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HomeMy WebLinkAbout218-088Winston, Hugh E (CED)
From: Winston, Hugh E (CED)
Sent: Thursday, September 10, 2020 4:13 PM
To: william.r.long@cop.com
Cc: Loepp, Victoria T (CED)
Subject: KRU 31-01 L1-01 Permit Expired
Hi William,
The permit to drill for well KRU 31-01L1-01 which was issued to CPAI on August 301h, 2018 has expired under regulation
20 AAC 25.005 (�}. The permit has been marked expired in the well history file and in the AOGCC database.
Please let me know if you have any questions. Thanks
Huey Winston
Statistical Technician
Alaska Oil and Gas Conservation Commission
hugh..winston «alaska_.goy
907-793-1241
THE STATE
wo M�0'1'
GOVERNOR BILL WALKER
William R. Long
Staff CTD Engineer
ConocoPhillips Alaska, Inc.
PO Box 100360
Anchorage, AK 99510-0360
Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 3I-01 L 1-01
ConocoPhillips Alaska, Inc.
Permit to Drill Number: 218-088
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.claska.gov
Surface Location: 344' FSL, 179' FWL, SEC. 31, T13N, R9E, UM
Bottomhole Location: 404' FNL, 2069' FWL, SEC. 31, T13N, R9E, UM
Dear Mr. Long:
Enclosed is the approved application for the permit to redrill the above referenced development
well.
The permit is for a new wellbore segment of existing well Permit 185-307, API 50-029-21514-00-
00. Production should continue to be reported as a function of the original API number stated
above.
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.
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,
Hollis S. French
Chair
A J
DATED this 5 �' day of August, 2018.
STATE OF ALASKA
AL. :A OIL AND GAS CONSERVATION COMMA ON
PERMIT TO DRILL
RECEIVED
20 AAC 25.005
JUL 2 0 2018
1 a. Type of Work:
1 b. Proposed Well Class: Exploratory -Gas ❑ Service - WAG ❑ Service - Disp ❑
1 c. Spectf�jf y0N for:
Drill ❑ Lateral ❑✓
Stratigraphic Test ❑ Development - Oil ❑ Service - Winj ❑ Single Zone ❑
Coalbed a y tes ❑
Redrill ❑ Reentry ❑
Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑
Geothermal ❑ Shale Gas ❑
2. Operator Name:
5. Bond: Blanket ❑✓ • Single Well ❑
11. Well Name and Number:
ConocoPhillips Alaska, Inc.
Bond No. 5952180
Kuparuk Riv Unit 31-01L1-01
3. Address:
6. Proposed Depth: -71- r—> ' (r3 j
12. Field/Pool(s):
PO Box 100360 Anchorage, AK 99510-0360
MD: 12,250 ' TVEfS , 6290
Kuparuk River
Kuparuk River Oil .
4a. Location of Well (Governmental Section):
7. Property Designation: y'h /
�y'7
Surface: 344' FSL, 179' FWL, Sec. 31, T13N, R9E, UM
ADL 25521 Z* ��
Top of Productive Horizon:
8. DNR Approval Number:
13. Approximate Spud ate:
1213' FNL, 1973' FEL, Sec. 31, T13N, R9E, UM
LO/NS 83-130
8/ 018 1116115
Total Depth:
9. Acres in Property:
14. Distance t6 Nearest Property: VT
404' FNL, 2069' FWL, Sec. 31, T13, R9E, UM
2555
18,740'
4b. Location of Well (State Base Plane Coordinates - NAD 27):
10. KB Elevation above MSL (ft): 71
15. Distance to Nearest Well Open
Surface: x- 508056 • y- 6007286 ' Zone- 4
GL / BF Elevation above MSL (ft): 40
to Same Pool: 718- (31-03)
16. Deviated wells: Kickoff depth: 10,650 feet •
17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 95 degrees
Downhole: 5456 ' Surface: 4829
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"
2-3/8"
4.6#
L-80
ST-L
3050
9200.
12,250 .
6
Un-Cemented
fp 35�.
3777
t�,i
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):
9030
6542
N/A
8919
6460
8782
Casing
Length
Size
Cement Volume
MD
TVD
Conductor/Structural
73'
16"
274 Sx CS II
104'
104'
Surface
4315'
9-5/8"
1650 Sx AS III & 320 Sx Class G
4346'
3304'
Intermediate
Production
8986'
7"
300 Sx Class G & 175 Sx AS 1
9010,
6528'
Liner
Perforation Depth MD (ft):
Perforation Depth TVD (ft):
8734-8760, 8770-8798
6326-6345, 6352-6373
Hydraulic Fracture planned? Yes❑ No 0
20. Attachments: Property Plat ❑ BOP Sketch
Drilling Program
❑
❑
Time v. Depth Plot
Shallow Hazard Analysis
❑
Diverter Sketch
Seabed Report
Drilling Fluid Program
20 AAC 25.050 requirements❑
21. Verbal Approval: Commission Representative: Date
22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval. Contact Name: William R. Long
Authorized Name: William R. Long Contact Email: William. R.Lon COP.com
Authorized Title: Staff CTD Engineer Contact Phone: 907-263-4372
JJ
Authorized Signature: Date: —
Commission Use Only
Permit to Drill JU
'��
A� PI Number: /
L�kNumber: ' �� ` ���
Permit Approva
See cover letter for other
�/�
50-&, y
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:
Samples req'd: Yes ❑ No� Mud log req'd: Yes ❑ No
Other: �(j�J fCs -/0 4 9 GC
� 5 J
Z -5"- Srmeasures: Yes [ /No�❑/ Directional svy req'd: Yesv No❑
SZSpgc r�q excn req'd: Yes ❑ No (_j✓ Inclination -only svy req'd: Yes ❑ No
G�a�ns�, p a 7L Post initial injection MIT req'd: Yes ❑ No
A � y `p co i i-7 t a lah y fh c �b � rrh t /.,r tr r- -- I -
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
rTL ci Submit Form and
Form 10-401 Revised 5/2017 This permit is valid for 24 n f o o p oval per 20 AAC 25.005(g) Attachments in Duplicate
sConocoPhillip
Alaska
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
July 20, 2018
Commissioner - State of Alaska
Alaska Oil & Gas Conservation Commission
333 West 7th Avenue Suite 100
Anchorage, Alaska 99501
Dear Commissioner:
ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill four laterals out of the KRU 31-01
(PTD# 185-307) using the coiled tubing drilling rig, Nabors CDR3-AC.
CTD operations are scheduled to begin in August 2018. The objective will be to drill sig laterals, KRU 31-01L1,
31-011_1-01, 31-01L1-02, 31-011_1-03, 31-01L1-04, and 31-01L1-05, targeting the KuparukA-sand interval.
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
31-01 L1, 31-01 L1-01, 31-01 L1-02, 31-01 L1-03, 31-01 L1-04, and 31-01 L1-05
— Detailed Summary of Operations
— Directional Plans for 31-01L1, 31-01L1-01, 31-01L1-02, 31-01L1-03, 31-011_1-04, and 31-01L1-05
— Current wellbore schematic
— Proposed CTD schematic
If you have any questions or require additional information, please contact me at 907-263-4372.
Sincerely,
William R. Long
Coiled Tubing Drilling Engineer
ConocoPhillips Alaska
Kuparuk CTD Laterals
31-01L1, 31-01L1-01, 31-01L1-02, 31-01L1-03, 31-01L1-04, and 31-01L1-05
Application for Permit to Drill Document
1.
Well Name and Classification........................................................................................................ 2
(Requirements of 20 AAC 25.005(o and 20 AAC 25.005(b))..................-..................... .......................................................................... 2
2.
Location Summary.......................................................................................................................... 2
(Requirements of 20 AAC 25.005(c)(2)).......................... -... .................................................................... ....... ........................................ 2
3.
Blowout Prevention Equipment Information................................................................................. 2
(Requirements of 20 AAC 25.005(c)(3))............................................. ....... ........................................................................................... - 2
4.
Drilling Hazards Information and Reservoir Pressure.................................................................. 2
(Requirements of 20 AAC 25.005(c)(4))........... ..................... ............... .... ............... ........................................... -.................................. 2
5.
Procedure for Conducting Formation Integrity tests................................................................... 2
(Requirements of 20 AAC 25.005(c)(5))..................................................... ... ................... ........ ............................................................. 2
6.
Casing and Cementing Program.................................................................................................... 3
(Requirements of 20 AAC 25.005(c)(6)).................................................................................................................................................. 3
7.
Diverter System Information.......................................................................................................... 3
(Requirements of 20 AAC 25.005 c 7.................................................... 3
8.
Drilling Fluids Program.................................................................................................................. 3
(Requirements of 20 AAC 25.005 c 8.................................................................................... 3
9.
Abnormally Pressured Formation Information............................................................................. 4
(Requirements of 20 AAC 25.005 c 9...................................................... 4
10.
Seismic Analysis............................................................................................................................. 4
(Requirements of 20 AAC 25.005(c)(10))................................................................................................................................................ 4
11.
Seabed Condition Analysis............................................................................................................4
(Requirements of 20 AAC 25.005 c 11...................................................... ........................................................... ............................. 4
12.
Evidence of Bonding...................................................................................................................... 4
(Requirements of 20 AAC 25.005(c)(12))................................................................................................................................................ 4
13.
Proposed Drilling Program.............................................................................................................4
(Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 4
Summaryof Operations...................................................................................................................................................4
LinerRunning...................................................................................................................................................................6
14.
Disposal of Drilling Mud and Cuttings.......................................................................................... 6
(Requirements of 20 AAC 25.005(c)(14))................................................................................................................................................ 6
15.
Directional Plans for Intentionally Deviated Wells....................................................................... 7
(Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 7
16.
Attachments.................................................................................................................................... 7
Attachment 1: Directional Plans for 31-01 L1, 31-01 L1-01, 31-01 L1-02, 31-01 L1-03, 31-01 L1-04, and 31-01 L1-05 laterals.
......................................................................................................................................................................................... 7
Attachment 2: Current Well Schematic for 31-01.............................................................................................................7
Attachment 3: Proposed Well Schematic for 31-01 L1, 31-01 L1-01, 31-01 L1-02, 31-01 L1-03, 31-01 L1-04, and 31-01 L1-05
laterals.............................................................................................................................................................................7
Page 1 of 7 June 27, 2018
PTD Application: 31-01L1, 31-01L1-01, 31-01L1-02, 31-01L1-03, 31-01L1-04, and 31-01L1-05
1. Well Name and Classification
(Requirements of 20 AAC 25.005(o and 20 AAC 25.005(b))
The proposed laterals described in this document are 31-01 L1, 31-01 L1-01, 31-01 L1-02, 31-01 L1-03, 31-01 L1-04,
and 31-01 L1-05. All laterals will be classified as "Development -Oil" 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 forms for surface
and subsurface coordinates of each of the laterals.
3. Blowout Prevention Equipment Information
(Requirements of 20 AAC 25.005 (c)(3))
Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR3-AC.
BOP equipment is as required per 20 AAC 25.036 for thru-tubing drilling operations.
— Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 4900 psi. Using the
maximum formation pressure in the area of 5456 psi at the datum in 3N-05 (i.e. 16.7 ppg EMW), the
maximum potential surface pressure in 31-01, assuming a gas gradient of 0.1 psi/ft, would be 4829 psi.
See the "Drilling Hazards Information and Reservoir Pressure" section for more details.
— The annular preventer will be tested to 250 psi and 2,500 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 31-01 was measured to be 3943 psi at the datum (12.1 ppg EMW) on 5/3/2018.
The maximum downhole pressure in the 31-01 vicinity is the 3N-05 at 5456 psi at the datum or 16.7 ppg EMW.
Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b))
No specific gas zones will be drilled; gas injection has been performed in this area, so there is a chance of
encountering gas while drilling the 31-01 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 31-01 laterals will be shale instability across faults. Managed
pressure drilling (MPD) will be used to reduce the risk of shale instability associated with fault crossings.
5. Procedure for Conducting Formation Integrity tests
(Requirements of 20 AAC 25.005(c)(5))
The 31-01 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 June 27, 2018
PTD Application: 31-01L1, 31-01L1-01, 31-01L1-02, 31-01L1-03, 31-01L1-04, and 31-01L1-05
6. Casing and Cementing Program
(Requirements of 20 AAC 25.005(c)(6))
New Completion Details
Lateral Name
Liner Top
Liner Btm
Liner Top
Liner Btm
Liner Details
MD
MD
TVDSS
TVDSS
31-01 L1
10,650
11,900
6318
6225
2%", 4.7#, L-80, ST-L slotted liner;
aluminum billet on to
31-01L1-01
9200
12,250
6281
6290
2%", 4.7#, L-80, ST-L slotted liner. -
aluminum billet on to
31-01Ll-02
9085
11,925
6282
6212
2%", 4.7#, L-80, ST-L slotted liner;
aluminum billet on to
31-01Ll-03
10,100
12,000
6225
6204
2%", 4.7#, L-80, ST-L slotted liner;
aluminum billet on to
31-01 L1-04
9300
12,000
6258
6232
2%", 4.7#, L-80, ST-L slotted liner;
aluminum billet on to
31-01 L1-05
8725
12,050
6248
6188
2%", 4.7#, L-80, ST-L slotted liner;
deployment sleeve on to
Existing Casing/Liner Information
Category
OD
Weight
Connection
Top MD
Btm MD
Top
TVD
Btm
TVD
Burst
psi
Collapse
psi
Conductor
16"
62.5
JH-40
Welded
Surface
104
Surface
104
1640
670
Surface
9-5/8"
36
BTC
Surface
4346
Surface
3305
3520
2020
Production
7"
26
BTC
Surface
9010
Surface
6528
4980
4320
Tubing
3-1/2"
9.3
L-80
EUE8rd Mod
Surface
8747
Surface
6336
10,160
10,540
7. Diverter System Information
(Requirements of 20 AAC 25.005(c)(7))
Nabors CDR3-AC will be operating under 20 AAC 25.036, for thru-tubing drilling operations. Therefore, a
diverter system is not required.
8. Drilling Fluids Program
(Requirements of 20 AAC 25.005(c)(8))
Diagram of Drilling System
A diagram of the Nabors CDR3-AC mud system is on file with the Commission.
Description of Drilling Fluid System
— Window milling operations: Water based Power-Vis milling fluid (8.6 ppg)
— Drilling operations: Water based Power -Pro drilling mud (8.6 ppg). This mud weight may not
hydrostatically overbalance the reservoir pressure, overbalanced conditions will be maintained using
MPD practices described below.
— Completion operations: The 31-01 contains a downhole deployment valve allowing deployment of tool
strings and liner without pumping kill weight fluid. If the valve does not hold, BHA's will be deployed
using standard pressure deployments and the well will be loaded with 12.1 ppg NaBr completion fluid
in order to provide formation over -balance and maintain wellbore stability while running completions.
If higher formation pressures are encountered the completion brine will be weighted up with sodium
bromide or potassium formate.
Page 3 of 7 June 27, 2018
PTD Application: 31-01L1, 31-01L1-01, 31-01L1-02, 31-01L1-03, 31-01L1-04, and 31-01L1-05
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 31-01 laterals we will target a constant BHP of 12.1 EMW at the window. The constant BHP target will be
adjusted through choke pressure and/or mud weight increases to maintain overbalanced conditions if increased
reservoir pressure is encountered. Additional choke pressure or increased mud weight may also be employed
for improved borehole stability. Any change of circulating friction pressure due to change in pump rates or change
in depth of circulation will be offset with back pressure adjustments.
Pressure at the 31-01 Window (8728' MD, 6322' TVD) Using MPD
Pumps On 1.8 b m
Pumps Off
Formation Pressure 12.1
3978 psi
3978 psi
Mud Hydrostatic 8.6
2827 psi
2827 psi
Annular friction i.e. ECD, 0.080 si/ft
698 psi
0 psi
Mud + ECD Combined
no chokepressure)
3525 psi
underbalanced —453psi)
2827 psi
underbalanced —1151psi)
Target BHP at Window 12.1
3978 psi
3978 psi
Choke Pressure Required to Maintain
Target BHP
453 psi
1151 psi
9. Abnormally Pressured Formation Information
(Requirements of 20 AAC 25.005(c)(9))
N/A - Application is not for an exploratory or stratigraphic test well.
10. Seismic Analysis
(Requirements of 20 AAC 25.005(c)(10))
N/A - Application is not for an exploratory or stratigraphic test well.
11. Seabed Condition Analysis
(Requirements of 20 AAC 25.005(c)(11))
N/A - Application is for a land based well.
12. Evidence of Bonding
(Requirements of 20 AAC 25.005(c)(12))
Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission.
13. Proposed Drilling Program
(Requirements of 20 AAC 25.005(c)(13))
Summary of Operations
Background
KRU well 3I-01 is a Kuparuk producer equipped with 3-1/2" tubing and 7" production casing. The CTD
sidetrack will utilize laterals to target the Kuparuk sands to the west and north of the existing 31-01
wellbore. The laterals will increase throughput and recovery from a potentially sheltered corner of a fault
block.
A recent rig workover installed tandem wedges to facilitate cutting a window with CTD. Prior to CTD
operations E-line will set an inner wedge in the tandem wedge. CDR3-AC will mill a window in the tubing
and casing using the tandem wedge like a whipstock.
Page 4 of 7 June 27, 2018
PTD Application: 31-01L1, 31-01L1-01, 31-01L1-02, 31-011-1-03, 31-01L1-04, and 31-01Ll-05
Pre-CTD Work
1. RU Slickline: Pull SOV and set GLVs.
2. RU E-line: Set inner wedge.
3. Prep site for Nabors CDR3-AC.
Ria Work
1. MIRU Nabors CDR3-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test.
3I-OIL1 Lateral (A sand - West)
a. Mill 2.80" window at 8728' MD.
b. Drill 3" bi-center lateral to TD of 11,900' MD.
c. Run 2%" slotted liner with an aluminum billet from TD up to 10,650' MD.
3. 3I-OIL1-01 Lateral (A sand- West)
a. Kickoff of the aluminum billet at 10,650' MD.
b. Drill 3" bi-center lateral to TD of 12,250' MD. -
c. Run 2%" slotted liner with aluminum billet from TD up to 9200' MD.
4. 3I-OILI-02 Lateral (A sand - West)
a. Kick off of the aluminum billet at 9200' MD.
b. Drill 3" bi-center lateral to TD of 11,925' MD.
c. Run 2%" slotted liner with aluminum billet from TD up to 9085' MD.
5. 3I-01L1-03 Lateral (A sand -North)
a. Kick off of the aluminum billet at 9085' MD.
b. Drill 3" bi-center lateral to TD of 12,000' MD.
c. Run 2%" slotted liner with aluminum billet from TD up to 10,100' MD.
3I-01L1-04 Lateral (A sand - North)
a. Kickoff of the aluminum billet at 10,100' MD.
b. Drill 3" bi-center lateral to TD of 12,000' MD.
c. Run 2%" slotted liner with aluminum billet from TD up to 9300' MD.
7. 3I-OIL1-03 Lateral (A sand -West)
a. Kickoff of the aluminum billet at 9300' MD.
b. Drill 3" bi-center lateral to TD of 12,050' MD.
c. Run 2%" slotted liner with deployment sleeve from TD up to 8725' MD.
8. Freeze protect, ND BOPE, and RDMO Nabors CDR3-AC.
Post -Rig Work
1. Return to production.
Page 5 of 7 June 27, 2018
PTD Application: 31-0111-1, 31-0111-1-01, 31-0111-1-02, 31-0111-1-03, 31-01L1-04, and 31-01L1-05
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 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 31-01 well has a deployment valve installed. It will serve to deploy liners into the newly drilled laterals.
If the valve fails, the 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 23/" 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).
Page 6 of 7 June 27, 2018
PTD Application: 31-01L1, 31-01L1-01, 31-01L1-02, 31-01L1-03, 31-01L1-04, and 31-01L1-05
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 Plans
- 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 ft
31-01 L1
18,980
31-01L1-01
18,740
31-01 L1-02
18,990
31-01L1-03
20,930
31-01L1-04
20,815
31-01L1-05
20,845
- Distance to Nearest Well within Pool
16. Attachments
Attachment 1:
laterals.
Lateral Name
Distance ft
Well
31-01 L1
513
31-03
31-01 L1-01
718
31-03
31-01L1-02
513
31-03
31-01L1-03
159
3M-04
31-01 L1-04
159
3M-04
31-01Ll-05
159
3M-04
Directional Plans for31-01L1, 31-01L1-01, 31-01L1-02, 31-01L1-03, 31-01L1-04, and 31-01L1-05
Attachment 2: Current Well Schematic for 31-01..
Attachment 3: Proposed Well Schematic for 31-01 L 1, 31-01 L 1-01, 31-01 L 1-02, 31-01 L 1-03, 31-01 L 1-04, and 31-
01 L 1-05 laterals.
Page 7 of 7 June 27, 2018
ConocoPhillips
ConocoPhillips (Alaska) Inc. -Kup2
Kuparuk River Unit
Kuparuk 31 Pad
31-01
31-01 L1-01
Plan: 31-01 L1-01_wp02
Standard Planning Report
19 July, 2018
B ER
UGHES
a GE company
ConocoPhillips
Database:
EDT Alaska Sandbox
Company:
ConocoPhillips (Alaska) Inc. -Kup2
Project:
Kuparuk River Unit
Site:
Kuparuk 31 Pad
Well:
31-01
Well bore:
31-01 L 1-01
Design:
31-01 L 1-01 _wp02
ConocoPhillips
Planning Report
Local Co-ordinate Reference:
Well 31-01
TVD Reference:
Mean Sea Level
MD Reference:
31-01 @ 71.00usft (31-01)
North Reference:
True
Survey Calculation Method:
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
BA ER
F�UGHES
a GE company
---------------------- --------
Site Kuparuk 31 Pad `
Site Position: Northing: 6,007,285.50 usft Latitude: 70° 25' 52.059 N
From: Map Easting: 508,056.44 usft Longitude: 149° 56' 3.597 W
Position Uncertainty: 0.00 usft Slot Radius: 0.000 in Grid Convergence: 0.06 °
Well 31-01
Well Position +N/S
0.00 usft Northing:
6,007,285.50 usft
Latitude: 70° 25' 52.059 N
+E/-W
0.00 usft Easting:
508,056.44 usft
Longitude: 149° 56' 3.597 W
Position Uncertainty
I
0.00 usft Wellhead Elevation:
usft
Ground Level: 0.00 usft
Wellbore 31-01L1-01
Magnetics Model Name Sample Date Declination Dip Angle Field Strength
(°) (°) (nT)
BGGM2018 9/1/2018 16.95 80.93 57,444
Design-31-011-1-01_wp02
Audit Notes:
Version: Phase: PLAN Tie On Depth: 10,650.00
Vertical Section: Depth From (TVD) +N/-S +El-W Direction
(usft) (usft) (usft) (°)
0.00 0.00 0.00 300.00
Plan Sections
Measured
TVD Below
Dogleg
Build
Turn
Depth
Inclination
Azimuth
System
+Nl-S
+El-W
Rate
Rate
Rate
TFO
(usft)
(°)
(I
(usft)
(usft)
(usft)
(°/100ft)
(°/100ft)
(°/100ft)
(°)
10,650.00
88.59
256.52
6,317.55
3,722.95
3,110.44
0.00
0.00
0.00
0.00
10,750.00
93.09
261.89
6,316.09
3,704.24
3,012.29
7.00
4.50
5.36
50.00
10,950.00
93.00
275.91
6,305.41
3,700.40
2,813.11
7.00
-0.05
7.01
90.00
11,100.00
91.14
286.25
6,299.99
3,729.17
2,666.20
7.00
-1.24
6.89
100.00
11,300.00
94.69
299.81
6,289.77
3,807.07
2,482.83
7.00
1.78
6.78
75.00
11,475.00
89.46
310.90
6,283.41
3,908.09
2,340.47
7.00
-2.99
6.34
115.00
11,725.00
89.49
328.40
6,285.72
4,097.86
2,179.23
7.00
0.01
7.00
90.00
11,900.00
89.50
316.15
6,287.28
4,236.00
2,072.35
7.00
0.01
-7.00
270.00
12,250.00
89.54
340.65
6,290.25
4,531.81
1,890.34
7.00
0.01
7.00
90.00
Target
7/19/2018 12:52:11PM Page 2 COMPASS 5000.14 Build 85
ConocoPhillips BA_ j{ER
ConocoPhillips Planning Report 11 IGHES
BAT
GE company
Database:
EDT Alaska Sandbox
Local Co-ordinate Reference:
Well 31-01
Company:
ConocoPhillips
(Alaska)
Inc. -Kup2
TVD Reference:
Mean
Sea Level
Project:
Kuparuk River Unit
MD Reference:
31-01
@ 71.00usft (31-01)
Site:
Kuparuk 31 Pad
North Reference:
True
Well:
31-01
Survey Calculation Method:
Minimum Curvature
Wellbore:
31-01L1-01
Design:
31-01 Li-01_wp02
Planned Survey
Measured
TVD Below
Vertical
Dogleg
Toolface
Map
Map
Depth Inclination
Azimuth
System
+N/-S
+E/-W
Section
Rate
Azimuth
Northing
Easting
(usft)
(°)
(°)
(usft)
(usft)
(usft)
(usft)
(/100ft)
(°)
(usft)
(usft)
10,650.00 .
88.59
256.52
6,317.55
3,722.95
3,110.44
-832.25
0.00
0.00
6,011,011.44
511,162.55
TIP/KOP
10,700.00
90.84
259.20
6,317.80
3,712.44
3,061.57
-795.18
7.00
50.00
6,011,000.88
511,113.69
10,750.00
93.09
261.89
6,316.09
3,704.24
3,012.29
-756.60
7.00
49.99
6,010,992.62
511,064.42
Start 7 dis
10,800.00
93.08
265.39
6,313.39
3,698.71
2,962.67
-716.40
7.00
90.00
6,010,987.03
511,014.82
10,900.00
93.04
272.40
6,308.05
3,696.79
2,862.90
-630.95
7.00
90.19
6,010,985.01
510,915.06
10,950.00
93.00
275.91
6,305.41
3,700.40
2,813.11
-586.02
7.00
90.56
6,010,988.57
510,865.27
3
11,000.00
92.39
279.36
6,303.06
3,707.03
2,763.61
-539.84
7.00
100.00
6,010,995.15
510,815.77
11,100.00
91.14
286.25
6,299.99
3,729.17
2,666.20
-444.42
7.00
100.16
6,011,017.17
510,718.35
4
11,200.00
92.94
293.02
6,296.43
3,762.72
2,572.14
-346.17
7.00
75.00
6,011,050.62
510,624.25
11,300.00
94.69
299.81
6,289.77
3,807.07
2,482.83
-246.65
7.00
75.24
6,011,094.87
510,534.91
5
11,400.00
91.71
306.15
6,284.18
3,861.40
2,399.13
-147.01
7.00
115.00
6,011,149.10
510,451.16
11,475.00
89.46
310.90
6,283.41
3,908.09
2,340.47
-72.87
7.00
115.36
6,011,195.73
510,392.46
6
11,500.00
89.46
312.65
6,283.64
3,924.74
2,321.83
-48.39
7.00
90.00
6,011,212.36
510,373.80
11,600.00
89.47
319.65
6,284.58
3,996.81
2,252.59
47.60
7.00
89.98
6,011,284.34
510,304.49
11,700.00
89.48
326.65
6,285.50
4,076.77
2,192.66
139.49
7.00
89.92
6,011,364.23
510,244.47
11,725.00
89.49
328.40
6,285.72
4,097.86
2,179.23
161.66
7.00
89.85
6,011,385.30
510,231.03
7
11,800.00
89.49
323.15
6,286.39
4,159.84
2,137.06
229.17
7.00
-90.00
6,011,447.23
510,188.79
11,900.00
89.50
316.15
6,287.28
4,236.00
2,072.35
323.29
7.00
-89.95
6,011,523.31
510,124.01
8
12,000.00
89.50
323.15
6,288.15
4,312.15
2,007.64
417.41
7.00
90.00
6,011,599.39
510,059.23
12,100.00
89.51
330.15
6,289.01
4,395.63
1,952.70
506.73
7.00
89.94
6,011,682.79
510,004.20
12,200.00
89.53
337.15
6,289.85
4,485.17
1,908.34
589.92
7.00
89.88
6,011,772.28
509,959.74
12,250.00
89.54
340.65
6,290.25 -
4,531.81
1,890.34
628.83
7.00
89.82
6,011,818.90
509,941.69
Planned TD at 12250.00
711912018 12:52.11PM Page 3 COMPASS 5000.14 Build 85
ConocoPhillips
BAT
BA_ KER
ConocoPhillips
Planning Report
IGHES
GE company
Database: EDT Alaska Sandbox
Local Co-ordinate Reference:
Well 31-01
Company: ConocoPhillips (Alaska) Inc. -Kup2
TVD Reference:
Mean Sea Level
Project: Kuparuk River Unit
MD Reference:
31-01 @ 71.00usft (31-01)
Site: Kuparuk 31 Pad
North Reference:
True
Well: 31-01
Survey Calculation Method:
Minimum Curvature
Wellbore: 31-01 Li-01
Design: 31-01 L1-01_wp02
Targets
Target Name
hit/miss target Dip Angle Dip Dir. TVD
+N/-S +E/-W Northing
Easting
Shape (°) (°) (usft)
(usft) (usft) (usft)
(usft) Latitude
Longitude
31-01L1 Fault4 0.00 0.00 6,306.00
2,170.491,142,991.78 6.010,690.00
1,650,931.00 70° 11' 58.128 N
140° 41' 33.291 W
- plan misses target center by 1139882.40usft at 10650.00usft MD (6317.55 TVD, 3722.95 N, 3110.44 E)
- Polygon
Point 1 6,306.00
0.00 0.00 6,010,690.00
1,650,931.00
Point 2 6,306.00
1.00 1.00 6,010,691.00
1,650,932.00
31-011-1-01_T01 0.00 0.00 6,307.00
2,218.501,142,984.84 6,010,738.00
1,650,924.00 70° 11' 58.604 N
140° 41' 33.279 W
- plan misses target center by 1139875.38usft at 10650.00usft MD (6317.55 TVD, 3722.95 N, 3110.44 E)
- Point
31-01L1-01_T03 0.00 0.00
6,290.00
3,051.61 1,142,035.64
6,011,570.00
1,649,974.00
700 12' 8.102 N 1400 41' 56.809 W
- plan misses target center by 1138925.39usft
at 10650.00usft
MD (6317.55 TVD, 3722.95 N, 3110.44 E)
- Point
31-01L1_Fault2_M 0.00 0.00
0.00
2,347.391,144,024.08
6,010,868.00
1,651,963.00
70° 11' 58.310 N 140° 41' 2.957 W
plan misses target center by 1140931.96usft
at 10650.00usft
MD (6317.55 TVD, 3722.95 N, 3110.44 E)
Rectangle (sides W1.00 H1,000.00 D0.00)
31-01 CTD Polygon Nortl 0.00 0.00
0.00
1,925.81 1,144,520.67
6.010,447.00
1,652,460.00
70° 11' 53.479 N 140° 40' 50.588 W
- plan misses target center by 1141429.13usft
at 10650.00usft
MD (6317.55 TVD, 3722.95 N, 3110.44 E)
- Polygon
Point 1
0.00
0.00 0.00
6,010,447.00
1,652,460.00
Point
0.00
934.28-183.06
6,011,380.99
1,652,275.95
Point 3
0.00
1,493.14 8.54
6,011,940.00
1,652,466.93
Point
0.00
3,219.29 34.31
6,013,666.00
1,652,490.83
Point 5
0.00
3,030.77 517.17
6,013,478.02
1,652,973.85
Point
0.00
1,541.74 407.63
6,011,989.03
1,652,865.92
Point 7
0.00
759.88 195.80
6,011,207.02
1,652,654.96
Point 8
0.00
96.56 438.14
6,010,544.02
1,652,897.99
Point 9
0.00
-181.13 107.82
6,010,266.00
1,652,568.00
Point 10
0.00
0.00 0.00
6,010,447.00
1,652,460.00
31-01 CTD Polygon Nortl 0.00 0.00
0.00
1,758.681,144,621.50
6,010,280.00
1,652,561.00
70° 11' 51.707 N 140° 40' 48.435 W
- plan misses target center by 1141530.23usft at 10650.00usft
MD (6317.55 TVD, 3722.95 N, 3110.44 E)
- Polygon
Point 1
0.00
0.00 0.00
6,010,280.00
1,652,561.00
Point
0.00
124.72 281.16
6,010,405.01
1,652,842.00
Point
0.00
451.71 326.50
6,010,732.02
1,652,886.98
Point
0.00
799.27-180.20
6,011,079.00
1,652,379.96
Point 5
0.00
595.76-1,655.55
6,010,873.91
1,650,904.97
Point
0.00
1,672.96-2,710.55
6,011,949.86
1,649,848.92
Point
0.00
1,106.98-2,787.14
6,011,383.86
1,649,772.94
Point
0.00
224.03-1,954.97
6,010,501.90
1,650,605.98
Point 9
0.00
417.38-329.60
6,010,696.98
1,652,230.98
Point 10
0.00
295.07 -34.70
6,010,575.00
1,652,525.98
Point 11
0.00
0.00 0.00
6,010,280.00
1,652,561.00
31-0lL1-03_Fault5 0.00 0.00
6,246.00
2,665.881,144,525.47
6,011,187.00
1,652,464.00
70° 12' 0.656 N 140° 40' 47.202 W
plan misses target center by 1141415.52usft at 10650.00usft
MD (6317.55 TVD, 3722.95 N, 3110.44 E)
Polygon
Point 1
6,246.00
0.00 0.00
6,011,187.00
1,652,464.00
Point
6,246.00
1.00 1.00
6,011,188.00
1,652,465.00
31-01L1-03_Fault5_M 0.00 0.00
0.00
2,665.881,144,525.47
6,011,187.00
1,652,464.00
70° 12' 0.656 N 1400 40' 47.202 W
plan misses target center by 1141433.00usft at 10650.00usft
MD (6317.55 TVD, 3722.95 N, 3110.44 E)
Rectangle (sides W1.00 H1,000.00 D0.00)
31-0lL1 Fault3_M 0.00 0.00
0.00
2,283.991,143,457.95
6,010,804.00
1,651,397.00
70° 11' 58.537 N 140° 41' 19.445 W
plan misses target center by 1140365.92usft at 10650.00usft
MD (6317.55 TVD, 3722.95 N, 3110.44 E)
Rectangle (sides W1.00 H1,000.00 D0.00)
31-01 CTD Polygon Wes 0.00 0.00
0.00
1,758.681,144,621.50
6,010,280.00
1,652,561.00
70° 11' 51.707 N 140° 40' 48.435 W
711912018 12:52:11 PM
Page 4
COMPASS 5000.14 Build 85
ConocoPhillips
ConocoPhillips Planning Report
Database:
EDT Alaska Sandbox
Local Co-ordinate Reference:
Company:
ConocoPhillips (Alaska) Inc. -Kup2
TVD Reference:
Project:
Kuparuk River Unit
MD Reference:
Site:
Kuparuk 31 Pad
North Reference:
Well:
31-01
Survey Calculation Method:
Wellbore:
31-01 Li-01
Design:
31-01 L1-01_wp02
Well 31-01
Mean Sea Level
31-01 @ 71.00usft (31-01)
True
Minimum Curvature
BA ER
I IGHES .
GE company
plan misses target center by 1141530.23usft at 10650.00usft MD (6317.55 TVD, 3722.95 N, 3110.44 E)
Polygon
Point 1
0.00
0.00 0.00
6,010,280.00
1,652,561.00
Point
0.00
124.72 281.16
6,010,405.01
1,652,842.00
Point
0.00
451.71 326.50
6,010,732.02
1,652,886.98
Point
0.00
799.27-180.20
6,011,079.00
1,652,379.96
Point 5
0.00
523.82-2,687.73
6,010,800.87
1,649,872.97
Point
0.00
138.79-2,702.13
6,010,415.86
1,649,858.99
Point?
0.00
417.37-319.60
6,010,696.98
1,652,240.98
Point 8
0.00
299.07 -34.70
6,010,579.00
1,652,525.98
Point 9
0.00
0.00 0.00
6,010,280.00
1,652,561.00
31-01L1_Fault3 0.00 0.00
6,299.00
2,283.991,143,457.95
6,010,804.00
1,651,397.00
700 11' 58.537 N 140° 41' 19.445 W
- plan misses target center by 1140348.42usft at 10650.00usft
MD (6317.55 TVD, 3722.95 N, 3110.44 E)
- Polygon
Point 1
6,299.00
0.00 0.00
6,010,804.00
1,651,397.00
Point 2
6,299.00
1.00 1.00
6,010,805.00
1,651,398.00
31-01L1_Fault2 0.00 0.00
6,288.00
2,347.391,144,024.08
6,010,868.00
1,651,963.00
70° 11' 58.310 N 140' 41' 2.957 W
- plan misses target center by 1140914.46usft at 10650.00usft
MD (6317.55 TVD, 3722.95 N. 3110.44 E)
- Polygon
Point 1
6,288.00
0.00 0.00
6,010,868.00
1,651,963.00
Point 2
6,288.00
1.00 1.00
6,010,869.00
1,651,964.00
31-01L1-01_T02 0.00 0.00
6,284.00
2,404.021,142,515.99
6,010,923.00
1,650,455.00
70' 12' 1.102 N 140° 41' 45.891 W
- plan misses target center by 1139406.3lusft at 10650.00usft
MD (6317.55 TVD, 3722.95 N, 3110.44 E)
- Point
31-01L1_Fault4_M 0.00 0.00
0.00
2,170.491,142,991.78
6,010,690.00
1,650,931.00
70° 11' 58.128 N 140° 41' 33.291 W
- plan misses target center by 1139899.90usft at 10650.00usft
MD (6317.55 TVD, 3722.95 N, 3110.44 E)
- Rectangle (sides W1.00 1-11,000.00 D0.00)
Casing Points
Measured Vertical Casing Hole
Depth Depth Diameter Diameter
(usft) (usft) Name (in) (in)
12,250.00 6,290.25 2 3/8" 2.375 3.000
Plan Annotations T--�
Measured
Vertical
Local Coordinates
Depth
Depth
+N/-S
+E/-W
(usft)
(usft)
(usft)
(usft)
Comment
10,650.00
6,317.55
3,722.95
3,110.44
TIP/KOP
10,750.00
6,316.09
3,704.24
3,012.29
Start 7 dls
10,950.00
6,305.41
3,700.40
2,813.11
3
11,100.00
6,299.99
3,729.17
2,666.20
4
11,300.00
6,289.77
3,807.07
2,482.83
5
11,475.00
6,283.41
3,908.09
2,340.47
6
11,725.00
6,285.72
4,097.86
2,179.23
7
11,900.00
6,287.28
4,236.00
2,072.35
8
12,250.00
6,290.25
4,531.81
1,890.34
Planned TD at 12250.00
711912018 12:52::11PM Page 5 COMPASS 5000.14 Build 85
ConocoPhillips
Company:
ConocoPhillips (Alaska) Inc. -Kup2
Project:
Kuparuk River Unit
Reference Site:
Kuparuk 31 Pad
Site Error:
0.00 usft
Reference Well:
31-01
Well Error:
0.00 usft
Reference Wellbore
31-01 Li-01
Reference Design:
31-01 L1-01_wp02
Baker Hughes INTEQ
Travelling Cylinder Report
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Output errors are at
Database:
Offset TVD Reference:
Well 31-01
31-01 @ 71.00usft (31-01)
31-01 @ 71.00usft (31-01)
True
Minimum Curvature
1.00 sigma
OAKEDMP2
Offset Datum
B IUGHES
a GE company
Reference
31-01L1-01_wp02
Filter type:
GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
Interpolation Method:
MD Interval 25.00usft Error Model: ISCWSA
Depth Range:
10,650.00 to 12,250.00usft Scan Method: Tray. Cylinder North
Results Limited by:
Maximum center -center distance of 1,417.90 usft Error Surface: Pedal Curve
Survey Tool Program Date 7/18/2018
From To
(usft) (usft) Survey (Wellbore) Tool Name Description
100.00 8,700.00 31-01 (31-01) GCT-MS Schlumberger GCT multishot
8,700.00 10,650.00 31-Ol L1_wp02 (31-01 L1) MWD MWD - Standard
10,650.00 12,250.00 31-01L1-01_wp02(31-0111-01) MWD MWD- Standard
Casing Points
Measured Vertical Casing Hole
Depth Depth Diameter Diameter
(usft) (usft) Name
12,250.00 6,361.25 2 3/8" 2-3/8 3
Summary
Site Name
Offset Well - Wellbore - Design
Kuparuk 31 Pad
31-01 - 31-01 - 31-01
31-01 - 31-01 L1 - 31-01 1-1_wp02
31-01 - 31-01 L1-02 - 31-01 L1-02_wp01
31-01 - 31-01 L1-03 - 31-01 11-03_wp02
31-01 - 31-01 L1-04 - 31-01 L1-04_wp01
31-01 - 31-01 L1-05 - 31-01 L1-05_wp01
31-02 - 31-02 - 31-02
31-03 - 31-03 - 31-03
31-04 - 31-04 - 31-04
31-05 - 31-05 - 31-05
31-06 - 31-06 - 31-06
31-07 - 31-07 - 31-07
31-08 - 31-08 - 31-08
Reference Offset Centre to No -Go Allowable
Measured Measured Centre Distance Deviation Warning
Depth Depth Distance (usft) from Plan
(usft) (usft) (usft) (usft)
Out of range
10,959.65 10,975.00 58.82 1.40 58.52 Pass - Minor l/10
10,890.45 10,925.00 16.50 1.38 15.19 Pass - Minor 1/10
Out of range
Out of range
Out of range
Out of range
11,917.17 8,100.00 717.80 294.78 424.80 Pass- Major Risk
Out of range
Out of range
Out of range
Out of range
Out of range
Offset Design
Kuparuk 31 Pad - 31-01 - 31-01 L1 - 31-01 L1_wp02
offset Site Error: 0.00 usft
Survey Program: 100-GCT-MS, 8700-MWD
Rule Assigned: Minor 1110
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)
(°)
lush)
(usft)
()
(usft)
(usft)
(ush)
10,674.98 6,388.92
10,675.00
6,389.04
0.14
0.18
157.86
3,716.78
3,086.22
2-11116
0.66
0.69
-0.02 FAIL - Minor l/10
10699.86 6,388.80
10,700.00
6,389.26
0.28
0.36
159.23
3,709.91
3,062.19
2-11/16
2.64
0.98
1.67 Pass - Minor l/10
10,724.53 6,388.21
10,725.00
6,389.22
0.37
0.54
160.64
3,702.36
3,038.36
2-11/16
5.93
1.16
4.77 Pass - Minor 1 /10
10,748.90 6,387.15
10,750.00
6,388.92
0.45
0.72
162.09
3,694.13
3.014.76
2-11/16
10.51
1.28
9.23 Pass - Minor l/10
10,772.97 6,385.85
10,775.00
6,388.30
0.55
0.91
164.52
3,685.87
2,991.17
2-11/16
15.73
1.34
14.39 Pass - Minor l/10
10,796.88 6,384.56
10,800.00
6.387.30
0.64
1.09
167.67
3,678.24
2,967.38
2-11/16
20.96
1.37
1964 Pass - Minor l/10
CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation
7/18/2018 2:49:59PM Page 2 COMPASS 5000.14 Build 85
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31-01 RWO Final Schematic
16" 62# H-40
shoe @ 104' MD
9-5/8" 36# J-55 shoe
@ 4346' M D
A2-sand perfs
8734' - 8760' MD
Al -sand perfs
8770' - 8798' MD
7" 26# J-55 shoe @ 9010' MD
Updated: 19-Jul-2018 RLP
3-1/2" Camco MMG gas lift mandrels @ 3130' RKB
Baker Orbit Valve @ 3597' RKB
3-1/2" 9.3# L-80 ELIE 8rd Tubing to surface
3-1/2" Camco MMG gas lift mandrels @ 4930, 6251',
7272', 8003' & 8465' RKB
Baker Locator @ 8518' RKB
Baker PBR 80-40 @ 8522' RKB (2.99" ID)
Baker FHL Packer @ 8535' RKB (2.91" ID)
3'/2" X landing nipple at 8588' RKB (2.813" min ID)
Northern Solutions WEDGE (see details)
Top of Wedge Assembly @ 8698' RKB
3-'/2' X landing nipple at 8712' RKB (2.813" min ID)
Top of Wedge Assembly @ 8728' RKB
3-1/2" X landing nipple at 8742' RKB (2.813" min ID)
Baker WLEG @ 8747' RKB
Northern Solutions Wedge
* 3-1/2" 9.3# L-80 Base Pipe
* 5.905" OD (12.9' long)
* —50' Total Length
* 0.625" Bore thru Ter Tray
* 1.125" Bore thru LoWer, Section
* HE$ 2,81" X Nipple below,
F
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TRANSMITTAL LETTER CHECKLIST
WELL NAME: ��jC.L a Z /
4
PTD:
Development Service Exploratory _ Stratigraphic Test _ Non -Conventional
FIELD: �G-�� l -Gs� 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. lyS —37, API No. 50-0-
(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,
z/
{/
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 31-01L1-01 Program DEV Well bore seg d❑
PTD#: 2180880 Company CONOCOPHILLIPS ALASKA, INC.
Initial Class/Type
DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal ❑
Administration
117
Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)
NA
1
Permit fee attached
NA
12
Lease number appropriate
Yes
Entire well within ADL0025521
3
Unique well name and number
Yes
4
Well located in a defined -pool
Yes
KUPARUK RIVER, KUPARUK RIV OIL - 490100
5
Well located proper distance from drilling unit boundary
Yes
Kuparuk River Oil Pool, governed by Conservation Order No. 432D
6
Well located proper distance from other wells
Yes
Conservation Order No. 432D has no interwell spacing restrictions. Wellbore-will be more than 500'
17
Sufficient acreage available indrillingunit
Yes
from an external property line -where ownership or landownership changes. As proposed, -well will
8
If deviated, is wellbore plat included
Yes
conform to spacing requirements.
9
Operator only affected party
Yes
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
SFD 7/24/2018
13
Can permit be approved before 15-day wait
Yes
14
Well located within area and strata authorized by Injection Order # (put 10# in
comments) (For! NA
15
All wells within 1/4 mile area of review identified (For service well only)
NA
16
Pre -produced injector: duration of pre -production less than 3 months (For service well only) NA
18
Conductor string provided
NA
Conductor set in KRU 31-01
Engineering
19
Surface casing protects all known USDWs
NA
Surface casing set in KRU 31-01
20
CMT vol adequate to circulate on conductor & surf csg
NA
Surface casing set and fully cemented
21
CMT vol adequate to tie-in long string to surf csg
NA
22
CMT will cover all known productive horizons
No
Productive interval will be completed with uncemented slotted liner
23
Casing designs adequate for C, T, B & permafrost
Yes
24
Adequate tankage or reserve pit
Yes
Rig has steel tanks; all waste to approved disposal wells
25
If a re -drill, has a 10-403 for abandonment been approved
NA
I26
Adequate wellbore separation proposed
Yes
Anti -collision analysis complete; no major risk failures
27
If diverter required, does it meet regulations
NA
Appr
Date
28
Drilling fluid program schematic -& equip list adequate
Yes
Max formation pressure is-5456 psig(16.7 ppg EMW); will drill w/ 8.6 ppg EMW andmaintainoverbal-w/ MPD
VTL
8/28/2018
129
BOPEs, do they meet regulation
Yes
30
BOPE press rating appropriate; test to (put psig in comments)
Yes
MPSP is 4829 psig; will test BOPs to 4900 psig
131
Chokemanifoldcomplies w/API RP-53 (May 84)
Yes
32
Work will occur without operation shutdown
Yes
33
Is presence of H2S gas probable
Yes
H2S measures required
34
Mechanical condition of wells within AOR verified (For service well only)
NA
35
Permitcanbe issued w/o hydrogen sulfide measures
No
31-Pad wells are H2S-bearing. H2S measures are required.
Geology
36
Data presented on potential overpressure zones
Yes
Expected reservoir pressure is -12.1 ppg EMW, with a maximum up to --16.7 ppg EMW.
Appr
Date 137
Seismic analysis of shallow gas zones
NA
Well will be drilled using 8.6 ppg mud, a coiled -tubing rig, and managed pressure drilling
SFD
7/24/2018
38
Seabed condition survey -(if off -shore)
NA
technique to control formation pressures and stabilize shale sections. NOTE: Chance of
I39
Contact name/phone for weekly progress reports- [exploratory only]
NA
encountering gas while drilling this wellbore due to gas injection performed in this area.
Geologic Engineering Public
Commissioner: Date: Commissioner: Date Commissioner Date
