Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
Loading...
HomeMy WebLinkAbout216-172Guhl, Meredith D (DOA)
From: Guhl, Meredith D (DOA)
Sent: Friday, January 18, 2019 11:05 AM
To: Eller, J Gary
Cc: Loepp, Victoria T (DOA); Boyer, David L (DOA)
Subject: KRU 3M-14A L1, L2, L3: PTDs 216-172, 216-173, 216-174: Expired
Hello Gary,
The following Permits to Drill, issued to ConocoPhillips Alaska, have expired under Regulation 20 AAC 25.005 (g). The
PTDs will be marked expired in the AOGCC database.
• KRU 3M-14A L1, PTD 216-172, Issued 30 December 2016
• KRU 3M-14A L2, PTD 216-173, Issued 30 December 2016
• KRU 3M-14A L3, PTD 216-174, Issued 30 December 2016
If you have any questions, please contact me.
Thank you,
Meredith
Meredith Guhl
Petroleum Geology Assistant
Alaska Oil and Gas Conservation Commission
333 W. 7th Ave, Anchorage, AK 99501
meredith.guhl@alaska.gov
Direct: (907) 793-1235
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 Meredith Guhl at
907-793-1235 or meredith.guhl@alaska.gov.
THE STATE
Conservation Commission
GOVERNOR BILL WALKER
Gary Eller
Principal CTD Engineer
ConocoPhillips Alaska, Inc.
P.O. Box 100360
Anchorage, AK 99510-0360
Re: Kuparuk River Field, Kuparuk River Oil Pool, 3M-14AL1
ConocoPhillips Alaska, Inc.
Permit to Drill Number: 216-172
Surface Location: 950' FNL, 1598' FEL, Sec. 25, T13N, R8E, UM
Bottomhole Location: 502' FNL, 1548' FEL, Sec. 25, T13N, R8E, UM
Dear Mr. Eller:
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Enclosed is the approved application for permit to re -drill the above referenced development
well.
The permit is for a new wellbore segment of existing well Permit No. 216-171, API No. 029-
21726-01-00. Production should continue to be reported as a function of the original API number
stated above.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Cathy . Foerster
Chair, Commissioner
DATED this�e—day of December, 2016.
STATE OF ALASKA
ALm,DKA OIL AND GAS CONSERVATION COMMi--iON
PERMIT TO DRILL
„ % 20 AAC 25.005
1 a. Type of Work:
Drill Lateral [✓�
1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑
Stratigraphic Test ❑ Development - Oil ❑� ' Service - Winj ❑ Single Zone Ell
1 c. Specify if well is proposed for:
Coalbed Gas ❑ Gas Hydrates ❑
Redrill [ Reentry ❑
Exploratory - Oil ❑ Development - Gas ❑
Service - Supply ❑ Multiple Zone ❑
Geothermal ❑ Shale Gas ❑
2. Operator Name:
5. Bond: Blanket 0 , Single Well ❑
11. Well Name and Number:
ConocoPhillips Alaska Inc
Bond No. 59-52-180 •
KRU 3M-14AL1 r
3. Address:
6. Proposed Depth:
12. Field/Pool(s):
P.O. Box 100360 Anchorage, AK 99510-0360
MD 9650 ` ND: 6200
Kuparuk River Field/ Kuparuk Oil Pool
4a. Location of Well (Governmental Section):
7. Property Designation (Lease Number): 045
Surface: 950' FNL, 1598' FEL, Sec. 25, T13N, R8E, UM
ADL 25522
Top of Productive Horizon:
8. Land Use Permit:
13. Approximate Spud Date:
3787' FNL, 702' FEL, Sec. 24, T13N, R8E, UM
ALK 2558
1/15/2017
Total Depth:
502' FNL, 1548' FEL, Sec. 25, T13N, R8E, UM
9. Acres in Property:
2X 3J J-6
14. Distance to Nearest Property:
6800'
4b. Location of Well (State Base Plane Coordinates - NAD 27):
10. KB Elevation above MSL (ft): 64 ,•
15. Distance to Nearest Well Open
Surface: x- 506270 y- 6016548 Zone- 4
GL Elevation above MSL (ft): 27 r
Ito Same Pool: 1879' to 3M-18
16. Deviated wells: Kickoff depth: 7500 feet
17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 101 degrees
Downhole: 4728 psig Surface: 4108 psig ,
18. Casing Program:
Specifications
Top - Setting Depth - Bottom
Cement Quantity, c.f. or sacks
Hole
Casing
Weight
Grade
Coupling
Length
MD
TVD
MD
TVD
(including stage data)
3"
2.375"
4.7#
L-80
ST-L
7,200
6,267
9,650
6,263
Slotted
19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations)
Total Depth MD (ft):
Total Depth TVD (ft):
Plugs (measured):
Effect. Depth MD (ft):
Effect. Depth TVD (ft):
Junk (measured):
7129'
6400'
7124'
7224'
6481'
7127'
Casing
Length
Size
Cement Volume
MD
TVD
Conductor/Structural
83'
16"
200 sx CS3
121'
121
Surface
3436'
9-5/8"
1389 sx AS III & 371 sx Class G
3473'
3377'
Scab Liner
528'
4-1/2"
175 sx CS 1
7127'
6399'
Production
7189'
7"
300 sx Class G & 175 sx CS I 1
7224'
6481'
Perforation Depth MD (ft): 6940' - 6976', Reperf: 6956' - 6976'
Perforation Depth TVD (ft): 6240' - 6270, Reperf: 6253' - 6270
20. Attachments: Property Plat ❑ BOP Sketch 0 Drilling
Program Time v. Depth Plot ❑ Shallow Hazard Analysis
Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program ❑� 20 AAC 25.050 requirements
21. Verbal Approval: Commission Representative:
Date 12/12/2016
22. 1 hereby certify that the foregoing is true and the procedure approved herein will not Jeff Connelly @ 263-4112
be deviated from without prior written approval. Contact
Email Ieff.S.COIIneIIV�COp.COfri
Printed Name G. Eller
Title Principal CTD Engineer
Signature
Phone 263-4172 Date 12/12/2016
Commission Use Only
Permit to Drill �l
Number: d —
API Number:
50- OZ9 — J 1
Permit Approval
Date: /
See cover letter for other
requirements.
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coal ed methane, gas hydrates, or gas contained in shales:
Other: tr�5 f� Samples req'd: Yes ❑ No[� Mud log req'd: Yes❑ No[�
F30P t ¢/vG� ��5, q
Directional svy req'd: Yes [� No
by `�` rt vr-N �C ✓ i/,�� �b z�G0)J5 G IDS measures: Yes [✓� No El Directional
T Spacing ception req'd: Yes ElNo�✓J Inclination -only svy req'd: Yes❑ NoZ,,,
r9 V u I'1 GL n C zr f U U gtr' ZS 5��� Post initial injection MIT req'd: Yes ❑ NoEl
i� GirGrr�-t-�rf td mellow �s kicc�f-FPoi�f ,� be�rnyPO,r��t'�clOh -�Gt�
C/ ;W[ V?k1 l Q tt
Approved by:
APPROVED BY
COMMISSIONER THE COMMISSION Date: -3D—
a 04 w o A Submit Form and
Form 10-401 (Revised 11/2015) This permit is valid for 24 month e a C 25.005(g)) Attachments in Duplicate
YTL )2/1� ll�
ConocoPhillips
Alaska
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
December 28, 2016
Commissioner - State of Alaska
Alaska Oil & Gas Conservation Commission
333 West 7th Avenue Suite 100
Anchorage, Alaska 99501
Dear Commissioner:
ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill a quad -lateral out of KRU 3M-14
(PTD# 187-051) using the coiled tubing drilling rig, Nabors CDR2-AC. The work may begin as soon as January
1, 2017. The CTD objective will be to drill four laterals (3M-14A, 3M-14AL1, 3M-14AL2, and 3M-14AL3),
targeting the Kuparuk A -sand.
The final CTD completion will fully isolate the 3M-14 mother bore, which suffers from damaged 41/" liner and
rock production. There is insufficient room to properly abandon the 3M-14 mother bore with a plug or cement,
so ConocoPhillips requests a variance to the requirements of 20 AAC 25.112(c) for alternate plugging which will
isolate/abandon 3M-14 via swell packer and liner -top packer of the final CTD completion.
To account for geological uncertainties, ConocoPhillips requests a variance from the requirements of 20 AAC
25.015 to allow the actual kick-off point of the laterals to be anywhere along the length of the parent borehole
instead of being limited to 500' from the original point.
Attached to this application are the following documents:
— Permit to Drill Application Forms (10-401) for 3M-14A, 3M-14AL1, 3M-14AL2, and 3M-14AL3
— Sundry Application Form (10-403) for abandonment of 3M-14
— Detailed Summary of Operations
— Directional Plans for 3M-14A, 3M-14AL1, 3M-14AL2, and 3M-14AL3
— Current wellbore schematic
— Proposed wellbore schematic
If you have any questions or require additional information, please contact me at 907-263-4172
Sincerely,
Gary Eller
ConocoRhM Coiled Tubing Drilling Team Lead
Kuparuk CTD Laterals NABOA: `ASKA
3M-14A, 3M-14AL1, 3M-14AL2, and 3M-14AL3, CD
'} Application for Permit to Drill Document ZRC
1.
Well Name and Classification........................................................................................................
2
(Requirements of 20 AAC 25.005(o and 20 AAC 25.005(b))...................................................................................................................
2
2.
Location Summary..........................................................................................................................
2
(Requirements of 20 AAC 25.005(c)(2))..................................................................................................................................................
2
3.
Blowout Prevention Equipment Information.................................................................................
2
(Requirements of 20 AAC 25.005(c)(3)).................................................................................................................................................
2
4.
Drilling Hazards Information and Reservoir Pressure..................................................................
2
(Requirements of 20 AAC 25.005(c)(4)).................................................................................................................................................
2
5.
Procedure for Conducting Formation Integrity tests...................................................................
2
(Requirements of 20 AAC 25.005(c)(5))..................................................................................................................................................
2
6.
Casing and Cementing Program....................................................................................................
3
(Requirements of 20 AAC 25.005(c)(6))..................................................................................................................................................
3
7.
Diverter System Information..........................................................................................................
3
(Requirements of 20 AAC 25.005(c)(7))..................................................................................................................................................
3
8.
Drilling Fluids Program..................................................................................................................
3
(Requirements of 20 AAC 25.005(c)(8))..................................................................................................................................................
3
9.
Abnormally Pressured Formation Information.............................................................................
4
(Requirements of 20 AAC 25.005(c)(9))..................................................................................................................................................
4
10.
Seismic Analysis.............................................................................................................................
4
(Requirements of 20 AAC 25.005(c)(10))................................................................................................................................................
4
11.
Seabed Condition Analysis............................................................................................................
4
(Requirements of 20 AAC 25.005(c)(11))................................................................................................................................................
4
12.
Evidence of Bonding......................................................................................................................
4
(Requirements of 20 AAC 25.005(c)(12))................................................................................................................................................
4
13. Proposed Drilling Program............................................................................................................. 4
(Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 4
Summaryof Operations...................................................................................................................................................4
LinerRunning...................................................................................................................................................................6
14. Disposal of Drilling Mud and Cuttings.......................................................................................... 6
(Requirements of 20 AAC 25.005(c)(14))................................................................................................................................................ 6
15. Directional Plans for Intentionally Deviated Wells....................................................................... 7
(Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 7
16. Attachments....................................................................................................................................7
Attachment 1: Directional Plans for 3M-14A, 3M-14AL1, 3M-14AL2, and 3M-14AL3.....................................................7
Attachment 2: Current Well Schematic for 3M-14...........................................................................................................7
Attachment 3: Proposed Well Schematic for 3M-14A, 3M-14AL1, 3M-14AL2, and 3M-14AL3.......................................7
Page 1 of 7 December 28, 2016
PTD Application: 3M-14A, AL1, AL2, and AL3
1. Well Name and Classification
(Requirements of 20 AAC 25.005(o and 20 AAC 25. 005(b))
The proposed laterals described in this document are 3M-14A, 3M-14AL1, 3M-14AL2, and 3M-14AL3.
2. Location Summary
(Requirements of 20 AAC 25.005(c)(2))
These laterals will target the A sand package in the Kuparuk reservoir. See attached 10-401 form for surface
and subsurface coordinates of the 3M-14A, 3M-14AL1, 3M-14AL2, and 3M-14AL3.
3. Blowout Prevention Equipment Information
(Requirements of 20 AAC 25.005 (c)(3))
Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR3-AC.
BOP equipment is as required per 20 AAC 25.036 for thru-tubing drilling operations.
— Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 4600 psi. Using the
maximum formation pressure in the area of 3M-26 (i.e. 14.67 ppg EMW);{the maximum potential
surface pressure in 3M-14, assuming a gas gradient of 0.1 psi/ft, would be 4108 psi./ See the "Drilling
Hazards Information and Reservoir Pressure" section for more details.
— The annular preventer will be tested to 250 psi and 2500 psi.
4. Drilling Hazards Information and Reservoir Pressure
(Requirements of 20 AAC 25.005 (c)(4))
Reservoir Pressure and Maximum Downhole Pressure (Requirements of 20 AAC 25.005 (c)(4)(a))
The formation pressure in KRU 3M-14 was measured to be 4092 psi (12.62 ppg EMW) on 11/29/2016. The
maximum downhole pressure in the vicinity is 3M-26 at 4728 psi'(14.67 ppg EMW) measured 7/23/2016,
although we have been back -flowing 3M-26 and 3M-06 in order to reduce formation pressure in the area. Since
this back -flow began in July we have seen a steady reduction in the formation pressure at 3M-14, so that we
now believe the measured formation pressure in 3M-14 represents the highest pressure we expect to encounter
during drilling. The lowest downhole pressure in the 3M-14 vicinity is to the northeast in the 3Q-02 injector at
4069 psi (12.51 ppg EMW) measured 8/6/2014.
Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b))
MI gas injection has occurred in the area, there is the potential of encountering free gas while drilling the 3M-14
laterals. If significant gas is detected in the returns, the contaminated mud can be diverted to a storage tank
away from the rig.
Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c))
The major expected risk of hole problems in the 3M-14 laterals will be shale instability at large fault crossings.
Managed pressure drilling (MPD) will be used to reduce the risk of shale instability associated with the fault
crossing.
5. Procedure for Conducting Formation Integrity tests
(Requirements of 20 AAC 25.005(c)(5))
The 3M-14 laterals will be drilled under 20 AAC 25.036 for thru-tubing drilling operations so a formation integrity
test is not required.
Page 2 of 7 December 28, 2016
PTD Application: 3M-14A, AL1, AL2, and AL3
6. Casing and Cementing Program
(Requirements of 20 AAC 25.005(c)(6))
New Completion Details
Lateral
Liner Top
Liner Btm
Liner Top
Liner Btm
Liner Details
Name
MD
MD
TVDSS
TVDSS
3M-14A
7500'
9,600'
6,182'
6,215'
2%", 4.7#, L-80, ST-L slotted liner;
aluminum billet on top
3M-14AL1
7200'
9,650'
6,204'
6,200'
2%", 4.7#, L-80, ST-L slotted liner, -
aluminum billet on top
3M-14AL2
6,981'
10,250'
6,207'
6,206'
2%", 4.7#, L-80, ST-L slotted liner;
aluminum billet on tip
3M-14AL3
6575'
10,250'
6,058
6,175'
2%", 4.7#, L-80, ST-L slotted liner;
up into 3.5" tubing
Existing Casing/Liner Information
Category
OD
Weight
(ppf)
Grade
Connection
Top
MD
Btm
MD
Top
TVD
Btm
TVD
Burst
psi
Collapse
psi
Conductor
16"
62.5
H-40
Welded
38'
121'
38'
121'
1640
630
Surface
9-5/8"
36.0
J-55
BTC
37'
3473'
37'
3377'
3520
2020
Production
7"
26.0
J-55
BTC
35'
7224'
35'
6481'
4980
4330
Scab Liner
4-1/2"
12.6
L-80
IBTM
6599'
7127'
5953'
6399'
8430
7500
Tubing
3-1/2"
9.3
L-80
EUE
33'
6502'
33'
5873'
1 10160
10540
7. Diverter System Information
(Requirements of 20 AAC 25.005(c)(7))
Nabors CDR3-AC will be operating under 20 AAC 25.036, for thru-tubing drilling operations. Therefore, a
diverter system is not required.
8. Drilling Fluids Program
(Requirements of 20 AAC 25.005(c)(8))
Diagram of Drilling System
A diagram of the Nabors CDR3-AC mud system is on file with the Commission.
Description of Drilling Fluid System
— Window milling operations: Chloride -based RoVis mud (8.6 ppg)
— Drilling operations: Chloride -based RoVis mud (9.6 ppg expected).This mud weight will not
hydrostatically overbalance the reservoir pressure; overbalanced conditions will be maintained using
MPD practices described below.
— Completion operations: The well will be loaded with 13.0 ppg potassium formate completion fluid to
provide formation over -balance and well bore stability while running completions.
Managed Pressure Drilling Practice
Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on
the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud
weight is not, in many cases, the primary well control barrier. This is satisfied with the 5000 psi rated coiled tubing
pack off and MPD choke. BOPE equipment provides the secondary well control as detailed in section 3 "Blowout
Prevention Equipment Information".
Page 3 of 7 December 28, 2016
PTD Application: 3M-14A, AL1, AL2, and AL3
In the 3M-14 laterals we will target a constant BHP of 12.8 ppg EMW at the window. The constant BHP target will
be adjusted through choke pressure and/or mud weight increases to maintain overbalanced conditions if
increased reservoir pressure is encountered. Additional choke pressure or increased mud weight may also be
employed for improved borehole stability. Any change of circulating friction pressure due to change in pump rates
or change in depth of circulation will be offset with back pressure adjustments.
Pressure at the 3M-14 Window (6931' MD, 6232' TVD) Using MPD
Pumps On (1.5 bpm)
Pumps Off
A -sand Formation Pressure (12.6 pp)
4083 psi
4083 psi
Mud Hydrostatic (9.6
3111 psi
3111 psi
Annular friction i.e. ECD, 0.080 psi/ft)
555 psi
0 psi
Mud + ECD Combined
(no choke pressure)
3666 psi
(underbalanced
—420 psi)
3111 psi
(underbalanced
—970 psi)
Target BHP at Window (12.8 pp)
4148 psi
4148 psi
Choke Pressure Required to Maintain Target
BHP
480 psi
1040 psi
9. Abnormally Pressured Formation Information
(Requirements of 20 AAC 25.005(c)(9))
N/A - Application is not for an exploratory or stratigraphic test well.
10. Seismic Analysis
(Requirements of 20 AAC 25.005(c)(10))
N/A - Application is not for an exploratory or stratigraphic test well.
11. Seabed Condition Analysis
(Requirements of 20 AAC 25.005(c)(11))
N/A - Application is for a land based well.
12. Evidence of Bonding
(Requirements of 20 AAC 25.005(c)(12))
Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission.
13. Proposed Drilling Program
(Requirements of 20 AAC 25.005(c)(13))
Summary of Operations
Background
KRU 3M-14 is a Kuparuk A -sand production well that was worked over to install 4'/" scab liner to remediate
rock production from the perfs, but it didn't take long for the 4'/2" scab liner to become damaged and rock
production to resume so that the well is still not capable of production. Four CTD laterals will be drilled from
the 31VI-14 parent well -bore, two to the south and two to the north, to serve as a replacement wellbore and
isolate section producing rocks. The mother completion will be isolated/abandoned using a 2W swell
packer and liner top packer — insufficient room exists to plug the mother completion with cement or a
mechanical plug. ConocoPhillips requests a variance to the requirements of 20 AAC 25.112(c) for the
alternate plugging method which will not risk migration of fluids between strata.
Page 4 of 7 December 28, 2016
PTD Application: 3M-14A, AL1, AL2, and AL3
The 3M-14A lateral will exit through the 4'/2" scab -liner and 7" casing via whipstock at 6931' MD and TD
at 9600' MD, targeting the Al sands. It will be completed with 2%" slotted liner from TD up to 7500' MD
with an aluminum billet for kicking off the 3M-14AL1 lateral.
The 3M-14AL1 lateral will drill south to a TD of 9650' MD targeting the A2 sands It will be completed
with 2%" slotted liner from TD up to 7200' MD with an aluminum billet for kicking off the 3M-14AL2
lateral.
The 3M-14AL2 lateral will drill north to a TD of 10250' MD targeting the Al sand. It will be completed
with 2%" slotted liner from TD up to 6981' MD with an aluminum billet for kicking off the 3M-14AL3
lateral.
The 3M-14AL3 lateral will drill north to a TD of 10250' MD targeting the Al sands. It will be completed
with 2%" slotted liner from TD up to —6575' MD up into the 3.5" tubing. A 2%" swell packer and a 3%2"
liner -top packer will be used along with blank 2%" liner to isolate/abandon the original 3M-14 completion,
mitigating against future rock production.
Pre-CTD Work
1. RU Slickline: Obtain static bottom -hole pressure
2. RU E-line: Drift tubing and tag fill/rocks at 6954' MD
3. RU E-line: Set Baker Hughes whipstock at 6931' MD.
4. Prep site for Nabors CDR3-AC, including setting BPV.
Ria Work
1. MIRU Nabors CDR2-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test.
2. 3M-14A Lateral (A sand - south)
a. Mill 2.80" window at 6931' MD.
b. Drill 3" bi-center lateral to TD of 9600' MD.
c. Run 2%" slotted liner with an aluminum billet from TD up to 7500' MD.
3. 3M-14AL1 Lateral (A sand - south)
a. Kick off of aluminum billet at 7500' MD.
b. Drill 3" bi-center lateral to TD of 9650' MD.
c. Run 2%" slotted liner from TD up to 7200' MD.
4. 3M-14AL2 Lateral (A sand -north)
a. Kick off of aluminum billet at 7200' MD.
b. Drill 3" bi-center lateral to TD of 10250' MD.
c. Run 2%" slotted liner from TD up to 6981' MD.
5. 3M-14AL3 Lateral (A sand - north)
a. Kickoff of aluminum billet at 6981' MD.
b. Drill 3" bi-center lateral to TD of 10250' MD.
c. Run 2%" slotted liner from TD up to 6575' MD. Liner will include a swell packer, blank 2%"
liner, and a sealbore deployment sleeve to isolate/abandon the mother completion.
6. Freeze protect. Set BPV, ND BOPE. RDMO Nabors CDR2-AC.
Page 5 of 7 December 28, 2016
PTD Application: 3M-14A, AL1, AL2, and AL3
Post -Rig Work
1. Pull BPV.
2. Obtain S13HP.
3. Install liner -top packer onto the 2%" liner
4. Install GLV's.
5. Return to production.
Pressure Deployment of BHA
The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on
the Christmas tree. MPD operations require the BHA to be lubricated under pressure, so installed in this well is a
deployment valve. This valve, when closed using hydraulic control lines from surface, isolates the well pressure
and allows long BHA's to be deployed/un-deployed without killing the well.
If the deployment valve fails, operations will continue using the standard pressure deployment process. A system
of double swab valves on the Christmas tree, double deployment rams, double check valves and double ball
valves in the BHA, and a slick -line lubricator can be used. This pressure control equipment listed ensures there
are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment
process.
During BHA deployment, the following steps are observed.
— Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is
installed on the BOP riser with the BHA inside the lubricator.
— Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and
the BHA is lowered in place via slickline.
— When the BHA is spaced out properly, the double deployment rams are closed on the BHA to isolate
reservoir pressure via the annulus. A closed set of double ball valves and double check valves isolate
reservoir pressure internal to the BHA. Slips on the double deployment rams prevent the BHA from
moving when differential pressure is applied. The lubricator is removed once pressure is bled off above
the deployment rams.
— The coiled tubing is made up to the BHA with the double ball valves plus the double check valves in the
closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the
double ball valves are opened. The injector head is made up to the riser, annular pressure is equalized,
and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole.
During BHA undeployment, the steps listed above are observed, only in reverse
Liner Running
— The 3M-14 laterals will be displaced to an overbalanced fluid prior to running liner. See "Drilling Fluids"
section for more details.
— While running 2%" slotted liner, a joint of 2%" non -slotted tubing will be standing by for emergency
deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a
deployment drill with this emergency joint on every slotted liner run. The 23/" rams will provide
secondary well control while running 2%" liner.
14. Disposal of Drilling Mud and Cuttings
(Requirements of 20 AAC 25.005(c)(14))
• No annular injection on this well.
• All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal.
• Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1 R-18
or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable.
Page 6 of 7 December 28, 2016
PTD Application: 3M-14A, AL1, AL2, and AL3
• All wastes and waste fluids hauled from the pad must be properly documented and manifested.
• Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200).
15. Directional Plans for Intentionally Deviated Wells
(Requirements of 20 AAC 25.050(b))
- The Applicant is the only affected owner.
- Please see Attachment 1: Directional Plan
- Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run.
- MWD directional, resistivity, and gamma ray will be run over the entire open hole section.
- Distance to Nearest Property Line (measured to KPA boundary at closest point)
Lateral Name
Distance
3M-14A
6800'
3M-14AL1
6800'
3M-14AL2
5230'
3M-14AL3
5230'
- Distance to Nearest Well within Pool
Lateral Name
Distance
Well
3M-14A
1879'
3M-18
3M-14AL1
1879'
3M-18
3M-14AL2
1146'
3M-18
3M-14AL3
1146'
3M-18
16. Attachments
Attachment 1: Directional Plans for 3M-14A, 3114-14AL1, 3M-14AL2, and 3M-14AL3
Attachment 2: Current Well Schematic for 3114-14
Attachment 3: Proposed Well Schematic for 3114-14A, 3M-14AL 1, 3M-14AL2, and 3M-14AL3
Page 7 of 7 December 28, 2016
ConocoPhillips
ConocoPhillips (Alaska) Inc. -Kup2
Kuparuk River Unit
Kuparuk 3M Pad
3M-14
3M-14AL1
Plan: 3M-14AL1_wp03
Standard Planning Report
08 December, 2016
CA &
BAKER
HUGHES
ConocoPhillips
Database:
EDM Alaska NSK Sandbox
Company:
ConocoPhillips (Alaska) Inc. -Kup2
Project:
Kuparuk River Unit
Site:
Kuparuk 3M Pad
Well:
3M-14
Wellbore:
3M-14AL1
Design:
3 M-14A L 1 _wp03
ConocoPhillips
Planning Report
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Well 3M-14
Mean Sea Level
3M-14 @ 63.00usft (3M-14)
True
Minimum Curvature
Project Kuparuk River Unit, North Slope Alaska, United States
Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level
Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point
Map Zone: Alaska Zone 04 Using geodetic scale factor
rG.I
BAKER
HUGHES
Site Kuparuk 3M Pad
Site Position: Northing: 6,016,202.17 usft Latitude: 700 27' 19.780 N
From: Map Easting: 506,126.99usft Longitude: 1490 56' 59.998 W
Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: 0.05 °
Well
3M-14
Well Position
+N/-S
0.00 usft Northing:
6,016,548.62 usft
Latitude:
70° 27' 23.186 N
+E/-W
0.00 usft Easting:
506,270.30 usft
Longitude:
149° 56' 55.779 W
Position Uncertainty
0.00 usft Wellhead Elevation:
usft
Ground Level:
0.00 usft
Wellbore
3M-14AL1
Magnetics
Model
Name
Sample Date
Declination
Dip Angle
Field Strength
BGGM2016
3/1/2017
17.72
81.00
57,547
Design
3M-14AL1_wp03
Audit Notes:
Version:
Phase:
PLAN
Tie On Depth:
7,500.00
Vertical Section:
Depth From (TVD)
+N/-S
+E/-W
Direction
(usft)
(usft)
(usft)
(I
-26.40
0.00
0.00
180.00
Plan Sections
Measured
TVD Below
Dogleg Build
Turn
Depth Inclination
Azimuth
System +N/-S
+El-W
Rate
Rate
Rate
TFO
(usft) (°)
(°)
(usft) (usft)
(usft)
(°/100ft) (°/100ft)
(°/100ft)
(°)
Target
7,500.00
89.75
180.04
6,181.00 2,268.17
1,066.64
0.00
0.00
0.00
0.00
7,610.00
97.45
180.04
6,174.10 2,158.47
1,066.55
7.00
7.00
0.00
0.00
7,725.00
90.47
184.06
6,166.16 2,043.91
1,062.43
7.00
-6.07
3.49
150.00
7,825.00
90.46
191.06
6,165.35 1,944.85
1,049.29
7.00
0.00
7.00
90.00
8,125.00
89.00
212.01
6,166.78 1,667.35
939.79
7.00
-0.49
6.98
94.00
8,425.00
89.07
233.01
6,171.90 1,447.47
738.24
7.00
0.02
7.00
90.00
8,650.00
89.10
217.26
6,175.53 1,289.27
579.28
7.00
0.02
-7.00
270.00
8,750.00
89.11
210.26
6,177.09 1,206.19
523.76
7.00
0.01
-7.00
270.00
8,900.00
89.12
220.76
6,179.42 1,084.27
436.76
7.00
0.01
7.00
90.00
9,200.00
88.82
199.76
6,184.86 826.64
286.45
7.00
-0.10
-7.00
269.00
9,500.00
87.83
220.74
6,193.73 569.05
136.24
7.00
-0.33
7.00
93,00
9,650.00
87.32
210.25
6,200.11 447.21
49.34
7.00
-0.34
-7.00
267.00
12/8/2016 5:30.09PM Page 2 COMPASS 5000.1 Build 74
ConocoPhillips
ConocoPhillips (Alaska) Inc.
-Kup2
Kuparuk River Unit
Kuparuk 3M Pad
3M-14
3M-14AL1
3M-14AL1_wp03
Travelling Cylinder Report
08 December, 2016
Ff pp-_
'A &I
BAKER
HUGHES
Baker Hughes INTEQ rigs
ConocoPhillips Travelling Cylinder Report BAKER
HUGHES
Company:
ConocoPhillips (Alaska) Inc. -Kup2
Project:
Kuparuk River Unit
Reference Site:
Kuparuk 3M Pad
Site Error:
0.00 usft
Reference Well:
3M-14
Well Error:
0.00 usft
Reference Wellbore
3M-14AL1
Reference Design:
3M-14AL1_wp03
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Output errors are at
Database:
Offset TVD Reference:
Well 3M-14
3M-14 @ 63.00usft (3M-14)
3M-14 @ 63.00usft (3M-14)
True
Minimum Curvature
1.00 sigma
OAKEDMP2
Offset Datum
Reference 3M-14AL1_wpO3
Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
Interpolation Method: MD Interval 25,00usft Error Model: ISCWSA
Depth Range: 7,500.00 to 9,650.00usft Scan Method: Tray. Cylinder North
Results Limited by: Maximum center -center distance of 1,161.34 usft Error Surface: Elliptical Conic
Survey Tool Program
Date 12/8/2016
From
To
(usft)
(usft) Survey (Wellbore)
Tool Name
Description
100.00
6,900.00 3M-14 (3M-14)
BOSS -GYRO
Sperry -Sun BOSS gyro multishot
6,900.00
7,500.00 3M-14A(wp05) (3M-14A)
MWD
MWD - Standard
7,500.00
9,650.00 3M-14AL1_wp03 (3M-14AL1)
MWD
MWD - Standard
Vertical
Depth
(usft)
3,389.72 9 5/8"
9 091 11 7 1/R"
Summary
Site Name
Offset Well - Wellbore - Design
Kuparuk 3M Pad
3M-05 - 3M-05 - 3M-05
3M-06 - 3M-06 - 3M-06
3M-13 - 3M-13 - 3M-13
3M-14 - 3M-14 - 3M-14
3M-14 - 3M-14A - 3M-14A_wp06
3M-14 - 3M-14AL2 - 3M-14AL2_wp06
3M-14 - 3M-14AL3 - 3M-14AL3_wp00
3M-15 - 3M-15 - 3M-15
3M-16 - 3M-16 - 3M-16
3M-17 - 3M-17 - 3M-17
3M-18 - 3M-18 - 3M-18
3M-19 - 3M-19 - 3M-19
3M-20 - 3M-20 - 3M-20
3M-26 - 3M-26 - 3M-26
Reference
Offset
Centre to
No -Go
Allowable
Measured
Measured
Centre
Distance
Deviation
Warning
Depth
Depth
Distance
(usft)
from Plan
(usft)
(usft)
(usft)
(usft)
Out of range
Out of range
Out of range
7,510.42
6,975.00
276.89
12.76
268.77
Pass- Major Risk
7,509.98
7,525.00
1.46
1.17
0.40
Pass - Minor 1/10
7,506.84
6,975.00
275.65
1.09
274.74
Pass - Minor l/10
7,506.84
6,975.00
275.65
1.09
274.74
Pass - Minor l/10
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
Offset Design
Kuparuk 3M Pad
- 3M-14 - 3M-14 - 3M-14
offset Site Error: 0.00 usft
Survey Program: 100-BOSS-GYRO
Rule Assigned: Major Risk
Offset Well Error: 0.00 usft
Reference
Onset
Semi Major Axis
Measured Vertical
Measured
Vertical
Reference
Offset Toolface +
Offset Wellbore
Centre
Casing -
Centre to
No Go
Allowable
Warning
Depth Depth
Depth
Depth
Azimuth
+N/.S
+E/-W
Hole Size
Centre
Distance
Deviation
(usft) (usft)
(usft)
(usft)
(usft)
(usft) (°)
(usft)
(usft)
()
(usft)
(usft)
(usft)
7,510,42 6,243.98
6,975.00
6,269.35
0,70
0.45 -84,70
2,257.75
790.90
5
276,89
12.76
268.77 Pass -
Major Risk, CC, ES, SF
7,523.39 6,243.77
6,950.00
6,248.21
0,77
0,30 -89.04
2,244,88
787.35
5
279,30
12.77
271.42 Pass -
Major Risk
7,537,08 6,243.32
6,925,00
6,227,09
0.84
0,15 -93.24
2231.98
783.81
5
283.27
12,78
275.62 Pass -Major
Risk
7,551,51 6,242.60
6,900.00
6,205.99
0,92
0.00 -97.26
2,219.05
780.26
5
288,68
12.79
281.23 Pass-
Major Risk
CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation
121812016 3:34:05PM Page 2 COMPASS 5000.1 Build 74
W
illm
owe
wo
f
inoCBJE
O _ v E E
K JB7
N
(L
m �
oar`
J Ln
LO
m
0
0
w
m
m O r a�
a_ `m m
Q H U) M V L L') m r m rn r- M
V
�rr<-LnLnrrrnrvLn�
V T m M V N 04 cD O N
U)m -GM V 1� roi cO�mO>r
4%z
a
C-4 V V m V mOmNm�
O O m V N N O o p��
G O
co
N N
cU
N O O O o 0 0 0 0 0 0 0 0
---I N
U o 0 0 0 0 0 0 0 0 0 0 0
O O O O a 6 0 0 0 m m I--
Lm,
O O O O
O N
ch
CV
N N N
lT 0 0 0 O O O O O O O O O
cV0 Ln V Nto-, N N10, �r V N c�7
L 1.1 m m N p m N O M c 0 c 0 m a i
Q 10
_
} mmm V M M r N M m M V
O O
N O
J
Q
w N
O
U) r LO L n r r rn r v L n
V pmM V N NLOON
LO
Za ,tr-
�[]
} m V V ca V m O m N c0 V
O m��� O m Ln
�
V
N N N
w
U) O M r Q) L n 0 V m r �--'
M C'4
CCO
Cl V mL m,--L I a'Mo
]mrmLDmrrrrmO>p
't,�
~commmmmmmmcO tD
CNp
Zc
'N V V com��LommmV Ln
Q O O O O O O N Cl! r r r N
O
co
O O V N M r O O m 0 0
m m m Q) M N m NN
NN N
U LO LA r cO O r O N N M N
C r V V V C 0C - c-mmM
o
a r o o a of O> p� 01 ao ti ff
O
m 0) O f 0 mmm a p m m m m
L+ CDQ
O O O O O O O O O O CD 0
O O Cl O O O O O O O o 0
O O L [) L A L n L n 0 0 0 6 6 0
O •- N N N N In LO O O O Ln
ttJ LDr m� V m rrnN L!>m
r r r r m m m m m rn rn rn
0
�
z oCO
-
o_
�e
e
-
col
Tvtl
c
o
_C
O
O
ca
O
_-
W
3
If
w�
ZO
1-
I-W£
-----
1 [
6l
a.
a
�
t
�
v
�I
N
4
�
V
N �
C
i
Ic
N
'
C
(ai/Usn pL) gldaQ leopian anti
w W
�LINM
we
teat
m
Q.
s
a
O
u
O
C
O
u
v fa
AN
we
�g_o
9
CL
�
�
S
0
c
0
(uiGmo;@ R\iio N/(-)gToS
KUP PROD 3M-14
c.onocomilips -
Alaska, Inc.
• • •
well Attributes Max
Angle & MD TD
Wellbore API/UW Field Name Wellbore Status ncI
500292172600 KUPARUK RIVER UNIT PROD
(°) MD (ftKB) Act
35.63 5,800.00
Elm (ftKB)
7,244.0
Comment H2S (pp.) Date
SSSV: NIPPLE 125 4/4/2013
Annotation End Date
Last WO: 12/19/2012
KB-Grd (k) Rig Release Data
41.90 6/5/1987
3M-14,W 20169:22:54AM
ertica metes atlas
.. .._.._..._.... .....__
HANGER, 32.8
CONDUCTOR; 38.0-121.0
NIPPLE; 5417
GAS LIFT; 2.523.3
SURFACE; 37.0J.473.1-
GAS LIFT; 4, 115.1
GAS LIFT; 5,272.2
GAS LIFT; 6.113.2
GAS LIFT; 6,423.2
SEAL ASSY; 6.479.7
PBR; 6,486.2
PACKER; 6,5093
NIPPLE; 6,559.8
SEAL ASSY; 6,605.E
GMT SQZ; 6,940.0-6.942.0-
CMT SQZ; 6,944.06,945c-
SQZ; 6.9480E,949.0-
RPERF; 6,956-6,976.0L__
CMT SQZ: 6,954Z-6,992.0-
SCAB LINER; 6,598.9-7.127.0
FISH; 7,127.0
PRODUCTION, 34.8-7.224.0
II
......_...
Annotation Depth (ftKB) End Date
Last Tag: SLIM 6,926.o 3/30/2016
Annotation Last Mod By End Date
Rev Reason: TAG lehallf 3/312016
Casing Strings
Casing Description OD
CONDUCTOR
(in)
16
ID (in)
15.062
Top (ftKB)
38.0
Set Depth (ftKB)
121.0
Set Depth (ND)...
121.0
WtlLen (L..
62.58
Grade
H7
Top Thread
welded
Casing Description OD
SURFACE
(in)
95/8
ID (in)
8.921
Top (ftKB)
37.0
Set Depth (ftKB)
3,473.1
Set Depth (ND)...
3,376.7
WtlLen (I...
36.00
Grade
J-55
Top Thread
BTC
Casing Description OD
PRODUCTION
(in)
7
ID (in)
6.27E
Top (ftKB)
34.8
Set Depth (ftKB)
7,224.0
Set Depth (ND)...
6,481.2
WtlLen (I...
26.00
Grade
J-55
Top Thread
BTC
Casing Description OD
SCAB LINER
(in)
41/2
ID (in)
3.958
Top (ftKB)
6,598.8
Set Depth (ftKB)
7,12Z0
Set Depth (ND)...
6,398.5
WtlLen (I...
12.60
Grade
L-80
Top Thread
IBTM
Liner Details
Top (ftKB)
Top (ND) (ftKB)
Top Intl (°)
Item Des
Co.
Nominal ID
(in)
6,598.8
5,953.3
33.55
PACKER
Baker "2RH" ZXP Liner Top Packer w/ 10' Tie -back
Ed, 5" BTC BxP
4.300
6,617.4
5,968.8
33.47
HANGER
BAKER HYDRUALIC FLEX -LOCK LINER HANGER
4.400
6,627.2
5,977.0
33.42
SBE
Baker 80-40 SBE, 20' Long, 5" BTC
4.000
Tubing Strings
Tubing Description I String Ma... ID (in) Top (ftKB) Set Depth (ft.. Set Depth (ND) (... Wt (Iblft) Grade Top Connection
TUBING WO 31/2 2.992 32.5 6,502.4 5,873.0 9.30 L-80 JEUE
Completion Details
Top (ftKB)
Top (TVD) (ftKB)
Top Intl (°)
Item Des
Com
Nominal ID
(in)
32.8
32.8
0.04 HANGER
FMC, GEN IV Tbg hanger w/ 3 1/2" TBG Pup.
2.992
541.7
541.7
0.31 NIPPLE
2.875" Landing Nipple w/'DS' Profile
2.875
6,479.7
5,854.1
33.74 SEAL
ASSY
Baker 80-40 GBH-22 Production Seal Assembly
2.990
Tubing Description String Ma... ID (in) Top (ftKB) Set Depth (% Set Depth (ND) (... wt (lblft) Grade Top Connection
PACKER ASSY 3.98 2.980 6,486.2 6.643.5 5,990.E EUE
Completion Details
Top (ftKB)
Top (ND) (ftKB)
Top Incl (°)
Item Des
Com
Nominal ID
(in)
6,486.2
5,859.5
33.70 PBR
BAKER PBR
4.000
6,509.3
5,878.7
33.62 PACKER
BAKER 'FHUPACKER
2.980
6,559.8
5,920.8
33.58 NIPPLE
CAMCO 2.812" Landing Nipple w/'DS' Profile
2.812
6,605.6
5,959.0
33.52 SEAL
ASSY
BAKER 8040 GBH-22 Production Seal Assembly w/ 2-ft
space out
2.980
Other In Hole
(Wireline retrievable plugs, valves, pumps, fish, etc.)
Top (ftKB)
Top (ND) Top
(ftKB) V
Intl
Des
Com
Run Date
ID (in)
7,127.0
6,398.5 31.50
FISH
ESP motor parts, remnants of ESP motor pushed 12/3/2012
downhole to 7127 RKB w/workover 12/3/2012 -
should be fill to 7244' drillers TO (FRAC or formation
sand) 6/10/2005 - ESP motor parts, remnants of
ESP motor pushed downhole to 7010 w/workover
6/10-006
Perforations & Slots
Top (ftKB)
Btm (ftKB)
Top (TVD) arm
(ftKB)
(ND)
(ftKB)
Zone
(shots/f
Date
Shot
Den
t)
Type
Co.
6,940.0
6,942.0
6,239.8
6,241 4 A-2,
3M-14 8/16/1987
1.0 CMT
SQZ
Covered
liner
by CMT Scab
2012
®
6,944.0
6,945.0
6,243.1
6,244.0 A-2,
3M-14 9/16/1987
1.0 CMT
SQZ
Covered
liner
by CMT Scab
2012
®
6,948.0
6,949.0
6,246.5
6,247.4 A-2,
3M-14 8/16/1998
1.0 CMT
SQZ
Covered
liner
by CMT Scab
2012
6,954.0
6,992.0
6,251.6
6,283.7 A-1,
3M-14 8/16/1987
4.0 CMT
SQZ
Covered
liner
by CMT Scab
2012
6,956.0
6,976.0
6,253.3
6,270.2 A-1,
3M-14 2/21/2013
2.0 RPERF
HSC
phasing,
HMX
2.5" w/180 degree
Millenium II
charges
Cement Squeezes
Top (ftKB)Btm
(ftKB)
Topl
(ftKB
D) Btm (ND)
) (ftKB) I
Des
Start Date
Com
6,598.8
/,12/.Ul
b,953.31
6,398.5 I Liner
Cement
12/7/2012
Mandrel Inserts
at
allCMT
N Top (ftKB)
Top (ND)
(ftKB)
Make Model
OD (in)
Valve
Be, Type
Latch
Type
Port Size
(in)
TRO Run
(psi)
Run Date
Com
2,523.3
2,520.6
Camco MMG
1 1/2 GAS
LIFT GLV
R-20
0.188
1,270.0
5/22/2013
10:00
2 4,115.1
3,905.6
Camco MMG
1 112 GAS
LIFT GLV
R-20
0.188
7268.0
5/22/2013
5:00
3 5,272.2
4,863.3
Camco MMG
1 112 GAS
LIFT GLV
R-20
0.188
1,277.0
5/22/2013
7:00
4 6,113.2
5,551.4
Camco MMG
11/2
GAS LIFT OV
RD02
0
0.250
0.0
5/22/2013
1:00
5 6,423.2
5,807.2 1
Camco MMG
1 1 1/2
GAS LIFT DMY
IRK
=
12/17/2012
6:30
Notes: General & Safety
End Date
Annotation
7/2/2006
NOTE: WORKOVER
7/28/2006
NOTE: PER CALIPER LOG 6/2712006, SEVERE 7" CASING DAMAGE @ 6942'-6946'
8/17/2006
NOTE: RECOVERED ROCKS TO 1.5" DURING TAG
7/21/2008
NOTE: SAND & PEBBLES OBSERVED @ 6930'
10/10/2010
NOTE: View Schematic w/ Alaska SchematiC9.0
12/19/2012
NOTE: WORKOVER SET CEMENTED 4.5" SCAB LINER TO COVER 7" PROD CSG DAMAGE
u
p
Of
U)
iq
(n
(D
V
m
N
C
_
m
N
m
O
N
Y
C
E
U
0 t9
O o0
2 N
CID
In
'O II
�Y �
v
�
O
� m
�
coy
�
D io s
m m
Ix
Ca 04
m 6 rn. m
V C J
Ll.l V
N m U
a)C
co W
.0 m
m n
cu
O1N
Q@m
(O
Lo
O.
— CL n
v
a
.oll
o
a) m=
O
U Y p r
M a
(p
(n 0- LL
a O
N C a0
QI 'C
V
N N N
n N
OU
— J
N N [V
U)
\
mmm
=m
X Tm
M O
M
m m m
m m
N LL m a
`° N
O
O
n
(0
N
0
C)
0
m
a`r
to a ,c
3 � aai
c in
ca
� c
m d N
0 0 l+ 1
II
O
O C
LL m m 2 O II m
.y. c n N . /^ c LO
0 (Y N LO
N Q Nto
=) m
CIS
a E N N
N N
�� II N
a m
II � , 4•
30
II II
OfN
N� �zo N II II �o
n I3 t rp
2rn mC a o.c
m Cl CD— to :L'
-o . a (o N 3
c
N� N 11
Vl� (a nII
Q co Q (00 Uf] NF-
a
o=� II II ��o�
(pr c w-
c,
`p y En
co II II MdN(O0
N 3 c",
nu=y (a II II o
3p— C
j 0 CL Z
Q�yd II II0 co
N
M d N C
m
J
Loepp, Victoria T (DOA)
From:
Loepp, Victoria T (DOA)
Sent:
Wednesday, December 28, 2016 10:34 AM
To:
Eller, J Gary
Cc:
Bettis, Patricia K (DOA)
Subject:
RE: KRU 3M-14 (187-051) CTD Sidetrack
Thanx for the heads up -
From: Eller, J Gary[mailto:J.Gary.Eller@conocophillips.com]
Sent: Wednesday, December 28, 201610:32 AM
To: Loepp, Victoria T (DOA) <victoria.loepp@alaska.gov>
Cc: Starck, Kai <Kai.Starck@conocophillips.com>; Haggerty-Sherrod, Ann (Northland Staffing Services) <Ann.Haggerty-
Sherrod@contractor.conocophillips.com>
Subject: RE: KRU 3M-14 (187-051) CTD Sidetrack
Victoria — I have four 10-401's and one 10-403 headed over to you today for KRU 3M-14.
In related news, Nabors CDR2 is in the midst of a difficult workover on well 3M-24. We are going to make one last effort
to retrieve a packer that has given us substantial trouble already. If we recover the packer, then we'll proceed according
to our original plan. But if we fail, we plan to suspend that workover and move Nabors CDR2-AC to well 3M-14 to drill
these laterals. That means there is the possibility that we will want to begin CTD operations on 3M-14 as early as
January 1, 2017, so I request expedited approval of these drilling permits (at least the first one, 3M-14A).
I'm sorry to rush you like that, but events have conspired against us. Thanks much for your help.
-Gary Eller
From: Loepp, Victoria T (DOA) [mailto:victoria.loepp alaska.gov]
Sent: Wednesday, December 28, 2016 8:26 AM
To: Eller, J Gary<J.Gary.Eller@conocophillips.com>
Subject: [EXTERNAL]RE: KRU 3M-14 (187-051) CTD Sidetrack
Hi Gary,
We will still need a plug for redrill 10-403 for the motherbore to review the proposed abandonment. We will also
approve the alternate plug placement approval as a part of that 10-403. Please submit the 10-403 plug for redrill with
the PTDs even though the abandonment procedure will be accomplished during the CTD sidetrack.
Thanx,
Victoria
Victoria Loepp
Senior Petroleum Engineer
State of Alaska
Oil & Gas Conservation Commission
333 W. 7th Ave
Anchorage, AK 99501
Work: (907)793-1247
Victoria. Loepp(a)alaska.gov
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation
Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged
information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended
recipient of this e-mail, please delete it, v, _)ut first saving or forwarding it, and, so that the A� CC is aware of the mistake in sending it to
you, contact Victoria Loepp at (907)793-1247 or Victoria.Loepg@alaska.aov
From: Eller, J Gary [mailto:J.Gary.Eller@conocophillips.com]
Sent: Tuesday, December 27, 2016 3:15 PM
To: Loepp, Victoria T (DOA) <victoria.loepp@alaska.gov>
Cc: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov>; Burke, Jason <Jason.Burke@conocophillips.com>; Connelly, Jeff
<Jeff.S.ConnellV@conocophillips.com>; Starck, Kai <Kai.Starck@conocophillips.com>
Subject: KRU 3M-14 (187-051) CTD Sidetrack
Victoria — In just a few days, ConocoPhillips will be submitting 10-401's for CTD sidetrack/laterals from KRU 3M-14 (187-
051). Well 3M-14 is a rock producer that is incapable of production, and the CTD sidetrack will restore this lost
productivity. The attached schematic shows that following the sidetrack, the new CTD borehole will be completed with 2-
3/8" swell packer and liner -top packer in order to permanently isolate the existing, rock -producing perfs of KRU 3M-14.
I wanted to contact you because the abandonment of the motherbore, 3M-14, is unusual in that we are unable to
mechanically abandon the perforated, rock -producing interval prior to CTD sidetrack. There is just sufficient room above
the compromised 4%2" scab liner for a single whipstock exit, and we do not have room for a cement plug or other
mechanical isolation. However, the final CTD completion with swell packer and liner -top packer will permanently isolate
the mother completion.
It is ConocoPhillips intention to do the following:
• We will submit the 10-401 s as a sidetrack of 3M-14 (i.e. 3M-14A) since the mother completion will be fully
isolated/abandoned.
• The 10-401s will address the completion plan which will isolate/abandon KRU 3M-14 (187-051). We recognize that this
isolation method does not meet the requirements of 20 AAC 25.112(c), but we believe it meets the intent of accomplishing
the sidetrack and restoring production without risking migration of fluids to other zones.
• Since there are no pre-CTD operations that need to be performed to abandon 3M-14, we do not intend to submit a 10-
403 for the isolation/abandonment; that will be addressed in the 10-401 s. We do plan to submit a 10-407 post-CTD for
the abandonment of 3M-14 (187-051) as permitted under the 10-401 s.
Please contact me if you'd like to discuss this further.
<< File: 3M-14 proposed PTD schematic.pdf >>
3. Gary Eller
CTD Team Lead
ConocoPhillips - Alaska
work: 907-263-4172
cell: 907-529-1979
TRANSMITTAL LETTER CHECKLIST
WELL NAME: /<P, LL 114 A L, I
PTD: �/6 J ?2,
Development _ Service
FIELD: �U4ui
Exploratory _ Stratigraphic Test _ Non -Conventional
POOL:Kk-_44�kwV
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK
OPTIONS
TEXT FOR APPROVAL LETTER
MULTI LATERAL
The permit is for a new wellbore segment of existing well Permit
/
(If last two digits
No. C21(4 ") ( , API No. 50-i�_-��-01 - OCR. Production
V
in API number are
should continue to be reported as a function of the original API number stated
between 60-69)
above.
In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the
Pilot Hole
pilot hole must be clearly differentiated in both well name
( PH) and API number (50- -
from records, data and logs acquired for well.
The permit is approved subject to full compliance with 20 AAC 25.055. Approval
Spacing Exception
to produce / inject is contingent upon issuance of a conservation order approving
a spacing exception. (Company Name) Operator assumes the liability of any
protest to the spacing exception that may occur.
All dry ditch sample sets submitted to the Commission must be in no greater than
Dry Ditch Sample
30' sample intervals from below the permafrost or from where samples are first
caught and 10' sample intervals through target zones.
Please note the following special condition of this permit:
Non-
Production or production testing of coal bed methane is not allowed for name of
Conventional
well until after (Company Name) has designed and implemented a water well
Well
ro baseline data on water
testing program to provide g p quality and quantity.
(Company Name) must contact the Commission to obtain advance approval of
such water well testing program.
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to
be run. In addition to the well logging program proposed by (Company Name)
in the attached application, the following well logs are also required for this well:
Well Logging
Requirements
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite
curves for well logs run must be submitted to the AOGCC within 90 days after
completion, suspension or abandonment of this well.
Revised 5/2013
WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100
PTD#:2161720 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type
Well Name: KUPARUK RIV UNIT 3M-14AL1 Program DEV Well bore seg
DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal ['
Administration
17
Nonconven. gas conforms to AS31.05.0300.1.A),0.2.A-D)
NA
1
Permit fee attached
NA
2
Lease number appropriate
Yes
ADL0025523, Surf Loc & TD; ADL0025522, Top Prod Interv.
3
Unique well name and number
Yes
KRU 3M-14AL1
4
Well located in a defined pool
Yes
KUPARUK RIVER, KUPARUK RIV OIL - 490100, governed by Conservation Order 432D.
5
Well located proper distance from drilling unit boundary
Yes
CO 432D contains no spacing restrictions with respect to drilling unit boundaries.
6
Well located proper distance from other wells
Yes
CO 432D has no interwell spacing restrictions.
7
Sufficient acreage available in drilling unit
Yes
8
If deviated, is wellbore plat included
Yes
9
Operator only affected party
Yes
Wellbore will be more than 500' from an external property line where ownership or landownership changes.
10
Operator has appropriate bond in force
Yes
Appr Date
11
Permit can be issued without conservation order
Yes
12
Permit can be issued without administrative approval
Yes
PKB 12/28/2016
13
Can permit be approved before 15-day wait
Yes
14
Well located within area and strata authorized by Injection Order # (put 10# in comments) (For
NA
15
All wells within 1/4 mile area of review identified (For service well only)
NA
16
Pre -produced injector: duration of pre -production less than 3 months (For service well only)
NA
18
Conductor string provided
NA
Conductor set in KRU 3M-14
Engineering
19
Surface casing protects all known USDWs
NA
Surface casing set in KRU 3M-14
20
CMT vol adequate to circulate on conductor & surf csg
NA
Surface casing set and fully cemented
21
CMT vol adequate to tie-in long string to surf csg
NA
22
CMT will cover all known productive horizons
No
Productive interval completed with slotted liner
23
Casing designs adequate for C, T, B & permafrost
Yes
24
Adequate tankage or reserve pit
Yes
Rig has steel tanks; all waste to approved disposal wells
25
If a re -drill, has a 10-403 for abandonment been approved
NA
26
Adequate wellbore separation proposed
Yes
Anti -collision analysis complete; no major risk failures
27
If diverter required, does it meet regulations
Yes
Appr Date
28
Drilling fluid program schematic & equip list adequate
Yes
Max formation pressure is 4728 psig(14.7 ppg EMW); will drill w/ 9.6 ppg EMW and maintain overbal w/ MPD
VTL 12/29/2016
29
BOPEs, do they meet regulation
Yes
30
BOPE press rating appropriate; test to (put psig in comments)
Yes
MPSP is 4108 psig; will test BOPs to 4600 psig
31
Choke manifold complies w/API RP-53 (May 84)
Yes
32
Work will occur without operation shutdown
Yes
33
Is presence of H2S gas probable
Yes
112S measures required
34
Mechanical condition of wells within AOR verified (For service well only)
NA
35
Permit can be issued w/o hydrogen sulfide measures
No
Wells on 3M-Pad are H2S-bearing. H2S measures required.
Geology
36
Data presented on potential overpressure zones
Yes
Max potential reservoir pressure is 14.67 ppg EMW; will be drilled using 9.6 ppg mud and MPD technique.
Appr Date
37
Seismic analysis of shallow gas zones
NA
PKB 12/28/2016
38
Seabed condition survey (if off -shore)
NA
39
Contact name/phone for weekly progress reports [exploratory only]
NA
Onshore development lateral to be drilled.
Geologic Engineering Public
Commissioner: Date: Commissioner Date C oner Date
�Z' Its
