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Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout219-1671
Winston, Hugh E (OGC)
From:Winston, Hugh E (OGC)
Sent:Thursday, January 13, 2022 3:10 PM
To:McLaughlin, Ryan; Germann, Shane
Cc:Loepp, Victoria T (OGC)
Subject:CPAI Expired Permits
Hello,
The following permits have expired under regulation 20 AAC 25.005 (g). The permits has been marked expired in their
well history file and in the AOGCC database. Please let me know if you have any questions or concerns regarding this
expiration.
KRU 1R‐23AL1 expired 12/4/2021
KRU 1R‐23AL3 expired 12/4/2021
KRU 3O‐04L1‐02 expired 12/13/2021
Huey Winston
Statistical Technician
Alaska Oil and Gas Conservation Commission
hugh.winston@alaska.gov
907‐793‐1241
THE STATE
'ALASKA
GOVERNOR MIKE DUNLEAVY
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 1R-23AL1
ConocoPhillips Alaska, Inc.
Permit to Drill Number: 219-167
Surface Location: 4854' FNL, 144' FWL, SEC. 17, T12N, R10E, UM
Bottomhole Location: 2284' FNL, 5011' FWL, SEC. 9, T12N, R10E, UM
Dear Mr. Ohlinger:
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.olaska.gov
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. 219-166, API No. 50-029-22200-
01-00. 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,
J e M Price
Chair
DATED this 4 day of December, 2019.
1171CVGI V L�.1-P
NOV 21 2019
STATE OF ALASKA
AL. . -)IL AND GAS CONSERVATION COMM, (.,.
PERMIT TO DRILL
20 AAC 25.005
1 a. Type of Wo .
'1b. ' I prised Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑
1 c. Specify if well is proposed for:
Drill ❑ Lateral ❑�
Stratigraphic Test ❑ Development - Oil 2 • Service - Winj ❑ Single Zone ❑� .
Coalbed Gas ❑ Gas Hydrates ❑
Redrill ❑ Reentry ❑
Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑
Geothermal ❑ Shale Gas ❑
2. Operator Name:
5. Bond: Blanket ❑� . Single Well ❑
11. Well Name and Number:
ConocoPhillips Alaska, Inc.
Bond No. 5952180
KRU 1R-23AL1
3. Address:
6. Proposed Depth:
12. Field/Pool(s):
P.O. Box 100360 Anchorage, AK 99510-0360
MD: 16,665 TVD: 7024'
Kuparuk River Field /
Kuparuk River Oil Pool '
4a. Location of Well (Governmental Section):
7. Property Designation:, tp c. 2-5'63%
Surface: 4854' FNL, 144' FWL, Sec 17, T12N, R10E, UM A n
, ' - ADL 25627 %+�
Top of Productive Horizon:
8. DNR Approval Number:
13. Approximate Spud Date:
2534' FNL, 3028' FWL, Sec 9, T12N, R10E, UM
LONS 83-134
12/5/2019
9. Acres in Property:
14. Distance to Nearest PropertV:
Total Depth:
2284' FNL, 501 V FWL, Sec 9, T12N, R10E, UM
2560
3041' `
4b. Location of Well (State Base Plane Coordinates - NAD 27):
10. KB Elevation above MSL (ft): 88' •
15. Distance to Nearest Well Open
Surface: x- 539830 y- 5991630 • Zone- 4
GL / BF Elevation above MSL (ft): 45'
to Same Pool: 3002', 1 R-35
16. Deviated wells: Kickoff depth: 14,100 ' feet
17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 103 degrees
Downhole: 3515 • Surface: 2841 -
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"
N/A
Unlined delineation lateral
w/anchored billet at 12,500' MD
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):
12180'
7004'
N/A
12178'
7003'
N/A
Casing
Length
Size
Cement Volume
MD
TVD
Conductor/Structural
79'
16"
331 sx AS 1
123'
123'
Surface
6289'
9-5/8"
1300 sx PF E, 630 sx Class 'G'
6331'
4072'
Production
12149'
7"
380 sx Class 'G'
12178'
7003'
Perforation Depth MD (ft): 11710'-11770'
Perforation Depth TVD (ft): 6774'-6803'
Hydraulic Fracture planned? Yes❑ No E
20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 0 20 AAC 25.050 requirements
21. Verbal Approval: Commission Representative: Date
22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval. Contact Name: Ryan McLaughlin
Authorized Name: James Ohlinger Contact Email: r an.mclaU hlin(oCO .com
Authorized Title: Staff CTD Engineer Contact Phone: 907-265-6218
Sane efm"y) I'
Authorized SignatureJL2:Date: ^
Co mission Use Only
Permit to Drill L/ /ice !
Number: �� �i `
API Number ,� /
50-L%c——Z�c� '�i`Y —L
Permit Approval
Date l?j u
l
See cover letter for other
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:�D� 7GS 7 f0 3Sa o pSSamples req'd: Yes ❑ No� Mud log req'd: Yes ❑ No V
�%�n v �Gl ✓ p iC✓f h fTi' �YS� f 0 Z J UOpSl 2S measures: Yes [ / No El Directional svy req'd: Yes d No ❑
S Za iy exception req'd: Yes El No Inclination -only svy req'd: Yes E]No [�
( Post initial injection MIT req'd: Yes ❑ No
/ 5 � rC4 t r-cl fo a, fl u /c o ff p o i' -/;� a b z
t CE-/0P-)9 _117C P rl t /47-te r---1Z / -
APPROVED BY
q I
Approved by: ~ COMMISSIONER THE COMMISSION Datel�/
% Submit Form and
Form 10-401 ised 5/2017 This permit is valid for, 24 rgo�s r h Aar of approval per 20 AAC 25.005(g) �Attahmentg in Duplicate
ConocoPhillips
Alaska
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
November 20, 2019
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 1 R-23
(PTD# 191-101) using the coiled tubing drilling rig, Nabors CDR3-AC.
CDR3-AC previously attempted to drill the 1 R-231_1 (219-128) lateral in October 2019, but after drilling 3
plugbacks due to hole cleaning and hole stability issues, the decision was made to RDMO. The well is currently
being set-up for a cement pilot hole exit by cement squeezing the original C-sand perforations up to the tubing
tail. CDR3-AC plans to return to the well and CTD operations are scheduled to begin on December 5th, 2019.
The objective will be to drill three laterals — 1 R-23A and 1 R-23AL1 will be unlined delineation laterals to the
north and east, crosscutting through the A3 and C1 sands. 1 R-23AL2 will be drilled to the north targeting the
C1 sands and lined with 2-3/8" solid and slotted liner from TD up into the tubing tail. The fourth lateral, 1 R-
23AL3, will be a contingency lateral that will target the C1 sands in an upthrown fault block. This lateral will be
drilled only if the oil -water -contact comes in higher than anticipated and the project does not get completed to
scope.
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 1 R-23A, 1 R-23AL1, & 1 R-23AL2, & 1 R-23AL3
- Detailed Summary of Operations
- Directional Plans for 1 R-23A, 1 R-23AL1, & 1 R-23AL2, & 1 R-23AL3
- Current wellbore schematic
- Proposed CTD schematic
If you have any questions or require additional information, please contact me at 907-265-6218.
Sincerely,
Ryan McLaughlin
Coiled Tubing Drilling Engineer
ConocoPhillips Alaska
Kuparuk CTD Lateral
1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3
Application for Permit to Drill Document
1.
Well Name and Classification........................................................................................................ 2
(Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b))................................................................................................................... 2
2.
Location Summary.......................................................................................................................... 2
(Requirements of 20 AAC 25.005(c)(2)).................................................................................................................................................. 2
3.
Blowout Prevention Equipment Information................................................................................. 2
(Requirements of 20 AAC 25.005(c)(3))................................................................................................................................................. 2
4.
Drilling Hazards Information and Reservoir Pressure.................................................................. 2
(Requirements of 20 AAC 25.005(c)(4))................................................................................................................................................. 2
5.
Procedure for Conducting Formation Integrity tests................................................................... 2
(Requirements of 20 AAC 25.005(c)(5)).................................................................................................................................................. 2
6.
Casing and Cementing Program.................................................................................................... 3
(Requirements of 20 AAC 25.005(c)(6)).................................................................................................................................................. 3
7.
Diverter System Information.......................................................................................................... 3
(Requirements of 20 AAC 25.005(c)(7)).................................................................................................................................................. 3
8.
Drilling Fluids Program.................................................................................................................. 3
(Requirements of 20 AAC 25.005(c)(8)).................................................................................................................................................. 3
9.
Abnormally Pressured Formation Information............................................................................. 4
(Requirements of 20 AAC 25.005(c)(9)).................................................................................................................................................. 4
10.
Seismic Analysis............................................................................................................................. 4
(Requirements of 20 AAC 25.005(c)(10))................................................................................................................................................ 4
11.
Seabed Condition Analysis............................................................................................................ 4
(Requirements of 20 AAC 25.005(c)(11))................................................................................................................................................ 4
12.
Evidence of Bonding...................................................................................................................... 4
(Requirements of 20 AAC 25.005(c)(12))................................................................................................................................................ 4
13. Proposed Drilling Program............................................................................................................. 4
(Requirements of 20 AAC 25.005(c)(13))................................................................................................................................................ 4
Summaryof Operations...................................................................................................................................................4
LinerRunning...................................................................................................................................................................6
14. Disposal of Drilling Mud and Cuttings.......................................................................................... 6
(Requirements of 20 AAC 25.005(c)(14))................................................................................................................................................ 6
15. Directional Plans for Intentionally Deviated Wells....................................................................... 6
(Requirements of 20 AAC 25.050(b))...................................................................................................................................................... 6
16. Attachments.................................................................................................................................... 7
Attachment 1: Directional Plans for 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3........................................................7
Attachment 2: Current Well Schematic for 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3.............................................7
Attachment 3: Proposed Well Schematic for 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3..........................................7
Page 1 of 7 November 11, 2019
PTD Application: 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3
1. Well Name and Classification
(Requirements of 20 AAC 25.005(o and 20 AAC 25.005(b))
The proposed laterals described in this document are 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3. The
laterals will be classified as "Development - Oil" wells.
2. Location Summary
(Requirements of 20 AAC 25.005(c)(2))
These laterals will target the C1 and A3 sand packages in the Kuparuk reservoir. See attached 10-401 form for
surface and subsurface coordinates of 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3.
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 3,500 psi. Using the
maximum formation pressure in the area of 3517 psi in 1 R-23 (i.e. 10.0 ppg EMW), the maximum
potential surface pressure in 1 R-23, assuming a gas gradient of 0.1 psi/ft, would be 2841 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 1 R-23 was measured to be 3517 psi (10.0 ppg EMW) on 12/20/2010. The
maximum downhole pressure in the 1 R-23 vicinity is the 1 R-23 at 3517 psi or 10.0 ppg EMW on 12/20/2010.
Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b))
No specific gas zones will be drilled; gas injection has been performed in this area, so there is a chance of
encountering gas while drilling the 1 R-23A laterals. If 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 1 R-23A 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 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3 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 16, 2019
PTD Application: 1 R-23A, 1 R-2sAL1, & 1 R-23AL2 & 1 R-23AL3
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
Delineation lateral —will be unlined
1 R-23A
N/A
N/A
N/A
N/A
with an anchored billet set at 14,100'
MD
Delineation lateral — will be unlined
1 R-23ALl
N/A
N/A
N/A
N/A
with an anchored billet set at 12,500'
MD
2-3/8", 4.7#, L-80, ST-L slotted/solid
1R-23AL2
11,605'
17,700'
6636'
6615'
liner, with oil and water tracer pups,
and sealbore deployment sleeve
1R-23AL3
11,605'
14,000'
6636'
6500'
2-3/8", 4.7#, L-80, ST-L slotted liner
Existing Casing/Liner Information
Category
OD
Weight
f
Grade
Connection
Top MD
Btm MD
Top
TVD
Btm
TVD
Burs
t psi
Collapse
psi
Conductor
16"
62.5
H-40
Welded
Surface
123'
Surface
123'
1640
670
Surface
9-5/8"
36.0
J-55
BTC
Surface
6331'
Surface
4072'
3520
2020
Production
7"
26.0
L-80
NSCC
Surface
12,178'
Surface
7003'
4980
4320
Tubing
3-1/2"
9.3
J-55 I
EUEABMOD
I Surface
1 11,610
1 Surface
1 6727'
8430
7500
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
Water based Power-Vis milling fluid (8.6 ppg)
— Window milling operations:
— Drilling operations: Water based PowerVis 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 a weighted completion fluid in order to provide formation over -balance and maintain
wellbore stability while running completions.
Managed Pressure Drilling Practice
Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on
the open hole formation and promote wellbore stability throughout the coiled tubing drilling (CTD) process. Mud
weight is not, in many cases, the primary well control barrier. This is satisfied with the 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".
Page 3 of 7 September 16, 2019
PTD Application: 1 R-23A, 1 R-L3AL1, & 1 R-23AL2 & 1 R-23AL3
In the 1 R-23A laterals we will target a constant BHP of 11.8 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 1R-23A Window (11,650' MD, 6745' TVD) Using MPD
Pumps On 1.8 b m
Pumps Off
Formation Pressure 10.0
3507 psi
3507 psi
Mud Hydrostatic 8.6
3016 psi
3016 psi
Annular friction (i.e. ECD, 0.080 psi/ft)
932 psi
0 psi
Mud + ECD Combined
no chokepressure)
3948 psi
Overbalanced —441psi)
3016 psi
Underbalanced —491 psi
Target BHP at Window 11.8
4139 psi
4139 psi
Choke Pressure Required to Maintain
Target BHP
191 psi
1123 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
In October 2019, CDR3-AC rigged up and attempted to drill 3 laterals out of KRU 1 R-23. After 3 plugbacks while
drilling the 1 R-23L1 lateral, due to poor hole conditions and hole cleaning issues, the decision was made to
RDMO and reattempt at a later date via cement pilot hole exit. This will require E-line to perforate the tubing tail,
and service coil to cement squeeze the C-sand perforations up to the tubing tail. This wellwork is ongoing.
CDR3-AC will return to 1 R-23 in mid -December, mill a pilot hole down to 11,680' MD, set a whipstock and mill a
2.80" window in the production casing at a depth of 11,650' MD. After that, the 1 R-23A delineation lateral will be
drilled to the north and crosscut through the C1 and A3 sands to determine rock quality and oil -water contact in
both sand packages. An anchored billet will be set and the 1 R-23AL1 lateral will be drilled to the east,
crosscutting through the C1 and A3 sands to determine rock quality and OWC in the eastern fault block. Finally,
an anchored billet will be set and the 1 R-23AL2 lateral will be drilled to the north, targeting the C1 sands, and
lined with 2-3/8" slotted liner to the tubing tail. If the C1 sands are found to be wet due to a higher than anticipated
oil -water -contact, the 1 R-23AL2 lateral will not be drilled and instead a contingency lateral, 1 R-23AL3, will be
Page 4 of 7 September 16, 2019
PTD Application: 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3
drilled targeting the C1 sands in an upthrown block This lateral will be lined with 2-3/8" slotted liner from TD to the
tubing tail.
Pre-CTD Work
1. RU E-line: Perforate Tubing Tail
2. RU CTU: Injectivity test, cement 1 R-23 up to the tubing tail, mill XN nipple to 2.80", mill cement to
11,609' MD
Rig Work
1. MIRU Nabors CDR3-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test.
1 R-23A Lateral (Delineation Lateral A/C Sands - North)
a. Mill cement from tubing tail (11,609' MD) to 11,680' MD
b. Set whipstock at 11,650' MD
c. Mill 2.80" window at 11,650' MD
d. Drill 3" bi-center lateral to TD of 15,846' MD
e. Set anchored aluminum billet at 14,100' MD
3. 1 R-23AL1 Lateral (Delineation Lateral A/C Sands - East)
a. Kickoff of the aluminum billet at 14,100' MD
b. Drill 3" bi-center lateral to TD of 16,665' MD
c. Set anchored aluminum billet at 12,500' MD
4. 1 R-23AL2 Lateral (C1 Sand — North)
a. Kick off of the aluminum billet at 12,500' MD
b. Drill 3" bi-center lateral to a TD of 17,700' MD
c. Run 2-3/8" slotted/blank liner with oil/water tracer pups and sealbore deployment sleeve from
TD up to 11,605' MD
1 R-23AL3 Lateral (Cl Sand — North)
a. Kick off of the aluminum billet at 12,400' MD
b. Drill 3" bi-center lateral to a TD of 14,000' MD
c. Run 2-3/8" slotted liner and sealbore deployment sleeve from TD up to 11,605' MD
6. Freeze protect, ND BOPE, and RDMO Nabors CDR3-AC rig.
Post -Rig Work
1. RU E-Line: Set LTP
2. Return well to production.
Pressure Deployment of BHA
The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the swab valve on the
Christmas tree. MPD operations require the BHA to be lubricated under pressure using the swab valve on the
Christmas tree, deployment ram on the BOP, check valve and ball valve in the BHA, and a slick -line lubricator.
This pressure control equipment listed ensures reservoir pressure is contained during the deployment process.
During BHA deployment, the following steps are observed.
— Initially the swab valve on the tree is 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 valve. The swab valve is opened and the
BHA is lowered in place via slick -line.
— When the BHA is spaced out properly, the deployment ram is closed on the BHA to isolate reservoir
pressure via the annulus. A closed ball valve and check valve isolate reservoir pressure internal to the
Page 5 of 7 September 16, 2019
PTD Application: 1 R-23A, 1 R-2,sAL1, & 1 R-23AL2 & 1 R-23AL3
BHA. Slips on the deployment ram prevent the BHA from moving when differential pressure is applied.
The lubricator is removed once pressure is bled off above the deployment ram.
- The coiled tubing is made up to the BHA with the ball valve in the closed position. Pressure is applied to
the coiled tubing to equalize internal pressure and then the ball valve is opened. The injector head is
made up to the riser, annular pressure is equalized, and the deployment ram is opened. The BHA and
coiled tubing are now ready to run in the hole.
During BHA undeployment, the steps listed above are observed, only in reverse.
Liner Running
- The 1 R-23A, 1 R-23AL1, & 1 R-23AL2 & 1 R-23AL3 laterals will be displaced to an overbalancing fluid
prior to running liner. See "Drilling Fluids" section for more details.
- 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 AAC 25.005(c)(14))
• No annular injection on this well.
• All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal.
• Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1 R-18
or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable.
• All wastes and waste fluids hauled from the pad must be properly documented and manifested.
• Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200).
15. Directional Plans for Intentionally Deviated Wells
(Requirements of 20 AAC 25.050(b))
- The Applicant is the only affected owner.
- Please see Attachment 1: Directional Plans
- Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run.
- MWD directional 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
1 R-23A
4790'
1 R-23AL1
3041'
1R-23AL2
2541'
1 R-23AL3
5105'
- Distance to Nearest Well within Pool
Lateral Name
Distance
Well
1 R-23A
2935'
1 R-35
1 R-23AL1
3002' •
1 R-35
1 R-23AL2
2872'
1 R-35
1 R-23AL3
2972'
1 R-35
Page 6 of 7 September 16, 2019
PTD Application: 1 R-23A, 1 R-2sAL1, & 1 R-23AL2 & 1 R-23AL3
16. Attachments
Attachment 1: Directional Plans for the 1 R-23A, 1 R-23AL 1, & 1R-23AL2 & 1 R-23AL3 laterals
Attachment 2: Current Well Schematic for 1R-23
Attachment 3: Proposed CTD Well Schematic for the 1 R-23A, 1 R-23AL 1, & 1R-23AL2 & 1 R-23AL3 laterals
Page 7 of 7 September 16, 2019
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ConocoPhilli s
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ConocoPhillips Alaska Inc—Kuparuk
Kuparuk River Unit
Kuparuk 1 R Pad
1 R-23
1 R-23AL1
Plan: 1 R-23AL1 wp04 (Draft A)
Standard Planning Report
18 November, 2019
Baker • X'M7'
ConocoPhillips
Database:
EDT 14 Alaska Production
Company:
ConocoPhillips Alaska Inc Kuparuk
Project:
Kuparuk River Unit
Site:
Kuparuk I Pad
Well:
1 R-23
Wellbore:
1 R-23AL1
Design:
1R-23AL1_wp04 (Draft A)
ConocoPhillips
Planning Report
Baker Hughes
Local Co-ordinate Reference:
Well 1 R-23
TVD Reference:
Mean Sea Level '
MD Reference:
1 R-23 @ 88.00usft (1 R-23)
North Reference:
True
Survey Calculation Method:
Minimum Curvature
Project Kuparuk River Unit, North Slope Alaska, United States
Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level
Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point
Map Zone: Alaska Zone 04 • Using geodetic scale factor
Site
Kuparuk 1 R Pad
i
Site Position:
Northing:
5,991,050.01 usft Latitude:
70' 23' 11.370 N
From:
Map
Easting:
539,829.93 usft Longitude:
149' 40' 33.803 W
Position Uncertainty:
0.00 usft
Slot Radius:
0.000 in Grid Convergence:
0.31 °
Well
1 R-23
Well Position
+N/-S 0.00 usft
Northing:
5,991,630.19 usft Latitude:
700 23' 17.076 N
+E/-W 0.00 usft
Easting:
539,829.67 usft Longitude:
149° 40' 33.721 W
Position Uncertainty
0.00 usft
Wellhead Elevation:
usft Ground Level:
0.00 usft
Wellbore 1R-23AL1
Magnetics Model Name Sample Date Declination Dip Angle Field Strength
(1(1(nT)
BGGM2018 12/1/2019 16.33 80.88 57,400
Design 1R-23AL1_wp04 (Draft A)
Audit Notes:
Version: Phase:
Vertical Section: Depth From (TVD)
(usft)
0.00
PLAN Tie On Depth: 14,100.00
+N/-S +E/-W Direction
(usft) (usft) (°)
0.00 0.00 90.00
Plan Sections
Measured
TVD Below
Dogleg
Build
Turn
Depth
Inclination
Azimuth
System
+N/-S
+E/-W
Rate
Rate
Rate
TFO
(usft)
(°)
(°)
(usft)
(usft)
(usft)
(°/100usft)
(°/100usft)
(°I100usft)
{°) Target
14,100.00
97.36
18.62
6,686.64
7,603.85
8,137.68
0.00
0.00
0.00
0.00
14,180.00
102.96
18.62
6,672.53
7,678.45
8,162.81
7.00
7.00
0.00
0.00
14,500.00
94.96
39.82
6,622.17
7,952.13
8,316.64
7.00
-2.50
6.63
109.00
14,850.00
83.38
61.45
6,627.30
8,172.48
8,585.09
7.00
-3.31
6.18
118.00
14,930.00
83.38
61.45
6,636.53
8,210.46
8,654.89
0.00
0.00
0.00
0.00
15,050.00
77.49
67.53
6,656.48
8,261.43
8,761.56
7.00
-4.91
5.06
135.00
15,150.00
74.07
73.83
6,681.07
8,293.52
8,852.96
7.00
-3.42
6.30
120.00
15,350.00
88.07
73.83
6,712.06
8,348.41
9,042.24
7.00
7.00
0.00
0.00
16,050.00
88.73
122.84
6,732.91
8,250.01
9,713.61
7.00
0.10
7.00
90.00
16,665.00
52.61
148.28
6,936.09
7,856.77
10,119.62
7.00
-5.87
4.14
150.00
11/1a12019 9:15:42AM Page 2 COMPASS 5000.14 Build 85H
ConocoPhillips
ConocoPhillips Planning Report Baker Hughes
Database:
EDT 14 Alaska Production
Company:
ConocoPhillips Alaska Inc-Kuparuk
Project:
Kuparuk River Unit
Site:
Kuparuk 1 R Pad
Well:
1 R-23
Wellbore:
1 R-23AL1
Design:
1 R-23AL1_wp04 (Draft A)
Planned Survey
Measured
Depth Inclination
Azimuth
(usft)
(I
(°)
14,100.00
97.36
18.62
TIP/KOP
14,180.00
102.96
18.62
Start DLS 7.00 TFO
109.00
14, 200.00
102.50
19.97
14, 300.00
100.11
26.68
14,400.00
97.58
33.29
14,500.00
94.96
39.82
Start DLS 7.00 TFO
118.00
14,600.00
91.65
46.00
14,700.00
88.32
52.16
14,800.00
85.01
58.34
14,850.00
83.38
61.45
Start 80.00
hold at 14850.00
MD
14,900.00
83.38
61.45
14,930.00
83.38
61.45
Start DLS 7.00 TFO
136.00
15,000.00
79.93
64.97
15,050.00
77.49
67.53
Start DLS
7.00 TFO
120.00
15,100.00
75.76
70.65
15,150.00
74.07
73.83
Start Build 7.00
15,200.00
77.57
73.83
15,300.00
84.57
73.83
15,350.00
88.07
73.83
Start DLS
7.00 TFO 90.00
15,400.00
88.07
77.33
15,500.00
88.10
84.33
15,600.00
88.15
91.34
15,700.00
88.24
98.34
15,800.00
88.35
105.34
15,900.00
88.49
112.34
16,000.00
88.64
119.34
16,050.00
88.73
122.84
Start DLS
7.00 TFO 160.00
16,100.00
85.70
124.60
16,200.00
79.66
128.16
16,300.00
73.65
131.86
16,400.00
67.72
135.79
16,500.00
61.88
140.07
16,600.00
56.20
144.84
16, 665.00
52.61
148.28
Planned TD at 16665.00
Casing Points
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Well 1 R-23
Mean Sea Level
1 R-23 @ 88.00usft (1 R-23)
True
Minimum Curvature
TVD Below
Vertical
Dogleg
Toolface
Map
Map
System
+N/S
+E/-W
Section
Rate
Azimuth
Northing
Easting
(usft)
(usft)
(usft)
(usft)
(°/100usft)
(°)
(usft)
(usft)
6,686.64
7,603.85
8,137.68
8,137.68
0.00
0.00
5,999,276.53
547,925.94
6,672.53
7,678.45
8,162.81
8,162.81
7.00
0.00
5,999,351.25
547,950.67
6,668.12
7,696.86
8,169.26
8,169.26
7.00
109.00
5,999,369.69
547,957.02
6,648.50
7,786.83
8,208.09
8,208.09
7.00
109.30
5,999,459.86
547,995.36
6,633.11
7,872.35
8,257.46
8,257.46
7.00
110.62
5,999,545.63
548,044.27
6,622.17
7,952.13
8,316.64
8,316.64
7.00
111.63
5,999,625.72
548,103.02
6,616.40
8,025.20
8,384.57
8,384.57
7.00
118.00
5,999,699.14
548,170.56
6,616.43
8,090.66
8,460.09
8,460.09
7.00
118.36
5,999,765.00
548,245.72
6,622.25
8,147.53
8,542.06
8,542.06
7.00
118.36
5,999,822.30
548,327.38
6,627.30
8,172.48
8,585.09
8,585,09
7.00
118.00
5,999,847.48
548,370.27
6,633.07
8,196.22
8,628.71
8,628.71
0.00
0.00
5,999,871.44
548,413.76
6,636.53
8,210.46
8,654.89
8,654.89
0.00
0.00
5,999,885.82
548,439.86
6,646.69
8,241.67
8,716.69
8,716.69
7.00
135.00
5,999,917.36
548,501.49 i
6,656.48
8,261.43
8,761.56
8,761.56
7.00
134.49
5,999,937.35
548,546.25
6,668.05
8,278.79
8,806.99
8.806.99
7.00
120.00
5,999,954.95
548,591.581
6,681.07
8,293.52
8,852.96
8,852.96
7.00
119.28
5,999,969.93
548,637.46
6,693.32
8,307.02
8,899.50
8,899.50
7.00
0.00
5,999,983.67
548,683.93
6,708.84
8,334.52
8,994.32
8,994.32
7.00
0.00
6,000,011.67
548,778.59
6,712.06
8,348.41
9,042.24
9,042.24
7.00
0.00
6,000,025.82
548,826.43
6,713.74
8,360.86
9,090.63
9,090.63
7.00
90.00
6,000,038.52
548,874.75
6,717.09
8,376.78
9,189.23
9,189.23
7.00
89.88
6,000,054.97
548,973.26
6,720.36
8,380.55
9,289.04
9,289.04
7.00
89.65
6,000,059.27
549,073.04
6,723.51
8,372.13
9,388.58
9,388.58
7.00
89.42
6,000,051.38
549,172.60
6,726.49
8,351.63
9,486.34
9,486.34
7.00
89.20
6,000,031.41
549,270.47
6,729.26
8,319.37
9,580.89
9,580.89
7.00
88.99
5,999,999.65
549,365.18
6,731.76
8,275.82
9,670.81
9,670.81
7.00
88.80
5,999,956.58
549,455.31 i
6,732.91
8,250.01
9,713.61
9,713.61
7.00
88.62
5,999,931.00
549,498.25
6,735.34
8,222.29
9,755.14
9,755.14
7.00
150.00
5,999,903.51
549,539.92
6,748.08
8,163.52
9,834.96
9,834.96
7.00
149.91
5,999,845.17
549,620.04
6,771.16
8,101.04
9,909.46
9,909.46
7.00
149.46
5,999,783.09
549,694.87
6,804.24
8,035.78
9,977.54
9,977.54
7.00
148.60
5,999,718.20
549,763.29
6,846.81
7,968.71
10,038.18
10,038.18
7.00
147.30
5,999,651.47
549,824.28
6,898.26
7,900.84
10,090.47
10,090.47
7.00
145.48
5,999,583.88
549,876.93
6,936.09
7,856.77
10,119.62
10,119.62
7.00
143.02
5,999,539.97
549,906.31
Measured Vertical Casing Hole
Depth Depth Diameter Diameter
(usft) (usft) Name (in) (in)
16,665.00 6,936.09 2-3/8" 2.375 3.000
1111812019 9:15:42AM Page 3 COMPASS 5000.14 Build 85H
ConocoPhillips
ConocoPhillips Planning Report Baker Hughes
Database:
EDT 14 Alaska Production
Company:
ConocoPhillips Alaska Inc—Kuparuk
Project:
Kuparuk River Unit
Site:
Kuparuk 1 R Pad
Well:
1 R-23
Wellbore:
1 R-23AL1
Design:
1 R-23AL1_wp04 (Draft A)
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Well 1 R-23
Mean Sea Level
1 R-23 @ 88.00usft (1 R-23)
True
Minimum Curvature
Plan Annotations
Measured
Vertical
Local Coordinates
Depth
Depth
+Nl-S
+E/-W
(usft)
(usft)
(usft)
(usft)
Comment
14,100.00
6,686.64
7,603.85
8,137.68
TIP/KOP
14,180.00
6,672.53
7,678.45
8,162.81
Start DLS 7.00 TFO 109.00
14,500.00
6,622.17
7,952.13
8,316.64
Start DLS 7.00 TFO 118.00
14,850.00
6,627.30
8,172.48
8,585.09
Start 80.00 hold at 14850.00 MD
14,930.00
6,636.53
8,210.46
8,654.89
Start DLS 7.00 TFO 135.00
15,050.00
6,656.48
8,261.43
8,761.56
Start DLS 7.00 TFO 120.00
15,150.00
6,681.07
8,293.52
8,852.96
Start Build 7.00
15,350.00
6,712.06
8,348.41
9,042.24
Start DLS 7.00 TFO 90.00
16,050.00
6,732.91
8,250.01
9,713.61
Start DLS 7.00 TFO 150.00
16,665.00
6,936.09
7,856.77
10,119.62
Planned TD at 16665.00
11/18/2019 9:15.42AM Page 4 COMPASS 5000.14 Build 85H
ConocoPhillips
ConocoPhillips Anticollision Report Baker Hughes
Company:
ConocoPhillips Alaska Inc-Kuparuk
Project:
Kuparuk River Unit-2
Reference Site:
Kuparuk 1 R Pad
Site Error:
0.00 usft
Reference Well:
1 R-23
Well Error:
0.00 usft
Reference Wellbore
1 R-23ALl
Reference Design:
1 R-23AL1_wpO4 (Draft A)
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Output errors are at
Database:
Offset TVD Reference:
Well 1 R-23
1 R-23 @ 88.00usft (1 R-23)
1 R-23 @ 88.00usft (1 R-23)
True
Minimum Curvature
2.00 sigma
EDT 14 Alaska Production
Offset Datum
Reference
1R-23AL1_wp04 (Draft A)
Filter type:
GLOBAL FILTER APPLIED: All wellpaths within 200'+
100/1000 of reference
Interpolation Method:
MD Interval 25.00usft
Error Model:
ISCWSA
Depth Range:
14,100.00 to 16,665.00usft
Scan Method:
Tray. Cylinder North
Results Limited by:
Maximum ellipse separation of 3,000.00 usft
Error Surface:
Combined Pedal Curve
Warning Levels Evaluated at: 2.79 Sigma
Casing Method:
Added to Error Values
Survey Toot Program
Date 11/15/2019
From
To
(usft)
(usft) Survey (Wellbore)
Tool Name
Description
100.00
11,600.00 1 R-23 (1 R-23)
GCT-MS
Schlumberger GCT multishot
11,600.00
14,100.00 1R-23A_wp06 (Draft A) (1R-23A)
MWD OWSG
OWSG MWD- Standard
14,100.00
16,665.00 1R-23AL1_wpO4(Draft A)(1R-23AL1)
MWD OWSG
OWSGMWD- Standard
Summary
Reference
Offset
Distance
Measured
Measured
Between
Between
Separation Warning
Site Name
Depth
Depth
Centres
Ellipses
Factor
Offset Well - Wellbore - Design
(usft)
(usft)
(usft)
(usft)
Kuparuk 1 R Pad
1 R-23 - 1 R-23A - 1 R-23A_wp06 (Draft A)
14,415.46
14,425.00
45.91
38.52
6.215 CC, ES, SF
1R-23-1R-23AL2-1R-23AL2_wp03(Draft A)
14,102.01
14,100.00
82.49
53.44
2.839 Normal Operations, CC, ES,
Offset Design
Kuparuk 1 R Pad -
1 R-23 - 1
R-23A - 1
R-23A_wp06
(Draft A)
Offset Site Error: 0.00 usft
Survey Program: 100-GCT-MS, 11600-MWD OWSG
Offset Well Error: 0.00 usft
Reference
offset
Semi Major
Axis
Distance
Measured
Vertical
Measured
Vertical
Reference
Offset
Azimuth
Offset Wellbore
Centre,
Between
Between
Minimum
Separation
Warning
Depth
Depth
Depth
Depth
from North
+N/S
+E/-w
Centres
Ellipses
Separation
Factor
(usft)
(usft)
(usft)
(usft)
(usft)
(usft)
(°)
(usft)
(usft)
(usft)
(usft)
(usft)
14,125.00
6,771.06
14,125.00
6.771.22
0.21
0.36
-161.38
7,627.32
8,145.59
0.16
-0.11
0.27
0.604
STOP Drilling
14,150.00
6,766.72
14,150.00
6,767.37
0.42
0.72
-161.38
7,650.73
8,153.47
0.65
0.34
0.32
2.062
Caution Monitor Closely
14,174.94
6,761.65
14,175.00
6,763.09
0.63
1.07
-161.38
7674.07
8,161.34
1.47
1.12
0.35
4,157
14,199.92
6,756.14
14,200.00
6,758.38
0.84
1.43
-154.02
7,697.34
8,169.18
2.30
1.82
0.49
4.716
14,224.91
6,750.86
14,225.00
6,753.38
1.06
1.79
-132.34
7,720.57
8,176.94
2.87
1.42
1.45
1.982
Caution Monitor Closely
14,249.79
6,745.84
14,250.00
6,748.62
1.28
2.16
-107.34
7,743,94
8,184.42
4.35
1.55
2.80
1,556
Caution Monitor Closely
14,274.49
6,741.11
14,275.00
6,744.15
1.50
2.52
-90.87
7,767.47
8,191.62
7.08
3.28
3.80
1.863
Caution Monitor Closely
14,298.95
6,736.68
14,300.00
6,739.97
1.72
2.89
-81 05
7,791.13
8,198.52
11.00
6.44
4.55
2.414
Caution Monitor Closely
14,323.10
6,732.56
14,325.00
6,736.08
1.94
3.25
-74.68
7,614.92
8,205.13
15.99
10.79
5.20
3.076
14,346.88
6,728.74
14,350.00
6,732.48
2.16
3.62
-70.11
7,838.84
8,211.43
22.02
16.23
5.79
3.805
14,370.24
6,725.23
14,375.00
6,729.18
2.37
3.99
-66.56
7,B62.89
8,217.44
29.03
22.69
6.34
4.577
14.393.11
6,722.03
14,400.00
6,726.17
2.59
4.36
-63.64
7,887.04
8,223.14
37.01
30.13
6.88
5.383
14,415.46
6719.12
14,425.00
6,723.46
2.80
4.73
-61.16
7,911.30
8,228.55
45.91
38.52
7.39
6.215
CC, ES, SF
14,437.27
6,716.50
14,450.00
6,721.07
3.00
5.10
-59.01
7,935.65
8,233.68
55.67
47.80
7.88
7.068
14,458.49
6,714.16
14,475.00
6,719.02
3.21
5.47
-57.11
7,960.08
8,238.54
66.28
57.93
8.35
7.940
14,479.10
6,712.08
14,500.00
6,717.29
3.40
5.84
-55.40
7,984.60
8,243.12
77.69
68.88
8.80
8.826
14,500.00
6,710.17
14,525.00
6.715.84
3.61
6.22
-53.75
8,009.19
8,247.38
89.91
80.63
9.28
9.686
14.518.46
6,708.68
14,550.00
6,714.60
3.79
6.59
-52.34
8,033.86
8,251.27
102.93
93.27
9.65
10.662
14,537.18
6,707.36
14,575.00
6,713.58
3.97
6.96
-50.94
8,05B.59
8,254.78
116.70
106.64
10.06
11.601
14,555.21
6,706.28
14,600.00
6.712.78
4.15
7.33
-49.61
8,083.37
8,257.92
131.20
120.75
10.45
12.554
14,572.54
6,705.41
14,625.00
6,712.20
4.32
7.71
-48.35
8,108.21
8,260.69
146.39
135.57
10.82
13.527
14,589.25
6,704.75
14,650.00
6,711.91
4.49
8.08
-47.20
8,133.08
8,263.21
162.14
150.96
11.18
14.505
14,605.48
6,704.26
14,675.00
6,712.06
4.65
8.46
-46.17
8,157.96
8,265.73
178.25
166.72
11.52
15.471
CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation
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Loepp, Victoria T (CED)
From: Loepp, Victoria T (CED)
Sent: Friday, November 1, 2019 10:51 AM
To: McLaughlin, Ryan; Boyer, David L (CED)
Cc: Ohlinger, James J
Subject: KRU 1 R-23(PTD 191-101, Sundry 319-493) Set 261 B Whipstock
Follow Up Flag: Follow up
Flag Status: Completed
Ryan,
This sundry work for setting a whipstock in motherbore KRU 1R-23 has changed from setting a 261B whipstock(originally
the C Sand was left open) to a plug for redrill since now all the perforations will be cemented. The paperwork has just
increased. This is what is needed:
1. A plug for redrill sundry for KRU 1R-23(PTD 191-101); we can change this existing sundry(319-492) to plug for
redrill by hand. No need to resubmit the whipstock sundry.
2. However, the naming convention of the sidetrack and laterals must change as follows and new PTDs must be
submitted:
a. Well KRU 1R-23L1 will need to be resubmitted as KRU 111-23A
b. Well KRU 1R-23L1-01 will need to be resubmitted as KRU 1R-23A-4111
c. Well KRU 1R-231-1-02 will need to be resubmitted as KRU 1R-23A-P2
d. These will all be assigned new PTD and API numbers. The motherbore will be abandoned and the KRU
1R-23L1 closed out.
I will route the plug for redrill whipstock for KRU 1R-23 for approval today or Monday.
However, please submit the required new PTDs.
So sorry for the additional paperwork. Let me know if any clarification is needed.
Thanx,
Victoria
Victoria Loepp
Senior Petroleum Engineer
State of Alaska
Oil & Gas Conservation Commission
333 W. 7th Ave
Anchorage, AK 99501
Work: (907)793-1247
Victoria. Loepp(a1alaska.aov
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 Victoria Loepp at (907)793-1247 or Victoria. Loepp alaska.gov
Loepp, Victoria T (CED)
From: Loepp, Victoria T (CED)
Sent: Tuesday, October 29, 2019 10:18 AM
To: McLaughlin, Ryan
Cc: Ohlinger, James J
Subject: KRU 1 R-23L1(PTD 219-128) Operations Shutdown Request
Follow Up Flag: Follow up
Flag Status: Completed
Ryan,
Verbal approval is granted for the Operations Shutdown for CRD3-AC for KRU 1R-23L1(PTD 219-128).
Thanx,
Victoria
Victoria Loepp
Senior Petroleum Engineer
State of Alaska
Oil & Gas Conservation Commission
333 W. 7th Ave
Anchorage, AK 99501
Work: (907)793-1247
Victoria. LoePP(a).alaska.gov
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 Victoria Loepp at (907)793-1247 or Victoria. Loepp@alaska.aov
From: McLaughlin, Ryan <Ryan.McLaughlin@conocophillips.com>
Sent: Tuesday, October 29, 2019 10:13 AM
To: Loepp, Victoria T (CED) <victoria.loepp@alaska.gov>
Cc: Ohlinger, James J <James.J.Ohlinger@conocophillips.com>
Subject: 1R-23 (PTD 191-101) Operations Shutdown Request
Hello Victoria
On October 16th CDR3-AC rigged up to drill a tri-lateral project on 111-23. After 3 unsuccessful attempts at drilling the
1R-23L1 lateral, primarily due to hole cleaning issues in the 7" production casing, the decision was made to rig down
CDR3-AC from 1R-23 and set the well up for a cement pilot hole exit for the rig to come back at a later date and
complete the scope of the project under the approved PTD.
In preparation for resuming CTD operations on this well, perforations will be shot in the tubing tail, cement will be
pumped to occupy the 7" casing and plug off C-sand perforations, and the XN nipple in the tubing tail will be milled out.
CDR3-AC will mill a cement pilot hole, set a 3-1/2" whipstock, and mill a 2.80" window in the production casing at a
depth of 11,662' MD and complete the original scope of the project under the existing permits .
We are requesting verbal approval for an Operations Shutdown with the Sundry to be submitted today. We will also
submit a subsequent sundry request for cement -squeezing the C-sand perforations and setting a new whipstock prior to
beginning the service coil work.
Regards,
Ryan McLaughlin
Coiled Tubing Drilling Engineer
ConocoPhillips Alaska
Office:907-265-6218 Cell:907-444-7886
700 G St, ATO 670, Anchorage, AK 99501
Loepp, Victoria T (CED)
From:
Sent:
To:
Cc:
Subject:
Attachments:
Mel, Guy, Sam,
FYI
Loepp, Victoria T (CED)
Thursday, November 7, 2019 9:18 AM
Melvin Rixse; Schwartz, Guy L (CED)
Chmielowski, Jessie L C (CED); Carlisle, Samantha J (CED); Boyer, David L (CED)
FYI: KRU/CRU PTD(10-401s) while Victoria on A/L
Sonic Conditions of Approval.docx; Perm it_219-140_101619.pdf, 8.13.19 Conditions of
Approval NFT.SSSV.ESP 311-111.docx; Perm it_219-134_102219.pdf
Rotary PTDs that will be submitted for AOGCC approval include KRU 3R-107(producer) and CRU CD5-96: Guy will handle
these. Guy attached are conditions of approval that I'm attaching to DS-3R producers relating to the no flow test
required for elimination of the SSSV requirement. I worked on these conditions with Jim and would like to be consistent
with the DS-3R producers.
CTD PTDs that will be submitted include KRU 1R-23 sidetrack and laterals and 3H-01 sidetrack and laterals: Mel will
handle these; Mel, I attached 10-401 "condition" for kickoff point variance so you can see what we have been granting
on these CTD laterals. Note, originally the 111-23 PTDs were approved as laterals because C sand was left open in the
motherbore. This has changed. They are now plugging the motherbore and drilling a sidetrack (111-23A) plus
laterals. The plug for redrill sundry for the motherbore has been approved however they will be submitting new
PTDs(10-401s) for the 1R-23 sidetrack and laterals.
Also attached is 10-401 Conditions of Approval for running the sonic for cement evaluation for wells to be fracked or
injectors which I have been including as a part of the 10-401 approval.
Thank you!
Victoria Loepp
Senior Petroleum Engineer
State of Alaska
Oil & Gas Conservation Commission
333 W. 7th Ave
Anchorage, AK 99501
Work: (907)793-1247
Victoria. LoeppOa laska.gov
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 Victoria Loepp at (907)793-1247 or V;ofo_ria.Loep nn a ska:aov
TRANSMITTAL LETTER CHECKLIST
WELL NAME: o'e— Z3 �
PTD: _%
Development — Service Exploratory S — p ry — tratigraphic Test _Non -Conventional
FIELD: /� '
POOL: �` ,-
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI The permit is for a new wellbore segment of existing well Permit
No. �
LATERAL �� API No. 50-C�2 �-
'- 2 /-G
(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 ( PI) and API number (50- -
`) from records, data and logs acquired for well
name on permit).
The Permit's 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. (Comvan N
of an Y---fie) Operator
assumes the liability y 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 throu tar et 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 (Comnanv Name) has designed and
Well implemented a water well testing program to provide baseline data on
water quality and quantity. (Company Nam) must contact the AOGCC
to obtain advance approval of such water well testin ro
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
f Requirements
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
V composite curves for well logs run must be submitted to the AOGCC
within 90 da s after com letion, 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 1R-23AL1 Program DEV _ Well bore seg ❑d
PTD#: 2191670 Company ConocoPhillips Alaska, Inc. Initial Class/Type
DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal ❑
Administration
1
Permit fee attached_ - _ - - - - -- - _ _ _ _
NA_ _
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _
2
Lease number appropriate_ - - -
Yes -
- - - - -
- - - - - - Surface Location Iies_with in ADL0025635, Portion_of Well Passes Thru -------------
3
3
Unique well name and number - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ _
Yes -
.. _ - _ _ Top_Prod_ Int_& TD of -this lateral lie with in_ADL0025627. - - - - _ - _ - -
4
Well located in a_definedpool - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
Yes _
_ - - - _ _ Kuparuk River Oil_ Pool, governed by Conservation Order No. 432D _ _ . - - _ - _ - _ _ - - - - - - - - - - -
5
Well located proper distance from_ drilling unit_boundary_ _ _ - - - _ - - - - - - - - - - - - -
Yes -
- - - - - - CO 432D Rule 3: There shall be no restrictions as to well spacing except that no pay shall be opened in-
6
Well located proper distance from other wells- - - - - - - - - - - - - - - - - - - - - - - - - - - - -
Yes -
- - - - - - a well closer_than_500 feet to an external property -line where ownership or landownership changes._
7
Sufficient acreage available in -drilling unit - - - - - - - - - - - - - - - - - - - - - - - - - - - -
Yes -
- - - - - - As planned, this lateral well branch conforms with spacing_ requirements. - - - - - - - _ _ _ . - _ .
8
-if-deviated, is_wellbore plat -included _ - _ _ - - - - - - - - - - - - - - - - -
Yes
9
Operator only affected party - - - - - - - - - - - - - - - - - - - - - - - - -
Yes -
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
10
Operator has -appropriate bond in force ------- ------
Yes--------------------------------------------------
-- ------------
11
Permit_ can be issued without conservation order- - - - -- - - -- - - - - - - - - - - _ _ _ _ _ _
Yes-
- - - - -- - - - - - - - - - - - --- - -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - -- - - -
Appr Date
12
Permit can be issued without administrative -approval _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Yes -
- - - - - - - - - - - - - - - - - - - - - - - - - . - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
13
Can permit be approved before 15-day wait_ - - - - - -
Yes
SFD 11/22/2019
_ - _ _ _
_
_ _ _ _ _ _ _ _
14
Well located within area and -strata authorized by Injection Order # (put_10# in_comments)_(For_
NA_ _
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
15
All wells_within 1/4_mile area of review identified (For service Well only)- - - - - - -
NA_
16
Pre -produced injector: duration of pre -production less than_ 3 months -(For -service well only)
NA- -
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
17
Nonconven. gas conforms to AS31.05 030(j.1.A),Q,2.A-D) - - - - - - - - - - - - - - - - - - - - -
NA_ -
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
18
Conductor string -provided - - - - - - - - - _ - - _ _ _ - - - -
NA_ -
- - - - - - Conductor set_for_KRU_ 1_R-23 - - - - -
Engineering
19
Surface casing_ protects all -known- USDWs - - - - - - - - - _
NA_ -
- Surface casing set for KRU_1R-23- - - - - - - - - - - - - - - - - - -
20
CMT_vol_adequate _to circulate_on conductor& surf_csg - - _ _
NA_ _
_ _ _ _ _ _ Surface casing set and fully cemented - - - - - - - - - - - - -- - - - -
21
CMT_vol_adequate _to tie-in long string to surf csg- - - - - - - - - - - - - - - - - - - - - - - - - - -
NA_ _
_ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ - _ - _ - _ _ _ _ _ _ _ _ - _ _ - _ _ _ - _ _ _ _ - _ - - - - - - -
22
CMT_will cover all known productive horizons- - - - - - - - - - - - - - - - - - - - - - - - - - - -
No_ -
_ - _ _ _ _ Prod uctiv_e_interval will not be -completed; -unlined delineation lateral
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
-ifa_re-drill, has_a_ 10-403 for abandonment been approved - - -
NA_
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
26
Adequate wellbore separation proposed ....... - - - - -
Yes -
- - - - . _ Anti -collision analysis complete; no major risk failures - _ _ _ - - - . .
27
If_diverter required, does it meet regulations_ - - - - - - - _
Yes _
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Appr Date
28
Drilling fluid program schematic & equip list adequate_ - - - - - -
Yes -
- _ - - - _ Max formation_ pressure is_3515 psig(10 ppg EMW); will drill w/ 8 6_ppg EMW_ and maintain overbal_w/ MPD_ -
VTL 12/4/2019
29
BOPEs, do they meet regulation - - - - - - - - - - - - - - - - - - - - - - - - - - -
Yes
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
30
BOPE_press rating appropriate; test to _(put psig in comments)- - - - - - - - - - - - - - - - - - - -
Yes -
- - - - - - MPSP is 2841_ psig: will test BOPs_to 3500_psig - . - -
31
Choke_ manifold complies w/API_ RP-53 (May 84) - - - - - - - -- - - - - - - - - - - - - - - - - -
Yes -
- - - - - - - - - - . - - - - - - - - - - - .. - -- - . - - -
32
Work will occur without operation shutdown- - - - - - - - - - - - - - - - - - - - - - - - - - _ _
Yes .
- - -
33
Is presence_of H2S gas probable - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
Yes
- H2S measures required- - - - _ - .
34
Mechanical condition of wells within AOR verified (For service well only) - - _ - - - _ _ - _ _ _
NA- -
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ - _ _ _ _ - - _ - - - - - - - - - - - -
35
Permit_can be issued w/o hydrogen sulfide measures - - - - - - - - _
---------------
No.
Wells_on_1R-Pad amH2S-bearing. H2S measures required, - - - - - - - - - - _ -----------------
Geology
36
Data_presented on potential overpressure zones
Yes -
- Expected reservoir pressure is 10.0 ppg, with some_potential of -higher pressure due togas _
Appr Date
37
Seismic analysis_of shallow gas_zones------------------- - - - - - - - - - - - - -
NA_ _
_ - _ _ - - injection within this area. Well will be drilled using 8,6 ppg mud,_a coiled -tubing rig, and_ - _ _ _ _ - _ _
SFD 11/22/2019
38
Seabed condition survey -(if off -shore) - - - - - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
NA_ -
- - - - - - managed pressure drilling_ technique to control formation_ pressures and stabilize shale sections_ by_ - -
39
Contact name/phone for weekly -progress reports_ [exploratory only] - - - - - - _ _ _ _ _ _ _ _
NA_ -
- - - - - - maintaining a constant pressure gradient of about 11.8_ ppg EMW- - - - - - - - - - - - - - - - - - - - - - - -
Geologic Engineering Public
Commissioner: Date: Commissioner: Date C miss' ne Date
