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HomeMy WebLinkAbout216-091Guhl, Meredith D (DOA)
From: Guhl, Meredith D (DOA)
Sent: Friday, August 31, 2018 10:57 AM
To: 'Starck, Kai'
Cc: Loepp, Victoria T (DOA); Davies, Stephen F (DOA); Boyer, David L (DOA)
Subject: Expired Permits to Drill: KRU 213-02A L2 and KRU 213-02A L2-01
Hello Kai,
The following Permits to Drill, issued to ConocoPhillips Alaska, have expired under Regulation 20 AAC 25.005
PTDs will be marked expired in the AOGCC database.
• KRU 26-02A L2, PTD 216-090, Issued 16 August 2016
• KRU 213-02A 1-2-01, PTD 216-090, Issued 16 August 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
The
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation
Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.
The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail,
please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at
907-793-1235 or meredith.guhl@alaska.gov.
THE STATE
GOVERNOR BILL WALKER
Jason Burke
CTD Coordinator
ConocoPhillips Alaska, Inc.
P.O. Box 100360
Anchorage, AK 99510-0360
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 2B-02AL2-01
ConocoPhillips Alaska, Inc.
Permit to Drill Number: 216-091
Surface Location: 744' FSL, 273' FEL, SEC. 19, T11N, R9E, UM
Bottomhole Location: 4669' FSL, 1541' FEL, SEC. 30, T11N, R9E, UM
Dear Mr. Burke:
Enclosed is the approved application for permit to re -drill the above referenced development
well.
The permit is for a new wellbore segment of existing well Permit No. 216-087, API No. 50-029-
21154-01-00. 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 � ay of August, 2016.
J
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION JUL 13 2016
PERMIT TO DRILL
20 AAC 25.005
1 a. Type of Work: 1
1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp
1 C. Specify if well is proposed for:
Drill ❑ Lateral 0
Stratigraphic Test ❑ Development -Oil ❑� Service - Winj ❑ Single Zone '8
Coalbed Gas ❑ Gas Hydrates ❑
Redrill L Reentry ❑
Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone L
Geothermal ❑ Shale Gas ❑
11. Well Name and Number:
2. Operator Name:
5. Bond: Blanket Q Single Well ❑
ConocoPhillips Alaska Inc
Bond No. 5952180
2B-02AL2-01
3. Address:
6. Proposed Depth:
12. Field/Pool(s):
P.O. Box 100360 Anchorage, AK 99510-0360
MD: 10500' TVD: 6022'
Kuparuk River Field /
Kuparuk Oil Pool
4a. Location of Well (Governmental Section):
7. Property Designation (Leaseber):
Surface: 744' FSL, 273' FEL, Sec 19, T11 N, R9E, UM
ADL 25656 aS G S j �+f�
Top of Productive Horizon:
8. Land Use Permit:
13. Approximate Spud Date:
4188' FSL, 958' FEL, Sec 30, T11 N, R9E, UM
ALK 2582 _
9/15/2016
Total Depth:
9. Acres in Property:
14. Distance to Nearest Property:
4669' FSL, 1541' FEL, Sec30, T11N, R9E, UM
2560 '�i'g(s. 7
18900'
4b. Location of Well (State Base Plane Coordinates - NAD 27):
10. KB Elevation above MSL (ft): 34" Wil5.
Distance to Nearest Well Open
Surface: x-508371 y- 5954890 Zone-4
GL Elevation above MSL (ft): 92'
Ito Same Pool: 1465' (2B-08)
16. Deviated wells: Kickoff depth: 8300 feet
17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 100 degrees •
Downhole: 3973 psi Surface:
3369 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"
2-3/8"
4.7#
L-80
ST-L
3900'
6600'
6005'
10500'
6022'
N/A
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):
6976
6322
N/A
6851
6216
Fish - 6685' MD
Casing
Length
Size
Cement Volume
MD
TVD
Conductor/Structural
110'
16"
119 sx Cold Set II
110,
110,
Surface
2727'
9.625"
800 sx Cold Set III, 300 sx Cold Set If
2727'
2727'
Intermediate
Production
6934'
7"
280 sx Class G, 250 sx Cold Set I
6934'
8287'
Liner
Perforation Depth MD (ft): 6526'-6568',
Perforation Depth TVD (ft): 5943'-5978', 6022'-6098'
6620'-6710'
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 requirements0
21. Verbal Approval: Commission Representative: Date
71a /6
22. 1 hereby certify that the foregoing is true and the procedure approved herein will not
Mike Callahan 263-4180
be deviated from without prior written approval. Contact
mike.callahanp_cop.com
Email
Printed Name Jason Burke Title CTD Coordinator
Signature Phone 265-6097 Date
6
Commission Use Only
Permit to Dri API Number: Permit Approval [�+ See cover letter for other
Number: 6 — �Q 50- 0U — � / 61 i� ��� Date: U I ( 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: Bo P fr3 f p rr55vt-G 3Tgr h 5 r q Samples req'd: Yes � Nod Mud log req'd: Yes Nov
measures: Yes No L] Directional Yes No
/�� vl✓e N , ` frs �p 5�U/U f2$ tc�2S
Yes ❑ No[Zf Inclination
� -'(
svy req'd:
-only svy req'd: Yes❑ Not
A Ka r1'C4 { fo z 5- ft.4 C 25, U J 5 6 pacing exception req'd:
5 9 r 4 vl ted to C( 1/0 w f"Lt L l< I Lk V ff p n Pn t -(- D b e a n y Post initial injection
0IY' T
MIT req'd: Yes ❑ No
J
ftlCp4'-tw¢ latrr4d.
APPROVED BY
p
�6
Approved by:(atl_r'16�1119 COMMISSIONER THE COMMISSION
Date: O ,
/V %L 5//5/ 1' �J T I "1 7 Submit Form and
FQpm1O-gQ1 ([fie ise AL
This permit is valid for 2months from the date of approval (20 AAC 25.005(g)) Attachments in Duplicate
R (V1 I ,/A 7iS116
ConocoPhillips
p
Alaska
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
July 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 applications for permits to drill 5 laterals out of the Kuparuk Well
28-02 using the coiled tubing drilling rig, Nabors CDR2-AC or CDR3-AC.
To account for geological uncertainties, ConocoPhillips requests a variance from the requirements of 20 AAC
25.015 to allow the actual kick-off point to be anywhere along the length of the parent lateral instead of being
limited to 500' from the original point.
A sundry application is attached to plug the KRU 213-02 (184-122) perforations to allow these laterals to be
drilled. As detailed in the attachments, ConocoPhillips requests a variance from the requirements of 20 AAC
25.112(c)(1) to plug the A/C -sand perforations in 213-02.
Attached to this application are the following documents:
— 10-403 Sundry Application to Abandon KRU 213-02 (184-122)
— Operations Summary in support of the 10-403 sundry application
— 10-401 Applications for 213-02A, 213-02AL1, 213-02AL1-01, 213-02AL1-02, and 213-02AL2
— Detailed Summary of Operations
— Directional Plans for 213-02A, 213-02AL1, 213-02AL1-01, 213-02AL1-02, and 213-02AL2
— Proposed CTD Schematic
If you have any questions or require additional information, please contact me at 907-263-4180.
Sincerely,
Mike Callahan
ConocoPhillips Alaska
Coiled Tubing Drilling Engineer
Kuparuk CTD Laterals NABOA.S A_LASKA
2B-02A, AL1, AL1-011 AL2 & AL2-01 CDA
Application for Permit to Drill Document VAC
1. Well Name and Classification...........................................................................................................2
(Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b))......................................................................................................................2
2. Location Summary.............................................................................................................................2
(Requirements of 20 AAC 25.005(c)(2))...................................................................................................................................................... 2
3. Blowout Prevention Equipment Information...................................................................................2
(Requirements of 20 AAC 25.005(c)(3)).....................................................................................................................................................2
4. Drilling Hazards Information and Reservoir Pressure....................................................................2
(Requirements of 20 AAC 25.005(c)(4))..................................................................................................................................................... 2
5. Procedure for Conducting Formation Integrity tests.....................................................................2
(Requirements of 20 AAC 25.005(c)(5))...................................................................................................................................................... 2
6. Casing and Cementing Program......................................................................................................3
(Requirements of 20 AAC 25.005(c)(6))...................................................................................................................................................... 3
7. Diverter System Information.............................................................................................................3
(Requirements of 20 AAC 25.005(c)(7))...................................................................................................................................................... 3
8. Drilling Fluids Program.....................................................................................................................3
(Requirements of 20 AAC 25.005(c)(8))...................................................................................................................................................... 3
9. Abnormally Pressured Formation Information...............................................................................4
(Requirements of 20 AAC 25.005(c)(9))........................................................................................ 4
..............................................................
10. Seismic Analysis................................................................................................................................4
(Requirements of 20 AAC 25.005(c)(10)).................................................................................................................................................... 4
11. Seabed Condition Analysis...............................................................................................................4
(Requirements of 20 AAC 25.005(c)(11)).................................................................................................................................................... 4
12. Evidence of Bonding.........................................................................................................................4
(Requirements of 20 AAC 25.005(c)(12))....................................................................................................................................................4
13. Proposed Drilling Program...............................................................................................................4
(Requirements of 20 AAC 25.005(c)(13)).................................................................................................................................................... 4
Summaryof Operations.................................................................................................................................................. 4
LinerRunning.................................................................................................................................................................. 6
14. Disposal of Drilling Mud and Cuttings.............................................................................................7
(Requirements of 20 AAC 25.005(c)(14)).................................................................................................................................................... 7
15. Directional Plans for Intentionally Deviated Wells..........................................................................7
(Requirements of 20 AAC 25.050(b)).......................................................................................................................................................... 7
16. Attachments.......................................................................................................................................7
Attachment 1: Directional Plans for 213-02A, AL1, AL1-01, AL12 & AL2-01 laterals....................................................... 7
Attachment 2: Current Well Schematic for 213-02........................................................................................................... 7
Attachment 3: Proposed Well Schematic for 213-02A, AL1, AL1-01, AL2 & AL2-01 laterals ........................................... 7
Page 1 of 7 July 13, 2016
PTD Application: 213-02A, AL1, AI1-01, AL2 & AI2-01
1. Well Name and Classification
(Requirements of 20 AAC 25.005(t) and 20 AAC 25.005(b))
The proposed laterals described in this document are 26-02A, 26-02AL1, 26-02AL1-01, 2B-02AL2, & 213-
02AL2-01. All laterals will be classified as Production 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 213-02A, 213-02AL1, 26-02AL1-01, 2B-02AL2, & 26-02AL2-01.
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.
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 3750 psi. Using the
maximum formation pressure in the area of 3973 psi in 213-08 (12.6 ppg EMW), the maximum potential
surface pressure in 26-02, assuming a gas gradient of 0.1 psi/ft, would be 3369 psi. See the "Drilling
Hazards Information and Reservoir Pressure" section for more details.
— The annular preventer will be tested to 250 psi and 2,500 psi.
4. Drilling Hazards Information and Reservoir Pressure
(Requirements of 20 AAC 25.005 (c)(4))
Reservoir Pressure and Maximum Downhole Pressure (Requirements of 20 AAC 25.005 (c)(4)(a))
The formation pressure in KRU 213-02 was measured to be 2142 psi (6.9 ppg EMW) on 5/7/2016. The
maximum downhole pressure in the 213-02 vicinity is to the west in the 213-08 injector at 3973 psi (12.6 ppg
EMW) from March of 2014. Pressure management in the area is expected to bring the formation pressure
down to —11.0 ppg by the time of drilling.
Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b))
Wells on 213 pad have injected gas, so there is a chance of encountering free gas while drilling the 213-02
laterals. If significant gas is detected in the returns the contaminated mud can be diverted to a storage tank
away from the rig.
Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c))
The major expected risk of hole problems in the 213-02 laterals will be shale instability across faults. Managed
pressure drilling (MPD) will be used to reduce the risk of shale instability associated with fault crossings.
5. Procedure for Conducting Formation Integrity tests
(Requirements of 20 AAC 25.005(c)(5))
The 213-02 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 July 13, 2016
PTD Application: 213-02A, AL1, AL1-01, AL2 & AL2-01
6. Casing and Cementing Program
(Requirements of 20 AAC 25.005(c)(6))
New Completion Details
Lateral Name
Liner Top
Liner Btm
Liner Top
Liner Btm
Liner Details
MD
MD
TVDSS
TVDSS
213-02A
8385'
9900,
5993'
5969'
2-3/8", 4.7#, L-80, ST-L slotted liner;
aluminum billet on to
2B-02AL1
8500'
10425'
5981'
5899'
2-3/8", 4.7#, L-80, ST-L slotted liner;
aluminum billet on to
26-02AL1-01
6630'
9800'
5871'
5989'
2-3/8", 4.7#, L-80, ST-L slotted liner;
deployment sleeve on to
2B-02AL2
8300'
9900,
5997'
5965'
2-3/8", 4.7#, L-80, ST-L slotted liner;
aluminum billet on to
2B-02AL2-01
6600'
10500'
5879'
5896'
2-3/8", 4.7#, L-80, ST-L slotted liner;
deployment sleeve 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"
62.5
H-40
Welded
0'
110,
0'
110'
1640
670
Surface
9-5/8"
36.0
J-55
BTC
0'
2727'
0'
2727'
3620
2020
Production
7"
26.0
J-55
BTC
0'
6934'
0'
6287'
4980
4320
Tubin
3-1/2"
9.3
J-55
EUE-8rd
0
6616'
0
6019' 1
6980 1
7400
7. Diverter System Information
(Requirements of 20 AAC 25.005(c)(7))
Nabors CDR2-AC will be operating under 20 AAC 25.036, for thru-tubing drilling operations. Therefore, a
diverter system is not required.
8. Drilling Fluids Program
(Requirements of 20 AAC 25.005(c)(8))
Diagram of Drilling System
A diagram of the Nabors CDR2-AC mud system is on file with the Commission.
Description of Drilling Fluid System
— Window milling operations: Chloride -based FloVis mud (8.6 ppg)
— Drilling operations: Chloride -based FloPro mud (8.6 ppg). This mud weight will not hydrostatically
overbalance the reservoir pressure, overbalanced conditions will be maintained using MPD practices
described below.
— Completion operations: The well will be loaded with 11.8 ppg NaBr completion fluid (unless
unexpected, higher pressure is encountered, in which case higher density NaBr or potassium formate
will be used) in order to provide formation over -balance and well bore stability while running
completions.
Managed Pressure Drilling Practice
Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on
the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud
weight is not, in many cases, the primary well control barrier. This is satisfied with the 5,000 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 26-02 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
Page 3 of 7 July 13, 2016
PTD Application: 213-02A, AL1, AL1-01, AL2 & AL2-01
increased reservoir pressure is encountered. Additional choke pressure or increased mud weight may also be
employed for improved borehole stability. Any change of circulating friction pressure due to change in pump rates
or change in depth of circulation will be offset with back pressure adjustments.
Pressure at the 2B-02 Window 6640' MD 6039' TVD) Hcin MPD
m
Pumps OFpsi
Pumps Off
A -sand Formation Pressure 6.9 )
21
2158 psi
Mud Hydrostatic (8.6
27
2701 psi
Annular friction i.e. ECD, 0.090 psi/ft
5
0 si
Mud + ECD Combined
no choke pressure)p
32s
2701 psi
Target BHP at Window 11.8
3706 psi
3706 psi
Choke Pressure Required to Maintain
Target BHP
407 psi
P
1005 psi
9. Abnormally Pressured Formation Information
(Requirements of 20 AAC 25.005(c)(9))
N/A - Application is not for an exploratory or stratigraphic test well.
10. Seismic Analysis
(Requirements of 20 AAC 25.005(c)(10))
N/A - Application is not for an exploratory or stratigraphic test well.
11. Seabed Condition Analysis
(Requirements of 20 AAC 25.005(c)(11))
N/A - Application is for a land based well.
12. Evidence of Bonding
(Requirements of 20 AAC 25.005(c)(12))
Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission.
13. Proposed Drilling Program
(Requirements of 20 AAC 25.005(c)(13))
Summary of Operations
Background
KRU well 213-02 is a Kuparuk A/C -sand producer equipped with 3-1/2" tubing and 7" production casing.
The CTD sidetrack will utilize up to five laterals to target the A3/A4 sands to the north and south of 213-02.
Prior to CTD operations, E-Line will punch 2' of holes in the 3-1/2" tubing tail at 6609' MD and the "D"
nipple at 661 1' MD will be milled out to a 2.80" ID. The existing C-Sand perforations will be squeezed
with cement to abandon the C-Sand. A second cement job will then be performed to cover the A -Sand
perfs and provide the cement pilot hole for the kick -out of the 7" casing. ConocoPhillips requests a
variance from the requirements of 20 AAC 25.112(c)(1) to plug the A -sand and C-sand perforations
in this manner.
Following the cement squeeze Nabors CDR2-AC will drill a pilot hole to 6650' MD and set a mechanical
whip -stock in the 2.80" pilot hole to kick off at 6640' MD. All five laterals will be completed with 2-3/8"
slotted liner from TD with the last lateral liner top located inside the 3-1 /2" tubing tail.
Page 4 of 7 July 13, 2016
PTD Application: 2B-02A, AL1, AL1-01, AL2 & AL2-01
213-02A southern lateral will exit the cement pilot hole at 6640' MD and TD at 9900' MD, targeting the A4
and A3 Sands. It will be completed with 2-3/8" slotted liner from TD up to 8385'MD with an aluminum
billet for kicking off the 213-02AL 1.
The 213-02AL 1 lateral will kickoff of the aluminum billet at 8385' and drill to the north to a TD of 10425'
MD targeting the A4 Sand. It will be completed with 2-3/8" slotted liner from TD up to 8500' MD with an
anchored billet for kicking off the 213-02AL 1-01.
The 213-02AL1-01 lateral will kickoff the anchored billet at 8500' and drill to the north to a TD of 9800'
MD, targeting the A3 Sand. It will be completed with 2-3/8" slotted liner from TD back into the cement
pilot hole with a deployment sleeve.
The 213-02AL2 lateral will exit the cement pilot hole at 6630' and drill to the south to a TD of 9900' MD.
It will be completed with 2-3/8" slotted liner from TD up to 8300' MD with an anchored billet for kicking
off the 2B-02AL2-01.
The 2B-02AL2-01 lateral will kickoff the anchored billet at 8300' and drill to the north to a TD of 10500'
MD. It will be completed with 2-3/8" slotted liner from TD back into the 3-1/2" tubing tail with a
deployment sleeve.
Pre-CTD Work
1. RU Slickline: Obtain SBHP, dummy off gas lift mandrels, and pressure test.
2. RU E-line: Punch 2' of holes in the 3 %2" tubing tail at 6609' MD.
3. RU Pumping Unit: perform injectivity test down the tubing.
4. RU Service Coil: Mill out "D" nipple and cement squeeze the C-sand perforations. Wait on cement
for 72 hours.
5. RU Service Coil: Cement squeeze A -Sand perforations and leave plug for cement pilot hole.
6. RU Slick -line: Tag top of cement and pressure test cement.
7. Prep site for Nabors CDR2-AC and set BPV.
Rig Work
1. MIRU Nabors CDR2-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test.
213-02A Sidetrack (A3/A4 Sands - South)
i. Drill 2.80" high -side pilot hole through cement to 6670' MD
ii. Caliper pilot hole
iii. Set top of whip -stock at 6640' MD
iv. Mill 2.80" window at 6640' MD.
v. Drill 3" bi-center lateral to TD of 9900' MD.
vi. Run 2%" slotted liner with an aluminum billet from TD up to 8385' MD.
3. 2B-02AL 1 Lateral (A4 Sand - North)
i. Kickoff of the aluminum billet at 8385' MD.
ii. Drill 3" bi-center lateral to TD of 10425' MD.
iii. Run 2%" slotted liner with anchored billet from TD up to 8500' MD.
Page 5 of 7 July 13, 2016
PTD Application: 2B-02A, AL1, AU-01, AL2 & AL2-01
4. 213-02AL1-01 Lateral (A3 Sand -North)
i. Kick off of the aluminum billet at 8500' MD.
ii. Drill 3" bi-center lateral to TD of 9800' MD.
iii. Run 2%" slotted liner with deployment sleeve from TD up to 6635' MD.
213-02AL2 Lateral (A3/A4 Sand - South)
i. Set top of whipstock at 6630' MD.
ii. Mill 2.80" window at 6630' MD
iii. Drill 3" bi-center lateral to TD of 9900' MD.
iv. Run 2%" slotted liner with anchored billet from TD up to 8300' MD.
6. 2B-02AL2-01 Lateral (A3/A4 Sand - North)
i. Kickoff of the aluminum billet at 8300' MD.
ii. Drill 3" bi-center lateral to TD of 10500' MD.
iii. Run 2%" slotted liner with deployment sleeve from TD up to 6600' MD.
7. Freeze protect, set BPV, ND BOPE, and RDMO Nabors CRD2-AC.
Post-Ria Work
1. Pull BPV
2. Obtain SBHP
3. Install gas lift design
4. Return to production
Pressure Deployment of BHA
The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on
the Christmas tree. MPD operations require the BHA to be lubricated under pressure 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 213-02 laterals will be displaced to an overbalancing fluid (11.8 ppg NaBr) prior to running liner. See
"Drilling Fluids" section for more details.
Page 6 of 7 July 13, 2016
PTD Application: 213-02A, AL1, AL1-01, AL2 & AL2-01
— While running 2-3/8" slotted liner, a joint of 2-3/8" 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 2-3/8" rams will
provide secondary well control while running 2-3/8" liner.
14. Disposal of Drilling Mud and Cuttings
(Requirements of 20 AA 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 AA 25.050(b))
— The Applicant is the only affected owner.
— Please see Attachment 1: Directional Plans
— Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run.
— MWD directional, resistivity, and gamma ray will be run over the entire open hole section.
— Distance to Nearest Property Line (measured to KPA boundary at closest point)
Lateral Name
I Distance
2B-02A
18000'
2B-02AL1
18900'
2113-02AL1-01
18900'
2B-02AL2
18000'
2B-02AL2-01
18900,
— Distance to Nearest Well within Pool
Lateral Name
Distance
Well
2113-02A
950'
213-07
26-02AL1
1580'
26-08
213-02AL1-01
1475'
213-08
2B-02AL2
950'
213-07
2B-02AL2-01
1465'
2B-08
16. Attachments
Attachment 1: Directional Plans for 2B-02A, AL 1, AL 1-01, AL2 & AL2-01 laterals
Attachment 2: Current Well Schematic for 2B-02
Attachment 3: Proposed Well Schematic for 2B-02A, AL 1, AL 1-0 1, AL2 & AL2-01 laterals
Page 7 of 7 July 13, 2016
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ConocoPhillips
ConocoPhillips (Alaska) Inc. -Kup2
Kuparuk River Unit
Kuparuk 213 Pad
2B-02
213-02AL2-01
Plan: 2B-02AL2-01_wp01
Standard Planning Report
11 July, 2016
FeAA r k I
BAKER
HUGNES
ConocoPhillips ,fA:.
ConocoPhillips Planning Report BAKER
HUGHES
Database:
EDM Alaska NSK Sandbox
Company:
ConocoPhillips (Alaska) Inc. -Kup2
Project:
Kuparuk River Unit
Site:
Kuparuk 2B Pad
Well:
26-02
We I I bore:
213-02AL2-01
Design:
2B-02AL2-01_wp01
Local Co-ordinate Reference
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Well 2B-02
Mean Sea Level
213-02 @ 126.00usft (213-02)
True
Minimum Curvature
Project Kuparuk River Unit, North Slope Alaska, United States
Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level
Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point
Map Zone: Alaska Zone 04 Using geodetic scale factor
Site Kuparuk 2B Pad
Site Position: Northing: 5,954,944.68 usft Latitude: 70° 17' 17.239 N
From: Map Easting: 508,346.10usft Longitude: 149° 55' S6.803 W
Position Uncertainty: 0.00 usft Slot Radius: 0.000in Grid Convergence: 0.06 °
Well 2B-02
Well Position +N/-S
+E/-W
Position Uncertainty
0.00 usft
Northing:
0.00 usft
Easting:
0.00 usft
Wellhead Elevation:
Wellbore 26-02AL2-01
Magnetics Model Name Sample Date
BGGM2016 10/1/2016
Design 2B-02AL2-01_wp01
Audit Notes:
Version:
Vertical Section:
Plan Sections
5,954,890.07 usft Latitude: 70° 17' 16.702 N
508,370.93 usft Longitude: 149° 55' 56.081 W
usft Ground Level: 0.00 usft
Declination Dip Angle
(°) (°)
17.90
Phase: PLAN
Depth From (TVD) +N/-S
(usft) (usft)
0.00 0.00
Tie On Depth
+E/-W
(usft)
000
Field Strength
(nT)
80.90 57,541
8,300.00
Direction
(I
345.00
Measured
TVD Below
Dogleg
Build
Turn
Depth
Inclination
Azimuth
System
+N/-S
+E/-W
Rate
Rate
Rate
TFO
(usft)
(°)
(I
(usft)
(usft)
(usft)
(°/100ft)
(°/100ft)
(°/100ft)
(°)
8,300.00
89.53
277.38
5,996.92
-3,114.17
-1,367.64
0.00
0.00
0.00
0.00
8.400.00
99.91
283.44
5,988.69
-3,096.24
-1,465.49
12.00
10.38
6.06
30.00
8,600.00
93.07
306.61
5,965.80
-3,012.57
-1.644.08
12.00
-3.42
11.58
105.00
8,800.00
92.80
330.64
5,955.42
-2,863.80
-1,775.14
12.00
-0.13
12.02
90.00
9,050.00
92.42
0.67
5,943.76
-2,624.62
-1.836.31
12.00
-0.15
12.01
90.00
9,525.00
87.13
57.44
5,945.75
-2,226.28
-1,615.07
12.00
-1.11
11.95
95.00
9,725.00
87.38
33.41
5.955.45
-2,087.11
-1,473.81
12.00
0.12
-12.01
270.00
10,025.00
96.61
358.56
5,944.69
-1,803.69
-1,392.34
12.00
3.07
-11.62
285.00
10,200.00
99.74
19.54
5.919.54
-1,633.62
-1,365.39
12.00
1.79
11.99
80.00
10,300.00
93.61
29.93
5,907.89
-1,543.61
-1,323.85
12.00
-6.13
10.39
120.00
10,500.00
93.30
5.89
5,895.64
-1,355.05
-1,262.91
12.00
-0.16
-12.02
270.00
Target
711112016 12 15.59PM Page 2 COMPASS 5000.1 Build 74
r
- ConocoPhillips Has
ConocoPhillips Planning Report BAKER
HUGHES
Database:
EDM Alaska NSK Sandbox
Local Co-ordinate Reference:
Well 2B-02
Company:
ConocoPhillips (Alaska) Inc. -Kup2
TVD Reference:
Mean Sea Level
Project:
Kuparuk River Unit
MD Reference:
26-02 @ 126.00usft (2B-02)
Site:
Kuparuk 2B Pad
North Reference:
True
Well:
2B-02
Survey Calculation Method:
Minimum Curvature
W e l l b o re:
2 B-02AL2-01
Design:
2B-02AL2-01_wp01
Planned Survey
Measured
TVD Below
Vertical
Dogleg
Toolface
Map
Map
Depth Inclination
Azimuth
System
+N/-S
+E/-W
Section
Rate
Azimuth
Northing
Easting
(usft)
(°)
(°)
(usft)
(usft)
(usft)
(usft)
(°/100ft)
(°)
(usft)
(usft)
8,300.00
89.53
277.38
5,996.92
-3,114.17
-1,367.64
-2,654.09
0.00
0.00
5,951,774.69
507,006.89
TIP/KOP
8,400.00
99.91
283.44
5,988.69
-3,096.24
-1,465.49
-2,611.44
12.00
30.00
5,951,792.51
506.909.03
Start 12 dls
8,500.00
96.62
295.10
5,974.27
-3,063.60
-1,558.71
-2,555.79
12.00
105.00
5,951,825.04
506,815.78
8,600.00
93.07
306.61
5,965.80
-3,012.57
-1,644.08
-2,484.40
12.00
106.68
5,951,875.97
506,730.37
3
8,700.00
93.00
318.62
5,960.50
-2,945.09
-1,717.44
-2,400.23
12.00
90.00
5,951,943.37
506,656.95
8,800.00
92.80
330.64
5.955.42
-2,863.80
-1,775.14
-2,306.77
12.00
90.64
5,952,024.59
506,599.16
4
8,900.00
92.74
342.65
5,950.57
-2.772.27
-1,814.66
-2,208.13
12.00
90.00
5,952,116.06
506,559.53
9,000.00
92.56
354.66
5,945.93
-2,674.50
-1,834.27
-2,108.63
12.00
90.58
5,952,213.79
506,539.82
9,050.00
92.42
0.67
5,943.76
-2,624.62
-1,836.31
-2,059.91
12.00
91.14
5,952.263.67
506,537.73
5
9,100.00
91.89
6.65
5,941.87
-2,574.78
-1,833.12
-2,012.60
12.00
95.00
5,952,313.51
506,540.86
9,200.00
90.76
18.60
5,939.55
-2,477.40
-1,811.32
-1,924.18
12.00
95.23
5,952,410.90
506,562.55
9,300.00
89.60
30.54
5,939.23
-2,386.62
-1,769.81
-1,847.24
12.00
95.50
5,952,501.72
506,603.95
9,400.00
88.46
42.49
5,940.92
-2.306.41
-1,710.43
-1,785.13
12.00
95.54
5,952,581.99
506,663.24
9,500.00
87.39
54.45
5,944.55
-2,240.27
-1,635.75
-1,740.57
12.00
95.34
5,952,648.21
506,737.83
9,525.00
87.13
57,44
5,945.75
-2,226.28
-1,615.07
-1,732.41
12.00
94.90
5,952,662.21
506,758.50
6
9,600.00
87.17
48.43
5,949.48
-2,181.18
-1,555.36
-1,704.31
12.00
-90.00
5.952,707.37
506,818.16
9,700.00
87.33
36.42
5,954.30
-2,107.59
-1.488.10
-1,650.62
12.00
-89.55
5,952,781.04
506,885.33
9,725.00
87.38
33.41
5,955.45
-2,087.11
-1,473.81
-1,634.55
12.00
-88.97
5,952,801.53
506,899.60
7
9,800.00
89.73
24.72
5,957.35
-2,021.65
-1,437.42
-1,580.73
12.00
-75.00
5,952,867.03
506,935.91
9,900.00
92.87
13.14
5,955.07
-1,927.25
-1,405.04
-1,497.93
12.00
-74.78
5,952,961.45
506,968.18
10,000.00
95.88
1.49
5,947.41
-1,828.54
-1,392.35
-1,405.87
12.00
-75.04
5,953,060.16
506,980.75
10,025.00
96.61
358.56
5,944.69
-1,803.69
-1,392.34
-1,381.87
12.00
-75.94
5,953,085.01
506,980.74
8
10,100.00
98.08
7.51
5.935.09
-1,729.49
-1,388.42
-1,311.21
12.00
80.00
5,953,159.21
506,984.57
10,200.00
99.74
19.54
5,919.54
-1,633.62
-1,365.39
-1,224.57
12.00
81.15
5,953,255.09
507,007.50
9
10,300.00
93.61
29.93
5,907.89
-1,543.61
-1,323.85
-1,148.37
12.00
120.00
5,953,345.14
507,048.93
10
10,400.00
93.54
17.91
5,901.63
-1,452.54
-1,283.46
-1,070.86
12.00
-90.00
5,953,436.24
507,089.22
10,500.00
93.30
5.89
5,895.64
-1,355.05
-1,262.91
-982.01
12.00
-90.75
5,953,533.75
507,109.65
Planned TD at 10500.00
711112016 12:15:59PM Page 3 COMPASS 5000.1 Build 74
ConocoPhillips rr..I
ConocoPhillips Planning Report BAKER
HUGHES
Database:
EDM Alaska NSK Sandbox
Company:
ConocoPhillips (Alaska) Inc. -Kup2
Project:
Kuparuk River Unit
Site:
Kuparuk 213 Pad
Well:
26-02
Wel I bore: 213-02AL2-01
Design: 2 B-02A L2-01 _wp 01
Targets
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Well 213-02
Mean Sea Level
26-02 @ 126.00usft (213-02)
True
Minimum Curvature
Target Name
hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting
Shape (°) (°) (usft) (usft) (usft) (usft) (usft)
28-02A_Fault1 0.00 0.00 0.00-4,064.721,139,312.09 5,952,094.00 1,647,573.00
plan misses target center by 1140593.46usft at 10500.00usft MD (5895.64 TVD,-1355.05 N,-1262.91 E)
Rectangle (sides W1,000.00 1-11.00 D0.00)
26-02 CTD Polygon Soy
0.00 0.00 0.00
-3,303.661,139,325.94
5,952,855.00
- plan misses target center by 1140605.76usft at 10500.00usft MD (5895.64
TVD,-1355.05
N,-1262.91 E)
Polygon
Point 1
0.00
0.00
0.00
5,952,855.00
Point 2
0.00
-207.95
-66.23
5,952,647.00
Point 3
0.00
-450.95
-87.49
5.952,404.00
Point
0.00
-603.91
-139.66
5,952,251.00
Point 5
0.00
-895.90
-177.97
5,951,958.99
Point
0.00
-1,058.81
-276.15
5,951,795.99
Point?
0.00
-1,131.70
-387.24
5,951,722.98
Point
0.00
-1,148.53
-553.28
5,951,705.97
Point
0.00
-1,107.38
-689.25
5,951,746.96
Point 10
0.00
-1,086.18
-876.24
5,951,767.95
Point 11
0.00
-1,126.98
-1,071.30
5,951,726.94
Point 12
0.00
-1,213.81
-1,234.41
5,951,639.94
Point 13
0.00
-1,362.65
-1,397.59
5,951,490.93
Point 14
0.00
-1,560.58
-1,487.81
5,951,292.92
Point 15
0.00
-1,762.58
-1,502.02
5,951,090.93
Point 16
0.00
-1,974.58
-1,527.25
5,950,878.92
Point 17
0.00
-2,293.59
-1,544.59
5,950,559.92
Point 18
0.00
-2,546.56
-1,600.87
5,950,306.91
Point 19
0.00
-2,772.51
-1,663.11
5,950,080.92
Point20
0.00
-21835.88
-1,323.14
5,950,017.93
Point21
0.00
-2,609.91
-1,273.90
5,950,243.93
Point22
0.00
-2,224.92
-1,225.49
5,950,628.94
Point23
0.00
-1,915.91
-1,204.16
5,950,937.94
Point24
0.00
-1,647.90
-1,192.87
5,951,205.94
Point25
0.00
-1,461.05
-1,033.66
5,951,392.95
Point26
0.00
-1,398.24
-852.57
5,951,455.95
Point27
0.00
-1,450.51
-599.60
5.951,403.97
Point28
0.00
-1,443.76
-362.57
5.951,410.98
Point29
0.00
-1,344.01
-119.44
5,951.510.99
Point30
0.00
-1,146.17
50.79
5,951,709.00
Point 31
0.00
-948.22
117.00
5,951,907.01
Point32
0.00
-670.24
165.30
5,952,185.01
Point 33
0.00
-503.27
210.49
5,952,352.01
Point 34
0.00
-257.27
231.75
5,952,598.01
Point 35
0.00
-80.32
294.94
5,952,775.02
Point 36
0.00
0.00
0.00
5,952,855.00
213-02 CTD Polygon Nor
0.00 0.00 0.00
-4,754.151,138,740.27
5,951,404.00
- plan misses target center by 1140023.49usft at 10500.00usft
MD (5895.64 TVD,-1355.05
N,-1262.91 E)
- Polygon
Point 1
0.00
0.00
0.00
5,951,404.00
Point
0.00
62.22
-200.95
5,951,465.99
Point 3
0.00
187.45
-405.84
5,951,590.98
Point
0.00
350.59
-523.68
5,951,753.97
Point 5
0.00
632.70
-596.39
5,952,035.97
Point 6
0.00
850.69
-565.15
5,952,253.98
Point
0.00
1,041.60
-470.94
5,952,444.97
Point
0.00
1,159.51
-366.81
5,952,562.99
Point
0.00
1,326.44
-286.62
5,952,729.99
Point 10
0.00
1,528.41
-241.40
5,952,931.99
Point 11
0.00
1,746.36
-175.16
5,953,149.99
1, 647, 586.00
1, 647, 586.00
1, 647, 520.01
1,647,499.02
1,647,447.03
1,647,409.05
1,647,311.06
1,647,200.06
1,647,034.05
1, 646, 898.05
1, 646, 711.06
1, 646, 516.06
1, 646, 353.07
1,646,190.07
1,646,100.08
1,646, 086.09
1,646, 061.10
1,646,044.12
1,645,988.13
1, 645, 926.14
1,646,266.15
1, 646, 315.13
1, 646, 363.11
1, 646, 384.09
1, 646, 395.08
1, 646, 554.07
1, 646, 735.07
1, 646, 988.07
1,647, 225.07
1,647,468.07
1,647, 638.06
1,647,704.04
1,647, 752.03
1,647,797.03
1,647, 818.01
1,647, 881.00
1,647,586.00
1, 647, 002.00
1,647,002.00
1,646,801.00
1,646,595.99
1,646,477.98
1,646,404.97
1,646,435.96
1,646,529.95
1,646,633.94
1,646,713.93
1,646,758.92
1,646, 824.91
Latitude Longitude
70° 2' 34.277 N 140° 47' 25.345 W
70° 2' 41.646 N 140° 47' 21.678 W
700 2' 28.422 N 1400 47' 44.562 W
711112016 12.15:59PM Page 4 COMPASS 5000 1 Build 74
V - ConocoPhillips rigs
ConocoPhillips Planning Report BAKER
HUGHES
Database:
EDM Alaska NSK Sandbox
Company:
ConocoPhillips (Alaska) Inc. -Kup2
Project:
Kuparuk River Unit
Site:
Kuparuk 213 Pad
Well:
213-02
We I I bo re:
2 B-02A L2-01
Design:
2B-02AL2-01 _wp01
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Well 2B-02
Mean Sea Level
213-02 @ 126.00usft (213-02)
True
Minimum Curvature
Point 12
0.00
1,896.32
-119.00
5,953,300.00
1,646,880.90
Point 13
0.00
2,493.14
103.66
5,953,897.00
1,647,102.87
Point 14
0.00
2,433.82
398.63
5,953,838.02
1,847,397.88
Point 15
0.00
1,832.99
182.97
5,953,237.01
1,647,182.91
Point 16
0.00
1,590.04
109.70
5,952,994.00
1,647,109.92
Point 17
0.00
1,309.08
46.40
5,952,713.00
1,647,046.94
Point 18
0.00
1,093.16
-43.84
5,952,497.00
1,646,956.95
Point 19
0.00
920.26
-155.04
5,952,323.99
1,646,845.95
Point20
0.00
718.34
-256.26
5,952,121.98
1,646,744.97
Point 21
0.00
500.32
-252.49
5,951,903.99
1.646,748.98
Point22
0.00
350.15
-106.64
5,951,754.00
1,646.894.98
Point23
0.00
297.97
59.32
5,951,702.01
1,647,060.98
Point24
0.00
0.00
0.00
5,951,404.00
1,647,002.00
26-02A_Fault3 0.00 0.00 0.00-4,570.011,138,632.46 5,951,588.00
1,646,894.00
plan misses target center by 1139915.15usft at 10500.00usft MD (5895.64 TVD,-1355.05 N,-1262.91 E)
Rectangle (sides W1,000.00 H1.00 D0.00)
2B-02A_Fault2 0.00 0.00 0.00-4,602.151,138,747.44 5,951,556.00
1,647,009.00
plan misses target center by 1140030.22usft at 10500.00usft MD (5895.64 TVD,-1355.05 N,-1262.91 E)
Rectangle (sides W1,000.00 H1.00 D0.00)
26-02AL1_Faultl 0.00 0.00 0.00-3,525.931,138,649.63 5,952,632.00
1,646,910.00
plan misses target center by 1139929.85usft at 10500.00usft MD (5895.64 TVD,-1355.05 N,-1262.91 E)
Rectangle (sides W1,000.00 H1.00 D0.00)
2B-02AL2-01_T01 0.00 0.00 5,966.00-4,530.86 1,138,501.49 5,951,627.00
1,646,763.00
plan misses target center by 1139768.83usft at 10500.00usft MD (5895.64 TVD,-1355.05 N,-1262.91 E)
Point
26-02AL2-01_T02 0.00 0.00 5,896.00-2,874.121,138,882.37 5,953,284.00 1,647,142.00
plan misses target center by 1140146.30usft at 10500.00usft MD (5895.64 TVD,-1355.05 N,-1262.91 E)
Point
213-02 CTD Polygon We:
0.00 0.00 0.00
-4,661.861,138,482.34
5,951,496.00
- plan misses target center by 1139765.30usft at 10500.00usft
MD (5895.64 TVD,-1355.05 N,-1262.91 E)
Polygon
Point 1
0.00
0.00
0.00
5,951,496.00
Point
0.00
83.16
-138.93
5,951,579.00
Point
0.00
253.37
-322.76
5,951,748.99
Point
0.00
489.49
-416.52
5,951,984.98
Point 5
0.00
732.51
-413.26
5,952,227.98
Point 6
0.00
965.45
-329.01
5,952,460.99
Point
0.00
1,107.29
-165.84
5,952,602.99
Point
0.00
1,211.08
35.29
5.952,707.00
Point
0.00
1,256.87
237.36
5,952,753.01
Point 10
0.00
1,134.84
260.23
5,952,631.02
Point 11
0.00
971.79
292.06
5,952,468.02
Point 12
0.00
940.93
157.02
5,952,437.01
Point 13
0.00
902.03
55.96
5,952,398.00
Point 14
0.00
843A1
-27.11
5,952,339.00
Point 15
0.00
767.16
-79.19
5,952,262.99
Point 16
0.00
663.18
-111.31
5,952,158.99
Point 17
0.00
538.17
-107.44
5,952,034.00
Point 18
0.00
444.12
-69.54
5,951.940.00
Point 19
0.00
350.03
6.37
5,951.846.00
Point20
0.00
294.93
90.32
5,951,791.00
Point21
0.00
0.00
0.00
5,951,496.00
1,646,744.00
1, 646, 744.00
1, 646, 604.99
1,646,420.99
1, 646, 326.98
1, 646, 329.97
1,646,413.95
1,646,576.94
1,646,777.94
1,646,979.94
1,647, 002.94
1,647, 034.95
1, 646, 899.96
1, 646, 798.95
1, 646, 715.95
1,646,663.96
1,646,631.96
1, 646, 635.97
1,646,673.97
1, 646, 749.98
1, 646, 833.98
1,646,744.00
70' 2' 30.368 N 140° 47' 46.836 W
70° 2' 29.887 N 140° 47' 43.705 W
70° 2' 40.481 N 140° 47' 41.861 W I
70' 2' 30.940 N 140' 47' S0.390 W
70° 2' 46.469 N 140' 47' 32.442 W I
70' 2' 29.697 N 140° 47' 51.497 W
Casing Points
Measured Vertical Casing Hole
Depth Depth Diameter Diameter
(usft) (usft) Name (in) (in)
10,500.00 5,895.64 2 3/8" 2 375 3.000
711112016 12:15:59PM Page 5 COMPASS 5000.1 Build 74
101, ConocoPhillips CA..
ConocoPhillips Planning Report BAKER
HUGHES
Database:
EDM Alaska NSK Sandbox
Company:
ConocoPhillips (Alaska) Inc. -Kup2
Project:
Kuparuk River Unit
Site:
Kuparuk 213 Pad
Well:
2B-02
Well bore:
26-02AL2-01
Design:
2 B-02AL2-01 _wp01
Plan Annotations
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Measured
Vertical
Local Coordinates
Depth
Depth
+N/-S
+E/-W
(usft)
(usft)
(usft)
(usft)
Comment
8,300.00
5,996.92
-3,114.17
-1,367.64
TIP/KOP
8,400.00
5,988.69
-3,096.24
-1,465.49
Start 12 dls
8,600.00
5,965.80
-3,012.57
-1,644.08
3
8,800.00
5,955.42
-2,863.80
-1,775.14
4
9,050.00
5,943.76
-2,624.62
-1,836.31
5
9,525.00
5,945.75
-2,226.28
-1,615.07
6
9,725.00
5,955.45
-2,087.11
-1,473.81
7
10,025.00
5,944.69
-1,803.69
-1,392.34
8
10,200.00
5,919.54
-1,633.62
-1,365.39
9
10,300.00
5,907.89
-1,543.61
-1,323.85
10
10,500.00
5,895.64
-1,355.05
-1,262.91
Planned TD at 10500.00
Well 2B-02
Mean Sea Level
28-02 @ 126.00usft (2B-02)
True
Minimum Curvature
711112016 12:15:59PM Page 6 COMPASS 5000.1 Build 74
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- ConocoPhillips WIN
ConocoPhillips Travelling Cylinder Report BAKER
HUGHES
Company:
ConocoPhillips (Alaska) Inc -Kup2
Project:
Kuparuk River Unit
Reference Site:
Kuparuk 2B Pad
Site Error:
0 00 usft
Reference Well:
2B-02
Well Error:
0 00 usft
Reference Wellbore
2B-02AL2
Reference Design:
2B-02AL2_wp02
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Output errors are at
Database:
Offset TVD Reference:
Well 2B-02
2B-02 @ 126 00usft (26-02)
2B-02 @ 126.00usft (213-02)
True
Minimum Curvature
1.00 sigma
EDM Alaska ANC Prod
Offset Datum
teference
2B-02AL2_wp02
'ilter type:
GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
iterpolation Method:
MD Interval 25.00usft Error Model: ISCWSA
lepth Range:
6,600.00 to 9,900.00usft Scan Method: Tray. Cylinder North
results Limited by:
Maximum center -center distance of 1,177.40 usft Error Surface: Elliptical Conic
Survey Tool Program Date 7/8/2016
From To
(usft) (usft) Survey (Wellbore) Tool Name Description
200.00 6,600.00 2B-02 (213-02) GCT-MS Schlumberger GCT multishot
6,600.00 9,900.00 2B-02AL2_wp02 (2B-02AL2) MWD MWD - Standard
Casing Points
Measured Vertical Casing Hole
Depth Depth Diameter Diameter
(usft) (usft) Name
9,900,00 6,090.75 2 3/8" 2-3/8 3
I
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 2B Pad
213-02 - 28-02 - 213-02
6,649.97
6,650.00
0.69
1.94
-1.24
FAIL - Major Risk
2B-02 - 2B-02A - 213-02A_wp05
6,62500
6,625.00
0.00
0.46
-0.45
FAIL - Minor 1/10
2B-02 - 2B-02AL1 - 2B-02AL1_wp02
6,625.00
6,625,00
0.00
0.46
-0.45
FAIL - Minor 1/10
28-02 - 2B-02AL1-01 - 2B-02AL1-01_wp02
6,625.00
6,625.00
0.00
0.46
-0,45
FAIL- Minor 1/10
213-02 - 2B-02AL2-01 - 26-02AL2-01_wp01
8,300.00
8,300.00
0.00
0.35
-0.22
FAIL - Minor 1/10
28-03 - 28-03 - 213-03
8,050.00
6,950,00
1,161.64
21T90
953.99
Pass - Major Risk
2B-03 - 2B-03A - 213-03A
8,050.00
6,950.00
1.161.64
217.90
953.99
Pass - Major Risk
2B-04 - 2B-04 - 2B-04
26-06 - 213-06 - 2B-06
Out of range
Out of range
2B-07 - 2B-07 - 26-07
9,775.00
7,575.00
968.48
283.65
711.70
Pass - Major Risk
Offset Design
Kuparuk 2B Pad
- 213-02 - 213-02 - 2B-02
Survey Program: 200-GCT-MS
Rule Assigned: Major Risk
Offset Site Error: 0 00 usft
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
Depth
Depth
Depth
Depth
Azimuth
+N/-s
+E/-W
Hole Size
Centre
Distance
Warning
Deviation
(usft)
(usft)
(usft)
(usft)
(usft)
(usft)
(")
(usft)
(usft)
1")
(usft)
(usft)
(usft)
6,625.00
6,026,39
6,625.00
6,026+39
0.07
0.14
3.69
-1.832.49
-677.43
2-11/16
0.00
1_01
-0,97 FAIL- Major Risk, CC
6,649.97
6,047.10
6,650.00
6,04Z51
0,08
0,28
17.20
-1,845.22
-681.53
2-11/16
0.69
1.94
-1.24 FAIL- Major Risk, ES, SF
6,674,29
6,065.44
6,675.00
6,068.62
0.09
0.42
17.35
-1,857.96
-685.67
2-11/16
4.43
3.32
1.11 Pass - Major Risk
6,696.80
6,079.79
6,700.00
6,089.71
0.09
0.56
17.41
-1,870.71
-689.83
2-11/16
12.14
4.58
7,56 Pass - Major Risk
6,716,75
6,090.11
6.725,00
6,110,80
0.10
0.70
17.46
-1,883,47
-694.00
2-11/16
23,26
5,62
17,64 Pass - Major Risk
6,733,92
6,097,02
6,750.00
6,131.89
0,11
0.84
17.50
-1.896.23
-698A7
2-11/16
37.19
6.46
30.72 Pass - Major Risk
6,748.46
6,101.37
6.775.00
6, 152.99
0,12
0.98
17,54
-1,908.99
-702.34
2-11/16
53,32
7.12
46.20 Pass - Major Risk
6,760.00
6,103,80
6,800.00
6,174,08
0.13
1.12
17,57
-1,921.75
-706,50
2.11/16
71.16
7.62
63,54 Pass - Major Risk
6,770.00
6,105.17
6.825.00
6,195.17
0.14
1,26
17.60
-1,934,61
-710.67
2-11/16
90.32
8,03
82.31 Pass - Major Risk
6,78000
6,105.85
6,850.00
6,21626
0.14
1,40
17.61
-1,947,27
-714,83
2-11/16
110.49
8.43
102.14 Pass - Major Risk
CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation
71812016 10.39:13AM Page 2 COMPASS 5000 1 Build 74
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101ConocoPhillips BAKER..
ConocoPhillips Travelling Cylinder Report
HUGHES
Company:
ConocoPhillips (Alaska) Inc. -Kup2
Project:
Kuparuk River Unit
Reference Site:
Kuparuk 2B Pad
Site Error:
0,00 usft
Reference Well:
213-02
Well Error:
0 00 usft
Reference Wellbore
2B-02AL2-01
Reference Design:
2B-02AL2-01_wp01
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Output errors are at
Database:
Offset TVD Reference:
Well 2B-02
213-02 @ 126 00usft (2B-02)
2B-02 @ 126.00usft (213-02)
True
Minimum Curvature
1 00 sigma
EDMAlaska ANC Prod
Offset Datum
Reference 2B-02AL2-01_wp01
=ilter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
nterpolation Method: MD Interval 25.00usft Error Model: ISCWSA
)epth Range: 8,300.00 to 10,500.00usft Scan Method: Tray. Cylinder North
Results Limited by: Maximum center -center distance of 1,237.40 usft Error Surface: Elliptical Conic
Survey Tool Program Date 7/8/2016
From To
(usft) (usft) Survey (Wellbore)
Tool Name
Description
200.00 6,600.00 26-02 (2B-02)
GCT-MS
Schlumberger GCT multishot
6,600.00 8,300.00 2B-02AL2_wp02 (26-02AL2)
MWD
MWD- Standard
8,300.00 10,500.00 2B-02AL2-01_wp01 (2B-02AL2-01)
MWD
MWD- Standard
Casing Points
Measured Vertical
Casing Hole
Depth Depth
Diameter Diameter
(usft) (usft)
Name
(") (")
10,500.00 6,021.64 2 3/8"
2-3/8 3
Summary
Reference
Offset
Centre to
No -Go
Allowable
Measured
Measured
Centre
Distance
Deviation
Warning
Site Name
Depth
Depth
Distance
(usft)
from Plan
Offset Well - Wellbore - Design
(usft)
(usft)
(usft)
(usft)
Kuparuk 2B Pad
28-02 - 213-02 - 26-02
9,959.12
6,825.00
697.60
47.70
656.03
Pass - Major Risk
213-02 - 213-02A - 2B-02A_wp05
8,571.45
8,525.00
21.12
0.53
2077.
Pass - Minor 1/10
2B-02 - 213-02AL1 - 2B-02AL1_wp02
8,913.61
8,850,00
1.65
0.51
0.52
Pass - Minor 1/10
28-02 - 2B-02AL1-01 - 2B-02AL1-01_wp02
8,707.70
8,650.00
16.01
0.54
15.78
Pass - Minor 1/10
213-02 - 2B-02AL2 - 2B-02AL2_wp02
8,300.00
8,300.00
0.00
0.35
-0.22
FAIL - Minor 1/10
213-03 - 28-03 - 213-03
Out of range
2B-03 - 28-03A - 2B-03A
Out of range
28-04 - 213-04 - 213-04
Out of range
26-06 - 28-06 - 2B-06
Out of range
28-16 - 28-16 - 26-16
Out of range
Offset Design
Kuparuk 2B Pad - 213-02 - 213-02 - 213-02
Survey Program: 200-GCT-MS
Rule Assigned: Major Risk
Offset Site Error: 0 00 usft
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
Depth
Depth
Depth
Depth
Azimuth
+N/-S
+E/-W
Hole Size
Centre
Distance
Warning
Deviation
(usft)
(usft)
(usft)
(usft)
(usft)
(usft)
(°)
(usft)
(usft)
(")
(usft)
(usft)
(usft)
9,925.00
6,079,65
6,950.00
6,300.63
2.83
1.96
118.45
-1,998,31
-731,48
2-11/16
710.52
48,23
667.05 Pass - Major Risk
9,926.00
6,079.65
6,975.00
6.321.72
2.83
2.10
120,03
-2,011,07
-735.65
2-11116
715.31
48.44
671.32 Pass - Major Risk
9,925.00
6,079+65
6,976.00
6,322.56
2.83
2,11
120.10
-2,01t58
-735,81
2-11/16
715.51
48.45
671.51 Pass - Major Risk
9,935.21
6,078,97
6,925.00
6,279.54
2.82
1.82
115.58
-1,985,55
-72Z32
2-11/16
70641
48,17
663.37 Pass - Major Risk
9,941.15
6,078,56
6,900,00
6,258.44
2.82
1,68
113.22
-1,972.79
-723.16
2-11/16
703,07
48.05
660.41 Pass - Major Risk
9,950.00
6,077.90
6,850.00
6,216,26
2.81
1.40
108,83
-1,947.27
-714.83
2-11/16
698.68
47,77
656.77 Pass- Major Risk
9,950.00
6,077,90
6,875,00
6.237,35
2.81
1,54
110.47
-1,960,03
-718,99
2-11/16
700.50
47.97
658,19 Pass - Major Risk
9,959.12
6,077A8
6,825.00
6,196.17
2,81
1.26
106.03
-1,934,51
-710.67
2-11/16
697.60
47.70
656.03 Pass- Major Risk, ES, SF
9,965,17
6,076.67
6,800.00
6,174.08
2.80
1.12
103.61
-1,921.75
-706.50
2-11/16
697.31
47.58
656.09 Pass - Major Risk, CC
��- •� _�......--yanr puim or - min separation Tactor, Ls - min ellipse separation
71812016 10:57.16AM Page 2 COMPASS 5000.1 Build 74
TRANSMITTAL LETTER CHECKLIST
WELL NAME:
PTD: 02 —
/ Development Service _ Exploratory _ Stratigraphic Test _ Non -Conventional
FIELD: )4,A-rJ< Riy POOL: ZV
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. API No. 50- o a- a I ► ,5LJ -_PL- OC'> .
I/
(If last two digits
Production should continue to be reported as a function of the original
in API number are
API number stated above.
between 60-69)
In accordance with 20 AAC 25.005(f), all records, data and logs
acquired for the pilot hole must be clearly differentiated in both well
Pilot Hole
name ( PH) and API number (50- -
- - from records, data and logs acquired for well
(name on ermit).
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce/inject is contingent upon issuance of a conservation
Spacing Exception
order approving a spacing exception. (Company Name) Operator
assumes the liability of any protest to the spacing exception that may
occur.
All dry ditch sample sets submitted to the AOGCC must be in no greater
Dry Ditch Sample
than 30' sample intervals from below the permafrost or from where
samples are first caught and 10' sample intervals through target zones.
Please note the following special condition of this permit:
production or production testing of coal bed methane is not allowed for
Non -Conventional
(name of well) until after (Company Name) has designed and
Well
implemented a water well testing program to provide baseline data on
water quality and quantity. (Company Name) must contact the AOGCC
to obtain advance approval of such water well testing program.
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of
well logs to be run. In addition to the well logging program proposed by
(Company Name) in the attached application, the following well logs are
also required for this well:
Well Logging
Requirements
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for well logs run must be submitted to the AOGCC
within 90 days after completion, suspension or abandonment of this well.
Revised 2/2015
WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100
Well Name: KUPARUK RIV UNIT 2B-02AL2-01 Program DEV Well bore seg d❑
PTD#:2160910 Coml
Administration 17
1
Appr Date
PKB 7/15/2016
Engineering
Appr Date
VTL 8/15/2016
Geology
Appr Date
PKB 7/15/2016
5
6
7
8
9
10
11
12
13
14
15
16
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
my CONOCOPHILLIPS ALASKA_INC Initial Class/Type
DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal
Nonconven. gas conforms to AS31.05.0300.1_.A),Q.2_.A-D)
NA
Permit fee attached
NA
Lease number appropriate_ -
Yes
ADL0025655, Surf Loc; ADL0025656, Top Prod_Interv._& TD._
Unique well name and number
Yes
KRU 2B-02AL_2-01
Well located in_a_defined pool
Yes
KUPARUK RIVER, KUPARUK RIV OIL - 490100,.goyerned_by Conservation_ Order No. 432D._
Well located proper distance from drilling unit _boundary-
Yes
CO 432D contains no spacing restrictions with respect to drilling unit boundaries.
Well located proper distance from other wells_
Yes
CO 432D has no interwell -spacing -restrictions.
Sufficient acreage available in -drilling unit
Yes
If deviated, is_wellbore plat -included _ _ _
Yes
Operator only affected party _ - - - _ _ _ _ _ _ _ _ _ _ _ _ _
Yes _
- - Wellbore.will be_ more than 500' from an external property line where_ ownership or landownership_ changes
Operator has appropriate_ bond in force
Yes
Permit can be issued without conservation order
Yes
Permit can be issued without administrative approval
Yes
Can permit be approved before 15-day wait
Yes
Well located within area andstrataauthorized by Injection Order# (put_10# in comments) -(For-
NA_All
wells within _1/4_ mile_area_of review identified (For service well only) _
NA_
Pre -produced injector: duration of pre production less than 3 months (For service well only)
NA
Conductor string provided
NA
Conductor set_ in KRU 2B-02
Surface casing protects all known USDWs
NA
Surface casing set in KRU 2-02
CMT vol adequate_ to circulate -on conductor_ & surf_csg
NA
Surface casing set and fully cemented
CMT- vol adequate_ to tie -in -long string to surf csg-
NA
CMT will cover all known productive horizons
No
Productive interval will be completed with_uncemented slotted liner
Casing designs adequate for C, T, B & permafrost
Yes
Adequate tankage or reserve pit
Yes
Rig has steel tanks, all waste to approved disposal wells
If_a re -drill, has a 10-403 for abandonment been approved
NA
Adequate wellbore separation proposed
Yes
Anti -collision analysis complete; no major risk failures
If diverter required, does it meet regulations
NA
Drilling fluid program schematic & equip list adequate
Yes
Max formation pressure is 3973 psig(12.6 ppg EMW); will drill w/ 8.6 ppg EMW and maintain overbal w/ MPD
BOPEs, do they meet regulation
Yes
BOPE press rating appropriate; test to (put psig in comments)
Yes
MPSP is 3369 psig; will test BOPS to 3750 psig
Choke manifold complies w/API RP-53 (May 84)
Yes
Work will occur without operation shutdown_
Yes
Is presence of 112S gas probable -
Yes
H2S measures required
Mechanical condition of wells within AOR verified (For service well only)
NA
35 Permit can be issued w/o hydrogen -sulfide measures No
36 Data presented on potential overpressure zones Yes
37 Seismic analysis of shallow gas zones NA
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 Corpmissioner Date
L) S �//6/ice, �i 8 -/6-/� ��►-� (l e
Wells on 213-Pad are_H2S-bearing. 112S measures -required.
Max. potential_ reservoir pressure is 12.6 ppg EMW-,will be drilled using 8.6 ppg mud and MPD technique.
Onshore development well to be drilled,
