP as follows (top down): x 13-5/8” x 5M Shaffer annular BOP. x 13-5/8” Shaffer Type “SL” Double ram. (2-7/8” X 5” VBR in top cavity, blind ram in btm cavity) x 13-5/8” mud cross x 13-5/8” Shaffer Type “SL” single ram. (2-7/8” X 5” VBR) x N/U pitcher nipple, install flowline. x Install (2) manual valves on kill side of mud cross. Manual valve used as inside or “master valve”. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. x 16-3/4” 5M Clamp hub adapter required 4. Test BOPE. x Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Ensure to leave “A” section side outlet valves open during BOP testing so pressure does not build up beneath the TWC. Confirm the correct valves are opened!!! x Test VBRs on 3.5” and 4.5”test joints (3000 psi) x Test Annular on 3.5” test joint (2500 psi) x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 5. Pull Blanking plug and BPV 2. Preparatory Work and Mud Program 1. Mix 9.0 WBM mud for 6-1/8” hole section. 2. 6” liners installed in mud pump #1 and pump #2. (PZ-10’s) x Gardner Denver PZ-10’s Pumps are rated at 4932 psi (98%) with 6” liners and can deliver 422 gpm at 115 spm. x Pump range for drilling will be 150-300 gpm. This can be achieved with one or both pumps. Well Prognosis Well: NCIU A-06 Date: 7/2/25 3. 6-1/8” Production hole mud program summary: x Primary weighting material to be used for the hole section will be barite to minimize solids. Ensure enough barite is on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. x Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. System Type:LNSD WBM Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 3318’- TD 8.8-10.3 40-53 6-15 13-24 8.5-9.5 ч 11.0 System Formulation: 2% KCL/BDF-976/GEM GP Product Concentration Water KCl Caustic BARAZAN D+ DEXTRID LT PAC L BDF-976 GEM GP BARACARB 5/25/50 STEELSEAL 50/100/400 BAROFIBRE BAROTROL PLUS SOLTEX BAROID 41 ALDACIDE-G 0.905 bbl 7 ppb 0.2 ppb (9 pH) 1.0 ppb (as required 18 YP) 1-2 ppb 1 ppb 4 ppb 1.0% by volume 5 ppb (1.7 ppb of each) 5 ppb (1.7 ppb of each) 1.7 ppb 4.0 ppb 2 – 4 ppb as needed 0.1 ppb Well Prognosis Well: NCIU A-06 Date: 7/2/25 4. Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP’s from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. 5. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation. 3. Decomplete, Plug parent wellbore Operation Steps: 1. Pull 4-1/2” tubing from the pre-rig cut at 3860’ 2. Set wear bushing in wellhead. Ensure ID of wear bushing >6-1/8”. 3. PU 7” cement retainer and set at 3850’ 4. Pump 70 bbls of 15.3# below the retainer x 2x volume of 7” from 4731’ to 3850’ 5. Unsting from retainer and lay in ~200’ of cement above the retainer (~8 bbls) x Annular 7” cement at 2500’ per 05/27/1969 CBL 6. WOC, Tag cement 7. Pressure test 7” casing to 2050 psi. x 7” 23# J-55 Burst = 4360 psi 4. Set Whipstock, Mill Window Operation Steps: 1. Make up the WIS hydraulic set Whipstock. 2. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock assembly ¾Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly. ¾Avoid sudden starts and stops while running the whipstock. ¾Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to spud or catch the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly when releasing the work string to RIH. These precautions are required to Well Prognosis Well: NCIU A-06 Date: 7/2/25 avoid any weakening of the whipstock shear mechanisms and / or to avoid part / preset on the packer. 3. Orient whipstock as directed by the directional driller. The directional plan specifies 150 deg ROHS. 4. Set the top of the whipstock at ~3,318’ MD x 7” Collar at 3308’ x Ref log: NCIU A-06 CBL 05/27/1969 Mill Window under drilling permit. Well Prognosis Well: NCIU A-06 Date: 7/2/25 BOPE Schematic Sundry Application Well Name______________________________ (PTD _________; Sundry _________) Plug for Re-drill Well Workflow This process is used to identify wells that are suspended for a very short time prior to being re-drilled. Those wells that are not re-drilled immediately are identified every 6 months and assigned a current status of "Suspended." Step Task Responsible 1 The initial reviewer will check to ensure that the "Plug for Redrill" box in the upper left corner of Form 10-403 is checked. If the "Abandon" or "Suspend" boxes are also checked, cross out that erroneous entry and initial it on the Form 10-403. Geologist 2 If the “Abandon” box is checked in Box 15 (Well Status after proposed work) the initial reviewer will cross out that checkbox and instead, check the "Suspended" box and initial those changes. Geologist The drilling engineer will serve as quality control for steps 1 and 2. Petroleum Engineer (QC) 3 When the RA2 receives a Form 10-403 with a check in the "Plug for Redrill" box, they will enter the Typ_Work code "IPBRD" into the History tab for the well in RBDMS. This code automatically generates a comment in the well history that states "Intent: Plug for Redrill." Research Analyst 2 4 When the RA2 receives Form 10-407, they will check the History tab in RBDMS for the IPBRD code. If IPBRD is present and there is no evidence that a subsequent re-drill has been completed, the RA2 will assign a status of SUSPENDED to the well bore in RBDMS. The RA2 will update the status on the 10-407 form to SUSPENDED, and date and initial this change. If the RA2 does not see the "Intent: Plug for Redrill" comment or code, they will enter the status listed on the Form 10-407 into RBDMS. Research Analyst 2 5 When the Form 10-407 for the redrill is received, the RA2 will change the original well's status from SUSPENDED to ABANDONED. Research Analyst 2 6 The first week of every January and July, the RA2 and a Geologist or Reservoir Engineer will check the "Well by Type Work Outstanding" user query in RBDMS to ensure that all Plug for Redrill sundried wells have been updated to reflect current status. At this same time, they will also review the list of suspended wells for accuracy and assign expiration dates as needed. Research Analyst 2 Geologist or Reservoir Engineer NCIU A-06 325-399169-050 SFD 7/22/2025 SFD 7/22/2025 1 Dewhurst, Andrew D (OGC) From:Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent:Friday, 1 August, 2025 10:53 To:Dewhurst, Andrew D (OGC) Cc:Rixse, Melvin G (OGC); Davies, Stephen F (OGC); Roby, David S (OGC); Christopher Stone Subject:RE: [EXTERNAL] Re: NCIU A-06 10-403 (Sundry 325-399) Zonal Abandonment Andy, While Hilcorp maintains the interval is of the same indigenous strata, your proposal to move this plugging forward using a top of Ʊll/junk justiƱcation in section (c)(1)(C) is acceptable. Hilcorp hopes to have more meaningful discussion and alignment regarding the plugging regulations soon. Safely plugging wells is important to Hilcorp. Variance Request 20 AAC 25.112(c)(1)(C) - however, the commission will approve plugging from the top of Ʊll or the top of junk instead of from the plugged-back total depth, if the commission determines that the objectives of this subsection will be met’ JustiƱcation: - 12/12/2001 EZSV Bridge plug set 5172’ - 1/29/2002 Tagged Ʊll at 4805’, Set PX plug at 4717’ 2 - SigniƱcant drop in water production and increase of gas post plug set conƱrms isolation from lower zones. 3 - 5/12/2002 Ongoing Ʊll issues and loss of gas production. Historically, Ʊll from the beluga sands stop gas production at migration. 4 - 5/13/2005 More Ʊll issues - 5/13/2007 More Ʊll issues 5 - 6/2/2009 More Ʊll issues, swedge required to get through tubing - 2/20/2012 Bailing Sand 6 - 1/22/2012 Partial cut of tubing tail 7 - 12/19/2014 Bailing Ʊll and hard clay 8 - 3/5/2015 FCO to top of packer, loss circulation 9 - Hard pack Ʊll is expected in the lower 4-1/2” tubing - Removing packer, inner string, and Ʊll past the lower perforations would unnecessarily expose the operation to loss circulation, stuck pipe, and well control risk - A solid sand plug in the tubing is a suitable base to place cement on top of. Regards, sean From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Thursday, July 31, 2025 2:52 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; Christopher Stone <Christopher.Stone@hilcorp.com> Subject: [EXTERNAL] Re: NCIU A-06 10-403 (Sundry 325-399) Zonal Abandonment Sean, If the open perforations below the tubing tail/Ʊll are plugged with Ʊll in such a manner that hydrocarbons are unable to migrate into other strata, then this work program could be approved with a variance CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 10 request (similar to the NCIU A-21 sundry referenced below). However, if the perforated intervals are open to each other, then it would require a waiver of 20 AAC 25.112(c). Andy From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Thursday, 31 July, 2025 10:46 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; Christopher Stone <Christopher.Stone@hilcorp.com> Subject: FW: [EXTERNAL] RE: NCIU A-06 10-403 (Sundry 325-399) Zonal Abandonment Andy – below are our observations you requested in a phone conversation with Chris Stone supporting a lack of communication between zones. The information below is an AOGCC request, not justiƱcation for a variance. Hilcorp maintains the plugging plan is permissible under the current regulations. Evidence supporting a lack of “cross Ʋow” occurring between wellbores 1. The Beluga reservoir exhibits signiƱcant lateral discontinuity, primarily resulting from the Ʋuvial depositional processes that controlled sediment distribution. This heterogeneity is evident in the Beluga outcrop in the image below, where sands within a single stratigraphic interval of the Beluga formation often lack lateral continuity and may represent distinct, isolated channel or bar deposits rather than uniform, laterally extensive units. 2. The discontinuous and compartmentalized nature of the Ʋuvial sands has resulted in an absence of detectable interference between online producers. Type-curve analysis demonstrates that wells drilled in 2021 exhibit production behavior that is unaƯected by the completion and production of oƯset wells drilled in subsequent years. For instance, well A-03, brought online in 2021, shows no observable deviations or inƲection points in its type-curve corresponding to the startup dates of nearby wells brought 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. 11 online in later years, as annotated on the graph below. The absence of such inƲections suggests a lack of observable reservoir communication. This analysis has been applied across all available producers, consistently yielding similar results. 3. Fill within the wellbore has been repeatedly demonstrated to act as an eƯective barrier to Ʋuid Ʋow. A recent example presented before the AOGCC is well A-21A, where the well was pressured up to approximately 4,000 psi in preparation for abandonment, yet no injectivity was observed. This lack of pressure communication/injectivity indicates that the presence of Ʊll can result in isolation within a wellbore. Numerous production-related instances further support this conclusion. Throughout the past year, Hilcorp has submitted multiple sundry requests for coil tubing cleanouts in response to observed productivity declines attributed to Ʊll accumulation. Recent cleanouts include: A-09 (sundry #324-505) A-16 (sundry #324-514) A-19 (sundry #325-261) B-02 (sundry #324-055) Following cleanout operations, improvements in well performance were observed, reinforcing the conclusion that wellbore Ʊll impedes production by restricting Ʋuid communication across producing intervals. In the speciƱc case of A-06, tagging operations in May 2005 identiƱed Ʊll at a depth of 4,711 feet, corresponding to the top of the C.I. 6 sand. This obstruction is eƯectively isolating the C.I. 6 sand from subsequent intervals below, down to the Beluga O sands. Regards, sean From: Sean McLaughlin <sean.mclaughlin@hilcorp.com> Sent: Tuesday, July 29, 2025 6:52 PM To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Christopher Stone <Christopher.Stone@hilcorp.com> Subject: RE: [EXTERNAL] RE: NCIU A-06 10-403 (Sundry 325-399) Zonal Abandonment 12 Andy, I believe Hilcorp gave a convincing case yesterday why the plugging should be approved as planned. I understand that the AOGCC may want to go a diƯerent direction, but the plan meets the current regulations and historical standards. To sum up the discussion points: - AOGCC doesn’t have a deƱnition for indigenous strata. This is a signiƱcant problem. - The term “Strata” is used in this portion of the regulations. Strata is plural, meaning multiple layers. - Strata are not deƱned by a distance. - Original perforation interval shot in 1969 was 4021’ – 7010’. - The well is depleted, and the sands are discontinuous. - There are no natural beds or boundaries that separate this interval. - There is no negative impact to future production or injection. This is a very tender formation, and zones lock up quickly and naturally with Ʊll. - The proposed plugging is in line with historical standards as evidenced by the plugging of A-01, A-03, and A- 04 in 2021. Hilcorp has been planning to plug A-06 and A-07 in the same manner since then. - AOGCC staƯ made it clear this was a re-direction of the regulations. That is not a fair approach and is in a way altering the regulations without proper approval. My suggestion is to honor the current regulations, work on an approved change, and grandfather old wells. If you would like to work on a framework for the future plugging of wells that would be welcome, but don’t hold this Sundry hostage to do so. Please reconsider approving the plugging sundry based on 20 AAC 25.112(c)(1)(E) as requested. Furthermore, the well is currently in an optimum state to be securely plugged. A cement retainer and downsqueeze, as proposed, is the safest way to plug this well. Pulling an inner string, Ʊshing out a tubing tail , cleaning out Ʊll, and milling a plug add well control, stuck pipe, and loss circulation risk. There is a scenario where the well is junked, and the slot is lost. Plugging as proposed is the surest, safest, and most eƯective way to reduce risk and prepare the well for a sidetrack. Regards, sean From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Tuesday, July 29, 2025 3:46 PM To: Sean McLaughlin <sean.mclaughlin@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Roby, David S (OGC) <dave.roby@alaska.gov>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Christopher Stone <christopher.stone@hilcorp.com> Subject: [EXTERNAL] RE: NCIU A-06 10-403 (Sundry 325-399) Zonal Abandonment Sean, Thank you for coming by yesterday to discuss this sundry. The plugging requirements described below are not met with the proposed work. As we discussed, there is potential for an abandonment framework (speciƱcally discussed yesterday for the Beluga) that includes a variance or in some circumstances a waiver, with proper justiƱcation. Without that justiƱcation, we cannot waive the requirements. Andy CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 13 -----Original Appointment----- From: Rixse, Melvin G (OGC) Sent: Thursday, July 24, 2025 9:07 AM To: Rixse, Melvin G (OGC); Dewhurst, Andrew D (OGC); Sean McLaughlin Cc: McLellan, Bryan J (OGC); Lau, Jack J (OGC); Boman, Wade C (OGC); Davies, Stephen F (OGC); Roby, David S (OGC); Christianson, Grace K (OGC); CAL-DOA-AOGCC (CED sponsored); Christopher Stone Subject: NCIU A-06 10-403 Zonal Abandonment When: Monday, July 28, 2025 3:00 PM-4:00 PM (UTC-09:00) Alaska. Where: AOGCC Public Conference Room AOGCC would like to discuss the reservoir(s) abandonment of PTD 169-050 NCIU A-06. Of note is AOGCC’s requirement for zonal isolation: 20 AAC 25.112. Well plugging requirements. (c) Plugging of cased portions of a wellbore must be performed in a manner that ensures that all hydrocarbons and freshwater are conƱned to their respective indigenous strata and are prevented from migrating into other strata or to the surface. The minimum requirements for plugging cased portions of a wellbore are as follows: …….. It appears that the 10-403 will not provide any cement zonal isolation between the PX plug at 4717’ MD and PBTD at 6380’ MD, which could allow future crossƲow of ~1663’ MD. Ongoing background discussions with Hilcorp has asserted by AOGCC, that commercially comingled gas pools have been allowed for production management but have not been given ‘rote’ approval for Ʊnal zonal isolation. Hilcorp’s geologist would be welcome to attend, as discussion of natural barriers across these comingled zones would be helpful. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 OƯice 907-297-8474 Cell Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 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. 14 While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Nolan Vlahovich Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 06/27/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: NCIU A-06 PTD: 169-050 API: 50883200260000 CBL log scan from Schlumberger 27 May 1969 SFTP Transfer - Data Folders: Please include current contact information if different from above. 169-050 T40633 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.07.07 12:20:04 -08'00' RECEIVED STATE OF ALASKA , ALMA OIL AND GAS CONSERVATION COMAION JAN 2 5 2013 REPORT OF SUNDRY WELL OPERATIONS AOGCC 1. Operations Abandon ❑ Repair Well ❑ Plug Perforations LJ Perforate (J Other U Deep Gas Lift Performed: Alter Casing ❑ Pull Tubing ❑ Stimulate - Frac ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Stimulate - Other ❑ Re -enter Suspended Well ❑ 2. Operator ConocoPhillips Alaska, Inc. 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development Q Exploratory ❑ 169 -050 3. Address: P.O. Box 10360 Anchorage Alaska, 99510 StratigraphiC❑ Service ❑ 6. API Number: 50- 883 - 20026 -00 -00 7. Property Designation (Lease Number): 8. Well Name and Number: ASL 0017589 / ADL 0037831 NCIU A - 06 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): - No new logs obtained North Cook Inlet / Tertiary Gas Pool 11. Present Well Condition Summary: Total Depth measured 8045 feet Plugs measured 4717 feet true vertical 6892 feet Junk measured 4711' fill feet Effective Depth measured 6380 feet Packer measured 3912' feet true vertical 5503 feet true vertical 3490 feet Casing Length Size MD TVD Burst Collapse Structural 30" 382' 382' Conductor 16" 623' 623' Surface 10 -3/4" 2579' 2397' SCANNED MAR 1 2013 Intermediate Production 7" 8016' 6870' Liner Perforation depth Measured depth 4021 - 7010 feet tubing puch holes 3880' - 3886' 4 spf True Vertical depth 3571 - 6015 feet 3462' - 2468' Tubing (size, grade, measured and true vertical depth) 4 -1/2" 12.6 & 12.75# J -55 6279' 5422' Packers and SSSV (type, measured and true vertical depth) WFT wide pack LE 3865' - 3893' HES XXO 295' 295' 3448' - 3473' 12. Stimulation or cement squeeze summary: Installed Deep Gas Lift assembly across tubing punch holes to assist in de- watering the well Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 Bbls 0 0 120 55 Subsequent to operation: 0 Bbls 2640 Mcf /d 4 Bbls 560 71 psi flowing 14. Attachments: 15. Well Class after work: N. Copies of Logs and Surveys Run N/A Exploratory❑ Development Q Service ❑ m Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil ❑ Gas 0 WDSPL ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: Contact Marcus Barbee Email barbemq a(�conocophillips.com Printed Name Marcus Barbee Title Wells Engineer Signature ' Phone 265 -6932 Date 1/24/2013 RBDMS JAN 2 8 2013 4T4,-) 1.3/-3 Sub mit Ori mal Onl Form 10 -404 Revised 10/2012 g y Am (A1,) • • 9/23/12 RU SL, PULL SSSV, DRIFT TUBING, RD SL, READY FOR DGL, IN PROGRESS TRAVEL TO PLATFORM, ORIENTATE CREWS, BEGIN SPOT EQUIPMENT, IN 9/25/12 PROGRESS 6HR WEATHER HOLD, FINISH SPOT EQUIPMENT, MIX KCL, RU PUMP, RU 9/26/12 ELINE, IN PROGRESS RU RISER / BOP / WORK BASKET, STRAP TUBING, INJECT WASTE FLUID, MIX 9/27/12 KCL, IN PROGRESS PUMP TO KILL 150BBL, MONITOR WELL, FINISH RU BOP, TFST ROP 250/3000PSI, RUN 23 JOINTS 1.900" = 746.5', HANG OFF IN BOP, SHUTDOWN 9/28/12 FOR NIGHT, IN PROGRESS PUMP 70BBL 6% KCL, PULL 2 STANDS OF TUBING, MU LOWER PACKER, RU ELINE, SET LOWER PACKER @ 3898' RKB TO CENTER OF ELEMENT, RU SL, 9/29/12 RIH W/TEST TOOL, PT PACKER TO 1000PSI, POOH, SHUTDOWN FOR NIGHT RU ELINE, RIH W/TUBING PUNCH, PUNCH TUBING FROM 3880.2' TO 3885.7' 9/30/12 RKB, RD ELINE, IN PROGRESS RU SL, MU DPU AND UPPER PACKER ASSEMBLY, RIH, SET UPPER PACKER, RIH W/TEST TOOL, TEST UPPER PACKER 500 /1000PSI, POOH, SHUTDOWN 10/1/12 FOR NIGHT, IN PROGRESS We turned the well over to production and the shoe was plugged, the time from the 1st to the 21st we were trying to get back to the well for warrenty work RU SL, PULL SSSV, PULL UPPER DGL PACKER, PACKER, 10/21/12 REDRESS, RU ELINE, SHUTDOWN FOR NIGHT 10/22/12 RU ELINE, RIH W /JET CUTTER, CUT OFF DGL TUBING TAIL. RD, IN PROGRESS RU SL, SET UPPER PACKER @ 3839' RKB, PACKER DID NOT SET, PULL 10/23/12 PACKER, REDRESS, SHUT DOWN FOR NIGHT, IN PROGRESS INSPECT ALL DGL EQUIPMENT/ SL UNIT, RU SL, SET UPPER PACKER, SET TEST TOOL, LOAD TUBING, PT UPPER PACKER 1000 PSI W /6% KCL, PASSED, 10/24/12 PULL TEST TOOL, SET SSSV, SHUTDOWN, RETURN WELL TO PRODUCTION P , I • . COnoeoPllillips NCIU Well A-6 Completion Diagram API# 508832002600 Gas Producer FMC OCT RKB -Drill Deck: Sing/eComp. FMC 41/2" 8rd X 41/2" BT &C RKB -THF: 40.25 N SSSV . Annulus Fluid: Salt Water with 3 bbl Methanol RKB-SL : 115.9 ,::r 382' TOC: 2500' from CBL dated 05 /27169 WATER DEPTH: 120' RKB -ML. • ::t)Tf �I� : :Toix::l::9ottodi::i: Wr:::::: :: iSiiiile::�::::COrin:: give¢: COIF :::f::::::::::::Taisii:::::: •: x CASING & TUBING . A 1 6" @ 623' 30 " 41' 382' 16 " 41' 623' 65# H-40 1540 600 293 103/4" 41' 2579' 45.5#851# J-55 BT &C 3350 1970 531 7 39' 79' 26# J-55 BT &C 4660 4080 327 7" 79' 8986' 23# J55 BT &C 4080 3080 288 7 " 8966' 8016' 289 J -55 BT&C 4660 4080 327 4 112" 41' 328' 12.69 J55 mod BT &C 4730 4980 134 41/2" 328' 6261' 12.75# J55 mod 8r4 4730 4980 134 ::::81:::: :::::Tol: :::::: twitot6:::::::::::::::::::::::, Desirlptlori: : :: :: :: :: :::::: :: :: :::::: :: :: :: :IR:: :: :: :: :: :: :: bD:::: :: :: :: :::::: :: ?: TOC @ 2500' CBL PRODOC77ONTUBING STRING &JEWELRY 10 3/4" @ 2579' 73 000 40.25 Elevation :: s 72 40. 0.65 FMC / OCT 6" 3M 4 1/2 8rd x 4 1/7' BTC T8G Hanger 3.958 6.000 71 40.90 1.33 4 1/2" BTC Pup Jt. 3.992 4.500 70 42.23 252.16 4 1/2" BTC Mod. J-55 Tubing 1992 4.500 - On, 4 �� `: Halliburton VSR packer @ 3912' 69 294.39 2.46 Halliburton "XXO" -set SCSSV 1/02 3.813 5.580 68 296,65 31.36 4 1/2" BTC Mod. J -55 Tubing 3.992 4 500 67 328.21 0 8 0/0 4 1/2" BTC Box x 4 vr EU Box 3.992 4.500 61 ;i I 66 329.01 3573 48 4 1/2 EU Mod J -55 Ord Tubing 3.992 4.500 Cook Inlet Sands 65 390249 8.68 Upper "PBR" Assembly 3.950 5.750 Perforations Squeezed w /cement 64 3911.17 2 62 Retch Latch Seal Unit 3.950 5.560 : 4021 -4031 CI-Stray 63 3912.29 6.48 Halliburton 'VSR" Packer 3.880 5.870 ' _ : 4055 -4080 CI-A 62 3918.77 30.45 4 12" EU Mod J -55 8rd Tubing 3.992 4.500 '. 4102 -4107 CIS 61 3949.22 1.44 Halliburton "X" NI• • 3.813 5.580 _ _ • 4112 - 4162 CI -B 60 3950,68 280 24 4 1/7' EU Mod J55 8rd 3.992 4.500 59 4230.90 2.62 No Go Seal Unit 3.950 5.560 : = ;:: TWR packer @4232' 58 4232.02 4.29 Halliburton 'TNR" Packer 4.000 5.870 57 4236.31 8.18 Mill Out Extension 8 Tubing Adaptor 4.276 5.560 • 56 4244 49 156.92 4 1/T EU Mod J -55 8rd Tobin • 3.992 4.500 g; 5 4325 - 4380 CI - 1.0 55 4401.41 4.22 Halliburton "XD" Sliding Sleeve OPEN 3.813 5.560 55 F 4388 -4398 CI -1.0 54 4405.63 2,62 No Go Seal Unit 3.950 5.560 • 53 4406.75 4.3 Halliburton "TWR" Packer 4.000 5.870 52 4411.05 8.23 Mill Out Extension & Tubing Adaptor 4,276 5.560 Halliburton TWR packer @ 4406' 51 4419.28 68.18 4 1/2" EU Mod 755 8rd & PU• Jts. 3.992 4.500 I SO 4487.46 4.22 Halliburton "XD" Sliding Sleeve OPEN 3.813 5.560 x 4420 -4490 CI -2.0 49 4491.68 415 41/2' Pip Jt. 3.992 4.500 ▪ 50 48 4495.83 262 No Go Seal Unit 3.950 5.560 47 4496.95 4.3 Halliburton "TWR" Packer 4.000 5.870 ' f_ ; in•. Halliburton TWR packer 46 4501.25 8.19 ME Out Extension & Tub Ada•tor 4,276 5.560 45 4509.44 30.54 4 1/2" EU Mod J -55 8rd Tubing 3.992 4.500 44 '9 , 4509 - 4519 CI 44 4539.98 4.22 Halliburton "XD" Sliding Sleeve OPEN 3.813 5.560 • -' 4540 -4550 CI-3.1 43 4544.10 814 4 1/2" Pup Jt. 3.992 4.500 42 4552.24 2 62 No Go Seal Unit 3.950 5.560 • . : Halliburton TWR packer @ 4553' 41 4553.36 4.3 Halliburton "TWR" Packer 4.000 5.870 40 4557 66 7.23 Mill Out Extension & Tubing Adaptor 4.276 5.560 39 4564,89 62.98 4 1/2" EU Mod J-55 8rd Tubin • 3.992 4.500 38 :, 4564 - 4614 CI 38 4627.87 4.22 Halliburton "XD" Sliding Sleeve OPEN 3.813 5.560 37 4632.09 6.10 4 1/2" Pup Jt 3.992 4.500 36 4638.19 2.62 No Go Seal Unit 3 950 5.560 • Halliburton 1WR packer @4639' 35 4639.31 4.3 Halliburton "TWR" Packer 4.000 5.870 4660 - 4700 CI5.0 34 4643.61 8 3 Mill Out Extension & Tubing Adaptor 4 276 5.560 • 4711 -4716 CI-5.1 33 4651 91 68,89 41/7 EU Mod 7-55 8rd Tobin. 3.992 4500 32 4717.00 PX Plug_ • • 32 PX Plug @ 4717' (1P02) 31 4718.80 2.62 No Go Seal Unit 3.950 5 560 � ■ ::i Halliburton TWR packer @ 4719' 30 4719.92 4.3 Halliburton "TWR" Packer 4.000 5.870 29 4724 22 8.4 Mill Out Extension & Tubing Adaptor 4 276 5.560 _ 28 4732.62 30.33 4 1/2" EU Mod J55 8rd Tubing 3.992 4.500 27 MM : 4733 -4753 CI-6.0 27 4762.95 4.22 Halliburton "XD" Sliding Sleeve CLOSED 3.813 5.580 ® 26 4767.17 4.10 4 12" Pop Jt. 3,992 4.500 25 4771.27 2.62 No Go Seal Unit 3.950 5.560 -- --d 0 Halliburton TWR packer @ 4772' 24 4772.39 4.3 Halliburton 'TWR" Packer 4.000 5.870 23 4776,89 8 3 Mill Out Extension & Tubing Adaptor 4.276 5.560 4792 -4822 CI -7,0 22 4784.99 79.07 4 1/2" EU Mod J -55 8rd Tubing & Pup Jts. 3.992 4.500 + 4832 - 4852 CI 7.1 21 4864.06 262 No Go Seal Unit 3 950 5,560 is !..5-C.;','''•'-'.` .j,ya26c,,,,,y JX 20 4885.18 4.3 Halliburton "TWR" Packer 4.000 5.870 19 4869 48 826 Mill Out Extension & Tubing Adaptor 4.276 5.560 • � ::.'Halliburton TWR packer @4865' 18 4877.74 59.53 41/2" EU Mod J55 8rd Tubing 3.992 4.500 ___ .: 17 4937.27 4.22 Halliburton "XD" Sliding Sleeve CLOSED 3.813 5.560 • • . 4880 -4890 CI5.0 16 4941 49 43.65 4 1/2" EU Mod J-55 8rd Tubing & Pup Jts. 3,992 4.500 4912 -4927 CI-8.2 15 4985,14 162 No Go Seal Unit 3.950 5.560 17 14 4986.28 4.3 Halliburton "TWR" Packer 4.000 5.870 "v +: :::::: 4963 -4983 CI-9.0 13 4990,56 8.31 Mill Out Extension & Tubin• Ada•tor 4.278 5.560 ry 12 4998.87 113.14 4 1/2" EU Mod J -55 8rd Tubin• & Pu• Jts. 3.992 4.500 • .: 11 5112.01 4.22 Halliburton "XD" Sliding Sleeve OPEN 3.813 5.680 10 5116,23 62 65 4 12" EU Mod J -55 Ord Tubing 3,992 4.500 9 5172.00 EZSV BP set 12101 - � Halliburton TWR packer @ 4986' 8 5178.88 2 62 No Go Seal Unit 3.950 5.560 hie iii 5004 - 5014 CI -10.0 7 5180.00 4.3 Halliburton 'TWR" Packer 4.000 5.870 _ _ 5031 - 5078 CI -11.0 6 5184.30 8.32 Mill Out Extension & Tubm• Ada •tor 4.276 5 560 11 5 5192.62 405.26 4 12" EU Mod J55 8rd Tubing 3.992 4.500 LIMMEM :ii. 4 5597.88 4.22 Halliburton "XA" Sliding Sleeve 3.813 5.560 9 :7 EZSV BP @ 5172 (12/01) 3 5602.10 657 32 4 12" EU Mod J -55 Ord Tubing 3.992 4.500 Halliburton TWR packer @5180' 2 6259.42 1.50 Halliburton "XN" NI• •le 3.725 5.560 ? Beluga Sands 1 6260.92 0.57 Re-entry Guide 3.995 5.560 • • ' i • 5220 - 5235 b-2 6261.49 End of Tubing • ` . 1... ............ • - �,, 5302 - 530 a b-5 5 .. :i 5327 - 5332 135 Well History • >' 5393 - 5413 o-1 April 1969 - Well completed in CI Stray,A,B,1 -11 and Beluga Commingled • We; 5444 -6448 0-2.5 with 4 "X3 -1/2" tubing sat at 4349' • 4 1 5540 - 5545 d-1 September 1994 Workover - Well completed in Beluga b-2 thru h -9 5665 - 5680 d -5 Set BP at 6380' to abandon Beluga j -1 thru o-4 without testing • 5731 - 5736 e-4 Squeeze Cook Inlet Stray, A, & B perforations 5793 - 5797 e-8 Reperforate/Add Perfs In Beluga from 5220'-6261' Reperforate Cook Inlet 1.0 thru 11.0 from 4325'5076' 5810 - 5820 e-9 September 1999 - Top of Fill 6267 RKB • 5842 - 5847 f -1 June 4, 2001 Tag fill @ 5986 WLM i. 5884 - 5889 1 -3 Dec. 11, 2001 Pull SCSSV 5895 - 5915 f-4 Dec.12, 2001 Set 4.5" EZSV bridge plug @ 5172' ROB 5980 - 5990 g -1 Dec. 13, 2001 Open XD sleeve @ 5112', set SCSSV 6084 - 6094 h1 & h1.1 Jan 30, 2052 Tag fill @ 4805' WLM; set PX plug @ 4717' WLM 6123 -6133 h -3 Jan 31, 2002 Open sleeves @ 4353', 4458', 4491', 4579'; set SSSV 6136 - 6141 h-4 May 13, 2002 - Tag plug @ 4710' WLM i 2 s s 6182 -6197 h -7 May 13 ,2005 -Tag plug @ 4711' WLM (4751' RKB) 1 6238 - 8261 9-9 EZSV @ 6380 6420 - 6425 ( -1 i 6520 -6525 k-3 iii 6536 - 6551 k-4 6587 - 8592 1 -2 i 6684 - 6689 m5 is 6734 -6739 m-9 • 6828 - 6843 n -2 6995 -7010 0-4 PBTD 6380' Updated: 5/1312005 By) Dan Bearden :>: >; ::: 7" @8010' PBTD: 6380' PX Plug Tag: 4711' WLM 52005 TD . 8,045' Well: North Cook Inlet Unit No. A -06 Location: Lower Cook Inlet. Alaska Field' Cook Inlet Unit JDB Customer Conoco P Contact Marcus Bar , Thure Johnson Ike. Contact Details Jake Bramwell / Jason Moseley W /ford Location Alaska - Cook Inlet Weatherford Field/ Well No. NCI A -0 C A-06 Toolstrin • Desc. Lower Packer BHA for 374 WidePak RGL S stem BHA Seq Description Asset OD (Inches) ID (Inches) Weight Length Total Depth Number (Lbs) (Feet) 1 Top Of Packer 3864.89 } i i(E fi { 2 Center Packing Element 3869.99 3 374 Widepak Packer , �/y/�/ WFT 3.740" 2.375" 95.2 Lbs 6.21 3871.10 8 x Setting pins (96001bs) 5 x Release Pins (60001bs) P t 3.5" VAM FJL Pin 2.875" Sealbore ID 3880.2 4 Tubing Punch AlE.,< 3885.7 5 2 -Each 9.2# Pup Joints WFT 3.530" 2.930" 92.0 Lbs 19.66 3890.76 3.5" VAM FJL Box x Pin 6 Centralift AVE Sub pCg 3.515" N/A 14.5# 0.44 3891.20 3.5" Vam FJL Box X Pin I O 7 WP Anchor Seal Latch WFT 3.700" 2.240" 39.8 Lbs 3.67 3893.00 3.5" VAM FJL Box c/w Seal Stack ill 5 x Release Pins (6000Ibs) Dual Flapper Check Valve WFT 1.688" 0.790" 3.1 Lbs 0.00 1.0" CS pin X Stub Acme Box I i l 8 Top Of Packer 3893.00 )t 9 Bottom Of Seal Assembly 3894.87 10 Center Packing Element 3898,00 11 374 Widepak Packer V r1," WFT 3.740" 2.375" 95.2 Lbs 6.21 3899.21 i lif 8 x Setting pins (9600 lbs) 5 x Release Pins (60001bs) 2.875" WTS -8 Pin 2.875" Sealbore ID 12 Slotted Sub WFT 3.215" 2.375" 10.3 Lbs 1.34 3900.55 2.875" WTS -8 Box x Stub Acme Box Stinger Rod w/ DFCV WFT 1.750" 0.875" 41.6 Lbs 6.56 3901.43 1 1" CS Pin X Guide Nose c/w Seal Stack 13 PBR - Seal Bore WFT 2.875" 1.750" 26.3 Lbs 0.96 3901.53 Stub Acme Pin x 2.375" WTS -8 Pin NIS 14 Torq -Thru Quick Connect WFT 2.875" 1.375" 25.0 Lbs 1.66 3903.21 rl 2.375" WTS -8 Box x 1.900 NU 1 Ord Pin 15 23 -JTS" Of Jointed Pipe �,_ CoP 2.115" 1.560" 746.46 4649.67 1 ; 1.90" NU 1ORD, 2.75Ib /ft qtr i; ■ 16 2.375" Dual Flapper Assembly WFT 2.375" 0.375" 10.0 Lbs 0.78 4650.45 1.900" NU 1ORD Box x Bullnose w/ 3/8" Restriction for Flow control PREPARED BY: Joe Bob Maddox & Howard Bolton Weight : 438 Lbs Date 9/29/12 TRADE SECRET AND CONFIDENTIAL Copyright © Weatherford Inc. 2012 tiCUCIVCV • . STATE OF ALASKA DEC 0 7 2012 ALARA OIL AND GAS CONSERVATION COM SION REPORT OF SUNDRY WELL OPERATIONS AOGCC 1. Operations Abandon U Repair Well Li Plug Perforations LJ Perforate Li Other U Deep Gas Lift Performed: Alter Casing ❑ Pull Tubing ❑ Stimulate - Frac ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Stimulate - Other ❑ Re -enter Suspended Well ❑ 2. Operator ConocoPhillips Alaska, Inc. 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development Is Exploratory ❑ 169 -050 3. Address: P.O. Box 10360 Anchorage Alaska, 99510 Stratigraphic ❑ Service ❑ 6. API Number: 50- 883 - 20026 -00 -00 7. Property Designation (Lease Number): 8. Well Name and Number: ASL 0017589 / ADL 0037831 " NCIU A - 06 ' 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): No new logs obtained North Cook Inlet / Tertiary Gas Pool 11. Present Well Condition Summary: Total Depth measured 8045 feet Plugs measured 4717 feet true vertical 6892 feet Junk measured 4711' fill feet Effective Depth measured 6380 feet Packer measured 3912' feet true vertical 5503 feet true vertical 3490 feet Casing Length Size MD TVD Burst Collapse Structural 30" 382' 382' Conductor 16" 623' 623' Surface 10 -3/4" 2579' 2397' SCANNED MAR 1 1 Z0i3 Intermediate Production 7" 8016' 6870' Liner Perforation depth Measured depth 4021 - 7010 feet tubing puch holes 3880' - 3886' 4 spf True Vertical depth 3571 - 6015 feet 3462' - 2468' Tubing (size, grade, measured and true vertical depth) 4 -1/2" 12.6 & 12.75# J -55 6279' 5422' Packers and SSSV (type, measured and true vertical depth) WFT wide pack LE 3865' - 3893' HES XXO 295' 295' 3448' - 3473' 12. Stimulation or cement squeeze summary: Installed Deep Gas Lift assembly across tubing punch holes to assist in de- watering the well Intervals treated (measured): Treatment descriptions including volumes used and final pressure: X 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 Bbls 0 0 120 55 Subsequent to operation: 0 Bbls 764 Mcf /d 2 Bbls 790 76 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory Development la ` Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil ❑ .-- Gas 0 WDSPL ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: Contact Marcus Barbee Email barbemp(a�conocophillips.com Printed Name Marcus Barbee Title Wells Engineer Signature Phone 265 -6932 Date 12/5/2012 y ,� r� �"«fy.; 1 0 72C17 I'a' Form 10-404 Revised 10/2012 1 Submit Original Only P • • 9/23/12 RU SL, PULL SSSV, DRIFT TUBING, RD SL, READY FOR DGL, IN PROGRESS TRAVEL TO PLATFORM, ORIENTATE CREWS, BEGIN SPOT EQUIPMENT, IN • 9/25/12 PROGRESS 6HR WEATHER HOLD, FINISH SPOT EQUIPMENT, MIX KCL, RU PUMP, RU 9/26/12 ELINE, IN PROGRESS RU RISER / BOP / WORK BASKET, STRAP TUBING, INJECT WASTE FLUID, MIX 9/27/12 KCL, IN PROGRESS PUMP TO KILL 150BBL, MONITOR WELL, FINISH RU BOP, TEST BOP 250/3000PSI, RUN 23 JOINTS 1.900" = 746.5', HANG OFF IN BOP, SHUTDOWN 9/28/12 FOR NIGHT, IN PROGRESS PUMP 70BBL 6% KCL, PULL 2 STANDS OF TUBING, MU LOWER PACKER, RU ELINE, SET LOWER PACKER @ 3898' RKB TO CENTER OF ELEMENT, RU SL, 9/29/12 RIH W/TEST TOOL, PT PACKER TO 1000PSI, POOH, SHUTDOWN FOR NIGHT RU ELINE, RIH W/TUBING PUNCH. PUNCH TUBING FROM 3880.2' TO 3885.7' 9/30/12 RKB, RD ELINE, IN PROGRESS RU SL, MU DPU AND UPPER PACKER ASSEMBLY, RIH, SET UPPER PACKER, RIH W/TEST TOOL, TEST UPPER PACKER 500 /1000PSI, POOH, SHUTDOWN 10/1/12 FOR NIGHT, IN PROGRESS We turned the well over to production and the shoe was plugged, the time from the 1st to the 21st we were trying to get back to the well for warrenty work RU SL, PULL SSSV, PULL UPPER DGL PACKER, LAYDOWN PACKER, 10/21/12 REDRESS, RU ELINE, SHUTDOWN FOR NIGHT 10/22/12 RU ELINE, RIH W /JET CUTTER, CUT OFF DGL TUBING TAIL, RD, IN PROGRESS RU SL, SET UPPER PACKER @ 3839' RKB, PACKER DID NOT SET, PULL 10/23/12 PACKER, REDRESS, SHUT DOWN FOR NIGHT, IN PROGRESS INSPECT ALL DGL EQUIPMENT/ SL UNIT, RU SL, SET UPPER PACKER, SET TEST TOOL, LOAD TUBING, PT UPPER PACKER 1000 PSI W /6% KCL, PASSED, 10/24/12 PULL TEST TOOL, SET SSSV, SHUTDOWN, RETURN WELL TO PRODUCTION • Customer Conoco es • Contact Marcus Barbee, Thure Johnson Contact Details Jake Bramwell / Jason Moseley W /ford Location Alaska - Cook Inlet 1Neatherford Field/ Well No. NCI A - 06 Toolstrin . Desc. Lower Packer BHA for 374 WidePak RGL S stem Asset Weight Length Total Depth BHA Seq Description OD (Inches) ID (Inches) p Number (Lbs) (Feet) 1 Top Of Packer 3864.89 I 2 Center Packing Element 3869.99 4 L 3 374 Widepak Packer WFT 3.740" 2.375" 95.2 Lbs 6.21 3871.10 8 x Setting pins (96001bs) 5 x Release Pins (6000Ibs) 3.5" VAM FJL Pin 2.875" Sealbore ID 3880.2 4 Tubing Punch 3885.7 5 2 -Each 9.2# Pup Joints WFT 3.530" 2.930" 92.0 Lbs 19.66 3890.76 3.5" VAM FJL Box x Pin 6 Centralift AVE Sub PCS 3.515" N/A 14.5# 0.44 3891.20 3.5' Vam FJL Box X Pin 0 7 WP Anchor Seal Latch WFT 3.700" 2.240" 39.8 Lbs 3.67 3893.00 3.5" VAM FJL Box c/w Seal Stack 5 x Release Pins (6000Ibs) Dual Flapper Check Valve WFT 1.688" 0.790" 3.1 Lbs 0.00 1.0" CS pin X Stub Acme Box 8 Top Of Packer 3893.00 9 Bottom Of Seal Assembly 3894.87 10 Center Packing Element 3898.00 4. 11 � 1 1 >f IN 11 374 Widepak Packer WFT WFT 3.740" 2.375" 95.2 Lbs 6.21 3899.21 8 x Setting pins (9600 lbs) 5 x Release Pins (6000Ibs) 2.875" WTS -8 Pin 2.875" Sealbore ID 12 Slotted Sub W 3.215" 2.375" 10.3 Lbs 1.34 3900.55 ® 2.875" TS -8 Box x Stub Acme Box II Stinger Rod w/ DFCV WFT 1.750" 0.875" 47.6 Lbs 6.56 3901.43 7 1" CS Pin X Guide Nose c/w Seal Stack 13 PBR - Seal Bore WFT 2.875" 1.750" 26.3 Lbs 0.96 3901.53 Stub Acme Pin x 2.375" WTS -8 Pin 14 Torq -Thru Quick Connect WFT 2.875" 1.375" 25.0 Lbs 1.66 3903.21 2.375" WTS -8 Box x 1.900 NU lord Pin 1. 15 23 -JTS" Of Jointed Pipe CoP 2.115" 1.560" 746.46 4649.67 1.90" NU 1ORD, 2.751b/ft 16 2.375" Dual Flapper Assembly WFT 2.375" 0.375" 10.0 Lbs 0.78 4650.45 1.900" NU 1ORD Box x Bullnose w/ 3/8" Restriction for Flow control PREPARED BY: Joe Bob Maddox & Howard Bolton Weight : 438 Lbs Date 9/29/12 TRADE SECRET AND CONFIDENTIAL Copyright © Weatherford Inc. 2012 • • • C onocoPhilhps NCIU Well A-6 Completion Diagram API # 508832002800 Gas Producer FMC OCT RKB -Drill Deck: Single C o m p . FMC 41/2" 8rd X 41/2" BT &C RKB -THF: 40.25 99 SSSV Annulus Fluid: Salt Water with 3 bbl Methanol RKBSL: 115.9 '::382' TOC: 2500' from CBL dated 05/27169 WATER DEPTH: 120' RKB -ML : :::::66::::1 ::::7 :::I: aoticrii ::I ::::: Wr: I: Giide::it caiio:::::::1 :::::ei / :4:: ::::::::::Ted:n::_::: ::: : x CASING & TUBING s�;.: a 16" @ 623' 30 " 41' 382' 16" 41' 623' 65# H-40 1540 600 293 10 3/4 " 41' 2579' 45.51i & 519 J-55 BT &C 3350 1970 531 7" 39' 79' 26# J-55 BT&C 4660 4080 327 7" 79' 6966' 23# J-55 BT &C 4080 3080 288 7" 6966' 8016' 26# J-55 BT &C 4660 4080 327 4 112• 41' 328' 12.6# J-55 mod BT &C 4730 4980 134 41/2" 328' 6261' 12.75# J-55 mod 8rd 4730 4980 134 :::: No:::::::::: ToP::::::::: Lejf9t(1 ::::::::::::::::::::::: 6C 1pti? r/::::::::: ::::::::::::::::::::::::::::::: :::: IQ'::::::::::: :::::::::::OD': :: :::::::::::: TOC @ 2500' CBL PRODUCTION TUBING STRING & JEWELRY :J i: 41 qt 10 3f4" @ 25 F 73 0 00 40.25 Elevation _ 72 40.25 0 1.3 6 3 FMC OCT 6" 3M 4 1 2 8 tl x 4 1/2' BTC TBG Hanqe r 3.958 6.000 71 40 1.33 4 i!2' l BTC Pup Jt 3.992 4 500 70 42.23 252.16 4 1/2" BTC Mod. J-55 Tubing 3.992 4.500 • �i • „ Halliburton VSR packer @ 3912' 69 294.39 2.46 Halliburton "XXO" - set SCSSV 1/02 3.813 5.560 • 68 296.85 31.36 4 1l2" BTC Mod J -55 Tubing 3 992 4.500 • 67 328.21 0.8 X/O 4 1/2" BTC Box x 4 !/2 "' EU Box 3 992 4 500 61 66 329 01 3573.48 4 1/2" EU Mod J-55 8rd Tubing 3 992 4.500 Cook Inlet Sands 65 3902.49 868 Upper "PBR" Assembly 3.950 5.750 • 5 Perforations Squeezed w /cement 64 3911 17 2.62 Retch Latch Seal Unit 3.950 5.560 : 4021 -4031 CI-Stray 63 3912.29 6.48 Halliburton "VSR" Packer 3.880 5.870 4055 - 4080 CI-A 62 3918.77 30.45 4 12" EU Mod J -55 8rd Tubing 3.992 4 500 4102 -4107 CI -B 61 3949.22 1.44 Halliburton "X" Nipple 3.813 5.560 4112 -4162 CI -B 60 3950.66 280.24 41/2" ELI Mod J-55 8rd 3.992 4.500 59 4230.90 2.62 No Go Seal Unit 3.950 5.560 ; = 1 = =� Halliburton TWR pecker @ 4232' 58 4232.02 4.29 Halliburton 'TWR" Packer 4.000 5.870 • 57 4236.31 8.18 Mill Out Extension 8 Tubing Adaptor 4 276 5.560 56 4244.49 156.92 4 1/2" EU Mod J -55 Ord Tubing 3 992 4.500 • _ __ 4325 - 4380 CI - 1.0 55 4401.41 4.22 Halliburton "XD" Sliding Sleeve OPEN 3.813 5.660 55 "1 4388 -4398 CI -1.0 54 440563 262 No Go Seal Und 3.950 5.560 or 53 4406.75 4.3 Hatliburton "TWR" Packer 4.000 5.870 52 4411 05 8.23 Mill Out Extension & Tubing Adaptor 4.276 5.560 �� Halliburton TWR packer @ 4406' 51 4419 28 68.18 4 1/7' EU Mod J55 8rd & Pup Jts. 3.992 4.500 4:::, 50 4487.46 4.22 Halliburton "XD" Sliding Sleeve OPEN 3.813 5.560 4420 -4490 CI -2.0 49 4491.68 4.15 4 1/2" Pup Jt. 3 992 4.500 50 48 4495.83 2 62 No Go Seal Unit 3 950 5.560 47 4496.95 4.3 Halliburton "TWR" Packer 4.000 5.870 ' ; Halliburton TWR packer @ 4496' 46 4501.25 8.19 Mill Out Extension & Tubing Adaptor 4.276 5.560 ::;:: , I It: 45 4509.44 30.54 4 1/2" EU Mod J -55 8rd Tubing 3.992 4,500 44 4509 - 4519 CI 44 4539.98 4.22 Halliburton "XD" Sliding Sleeve OPEN 3.813 5.560 • > : 4540 - 4550 CI-3.1 43 4544.10 8.14 4 1/2" Pup Jr 3.992 4.500 42 4552.24 2.62 No Go Seal Unit 3.950 5.560 ∎�: ::: Halliburton TWR packer @4553' 41 4553.36 4.3 Halliburton "TWR" Packer 4.000 5.870 :. 11 :,..4:::: 40 4557.86 7.23 Mill Out Extension & Tubing Adaptor 4.278 5.560 39 4564.89 82 98 4 1/2" EU Mod J -55 Ord Tubing 3.992 4.500 38 4564 - 4614 CI 38 4627.87 4.22 Halliburton " XD" Sliding Sleeve OPEN 3.813 5.560 37 4632.09 6.10 4 1/2" Pup JL 3.992 4.500 36 4638.19 2.62 No Go Seal Und 3.950 5.560 7: Halliburton TWR packer @ 4839' 35 4639.31 4.3 Halliburton 'TWR" Packer 4.000 5.870 4860 -4700 CI-60 34 4643 61 8.3 Mill Out Extension & Tubing Adaptor 4.276 5.560 4711 - 4716 CI-61 33 4651.91 66.89 41/T EU Mod J55 8rd Tobin. 3.992 4.500 f , ,,,',. +a it • 32 ®" PX PIUr 32 :: PX Plug @ 4717 (1/02) 31 4718.80 2 62 No Go Seal Unit 3 950 5.560 •,, 'MR" TWR packer @ 4719' 30 4719.92 4.3 Halliburton R" Packer 4.000 5.870 • 29 4724.22 8.4 Mill Out Extension & Tubing Adaptor 4 276 5.560 28 473262 30.33 4 EU Mod J -55 8rd Tubing 3.992 4.500 27 '® _ 4733 -4753 CI5.0 27 4762.95 4.22 Halliburton "XD" Sliding Sleeve CLOSED 3.813 5.560 iii ® iii, 26 4767 17 4.10 4 112" Pup JL 3.992 4.500 25 4771 27 2.62 No Go Seal Unit 3.950 5.560 I� Halliburton TWR packer 4772' 24 4772.39 4.3 Halliburton 'TNR" Packer 4.000 5.870 23 4776 69 8.3 Mill Out Extension & Tubing Adaptor 4.276 5.560 • Ifir b e , i t_. tJa 4792 - 4822 CI -7.0 22 4784.99 79.07 4 1/2" EU Mod J -55 8rd Tubing & Pup Jts. 3.992 4.500 '' 4832 -4852 Cl 7.1 21 4864.E 2.62 No Go SCI Unit 3 950 5 660 "l 20 4865.18 4.3 Halliburton WR "Packer 4.000 5.870 .; b7 ..:'? 19 MZSICIII 8.26 Mill Out Extension & Tubing Adaptor 4.276 5 560 Halliburton TWR packer @ 4865' 18 4877.74 59 53 4 1/2" EU Mod J-55 8rd Tubing 3.992 4 500 17 4937.27 4.22 Halliburton "XD" Sliding Sleeve CLOSED 3.813 5.580 _ : 4880 - 4890 CI-8.0 18 4941.49 43.65 4 1/2" EU Mod J55 8rd Tubing & Pup Jts 3.992 4.500 „ 4912 - 4927 CI-8.2 15 4985.14 2.62 No Go Seal Unit 3 950 5.560 17 14 4986.26 4.3 Halliburton 'TWR" Packer 4.000 5.870 . 4963 -4983 CI -9.0 13 4990.58 8.31 Mill Out Extension 8 Tubing Adaptor 4276 5.560 1 12 4998.87 113.14 4 1/2" EU Mod J -55 8rd Tubing & Pup Jts. 3.992 4 500 ` 11 5112.01 4.22 Halliburton "XD" Sliding Sleeve OPEN 3.813 5.560 10 511623 6265 41/2" EU Mod J -55 Ord Tubing 3.992 4.500 9 5172.00 EZSV BP net 12/01 I♦ .Halliburton TWR pecker 4988' 8 5178.88 2.62 No Go Seal Unit 3.950 5.560 5004 -5014 CI -10.0 7 5180.00 4.3 Halliburton 'TWR" Packer 4.000 5.870 : 5031 -5076 CI -11.0 6 5184.30 8.32 Mill Out Extension & Tubing Adaptor 4.276 5.560 11 ,y 5 5192.62 405.26 4 1/2" EU Mod J -55 8rd Tubing 3.992 4.500 i. 4 5597.88 4.22 Halliburton "XA" Sliding Sleeve 3.813 5.560 9 5: EZSV BP @ 5172 (12/01) 3 5602 10 657.32 4 1/2" EU Mod J -55 8rd Tubing 3 992 4.500 * `. ' v i Halliburton TWR packer @ 5180' 2 6259.42 1.50 Halliburton "XN" Nipple 3.725 5.560 Beluga Sands 1 6260.92 0.57 Re -entry Guide 3.995 5.560 • - • 5220 -5235 5-2 6261.491 End of Tubing 5302 - 5308 05.5 ...... ...... ........................ . • • $ 5327 - 5332 0-6 Well History • :i' 5393 - 5413 o-1 April 1969 - Well completed in CI Stray,A,B,1 -11 and Beluga Commingled - 5444 - 5448 0-2.5 with 4"X3-1/2" tubing set at 4349' 4 " NA" rEll _ : 5540 - 5545 d -1 September 1994 Workover - Well completed in Beluga b-2 thin h -9 : 5665 - 5680 d -5 Set BP at 6380' to abandon Beluga j-1 thru o-4 without testing ( : • 5731 - 5736 e-4 Squeeze Cook Inlet Stray, A, 8 B perforations i', 5793 - 5797 e•8 Reperforate/Add Perfs in Beluga from 5220'-6261' Reperforate Cook Inlet 1.0 thru 11.0 from 4325' -5078' - 5810 - 5820 e-9 September 1999 - Top of Fill 6267 RKB 5842 - 5847 f -1 June 4, 2001 Tag fill @ 5986 WLM :. 5884 - 5889 fJ Dec. 17, 2001 Pull SCSSV is 5895 - 5915 f-4 Dec. 12, 2001 Set 4.5" EZSV bridge plug @ 5172' RKB 5980 - 5990 g-1 Dec. 13, 2001 Open XD sleeve @ 5112', net SCSSV ;, : 6084 - 6094 ht & h1.1 Jan 30, 2002 Tag fill @ 4805' WLM; net PX plug @ 4717' WLM 6123 - 6133 h-3 Jan 31, 2002 Open sleeves @ 4353', 4458', 4491', 4579'; set SSSV i, 6136 -6141 h-4 May 13,2002- Tag plug @4710' WLM 2 6182 -6197 h-7 May 13, 2005 - Tag plug @ 4711' WLM (4751' RKB) 1 i:. 6236 - 8261 h-9 EZSV @ 6380 6420 - 6425 j -1 6520 -6525 k -3 6536 - 6551 k-4 6587 - 6592 1 -2 • 6684 - 6689 m5 >. 6734 -8739 m-9 • 6828 - 6843 n -2 • ii 6995 - 7010 04 PBTD 8380' • Updated : 5/13/2005 By: Dan Bearden y :. 7"@,,,,' PBTD: 6380' IPX Plug Tag: 4711' WLM 52005 TD - 8,045' Well: North Cook Inlet Unit No. A -08 I Location: Lower Cook Inlet, Alaska Field: Cook Inlet Unit JDB pc ti 12 q.,,_s,/,- -c-.f-- , __)-- i _ pi, T --_,=_,,,_ _=._ 1 _ __,, -- - 1_- __ Z nn nn Z Upper DGL Pkr Lowest GLM - ��., AVE Sub 4/ - ■ kti Dual flapper Production pkr 4448' check valve Ir $ V X Anchor Latch Lower DGL Pkr r000000,, seal Assy. Ported sub o 0 0 0 PBR c PBR seal Assy. ft 'U Deep Gas Lift ft _ Supply pipe A A ft C: O O Dual Float Shoe 0 A O n A fi, • i 1 Deep g as lift with Mandrels Upper DGL Packer assy. e • • Pup joint AVE Sub Anchor Latch seal assy. Dual flapper a = _.,ipl Check valves • M Lower DGL Packer assy. 1 PBR seal assy. Ported sub r I PBR 4448 production pkr 1.900" IJ pipe = 2.375" dual flapper guide shoe 4698' Shoe depth -- / 2fcb6 �, 5392' New perfs 1994 never produced 7542' ,,.:: - . ° . _ a t''' • Mr. Schwartz, This is an example of deep gas lift when we have mandrels to work with. Deep gas lift without mandrels is what we discussed, the only difference is that I do not need to tubing punch when there are mandrels to utilize. Please let me know if you require any additional information from me. The overall idea is to have the ability to keep the water off of the productive interval that is choking back the wells. Best regards, Marcus Barbee 2\9 WELL LOG TRANSMITTAL To: Alaska Oil and Gas Conservation Comm. October 5, 2012 Attn.: Howard Okland 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: Deep Gas Lift Hoist / Perforating Record: NCI A -06 Run Date: 09/29/2012 & 09/30/2012 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Klinton Wood, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 NCI A -06 Digital Data (LAS), Digital Log file, Casing Inspection Report, 3D Viewer 1 CD Rom 50- 883 - 20026 -00 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline & Perforating Attn: Klinton Wood SCANS APR 0 a 201, 6900 Arctic Blvd. NN..11� Anchorage, Alaska 99518 Office: 907 - 273 -3527 Fax: 907 - 273 -3535 klinton.wood @halliburton.com Date: l� �2. 712 Signed: Page 1 of 2 • Schwartz, Guy L (DOA) From: Barbee, Marcus G (Swift Technical Services LLC) [Marcus.G. Barbee @contractor.conocophillips.com] Sent: Monday, September 24, 2012 12:01 PM To: Schwartz, Guy L (DOA) Cc: Buck, Brian R l &Q cj —0C O Subject: RE: Tyonek Deep Gas Lift A -06 Mr. Schwartz, Yes, this is the first deep gas lift assist system to be installed on the Tyonek Platform. We are hopeful that this will be successful in our attempt to keep water off of zone and allow the wells to produce at their potential. If so, there may be more candidates that come available for this technology. Thank you, and if you would like I will let you know the overall outcome of the installations. Best regards, Marcus HNEO APR 17 2,010 From: Schwartz, Guy L (DOA) [ mailto:guy.schwartz @alaska.gov] Sent: Monday, September 24, 2012 11:37 AM To: Barbee, Marcus G (Swift Technical Services LLC) Subject: [EXTERNAL]RE: Tyonek Deep Gas Lift A -06 Marcus, I don't see any reason for a 10-403 sundry request for this scope of work. Is this the first gas assist lift (DGL) on the Tyonek Platform? I am not familiar with the production setup out there on these gas wells. Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Barbee, Marcus G (Swift Technical Services LLC) [mailto:Marcus.G. Barbee @contractor.conocophillips.com] Sent: Monday, September 24, 2012 10:28 AM To: Schwartz, Guy L (DOA) Subject: FW: Tyonek Deep Gas Lift A -06 Mr. Schwartz, As per our phone conversation pertaining to Tyonek Platform Well A - 06. We have already: • Drifted and tagged and confirmed clearance • Proved integrity of the production tubing are planning: 9/24/2012 Page 2 of 2 . • • Rig up and test 4.06" TOTCO quad BOP's dressed with blinds, shears, slips, pipes (top down) • Kill the well with a tubing volume and a half of 6% KCL • Monitor the well for 1 hour and determine a loss rate • Fill the hole and run 1.900" IJ pipe (+ -900') with the Unit Crane • Connect it to a packer and E - Line setting assembly, lubricate same and stab on • RIH & Set the packer above the production packer @ + -3900' • Test the integrity of the packer from above • Tubing punch above the packer • Run a straddle assembly that will allow gas from the production tubing annulus to enter the inner string /dip tube, realize annular flow from its shoe up the production tubing by dip tube annulus, (lifting produced water along the way) re -enter the production stream below and through the straddle assembly and on to surface above the upper packer. A power point is attached for clarification. If necessary, I can modify this example to reflect a mandrel less completion, but I think it will be self explanatory. The lower assembly will be an e-line operation and the upper packer assembly will be a slick - line operation. Thank you for taking the time to discuss this with me this morning; if you have any questions please do not hesitate to call. I am on the Tyonek Platform now and can be reached at 1- 907 - 776 -2096. Marcus Barbee Wells Engineer ConocoPhillips Alaska, Inc. 9/24/2012 • S Mr. Schwartz, This is an example of deep gas lift when we have mandrels to work with. Deep gas lift without mandrels is what we discussed, the only difference is that I do not need to tubing punch when there are mandrels to utilize. Please let me know if you require any additional information from me. The overall idea is to have the ability to keep the water off of the productive interval that is choking back the wells. Best regards, Marcus Barbee • 0 Deep gas lift with Mandrels Upper DGL Packer asst'. • ■ Pup joint AVE Sub Anchor Latch - seal assy. Dual flapper Check valves • Cr a`_ Lower DGL Packer assy. --_____.÷ ■ I PBR seal assy. Ported sub PBR `_ _ _ z 'l 4448' production pkr EE Z- 1.900" IJ pipe = _ 1 1 2.375" dual flapper guide shoe 4698' Shoe depth q3d a��\ 5392' �� New perfs 1994 never produced 7542' • • IJ I _ ii- i►e 1 Z A n g Upper DGL Pkr , 11 _ � itv Lowest GLM I E AVE Sub ` .. 1---- Dual flapper Production pkr 4448' V check valve g Lower DGL Pkr o A Latch . 0 0 o seal Assy. Ported sub 4 o o � ° 0 Q1 ° 0 °°°3 PBR PBR seal Assy. ' fi V J Deep Gas Lift ft - ft Supply pipe A ft L O O O Dual Float Shoe O 0 fi. O i A f V ft Well Name Pre 2008 Survey Location NAD27 ASP 4 Northing Easting Post 2008 Survey Location NAD27 ASP4 Northing Easting Distance Moved NCI A-01 2,586,726.69 332,100.19 2,586,726.40 332,102.26 2.09 NCI A-02 2,586,722.85 332,108.29 2,586,721.16 332,111.27 --- 3.43 NCI A-03 - - 2,586,728.60 332,106.22 2,586,728.31 332,109.43 ---- 3.22 ----- NCI A-04 2,586,719.62 ------ 332,105.09 -- 2,586,718.58 332,108.09 3.18 NCI A-05 2,586,725.55 332,110.17 _ 2,586,725.14 332,111.79 1.67 NCI A-06 2,586,719.66 332,102.09 2,586,719.22 332,104.19 2.15 NCI A-07 2,586,727.79 332,103.73 _ 2,586,728.78 332,105.40 1.94 NCI A-08 2,586,720.56 332,098.31 2,586,722.44 332,101.65 3.83 NCI A-09 2,586,666.58 332,039.08 2,586,667.35 332,040.44 1.56 NCI A-10 2,586,670.21 332,040.91 2,586,673.71 332,044.17 4.78 NCI A-10A 2,586,670.21 332,040.91 2,586,673.71 - 332,044.17 4.78 --- NCI A-11 2,586,670.23 332,039.14 - 2,586,677.01 __ _ 332,041.75 _ __7.27 NCI A-12 2,586,722.73 331,947.80 2,586,723.59 331,994.15 46.36 NCI A-13 2,586,734.88 331,993.50 2,586,733.15 331,995.48 2.63 NCI B-01 2,586,730.03 331,999.80 2,586,723.04 331,998.16 7.18 NCI B-01A 2,586,730.03 331,999.80 2,586,723.04 331,998.16 7.18 NCI B-02 2,586,731.14 331,999.29 2,586,729.60 332,001.86 3.00 NCI B-03 2,586,731.69 331,986.37 2,586,726.81 331,991.70 7.23 NCI B-03PB1 2,586,731.69 331,986.37 2,586,726.81 331,991.70 7.23 • • ~~N~ APR ~ 4 200 !~~ --oS~ REV DATE BY CK APP ESCRIPTION REV DATE 8Y C P DESCRIPTION I 2/29/08 SAS ~(VV/-I MODIFY WELL HOUSE SCHEMATIC, SH T.2 ADD MUD LINE ELEV., SHT.3 ~ ~ 36 31 o T 12 IV 31 32 ~ " .~ ~2 ~ 1 6 T I I N 6 5 (v I rw as N s, isvs• SEE. 6 1206' SCALE: I"=1320' -6 -- ~ ~ o ~ ~ 1 6 6 5 12 7 ~ 8 ~ ~ GENERAL NOTES: ~ ~F ~ EE .......... .• ~-q !~ 1. SEE SHEET 3 FOR COORDINATE TABLE P ~ , . s ~ • '~ .../~ 1 ~ ~~ • 2. SEE SHEET 3 FOR NOTES ON HORIZONTAL AND ~ ~ ~ ~ ~ ~ ~ ~ VERTICAL SURVEY DATA 49th : ~j r ~ • ' ..... 3. SECTION LINES AND TIES ARE BASED ON PROTRACTED ~"""""""""""""""""""""` VALUES. ~.~ ................................... ....~ i ~ ~• ~, =: KENNETH W. AYERS ~~ ~o~ LS-8535 ',~ ~~~~ ~• J' '., SURVEYOR'S CERTIFICATE ~ ~1~1, AROF,,.,.,.,,,`~'P~::~i ~ ~ I HEREBY CERTIFY THAT 1 AM PROPERLY REGISTERED AND ~~~;"~=~~~ LICENSED TO PRACTICE LAND SURVEYING IN THE STATE OF ALASKA AND THAT THIS PLAT REPRESENTS A SURVEY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL DONE BY LOUNSBURY DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF & nssoccATES, INC. S[1RVEYORS ENGINEERS PLANNERS FEBRUARY 28, 2008. ~ PHONE: (907/ 272-5451 `„~ AREA: MODULE: UNIT: ConocoPhilli s NORTH COOK INLET p TYONEK PLATFORM Alaska, Inc. WELL CONDUCTOR AS BUILT CADD FILE N0. DRAWING N0: PART: REV: 08-005 AS BUILT 02/27/08 ~g~05 AS BURET 1 of 3 1 I r~ REV DATE BY CK APP DESCRIPTION REV DATE BY CK P DESCRIPTION I 2/29/08 SAS KWA MODIFY WELL HOUSE SCHEMATIC, SHT.2 AOD MUD LINE ELEV., SHT.3 ~_ v g ys ~ aY 9 °p 8~ pA9 ,3 a TYM ns ~p S. 9w' S~ sc a ~~ ~j ~O so ~`s SCALE: I"=30' 99 AA~ O SD 600 50 E - ESD 600-51 O Ala 7 Ip •92 A6 A•A• 83 : •p5 A6• A3• AI2 81 • ••A5 A4 A2 WELL HOUSE 2 Op• z p A1O• LEGEND: O •p5 3 AB • WELL p WELL CONDUCTOR 0 ESD (EMERGENCY SHUT OFF VAL VEl GENERAL NOTES: !. SEE SHEET 3 FOR COORDINATE TABLE 2. SEE SHEET 3 FOR NOTES ON HORIZONTAL AND VERTICAL SURVEY DATA LOUNSBURY 3. NO WELLS EXIST IN WELL HOUSE N0. 4, AND IT WAS NOT & ASSOCIATES, INC. AS BUILT J SURVEYORS ENGINEERS PLANNERS 907 272 5451 ~ ) - PHONE: ( y„i AREA: MODULE: UNIT: Philli s C NORTH COOK INEET p onoco TYONEK PLATFORM Alaska, Inc. W ELL CONDUCTOR AS BUILT CADD FILE N0. 08-005 AS BUILT 02/27/08 DRAWING N0: 08-005 AS BUNT PART: 2 of 3 REV: 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 'REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown_ Stimulate _ Plugging_ Pedorate _ Pull tubing _ 2. Name of Operator Alaska, Inc. 3. Address P. O. Box 100360 AK 99510-0360 4. Location of well at surface 1259~ FNL, 1083' FWL, Sec. 6, T11N, RDW, SM - Leg At top of productive interval 2600' FNL, 400' FWL, Sec. 6, T11N, RDW, SM At effective depth Alter ~-.,~.~ing _ 5. Type of Well: Development __X Exploratory __ Stratigraphic _ Service__ At total depth 680' FSL, 741' FEL, Sec. 1, T11N, R10W, SM 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Length Size Conductor 623' 16" Surface Casing 2579' 10.75" Production 8016' 7" 8045 feet 6892 feet 6380 feet 5490 feet Cemented 575 sx Class G 709 sx Class G 1107 sx Class G 'Plugs (measured) Junk (measured) Repair well _ Other_X Set Plug 6. Datum elevation (DF or KB feet) RKB 116 feet 7. Unit or Property name North Cook Inlet Unit 8. Well number NCI A-06 9. Permit :number / approval number 1~5o / 10. APl number 50-283-20026-00 11. Field / Pool North Cook .Inlet Measured Depth 623' 2579' 8016' True vertical DePth 623' 2397' 6866' Perforation depth: measured refer to attached schematiC true vertical (size, grade, and measured depth) Packers & SSSV (type & measured depth) RECEIVED 4.5",12.5#,J-55 @ 6261' refer to attached schematic refer to a_tt_e~.hed schematic 13. Stimulation or cement squeeze summary Intervals treated (measured) N/A Treatment description including volUmes used and final pressure OiI-Bbl Prior to well operation N/A Subsequent to operation N/A JUN 2O 2002 A~as~3 Oil & Gas Cor~s. Comm~s$1~,, Anchorage ~Representative Daily Averaqe Production or Injection Data Gas-Mcf Water-Bbl Copies of Logs and Surveys run Daily Report of Well Operations _X Oil _ Ga 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Brian Seitz Suspended __ 7~.~~ Title: ~k~ Tc.;m Lc=der' Casing Pressure Tubing Pressure Service. __ Question~? Call Len-Janso'n (907)' 776-2046 Date ~ 263-4612 Form 10-404 Rev 06/15/88 · SUBMIT.IN DUPLICATE Date Comment 'NCI A-06 Event History 12/11'/01 12/12/01 1 2/13/01 01/29/02 01/30/02 Pull SCSSV, Drift tbg in prep for EZSV bridge plug. Set 4 1/2" EZSV bridge plug @ 5172' MD- set good. Shift sleeve in Cook Inlet zone @ 5079' WLM/set SCSSV and tested good. Drift & tag, set PX plug. Objective - convert well to upper cook inlet producer. Set PX plug, open sleeves, set SSSV. Objective - convert well to upper cook inlet producer. ',Page I of I 2/21/'2002 382 623 TOC @ 2500' 10 3/4" @ 2579 Cook Inlet Sands "VSR" packer @ 3912' Perforations Squeezed w/cement 4021 - 4031 CI-Stray 4055 - 4080 CI-A 4102- 4107 CI-B 4112-4162 CI-B Packer @ 4232 4325-4380 C1-1.0 4388-4398 C1-1.0 Packer @ 4406 4420-4490 CI-2.0 Packer @ 4496 4509-4519 CI-3.0 4540 - 4550 CI-3.1 Packer @ 4553 4564-4614 CI-4.0 Packer @ 4639 4660-4700 CI-5.0 4711 -4716 CI-5.1 Packer @ 4719 4733- 4753 CI-6.0 Packer@4772 4792- 4822 CI-7.0 4832- 4852 CI 7.1 Packer @ 4865 4880 - 4890 CI-8.0 4912-4927 CI-8.2 4963- 4983 CI-9.0 Packer@4986 5004-5014 C1-10.0 5031-5076 C1-11.0 XD Sleeve @ 5112/EZSV BP @ 517 Packer @ 5180 NOIU A-6 FMC OCT W~--~0mpletion Diagram FMC 4 1/2" 8rd X 4 1/2" BT&C Salt Water With 3 bbl Me~_h~nnl 2500' from CBL d_nt,~_ 05/27/69 WATER DEPTH: 120' Prod~!on WT [ Grade [ Conn. 65 lb/ft H-40 45.5 & 51 lb/ft J-55 BT&C 26 ib/ft J-55 BT&C 23 lb/ft J-55 BT&C 26 lb/ft $-55 BT&C 12.6 lb/ft J-55 12.75 ibm ~-55 mod BT&C mod 8rd Description PRODUCTION TUBING STRING Elevation FMC / OCT 6" 3M 4 1/2" 8rd x 4 1/2" BTC 4 1/2" BTC Pup Jt. 4 112" BTC Mod. J-55 Tubing Halliburton "XXO" WLRSVN - reset SCSSV 12/13/01 4 1/2" BTC Mod. J-55 Tubin~ X/O 4 1/2" BTC Box x 4 !/2'" EU Box 4 1/2" EU Mod J-55 8rd Tubing Upper "PBR" Assembly Ratch Latch Seal Unit Halliburton "VSR" Packer 4 1/2" EU Mod J-55 8rd Tubing "X" Nipple 4 1/2" EU Mod J-55 8rd No Go Seal Unit Halliburton "TWR" Packer Mill Out Extension & Tubing Adaptor 4 1/2" EU Mod J-55 8rd Tubing Halliburton "XD" Sliding Sleeve No Go Seal Unit Hallihurton "TWR" Packer Mill Out Extension & Tubing Adaptor 4 1/2" EU Mod J-55 8rd & Pup Jts. Halliburton "XD" Slidin~ Sleeve ) Jt. No Go Seal Unit Halliburton "TWR" Packer Mill Out Extension & Tubing Adaptor 4 1/2" EU Mod J-55 8rd Tubin~ Halliburton "XD" Slidin~ Sleeve ) Jt. No Go Seal Unit HallibUrton "TWR" Packer Mill Out Extension & Tubin~ Adaptor 4 1/2" EU Mod J-55 8rd Tubin~ Halliburton "XD" Slidinl~ Sleeve ) Jt. No Go Seal Unit Halliburton "TWR" Packer Mill Out Extension & Tubing Adaptor 4 1/2" EU'Mod J-55 8rd Tubin~ No Go Seal Unit Halliburton "TWR" Packer Mill Out Extension & Tubing Adaptor 4 1/2" EU Mod J-55 8rd Tubing Halliburton "XD" Siidin~ Sleeve Jt. No Go Seal Unit Halliburton "TWR" Packer Mill Out Extension & Tubing Adaptor 4 1/2" EU Mod J-55 8rd Tubing & Pup Jts. No Go Seal Unit Halliburton "TWR" Pa~kor Mill Out Extension & Tubin 4 1/2" EU Mod J-55 8rd Tubing Halliburton "XD" Sliding Sleeve 4 1/2" EU Mod J-55 8rd Tubing & Pup Jts. No Go Seal Unit Halliburton "TWR" Packer Mill Out ExtensiOn & Tubin~ Adaptor 4 1/2" EU Mod J-55 8rd Tubin Halliburton "XD" Slidin~ Sleeve 4 1/2" EU Mod J-55 8rd Tubin~ No (30 Seal Unit Halliburton "TWR" Packer Mill Out Extension & Tubing Adaptor Jts. 4 1/2" EU Mod J-55 8rd Tubin~ Halliburton "XA" Slidin~ Sleeve 4 1/2" EU Mod J-55 8rd Tubin~ Deck: 40.25 ~B-SL: ~ 11S.90 TD = 8,045' . . Beluga 5220-5235 5302-5308 5327-5332 5393-5413 5444-5448 5540-5545 5665-5680 5731-5736 5793-5797 Sand~'~ b-2 b-5.5 b-6 c-1 c-2.5 d-1 d-5 e-4 e-8 5810-5820 5842- 5847 5884-5889 5895-5915 5980-5990 6084-6094 6123-6133 6136- 6141 6182- 6197 6236-6261 e-9 f-1 f-3 f-4 g-1 hl & h1.1 h-3 h-4 h-7 h-9 ezsv @ 6380 6420-6425 j-1 6520- 6525 k-3 6536-6551 k-4 6587-6592 I-2 6684-6689 m-6 6734-6739 m-9 6828-6843 n-2 6995-7010 o-4 7" @ 8016 *New Pedorations (1994) 1 I 6260'92 ,I ' 0.57' IRe;entry Guide t 626,.491 }End of Tubing WELL HISTORY 3.725 [ 5.560 3.995I' 5.56,0 April 1969 - Well COmpleted in CI Stray,A,B,l-ll and Beluga Commingled with 4"X3-112" tubing est at 4349' September 1994 Workover - Well completed in Beluga b-2 thru h-9 Set BP at 6380' to abandon Beluga j-1 thru o-4 without testing i!;ueeze Cook Inlet Stray, A, & B perforations leperforate/Add Perfs in Beluga from 5220'-6261' Reperforate Cook Inlet 1.0 thru 11.0 from 4325'-5076' September 1999 - Top of Fill 6267 RKB 3ec. 11, 2001 Pull SCSSV Dec. 12, 2001 Set 4.5" EZSV bridge plug @ 5172' RKB Dec. 13, 2001 Open XD sleeve @ 5112', set SCSSV Updated b~': ImO 1/6102 I PBTD: 6380' [Supv: Well: North Cook Inlet Unit No. A-06 ITb~[ Wt: 4 1/2" - 12.6 & 12.75 lb/fi I November 1, 1994 Location: Lower Cook Inlet, Alaska Field: Cook Inlet Unit MPG PHILLIPS Alaska, inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 B. Seitz Phone (907) 265-6961 Fax: (907) 265-6224 March 12, 2002 Commissioner Cammy Oechsli Taylor State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Report of Sundry Well Operations lqCIU A-06 (169-050) Dear Commissioner: Phillips Alaska, Inc. submits the attached Report of Sundry Well Operations for the recent operations on the Tyonek well NCIU A-06. A plug was set to isolate lower zones .to allow for production from only the upper zone. If there are any questions, please contact me or Len Janson at 907-776-2046. Sincerely, B. Seitz Sr. Operations/Reservoir Engineer Phillips Alaska Inc. .BS/skad RECEIVED JUN 20 2002 (]ii & !~,~ :, iO~ OFtI $!NAL STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation Shutdown~ Pull Tubing X_ 2. Name of Operator: Phillips Petroleum Co. 3. Address: P.O. Box 1967 Houston, TX 77251-1967 Stimulate Alter Casing Plugging Repair Well 5. Type of Well Development X Exploratory Stratigraphic Service Perforate X Other 6. Datum elevation (DF or RKB) RKB 116 Feet 7. Unit or Property Name North Cook Inlet Unit 4. Location of well at surface: 1259' FNL & 1083' FWL At top of productive interval: 2679' FNL & 424' FWL At effective depth: 2679' FNL & 424' FWL At total depth: 1392' FSL & 203' FEL Leg 3, Slot 3 PPCo. Tyonek Platform Sec 6 - T11N - R9W North Cook Inlet, Ak. 4021' MD 3567' TVD SecE-TllN-R9W 4021' MD 3567' TVD SecE-T11N- R9W 6380' MD 5713' TVD sec 1 -T11N-R10W 8. Well Number A-06 9. Permit Number / Approval Number 69-0050 19-220 10. APl Number 50-883-20026 11. Field / Pool Cook Inlet / Beluga 12. Present well condition summary: Total Depth: measured 8,045 feet true vertical 6,892 feet Effective Depth: measured 4,021 feet true vertical 3,567 feet Plugs (measured) PBTD: Junk (measured) 6,380' ORIGINS/_ Casing: Structural Conductor Surface Intermediate Production Liner Length Size Cemented Measured Depth True Vertical Depth 30 " Driven 382 382 16 " 575 sx CI "G 623 623 10 3/4" 709 sx CI "G 2,579 2,397 1107 sx Cl "G 8,016 6,866 Perforation Depth: measured 4021' - 7010' true vertical 3567' - 6005' Tubing (size, grade and measured depth) Packers and SSSV ( type and measured depth) 4 1/2" 12.6 Ib/ft J-55 Mod BT&C Tubing 41-328' 4 1/2" 12.75 Ib/ft J-55 Mod 8rd Tubing 328-6261' Halliburton "XXO" WLRSVN at 294', Halliburton "VSR" packer at 3912' Halliburton "TWR" Packers at 4232', 4406', 4496', 4553', 4639', 4719', 4772', 4865~41~1~ 13 o 1 E 13. Stimulation or cement squeeze summary: Intervals treated (measured): 14. Treatment description including volumes used and final pressure: Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Prior to well operation: 0 12400 Water-Bbl Casing Pressure 0.44 210 0il & Gas Cons. C0mm. issipn Tubing Pressure 933 07/04/94 Subsequent to operation 0 15900 1,9 580 961 12/O8/94 15. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations 16. Status of Well Classification as: X Oil__ Gas X Suspended Service 15. I hereby certify that the foregoing is true and correct to the best of my knowledge: Signed ~ * ~r ~ Title Principle Engineer Form 10-404 Rev. 06/15/88 Date 19-Jan-95 SUBMIT IN DUPLICATE PHILLIPS PETROLE~ ~' DAILY REPORT SUMMARYI PAGE:i WELL:North Cook Inlet Unit No. FIELD:COOK INLET NORTH CNTY/STATE:TYONEK OFFSHORE/ALASKA RIG:Pool Arctic Alaska/Pool Arctic Alaska AFE$:P-V127 AUTH COST:$1,757,000 DATE DEPTH RPT NO IM OPERATIONS SUflMARY DAILY COST OJI4 COST EVENT TYpE; Wor~over 09/01/9~ 8,045 1 8.5 FINISHED RD COIL TBG/SKIDDED RIG FROM A-&/KILLED UELL/PULLED S29,220 S29,220 SSSV/SET PLUG IN SSSV NIPPLE/RD RISER/SET BPV/ND TREE/MU BOP'S 09/02/94 "8,045 2 8.5 FINISHED NU BOP'S/TESTED BOP'S/PULLED UIRELINE PLUG/PULLED S45',717 $74,9~6 SEALS FREE/POOH LAYING DM TUBING-FULL RECOVERY/HU PACKER MILLING ASSEMBLY/ 0~/03/9~ ..... 8,045 3 8.5 MILLED OVER & RECOVERED PACKER/GLEANED OUT SAND/PCX)fl/ ' S57,084 S132,021 ..... REPAIRED UELL HEAD/RIH UITH EZSV/ 09/04/94 8,045 ' 4 8.5 SET CIBP E6~80/CBU/POOH/TIH SET CIBP G~2OO/CBU/QJT DRLG LINE S35,3~0 " S1'6~,~)0 POOH/RIH OPEN ENDEO/SET OMT PLUG & SQUEEZE STRAY A & B PERFS POON/RIH U/BIT TO CLEAN OUT/CLEAN OUT TO 82.! F/PERFS/I~ 8.5 DRILLED UP ONT & TESTED STRAY A & B PERFS/DRILLED UP EZSV/ RIH TO PBTD/CIRC HOLE CLEAN/POOH/PU PERF GUNS FOR BELUGA & RIH/RU & CORRELATE U/SCHLUMBERGER 8.5 PERFORATE & SURGE BELUGA PERFS/KILL UELL/CIRC OUT GAS/POOH/ 09/05/94 8,04S 5 S61;276 S228,636 04/06/94 8,045 "'6 MAKE BIT & SCRAPER RUN/MU & RIH UITH PERFORATING ASSEMBLY TO PERFORATE COOK INLET/CORRELATE U/SCHLUMBERGER $38,946 $267,582 0~/07/9~ ..... 8']'04~ " '7' 8.5 PERFORATED & SURGED COOK INLET SANDS/KILLED UELL/POOH/MADE $294,62i $562,203 BIT & SCRAPER RUN/CBU/POOH/RIH UITH PKR & TAIL PIPE/JET IN U/CT & N2 TO CLEAN UP BELUGA SANDS/FLOU TEST BELUGA 09/08/94 8,045 8 8.5 FINISHED TESTING BELUGA/CIRC UELL DEAD/POOH & LD TAIL PIPE/ $81,221 $643,~25 RIH & JET IN COOK INLET/FLON TEST COOK INLET TO CLEAN UP/ CIRC UELL DEAD/POOH/MAKE SCRAPER RUN/CIRC HOLE CLEAN/POOH 09/09/94 8,045 9 8.5 RUN COMPLETION BY SETTING PACKER ASSEMBLIES # 1, # 2, # 3, $6~,297 $?07,722 # 4, RIM U/# 5 AT REPORT TIME 09/10/94 8,045 ........ 10' 8.5 CONTINUE U/OOMPLETION BY SETTING PACKER ASSEMBLIES # 5, # 6, $31,830 S739,552' # 7, # 8, # 9, # 10, & RIH U/# 11. 09/11/94 8,045 11 8.6 FINISHED RUNNING COMPLETION/DISPLACED ANNULUS UITH PACKER S352,334 S1,091,886 FLUID/ND BOP~S/NU & TEST TREE & FLOULINE/TEST CASING/RU RISER & COIL TBG/JET IN UELL/FLOU UELL FOR CLEAN UP 09/12/94 8,045 12 8.6 FINISHEO FLC~/ING A-6 FOR CLEAN UP. RD COIL TBG & TEST EQUIP $71,204 $1,163,090 PREPARE RIG FOR SKIODING TO Ao3/RELEASE UELL TO PROOUCTION ***** FINAL REPORT ***** 10/30/94 8,045 13 8.6TIH U/GUAGE RING & SHIFTING TOOL CHECKING SLEEVES.CLOSED $1,000 S1,164,090 SLEEVES THAT UERE OPEN. PRODUCING BELUGA ZONES gBOTTCM. TURN UELL BACK INTO PRODUCTION. DAYSUM.RPl 12/07/94 RECEIVED JAN 2 T 1995 AnChor !INAL WELL COMPLETION DIAGRAM PSTO 5380' 'ID = 045' 382 623 TOC · 2500' 10 3/4' O 2570 UlCer cook Inl~ Sandl 4021 ~ 4031 4055.4080 4102-4107 4112-4162 Packw~4232 4325 - 4380 C1-1 4388 - 439~ 4420 - 4490 Ck2 Packer · 4496 4509 - 4519 CI-3 4540 - 4550 Packer O 4553 4564 - 4514 Cl-4 ~ 4660 - 4700 C1-5 ~.~ 4711-4715 4733 - 4753 Cl-~ 4792 - 4822 Ct-7 4832 o 4852 4012 - 4027 4963 - 49~3 C1-9 packer O 4986 5004 - 5014 CklO 5031 - 5075 Ck11 packer · 5180 5220 - 5235 5327 - 5332 5393 - 5413 5540 - 5545 5731 - 573~ · " 5793- 5701 5910 - 5820 5042 - 5847 5884 - 5889 5895 - 5015 5980 - 5990 5135 - 6141 6182 - 5107 $23~ - 0261 ezsv G 6380 6420 - 6425 6520 - 6525 6536 - 6551 6587 - 6592 6~84- 6689 6734 - 6739 699~- 7010 7" Q 8016 FMC OCT FMC 4 I/~" ~rd X 4 IIZ" BT&C Sail Water wJtb 3 bbl Melband RKB-DrlII I)ed~ RK&.THF: 49.2~ Rifll-SL: I IS.90 2500' rrem CBL dated 05/271&9 Predudlen Casing: WATER DEPTH: 120 * RKB. ML: TUbing StrJn~ 12.751b/fl PRODUCTION TUBING STRING Elevation FMC / OCT 6" 3M 4 !/2" 8rd x 4 ) JL I/2" BTC Mod. J-55 Tubing Hallibta~on ":XXO" WLRS'v'N I/2" BTC Mod. J-~ Tubir~ X/O 4 I/2" BTC Box x 4 ~/2"' EU Box 4 I/2" EU Mod J-55 8~d Tubin8 'PBR" iRatch Latch Seal Unit Ha]libu,'ton 'VSR' Packer 4 1/2' EUMod J-55 8rdTubing Halliburton "X" Nipple 4 !/2" EU Mod J-55 8rd Hallibmlon "TWR' Packer Mill Out Extension ac Tubing Adaptor 4 I/2" EU Mod J-55 8rdTubin8 Halliburton "XD" Slidin8 Sleeve No Go Seal Unit Halliburton "TWR." Packer Mill Out Extension ac Tubing Adaptor 4 I/2" EU Mod J-55 8rd ac Pup Jts. Halliburton "XD" Sliding Sleeve 4 I/2' Pup Jr. No Go Seal Unit Halliburton "TWR" Packer Mill Out Extension ac Tubing Adaptor 4 I/2' EU Mod J-55 8rdTubin~ Ha]Ubtcrton 'XD' Sliding Sleeve 4 1/2" Pup JL No Go Seal Unit H~lllbmlon 'TWR" Packer Mill Out Extension ac Tubing Adaptor 4 !/2" ELI Mod J-55 8rdTubing HalUburton "X]:)" Sliding Sleeve I/2" Pup JL No Go Seal Unit Hnllibuflon "TWR" Packer [Mill Out Extension ac Tubin~ Adaptor EU Mod J-55 Srd Tubing No Go Seal Unit Haliibu~mn "TWR.' Packer Ivlill OUt Extension ac"rubin~ Adaptor 4 I/2" EU Mod J-55 8rdTubing Hdlibu.~n 'XD" S{iding Sleeve 1/2" Pup jr. No Go Seal Unit Hallibmton "'I~ZR." Packer Mill Out Extension ac Tubing Adaptor 4 i/2' EU MOd J-55 8rd Tubing ac PUp Jts. No Go Sed Unit HaUiburton "TWR." Packer Mill Out Extension & Tubin~ Adaptor 4 I/2' EU Mod J-55 8rdTubing Hatlibmton "XD' Slidiag Slaeve 4 !/2" EU Mod J-55 Srd Tubin~ ac Pup Jts. Hallibu~on "TWR." Packer Mill Out Extension & Tubing Adaptor 4 I/2" ELI Mod J-55 8rdTubi~g ac PUp Jts. Hallibuaon ':RD" Slidin~ Sleeve 4 I/2" EUMod J-55 8rdTubin8 No Go Seal Unit Hailibmton "*I~/~." Packer Mill Out Extension & Tubing Adaptor 4 !/2' EUMod J-55 SrdTubi~ Hallibuxton "XA' Sliding Sleeve 4 !/2" EU Mod J-55 8rd Tubing Halliburton "XN" Nipple ~ Gu~dc PRODUCflON PERFORATION INTERVALS COOK INLET SANDS ~ 4021 o 4031 S(lueez~l ~ Ck"B' 4102 - 4107 ,Squeezed ~ ck'r 4112.4102 Squeezed 43~-4380 4388-~ C~2 4420-4490 C~3 4509-4519 4540-4550 CI-4 4564-4514 4860-4700 4711- 4716 CI-6 4733 - 4753 CI-7 4792 - 4822 4832 - 4852 CI.8 488O - 489O 4012 - 4927 C1-9 4963 * 4983 C1-10 5004 - 5014 C1-11 5031. 5076 Re-Perf'd Rl-Peffd New Perfs BELUGA "Low~' SANDS 5220- 5235 5302 - 530~ 5327 - 5332 53~ - 5413 5444 - 5~45 5540 - 5545 50~5 - 5050 5731 - S733 5753- 5707 5810 - 5820 5842 - 5847 5895 - 5015 5980.5~0 6123 - 6133 6136 - 8141 6182 - 8197 0236 - 6261 6420. 0425 0520 - 5525 6536. 6551 65~1. 6592 0734 - 0730 ~a25. ~a43 6996 - 7010 No~ Re-P~f'd PBTD: 6380' {$up~. Wel~ North Cook IMd Unit Ne. A-e6 Location: ~w~ C~k I~ ~h {TbgWt: 41/2" - 12.6 ac 12.751b/It Field: Cook Inlet Unit Novemb~ 1, 1994 MPG PHILLIPS PETROLEUM HOUSTON, TEXAS 77251-1967 BOX 1967 NORTH AMERICA EXPLORATION AND PRODUCTION COMPANY BELLAIRE, TEXAS 6330 WEST LOOP SOUTH PHILLIPS BUILDING August 09, 1994 North Cook Inlet Unit "A-6" Phillips Tyonek Platform "A" North Cook Inlet, Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: North Cook Inlet Unit A-6 Workover Program ORIGINAL Attached are three copies of the Application for Sundry Approvals, form 10-403, and three copies of the tentative workover program for the vvorkover of the A-6 well on the North Cook Inlet Unit. Included in the program are the BOP schematic and the well control policy for the vvorkover. If you have any questions concerning this workover or need any additional information please contact Paul R. Dean at (713) 669-3502. Regards, D~C Ginger Drilling and Production Engineering cc (w/enc): V. R. Chamberlain ~ M. L. Jones (r) P. R. Dean J.F. Mitchell Central files Gas Cons. c0m~'tss'~0~ Anch0ra~e 1. Type of Request: 2. Name of Operator. Philli )leum Co. 3. Address: 6330 W. Loop South Bellaire Texas 77401 4. Location of well at surface: 1259' FNL & 1083' FWL At top of productive interval: 2679' FNL & 424' FWL At effective depth: 2679' FNL & 424' FWL At total depth: 680' FSL & 741' FEL Sec 1 - T11N - R10W 12. Present well condition summary: Total Depth: measured 8,045 feet true vertical 6,892 feet ..... STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS Abandon ~ Suspend Operation Shutdown ..... Alter Casing __Repair Wel Plugging X Time Extension ram Pull Tubin~l X ,,,,,Variance 5. Type of Well Development X Exploratory Stratigraphic Service Leg 3, Slot 3 PPCo. Tyonek Platform Sec 6 - T11 N - R9W 4021' MD Sec 6 - T11N - R9W 4021' MD Sec 6 - T11N - R9W 8045' MD North Cook Inlet, Ak. 3567' I'VD 6892'TVD Plugs (measured) Effective Depth: measured 4,021 feet true vertical 3,567 feet Junk (measured) Reenter Suspended Well Stimulate Perforate X Other .,X (add peris) 6. Datum elevation (DF or RKB) RKB 116 Feet 7. Unit or Property Name North Cook Inlet Unit 8. Well Number A-06 9. Permit Number / Approval Number 10. APl Number 50-883-20026 11. Field / Pool Cook Inlet / Belu(ja PBTD: 7,977' ORIGINAL Casing: Structural Conductor Surface Intermediate Production Liner Length Size Cemented Measured Depth True Vertical Depth 30" Driven 382 382 16" 575 sx CI "G" 623 623 10 3/4" 709 sx CI "G" 2,579 2,397 7" 1107sxCl"G" 8,016 RECEI" ED Perforation Depth: measured 4021' - 7010' AUG 1 5 1994 true vertical Tubing (size, grade and measured depth) Packers and SSSV ( type and measured depth) 13. Attachments: 3567' - 6005' A, iE[ska 0il & Gas Cons. Commission Anchorage 4" 10.9 Ib/ft J-55 BT&C & 3 1/2" 9.2 Ib/ft J-55 BT&C set at 4,349'. Otis "RH" retrievable packer @ 3,983'; Otis "WB" permanent packer @ 4,310'. Otis "AC" Wireline Retrievable SSSV 280.20'. Descrip~on Summary of Proposal Detailed Operations Program __ BOP Sketch 14. Estimated Date for Commencing Operations: September 0111994 16. If Proposal was Verbally Approved: 15. Status of Well Classification as: Oil Gas .. Suspended __ Name of Approver Date Approved Service 17. I hereby certify that the fore~qoing is true and correct to the best of my knowledge: Signed ~_~~~ D.C. Gill Title Drli~. & Prod. Eni~r. Mana~)er Date FOR COMMISSION USE ONLY Conditions of Approval: Notify Commission so Representative may witness I Approval_No. Plug Integrity BOP Test Location Cle, a~.ance m Cj, Mechanical Integ'iity Test Subsequent Form Required 10 - Approved by Order of the Commission Form 10-403 Rev. 06/15/88 Original Signea By W_-. Commissioner Date ~/"~'~/· '( SUBMIT IN t"P, IPLICATE Approved Copy Returned NCIU A--6 RISER AND BOP ARRANGEMENT 6M ANNULAR PREVENTER 10M VARIABLE BORE PIPE RAMS 1OM BLIND RAMS DRILLING SPOOL 1/2' 1OM PIPE RAMS RISER 13 6/8' 1OM X 13 6/8' 6M ADAPTER 13 6/8' 6M X 16 3/4' 6M CLAMP RISER 16 3/4' 6M X 16 3/4" 6M UNIHEAD 16' 8RD X 16 3/4" 6M CLAMP HUB RECEIVED /~UG 1 5 1994 Alaska 0il& Gas Cons. Commission Anchorage SECTION WELL CONTROL PROCEDURES This well is a category 3 well, as defined in Phillips Completion Workover and Well Control Policy. As such two barriers must be in place during nipple up and nipple down operations. For all other operations, two barriers, e.g. the BOP's, fluid column, etc. must be in place in order to conduct simultaneous operations. The BOP equipment is 10000 psi WP Class 4 as per Phillips Well Control manual. The bottom set of rams should be 5" pipe rams,.the middle set will be blind rams and the top set should be variable rams. Although the BOP is rated to 10000 psi, the riser and the wellhead are rated to 5000 psi. The BOP and choke manifold should be stump tested to 3000 psi. The BOP should be tested to 3000 psi upon nipple up and to 1500 psi on a weekly basis. The Alaska Oil and Gas Conservation Commission (AOGCC) should be notified prior to conducting BOP tests. The notification to AOGCC should be made early enough for them to witness the test if they desire. The maximum surface pressure for the well is 1049 psi. This pressure was obtained during the welltest of August 05, 1994. The well can be killed and stability maintained with 8.5 lb/gal fluid. Well control drills are to be conducted with each crew as per Phillips well control manual. Drills should be reported on the IADC daily drilling report and on Phillips Daily Drilling Report. This well produces from a series of very permeable sands. A small decrease in pressure at the perforations can result in very large flowrates. It is vital that good well control practices be followed during the course of this workover. Trip speed while POOH should be kept relatively slow to avoid any tendency to swab. Before any trip is made swab and surge calculations should be made based on the properties of the fluid in the hole. DO NOT exceed the running speed determined by the calculations. A detailed trip book comparing measured fill up requirements to the calculated requirements should be maintained for each trip. The cause for any discrepency between the actual and required fill up volume must be determined before continuing with the trip. MAINTAINING CONTROL OF THE WELL IS OF THE UPMOST IMPORT~NCE, TRIP SPEED IS SECOND/~RY. Four perforated intervals are isolated between the Otis "RH" retrievable and the "WD" permanent packer, and there are 40 different intervals below the "WD" that are effectively commingled at the present time and cannot be isolated. Ail of the zones presently perforated in this well can be killed with water. As a precautionary measure, a line should be ran from the annulus valves on the tubing head to supply workover fluid, drillwater, or seawater. This line can be used to supply workover fluid as discussed above or as a last resort can be used to kill the well with drillwater or seawater. Pumping drillwater or seawater through the annulus valves should be considered only in an emergency situation as these fluids could result in formation damage. AUG 1 5 ~994 Alaska 0~{ & Gas Cons. Commiss}on Anchorage August 9, 1994 Houston, Texas North Cook Inlet Unit "A"-6 North Cook Inlet Unit Tyonek County, Alaska Tentative Procedure ® Skid rig over Well No. 6 slot in Leg 3. Kill well with 8.5 lb/gal KCl water / XanVis polymer. Fill tubing and annulus with 2 % kcl water. Bleed off pressures and monitor same. Close SSSV. · Install BPV, remove XMAS tree, NU and test 13 5/8" 10M BOP equipment. Utilize a 16 3/4" 5M x 13 5/8" 10M DSA (FMC Unihead with 16 3/4" 5M BX Clamp Hub). Test the BOP equipment as per the attached "Well Control" program. · · Rig up to pull tubing. Release Otis "RH" packer (3,983'). Pull 4" tubing, SSSV and retrievable packer with tailpipe and seal assembly from the "WB" packer at 4,310'. Circulate out any gas from below the packer. Inspect all tubulars for "NORM.____" contamination. TIH with packer milling assembly. Mill over packer slips and recover Otis "WB" permanent packer. POOH. ® TIH with 6 1/8" bit and casing scraper for 7 "23 and 26 lb/ft casing. Clean out casing to a minimum of 7,200' (PBTD is 7,977'). Circulate hole clean and POOH. 6. TIH with EZSV drillable bridge plug. Set BP at 4,200'. · TIH with open ended drill pipe and spot 150 sx cement from 4,200 - 3,500'. Pull drill string above cement and squeeze Cook Inlet Stray, "A" and "B" perfs (4,021 - 4,162'). POOH with drill string. WOC 8 hours minimum. · TIH with bit and drill out cement. Test each perforated interval to 2000 psi. Resqueeze as necessary. When squeeze is obtained, TIH to 7200' and circulate hole clean. POOH. · Make up and TIH with tubing conveyed perforating assembly to reperforate the existing and new Beluga Sands as follows: 5220' - 5235' ** 5302' - 5308' 5327' - 5332' 5393' - 5413' ** 5444' - 5448' 5540' - 5545' 5665' - 5680' 5731' - 5736' ** 5793' - 5797' 5810' - 5820' 5842' - 5847' 5884' - 5889' 5895' - 5915' 5980' - 5990' 6084' - 6094' 6123' - 6133' 6136' - 6141' 6182' - 6197' 6236' - 6261' 6420' - 6425' 6520' - 6525' 6536' - 6551' 6587' - 6592' 6684' - 6689' 6734' - 6739' 6828' - 6843' 6995' - 7010' New perforations REC[IYF. D AUG ] 5 1994 Ataska Oil & Gas Cons. Commission Anchorage 10. Use Gamma Ray log to correlate guns on depth. Set packer and pressure up on tubing with nitrogen to fire guns. 11. Unload well and flow for initial clean-up. 12. Kill well and POOH with perforating assembly. 13. Make up and TIH with tubing conveyed perforating assembly to reperforate the existing Cook Inlet Sands as follows: 4325' - 4380' 4388' - 4398' 4420' - 4490' 4509' - 4519' 4540' - 4550' 4564' - 4614' (CI-1) 4733' - 4753' (CI-6) (CI-1) 4792' - 4822' (CI-7) (CI-2) 4832' - 4852' (CI-7) (CI-3) 4880' - 4890' (CI-8) (CI-3) 4912' - 4927' (CI-8) (CI-4) 4963' - 4983' (CI-9) 5004' - 5014' (CI-10) 5031' - 5076' (CI-11) 14. Use Gamma Ray log to correlate guns on depth. Set packer and pressure up on tubing with nitrogen to fire guns. RECEIVED 15. Unload well and flow for initial clean-up. AUG ]5 ]994 16. Kill well and POOH with perforating assembly. AiaskaOil&GasCons. Com~ssion 17. TIH with bit and scraper and clean out well to PBTD. Cirq~~ ou~ gas until well is stable. 18. If significant volumes of water and/or sand is produced during Step No. 8, TIH with DST tools and isolate intervals to check for water production. 19. If significant volumes of water and/or sand is produced during Step No. 12, TIH with DST tools and isolate interVals to check for water production. 20. TIH with permanent packer assemblies as outlined on the "Proposed Well Completion Diagram" Set packer isolation assemblies at 5,175' · f 4,865', 4,772', 4,720, 4,640', and 4,250'. Set Halliburton 7" retrievable "VSR" packer at 3,940'. 21. Make up Halliburton packer seal assembly onto the 4 1/2" tubing. TIH with 4 1/2" tubing and SCSSV landing nipple. Land seal assembly into isolation packer. Test annulus, then pull out of seal assembly and circulate 70/30 methanol / KCl packer fluid into annulus. Space out tubing. 22. Close SCSSV, install BPV, ND BOP equipment and NU and test 7 1/16" x 4 1/2" Xmas Tree. Remove BPV's. 23. Use coiled tubing (if necessary) and nitrogen to lower fluid level and get well kicked off. Unload well and allow clean up through the production testing equipment. Release workover rig to next well. NOTE: BHP at 3880 TVD is approx 1400 psi (7.0 lb/gal equivalent), somewhat less than the 8.5 lb/gal equivalent which will be used to kill the well during the recompletion phase. 623 TOC ~ 25OO' 10 3/4' @ 2579 , I~ROPOSED WELL COMPLETI~DIAGRAM Ma .'FC'T~,OD) FMC OCT ' : FMC 4 1/2' 8rd X 4,1/2' BT&C Aanalua Fluid: Salt Water witk 3 bbl Mcthaaol RKB-Drill Deck: RKB-THI; 40.25 RKB-SL: 115.90 TOC: 2500' from CBL dated 05/27/69 WATER DEPTH: 120 RKB-ML: Production Casing: 41 623 41 45.5 & 51 39 79 26 lb/ft 79 Tubin 23 lb/fl H-40 600 J-55 BT&C 1970 J-55 J-55 J-55 BT&C BT&C BT&C 408O 39 315 315 12.75 lb/ft J-55 mod BT&C 4730 4980 J-55 mod 8rd 4730 4980 PRODUCTION TUBING STRING PBTD 7977' · VSH' packer @ 5940' 4021 - 4031 4055 -- 4080 4102 -- 4107 4112-4162 Packer @ 4250 4325 - 438O C1-1 4388-4398 4420 - 4490 CI-2 4509 - 4519 CI-3 4540 - 4550 4564 - 4614 CI-4 Packer @ 4640 4660 - 4700 CI-5 4711 - 4716 Packer ~ 4720 4733 - 4753 CI-6 Packer @ 4772 4792 - 4822 Cl-7 4832 - 4852 Packer @ 4865 4880 - 4890 CI-8 4912 - 4927 4963 - 4983 CI-9 5OO4 - 5014 C1-10 5031 - 5076 C1-11 Packer @ 5175 Beluga 5220 - 5235 **5302-5308 5327 - 5332 5393 - 5413 ** 5444-5448 5540 - 5545 5665 - 5680 5731 - 5736 ** 5793 - 5797 5810 - 5520 5842 - 5847 5895 - 5915 5980 - 5990 6123 - 6133 6136 - 6141 6182 - 6197 6236 - 6261 6520 - 6525 6536 - 6551 6587 - 6592 6684 - 6689 6734 - 6739 6828 - 6843 6995 - 7010 7" ~) 8016 -0.00 40.25 Elevation 40.25 41.25 238.95 280.20 4.51 314.71 319.71 3908.50 3910.00 3940.00 3947.00 4247.00 3588.79 1.50 3.00 FMC / OCT 8' 3M 4 1/2' 8rd x 4 1/2' BT&C Tubing Hanger 4 1/2" 12.6 lb/ft J-55 mod BT&C Tubing H'burton 4 1/2" WLRSV Safety Valve Nipple; SCSSV 4 1/2" 12.6 ib/ft J-55 mod BT&C Tubing 4 1/2" BT&C x 4 1/2" EUE X-Over 4 1/2" 12.6 lb/ft J-55 mod EUE Tubing Halliburton 4 1/2" "X~ Nipple 4 1/2" 12.6 lb/ft J-55 mod EUE Tubing H'burton 7" x 3" "VSH" Hydraulic Set Retr. Packer 4 1/2" 12.6 lb/ft J-55 mod EUE Tubing Halliburton "No-Go" Seal Unit 3.958 3.958 3.958= 2.991 3.958 3.813 3.958 3.958 4250.00 10.00 4260.00 363.00 4623.00 4.00 4627.00 4637.00 10.00 H'burton "AWR" Permanent Packer & Tbg. Adapter 4 1/2" 12.6 lb/ft J-55 mod EUE Tubing Halliburton 4 1/2" "XD" Sliding Sleeve 4 1/2" 12.6 lb/ft J-55 mod EUE Tubing Halliburton "No-Go" Seal Unit 4.000 3.958 3.813 3.958 3.900 4640.001 10.00 4650.001 67.00 4717.001 3.00 JH'burton "AWR" Permanent Packer & Tbg. Adapter 4 1/2" 12.6 lb/ft J-55 mod EUE Tubing Halliburton "No-Go" Seal Unit 4.000 3.958 4720.00 4730.00 4755.00 4759,00 4769.00i 10.00 25.oo 3.oo H'burton "AWR" Permanent Packer & Tbg. Adapter 4 1/2" 12.6 lb/fl J-55 mod EUE Tubing Hall!.b~rton 4 1/2" "XD" Sliding Sleeve 4 1/2 12.6 lb/ft J-5.5. mod EUE Tubing Halliburton "No-Go Seal Unit 3.958 3.813! 3.958 3.900 4772.001 10.0o 4782.00 80.00 4862.00 3,00 H'burton "AWR" Permanent Packer & Tbg. Adapter I 4 1/2" 12.6 ib.!ft J'5.5. mod EUE Tubing Halliburton No-Go Seal Unit 3.958 4865.00 10.00 4875.00 233.00 5108.00 4.00 5112.00 60.00 5172.00 3.00 H'burton "AWE" Permanent Packer & Tbg. Adapter 4 1/2" 12.6 ib/ft J-55 mod EUE Tubing Halliburton 4 1/2" "XD" Sliding Sleeve 4 1/2" 12.6 lb/ft 3-55 mod EUE Tubing Halliburton "No-Go" Seal Unit 4.000 3.958 3.813 3.958 5175,00 5185:00 6004.00 7010.00 H%urton "A~" Permanent Packer & 10:00 815.00 4.00 4 1/2" 12.6 lb/ft J-55 mod EUE Tubing Halliburton 4 1/2" "XD" Sliding Sleeve 4 1/2" 12.6 lb/ft J-55 mod EUE Tubing Halliburton 4 7012.00 End of Tubing 4.000 3.958 3.813 3.958 3.725 PRODUCTION PERFORATION INTERVALS COOK INLET SANDS I Stray 4021 - 4931 To Upper Cl-'A' 4055 - 4080 Be Squeezed I Upper Cl-'B' 4102 - 4107 I Upper Cl-'B' 4112 - 4162 CI- 1 4325 - 4380 4388-4398 CI-2 4426 - 4490 CI-3 4509 - 4519 4540 - 4550 CI-4 4564 - 4614 CI-5 466O - 47O0 4711 - 4716 CI-6 4733 - 4753 CI-7 4792 - 4822 4832 - 4852 CI-8 4880 - 4890 4912 - 4927 CI-9 4963 - 4983 C1-10 5004 - 5014 C1-11 5031 - 5076 ** New Perfs BELUGA SANDS 'Upped 'Middle' RECEIVED AUG 1 5 1994 5220 - 5235 5302-5308 5327 - 5332 5,393 - 5413 5444-5448 5540 - 5545 5665-5680 5731 - 5735 5793 - 5797 5810 - 5820 5842 - 5847 5884 - 5889 5895 - 5915 5980 - 5990 6123 - 6133 6136 - 6141 8182 - 6197 6238 - 6261 5420 - 8425 6520 - 6525 Naska Oil & Gas Cons. Commissiom~ - 6551 ._... ~Anchorane 6557 - 6892 6734 - 8739 'Lowm' 8828 - 8843 6995 - 7010 Well: 977' I Supv= I Tbg We North Cool[ Inlet Unit No. A-06 4 1/2" - 12.6 & 12.75 lb/ft Au TD 045' Location: Lower Alaska Field: .382 623 TOC @ 2500' 10 3/4' @ 2571 *** EXISTING WELL COMPLETION*~AGRAM (Make,T~pe,OD) FMC OCT FMC 4 1/2' 8rd X 4" BT&C Rl~-Drill Deck: 40.2.$ Annulus Fluid: Salt Water with 3 bbl Methanol RKB-SL: 115.90 TOC: 2500' from CBL dated 05/27/69 WATER DEPTH: 120 RKB-ML: Production Casing: 41 382 41 623 H-40 41 39 79 79 Tubin 39 1540 45.5 & 51 J-55 BT&C 3350 1970 26 lb/ft J-55 BT&C 4660 4080 23 lb/ft J-55 BT&C 4080 3080 26 lb/ft J-55 BT&C 4660 4080 10.9 ib/ft I J-55 BT&C 5150 5730 9.3 lb/ft I J-55 BT&C 5700 6440 PRODUCTION TUBING STRING Beluga Sands PBTD 7977' TD Otis RH packer Sands 4021 - 4031 4055 - 4080 4102 -- 4107 4112 - 4162 Otis WB packer @ 4310' 4325 - 4380 CI- 1 4388 - 4398 4420 - 4490 CI-2 45O9 - 4519 CI-3 4540 - 4550 4564 - 4514 Cl-4 4660 - 470O CI-5 4711 - 4716 4733 - 4753 Cl-6 4792 - 4822 CI-7 4832 - 4852 4880 - 4890 CI-8 4912 - 4927 4963 - 4983 CI-9 50O4 - 5014 C1-10 5031 - 5076 Cl- 11 5220 - 5235 5327 - 5332 5393 - 5413 5865 - 5680 5731 - 5736 5810 - 5820 5842 - 5847 5895 - 5915 5980 - 5990 6084 - 6094 6123 - 6133 6136 - 6141 6182 - 6197 6236 - 6261 6420 - 6425 6520 - 6525 6536 - 6551 6587 - 6592 6734 - 6739 6828 - 6843 6995 - 7010 7 Ii @ ~Y~k 40.25 41.25 280.20 284.71 317.71 322.71 3975.63 3976.00 3982.95 3989.95 4270.60 40.25 Elevation FMC / OCT 6' 3M 4 1/2' 8rd x 4' BT&C Tubing Hanger 238,95 4" 10.9 lb/ft J-55 BT&C Tubing 4.51 Otis 3 1/2" AO Ball Valve Nipple and SCSSV 33.00 4" 10.9 lb/ft J-55 BT&C Tubing 5.00 CAMCO 3 1/2" GLM 3652.92 4" 10.9 lb/ft J-55 BT&C Tubing 4273,60 32.81 4306.41 3.72 4310.13 4320.54 0.37 4" BT&C x 3 1/2" X-OVER 6.95 Camco KBM 3 1/2" GLM 7.00 Otis 7~ x 3" "RH" Hydraulic Set Retrievable Packer 280.65 9.3 lb/ft J-55 BT&C Tubing 3.00 Otis 3 1/2" "XO" Sliding Sleeve 3 1/2 9.3 lb/ft J-55 BT&C Tubin 3 1/2" "X" 10.41 Otis 7" x 4" "WB" Permanent Packer 15.00 4335.54 1.50 4337.04 10.68 4347.72 J-55 BT&C Tubing 1/2" 9.3 lb/ft J-55 BT&C Tubing 1.27 Otis 3 1/2" "Q" Nipple End of Tubing 3.958 3.476 2.760 3.476 2.991 3.476 2.992 2.991 2.992 2.750 2.992 2.750 4,00 2.992 2.750 2.992 2.625 NOTES: 1.65" ID Otis Model "G" Packoff Assembly Installed at 4,130 - 48' 10/20-21/88. 1.432" ID Otis "N" Nipple, and Otis 3 1/2" T-Lock Mandrel set in "Q" nip )le 10/21/88. PRODUCTION PERFORATION INTERVALS COOK INLET SANDS Stray 4021 - 4031 Upper CI-'A' 4055 - 4080 UpperCI-'B' 4102 - 4107 UpperCl-'B' 4112 - 4162 CI- 1 4325 - 4380 4388 - 4398 CI-2 4420 - 4490 CI-3 4509 - 4519 4540 - 4550 CI-4 4564 - 4814 CI-5 4660 - 4700 4711 - 4716 C1-6 4733 - 4753 CI-7 4792 - 4822 4832 - 4852 Cl-8 4880 - 4890 4912 - 4827 CI-9 4963 - 4983 C1-10 5004 - 5014 CI- 11 5~31 - 5076 BELUGA SANDS · Upper' 5220 - 5235 5327 - 5332 5393 - 54i3 5540 - 5545 5685 - 5680 5731 - 5738 'Middle' 5810 - 5920 5842 - 5847 5895 - 5915 5980 - 5990 6123 - 6133 6138 - 6141 6162 - 8197 6230 - 8281 8420 - 8425 6520 - 6525 6538 - 6551 6587 - 6592 8884 - 6889 6734 - 8739 'Lower' 6828 - 6843 6995 - 7010 Well: I supv: I TbS Wt: 4" - 10.9 lb/ft North Cook Inlet Unit No. A-06 I 3 1/2" - 9.3 lb/ft Au Location: Lower Cook Field: Cook Inlet Unit kUG 1 5 1994 Alaska Oit & Gms Cons. Commismion Anchorage PRD UEPAR~NT OF NATURAL RES0URCES .Divisic~ of Oil and Gas fkmser~at/~ J~%e 1, 1978 ~tness subsurfa~ safety val~ (SSS~ ar~ surface safety val~as (SS%9 plus ~.~gh and Iow pilots, Phillips P latfonm ~,...May 19, 1978 - I left Anchorage to Kenai at 8:00 AM by AAI, arrivin~ in ~Hmai at 8:30 AM.~ I wa/Red to F~a~_ air service where I was to get a vales tb~t failed last test cn 4/20/78. I arri~ c~ the platform at 12:10 PM. I m~t Bob Gamble, the supervisor for Phillips platfcxm. Below are the results of the tests: W~ll No. F]x~ PSI Test PSI 1400 900 - 1375 875 A-1 ~.. 1500 1000 A-5 1400 900 PL~t ~ ~.- I rewi~ t~m ~:. /nd/cared safety valves plus high ~a~ests were satisfacto~. Attachment A1 .a Oil and Gas Conservation Commi.. Field Inspection Report Drlg. Permit No._ ....... Wel 1/Platfm Sec T R___,_ _M Operator_/O_~?///~/?o_~_ .p~_~.~Fo~lRepresented by~_~/~&9/~_-~ Name & Number.~/j!~_!!~_]~____ Satisfactory Type Inspection Yes No Item ( ) Location,General () () () () () () () () ~) () () () () () () () () () () () 1. Well Sign 2. General Housekeeping t. Reserve Pit-( )open( )filled 4. Rig, (~ Safety Valve Tests 5. Surface-No. Wells ~ 6 Subsurface-No. Wel - ( ) Well Test Data 7. Well Nos. , , , 8. Hrs. obser , , , 9. BS&W , , , 10. Gr. Bbls. ( ) Final Abandonment ll. P&A Marker Satisfactory Type Inspection Yes No Item ( ) BOPE Tests () () () () () () () () () () () () () (,) () () () () () () () () () () () () () () 15 16 17 18 19 20 21 22 23 "Casinq set 0 TesL fluid-( )wtF.---~ )mud ( ) oil Master Hyd. Control Sys.- psig N2 btls. , __,__ , psig Remote Controls Drillin9 spool-~"outlets Kill Line-( ) Check valve Choke Flowline ( ) HCR valve Choke Manifold No. valvs flms 24. Chokes-( )Remote( )Pos.(-~dj. 25. Test Plum-( )Wellhd( )csq( )none 26. Annular Preventer,___~psi.Q 27. Blind Rams, psim 28. Pipe Rams ~psiq ( ) ( ) lZ. Water well-( )capped( )plugged ( ) ( ) 29. Kelly & Kelly-cock ~psig ( ) ( ) ' 13. Clean-up ( ) ( ) 30. Lower Kelly valve psin ( ) ( ) 14. Pad leveled ( ) ( ) 31. Safety Floor valves--Z~-'--)-BV ( )Dart Total inspection observation time hrs/days Total number leaks and/or equip, failures Remarks ~t~7'~=,~y ~S~ l//~z.M~_:-~-~/~ ~z~,~l ~~ . t ~ - Form 10-403 REV. 1-10-3'3 Submit "1 ntentlons" 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.) 5. APl NUMERICAL CODE 50-283~P_Qo26 6. LEASE DESIGNATION AND SERIAL NO. ADL-37831 7. IF INDIAN, ALLOTTEE OR TRIBE NAME ~' O,L [--I GAs [~ WELLI I WELL OTHER 2. NAME OF OPERATOR Phillips Petroleum Company' 3. ADDRESS OF OPERATOR P.O. Drawer 66 / Kenai., Al~ 99611 4. LOCATION OF WELL Atsurface Leg 3, Slot 3, 12591 FNL, 1083t FkrL, Sec. 6~ TllN, R9W, S.M. BHL 680' FSL~ 741' FEL~ Sec. 1, TllN, R10W~ S.M. 13. ELEVATIONS (Show whether DF, RT, GR, etc.) 14. CheCk Appropriate Box To Indicate Nature of Notice, Re 8. UNIT, FARM OR LEASE NAME 10. FIELD AND POOL, OR WILDCAT Norbk Cook Inlet 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) See.' Item 4 BHL 12. PERMIT NO. 69-50. )ort, or Other Data NOTICE OF INTENTION TO: TEST WATER SHUT-OFF ~ I FRACTURE TREAT ~ SHOOT OR ACIDIZE ~ REPAIR WELL L.~ (Other) CleanouL PULL OR ALTER CASING MULTIPLE COMPLETE ABANDON* CHANGE PLANS SUBSEG~UENT 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 pertinent details, and give pertinent dates, including estimated date of starting any proposed work. 1. Rig up. Kill well with. 10.0 ppg mud. Remove tree. Ins:tall 12"-3000# WP riser and 12" 3000# WP double gate preventor and Hydril. Test BOP and riser. 2. Pull 4" tbg and retrievable packer. 3. Clean out to 7977 ~TD. 4. Run combination 4 "x 3 1/2" tubing string ~ith. Otis subsurface safety valve set about 280' RKB and Otis retrievable packer set about 3980 MD RKB, and tubing set 7016 MD RKB. Test packo ff. 5. Install tree and displace mud with. water. Set hydraulic packer. 6. Clean up well and conduct 4 point BPT. 7. Utilize as a producer commingled in Cook Inlet and Beluga pays.. Estimated start of Operations is 9/2/75. TITLE Senior Petroleum EnKineer., DATE r 11. m. yorver 7/15/75 (This space for State office usa) APPROVED BY CONDITIONS OF APPROVAL, IF ANY.- T IT LE DATE See Instructions On Reverse Side PHILLIPS PETROLEUM ANCHORAGE, ALASKA 99501 515 'D" STREET, ROOM 204 EXPLORATION AND PRODUCTION DEPARTMENT COMPANY September 19, 1969 Mr. Harry Kugler Depa~ent of Natural Resources Oil and Gas Division 3001 Porcupine Drive Anchorage, Alaska Dear Mr. K~ler: Enclosed, for your records, is one copy of the following: Enclosures Sub-Surface Directional Survey - NCI Unit #A-5 Sub-Surface Directional Survey -NCI Unit #A-6. Very truly y~urs, L. L. Vigoren DIVISION Of OIL AND ~ / , F~orm P--7 SUBMIT IN DUPLICATE* STATE OF ALASKA :~See other In- structions on OIL AND GAS GONSERvATION,)~coMMITTEE~ -- reverse .... ~ELL_CQ~PLETION.OR_RECOMPLEIION RE~0RT AND LOG * la. TYPg O~ W~LL: om ~ WELL W~LL ~ DaY ~ Othg~ b. TYPE OF COMPLE~ON: nac~ -- nEava. Other WELL OVER ~N . ~. NAM~ OF OP[RATOR " ' ~. ADDRESS OF' OPERATOR ~,' 515 D Street, Anchorage, Alaska 99~01 4. LOCATION Or WELL (Report location clearly and in accordancg with any S,.tffte requirements) at..,ace L~g 3, Slot 3, 1259' FNL, 1083.' FWL,~ S~c. 6, TllN': i S.M., North Cook Inlet, Platform "Tyo~ek'% ' 5. AP1 ~CAL CODE API 50-283-20026 8. I_~..a. SE D~IGi~'[ON AND SERIAL NO./~ ADL 37831 7. IF IITDIAH, AhI~-l-r~-'~: OR TPdBE NAME 8. UNIT.Fa OR LEASE NAM2E North Cook Inlet Un&.t 9. VgELL NO. #A-6 '~ . .. 10. FIELD A~ID'POOLi OR WILDCAT North Cook Inlet 11. SEC;, T.0 R., M.T (~'TOM I-IOLE O~VE) i At top prod. interval reported below , 12600' FNL, &00' F~, Sec. 6, TllN; R~I~, al. Mo: ::': ; At total depth .... Sec, 1, T3_IN, R10W, .S.H. i,..8~5.~.. ~,~..,. ~ 6891.86 !~ .~.. 18i T~ D~H, ~ & TVD~9. ~LUG ~CK MD & ~. ~ ~L~ ~L,. ,,: [ 21. " , ' INTERVALS'DRI~ED BY .', ,,' ~5t ~ '/ ~ 7977' ~ I ~w~v* '~ ! ~O~A'~ ~00~ ' , " ,"1:::.' ~:,~ ~oo~s ~., PRODdiNG ~V~(S), OF ~ ~M~TIO~. U r ~ et Sd. ' ~t.~ 24.~E~CTRIC~DOT~G~:~UN ~el~a b828' tTVD ~ CASING RECORD (Report all strings set in w$11) CASLNG SIZE WEIGI-I~ DEPTH SET (iVED) 16" 0D Sx 7" OD LINER ;'~ SIZE TOP (MDI ~BOTTOM (MD) SACI(S CEMENT* (Interval, size and number) 29. SCREEN 27. SIZE AC..~:, SHOT; F?~'URE; CEM~N~ (Mil3) .. AlViOUNT ', D,a. TE FIRST PI~©DUCTION [ ~PI~O~CTION METIfOD (Flowing,, gas lift, ~mraping--$ize a~l~ type o~,p~P) : [II/'E~.L STATUS (..,,l~rod~cing or: .. ! , O · DISPOSITIONi~OF OAS (SOld, .8ed to~t. eg, vented, ete. i' ~2 t ~:' ,: ' , ~ ]TEST WITNE~S~'D BY t ~ s2. ~iST o; ATTA'~,ENT-' 1...;i Chronological Well History,* 2:. Sample Description.. 3. Sidewall Core Descrip~ns. !1~.": Perfo~atinM and Squeeze R~co~, , } 3~. I hereby ce~iify ~hat the forego ,~g and ~ac~hed information is complete and correct as determined from all:available records ' / // : *(See Instructions-- and Spaces for Additional Data on Reverse Side) INSTRUCTIONS :.' General: This fo'r-'~'is designed fo'~ submitting'a cc~mplete and correct well completion report and log o~n] ": .. all types of. lands '~nd leases in Alaska. ! ,. J . . ~ltem: 16: Indicate which elevation is used as refe~:ence (wh~re not otherwise showBi for dep. ih measure- ,' . ments given in ether spaces~'on this form and in any attachments. ,- . . Items 20, a~d.;~l:: ff this well is cOmpleted for. separate production from more thar~ one interval zone, ~. (multiple compJetion), so state in 'jte.m 20, nhd'-in item 22 show th~' prc.ziucing i~ferval, or' interval~i :i..':~' 'top(s)', bottom(s) and name (s) (if any) forigqly.-.the interval repo"ted in item 30. Submit a separate report ., . (page). on this form, adequately-:idehtified,' for ~ach addi~t~onai inte, vai to be-S~pe'rately predicted -- ;. lng the additional data pertine'pt to sUch. interval.- "Z..:.... .'.u _ "'- -Ifem26: "Sacks Cement": Attached supplement.al records fc;r_t, hi'~,.'weH should sho'wthe details of'any mUl- ? ... tiple stage cementing and the location of the Cementing 'tool: . - Item 28:.Submit a separate completion report on this form for each interval to be separately produced. · ~' " "(See instruction for items 20 and 22 above).; -.. .~. . ~ · :. .- · -'-_ ~ . . /~ ... ~ -- · _. . ' 34. SUMMA.~Y O~ i?OH. MATION TE~TS INCLUDING INT~VA~ ~D, P~UR~ DA~A ~ ~O~ OF OIL. ' ' - · 35. G~IC M&RK~ -' ' ':' WA~ AND MUD ~ , . .. ~_. : , ... .... .- ....t:: :... -. ':' - ' I _. :.. .,. , -' ~AS. D~ ~ V~T. D~ ,... . . - ..,.._. .. .... ..Coo"- .... See attached chrono'to~'c~ we~ ~st . :- ...... , ' ..:: _ ........ . , :, u~er k ~et 4059 3 ,'..: .~ - . .. (' : z., ~ ..w ..~ , -,.-- . _.."::,,_~ . .. :.c s . 4320 , . . -. '-' ': ~-...' · . :'. .' . ... :; -. . . '"..-:.7,7. ~ '/" .:q · ,.. .. ~ - '~ , ~; ~ ..... ,,. ,~ ':.. ~ ... ,,. . - ~ ., . /~._ ..~ :-~.,-.. . . . . .... - - ~ ~ -~ . . 38. CORE DATA, A~ACI[ BRIEF .D~CRIP~O~S. OF LITHOLOGY, .POROSITY, FHA~;' APP~ DIPS '' . ., -AND.D~FEC~D"SIIOW$- OF OIL, G~ OR WA~. ' _ · -- - ii . . .: ,-, , . . ; . , · . . · .-.~ ] , . .' . - ..... ~ ~ . , ; ,. : . ,' _ . , -. ...-~ _ _ ;... .. ,, . . .. ;. :,.- ~ , .. - . _~ .--. . . .-. . ~ ~ . , · ";"_ a ip¢i .... " "" '" - '" ' '.'~;.. · See a~gaehe~ ~ e de~ r on. :.. _, . ~--~ ,-, --~ · ,~ ; . .:~ , -. .:_. ~ _~ ~:: ..... .. .: ~ .... . _ . . , · .. , · : ..... , .- · SI'MBOL OF SERVICE REPORT of SUB-SURFACE DIRECTIONAL SURVEY PHILLIPS PETROLEUM PLATFORM COMPANY "A" A - 6 WELL NAME NOR T H COOK INLET LOCATION JOB NUMBER AM 5- 1~69 TYPE OF SURVEY S INGLE SHOT SURVEY BY ANCHORAGE DATE MAY 1969 OR=ICE .-.~1 I~. UTt40 BY EASTCO IN U. S. A. H E L L C 0 H P L E T I 0 ,",1 R E P O R T PAGE PHILLIPS PETROLEUM CO A-6 PREPARED BY SCS FOR EASTMAN 05/27/69 TANGENTIAL ~ETHOD MEASURED COURSE - - O E V [ A T ! 0 N .... C 0 U R S E - - - DEPTH LENGTH ANGLE DIRECTION AMOUNT V.DEPTH LATITUDE DEPARTURE T 0 T A L V.DEPTH LATITUDE DEPARTURE ORIGIN LOCATED AT MD = 783.00, TVD = 843. 60. 2 45' S 10 E 2.87 59.93 2.83 S 874° 31, 4 O' S I5 W 2.16 30.92 2.08 S 906. 32, 5 45' S 22 W 3.20 31.83 2.97 S 984. 78, 8 15' S 25 W 11.19 77.19 L0.14 S /047. 63. g O' S 27 W 9.85 62.22 8.78 S 1143, 96. 11 45' S 27 W 19.54 93.98 17.41S 1238o 95. 14 30' S 27 W 23.78 91.97 21.19 S 1332. 94. 15 30' S 27 W 25.12 90.58 22.38 S 1426. 94. 18 30' S 26 W 29.82 89.14 26.80 S 1519. 93. 21 30' S 26 W 34.08 86.52 30.63 S 1611. 92. 22 15' S 25 W 34.83 85.14 31.57 S 1704. 93. 24 O' S 26 W 37.82 84.95 33.99 S 1797. 93, 25 45' S 24 W 40.40 83.76 36.91 S 1889. 92. 28 45' S 25 W 44.25 80.65 40.10 S 1982. 93. 31 45' S 25 W 48.93 79.08 44.35 S 2073. 91. 34 45, S 24 W 51.86 74.76 47.38 S 2153. 80. 35 15' S 26 W 46.17 65.33 41.49 S 2248, 95. 35 15' S 25 W 54.82 77.58 49.69 S 2374. 126. 35 15' S 25 W 72.72 102.89 65.90 S 2498, 124. 35 45' S 25 W 72.44 100.63 65.65 S 2610, 112, 36 30' S 26 W 66.62 90.03 59.87 S 2675. 65. 37 15' S 25 W 39.34 51.74 35.65 S 2738. 63. 36 45' S 25 W 37.69 50.47 34.16 S 2831. 93. 35 45' S 25 W 54.33 ?5.47 49.24 S 2956, 125, 35 45' S 25 W 73.08 101.%4 66.18 S 3144. 188. 35 45' S 25 W 109.83 152.57 99.54 S 3360, 216. 35 45' S 24 W 126,19 175.29 115.28 S 3612. 252. 36 15' S 22 W 149.01 203.22 138.15 S 3858. 246. 36 15' S 27 W 145.46 198.38 129.60 S 4042, 184, 37 O' $ 23 W 110.73 146.94 101.93 S 4168, ~26, 37 O' S 22 W 75.82 100.62 70.30-5 782.96, LATITUDE = -8.43, DEPARTURE = 0.49 E 842.89 0.55 W 873.81 1.20 W 905.65 4.73 W 982.84 4.47 W 1045.07 8.87 W 1139.05 10.79 W 1231.03 11.40 W 1321.61 13.07 W 1410.75 14.94 W 1407.28 14.72 W 1582.43 16.58 W 1667.39 16.43 W 1751.16 18.70 W 1831.81 20.68 W 1910.90 21.09 W 1985.67 20.24 W 2051.00 23.17 W 2128.58 30.73 W 2231.48 30.61 W 2332.11 29.20 W 2422.I4 16.62 W 2473.88 15.93 W 2524.36 22.96 W 2599.84 30.86 W 2701.29 46.4I W 2853.86 51.32 W 55.82 W 66.03 W 43.26 W 28.40 W -2.66 11.26 S 2.16 W 13.35 S '!2.71 W 16.32 S 3.92 W 26.47 S 8.65 W 35.25 S 13.12 W 52.67 S 22.00 W 73.86 S 32.79 W 96.24 S 44.20 W 123.05 S K 57.2? W 153.68 S 72.22 W 185.26 S 86.94 W 219.25 S I03.52 W 256.I6 S 119.95 W 296.27 S 138.65 W 340.62 S ~ 159.34 W 388.01 S 180.43 W 429.51 S 200.67 W 479.20 S 223.85 W 545.11 S 254.58 W 610.76 S 285.20 W 670.64 S 314.40 W 706.30 S 331.03 W 740.46 S 9..346.96 W 789.71 S 369.92 W 855.90 S 400.79 W 955.44 S 447.21 W 3029.16 1070.73 S 498.54 W 3232.39 1208.89 S~ 554.36 W 34'~0.77 1338.50 S 620.39 W 3577.72 1440.43 S 663.66 W 3678.35 1510.74 S ~ 692.07 W WELL COMPLETION REPORT PAGE Z PHILLIPS PETROLEUM CO A-6 PREPARED BY SCS FOR EASTMAN 05/2?/69 TANGENTIAL METHOD MEASURED COURSE - - D E V I A T I O N - C O U R S E DEPTH LENGTH ANGLE DIRECTION AMOUNT V.DEPTH LATITUDE DEPARTURE T 0 T A L V.DEPTH LATITUDE DEPARTURE 4321. 153. 36 15' S 23 W 90.47 123.38 83.27 S 35.34 W 4487. 166. 35 15' S 23 W 95.80 135.56 88.18 S 37.43 W 4673. 186. 35 O' S 23 W 106,68 152.36 98.20 S 4L.68 W 4891, 218. 35 O' S 24 W 125.03 178.57 114.22 S 50.85 W 5112. 221. 34 45' S 25 W 125.96 181,58 114.16 S 5'3.23 w 5358. 246. 34 45' S 2'~ W 140.21 202.12 124.93 S 63.65 W 5~76, 218, 34 15' S 30 W 122.69 180.19 106.25 $ 61.34 W 5764. 188, 35 O' S 31W 107.83 154.00 92.43 S 55.53 W §980, 216. 35 O' S 31W 123.89 176.93 106.19 S 63.80 W 6197, 217. 35 15' S 34 W 125,24 177.21 103,82 S 70.03 W 6323, 126. 35 15' S 35 W 72.72 102.89 59.56 S 41.71W 6514. 191. 35 15' S 35 W 110.23 155.97 90.29 S 63.22 W 6793, 279. 35 30' S 36 W 162.01 227.13 131.07 S 95.23 W 7010. 217. 34 45' S 37 W 123,68 178.29 98.78 S 74.43 W 7~96. 186. 34 O' S 38 W 104.00 1~.20 81.96 S 64.03 W 7447, 2~1, 33 O' S 37 W 136.70 210.50 109.17 S 82.27 W 7635, 188, 31 O' S 37 W 96.82 161.14 77.32 S 59.27 W 7912, 2?7. 28 30' S 38 W 132.17 243,43 104.15 S 81.37 W 8045, 133. 27 30' S 40 W 61.41 117.97 47.04 S 39.47 W 3801.73 1594.02 S 727.42 3937,30 1682.21 S 764.85 4089,66 1780.41 S~ 806.54 4268.23 1894.64 S 857.39 4449.82 2008.81 S 910.63 4651.94 2133.74 S ~ 974.29 4832,14 2240.00 S 1035.64 4986.14 2332.43 S lOgl.17,W 5163,08 2438.62 S ~ 1154.98 5340.29 2542.45 S 1225,02 5443.19 2602.02 S 1266.73 5509,16 2692.32 S ~ 1329.95 5826.30 2823.39 S 1425.19 6004,60 2922.18 S 1499,62 6158.80 3004.14 S 1563.66 6369.31 3113.31 S ~1645,93 6530,45 31g0.64 S 1704.20 67?3.89 3294.80 S 1785.57 6891.86 3341.84 S K 1825.05 CLOSURE 3807.72 S 28- 38' W F-OR E~AGTM,/~ l ii j~ . _ j - ~ A-6 p~AIREH I i . [ .... L t i I T~O 6~::) 45 '.,, ' Form No. REV. 9-30-6T 1. O~L WELL L--~~ STATE OF ALA~ O}L AND GAS CONSERVATION COMMITTEE SU~MIT IiN DEPLICATE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS ,~,, GWELLA8 [] OTHER 2. NA/VIE OF OPIgt%ATOR 8, UN'IT,FA3LM OR LEASE NAAIE Phillips Petrolem Com~ny No~h Cook Inle% U~% 3. ADDRESS OF OPhiR 9. WE~ 515 "D" Street, Anchorage, A~ska 99501 ~A~ 4. LOCATION OF At Surface: Leg 3, Slot 3, 1259' FNL, 1083' FWL, Sec. 6, TI/N, R9W, S.M., North Cook Inlet, Platform "Tyonek". At Proposed Production Zone: 2600' FNL, 400' FWL, Sec. 6, TI/N, R9W, S.M. 10. FIELD A~ND POOL. OR WILDCAT .. North COOk Inlet 11, SEC., T., R., M.. t BOT'TOM HOLE OB,VECTrVE ) Sec. 1, T!.IN,. RIOW,_.S.M. 12. PER/%IIT brO. 69-50 i. 13. REPORT TOTAL DEP/%I AT F2qD OF MONTH, CHANGES IN HOLE SI/E, CASING AND CEMENTING JOBS INCLUDING DEPTH SET A1NM~ VOLUA/IES USED, PERi'ORATIONS, TESTS AATD RESULTS, FISHING JOBS. JU1VK ~ HOLE AND SIDE-Tlq~CKED HOLE A/VD A2qY OTHER SIGNIFICANT CI-IAN~ES IN HOI~ C~NDITIONS. 6-13-69 6-1-69 6-2/9-69 Completed as gas well in commingled Cook Inlet and Beluga Sands. Released rig @ 2:30 P.M. Wait on Otis wireline. 6-10/ll-69 Flow well to clean up. 6-12/13-69 Ran 4-pt test as follows: #1 - Flowed ½ hr on 7/16"-choke, FTP 1894 PSIG, Temp 66©, FARO 10.35~ MMCFD; #2 - Flowed ½ hr on ½" choke, FTP 1860 PSIG, Temp 65o©, FARO 13.~99 MMCFD; #3 Flowed 1 hr on 5/8" choke, FTP 1757 PSIG, Temp 6&o, FARO 20.295 MMCFD; #& - Flowed 1 hr on 3/&" choke, FTP 1630 PSIG, Temp 6& , FARO 27.260 MMCFD. 26 hr SIP 1939 PSIG. CAOF 52 MMCFD. JUL .1969 DIVISION OF OIL AND GAS ANCHORAG~ / OTE--Report on this form is required for each calendar month, regardless of the status of operations, and must De filed in duplicat~ the Division of Mines & Minerals by the 15th o¢ the succeeding month, unless otherwise directed. ~' ,__~.~---- ' ~ ATTACHMENT #1 \. CHRONOLOGICAL WELL HISTORY ~;--26/29-69 ~-3o-69 Spud 15" hole 9:00 P.M., 5-10-69. Drld to 650'. Rrna to 22" hole to 650'. Ran and set 16" csg @ 623.&5'. Cmtd w//*50 sx Type "G" cmt w/200 bbls prehydrated &% Gel wtr, tailed in w/125 sx Type "G" cmt w/2% cc. Drld 15" hole to 2610'. Ran lO-3/&" csg & set @ 2580'. Cmtd w/58/* sx Type "G" cmt mxd w/275 bbls ~% prehydrated Gel wtr. Tailed in w/125 sx Neat cmt mxd w/ 15 bbls 2% cc wtr. Drld 9-5/8" hole to 80/*5'. Ran IES, FDC and SNP Logs. Tool 30 sidewall cores as follows: 773/*', 7732', 7658', 763~', 7629', 7286', 7281', 7012', 7006', 7002', 699/*', 6837', 6830', 6688', 6258', 62/*3', 4244', 4238', 4230', 4220', 4216', 4210', 420/*', /.190', /.188', /.183', ~16/*', /.151', /*1~i' and /.125'. Ran 7" csg, set @ 8016'. Cmtd w//*02 sx Type "G" cmt mxd w/137 bbls prehydrated 8.5% Diacel "D" & 2% Gel, 2nd stage cmtd w/705 sx Type "G" cmt mxd w/705 sx Type "G" cmt mxd w/lO5 bbls 2% cc. Ran Cement Bond Log twice. .Perf'd w//* shots 4299'-&300' & squeezed perf's w/ll8 sx Type "G" cmt w/15 bbls 2% cc. Perf' d following intervals, IES Meas: 6995 '-7010' 668/*'-6689' 6182 ' -6197 ' 588/* '-5889 ' 5393' -5/.13' /.912'-~927' 4660'-/*700' /.325 ' -/*380 ' , 6587'-6592' , 6136'-61~1' , 58&2'-58/.7' , 5327'-5332' , /.880'-/,890' , /.56/*'-/,61/,' · /.112 ' -~162 ' , 6828' , 6536'-6551', 6520'-6525' , 6123'-6133', , 5810'-5820', 5731'-5736' , 5220'-5235', 5031'-5076' , /.832'-/.852', /*792'-/*822' , /*5/*0'-/*550', /.509'-/.519' , /*102'-~107', /*055'-/*080' , 673/*'-6739', , 6420' -6/,25 ', 6236 ' -6261', , 5980'-5990', 5895'-5915', , 5665'-5680', 55/*0'-55/*5', , 500/*'-5024', /*963'-/,983', , /.733'-/.753', /.711'-/.716', · ~J+20'-4490', /.388'-~+398', , /.021' -/*031'. Ran combination 3½" and /*" tbg string. Set @ /.315'. Prep to test well. Released rig @ 2:30 P.M. Wait on Otis wireline. Flow well to clean up. Ran ~-pt test as follows: #1 - Flwd ½ hr on 7/16" chk, FTP 189/* PSIG, Temp 66°, FARO 10.35/* MMCFD; #2 - Flwd ½ hr on ½" chk, FTP 1860 PSIG, Temp 65°, FARO ,, O 13./.99 MMCFD; #3 - Flwd i hr on 5/8 chk, FTP 1757 PSIG, Temp 6/* , FARO 20.295 ,, MMCFD; #/* - Flwd i hr on 3//* chk, FTP 1630 PSIG, Temp 6/* , FARO 27.260 MMCFD. 26 hr SIP 1939 PSIG. CAOF 52 MMCFD. Completed as gas well in commingled Cook Inlet and Beluga Sands. ATTACHMENT #2 PHILLIPS PETROLEUM COMPANY N.C.I. Unit #A-6 Cook Inlet, Alaska 2600- 3~40 3~Ao- 38Ao. 38&0- &020 A020- A300 ~300- A320 A320- 5078 5078- 588O 5880 - 6260 6260- 69OO 6':)oo- tD SA~PLE DESCRIPTION Sand; ~ KY, m-cg, poorly sorted, quartz and abundant dark rock fra~nents; scattered claystone and coal beds. Sand; med gy, mg, poorly sorted, quartz and black, brown, green, and yellow grains; with some gy silty claystone and thin coal beds. Sand; med gy, mg, poorly sorted, subangular to subround, abdnt black, brown, and green grains; with some gray, silty ClAystone and thin coal beds. Sand; dk gy, f-rog, mod sorted, subangular to subround, abdnt black, brown, green, and yellow grains. Claystone; gy, silty; with thin coal beds° Sand; dk MY, m-cg, mod srtd, subangular to subround, abdnt black, brown, and green grains; with some gray and brown silty, carbonaceous claystone and thin coal beds. Claystone; gy, silty, micaceous, soft; and claystone- tan, hd; with scattered thin sand and sandstone beds; and thin coal beds. Sand; It EY, f-cg, subangular to subround, abdnt gy, smoky quartz, grains, some black grains, tr green, brown, and pink grains; with tan, calcareous siltstone, and gy silty claystone. Claystone; gy, sli slty, soft to mod hd; with scattered thin beds of sand, sandstone, coal and siltstor~ Siltstone; reed gy, hd, calcareous; with thin beds of claystone; coal, and gray, calcareous sandstone. July 28, 1969 Ken W. Sloan ATTACHMENT PHILLIPS PETROLEUM COMPANY N.C.I. Unit #A-6 Cook Inlet, Alaska SIDEWALL CORE DESCRIPTIONS 4154 416/+ 418~ 4188 4190 4204 4210 4216 .~.20 4230 4238 4244 6243 6258 6688 6830 ,, o. m m m Sd- It gy, vf-fg' mod srtd, good P&P, w/sctd coal frag Sd - it gy, vf-fg,-mod srtd, good P&P Sd- it gy, m-cg, pebbly, clay clasts, clay matrix, v. poorly srtd, low P&P Sd- It gy, .fg, mod srtd, subang-subrnd, excellent P&P Sd- a's above Sd- it gy, fg, mod srtd, excellent P&P, abndt blk, bm, amber, and green grains, sli clayey Sd.-It gy, x..f~, mod srtd, excellent P&P, abndt blk, bm, amber, anc green grains Sd - as above Sd- it gy, fg, sli clayey, mod srtd, good P&P, subang Sd - It gy, fg, Vo clayey w/30% brn and wht clay matrix, poorly srtd, low P&P, abndt gm, red and blk grains Sd- It gy, vfg, slty, mod srtd, low P&P Sd - it gy, 'm-cg, clayey w/approx 20% wht clay matrix, also se brn and grn clay? matrix material, v. poorly srtd, iow P&P, prod qtz & feldspar w/se blk and grn grains Sd- it gy, fg, mod srtd, ang-subang, excellent P&P, qtz, feldspar, & abndt blk, red, and green grains, sli clayey Sd - It gy, f$, mod srtd, ang-subang, excellent P&p, qtz, feldspar, & abndt blk, red and green grains ss & Clyst- 'Interlaminated; ss- mod gy, fg, slty, clayey, poorly srtd, friable, fair P&P; clayst- it gy to dk gy,. firm, w/se blk c~rb lam ss - mod gy, fg, clayey, slty, poorly srtd, fair P&P, friable, sctd small coal frag ss- it gy, vf-fg, sli slty, sli ~clayey, mod. srtd, fair P&P, friable, pred. qtz & feldspar, w/small coal frag ' ss- it gy, vfg, slty, v. clayey, poorly srtd, low P&P, fria~a~'~, ~ sctd small c~al frag 68.37 699~ 7OO2 ?OO6 7012 7281 7.286 - 7629 . - 763/, - 7658 - 7?32 - T73~ - - ss - it gy, vf-fg, sli slty, mod srtd, fair P&P, pred. qtz & feldspar, friable -' ss - It gy, fg, slty, sli clayey, mod srtd, .fair P&P, friable, w/dk gy carb .clyst inclusions ss- it gy, fg, slty, clayey, mod srtd, fair P&P, friable, pred. qtz & feldspar w/sctd small coal frag ss - it gy, fg, slty, clayey, poorly srtd, fair P&P, pred. qtz & feldspar, friable - Mudst- It gy, v. sandy, carb w/abndt small coal frag, firm - ss - It gy, vfg, v. clayey, slty, v. poorly srtd, low P&P, friable ss- It gy, vf-fg, v. clayey, v. poorly srtd, low P&P, abndt small coal frag, friable ss - It gy, vfg, sli slty, mod stud, fair P&P, friable, abndt blk grains ss - It gy, fg, sli slty, sli clayey, poorly srtd, fair P&P, pred. qtz & feldspar, se blk grains, friable ss- med. gy, vfg, v. slty, v. clayey, p.oorly srtd, iow P&P, friable, sli calc. sltst- reed gy, clayey, sli sdy, firm ss- reed gy, vf-fg, v- slty, v. clayey, poorly srtd, low P&P, friable. Clyde R, Seewald May 26, 1969" PERFORATING A, ND sOUEEZE Rf:CORD Well [)ate ': ' "" II II. II Il II !! Il Il II !1 . Per[orating To 4753' 47]6 ' 4700'" 46:L/,' 1~550' &398' &380' ~107' &080' &031' ?ne follow~ 4300' · . - · F£orll ]+733'/~ &711 · ~.660 &509 4325 ~+102 ~055'/ &021 ng perforati .4299' · . No. of No. of Size of ~un Feet Pofforafed Holes Holes O;ame{'er 20" 80 5' 20 &O' 160 50' 200 'lO' 40 - . 10' - ' 40 70' 280 10' &O 55 ' --- 220'''::~' 50' 200' 5' 20 25' 100 10' ~0 · · Gull · 3~ 2" 45- .,-3/8 · 35 2" · /+5 3-3/8" · 35' 2" I! '.. l!1: . l .. · 11 '/ ' ' ' . I1: ." . . · Scallop Myp3r jet Sca!}op Ilyper Je ._Scallop · . · 11. ll.~ " , 2il .. II ' - I1 II. I! ;":- ' . . . ".. ;:: '.. - :: '. ~:.;.' f:...:.'~ :,:.... .- II I{Iper Jeb Scallop ... . S eh !t~'..-;e rger I! I! - .: · 0:o:..: inlet Unit '\- - . . - : PERFORATING AND SOUEEZE RECORD .- o 11 11 Il I! II .'i · _ ., . Perforating 1ES 70~0' 6739' -'" 6689~ 6592' 6551' --6525' 62A6 ' 6261' 6197' 61~1' 6133' 5990' 5915" 5889' 58~7' 5820' 5736' 5680' 5fl13' · ~332' ~23~' 5o76' ~50~' ~+9~3' A927' 4~52 ' ~822' From Feet' Perfera,:ed 6828' 668~' 6536'~ 6520' / 6~0' 6236 ~ 62~6 6182, 6136,~ 6~3 '/ 608~,~ 5980,~ 5895'~ .58~,~ 58!0,'~ 5731' 5665,y 5393'~ 5327,* 5220 ' 5031,/ ~880, 1~832,~ IJ92"/' 15' - 15' 5' 5' lC' 15' 15' 5' lC' lC' lC' 20' .. lC' 15' 5' 20' 15' lC' 20' 15' 10' 20' 30' No. of S,',ze of Holes Holes 20- 20 '"':. 20 6O; 20 2O _ hO 60 60 2O ~0 /~0 ' 2O 20 ' · O ' .~' 20; ' 6O - 2O 2O 60 180 ho 8O 60 flO 8O 120 . .. .~7 °6?- .I~5 .35 ' · ILL-: '..- ./~7 II :r; ,-. , ,_~ . : .:. · !I: ,._ .35 · o Ohme!er I1 !! Il 3-3/8" 3-3/a" /.~11 2·11 II 3-3/8" 3-3/8" 211 Il 3--3/8" 3-3/8" · o No Plug Sch!::;':,t -: rger hyper Jeu - . .... Hyper Jet Mo Plug l{~p~ r Jet Scallop .. .. No' PI~ -' ~...4"._.:~-~ ?allop .... . ' ..:-" -t,'.-- -"': ""- ' . - 1~ ....~ .. . II ; .... . - .: , 5eallop -. - Jet Scallop'.. Il Itypor Jet Scallop. · Hyp~r Jet Form No. P--4 REV. 9-30-6T STATE OF ALASKA O~L AND GAS CONSERVATION COMMITTEE SUBMIT IN DEPLICATE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS ~. API NL-~.IEI~ICAL CODE API 50-283-20026 6. LF~SE DESIGNATION AND SERIAL NO. ADL-37831 ?. IF I~-DIAN, ALOT'I'EE OR TIRIBE NAA[E 0IL ~-~ GAS ~ WELL ~ WELL OTHER 2. NAME OF OPEP~TOR Phillips Petroleum Company 3. ADDRESS OF OPERATOR ~1~ "D" Street~. Anchorage_, Alaska ~O1 4.LOCATION OF WELL At Surface: Leg 3, Slot 3, 1259' FNL, 1083' FWL, Sec. 6, TllN, RgN, S.M., North Cook Inlet, Platform "Tyenek" At Preposed Pred. Zone: 2600' FNL, ~' FWL, Sec. 6, TllN, RgW, 8. U'NIT,F.A-R.%~ OR LEASE NA_%IE North Cook Inlet Unit 9. %VELL NO. 10. FIELD AlXTD POOL, OR WILDCAT North Cook Inlet 11. SEC., T., R., M., (BO'I~I'OM HOLE OBJECTIVE) Sec. 1, TllN, RIGW, S.M. 12. PERMIT NO. 69-50 13. REPORT TOTAL DEPTH AT END OF MONTH, CHANGES IN HOLE SI~E, CASING AND CEMENTING JOBS INCLUDING DEPTH SET A/ND VOLT/MES USED, PERFORATIONS, TESTS A/ND RESULTS, FISHING JOBS, JLrNK IN HOLE AND SIDE-TRACKED HOLE ANT) A_NY OTHER SIGNIFICA/XTT CI-IAN~ IN HOL~ CONT)ITIONS. 5-30--69 (Cent'd) ~733 ' -~753 ' ~102 ' -~107 ' , ~711'-~716', ~660'-~7~', ~56~'-&614', , M+20'-M+90', ~388'-~398", ~325'-~380', ~'-4~162' , ~O55'-~O80', ~21'-~31". 5-31-~9 Ran cembimatiem 3½" and &" tbg string, Set at &315'. JUN 1 1969 DIVISION OF OIL Al,ID ~A~ A~~GE 1~. I hereby ~ t ~e fore~o' g ' d ~ - ~ /OYE Reoort on t~iS [orm i~ re~i~ed for each ca[enda~ too,th, r eoardless ot the status ot o~eratio,i, an~ m~ ~ flied in d~plkate ~ the DMsion of Mines ~ Mi~erais b~ the 15th of the s~cceedi~ memk ~less othe~i~ directed. Form No. P--4 ~-'v. 9-3o-6~ STATE OF'ALASKA SUB~ m D~LIC~rS AND GAS CONSERVATION COMMITTEE IMONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS 2. NA/VIE OF OP]~q.A. TOR PhiLLips Petreleum Ce~ 3, ADDRESS OF OPERATOR 51~ "D" Street; Ancherage, Alaska 99~01 4. LOCATION OF V~TM At Surface: Leg 3, Slet 3, 1259' FNL, 1083' FWL, Sec. 6, Ti_N, RgW, S.M., North Geck Inlet, Platferm "Tyenek" At Proposed Pred. Zene: 2600' FNL, ~' FWL, Sec. 6, RgW, S.M. ADL-37831 . i 8. TJ/%'IT,FA_RA{ OR LEASE N.AAIE Ner~h C~k Inlet Unit Sec. 1, TllN, R10W~ $.M. 19. PERNIIT NO. 69-5o 13. HEPOi~T TOTAL DEPTH AT END OF MONTH, CI-IA~TGES IN HOLE SIZE, CASING ANT) CESV~ENTING JOBS INCLUDING DEPTH SET A_N]) VOLUATES USET), P~O'RATIONS, TESTS ~ RESULTS, FISHING JOB~, JUATK IN HOLE A-ND SIDE-TRACKED HOLE AND A/~Y OTHER SIGNIFICA~WT CHAN~ES IN HOL~ CO.larDITIONS. 5-31-69 PBTD 7977' Prepare te test well Spud 15" hele, drill te 650', ream te 22" hele to 650'. Ran and set 16". csg at 623.;+5'. Cemented w/;+SO sx Type "~" cement w/2~ b~ls prehydrated ;+% ~el wtr, tailed in w//25 sx Type "~" cement w/2% cc. ~illed 15" hole te 2$10'. Ram 10-3/;+" csg and set e 25~'. 0emented w/58& sx Type ,~,:, cement m~d w~y'~bbl.s ;+% prehydrated Gel wtr. Tailed in w/125 sx Neat cementV~ ~/15 bbls 2%cc wtr. Drilled 9-5/8" hele te ~;+5':. Ran IES, ~ and ~ Legs. Teek 30 sidewall cores as fellows: 773;+', 7732', 7658', 7$3;+", 7629 7286:', 7281', 70~', 7~06', 7~2', 699;+', 6837', 6830'~, 6688', 6258', 623+3', ~2~'-, ~238', ~230~', ~220', ~216', ~10', ;+20;+', &l~', ~;+188', ~183', ;+16;+', ;+151', ~' and ~5'- 5-26/29-69 Ran 7" csg, set at ~16'. Cemented w/;+02 sx Type "G" cement w/137 bbls prehydrated 8.5% Diacel "D" & 2% Gel, 2nd stage cemented w/705 sx Type "G" cement mxd w/105 bbls 2%cc. Ran Ce- ment Bend Leg twice. Perforated w/;+ shets ~99'-4+-300' 'and and squeezed perf's w/l18 ax Type "G" cement w/15 bbls 2% cc 5-30-69 Perforated fellewi~ intervals, IES Measurements: 6995'-7010', 6~8'-68;+3', 673;+'-6739', 668;+'-6689', 6587'-6592', 6536'-6551' 6520'-6525', 6;+20'-6~5', 6236'-6261', 6182'-6197', 6~3'-6133', 608~'-609;+', 59~'-5990~, 5895'-5915', 588;+~'-5889' 58;+2'-58;+7', 5810'-5820', 5731-5736', 5665'~6~'', 5393'-5;+13', 5327'-5332', 5220'-5235', 5031'-5076', ;+963'-;+983', ;+912'~-;+927' , ;+880'-4+890', ;+832'-&852', ;+792'-;+822' 14. I hereby certify that the foregoing is true and correct SIGNED TITLE DA'rE NOTE--Report on this form is required for each calendar month, regardless of the status of operations, and must be filed in duplicate with the Division of Mines & Minerals by the 15th of the succeeding month, unless otherwise directed. ,STATE 'OF ALASKA auam'r m -' OIL AND GAS CONSERVATION COMMITTEE: ,. .uL}:,! n ..... .-::,.~"GA$ WELL .'OPEN FLOW POTENTIAL TEST '.:REPORT " ~;" "'[~ ' 4*POINT TEST ' ', '" .... DI ~ iSICN .... .,~... Teat , Field _ ' ..... J ~eservolr · . ~e~ '~ ' /. m I Lease ~-~ ,' ! ~.~ ~c / - c/~-./~,. ~ TBO. J CSG. J Temprr.t~e _ ~ ~ _ ~/~.~ ~_.~' _~ · ~. -. ~/ I /~,~ I ~o .~~& I~ _. , ... .... ,.. ~ulllple Completion (gull o~ Triple) ' J I .......... i iii i i ii i i i i ill L i O~8~VED DATA Flow Data . Date JVv'ell ~°o. ,'PRESI UI1E ': CALCUI~ATIONS .... Coeffl- - -- ' J Flow Temp. , 'Gravity ' Compress. NO. cleat ...~/~ ' .p .Pressure Factor .Factor .'Factor Rate of Flow (24 Hr.)Vw m psis " . F ,F ~ F Q MCF/D t . . g ,pr · ,..L_~, ~_:,'_v "/~ · ,. ~~ ' ..../, ~/ . '""~,/0~ '.':'.'.. I0, ~ ~'~ , . , . ~.__ .,. ~, / .. /,6Y~ ~-~, .... ~ .... /, 1/~ /~. ~.__ [ ~~ .. /~77- , ~2) .. _ / .../,/~ ' ., . FL(Il%? CALCULATIONS Time (Prover) (Choke) Press, Diff. , '-Tubing 'Casing Flowing .NO. of Flow ~). ~ h . Press. Press. Temp. Hours Size Size pslg Iv pslg pslg ..; '_ .................. .,-, .."::/4~A,/. ' ...... .,. Z~ . ' ~,'o~o '~/>'~ . ' /~ ~ ', "',',' / ~~, , . ' ,. /. I_ ~ _ ~/~_.. /~..~ ~~~ . . ~ . j ~'.,vlll, ef Liquid (Apll · """'"" "°""""' 7~9,~/ ,.~,/,~ J" . ' ........... Il I IIII I I I II I l Ill L I II I I II · i-- i i i j~/ ill i i i i .: , CERTIFICATE:' I, the under~lfned, state'thkt:Z m tb'-,/~'.-//&-'~- /'~- Of the -- (company), and that ! nm luthorlzed by Ildd comimny to make this report; and that thio report was pre. pared under my supervision and 'dlr~Jon .and that the facts stated therein &re'true, eorreet and complete to t~e ~e~e~ m~ Form P~I! :.~ OIL AND GAs CONSERVATION GOMMITTEE Reid ~ e~,.~ '- ~ r. c, ~luclng Formation [ Oil OrMdlent Water Gradient IIESERVOII1 PI:LESSUBE BEPORT ',.-' -~ ~ ' - · ~ ~ ~LAddress. .~* Initial~,. Completion, ex. { Special* Lease '% Date Tested -'i .. . - - . . - ~ ;,.:._ · · · ;L . . -.~ .. :- cji . ~ Bomb Test Data Shut-In --. Tubing Observed Pressure Pressure OSee Instructions on Reverse Side . · (company), and that I am authorized by said company, to make this'reporti and that this report was prepared under my supervision and direction and that the facts stated therein are true, correct and ~omplete to the best of my knowledge. '- i~_. . ... -' ' ' '-'-?:- , ' .'-'*, ' - ..' '. '.' dmf~--& .... -' - - ': '. r. ''~ ,' :. '} '' General Survey* - [ Datum Plane 8ontc Instrument Test Data Pressure Test t I Casing &t (Bbls. per Day) Pressure Datum '' JIJNJJJ pJ, JJJjJJJiJJ~JJ JO. jj DXVXSX~ 0~ OXL ~ GAS April ~th ~ Xul~t ~ait l~tllipm Pmt:r~lmum ~, op~at~ ~z~t Offi~m ~ b ~ qq~oved mil ~ ~ BmTmll FORM SA- I B MEMORANDUM ( State of Alaska FROM: DATE SUBJECT: FORM SA- I B MEMORANDUM State of Alaska TO: F DATE FROM: SUBJECT: Form REV. 9-30-67 [ . reverse side) S'[ATE OF ALASKA OIL AND GAS CONSERVATION ,COMMITTEE APPLICATION FOR PERMIT TO DRILL, DEEPEN, OR PLUG BACK la. TYPE OF WORK DRILL [] DEEPEN [] PLUG BACK b. TYPE OF WELL WELL WELL OTHER ZONE ZONE 2. NAME OF OPERATOR Pb~ l]_~ os Petroleum C~mpany 3. ADDRES~ O~F OPERATOR q "D" Street. Anaherm~e. ~lask. 99503 4:LO-OATIONOFWELLAt surf.ace i~g 3, Sl~t'3, 1259' FNL, 1083' FWL, Sec. 6, T~W, RgW, S.M., No~bh Cook Inlet, Platform "Tyonek" At proposed prod. zone 2600~ FNL, 400' F~L, Sec. 6, T]IM, Rgw, S.M. 13. DISTANCE IN MILES AND DIRECTION F.~OM NEAREST TOWN OR POST OFFICE* 10.5 ndles East of ~T~nek; ~laska 14. BOND INFORi~ATION: M-ML-IV State Wide Bond Rl-1 API 50-283-20026 6. LEASE D~SIGNATION ~ SERIAL NO. ADL-378~l I. IF IN/)IA/~. ALLO~EE OR ~ N22M~ 8. UNIT, FAPaM OR LEASE NAME North Cook Inlet Unit 9. WELL NO. 10. FIELD AND POOL, OR WILDCAT TYPE Surety and/or No. 15. DISTANCE FROM PROPOSED* LOCATION TO NEAREST PROPERTY OR LEASE LINE. FT~ (Also to nearest drig, unit, if any) ~,.(~('~ 18. DISTANCE FROM PROPOSED LOCATION* TO NEAREST WELL DRILLING, COMPLETED, OR APPLIED FOR, FT. 135o, 21. ELEVATIONS (Show whether DF. RT, CR, etc.) I~_WR I 1 ~ I flaCOn I~I'.T;W NO. OF ACRES IN LEASE 6~00~ MD 7000~ 23. PROPO.SED CASING AND CEMENTING PROGRAM North C~ok Inlet i1. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) Sec, 1, TI]N, IAOW, S.M. Aznount ,17. N-O.' ACRES ASSIGNED TO THiS WELL 20, ROTARY OR CABLE TOOLS Rotary 22. APPROX. ,DATE WORK WILL START* 5-15-69 CAsING!I WEIGHT PER FOOT GRADE 'II SE~TING DEPTH '1 · SIZE OF HOLE I~ SIZE OF , QUANTiTY'~F CEMENT 22" 16" 65~, H-~0 600~ o~. Circ~late t° SUrface . o_~Tm', 7" 6~.~'~. Oq~ .T_~.~ .~ 8200tfJ/~ ~ u~-{o-~-~6~e Day zone , 1. Deviation required to reach BHL from permanent platform, 2. There are no effected operators. 3. BOP Specification attached. 4. Intervals of interest wi~ be perforated and may be stimulated. * Refer to State ef Alaska, Alaska 0il & Gas Conservation Committee, Conservation Order #4D, dated 6-8-67 and #68, dated 12-7-68. APR 2 ' 969 I~ ABO~AC~ DE$CZ~IBE PRO,PO$~ PI~OGRA.M: If proposal Is to deepen or plum back, ~ive ~ata on presen¢ productive zon~ propose~ r~v productive zo~ie. If pro,posal is ~o drill or deepen diree~ionally, give perthten¢ data on s~bsurface ~ocat~ons and meas~Lme~,an~w~ true ,~ert21 depths. Give bl,~ut preventer progra,m. 24. I herebY' ce~ify~$hat the Forego4~g/isL~rue and Correc$ S, GNrO ~ /~,~-~'~.~'~ DATE April 25, 1969 District Office MEt. - // - ... ~ -.,/ --- . , . - ,~,=,.~ (This sp~ f.or State off. ice use) CONDITIONS OF APPROV,qJ..,, IF ANY: [] Y~S ~f~o ~7-/~ ~ ~{--,"~-,-v 'Z-- ES [] NO ~ :: ,.:': '-' ';' :~ :i{~:- ~'.~: x' ,::x , ,) April 30, 1969 PERATIT NO_ fl- ,,-J>/' ~ . ,.~ APPROVAL DATE APPROVED B__ , TITLE. Div. nf: ri'il & G~S DATE April 30, 1969 *See Instructions On Reverse Side 36 12 ~ DI./7'589 7 5 13 APR B $ I969 DIVISION OF OiL AND GAS ANCHO~,~.?,E , 18 ................. .~D/.. 18741 GRID PHILLIPS PETROLEUM COMPANY 515 "D" ;STREET ANCHORAGE ,ALASKA PLAT OF NORTH COOK INLET UN IT TYONEK PLATFORM ...... ISCALgi ,,, ,,,~0,AT£:: '4-3-0S .... 36 I 31 6 I 6 LEG NE. LAT. 61° 04' 36.38" LONG.150° 56' 55.63" Y: 2,586,73 I X: 331,995 FROM N.W. COR. i~250' SOUTH 8~ 975' EAST. SCALE I". 1,000' T 12N TIIN LEG N°-. 4 LEG N-°. 2' LAT. 61° 04' 36.89" LAT. 61° 04' 35.83" LONG. 150° 56' 54.25" LONG. 150° 56' 54.77" Y: 2.586,781 Y: 2,586,674 X=, 332,063 X= 332,036 FROM NW. COR. FROM N.W. COR. 1,198' SOUTH & 1,305' SOUTH E~ 1,043' EAST. , 1,018' EAST. -, 31 32. 6 LEG'NE 3 LAT. 61<' 04' 36-3'4" LONG. I~O° 56' 53.39" Y= 2,586,72 4 X= ~332,105 FROM N.W. COR. 1,254' SOUTH .8 1,085' EAST. 5 8, CERTIFICATE OF SURVEYOR I hereby certify that I am properly registered and licensed to practice land surveying in the State of Alaska and that this plat represents a location survey made by me or under my supervision and that all dimensions and other details ere correct. " / DA~E SURVEYOR ~ NOTE The location of the platform legs was accomplished by using triangulation stations BELUGA,TERRACE,and TYONEK which are all U.S.C.t~ G.S. stations. AIl coordinates are Alaska State Plane, Zone 4. NOTE: Plat emended 7AUG:68! revised ~e§ ,: . CHOKE MANIFOLD HOOKUP DOUBL[( PREVENT[:RS PLATFORM FOR · o G 4" SERIES 1500 VALVE G 2" SERIES 1500 VALVE G 2" MUD PRESSURE GAUGE Ol"J 4"X ~'X~" SERIES 1500 STEEL TEE REV. :::,/l I/G3 SCtt~.OL ,_E E NOTE: Double Preventers are used with flanged side outlets for choke manifold and filluP line connec~tiOns. !--- . N,C.I.U. 5000 PSi WOR" ~,ING ,-,, BLOWOUT PRFVEN'F'''r''_ ,:F, I-lOOK--UP (SERIES 1500 F[.ANG~S OR PHlLLIPS FL:,,-,,.,_.EUi,'I CO,i, PANY PRODUCTION DEPARTMENT SERIES 1500 X 2" SERIES 1500 STE'EL CROSS 2"SERIES 1500 POSITIVE CHOKE 2" SERIES 1500 ADJUSTABLE CHOKE Leg I Leg 4 North Cook iniet Unit N.C.I.. Un.~. · · ,.c.,.u.,,~~ _ "u." ~PR 2,8 D1¥1510~ OF Oit. AHD ii i PHI.I~LIPS PETROLEUM COMPANY 515-~' STREET ANCHORAGE,ALASi<A , NORTH COOK INLET TYONEK PLATFORM COOK INLET ~ ALASKA NOTE, Using PLATFORM NORTH, Slot No.! will . furthest pl(3tform North slot in pl(]tform west quodr(3nt of ony legl Slots ere Ithru8 inoc°unter'cl°ck'wi~e directi~/" PLATFORM LOCATION: SlC,6"|IN-gW [ DATE;: 4 '~J'69 b-RW,N. N. ~. P...n .... I NO,,T TO SC,A,I:.E '! Company Lease & Well No. CHECK LIST FOR NEW WELL PERMITS Yes No Remarks 1. Is well to be located in a defined pool ................. /~.J~ 2. Do statewide rul es apply ........................ $. Is a registered survey plat attached .................. ~ 4. Is well located proper distance from property line ........... ~_~_~. '. .... .~,~, 5. Is well located proper distance from other wells ............ /~x~ 6. Is sufficient undedicated acreage available in this pool ........ ~ I. Is well to be deviated 8. Is 'operator the only affected party .................... ~t~ ii~ ~. Can permit be approved before ten-day wait ............... ~< 10. Does operator have a bond in 'force ................... ~. II Is conductor string provided 12. 'Is enough cement used to circulate on conductor and surface ...... /'~ 13. Will cement tie in surface and intermediate or production strings . . . 14. Will cement cover all possible productive horizons ........... ..A/ 15. Will surface casing cover all fresh water zones ............. 2'''') , Will surface cst. internal burst equal .5 psi/ft· to next string .... .~ 17. Will all casing give adequate safety in collapse and tension ...... j~ 18. 'Does BOPE have sufficient pressure rating ............... ~ · Additional Requirements' __~_~zm~.~,f~/ X~-/~ ~/~ ~/c~p ~x~z~ ~z~}×~ ~~ ~~ Approval Recommemded' ' ~. --' ,--,-,~ TRM. m ~ . i... REL ~ KLV .~d ~-~ OKG ,,~
