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HomeMy WebLinkAbout216-150Guhl, Meredith D (DOA)
From: Guhl, Meredith D (DOA)
Sent: Monday, November 26, 2018 9:27 AM
To: 'Starck, Kai'
Cc: Loepp, Victoria T (DOA); Boyer, David L (DOA)
Subject: KRU 3H-22 1-1-01, 1-1-04, 0-05, PTDs 216-146, 216-149, 216-150, Permits Expired
Hello Kai,
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 31-1-22 1-1-01, PTD 216-146, Issued 15 November 2016
• KRU 3H-22 L1-04, PTD 216-149, Issued 15 November 2016
• KRU 3H-22 1-1-05, PTD 216-150, Issued 15 November 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
X A y S
GOVERNOR BILL WALKER
G. Eller
CTD Team Lead
ConocoPhillips Alaska, Inc.
P.O. Box 100360
Anchorage, AK 99510-0360
Alaska Gil and Gas
Conservation Commission
Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 31-1-221, 1-05
ConocoPhillips Alaska, Inc.
Permit to Drill Number: 216-150
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Surface Location: 957' FNL, 282' FWL, Sec. 12, T12N, R8E, UM
Bottomhole Location: 2550' FNL, 2831' FWL, Sec. 35, T13N, R8E, UM
Dear Mr. Eller:
Enclosed is the approved application for permit to redrill the above referenced service well.
The permit is for a new wellbore segment of existing well Permit No. 188-110, API No. 50-103-
20097-00-00. 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.
SincerelyeT.amel
amount, Jr.
Commissioner
DATED this day of November, 2016.
RECEIVED
STATE OF ALASKA
AL -A OIL AND GAS CONSERVATION COMMi- ,,JN
PERMIT TO DRILL
20 AAC 25.005
NOV 0 3 2016
1 a. Type of Work:
1 b. Proposed Well Class: Exploratory -Gas ❑
Service - WAG ❑✓ Service - Disp ❑
1 c. Specify if well is proposed for:
Drill ❑ Lateral 0
Stratigraphic Test ❑ Development - Oil ❑
Service - Winj ❑ Single Zone P]
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 31-1-221-1-05
3. Address:
6. Proposed Depth:
12. Field/Pool(s):
P.O. Box 100360 Anchorage, AK 99510-0360
MD: 11,750' TVD: 6188' v
Kuparuk River Field/ Kuparuk Oil Pool
4a. Location of Well (Governmental Section):
7. Property Designation (Lease Number): A
Surface: 957' FNL, 282' FWL, Sec. 12, T12N, R8E, UM
ADL 25523 1
Top of Productive Horizon:
8. Land Use Permit:
13. Approximate Spud Date:
4451' FNL, 2371' FWL, Sec. 35, T13N, R8E, UM
ALK 2559
12/5/2016
Total Depth:
9. Acres in Property: ?AA
,�J
14. Distance to Nearest Property:
2550' FNL, 2831' FWL, Sec. 35, T13N, R8E, UM
?,5���
11,075'
4b. Location of Well (State Base Plane Coordinates - NAD 27):
10. KB Elevation above MSL (ft): 76
15. Distance to Nearest Well Open
Surface: x- 498656 y- 6000700 Zone-4
GL Elevation above MSL (ft): 39
to Same Pool: 1322' to 3M-29
16. Deviated wells: Kickoff depth: 9815 feet 4M
17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 76 degrees
Downhole: 18Z�4 4 psig Surface: 3 41 psig
18. Casing Program:
Specifications
Top - Setting Depth - Bottom
Cement O antity, 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
9715
6063
11750
6187
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):
10234'
6379'
None
9818'
6125'
None
Casing
Length
Size
Cement Volume
MD
TVD
Conductor/Structural
115'
16"
250 sx AS 1
115'
115'
Surface
4348'
9-5/8"
1500 sx AS III & 500 sx Class G
4348'
3127'
Intermediate
Production
10052'
7"
1280 sx Class G & 175 sx AS 1
10052'
6268'
Liner
Perforation Depth MD (ft): 9690'-9710', 9716'-9736', 9754'-9774'
Perforation Depth TVD (ft):
6047'-6059', 6063'-6075',6086'-6098'
20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling
Program 0 Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050//requirements 0
21. Verbal Approval: Commission Representative:
Date ///Z AZ 0 b
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.connellyy@cop.com
Printed Name G. Eller \
Title CTD Team Lead
Signature
Phone 263-4172 Date `p
Commission Use Only
Permit to Drill
PI Number:
Permit Approval
See cover letter for other
Number:
_
50- 03- - - Q
Date: (
requirements.
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Other. 41- �
L-(,r0d �$ i a�0/ p —�a�:34-
Samples req'd: Yes ❑ No V Mud log req'd: Yes ❑ No [yT
H2S measures: Yes 14 No ❑ Directional svy req'd: Yes [' No E]
/)pacing
ulf7m Op�^�;cr� w� t%Gc_a�r�t4
exception req'd: Yes ❑ Nov Inclination -only svy req'd: Yes ❑ No
Post initial injection MIT req'd:Yes ❑ No❑
t� �u►iit� 1 rc.�. 7�0 �C� �4 c- �:�: a lSC6i is
��,-be-�. Ala �lCv-cam k�l_k-cuff
APPROVED BY /
Approved
COMMISSIONER THE COMMISSION Date: l l S
il-.6 «l y l /6 ()h 4�Lt"_ (.� /l4-7'2//'bSubmit Form and
Form 10-401 (Revised 11/2015) s S 7'idfdrr �]4{ii���aaanth rom the dale of approval 0 AAC 25.005(g)) Attachments in Duplicate
ConocoPhillips
Alaska
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
October 27, 2016
Commissioner - State of Alaska
Alaska Oil & Gas Conservation Commission
333 West 7th Avenue Suite 100
Anchorage, Alaska 99501
Dear Commissioner:
RECEIVED
NOV 0 3 2016
A0GC0
ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill a hexa-lateral out of the Kuparuk Well
31-1-22 (PTD# 188-011) using the coiled tubing drilling rig, Nabors CDR2-AC or CDR3-AC (Note: The 31-1-22 CTD
project is planned for CDR2-AC drilling at the time of PTD submittal, please be aware that for scheduling
purposes, CDR3 may be utilized for drilling activities should the need arise). The work is scheduled to begin
December 5, 2016. The CTD objective will be to drill six laterals (31-1-221-1, 3H-22L1-01, 31-1-221-1-02, 31-1-221-1-
03, 31-1-221-1-04, and 31-1-221-1-05), targeting the Kuparuk A -sand intervals. A 4-1/2" big tail pipe was installed
during RWO prior to CTD operation.
To account for geological uncertainties, ConocoPhillips requests a variance from the requirements of 20 AAC
25.015 to allow the actual kick-off point to be anywhere along the length of the parent lateral 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 31-1-221-1, 31-1-221-1-01, 31-1-221-1-02, 31-1-221-1-03, 3H-
221-1-04, and 31-1-221-1-05
— Detailed Summary of Operations
— Directional Plans for 31-1-221-1, 31-1-221-1-01, 31-1-221-1-02, 31-1-221-1-03, 31-1-221-1-04, and 31-1-221-1-05
— Current wellbore schematic
— Proposed wellbore schematic
If you have any questions or require additional information, please contact me at 907-263-4112.
Sincerely,
Jeff Connelly
Coiled Tubing Drilling Engineer
Kuparuk CTD Laterals �ri9i,NABORSALA��KA
3H-22L1, 3H-22L1-01, 3H-22L1-02, 3H-22L1-03, t.
31-1-221-1-04, and 3H-221-1-05 VAC
Application for Permit to Drill Document
1.
Well Name and Classification........................................................................................................ 2
(Requirements of 20 AAC 25.005(f) 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.......................................................................................... 7
(Requirements of 20 AAC 25.005(c)(14))................................................................................................................................................ 7
15.
Directional Plans for Intentionally Deviated Wells....................................................................... 7
(Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 7
16.
Quarter Mile Injection Review (for injection wells only)............................................................... 7
(Requirements of 20 AAC 25.402).......................................................................................................................................................... 7
17.
Attachments.................................................................................................................................... 8
Attachment 1: Directional Plans for 3H-22L1, 3H-221-1-01, 3H-221-1-02, 3H-221-1-03, 3H-221-1-04, and 3H-22L1-05... 8
Attachment 2: Current Well Schematic for 31-1-22............................................................................................................8
Page 1 of 8 October 27, 2016
Attachment 3: Proposed Well Schematic for3H-22L1, 31-1-22L1-01, 3H-221-1-02, 3H-22L1-03, 3H-22L1-04, and 3H-
22 L 1-05..........................................................................................................................................................................
1. Well Name and Classification
(Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b))
The proposed laterals described in this document are 31-1-221-1, 31-1-221-1-01, 31-1-221-1-02, 31-1-221-1-03, 31-1-
221-1-04, and 31-1-221-1-05. All laterals will be classified as "Service — WAG" wells.
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 31-1-221-1, 31-1-221-1-01, 31-1-221-1-02, 31-1-221-1-03, 31-1-221-1-04, and 31-1-221-1-
05.
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 CDR2-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 4700 psi. Using the
maximum formation pressure in the area of 31-1-31 (i.e. 15 ppg EMW), the maximum potential surface
pressure in 31-1-22, assuming a gas gradient of 0.1 psi/ft, would be 4205 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 31-1-22 was measured to be 4107 psi (13.01 ppg EMW) on 9/25/2016. The
maximum downhole pressure in the 31-1-22 vicinity is 31-1-31 at 4825 psi (15 ppg EMW) measured 10/8/2016.
The lowest downhole pressure in the 31-1-22 vicinity is to the east in the 31-1-21 producer at 3290 psi (10.22 ppg
EMW) measured 6/24/2016.
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 31-1-22
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 31-1-22 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 31-1-22 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 8 October 27, 2016
PTD Application: 31-1-22L1, 1_1-01, L1-02, 1-1-03, 1-1-04, and 1_1-05.
6. Casing and Cementing Program
(Requirements of 20 AAC 25.005(c)(6))
New Completion Details
.-f
Lateral
Liner Top
Liner Btm
Liner Top
Liner Btm
Liner Details
Name
MD
MD
TVDSS
TVDSS
3H-221_1
10,070'
11,750'
6,036'
6,725'
2%", 4.7#, L-80, ST-L slotted liner;
aluminum billet on top
3H-221_1-01
9,815'
11,150'
6,028'
6,008'
2%", 4.7#, L-80, ST-L slotted liner;
aluminum billet on top
3H-221_1-02
9,900,
11,750'
6,037'
6,102'
2%", 4.7#, L-80, ST-L slotted liner;
aluminum billet on to
3H-221_1-03
9,765'
11,825'
6,013'
6,071'
2%", 4.7#, L-80, ST-L slotted liner;
aluminum billet on top
3H-22L1-04
9815
11,750'
6028'
5,950'
2%", 4.7#, L-80, ST-L slotted liner;
aluminum billet on top
3H-221_1-05
9,715'
11,750'
5,987'
6111
2%", 4.7#, L-80, ST-L slotted liner;
deployment sleeve on top
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
0'
115'
0'
115'
1640
630
Surface
9-5/8"
36.0
J-55
BTC
0'
4,348'
0'
3,126'
3520
2020
Production
7"
26.0
J-55
BTC
0'
10,052'
0'
6269'
4980
4330
Tubing
3-1/2"
9.3
L-80
EUE
0'
9664'
0'
6457'
10180
10540
Tubing Tail
4-1/2"
12.6
L-80
I STC
9664'
9748'
6402'
1 6457'
NA
NA
7. Diverter System Information
(Requirements of 20 AAC 25.005(c)(7))
Nabors CDR2-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 CDR2-AC mud system is on file with the Commission.
Description of Drilling Fluid System
- Window milling operations: Chloride -based FloVis mud (8.6 ppg)
- Drilling operations: Chloride -based FloVis mud (8.6 ppg). 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 NaBr or K-Formate completion fluid in order 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
Page 3 of 8 October 27, 2016
N rD Application: 3H-22L1, L1-01, Li-02, L1-03, L1-04, and L1-05.
pack off and MPD choke. BOPE equipment provides the secondary well control as detailed in section 3 "Blowout
Prevention Equipment Information".
In the 3H-22 laterals we will target a constant BHP of 13.1 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.
Reservoir pressure at 3H-22 is expected to continue to come down, as it has in the past two months through
pressure management in the area. Target pressure at the window will likely be modified to reflect this decrease
in pressure at time of CTD drilling, though for purposes of planning 13.1 ppg at the window will be used for the
calculations below.
Pressure at the 3H-22 Window (9715' MD, 6435' TVD) Using MPD
Pumps On (1.5 bpm)
Pumps Off
A -sand Formation Pressure (13.1 pp)
4107 psi
4107 psi
Mud Hydrostatic 8.6
2778 psi
2778 psi
Annular friction i.e. ECD, 0.080 si/ft
777 psi
0 psi
Mud + ECD Combined
3555 psi
2778 psi
(no choke pressure)
(underbalanced --552
(underbalanced
psi)
—1329 psi)
Target BHP at Window (13.1 ppg)
4383 psi
4383 psi
Choke Pressure Required to Maintain Target
828 psi
1605 psi
BHP
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
Well KRU 3H-22 is a Kuparuk A -sand injection (service) well that has been recently worked over to install
new 3Y2" tubing with a 4-1/2" Big Tail Pipe (BTP). Six CTD laterals will be drilled from the 31-1-22, three to
the north and three to the west, with the laterals targeting the Kuparuk A1, A2, and A3 sands.
Page 4 of 8 October 27, 2016
F,TD Application: 31-1-22L1, L1-01, Li-02, L1-03, L1-04, and L1-05.
The 3H-22L1 lateral will exit through the 4'h" BTP and 7" casing at 9715' MD and TD at 11,750' MD,
targeting the A1, A2 and A3 sands. It will be completed with 2%" slotted liner from TD up to 10,070' MD
with aluminum billet for kicking off the 3H-22L1-01 lateral.
The 3H-22L1-01 lateral will drill west to a TD of 11,150' MD targeting the Al and A2 sands. It will be
completed with 2%" slotted liner from TD up to 9,815' MD with an aluminum billet for kicking off the 3H-
22L 1-02 lateral.
The 3H-22L1-02 lateral will drill north to a TD of 11,750' MD targeting the Al sand. It will be completed
with 2%" slotted liner from TD up to 9,900' MD with an aluminum billet for kicking off the 3H-22L1-03
lateral.
The 3H-22L1-03 lateral will drill south to a TD of 11,825' MD targeting the Al, A2, and A3 sands. It will
be completed with 2%" slotted liner from TD up to 9765' MD with an aluminum billet for kicking off the
3H-22L 1-04 lateral.
The 3H-22L1-04 lateral will drill west to a TD of 11,750' MD targeting the A sands. It will be completed
with 2%" slotted liner from TD up to —9815' MD with an aluminum billet for kicking off the 3H-22L1-05
The 3H-22L1-05 lateral will drill north to a TD of 11,750' MD targeting the A3 sands. It will be completed
with 2%" slotted liner from TD up to TOWS with a deployment sleeve.
Pre-CTD Work
1. RU Slickline: Pull sheared SOV, injection test, obtain an A -sand SBHP, drift a dummy whip -stock.
2. RU E-line: Perform a jewelry log
3. RU E-line: Set Baker Hughes whipstock at 9715'
4. Prep site for Nabors CDR2-AC, including setting BPV.
Rig Work
1. MIRU Nabors CDR2-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test.
2. 3H-22L1 Lateral (A sand - west)
a. Mill 2.80" window at 9715' MD.
b. Drill 3" bi-center lateral to TD of 11,750' MD.
c. Run 2%" slotted liner with an aluminum billet from TD up to 10,070' MD.
3. 3H-22L1-01 Lateral (A sand -west)
a. Kick off of aluminum billet at 10,070' MD.
b. Drill 3" bi-center lateral to TD of 11,150' MD.
c. Run 2%" slotted liner from TD up to 9,815' MD.
4. 3H-22L1-02 Lateral (A sand - north)
a. Kick off of aluminum billet at 9,815' MD.
b. Drill 3" bi-center lateral to TD of 11,750' MD.
c. Run 2%" slotted liner from TD up to 9,900' MD.
5. 3H-22L 1-03 Lateral (A sand -north)
a. Kickoff of aluminum billet at 9,900' MD.
b. Drill 3" bi-center lateral to TD of 11,825' MD.
Page 5 of 8 October 27, 2016
PTD Application: 311-22L1, L1-01, Li-02, L1-03, L1-04, and L1-05.
c. Run 2%" slotted liner from TD up to 9765' MD.
3H-22L1-04 Lateral (A sand - west)
a. Kick off of aluminum billet at 9,765 MD.
b. Drill 3" bi-center lateral to TD of 11,750' MD.
c. Run 2%" slotted liner from TD up to 9,815' MD.
31-1-221-1-05 Lateral (A sand - north)
a. Kick off of aluminum billet at 9,815' MD.
b. Drill 3" bi-center lateral to TD of 11,750' MD.
c. Run 2%" slotted liner from TD up to TOWS at 9715' MD
Freeze protect. Set BPV, ND BOPE. RDMO Nabors CRD2-AC.
Post -Rig Work
1. Pull BPV.
2. Pre -produce for less than 30 days
3. Return to injection.
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 31-1-22 laterals will be displaced to an overbalanced fluid (K-Formate or NaBr depending on
pressures encountered at time of drilling) prior to running liner. See "Drilling Fluids" section for more
details.
Page 6 of 8 October 27, 2016
PTD Application: 31-1-221-1, L1-01, Li-02, L1-03, L1-04, and L1-05.
— 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 2%" 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.
• 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
3H-22L1
9820'
3H-22L1-01
10060'
3H-22L1-02
11075'
3H-221_1-03
11075'
3H-221_1-04
9820'
31HI-2211-1-05
11,075'
— Distance to Nearest Well within Pool
Lateral Name
Distance
Well
3H-22L1
1551'
3H-191-1
3H-22L1-01
1551'
3H-191-1
3H-22L1-02
1322'
3M-29
3H-22L1-03
1322'
31VI-29
31HI-2211-1-04
1551'
31-1-191-1
31HI-2211_1-05
1322'
31VI-29
16. Quarter Mile Injection Review (for injection wells only)
(Requirements of 20 AAC 25,402)
There are no wells within 1/4-mile of the 3H-221-1, 3H-221-1-01, 3H-221-1-02, 3H-221-1-03, 3H-221-1-04, and 3H-
221-1-05 laterals
Page 7 of 8 October 27, 2016
PTD Application: 31-1-221-1, L1-01, L1-02, L1-03, L1-04, and L1-05.
3H-22 (mother bore) Injector
• Classified as a "Normal Well"
• Original PTD is 188-011 & API Number is 50-103-20097-00
• The well was completed in RWO with 3.5" 9.3# L-80 tubing, 4.5" 12.6# L-80 Big Tail Pipe, and 7" 26# J-
55 production casing.
• A -sand perforations:
• Measure Depth: 9690' — 9710' MD, 9716'-9736' MD, and 9754'-9774' MD
• TVD: 6047'-6059' TVD, 6060'-6075' TVD, and 6086'-6098' TVD
• Production packer at 9578' MD — 5979' TVD, which is less than 200' from A -sand perforations
• Well is currently off-line
• 7" production casing was cemented with 200 sx class G (minimum)
• TOC 500' above top of Kuparuk
• 3H-22L1-02, 3H-22L1-03, & 3H-221-1-05 are planned at 1322' from 3M-29, 3M-29A, & 3M-29APB1,
which is 2' outside of %4 mile radius.
17. Attachments
Attachment 1: Directional Plans for 314-220, 3H-22L1-01, 3H-22L1-02, 3H-220-03, 3H-22L1-04,
and 314-220-05
Attachment 2: Current Well Schematic for 3H-22
Attachment 3: Proposed Well Schematic for 3H-22L1, 3H-220-01, 3H-22L1-02, 3H-220-03,
3H-22L 1-04, and 3H-22L 1-05
Page 8 of 8 October 27, 2016
ConocoPhillips
ConocoPhillips (Alaska) Inc. -Kup2
Kuparuk River Unit
Kuparuk 3H Pad
3H-22
3 H-221_ 1-05
Plan: 31-1-221-1-05_wp00
Standard Planning Report
25 October, 2016
WE P h I
BAKER
NUGNES
✓ ConocoPhillips WE&I
ConocoPhillips Planning Report BAKER
HUGHES
Database:
EDM Alaska NSK Sandbox
Company:
ConocoPhillips (Alaska) Inc. -Kup2
Project:
Kuparuk River Unit
Site:
Kuparuk 3H Pad
Well:
3H-22
Wel (bore:
3 H-22 L 1-05
Design:
3 H-22 L 1-05_wp00
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Well 3H-22
Mean Sea Level
3H-22 @ 76.00usft (3H-22)
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
Site Kuparuk 3H Pad
Site Position: Northing: 6,000,110.73 usft Latitude: 700 24' 41.531 N
From: Map Easting: 498,655.44 usft Longitude: 150° 0' 39.416 W
Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: -0.01 °
Well
3H-22
Well Position
+N/-S
0.00 usft Northing:
6,000,700.42 usft
Latitude: 70' 24' 47.331 N
+E/-W
0.00 usft Easting:
498,655.73 usft
Longitude: 1500 0' 39.411 W
Position Uncertainty
0.00 usft Wellhead Elevation:
usft
Ground Level: 0.00 usft
Wellbore
3H-221-1-05
Magnetics Model Name Sample Date Declination
BGGM2016 12/1/2016 17.83
Design
3H-22L1-05_wp00
Audit Notes:
Version:
Phase:
PLAN
Vertical Section:
Depth From (TVD)
+N/-S
(usft)
(usft)
L-
0.00
- -
0.00
Plan Sections
Measured
TVD Below
Depth Inclination
Azimuth
System
+N/-S
+E/-W
(usft)
(°)
(°)
(usft)
(usft)
(usft)
9,815.00
81.87
343.54
6,028.12
7,154.83
1,020.69
9,965.00
89.95
350.27
6,038.83
7,300.36
986.89
10,100.00
88.31
359.58
6,040.89
7,434.67
974.96
10,400.00
88.43
20.59
6,049.52
7,728.26
1,027.18
10,700.00
89.25
359.60
6,055.68
8,021.90
1,079.44
11,100.00
90.27
27.58
6,057.39
8,406.84
1,172.51
11,200.00
85.78
32.95
6,060.84
8,493.11
1,222.84
11,400.00
84.70
18.95
6,077.53
8,671.86
1,309.85
11,750.00
84.35
43.56
6,111.47
8,967.39
1,489.17
Dip Angle
(1)
Tie On Depth:
+E/-W
(usft)
0.00
80.98
Field Strength
(nT)
57,545
9,815.00
Direction
(°)
0.00
Dogleg
Build
Turn
Rate
Rate
Rate
TFO
(°/10oft)
(°/100ft)
(°/100ft)
(°) Target
0.00
0.00
0.00
0.00
7.00
5.39
4.48
40.00
7.00
-1.21
6.90
100.00
7.00
0.04
7.00
90.00
7.00
0.27
-7.00
272.00
7.00
0.26
7.00
88.00
7.00
-4.49
5.37
130.00
7.00
-0.54
-7.00
265.00
7.00
-0.10
7.03
92.00
1012512016 4:02.12PM Page 2 COMPASS 5000.1 Build 74
ConocoPhillips rigs
ConocoPhillips Planning Report BAKER
HUGHES
Database:
EDM Alaska NSK Sandbox
Local Co-ordinate Reference:
Well 31-1-22
Company:
ConocoPhillips
(Alaska)
Inc. -Kup2
TVD Reference:
Mean
Sea Level
Project:
Kuparuk River
Unit
MD Reference:
31-1-22 @ 76.00usft (31-1-22)
Site:
Kuparuk 3H Pad
North Reference:
True
Well:
31-1-22
Survey Calculation
Method:
Minimum Curvature
Wellbore:
3H-221-1-05
Design:
31-1-221-1-05_wP00
Planned Survey
Measured
TVD Below
Vertical
Dogleg
Toolface
Map
Map
Depth Inclination
Azimuth
System
+N/-S
+E/-W
Section
Rate
Azimuth
Northing
Easting
(usft)
(1)
(1)
(usft)
(usft)
(usft)
(usft)
(°/100ft)
(°)
(usft)
(usft)
9,815.00
81.87
343.54
6,028.12
7,154.83
1,020.69
7,154.83
0.00
0.00
6,007,854.35
499,677.61
TIP/KOP
9,900.00
86.44
347.37
6,036.78
7.236.64
999.48
7,236.64
7.00
40.00
6,007,936.16
499,656.42
9,965.00
89.95
350.27
6,038.83
7,300.36
986.89
7,300.36
7.00
39.61
6,007,999.87
499,643.84
Start 7 dls
10,000.00
89.52
352.68
6,038.99
7,334.97
981.71
7,334.97
7.00
100.00
6,008,034.48
499,638.66
10,100.00
88.31
359.58
6,040.89
7,434.67
974.96
7,434.67
7.00
99.99
6,008,134.17
499.631.93
3
10,200.00
88.33
6.58
6,043.82
7,534.42
980.33
7,534.42
7.00
90.00
6.008,233.90
499,637.32
10,300.00
88.36
13.59
6,046.71
7,632.77
997.82
7,632.77
7.00
89.79
6,008,332.24
499,654.83
10,400.00
88.43
20.59
6,049.52
7,728.26
1,027.18
7,728.26
7.00
89.59
6,008,427.72
499.684.20
4
10.500.00
88.68
13.59
6,052.05
7,823.75
1,056.54
7,823.75
7.00
-88.00
6,008.523.20
499,713.57
10.600.00
88.96
6.59
6.054.11
7,922.12
1,074.04
7,922.12
7.00
-87.82
6,008,621.56
499,731.09
10,700.00
89.25
359.60
6,055.68
8,021.90
1,079.44
8,021.90
7.00
-87.68
6.008,721.32
499,736.51
5
10,800.00
89.50
6.60
6,056.78
8,121.69
1,084.84
8,121.69
7.00
88.00
6,008,821.10
499,741.93
10,900.00
89.75
13.59
6,057.44
8,220.08
1,102.36
8.220.08
7.00
87.92
6,008.919.48
499,759.46
11,000.00
90.01
20.59
6,057.65
8,315.60
1,131.72
8,315.60
7.00
87.88
6,009.014.99
499,788.84
11,100.00
90.27
27.58
6,057.39
8,406.84
1,172.51
8,406.84
7.00
87.86
6,009,106.21
499,829.63
6
11,200.00
85.78
32.95
6,060.84
8,493.11
1,222.84
8,493.11
7.00
130.00
6,009,192.46
499,879.98
7
11,300.00
85.20
25.96
6,068.71
8,579.86
1,271.83
8,579.86
7.00
-95.00
6,009,279.19
499,928.98
11,400.00
84.70
18.95
6,077.53
8,671.86
1.309.85
8,671.86
7.00
-94.45
6,009,371.17
499,967.01
8
11,500.00
84.49
25.97
6,086.96
8,763.80
1,347.86
8,763.80
7.00
92.00
6,009,463.10
500,005.03
11,600.00
84.37
33.01
6,096.68
8,850.38
1,396.83
8,850.38
7.00
91.34
6,009,549.66
500,054.01
11,700.00
84.33
40.04
6,106.53
8,930.30
1,456.01
8,930.30
7.00
90.65
6,009,629.57
500.113.21
11,750.00
84.35
43.56
6,111.47
8,967.39
1,489.17
8,967.39
7.00
89.96
6,009,666.64
500.146.37
Planned
TD at 11750.00
1012512016 4:02:12PM Page 3 COMPASS 5000.1 Build 74
ConocoPhillips
ConocoPhillips (Alaska) Inc.
-Ku p2
Kuparuk River Unit
Kuparuk 3H Pad
3H-22
3H-22L1-05
3H-22L1-05_wp00
Travelling Cylinder Report
25 October, 2016
we pp-_
JA as
BAKER
HUGHES
Baker Hughes INTEQ RN
ConocoPhillips Travelling Cylinder Report BAKER
HUGHES
Company:
ConocoPhillips (Alaska) Inc. -Kup2
Project:
Kuparuk River Unit
Reference Site:
Kuparuk 3H Pad
Site Error:
0.00 usft
Reference Well:
3H-22
Well Error:
0.00 usft
Reference Wellbore
3H-221-1-05
Reference Design:
3H-22L1-05_wp00
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Output errors are at
Database:
Offset TVD Reference:
Well 3H-22
3H-22 @ 76.00usft (3H-22)
3H-22 @ 76.00usft (3H-22)
True
Minimum Curvature
1.00 sigma
OAKEDMP2
Offset Datum
Reference
3H-22L1-05_wp00
Filter type:
GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
Interpolation Method:
MD Interval 25.00usft Error Model: ISCWSA
Depth Range:
9,815.00 to 11,750.00usft Scan Method: Tray. Cylinder North
Results Limited by:
Maximum center -center distance of 1,367.40 usft Error Surface: Elliptical Conic
Survey Tool Program
Date 10/25/2016
From
To
(usft)
(usft) Survey (Wellbore)
Tool Name
Description
100.00
9,700.00 3H-22 (3H-22)
GCT-MS
Schlumberger GCT multishot
9,700.00
9,765.00 3H-221_1_wp04 (3H-22L1)
MWD
MWD - Standard
9,765.00
9,815.00 3H-22L1-04_wp00 (31H-221_1-04)
MWD
MWD - Standard
9,815.00
11,750.00 3H-22L1-05_wp00 (3H-221-1-05)
MWD
MWD - Standard
Casing Points
Measured Vertical
Casing Hole
Depth Depth
Diameter Diameter
(usft) (usft) Name
115.00 115.00 16"
16 26
4,348.00 3,127.05 9 5/8"
9-5/8 13-1/2
11,750.00 6,187.47 2 3/8"
2-3/8 3
Summary
Reference
Offset
Centre to
No -Go
Allowable
Measured
Measured
Centre
Distance
Deviation
Warning
Site Name
Depth
Depth
Distance
(usft)
from Plan
Offset Well - Wellbore - Design
(usft)
(usft)
(usft)
(usft)
Kuparuk 3H Pad
3H-20 - 3H-20L1-02 - 3H-2011-02
Out of range
3H-20 - 3H-20L1-06 - 3H-20L1-06
Out of range
3H-21 - 3H-21 - 3H-21
Out of range
3H-22 - 3H-22 - 3H-22
9,834.35
9,850.00
42A 8
8.15
34.07
Pass - Major Risk
3H-22 - 3H-221_1 - 3H-22L1_wp04
9,825.00
9,825.00
0.52
0.32
0.25
Pass - Minor 1/10
3H-22 - 3H-22L1-01 - 3H-2211-01_wp01
9,825.00
9,825.00
0.52
0.32
0.25
Pass - Minor 1/10
3H-22 - 3H-22L1-02 - 3H-221-1-02_wp02
9,825.00
9,825.00
0.46
0.32
0.18
Pass - Minor 1/10
3H-22 - 3H-22L1-03 - 3H-22L1-03_wp02
9,825.00
9,825.00
0.46
0.32
0.18
Pass - Minor 1/10
3H-22 - 3H-22L1-04 - 3H-22L1-04_wp00
9,824.99
9,825.00
0.33
0.29
0.09
Pass - Minor 1/10
3H-24 - 3H-24 - 3H-24
Out of range
3H-28 - 3H-28 - 3H-28
Out of range
3H-28 - 3H-28A- 3H-28A
Out of range
3H-31 - 3H-31 - 3H-31
Out of range
3H-32 - 3H-32 - 3H-32
Out of range
3H-32 - 3H-32PB1 - 3H-32PB1
Out of range
Kuparuk 3M Pad
3M-29 - 3M-29 - 3M-29
11,600.00
11,475.00
1,276.94
534.68
743.77
Pass - Major Risk
3M-29 - 3M-29A - 3M-29A
11,600.00
11,475.00
1,276.94
538.61
739.89
Pass - Major Risk
3M-29 - 3M-29APB1 - 3M-29APB1
11,600.00
11,475.00
1,276.94
538.61
739.89
Pass - Major Risk
CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation
1012512016 11:57:50AM Page 2 COMPASS 5000.1 Build 74
6 668
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ConocoPhillips
Well Attributes I
Max Angle & MD
TD
Alaska. Inc.
WIComment
We llbore API/UWI Field Name Wellbore Status
501032009700 KUPARUK RIVER UNIT INJ
ncl C) MD (ftKB)
60.15 5,100.00
Act Bum (ftKB)
10,234.0
---
H2S (pp.) I Data
SSSV: None
Annotation End Date KB-Grd (ft)
Last WO: 3/20/2016
Rig Release Dale
42.01 2/28/1988
3H-22, 101712016342:55 PM
Vertical schematic actual
Annotation Depth (ftKB) End Date
Annotation Last Mod By End Data
Last Tag: SLM 9,803.0 5/26/2016
Rev Reason: SET WHIPSTOCK pproven 10/7/2016
HANGER; 358
Casing Strings
Casing Description OD
(in)
ID (in)
Top (ftKB)
Set Depth (ftKB) Set
Depth (TVD)...
Wt/L¢n (I...
Grado
Top Thread
CONDUCTOR
1 ,
15.062
36.0
115.0
115.0
62.50
H-40
WELDED
Casing Description OD
(in)
ID (in)
Top (ftKB)
Sat Depth (ftKB) Set
Depth (TVD)...
Wt/Len (I...
Grade
Top Thread
SURFACE
95/8
8.921
35.0
4,347.E
3,126.8
36.00
J-55
BTC
Casing Description OD
(in)
ID (in)
Top (ftKB)
Set Depth (ftKB) Set
Depth (TVD)...
WNLen (I...
Grade
Top Thread
PRODUCTION
7
6.276
35,0
10,052.2
6,267.8
26.00
J-55
BTC
Tubing Strings
Tubing Description String Ma... ID (in) Top (ftKB) Set Depth (ft.. Set Depth (TVD) (... Wt (Ibffl) Gratle Top Connection
TUBING RW02016 3 1/2 2.992 35.0 9,586.8 5,984.E 9.30 L-80 EUE 8rd Mod
CONDUCTOR, 36.0-115.0
Completion Details
Nominal ID
Top (ftKB)
Top (TVD) (ftKB)
Top Ind (°)
Item Des
Com
(in)
35.0
35.0
0.09 HANGER
McEvoy Gen III Tubing Hanger, MSDP-".5-MS-3,
7- 2.950
GAS LIFT', 3,246.3
1116" x 3-112" EUE 8rd Box x Box, 3" H BPVG
9,574.2
5,976.9
52.65 LOCATOR
Locator Sub, GBH-22 (bottom of the locator spaced
out 2.990
3.83')
9,575.3
5,977.6
52.65 SEALASSY
Seal Assembly, 80-40
3.020
Tubing Description String
Ma...
ID (in)
Top. (ftKB) Set
Depth (ft..
Set Depth (TVD) (...
Wl thin) Grade
Top Connection
LOWER COMPRWO 41/2
3.958
9,578.3
9,736.0
6,075.3
12.60 L-80
STC
2016
Completion Details
SURFACE; 35.03,347.6-
Nominal ID
Top (ftKB)
Top (TVD) (ftKB)
I Top Ind (°)
Item Des
Com
(in)
9,578.3
5,979.4
52.65 PACKER
587-400 Model 'F' Production Packer
4.000
GAS LIFT; 5,590.9
9,58t6
5,981.4
52.64 SEE
8040 Seal Bore Extension (SBE)
4.000
9,591.0
5,987.1
52.62 XO
Reducing
Crossover, 4-3/4" Stub Acme Box x 3-1/2" EUE
8rd Pin 2.970
9,639.7
6,016.7
52.57 NIPPLE
Nipple, HES, 2.813" X, SN: C-3562596
2.812
9,651.6
6,023.9
52.56 PORTED
Ported Crossover, 3-12" EUE 8rd Mod Box x4-1/2"
STC 2.992
CROSSOVER
Pin
GAS LIFT, 7,2602
9,653.4
6,025.0
52.5E PORTED
Ported Wearsox Joint, 4-1/2", 12.6#, L-80, STC
Box x 3.958
WEARSOX
1
I
Mule Shae
Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.)
Top (TVD)
Top
Incl
Top (ftKB)
(ftKB)
(°)
Des
Co.
Run Date
ID (in)
9,715.0
6,062.5
52.52
WHIPSTOC
BAKER 3.5"X4.5" WHIPSTOCK(GENII DELTA). 10/6/2016
GAS LIFT; 8,576,8
TOWS = 9715, WHIPSTOCK ORIENTATION =
330DEG, CCL TO TOP OF WHIPSTOCK = 14.9', RA
TAG @7.35 FROM TOP, WHIPSTOP OAL=12.97
Perforations & Slots
Shot
GAS LIFT; 9, 51] 2
Dens
Top (TVD) Btm
(TVD)
(shols/f
Top (ftKB)
Btm (ftKB)
(ftKB)
(ftKB)
Zone
Date
t)
Type
Co.
9,690.0
9,710.0
6,047.3
6,059.4 A-3,
31-1-22
8/11/1988
8.0
APERF 2
1/8 EnerJet; 60 deg ph
9,716.0
9,736.0
6,063.1
6,075.3 A-2,
31-1-22
8/11/1988
8.0
APERF 2
1/8 EnerJet; 60 deg ph
LOCATOR; 9, 574 2
9,754.0
9,774.0
6,086.2
6,098.4 A-1,
31-1-22
4/25/1986
4.0
IPERF SOS
4.5" Ultra P; 120
deg
ph
PACKER; 9 579.3
Mandrel Inserts
SEAL ASSY; 9,575.3
St
SEE: 9,581.E
ali
N Top (ftKB)
ftKB )
ToD)
(ftKB)
Make Model
OD in
( )
�G,
Valve p
Type
Latch
Type
Pad Size
(in)
T (p Run
(psi)
Run Dale
Co.
1 3,246.3
2,509.1
Cameo MMG
1 1/2
GAS LIFT
DMY
RK
0.000
0.0 3/19/2016
xO R¢ducing; 9,591.0
2 5,598.9
3,802.4
Cameo MMG
11/2
GAS LIFT
DMY
RK
0.000
0.0 3/19/2016
3 7,260.2
4,693.3
Cameo MMG
1 112
GAS LIFT
DMY
RKP
0.000
0.0 5/272016
4 8,576.8
5,395.5
Camco MMG
1 112
GAS LIFT
DMY
RK
0.000
0.0 3/19/2016
5 9,517.3
5,942.4 1
Cameo MMG
1 1/2
GAS LIFT
DMY
RK
0.000
0.0 3/19/2016
Notes: General & Safety
End Date
Annotation
NIPPLE; 9,639.E
4/28/1988
NOTE: Bad spot in 7"CSG 8257'-8281'; Max ID=6.45"; Tested to 2600psi w/10 ppg Brine.
11/2/2010
NOTE: View Schematic w/ Alaska Schematic9.0
PORTED CROSSOVER:
9,651.6
PORTED W EARSOX; 9,653A
APERF; 9,690.0-9,710.0-
W HIPSTOC', 9,]15.0
APERF: 9, 716.0-9, 73fi.0
IPERF; 9,754.0-9,774.0-
PRODUCTION; 35.0-10,052.2
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1
Bettis, Patricia K (DOA)
From: Connelly, Jeff <Jeff.S.Connelly@conocophillips.com>
Sent: Wednesday, November 09, 2016 5:47 AM
To: Bettis, Patricia K (DOA)
Subject: RE: KRU 3H-221-1 (PTD 216-145): Permit to Drill Application
Patricia,
The maximum down -hole pressure and potential surface pressure should be based on 3H-31 as follows:
Maximum down -hole pressure: 4825 psi
Maximum potential surface pressure: 4205 psi (assuming a gas gradient of 0.1 psi/ft)
I apologize for the inconsistency between the two documents.
Regards,
Jeff Connelly
From: Bettis, Patricia K (DOA) [mailto:patricia.bettis@alaska.gov]
Sent: Tuesday, November 08, 2016 4:32 PM
To: Connelly, Jeff <Jeff.S.Connelly@conocophiIli ps.com>
Subject: [EXTERNAL]KRU 31-1-221-1 (PTD 216-145): Permit to Drill Application
Good afternoon Jeff,
On Form 10-401, Box 17, the maximum downhole pressure is shown as 4384 psig; whereas the maximum potential
surface pressure is stated as 3741 psig.
On page 2 of the "Application for Permit to Drill Document", it is stated that the maximum downhole pressure in the 3H-
22 vicinity is 3H-31 at 4825 psi; whereas the maximum potential surface pressure in 31-1-22, assuming a gas gradient of
0.1 psi/ft would be 4205 psi.
Please clarify what ConocoPhillips anticipates to be the maximum downhole pressure in the 3H-22 vicinity and the
maximum potential surface pressure for 3H-22.
Thank you,
Patricia
Patricia Bettis
Senior Petroleum Geologist
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue
Anchorage, AK 99501
Tel: (907) 793-1238
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
TRANSMITTAL LETTER CHECKLIST
WELL NAME: RR CA_ 3H — J2 IQ QS"
PTD: Q ll - / S�
Development / Service _ Exploratory Stratigraphic Test Non -Conventional
FIELD: �i1/� POOL:
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK
OPTIONS
TEXT FOR APPROVAL LETTER
MULTI
The permit is for a new wellbore segment of existing well Permit
/
LATERAL
No. i 110 , API No. 50-_La- c2 00 - 00 - oo .
(If last two digits
Production should continue to be reported as a function of the original
in API number are
API number stated above.
between 60-69)
In accordance with 20 AAC 25.005(f), all records, data and logs
acquired for the pilot hole must be clearly differentiated in both well
Pilot Hole
name ( PH) and API number (50- -
- -� from records, data and logs acquired for well
(name on permit).
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce/inject is contingent upon issuance of a conservation
Spacing Exception
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 AOGCC must be in no greater
Dry Ditch Sample
than 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:
production or production testing of coal bed methane is not allowed for
Non -Conventional
(name of well) until after (Company Name) has designed and
Well
implemented a water well testing program to provide baseline data on
water quality and quantity. (Company Name) must contact the AOGCC
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 2/2015
WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 _
_
Well Name: KUPARUK RIV UNIT 31-1-221-1-05 ___ Program SER Well bore seg
PTD#: 2161500 Company CONOCOPHILLIPS ALASKA INC Initial Class[Type
SER / 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 -
ADL0025532,-Surf Loc; ADL0025523, Topprod.lntery &-TD.
I3
Unique well name and number -
Yes
KRU 3H-22L1-05_
4
Well located in-a.defined-pool _
Yes
governed b Conservation. Order No, 432D.
KUPARUK RIVER,-KUPARUK RIV OIL - 490100,_ y
9
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.avail_able in-d-rilling 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 11/9/2016
.
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_
Yes -
- - - - AIO.2_C-Kupar_uk River -Unit _ - - - - -
15
All wells- within _1Amile-area_of review identified (For service well only)
Yes
- - - - KRU 3H-22,_3H-22L1-02, 31-1-221-1-03, 3M-29
116
Pre -produced injector: duration -of pre production less than 3 months (For service well only)
Yes
- - - Well will be pre -produced for less than 30 days.
18
Conductor string -provided - - - -
NA_
Conductor set_in Motherbore 31-1-22
Engineering
19
Surface casing_ protects all known USDWs - _ - - _ _ _ _ _ _ - - -
NA-
- -Surface casing set and cemeneted in motherbore_3H-22_
20
CMT_vol_ adequate to circulate -on conductor & surf-csg . - - -
NA
- - .. _ .
21
CMT_vol adequate to tie -in -long string to_surfcsg. - - -
NA_
7"_production casing cemented. properly. Cutting window in the -tubing. tail.. .
22
C_MT will coverall known -productive horizons- . - -
Yes
Setting 2.3/8" slotted-liner.in the lateral..
23
Casing designs adequate for C,_T, B &- permafrost_ - - - - - -
Yes -
-
24
Adequate tankage.or reserve pit
Yes
Rig has steel pits. All waste -to approved disposal wells. - - - - -
25
If_a_re-drill, has-a.1-0-403 for abandonment been approved
NA_
Motherbore will -not be P_& A'd- - - . - . - . - .. - - - - - - - - - - - . -
26
Adequate wellbore separat_io_n_proposed_ - - -
Yes
Anti -collision data provided.- No issues - - - - - - - - - - - - - - - - - - - - - - - -
27
If-diverter required, does it meet_ regulations
NA_
Wellhead in place. Will place BOPE on production tree._
Appr Date
28
Drilling fluid_ program schematic-&- equip list_adequat_e_
Yes
Max formation pressure = 4825 psi (15 ppg EMW) Will -drill with 8.6 ppg_mud_a_nd _maintain_ BHP with_MPD
GLS 11/14/2016
29
BOPEs,_do they meet regulation _ _ _ _ - _ -
Yes _
CDR2 has 5000 psi BOPS .. .. - - -- - - - - - - - - - - - - -- - - -
30
BOPE press rating appropriate; test to -(put psig in comments)_ - - -
Yes
MASP= 4205 psi Will test -ROPE -to 4500_psi_( annular to_2500 psi) - -
31
Choke_ manifold compliesw/API RP-53(May 84)__________ __ _
Yes_-
--..-------- --- - ----------------- -- -- -- --- - - - -- - --
32
Work will occur without operation shutdown_ - - - -
Yes
- - - - - - - - - - - - - - -
33
Is presence_ of 112S gas probable - - - - - - - - -
Yes
112S on pad._ Rig has sensors and alarms.
134
Mechanical -condition of wells within AOR verified (For service well only) - - - - - - - - - - - -
Yes
AOR completed_. -Nowells with Kup A sand penetrations in 1/4 mile area.
i35 Permit_can be issued w/o hydrogen sulfide measures - - - - - - - - - - - No_ Wells-o_n_3H-Pad are_H2_S-bearing. 112S measures_ required.
Geology 36 Data_presented on potential overpressure zones Yes Maximum potential -reservoir pressure_ is 15.0 ppg_EMW;_will be drilled_ using 8.6_ppg mud and MPD technique._
Appr Date 37 Seismic_analysis_ of shallow gas -zones. NA_ - - - - - - - - - - - - - - - - - - - - - - - - - - -
PKB 11/9/2016 38 Seabed condition survey -(if off -shore) _ _ _ _ _ _ _ _ - - - - - - - - - - NA-
39 Contact name/phone for weekly_ progress reports_ [exploratory only] NA- Onshore service well to be drilled.
Geologic Engineering Public 31-1-221-1-05 is the 6th lateral to be drilled. Will target KUP A sand north of the motherbore current BHL. GIs.
4 ;�f
Date: Commissioner: Date Date
1/rs/l� dco issioner t L I t1% 1 t-L
