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HomeMy WebLinkAbout218-113Carlisle, Samantha J (DOA)
From:
Davies, Stephen F (DOA)
Sent:
Monday, February 11, 2019 3:41 PM
To:
Carlisle, Samantha J (DOA)
Cc:
Boyer, David L (DOA)
Subject:
Withdraw the Permits to Drill for KRU 2G-061_1-01 (PTD 218-113), L1-02 (PTD 218-114),
and L1-03 (PTD 218-115)
Attachments:
2G-06A_wp06 MD - NAD27.txt; 2G-06AL1_wp05 MD - NAD27.txt; 2G-06AL2_wp03 MD -
NAD27.txt; 2G-06AL2-01_wp03 MD - NAD27.txt
Sam,
Please place a copy of the email below in the following well history files: KRU 2G-06L1-01 (PTD 218-113), L1-02 (PTD
218-114), and L1-03 (PTD 218-115).
Thanks,
Steve D.
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 Steve Davies at 907-793-1224 or steve.davies@alaska.gov.
From: Herring, Keith E <Keith.E.Herring@conocophillips.com>
Sent: Monday, February 11, 2019 3:26 PM
To: Davies, Stephen F (DOA) <steve.davies@alaska.gov>
Subject: RE: [EXTERNAL]Survey Digital Files for KRU 2G-06A, KRU 2G-06AL1, KRU 2G-06AL2, and KRU 2G-06AL2-01
Steve,
Please see attached.
As per our conversation please withdraw the Permit to Drill applications for the KRU 2G-06L1-01, L1-02, and L1-03 that
were issued during 2018.
Thanks,
Keith Herring
CTD Engineer
907.263.4321 (Office)
907.570.2410 (Mobile)
700 G Street, ATO — 664
Keith. F,.Hening(�Pconocophillips.com
ConocoPhillips
From: Davies, Stephen F (DOA) <steve.davies@alaska.gov>
Sent: Monday, February 11, 2019 3:06 PM
To: Herring, Keith E <Keith.E.Herring@LunocophilIips.com>
Subject: [EXTERNAL]Survey Digital Files for KRU 2G-06A, KRU 2G-06AL1, KRU 2G-06AL2, and KRU 2G-06AL2-01
Keith,
Could CPAI please provide digital files of the proposed directional surveys for KRU 2G-06A, KRU 2G-06AL1, KRU 2G-
06AL2, and KRU 2G-06AL2-01? Having these files will speed review of the Permit to Drill applications for these
wellbores. Excel spreadsheet or ASCII table formats are acceptable. I only need MD, Azimuth and Inclination
information.
Does CPAI wish to withdraw the Permit to Drill applications for KRU 2G-06L1, L1-01, L1-02 and L1-03 that were issued
during 2018?
Thank you for your help,
Steve Davies
Senior Petroleum Geologist
Alaska Oil and Gas Conservation Commission (AOGCC)
907-793-1224
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 Steve Davies at 907-793-1224 or steve.daviesC@alaska.gov.
From: Herring, Keith E <Keith.E.Herring@conocophillips.com>
Sent: Friday, September 21, 2018 9:16 AM
To: Boyer, David L (DOA) <david.boVer2@a1aska.gov>
Cc: Davies, Stephen F (DOA) <steve.davies@alaska.gov>; Long, William R <William.R.Long@conocophillips.com>
Subject: RE: [EXTERNAL]Survey Digital Files for KRU 2G-06L1, 1-1-01, L1-02 and L1-03
Dave,
Please see attached.
Thanks,
Keith Herring
CTD Engineer
907.263.4321 (Office)
907.570.2410 (Mobile)
700 G Street, ATO — 664
Keith.E.Herring@conocophillips.com
r
Kaska
From: Boyer, David L (DOA) <david.boyer2@alaska.g_ov>
Sent: Friday, September 21, 2018 8:46 AM
To: Herring, Keith E <Keith.E.Herring@conocophillips.com>
Cc: Davies, Stephen F (DOA) <steve.davies@alaska.gov>
Subject: [EXTERNAL]Survey Digital Files for KRU 2G-06L1, 1-1-01, L1-02 and L1-03
Hi Keith,
Permit to Drill Applications for the 4 KRU 2G-06 laterals on 09/18. Steve and I are reviewing them and see that the first
lateral is scheduled for 10/01/18. If you can e-mail me digital surveys (Excel or ASCII text files) for the 4 laterals, it really
speeds up the data entry into our Geographics database. We only load the MD, inclination, and azimuth columns but if it
is easier to send the Baker Hughes files, we can extract what we need to plot the well on our maps.
Thank you,
Dave Boyer
Senior Geologist
AOGCC
THE STATE
fALASKA
GOVERNOR BILL WALKER
James Ohlinger
Staff CTD Engineer
ConocoPhillips Alaska, Inc.
PO Box 100360
Anchorage, AK 99510-0360
Alaska Oil and Gas
Conservation Commission
Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 2G-06L1-01
ConocoPhillips Alaska, Inc.
Permit to Drill Number: 218-113
Surface Location: 547' FSL, 236' FWL, SEC. 32, T11N, R9E, UM
Bottomhole Location: 5221' FNL, 1312' FEL, SEC. 29, T11N, R9E, UM
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Dear Mr. Ohlinger:
Enclosed is the approved application for the permit to redrill the above referenced development well.
The permit is for a new wellbore segment of existing well Permit No. 184-082, API No. 50-029-21121-007
00. Production should continue to be reported as a function of the original API number stated above.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must
be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well.
This permit to drill does not exempt you from obtaining additional permits or an approval required by law
from other governmental agencies and does not authorize conducting drilling operations until all other
required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw
the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an
applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC
order, or the terms and conditions of this permit may result in the revocation or suspension of the permit.
Sincerely,
6399���
Hollis S. French
Chair
DATED this day of October, 2018.
STATE OF ALASKA
ALA -,.A OIL AND GAS CONSERVATION COMMIS-iON
PERMIT TO DRILL
20 AAC 25.005
1 a. Type of Work: •
1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑
1 c. Specify if well is proposed for:
Drill ❑ Lateral R1
Stratigraphic Test ❑ Development - Oil El * Service - Winj ❑ Single Zone ❑� '
Coalbed Gas ❑ Gas Hydrates ❑
Redrill ❑ Reentry ❑
Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑
Geothermal ❑ Shale Gas ❑
2. Operator Name:
5. Bond: Blanket Q Single Well ❑
11. Well Name and Number:
ConocoPhillips Alaska, Inc.
Bond No. 5952180
i
KRU 2G-061-1-01
3. Address:
6. Proposed Depth:
12. Field/Pool(s):
P.O. Box 100360 Anchorage, AK 99510-0360
MD: 9750' TVD: 5859'
Kuparuk River Field /
Kuparuk River Oil Pool
4a. Location of Well (Governmental Section):
7. Property Designation:
Surface: 547' FSL, 236' FWL, Sec 32, T11 N, R9E, UM
ADL 25656
Top of Productive Horizon:
8. DNR Approval Number:
13. Approximate Spud Date:
1238' FNL, 1175' FEL, Sec 32, T11N, R9E, UM
LONS 82-180
10/1/2018
Total Depth:
9. Acres in Property:
14. Distance to Nearest Property:
5221' FNL, 1312' FEL, Sec 29, T11 N, R9E, UM
2491
23075'
4b. Location of Well (State Base Plane Coordinates - NAD 27):
10. KB Elevation above MSL (ft): 140' ,
15. Distance to Nearest Well Open
Surface: x- 508930 - y- 5944135 , Zone- 4
GL / BF Elevation above MSL (ft): 104'
to Same Pool: 525', 2F-20
16. Deviated wells: Kickoff depth: 8400' feet
17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 99 degrees
Downhole: 4,908 Surface: 4,320
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
1450'
8300'
5913'
9750'
5859'
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):
8485'
6253'
N/A
8368'
6158'
8158'
Casing
Length
Size
Cement Volume
MD
TVD
Conductor/Structural
72'
16"
202 sx Cold Set II
110,
110,
Surface
3097'
9-5/8"
1035 sx PF E, 250 sx PF C
3134'
2774'
Production
8413'
7"
575 sx Class G, 250 sx PF C
8449'
6224'
Perforation Depth MD (ft): 8188' - 8198'
Perforation Depth TVD (ft): 6013' - 6021'
8216' - 8246'
6035- 6060'
Hydraulic Fracture planned? Yes ❑ No ❑✓
20. Attachments: Property Plat ❑ Sketch
ing Program
❑ DSleabed
v. Depth Shallowduiements8
❑ eFluid ❑
DivBOP
erter Sketch
Report
20 AAC 25.050 regot
Drilling Program
21. Verbal Approval: Commission Representative: Date
22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval. Contact Name: Keith Herring
Authorized Name: James Ohlinger Contact Email: Keith. E.Herrin c0 .com
Authorized Title: Staff CTD Engineer Contact Phone: 907-263-4321
Date: 19/ �IR
Authorized Signature:
Commission Use Only
Permit to Drill
API Number: Permit
Approval p
See cover letter for other
Number: $ -� 13
50- Q� (� — O
Date: ��ii
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: EK
Other: l3oP tcs f SG�� ��� - Samples req'd: Yes ❑ No ER" Mud log req'd: Yes❑ NoE'r
to y
i / "t-7 1/1 a r- /j7 l v vv fl s f2' j 7` �d .25H2,S measures: Yes [� No[:] Directional svy req'd: Yes [� No ❑
-
6/$11 )Spacing exception req'd: Yes ❑ NoEyJ/ Inclination -only svy req'd: Yes❑ No[Y
Post initial injection MIT req'd: Yes ElNoE�_
7=J 7'c C1 /!ow 7�� kiLk 5) P6)' 7' fo be cr�cih -/ }ham
cely«
PG�rt<�7-
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date: 4 Its
IO Jr7L O Submit Form and
Form 10-401 Revised 5/2017 This ermit is valid for f)RsJfjt1e e�a proval per 20 AAC 2 05(g) Attachments in Duplicate
.+� / f% P, 8. wl Z�rl rs ✓e.
ConocoPs
philli
Alaska
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
September 10, 2018
Commissioner - State of Alaska
Alaska Oil & Gas Conservation Commission
333 West 7th Avenue Suite 100
Anchorage, Alaska 99501
Dear Commissioner:
ConocoPhillips Alaska, Inc. hereby submits applications for permits to drill four laterals out of the KRU 2G-06
(PTD# 184-082) using the coiled tubing drilling rig, Nabors CDR3-AC.
CTD operations are scheduled to begin in October 2018. The objective will be to drill four laterals, KRU 2G-
061-1, 2G-061_1-01, 2G-061-1-02, and 2G-061-1-03, targeting the Kuparuk A -sand interval.
To account for geological uncertainties, ConocoPhillips requests a variance from the requirements of 20
AAC 25.015 to allow the actual kick-off point to be anywhere along the length of the parent lateral instead of
being limited to 500' from the original point.
Attached to this application are the following documents:
— Permit to Drill Application Forms (10-401) for 2G-061-1, 2G-061-1-01, 2G-06L1-02, and 2G-06L1-03
— Detailed Summary of Operations
— Directional Plans for 2G-061-1, 2G-061-1-01, 2G-061-1-02, and 2G-061-1-03
— Current wellbore schematic
— Proposed CTD schematic
If you have any questions or require additional information, please contact me at 907-263-4321.
Sincerely,
Keith Herring
Coiled Tubing Drilling Engineer
ConocoPhillips Alaska
Kuparuk CTD Laterals
2G-061-1, 2G-06L1-01, 2G-061-1-02, and 2G-0611-1-03
Application for Permit to Drill Document
1.
Well Name and Classification........................................................................................................ 2
(Requirements of 20 AAC 25.005(o and 20 AAC 25.005(b))................................................................................................................... 2
2.
Location Summary.......................................................................................................................... 2
(Requirements of 20 AAC 25.005(c)(2))..................................................................................................................................................2
3.
Blowout Prevention Equipment Information................................................................................. 2
(Requirements of 20 AAC 25.005(c)(3)).................................................................................................................................................2
4.
Drilling Hazards Information and Reservoir Pressure.................................................................. 2
(Requirements of 20 AAC 25.005(c)(4))................................................................................................................................................. 2
5.
Procedure for Conducting Formation Integrity tests................................................................... 2
(Requirements of 20 AAC 25.005(c)(5)).................................................................................................................................................. 2
6.
Casing and Cementing Program.................................................................................................... 3
(Requirements of 20 AAC 25.005(c)(6)).................................................................................................................................................. 3
7.
Diverter System Information.......................................................................................................... 3
(Requirements of 20 AAC 25.005(c)(7)).................................................................................................................................................. 3
8.
Drilling Fluids Program.................................................................................................................. 3
(Requirements of 20 AAC 25.005(c)(8)).................................................................................................................................................. 3
9.
Abnormally Pressured Formation Information............................................................................. 4
(Requirements of 20 AAC 25.005(c)(9)).................................................................................................................................................. 4
10.
Seismic Analysis............................................................................................................................. 4
(Requirements of 20 AAC 25.005(c)(10))................................................................................................................................................4
11.
Seabed Condition Analysis............................................................................................................4
(Requirements of 20 AAC 25.005(c)(11))................................................................................................................................................ 4
12.
Evidence of Bonding...................................................................................................................... 4
(Requirements of 20 AAC 25.005(c)(12))................................................................................................................................................ 4
13. Proposed Drilling Program.............................................................................................................4
(Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 4
Summaryof Operations...................................................................................................................................................4
LinerRunning...................................................................................................................................................................6
14. Disposal of Drilling Mud and Cuttings.......................................................................................... 6
(Requirements of 20 AAC 25.005(c)(14))................................................................................................................................................ 6
15. Directional Plans for Intentionally Deviated Wells....................................................................... 7
(Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 7
16. Attachments.................................................................................................................................... 7
Attachment 1: Directional Plans for 2G-061-1, 2G-06L1-01, 2G-061-1-02, and 2G-061-1-03 laterals................................7
Attachment 2: Current Well Schematic for 2G-06...........................................................................................................7
Attachment 3: Proposed Well Schematic for 2G-061-1, 2G-06L1-01, 2G-061-1-02, and 2G-061-1-03 laterals.................7
Page 1 of 7 September 10, 2018
PTD Application: 2G-06L1, 2G-06L1-01, 2G-06L1-02, and 2G-06L1-03
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 2G-061-1, 2G-061-1-01, 2G-061-1-02, and 2G-061-1-03. All
laterals will be classified as "Development -Oil" wells.
2. Location Summary
(Requirements of 20 AAC 25.005(c)(2))
These laterals will target the A sand package in the Kuparuk reservoir. See attached 10-401 forms for surface
and subsurface coordinates of each of the laterals.
3. Blowout Prevention Equipment Information
(Requirements of 20 AAC 25.005 (c)(3))
Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR3-AC.
BOP equipment is as required per 20 AAC 25.036 for thru-tubing drilling operations.
— Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 5,000 psi. Using the
maximum formation pressure in the area of 4,908 psi in 213-05 (i.e. 15.5 ppg EMW), the maximum
potential surface pressure in 2G-06, assuming a gas gradient of 0.1 psi/ft, would be 4,320 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 2G-06 was measured to be 3,897 psi (12.6 ppg EMW) on 7/15/2018. The
maximum downhole pressure in the 2G-06 vicinity is the 213-05 at 4,908 psi or 15.5 ppg EMW.
Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b))
No specific gas zones will be drilled; gas injection has been performed in this area, so there is a chance of f
encountering gas while drilling the 2G-06 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 2G-06 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 2G-06 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 September 10, 2018
PTD Application: 2G-06L1, 2G-061_1-01, 2G-061_1-02, and 2G-061_1-03
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
2G-06L1
8,400'
9,750'
5,912'
5,882'
23/", 4.7#, L-80, ST-L slotted liner;
aluminum billet on to
2G-06L1-01
8,300'
9,750'
5,913'
5,859'
23/", 4.7#, L-80, ST-L slotted liner;
aluminum billet on to
2G-061_1-02
8,400'
9,900,
5,914'
5,898'
2'/", 4.7#, L-80, ST-L slotted liner;
aluminum billet on to
2G-061_1-03
8,006'
9,900,
5,730'
5,873'
2%", 4.7#, L-80, ST-L slotted liner;
deployment sleeve on to
Existing Casing/Liner Information
Category
OD
Weigh
t
Grade
Connection
Top MD
Btm MD
Top
TVD
Btm
TVD
Burst
psi
Collapse
psi
Conductor
16"
62.5
H-40
Welded
Surface
110,
Surface
110,
1640
670
Surface
9-5/8"
36
J-55
BTC
Surface
3134'
Surface
2774'
3520
2020
Production
7"
26
J-55
BTC
Surface
8449'
Surface
6224'
4980
4320
Tubing
3-1/2"
9.3
L-80
EUE 8rd MOD
Surface
8044'
Surface
5899'
10,160
10,540
7. Diverter System Information
(Requirements of 20 AAC 25.005(c)(7))
Nabors CDR3-AC will be operating under 20 AAC 25.036, for thru-tubing drilling operations. Therefore, a
diverter system is not required.
8. Drilling Fluids Program
(Requirements of 20 AAC 25.005(c)(8))
Diagram of Drilling System
A diagram of the Nabors CDR3-AC mud system is on file with the Commission.
Description of Drilling Fluid System
— Window milling operations: Water based Power-Vis milling fluid (8.6 ppg)
— Drilling operations: Water based Power -Pro drilling mud (8.6 ppg). This mud weight may not
hydrostatically overbalance the reservoir pressure, overbalanced conditions will be maintained using
MPD practices described below.
— Completion operations: BHA's will be deployed using standard pressure deployments and the well will
be loaded with 12.8 ppg potassium formate completion fluid in order to provide formation over -balance
and maintain wellbore stability while running completions. If higher formation pressures are
encountered the completion brine will be weighted up with potassium formate.
Page 3 of 7 September 10, 2018
PTD Application: 2G-06L1, 2G-06L1-01, 2G-06L1-02, and 2G-06L1-03
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 2G-06 laterals we will target a constant BHP of 12.6 EMW at the window. The constant BHP target will be
adjusted through choke pressure and/or mud weight increases to maintain overbalanced conditions if increased
reservoir pressure is encountered. Additional choke pressure or increased mud weight may also be employed
for improved borehole stability. Any change of circulating friction pressure due to change in pump rates or change
in depth of circulation will be offset with back pressure adjustments.
Pressure at the 2G-06 Window (8,134' MD, 5,970' TVD) Usinq MPD
Pumps On 1.8 b m
Pumps Off
Formation Pressure 12.6
3897 psi
3897 psi
Mud Hydrostatic 8.6
2669 psi
2669 psi
Annular friction i.e. ECD, 0.080 si/ft
650 psi
0 psi
Mud + ECD Combined
no chokepressure)
3319 psi
underbalanced —578psi)
2669 psi
underbalanced —1228psi)
Target BHP at Window 12.6
3911 psi
3911 psi
Choke Pressure Required to Maintain
Target BHP
592 psi
1242 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 2G-06 is a Kuparuk producer equipped with 3-1/2" tubing and 7" production casing. The CTD
sidetrack will utilize laterals to target the Kuparuk A -sands to the north and south of the existing 2G-06
wellbore. The laterals will reclaim resource from the long term shut in rock producer 2G-06 and provide
additional offtake in a high-pressure area.
Page 4 of 7 September 10, 2018
PTD Application: 2G-06L1, 2G-06L1-01, 2G-06L1-02, and 2G-06L1-03
CDR3-AC will set a mechanical whipstock (High Expansion Wedge) inside the 7" casing at the planned
kick off point of 8,134' MD. The 2G-06L1 lateral will exit through the 7" at 8,134'MD and TD at 9,750'
MD, targeting the A sand to the north. It will be completed with 2-3/8" slotted liner from TD up to 8,400'
MD with an aluminum billet for kicking off the 2G-06L1-01 lateral.
The 2G-06L1-01 lateral will drill to a TD of 9,750' MD targeting the A sand to the north. It will be
completed with 2-3/8" slotted liner from TD up to 8,300' MD with an aluminum billet for kicking off the
2G-06L 1-02 lateral.
The 2G-06L1-02 lateral will drill to TD of 9,900' MD targeting the A sand to the south. It will be
completed with 2-3/8" slotted liner from TD up to 8,400' MD with an aluminum billet for kicking off the
2G-06L 1-03 lateral.
The 2G-06L1-03 lateral will drill to TD of 9,900' MD targeting the A sand to the south. It will be
completed with 2-3/8" slotted liner from TD up into the 3-1/2" tubing at 8,006' MD with a deployment
sleeve.
Pre-CTD Work
1. RU Service Coil: Conduct fill cleanout.
2. RU Slickline: Obtain SBHP and conduct dummy whipstock drift.
3. Prep site for Nabors CDR3-AC.
Ria Work
1. MIRU Nabors CDR3-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test.
2. 2G-06L 1 Lateral (A4 sand -North)
a. Set top of high expansion wedge at 8,134' MD.
b. Mill 2.80" window at 8,134' MD.
c. Drill 3" bi-center lateral to TD of 9,750' MD.
d. Run 2%" slotted liner with an aluminum billet from TD up to 8,400' MD.
3. 2G-06L 1-01 Lateral (A4 sand -North)
a. Kickoff of the aluminum billet at 8,400' MD.
b. Drill 3" bi-center lateral to TD of 9,750' MD.
c. Run 2%" slotted liner with aluminum billet from TD up to 8,300' MD.
4. 2G-06L1-02 Lateral (A4 sand - South)
a. Kickoff of the aluminum billet at 8,300' MD.
b. Drill 3" bi-center lateral to TD of 9,900' MD.
c. Run 2%" slotted liner with aluminum billet from TD up to 8,400' MD.
5. 2G-06L1-03 Lateral (A4 sand -South)
a. Kick off of the aluminum billet at 8,400' MD.
b. Drill 3" bi-center lateral to TD of 9,900' MD.
c. Run 2%" slotted liner with deployment sleeve from TD up to 8,006' MD.
6. Obtain SBHP, freeze protect, ND BOPS, and RDMO Nabors CDR3-AC.
Post -Rig Work
1. Return to production.
Page 5 of 7 September 10, 2018
PTD Application: 2G-06L1, 2G-06L1-01, 2G-06L1-02, and 2G-06L1-03
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
- 2G-06 CTD laterals will be displaced to an overbalance completion fluid (as detailed in Section 8 "Drilling
Fluids Program") prior to running liner.
- While running 23/" slotted liner, a joint of 23/" non -slotted tubing will be standing by for emergency
deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a
deployment drill with this emergency joint on every slotted liner run. The 2%" rams will provide
secondary well control while running 23/" liner.
14. Disposal of Drilling Mud and Cuttings
(Requirements of 20 AAC 25.005(c)(14))
• No annular injection on this well.
• All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal.
• Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1 R-18
or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable.
• All wastes and waste fluids hauled from the pad must be properly documented and manifested.
• Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200).
Page 6 of 7 September 10, 2018
PTD Application: 2G-06L1, 2G-06L1-01, 2G-061-1-02, and 2G-061-1-03
15. Directional Plans for Intentionally Deviated Wells
(Requirements of 20 AAC 25.050(b))
- The Applicant is the only affected owner.
- Please see Attachment 1: Directional Plans
- Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run.
- MWD directional, resistivity, and gamma ray will be run over the entire open hole section
- Distance to Nearest Property Line (measured to KPA boundary at closest point)
Lateral Name
Distance
2G-06L1
23,075'
2G-061-1-01
23,075'
2G-06L1-02
22,200'
2G-06L1-03
22,200'
- Distance to Nearest Well within Pool
Lateral Name
Distance
Well
2G-06L1
525'
2F-20
2G-061-1-01
525'
2F-20
2G-061-1-02
1285'
2G-08
2G-06L1-03
1285'
2G-08
16. Attachments
Attachment 1: Directional Plans for 2G-06L 1, 2G-06L 1-01, 2G-06L 1-02, and 2G-06L 1-03 laterals.
Attachment 2: Current Well Schematic for 2G-06.
Attachment 3: Proposed Well Schematic for 2G-06L1, 2G-06L1-01, 2G-06L1-02, and 2G-06L1-03 laterals.
Page 7 of 7 September 10, 2018
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_ConocoPhillips Export Company
Kuparuk River Unit
Kuparuk 2G Pad
2G-06
2G-06L1-01
Plan: 2G-06L1-01_wp05
Standard Planning Report
21 August, 2018
BER
BA 0
GE company
ConocoPhillips BA ER
ConocoPhillips Planning Report IUGHES
a GE company
Database:
EDT 14 Alaska Production
Company:
_ConocoPhillips Export Company
Project:
Kuparuk River Unit
Site:
Kuparuk 2G Pad
Well:
2G-06
Welibore:
2G-061-1-01
Design:
2G-061-1-01 _wp05
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Well 2G-06
Mean Sea Level
2G-06 @ 140.00usft (2G-06)
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
Goo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point
Map Zone: Alaska Zone 04 Using geodetic scale factor
Site
Kuparuk 2G Pad
i
j Site Position:
Northing:
5,944,015.12
usft Latitude:
70° 15' 29.734 N
From:
Map
Easting:
508,649.96
usft Longitude:
149° 55' 48,314 W
Position Uncertainty:
0.00 usft Slot Radius:
0.000 in Grid Convergence:
0.07 °
Well ll
2G-06
Well Position
+NIS
0.00 usft Northing:
5,944,135.21 usft Latitude:
70° 15' 30.911 N
+E/-W
0.00 usft Easting:
508,929.90 usft Longitude:
149° 55' 40.165 W
Position Uncertainty
- 0.00 usft Wellhead Elevation:-
usft Ground Level:
0.00 usft
FWeb
2G-06L1-01
s
Model Name Sample Date
Declination Dip Angle
Field Strength
(I
(I
(nT)
BGGM2018 12/1/2018
16.75 80.81
57,424
_ _
Design
2G-06L1-01_wp05
Audit Notes:
Version:
Phase:
PLAN
Tie On Depth:
8,400.00
Vertical Section:
Depth From (TVD)
+NIS
+E/-W Direction
(usft)
(usft)
(usft)
(°)
0.00
0.00
0.00
0.00
Plan Sections
i
Measured
TVD Below
Dogleg Build Turn
Depth Inclination
Azimuth System +N/S
+E/-W
Rate Rate Rate
TFO
(usft) (°)
(°) (usft) (usft)
(usft)
(°/100usft) (°/100usft) (°NOOusft)
(°) Target
8,400.00
94.14
29.17 5,912.25 3,496.13
3,857.18
0.00 0.00 0.00
0.00
8,470.00
86.86
24.97 5,911.65 3,558.40
3,889.00
12.00 -10.40 -5.99
210.00
8,600.00
92.24
10.32 5,912.67 3,681.90
3,928.29
12.00 4.14 -11.27
290.00
8,700.00
92.19
358.32 5,908.80 3,781.36
3,935.80
12.00 -0.05 -12.01
270.00 1
8,900.00
98.45
335.03 5,890.01 3,973.73
3,890.45
12.00 3.13 -11.64
286.00
9,075.00
89.28
353.99 5,878.12 4,141.08
3,844.23
12.00 -5.24 10.83
115.00
9,200.00
85.96
339.34 5,883.34 4,262.26
3,815.53
12.00 -2.65 -11.72
257.00
9,425.00
90.91
5.90 5,889.59 4,483.26
3,786.98
12.00 2.20 11.80
80.00
9,750.00
99.47
327.66 5,859.07 4,792.32
3,715.15
12.00 2.63 -11.77
284.00
812112018 1:52:50PM Page 2 COMPASS 5000.14 Build 85
ConocoPhillips BA ER
ConocoPhillips Planning Report I-UGHES
a GE company
Database:
EDT 14 Alaska Production
Local Co-ordinate Reference:
Well 2G-06
Company:
_ConocoPhillips Export Company
TVD Reference:
Mean Sea Level
Project
Kuparuk River Unit
MD Reference:
2G-06 @ 140.00usft (2G-06)
Site:
Kuparuk 2G Pad
North Reference:
True
Well:
2G-06
Survey Calculation Method:
Minimum Curvature
Weilbore:
2G-06L1-01
Design:
2G-06 L 1-01 _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)
, 8,400.00
94.14
29.17
5,912.25
3,496.13
3,857.18
3,496.13
0.00
0.00
5,947,635.56
512,782.54
TIP/KOP
8,470.00
86.86
24.97
5,911.65
3,558.40
3,889,00
3,558.40
12.00
150.00
5,947,697.86
512,814.29
Start 12 dis
8,500.00
88.10
21.59
5,912.97
3,585.93
3,900.85
3,585.93
12.00
-70.00
5,947,725.40
512,826.10
8,600.00
92.24
10.32
5,912.67
3,681.90
3,928.29
3,681.90
12.00
-69.85
5,947,821.39
512,853.43
3
8,700.00
92.19
358.32
5,908.80
3,781.36
3,935.80
3,781.36
12.00
-90.00
5,947,920.85
512,860.82 !
4
8,800.00
95.43
346.73
5,902.13
3,880.11
3,922.87
3,880.11
12.00
-74.00
5,946,019.58
512,847.77
8,900.00
98.45
335.03
5,890.01
3,973.73
3,890.45
3,973.73
12.00
-74.77
5,948,113,15
512,815.25
5
9,000A0
93.26
345.91
5,879.78
4,067.33
3,857.30
4,067.33
12.00
115.00
5,948,206.70
512,781.99I
9,075.00
89.28
353.99
5,878.12
4,141.08
3,844.23
4,141.08
12.00
116.11
5,948,280.43
512,768,84
6
9,100.00
88.60
351.06
5,878.58
4,165.86
3,840.98
4,165.86
12.00
-103.00
5,948,305.21
512,765.56
9,200.00
85.96
339.34
5,883.34
4,262.26
3,815.53
4,262.26
12.00
-102.95
5,948,401.57
512,739.99
7
9,300.00
88.12
351.16
5,888.52
4,358.67
3,790.17
4,358.67
12.00
80.00
5,948,497.93
512,714.52
9,400.00
90.35
2.96
5,889.86
4,458.34
3,785.05
4,458.34
12.00
79.39
5,948,597.59
512,709.29
1 9,425.00
90.91
5.90
5,889.59
4,483.26
3,786.98
4,483.26
12.00
79.23
5,948,622.51
512,711.19
8
9,500.00
93.07
357.16
5,886.98
4,558.12
3,788.99
4,558.12
12.00
-76.00
5,948,697.36
512,713.11
9,600.00
95.83
345.45
5,879.20
4,656.49
3,773.96
4,656.49
12.00
-76.30
5,948,795.70
512,697.96
9,700.00
98.34
333.62
5,866.82
4,749.29
3,739.36
4,749.29
12.00
-77.22
5,948,888.46
512,663.25
9,750.00
99.47
327,66
5,859.07
4,792.32
3,715.15
4,792.32
12.00
-78.68
5,948,931.46
512,639.00
Planned TD at 9760.00
J
rasing Points
Measured Vertical Casing Hole
Depth Depth Diameter Diameter
(usft) (usft) Name (in) (in)
9,750.00 5,859.07 2 3/8" 2.375 3.000
Plan Annotations
Measured
Vertical
Local Coordinates
Depth
Depth
+N/-S
+E/-W
(usft)
(usft)
(usft)
(usft)
Comment
8,400.00
5,912.25
3,496.13
3,857.18
TIP/KOP
8,470.00
5,911.65
3,558.40
3,889.00
Start 12 dis
8,600.00
5,912.67
3,681.90
3,928.29
3
8,700.00
5,908.80
3.781.36
3,935.80
4
8,900.00
5,890.01
3;973.73
3,890.45
5
9,075.00
5,878.12
4,141.08
3,844.23
6
9,200.00
5,883.34
4,262.26
3,815.53
7
9,425.00
5,889.59
4,483.26
3,786.98
8
9,750.00
5.859.07
4,792.32
3,715.15
Planned TD at 9750.00
812112018 1:52:50PM Page 3 COMPASS 5000.14 Build 85
- ConocoPhillips BA�<ER
ConocoPhillips Travelling Cylinder Report UiGHES
a GE company
Company:
ConocoPhillips (Alaska) Inc. -Kup2
Project:
Kuparuk River Unit
Reference Site:
Kuparuk 2G Pad
Site Error.
0.00 usft
Reference Well:
2G-06
Well Error.
0.00 usft
Reference Wellbore
2G-06L1-01
Reference Design:
2G-06L1-01_wp05
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Output errors are at
Database:
Offset TVD Reference:
Well 2G-06
2G-06 @ 140.00usft (2G-06)
2G-06 @ 140.00usft (2G-06)
True
Minimum Curvature
1.00 sigma
EDT 14 Alaska Production
Offset Datum
Reference
2G-06L1-01_wp05
Fitter type:
GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
Interpolation Method:
MD Interval 25.00usft Error Model: ISCWSA
Depth Range:
8,400.00 to 9,750.00usft Scan Method: Tray. Cylinder North
Results Limited by:
Maximum center -center distance of 1,161.00 usft Error Surface: Pedal Curve
Survey Tool Program
Date 8/21/2018
From
To
(usft)
(usft) Survey (Wellbore)
Tool Name
Description
200.00
8,100.00 2G-06 (2G-06)
SEEKER MS
BHI Seeker multishot
8,100.00
8,400.00 2G-061_1_wp03(2G-06L1)
MWD
MWD- Standard
8,400.00
9,750.00 2G-06L1-01_wp05(2G-06L1-01)
MWD
MWD- Standard
Casing Points
Measured
Vertical
Casing Hole
Depth
Depth
Diameter Diameter
(usft)
(usft) Name
(in) (in)
9,750,00
5,999.07 2 3/8"
2.375 3.000
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)
2L Pad
2L-328 - 2L-328 (Sierra) - 2L-328 Planned
Out of range
Kuparuk 2F Pad
2F-20 - 2F-20 - 2F-20
Out of range
Kuparuk 2G Pad
2G-06 - 2G-06L1 - 2G-06L1_wp03
9,293.39
9,275.00
23.87
1.51
23.64
Pass - Minor 1/10
2G-06 - 2G-061_1-02 - 2G-061_1-02_wp03
8,403.80
8:425.00
49.00
0.70
48,51
Pass - Minor 1/50
2G-06 - 2G-061-1-03 - 2G-06L1-03_wp03
8,403.95
8,425.00
48.91
0.68
48.45
Pass - Minor 1/10
Offset Design
Kuparuk 2G Pad - 2G-06 - 2G-061_1 - 2G-06L1_wp03
Offset Site Ertor: 0.00 usft
Survey Program: 200SEEKER MS,
8100-MWD
Rule Assigned: Minor
1/10
Offset Well Error. 0.00 usft
Reference
offset
Semi Major Axis
Measured
Vertical
Measured
Vertical
Reference
Offset
Toofface+
Onset Wellbore Centre
Casing -
Centre to
No Go
Allowable Warning
Depth
Depth
Depth
Depth
Azimuth
+N7S
+E/-W
Hole Size
Centre
Distance
Deviation
(usft)
(usft)
(usft)
(usft)
(usft)
(usft)
M
(usft)
(usft)
(in)
(usft)
(usft)
(usft)
8,424.94
6,051.02
8.425.00
6,050.16
0.04
0.02
-26.01
3.518.56
3.867.98
2.687
1.45
0.46
1.12 Pass - Minor 1/10
8,449.53
6,050.90
8.450.00
6,047.50
0.05
0.04
-27.75
3.542.07
3,876.00
2.687
5,79
0.50
5.43 Pass - Minor 1110
8,473.53
6,051.83
8475.00
6,044.31
0.06
0.06
-29.77
3,566.33
3,881.09
2.687
12.92
0.57
12.52 Pass -Minor l/10
8,498.06
6,052.90
8,500.00
6,040.98
0.07
0.08
.33.40
3,590.88
3,884.34
2.687
20.91
0.66
20.46 Pass- Minor 1/10
8,523.23
6,053.54
8,525.00
6,037.85
0.09
0.11
-37.16
3,615.56
3,886.86
2.687
28.17
0.76
27.68 Pass - Minor 1/10
8,549.02
6,053.73
8,550.00
6,034.92
0.11
0.13
-41.09
3,640.32
3,888.645
2.687
34.67
0A6
34.12 Pass - Minor 1/10
8,575.45
6,053.42
8,575.00
6,032.51
0.14
0.16
-45.42
3,665.17
3,889.96
2.687
40.03
0.96
39.42 Pass - Minor 1/10
8.602.40
6,052.58
8,600.00
6,030.76
0.17
0,18
-50.25
3,690.09
3,890.89
2,687
44.05
1.05
43.39 Pass - Minor 1/10
8,629.47
6,051.52
8,625.00
6,029.67
0.20
0.22
-55.38
3.715.06
3,891.44
2.687
46.84
1.14
46.11 Pass - Minor 1/10
8,656.81
6,050.46
8,650.00
6,029.23
0.24
0.25
-60.49
3,740.05
3,891,60
2.687
48,45
1.21
47.66 Pass - Minor 1/10
CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation
812112018 3.40.47PM Page 2 COMPASS 5000.14 Build 85
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KUP PROD 2G-06
COIIOCOPItiIIII35
Alaska, Inc. -
Well Attributes Max Angle & MD TD
Field Name Welibore APIIUWI WtlI-.
KUPARUK RIVER UNIT 500292112100 PROD
Status ncl (°) MD
4.60 4,000.00
(RKB)) Act
8,48-
Ban (RKB)
Comment
SSSV: NIPPLE
H25 (ppm) Date
110 12l1912017
Annotation
Last WO:
End Date
7/14l2070 36.00
KS-Grd (ft) Rig
6/18/1984
Release Date
2G-05.7n7IN189.03.32AM
Last Tag
Verlical schematk (actual)
Annotation
Last Tag: RKB
End Data
7/15/2018
Depth (RKB) Last
8,168.0 fergusp
Mad ey
HANGER; 30A
CONDUCTOR: 38.0-110.0
NIPPLE: 524.7
GAS LIFT. 2.951.5
SURFACE: 372-3,133.g-
GAS LIFT', 4.945.4
GAS LIFT: 6,250.3
GAS LIFT: 7,246.0
GAS LIFT, 7,898.2
PBR; 7,956.E
PACKER: 7,968,3
NIPPLE, 8,011.2
FISH: 8,158.0
IPERF, 8,188,0-0.198.0-
IPERF; 6,216.M 246.0-
PRODUCTION, 35.M.449.1
Last Rev Reason
Annotation Elul Date Last Mod By
Rev Reason: Set new Rocksaeen. 71162018 fergusp
Casing Strings
Casing Description
CONDUCTOR
OD (in)
16
ID (in) Top(RKB)
15.06 38.0
Set
110.0
Depth(ftKB) Set
110.0
Depth (TVD) WdLen(1...
62.58
Grade
H-40
Tap Thread
Welded
Casing Description
SURFACE
OD (in)
95/8
ID (in) Top
9.21 372
MK8{ Set
3,133.9
Depth (RKB) I Set
2,773.7
Depth (TVD)... WOLen
36.00
(1... Grade
J-55
Top Thread
BTC
Casing Description
PRODUCTION
OD (in)
7
I ID (in) Top
6.28 135.9
(RKB) Set
8,449.1
Depth (ftf(B{ I Set
16,2218
Depth jTVD)... Wt1Len
26.00
(L.. Grade
J-55
Top Thread
BTC
Tubing Strings
TuWnB DescriptionString Ma... ID (in) lop (RKB) Set Depth (h.. Set Depth (TVD) (... Wt (Iblit) Grade Top Connection
TUBING WO 31/2 2.91 30.1 7,969.3 5,841.4 9.30 L-80 EUE8rdABMOD
Completion Details
Top (ftKB)
Top fTVD)
(ftKB)
Top Intl
(°)
Item Des
corn
Nominal
ID (in)
30.1
30.1
0.09
HANGER
Vetco/Gray Gen II TUBING HANGER
2.938
524.7
524.6
1.18
NIPPLE
3.5'Camco 'DS"Nipple w/2.875 profile
2.875
7,956.6
5,831.E
39.63
PER
PER Seal Assembly (sheared) w/ T space out STABBED INTO
PACKER ASSEMBLY
2.980
Tubing Description String Ma...
TUBING Packer Assy 3 t/2
10 (in) Top (RKB) Set Depth (ft.. Set De.P1h W-1(... Wt (I6Mt) Grade Top Connection
2.99 7,968.3 8,043.E 5,899.1 9.30 L-80 aRD EUE
Completion Details
Top (RKBj
Top ITVD) Top
(RKB)
Intl
()
It.. Des
Com
Nominal
ID (in)
7,968.3
5,840.7
39,50
PACKER
FHL Packer
3,030
8,011.2
5,873.8
39.03
NIPPLE
2.813" DS Nipple
2.813
Other In Hole (Wirelioe retrievable plugs,
valves, pumps, fish, etc.)
Top (RKB)
Top(TVD) Topincl
(RKB)
(°)
Des
Co.
Run Date
ID (in)
8,011.0
5,873.7
39.04 CS-LOCK/THEA
ROCKSCREEN
2.81" CS -LOCK W/tapppered Rocksaeen, 2.79 z 2.40"'
THEA Rockscreen (OAL 80')
7/1612018
0.000
8.158.0
5,989.3
37.21 FISH
LOWER PACKER FROM OLD COMPLETION, PXX
PLUG, & REST OF TUBING DOWN TO WIRELINE RE -
ENTRY GUIDE IS IN FILL. TAGGED HARD MUD @o
8158 SLM.
1/6/2008
0.000
Perforations & Slots
Top (ttK8)
Top
Btm (RKB)
(TVD)
(RKB)
Btm ITVDI
(RKB)
Linked Zone
Date
Shot
Dens
(shotsMt
)
Type
Cam
8,188.0
8,198.0
6,013.3
6,021.3 A-5,
2G-06
9/24/1988
4.0
IPERF
90 deg. Phasing; 4"
Schlumberger Casi
8,216.0
8,246.0
6,035.7
6,059.9 A-4,
2G-06
9/24/1988
4.0
IPERF
90 deg. Phasing; 4"
Schlumberger Casi
Mandrel Inserts
St
ati
N Top dtKE1)
Top (TVD)
(RKB)
Make
Model
OD (Inj
Se.
Valve
Type
Latch
Type
Port Size
(in)
TRO Run
(psi)
Run Data
corn
$951.5
2,655.4
Camco
MMG
1 1/2 GAS
LIFT
GLV
RK
0.188
1,240.0
2/8/2018
9:30
2 4,945.5
3,851.9
Camco
MMG
11t2 GAS
LIFT
GLV
RK
0.188
1,220.0
2/8/2018
10:30
3 6,250.3
4,646.2
Camco
MMG
1 112 GAS
LIFT
GLV
RK
0.188
1,217.0
2/8/2018
1:00
4 7,246.0
5,310.6
Carom
MMG
11/2 GAS
LIFT
GLV
RK
0.188
1,232.0
2/8/2018
930
5 7,898.2
5,786.8
Camco
MMG
11/2 GAS
LIFT
OV
RK
0.250
0.0
2/7/2018
10:30
Notes: General & Safety
End Date
Annotation
1/2l2000
NOTE: WORKOVER
12110/2007
NOTE: "MIT TESTING WILL HAVE TO USE IDS NIPPLE @ 8008'***
12/1012007
NOTE: WORKOVER
7/2/2009
NOTE: 5005 = TIGHT SPOT, UNABLE TO WORK 2.6" GAUGE RING PAST 6/27/2009
7/2/2009
NOTE: View Schematic w/ Alaska Schematic9.0
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TRANSMITTAL LETTER CHECKLIST
WELL NAME: KR ct
PTD: -4. ($ 11F,
development Service Exploratory _ Stratigraphic Test _ Non -Conventional
FIELD: K &4 pa lru �,- R1 Ve Ir POOL: Ku pa $-" k R t VEY' 0
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK
OPTIONS
TEXT FOR APPROVAL LETTER
MULTI
The permit is for a new wellbore segment of existing well Permit
/
LATERAL
No. I?, W -pg� API No. 50- OZ - Z1 1 Z 1 -w- o O•
✓
(If last two digits
Production should continue to be reported as a function of the original
in API number are
API number stated above.
between 60-69
In accordance with 20 AAC 25.005(f), all records, data and logs
acquired for the pilot hole must be clearly differentiated in both well
Pilot Hole
name ( PH) and API number (50- -
- -� from records, data and logs acquired for well
name on permit).
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce/inject is contingent upon issuance of a conservation
Spacing Exception
order approving a spacing exception. (Company Name) Operator
assumes the liability of any protest to the spacing exception that may
occur.
All dry ditch sample sets submitted to the AOGCC must be in no greater
Dry Ditch Sample
than 30' sample intervals from below the permafrost or from where
samples are first caught and 10' sample intervals through target zones.
Please note the following special condition of this permit:
production or production testing of coal bed methane is not allowed for
Non -Conventional
(name of well) until after (Company Name) has designed and
Well
implemented a water well testing program to provide baseline data on
water quality and quantity. (Company Name) must contact the AOGCC
to obtain advance approval of such water well testing program.
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of
well logs to be run. In addition to the well logging program proposed by
(Company Name) in the attached application, the following well logs are
also required for this well:
V
Well Logging
Requirements
j
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 2G-0611-01 Program DEV Well bore seg ❑d
PTD#: 2181130 Company CONOCOPHILLIPS ALASKA. INC. Initial Class/Type
DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal ❑
Administration
17
Nonconven. gas conforms to AS31.05.030(1.1_.A),Q.2.A-D) - - - - -
N_A-
- - - - - - - - - - - - - _ _ _ _
1
Permit fee attached----------- ---------------
N_A_
2
Lease number appropriate_ - - - - - - -
Yes -
- - - - - - - - - -
3
Unique well -name and number - - -
Yes _
4
Well located in-a_defined-pool -
Yes -
----------------------------------------
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'
6
Well located proper distance from other wells_ - - - ------ -------------
Yes
- from an external property line_ where_ ownership or landownership_ changes. _A_sproposed,well _w_ill_ - -
7
Sufficient acreage_avail_able in_dril_ling unit_ - - - - - - - - - -
Yes
conform to spacing- requirements. -------------------------------------
8
If -deviated, is_wellbore plat_induded - - - - - - - - - - -
No.
Directional- plan view_is included for 4 laterals. ------------------
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 - - -
es -
DLB 9/24/2018
13
Can permit be approved before 15-daywait--- - - - - - - - - - - - - - - - - - - - -
Yes-
- - - - - - - - - - -
14
Welllocated within area and_strata authorized by Injection Order # (put_ 10# incomments) _(For
-NA - -
.
15
All wells -within _114_ mile -area -of review identified (For service well only)
NA-
16
Pre -produced injector: duration of pre production Less than 3 months_ (Forservice well only)
NA-
18
or
Conductor string_provided
NA_
Conductor set in KRU 2G-06
Engineering
19
Surface protects all -known USDWs
NA_
Surface casing set in- KRU 2G-06 - - - - - - - - - - - - - - - - -
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 coverall known -productive horizons- - - - - - - - - - - - - -
- - - - - - - No_
Pr_oductive-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
lf-a re -drill, has a 1.0-403 for abandonment been approved - --------------
NA_
- - - - - - - - - . - - .. . .
26
Adequate well bore separation -proposed - - - - - - - - - - - - - - - - - - - - - - -
- - - - - - Yes
- - - - Anti -collision analysis complete: no major risk failures
27
if_diverter required, does it meet regulations- - - - - - - - - - - - - - - - - - - - - - - -
- - - - - - N_A_ - - - -
- - - - - - - - - - - - _ - -
-----------------
Appr Date
28
-Drilling fluid_ program schematic & equip list adequate_ - - - - - - ---------
- - - - - Yes
Max formation- pressure is.4908 psig(15.5 ppg_E_MW), will drill_w/ 8.6_ppg EMW and -maintain ov_erbal_w/ MPD
VTL 10/5/2018
29
BOPEs,_dothey meet regulation - - . - - - . _ - . _ . - - -
... . Yes-
- - - - - - - - - - - - - - - - - - - - - - - -
30
BOPE_press rating appropriate; test to -(put psig in comments). -
Yes - - -
- - - - MPSP is 4320 psig, will test BOPs_to 5000_psig - - - - . -
31
Choke_ manifold complies w/API_RP-53(May 54)----- -- -- - - - - -- -
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 verifled (For service well only) - - - - - -
- - - - - - - NA_
- - - - - - - - - - - - - - - - - - - - - - -
35
Permit Gan be issued w/o hydrogen_ sulfide measures
No
Wells on 2G-Pad are 112S-bearing. H2S measures required.
Geology
36
-Data-presented on potential overpressure zones
Yes
Appr Date
37
Seismic_ analysis of shallow gas -zones_
N_A_
- .
DLB 9/24/2018
38
Seabed condition survey -Of off -shore)
NA
39
Contact name/phone for weekly -progress reports [exploratory only] - - - - - - - - -
- - - - - - NA_
Geologic Engineering Public
Commissioner: Date: Commissioner: Date Commissioner Date
