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HomeMy WebLinkAbout216-012Guhl, 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 L1-01, 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.guhl@alaska.gov.
'PTo Z /G —U l 7i
Loepp, Victoria T (DOA)
From:
Phillips, Ron L <Ron.L.Phillips@conocophillips.com>
Sent:
Friday, October 07, 2016 10:28 AM
To:
Loepp, Victoria T (DOA)
Cc:
Eller, J Gary
Subject:
Kuparuk 1H-07AL1 permit 216-012
Follow Up Flag:
Follow up
Flag Status:
Flagged
Victoria,
Due to hole conditions deteriorating at the Kuparuk A6/131 interface we will have to plug back and re -drill the 1H-07A
permit 216-011. Due to crossing two unplanned faults (30'DTN and 21' DTS) our second lateral (11-1-07AL1, #216-012)
will need to be moved —500' to the west to provide injection for the wells on the west side of that unplanned fault. Also
a third lateral (proposed 1H-07AL2) is planned for the east side of that unplanned fault. We will not have a plan put
together for either the revised 1H-07AL1 or the new 1H-07AL2 for you until Monday morning, so we are just giving you a
heads up that we will need the permit revision and new permit for the third lateral sometime around Tuesday
10/11/2016.
Thanks,
Ron Phillips
Senior CTD Engineer
ConocoPhillips Alaska
1
THE STATE
OfALAV—KA-
GOVERNOR BILL WALKER
Daniel Venhaus
CTD Manager
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.olaska.gov
Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 1 H-07AL I
ConocoPhillips Alaska, Inc.
Permit to Drill Number: 216-012 (revised)
Surface Location: 768' FNL, 787' FEL, SEC. 33, T12N, RIOE, UM
Bottomhole Location: 1687' FNL, 4946' FEL, SEC. 27, T12N, RI OE, UM
Dear Mr. Venhaus:
Enclosed is the approved application for permit to redrill the above referenced service well. This
permit supersedes and replaces the permit previously issued for this well dated January 22, 2016.
The permit is for a new wellbore segment of existing well Permit No. 216-011, API No. 50-029-
20755-01-00. Injection and production should continue to be reported as a function of the
original API number stated above.
This permit to drill does not exempt you from obtaining additional permits or an approval
required by law from other governmental agencies and does not authorize conducting drilling
operations until all other required permits and approvals have been issued. In addition, the
AOGCC reserves the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the
Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to
comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska
Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result
in the revocation or suspension of the permit.
Sincerely,
Cathy P oerster
Chair
DATED this ��i�f October, 2016.
STATE OF ALASKA I
n v�S f ;KA OIL AND GAS CONSERVATION COW 3ION
PERMIT TO DRILL
RECEIVED
OCT 11 2016
20 AAC 25.005
1 a. Type of Work:
1 b. Proposed Well Class: Exploratory - Gas ❑
Service - WAG ❑ Service - Disp ❑
1 c. Speci i i r for:
Drill ❑ Lateral • 0
Stratigraphic Test ❑ Development - Oil ❑
Service - Winj ❑✓ , Single Zone 0
Coalbed Gas ❑ Gas Hydrates ❑
Redrill ❑ Reentry ❑
Exploratory - Oil ❑ Development - Gas ❑
Service - Supply ❑ Multiple Zone ❑
Geothermal ❑ Shale Gas ❑
2. Operator Name:
5. Bond: Blanket ❑✓ t Single Well ❑
11. Well Name and Number:
ConocoPhillips Alaska Inc
Bond No. $4g$.26_2,2. o
KRU 1 H-07ALl
3. Address:
6. Proposed Depth:
12. Field/Pool(s):
P.O. Box 100360 Anchorage, AK 99510-0360
MD: 10200' TVD: 6582' %
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:
2307' FNL, 4850' FEL, Sec. 27, T12N, R10E, UM
ALK 464
10/13/2016
Total Depth:
9. Acres in Property:
14. Distance to Nearest Property:
1687' FNL, 4946' FEL, Sec 27, T12N, R10E, UM
2560
6575'
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: 1610' 1 H-17
16. Deviated wells: Kickoff depth: 8540' 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)
T'
2.375"
4.7#
L-80
ST-L
630'
9570'
6556
10200
6582
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' 16744'
20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling
Program Q Time v. Depth Plot ❑ Shallow Hazard Analysis❑
Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program 0 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
9
be deviated from without prior written approval.
Contact Ron Phillips @ 265-6312
Email ron l.phllhps(Q' cop.com
Printed Name Kai Starck
Title CTD Director
Signature
Phone 263-4093 Date
Commission Use Only
Permit to Drill
API Number:
Permit Approval
See cover letter for other
Number:;L�(Q-012 Ctvt-1 4
G
50-OIL. (-LO-i6 -C4G
-GU
Date: (- 22-(
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: 20
Other: 7q�P
Samples req'd: Yes ❑ Noy Mud log req'd: Yes❑ No[if
H2S measures: Yes [�No ❑ Directional svy req'd: Yes E;KNo ❑
V
Spacing
exception req'd: Yes ❑ No Inclination -only svy req'd: Yes ❑ No
Post initial injection MIT req'd: Yes No ❑
�A
APPROVED BY
Approved by:
COMMISSIONER THE COMMISSION Date: l0
I Submit Form and
OForm 10-401 (Revised 11/2015) RV rl I ALonths from the qate of approval (20 AAC 25.005(g)) Attachments in Duplicate
*4 /o/11//(. "e'00' lofi
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:
OCT 112016
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
�1 Kuparuk CTD Laterals NABOASAIASKA
1 H-07A, AL1 revised & AL1-01 CIJ, 19
Application for Permit to Drill Document 211C
1.
Well Name and Classification........................................................................................................ 2
(Requirements of 20 AAC 25.005(t) 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 & AL1-01...............................................................................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: 1 H-07A, AL1 revised & AL1-01
1. Well Name and Classification
(Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b))
The proposed laterals described in this document are 1 H-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 psi and to 3P0 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: 11-1-07A, AL1 revised & AL1-01
6. Casing and Cementing Program
(Requirements of 20 AAC 25.005(c)(6))
New Completion Details
Lateral
Liner Top
Liner Btm
Liner Top
Liner Btm
Name
MD
MD
TVDSS
TVDSS
Liner Details
1H-07A
8540'
11100'
6621'
6582'
2%", 4.7#, L-80, ST-L slotted liner;
aluminum billet on top
1H-07AL1
9570'
10200'
6641'
6667'
2%", 4.7#, L-80, ST-L slotted liner, -
revised
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 to acker 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 ELIE
25'
1 7662'
0'
1 6413'
10 660
10530
7. Diverter System Information
(Requirements of 20 AAC 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 AAC 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 1 H-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: 7H-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 1 H-07 Window (7842' MD, 6566' TVDSS) Using MPD
Pumps On
1.5 b m)
Pumps Off
A -sand Formation Pressure (10.9 p)
3721 psi
3721 psi
Mud Hydrostatic 9.6 )
3278 psi
3278 psi
Annular friction i.e. ECD, 0.060 psi/ft
471 psi
0 psi
Mud + ECD Combined
3748 psi
3278 psi
(no choke pressure)
(overbalanced
(underbalanced
—27psi)
—444psi)
Target BHP at Window (11.8 )
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 1 -07 is a Kuparuk A -sand injection well equipped with 3'/z" tubing and 7" production casing.
One lateral will be drilled to the south of the parent well and t\v-o laterals "H] be drilled to the north with
the laterals targeting the A4 sand. A thru-tubing whip -stock will be set inside the 3'/2" liner at the planned
kickoff point of 7842' MD to drill three laterals.
The 1 H-07A southern sidetrack will exit through the 3 /2" 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 1 H-07AL1 lateral. /
The 1 H-07AL 1 will drill north then west to a TD of 10,200' M D 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 1 H-
07AL 1 lateral.
Page 4 of 7 October 10, 2016
PTD Application: iH-07A, AL1 revised & AL1-01
The 1H-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
Rig 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. 1 H-07AL 1 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: -i H-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. ,
• All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal.
• Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1 R-18
or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable.
• All wastes and waste fluids hauled from the pad must be properly documented and manifested.
• Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200).
15. Directional Plans for Intentionally Deviated Wells
(Requirements of 20 AAC 25.050(b))
— The Applicant is the only affected owner.
— Please see Attachment 1: Directional Plan
— Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run.
— MWD directional, resistivity, and gamma ray will be run over the entire openhole section. r/
Page 6 of 7 October 10, 2016
PTD Application: -IH-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
1 6215'
— Distance to Nearest Well within Pool
Lateral Name
Distance
Well
1 H-07A
1 H-14
1080'
1 H-07ALl
revised
1 H-17
1610'
1 H-07AL1-01
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
Top of A -sand
Topof A-Sand08
TOPof Cement
Topaf Cement
TOPofckment
eemrvolr Status
2ow16alation
cemem Operadoru Summary
Mechan(cal Integrity
PTO
API
WELL NAME
STANS
08 Peol(MD)
Peal(WOZ)
(MD)
(1W551
Determined8y
182-0.
SM0 20155
1H-07
Suspended
7696'
69a1' s
6850'
5656' •
C9L
Perk cemented and
packer@y880'MO
9625ss Cl- Gcement
Stanessedpassing MR
8/11/13
abandoned
Al [0 2820 psi on
6M'
6300'
5798'
Ca
Per(s open For
Packer @680A'MD
590" Class Gcement
51-Tlft Passed. Initial T/1/0=
192-131
56029-22315
1H-16
Pradudng
MS'
prod..,-
si IW/1250/780 on 5/30/15
193-052
50029.22359
kH-14
Producing
869V
054 •
9330'
6412-
Cu
Peds open fw
packer@8122'MO
520 sss Class G cement
Competent prodaoar with
produ¢ion
passingM
iw--**'
ConocoPh i I I i ps
ConocoPhillips (Alaska) Inc. -Kup1
Kuparuk River Unit
Kuparuk 1 H Pad
1 H-07
1 H-07AL1
Plan: 1 H-07AL1_wp06
Standard Planning Report
08 October, 2016
FA 39 P P'
BAKER
HIJGHES
ConocoPhillips
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
Design:
1 H-07AL1_wp06
ConocoPhillips
Planning Report
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
rG.I
BAKER
HUGHES
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:
0,000in Grid Convergence:
0.38 °
Well
1 H-07
Well Position
+N/-S
0.00 usft Northing:
5,979,935.13 usft Latitude:
70° 21' 21.476 N
+E/-W
0.00 usft Easting:
549,560.55 usft Longitude:
1490 35' 51.058 W
Position Uncertainty
0.00 usft Wellhead Elevation:
usft Ground Level:
0.00 usft
Wellbore
1 H-07ALl
Magnetics
Model
Name
Sample Date
Declination Dip Angle
Field Strength
(nT)
BGGM2016
9/1/2016
18.07
80.98
57,554
i Design
1H-07AL1_wp06
Audit Notes:
Version:
Phase:
PLAN
Tie On Depth:
8,540.00
Vertical Section:
Depth From (TVD)
+Nl-S
+E/-W
Direction
(usft)
(usft)
(usft)
(°)
0.00
0.00
0.00
350.00
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) (°110oft)
(°)
Target
8,540.00
86.20
208.72
6,620.88 3,070.32
1,583.87
0.00 0.00
0.00
0.00
8,640.00
89.75
243.56
6,624.53 3,002.17
1,512.90
35.00 3.55
34.85
85.00
8,740.00
89.79
278.56
6,624,94 2,986.88
1,415.65
35.00 0.05
35.00
90.00
8,940.00
88.52
348.56
6,628.32 3,116.26
1,279.58
35.00 -0.64
35.00
91.50
9,040.00
87.32
355.46
6,631.95 3,215.16
1,265.70
7.00 -1.20
6.90
100.00
9,140.00
85.53
348.68
6,638+20 3,313.96
1,251.95
7.00 -1.79
-6.78
255.00
9,240.00
89.05
354.74
6,642.93 3,412.74
1,237.57
7.00 3.52
6.06
60.00
9,310.00
90.32
350.01
6,643.32 3,482.10
1,228.28
7.00 1.81
-6.76
285.00
9,460.00
90.68
0.50
6,642.02 3,631.37
1,215.89
7.00 0.24
7.00
88.00
9,710.00
89.44
343.05
6,641.76 3,877.84
1,180.26
7.00 -0.49
-6.98
266.00
9,910.00
86.34
356.71
6,649.15 4,074.09
1,145.20
7.00 -1.55
6.83
103.00
10,030.00
86.38
348.29
6,656.78 4,192.72
1,129.58
7.00 0.03
-7.01
270.00
10,200,00
86.46
0.21
6,667.44 4,361.23
1,112.63
7.00 0.05
7.01
90.00
101812016 2.05:51PM
Page 2
COMPASS 5000.1 Build 74
ConocoPhillips re.■
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
Design:
1 H-07AL1_wp06
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)
8,540.00
86.20
208.72
6,620.88
3,070.32
1,583.87
2,748.64
0.00
0.00
5,983,015.56
551,123.92
TIP/KOP
8,600.00
88.24
229.64
6,623.82
3,024+13
1,546.21
2,709.69
35.00
85.00
5,982,969.13
551,086.57
8,640.00
89.75
243.56
6,624.53
3.002.17
1,512.90
2,693.85
35.00
83.97
5,982,946.95
551,053.41
Start 35 dis
8,700.00
89.76
264.56
6,624.79
2,985.79
1,455.53
2,687.68
35.00
90.00
5,982,930.20
550,996.16
8,740.00
89.79
278.56
6,624.94
2,986+88
1,415.65
2,695.68
35.00
89.91
5,982,931.02
550,956.27
3
8,800.00
89.27
299.56
6,625+44
3,006.37
1,359.26
2,724.66
35.00
91.50
5,982,950.13
550,899.76
8,900.00
88.64
334.56
6,627.32
3,078.42
1,292.19
2,807.27
35.00
91.33
5,983,021.73
550,832.23
8,940.00
88.52
348.56
6,628.32
3,116.26
1,279.58
2,846.72
35.00
90.67
5,983,059.49
550,819.36
End 35 dis, Start 7 dis
9,000.00
87.79
352.70
6,630.25
3,175.42
1,269.82
2,906.67
7.00
100.00
5,983,118.57
550,809.21
9,040.00
87.32
355.46
6,631.95
3,215.16
1,265.70
2,946.53
7.00
99.87
5,983,158.28
550,804.83
5
9,100.00
86.24
351.40
6,635.33
3,274.66
1,258.85
3,006.32
7.00
-105.00
5,983,217.73
550,797.59
9,140.00
85.53
348.68
6,638.20
3,313.96
1,251+95
3,046.21
7.00
-104.77
5,983,256.97
550,790.43
6
9,200.00
87.64
352.32
6,641.78
3,373.01
1,242.07
3,106.09
7.00
60.00
5,983,315.96
550,780+16
9,240.00
89.05
354.74
6,642.93
3,412.74
1,237.57
3,145.99
7.00
59.78
5,983,355.65
550,775.39
7
9,300.00
90.14
350.68
6,643.36
3,472.24
1,229.96
3.205.91
7.00
-75.00
5,983,415.09
550,767.39
9.310.00
90.32
350.01
6,643.32
3,482.10
1,228.28
3,215+91
7.00
-74.97
5.983,424.94
550,765.65
8
9,400.00
90.53
356.31
6,642.65
3,571.41
1,217.56
3,305.72
7.00
88.00
5,983,514.17
550,754.34
9,460.00
90.68
0.50
6,642.02
3,631.37
1,215.89
3,365.06
7.00
88.05
5,983,574.11
550,752.27
9
9,500.00
90.48
357.71
6,641.62
3,671.36
1,215.27
3,404.55
7.00
-94.00
5,983,614.09
550,751.39
9,600.00
89.99
350.73
6,641.21
3.770.79
1,205.20
3.504.22
7.00
-94.03
5.983,713.44
550,740.66
9,700.00
89.49
343.74
6,641.66
3,868.25
1,183.12
3,604+04
7.00
-94.06
5,983,810+75
550,717.94
9,710.00
89.44
343.05
6,641.76
3,877.84
1,180.26
3,613.97
7.00
-94.02
5,983,820.31
550,715.02
10
9,800.00
88.03
349.19
6,643.74
3,965.14
1,158.68
3,703.70
7.00
103.00
5,983,907.46
550,692.87
9,900.00
86.49
356.02
6,648.52
4,064.13
1,145.83
3,803.42
7.00
102.86
5,984,006.36
550,679.36
9.910.00
86.34
356.71
6,649.15
4,074.09
1,145.20
3,813.34
7.00
102.54
5.984,016.32
550,678.66
11
10,000.00
86.36
350.40
6,654.88
4.163.30
1,135.12
3,902.94
7.00
-90.00
5,984,105.44
550,667.99
10,030.00
86.38
348.29
6,656.78
4,192.72
1,129.58
3,932+87
7.00
-89.60
5,984,134.82
550,662.26
12
10,100.00
86.39
353.20
6,661.20
4,261.65
1,118.35
4,002.71
7.00
90.00
5,984,203.67
550,650.58
10,200.00
86.46
021
6,667.44
4,361.23
1.112.63
4,101.77
7.00
89.69
5,984,303.20
550,644.19
Planned TD at 10200.00
101812016 2:05:51PM 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
1 H-07AL1_wp06
Travelling Cylinder Report
08 October, 2016
FSAiks
BAKER
NUGNES
�.- Baker Hughes INTEQ Has
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:
1 H-07
Well Error:
0.00 usft
Reference Wellbore
1 H-07ALl
Reference Design:
1 H-07AL1_wp06
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_wp06
Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA
Depth Range: 8,540.00 to 10,200.00usft Scan Method: Tray. Cylinder North
Results Limited by: Maximum center -center distance of 1,211.50 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-07AP81 (1H-07APB1)
MWD
MWD- Standard
8,019.45
8,540.00 1 H-07A_wp10 (1 H-07A)
MWD
MWD - Standard
8,540.00
10,200.00 1 H-07AL1_wp06 (1 H-07AL1)
MWD
MWD - Standard
Casing Points
Measured
Vertical
Depth
Depth
(usft)
(usft)
10,200.00
6,752.44 2 3/8"
Summary
Site Name
Offset Well - Wellbore - Design
Kuparuk I Pad
1 H-01 - 1 H-01 - 1 H-01
1 H-05 - 1 H-05 - 1 H-05
1 H-05 - 1 H-105 - 1 H-105
1 H-06 - 1 H-06 - 1 H-06
1 H-07 - 1 H-07 - 1 H-07
1 H-07 - 1 H-07A - 1 H-07A_wpl 0
1 H-07 - 1 H-07ALl-01 - 1 H-07ALl-01_wp01
1 H-07 - 1 H-07APB1 - 1 H-07APB1
1 H-07 - 1 H-07AP62 - 1 H-07APB2
1 H-08 - 1 H-08 - 1 H-08
1 H-09 - 1 H-09 - 1 H-09
1 H-10 - 1 H-10 - 1 H-10
1 H-10 - 1 H-10A - 1 H-10A
1 H-11 - 1 H-11 - 1 H-11
1 H-12 - 1 H-12 - 1 H-12
1 H-13 - 1 H-13 - 1 H-13
1 H-14 - 1 H-14 - 1 H-14
1 H-15 - 1 H-15 - 1 H-15
1 H-18 - 1 H-18 - 1 H-18
1 H-21 - 1 H-21 - 1 H-21
1 H-22 - 1 H-22 - 1 H-22
Plan: 1 H-104 (formerly 101 and 27) - Plan: 1 H-104
Plan: 1 H-104 (formerly 101 and 27) - Plan:1 H-104
Plan: 1 H-104 (formerly 101 and 27) - Plan:1 H-104
Plan: 1 H-104 (formerly 101 and 27) - Plan:1 H-104
Plan: 1 H-104 (formerly 101 and 27) - PlanA H-104
Plan: 1 H-106 (formerly 107 and 28D) -Plan: 1 H-1(
Name
Casing Hole
Diameter Diameter
2-3/8
3
Reference Offset Centre to No -Go Allowable
Measured Measured Centre Distance Deviation Warning
Depth Depth Distance (usft) from Plan
(usft) (usft) (usft) (usft)
8,540.00
7,600.00
415.64
14.64
8,549.99
8,550.00
0.25
0.48
9,575.00
9,575.00
0.06
0.47
8,621.32
8,625.00
35.94
1.31
8,540.00
7,600.00
415.64
6.80
10,186.08 8,525.00 282.20 277.08
Out of range
Out of range
Out of range
Out of range
407.20
Pass - Major Risk
-0.22
FAIL- Minor 1/10
-0.40
FAIL - Major Risk
35.07
Pass - Minor 1/10
415.06
Pass - Minor 1/10
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
105.21
Pass - Major Risk
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation
101812016 1:44:12PM Page 2 COMPASS 5000.1 Build 74
Baker Hughes INTEQ rigs
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-07AL1
Reference Design:
111-07AL1_wp06
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
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 1H Pad
Plan: 1 H-107 (formerly 108 and 30E) - Plan: 1 H-10
Out of range
Plan: 1 H-112 (formerly 106 and 28E) - Plan: 1 H-11
Out of range
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)
(")
(usft)
(usft)
(usft)
8,540.00
6,705.88
7,600.00
6,360.78
0.62
0.00
175.04
2,938.84
1,774.61
2-11/16
415,64
14.64
407.20 Pass - Major Risk, CC, ES, SF
8,545.31
6,706.22
7,575.00
6,339.69
0.74
0.00
178.98
2,930.75
1,763.89
2-11116
431.18
14.69
422.63 Pass - Major Risk
8,550.00
6,706.51
7,550.00
6,318.62
0.85
0.00
-177.51
2,922A7
1,753.28
2-11/16
447.54
14.74
438.89 Pass - Major Risk
8,556.03
6,706.87
7,525.00
6,297.58
0.85
0.00
-173.75
2,914.00
1,742.77
2-11/16
464.60
14.79
455.89 Pass - Major Risk
8,560.00
6,707.09
7,500.00
6,276.57
0.85
0.00
-170.86
2,905.34
1,732.36
2-11/16
482.29
14.82
473.55 Pass - Major Risk
8,570.00
6,707.62
7,475.00
6,255.58
0.86
0.00
-166.15
2,896.53
1,722.02
2-11/16
500.51
14.90
491.65 Pass - Major Risk
8,573.84
6,707.80
7,450.00
6,234.64
0.86
0.00
-163.63
2,887.61
1,711.69
2-11/16
519.14
14.93
510.24 Pass - Major Risk
8,580.00
6,708.08
7,425.00
6,213.73
0.87
0.00
-160.47
2,878.56
1,701.39
2-11/16
538.15
14.98
529.19 Pass - Major Risk
8,586.70
6,708.35
7,400.00
6,192.86
0.88
0.00
-157.27
2,869.41
1,691.11
2-11/16
557.49
15.04
548.47 Pass - Major Risk
8,593.37
6,708.60
7,375.00
6,172.03
0.88
0.00
-154.19
2,860.13
1,680.86
2-11/16
577.13
15.09
568.03 Pass - Major Risk
8,600.00
6,708.82
7,350.00
6,151.24
0.89
0.00
-151.23
2,850.73
1,670.66
2-11116
597.04
15.15
587.87 Pass - Major Risk
8,607.05
6,709.02
7,325.00
6,130.47
0.90
0.00
-148.23
2,841.21
1,660.50
2-11/16
617.18
15.20
607.94 Pass - Major Risk
8,614.00
6,709.19
7,300.00
6,109.74
0.91
0.00
-145.35
2,831.56
1,650.39
2-11/16
637.54
15.26
628.22 Pass - Major Risk
8,620.00
6,709.30
7,275.00
6,089.04
0.92
0.00
-142.88
2,821.81
1,640.32
2-11/16
658.08
15.31
648.70 Pass - Major Risk
8,630.00
6,709.45
7,250.00
6,068.37
0.93
0.00
-139.10
2,811.99
1,630.26
2-11116
678.79
15.38
669.30 Pass - Major Risk
8,634.86
6,709.49
7,225.00
6,047.72
0.94
0.00
-137.15
2,802.08
1,620.24
2-11116
699.64
15.42
690.09 Pass - Major Risk
8,640.00
6,709.53
7,200.00
6,027.10
0.95
0.00
-135.17
2,792.08
1,610.23
2-11/16
720.63
15.46
711.02 Pass - Major Risk
8,646.83
6,709.56
7,175.00
6,006.51
0.96
0.00
-132.64
2,782.02
1,600.25
2-11/16
741.77
15.52
732.08 Pass - Major Risk
8,650.00
6,709.57
7,150.00
5,985.93
0.96
0.00
-131.42
2,771.90
1,590.31
2-11/16
763.06
15,55
753.34 Pass - Major Risk
8,660.00
6,709.61
7,100.00
5,944.80
0.98
0.00
-127.83
2,751.46
1,570.53
2-11/16
806.06
15.64
796.21 Pass - Major Risk
8,660.00
6,709.61
7,125.00
5,965.36
0.98
0.00
-127.87
2,761.71
1,580.40
2-11/16
784.50
15.64
774.65 Pass - Major Risk
8,670.00
6,709.66
7,050.00
5,903.78
1.00
0.00
-124.37
2,730.80
1,550.78
2-11116
849.50
15.72
839.53 Pass - Major Risk
8,670.00
6,709.66
7,075.00
5,924.28
1.00
0.00
-124.34
2,741.15
1,560.66
2-11116
827.74
15.72
817.77 Pass - Major Risk
8,676.35
6,709.69
7,025.00
5,883.32
1.02
0.00
-122.21
2,720.38
1,540.89
2-11116
871.37
15.78
861.31 Pass - Major Risk
8,680.00
6,709.70
7,000.00
5,862.89
1.02
0.00
-121.00
2,709.92
1,530.98
2-11/16
893.32
15.81
883.22 Pass - Major Risk
8,685.01
6,709.72
6,975.00
5,842.51
1.04
0.00
-119.34
2,699.40
1,521.03
2-11/16
915.34
15.86
905.18 Pass - Major Risk
8,690.00
6,709.74
6,925.00
5,801.91
1.05
0.00
-117.82
2,678.21
1,500.96
2-11/16
959.58
15.90
949.34 Pass - Major Risk
8.690.00
6,709.74
6,950.00
5,822.18
1.05
0.00
-117.71
2,688.83
1,511.02
2-11/16
937.43
15.90
927.20 Pass - Major Risk
8,700.00
6,709.79
6,875.00
5,761.54
1.07
0.00
-114.62
2,656.79
1,480.67
2-11/16
1,004.01
15.98
993.64 Pass - Major Risk
8,700.00
6,709.79
6,900.00
5,781.70
1.07
0.00
-114.47
2,667.53
1,490.83
2-11/16
981.77
15.98
971.41 Pass - Major Risk
8,704.34
6,709.80
6,850.00
5,741.43
1.08
0.00
-113.26
2,645.98
1,470.49
2-11/16
1,026.33
16.02
1,015.90 Pass - Major Risk
8,710.00
6,709.83
6,800.00
5,701.35
1.10
0.00
-111.63
2,624.13
1,450.08
2-11116
1,071.15
16.11
1,060.65 Pass - Major Risk
8,710.00
6,709.83
6,825.00
5,721.37
1.10
0.00
-111.45
2,635.09
1,460.29
2-11116
1,048.71
16.11
1,038.21 Pass - Major Risk
8,714.33
6,709.84
6,775.00
5,681.40
1.11
0.00
-110.31
2,613.06
1,439.88
2-11116
1,093.66
16.18
1,083.09 Pass - Major Risk
8,720.00
6,709.87
6,700.00
5,621.95
1.12
0.00
-108.93
2,578.95
1,409.43
2-11116
1,161.56
16.26
1,150.90 Pass - Major Risk
8,720.00
6,709.87
6,725.00
5,641.69
1.12
0.00
-108.73
2,590.47
1,419.55
2-11/16
1,138.86
16.26
1,128.21 Pass - Major Risk
8,720.00
6,709.87
6,750.00
5,661.51
1.12
0.00
-108.52
2,601.84
1,429.70
2-11/16
1,116.24
16.26
1,105.59 Pass - Major Risk
CC - Min Centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation
101812016 1:44:12PM Page 3 COMPASS 5000.1 Build 74
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TRANSMITTAL LETTER CHECKLIST
WELL NAME: KA(A, l f+—O ?All (_ 6UISki�)
PTD: -21( - o12
Development /Service _ Exploratory _ Stratigraphic Test _ Non -Conventional
FIELD: 1�4�1 /in`� I`J�i POOL: t
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK
OPTIONS
TEXT FOR APPROVAL LETTER
ULTI
The permit is for a new wellbore segment of existing well Permit
LATERAL
No. 216 —Off , API No. 50- 021 - 10 Z55 -_aL- (ZS .
(If last two digits
}.should continue to be reported as a function of the original
in API number are
API number stated above.
between 60-69)
% � ` W k1odz"
In cordance 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 onpermit).
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) 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#:2160120 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type
Well Name: KUPARUK RIV UNIT 1 H-07AL1 Program SER Well bore seg
SER / 1WINJ GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal
Administration
17
Nonconven. gas conforms to AS31.05.0300.1.A),0.2.A-D)
NA
1
Permit fee attached
NA
2
Lease number appropriate
Yes
Entire Well lies within ADL0025639.
3
Unique well name and number
Yes
KRU 1 H-07AL1
4
Well located in a defined pool
Yes
Kuparuk River Oil Pool, Kuparuk Riv Oil-490100, governed by Conservation Order No. 432D
5
Well located proper distance from drilling unit boundary
Yes
Conservation Order No. 432D has no interwell spacing restrictions. Wellbore will be more than 500' from
6
Well located proper distance from other wells
Yes
an external property line where ownership or landownership changes. As proposed, well will
7
Sufficient acreage available in drilling unit
Yes
conform to spacing requirements.
8
If deviated, is wellbore plat included
Yes
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
PKB 10/11/2016
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
Area Injection Order No. 2C - Kuparuk River Unit
15
All wells within 114 mile area of review identified (For service well only)
Yes
KRU 1 H-07, KRU 1 H-07A, KRU 1 H-14
16
Pre -produced injector: duration of pre -production less than 3 months (For service well only)
Yes
18
Conductor string provided
NA
Conductor set in KRU 1 H-07
Engineering
19
Surface casing protects all known USDWs
NA
Surface casing set in KRU 1H-07
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
No
26
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 pres is 3721 psi(10.9 ppg EMW); will drill w/ 9.6 ppg EMW and maintain overbal w/ MPD
VTL 10/12/2016
29
BOPEs, do they meet regulation
Yes
30
BOPE press rating appropriate; test to (put psig in comments)
Yes
MPSP is 3065 psig; will test BOPs to 3500 psig
31
Choke manifold complies w/API RP-53 (May 84)
Yes
32
Work will occur without operation shutdown
Yes
33
Is presence of H2S gas probable
Yes
H2S measures required
34
Mechanical condition of wells within AOR verified (For service well only)
Yes
AOR complete; mechanical condition verified
35
Permit can be issued w/o hydrogen sulfide measures
No
Wells on 1H-Pad are H2S-bearing. H2S measures required.
Geology
36
Data presented on potential overpressure zones
Yes
Expected reservoir pressure is 10.9 ppg EMW; well will be drilled using 9.6 ppg mud, a
Appr Date
37
Seismic analysis of shallow gas zones
NA
coiled -tubing rig, and managed pressure drilling technique to control formation pressures.
PKB 10/11/2016
38
Seabed condition survey (if off -shore)
NA
39
Contact name/phone for weekly progress reports [exploratory only]
NA
Geologic
Engineering Public
Commissioner: Date:
Commissioner: Date Commissioner Date
DTS 161 l z/ %4
jw
� ' ` /a-'/2 —/X
THE STATE Alaska Oil and Gas
®fALASKA Conservation Commission
GOVERNOR BILL WALKER
Daniel Venhaus
CTD Manager
ConocoPhillips Alaska, Inc.
P.O. Box 100360
Anchorage, AK 99510-0360
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.00gcc.olaska.gov
Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 1H-07AL1
ConocoPhillips Alaska, Inc.
Permit to Drill Number: 216-012
Surface Location: 768' FNL, 787' FEL, SEC. 33, T12N, RI OE, UM
Bottomhole Location: 1938' FNL, 4439' FEL, SEC. 27, T12N, R10E, UM
Dear Mr. Venhaus:
Enclosed is the approved application for permit to redrill the above referenced service well.
The permit is for a new wellbore segment of existing well Permit No. 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,
Cathy . Foerster
Chair
DATED this 22 day of January, 2016.
STATE OF ALASKA i
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
RECEIVED
JAN 14 2016
1 a. Type of Work:
1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑
1 c. Specify if wall is proposed for:
Drill ❑ Lateral ❑✓
Stratigraphic Test ❑ Development - Oil ❑ Service - Winj Q• Single Zone Q
Coalbed Gas ❑ Gas Hydrates ❑
Redrill ❑ Reentry ❑
Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑
Geothermal ❑ Shale Gas ❑
2. Operator Name:
5. Bond: Blanket Q Single Well ❑
11 - ell Name and Number:
ConocoPhillips Alaska Inc
Bond No. $ - 5 Zf
,�,le, KRU 1H-07AL1 .
3. Address:
6. Proposed Depth:
12. Field/Pool(s):
P.O. Box 100360 Anchorage, AK 99510-0360
MD: 9250' ' TVD 6659'
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:
66 FNL, 4154' FEL, Sec. 27, T12N, R10E, UM
ALK 464
3/1/2016
Total Depth:
9. Acres in Property:
14. Distance to Nearest Property:
1938' FNL, 4439' FEL, Sec 27, T12N, R10E, UM
2560
6990'
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: 730' 1 H-14
16. Deviated wells: Kickoff depth: 8254' feet
17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 101 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
1420'
7830'
6650'
9250' .
6659'
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 11
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', 5534' - 6555', 5713' - 672U & 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
22. 1 hereby certify that the foregoing is true and the procedure approved herein will not —
be deviated from without prior written approval. Contact Jason Burke @ 265-6097
Email iason.burke(cDcop.com
Printed Name Daniel Venhaus Title CTD Manager
Signature Phone 265-6120 Date �— ILI- f
Commission Use Only
Permit to Drill
�! (��` �1
API Number: /
Permit Approval
See cover letter for other
Number:
500�'7 c/�J
ate: ` a�
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: Samples
191" � f to 35i/U 5 req'd: Yes ❑ No6 Mud log req'd: Yes❑ No�
A."- V ro/No❑
C/f ar /fir'- yy /-D Z5eA2FAAz�measures: Yes No El Directional svy req'd: Yes "'LJ
�❑
f� tY W� tnt SStd /in I-�7A Spacing excepQon req'd: Yes ❑ No[ Inclination -only svy req'd: Yes ;WN,
c` y _J CC �!G Post initial injection MIT req'd: Yes
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:O ——
!� L / 27-l�
Form 10-401 (Revised 1112015) This permit is valid for 24 months from the date of approval (20 AAC 25.005(g))
ORIGINAL
Submit Form and
Attachments in Duplicate
ConocoPhillips
Alaska
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
January 13, 2016
Commissioner - State of Alaska
Alaska Oil & Gas Conservation Commission
333 West 7th Avenue Suite 100
Anchorage, Alaska 99501
Dear Commissioner:
ConocoPhillips Alaska, Inc. hereby submits an application for permits to drill a two lateral well out of the Kuparuk
well 1 H-07 using the coiled tubing drilling rig, Nabors CDR2-AC.
The work is scheduled to begin in March 2016. The CTD objective will be to drill three laterals (1 H-07A & 1 H-
07AL1), 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
— Detailed Summary of Operations
— Directional Plans
— Current Schematic
— Proposed Schematic
If you have any questions or require additional information please contact me at 907-265-6097.
Sincerely,
Jason Burke
Coiled Tubing Drilling Engineer
907-231-4568
KRU IH-07 CTD Summary for M22in2 Sundry (10-403)
Summary of Operations:
Well KRU 1H-07 is a Kuparuk A-sand/C-sand injection (service) well equipped with 3'/z" tubing and
7" production casing. The CTD laterals drilled from the injector well will target the Kuparuk A -sands
in fault blocks adjacent and corresponding to the wells current locations. KRU 1H-07 is planned for 2
laterals or 4,245' of total hole in the A -sand reservoir.
Prior to drilling, the existing C-sand perforations in 1H-07 will be plugged with cement, and the A -sand
will need to be permanently abandoned with sand and cement on top of a plug set in the 27/8" tubing tail.
The purpose of this is to provide a means to kick out of the 3-1/2" and 7" casing and also to isolate the
C-sand and A -sand perfs from the newly drilled laterals in the A -sand. ConocoPhillips requests a
variance from the requirements of 20 AAC 25.112(c)(1) to plug the A/C -sand perfs in this manner.
Cement will be laid in from the tubing tail plug at 7910' MD and then squeezed into the C 1 & C3/C4
perforations through the AVA'ported nipples located at 7781' & 7874' MD. The cement will be milled
out using CT down to 7857' MD which will leave a 32' cement plug on top of the sand and plug in the
2%" tailpipe. A mechanical whip -stock will then be set at 7842' MD to perform the CT sidetrack for
1H-07A & AL1.
CTD Drill and Complete 1H-07 Laterals: April 2016
Pre-CTD Work
1. RU slick -line
i. Set plug in D-nipple at 7899` MD.
ii. Dump 10' of sand on top of tubing tail plug
2. RU coil
i. Cement squeeze C-sand perforations, and fill 3-1/2" x 7" annuli allow cement to
harden.
ii. Mill down to 7857' MD
iii. Under ream down to 7857' MD
iv. Pressure test cement.
3. RU E-Line
i. Dummy WS drift to 7842'
ii. Run and set WS at 7842' MD.
4. Prep site for Nabors CDR2-AC, including setting BPV
Rig Work
1. MIRU Nabors CDR2-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test.
2. 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 8,254' MD
3. 1H-07AL1 Lateral (A4 sand south)
a. Kick off of the aluminum billet at 8,254' MD
b. Drill 2.74" x 3.00" bi-center lateral to TD of 9,250' MD
Page 1 of 2 1/11/2016
c. Run 2%" slotted liner from TD up to 7830' MD, inside the 3'/2" tubing. Liner
includes a swell packer at 7832' MD and a liner -top packer inside the 3'/z" tubing.
4. Freeze protect. Set BPV, ND BOPE. RDMO Nabors CRD2-AC.
Post -Rig Work
1. Pull BPV
2. Obtain static BHP. Install GLV's.
3. Produce well for more than 30 days
4. Re -sundry to turn back to injection
Page 2 of 2 1/11/2016
Kuparuk CTD Laterals MdQ0�7f9 A,d A5KA
"# 1 H-O7A & AU CIS
Application for Permit to Drill Document 2AC
1.
Well Name and Classification...........................................................................................................2
(Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b))......................................................................................................................2
2.
Location Summary.............................................................................................................................2
(Requirements of 20 AAC 25.005(c)(2))...................................................................................................................................................... 2
3.
Blowout Prevention Equipment Information...................................................................................2
(Requirements of 20 AAC 25.005(c)(3)).....................................................................................................................................................2
4.
Drilling Hazards Information and Reservoir Pressure....................................................................2
(Requirements of 20 AAC 25.005(c)(4)).....................................................................................................................................................2
5.
Procedure for Conducting Formation Integrity tests.....................................................................2
(Requirements of 20 AAC 25.005(c)(5))......................................................................................................................................................2
6.
Casing and Cementing Program......................................................................................................3
(Requirements of 20 AAC 25.005(c)(6))......................................................................................................................................................3
7.
Diverter System Information.............................................................................................................3
(Requirements of 20 AAC 25.005(c)(7))...................................................................................................................................................... 3
8.
Drilling Fluids Program.....................................................................................................................3
(Requirements of 20 AAC 25.005(c)(8))......................................................................................................................................................3
9.
Abnormally Pressured Formation Information...............................................................................4
(Requirements of 20 AAC 25.005(c)(9))......................................................................................................................................................4
10.
Seismic Analysis................................................................................................................................4
(Requirements of 20 AAC 25.005(c)(10))....................................................................................................................................................4
11.
Seabed Condition Analysis...............................................................................................................4
(Requirements of 20 AAC 25.005(c)(11))....................................................................................................................................................4
12.
Evidence of Bonding.........................................................................................................................4
(Requirements of 20 AAC 25.005(c)(12))....................................................................................................................................................4
13.
Proposed Drilling Program...............................................................................................................4
(Requirements of 20 AAC 25.005(c)(13))....................................................................................................................................................4
Summaryof Operations.................................................................................................................................................. 4
LinerRunning.................................................................................................................................................................. 6
14.
Disposal of Drilling Mud and Cuttings.............................................................................................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........................................................................................................ 7
Attachment 2: Current Well Schematic for 1 H-07........................................................................................................... 7
Attachment 3: Proposed Well Schematic for 1 H-07A & AL1.......................................................................................... 7
Page 1 of 7 January 11, 2016
PTD Application: 1 H-07A & AL1
1. Well Name and Classification
(Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b))
The proposed laterals described in this document are 1 H-07A & 1-1. 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 1H-07A & L1.
3. Blowout Prevention Equipment Information
(Requirements of 20 AAC 25.005 (c)(3))
Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR2-AC.
BOP equipment is as required per 20 AAC 25.036 for thru-tubing drilling operations.
— Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 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 January 11, 2016
PTD Application: 1 H-07A & AL1
6. Casing and Cementing Program
(Requirements of 20 AAC 25.005(c)(6))
New Completion Details
Lateral
Liner Top
Liner Btm
Liner Top
Liner Btm
Liner Details
Name
MD
MD
TVDSS
TVDSS
1 H-07A
8254'
11100,
6481'
6582'
2%", 4.7#, L-80, ST-L slotted liner;
aluminum billet on top
2%", 4.7#, L-80, ST-L slotted liner;
1 H-07ALl
7830'
9250'
6650'
6659'
with a swell packer in the 'B' shale
and a liner top packer on top
Existing Casing/Liner Information
Category
OD
Weight
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'
7662'
0'
6413'
10160
10530
7. Diverter System Information
(Requirements of 20 AAC 25.005(c)(7))
Nabors CDR2-AC will be operating under 20 AAC 25.036, for thru-tubing drilling operations. Therefore, a
diverter system is not required.
8. Drilling Fluids Program
(Requirements of 20 AAC 25.005(c)(8))
Diagram of Drilling System
A diagram of the Nabors CDR2-AC mud system is on file with the Commission.
Description of Drilling Fluid System
— Window milling operations: Chloride -based RoVis 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 1 H-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
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.
Page 3 of 7 January 11, 2016
PTD Application: 1 H-07A & AL1
Pressure at the 1 H-07 Window (7842' MD, 6566' TVDSS) Using MPD
Pumps On
(1.5 bpm)
Pumps Off
A -sand Formation Pressure 10.9
3721 Psi
3721 psi
Mud Hydrostatic 9.6
3278 psi
3278 psi
Annular friction i.e. ECD, 0.060 si/ft
471 psi
0 psi
Mud + ECD Combined
3748 psi
3278 psi
(no choke pressure)
(overbalanced
(underbalanced
-27psi)
-444psi)
Target BHP at Window (11.8 p)
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 1H-07 is a Kuparuk A -sand injection well equipped with 3'/2" tubing and 7" production casing.
Two laterals will be drilled to the south of the parent well with the laterals targeting the A4 sand. A thru-
tubing whip -stock will be set inside the 3 %2" liner at the planned kickoff point of 7842' MD to drill both
laterals.
The 1 H-07A southern sidetrack will exit through the 3'/2" 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 8254'
MD with an aluminum billet for kicking off the 1H-07AL1 lateral.
The 1H-07AL1 will drill south to a TD of 9250' MD targeting the A4 sand. It will be completed with 2%"
slotted liner from TD up to 7830' MD with a swell packer in the `B' shale and a liner top production packer
on top.
Page 4 of 7 January 11, 2016
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 C 1 perfs
3. RU slick -line
a. Pull AVA isolation sleeve at 7781 ` MD allowing the C1 & 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
Rig 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 8,254' MD
1H-07AL1 Lateral (A4 sand south)
a. Kick off of the aluminum billet at 8,254' MD
b. Drill 2.74" x 3.00" bi-center lateral to TD of 9,250' MD
c. Run 2%" slotted liner with swell packer at 7832' MD from TD up to 7830' MD, inside the 3'/2"
tubing with a liner top packer
Freeze protect. Set BPV, ND BOPE. RDMO Nabors CRD2-AC.
Post -Rig Work
1. Pull BPV
2. Obtain static BHP. Install GLV's.
3. Produce well for more than 30 days
4. Re -sundry to turn back to injection
Pressure Deployment of BHA
The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves
on the Christmas tree. MPD operations require the BHA to be lubricated under pressure 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.
Page 5 of 7 January 11, 2016
PTD Application: 1 H-07A & AL1
— 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 2g/" slotted liner, a joint of 2%" non -slotted tubing will be standing by for emergency
deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a
deployment drill with this emergency joint on every slotted liner run. The 2'/" rams will provide
secondary well control while running 2'/" liner.
14. Disposal of Drilling Mud and Cuttings
(Requirements of 20 AAC 25.005(c)(14))
• No annular injection on this well. .
• All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal.
• Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1 R-18
or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable.
• All wastes and waste fluids hauled from the pad must be properly documented and manifested.
• Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200).
15. Directional Plans for Intentionally Deviated Wells
(Requirements of 20 AAC 25.050(b))
— The Applicant is the only affected owner.
— Please see Attachment 1: Directional Plan
— Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run.
— MWD directional, resistivity, and gamma ray will be run over the entire openhole section. .
— Distance to Nearest Property Line (measured to KPA boundary at closest point)
Lateral Name
Distance
1 H-07A
6990'
1 H-07AL1
6990'
Page 6 of 7 January 11, 2016
PTD Application: 1 H-07A & AL1
- Distance to Nearest Well within Pool
Lateral Name
Distance
Well
1 H-07A
1 H-14
1080'
1 H-07ALl
1 H-14
730'
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 wells
• See Attached AOR sheet
17. Attachments
Attachment 1: Directional Plans for 1 H-07A & AU
Attachment 2: Current Well Schematic for 1H-07
Attachment 3: Proposed Well Schematic for 1H-07A & AL1
Page 7 of 7 January 11, 2016
Area of Review Well Name
Topof A -sand
Topof A-SaMOH
Top of Cement
Topof Cement
Ce Top Mment
PM
API
WELL NAME
STATUS
Oil Paol(MD)
P-1POSS)
(MD)
(TVD65)
Determined By
Heservolr Status
Zonal Isolation
femeM Operations Summary
Mechaniollntegrity
Pertscementedand
State witnessed passing MIT
182-OM
5"29-20755
iH-07
Suspended
7696'
6901' .
6850'
slisV •
CBL
abandoned
Packer @ 7960' MD
962sas Class G cement
IA to 2820 psi on 8111/13
192-131
50-02922315
2H-16
Producing
7185'
6632' .
6300'
5798'
CET
Perts open for
packer@680A'MD
5905ss Class G cement
SI-TIFL Passed. Initial T/I/0=
prod-0,
si IM/1250/780 on 5/30115
193-052
50023-59
1H-14
Producing
11M
655A' •
8330'
6612'
CET
Perfsppen
packer@8172'MD
520—Class G cement
with
Compepassin
prodeaion
TIFL
passing TlFL
KUP INJ 1H-07
ConocoPhillIPS
/lleh$1(Li, Inc,
'
...
Well Attributes
Max Angle & MD TD
lWellbore API/UWI Fieltl Name Wellbom Status
500292075500 KUPARUK RIVER UNIT INJ
ncl (-) MD tkKB) Act
53.77 5,200.00
St. (ftKB)
8,300.0
lComment M25 (ppm) Date
SSSV: NIPPLE
Annotation End Date
Last WO: 11111I2007
KB-Grd (ft) Rig Release Date
35.491 6/16/1982
1H-07,11111120138.47:34 PM
enea emote a�tua
Annotation Depth (ftKB) End Date
Last Tag: SLIM 8,079.0 11/3Y2013
Annotation Last Motl By Entl Date
Rev Reason: GLV C/O, TAG, RESET BPC lehallf 11111/2013
HANGER; 24.9
CONDUCTOR; 30.0.80.0
NIPPLE; 503.4
h
SURFACE; 29.0-2,365.0
GAS LIFT; 7,572.0
NIPPLE; 7,620.0
SEAL ASSY; 7,658.4
PBR; 7,661.E
PACKER; 7,675.4
INJECTION; 7,688.7
IPERF; 7,696.0-7,755.0-
SLEEVE; 7,787.3
NIPPLE; 7,781.3
SEAL ASSY; 7,788A
PACKER;7,789.0
INJECTION; 7,8D0.7
IPERF; 7,805.0-7,830.0--�
SLEEVE; 7,874.2
NIPPLE; 7,874.2
SEAL ASSY; 7.879.7
PACKER; 7,880.1
SBE;7,883.e
NIPPLE; 7.898.9
WLEG; 7,910.1
RPERF; 8,075.041,023.0
IPERF; 8,015.0-8,023.0�
RPERF; 8,031.018,051.0
PERF; 8,031.Od,051.0�
FISH; 8,162.0
PRODUCTION; 29.0-8,274.0
_
-
r
Casing Strings
Casing Description OD
CONDUCTOR
(in)
16
ID (In)
15.060
Top (ftKB)
30.0
Set Depth (ftKB)
80.0
Set Depth (TVD)...
80.0
WtlLen (I...
65.00
Grade
H-40
Top Thread
WELDED
Casing Description OD
PRODUCTION
(in)
7
I ID (In)
6.276
Top (ftKB)
29.0
Set Depth (ftKB
8,27)4.0
Set Depth ITVD)...
6,936.9
WtlLen 11-•.
26.00
Grade
K-55
Top Thread
BTC
Tubing Strings
Tubing Descripton String Ma... ID (in) Top (ftKB) Set Depth (tL. Set Depth (TVD) (... Wt (INft) Grade Top Connection
TUBING 2007 WO 3 12 2.992 24.9 7,662.0 6,413.2 9.30 L-80 EUE 8RD
Completion Details
Top (ftKB)
Top (ND) (HKB)
Top Ind (°)
Item Des
Co.
Nominal ID
(in)
24.9
24.9
0.15 HANGER
CAMERON GEN 4 TUBING HANGER
3.500
503.4
503.3
0.49 NIPPLE
CAMCO DS NIPPLE
2.875
7,620.0
6,377.7
32.41 NIPPLE
CAMCO DS NIPPLE
2.813
7.658.4
6,410.1
32.37 SEAL
ASSY
LOCATOR SEAL ASSEMBLY
3.000
Tubing Description String
TUBING 1994 WO 41/2
3.5x2.875
Ma...
ID (in)
2.992
Top (ftKB)
7,661.E
Set Depth (R. Set
7,910.7
Depth (ND) (.., wt
6,624.2
(INk) Grade
9.30 L-80
Top
EUE8RDMCD
Connection
Completion Details
Top (ftKB)
Top (TVD) (ftKB)
Top Incl (°)
Item Des
Com
Nominal ID
(in)
7.661.6
6,412.8
32.36 PBR
BAKER 80-40 PBR w/ 10' STROKE
3.000
7,675.4
6.424.5
32.35 PACKER
BAKER'FHL' RETRIEVABLE PACKER
2.992
7,702.9
6,447.8
32.31 BLAST
JTS
STEEL BLAST JOINTS
2.992
7,781.3
6,514.0
32.03 NIPPLE
AVA BPL PORTED NIPPLE
2.812
7,788.1
6,519.8
32.01 SEAL
ASSY
BAKER KBG-22 ANCHOR SEAL ASSY
3.000
7,789.0
6,520.E
32.01 PACKER
BAKER 8D40'SAB-3' PERMANENT PACKER
3.250
7,815.0
6,542.7
31.89 BLAST
JTS
STEEL BLAST JOINTS
2.992
7,874.2
6,593.0
31.61 NIPPLE
AVA BPL PORTED NIPPLE
2.750
7,876.9
6,595.3
31.60 XO
Reducing
CROSSOVER 3.5 x 2.875. ID 2.441, #6.5, L-80,
EUE8RDMOD
2.875
7,879.1
6,597.2
31.58 SEAL
ASSY
BAKER 80-32 GBH-22 LOCATOR SEAL ASSEMBLY
2.437
7,880.1
6,598.1
31.58 PACKER
BAKER 84-32 MODEL'D' PERMANENT PACKER
3.250
7,883.8
6,601.2
31.56 SBE
SEAL BORE EXTENSION
3.250
7,898.91
6,614.1
31.49 NIPPLE
OTIS'XN' NIPPLE
2.250
7,910.2
6,623.7
31.43 1 WLEG
BAKER WIRELINE ENTRY GUIDE
2.441
Other In Hole
(Wireline retrievable plugs, valves, pumps, fish, etc.)
Top (ftKB)
Top(TVD)
(ftKB)
Topincl
(-)
Des
Com
Run Date
ID (in)
7,781.3
6,514.0
32.03
SLEEVE
SET 2.81" BPC = COMMINGLING OR OPEN
11/3/2013
2.310
7,874.2
6,593,0
31.61
1 SLEEVE
SET 2.75" BPI = ISOLATION OR CLOSED
5/6/2009
2.310
8,192.0
6,839.7
29.83
FISH
Vann Gun Left in Hole after original perf
6/1611982
Perforations & Slots
Top (ftKB)
Bt. (ftKB)
Top (TVD)
(ftKB)
Bum (ND)
(ftKB)
Zone
Date
Shot
Dens
(shotsR
t)
Type
Com
7,696.0
7,755.0
6,441.9
6,491.8 C4,
07
C-3, 1H- 620/1988
8.0
IPERF
2 1/8" EnerJet; 30 deg
ph
j�
1
7,805.0
7,830.0
6,534.2
6,555.4 C-1,
1H-07
UNIT B, 620/1988
4.0
IPERF
2 1/8" EnerJet
8,015.0
8.023.0
6,713.4
6,720.2 A-5,
1 H-07 2/16/2007
6.0
RPERF
21/8" EnerJet, 0 deg
phase
8,015.0
8,023.0
6.713.4
6,720.2 A-5,
1H-07 620/1988
12.0
IPERF
21/8" EnerJet
8,031.0
8,051.0
6,727.1
6,744.2 A-4,
1H-07 2062007
6.0
RPERF
21/8" EnerJet, 0 deg
phase
8,031.0
8,051.0
6,727.1
6,744.2 1 A-4,
1H-07 6/20/1988
1 12.0
IPERF
21/8" EnerJet
Mandrel Inserts
St
ad
on No Top (ftKB)
Top (TVD)
(ftKB)
Make
Model
OD (in)
Se,
Valve
Type
Latch
Type
Port Size
(in)
TRO Run
(psi)
C
o
Run Data m
1 7,572.0
6,337.2
CAMCO KBMG
1 GAS LIFT
DMY
BK
0.000
0.0 11I1512007
2 7,688.7
6,435.7
CAMCO MMM
11/2
INJ
DMY
RK
0.000
0.0 525/1994
3 7,800.7
6,530.5
CAMCO MMM
11/2
INJ
CV
RK
0.188
0.0 11/3/2013
Notes: General & Safety
End Date
Annotation
5/24/1994
NOTE: WORKOVER
2I17/2004
NOTE: WAIVERED WELL: TxIA COMMUNICATION
3/2/2011
NOTE: View Schematic w/ Alaska Schematic9.0
327/2012
NOTE: The 2007 tubing detail did not include the RKB; adjusted for RKB, but need verifying
ConocoPhillips
Project: Kuparuk Rl— Unit
Site: Kuper It 1H Pad
tiaGnetrc Ten Nfi
Mapnnic rwa
WELLSORE DETAILS: IH-07A
REFERENCE[WOPM4TICN
Parenl Wellhore: 1H-07
Do ate (NE) Rero'a'en: Wel 1H4D7. aWra'
Well: 1H-07
summn. s>asran*
Tie on MD: 7800.00
V,"(M) Rekrenrn: Mean Sea Leal
Wellbore: 1 H-07A
Plan: 1H-07A_Wp05(1H-07T1H-07A)
ooarok arm'
we ulnolc
m BCGu1ot5
Semen (v5) Refeence: SIM- IO.ODN, OOOE)
Mrawred DEN Reference: 7HD7gas.oDan (tH07)
IM7!0
Celarletionf.— L5NOO.e
West( -)/East(+) (250 usft/in)
FIrl.I
BAKER
HUGHES
NADConversion
Kuparuk River Unit
Kuparuk 1 H Pad
1 H-07
1 H-07AL1
Plan: 1 H-07AL1_wp04
Standard Planning Report
07 January, 2016
we pp�_-
JA as
BAKER
HUGHES
Database:
EDM Alaska ANC Prod
Company:
NADConversion
Project:
Kuparuk River Unit
Site:
Kuparuk 1 H Pad
Well:
1 H-07
Wellbore:
1 H-07AL1
Design:
1 H-07AL1_wp04
ConocoPhillips
Planning Report
Local Co-ordinate Reference:
Well 1 H-07
TVD Reference:
Mean Sea Level
MD Reference:
1 H-07 @ 85.00usft (1 H-07) -
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
rG.I
BAKER
HUGHES
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" Grid Convergence: 0.38 °
Well 1 H-07
Well Position +Nl-S 0.00 usft Northing: 5,979,935.13 usft Latitude: 70° 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 1 H-07ALl
Magnetics Model Name Sample Date Declination Dip Angle Field Strength
(1 (°) (nT)
BGGM2015 4/1/2016 18.60 81.00 57,498
Design 1 H-07AL1_wp04
Audit Notes:
Version: Phase: PLAN Tie On Depth: 8,254,00
Vertical Section: Depth From (TVD) +N/-S +E/-W Direction
(usft) (usft) (usft) (°)
0.00 0.00 0.00 350.00
Plan Sections
Measured
TVD Below
Dogleg
Build
Turn
Depth
Inclination
Azimuth
System
+N/-S
+E/-W
Rate
Rate
Rate
TFO
(usft)
(°)
(I
(usft)
(usft)
(usft)
(°/100usft)
(°/100usft)
(°/loousft)
(°) Target
8,254.00
76.78
262.94
6,649.97
3,264.30
1,804.71
0.00
0.00
0.00
0.00
8,324.00
101.18
276.78
6,651.21
3,264.16
1,735.42
40.00
34.86
19.78
30.00
8,394.00
86.62
300.82
6,646.39
3,286.56
1,670.01
40.00
-20.81
34.33
120.00
8,530.00
88.03
355.26
6,653.26
3,397.53
1,600.82
40.00
1.04
40.03
90.00
8,630.00
89.85
2.02
6,655.11
3,497.42
1,598.46
7.00
1.82
6.76
75.00
8,730.00
94.35
7.40
6,651.45
3,596.95
1,606.65
7.00
4.49
5.37
50.00
8,830.00
90.83
13.46
6,646.93
3,695.14
1,624.73
7.00
-3.52
6.06
120.00
8,900.00
88.38
9.21
6,647.42
3.763.75
1,638.48
7.00
-3.50
-6.06
240.00
9,075.00
88.41
356.96
6.652.33
3,938.10
1,647.87
7.00
0.02
-7.00
270.00
9,250.00
87.39
344.74
6,658.76
4,110.43
1,620.12
7.00
-0.59
-6.98
265.00
11712016 11:39:OOAM Page 2 COMPASS 5000.1 Build 74
s-1 ConocoPhillips MAP aI
Ct)C1C3c&hilfips Planning Report BAKER
HUGHES
Database:
EDM Alaska ANC Prod
Local Co-ordinate Reference:
Well 1 H-07
Company:
NADConversion
TVD Reference:
Mean Sea Level
Project:
Kuparuk River Unit
MD Reference:
1 H-07 @ 85.00usft (1 H-07)
Site:
Kuparuk I Pad
North Reference:
True
Well:
1 H-07
Survey Calculation Method:
Minimum Curvature
Wellbore:
1 H-07AL1
Design:
1H-07AL1 wp04
Planned Survey
Measured
TVD Below
Vertical
Dogleg
Toolface
Map
Map
Depth Inclination
Azimuth
System
+W-S
+E/-W
Section
Rate
Azimuth
Northing
Easting
(usft)
(°)
0
(usft)
(usft)
(usft)
(usft)
(°/100usft)
(°)
(usft)
(usft)
8,254.00
76.78
262.94
6,649.97
3,264.30
1,804.71
2,901.32
0.00
0.00
5,983,210.98
551,343.45
TIP/KOP
8,300.00
92.82
272.03
6,654.13
3,262.34
1,759.14
2,907.31
40.00
30.00
5,983,208.72
551,297.90
8,324.00
101.18
276.78
6,651.21
3,264.16
1,735.42
2,913.22
40.00
29.17
5,983,210.38
551,274.17
Start 40 dis
8,394.00
86.62
300.82
6,646.39
3,286.56
1,670.01
2,946.64
40.00
120.00
5,983,232.35
551,208.62
3
8,400.00
86.62
303.22
6,646.74
3,289.74
1,664.93
2,950.65
40.00
90.00
5,983,235.49
551,203.52
8,500.00
87.50
343.27
6,652.09
3,368.13
1,606.40
3,038.01
40.00
89.86
5,983,313.48
551,144.47
8,530.00
88.03
355.26
6,653.26
3,397.53
1,600.82
3,067.93
40.00
87.72
5,983,342.84
551,138.71
End 40 dls, Start 7 dis
8,600.00
89.30
360.00
6,654.89
3,467.43
1,597.93
3,137.27
7.00
75.00
5,983,412.71
551,135.35
8,630.00
89.85
2.02
6,655.11
3,497.42
1,598.46
3,166.72
7.00
74.89
5,983,442.71
551,135.68
5
8,700.00
93.00
5.78
6,653.37
3,567.21
1,603.22
3,234.62
7.00
50.00
5,983,512.53
551,139.98
8,730.00
94.35
7.40
6,651.45
3,596.95
1,606.65
3,263.32
7.00
50.09
5,983,542.28
551,143.22
6
8,800.00
91.89
11.64
6,647.64
3,665.87
1,618.21
3,329.17
7.00
120.00
5,983,611.26
551,154.32
8,830.00
90.83
13.46
6,646.93
3,695.14
1,624.73
3,356.87
7.00
120.23
5,983,640.58
551,160.64
7
8,900.00
88.38
9.21
6,647.42
3,763.75
1,638.48
3,422.05
7.00
-120.00
5,983,709.27
551,173.94
8
9,000.00
88.39
2.21
6,650.24
3,863.15
1,648.42
3,518.22
7.00
-90.00
5,983,808.73
551,183.22
9,075.00
88.41
356.96
6,652.33
3,938.10
1,647.87
3,592.12
7.00
-89.80
5,983,883.66
551,182.17
9
9,100.00
88.26
355.21
6,653.06
3,963.03
1,646.17
3,616.97
7.00
-95.00
5,983,908.58
551,180.30
9,200.00
87.67
348.23
6,656.61
4,061.86
1,631.79
3,716.80
7.00
-94.95
5,984,007.30
551,165.27
9,250.00 '
87.39
344.74
6,658.76 •
4,110.43
1,620.12
3,766.65
7.00
-94.70
5,984,055.78
551,153.28
Planned TD at 9250.00
rasing Points
Measured Vertical Casing Hole
Depth Depth Diameter Diameter
(usft) (usft) Name
11,100.00 2 3/8" 2-3/8 3
Plan Annotations
Measured
Vertical
Local Coordinates
Depth
Depth
+N/-S
+E/-W
(usft)
(usft)
(usft)
(usft)
Comment
8,254.00
6,649.97
3,264.30
1,804.71
TIP/KOP
8,324.00
6,651.21
3,264.16
1,735.42
Start 40 dls
8,394.00
6,646.39
3,286.56
1,670.01
3
8,530.00
6,653.26
3,397.53
1,600.82
End 40 dls, Start 7 dis
8,630.00
6,655.11
3,497.42
1,598.46
5
8,730.00
6,651.45
3,596.95
1,606.65
6
8,830.00
6,646.93
3,695.14
1,624.73
7
8,900.00
6,647.42
3,763.75
1,638.48
8
9,075.00
6,652.33
3,938.10
1,647.87
9
9,250.00
6,658.76
4,110.43
1,620.12
Planned TD at 9250.00
11712016 11.,39:00AM Page 3 COMPASS 5000.1 Build 74
Baker Hughes INTEQ MAP aI
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:
1 H-07
Well Error.
0.00 usft
Reference Wellbore
1H-07AL1
Reference Design:
1 H-07AL1_wp04
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 1 H-07AL1_wp04
Filtertype: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA
Depth Range: 8,254.00 to 9,250.O0usft Scan Method: Tray. Cylinder North
Results Limited by: Maximum center -center distance of 1,116.50 usft Error Surface: Elliptical Conic
Survey Tool Program
Date 11712016
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 multlshot
7,800.00
8,254.00 1 H-07A_wp05 (1 H-07A)
MWD
MWD- Standard
8,254.00
9,250.00 1 H-07AL1_wp04 (1 H-07AL1)
MWD
MWD- Standard
Casing Points
Measured Vertical Casing Hole
Depth Depth Diameter Diameter
(usft) (usft) Name () ( )
11,100.00 2 3/8" 2-3/8 3
Summary
Site Name
Offset Well - Wellbore - Design
Kuparuk 1 H Pad
1 H-01 - 1 H-01 - 1 H-01
1 H-05 - i H-05 - 1 H-05
1 H-05 - 1 H-105 - 1 H-105
1 H-06 - 1 H-06 - 1 H-06
1 H-07 - 1 H-07 - 1 H-07
1 H-07 - 1 H-07A - 1 H-07A_wp05
1 H-08 - 1 H-08 - 1 H-08
i H-09 - 1 H-09 - 1 H-09
1 H-10 - 1 H-10 - 1 H-10
i H-11 - 1 H-11 - 1 H-11
1H-12-1H-12-11-1-12
1H-13-11-1-13-11-1-13
1 H-14 - 1 H-14 - 1 H-14
11-1-15-11-1-15-11-1-15
1H-18-11-1-18-11-1-18
1 H-21 - i H-21 - 1 H-21
1 H-22 - 1 H-22 - 1 H-22
Plan: 1 H-104 (formerly 101 and 27) - Plan: 1 H-104
Plan: 1 H-104 (formerly 101 and 27) - Plan:1 H-104
Plan: 1 H-104 (formerly 101 and 27) - Plan:1 H-104
Plan: 1 H-104 (formerly 101 and 27) - Plan:1 H-104
Plan: 1 H-104 (formerly 101 and 27) - Plan,1 H-104
Plan: 1 H-106 (formerly 107 and 28D) - Plan: 1 H-10
Plan: 1 H-107 (formerly 108 and 30E) - Plan: 1 H-10
Plan: 1 H-112 (formerly 106 and 28E) - Plan: 1 H-11
Reference Offset Centre to
Measured Measured Centre
Depth Depth Distance
(usft) (usft) (usft)
8,330.00 7,550.00 539.74
8,274.73 8,275.00 2.37
No -Go Allowable
Distance Deviation Warning
(usft) from Plan
(usft)
11.69
0.66
9,212.89 8,050.00 739.52 246.65
Out of range
Out of range
Out of range
Out of range
533.64 Pass - Major Risk
1.82 Pass - Major Risk
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
544.07 Pass - Major Risk
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
CC - Min centre to center distance or covergent point, SF - min separation factor. ES - min ellipse separation
11712016 10.59:56AM Page 2 COMPASS 5000.1 Build 74
Project: Kuparuk River Unit
e�i,=121; I...
WELLBORE DETAILS: iH-07AL7 REFERENCE
1NMIVMTION
Parent Wei bore: 1H-07A C dnala(N/)Raf..
Wd1Hd7,T..Noth
Site: Kuparuk 1H Pad
a xr,eu
was
ConoeoPhillips
Well: 1H-07
Wellbore: 1H-07AL7
sN.opsirs7 w,
eiaa
v ,.I(7 )Rd.
Tie on MD. 8254.00 Sedlov(VS)Rde
.uean seaLM
Slot-(OMN,MQ
BAKER
Plan: 1H-07AL1 wp04(1H-0711Hfi7AL1)
Mao 'BGG Nt
Mra ,.)e.Rd.
Cakuh4m Mtll,od
1HLI@a u.(WTf
Mnmum Curvalve
HUGNES
WELL DETAILS: 1H-07
4400
+N/-S +E/-W Northing Easting Latitude
Longitude
4300
0.00 0.00 5979935.13 549560.55 70' 21' 21.476 N 149°
35' 51,058 W
4200
Sec MD Inc Azi TOSS -0-S +E/-W Dleg TFace VSect
Annotation
PIernod
TI
092
.00
1 8254'00 76.78 262.94 6649.97 3264.30 1804.71 0.00 0.00 2901.32
TIP/KOP
9100
3-07/1
-07A
1
2 8324'00 101.18 276.78 6651.21 3264.16 1735.42 40.00 30.00 2913.22
Start 40 dls
3 8394.00 86.62 300.82 6646.39 3286.56 1670.01 40.00 120.00 2946.64
3
4000
4 8530.00 88.03 355.26 6653.26 3397.53 1600.82 40.00 90.00 3067.93
End 40 d1s, Start 7 dls
5 8630.00 89.85 2.02 6655.11 3497.42 1598.46 7.00 75.00 3166.72
5
C3900
6 8730.00 94.35 7.40 6651.45 3596.95 1606.65 7.00 50.00 3263.32
7 8830.00 90.83 13.46 6646.93 3695.14 1624.73 7.00 120.00 3356.87
6
7
a36�
8 8900.00 88.38 9.21 6647.42 3763.75 1638.48 7.00 240.00 3422.05
8
9 9075.00 88.41 356.96 6652.33 3938.10 1647.87 7.00 270.00 3592.12
9
23700
I.J.
10 9250.00 87.39 344.74 6658.76 4110.43 1620.12 7.00 265.00 3766.65
Planned TD at 9250.00
+j600
i~
,03500
-
40 1s,5
7Wl
400
y3300
3
-
S
40
H
iH-07
L1
1
-07A
iz
3200
IH
711H
7
3100
71
711E-07A
3000
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
6440
West(
-)/East(+)
(100
us
in)
6475
6510
Pg
w 6545
6
5
v 6580
M
6615
d
a)
Plior
To
d925000
Q 6650
`r 6665
6720
Soo
40dL
End 4
dls,
7
s
7
6755
[
6790
H-07/
H-07
6825
Mean Sea L.
2625 2660 2695 2730 2765 2800 2835 2870 2905 2440 2975 3010 3045 3080 3115 3150 3185 3220 3255 3290 3325 3360 3395 3430 3465 3500 3535 3570 3605 3640 3675 3710 3745 3780 3815 3850 3985 3920 3955
Vertical Section at 350.00' (35 usft/in)
1H-07 Proposed CTD Schematic
16" 65# H-40 at
80' MD
10-3/4" 45.5#
K-55 at 2365' MD
C3/4 perfs (sqz'd)
7696'-7755' MD
C4 straddle cement
squeezed unless
injectivity low
C1 perfs
7805'-7830' MD
C1 straddle cement
squeezed
KOP @ 7842' MD
Annulus of C1 straddle
assembly cement squeezed
A -sand perfs
8015'-805V MD
7" 29# K-55 at
8274' MD
IDS nipple at 503' MD (2.875" min ID)
3%i' 9.3# L-80 ELIE 8rd Tubing to surface
31/" Camco KBMG gas lift mandrel at 7572' MD
IDS landing nipple at 7620' MD (2.812" min ID)
Baker 31/2" PBR at 7662' MD
Baker FHL packer at 7675' MD
3%" Camco MMM production mandrel at 7689' MD
AVA ported nipple at 7781' (2.813" ID)
Baker KBG-22 anchor seal assembly at 7788' MD
Baker SAB-3 packer at 7789' MD
31/:" Camco MMM production mandrel at 7801' MD
AVA ported nipple at 7874' (2.75" ID)
x/o to 21%" tubing at 7877' MD
Baker D packer at 7880' MD
XN landing nipple at 7899' MD (2.25" min ID)
Plug set to abandon A -sand pens, capped with cement
2'/" tubing tail at 7910' MD
1 H-07A, wp04
Liner -top packer at —7832' MD & @ 11,109 MD
swell packer in B-shale to ensure Liner top at 8254' MD
no behind -pipe comm to CI
1 H-07AL1, wp04
D @ 9250' MD
Liner top at 7846 MD
ter'fj
,i r
uparuk River Unit
Kuparuk I H Pad
I H-07
Plan: 9 H-07A wp05
Standard Planning Report
07 January, 2016
FMA
BAKER
NuGHEs
Database:
EDMAlaska ANC Prod
Company:
NADConversion
Project:
Kuparuk River Unit
Site:
Kuparuk 1 H Pad
Well:
1 H-07
Wellbore:
1 H-07A
Design:
1 H-07A_wp05
ConoCoPhillips
Planning Report
Local Co-ordinate Reference:
Well 1 H-07
TVD Reference:
Mean Sea Level
MD Reference:
1 H-07 @ 85.00usft (1 H-07)
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
ITS
BAKER
HUGHES
Site Kuparuk 1 H Pad
Site Position: Northing: 5,979,968.84 usft Latitude: 70' 21' 21.831 N
From: Map Easting: 549,197.16 usft Longitude: 149' 36' 1.675 W
Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.38 °
Well 1 H-07
Well Position +Nl-S 0.00 usft Northing: 5,979,935.13 usft Latitude: 70° 21' 21.476 N
+E/-W 0.00 usft Easting: 549,560.55 usft - Longitude: 1490 35' 51.058 W
Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft
Wellbore 1 H-07A
Magnetics Model Name Sample Date Declination Dip Angle Field Strength
(I (I (nT)
BGGM2015 4/1/2016 18.60 81.00 57,498
Design 1 H-07A_wp05
Audit Notes:
Version: Phase: PLAN Tie On Depth: 7,800.00
Vertical Section: Depth From (TVD) +N/-S +E/-W Direction
(usft) (usft) (usft) (I
0.00 0.00 0.00 200.00
1/7/2016 11:44:43AM Page 2 COMPASS 5000.1 Build 74
Database:
EDM Alaska ANC Prod
Company:
NADConversion
Project:
Kuparuk River Unit
Site:
Kuparuk 1 H Pad
Well:
1 H-07
Wellbore:
1 H-07A
Design:
1 H-07A_wp05
C-0mocophillips
Planning Report
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
rG.I
BAKER
HUGHES
Plan Sections
Measured
TVD Below
Dogleg
Build
Turn
Depth
Inclination
Azimuth
System
+Nl-S
+El-W
Rate
Rate
Rate
TFO
(usft)
(1)
V)
(usft)
(usft)
(usft)
(°1100usft)
(°1100usft)
(*1100usft)
V) Target
7,800.00
31.97
55.69
6,444.91
2,999.74
1,862.27
0.00
0.00
0.00
0.00
7,842.00
31.76
55.94
6,480.58
3,012.20
1,880.61
0.59
-0.50
0.60
147.96
7,867.00
39.55
49.08
6,500.89
3,021.11
1,892.10
35.00
31.18
-27.44
330.00
7,937.00
65.05
34.08 '
6,543.49
3,062.83
1,927.42
40.00
36.42
-21.44
330.00
8,007.00
74.79
6.05
6,567.92
3,123.92
1,949.19
40.00
13.92
-40.04
285.00
8,347.07
90.00
227.81
6,661.00
3,226.12
1,722.36
40.00
4.47
-40.65
-106.37
8,387.07
90.00
224.61
6,661.00
3,198.45
1,693.49
8.00
0.00
-8.00
270.00
8,460.00
91.00
221.87
6,660.37
3,145.32
1,643.53
4.00
1.37
-3.76
290.00
8,550.00
94.54
222.50
6,656.02
3,078.72
1,583.18
4.00
3.94
0.70
10.00
8,690.00
89.95
225.70
6,650.53
2,978.30
1,485.86
4.00
-3.28
2.29
145.00
8,890.00
89.81
233.70
6,650.94
2,849.06
1,333.45
4.00
-0.07
4.00
91.00
9,175.00
89.82
222.30
6,651.87
2,658.68
1,121.99
4.00
0.00
-4.00
270.00
9,425.00
90.69
212.34
6,650.78
2,460.12
970.61
4.00
0.35
-3.98
275.00
9,750.00
90.67
199.34
6,646.92
2,168.27
829.27
4.00
-0.01
-4.00
270.00
9,950.00
104.45
196.85
6,620.67
1,980.30
767.78
7.00
6.89
-1.24
350.00
10,150.00
94.39
186.97
6,587.91
1,787.70
727.40
7.00
-5.03
-4.94
225.00
10,425.00
91.19
205.98
6,574.41
1,525.57
649.79
7.00
-1.16
6.91
99.00
10,600.00
89.47
193.85
6,573.39
1,361.35
590.29
7.00
-0.98
-6.93
262.00
10,850.00
88.89
211.34
6,576.98
1,131.46
494.61
7.00
-0.23
7.00
92.00
11,100.00
88.65
193.84
6,582.39
901.60
398.96
7.00
-0.10
-7.00
269.00
1/7/2016 11:44:43AM Page 3 COMPASS 5000.1 Build 74
ConocoPhillips FSN
Conocophillips Planning Report RAKER
HUGHES
Database:
EDM Alaska ANC Prod
Local Co-ordinate Reference:
Well 1H-07
Company:
NADConversion
TVD Reference:
Mean Sea Level
Project:
Kuparuk River Unit
MD Reference:
1 H-07 @ 85.00usft (1 H-07)
Site:
Kuparuk I Pad
North Reference:
True
Well:
1H-07
Survey Calculation Method:
Minimum Curvature
Wellbore:
1 H-07A
Design:
1H-07A wp05
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)
(°1100usft)
(°)
(usft)
(usft)
7,800.00
31.97
55.69
6,444.91
2,999.74
1,862.27
-3,455.77
0.00
0.00
5,982,946.83
551,402.75
TIP
7,842.00
31.76
55.94
6,480.58
3,012.20
1,880.61
-3,473.75
0.59
147.96
5,982,959.41
551,421.01
KOP
7,867.00
39.55
49.08
6,500.89
3,021.11
1,892.10
-3,486.05
35.00
-30.00
5,982,968.40
551,432.44
End 35 dls, Start 40 dls
7,900.00
51.34
40.67
6,524.02
3,037.84
1,908.51
-3,507.39
40.00
-30.00
5,982,985.24
551,448.73
7,937.00
65.05
34.08
6,543.49
3,062.83
1,927.42
-3,537.34
40.00
-24.06
5,983,010.35
551,467.48
4
8,000.00
73.63
8.69
6,566.02
3,117.24
1,948.33
-3,595.62
40.00
-75.00
5,983,064.89
551,488.03
8,007.00
74.79
6.05
6,567.92
3,123.92
1,949.19
-3,602.19
40.00
-65.89
5,983,071.58
551,488.85
5
8,100.00
68.08
327.34
6,598.57
3,207.83
1,929.96
-3,674.46
40.00
-106.37
5,983,155.35
551,469.06
8,200.00
71.14
284.65
6,634.89
3,261.03
1,856.13
-3,699.20
40.00
-93.59
5,983,208.05
551,394.88
8,300.00
83.00
245.33
6,658.10
3,251.91
1,761.37
-3,658.22
40.00
-78.07
5,983,198.30
551,300.20
8,347.07
90.00
227.81
6,661.00
3,226.12
1,722:36
-3,620.64
40.00
-68.88
5,983,172.26
551,261.36
End 40
dls, Start RSM
8,387.07
90.00
224.61
6,661.00
3,198.45
1,693.49
-3,584.76
8.00
-90.00
5,983,144.40
551,232.68
7
8,400.00
90.18
224.12
6,660.98
3,189.20
1,684.44
-3,572.98
4.00
-70.00
5,983,135.10
551,223.70
8,460.00
91.00
221.87
6,660.37
3,145.32
1,643.53
-3,517.76
4.00
-70.00
5,983,090.95
551,183.08
8
8,500.00
92.57
222.15
6,659.12
3,115.62
1,616.78
-3,480.69
4.00
10.00
5,983,061.07
551,156.52
8,550.00
94.54
222.50
6,656.02
3,078.72
1,583.18
-3,434.53
4.00
10.01
5,983,023.96
551,123.17
9
8,600.00
92.90
223.64
6,652.77
3,042.27
1,549.11
-3,388.63
4.00
145.00
5,982,987.29
551,089.35
8,690.00
89.95
225.70
6,650.53
2,978.30
1,485.86
-3,306.88
4.00
145.07
5,982,922.91
551,026.53
10
8,700.00
89.94
226.10
6,650.54
2,971.34
1,478.68
-3,297.89
4.00
91.00
5,982,915.90
551,019.40
8,800.00
89.87
230.10
6,650.70
2,904.58
1,404.26
-3,209.70
4.00
91.00
5,982,848.65
550,945.43
8,890.00
89.81
233.70
6,650.94
2,849.06
1,333.45
-3,133.30
4.00
90.99
5,982,792.67
550,874.99
11
8,900.00
89.81
233.30
6,650.98
2,843.11
1,325.41
-3,124.97
4.00
-90.00
5,982,786.67
550,866.99
9,000.00
89.81
229.30
6,651.30
2,780.60
1,247.38
-3,039.54
4.00
-90.00
5,982,723.65
550,789.38
9,100.00
89.81
225,30
6,651.63
2,712.80
1,173.90
-2,950.70
4.00
-89.99
5.982,655.38
550,716.36
9,175.00
89.82
222.30
6,651.87
2,658.68
1,121.99
-2,882.09
4.00
-89.97
5,982,600.92
550,664.82
12
9,200.00
89.90
221.31
6,651.93
2,640.05
1,105.33
-2,858.88
4.00
-85.00
5,982,582.17
550,648.28
9,300.00
90.25
217.32
6,651.80
2,562.69
1,041.98
-2,764.52
4.00
-85.00
5,982,504.41
550,585.46
9,400.00
90.60
213.34
6,651.06
2,481.13
984.17
-2,668.10
4.00
-85.00
5,982,422.47
550,528.19
9,425.00
90.69
212.34
6,650.78
2,460.12
970.61
-2,643.73
4.00
-85.03
5,982,401.38
550,514.77
13
9,500.00
90.68
209.34
6,649.88
2,395.74
932,17
-2,570.08
4.00
-90.00
5,982,336.75
550,476.76
9,600.00
90.68
205.34
6,648.69
2,306.94
886.26
-2,470.93
4.00
-90.04
5,982,247.65
550,431.44
9,700.00
90.67
201.34
6,647.51
2,215.14
846.65
-2,371.13
4.00
-90.08
5,982,155.61
550,392.45
9,750.00
90.67
199.34
6,646.92
2,168.27
829.27
-2,321.13
4.00
-90.13
5,982,108.62
550,375.38
End RSM, Start 7 dls
9,800.00
94.11
198.73
6,644.84
2,121.05
812.98
-2,271.19
7.00
-10.00
5,982,061.30
550,359.40
9,900.00
101.01
197.49
6,631.69
2,026.89
782.18
-2,172.18
7.00
-10.03
5,981,966.95
550,329.23
9,950.00
104.45
196.85
6,620.67
1,980.30
767.78
-2,123.47
7.00
-10.19
5,981,920.28
550,315.14
15
,
10,000.00
101.96
194.32
6,609.25
1,933.42
754.71
-2,074.95
7.00
-135.00
5,981,873.31
550,302.38
11772016 11.44:43AM Page 4 COMPASS 5000.1 Build 74
ConocoPhiflips FWAV
onocoPhi li s Planning Report BAKER
HUGHES
Database:
EDM Alaska ANC Prod
Local Co-ordinate Reference:
Well 1 H-07
Company:
NADConversion
TVD Reference:
Mean Sea Level
Project:
Kuparuk River Unit
MD Reference:
1H-07 @ 85.00usft (1H-07)
Site:
Kuparuk 1H Pad
North Reference:
True
Well:
1H-07
Survey Calculation Method:
Minimum Curvature
Wellbore:
1 H-07A
Design:
1 H-07A_wp05
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)
(°1100usft)
(°)
(usft)
(usft)
10,100.00
96.93
189.39
6,592.83
1,836.94
734.48
-1,977.36
7.00
-135.58
5,981,776.71
550,282.79
10,150.00
94.39
186.97
6,587.91
1,787.70
727.40
-1,928.67
7.00
-136.39
5,981,727.42
550,276.03
16
10,200.00
93.83
190.44
6,584.32
1,738.41
719.85
-1,879.77
7.00
99.00
5,981,678.09
550,268.81
10,300.00
92.68
197.35
6,578.64
1,641.55
695.88
-1,780.56
7.00
99.25
5,981,581.09
550,245.49
10,400.00
91.49
204.26
6,574.99
1,548.19
660.40
-1,680.70
7.00
99.64
5,981,487.51
550,210.63
10,425.00
91.19
205.98
6,574.41
1,525.57
649.79
-1,655.81
7.00
99.89
5,981,464.81
550,200.18
17
10,500.00
90.46
200.78
6,573.33
1,456.76
620.04
-1,580.97
7.00
-98.00
5,981,395.81
550,170.88
10,600.00
89.47
193.85
6,573.39
1,361.35
590.29
-1,481.14
7.00
-98.07
5,981,300.22
550,141.77
18
10,700.00
89.23
200.85
6,574.52
1,265.97
560.49
-1,381,32
7.00
92.00
5,981,204.65
550,112.60
10,800.00
89.00
207.85
6,576.07
1,174.93
519.30
-1,281.68
7.00
91.92
5,981,113.35
550,072.01
10,850.00
88.89
211.34
6,576.98
1,131.46
494.61
-1,232.39
7.00
91.81
5,981,069.73
550,047.62
19
10,900,00
88.84
207.84
6,577.97
1,088.00
469.93
-1,183.11
7.00
-91.00
5,981,026.11
550,023.22
11,000.00
88.73
200.84
6,580.10
996.97
428.74
-1,083.48
7.00
-90.93
5,980,934.82
549,982.64
11,100.00
88.65 ,
193.84
, 6,582.39
901.60
398.96
-983.68
7.00
-90.78
. 5,980,839.26
. 549,953.49
Planned TD at 11100.00
rasing Points
Measured Vertical Casing Hole
Depth Depth Diameter Diameter
(usft) (usft) Name
11,100.00 6,582.39 23/8" 2-3/8 3
Plan Annotations
Measured
Vertical
Local Coordinates
Depth
Depth
+N/-S
+E/-W
(usft)
(usft)
(usft)
(usft)
Comment
7,800.00
6,444.91
2,999.74
1,862.27
TIP
7,842.00
6,480.58
3,012.20
1,880.61
KOP
7,867.00
6,500.89
3,021.11
1,892.10
End 35 dls, Start 40 dls
7,937.00
6,543.49
3,062.83
1,927.42
4
8,007.00
6,567.92
3,123.92
1,949.19
5
8,347.07
6,661.00
3,226.12
1,722.36
End 40 dls, Start RSM
8,387.07
6,661.00
3,198.45
1,693.49
7
8,460.00
6,660.37
3,145.32
1,643.53
8
8,550.00
6,656.02
3,078.72
1,583.18
9
8,690.00
6,650.53
2,978.30
1,485.86
10
8,890.00
6,650.94
2,849.06
1,333.45
11
9,175.00
6,651.87
2,658.68
1,121.99
12
9,425.00
6,650.78
2,460.12
970.61
13
9,750.00
6,646.92
2,168.27
829.27
End RSM, Start 7 dls
9,950.00
6,620.67
1,980.30
767.78
15
10,150.00
6,587.91
1,787.70
727.40
16
10,425.00
6,574.41
1,525.57
649.79
17
10,600.00
6,573.39
1,361.35
590.29
18
10,850.00
6,576.98
1,131.46
494.61
19
11,100.00
6,582.39
901.60
398.96
Planned TD at 11100.00
1/7l2016 11:44:43AM Page 5 COMPASS 5000.1 Budd 74
Conn Phillips
Company:
ConocoPhillips (Alaska) Inc. -Kup1
Project:
Kuparuk River Unit
Reference Site:
Kuparuk I Pad
Site Error.
0.00 usft
Reference Well:
1H-07
Well Error.
0.00 usft
Reference Wellbore
1H-07A
Reference Design:
1 H-07A_wp05
Baker Hughes INTE01
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 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 1 H-07A_wp05
Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA
Depth Range: 7,800.00 to 11,100.00usft Scan Method: Tray. Cylinder North
Results Limited by: Maximum center -center distance of 1,301.50 usft Error Surface: Elliptical Conic
Survey Tool Program Date 117/2016
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
7,800.00 11,100.00 1 H-07A_wp05 (1 H-07A) M WD M WD - Standard
Casing Points
Measured Vertical Casing Hole
Depth Depth Diameter Diameter
(usft) (usft) Name (") (")
11,100.00 6,667.39 2 3/8" 2-3/8 3
Summary
Site Name
Offset Well - Wellbore - Design
Kuparuk 1 H Pad
1 H-05 -1 H-05 - 1 H-05
1 H-05 - 1 H-105 - 1 H-105
1 H-07 - 1 H-07 - 1 H-07
1 H-07 - 1 H-07AL1 - 1 H-07AL1_wp04
1H-10-1H-10-1H-10
1 H-12 - 1 H-12 - 1 H-12
1 H-13 - 1 H-13 - 1 H-13
i H-14 - 1 H-14 - 1 H-14
1 H-15 - 1 H-15 - 1 H-15
1 H-16 - 1 H-16 - 1 H-16
1 H-21 - 1 H-21 - 1 H-21
Plan: 1 H-104 (formerly 101 and 27) - Plan: 1 H-104
Plan: 1 H-104 (formerly 101 and 27) - Plan:1 H-104
Plan: 1 H-104 (formerly 101 and 27) - Plan:1 H-104
Plan: 1 H-104 (formerly 101 and 27) - Plan:1 H-104
Plan: 1 H-104 (formerly 101 and 27) - Plan:1 H-104
Plan: 1 H-112 (formerly 106 and 28E) - Plan: 1 H-11
Reference Offset Centre to No -Go Allowable
Measured Measured Centre Distance Deviation
Depth Depth Distance (usft) from Plan
(usft) (usft) (usft) (usft)
7,849.99 7,850.00
8,274.73 8,275.00
8,370.87 7,925.00
10,050.00 7,150.00
0.20 2.08
2.37 0.46
1,088.83 264.13
1,130.82 259.81
MAP A
BAKER
HU GHES
Warning
Out of range
Out of range
-1.60 FAIL - Major Risk
2.02 Pass - Minor 1/10
Out of range
Out of range
Out of range
843.98 Pass - Major Risk
Out of range
874.93 Pass - Major Risk
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
Out of range
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 MajorAxis
Measured Vertical
Measured
Vertical
Reference
offset Toolface+
Offset Wellbore
Centre
Casing -
Centre to
No Go
Allowable Warning
Depth Depth
Depth
Depth
Azimuth
+N/S
+EI-W
Hole Size
Cernre
Distance
Deviation
(usft) (usft)
(usft)
(usft)
(usft)
(usft)
1')
(usft)
(usft)
I")
(usft)
(usft)
(usft)
7,825.00 6,551.13
7.825.00
6,551.13
0.08
0.15
85.54
3,007.17
1,873.19
2-11116
0.00
1.08
-0.86 FAIL -Major Risk, CC
7,849.99 6,572.29
7,850.00
6,572.38
0.13
0.31
-155.07
3,014.55
1,884.10
2-11116
0.20
2.08
-1.60 FAIL- Major Risk, ES, SF
7,874.53 6,591.58
7,875.00
6,593.66
0.13
0.46
-156.33
3,021.811
1,894.99
2-11116
3.37
3.60
0.01 Pass -Major Risk
7,897.41 6,607.39
7,900.00
6,614.97
0.14
0.62
-159.51
3.029.15
1,905.86
2-11/16
10.53
5.15
5.63 Pass -Major Risk
CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation
1iN2016 10:47:47AM Page 2 COMPASS 5000.1 Build 74
Project: Kuparuk River Unit
p euc xT�- n-
mn`rKa
WELLBORE DETAILS: 1H-07A REFERENCE
INFORMATION
Parent Welibore: 1H-07 Coa6:Wa (Nk] Me,-
Par.
'NO "a7,Tua No4h
Sit.: Kuparuk 7H Pad
M,
FORM
'
Well: 1H-07
Welibore: 1H-07A
su „su sieers..
c,' sroo'
Te on MD: 7800.00 Ve (M)Relaence:
S w(n)Releenw:
Mean Sra Lerel
Sim-AWN,o.0067
BAKER
ConocoPhillips
Plan: 1H.07Awp05 t1H-0711H-07A)
o a. a:u.'s
M.. veeO�nRelae
CaEWalion Melhoa
1Nm@a.00urnllNa
Mininum Cavalue
HUGHES
WELL DETAILS: 1H-07
a800
4500
+N1-S +EI-W Northing Easting Latitude
Longitude
0.00 0.00 5979935.13 549560.55 70° 21' 21.476 N 149'
35' 51.058 W
4200
Sec MD Inc Azi TVDSS +N/-S +EI-W Dleg TFace VSect
Annotation
1 7800.00 31.97 55.69 6444'91 2999.74 1862.27 0.00 0.00-3455.77
TIP
3900
H-07
T03
1}i-
7A 7
1x-07
2
_T01
2 784200 31.76 55.94 6480.58 3012.20 1880.61 0.59 147.96-3473.75
KOP
3 7857.00 39.55 49.08 6500.89 3021.11 1892.10 35.00 330.00-3486.05
End 35 dls, Start 40 dis
3600
F.
d40
s,S
RSM
4 7937.00 65.05 34.08 6543A9 3062.83 1927.42 40.00 330.00-3537.34
4
5 8007.00 74.79 6.05 6567.92 3123.92 1949.19 40.00 285.00-3602.19
5
-3300
11-1-o
_T
-
-
51
-0711
-07
6 8347.07 90.00 227.81 6661.00 3226.12 1722.36 40.00-106.37-3620.64
End 40 dis, Start RSM
5
7 8387.07 90.00 224.61 6661.00 3198.45 1693.49 8.00 270.00-3584.76
7
4y3000
-
-
1
'
8 8460.00 91.00 221.87 6660.37 3145.32 1643.53 4.00 290.00-3517.76
8
0
9 8550.00 94.54 222.50 6656.02 3078.72 1583.18 4.00 10.00-3434.53
9
2700
lamE
up
10 8690.00 89.95 225.70 6650.53 2978.30 1485.86 4.00 145.00-3306.88
10
11 8890.00 89.81 233.70 6650.94 2849.06 1333.45 4.00 91.00-3133.30
11
'42400
13
12 9175.00 89.82 222.30 5651.87 2658.68 1121.99 4.00 270.00-2882.09
13 9425.00 90.69 21234 6650.78 2460.12 970.61 4.00 275.00-2643.73
12
13
.02100
IH-Cr
-07A
A To
Fault
---
--
14 9750.00 90.67 199.34 6646.92 2168.27 829.27 4.00 270.00-2321.13
End RSM, Start7dls
x-o7
TOO-
- - --
- 1
aRs
,snd
als
15 9950.00104.45 196.85 6620.67 1980.30 767.78 7.00 350.00-2123.47
15
aSoo
e
1610150.00 94.39 186.97 6587.91 1787.70 727.40 7.00 225.00-1928.67
16
70
17 10425.00 91.19 205.98 6574.41 1525.57 649.79 7.00 99.00-1655.81
17
81 s00
-
1810600.00 89.47 193.85 6573.39 1361.35 590.29 7.00 262.00-1481.14
18
19 10850.00 88.89 211.34 6576.98 1131.46 494.61 7.00 92.00-1232.39
19
1200
20 11100.00 88.65 193.84 6582.39 901.60 398.96 7.00 269.00-983.68
Planned TD at 11100.00
900
i4
600
300
-1500
-1200
-900
-600
-300
0
300
600
900
1200
1500
1800
2100
2400
2700
3000
3300
3600
608
1
1
1
1
West(
-)/East(+)
(300
usftlin)
6175
6270E-
6
w 6365
6
a
s
x
r
x
-
V1 6460
4.
KO
6555
d
s,
L,04
11
�] 665
`*ed+3lD
_
i
17
18
19
p1
all
10D.00
6745
Ind 40
s,s
RS
1
1H-17/i
H-
7A
6840
H
End P.I§M
S
7dl
Mx
1
-07/1
-07
[� 6935
7030
1H
07)
ul[1
7125
Mean Sea L
-3990 -3895 -3800 -3705 -3610 -3515 -3420 -3325 -3230 -3135 -3040 -2945 -2850 -2755 -2660 -2565 -2470 -2375 -2280 -2185 -2090 -1995 -1900 -1805 -1710 -1615 -1520 -1425 -1330 -1235 -1140 -1045 -950 -855 -760 -665 -570 475 -390
Vertical Section at 200.00' (95 usft1in)
TRANSMITTAL LETTER CHECKLIST
WELL NAME: 1��ezl //
PTD:
Development _ Service Exploratory _ Stratigraphic Test Non -Conventional
FIELD: 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. 2-4'6,--&, I / , API No. 5019? - W%SS-e:2 I - 60.
(If last two digits
-V-r tiv should continue to be reported as a function of the original
in API number are
API n tuber stated above.
between 60-69)
hurt' c,.(z, �r�d�76 cti
In accordance th 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 onpermit).
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#:2160120 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type
Well Name: KUPARUK RIV UNIT 1H-07AL1 Program SER Well bore seg 141
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
Entire Well lies within ADL0025639.
3
Unique well name and number
Yes
KUPARUK RIVER, KUPARUK RIV OIL - 490100
4
Well located in a defined pool
Yes
Kuparuk River Oil Pool, governed by Conservation Order No. 4.32D
5
Well located proper distance from drilling unit boundary
Yes
Conservation Order No. 432D has no interwell spacing restrictions. Wellbore will be more than 500' from
6
Well located proper distance from other wells
Yes
an external property line where ownership or landownership changes. As proposed, well will
7
Sufficient acreage available in drilling unit
Yes
conform to spacing requirements.
8
If deviated, is wellbore plat included
Yes
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 1/20/2016
13
Can permit be approved before 15-day wait
Yes
14
Well located within area and strata authorized by Injection Order # (put IO# in comments) (For
Yes
Area Injection Order No. 2C - Kuparuk River Unit
15
All wells within 114 mile area of review identified (For service well only)
Yes
KRU 1 H-07, KRU 1 H-07A, KRU 1 H-14
16
Pre -produced injector: duration of pre -production less than 3 months (For service well only)
Yes
18
Conductor string provided
NA
Conductor set in KRU 1 H-07
Engineering
19
Surface casing protects all known USDWs
NA
Surface casing set in KRU 1H-07
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
No
26
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 pres is 3721 psi(10.9 ppg EMW); will drill w/ 9.6 ppg EMW and maintain overbal w/ MPD
VTL 1/22/2016
29
BOPEs, do they meet regulation
Yes
30
BOPE press rating appropriate; test to (put psig in comments)
Yes
MPSP is 3065 psig; will test BOPs to 3500 psig
31
Choke manifold complies w/API RP-53 (May 84)
Yes
32
Work will occur without operation shutdown
Yes
33
Is presence of 112S gas probable
Yes
H2S measures required
34
Mechanical condition of wells within AOR verified (For service well only)
Yes
AOR complete; mechanical condition verified
35
Permit can be issued w/o hydrogen sulfide measures
No
Wells on 1H-Pad are H2S-bearing. H2S measures required.
Geology
36
Data presented on potential overpressure zones
Yes
Expected reservoir pressure is 10.8 ppg EMW; well will be drilled using 9.6 ppg mud, a
Appr Date
37
Seismic analysis of shallow gas zones
NA
coiled -tubing rig, and managed pressure drilling technique to control formation pressures.
SFD 1/20/2016
38
Seabed condition survey (if off -shore)
NA
39
Contact name/phone for weekly progress reports [exploratory only]
NA
Geologic Engineering Public
Commissioner: Date: Commission r: Date Commissioner Date
izZ ��
ojs )IZz1,6
