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HomeMy WebLinkAbout216-130Guhl, Meredith D (DOA)
From: Guhl, Meredith D (DOA)
Sent: Monday, November 26, 2018 9:44 AM
To: 'Starck, Kai'
Cc: Loepp, Victoria T (DOA); Boyer, David L (DOA)
Subject: KRU 1H-07A L1, L1-01, PTDs 216-012, 216-130, Permits Expired
Hello Kai,
The following Permits to Drill, issued to ConocoPhillips Alaska, have expired under Regulation 20 AAC 25.005 W. The
PTDs will be marked expired in the AOGCC database.
• KRU 1H-07A L1, PTD 216-012, Issued 12 October 2016
• KRU 1H-07A 1-1-01, PTD 216-130, Issued 14 October 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-Buhl@alaska.gov.
THE STATE
944113agolk'
GOVERNOR BILL WALKER
Kai Starck
CTD Director
ConocoPhillips Alaska, Inc.
P.O. Box 100360
Anchorage, AK 99510-0360
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
WWW.aogcc.alaska.gov
Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU I H-07AL 1 -0 1
ConocoPhillips Alaska, Inc.
Permit to Drill Number: 216-130
Surface Location: 768' FNL, 787' FEL, Sec. 33, T12N, RI OE, UM
Bottomhole Location: 2260' FNL, 3826' FEL, Sec. 27, T12N, RIOE, UM
Dear Mr. Starck:
Enclosed is the approved application for permit to drill the above referenced service well.
The permit is for a new wellbore segment of existing well Permit No. 216-011, API No. 50-029-
20755-01-00. 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,
Cat4 P. Foerster
Chair
DATED this 1 day of October, 2016.
t`t.;t1VMU
OCT 11 2016
STATE OF ALASKA
A :A OIL AND GAS CONSERVATION COMIV ,ON
PERMIT TO DRILL
20 AAC 25.005
AOGCC
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 ❑✓
Stratigraphic Test ❑ Development - Oil ❑
Service - Winj Single Zone
Coalbed Gas ❑ Gas Hydrates ❑
Redrill ❑ Reentry ❑
Exploratory - Oil ❑ Development - Gas ❑
Service - Supply ❑ Multiple Zone ❑
Geothermal ❑ Shale Gas ❑
2. Operator Name:
5. Bond: Blanket ❑✓ Single Well ❑ e4
11. Well Name and Number:
ConocoPhillips Alaska Inc
Bond No. _)'r S
KRU 1 H-07AL1-01
3. Address:
6. Proposed Depth: PR L I
12. Field/Pool(s):
P.O. Box 100360 Anchorage, AK 99510-0360
y1
MD: 10850' ° TVD: 6' v
Kuparuk River Field / Kuparuk Oil Pool
4a. Location of Well (Governmental Section):
7. Property Designation (Lease Number):
Surface: 768' FNL, 787' FEL, Sec. 33, T12N, R10E, UM
ADL 25639
Top of Productive Horizon:
8. Land Use Permit:
13. Approximate Spud Date:
2933' FNL, 4442' FEL, Sec. 27, T12N, R10E, UM
ALK 464
10/13/2016
Total Depth:
9. Acres in Property:
14. Distance to Nearest Property:
2260' FNL, 3826' FEL, Sec 27, T12N, R10E, UM
2560 Y
6215'
4b. Location of Well (State Base Plane Coordinates - NAD 27):
10. KB Elevation above MSL (ft): 85' "
15. Distance to Nearest Well Open
Surface: x- 549561 y- 5979935 Zone-4
GL Elevation above MSL (ft): 35'
to Same Pool: 1755' 1 H-17
16. Deviated wells: Kickoff depth: 9570' feet -
17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 91 degrees
Downhole: 3721 psi Surface: 3065 psi
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
3013'
7837'
6391'
10850'
6554'
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):
8300'
6959'
None
8194'
6867'
None
Casing
Length
Size
Cement Volume
MD
TVD
Conductor/Structural
80,
16"
315 sxs AS II
80'
80'
Surface
2365'
10-3/4"
1000 sx AS III & 250 sx AS II
2365'
2340'
Intermediate
Production
8274'
7"
962 sx Class G
8274'
6937'
Liner
Perforation Depth MD (ft): 7696' - 7755', 7805' - 7830', 8015' -
Perforation Depth TVD (ft): 6442' - 6492', 6534' - 6555', 6713' - 6720' & 6727' -
8023' & 8031' - 8051'
6744'
20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling
Program Q Time v. Depth Plot ❑ Shallow Hazard Analysis❑
Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements0
21. Verbal Approval: Commission Representative:
Date
Cb
22. 1 hereby certify that the foregoing is true and the procedure approved herein will not
be deviated from without prior written approval.
Contact Ron Phillips @ 26�6312
Email ron.l.phillips(�i_)cop.com
Printed Name Kai Starck
Title CTD Director
Signature
Phone 263-4093 Date �� -/� - ZO/lO
Commission Use Only
Permit to Drill
API Number:
Permit Approval
See cover letter for other
Number: 1�
_
50- — -
5
-- db
'J
Date: I O - (y - ( Le
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: DP �tS J�—v� S --
r
Samples req'd: Yes ❑, Nod Mud log req'd: Yes ❑ No [✓�
HZS measures: Yes [1( No Directional svy req'd: Yes No ❑
-hh "e4 ✓ `�i/C� � /5
I-p U0 5 Spacing
LnJS
exception req'd: Yes ❑ No Inclination -only svy req'd: Yesr❑ Nog
Post initial injection MIT req'd: Yes I No ❑
L
APPROVED BY
Approved by _
COMMISSIONER THE COMMISSION Date:/)
-V'TZ10//Z1/6 `
�� �� 1411 A � tl// Submit Form and
GR
Form 10-401 (Revised 11/2015) p r , i , �� f 2 months from the date of approval (20 AAC 25.005(g)) Attachments in Duplicate
O L
ConocoPhillips
Alaska
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
October 10, 2016
Commissioner - State of Alaska
Alaska Oil & Gas Conservation Commission
333 West 7th Avenue Suite 100
Anchorage, Alaska 99501
Dear Commissioner:
RECEIVED
OCT 11 2016
-AOGCC
ConocoPhillips Alaska, Inc. hereby submits an application for permits to drill a tri-lateral well out of the Kuparuk
well 1 H-07 using the coiled tubing drilling rig, Nabors CDR3-AC.
Note: This is a revision to move the second lateral 1 H-07AL1 —500 to the west of the approved PTD 216-012
due to an unplanned fault and to drill a new unplanned third lateral 1 H-07AL1-01 to the east of the unplanned
fault.
The work is scheduled to begin in Oct. 12, 2016. The CTD objective will be to drill three laterals (1 H-07A, 1 H-
07AL1 & 1 H-07AL1-01), targeting the A -sand intervals. A cement plug must be placed and squeezed in the3.5"
x 7" annulus of well 1 H-07 to facilitate a casing exit for these laterals, which will likewise effectively plug off the
existing perforations. ConocoPhillips requests a variance from the plugging requirements of 20 AAC
25.112 (c) to facilitate the casing exit of the 1H-07 horizontal laterals. The proposed plugging procedure
meets the overall objective of this section, providing an equally effective plugging of the well to prevent migration
of fluids to other hydrocarbon zones or freshwater.
Attached to this application are the following documents:
— 10-403 Sundry application to plug A/C -sand perfs in 1 H-07
— Summary of the operations
— Permit to Drill Application Form 10-401 for 1 H-07A, 1 H-07AL1 revised & 1 H-07AL1-01
— Detailed Summary of Operations
— Directional Plans
— Current Schematic
— Proposed Schematic
If you have any questions or require additional information please contact me at 907-265-6312.
Sincerely,
Ron Phillips
Coiled Tubing Drilling Engineer
907-265-6312
Kuparuk CT® Laterals NABORS ALASKA
1 H-07A, AL`i revised & AL1-a'i
C(J9
Application for Permit to Drill Document ZORC
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....................................................................... 6
(Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 6
16. Quarter Mile Injection Review (for injection wells only)............................................................... 7
(Requirements of 20 AAC 25.402).......................................................................................................................................................... 7
17. Attachments.................................................................................................................................... 7
Attachment 1: Directional Plans for 1 H-07A, AL1 revised & AU-01...............................................................................7
Attachment 2: Current Well Schematic for 1 H-07............................................................................................................7
Attachment 3: Proposed Well Schematic for 1 H-07A, AL1 revised & AL1-01.................................................................7
Page 1 of 7 October 10, 2016
PTD Application: 1H-07A, AL1 revised & AL1-01
1. Well Name and Classification
(Requirements of 20 AAC 25.005(t) and 20 AAC 25.005(b))
The proposed laterals described in this document are 1H-07A, AL1 revised & AL1-01. All laterals will be
classified as "Service — Injection" 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 1 H-07A, AL1 revised & AL1-01.
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 /
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 p and to 3500 psi. Using the
maximum formation pressure in the area of 3721 psi in 1 H-07 (i.e. 10.9 ppg EMW), the maximum
potential surface pressure in 1 H-07, assuming a gas gradient of 0.1 psi/ft, would be 3065 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 1 H-07 was measured to be 3721 psi (10.9 ppg EMW) on 11/27/2015. The
maximum downhole pressure in the 1 H-07 vicinity is the 1 H-07. The well will be drilled toward lower pressure.
Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b))
No gas injection performed at 1 H pad however, 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 is 1 large fault crossing. 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 1 H-07 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 October 10, 2016
PTD Application: 1H-07A, AL1 revised & AL1-01
6. Casing and Cementing Program
(Requirements of 20 AA 25.005(c)(6))
New Completion Details
Lateral
Liner Top
Liner Btm
Liner Top
Liner Btm
Name
MD
MD
TVDSS
TVDSS
Liner Details
2%", 4.7#, L-80, ST-L slotted liner;
1H-07A
8540'
11100,
6621'
6582'
aluminum billet on top
1H-07ALl
23/", 4.7#, L-80, ST-L slotted liner;
revised
9570'
10200'
6641'
6667'
aluminum billet on to
2'/", 4.7#, L-80, ST-L slotted liner;
1H-07AL2
7837'
10850'
6476'
6639'
with a swell packer in the 'B' shale
and a liner top packer on to
Existing Casing/Liner Information
Category
OD
Weight
(ppf)
Grade
Connection
Top
MD
Btm
MD
Top
TVD
Btm
TVD
Burst
psi
Collapse
psi
Conductor
16"
65.0
H-40
Welded
30'
80'
0'
80'
1640
630
Surface
10-3/4"
45.5
K-55
BTC
29'
2365'
0'
2340'
3580
2090
Production
7"
26.0
K-55
BTC
29'
8274'
0'
6937'
4980
4330
Tubing
3-1/2"
9.3
L-80
8rd EUE
25'
1 7662'
0'
6413'
1 10160
10530
7. Diverter System Information
(Requirements of 20 AA 25.005(c)(7))
Nabors CDR2-AC / 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 AA 25.005(c)(8))
Diagram of Drilling System
A diagram of the Nabors CDR2-AC / CDR3-AC mud system is on file with the Commission.
Description of Drilling Fluid System
— Window milling operations: Chloride -based FloVis mud (9.7 ppg)
— Drilling operations: Chloride -based PowerVis mud (9.6 ppg). This mud weight will not hydrostatically
overbalance the reservoir pressure, overbalanced conditions will be maintained using MPD practices
described below.
— Completion operations: BHA's will be deployed using standard pressure deployments and the well will
be loaded with 11.8 ppg NaBr completion fluid in order to provide formation over -balance and maintain
wellbore 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".
In the 1H-07 laterals we will target a constant BHP of 11.8 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
Page 3 of 7 October 10, 2016
PTD Application: 1H-07A, AL1 revised & AL1-01
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 1H-07 Window (7842' MD, 6566' TVDSS) Using MPD
Pumps On
(1.5 bpm)
Pumps Off
A -sand Formation Pressure (10.9pp)
3721 psi
3721 psi
Mud Hydrostatic (9.6 pp)
3278 psi
3278 psi
Annular friction (i.e. ECD, 0.060 psi/ft)
471 psi
0 psi
Mud + ECD Combined
3748 psi
(overbalanced
3278 psi
(underbalanced
(no choke pressure)
—27psi)
—444psi)
Target BHP at Window (11.8 ppg)
4029 psi
4029 psi
Choke Pressure Required to Maintain
281 psi
751 psi
Target 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 W-07 is a Kuparuk A -sand injection well equipped with 31/2" tubing and 7" production casing.
One lateral will be drilled to the south of the parent well and two laterals will be drilled to the north with
the laterals targeting the A4 sand. A thru-tubing whip -stock will be set inside the 31/2" liner at the planned
kickoff point of 7842' MD to drill three laterals.
The 1H-07A southern sidetrack will exit through the 31/Z" liner and 7" production casing at 7842' MD and
TD at 11,100' MD, targeting the A4 sand. It will be completed with 2%" slotted liner from TD up to 8540'
MD with an aluminum billet for kicking off the 1H-07AL1 lateral.
The 1H-07AL1 will drill north then west to a TD of 10,200' MD targeting the A4 sand. It will be
completed with 2%" slotted liner from TD up to 9570' MD with an aluminum billet for kicking off the 1H-
07AL 1 lateral.
Page 4 of 7 October 10, 2016
PTD Application: 1H-07A, AL1 revised & AL1-01
The iH-07AL1-01 will drill north then east to a TD of 10,850' MD targeting the A4 sand. It will be
completed with 2%" slotted liner from TD up to 7837' MD with a swell packer in the `B' shale and a liner
top production packer on top.
Pre-CTD Work
1. RU slickline.
a. Pull lower most AVA isolation sleeve at 7874` MD
b. Dummy of GLV's
2. RU pumping
a. Perform injectivity test using diesel on the C1 perfs
3. RU slick -line
a. Pull AVA isolation sleeve at 7781 ` MD allowing the C 1 & C3/C4 to equalize
4. RU coil
a. Cement squeeze C-sand perforations, and fill 3-1/2" x 7" annuli allow cement to harden.
b.Mill down to 7857' MD
c. Under ream down to 7857' MD
d. Pressure test cement.
5. RU E-Line
a. Dummy WS drift to 7842'
b. Run and set WS at 7842' MD.
6. Prep site for Nabors CDR2-AC, including setting BPV
Ria Work
1. MIRU Nabors CDR2-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test.
2. 1H-07A Side Track (A4 sand south)
a. Mill 2.80" window at 7,842' MD.
b. Drill 2.74". x 3.00" bi-center lateral to TD of 11,100' MD
c. Run 2%" slotted liner with an aluminum billet from TD up to 8,540' MD
3. 1H-07AL1 Lateral (A4 sand northwest)
a. Kick off of the aluminum billet at 8,540' MD
b. Drill 2.74" x 3.00" bi-center lateral to TD of 10,200' MD
c. Run 2%" slotted liner with an aluminum billet from TD up to 9,570' MD
4. 1 H-07AL 1 -0 1 Lateral (A4 sand northeast)
a. Kickoff of the aluminum billet at 9,570' MD
b. Drill 2.74" x 3.00" bi-center lateral to TD of 10,850' MD
c. Run 2%" slotted liner (with swell packer in Kuparuk B) from TD up to 7837' MD, inside the
3'/2" tubing
5. Freeze protect. Set BPV, ND BOPE. RDMO Nabors CRD2-AC / CDR3-AC.
Post -Rig Work
1. Pull BPV
2. Obtain static BHP. Install GLV's and Liner top packer.
3. Produce well for more than 30 days
4. Re -sundry to turn back to injection
Page 5 of 7 October 10, 2016
PTD Application: 1H-07A, AL1 revised & AL1-01
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 using 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 slick -line.
— 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 1 H-07 CTD laterals will be displaced to an overbalance completion fluid (as detailed in Section 8
"Drilling Fluids Program") prior to running liner.
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. f
• 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 AA 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 openhole section.
Page 6 of 7 October 10, 2016
PTD Application: 1 H-07A, AL1 revised & AL1-01
— Distance to Nearest Property Line (measured to KPA boundary at closest point)
Lateral Name
_.
Distance
1 H-07A
6990'
1 H-07ALl
revised
6575'
1 H-07AL1-01
6215'
— Distance to Nearest Well within Pool
Lateral Name_
Distance
Well
1 H-07A
1 H-14
1080'
1 H-07AL1
revised
1 H-17
1610'
1 H-07ALl -01
1 H-17
1755'
16. Quarter Mile Injection Review (for injection wells only)
(Requirements of 20 AAC 25.402)
1 H-14 & 1 H-16 are within %4-mile of the 1 H-07A, L1 revised &1 L-01 wells
• See Attached AOR sheet
17. Attachments
Attachment 1: Directional Plans for 1H-07A, AL1 revised & AL1-01
Attachment 2: Current Well Schematic for 1H-07
Attachment 3: Proposed Well Schematic for 1H-07A, AL1 revised & AL1-01
Page 7 of 7 October 10, 2016
Area of Review Well Name
Topof A -sand
Top ofASand Oil
TOP of Cement
ToPof Cement
Top of :o"M
Reservoir Btatus
Zonal Isolation
Cement Opereti—Summary
Mechanical lntegr'dy
Pf0
API
WELL NAME
STATUS
08 Pont (MO)
Pool )TV05S)
)MD)
)]YOBS)
Determined8y
6441'
685V
5-- •
CSL
Perfs cemented and
Packer @7880'MD
962 sss Class Gcemen[
State witnessed passing MR
182-084
50029-20755
iH-07
Suspended
]696-
+
abandoned
IA to 2820 psi on 8/11/13
6632'
0.'
5798'
CET
Peds open for
packer@6804'MD
590 sas Class G cement
�ZL Passed. Initial T/1/0=
192.131
S0OB-22315
1H-16
Pmdudng
7185'
pmd..ion
si 160/1250/780 on 5/30/15
8691'
6554' •
8330'
6412'
Cu
Peds open for
Packer@8172'MD
520 sas Class G cement
Competent producer with
193-OS2
5 029-22359
1H44
Producing
production
passing TlFL
��
ConocoPh i I I i ps
ConocoPhillips (Alaska) Inc. -Kup1
Kuparuk River Unit
Kuparuk 1 H Pad
1 H-07
1 H-07AL1-01
Plan: 1 H-07AL1-01_wp01
Standard Planning Report
08 October, 2016
BAKER
HUGHES
ConocoPhillips rigs
ConocoPhillips Planning Report BAKER
HUGHES
Database:
EDM Alaska NSK Sandbox
Company:
ConocoPhillips (Alaska) Inc. -Kupl
Project:
Kuparuk River Unit
Site:
Kuparuk 1 H Pad
Well:
1 H-07
Wellbore:
1 H-07ALl-01
Design:
1 H-07AL1-01_wp01
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Well 1 H-07
Mean Sea Level
1 H-07 @ 85.00usft (1 H-07)
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 1 H Pad
Site Position:
Northing:
5,979,968.84 usft Latitude:
70° 21' 21.831 N
From:
Map
Easting:
549,197.16usft Longitude:
149° 36' 1.675 W
Position Uncertainty:
0.00 usft
Slot Radius:
0.000 in Grid Convergence:
0.38 °
Well
1 H-07
Well Position
+N/-S 0.00 usft
Northing:
5,979,935.13 usft Latitude:
700 21' 21.476 N
+E/-W 0.00 usft
Easting:
549,560.55 usft Longitude:
149° 35' 51.058 W
Position Uncertainty
0.00 usft
Wellhead Elevation:
usft Ground Level:
0.00 usft
Wellbore
1H-07AL1-01
7
Magnetics
Model Name
Sample Date
Declination Dip Angle
Field Strength
BGGM2016
9/1/2016
18.07 80.98
57,554
Design
1 H-07AL1-01_wp01
Audit Notes:
Version:
Phase: PLAN
Tie On Depth:
9,570.00
YCI VI.aI Js:VV VI1. s: �Jlll 1-1 Vlll,lYvr TIYI-J TG/-YY VIICI:IIVII
(usft) (usft) (usft) (°)
0.00 0.00 0.00 - - 90.00
Plan Sections
Measured
TVD Below
Dogleg
Build
Turn
Depth
Inclination
Azimuth
System
+N/-S
+E/-W
Rate
Rate
Rate
TFO
(usft)
(°)
(°)
(usft)
(usft)
(usft)
(°/100ft)
(°/100ft)
(°/100ft)
(°) Target
9,570+00
90.13
352.82
6,641.24
3,741.10
1,209.49
0.00
0.00
0.00
0.00
9,770.00
91.39
32.81
6,638.47
3,932.16
1,252.94
20.00
0.63
19.99
88.00
9,940.00
89.14
66.73
6,637.66
4,040.35
1,380.84
20.00
-1.32
19.96
93.60
10,140.00
89.98
106.73
6,639+25
4,051.52
1,576.47
20.00
0.42
20.00
89.00
10,315.00
89.98
118.98
6,639.30
3,983+68
1,737.43
7.00
0.00
7.00
90.00
10,490.00
89.98
106.73
6,639.35
3,915.85
1,898.39
7.00
0.00
-7.00
270.00
10,640.00
89.98
117.23
6,639.39
3,859.79
2,037.29
7.00
0.00
7.00
90.00
10,850.00
89.99
102.53
6,639.45
3,788.59
2,234.24
7.00
0.00
-7.00
270.00
101812016 2:08 26PM Page 2 COMPASS 5000.1 Build 74
ConocoPhillips rigs
ConocoPhillips Planning Report BAKER
HUGHES
Database:
EDM Alaska NSK Sandbox
Local Co-ordinate Reference:
Well 1 H-07
Company:
ConocoPhillips (Alaska) Inc. -Kupl
TVD Reference:
Mean Sea Level
Project:
Kuparuk River Unit
MD Reference:
1 H-07 @ 85.00usft (1 H-07)
Site:
Kuparuk 1H Pad
North Reference:
True
Well:
1H-07
Survey Calculation Method:
Minimum Curvature
Wellbore:
1 H-07ALl-01
Design:
1 H-07AL1-01_wp01
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)
(°h00ft)
(1)
(usft)
(usft)
9,570.00
90.13
352.82
6,641.24
3,741,10
1,209.49
1,209.49
0.00
0.00
5,983,683.78
550,745.15
TIP/KOP
9,600.00
90.34
358.82
6,641.11
3,771.00
1,207.31
1,207.31
20.00
88.00
5,983,713.67
550,742.77
9,700.00
91.00
18.81
6,639.93
3,869.32
1,222.55
1,222.55
20.00
88.03
5,983,812.07
550,757.36
9,770.00
91.39
32.81
6,638.47
3,932.16
1,252.94
1,252.94
20.00
88.26
5,983,875.11
550,787.33
Start 20 dls
9,800.00
91.01
38.80
6,637.84
3,956.48
1,270.48
1,270.48
20.00
93.60
5,983,899.54
550,804.70
9,900.00
89.67
58.75
6,637.24
4,022.05
1,345.31
1,345.31
20.00
93.73
5,983,965.60
550,879.09
9,940.00
89.14
66.73
6,637.66
4,040.35
1,380.84
1,380.84
20.00
93.84
5,983,984.13
550,914.49
3
10,000.00
89.37
78.73
6,638.44
4,058.12
1,438.02
1,438.02
20.00
89.00
5,984,002.28
550,971.56
10,100.00
89.80
98.73
6,639.18
4,060.32
1,537.49
1,537.49
20.00
88.84
5,984,005.14
551,071.00
10,140.00
89.98
106.73
6,639.25
4,051.52
1,576.47
1,576.47
20.00
88.70
5,983,996.59
551,110.03
End 20 dls,Start 7 dis
10,200.00
89.98
110.93
6,639.27
4,032.16
1,633.25
1,633.25
7.00
90.00
5,983,977.61
551,166.93
10,300.00
89.98
117.93
6,639.30
3,990.83
1,724.24
1,724.24
7.00
90.00
5,983,936.89
551,258.19
10,315.00
89.98
118.98
6.639.30
3,983.68
1,737.43
1,737.43
7.00
90.00
5,983,929.83
551,271.42
6
10,400.00
89.98
113.03
6,639.33
3,946.44
1.813.79
1,813.79
7.00
-90.00
5,983,893.09
551,348.02
10,490.00
89.98
106.73
6,639.35
3,915.65
1,898.39
1,898.39
7.00
-90.00
5,983,863.07
551.432.81
6
10,500.00
89.98
107.43
6,639.35
3,912,91
1,907.95
1,907.95
7.00
90.00
5,983,860.20
551,442.38
10,600.00
89.98
114.43
6.639.38
3,877.22
2,001.29
2,001.29
7.00
90.00
5,983,825.13
551,535.96
10,640.00
89.98
117.23
6,639.39
3,859.79
2,037.29
2,037.29
7.00
90.00
.5,983,807.94
551,572.07
7
10,700.00
89.98
113.03
6,639.41
3,834.32
2,091.60
2,091.60
7.00
-90.00
5,983,782.83
551,626.54
10,800.00
89.99
106.03
6,639.43
3,800.92
2,185.79
2,185.79
7.00
-90.00
5,983,750.05
551,720.94
10,850.00
89.99
102.53
6,639.45
3,788.59
2,234.24
2,234.24
7.00
-90.00
5,983,738.05
551,769.46
Planned TD at 10860.00
101812016 2:08:26PM Page 3 COMPASS 5000.1 Build 74
ConocoPhillips
ConocoPhillips (Alaska) Inc.
-Kup1
Kuparuk River Unit
Kuparuk 1 H Pad
1 H-07
1 H-07AL1-01
1 H-07AL1-01_wp01
Travelling Cylinder Report
08 October, 2016
F I I
CFO's
BAKER
HUGHES
Baker Hughes INTEQ F&A.■
ConocoPhillips Travelling Cylinder Report BAKER
HUGHES
Company:
ConocoPhillips (Alaska) Inc. -Kupl
Project:
Kuparuk River Unit
Reference Site:
Kuparuk 1 H Pad
Site Error:
0.00 usft
Reference Well:
1H-07
Well Error:
0.00 usft
Reference Wellbore
1H-07ALl-01
Reference Design:
1H-07AL1-01_wp01
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Output errors are at
Database:
Offset TVD Reference:
Well 1 H-07
1 H-07 @ 85.00usft (1 H-07)
1 H-07 @ 85.00usft (1 H-07)
True
Minimum Curvature
1.00 sigma
OAKEDMP2
Offset Datum
Reference
1H-07AL1-01_wp01
:ilter type:
GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
nterpolation Method:
MD Interval 25.00usft Error Model: ISCWSA
)epth Range:
9,570.00 to 10,850.00usft Scan Method: Tray. Cylinder North
Results Limited by:
Maximum center -center distance of 1,276.50 usft Error Surface: Elliptical Conic
Survey Tool Program
Date 10/8/2016
From
To
(usft)
(usft) Survey (Wellbore)
Tool Name
Description
100.00
7,800.00 1 H-07 (1 H-07)
BOSS -GYRO
Sperry -Sun BOSS gyro multishot
7,840.50
8,019.45 1H-07APB1 (11-1-07AP131)
MWD
MWD- Standard
8,019.45
8,540.00 1 H-07A_wpl0 (1 H-07A)
MWD
MWD - Standard
8,540.00
9,570.00 1H-07AL1_wp06(1H-07AL1)
MWD
MWD- Standard
9,570.00
10,850.00 1H-07AL1-01_wp01 (1H-07AL1-01)
MWD
MWD- Standard
Casing Points - -
Measured Vertical Casing Hole
Depth Depth Diameter Diameter
(usft) (usft) Name
10,850.00 6,724.45 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 1 H Pad
1 H-05 - 1 H-05 - 1 H-05
Out of range
1 H-07 - 1 H-07 - 1 H-07
10,850.00
8,300.00
70926
52.32
656.94
Pass - Major Risk
1 H-07 - 1 H-07A- 1 H-07A_wpl0
10,700.00
8,175.00
619.90
34.56
585.39
Pass - Major Risk
1 H-07 - 1 H-07ALl - 1 H-07AL1_wp06
9,575.00
9,575.00
0.06
0.39
-0.27
FAIL - Minor 1/10
1 H-07 - 1 H-07APB1 - 1 H-07APB1
10,700.00
8.175.00
627.02
41.06
585.97
Pass - Major Risk
1 H-07 - 1 H-07APB2 - 1 H-07APB2
10,700.00
8,156.00
625.97
41.17
584.85
Pass - Major Risk
1 H-14 - 1 H-14 - 1 H-14
9.900.00
8,425.00
409.98
259.12
178.43
Pass - Major Risk
Offset Design
Kuparuk 1 H Pad - 1 H-07 - 1 H-07 - 1 H-07
Offset Site Error: 0.00 usft
Survey Program:
100-BOSS-GYRO
Rule Assigned: Major Risk
Offset Well Error: 0.00 usft
Reference
Offset
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)
1")
(usft)
(usft)
(usft)
10,717.65
6,724.41
7,525.00
6,297.58
3.14
0.00
178.34
2,914.00
1,742.77
2-11116
1,072.46
43.07
1,034.24 Pass - Major Risk
10,720.67
6,724.41
7,550.00
6,318.62
3,15
0.00
178.92
2,922.47
1,753,28
2-11116
1,053.40
43.16
1,014.96 Pass - Major Risk
10,723.82
6.724.41
7,575.00
6,339.69
3A7
0.00
179.53
2,930.75
1,763,89
2-11116
1,034.70
43.25
996.03 Pass - Major Risk
10,727.07
6,724.41
7,600.00
6,360.78
3.18
0.00
-179.83
2,938.84
1,774,61
2-11116
1,016.37
43.34
977.47 Pass - Major Risk
10,730.44
6,724.41
7,625.00
6,381.89
3.20
a00
-179A7
2,946.78
1,785.41
2-11116
998.41
43.44
959.27 Pass - Major Risk
10,733.90
6,724.42
7,650.00
6,403.00
3.22
0.00
-178.47
2,954.58
1,796.28
2-11116
980.82
43.54
941.42 Pass - Major Risk
10,750.00
6,724.42
7,675.00
6,424.12
3.30
0.00
-178.63
2,962.27
1,807.24
2-11116
963.78
44.01
923.74 Pass - Major Risk
10,750.00
6,724.42
7,700.00
6,445.24
3.30
0.00
-177.62
2,969.83
1,818.27
2-11116
946.89
44.01
906.69 Pass - Major Risk
10,750.00
6,724.42
7,725.00
6,466.38
3.30
0.00
-176.57
2,977.32
1,829.32
2-11/16
930.42
44.01
890.06 Pass - Major Risk
10,750.00
6,724.42
7,750.00
6,487.54
3.30
0.00
-175.49
2,984.80
1,840.33
2-11/16
914.34
44.01
873.83 Pass - Major Risk
CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation
101a12016 1:57:49PM Page 2 COMPASS 5000.1 Build 74
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TRANSMITTAL LETTER CHECKLIST
WELL NAME: KR tom, 4 - D4 ALi - of
PTD: alb - /3-C3
Development Service _ Exploratory _ Stratigraphic Test _ Non -Conventional
FIELD: 4 i POOL:
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
No. Q14 — 0 t I , API No. 50-W? - 0 ? S - 01 - ob .
(If last two digits
1woductioir should continue to be reported as a function of the original
in API number are
API number stated above.
between 60-69)
n
In rdance 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
PTD#:2161300 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type
Well Name: KUPARUK RIV UNIT 11-1-07AL1-01 Program SER Well bore seg
SER / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal;
Administration 17
Nonconven. gas conforms to AS31.05.030(j.1.A),0.2.A-D)
NA
1
Permit fee attached
NA
2
Lease number appropriate
Yes
ADL0025639, entire wellbore
3
Unique well name and number
Yes
KRU 1H-07AL1-01
4
Well located in a defined pool
Yes
KUPARUK RIVER, KUPARUK RIV OIL - 490100, governed by Conservation Order No. 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 10/12/2016
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 2C-Kuparuk River Unit
15
All wells within 1 /4 mile area of review identified (For service well only)
Yes
KRU 1 H-05, 1 H-14, 1 H-07
16
Pre -produced injector: duration of pre -production less than 3 months (For service well only)
Yes
18
Conductor string provided
NA
Engineering
19
Surface casing protects all known USDWs
NA
20
CMT vol adequate to circulate on conductor & surf csg
NA
21
CMT vol adequate to tie-in long string to surf csg
NA
22
CMT will cover all known productive horizons
No
23
Casing designs adequate for C, T, B & permafrost
Yes
24
Adequate tankage or reserve pit
Yes
25
If a re -drill, has a 10-403 for abandonment been approved
NA
26
Adequate wellbore separation proposed
Yes
27
If diverter required, does it meet regulations
NA
Appr Date
28
Drilling fluid program schematic & equip list adequate
Yes
VTL 10/12/2016
29
BOPEs, do they meet regulation
Yes
30
BOPE press rating appropriate; test to (put psig in comments)
Yes
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
34
Mechanical condition of wells within AOR verified (For service well only)
Yes
35
Permit can be issued w/o hydrogen sulfide measures
No
Geology
36
Data presented on potential overpressure zones
Yes
Appr Date
37
Seismic analysis of shallow gas zones
NA
PKB 10/12/2016
38
Seabed condition survey (if off -shore)
NA
39
Contact name/phone for weekly progress reports [exploratory only]
NA
Conductor set in KRU 1 H-07
Surface casing set in KRU 1 H-07
Surface casing set and fully cemented
Productive interval will be completed with uncemented slotted liner
Rig has steel tanks; all waste to approved disposal wells
Anti -collision analysis complete; no major risk failures
Max formation pressure is 3721 psig(10.9 ppg EMW); will drill w/ 9.6 ppg EMW and maintain overbal w/ MPD
MPSP is 3065 psig; will test BOPs to 3500 psig
H2S measures required
AOR complete; mechanical condition verified
Wells on 1H-Pad are H2S-bearing. 112S measures required.
Maximum potential reservoir pressure is 10.9 ppg EMW; will be drilled using 9.6 ppg mud and MPD technique.
Onshore service well to be drilled.
Geologic Engineering Public
Date: Date Date
Commissioner: Co fission � /� Com 'ssi ner I
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