Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout201-226C:\Users\grgluyas\AppData\Local\Microsoft\Windows\INetCache\Content.Outlook\0O55OAKD\2025-10-03_16054_KRU_2P-415A_CaliperSurvey_LogData_Transmittal.docx
DELIVERABLE DISCRIPTION
Ticket # Field Well # API # Log Description Log Date
16054 KRU 2P-415A 50-103-20383-01 Caliper Survey w/ Log Data 03-Oct-25
DELIVERED TO
Company & Address
DIGITAL FILE
# of Copies
LOG PRINTS
# of Prints
CD’s
# of Copies
1
AOGCC
Attn: Natural Resources Technician
333 W. 7th Ave., Suite 100
Anchorage, Ak. 99501-3539
Delivered By: CPAI Sharefile
______________________________ _____________________________________
Date received Signature
______________________________ ______________________________________
PLEASE RETURN COPY VIA EMAIL TO:
DIANE.WILLIAMS@READCASEDHOLE.COM
READ CASED HOLE, INC., 4141 B STREET, SUITE 308, ANCHORAGE, AK 99503
PHONE: (907)245-8951
E-MAIL : READ-Anchorage@readcasedhole.com WEBSITE : WWW.READCASEDHOLE.COM
201-226
T40966
10/8/2025
Gavin
Gluyas
Digitally signed
by Gavin Gluyas
Date: 2025.10.08
14:03:30 -08'00'
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Extend Exp Date
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address: Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
9038'
Casing Collapse
Structural
Conductor
Surface
Intermediate
Production
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
9/30/2025
3-1/2"
Packer: Baker G-22 Seal Assy
SSSV: None
Perforation Depth MD (ft):
L-80
3685'
8640-8650' below cement plug
9000'
5682-5691' below cement plug
5-1/2" x 3-1/2"
Perforation Depth TVD (ft):
110'
3713'
6039'9026'
16"
7-5/8"
82'
8211'
MD
110'
2449'
ConocoPhillips Alaska, Inc.
Length Size
Proposed Pools:
PRESENT WELL CONDITION SUMMARY
Meltwater Oil Pool -
Abandoned
TVD Burst
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0373112
201-226
P.O. Box 100360, Anchorage, AK 99510 50-103-20383-01-00
Kuparuk River Field Meltwater Oil Pool- Suspended
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):
8191' MD and 5271' TVD
N/A
Jill Simek
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
Jill.Simek@conocophillips.com
(907) 263-4131
Staff Well Interventions Engineer
KRU 2P-415A
6050' 3024' 2185'
3024', 3721', 3798',
6333', 8518', 8625'
N/A
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 4:01 pm, Aug 27, 2025
Jill Simek Digitally signed by Jill Simek
Date: 2025.08.27 15:55:37
-08'00'
325-521
All conditions on original approved sundry apply 12/31/2025
No further extensions will be approved.
10-407
DSR-9/10/25
X X
VTL 9/3/2025 SFD 9/16/2025JLC 9/16/2025
Gregory C Wilson Digitally signed by Gregory C
Wilson
Date: 2025.09.17 13:21:40 -08'00'09/17/25
RBDMS JSB 091925
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
Commissioner, State of Alaska August 26, 2025
Alaska Oil & Gas Conservation Commission
333 West 7th Avenue Suite 100
Anchorage, Alaska 99501
Dear Commissioner:
Please find the attached 10-403 Application for Sundry Approval for
ConocoPhillips Alaska, Inc. well KRU 2P-415 (PTD# 201-226). We are
requesting to extend the Suspension Expiration Date to December 31, 2025, to
finish the P&A.
If you have any questions, please contact me at 263-4131.
Sincerely,
Jill Simek
Staff Well Interventions Engineer
p, ( )
requesting to extend the Suspension Expiration Date to December 31, 2025
Last Tag
Annotation Depth (ftKB) Wellbore End Date Last Mod By
Last Tag: SLM 8,874.0 2P-415A rmoore22
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Updated TOC after slickline tag 2P-415A 8/20/2025 rmoore22
Casing Strings
Csg Des OD (in) ID (in) Top (ftKB)
Set Depth
(ftKB)
Set Depth
(TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread
CONDUCTOR 16 15.06 28.0 110.0 110.0 62.50 H-40 WELDED
SURFACE 7 5/8 6.87 27.9 3,713.0 2,448.7 29.70 L-80 BTC Mod
Kill string 5 1/2 4.95 23.2 1,993.0 1,762.1 15.50 L-80 BTC Mod
PRODUCTION
5.5"x3.5" @ 8210'
5 1/2 4.95 25.3 9,025.8 6,038.6 15.50 L-80 BTC Mod
Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string
Top (ftKB)
3,924.3
Set Depth …
8,210.7
Set Depth …
5,288.8
String Max No…
3 1/2
Tubing Description
Tubing - Production
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE-8rd
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
5,662.6 3,246.5 60.24 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
6,864.7 4,069.7 29.51 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
7,540.6 4,678.8 26.93 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,090.5 5,178.2 23.38 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,134.0 5,218.2 23.00 SLEEVE-C 4.500 BAKER CMU NON-ELASTOMER
SLIDING SLEEVE w/CAMCO DS
PROFILE - CLOSED 11/14/2009
BAKER CMU 2.812
8,150.0 5,233.0 23.07 NIPPLE 3.750 CAMCO D NIPPLE CAMCO D 2.750
8,193.3 5,272.8 23.26 LOCATOR 4.500 BAKER 80-40 G-22 LOCATOR SUB BAKER 3.000
8,193.8 5,273.2 23.27 SEAL ASSY 4.000 BAKER G-22 SEAL ASSY BAKER 3.000
Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.)
Top (ftKB)
Top (TVD)
(ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in)
3,768.0 2,471.3 65.85 CUT WELLTEC MECHANICAL
TBG CUT AT 3780' D25 RKB.
(55' below surface shoe)
4/25/2024 4.950
3,798.0 2,483.6 66.08 PLUG 4.25" - 4.75" Alpha CIBP 3810'
D25 RKB (85' below surface
shoe)
4/25/2024 0.000
8,105.0 5,191.6 23.24 TUBING
PUNCH
3' TUBING PUNCH, 1.56", 3
GRAM, 6 SPF, 18 0.43"
HOLES
OWEN 3/24/2024 2.992
8,625.0 5,668.7 24.22 PLUG Set TTS CIBP (2.63" x 1.37' ) 10/7/2023 0.000
8,898.0 5,919.5 21.81 Plug Catcher WEATHERFORD PLUG
CATCHER
12/4/2001 0.000
Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal ID
(in)
25.9 25.9 0.00 PRODUCTION 5.500 4.950
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft)Type Com
8,640.0 8,650.0 5,682.3 5,691.5 T-3, 2P-415 12/24/2001 6.0 IPERF HMX Chrgs, 60 deg ph
Stimulation Intervals
Top (ftKB) Btm (ftKB)
Inter
val
Num
ber Type Subtype Start Date
Proppant
Designed (lb)
Proppant
Total (lb)
Vol Clean
Total (bbl)
Vol Slurry
Total (bbl)
8,640.0 8,650.0 1 FRAC 12/24/2001 0.0 0.00 0.00
Cement Squeezes
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Des Com
Pump Start
Date
8,518.0 8,625.0 5,570.9 5,668.7 Cement Plug Dump bailed cement with Slickline on top of CIBP 12/18/2023
6,333.0 8,105.0 3,651.2 5,191.6 Intermediate
String 1
Cement
PUMPED 31 BBLS OF 15.8 CLASS G CEMENT
FOR INTERMEDIATE BALANCED PLUG
3/30/2024
3,721.0 3,798.0 2,452.0 2,483.6 Cement Plug PJSM. Test lines to 3000 PSI. Pump 9 BBLS 11.0
ppg MudPush spacer + 29 BBLS 16.5 ppg cement +
13 BBLS 11.0 ppg MudPush spacer + 2 BBLs FW to
clear lines. Displace with 45 BBLs 9.8 ppg Brine.
4/28/2024
3,024.0 3,721.0 2,185.4 2,452.0 Cement Plug Lay in 500' Class G Cement Plug 7/9/2025
2P-415A, 8/26/2025 4:05:23 PM
Vertical schematic (actual)
PRODUCTION 5.5"x3.5" @
8210'; 3,780.0-9,025.8
Plug Catcher; 8,898.0
IPERF; 8,640.0-8,650.0
FRAC; 8,640.0
PLUG; 8,625.0
Cement Plug; 8,518.0 ftKB
TUBING PUNCH; 8,105.0
GAS LIFT; 8,090.5
GAS LIFT; 7,540.6
GAS LIFT; 6,864.7
Intermediate String 1 Cement;
6,333.0 ftKB
GAS LIFT; 5,662.6
PLUG; 3,798.0
CUT; 3,768.0
Cement Plug; 3,721.0 ftKB
SURFACE; 27.9-3,713.0
Cement Plug; 3,024.0 ftKB
Kill string; 23.2-1,993.0
CONDUCTOR; 28.0-110.0
KUP PROD
KB-Grd (ft)
34.50
RR Date
12/5/2001
Other Elev…
2P-415A
...
TD
Act Btm (ftKB)
9,038.0
Well Attributes
Field Name
MELTWATER
Wellbore API/UWI
501032038301
Wellbore Status
PROD
Max Angle & MD
Incl (°)
68.89
MD (ftKB)
5,168.44
WELLNAME WELLBORE2P-415A
Annotation
Last WO:
End DateH2S (ppm)
82
Date
12/21/2013
Comment
SSSV: NIPPLE
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
TO: Jim Regg DATE:
P.I. Supervisor
SUBJECT:
FROM:
Petroleum Inspector
Section:17 Township:8N Range:7E Meridian:Umiat
Drilling Rig:Rig Elevation:Total Depth:9038 ft MD Lease No.:ADL0373112
Operator Rep:Suspend:P&A:X
Conductor:16"O.D. Shoe@ 110 Feet Csg Cut@ Feet
Surface:7-5/8"O.D. Shoe@ 3713 Feet Csg Cut@ Feet
Intermediate:O.D. Shoe@ Feet Csg Cut@ Feet
Production:5-1/2" x 3-1/2"O.D. Shoe@ 9026 Feet Csg Cut@ 3780 Feet
Liner:O.D. Shoe@ Feet Csg Cut@ Feet
Tubing:3-1/2"O.D. Tail@ 8208 Feet Tbg Cut@ 3927 Feet
Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified
Annulus Bridge plug 3798 ft 3024 ft 6.8 ppg Wireline tag
MIT Initial 15 min 30 min 45 min Result
Tubing 1540 1450 1420
IA 1540 1450 1420
OA 1540 1450 1420
Initial 15 min 30 min 45 min Result
Tubing
IA
OA
Remarks:
Attachments:
Ryan Moore
Casing/Tubing Data (depths are MD):
Plugging Data (depths are MD):
See attached
August 20, 2025
Josh Hunt
Well Bore Plug & Abandonment
KRU 2P-415A
ConocoPhillips Alaska
PTD 2012260; Sundry 325-203
Remarks; Photo
Test Data:
P
Casing Removal:
rev. 3-24-2022 2025-0820_Plug_Verification_KRU_2P-415A_jh
2025-0820_Plug_Verification_KRU_2P-415A_remarks_jh
Page 1 of 1
Plug Verification – KRU 2P-415A (PTD 2012260)
AOGCC Inspector J. Hunt
8/20/2025
I was already at KRU 2P for the other plug verifications. Ryan Moore and I went over the
Sundry for this well and discussed the plan forward. This is the third plug in a series of four.
They had the standard BHA assembly including weight pipe, spangs, oil jars, a 2.70-inch
OD stabilizer, and a 1.75-inch ID bailer. This assembly was around 30 feet long and 200 lbs.
They ran the BHA in the 2P-415A slowly, hit a lot of cement stringers on the way in, and
worked down until it would not go any further. The tag was solid and repeatable at 3024 feet
MD (3054 feet RKB). An MIT was performed to confirm the integrity of the cement plug, and
a passing test was obtained. I noticed in the approved Sundry that a draw down test (DDT)
was also required. A bleed trailer was hooked up and they bled the well to 0 psi then shut it
in. I was working three different jobs at the time on KRU 2P-pad, going back and forth
between them. This amounted to a 45-minute observed DDT – there was no pressure build.
The well was opened, and no flow or pressure was observed at this time.
Photo - A soft mushy sample was recovered from the bailer.
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
9038'3708'
Casing Collapse
Structural
Conductor
Surface
Intermediate
Production
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
5/1/2025
3-1/2"
Packer: Baker G-22 Seal Assy
SSSV: None
Perforation Depth MD (ft):
L-80
3685'
8640-8650' below cement plug
9000'
5682-5691' below cement plug
5-1/2" x 3-1/2"
Perforation Depth TVD (ft):
110'
3713'
6039'9026'
16"
7-5/8"
82'
8211'
MD
110'
2449'
ConocoPhillips Alaska, Inc.
Length Size
Proposed Pools:
PRESENT WELL CONDITION SUMMARY
Meltwater Oil Pool -
Abandoned
TVD Burst
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0373112
201-226
P.O. Box 100360, Anchorage, AK 99510 50-103-20383-01-00
Kuparuk River Field Meltwater Oil Pool- Suspended
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):
8191' MD and 5271' TVD
N/A
Jill Simek
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
Jill.Simek@conocophillips.com
(907) 263-4131
Staff Well Interventions Engineer
KRU 2P-415A
6050' 3488' 2361'
3488', 3721', 3798',
6333', 8518', 8625'
N/A
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 3:35 pm, Apr 03, 2025
Jill Simek Digitally signed by Jill Simek
Date: 2025.04.03 14:58:43
-08'00'
325-203
X
10-407
X
9/30/2025
VTL 4/21/2025 DSR-4/7/25A.Dewhurst 10APR25*&:
Jessie L. Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2025.04.22 10:35:40 -08'00'04/22/25
RBDMS JSB 042225
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C80 @ 3775' KBC80 @ 3775' KB
2P-415A P&A Schematic - Current
Conductor:
16" Conductor 110' KB
Production Casing Cement:
62.5 bbls of 15.8# Class G Cement
Calculated TOC @ 5,782' KB
1
3
5
4
Production Casing:
5.5" x 3.5" @ 8,210' KB, 15.5# x 9.3#,
L-80 BTC Mod
Set @ 9,025.8’ KB
T-3 Peforations:
@ 8,640' – 8,650' KB (10')
Surface Casing:
7-5/8", 29.7#, L-80 BTC Mod
Set @ 3,713' KB
Production Tubing:
3 ½”, 9.3# L-80 EUE-8rd
Set @ 8,208.4' KB
6
Item Depth - tops
(KB)
1FMC Hanger 25.3'
2 Cast Iron Bridge Plug 3,798'
3
Baker CMU Non-Elastomer Sliding
Sleeve w/ Camco DS Profile -
Closed 11/14/2009
8,134.0'
4 Camco D Nipple 8,150.0'
5 Baker 80-40 G-22 Locator Sub 8,193.3'
6 Baker G22 Seal Assembly 8,193.8'
Plug #1 – Reservoir
TOC 8518' RKB
Plug #2 – Intermediate
TOC 6333' RKB
BOC @ 8105' RKB
Surface Shoe Cement
TOC Tagged @ 3721' RKB
BOC @ 3768' RKB
IBP @ 3488' RKB
PT to 1000 PSI for 30 min
FISH: IBP @ 3708' RKB
PT failed; rig unable to retrieve
2
5-½” Kill String
@ 1993' RKB
9.8 ppg NaCl w/ FP
C80 @ 3775' KBC80 @ 3775' KB
2P-415A P&A Schematic - Proposed
Conductor:
16" Conductor 110' KB
Production Casing Cement:
62.5 bbls of 15.8# Class G Cement
Calculated TOC @ 5,782' KB
1
3
5
4
Production Casing:
5.5" x 3.5" @ 8,210' KB, 15.5# x 9.3#,
L-80 BTC Mod
Set @ 9,025.8’ KB
T-3 Peforations:
@ 8,640' – 8,650' KB (10')
Surface Casing:
7-5/8", 29.7#, L-80 BTC Mod
Set @ 3,713' KB
Production Tubing:
3 ½”, 9.3# L-80 EUE-8rd
Set @ 8,208.4' KB
6
Item Depth - tops
(KB)
1FMC Hanger 25.3'
2 Cast Iron Bridge Plug 3,798'
3
Baker CMU Non-Elastomer Sliding
Sleeve w/ Camco DS Profile -
Closed 11/14/2009
8,134.0'
4 Camco D Nipple 8,150.0'
5 Baker 80-40 G-22 Locator Sub 8,193.3'
6 Baker G22 Seal Assembly 8,193.8'
Plug #1 – Reservoir
TOC 8518' RKB
Plug #2 – Intermediate
TOC 6333' RKB
BOC @ 8105' RKB
Surface Shoe Cement
TOC Tagged @ 3721' RKB
BOC @ 3768' RKB
2
Plug #3
TOC 3221' RKB
BOC @ 3721' RKB
5-½” Kill String
@ 1993' RKB
BP @ ~2000’ RKB
Plug #4
TOC @ Surface
BOC @ 1993' RKB
Last Tag
Annotation Depth (ftKB) Wellbore End Date Last Mod By
Last Tag: RKB (Tagged TOC) 2P-415A 3/17/2024 rogerba
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Update schematic post Doyon 25 P&A 2P-415A 5/5/2024 rogerba
Casing Strings
Csg Des OD (in) ID (in) Top (ftKB)
Set Depth
(ftKB)
Set Depth
(TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread
CONDUCTOR 16 15.06 28.0 110.0 110.0 62.50 H-40 WELDED
SURFACE 7 5/8 6.87 27.9 3,713.0 2,448.7 29.70 L-80 BTC Mod
Kill string 5 1/2 4.95 23.2 1,993.0 1,762.1 15.50 L-80 BTC Mod
PRODUCTION
5.5"x3.5" @ 8210'
5 1/2 4.95 25.3 9,025.8 6,038.6 15.50 L-80 BTC Mod
Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string
Top (ftKB)
3,924.3
Set Depth …
8,210.7
Set Depth …
5,288.8
String Max No…
3 1/2
Tubing Description
Tubing - Production
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE-8rd
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
5,662.6 3,246.5 60.24 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
6,864.7 4,069.7 29.51 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
7,540.6 4,678.8 26.93 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,090.5 5,178.2 23.38 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,134.0 5,218.2 23.00 SLEEVE-C 4.500 BAKER CMU NON-ELASTOMER
SLIDING SLEEVE w/CAMCO DS
PROFILE - CLOSED 11/14/2009
BAKER CMU 2.812
8,150.0 5,233.0 23.07 NIPPLE 3.750 CAMCO D NIPPLE CAMCO D 2.750
8,193.3 5,272.8 23.26 LOCATOR 4.500 BAKER 80-40 G-22 LOCATOR SUB BAKER 3.000
8,193.8 5,273.2 23.27 SEAL ASSY 4.000 BAKER G-22 SEAL ASSY BAKER 3.000
Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.)
Top (ftKB)
Top (TVD)
(ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in)
3,488.0 2,361.0 68.07 IBP 3.5" TAM IBP run by
yellowjacket. Packer tested
1000psi 30 minutes
TAM 5/2/2024
3,708.0 2,446.6 65.77 IBP 2.5" TAM IBP run by
yellowjacket. Packer did not
test. Was pushed to bottom.
Unable to fish out. Top of fish
is ~5' inside csg. 2.13" OD HR
running tool 0.79' long looking
up.
TAM 5/2/2024 0.000
3,768.0 2,471.3 65.85 CUT WELLTEC MECHANICAL
TBG CUT AT 3780' D25 RKB.
(55' below surface shoe)
4/25/2024 4.950
3,798.0 2,483.6 66.08 PLUG 4.25" - 4.75" Alpha CIBP 3810'
D25 RKB (85' below surface
shoe)
4/25/2024 0.000
8,105.0 5,191.6 23.24 TUBING
PUNCH
3' TUBING PUNCH, 1.56", 3
GRAM, 6 SPF, 18 0.43"
HOLES
OWEN 3/24/2024 2.992
8,625.0 5,668.7 24.22 PLUG Set TTS CIBP (2.63" x 1.37' ) 10/7/2023 0.000
8,898.0 5,919.5 21.81 Plug Catcher WEATHERFORD PLUG
CATCHER
12/4/2001 0.000
Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal ID
(in)
25.9 25.9 0.00 PRODUCTION 5.500 4.950
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft)Type Com
8,640.0 8,650.0 5,682.3 5,691.5 T-3, 2P-415 12/24/2001 6.0 IPERF HMX Chrgs, 60 deg ph
Stimulation Intervals
Top (ftKB) Btm (ftKB)
Inter
val
Num
ber Type Subtype Start Date
Proppant
Designed (lb)
Proppant
Total (lb)
Vol Clean
Total (bbl)
Vol Slurry
Total (bbl)
8,640.0 8,650.0 1 FRAC 12/24/2001 0.0 0.00 0.00
Cement Squeezes
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Des Com
Pump Start
Date
8,518.0 8,625.0 5,570.9 5,668.7 Cement Plug Dump bailed cement with Slickline on top of CIBP 12/18/2023
6,333.0 8,105.0 3,651.2 5,191.6 Intermediate
String 1
Cement
PUMPED 31 BBLS OF 15.8 CLASS G CEMENT
FOR INTERMEDIATE BALANCED PLUG
3/30/2024
3,721.0 3,798.0 2,452.0 2,483.6 Cement Plug PJSM. Test lines to 3000 PSI. Pump 9 BBLS 11.0
ppg MudPush spacer + 29 BBLS 16.5 ppg cement +
13 BBLS 11.0 ppg MudPush spacer + 2 BBLs FW to
clear lines. Displace with 45 BBLs 9.8 ppg Brine.
4/28/2024
2P-415A, 4/3/2025 12:26:26 PM
Vertical schematic (actual)
PRODUCTION 5.5"x3.5" @
8210'; 3,780.0-9,025.8
FLOAT SHOE; 9,024.7-9,025.8
FLOAT COLLAR; 8,929.3-
8,930.3
Plug Catcher; 8,898.0
FRAC; 8,640.0
IPERF; 8,640.0-8,650.0
PLUG; 8,625.0
Cement Plug; 8,518.0 ftKB
SEAL ASSY; 8,193.8
SBE; 8,190.7-8,210.1
LOCATOR; 8,193.3
NIPPLE; 8,150.0
SLEEVE-C; 8,134.0
TUBING PUNCH; 8,105.0
GAS LIFT; 8,090.5
GAS LIFT; 7,540.6
GAS LIFT; 6,864.7
Intermediate String 1 Cement;
6,333.0 ftKB
GAS LIFT; 5,662.6
PLUG; 3,798.0
CUT; 3,768.0
Cement Plug; 3,721.0 ftKB
IBP; 3,708.0
SURFACE; 27.9-3,713.0
FLOAT SHOE; 3,711.5-3,713.0
FLOAT COLLAR; 3,623.4-
3,624.7
IBP; 3,488.0
Kill string; 23.2-1,993.0
PORT COLLAR; 988.0-990.5
CONDUCTOR; 28.0-110.0
HANGER; 27.9-30.5
HANGER; 23.2-25.9
KUP PROD
KB-Grd (ft)
34.50
RR Date
12/5/2001
Other Elev…
2P-415A
...
TD
Act Btm (ftKB)
9,038.0
Well Attributes
Field Name
MELTWATER
Wellbore API/UWI
501032038301
Wellbore Status
PROD
Max Angle & MD
Incl (°)
68.89
MD (ftKB)
5,168.44
WELLNAME WELLBORE2P-415A
Annotation
Last WO:
End DateH2S (ppm)
82
Date
12/21/2013
Comment
SSSV: NIPPLE
Reviewed By:
P.I. Suprv
Comm ________
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9
9
9
9
9
2024-0930_Suspend_KRTU 2P-415A_photos_bb
Page 1 of 1
Suspended Well Inspection – KRU 2P-415A
PTD 2012260
AOGCC Inspection Rpt # susBDB241001133059
Photos by AOGCC Inspector B. Bixby
9/30/2024
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other:
Development Exploratory
Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number): 8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 9038'feet 3810', 8625'feet
true vertical 6050' feet None feet
Effective Depth measured 3495'feet 8194'feet
true vertical 2364' feet 5273' feet
Perforation depth Measured depth
True Vertical depth
Tubing (size, grade, measured and true vertical depth) 3-1/2" L-80 8211' MD 5289' TVD
Packers and SSSV (type, measured and true vertical depth) 8194' MD
N/A
5273' TVD
N/A
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure: N/A
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work: Meltwater Oil Pool- Suspended
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date: Contact Name:
Authorized Title:
3713' 2449'
Burst Collapse
Production
Liner
9000'
Casing
6039'9026'
3685'
110'Conductor
Surface
Intermediate
16"
7-5/8"
82'
measured
TVD
5-1/2" x 3-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
201-226
50-103-20383-01-00
P.O. Box 100360
Anchorage, AK 99510
3. Address:
ConocoPhillips Alaska, Inc.
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
ADL0373112
Kuparuk River Field/ Meltwater Oil Pool
KRU 2P-415A
Plugs
Junk measured
Length
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
~
Gas-Mcf
MD
~
Size
110'
~ ~~
SUSPENDED ~~
~
N/A
Sr Pet Eng: Sr Pet Geo: Sr Res Eng:
WINJ WAG
~
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
N/A
Packer: Baker G-22 Seal Assembly
SSSV: None
Dusty Freeborn
Staff Projects Engineer
8640-8650'
5682-5691'
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
Contact Email: dusty.freeborn@conocophillips.com
Contact Phone: (907) 265-6218
By Grace Christianson at 3:15 pm, Oct 17, 2024
Digitally signed by Dusty Freeborn
DN: CN=Dusty Freeborn, O=ConocoPhillips Alaska, OU
=Well Integrity and Intervention, E=Dusty.Freeborn@
conocophillips.com, C=US
Reason: I am the author of this document
Location: Anchorage, Alaska
Date: 2024.10.16 15:02:53-08'00'
Foxit PDF Editor Version: 13.0.0
Dusty
Freeborn
Last Tag
Annotation Depth (ftKB) Wellbore End Date Last Mod By
Last Tag: RKB (Tagged TOC) 2P-415A 3/17/2024 rogerba
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Update schematic post Doyon 25 P&A 2P-415A 5/5/2024 rogerba
Casing Strings
Csg Des OD (in) ID (in) Top (ftKB)
Set Depth
(ftKB)
Set Depth
(TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread
CONDUCTOR 16 15.06 28.0 110.0 110.0 62.50 H-40 WELDED
SURFACE 7 5/8 6.87 27.9 3,713.0 2,448.7 29.70 L-80 BTC Mod
Kill string 5 1/2 4.95 25.3 1,995.1 1,763.2 15.50 L-80 BTC Mod
PRODUCTION
5.5"x3.5" @ 8210'
5 1/2 4.95 25.3 9,025.8 6,038.6 15.50 L-80 BTC Mod
Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string
Top (ftKB)
3,924.3
Set Depth
8,210.7
Set Depth
5,288.8
String Max No
3 1/2
Tubing Description
Tubing - Production
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE-8rd
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
5,662.6 3,246.5 60.24 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
6,864.7 4,069.7 29.51 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
7,540.6 4,678.8 26.93 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,090.5 5,178.2 23.38 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,134.0 5,218.2 23.00 SLEEVE-C 4.500 BAKER CMU NON-ELASTOMER
SLIDING SLEEVE w/CAMCO DS
PROFILE - CLOSED 11/14/2009
BAKER CMU 2.812
8,150.0 5,233.0 23.07 NIPPLE 3.750 CAMCO D NIPPLE CAMCO D 2.750
8,193.3 5,272.8 23.26 LOCATOR 4.500 BAKER 80-40 G-22 LOCATOR SUB BAKER 3.000
8,193.8 5,273.2 23.27 SEAL ASSY 4.000 BAKER G-22 SEAL ASSY BAKER 3.000
Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.)
Top (ftKB)
Top (TVD)
(ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in)
3,495.0 2,363.6 68.07 IBP 3.5" TAM IBP run by
yellowjacket. Packer tested
1000psi 30 minutes
TAM 5/2/2024
3,708.0 2,446.6 65.77 IBP 2.5" TAM IBP run by
yellowjacket. Packer did not
test. Was pushed to bottom.
Unable to fish out. Top of fish
is ~5' inside csg. 2.13" OD HR
running tool 0.79' long looking
up.
TAM 5/2/2024 0.000
3,780.0 2,476.2 65.94 CUT WELLTEC MECHANICAL
TBG CUT AT 3780' D25 RKB.
(55' below surface shoe)
4/25/2024 4.950
3,810.0 2,488.4 66.17 PLUG 4.25" - 4.75" Alpha CIBP 3810'
D25 RKB (85' below surface
shoe)
4/25/2024 0.000
8,105.0 5,191.6 23.24 TUBING
PUNCH
3' TUBING PUNCH, 1.56", 3
GRAM, 6 SPF, 18 0.43"
HOLES
OWEN 3/24/2024 2.992
8,625.0 5,668.7 24.22 PLUG Set TTS CIBP (2.63" x 1.37' ) 10/7/2023 0.000
8,898.0 5,919.5 21.81 Plug Catcher WEATHERFORD PLUG
CATCHER
12/4/2001 0.000
Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal ID
(in)
28.0 28.0 0.00 PRODUCTION 5.500 4.950
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft)Type Com
8,640.0 8,650.0 5,682.3 5,691.5 T-3, 2P-415 12/24/2001 6.0 IPERF HMX Chrgs, 60 deg ph
Stimulation Intervals
Top (ftKB) Btm (ftKB)
Inter
val
Num
ber Type Subtype Start Date
Proppant
Designed (lb)
Proppant
Total (lb)
Vol Clean
Total (bbl)
Vol Slurry
Total (bbl)
8,640.0 8,650.0 1 FRAC 12/24/2001 0.0 0.00 0.00
Cement Squeezes
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Des Com
Pump Start
Date
8,518.0 8,625.0 5,570.9 5,668.7 Cement Plug Dump bailed cement with Slickline on top of CIBP 12/18/2023
6,600.0 8,100.0 3,849.8 5,187.0 Intermediate
String 1
Cement
PUMPED 31 BBLS OF 15.8 CLASS G CEMENT
FOR INTERMEDIATE BALANCED PLUG
3/30/2024
3,720.0 3,810.0 2,451.6 2,488.4 Cement Plug PJSM. Test lines to 3000 PSI. Pump 9 BBLS 11.0
ppg MudPush spacer + 29 BBLS 16.5 ppg cement +
13 BBLS 11.0 ppg MudPush spacer + 2 BBLs FW to
clear lines. Displace with 45 BBLs 9.8 ppg Brine.
4/28/2024
2P-415A, 9/25/2024 11:29:58 AM
M
D
(ft
KB
)
-1,272.0
-1,233.6
-1,186.0
-1,144.4
-1,109.3
-894.4
0.0
27.9
109.9
990.5
3,495.1
3,623.4
3,708.0
3,712.9
3,720.1
3,780.8
3,811.4
5,575.1
5,662.7
5,674.9
6,858.9
6,871.4
7,528.9
7,540.7
7,552.8
8,090.6
8,100.1
8,105.0
8,133.9
8,149.9
8,157.2
8,187.3
8,190.6
8,193.9
8,210.6
8,257.9
8,288.4
8,319.9
8,507.9
8,557.1
8,619.1
8,627.0
8,649.9
8,798.9
8,825.1
8,898.9
8,930.1
9,025.9
Vertical schematic (actual)
T-7 (final)
T-4.1 (fi
T-4.2 (fi
T-3 (final)
T-3.1 (fi
T-2 (final)
FLOAT SHOE; 9,024.7-9,025.8; 1.10; 4-18; 3.500; 2.992
PRODUCTION; 8,930.3-9,024.7;
94.42; 4-17; 3.500; 2.992
FLOAT COLLAR; 8,929.3-8,930.3;
0.96; 4-16; 3.500; 2.992
PRODUCTION; 8,897.9-8,929.3;
31.42; 4-15; 3.500; 2.992
PROD w/plug catcher; 8,619.0-8,897.9; 278.93; 4-14; 3.500; 2.992
IPERF; 8,640.0-8,650.0; 12/24/2001
PUP; 8,608.8-8,619.0; 10.15; 4-13;
3.500; 2.992
PRODUCTION; 8,328.0-8,608.8;
280.83; 4-12; 3.500; 2.992
PUP; 8,319.9-8,328.0; 8.05; 4-11; 3.500; 2.992
PRODUCTION; 8,288.5-8,319.9; 31.41; 4-10; 3.500; 2.992
PUP; 8,282.5-8,288.5; 6.06; 4-9;
3.500; 2.992
PRODUCTION; 8,220.7-8,282.5; 61.80; 4-8; 3.500; 2.992
PUP; 8,210.7-8,220.7; 10.00; 4-7; 3.500; 2.992
XO reducing; 8,210.1-8,210.7; 0.57; 4-
6; 5.500; 3.500
SEAL ASSY; 8,193.8-8,210.7; 16.90; 2-
25; 4.000; 3.000
SBE; 8,190.7-8,210.1; 19.44; 4-5; 5.500; 4.950
LOCATOR; 8,193.3-8,193.8; 0.52; 2-24; 4.500; 3.000
TUBING PUP; 8,187.2-8,193.3; 6.05; 2
-23; 3.500; 2.992
XO THREAD; 8,189.5-8,190.7; 1.16; 4-4; 5.500; 4.950
PUP; 8,178.3-8,189.5; 11.20; 4-3;
5.500; 4.950
TUBING; 8,157.0-8,187.2; 30.22; 2-22;
3.500; 2.992
TUBING PUP; 8,151.0-8,157.0; 6.00; 2-21; 3.500; 2.992
NIPPLE; 8,150.0-8,151.0; 0.98; 2-20;
3.750; 2.750
TUBING PUP; 8,137.9-8,150.0; 12.10;
2-19; 3.500; 2.992
SLEEVE-C; 8,134.0-8,137.9; 3.96; 2-
18; 4.500; 2.812
TUBING; 8,102.6-8,134.0; 31.36; 2-17; 3.500; 2.992
TUBING PUP; 8,097.1-8,102.6; 5.52; 2-16; 3.500; 2.992
GAS LIFT; 8,090.5-8,097.1; 6.63; 2-15; 4.750; 2.900
TUBING PUP; 8,084.5-8,090.5; 5.97; 2-14; 3.500; 2.992
TUBING; 7,552.7-8,084.5; 531.76; 2-13; 3.500; 2.992
TUBING PUP; 7,547.3-7,552.7; 5.47; 2
-12; 3.500; 2.992
GAS LIFT; 7,540.6-7,547.3; 6.62; 2-11;
4.750; 2.900
TUBING PUP; 7,534.8-7,540.6; 5.88; 2
-10; 3.500; 2.992
TUBING; 6,876.8-7,534.8; 657.93; 2-9;
3.500; 2.992
TUBING PUP; 6,871.3-6,876.8; 5.49; 2
-8; 3.500; 2.992
GAS LIFT; 6,864.7-6,871.3; 6.62; 2-7;
4.750; 2.900
TUBING PUP; 6,858.8-6,864.7; 5.89; 2-6; 3.500; 2.992
TUBING; 5,674.7-6,858.8; 1,184.08; 2-5; 3.500; 2.992
PRODUCTION; 3,780.0-8,178.3; 8,150.25; 4-2; 5.500; 4.950
TUBING PUP; 5,669.3-5,674.7; 5.45; 2-4; 3.500; 2.992
GAS LIFT; 5,662.6-5,669.3; 6.68; 2-3; 4.750; 2.900
TUBING PUP; 5,656.6-5,662.6; 5.98; 2-2; 3.500; 2.992
TUBING; 3,924.3-5,656.6; 1,732.35; 2-1; 3.500; 2.992
FLOAT SHOE; 3,711.5-3,713.0; 1.51; 3-7; 7.625; 6.875
SURFACE; 3,624.7-3,711.5; 86.79; 3-6; 7.625; 6.875
FLOAT COLLAR; 3,623.4-3,624.7;
1.33; 3-5; 7.625; 6.875
SURFACE; 990.5-3,623.4; 2,632.91; 3-
4; 7.625; 6.875
PRODUCTION; 28.0-1,995.1; 1,967.09; 2-2; 5.500; 4.950
PORT COLLAR; 988.0-990.5; 2.42; 3-
3; 7.625; 6.875
SURFACE; 30.5-988.0; 957.58; 3-2;
7.625; 6.875
CONDUCTOR; 28.0-110.0; 82.00; 1-1; 16.000; 15.062
HANGER; 27.9-30.5; 2.57; 3-1; 10.650; 7.625
HANGER; 25.3-28.0; 2.70; 2-1; 8.500;
5.500
KUP PROD
KB-Grd (ft)
34.50
RR Date
12/5/2001
Other Elev
2P-415A
...
TD
Act Btm (ftKB)
9,038.0
Well Attributes
Field Name
MELTWATER
Wellbore API/UWI
501032038301
Wellbore Status
PROD
Max Angle & MD
Incl (°)
68.89
MD (ftKB)
5,168.44
WELLNAME WELLBORE2P-415A
Annotation
Last WO:
End DateH2S (ppm)
82
Date
12/21/2013
Comment
SSSV: NIPPLE
ORIGINATED
TRANSMITTAL
DATE: 6/26/2024
ALASKA E-LINE SERVICES
TRANSMITTAL
#: 4742
42260 Kenai Spur Hwy
PO BOX 1481 - Kenai, Alaska 99611 FIELD Meltwater
PH: (907) 283-7374 FAX: (907) 283-7378
DELIVERABLE DESCRIPTION
TICKET # WELL # API #
LOG
DESCRIPTION
DATE OF
LOG
4742 2P-415A 501032038301 Tubing Punch 24-Mar-2024
RECIPIENTS
Conoco Phillips Alaska, Inc.
DIGITAL FILES PRINTS CD'S
1 0 0 0 USPS
0
0 0
0
Received
By: Received By:
Signature Signature
AOGCC
DIGITAL FILES PRINTS CD'S
1 SharePoint
Link 0 0 USPS
Attn: Natural Resources Technician II
abby.bell@alaska.gov Alaska Oil & Gas Conservation Commision
333 W. 7th Ave, Suite 100 - Anchorage, AK 99501
Received
By: Received By:
Signature Signature
201-226
T39060
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.06.26 15:29:03 -08'00'
DNR
DIGITAL FILES PRINTS CD'S
1 SharePoint
Link 0 0 USPS
Attn: Natural Resource Tech II
DOG.Redata@alaska.gov 550 West 7th Ave, Suite #802 - Anchorage, AK 99501
Delivery Method: USPS
Received
By: Received By:
Signature Signature
Please return via e-mail a copy to both:
AR@ake-
line.com 0
201-226
T38922
Gavin Gluyas
Digitally signed by Gavin
Gluyas
Date: 2024.06.13 08:22:50
-08'00'
2P-415A
201-226
T38914
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.06.12 14:57:36
-08'00'
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: ___________________ Service Stratigraphic Test
2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval:17. Field / Pool(s):
GL: BF:
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 N/A (ft MSL)
22. Logs Obtained:
N/A
23.
BOTTOM
16" B 110'
7.625" L-80 2449'
5.5" L-80 5288'
3.5" L-80 6038'
24. Open to production or injection? Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production: Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press. 24-Hour Rate
8210'
SIZE DEPTH SET (MD)
3619-3768' MD Cement - Drilled Out Attempt #1
9025'
Surface
5288'
62.5#
29.7#
110'
Surface
Sr Res EngSr Pet GeoSr Pet Eng
Oil-Bbl: Water-Bbl:
31 bbls 15.8 ppg Class G Cement
3721-3768' MD 29 bbls 16.5 ppg Cement
Water-Bbl:
PRODUCTION TEST
N/A
Date of Test: Oil-Bbl:
Flow Tubing
6600-8100' MD
3446-3768' MD
SUSPENDED
8640-8650' MD and 5682-5692' TVD (cemented)
Gas-Oil Ratio:Choke Size:
Cement - Drilled Out Attempt #2
Per 20 AAC 25.283 (i)(2) attach electronic information
N/A
PACKER SET (MD/TVD)
42"
9.875"
15 sx AS1
Surface 410 sx AS Lite, 290 sx
LiteCRETE
9.3#
Surface
8210'
3713'Surface
surface
If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size
and Number; Date perf'd or liner run):
15.5#
WT. PER
FT.GRADE
12/3/2001
CEMENTING RECORD
5867175
1546' MD/ 1464' TVD
SETTING DEPTH TVD
5867138
TOP HOLE SIZE AMOUNT
PULLED
449442
449614
TOP
SETTING DEPTH MD
suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log,
spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar
locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary.
N/A
BOTTOM
Kuparuk River Field/ Meltwater Oil Pool-
Suspended
N/A
50-103-20383-01-00
KRU 2P-415A
ADL0373112
869' FNL, 2226' FWL, Sec. 17, T8N, R7E, UM
2580' FSL, 2382' FWL, Sec. 16, T8N, R7E, UM
11/29/2002
9038' MD/ 6050' TVD
3495' MD/ 2364' TVD
P.O. Box 100360, Anchorage, AK 99510-0360
444186 5869007
2616' FSL, 2209' FWL, Sec. 16, T8N, R7E, UM
9. Ref Elevations: KB:251.4
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
ConocoPhillips Alaska, Inc.
WAG
Gas
5/4/2024 201-226/ 324-146/ 324-240/
324-252/ 324-265
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
included above6.75"
TUBING RECORD
62.5 bbls Class G6.75"
8211'3.5"
CASING
Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment
By Grace Christianson at 3:12 pm, May 31, 2024
Suspended
5/4/2024
JSB
RBDMS JSB 070324
xGDSR-7/9/24
Conventional Core(s): Yes No Sidewall Cores:
N/A
30.
MD TVD
Surface Surface
1546' 1464'
Top of Productive Interval
N/A
31. List of Attachments: Schematics, Summary of Operations, Cement Reports
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Sydney Long
Digital Signature with Date:Contact Email: sydney.long@conocophillips.com
Contact Phone:(907) 265-6312
Senior RWO/CTD Engineer
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31:
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if
needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Permafrost - Top
Permafrost - Base
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS
N/A Suspended
TPI (Top of Producing Interval).
Authorized Name and
Formation Name at TD:N/A Suspended
Authorized Title:
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core
analysis, paleontological report, production or well test results, per 20 AAC 25.070.
INSTRUCTIONS
Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from
a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
C80 @ 3775' KBC80 @ 3775' KB
2P-415A Suspension Schematic
Conductor:
16" Conductor 110' KB
Production Casing Cement:
62.5 bbls of 15.8# Class G Cement
Calculated TOC @ 5,782' KB
1
3
5
4
Production Casing:
5.5" x 3.5" @ 8,210' KB, 15.5# x 9.3#,
L-80 BTC Mod
Set @ 9,025.8’ KB
T-3 Peforations:
@ 8,640' – 8,650' KB (10')
Surface Casing:
7-5/8", 29.7#, L-80 BTC Mod
Set @ 3,713' KB
Production Tubing:
3 ½”, 9.3# L-80 EUE-8rd
Set @ 8,208.4' KB
6
Item Depth - tops
(KB)
1 FMC Hanger 23.1'
2 Cast Iron Bridge Plug 3798.0'
3
Baker CMU Non-Elastomer Sliding
Sleeve w/ Camco DS Profile -
Closed 11/14/2009
8,131.6'
4 Camco D Nipple 8,147.7'
5 Baker 80-40 G-22 Locator Sub 8,190.9'
6 Baker G22 Seal Assembly 8,191.5'
Plug #1 – Reservoir
TOC 8518' RKB
Plug #2 – Intermediate
TOC 6333' RKB
BOC @ 8105' RKB
Surface Shoe Cement
TOC Tagged @ 3721' RKB
BOC @ 3768' RKB
IBP @ 3488' RKB
PT to 1000 PSI for 30 min
2
5-½” Kill String
@ 1993' RKB
9.8 ppg NaCl w/ FP
Last Tag
Annotation Depth (ftKB) Wellbore End Date Last Mod By
Last Tag: RKB (Tagged TOC) 2P-415A 3/17/2024 rogerba
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Annotate Tbg Cut 2P-415A 4/3/2024 bworthi1
Casing Strings
Csg Des OD (in) ID (in) Top (ftKB)
Set Depth
(ftKB)
Set Depth
(TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread
CONDUCTOR 16 15.06 28.0 110.0 110.0 62.50 H-40 WELDED
SURFACE 7 5/8 6.87 27.9 3,713.0 2,448.7 29.70 L-80 BTC Mod
PRODUCTION
5.5"x3.5" @ 8210'
5 1/2 4.95 25.3 9,025.8 6,038.6 15.50 L-80 BTC Mod
Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string
Top (ftKB)
3,924.3
Set Depth …
8,210.7
Set Depth …
5,288.8
String Max No…
3 1/2
Tubing Description
Tubing - Production
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE-8rd
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
5,662.6 3,246.5 60.24 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
6,864.7 4,069.7 29.51 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
7,540.6 4,678.8 26.93 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,090.5 5,178.2 23.38 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,134.0 5,218.2 23.00 SLEEVE-C 4.500 BAKER CMU NON-ELASTOMER
SLIDING SLEEVE w/CAMCO DS
PROFILE - CLOSED 11/14/2009
BAKER CMU 2.812
8,150.0 5,233.0 23.07 NIPPLE 3.750 CAMCO D NIPPLE CAMCO D 2.750
8,193.3 5,272.8 23.26 LOCATOR 4.500 BAKER 80-40 G-22 LOCATOR SUB BAKER 3.000
8,193.8 5,273.2 23.27 SEAL ASSY 4.000 BAKER G-22 SEAL ASSY BAKER 3.000
Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.)
Top (ftKB)
Top (TVD)
(ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in)
3,780.0 2,476.2 65.94 CUT WELLTEC MECHANICAL
TBG CUT AT 3780' D25 RKB.
(55' below surface shoe)
4/25/2024 4.950
3,810.0 2,488.4 66.17 PLUG 4.25" - 4.75" Alpha CIBP 3810'
D25 RKB (85' below surface
shoe)
4/25/2024 0.000
8,105.0 5,191.6 23.24 TUBING
PUNCH
3' TUBING PUNCH, 1.56", 3
GRAM, 6 SPF, 18 0.43"
HOLES
OWEN 3/24/2024 2.992
8,625.0 5,668.7 24.22 PLUG Set TTS CIBP (2.63" x 1.37' ) 10/7/2023 0.000
8,898.0 5,919.5 21.81 Plug Catcher WEATHERFORD PLUG
CATCHER
12/4/2001 0.000
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft)Type Com
8,640.0 8,650.0 5,682.3 5,691.5 T-3, 2P-415 12/24/2001 6.0 IPERF HMX Chrgs, 60 deg ph
Stimulation Intervals
Top (ftKB) Btm (ftKB)
Inter
val
Num
ber Type Subtype Start Date
Proppant
Designed (lb)
Proppant
Total (lb)
Vol Clean
Total (bbl)
Vol Slurry
Total (bbl)
8,640.0 8,650.0 1 FRAC 12/24/2001 0.0 0.00 0.00
Cement Squeezes
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Des Com
Pump Start
Date
8,518.0 8,625.0 5,570.9 5,668.7 Cement Plug Dump bailed cement with Slickline on top of CIBP 12/18/2023
6,600.0 8,100.0 3,849.8 5,187.0 Intermediate
String 1
Cement
PUMPED 31 BBLS OF 15.8 CLASS G CEMENT
FOR INTERMEDIATE BALANCED PLUG
3/30/2024
2P-415A, 5/1/2024 3:18:56 PM
Vertical schematic (actual)
PRODUCTION 5.5"x3.5" @
8210'; 3,780.0-9,025.8
Plug Catcher; 8,898.0
IPERF; 8,640.0-8,650.0
FRAC; 8,640.0
PLUG; 8,625.0
Cement Plug; 8,518.0 ftKB
TUBING PUNCH; 8,105.0
GAS LIFT; 8,090.5
GAS LIFT; 7,540.6
GAS LIFT; 6,864.7
Intermediate String 1 Cement;
6,600.0 ftKB
GAS LIFT; 5,662.6
PLUG; 3,810.0
CUT; 3,780.0
SURFACE; 27.9-3,713.0
CONDUCTOR; 28.0-110.0
KUP PROD
KB-Grd (ft)
34.50
RR Date
12/5/2001
Other Elev…
2P-415A
...
TD
Act Btm (ftKB)
9,038.0
Well Attributes
Field Name
MELTWATER
Wellbore API/UWI
501032038301
Wellbore Status
PROD
Max Angle & MD
Incl (°)
68.89
MD (ftKB)
5,168.44
WELLNAME WELLBORE2P-415A
Annotation
Last WO:
End DateH2S (ppm)
82
Date
12/21/2013
Comment
SSSV: NIPPLE
May 29, 2024
VIA E-MAIL DELIVERY
Victoria Loepp
Senior Petroleum Engineer
Alaska Oil and Gas Conservation Commission
333 West Seventh Avenue, Suite 100
Anchorage, Alaska 99501-3572
Subject: Summary of 2P-415A Surface Casing Shoe Cement Plug Operations
Dear Ms. Loepp,
2P-415A was one of the wells approved for plugging and abandonment (P&A) in Q2 2024 by the AOGCC. This was
the second well to be plugged and abandoned on the pad. Three attempts were made to set and test a cement
plug at the surface casing shoe per the approved sundry, without success. The repeated attempts at cement, the
context of working in the presence of Iron Sulfide scale, and the warming weather adding risk to being able to
remove Doyon 25 from 2P pad prior to the roads becoming impassible by heavy loads, resulted in the approved
suspension of the well. ConocoPhillips currently plans to return to the well to complete the abandonment in late
2024 through early 2025.
On this well, the tubing was pulled from a pre-rig cut. A CIBP was set in the production casing and the latter cut
above it. Circulation was established and the OA was circulated to KWF. The production casing was then used as
the cementing string for placing the surface casing shoe cement plug. The following is a summary of cementing
operations on 2P-415A as requested in our meeting on May first. Please note, all depths are converted to original
RKB in the following summary and will differ from the operational time log which referenced Doyon 25 RKB depths.
Cement Plug Attempt #1
Design
o 29 BBL 16.5 Class G Cement
o Displace with 9.8 PPG Brine
Summarized Operational Procedure
o Spot balanced plug at 3768’ RKB
o POOH cement string to 3517’ RKB. Circulate out excess cement.
o POOH cement string above TOC to 3159’ RKB. Close annular and apply 200 psi to wellbore.
WOC. Break string over approximately every hour to confirm free
Result
o Wash down to 3619’RKB with returns of contaminated cement. Tag 10k at 3619’
o Attempt to pressure test. Pressure decreased from 812 to 490 PSI in 10 minutes. Repeat a total
of 3 tests with confirmed failure.
Sydney Long
Senior Rig Workover Engineer
700 G Street, ATO 1562
Anchorage, AK 99510
(907) 265 - 6321 (office)
Sydney.Long@conocophillips.com
Cement Plug Attempt #2
Design
o Same cementing program as Cement Plug Attempt #1
o Displace with 9.8 PPG Brine – displace by ~10 BBL less than first plug
Summarized Operational Procedure
o Spot balanced plug at tagged depth of drilled cement at 3719’ RKB
o POOH cement string to 3434’ RKB. Circulate out excess cement
o POOH cement string above TOC to 3159’ RKB. Close annular and apply 200 psi to wellbore.
WOC.
Key Changes Made
o Decreased displacement to have higher overbalance inside pipe while pulling out of cement plug
to mitigate contamination
o Did not reciprocate pipe above plug while WOC as often to minimize any swab effect on the well
o Pulled up higher for circulation to mitigate contamination
Result
o Wash down to 3446’ MD and tag cement
o Attempt to pressure test. Failed test with a pressure decreasing from 1670 to 1312 PSI in 30
minutes. Repeat a total of 2 tests with confirmed failure.
Cement Plug Attempt #3
Design
o 29 BBL 15.9 PPG AS1 Cement
o Displace with 9.8 PPG WBM
Summarized Operational Procedure
o Circulate well over to 9.8 PPG WBM
o Spot balanced plug at 3722’ RKB
o POOH cement string to 3508’ RKB. Attempt to circulate excess cement. Observe lost returns.
o POOH cement string to 3158’ RKB and attempt to regain returns unsuccessfully.
o POOH to surface
Key Changes Made
o Displaced to 9.8 PPG WBM per lessons of shallow plug sets on WD-03 and feedback from Global
Wells SMEs
o Moved from a Class G cement to an AS1 blend to reduce thickening time and WOC time
Result
o Lost circulation while attempting to circulate out excess cement due to apparent contamination
o Viscous mud was observed during the TIH with the cleanout BHA. Stringers were observed as
high as 2158’ RKB. Cement was tagged at 3721’ RKB (8’ below the surface casing shoe
potentially indicating losses at the shoe)
Our team is still reviewing the above operations and developing a recommendation for the completion of this
P&A.
If you have any questions or require any further information, please feel free to contact me.
Sydney Long
Senior Rig Workover Engineer
Attachment: Schematic of 2P-415A Cement Plug Attempts
C80 @ 3775' KB
2P-415A Well Surface Shoe Cement Plugs
Conductor:
16" Conductor 110' KB
Production Casing:
5.5", 15.5#, L-80 BTC Mod
Cut @ 3,768' KB
Surface Casing:
7-5/8", 29.7#, L-80 BTC Mod
Set @ 3,713' KB
TOC @ ~3508' RKB
BOC @ 3722' RKB
Cement in Place @
19:30 4/30/24
Tagged Depth @
3721' RKB
05:15 5/1/24
TOC @ 3434' RKB
BOC @ 3719' RKB
Cement in Place @
18:45 4/28/24
Tagged Depth @
3446' RKB
14:00 4/29/24
TOC @ 3517' RKB
BOC @ 3768' RKB
Cement in Place @
14:00 4/26/24
Tagged Depth @
3619' RKB
17:00 4/27/24
Attempt #1 Attempt #2 Attempt #3
Page 1/11
2P-415
Report Printed: 5/30/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/20/2024
12:00
4/20/2024
13:30
1.50 MIRU, MOVE RURD P Continue with interconnections. Prep
casing shed for move. Stomp out casing
shed and move away with trucks. Skid
rig floor into STOW position.
0.0 0.0
4/20/2024
13:30
4/20/2024
15:30
2.00 MIRU, MOVE MOB P Prep to lay down derrick. Stomp out and
set pits, power, and pumps modules on
suspension. Move modules.
0.0 0.0
4/20/2024
15:30
4/20/2024
19:00
3.50 MIRU, MOVE MOB P Lay down derrick. Unpin pipe shed and
stomp into position for trucks. Out and
90° turn.
0.0 0.0
4/20/2024
19:00
4/21/2024
00:00
5.00 MIRU, MOVE MOB P Install Jeep into sub. Move sub off 2P-
420 well at 20:00hrs. Moving into
position on 2P-415 well.
0.0 0.0
4/21/2024
00:00
4/21/2024
01:00
1.00 MIRU, MOVE MOB P Continue moving Sub into position on
2P-415 well.
0.0 0.0
4/21/2024
01:00
4/21/2024
02:00
1.00 MIRU, MOVE MOB P Stomp Sub onto 2P-415 well center at
02:00hrs, 4-21-24.
0.0 0.0
4/21/2024
02:00
4/21/2024
07:30
5.50 MIRU, MOVE MOB P Move pit module and pipe module into
stomping position. Stomp pipe module
to Sub and pin.
0.0 0.0
4/21/2024
07:30
4/21/2024
10:30
3.00 MIRU, MOVE MOB P Move pump, motor and casing modules
into stomping position.
0.0 0.0
4/21/2024
10:30
4/21/2024
12:00
1.50 MIRU, MOVE RURD P Raise derrick and skid to drilling
position. Install interconnections. Lower
C section.
0.0 0.0
4/21/2024
12:00
4/21/2024
16:00
4.00 MIRU, MOVE RURD P Raise cattle chute. Continue installing
interconnections.
0.0 0.0
4/21/2024
16:00
4/21/2024
18:00
2.00 MIRU, MOVE RURD P Work on rig acceptance checklist. Rig
acceptance at 17:00hrs, 4-21-24.
SIMOPS: Received 200bbls Vis Brine.
0.0 0.0
4/21/2024
18:00
4/21/2024
20:30
2.50 MIRU, WELCTL RURD P Continue installing interconnections
between Sub and pit module.
SIMOPS: Check well pressures. R/U
flange and line Tiger tank to IA and
injection line to tree.
TBG: 0psi
IA: 0psi
OA: 160psi
0.0 0.0
4/21/2024
20:30
4/21/2024
22:00
1.50 MIRU, WELCTL OTHR P Bled off 160psi from OA to Tiger tank.
B/D hard line and prime #2 mud pump.
0.0 0.0
4/21/2024
22:00
4/21/2024
22:30
0.50 MIRU, WELCTL PRTS P PJSM. Blow air through injection line
and flood with water. Attempt to test
lines with #1 MP - unable to hold
pressure with no external leaks. Line up
#2 mud pump. Attempt to test lines with
same results.
0.0 0.0
4/21/2024
22:30
4/22/2024
00:00
1.50 MIRU, WELCTL CIRC P Inspect mud pumps - fluid ends full of
LCM. Clean out pumps. Circulate out
suction lines through bleeder.
0.0 0.0
4/22/2024
00:00
4/22/2024
01:00
1.00 MIRU, WELCTL OTHR P Continue to flush and test mud pumps to
2500psi (good test).
0.0 0.0
4/22/2024
01:00
4/22/2024
02:00
1.00 MIRU, WELCTL CIRC P Flood lines to Tiger tank. Test lines to
2500psi (good test). Circulate out freeze
protect. Pumped 101bbls 9.8ppg in/out.
0.0 0.0
4/22/2024
02:00
4/22/2024
03:00
1.00 MIRU, WHDBOP RURD P OWFF (static). Blow down and R/D
service lines.
0.0 0.0
4/22/2024
03:00
4/22/2024
03:30
0.50 MIRU, WHDBOP NUND P N/D Tree and inspect hanger (good).
Install blanking plug.
0.0 0.0
Rig: DOYON 25
RIG RELEASE DATE 5/4/2024
Page 2/11
2P-415
Report Printed: 5/30/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/22/2024
03:30
4/22/2024
12:00
8.50 MIRU, WHDBOP NUND P N/U DSA and high pressure riser. N/U
BOP's kill/choke lines.
SIMOPS: Mix pills and work on pump
module tires.
0.0 0.0
4/22/2024
12:00
4/22/2024
14:30
2.50 MIRU, WHDBOP NUND P N/D and change out high pressure riser
spool (Joes box wouldn't clear), N/U
BOP.
0.0 0.0
4/22/2024
14:30
4/22/2024
19:30
5.00 MIRU, WHDBOP PRTS P Test BOPE. All test T/ 250 low for 5 min
and 2,500 high for 5 min charted.
Manual operated & super choke tested
T/2,000 psi charted, W/ 3-1/2" and 5.5"
test JT test annular, 3-1/2 X 5-7/8" UPR,
Test choke valves 1-15, manual
operated & super choke, Kill manual,
HCR's, 4" valves on kill line, Upper and
lower IBOP on TD; Blind/shear rams;
Perform KOOMEY drawdown, ACC =
2950 PSI. MANIF. = 1500 PSI. ACC =
1900 PSI After all functions on bottles,
14 sec for 200 psi. Build W/ 2 Elec.
pumps, 70 sec T/ Build full system.
Pressure W/ 2 Elec. & 2 Air pumps,
Closing times, Annular = 22 sec. UPR =
5 sec. Blind / Shears = 5 sec. LPR = 4
sec. Choke HCR = 2 sec. Kill HCR = 2
sec; Test PVT G/L and flow out alarms,
Test LEL and H2S alarms.
AOGCC Sean Sullivan witnessed BOP
test.
0.0 0.0
4/22/2024
19:30
4/22/2024
20:30
1.00 MIRU, WHDBOP RURD P R/D test equipment and blow down
surface equipment.
0.0 0.0
4/22/2024
20:30
4/22/2024
21:00
0.50 MIRU, WHDBOP PRTS P Between crew change, choke line
manual HCR valve wasn't tested. R/U
test joint and test choke line manual
valve 250/2500psi 5/5min.
0.0 0.0
4/22/2024
21:00
4/22/2024
22:00
1.00 MIRU, WHDBOP RURD P R/D test equipment and blow down
surface equipment. M/U 4" double. 0psi
on IA. Pull blanking plug. OWFF (static),
RIH and screw into hanger. BOLD's.
0.0 0.0
4/22/2024
22:00
4/22/2024
23:00
1.00 COMPZN, CSGRCY CIRC P Off seat hanger - 74k (clean pull, good
cut). Well static. Circulate and stage
pumps up to 252gpm, 1020psi, (full
returns). Pumped 1780stks. OWFF
(static).
Note: LCM returns noticed. Circulated
and cleaned up.
3,924.0 3,919.0
4/22/2024
23:00
4/22/2024
23:30
0.50 COMPZN, CSGRCY OTHR P Pull hanger to floor and L/D (good
condition). Blow down surface
equipment.
3,919.0 3,887.0
4/22/2024
23:30
4/23/2024
00:00
0.50 COMPZN, CSGRCY PULL P POOH and L/D 3-1/2" EUE 9.3ppf L-80
tubing from 3887' MD to 3600' MD.
3,887.0 3,600.0
4/23/2024
00:00
4/23/2024
04:30
4.50 COMPZN, CSGRCY PULL P POOH and L/D 3-1/2" EUE 9.3ppf L-80
tubing from 3600' MD to 0' MD.
Recovered ~ 3927' MD (with 25 RKB)
1) 1-2.75" niple
2) GLM
3) 2- pup joints
4) Cut joint
5) Hanger w/pup joint
3,600.0 0.0
Rig: DOYON 25
RIG RELEASE DATE 5/4/2024
Page 3/11
2P-415
Report Printed: 5/30/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/23/2024
04:30
4/23/2024
06:00
1.50 COMPZN, PLUG ELNE P R/U AKE 9/32" E-line tools and
equipment. (Pump out stack measure
RKB to lock downs 8'). Install Dutch
riser.
0.0 0.0
4/23/2024
06:00
4/23/2024
09:00
3.00 COMPZN, PLUG ELNE P RIH with PESI 4.25” ALPHA CIBP at
100'/min to 2090' MD. Top of fish 2077'
MD. String weight at surface 300lbs.
(Solid set down. No reduction of weight
to this point). Attempt to work up without
sucess. Discuss path forward with town.
Decsion made to work to max tension..
Work tool string to 3500lbs line tension
and observe string jump. POOH with E-
line. Pulled out of ropesocket. R/D E-line
and Dutch riser.
0.0 0.0
4/23/2024
09:00
4/23/2024
13:30
4.50 COMPZN, PLUG WAIT T Waiting on Halliburton slickline
equipment. Monitor well while servicing
rig, Test mud pump #1 discharge valves
to 3500psi (good test).
0.0 0.0
4/23/2024
13:30
4/23/2024
19:00
5.50 COMPZN, PLUG DSL T R/U Halliburton 1.60" slick line
equipment. RIH and latch onto fish at
2077'. On 3rd attempt latch on to fish.
No extra drag noted reaching fish.
1st run Attempt jarring on fish without
success. On second hit1800#'s with
hydraulic jar lost fish. At surface inspect
tool string. Observed some fishneck
sheared off.
2nd run Attempt jarring on fish without
success. On 9ths hit 1500#'s with
hydraulic jar lost fish. At surface inspect
tool string.
POOH and R/D slick line.
Note: Small particles of solids noticed
inside bell guide.
4-1/2" OD Bell guide
1-3/8" pulling tool
11.0' weight bar
Oil Jar
Spang Jar
total length 31'
0.0 0.0
4/23/2024
19:00
4/23/2024
20:00
1.00 COMPZN, PLUG PRTS T Close BSR. Change UPR from 3-1/2" X
5-7/8 VBRs to 2-7/8" X 5" VBRs.
0.0 0.0
4/23/2024
20:00
4/23/2024
21:30
1.50 COMPZN, PLUG WAIT T Waiting on tools and equipment - 2-7/8"
test joints and Baker Fishing tools. All en
route.
0.0 0.0
4/23/2024
21:30
4/24/2024
00:00
2.50 COMPZN, PLUG PRTS T M/U test plug. Run and attempt to test.
Test plug leaking by (wrong test plug
profile). M/U tubing hanger and blanking
plug. Run in and RILD.
0.0 0.0
4/24/2024
00:00
4/24/2024
02:00
2.00 COMPZN, PLUG PRTS T Fill system and test annular and 2-7/8" x
5" UPRs to 250 psi low and 2500 psi
high f/ 5/10 minutes each. BO LDS. LD
test jt/XO/blanking plug and hanger. RU
casing tongs.
SimOps: Strap 2-7/8" HTPAC tbg.
0.0 0.0
Rig: DOYON 25
RIG RELEASE DATE 5/4/2024
Page 4/11
2P-415
Report Printed: 5/30/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/24/2024
02:00
4/24/2024
03:00
1.00 COMPZN, PLUG BHAH T MU BHA #1 as follows:
4-11/16" OD overshot
3-1/8" ID basket graple
2-1/4" ID steel stop
X/O
Bumper Jar
Oil Jar
X/O
X/O to 2-7/8" HTPAC work string.
0.0 31.0
4/24/2024
03:00
4/24/2024
06:00
3.00 COMPZN, PLUG PULD T RIH PU singles of 2-7/8" HTPAC tbg to
2080'. Take PU and SO at 1950'.
PU: 58k
SO: 66k
31.0 2,080.0
4/24/2024
06:00
4/24/2024
06:30
0.50 COMPZN, PLUG FISH T Set down @ 2083'. Set 15k down. PU
staging up to 99k. Observe hookload
drop confirming Eline running tool free.
2,080.0 2,083.0
4/24/2024
06:30
4/24/2024
09:00
2.50 COMPZN, PLUG PULD T POOH f/ 2083' LD 2-7/8" tbg. 2,083.0 0.0
4/24/2024
09:00
4/24/2024
10:00
1.00 COMPZN, PLUG BHAH T Release Eline running tool and LD BHA
#1.
0.0 0.0
4/24/2024
10:00
4/24/2024
11:00
1.00 COMPZN, PLUG BHAH T Clean and clear rig floor. MU BHA #2 as
follows:
XO
Jars
Bumper jar
Back pressure valve
Circ Sub
Motor
Mill
0.0 38.0
4/24/2024
11:00
4/24/2024
15:00
4.00 COMPZN, PLUG PULD T Single in hole w/ BHA #2 to 2090'.
PU: 61k
SO: 68k
38.0 2,090.0
4/24/2024
15:00
4/24/2024
16:00
1.00 COMPZN, PLUG MILL T Mill CIBP f/ 2090' to 2092'. Observe diff
pressure fall off.
160 GPM
1500 PSI
5-6k WOB
2,090.0 2,092.0
4/24/2024
16:00
4/25/2024
00:00
8.00 COMPZN, PLUG WASH T Wash down pushing CIBP f/ 2092' to
2271'.
RIH pushing CIBP f/ 2271' to 2762'.
Observe 4k weight down.
Wash down pushing CIBP f/ 2762' to
2863'.
RIH pushing CIBP f/ 2863' to 3315'.
Taking weight.
Wash down pushing CIBP f/ 3315' to
3560.
160 GPM
1500-1700 PSI
2-4k WOB
2,092.0 3,560.0
4/25/2024
00:00
4/25/2024
01:00
1.00 COMPZN, PLUG PULD T RIH singling in w/ 2-7/8" tbg f/ 3560' to
3850'.
3,560.0 3,850.0
4/25/2024
01:00
4/25/2024
05:00
4.00 COMPZN, PLUG PULD T POOH LD singles f/ 3850' to surface. 3,850.0 0.0
4/25/2024
05:00
4/25/2024
05:30
0.50 COMPZN, PLUG BHAH T LD mill assembly. 0.0 0.0
4/25/2024
05:30
4/25/2024
06:00
0.50 COMPZN, PLUG BHAH T MU and RIH w/ 5-1/2" scraper assembly
to 340'.
0.0 340.0
4/25/2024
06:00
4/25/2024
10:00
4.00 COMPZN, PLUG PULD T Single in w/ 5-1/2" scraper assembly f/
340' to 3850'.
340.0 3,850.0
Rig: DOYON 25
RIG RELEASE DATE 5/4/2024
Page 5/11
2P-415
Report Printed: 5/30/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/25/2024
10:00
4/25/2024
14:30
4.50 COMPZN, PLUG PULD T POOH w/ 5-1/2" scraper assembly f/
3850' to surface.
3,850.0 0.0
4/25/2024
14:30
4/25/2024
15:30
1.00 COMPZN, PLUG BHAH T LD scraper assembly. 0.0 0.0
4/25/2024
15:30
4/25/2024
16:30
1.00 COMPZN, PLUG CLEN T Flow check and clean and clear rig floor. 0.0 0.0
4/25/2024
16:30
4/25/2024
18:00
1.50 COMPZN, PLUG RURD T PJSM. RU Eline. and MU 5-1/2" CIBP
on Eline.
0.0 0.0
4/25/2024
18:00
4/25/2024
21:00
3.00 COMPZN, PLUG ELNE T RIH w/ 5 1/2" CIBP on Eline to 3840'.
Correlate and confirm depth and collar
location.
Collar at 3828' ELM. Set CIBP at 3810'
ELM D25 RKB (85' below surace csg
shoe)
Tension before setting 510 lbs/After 285
lbs.
PU and confirm free. Set down and tag
CIBP on depth.
0.0 0.0
4/25/2024
21:00
4/25/2024
21:30
0.50 COMPZN, PLUG ELNE P POOH w/ Eline. 0.0 0.0
4/25/2024
21:30
4/25/2024
22:00
0.50 COMPZN, PLUG PRTS P RU and test CIBP to 1000 PSI f/ 10
minutes. Good test. .5 bbls pumped/.5
bbls returned.
0.0 0.0
4/25/2024
22:00
4/26/2024
00:00
2.00 COMPZN, PLUG ELNE P RIH w/ mechanical cutter on Eline.
Correlate and get on depth. Make cut at
3780' D25 RKB (55' below surface
shoe). Observed 200 PSI increase on
OA.
0.0 0.0
4/26/2024
00:00
4/26/2024
02:00
2.00 COMPZN, PLUG CIRC P PJSM. Pump 60 BBLs Deep Clean pill
and chase w/ 9.8 Vis Brine. Circulate
until good Vis Brine to surface. 250
BBLs pumped. SD. Flow check. Good.
ICP @ 4 BPM - 390 PSI.
FCP @ 3 BPM - 210 PSI. OA - 90 PSI.
0.0 0.0
4/26/2024
02:00
4/26/2024
04:00
2.00 COMPZN, PLUG ELNE P Eline disengaged cutter and POOH. LD
tools and RD Eline.
0.0 0.0
4/26/2024
04:00
4/26/2024
05:00
1.00 COMPZN, PLUG WWSP P MU packoff retrival tool. Retrieve
packoff.
0.0 0.0
4/26/2024
05:00
4/26/2024
05:30
0.50 COMPZN, PLUG THGR P MU 5-1/2" landing joint and pup joint for
spaceout. MU to hanger and PU hanger
6ft. Breakover at 130k, PU 102k. Set
slips and LD 5 1/2" pup joint.
0.0 0.0
4/26/2024
05:30
4/26/2024
06:00
0.50 COMPZN, PLUG RURD P MU cement line to landing joint. 0.0 0.0
4/26/2024
06:00
4/26/2024
10:30
4.50 COMPZN, PLUG CIRC P Circulate.
160 GPM
160 PSI
0.0 0.0
4/26/2024
10:30
4/26/2024
12:00
1.50 COMPZN, PLUG CMNT P PJSM. Swap over to cement unit. Test
lines to 3000 PSI. Load wiper ball. Mix
and pump 9 BBLs 11.0 ppg MudPush
spacer + 29 BBLS 16.5 ppg cement +
13 BBLs 11.0ppg MudPush spacer + 2
BBls FW. Swap over to rig and and
displace w/ 56 BBLs 9.8ppg Brine.
0.0 0.0
4/26/2024
12:00
4/26/2024
13:00
1.00 COMPZN, PLUG PULD P POOH LD tbg f/ 3780' to 3529' at 15-30
ft/min.
0.0 0.0
4/26/2024
13:00
4/26/2024
14:00
1.00 COMPZN, PLUG CIRC P Circulate BU and contaminated fluid out.
110 BBLs contaminated fluid.
Note: Cement in place at 14:00 hrs
4/26/24
0.0 0.0
Rig: DOYON 25
RIG RELEASE DATE 5/4/2024
Page 6/11
2P-415
Report Printed: 5/30/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/26/2024
14:00
4/26/2024
15:00
1.00 COMPZN, PLUG PULD P POOH LD tbg f/ 3529' to 3171'. 0.0 0.0
4/26/2024
15:00
4/27/2024
00:00
9.00 COMPZN, PLUG WOC P Close annular and apply 200 PSI to
wellbore. Wait on cement. Break over
string every hour and monitor pressure.
SimOps:
Inventories/MP2s/Housekeeping.
0.0 0.0
4/27/2024
00:00
4/27/2024
06:00
6.00 COMPZN, PLUG WOC P WOC. Break over every hour. Perform
housekeeping/MP2s.
3,164.0 3,164.0
4/27/2024
06:00
4/27/2024
06:30
0.50 COMPZN, PLUG WOC P Verify no pressure. Open up well and
work string f/ 3164' to 3131'.
85k PU
82k SO
3,164.0 3,131.0
4/27/2024
06:30
4/27/2024
11:00
4.50 COMPZN, PLUG WOC P WOC. Monitor well w/ constant hole fill. 3,131.0 3,171.0
4/27/2024
11:00
4/27/2024
12:00
1.00 COMPZN, PLUG PULD P Single in hole w/ 4" DP f/ 3171' to 3520'. 3,171.0 3,520.0
4/27/2024
12:00
4/27/2024
12:30
0.50 COMPZN, PLUG WASH P Wash down f/ 3520' to 3613'. Did not tag
any hard cement.
1BPM
67 PSI
78k SO
3,520.0 3,613.0
4/27/2024
12:30
4/27/2024
14:00
1.50 COMPZN, PLUG CIRC P Circulate surface to surface. Observed
contaminated cement at BU.
5 BPM
165 PSI
3,613.0 3,613.0
4/27/2024
14:00
4/27/2024
15:00
1.00 COMPZN, PLUG WASH P Wash down f/ 3613' to 3631'. Tag with
10k down x 3 staging pumps up to 4
BPM with no increase in PSI. Circulate
BU.
4 BPM
145 PSI
3,613.0 3,631.0
4/27/2024
15:00
4/27/2024
15:30
0.50 COMPZN, PLUG PRTS T RU and test cement plug to 812 PSI.
Observed pressure drop to 490 PSI in
10 minutes. .5 BBLs pumped / .25 BBLS
returned.
3,631.0 3,631.0
4/27/2024
15:30
4/27/2024
16:30
1.00 COMPZN, PLUG TRIP T Flow check.POOH and rack back 4" DP
to 3171'.
3,631.0 3,171.0
4/27/2024
16:30
4/27/2024
18:00
1.50 COMPZN, PLUG RURD T RU to LD 5 1/2" csg. 3,171.0 3,171.0
4/27/2024
18:00
4/27/2024
21:30
3.50 COMPZN, PLUG PULD T POOH LD 5 1/2" to surface. 87 joints
total + cut joint (3739.81'). 24
centralizers removed.
3,171.0 0.0
4/27/2024
21:30
4/27/2024
22:00
0.50 COMPZN, PLUG CIRC T MU jetting tool and jet stack. 0.0 0.0
4/27/2024
22:00
4/27/2024
22:30
0.50 COMPZN, PLUG BHAH T MU cleanout BHA.
6 3/4' mill tooth bit
Bit sub
XO
0.0 0.0
4/27/2024
22:30
4/28/2024
00:00
1.50 COMPZN, PLUG PULD T Single in hole w/ cleanout BHA to 1380'. 0.0 1,380.0
4/28/2024
00:00
4/28/2024
03:00
3.00 COMPZN, PLUG PULD T Single in hole w/ 6 3/4" cleanout BHA f/
1380' to 3505'.
1,380.0 3,505.0
4/28/2024
03:00
4/28/2024
03:30
0.50 COMPZN, PLUG WASH T Wash down f/ 3505' to 3629'. Tag
cement at 3629'.
3,505.0 3,629.0
Rig: DOYON 25
RIG RELEASE DATE 5/4/2024
Page 7/11
2P-415
Report Printed: 5/30/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/28/2024
03:30
4/28/2024
04:30
1.00 COMPZN, PLUG DRLG T Drill cement f/ 3629' to 3735'. Good
cement cuttings across shakers.
400 GPM
790 PSI
80 RPM
2-3k TQ
6-9k WOB
3,629.0 3,735.0
4/28/2024
04:30
4/28/2024
05:00
0.50 COMPZN, PLUG CIRC T Circulate BU while pulling back into
shoe to 3625'.
400 GPM
770 PSI
3,735.0 3,625.0
4/28/2024
05:00
4/28/2024
06:00
1.00 COMPZN, PLUG LOT T RU and perform LOT/Injectivity test.
Broke over at 671 PSI. Injected 6 BBLs
at 1 BPM at 480 PSI. Bled back 4 BBLS
from initial injection.
3,625.0 3,625.0
4/28/2024
06:00
4/28/2024
07:00
1.00 COMPZN, PLUG CIRC T CBU.
3-4 BPM
120-140 PSI
3,629.0 3,735.0
4/28/2024
07:00
4/28/2024
10:30
3.50 COMPZN, PLUG TRIP T POOH racking back 4 " DP. Flow check
at surface. Static.
3,625.0 0.0
4/28/2024
10:30
4/28/2024
16:00
5.50 COMPZN, PLUG PULD T RU and single in 5-1/2" casing to 3731'.
Tagged up.
0.0 3,731.0
4/28/2024
16:00
4/28/2024
16:30
0.50 COMPZN, PLUG CIRC T RU to pump cement. Break circulation
and stage up rates to 6BPM/252 PSI.
3,731.0 3,731.0
4/28/2024
16:30
4/28/2024
17:30
1.00 COMPZN, PLUG CMNT T PJSM. Test lines to 3000 PSI. Pump 9
BBLS 11.0 ppg MudPush spacer + 29
BBLS 16.5 ppg cement + 13 BBLS 11.0
ppg MudPush spacer + 2 BBLs FW to
clear lines. Displace with 45 BBLs 9.8
ppg Brine.
3,731.0 3,731.0
4/28/2024
17:30
4/28/2024
18:00
0.50 COMPZN, PLUG PULD T POOH LD 5 1/2" casing at 15 ft/min to
3446'.
3,731.0 3,446.0
4/28/2024
18:00
4/28/2024
19:00
1.00 COMPZN, PLUG CIRC T Circulate hole clean. 53 BBLS
contaminated fluid dumped.
5 BPM
180 PSI
Note: Cement in place at 18:45hrs
4/28/24.
3,446.0 3,446.0
4/28/2024
19:00
4/28/2024
19:30
0.50 COMPZN, PLUG PULD T POOH LD 5 1/2" casing to 3171'. 3,446.0 3,171.0
4/28/2024
19:30
4/28/2024
20:00
0.50 COMPZN, PLUG WOC T WOC. MU circulating swedge and TIW
valve. Close annular and apply 200 PSI
to wellbore.
3,171.0 3,171.0
4/28/2024
20:00
4/29/2024
00:00
4.00 COMPZN, PLUG WOC T WOC. Perform housekeeping and
MP2s.
3,171.0 3,171.0
4/29/2024
00:00
4/29/2024
07:00
7.00 COMPZN, PLUG WOC T WOC. Perform housekeeping and
MP2s.
3,171.0 3,171.0
4/29/2024
07:00
4/29/2024
07:30
0.50 COMPZN, PLUG WOC T Confirm pressure bled off from wellbore.
Open annular and flow check. Static.
Monitor well with holefill.
3,171.0 3,171.0
4/29/2024
07:30
4/29/2024
13:00
5.50 COMPZN, PLUG WOC T WOC. Perform housekeeping and
MP2s.
3,171.0 3,171.0
4/29/2024
13:00
4/29/2024
14:00
1.00 COMPZN, PLUG TRIP T XO to 4" DP and RIH f/ 3171' to 3362' 3,171.0 3,362.0
4/29/2024
14:00
4/29/2024
14:30
0.50 COMPZN, PLUG WASH T Wash down f/ 3362' to 3458' 84 GPM/80
PSI. Tagged cement at 3455'. 140 PSI
increase. Circulate BU at 250 GPM/250
PSI
3,362.0 3,458.0
Rig: DOYON 25
RIG RELEASE DATE 5/4/2024
Page 8/11
2P-415
Report Printed: 5/30/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/29/2024
14:30
4/29/2024
16:00
1.50 COMPZN, PLUG PRTS T RU and attermpt to pressure test
cement plug. 750 PSI/1500PSI. Made 2
attempts. Unsuccessful. RD test
equipment.
3,458.0 3,458.0
4/29/2024
16:00
4/29/2024
17:00
1.00 COMPZN, PLUG TRIP T POOH racking 4" DP f/ 3454' to 3172'. 3,458.0 3,172.0
4/29/2024
17:00
4/29/2024
18:00
1.00 COMPZN, PLUG RURD T RU handling equipment f/ 5 1/2" casing.
Wait on casing personnel.
3,172.0 3,172.0
4/29/2024
18:00
4/29/2024
22:30
4.50 COMPZN, PLUG PULD T POOH LD 5 1/2" casing f/ 3172' to
surface.
3,172.0 0.0
4/29/2024
22:30
4/30/2024
00:00
1.50 COMPZN, PLUG TRIP T MU Cleanout assembly.
6 3/4" mill tooth bit
Bit sub
XO
RIH on 4" DP to 2653'.
0.0 2,653.0
4/30/2024
00:00
4/30/2024
00:30
0.50 COMPZN, PLUG TRIP T RIH w/ 6 3/4" cleanout assembly f/ 2653'
to 3408'.
2,653.0 3,408.0
4/30/2024
00:30
4/30/2024
01:00
0.50 COMPZN, PLUG WASH T Wash down f/ 3408' to 3455'. Tag
cement at 3453'.
250 GPM
320 PSI
3,408.0 3,455.0
4/30/2024
01:00
4/30/2024
03:00
2.00 COMPZN, PLUG DRLG T Drill cement f/ 3455' to 3740'.
400 GPM
860 PSI
60 RPM
2-3k TQ
3-9k WOB
3,455.0 3,740.0
4/30/2024
03:00
4/30/2024
03:30
0.50 COMPZN, PLUG CIRC T Circulate BU.
400 GPM
860 PSI
60 RPM
2-3k TQ
3,740.0 3,690.0
4/30/2024
03:30
4/30/2024
04:30
1.00 COMPZN, PLUG LOT T RU and perform LOT/Injectivity test.
Broke over at 735 PSI. Stage rate to 1
BPM and inject 10 BBLS. ICP 501
PSI/FCP 471 PSI. SD. Bled back 7.5
BBLS. RD test equipment.
3,690.0 3,690.0
4/30/2024
04:30
4/30/2024
07:00
2.50 COMPZN, PLUG TRIP T POOH racking back 4" DP. LD cleanout
assembly.
3,690.0 0.0
4/30/2024
07:00
4/30/2024
12:00
5.00 COMPZN, PLUG PULD T RU and RIH w/ 5 1/2" csg to 3734'. 0.0 3,734.0
4/30/2024
12:00
4/30/2024
13:00
1.00 COMPZN, PLUG CIRC T Displace 9.8ppg brine to 9.8ppg WBM. 3,734.0 3,734.0
4/30/2024
13:00
4/30/2024
17:00
4.00 COMPZN, PLUG CIRC T Circulate while waiting on water truck
(broke down).
3,734.0 3,734.0
4/30/2024
17:00
4/30/2024
19:00
2.00 COMPZN, PLUG CMNT T PJSM w/ cementers. Test lines to 3000
psi. Pump 9 BBLS 10.5ppg MudPush
spacer + 29 BBLs 15.9ppg cement + 13
BBLs 10.5ppg MudPush spacer. Pump
2BBL FW to clear line. Swap over to rig
pumps and displace with 47 BBLs
9.8ppg WBM.
3,734.0 3,734.0
4/30/2024
19:00
4/30/2024
19:30
0.50 COMPZN, PLUG PULD T POOH LD 5 1/2" csg at 15 ft/min f/ 3734'
to 3520'.
3,734.0 3,520.0
4/30/2024
19:30
4/30/2024
20:00
0.50 COMPZN, PLUG CIRC T MU cement line and break circulation.
Stage up to 6 BPM. Observed losses.
SD and check surface equipment. Stage
rate bck up still observed losses. SD.
47 BBLS lost.
3,520.0 3,520.0
Rig: DOYON 25
RIG RELEASE DATE 5/4/2024
Page 9/11
2P-415
Report Printed: 5/30/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
4/30/2024
20:00
4/30/2024
20:45
0.75 COMPZN, PLUG PULD T POOH LD 5 1/2" csg to 3170'. 3,520.0 3,170.0
4/30/2024
20:45
4/30/2024
21:00
0.25 COMPZN, PLUG CIRC T Stage up rate to 1 BPM. No returns and
still losing mud. SD pumps.
3,170.0 3,170.0
4/30/2024
21:00
5/1/2024
00:00
3.00 COMPZN, PLUG PULD T POOH LD 5 1/2" csg f/ 3170' to 1735'.
Discuss plan forward with office.
Decision made to POOH w/ 5 1/2" csg.
3,170.0 1,735.0
5/1/2024
00:00
5/1/2024
02:00
2.00 COMPZN, PLUG PULD T POOH LD 5 1/2" csg f/ 1735' to surface. 1,735.0 0.0
5/1/2024
02:00
5/1/2024
02:30
0.50 COMPZN, PLUG TRIP T Clean and clear rig floor. MU Cleanout
assembly. RIH to 940'.
0.0 940.0
5/1/2024
02:30
5/1/2024
03:30
1.00 COMPZN, PLUG CIRC T Circulate and condition mud. Mud was
very thick 300+ vis.
200-250 GPM
270-370 PSI
940.0 940.0
5/1/2024
03:30
5/1/2024
04:00
0.50 COMPZN, PLUG TRIP T RIH to 1500'. 940.0 1,500.0
5/1/2024
04:00
5/1/2024
04:30
0.50 COMPZN, PLUG CIRC T Circulate and condition mud. Observed
mudpush and cement over shakers.
150-180 GPM
200-430 PSI
1,500.0 1,500.0
5/1/2024
04:30
5/1/2024
04:45
0.25 COMPZN, PLUG TRIP T RIH to 1900'. 1,500.0 1,900.0
5/1/2024
04:45
5/1/2024
05:00
0.25 COMPZN, PLUG CIRC T Circulate and condition mud.
170-200 GPM
400-495 PSi
1,900.0 1,900.0
5/1/2024
05:00
5/1/2024
05:15
0.25 COMPZN, PLUG TRIP T RIH f/ 1900' to 2170'. Taking weight
cement stringer.
1,900.0 2,170.0
5/1/2024
05:15
5/1/2024
09:00
3.75 COMPZN, PLUG WASH T Wash down f/ 2170' to 3733' Tag and set
down 8k.
200 GPM
625 PSi
2,170.0 3,733.0
5/1/2024
09:00
5/1/2024
17:30
8.50 COMPZN, PLUG CIRC T PU to 3713'. Circulate and condition
mud.
3,733.0 3,713.0
5/1/2024
17:30
5/1/2024
19:00
1.50 COMPZN, PLUG DISP T Displace 9.8ppg WBM to 9.8 clear
Brine.
3,713.0 3,713.0
5/1/2024
19:00
5/1/2024
21:00
2.00 COMPZN, PLUG TRIP T Flow check. POOH w/ cleanout
assembly. LD cleanout assembly.
3,713.0 0.0
5/1/2024
21:00
5/1/2024
21:30
0.50 COMPZN, PLUG CIRC T MU jetting tool and jet stack. 0.0 0.0
5/1/2024
21:30
5/2/2024
00:00
2.50 COMPZN, PLUG TRIP T MU 2 7/8" inflatable packer assembly.
RIH to 3055'. 60-80ft/min.
0.0 3,055.0
5/2/2024
00:00
5/2/2024
01:00
1.00 COMPZN, PLUG TRIP T RIH f/ 3050' to 3605'. 3,050.0 3,605.0
5/2/2024
01:00
5/2/2024
01:30
0.50 COMPZN, PLUG TRIP T Set on depth with middle of element at
3600'. Pressure up in 300-500 PSI
increments holding for 5 minutes at
each increment to 2000 PSI (set to
shear at 1300 PSI). No shear. Bled off
pressure to 300 PSI.PU to use
secondary shear. Sheared with 9k
overpull.
3,605.0 3,605.0
5/2/2024
01:30
5/2/2024
02:30
1.00 COMPZN, PLUG PRTS T PU and space out. RU test equipment.
attempt to test packer. Made 2 attempts
with no success. Max pressure
observed 620 PSI.
3,605.0 3,521.0
5/2/2024
02:30
5/2/2024
04:30
2.00 COMPZN, PLUG TRIP T POOH to surface. Running tool visually
looked ok.
3,521.0 0.0
Rig: DOYON 25
RIG RELEASE DATE 5/4/2024
Page 10/11
2P-415
Report Printed: 5/30/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
5/2/2024
04:30
5/2/2024
05:30
1.00 COMPZN, PLUG SLPC T Slip/Cut drill line. 0.0 0.0
5/2/2024
05:30
5/2/2024
06:30
1.00 COMPZN, PLUG WAIT T Wait on test packer to arrive. 0.0 0.0
5/2/2024
06:30
5/2/2024
10:00
3.50 COMPZN, PLUG TRIP T MU test packer and RIH to 3515'. 0.0 3,515.0
5/2/2024
10:00
5/2/2024
11:00
1.00 COMPZN, PLUG PRTS T Set test packer. Attempt to test below
packer. Unsuccessful. Max pressure
630 PSI. Bled off pressure and line up to
test above packer. 1600 PSI for 30
minutes. Good test.
3,515.0 3,515.0
5/2/2024
11:00
5/2/2024
12:00
1.00 COMPZN, PLUG PRTS T RIH. Tag inflatable packer. Attempt to
test below packer. Unsuccessful.
3,515.0 3,594.0
5/2/2024
12:00
5/2/2024
14:30
2.50 COMPZN, PLUG TRIP T POOH to surface. LD test packer. 3,594.0 0.0
5/2/2024
14:30
5/2/2024
17:00
2.50 COMPZN, PLUG TRIP T MU overshot for inflatable packer. RIH
to 3722'. Set down 10k 3 times.
Observed increase in PU
0.0 3,722.0
5/2/2024
17:00
5/2/2024
20:30
3.50 COMPZN, PLUG TRIP T POOH to surface. Did not have fish.
Inspect overshot. Indication of fish going
into overshot but no indication of
grapple engaging fish. Discuss plan
forward with town. Decision made to
leave IBP in hole and run 2nd IBP(3
1/2") in hole and set.
3,722.0 0.0
5/2/2024
20:30
5/2/2024
23:00
2.50 COMPZN, PLUG TRIP T MU 3 1/2" IBP. RIH. 60-80 FPM f/
surface to 3505'.
0.0 3,505.0
5/2/2024
23:00
5/3/2024
00:00
1.00 COMPZN, PLUG PACK T Pressure up in 500 PSI increments.
Hold for 5 minutes at each stage.
Sheared and set packer with 2740 PSI.
Middle of element at 3500'.
3,505.0 3,505.0
5/3/2024
00:00
5/3/2024
01:00
1.00 COMPZN, PLUG PRTS T LD single to 3498'. RU test equipment.
Test IBP to 1000 PSI f/ 30 minutes.
Good test. Charted.RD test equipment
3,505.0 3,498.0
5/3/2024
01:00
5/3/2024
04:30
3.50 COMPZN, PLUG PULD T POOH LD 4" DP. (culled 22 bad joints).
LD running tool. Visually ok.
3,498.0 0.0
5/3/2024
04:30
5/3/2024
05:00
0.50 COMPZN, PLUG PULD T RIH 3 stds 4" DP f/ derick and POOH
LD.
0.0 0.0
5/3/2024
05:00
5/3/2024
05:30
0.50 COMPZN, PLUG RURD T RU to run 5 1/2" casing. 0.0 0.0
5/3/2024
05:30
5/3/2024
09:00
3.50 COMPZN, PLUG PULD T RIH w/ 5 1/2" casing to 1960'. 46 joints
ran
0.0 1,960.0
5/3/2024
09:00
5/3/2024
11:30
2.50 COMPZN, PLUG HOSO T MU hanger and landing joint. land
hanger. end of 5 1/2" casing at 2005'.
Run and install packoff. RILDS. Test
packoff to 5000 PSI. Good test. MU and
land 3.5" tbg hanger and RILDS.
0.0 0.0
5/3/2024
11:30
5/3/2024
12:30
1.00 COMPZN, WHDBOP CLEN P Clean and clear rig floor,Joe's Box,BD
top drive/mud lines/choke and kill lines.
0.0 0.0
5/3/2024
12:30
5/3/2024
16:45
4.25 COMPZN, WHDBOP RURD P RD Joe's Box,flow lines, hole fill lines
and ND BOPE.
0.0 0.0
5/3/2024
16:45
5/3/2024
18:00
1.25 COMPZN, WHDBOP WWSP P Clean wellhead. NU tree. Test hanger
seals to 5000 PSI f/ 10 minutes.
0.0 0.0
5/3/2024
18:00
5/3/2024
21:30
3.50 DEMOB, MOVE FRZP P RU to freeze protect well. Test lines.
Pump 45 BBLS diesel down OA and
take returns out tbg. SD and let well
Utube.
SimOps: Prep to scope down derrick.
0.0 0.0
5/3/2024
21:30
5/3/2024
23:00
1.50 DEMOB, MOVE RURD P BD lines in cellar. Secure well. Scope
derrick down. Remove scoping lines.
sheave pins. Pin top drive.
0.0 0.0
Rig: DOYON 25
RIG RELEASE DATE 5/4/2024
Page 11/11
2P-415
Report Printed: 5/30/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
5/3/2024
23:00
5/4/2024
00:00
1.00 DEMOB, MOVE RURD P Swap power to move generators.
Secure top drive. Lower cattle
chute.Store cellar equipment.
Disconnect electrical in csg
shed/derrick/pump and motor complex.
0.0 0.0
Rig: DOYON 25
RIG RELEASE DATE 5/4/2024
DTTMSTART JOBTYP SUMMARYOPS
3/24/2024 CHANGE
WELL TYPE
SHOOT TUBING PUNCH FROM 8105'-8108' RKB, CCL-TS=4', CCL STOP DEPTH=8101.0',
LOG CORRELATED TO TBG TALLY DATED 5-DEC-2001, PRE-SHOT T/IA=2000/0, POST-
SHOT T/IA=700/580, LRS PRESSURED UP TBG TO 2500 PSI, IA PRESSURE INCREASE
TO 2500, WELL LEFT S/I, FUSIBLE REMOVED. JOB IS READY FOR CIRC TEST &
CEMENTING
3/25/2024 CHANGE
WELL TYPE
RIG UP LRS PUMP UNIT TO TBG, PUMP 15 BBLS DOWN TBG @ 2 BPM, 1000 PSI PUMP
PRESSURE THROUGH PERFERATIONS AND UP IA TO TANK, U TUBE. JOB COMPLETE,
RIG DOWN
3/25/2024 CHANGE
WELL TYPE
(SECURE) CDDT T X IA TO 0 PSI (PASS) BLEED OA FOR BUR (IN PROGRESS)
3/26/2024 CHANGE
WELL TYPE
(SECURE) BLEED OA FOR BUR (COMPLETE)
3/30/2024 CHANGE
WELL TYPE
PUMPED INTERMEDIATE BALANCED CEMENT PLUG. PUMPED 31 BBLS OF 15.8 PPG
CEMENT AND DISPLACED IT WITH 57 BBLS OF 9.8 PPG BRINE PLACING THE TOC AT
~6600' RKB IN THE TUBING AND IA. READY FOR FREEZE PROTECT.
4/1/2024 CHANGE
WELL TYPE
SHEARED SOV. CIRCULATED 60 BBLS OF DIESEL FREEZE PROTECT.
4/2/2024 CHANGE
WELL TYPE
****AOGCC WITNESSED**** TAG TOP OF CEMENT @ 6333' RKB. PERFORMED PASSING
CMIT TO 1500 PSI. READY FOR E-LINE.
4/3/2024 CHANGE
WELL TYPE
CUT 3.5" TUBING WITH WELLTEC MECHANICAL CUTTER AT 3912' RKB. TATTLETALE
SHOWED BLADE EXTENSION TO 4.45" AND CCL SHIFT SEEN ON LOG AFTER CUTTING
(TBG WAS IN TENSION).
JOB COMPLETE, READY FOR RIG
4/20/2024 RECOMPLETI
ON
Stomp modules in position for trucks. Move modules. Unpin pipe module. Stomp out pipe
module and turn 90° into truck position. Instll Jeep onto Sub. Move off 2P-420 well center at
20:00hrs. Move Sub to 2P-415 well.
4/21/2024 RECOMPLETI
ON
Move Sub into position. Stomp Sub over 2P-415 well center. Move pipe module into position.
Stomp pipe module and pin to Sub. Continue moving modules into position and stomp in place.
Install interconnections. Raise derrick and skid rig floor. Scope derrick. Accept Rig on 2P-415
at 17:00hrs 4-21-24. Continue with interconnections, R/U service lines to well. Attempt to
pressure test. Trouble shoot pumps (LCM in pumps). Flush LCM from system.
4/21/2024 SUPPORT
OTHER
OPERATIONS
PREP E-LINE UNIT & TOOLS FOR RIG SUPPORT, STAGE EQUIPMENT AT 2P PAD,
STANDBY FOR CALL OUT
4/22/2024 RECOMPLETI
ON
Continue flush lines and test pud pumps. Test lines. Circulate out freeze protect. OWFF. N/D
tree. N/U BOP and test. Pull and L/D 3-1/2" tubing.
4/22/2024 SUPPORT
OTHER
OPERATIONS
CONTINUE ON STANDBY FOR DOYON 25, RECIEVE 4 HOUR CALL OUT AT 22:00
4/23/2024 RECOMPLETI
ON
L/D tubing. R/U Eline. RIH with 4.25" CIBP. Hard set down at 2090' ELM. Attempt to work free.
Pull out rope socket. R/D E-Line and wait on slick line equipment. R/U slick line and made two
attempts to jar free without success. R/D slick line. Change UPR to 2-7/8" X 5" VBRs and test
UPR and Annular with 2-7/8" test joint to 250/2500psi.
4/23/2024 SUPPORT
OTHER
OPERATIONS
RIH WITH PESI CIBP FOR 5.5" CASING. SET DOWN EARLY AT ~2090', UNABLE TO MOVE
UP OR DOWN, CANNOT WORK FREE, DECISION MADE TO PULL OUT OF ROPE
SOCKET, EL TOOLSTRING LIH: HEAD, CCL, BAKER 20 SETTING TOOL, CIBP (OAL 12.6',
MAX OD 4.24")
4/23/2024 CHANGE
WELL TYPE
JARRED ON E-LINE FISH FOR 30 MIN'S @ 2081' RKB BREAKING PULLING TOOLS AND
DAMAGING 1" FN ON FISH, JOB SUSPENDED SO RIG CAN FISH WITH BIGGER TOOLS.
4/24/2024 RECOMPLETI
ON
Test UPR and Annular with 2-7/8" test joint to 250/2500psi. R/D test equipment. M/U Baker
fishing assy. Single in hole with 2-7/8" work string. Latch ELine running tool and POOH. MU
milling assembly. RIH and mill CIBP. Wash CIBP to 3560'.
4/25/2024 RECOMPLETI
ON
POOH and LD mill assembly. RIH w/ 5-1/2" casing scraper and POOH. RU Eline. RIH w/ 5-
1/2" CIBP and set at 3810'. POOH. MU cutter and RIH on Eline.
2P-415A Suspend
Summary of Operations
4/25/2024 SUPPORT
OTHER
OPERATIONS
RUN 1: SET 5.5" CIBP AT 3810.0'.
4/26/2024 SUPPORT
OTHER
OPERATIONS
RUN 2: CUT CASING W/ WELLTEC 5.5" MECHANICAL CUTTER AT 3780'. RIG CIRCULATE
FLUIDS DOWN CASING TAKING RETURNS OFF OF OA.
JOB COMPLETE
4/26/2024 RECOMPLETI
ON
Circulate pill surface to surface. POOH w/ Eline. RD Eline. Retrieve packoff and confirm tbg
free. Pump 1st cement plug. POOH above cement and circulate. WOC.
4/27/2024 RECOMPLETI
ON
WOC. RIH and tag cement. Attempt to test. Unsuccessful. POOH LD 5 1/2" csg. MU clean out
assembly and RIH.
4/28/2024 RECOMPLETI
ON
RIH w/ 6 3/4" cleanout assembly. Perform LOT and injectivity test. POOH. RIH w/ 5 1/2"
casing. Pump cement plug. WOC.
4/29/2024 RECOMPLETI
ON
WOC. RIH and tag plug. Attempt to test. Unsuccessful. POOH laying down 5 1/2" casing.
4/30/2024 RECOMPLETI
ON
RIH. Drill out cement. Perform injection test.
POOH. RIH w/ 5 1/2" casing. Pump cement plug. Pull above plug. Attempt to circulate.
Observed losses. POOH LD Csg.
5/1/2024 RECOMPLETI
ON
LD 5 1/2" csg. RIH w/ cleanout assembly. Circulate and condition mud. Displace to 9.8ppg Vis
Brine. POOH w/ cleanout assembly. MU inflatable packer and RIH.
5/2/2024 RECOMPLETI
ON
RIH and set IBP. PU and test. Unsuccessful. POOH. Slip/Cut drill line. RIH w/ test packer. Test
IBP. Leaking. Test casing to 1500 PSI f/ 30 minutes. Good test. POOH. RIH w/ overshot to
retrieve IBP. Set down and engage fish. POOH. Unsuccessful. Decision made to set 2nd IBP.
RIH and set IBP.
5/3/2024 RECOMPLETI
ON
Test IBP. POOH LD 4" DP. Run 5 1/2" csg to 2000'. Land hanger and packoff. Test pack off.
ND BOPE. NU tree. Test seals. Freeze protect well w/ 45 BBLS diesel. Scope down derrick.
Release rig at 00:00 hrs 5/4/24
Page 1/1
2P-415
Report Printed: 5/30/2024
Cement Detail Report
Cement Details
Description
Intermediate String 1 Cement
Cementing Start Date
3/30/2024 12:00
Cementing End Date
3/30/2024 15:45
Wellbore Name
2P-415A
Comment
Cement Stages
Stage # 1
Description
Intermediate String 1
Cement
Objective Top Depth (ftKB)
6,600.0
Bottom Depth (ftKB)
8,100.0
Full Return?
No
Vol Cement …Top Plug?
No
Btm Plug?
No
Q Pump Init (bbl/m… Q Pump Final (bbl/… Q Pump Avg (bbl/…P Pump Final (psi) P Plug Bump (psi) Recip?
No
Stroke (ft) Rotated?
No
Pipe RPM (rpm)
Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in)
Comment
PUMPED 31 BBLS OF 15.8 CLASS G CEMENT FOR INTERMEDIATE BALANCED PLUG
Cement Fluids & Additives
Fluid
Fluid Type Fluid Description Estimated Top (ftKB) Est Btm (ftKB) Amount (sacks) Class Volume Pumped (bbl)
Yield (ft³/sack)Mix H20 Ratio (gal/sa…Free Water (%) Density (lb/gal) Plastic Viscosity (cP) Thickening Time (hr) CmprStr 1 (psi)
Additives
Additive Type Concentration Conc Unit label
String: Intermediate String 1 Cement
Job:
Page 1/1
2P-415
Report Printed: 5/30/2024
Cement Detail Report
Cement Details
Description
Cement Plug
Cementing Start Date
4/28/2024 12:00
Cementing End Date
4/28/2024 15:00
Wellbore Name
2P-415A
Comment
PJSM. Test lines to 3000 PSI. Pump 9 BBLS 11.0 ppg MudPush spacer + 29 BBLS 16.5 ppg cement + 13 BBLS 11.0 ppg MudPush spacer + 2 BBLs FW to clear
lines. Displace with 45 BBLs 9.8 ppg Brine.
Cement Stages
Stage # 1
Description
Cement Plug
Objective Top Depth (ftKB)
3,720.0
Bottom Depth (ftKB)
3,810.0
Full Return?
No
Vol Cement …Top Plug?
No
Btm Plug?
No
Q Pump Init (bbl/m… Q Pump Final (bbl/… Q Pump Avg (bbl/…P Pump Final (psi) P Plug Bump (psi) Recip?
No
Stroke (ft) Rotated?
No
Pipe RPM (rpm)
Tagged Depth (ftKB) Tag Method Depth Plug Drilled Out To (ftKB) Drill Out Diameter (in)
Comment
PJSM. Test lines to 3000 PSI. Pump 9 BBLS 11.0 ppg MudPush spacer + 29 BBLS 16.5 ppg cement + 13 BBLS 11.0 ppg MudPush spacer + 2 BBLs FW to clear
lines. Displace with 45 BBLs 9.8 ppg Brine.
Cement Fluids & Additives
Fluid
Fluid Type Fluid Description Estimated Top (ftKB) Est Btm (ftKB) Amount (sacks) Class Volume Pumped (bbl)
Yield (ft³/sack)Mix H20 Ratio (gal/sa…Free Water (%) Density (lb/gal) Plastic Viscosity (cP) Thickening Time (hr) CmprStr 1 (psi)
Additives
Additive Type Concentration Conc Unit label
String: Cement Plug
Job:
Repair WellFracture StimulatePlug Perforations Operations shutdownAbandon1. Type of Request:
Pull TubingOther StimulatePerforate Change Approved ProgramSuspend
Alter CasingPerforate New Pool Re-enter Susp Well Other: ___________________Plug for Redrill
5. Permit to Drill Number:4. Current Well Class:2. Operator Name:
DevelopmentExploratory
3. Address:ServiceStratigraphic 6. API Number:
8. Well Name and Number:7. If perforating:
What Regulation or Conservation Order governs well spacing in this pool?
NoYes
10. Field:9. Property Designation (Lease Number):
11.
Junk (MD):Total Depth TVD (ft):Total Depth MD (ft):
None9038'
CollapseCasing
Structural
Conductor
Surface
Intermediate
Production
Liner
Packers and SSSV MD (ft) and TVD (ft):Packers and SSSV Type:
Wellbore schematic 13. Well Class after proposed work:Proposal Summary12. Attachments:
Development ServiceBOP Sketch Exploratory StratigraphicDetailed Operations Program
15. Well Status after proposed work:14. Estimated Date for
WDSPLWINJOILCommencing Operations:Suspended
SPLUGGAS WAG GSTOR16. Verbal Approval:
AOGCC Representative: GINJ AbandonedOp Shutdown
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? NoYes
APPROVED BY
Date:COMMISSIONER THE AOGCCApproved by:
Sr Pet Geo Sr Res EngSr Pet EngComm.Comm.
Senior RWO/CTD Engineer
KRU 2P-415A
852 psi6050'
N/A
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):
Authorized Name and
Digital Signature with Date:
Tubing Size:
AOGCC USE ONLY
Tubing MD (ft):Tubing Grade:
8191' MD and 5271' TVD
N/A
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0373112
201-226
P.O. Box 100360, Anchorage, AK 99510 50-103-20383-01-00
Kuparuk River Field Meltwater Oil Pool
ConocoPhillips Alaska, Inc.
SizeLength
Proposed Pools:
PRESENT WELL CONDITION SUMMARY
Meltwater Oil Pool -
Abandoned
BurstTVD
8208'
MD
110'
2449'
110'
3713'
6039'9026'
16"
7-5/8"
82'
3685'
8640-8650'
9000'
5682-5691'
5-1/2" x 3-1/2"
Perforation Depth TVD (ft):
3-1/2"
Packer: Baker G-2 Seal Assy
SSSV: None
Perforation Depth MD (ft):
L-80
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Plugs (MD):
8625', 8518', 6600'
Effective Depth MD:
6600'
Effective Depth TVD:
3850'
Apr-27-2024
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Contact Name: Shane Germann
4/27/2024
Date:
Contact Email:shane.germann@conocophillips.com
Contact Phone:(406) 670-1939
By Grace Christianson at 8:48 am, Apr 29, 2024
Digitally signed by Shane Germann
DN: O=ConocoPhillips, CN=Shane Germann
, E=shane.germann@conocophillips.com
Reason: I am the author of this document
Location:
Date: 2024.04.27 17:15:53-08'00'
Foxit PDF Editor Version: 13.0.0
DSR-4/29/24
10-407
BOP test to 2500 psig; Annular preventer test to 2500 psig.
A variance to 20 AAC 25.112(a)(1)(A) is granted. Cement is not required from 100' below the base of the C-80 to 100' above the top
of the C-80. The variance is granted to allow an equally effective plug which includes the placement of a cement
plug from ~50' MD below the surface casing shoe in the open hole to 150' MD into the surface casing. (20 AAC 25.112(i))
A variance to the cement logging required in Other Order 196 is granted. Cement logging is not required.
AOGCC inspection required after cutoff and before remedial cementing
VTL 4/29/2024
Victoria Loepp 4/27/2024
2nd try intm plug
SFD 4/29/2024
X
X
X
JLC 5/6/2024
2P-415 Plug and Abandonment
Background & Objective
2P-415A was a producer that has been shut in since April 2019. This well is ultimately slated to be
P&Ad as part of the 2P pad abandonment. This well is in the process of being suspended with a
CIBP and cement placed and is currently waiting for AOGCC witness of a tag and test (as of
3/5/2024). The remaining steps to P&A this well include three more cement plugs: an intermediate
plug across the tubing, a plug across the surface casing shoe after the tubing and production
casing has been pulled, and then a final plug to surface.
Well Data
Meltwater Formation:
Reservoir pressure 2/16/2017 = 1420 psi (.25 psi/ft)
MASP = 852 psi
Reservoir abandoned (CIBP & cement) 12/18/23
C-80 Formation:
OAP = 183 psi (9/17/23) (fluid packed with diesel)
MASP = 770 psi
Max deviation = 69 deg at 5168 KB
Intermediate Plug Wireline & Pumping
Date: 2-6-24
Prepared by: Katherine OConnor
Estimated Start Date: 2-26-24
Procedure
1. Punch tubing at ±8,100 RKB
2. Pump the following schedule taking returns up the IA:
a. ±50 bbls surfactant wash
b. ±190 bbls 9.8 brine
c. ±31 bbls cement
d. ±57 bbls 9.8 brine displacement
3. This should leave TOC in tubing and IA hydrostatically balanced with cement top at 6600
MD
4. RIH and tag TOC and perform pressure test to 1500 psi (AOGCC Witnessed)
5. Cut tubing at ±3,900 RKB
Top Bottom Size ID bbls/ft ft volume ft/bbl notes
3-1/2" tubing 0 8100 3.5" 9.3# 2.99" 0.0087 8100 70.3 115.1 from punch depth
3-1/2" x 5-1/2" Annulus 0 8100 3.5" 9.3# x 5.5" 15.5# 4.95" x 3.5" 0.0119 8100 96.4 84.0 from punch depth
Tubing Cement 6600 8100 3.5" 9.3# 2.99" 0.0087 1500 13.0 115.1
Annular Cement 6600 8100 3.5" 9.3# x 5.5" 15.5# 4.95" x 3.5" 0.0119 1500 17.9 84.0
2P-415A Well Suspension Schematic
Conductor:
16" Conductor 110' KB
Production Casing Cement:
62.5 bbls of 15.8# Class G Cement
Calculated TOC @ 5,782' KB
1
2
3
5
4
Production Casing:
5.5" x 3.5" @ 8,210' KB, 15.5# x 9.3#,
L-80 BTC Mod
Set @ 9,025.8 KB
T-3 Peforations:
@ 8,640' 8,650' KB (10')
Surface Casing:
7-5/8", 29.7#, L-80 BTC Mod
Set @ 3,713' KB
Production Tubing:
3 ½, 9.3# L-80 EUE-8rd
Set @ 8,208.4' KB
6
Item Depth - tops
(KB)
1 FMC Tubing Hanger 23.1'
2 Camco DS Nipple 505.4'
3
Baker CMU Non-Elastomer Sliding
Sleeve w/ Camco DS Profile -
Closed 11/14/2009
8,131.6'
4 Camco D Nipple 8,147.7'
5 Baker 80-40 G-22 Locator Sub 8,190.9'
6 Baker G22 Seal Assembly 8,191.5'
Plug #1 Reservoir
TOC 8594' RKB
C80 @ 3775' KB C80 @ 3775' KB
Plug #2 Intermediate
TOC ±6600' RKB
BOC @ ±8100' RKB
Surface Casing Plugs Rig
Date: 3-5-2024
Prepared by: Sydney Long
Estimated Start Date: 4-15-2024
MIRU
1. MIRU on 2P-415A. (No BPV due to abandonment of all perforations.)
2. Record shut-in pressures on the T & IA. If there is pressure, bleed o IA and/or tubing
pressure and complete 30-minute NFT. Verify well is dead before proceeding.
3. ND Tree and NU BOPE. Test rams and annular to 250/2,500 PSI.
a. Will not set BPV due to two tested cement plugs below providing two barriers to
formation.
b. BOPE Con guration: Annular / Variable Bore Rams / Blind Rams
4. Circulate tubing and IA to brine.
Retrieve Tubing
5. MU landing joint and BOLDS.
6. Pull tubing from pre-rig cut to surface and LD.
Execute First Surface Casing Abandonment Plug
1. Set bridge plug in production casing 100 below surface casing shoe
2. Cut production casing 50 below surface casing shoe
3. Circulate OA to brine and complete 30-minute NFT.
a. Punch holes in production casing at the surface casing shoe if unable to achieve
circulation from production casing cut.
4. MU landing joint for production casing hanger and con rm casing is free from cut by picking
up casing.
a. Contingency: If unable to pull production casing from original cut depth
i. Perform second cut inside surface casing shoe
ii. Pull casing down to upper cut and laydown
iii. PU DP and shing assembly
iv. TIH and engage cut stub of prod casing. Fish stub free.
v. Retrieve to surface. LD DP
5. Pump cement plug through the production casing cut. Utilize 10.2 BBL of cement, plus
excess, to target a nal TOC ±150 inside the surface casing shoe. Slightly under displace
cement and pull 5-1/2 casing slowly to above nal TOC - allowing cement to ll the space
vacated by the casing displacement. Ensure base of 5-1/2 casing is between 150 200
inside the surface casing shoe based on space out of a casing collar at the oor. Circulate
the base of the prod casing clear of any residual cement. See table below for cement
volume calculations.
a. Contingency: if unable to pull prod casing from original cut depth
i. TIH with tubing to above the casing shoe
ii. Pump cement plug across the shoe through the tubing. PU and circulate the
base of the tubing clear
b. A Variance is requested to 20 AAC 25.112 requiring cement 100 below hydrocarbon
bearing zones. It is our intention to recover 50 of production casing from the open
hole section.
c. A Variance is requested to Order 196 requiring the cement to be logged. It is not our
intention, nor recommendation for the integrity of the abandonment, to drill out the
cement plug once pumped.
6. WOC
7. Tag cement and PT to 1,500 PSI with state witness
a. Pressure up to FIT equivalent and hold for 10 min to ensure no leak o prior to
increasing pressure to full 1,500 PSI for 30-min state witness
b. Observe pressure leak o during test. Pull 5-1/2 casing out of the well.
8. PU milling BHA and clean out the cement plug to below the surface casing shoe and until
injectivity is achieved. POOH and LD DP.
9. PU and RIH with cementing string
10. Place the cementing string at the milled depth and pump a balanced plug. Pull the string
slowly up through the cement to above the TOC. Perform a light hesitation squeeze and
place pressure on the TOC. Target a nal TOC ±150 inside the surface casing shoe.
11. WOC
12. Tag cement and PT to 1,500 PSI with state witness
2P-415A Well Surface Shoe Cement Schematic
Conductor:
16" Conductor 110' KB
Production Casing Cement:
62.5 bbls of 15.8# Class G Cement
Calculated TOC @ 5,782' KB
1
3
5
4
Production Casing:
5.5" x 3.5" @ 8,210' KB, 15.5# x 9.3#,
L-80 BTC Mod
Set @ 9,025.8 KB
T-3 Peforations:
@ 8,640' 8,650' KB (10')
Surface Casing:
7-5/8", 29.7#, L-80 BTC Mod
Set @ 3,713' KB
Production Tubing:
3 ½, 9.3# L-80 EUE-8rd
Set @ 8,208.4' KB
6
Item Depth - tops
(KB)
1 FMC Hanger 23.1'
2 Cast Iron Bridge Plug 3860.0'
3
Baker CMU Non-Elastomer Sliding
Sleeve w/ Camco DS Profile -
Closed 11/14/2009
8,131.6'
4 Camco D Nipple 8,147.7'
5 Baker 80-40 G-22 Locator Sub 8,190.9'
6 Baker G22 Seal Assembly 8,191.5'
Plug #1 Reservoir
TOC 8594' RKB
C80 @ 3775' KB C80 @ 3775' KB
Plug #2 Intermediate
TOC ±6600' RKB
BOC @ ±8100' RKB
Plug #3 Surface Shoe
TOC 3563' RKB
BOC @ ±3860' RKB
Base of 5-½ Casing
150'-200' Inside Surface
Shoe
2
Execute Final Abandonment Plug
13. Land workstring in casing hanger pro le.
14. ND BOPE. NU dry hole tree.
15. Circulate cement surface to surface until full cement returns observed on surface. See
table below for cement volumes.
RDMO
16. ND BOPE. NU dry hole tree.
17. RDMO.
Cement Plug TOC BOC Section ID BBL/FT Volume Notes
Surface Shoe
3763 3813 Open Hole 6.75 0.03867 1.9 Displacement of Prod Casing
Stub Included in BBL/FT calc
3713 3763 Open Hole 6.75 0.04426 2.2
3613 3713 Surface Casing 6.87 0.04026 6.1
10.2 Total Volume of Plug
Surface Casing 23 3560 Surface Casing 6.87 0.0426 142.0 Displacement of Prod Casing
Included in BBL/FT calculation
Execute Final Abandonment
Surface Excavation
18. DHD to perform drawdown test on tubing, IA, and OA
19. Remove well house.
20. Bleed o T/I/O to ensure all pressure is bled o the system.
21. Remove tree in preparation for excavation and casing cut.
22. If shallow thaw conditions are found, have shoring box installed during the excavation
activity to prevent lose ground from falling into the excavation.
23. Cut o wellhead and all casing strings at 4 feet below original ground level.
24. Perform top job if needed to ensure cement is at surface on all strings. AOGCC witness and
photo document required.
25. Send the casing head with stub to materials shop. Photo document.
26. Weld 1/4" thick cover plate (16" OD) over all casing strings with the following information
bead welded into the top. Photo document. AOGCC witness required.
a. ConocoPhillips
b. KRU 2P-415A
c. PTD #: 201-226
d. API #: 50-103-20383-01-00
27. Remove cellar. Back ll cellar with gravel/ll as needed. Back ll remaining hole to ground
level.
28. Obtain site clearance approval from AOGCC. RDMO.
29. Report the nal P&A has been completed to the AOGCC. Photo document nal location
condition after work is completed
2P-415A Well Final P&A Schematic
Conductor:
16" Conductor 110' KB
Production Casing Cement:
62.5 bbls of 15.8# Class G Cement
Calculated TOC @ 5,782' KB
1
3
5
4
Production Casing:
5.5" x 3.5" @ 8,210' KB, 15.5# x 9.3#,
L-80 BTC Mod
Set @ 9,025.8 KB
T-3 Peforations:
@ 8,640' 8,650' KB (10')
Surface Casing:
7-5/8", 29.7#, L-80 BTC Mod
Set @ 3,713' KB
Production Tubing:
3 ½, 9.3# L-80 EUE-8rd
Set @ 8,208.4' KB
6
Item Depth - tops
(KB)
1 FMC Hanger 23.1'
2 Cast Iron Bridge Plug 3860.0'
3
Baker CMU Non-Elastomer Sliding
Sleeve w/ Camco DS Profile -
Closed 11/14/2009
8,131.6'
4 Camco D Nipple 8,147.7'
5 Baker 80-40 G-22 Locator Sub 8,190.9'
6 Baker G22 Seal Assembly 8,191.5'
Plug #1 Reservoir
TOC 8594' RKB
C80 @ 3775' KB C80 @ 3775' KB
Plug #2 Intermediate
TOC ±6600' RKB
BOC @ ±8100' RKB
Plug #3 Surface Shoe
TOC 3563' RKB
BOC @ ±3860' RKB
Plug #4 Surface
TOC 23' RKB
BOC @ ±3560' RKB
2
CAUTION: This email originated from outside the State of Alaska mail
system. Do not click links or open attachments unless you recognize the
sender and know the content is safe.
From:Loepp, Victoria T (OGC)
To:Germann, Shane
Cc:Regg, James B (OGC); DOA AOGCC Prudhoe Bay
Subject:Re: 2P-415A Repump Surface Shoe PlugAPPROVED
Date:Saturday, April 27, 2024 6:09:08 PM
Shane,
Target plug height is 150 or slightly more.
This plan forward is approved. Please submit change of approved sundry on Monday.
Victoria
Sent from my iPhone
On Apr 27, 2024, at 4:08PM, Germann, Shane
<Shane.Germann@conocophillips.com> wrote:
Good Afternoon,
The surface shoe cement plug on 2P-415A was pumped Friday to plan. A WOC of +24
hours was performed before having AOGCC at the rig to witness the tag and test this
afternoon. Good cement was tagged at 3,631' RKB (D25), which would place TOC ~94'
above the surface shoe, with a 10 klb set down. It was then attempted to pressure test
- unsuccessfully. The pressure bled off from 800 psi to 500 psi in 10 minutes. We are
currently prepping to pull out of hole with the 5-1/2 casing to surface.
Our recommended plan forward is as follows:
1. Continue to POOH with the 5-1/2 casing and lay down
2. Pick up a cement milling BHA. Mill out the cement plug until below the surface
shoe and injectivity is achieved.
3. POOH with the milling BHA and lay down drill pipe
4. Pick up and RIH with cementing string
5. Place the workstring at the milled depth and pump a balanced plug. Pull the
workstring slowly up through the cement to above the top. Perform a light
hesitation squeeze and place pressure on the TOC.
6. WOC
7. Tag and test the TOC per AOGCC with witness
8. Proceed with the approved sundry
Please let me know if you have any questions or concerns. Feel free to call my cell if
you have any questions.
Thanks,
Shane Germann
CTD/RWO Engineer
ConocoPhillips Alaska
Office: 907-263-4597
Cell: 406-670-1939
700 G St, ATO 664, Anchorage, AK 99501
Repair WellFracture StimulatePlug Perforations Operations shutdownAbandon1. Type of Request:
Pull TubingOther StimulatePerforate Change Approved ProgramSuspend
Alter CasingPerforate New Pool Re-enter Susp Well Other: ___________________Plug for Redrill
5. Permit to Drill Number:4. Current Well Class:2. Operator Name:
DevelopmentExploratory
3.Address:ServiceStratigraphic 6. API Number:
8.Well Name and Number:7.If perforating:
What Regulation or Conservation Order governs well spacing in this pool?
NoYes
10.Field:9. Property Designation (Lease Number):
11.
Junk (MD):Total Depth TVD (ft):Total Depth MD (ft):
None9038'
CollapseCasing
Structural
Conductor
Surface
Intermediate
Production
Liner
Packers and SSSV MD (ft) and TVD (ft):Packers and SSSV Type:
Wellbore schematic 13. Well Class after proposed work:Proposal Summary12. Attachments:
Development ServiceBOP Sketch Exploratory StratigraphicDetailed Operations Program
15. Well Status after proposed work:14. Estimated Date for
WDSPLWINJOILCommencing Operations:Suspended
SPLUGGAS WAG GSTOR16. Verbal Approval:
AOGCC Representative: GINJ AbandonedOp Shutdown
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? NoYes
APPROVED BY
Date:COMMISSIONER THE AOGCCApproved by:
Sr Pet Geo Sr Res EngSr Pet EngComm.Comm.
Senior RWO/CTD Engineer
KRU 2P-415A
852 psi6050'
N/A
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):
Authorized Name and
Digital Signature with Date:
Tubing Size:
AOGCC USE ONLY
Tubing MD (ft):Tubing Grade:
8191' MD and 5271' TVD
N/A
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0373112
201-226
P.O. Box 100360, Anchorage, AK 99510 50-103-20383-01-00
Kuparuk River Field Meltwater Oil Pool
ConocoPhillips Alaska, Inc.
SizeLength
Proposed Pools:
PRESENT WELL CONDITION SUMMARY
Meltwater Oil Pool -
Abandoned
BurstTVD
8208'
MD
110'
2449'
110'
3713'
6039'9026'
16"
7-5/8"
82'
3685'
8640-8650'
9000'
5682-5691'
5-1/2" x 3-1/2"
Perforation Depth TVD (ft):
3-1/2"
Packer: Baker G-2 Seal Assy
SSSV: None
Perforation Depth MD (ft):
L-80
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Plugs (MD):
8625', 8518', 6600'
Effective Depth MD:
6600'
Effective Depth TVD:
3850'
Apr-27-2024
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior writt en approval.
Contact Name: Shane Germann
4/27/2024
Date:
Contact Email:shane.germann@conocophillips.com
Contact Phone:(406) 670-1939
By Grace Christianson at 8:48 am, Apr 29, 2024
Digitally signed by Shane Germann
DN: O=ConocoPhillips, CN=Shane Germann
, E=shane.germann@conocophillips.com
Reason: I am the author of this document
Location:
Date: 2024.04.27 17:15:53-08'00'
Foxit PDF Editor Version: 13.0.0
324-252
DSR-4/29/24
10-407
BOP test to 2500 psig; Annular preventer test to 2500 psig.
A variance to 20 AAC 25.112(a)(1)(A) is granted. Cement is not required from 100' below the base of the C-80 to 100' above the top
of the C-80. The variance is granted to allow an equally effective plug which includes the placement of a cement
plug from ~50' MD below the surface casing shoe in the open hole to 150' MD into the surface casing. (20 AAC 25.112(i))
A variance to the cement logging required in Other Order 196 is granted. Cement logging is not required.
AOGCC inspection required after cutoff and before remedial cementing
VTL 4/29/2024
2nd try intm plug
SFD 4/29/2024
X
X
X
H$8
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.04.29 15:19:34 -08'00'04/29/24
RBDMS JSB 043024
2P-415 Plug and Abandonment
Background & Objective
2P-415A was a producer that has been shut in since April 2019. This well is ultimately slated to be
P&A’d as part of the 2P pad abandonment. This well is in the process of being suspended with a
CIBP and cement placed and is currently waiting for AOGCC witness of a tag and test (as of
3/5/2024). The remaining steps to P&A this well include three more cement plugs: an intermediate
plug across the tubing, a plug across the surface casing shoe after the tubing and production
casing has been pulled, and then a final plug to surface.
Well Data
Meltwater Formation:
x Reservoir pressure 2/16/2017 = 1420 psi (.25 psi/ft)
x MASP = 852 psi
x Reservoir abandoned (CIBP & cement) 12/18/23
C-80 Formation:
x OAP = 183 psi (9/17/23) (fluid packed with diesel)
x MASP = 770 psi
Max deviation = 69 deg at 5168’ KB
Intermediate Plug – Wireline & Pumping
Date: 2-6-24
Prepared by: Katherine O’Connor
Estimated Start Date: 2-26-24
Procedure
1. Punch tubing at ±8,100’ RKB
2. Pump the following schedule taking returns up the IA:
a. ±50 bbls surfactant wash
b. ±190 bbls 9.8 brine
c. ±31 bbls cement
d. ±57 bbls 9.8 brine displacement
3. This should leave TOC in tubing and IA hydrostatically balanced with cement top at 6600’
MD
4. RIH and tag TOC and perform pressure test to 1500 psi (AOGCC Witnessed)
5. Cut tubing at ±3,900’ RKB
Top Bottom Size ID bbls/ft ft volume ft/bbl notes
3-1/2" tubing 0 8100 3.5" 9.3# 2.99" 0.0087 8100 70.3 115.1 from punch depth
3-1/2" x 5-1/2" Annulus 0 8100 3.5" 9.3# x 5.5" 15.5# 4.95" x 3.5" 0.0119 8100 96.4 84.0 from punch depth
Tubing Cement 6600 8100 3.5" 9.3# 2.99" 0.0087 1500 13.0 115.1
Annular Cement 6600 8100 3.5" 9.3# x 5.5" 15.5# 4.95" x 3.5" 0.0119 1500 17.9 84.0
2P-415A Well Suspension Schematic
Conductor:
16" Conductor 110' KB
Production Casing Cement:
62.5 bbls of 15.8# Class G Cement
Calculated TOC @ 5,782' KB
1
2
3
5
4
Production Casing:
5.5" x 3.5" @ 8,210' KB, 15.5# x 9.3#,
L-80 BTC Mod
Set @ 9,025.8’ KB
T-3 Peforations:
@ 8,640' – 8,650' KB (10')
Surface Casing:
7-5/8", 29.7#, L-80 BTC Mod
Set @ 3,713' KB
Production Tubing:
3 ½”, 9.3# L-80 EUE-8rd
Set @ 8,208.4' KB
6
Item Depth - tops
(KB)
1 FMC Tubing Hanger 23.1'
2 Camco DS Nipple 505.4'
3
Baker CMU Non-Elastomer Sliding
Sleeve w/ Camco DS Profile -
Closed 11/14/2009
8,131.6'
4 Camco D Nipple 8,147.7'
5 Baker 80-40 G-22 Locator Sub 8,190.9'
6 Baker G22 Seal Assembly 8,191.5'
Plug #1 – Reservoir
TOC 8594' RKB
C80 @ 3775' KB C80 @ 3775' KB
Plug #2 – Intermediate
TOC ±6600' RKB
BOC @ ±8100' RKB
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
TO: Jim Regg DATE:
P.I. Supervisor
SUBJECT:
FROM:
Petroleum Inspector
Section:17 Township:8N Range:7E Meridian:Umiat
Drilling Rig:Doyon 25 Rig Elevation:39.1 Total Depth:9038 ft MD Lease No.:ADL 0373112
Operator Rep:Suspend:P&A:X
Conductor:16"O.D. Shoe@ 110 Feet Csg Cut@ NA Feet
Surface:7-5/8"O.D. Shoe@ 3713 Feet Csg Cut@ NA Feet
Intermediate:NA O.D. Shoe@ NA Feet Csg Cut@ NA Feet
Production:5-1/2"x3-1/2"O.D. Shoe@ 9026 Feet Csg Cut@ 3780 Feet
Liner:NA O.D. Shoe@ NA Feet Csg Cut@ NA Feet
Tubing:3-1/2"O.D. Tail@ 8208 Feet Tbg Cut@ 3927 Feet
Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified
Initial 15 min 30 min 45 min Result
Tubing
IA
OA
Initial 15 min 30 min 45 min Result
Tubing
IA
OA
Remarks:
Attachments:
Jonathan Benedict
Casing/Tubing Data (depths are MD):
Plugging Data (depths are MD):
On 4/27 I traveled to location to witness that tag and pressure test of a cement plug isolating a 55 foot open hole section below
the surface casing shoe. Variance to 20 AAC 25.112(a)(1)(A) was granted by AOGCC. Cement plug was to be from ~ 50 feet
measured depth (MD) below surface shoe to at least 150 feet inside the surface casing (3563 ft MD). Washing down to 3613 ft
MD with 5-1/2" x 4" string they found no cement. Circulating bottoms up we observed green cement at surface. On 4/29 I was en
route to location after the unsatisfactory plug was millled up to below the surface shoe and the cement job re done. I was called
and informed a pre-test was done and it failed. It appears the rig will be milling up the plug again and attempting to redo for the
second time.
April 27, 2024
Austin McLeod
Well Bore Plug & Abandonment
Kuparuk River Unit 2P-415A
ConocoPhillips Alaska, LLC
PTD 2012260; Sundry 324-146
none
Test Data:
Casing Removal:
rev. 3-24-2022 2024-0427_Plug_Verification_KRU_2P-415A_am
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
TO: Jim Regg DATE:
P.I. Supervisor
SUBJECT:
FROM:
Petroleum Inspector
Section:17 Township:8N Range:7E Meridian:Umiat
Drilling Rig:n/a Rig Elevation:n/a Total Depth:9038 ft MD Lease No.:ADL 0373112
Operator Rep:Suspend:P&A:X
Conductor:16"O.D. Shoe@ 110 Feet Csg Cut@ Feet
Surface:7 5/8"O.D. Shoe@ 3713 Feet Csg Cut@ Feet
Intermediate:O.D. Shoe@ Feet Csg Cut@ Feet
Production:5 1/2" x 3 1/4"O.D. Shoe@ 9026 Feet Csg Cut@ Feet
Liner:O.D. Shoe@ Feet Csg Cut@ Feet
Tubing:3 1/2"O.D. Tail@ 8208 Feet Tbg Cut@ Feet
Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified
Fullbore Balanced 8100 ft 6335 ft 9.8 ppg Wireline tag
Initial 15 min 30 min 45 min Result
Tubing 1716 1640 1620
IA 1711 1640 1619
OA 263 191 177
Initial 15 min 30 min 45 min Result
Tubing
IA
OA
Remarks:
Attachments:
Ryan Moore
Casing/Tubing Data (depths are MD):
Plugging Data (depths are MD):
Travel to Kuparuk 2P-415 to witness tag and test of the intermediate balanced cement plug. I met with CPAI representative Ryan
Moore and received all appropriate documentation. The wireline unit utilized a digital depth recorder that was correlated to RKB.
The tool string had a 300 lb. weight bar and flapper bailer. They tagged before and after the MIT. The initial tag was 6333 ft MD
and cement sample was soupy with bits of clay like cement. The second tag was 6335 ft MD and the bailer had mostly clay like
cement.
April 2, 2024
Sully Sullivan
Well Bore Plug & Abandonment
KRU 2P-415A
ConocoPhillips Alaska LLC
PTD 2012260; Sundry 324-146
Well Schematic
Test Data:
P
Casing Removal:
rev. 3-24-2022 2024-0402_Plug_Verification_KRU_2P-415A_ss
===
415A
Plug Verification – KRU 2P-415A (PTD 2012260)
Well Schematic
4/2/2024
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
TO: Jim Regg DATE:
P.I. Supervisor
SUBJECT:
FROM:
Petroleum Inspector
Section:17 Township:8N Range:7E Meridian:Umiat
Drilling Rig:NA Rig Elevation:NA Total Depth:9038 ft MD Lease No.:ADL0373112
Operator Rep:Suspend:X P&A:
Conductor:16"O.D. Shoe@ 110 Feet Csg Cut@ NA Feet
Surface:7-5/8"O.D. Shoe@ 3713 Feet Csg Cut@ NA Feet
Intermediate:NA O.D. Shoe@ NA Feet Csg Cut@ NA Feet
Production:3-1/2"x5-1/2"O.D. Shoe@ 9026 Feet Csg Cut@ NA Feet
Liner:NA O.D. Shoe@ NA Feet Csg Cut@ NA Feet
Liner:NA O.D. Shoe@ NA Feet Csg Cut@ NA Feet
Tubing:3-1/2"O.D. Tail@ 8208 Feet Tbg Cut@ NA Feet
Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified
Tubing Bridge plug 8625 ft MD 8518 ft MD 8.6/6.9 ppg Wireline tag
Initial 15 min 30 min 45 min Result
Tubing 1720 1640 1580 1535
IA 520 560 550 570
OA 220 230 240 230
Initial 15 min 30 min 45 min Result
Tubing 1740 1680 1635
IA 600 630 670
OA 240 230 230
Initial 15 min 30 min 45 min Result
Tubing 1825 1810 1805
IA 1750 1750 1750
OA 230 230 230
Remarks:
Attachments:
Brent Rogers
F
Casing/Tubing Data:
Plugging Data (depths are MD):
P
I traveled to KRU 2P to witness the tag and pressure test of the bottom zone isolating cement plug that had been dumped bailed
on top of a cast iron bridge plug (CIBP) inside the well's 3-1/2 inch production string. CIBP is set at 8625 ft MD putting the CIBP
15 ft above the top perforation. Cement was dumped on 12/18/2023. Ran in the hole with generic 2-1/2 inch bailer slickline string.
Hanging weight of string ~ 250 pounds and tagged top of cement at 8518 ft MD (24° inclination) with mutiple jars down. Not
making any progress they pulled the string to surface and found good cement inside the bailer. They made two attempts to get a
passing MIT on the tubing/plug with no success. With increasing inner annulus pressures we decided to do a combination MIT on
both the tubing and inner annulus (CMIT TxIA) to prove plug integrity. Dummy valve in gas lift mandrel leak suspected. CMIT
passed. No other issues with this inspection.
March 17, 2024
Austin McLeod
Well Bore Plug & Abandonment
Kuparuk River Unit 2P-415A
ConocoPhillips Alaska Inc.
PTD 2012260; Sundry 323-404
none
Test Data:
F
Casing Removal:
rev. 11-28-18 2024-0317_Plug_Verification_KRU_2P-415A_am
Surface Casing Plugs – Rig
Date: 3-5-2024
Prepared by: Sydney Long
Estimated Start Date: 4-15-2024
MIRU
1. MIRU on 2P-415A. (No BPV due to abandonment of all perforations.)
2. Record shut-in pressures on the T & IA. If there is pressure, bleed oƯ IA and/or tubing
pressure and complete 30-minute NFT. Verify well is dead before proceeding.
3. ND Tree and NU BOPE. Test rams and annular to 250/2,500 PSI.
a. Will not set BPV due to two tested cement plugs below providing two barriers to
formation.
b. BOPE ConƱguration: Annular / Variable Bore Rams / Blind Rams
4. Circulate tubing and IA to brine.
Retrieve Tubing
5. MU landing joint and BOLDS.
6. Pull tubing from pre-rig cut to surface and LD.
Execute First Surface Casing Abandonment Plug
1. Set bridge plug in production casing 100’ below surface casing shoe
2. Cut production casing 50’ below surface casing shoe
3. Circulate OA to brine and complete 30-minute NFT.
a. Punch holes in production casing at the surface casing shoe if unable to achieve
circulation from production casing cut.
4. MU landing joint for production casing hanger and conƱrm casing is free from cut by picking
up casing.
a. Contingency: If unable to pull production casing from original cut depth
i. Perform second cut inside surface casing shoe
ii. Pull casing down to upper cut and laydown
iii. PU DP and Ʊshing assembly
iv. TIH and engage cut stub of prod casing. Fish stub free.
v. Retrieve to surface. LD DP
5. Pump cement plug through the production casing cut. Utilize 10.2 BBL of cement, plus
excess, to target a Ʊnal TOC ±150’ inside the surface casing shoe. Slightly under displace
cement and pull 5-1/2” casing slowly to above Ʊnal TOC - allowing cement to Ʊll the space
vacated by the casing displacement. Ensure base of 5-1/2” casing is between 150’ – 200’
inside the surface casing shoe based on space out of a casing collar at the Ʋoor. Circulate
the base of the prod casing clear of any residual cement. See table below for cement
volume calculations.
a. Contingency: if unable to pull prod casing from original cut depth
i. TIH with tubing to above the casing shoe
ii. Pump cement plug across the shoe through the tubing. PU and circulate the
base of the tubing clear
b. A Variance is requested to 20 AAC 25.112 requiring cement 100’ below hydrocarbon
bearing zones. It is our intention to recover 50’ of production casing from the open
hole section.
c. A Variance is requested to Order 196 requiring the cement to be logged. It is not our
intention, nor recommendation for the integrity of the abandonment, to drill out the
cement plug once pumped.
6. WOC
7. Tag cement and PT to 1,500 PSI with state witness
a. Pressure up to FIT equivalent and hold for 10 min to ensure no leak oƯ prior to
increasing pressure to full 1,500 PSI for 30-min state witness
b. Observe pressure leak oƯ during test. Pull 5-1/2” casing out of the well.
8. PU milling BHA and clean out the cement plug to below the surface casing shoe and until
injectivity is achieved. POOH and LD DP.
9. PU and RIH with cementing string
10. Place the cementing string at the milled depth and pump a balanced plug. Pull the string
slowly up through the cement to above the TOC. Perform a light hesitation squeeze and
place pressure on the TOC. Target a Ʊnal TOC ±150’ inside the surface casing shoe.
11. WOC
12. Tag cement and PT to 1,500 PSI with state witness
2P-415A Well Surface Shoe Cement Schematic
Conductor:
16" Conductor 110' KB
Production Casing Cement:
62.5 bbls of 15.8# Class G Cement
Calculated TOC @ 5,782' KB
1
3
5
4
Production Casing:
5.5" x 3.5" @ 8,210' KB, 15.5# x 9.3#,
L-80 BTC Mod
Set @ 9,025.8’ KB
T-3 Peforations:
@ 8,640' – 8,650' KB (10')
Surface Casing:
7-5/8", 29.7#, L-80 BTC Mod
Set @ 3,713' KB
Production Tubing:
3 ½”, 9.3# L-80 EUE-8rd
Set @ 8,208.4' KB
6
Item Depth - tops
(KB)
1FMC Hanger 23.1'
2 Cast Iron Bridge Plug 3860.0'
3
Baker CMU Non-Elastomer Sliding
Sleeve w/ Camco DS Profile -
Closed 11/14/2009
8,131.6'
4 Camco D Nipple 8,147.7'
5 Baker 80-40 G-22 Locator Sub 8,190.9'
6 Baker G22 Seal Assembly 8,191.5'
Plug #1 – Reservoir
TOC 8594' RKB
C80 @ 3775' KB C80 @ 3775' KB
Plug #2 – Intermediate
TOC ±6600' RKB
BOC @ ±8100' RKB
Plug #3 – Surface Shoe
TOC 3563' RKB
BOC @ ±3860' RKB
Base of 5-½” Casing
150'-200' Inside Surface
Shoe
2
Execute Final Abandonment Plug
13. Land workstring in casing hanger proƱle.
14. ND BOPE. NU dry hole tree.
15. Circulate cement surface to surface until full cement returns observed on surface. See
table below for cement volumes.
RDMO
16. ND BOPE. NU dry hole tree.
17. RDMO.
Cement Plug TOC BOC Section ID BBL/FT Volume Notes
Surface Shoe
3763 3813 Open Hole 6.75 0.03867 1.9 Displacement of Prod Casing
Stub Included in BBL/FT calc
3713 3763 Open Hole 6.75 0.04426 2.2
3613 3713 Surface Casing 6.87 0.04026 6.1
10.2 Total Volume of Plug
Surface Casing 23 3560 Surface Casing 6.87 0.0426 142.0 Displacement of Prod Casing
Included in BBL/FT calculation
Execute Final Abandonment
Surface Excavation
18. DHD to perform drawdown test on tubing, IA, and OA
19. Remove well house.
20. Bleed oƯ T/I/O to ensure all pressure is bled oƯ the system.
21. Remove tree in preparation for excavation and casing cut.
22. If shallow thaw conditions are found, have shoring box installed during the excavation
activity to prevent lose ground from falling into the excavation.
23. Cut oƯ wellhead and all casing strings at 4 feet below original ground level.
24. Perform top job if needed to ensure cement is at surface on all strings. AOGCC witness and
photo document required.
25. Send the casing head with stub to materials shop. Photo document.
26. Weld 1/4" thick cover plate (16" OD) over all casing strings with the following information
bead welded into the top. Photo document. AOGCC witness required.
a. ConocoPhillips
b. KRU 2P-415A
c. PTD #: 201-226
d. API #: 50-103-20383-01-00
27. Remove cellar. Back Ʊll cellar with gravel/Ʊll as needed. Back Ʊll remaining hole to ground
level.
28. Obtain site clearance approval from AOGCC. RDMO.
29. Report the Ʊnal P&A has been completed to the AOGCC. Photo document Ʊnal location
condition after work is completed
2P-415A Well Final P&A Schematic
Conductor:
16" Conductor 110' KB
Production Casing Cement:
62.5 bbls of 15.8# Class G Cement
Calculated TOC @ 5,782' KB
1
3
5
4
Production Casing:
5.5" x 3.5" @ 8,210' KB, 15.5# x 9.3#,
L-80 BTC Mod
Set @ 9,025.8’ KB
T-3 Peforations:
@ 8,640' – 8,650' KB (10')
Surface Casing:
7-5/8", 29.7#, L-80 BTC Mod
Set @ 3,713' KB
Production Tubing:
3 ½”, 9.3# L-80 EUE-8rd
Set @ 8,208.4' KB
6
Item Depth - tops
(KB)
1 FMC Hanger 23.1'
2 Cast Iron Bridge Plug 3860.0'
3
Baker CMU Non-Elastomer Sliding
Sleeve w/ Camco DS Profile -
Closed 11/14/2009
8,131.6'
4 Camco D Nipple 8,147.7'
5 Baker 80-40 G-22 Locator Sub 8,190.9'
6 Baker G22 Seal Assembly 8,191.5'
Plug #1 – Reservoir
TOC 8594' RKB
C80 @ 3775' KB C80 @ 3775' KB
Plug #2 – Intermediate
TOC ±6600' RKB
BOC @ ±8100' RKB
Plug #3 – Surface Shoe
TOC 3563' RKB
BOC @ ±3860' RKB
Plug #4 – Surface
TOC 23' RKB
BOC @ ±3560' RKB
2
CAUTION: This email originated from outside the State of Alaska mail
system. Do not click links or open attachments unless you recognize the
sender and know the content is safe.
From:Loepp, Victoria T (OGC)
To:Germann, Shane
Cc:Regg, James B (OGC); DOA AOGCC Prudhoe Bay
Subject:Re: 2P-415A Repump Surface Shoe PlugAPPROVED
Date:Saturday, April 27, 2024 6:09:08 PM
Shane,
Target plug height is 150’ or slightly more.
This plan forward is approved. Please submit change of approved sundry on Monday.
Victoria
Sent from my iPhone
On Apr 27, 2024, at 4:08ௗPM, Germann, Shane
<Shane.Germann@conocophillips.com> wrote:
Good Afternoon,
The surface shoe cement plug on 2P-415A was pumped Friday to plan. A WOC of +24
hours was performed before having AOGCC at the rig to witness the tag and test this
afternoon. Good cement was tagged at 3,631' RKB (D25), which would place TOC ~94'
above the surface shoe, with a 10 klb set down. It was then attempted to pressure test
- unsuccessfully. The pressure bled off from 800 psi to 500 psi in 10 minutes. We are
currently prepping to pull out of hole with the 5-1/2” casing to surface.
Our recommended plan forward is as follows:
1. Continue to POOH with the 5-1/2” casing and lay down
2. Pick up a cement milling BHA. Mill out the cement plug until below the surface
shoe and injectivity is achieved.
3. POOH with the milling BHA and lay down drill pipe
4. Pick up and RIH with cementing string
5. Place the workstring at the milled depth and pump a balanced plug. Pull the
workstring slowly up through the cement to above the top. Perform a light
hesitation squeeze and place pressure on the TOC.
6. WOC
7. Tag and test the TOC per AOGCC with witness
8. Proceed with the approved sundry
Please let me know if you have any questions or concerns. Feel free to call my cell if
you have any questions.
Thanks,
Shane Germann
CTD/RWO Engineer
ConocoPhillips Alaska
Office: 907-263-4597
Cell: 406-670-1939
700 G St, ATO 664, Anchorage, AK 99501
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Rig 25
To:DOA AOGCC Prudhoe Bay; Regg, James B (OGC); Brooks, Phoebe L (OGC)
Cc:Drilling Supervisor, Doyon 25; WSC Rig Advisor; Greg.S.Hobbs@conocophillips.com; Bill Walter; Samuel Dye; Ben
Wedin
Subject:Doyon 25 04-24-24
Date:Wednesday, April 24, 2024 1:22:34 AM
Attachments:Test Chart 2P-415 4-24-24.pdf
Doyon 25 04-24-24.xlsx
Some people who received this message don't often get email from rig25@doyondrilling.com. Learn why this is
important
Rig 25 BOP Test 2 7/8” x 5” 4/24/24
Zak Coleman
Rig 25 Tourpusher
rig25@doyondrilling.com
907-670-4971
.583$
37'
9
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSub m it to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:25 DATE: 4/24/24
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #22012260 Sundry #324-146
Operation: Drilling: Workover: x Explor.:
Test: Initial: x Weekly: Bi-Weekly: Other:
Rams:250/2500 Annular:250/2500 Valves:250/2500 MASP:852
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly
Permit On Location P Hazard Sec.P Lower Kelly
Standing Order Posted P Misc.P Ball Type
Test Fluid Water Inside BOP
FSV Misc
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0NATrip Tank
Annular Preventer 1 13-5/8"P Pit Level Indicators
#1 Rams 1 2-7/8" x 5"P Flow Indicator
#2 Rams 0NAMeth Gas Detector
#3 Rams 0NAH2S Gas Detector
#4 Rams 0NAMS Misc
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 0NA Time/Pressure Test Result
HCR Valves 0NASystem Pressure (psi)
Kill Line Valves 1NAPressure After Closure (psi)
Check Valve 0NA200 psi Attained (sec)
BOP Misc 0NAFull Pressure Attained (sec)
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:
Quantity Test Result Nitgn. Bottles # & psi (Avg.):
No. Valves 15 NA ACC Misc
Manual Chokes 1NA
Hydraulic Chokes 1NA Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer
#1 Rams
Coiled Tubing Only:#2 Rams
Inside Reel valves 0NA #3 Rams
#4 Rams
Test Results #5 Rams
#6 Rams
Number of Failures:0 Test Time:0.5 HCR Choke
Repair or replacement of equipment will be made within days. HCR Kill
Remarks:
AOGCC Inspection
24 hr Notice No Date/Time 4/23/24 16:57
Waived By
Test Start Date/Time:4/24/2024 0:30
(date) (time)Witness
Test Finish Date/Time:4/24/2024 1:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Sully Sullivan
Doyon
With 2 7/8" Test Jt, test Annular and Ram #1 to 250/2500psi for 5/5 minutes.
E. Potter / Z. Coleman
CPAI
J. Benedict / P. Angelle
KRU 2P-415A
Test Pressure (psi):
rig25@doyondrilling.com
d25cm@conocophillips.com
Form 10-424 (Revised 08/2022) 2024-0424_BOP_Doyon25_VBR_KRU_2P-415A
999
99
9999
9
9
MEU
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________KUPARUK RIV U MELT 2P-415A
JBR 06/11/2024
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:0
I was unable to be on location at the start of the test and did not witness the first three tests. Test # 1- Annular, CMV 1,13,14,15
4" kill line valve and 4" dart. Test #2- Upper rams, CMV 2,10,12,hcr kill and 4" FOSV. Test #3- CMV 6,9,11,Manual Kill and
UIBOP. Once on location we finished testing with 3.5" TJ and swapped over to 5.5" test joint. I tested all alarms and pvt's and
conducted a good drawdown test with no failures. After leaving location the CO man informed me that the Manual Choke line
valve was missed during the first three tests. I had him test it and send the chart. Both test charts are attached.
Test Results
TEST DATA
Rig Rep:Zach ColemanOperator:ConocoPhillips Alaska, Inc.Operator Rep:Jonathan Benedict
Rig Owner/Rig No.:Doyon 25 PTD#:2012260 DATE:4/22/2024
Type Operation:WRKOV Annular:
250/2500Type Test:INIT
Valves:
250/2500
Rams:
250/2500
Test Pressures:Inspection No:bopSTS240424065600
Inspector Sully Sullivan
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 4
MASP:
852
Sundry No:
324-146
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 NT
Lower Kelly 1 P
Ball Type 1 NT
Inside BOP 1 NT
FSV Misc 0 NA
15 NTNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13 5/8"NT
#1 Rams 1 3 1/2" x 5 7/8 NT
#2 Rams 1 blind/shear P
#3 Rams 1 3 1/2" x 5 7/8 P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3 1/8"NT
HCR Valves 2 3 1/8"NT
Kill Line Valves 1 3 1/8"NT
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P2950
Pressure After Closure P1900
200 PSI Attained P14
Full Pressure Attained P70
Blind Switch Covers:Pall stations
Bottle precharge P
Nitgn Btls# &psi (avg)P6@1904
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P22
#1 Rams P5
#2 Rams P5
#3 Rams P4
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
BOPE Test - Doyon 25
KRU 2P-415A; PTD 2012260
AOGCC Insp Rpt # bopSTS240424065600
4/22/2024
BOPE Test - Doyon 25
KRU 2P-415A; PTD 2012260
AOGCC Insp Rpt # bopSTS240424065600
4/22/2024
2P-415A 04/22/2023
Tested to 250PSI/5 MIN, 2500PSI/5 MIN
3.5” Test Jt
1.Annular Preventer, Valves: 1, 13, 14, 15, 4” Kill Line Valve, 4” DART
2.Upper Pipe Rams (3.5” x 5 7/8” ), Valves: 2, 10, 12, HCR KILL, 4” FOSV
3. Valves: 6, 9 ,11, MAN Kill & UIBOP
4.Valves: 5, 7, 8 & LIBOP
5.Valve: 3
6.Lower Pipe Rams (3.5” x 5 7/8” VBR’S)
5.5” Test Jt
7.Upper Pipe Rams (4.5” x 7” VBR’S) & HCR Choke
8.Lower Pipe Rams (3.5” x 5 7/8” VBR’S)
9.Blind Shear Rams, Valves: 4
10. Manually Operated & Super Choke (10A=SUPER Choke – 10B=MANUAL Choke)
CHART #2
11. MAN CHOKE
BOPE Test - Doyon 25
KRU 2P-415A; PTD 2012260
AOGCC Insp Rpt # bopSTS240424065600
4/22/2024
2P-415A 04/22/2023
Tested to 250PSI/5 MIN, 2500PSI/5 MIN
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft):Junk (MD):
9038'None
Casing Collapse
Structural
Conductor
Surface
Intermediate
Production
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
(907) 265-6312
Senior RWO/CTD Engineer
KRU 2P-415A
6050' 852 psi
N/A
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
sydney.long@conocophillips.com
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):
8191' MD and 5271' TVD
N/A
Sydney Long
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0373112
201-226
P.O. Box 100360, Anchorage, AK 99510 50-103-20383-01-00
Kuparuk River Field Meltwater Oil Pool
ConocoPhillips Alaska, Inc.
Length Size
Proposed Pools:
PRESENT WELL CONDITION SUMMARY
Meltwater Oil Pool -
Abandoned
TVD Burst
8208'
MD
110'
2449'
110'
3713'
6039'9026'
16"
7-5/8"
82'
3685'
8640-8650'
9000'
5682-5691'
5-1/2" x 3-1/2"
Perforation Depth TVD (ft):
4/24/2024
3-1/2"
Packer: Baker G-2 Seal Assy
SSSV: None
Perforation Depth MD (ft):
L-80
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Plugs (MD):
8625', 8518', 6600'
Effective Depth MD:
6600'
Effective Depth TVD:
3850'
By Grace Christianson at 2:13 pm, Apr 22, 2024
324-240
X
BOP test to 2500 psig; Annular preventer test to 2500 psig.
A variance to 20 AAC 25.112(a)(1)(A) is granted. Cement is not required from 100' below the base of the C-80 to 100' above the top
of the C-80. The variance is granted to allow an equally effective plug which includes the placement of a cement
plug from ~50' MD below the surface casing shoe in the open hole to 150' MD into the surface casing. (20 AAC 25.112(i))
A variance to the cement logging required in Other Order 196 is granted. Cement logging is not required.
AOGCC inspection required after cutoff and before remedial cementing
X
SFD 4/22/2024
4/24/2024
Apr 22, 2024
X
DSR-4/23/24VTL 4/23/2024
10-407
*&:
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.04.24 10:20:18 -08'00'04/24/24
RBDMS JSB 042524
2P-415 Plug and Abandonment
Background & Objective
2P-415A was a producer that has been shut in since April 2019. This well is ultimately slated to be
P&A’d as part of the 2P pad abandonment. This well is in the process of being suspended with a
CIBP and cement placed and is currently waiting for AOGCC witness of a tag and test (as of
3/5/2024). The remaining steps to P&A this well include three more cement plugs: an intermediate
plug across the tubing, a plug across the surface casing shoe after the tubing and production
casing has been pulled, and then a final plug to surface.
Well Data
Meltwater Formation:
x Reservoir pressure 2/16/2017 = 1420 psi (.25 psi/ft)
x MASP = 852 psi
x Reservoir abandoned (CIBP & cement) 12/18/23
C-80 Formation:
x OAP = 183 psi (9/17/23) (fluid packed with diesel)
x MASP = 770 psi
Max deviation = 69 deg at 5168’ KB
Intermediate Plug – Wireline & Pumping
Date: 2-6-24
Prepared by: Katherine O’Connor
Estimated Start Date: 2-26-24
Procedure
1. Punch tubing at ±8,100’ RKB
2. Pump the following schedule taking returns up the IA:
a. ±50 bbls surfactant wash
b. ±190 bbls 9.8 brine
c. ±31 bbls cement
d. ±57 bbls 9.8 brine displacement
3. This should leave TOC in tubing and IA hydrostatically balanced with cement top at 6600’
MD
4. RIH and tag TOC and perform pressure test to 1500 psi (AOGCC Witnessed)
5. Cut tubing at ±3,900’ RKB
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2P-415A Well Suspension Schematic
Conductor:
16" Conductor 110' KB
Production Casing Cement:
62.5 bbls of 15.8# Class G Cement
Calculated TOC @ 5,782' KB
1
2
3
5
4
Production Casing:
5.5" x 3.5" @ 8,210' KB, 15.5# x 9.3#,
L-80 BTC Mod
Set @ 9,025.8’ KB
T-3 Peforations:
@ 8,640' – 8,650' KB (10')
Surface Casing:
7-5/8", 29.7#, L-80 BTC Mod
Set @ 3,713' KB
Production Tubing:
3 ½”, 9.3# L-80 EUE-8rd
Set @ 8,208.4' KB
6
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Plug #1 – Reservoir
TOC 8594' RKB
C80 @ 3775' KB C80 @ 3775' KB
Plug #2 – Intermediate
TOC ±6600' RKB
BOC @ ±8100' RKB
Surface Casing Plugs – Rig
Date: 3-5-2024
Prepared by: Sydney Long
Estimated Start Date: 4-15-2024
MIRU
1. MIRU on 2P-415A. (No BPV due to abandonment of all perforations.)
2. Record shut-in pressures on the T & IA. If there is pressure, bleed oƯ IA and/or tubing
pressure and complete 30-minute NFT. Verify well is dead before proceeding.
3. ND Tree and NU BOPE. Test rams and annular to 250/2,500 PSI.
a. Will not set BPV due to two tested cement plugs below providing two barriers to
formation.
b. BOPE ConƱguration: Annular / Variable Bore Rams / Blind Rams
4. Circulate tubing and IA to brine.
Retrieve Tubing
5. MU landing joint and BOLDS.
6. Pull tubing from pre-rig cut to surface and LD.
Execute First Surface Casing Abandonment Plug
1. Set bridge plug in production casing 100’ below surface casing shoe
2. Cut production casing 50’ below surface casing shoe
3. Circulate OA to brine and complete 30-minute NFT.
a. Punch holes in production casing at the surface casing shoe if unable to achieve
circulation from production casing cut.
4. MU landing joint for production casing hanger and conƱrm casing is free from cut by picking
up casing.
a. Contingency: If unable to pull production casing from original cut depth
i. Perform second cut inside surface casing shoe
ii. Pull casing down to upper cut and laydown
iii. PU DP and Ʊshing assembly
iv. TIH and engage cut stub of prod casing. Fish stub free.
v. Retrieve to surface. LD DP
5. Pump cement plug through the production casing cut. Utilize 10.2 BBL of cement, plus
excess, to target a Ʊnal TOC ±150’ inside the surface casing shoe. Slightly under displace
cement and pull 5-1/2” casing slowly to above Ʊnal TOC - allowing cement to Ʊll the space
vacated by the casing displacement. Ensure base of 5-1/2” casing is between 150’ – 200’
inside the surface casing shoe based on space out of a casing collar at the Ʋoor. Circulate
the base of the prod casing clear of any residual cement. See table below for cement
volume calculations.
a. Contingency: if unable to pull prod casing from original cut depth
i. TIH with tubing to above the casing shoe
ii. Pump cement plug across the shoe through the tubing. PU and circulate the
base of the tubing clear
b. A Variance is requested to 20 AAC 25.112 requiring cement 100’ below hydrocarbon
bearing zones. It is our intention to recover 50’ of production casing from the open
hole section.
c. A Variance is requested to Order 196 requiring the cement to be logged. It is not our
intention, nor recommendation for the integrity of the abandonment, to drill out the
cement plug once pumped.
6. WOC
7. Tag cement and PT to 1,500 PSI with state witness
a. Pressure up to FIT equivalent and hold for 10 min to ensure no leak oƯ prior to
increasing pressure to full 1,500 PSI for 30-min state witness
2P-415A Well Surface Shoe Cement Schematic
Conductor:
16" Conductor 110' KB
Production Casing Cement:
62.5 bbls of 15.8# Class G Cement
Calculated TOC @ 5,782' KB
1
3
5
4
Production Casing:
5.5" x 3.5" @ 8,210' KB, 15.5# x 9.3#,
L-80 BTC Mod
Set @ 9,025.8’ KB
T-3 Peforations:
@ 8,640' – 8,650' KB (10')
Surface Casing:
7-5/8", 29.7#, L-80 BTC Mod
Set @ 3,713' KB
Production Tubing:
3 ½”, 9.3# L-80 EUE-8rd
Set @ 8,208.4' KB
6
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Plug #1 – Reservoir
TOC 8594' RKB
C80 @ 3775' KB C80 @ 3775' KB
Plug #2 – Intermediate
TOC ±6600' RKB
BOC @ ±8100' RKB
Plug #3 – Surface Shoe
TOC 3563' RKB
BOC @ ±3860' RKB
Base of 5-½” Casing
150'-200' Inside Surface
Shoe
2
Execute Final Abandonment Plug
8. Land workstring in casing hanger proƱle.
9. ND BOPE. NU dry hole tree.
10. Circulate cement surface to surface until full cement returns observed on surface. See
table below for cement volumes.
RDMO
11. ND BOPE. NU dry hole tree.
12. RDMO.
Cement Plug TOC BOC Section ID BBL/FT Volume Notes
Surface Shoe
3763 3813 Open Hole 6.75 0.03867 1.9 Displacement of Prod Casing
Stub Included in BBL/FT calc
3713 3763 Open Hole 6.75 0.04426 2.2
3613 3713 Surface Casing 6.87 0.04026 6.1
10.2 Total Volume of Plug
Surface Casing 23 3560 Surface Casing 6.87 0.0426 142.0 Displacement of Prod Casing
Included in BBL/FT calculation
Execute Final Abandonment
Surface Excavation
13. DHD to perform drawdown test on tubing, IA, and OA
14. Remove well house.
15. Bleed oƯ T/I/O to ensure all pressure is bled oƯ the system.
16. Remove tree in preparation for excavation and casing cut.
17. If shallow thaw conditions are found, have shoring box installed during the excavation
activity to prevent lose ground from falling into the excavation.
18. Cut oƯ wellhead and all casing strings at 4 feet below original ground level.
19. Perform top job if needed to ensure cement is at surface on all strings. AOGCC witness and
photo document required.
20. Send the casing head with stub to materials shop. Photo document.
21. Weld 1/4" thick cover plate (16" OD) over all casing strings with the following information
bead welded into the top. Photo document. AOGCC witness required.
a. ConocoPhillips
b. KRU 2P-415A
c. PTD #: 201-226
d. API #: 50-103-20383-01-00
22. Remove cellar. Back Ʊll cellar with gravel/Ʊll as needed. Back Ʊll remaining hole to ground
level.
23. Obtain site clearance approval from AOGCC. RDMO.
24. Report the Ʊnal P&A has been completed to the AOGCC. Photo document Ʊnal location
condition after work is completed
2P-415A Well Final P&A Schematic
Conductor:
16" Conductor 110' KB
Production Casing Cement:
62.5 bbls of 15.8# Class G Cement
Calculated TOC @ 5,782' KB
1
3
5
4
Production Casing:
5.5" x 3.5" @ 8,210' KB, 15.5# x 9.3#,
L-80 BTC Mod
Set @ 9,025.8’ KB
T-3 Peforations:
@ 8,640' – 8,650' KB (10')
Surface Casing:
7-5/8", 29.7#, L-80 BTC Mod
Set @ 3,713' KB
Production Tubing:
3 ½”, 9.3# L-80 EUE-8rd
Set @ 8,208.4' KB
6
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Plug #1 – Reservoir
TOC 8594' RKB
C80 @ 3775' KB C80 @ 3775' KB
Plug #2 – Intermediate
TOC ±6600' RKB
BOC @ ±8100' RKB
Plug #3 – Surface Shoe
TOC 3563' RKB
BOC @ ±3860' RKB
Plug #4 – Surface
TOC 23' RKB
BOC @ ±3560' RKB
2
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Annotate Tbg Cut 2P-415A 4/3/2024 bworthi1
Casing Strings
Csg Des OD (in) ID (in) Top (ftKB)
Set Depth
(ftKB)
Set Depth
(TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread
CONDUCTOR 16 15.06 28.0 110.0 110.0 62.50 H-40 WELDED
SURFACE 7 5/8 6.87 27.9 3,713.0 2,448.7 29.70 L-80 BTC Mod
PRODUCTION
5.5"x3.5" @ 8210'
5 1/2 4.95 25.3 9,025.8 6,038.6 15.50 L-80 BTC Mod
Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string
Top (ftKB)
3,924.3
Set Depth …
8,210.7
Set Depth …
5,288.8
String Max No…
3 1/2
Tubing Description
Tubing - Production
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE-8rd
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
5,662.6 3,246.5 60.24 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
6,864.7 4,069.7 29.51 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
7,540.6 4,678.8 26.93 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,090.5 5,178.2 23.38 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,134.0 5,218.2 23.00 SLEEVE-C 4.500 BAKER CMU NON-ELASTOMER
SLIDING SLEEVE w/CAMCO DS
PROFILE - CLOSED 11/14/2009
BAKER CMU 2.812
8,150.0 5,233.0 23.07 NIPPLE 3.750 CAMCO D NIPPLE CAMCO D 2.750
8,193.3 5,272.8 23.26 LOCATOR 4.500 BAKER 80-40 G-22 LOCATOR SUB BAKER 3.000
8,193.8 5,273.2 23.27 SEAL ASSY 4.000 BAKER G-22 SEAL ASSY BAKER 3.000
Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.)
Top (ftKB)
Top (TVD)
(ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in)
8,105.0 5,191.6 23.24 TUBING
PUNCH
3' TUBING PUNCH, 1.56", 3
GRAM, 6 SPF, 18 0.43"
HOLES
OWEN 3/24/2024 2.992
8,625.0 5,668.7 24.22 PLUG Set TTS CIBP (2.63" x 1.37' ) 10/7/2023 0.000
8,898.0 5,919.5 21.81 Plug Catcher WEATHERFORD PLUG
CATCHER
12/4/2001 0.000
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft)Type Com
8,640.0 8,650.0 5,682.3 5,691.5 T-3, 2P-415 12/24/2001 6.0 IPERF HMX Chrgs, 60 deg ph
Stimulation Intervals
Top (ftKB) Btm (ftKB)
Inter
val
Num
ber Type Subtype Start Date
Proppant
Designed (lb)
Proppant
Total (lb)
Vol Clean
Total (bbl)
Vol Slurry
Total (bbl)
8,640.0 8,650.0 1 FRAC 12/24/2001 0.0 0.00 0.00
Cement Squeezes
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Des Com
Pump Start
Date
8,518.0 8,625.0 5,570.9 5,668.7 Cement Plug Dump bailed cement with Slickline on top of CIBP 12/18/2023
6,600.0 8,100.0 3,849.8 5,187.0 Intermediate
String 1
Cement
PUMPED 31 BBLS OF 15.8 CLASS G CEMENT
FOR INTERMEDIATE BALANCED PLUG
3/30/2024
FRAC; 8,640.0
IPERF; 8,640.0-8,650.0
PLUG; 8,625.0
Cement Plug; 8,518.0 ftKB
TUBING PUNCH; 8,105.0
GAS LIFT; 8,088.2
GAS LIFT; 7,538.4
GAS LIFT; 6,862.5
Intermediate String 1 Cement;
6,600.0 ftKB
GAS LIFT; 5,660.4
CUT; 3,912.0
SURFACE; 27.9-3,713.0
GAS LIFT; 2,833.2
NIPPLE; 505.4
CONDUCTOR; 28.0-110.0
1a. Well Status:SuspendedAbandonedOtherSPLUGOil 1b. Well Class:
20AAC 25.11020AAC 25.105 ExploratoryDevelopment
WDSPLGINJ WINJ No. of Completions: ___________________Stratigraphic TestService
6. Date Comp., Susp., or2. Operator Name:
Aband.:
15. API Number:7. Date Spudded:3. Address:
16. Well Name and Number:8. Date TD Reached:4a. Location of Well (Governmental Section):
Surface:
17. Field / Pool(s):Top of Productive Interval:
GL: 224' BF:
18. Property Designation:10. Plug Back Depth MD/TVD:Total Depth:
19. DNR Approval Number:11. Total Depth MD/TVD:4b. Location of Well (State Base Plane Coordinates, NAD 27):
Zone- 4y-x-Surface:
20. Thickness of Permafrost MD/TVD:12. SSSV Depth MD/TVD:Zone- 4y-x-TPI:
Zone- 4y-x-Total Depth:
5. Directional or Inclination Survey: Yes (attached) No 21. Re-drill/Lateral Top Window MD/TVD:13. Water Depth, if Offshore:
Submit electronic information per 20 AAC 25.050 N/A (ft MSL)
22. Logs Obtained:
N/A
23.
BOTTOM
110'B16"
2449'L-807.625"
5288'L-805.5"
6038'L-803.5"
25.NoYes24. Open to production or injection?
26.
NoYesWas hydraulic fracturing used during completion?
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Method of Operation (Flowing, gas lift, etc.):Date First Production:
Gas-MCF:Production forHours Tested:
Test Period
Oil Gravity - API (corr):Gas-MCF:CalculatedCasing Press:
Press. 24-Hour Rate
Sr Res EngSr Pet GeoSr Pet Eng
N/A
Water-Bbl:Oil-Bbl:
14 Gal cement on top of CIBP @ 8625'8518-8625'
Water-Bbl:
PRODUCTION TEST
N/A
Oil-Bbl:Date of Test:
Flow Tubing
SUSPENDED
8640-8650' MD and 5682-5692' TVD
Gas-Oil Ratio:Choke Size:
Per 20 AAC 25.283 (i)(2) attach electronic information
15.5#
9025'
Surface
5288'
62.5#
29.7#
110'
8210'Surface
DEPTH SET (MD)SIZE
N/A
PACKER SET (MD/TVD)
42"
9.875"
15 sx AS1
Surface 410 sx AS Lite, 290 sx
LiteCRETE
9.3#
Surface
8210'
3713'Surface
Surface
CASING WT. PER
FT.GRADE
12/3/2001
CEMENTING RECORD
5867175
1546' MD/ 1464' TVD
SETTING DEPTH TVD
5867138
TOP HOLE SIZE AMOUNT
PULLED
449442
449614
TOP
SETTING DEPTH MD
suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log,
spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar
locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary.
N/A
Kuparuk River Field/ Meltwater- Suspended
BOTTOM
50-103-20383-01-00
KRU 2P-415A
ADL0373112
869' FNL, 2226' FWL,Sec. 17, T8N, R7E, UM
2580' FSL, 2382' FWL, Sec. 16, T8N, R7E, UM
11/29/2001
9038' MD/ 6050' TVD
P.O. Box 100360, Anchorage, AK 99510-0360
5869007444186
2616' FSL, 2209' FWL, Sec. 16, T8N, R7E, UM
9. Ref Elevations: KB: 254'
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
ConocoPhillips Alaska, Inc.
WAG
Gas
3/17/2024
If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size
and Number; Date perf'd or liner run):
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
included above6.75"
TUBING RECORD
62.5 bbls Class G6.75"
8210'3.5"
Due within 30 days of Completion, Suspension, or AbandonmentForm 10-407 Revised 10/2022
8518' MD, 5571' TVD
14. Permit to Drill Number / Sundry:
201-226/ 323-404
By James Brooks at 8:30 am, Mar 20, 2024
Suspended
3/17/2024
JSB
RBDMS JSB 040424
xGDSR-4/23/24
Conventional Core(s): Yes No Sidewall Cores:
N/A
30.
MD TVD
Surface Surface
1546' 1464'
Top of Productive Interval
N/A
31. List of Attachments: Schematics, Summary of Operations
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Katherine O'Connor
Digital Signature with Date:Contact Email: katherine.oconnor@conocophillips.com
Contact Phone:(907) 263-3718
Senior Well Interventions Engineer
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing
the data pertinent to such interval).
Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed
descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid
saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory
information required by 20 AAC 25.071.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment; or 90 days after log acquisition, whichever occurs first.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis,
paleontological report, production or well test results, per 20 AAC 25.070.
Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated
pool is a completion.
TPI (Top of Producing Interval).
Authorized Name and
N/A - Suspended
INSTRUCTIONS
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Authorized Title:
Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic
diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a
well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071.
Formation Name at TD:
If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed).
Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired.
Yes No
Well tested? Yes No
28. CORE DATA
If Yes, list intervals and formations tested, briefly summarizing test results for
each. Attach separate pages if needed and submit detailed test info including
reports and Excel or ASCII tables per 20 AAC 25.071.
NAME
Permafrost - Top
Permafrost - Base
29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS
N/A - Suspended
Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov
Digitally signed by Katherine O'Connor
DN: CN=Katherine O'Connor, O=ConocoPhillips, OU=Wells
Group, E=katherine.oconnor@conocophillips.com, C=US
Reason: I am the author of this documentLocation:
Date: 2024.03.19 13:22:25-08'00'
Foxit PDF Editor Version: 13.0.0
Katherine
O'Connor
DTTMSTART JOBTYP SUMMARYOPS
10/5/2023 CHANGE WELL
TYPE
DRIFT & TAG @ 8812' RKB. BRUSH & FLUSH TBG DOWN TO 8700' RKB. DRIFT
TBG W/ DUMMY CIBP TO 8812' RKB. READY TO PUMP INHIBITED SEAWATER
& CIBP.
10/6/2023 CHANGE WELL
TYPE
LOAD TBG & LINER W/ 54 BBLS OF INHIBITED SEAWATER. FREEZE PROTECT
TBG W/ 23 BBLS DIESEL. READY FOR RELAY.
10/7/2023 CHANGE WELL
TYPE
SET TTS 2.63" CIBP MID ELEMENT @ 8625' RKB. MIT-T TO 2500 PSI, PASSED.
READY FOR S/L TO DUMP BAIL CEMENT.
12/17/2023 CHANGE WELL
TYPE
DUMP BAIL APPROX ~4 GALS OF CEMENT ON TOP OF CIBP @ 8625' RKB, IN
PROGRESS
12/18/2023 CHANGE WELL
TYPE
DUMP BAIL APPROX ~10 GALS OF CEMENT ON TOP OF CIBP @ 8625' RKB.
ESTIMATE TOC @ 8594' RKB. READY FOR SW TAG & MIT.
2/13/2024 CHANGE WELL
TYPE
SET 2.79" JUNK CATCHER @ 8147' RKB ( LIH 48" ), PULLED 1" OV FROM STA
#5 @ 8088' RKB, LEAVING OPEN POCKET, LRS NIGHT CREW TO PUMP CIRC-
OUT, RDMO, JOB IN PROGRESS.
2/13/2024 CHANGE WELL
TYPE
CIRC OUT POST SLICKLINE
PUMP 173 BBLS INHIBITED SW FOLLOWED BY 41 BBLS DSL DWN TBG
TAKING RETURNS UP THE IA TO A RAIN FOR RENT TANK. U-TUBE TBG X IA
UNTIL EQUALIZED, COMBO MIT TBG X IA TO 2500 PSI (PASS)
2/16/2024 CHANGE WELL
TYPE
SET 1" BTM LATCH DUMMY VLV IN STA 5 @ 8088' RKB, ATTEMPT MITT TO
2500 PSI (FAILED), JOB IN PROGRESS
2/17/2024 CHANGE WELL
TYPE
RUN CHECKSET ON 3.5" OK-1 TO TAP STA 5 1" BTM LATCH VAVLE BACK
INTO POCKET @ 8088' RKB. PERFORM MITT TO 2500 PSI (PASSED), PULL
2.79" CATCHER FROM 8147' RKB. READY FOR SW TAG & TEST.
2/28/2024 CHANGE WELL
TYPE
(SUSPEND WELL) FT LDS/GN'S, T POT (PASS) T PPPOT (PASS) IC POT (PASS)
IC PPPOT (PASS)
3/17/2024 CHANGE WELL
TYPE
STATE WITNESS (AUSTIN MCLEOD) TAG TOC @ 8518' RKB, TWO ATTEMPTS
FOR MITT FAILED (TXIA COMMUNICATION). DISCUSS WITH INSPECTOR AND
PERFORM CMIT TXIA (PASSED). READY FOR NEXT STEP.
2P-415 Suspend
Summary of Operations
Last Tag
Annotation Depth (ftKB) Wellbore End Date Last Mod By
Last Tag: RKB 8,806.0 2P-415A 5/18/2018 fergusp
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Pulled OV, reset DMY after circ out 2P-415A 2/17/2024 rogerba
Notes: General & Safety
Annotation End Date Last Mod By
NOTE: VIEW SCHEMATIC w/Alaska Schematic9.0 11/18/2010 haggea
Casing Strings
Csg Des OD (in) ID (in) Top (ftKB)
Set Depth
(ftKB)
Set Depth
(TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread
CONDUCTOR 16 15.06 28.0 110.0 110.0 62.50 H-40 WELDED
SURFACE 7 5/8 6.87 27.9 3,713.0 2,448.7 29.70 L-80 BTC Mod
PRODUCTION
5.5"x3.5" @ 8210'
5 1/2 4.95 25.4 9,025.8 6,038.6 15.50 L-80 BTC Mod
Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string
Top (ftKB)
23.1
Set Depth …
8,208.4
Set Depth …
5,286.6
String Max No…
3 1/2
Tubing Description
TUBING
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE-8rd
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
23.1 23.1 0.00 HANGER 8.000 FMC TUBING HANGER 3.500
505.4 503.4 10.68 NIPPLE 4.520 CAMCO DS NIPPLE CAMCO DS 2.875
2,833.1 2,112.4 67.32 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
5,660.4 3,245.4 60.33 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
6,862.5 4,067.7 29.58 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
7,538.4 4,676.8 26.90 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,088.1 5,176.1 23.40 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,131.6 5,216.1 22.99 SLEEVE-C 4.500 BAKER CMU NON-ELASTOMER
SLIDING SLEEVE w/CAMCO DS
PROFILE - CLOSED 11/14/2009
BAKER CMU 2.812
8,147.7 5,230.9 23.06 NIPPLE 3.750 CAMCO D NIPPLE CAMCO D 2.750
8,190.9 5,270.6 23.25 LOCATOR 4.500 BAKER 80-40 G-22 LOCATOR SUB BAKER 3.000
8,191.5 5,271.1 23.26 SEAL ASSY 4.000 BAKER G-22 SEAL ASSY BAKER 3.000
Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.)
Top (ftKB)
Top (TVD)
(ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in)
8,625.0 5,668.7 24.22 PLUG Set TTS CIBP (2.63" x 1.37' ) 10/7/2023 0.000
8,898.0 5,919.5 21.81 Plug Catcher WEATHERFORD PLUG
CATCHER
12/4/2001 0.000
Mandrel Inserts : excludes pulled inserts
Top (ftKB)
Top (TVD)
(ftKB)
Top
Incl (°)
St
ati
on
No
/S Serv
Valve
Type
Latch
Type
OD
(in)
TRO Run
(psi) Run Date Com Make Model
Port
Size (in)
2,833.1 2,112.4 67.32 1 GAS LIFT DMY BTM 1 0.0 12/4/2001 0.000
5,660.4 3,245.4 60.33 2 GAS LIFT GLV BTM 1 1,892.0 11/9/2014 0.156
6,862.5 4,067.7 29.58 3 GAS LIFT DMY BTM 1 0.0 12/4/2001 0.000
7,538.4 4,676.8 26.90 4 GAS LIFT DMY BTM 1 0.0 12/4/2001 0.000
8,088.1 5,176.1 23.40 5 GAS LIFT DMY BTM 1 0.0 2/16/2024 0.000
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft)Type Com
8,640.0 8,650.0 5,682.3 5,691.5 T-3, 2P-415 12/24/2001 6.0 IPERF HMX Chrgs, 60 deg ph
Stimulation Intervals
Top (ftKB) Btm (ftKB)
Inter
val
Num
ber Type Subtype Start Date
Proppant
Designed (lb)
Proppant
Total (lb)
Vol Clean
Total (bbl)
Vol Slurry
Total (bbl)
8,640.0 8,650.0 1 FRAC 12/24/2001 0.0 0.00 0.00
Cement Squeezes
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Des Com
Pump Start
Date
8,518.0 8,625.0 5,570.9 5,668.7 Cement Plug Dump bailed cement with Slickline on top of CIBP 12/18/2023
2P-415A, 3/18/2024 4:38:07 PM
Vertical schematic (actual)
PRODUCTION 5.5"x3.5" @
8210'; 25.4-9,025.8
Plug Catcher; 8,898.0
FRAC; 8,640.0
IPERF; 8,640.0-8,650.0
PLUG; 8,625.0
Cement Plug; 8,518.0 ftKB
GAS LIFT; 8,088.1
GAS LIFT; 7,538.4
GAS LIFT; 6,862.5
GAS LIFT; 5,660.4
SURFACE; 27.9-3,713.0
GAS LIFT; 2,833.1
NIPPLE; 505.4
CONDUCTOR; 28.0-110.0
KUP PROD
KB-Grd (ft)
34.50
RR Date
12/5/2001
Other Elev…
2P-415A
...
TD
Act Btm (ftKB)
9,038.0
Well Attributes
Field Name
MELTWATER
Wellbore API/UWI
501032038301
Wellbore Status
PROD
Max Angle & MD
Incl (°)
68.89
MD (ftKB)
5,168.44
WELLNAME WELLBORE2P-415A
Annotation
Last WO:
End DateH2S (ppm)
82
Date
12/21/2013
Comment
SSSV: NIPPLE
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating: 8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
9038' None
Casing Collapse
Structural
Conductor
Surface
Intermediate
Production
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
2/26/2024
3-1/2"
Packer: Baker G-2 Seal Assy
SSSV: None
Perforation Depth MD (ft):
L-80
3685'
8640-8650'
9000'
5682-5691'
5-1/2" x 3-1/2"
Perforation Depth TVD (ft):
110'
3713'
6039'9026'
16"
7-5/8"
82'
8208'
MD
110'
2449'
ConocoPhillips Alaska, Inc.
Length Size
Proposed Pools:
PRESENT WELL CONDITION SUMMARY
Meltwater Oil Pool -
Abandoned
TVD Burst
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0373112
201-226
P.O. Box 100360, Anchorage, AK 99510 50-103-20383-01-00
Kuparuk River Field Meltwater Oil Pool
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):
8191' MD and 5271' TVD
N/A
Katherine O'Connor
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
katherine.oconnor@conocophillips.com
(907) 263-3718
Well Interventions Engineer
KRU 2P-415A
6050' 8625' 5669' 852 psi 8625'
N/A
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Samantha Coldiron at 3:13 pm, Mar 06, 2024
324-146
Digitally signed by Katherine O'Connor
DN: CN=Katherine O'Connor, O=ConocoPhillips, OU=
Wells Group, E=katherine.oconnor@conocophillips.com,
C=US
Reason: I am the author of this document
Location:
Date: 2024.03.05 15:08:50-09'00'
Foxit PDF Editor Version: 13.0.0
Katherine
O'Connor
DSR-3/6/24SFD 3/21/2024
BOP test to 2500 psig; Annular preventer test to 2500 psig.
A variance to 20 AAC 25.112(a)(1)(A) is granted. Cement is not required from 100' below the base of the C-80 to 100' above the top
of the C-80. The variance is granted to allow an equally effective plug which includes the placement of a cement
plug from ~50' MD below the surface casing shoe in the open hole to 150' MD into the surface casing. (20 AAC 25.112(i))
A variance to the cement logging required in Other Order 196 is granted. Cement logging is not required.
XX
AOGCC inspection required after cutoff and before remedial cementing
10-407X
(X-Over at 8210' MD) SFD
VTL 3/22/2024JLC 3/22/2024
TOC @ ~7,000' MD per email
from C. O'Connor, CPAI,
3/18/2024 SFD
TOC @ ~7,000' MD per email
from C. O'Connor, CPAI,
3/18/2024 SFD
Last Tag
Annotation Depth (ftKB) Wellbore End Date Last Mod By
Last Tag: RKB 8,806.0 2P-415A 5/18/2018 fergusp
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Pulled OV, reset DMY after circ out 2P-415A 2/17/2024 rogerba
Notes: General & Safety
Annotation End Date Last Mod By
NOTE: VIEW SCHEMATIC w/Alaska Schematic9.0 11/18/2010 haggea
Casing Strings
Csg Des OD (in) ID (in) Top (ftKB)
Set Depth
(ftKB)
Set Depth
(TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread
CONDUCTOR 16 15.06 28.0 110.0 110.0 62.50 H-40 WELDED
SURFACE 7 5/8 6.87 27.9 3,713.0 2,448.7 29.70 L-80 BTC Mod
PRODUCTION
5.5"x3.5" @ 8210'
5 1/2 4.95 25.4 9,025.8 6,038.6 15.50 L-80 BTC Mod
Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string
Top (ftKB)
23.1
Set Depth
8,208.4
Set Depth
5,286.6
String Max No
3 1/2
Tubing Description
TUBING
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE-8rd
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
23.1 23.1 0.00 HANGER 8.000 FMC TUBING HANGER 3.500
505.4 503.4 10.68 NIPPLE 4.520 CAMCO DS NIPPLE CAMCO DS 2.875
2,833.1 2,112.4 67.32 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
5,660.4 3,245.4 60.33 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
6,862.5 4,067.7 29.58 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
7,538.4 4,676.8 26.90 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,088.1 5,176.1 23.40 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,131.6 5,216.1 22.99 SLEEVE-C 4.500 BAKER CMU NON-ELASTOMER
SLIDING SLEEVE w/CAMCO DS
PROFILE - CLOSED 11/14/2009
BAKER CMU 2.812
8,147.7 5,230.9 23.06 NIPPLE 3.750 CAMCO D NIPPLE CAMCO D 2.750
8,190.9 5,270.6 23.25 LOCATOR 4.500 BAKER 80-40 G-22 LOCATOR SUB BAKER 3.000
8,191.5 5,271.1 23.26 SEAL ASSY 4.000 BAKER G-22 SEAL ASSY BAKER 3.000
Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.)
Top (ftKB)
Top (TVD)
(ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in)
8,594.0 5,640.4 24.13 OTHER Dump bail cement on CIBP 12/18/2023 0.000
8,625.0 5,668.7 24.22 PLUG Set TTS CIBP (2.63" x 1.37' ) 10/7/2023 0.000
8,898.0 5,919.5 21.81 Plug Catcher WEATHERFORD PLUG
CATCHER
12/4/2001 0.000
Mandrel Inserts : excludes pulled inserts
Top (ftKB)
Top (TVD)
(ftKB)
Top
Incl (°)
St
ati
on
No
/S Serv
Valve
Type
Latch
Type
OD
(in)
TRO Run
(psi) Run Date Com Make Model
Port
Size (in)
2,833.1 2,112.4 67.32 1 GAS LIFT DMY BTM 1 0.0 12/4/2001 0.000
5,660.4 3,245.4 60.33 2 GAS LIFT GLV BTM 1 1,892.0 11/9/2014 0.156
6,862.5 4,067.7 29.58 3 GAS LIFT DMY BTM 1 0.0 12/4/2001 0.000
7,538.4 4,676.8 26.90 4 GAS LIFT DMY BTM 1 0.0 12/4/2001 0.000
8,088.1 5,176.1 23.40 5 GAS LIFT DMY BTM 1 0.0 2/16/2024 0.000
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft)Type Com
8,640.0 8,650.0 5,682.3 5,691.5 T-3, 2P-415 12/24/2001 6.0 IPERF HMX Chrgs, 60 deg ph
Stimulation Intervals
Top (ftKB) Btm (ftKB)
Inter
val
Num
ber Type Subtype Start Date
Proppant
Designed (lb)
Proppant
Total (lb)
Vol Clean
Total (bbl)
Vol Slurry
Total (bbl)
8,640.0 8,650.0 1 FRAC 12/24/2001 0.0 0.00 0.00
2P-415A, 2/18/2024 8:27:32 AM
Vertical schematic (actual)
PRODUCTION 5.5"x3.5" @
8210'; 25.4-9,025.8
Plug Catcher; 8,898.0
FRAC; 8,640.0
IPERF; 8,640.0-8,650.0
PLUG; 8,625.0
OTHER; 8,594.0
GAS LIFT; 8,088.1
GAS LIFT; 7,538.4
GAS LIFT; 6,862.5
GAS LIFT; 5,660.4
SURFACE; 27.9-3,713.0
GAS LIFT; 2,833.1
NIPPLE; 505.4
CONDUCTOR; 28.0-110.0
KUP PROD
KB-Grd (ft)
34.50
RR Date
12/5/2001
Other Elev
2P-415A
...
TD
Act Btm (ftKB)
9,038.0
Well Attributes
Field Name
MELTWATER
Wellbore API/UWI
501032038301
Wellbore Status
PROD
Max Angle & MD
Incl (°)
68.89
MD (ftKB)
5,168.44
WELLNAME WELLBORE2P-415A
Annotation
Last WO:
End DateH2S (ppm)
82
Date
12/21/2013
Comment
SSSV: NIPPLE
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating: 8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
9038' None
Casing Collapse
Structural
Conductor
Surface
Intermediate
Production
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
2/26/2024
3-1/2"
Packer: Baker G-2 Seal Assy
SSSV: None
Perforation Depth MD (ft):
L-80
3685'
8640-8650'
9000'
5682-5691'
5-1/2" x 3-1/2"
Perforation Depth TVD (ft):
110'
3713'
6039'9026'
16"
7-5/8"
82'
8208'
MD
110'
2449'
ConocoPhillips Alaska, Inc.
Length Size
Proposed Pools:
PRESENT WELL CONDITION SUMMARY
Meltwater Oil Pool -
Abandoned
TVD Burst
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0373112
201-226
P.O. Box 100360, Anchorage, AK 99510 50-103-20383-01-00
Kuparuk River Field Meltwater Oil Pool
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):
8191' MD and 5271' TVD
N/A
Katherine O'Connor
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
katherine.oconnor@conocophillips.com
(907) 263-3718
Well Interventions Engineer
KRU 2P-415A
6050' 8625' 5669' 852 psi 8625'
N/A
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 3:43 pm, Feb 12, 2024
Digitally signed by Katherine O'Connor
DN: CN=Katherine O'Connor, O=ConocoPhillips, OU=Wells
Group, E=katherine.oconnor@conocophillips.com, C=US
Reason: I am the author of this document
Location:
Date: 2024.02.12 15:30:42-09'00'
Foxit PDF Editor Version: 13.0.0
Katherine
O'Connor
DSR-2/13/24SFD 2/14/2024
Abandon
Last Tag
Annotation Depth (ftKB) Wellbore End Date Last Mod By
Last Tag: RKB 8,806.0 2P-415A 5/18/2018 fergusp
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Dump bail cement on CIBP 2P-415A 12/18/2023 fergusp
Notes: General & Safety
Annotation End Date Last Mod By
NOTE: VIEW SCHEMATIC w/Alaska Schematic9.0 11/18/2010 haggea
Casing Strings
Csg Des OD (in) ID (in) Top (ftKB)
Set Depth
(ftKB)
Set Depth
(TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread
CONDUCTOR 16 15.06 28.0 110.0 110.0 62.50 H-40 WELDED
SURFACE 7 5/8 6.87 27.9 3,713.0 2,448.7 29.70 L-80 BTC Mod
PRODUCTION
5.5"x3.5" @ 8210'
5 1/2 4.95 25.4 9,025.8 6,038.6 15.50 L-80 BTC Mod
Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string
Top (ftKB)
23.1
Set Depth
8,208.4
Set Depth
5,286.6
String Max No
3 1/2
Tubing Description
TUBING
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE-8rd
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
23.1 23.1 0.00 HANGER 8.000 FMC TUBING HANGER 3.500
505.4 503.4 10.68 NIPPLE 4.520 CAMCO DS NIPPLE CAMCO DS 2.875
2,833.1 2,112.4 67.32 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
5,660.4 3,245.4 60.33 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
6,862.5 4,067.7 29.58 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
7,538.4 4,676.8 26.90 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,088.1 5,176.1 23.40 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,131.6 5,216.1 22.99 SLEEVE-C 4.500 BAKER CMU NON-ELASTOMER
SLIDING SLEEVE w/CAMCO DS
PROFILE - CLOSED 11/14/2009
BAKER CMU 2.812
8,147.7 5,230.9 23.06 NIPPLE 3.750 CAMCO D NIPPLE CAMCO D 2.750
8,190.9 5,270.6 23.25 LOCATOR 4.500 BAKER 80-40 G-22 LOCATOR SUB BAKER 3.000
8,191.5 5,271.1 23.26 SEAL ASSY 4.000 BAKER G-22 SEAL ASSY BAKER 3.000
Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.)
Top (ftKB)
Top (TVD)
(ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in)
8,594.0 5,640.4 24.13 OTHER Dump bail cement on CIBP 12/18/2023 0.000
8,625.0 5,668.7 24.22 PLUG Set TTS CIBP (2.63" x 1.37' ) 10/7/2023 0.000
8,898.0 5,919.5 21.81 Plug Catcher WEATHERFORD PLUG
CATCHER
12/4/2001 0.000
Mandrel Inserts : excludes pulled inserts
Top (ftKB)
Top (TVD)
(ftKB)
Top
Incl (°)
St
ati
on
No
/S Serv
Valve
Type
Latch
Type
OD
(in)
TRO Run
(psi) Run Date Com Make Model
Port
Size (in)
2,833.1 2,112.4 67.32 1 GAS LIFT DMY BTM 1 0.0 12/4/2001 0.000
5,660.4 3,245.4 60.33 2 GAS LIFT GLV BTM 1 1,892.0 11/9/2014 0.156
6,862.5 4,067.7 29.58 3 GAS LIFT DMY BTM 1 0.0 12/4/2001 0.000
7,538.4 4,676.8 26.90 4 GAS LIFT DMY BTM 1 0.0 12/4/2001 0.000
8,088.1 5,176.1 23.40 5 GAS LIFT OV BTM 1 5/20/2018 0.156
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft)Type Com
8,640.0 8,650.0 5,682.3 5,691.5 T-3, 2P-415 12/24/2001 6.0 IPERF HMX Chrgs, 60 deg ph
Stimulation Intervals
Top (ftKB) Btm (ftKB)
Inter
val
Num
ber Type Subtype Start Date
Proppant
Designed (lb)
Proppant
Total (lb)
Vol Clean
Total (bbl)
Vol Slurry
Total (bbl)
8,640.0 8,650.0 1 FRAC 12/24/2001 0.0 0.00 0.00
2P-415A, 2/9/2024 9:59:49 AM
Vertical schematic (actual)
PRODUCTION 5.5"x3.5" @
8210'; 25.4-9,025.8
Plug Catcher; 8,898.0
FRAC; 8,640.0
IPERF; 8,640.0-8,650.0
PLUG; 8,625.0
OTHER; 8,594.0
GAS LIFT; 8,088.1
GAS LIFT; 7,538.4
GAS LIFT; 6,862.5
GAS LIFT; 5,660.4
SURFACE; 27.9-3,713.0
GAS LIFT; 2,833.1
NIPPLE; 505.4
CONDUCTOR; 28.0-110.0
KUP PROD
KB-Grd (ft)
34.50
RR Date
12/5/2001
Other Elev
2P-415A
...
TD
Act Btm (ftKB)
9,038.0
Well Attributes
Field Name
MELTWATER
Wellbore API/UWI
501032038301
Wellbore Status
PROD
Max Angle & MD
Incl (°)
68.89
MD (ftKB)
5,168.44
WELLNAME WELLBORE2P-415A
Annotation
Last WO:
End DateH2S (ppm)
82
Date
12/21/2013
Comment
SSSV: NIPPLE
CAUTION: This email originated from outside the State of Alaska mail system.
Do not click links or open attachments unless you recognize the sender and know
the content is safe.
You don't often get email from katherine.oconnor@conocophillips.com. Learn why this is important
From:Davies, Stephen F (OGC)
To:O"Connor, Katherine
Cc:Loepp, Victoria T (OGC); Dewhurst, Andrew D (OGC)
Subject:RE: [EXTERNAL]RE: KRU 2P-415A (Permit 201-226; Sundry 324-144) - Question
Date:Monday, March 18, 2024 1:17:37 PM
Thank you, Katherine. The erroneous calculated cement top of 5,782 MD is based on 62-1/2 barrels
of cement, 6-3/4 hole diameter, 30% hole washout, and a production casing string consisting of
only 5-1/2 pipe (forgetting that a significant portion of that production casing string actually
consists of 3-1/2 pipe). Could you please check the calculated TOCs on schematic drawings that
accompany all future Sundry Applications?
Thanks for your help,
Steve Davies
AOGCC
From: O'Connor, Katherine <Katherine.OConnor@conocophillips.com>
Sent: Monday, March 18, 2024 12:54 PM
To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC)
<andrew.dewhurst@alaska.gov>
Subject: RE: [EXTERNAL]RE: KRU 2P-415A (Permit 201-226; Sundry 324-144) - Question
Hi Steve
I just pulled the drilling record, and confirmed there was 62.5 bbls of cement pumped. Using
that and the 6-3/4 hole size, I calculate TOC outside the casing being ~7000 KB depending on
how many digits I carry through in my calcs. So unsure how whomever made the schematic
got to 5782 KB.
Thanks
Katherine
Katherine OConnor
CPF2 Interventions Engineer
907-263-3718 (O)
214-684-7400 (C)
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Monday, March 18, 2024 12:09 PM
To: O'Connor, Katherine <Katherine.OConnor@conocophillips.com>
Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC)
<andrew.dewhurst@alaska.gov>
Subject: [EXTERNAL]RE: KRU 2P-415A (Permit 201-226; Sundry 324-144) - Question
CAUTION:This email originated from outside of the organization. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
Hi Katherine,
Im reviewing CPAIs revised Sundry Application for KRU 2P-415A. This is a minor point, but to
ensure that AOGCCs well records are accurate could you please confirm the calculated top of
cement for the 5.5 x 3.5 production casing string that is shown on the wellbore schematic drawing
as 5,782 MD?
Cheers and Be Well,
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.davies@alaska.gov
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content is
safe.
You don't often get email from katherine.oconnor@conocophillips.com. Learn why this is
important
From:Davies, Stephen F (OGC)
To:AOGCC Records (CED sponsored)
Subject:FW: [EXTERNAL]RE: KRU 2P-415A (Permit 201-226; Sundry 324-146) - Question
Date:Tuesday, March 19, 2024 5:27:13 AM
Please append a copy of the email thread below to Sundry Application 324-146 for KRU 2P-415A.
Thanks,
Steve
From: Davies, Stephen F (OGC)
Sent: Monday, March 18, 2024 1:18 PM
To: O'Connor, Katherine <Katherine.OConnor@conocophillips.com>
Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC)
<andrew.dewhurst@alaska.gov>
Subject: RE: [EXTERNAL]RE: KRU 2P-415A (Permit 201-226; Sundry 324-146) - Question
Thank you, Katherine. The erroneous calculated cement top of 5,782’ MD is based on 62-1/2 barrels
of cement, 6-3/4” hole diameter, 30% hole washout, and a production casing string consisting of
only 5-1/2” pipe (forgetting that a significant portion of that production casing string actually
consists of 3-1/2” pipe). Could you please check the calculated TOCs on schematic drawings that
accompany all future Sundry Applications?
Thanks for your help,
Steve Davies
AOGCC
From: O'Connor, Katherine <Katherine.OConnor@conocophillips.com>
Sent: Monday, March 18, 2024 12:54 PM
To: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC)
<andrew.dewhurst@alaska.gov>
Subject: RE: [EXTERNAL]RE: KRU 2P-415A (Permit 201-226; Sundry 324-146) - Question
Hi Steve
I just pulled the drilling record, and confirmed there was 62.5 bbls of cement pumped. Using that
and the 6-3/4” hole size, I calculate TOC outside the casing being ~7000’ KB depending on how many
digits I carry through in my calcs. So unsure how whomever made the schematic got to 5782’ KB.
Thanks
Katherine
Katherine O’Connor
CPF2 Interventions Engineer
907-263-3718 (O)
214-684-7400 (C)
From: Davies, Stephen F (OGC) <steve.davies@alaska.gov>
Sent: Monday, March 18, 2024 12:09 PM
To: O'Connor, Katherine <Katherine.OConnor@conocophillips.com>
Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC)
<andrew.dewhurst@alaska.gov>
Subject: [EXTERNAL]RE: KRU 2P-415A (Permit 201-226; Sundry 324-146) - Question
CAUTION:This email originated from outside of the organization. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
Hi Katherine,
I’m reviewing CPAI’s revised Sundry Application for KRU 2P-415A. This is a minor point, but to
ensure that AOGCC’s well records are accurate could you please confirm the calculated top of
cement for the 5.5” x 3.5” production casing string that is shown on the wellbore schematic drawing
as 5,782’ MD?
Cheers and Be Well,
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.davies@alaska.gov
Originated: Delivered to:29ͲNovͲ23
Halliburton Alaska Oil and Gas Conservation Comm.
Wireline & PerforatingAttn.:Natural Resource Technician
Attn: Fanny Haroun 333 West 7th Avenue, Suite 100
6900 Arctic Blvd. Anchorage, Alaska99501
Anchorage, Alaska 99518
Office: 907Ͳ275Ͳ2605
FRS_ANC@halliburton.com
The technical data listed below is being submitted herewith. Please address any problems or
concernstotheattention of the sender above
WELL NAME API # SERVICE ORDER # FIELD NAME JOB TYPE DATA TYPE LOGGING DATE PRINTS # DIGITAL #
11CͲ22 50Ͳ029Ͳ23127Ͳ00 908965028 Kuparuk River Multi Finger Caliper Field & Processed 20ͲNovͲ23 0 1
21DͲ38 50Ͳ029Ͳ22961Ͳ00 908965029 Kuparuk River Multi Finger Caliper Field & Processed 21ͲNovͲ23 0 1
31JͲ107 50Ͳ029Ͳ23366Ͳ00 n/a Kuparuk River Packer Setting Record FieldͲFinal 9ͲOctͲ23 0 1
41LͲ03A 50Ͳ029Ͳ21182Ͳ01 908347301 Kuparuk River Multi Finger Caliper Field & Processed 7ͲJanͲ23 0 1
52LͲ313 50Ͳ103Ͳ20277Ͳ00 n/a Kuparuk River Plug Setting Record FieldͲFinal 26ͲNovͲ23 0 1
62MͲ24 50Ͳ103Ͳ20171Ͳ00 n/a Kuparuk River Patch Setting Record FieldͲFinal 21ͲDecͲ22 0 1
72PͲ415A 50Ͳ103Ͳ20383Ͳ01 n/a Kuparuk River Plug Setting Record FieldͲFinal 7ͲOctͲ23 0 1
82PͲ417 50Ͳ103Ͳ20375Ͳ00 n/a Kuparuk River Plug Setting Record FieldͲFinal 6ͲOctͲ23 0 1
92PͲ420 50Ͳ103Ͳ20391Ͳ00 n/a Kuparuk River Plug Setting Record FieldͲFinal 5ͲOctͲ23 0 1
10 2VͲ05 50Ͳ029Ͳ21051Ͳ00 n/a Kuparuk River Plug Setting Record FieldͲFinal 19ͲJulͲ23 0 1
PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF:
Fanny Haroun, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518
FRS_ANC@halliburton.com
Date:Signed:
Transmittal Date:
1. 1C-22 PTD:202-222 T38179
2.1D-38 PTD: 200-077 T38180
3. 1J-107 PTD: 207-107 T38181
4. 1L-03A PTD: 199-037 T38182
5. 2L-313 PTD: 198-219 T38183
6. 2M-24 PTD: 192-050 T38184
7. 2P-415A PTD: 201-226 T38185
8. 2P-417 PTD: 201-069 T38186
9. 2P-420 PTD: 201-182 T38187
10. 2V-05 PTD: 183-176 T38188
12/1/2023
72PͲ415A 50Ͳ103Ͳ20383Ͳ01 n/a Kuparuk River Plug Setting Record FieldͲFinal 7ͲOctͲ23 0 1
Kayla
Junke
Digitally signed
by Kayla Junke
Date:
2023.12.01
12:25:47 -09'00'
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address: Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
9038'None
Casing Collapse
Structural
Conductor
Surface
Intermediate
Production
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
(907) 263-3718
Well Interventions Engineer
KRU 2P-415A
6050' 9038' 6050' None
N/A
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
katherine.oconnor@conocophillips.com
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):
8191' MD and 5271' TVD
505' MD and 503' TVD
Katherine O'Connor
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0373112
201-226
P.O. Box 100360, Anchorage, AK 99510 50-103-20383-01-00
Kuparuk River Field Meltwater Oil Pool
ConocoPhillips Alaska, Inc.
Length Size
Proposed Pools:
PRESENT WELL CONDITION SUMMARY
N/A-Suspended
TVD Burst
8208'
MD
110'
2449'
110'
3713'
6039'9026'
16"
7-5/8"
82'
3685'
8640-8650'
9000'
5682-5691'
3-1/2" x 5-1/2"
Perforation Depth TVD (ft):
8/5/2023
3-1/2"
Packer: Baker G-22 Seal Assembly
SSSV: Camco DS Nipple
Perforation Depth MD (ft):
L-80
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 3:43 pm, Jul 18, 2023
323-404
Digitally signed by Katherine O'Connor
DN: CN=Katherine O'Connor, O=
ConocoPhillips, OU=Wells Group, E=
katherine.oconnor@conocophillips.com, C=US
Reason: I am the author of this document
Location:
Date: 2023.07.18 12:58:01-08'00'
Foxit PDF Editor Version: 12.1.2
Katherine
O'Connor
10-407
MDG 7/2/2023
X
VTL 7/26/2023 DSR-7/19/23
X
December 31, 2024
GCW 07/26/2023JLC 7/26/2023
07/26/23
Brett W.
Huber, Sr.
Digitally signed by
Brett W. Huber, Sr.
Date: 2023.07.26
19:43:34 -06'00'
RBDMS JSB 072823
2P-415A Suspension
Date WriƩen: 13 June 2023
ExecuƟon Date: August 5, 2023
Prepared by: Katherine O’Connor
Background & ObjecƟve
2P-415A was a producer that has been shut in since April 2019. This well is ultimately slated to be P&Ad
as part of the 2P pad abandonment. 2P pad does not have any facilities or surface line hookups, and the
pad is slated to be used as storage for Willow development project in 2026. This well will be suspended in
2023, and it is currently planned to be fully abandoned in 2024.
Well Data
Reservoir pressure 2/16/2017 = 1420 psi (.25 psi/ft)
MASP = 852 psi
Last tag 8808’ RKB on 5/18/18
Procedure
Wireline & Pumping
1. Fluid pack tubing and IA with corrosion inhibited seawater and freeze protect
2. Set CIBP @ ±8,625’ RKB (must be set within 50’ of the top of perforations)
3. Perform CMIT-TxIA to 2500 psi, record results
4. Perform MIT-T to 2500 psi, record results
5. Dump bail at least 30’ of cement on top of CIBP
6. Allow 72 hours for cement to harden, notify AOGCC at least 24 hours in advance
7. RIH and tag TOC, approx. 8595’ RKB (MUST BE AOGCC WITNESSED)
8. RU LRS as necessary. Perform pressure test to 1500 psi (MUST BE AOGCC WITNESSED)
9. Perform DDT and record results
DHD
1. Schedule wellsite inspection within 12 months of suspension approval
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Tag, OV swap. 2P-415A 5/20/2018 fergusp
Notes: General & Safety
Annotation End Date Last Mod By
NOTE: VIEW SCHEMATIC w/Alaska Schematic9.0 11/18/2010 haggea
Casing Strings
Csg Des OD (in) ID (in) Top (ftKB)
Set Depth
(ftKB)
Set Depth
(TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread
CONDUCTOR 16 15.06 28.0 110.0 110.0 62.50 H-40 WELDED
SURFACE 7 5/8 6.87 27.9 3,713.0 2,448.7 29.70 L-80 BTC Mod
PRODUCTION
5.5"x3.5" @ 8210'
5 1/2 4.95 25.4 9,025.8 6,038.6 15.50 L-80 BTC Mod
Tubing Strings: string max indicates LONGEST segment of string
Top (ftKB)
23.1
Set Depth …
8,208.4
Set Depth …
5,286.6
String Ma…
3 1/2
Tubing Description
TUBING
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE-8rd
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
23.1 23.1 0.00 HANGER 8.000 FMC TUBING HANGER 3.500
505.4 503.4 10.68 NIPPLE 4.520 CAMCO DS NIPPLE CAMCO DS 2.875
2,833.1 2,112.4 67.32 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
5,660.4 3,245.4 60.33 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
6,862.5 4,067.7 29.58 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
7,538.4 4,676.8 26.90 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,088.1 5,176.1 23.40 GAS LIFT 4.750 CAMCO KBG-2-9 CAMCO KBG-2-9 2.900
8,131.6 5,216.1 22.99 SLEEVE-C 4.500 BAKER CMU NON-ELASTOMER
SLIDING SLEEVE w/CAMCO DS
PROFILE - CLOSED 11/14/2009
BAKER CMU 2.812
8,147.7 5,230.9 23.06 NIPPLE 3.750 CAMCO D NIPPLE CAMCO D 2.750
8,190.9 5,270.6 23.25 LOCATOR 4.500 BAKER 80-40 G-22 LOCATOR SUB BAKER 3.000
8,191.5 5,271.1 23.26 SEAL ASSY 4.000 BAKER G-22 SEAL ASSY BAKER 3.000
Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.)
Top (ftKB)
Top (TVD)
(ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in)
8,898.0 5,919.5 21.81 Plug Catcher WEATHERFORD PLUG
CATCHER
12/4/2001 0.000
Mandrel Inserts : excludes pulled inserts
Top (ftKB)
Top (TVD)
(ftKB)
Top
Incl (°)
St
ati
on
No
/S Serv
Valve
Type
Latch
Type
OD
(in)
TRO Run
(psi) Run Date Com Make Model
Port
Size (in)
2,833.1 2,112.4 67.32 1 GAS LIFT DMY BTM 1 0.0 12/4/2001 0.000
5,660.4 3,245.4 60.33 2 GAS LIFT GLV BTM 1 1,892.0 11/9/2014 0.156
6,862.5 4,067.7 29.58 3 GAS LIFT DMY BTM 1 0.0 12/4/2001 0.000
7,538.4 4,676.8 26.90 4 GAS LIFT DMY BTM 1 0.0 12/4/2001 0.000
8,088.1 5,176.1 23.40 5 GAS LIFT OV BTM 1 5/20/2018 0.156
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft)Type Com
8,640.0 8,650.0 5,682.3 5,691.5 T-3, 2P-415 12/24/2001 6.0 IPERF HMX Chrgs, 60 deg ph
Stimulation Intervals
Top (ftKB) Btm (ftKB)
Inter
val
Num
ber Type Subtype Start Date
Proppant
Designed (lb)
Proppant
Total (lb)
Vol Clean
Total (bbl)
Vol Slurry
Total (bbl)
8,640.0 8,650.0 1 FRAC 12/24/2001 0.0 0.00 0.00
FRAC; 8,640.0
IPERF; 8,640.0-8,650.0
GAS LIFT; 8,088.1
GAS LIFT; 7,538.4
GAS LIFT; 6,862.5
GAS LIFT; 5,660.4
SURFACE; 27.9-3,713.0
GAS LIFT; 2,833.1
NIPPLE; 505.4
CONDUCTOR; 28.0-110.0
STATE OF ALASKA
ALAS',OIL AND GAS CONSERVATION COMMlooION
REPORT OF SUNDRY WELL OPERATIONS
1.Operations Performed: Abandon r Repair well r Plug Perforations r Perforate r Other ri SPJP to Gaslift
Alter Casing r Pull Tubing r Stimulate-Frac Waiverconversion
� r Time Extension �'""
Change Approved Program rOperat.Shutdown r Stimulate-Other r Re-enter Suspended Well r
2.Operator Name: 4.Well Class Before Work: 5.Permit to Drill Number:
ConocoPhillips Alaska, Inc. Development 17, Exploratory r 201-226
3.Address: 6.API Number:
P. O. Box 100360,Anchorage,Alaska 99510 Stratigraphic r Service ( '4 50-103-20383-01
7. Property Designation(Lease Number): 8.Well Name and Number: - - -
ADL373112 • I 2P-415A
9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s):„
Kuparuk River Field/Meltwater Oil Pool
11.Present Well Condition Summary:
Total Depth measured N. 9038 feet Plugs(measured) None
true vertical 6050 feet Junk(measured) None
Effective Depth measured 8898 feet Packer(measured) 8192
true vertical 5920 feet (true vertical) 5271
Casing - Length Size MD TVD Burst Collapse
CONDUCTOR 82 16 110 110
SURFACE 3685 10.65 3713 2449
PRODUCTION 9000 8.5 9026 6039
RECEIVED
JAN 0 8 2„ :
Perforation depth: Measured depth: 8640-8650 AO(;CC,
True Vertical Depth: 5682-5692 SCORED MAY 2 9 2014 AOGCC
Tubing(size,grade,MD,and TVD) 3.5, L-80,8208 MD,5287 TVD
Packers&SSSV(type,MD,and TVD) SEAL ASSY-BAKER G-22 SEAL ASSY @ 8192 MD and 5271 TVD
SSSV=CAMCO DS NIPPLE @ 505 MD and 503 TVD _
12.Stimulation or cement squeeze summary:
Intervals treated(measured): RBDMA.MAY 17 2014
Treatment descriptions including volumes used and final pressure:
13. Representative Daily Average Production or Injection Data
Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure
Prior to well operation 0 0 0 0 220
Subsequent to operation 594 183 69 1105 230
14.Attachments 15.Well Class after work:
Copies of Logs and Surveys run Exploratory r Development F.7 *Service r Stratigraphic r
16.Well Status after work: Oil,P' Gas r WDSPL r
Daily Report of Well Operations X
GSTOR r WIND r WAG r GINJ r SUSP r SPLUG r
17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt:
N/A
Contact Bob Christensen/Darrell Humphrey Email nil 39(a conoCophillips.com
Printed Name 7- Bob - .ristens-n Title NSK Production Engineering Specialist
Signature / Phone:659-7535 Date V 6)///2/
L'G F 5/2-0/14-
,et- sem :
2P-415A
DESCRIPTION OF WORK COMPLETED
SUMMARY
Date Event Summary
11/13/09 PULLED 2.81"JET PUMP (S/N PH-1103) @ 8132' RKB. SET 2.75" D CAT SV @ 8148'
RKB. IN PROGRESS.
1.1/14/09
CIRCULATED 167 BBL DSL DOWN IA UP TBG TO PRODUCTION. CLOSED CMU @
8132' RKB. MITIA 3510 PSI, PASSED. PULLED 2.75" CAT SV @ 8148' RKB. COMPLETE.
10/12/13 (AC EVAL): OA BLEED. Initial T/I/O= SI 375/10/180. OA FL near surface. Rigged up no flow
meter to OA with full bore jewelry. Bled off OA gas through full bore jewelry in 30 seconds
(FTS). Final T/I/O =SI 375/10/152.
11/23/13 SET 2.75" D-CAT @ 8148' RKB. IN PROGRESS
11/24/13 PULL DV&SET OV @ 8088' RKB; P.T. TBG & PULL CAT.
12/16/13 Well RTS
•
KUP PROD 2P-415A
ConocoPhillips u Well Attributes Max Angle&MD TD
Alaska.11lt'. Wellbore APIIUWI Field Name Wellbore Status ncl0) MD(ftKB) Act Btm(ftKB)
creeoeJ4nihp, 501032038301 MELTWATER PROD 68.89 5,168.44 9,038.0
..- Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) -Rig Release Date
2P-415A,11/25/20138.1105AM SSSV:NIPPLE 25 10/21/2007 Last WO: 34.50 12/52001
Vesical schematic(actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date
..................................................
Last Tag:SLM 8,681.0 6/11/2013 Rev Reason:GLV C/0,H2S hlpshk( 11/25/2013
Casing Strings
HANGER;23.1 ,..Y Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)... Wt/Len(I...Grade Top Thread
CONDUCTOR 16 15.062 28.0 110.0 110.0 62.50 H-40 WELDED
`y 1j uta1.PRODUCTION 5.5"x3.5" 5 1/2 4 950 B)SURFACE 7 5/8 6.875 27.9 ftKB) Set Depth(ND)... Wt/Len(I. Grade Top Thread
Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB)
2,448.7 29.70 L-80 BTC Mod
�� Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)... Wt/Len(I...Grade Top Thread
•. 6,038.6 15.50 L-80 BTC Mod
@8210'
Tubing Strings
- Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft..Set Depth(ND)(...Wt(lb/ft) Grade Top Connection
CONDUCTOR.29.0-110.0--A a. TUBING 31/2 2.992 23.1 8,208.4 5,286.6 9.301-80 I-UL-8,d
Completion Details
Nominal ID
Top(ftKB) Top(TVD)(ftKB) Top Inel(6) Item Des Com (in)
NIPPLE;505.4 23.1 23.1 0.00 HANGER FMC TUBING HANGER 3.500'
As
505.4 503.4 10.68 NIPPLE CAMCO DS NIPPLE 2.875
8,131.6 5,216.1 22.99 SLEEVE-C BAKER CMU NON-ELASTOMER SLIDING SLEEVE 2.812
w/CAMCO DS PROFILE-CLOSED 11/14/2009
8,147.7 5,230.9 23.06 NIPPLE CAMCO D NIPPLE 2.750
- 8,190.9 5,270.6 23.25 LOCATOR BAKER 80-40 G-22 LOCATOR SUB 3.000
8,191.5 5.271.1 23.26 SEAL ASSY BAKER G-22 SEAL ASSY 3 000
GAS LIFT,2833.1 1
Other In Hole(Wireline retrievable plugs,valves,pumps,fish,etc.)
Top(ND) Top Incl
: Top(ftKB) (ftKB) 0 Des Com Run late ID(in)
•
8,898.0 5,919.5 21.81 Plug Catcher WEATHERFORD PLUG CATCHER 12/4/2001 0.000
Perforations&Slots
Shot '
Den
SURFACE;27.9-9713.0-• • Top(ND) Bin,(ND) (shots/f
Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date t) Type Corn
8 640 0 8,650.0 5,682.3 5.601.5 1-3 20-410 12/24/2001 6.0 (PERF 'HMX Chrgs,60 deg ph
GAS UFT;5.660.4 • Stimulations&Treatments
Min Top Max Btm
- Depth Depth Top(ND) Btm(ND)
(ftKB) (ftKB) (ftKB) (ftKB) _ Type Date Com
- 8,640.0 8,650.0 5,682.3 5,691.5 FRAC 12/24200 BERMUDA FRAC,114,75081620 CARBOLITE,11.2
1 PPA ON PERFS
GAS LIFT;6,862.5 Mandrel Inserts
I St
ati G
Non
o Top(ND) Valve Latch Port Size TRO Run
Top(ftKB) (ftKB) Make Model OD(in) SeraType Type (i n) (psi) Run Date rn
1 2,833.1 2,112.4 CAMCO KBG-2-9 1 GAS LIFT DMY BTM 0.000 0.0'12/42001
GAS LIFT,7,538.4
2 5,660.4 3,245.4 CAMCO KBG-2-9 1 GAS LIFT DMY BTM 0.000 0.0 12/42001
3 6,862.5 4,067.7 CAMCO KBG-2-9' 1 GAS LIFT 'DMY BTM 0.000 0.0 12/42001
f 4 7,538.4 4,676.8 CAMCO KBG-2-9 1 GAS LIFT DMY BTM D.000 0.0 12/42001
GAS LIFT,8,088.1
5 8,088.1 5,176.1 CAMCO KBG-2-9 1 GAS LIFT ,OV BTM 0.313 0.0 1124/2013
Notes:General&Safety
SLEEVE-C;8,131.6 End Date Annotation
11/18/2010 NOTE:VIEW SCHEMATIC w/Alaska Schematic9.0
NIPPLE:8,147.7 /
> ,d
LOCATOR;8,190.6
SEAL ASSY;8,191.5
(PERF;EtrRA;8.650.0' J I I
FRAC;8,640.0�Ij
Plug Catcher;8,698.0
PRODUCTION 5.543.5'al
82101 25.49,025.8
•
~
~ ~,.
PROActive Dingnos~ic SenvicES, INC.
~~LL LC~G
~"RAIi~~~~T~~4~
To: AOGCC
Christine Mahnken
333 West 7th Avenue
Suite 100
Anchorage, Alaska 99501
(907] 659-5102
~
RE : Cased Hole/Open Hole/Mechanical Logs and/orTubing Inspection(Caliper/ MTT)
The technical data listed below is being submitl:ed herewith. Please acknowledge receipt by returning
a signed copy of this transmittal letter to the following :
ProActive Diagnostic Services, lnc.
Attn: Robert A. Richey
130 West Irrternatianal Airport Road
Suite C
Anchorage, AK 99518
Fax (907) 245-8952
1) Caliper Report 04Aug-09 2P-424A 1 Report / EQE 5~103-20475-01
2) Caliper Report 0&Aug-09 2R415A 1 Report / EDE 50-103-20383-0
'~`b ~'` ~~``~° ~ ~ ~~~
;~~-( ~~'!
~t~`'~_~U ~'
~ ~ ~=,~ ~ai~~, '~ ~ ?~C,~`i
~~~,~'~~,~
;~
,,
i .~, ~ _
~ ( -,~ ;~ - ii;,
Signed : %J _ pate ` _ _
~
Print Name:
PROACTIVE DIAGNOSTIC SERVICES, INC., 130 W. INTERNATIONAt AIRPORT RD SUITE C, ANCHORAGE, AK 99518
PHONE: (907)245-8951 FAx: (907)245~58952
E-NIAIL : „_ ~r~a` ~, WEBSITE i P~~i, ~ ' ~ 'f
;= r
. C:`,Documents and Settings\Owner~Desktop\Tzansmit_Conoco.docx
~
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Memory Magnetic Thickness Tool
Log Resul~s Summary
Company: ConocoPhiliips Alaska, Inc. Well: 2P-415A
Log Date: August 8, 2009 Field: Meltwater
Log No. : 10577 State: Ataska
Run NO.: 2(2"d MT~ API NO.: 50-103-20383-01
Pipe1 Desc.: 3.5" 9.3 Ib. L-80 8RD EUE Top l.og I~tv11.: Surface
Pipe1 Use: Tubing 8ot. Log Intvll.: 8,136 F~ (MD)
Pipe2 Desc.: 5.5" 15.5 Ib. L-80 BTC MOD Top Log Infirl1.: 3,710 Ft. (MD) (MTT only)
Pipe2 Use: Producfion Casing Bot. Log lntvl1.: 8,129 Ft. (MD) (MT7 only)
inspection Type : Corrosive & Mechanical Damage Inspection
COMMENTS :
Tfris Caliper/ MTT data is tied into the top of GCM 5~ 8,091 f~ (Driller's Depth).
This is the first fime this weil has been logged with a PDS Caliper and the second time this well has been
logged with a 12 Arm Magnetic Thickness Tooi (Ml'T). The MTT responds to the total thickness of inetal of
the 3_5" tubing and 5.5" production casing. A single 10Hz pass was made at 20 fpm.
The additional metal vo/ume of the 7 5/8" surface casinq prevented the normal fttnctioning of the MTT, so no
interpreta6le results are availab/e from the bottom of the 7~/8" surface casincl to surface.
INTERPRETATION OF CALIPER LOG RESULTS:
This log was run to assess the condi~on of the tubing wi~tlr respect to internal corrosive and mechanical
damage. The caliper recordings indicate the 3.5° tubing logged is in good condition, with no significant wall
penetrations, areas of cross-sectional wall loss, or I.D. restrictions recorded.
'
'
~
'
~
3.5" TUBING - MAXIMUM RECORDED WALL PENETRATIONS:
fdo significant wall penetrations (> 15%} are recorded throughout the tubing logged.
3.5" TUBING - MAXIMUM RECORDED CROSS-SECTIONA~ METAL LOSS:
No significant areas of cross-sectional wall loss (> 7%) are recorded throughout the tubing fogged.
3.5" TUBING - MAXIMUM RECQRDED ID RESTRICTIONS:
No sig~ificant I.D. resfictians are recorded throughout the tubing logged.
COMpARISON TO PREVIOUS MTT LOG RESULTS:
A comparison of the current 10Hz pass to the previous 10Hz pass (July 27, 2007) indicates no significant
change in metal thickness during the time between Iogs. The current log was pulled at 20 fpm while the
previous log was run at 40 fpm. The slower logging speed used for the current log ~esults in a much more
stable tool response to metal volume surrounding it, and is betieved to be a significant factor to any
differences between the two consecutive logs. The additional signal noise inherent to the previous log pulled
at 40 fpm appears to artifiaally influence averaged metal loss calcutations in the direction of less volumeiric
metal loss_
ProActive Giagnostic Services, Inc. / P.O. 6ox 1369, Stiafford, 7?: 77497
Phone: (28i) or (88S) 565-9085 Fari: {281} 565-1359 E-mail: PDS-dmemorylog.com
Pr~idhoe 6ay Field Office Phone: (907) 659-23fl~• Fax: (Q07} 659-231~
~C~ L - ~2 C~ 1 ~~i=~.3
~ ~
INTERPRETATlON OF MTI' LOG RESULTS :
The 10Hz MTT log ~esults cover the interval irom 3,710' to 8,129'. The MTT log results indicate overall metal
loss generally ranging from 1% to 6% beiween the bottom of the surface casing cL?i 3,71 Q' and GLM 4 cQ
7,532'. little, if any, general metal loss is indica#ed below GLM 4, down to the bottom of the togged interval
~ 8,129'. A plot of average metal thickness rel~tive ta the calibration point on a joint-by joint basis is
included in this report. Changes in r~etal volume are relative to the calibrafion point at 8,030', where the
readings are assumed to represent undamaged pipe. All other readings are relative to this reference paint,
which include influences from the 3.5° tubing and 5.5" production casing.
A maximum overall metal volume loss of 6°Jo is indicated in tubing joint 134 (4,214' - 4,244'), where patterns
of intermitten# isolated metal los.s, revealed by high-frequency responses from the 12 sensors MTT readings,
are apparent. Most of these pattems occur between the bottom of tl~e surface casing and GLM 4~ 7,532',
with more prominent events indicated above GLM 3~ 6,851'. Similar responses are also clearly indicated in
the same intenrals on the previous MTT recordngs. These pattems of apparent isolated metal loss point #o
potential areas of moderate volumetric metal loss to the outside of the tubing. Details of the current 10Hz
MTT recordings, along with the 2007 Delta Metal Thickness curve, over the interval (3,705'-4,280') are
included in this report to show theses pattems.
The percent arcumferential metal loss expressed in this summary is a percentage of the total metal the tool
' is responding to, which includes influences from tt~e 3.5" and 5.5° pipe. If atl of the metal loss is specific to
#he 3.5" iubing, the percent metal loss irom that pipe alone is probably higher than the numbers expressed.
i~e metal ioss indicated could be from either or boih the 3.5° tubing or 5.5" production casing.
,
~
~
' Field Engineer: G. Etherton Analyst: C. Waldrop (Ml~ /HY. Yang & J. Burton (MTT} Wifiess: C. Kennedy
ProActive Diagnostic 5en,~ices, Inc. / P.O. 6ox 1369, Stafford, T~:. 7?497
Phane: {281) or (~88) 565-9085 Fax: {281) 565-1369 E-mail: PDS~a~memorylc~g.com
Prudhoe Eay Field Office Phone: (90?) 659-~34? Fax: {9~7} 659-231~}
'
'
~
Correlation of Recorded Damag
~ Pipe 1 3.5 in (6.7' - 8133.7') Well:
Field:
Company:
Country:
Survey Date:
~
;e to Borehole Profile
2P~15A
Meltwater
ConocoPhillips Alaska, Inc.
USA
August 8, 2009
^ A pprox. T ool De via6on ^ A pprox. Borehol e Profil e
10
781
1563
2351
Prod 1
3152
D
~
~
3936 `L
c
t
~
n.
w
4715 0
5499
GLM 2
6298
GLM 3
7096
GLM 4
7899
GLM 5
256.1 8134
0 5 0 1 00
Dam age Pr ofile (% wall) / Tool D eviatio n (degr ees)
Bottom of Survey = 256.1
1
25 -~
50
75
100
a~
~ 125
~
Z
c
° 150
175
200
225
250
• •
PDS Report Overview
~, S . Body Region Analysis
Well: 2P-415A Survey Date: August 8, 2009
Field: r~telhvater Tool Type: UW MfC 24 No. 212330
Company: ConocoPhillips Alaska, Inc. Tool Size: 1.69
Country: USA No. of Fingers: 24
Anal st: C. Waldro
Tubing: Nom.OD Weight Grade & Thread Nom.ID Nom. Upset Upper len. Lower len.
3.5 ins 93 ppf L-80 8RD EUE 2.992 ins 3.5 ins 6.0 ins 6.0 ins
Penetration and Metal Loss (%wal~
~ penetration body ~ metal loss body
250
200
150
100
50 ~ -- -
i
~ 0 to 1 to ' 1O ro 20 to 40 to over
1% 10% 20% 40% 85% 85%
Number of'oints anal sed total = 271
pene. 0 109 162 0 0 0
loss 39 232 0 0 0 0
Damage Configuration ( body )
10
0
isolated general line ri~ hole / poss
pitting corrosion corrosion corcosion ible hole
Number of'oints dama ed total = 0
0 0 0 0 0
Damage Profile (% wall)
~ penetration body ;~ metal loss body
0 50 100
n
Prod 1
GLM 2
GLM 3
GLM 4
GLM 5
Bottom of Survey = 256.1
Analysis Overview page 2
'
~
~
1
'
~
PDS R~ RT INT TABI.
0 10
Pipe: 3.5 in 93 ppf L-80 8KD EUE Well:
Body Wall: 0.254 in Field:
Upset Wall: 0.254 in Company:
Nominal I.D.: 2.992 in Country:
Survey Date:
~
~LATION SHEEf
2 P-415A
Meltwater
ConocoPhillips Alaska, Inc.
USA
August 8, 2009
Joint
No. Jt. Deptfi
(Ft.) Pen.
llp,c~t
(Ins.) Pen.
Body
(Ins.) Pen.
% Metal
I_oss
% Min.
I.D.
Qns.)
Comments Damage Profile
(%wall)
0 50 100
.1 7 0 0.01 5 1 2.95 PUP
1 10 0 0.03 13 6 2.93
1.1 42 0 0.01 6 0 2.91 PUP
1.2 44 0 0.02 7 4 2.91 PUP
2 50 0 0.03 10 0 2.94
3 82 0 0.02 9 3 2.94
4 112 0 0.01 5 ' 2.93
5 143 0 0.03 11 5 2.94
6 174 0 0.03 13 4 2.93
7 205 0 0.03 10 5 2.93
8 236 0 0.03 12 ; 2.93
9 268 0 0.02 8 "L 2.94
10 298 0 0.03 12 5 2.93
11 328 O 0.03 11 4 2.94
12 360 0 0.02 8 Z 2.94
13 390 0 0.04 14 4 2.91
14 422 0 0.03 11 5 2.94
15 453 0 0.01 6 2 2.91
15.1 485 0 0.03 13 1 2.90 PUP
15.2 491 0 0 0 (1 2.88 Camco DS-Ni le
153 492 0 0.03 11 0 2.88 PUP
16 498 0 0.01 5 1 2.93
17 530 ~) 0.02 9 1 2.93
18 561 0 0.01 4 2 2.93
19 593 O 0.03 10 5 2.93
20 624 0 0.02 9 1 2.94
21 656 0 0.02 9 1 2.94
22 687 0 OA2 9 1 2.94
23 719 0 0.01 6 2 2.94
24 750 ll 0.01 5 2 2.95
25 781 0 OA2 9 1 2.95
26 812 0 0.03 13 5 2.93
27 842 0 0.03 11 2 2.95
28 874 0 0.01 4 2 2.95
29 905 0 0.02 9 2 2.95
30 937 0 0.01 5 1 2.94
31 968 0 0.03 10 2 2.91
32 1000 0 0.03 11 "; 2.94
33 1031 0 0.04 14 3 2.94
34 1063 U 0.02 9 1 2.94
35 1094 0 0.03 11 4 2.94
36 1124 tl 0.02 8 1 2.93
37 1156 U 0.04 14 4 2.94
38 1187 0 0.01 5 1 2.94
39 1218 0 0.01 6 1 2.94
40 1249 0 0.02 9 1 2.94
41 1281 0 0.01 6 2 2.94
42 1312 U 0.03 10 2 2.94
43 1344 0 0.01 6 1 2.95
44 1375 ~) 0.01 5 1 2.93
_ Penetration Body
Metal Loss Body
Page 1
•
PDS REPORT JOINT TABI.
Pipe: 3.5 in 9.3 ppf L-80 8RD EUE Well:
Body Wall: 0.254 in Field:
Upset Wall: 0.254 in Company:
Nominal I.D.: 2.992 in Country:
Survey Date:
~
-LATION SHEEf
2 P-415A
Mellwater
ConocoPhillips Alaska, Inc
USA
August 8, 2009
Joint
No. Jt. Depth
(Ft) Pc~n.
U~»c~t
(Ins.) Pen.
Body
(Ins.) Pen.
% Metal
Ioss
%, Min.
I.D.
(Ins.)
Comments Damage Profile
(%wall)
0 50 100
45 1407 0 0.03 11 3 2.94
46 1438 0 0.04 15 4 2.95
47 1470 ll 0.03 12 2 2.94
48 1501 0 0.03 12 4 2.95
49 1532 0 0.04 14 5 2.94
50 1563 0 0.03 13 2 2.93
51 1595 0 0.02 9 4 2.93
52 1626 0 0.03 13 4 2.98
53 1658 0 0.03 13 6 2.90
54 1689 0 0.03 13 6 2.94
55 1721 ll 0.03 13 5 2.96
56 1752 0 0.02 7 4 2.95
57 1784 0 0.04 15 4 2.94
58 1815 0 0.03 11 3 2.94
59 1847 U 0.04 14 4 2.95
60 1878 U 0.03 12 4 2.94
61 1910 U 0.02 7 2 2.93
62 1942 0 0.03 11 6 2.92
63 1973 0 0.03 13 6 2.96
64 2005 0 0.03 12 5 2.95
65 2037 0 0.03 13 3 2.96
66 2068 U 0.01 6 1 2.92
67 2100 l1 0.02 9 3 2.95
68 2131 U 0.03 13 2 2.94
69 2163 0 0.03 10 3 2.94
70 2194 (1 0.03 10 5 2.94
71 2225 0 0.03 12 4 2.95
72 2257 0 .03 11 3 2.94
73 2288 0 0.04 14 5 2.94
74 2320 0 0.03 12 7 2.94
75 2351 0 0.03 13 3 2.94
76 2383 0 0.04 14 3 2.94
77 2414 0 0.04 14 6 2.92
78 2446 0 0.03 13 6 2.94
79 2476 0 0.03 13 7 2.94
80 2507 (1 0.03 13 6 2.94
81 2539 0 0.03 11 4 2.94
82 2571 0 0.03 12 ; 2.95
83 2602 0 0.03 12 7 2.94
84 2633 0 OA2 9 2 2.94
85 2665 t) 0.03 11 5 2.95
86 2696 (~ 0.03 11 3 2.94
87 2728 t) 0.03 13 b 2.92
88 2759 (1 0.03 11 1 2.94
89 2790 0 .03 12 4 2.93
9.1 2821 0 0.02 9 2 2.94 PUP
89.2 2828 l) 0 0 0 N A Production Mandrel 1 Latch ~ 530
89.3 2833 U 0.01 6 1 2.95 PUP
90 2839 0 0.03 11 6 2.96
91 2871 0 0.03 13 2 2.94
Penetration Body
Metal Loss Body
Page 2
~
PDS REPORT JOINT TABI.
Pipe: 3.5 in 9.3 ppf L-80 8RD EUE Well:
Body Wall: 0.254 in Field:
Upset Wall: 0.254 in Company:
Nominal I.D.: 2.992 in Country:
Survey Date:
•
i LATI O N S H EE(-
2 P-415A
Meltwater
ConocoPhillips Alaska, Inc.
USA
August 8, 2009
Joint
No. Jt. Depth
(Ft.) f'~n.
UE»c~t
(In..) Pen.
Body
(Ins.) Pen.
% Metal
Loss
% Min.
I.D.
(Ins.)
Comments Damage Profile
(%wall)
0 50 100
92 _ 2902 0 0.02 9 4 2.95
93 2934 tl 0.02 9 5 2.95
94 2964 0 0.03 13 b 2.94
95 2995 l) 0.02 9 3 2.93
96 3027 0 0.03 11 5 2.94
97 3058 0 0.02 9 5 2.93
98 3089 0 0.03 12 6 2.94
99 3120 0 0.04 15 7 2.95
100 3152 0 0.02 8 3 2.97
101 3183 ll 0.04 15 3 2.96
102 3214 U 0.04 14 5 2.94
103 3246 l) 0.03 11 1 2.96
104 3277 0 0.02 7 3 2.94
105 3309 l) 0.03 13 (~ 2.94
106 3340 0 0.02 9 4 2.94
107 3372 U 0.03 1Z 4 2.94
108 _ 3403 t) 0.03 12 4 2.94
109 3435 (1 0.02 9 4 2.93
110 3466 0 0.03 12 5 2.93
111 3498 U 0.02 9 5 2.96
112 3529 0 0.04 14 6 2.93
113 3560 (1 0.02 7 2 2.95
114 3592 0 0.02 8 2 2.95
115 3623 0 0.03 11 2 2.94
116 3655 0 0.03 11 5 2.94
117 3686 (1 0.04 14 6 2.93
118 3718 O 0.03 12 6 2.94
119 _ 3749 U 0.03 12 E~ 2.93
120 3780 l1 0.03 10 6 2.97
121 3812 0 0.01 4 1 2.96
122 3843 t) 0.03 12 4 2.94
123 3874 O 0.02 7 Z 2.96
124 3906 t~ 0.01 2 U 2.95
125 3936 (~ 0.04 14 5 2.94
126 3967 l) 0.02 9 "s 2.95
127 3999 0 0.03 12 ; 2.94
128 4030 0 0.03 12 4 2.94
129 _ L__ 4062 l) 0.03 12 3 2.93
130 ~ 4093 0 0.03 12 ~ 2.94
131 4124 0 0.03 11 S 2.94
132 4153 t) 0.03 12 G 2.94
133 4183 O 0.02 8 3 2.96
134 4214 0 0.03 12 3 2.92
135 4245 U 0.02 9 2 2.94
136 4276 0 0.02 9 2 2.93
137 4308 t1 0.01 6 0 2.93
138 4339 U 0.02 7 2 2.94
139 4371 0 0.03 10 2 2.90
140 4402 0 0.03 11 2 2.92
141 4434 0 0.02 9 1 2.94
~ Penetration Body
Meta) Loss Body
Page 3
PDS REPORT JOINT TABI.
Pipe: 3.5 in 93 ppf L-80 8RD EUE Well:
Body Wall: 0.254 in Field:
Upset Wall: 0.254 in Cornpany:
Nominal I.D.: 2.992 in Country:
Survey Date:
~
~LATION SHEET
2 P-415A
Meltwater
ConocoPhillips Alaska, Inc.
USA
August 8, 2009
Joint
No. )t. Depth
(Ft.) I'c~ii.
l1E>~c~t
~In~.) Pen.
Body
(Ins.} Pen.
% Metal
Loss
% Min.
I.D.
(Ins.)
Comments Damage Profile
(%wall)
0 50 100
142 4465 0 0.03 11 Z 2.94
143 4-496 0 0.01 5 2 2.93
144 4528 0 0.02 9 2 2.94
145 4559 O 0.03 12 4 2.94
146 4590 0 0.03 11 3 2.94
147 46Z 1 0 0.03 11 4 2.93
148 4653 (1 0.03 12 4 2.94
149 4684 O 0.02 9 4 2.93
150 4715 t) 0.04 14 :3 2.94
151 4746 O 0.04 15 6 2.93
152 4777 tl 0.03 13 4 2.95
153 4808 ll 0.04 14 5 2.94
154 4840 tl 0.02 9 "L 2.93
155 4872 (1 0.03 10 4 2.93
156 4903 ll 0.03 13 4 2.91
157 4934 l) 0.03 13 4 2.93
158 4966 O 0.03 12 3 2.90
159 4998 O 0.02 £3 3 2.94
160 5029 U 0.03 11 2 2.93
161 5061 t) 0.03 12 5 2.93
162 5091 ll 0.03 12 4 2.93
163 5123 U 0.04 14 4 2.95
164 5154 O 0.03 11 3 2.94
165 5185 O 0.03 12 4 2.92
166 5217 0 0.04 14 ~ 2.91
167 5248 l) 0.02 9 :3 2.94
168 5280 U 0.04 15 ; 2.94
169 5311 t1 0.03 13 5 2.93
170 5342 0 0.03 13 ~ 2.94
171 5374 (1 0.02 8 i 2.95
172 5405 0 0.03 12 4 2.94
173 5436 l) 0.03 13 4 2.93
174 5467 O 0.03 10 2 2.93
175 5499 (1 0.03 13 3 2.94
176 5530 O 0.02 £~ 1 2.92
177 5561 O 0.02 9 Z 2.91
178 5594 ll 0.04 14 1 2.91
179 5625 0 0.04 15 ~' 2.91
179.1 5657 0 0.02 9 ~ 2.94 PUP
179.2 5663 0 0 0 l) N A GLM 2 Latch ~ 11:30
179.3 5669 0 0.02 8 Z 2.94 PUP
180 5674 (1 0.03 1"~ 4 2.94
181 5706 U 0.03 12 6 2.92
182 5736 0 0.03 13 5 2.90
183 5767 U 0.03 10 2 2.91
184 5798 0 0.02 7 2 2.93
185 5830 l) 0.02 9 3 2.93
186 5861 0 0.01 6 1 2.94
187 5892 0 0.03 13 6 2.93
188 5924 O 0.01 6 1 2.95
Penetration Body
Meta) Loss Body
Page 4
PDS REPORT OINT TABULATION SH~ET
1
Pipe: 3.5 in 93 ppf L-80 8RD EUE Well: 2P-415A
Body Wall: 0.254 in Field: Meltwater
Upset Wall: 0.254 in Company: ConocoPhillips Alaska, Inc.
Nominal I_D.: 2.992 in Country: USA
Survey Date: August 8, 2009
Joint
No. Jt. Depth
(Ft.) Pen.
Upse~t
{Ins.) Pen.
Body
(InsJ Pen.
% Metal
Ioss
% Min.
I.D.
(Ins.)
Comments Damage Profile
(%wall)
0 50 100
189 5955 0 0.02 8 2 2.95
190 5986 0 0.01 2 1 2 94
191 6018 0 0.02 9 4 2.94
192 6049 0 0.02 9 2 2.93
193 6080 0 0.03 13 2 2.92
194 6111 0 0.02 9 1 2.92
195 6143 0 0.03 12 4 2.93
196 6174 0 0.03 10 4 2.92
197 6204 0 0.02 ~) 2 2.93
198 6235 ll 0.01 S 1 2.93
199 6267 0 0.03 12 6 2.93
200 6298 0 0.03 12 4 2.89
201 6330 0 0.03 11 6 2.94
202 6361 0 0.03 10 4 2.94
203 6392 (1 0.02 9 2 2.94
204 6422 0 0.04 15 2 2.88
205 6454 0 0.02 9 2 2.92
206 6484 0 0.04 15 4 2.93
207 6516 ll 0.03 13 4 2.94
208 6547 0 0.03 13 6 2.95
209 6579 0 0.02 8 2 2.93
210 6611 ~ 0.04 14 6 2.93
211 6642 0 0.04 14 4 2.93
212 6673 0 0.04 15 4 2.94
213 6702 0 0.04 15 5 2.94
214 6734 (1 0.03 13 5 2.94
215 6765 0 0.03 13 5 2.93
216 6796 0 0.04 14 4 2.93
217 6827 0 0.03 13 5 2.94
217.1 6858 0 0.02 7 2 2.95 PUP
217.2 6864 0 0 0 0 N A GLM 3 Latch ~ 1030
2173 6870 (1 0.01 4 1 2.94 PUP
218 6877 0 0.01 5 2 2.96
219 6907 0 0.04 14 4 2.92
220 6939 0 0.03 13 3 2.94
221 6970 0 0.03 12 3 2.93
222 7001 0 0.04 15 3 2.92
223 7033 0 0.04 15 5 2.92
224 7064 0 0.02 9 3 2,91
225 7096 0 0.03 13 4 2.94
226 7127 (1 0.03 13 4 2.93
227 7158 (~ 0.04 15 6 2.94
228 7190 0 0.03 13 4 2.93
229 7221 0 0.03 13 4 2.93
230 7253 0 0.03 11 2 2.92
231 7284 0 0.03 11 2 2.94
232 7315 (~ 0.03 13 4 2.94
233 7347 0 0.04 14 :; 2.93
234 7378 0 0.03 1:3 (i 2.92
235 7410 O 0.03 13 6 2.94
Penetration Body
Metal Loss Body
Page 5
~
PDS REPORT JOINT TABI.
Pipe: 3.5 in 93 ppf L-80 8RD EUE Well:
Body Wall: 0.254 in Field:
Upset Wall: 0.254 in Company:
Nominal I.D.: 2.992 in Country:
Survey Date:
•
i LATI O N SH E EI-
2 P-415A
Meltwater
ConocoPhillips Alaska, Inc.
USA
August 8, 2009
Joint
No. JL Depth
(ft.) Pc~n.
UF~s<~t
(Ins.) Pen.
Body
Qns.) Pen.
% Metal
Loss
% Min.
I.D.
(Ins.)
Comments Damage Profile
(%wall)
0 50 100
236 7441 0 0.02 9 5 2.96
237 7472 0 0.03 1'L 4 2.95
238 7504 ll 0.03 13 4 2.92
238.1 7535 U 0.03 12 2 2.95 PUP
238.2 7540 0 0 0 0 N A GLM 4 Latch ~ 730
2383 7548 U 0.02 6 2 2.96 PUP
239 7554 0 0.01 1 2.94
240 7585 0 0.03 13 1 2.93
241 7616 0 0.03 13 3 2.93
242 7648 0 0.02 7 2 2.95
243 7679 0 0.03 13 4 2.93
244 7710 0 0.04 15 6 2.94
245 7742 0 0.03 12 2 2.92
246 7773 0 0.04 15 6 2.91
247 7805 0 0.03 11 2 2.93
248 7836 0 OA2 9 5 2.93
249 7867 U 0.04 15 6 2.93
250 7899 0 0.03 12 4 2.93
251 7930 0 0.03 12 ~ 2.91
252 7960 0 0.03 12 5 2.92
253 7992 U 0.04 15 6 2.93
254 8023 t) 0.03 12 6 2.91
255 8054 0 0.02 S 2 2.93
255.1 8086 0 0.02 7 "L 2.97 PUP
255.2 8091 0 0 0 0 N A GLM 5 Latch ~ 2:30
2553 8097 O 0.01 2 1 2.96 PUP
256 8104 0 0.01 4 1 2.95
256.1 8134 0 0 0 0 2.81 Baker CMU Slidin Sleeve W Camco DS Profil
__ Penetration Body
Metal Loss Body
Page 6
OHz Avera e R• rded Metal Thickness Relativ Calibration Point
1 g
3.5" Tubing / 5.5" Production Casing Well: 2P-415A
Field: ,~telrivater
Company: ConocoPhillips Alaska, Inc.
Country: USA
Survey Date: August 8, 2009
^ Decrease ^ Increase
3780
4093
4402
4715
5029
5342
GLM 2
5674
0
~
v 5986
~
E ~
Z
6298 ~
~
c ~-
v
° 6611 0
GLM 3
6939
7253
GLM 4
7585
7899
GLM 5
256 8104
-50% 0 50%
Change in Metal Thickness (%)
Bottom of Survey = 256
120
130
140
150
160
170
180
190
200
210
220
230
240
250
' Details g~ 10Hz MTT Recordings Showing Intey~ittent Areas of Iso. Metal Loss
~ ~
2P-415A August 8, 2009
' PwoAcrivF oinq.~n+dc sE..dc~,, ~NC.
Database File. d.lwarriorldata\2p-415a1p1ot1.db
Dataset Pathname: ruN10HzPas
Presentation Format: 2.6_bw
, Dataset Creation: Mon Aug 10 15:36:53 2009
Charted by: Depth in Feet scaled 1:~40
' -20 2007 Defta Mtl. Thickness (%) 20 2.6
-~0 2009 Delta Mtl. Thickness {°/,) 20 -6.2
0 Line Speed (ft/min) -?00
I ,
' -- - - -
_ ~
Bottom of 7 5l8" Surtace
,
Tubin Co llar ~
3720
' asin Collar
Tubing
Jt.
118
'
~ 20 ^
07 Delta Metal Thickness
~ Apparent ~
, Tu bi Co llar ~ Isolatec
' 3760
Tubing
~ Jt. 119
asing Collar
'
-"'0 09 Delt a M etal Thickness
-- ~ -
Tu bing Co lla . - ~9~9~
' ~_ ._
Tubing
Jt
120
, .
3800 .
~ Tubi Collar
~ asin C~
' 38~0
Tubing
~ Jt. 121
_ .; .
-~... .~-
~
~ .~
~ ubin Collar =-r ~
- - ~t-
, Casin
~
3840
Tubing
Jt. 122
Collar
3860
Area of:
If'T
~d Metal
Area o
~d Metal
MTTP01 (rad) 12.6
MlTP12 (rad) 3.8
r Apparent Area o
~~'~Isolated Metal Los~
3880
Tubing Isolated Metal
Jt. 123
Colla~r900
3920
Tubing
Jt. 124
~ 3940
Collar
Tubing
Jt. 125
3960
'~Q~iO
Coliar
Tubing
Jt. 126
Area ofi
I~ f
~d Metal
Tubing
Jt. 127 Apparent Area
~`~ Isolated Metal I
Collar
4040
Tubing
Jt. 1 ~8
Collar
Tubing
Jt. 129
4080
Area
' Tubing Co llar ~~
~-- ,-,
-- ~~
-
4100
,
Tubing
asing Collar
Jt. 130
'
4120
Tu bin Co llar~~ ~
'
Tubing
Jt. 131
' 4140
' u bing Co llar ~~~-~
-~.~ --
:~
~
Casin Coll
_
4160
' Tubing
Jt. 132
,
u
bing
Co
llar 4'180
~
'
Tubing
'
~
asi - Jt. 133
Collar4~00
, ubing Collar ' ~
4220
, Tubing
Jt. 134
' - ,
~~ ~:Casing CoIla4240
Tubin Collar~- ~=-^~~
~ _ , F__,
~-~= -0~:~~~ Delt~ Metal Thickness
r _
~ ~007 DeRa Metal Thick
' 4~60
Tubing
' Jt. 135
Tubirtq Colla ~...
' -20 2007 Delta Mtl. Thickness (%) 20
-20 2009 DeRa Mtl. Thickness (%) 20
, a Line Speed (ft/min) -~00
Apparent Area oP~
~Isolated Metal
t Area
~ ~i
Metal L
Area
~ent Area of~
~lated Metal
Metal
~rent Area
R I V
Area of-
~~ ~ -
~d Metal
2.6 MTTP01 (rad)
-6.2 MTfP12 (rad)
12.6
3. 8
,
' ~
ConocoPhillips Alaska, Inc.
~RU 2P-415A
2P-415A - _
APi: 501032038301 Weli T e: PROD An le TS: d
~BING SSSV Type: Nipple Orig 12/24/2001 Angle @ TD: 21 deg @ 9038
$`10•
s
6oo Com leeon:
.
.
:.992~
Annular Fluid:
Last W/O:
Rev Reason:
TAG, OPEN
FACE SLEEVE, SET
3~i3.
~
seo PUMP
.
.
~a.~o
~
Reference L:
Ref l Date:
Last U date:
8/7/2007
Last Ta : --
8733
TD:
9038 ftKB
Last Ta Date: 7/26/2007 Max Hole An le: 69 de 5168
Cesing Strin - ALL STRINGS
l -
Descrlptlon
Size
T
Botinm
ND
YVt
Grade
__ Thread
'nO~'~
8
~q
~ __
CONDUCTOR 16.000 0 110 110 62.50 H-40 WELD
`
'
s.soo,
~
) SURFACE 7.650 0 3713 2449
-~ 29J0 L-80 B7C Mod
15.50) ~ PRODUCTION _
~__ b.500 0 8210 5288 15.50 L-80 BTC Mod
_
LINER 3.500 8210 9025 6038 9.30 L-80 BTC Mod
Tubin~
Strin~ TUBING
~
_
---size - ~ = T
op eawm ~ y~rt __ . _ ~raae rnreaa
---
3.500 _
-
0 -
8210 -----
5288 9.30 1-80 SRD EUE
`
m - ._
;m,
~ Perfarations SummarY
--
an,s 2 I __
Interval ND Zone ~ Shatus Ft SPF Date TY Comment
5~~
~--- --~
8640 - 8650 5682 - 5691
-- - L 10 6 12/24/2001 IPERF HMX Chrgs, 60 de h
t.~5o) ' _
_
Stimulations 8 Treatments
~ Irrterval Date T Comment
8640 - 8650 12/24I2001 FRAC BERMUDA FRAC, 114,750# 16%20 CARBOLITE, 11.2 PPA
~ ON PERFS
as LiR -.. __. . ... .._
~mmy Gas Lift MendrelsNalve s
arve 3 St MD TVD Man Mfr f Man Type V Mfr V Type V OD Latch Port TRO Date Run Vlv
sas~. Cmnt
i.~5o~ ' 1 2836 2113 CAMCO KBG-2-9 DMY 1.0 BTM 0.000 0 12i4/2001
l 2 5663 3247 CAMCO KBG-2-9 DMY 1.0 B7M 0.000 0 12/4l2001
I 3 6866 4071 CAMCO KBG-2-9 DMY 1.0 BTM 0.000
----- 0
- 12/4/2001
-
' 4 7541 4679 CAMCO KBG-2-9 DMY 1.0 BTM 0.000 0 12/4/2001
asl.iR -
~mmy -- - 5 8091 5179 CAMCO KBG-2-9 DMY 1.0 BTM 0.000 0 3/3/2002
a~ve a I
Other
U 5 A UIp~6tC~_ JEINELRY
j D 11/D T ~ -- Descrlptlon _ ID
i ~~ 505 503 NIP CAMCO 'DS' LANDING NIPPLE 2.875
8132 5216 SLEEVE-O BAKER CMU NON-ELASTOMER SLIDING SLEEVE W/CAMCO DS 2.812
PROFILE - OPENED 7/26/2007
8132 5216 PUMP JET PUMP (S# PH-1045, 10A RATIO, #10 THROAT, #10 NOZZLE) set 0.000
as ~rtt
~mmy 7/28/2007
aNe 5 II . I 8148 5231 NIP CAMCO 'D' NIPPLE 2J50
809`•
1
750 I 8191 5271 LOCATOR _
BAKER LOCATOR SUB 3.000
.
) f ~ ~ ~ -8192 5272 SEAL BAKER G-22 LOCATOR SEAL ASSEMBLY 80-40 3.000
8898 5919 Plug 0.000
Catcher
VEO -
8133,
t.500)
NIP
8149.
3.750)
4TOR
8192.
1.500)
SEAL
8193.
1.000)
FRAC
8650) - -
Pert ~
8650) . _...
~kher
8899.
3.500)
KkGESVED e~/09,r~009 ~4;15 281~17125 FDS (~J!2P
A~ug QQ Q9 01:17a (af~ k~c 90F 6~}2314 p.~F
~ _ e~!'1' ~~~~,~~t~o pua o~ . ; 9~: 9~ ~ , ~a~~~e~ee. . , ~. ~a~~e~aai~~M t
. ~ r'
~ ~,
~~iM' ~ ~~~
, ~h, . .~. _- ~°'.w'~7 .-~'_ ...~. !~T-
g~'~: ~1 ' ' ' ' . RI~'3a 'N!i
i3U8~'1GM~€! PtifUiR~ ~ W~7.i~: ~R-4'19 F)G.U: A+Ieltu~atQr
, : •
C]TsM # E?~srCR.iP'~Ctl3l~i ~ i.~. f3.0. 1.~1~4G'f'H
t~.b~
50 3.3 ~, q~ ~ S ~. ~d ~.65
3.3 X ~, Q ° ` ~ BfiD ' , .
~.~ ~ e~s ar~ •
8.6 SotYl W~ 6 E3T~ dApd x~I~+~RGPin
S.b" " oo v,d~.5 1
.~ ~ -~ erc r~va.~~ x ~ ~'.7~
z.~'z
2.~8!
2,A00
~,ue 3,7
.~ a
3.
~.T2G
~
S.~
B.BS
3 3.5 ~att~rn 8~C ~9 n x Eue ~1
'-~l h'' Cem~o ~ar! l~7de,r~ , M ~ i.tstc:h
,~ro -~a grc ~o~.~ x~ a er~ ~.~
x, {)4
~
4.7~6 ~~`~
,~S
a
+F ~.5 Bat~oyn ll~lodF'ri x d~P~+
s.~ " a m- ~
.~ Y x~o ~ sTC ~~~ a~ ~ru~ ~d ~.89~
~,
s.a ~ ~.b40
a.
~a ~Krs 6_5~
a,~
~ q.~
6 6 8aligl~t?G+4 ~ BTG idiod. Ilt ' 8
3.fi'x1" ~ ~ S Mkf ~ 1d - i ~l~h
3 6 To 7~1a -BO Mad.Pi~ x~ue ~rri
~..~~
~.892 ~.
4.
4.4SD ~•
~.~i
6.9
B ~,8 $o~ol'n if~D ~B(i B7'G .P~ k ~v~ er+~
•{~'i 0~ 4 1~f1 ~!+Tau ~ f S~L'
3.3 Ta afJ4 Pu x Eue • ~,98~.
~.~QB
~. ~
d.7~J~'
4 ~.~7
~r~l7
.~.9~
7 6CRt~13.5 L-~'Ett9 ~xF
.6 ~c 2.N7~ [~tncya'Ol~i" ]W F~lE L9R '
o ~.~ g~ - . ~ ~ 2
,~t75
2.y9~ Su~t1
4.5: !~
~4 ' ,
1 9{1
~ ~.QB
i
i~1C1~6: li~d1 iFii UI~ a DCIS~shear 1r~W4~.eAt 300~ e~E ~ R in
Painlod wii~Fi 4ahh~a -
~y.
~ ~ i'nu°.t • - •
, _... ~ _. . .. ....._-., _-_.... . . ._..~.....~_.__ ...-.....--..~ . ~ -• ~-- -' • . ~ ..~..~•~ .. ~- . . • ' i
t
. ~
r,~tc~Xt~ este~ta~t35 r~:15 i01431717,5
lu,g tf9 D9 41:17a f~ kyc
}r. o , ~ .
• . . ~ ~`i~S~fA$ ~i~
7 ~" ~aurfaCB ca:~',r,~
1~U.,LI~S AI~~Ca, ltt~
#~lhi C~~P
907 ~1 A~ p.5
f- -
bVELI.: ~P-4~'i6
pAT~: t~/Q~1'!}~
e
Conoc~illips
Alaska
e
V'..,·iê.-
!\ 1\ 0 5 2006
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
&
,~nchcrllge
June 06, 2006
Mr. Tom Maunder
Alaska Oil & Gas Commission
333 West ih Avenue, Suite 100
Anchorage, AK 99501
,~-. ~,\~.~\,,-í~:;:~)
,.:¡:~~t:'.._; \ ,\11~,~:;
t~~
Dear Mr. Maunder:
Enclosed please find a spreadsheet with a list of wells from the Kuparuk field (KRU). Each of
these wells was found to have a void in the conductor by surface casing annulus. The voids that
were greater than 6 feet were first filled with cement to a level of2.5 feet. The remaining
volume, 2.5 to 6 feet of annular void respectively was coated with a corrosion inhibiter,
RG2401, then filled with a viscous hydrocarbon based sealant, Royfi1l404B, engineered to
prevent water from entering the annular space. As per previous agreement with the AOGCC,
this letter and spreadsheet serves as notification that the treatments took place and meets the
requirements of form 10-404, Report of Sundry Operations.
The cement top-fill operation was completed on May 05, 2006. Schlumberger Well Services
mixed 15.7 ppg Arcticset I in a blender tub. The cement was pumped into the conductor bottom
and cemented up via a hose run to the existing top of cement. The corrosion inhibitor and
sealant were pumped in a similar manner on May 18th, 19th and 31 S\ 2006. The attached
spreadsheet presents the well name, top of cement depth prior to filling, and volumes used on
each conductor.
Please call Marie McConnell or myself at 907-659-7224, if you have any questions.
Sincerely,
ç("~f..~6 A~
C::>6! ~ 0 106
Attachment
8e \- dd~
e
e
ConocoPhillips Alaska Inc.
Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off
Kuparuk Field
June 6,2006
Well Initial top Vol. of cement Final top of Cement top
Name PTD # of cement um ed cement off date
ft bbls ft
·
ConocÓÁ,illips
Alaska
a: 'C': t:
~::~.;.? 1-.a-
¡Ji\i 1 -tt,
¡. "'
i,;'¡
Dil& G~s
Am~hî)rage
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
dDI-~:; 9..~
June 06, 2006
Mr. Tom Maunder
Alaska Oil & Gas Commission
333 West ih Avenue, Suite 100
Anchorage, AK 99501
..\--,
''-, ~".~.. .'...... '\1\( 't.,,;;,.... r
,~",'.}\ ",,~J)
':j t') In P, ç,'>
,:',:1 ,-',,:¡ -,.., )
Dear Mr. Maunder:
Enclosed please find a spreadsheet with a list of wells from the Kuparuk field (KRU). Each of
these wells was found to have a void in the conductor by surface casing annulus. The voids that
were greater than 6 feet were first filled with cement to a level of 2.5 feet. The remaining
volume, 2.5 to 6 feet of annular void respectively was coated with a corrosion inhibiter,
RG2401, then filled with a viscous hydrocarbon based sealant, Royfi1l404B, engineered to
prevent water from entering the annular space. As per previous agreement with the AOGCC,
this letter and spreadsheet serves as notification that the treatments took place and meets the
requirements of form 10-404, Report of Sundry Operations.
The cement top-fill operation was completed on May 05,2006. Schlumberger Well Services
mixed 15.7 ppg Arcticset I in a blender tub. The cement was pumped into the conductor bottom
and cemented up via a hose run to the existing top of cement. The corrosion inhibitor and
sealant were pumped in a similar manner on May 18th, 19th and 31 st, 2006. The attached
spreadsheet presents the well name, top of cement depth prior to filling, and volumes used on
each conductor.
Please call Marie McConnell or myself at 907-659-7224, if you have any questions.
ConocoPhillips Problem Well Supervisor
Attachment
#
.
.
ConocoPhillips Alaska Inc.
Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off
Kuparuk Field
June 6,2006
Vol. of cement Final top of Cement top
um ed cement off date
bbls ft
Royfill4048
vol.
al
Corrosion
inhibitor/
sealant date
5/19/2006
.
.
MICROFILMED
07/25/06
DO NOT PLACE
ANY NEW MATERIAL
UNDER THIS PAGE
F:\LaserFicbe\CvrPgs_ Inserts\Microfilm _ Marker.doc
WELL LOG TRANSl\1ITI AL
To:
State of AJaska
Alaska Oil and Gas Conservation C01TIm
Ann: Robin Deason
333 West 7tß Avenue, Suite 100
.~chorage, Alaska
July 06, 2004
RE: MWD Fonl1ation EvaJuation Logs 2P-415A
AK-l\.1l\f-11187
I LDWG formatted Disc with verification listing.
API#: 50-103-20383-01
/.;< ,5- J ~'í
PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL
LETTER TO THE ATTENTION OF:
Speny-Sun
Attn: Rob KaJish
6900 Arctic Blvd.
Anchorage, Alaska 995 18
Date: ! f.I ~ Ìv\.4"\
Signed: I t -.vJ 0 Jl"--/
e-:2 t) I - ;< ~ ,,,
:¡"
~t1 / -..;¿ 2. (~
/2,j- J,/
Sperry-Sun Drilling Ser..lices
LIS Scan Utility
$Revision: 3 $
LisLib $Revision: 4 $
Thu Jun 24 13:06:32 2004
Reel Header
Service name............ .LISTPE
Date. . . . . . . . . . . . . . . . . . . . .04/06/24
Origin. . . . . . . . . . . . . . . . . . . STS
Reel Name............... .m~KNOWN
Continuation Number..... .01
Previous Reel Name...... . UNKNOWN
Comments................ .STS LIS
Writing Library. Scientific Technical Services
Tape Header
Service name............ .LISTPE
Da t e. . . . . . . . . . . . . . . . . . . . . 04/06/24
Origin. . . . . . . . . . . . . . . . . . . STS
Tape Name............... .UNKNOWN
Continuation Number..... .01
Previous Tape Name...... .UNTI~OWN
Comments................ .STS LIS
Writing Library. Scientific Technical Services
Physical EOF
Comment Record
TAPE HEADER
Kuparuk River Field
MWD/MAD LOGS
#
WELL NAl\1E:
API NUMBER:
OPERATOR:
LOGGING COMPANY:
TAPE CREATION DATE:
#
JOB DATA
2P-415A
501032038301
PHILLIPS Alaska, Inc.
Sperry Sun
23-JUN-04
JOB NUMBER:
LOGGING ENGINEER:
OPERATOR WITNESS:
MWD RUN 1
AK-MM-11187
J. STRAHAN
D. GLADDEN
MWD Rill.J 2
AK-MM-11187
B. ZIEMKE
D. GLADDEN
MWD RUN 4
AK-MM-11187
J. STRAHAN
D. PRESNELL
#
SURFACE LOCATION
SECTION:
TOWNSHIP:
RANGE:
FNL:
FSL:
FEL:
FWL:
ELEVATION (FT FROM
KELLY BUSHING:
DERRICK FLOOR:
GROUND LEVEL:
17
8N
7E
869
2226
MSL 0)
.00
251.40
224.00
#
WELL CASING RECORD
1ST STRING
OPEN HOLE CASING DRILLERS
BIT SIZE (IN) SIZE (IN) DEPTH (FT)
9.875 16.000 120.0
2ND STRING
3RD STRING
PRODUCTION STRING
6.750
6.750
7.625
7.625
3713.0
3713.0
#
REI\1ARKS:
1. ALL DEPTHS ARE MEASURED DEPTHS (MD) UNLESS OTHERWISE
NOTED.
2. MWD RUN 1 IS DIRECTIONAL WITH DUAL GAMMA RAY (DGR)
UTILIZING
GEIGER-MUELLER TUBE DETECTORS, AND ELECTROMAGNETIC
WAVE
RESISTIVITY PHASE-4 (EWR4).
3. MWD RUNS 2&4 ARE DIRECTIONAL WITH DGR, EWR4,
COMPENSATED THERMAL
NEUTRON POROSITY (CTN), AND STABILIZED LITHO-DENSITY
(SLD) .
4. THIS WELL BORE SIDETRACKS FROM THE PARENT WELL
2P-415 AT 55751MD,
32061TVD.
5. SLD AND CTN DATA IN THE INTERVAL 8050'MD TO 88761MD
(5141-5899ITVD)
DISPLAY EFFECTS OF SEVERE BOREHOLE SPIRALING.
6. MWD DATA IS CONSIDERED PDC PER THE E-MAIL FROM D.
SCHWARTZ FOR S. MOOTHART
DATED 12/06/01.
7. MWD RUNS 1-3 REPRESENT WELL 2P-415A WITH API#:
50-103-20383-01. THIS WELL REACHED A TOTAL DEPTH
(TD)
OF 9038'MD, 6050'TVD.
SROP = SMOOTHED RATE OF PENETRATION WHILE DRILLING.
SGRC = SMOOTHED GAMMA RAY COMBINED.
SEXP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (EXTRA
SHALLOW SPACING) .
SESP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY
(SHALLOW SPACING) .
SEMP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (MEDIUM
SPACING) .
SEDP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (DEEP
SPACING) .
SFXE = SMOOTHED FORMATION EXPOSURE TIME.
TNPS = SMOOTHED THERMAL NEUTRON POROSITY (SS MATRIX,
FIXED HOLE SIZE) .
CTFA = SMOOTHED AVERAGE OF FAR DETECTOR'S COUNT RATE.
CTNA = SMOOTHED AVERAGE OF NEAR DETECTOR'S COUNT RATE.
SBD2 = SMOOTHED BULK DENSITY-COMPENSATED (LOW-COUNT
BIN) .
SC02 = SMOOTHED STANDOFF CORRECTION (LOW-COUNT BIN) .
SNP2 = SMOOTHED NEAR DETECTOR ONLY PHOTOELECTRIC
ABSORPTION FACTOR
(LOW-COUNT BIN) .
PARAMETERS USED IN POROSITY LOG PROCESSING:
HOLE SIZE: 6.125"
MUD WEIGHT: 10.0 PPG
MUD SALINITY: 28000-32000 PPM CHLORIDES
FORMATION WATER SALINITY: 22727 PPM CHLORIDES
FLUID DENSITY: 1.0 G/CC
MATRIX DENSITY: 2.65 G/CC
LITHOLOGY: SANDSTONE
$
File Header
Service name............ .STSLIB.001
Service Sub Level Name.. .
Version Number.......... .1.0.0
Date of Generation...... .04/06/24
Maximum Physical Record. .65535
File Type. .. ............ .LO
Previous File Name...... .STSLIB.OOO
Comment Record
FILE HEADER
FILE NUMBER:
EDITED MERGED MWD
Depth shifted and
DEPTH INCREMENT:
#
FILE SUMMARY
PBU TOOL CODE
GR
FET
RPX
RPS
RPM
RPD
ROP
PEF
NPHI
FCNT
NCNT
DRHO
RHOB
$
1
clipped curves; all bit runs merged.
.5000
START DEPTH
86.5
110.0
110.0
110.0
110.0
110.0
142.0
3703.0
3703.0
3703.0
3703.0
3711.0
3711.0
STOP DEPTH
8984.0
8991.0
8991.0
8991.0
8991.0
8991.0
9038.0
8875.5
8947.0
8947.5
8947.0
8875.5
8875.5
#
BASELINE CURVE FOR SHIFTS:
CURVE SHIFT DATA (MEASURED DEPTH)
--------- EQUIVALENT UNSHIFTED DEPTH ----
BASELINE DEPTH
$
#
MERGED
PBU
MWD
MWD
MWD
$
DATA SOURCE
TOOL CODE
#
REMARKS:
BIT RUN NO MERGE TOP
1 86.5
2 3719.0
4 5575.0
MERGE BASE
3719.0
5575.0
9038.0
MERGED MAIN PASS.
$
#
Data Format Specification Record
Data Record Type..................O
Data Specification Block Type.....O
Logging Direction................ .Down
Optical log depth units.......... .Feet
Data Reference Point............. .Undefined
Frame Spacing.................... .60 .1IN
Max frames per record............ .Undefined
Absent value..................... .-999.25
Depth Units.......................
Datum Specification Block sub-type...O
Name SeD/ice Order Units Size Nsam Rep Code Offset Channel
DEPT FT 4 1 68 0 1
ROP MWD FPH 4 1 68 4 2
GR MWD API 4 1 68 8 3
RPX MWD OHMM 4 1 68 12 4
RPS Mvm OHMM 4 1 68 16 5
RPM MWD OHMM 4 1 68 20 6
RPD MWD OHMM 4 1 68 24 7
FET MWD HR 4 1 68 28 8
NPHI MWD PU 4 1 68 32 9
FCNT MWD CP30 4 1 68 36 10
NCNT MWD CP30 4 1 68 40 11
RHOB MWD G/CC 4 1 68 44 12
DRHO MWD G/CC 4 1 68 48 13
PEF MWD B/E 4 1 68 52 14
First Last
Name Service Unit Min Max Mean Nsam Reading Reading
DEPT FT 86.5 9038 4562.25 17904 86.5 9038
ROP MWD FPH 0.4 1962.36 91.8785 17793 142 9038
GR MWD API 21.55 250.54 120.636 17796 86.5 8984
RPX MWD OHMM 0.29 1677.91 6.10096 17715 110 8991
RPS MWD OHMM 0.38 2000 25.2575 17715 110 8991
RPM MWD OHMM 0.4 2000 57.0422 17715 110 8991
RPD MWD OHMM 1.04 2000 63.266 17715 110 8991
FET MWD HR 0.24 370.37 1.12995 17715 110 8991
NPHI MWD PU 12.23 66.13 34.2318 10489 3703 8947
FCNT MWD CP30 100 679 252.756 10490 3703 8947.5
NCNT MWD CP30 12793 28562 18444.7 10489 3703 8947
RHOB MWD G/CC 2.005 3.364 2.37526 10330 3711 8875.5
DRHO MWD G/CC -0.082 0.932 0.0866901 10330 3711 8875.5
PEF MWD B/E 1.57 13.36 3.58888 10346 3703 8875.5
First Reading For Entire File......... .86.5
Last Reading For Entire File.......... .9038
File Trailer
Service name............ .STSLIB.001
Service Sub Level Name...
Version Number.......... .1.0.0
Date of Generation...... .04/06/24
Maximum Physical Record. .65535
F i 1 e Type................ LO
Next File Name.......... .STSLIB.002
Physical EOF
File Header
Service name............ .STSLIB.002
Service Sub Level Name...
Version Number.......... .1.0.0
Date of Generation...... .04/06/24
Maximum Physical Record. .65535
Fi Ie T~.'pe................ LO
Previous File Name...... .STSLIB.001
Comment Record
FILE HEADER
FILE NUMBER:
RAW MWD
Curves and log
BIT RUN NUMBER:
DEPTH INCREMENT:
#
FILE SUMMARY
VENDOR TOOL CODE
GR
RPX
RPS
RPM
RPD
FET
ROP
$
2
header data for each bit run in separate files.
1
.5000
START DEPTH
86.5
110.0
110.0
110.0
110.0
110.0
120.0
STOP DEPTH
3685.5
3678.5
3678.5
3678.5
3678.5
3678.5
3719.5
#
LOG HEADER DATA
DATE LOGGED:
SOFTWARE
SURFACE SOFTWARE VERSION:
DOWNHOLE SOFTWARE VERSION:
DATA TYPE (MEMORY OR REAL-TIME) :
TD DRILLER (FT):
TOP LOG INTERVAL (FT):
BOTTOM LOG INTERVAL (FT):
BIT ROTATING SPEED (RPM):
HOLE INCLINATION (DEG
MINIMUM ANGLE:
MAXIMUM ANGLE:
#
TOOL STRING (TOP TO
VENDOR TOOL CODE
DGR
Et'1R4
$
BOTTOM)
TOOL TYPE
DUAL GAMMA RAY
ELECTROMAG. RESIS. 4
#
BOREHOLE AND CASING DATA
OPEN HOLE BIT SIZE (IN):
DRILLER1S CASING DEPTH (FT):
#
BOREHOLE CONDITIONS
MUD TYPE:
MUD DENSITY (LB/G):
MUD VISCOSITY (S):
MUD PH:
MUD CHLORIDES (PPM):
FLUID LOSS (C3):
RESISTIVITY (OHMM) AT TEMPERATURE (DEGF)
MUD AT MEASURED TEMPERATURE (MT):
MUD AT MAX CIRCULATING TERMPERATURE:
MUD FILTRATE AT MT:
MUD CAKE AT MT:
#
NEUTRON TOOL
MATRIX:
MATRIX DENSITY:
HOLE CORRECTION (IN):
#
TOOL STANDOFF (IN):
EWR FREQUENCY (HZ):
#
REMARKS:
09-NOV-01
Insite
66.16
Memory
3719.0
.6
68.4
TOOL NUMBER
59583
138303
9.875
120.0
Water
9.65
56.0
8.9
27500
5.6
Based
.050
.029
.100
.120
58.0
104.0
56.0
58.0
$
#
Data Format Specification Record
Data Record Type. .................0
Data Specification Block Ty~e.....O
Logging Direction.... . . . . . . . . . . . . . Down
Optical log depth units.......... .Feet
Data Reference Point............. .Undefined
Frame Spacing.................... .60 .1IN
Max frames per record. ........... .Undefined
Absent value..................... .-999.25
Depth Uni t s . . . . . . . . . . . . . . . . . . . . . . .
Datum Specification Block sub-type...O
Name Service Order Units Size Nsam Rep Code Offset Channel
DEPT FT 4 1 68 0 1
ROP MWD010 FPH 4 1 68 4 2
GR MWD010 API 4 1 68 8 3
RPX MWD010 OHMM 4 1 68 12 4
RPS MWD010 OHMM 4 1 68 16 5
RPM MWD010 OHMM 4 1 68 20 6
RPD MWD010 OHMM 4 1 68 24 7
FET MWDOIO HR 4 1 68 28 8
First Last
Name Service Unit Min Max Mean Nsam Reading Reading
DEPT FT 86.5 3719.5 1903 7267 86.5 3719.5
ROP MWDOIO FPH 0 1962.36 95.3254 7157 120 3719.5
GR MWD010 API 21.55 144.88 85.9822 7199 86.5 3685.5
RPX MWD010 OHMM 0.29 1483.67 8.57147 7138 110 3678.5
RPS MWD010 OHMM 0.89 2000 55.2924 7138 110 3678.5
RPM MWD010 OHMM 0.94 2000 133.137 7138 110 3678.5
RPD MWD010 OHMM 1.86 2000 147.341 7138 110 3678.5
FET MWD010 HR 0.24 6.43 0.805779 7138 110 3678.5
First Reading For Entire File......... .86.5
Last Reading For Entire File.......... .3719.5
File Trailer
Service name............ .STSLIB.002
Service Sub Level Name...
Version Number.......... .1.0.0
Date of Generation...... .04/06/24
Maximum Physical Record. .65535
File Type............... .LO
Next File Name.......... .STSLIB.003
Physical EOF
File Header
Service name............ .STSLIB.003
Service Sub Level Name...
Version Number.......... .1.0.0
Date of Generation...... .04/06/24
Maximum Physical Record. .65535
File Type................LO
Previous File Name...... .STSLIB.002
Comment Record
FILE HEADER
FILE NUMBER:
RAW MWD
Curves and log
BIT RUN NUMBER:
DEPTH INCREMENT:
#
FILE SUMMARY
VENDOR TOOL CODE
FET
RPS
RPX
GR
PEF
RPM
RPD
NPHI
FCNT
NCNT
DRHO
RHOB
ROP
$
3
header data for each bit run in separate files.
2
.5000
START DEPTH
3673.5
3673.5
3673.5
3686.0
3703.0
3703.0
3703.0
3703.0
3703.0
3703.0
3711.0
3711.0
3720.0
#
LOG HEADER DATA
DATE LOGGED:
SOFTWARE
SURFACE SOFTWARE VERSION:
DOWNHOLE SOFTWARE VERSION:
DATA TYPE (MEMORY OR REAL-TIME) :
TD DRILLER (FT):
TOP LOG INTERVAL (FT):
BOTTOM LOG INTERVAL (FT):
BIT ROTATING SPEED (RPM):
HOLE INCLINATION (DEG
MINIMUM ANGLE:
MAXIMUM ANGLE:
#
TOOL STRING (TOP TO
VENDOR TOOL CODE
DGR
EWR4
CTN
SLD
$
#
STOP DEPTH
5574.5
5574.5
5574.5
5575.0
5574.5
5574.5
5574.5
5574.5
5574.5
5574.5
5574.5
5574.5
5575.0
BOTTOM)
TOOL TYPE
DUAL GAMMA RAY
ELECTROMAG. RESTS. 4
COMP THERMAL NEUTRON
STABILIZED LITHO DEN
BOREHOLE AND CASING DATA
OPEN HOLE BIT SIZE (IN):
DRILLER'S CASING DEPTH (FT):
#
BOREHOLE CONDITIONS
MUD TYPE:
MUD DENSITY (LB/G):
MUD VISCOSITY (S):
MUD PH:
MUD CHLORIDES (PPM):
FLUID LOSS (C3):
RESISTIVITY (OHMM) AT TEMPERATURE (DEGF)
MUD AT MEASURED TEMPERATURE (MT):
MUD AT MAX CIRCULATING TERMPERATURE:
MUD FILTRATE AT MT:
MUD CAKE AT MT:
#
19-NOV-01
Insite
66.16
Memory
5575.0
26.8
68.9
TOOL NUMBER
119578
94573
100547
100547
6.750
3713.0
Water
10.00
51.0
.5
28000
4.0
Based
.080
.052
.100
.140
80.0
125.8
70.0
70.0
NEUTRON TOOL
MATRIX:
MATRIX DENSITY:
HOLE CORRECTION (IN):
#
TOOL STANDOFF (IN):
EWR FREQUENCY (HZ):
#
REMARKS:
$
#
Data Format Specification Record
Data Record Type..................O
Data Specification Block Type.....O
Logging Direction... . . . . . . . . . . . . . . Down
Optical log depth units.......... .Feet
Data Reference Point............. .Undefined
Frame Spacing.................... .60 .1IN
Max frames per record............ . Undefined
Absent value. . . . . . . . . . . . . . . . . . . . . . - 999.25
Depth Units. . . . . . . . . . . . . . . . . . . . . . .
Datum Specification Block sub-type...O
Name Service Order Units Size Nsam Rep Code Offset Channel
DEPT FT 4 1 68 0 1
ROP MWD020 FPH 4 1 68 4 2
GR MWD020 API 4 1 68 8 3
RPX MWD020 OHMM 4 1 68 12 4
RPS MWD020 OHMM 4 1 68 16 5
RPM MWD020 OHMM 4 1 68 20 6
RPD MWD020 OHMM 4 1 68 24 7
FET MWD020 HR 4 1 68 28 8
NPHI MWD020 PU 4 1 68 32 9
FCNT MWD020 CP30 4 1 68 36 10
NCNT MWD020 CP30 4 1 68 40 11
RHOB MWD020 G/CC 4 1 68 44 12
DRHO MWD020 G/CC 4 1 68 48 13
PEF MWD020 B/E 4 1 68 52 14
First Last
Name Service Unit Min Max Mean Nsam Reading Reading
DEPT FT 3673.5 5575 4624.25 3804 3673.5 5575
ROP MWD020 FPH 4.63 328.87 106.162 3711 3720 5575
GR MWD020 API 58.67 250.54 146.529 3779 3686 5575
RPX MWD020 OHMM 0.33 1677.91 4.89165 3755 3673.5 5574.5
RPS MWD020 OHMM 0.38 1678.09 5.51519 3754 3673.5 5574.5
RPM MWD020 OHMM 0.4 2000 7.34393 3744 3703 5574.5
RPD MWD020 OHMM 2.58 1831.63 9.5135 3744 3703 5574.5
PET MWD020 HR 0.25 83.28 1.907 3755 3673.5 5574.5
NPHI MWD020 PU 20.75 57 40.3375 3744 3703 5574.5
FCNT MWD020 CP30 101 448 183.88 3744 3703 5574.5
NCNT MWD020 CP30 12793 23861 16872.6 3744 3703 5574.5
RHOB MWD020 G/CC 2.011 3.364 2.2863 3728 3711 5574.5
DRHO MWD020 G/CC -0.064 0.932 0.0969675 3728 3711 5574.5
PEF MWD020 B/E 1.57 13.36 3.81613 3744 3703 5574.5
First Reading For Entire File......... .3673.5
Last Reading For Entire File.......... .5575
File Trailer
Service name............ .STSLIB.003
Service Sub Level Name...
Version Number.......... .1.0.0
Date of Generation...... .04/06/24
Maximum Physical Record. .65535
File Type....... """" .LO
Next File Name.......... .STSLIB.004
Physical EOF
File Header
Service name............ .STSLIB.004
Service Sub Level Name...
Version Number.......... .1.0.0
Date of Generation...... .04/06/24
Maximum Physical Record. .65535
File Type................LO
Previous File Name...... .STSLIB.003
Comment Record
FILE HEADER
FILE NUMBER:
RAW MWD
Curves and log
BIT RUN NUMBER:
DEPTH INCREMENT:
#
FILE SUMMARY
VENDOR TOOL CODE
RPX
PEF
RPS
RPM
RPD
FET
FCNT
NCNT
RHOB
DRHO
NPHI
GR
ROP
$
4
header data for each bit run in separate files.
4
.5000
START DEPTH
5575.0
5575.0
5575.0
5575.0
5575.0
5575.0
5575.0
5575.0
5575.0
5575.0
5575.0
5575.5
5575.5
#
LOG HEADER DATA
DATE LOGGED:
SOFTWARE
SURFACE SOFTWARE VERSION:
DOWNHOLE SOFTWARE VERSION:
DATA TYPE (MEMORY OR REAL-TIME) :
TD DRILLER (FT):
TOP LOG INTERVAL (FT):
BOTTOM LOG INTERVAL (FT):
BIT ROTATING SPEED (RPM):
HOLE INCLINATION (DEG
MINIMUM ANGLE:
MAXIMUM ANGLE:
#
STOP DEPTH
8991.0
8875.5
8991.0
8991.0
8991.0
8991.0
8947.5
8947.0
8875.5
8875.5
8947.0
8984.0
9038.0
TOOL STRING (TOP TO BOTTOM)
VENDOR TOOL CODE TOOL TYPE
DGR DUAL GAMMA RAY
EWR4 ELECTROMAG. RESIS. 4
03-DEC-01
Insite
66.16
Memory
9038.0
21.0
61.4
TOOL NUMBER
149832
148574
CTN
SLD
$
COMP THERMAL NEUTRON
STABILIZED LITHO DEN
#
BOREHOLE AND CASING DATA
OPEN HOLE BIT SIZE (IN):
DRILLER'S CASING DEPTH (FT):
#
BOREHOLE CONDITIONS
MUD TYPE:
MUD DENSITY (LB/G):
MUD VISCOSITY (S):
MUD PH:
MUD CHLORIDES (PPM):
FLUID LOSS (C3):
RESISTIVITY (OHMM) AT TEMPERATURE (DEGF)
MUD AT MEASURED TEMPERATURE (MT):
MUD AT MAX CIRCULATING TERMPERATURE:
MUD FILTRATE AT MT:
MUD CAKE AT MT:
#
NEUTRON TOOL
MATRIX:
MATRIX DENSITY:
HOLE CORRECTION (IN):
#
TOOL STANDOFF (IN):
EWR FREQUENCY (HZ):
#
REMARKS:
$
#
Data Format Specification Record
Data Record Type..................O
Data Specification Block Type.....O
Logging Direction... . . . . . . . . . . . . . . Down
Optical log depth units.......... .Feet
Data Reference Point............. .Undefined
Frame Spacing.................... .60 .1IN
Max frames per record............ .Undefined
Absent value..................... .-999.25
Depth Units. . . . . . . . . . . . . . . . . . . . . . .
Datum Specification Block sub-type...O
111124
417
6.750
3713.0
Water
9.90
45.0
9.3
31000
5.0
Based
.140
.077
.120
.180
Name Service Order Units Size Nsam Rep Code Offset Channel
DEPT FT 4 1 68 0 1
ROP MWD040 FPH 4 1 68 4 2
GR MWD040 API 4 1 68 8 3
RPX MWD040 OHMM 4 1 68 12 4
RPS MWD040 OHMM 4 1 68 16 5
RPM MWD040 OHMM 4 1 68 20 6
RPD MWD040 OHMM 4 1 68 24 7
PET MWD040 HR 4 1 68 28 8
NPHI MWD040 PU 4 1 68 32 9
FCNT MWD040 CP30 4 1 68 36 10
NCNT MWD040 CP30 .:1 1 68 40 11
RHOB MWD040 G/CC 4 1 68 44 12
DRHO MWD040 G/CC 4 1 68 48 13
PEF MWD040 B/E 4 1 68 52 14
Name Service Unit
Min
Max
Mean Nsam
63.0
120.0
63.0
63.0
First
Reading
Last
Reading
DEPT FT 5575 9038 7306.5 6927 5575 9038
ROP MWD040 FPH 0.4 330.46 80.6503 6926 5575.5 9038
GR MWD040 API 65.7 213.28 142.875 6818 5575.5 8984
RPX MWD040 OHMM 0.78 18.88 4.17592 6833 5575 8991
RPS MWD040 OHMM 1.06 19.29 4.69261 6833 5575 8991
RPM MWD040 OHMM 1.03 20.07 4.78243 6833 5575 8991
RPD MWD040 OHrw1M 1.04 17.21 4.89069 6833 5575 8991
FET MWD040 HR 0.33 370.37 1.16976 6833 5575 8991
NPHI MWD040 PU 12.23 66.13 30.8427 6745 5575 8947
FCNT MWD040 CP30 100 679 290.982 6746 5575 8947.5
NCNT MWD040 CP30 13850 28562 19317.3 6745 5575 8947
RHOB MWD040 G/ee 2.005 3.03 2.4255 6602 5575 8875.5
DRHO MWD040 G/CC -0.082 0.675 0.0808867 6602 5575 8875.5
PEF MWD040 B/E 2.23 7.27 3.46001 6602 5575 8875.5
First Reading For Entire File......... .5575
Last Reading For Entire File.......... .9038
File Trailer
Service name............ .STSLIB.004
Service Sub Level Name...
Version Number.......... .1.0.0
Date of Generation...... .04/06/24
Maximum Physical Record. .65535
File Type................LO
Next File Name.......... .STSLIB.005
Physical EOF
Tape Trailer
Service name............ .LISTPE
Da t e. . . . . . . . . . . . . . . . . . . . . 04 / 06/ 24
Origin. . . . . . . . . . . . . . . . . . . STS
Tape Name............... . UNKNOWN
Continuation Number..... .01
Next Tape Name.......... . UNKNOWN
Comments................ .STS LIS
Writing Library.
Scientific Technical Services
Reel Trailer
Service name............ .LISTPE
Date. . . . . . . . . . . . . . . . . . . . .04/06/24
Or ig in. . . . . . . . . . . . . . . . . . . STS
Reel Name............... . UNKNOWN
Continuation Number..... .01
Next Reel Name.......... . UNKNOWN
Comments................ .STS LIS
Writing Library.
Scientific Technical Services
Physical EOF
Physical EOF
End Of LIS pile
~ '-( J~ À ~ D ~
DATA SUBMITTAL COMPLIANCE REPORT
1/6/2004
Permit to Drill 2012260
Well Name/No. KUPARUK RIV U MELT 2P-415A
Operator CONOCOPHILLIPS ALASKA INC
5¡t~d. c1Q fJðl/ tU4l
API No. 50-103-20383-01-00
MD
9038 -----
ND 6050 r
Completion Date 12/24/2001 ,..-
Completion Status
1-01L
Current Status 1-01L
UIC N
.. - - -
--------------------- --------------------------- ---------------------~- -- --- - ------ ---- ---
---------.--------------------- -----------._._-------
-- ----.- ---------- ------ ------
-----
REQUIRED INFORMATION
Mud Log No
Samples No
Directional Survey
Yes
------------
- ---_._---------------
------------
------------. --------
DATA INFORMATION
Types Electric or Other Logs Run:
Well Log Information:
Log/ Electr
Data Digital Dataset
Type Med/Frmt Number
(data taken from Logs Portion of Master Well Data Maint)
(
Name
Log Log Run
Scale Media No
Interval
Start Stop
OH/
CH
Received
Comments
Well Cores/Samples Information:
Name
Interval
Start Stop
Sent
Received
Sample
Set
Number Comments
ADDITIONAL INFORMATION
Well Cored? Y I tV
Daily History Received?
(ýYN
@N
Chips Received? ~
Formation Tops
Analysis
Received?
:!-!J.L-
('
c~~ I ~ S~ ~ -g ~ -c;;::::- WJty. =-.t«>-~ -::: ~¡; L -~=;:~=1 ~~
.
- ~ r../8_~5L!J.!:1J. ()~"~£1J.!."!;-~:;U _~,I~ i~_____-- -. --:.-=-----:-----.-~==---------. --====--=-=-===
Compliance Reviewed By: ------------ --------- Date: -_._~_..:L_J-_~~ t..{
/If r'f~ It aD f1I .
frw()þ./ì~ Jj~ ~
)'1 k ~l
~ g?Óå -gò e)l\
~
Annular Disposal during the first quarter of 2003:
h(l) h(2) h(3) Total for Freeze Previous New Start End Source Wells
Well Name Volume Volume Volume Quarter Protect Total Total Date Date
Volumes
3S-18 31501 100 0 31601 306 0 31907 January March 3S-15, 3S-16, 3S-22, 3S-08
2003 2003
3S-07 13415 100 0 13515 216 18255 31986 Dec 2002 Jan 2003 3S-10, 3S-15, 3S-09, 3S-14
CD2-48 20144 100 0 20244 375 11381 32000 Dec 2002 Feb 2003 CD2-45, CD2-35, CD2-08, CD2-28
CD2-17 2647 100 0 2747 372 15062 18181 May 2002 Feb 2003 CD2-08, CD2-48, CD2-46
CD2-22 30773 100 0 30873 380 0 31253 Feb 2003 March CD2-08, CD2-36, CD2-51
2003
3S-10 21104 100 0 21204 388 0 21592 March March 3S-21,3S-08
2003 2003
lC-22 26944 100 0 27044 0 0 27044 March March lC-190, lC-174
2003 2003
Puviaq #1 4616 100 0 4716 15 0 4731 March March Puviaq 1
2003 2003
if
~
l\f¡l
A
l"fi
h' hD'
IA h '
E ' dd '
hfi
2003
ota 0 urnes Into nnu I or W IC lsposa ut orzzatlon xplre urzng t e lrst quarter
Freeze Protect Total Volume Start End Source Wells
Total h(l) Total h(2) Total h(3) Fluids Injected Date Date
Well Name Volume Volume Volume Volume Status of Annulus
2P-420 9479 100 0 150 9729 Open, Freeze Protected April 2002 May 2002 2P-427, Heavenly
CD2-34 22895 100 0 372 23367 Open, Freeze Protected October Dec 2002 CD2-13, CD2-37, CD2-
2002 35
2P-415A 31181 100 0 52 31333 Open, Freeze Protected March 2002 April 2002 2P-441, 2P-431, Grizzly,
2P-422A, 2P-427,
Heavenly
CD2-26 29146 100 0 380 29626 Open, Freeze Protected September October CD2-38, CD2-44, CD2-
2002 2002 29, CD2-13
CD2-49 27474 100 0 386 27960 Open, Freeze Protected April 2002 May 2002 CD2-50, CD2-46, CD2-
22 b
t
ECEIVED ~
APR 1 6 2003 ~
Alaska Oil & Gas Cons. COmmiSSion&'
Anchorage ~
Re: Jet Pumped Wells
Subject: Re: Jet PU1l1ped \Vells
From: "NSK Problem vVell SUpV" <n 1617@'conoeophillips.eonl>
Date: Sat, 7 Dee 2002 14:07:01 -0900
To: Tonl Maunder <tonl_maunder@ladnlin.state.ak.us>
CC: "n 1617" <n 1617@~conoeophillips.coln>
Tom: I requested a list of surface powered jet pump wells from our PEls.
The following should be the current total for the Kuparuk area:
West Sak wells:
1C-123 (PTD 2010840) was recently 51 for high watercut
1C-135 (PTD 2012200) is a huff and puff well and was recently put on water
injection cycle
CPF 2 are as follows:
2L-307 (PTD 1982560)
2L-313 (PTD 1982190)
2L-315 (PTD 1982180)
2L-321 (PTD 1982620)
2L-325 (PTD 1982090)
2N-303 (PTD 2001690)
2N-304 (PTD 2011300)
2N-305 (PTD 2001350)
2N-318 (PTD 2001000)
2N-319 (PTD 1981970)
2N-332 (PTD 2000790)
2N-337 (PTD 1981220)
2N-339 (PTD 1981000)
...._~ 2P-415 (PTD 2012260)
There are no surface powered jet pump wells at CPF3.
I hope this answers your question. Let me know if you need more
information.
Jerry Dethlefs
ConocoPhillips Problem Well Supervisor
Tom Maunder < t Gill maunde r';:ì.Jadm in . s tat e . a k . lJ S >
12/06/2002 09:00 AM
To:
NSK Problem Well Supv/PPCO@Phillips
cc:
Subject:
Jet Pumped Wells
Pete and or Jerry,
I have some emails f h'l b
rom aWl e ack regarding the wells out there on
jet pumps. Would :lOU please pro 0'; ide an updated 1 i st lng of t.h~ i,vell ~
presently on jet pumps in greater KRU??
Thanks in advance.
To
~D kddt.ç,
A
I DO
ld o
th
d
t
12002
(
nnu ar lsposa url11g e secon quar er 0 0
.
h(l) h(2) h(3) Total for Freeze Previous New Start End Source Wells
Well Name Volume Volume Volume Quarter Protect Total Total Date Date
Volumes
CD2-15 10176 100 a 10276 371 10446 21093 March April CD2-25, CD2-50
2002 2002
2P-420 9479 100 0 9579 150 a 9729 April May 2002 2P-427, Heavenly
2002
2P-415A 26238 100 a 26338 52 4943 31333 March April 2P-431, 2P-422A, 2P-427,
2002 2002 Heavenly, Grizzly, 2P-441
CD2-49 27474 100 0 27574 386 0 27960 April May 2002 CD2-46, CD2-22, CD2-50
2002
CD2-17 14962 100 0 15062 372 a 15434 May 2002 June 2002 CD2-48, CD2-46
ID-ll 32102 100 0 32202 235 a 32437 May 2002 June 2002 1D-103
CD2-32 18536 100 0 18636 379 0 19015 June 2002 June 2002 CD2-19, CD2-41
IC-18 4176 100 a 4276 379 0 4655 June 2002 June 2002 1C-104
~
I \f¡ I
A
l"fi
h' hD'
I A th ' t'
E . dd '
h
d
2002
~-
ora 0 urnes Into nnu I or W IC lsposa u orzza Ion xplre url111( t e secon quarter o
o
Freeze Protect Total Volume Start End Source Wells
Total h(l) Total h(2) Total h(3) Fluids Injected Date Date
Well Name Volume Volume Volume Volume Status of Annulus
IJ-09 24202 100 a 330 24632 Open, Freeze Protected May 2001 May 2001 11-10
lC-17 33139 100 0 160 33399 Open, Freeze Protected May 2001 June 2001 lC-133, lC-12l, lC-
123, 1 C-127
CD2-42 33507 100 0 385 33992 Open, Freeze Protected June 2001 October CD2-24, CD2-33, CD2-
2001 15
2P-417 30965 100 a 887 31952 Open, Freeze Protected October March - 2P-422, Grizzly, 2P-45l,
2001 2002 2P-441, 2P-448, 2P-
422A,2P-420
lC-27 31766 100 0 153 32019 Open, Freeze Protected June 2001 July 2001 lC-127, lC-1l7, lC-
Ill, lC-123
.
A
I Do
ld '
h fi
if 2002
Jo/,
nnu ar lsposa urzng t e Irs! quarter 0 0
°
h(l) h(2) h(3) Total for Freeze Previous New Start End Source Wells
Well Name Volume Volume Volume Quarter Protect Total Total Date Date
Volumes
2P-417 25534 100 0 25634 887 5431 31952 October March 2P-448, 2P-422A, Grizzly #1,
2001 2002 2P-451, 2P-441, 2P-420
CD2-14 16138 100 0 16238 376 14459 31073 November March CD2-32, CD2-47, CD2-45
2001 2002
lC-14 9626 100 0 9726 0 22489 32215 October January 1R-36, 1C-24, 1C-109
2001 2002
CD2-15 10346 100 0 10446 371 0 10817 March March CD2-50
2002 2002
CD2-47 16459 100 0 16559 375 10415 27349 December January CD2-34, CD2-26,
2001 2002
CD2-45 22514 100 0 22614 377 0 22991 January February CD2-49, CD2-17
2002 2002
.~ (p 2P-415A 4843 100 0 4943 52 0 4995 March March Grizzly #1, 2P-431, 2P-441
2002 2002
CD2-26 0 a 0 0 380 0 380 -- -- Freeze protect only for CD2-26
CD2-49 0 0 0 0 386 0 386 Feb 2002 Feb 2002 Freeze protect only
(
~
l\f¡l
, t A
l'fi
h' hD'
IA h '
E ' dd °
h fi'
2002
ota 0 urnes In 0 nnu I or W IC lsposa ut orzzatlon xplre urzng t e lrst quarter °
,
Freeze Protect Total Volume Start End Source Wells
Total h(l) Total h(2) Total h(3) Fluids Injected Date Date
Well Name Volume Volume Volume Volume Status of Annulus
ID-32 23162 100 0 337 23599 Open, Freeze Protected January February ID-39
2001 2001
IJ -03 30024 100 0 0 30124 Open, Freeze Protected March 2001 May 2001 11-09, 11-14, 11-10
(
( STATE OF ALASKA (
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
1. Status of well Classification of Service Well
Oil 0 Gas 0 Suspended 0 Abandoned 0 Service 0 -,........->11""" --'!'"
2. Name of Operator . ", -\ ",:-; "" ,.;! 7. Permit Number
~ ~: .' - .' - ,--""'~ -
Phillips Alaska, Inc. 4 ~ ~.9~ ' 201-226
3. Address s.u roft.......'t '( 8. API Number
~.
P. O. Box 100360, Anchorage, AK 99510-0360 ~ "' ¥~ ....... (;".r_, r 50-103-20383-01
4. Location of well at surface -"- _.-- - -.- .--- -,-.-," '" .- ,~,~-:,'--,of-,!<,~-" " 9. Unit or Lease Name
- - -,-- -. ,
,"- - - . : _.;, ~
869' FNL, 2226' FWL, Sec. 17, T8N, R7E, UM ;-'. T, ¡ (ASP: 444186, 5869007) Kuparuk River Unit
-- - - - - \
At Top Producing Interval : , ~. Z'¡ ./> I : 10. Well Number
, ----------,'
2616' FSL, 2209' FWL, Sec. 16, T8N, R7E, UM \ ,~:- -:-:~:J f (ASP: 449442, 5867175) 2P-415A
At Total Depth 1, .--.-P-Þ------ ( 11. Field and Pool
2580' FSL, 2382' FWL, Sec. 16, T8N, R7E, UM;"'""---"":"'--'" (ASP: 449614, 5867138) Kuparuk River Field
5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. Meltwater Pool
RKB 254' AMSL ADL 373112, ALK 4998
12. Date Spudded 13. Date T.D. Reached 14. Date Comp., s~r Aband. 15. Water Depth, if offshore 16. No. of Completions
November 29, 2001 December 3, 2001 Decembe~ , 001 I!l> N/A feet MSL 1
17. Total Depth (MD + TVD) 18. Plug Back Depth (MD + TVD) 19. Directional Survey 20. Depth where SSSV set 21. Thickness of Permafrost
9038' MD 1 6050' TVD 8898' MD 1 5920' TVD YES 0 No 0 N/A feet MD 1546' (approx)
22. Type Electric or Other Logs Run
GR/Res/Neu Dens, Platform Express
23. CASING, LINER AND CEMENTING RECORD
SETTING DEPTH MD
CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED
16" 62.5# B Surface 110' 42" 15 sx AS 1
7.625" 29.7# L-80 Surface 3713' 9.875" 410 sx AS Lite, 290 sx LiteCrete
5.5" 15,5# L-80 Surface 8210' 6.75" 62.5 bbls Class G
3.5" 9.3# L-80 8210' 9025' 6.75" included above
24. Perforations open to Production (MD + TVD of Top and Bottom and 25. TUBING RECORD
interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD)
3.5" .. 8210' N/A
8640' - 8650' MD 5682' - 5692' TVD 6 spf 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC.
DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED
8640' - 8650' 114750# 16/20 carbolite in formation, 11.2 ppa on
perfs, left 26350# 16/20 and 12/18 prop in wellbore
27. PRODUCTION TEST
Date First Production Method of Operation (Flowing, gas lift, etc.)
January 1, 2002 Flowing
Date of Test Hours Tested Production for OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-Oil RATIO
1/27/2002 8.5 hours Test Period> 155 780 46 100 2590
Flow Tubing Casing Pressure Calculated Oll-BBl GAS-MCF WATER-BBL OIL GRAVITY - API (corr)
press. 298 psi 743 24-Hour Rate> 439 2201 130 not available
28. CORE DATA
Brief description of lithology, porosity, fractures, apparent dips and pressence of oil, gas or water. Submit core chips. RECEIVED
N/A FEa 062002
Alaska Oil & Gas Cons, Commission
Anchorage
-
Form 10-407 Rev. 7-1-80
CONTINUED ON REVERSE SIDE
Submit in duplicate
"'\ \'--"~~ ~ i;'~'" ~ ih ~ 1'\, ~ R B 0 M 5 B F l
(J r< \ \] \ '\\~ é"\ l-
FEB I I 2002
~J-
.29.
30.
GEOLOGIC MARKERS
FORMA TrON TESTS
NAME
MEAS.DEPTH
TRUE VERT. DEPTH
Include interval tested, pressure data, all fluids recovered and gravity.
GOR, and time of each phase.
T3
T2
8558'
8745'
5608'
5778'
Annulus left open - freeze protected with diesel.
31. LIST OF ATTACHMENTS
Summary of Daily Operations, Directional Survey
32. I hereby certify that the following is true and correct to the best of my knowledge.
Questions? Pat Reilly 265-6048
Signed
Title
Drillina Enaineering SuDervisor
Date ~ Fd
ð2-
Prepared by Sharon Allsup-Drake
INSTRUCTIONS
General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and
leases in Alaska,
)-"'"
Item 1: Classification of Service wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water
supply for injection, observation, injection for in-situ combustion.
Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other
spaces on this form and in any attachments,
Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in
item 16, and in item 24 show the producing intervals for the interval reported in item 27. Submit a separate form for each
additional interval to be separately produced, showing the data pertinent to such interval.
Item 21: Indicate whether from ground level (GL) or other elevation (OF, KB, etc,),
Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location
of the cementing tool.
Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection,
Shut-in, Other-explain, RECEIVED
Item 28: If no cores taken, indicate "none".
Form 10-407
FEE 0 6 2002
ORIGINAL
Alaska Oil & Gas Coos, Commission
Anchorage
("
(
Page 1 of 12
PHilliPS ALASKA INC.
Operations Summary Report
Legal Well Name:
Common Well Name:
Event Name:
Contractor Name:
Rig Name:
Date
11/3/2001
11/4/2001
11/5/2001
11/6/2001
2P-415
2P-415
ROT - DRILLING
Doyon
Doyon 141
Sub
From - To Hours Code Code Phase
00:00 - 02:00
02:00 - 08:00
08:00 - 12:00
12:00 - 00:00
2.00 MOVE MOVE MOVE
6.00 MOVE MOVE MOVE
4.00 MOVE MOVE MOVE
12.00 RIGMNT RGRP MOVE
00:00 - 00:00
24.00 RIGMNT RGRP MOVE
00:00 - 18:00
18.00 RIGMNT RGRP MOVE
18:00 - 20:00
2.00 DRILL
RIRD SURFAC
20:00 - 21 :30
1.50 RIGMNT RURD SURFAC
21 :30 - 23:00
23:00 - 00:00
1,50 DRILL PULD SURFAC
1.00 WELCT BOPE SURFAC
00:00 - 10:30
10,50 DRILL
PULD SURFAC
10:30 - 12:00
12:00 - 13:00
1.50 DRILL
1,00 DRILL
PULD SURFAC
SFTY SURFAC
13:00 - 17:00
4.00 RIGMNT RGRP SURFAC
17:00 - 18:00 1.00 DRILL PULD SURFAC
18:00 - 21:30 3.50 DRILL PULD SURFAC
21 :30 - 22:00 0.50 DRILL CIRC SURFAC
22:00 - 22:30 0.50 DRILL DRLG SURFAC
22:30 - 23:00 0,50 DRILL DRLG SURFAC
23:00 - 00:00 1.00 DRILL TRIP SURFAC
1117/2001 00:00 - 07:00 7.00 DRILL DRLG SURFAC
07:00 - 09:30 2,50 RIGMNT RGRP SURFAC
09:30 - 00:00 14.50 DRILL DRLG SURFAC
Spud Date: 11/4/2001
End:
Group:
Start: 11/2/2001
Rig Release: 12/6/2001
Rig Number: 141
Description of Operations
Prepare rig for rig move
Move rig from 2P-420 to 2P-415
Rig to get ready for spudding new well
RID Top Drive System, to be replaced with n
ew System. Remove electric Emago brake sy
stem to be taken to shop and repaired, and
reinstalled.
Change out Top Drive System, Repair Emago
electric brake system,New top drive in plac
e, making finial adjustments, Installing Ema
go electric brake. Loading DP in pipe shed,
N/U bell nipple.
Finish Top Drive installation, Finish Emago
electric brake repair, Repair hydraulics on p
ipe skate, load pipe shed with DP, offload s
pud mud and inspect derrick for tools and 10
ose items, Accept rig at 1800 hrs. 11/051
01
Rig up and calibrate Sperry Sun MWD and E
poch Mud Logs onto drawworks
Slip and cut drill line, adjust link tilt to P/U
DP
P/U 10 stands 4" DP
Test diverter system as per reg's, test accu
mulator, check and test all gas detection. E
very thing tested OK
P/U 4" DP and stand back in derrick, 105 st
ands total
P/U HWDP and stand in derrick
Hold pre-job safety meeting with both crews
and service company's, had group discussio
n on Safety, objectives, hazards and well pi
an,
Work on new top drive system, Install 2 new
stablizers on new top drive rail. Install & w
eld new tieback pad eyes to new torque tube
P/U 8" M 1 C Motor wi 1.2 AKO I 9 3/4" Strt
UBHS - Steam and warm motor
P/U BHA #1 - P/U and scribe tool, initilize
& program Smart Tools
Flood Conductor & Diverter System - Ck surf
ace lines and Diverter system for leaks"OK"
C/O Ice & CMT 89' to 120'
Spud Well - Drlg 120' to 165' MD (Bury MWD
)
SIB 1 std HWDP - P/U remaining BHA & 3 fie
x DCs
Dir Drlg 165' - 586 MD (KOP 250')
Trouble Shoot Elect problem in Top Drive -
Loose wire in control circuit board.
Dir Drlg 586' to 1500' MD (1426' TVD) ART
7.3 hrs, AST 9.5 hrs
Printed: 1/17/2002 10:11:46 AM
Legal Well Name:
Common Well Name:
Event Name:
Contractor Name:
Rig Name:
Date
11/8/2001
11/9/2001
11/10/2001
11/11/2001
(
f'
(
Page 2 of 12
PHilliPS ALASKA INC.
Operations Summary Report
2P-415
2P-415
ROT - DRILLING
Doyon
Doyon 141
Sub
From - To Hours Code Code Phase
00:00 - 07:00
07:00 - 07:30
07:30 - 09:30
09:30 - 10:00
10:00 -11:00
11:00 -12:00
12:00 - 00:00
00:00 - 12:00
12:00 - 21 :00
21 :00 - 23:00
23:00 - 23:30
23:30 - 00:00
00:00 - 03:00
03:00 - 03:30
03:30 - 09:00
09:00 - 09:30
09:30 - 14:30
14:30 - 16:00
16:00 - 16:30
16:30 - 17:00
17:00 - 18:00
18:00 -19:00
19:00 - 00:00
00:00 - 01 :00
01 :00 - 02:30
02:30 - 06:30
06:30 - 08:30
7.00 DRILL
0.50 DRILL
2.00 DRILL
DRLG SURFAC
CIRC SURFAC
WIPR SURFAC
0.50 RIGMNT RSRV SURFAC
1.00 DRILL WIPR SURFAC
1,00 DRILL REAM SURFAC
12.00 DRILL
12.00 DRILL
9.00 DRILL
2.00 DRILL
0.50 DRILL
0.50 DRILL
3.00 DRILL
0.50 DRILL
5.50 DRILL
0.50 DRILL
5.00 DRILL
1,50 DRILL
0.50 DRILL
0.50 DRILL
1.00 DRILL
1.00 DRILL
5.00 DRILL
1.00 DRILL
1,50 DRILL
4.00 DRILL
2,00 DRILL
DRLG SURFAC
DRLG SURFAC
DRLG SURFAC
CIRC SURFAC
WIPR SURFAC
REAM SURFAC
REAM SURFAC
TRIP SURFAC
CIRC SURFAC
Spud Date: 11/4/2001
End:
Group:
Start: 11/2/2001
Rig Release: 12/6/2001
Rig Number: 141
Description of Operations
Dir Drlg 1500' to 1850' MD ( 1683' TV D) AR
T .9 hrs , AST 3.8 hrs
Pump Sweep - Circu hole clean - Observe we
II (Static)
Wiper Trip - TOH to 190' (Tight 1650' - 1580
30K overpull)
Service Rig & Top Drive
TIH to 1460' - Tight hole
Kelly up Top Drive - Wash & Ream tight spot
@ 1460 -1475' - Wash to Bttm - CBU
Dir Drlg 1850' to 2500' MD ( 1977' TVD ) A
RT 4.5 hrs , AST 5.3 hrs
Dir Drlg 2500' to 3280' MD ART 7.9 hrs , A
ST1.7hrs
Dir Drlg 3280' to 3719' MD (2450' TVD) TO
7 5/8" Csg Pt. ART 6.3 hrs , AST 0.7 hrs
Pump wt/hi vis Sweep I good return - Circu
hole clean
TOH - Tight @ 3454'
Back Ream tight hole fl 3454' thru 3290'
Back ream 3290' to 2620' - Suspect cutting
bed buildup - 30k overpull - Some pack off p
roblems
TIH to 3719' - No tight hole - No fill -
Circu & Condition - CBU - Recip & Rotate (9
0-95 RPMs Motor bend MAX) Pump 3 - 20 bbl
Hi Wt/Hi Vis Sweeps back to back(circu rat
e 14 bpm) - Good cuttings return on first tw
0 sweeps - reduced amount on last one. CBU
OBSV SURFAC 0 b s e r v ewe II per pol icy - T 0 H to 2 6 2 0 I - T i g
ht
REAM SURFAC B a c k Rea m & p u m p 0 u t 0 f h 0 I e 2 62 0' to 1 3 7 3
TRIP SURFAC
PULD SURFAC
PULD SURFAC
PULD SURFAC
TRIP SURFAC
REAM SURFAC
REAM SURFAC
CIRC SURFAC
TRIP
SURFAC
RIRD SURFAC
TOH t/ BHA - 5-8k overpull - No Swab
Drain Motor - Brk& Grade Bit - LID Motor
LID Smart tools
P/U BHA #2 - HO cia assy
TIH wI HO assy to 1222' ( @ DP )
Wash & Ream wi HO assy - Pump Wt I Hi Vis
sweeps @ 2380' , 3330' & 3719' to maximiz
e hole cleaning - Good amount of cutting ret
urn with each sweep - Hi Torque spot @ 21
80' - Work until clean
Con't Wash & Ream to BTTM @ 3719' MD (24
50' TVD)
Circu & Condition - Pump Wt/Hi Vis Sweeps
( 2 back to back) - Circu hole clean good r
eturn of cutting on first sweep, looked clea
n after #2 sweep to surface - CBU
TOH - No tight hole - No swab - LID HO ass
y- Observe well per Phillips policy
Clean all drlg tools from floor - R/U 7 5/8"
Printed: 1/17/2002 10:11:46AM
~ ~ -
1~'PHILLlPS~.
( 'TjTfI )
~
~
Legal Well Name:
Common Well Name:
Event Name:
Contractor Name:
Rig Name:
Date
11/11/2001
11/12/2001
11/13/2001
("
("
-
From - To Hours Code Sub Phase
Code
06:30 - 08:30
08:30 - 16:00
16:00 - 19:30
19:30 - 20:00
20:00 - 22:00
22:00 - 23:00
23:00 - 00:00
00:00 - 02:00
02:00 - 04:00
04:00 - 06:00
06:00 - 12:00
12:00 - 12:30
12:30 - 17:30
17:30 - 19:30
19:30 - 22:30
22:30 - 00:00
00:00 - 00:30
00:30 - 01 :00
01 :00 - 02:00
02:00 - 05:00
05:00 - 06:30
06:30 - 07:30
PHilliPS ALASKA INC.
Operations Summary Report
2P-415
2P-415
ROT - DRILLING
Doyon
Doyon 141
2.00 DRILL
7.50 CASE
3.50 CASE
0,50 CASE
RIRD SURFAC
RUNC SURFAC
CIRC SURFAC
RURD SURFAC
2.00 CEMENl PUMP SURFAC
1.00 CEMEN" DISP SURFAC
1.00 CEMEN" PULD
2,00 CEMEN" PULD
2.00 WELCTL NUND
2.00 WELCTL NUND
6.00 WELCTL NUND
0.50 WELCTL BOPE
5.00 WELCTL BOPE
SURFAC
SURFAC
SURFAC
SURFAC
SURFAC
SURFAC
PROD
2.00 RIGMNT RSRV PROD
3.00 DRILL PULD PROD
1.50 DRILL
0,50 DRILL
0.50 DRILL
1.00 DRILL
3,00 DRILL
1,50 DRILL
1.00 DRILL
TRIP PROD
TRIP PROD
CIRC PROD
DEaT PROD
DRLG PROD
CIRC PROD
FIT
PROD
Page 3 of 12
Spud Date: 11/4/2001
End:
Group:
Start: 11/2/2001
Rig Release: 12/6/2001
Rig Number: 141
Description of Operations
Csg tools
PJSM - Run 7 5/8" 27,9# L-80 BTC-M (85
jts total) TAM collar @ 988.05 - SHOE @ 3
713' MD (2448' TV D)
Circu & Condition - Est & Stage up to 6 BPM
wi Franks fill tool - Condition mud for CMT
13,000 stks -Recip csg 10-12 ft - Full retu
r n s
LID Franks fill tool - P/U Dowell Schlumberg
er CMT head - Re-Estb circulation
CMT Csg - Pump 10 bbl CW100 , Pressure te
st lines 3000 psi, pump 30 bbls CW100, Dro
p Bttm plug, pump 30 bbls MudPUSH @ 10,5
ppg, pump 325 bbls Lead @ 10,7 ppg , pu
mp 124 bbls Tail @ 12.0 ppg Drop Bttm plug
, 5 bbl H2o, (See detail for chem. added) T
urn over to Rig for Disp. - ReCip csg show
ed signs of being sticky 300 bbls into pumpi
ng Lead -Landed on Hanger
Disp CMT wI Rig - Bump plug wI 1591 stks (
1600 stks calcu bump) Bump plug w/250 psi
( Lift psi 600) Had CMT to surface 400 stks
into disp (Total 10,7+ppg CMT to surface 12
0.2 bbls) CIP 10:50 PM - SI 5 min - Bleed
pressure off - Floats held
Flush Diverter & Lines - Clean cellar
RID CMT head - Clean equip off floor
NID Diverter System
M/U & Orient Csg Head - Test to 1000 psi
N/U 13 5/8" 5K BOPs & Flow lines
Set Test Plug - R/U to test
Test BOPs & Choke Manifold - Test 250psi I
3500psi . Test Ann. 250psi I 2500 psi. Hold
ea. test 5 min. Valve #3 on choke manifold
failed - Mechanic rebuilt valve ,retest "OK"
-(AOGCC rep Jeff Jones waived witness tes
t) - Install wear bushing
CIO Saver Sub on Top Drive
P/U BHA # 3 - Scribe,initilize & program too
I - Install scources
TIH -( Rotate slowly thru TAM @ 988' )
TIH - Tag @ 3622'
Estb Circu - Circu pipe volume clear air
Test Csg to 2500psi - On Chart for AOGCC -
Hold 30 min
Drlg FC, CMT, FS and 30' new hole to 3749'
MD ( 2462' TVD)
CBU - Displace fresh mud into system - Cir
cu & Condition mud to uniform 10.0 ppg Out
& In for LOT
Preform FIT - Hold 770 psi @ surface - Mud
10.0 ppg - OH 2462' TVD after 10 min loss 3
5 psi = 16.0 EMW
Printed: 1/17/2002 10:11:46AM
('
Page 4 of 12
PHilliPS ALASKA INC.
Operations Summary Report
Legal Well Name: 2P-415
Common Well Name: 2P-415
Event Name: ROT - DRILLING
Contractor Name: Doyon
Rig Name: Doyon 141
Date From - To Hours Code Sub Phase
Code
11/13/2001 07:30 - 08:30 1.00 DRILL DRLG PROD
08:30 - 09:00 0.50 DRILL CIRC PROD
09:00 - 00:00 15.00 DRILL DRLG PROD
11/14/2001 00:00 - 06:30 6.50 DRILL DRLG PROD
06:30 - 08:00 1.50 DRILL CIRC PROD
08:00 - 09:30 1.50 DRILL WIPR PROD
09:30 -11:00 1,50 RIGMNT RURD PROD
11:00 -12:00 1.00 DRILL WIPR PROD
12:00 - 00:00 12,00 DRILL DRLG PROD
11/15/2001
8.00 DRILL
DRLG PROD
00:00 - 08:00
08:00 - 09:30
1.50 DRILL
CIRC PROD
09:30 - 12:00 2.50 DRILL DRLG PROD
12:00 - 16:00 4,00 DRILL DRLG PROD
16:00 - 18:00 2.00 DRILL CIRC PROD
18:00 - 20:00 2.00 DRILL WIPR PROD
20:00 - 20:30 0.50 RIGMNT RSRV PROD
20:30 - 22:30 2.00 DRILL WIPR PROD
22:30 - 00:00 1,50 DRILL DRLG PROD
11/16/2001 00:00 - 06:30 6.50 DRILL DRLG PROD
06:30 - 09:00
2.50 DRILL
REAM PROD
09:00 - 09:30
09:30 - 12:00
0.50 DRILL
2.50 DRILL
REAM PROD
DRLG PROD
12:00 - 00:00
12,00 DRILL
DRLG PROD
Spud Date: 11/4/2001
End:
Group:
Start: 11/2/2001
Rig Release: 12/6/2001
Rig Number: 141
Description of Operations
Dir Drlg 3749' to 3830' MD
CBU - Establish PWD Base Line
Dir Drlg & Slide 3830' to 4820' MD (2906' T
VD) ART 11.2 hrs, AST.7 hrs
Dir Drlg & Slide 4820' to 5234' MD ART 3.
4 hrs , AST 1.2 hrs ECDs 12.05
CBU - Pump WtlHi Vis sweep - Circu hole cl
ean
T'OH tI Shoe@ 3713' - Monitor well per Phi I Ii
ps policy
Slip & Cut Drill Line - Service Top Drive &
Rig
rlH
ill
Dir Drlg & Slide 5234' to 5950' MD (3366' T
VD) ART 7.4 hrs , AST 1,4 hrs ECDs 11.7
**1**Note**** While drilling WtlHi Vis sweeps
were pumped @ 5234' , 5715' , & 5811'
Dïr Drlg & Slide 5950' to 6387' MD (3552' T
VD) ART 5.4 hrs , AST 1.2 hrs
H"igh ECDs (12.4)- Circu Sweeps - Pump Wtl
Hi Vis & followed with Hi Vis back to back -
After circu ECDs 11,6
Dir Drlg & Slide 6387' to 6510' MD (3601' T
VD) ART 1.0 hrs, AST .4 hrs
Dir Drlg & Slide 6510' to 6771' MD (3709' T
VD) ART 3.2 hrs, AST 0,3 hrs
Circu hole clean pumping tandem sweeps -
Monitor well per Phillips policy. Pryor ECDs
11,9 - Post circu ECDs 11.45
Wiper Trip to Shoe @ 3713' - No tight hole
Service Rig and Top Drive
TIH - Wash 90' to Bttm - No fill ( Total BU
Gas 103 units)
Dir Drlg & Slide 6771' to 6867' MD (3749' T
VD) ART 1.2 hrs, AST 0.0 hrs
Dir Drlg 6867' to 7328' MD (3943' TV D) - Ho
Id packing off - Able to rotate and recip up
& Dn but will nor circulate - ART 3.8 hrs ,
AST 0 ,7 hrs
Bk Ream & Attempt to regain circulation - B
k ream & SIB 2 stds DP @ 7165' Regained c
ircu - Stage up circu f 11.5 bpm to 7.4 bpm (
drilling rate) - Circu BU had alarge amount
of clay across shakers
Wash & Ream 7165' to 7328' MD
Dir Drlg 7328' to 7443' MD (3990' TV D) ART
1.0 hrs ,AST 0.5 hrs
Dir Drlg 7443' to 8195' MD ( 4297' TVD) AR
T 8,9 hrs , AST 0.4 hrs **Note** Pumped t
and em sweeps @ 7328',7731',& 8115' - First
sweep is Wt I Hi Vis 20 bbl and the 2nd is
Hi Vis only 15 bbl
tI 5141' - Wash to Bttm @ 5234' - No F
Printed: 1/17/2002 10:11:46 AM
Legal Well Name:
Common Well Name:
Event Name:
Contractor Name:
Rig Name:
Date
11/17/2001
11/18/2001
11/19/2001
11/20/2001
(
('
Page 5 of 12
PHilliPS ALASKA INC.
Operations Summary Report
2P-415
2P-415
ROT - DRILLING
Doyon
Doyon 141
Spud Date: 11/4/2001
End:
Group:
Start: 11/2/2001
Rig Release: 12/6/2001
Rig Number: 141
Description of Operations
Sub
From - To Hours Code Code Phase
00:00 - 08:00
08:00 - 09:00
09:00 - 10:30
10:30 - 11 :30
11 :30 - 12:00
12:00 - 00:00
00:00 - 12:00
12:00 - 00:00
00:00 - 04:00
04:00 - 05:00
05:00 - 05:30
05:30 - 06:00
06:00 - 08:30
08:30 - 09:30
09:30 - 12:00
12:00 - 15:30
15:30 - 17:30
17:30 - 20:00
20:00 - 22:30
22:30 - 00:00
00:00 - 08:00
08:00 - 08:30
8.00 DRILL
1.00 DRILL
1.50 DRILL
1,00 DRILL
0.50 DRILL
12,00 DRILL
12,00 DRILL
12.00 DRILL
4.00 DRILL
1.00 DRILL
0.50 DRILL
0.50 DRILL
2.50 DRILL
1.00 DRILL
2.50 DRILL
3,50 DRILL
2.00 DRILL
2.50 DRILL
2,50 DRILL
1,50 DRILL
8.00 DRILL
0.50 DRILL
DRLG PROD
CIRC PROD
WIPR PROD
WIPR PROD
REAM PROD
DRLG PROD
DRLG PROD
DRLG PROD
DRLG PROD
DRLG PROD
TRIP PROD
OBSV PROD
DRLG PROD
OBSV PROD
DRLG PROD
OBSV PROD
DRLG PROD
OBSV PROD
DRLG PROD
OBSV PROD
OBSV PROD
TRIP
PROD
Dir Drlg 8195' to 8692' MD (4504' TV D) ART
5.4 hrs , AST 0,4 hrs
Circu & Pump tandem sweeps - Circu hole cl
ean ECDs start 11.8 & 11.4 final
Wiper Trip to 6500' - Monitor well per Philli
ps policy - No Tight hole
TIH to 8596'
Wash & Ream 8596' to 8692' MD (4504' TVD)
BU Max Gas 120 units
Dir Drlg 8692' to 9345' MD ( 4826' TVD) AR
T 6.2 hrs , AST 2.0 hrs
Dir Drlg 9345' to 9925' MD (5240' TV D) ART
5.6 hrs , AST 3.1 hrs
Dir Drlg 9925' to 10346' MD (5603'
T 5.4 hrs, AST 2.4 hrs **Note**
is & Hi Vis tandem sweeps pumped
10035 MAX Gas units 1150 units
BUs
Dir Drlg 10,346' to 10,453' MD ( 5698' TVD)
ART 2.1 hrs , AST 0.7 hrs ECDs 11.2 - Lo
st Returns
Mix & Spot on bttm #1 19 bbl LCM pill (12.5
ppb Barafiber) 20 spm =450psi - No returns
TVD) AR
Wt I Hi V
@ 9673 ,
@10,300'
TOH to 10,230'
Monitor well & LCM pill - Loss rate 25 BPH -
Spoke wI Team Leader & Well Engineer abo
ut plan forward
Mix & Spot #2 100 bbl LCM pill ( 12.5ppb
Barafiber) 16 spm = 450 psi - No Returns
Monitor well - Loss rate 23 BPH
Mix & Spot # 3 100 bbl LCM pill (10 ppb B
arafiber, 10 ppb Walnut Med,) 16 spm = 330
psi - No Returns
Monitor well - Loss rate 6-10 BPH
Mix & Spot # 4 100 bbl LCM pill (15 ppb B
arafiber, 10 ppb Baracarb 150) 16 spm = 35
0 psi - No Returns - Spoke wI Steped up Tea
m Leader & Well Engineer about plan forwar
d,
Monitor well - Static - Attenpt to circu @ 11
4 bpm - No returns
Mix & Spot # 5 100 bbl LCM pill (10 ppb B
arafiber, 12 ppb Baraseal fine, 8 ppb walnut
med, ) 16 spm = 400 psi - No Returns
Monitor well - Static - Attempt to circu @ 1,
3 & 4 bpm - No returns **Note** Total Mud
loss for day = 1370 bbls
Observe well, rotating and reciprocating, wh
ile waiting on Dowell LCM plug material and
equipment, well took 19 bbls fluid to keep h
0 I e full.
TIH to 10453'
Printed: 1/17/2002 10:11:46AM
(
(
Page 6 of 12
PHilliPS ALASKA INC.
Operations Summary Report
Legal Well Name: 2P-415
Common Well Name: 2P-415
Event Name: ROT - DRILLING
Contractor Name: Doyon
Rig Name: Doyon 141
Date From - To Hours Code Sub Phase
Code
11/20/2001 08:30 - 09:30 1.00 DRILL OBSV PROD
09:30 - 11 :30 2.00 DRILL CIRC PROD
11:30 -12:30
1.00 DRILL
OBSV PROD
12:30 - 13:30
1,00 DRILL
PROD
TRIP
13:30 - 16:00
2.50 DRILL
CIRC PROD
16:00 - 22:00
6.00 DRILL
PROD
TRIP
22:00 - 23:00
1.00 DRILL
PROD
TRIP
23:00 - 00:00 1.00 DRILL CIRC PROD
11/21/2001 00:00 - 01 :30 1.50 DRILL TRIP PROD
01 :30 - 04:00 2.50 DRILL TRIP PROD
04:00 - 05:00 1.00 DRILL PULD PROD
05:00 - 08:30 3.50 WELCT BOPE PROD
08:30 - 09:00 0.50 DRILL PULD PROD
09:00 - 13:00 4.00 DRILL PULD PROD
13:00 - 14:30 1.50 DRILL TRIP PROD
14:30 - 15:30 1.00 DRILL TRIP PROD
15:30 - 16:00 0.50 DRILL CIRC PROD
16:00 - 17:30 1.50 DRILL TRIP PROD
17:30 - 19:00 1.50 DRILL CIRC PROD
19:00 - 20:30 1,50 DRILL TRIP PROD
20:30 - 23:00 2.50 DRILL REAM PROD
23:00 - 00:00
1.00 DRILL
DRLG PROD
Spud Date: 11/4/2001
End:
Group:
Start: 11/2/2001
Rig Release: 12/6/2001
Rig Number: 141
Description of Operations
Observe well while batch mixing Dowell Inst
an SEAL LCM slurry
Pump Dowell LCM plug as follows, 2 bbls. fr
. water, test lines to 3500 psi, Pump 8 bbls.
fro water, 50 bbls. Dowell InstanSEAL LCM
slurry, 10 bbls. fro water, lost all 70 bbls of
fluid to hole, take over pumping with rig pu
mp, Displace with 100 bbls 10 ppg mud at 8
BPM at 3500 psi, this puts the LCM slurry 0
ut of bit, lost 88 bbls while displacing. Reg
ained slight circ. at end of job.
Monitor well with everything static to let Plu
g set
POOH 5 stands to 9950', hole was swabbing,
so pumped out with enough fluid to replace
pipe displacement.
Establish circ., had approx. 75% returns to
start with and during circ. it fell to as Iowa
s 50%, then gradually picked up to 80% retu
rns. pumped 470 bbls, approx 1,5 times bott
oms up, lost 177 bbls while pumping. Mud w
eight in was 10 ppg - 50- vis. and out was 1
0.3 - 90+- vis.
POOH to 5622', hole would swab, so pumped
out using enough fluid to replace pipe displ
acement
POOH, hole quit swabbing, so was able to p
ull using trip tank, hole took proper displac
ement
Circ, and Cond, mud to 10 ppg at 50- vis, ha
d no losses at shoe.
POOH to BHA
POOH with BHA, pull radio-active sources, d
ownload MWD and stand back in derrick
Pull wear bushing, set test plug
Test BOP's, 250 low and 3500 psi high
Pull test plug, install wear bushing
P/U BHA, load MWD, install radio-active sou
rce, RIH with DC's, pulse test MWD
RIH with HWDP
TIH with DP to shoe at 3700'
Circ. bottoms up, 9.9+ mud weight all the w
ay around, no mud losses
TIH to 7200', no tight spots
Circ. and condo mud, 9,9+ mud weight all th
e way around, no mud losses
TIH to 10,000', no tight hole
Wash from 10,000' to 10,430', condo mud to
9.9+ ppg mud weight, tag hard plug at 10,43
0', no mud losses
Drill Instan-Seal plug from 10,430' to 10,45
3', took 10k weight to drill up plug, lost 92
bbls mud while drilling plug, circ. rate was
Printed: 1/17/2002 10:11 :46 AM
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(
Page 7 of 12
PHilliPS ALASKA INC.
Operations Summary Report
Legal Well Name: 2P-415
Common Well Name: 2P-415
Event Name: ROT - DRILLING
Contractor Name: Doyon
Rig Name: Doyon 141
Date From - To Hours Code Sub Phase
Code
11/21/2001 23:00 - 00:00 1.00 DRILL DRLG PROD
11/22/2001 00:00 - 21 :00 21.00 DRILL DRLG PROD
21 :00 - 23:30
2.50 DRILL
CIRC
PROD
11/23/2001
23:30 - 00:00
00:00 - 00:30
00:30 - 06:00
0.50 DRILL
0.50 DRILL
5.50 DRILL
TRI P PROD
TRI P PROD
REAM PROD
06:00 - 09:00 3.00 DRILL CIRC PROD
09:00 - 15:30 6.50 DRILL TRIP PROD
15:30 - 18:00 2,50 DRILL PULD PROD
18:00 - 19:00 1.00 LOG RURD PROD
19:00 - 21:00 2.00 LOG ELOG PROD
21:00 - 21:30 0,50 LOG PULD PROD
21 :30 - 00:00 2.50 LOG PULD PROD
11/24/2001 00:00 - 06:30 6.50 LOG PULD PROD
06:30 - 07:00 0.50 LOG SFTY PROD
07:00 - 09:00 2.00 LOG DLOG PROD
09:00 - 09:30 0.50 LOG CIRC PROD
09:30 - 16:00 6.50 LOG DLOG PROD
16:00 - 17:00 1,00 LOG CIRC PROD
17:00 - 19:00 2,00 LOG PULD PROD
19:00 - 19:30 0.50 LOG DLOG PROD
19:30 - 00:00 4.50 LOG DLOG PROD
11/25/2001 00:00 - 06:00 6,00 LOG DLOG PROD
06:00 - 06:30 0.50 LOG DLOG PROD
06:30 - 08:00 1.50 LOG OTHR PROD
08:00 - 11 :30 3.50 LOG CIRC PROD
Spud Date: 11/4/2001
End:
Group:
Start: 11/2/2001
Rig Release: 12/6/2001
Rig Number: 141
Description of Operations
250 gpm, pump pressure at 1800 psi
Drill from 10453' to 11075' MD, 6272' TVD,
mud losses started out at 80 BPH and finiall
y stopped by 10900', well started then givin
g back fluid, it would flow on connections, b
ut then would decrease with time. Formation
is breathing. Barafiber and Bara Seal was u
sed to stop mud losses, added into suction
pit. ART = 15.9 hrs,
Circ, and Condo hole, pump sweep, Circ. and
Cond" observe well while blowing down kel
Iy and stand pipe. Formation breathing, givi
ng back fluid, but slowed with time,
Start wiper trip to 9900'
TIH to 10,000'
Make mad pass log with Sperry Sun MWD/LW
D from 10,000' to 10,620', TIH to bottom 11,
075'
Circ. and Condo hole, spot a drill and slide
pill in open hole, observe well
POOH to BHA
Down load Sperry Sun LWD, LID BHA
R/U Schlumberger wire line
RIH wlRun #1 - Dipole Sonic, couldn't get p
ast 3909', POOH
LID Dipole sonic
P/U CMR/MDT to be run pipe conveyed, surf
ace test tools
P/U CMR/MDT tools on Drill Pipe, surface te
st tool string, unable to get CMR and MDT t
0 run in tandem, but would run ok separatly,
RID CMR tool and test MDT, test was ok.
Held pre-job safety meeting
TIH to 3650' with MDT tool
Circ. DP volumn, hang schlumberger top she
ave
Trip in with MDT to 9858', break circ. every
10 stands
Circ. DP volumn
Make up cross overs, side entry sub and cro
ss over to DP, RIH with wire line, latch into
MDT tool and test connection, OK.
TIH to 10233'
Make sets at various depths from 10233' to
10751' getting formation pressures
In hole with MDT tool taking pressures and
samples at various sets
TOOH to 9950'
Release wire line connection, POOH with wir
e line, LID side door entry sub.
Circ. and cond, hole, had 2200 units of bott
oms up gas.Was limited to 3 bbls per min w
hi Ie circ. because of logging tools and circ,
Printed: 1/17/2002 10:11:46 AM
(
('
PHilliPS ALASKA INC.
Operations Summary Report
Legal Well Name: 2P-415
Common Well Name: 2P-415
Event Name: ROT - DRILLING
Contractor Name: Doyon
Rig Name: Doyon 141
Date From - To Hours Code Sub Phase
Code
11/25/2001 08:00 - 11:30 3.50 LOG CIRC PROD
11 :30 - 12:00 0.50 WELCT OBSV PROD
12:00 - 15:00 3.00 LOG DLOG PROD
15:00 - 15:30 0.50 RIGMNT RSRV PROD
15:30 - 17:00 1,50 LOG DLOG PROD
17:00 - 20:00 3.00 LOG PULD PROD
20:00 - 21 :00 1,00 LOG PULD PROD
21 :00 - 23:00 2,00 LOG DLOG PROD
23:00 - 00:00 1.00 RIGMNT RSRV PROD
11/26/2001 00:00 - 00:30 0,50 RIGMNT RSRV PROD
00:30 - 04:30 4.00 LOG DLOG PROD
04:30 - 06:00 1.50 LOG CIRC PROD
06:00 - 1 0:30 4.50 LOG DLOG PROD
10:30 - 12:30
2.00 LOG
DLOG PROD
12:30 - 15:00
15:00 - 17:00
2.50 LOG
2.00 LOG
DLOG PROD
DLOG PROD
17:00 - 17:30 0.50 LOG DLOG PROD
17:30 - 19:00 1.50 LOG DLOG PROD
19:00 - 00:00 5.00 LOG DLOG PROD
11/27/2001 00:00 - 01 :00 1.00 LOG DLOG PROD
01 :00 - 03:00 2.00 LOG CIRC PROD
03:00 - 03:30 0.50 WELCT OBSV PROD
03:30 - 08:30 5,00 LOG DLOG PROD
08:30 - 09:00 0.50 LOG PULD PROD
09:00 - 11 :00 2.00 DRILL PULD PROD
11 :00 - 16:00 5.00 DRILL TRIP PROD
16:00 - 18:00 2,00 DRILL CIRC PROD
18:00 - 19:30
1,50 DRILL
PROD
CIRC
19:30 - 22:30
CIRC PROD
3,00 DRILL
22:30 - 23:00
0,50 CEMEN PLUG PROD
Page 8 of 12
Spud Date: 11/4/2001
End:
Group:
Start: 11/2/2001
Rig Release: 12/6/2001
Rig Number: 141
Description of Operations
sub.
Monitor well for flow, pump slug, blow down
stand pipe and kelly hose.
POOH to 7 5/8" casing shoe
Service top drive, observe well for flow.
TOOH
Take gas samples and fluid samples from th
e 2 sample chambers in tool, LID MDT tool
P/U Dipole sonic tool on drill pipe and test
TIH with sonic tool on drill pipe to 3648'
Slip and cut drill line
Slip and Cut drill line
TIH to 8800', beaking circ, every 10 stands,
trip speed 90' per min,
Install side door entry sub and pump down w
ireline wet connect, latch into tool.
TIH logging from 9000' to 10700', had troubl
e with wet connect coming loose and poor si
g n al
Trouble shooting logging tool problems, wet
connect coming loose on tool and getting po
or signal when it is hooked up.
POOH to side door entry sub.
POOH with wire line, rebuild quick connect,
found leak in wire line,cut line and rebuild r
ope socket. Test connector, everything tests
ok,
RIH with logging tool to 9954'
M/U side door entry sub and RIH with wet co
nnect on wire line, latch onto logging tool.
Run Dipole Sonic Log down from 9965 to 110
47', then logged back up hole to 9965'
Pull wire line out of hole, remove side entry
sub.
Circ. bottoms up
Check for flow, pump slug, blow down stand
pipe and rotary hose.
POOH with logging tools on DP.
LID logging tools, RID Schlumberger
P/U 18 jts of 2 7/8 tubing and mule shoe for
cementing stinger (550').
TIH to 10866'
Circ. and cond hole, had mud losses to hole
at 75 bbls per hr.Added bara seal and bara
carb to cure losses,
RIH to 11075' and spot high vis pill on botto
m
Pull up to 10866' and circ. while waiting on
Dowell Well to get all their chemicals here f
or the cement job. They were stuck behind a
rig move of Nordic 3, Hole was stable with
no mud losses,
Mix and pump 25.4 bbls 15,8 ppg cement slu
Printed: 1/17/2002 10:11:46 AM
(
Page 9 of 12
PHilliPS ALASKA INC.
Operations Summary Report
Legal Well Name: 2P-415
Common Well Name: 2P-415
Event Name: ROT - DRILLING
Contractor Name: Doyon
Rig Name: Doyon 141
Date From - To Hours Code Sub Phase
Code
11/27/2001 22:30 - 23:00 0.50 CEMEN PLUG PROD
23:00 - 23:30 0.50 CEMEN TRIP PROD
23:30 - 00:00 0,50 CEMEN CIRC PROD
11/28/2001 00:00 - 01 :30 1,50 CEMEN CIRC PROD
01 :30 - 02:00 0.50 CEMEN PLUG PROD
02:00 - 03:00 1.00 CEMEN TRIP PROD
03:00 - 09:00 6.00 CEMEN CIRC PROD
09:00 - 10:00 1.00 CEMEN TRIP PROD
10:00 - 14:00 4.00 CEMEN CIRC PROD
14:00 - 14:30 0,50 CEMEN TRIP PROD
14:30 - 16:00 1.50 CEMEN TRIP PROD
16:00 - 16:30 0,50 CEMEN CIRC PROD
16:30 - 18:00 1.50 CEMEN CIRC PROD
18:00 - 19:00 1.00 CEMEN PLUG PROD
19:00 -19:30 0,50 CEMEN TRIP PROD
19:30 - 20:30 1.00 CEMEN CIRC PROD
20:30 - 21 :00 0.50 DRILL TRIP PROD
21:00 - 21:30 0.50 RIGMNT RSRV PROD
21 :30 - 23:00 1.50 DRILL TRIP PROD
23:00 - 00:00 1,00 DRILL TRIP PROD
11/29/2001 00:00 - 01 :00 1,00 DRILL TRIP PROD
01:00 - 01:30 0.50 DRILL RIRD PROD
01 :30 - 06:00 4.50 WELCT BOPE PROD
06:00 - 06:30 0,50 DRILL RIRD PROD
06:30 - 10:30 4.00 DRILL PULD PROD
10:30 - 12:00 1,50 DRILL TRIP PROD
12:00 - 12:30 0,50 DRILL CIRC PROD
12:30 - 13:00 0.50 DRILL TRIP PROD
13:00 - 14:00 1.00 DRILL CIRC PROD
14:00 - 14:30 0.50 DRILL TRIP PROD
14:30 - 15:00 0.50 DRILL CIRC PROD
15:00 - 16:30 1,50 DRILL REAM PROD
16:30 - 00:00 7.50 DRILL DRLG PROD
11/30/2001 00:00 - 08:00 8.00 DRILL DRLG PROD
08:00 - 08:30 0.50 DRILL CIRC PROD
08:30 - 10:30
PROD
2.00 DRILL
TRIP
Spud Date: 11/4/2001
End:
Group:
Start: 11/2/2001
Rig Release: 12/6/2001
Rig Number: 141
Description of Operations
rry and balance on bottom with mud
POOH to 10366'
Circ. bottoms up
Continue to circ. while mixing cement in bat
ch mixer.
Spot 500' balanced cement plug, 25.4 bbls 1
5,8 ppg from 10366' to 9866'
POOH to 9366'
Circ. and condo mud, waiting on cement to s
et before going back and tagging top plug,
RIH to 9890', felt like we were going in gree
n cement, POOH to 9600'
Circ, while waiting on cement to set
RIH to tag cement, started taking some weig
ht at 9880', found hard cement at 9925', set
down 20,000 Ibs on plug. State man witness
ed and said everything was good to go
POOH to 6400'
Spot high vis pill from 6400' to 6000'
POOH to 6000' circ. bottoms up
Spot balanced cement plug from 6000' to 54
00',30.5 bbls of 17 ppg cement slurry
POOH to 4800'
Circ. bottoms
POOH to shoe
Service rig, observe flow
POOH to 2 7/8" stinger, layed down 72 jts 4
II DP
R/U and pull 2 7/8" tubing, Had 5 jts rayed
down at report time
POOH LID 2 7/8" tubing
Pull wear bushing and run test plug
Test BOP's to 250 psi low and 3500 psi high
Pull test plug and run wear bushing
P/U bit and Baker mud motor and test, P/U
Sperry Sun MWD/LWD, upload and load radio
-active source and test.
TIH to 3780'
Circ and test MWD/LWD tool
TIH to 5130'
Circ. bottoms up, establish PWD base line.
TIH to 5490', no sign of cmt.
Circ. bottoms up, no cement in returns
Wash down to 5498' and tag cement, drill ou
t cement with up to 20k to 5575'
Time drill to kick off cement plug from 5575'
to 5582'
Drill from 5582' to 5896', Hole packed off 0
n connection at 5843', pipe hung up.
Couldn't circulate or go down, took 60,000 t
0 80,000 overpull to break loose. Work pipe
and regain circulation.
Make wiper trip above sidetrack point 5500'.
Printed: 1/17/2002 10:11:46 AM
Legal Well Name:
Common Well Name:
Event Name:
Contractor Name:
Rig Name:
Date
11/30/2001
12/1/2001
12/2/2001
1213/2001
12/4/2001
(
('
Page 10 of 12
PHilliPS ALASKA INC.
Operations Summary Report
2P-415
2P-415
ROT - DRILLING
Doyon
Doyon 141
Sub
From - To Hours Code Code Phase
08:30 - 10:30
10:30 - 00:00
00:00 - 04:00
04:00 - 05:00
05:00 - 06:00
06:00 - 00:00
00:00 - 02:30
02:30 - 04:00
04:00 - 08:00
08:00 - 00:00
00:00 - 04:00
04:00 - 05:00
05:00 - 06:30
06:30 - 09:00
09:00 - 14:00
14:00 - 14:30
14:30 - 15:30
15:30 - 16:30
16:30 - 17:00
17:00 - 18:00
18:00 - 20:00
20:00 - 21 :00
21 :00 - 23:30
23:30 - 00:00
00:00 - 04:30
04:30 - 05:30
2.00 DRILL
13.50 DRILL
4.00 DRILL
1.00 DRILL
1.00 DRILL
18.00 DRILL
2,50 DRILL
1.50 DRILL
4,00 DRILL
16.00 DRILL
4.00 DRILL
1.00 DRILL
1.50 DRILL
2.50 DRILL
5.00 DRILL
0.50 DRILL
1.00 DRILL
1.00 DRILL
0.50 DRILL
1.00 DRILL
2.00 CASE
1.00 CASE
2.50 CASE
0,50 CASE
4.50 CASE
1.00 CASE
TRIP
PROD
DRLG PROD
DRLG PROD
CIRC PROD
WIPR PROD
DRLG PROD
DRLG PROD
CIRC PROD
WIPR PROD
DRLG PROD
DRLG PROD
CIRC
PROD
DRLG PROD
CI RC PROD
TRIP PROD
SFTY PROD
RIRD PROD
PULD PROD
RI RD PROD
RI RD PROD
RUNC PROD
RURD PROD
RUNC PROD
CIRC PROD
RUNC PROD
CI RC PROD
Spud Date: 11/4/2001
End:
Group:
Start: 11/2/2001
Rig Release: 12/6/2001
Rig Number: 141
Description of Operations
Had a tight spot when stabilizer came thro
ugh sidetrack area, Going back in hole the b
it took weight going into sidetrack area at 5
580'. Wash and ream down through tight spo
ts and go to bottom.
Drill from 5896' to 6583' MD, 3836' TVD T
wice while drilling this interval we had some
thing fall in or pack off. Pumping a high vis
sweep every hour, and having no hole proble
ms. Total slide time for today = 5.2 hrs. T
otal rotating time today = 11.3 hrs.
Drill from 6583' to 6856' MD,
Circ. bottoms up, observe well, blow down s
tand pipe,
Wiper trip to 5500', no excess drag.
Drill from 6856' to 7816' MD, 4927' TVD Pu
mping high vis sweep 10 to 15 bbl every hr,
for hole cleaning Total slide time today =
3.8 hrs. Total rotate time today = 13,4 hrs
Drill from 7816' to 8008' MD
Circ, bottoms up, clean up hole. Observe for
flow, pump slug, blow down stand pipe.
Wiper trip to shoe, (3700') and back to bott
om, no excess drag or fill.
Drill from 8008' to 8777' MD, 5807' TVD EC
D while drilling staying around a 10,7 PPG
Slide time for the day = 1,8 Rotating time
= 12.8
Drilling from 8777' to 8970' MD, 5984 TVD,
Sperry Logging tool failed
Circ, while waiting on decision to drill ahea
d or POOH to fix tool
Drilling from 8970' to 9038' MD, 6050' TVD
Circ, pump high vis sweep, circ 2 bottoms u
p, shakers clean, observe well, pump slug,
blow down stand pipe.
POOH to BHA
PJSM on down loading radio active sources,
pull R. A, sources
Down load MWD/LWD info.
L/D BHA
Pull wear bushing
R/U to run 3 1/2" casing, hold PJSM
Run 25 jts 3 1/2" casing, float equip, and B
aker seal bore,
R/U to run 5 1/2" casing
RIH with 5 1/2" casing to 3700', using Frank
s fill up tool.
Circ and condo mud with full returns,
Co nt' to Run 5 1/2" Csg tI 7000'
Circu & Cond Mud - Only have partial return
s -Losing 66% pumped -While pumping 3 bp
m, returns 1 bpm
Printed: 1/17/2002 10:11:46AM
~ ...... ~
'fpH'LUPS~
~~)
~
12/5/2001
t'
(
("
PHilliPS ALASKA INC.
Operations Summary Report
17:00 - 17:30
0.50 CASE RURD PROD
Legal Well Name: 2P-415
Common Well Name: 2P-415
Event Name: ROT - DRILLING
Contractor Name: Doyon
Rig Name: Doyon 141
Date From - To Hours Code Sub Phase
Code
12/4/2001 05:30 - 09:00 3.50 CASE RUNC PROD
09:00 - 17:00 8.00 CASE CIRC PROD
17:30 - 18:30
1.00 CEMENl PUMP PROD
1.50 CEMENl PUMP PROD
18:30 - 20:00
20:00 - 21 :00
1.00 CEMENl PULD PROD
21 :00 - 22:30
1.50 CASE NUND PROD
22:30 - 23:00
23:00 - 00:00
0.50 CMPL TN RURD PROD
1.00 CMPL TN RUNT PROD
00:00 - 06:30
06:30 - 08:30
6.50 CMPL TN RUNT CMPL TN
2.00 CMPLTN CIRC CMPLTN
08:30 - 14:00
5.50 CMPLTN CIRC CMPLTN
14:00 - 15:30
1.50 CMPL TN SOHO CMPL TN
15:30 - 16:30
16:30 - 17:30
1.00 CMPL TN SOHO CMPL TN
1.00 WELLSR DEOT CMPL TN
17:30 - 18:00
0.50 WELLSF DEOT CMPL TN
Page 11 of 12
Spud Date: 11/4/2001
End:
Group:
Start: 11/2/2001
Rig Release: 12/6/2001
Rig Number: 141
Description of Operations
Con't TIH Running 5 1/28 Csg to 9025' Shoe
depth
Circu & Condit Mud with partial returns Loss
es 25-30 BPH - Stage SPM up slowlyfl 1/4 b
pm to 5 BPM - Mixing LCM @ 26 ppb ( 13 pp
b Barofiber,13 ppb Baroseal Med ) Total los
ses for all circulating 412 bbls- **Note** @
1700 hrs losses had stopped and returns h
ad returned to full.
RID Franks fill tool - R/U 5 1/2" Dowell CMT
head
Circu & Batch Mix CMT - Move Trucks into S
ervice CMT Unit
Pump 2 bbl mud - Pressure Test CMT lines t
0 3500 psi per program - "OK" - CMT per we I
I plan - Pump 30 bbl 10.5ppg MudPUSH wI 2
Sibs D29 , 62.5 bbls Slurry @ 15.8 ppg wI 1
50 Ibs D29 ,D053 3.00% ,M117 0.30% , DO
65 0.450% , D800 0.200% (Wet phase D600
G 2.0 gal/sk , D047 0.200 gal/sk ), Drop PI
ug , Pump 15 bbls 10.2 ppg brine - Rig displ
aced wI 9.9+ mud - Plug bumped @ 1816 stk
s (caccu to bump 1842 stks) CMT rate 4 BP
M (last 20 bbls @ 2.5 bpm) Had full returns
thru complete job - Reciped Csg to 1650 stk
s displacement (last 16.6 bbls) CIP 2000 hr
s
Bleed off pressure - Floats Held - RID Dowe
II - RID Csg Tools
InstallS 1/2" Csg hanger Packoff - Test to
5000 psi per well program for 10 min "OK"
R/U to Run 3 1/2" Completion Tbg
Run 3 1/2" 9.3# L-80 8rd EUE Tbg Complet
ion
Con't Run Completion - Tag top CSR
Circu & C/O well fluid to Sea Water - Pump
dn Tbg @ 5 BPM = 1440psi total of 3200 stk
s (320 bbls)
Reverse Circu Sea Water @ 4 bpm = 1160 ps
i-Pump "Dirt Magnet Sweep & Hi Vis sweep
to maximize csg cleaning - Circu total 7995
stks (800 bbls) At final circu NT Us = 11 -
Sample caught and retained for engineer
Tag up on collar locator @ 8188'- Space out
w/2 pups (6.13 + 2.02) placed 1 full jt bel
ow Tbg Hanger - Space out 1.5' above locat
or
Land Tbg Hanger - RILDS
Pressure up Tbg to 500psi per program - Te
st 3.5" X 5.5" Annulas wI 3000psi hold for
30 min (on Chart for AOGCC) Loss 50 psi aft
er 30 min
Bleed pressure off Tbg and Shear out GLM
Printed: 1/17/2002 10:11:46AM
(
(
PHilliPS ALASKA INC.
Operations Summary Report
Legal Well Name: 2P-415
Common Well Name: 2P-415
Event Name: ROT - DRILLING
Contractor Name: Doyon
Rig Name: Doyon 141
Date From - To Hours Code Sub Phase
Code
12/5/2001 17:30 - 18:00 0.50 WELLS DEOT CMPL TN
18:00 - 18:30 0.50 WELLS PULD CMPL TN
18:30 - 20:30 2.00 WELLS NUND CMPL TN
20:30 - 22:30 2,00 WELLS NUND CMPL TN
22:30 - 23:00 0.50 WELLS NUND CMPL TN
23:00 - 00:00 1,00 WELLS FRZP CMPL TN
12/6/2001
00:00 - 01 :00
1,00 WELLS FRZP CMPL TN
01 :00 - 02:30
1,50 WELLS FRZP CMPL TN
02:30 - 03:30
1.00 WELLS PLGM CMPL TN
03:30 - 12:30
9.00 WELLS PULD CMPL TN
12:30 - 15:00
2,50 WELLS RURD CMPL TN
Page 12 of 12
Spud Date: 11/4/2001
End:
Group:
Start: 11/2/2001
Rig Release: 12/6/2001
Rig Number: 141
Description of Operations
@ 8091' MD
LID landing jt - RID GBR tools
Set BPV - NID BOPs
N/U Production Tree - Orient & Test - Test
Tbg Hng & Adp Flange to 5000psi "OK"
Pull BPV - Set TWC - Test Tree 250psi 10 /
5000 hi (hold ea. test 5 min "OK")
Freeze Protect well - Pump 55 bbls dn 5.5"
X 3,5" Ann - Put Ann & Tbg in comunication
and let U tube
Con't 5,5" X 3.5" Tbg Ann, in commication "
U" tubing - R/U to LOT 7 5/8" X 5.5" Ann
Preform LOT & Injt Test on 7 5/8" X 5.5" An
nluas - Formation break @ 940 psi - Injt rat
e @ 1 bpm = 1120 psi Freeze protected Ann
pumping 52 bbls diesel
Set BPV - Secure well - Install all flanges &
blinds
LID all SWDP & DP out of derrick ( 83 stds
D P )
Prep Rig for Move - Drain & Blow dn all serv
ice lines ,water,steam,glycol ect, Rig Relea
sed 1500 hrs ,12/06/2001
Printed: 1/17/2002 10:11:46 AM
SENT BY,:
Date
12/23101
12/24/01
12124/01
12/27/01
12/28/01
12/31/01
01/01/02
01/02/02
. -- - .
01/08/02
01/09/02
01/19/02
01/20/02
2- 8- 2 ; 1:37PM;
{
PHILLIPS AK INC-'~
(
:# 2/ ~
2P-415A Event History
Comment
DRIFTED TBG W/22& 6h X 2.565~DUMMY GUN & TAGGED FILL @ 8707' RKB, EST. 57' BELOW TARGET
PERF DEPTH, SET SPARTEK @ 8091' RKB. PT TBG & CSG. BOTH GOOD TESTS. [TAG, PRESSURE
DATA]
PUMPED INITIAL FRACTURE TREATMENT. PLACED 114,750# 16120 CARBOUTE IN FORMATION, 11.2
PPA ON PERFS, 80% OF DESIGN. HAD NWBSO, LEFT 26,350# 16/20 AND 12/18 PROP IN WELLBORE.
NOTE; MOST TREESAVER RUBBERS NOT RECOVERED, [FRAC.REFRAC]
PERFORATE 86401.50' (101) WITH 2.58 HSC, 6 SPF, 60 DEG PHASED, POWERFLOW HMX CHARGES
(0.6611 ENT HOLE). OBTAIN SBHP AT 8645' (2454 PSI), AND 8091' (2207 PSI),
PERFORMED POST-FRAC CLEANOUT TO 8825' CTM (EST, 150' OF RATHOLE) USING A 1.75" JET~
SWIRL NOZZLE WI SLICK SEAWATER, SLICK DIESEL, AND 1.1/2# BIOZAN, WELL FREEZE PROTECTED
TO 2500'+. [FCO]
TAGGED Fill @ 8482' RKB, EST 168' OF FILL, REPLACED SPARTEK GAUGE @ 8091' RKB WI av, PT
TBG TO 2500# HELD. PULLED CAT SV @ 8148' RKB [TAG, PRESSURE DATA. GLV, PT TBG-CSG]
PERFORMED A REVERSE OUT FCC TO 8870.11 CTMD. WELL FREEZE PROTECTED TO 5000'. WELL IS
ATTEMPTING TO FLOW WITH A COLUMN OF DIESEL. FREEZE PROTECTED AND TAGGED FLOW LINE
. ". ~/10 ~~.~~ DIESEL. ~ "'. .......-.. ..---.
NITROGEN PUMPING CHARGES FOR INITIAL LIFT TO FLOW.
NITROGEN PUMPING CHARG~S FOR INITIA~ LIFTTO_F.LPW,- . . -. - -
ENCOUNTEf1Eo LIGHT PARAFFIN & HYDRATES @ TBG HANGER. TAGGED CARBO UTE BRIDGE ÖR
FILL @ 81121 AKB; PERFS 8640-86501. IN PROGRESS, [PARAFFIN, TAG]
REPLACED OV @ 80911 AKB, BAILED FRAC SAND @ 8097' WLM (GLV, PARAFFIN]
UNIT DOWN Qy'.~ TO WEA T~~..B1C.QJ.. ,..... .. .
CLEANED FILl.. TO aS$5 CTM USING A 2" JET-SWIRL NOZZLE WI SLICK DIESEL & '~'/2# BIOZAN (EST.
1001 OF RATHQLE), WELL FLOWING ON ITS OWN; LEFT SHUT IN AND FREEZE PROTECTED TO 2500'.
[FCO]
RECEIVED
FE8 . 8 2002
Alaska Oil & Gas Gons. L;ommISS¡o¡
AnchoraQ8
Page 1 of 1
2/612002
DEFINITIVE
\-.
Kuparuk River Unit
North Slope, Alaska
Kuparuk 2P, Slot 2P-415
2P-415
Job No. AKMM11187, Surveyed: 3 December, 2001
--
SURVEY REPORT
27 December, 2001
Your Ref: API 501032038300
Surface Coordinates: 5869006.85 N, 444185.88 E (70° 03' 09.9828" N, 1500 26' 47.9760" W)
Kelly Bushing: 251.400 above Mean Sea Level
~
{
'-.-
spe"-'Y-5iul1
DRILL.ING SERVices
A Halliburton Compllny
Survey Ref: svy9745
Sperry-Sun Drilling Services
Survey Report for 2P-415
Your Ref: API 501032038300
Job No. AKMM11187, Surveyed: 3 December, 2001
.
North Slope, Alaska
Kuparuk River Unit Kuparuk 2P
Measured Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical
Depth Incl, Azim. Depth Depth Northings Eastlngs Northlngs Eastlngs Rate Section Comment
(ft) (ft) (ft) (ft) (ft) (ft) (ft) (°/1 DOft)
5552.02 66,520 102.280 2945.17 3196.57 1682,88 S 3606,06 E 5867297,59 N 447779.51 E 3950.95 Tie On Point --,
--,
5575.00 65.083 102.666 2954.59 3205.99 1687.41 S 3626.53 E 5867292,91 N 447799,94 E 6.438 3971.81 Window Point
-.~.. 5633.98 61 .400 103.700 2981.14 3232.54 1699.41 S 3677,80 E 5867280.53 N 447851.12 E 6.438 4024.26
5732.96 57.380 103.230 3031.53 3282.93 1719.25 S 3760.62 E 5867260.09 N 447933,80 E 4.082 4109,15
5829.03 56.430 102.280 3083.98 3335.38 1737,02 S 3839.12 E 5867241.74 N 448012.17 E 1.290 4189.27
5926.47 54.930 101.850 3138.92 3390.32 1753.85 S 3917,81 E 5867224,34 N 448090.74 E 1.582 4269.29
6018.65 51.990 99,710 3193.80 - 3445.20 1767,72 S 3990,55 E 5867209,93 N 448163.37 E 3.694 4342.73
6112.98 50.640 99.120 3252.76 3504.16 1779,77 S 4063,19E 5867197,35 N 448235,91 E 1.512 4415.50
6209.75 48.890 99.190 3315.26 3566.66 1791.52 S 4136,12 E 5867185.07 N 448308,76 E 1.809 4488.46
6304,07 45.430 99.240 3379.39 3630.79 1802.59 S 4204.37 E 5867173.49 N 448376.93 E 3,669 4556.77
6405.73 43.700 97.080 3451.82 3703.22 1812.74 S 4274,97 E 5867162,83 N 448447.46 E 2.262 4627.02
6501,54 41.110 95,650 3522.56 3773,96 1819,92 S 4339,18 E 5867155.18 N 448511.60 E 2.884 4690.26
6597,27 38.270 94.640 3596,22 3847.62 1825.42 S 4400,06 E 5867149,24 N 448572.44 E 3.042 4749.82
6693.11 34.990 93.310 3673.12 3924.52 1829.41 S 4457,09 E 5867144,83 N 448629.44 E 3.521 4805.25
6787.54 31.850 93.710 3751.93 4003.33 1832.58 S 4508.99 E 5867141,27 N 448681.32 E 3.333 4855.56
6882.04 28.990 89.970 3833.42 4084.82 1834,19 S 4556,79 E 5867139.32 N . 448729.11 E 3.628 4901.48
6979.31 25.930 90.520 3919.72 4171.12 1834.37 S 4601.64 E 5867138,81 N 448773.95 E 3.157 4944.15
7074.81 25.360 90.700 4005.81 4257,21 1834,81 S 4642,97 E 5867138,07 N 448815.28 E 0,602 4983.56
7173.48 24.010 89.640 4095.46 4346,86 1834.94 S 4684,17 E 5867137,64 N 448856.48 E 1.440 5022.75 --
7269.27 24.340 87.770 4182.85 4434,25 1834,05 S 4723.39 E 5867138,24 N 448895,70 E 0.870 5059.73
7365.83 25.380 88.890 4270.46 4521,86 1832,87 S 4763,96 E 5867139,12 N 448936.28 E 1.182 5097.92
7460.67 26.170 88.200 4355.87 4607.27 1831,82 S 4805,19 E 5867139,87 N 448977.51 E 0.891 5136.77
7556.88 27.080 88.550 4441.87 4693.27 1830,60 S 4848,28 E 5867140,77 N 449020.62 E 0.960 5177.34
7652.81 25.920 88.060 4527.72 4779.12 1829,34 S 4891,07 E 5867141,72 N 449063.41 E 1,230 5217.60
I 4931.99 E 5867141,75 N 449104,33 E 1.721 5256.37
7748,20 24.900 91.060 4613.89 4865.29 1829.00 S
7843,85 24,210 91.290 4700.89 4952.29 1829.82 S 4971,73 E 5867140,65 N 449144.06 E 0.728 5294.39
7939.79 23.200 90.570 4788.73 5040.13 1830.45 S 5010.29 E 5867139,74 N 449182.62 E 1.095 5331.23
8036.37 23.880 90.390 4877.27 5128.67 1830,77 S 5048,86 E 5867139.13 N 449221,19 E 0.708 5367.98
8131,72 22.990 88,750 4964,76 5216,16 1830.50 S 5086,78 E 5867139,13 N 449259,11 E 1.157 5403.92
8228.28 23.420 89.800 5053.51 5304.91 1830.02 S 5124.82 E 5867139.33 N 449297.15 E 0.618 5439.92
------- -.----------
n-- -- ---
27 December, 2001- 16:07
Page 2 of 4
OrillQuest 2.00.08.005
Kuparuk River Unit
Measured
Depth
(ft)
I
\
.........
8324.05
8421.14
8516.87
8613.21
8709.53
8805.54
8902.50
8967.50
9038.00
Incl.
22.350
24.190
23.600
24.260
23.970
22.850
21.760
20.950
20.950
Azim.
89.670
91.580
91.410
90.550
88.670
89,310
89.030
88.210
88.210
Sub-5ea
Depth
(ft)
5141.74
5230.93
5318.45
5406.51
5494.43
5582.53
5672.24
5732.77
5798.61
Sperry-Sun Drilling Services
Survey Report for 2P-415
Your Ref: API 501032038300
Job No. AKMM11187, Surveyed: ,3 December, 2001
Vertical
Depth
(ft)
Local Coordinates
Northings Eastlngs
(ft) (ft)
Global Coordinates
Northlngs Eastlngs
(ft) (ft)
5867139.23 N
5867138.50 N
5867137,21 N
5867136.26 N
5867136,23 N
1831.02 S
1830.49 S
1829.93 S
1829.14 S
~
All data is in Feet (US) unless otherwise stated, Directions and coordinates are relative to True North.
Vertical depths are relative to Well. Northings and Eastings are relative to Well.
5393.14
5482.33
5569.85
5657.91
5745.83
1829,85 S
1830.29 S
1831.30 S
1831.97 S
1831.70 S
5162,06 E
5200,41 E
5239.17 E
5278,24 E
5317.59 E
5833.93
5923.64
5984.17
6050.01
.
5355,73 E
5392.53 E
5416,19 E
5441,38 E
Magnetic Declination at Surface is 25.396° (05-Nov-01)
The Dogleg Severity is in Degrees per 100 feet (US).
Vertical Section is from Well and calculated along an Azimuth of 108.160° (True).
Based upon Minimum Curvature type calculations, at a Measured Depth of 9038_.00ft"
The Bottom Hole Displacement is 5740,59ft., in the Direction of 108.580° (True).
27 December, 2001- 16:07
5867136,63 N
5867136.89 N
5867137,28 N
5867137,89 N
449334.40 E
449372.74 E
449411.49 E
449450,56 E
449489,91 E
449528.05 E
449564,85 E
449588.51 E
449613.71 E
Page 3 of 4
Dogleg
Rate
(0/100ft)
1.119
2.048
0.620
0.775
0.852
1.196
1.130
1.328
0.000
------
Vertical
Section
5475.25
5511.83
5548.97
5586.31
5623.61
5659.64
5694.44
5716.74
5740.44
.
r
North Slope, Alaska
Kuparuk 2P
Comment
--,
Projected Survey
-----
DrillQlIest 2.00.08.005
. .
Kuparuk_River Unit
Comments
,
,,-.
Measured
Depth
(ft)
5552.02
5575.00
9038.00
Sperry-Sun Drilling Services
Survey Report for 2P-415
Your Ref: API 501032038300
Job No. AKMM11187, Surveyed: 3 December, 2001
.
r
1682.88 S
1687.41 S
1829.14 S
Survey tool program for 2P-415
North Slope, Alaska
Kuparuk 2P
Station Coordinates
TVD Northings Eastings
(ft) (ft) (ft)
3196.57
3205.99
6050.01
From
Measured Vertical
Depth Depth
(ft) (ft)
0.00
27 December, 2001 - 16:07
0.00
To
Measured Vertical
Depth Depth
(ft) (ft)
9038.00
6050.01
--------------
Comment
---....
3606.06 E
3626.53 E
5441,38 E
Tie On Point
Window Point
Projected Survey
Survey Tool Description
MWD Magnetic (2P-415PB1)
~'-
Page 4 of 4
DrillQuest 2.00,08.005
- .
(
l
,
.'
PHilliPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Post Office Box 100360
Anchorage,AJaska 9951~360
C. Mallary
Phone (907) 265-6434
Fax: (907) 265-6224
January 31, 2002
Ms, Cammy Oechsli Taylor
Commissioner
State of Alaska
Alaska Oil & Gas Conservation Commission
333 W, 7th Avenue, Suite 100
Anchorage, Alaska 99501
Subject: Application for Sundry Approval for 2P-415A
Dear Commissioner:
Phillips Alaska, mc, submits the attached Application for Sundry Approval for 2P-415A, We are
requesting approval for annular disposal down this well,
If you have any questions regarding this matter, please contact Pat Reilly at 265-6048.
S incerel y ,
é', ~ %
C, Mallary U
Drilling Engineering Supervisor
P AI Drilling
CM! skad
RECEIVED
FEB 0 1 2002
Alaska Oil & Gas Cons, Commission
Anchorage
(J {-) ~ <,.., ~ !.' ~ I't 1
i !~,,'1{~w~!,~"f!"
it,\" .!\_..Jit\\\:l,.J, ,
~ ~ "'-"" ¡, ~ ~"t "\ ,",-
"
( STATE OF ALASKA ~:
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
\¡.Jc;A "L/if/O7-
!r ~1'1
o)":s 2( 'I 10 è
ðfv\ \t- 91?/ {) J-
- .
1. Type of request:
Abandon- Suspend-
Alter casing - Repair well -
Change approved program -
2. Name of Operator
Phillips Alaska, Inc.
3. Address
P. O. Box 100360
Anchorage, AK 99510-0360
4. Location of well at surface
869' FNL, 2226' FWL, Sec. 17, T8N , R7E, UM
At top of productive interval
2616'FSL,2209'FWL,Sec.16,T8N, R7E, UM
At effective depth
At total depth
2580' FSL, 2382' FWL, Sec. 16, T8N , R7E, UM
12. Present well condition summary
Total depth: measured
true vertical
Effective depth:
measured
true vertical
Casing
CONDUCTOR
SURFACE
PRODUCTION
PRODUCTION
PRODUCTION
Length
110'
3683'
8180'
815'
Size
16"
7-5/8"
5-1/2"
3-1/2"
Perforation depth:
measured
8640' - 8650'
true vertical
5682' - 5692'
Operational shutdown -
Plugging -
Pull tubing -
5. Type of Well:
Development _X
Exploratory -
Stratigraphic -
Service
(asp's 444186,5869007)
(asp's 449442, 5867175)
(asp's 449614,5867138)
9038 feet
6050 feet
8898 feet
5920 feet
Plugs (measured)
Junk (measured)
Cemented
15 sx AS 1
410 sx AS Lite, 290 sx LiteCrete
62.5 bbls Class G
included above
Tubing (size, grade, and measured depth
3-1/2",9.3#, L-80 Tbg @ 8210' MD.
CAMCO 'OS' LANDING @ 505' MD.
Description summary of proposal _X Detailed operations program - BOP sketch -
Refer to attached Morning Drilling-Report for LOT Tests, surface cement details and casing detail sheets, schematic ~X
14. Estimated date for commencing operation 15. Status of well classification as:
February 1(2002
16. If proposal was verbally approved
Packers & SSSV (type & measured depth)
No packer
13. Attachments
Oil_X
Re-enter suspended well -
Time extension - Stimulate -
Variance - Periorate -
6. Datum elevation (OF or KB feet)
RKB 251 feet
7. Unit or Property name
Other _X
Annular Disposal
Kuparuk River Unit
8. Well number
2P-415A
9. Permit number I approval number
201-226
10. API number
50-103-20383-01
11. Field I Pool
Kuparuk River Field / Meltwater Pool
Measured Depth
110'
3713'
8210'
9025'
True vertical Depth
110'
2449'
5288'
6038'
RECEIVED
FEB 0 1 200?
Alaska Oil & Gas Cons, Commission
Anchorage
Gas-
Suspended -
Name of approver Date approved Service
17. I herebC!,.,.r:ilp:t the lorogOIn?1 t1 and c()rr~ct to the bf'.st of my knowlcc.lrje.
lAY y f2~TJI
Signed i - -- Title: Drilling Engineering Supervisor
c. Mallarv
V FOR COMMISSION USE ONLY
Conditions of approval: Notify Commission so representative may witness
Plug integrity - ,BOP Test - Location clearance - e t
Mechanicall~tegritv Test )l~ Subsequent form required 10-~
Approved by order of the Commission
Form 10-403 Rev 06/15/88 .
Original Signed By
- .... L .I!
.
ORiGiNAL
QuasllDrs? Call Pat R.~5-6(Ma
h8œM b, ~::~ AL:!!!.3;
Approval no. ,?Ii) - eLl C\
o-t l'tVU/Ut(l,\¡/ c4~ro ~C{.l, wGA-
Date <~ / <If) J-;
I
Commissioner
~
SUBMIT IN TRIPLICATE
('
("
('
Annulus Disposal Transmittal Form - Well 2P-415
A. Designation of the well or wells to receive drilling 2P-415
wastes:
B, The depth to the base of freshwater aquifers and No Aquifers 1 Base Permafrost = +1- 14541 TVD RKB
permafrost, if present.
C, A stratigraphic description of the interval exposed to the From the 9-5/8" shoe to the Cement top all that is open
open annulus and other information sufficient to support is interbedded claystone, siltstone and shale with
a commission finding that the waste will be confined and occasional minor non-hydrocarbon bearing sands,
will not come to the surface or contaminate freshwater,
D, A list of all publicly recorded wells within one-quarter See attached horizontal plane clearance report and plot
mile and all publicly recorded water wells within one mile indicating no surface shoes within 1/4 mile of the
of the well to receive drilling waste, surface casing shoe of 2P-415, There are no potable
water wells within one mile of 2P-415,
E. Identify the types and maximum volume of waste to be Types of waste can be drilling mud, drilling cuttings,
disposed of and the estimated density of the waste cement-contaminated drilling mud, completion fluids,
slurry, diesel, formation fluids associated with the act of drilling
a well, domestic waste water, and any added water
needed to facilitate pumping of drilling mud or drilling
cuttings, Maximum volume to be pumped is 35,000
bbls.
F, An estimate of maximum anticipated pressure at the Maximum anticipated pressure at casing shoe du ring
outer casing shoe during annular disposal operations disposal operations is 1,971 psi. See attached
and calculations showing how this value was calculation page,
determined,
G, Details that show the shoe of the outer casing is set See attached: cementing reports, LOT 1 FIT reports and
below the base of any freshwater aquifer and casing reports,
permafrost, if present, and cemented with sufficient
cement to provide zone isolation:
H. Details that show the inner and outer casing strings See attached casing summary sheet and calculation
have sufficient strength in collapse and burst to pages.
withstand anticipated pressure of disposal operations:
I. Any additional data required by the Commission to
confirm containment of drilling wastes:
. .
,"
(
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2000
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'200
4800
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2800
2400
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Structure: Drill Site 2P
Field: Meltwater
1200
BOO
400
400
f
Alaska,
Inc
Well: 41 SA
location: North Slope. Alaska
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BOO
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J600
2000
2400
2BOO
J200
1200
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4800
5200
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(
H 0 R I Z 0 N TAL
Phillips Alaska, Inc.
Drill Site 2P
4l5A
slot *415
Meltwater
North Slope, Alaska
P LAN E
C LEA RAN C E
(
R E PO R T
Field is centred on 44l964.235,586989l.466,999.00000,N
Structure is centred on 44l964.235,586989l.466,999.00000,N
~
Baker Hughes INTEQ
Your ref: MWD <5552 - 9038'>
Our ref: svy665l
License:
Date printed: l4-Dec-200l
Date created: 2-Dec-200l
Last revised: 3-Dec-200l
Slot location is n70 3 9.983,w150 26 47.976
Slot Grid coordinates are N 5869006.867, E 444185.881
Slot local coordinates are 867.73 S 2228.54 E
Projection type: alaska - Zone 4, Spheroid: Clarke - 1866
Reference North is True North
Report is limited to clearances less than 2000 feet
Object wellpath
DECREASING CLEARANCES of less than 1000 feet are indicated by an asterisk, e.g. 487.4*
MWD <0-9224'>,,438,Drill Site 2P
MWD <0 - 6008'>,,4l7,Drill Site 2P
MWD <0-6860'>, ,420,Drill Site 2P
MWD <O-???'>, ,429,Drill Site 2P
MWD <3660 - 11075'>,,4l5,Drill Site 2P
PMSS <22l2-7349'>"MWN#2A,Meltwater North #2
PMSS <0-6300'>"MWN#2,Meltwater North #2
PMSS <0-6l22'>"MWN#l,Meltwater North #1
PMSS <0-8935'>"MWSouth1,Meltwater South #1
Closest approach with Horizontal
Last revised Distance M.D.
4-Jun-2001 459.9 230.3
25-May-2001 38.7 261.0
30-0ct-2001 99.4 230.3
14-Dec-2001 279.0 261.0
2-Dec-2001 0.0 5552.0
26-Feb-2001 478.4 5024.4
26-Feb-2001 415.2 5096.6
26-Feb-2001 6234.0 3919.5
6-Mar-2001 45267.2 7988.1
Plane method
Diverging from M.D.
230.3
261.0
8805.5
261.0
5552.0
5024.4
5096.6
3919.5
8565.0
(
(
Phillips Alaska, Inc.
Drill Site 2P,415A
Meltwater , North Slope, Alaska
CLEARANCE LISTING Page 1
Your ref : ~~ <5552 - 9038'>
Last revised: 3-Dec-2001
Reference wellpath
Object wellpath : MWD <3660 - 11075'>,,415,Drill Site 2P
Horiz Horiz Min'm
M.D. T.V.D. Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist
3713.0 2448.7 1008.2S 2074.7E 3712.9 2448.6 1008.2S 2074.7E 295.7 0.1 0.0
Coordinates
All data is in feet unless otherwise stated.
Casing dimensions are not included.
from slot #415 and TVD from RKB (Doyon 141) (254.00 Ft above mean
Vertical section is from wellhead on azimuth 108.16 degrees.
Calculation uses the minimum curvature method.
Presented by Baker Hughes INTEQ
sea level).
(
(
Phillips Alaska, Inc.
Drill Site 2P,415A
Heltwater,North Slope. Alaska
CLEARANCE LISTING Page 2
Your ref: MWD <5552 - 9038'>
Last revised: 3-Dec-2001
Reference wellpath
Object wellpath : PHSS <2212-7349'>,.MWNi2A,Heltwater North *2
M.D.
T.V.D.
Rect Coordinates
H.D.
T.V.D.
Rect Coordinates
Horiz
Bearing
Horiz
Dist
Min'm
Dist
3713.0
2448.7
1008.2S
2074.7E
2445.4
2448.7
1217.1S
3494.7E
98.4 1435.3
13 82 . 7
Coordinates
All data is in feet unless otherwise stated.
Casing dimensions are not included.
from slot #415 and TVD from RKB (Doyon 141) (254.00 Ft above mean
vertical section is from wellhead on azimuth 108.16 degrees.
Calculation uses the minimum curvature method.
Presented by Baker Hughes INTEQ
sealevel).
3713.0
(
.'
(
Phillips Alaska, Inc.
Drill Site 2P,415A
Meltwater,North Slope, Alaska
CLEARANCE LISTING Page 3
Your ref : m~ <5552 - 9038'>
Last revised: 3-Dec-2001
Reference wellpath
Object wellpath : PMSS <0-6300'>"MWNi2,Meltwater North i2
M.D.
Rect Coordinates
Horiz
Bearing
Horiz
Dist
Min'm
Dist
T.V.D.
T.V.D.
Rect Coordinates
M.D.
2448.7
1008.2S
2074.7E
2445.6
2448.7
1217.2S
3491.4E
98.4 1432.0
1400.2
Coordinates
All data is in feet unless otherwise stated.
Casing dimensions are not included.
from slot #415 and TVD from RKB (Doyon 141) (254.00 Ft above mean
Vertical section is from wellhead on azimuth 108.16 degrees.
Calculation uses the minimum curvature method.
Presented by Baker Hughes INTEQ
sealevel).
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Intermediate
Well
Date
2P-415
1/31/2002
Surface
(
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TVD
2449 ft.
Surface CasinQ
Size
Wt.
Grade
Pburst @ 100%
Pburst @ 85%
Fluid Weight on Backside
Max Disposal Pressure
7.625 In.
29.70 Ibs.
L 80
6890 psi
5857 psi
8,3 ppg ",,/
1500 psi
42.5 ppg /
Maximum Mud Weight =
(to burst casing)
Surface Casing Burst
MMW = Pb@85%+(Fluid Weight on Backside)(.O52)(TVD)-Max Disposal Press
(.O52)(TVD)
Maximum Pressure at Surface Shoe
Max Disposal MW 12,0 ppg
Max Pressure at Surface Shoe = 1971 psi /°
Max Pressure at Surface Shoe
Max Press=Max Disposal Press+(Max Disposal MW)(.O52)(TVD)-(Fluid Wt. On Backside)(.O52)(TVD)
Intermediate Casina
Size
Wt.
Grade
Pcollapse @ 1 00%
Pcollapse @ 85%
Gas Depth (TVD)
Gas Gradient
Max Disposal Pressure
5.500 In.
15,50 Ibs,
L 80
4990 psi
4242 psi
2449 ft.
0.11 ppg
1500 psi
Maximum Mud Weight =
(to collapse casing)
/'
23.6 ppg
Intermediate Casing Collapse
MMW = Pc@85%+(Gas Gradient)(Gas TVD)-Max Disposal Press
(TVD)(.O52)
CASING TEST and FORMATION INTEGRITY TEST
Well Name:
11/13/2001
Supervisor: Dearl W. Gladden
2P - 415
Date:
Reason(s) for test:
0 Initial Casing Shoe Test
0 Formation Adequacy for Annular Injection
0 Deep Test: Open Hole Adequacy for Higher Mud Weight
Casing Size and Description: 75/811 29.7# L-80 BTC-M
Hole Depth:
3,749' TMD
2,462' TVD
Casing Setting Depth:
3,713' TMD
2,4481 TVD
Mud Weight:
Length of Open Hole Section:
361
10.0 ppg
r::;?"""--~.'
EMW=
=
1770 psi
O.Ò52X 2,462'
/
EMW for open hole section = 16.0 ppg
Leak-off Press. + Mud Weight
0.052 x TVD
+ 10,0 ppg
Fluid Pumped = 0.6 bbl
Pump output = 0.1010 bps
3,000 psi
2,900 psi
2,800 psi
2,700 psi
2,600 psi
2,500 psi
2,400 psi
2,300 psi
2,200 psi
2,100 psi
2,000 psi
1,900 psi
W 1,800 ps~
c: 1,700 pSI
:) 1,600 psi
en 1,500 psi
æ 1,400ps~
c: 1,300 pSI
D. 1,200 psi
1,100 psi
1,000 psi
900 psi
800 psi
700 psi
600 psi
500 psi
400 psi
300 psi
200 psi
100 psi
Opsi
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t-1~CASING TEST
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LEAK-OFF DATA
1
MINUTES
FOR
LOT STROKES PRESSURE
I----------------¡----------------'- ------------ ----,
: : 0 stks: 0 psi :
'---------------_.I.._--------------~-----------------1
! ¡ 2 stks ! 240 psi I
1----------------""---------------"-----------------4
! ! 4 stks ¡ 560 psi!
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! ! 6 stks ¡ 770 psi""":
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'20" ,765.'
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1 ,mln 1 1 pSI I
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: 6,0 mln : : 755 pSI I
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I 7.0 mln : : 750 pSI I
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, 9 0 'I I 745 . ,
I ,minI I pSI I
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¡ 10,0 min ¡ ¡ 745"",5i ¡
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CASING TEST DATA
MINUTES
FOR
CSGTEST STROKES PRESSURE
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..----------------Þ---------------1-----------------1
! ¡ 6 stks ! 750 psi ¡
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! ! 8 stks I 925 psi!
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~---- ------------~ -_!~-~~-~!_-~-_!!~-~-~_p'~~. ~
I : 12 stks 1 1 ,350 psi
t--- ------ -- -- ---t--:¡~f štkš--l-:¡:6"õ-Õ-¡;s r I
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I : 16 stks I 1,895 pSI:
L_---------------t---------------1----------------_..I
! : 18 stks 1 2,190 psi! ~
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I , 20 stks I 2,495 pSI:
.. ---- ------------þ ---- -----------1 - ----------------..
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r -- -- -- ----------r---- -- -- -- -----.,--- --------------.,
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:----------- -.- -- -- t ------- ------ -- ~---------------.---i
I 2,0 mln I I 2,490 pSI '-"--ê-
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¡ 3.0 min I I 2,485 psi
L__-- -- ----------t-- ---------- ---1-----------------~
! 4,0 min , I 2,480 psi!
,"-------- ---_____"n -- - - - --------..-----------------..
! 5,0 min ! ! 2,480 psi!
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! 6.0 min ! ! 2,475 psi!
,.------------ ----,.------------- - -of-----------------"
! 7,0 min ! ! 2,470 psi!
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! 8.0 min I : 2,470 psi I
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I 10,0 mln : I 2,460 psi:
~-- ------ ----:----t ------------ ---- ---------------,;---i
I 15.0 mln : I 2,460 pSI:
L______-- --------t------ -- -------..1--- ------- -------..1
! 20.0 min : ! 2,455 psi i
L------- ----- ---- ..----- -------- --,,------ -----------..1
! 25,0 min ! ! 2,455 psi ¡
..- ----------- -- -- þ----- ----------1---- -------------.. ~
i --~~.:Q_~J~__Lm_--- ------ L _3!~~_~_E~~J
NOTE: TO CLEAR DATA, HIGHLIGHT AND PRESS THE DELETE KEY
CASING TEST and FORMATION INTEGRITY TEST
Well Name:
2P-415
12/5/2001
Date:
Supervisor: Dearl W. Gladden
Reason(s) for test:
D Initial Casing Shoe Test
[2] Formation Adequacy for Annular Injection
D Deep Test: Open Hole Adequacy for Higher Mud Weight
Casing Size and Description: 75/8" 29.7# L-80 STC M
Casing Setting Depth:
Hole Depth:
5,760' TMD
3,298' TVD /'
3,713' TMD
2,448' TVD
2,047' v'
9.9 ~pg
Length of Open Hole Section:
+ 9,9 ppg
Mud Weight:
EMW=
-
960 psi
0.052 x 3,298'
/" !~q~,o
EMW for open hole section = 15.5 ppg '-GII',!tJ
Leak-off Press, + Mud Weight
0,052 x TVD
~'tt i -
l ~r~\
~ 15, I I' ....)
Pump output = 0.1010 bps
Fluid Pumped = 8.1 bbl
2,800 psi
2,700 psi
2,600 psi
2,500 psi
2,400 psi
2,300 psi
2,200 psi
2,100 psi
2,000 psi
1,900 psi
1,800 psi
1,700 psi
~ 1,600 psi
~ 1,500 psi
en .
en 1,400 ps~
W 1,300 pSI
a: 1,200 psi
Q. 1,100psi
1,000 psi
900 psi
800 psi
700 psi
600 psi
500 psi
400 psi
300 psi
200 psi
100 psi
0 psi
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! ¡ 4 stks ¡ 190 psi!
1----------------""'-- -------------¿--- --------------..
! ¡ 8 stks ! 300 psi!
1----------------+---------------.-----------------.
¡ ¡ 12 stks ! 410 psi!
,----------------..----------------.-----------------..
I I 16 stks : 500 Psi:
, , , ,
,----------------.,..---------------.-----------------,
: : 20 stks I 580 psi I
:----------------+---------------~-----------------~
: : 24 stks : 650 psi:
:----------------+---------------f-----------------'¡
: : 28 stks : 720 psi:
,----------------+---------------t-----------------i
! ; 32 stks : 780 psi I
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¡ ! 36 stks ! 860 psi ¡
1----------------""'---------------"-----------------"
! ! 40 stks ! 890 psi!
1----------------+---------------.-----------------"
i ! 44 stks ! 870 psi ¡
,----------------..----------------.-----------------..
! ! 48 stks ! 900 psi ¡
,----------------.,..-------------- -, -----------------,
: : 52 stks : 930 psi:
1-- --------------+---------------~------- --- -------~
: : 56 stks : 930 psi:
:----------------+---------------f-----------------'¡
: : 60 stks : 960 psi:
,----------------+---------------t-----------------'¡
! : 64 stks : 920 psi I
I_--____---------..---------------¿-----------------.I
¡ ! 68 stks ! 910 psi!
'----------------""'---------------"-----------------"
! ! 72 stks ! 940 psi!
1--------------- -+---- -----------.------------- ----..
! ! 76 stks ! 940 psi ¡
1----------------"----------------.-----------------"
: : 80 stks : 940 Psi I
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¡ SHUT IN TIME ¡ SHUT IN PRESSURE
:------------:-----+---------------¡----- ---------:----¡
: 0.0 mln : : 940 pSI:
,----------------.....---------------..-----------------..
, 10 ., 1 940 . ,
: . mln I : pSI:
1----------- -----+------- --------.-----------------..
'20' 1 '935"
: .mlnl I pSI:
1--------------- -..------- ---------.--- --------------..
'30" '930"
I .mlnl I pSI:
r-----------:-----T---------------1-------------:---1
, 4.0 mln , , 920 pSI I
¡------------:-----t---------------t -------------: ---i
. 5.0 mln , , 910 PSI,
:------------:-----+---------------f-------------:---'¡
: 6.0 mln : : 895 pSI:
:------------:-----+---------------t-------------:---i
: 7.0 mln : : 895 pSI I
'----------------"--------------_¿_----------------1
i 8,0 min ! ! 885 psi:
,----------------.....---------------..-----------------..
'90" '885"
: ,mini I pSI:
1----------------+---------------"-----------------"
L_!Q:9._rn!~--L--------______L --~~~.p_~L_.J
CASING TEST DATA
MINUTES
FOR
CSG TEST STROKES PRESSURE
,"--- ------ -- ----- r----- ----- -----,-- ---------------,
I ; 0 stks: 0 psi :
~--------------- -t---- -- -------- -1- _____n__-------i
1 , , ,
, 1 I ,
..--- ------ -------..------- --------..-- ----- --- -- -----..
: : I :
, I I J
.. ----------- ---- -..------ -------- -..- -- ----- ----- ----..
, , , ,
, , , ,
I I I I
..--------------- -..-- ------------- ..------ -----------..
, , , I
, I I 1
, I , ,
r------ -- n__-- -- r--- ------------,-----------------,
: ' , ~,
..----------------~-------- -------~--------------- -. -
I I ,
, , ,
~---- n______----~--------------- ~-----------------
I I I :
~---------- ------ ~------------- --- -----------------of
1 I I ,
, I , I
~ - -- -------------t---- -- - - -- -----1- ----- -- ---- - - --- i
, , , I
, , I I
..-------------- -- ..-- -------------..- ----- -------- ---...
, , I 1
I' ,
J I 1
..--------- ------- þ------- ---- ----..---- --____n-----"
, I I '
" I
" I
.. - ---------------..------- --------..-----------------..
, , I '
" ,
" I
..---------------- r---------------'- ---------- ------..
I I , I
1 , , ,
~- ---- --- - - - ----- ~------------- -- ~------ ----- ------~
, , I I
~-- -- ------------~-- ------ -------~ -- - -- ------------~
I , , ,
, I , ,
~------------ ---- ~----- ---- - ---- -i-- -- - ---- --------of
I . , ,
, J , I
~--- -- -- -- -- -----t---------------1---- - ----- ---- ---1
, I , I
, I , ,
.. ----------------..---------- -----..-- --- ------------...
I , , ,
1 , J I
I , J I
..------------ -- --..- -- ------------ ..-----------------..
, , , I
J I , I
I , , ,
! SHUT IN TIME! SHUT IN PRESSURE
..----------------..---------------,---------______n.,
. 0 0 " '0 ' ,
I . mln I I pSI 1
~--------- -- ----- ~--------- ---- - -~---- --- -----------1
I 1,0 min : I I
~-----------.----- ~--- -- ---- ------ ~------ ----- - ------1
I 2,0 mln I I -'-
~------- ----.----- ~--------- -- --- -i-- -- - ____-n----'
I 3,0 mln : I
.. ----------______L____---- -- -----.1-------------- ---...
¡ 4.0min ! ! ¡
..--- ---------- -- - ..------- ------- -..---- - ------------...
! 5.0 min ! ! i
r----- ------,-- ---r----------- -- - -1---- -- - ___n-----1
: 6,0 mln I : :
.. -- -- ---- --------..-- -------- ----- ..-----_____n- - ---..
i 7,0 min ! ! !
..-------- --------..--- - --- ------ --,- ----------- --_n,
: 8.0min : I :
1--- - ------ ---- -- - }.------- ----- -- -~ ---- --- -------- ---I
: 9,0 min : I :
~-------- ----.----~_____n --------~------------ - -----I
I 10,0 mln I : I
~------------.---- ~---------------- ------ -----------of
: 15.0 mln : : :
~------------.----t---------- -----'1 ----- --_n -------i
I 20.0 mln I : I
..- ---------------..--- --- - --------..- -______n__n___'"
! 25,0 min ! ! !
r------------.----t---------------1-----------------1
I 30,0 mJn I I I
..---- ------ ------..----- ---- ------..- - ---------------..
NOTE: TO CLEAR DATA, HIGHLIGHT AND PRESS THE DELETE KEY
API: 501032038301
SSSV Type: Nipple
Annular Fluid:
Reference Loq:
Last Taa: 8482
Last TaQ Date: 12/28/2001
Casiml String - ALL STRINGS
Description Size
CONDUCTOR 16.000
SURFACE 7.650
PRODUCTION 5.500
PRODUCTION 3.500
Tubina String - TUBING
Size I Top I Bottom I TVD I Wt I Grade I
3.500 1 0 1 8210 1 8210 1 9.30 I L-80 I
Peñorations Summary
Interval TVD I Zone I Status I Ft ISPFI Date I Tvpe I Comment
8640 - 8650 8640 - 8650 I I I 10 1 6 112/24/20011 IPERF 1 HMX ChrQs, 60 deQ ph
Gas Lift MandrelsNalves
St MD TVD Man
Mfr
1 2836 2836 CAMCO
2 5663 5663 CAMCO
3 6866 6866 CAMCO
4 7541 7541 CAMCO
5 8091 8091 CAMCO
Other plugs equip,. ,ete,
Depth TVD Type
505 505 NIP
8132 8132 SLEEVE
8148 8148 NIP
8191 8191 LOCATOR
8192 8192 SEAL
8898 8898 Plug
Catcher
GenetáINótes...,.'.......'... ....'."'... ... .......... c
Date I Note
12/31/20011 FCO to 8870.1' CTMD
('
~PHILLIPS Alaska, Inc.
~ A Subsidiary of PHILLIPS PETROLEUM COMPANY
TUBING
(0-8210,
00:3.500,
10:2.992)
2P-415A
SURFACE
(0-3713,
00:7.650,
Wt:29.70)
-\
~+
;,
"
'0'
.,
:.
'J::
.,:
I
-.
PRODUCTION
(0-8210,
00:5.500,
Wt:15.5O)
--
I
""""
>"""------.'r
i
Gas Lift
MandrelNalve
5 (8091-8092,
00:4.750)
SLEEVE
(8132-8133.
00:4.500)
NIP
(8148-8149,
00:3.750)
.
LOCATOR
(8191-8192,
00:4.500)
SEAL
(8192-8193,
00:4.000)
.,.... '.....
...:.. .:c'.'
-
.....
.'.'
Pert
(8640-8650)
~
-
r---
r--
r---
r--
-
-
-
Plug Catcher
(8898-8899,
00:3.500)
--~---
(
KRU
Well Type: PROD
OriQ Completion:
Last W/O:
Ref Log Date:
TD: 9025 ftKB
Max Hole Angle: 0 deQ ~
Top
0
0
0
8210
Bottom
110
3713
8210
9025
Man
Type
KBG-2-9
KBG-2-9
KBG-2-9
KBG-2-9
KBG-2-9
- JEWELRY
VMfr
2P-415A
Anale (á) TS: dea ~
AnQle @ TD: deç¡ (á)
Rev Reason: FCO by ImO
Last Update: 1/1/2002
TVD
110
3713
8210
9025
Wt
62.50
29.70
15.50
9.30
Grade
H-40
L-80
L-80
L-80
Thread
WELD
BTC Mod
BTC Mod
BTC Mod
Thread
8RD EUE
V Type V OD Latch Port TRO
Vlv
Cmnt
DMY
DMY
DMY
DMY
OV
1.0
1.0
1.0
1.0
1.0
BTM
BTM
BTM
BTM
BTM
0.000
0.000
0.000
0.000
0.313
0
0
0
0
0
Date
Run
12/4/2001
12/4/2001
12/4/2001
12/4/2001
12/28/2001
..
Description
CAMCO 'DS' LANDING NIPPLE
BAKER CMU NON-ELASTOMER SLIDING SLEEVE W/CAMCO DS PROFILE
CAMCO 'D' NIPPLE
BAKER LOCATOR SUB
BAKER G-22 LOCATOR SEAL ASSEMBLY 80-40
.. ..... .,'.., ..
ID
2.875
2.812
2.750
3.000
3.000
0.000
------- -- --- --
- ------ - - - -- --
-..PH~ILLIPS~ALA~KA INC.
-- -- -
--ea~i...gAepo rt
Legal Well Name: 2P-415
Common Well Name: 2P-415
Event Name: ROT - DRILLING
---General.-Information
Report #: 1
Start: 11/2/2001
String Type: Surface Casing
Hole TVD: 2,448.0 (ft)
Ground Level: 224.00 (ft)
Circ Hours: 3.50 (hr)
Permanent Datum:
KB-Datum:
CF Elevation:
Mud Lost:
Rotary Kelly Bushing
228.65 (ft)
(ft)
(bbl)
Hole Size:
Water TMD:
Liner Overlap:
KB to Cutoff:
------ -- -- --
Cé1Sil1gFïånge lWellhead .
Manufacturer:
Hanger Model:
FMC
A-75 Fluted
Mod~: GenV
Packoff Model:
Actual TMD Set: 3,713.01 (ft)
(ft)
(ft)
27.90 (ft)
Threads
Iri~E!g..aICasingDetaii --
- I - - ---- !MU Torq. =rHD
--I --.(ft~lbf)
--- Drift
(in) --
Casing Hanger
Casing
Cement Stage Tool
Casing
Float Collar
Casing
Float Shoe
7.625
7.625
1
22
1
61
1
2
1
2.57
957.58
2.42
2,632.91
1.33
86.79
1.51
29.701 L-80
6.7501 BTC
7.625
7.625
7.625
7.625
29.701 L-80
6.7501 BTC
29.70 I L-80
6.7501 BTC
27.90
30.47
988.05
990.47
3,623.38
3,624.71
3,711.50
- Spacing
(ft)
Accessory --.
Non-lntegräfCa!)ing Accessories
Bowspring Centralizer
Number
12
-.Remarks ..
Page 1 of 1
Spud Date: 11/4/2001
Report Date: 11/11/2001
End:
Hole TMD:
Str Wt on Slips:
Max Hole Angle:
Days From Spud:
3,713.0 (ft)
90 (Ibs)
66.00 (O)
5.50 (days)
--'--
Top Hub/Flange: (in) 15,000 (psi)
BTM Hub/Flange: (in) /5,000 (psi)
Model
Cond, I Max CD Min ID I Compo Name
(in) (in)
Casing Hanger
6.875175/8" 29.7# L-8
Cement Stage TI
6.8751 75/8" 29.7# L-81 r~
Float Collar
6,875175/8" 29.7# L-8
Float Shoe
Interval
How Fixed
3,193.0
Bottom (ft)
3,713.0 1 OverCollar
Ran Weatherford Bow Spring Cent. in the middle of jts 1,2,&3 on stop rings and across collar on 4 thru 12. No probl
ems of any kind on complete Csg job.
Printed: 1/31/2002 2:18:55 PM
(
('
PHILLIPS ALASKA INC.
Cementing Report
Legal Well Name: 2P-415
Common Well Name: 2P-415
Event Name: ROT - DRILLING
Report #:
Start:
1
11/2/2001
Cement Job Type: Primary
Prima
Hole Size: 9.875 (in) Hole Size:
TMD Set: 3,713 (ft) sa TMD: (ft)
Date Set: 11/11/2001 sa Date:
Csg Type: Surface Casing sa Type:
Csg Size: 7.625 (in.)
Cmtd. Csg: OPEN HOLE Cmtd. Csg:
Cement Co: Dowell Schlumberger
S ueeze Casin
Hole Size:
TMD Set:
Date Set:
Csg Type:
sa TMD:
sa Date:
Cmtd. Csg:
Cementer: Kevin Anderson
Rot Time Start: :
Rec Time Start:16:00
Time End: :
Time End: 21 :35
RPM:
SPM:
Init Torque: (ft-Ibf)
Stroke Length: 12.0 (ft)
Avg Torque: (ft-Ibf)
Drag Up: 112 (Ibs)
Max Torque: (ft-Ibf)
Drag Down: 75 (Ibs)
Page 1 of 3
Spud Date: 11/4/2001
Report Date: 11/11/2001
End:
Plu
Hole Size:
Top Set:
BTM set:
Plug Date:
Plug Type:
Drilled Out:
Cmtd. Csg:
(ft)
(ft)
Pipe Movement
Pipe Movement: Reciprocating
Stage No: 10f1
Type: Cement Casing Start Mix Cmt: 20:19 Disp Avg Rate: 5.50 (bbl/min) Returns: Full
Volume Excess %: 430.00 Start Slurry Displ: 20:44 Disp Max Rate: 6.00 (bbl/min) Total Mud Lost: (bbl) ,"/
Meas. From: Surface Start Displ: 22:22 Bump Plug: Y Cmt Vol to Surf: 120.20 (bbl)
Time Circ Prior End Pumping: 22:56 Press Prior: 450 (psi)
To Cementing: 3.50 End Pump Date: 11/11/2001 Press Bumped: 600 (psi) Ann Flow After: N
Mud Circ Rate: 252 (gpm) Top Plug: Y Press Held: 850 (min) Mixing Method:
Mud Circ Press: 250 (psi) Bottom Plug: Y Float Held: Y Density Meas By:
Type: KCL Polymer Density: 9.6 (ppg) Visc: 45 (s/qt)
Bottom Hole Circulating Temperature:56 (OF)
Displacement Fluid Type:Mud
PVNP: 12 (cp)/15 (lb/100ft2) Gels 10 sec: 5 (lb/100ft2) Gels 10 min: 11 (lb/100ft2)
Bottom Hole Static Temperature: (OF)
Density: 9.6 (ppg) Volume: 160.69 (bbl)
~ - - -
- - - -
- -- - -- - --
- -
Stêlg~ No: 1SlurrY~O:1()f2
Slurry Data
Fluid Type: LEAD Description: ASLite
Slurry Interval: (ft) To: 1,546.00 (ft) Cmt Vol: 325.0 (bbl)
Water Source: Rig Tanks Slurry Vol:410 (sk)
Test Data
Thickening Time: 6.00
Free Water: (%)
Fluid Loss: (cc)
Fluid Loss Pressure:
Temperature: 74 (OF)
Temperature: (OF)
Temperature: (OF)
(OF)
Class:
Density: 10.70 (ppg) Yield: 4.45 (fP/sk)
Water Vol: 202.0 (bbl) Other Vol: 0
Time
Compressive Strength 1:
Compressive Strength 2:
Purpose: PRIMARY
Mix Water: (gal)
Foam Job: N
Temp
74 (OF)
80 (OF)
Pressure
50 (psi)
500 (psi)
Printed: 1/31/2002 2:18:37 PM
(
(
PHilliPS ALASKA INC.
Cementi n9 Report
Page 2 of 3
Legal Well Name: 2P-415
Common Well Name: 2P-415
Event Name: ROT - DRILLING
Report #:
Start:
1
11/2/2001
Spud Date: 11/4/2001
Report Date: 11/11/2001
End:
Stage No: 1 Slurry No: 1 of 2 - Additives
Trade Name
T e
Concentration
Units
Li uid Conc.
Units
G
D-124
D-053
D-079
S-001
D-046
0-065
FILLITE
50.0
30.0
1.5
1.5
0.6
0.5
Stage No: 1 Slurry No:2 of 2
Slurry Data
Fluid Type: TAIL Description: LiteCRETE Class:
Slurry Interval: 1,566,00 (ft)To: 3,719.00 (ft) Cmt Vol: 142.5 (bbl) Density: 12.00 (ppg) Yield: 2.40 (fP/sk)
Water Source: Rig Tanks Slurry Vol:290 (sk) Water Vol: 56.0 (bbl) Other Vol: 0
Purpose: PRIMARY
Mix Water: 8.16 (gal)
Foam Job: N
Test Data
Thickening Time: 2.13
Free Water: 8.16 (%)
Fluid Loss: (cc)
Fluid Loss Pressure: (OF)
Temperature: 74 (OF)
Temperature:72 (OF)
Temperature: (OF)
Time
Compressive Strength 1:
Compressive Strength 2:
Temp
(OF)
(OF)
Pressure
50 (psi)
500 (psi)
-- Concentration
-- -- - - --- -- - - -- --
- - - -
- - - --
- - -
Stage No: 1 Slurry No:2 bf2 .. Additives -
CemPLUS Blend
D046
D065
D079
Liner Top~Test .-
Test Press: 2,500 (psi)
For: 30 (min)
Cement Found between
Shoe and Collar: N
Pressure: 16.00 (ppge)
Tool: N
Open Hole: 36 (ft)
Hrs Before Test:
Liner Lap:
Pos Test: (ppge)
Neg Test: (ppge)
Hrs Before Test:
Cement Found on Tool: N
Tool: N
Tool: N
- ~ -
- -
~ - - -
Log/Survey Evaluation-
. Interpretation Summary
CBL Run: N
Under Pressure: (psi)
Bond Quality:
Cet Run:
Bond Quality:
Temp Survey: N
Hrs Prior to Log:
N
Cement Top: (ft) ,.
How Determined: 120 bbls to surface .,/'
TOC Sufficient: Y
Job Rating:
If Unsuccessful Detection Indicator:
Remedial Cementing Required:
Number of Remedial Squeezes:
N
Printed: 1/31/2002 2:18:37 PM
(
(
PHILLIPS ALASKA INC.
Cementing Report
Page 3 of 3
Legal Well Name: 2P-415
Common Well Name: 2P-415
Event Name: ROT - DRILLING
Report #:
Start:
1
11/2/2001
Spud Date: 11/4/2001
Report Date: 11/11/2001
End:
Remarks
Pump 10 bbl CW100,Test lines 3500psi,30 bbl CW100, Drop Bttm Plug, 30 bbls MudP
USH @ 10.5# wi Dye, 325 bbls Lead @ 10.7# ,124 bbls Tail @ 12.0# , Drop Top PI
ug ,5 bbl HBP--thru tub ,Displace w/Mud Rig Pumps 1591 stks (160.69 bbls) Bumped
plug wi 650 psi -Held 850 psi 5 min - Bleed presure off - Floats held. Ran 12 w
eatherford bow spring centrilizers - 1 ea. in the middle of its 1,2,3 over stop collar
and across collar on 4 thru 12 .
Printed: 1/31/2002 2:16:37 PM
.. ..
f'HI L~IP~A LASKA INC.
. .... -. .... .. ... .' .... ... ..
. .." ... .'"
.C-.'.--""R' ':.. ... ... t
:......8Slng . epor.
, .
Page 1 of 2
Legal Well Name: 2P-415
Common Well Name: 2P-415
Event Name: ROT - DRILLING
Report #: 2
Start: 11/2/2001
Spud Date: 11/4/2001
Report Date: 12/4/2001
End:
'. . Genets I Inform ati ()11
String Type: Production Casing
Hole TVD: 6,050.0 (ft)
Ground Level: 224.00 (ft)
Circ Hours: (hr)
Permanent Datum:
KB-Datum:
CF Elevation:
Mud Lost:
Rotary Kelly Bushing
228.65 (ft)
(ft)
(bbl)
Ca$il1gFlange {Wellhead
Hole Size:
Water TMD:
Liner Overlap:
KB to Cutoff:
(ft)
(ft)
25.35 (ft)
Hole TMD:
Str Wt on Slips:
Max Hole Angle:
Days From Spud:
9,038.0 (ft)
(Ibs)
68.89 (O)
28.50 (days)
,-.,
Manufacturer:
Hanger Model:
Actual TMD Set: 9,025.80 (ft)
FMC
Model: Gen 4/5
Packoff Model:
Top Hub/Flange: (in) 15,000 (psi)
BTM Hub/Flange: (in) I 5,000 (psi)
Item I Size Weight. Gracie "'Drift Threads.'. '. JTS Length. . Top MUrorq~ THO Manufacturer Model I cond'IMax OD Min 10 I Compo Name
...
(in.) '. (Ib/ft) . (in) '. .... (ft) .... (ft) (ft-Ibf) (in) (in)
CASING HANGER 5.500 4.825 BTC 1 2.70 25.35 FMC Gen. V
5 1/2 CASING - PRODU 5.500 15.50 L-80 4.825 BTC 191 8,150.25 28.05 4.950
5 1/2 CASING - PUP JT 5.500 15.50 L-80 4.825 BTC 1 11.20 8,178.30 BAKER 4.950
CROSS OVER COLLAR 5.500 4.825 BTC x SBE 1 1.16 8,189.50 BAKER 4.0601 1--
SEAL BORE EXTENSIO 5.000 4.000 SBE 1 19.44 8,190.66 BAKER 4.000
CROSS OVER 5.000 2.867 SBE x EUE 1 0.57 8,210.10 BAKER 3.000
31/2 CASING - PUP JT 3.500 9.30 L-80 2.867 EUE 1 10.00 8,210.67 2,992
3 1/2 CASING - PRODU 3.500 9.30 L-80 2.867 EUE 2 61.80 8,220.67 2.992
3 1/2 CASING - PUP JT 3.500 9.30 L-80 2.867 EUE 1 6.06 8,282.47 2.992
31/2 CASING - PRODU 3.500 9.30 L-80 2.867 EUE 1 31.41 8,288.53 2,992
31/2 CASING - PUP JT 3.500 9.30 L-80 2.867 EUE 1 8.05 8,319.94 2.992
3 1/2 CASING - PRODU 3.500 9.30 L-80 2.867 EUE 9 280.83 8,327.99 2.992
31/2 CASING - PUP JT 3.500 9.30 L-80 2.867 EUE 1 10.15 8,608.82 2.992
31/2 CASING - PRODU 3.500 9.30 L-80 2.867 EUE 9 278.93 8,618.97 2.992
PLUG CATCHER 3.500 1 8,897.90 Y WEATHERFORD 2.992
3 1)2 CASING - PRODU 3.500 9.30 L-80 2.867 EUE 1 31.42 8,897.90 Y 2.992
FLOAT COLLAR 3.500 EUE 1 0.96 8,929.32 Y WEATHERFORD
31/2 CASING - PRODU 3.500 9.30 L-80 2.867 EUE 3 94.42 8,930.28 Y 2.992
Printed: 1/31/2002 2:19:01 PM
o.
Page 2 of 2
, , , -
", , -"
Casing Report
Legal Well Name: 2P-415
Common Well Name: 2P-415
Event Name: ROT - DRILLING
Report #: 2
Start: 11/2/2001
Spud Date: 11/4/2001
Report Date: 12/4/2001
End:
Model
Cond, IMaxoo Min 10 I Compo Name
(in) (in)
Item.
"Grade I ,'.'Orift , I Thrë~dslJTS
(in)""
IIltijgÏ'al CasirigDetaii "
FLOAT SHOE
3.500
1
1.10
WEATHERFORD
--~.
"Non-Integral Casing ~ccessories
Accessory
", Manufacturer
Number
Spacing
(ft)
Interval
How Fixed
Bowspring Centralizer
Bowspring Centralizer
Centering Guides
WEATHERFORD
WEATHERFORD
PESI
25
17
29
Top (ft)
8,890.0
7,488.0
114.0
Bottom (ft)
9,015.0 Clamped
8,178.0 OverCollar
3,685.0 Slid On
... Remarks '"
Ran
25 jts. 3 1/2" L-80 9.3# EUE tubing
Ran
191 jts. 5 1/2" L-80 15.5# BTC casing
-
Printed: 1/31/2002 2:19:01 PM
(
~"
PHilliPS ALASKA INC.
Cementing Report
Legal Well Name: 2P-415
Common Well Name: 2P-415
Event Name: ROT - DRILLING
Hole Size:
TMD Set:
Date Set:
Csg Type:
Csg Size:
Prima
6.750 (in)
9,026 (ft)
12/4/2001
Production Casing
5.500 (in.)
Cmtd. Csg: Production Casing
Cement Co: Dowell Schlumberger
Report #:
Start:
2
11/2/2001
Cement Job Type: Primary
Hole Size:
sa TMD: (ft)
sa Date:
sa Type:
Cmtd. Csg:
S ueeze Casin
Hole Size:
TMD Set:
Date Set:
Csg Type:
sa TMD:
sa Date:
Cmtd. Csg:
Cementer: Steve Doughten
Pipe Movement
Rot Time Start: :
Rec Time Start:09:00
Time End: :
Time End: 19:30
RPM:
SPM:
Init Torque: (ft-Ibf)
Stroke Length: 12.0 (ft)
Type: Cement Casing
Volume Excess %:
Meas. From:
Time Circ Prior
To Cementing: 9.50
Mud Circ Rate: 210 (gpm)
Mud Circ Press: 410 (psi)
Start Mix Cmt: 18:26
Start Slurry Displ: 19:08
Start Displ: 19:14
End Pumping: 20:02
End Pump Date: 12/4/2001
Top Plug: N
Bottom Plug: Y
Disp Avg Rate:
Disp Max Rate:
Bump Plug:
Press Prior:
Press Bumped:
Press Held:
Float Held:
Page 1 of 2
Spud Date: 11/4/2001
Report Date: 12/4/2001
End:
Plu
Hole Size:
Top Set:
BTM set:
Plug Date:
Plug Type:
Drilled Out:
Cmtd. Csg:
(ft)
(ft)
Pipe Movement: Reciprocating
Avg Torque: (ft-Ibf)
Drag Up: 100 (Ibs)
Max Torque: (ft-Ibf)
Drag Down: 70 (Ibs)
4.00 (bbl/min)
4.20 (bbl/min)
Y
1,025 (psi)
200 (psi)
1,225 (min)
Y
Returns: Full
" Total Mud Lost:
Cmt Vol to Surf:
(bbl)
(bbl)
Ann Flow After: N V
Mixing Method: Batch
Density Meas By: M Motion
'" "
, " " "
", , , ,
, "" ",
,JluçlDatf) ,
Type: KCL Polymer Density: 9.9 (ppg) Visc: 46 (s/qt)
Bottom Hole Circulating Temperature: (OF)
Displacement Fluid Type:Mud
PVIYP: 11 (cp)/14 (lb/100ft2) Gels 10 sec: 3 (lb/100ft2) Gels 10 min: 7 (lb/100ft2)
Bottom Hole Static Temperature: (OF)
Density: 9,9 (ppg) Volume: 201.00 (bbl)
Slurry Data
Fluid Type: PRIMARY
Slurry Interval: (ft) To: (ft)
Water Source:
Test Data
Thickening Time:
Free Water: (%)
Fluid Loss: (cc)
Fluid Loss Pressure:
(OF)
, , "
, " " ,
Stage N°: 1 Slurry No: 1 .011 "
Description:
Cmt Vol: 62.5 (bbl)
Slurry Vol: (sk)
Density: (ppg)
Water Vol: (bbl)
Class: G
Yield: (fP/sk)
Other Vol: 0
Temperature: (OF)
Temperature: (OF)
Temperature: (OF)
Time
Compressive Strength 1:
Compressive Strength 2:
Purpose: PRIMARY
Mix Water: (gal)
Foam Job: N
Temp
(OF)
(OF)
Pressure
(psi)
(psi)
Printed: 1/31/2002 2:18:48 PM
('
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(
PHilliPS ALASKA INC.
Cementi ng Report
Page 2 of 2
Legal Well Name: 2P-415
Common Well Name: 2P-415
Event Name: ROT - DRILLING
Report #:
Start:
2
11/2/2001
Spud Date: 11/4/2001
Report Date: 12/4/2001
End:
Casing Test
Shoe Test
Liner Top Test
Test Press: (psi)
For: (min)
Cement Found between
Shoe and Collar:
Pressure: (ppge)
Tool:
Open Hole: (ft)
Hrs Before Test:
Liner Lap:
Pos Test: (ppge)
Neg Test: (ppge)
Hrs Before Test:
Cement Found on Tool:
Tool:
Tool:
CBL Run:
Under Pressure: (psi)
Bond Quality:
Cet Run:
Bond Quality:
Temp Survey:
Hrs Prior to Log:
Cement Top: (ft)
How Determined:
TOC Sufficient:
Job Rating:
If Unsuccessful Detection Indicator:
Remedial Cementing Required:
Number of Remedial Squeezes:
Remarks. '
Pumped 30 bbls 10.5 ppg MudPush wi 25 Ibs D29 , Pumped 62.5 bbls CMT slurry lOG
wi D053 3.00% , M117 0.300%, D065 0.450%,0800 0.20% and 150 Ibs D29
Printed: 1/31/2002 2:18:48 PM
I
\
(-
Note to File
We1l2P-415A
PTO 201-226
Sundry 302-049
Phillips Alaska, Inc, (PAl) requests approval for annular disposal in the subject
well. This note analyzes information submitted by PAl and recommends
approving PAl's request for annular disposal.
Well 2P-415A is part of the Meltwater development, which is located south of the
Tarn prospect and is the southernmost Kuparuk satellite, 2P-415A was
completed in November 2001, There are no surface casing shoes within a
quarter-mile of 2P-415A's 7-5/8" casing shoe,
7 -5/8" surface casing in 2P-415A was cemented with 325 bbls lead cement
followed by 124 bbls tail cement, totaling about 2160/0 excess cement relative to
gauge wellbore, 120 bbls of lead cement circulated to surface during initial
placement. Successful placement of such volumes of cement indicates that 2P-
415A's surface casing is adequately cemented,
After drill-out to 36 feet below the 7-5/8" shoe, the formation did not leak off to
16,0 ppg EMW, Applied pressure dropped only 25 psi (from 770 psi) during a 10
minute observation, 2P-415A was then drilled to about 5760 feet MO (about
2047 feet below the 7-5/8" casing shoe), at which point an injectivity test showed
a pressure gradient of 15.5 ppg EMW, During this test, pressure response
departed from linear at about 900 psi, reaching a maximum of 960 psi, then
stabilizing between 900 psi and 1000 psi. 880 psi shut-in pressure was
observed, After drilling to TO of 9025 feet, 5-1/2" x 3-1/2" production casing was
run and cemented, followed by 3-1/2" tubing completion,
Based upon information submitted, AOGCC recommends approval of Phillips'
request for annular disposal in Well 2P-415A (PTO 201-226),
Winton Aubert V,.1l'::1Å h~~...od
Petroleum Engineer ¿J '-I { 07-
'i~,
Se_lID_eruer
NO. 1725
01 /15/02
Alaska Oil & Gas Cons Comm
Attn: Lisa Weepie
333 West 7th Ave, Suite 100
Anchorage, AK 99501
Kuparuk
CD
Color
Schlumberger Technology Corporation, by and through is Geoquest Division
3940 Arctic Blvd, Suite 300
Anchorage, AK 99503-5711
ATTN: Sherrie
Company:
2P-415A PRESSITEMP STATION LOGS 12/24/01 1 1
2P-417 STATIC BOTTOM HOLE PRESS SURVEY 12/13/01 1 1
2P-420 PRESSITEMP STATION LOGS 12/23/01 1 1
1C-135 22010 USIT 12/18/01 1
1 R-36 22009 USIT 12/27/01 1
2N-348 22011 SCMT 12/09/01 1
2P-420 22008 SCMT 12/22/01 1
REGt:Î\i~1
c5bl- d~
~O I-OltJ~
õ\ 0 I-I ~ ~
aOI~dÒO
ó{O)-,ad-1
ao)- 1 L- d
d- Q )-) ~ J
.~
<
Field:
Well
Job#
Log Description
Date
Sepia
BL
SIGNE~ ~-~~
DATE: ,!ßtI 2 5 200L
Alaska Oil & Gas Cons. Commi8sion
Please sign and return one copy of this transmittal to Sherrie at the above address or fax to (907) 561-8317. Thank you, Anchorage
,
~1f~1rΠ[ID~ ~~~~[K\~
.~,
ALAS KA 0 IL AND GAS
COlVSERVATI ON COMMISSION
TONY KNOWLES, GOVERNOR
333 W. "JTH AVENUE, SUITE 100
ANCHORAGE, ALASKA 99501-3539
PHONE (907) 279-1433
FAX (9O7)27~7542
James Trantham
Drilling Engineering Supervisor
Phillips Alaska, Inc,
PO Box 100360
Anchorage AK 99510
Re:
Kuparuk River Unit 2P-415A
Phillips Alaska, Inc.
Permit No: 201-226
Sur Loc: 869' FNL, 2226, FWL, SEC. 17, T8N, R7N, UM
Btmhole Loc. 2587' FSL, 2373' FWL, SEC. 16, T8N, R7E, UM
Dear Mr, Trantham:
Enclosed is the approved application for permit to redrill the above referenced well,
The permit to drill does not exempt you from obtaining additional permits required by law from other
governmental agencies, and does not authorize conducting drilling operations until all other required
permitting determinations are made.
Annular disposal of drilling wastes will not be approved for this well until sufficient data is submitted to
ensure that the requirements of 20 AAC 25.080 are met. Annular disposal of drilling waste will be
contingent on obtaining a well cemented surface casing confirmed by a valid Formation Integrity Test
(FIT). Cementing records, FIT data, and any CQLs must be submitted to the Commission for approval on
form 10-403 prior to the start of disposal operations.
Please note that any disposal of fluids generated from this drilling operation which are pumped down the
surface/production casing annulus of a well approved for annular disposal on 2P pad_must comply with
the requirements and limitations of 20 AAC 25,080, Approval of this permit to drill does not authorize
disposal of drilling waste in a volume greater than 35,000 barrels through the annular space of a single
well or to use that well for disposal purposes for a period longer than one year.
Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25 035. Sufficient
notice (approximately 24 hours) must be given to allow a representative of the Commission to witness a
test of BOPE installed prior to drilling new hole, Notice may be given by contacting the Commission
petroleum field inspector on the North Slope pager at 659-3607.
Sincerely,
(~_.- ..~ ~
C,;;~;r~aYlor
Chair
BY ORDER q~ .THE COMMISSION
DATED this~ day of November, 2001
jjcÆnclosures
cc:
Department of Fish & Game, Habitat Section w/o encl.
Department of Environmental Conservation w/o encl.
( STATE OF ALASKA (
ALASKA Oil AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
kl\b'l
20 MC 25.005
1a. Type of work: Drill It) Redrill 0 1b. Type of well. Exploratory 0 Stratigraphic Test 0 Development Oil It)
Re-entry 0 Deepen 0 Service 0 Development Gas 0 Single Zone It) Multiple Zone 0
2. Name of Operator 5. Datum elevation (DF or KB) 10. Field and Pool
Phillips Alaska, Inc. RKB 80 feet
3. Address 6. Property Designation Kuparuk River Field
P.O. Box 100360 Anchorage, AK 99510-0360 ADL 373112 ALK 4998 Meltwater Pool
4. Location of well at surtace 7. Unit or property Name 11. Type Bond (see 20 MC 25.0251)
869' FNL, 2226' FWL, Sec. 17, T8N, R7E, UM Kuparuk River Unit Statewide
At top of productive interval 8. Well number Number
2586' FSL, 2257' FWL, Sec. 16, T8N, R7E, UM 2P-415A #59-52-180
At total depth 9. Approximate spud date Amount
2587' FSL, 2373' FWL, Sec. 16, T8N, R7E, UM November 29, 2001 $200,000
12. Distance to nearest property line 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD)
2257' @ Target feet 2P-417 ,38.9' @ 275' 2560 9006' MD 16011' TVD
16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2»
Kickoff depth: 5600' MD Maximum hole angle 69 deg. Maximum surface 2040 psig At total depth (TVD) 2705 psig
18. Casing program Setting Depth
size Specifications Top Bottom Quantity of Cement
Hole Casino Weioht Grade Coupling Length MD TVD MD TVD (include stage data)
6.75" 5.5" 15.5# L-80 BTC, ABmo( 8144' 30' 30' 8174' 5252' 290 sx Class G wi GasBlok
6.75" 3.5" 9.3# L-80 EUE 8rd Mo~ 832' 8174' 5252' 9006' 6011' included above
19. To be completed for Redrill, Re-entry, and Deepen Operations.
Present well condition summary
Total Depth: measured 11075 feet Plugs (measured)
true vertical 6272 feet
Effective Depth: measured feet Junk (measured)
true vertical feet
Casing Length Size Cemented Measured depth True Vertical depth
Conductor 120' 16" 16 cu yds High Early 120' 120'
Surface 3713' 9.875" 305 bbls AS III, 143 bbls LiteCrete 3713' 2448'
Production
RECEIVED
Liner
Perforation depth: measured NOV 2 9 2001
true vertical Alaska 011 & Gas Cons, CommIssiOn
Anchorage
20. Attachments Filing fee It) Property Plat 0 BOP Sketch 0 Diverter Sketch 0 Drilling program It)
Drilling fluid prog~m 0 Time vs depJþ plot DRefraction analysis 0 Seabed report 0 20 AAC 25.050 requirements 0
2' - I hereby ce~ ~ the ?l ~s L correct to the best of my knowledge -Questlons?Pat Reilly 265-604l
. 7J J~ - ..... ff 1'1c; I~ .
Signed . ~ - ,. - "~. Title: Drilling Engineering SupeNisor Date
C. Mallary - hI! LlJ/""",,-nr:::.la
// Commission Use Onl\ /
Permit Number API number Approval date / / he¡ ~ See cover letter
2-/? / - 2.. Z ¿::: 50- /03 -.2.n.5 ?3 -0 I for other requirements
Conditions of approval Samples required 0 Yes 181 No Mud log required 1 7 0 Yes ßI No
Hydrogen sulfide measures 0 Yes ~ No Directional survey required (81 Yes 0 No
Required working pressure for BOPE D2M; 0 3M; 0 5M; 0 10M;D Ell ~Ò~\" ~~ -\x..~\--
Other:
Original Signed By by order of / / /d-CJ /ó /
Approved by I" 1'\ I I' Commissioner the commission Date
. /
Form 10-401 Rev. 12/1/85 '
ORIGINAL
Submit in triplicate
.
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Phillips Alaska, Inc.
Drill Site 2P
415A
slot #415
Meltwater
North Slope, Alaska
PRO PO SA L
LIS TIN G
by
Baker Hughes INTEQ
Your ref: 415A Version #2
Our ref: prop4996
License:
Date printed: 27-Nov-2001
Date created: 26-Nov-2001
Last revised: 27-Nov-2001
Field is centred on 441964.235,5869891.466,999.00000,N
Structure is centred on 441964.235,5869891.466,999.00000,N
Slot location is n70 3 9.983,w150 26 47.976
Slot Grid coordinates are N 5869006.867, E 444185.881
Slot local coordinates are 867.73 S 2228.54 E
Projection type: alaska - Zone 4, Spheroid: Clarke - 1866
Reference North is True North
.
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(
Phillips Alaska, Inc. PROPOSAL LISTING Page 1
Drill Site 2P,4l5A Your ref : 415A Version #2
Meltwater,North Slope, Alaska Last revised : 27-Nov-2001
Measured Inclin. Azimuth True Vert R E C TAN G U LA R Dogleg Vert
Depth Degrees Degrees Depth COO R DIN A T E S Deg/100ft Sect
5600.00 65.82 102.06 3215.95 1692.14 S 3648.96 E 0.00 3994.60 Sidetrack KOP
5700.00 62.85 101.61 3259.27 1710.62 S 3737.17 E 3.00 4084.17
5800.00 59.87 101.13 3307.19 1727.92 S 3823.20 E 3.00 4171.31
5900.00 56.91 100.62 3359.60 1743.99 S 3906.82 E 3.00 4255.78
6000.00 53.94 100.08 3416.34 1758.80 S 3987.81 E 3.00 4337.34
6100.00 50.97 99.50 3477.27 1772.29 S 4065.93 E 3.00 4415.78
6200.00 48.01 98.87 3542.22 1784.43 S 4140.98 E 3.00 4490.87
6300.00 45.06 98.17 3611.00 1795.19 S 4212.75 E 3.00 4562.42
6400.00 42.10 97.40 3683.44 1804.54 S 4281. 04 E 3.00 4630.23
6500.00 39.16 96.53 3759.32 1812.45 S 4345.67 E 3.00 4694.10
6600.00 36.22 95.55 3838.45 1818.90 S 4406.45 E 3.00 4753.87
6700.00 33.29 94.42 3920.60 1823.88 S 4463.23 E 3.00 4809.37
6800.00 30.37 93.10 4005.56 1827.36 S 4515.85 E 3.00 4860.45
6900.00 27.47 91.53 4093.08 1829.34 S 4564.15 E 3.00 4906.97
7000.00 24.59 89.62 4182.93 1829.82 S 4608.02 E 3.00 4948.80
7009.67 24.31 89.41 4191.73 1829.79 S 4612.02 E 3.00 4952.59
7500.00 24.31 89.41 4638.59 1827.73 S 4813.86 E 0.00 5143.73
8000.00 24.31 89.41 5094.26 1825.62 S 5019.68 E 0.00 5338.64
8500.00 24.31 89.41 5549.93 1823.52 S 5225.50 E 0.00 5533.55
8541.63 24.31 89.41 5587.87 1823.34 S 5242.63 E 0.00 5549.78
8641.63 24.31 89.41 5679.00 1822.92 S 5283.80 E 0.00 5588.76 T/ Bermuda (T3)
8723.93 24.31 89.41 5754.00 1822.58 S 5317.67 E 0.00 5620.84 2P-415A ST TGT 26 Nov 01
8806.22 24.31 89.41 5829.00 1822.23 S 5351. 55 E 0.00 5652.92 B/ Bermuda (T2)
9000.00 24.31 89.41 6005.60 1821.41 S 5431. 31 E 0.00 5728.46
9006.22 24.31 89.41 6011. 27 1821.39 S 5433.88 E 0.00 5730.89 TD
All data is in feet unless otherwise stated.
Coordinates from slot #415 and TVD from RKB (Doyon 141) (254.00 Ft above mean sea
Bottom hole distance is 5731.01 on azimuth 108.53 degrees from wellhead.
Total Dogleg for wellpath is 42.29 degrees.
Vertical section is from wellhead on azimuth 108.16 degrees.
Calculation uses the minimum curvature method.
Presented by Baker Hughes INTEQ
level) .
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Phillips Alaska, Inc.
Drill 8ite 2P,415A
Meltwater,North 8lope, Alaska
PROPO8AL LI8TING Page 2
Your ref: 415A Version #2
Last revised: 27-Nov-2001
Comments in wellpath
--------------------
--------------------
MD
TVD
Rectangular Coords.
Comment
-----------------------------------------------------------------------------------------------------------
5600.00 3215.95 1692.14 8 3648.96 E 8idetrack KOP
8541.63 5587.87 1823.34 8 5242.63 E 5.5x3.5 XO
8641. 63 5679.00 1822.92 8 5283.80 E TI Bermuda (T3)
8723.93 5754.00 1822.58 8 5317.67 E 2P-415A 8T TGT 26 Nov 01
8806.22 5829.00 1822.23 8 5351. 55 E BI Bermuda (T2)
9006.22 6011. 27 1821.39 8 5433.88 E TD
Casing positions in string 'A'
------------------------------
------------------------------
Top MD
Top TVD
Rectangular Coords.
Bot MD
Bot TVD
Rectangular Coords.
Casing
-----------------------------------------------------------------------------------------------------------
n/a
n/a
3215.95
3215.95
1692.148
1692.148
3648.96E
3648.96E
9006.22
n/a
6011.27
3215.95
1821.398
1692.148
5433.88E
3648.96E
5.5 x 3.5 C8G
7 5/8" C8G
Targets associated with this wellpath
-------------------------------------
-------------------------------------
Target name
Geographic Location
T.V.D.
Rectangular Coordinates
Revised
-----------------------------------------------------------------------------------------------------------
2P-415A 8T TGT 26 No 449489.000,5867144.000,999.00
5754.00
1822.588
5317.67E
26-Nov-2001
Meltwater 2P-415 A SiC, ~ Track
Proposed Completion Schematic
Slimhole Base Case - 3-1/2" Completion String
16" 62.6#
@ +/- 120' MD
Depths are
based on
Doyon 141
RKB
Surface csg.
7-5/8" 29.7# L-80 BTCM
+1- 3713' MD I 2449' 1VD
12' Pup (Critical)
Intermediate csg.
5-1/2" 15.5# L-80 BTCM
run CSR to surface
+1- 8174' MD I 52521VD
Future Perforations
Production csg
3-1/2" 9.3# L-80 EUE8RD
TD to CSR
+1- 9006' MD / 6011' 1VD
('
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
3-1/2" FMC Gen 5 Tubing Hanger, 3-1/2" L-80 EUE8RD pin down
3-1/2" 9.3# L-80 EUE8RD Spaceout Pups as Required
3-1/2" 9.3# L-80 EUE8RD Tubing to Surface
3-1/2" Camco 'DS' nipple w/ 2.875" No-Go Profile. 3-1/2" x 6' L-80 handling
pups installed above and below, EUE8RD set at +1- 500' MD
3-1/2" 9.3# L-80 EUE8RD tubing to landing nipple
3-1/2" x 1" Camco IKBUG-2-9' Mandrels w/ DV's and RK latch's (Max. aD 4.725",
ID 2.90"), IBT box x box, 3-1/2" X 6' L-80 EUE8RD box x IBT pin handling pup
installed above, 3-1/2" x 6' L-80 IBT pin x EUE8RD pin handling pup installed below.
Spaced out w/ 3-1/2" 9.3# L-80 EUE8RD tubing as follows:
GLM#
1VD-RKB
MD-RKB
GLM Numbers and Spacing To Be Determined
3-1/2" X 1" Camco 'KBG-2-9' mandrel wi DCK-3 shear valve and bottom latch
(Max. OD 4.725", ID 2.90"), IBT box x box, pinned for 3000 psi shear (casing to
tubing differential), 3-1/2" x 6' L-80 EUE8RD box x IBT pin handling pup installed
above, 3-1/2" x 6' L-80 IBT pin x EUE8RD pin handling pup installed below
1 jt 3-1/2" 9.3# L-80 EUE8RD tubing
3-1/2" Baker 'CMU' sliding sleeve wi 2.813" Camco No-Go profile, EUE8RD
box x pin. 3-1/2" x 6' L-80 EUE8RD handling pups installed above
3-1/2" Camco 'D' nipple wi 2.75" No-Go profile. 3-1/2" x 12' L-80 EUE8RD
handling pup installed above. 3-1/2" x 6' L-80 EUE8RD handling pup below
1 jt 3-1/2" 9.3# L-80 EUE8RD tubing
3-1/2" Baker 80-40 GBH-22 casing seal assembly wi 15' stroke, 3-1/2" L-80
EUE8RD box up, 3-1/2" x 6' L-80 EUE8RD handling pup installed on top
Baker Casing Seal Receptacle, 80-40, 5-1/2"BTCM x 3-1/2" EUE8RD
Baker 5" OD x 4" ID 17' Seal Bore Extension
CSR set at +1- 100' above top perforation
PJR, 11/29/01
Schlumberger
Cem\.JADE Preliminary Job Design
5 1/2' x 3 1/2' Production
Preliminary Job Design based on limited input data. For estimate purposes only.
Rig: Doyon 141
Location: Kuparuk (Meltwater)
Client: Phillips Alaska, Inc.
Revision Date: 11/29/2001
Prepared by: Kevin Tanner
Location: Anchorage, AK
Phone: (907) 265-6205
Mobile: (907) 230-6628
email: ktanner@slb.com
Volume Calculations and Cement Systems
(Volumes are based on 75% excess, Top of tail slurry is designed to be 500' above
casing X-over.
Tail Slurry (minimum thickening time 140 min,)
GasBLOK wI Class G + D53, D600, D135, D800, D047, D065, per lab testing
@ 15,8 ppg, 1.2 fe/sk
Pre\10US Csg.
< 7 5/8", 29.7#, L-80 grade
BTC, AB Modified
at 3,713 ft. MD
< 51/2", 15.5#, L-80 grade
BTC, AB Modified
in 6 3/4" OH
< Top of Tail at
7,674 ft. MD
< X-o\A3r at 8,174 ft. MD
< Top of Bermuda Fm.
at 8,641 ft. MD
< 31/2", 9.3#, L-80 grade
EUE, 8rd Modified
in 6 3/4" OH
ill at 9,006 ft. MD
(6,011 ft. 1VD)
. Mark of Schlumberger
0,0835 ft3/ft x 500' x 1,75 (75% excess) =
0,1817 ft3/ft x (9006" 8174') x 1,75 (75% excess) =
0,0488 fe/ft x 80' (Shoe Joint) =
73.1 fe + 264.6 fe + 3,9 fe =
341,6 fel 1,2 ft3/sk =
Round up to 290 sks
73,1 fe
264,6 fe
3.9 fe
341,6 fe
284,7 sks
BHST = 132°F, Estimated BHCT = 118°F.
(BHST calculated using a gradient of 2,2°F/1 00 ft. below the permafrost)
PUMP SCHEDULE
Stage
Pump Rate
(bpm)
Stage
Volume
Cumulative
Stage Time Time
(min)
(bbl) (min)
CW 1 00 6 40 6,7 6,7
Drop Bottom Plug 3,0 9.7
MudPUSH XL 6 30 5,0 14,7
Tail Slurry 6 62 10.3 25,0
Drop Top Plug 3,0 28,0
Displacement 6 181 30,2 58,2
Bump Plug 3 20 6,7 64.9
MUD REMOVAL
Recommended Mud Properties: 10,0 ppg, Pv < 15, T y < 15, As thin and light as possible
to aid in mud removal during cementing,
Spacer Properties: 12.0 ppg MudPUSH* XL, Pv::= 19-22, T y ::= 22-29
Centralizers: Recommend 1 per joint across zones of interest for proper cement
placement.
(
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2P-415 Proposed Sidetrack procedure.
1. Plug back Bermuda and Cairn intervals and place kick off plug as per approved plug
back procedure,
2, POOH and test BOPE to 3500 psi. (pressure from approved permit to drill)
3, Rill to planned top of kick off plug (5400'),
4, Drill out 200' of the cement plug to planned kick off point (5600'),
5, Directionally drill 6-3/4" hole to well total depth (+1- 9006' MD) according to
directional plan. Run MWD 1 L WD logging tools in drill string for directional
monitoring and formation data gathering, Circulate and condition hole, POOH.
6, Run open hole e-line or drill pipe conveyed logs as needed,
7, Run and cement 5,5' 15,5# L-80 BTCM x 3-112 9.3# L-80 8RD tapered production
casing string with Baker casing seal receptacle crossover (CSR). Place CSR +1- 100'
above the Cairn interval for possible future access,
8, Run and land 3-1/2" tubing. Displace well to completion brine,
9. Pull landing joint. Install BPV, Nipple down BOP stack, and nipple up production
tree, Pull BPV, Install test plug, Pressure test production tree, Pull test plug, Secure
well,
10, Freeze protect well. Set BPY. Release rig and turn well over to production.
11. Clean location and RDMO in preparation for coiled tubing cleanout and perforating,
PHILLIPt Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
~:
Phillips Alaska, Inc.
Post Office Box 100360
Anchorage, Alaska 99510
November 29, 2001
Ms. Cammy Oechsli Taylor
Commissioner
Alaska Oil and Gas Conservation Commission
333 West th Avenue, Suite 1oO
Anchorage, AK 99501
(907) 279-1433
Re:
Application for Permit to Drill:
2P-415A
Surface Location:
Target Location:
Bottom Hole Location:
869' FNL,2226'FWL, Sec. 17,T8N,R7E
2586'FSL, 2257'FWL, Sec, 16,T8N,R7E
2587' FSL, 2373' FWL,Sec, 16,T8N, R7E
Dear Commissioner:
Phillips Alaska, Inc, hereby applies for a Permit to Drill to drill a sidetrack development well 2P-415A, This
sidetrack is due to the absence of productive pay,
The well will be drilled and completed using Doyon 141, Please utilize documents on file for this rig,
Subject to AOGCC approval, fluids and cuttings generated from drilling the well will be pumped down an
approved and existing annulus on Drillsite 2P, or hauled to an approved Prudhoe or GKA Class II disposal
wel,
The following people are the designated contacts for reporting responsibilities to the Commission:
A) Completion Report Sharon Allsup-Drake, Drilling Technologist
(20 AAC 25,070) 263-4612
B)
Geologic Data and Logs
(20 AAC 25,071)
Steve Moothart, Geologist
265-6965
If you have any questions or require further information, please contact Pat Reilly at (907) 265-6048,
C, Mallary
Drilling Engineering Supervisor
eVe. ~,.I1411 Y
RECEIVED
NOV 2 9 2001
Alaska 011 & Gas Cons. Commission
Anchorage
OR I GINAL
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P. O. Box 102776
Anchorage, AK 99510-2776
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CHECK 1
ST ANDARD LEITER
DEVELOPMENT
DEVELOPMENT
RED RILL
v
EXPLORATION
INJECTION WELL
INJECTION WELL
REDRILL
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TRANSMIT AL LETTER CHECK LIST
CIRCLE APPROPRIATE LETfERIP ARAGRAPHS TO
BEINCLUDEDINTRANSNOTTALLETTER
WELL NAME K.,('?f 2jJ-~/SA-
CHECK WHAT APPLIES
ADD-ONS (OPTIONS)
MULTI LATERAL
(If api number last two (2)
digits are between 60-69)
PILOT HOLE (PH)
A-/a
ANNULAR DISPOSAL
L-)NO
ANNULAR DISPOSAL
L-) YES
ANNULAR DISPOSAL
THIS WELL
"CLUE"
The permit is for a new wellbore segment of existing well
. Permit No, ' API No. . .
Production should continue to be reported as a function of
the original API number stated above.
In accordance with ~O AAC 25.005(1), all records, data and
logs acquired for the pilot hole must be clearly
differentiated in both name (name on permit plus PH)
and API number (50 -70/80) from
records, data and logs acquired for well (name on permit).
Annular disposal has not been requested. ..
Annular Disposal of drilling wastes will not be approved. . .
Annular Disposal of drilling wastes will not be approved. . .
DISPOSAL INTO OTHER Please note that an disposal of fluids generated... .
ANNULUS
L-> YES +
SPACING EXCEPTION
Templates are located m drive\jody\templates
Enclosed is the approved application for permit to drill the
above referenced well. The permit is approved .sùbject to
full compliance with 20 AAC 25.055. Approval to peñorate
and produce is contingent upon issuance of a conservation
order approving a spacing exception.
(Companv Name) will assume the liability of any protest to
the spacing exception that may occur.
WELL PERMIT CHECKLIST
FIELD & POOL 4 c¡ ð J40
1. Permit fee attached...,..."..",., """ .
2. Lease number appropriate. . . . , . . . , . . . - . . . . . .
3. Unique well name and number. ., . . . . , . . , . . . . . . .
4. Well located in a defined pool., . . . . . . , . . . . . . . . .
5. Well located proper distance from drilling unit boundary. . . .
6. Well located proper distance from other wells.. - . - - . . . .
7. Sufficient acreage available- in drilling unit.. . . , . . . . . . .
8. If deviated, is wellbóre plat included.. . . , , . . . . . . . . .
9. Operator only affected party.. . . . , . , . , . . . . . . , . .
10. Operator has appropriate bond in force. . . . . . . . . . . . .
11. Permit can be issued without conservation order. , . . . . . .
12. Permit can. be issued without administrative approval.. . . , ,
13. Can permit be approved before 15-day wait.. , . , . . . . . .
14, Conductor string provided . . . . . . . . " . . . . . . . . .
15. Surface casing protects all known USDWs. , . . , . . . . . .
16. GMT vol adequate to circulate on conductor & surt csg, , , . .
17. GMT vol adequate to ,tie-in long string to surf csg. . , . . , . .
18. CMT will cover all known productive horizons. , . , . " . , . .
19. Casing designs adequate for C, T. B & permafrost. . , . . , .
20, Adequate tankage or reserve pit.. . . . . . . . . . . , . . . .
21, If a re-drill, has a 10-403 for abandonment been approved, . .
22. Adequate well bore separation proposed.. . , . . , . , , , , ,
23. If diverter required, does it meet regulations. . . . . , . . , ,
24. Drilling -fluid program schematic & equip list adequate, , , . .
25. BOPEs, do they meet regulation. . . . . . . . . . . , . . , .
26. BOPE press rating appropriate; test to ~O psig.
, 27. Choke manifold complies w/API RP-53 (May 84). , . , . . . .
28. Work will occur without operation shutdown. . . , . . , . , , .
29, Is presence of H:25 gas probable.. . . . . . . . . . . , . . , .
30. Permit can be issued w/o hydrogen sulfide measures. , . "
31. Data presented on potential overpressure zones. , . , , . .
32. Seismic analysis of shallow gas zones. . . . . . . . . . . . .
R u~A JE . 33. Seabed condition survey (if off-shore). . . . . . . . . , . . ,
~ 34, Contact name/phone for weekly progress reports [exploratory onl
ANNULAR DISPOSAL35. With proper cementing records, this plan.
(A) will contain waste in a suitable receiving zone; . . . . . . .
(B) will not contaminate freshwater; or cause drilling waste. ..
to surface; "
(C) will not impair mechanical integrity pf the well used for disposal; Y N
(D) will not damage producing formation or impair recovery from a Y N
pool; and
E will not circumvent 20 MC 25.252 or 20 MC 25.412. Y N
GEOLOGY: ENGINEERING:' UIC/Annular COMMISSION:
~ WM '8~s~
JM~
ADMINISTRA TION
AB R n9A T.9-
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ENGINEERING
GEOLOGY
APPR
DATE
WELL NAME
LJr-L/ J-~;
c:\msoffice\wordian\diana\checklist (rev. 11/01/100)
2.¡Þ-~ PROGRAM: exp - dev
GEOLAREA ?7o
Y N
Y N
Y
Y
Y
Y
Y
Y
Y N
Y
Y
Y
Y N
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serv well bore seg _ann. disposal para req k.
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