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Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address: 3800 Centerpoint Drive, Suite 1400 Stratigraphic Service 6.API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): North Cook Inlet Field / Tertiary System Gas Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 8,279'4,351' Casing Collapse Structural Conductor 630 psi Surface 2,700 psi Intermediate Production 3,270 psi 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 Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email:kkozub@hilcorp.com Contact Phone: (907) 570-1801 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Other: Plug for Redrill 7,012'4,283'3,796'1,205 psi 6,324'7" Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 9/16/2021 4-1/2" Daniel E. Marlowe Packers (see schematic) & Otis SCSSV Nipple 7,449' Perforation Depth MD (ft): 4,057 - 6,798 7,449' See schematic & 274 (MD) 274(TVD) Tubing Grade:Tubing MD (ft): 3,067 - 5,808 Perforation Depth TVD (ft): 388' 30" 16" 10-3/4" 614' 2,544' 614' 2,393' 614' 2,544' 388' 12.6 / J-55 TVD Burst 6,971 4,360 psi Tubing Size: MD 1,640 psi 4,030 psi 168-072 50-883-20016-00-00Anchorage, AK 99503 Hilcorp Alaska, LLC N/A N Cook Inlet Unit A-01 COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 / ADL0037831 Authorized Signature: Operations Manager Karson Kozub PRESENT WELL CONDITION SUMMARY Length Size See schematic 388' Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 8:39 am, Sep 03, 2021 321-444 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.09.02 16:46:16 -08'00' Dan Marlowe (1267) Plug for Redrill X BOP test to 3000 psi, annular to 2500 psi. DLB 09/03/2021BJM 9/7/21 X 10-407 DSR-9/3/21 dts 9/8/2021 JLC 9/8/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.08 13:40:05 -08'00' RBDMS HEW 9/10/2021 Well Work Prognosis Well Name:NCIU A-01 API Number: 50-883-20016-00-00 Current Status:Producer – Shut in Leg:Leg #3 SE Corner Estimated Start Date:9/16/2021 Rig:Spartan 151 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:168-072 First Call Engineer:Karson Kozub (907) 777-8434 (O) (907) 570-1801 (M) Second Call Engineer:Katherine O’Connor (907) 777-8376 (O) (214) 684-7400 (M) Current Bottom Hole Pressure: 1,566 psi @ 3,616’ TVD 0.433 psi/ft gradient to surface Maximum Expected BHP:1,566 psi @ 3,616’ TVD 0.433 psi/ft gradient to surface Maximum Potential Surface Pressure: 1,205 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary A-01 is a watered-out producer. The well was drilled in 1968 and completed in 1969 as a commingled Cook Inlet and Beluga producer. The well began producing water in 1987, and in 1992 was worked over to isolate the intervals producing water, re-perforate and stimulate the Cook Inlet and Beluga sands not producing, and to run a multiple packer completion for proper zone isolation. The well was shut in from 2006 to 2020 due to water production from deeper Cook Inlet Sands. In 2020 perforations below 4,290’ were isolated and the Cook Inlet Stray Sands were perforated. The well flowed for a short period and watered out. The purpose of this sundry is to isolate the current wellbore and set up for redrilling. Wellbore Notes: x SL found thick mud/sand @ 4,044’ (3/13/2020) x SSSV was pulled on (3/6/2020) Pre-rig work: x Fluid pack well with KWF x MIT-IA to 3,000psi, this will ensure overshot is sealed and casing is good for PTD MASP (2,814 psi) x Attempt to inject down the tubing at 1,500psi to see if the formation will take fluid, establish injection rate. Monitor IA pressure while pumping. Procedure: 1. MIRU Spartan 151 2. RU E-line pressure test lubricator to 250psi low/1,500psi high a) RIH and tag fill ±4,044’ b) Cut tubing at ±3,980’ c) *Note overshot @~3,985’ is pinned to shear, unknown what the pins are, could be ~80k 3. Circulate well with 9.5 ppg mud a) Monitor well to ensure static 4. Install BPV, ND tree, NU Unihead adapter and BOP 5. Test BOP’s to 250psi low/3,000psi high /2,500 psi annular. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). *Note hanger may leak rolling test likely on Unihead adapter flange break a) Pull BPV b) Monitor well to ensure static 6. Pull upper completion from ±3,980’, fishing as needed 7. RIH and set cement retainer ±3,950’ 8. RIH, sting into cement retainer 9. Conduct injectivity test 10. Perform Hesitation Squeeze with ±15 BBL of cement through cement retainer. a) *Note: it’s likely squeezing into formation is not possible with fill in the well b) *contingent to lay 100ft of cement on top of the retainer 11. Un-sting from cement retainer and place 75ft (~ 3 BBL) of cement on top of EZSV Remove lock plate - see wellhead diagram. MPSP on drilling program is 2814 psi. Test BOP’s to 250psi low/3,000psi high /2,500 psi annular. Well Work Prognosis a) Depending upon squeeze. Can place up to 18 BBL on top of retainer. Note: Max TOC is 3,300Ft for a 3,150’ whipstock b) Circulate clean. POOH. 12. Wait on cement, RIH with clean out assy to whipstock set depth 13. RIH and tag TOC 14. Test IA to 3,000 psi and chart for 30 minutes. ***Remaining Procedure to be included on the Permit to Drill for the redrill*** Phase II General sequence of operations pertaining to drilling procedure: (informational only) 1. Resume operations on PTD 2. PU redrill BHA and RIH 3. Swap well to drilling fluid 4. Kick off whipstock into new formation 5. Drill per directional plan 6. Run/Cement 4.5” casing 7.Swap to completion sundry Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic 4. BOP Drawing 5. Fluid Flow Diagrams 6. Sundry Revision Change Form p ***Remaining Procedure to be included on the Permit to Drill for the redrill*** _____________________________________________________________________________________ Updated By: JLL 02/28/20 SCHEMATIC North Cook Inlet Unit Well: NCI A-01 Last Completed: 11/03/1992 PTD: 168-072 API: 50-883-20016-00 PBTD: 7,156’ TD: 8,279’ 30” RKB: 116’ 7” CI-A CI-B 3 4 5 6 7 8 9 10 11 12 13 16” 10-3/4” 1 2 Fill 4,348’ on 7/13/11 14 15 16 17 Temperature tool stuck in fill @ 4,351’ CI-8.0 CI -9.0 CI -10.0 CI -11.0 C-5 D-1 D-3 D-4 E-8 E-9 G-1 G-2 H-4 M-3 I-7 J-2.1 J-3 CI-3.0 -6.0 CI -6.2 CI-1.0 CI-2.0 M-2 18 19 Tight spot @ 4,002’Sterl Stray CIBP @ 4,290’ w/ 5’ Cement TOC2,570’ CBL 1992 X XN CASING DETAIL Size Wt Grade Conn ID Top Btm 30” 29.000 Surf 388’ 16” 65 H-40 15.250 Surf 614’ 10-3/4” 51 J-55 9.850 Surf 2,544’ 7” 23 J-55 Butt 6.366 Surf 7,449’ TUBING DETAIL 4-1/2” 12.6 J-55 EUE-8rd 3.958 Surf 6,971’ Tubing punch 4,060’ – 4,061’ (2/11/20) PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status CI - Stray 3 4,057’ 4,067’ 3,607’ 3,616’ 10’ 02/12/20 Open CI-A 4,085' 4,095' 3,630' 3,639' 10' 2/1/1969 Cmt Szq CI-B 4,116' 4,140' 3,656' 3,676' 24' 2/1/1969 Cmt Szq CI-1.0 4,351' 4,391' 3,854' 3,887' 40' 2/1/1969 Open CI-2.0 4,402' 4,482' 3,896' 3,963' 80' 2/1/1969 Open CI-3.0 4,516' 4,525' 3,991' 3,999' 9' 2/1/1969 Open CI-4.0 4,552' 4,588' 4,021' 4,051' 36' 2/1/1969 Open CI-5.0 4,624' 4,674' 4,081' 4,122' 50' 2/1/1969 Open CI-6.0 4,708' 4,738' 4,150' 4,174' 30' 2/1/1969 Open CI-6.2 4,760' 4,784' 4,192' 4,212' 24' 2/1/1969 Open CI-8.0 4,874' 4,886' 4,284' 4,294' 12' 2/1/1969 Open CI-9.0 4,960' 4,972' 4,354' 4,363' 12' 2/1/1969 Open CI-10.0 5,000' 5,012' 4,386' 4,395' 12' 2/1/1969 Open CI-11.0 5,044' 5,080' 4,421' 4,449' 36' 2/1/1969 Open C-5 5,590' 5,598' 4,852' 4,858' 8' 2/1/1969 Open D-1 5,604' 5,616' 4,863' 4,872' 12' 2/1/1969 Open D-3 5,663' 5,692' 4,909' 4,932' 29' 2/1/1969 Open D-4 5,708' 5,715' 4,945' 4,950' 10' 2/1/1969 Open E-8 5,874' 5,888' 5,076' 5,088' 14' 2/1/1969 Open E-9 5,892' 5,904' 5,162' 5,100' 12' 2/1/1969 Open G-1 6,076' 6,084' 5,237' 5,243' 8' 2/1/1969 Open G-2 6,098' 6,116' 5,254' 5,268' 18' 2/1/1969 Open H-4 6,271' 6,278' 5,391' 5,397' 7' 2/1/1969 Open M-3 6,508' 6,814' 5,578' 5,820' 306' 2/1/1969 Open I-7 6,509' 6,514' 5,579' 5,583' 5' 2/1/1969 Open J-2.1 6,578' 6,584' 5,634' 5,638' 6' 2/1/1969 Open J-3 6,589' 6,602' 5,642' 5,653' 13' 2/1/1969 Open M-2 6,790' 6,798' 5,801' 5,808' 8' 2/1/1969 Open JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 39’ 39’ 4.500 Hanger 1 274’ 274’ 3.813 Otis SCSSV Nipple 2 3,985’ 3,548’ 3.940 Otis Overshot Sealing Divider 3 4,000’ 3,561’ 3.880 Otis VCR Retrievable Packer 4,290’ 3,802’ CIBP w/ 5’ cement (TOC 4,283’) 4 4,299’ 3,810’ 4.000 Otis TWR Permanent Packer 5 4,494’ 3,973’ 3.810 Otis XA Sliding Sleeve (Opens up) – Opened 10/1996 6 4,502’ 3,980’ 4.000 Otis TWR Permanent Packer 7 4,704’ 4,147’ 3.810 Otis XD Sliding Sleeve (Opens down) Closed 4,753’ 4,187’ 3.500 XO 4.5 x 3.5, 9.3# J-55 EUE8rd 8 4,764’ 4,196’ 4.000 Otis BWH Permanent Packer 9 4,882’ 4,291’ 4.000 Otis BWH Permanent Packer 10 4,924’ 4,325’ 2.750 Otis XA Sliding Sleeve (Opens up) – Opened 7/1996 11 5,023’ 4,404’ 4.000 Otis BWH Permanent Packer 12 5,056’ 4,430’ 2.750 Otis Sliding Sleeve XO (Opens down) Closed – Set Isolated Sleeve 13 5,076’ 4,446’ 4.000 Otis BWH Permanent Packer 14 5,088’ 4,456’ 2.313 Otis Sliding Sleeve XO (Opens down) Closed 15 6,895’ 5,884’ 2.205 Otis X Nipple 16 6,960’ 5,936’ 2.205 HES XN Nipple 17 6,971’ 5,945’ 2.441 Wireline Re-Entry Guide 18 7,156’ 6,091’ Baker Retrievable Bridge Plug 19 7,405’ 6,289’ SLB Bobcat Retrievable Bridge Plug -00 DLB _____________________________________________________________________________________ Updated By: JLL 09-02-21 PROPOSED North Cook Inlet Unit Well: NCI A-01 PTD: 168-072 API: 50-883-20016-00 PBTD: 7,156’ TD: 8,279’ 30” RKB: 116’ 7” CI-A CI-B 3 4 5 6 7 8 9 10 11 12 13 16” 10-3/4”1 2 Fill 4,348’ on 7/13/11 14 15 16 17 Temperature tool stuck in fill @ 4,351’ CI-8.0 CI -9.0 CI -10.0 CI -11.0 C-5 D-1 D-3 D-4 E-8 E-9 G-1 G-2 H-4 M-3 I-7 J-2.1 J-3 CI-3.0 -6.0 CI -6.2 CI-1.0 CI-2.0 M-2 18 19 Tight spot @ 4,002’ Sterl StrayCIBP @ 4,290’ w/ 5’ Cement Tbg Cut +/-3,980’ Cement Retainer +/- 3,950’ TOC 2,570’ CBL 1992 X XN CASING DETAIL Size Wt Grade Conn ID Top Btm 30” 29.000 Surf 388’ 16” 65 H-40 15.250 Surf 614’ 10-3/4” 51 J-55 9.850 Surf 2,544’ 7” 23 J-55 Butt 6.366 Surf ±3,150’ (KOP) TUBING DETAIL PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status CI - Stray 3 4,057’ 4,067’ 3,607’ 3,616’ 10’ 02/12/20 Isolated CI-A 4,085' 4,095' 3,630' 3,639' 10' 2/1/1969 Isolated CI-B 4,116' 4,140' 3,656' 3,676' 24' 2/1/1969 Isolated CI-1.0 4,351' 4,391' 3,854' 3,887' 40' 2/1/1969 Isolated CI-2.0 4,402' 4,482' 3,896' 3,963' 80' 2/1/1969 Isolated CI-3.0 4,516' 4,525' 3,991' 3,999' 9' 2/1/1969 Isolated CI-4.0 4,552' 4,588' 4,021' 4,051' 36' 2/1/1969 Isolated CI-5.0 4,624' 4,674' 4,081' 4,122' 50' 2/1/1969 Isolated CI-6.0 4,708' 4,738' 4,150' 4,174' 30' 2/1/1969 Isolated CI-6.2 4,760' 4,784' 4,192' 4,212' 24' 2/1/1969 Isolated CI-8.0 4,874' 4,886' 4,284' 4,294' 12' 2/1/1969 Isolated CI-9.0 4,960' 4,972' 4,354' 4,363' 12' 2/1/1969 Isolated CI-10.0 5,000' 5,012' 4,386' 4,395' 12' 2/1/1969 Isolated CI-11.0 5,044' 5,080' 4,421' 4,449' 36' 2/1/1969 Isolated C-5 5,590' 5,598' 4,852' 4,858' 8' 2/1/1969 Isolated D-1 5,604' 5,616' 4,863' 4,872' 12' 2/1/1969 Isolated D-3 5,663' 5,692' 4,909' 4,932' 29' 2/1/1969 Isolated D-4 5,708' 5,715' 4,945' 4,950' 10' 2/1/1969 Isolated E-8 5,874' 5,888' 5,076' 5,088' 14' 2/1/1969 Isolated E-9 5,892' 5,904' 5,162' 5,100' 12' 2/1/1969 Isolated G-1 6,076' 6,084' 5,237' 5,243' 8' 2/1/1969 Isolated G-2 6,098' 6,116' 5,254' 5,268' 18' 2/1/1969 Isolated H-4 6,271' 6,278' 5,391' 5,397' 7' 2/1/1969 Isolated M-3 6,508' 6,814' 5,578' 5,820' 306' 2/1/1969 Isolated I-7 6,509' 6,514' 5,579' 5,583' 5' 2/1/1969 Isolated J-2.1 6,578' 6,584' 5,634' 5,638' 6' 2/1/1969 Isolated J-3 6,589' 6,602' 5,642' 5,653' 13' 2/1/1969 Isolated M-2 6,790' 6,798' 5,801' 5,808' 8' 2/1/1969 Isolated JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 ±3,150’ ±2,873’ Whipstock 2 ±3,950’ ±3,520’ Cement Retainer ±3,980’ ±3,544’ Tubing Cut 3 4,000’ 3,561’ 3.880 Otis VCR Retrievable Packer 4,290’ 3,802’ CIBP w/ 5’ cement (TOC 4,283’) 4 4,299’ 3,810’ 4.000 Otis TWR Permanent Packer 5 4,494’ 3,973’ 3.810 Otis XA Sliding Sleeve (Opens up) – Opened 10/1996 6 4,502’ 3,980’ 4.000 Otis TWR Permanent Packer 7 4,704’ 4,147’ 3.810 Otis XD Sliding Sleeve (Opens down) Closed 4,753’ 4,187’ 3.500 XO 4.5 x 3.5, 9.3# J-55 EUE8rd 8 4,764’ 4,196’ 4.000 Otis BWH Permanent Packer 9 4,882’ 4,291’ 4.000 Otis BWH Permanent Packer 10 4,924’ 4,325’ 2.750 Otis XA Sliding Sleeve (Opens up) – Opened 7/1996 11 5,023’ 4,404’ 4.000 Otis BWH Permanent Packer 12 5,056’ 4,430’ 2.750 Otis Sliding Sleeve XO (Opens down) Closed – Set Isolated Sleeve 13 5,076’ 4,446’ 4.000 Otis BWH Permanent Packer 14 5,088’ 4,456’ 2.313 Otis Sliding Sleeve XO (Opens down) Closed 15 6,895’ 5,884’ 2.205 Otis X Nipple 16 6,960’ 5,936’ 2.205 HES XN Nipple 17 6,971’ 5,945’ 2.441 Wireline Re-Entry Guide 18 7,156’ 6,091’ Baker Retrievable Bridge Plug 19 7,405’ 6,289’ SLB Bobcat Retrievable Bridge Plug -00 DLB Current Wellhead 3/30/2020 NCIU A-01 Unihead, OCT type 3, 16 3/4 5M BX-161 hub top X 16'’ LTC casing bottom, w/ 2- 2 LPO on lower section, 2- 2 1/16 5M SSO on middle section, 2- 2 1/16 5M SSO on upper section , IP internal lockpin assy 28'’ Starting head, OCT, 30 ½ 1M X 28'’BW, w/ 2- 4'’ 1M EFO Tbg hanger, FMC-UH-A-EN, 6'’ X 4 ½ EUE 8rd lift and 4 ½ IBT susp, w/ 4'’ Type IS BPV profile, 1- ¼ non cont control line port Hanger is nested in pack-off and held down by lock plate Lock-plate needs to be removed before nipple up of BOPE Tyonek Platform A-01 28 X 16 X 10 3/4 X 7 x 4 1/2 Tree assy, 4 1/16 3M Adapter, 16 ¾ 5M clamp hub x 4 1/16 3M stdd top, prepped f/ 1- non cont control line port 16'’ 10 ¾’’ 7'’ 4 ½’’ Hanger leaks stated by Conoco 2011 1. BOP Schematic 2. Choke Manifold Schematic Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well: N Cook Inlet Unit A-01 (PTD 168-072)Sundry #: XXX-XXXAny modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.Sec Page Date Procedure Change New 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS RECEIVED MAR 4 2020 1. Operations Abandon Plug Perforations L4J Fracture Stimulate EJ Pull Tubing LJ AOGGoGutdown Li Performed: Suspend ❑ Perforate Other Stimulate ❑ Alter Casing El Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development 0 Exploratory ❑ Stratigraphic ❑ Service ❑ 168-072 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-833-20016-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0017589 / ADL0037831 N Cook Inlet Unit A-01 9. Logs (List logs and submit electronic and printed data per 20AAC25.071). 10. Field/Pool(s): N/A North Cook Inlet Field / Tertiary Gas Pool 11. Present Well Condition Summary: Total Depth measured 8,279 feet Plugs measured See Schematic feet true vertical 7,006 feet Junk measured 4,351 feet Effective Depth measured 4,283 feet Packer measured See Schematic feet true vertical 3,796 feet true vertical See Schematic feet Casing Length Size MD TVD Burst Collapse Structural 388' 30" 388' 388 Conductor 614' 16" 614' 614' 1,640 psi 630 psi Surface 2,544' 10-3/4" 2,544' 2,393' 4,030 psi 2,700 psi Intermediate Production 7,449' 7" 7,449' 6,324' 4,360 psi 3,270 psi Liner Perforation depth Measured depth 4,057 - 6,798 feet True Vertical depth 3,067-5,808 feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6 / J-55 6,971 (MD) 5,945 (TVD) 274' 9MD) Packers and SSSV (type, measured and true vertical depth) See Schematic Otis SCSSV Nipple 274' (TVD) 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure E Prior to well operation: 0 0 0 48 23 Subsequent to operation: 1 0 3153 1 54 1 354 485 14. Attachments (required per 20 AAc 25070, 25.071, s 25.283) 15. Well Class after work: Daily Report of Well Operations El Exploratory ❑ Development Q Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. WeII Status after work: Oil ❑ Gas Q WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if G.O. Exempt: 320-023 Authorized Name: Daniel E. Marlowe Contact Name: Joe Kaiser Authorized Title: Operations Manaqqr7 Contact Email: kalser@hilcorD. coni Authorized Signature: - — - ,�� Date: ln? Contact Phone: (907) 777-8393 Form 10-404 Revised 4/2017 iBDMS1� MAR 0 5 2020 Submit Original Only 0 Ailcorp Alaska, LLC � IIRKB�1166'' I 1 Zl 16" 10-3/4- Tight 0 3/4"Tight spot 3 @ 4,002' CI BP @ 4,290' w/ 5' Cement Fill 4,345 on 4 7/13/11 Temperature tool stuck in fill @ 4,351' 6 ' CI -1.0 G-20 18 19 7 Im PBTD: 7,156' G5 D1 D3 D4 E-8 E-9 G-1 G-2 H4 1A'3 7 J-2.1 L3 Nt2 TD: 8,279' Updated By: JILL 02/28/20 SCHEMATIC North Cook Inlet Unit Well: NCI A-01 Last Completed: 02/28/1969 PTD: 168-072 API: 50-883-20016-00 Size Wt Grade Conn ID Top Btm 30" 39'4.500 CI - Stray 3 29.000 1 Surf 388' 16" 65 H-40 15.250 Surf 614' SO -3/4" 51 J-55 9.850 Surf 2,544' 7" 23 =%^ 0-10.0 Surf 7,449' 4 4,299' 3,810' 4.000 11 1 4,494' 3,973' 3.810 Otis XA Sliding Sleeve(Opens up) -Opened 10/1996 18 19 7 Im PBTD: 7,156' G5 D1 D3 D4 E-8 E-9 G-1 G-2 H4 1A'3 7 J-2.1 L3 Nt2 TD: 8,279' Updated By: JILL 02/28/20 SCHEMATIC North Cook Inlet Unit Well: NCI A-01 Last Completed: 02/28/1969 PTD: 168-072 API: 50-883-20016-00 Size Wt Grade Conn ID Top Btm 30" 39'4.500 CI - Stray 3 29.000 1 Surf 388' 16" 65 H-40 15.250 Surf 614' SO -3/4" 51 J-55 9.850 Surf 2,544' 7" 23 J-55 Butt 1 6.366 Surf 7,449' TUBING DETAIL 4-1/2" 1 12.6 J-55 EUE-8rd 3.958 Surf 6,971' Tubing punch 4,060'- 4,061'(2/11/20) IFWFI RV DFTAII No Depth (MD) Depth (TVD) ID OD Item FT 39' 39'4.500 CI - Stray 3 Hanger 1 274' 274' 3.813 Otis SCSSV Nipple 2 3,985' 3,548' 3.940 Otis Overshot Sealing Divider 3 4,000' 3,561' 3.880 Otis VCR Retrievable Packer 4,116' 4,290' 3,802' 3,676' EIRP w/ 5'cement(TOC 4,283') 4 4,299' 3,810' 4.000 Otis TWR Permanent Packer 5 4,494' 3,973' 3.810 Otis XA Sliding Sleeve(Opens up) -Opened 10/1996 6 4,502' 3,980' 4.000 Otis TVVR Permanent Packer 7 4,704' 4,147' 3.810 Otis XD Sliding Sleeve (Opens down) Closed 4,525' 4,753' 4,187' 3.500 X04.5 x 3.5, 9.3#J-55 EUE8rd 8 4,764' 4,196' 4.000 Otis BWH Permanent Packer 9 4,882' 4,291' 4.000 Otis BWH Permanent Packer 10 4,924' 4,325' 2.750 Otis XA Sliding Sleeve (Opens up) -Opened 7/1996 it 5,023' 4,404' 4.000 Otis BWH Permanent Packer 12 5,056' 4,430' 2.750 Otis Sliding Sleeve XO (Opens down) Closed -Set Isolated Sleeve 13 5,076' 4,446' 4.000 Otis BWH Permanent Packer 14 5,088' 4,456' 2.313 Otis Sliding Sleeve XO (Opens down) Closed 15 6,895' 5,884' 2.205 Otis X Nipple 16 6,960' 5,936' 2.205 HES XN Nipple 17 6,971' 5,945' 2.441 Wireline Re -Entry Guide 18 7,156' 6,091' 4,395' Baker Retrievable Bridge Plug 19 7,405' 6,289' 5,044' SLB Bobcat Retrievable Bridge Plug PFRPn PATIr1N DFTAII Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT DateStatus CI - Stray 3 4,057' 4,067' 3,607' 3,616' 10' 02/12/20 Open CI -A 4,085' 4,095' 3,630' 3,639' 10' 2/1/1969 Cmt Szq CI -B 4,116' 4,140' 3,656' 3,676' 24' 2/1/1969 Cmt Szq CI -1.0 4,351' 4,391' 3,854' 3,887 40' 2/1/1969 Open C1-2.0 _01 4,402' 4,482' 3,896' 3,963' 80' 2/1/1969 Open 30 4,516' 4,525' 3,991' 3,999' 9' 2/1/1969 Open CI -4.0 4,552' 4,588' 4,021' 4,051' 36' 2/1/1969 Open CI -5.0 4,624' 4,674' 4,081' 4,122' S0' 2/1/1969 Open Ck6.0 4,708' 4,738' 4,150' 4,174' 30' 2/1/1969 Open CI -6.2 4,760' 4,784' 4,192' 4,212' 24' 2/1/1969 Open CI -8.0 4,874' 4,886' 4,284' 4,294' 12' 2/1/1969 Open CI -9.0 4,960' 4,972' 4,354' 4,363' 1 12' 2/1/1969 Open CI -10.0 5,000' 5,012' 4,386' 4,395' 12' 2/1/1969 Open 01-11.0 5,044' 5,080' 4,421' 4,449' 36' 2/1/1969 Open C-5 5,590' 5,598' 4,852' 4,858' 8' 2/1/1969 Open D-1 5,604' 5,616' 4,863' 4,872' 12' 2/1/1969 Open D-3 5,663' 5,692' 4,909' 4,932' 29' 2/1/1969 Open D-4 5,708' 5,715' 4,945' 4,950' 30' 2/1/1969 Open E-8 5,874' 5,888' 5,076' 5,088' 14' 2/1/1969 Open E-9 5,892' 5,904' 5,162' 5,100' 12' 2/1/1969 Open G-1 6,076' 6,084' 5,237' 5,243' 8' 2/1/1969 Open G-2 6,098' 6,116' 5,254' 5,268' 18' 2/1/1969 Open H-4 6,271' 6,278' 5,391' 5,397' 7' 2/1/1969 Open M-3 6,508' 6,814' 5,578' 5,820' 306' 2/1/1969 Open 1-7 6,509' 6,514' 5,579' 5,583' 5' 2/1/1969 Open J-2.1 6,578' 6,584' 5,634' 5,638' 6' 2/1/1969 Open J-3 6,589' 6,602' 5,642' 5,653' 13' 2/1/1969 Open M-2 6,790' 6,798' 5,801' 5,808' 8' 2/1/1969 Open Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date N Cook Inlet Unit A-01 Eline 50-833-20016-00-00 168-072 2/10/20 2/12/20 Daily Operations: 02/10/20 - Monday Arrive on Tyonek, attend orientation, obtain PTW, hold PJSM. Spot Equipment. MU 2.75" GR/CCL, eline jars, Baker #10 setting tool w/ 3.50"OD CIBP. Move to well. PT 250L/2000H. Open swab. RIH (15'-CCL to CIBP). 20psi on well. Run correlation pass from PBTD to 4000'. Confirm correlation (add 10') Drop down and position CIBP at 4290' and set. POOH. Close swab, secure well and rig back for the night. 02/11/20-Tuesday Attend operations meeting with production team. Obtain PTW and hold PJSM. MU 2.50" x 20' dump bailer, mix 5 gallons of cement. Fill bailer, move to well and RIH. Tag CIBP, pickup 10' and dump cement. POOH. OOH. Lay down bailer. Add second set of WLV's. Build 1-9/16" x 1' (4spf) tubing puncher w/ decentralizers and MU with wt. bar & GR/CCL. Move to well and PT. Fixed Oring leak. Repair and PT 250L/2000H. Discovered wing valve leak at low pressure. Crew made up coupling flange. Jumped lift gas to tubing. (450 psi). Open swab and RIH. (9' CCL to top shot). Stopped at cement top and logged GR/CCL correlation pass up to 2400'. End pass, send log to Anchorage. Confirm correlation is on depth. Drop down and log up position pass. Pull into position at 4051' (CCL depth). Monitor tubing pressure (445 psi). Fire gun @ 4060'-61'. Drop down and log perforations. (Good indication of shots) POOH. OOH. Rig back and secure well w/ night cap. Tubing Pressure 425 psig. 02/12/20 - Wednesday Attend production ops meeting, obtain PTW and hold PJSM. RU e-line and lubricator. Arm perf gun. MU & hot check 2.75" GR/CCL and MU to perf gun. Lift gas to well to 450 psi. Move to well and PT 250L / 2000H. RIH. (7.5' CCL to top shot). Witnessed fluid level at 1450'. Tagged PBTD at 4283' (TOC). PU logging correlation pass to 3900'. End pass and send log to Anchorage. Drop well pressure to 150 psi. Confirmed correlation, pull into position at 4049.5' (CCL depth) and fire gun at 4057'- 4067'. Tubing pressure rose to 200 psi. POOH. OOH. Shut'in swab (650 psi). RD. Rigged out of way. RU slickline to set SSSV. Leave platform for OSK. THE STATE OfALASKA GOVERNOR MIKE DUNLEAVY Dan Marlowe Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: North Cook Inlet Field, Tertiary Gas Pool, NCIU A-01 Permit to Drill Number: 168-072 Sundry Number: 320-023 Dear Mr. Marlowe: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. V' ------'-- Jay of January, 2020. 3BDMSt6J1AN 3 12020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25 280 RECEIVED JAN 17A�Gt?02�✓zo 1. Type of Request: Abandon ❑ Plug Perforations 0 Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑' Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Reddll ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q . Strati ra hic ❑ g p ❑ Service 168-072 ' 3. Address: 3800 Centerpoint Drive, Suite 1400 P 6. API Number: Anchorage, AK 99503 50-833-20016-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 68 ' Will planned perforations require a spacing exception? Yes ❑ No Q N Cook Inlet Unit A-01 - 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0017589 / ADL0037831 I North Cook Inlet Field / Tertiary Gas Pool - 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 8,279 7,006 4,348 3,851 1,212 psi 7,156 & 7,405 4,351 Casing Length Size MD TVD Burst Collapse Structural 388' 30" 388' 388' Conductor 614' 16" 614' 614' 1,640 psi 630 psi Surface 2,544' 10-3/4" 2,544' 2,393' 4,030 psi 2,700 psi Intermediate Production 7,449' 7" 17,449' 16,324' 14,360 psi 3,270 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 4,351 - 6,798 3,854 - 5,808 4-1/2" 12.6 / J-55 6,971 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): See Schematic See Schematic 12. Attachments: Proposal Summary 0 Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Strati ra hic g p ❑ Development ❑� Service ❑ 14. Estimated Date for 15. Well Status after proposed work: 1/31/2020 Commencing Operations: OIL ❑ WINJ E]WDSPL ❑ Suspended ❑ GAS ❑� WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Dan Marlowe Contact Name: Joe Kaiser Authorized Title: Operations Ma r 4Z Contact Email: ka15@r hIICOr .CODS Contact Phone: (907) 777-8393 Authorized SignatuDate: C'U jZUZCJ COMMISSI N USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 0 n G Plug Integrity F-1SOPTest F] Mechanical Integrity Test E]Elv Location Clearance Other: IBDMS !f"- JAN 3 12020 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes No Subsequent Form Required: / 0-90 APPROVED BY /J Approved by: COMMISSIONER THE COMMISSION Date: w Z /" / — Submit Form and Form 10 3 Revise Approved application is valid for 12 months from the date of a6ip o.�,l i� I �I ,/�hhenIs in yplic tZ7 n Hilcorp Alaska, LU Well Prognosis Well: Tyonek A-01 Date:1/17/2020 Well Name: Tyonek A-01 API Number: 50-883-20016-00 Current Status: SI Gas Well Leg: Leg #3 (SE) Estimated Start Date: January 31, 2020 Rig: E -Line Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 168-072 First Call Engineer: Joe Kaiser (907) 777-8393 (0) (907) 952-8897 (M) Second Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Maximum Expected BHP: 1,576 psi @ 3,639' TVD (Based on 0.433 psi/ft to surface) Max. Potential Surface Pressure: 1,212 psi (Based on 0.1 psi/ft gas gradient) Brief Well Summary The NCIU A-01 well was drilled in 1968 and completed in 1969 as a commingled Cook Inlet and Beluga producer. The well began producing water in 1987, and in 1992 was worked over to isolate the intervals producing water, re -perforate and stimulate the Cook Inlet and Beluga sands not producing, and to run a multiple packer completion for proper zone isolation. The well has been shut in since 2006 due to water production from deeper Cook Inlet Sands. The proposed perf adds will target Cook Inlet Stray Sands below the top packer that have not yet been produced from this completion. The purpose of this sundry is to isolate the perforations below and re -perforate the Sterling Stray Sands. Notes Regarding Wellbore Condition • Suspected restriction at —4,002' • Slickline will tag and drift tubing prior to procedure below. Procedure: 1. MIRU E -line, PT lubricator to 2,000 psi High/ 250 Low. 2. RIH pull SSSV. POOH. LD SSSV 3. RIH with 4.5" CIBP to ±4,290'. Use Gamma/CCL to correlate. Verify plug is set above/below a collar. Consult Engineer prior to setting. Set plug. POOH. Note: confirm water level. a. Contingency: CIBP maybe set higher. Depends on amount encountered in wellbore. 4. RU bailer. RIH and place 5' of cement on top of CIBP. POOH. 5. Contingency if fluid is present: RU and RIH with swab cups. Remove as much fluid as possible from tubing. POOH 6. RU tubing punch. RIH with tubing punch. Punch hole at 4,060'. Consult Engineer prior to tubing punch. POOH. 7. RU wireline perforating guns. 8. RIH and perforate the following intervals: Zone Sands (Mp) Btm (MD) FT SPF Sterling Cl Stray ± ± 5' 6 Sterling Cl Stray ± 20' 6 Sterling Cl Stray ±4,050' ±4,070' 20' 6 Sterling A ±4,080' ±4,100' 20' 6 H ffilw.m Alaska, LU Well Prognosis Well: Tyonek A -O3 Date:1/17/2020 a. Proposed perf's shown on the proposed schematic in red font. b. Final Perf tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Correlation Log. d. Use Gamma/CCL to correlate. Utilize Press/Temp tool if available e. Record tubing pressures before and after each perforating run. 9. RIH w/ SSSV and set in profile. 10. RD wireline 11. Turn well over to production. Contingency Procedures: 12. The Sterling A sand (via tubing punch in step 6) may be tested prior to adding the Sterling Stray sand perforations. 13. Each Sterling Stray Sand may be tested prior to adding further Sterling Stray sand perforations. Attachments: 1. Actual Schematic 2. Proposed Schematic ffiIcoro Alaska, LLC RKB: =116' I I I 1 U 30' 2 3 Tight spot 4 @ 4,002' FII 4,348' on 7/13/11 Tenp,,u,re 6 tool stuck in fill @4,35V 9 9 11 13 7S X Now 7r -, 18 19 r PBTD: 7,156 CI -A CI -B CI -1.0 CI -20 G-3.0 CI -4.O CI -50 CI -B.0 Cl -62 Cl -8.0 CS D-1 D3 D4 E-8 E-9 G-1 G-2 144 W I-7 }2.1 43 W TD: 8,279' North Cook Inlet Unit Well: NCI A-01 Last Completed: 02/28/1969 SCHEMATIC PTD: 168-072 API: 50-883-20016-00 CAGIMC rIPTAII Size Wt Grade CoEnlTop OD Item Btm30' 39' 39' 4.500 Hanger Surf 388'16" 274' 65 H-40 2 Surf 61410-3/4" 3.940 51 1-55 Surf 25447" Otis VCR Retrievable Packer 23 J-55 Bu Surf 7,449' TUBING DETAIL 4-1/2" 12.6 J-55 EUE-Srd 3.958 Surf 6,971' IFWFI Rv nJ:TAII No Depth (MD) Depth (TVD) ID OD Item FT 39' 39' 4.500 Hanger 1 274' 274' 3.813 Otis SCSSV Nipple 2 3,985' 3,548' 3.940 Otis Overshot Sealing Divider 3 4,000' 3,561' 3.880 Otis VCR Retrievable Packer 4 4,299' 3,810' 4.000 Otis TWR Permanent Packer 5 4,494' 3,973' 3.810 Otis XA Sliding Sleeve (Opens up) - Opened 10/1996 6 4,502' 1,980' 4.000 Otis TWR Permanent Packer 7 4,704' 4,147' 3.810 Otis XD Sliding Sleeve (Opens down) Closed 9' 4,753' 4,187' 3.500 X04.5 x 3.5, 9.3#1-55 EUE8rd 8 41764' 4,196' 4.000 Otis BWH Permanent Packer 9 4,882' 4,291' 4.000 Otis BWH Permanent Packer 10 4,924' 4,325' 2.750 Otis XA Sliding Sleeve (Opens up) - Opened 7/1996 11 5,023' 4,404' 4.000 Otis BWH Permanent Packer 12 5,056' 4.437 2.750 Otis Sliding Sleeve XO (Opens down) Closed - Set Isolated Sleeve 13 5,076' 4,446' 4.000 Otis BWH Permanent Packer 14 5,088' 4,456' 2.313 Otis Sliding Sleeve XO (Opens down) Closed 156,895' 2/1/1969 5,884' 2.205 Otis X Nipple 16 6,960' 5,936' 2.205 HES XN Nipple 17 6,971' 5,945' 2.441 Wireline Re -Entry Guide 18 7,156' 6,091' Open Baker Retrievable Bridge Plug 19 7,405' 6,289' 4,449' SLB Bobcat Retrievable Bridge Plug DFRFr1RATInki IIFTAll Zone Top (MD) Btm (MD) Top (ND) Btm (TVD) FT Status CI -A 4,085' 4,095' 3,630' 3,639' 30' SzqCI-B 4,116' 4,140' 3,656' 3,676' 24' j2/*1/1969Cmtmt mt SzqCI-1.0 4,351' 4,391' 3,854' 3,887' 40'OpenCI-2.0 4,402' 4,482' 3,896' 3,963' 80' penCI-3.0 4,516' 4,525' 3,991' 3,999' 9' penCI-4.0 4,552' 4,588' 4,021' 4,051' 36' pen 0-5.0 4,624' 4,674' 4,081' 4,122' 50' 2/1/1969 Open C1-6.0 4,708' 4,738' 4,150' 4,174' 30' 2/1/1969 Open CI -6.2 4,760' 4,784' 4,192' 4,212' 24' 2/1/1969 Open 0-8.0 4,874' 4,886' 4,284' 4,29,V 12' 2/1/1969 Open CI -9.04,960' 4,972' 4,354' 4,363' 12' 2/1/1969 Open CI -10.0 5,000' 5,012' 4,386' 4,395' 12' 2/1/1969 Open CI -11.0 5,044 5,080 4,421 4,449' 36' 2/1/1969 Open C-5 5,590 5,598 4,852' 4,858 8' 2/1/1969 Open D-1 5,604' 5,616' 4,863' 4,872' 12' 2/1/1969 Open D-3 5,663' 5,692' 41909'95,8081 32' 29' 2/1/1969 Open D-4 5,708' 5,715' 4,94550' 10' 2/1/1969 Open E-8 5,874' 5,888' 5,07688' 14' 2/1/1969 Open E-9 5,892' 5,904' 5,16200' 12' 2/1/1969 Open G-1 6,076' 6,084' 5,23743' 8' 2/1/1969 Open G-2 6,098' 6,116' 5,25468' 18' 2/1/1969 Open H-4 6,271' 6,278' 5,39197' 7' 2/1/1969 Open M-3 6,508' 6,814' 5,5780' 306' 2/1/1969 Open 1-7 6,509' 6,514' 5,5793' 5' 2/1/1969 Open J-2.1 6,578' 6,584' 5,6348' 6' 2/1/1969 Open 1-3 6,589' 6,602' 5,6423' 13' 2/1/1969 Open M-2 6,790' 6,798' 5,8018' 8' 2/1/1969 Open Updated By: JILL 01/06/2020 0 Ell 16" 103/4" 2 Tight spot 3 @ 4,00Y OBP @`4,290 w/S Cement 8114,348'an4 7/]3/11 Temperature taolstudrin 611@4,351' 6 CICO CI -20 aa0-6.0 046.2 0-8o CI -9.0 a-10.0 CM1.0 G5 o-1 D3 D4 E8 E-9 G-1 G2 1+4 M3 1-7 121 J3 M,2 18 r tin .�.N.:r ✓ PBTD: 7,156' T0: 8,279' Updated By: JILL 01/10/2020 Depth (MD) Depth (ND) ID North Cook Inlet Unit FT 39' 39' 4.500 Hanger 1 Well: NCI A-01 274' 3.813 Otis SCNipple 2 PROPOSED SCHEMATIC Last Completed: 02/28/1969 Otis Overshot Sealing Divider 3 4,000' 3,561' 3.880 PTD: 168-072 ±4,050' 1lilenru amska, ttc ±3,802' ±3,618' API: 50-883-20016-00 4 4,299' 3,810' 4.000 CASING DETAIL 5 WB: 116 3,973' 3.810 Otis XA Sliding Sleeve (Opens up) - Opened 10/1996 6 4,502' 3,980' 4.000 Otis TNR Permanent Packer 7 4,704' 4,147' 3.810 Otis XD Sliding Sleeve (Opens down) Closed 4,753' 4,187' 3.500 XO 4.5 x 3.5, 9.311 J-55 EUE8rd 8 4,764' 4,196' 4.000 Otis BWH Permanent Packer 9 4,882' 16" 103/4" 2 Tight spot 3 @ 4,00Y OBP @`4,290 w/S Cement 8114,348'an4 7/]3/11 Temperature taolstudrin 611@4,351' 6 CICO CI -20 aa0-6.0 046.2 0-8o CI -9.0 a-10.0 CM1.0 G5 o-1 D3 D4 E8 E-9 G-1 G2 1+4 M3 1-7 121 J3 M,2 18 r tin .�.N.:r ✓ PBTD: 7,156' T0: 8,279' Updated By: JILL 01/10/2020 Size Wt Grade Conn Btm 30" 29.000 Surf 388' 16" 65 1 H-40 15.250 1 Surf 1 614' 10-3/4" 51 1 1-55 1850 Surf I 2,544' 7" 23 1-55 1 Butt 1 6.366 Surf 1 7,449' TUBING DETAIL 4-1/2" 12.6 1-55 EUE-erd 3.958 Surf 6,971' No Depth (MD) Depth (ND) ID Top FT 39' 39' 4.500 Hanger 1 274' 274' 3.813 Otis SCNipple 2 3,985' 3,548' 3.940 Otis Overshot Sealing Divider 3 4,000' 3,561' 3.880 TUBING DETAIL 4-1/2" 12.6 1-55 EUE-erd 3.958 Surf 6,971' No Depth (MD) Depth (ND) ID OD Item FT 39' 39' 4.500 Hanger 1 274' 274' 3.813 Otis SCNipple 2 3,985' 3,548' 3.940 Otis Overshot Sealing Divider 3 4,000' 3,561' 3.880 Otis VCR Retrievable Packer ±4,050' ±4,290' ±3,802' ±3,618' CHIP w/5' cement 4 4,299' 3,810' 4.000 Otis TWR Permanent Packer 5 4,494' 3,973' 3.810 Otis XA Sliding Sleeve (Opens up) - Opened 10/1996 6 4,502' 3,980' 4.000 Otis TNR Permanent Packer 7 4,704' 4,147' 3.810 Otis XD Sliding Sleeve (Opens down) Closed 4,753' 4,187' 3.500 XO 4.5 x 3.5, 9.311 J-55 EUE8rd 8 4,764' 4,196' 4.000 Otis BWH Permanent Packer 9 4,882' 4,291' 4.000 Otis BWH Permanent Packer SO 4,924' 4,325' 2.750 Otis XA Sliding Sleeve (Opens up) - Opened 7/1996 11 5,023' 4,404' 4.000 Otis BWH Permanent Packer 12 5,056' 4.430' 2.750 Otis Sliding Sleeve XO (Opens down) Closed -Set -Isolated Sleeve 13 5,076' 4,446' 4.000 Otis BWH Permanent Packer 14 5,088' 4,456' 2.313 Otis Sliding Sleeve XO (Opens down) Closed 15 6,895' 5,884' 2.205 Otis X Nipple 16 6,960' 5,936' 2.205 HES XN Nipple 17 6,971' 5,945 2.441 Wireline Re -Entry Guide 18 7,156' 6,091' 4,212' Baker Retrievable Bridge Plug 19 7,405' 6,289' 4,874' SLB Bobcat Retrievable Bridge Plug Zone Top (MD) Bim (MD) Top (ND) Btm (ND) FT Date Status Ster. Stray 14,005' ±4,010' ±3,565' ±3,569' 5' Future Proposed Ster. Stray ±4,020' ±4,040' ±3,577' ±3,593' 20' Future Proposed Star. Stray ±4,050' ±4,070' ±3,601' ±3,618' 20' Future Proposed CI -A ±4,080' ±4,100' ±3,625' ±3,644' 20' Future Proposed CIA 4,0851 4,095' 3,630' 3,639' 10' 2/1/1969 Cmt Szq G -B 4,116'4,140' 3,656' 3,676' 24' 2/1/1969 Cmt Szq CI -1.0 4,351' 4,391' 3,854' 3,887' 40' 2/1/1969 Open CI -2.0 4,402 4,482' 3,896' 31963' 80' 2/1/1969 Open CI -3.0 4,516' 4,525' 3,991' 3,999' 9' 2/1/1969 Open CI -4.0 4,552' 4,588' 4,021' 4,051' 36' 2/1/1969 Open CI -5.0 4,624' 4,674' 4,081' 4;122' S0' 2/1/1969 Open CI -6.0 4,708' 4,738' 4,150' 4,174' 30' 2/1/1969 Open CI -6.2 4,760' 4,784' 4,192' 4,212' 24' 2/1/1969 Open CI -8.0 4,874' 4,886' 4,284' 4,294' 12' 2/1/1969 Open CI -9.0 4,960' 4,972' 4,354'. 4,363' 12' 2/1/1969 Open CI -10.0 5,000' 5,012' 4,386 44,395' 12' 2/1/1969 Open CI -11.0 5,044' 5,080' 4,421' 4,449' 36' 2/1/1969 Open C-5 S,%§ 5,598' 4,852' 4,858' 8' 2/1/1969 Open D-1 5,604' 5,616' 4,863' 4,872' 12' 2/1/1969 Open D-3 5,663' 5,692' 4,909' 4,932' 29' 2/1/1969 Open D-4 5,708' 5,715' 4,945' 4,950' 30' 2/1/1969 Open E-8 5,874' 5,888' 5,076' 5,088' 14' 2/1/1969 Open E-9 5,892' 5,904' 5,162' 5,100' 12' 2/1/1969 Open G-1 6,076' 6,084' 5,237' 5,243' B. 2/1/1969 Open G-2 6,098' 6,116' 5,254' 5,268' 18' 2/1/1969 Open H-4 6,271' 6,278' 5,391' 5,397' 7' 2/1/1969 Open M-3 6,508' 6,814' 5,578' 5,820' 306 2/1/1969 Open -7 6,509' 6,514' 5,579' 5,583' 5' 2/1/1969 Open 1-2.1 6,578' 6,584' 5,634' 5,638' 6' 2/1/1969 Open J-3 6,589' 6,602' 5,642' 5,653' 13' 2/1/1969 Open M-2 6,790' 6,798' 5,801' 5,808' 8' 2/1/1969 Open Davies, Stephen F (CED) From: Tommy Nenahlo <tnenahlo@hilcorp.com> Sent: Friday, January 24, 2020 9:55 AM To: Davies, Stephen F (CED) Cc: Joe Kaiser; Daniel Yancey Subject: RE: [EXTERNAL] NCIU A-01 (PTD 168-072; Sundry 320023) - Requests Attachments: Structural Cross Section.JPG Steve — The requested Sterling Stray 3 (4,050'-4,070') and Sterling A (4,080'-4,100') sands are within the Tertiary Systems Gas Pool as defined in Conservation Order No. 68. Upon further evaluation, the requested Sterling Stray sand perforations from 4,005'-4,010' and 4,020'-4 040' lie just outside of the Tertiary Gas Systems Pool, and so will not be perforated at this time. The Sterling Stray 1 sand (4,020'-4,040') had been open in the A-11 (SI 1997) and A-12 (51 2014) with the previous operator but are no longer active perforations. The Sterling 3 Sand (4,050'-4,070') was perforated in the A-11 (SI 1997). The A-11 and A-12 wells both have cement plugs preventing the ability to produce these wells. Please refer to the attached cross section for our correlation. The pick of the currently defined top of the Tertiary Gas Systems Pool is shown on the Cl State 17589-1 log. We continue to identify gas -bearing sands that lie just above the current definition of the Tertiary Gas Systems Pool. To properly develop the gas accumulation at the North Cook Inlet Unit we will need to modify the Pool Rules to encompass the full column. Expect this request in the near future. Please let me know if you need any further information! Thanks, Tommy Nenahlo I Reservoir Engineer Cook Inlet Asset Team Hilcorp Alaska, LLC Office: +1 (907) 777-3424 Mobile: +1 ( 720) 273-2685 tnenahlo((Ohilorp_-om From: Davies, Stephen F (CED) [mailto:steve.davies @alasba.pov] Sent: Tuesday, January 21, 2020 3:35 PM To: Joe Kaiser <jkaiser@hilcorp.com> Subject: [EXTERNAL] NCIU A-01 (PTD 168-072; Sundry 320023) - Requests Joe, Could Hilcorp please provide a structural cross-section that demonstrates the relationship of the Stray sands that Hilcorp proposes to perforate in NCIU A-01 to Cook Inlet State 17589-1, which is the reference log for the Tertiary System Gas Pool as defined in Conservation Order No. 68? Are these stray sands perforated in any other NCIU well? If so, which well? If the stray sands lie outside of the Tertiary System Gas Pool, does Hilcorp have AOGCC approval to commingle production within NCIU A-01? (See 20 AAC 25.215(b).) If so, which order? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.daviesPa laska.gov. The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. 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. N Q U 2 oil rr�IW�iHI�'_ rl��rlaim 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 2,586,72779 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 • • ~~~ APR 4 20D8 /~o`?~'d`7~ REV DATE BY CK APP SCRIPTION REV DATE BY CK P DESCRIPTION I 2/29/08 SAS KWA MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADD MUD LINE ELEV., SHT.3 god Z ~ 36 31 T 12 N 31 32 ~; y~i ~ 1 6 T 11 N 6 5 N I '~ "° N s. n'is' I`~ SE[. 6 1206' SCALE: I"-1320' -- -6 - ~ ~ ~ o ~ ~ 1 6 6 5 12 7 ~ 8 GENERAL NOTES: .~~~~ ~F, /~'~ ~\~' ~~ 1. SEE SHEET 3 FOR COORDINATE TABLE ' 1 ~'~P;.•''~• ,••••• '5~ ~ 2. SEE SHEET 3 FOR NOTES ON HORIZONTAL AND 9 ~ ~ ~ •• ~ ° ~• VERTICAL SURVEY DATA d ~ 49th • ~j 3. SECTION LINES AND TIES ARE BASED ON PROTRACTED ~ ""''""""""""""""""""""`""' j VALUES. ~ ~ . ~ ................................ ....~ ~ ~ ~ • ~, ;• KENNETH W. AYERS ~' ~o i ~~ s~, %~ LS-8535 •,' ~,~i SURVEYOR'S CERTIFICATE •,,, A •` I HEREBY CERTIFY THAT 1 AM PROPERLY REGISTERED ~~ ROFESSIONP~~P~~~ AND ~~, ~~~ ,"" LICENSED TO PRACTICE LAND SURVEYING IN THE STATE OF ALASKA AND THAT THIS PLAT REPRESENTS A SURVEY DONE BY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL LOUNSBURY DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF & nssoc[ATES, [[vc. FEBRUARY 28, 2008. SURVEYORS ENGINEERS PWNNERS ~ PHONE: f907) 272-5451 ~ AREA: MODULE: UNIT: ConocoPhilli s NORTH COOK INLET p TYONEK PLATFORM Alaska, Inc. WELL CONDUCTOR AS BUILT CADD FILE N0. 08-005 AS BUILT 02/27/08 DRAWING N0: ~g-~~5 /~S BU~~T PART: 1 OE 3 REV: 1 REV DATE BY CK APP ESCRIPTION REV DATE BY C P DESCRIPTION 1 2/29/08 SAS KWA MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADD MUD LINE ELEV., SHT.3 x g ~ ~ ~r z~ ~~ a h s~'3 ~ AA 99 >u~ ns rso S. 9.q. sc e ~lT ~~ ~j ~ ~~ ts~ SCALE: 1"-30' a 9 pA O L ESD 600 -50 ESD 600-51 O Ala 7 Ip •B2 83 AB A•A• • : •p5 A3• A8 A12 BI : •A5 • A4 A WELL HOUSE 2 ' O • p ap 41Op5 LEGEND: O 3 ~ A • WELL p WELL CONDUCTOR 0 ESD (EMERGENCY SHUT OFF VAL VE1 GENERAL NOTES: 1. 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 SURVEYORS ENGINEERS PWNNERS ~ ~~ PHONE: f907J 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 08-005 AS BUILT 2 of 3 1 REV DATE BY CK APP `~CESCRIPTION ~ 2/29/08 SAS KWA MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADD MUD LINE ELEV., SHT.3 ASP ZONE 4, NADI33, FEET NADI33 GEOGRAPHIC MLLW DESCRIPTION (POINT NO.) NORTHING FASTING LATITUDE LONGITUDE ELEVATION NqU WELL TAG NO. WELL HOUSE N0. 1 1001 2586492 1472018 61 04 34.38 150 57 03.71 72.0 Conductor 1 1002 2586489 1472017 61 04 34.34 150 57 03.72 73.9 63 1003 2586485 1472019 61 04 34.31 150 57 03.67 74.1 A12 1004 2586485 1472023 61 04 34.31 150 57 03.59 73.8 Bi 1005 2586487 1472027 61 04 34.33 150 57 03.52 72.0 Conductor 5 1006 2586491 1472027 61 04 34.37 150 57 03.52 73.7 B2 1007 2586495 1472025 61 04 34.41 150 57 03.57 72.1 Conductor 7 1008 2586495 1472021 61 04 34.41 150 57 03.65 73.7 A13 WELL HOUSE N0.2 2001 2586437 1472060 61 04 33,84 150 57 02.83 71.9 Conductor 1 2002 2586433 1472059 61 04 03.38 150 57 02.84 71.9 Conductor 2 2003 2586430 1472062 61 04 33.77 150 57 02.79 71.8 Conductor 3 2004 2586429 1472066 61 04 33.77 150 57 02.71 73.4 A9 2005 2586431 1472069 61 04 33.79 150 57 02.65 71.9 Conductor 5 2006 2586435 1472069 61 04 33.83 150 57 02.64 73.3 A10 2007 2586439 1472067 61 04 33.86 150 57 02.69 73.3 A11 2008 2586439 1472063 61 04 33.87 150 57 02.77 71.9 Conductor 8 WELL HOUSE N0.3 3001 2586488 1472128 61 04 34.36 150 57 01.47 73.0 Al 3002 2586484 1472127 61 04 34.32 150 57 01.48 73.1 A8 3003 2586481 1472130 61 04 34.29 150 57 01.43 73.1 A6 3004 2586480 1472133 61 04 34.28 150 57 01.35 73.0 A4 3005 2586483 1472137 61 04 34.31 150 57 01.29 73.0 A2 3006 2586487 1472137 61 04 34.34 150 57 01.28 73.0 A5 3007 2586490 1472135 61 04 34.38 150 57 01.33 73.0 A3 3008 2586490 1472131 61 04 34.38 150 57 01.41 73.3 A7 50 2586540 1472069 61 04 34.86 150 57 02.69 72.7 ESD Valve 600-50 51 2586501 1472011 61 04 34.46 150 57 03.86 72.6 ESD Valvle 600-51 100 2586572 1472123 61 04 35.18 150 57 01.58 115.3 Top center helipad -101' .MUD LINE SURVEY NOTES: 1. ALL COORDINATES ARE ASP ZONE 4, NAD83, US SURVEY FEET. GEOGRAPHIC COORDINATES ARE NAD83. 2. ELEVATIONS ARE IN FEET, BASED ON MLLW, REFERENCED TO DRAWING NO. MPD- TY04-2021, SHEET 1 OF I, REV. 2 3. ALL AS BUILTS ARE TO THE CENTER OF EXISTING STRUCTURE. 4. WELL CONDUCTOR ARE VERTICALLY AS BUILT TO THE TOP OF A 1/4" STEEL LID, TACK WELDED TO THE TOP OF THE CONDUCTOR: 5. WELLS ARE VERTICALLY AS BUILT TO THE TOP OF THE LOUNSBURY LOWEST HORIZONTAL FLANGE ON THE WELL. & ASSOCIATES, INC. SURVEYORS ENGINEERS PLANNERS ~ PHONE: /907/ 272-5451 ~,~ AREA: MODULE: UNIT: ConocoPhillips NORTH COOK INLET TYONEK PLATFORM. Alaska, Inc. WELL CONDUCTOR AS BUNT CADD FILE N0. DRAWING N0: PART: REV: 08-005 AS BUILT 02/27/08 08-005 AS BUNT 3 of 3 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown_ Stimulate_ Plugging _ Perforate _ Pull tubing _ Alter casing _ Repair well _ Other _X Variance 2. Name of Operator Conoco Phillips Alaska, Inc. 3. Address P. O. Box 100360 Anchorage, AK 99510-0360 4. Location of well at surface 1252' FNL, 1081' FWL, Sec. 6, T11N, R9W At top of productive interval 46' FSL, 275' FWL, Sec. 31, T12N, R9W At effective depth At total depth 2320' FSL, 703' FWL, Sec. 36, T12N, R10W 5. Type of Well: Development __X Exploratory i Stratigraphic _ Service_ 6. Datum elevation (DF or KB feet) RKB 116' feet 7. Unit or Property name North Cook Inlet 8. Well number A-1 9. Permit number / approval number 68-72 / 302-226 10. APl number 50-883-20016 11. Field / Pool Cook Inlet / Beluga 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Structural Conductor Surface Production Length Size 30" 16" 10-3/4" 7" 8279 7006 feet feet feet feet Cemented Driven 950 sx 865 sx 1098 sx Plugs (measured) Junk (measured) 7500-7700 Bridge plugs at7405'and 7156' Measured Depth True vertical Depth 388' 388' 614' 614' 2544' 2393' 7449' 6315' Perforation depth: measured 4085-6814' true vertical 3630-5822' Tubing (size, grade, and measured depth) Packers & SSSV (type & measured depth) 4-1/2" 12.75#, J-55, surface-4749' 3-1/2" 9.3#, J-55, 4749-5028' Otis BWB Packers @ 5028', 4986', 4856', 4749' Otis WSR retrievable packer @ 4000' 2-7/8" 6.5#, J-55,5028-692z~t: : :: :-:.: Otis TWR permanent packers ~ 4498' and 4298' Otis SCSSSV ~ 277' 13. Stimulation or cement squeeze summary Intervals treated (measured) N/A Treatment description including volumes used and final pressure 14. OiI-Bbl Prior to well operation N/A Subsequent to operation N/A Representative Daily Averaqe Production or Injection Data Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure - 15. Attachments Copies of Logs and Surveys run __ Daily Report of Well Operations _X Oil __ Gas __ XX Suspended __ Service. 17. I hereby' certify that the foregoing is true and correct to the best of my knowledge. Signed Tit!e Prob!em We!! Form 10-404 Rev 06/15/88 · Date ?//~/~ 2 SUBMIT IN DUPLICATE Date Comment NCIUA-1 Event History 05/13/02 06/05/02 09/10/02 09/11/02 09/12/02 STATIC BHP & SET SSSV MONITOR WELLHEAD SSSV CONTROL PRESSURE SET 4.5" PES PLUG AT 3900' WLM. DRAWDOWN TESTED 600 PSI --> 0 PSI, GOOD. SET DUMMY SSSV W/PX PLUG & PRONG IN SSSV NIPPLE AT 273' RKB. LOADED TBG ABOVE SSSV WITH 50/50 WATER/TEG, PRESSURE TESTED TO 1500 PSI (LEAKING, SUSPECT THRU FAILED NECK SEALS). SET BPV. BLEED TBG HANGER & IA TO ZERO. PURGE FLOWLINE, BREAK AT WING VALVE & REMOVE TREE. IN PROGRESS. REMOVE WELLHEAD (WITH NEW MASTER & SWAB VALVES). PT CONTROL LINE, MUSHY DUE TO GAS IN LINE. ATTEMPT PT TBG HANGER VOID, NO GOOD (KNOWN LEAK THRU TBG HANGER SEALS). PULL BPV. PULL PRONG & DUMMY SSSV/PX PLUG FROM SSSV NIPPLE. PULL PES PLUG. SET SSSV, CHECK SET (O.K.); CONTROL LINE HOLDING PRESSURE NOW DUE TO REPLACED NECK SEALS; DRAWDOWN TEST TO 200 PSI DIFFERENTIAL; O.K. RDMO. PULLED SSSV FROM 242' WLM - TAGGED FILL @ 5150' WLM Page I of I 9/16/2002 PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 M. Mooney Phone (907) 263-4574 Fax: (907) 266-6224 September 17, 2002 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Report of Sundry Well Operations NCIUA-1 (68-72 / 302-226) Dear Commissioner: Phillips Alaska, Inc. submits the attached Report of Sundry Well Operations for the recent operations on the Tyonek well NCIUA-01. If there are any questions, please contact me at 263-4574. Sincerely, M. Mooney Wells Team Leader Phillips Drilling MM/skad Jul 19 02 02:0~p P P~,)WELLS GROUP 90'7 ,~)59 7314 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of request: Abandon_ Suspend_ Operational shutdown _ Re-enter suspended well _ Alter casing _ Repair well _ Plugging_ Time extension _ Stimulate _ Change approved program _ Pull tubing _ Variance _X Perforate _ Other _ 2. Name of Operator Phillips Alaska, Inc. 3. Address P. O. Box 100360 Anchorage, AK 99510-0360 4. Location of well at surface 1252' FNL, 1081' FWL, Sec. 6, T11N, R9W At top of productive interval 46' FSL, 275' FWL, Sec. 31, T12N, R9W At effective depth 5. Type of Well: DevelopmenLX Exploratory _ Stratigraphic _ Service_ At total depth 2320' FSL, 703' FWL, Sec. 36, T12N, R10W (e~p'$ O, o) 6. Datum elevation (DF or KB feet) R KB 116' feet 7. Unit or Property name North Cook Inlet 8. Well number A-~I 9. Permit number / approval number 7z.. 10. APl number 50-883-20016 11. Field / Pool Cook Inlet/Beluga 12. Present well condition summary Total depth: measured true vertical Effective depth: Casing Structural Conductor Sudace Production measured true vertical Length Size 30" 16" 10-3/4" 7" 8279 7006 feet feet feet Junk (measured) feet Cemented Driven 950 sx 865 sx t 098 sx Plugs (measured) 7500-7700 Bridge plugs at 7405' and 7156' Measured Depth 388' 614' 2544' 7449' True vertical Depth 388' 614' 2393' 6315' Perforation depth: measured 4085-6814' true vertical Tubing (size, grade, and measured depth Packers & SSSV (type & measured depth) 3630-5822' 4-1/2" 12.75#, J-55, surface-4749' 3-1/2" 9.3#, J-55, 4749-5028' 2-7/8" 6.5#, J-55, 5028-6924' Otis BWB Packers @ 5028', 4986', 4856', 4749' Otis WSR retrievable packer @ 4000' RECEIVEID JUL 1 AIJI~ 0il & (?~ ~. ~missio~ Otis TWR permanent packers @ 4498' and 429B' Otis ball type SSSV @ 277' 13. Attachments Description summary of proposal __.X Detailed operations program _ BOP sketch _ 15- Status of well classification as: 14. Estimated date for commencing operation Immediately 16. If proposal was verbally approved ame of approver Date approved OiL Gas _X Suspended _ Service 17. I hereby certify that the foregoing is true and correct lo the best of my knowledge. Signed,~,~/e~'''* ,.,. Title: Problem Well Supervisor FOR COMMISSION USE ONLY Date Conditions of approval: Notify Commission so representative may witness I Approval no....~ _ 2_ Plug integdtyI BOP Test__ Location clearance _ I Approved by order of the Commission ~ O~ T _a~l' Commissioner Date ' , .. Form 10-403 Rev 06/15/88 · ORIGINAL SUBMIT IN TRIPLICATE 5 XN PBTD 7409' TD 8279' 614' 10 3/4" ~ 2544' Otis VSR packer ~ 3998' Cook inlet Sanda 4085-4095 Cl - A SQUEEZED 4116-4140 CI-B SQUEEZED pac~er~4296' 4351-4391 Cl- 1.0 4402-4482 Cl-2.0 packer~4498' 4516-4525 Cl- 3.0 4552-4588 Cl-4.0 4624.4674 Cl-5.0 4708-4738 Cl-6.0 packer~i4749' 47604784 Cl-6.2 packer~}4856' 4874-4856 Cl-8.0 4960-4972 Cl-9.0 packer~}4986' 5000-5012 C~10.0 packer~ 5027' 5044-5080 C~11.0 Beluga Sands 5590-5598 o-5 5604-5616 d-1 5663.5674 d-3 5679-5692 d-3 5708-5715 d-4 5874-5888 e-8 5892-5904 e-9 6076-6084 g-1 6098-6116 g-2 6271-6278 h-4 6509-6514 i-7 6578-6584 j2.1 6589-6602 j-3 6790-6756 m-2 6805-6814 m-3 BRIDGE PLUG ~ 7156 BRIDGE PLUG ~ 7405 7" ~ 7449' NCIUWELLA-I Completion Diagram IBPV(Make,TypetOD) FMC OCT TC - lA RKB-Drill Deck: 24.5' 'rl~l.Hgr.(Make,Type) FMC UH - IA RKB-THF: 38.90 Annulus Fluid: INHIBITED WATER WITH GLYCOL FOR FREEZE PROTECTION I RKB-SL: 116.00 TOC WATER DEl' IH: 120' 1RKB-ML: Production Casin~l: 30" SURFACE 386' I I I I 16" SURFACE 614' 65.00 H-40I I I I 103/4" SURFACE 353' 51.00 J-55I I I I I 10 3/4" I 353' 2544' 46.50 J-55 I I 7" I SURFACE +/- 78' 28.00 J-55 BUTT 5680 4330 I 415000 I 7" I +/- 60 6910' 23.00 J-55 BUTT 4980 3270 I 366O00 I 7" I 6910' 7449' I 26.oo J-55 t BUTT I 569O I 43301 415000 Tubing String: 4 1/2" 39 308' t2.6 Ib/ftJ-55 BUTT I 6620 5730 198OOO " 308' 4749' t2.75 Ib/ft J-55 EUE 8RD I 6620 I 5730 I 198000 4 1/2 31/2- I 4749 I 8028' I 9.3 Ib/ff I J-55 I EUE 8RD I 79801 74001 142500 2 7/8" I 6028 [ 4749' I 6.51b/ft ] J-55 RUE 8RD I 8300 j 78801 99700 ilii: :Nb"::: PRODUCTION TUBING STRING fi=MC TUBING HANGER ~ tl2" BUTTRESS TUBING & PUP JOINTS OTIS SCSSV NIPPLE 4 112" BUT'rRESS TUBING X-OVER 4 '1/2" RUE 8RD PIN TO 4 '1/2" BUTT BOX 4 1/2" RUE 8RD TUBING AND PUP JOINTS OTIS OVERSHOT SEALING DIVIDER O'135 RATCH LATCH OTIS IYPE VSR RETRIEVABLE PACKER 4 '1/2" RUE 8RD TUBING AND PUP JOINTS OTIS RATCH LATCH ' PACKER 4 1/2" RUE 8RD TUBING AND PUP JOINT ~ 1/2'" BLAST JOINTS 4 1/2" RUE 8RD PUP JOINT 4 1/2" OTIS XA SUDING SLEEVE [ tl2" RUE 8RD PUP JOINT OTIS RATCH LATCH OTIS TYPE 'I1NR PERMANENT PACKER IOINT /2"' BLAST JOINTS ~ 1/2" EUE 8RD PUP JOINT i4 112'" BLAST JOINTS ~ TUBING JOINTS .AST JOINTS 4 t/2" OTIS XD SLIDING SLEEVE 4 112'" BLAST JOINTS 4 1/2" RUE 8RD PUP JOINT 1/2" RUE 8RD BOX X 3 1/2" RUE 8RD PIN SEAL ASSEMBLY OTIS BWH PERMANENT PACKER SEAL BORE EXTENSION 3 1/2 8RD TUBING AND PUP JOINTS SEAL ASSEMBLY ~ERMANENT PACKER SEAL BORE EXTENSION TUBING ADAPTOR 3 '112"' BLAST JOINTS 3 '112" RUE 8RD PUP JOINT 3 '1/2 8RD TUBING AND PUP JOINTS 3 '112'" BLAST JOINTS 3 1/2" RUE 8RD PUP JOINT SEAL ASSEMBLY PERMANENT PACKER TUBING ADAPTOR 1/2'" BLAST JOINTS '112 OTIS XO SUDING SLEEVE 112" RUE 8RD PUP JOINT SEAL ASSEMBLY OTIS BWH PERMANENT PACKER SEAL BORE EXTENSION 7/8" OTIS XO SMDING SLEEVE 718" BLAST JOINTS 7/~" 8RD TUBING AND PUP JOINTS ' JOINTS 718" 8RD TUBING AND PUP JOINTS 718" BLAST JOINTS 2 718" 8RD PUP JOINTS 2 718" BLAST JOINTS 2 718" 8RD TUBING AND PUP JOINTS 2 7/8" BLAST JOINTS : 7/8" 8RD TUBING AND PUP JOINTS 2 718" BLAST JOINTS 2 718" 8RD TUBING AND PUP JOINTS : 718" BLAST JOINTS 2 718" 8RD TUBING AND PUP JOINTS 2 718" BLAST JOINTS 2 718" 8RD TUBING AND PUP JOINTS 2 7/8" BLAST JOINTS 2 718" 8RD TUBING AND PUP JOINTS 2 7/8" BLAST JOINTS 2 718" 8RD TUBING OTIS "X" NIPPLE 2 718" 8RD TUBING XN" NIPPLE 2 718" 8RD TUBING WIREUNE REENTRY GUIDE END OF TUBING BAKER RETRIEVABLE BRIDGE PLUG BOBCAT RETRIEVABLE BRIDGE PLUG PBTD ~ot~ ' Well History Original Completion 2/69 - 4-1/2 X 3-1/2 tubing at 4521' Cl A, B, 1.0, 2.0,3.0, 4.0, 5.0, 6.0,6.2, 8.0,9.0,10.0,11.0 and Beluga c-5 to m-3 Commingled After September 1992 Workover- Cl 11.0 & Beluga Open July 1996 - WL Selective, Abandon Cl 11.0 & Beluga due to water prouction Open CI 8.0 - 9.0 Sliding Sleeve Ictober 1996 - WL Selective, Abandon CI 8.0 - 9.0 due to sand production Open CI 1.0 - 2.0 Sliding Sleeve )ctober 1999 - Top of fill 4697' Updated: October 1999 By:. DKT PBTD: 7,409' I Supv:. Well: North Cook Inlet Unit No. A*01 ] Location: Lower Cook Inlet, Alaska Tbg Wt: .5" - 12.75 Ib/fi~ 3 1/2" - 9.3 lb/fi, 2 7/8" - 6.4 Ib/fi September 20,1994 Field: Cook Inlet Unit MPG Re: Tyonek Wells A-1 and A-8 Subject: Re: Tyonek Wells A-1 and A-8 Date: Fri, 19 Jul 2002 15:48:20 -0800 From: Winton Aubert <Winton_Aubert@admin.state.ak.us> Organization: AOGCC To: NSK Problem Well Supv <nl 617~ppco.com> CC: Thomas E Maunder <tom_maunder~admin.state.ak.us> Jerry, AOGCC hereby confirms verbal approval to produce N. Cook Inlet Wells A-1 and A-8 without functioning subsurface safety valves. This approval expires 10/01/2002. Hard copies of submitted Forms 10-403 will follow. Winton Aubert AOGCC 907 793-1231 NSK Problem Well Supv wrote: Winton: I just talked with the Tyonek Supervisor and he verified that all the SSV's on the platform (including A-1 & 8) are functional and passed their last tests. They are keeping them in good shape. Please let me know about your approval. Thanks! Jerry Dethlefs Phillips Problem Well Supervisor Winton Aubert <Winton Aubert@admin . state.ak, us> -- 07/19/2002 02:10 PM To: NSK Problem Well Supv/PPCO@Phillips cc: Subject: Re: Tyonek Wells A-1 and A-8 Jerry, Please include a statement regarding whether there are functioning surface safety valves (SSV) on these wells. Thanks, Winton Aubert AOGCC 907 793-1231 NSK Problem Well Supv wrote: > Winton: Attached are 10-403 forms, a discussion, and schematics for > Phillips Tyonek platform wells A-1 and A-8. As per your discussion with Len > Janson, a variance is requested to temporarily produce these two wells > without a SSSV. Our vendor should have the plugs and equipment to fix these > wells by the first of September and we plan on the repairs immediately > thereafter. I am faxing to your office a signed copy of the 10-403. I will > give you a call a little later this afternoon. Thanks! > > Jerry Dethlefs(See attached file: NCIUA-8 10-403 SSSV Remove 07-19-02. xls) > (See attached file: NCIUA-1 10-403 SSSV Remove 07-19-02.xls)(See attached > file: NCIUA-8 10-403 SSSV Remove 07-19-02.xls)(See attached file: NCIUA-1 > 10-403 SSSV Remove 07-19-02.xls)(See attached file: NCIUA-8 Schema ti c. xl s) Re: Tyonek Wells A-1 and A-8 > ~ (See attached file: NCIUA-1 Schematic.xls) > > Phillips Problem Well Supervisor > > 659-7224 Jul 18 02 02:04p PR~WELLS GROUP Jerry Dethlefs 907-694-9273 S07~59 7314 p.1 To: Winton Aubert From: Jerry Dethlefs Fax: 276-7542 Pages: 3 Phone: 793-1231 Date: 7/19/2002 Re: Tyonek Sundry's CC: [] Urgent x For Review [] Please Comment [] Please Reply [] Please Recycle · Comments: Winton: Attached are (2) Sundry 10-403 variance requests for Tyonek platform wells NCIU A-1 & A-8. i will give yom a call later today, or you can call me at 659-7224. Thanks! Jerry Dethlefs Phillips Alaska, Inc. RECEIVED JUL 1 9 ZOU/_ AllmlmOit&GmC, alm.~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation Shutdown__ Stimulate__ Plugging ~ Perforate __x__ Pull Tubing __X Alter Casing __ Repair Well Other X 2. Name of Operator: Phillips Petroleum Co. 3. Address: P.O. Box 1967 Houston, Texas 77251-1967 5. Type of Well Development Exploratory Stratigraphic Service 4. 'Location of well at surface: ' 1252' FNL & 1081' F At top of productive interval: 46' FSL & 275' FWL All effective depth: At total depth: 2320' FSL & 703' F , ~ , 12. Present well condition summary: Total Depth: measured true vertical Effective Depth: measured true vertical Leg 3, Slot 1 PPCo. Tyonek Platform A Sec6-T11N-R9W Sec 31 - T12N - R9W Sec 36 - T12N - R10W 8279 Plugs (measured) 7006 Junk (measured) I 6. Datum elevation (DF or RKB) RKB 116 7. Unit or Property Name North Cook Inlet Unit Feet 8. Well Number A-1 9. Permit Number / ApproVal Number 10. APl Number 50-883-20016 11, Field I Pool Cook Inlet / Beluga PBTD 7500-7700 Bridge Plugs at 7405 & 7156 ORIGINAL Casing: Length Structural Conductor Surface Intermediate Production Liner Perforation Depth: measured Size Cemented Measured Depth 30" Driven 388' 16" 950 sacks 614' 10 3/4" 865 sacks 2544' 7" 1098 sacks 7449' 4085' - 0814' True Vertical Depth 388' 614' 2393' 6315' RECEIVED true vertical 3630' - 5822' JAN 2 7 1995 Tubing (size, grade and measured depth) 4-1/2" 12.75 PPF J-55 surface - 4749' i~,l~$ka 0ii & Gas Cons. C0mmis,, 3-1/2" 9.3 PPF J-55 4749-5028 Anch0rz .~ 2-7/8" 6.5 PPF J-55 5028-6924 Packers and SSSV ( type and measured depth) Otis BWB permanent packers at 5028', 4986', 4856', & 4749'. Otis TWR permanent packers at 4498' & 4298'. Otis VSR retrievable packer at 4000'. Otis ball type SCSSV at 277'. 13. Stimulation or cement squeeze summary: Intervals treated (measured): Cement squeezed 4085' - 4140' Treatment description including volumes used and final pressure: Squeezed 4085' - 4140' w/250 sacks Class G to 2,000 psi 14. Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 41 O0 147.24 128 843 05/04/92 Subsequent to operation 0 8200 39.54 840 911 01/Ol/93 15. Attachments: Copies of Logs and Surveys Run __ Daily Report of Well Operations 10, 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 '~.~ ~ ¢~~-~--~ Title Principle Engineer Date 19-Jan-95 Form 10-404 Rev. 06/15/88 SUBMIT IN DUPLICATE J0~ WELL COMPLETION 614' IBPV(Mlke, Type.OD) ITbg. Hgr.(Make,Type) IAnnuius Fluid: ITOC: ~ OD ! Top FMC OCT TC -" IRKB.Orill I:)e~k: 24. FMC UH - lA i '~, IRKB-THF: 30.90 INHIBITED WATER WiTN GLYCOL I~.~.~,~:IEEZE PROTECTIONRKB-SL: 116.00 WATER DEPTH: 120' tRKB.ML: Bottom ' VVT I Grade i Conn. ] Burnt Coil I Tensn Production Casing: 30" I SURFACE J 388' 1 16.' f SURFACE 614' 65.00, H-40 10 3/4" J SURFACE ' 353' 51.00i J-55 103/4" ! 353' 2544' 46.501 J-55 T' I SURFACE ~ +/- 78' 28.001 J-55 Bu3-r 5680 T' +/- 60 : 6910' 23.001 J-55 43301 4150(X} 3270J 366000 7" 6910' 7449' 26.00! J-55 4330t 4150(X) Tubing String: i 4 1/2" 39 J-55 BUTT ', 6620' J-55 EUE 8RD I 1/2" ~ 308' 1/2" 308' 12.6 Ib/ft ~ 4749' : 12.751b/fi j 6620: 7/8" No. 4749 5028' ' 9.3 Ib/ft , J-55 J EUE 8RD I 7980i 5026 4749' 6.51b/ft I J-55 I EUE 6RD I 8300, Top ! Length i Description PRODUCTION TUBING STRING 57301 198000 57301 198000 74001 142500 76801 99700 ID j OD ; 81 i 273.50 I 80 i 277.121 31.1514 1/2" BUTTRESS TUBING 3.9501 4.540 i 79 308.271 4.75 IX.OVER 4 1/2" EUE 5RD PIN TO 4 1/2" BU'I"T BOX 3.9501 5.740 78 i 313.02 i 3672.17 t4 1/2" EUE 8RD TUBING AND PUP JOINTS 3.9581 4.500 77 i 3985.19' 12.24 IOTIS OVERSHOT SEALING DIVIDER 3.940J 5.980 i 3997.43 i 2.82 JOTIS RATCH LATCH 75 ~ 3998.6t t i 76 83 38.901 0.50 ~fFMC TUBING HANGER = 82 i 39.40 '~ 234.10 i4 1/2" BUTTRESS TUBING & PUP JOINTS 3.9501 4.540 3.62 IOTI$ SCSSV NIPPLE 3.8131 5.530 6.48 IOTIS TYPE VSR RETRIEVABLE PACKER 290.2114 1/2" EUE 8RD TUBING AND PUP JOINTS 2.62 IOTIS RATCH LATCH (NO LATCH) 4.78 IOTIS TYPE TWR PERMANENT PACKER 39.56 ~4 1/2" EUE 8RD TUBING AND PUP JOINT 74 i 4005.081 73 ~ 4295.30; 72 ~ 4298.481 71 i 4301.24~ 3.940 S.630 3.8801 6.ooo 3.958 1 4.500 3.9401 5.6301 4.50o! 5.875 3.950! 4.500 3.9501 5.5001 3.9501 4.500 70 ; 4340.80: 147.7514 1/2" BLAST JOINTS 69 I 4488.55 i 2.0814 1/2" EUE 8RD PUP JOINT 68 ! 4490.63 ~ 4.23 t4 1/2" OTIS XA SLIDING SLEEVE (OPENS UP) 3.8101 5.510 67 , 4494.86 i 2.0614 1/2" EUE 8RD PUP JOINT 3.958; 4.500 66 i 4496.92 ! 2.62 IOTIS RATCH LATCH {NO LATCH) 3.940i 5.830 4.76 IOTIS TYPE TVVR PERMANENT PACKER , 4.0001 5.875 3.958 4.500 3.950 5.800 65 ~ 4498.104 ~ 64 i 4502.86 i 8.0914 1/2" EUE 8RD PUP JOINT i 63 I 4St0.92. 19.72 i4 1/2' BLAST JOINTS ; 62 I 4530 67 20 22 4 1/2" EUE 8RD PUP JOINT 3.958 4.500 !61 '~ 4550:891 39:4014 1/2" BLAST JOINTS ! 3.950 5.600 I 50 I 4290.291 30.56 4 1/2" EUE 8RD TUBING JOINTS 3.9561 4.500 59 4620 851 78.8014 1/2" BLAST JOINTS ! 3.950 5.600 10 3/4" ~ 2544' i 58 4899.65 4.2414 1/2" OTIS XD SUDING SLEEVE (OPENS DOWN); 3.810 5.510 i 57 r 4703.89 39.40141/2,- BLAST JOINTS : 3.950 1 5.600 ! 55 4748.51 ! 0.84 i4 1/2" EUE 8RD BOX X 3 1/2" EUE 8RD PiN : 2.990 5.570 ~ 56 ; 4743.291 5.22 i4 1/2" EUE 8RD PUP JOINT i 3.950 4.500 i 54 ; 4749.351 10.13 JSEAL ASSEMBLY i 2.9701 4.470 53 I 4749 35 4 53 IOTIS BWH PERMANENT PACKER 4.0001 5.880 Otis VSR packer 52 4753:88t 7:49 JSEAL BORE EXTENSION 4.0001 6.050 I S0 4761.92 95.58 i3 1/2 8RD TUBING AND PUP JOINTS i 2.990 3.750 I 49 4857.50 t0 07 SEAL ASSEMBLY ' 2.970 4.470 48 4856.13 4 53 tOTI$ BWH PERMANENT PACKER 4.0001 5.880 4116-4140SQUEEZED, 45 4868.70/ 19.70 31/2"BLAST JOINTS i 2.9901 4.550 I 44 4888.40 / 10.15 t3 1/2" EUE 8RD PUP JOINT ! 2.990 3.750 43 I 4898.55 ~ 3.7213.S" OTIS XA SUDING SLEEVE (OPENS UP) i 2.750 4.2K ! 42 : 4902.27: 56.44 i3 1/2 8RD TUBING AND PUP JOINTS 2.990 3.750 packer ~ 4296' , 41 , 4957.71 i 19.70 J3 1/2'" BLAST JOINTS , 2.9901 4.550 ~ 40 ~ 4977.41 I 9 97 3 1/2" EUE 8RD PUP JOINT ! 2.9901 4.560 4351-4391 C - 1 39 ! 4987.38 i 10.13 JSEAL ASSEMBLY i 2.970 ~ 4.470 4402-4482 CI - 21 38 ; 4985.88 4.55 IOTIS BWH PERMANENT PACKER ! 4.000 / 5.875 37 4990.43 t 7.42 l SEAL BORE EXTP. NSION : 4.000 ~ 5.000 2.990 / 5.750 packer ~ 4498' ~ 36 I 4997.85 0.61 ITUBING ADAPTOR , i 35 4998.46 t 19.70 J3 1/2' BLAST JOINTS i 2.9901 4.550 4516-4525 CI - 3 33 ! 5021.77 6.0513 1/2" EUE 8RD PUP JOINT ! 2.990 4.550 4552-4588 CI - 4 32 I 5027.82 10.17 tSEAL ASSEMBLY I 2.970 ~ 4.000 4624-4674 CI - 51 31 5027.801 4.53 IOTIS BWH PERMANENT PACKER ! 4.000 5.272 4708-4738 CI - 6 30 I 5032.33 i 7.41 !SEAL BORE EXPANSION ' 4.000 5.032 I 29 ', 5039.74 0.62 ITUBING ADAPTOR ! 2 990 6.750 I 28 5040.361 3.1812 7/8" OTIS XO SLIDING SLEEVE (OPENS DOWN) ' ' i 2.313 3.750 ~ 27 ! 5043 541 39.40 J2 7/8" BLAST JOINTS i 2.4401 3.310 26 ! 5082.941 505.1012 7,'8" 8RD TUBING AND PUP JOINTS I 2.440 3.110 : 25 5588.041 29.5512 7/8" BLAST JOINTS 2.440 3.110 I 5617.59 39.11 }2 7/8" 8RD TUBING AND PUP JOINTS t 2.440 3.110 i 2.440 3.110 packer ~ 4749' 4760-4784 Cl - 7 i 24 I 23 5056.701 39.40 i2 7/8" BLAST JOINTS ' 22 5058.10 t 10.19 t2 Tm" eRD PUP JOINTS packer O 4856' i 21 I 5706.291 9.8612 7/8" BLAST JOINTS 20 I 5716.141 152.94 t2 7/8" 8RD TUBING AND PUP JOINTS 4874-4886 CI-8[ 19 ! 5869.08! 39.4012 7/8" BLAST JOINTS 5908.48 t 163.5412 7/8" 8RD TUBING AND PUP JOINTS 18 ~ i 17 t 6072.021 49.2512 7/8" BLAST JOINTS 4960-4972 CI - 91 16 ! 6121.271 148.0812 7/~" 8RD TUBING AND PUP JOINTS 9.85 ~2 7/8" BLAST JOINTS 15 ; 6269.35 J ~ 14 I 6279.201 227.1912 7/8" 8RD TUBING AND PUP JOINTS packer ~ 4986' 13 I 6506.39 ! 9.9512 7/8" BLAST JOINTS 12 i 6216.24 ~ 59.55 12 7/8" 8RD TUBING AND PUP JOINTS 6575.79 ~ 29.5512 7/8" BLAST JOINTS 5000-5012 C1-10 11 ~ 10 i 6805.34 ~ 180.8612 718" 8RD TUBING AND PUP JOINTS 5044-5080 C1-11 ' 9 ~ 6786.20; 29.5512 7/8" BLAST JOINTS 8 ~ 6815.751 31.1012 7/Il" 8RD TUBING ~ 7 6846.851 1.29 IOTIS "X" NIPPLE 34 XO ~oooo ! packer ~ 502T 559O-5598 5579-5692 5708-5715 5874-5888 55;2.56o4 6o7~o~4 50~-6116 6271-6278 65oe-6514 6570-65~ 655~o2 6790-6788 ~3s-5614 6848.14 ! 63.7512 7/8" 8RD TUBING 6911.89, 1.281XN" NIPPLE 6913.17; 9.9812 7~" 8RD TUBING 6923.15 t 0.49 iWIRELINE REENTRY GUIDE BRIDGE PLUG ~ 7156 BRIDGE PLUG (~ 74~ ~ 7'~ TD 8279' lEND OF TUBING ! 2.440 t 3.110 I 2.4401 3.310 · 2.440 3.110 ! 2.440 3.310 2.440 3.110 2.440 3.310 2.4401 3.110 2.440 3.310 ~ 2.440 3.110 ~ 2.4401 3.310 2.4401 3.110 2.440 i 3.310 2.440 3.110 2.440 3.310 2.440 t 3.110 2.205 i 3.23O 2.4401 3.110 2.2051 3.230 2.44t 3.110 2.441 4.500 2.411i 3.110 6923.64 i 7156.001 IBAKER RETRIEVABLE BRIDGE PLUG .. PLUGJ 7405.00 :, ISCHLUM. BOBCAT RP. IKIEVABLE BRIDGE 7409.00, iPBTD COOK INLET SANDS UCI-A 4085-4095 SQUEEZED UCI-B 4116-4140 SGUE-=7'ED C1-1 4351-4391 Cl-2 44O2-4482 Cl-3 4516-4525 Cl-4 4552-4588 CI-5 4624-4674 BELUGA SANDS "Middle" 5590-5598 5604-5616 5663-5674 5679-5692 5708-5715 5574-5888 5892°5904 6076-6084 6098-6116 6271-6278 "Lower" CI-6 4708-4738 6509-6514 CI-7 4760-4784 6578-6584 Cl-6 4874-4886 6.589-6602 Cl-g 4960-4972 6790-6799 C1-10 5000-5012 6805-6814 C1-11 5044-5080 744~ !PBTD: 7.409' ~Supv: !'rbg wt: IWell: North Cook Inlet Unit No. A-01" [ SelXen~M 20, 1994 ,L_n~_~m_n: Lower Cook Inlet. Alaska Field: Cook Inlet Unit MPG 4.5" - 12.75 lb/It, 3 1/'2" - 9.3 lb/It, 2 7/8" - 6.4 lb, i PHILLIPS PETROLEUM HOUSTON, TEXAS 77251-1967 BOX 1967 June 22, 1992 EXPLORATION AND PRODUCTION GROUP COMPANY ORIGINAL BELLAIRE, TEXAS 6330 WEST LOOP SOUTH PHILLIPS BUILDING Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: North Cook Inlet Unit A-1 Workover Program Attached are three copies of the Application for Sundry Approvals, form 10-403, and three copies of .the detailed workover program for the workover of the A-1 well on the North Cook Inlet Unit. Included in the detailed program are BOP schematics and the workover fluid program. If you have any questions concerning this workover or need any additional infOrmation please contact Dennis Morgan at (713) 669-2173. DCG:DRM/bcf CC: A. R. Lyons- Kenai W. R. Gibson (r) D. R. Morgan Central files Regards, D. C. Gill Drilling and Production Engineering Manager RECEIVED JUL - 2 1992 Alaska Oil & Gas Cons. t;ommissi0.ll Anchorage o,, .. APPLICATION FOR SUNDRY APPROVALS 1, Type of Request: Abandon __ Suspend __ Alter casing __ Repair well __ Change approved program __ Operation shutdown __ Re-enter suspended well ~ Plugging __ Time extension __ Stimulate ~ Pull tubing ~ Variance __ Perforate __ Other 2. Name of Operator Phillips Petroleum Company 3. Address P. O. Box 1967, HoUston, TX 77251-1967 4. Location of well at surface Platform A 1252' ~NL, 1081' F~E, sEc 6- At top of productive interval 46' FSL, 275' FWL SEC 31-T12N At effective depth 5. Type of Well: Development Exploratory Stratigraphic Service ]~ ,,_~ Leg 3 Slot 1, TIIN - R9W - R9W ,. At total depth 2320' ;FSI,, 703' ;FWL SEC 36 - T12N, RIOW 6. Datum elevation (DF or KB) AEB 116 7. Unit or Property name North Cook Inlet 8. Well number A-1 rmit number - 007 .... 10. APl number 50-- 883-20016 11. Field/POol feet 12. Present well condition summary Total depth: measured true vertical 8279' 7006' feet Plugs (measured) feet 7500'-7700' Effective depth: measured true vertical feet Junk (measured)--- .- feet Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: Length measured 4085'-6814' Size Cemented Measureddepth ~ueve~icaldepth 30" Driven 388' 388' 16" 950 Sacks 614' 614' 10-3/4" 865 Sacks 2544' 2393' 7" 1098 Sacks 7449' 6315' RECEIVED true vertical 3630'-5822' Tubing (size, grade, and measured depth) Packers and SSSV (type and measured depth) 13. Attachments 4" 10.9 PPF J-55 3~" a 9.3 PPF J-55 Otis RH packer at d U L - 2 1992 Surface - 4048r~la$-ka Oil & Gas Cons. uummissi( 4048 '-4521' ~ch0rage 4058' Otis WB packer at 4311' mt &515' Cmrnrn ~.qR-7 flmnnmr rvn~ .~.~.~V Description summary of proposal __ Detail~l operations program x BOP sketch x..x_ 14. Estimated date for commencing operation Augus,t 1, 1992 16. If proposal was verbally approved Name of approver Date approved 15. Status of well classification as: Oil ~ Gas ~ Suspended Service 1Z I hereby certify that the foregoing is true and correct to the best of m'! knowledge. FOR COMMISSIOIkJ USE ONLY Date ~,//X.~/'~ 2,- Conditions of approval: Notify Commission so representative may witness Plug integrity __ BOP Test __ Location clearance ~ Mechanical Integrity Test ~ Subsequent form required 10- ¥.n~ Approved by order of the Commission Original Signed By David W. Johnston IAppr°val,N°' ?~-~, ¢ Approved Copy Returned % Form 10-403 Rev 06/15/88 Commissioner Date ~//1~/~ ~ ~ SUBMIT IN TRIPLICATES~ PHILLIPS PETROLEUM COMPANY NORTH AMERICA E & P DRILLING OPERATIONS THIS IS NOT A TIGHT HOLE WELL: NCIU A-1 COUNTY, STATE: Tyonek, Ak. FIELD: North Cook Inlet Unit AREA: Kenai SURFACE LOCATION: Leg 3 Slot I PROJECT SPONSOR: L.C. Krusen 1252' FNL, 1081' FWL Sec 6-T11N-RgW J.J. Voelker BOTTOMHOLE LOCATION: 2320' FSI., 703' FEL SEC 36-T12N-R10W AFE: P-V123 BUDGET ITEM: 2C GROSS AUTHORIZATION: $1,567,400 PARTNERS, W.I.: Phillips 100% OBJECTIVE: Shut off intervals producing water and/or sand, reperfomte and/or stimulate unproductive intervals and isolate Cook Inlet and Beluga sands. Original (X) Supplement () Revision () APPROVED IN QUALITY PLANNING COMMITTEE: 4anuary 30, 1992 DRILLING ENGINEER DRILLING ENGINEERING DIRECTOR DRILLING SUPERINTENDEN'i'' D & P ENGINEERING MANAGER DISTRIBUTION: B.L Jones W.R. Gibson (r) C. A. Boykin W.L Carrico Development Supervisor (2) A.R. Lyons (r) LC. Krusen D.R. Morgan D.C. Gill H.J. Robinson (r) J.J. Voelker J.E. Stark (r) B.W. Baird A.L Sorrels Central Files RECEIVED L - ~ 199~ Gas [;0ns. bum~'tss'tot~ ~nch0rage NCIU A-1 WORKOVER PROCEDURE A® Be Ce De Ee Fe Ge I · J® Ke L· M® Ne O· INDEX OF PROCEDURES · APPROVALS AND INDEX GENERAL COMMENTS, WORKOVER OBJECTIVES AND WELL HISTORY · WORKOVER PROCEDURE A. ESTABLISH BARRIERS, INSTALL BOPS AND KILL WELL B. PULL EXISTING COMPLETION C. IDENTIFY AND SHUT OFF WATER PRODUCING INTERVALS D. TEST COOK INLET SANDS E. TEST BELUGA SANDS F. RUN NEW COMPLETION WELL CONTROL PROCEDURES WORKOVER/COMPLETION FLUID PROGRAM FISHING PROGRAM TEST PROCEDURES A. COOK INLET A AND B SANDS B. COOK INLET SANDS 1 THROUGH 11 C. BELUGA SANDS D. TEST TO DETERMINE SOURCE OF WATER PRODUCTION SQUEEZE PROCEDURES A. COOK INLET A AND B B. ANY OTHER INTERVALS STIMULATION PROCEDURES COMPLETION PROCEDURE SIMULTANEOUS ACTIVITIES GUIDELINES DIRECTIONAL SURVEY CURRENT WELLHEAD AND CHRISTMAS TREE DETAIL PROPOSED WELLHEAD AND CHRISTMAS TREE DETAIL CURRENT COMPLETION SCHEMATIC NCIU A-1 WORKOVER PROCEDURE P. PROPOSED COMPLETION SCHEMATICS Qe PORE PRESSURE PLOTS AND PRODUCTION LOG SUMMARY BOP AND RISER HOOK UP S. VENDOR LISTS T. PHONE LISTS ~")S STATE OF ALASKA), ~ A KA OIL AND GAS CONSERVATION C.~,v, MISSION ......... APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon [] Suspend [] Operation Shutdown [] Re-enter suspended well [] Alter casing [] Time extension [] Change approved program [] Plugging [] Stimulate [] Pull tubing [] Amend order [] Perforate [] Other ~ (S~SCS 2. Name of Operator 5. Datum elevation(DF or KB) Phillips Petroleum Company 4200 TVD RKB feet 3. Address 6. Uniter Property name P.O. Drawer 66 - Kenai, AK 99611 North Cook Inlet Unit 4. Location of well at surface Leg 3, Slot 1, 1252.28' FNL, 1080.84' FWL, Sec. 6, TllN, R9W, S.M. At top of productive interval 46' FSL, 275'FWL, Sec.' 31, T12N, R9W, S.M. At effective depth At total depth 2320'FSL, 703' FWL, Sec. 36, T12N, R10W, S.M. 7. Well number A-1 8. Permitnumber 68-72 9. APInumber 50-- 883-20016-00 10. Pool C~ok Inlet & Beluga 11. Present well condition summary Total depth: measured 7409 RKB feet true vertical 6283 RKB feet Effective depth: measured feet ' true vertical feet Plugs (measured) RECEIVED Junk (measured) NOV 0 5 ]~ · ~.~.D ] -.~,'i~__,~..: i*A.~,,.~,,~ ~~'-.~,' , ~ . ,, .... ' ' ~ Casing Length Size Cemented Measured dept~~~¢~~pth Structural -- Conductor 30" -- 388 Surface 16" Surface 614 Intermediate 10 - 3/4" Surface 2544 Production 7" 2557' ~ ~B 8279 Liner Perforation depth: measured (~B) 4085-4140 4351-4482 4552-5080 5590-6814 388 614 2383 7006 true vertical (R_KB) 3623-3670 3847-3957 4014-4440 4841-5811 Tubing (size, grade and measured depth) 4" 10.9PPF J-55 3-1/2" BHA ' 2-7/8" BHA Packers and SSSV (type and measured depth) 1) SSSV 3-1/2" Baker A-3 SSCSV @ 283.34' MD RKB 40.23-4048.24 MD RKB 4048.24-4311.28 MD RKB 4311.28-4520.99 MD RKB 2) Packers - see schematic 12.Attachments Description summary of proposal ~ Detailed operations program [] BOP sketch [] (See Cover Letter ) Well Schematic ~ 13. Estimated date for commencing operation March 14, 1990 14. If proposal was verbally approved (replace SCSSV with SSCSV) Name of approver Mr. M. Minder Date approved May 8, 1990 15. I hereby certify that the foregoing.is true and correct to the best of my knowledge Signed _< Title District Manager Commission Use Only Conditions of approval Notify commission so representative may witness I Approval [] Plug integrity [] BOP Test [] Location clearance I DateNov. 1~ 1990 .o. Approved Copy Re}urned ORIGINAL SIGNED BY I \! J~ ~ LONNIE C. SMITH Approved by ,,.,'--~""~--~'""J Commissioner :orm 10-403 R~1.,2-1-85 J - v) by order of ,, / ,-, I.,~... the commission ~ Sub'it iB RKB NCIU WELL NO. A-I - COOK INI ~ ALASKA SC ;ATIC TO TUBING HANGER 'OP== Kay 1:3, 1971 W. J. t~x~/~! I. D. - Inches ITEM 3.~76 ~" 10.~ J-55 B~ttresm ~g. string RKB -Top== 2.760 3~" Drive Pipe at' 388' EEB 16" 65~ H-~O csg. · 613.59 R~B Cemented to ~u~f&ee 10-3/~" ~5.~[~ (Botts) ar~ 51~ (?op) J-55 csg. e 25&3.77' REB Cemented to Surface 2.992 Crossover A" to 3~" tbg. string 2.750 Otis 3~'_' .X,' Nipple 2.991 Camco .:}~" ~.75o Otis 3~" Polished Nipple 2.900 Otis ?" x 3~" R~-! Packer (b) 3.O00 ~aker &~" Blast Jts: 2.750 Otis 3t" "XO" Sliding Sleeve 2.625 O~is 3~" "Q" Nipple 3.000 Otis Locator & ~:' x 3 ft. Seal Assy, 2.313 Otis 2-7/8" "XO" Sliding Sleeve 2.313 Otis 2.-7/8" "X" Nipple 2.380 Otis 3~" x 6 ft. Seal Aosy. 2.~1 Otis 2-7/8" Mule Shoe 7" 2~ J-55 ~ange Jr. in top of string ~tt~ Latch Dua~ Valve (b) 3o,ooo~ Shear (~) RECEIVED Upper Cook Inlet Perle. &O85' -~liO' ( 3&' ) Otis 7" x &" WB Pkr. e &311' Cook Inlet Perle. &351'-~482' (120') O~is 7" x 3~" WA Pkr. e i515' Cook Inlet Perfs. 7" S~age Collar Beluga Perle. &552'-5080' (200') 50%.31 ' 5590'-681~.' (151') Top of 26/ J-55 ceg. · 6909.65' (c) 7" 2M & 26~ J-55 cag. I 7/g,.9.o8' Cemented back t,e 255?' by 2 Stage (CB~) PHILLIPS PETROLEUM KENAI, ALASKA 99611 DRAWER 66 PHONE: 907 776-8166 EXPLORATION AND PRODUCTION GROUP Western Exploration and Production Division Kenai District RE: Sundry Approval for SSCSV Mr. Lonnie C. Smith State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Dear Mr. Smith: COMPANY November 1, 1990 In accordance with 20 ACC 25.265 (2), this is to request AOGCC's formal approval of th'~' Sub-Surface Controlled Safet~ Valve (SSCSV) presently installed in the North Cook Inlet UnitWell A-1. An Application for Sundry Approvals ForTM 10-403 is attached for this purpose. Control line pressure to the well's Surface Controlled Sub-Surface Safety Valve (SCSSV) was lost on January 10, 1990. Various tests indicate that the sealing surface has been compromised on the valve landing nipple's upper polish bore (i.e. lock packings). Numerous attempts have been made to regain the seal (oversize packings, different packing materials and arrangements, teflon sealant, etc.), but all have been unsuccessful. On March 14, 1990, a Baker 3-1/2" A-3 SSCSV was first installed for trial purposes. After several more attempts to regain a SCSSV control pressure seal, an SSCSV design was finalized and run on May 8, 1990. The successful SSCSV test results were transmitted via facsimile to the AOGCC office, and verbal approval for the SSCSV installation was received. The Well A-1 SSCSV is currently equipped with a 67/64th's orifice and a single spring spacer. The valve is tested quarterly along with all of the other NCIU SCSSV's, except that the uncontrolled flow condition is simulated by briefly choking the well back and then quickly opening the choke. Please direct any questions to L.C. "Fritz" Krusen, our Senior Production Engineering Specialist. Yours sincerely, H.L. Patterson District Manager HLP/LCK/eh att. E~P~~ OF NATURAL ~ Division of Oil and Gas Conservation Director ~ Hoyle H. H~ai'ltcn '/~/£~ Chief Petroleum En~lvt' . June 1, 1978 Harold R. Hawk/ns Petroleum ~tor ~f' Rewitness subsurface safety valve (SSSV) and surfaoe safety valves (SSV) plus high and lc~,¢ pilots, Phillips PlatfolIa North Cook Inlet ~n~day, May 19, 1978 - I left Anchorage to Kenai at 8:00 AM by AAI, arriving in Kenai at 8:30 AM. I walked to F~mai air service ~ere I was to get a chopper ride to Phillips platfonn. Purpose of trip to rewitness safety valves that failed last test cn 4/20/78. I arrived on the platform at 12:10 PM. I mat Bob Gamble, the supervisor for Philips platfc~m. Bel~¢ are the results of the tests: A-6 A-ii Pilot Flow PSI - Test PSI SSSV ~_SV 1400 900 OK OK OK CK 1375 875 OK f~{ (~ 1500 1000 OK OK OK 1400 900 OK OK OK In s~: I r~itnessed the abcu~ indicated ~fety valves plus high and 10w pilots that failed in prev~ tests on the Phillips platform. Retests were satisfactory. Atta~t Satisfactory Type Inspection Yes No Item ( ) Location,General () () () () () () ~<) ( ) () () () () () () 1. Well Sign 2. General Housekeepina R. Reserve Pit-( )open( )filled ( ) ( ) 17 4. Rig. ~ Safety Valve Tests __ 5. Surface-No. Wells ~_~ 6. Subsurface-No. Wells / - ( ) Well Test Data 7. Well Nos. , , , 8. Hrs obser , , 9. BS&W , , , Satisfactory Type Insp.ection Yes No Item ( ) BOPE Tests ( ) ( ) 15. "Casing set ~a ( ) ( ) 16 lesL fluid-( )wtr. ~-)mud ( ) oil Master Hyd. Control Sys.- psig ( ) ( ) 18 H2 btls. , __,__,__psiq ( ) ( ) 19 Remote Controls ( ) · ( ) 20 Drilling spool- I'outlets ( ) (.) 2t Kill Line-( )Check valve ( ) ( ) 22 Choke Flowline ( )HCR valve () ( ) 23 Choke Manifold No. valvs flas ( ) ( ) 24 Chokes.-( )Remote( )Pos.(-~dj. ( ) ( ) 25 Test Plug-( )Wellhd( )csq( )none ( ) ( ) lO. Gr. Bbls., , , ( ) ( ) 26 ( ) Final Abandonment ( ) ( ) 27 ( ) ( ) 11. P&A Marker ( ) ( ) 28 ( ) ( ) l>'. Water well-( )capped( )plugged ( ) ( ) 29 ( ) ( ) 13. Clean-up ( ) ( ) 30 ( ) ( ) 14. Pad leveled ( ) ( ) 31 Annular Preventer,_ _?sia Blind Rams, psia Pipe-Rams ~psiq Kelly & Kelly-cock psig Lower Kelly valve psim Safety Floor valves-~- --)-BV ( )Dart Total inspection observation time hrs/days Total number leaks and/or equip, failures Remarks ~F~b'7' ~ ///~-z.~z_~5 .7-/~,/,~-/'=~/z,~!~ ~/~~ ~ o ' ...... ~ .............. r - - . ;- .~' -,' · - ; ' - Z . - ,/ .... .2-~.~_f~~ , ~~~e~o x.a ~ _ ~ ~.~::~--~ ~::~ -~_./Tz~~ F~n ,,~, , ....... .... ~~~ ~ z/~~~~ __ ~ ~ ...... ~. , _ _._~..~.~ ..... . cc:.~J.~ 4 zzTF~ ~ot~fy ~n~-ys or ~hen , eady~tnspected by~~f~X~2.?ate~~~ Form 10-403 REV. 1-10-73 Submit "1 ntentions" 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.) 1. Ow~LLLDWELLGAS [~ OTHER 2. NAME OF OPERATOR 3. A D D R E~BB-~dPE RATO R 4. LOCATION OF WELL Atsurface Leg 3, Slot 1, 1252.28' FNL, 1080.84t FY.L, Sec. 6, TllN, Rgw., S.M. BHL 2320' FSL, 703' FWL, Sec. 36, T12N, R10W., S.M, 13. ELEVATIONS (Show whether DF, RT, GR, etc.) RKB 116 ' from MLLW 14. CheCk Appropriate Box To Indicate Nature of Notice, Re 5. APl NUMERICAL CODE 50-.283~20016 6. LEASE DESIGNATION ANO SERIAL NO. ADI~-37831 7. IF INDIAN, ALLOTTEE OR TRIBE NAME ., 8. UNIT, FARM OR LEASE NAME 9. WELL NO. 10. FIELD AND POOL, OR WILDCAT North. Cook T. nlet 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) See Item 4 BHL 12. PERMIT NO. 68-72 3orr, or Other Data NOTICE OF INTENTION TO: TEST WATER SHUT-OFF L_.J PULL OR ALTER CASING L-~ FRACTU R E T R EAT MU LTI PLE COMPLETE SHOOT OR ACIDIZE ABANDON* REPAIR WELL CHANGE PLANS (Other) Cle an out SUBSEQUENT REPORT OF: WATER SHUT-OFF ~ REPAIRING WELL FRACTURE TREATMENT ALTERING CASING SHOOTING OR ACIDIZING ABANDONMENT* (Other) (NOTE: Report results of multiple completion on Well Completion or Recomp!etion 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. Install 12"- 3000# WP riser and 12"-3000# WP double gate preventer and H~rdril. Test BOP and riser. 2. Pull 4" 'tbg and retrievable pack.er. 3. Clean out to 7409 PBTD. 4. Run combination 4" x 3 1/2" tubing string with. Otis subsurface safet~ valve set about 283' RKB and Otis retrievable packer set about 4050 MD RKB, and tubing set 6820' MD RKB. 5. Install tree and displace mud with water. Set hydraulic packer., Test packoff, 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 8/1/75. TITLE Sr. Petroleum Engineer DATE 7/15/75 16. I hereby certify that th~f~g~g Is true and correct~ (This sl~ace for State office use) APPROVED BY CONDITIONS OF APPROVAL, IF ANY: T IT LE DATE See Instructions On Reverse Side PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99501 ~ 515 "D" STREET EXPLORATION AND PRODUCTION DEPARTMENT June 26, 1969 Mr. T. R. Marshall, Jr. Division of Mines & Minerals Department of Natural Resources State of Alaska 3001 Porcupine Drive Anchorage, Alaska Gent lemen: As per your request, please find copies of blue line Electrical Logs for NCIU,~~ #A-2, #A-3 and #A-~. If at all possible, these blue lines will be furnished with Completion Reports, in the future. Yours truly, JBG: jo Attachment HILLIPS PETROLEUM COMPANY District Office Man,er 10, .J 2 3 4. 6 6 7' 8 910 RECEIVED ,!U~ ~ 1969 DIVISION OF OIL AND GAS ANCHOP~.GE 2 3 4 5 67 8 9100 2 3 4 5 G 7 8 ,9 10 Form No. G-1 ~E¥1$ED : JAN. I ~ IgGt OIL AND GAS, CONSERVATION COMMIT'fEE SUBMIT" 1~ DUPLICAT~ Initial GAS WELL "OPEN FLOW POTENTIAL'ffEST REPORT Test [~r/ Annual D special OlJer;tJo~-'~-~ ' ~ I Lease - ' IV;ell Xo. · ................ , ~1 ~US~ .............. ' ~i~ t~ o~eetion Type Taps ~.:~. '/. < ,' o:% ~ .................... t Time 4~') -~q~ek~-~-- Press Diff. ' 'Tubing Casing - Flowing .~o. of Flow (Line) (Orifice) : ,>, h Press. .~ Press. Temp.. · ' Hours Size ' Size psig w . psig psig *F '~% s, ~' .... ,.....~ / ~z,:~ ~.~ ~,~ . ~::~' .~ .... /q.~. ' . . .~/~- ~. './:~ ......... ,~ ..~:~ /~ /~?~ ..... 7~.. FLO%¥' CALCULATIONS Coeffi- - ...... ' Flow Temp. ' t~Iravlty ' Compress. Ho. clentV-'~/hw P ~ Pressure Factor · Factor Factor Rate of Flow (24 Hr.) m psia : F 'F F q MCF/D t g pv ,. -.~-.?'-: / ~' ,..7.,~. - .~ ..... '" ' P.O& ¢"'Y ",'~:>'>'~:._',., ~,:a"_-:./' ' '/.oe;,3,-'. //, ,. t P' -~-~z' ...'c}~m,,'X . ,, ?:~ ,>/ . ~: ........ ), o~q: ~-m~,_~..~ PRESSURE CALCULATIONS FORM SA- i B TO[- O. K. Gilbreth, Jr. EMORANDUM ' State of Al,aska DIVISION OF OTT. AND GAS Chief Petroleum Engineer FROM: Robert E. Larson Petroleum Engineer DATE : May 28, 1969 SUBJECT: Multipoint Flow Test North Cook Inlet Unit 1-A On May 22, 1969, I traveled to the Phillips North Cook Inlet Platform to witness a four-point flow test on their 1-A well. The well was arranged to flow through a line heater to a variable choke, then through a test separator, and m~,ter to a pressure regulator, where the final pressure drop was taken. No arrangements had been made to use a bottom hole pressure recorder as all reliance was being placed on the use of tubing pressures taken with a deadweight tester. Static pressure at the meter was also spot-checked with a deadweight tester. Start of the test was delayed until 3:00 p.m. because of time needed,to finishthe rigging-up of the deadweight tester. Four flow rates were established. The static tubing pressure was 2021 psi' at the start of the test. Flowing tubing pressures were taken at fifteen minute intervals after each new flow rate was established. During the first three flow .. rates the flowing pressure increased after the first pressure reading was taken. The increase was generally in one or two psi increments,. Tubing pressure behavior during the final flow rate was erratic because the pressure held steady for two, fifteen minute intervals then dropped eleven psi, then increased two psi, and then again dropped three psi. The flow rate was constant during the time of fl0w so it was believed that the minor differences in pressure would be inconsequential to the final calculations. Mr. Porter, Phillips' engineer, thought that this behavior was caused by formation of hydrates in the tubing. No liquids, either hydrocarbon or water, were trapped in the separator. The well was shut-in at 8:50 p.m. and by 9:00 p.m. the tubing pressure had increased to 2033 psi. The increase in shut-in pressure at the end of the test as compared to the start of the test can be attributed to either a warmer gas column in the tubing, a better cleanup of the well allowed increased communication between the well bore and the formation, or a combination of both. It is possible that the test results might be erratic because of the large interval o~en to production and the possibility of cross flow between perforated intervals. REL:jm PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99501 ~ 515 "D" STREET EXPLORATION AND PRODUCTION DEPARTMENT April 2~, 1969 Division of Mines and Minerals Department of Natural Resources State of Alaska 3001 Porcupine Drive Anchorage, Alaska 9950~ Attention: Mr. T. R. Marshall, Jr. Gent lemen: We believe we~f~krnished you field prints of the Induction Electrical Log on We ~-l-1)tand #A-3. Enclosed please find finished prints of same. Yours truly, ips / District Office Manager JBG: jo Attachments :' ., ' : reverse s~de) ' ~[VJ~Jo~ oF o~: ~::v ~,s OIL AND GAS CONS~AT~N COMMITTEE : ! - ~ ~-~ _ ~ - : AND * ' : ~ELL ~QM,~LEI!.OH,.,.QR,R~OM~LEiIO~,~R~RI , LOG' la TYPE OF WELL OIL ~ ~AS f'~ ~ :~ ~i:~ :"~' --- -- ~b. TYPE OF COMP'LEmON: ~':'::: : ~ .: , ,b~ ..~ ,i ADDRESS OF OPERATOR ~ : -'. , " 515 "D" ~et. i~he~e. Aq~s~ 995~ ~ ~ ~ ~,'::, , ~,,-. <. ,- - At top prod. interval reported below -,~ ~-,: ' : ~"~ ~'27~' ~, ~e; 3:, ~,i? '.~'~ S.~.- At total dep~ 23~' r~ · 7o~' ~9 '~:,.~, SPUDDKD 14. DATE T.D. 15. DATE CO'M~, SUSP= O~ ABAND. t0-~-6~ ~OW ~Y* ~.D'F, RKB,~ RT, a0T~i~ ToOL~' TYPE EL,ECTRIC AJ~TD OTHER CASING SIZE 10-"t - . - LINER P,,E C 01:~ ~' TOP (MD3 CASING P-,~X)RD (Report all strings DEPTH S~T HOLE SIZE (MD) SACKS 2a.. PElf'ORATIONS OPEN TO (Interval, size and ·., . :! "t .., INTERVALS -DR[I~LED BY C~SLE TO6LS ~NAL SURV'~Y '~e8 .,:- · DATE FIlleT PI~bUCTION [ PRODUCTION METHOD CFlowh~. ~s lift. pumrh~--~tize al~ type o{,P~P) -., '~. S'I'A'II~'S C~,~'odlicir~i0r _ · ot nr~due~d ve~ : :.: Flow :2 ~ ":~.._ :' , '~' , ':':. : .... __~-=~ ~~ien Te~$ :~ not 31. DISPOSITION OF GAS (~0lg, ~ ~ el, v~ted, etc.) ' '~' EST wITNESSED BY ~ut-~ 32. LIST OF , 33. I hereb~ cer~y t~at the tore~lng~d at~ched information l~ complete and ~r~t a~ determined from all:available r~cords SIGNED TITLE ·(~e J.,.~cfio., ~.J ~ ~ -INSTRUCTIONS ' ! ~ General: Th;is form is designe roi ~ '"~' subm,tt~ng a complete and correct well comple~ion report end log ~, all types of lands'and leases:in 'Alaska.. I .... ',..: - -- r - Itm: 16: Indicate which eleva4ion is ~-~e'a ~ reference (where nol othe~iset~hown) for de : measure' , '. ments given in othe~ spaces ont~his_ form ~d in any:,~ attachments .... ~ .l. s..o:'" 'k-i': ' Item~_ 20, rand 22:: If this welJ .is com~let~'~ for separate production from more th~n 'one interval~ zone.o (multiple co'mpletion), so state in item~:'20,. A,nd.. . in item 22 ~o~ ~the prcducing interv~l,~, oft. interval~,.. 'top(~)~ bottom(s) and name (s) (if any) f6r~bq~y,the interval :rep, S. ted in "item 30. Submit a separate re~rt (page) on this ·form. edequatel~-identif~, f~r .e.ch ~ition~l"i~te, v~l to ~ seper~tely~ pro~c~,l~h0~.~' ' '' '/f ing the e~itionel data pertin~t to such~idtbF~.l. · ': ~;--o ': :-... ~ ~'~ I~m26: "~cks Cement": Att~hjed supplemental . for . :. reco~s ~hj~:well should show the detnil~ of'any~mOl- ~ tiple stage cementing nn~ the ioc.hon.~of.-th~,: c~menti~g tool.:,.::: .- ~.,. ': ?S' ':~ sep~rnt~y produ~. ~: Item 28: Submit ~ ~pnrate ; ..... ' co~plehon-re~rt .~n this~jJform fo~ ;'~ch interval to ~. , (~ instruction for items 20 and.:"~22 a~e):' ~. ~ o? _ ~ .... ,~ "'- -0 ~ ) . ' "' C.:~. ~ ' SECTION B GENEI~AL COMMENTS WORKOVER OBJECTIVES WELL HISTORY RECEIVED GENERAL COMMENTS While the workover is in progress the Drilling Supervisor has overall responsibility for the workover activity. The Lead Operator has responsibility for the production activities and routine operation of the platform. The Drilling Supervisor and Lead Operator are expected to maintain close communications. In the event of an emergency the Drilling Supervisor is designated "Person in Charge". Safety is the top priority in conducting this workover program. Production from the other 11 wells on the platform will continue throughout the course of the workover. This will result in simultaneous activites on the platform. These activities will be performed following the procedures found in the North Cook Inlet Unit, Platform A, standard Procedure Guidelines for Simultaneous Activities. A copy of the Standard Procedure Guidelines for Simultaneous Activities is included as section K of this program. There may be occasions when the other wells in wellroom 3, wells 2 through 8, will need to be shut in to continue with the workover. This could occur for such activites as nippling up and down the X-mas tree and risers, or welding on the new flowline. ~This work can be planned for in advance so that the impact on pr6duction is minimal. When this situation arises, the wells should be shut in and the workover activity should proceed. However, if the wells are required to meet the deliverability requirements of the plant then the workover activity should wait until such time as the wells can be shut in. The delivery requirements of the plant are more important than the workover. To minimize the potential for lost rig time due to conflicts with the production operations, close communication between the Phillips Drilling Supervisor and the Platform Lead Operator will be required. This workover is intended to shut off a water producing interval and to answer several reservoir questions. The procedure, particularly with regard to restoring production from intervals that are not producing, will be subject to change based on the results observed. WORKOVER OBJECTIVES: 1. Identify and shut off intervals producing water. · Test Cook Inlet sand to confirm all zones that should be 'producing are producing and to gather reservoir data to refine the reservoir model. · · · · · Reperforate/Stimulate any Cook Inlet sands not producing· Test Beluga sands tO confirm all zones that should be producing are producing and to gather reservoir data to refine the reservoir model. Reperforate/Stimulate Beluga intervals not producing. Run completion with multiple packers for proper zone isolation. Begin producing well, initially from Beluga adding Cook Inlet when needed. WELL HISTORY AND CURRENT CONDITION: The well was drilled in 1968 and completed as a commingled Cook Inlet and Beluga producer in 1969. The well is completed with an Otis RH retrievable packer set at 4058, an Otis WB permanent packer at 4311 and an Otis WA permanent packer at 4515. The two permanent packers were set on wireline. The seal assemblies were then run as part of the tailpipe for the RH packer, and were stabbed into the sealbore of the WB and WA packers. The tubing ends a~ 4521. A schematic drawing and detailed description of ~he current completion is shown in section O. The Cook Inlet A and B sands were to produce through a XO sliding sleeve at 4211. The Cook Inlet 1 and 2 sands produce through a XO sleeve at 4412. The remaining intervals, including 7 additional Cook Inlet sands and 15 intervals in the Middle and Lower Beluga produce from below the WA packer. A plot of the current pore pressure vs depth is shown in section Q. Note that the pressure gradient decreases from about 8.3 ppg in the Cook Inlet B sand to about 5.4 ppg in the Cook Inlet 11 sand and then increases to about 7.5 ppg in the Middle and Lower Beluga. The Cook Inlet 3 sand was below a gas water contact and has never been perforated in this well. The well is equipped with an FMC-OCT wellhead and X-mas tree. A drawing of the tree is shown in section M. Test plugs, wear bushings and any required wellhead service will be supplied by FMC. Both permanent packers have leaked since their original installation in 1969. This well was to have been worked over in the 1975 workover program to repair these leaks, however this workover was not performed. This well began producing water in 1987. The water production rate has increased to approximately 200 bpd. Production logs have shown that the water is produced from the intervals above the WA packer. The water is probably produced from the CI B sand from 4116 - 4140. The XO sliding sleeve at 4211 was cloSed in an attempt to shut off the water. This was unsuccessful since the packer is leaking. This interval will be abandoned during the course of the workover. Production logs were ran on this well in 1986, 1987, 1988, and 1991. A summary of the 1991 log result is included in section Q. In 1990 the DSHV control line failed. A velocity valve was installed, replacing the surface controlled valve, and production resumed. The sands in this well are highly permeable. A small reduction in the pressure at the perforations can result in very high flowrates. Be sure that all personnel are aware of this and understand the importance of following good well control practices. Crews should be alert for any indications of flow and prepared to shut in the well and circulate through the choke at any time. SECTION C WORKOVER PROCEDURE 'PROCEDURE Establish barriers, install BOPs and kill well: Wells are category three, 2 tested barriers are required to ND tree. Al. A2. A3. A4. a¸5. RU wireline lubricator and test to 2000 psi. Pull velocity valve. Install plug in X nipple at 4048'. Bleed off pressure to test plug from below. Load well with KCL water, see workover fluid section E for kill fluid recipe. Note: The fluid column does not qualify as a second tested barrier. The density of the fluid column is adequate, however the volume of fluid is insufficient to contain the well. The fluid column is needed to facilitate testing of the plug in the DHSV nipple. A6. Install and test a plug in the DHSV nipple using the volume measurement method as follows:. ae Pressure up on the tubing to 2000 psi. Be Bleed off the pressure carefully measuring the volume bled back. C. Pressure up the tubing to 2000 psi a second time, then run a blanking plug and set the plug in the DHSV nipple while holding the pressure on the tubing. De Bleed off the pressure carefully measuring the volume. If the plug is holding, the volume bled back should be about 10% of the volume measured in step B. A7. AS. A9. Install BPV Skid rig over well. ND tree. Back out the tubing hanger hold down bolts and remove the 16 3/4" hold down plate from tubing hanger before nipping up the riser and BOP. Note: Tree should be sent to FMC for inspection, repair, and addition of a second master valve. Al0. NU and test riSer and BOP to 3000 psi. See the well control section of this procedure for additional details concerning BOP tests and well control requirements. Ail. Retrieve BPV, blanking plug, and deep plug. Al2. Kill well with kill fluid. Sized salt pills are recommended if needed for fluid loss control. Note: In view of the long perforated interval below the tubing tail the best way to kill the well may be to use coiled tubing to circulate the well with kill fluid. This may be faster and more cost effective than lubricating kill fluid into the well. Note: See attached workover/completion fluid, section E, for additional details and contingency plans for workover fluids. Pull existing completion, clean out to TD: BI. Screw DP into tubing hanger and pull on DP to release Otis RH packer. Limit pull to 150,000 lbs hookload. The OtiS RH packer is a pull to release packer, rotation is not needed. Note: Be prepared for gas bubbles anytime, but espec~911y when a packer is released. B2. If pipe does not come free, see attached fishing program for additional details on fishing for packer and tailpipe. Note: The two permanent packers were set on wireline. The two seal assemblies were run as part of the tailpipe below the RH packer. If either of the seal assemblies is stuck it will be necessary to cut the tailpipe to release the RH packer. B3. If pipe does come free circulate at least one full hole volume before POOH. Be prepared to shut well in and cirCulate through choke as there may be significant volumes of gas trapped below the packer. B4. POOH w/tubing, packer, tailpipe and seal assemblies. Pull slow to avoid any tendency to swab. Note: Tubing is to be checked for NORM contamination Note: A detailed description of the completion equipment presently in this well is found in section O. The tubing in the well includes 4" and 3 1/2" as well as several blast joints and other tools. Have handling tools available to cover both sizes of tubing in the well. B5. RIH w/ packer milling and retrieving tool and mill over slips of WB packer. Retrieve packer. B6. RIH w/ packer milling and retrieving tool and mill over slips of WA packer. Retrieve packer. B7. After all tubing has been recovered, RIH w/ 6" bit and clean out to PBTD at 7409'. Identify and shut off water/sand producing zones. Test 1: Most likely water/san4 source - Cook Inlet B san4 Cl. RU Schlumberger and run Ultrasonic Inspection Tool. Note: These logs are to determine if behind pipe communication exists and to determine the condition of the casing. C2. RIH w/ Schlumberger Bobcat Retrievable Bridge Plug (RBP) and set at + 4000'. C3. Test casing to 2000 psi. C4. Move RBP to 4300'. The RBP should be between CI B sand and CI -_ 1 sand. Dump sand on top of RBP. C5. Displace well w/ test fluid. C6. RIH w/ test tools and test CIA and B sands. See the detailed test procedures, section G. Note: The CI B sand is the zone believed to be the major water producer in the well. This test is to confirm this belief. C7. POOH w/ test tools C8. RIH and squeeze perfs in CIA and B sands. See attached squeeze procedures, section H. Note: NCIU A-l: A & B, 55' gross, 34' net, C9. Drill out cement and test perfs to 2000 psi. Resqueeze as necessary. Test 2: Cook Inlet Interval D1. Move RBP to between Cook Inlet and Beluga, RBP should be set at + 5200'. D2. RIH w/ test tools. See the detailed test procedure, section G. Alaska Oil & gas ;ons. D3. Test Cook Inlet interval. At least 2 flowing passes will be made with PLT tools at different rates. One rate should be high enough to produce large enough drawdown for all CI sands to be producing. (Surface equipment will be designed for 20 MMCFD rates.) D4. If test produces significant volumes of water, the water source will be isolated and shut off. If test shows some intervals are not producing they will be reperforated and the test repeated. If the interval still does not produce it will be isolated and tested alone and stimulated if necessary. Beluga Test: performed last to minimize time spent with kill fluid across Beluga before production begins. El. Move RBP to below bottom Beluga perforation. Set RBP at ± 6900'. E2. RIH w/ test tools. See the detailed test procedure, section G. E3. Test Beluga interval. At least 2 flowing passes will be made with PLT tools at different rates. One rate should be high enough to produce large enough drawdown for all Beluga intervals to be producing. (Surface equipment will be designed for 20 MMCFD rates.) __~ E4. If PLT shows fluid covering any Beluga perfs. RIH w/ coiled tubing and use nitrogen lift water out of well. E5. If test produces significant volumes of water, the water source will be isolated and shut .off. If test shows some intervals are not producing they will be reperforated and the test repeated. If an interval still does not produce it will be isolated and tested alone and stimulated if necessary. E6. After all work to restore Beluga production is complete, a single layer in the Beluga will be tested to provide deliverability data. The reservoir engineer on location will determine which interval to test. Kill the well and move the RBP to below the interval to be tested. E7. RIH w/ test tools to conduct buildup and drawdown tests of the Beluga interval. Test as required. ES. Kill well, displace to completion fluid and POOH with test tools and RBP. Run new completion - See detailed completion procedure, 'section J. Fi. RIH w/ subassembly 1, shown in section P, including 2 7/8" tailpipe, profile nipples, blast joints, sliding sleeves and permanent packer. Set packer to isolate Beluga from CI. F2. Jet in Beluga to minimize time spent with any completion fluid across Beluga. F3. Set plug in XN nipple in 2 7/8" tailpipe. Bleed off pressure and load well with completion fluid. F4. Run subassemblies 2 through 6 as per section J. Note: Final completion design is subject to change depending on results of CI tests and on cement qUality, however preliminary design is shown in the schematics. Note that in order to obtain the desired zone isolation several packers are needed. All sliding sleeves are to be run in the closed position. F5. Run subassembly 7. Prior to latching seal assembly into packer reverse circulate to displace well with packer fluid. F6. Set and test DHSV, set BPV. -_ F7. ND BOP, NU tree. Connect flowlines. Since an extra master valve is being added, new flowlines will be needed. Note: Tested barriers will include the completion fluid currently in well and the DHSV. The plug.in the XN nipple of the 2 7/8" also qualifies as a tested barrier for the Beluga interval. Untested barriers would include the closed sliding sleeves in combination with the production packers and the back pressure valve. F8. Retrieve BPV, and the DHSV. F9. RIH w/ coiled tubing and displace completion fluid with nitrogen. Fl0. Recover plug from 2 7/8" tailpipe. If the plug cannot be retrieved the 2 7/8" tailpipe will be perforated above the plug. Fll. Install and test DHSV. Fl2. Turn well to production, initially producing from Beluga. Production will open sliding sleeves to produce Cook Inlet sands as they feel necessary. SECTION D WELL CONTROL PROCEDURES Well Control This well is a category 3 well, as defined in Phillips Completion Workover and Well Control Policy. As such two tested 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 3 1/2" 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. 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. A large number of trips can be expected during the course of this workover. It is vital that good well control practices be followed during the course of these trips. Trip speed while POOH should be kept relatively slow ~o 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. M~INTAINING CONTROL OF THE WELL IS OF THE UPMOST IMPORTANCE, TRIP SPEED IS SECONDARY. Both of the permanent packers are leaking; therefore, 26 different intervals between 3630' and 5822' TVD (4085' - 6814' MD), are effectively commingled at the present time and cannot be isolated until the existing completion is removed. A pl°t of reservoir pressure, based on the RFT results from 'the Sunfish No. 1 and production logs ran in wells A-i, A-3 and A-7 is shown in section Q. Note that the mud gradient varies from an 8.3 ppg equivalent in the Cook Inlet B sand to a 5.4 ppg equivalent in the Cook Inlet 11 sand. The Beluga sands will have a slightly . higher pressure than the Cook Inlet sands because of the water that has accumulated in the wellbore and inhibited flow from the Beluga. The production log from the A-1 shows that the water accumulation now covers the Cook Inlet 10 and 11 sands in addition to the Beluga. The top of the water accumulation as identified on the log is at + 4900', The results from the A-9 workover should be used to update the reservoir pressure data. The variations in gradient and the long interval between the tubing tail and the bottom perforation may make it difficult to kill the well and could create well control problems throughout the workover with sand. There is a possibility that the lower pressured intervals will not support a fluid column adequate to control the higher pressured intervals withoUt addition of a bridging agent to the workover fluid. A premixed pill designed to bridge off the lower pressured zones should be maintained in one of the mud pits until the well has been cleaned out to TD. If the well cannot be made to stand full, then well control can be maintained by constantly pumping workover fluid down the annulus. 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. SECTION E WORKOVER FLUID PROGRAM Workover Fluid Program The base fluid for the workover is 2% KCL water. Fluid density will be 8.4 ppg. Kill fluid: This fluid will be used for the initial kill operations and will be used while cleaning out the existing completion and circulating out any fill that has accumulated in the wellbore. The initial volume of kill fluid should be built using the fluid left in the pits from the workover on the A-9 well. Fluid Properties: Weight: 8.4 Total hardness: less than 100 ppm KCl concentration: 7 ppb For additional fluid loss control use pills of workover fluid containing 3 ppb Xanvis (XC polymer). The polymer should be hydrated and sheared properly to obtain the maximum low shear rheology. If additional fluid loss is required LCM pills of Literal XCP pill will be used, The volume of the pill and the amount of bridging agent to be used will be determined based on the rate of loss. Saturate the system with LiteSal (borate salts) and add 2 - 3 ppb Liteplug fine to the circulating system. Then spot the LCM pill across the thief zone. Should additonal fluid loss control be needed for seepage control while working with the thief zones open, add 15 ppb LiteSal XCP and 5 ppb pH-6. This will viscosify the system to suspend additional bridging agent. Then add 5 - 10 ppb Liteplug if needed. Sweeps containing 3 PPB Xanvis should be used as needed for hole cleaning while circulating out the sand. Screens on the shaker should be as fine as possible without blinding. Sand that is circulated out should be sampled to insure it complies with the NPDES permit and diposed of overboard. If the sand cannot be disharged overboard it will be collected in bins and sent to shore for disposition. Test Fluid: Cook Inlet A and B test Test fluid is to be clean workover fluid. After setting the RBP at 4300', build the required volume of clean base workover fluid as was used for the initial kill fluid. Displace the well with the clean fluid and store the kill fluid either in the girder tanks or in the mud pits. Conduct the test of the Cook Inlet A, and B as required. Kill the well with clean workover fluid. This gradient in this interval is expected to be about $ ppg so fluid loss control is not expected to be a problem. If fluid loss control is needed use Xanvis pills. After test is complete continue using the fluid-in the well to squeeze the Cook Inlet A and B, and to drill out the cement. Test Fluid: Cook Inlet i through 11 test After the RBP has been moved to 5200' dump the cement contaminated system and build a clean fluid with same composition as above. Displace the well with the clean flUid. If Xanvis or Litesal was needed for fluid loss control previously a polymer breaker will be needed to obtain a valid test. If this is the case spot .a pill containing sodium hypochlorite across the Cook Inlet interval to-be tested, i.e. from 5200' to 4300'. The concentration- of sodium hypochlorite will vary from 1-2 55 gallon drums per 50 bbls of workover fluid dependent on the volume and composition of fluid lost in the well. Let this pill soak while POOH with the drillpipe and RIH with test tools. The.pill will act to break the polymer required for fluid loss control and will be produced during the test. After the test is complete, fluid loss control may be needed in the kill fluid. If so use the kill fluid previously stored. Test Fluid: Beluga test After the RBP has been moved to TD displace the well with clean fluid with same composition as above. Fluid loss control should not be required for the Beluga so the polymer breaker will not be needed. Likewise fluid loss control should not be needed to kill the Beluga. Completion flui~ Continue using the Beluga test fluid as the completion fluid. After setting subassembly 1 and installing the plug in the XN nipple, it may be desirable to spot another sodium hypochlorite pill across the Cook Inlet 1 through 11. This would be advised if fluid loss control was needed to kill the Cook Inlet interval after the Cook Inlet test was complete. If this is required, spot the pill across the Cook Inlet perforations and let it soak for 1-2 hours. Then displace the well with clean workover fluid and run subassemblies 2 through 6. Packer fluid. After RIH with subassembly 7 reverse circulate with packer fluid containing corrosion inhibitor. Leave 4 barrels of glycol in the top of the tubing X casing annulus to act as freeze protection. SECTION F FISHING PROGRAM Fishing Program This well produces water, presumably from the Cook Inlet B sand at 4116 - 4140. There is a high probablity that the tailpipe below the retrievable packer will be stuck in the seal bore of either the WB or the WA permanent packer. If the tailpipe is stuck it will need to be cut before the retrievable packer can be released. The following outlines the steps to cut and pull the packer and tailpipe, and mill up the permanent packers. A detailed description of the completion equipment presently in this well is found in section O. The tubing in the well includes 4" and 3 1/2" as well as several blast joints and other tools. Have handling tools and fishing tools available to cover all sizes of tubing and the completion tools found in the well. Assuming the initial attempt to pull the packer in step BI has failed, proceed as follows, adjusting the procedure as needed based on the fish to be recovered: · RIH with a chemical cutter and cut the 3 1/2" tailpipe in the center of a joint of tubing immediately above the Otis Q nipple. The Q nipple is at 4309' so the cut should~ ~e made at about 4295'. Use a CCL to insure the cut is made near the center of the joint. · Pull on DP to release to release Otis RH packer. Limit pull to 150,000 lbs hookload. · If packer is still stuck make a chemical cut in the 4" tubing above the packer. The cut should be made at about 4035' and near the center of the joint. 5. POOH and LD tubing. Note: Tubing is to be checked for NORM contamination. · RIH w/ overshot and jars· Latch onto fish and jar fish out of hole. · Continue RIH w/overshot and jars. Latch onto fish and jar fish out of hole until seal assembly stabbed into WB packer has been retrieved. · The seal assembly stabbed into the WA packer may be stuck. If it is stuck and cannot be jarred out in step 7 make a chemical cut in the 3 1/2" tubing at_+ 4500' , then jar the fish out of the hole. · RIH w/ packer milling and retrieving tool, and jars. Mill over slips on WB packer and POOH w/ packer. Note: Casing is 23 lb/ft J-55. Take care in milling up packer to minimize risk of milling a hole in the casing. 10. RIH w/ overshot and jars. Latch onto fish and jar seal assembly out of WA packer. 11. RIH w/ packer milling and retrieving tool, and jars. Mill over slips of WA packer. 12. POOH with packer. 13. After WA packer and its tailpipe have been recovered, RIH w/ a 6" bit and clean out to PBTD at 7409'. ~ES~ PROCEDURes RECEIVED d U L - 2 1992 ~aska Oil & Gas bu~s. ~,ummission /~lchorage DRILL STEM TEST PROCEDURES These tests will follow the guidelines for conducting drill stem tests on bottom supported marine rigs found in Phillips Drill' Stem Testing Manual. Bottomhole pressure'is anticipated to be 1200 psi for each test. The produced fluid will be dry gas and possibly water and/or sand. Rig up surface equipment as shown on the attached schematic. The preferred location for the surface equipment will be located on the rig pipe rack between wellrooms 1 and 2. The flare boom should be located on the NW corner of the platform near the existing process flare. The test manifold should be Piped to permit gas t'o flow either to the rental separator or to the platform test separator. This will allow the .gas to be flared during clean up flows but sold during extended flow tests. The exact routing of the line to the test separator will be determined. Ail surface equipment upstream of the separator is to be rigged up and hydrostatically tested to 1500 psi. After the hydrostatic test is complete and any leaks repaired, retest using nitrogen or helium to 1500 psi. All'piping is to be securely snubbed down. Any piping downstream of the separator but upstream of the last-v&lve before the burner boom should be tested to 100 psi over the operating pressure of the platform test separator. NCIU WELL TESTS SURFACE EQUIPMENT TO PRODUCTION__ TEST SEPARATOR TO BURNER BOOM SEPARATOR SCRUBBER LINE HEATER 8AND TANK COOK INLET A AND B DST BEGIN TEST, FLOW WELL END TEST DOES WELL PRODUCE WATER? YES ~ NO II SQUEEZE INTERVAL STIMULATE ZONES NOT PRODUCING YES END TEST NO YES SHOULD INTERVALI BE SQUEEZED? ARE ALL PERFORATED INTERVALS PRODUCING AS EXPECTED? YES NO PERFORATE ZONES NOT PRODUCING W/ THRU TUBING GUNS I ARE ALL PERFORATED INTERVALS PRODUCING AS EXPECTED? COOK INLET ']% AND B Test Objective: Verify interval produces water and sand Procedure: · Displace well with test fluid, see workover fluid section E for test fluid recipe. · · RIH w/ DST tools as shown on the attached schematic. The PCT valve should be run in the closed position So that the pipe is dry. Set Bobcat Retrievable Bridge Plug (RBP) at 4300' and Positrieve packer at ± 4000'. · Install test tree· Rig up flowlines and surface equipment. Pressure test the entire surface system. All lines upstream of the separator should be tested to 1500 psi. Any piping downstream of the separator but upstream of the last valve before the burner boom should be tested to 100 psi over the operating pressure of the platform test separator. · Fill drillpipe with nitrogen'and pressure up on drillpipe to 1100 psi. · Close the pipe rams, and pressure up on the annulus to open the PCT valve. Cycle the valve to the held open position. Open the choke at surface and permit the well to clean up.through the separator. If the well does not flow at high enough flowrates to lift the water volume below the PCT valve, use gas from the platform to kick the well off. If the well cannot be kicked off using gas from the platform then coiled tubing and nitrogen should be used to jet the well in. · Continue flowing the wei1.. Flow the well at various rates ranging from 0 - 20 MMCFD, monitoring for water and sand production. Note the flowrate where sand production can be detected. The flowrates and lengths of the flow periods at each rate will be determined by the reservoir engineer on location. The well is to be flowed at a high enough rate to maximize the drawdown thereby insuring that all the intervals are producing. Production logs are planned during this test to determine the contribution from each of the sands and to determine the pressure in each sand. Production logs should be ran at flowrates lower than the flowrate that produces sand in order to avoid cutting the electric' line with sand. 8. Close the tester valve and open the MIRV reversing valve. · Reverse circulate taking returns through the separator until the tubing is full of kill fluid and well is dead. 10. POOH w/ test tools and prepare to squeeze this interval. If this interval does not produce water and sand the zone will not be squeezed but will be isolated with packers during the final completion so that the remaining reserves in the A ~nd B can be produced. DST TOOL STRING TEST 1 COOK INLET A AND B TEST TREE 3 1/2' DRILLPIPE TO SURFACE SHORT REVERSING VALVE I STAND 3 1/2' DRILLPIPE MIRV REVERSING VALVE I STAND 3 1/2' DRILLPIPE PCT VALVE W/ HOLD OPEN HYDROSTATIC REFERENCE TOOL POSITRIEVE PACKER COOK INLET I- 11 DST ' I YES /'~ NO ! ARE ALL PERFORATED END TESTI ~,. .,2' I INTERVALS ,PRODUCING "' RUN TESTTO ~ YES /L DETERMINE INTERVAL(S) ~ END TEST I !, ~.~ ,~s~I I SHOULD WATER ZONE(S) BE SQUEEZED? I SQUEEZE INTERVAL(al ..o.uc,:.. ADDITIONAL 8TIM ULATION PROCEDURE TO BE DETERMINED NO YES NOT PRODUCING W/ THRU TUBING GUN8 ARE ALL PERFORATED INTERVALS PRODUCING AS EXPECTED? Y ! STIMULATE ZONES I NOT PRODUCING ARE ALL PERFORATED INTERVALS PRODUCING A8 EXPECTED? cOOK INLET S/~NDS i THROUGH 11 Test Objective: Verify all perforated intervals are producing as expected, reperforate or stimulate any zones not producing, identify' any zones producing water and or sand, and gather reservoir data to update the reservoir model. Procedure: I · · Displace well with test fluid, see workover fluid section E for test fluid recipe. RIH w/ DST tools as shown on the attached schematic. The PCT valve should be run in the closed position so that the pipe is dry. Note: If the Cook Inlet A and B have not been squeezed use the DST tools that will be used for the Beluga test with the MFE valve instead of the PCT valve. 3. Set packer at ± 4300'. · Install test tree. Rig up flowlines and surface equipment. Pressure test the entire surface system. All lines.upstream of the separator should be tested to 1500 psi.__ Any piping downstream of the separator but upstream of the last valve before the burner boom should be tested to 100 psi over the operating pressure of the platform test.separator. · Fill drillpipe with nitrogen and pressure up on drillpipe to 1100 psi. · Close the pipe rams, and pressure up on the annulus to open the PCT valve. Cycle the PCT valve to the held open position. Open the choke at surface and permit the well to clean up through the separator. If the well does not flow at high enough flowrates to lift the water volume below the PCT valve, use gas from the platform to kick the well off. If the well cannot be kicked off using gas from the platform then coiled tubing and nitrogen should be used to jet the well in. 17. Continue flowing the well. Flow the well at various rates ranging from 0 - 20 MMCFD, monitoring for water and sand production. The flowrates and lengths of the flow periods at each rate will be determined by the reservoir engineer on location. The well is to be flowed at a high enough rate to maximize the drawdown thereby insuring that all the intervals are producing. Production logs are planned during this test to determine the contribution from each of the sands and to determine the pressure in each sand. If the production logs show workover fluid covering the lower zones, RIH w/ coiled tubing and use nitrogen to lift the water out, then continue testing. · If water production was observed during the test, review the production log results to determine which zone appears to be the most likely source of the water, and continue with steps 9 through 12. If the test did not produce water skip to step 13. 9. Close the PCT valve and open the MIRV reversing valve. 10. Reverse circulate taking returns through the separator until 'the tubing is full of kill fluid and well is dead. 11. RIH and latch onto RBP. Move RBP to just below the highest zone identified as a possible source of the water from the production logs. 12. POOH w/ annulus pressure operated test tools. Skip to test procedure entitled "Test to determine source of water production", page 20. 13. If the production logs show any interval to be non productive, perforate the non productive interval with 4 spf using 2 1/8" hollow steel carrier thru tubing perforating guns and deep penetrating charges. 14. After perforating, open the choke at surface and resume flowing the well through the separator. Flow the well and rerun the production logs as in step 6 above. If flow from the interval has resumed continue with test procedure. If interval is still not productive then the interval will be stimulated. Refer to the appropriate stimulation procedure in section I. 15. Close the PCT valve and open the MIRV reversing valve. 16. Reverse circulate taking returns through the separator until the tubing is full of kill fluid and well is dead. 17. POOH with test tools. DST TOOL STRING TEST 2 COOK INLET 1 THROUGH 11 TEST TREE 3 1/2" DRILLPIPE TO SURFACE SHORT REVERSING VALVE I STAND 8 1/2' DRILLPIPE MIRV REVERSING ~,LVE I STAND ~1 1/2' DRILLPIPE PCT VALVE W/ HOLD OPEN HYDROSTATIC REFERENCE TOOL POSlTRIEVE PACKER BELUGA DST BEGIN TEST, FLOW WELL I DOES WELL PRODUCE WATER? I YE8 END TEST RUN TEST TO DETERMINE INTERVAL(S) PRODUCING WATER SHOULD WATER BE SQUEEZED? NO IRETEST I CONDUCT BUILDUP/DRAWDOWN TEST ON ONE SAND YES ~ NO I SQUEEZE INTERVAL(S) PRODUCING WATER END TEST ADDITIONAL STIMULATION PROCEDURE TO BE DETERMINED NO YES IDENTIFY INTERVALS NOT PRODUCING AS. EXPECTED? END TEST PERFORATE ZONES NOT PRODUCING W/ TCP GUNS I IRETEST ,,I INTERVALS PRODUCING AS EXPECTED? 8TIM ULATE ZONE8 NOT PRODUCING I ARE ALL PERFORATED INTER. L8 PRODUCING A8 EXPECTED? I YES BELUGA TEST PROCEDURE Test Objective: Verify all perforated intervals are producing as expected, reperforate or stimulate any zones not producing, identify any zones producing water and or sand, and gather reservoir data to update the reservoir model. Procedure: l® Displace well with test fluid, see workover fluid section E for test fluid recipe. · RIH w/ DST tools as shown on the attached schematic. The MFE valve should be run in the closed position so that the pipe is dry. · Set packer at ± 5500'. Close pipe rams. Note: The mechanically operated DST tools needed for this test are operated by manipulating the drillpipe. Space out the drillsting to insure that the drillpipe can be manipulated as needed to operate the tools with the pipe rams closed. · Install test tree. Rig up flowlines and surface equipment. Pressure test the entire surface system. All lines upstream of the separator should be tested to 1500 psi. Any piping downstream of the separator but upstream of the last valve before the burner boom should be tested to 100 psi over the operating pressure of the platform test separator. · Fill drillpipe with nitrogen and pressure up on drillpipe to 1100 psi. · Close the pipe rams, and slack off on the drillstring to open the MFE Valve. Cycle the MFE valve to the held open position. Open the choke at surface and permit the well to clean up through the separator. · Rig up coiled tubing unit on top of the test tree, open the choke at surface.and begin RIH with the coiled tubing and use nitrogen to lift water from below the packer. · Run the coiled tubing to 6900' and continue jetting with nitrogen to lift water off of all perforated intervals. 13 · Continue flowing the well. Flow the well at various rates ranging from 0 - 20 MMCFD, monitoring for water and sand production. The flowrates and lengths of the flow periods at each rate will be determined by the reservoir engineer on location. The well is to be flowed at a high enough rate.to maximize the drawdown thereby insuring that all the intervals are producing. Production logs are planned during this test to determine the contribution from each of the sands and to determine the pressure in each sand. Note: If any zones are not producing an attempt should be made to surge the existing perforations. To do this close the MFE valve, bleed the wellhead pressure to 0, and open the MFE valve. 8. Close the MFE tester valve and open the MIRY reversing valve. · Reverse circulate taking returns through the separator until the tubing is full of kill fluid and well is dead. 10. If water production was observed during the test, review the production log results to determine which zone appears to be the most likely source of the water, and continue with steps 11 and 12. If the test did not produce water skid ~o step 13. 11. RIH and latch onto RBP. Move RBP to just below the highest zone identified as a potential source of the water from the production logs. 12. POOH with test tools. Skip to test procedure entitled "Test to determine source of water production,,, page 20. 13. RIH w/ tubing conveyed perforating guns and DST tools per attached schematic to reperforate any non productive intervals. 14. Run correlation log to locate TCP guns to perforate desired intervals and set packer. 15. Close the pipe rams, and slack off on the drillstring to open the MFE valve. Rerun the correlation log to verify the guns are on depth. Note that a RA tag is included below the packer for the second correlation log. This is to verify that the drillpipe movement needed to set the packer did not affect the gun setting depth. ~4 16. Fill the drillpipe with nitrogen and fire guns by pressuring up on the drillpipe to the required pressure then bleeding off to the pressure needed for 500 psi underbalance. Bottomhole pressure data for determining underbalance will be determined from the production logs ran in step 7. After perforating, open the choke at surface and permit the well to clean up through the separator. Flow until well has cleaned up, 17. Close the MFE tester valve and open the MIRV reversing valve. 18. Reverse circulate taking returns through the separator until the tubing is full of kill fluid and well is dead. 19. POOH with TCP guns, check guns to verify all shots fired. 20. Repeat steps 2 through 13. If production logs show an interval is still not productive it will be stimulated. Refer to the appropriate stimulation procedure in section I. 21. The reservoir engineer will select a zone in the Beluga for drawdown and buildup testing. Move the RBP to below the zone to be tested. 22. RIH w/ DST assembly for buildup and drawdown, tests per attached schematic. Run MFE valve in the closed_position so that pipe is dry. Set packer above zone to be tested. The final configuration of the tool string below the packer will be dependent on the space available between the packer and'RBP. 23. Install test tree. Rig up flowlines and surface equipment. Pressure test the entire sur.face system. All lines upstream of the separator should be tested to 1500 psi. Any piping downstream of the separator but upstream of the last valve before the burner boom should be tested to 100 psi over the operating pressure of the platform test separator. 24. Fill drillpipe with nitogen and pressure up to' the reservoir pressure measured in step 7. 25. Close the pipe rams and slack off on the drillpipe to open the MFE valve. Open the choke at surface and permit the well to clean up through the separator. 26. Conduct drawdown and buildup tests well as directed by reservoir engineer on location. Surface readout pressure gauges will be used. 27. Close the MFE valve and open the MIRV reversing valve. ~5 ¸28. 29. 29. 30. Reverse circulate taking returns through the separator until the tubing is full of kill fluid and well is dead. POOH w/ test tools. RIH and latch RBP. RIH to TD and displace well with filtered KCL water for final completion, see workover fluid section E for completion fluid recipe. POOH w/ RBP and prepare for final completion of well. DST TOOL STRING TEST BELUGA TEST TREE S 1/2' DRILLPIPE TO SURFACE SHORT REVERSING VALVE I STAND 3 1/2' DRILLPIPE MIRV REVERSING V~,LVE I STAND 8 1/2' DRILLPIPE MFE VALVE W/ HOLD OPEN 1 STAND 3 1/2' DRILLPIPE JARS SAFETY JOINT POSITRIEVE PACKER TUBING CONVEYED PERFORATING TEST TREE 1/2' DRILLPIPE TO SURFACE SHORT REVERSING VALVE I STAND 8 1/2' DRILLPIPE MIRV REVERSING VALVE I STAND ;3 1/2' DRILLPIPE MFE VALVE W/ HOLD OPEN 1 STAND 8 1/2' DRILLPIPE JAR8 SAFETY JOINT POSlTRIEVE PACKER 8 1/2' DRILLPIPE AND PUPS AS NEEDED TO SPACE OUT RADIOACTIVE MARKER PORTED SUB 3 1/2' DRILLPIPE AND PUP8 A8 NEEDED TO SPACE OUT FIRING HEAD- INTERAL PRESSURE PERFORATING GUNS DST TOOL STRING TEST 5 BELUGA DRAWDOWN/BUILDUP TEST TEST TREE ;3 1/2' DRILLPIPE TO SURFACE SHORT REVERSING VALVE I STAND 3 1/2' DRILLPIPE MIRV REVERSING VALVE I STAND 3 1/2' DRILLPIPE MFE VALVE W/ HOLD OPEN I STAND ;3 1/2' DRILLPIPE JAR8 SAFETY JOINT POSiTRIEVE PACKER BUNDLE CARRIERS TO BE DETERMINED TEST TO DETERMINE soURCE OF WATER PRODUCTION Objective: Identify intervals producing water. le RIH w/ DST tools per attached Schematic. MFE valve should be run in closed position. 2. Set packer above uppermost zone expected to produce water. · Install test tree. Rig up flowlines and surface equipment. Pressure test the entire surface system. All lines upstream of the separator should be tested to 1500 psi. Any piping downstream of the separator but upstream of the last valve before the burner boom should be tested to 100 psi over the operating pressure of the platform test separator. · Fill drillpipe with nitrogen and pressure up to reservoir pressure of interval being tested. · Close the pipe rams and slack off on the drillpipe to open the MFE valve. Open the choke at surface and permit the well to clean up through the separator. · Continue flowing the well. 'Flow the well at. various rates ranging from 0 - 20 MMCFD, monitoring for water and sand production. · After the test is complete, close the MFE valve and bleed off the gas inside the drillpipe. · If this interval does not produce water, RIH and lower the RBP to below the next zone that might produce water, reset the packer above that zone and repeat steps 3 through 8. If this interval does produce water and there are other intervals that may also produce water, lower'the RBP to below the-next zone suspected of water production and reset the packer above the zone and repeat steps 3 through 8. · After all zones suspected of producing water have been tested, open the MIRV reversing valve and reverse circulate taking returns through the separator until the tubing is full of kill fluid and well is dead. 10. POOH w/ test tools. 11. The intervals producing water may be squeezed per the appropriate squeeze procedure in section H or may be isolated by packers in the final completion. 2O DST TOOL STRING TEST 4 DETERMINE WATER SOURCE TEST TREE 8 1/2' DRILLPIPE TO 8URFACE SHORT REVER81NG VALVE I STAND .,I 1/2' DRILLPIPE MIRV REVERSING ~,LVE 1 STAND 8 1/2' DRILLPIPE MFE VALVE W/ HOLD OPEN I STAND 3 1/2' DRILLPIPE JAR8 8AFETY JOINT PO81TRIEVE PACKER SECTION H SQUEEZE PROCEDURES SQUEEZE PROCEDURE Send samples of cement, additives, and mix water to Dowe11- Schlumberger for testing at least 4 days prior to squeeze job. Bradenhead Squeeze Procedure for A and B sands. The' interval to be squeezed is as follows: Cook Inlet A: Cook Inlet B: 4085' - 4095' 4116' - 4140' Static Temperature: 95 deg. le A Bobcat Retrievable Bridge Plug (RBP) will have been set below the Cook Inlet B sand. · RIH w/ 20 joints 2 7/8" tubing and 3 1/2" DP to + 4200' MD. Dump sand on top of the bridge plug. 3. Establish circulation then close annular preventer. 4. Establish injection rate.then open annular preventer. · Mix 20 BBLS of cement in batch mixer as follows: 100 sacks Class G cement 0.5 % D156 (fluid loss additive) 0.05 gal/sk D-47 (antifoam) 4.97 gal/sk fresh water Density: Yield: Thickening Time: Fluid Loss: 15.8 ppg 1.15 cu ft/sack 4:30 hours 40 cc/30 min Note: D156 is a dry additive and should be premixed in the mix water · Pump a 20 barrel fresh water spacer then spot the 20 bbls of cement as a balanced plug. Pump a 5 bbl fresh water spacer behind the cement and displace with workover fluid. · · POOH w/ 7 stands. Close annular and squeeze cement into formation. Displace 7 bbls of cement into formation then slow pump rate down to hesitation squeeze the remainder of the cement. Limit pressure to 2000 psi. · If the pressure does not increase overdisplace the cement and proceed to, step 10. If pressure does increase permit the pressure to increase to 2000 psi and hold 2000 psi while WOC. Keep pipe moving in ± 25' long strokes (make strokes as long as possible without stripping a tool joint through the annular preventer)' while WOC..If there are any indications that cement is remaining around the drillpipe, open the annular, circulate the well clean, POOH, and skip to step 12. 10. RIH to ± 4200 and circulate 2 hole volumes prior to repeating squeeze procedure. 11. Repeat steps 3 through 9 if needed. 12. After the squeeze is complete, RIH w/ 6" bit to drill cement. 13. Drill to 4100 and test Cook Inlet A perforations to 2000 psi. 14. Drill to 4160 and test CoOk Inlet B perforations to 2000 psi. Note: If any of the perforations does not test, repeat the squeeze procedure before continuing. Squeeze Procedure for any Cook Inlet or Beluga sand below the Cook Inlet B sand. If excessive water production occurs when testing either the Cook Inlet or Beluga the interval producing the water will be identified and may be squeezed. In this event the zone producing the water will be isolated f=om below with a bridge plug and from above with a cement retainer. The setting depth of the bridge plug and the retainer may be critical due to the proximity of the adjacent sands. A Bobcat Retrievable Bridge Plug (RBP) will have been used in the testing program that identified the interval producing water. Depending on the spacing between the interval to be squeezed and the interval below either a retrievable bridge plug or a drillable bridge plug will be used for zone isolation. A drillable bridge plug should be ordered when it becomes apparent that a squeeze will be performed that may require its use. Squeeze Procedure le If spacing of bridge plug to isolate from below is critical, POOH with the Bobcat Retrievable Bridge Plug (RBP) used for testing. If spacing is not critical leave the RBP. in the well and dump sand on top of the Plug. · If spacing of the bridge, plug is critical, set a drillable bridge plug on wireline at the appropriate depth. · Set a cement retainer on wireline above the perforations to be squeezed. 4. RIH w/ cement stinger and sting into retainer. · Close the annular and establish injection rate. Note that there are several sets of open perforations above the retainer and there is a chance for communication through these perforations to the annulus. Observe the annulus for any indications of this before proceeding. · Mix the desired cement volume in the batch mixing tank. Final cement formulation will be determined based on the interval to be squeezed. Have Dowell- Schlumberger test cement formulations using bottomhole temperatures of the interval to be squeezed. · Pump a 5 barrel fresh water spacer and the cement'followed by a 5 barrel -fresh water spacer then displace with workover fluid. Hesitate during the squeeze as needed. Desired squeeze pressure is 2000 psi. If the interval does not squeeze overdisplace to facilitate another attempt. Observe the annulus for any indications of communication. Note: Communication is possible even if there is no indication of communication at surface. Cement could enter the wellbore through one set of perforations and displace the workover fluid out through another set of perforations. · Unsting from retainer and pick up to above the top set of open perforations. Do not attempt to reverse circulate until pipe is above all the open perforations. Steps 8 - 10 should be performed even if another squeeze will be attempted before drilling up the retainer due to the possibility of cement in the annulus. · Reverse circulate to insure the drillpipe and annulus are clear. 10. If an additional squeeze wilt not be required POOH. -_ If an additional squeeze will be required WOC, then run back into hole, sting into the retainer and repeat squeeze procedure· ~ 11. Drill out retainer and cement to past bottom perforation to be squeezed. If RBP was used, drill out all cement, if a drillable bridge plug was used then drill past the bottom perforation but do not drill up the bridge plug. 12. RIH w/ packer. 13. Test the squeezed perforations to 2000 psi. 14. If the perforations test, POOH w/ packer. If perforations do not test POOH w/packer and repeat squeeze procedure. 15. RIH w/ 6" bit and drill out bridge plug (if applicable) SECTION I STI~ULATIoN PROCEDUREs RECEIVED J U L - 2 1992 Alaska Oil & Gas bu~s. ~,~mmission Anchorage STIMULATION PROCEDURE 1. Move RBP to below the highest interval to be stimulated. · RIH w/ 'packer and BHA per attached schematic. Set packer above interval to be stimulated. MFE should be in the closed position so that the pipe is run dry. · Install test tree. Rig up flowlines and surface equipment. Pressure test the entire surface system. All lines upstream of the separator should be tested to 2000 psi. All lines between the separator and the burner boom should be tested to 125 psi. · Open the MFE valve with 0 psi on the test string to surge the perforations. Flow the Well as directed, if the flowrate is acceptable skip to step 8. · Close pipe rams, fill drillpipe, open MIRV reversing valve and spot stimulation fluid to near MIRY reversing valve. The stimulation fluid will be 7.5% HCl acid with clay stabilizer, surfactant, and iron sequestering agent. The volume to be used will depend on the interval to be stimulated. · Close MIRV reversing valve, open MFE valve and pump remainder of stimulation fluid. 7. Displace with nitrogen. · Flow back as directed. If interval cleans up and flows at an acceptable rate continue to step 9. If interval does not flow at an acceptable rate an alternative stimulation procedure will be developed by the reservoir engineer and the drilling engineer on site. · 10. Close the MFE, release the packer and move RBP to below the next zone to be stimulated. Set packer above zone and repeat steps 3 through 8. After all intervals have been stimulated and are producing at acceptable rates, kill well and POOH w/ packer. TOOL STRING FOR STIMULATIONS TEST TREE 1/2' DRILLPIPE TO SURFACE SHORT REVERSING VALVE I ,STAND 3 1/2' DRILLPIPE MIRV REVERSING ~"~LVE I STAND 3 1/2' DRILLPIPE MFE VALVE W/ HOLD OPEN o I STAND ;3 1/2' DRILLPIPE JAR8 SAFETY JOINT POSlTRIEVE PACKER SECTION J COMPLETION PROCEDURE COMPLETION PROCEDURE Note: Detailed schematics of each subassembly are shown in section P. The final completion design is subject to change based on the results of the well testing. Other adjustments to the 'setting depths of the equipment will be made based on the actual length of the tools and the need for additional crossovers. Blast joints, are to remain opposite each set of perforations and the packers should be set to isolate the intervals shown. The completion design includes 2 7/8", 3 1/2" and 4 1/2" tubing and a large number of blast joints and other tools. Have tools available to handle all tubulars. 1. Make up subassembly 1 as per attached schematic and RIH. Note: XO sleeve should be in the closed position while RIH. · Run a GR-CCL log to verify the depth of the top blast joint. Set packer so that the top blast joint is located opposite the Middle Beluga perfs. · · Rig up test tree and RIH w/ coiled tubing. Jet__well in and flow through test separator until well cleans up. Set a blanking plug in the XN nipple at the end of the 2 7/8" tubing. · Bleed off pressure and load the well with completion fluid. Release DP from packer and POOH. 7. Make up subassembly 2 and RIH. 8. Sting seal assembly into packer set on subassembly 1. · Run a GR-CCL log to verify depth of the top blast joint. Set packer so that the top blast joint is opposite the Cook Inlet 8 perforations. 10. Release DP from packer and POOH. 11. Make up subassembly 3 and RIH. 12. Sting seal assembly into packer set on subassembly 2. 13. Run a GR-CCL log to verify depth of the top blast joint. Set packer so that the top blast joint is opposite the COok Inlet 7 perforations. 14. Release DP from packer and POOH. 15. Make up subassembly 4 and RIH. 16. Sting seal assembly into packer set on subassembly 3. 17. Run a GR-CCL log to verify depth of the packer. Set packer so that the top blast joint is opposite the Cook Inlet 4 perforations. 18. Release DP from packer and POOH. 19. Make up subassembly 5 and RIH. 20. Sting seal assembly into packer set on subassembly 4. 21. Run a GR-CCL log to verify depth of the top blaSt joint. Set packer so that the top blast joint is opposite the Cook Inlet 1 perforations. 22. Release DP from packer and POOH. 23. Make up subassembly 6 and RIH. 24. Sting seal assembly into packer set on subassembly~5. 25. Release DP from packer and POOH LDDP. 26. Lay down any drillpipe stood back in the derrick. 27. Make up subassembly 7 and RIH. Note: This subassembly includes the SCSSV and the control line. 29. Prior to stinging into packer, reverse circulate to displace well with packer fluid. Leave 4 bbls of glycol in top of tubing x casing annulus for freeze protection. 30. Space out and latch into packer. Prepare to establish barriers, ND BOP and NU tree per step F6 of main procedure. PHILLIPS PETROLEUM COMPANY NORTH COOK INLET UNIT PLATFORM A STANDARD PROCEDURES GUIDELINES FOR SIMULTANEOUS ACTIVITIES '1.0 GENERAL 1.1 The following procedural guidelines will be used whenever simultaneous activities are in progress on North Cook Inlet Unit Platform A. There will be sitUations which do not fit the examples described in these guidelines. If any doubt exists about the correct action to be taken, consult the appropriate management personnel. RESPONSIBILTY While conducting simultaneous activities the Drilling Supervisor is responsible for Drilling, Completion and Workover activities. The platform Lead Operator is responsible for production activities and the routine operation of the platform. The Drilling Supervisor and the Lead Operator should assist each other in order to achieve the common objective of conducting simultaneous operations in a safe manner. Either the Drilling Supervisor or the Lead Operator has the aUthority to declare an emergency and shut in production when it is deemed unsafe to continue. In an emergency while drilling, completion, o~ workover activities are in progress the Drilling Supervisor will be the designated "Person In Charge". The "Person In Charge" will be responsible for the following: . . . o Assumes management responsibility for the safety of personnel and protection of property and equipment by activating the Emergency Plan and assuming operating direction. Evaluates the overall emergency situation based on the information at hand including information from the Toolpusher and the platform Lead Operator and makes decisions on actions to be taken. Initiates platform evacuation if necessary, and insures that all personnel are accounted for and evacuated. As soon as possible, contacts the Kenai Drilling Superintendent and the Kenai Plant Superintendent. These people will in turn activate the Phillips Emergency Communications Plan. 2.0 DEFINITIONS For the purpose of these guidelines the following definitions will apply. 2.1 SIMULTANEOUS ACTIVITIES Any of the following activities which are occurring simultaneously on the platform: Drilling, Workover/Hydraulic Workover, Concentric Tubing Workover, Production, Wireline Operations, Construction/Maintenance, 2.2 DRILLING Any work done on a well with the use of a drilling rig and related equipment, prior to the well being placed on production. 2.3 WORKOVER Any work done on a well with. the use of a drilling, workover, or hydraulic workover rig, after the well has been placed on production. 2.4 CONCENTRIC TUBING WORKOVER Any work. performed using a small string of tubing inside the production tubing or the drillpipe. The small tubing may be a small string of tubing run using the drilling rig or a snubbing unit, or the small tubing may be coiled tubing. 2.5 PRODUCTION Any work involving producing/injecting hydrocarbons or other fluids from/into a well. With the X-mas tree installed, stimulating is considered production. 2.6 WIRELINE Any work which involves using a wireline or electric line to run tools/instruments into or out of a well. REC£1V D J U L - ?- ]992 ~laska 0ii & Gas L;ons. Anchorage 2.7 2.8 2.9 2.10 CONSTRUCTION/MAINTENANCE Any work requiring issuance of hot work permits or involving heavy lifts. RIG MOVING/SKIDDING Movement of the derrick from one leg to another or from one well slot to another. BARRIER Any device, mechanical or fluid which prevents the uncontrolled flow of fluids from a well. HEAVY LIFT Any lift which requires the use of the main block of the crane. 3.0 BASIC PHILOSOPHY 1. Safety is of the highest priority in any activity. . Simultaneous activities will be Performed with a minimum of two barriers on each well. 3, If simultaneous activities are occurring and a well activity loses the minimum number of barriers, all wells within the wellroom of the offending well will be shut in. The Drilling Supervisor and Lead Operator Will evaluate the situation and determine if production from the remaining wellrooms should also be shut in. All other simultaneous activity must cease until the required number of barriers is restored. 0 More than two simultaneous activities can occur provided that at least two barriers are maintained for each well activity. Se Communication between all parties involved, onshore as well as offshore, is critical to the conduct of simultaneous activities. This communication begins during prejob planning, and should continue until the job is complete. 4.0 ACCEPTABLE BARRIERS Examples of acceptable tested barriers for each activity are as follows: 4.1 DRILLING . Stable fluid column of sufficient density to prevent flow from any formations open to the well. Fluid barriers should be tested by observing the well for an appropriate period, normally at least 30 minutes. 2. Blowout Preventer Stack tested to Phillips specifications 3. Tested casing 4. Bridge Plug 4.2 WORKOVER/HYDRAULIC WORKOVER lo Stable fluid column of sufficient density to prevent flow from any formations open to the well. Fluid barriers should be tested by observing the well for an appropriate period, normally at least 30 minutes. 2. Blowout Preventer Stack tested to Phillips specifications. 3. Downhole Safety Valve 4. Back Pressure Valve 5. Wireline plug set in the appropriate profile nipple 6. Bridge Plug 7. Hydraulic Workover Unit BOP 4.3 CONCENTRIC TUBING WORKOVER 4.4 Ii Stable fluid column of sufficient density to prevent flow from any formations open to the well, Fluid barriers should be tested by observing the well for an appropriate period, normally at least 30 minutes 1 Hydraulic Workover Unit BOP, drilling rig BOP, or coiled tubing unit BOP. PRODUCTION For production operations the tubing and the annuli must be considered as independent flowpaths. Each flowpath must have two barriers. 4.4.1 PRODUCTION TUBING 4.5 1. X-mas tree 2. Downhole safety valve 3. Wireline plug 4.4.2 ANNULUS WIRELINE le X-mas tree and wellhead including annulus valves Packer and tubing with tested casing o Stable packer/completion fluid or mud of sufficient density to control formations potentially open to the well 1. X-mas tree 2. Wireline BOP 5.0 SPECIAL CONDITIONS AND PROCEDURES 5.1 SURVEILLANCE AND COMMUNICATIONS Performing the. various activities simultaneously requires the coordinated efforts of all the groups involved. This coordination requires that proper communications be maintained between all the groups. This is enhanced by the Hot Work Permit system and 'the surveillance of the Lead Operator, the Drilling Supervisor, and the conscious effort of all platform personnel to be aware of and adhere to the simultaneous activities guidelines. A safety meeting should be held prior to each critical operation, A critical operation is defined as any operation that could affect the security of a well. 5.2 DRILLING AREA EXCEEDING 60% LOWER EXPLOSIVE LIMIT 5.3 Simultaneous activities shall cease in the event the gas level in the drilling area exceeds 60% of the lower explosive limit. The drilling area includes the rig floor, BOP deck, wellhead area, and mud pits. BOP DROP RADIUS The BOP handling system has been designed to eliminate the risk of the BOP stack falling while nippling Up/down. Shutting in producing wells to nipple up/down the stack is not necessary provided that the stack is supported by the handling system. If the BOP cannot be supported by the BOP handling system, such as for replacing the stack or a major component of the.stack, all wells in the wellroom need to be shut in. The shut in should occur when the BOP is removed from the handling syStem. The. wells should remain shut in until 4 studs, spaced around the flange, are in .place securing the BOP to the riser. For nippling down, the shut in should occur when 4 studs remain securing the BOP to the riser and the wells should remain shut in until the BOP is secured in the handling system. Shut in of a well should be done using established procedures, confirming the DHSV is closed, bleeding off wellhead and flowline pressure to header pressure, bleeding off any annulus pressure, and closing the master valve. 5.4 HEAVY LIFTS The following procedures will apply for heavy lifts. . A flagman will be present at all times during any lift. He will be in radio contact and, if possible, visual contact with the crane operator. . Prior to the lift, the crane driver and flagman will discuss relevant hazards and agree on proper action. . Every effort will be made to avoid making a heavy lift over any hazardous area. . Any time a heavy lift is made over the drill deck, any wells within the swing path should be shut in. . Loads should not be lifted any higher than necessary to clear obstructions in the swing path. . Loads will not; be rotated above a hazardous area, including the wellrooms, unless it cannot be avoided. 7. . Use tag lines on load to guide them into correct and safe position. 8. Visually inspect rigging. (slings, hooks, shackles, etc.) before use ge The crane operator is responsible for seeing that all rules are followed before a lift is made. 5.5 HOT WORK Any welding, torch cutting, or other hot work in a wellroom or the drilling area shall be evaluated to determine what activities, if any, should cease, and which wells, if any, should be shut in. Appropriate procedures and hot work permits will be prepared and approved by the Drilling Supervisor and the Platform Lead Operator to insure hot work operations are conducted safely in conjunction with any other activities in progress. 5,6 5.7 EMERGENCY SHUT-DOWN SYSTEM (ESD) The ESD system must be capable of handling all activities in progress on the platform. Testing of the ESD system is to be carefully coordinated to prevent the loss of vital capabilities during simultaneous activities. DIRECTIONAL DRILLING In the event of a drilling operation taking place, a "safety zone" will be established around the drilling well. The safety zone is equal to the minimum wellhead spacing or 1.5 % of the measured depth of the current drilling depth below mudline, whichever is greater. If a producing well intersects the safety zone, then the producing well must be shut in by-setting a plug below the potential point of intersection. Once the risk of collision is past the plug can be retrieved and production resume. A detailed analysis of the location of nearby production wells in relation to the proposed path of the drilling well will be included with the drilling program. In all cases, when a producing well is near the safety zone directional control will take priority over penetration rate. 6.0 EXAMPLE SITUATIONS The examples shown in this section are intended to clarify the simultaneous activities guidelines. These examples are not intended to cover every possible situation. For situations which are not covered by an example the appropriate management, normally the Drilling Supervisor, will evaluate the situation and determine the action to take. 6.1 DRILLING SITUATION 1. Well kick 2. Loss of c£rcuLation before 20" casins has been set 3. Loss of circulation, &bls to keep hole full 4. Loss of circulation, unable keep hole full but can pump seawater down annulus and pore pressure of fozmations open is less than a seawater 5. Loss of circulation, unable keep hole full but can monitor fluid Level wi~h ach,meter o~her devices and determine that fluid coLuum is stable and of sufficient heisht exceed pore pressure of any formation open 6. Loss of circulation, unable to keep hole full. Pore pressure of fo~mation open exceeds a seawater sradient and fluid level c~nnot be monitored 7. Gas Level exceeds 60Z Se g. 10. BOP control failure - unable to close r~ms or annuLaz preventer Failure of a component of the BOP stack i.e. one of the pipe rams, the blind/shea~ ram, or the annuLa~ to function or hold pressure. At Least one of the components be~ow the failed component wilt spacers pcoporL7 and will hold pressure Leak in a flunks or riser below ~he bott~n component of tho BOP which could be used shut Ln the well 11. Stuck pipe, fult circu~ation ACTION A11 o~her activities must cease until wel~ is stable No action required, s~nuLtaneous activities can continue No action required, s4multanooue activities can continue Ho action required s4,nultanoons ect4vities can continue No action required, s~muLtaneous activities can continue AL1 other activities must cease until tho hole can bo kept full activities must cease ALL other activihios must cease. Run test/abandonment plus into wellhead 8nd Lock down. Other activities can then be resumed. S~nuLtaneous act4v4ties can continue. Run test/abandonment plus into wellhead end ~ock down. Make necessary repairs to BOP. O~hor activities must cease. Run test/abandonment plus ~n~oweLlhoadandl~ck down. O~he~ activities can · os~o ~d ~op~EB c~bo Loss of barrier No formations capable of flow have been penetrated therefore no barriers a~e No barrier Lost No barrier Lost as 1OhS as £t is possible to pump seawater ~nto annulus No barrier is ~6st-as Lon~ aa fluid coLunm is known to bo sufficient to overbalance pore pressure, The £luid level does not need to be at su~face but must be observable .$n some Loss of barrier No barrier ~ost but hazard condition exists No barrier is Lost Loss of barrier 10 12. 13. 14. Stuck pipe, reducing mud wei&ht to fzee differentially stuck pipe Unable to circulate due to plus~ed Bit Dl~ectional d~illin~ we~l, safer2 zone will approach an active well. Potential poAnt of intersection is above shoe ol conductor casinA of active well Di~ectional drillin~ well, safety zone will approach an active well. Potential point of intersection is belme shoe of conducto~ casin~ ol active well 16. ~rO/ND BOP 17. NU/ND Riser or X-mas t~ee Notii~ Production, ii well kick is induced inadvertently oLhe~ activities ~ust cease, see example 1. OLher~iae, sis~lhaneous activities can conZAnue ~oactionrequi~ed, simultaneous activities can continue Othe~ activities can continue, d~A1As~o~12 and cautiousl~ until past potentialpoint ol inte~section. Ii ~hmre is any indication o£ coLLtsion stop d~illin~ and pLu~back in ozdec to side.ack Activewellmus~ be plu~sed below potantial point ol intecsection before ~he safety sene ~eaches the potential intersection point. A pump open plu~ is acceptable and can be opened as soon as the safety zone is past the potential point of inte~section No action ~equi~ed, simultaneous activities can cuntAnue. Shut in all wells and ilowlAnes in wellxoom. ~ells 'will ~emain shut in when less than i studs a~e in place. Need ~obe a~a~e for potential loss ol baxcie~ ~oba~xie~ lost Since the~e a~e at least ~h~ee casAn~e eepa~atin~ the d~illAn~ well ~ ~e active w~ ~~em a co~si~~d be detect~belo~e ~e active we~ ia d~ ~e~e~o~e a co.sion ~no~ ~es~ in a loss o~ ~ss ~ a b~ie~ ~ ei~er ~e ~i~ ~ o~ ~e active ~e~Leas ~e active ~Ll ia plied No barriers lost ~i the riser o~ X-mas t~ee were to fall the X-mas tree box~ier on wells in the wel]_-ocmwould be Jeapocdized. 11 6.2 WORKOVER 1. ~elZ kick All o~her activity must cease until well As s~able See d~l!!!_n~= examples 2 - 6 See d~i!~ examples 8 - 10 Hoti~y produc~ion o~ situation end p~oceod peE d~iLl.tn~ examples 2 - 6 Loss o£ ba==ie= Same as £o= d~illAns examplea Same as ~o~ ch~illin~ examples Need to be awa~e £or loss o~ ba==ier 12 6.3 SNUBBING SXTUATTOH 1. See concent=ic tubin~ examples 6.4 CONCENTRIC TUBING WORKOVER SITUATION ACTIO~ Leak in shes= seal BOP o= hydraulic wo=kove= unAt, =is ob coiled tubing BOP. Concent=ic tubing is not in the well. Leak in shes= seal BOP o= hydraulic workove= unit, =iA o~ coiled tubinS BOP. Concent=ic tubin~ is in well so maste= valve cannot be closed Close maste= valve and.mke =epai=s. Othe= activities cease unless downhole baczie= exists. Othe= activities must cease. Pull concent=ic tubing out of hole and pzoceed aa pe= example 1. Loss of bax=ie= Loss of ba==ie= 14 6.5 WIRELINE valve, lrycLTostatic co[unn of £1u4d in annulus 4a S~eatmr 2. Pullin~/rmming Cl~/gas 1.tft valve, hychrostat~c column of fluid in annulus is Lees ~han BHP. 3. Leaking wireline riser ACTXON ~o action requA~ed. simaltaneous activities can continue Ho action required, simultaneous activities can continue Unless a downhole bax~iar is present so that the wireLtne barrier, alt other activities must cease, and the well shut in at the X-mas t~oo (shear wireLtne if necoaa&ry) REHARXS ara lost Acceptable pcactice fo~ this' closely manned operation Loss of second Wireline tools, plugs, logging tool or other device stuck in X-mae tree preventing closure of master valve Flowing well while production Lo~ging, obtaining wi~eline samples, or flowing trash off plugs, etc. without DHSV in place Unless a downholo barrier is resent so that the X-mas tree s not ~he second bar~ie~, al1 other activitiee ~et cease. ~o action required, simultaneous activities can continue Loss of second barrier Acceptable l~actice for this necessary and closely manned operation 15 6.6 MAJOR CONSTRUCTION ACTXON Hot work in no well activity in progress and no wells a~e on Sas lift Bet work in wellxoom, wells a=e gas lifted. work in d~illing a~eas 5. Beav~ lift over skid deck Hot work in wellhead &cea, scanewells on platfomhave annulus p=asS~Lce (see production examples) Make ea~ety evalua~Lou to determine what wells (i£ any) ~o shut in. Remainder of wells can continue IXLXM~ucins. Water injection can continue even An adjacent wells at ~he discretion of t, he Lead Operator Make safety evaXuation to determine what weLls (if any) to shut in. If a well activity, i.e. d~illins, woEkover etc. As in l~OSress on aw ell Chat would have boon shut An, ~han tho well activitymust also cease. If the well wouldnot have been shut in ~hen the activity may be permitted to continue. Hake safety evaluation to determine what wells (if any) to shut in. Make evaluation to determine what welts (tf any) can continue to be gas lifted. Evaluation sas lASt should consider how far ~as jet would reach i£ a annulus valve were to fail. Bleed off gas pressure in annulus on allwelLs where sas 1Aft is stopped and close annulus valve Activity usins d~illins must cease. Other can continue as per exanplue 1 and 3 Shut in alt wells, flowlAnos, and headers in .swine path Bleed of£ annulus pressure and shut An annulus valve, o~har activities can continue as per examples 1 and 3. No barriers lost, hut potential hazard fo~ nearby wells Ho barriers lost, foe this eese t. hero As no practical renco whether a wel3 As producins or has another activity in p~ogress. Should a annulus valve fail. a sas jet wouldbe released in ~he wellhead area. Hot work should not be pe~o~ned in a~oas whe~e this jet could reach. Wells may continue producing but withou~ sas Ltft assistance No barriers lost, but potential hazaxd exists for wb.ll activiZy usins d~illins rag Tf' load were d~opped it would .leopardize the X-mas tree as as barrier Situation As similar to gas iAft 16 6.7 MULTIPLE WELL ACTIVITIES 2'. Two ~ell ac~ivi[ie~ - I. e. d~illAns0 wo~eve~, ~t~elAae, coiled tubing axe planned ~o occu~ concurrently. Two wel~ activities axe planned to occu~ concu=rently, at least one o£ the activities involves wor~in~ in the =esez~oi= Mo=e C~an two ac~ivities axe planned to occu= concu~=ently ACTION Evaluate planned activities £o~ potential con~lActe which uould jeopaxdize a baccie~ on one o£ ~he activitiea, l£ no conflict exists boC~ activitAee can con~Lnue. ~£ con£1ict does exiat, ~eeolve con£1ict - i.e. pe~£om only one activit~, or ceachedule con£1Ac~inS portion o~ activitAes, cc o~he~ action as ~equi~cd. Same as example 1 S~e as example 1, howevec aa ~he numbec cE well activities incceases ~he possibility o~ con~llcts occu~=in~ also increases. As lens as thecm are no conf. tActs between actAvAtAes then each activit7 can continue wiZhout arbitrary ~est~ic~ions. ~ock in the ~eservoi~ is not ei~ni£icentl~ di£ferent nor mo~e hazardous than workAns elsewhere in a well 17 6.8 PRODUCTION DHSV unaJor leakaae cz D~V DHSV £ails open cz is blown 2. DHSVmAnor leakase 3. DHSV fails closed but holds pressure O~her activities must'cease. Shut An the pcobl-~ well and evaluate situation. Shut in other wells only i£ ~be overall operatAon Aa An jeopardy. IlHSV must be replaced before other act~Lvitiee can Other activities can continue, #ell can be kept on p~oduction but DKSV ia to be zeteeted at 7 day intervals until the valve is replaced. The valve should be replaced at the first Other activAties can continue, chanse DHSV at Eizst chance. R~ARK3 Loss o£ baz::iez DH~V is still considered a Ho barriers lost up the hol 4. DH~V fails closed but lears T~oat aar ezample 1 or 2 depondinspeon severit7 o£ leak S. 7. Annulus p~essuze, pressure can not be bled o£f with a 1/2" hose to below FTP o£ well indicatin~ tubin$ - annulus be bled off with a 1/2" hose Annulus pressure, pressure can nos be bled o££ with a 1/2" hose but can be bled o££ with a 2" chicksan. Annulus Aa not tubAn$ X casinS annulus. Other activities must cease unless leak is detonniped to be above DHSV. Shut in well, as soon as posaiblewell should be lussed with a deep plus or llled with fluid. Ho attach required, simultaneous activities can continue Same as example 6 Loss o£ annulus barrier, In cases where annulus ossuze can be bled below F consult with the O~s to determine the annulus pressure history o£ the _we~l and fez a determination of any action to be taken. Sus~aAned £1ow cannot occu~ since pressure can be bled ~herefore downhole.barriez (fluid, etc) is still a barrier 8. Annulus pressure, pressuzo can not be bled o£f with a 1/2" hose and produces at a stable rate th~oush a 2" chAaksan O~her activities must cease. Evaluate situation to determine i£weL1, should be shut in and corrective actions to bake. Pzoduction can continue on otJ~er Loss o£ annular barrier 18 6.9 WATER INJECTION 1. Soo p.roduc~on examples 19 DIRECTIOHRL SURVEY WELL REFERENCE HO; DR iLL COURSE DEPTH LENGTH m, mmJmmmm mmmmm~ .8 738, El 38. El 761 ,El 31.0 ?92.8 31.0 821 .B 29.0 952.8 64.0 1044.8 92.0 1109.6 65.0 11~3.~ 6~,e 1237.B 6~.e 129~.~ 61 .~ 1330, B 32. e 1422. ~ 92. ~ 1514.e 1688.e ~4.B l~B1,8 IP94.9 93. B 1888,~ 2~4.~ 2r53.e 2214,e 61 ,~ 23~7,~ 93.~ 2481. B 94. e 2555.B 154.e 2617.e 62.e 2~18.e 93.e 2881.e 171.e 3899, B 218.8 S266,6 IB~. 6 3379. ~ 93, ~ 3527. ~ I~B. ~ 3559,9 32, ~ 362~, ~ 61. ~ 3722,9 1~2,~ 3879.8 157. ~ 4FJ35.6 156.6 4178.~ 135.B HETHOD: E&P30037 RflDUIS OF CURVRTURE OPERflTOR; PH ILL IPS DRIFT RNG -VERTICflL DEPTH-- DEC DEG COURSE TOTflL 2,25 699,8 699,8 1,50 30,0 729,8 2,25 31.8 768,8 3.25 31.6 791.8 3,25 29,6 826, ? 3.25 66.9 887.6 3. ?5 63.9 951.5 4.56 91.8 1643.2 4.56 64.8 1166,6 4.56 63.8 1171.6 5.75 63.? 1235,6 7.56 66.6 1296.2 El. 25 31 · ? 1327.9 l 1.25 96.?' 1416.5 14.?5 89.6 1568.2 18.25 96. I 1598,3 21 · 56 87.4 1685. ? 24.25 85.? 1771.4 26, ?'5 04, 8 1856.2 36,75 88.6 1936.9 33.66 ?9.8 2616.? 37.66 64. ? 2681 . 4 37,75 48.5 2129,9 37, OB 73,9 2283.8 36.75 ?5.2 2279.6 37, ?'5 122.6 2481.6 38,66 48,9 2458.5 38,60 73,3 2523,8 3?, 00 135, ? 2659,4 37,75 173,2 2832. ? 38.50 147, I 2979.8 38.75 72,7 3852,4 3~,50 119.5 3172,8 33,50 26. ? 3198.6 34.00 50. ? 3249.4 34.75 84, 2 3333.5 35,25 128,6 3.-!62. l 36.00 126.8 3589.6 32.60 l 11.9 3700.8 WELL: DRIFT DIR RZ II'IUTH 41 36 22 345 334 326 32? 346 341 346 340 3,35 332 336 329 338 329 329 327 325 325 326 325 326 326 325 326 325 325 324 338 330 330 $30 · 329 334 DRlE: 8/23/76 LERSE RI'ID TRflCT: NC I ---COURSE DEPRRTURES--- N/'S E./U TOTRL DEPRRTURES N/S E,,'U UELL ~: / .06 .06 3,89 13,39 3,69 13,39 ,50 ,83 3,59 14,22 · 79 ,63 4,38 14, 85 1.38 . ?2 5.68 15.5? 1.59 ,41 ?.2? 15.98 3,77 -. 26 11,63 15. ?2 3.65 -' 1,3? 14.69 14, 35 5.54 -3.66 26.22 10, ?6 4.1 El -'3.63 24.32 ?, ?2 4.48 -2,24 28.86 5.49 5,39 -'1,91 34, 19 3,58 6.63 -2.35 46.83 t. 23 4.12 -'1.50 44.95 -.'27 14.39 -5.96 59,34 -6.23 18.52 -9.23 77.85 -15.46 23,35 - 12,94 161,26 -28,48 2P. 24 - 16.65 128,43 -44.45 31,14 -18.35 159.58 -62.79 34.86 -28,54 194, 44 -83,33 37,92 -22,79 232,37 -. 106, 12 42.09 -26,36 274.46 - 132.42 37.56 -25.33 312.61 - 157. ?5 30,33 -21.24 342,34 - 17'8.99 46.52 -3; 1.97 388.87 -210.96 46,49 -7:; 1,95 435,35 -242.91 76.82 -52.79 512, 17 -'295,? l 31,56 -21,29 543.73 -316,99 47, 19 -~;2,43 598,92 -349,42 85.79 -58.96 676. ? l -468.38 189.06 -F4.95 785,76 -483.33 94.57 -66,22 886.33 -549.55 4;", 26 -~.;3,71 927,59 -583.26 ?'3.12 -47.48 1000.?1 -638,74 15.36 -8.83 1016,61 -639.58 29.35 - 16.94 1845.36 -656.52 49.87 -2:8.79 1895.23 -685.32 77.59 -45,F1 1172.82 -731.82 78.29 -46.12 1251.11 -.777.14 · 6R.63 -.':;5,43 1317.7'4 -812.57 DIRECTIOHRL SURVEY IdELL REFEREHCE HO= E&P30037 HETHOD ,' RRDU IS OF CURVRTURE OPERRTOR = PH[LLIPS DRILL COURSE DRIFT RHG DEPTH LEHGTH DEC DEG 4232.B 62.0 32.25 4491.0 155.B 33,F5 4787.B 216.8 35.68 4?99.6 92,6 35.75 4983.E I84.6 3?,BB 5]40.6 157,6 37.75 5269.~ 129.6 38.25 5456.6 1~?.8 38.00 56?4.6 218,6 37,75 5984.0 310.6 37,25 6233.E 249.0 37.75 6542.6 309.0 30.00 6855.6 313.0 37.50 7159.6 364,6 37.75 ?356.0 197,0 37.75 7655.B 299,6 34.56 ?751.6 96.6 · 33.86 7966.6 209.B 33.86 8279,B 319,8 34,88 UELL: ~ -VERTICRL DEPTH-- DR[FT DIR COURSE TOTRL RE IHUTH 52.5 3753,4 332 e?.? 3e4t,l 332 129.6 3970.? 333 178,3 4149,8 331 75.8 4224.8 335 140.1 4372,1 334 124.8 4496.9 334 lOl,? 4598.5 336 147.1 4745,6 336 172.1 4917.? 337 245.9 5163.? 33? 197.5 5361.2 338 243.9 5605.1 339 247,5 5852,6 339 240.8 6093.4 340 ]55.8 6249.2 339 241.5 6498.6 339 79.8 6578,5 33? 175,3 6745.7 336 266,8 ?6ti,? 337 DRTE: 8/23/'76 LERSE FiND TRF~CT: HCI ---COURSE DEPARTURES--- N/S E/U 29.37 - 14.9? 49,34 -26,23 ?5,38 -~;9.24 lB?. 67 -57,25 4?. 45 -24.18 98.49 -46.98 85.66 -'lt. 78 ? 1.98 -2;3.56 185.47 -46,96 122.74 -53.37 173.71 -?'3.74 140.04 -.=;8. El l 176.51 -69.53 178.90 -68.67 173.84 -64.99 112,97 -42,24 164,54 -63, 16 49.45 - 19.98 184.38 -45.39 161,46 -F6,21 [,ELL TOTRL DEPRRTURES H/S E/U 1347, ll -'827.53 13~6,45 1471.83 -893.81 1579,58 -958,26 1626,94 -.974,43 1725.43 -1021,4t 1811.89 -1863.19 1883.06 -1096.75 1988,54 -1143.?1 2111,28 -1197,86 2284.99 -1276.82 2425.63 -1328.83 2681.54 -1398.36 2788.44 -1467.83 2954.28 -1532,83 3867,25 -1574,27 3231,86 -1637,43 3281.25 -1657,41 3385.63 -1782,88 3547.69 -1773.81 . o iii , ii i ! ! i i ii i i ~.' '= .~' t I 120" 29 · 0 .7 /,c I '~ 49 -~--, 26.25 24 24 . ~~12 ( b~;~c~,,9 v^c~lS, · i GIIIII$1MAS 1REE ASSEMBLY · - NO. X-IB34-L-REV 9 rC)R; PHILLIPS PE T. GO. ,--20 2526 1718 I OIL CENTER TOOL DIVISION · CHRISTMI::IS TREE PI:IRTS~,~IS? FHILT.IPS PETRO~.~UN COMPANY COOK ~N~, AI~SKA X-183N-L-Rev.9 · . ~8"' x ~6"x ~o-3/~" x 7" x ~" 'zooo~---~ooo~ .... 3ooo~--.--5oo0 WORKING -rIEM pART NO.' i QUAN' -., D E S CZ R I P TLI O N . um~ rmu~ TOT~,, ne I ] Head,-28"OD (.500"-Wall). Buttw.e~ x__ 30-~/~" ~00~~ (3~-~7/3~" ~,D.-Rin~ ' 0 Groove) Clamp Hub W/2 - ~ 10 ~F .... . ... -' FlsnEe~ ~tle~s; Seat fo~ .Unread All,ninE "'" '" ' Pin 90~ to 4" ~tlets & 2 - 1-1/2"LF 45° a ~25° From All,nih{ .Pin . Secondary 'CemenZln~ Access W~lusn Mour~ted P~pe Plu~s (~er ~ your ~-.so9) Ref _ . ' 2" 10o~P ~ iO ~ 2 Flange, Companion, . ~ 2' R~n~ Gaskets., API Y~tsl, R-37 3.(3 Q 1. Bull Plu~, Type B-~ x . 5 I Bull_ P_lu~, Type B, 5 16 Studs & Nuts, Udy. 7/8" x 6" 1.27 [ I Unread, Type III, 16"0D 8~ 'Fe_~ le Bt~,, · ~n~ Nlp~11~/~ Clamp Hub Top W/2-~"~ ~tlet In Lowe~ '~ Section ~ ~-2" 500~P Studded ~tlet~s Each In Middle ~ Upper Sections W/32~ ?/~" x Shots 'Allen Screws Installed . ~ Extra Deck Counter Bor~V.R. Threads i~ 2" Studded Outlets W/R~"0D Double Dovetsll Pk~. Sero1 Btm. ~ Ali~n Groov~ (Per ~yout ~L-~175)' Ref. #8465 7~ 32 Pad Studs & Nuts, UdF. '7/8" x ~" .f;8 ~ I HsnEe~ Caslq~, T~pe ~-A, Flu~ed, 16-5/5" 0D x 10-3/4"0D 8~ _~Z o ~ B~m. , W 11" L.H. Aqme Tbd, Top [Per ~Fou~ ~175)' Her. 'g8~bb' ' - 8~; I Casin~ Nipple, Grade J-55, 10-3/~"0D 8~ ~, o ~ x ~8" ~n~ / ContinueO... PHILLIPS P~ROLEUt.1 COMPANY COOK ~ILET, AL.qSKA X-183~4 -L-Rev. 9 (P~; .#2. ) 28" .:x - :t6" x- ~.o -3/~" 7:! tREE NO. SIZE ITZM PA~T NO. . 11 WO~ClNG ........ · DEBCRIPTION zooof/ - eooo~ - 3oooff - 5ooq X 10" Bow 1 R~f. CPer I~y~ut'-'L-/l175)'-- Hsn,~, Cas in~, Type Il!t, -A, ~u~ed/ Acme ~. Top (Per ~you~ 10" L.H. Cssln~ Nipple, x ' 16" Long (~rsde a'-55, ;7"OD 8RF, ~- ckoff Bushing: Type Ltd-A, 16-5/8"0D ~ - 1/2" ID x 5" Bow ! Per L-s,vout {; ~-'~x ~ D) Ref. ~8~68) UNIT PRICE Han~er, "Type_-.. · UH-.'~. , Ext~ende..d i,3eck; 6" x 4"0D ~u~~S,_____ Cf '£i~d. Btm. x, ~'~9~ a.-1/Z?'-~_UF.--8~,~ ~5"~ Groo~Ted :oz' OCT .TFpe "_TS" B~V & 1/q" .'a~oed & Tb~re~de access Por~ *or ~c~ -- ?y~3 v~ ~0~ Between. Top. '.'0" Rin~ ..S~a ls. ~ W/2. :- Sea i. Rin~s Lif~ln~ Eye~ (Per ~y~t ~L-~175) Ref. $8~69) Chsr~e for ~~~~Tuhin~ Thds. (i) ~00~WP Ou_ ul, mp Hub C!3mp= Assemb i.~,. Complete ~. OCT ;'..-Bolt -- t, ,,- . :~.:,.~ ' ~6-~/~ ~oo~,; ~'s~s I ~o ~ch io~ros 1 Bore of Un~h~s~ Allen Wrench for Ditto, 1" Hex Continued .'. - TOTAL OIL CENTER TOOL DIVISION £MC CORPOP. RTION CHRISTMP~ TB~- PHILLIPS PETROT~U~4 COMPA~PZ COOK L-',!T.~'2, ALASKA .~- %-183~-L'Rev.9 (P~.#3) NO. 6 7 B PART NO. 3 3 3 3~ 28" x x6"x [o-3/a" x 7" x a" WOI~W~TG FRESSORE DESCRIPTION Nipple, }I-5, 2tt'x 6" XX UnibRZd'Hex, Lip T~pe, F.S., 2" 2:x ~"~ Nipple, N-5, lOOO~ · · Bull Plugs, Type 9-4, 2"LP Needle Valves, OCT, Type NFL, 1/2" Ring Gaskets,. API Metal, R-2a. 2" 3 Va Iv. es. OOT~ F.E., Full Port, W/~v~. Duty S~.em Protector 2" 5000~WP F la nge C ompa n i on... (~ Sets) stua~ a Nuts, Ody., 7/8" x 6" ,,.q J! . Adapter: 16-.~/~! 5000#T~P Cl~mp Hub _ ~o~om x ~" B0~WP m~uaded Top W/ ~o~om ~ored fOP a W/Groove · 2,,op-d for ~ccess W/Tes~ Por~'~ (Per ~-ou~ #L-~lT~) Re~". ~8~70 Ring Gaskets, .API Metal, R-37 ye lye, oc~o z.z., ~" 3oo~.'.~ w .,~vy. Duty S~eg Prot;ecto~ .e Tee, .T~pe T-608, ~" 3OO~l'~P x ~"- ~ Outlet Ad~.~.ter_ Bott;omho&~ Test' Tyge B-I~.-A_, 300Cn~WP. ~ss Ll~t Thd.. CRef. ,~2530 Needle Vs!ve, OCT, Type Continued... .-.20oo~ .... 30o~ · UNIT PRICE 5 ~.O2. 26. TOTAL ;9 (0 OIL CENTER TOOL- DIVISION ('~' 1')4C CORfOXATION ~, ~TMRS TB~'~- PHRTS T PHILLIPS PETROL~uq~I CO;&PAI~ COOK INLET, AIASKA X-1834-L-aev.9 (P~.#q.) 28" x 16'" x 10-3/q" x 7" x h" · ~ooo,~ - zooo~ - 3ooo~ - 5000 PART NO.' DEBC:RIPTION' · Oau~e, Xmas .Tree,. 2-1/2" Facel 0,5000~ TOTAL AD.'-31TIO?~A L EATERIAL , .Rin~ O~skets, API Metal, R-37 Studs a Nuts., Udy., 7/~" x 6" Bull P.~u$ T~,me 'B'O, 2"~ W/2" Hex Head & W/'0 Rz-~ S~:sx to Reach In~ernsl Bore of Unihead UNIT PP/CE P lu~s, T~-pe VR., 2" TOTAL CATALOG TOTAL GROSS PRICE DISCOUNT TOTA L ' le 21. TOTAL 13,0 3 ,7 C 12/. _.J L_ ~,:~ -EXISTING CONDITION SCHEM~,.C NCIU A-1 ' _ TSV _ BPV(Make,Type,OD): OCT TYPE IS Tbg. Hgr.(Make,Type): OCT UH-A RKB-THF: Annulus Fluid: FRESH WATER RKB -~1.: 116 TOC: 2557 PJ<B-ML: "~:::OD ,~ '~:'! TOp. 30' 42 388 16' 42 614 65.00 H--40 10 3/4' 42 353 51.00 J-55 10 3/4' 353 2544 45.50 J-55 7' 42 +!-80 26.00 J-S5 BLrl-r 5690 4330 415000{ 7~ +1-8¢ 6910 23.00 J-55 BLrI'T 4980 3270 366000! 7' 6910 7449 26.00 J-55 BLrl'r 5690 ; 4330 4150001 4' 40 4047 10.90 J-50 BuTr 7210 &590 169200 :FORMATION 'PERES !DePth i"' :'. ..... ':' :.. :::(TOP):":":'" ii-(F'r)-::: .::: i!::"-:;"::::?::i:~:.:::'!';.:::.::ili!::!ii::::i::!!i:.i!iiiii?:~::i::-::~:~.: '-';.:'!:!~i:i.!:iiii!:~ :..!::-":'i'i:~:~ :::i!:!:i~!i:111~:~!~:i:ii~:,i:~ ii:~!i!i!~:i!!!;:!ON): .'-:' 3~ I OCT UH-A TUBING HANGER 40 243 4" Bu3"r~TuBING 3.475 4.000 ~ 3 OTIS T~V NIPPLE 2.7~0 4~80 I ~80 3752 4" BUTIltE~ TUBING 11.475 4.~00 4048 1 X-OVER4" BUTTRESSX3 1/2' BUTTRESS 2.992 4.{XX) KBX 4049 2 OTIS 3 1/2' X NIPPLE 2.750 3.500 U 405~ 7 CAMCO KBM MANDREL 2.750 4.500 I I 4058 2 OTIS 3 1/2' POUSHED NIPPLE 2.750 4060 5 OTIS RH PACKER 2.780 6.000 Cl A 4085-4095 4068 80 4 1/2' B~ JOINTS 3.000 5.563 Cl B 4116-4140 4 1/2' BLAST JOINTS 3.000 5.563 4148 63 3 1/2' Bu3'rRESSTUBING AND PUP JOINTS .2.992 3.500 XC 4211 3 XO SLIDING SLEEVE 2.813 4.500 4214 95 3 1/2' TUBING AND PUP JOINTS 2.992 3.500 i Q 4309 2 Q NIPPLE 2.625 3.500.. I 4311 3 LOCATOR AND 4' x 3 FT SEAL ASSEMBLY' ' 3.000 4.000 '----~ ~ 4311 o~s WPE w~ PERMANENT PACKER 4.000 5.000 4314 e. 3 1/2' TUmNGAND PUP JOINTS 2.~ ~.500 Cl I 4351-4391 xo 4412 3 XO SMDING SLEEVE 2.313 2.875 Cl 2 4402-4482 X 4415 97 3 1/2' TUBING AND PUP JOINTS 2.992 3.500 4512 2 X NIPPLE 2.313 2.875 4514 6 OTIS 3 1/2' X 6 FT SEAL ASSEMBLY 2 4 ~ ~ 4515 OTIS TYPE WA PERMANENT PACKER 4 6 I 4521 2 7/8' MULE SHOE Cl 4 4552-4588 Cl 5 4624-4674 Cl 6 4708-4738 Cl 7 4760-4784 Cl 8 4874-4886 C110 5(XX)-5012 C111 5044-5080 M BELUGA 5590-5596 M BELUGA 5604-5816 M BELUGA 5663-5874 M BELUGA 5879-5692 M BELUGA 5708-5715 M BELUGA 5874-5888 M BELUGA 5892-5904 M BELUGA 16076-6084 M BELUGA 6098-6118 M BELUGA 6271-6278 L BELUGA 6509-6514 L BELUGA 6578-6584 L BELUGA 6589-6602 L BELUGA 6790-6799 L BELUGA 6805-6814 ~-3-'::.~::~:~:.:..'-.-:.:.:.:.:.:.'.'. :::::::.A::~,' DRILLED IN 1968, COMPLETED IN 1969 DEVIATION 38 DEG ...... .~t'nJul Ft.ld: INHIBITED WA'IER WITH GLYCOL FOR FREE2~ PFIOTECTION le 42 e14 M,.oo H-40 10 M4 4~. ~68 51.00 J-~ 10 ~4 M~I ~S44 45.50 J-~ · 4. +~- .o ~..(x) ,j-~ BUTT ,eeo 4 1R 4~ ~e4 ¶~.eO U--56 BuI'r 8~20 4 1/2~ ~ 4TS4 1=75 J-~ EUE MID · ~ ~ ~ 47~ s~oe uo ~-~ E~E e.D ?eeo 74~0 · 7~ s~M 72.0 &so u-~ EUE M~D .W) ?MO ee?oo ~e I 11JSINQ HANGER 40 ~1114 1N'BUTIRE88TUBING W 4.~00 ~81 8 O'R8 ~ NIPPLE 284 5 X-OVER 4 1)2' MID EUE PIN X 4 lj2' BuTr BOX 8.M4 4.500 ' 288 8eee4 1~)' EUE MID TUBING ~.e58 4.SO0 ~ee7 5 8F.~. A88EklSLY ~.SeO 5.0(X) [] · 4w) ? OTto ~ ve~ mTnEVAm. E PAC~. 4.0oo ,.ooo Gl A 40e5~ 8(2JEEZED Cl B 4118--4140 400? 291 , 1/2' TUBINQ AND FUF) JOINT8 8.858 4.500 4~, ~ ~ uNrr FO, RATC, A ~TCH ,FAO ~.O00 · · ~o 7 o~ TYeE v8, mTREVA~.~ PAOKE. 4307 88 4 t/2" TUBING )~10 PUP JOtNT8 8.858 4.500 M ~ 4 ~pu~,,~w~ u, 4.~ Ct2 4402~ 4887 eO 4 1/2" BLAST JOINT8 8.8~5 5.563 44~7 ~,t 4 1Mi' TUBING AND PUP JOINT8 ~.858 4.500 X~ 4520 $ XA 8UDINQ SLEEVE ~.81~ 5.563 4525 2 SEAL UNIT FOR RATOH A LATCH HEAD ..860 I.O00 ~ 2 RATCH A LA'rCH REOIEVING HEAD 6.000 ~ 4 4552~ 4550 40 4 1/2' BLAST JOINT8 - 4580 ~e 4 1/2'TUBING MD PUPJOiNT8 ~.M,e 4.~00 ~15 4~24-4874 4~1e eO 4 1/2' BI. AST JOINT8 ~.865 5.~ 467e 17 4 IN' PUP JOINT8 S.eS~ 4.S(X) XO M ~ XO 8LJDIN(~ 8LEE~ ,Ieee 4 4 1/2' TUBING ,~ND PUP JOINT8 ~.e58 4.5~0 cie 4708-..4738 47o~ 40 4 1N" BI..J. ST JCXNT8 4748 I 4 1/2' PUP JOtNT8 3.e6~ 4.~00 47M , SEAL. ASSEMBLY ~.,e2 4.000 8116 26 8 1~f2' PUP JOINT8 ~.992 8.500 C111 5044-5{~0 5042 40 ~ 1~2' BLAST JOINI~8 2.882 4.500 50e2 10 8 I~2'PUpJOINT8 2.992 3.500 XO 50e2 ~ xo 8LJDINqi SLEEVE ~..e18 4.500 · .i 3 OTIS TYPE AWD PERMANENT PACKER 4.000 6.000 M BELUGA 5590-5596 M BELUGA 5604-5616 M BELUGA 5663-5674 M 5679-5692 M BELUGA 5708-5715 M BELUGA 5874-5888 M BELUGA 5892-5904 M BELUGA 6076-6084 M 6098-6118 M BELUGA 6271-6278 L BELUGA 6509-6514 L BELUGA 6578-6584 · L BELUGA 6589-6602 6575 6605 L BELUGA 6790-6799 6787 L BELUGA 6805-6814 6817 7238 7239 SEAL BORE EXTENSION 3250 5.500 I JT 2 7/8" J-55 EUE 8RD TUBING 2.441 2.875 XO SUDING SLEEVE 2.313 3.668 7/8" TUBING AND PUP JOINTS 2.441 2.875 2 7/8" BLAST JOINTS 2.362 3.668 2 7/8" PUP JOINT 2.441 2.875 2 7/8" BLAST JOINTS 2.362 3.668 2 7/8" TUBING AND PUP JOINTS 2.441 2.875 2 7/8" BLAST JOINTS 2.362 3.668 2 7/8" BLAST JOINTS 2.362 3.668 2 7/8" PUP JOINTS 2.441 2.875 2 7/8" BLAST JOINTS 2.362 3.668 27/8" TUBING AND PUP JOINTS 2.441 2.875 2 7/8" BLAST JOINTS 2.362 3.668 7/8" BLAST JOINTS ~ 2.362 3.668 2 7/8" TUBING AND PUP JOINTS 2.441 2.875 2 7/8" BLAST JOINTS 2.362 3.668 2 7/8" TUBING AND PUP JOINTS 2.441 2.875 2 7/8" BLAST JOINTS 2.362 3.668 2 7/8" TUBING AND PUP JOINTS 2.441 2.875 2 7/8" BLAST JOINTS 2.362 3.668 2 7/8" TUBING AND PUP JOINTS 2.441 2.875 2 7/8" BLAST JOINTS 2.362 3.668 2 7/8" TUBING AND PUP JOINTS 2.441 2.875 2 7/8" BLAST JOINTS 2.362 3.668 2 7/8" BLAST JOINTS 2.362 3.668 2 7/8" TUBING AND PUP JOINTS 2.441 2.875 2 7/8" BLAST JOINTS 2.362 3.668 2 7/8" BLAST JOINTS 2.362 3.668 2 7/8" TUBING AND PUP JOINTS 2.441 2.875 OTIS XN NIPPLE 2.205 2.875 PUP JOINT 2.441 2.875 WIREMNE REENTRY GIUDE 2.441 2.875 END OF TUBING PBTD DEVIATION 38 DEG 00g'g 0g~'£ NOISN:::IIX3 :::lblO8 000'9 O00't, I. A'lSHI:I$SV8FtS NO 1::!$ l::13)lO'~'d QAAV SLLO 000' l~ ~66'~ Alt3 IN::i$SY '1 V'-dS 00g'g ~66'~ SINIOr dl'ld .Z/L £ 00g't, CL9'~ 3Ag:I'IS ONIQIqS OX 00g'C ~66'~ SINIOr dnd .~/~ C 00g't~ ~99'~' SINIOP 1SV'II:i .~/~ C 090g-t~t~0g ~ L IO oog'g ~66'~ S.LNIOP diqd .~/L C 00g't ~99'~ $1NIOP 1SY'Ig .r,/t ~ ~t0g-000g 0[ I0 g66'~ S. LNIOP dFld ONV !DNIgRI.?,,/I. C SINIOI' 15V'18 .~/t C $1NIOP dfld .7,,/'1. C ~£0'g O00't~ NOISN.gJ.X~ 3ldOG 000'9 oo0'v 1::13)lOVd 1N:INVlRI:::I::Id OARV ::id,LL SLLO 9g9~-~Zg~ glo OX ,-lan:assvgns 't-V I'IION ~IIV~=iHOS NOIl:l-ldiAlO00:::tN " L~' C '3 [_ p ,~NED COMPLETION SCHEMATI NCIU A-I' SUBASSEMBLY :" ' ~': ' F ' : :'" ::~::'"':':": '"' ': ::': '~ '" ':";:': ' ' :: ::~ :' ':'::' ~:: ~'':: :' ':: :': :' ' ::: :'":: :~::: :~;::: :: ::::::::': :'::' ======================= :":' ' · , , ,, 4752 8 SEAL BORE EXTENSION 4.000 5.032 ..... CI 7 4760-4784 4760 30 3 1/2" BLAST JOINTS 2.882 4.500 , , 4790 51 3 1/2"TUBING AND PUP JOINTS 2.992 3.500 XA 4841 3 XA SUDING SLEEVE 2.813 4.500 ,, - 4844 10 3 1/2"TUBING PUP JOINT 2.992 3.500 ....... 4854 5 SEAL ASSEMBLY 2.992 4.000 4859 3 OTIS AWD PACKER SET ON SUBASSEMBLY2 4.000 6.000 4862 8 SEAL BORE EXTENSION 4.000 5,032 ,, , i .... XO ',D COMPLETION SCHEMATIC NCIU A-1' SUBASSEMBLY 4 -:.: : Cl 4 4552-4588 Cl 5 4624-4674 Cl 6 4708-4738 OTIS TYPE BWR PERMANENT PACKER 4 1/2" PUP JOINTS 4 1/2" BLAST JOINTS 4 1/2"TUBING AND PUP JOINTS 4 1/2" BLAST JOINTS 4 1/2" PUP JOINTS XO SUDING SLEEVE 4 1/2" TUBING AND PUP JOINTS 4 1/2" BLAST JOINTS 4 1/2" PUP JOINTS SEAL ASSEMBLY OTIS AWD PACKER SET ON SUBASSEMBLY 3 SEAL BORE EXTENSION 4.000 6.000 3~58 4.500 3.865 5.563 3.958 4,500 3.865 5.563 3.958 4.500 3.813 4.5OO 3.958 4.500 3.865 5.563 3.958 4.500 2.992 4.000 4.000 6.000 4.000 5.032 .,dED COMPLETION SCHEMATIC NCIU A- CI I 4351-4391 CI 2 4402-4482 1- SUBASSEMBLY 5 OTIS TYPE VSR RETRIEVABLE PACKER 4 1/2"TUBING AND PUP JOINTS 4 1/2" BLAST JOINTS 4 1/2" PUP JOINTS 4 1/2" BLAST JOINTS 4 1/2"TUBING AND PUP JOINTS XA SUDING SLEEVE 4 1/2" PUP JOINTS SEAL UNIT FOR RATCH A LATCH HEAD RATCH A LATCH RECIEVlNG HEAD OTIS BWR PACKER SET ON SUBASSEMBLY 4 3.860 3.958 3.865 3.958 3.865 3.958 3.813 3.958 3,860 5.000 4,000 6.000 4.500 5.563 4.500 5.563 4,500 5.563 4.500 5.000 6.000 6.000 ,,NED COMPLETION SCHEMATIC NCIU A-I' SUBASSEMBLY 6 CIA 4O85-4095 CI B 4116-4140 OTIS TYPE VSR RETRIEVABLE PACKER SQUEEZED SQUEEZED 4 1/2" TUBING AND PUP JOINTS SEAL UNIT FOR RATCH A LATCH HEAD 4.000 3.958 5.000 3.860 ?ill!iii(IN) 6.000 4.500 6.000 6.000 OTIS VSR PACKER SET ON SUBASSEMBLY 5 ;. _ L P NNED COMPLETION SCHEMATIC NCl A-1 SUBASSEMBLY7 !-:F. ORMATIOI~ i:PERFS .... l il .:'l~eplfi~!!.-:: .:;iiLength.i ~,- : .';: Des,cription · ' -i:i!;I.Oi:-. ~i:::i ~ ' ' ·' ;(TOP)-.+ i~(Fr) ' : -- ~ '~ : '.'~'.'-..~ ~...-~i:i~; '. ;:?,~?-~'._...~:;~;!;:~i?,,~.,__ ' ': 39 I TUBING HANGER 40 241 4 1/'Z' 8uI'rRESS TUBING 3.958 4.500 284 5 X-OVER 4 1/'Z' 8RD EUE PIN X4 1/2' BuTr BOX 3.958 4.500 .... , , , , ,., - ....... .......... , , 289 3698 4 1/2" EUE 8RD TUBING 3.958 4.500 .... 3987 5 SEAL ASSEMBLY 3.860 5,000 , , 3992 6 UPPER SEAL BORE W/RATCH A LATCH SEALS 5.000 6.000 ......... , 3998 2 SEAL UNIT FOR RATCH A LATCH HEAD 3.860 5.000 4000 7 OTIS TYPE VSR RETRIEVABLE PACKER 4.000 6.000 I ' ' I , , ..... NCIU RESERVOIR PRESSURES BASED ON SUNFISH RFT DATA 3000 4OOO 5000 6OO0 0 TVD COOK INLET B COOK I=NLET COOK INLET 6 : C.OOK INLET 7 \ '-. O0~K IN~ET COOK INLET COOK INLE~.T 2 COOK INLE..'r 4 COOK INLET.. 8 .............................. .C....O..,O...K.....LN...L...E...T.....tO... ..... COOK INLET 11\ UP.PER BELUQA :. : .. ~.IdlDDLE BELba^ '.. 500 1000 1500 2000 2500 RESERVOIR PRESSURE(PSI) 3000 NClU RESERVOIR PRESSURES BASED ON-A-1 PRODUCTION LOG TVD 3000 4OOO SOO0 6000 0 ~o--o ...... .o ..... o ...... o.o-oo ..... ....................., ......... oo~. ....... o.o-~. ....... ooo.'.1-o-oo ................ · ..................... o...oooo ................ · ...... · ...... ooo. ..... · · . : ; ~ COOK INLET ^, B, 1 AND 2 I............................ '~'~'~'"i"~'~"~'~.:"~ ..... 'f: ........... ,~' .......... ~' ...................................................................................... ~ --5 COa. K INLET 10 -. ................................................................................... ~ .............. i~. ............. i~: ............ :~. ........................................................... : : ............................................................................................ ~. ................ ~. ................ ~ ................ ~ ............................................. ; 500 1000 1500 2000 2500 RESERVOIR PRESSURE(PS1) 3000 PL ADVISOR Production Logs Interpretation Using a Global Solver (V4) North Cook Inlet A-1 Company Field Well Logging Date Processing Date Reference . PHILLIPS PETROLEUM COMPANY - NORTH COOK INLET GAS PLATFORM . NORTH COOK INLET A-1 _ - JULY5,1991 . DECEMBER 21,1991 . 74687 Schlumberger Well Services Alaska Division Computing Center 500 West International Airport Road Anchorage, Alaska 99518 907/562-2654 PHH, LIPS PETROLEUM NORTH COOK INLET FIELD Well A-1 Logged 7/05/91 INTERPRETATION This wen was produc and production lOgged at the following surface production rates: 0.0 MMscf/day, 10.2 MMscf/day, 8.2 MMscf/day, and 9.4 MMscf/day. A pressure build-up survey, PBU, was done after the 9.4 MMscf/day production log survey was completed. The 10.2 MM and 8.2 MM surveys were done across the producing zones below the robing tail, while the 9.4 MM survey was done only across the sliding sleeves located in the tubing at 4211 and 4412 ft. The shut-in survey was done across all zones, below and above the tubing tail. This information was then used to determine 1.)the reservoir pressure for each of the producing byers, 2.)productivity index, and 3.)if there is crossflow between zones. The most important information from the survey is that zone CI-11 is covered with water and is not producing, or the production is Wo small to measure. This is important, because in thc past, this zone was a low pressure zone that was recharged when the well was shut-in at thc surface. This zone was' also one of thc best producing zones in the well when the bottom hole pressure was drawn down -- but now thc zone produces nothing. Another very important piece of information is from the continuous flowmcter survey that was recorded in the tubing and just below the tubing tail while the well is producing 9.4 MMscf/day at surface. It appears that thc top sliding slide is closed. No production is entering thc well through this sleeve. The bottom sliding sleeve is leaking and the production below thc tubing tail is less than the production above the tubing tail. I believe that the lower two packers are leaking and the production from the A, B, CI-1, and CI-2 sands is being produced down the annulus, through the lower sliding sleeve and also around the robing tail. The WFL log indicates no water flowing just above the tubing tail, but it does indicate water flowing above both sliding sleeves at a depth of 4173 ft. The water has to be entering thc tubing through the lower sliding sleeve. The temperature log indicates that the Middle Beluga sand at 5604-5616 ft. is trying to produce. Zone CI-6 is a thief zone when the well is shut in. Zone CI-4 is also taking some production when the well is shut-in. The main producing zones are: CI-4, CI-6, CI-8, CI-10, and the zones above the robing tail. The pressure build-up survey when corrected to 4400 ft. TVD indicates that the average pressure of all the producing zones is 1257.3 psi. PHILLII~j PETROLEUM NORTH COOK INLET FIELD KENAI, ALASKA The following ruults wei~ determined: Zone Producin~ Interval Well A.1 Logged 7/0S/91 A B Tubing 3995 1247.3 1260.2 +14.7 IMM/16.3 psi CI-I Tail CI-2 · CI-4 4552-4588 4030 1234.2 1246.0 0.5 IMM/45.9 psi CI-5 4624-4674 4081 m m ~ CI-6 4708-4738 4150 1237~ 1245.5 0.0 IMM/12.0 psi CI-8 48744886 4284 1263.0 1266.7 +21.2 IMM/20.7 psi Cl-10 ~00-$012 4386 1301.5 1302.0 +56.5 IMM/~3.9 psi CI-11 ~044-5080 4428 ~ ~ ~ M.B. 5604-5616 5496 m ~ ~ The presmre build-up survey when corrected to 4400 ft. TVD indi~_, that the average presmm of all the producing zones is 1257.3 psi. All potential psusu~.s are refe~.~:ed to a TVD depth of 4400 ft. 'Fne gas gradient is 0.032 psi/ft. The Productivity lnchex was calculated for the 10.2MM and 8.2MM rates. COMPARISON OF 1987,198t, and 1991 RESULTS Ali pressures values are referenced to 4400 ft., TVD ZoM 1987 Pressure 1988 Pressure 1991 Pressure Stray Not Perforated A* 1452.0 1374.2 1260.2 B* 1452.0 1374.2 1260.2 CI-I* 1452.0 1374.2 1260.2 CI-2* 1452.0 1374.2 1260.2 CI-3 Not Perforated CI-4 1450.5 7 1246.0 CX-5 Not Prodncing 1369.2 Not Producing CX-6 1407.0 1358.8 1245.5 CI-7 1412.0 Not Producing Not Producing ' CI-8 1409.~ 1374.1 1266.7 CI-9 Not Perforated CLI0 1493.5 1447.9 1302.0 CX- 11 1398.5 1357.3 Not Producing U.B. Not Pefforamt M.B. 1424.2 ? ? L.B. Not Pmdncing Not Producing Not Prodncing *~ones A, B, CLI, and CI-2 a~ aH behind tubing. *Zones Cl-I 1 is covered with water and is not producing in 1991. 7Zones that a~ l~dnc/ng, but a reservoir prusur~ could not be caicu!~___~-d_ due to tbe pro~___~n,~o~ from the zone was not great enough or the pmcluction from one rate to ano~er was not stable or it was influenced by the water column in the wellbore. PHILLWS PETROLEUM NORTH COOK INLET FIELD KENAI, ALASKA Well A-I Logged 7/05/91 SURFACE PRODUCTION RATES Zones Perforations TVD Stray Not Perforated A 4085-495 3629 B 41164140 3655 CI-I 4351-4391 3853 CI-2 4402-4482 3896 CI-3 Not Perforated T.T. 4521 3995 10.2MMscf 8.2MMscf 0.0MMscf Zones A, B, CI-I, and CI-2 are behind.tubing and comingled. These zones are entering the tubing around the tubing tail and lower sliding sleeve. 2,612,100 1,803,600 +450,000 CI-4 4552-4588 4030 740,800 442,000 -269,3000 CI-5 4624-4674 4081 0 0 0 CI-6 4708-4738 4150 3,448,900 2,376,6000 -1,283,400 CI-7 4760-4784 4189 0 0 0 CI-8 4874-4886 4284 2,532,300 1,870,700 +680,000 CI-9 Not Perforated CI-10 5000-5012 4386 865,900 1,707,100 +422,700 CI- 11 5044-5080 4428 TSTM* TSTM* TSTM* U. Beluga Not Perforated M. Beluga 5604-5616 TSTM* TSTM* TSTM* L. Beluga Not Producing 0 0 0 Calcula~d Surface Rates lO.2MMscf 8.2MMscf O. OMMscf Zones A, B, Cl- 1, and CI-2 are producing together and around the tubing tail. The upper sliding sleeve at 4211 is closed and there is not production coming from this sliding sleeve. The lower sliding sleeve is leaking with most of the production coming around the tubing tail. The production from Zone CL 10 is less at the 10.2MM surface ram than the 8.22MM surface rate. This is due to the standing water in the bottom of the well moves up the well from 4925 ft. to 4878 ft. and covers Zone CI-10 when the well is produced at 10.2MM/day. This additional . water column restricts the gas flow rate out of Zone CI-10. TSTM*--too small to measure. Gas/Water contacts are at: 10.2MMscf-- 4878 MD, 4287 TVD 8.2MMScf---4925 MD, 4325 TVD 0.0MMscf-- 4888 MD, 4295 TVD llll IIII PHILUP$ PETROLEUM CO, WELL NCI A-l, N. COOK INLET, 7/05/91 (74687) PRODUCTION FLOW PROFILES AT DIFFERENT FLOW RATES GAMMA-RAY 1991 IO.2MM 8.2MM O. OMM o (GAP~) ~0 O. CMs, f) '~2000 O. (Ms~ '12000 -2000. (MScO 20OO ¢1 ¢1 l PHILLIPS PETROLEUM NORTH COOK INLET FIELD KI~AI, ALASKA WATERFLOW LOG DATA Well A-I Logged 7/05/91 F'de # Minitron Pulse 1 Ft. 2 Fr. 1.5 I:L Depth Detect Detec~ Detect Ft. FPM FPM FPM 43 4173.3 lOx15 0 0 111.9 *** 4210 --Upper Sliding Sleeve ,,, 4412 -- Lower Sliding Sleeve 46 4516.3 10xl$ 0 0 0 *** 4521 m TUBING TAR, 44 4538.3 lOxl$ 0 0 0 *** Zon~ Cl-4 *** Zone Cl-5 47 4693.2 lOx15 0 0 0 *** Zone CI-6 40 4743.3 lOx13 0 0 0 *** Zone CI-7 31 4848.4 2x13 0 0 _ 0~ 33 .4848.4 10115 0 0 0 *** Zone CI-8 28 4938.4 10xl5 0 F 44.8 29 4938.4 10xl5 0 F 45.9 39 4993.3 10x7 0 F 42.4 *** Zone CLIO 36 5008.3 lOx15 F F 46.9 37 5013.3 l(}xl6 F 2.3 0 30 5018.4 10xl5 0 0 0 38 5018.4 10xl2 0 0 0 *** Zo~ CI-I 1 34 10x15 0 0 0 **** The WFL tool was nm in rise 'UP FLOW MODE". **** CALCULATING WATER FLOW AT A DEFrH OF 4173.3 BWPD = ((2.992f2)*'2 - (1.6875/2)*'2)(3.1416)(1.7408)(111.9)(Hy) = 95.5 BWPD, Hy = .10 Tber~ is no water flowing below the tubing tail in tiffs well 'l'ne only flowing water that was detected in this well was above thc sliding sleeves at 4210 md 4412 n. negor~ ~is wen is worted over, it would be a good idea to rerun the WFL log and determine if the water is co_ming from the upper or lower sliding sleeves. It should be kept in mind that the lower two packers are leaking in this well and thi~ was verified in 1987. Them is no water flowing at the following dq~hs * 4938, 4993. 5008, and 5013. The water flowing effect at these ~ is due to water being pulled up the well by the gas that is being produced from Zone CI*I0 and then the warn' is falling back down the well. This effect is called "the water faliback effect". 'lhe WFL tool measured only water flowing in the up direction, because the tool was setup to measure only the water flow in the up direction. BASE GAMMA-RAY (~API) 4100 4200 01-2 45O0 ~ 01-4 4~00~ .. CI-5 4700 ~ 4900 5OOO CI-8 530~ 5400 '~ -.~' 5500 ~ -'" M. BELUGA A B MINr1310N PHILLIPS P r,,E'~)LEUM CO, W~ NCl A-l, N. COOK INLET, 7/05/91 (74687) ~::: :::::::::::::::::::::::::::::::::::: ;::~;i:~;_;:;:~_;;~.,::~j>;,;-;.;.;-;,.>.~.;,;-.'i::~:~,, x- .............. ...;.;<.-,..-..,?..,~...,.-;-;.....,.;-......................-~......-.....-.-..... :.:..... I · ,..-.-.-.-,-.,.,v.-,-~.,,..,,,,~.,.,-....;-~,;--~,,,,..,.-.F~ ,:~,,,,..~>.,.:.,.,:,:,t.,,-~*¢.~,,~ WATER ......,;.~:¥~.*.,~,....:,:-:.;.:.:-:.:.:.:.:-:.:':..,:.:...:.:.:.:.:-:.:.:.-:-:...:-:-' .... '-...'.' CALCULATED WATER PRODUCTION RATE FROM WFL LOG I o. (BWPD) 200 THE BOTTOM 'rwo PACKERS ARE LEAKING. THE,WFL LOG DETERMINED THAT WHERE IS NO WATER FLOWING ABOVE THE'TUBING TAIL. ABOVE BOTH OF THE SIDLING SLEEVES THERE I$112 BWPD FLOWING. THE UPPER SLIDING SLEEVE I$ CLOSED, BUT LOWER :SLEEVE IS PARTLY OPEN. WFL MEASUREMENTS WATER FLOW ADVISOR INTERPRETATION PHILLIPS PETROLEUM NORTH COOK INLET FIELD KENAI, ALASKA Well A-1 Logged 7/05/91 10.2 MMscf/Day -- Surface Rate 10.2 MMscf/Day .-- Production Logging Rate ~one Perforations Zone Contributing Percent Stray A B CI-1 CI-2 CI-3 Not Perforate3 -- 4085-4095 4116-4140 43514391 4402-4482 Not Perforated -- S.S.** T.T.*** 4211 Zones A&B 4412 Zones C-I&2 4521 Zones A,B,C-I&2 CI4 4552-4588 4552-4580 7.3 4708-4738 47084738 33.8 47604784 48744886 48744886 24.8 Not Perforated CI-IO 5000-5012 5000-5012 8.5 CI-11 5044-5080 5044-5080 TSTM Not Perforated 5590-5596, 5604-5616, 5663-5674, 5679-5692, 5708-5715, 5874-5888, 5892-5904, 6076-6084, 6098-6118, 6271-6278 6509-6514, 6578-6584, 6589-6602, 6790-6799, 6806-6814 *Upper sliding sleeve is not producing. **Lower sliding sleeve is l~king. ***Most of the production from behind the tubing is entering the tubing at the tubing tail Rate Mscf/D 2612.1 740.8 0.0 3448.9 0.0 2532.3 865.9 II II GR 1991 (GAPI) 80. .. FBS FLUID VEL -80. (F/MN) 400. iii ZONE Cl-8 ZONE C1-10 ZONE C1-11 PHILUPS PETROLEUM CO, WELL NCl A-1. N. COC ET, 7/05/91 174687) · SURFACE PRODUCTION RATEWAS 10.2 MMscf / DAY WITH SOME WATER 0.1 I FLUID DENSITY I TEMPERATURE FBS SPINNER ' (G/C3) 1,1I 82 (DEGF) 92. .10. (RPS) 20. ZONE CI-4 ZONE Cl-5 ZONE CI-6 ZONE Cl-7 PRESSURE 1150 (PSI) 1350. PHILLIPS PETROLEUM NORTH COOK INLET FIELD KENAI, ALASKA Well A-1 Logged 7/05/91 9.4 MMscf/Day--- Surface Rate 9.321 MMscf/Day --- Production Logging Rate Zone Perforations Zone Contributing Percent Rate Mscf/D Stray A B CI-1 CI-2 CI-3 Not Perfornte, d 4085-4095 4116-4140 4351-4391 4402-4482 Not Perforated 0.0 S.S.** T.T.*** Below the robing tnil CI.4 · 4211 Zones A&B 0.0 4412 Zones C-I&2 5.2 4521 Zones A,B,C-I&2 22.8 72.0 4552-4588 4552-4580 _. Producing 0.0 482.4 2127.0 6711.8 4624-4634 0.0 CI-6 4708 -4738 4708-4738 Producing 4760-4784 0.0 CI-8 4874-4886 4874-4886 Producing Not Per[om~ CI-10 5000-5012 5000-5012 Producing CI-11 5044-5080 5044-5080 TSTM Not Peffor~d 5590-5596, 5604-5616, 5663-5674, 5679-5692, 5708-5715, 5874-5888, 5892-5904 6076-6084, 6098-6118, 6271-6278 6509-6514, 6578-6584, 6589-6602, 6790-6799, 6806-6814 Only thc robing was logged at this rate. *Upper sliding sleeve is not producing. **Lower sliding sleeve is leaking. ***Most of thc production from behind thc tubing is entering thc robing at thc tubing tail. i i - ~ .) p.lll Ips PETROLELIM CO, WELL NCIA-I' N., JK INLET. 7/0E/9'1 (746~7) SURFACE PRODUCTION RATE WAS 9.4 MMscf / DAY WITH SOME WATER ,,, GR 1991 FBS FLUID VEL FLUID DENSITY TEMPERATU RE FBS SPINN ER PRESSURE ._ o. (C-=APl) 80. 1000. (:F/lVlN) 3000, 0.t (~C3) 1.1 aO (DE~II=) 84. 160. (RI)S) 260. 1160 (PSi) 1200. PRODUCTION LOGGED ONLY THE TUBING ! \ \ 43OO /. ! UPPER SLIDING SLEEVE MIDDLE PACKER LOWER SLIDING SLEEVE BOTTOM TWO PACKERS ARE LEAKING PHILLIPS PETROLEUM NORTH COOK INLET FIELD KENAI, ALASKA Well A-1 Logged 7/05/91 8.2 MMscf/Day -- Surface Rate 8.2 MMscf/Day -- Production Logging Rate Zone Perforations Zone Percent Rate Contributing Mscf/D Stray A B CI-1 CI-2 CI-3 Not Perforated 4085-4095 4116-4140 4351=4391 4402-4482 Not Perforated S.S.** T.T.*** 4211 Zones A&B 4412 Zones C-I&2 4521 Zones A,B, CI-I&2 22.O 1803.6 4552-4588 4552-4580 5.4 442.0 4624-4634 .... 0.0 4708-4738 4708-4738 29.0 2376.6 4760-4784 ..... 0.0 4874-4886 4874-4886 22.8 1870.7 Not Perforated CI-IO 5000-5012 5000-5012 20.8 1707.1 CI-11 5044-5080 5044-5080 TSTM TSTM Not Perforated M.B." L~B. 5590-5596, 5604-5616, 5663-5674, 5679-5692, 5708-5715, 5914-5888, 5892-5904, 6076-6084, 6098-6118, 6271-6278 6509-6514, 6578-6584, 6589-6602, 6790-6799, 6806-6814 *Upper sliding sleeve is not producing. **Lower sliding sleeve is leaking. ***Most of the production from behind the tubing is entering the robing at the tubing tail. *Production from the sliding sleeves ar~ combined. PHlUJPS PETROLEUM CO, WEII NCI A-l, N. COOK INLET, 7/06/91 (74687) SURFACE PRODUCTION RATEWAS 8.2 Mldscf/DAYWITH SOMEWATER __ (3R 1991 FBS FLUID VEL FLUID DENSITY TEMPERATURE FB$ SPINNER PRESSURE , o. (eAPI) ~0. -~0. (F/MN) ~00. 0.~ (~/C~) t.~ aa (DEeF) ;2. -~S. (;~) ;0. ~200 (PSi) ~:~SO. S ZONE C1-5 I .... ~ I I: ' II 4700" ,. / \ -- I .,,,~~ l! I: I ! 5100 ' PHILLIPS PETROLEUM NORTH COOK INLET FIELD KENAI, ALASKA Well A.1 Logged 7/05/91 0.0 MMscf/Day-- Surface Rate 0.0 MMscf/Day- Production Logging Rate Zone Perforations Zone Contributing Percent Rate Mscf/D SWay Not Perforated --- A 4085-4095 B 4116-4140 CI-1 4351-4391 CI-2 4402-4482 Cl-3 Not Perfornted -- S.S.* 4211 Zones A&B S.S.** 4412 Zones C-I&2 T.T.*** 4521 Zones A,B, CI-I&2 +29.0 +450.0 Cl.4 4552-4588 4552-4580 -10.8 - -269.3 Cl-5 4624-4634 -- -- 0.0 Cl-6 4708-4738 4708-4738 -89.2 -1283.4 Cl-7 4760-4784 -- -- 0.0 Cl-8 4874-4886 4874-4886 +43.8 +680.0 Cl-9 Not Perforated Cl- l O 5000-5012 5000-5012 +27.2 +422.7 Cl-ll 5044-5080 5044-5080 TSTM TSTM U.B. Not Perforated 5590-5596, 5604-5616, 5663-5674, 5679-5692, 5708-5715, 5874-5888, 5892-5904, 6076-6084, 6098.-6118, 6271-6278 6509-6514, 6578-6584, 6589-6602, 6790-6799, 6806-6814 *Upper sliding sleeve is not producing. **Lower sliding sleeve is leaking. ***Most of the production from behind the tubing is entering the tubing at the robing tail. Il 1 i i iiiii i i ~ ~.,~ i i ii i --' ~ PHILLII~ PETROLEUM CO, WELL NCI A-l, N.___K INLET. 7/05/m (74~S7) WELL SHUT-IN AT 8UFACE · ...... GR 1991 FBS FLUID VEL FLUID DENSITY TEMPERATURE FBS SPINNER PRESSURE .... O. (GAl=I) 80. -50. (F/MN) 75. 0.1 (G/Ca) 1.1 80 (DEGF) 92. 2. (RPS) 7. 1200 (PSI) 1350, ... -- i i i u i , I t I I I 5100 . PHILLIPS PETROLEUM NORTH COOK INLET FIELD KENAI, ALASKA Well A.1 Logged 7/05/91 LISTING OF MD, TVD, PRESSURE AND PRODUCTION RATE FROM EACH PRODUCTION ZONE Zone M.D. TVD 10.2MMscf 8.2MMscf 00.MMscf A B CI-1 0-2 (s.s.) ~412 3905 (T.T.) 4521 3995 2612.1 M 1803.6 M 450.0 M 1205.5 psi 1216.9 psi 1240.3 psi CI-4 4552 4030 740.8 M 442.0 M 1201.8 psi 1215.9 psi -269.3 M 1240.8 psi CI.6 4708 4150 3448.9 M 2376.6 M 1206.0 psi 1220.3 psi ~-1283.4 M 1245.0 psi CI-8 4874 4284 2532.9 M 1870.7 M 1211.0 psi 1224A psi .680.0 M 1248.7 psi CI-10 5000 4386 865.9 M 1707.1 M 1244A psi 1243.2 psi 422.7 M 1286.9 psi CMl 5044 4428 1259.3 psi 1258.0 psi 1302.6 psi 10.2 MMscf/day -- 4878, MD 4287, TVD 8.2 MMscf/day -- 4925, MD 4325, TVI) 0.0 Mscf/day -- 4888, MD 4295, TVD Thc production coming from above thc robing tail is all referenced to thc robing tail, because thc upper sliding sleeve is closed and thc bottom sliding sleeve is leaking only about 480 Mscf/day when thc surface production is 9.4 MMsef/day. Thc bottom two packers are leaking and thc production from the annulus is flowing downward and enters thc well at thc robing tail. PHILLIPS PETROLEUM NORTH COOK INLET FIELD KENAI, ALASKA Well A.I Logged 7/05/91 STRAIN GAUGE PRESSURE VERSUS "TVD'* Measured TVD 10.2 MM 9.4 MM 8.2 MM 0.0 MM 4070 4~0 4540 4600 4680 474~ ~$0 4940 ~50 3617.6 3793.8 39613 4011.2 4060.7 4126.9 4179A 4264.9 4337.8 4401.7 4819.7 4938.5 --- 1162.93 --- -- 1180.16 -- -- 119529 --- 1204.66 -- 1217,83 1202.89 -- 1217.55 1205.17 --- 1219.77 1206.81 --- 1221.40 1210.40 --- 1223.82 1226.50 --- 1227A1 1251.09 --. 1249,85 1432.21 ---. 143537 1483.20 -- 1486.67 123929 124036 1245.25 1240.65 1242.28 1244A1 1245.88 1248.07 1265.82 1293.98 1478.76 153227 lVlD TVD 4521 3995 4870 4281 4918 4320 4896 4302 Tubing Tail 10.2 MMscf rate, gas/gas-wa~' contact' 9.4 ~ rate, gas/gas-water comaet 8.2 Ml~f rate, gas/gas-warn' contact 0.0 MMscf rate, gas/gas-wa~er contact *9A MMscf production rate was only logged inside tubing. _ GR 1991 o. ¢OAP~) ~0. 1:933 Ft 4700{ ) 51Q0 -~HILUPS PETROLEUM CO, WELL NCl A-l, N. CO0! ~ 7/05/91 (74687) PRESSURE GRADIENTS FOR DIFFERENT SURFACE FLOW RATES PRESSURE 11 SO (PSO 13SO. ...... ~ :. el- D 4081 i ! ' , ~ , i !~ : 8.OM SURFACE I ~ ii I ; I [- WELL SHe-iN , ,,, I : m [ , ~l-o D 42 4) .! ~ , :GAS~ATER CO.ACm I ~ ~ AS SURFACE PRODUC~ON ,, [ ~TES CHANGE I , ~M~SURED OEP* VS ,RE~URE""" G~D~ms,Xxlq3 NCIU RESERVOIR PRESSURES BASED ON A-3 PRODUCTION LOG 3000 TVD 4000 5000 600O \¢ : ......................................................... i .......... A. .......... ;., .......... q ...................................................................................................... ',,. \ '-,.. ',,.. \ "-.. ,~?OQK INLET A, B ............................................................... ....... ; ...... ..... ................................................................................. COOK INLET 11 : " .......................................................................... ... ............ \. ............. ~: ............................................................. ... ....................... 0 500 1000 1500 2000 2500 ;3000 RESERVOIR PRESSURE (PSI) NCIU RESERVOIR PRESSURES BASED ON A-7 PRODUCTION LOG 3OO0 TVD 5O0O 6O0O ! I I: I 0 500 1000 1500 2000 2500 3000 RESERVOIR PRESSURE (PSI) NCIU A-1 RISER AND BOP ARRANGEMENT I 6M ANNULAR PREVENTER 1OM VARIABLE BORE PIPE RAMS 1OM BLIND RAMS DRILLING SPOOL 3 1/2' 1OM PIPE RAMS RISER' 13 5/8' 1OM X 13 6/8' 6M ADAPTER 13 $/8' 6M X 16 3/4' 6M CLAMP RISER 16 3/4' 6M X 16 3/4' 6M I UNIHEAD 16' 8RD X 16 3/4' 6M CLAMP HUB Vendor List Service Drilling Rig Cement and Pumping Services Workover Fluid Well Testing Equipment (surface) Drill Stem Test Tools (downhole) Nitrogen Pumping Service Wireline Logging Tubing Conveyed Perforating Wellhead Equipment and Service Rental and Fishing Tools Rental Tools* Rental Tools* Coiled Tubing Service Vendor Contact Telephone Pool Arctic Alaska Larry Ross (907) 276-5464 Dowell-Schlumberger M-I Drilling Fluids Production Testing Service Schlumberger BJ Services Schlumberger Vann Systems Mike Mahoney Bob Haagensen Robert Hoff Lance Dunn David Wallingford Lance Dunn Chris Cowans (907) 274-5564 (907) 258-2022 (907) 776-8182 (907) 562-2654 (907) 283-7812 (907) 563-3990 FMC Russ McBeth TH State Jimmy Bowman Homco DSR Companies Arctic Recoil Alvan Walker Kenai Air (907) 776-8791 Helicopter Service Supply Boat PVT system and service Free point & back off tools Seacor "Mustang Island" Totco Dia-Log Billy Applewhite (907) 522-3234 (907) 283-1980 (907) 283-7561 (907) 562-7602 (907) 263-4577 * Additional rental tool companies are listed to provide flexibility in the event Td State is unable to provide all the tools required. Telephone List i Position Drilling & Production Engineering Manager Kenai Area Manager Drilling Supt. Drilling Engineering Director Drilling Engineer Production Engineer Reservoir Engineer Materials Coordinator - Kenai Material Coordinator - Houston Safety Specialist - Kenai Alaska Oil and Gas Conservation Commission David Gill Roy Lyons Walt Carrico Wes Gibson Dennis Morgan Fritz Krusen Joe Voelker Jim Magee Mary Laws Bob Wirtanen LOnnie Smith Office Number (713) 669-3519 (907) 776-8166 (907) 776-8166 (713) 669-2969 (713) 669-2173 (907) 776-8166 (713) 669-7475 (907) 776-8166 (713) 669-3712 (907) 776r8166 (907) 279-1433 2640 - 2670 2670- ~030 ~O30 - &260 ~2'60- 4310 4310- ~320 4320- ~800 4800- ~970 4970 - 5155 5155- 5520 5520- 5910 5910- 6075 6075 - 6155 6155 - 62~5 6245 - 6515 6515 - 6570 6570 - 6855 6855 - 6890 6890- 7245 7245 - 7&75 7~75 - 8270 March 24, 1969 Clyde R. Seewald PHILLIPS PETROLEUM COMPANY N.C'I.Unit #A-1 North Cook .Inlet Field Cook ~nlet, Alaska SAMP~ D~CRIPTION Claystene, it. gy, soft, calc. Sand; dk gy, f-cg, poorly srtd, pred. qtz. w/sctd gy claystome stringers, amd w/sctd thin coal beds. Sand; med gy, f-rog, slty, poorly srtd. Claystone; gy to bm, slty, carb., hd. Coal Sand; med gy, m-cg, mod srtd, pred. qtz. w/abun blk, gm, and pink grains; w/sctd thin coal beds and claystone stringers. No sample returns. Sand; mod gy, rog, ang-subang; w/sctd coal beds and w/Brown carb. sh stringers. Clay; gy, slty, soft; w/sctd coal beds and w/sctd thin sand stringers. Claystone; gy to bm, slty, mod hd w/some sandstone and siltstone stringers. Sandstone; gy, f-rog, ang-subang, pred. qtz., friable, w/some shale and siltstone stringers.. Shale; gy, slty, carb., mod hd, w/siltstone stringers. Sandstone; gy, f-rog, very friable, ang-smbang. Shale; gy, slty, mod hal, w/se thin sandstone stringers. Sandstone; It. gy, fg, subang, friable. Claystone; gy to tan-gy, silty, soft w/sctd coal beds. Sandstone; ned gy, vf-fg, silty, poorly srtd. Claystone; gy to tan-gy, carb., soft w/thin siltstone, sandstone and coal stringers. Claystone; gy to tan-gy, carb., soft Claystone; gy, silty, calc, soft to firm PHILLIPS PETROLEUM COMP~ N.C.I. UNIT NO. A-1 Sidewall Core Analysis Shot 30 Sidewall Cores, Recovered 30 Sidewall Cores with no shows. '1,.090 4117 ~,126 /.,158 /+190 /.,.390 ~560 ss, med. gry., fri., fair-well srtd.,' clear, subang fn. gr. (siderite ~6% and grn. stn .grs 10%) gd. per & perm. ss, med. gry, fri., fo srtd., subang, vf~-fn gr (siderite ~5% & gm. stn. 10%) gal. por &'perm. ss, med. gry., slt. fri, prly. srtd., suban~, v. fn-fn gr (siderite 30%, gm. stn. 5%) ably., pr. por. ss, med. gry., sli. fri, pr-f. srtd., subang to subrnd fn-med, gr (siderite 50% & gm. stn. 10%) Ed. per & perm. ss, med. gry., fri, prly. srtd., subang-subrnd, vfn-c, gr (siderite ~8% & gm. stn. 15%) good per & perm. . ss, med. gry.,' fri., prly srtd., ang-subang, v.fn-fn gr. (siderite 30% & gm. stn. grs 15%) f-gd per & perm. ss, med. gry., sli. fri, w. srtd., ang, vfn. gr. (siderite 30%) gd. per & perm'. ss, med. gry., fri, clean, w. srtd., subang, fn. gr, (siderite ~8% & gm. stn. grs. 5%) gd. per & perm. ss, ii-med, gry., sli fri, pr-f. Srtd., subang, vfn-med, gr. (siderite 25%) pr-f. per, has perm. ss, med. gry., sli to fri w. srtd., ang, v.fn gr. (siderite &O% & gm.. stn. pres~) gd. per & perm. A720 ~763 ss, Ii-med. gry., fri, w. srtd., subang, med. gr. (siderite 40% & gm. stn. 5%), gd. per & perm. ss, med. gry., sli fri, f. srtd., ang, v. fa. gr. (siderite grs. 15%) sli clayey, fair per & perm. siltst., med. gry., sft, clayey, pr-f. per &'tight ss, med. gry., ali fri f. srtd.., ang, v.fn. gr. (gm. stn.. 30% & widely scat. coal grs.~ tr. clay, pr-f. por · ss, med. gry., sli ~fri, prly. srtd., subang, v. fn-med, gr (siderite 10% & coal grs. pres.) tr. clay., f~. per & has perm. ,. 5900 6050 ~ 6100 611~ · ,, : 6592. 6596 7156 7166 · ~, i: 7250 7381 !. ss, wed. gry., sli fri, prly. srtd., subang, v.fn-c, gr (15% siderite grs.) sli clayey, pr-f. pot ss, Ii. gry., sli-fri, clean, w. srtd., ang, v. fn. gr (siderite 15% & gm. stn. grs. pres.) gd. pot & perm. ss, lt.-med, gry., sli fri, clean., w. srtd., subang, fn. gr (siderite & grn st 25%) f-gd pot & perm. w/coarse to pbl. size coal grs. com' ss, li.-med, gry., sli fri~ clean, w~' srtd.,' subang, fn. gr (siderite & grn st, 25%) f-gd pot & perm. ss, li. gry., sli fri, f-w. sortd., subang, fn. gr,(siderite & gm. sin. grs. 35%) f-gd. por & perm. ss, ii. gry., sli fri, pr.-f, srtd., subang-subrnd, fn-med, gr. (siderite 20%, gm. stn& coal grs. pres. ) tr, clay, fair p. or - has perm.. ss, med.-gry., sli fri, f.'-w, srtd., subang, fn. gr. (siderite 25%)sli. ~ 'clayey, fair por & perm. "ss, med. gr., sli fri, f. srtd., subang-subrnd., fn-med, gr (siderite & gm. stn. grs. com.), sli to clayey, pr-fair por & tight sam · a s above ss, med. gr., ali fri, prly. srtd., subang-subrnd, fn-coarse gr., (siderite & coal grs. pres.) clayey, pr. to fair por. & tight ss, med. gry., sli fri,' prly. srtd., subang fn-med, gr. (siderite grs. com.) slio carb., .clayey, fair por ss, med~ gry., sli fri, subang, fn. gr. (20% siderite & gm. stn. gms.) sli. carb. & clayey, poor-f, por, tight ss, med. gry., sli fri,. subang-subrnd, fn-med, gr. (20% gm. stn. grs.) clayey with widely scat. coal lams, fair por & tight ss, med,.~gry..., sli fri, subang-subrnd, fn-med, gr,, (20% gm. stn. grs.) clayey with widely scat. coal .lams, poor por & tight clayst., reed. · gry., sft., noncalc Described by Ken Sloan Februar~ -~, l~9 f,, CHRONOLOGICAL WELL HISTORY S~radded from surface. Drill 15" hole and ream to 22" to 630'. Set 16" casing at 613.59' and cemented w/950 sacks cement and 200 sacks down around top. 10/30-1/9/69 Suspended. Waiting on rig. Moved rig on hole, NU BOP & tested BOP & equipment to 20OO~. Drilled 15" hole to 2137'. Jumped DC pin out of b~x. Recovered fish. Drilled 15" hole to 2555'. Ran 10-3/~" casing, set at 25~3.77'. Cemented w/865 sx. Drilled 9-5/8" hole to 27~2'. Pipe stuck. Sp~tted 50 bbls diesel w/3 gallon Scotfree. Jarred fish loose. Drilled 9-5/8" hole to 2772', pipe stuck. Spotted ~O bbls diesel. Could not jar loose. Backed off O 2518.16'. Left 9-5/8" bit, 8" reamer, 2-7 3/~" monel collar, 7-3/~" stabilizer, 7-3/~" x 9-5/8" XO stabilizer and 5-7~" drill collars. Washed over fish to 2667', milled on stabilizer, COOH, WIH & recovered fish. Drilled 9-5/8" hole to 7127'. Drilled 9-5/8" hole to 8279'.. Took 30 sidewall cores. Set cement plug 770o' - 7500' w/l12 sx Type "G" cement in 13½ bbls 2% cc. Set 7" csg O 7~49.08'. Cemented w/S&6 sx Type "G" cement w/prehydrated Diacel 'D' and 2% cc. 2nd stage w/552 sx Type "G" cement in 2% cc water. Perforate as follows, & holes/ft., .&8" Dia., -6806'-681~,~, 6790'-6799', 6589'-6602', 6578'-658A', 6509'-6524', 6271'-6278', 6098'-6118', 6076'- 608&', 5892'-590~', 587&'-5888', 5708'-5715', 5679'-5692', 5663'-567&', 560&',5616', 5590'-5596', 50~+'-5080', 5000'-5012', ~87~'-&886', &760'- ~78~', ~708'-~738',~62~'-~67&', ~552'-~588', &A02'-~482', &351'-~391' ~116 ' -~240 ', ~O85 ' -~O95 '. Ran comb 3½" & ~" tubing string, set $ ~521'. 2/21/69 Ran ~-point back pressure test on perf's ~085'-~240'. Pt. #1, Flow 3-3/~ hrs on 3/~" choke, FTP 1275 PSIG, F.T. 58°F, FARO 20,050 MMCFD. Pt. #2, Fl~w 1½ hrs on 5/8" choke, FTP 2490 PSIG, F.T. 56~°F. FARO 16.150 MCFD. Pt. #3, Flow 1 hr on ~" choke, FTP 1706 PSIG, F.T. 5~F, FARO'il, 530 M~FD. Pt. #&,_Flow 1 hr on 7/16" choke, FTP 1781 PSIQ, F.T. 58~F, FARO 9,080 MCFD. 7~ hrs SITP 1912 PSIG, CAOF 28,000 MCFD. Shut In. DIVISION OF C, il. Ab!D OAS , EONOLOG CAL (C0N'T) 2/27-28/69 Test perf's ~552'-681~' DILL Moas. Flow 9 hrs en 3/~" choke, FTP 16~ PSI, F.T. 60OF, FARO 28.~ MMCFD. Flow 1 hr on ~" choke, FTP 1909 PSI, F.~. 62OF, FARO 14 MMCFD. Flow 1 hr on 3/8" choke, FTP 1978 PSI, F._T. 6lYF, FARO 7.9 MMCFD. Flew ~ hr on ~" choke, FTP 2011 PSI, F.T. 60~F, FARO 2023 PSI. Shut in for buildup 2 h~O rains. SITP 2023 PSI. Test perf's ~351'-~391'~ 4%+02'-4482' 5 hrs. Flo~.~5 hrs on 3/~" choke, FTP 1706 PSIG, F.T. 65°, FARO 25.7 ~CFD. Ail tests inaccurate' Communi- cations indicated. /- ~orth Cook Inlet Unit PERFORATIN~ AND $(pUEEZE RECORD ~I_V_I$1ON OF Oil. AND GAS Well ,,, Date 2-12-~9 2-13-69 STze of CastTng If H # U Per~orafing 68o6, 6790, 6589, 65?8, 6509, 6271' 6098' 6076' 5708' ~79' 5663' 5590' ~00' ~708' ~552' ~2 ' ~351' From 6814' ~ 6799' / 6602,/ 658~,~ 651~,/ 6~?~' ~ 6118,,/'. 6o~,~ 59o~,V ~6~6' ~, A886,~/ ~738'~ ~?A'C &391'~ ~0,/ Feet Per~orated 9' 13' 6' ?, 20' 8' 12' 1~' 7' 13' 11' 12' 6' 36' 12' 12' 30' ~0' 36' 80' Z~' 10' Holes 32 3~ ~6 28 20~ She of Holes fl fl H . # fl GUll DTamefer Ii ti _# fl ti fl # # # Gun Type Jet · · Pe~orafing Company ~resser Atlas II tlr Il n II Il II ti # 11 Il # ti If It Il II II 11 II II # II 11 II PHILLIPS PETROLEUM DAILY REPORT SUMMARY WELL: ~orth Cook Inlet Unit No. A-01 RIG: / FIELD: COOK INLET CNTY/S TATE: TYONEK%ALAS KA PAGE: 1 AFE#:P-V123 AUTH COST:$2,732,000 DATE DEPTH RPT NO MW OPERATIONS SUMMARY DAILY COST CUM COST EVENT TYPE:Workover 07/28/92 7,449 I RIG UP LUBRICATOR ' TEST ' PULL SSSV ' LOST PRONG ' TIH ' $1,506 $1,506 COULD NOT GET TOOLS BELOW 4170' ' SECURE WELL - SIFN 07/29/92 7,449 2 SAFETY MTG., PULL SLIDING SLEEVE PACKOFF, RUN 2" GR, SET X $7,329 $8,835 PLUG AT 4003', BLEED 500 PSI, PLUG HOLDING, FILL TUBING, SET BLANKING PLUG & PRONG, SET BPV, SECURE WELL 09/15/92 7,449 3 SKIDDING RIG TO A-1 $14,015 $22,850 09/16/92 7,449 4 SKID RIG. RIG OVeR A-l, SLOT AT MIDNITE, THIS DATE. $28,57'5 $51,423 CONTINUE RIG UP OF FLOOR AND LINES AND UTILITES. 09/17/92 7,449 5 RIG UP OVERNCIU A-1 - NIPPLE DOWN X'MAS TREE - RIG UP $32,083 $83,506 RISER SECTIONS AND BOPS 09/18/92 7,449 6 8.4 FINISH N/U-TEST BOPS-PULL BPV-PULL AO PLUG @ 283'-PULL "X" $36,714 $120,220 PLUG FROM 4049'-SHEAR PACKER LOOSE FROM 4060'-CIRCULATE OUT ANNULUS FLUID 09/19/92 7,449 7 8.2 CIRC AND CLEAN HOLE/LAY DOWN TUBING ANDASSORTED EQUIP./ $45,513 $165,733 TIH AND MILL OUT PACKER AT 4311'/CIRC BOTT UP/TOH W/PACKER 09/20/92 7,449 8 8.4 TOH W/WB PKR/TIH W/METAL MUN MILL/MILL OUT WA PKR AT 4515'/ $39,318 $205,051 TOH/TIH W/SPEAR AND RECOVER WA PKR/TOH/TIH W/6" MILL 6031'/ WASH AND CLEAN OUT TO 6265'/COULD NOT GET DEEPER/POOH 09/21/92 7,449 9 8.4 TOH W/MET MUN MILL FROM 6265/TIH W/FLAT BOTT MILL/WASH AND $31,542 $236,593 REAM SOFT SAND & FILL FROM 6265 TO 7424/CIRC HOLE CLEAN/POOH TIH W/BIT AND SCRAPER 09/22/92 7,449 10 8.4 FINISH TIH/CIRC & SWEEP HOLE/TOH/RU SCHLUMBERGER AND RUNNING $56,012 $292,605 CASING AND CEMENT EVALUATION LOGS 09/23/92 7,449 11 8.4 FINISH LOGGiNG/PICK UP RBP/RIH & SET AT 4026/TEST CSG TO $60,379 $352,984 2000 PSI/OK/TIH & SET RBP AT 4251/DUMP SAND/POOH/TIH AND SQUEEZE 4085 TO 4140/W IOOSX CEMENT/PU AND WOC/POOH/CUT LINE 09/24/92 7,449 12 8.5 WEEKLY BOP TEST/DRILL CMT TO 4100'/TEST PERFS/BROKE DOWN/ $51,025 $404,009 POOH/TIH/SQUEEZE PERFS-(4085-4095) W/50 SX/POOH/TIH/DRILL CMT TO 4100/CIRC BOTT UP 09/25/92 7,449 13 8.5 TEST PERFS(LEAK)/DRILL CMT TO 4205/TEST PERFS AT 4116 TO $46,710 $450,719 4140/LEAK/CBU/TOH/TIH/SQUEEZE 4085-4140 W/50 SX CLASS G~ TOH/TIH/TOC AT 3970/SOFT/NOC/DRILL CMT 4004-4075 09/26/92 7,449 14 8.4 DRILL CMT 4075 TO 4152/TEST PERFS/LEAKED/POH/TIH/SQUEEZE $43,791 $494,510 INTERVAL 4085 TO 4140 W/50 SX CLASS G/WOC/POH/PU MILL AND SCRAPER AND TIH/TAG CMT @ 3935/DRLG CEMENT TO 4030' 09/27/92 7,449 15 8.4 DRLG OUT CMT AND TEST SQUEEZED PERFS TO 2000 PSI/OK/MOVE RBP $33,404 $527,914 TO 5355'/DISPLACE HOLE/POOH W/RBP RET TOOL/RBP CAME APART/ LEFT IN HOLE/LAY DOWN 2.875" TBG/TIH-PUSH RBP TO 7405'/CBU 09/28/92 7,449 16 8.4 CIRC & COND/TRIP OUT/P/U TBG CONVEYED PERF ASS TO PERF COOK $119,210 $647,124 INLET SANDS - 4351 TO 5080 - TIH/PUT IN H20 CUSHION/TEST LINES/PERFORATE/FLOW WELL FOR CLEANUP 09/29/92 7,449 17 8.4 KILL WELL/POOH W/PERF ASSEMBLY/LAY DOWN GUNS/P/U DST TOOLS $46,085 $693,209 FOR DST #1/TIH/SET DST PKR @ 4287'/TEST 4351 TO 6814/ RUNNING PLT LOGS AT THIS TIME 09/30/92 7,449 18 8.4 LOGGING W/PLT ON DST #1/POOH W/gL/RELEASE PKR/MOVE BELOW $42,994 $736,203 CI-1 SAND & RESET ABOVE CI-2 SAND FOR DST #2/FLOW TO CLEANUP LOGGING N/PLT TOOLS ON LOW RATE FLOW/ 10/01/92 7,449 19 8.4 FLOW TEST DST #2/LOG W/PLT TOOL/POOH & RD gL/ATTEMPT LOWER $51,265 $787,467 PACKER & FAIL/CBU/POOH & LO DST TOOLS/TEST BOPE/TIH W/MILL & SCRAPPER/WORK THRU 4421-4430'/CON'T. TIH W/MILL 10/02/92 7,449 20 8.5 TIH TO TD.g/MILL/CBU g/HI-VlS SWEEP/POOH TIH W/DST TOOLS/ $88,434 $875,901 FAIL TO PASS 4418'/POOH LD PKR./TIH W/5.96" PACKER - gENT OK./SET PKR./FLOW TESTING DST #3/ 10/03/92 7,449 21 8.5 CLEANUP FLC~ DST #3/RU gL & PLT LOG WHILE FLOW TESTING/SI $62,691 $938,592 WELL/POOH W/WL/RELEASE PKR. & MOVE DOWNHOLE / RESET PKR./ OPEN WELL FOR CLEANUP DST ~ / 10/04/92 7,449 22 8.4 CLEANUP FLOW FOR DST #4/MANIFOLD FLARE LINES/CON'T. CLEANUP $40,607 $979,199 FLOW FOR DST #4 PHILLIPS PETROLEUM DAILY REPORT SUMMARY WELL: Eorth Cook Inlet Unit No. A-01 RIG: / FIELD: COOK INLET CNTY/STATE: TYONEK%ALASKA PAGE:2 AFE#:P-V123 AUTH COST:$2,732,000 DATE DEPTH RPT NO MW OPERATIONS SUMMARY DAILY COST CUM COST 10/05/92 7,449 23 8.4 CONTINUE CLEANUP FLO~ DST #4 $39,857 $1,019,056 10/06/92 7,449 24 8.4 CLEANUP FLOW DST #4/RU & LOG W/PLT LOGS/RD WL/REL. PKR./CBU $46,259 $1,065,315 POOH & CHG. OUT DST TOOLS/TIH W/DST TOOLS & RBP/SET RBP & ATTEMPT TO SET PKR. & FAIL/TIH TO RBP/PKR BACKED OFF XO SUB 10/07/92 ~,449 25 8.4 SCREW INTO PKR/RELEASE RBP/POOH/TIH W/RBP ON DP & SET/POOH $41,857 $1,107,172 W/SETTING TOOL/CHECK & TEST DST TOOLS/TIH W/TEST TOOLS/SET PKR/CLEANUP FLOW CI-3/RU WL/RUN PLT LOGS/ 10/08/92 7,449 26 8.4 FINISH LOG/SI FOR BUILDUP/POOH RD WL/CLOSE MFE/FAIL/TBG.FULL $61,086 $1,168,258 FLUID/CBU/REL PKR/LOWER TBG TO RBP & REL/LOWER RBP TO 4645' TIGHT/POOH/TEST BOP/TIH W/MILL/TIGHT @4421-4430' 10/09/92 7,449 27 8.4 WORK MILL THRU TIGHT CSG/TIH TO TD/CBU/POOH/TIH SET RBP/POOH $54,058 $1,222,316 TIH W/DST TOOLS/SET PKR/RU WL/TIH/OPEN WELL TO FLOW TEST CI-5 SAND/FLOW ~VARIOUS RATES/SI FOR BUILDUP/ 10/10/92 7,449 28 8.4 SI FOR BUILDUP-20' SAND FILL/POOH RD WL/ATTEMPT CLOSE MFE $48,100 $1,270,416 FAIL/SHEAR REV VALVE/CBU/POOH/LD DST TOOLS/TIH DP/REL & MOVE RBP TO 4751/POOH/TIH W/DST TOOLS/FLOW TEST/PLT LOG/ 10/11/92 7,449 29 8.4 PRES BUILDUP/POOH W/WL/REL PKR/ATTEMPT WASH OFF SAND FAIL/ $53,029 $1,323,445 POOH/TIH W/RET TOOL/REL RBP/POOH THRU TIGHT SPOTS 4720-4752 TIH W/MILL/CUT DRLG LINE/TIH W/MILL/ROTATE THRU 4420-4430 10/12/92 7,449 30 8.4 WORK THRU TIGHT SPOT IN CSG/POOH W/MILL/TIH & SET RBP/TIH W/ $50,772 $1,374,217 DST TOOLS & SET PKR/OPEN TOOL/WELL FAILED TO FLOW/RU WL/TIH FOR PRES BUILDUP/RD WL/REL PKR/CBU/POOH/TIH TO MOVE RBP/ 10/13/92 7,449 31 8.4 WASH SAND OFF RBP/REL & LOWER RBP/POOH/TIH W/DST TOOLS/SET $54,565 $1,428,782 PKR/PRES TBG TO 800#/OPEN MFE/WE.LL FAIL TO FLOW/TIH W/WL STUCK TOOL/PULL OFF ROPE SOCKET/REL PKR/CBU/POOH REC WL TOOL 10/14/92 7,449 32 8.4 TIH-WASH OUT SAND-TOH-P/U TEST TOOLS AND TIH FOR DST # 10 $54,916 $1,483,698 4874 TO 4886-DST # lO-END TEST-R/D TEST EQUIP-PUMP SWEEP- POOH-TIH-MOVE RBP TO 4982-TOH-TIH FOR DST #11 - 4960'-4972' 10/15/92 7,449 33 8.4 DST #11-(COOK INLET 9 ZONE FROM 4960' TO 4972')-R/D TEST $132,404 $1,616,102 EQUIP-CIRC HOLE CLEAN'TOH-TIH TO RBP AT 4982"ENGAGE AND RELEASE SAME'CBU'RESET AT 5032"TOH'WEEKLY BOP TEST 10/16/92 7,449 34 8.4 WEEKLY BOP TEST/TIH FOR DST #12/TEST CI-lO (5000-5012)/ $46,287 $1,662,388 KILL WELL/TOH W/TEST TOOLS/P/U RET TOOL FOR RBP & TIH W/SAME 10/17/92 7,449 35 8.4 TIH/RET RBP/TOH/PICK UP TOOLS & TBG FOR DST # 13/TIH/ABORT $36,116 $1,698,504 TEST DUE TO WASHOUT AND TOOL FAILURE/KILL WELL/TOH/CHANGE MFE/TIH/R/U TEST EQUIP/TEST/OPEN TOOL/REPAIR SURFACE LEAK 10/18/92 7,449 36 8.4 EQUIP REPAIR/DST #13 - 4960-6814/MOVE TOOLS DOWNHOLE/DST 14 $63,934 $1,762,438 5044-6814/ 10/19/92 7,449 37 8.4 COMPLETE DST #14/5044-6814/MOVE PACKER DOWN TO 5523/TEST $56,667 $1,819,105 EQUIP/CIRC AND BLEED EXCESSIVE GAS FROM ANNULUS/DST # 15 5590-6814/ 10/20/92 7,449 38 8.4 FINISH DST # 15/UNSEAT PKR/CBU/TIH TO 6835'/CBU/TOH WITH $57,741 $1,876,846 TEST STRING/LAY DOWN TOOLS/P/U RBP AND TIH 10/21/92 7,449 39 8.4 FINISH TOH/P/U TOOLS FOR DST # 16/TIH TO 4929'/DST # 16/ $29,955 $1,906,801 MOVE TOOLS TO 4992'/DST # 17/MOVE TOOLS TO 5034'/DST # 18 CI'11(5044'5080) 10/22/92 7,449 40 8.4 DST # 18/KILL WELL AND CIRC CLEAN/TOH/L/D TOOLS/P/U RET TOOL $99,592 $2,006,393 FOR RBP/TIH/LATCH RBP/CBU/TIH TO 5593/RBP STOPPED/WORK LOOSE WOIJLD NOT COME UP/TIH & LEAVE AT 7148/TOH/WEEKLY BOP TEST 10/23/92 7,449 41 8.4 BOP TEST/TIH/WORK THRU TITE SPOT 5053/5068/TIH TO 6847'/CBU $32,950 $2,039,342 TOH/P/U GUNS/TIH/CORRELATE GUNS/TEST LINES/PERFORATE BELUGA SANDS/FLOW WELL FOR CLEANUP AFTER PERFORATING 10/24/92 7,449 42 8.4 CLEAN UP FLOW AFTER PERFORATING/KILL WELL/TOH/LAY DOWN TCP $101,851 $2,141,193 GUNS (ALL FIRED)/TIH W/ MILL TO 7050/CBU/TOH/P/U TOOLS FOR DST #19/TIH/RIG UP ALL TEST EQUIPMENT FOR DST # 19 '~'0/25/92 7,449 43 8.4 PRESSURE TEST EQUIPMENT - DST # 19 OF BELUGA SAND FROM $37,498 $2,178,691 5590' TO 6814' 10/26/92 7,449 44 8.4 DST # 19 OF BELUGA SAND INTERVAL FROM 5590' TO 6814' ' MOVE $95,428 $2,274,119 TOOLS DOWN ' DST # 20 OF BELUGA SAND INTERVALS FROM 6271' TO (>814' PHILLIPS PETROLEUM PAGE:3 DAILY REPORT SUMMARY WELL: Morth Cook Inlet Unit No. A-01 RIG: / FIELD:COOK INLET AFE#:P-V123 CNTY/STATE:TYONEK~ALASKA AUTH COST:$2,732,000 DATE DEPTH RPT NO MW OPERATIONS SUMMARY 10/27/92 7,449 45 8.4 COMPLETE DST # 20/KILL WELL/PCX~H-LAY DOWN TBG & TEST TOOLS DAILY COST CUM COST S107,049 S2,381,168 10/28/92 7,449 T]H TO CLEAN OUT FILL TO 7148/TAG FILL AT 6941/CLEAN OUT TO 7148/TOH/P/U RET TOOL FOR RBP/TIH/WASH OVER AND LATCH RBP 46 8.4 CBU/LATCH RBP & POOH/LOST BTM. OF RBP/TIH W/MILL TAG RBP S53,999 $2,435,167 10/29/92 7,449 gTOO5/PUSH TO 7156/POOH LD BHA/TIH W/PROD ASSY & PKR/CORR W/WIRELINE/POOH W/WL 47 8.4 SETTING PRODUCTION ASSEMBLYS & PERMANENT PACKERS $34,367 $2,469,534 10/30/92 7,449 48 8.4 SET PROD ASSY & PKRS/CUT DRLG LINE/POOH LD DP/TIH W/SEAL $44,516 $2,514,050 10/31/92 7,449 ASSY ON 4.5" PROD TBG 49 8.4 TIH W/PROD TBG/SPACE OUT/DISP ANNULUS W/INHIBITED FLUID/LAND $268,992 $2,783,042 11/01/92 7,449 50 TBG HGR/SET SSSV ON WL/SET BPV/ND BOP/NU TREE/TEST TREE/ RU COIL TBG UNIT/ RU COIL TBG/TEST COIL & TEST EQUIP/TIH JETTING TO 6950'/END $55,409 $2,838,451 11/02/92 7,449 51 TBG ~6924'/JET DRY/POOH RD COIL TBG/WELL FAIL TO FLOW/RU GAS LINE TO TBG ATTEMPT TO ROCK WELL TO FLOW/ ATTEMPT INJECT GAS DOWN TBG TO FLOW WELL, FAIL/RU WL/PULL $50,358 $2,888,809 11/03/92 7,449 52 SSSV/SET BLANKING SLEEVE/CK FLUID LEVEL/RD WL/RU COIL TBG dET WELL IN/FLOW WELL TO CLEANUP/RU WL/PULL BLANKING SLEEVE SET SSSV/FLOW WELL TO CLEANUP/NU PRODUCTION FLOWLINE/RELEASE $58,139 $2,946,948 RIG 11/2/92 1800 HRS. DAYSUM.RP1 11/11/92 RECEIVED Gas Cons. Commission iii ii iii i SURVEY. PHILLIPS PETROLEUM COMPANY PLATFORM WELL NAME NORTH CO0:( LOCATION INLET .. ...... JO,5 NUMBER AMI-2..69 TYPE OF SURVEY SINGLE SHOT DATE JAN. 1969 SURVEY BY ANCHORAGE O~'.-tCE ' IIA UTHO IY IASTCO IN U, $, k, \ MEASURED ........ DEl)TH WELL COMPLETION REPORT PAGE COURSE - - D E V I A T I 0 N - C 0 U R S E T 0 LENGTH ~.ANGLE .DIRECTION AMOUN.T:_ V, DEPTH. LATITUDE DEPARTURE V,DEPTH TANGENTIAL METHOD'~ I ~ L LATITUDE DEPARTURE ORIGIN LOCATED AT MD = 563.00, TVD = 562,88, LATITUDE = 8,19, DEPARTURE = 2.03 700. 137, 2 15' N 7'/ E 5,37 136.89 1,20 N 5.24 E 699.77 9,39 N 7,27 ..... 730, 30, 1 30' ._ N.....41__E ................ 0,78 .....29,98 .... 0,59 N_ _ 0.51 E 729,76 .... .__9.,99 N 7,78 761. 31, 2 15' N 36 E 1,21 30,97 0,98 N 0,71 E 76'0.74 10,97 N 8,50 792, .............. 31 · ...... 3 15..!. ....... N._.22~E_ ........... .1...7_5 ..... 20.,.95 ........... i 1,62. N · .... 0.65 E ......... 7.91.69 .......... ...12,..~0..]"J ............. 9 ,.15_ 821, 29, 3 15' N 7 E 1,64 28,95 1,63 N 0.20 E' 820,64 14,23 N 9,36 :81~8, ............ 67, .... ]._.1.5 ....... N_.IS.._N .......--_3L,..79____6_6.,_8_9_ .....3.,66 .N .........0.,98._.Wi ......... 887,53 ...... 1.7, 90.. N ............ 8'.37 952, 64, 3 45' N 26 W 4,18 63,86 3,76 N 1,83 W 951,39 21,66 N '6,54 .... l.O_~_4 ................ 9.2. .... ~_ .... t. _30__'....i_N _.ztO_..W .............. 7_.,..Zl_'.9~L,, 7_1 .... ]' ....... 5_.52 .. N ............. 4,63_. N .......... 1043... 11 '. ........ 27 . 1 i. N ................ l · 90. E E E E 1109, 65, 4 30' N 33 W 5,09 64,79 4,27 N 2,77 W 1107,91 31, _.___LI_Z3 ....... _6...q:... .......... 3_0 .......... ~_20 .... W .... ]~....5_,..0_2 ...... 6.3_... 8.0_._.]...] .... 14'...71. N ........... 1...71. _W ....... I 171,7.1 ...... ~ ........ 36~. 1237. 64. 5 45' N 19 W 6.41 63.67 6.06 N 2.08 W 1235.39 42. 12.98 ............61, ........ 7 _:~_O_t .... N_2 _0. __.W_ ................. _7_.._~. ...... 6.,_0...,_4~_ .... .'[_. 48 . N .....2.72 W ..........1295.8.7 1330. 32. 8 15' N 20 W 4.59 31.66 4.31 1422 ............... .9._2.. ..... 11 15., ...... _N.._25_.._W_ ............. 17,_9A ..... 9.0.23 ...... 16.26 1514. 92. 14 45' N 28 W 23.42 88.96 20.68 1608 ....... 94.. 18 .15, ..N...30 W ........... 2.9..~-3 ..... 89.27 25.49 1701. 93. 21 30' N 31 ~ 34.08 86.52 29.21 1 7.9 4 , ............ 93.,.. _2 (-t. 1 5' . N... :3_0~. ~ .............. 3.8,.,.. 19. ..... ..8~.,,79 ........ 3 3 , 07 1888. 94. 26 45' N 31 W 42.30 83.94 36.26 1980, .......... 92, .30_._~5'_ ..... N_.31 .W ............. ~770._3 ...... 7_?.-.06 .... 40.32 2074. 2153, Z--Ll4, 2307. 2401, 2555. 2617. _ .2710. 2881. ..... 3099. 3286. 94. 33 O' N 33 W 51.19 78.83 42.93 79.. 3.7. O' .... N.. 3.5 .... ~J ........... _4.7 ..5_q.'63_,.0_9 ........... 3.8.94 61. 37 45' N 35 W 37.34 48.23 30.59 93..37 O' .N .34._w ....... 55._96. _74.27 ........ ~46...40 94. 15'4. 62, 93, 171 · .. 218, 187. 36 45' N 35 W 56.24 75.31 46.07 37 45' N 34 W . .94,28._121.76 ._. 78.16 38 0-' N 34 W 38.17 48.85 31.64 .38 .. O' . N .35 W ........ 57.25~ 73.28 ~6.90 37 O' N' 34 W 102.91 136.56 85.31 37 45' ..N 35. W .133,46.172,37 ....... 109,32 38 30' N 35 W 116.41 146.34 95.35 47 19 25 49,73 N 1.57 W 1327.54 54.05 N 7.58 W ...... 1.417.77 .70.32 N 10,99 W 1506,74 91.00 N .. 14.71W 1596.01 116,49 N 17.55 W 1682.54 145.71 N .~. 19.09 W ......1.767,33 . 178,79 N 21.79 W I851.27 2'15.05 N 24.22 W..` .Ig~0.34 . 255.37 N 27.88 W 2009.I7 298.31 N . .27.26~W ...... 2072,27 .... 337.26 N 21,42. W 2120.50' 367.85 N 31,29 W 2194,77 414,25 N 32.25 W 2270.09 460.32 N -52.72 W 2391.85 538.48 N 21.34 W 2440.71 570.13 N. 32.84 W 251A.00 617.03 N 57.54 W 2650.56 702.34 N 76.55 W _ 2822,93 811.67 N 66.77 W 2969.28 907.03 N 0,87 W N ............. 2, 59...W N 4.68 W N ........... 7:40_ W N 8.97 W N ................ 16.5.5..W ._ . N 27.55 W N .q. 2.27 W N 59.82 W N.. _78.92 W N 100.71 W N 124.94 W · N I52.82 W N. 180.09...W N 201.51 N 'k..-232.81 W N 265.07 W N 317.79 W N 339.14 W N 371.98 W N 429.53 w N ~. .506.08. N z,. 572.85 W PHILLIPS PET 'MEASURED COURSE ~. . DE PTH LENGTH --DEV ANGLE D ROLEUM COMPANY A-1 .PREPARED FOR' EASTMAN BY SCS I A T I 0 N - C 0 U R 'S E IRECTION AMOUNT V.DEPTH LATIIUDE DEPARTURE 02/04/69 . T V. DEPTH ................ -'P-iG E 2 TANGENTIAL METHOD ... T A L LATITUDE DEPARTURE ._ 3379. 93, 3527, 148, _3559, 32, 3620, 6I, ....... 3722 I02, 3879, I57, ..... 4035 ..... 156. 4170. 135. 38 45' N 36 33 30' N 30 33 30' N 30 34 O' N 30 .34 .45t N .30 35 15' N 31 .36 ....O.t .N..30 32 O' N 26 15'..N 8 32 45' N 8 ,33 45, ...N 35 O' N 35 45' N 37 O' N .37 45' N 38 15' N 38 O' N 37 45' N 37 15, N 37 45' N 38 O' N 37 30' N 37 45' N 37 45' N 34 30' N 33 O' N 33 O' N 34 O' N .423Z. 4336. ........ 4491 · 4707. ___ 4.799, .4983, ....... 5140. 5269, 5456. 5674. ....... 5984. 6233. __6542. 6855, ...... 7159. ~ 7356, _7655, 7751, · 7960, 8279, 62 32 104. 155. 216. .92. 184. 157. 129. 187. 218. 3~0. 249. 309. 313. 304. 197. 299. 96. 2','39. 319. W 58,21 72,52 47,09 N W 81,68 123,41 70,74 N W _.17,66 26,68 15,29 N W 34.11 50,'57 29,54 N .'W ............ 58..13 ..83.80 ....... 50.35 N W 90,61 128,21 77,66 N 34.21W 3041.81 40.84 W 3165.23 8.83 W 3191.91 17.05 W 3242.48 .... 29.06:W ._: ..... 3326.29. 46,66 W 3454. . W'. .............. 91,6~.~.126,20 ........ 79,40. N ..... 45,84.W ....... 3580, W 71.53 114.48 64.29 N 31,36 W 3695. W ............. 33.08 ......52,43 .... ' 29,21_N .... 15.53 W .i.J37.~_7. W' 56.26 87.46 49.67 N 26.41 W 3835. 2 27 W ............. 86, 11 .128., 87 .......... _76,72 29 W 25..W 26 W 26 W 24 W 24.W 23 W .23 W 22 W Z1 W 21 W 20 W 21 W 21 W 23 W 24 W 23 w N ......39.09..W ....... 39.63. 123.89 176.93 108.35 N ....... 53.75,. 74.66 .... 48,_71 .N 110.73 146.94 ...... 96.11 124.13 79.86 101.30 115.12 147.35 133.46 172.37 .187.64 246.76 152.44,196.88 _190.23 243,49 190,54 248.31 186,11 240,36 120,60 155.76 i69,35 246.4i 52,28 80.51 II3,82 I75,28 I78,38 264,46 99,52 N ._. 86,39 N 72,95 N 105,17 N 122,85 N .172,72 N 141,34 N I77,60 N I77,88 N- 174,89 N I12,59 N i58, ION 48, I2 N 103.98 N 164.20 N 60.06 W 4140. 22.71W . 4215. 48.54 W 4362. 42,13 W ~4486, 32,48 W 4587, 46,82 W 4735, 52,14 W 4907, ' 73.31 W _.. 5154, 57.10 W 5351. 68.I7 W 5594. 68.28' W 5843. 63.65 W 6083. 43.22 W 6239. 60.69 W 6485. 20.42 W 6566. 46.29 W 6741~ 69.69 W 7005. 954.12 1024.87 1040.16 1069.70 1120.05. 50 1197.72 71. : 1277..13_.. 19 1341.43 63 . :1370.64 607.06 W 647.91 W 656.74 W .. 673.79 W ......... 102,86_ W ....... 749.53 W 842,27 .W 10 1420,32 N 868,68 98 . 1497,05_..N 1605.40 N' 967.84 W ~ 1654.12 N__;~Rg,0_.56~,~ ...... ~ I753.65' N i03g. I0 W gl 58 53 66 1840,04 97 1912,99 33 2018,17. 70 2141,02 46 2313,75 34 2455~09 84 2632,69 I6 2810,58 53 2985.47 29 3098.07 71 3256.17 22 3304.30 50 3408.29 96 3572.49 1081.,.24. W III3.72 W N..~..1160.,55 W ...... 1212.69 W 1286.01.~ ....... 1343.12 W x1411.29 W '147'9.58 W ~.1543.23 w 1586.45,,~/ I647.I5 W i667.58 W I?13.87 W ~1783,57 W C£-OSU.E 3992.98 N 26- 32' W .') TVD = ............ TIVID = . Er'zT..q,.' F~ILLI~ ~ CC~NY A-1 PREP~ FOR E~T~ BY Form No. P---4 REV. 9°3O-67 STATE OF ALASKA suB~rr ~ DL~LZCA~ OIL AND GAS CONSERVATIO. N COMMITTEE MONTHLY REPORT OF 'DRI, LLING HLB ------'-- TRM --------- AND WOR'KOVER OPERATIONS OKG 2. NAME OF OPERATOR Phillips Petroleum Company 3. ADDRESS OF OPERATOR ~1.~ "D" Street, .Anchorage, Alaska 4. ~OCA~0N OF 99~Ol Leg 3, Slot 1, North .Cook Inlet Unit, Platform "Ty~nek" 1252.28' FNL, 1080.84' ~, Sec. 6, T~I]:~, Rgw, $.N. AP1 NLrMERICAL CODE 50-283-2o016 LEASE DESIGNATION AND SERIAL NO. ADL-37831 7. IF INDIA~T, ALOTTEE OR TRIBE NAME 8. U'NIT,FAd:Q~ OR LEASE NAME North Cook Inlet Unit 9. WELL NO. #A-i' 10. FIELD AND POOL. OR WILDCAT n, SEC., T., R., ~:, CSOTTO~ HO~ O~~ Sec. 36, T~N, ~OW' S.M. 12. PERMIT NO. 68-72 13. REPORT TOTAL DEPTH AT END OF MONTH, CI-IA~GES IN HOLE SIZE, CASING AND CEMENTING JOBS I~NCLUDING DEPTH SET A-ND VOLU1VIES USED, PERFORATIONS, TESTS AND R~ESULTS, FISHING JOBS, JI/NK IN HOLE AND SIDE-TRACKED HOLE A_%rD ~Y OTHER SIGNIFICAATT CH. ANGES IN HOL~ CONI)ITIONS. 2-28-69 2-l/4-69 2-8/r~-69 2-12/13-69 2-21--69 2-22--69 2-27/28-69 BECEIVII) MAR 12 196.q ~4. I he~y ce t Ioreg is ~lTect sm~= . . District Office h get. nAT~ March 11, 1969 --Report on this form is required for each calendar month, regardless of the status of operations, ancl must be filed in duplicate with fee Division of Mines & Minerals by the 15th of the succeeding month, unless otherwise directed. Suspended -Waiting on Rig. Drill 9-5/8" hole to 8279'. Took 30 sidewall cores. Set cement plug 77oo' - 75oo' w/l12 sx Type "G" cement in 13½ bbls 2% cc. Set 7" csg $ 7~9.08'. Cemented w/5~6 sx Type "G" cement w/prehydrated Diacel 'D' and ~ cc. 2nd stage w/552 sx Type "G"~cement in ~ cc water. 6589'-6602,,' 657S'~e4,' 6509'-65~:" '6i~i"~27S,, 6oge,-6lle,, 6o76,-6o84, 5892'-5~4', 5874'-5888', 5708'-5715', 5679'-5692', 5663 '-5674' , 5~4'-5616! 5590'-5596', ~0Z~'-50~', 50~,'-~_~ 462~,-~674,, '4552:,-4588!~~i'L~82i,~ 4351"-4391', , ~85'-~O957 Ran comb 3½" & 4" tmbi~g string, set $ 4521'. Ran 4-point.back pressure test an perf's ~85' - 4140'. Pt #1, Flew 3-3/4 hrs on 3/4" Mhoke, FTP 1275 PSIG, F.T. 58~, FARO 20,050 MCFD. Pt #2, Flew l½ hrs on choke' F.T. FArO 16,1 0 Pt #3, Flow 1 hr on ~" Choke, FTP 1706 PSIG, F.T. 58 F,_FARO 11,530 NCFD. Pt #4, Flew 1 hr on 7/16" choke, FTP 1781 PSIG, F.T. 58~F, FARO 9,080 MCFD. 7~ hrs SITP 1912 PSIG, CAOF 28,000 MCFD. Shut In. Test pe~rf,s 4552' - 68~14' DILL Neas. Flew 9 hfs on 3/4" choke, FTP 1690 PSI F.T. 60"F, FARO 28~4 MMCFD. Flow 1 hr on ~" choke, FTP 1~9 'PSI, F.T. 6~F, FARO /4 ~MCFD. Flew 1 hr on 3/8" choke, FTP 1978 PSI, F.T. 61°F, FARO 7.9 MMCFD. Flow ~ hr on ~" choke. FTP 2Oll PSI, F.T. 6$°F, FARO 2023 PSI. Shut in for buildup 2 hrs-20 mine. aITP 2023 PSI. Test perf's 4351' - 4391', ~J+O2' - ~+82' 5 hrs. Flow 5 hrS~ en 3/4" choke, FTP 1706 PSIG, F.T, 65°, FA~ 25.7 MMCFD. All tests inaccurate. Cemmuni~tions indicated. Suspended - WAITING ON RIG. l~rm ~o. P--4 R]gV. 9o2~-67 STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE MONTHLY RE!PORT OF DRI. LLING AND WORKOVER OPERATIONS 1. WELL SUBMIT IN DUFLICATE /4 KLV __,Z~'.- HWK ~ NAME OF OPERATOR Phillips Petroleuza CompanM ADDRESS OF OPEI{ATOR 515 "D" St ~ r~ Ancnoraoe Alaska 99501 4. LocAT~6N O'F WELL REL ~ Leg 4. :i, ~, .... th Cook Inlet Unit, Platform_ "Tyonek", 1252.28' FNL, 1080'8~' P>[L, Sec. 6, TI!N, RgW, S.M. , APz NU~EmCAL ~ODE '/$- LEAsE-DEsIO1kTATION A%'D SERIAL NO. I ADL-37~31 7. IF INDIA]~, ALOTTEE OR TRIBE NAME 8. UNIT,FA/~M OR LEASE NAME North Cook Inlet Unit g. WELL NO, 10. FLEL~ AND POOL. OR WILDCAT _North Cook Inlet 11. SEC., T., R., 1%~:. (BOI'I'OM HOLE OB,mCTnrE) 13. REPORT TOTAL DEPTH AT END OF MONTH, CHANGES IN HOLE SIZE, CASING AND CEMENTING JOBS INCLUDING DEPTH .Sec. 36, T!2N, R!OW~ S.M. 12. PEI~ViIT N'O. 65-72 ,, SET AlXrD VOLU/VIES USED, PERFORATIONS, TESTS A_N-D RESULTS, FISHING JOBS, JUNK IN HOLE A.ND SIDE-TRACKED HOLE AND ANY OTI-IER SIGNIFICANT CI-IA~GES IN HOLE CONDITIONS. Drilling 9-5/8" hole at 7127'. l/ll-:L. l fL6 l/l? Moved rig on. hole, krd BOP & tested BOP & equipment to 2000~~. Drilled 15" hole to 2!57'. Jm%ped DC pin out of box. Recovered fish. Drillect. 15" ho le to 25~5' Ran 1.0-3//+" casing, set at 254~.77~. Cemented w/~65 sx. ~ , ~V' Drilled 9-5/~" hole to 27~2'. Pipe stuck. Spotted 50 bbls diesel w/5 gallon Scotfree. Jarred fish loose. Drilled 9-5/8, hole to 2772', pipe stuck. Spotted 40 bbls diesel. CoUld not jar loose. Backed off ~ 2518.16'. Lef2 9-5/8" bit, 8" reamer, 2-7 3/~" roche! collar, 7-3/&-" stabilizer, 7-3/~" x 9-5/8".XO stabilizer and drill c~l!ars. Washed over fish,to 2667~, milled on stabilizer, COOH, T~KH & recovered fish. 1/2~-51 Drilled 9-5/8" hole to 7!27'. ., . . /, _ / .,;;s,o, o, o* ....... 14. I he.by ~y t e foreg~ ~ ~~ ~ ~ ' ' "' E~Repo~ on t~s form ~ required for each ~iendar montk regardless of t~e status of operaUon% with the 0ivision of Mines & Minerals by the 15th of the succeeding month, on[ess othe~se d~re~ed. lVorm No. P--4 REV. STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE SUBMIT IN DUPLICATE MONTHLY REPORT O:F DRILLING AND WORKOVER OPE:RATIONS 1. 2. NAME OF OPERATOR Phillips Petroleum Compamy 3, ADDRESS OF OPEi~ATOR 515 "D" St.~ Anchorage, Alaska 99501 4. LOCATION OF wa~L Leg 3, Slot #1, North Cook Inlet Unit, Platform Tyonek, ]252.28' FNL, 1080.8~' F~ffL, Sec. 6, TllN, R~, S.M. ~. AP1 NUAIERICAL CODE 50-283-20016 6. LEASE DESIGNATION AXD SERIAL NO. ADL-37831 7. IF INDIA]~, ALOTTEE OR TRIBE NAME 8.UNIT,FA3bM OR LEASE NAME North Cook Inlet Unit 9. WELL NO. ~A-1 10. FIRi ~r~ A_MD POOL. OR WILDCAT North Cook Inlet 11, SEC., T., R., M., (BO~FOM HOLE OBJECTrVE) Sec. 36, T12N, R10W, S.M. 12. PERMIT NO. · 68-72 13. REPORT TOTAL DEPTH AT END OF MONTH, CHA~NGES IN HOLE SIZE, CASING AND CEMENTING JOBS INCLUDING DEPTH SET AN~ VOLU1VIES USED, PERFORATIONS, ~STS AND RESULTS. FISHING JOBS, JLr~K IN HOLE AND SIDE-TIq. ACKED HOLE AND A.NY OTHER SIGNIFICANT CI-LA~G~ IN HOLE CONDITIONS. ll-6 Suspended-waiting op _~ig. 10-22 Spudded from surface. 10-23-29 Drill 15'.' hole and ream to 22" to 630'. Set 16" casing at 613.59' and cemented w/950 sacks cement and 200 sacks down around top. CENEI DIVISION OF OIL At,ID GAS ANCHOI~GE 14. I hereby certify ~ the~foregoing iz trl~ correct ' ~G~ k~~7~~.~~ District 0f£±ce ~naser ~^~ December 5~ 1968 , d/ I 1 /~E--Report on this form is required for each calendar month, regardless of the status of operations, and must be file¢ in duplicate with the Division of Mines & Minerals by the }Sth of the succeeding month, unless otherwise directed. PHiLLiPS PETrOLeUM COMPANY ANCHORAGE, A~SKA.99501 ~ 515 "D" STRE~ F. XPLORATiON AND PRODUCTION DEPARTMENT October 2&., 1968 Re: Spud new well NCIU '~''' TM t~. F. J. Keenan Director, .DiVision of Lands Sta:te of Alaska Department of Natural Resources 5~ 6th Avenue Anchorage ~ Alaska Dear Sir: This is to notify you that the subject well was spudded on State Lease ADL-37~3t at 19:30 hours on October 21, _908. The surface location of this..v.~elt is at ~.oco 2~' F~[L !0~0 8/~' FtyS, Sec. 6, T-Ii-N, R-9-W, S.M. b~e Plan to drii! this well directior,_a!ly to a bottom hole location of ~' ~-!O~'~ S.M. 89' FEL, 2575' FSL, Sec. ~o,. T-12-N, Very truly yours~ PHiLLZPS PETP~OLE~ CO~[PA~ District O~fice ~.~anager JBG: jo :'~ ~ '~ Marshall, jr. (~.) Division of ?.~imes & 3~nera!s Detriment of "~'~ ~ Re Stats of Alaska · 3001 ?orcupine Drive Anchorage, Alaska ~50~ RECEIVFD 25 196B 01¥1510N OF MINE,5 ANOJORAGE ~IF. Joha ,B.. ~tpsoa ~ please fi~ut the approved application for' pemit to drill the we£eeeaced veil. As per e~r telephone. y~r o~£~, ~e. chips are Ve~T truly yours, Themas R. l, htr~all, Jr. Petrolem l~per~lsor FORM SA,- 125.5M $/67 MEMORANDUM TO: n State of Alaska FROM: DATE : SUBJECT: FORM SA- I B 125.5M 8/67 MEMORAND.uM TO: j-- FROM: ) State of Alaska DATE SUBJECT: F~rrn P--1 REV. 9-30-67 STATE O'F ALASKA OIL AND GAS CONSER'VATIO, N ,CO,MMITTEE SUBMIT IN T~i.. TE (Other instructiong"Sn reverse side) APPLICATION FOR PERMIT TO DRILL, DEEPEN, OR PLLK~ BACK 11~. TYPE OF WORK DRILL J~ WELL WELL OTHER 2.NAME OF OPERATOR Ph~ll-lp~ Petrolem Company 3. ADDRESS C]~ OPERATOR DEEPEN [-] PLUG BACK ZONE ZONe. 515 "D" Street. AnchoraEe; Alaska 99501 LOCATIO~ O~ WELL ' At surface Leg 3, Slot #1, North Cook Inlet Unit, Platform "A", 1252.28' FNL, 1080.8~' IWgL, Sec. 6, TllN, Rgb, $.M. At pro.posed prod. zone 89' FEL. 25?3' FSL, Sec. 36, T12N, KIO~;'S-M.'' ~ 13. DISTANCE ~N MILES AND DIR_ECT!ON..F.%OM. NEAREST TOWN OR,POST OFFICE, 10.5 Niles East of Tyenek, Alaska .,~ I~. BOND INFORMATION: M-ND-IV Statewide Bond #Bi-1 TYPE Surety and/or No. 15. DISTANCE FROM PROPOSED* LOCATION TO NEAREST PROPERTY OR LEASE LLNE, FT. (Also to nearest drig, unit, if any)~ 18. DISTANCE FROM PROPOSED LocATIoN* TO NEAREST WELL DRILLING, COMPLETEp, OR APPLIED FOR, FT. 7,o7o feet 21. ELEVATIONS (Show whether DF, RT, C-R, etc.) RKB ll6 feet from PROPOSED CASING A/~D ~EMENTI~NG' PROGRAM API 50-283-20016 6. LF~SE DESIGNATION IA_ND SERIAL ADL-37831 7. IF INDIAN, ALLOTTEE OR TRIBE NAHE 9. WELL NO. ~0. Find AND POOL, OR WILDCAT 11. SEC.-, T., R., M., (BOSOM HOLE O~ECTIVE) Sec'. 36, T12N, R10W, S.M. 12. 17. ,NO~ ACRES ASSIGNED TO THiS WELL '20(' ROT~R'~ OR CABLE TOOLS APPROX, DATE WORK WILL START* October 1, 1968 SIZE OF HOLE SIZE OF CASING WEIGHT' ~"'PER ....... FOOT" ~G~AiNE~ !~: SETTING, DTM ' :' ' ~ ~ ~ '' $'' S~'~ ' $~ : ' ' ..... QUANTITY OF CEMENT 22" lA" 6~ H-40 600~ C~rc,'~e' ~"~":'~" :' ~o~'"'~s~face ~ 1. Deviation required tO reach BHL from potent Platform. 2. There are no affected operators. -' ' 3. BOP Specifications attached. ~. Intervals ef interest will be perforated and may be~ stimulated. * Refer to State of Alaska, Alaska 0il & Gas Conservation Co-..~ttee, Conservation Order #~0, dated 6-8-67. IN ABOVE SPACE DESCRIBE PROPOSED PROGRAM: If proposal i~ to deepen or plug back. give data on present productive zone and proposed new~._p..~mductive zohe. If proposal is to drill or deepen direct'onally, give pertinent data on subsurface R)cations and measuxed and 24. I hereby c~ti£y~t)~at %he Foregoing is T~e and Correct - //- . -I . . -- _ _ (This spree £~,~tate o£fice use) CONDI'lqONS 02" APPROVAL, IF AN~: SAlV~LES AND CORE CHIPS BF_~ [] YES DIRECTIONAL SURVEY 1~~ PRTM I-1 NO APPRO~ B . ~- , , . TI~ .... DA~ , ,. ~s~a O,i & Gas , , , A,P.I. NUMERICAL CODE 12 PROPOSED B.H.L. ,~' N.C.I. Un. No. A-I (, 89' FI[L& 2575"FSL~ of · · 6 7 32 5 8 GRID PHILLIPS PETROLEUM COMPANY $15' "D" STREET ANCHORAGF ,ALASKA PLAT OF NORTH COOK INLET UNIT PLATFORM '~A" DRWN. N. d, Pow~II NORTH,'COOK INLET UNIT A-~l PHILLIPS PETROLEUM COMPANY 515 "~' STREET ANCHORAGE,ALASKA NORTH COOl'(' iNLET PLATFORM COOK INLET ~ ALASKA NOTE: Usin9 PLATFORM NORTH, Slot No.I will bcthJ furthest platform North slot in plotform North- west quodront of any leg; Slots will be numbered' I thru. 8 in o counter-clock-wise direction. PLATFORM LOCATION: Sec,6-11N-gW I DATE: AUCUST "DRWN. N.J. Powoll NOT TO SCALE HOO?(UP FOR DOUBLE PREVENTERS 4' SERIES 1500 X 2' SERIES 1500 . ~_~.~- -. '.',e ~ - ¢ ~,,.~,,~,~oo~o~,~,v~c,o~ LINE ~, ,, ~ SERIES , ' ~ ,- .... t ~ .;,~.',- ,.. ·. . ~ .. PHILLIPS Pt: 1ROLEUi,.~ CO,'~,~'~NY "_ i~t~ PRODUCTION DEPARTMENT .- NOTE: Double Preventers are used with flanged side outlets for choke manifold and fillup line connectiOns. - . 5000 PSI WOR'" i',,ING BLO\VOUT PR¢~VEN'FER I-IOOK-UP (SERIES 1,500 FLANGerS OR DE').'.TER) REV. ,3/l!/G,S SCttEDULE E · I 6 TIIN I I ~ ': I //2 × I . I I I I I I I I I ~'i~ 7 .SCAL.~ ~"= ~,000' ~ 7 ~G Ng, LEG N~-. 4 LEG N~. 2 ~G N~ ~ LAT. 61° 04' ~.~8" LAT. 61° 04' 56.89" LAT. 61° 04' 55.83" LAT. 61~ 04' ~6.34" LONG.150° 56' 55.65" ' LONG. 15~ 56' 54.25" ~NG. 15~ 56' 54~77" ~NG. 15~ 56' 5~.59" Y= 2~586~731 Y= 2~86~781 Y= 2,586~ 674 Y= 2 ~5 86~72 4 X= ~51~995 X=' 332~ X= 352,056 X= 552~105 FROM N.W. COR. ~OM N.W. COR. FROM N.W. COR. FROM N W. COR. ~250' SOUTH .~ 1,198',~UTH & 1,5~' SOUTH ~ 1,254' SOUTH 8 975' EAST. i,043 EAST. · 1,018' EAST. 1,085' EAST~ 7 A UG':68 :* fo 8 CERTIFICATE OF SURVEYOR I hereby certify that lam 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 are correct. NOTE The location of the platform legs was accomplished by using triangulation stations BELUGA,TERRACE,and TYONEK which are all U.S.C.I~G.S. stations. AIl coordinates are Alaska State Plane, Zone 4. ,, N'~'~r~'H'~/I--tl,! PLAT' O'F' COOK I NLETUNIT PLATFORM "A" FO, PHILLIPS PETR~EUM CO ~TE: 21 JUNE ~ F.M. LtND~ ~:'~SO~ SCALE: I": I000' Land FB. 11~7~ Pp. 11-15 ' S~rveyors - ,