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HomeMy WebLinkAbout215-065Guhl, Meredith D (DOA)
From: Guhl, Meredith D (DOA)
Sent: Tuesday, April 25, 2017 1:11 PM
To: Larry Vendl
Cc: Bettis, Patricia K (DOA); Schwartz, Guy L (DOA)
Subject: SMU M-04, PTD 215-065, Permit Expired
Hello Mr. Vendl,
Permit to Drill 215-065, for Southern Miluveach Field M-04, issued 17 April 2015, has expired under Regulation 20 AAC
25.005 W. The PTD will be marked expired in the AOGCC database.
If you have any questions, please contact me.
Thank you,
Meredith
Meredith Guhl
Petroleum Geology Assistant
Alaska Oil and Gas Conservation Commission
333 W. 7th Ave, Anchorage, AK 99501
meredith.guhl@alaska.gov
Direct: (907) 793-1235
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation
Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.
The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail,
please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at
907-793-1235 or meredith.guhl@alaska.gov.
r-
THE STATE
°fALASKA
GOVERNOR BILL WALKER
Dan Shearer
Drilling Manager
Brooks Range Petroleum
510 L Street, Suite 601
Anchorage, AK 99501
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.olaska.gov
Re: Southern Miluveach Field, S. Miluveach and Kuparuk River Oil Pools, SMU M-04
Brooks Range Petroleum Corporation
Permit No: 215-065
Surface Location: 2408' FSL, 1723' FEL, SEC. 2, T14N, R7E, UM
Bottomhole Location: 3369' FSL, 3192' FEL, SEC. 35, T11N, R7E, UM
Dear Mr. Shearer:
Enclosed is the approved application for permit to drill the above referenced development well.
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,
Cathy . Foerster
Chair
DATED this I � d of April, 2015.
RECEIVED
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
APR 10 2015
AOGCC
1 a. Type of Work:
1 b. Proposed Well Class: Development - Oil ❑✓ • Service - Winj ❑ Single Zone 0 •
1 c. Specify if well is proposed for:
Drill I] - Lateral ❑
Stratigraphic Test ❑ Development - Gas ❑
Service - Supply ❑ Multiple Zone ❑
Coalbed Gas ❑ Gas Hydrates ❑
Redrill ❑ Reentry ❑
Exploratory ❑ Service - WAG ❑
Service - Disp ❑
Geothermal ❑ Shale Gas ❑
2. Operator Name:
5. Bond: Blanket - Single Well ❑
11. Well Name and Number:
Brooks Range Petroleum Corporation
Bond No, LPM 8842179 •
SMU M-04
3, Address:
6. Proposed Depth:
12. Field/Pool(s):
510 L St. Suite 601, Anchorage Alaska 99501
MD: 12,082' ' TVD: 6.208'
Southern Miluveach Unit
S Miluveach,
4a. Location of Well (Governmental Section):
7, Property Designation (Lease Number):
Surface: 2408 FSL 1723 FEL S2 T10N R7E UM
AOL 390680, 390691
Kuparuk River Oil - 764150
Top of Productive Horizon:
8. Land Use Permit:
13. Approximate Spud Date:
4334 FSL 3868 FEL S2 T10N R7E UM
LAS 27505
4/27/2015
Total Depth:
9. Acres in Property:
14. Distance to Nearest Property:
3368 FSL 3192 FEL S35 T11 N R7E UM
2;360'— S�40
2.831'
4b. Location of Well (State Base Plane Coordinates - NAD 27):
10, KB Elevation above N 108 feet
15. Distance to Nearest Well Open
Surface: x - 465255.45 y - 5940791.9 , Zone 4
GL Elevation above N 73.9 feet
to Same Pool: 4772' SMU M-02
16. Deviated wells: Kickoff depth: 500 feet '
17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 90.96 degrees
Downhole: 3,767 psig , Surface:
3,163 psig .
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)
42"
Insul 20"
91.5
A-53
Weld
80,
Surface
Surface
110,
110,
260 Sx ArcticCem (Approx)
754 TOTAL Sacks
12 1/4"
9 5/81,
40
L-80
BTC
2,532'
Surface
Surface
2,506'
2,508'
LEAD: 524 sx 10.7 ppg Permafrost L
TAIL: 229 sx 15.8 ppg SwiftCem
8 3/4"
7"
26
L-80
BTC-M
7,269'
Surface
Surface
7,343'
6,048'
LEAD: 67 sx 13 ppg VariCem
TOC: 6,843' MD/ 5,860' TVD
6 1/8"
1 4 1/2"
12.6
1 L-80
H521
4,889'
7,193'
1 5,998'
1 12,082'
1 6,208,
Slotted Liner
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):
Casing
Length
Size
Cement Volume
MD
TVD
Conductor/Structural
Surface
Intermediate
Production
Liner
Perforation Depth MD (ft):
Perforation Depth TVD (ft):
20. Attachments: Property Plat ❑r BOP Sketch [w] Drilling Program Time v. Depth Plot ❑
Shallow Hazard Analysis❑Z
Diverter Sketch 0 Seabed Report ❑ Drilling Fluid Program
20 AAC 25,050 requirementslo
21. Verbal Approval: Commission Representative:
Date
22. 1 hereby certify that the foregoing is true and correct.
Contact
Email
Printed Name Shearer
Title Drilling Manager
/
In
���f �----^
Signature (�/
Phone 907-887-4995 Date
4/9/2015
Commission Use Only
Permit to Drill
15 ' 10
API Number:
Permit Approval
See cover letter for other
Number: s
50. 03 — ti
—
Date:
requirements.
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed math", gas hydrates, or gas contained in shales:
Other: y �Q� S ` �� (� �S
? (T
Samples req'd: Yes ❑ A Nc[l�
Mud log req'd: Yes[] N�
H2S measures: Yes ® NC
Directional svy req'd: Yew Nc
5"�-t_Lt L� ✓`y �� E` e l f /---k Spacing exception req'd: Yes ❑ NcM/ Inclination
-only svy req'd: YesO Ncla
co A't /fk ul-11-6 , °z`r-
APPROVED BY
Approved by
COMMISSIONER THE COMMISSION
Date: — 1 _ _57-
--(_/7-1 r«-rllyll 5
Submit Form and
Fo(-R
evised 10/2012) This permit is valid for 24 months from the date of approval (20 AAC 26.006(g)) Attachments In Duplicate
IGINAL
RECEIVED
APR 10 2015
AOGCC
Brooks Range Petroleum
510 L St #601, Anchorage, AK 9950
Dan Shearer
Phone (907) 865-5815
Email: dshearer@brpcak.com
April 9, 2015
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
RE: Application for Permit to Drill Horizontal Production Well SMU M-04
Dear Commissioners,
Brooks Range Petroleum Corp. hereby applies for a Permit to Drill for the onshore horizontal
production well SMU M-04. This well will be drilled and completed using Nabors 16E. The
planned spud date could be as early as 04/27/2014,
Brooks Range Petroleum Corp. would also like to request a 14 day BOP test schedule at the
AOGCC's discretion.
Please find attached for the review of the Commission forms 10-401 and the information required by
20 ACC 25.005 for this well bore.
If you have any questions or require further information, please contact Joseph Longo at 907-947-
4323.
Sincerely,
Dan Shearer
Drilling Manager
Brooks Range Petroleum
Application for Permit to Drill Document
Water Injection Well SMU M-04
Table of Contents
1. Well Name.................................................................................................................
3
Requirementsof 20 AAC 25.005(f)............................................................................................................
3
2. Location Summary......................................................................................................
3
Requirements of 20 AAC 25.005(c)(2)........................................................................................................
3
Please see Attachment 9: Surface Platt......................................................................................................
3
Requirements of 20 AAC 25.050(b)............................................................................................................
3
3. Blowout Prevention Equipment Information................................................................. 4
Requirements of 20 AAC 25.005(c)(3)........................................................................................................
4
4. Drilling Hazards Information........................................................................................ 4
Requirementsof 20 AAC 25.005 (c)(4).......................................................................................................
4
S. Procedure for Conducting Formation Integrity Tests ...................................................... 4
Requirements of 20 AAC 25.005 (c)(5).......................................................................................................
4
6. Casing and Cementing Program...................................................................................
6
Requirementsof 20AAC25.005(c)(6)........................................................................................................
5
7. Diverter System Information.......................................................................................
6
Requirements of 20AAC25.005(c)(7)........................................................................................................
5
8. Drilling Fluid Program.................................................................................................
6
Requirementsof 20AAC25.005(c)(8)........................................................................................................
6
9. Abnormally Pressured Formation Information..............................................................
7
Requirements of 20AAC25.005 (c)(9).......................................................................................................
7
10. Seismic Analysis.........................................................................................................
7
Requirements of 20AAC25.005 (c)(10).....................................................................................................
7
11. Seabed Condition Analysis..........................................................................................
7
Requirements of 20AAC25.005 (c)(11).....................................................................................................
7
12. Evidence of Bonding...................................................................................................
7
Requirements of 20AAC25.005 (c)(12).....................................................................................................
7
SMU M-04 10-401 APD
Page 1 of 10
Printed: 9-Apr-15
Brooks Range Petroleum
13. Proposed Drilling Program.......................................................................................... 8
Requirements of 20 AAC 25.005 (c)(13)..................................................................................................... 8
14. Discussion of Mud and Cuttings Disposal and Annular Disposal .................................... 10
Requirements of 20 AAC 25.005 (c)(14)................................................................................................... 10
15. Attachments............................................................................................................ 10
Attachment 1 Drilling Procedure ............................................
Attachment 2 Directional Plan ...............................................
Attachment 3 Drilling Fluid Program ......................................
Attachment 4 Drilling Hazards Summary ................................
Attachment 5 Formation Integrity And Leak Off Test Procedure
Attachment 6 BOP and Diverter Configuration ........................
Attachment 7 Wellhead & Tree Configuration .........................
Attachment 8 Surface Platt ...................................................
........................... ...... ... I........... 10
................................................... 10
........... ..... ........ I............................. 10
.... ............................ ... ......... I ........ . 10
...................................................... 10
................. ........ I.,.......................... 10
...................................................1.1 10
...................................................... 10
SMU M-04_ 10-401 APD
Page 2 of 10
Printed: 9-Apr-15
Brooks Range Petroleum
1. Well Name
Requirements of 20AAC25.005 (f)
Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC
25.040(b). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix
to the name designated for the well by the operator and to the number assigned to the well by the commission.
Well Name: SMU M-04
2. Location Summary
Requirements of 20 AAC 25.005(c)(2)
An application for a Permit to Drill must be accompanied by each of the following items, except for on item already on file with the commission
and identified in the application:
(2) a plat identifying the property and the property's owners and showing
(A)the coordinates of the proposed location of the well at the surface, at the top of each objective formation, and at total depth, referenced to
governmental section lines.
(B) the coordinates of the proposed location of the well of the surface, referenced to the state plane coordinate system for this state as
maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration;
(C) the proposed depth of the well of the top of each objective formation and of total depth;
Location at Surface 2408 FSL 1723 FEL S2 T10N R7E UM
ASP Zone 4 NAD 27 Coordinates RKB Elevation 108.00' AMSL
Northing: 5,940,792' Easting: 465,255' Pad Elevation 73.9 AMSL
Location at Top of Productive
Interval ("Kuparuk C" Sand)
4334 FSL 3868 FEL S2 T10N R7E UM
Measured Depth, RKB:
7,713'
ASP Zone 4 NAD 27 Coordinates
Northing: 5,942,728' Easting: 463,118'
Total Vertical Depth, RKB:
6,145'
Total Vertical Depth, SS:
6,037'
Location at Total Depth
3369 FSL 3192 FEL S35 T11N R7E UM
ASP Zone 4 NAD 27 Coordinates
Northing: 5,947,039" Easting: 463,810'
Measured Depth, RKB:
12,082'
Total Vertical Depth, RKB:
6,208'
Total Vertical Depth, SS:
6,100'
Please see Attachment 9: Surface Platt
and
(0) other information required by 20 AA C 25. 050(b);
Requirements of 20 AAC 25.050(b)
If a well is to be intentionally deviated, the application for a Permit to Drill (Form 10-401) must
(1) include a plat, drown to a suitable scale, showing the path of the proposed wellbo re, including all adjacent wellbores within 200 feet of any
portion of the proposed well;
Please see Attachment 2: Directional Plan
and
(2) for all wells within 200 feet of the proposed wellbore
(A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show
that each named operator has been furnished a copy of the application by certified mail, or
(B) state that the applicant is the only affected owner.
The Applicant is the only affected owner.
SMU M-04 10-401 APD
Page 3 of 10
Printed: 9-Apr-15
Brooks Range Petroleum
3. Blowout Prevention Equipment Information
Requirements of 20 AAC 25.005(c)(3)
An application for a Permit to Drill must be accompanied by each of the following items, except for on item already on file with the commission
and identified in the application:
(3) a diagram and description of the blowout prevention equipment (BOPE) as required by 20 AAC 25.035, 20 AAC 25.036, or 20 AAC 25.037, as
applicable;
Please see Attachment 7: BOP and Diverter Configuration
4. Drilling Hazards Information
Requirements of 20 AAC 25.005 (c)(4)
An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission
and identified in the application:
(4) information on drilling hazards, including
(A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based
on a methane gradient, -
The expected reservoir pressure in the Kuparuk C Sand is 0.6240 psi/ft, or 12.0 ppg EMW (equivalent mud weight).
The maximum potential surface pressure (MPSP) based on the above maximum pressure gradient, a methane
gradient (0.10), and the planned vertical depth of the Kuparuk C formation is:
MPSP = (6,037 TVDss)(0.6240 - 0.10 psi/ft)
= 3,163 psi
(B) data on potential gas zones;
The K-10 Campanian sands are known for potential gas kicks in this area. The intermediate section will be drilled
with a minimum mud weight of 9.7 ppg prior to penetrating the K-10.
and
(C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a
propensity for differential sticking;
Please see Attachment 5: Drilling Hazards Summary.
5. Procedure for Conducting Formation Integrity Tests
Requirements of 20AAC 25.005 (c)(5)
An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission
and identified in the application:
(5) a description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(f);
Please see Attachment 6: Formation Integrity and Leak off Test Procedure
SMU M-04 10-401 APO
Page 4 of 10
Printed: 9-Apr-15
Brooks Range Petroleum
6. Casing and Cementing Program
Requirements of 20 AAC 25.005(c)(6)
An application for a Permit to Drill must be accompanied by each of the following items, except for on item already on file with the commission
and identified in the application:
(6) a complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre -perforated
liner, or screen to be installed, -
Casing and Cementing Program
See also Attachment 4: Cement Summary
Csg/Tbg
OD (in)
Hole
Size
Weight
(Iblft)
Grade
Connection
Length
(ft)
Top
MD/TVD
Btm
MD/TVD
Cement Program
(in)
(ft)
(ft)
Insul
2
42"
91.5
A-53
Weld
80'
Surface
110'/ 110'
260 sx ArcticCem (Approx)
754 TOTAL sx
9 5/8"
12 1/4"
40
L-80
BTC
2,532'
Surface
2,606'/2,508'
LEAD: 524 sx 10.7 ppg Permafrost L
TAIL: 229 sx 15.8 ppg SwiftCem
67 TOTAL sx
7"
8 3/4"
26
L-80
BTC-M
7,269'
Surface
7,343'/6,048'
LEAD: 67 sx 13.0 ppg VariCem
TOC: 6,843'/ 5,860' TVD
4 1/2"
6 1/8"
12.6
L-80
H521
4,889'
7,193'/5,997'
12,082'/6,208'
Slotted Liner
7. Diverter System Information
Requirements of 20 AAC 25.005(c)(7)
An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission
and identified in the application:
(7) a diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under
20 AAC 25.035(h)(2);
Please see Attachment 7: BOP Configuration.
SMU M-04_ 10-401 APD
Page 5 of 10
Printed: 9-Apr-15
Brooks Range Petroleum
8. Drilling Fluid Program
Requirements of 20 AAC 25.005(c)(8)
An application for a Permit to Drill must be accompanied by each of the following items, except for on item already on file with the commission
and identified in the application:
(8) a drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033;
Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033.
Drilling will be done with muds having the following properties over the listed intervals:
Surface Hole Mud Program (Spud Mud)
Spud to Base of Permafrost
Base Permafrost to TD
Parameter
Initial Value
Final Value
Initial Value
Final Value @ TD
Density (ppg)
9.0
9.4
(9.4
9.6,
Funnel Viscosity (sec)
220-300
200 — 300
200 — 250
150-200
Yield Point (cP)
45 — 60
50 — 70
50 — 70
45 — 60
PV (Ibs/100ft2)
20 — 30
20 — 45
20 — 45
20 — 30
pH
9.0-9.5
9.0-9.5
9.0-9.5
9.0-9.5
API Filtrate (cc)
8 —15
<10
<10
<10
Solids (%)
t 9%
Intermediate Hole Section (LSND)
Parameter
Initial Value
@ TD
Density (ppg)
9.7
10.7 1
Funnel Viscosity (sec)
35 — 45
35 — 45
Yield Point (Ibs/100ft')
22 — 28
22 — 28
Plastic Viscostiy (CP)
10 —15
10 — 15
Gels 10sec/ 10m in
8 —10/ <20
8 —10/ <20
Chlorides
<800
<800
pH
9.5-10
9.5-10
API Fluid Loss (cc/30min)
<10
<10
HTHP Fluid Loss (cc/30min)
<10
<10
M BT
<20
<20
Solids (ppb)
<11
<18
SMU M-04 10-401 APD
Page 6 of 10
Printed. 9-Apr-15
Brooks Range Petroleum
Production Hole Section (FloThru)
Parameter
Value
Density (ppg)
12.3
Funnel Viscosity (sec)
40 — 50
Yield Point (lbs/100 ft2)
20 — 30
Plastic Viscostiy (CP)
20 — 26
pH
9.0 — 9.5
API Fluid Loss (cc/30min)
<10
HTHP Fluid loss (cc/30min)
<6
LGS
<10%
9. Abnormally Pressured Formation Information
Requirements of 20 AAC 25.005 (c)(9)
An application for a Permit to Drill must be accompanied by each of the following items, except for on item already on file with the commission
and identified in the application:
(9) for an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by
20 AAC 25.033(f);
Not applicable: Application is not for an exploratory or stratigraphic test well.
10. Seismic Analysis
Requirements of 20 AAC 25.005 (c)(10)
An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission
and identified in the application:
(10) for an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25.061(a);
Not applicable: Application is not for an exploratory or stratigraphic test well.
11. Seabed Condition Analysis
Requirements of 20 AAC 25.005 (c)(11)
An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission
and identified in the application:
(11) for a well drilled from on offshore platform, mobile bottom -founded structure, jack -up rig, or floating drilling vessel, on analysis of seabed
conditions as required by 20 AAC 25.061(b);
Not applicable: Application is not for an offshore well.
12. Evidence of Bonding -
Requirements of 20 AAC 25.005 (c)(12)
An application fora Permit to Drill must be accompanied by each of the following items, except for on item already on file with the commission
and identified in the application:
(12) evidence showing that the requirements of 10 AAC 25.025 (Bonding)have been met;
Evidence of bonding for Brooks Range Petroleum Corp. is on file with the Commission.
SMU M-04 10-401 APD
Page 7 of 10
Printed: 9-Apr-15
//N10
Brooks Range Petroleum
13. Proposed Drilling Program
Requirements of 20AAC25.005 (c)(13)
An application for a Permit to Drill must be accompanied by each of the following items, except for on item already on file with the commission
and identified in the application:
Please refer also to Attachment 1— Drilling Procedure
1. Rig up on slot "R". Set 20" (34" sleeve) install insulated conductor (See the TSA installation instructions) using
"Watson" drill at a minimum depth of 80' below ground level. The RKB on the rig is anticipated to be 33' 1-1/2".
Install an 8' diameter by 5' deep corrugated pipe cellar.
2. Install 20" SOW X 19.995" Slick -neck with 18.75" Diameter Bowl, FMC landing ring assembly.
3. MIRU Nabors 16-E.
4. Nipple up diverter riser and 21-1/4" x 2K Hydril MSP diverter system. Install diverter line.
5. Notify (48 hour notice) AOGCC of planned diverter test so that they can witness test. Function test diverter
system and conduct diverter operation drills with each drilling crew.
6. Spud in and drill 12-1/4" hole directionally to total depth using a Gel based spud mud. Mud weight will
unweighted at 8.8-9.1 ppg and will naturally weight up to —9.6+ by TD.
7. Run 9-5/8" 40 ppf L-80 BTC surface casing to TD. Run a TAM port collar at 500' as a contingency in case of
losses during cementing operations. Run centralizers per cementing program.
8. Cement 9-5/8" casing to surface in one stage per cement program. The port collar will not be utilized unless
cement returns do not reach surface during the primary cement job. Per 20 AAC 25.030
9. ND diverter and NU 11"x 5K FMC Gen 5 wellhead. Install 11" X 13-5/8" DSAF.
10. NU 13-5/8" x 5K BOP stack and 3-1/16" x 5K choke manifold.
BOP configuration from top to bottom as follows:
13-5/8"x 5K Hydril GK Annular preventer
13-5/8"x 5K Pipe Rams 3-1/2" x 6" VBR's
13-5/8"x 5K Blind Shear Rams
13-5/8"x 5K Drilling spool with tea 3-1/16" outlets
13-5/8" x 5K Pipe Rams 2-7/8" x 5" VBR's
Test all components to 25014000 psi. Annular preventer may be tested to 25012500 psi only. Install wear bushing.
11. RIH w/ 8.75" BHA. Test 9-5/8" casing to 3000 psi with mud for 30 min. Record test on a chart.
12. Drill out float equipment and cement in the rat hole.
13. Clean pits. Bring on new mud.
14. Displace wellbore to new 9.7 ppg mud for drilling the 8-3/4" intermediate hole.
15. Drill 20' of new formation (but not more than 50') below the old TD depth.
16. Perform a leak off test (LOT). Based on offset well information, expect a LOT in the range of 16.0 ppg. A
minimum LOT value (-12.7 ppg) that is at least 2 ppg over MW proposed at TD of 8-3/4" hole will be needed
to accommodate mud hydrostatic + ECD effects.`-
SMU M-04 10-401 APD
Page 8 of 10
Printed: 9-Apr-15
Brooks Range Petroleum
17. Drill 8-3/4" hole per directional program to approximately 6766' MD (6010' TVD). Mud weight will start at 9.7
ppg and increase to 10.7 ppg 500' MD prior to the HRZ Shale, The K-1 marker in the Kalubik will be used to
pick the intermediate casing point.
18. BOP tests are required every 14 days Notify the AOGCC inspector at least 48 hours in advance of the start of
any BOPE test.
19. Run and cement 7" 26 ppf L-80 BTC-M intermediate casing to a minimum of 500' above the Tarn T-4 formation
top at 7343' MD/ 6048' TVD.
20. Freeze -protect the 7"x 9-5/8" annulus by down squeezing diesel to the outer annulus down to -1900' MD
(approx. 500' MD below base Permafrost),
21. Clean pits and lines.
22. RIH with 6-1/8" BHA. Test casing to 4000 psi for 30 min. Drill our shoe track and displace mud to new drill -in
fluid @ 12.3 ppg. Have extra kill weig`F fluid on location at all times when drilling the production interval. Drill
out the shoe track and 20' of new formation. Perform a formation integrity test (FIT) to 15.5 pp E W.
23. Drill the 6-1/8" hole through the Kuparuk "C" target interval. Provide sufficient rat hole for LWD logging and a
liner shoe track to a final TD of 12,082' MD (6208' TVD). Extreme care will be utilized when drilling near the
Kuparuk A sands.
24. Circulate the hole clean (a minimum of three bottoms up).
-/ 25. POH. LIDBHA.
j� 26. Rig up and run approximately 4,889' of 4-1/2" 12.6# L-80 H521 Slotted Liner with liner hanger and liner top
P( packer.
27. Set and test ZXP liner top packer per program.
28. Displace well to clean kill weight brine. POH.
29. Run 4-1/2" tubing completion per detailed completion procedure. Detailed completion procedure to be
submitted toAOGCC. S".'9'-) Veepf.j'
30. ND BOPE and NU Xmas tree. Test tree to 5,000 psi.
li 31. Freeze protect the tubing and IA to -1900' MD. Allow to U-tube.
Ste" 32. Install a BPV in the tubing hanger.
33. RD Nabors 16-E and move off.
34. RU well testing equipment.
35. Pull BPV with a lubricator. RU E-line, log onto depth and perforate.
36. Flow test well as per well testing procedure.
37. Pump kill -weight fluid and freeze protect the well. Set necessary mechanical plugs to provide required barriers
for operationally shutting down the well with all downhole production equipment in place. A Sundry Notice
(Form 403) will be filed with AOGCC describing barriers.
38. Install BPV in tubing hanger profile. Install VR plugs in all wellhead valves.
39. RDMO testing equipment.
SMU M-04 10-401 APD
Page 9 of 10
Panted., 9-Apr-15
Brooks Range Petroleum
14. Discussion of Mud and Cuttings Disposal and Annular Disposal
Requirements of 20 AAC 25.005 (c)(14)
An application for a Permit to Drill must be accompanied by each of the following items, except for on item already on file with the commission
and identified in the application:
(14) a general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator intends to
request authorization under 20AAC 25.080 for on annular disposal operation in the well.;
Waste fluids generated during the drilling process will be disposed of by hauling the fluids to the Prudhoe Bay or
ConocoPhillips Grind and Inject Facility located at 1B Pad. All cuttings generated will be hauled to the Prudhoe Bay
or ConocoPhillips Grind and Inject Facility located at 1B Pad for temporary storage and eventual processing for
injection down an approved disposal well.
15. Attachments
Attachment 1 Drilling Procedure
Attachment 2 Directional Plan
Attachment 3 Drilling Fluid Program
Attachment 4 Drilling Hazards Summary
Attachment 5 Formation Integrity And Leak Off Test Procedure
Attachment 6 BOP and Diverter Configuration
Attachment 7 Wellhead & Tree Configuration
Attachment 8 Surface Platt
SMU M-04 10-401 APO
Page 10 of 10
Printed: 9-Apr-15
Mustang
Development
Brooks Range Petroleum
AOGCC 10=401
Attachments
//Nldy�
Brooks Range Petroleum
Brooks Range Petroleum Corp. - AOGCC 10-401 Attachments
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
Drilling and Completion Well Plan
SMU M-04
"Argo"
Slim Hole Producer
Mustang
Development Drilling and Evaluation
Program
April 2015
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
Table of Contents
Introduction...............................................................................................................................................
3
ProjectOutline: .......................................................................................................................................
4
SMUMustang Well Testing: ....................................................................................................................
4
WellInformation: ....................................................................................................................................
5
GeneralWell Plan: SMU M-04...............................................................................................................9
ShortScope: ..........................................................................................................................................
10
DrillingRisks...........................................................................................................................................13
DrillingRisk Assessment........................................................................................................................
14
LOT/FIT...................................................................................................................................................16
PROCEDURE.........................................................................................................................................16
MASP & Casing Design Verification Calculations.............................................................................18
Maximum Anticipated Surface Pressure(MASP):.................................................................................
19
Casing Design Verification: ....................................................................................................................
20
Casing Design Factor Calculations: ........................................................................................................
21
Pre -operational Procedures..................................................................................................................
24
Pre -rig operations: ................................................................................................................................
25
DetailedOperational..............................................................................................................................
27
DrillingProcedures.................................................................................................................................27
Drill12-1/4" Surface Hole: ....................................................................................................................
28
Run9-5/8" Surface Casing: ...................................................................................................................
30
Cement9-5/8" Surface Casing: .............................................................................................................
33
Drill 8-3/4" Intermediate Hole: .............................................................................................................
35
8-3/4" Intermediate Hole Section Notes and Lessons Learned: ............................................................
37
Run7" Intermediate Casing: .................................................................................................................
38
Cement 7" Intermediate Casing: ...........................................................................................................
41
Drill6-1/8" Production Hole: ................................................................................................................
43
Run4-1/2" Slotted Liner: ......................................................................................................................
44
WellOverview: ......................................................................................................................................
46
2
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
Introduction
150409 SMU M-04 Well Plan Rev 1
Argo Drilling Program
Brooks Range Petroleum SMU M-04
Project Outline:
The Argo Horizontal Producer well "SMU M-04" will be drilled from the BRPC Mustang development
pad to the west of the 2L and 2M pads of Kuparuk field on the North Slope. The Argo well will consist
of a 20" x 34" insulated conductor pipe, 9-5/8" surface casing, 7" intermediate casing and a 4-1/2"
slotted production liner. The production interval will be drilled and evaluated with LWD.
The main objective of the well is to drill and complete a—5,000' horizontal producer in the Kuparuk
"C" sands. Following completion of this well, BRPC intends to test flow the well for as yet
undetermined amount of time to clean up the well, then perform a —126 hour test to acquire data and
to evaluate the reservoir properties. Post well test, this oil production will be re -injected into the Argo
"SMU M-02" well or sent to BP for disposal. The well will then be secured and suspended per AOGCC
regulations for use as a horizontal producer once the Mustang production facility has been
commissioned.
SMU Mustang Well Testing:
Winter 2014/2015
Three SMU Mustang wells are planned to be drilled this winter (2014/2015). Well flow tests are
being planned and AFE'd for the first two wells (one slant well and one horizontal producer). The
two well tests were designed to achieve the following objectives:
• To determine the reservoir and wellbore properties; determine flow capacity (kh), skin and
effective producing length (Leff).
• Limit fluid production from slant well test to minimize storage requirements.
• Keep bottom hole flowing pressure above bubble point prior to maximum -rate test.
• Short maximum -rate test after final build up.
The second well test is Argo HP (SMU M-04). After completion as a Horizontal Producer (4-1/2"
slotted liner), Argo will be flow tested for approximately one hundred twenty six (126)
hours. "Success" would be rates sustained in excess of 1500 BOPD. Flow test fluids will be injected
into the Lipizzan (SMU M-02 well) for storage or BP for disposal.
The horizontal flow test design should be revised, if needed, based on the results of the slant well.
Total test time is 126 hours excluding well clean-up period:
1. Clean-up flow as needed
2. Flow 6 hours at approximately 300 BOPD
3. Shut in well for 10 hours
4. Flow well for 36 hours at approximately 300 BOPD
5. Final shut-in for 72 hours
6. Maximum flow rate test for 2 hours
7. Kill well and freeze protect.
8. Secure well and suspend
9. RDMO
0
150409 SMU M-04 Well Plan Rev 1
P FJD
Argo Drilling Program
Brooks Range Petroleum
SMU M-04
Argo Horizontal Producer - Mustang Production Pad Slot "E"
Proposed Diagram
SM
-n
0
9-5/8" Tam Collar: 500' MD 1499' TVD
12-1/4" OH: 2,606' MD/ 2,608' TVD
Gas Lift Mandrels
Where Required
3.1/2", 9.3 ppf, L-80, TCII
TOL: 7,193' MDI 5,998' TVD
8.3/4" OH: 7,343' MD/6,048' TVD
6.1/8" OH: 12,082' MD/ 6,208' TVD
20" x 34" Conductor. 110' MD / 110' TVD
B/ Permafrost: 1,400' MD/ 1,396' TVD
SOV: 1,900' MD
9-6/8", 40#, L80, BTC: 2,606' MD/ 2,508' TVD
PP3 SIT
11.1 - Ic.70PS
Memory PT Gauge: 7,022' MD
Memory PT Gauge: 7,054' MD
ROC PT Gauge: 7,086' MD
X Nipple: 7,103' MD
3-1/2" X7" Packer. 7,126' MD
XNipple: 7,14T MD
Mirage Plug/ Auto Fill: 7,188' MD
WLEG: 7,196' MD
BTC-M: 7,343' MD/6,048' TVD 'Y O-r
�-, �
4-1/2" SL, 12.6#, L80, H621: 12,082' MD/ 6,208' TVD
Brooks Range Petroleum
Well Information:
Argo Drilling Program
SMU M-04
Operator
Brooks Range Petroleum Corporation
Well Name
SMU M-04
Bottom Hole Location
Argo
Slot
E
Well Type
Horizontal Producer
AOGCC Permit Number
TBD , jS-0(0
API Number Number
TBD
AFE Number
TBD
Primary target
Kuparuk C
Geodetic System
US State Plane 1924
Geodetic Datum
NAD 1927 (NADCOM CONUS)
Map Zone
Alaska Zone 04
Surface Location
2408 FSL 1723 FEL S2 T10N R7E UM
X- 4655255, Y- 5940792
Bottom hole location
857 FSL 1344 FEL S11 T10N VE UM
X — 463810 Y- 5947039
Area
Southern Miluveach Unit
Total Depth:
12,082' MD / 6,208'TVD
Rig
Nabors 16-E
Rotary Table to Ground Level
33' 1-1/2"
RKB
108'
Bottom hole static temperature
1400 F (6200' TVD)
150409 SMU M-04 Well Plan Rev 1
7
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Brooks Range Petroleum
Argo Drilling Program
SMU M-04
WELL
LATITUDE(N)
LONGITUDE(W)
NORTHING
EASTING
SECTION LINE OFFSET
PAD ELEVATION
sa A
N 070' 14' 57,101"
W 150' 16' 52171-
5940772.89
465198.38
2.389'
1.780'
73.6
8
N 070' 14' 57.147'
W 150' 16' 51.161'
5940777.52
465212.52
2,393'
1,766'
73-7
C
N C70' 14' 57.194'
W 150' 16' 51,346"
594078215
465226,79
2.398'
1,752'
73.8
D
N 070' 14' 57.24C"
W 150' 16' 50-932"
5940786.78
465241-05
2,403'
1.738,
73.9
•
E
N 070' 14' 57.291-
W 150. 16' 50.514"
5940791.90
465255.45
2,408'
1,723'
73.9
F
N 07C' 14' 57.332"
W 150' 16' 50.104"
594-0196.05
465269.58
2,412'
1.709,
74.0
G
N C70' 14' 57.379"
W 150' 16' 49 690"
5940800.69
465283.85
2.417'
1.695'
74.1
H
N C7C' 14' 57.425"
W 150' 16' 49.275'
5940805.32
465298.11
2,422'
1,68''
74-2
++ I
N C70' 14' 57.471'
W 150' 16' 4-8.853"
5940809.93
4-65312.31 1
2,426'
%r357'
74.7
N C7C' 14' 57,517"
W 150' 16' 48-447"
5940814.59
465326.64
2,431'
',652'
74.3
K
N C7C' 14' 57.564"
W 150' 16' 48.033"
59408'9,23
465340.90
2,436'
1,638'
74.4
L
N CIC' 14' 57.610'
W 150' 16' 4-1.6'8"
5940823.86
46.9355,17
2,440'
4,624'
74.5
as M
N 070' 14' 57,655"
W 150' 16' 47,213"
b940B28.42
465369.14
2,445'
1,610,
74.5
N
N C70' 14' 57.702"
W 150' 16' +6.790"
5940833.'3
465383.7012.450'
1,595'
74.6
0
N C/O* 14' 57.749"
'W 150' 16' 46.316"
5940837.77
465397.96
2,454'
1,581'
74.7
p
N 070' 14' 57,795"
W 150' 16' 45 961"
594C842.40
4455412.23
2,459'
1,567'
14.a
a
N 070' 14' 57.841"
W 150' 16' 45.547"
5940847,04
465426.49
2,464'
1,553'
74.8
R
N 070' 14' 5t88J"
'W 150' 16' 45.133"
5940851.67
465440 76
2,468'
".538'
74.9
LL
N C70' 14' 57.933"
W 150' 16' 44 719'
5940855.31
465455.02
2,473'
',524'
15.0
S
N 07C' 14' S6.354"
W 150' 16' 51.446"
5940696.80
465222.98
2,3'3'
1,756'
73.8
T
N 070' 14' 56.4-00"
W 150' 16' 51.032"
5940701,44
465237 24
2.317'
1,741-
73.9
U
N 07C' 14' 56.446"
W 150' 16' 50.617"
5940706.07
4-65251.51
2.322'
1.727'
74.0
V
N C70' 14' 56,493"
W 150' 16' 50 203"
5940710.71
465265.77
2.327'
1,713'
74.1
W
N 070' 14' 56.539"
W 150' 16' 49.789"
59407'5.34
465280 04
2,331'
1,699'
74.'
x
N 070' 14' 56.585"
W 150' 16' 49-375"
5940719.98
465794.3C,
2,336'
1,694'
74.2
Y
N 070' 14' 56.631"
W 150' 16' 48 960"
5940724.61
465308.571
2.34V
1.670'
74.3
Z
N 070' 14' 56.678"
W 150' 16' 48.546"
5940729,25
465322,83
2,346'
1,656'
74.4
AA
N 070' 14' 56.724"
W 150' 16' 4.8.132'
5940733.88
465337,C9
2,350'
1,542'
74.4
99
N 070' 14' 56.770"
W 150' 16' 47 718"
5940738.52
465351.36
2,355'
1,627'
74.5
cc
N 070' 14' 56.816'
W 150' 16' 47-303"
5940743.15
465365.62
2,360'
1,613'
74.6
DD
N 070' 14' 56.663"
'W 150' 16' 4-5M "
5940747.79
465379,89
2,364'
1,599'
747
EE
N 070' 14' 56.909"
W 150' 16' 46 475"
5940752.42
465394.15
2,369'
585'
74.7
FF
N 070' 14' 56,955"
'W 150' 16' 46061"
5940757.06
465408 42
2,374'
%570'
748
GG
N 070' 14' 57.001"
'W 150' 16' 45.646"
5940761.69
465422.68
2.378"
`,556'
74.9
HH
N 070' 14' 57.C48"
W 150' 16' 45.232"
5940166.33
465436.95
2,383'
1,542'
15.0
II
N C70' 14' 57.C94"
W 150' 16' 44 8"-8"
5940770.96
4-65451.21
1 2,388'
1,528'
75.0
JJ
N 070' 14' 57.140"
1 W 150' 16' 44.404"
15940775,60
465465.47
2,393'
1,513'
75,1
KK
N C7C' 14' S7J86"
W 150' 16' 43.989"
b940180.23
465479.74
2,39J'
499'
75.2
** Indicates Asbuilt Well Conductor Coordinates
Scale Faczor - 0.999901 i66
PROTRACTED SECTION 2, T. 10 N., R. 7 E., UMIAT MERIDIAN
8
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
General Well
Plan: SMU M=04
7
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Short Scope:
Argo Drilling Program
SMU M-04
1. Rig up on slot "R". Set 20" (34" sleeve) install insulated conductor (See the TSA installation
instructions) using "Watson" drill at a minimum depth of 80' below ground level. The RKB on the
rig is anticipated to be 33' 1-1/2". Install an 8' diameter by 5' deep corrugated pipe cellar.
2. Install 20" SOW X 19.995" Slick -neck with 18.75" Diameter Bowl, FMC landing ring assembly.
3. MIRU Nabors 16-E.
4. Nipple up diverter riser and 21-1/4" x 2K Hydril MSP diverter system. Install diverter line.
5. Notify (48 hour notice) AOGCC of planned diverter test so that they can witness test. Function
test diverter system and conduct diverter operation drills with each drilling crew.
6. Spud in and drill 12-1/4" hole directionally to 2,606' MD (2,508' TVD) using a Gel based spud
mud. The well will be kicked off at 500', built to 30.94° by TD. The base of the permafrost is
estimated to be at—1,400' MD (1,396' TVD).
7. Ensure X-0 with FOSV is on the floor.
8. Run 9-5/8" 40# L-80 BTC surface casing to TD. Run a TAM port collar at 500' as a contingency in
case of losses during cementing operations. Run centralizers per cementing program.
9. Cement 9-5/8" casing to surface in one stage per cement program. The port collar will not be
utilized unless cement returns do not reach surface during the primary cement job. Per 20 AAC
25.030 Ao , Cc . � C`,."-iL.... 130
10. ND diverter and NU 11"x 5K FMC Gen 5 wellhead. Install 11" X 13-5/8" DSAF.
11. NU 13-5/8" x 5K BOP stack and 3-1/16" x 5K choke manifold.
BOP configuration from top to bottom as follows:
- 13-5/8"x 5K Hydril GK Annular preventer
- 13-5/8"x 5K Pipe Rams - 3-1/2" x 6" VBR's
- 13-5/8"x 5K Blind Shear Rams
- 13-5/8"x 5K Drilling spool with 2ea 3-1/16" outlets
- 13-5/8" x 5K Pipe Rams-2-7/8" x 5" —VBR's
Test all components to 25014000 psi. Annular preventer may be tested to 25012500 psi only. Install
wear bushing.
12. RIH with 8-3/4" BHA, Test 9-5/8" casing to 3000 psi with 9.6 ppg mud for 30 min. Record test on
a chart. ----
13. Drill out float equipment and cement in the rat hole.
14. Clean pits. Bring on new mud.
15. Displace wellbore to new 9.7 ppg mud for drilling the 12.25" intermediate hole.
16. Drill 20' of new formation (but not more than 50') below the old TD depth.
17. Perform a leak off test (LOT). Based on offset well information, expect a LOT in the range of
16.0 ppg. A minimum LOT value (-12.7 ppg) that is at least 2 ppg over MW proposed at TD of
12.25" hole will be needed to accommodate mud hydrostatic + ECD effects.
18. Drill 8-3/4" hole per directional program to approximately 7,343' MD/ 6,048' TVD. Mud weight
will start at 9.7 ppg and increase to 10.7 ppg 500' prior to penetrating the HRZ. The K-1 marker
m
150409 SMU M-04 Well Plan Rev 1
Argo Drilling Program
Brooks Range Petroleum SMU M-04
in the Kalubik will be used to adjust the intermediate casing point. Set 10' TVD above the
Kuparuk C.
TD is -10 ft TVD above the Kuparuk "C" target estimated at 6,145' TVD.
19. BOP tests are required every 14 days. Notify the AOGCC inspector at least 48 hours in advance
of the start of any BOPE test. C. (e-
20. C/O and Test 7" Rams.
21. Run and cement 7" 26# L-80 BTC-M intermediate casing to a minimum of 500' above the
Kuparuk Sand. Ensure XO with FOSV is on the floor.
22. Freeze -protect the 9-5/8" x 7" annulus by down squeezing diesel to the outer annulus down to
—1900' MD (approx. 500' MD below base Permafrost).
23. Clean pits and lines.
24. RIH with 6-1/8" BHA. Test casing to 4000 psi for 30 min. Displace mud to new drill -in fluid @ 12.3
ppg-
Have extra kill weight fluid on location at all times when drilling the production interval.
25. Drill out the shoe track and 20' of new formation. Perform a formation integrity test (FIT) to 15.5
ppg EMW.
26. Drill the 6-1/8" hole through the Kuparuk "C" target interval to a final TD of 12,082' MD/ 6,208'
TVD.
Extreme care will be utilized when drilling near the Kuparuk A sands.
27. Circulate the hole until the shakers run clean per HXR.
28. BROOK LID BHA.
29. Rig up and run approximately 5000' of 4-1/2" 11.6 # L-80 H521 liner with SLZXP liner hanger and
liner top packer.
30. Set 4-1/2" Liner hanger and test packer.
31. Run 3-1/2" 9.3# L-80 TCII tubing per detailed completion procedure. Detailed completion
procedure to be submitted to AOGCC.
32. ND BOPE and NU Xmas tree. Test tree to 5,000 psi.
33. Freeze protect the tubing and IA to —1900' MD.. Allow to U-tube.
34. Set the 7" x 3.5" production packer and test both tubing and IA to 1500 psi for 30 minutes. Record
tests on a chart.
35. Install a BPV in the tubing hanger, consider setting plug in lower X-Nipple.
36. RD Nabors 16-E and move off.
37. RU well testing equipment.
38. Pull BPV with a lubricator.
39. Flow test well as per well testing procedure.
40. Pump kill -weight fluid and freeze protect the well. Set necessary mechanical plugs to provide
required barriers for operationally shutting down the well with all downhole production
11
150409 SMU M-04 Well Plan Rev 1
Argo Drilling Program
Brooks Range Petroleum SMU M-04
equipment in place. A Sundry Notice (Form 403) will be filed with AOGCC describing barriers.
41. Set plugs in nipple profiles install BPV in tubing hanger profile. Install VR plugs in all wellhead
valves.
42. RDMOtesting equipment.
12
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
Drilling Risks
13
150409 SMU M-04 Well Plan Rev 1
Argo Drilling Program
Brooks Range Petroleum SMU M-04
Drilling Risk Assessment
Increased Pore Pressure in Kuparuk (High)
The closest offset wells Mustang #1 (M-01) and North Tarn 1A had lost circulation and a kick. It
is believed that high mud weight of 12.5-12.9 ppg used to drill the production hole through the
Kuparuk "C" led to fracture and losses in the Kuparuk "A". Subsequently, a kick was taken and
circulated out with 11.8 ppg mud weight. The formation evaluation data from the N Tarn-1A
well shows that the reservoir pressure of Kuparuk "C" is -12.0 ppg and the Kuparuk "A" has
10.4 ppg pressure resulting from the injection activities on neighboring pads and depletion due
to production. Mud weight planned for the production section is 12.3 ppg and should provide a
sufficient overbalance across the producing intervals. Mud loggers will monitor pit levels,
background gas and other indicators of increasing pore pressure. Flow checks will be performed
on connections and the well will be monitored during trips to ensure proper fill up and to
minimize swabbing.
Lost Returns (High)
A risk of losses will be present during drilling SMU M-04. As seen in the SMU M-02 well, the
intermediate section has proven to be fractured in some areas. All efforts should be made to
reduce ECD's as much as possible. Do not exceed 12.3 ppg ECD while drilling the intermediate
hole section. The Kuparuk formation is known to be highly fractured in places. The mud density
and rheology will be maintained according to the mud program. The PWD tool will be used to
monitor real-time ECDs close to the bit and to help identify losses at the earlier stages. Pit levels
should be monitored at all times and tripping speeds will be controlled to reduce surge & swab
values. A contingency lost circulation plan (LCM decision tree) will be utilized to control losses.
Gas Hydrates ("'lediun- )
Experience in Tarn area shows that this area has hydrates. The mitigation is to drill the
permafrost section quickly and get surface casing set without delays. The section will need to
be drilled with MW of 9.3 ppg+ to overbalance the gas sands. There is commonly a thin tarry
sand at the 'K-10' level, about 2590' TVD; it is equivalent to the Tabasco sands but being thin
(to non-existent in places) and tarry, it has not shown commercial potential in this area (yet).
Minimum mud weight pre- K-10 sands is 9.8 ppg. In addition, pre -treating mud with Lecithin
and Screen Kleen, known to prevent gas hydrate destabilization. Lecithin and Screen Kleen will
be used in the surface mud system.
Shale Instability (
Known instability issues in this area are associated with drilling the HRZ shales. Mitigation
includes use of "shale inhibitors" (Resinex, Soltex) to coat potentially unstable zones and help
maintain a low fluid loss. Minimizing directional changes through the shales and increasing mud
density at the first sign of shale instability. According to the HRZ shale stability study and based
on the hole inclination and the azimuth, the mud weight required for drilling the HRZ shales in
the Argo intermediate hole should be in a range of 10.4 - 10.7 ppg.
14
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Hole Cleaning (Medium)
Argo Drilling Program
SMU M-04
In the surface interval, borehole cleaning issues may arise while drilling through the permafrost
due to the presence of loose gravel and boulders. A few mitigation measures can be used: drill
as fast as practical, do not leave the hole open for a long time, keep the mud cold and viscous.
In the intermediate interval maintain fast drilling, practice short trips every 24 hours or
1000'MD, whichever comes first, minimize static times and run the casing as soon as practical
after the borehole is drilled. Plotting torque and drag daily will indicate problematic trends.
Record torque and pick-up, rotating, and slack off weights on every connection.
Stuck Pipe due to Borehole Packoff (
Borehole packoff can occur due to conglomerate drilling and/or improper hole cleaning.
Monitor cuttings loading in the annulus and control drill and/or circulate out to clean hole and
lower ECD. The use of a PWD tool will help in identifying potential hole cleaning issues in real
time.
Stuck Pipe due to Differential Sticking (
Differential sticking occurs when BHA is across permeable sands. Pipe movement (reciprocation
and/or rotation) at all times helps to prevent sticking. Stabilizer placement should be optimized.
The risk of differential sticking in the Argo well exists; due to the section requirement to drill
with—10.4-10.6 ppg mud, which gives overbalance across normally pressured permeable zones.
Bit Balling ( Jediurr.)
Bit balling has occurred in the area. In the Argo well, the problem should be mitigated with use
of Nut plug and detergent sweeps which are sometimes effective in reducing clay balling effect.
The addition of SAPP down the drill pipe on connections can also help alleviate this problem.
Well Proximity Risks (
The closest wellbore to the Argo (M-02) well is Mustang #1 (M-01) and North Tarn #1A which is
located approximately 180 feet away at surface. Directional anti -collision simulation indicates
there is no anticipated interference expected between wellbores.
15
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
LOT/FIT
Argo Drilling Program
SMU M-03
PROCEDURE
16
150409 SMU M-04 Well Plan Rev 1
Argo Drilling Program
Brooks Range Petroleum SMU M-04
SMU M-02 LOT/FIT Procedure
1. Drill out the shoe track and clean out any rat hole from the previous hole section below the shoe.
From this depth, drill an additional 20 ft (minimum) to 50 ft (maximum) of new hole.
2. Circulate the wellbore clean and ensure MW in = MW out. Record this value. Line up one mud pump
on the kill line. Isolate the other pump(s).
3. Turn on the pump to flood the kill line and to ensure the hole is full and that no air is present in the
circulating system.
4. While pumping, ensure that the pump pressure gauge and the gauge on the chart recorder are
reading the same pressure.
5. Shut down the pump, position a tool joint at the rig floor and close the upper pipe rams.
6. Bring the mud pump on line slowly at % - %: bbl per minute and watch for pressure to start increasing.
CAUTIOUSLY look down the hole to verify no fluid is leaking past the closed pipe rams. Record the
pressure from the chart recorder vs strokes pumped every 2 or 3 strokes pumped. The pressure
should increase in a linear fashion vs strokes (Volume) pumped.
7. To perform a LOT (Leak -off Test), continue pumping and recording pressure vs strokes until the
pressure deviates from a straight line trend. Obtain one or two additional readings to confirm this
deviation from linearity.
8. Shut down the pump and continue to record pressure vs time, initially every 30 seconds for 2 minutes
and then every minute for an additional 8 minutes.
9. Plot the points for the pressure build up vs volume pumped on one chart and the pressure drop vs
time on a second chart.
10. By looking at the chart of pressure vs volume pumped, the leak -off pressure is the point at which the
curve deviates from a straight line trend.
11. Use the formula: Leak off (MW equiv) = MW + LO Pressure/(Shoe TVDx.052)
12. The FIT follows the same operational steps as previously described, except that the pressure is
increased to a pre -determined value previously calculated, where the plot of pressure vs volume
pumped does not deviate from a straight line. Using the same formula, the FIT value is obtained. If
however, deviation from a straight line does occur, do not keep pumping. The leak off pressure has
been reached and additional pumping may cause the formation to break down.
13. The final step is to bleed off the pressure from the test and measure the volume of fluid returned to a
small pit such as the trip tank or small pill pit. Depending on well design and depth, this volume bled
back could be small — maybe no more than 1 bbl.
17
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
MA P Casing
Design
Verification
Calculations
18
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Brooks Range Petroleum Corporation
Maximum Anticipated Pressure Calculations
Argo SMU M-04
Maximum Anticipated Surface Pressure (MASP):
Argo Drilling Program
SMU M-04
I
C���
Ce
12.25" Hole Section Tv -
This hole section will be drilled with a diverter only, no BOPE. While MASP will equal the formation pore
pressure at the surface casing shoe depth of 2,400' TVDss less a gas gradient to the surface, it cannot be shut
in, only diverted.
Offset well information indicates that the pore pressure at 2,400' TVDss will be a maximum of 9.5 ppg (0.494
psi/ft).
Calculation for MASP (12.25" hole) _ (2,400') x (0.494-0.10) = 946 psi.
8.75" Hole Section
The MASP for 8.75" hole section will be the formation pore pressure (less a full gas column to the surface) at
7,343' MD/ 5,940' TVDss
Offset well information indicates that pore pressure at 5,940' TVDss will be a maximum of 10.4 ppg (0.541
psi/ft).
Calculation for MASP (8.75" hole) _ (5,940') x (0.541-0.10) = 2,618 psi.
6.125" Hole Section
The MASP for the 6.125" hole section will be the formation pore pressure (less a full gas column to the
surface) at 12,082' MD/ 6,100' TVDss.
Offset well information indicates that pore pressure at 6,100' TVD will be a maximum of 12 ppg (0.624 psi/ft).
Calculation for MASP (6.125" hole) _ (6,100') x (0.624 - 0.10 =�3,1�96psi--'
With MASP in the 6.125" open hole section calculated to be 3,196 psi, the 5,000 psi BOPE system to be used
will be adequate.
Casing Design Verification:
Planned Casing program:
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
9.625"
7"
Surface Casing
Intermediate Casing
Depth (MD)
2,606'
7,343'
Depth (TVDss)
2,400'
5,940'
Hole size
12.25
8.75
Weight (ppf)
40
26
Grade
L-80
L-80
Connection
BTC
BTC-M
Nominal ID (in)
8.75
6.276
API Casing Design Factors
Design factors are essentially "safety factors" that allow the design of safe, reliable casing strings. Each
operator may have his own set of design factors based on his experience and the condition of the pipe. Here
we use operator's recommended design factors.
Design Factors:
Tensile Joint Strength:
Collapse (from external pressure):
Burst (from internal pressure):
Nt = 1.8 SF
Nc= 1.125 SF
Ni=1.25SF
The pore pressures and fracture gradients used here are those derived from studies of offsetting well North
Tarn 1, KRU 2L-03 and 2M-36.
Brooks Range Petroleum
Casing Design Factor Calculations:
Burst Requirements
Argo Drilling Program
SMU M-04
Use maximum anticipated surface pressures (MASP) for each casing string. For each casing string MASP is the
formation pressure at the next casing point less a gas column to surface.
9.625", 40#, L-80, BTC Surface Casing:
MASP at 8.75" hole section TVDss of 5,940':
MASP = (5,940') x ((9.5 ppg x 0.052)-0.10 psi/ft) = 946 psi (burst stress)
DFB ,St = burst strength / burst stress = 5,750 psi / 946 psi = 2.23 vs minimum SF of 1.25.
7", 26#, L-80, BTC-M Intermediate Casing:
MASP at 6.125" hole section TVDss of 6,100':
MASP = (6,100') ((10.4 ppg x 0.052)-0.10psi/ft) = 2,618 psi (burst stress)
DFBurst = burst strength / burst stress = 7,250 psi / 2,618 psi = 2.31 vs minimum SF of 1.25.
Argo Drilling Program
Brooks Range Petroleum
SMU M-04
Collapse Requirements
Use an external pressure consisting of the formation pore pressure at the casing shoe and an internal pressure
of a gas column to surface.
9.625", 40#, L-80, BTC Surface Casing:
External pore pressure = 9.5 x 0.052 x 2,400' = 1,186 psi
Internal pressure w/gas only = 0.10 x 2,400' = 240 psi
Collapse stress = 1,186 psi - 240 psi = 946 psi.
DFcoilapse = collapse rating / collapse stress = 3,090 / 946 = 3.27 vs minimum SF of 1.125.
7", 26#, L-80, BTC-M Intermediate Casing:
External pore pressure
Internal pressure w/gas only
= 10.4 x 0.052 x 5,940'= 3,212 psi
= 0.10 x 5,940' = 594 psi
Collapse stress = 3,212 psi — 594 psi = 2,618 psi
DFcoiiapse = collapse rating/collapse stress = 5,410 psi/ 2,618 psi = 2.07 vs minimum SF of 1.125.
Brooks Range Petroleum
Axial Requirements
9.625", 40#, L-80, BTC Surface Casing:
Weight in air = 2,606' x 40 Ib/ft
Pipe weight in mud = Pipe wt (in air) x Buoyancy Factor (BF)
BF for 9.6 ppg mud = (65.5-9.6)/ 65.5
Pipe weight in mud = 104,240 lbs x 0.8534
= 104,240 lbs.
= 0.8534
= 88,962 lbs.
Argo Drilling Program
SMU M-04
DFAx;ai = body tensile strength / buoyed wt. = 916,000 lbs. / 88,962 lbs. = 10.30 vs minimum SF of 1.8.
7", 26#, L-80, BTC-M Intermediate Casing:
Weight in air = 7,343' x 26 Ib/ft
= 190,918 lbs.
Pipe weight in mud = Pipe wt. (in air) x Buoyancy Factor (BF)
BF for 10.7 ppg mud = (65.5-10.7) / 65.5 = 0.8366"�
Pipe weight in fluid = 190,918 Ibs. x 0.8366 = 159,730 lbs.
DFAx;ai = joint tensile strength / buoyed wt = 604,000 Ibs. / 159,730 Ibs. = 3.78 vs minimum SF of 1.8.
Brooks Range Petroleum
Axial Requirements
Weight in air = 2,606'\� 40 Ib/ft
Argo Drilling Program
SMU M-04
/ Ia , I--( c
lbs.
Pipe weight in mud = Pipe t (in air) x Buoyancy Factor/(BF)BF for 9.6 ppg mud = (65.5-9. / 65.5 0.8534
Pipe weight in mud = 0.494 Ibs 0.8534 88,962 lbs.DFAxial =body tensile strength/ bu edwt.=916,000Ibs. = 10.30 vs minimum SF of
1.8.
Weight in air = 7,343' x 26 Ib/ft
Pipe weight in mud = Pipe wt. (in air) x Bu yancy\Ibs.
BF for 10.7 ppg mud = (65.5-10.7) / 65.5
Pipe weight in fluid = 190,918 lbs. x 0. 66
DFAxial = joint tensile strength / buo ed wt = 604,
= 190,918 lbs.
= 0.83
= 159,730 lbs.
,730 Ibs. = 3.78 vs minimum SF
of 1.8.
a
23
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum Argo Drilling Program
SMU M-04
remoperational
Procedures
24
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
Pre -rig operations:
1. Ensure regulatory compliance training is complete and key personnel are fully aware of responsibilities.
2. Make sure that the Alaska Clean Seas technician is available at all times.
3. Notify AOGCC of the start of operations and rig inspection for the Argo (M-03) well and post drilling
permit and drilling hazards in dog house. Post well sign on rig.
4. Drill 48" hole, install 20" x 34" insulated conductor and pour arctic concrete on the outside of the
conductor. Install 8' wide by 5' deep cellar on pad. Conductor and cellar tops to be positioned according
to diverter space out schematic. Bottom of cellar will be cemented. Install two 4" threaded outlets with
plugs below landing ring for taking cement returns and washing out diverter. Install FMC 20" SOW x
19.995" Slick -Neck with 18.75" DIA Bowl, Alloy landing ring. Company man and Nabors tool pusher will
verify 20" cut off height.
5. Diverter riser assembly should be made to length according to diverter line direction through sub base.
Drilling flowline riser above 21-1/4" annular riser should also be pre -fabricated to correct length
according to diverter space out schematic. Pre -assemble diverter spool, annular and flowline riser for
installation in one piece. Outlet flowline connected to the FMC riser 16" outlet to be minimum of 100
feet of 16", 0.375" wall thickness with hydraulic knife valve off of riser.
Ensure clearly marked "ON DIVERTER — Warning Zone" signs are on location and ready to position (On
each side and ahead of the vent line tip) once the rig has moved in and rigged up.
6. Control heat in cellar area to keep area cool to minimize thawing. Keep cellar pumped out at all times.
7. Ensure Baker-Lok is on location.
8. Casing pup joints should be made at Baker's machine shop in Deadhorse for the casing hanger
installation. Two 9-5/8" 40# L-80 buttress and two 7" 26# L-80 buttress pups 3-4 feet long will be
required. Two each 9-5/8" & 7" landing joints should be made at lengths according to the space out
plan for landing the 9-5/8" & 7" casing strings. Landing joint drawings provided by FMC.
9. Class II cuttings and liquid mud waste will be hauled to BP's Grind & Inject facility at DS 4. Class I waste
that has not been downhole may have to go to BP's Pad 3 facility. This plant is always busy and wait
times are long. Disposal at CPAI's 1B pad may be available, confirm with drilling manager prior to
releasing any shipments. Try to minimize generation of Class I waste whenever possible, and consider
beneficial re -use of these wastes, when possible. Additional cuttings storage tanks (Shale Bins) should
be available on location to avoid interruptions in drilling of surface hole.
10. Conduct specific tour safety meetings with each crew on the potential of gas hydrates or shallow gas
and the handling of same.
11. Ensure that Alaska Clean Seas technician is available at all times.
12. Have mud loggers rigged up prior to spud. Gas readings will be monitored constantly for presence of
hydrates or shallow gas. H2S gas is not expected. All depths will be measured from RKB. After ground
level elevation has been determined and RKB to ground level measured, all elevations including ground
level, (ice level, ice thickness under sub base if applicable) and should be recorded on morning reports
and the IADC report. Once the BOP stack is installed, a drawing showing RKB to each preventer and
wellhead equipment should be constructed and placed in the rig floor doghouse and Co Rep &
Toolpusher offices.
13. Strap drill pipe in the derrick and pick up 500' of 5" HWDP.
25
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
14. Notify AOGCC of intent to spud and plans to perform diverter function test and drills.
15. Install 6" liners in both rig pumps prior to spud. See BHA hydraulics for nozzle sizes and optimum
circulation rates.
16. Use nylon rabbit (8.75" OD special drift) to drift all 9-5/8", 40# casing including landing joints, casing
mandrel hangers and pup joints.
17. Cementers should catch surface water samples and begin running surface casing cement tests.
Cementers should be alerted as to spud time and given as much advance notice as possible to deliver
cement & cementing equipment to location. Will need 600+ bbls heated water (70-80 deg) for cement
jobs. Get from hot water plant in Prudhoe. (Will need two uprights or tiger tanks).
18. Contact TAM port collar representative to ensure the port collar and shifting tool will be on location,
and a person available for a second stage cement job on surface casing, if needed.
19. Inventory all pipe, drill pipe, HW drill pipe, drill collars, cross -over subs and pups on location and post
the joint count in the rig floor dog house, tool pusher & company man office.
20. Ensure that pipe rams are available for the following pipe sizes: 9-5/8" & 7" casing, 5" & 4" DP, 4-1/2"
liner and 3-1/2" tubing. Use VBR's when available.
21. Call FMC technician and GBR to install 20" landing ring and a diverter connector.
KR
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Detailed
Argo Drilling Program
SMU M-04
Operational
Drilling
Procedures
27
150409 SMU M-04 Well Plan Rev 1
/ 11P
Brooks Range Petroleum
Drill 12-1/4" Surface Hole
Argo Drilling Program
SMU M-04
Objective: The main objective of the surface hole is to drill the section efficiently and safely, to case
off the permafrost and unconsolidated formations below the permafrost and cement the 9-5/8"
surface casing to surface.
Logging Requirements: MWD / GR / Res '
Surface Drill Pipe
Joint
Body
DP
Tensile
Pipe
WT
Grade
Conn.
TJ OD
TJ ID
ID
MU TQ
Torsional
Torsional
capacity
Capacity
(ppf)
type
(in)
(in)
(in)
(ft.lbs)
Yield
Yield
w/conn.
(kips)
(ft Ibs)
(ft.lbs)
(gal / ft)
5" DP
19.5
S-135
NC50
6.625
3.25
4.276
26,800
51,700
58,100
.726
560.8
Surface Mud Properties
M
MD
ht
Viscosity
PV
YP
API FL
pH
0'- B/ Permafrost
8.8-9.1
220-300
20-45
45-70
8-15
9 — 9.5
B/ Permafrost —
9.4
200-250
20-45
45-70
<10
9 -9.5
Surface TD
Prior to cement
9.6+
1 80-100
1 12-25
1 20-25
Surface Section Procedure:
1. Install 21-1/4"x 2000 psi diverter with 16" outlet line as described in pre -rig operations. Function test
the diverter to verify the valve on the diverter line opens BEFORE the annular fully closes. The diverter
control system must open the side outlet valve and close the diverter element within 45 seconds for
this size of diverter. Give AOGCC 48 hour notice to witness test. Fill diverter & riser with water to check
for leaks. Record on IADC drilling report. Hold diverter and rig abandonment drill prior to drilling surface
hole.
2. Make sure the 4" outlets on the 20" conductor have valves and connections for taking mud returns.
Diverter lines to be as straight as possible. Ensure "Warning Zone - ON DIVERTER" signs and the rig well
sign are spotted correctly on location.
3. Spud mud will be mixed and hauled from the mud plant in Deadhorse per mud engineer and mud
program.
4. Dress drill bit. MU 12-1/4" BHA.
➢ Hughes VMD-3
➢ 1-16, 3-18's (.964 TFA)
5. Ensure mud loggers are fully rigged up and ready to go.
O
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
6. Spud well with reduced drilling parameters. Gradually increase drilling parameters when the BHA is
below the conductor shoe.
7. Drill 12-1/4" hole vertically to 500' per the directional plan and mud plan. Controlling ROP may be
necessary to prevent packing off, lost circulation or flow over the top of the bell nipple, especially when
sliding. Drill to section TD at 2,606' MD/ 2,508' TVD. Hold flow rates at +650 gpm as directional will
allow.
8. Actual TD will be based on LWD data. Attempt to place the casing shoe in a minimum 50' shale section,
if possible. The geologist will assist in picking casing shoe depth. Adjust TD as required for space out, to
leave up to 5-10' rathole depending casing strap for landing FMC 9-5/8" casing fluted mandrel type
casing hanger. Drift hanger and pup joint to 8.75". Attempt to drill hole to fit the casing to reduce the
number of pups required.
9. Pump a marker high-vis sweep at TD and note surface to surface strokes as an indication of washouts.
Make calculations of average hole size and consider adjusting excess cement volumes based on results,
if necessary.
10. Circulate the hole clean as per HXR
➢ Backream one (1) stand per bottoms up very slowly
• 80 GPM or greater
• 80 RPM or greater
11. Once the shakers have cleaned up Backream to the HWDP
12. Lay down the 12-1/4" BHA and download all memory data from MWD/LWD tools.
29
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Run 9-5%8" Surface Casing:
Argo Drilling Program
SMU M-04
Objective: is to run 9-518" casing to the required depth of 2, 753' MD and to cement the casing back
to surface in one stage.
Surface Casing Program
OD
WT
Grade
Conn.
Conn. OD
ID (in)
Drift (in)
Collapse
Burst
Tensile Yield
(in)
(ppf)
Type
(in)
(psi)
(psi)
(kips)
9-5/8
40
L-80
I BTC-M
10.625
8.835
8.75
3,090
5,750
916
Running Method
Conventional — Volant CRT
Surface Casing Connection Make Up Torque (ft-lbs.)
OD
WT
Opt.
(in)
(ppf)
Grade
Conn. Type
Make Up
Torque
9-5/8
40
L-80
BTC
"Triangle
"Torque values for the BTC casing are determined at the rig by making up the connection to the
make-up mark (base of triangle). Record torque values for the first 10 connections made up in this
manner and average. This average will be used as the make up torque for the remainder of the string.
Casing Running Notes
a. Perform dummy run prior to running casing
b. Surface casing will be landed on hanger, emergency casing slips will be used as contingency.
c. Rig up and utilize Volant CRT for the casing job.
d. Break circulation before reaching the base of the permafrost if casing run indicates poor hole
conditions.
e. Any packing off while running casing, and especially while above the base permafrost, should be
treated as a very serious problem if major returns are lost. It is preferable to pull casing out until
circulation can be re-established rather than risk not getting cement to surface. Contact the
Drilling Superintendent if the casing packs off high for discussion of the options.
f. Have FMC representative verify the correct casing hanger is on location prior to the point at which
it is needed.
30
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Running Procedure
Argo Drilling Program
SMU M-04
1. Inspect and DRIFT all Surface Casing to 8.75".
2. Break circulation before reaching the base of the permafrost if casing indicates poor hole conditions.
3. While running in the hole with the casing:
Obtain SO Weights as per HXR
4. MU shoe track and verify that floats are holding.
Surface Casing Running Order
1
Float shoe
Bakerlock
2
2 joints 9-5/8" 40# L-80 BTC casing
Bakerlock
3
Float Collar
Bakerlock
4
9-5/8" 40# L-80 BTC casing
5
**TAM BTC port collar +/- 500 ft
6
9-5/8" 40# L-80 BTC casing to hanger
7
FMC 9-5/8" mandrel hanger
8
9-5/8" landing joint
Slick landing joint if not running the TAM port collar
**If TAM port collar is run:
• A landing joint, which has a connection that can be broken below the rotary table, will need to be run to
allow for running the drill pipe inside the 9-5/8" without needing a false rotary table. Also, the drill pipe
running tool needs to be on location and stood back in the derrick ready to run in case the TAM port collar
needs to be opened to circulate cement to surface.
• If decision to run is at the last minute, ensure the additional footage of the port collar plus handling pup will
allow for sufficient rathole below the surface casing shoe.
Surface Centralizers
+/- 18 9-5/8" x 12-1/4" Bow Spring Halliburton
31
150409 SMU M-04 Well Plan Rev 1
/'Sl�
Brooks Range Petroleum
9-5/8" x 12-1/4" Bow 5arine Centralizers
• 2 at 5' & 8' above float shoe on stop collars, using stop
collars.
• No centralization on collar of 15Y joint
• 1 at 10' above the Float Collar, using stop collars
• From 3rd joint through the tail slurry (500'), 1 centralizer
per joint
• 2 on casing inside conductor
150409 SMU M-04 Well Plan Rev 1
Argo Drilling Program
SMU M-04
63
32
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
Cement 9-5/8" Surface Casing:
Surface Cementing Program
Section
Casing Size
Type of Fluid / Cmt
Volume
Properties
Lead Slurry
376 bbls
Density 10.7 ppg
(Permafrost L)
-
Yield 4.03 ft3/sk
Tail Slurry
Surface
9-5/8" 40# L80 BTC
(SwiftCem)
49 bbls
Density 15.8 ppg
Top of Tail @ 2,078' MD
-> ;2.; 5K
Yield 1.18 ft3/sk
Surface Cementing Notes
a. Obtain and review the Test Report from the cementing lab on the job blend prior to pumping the
cement. DO NOT pump cement if there are any doubts as to cement quality, quantities, pumping
times, or thickening times.
b. Use split landing joint if TAM port collar is utilized. It will need to be opened by running tool on
drill pipe and this will allow using standard rotary slips.
c. Ensure that enough cement retarder is built to keep cement from setting up prior to pumping
down disposal well.
d. Cementers should catch surface water samples and run surface casing cement tests.
e. Cementers should be alerted as to spud time and given as much advance notice as possible to
deliver cement & cementing equipment to location.
f. Will need 350+ bbls heated water (70-80 deg) for cement jobs. Get from hot water plant in
Prudhoe.
g. Ensure TIW valve or 2" Lo Torq valve with swage to 9-5/8" BTC is on the rig floor.
Surface Cementing Procedure
1. After reaching bottom, rig up and circulate with casing on bottom at 6-8 bpm, if possible, without losing
returns. Reduce mud viscosity prior to pumping cement if necessary.
➢ To help ensure good cement to surface after running the casing, and if practical for existing hole
conditions, condition mud to YP < 20 Ib/100ft2 prior to cementing the casing but after the casing is
on bottom. Have adequate supply of cold lake water on hand to ensure the desired rheologies can
be achieved.
2. Rig up to cement and pressure test cement lines.
3. Pump Mud Push Spacer. Shut down and drop bottom plug.
4. Pump cementjob per the attached Schlumberger cementing plan. Cement volumes are based on 50%
excess below the Permafrost and 300% excess in the Permafrost.
➢ If necessary, verify that the TAM Tech has located the proper crossovers to combo running tool.
➢ If necessary, rack TAM running tool in derrick and ready to run.
5. Report the number of bbls of cement returned to surface:
➢ Task one person to be in charge of monitoring for cement returns and volume of cement returns
33
150409 SMU M-04 Well Plan Rev 1
t/
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
➢ Recommend that a dye or small amount of celloflake be added to the wash or spacer to give an
indication of top of cement.
6. Drop top plug after the tail slurry.
7. Pump displacement at 8.5 bpm maximum.
8. Drop circulation rate 3 BPM for last 20 bbls of displacement prior to bumping plug.
9. Pump until the plug bumps and then pressure up to 500 psi above Final Circulating Pressure (FCP) to
ensure the plug has landed. If floats do not hold, maintain FCP on casing and shut in cement head for
a minimum of 6 hours before rechecking.
➢ Do not over displace the cement (Pump NO MORE than % the shoe joint volume).
➢ Watch for signs of packing -off during pumping operations and closely monitor the cellar area for
mud or cement returns around the conductor.
➢ In the event cement is not circulated to surface, pump the calculated volumes and prepare to
open the TAM Port Collar (if applicable) for a secondary cement job.
➢ AOGCC and Drilling Superintendent must be contacted prior to beginning top job. Do not
proceed with top job without AOGCC approval.
10. Drain and wash cement from riser. Nipple down riser and flush all lines.
11. Nipple up FMC wellhead, orienting the well head valves as indicated on the conductor markings.
➢ If there is any doubt about the proper orientation, call the Drilling Superintendent.
➢ Ensure that the seal between the casing hanger and well head is tested to 5,000 psi for 10 minutes.
➢ Measure the distance from the rig floor to the top flange of the well head and record on the IADC
report and in Openwells. Complete the Rig Elevation Record and place it in the electronic well
folder.
12. Nipple up the 13-5/8" 5K BOP stack and test per the AOGCC Permit to Drill
0 13-5/8"x 5K Hydril GK Annular preventer
0 13-5/8"x 5K Pipe Rams-3-1/2" x 6" -VBR's
0 13-5/8"x 5K Blind Shear Rams
o Mud Cross with 3" choke line and 2" kill line with 1 manual gate and 1 HCR gate valve on
each outlet
0 13-5/8" x 5K Pipe Rams-2-7/8" x 5" —VBR's
➢ Test rams and choke manifold components to 4000 psi high / 250 psi low
➢ Test annular preventer to 2500 psi high / 250 psi low
➢ Do not test BOPE against casing.
➢ Notify AOGCC 24 hours prior to performing BOP test.
■ PERMIT TO DRILL BOP testing frequency: 14 DAYS as Notified by AOGCC
34
150409 SMU M-04 Well Plan Rev 1
Argo Drilling Program
Brooks Range Petroleum SMU M-04
Drill 8-3/4" Intermediate Hole
Objective: The main objectives of the 8-314" intermediate hole are to efficiently and safely drill below the
Kalubik K-1 geologic marker and land the well 10' TVD above the Kuparuk C sand. Set 7" and adequately
cement the casing string to meet the criteria for a production well, a minimum of 500' above the Kuparuk
Sand.
Logging requirements: GR J Res /PWD.
Intermediate Drill Pipe
Joint
Body
DP
Pipe
p
WT
Grade
Conn.
Ti OD
TJ ID
ID
MU TQ
Torsional
Torsional
capacity
Tensile
(ppf)
type
(in)
(in)
(in)
(ft.lbs)
Yield
Yield
w/conn.
Capacity
(ft lbs)
(ft.lbs)
(gal / ft)
(kips)
5" DP
19.5
S-135
NC50
6.625
3.25
4.276
26,800
51,700
58,100
.726
560.8
Intermediate Mud properties:
Mud
MD
Weight
116/3
PV
yP
pH
HPHT FL
2,606' — 500' MD t HRZ
9.7 — 10
18/17
8-20
15-35
9.5 -10
<6
500' MD '(` HRZ — TD
10.7
18/17
8-20
15-35
9.5 -10
<6
1, Dress 8-3/4" bit. MU 8-3/4" RSS BHA and test.
2. RIH and tag up on cement inside 9-5/8" casing. Circulate and condition mud. Test casing to 3,000 psi,
making sure to chart the test. Displace to new weighted 9.7 ppg mud. Drill shoe track and 20' of new
formation below the previous rat hole.
3. Perform LOT. Expect a LOT value in excess of 15.0 ppg based on Mustang #1 FIT. Record the results on
the Morning Report and in the IADC report. If a minimum LOT/FIT pressure of 12.7 ppg_is not achieved
consult with drilling superintendent prior to drilling ahead.
4. Circulate and establish baseline parameters for clean hole ECD with planned mud weight, pump rate,
and rotary speed. Parameters should also include on and off bottom torque, on and off bottom
circulating pressure, and pickup, slack off, rotating weights and Slow Pump Rates.
5. Drill ahead in 8-3/4" hole with MWD/LWD/PWD tools. Proper hole cleaning is a major factor in
successfully drilling this hole section and running casing to bottom without problems.
• DO NOT EXCEED 12.3 ppg ECD, if this value is being approached contact Drilling Manager
and Drilling Engineer to determine acceptable way forward.
6. Weight up to 10.7 ppg with treated spike fluid 500' prior to penetrating the HRZ Shale
7. Do not weight up on the fly. Consider a short wiper trip while circulating hole clean and weighting up.
Note: The K-10 Campanian sands, 2,550' TVD, are known for potential gas kicks in this area. Have a minimum
mud weight of 9.7 ppg prior to drilling out. In the event the K-10 is encountered shallow to any prediction
pay close attention to pit levels well prior to drilling the K-10.
35
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum Argo Drilling Program
SMU M-04
8. Landing Point is 10' TVD above the top of the Kuparuk C Sand.
9. The plan is to drill to TD with one bit. The decision to trip for a bit will be based on the drilling parameters
and ability to follow the directional program.
10. Test BOPE every 14 days. Notify AOGCC at least 48 hours in advance of BOP testing.
11. When trips are required, follow good tripping practices. Monitor hole fill up closely on trips out and
monitor returns in trip tank on trips in hole. Use top drive and circulation when tight spots are
encountered. Approach tight spots with care and work through same by incrementally increasing drilling
parameters.
12. Flow -check all major drilling breaks. After making connections, initiate rotation before bringing up
pumps. Avoid circulating in the same spot for extended periods of time to avoid excessive washout at
one depth. Add lubricants as required to reduce torque and drag.
13. Circulate hole until shakers cleanup per HXR.
14. BROOH taking SLM, stand back 5" drill pipe.
15. PULL THE WEAR BUSHING.
36
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
8-3/4" Intermediate Hole Section Notes and Lessons Learned:
While drilling the SMU M-02 intermediate hole section several issues were encountered. The main issues
encountered through the section are outlined below:
• Faulting
• Losses
• Drilling Parameters
• Directional Control — Landing/ DLS
Faulting
It is suspected that we crossed a fault —82' into the C-40 where losses were encountered at—4,296' TVD.
Upon inspection of the seismic data it is probable that we encountered an area of secondary sub seismic
faulting as the well path crossed in between two known faults. To mitigate losses resulting from faulting
the well path for SMU M-04 has been modified as to not cross any known faults.
Losses
The losses encountered in this section were either a direct relation to faulting or potentially exasperated
due to accidentally pumping spike fluid down hole prior to the planned weight up scheduled depth. Any
pit that includes a high weight fluid must be isolated from inadvertently going downhole prior to being
mixed.
Going forward 60-80 ppb of sized calcium carbonate will be included in the active system to build a
sufficient wall cake immediately and/or serve as LCM in the event that a fault or significant losses are
encountered. Ensure that Form -A -Block is on location is the event that dramatic losses are encountered.
Drilling Parameters
While drilling this section there were no indications of insufficient hole cleaning prior to encountering
losses. That being said, care needs to be taken to not overload the hole with cuttings leading to increased
circulating pressures and possible detrimental effects to the wellbore. Make all attempts to keep
instantaneous ROP 5250 fph to aide in reducing ECD fluctuations while drilling ahead. ESD and ECD shall
be continuously monitored. DO NOT EXCEED 12.3 ppg ECD.
Directional Control — Landing/ DLS
In our attempts to land SMU M-02 the last 2 stands required significant sliding to reach our goals. It is
possible that excessive DLS was introduced into the wellbore at the HRZ/ Kalubik interface causing us to
be unsuccessful in getting our intermediate casing to bottom. This hole section will be drilled with a Xceed
Rotary Steerable BHA which should allow us to drill a much smoother path increasing our chances of
running casing successfully to bottom. Additionally, MLT torque rings and an eccentric nose guide shoe
will be incorporated into the string to allow for rotation in the event that an obstruction is encountered.
37
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
Run 7" Intermediate Casing:
Objective: The objective is to run and adequately cement the 7" casing string leaving cement at least 500'
above the Kuparuk Sand.
Intermediate Casing Program
OD
WT
Grade
Conn.
Conn. OD
ID (in)
Drift (in)
Collapse
Burst
Tensile Yield
(in)
(pp f)
1
Type
(in)
(psi)
(psi)
(kips)
7
26
L-80
I 13TC-M
7.875
6.276
6.151
5,410
7,250
614
Running Method
Conventional — Volant CRT
Intermediate Connection Make Up Torque (ft.lbs)
Opt.
OD
(in)
WT
(ppf)
Grade
Conn. Type
Make Up
Torque
7
26
L-80
BTC-M
21,080
"Torque values for the BTC casing with Torque rings is 21,080 ft-lbs. Ensure PESI hand is on location
to assist in making up the connection to the proper torque limits.
Intermediate Casing Running Notes:
a. Ensure MLT Torque rings are installed in the pipe shed prior to picking casing up.
b. Clean out suction screens on both mud pumps prior to running casing.
c. Ensure crossover from 7" BTC-M to TIW valve or 2" 1502 valve is on rig floor.
d. Drift all casing with 6.151" OD Nylon Drift
e. Ensure stroke counters at drillers console and choke control panel are operating.
f. Have centralizers on rig floor.
Intermediate Casing Running Procedure:
Install 7" casing rams in Top ram cavity. Notify AOGCC of test. Run test plug & close blind rams in
middle BOP, test per AOGCC PTD. AOGCC now wants a test of the rams themselves and not just a
body test —will need 7" test joint. Pull test plug.
Rig up Volant casing running tool. Do not perform the final make-up of casing in high gear. Make up
initially in high and then switch to low for final make up to the diamond, to obtain proper torque
values. Check that each joint is made up to the base of the triangle. Casing has modified connection,
so spare seal rings must be available on location. Always clean the connection thoroughly when
replacing seal ring.
Float equipment will be installed and Baker locked at machine shop. Make sure that all casing float
equipment is installed on the ip n end of casing joints. Drift 7" mandrel type casing hanger and pup
38
150409 SMU M-04 Well Plan Rev 1
Argo Drilling Program
Brooks Range Petroleum
SMU M-04
with 6.151" OD nylon drift. All 7" casing should be drifted with a nylon rabbit prior to running.
Company Rep to confirm casing joint count in pipe shed prior to starting to run casing.
4. Confirm that the hanger running tool and the pup joint on the bottom of the hanger have been pre -
torqued in shop. Reference the Wellhead tech and operation manual for details on the hanger
system. Install a stack centralizer on the landing joint to prevent the hanger from hanging up in a
cavity while reciprocating the casing. Emergency slips are provided by FMC for this wellhead system
if the casing gets stuck off bottom and the mandrel hanger can't be landed.
5. Make up mandrel hanger to landing joint and conduct a "Dummy Run".
6. Run 7" casing as follows:
1
Silver Bullet — Eccentric Nose Guide Shoe
Baker-Lok
2
2 joints 7" 26# L-80 BTC-M casing
Baker-Lok
3
Float Collar
Baker-Lok
4
7" 26# L-80 BTC-M casing
5
7" landingjoint
+/- 38 1 7" x 8-1/2" Centek Centralizers (Floating) Halliburton
7. Fill every joint with fill up tool. Monitor mud returns closely.
8. While running in the hole with the casing:
➢ Obtain SO Weights per HXR
9. Break circulation at the 9-5/8" surface casing shoe and circulate a minimum of one casing plus
annulus volume of mud to ensure pipe is clear.
10. Continue running casing in to open hole, filling each joint through the Volant tool. Break circulation
slowly about half way in to the open hole section. Stage pump up to —6 bpm over a 10 minute
period and CBU while slowly reciprocating pipe to break gels and condition mud. Watch for losses
and adjust flow rate accordingly. Continue running casing to bottom.
11. MU 7" mandrel hanger and landingjoint per FMC representative. Break circulation slowly and work
up to -6 bpm. Watch for losses, as before. Run hanger through the table and land the casing in the
wellhead at the correct depth as previously measured on dummy run.
12. With casing landed, install the cement head and circulate and condition mud. Reduce the YP and PV
per mud program. Break circulation slowly and increase pump rate slowly to avoid breaking down
the formation, not exceeding the maximum AV rate used to drill this hole section. If possible,
reciprocate pipe 5'-10' while circulating and cementing.
39
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Intermediate
Centralizer PlacemAnt
7" Centek Centralizers
15t - On stop collar 5' above float shoe
2"d - No centralizer on next joint
3rd - On stop collar 10' above float collar
4th joint to ±1000' above the shoe
o 1 centralizer floated between collars
From Iceberg to ±500' above.
o 1 centralizer floated between collars
150409 SMU M-04 Well Plan Rev 1
Argo Drilling Program
SMU M-04
40
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
Cement 7" Intermediate Casing:
Surface Cementing Program
Section
Casing Size
Type of Fluid / Cmt
Volume
Properties
Surface
7" 26# L80 BTC-M
Tail Slurry
(VariCem)
24 bbls
Density 13.00 ppg
Yield 1.938 ft3/sk
Intermediate Cementing Notes:
a. Cementers should catch surface water samples and run intermediate casing cement tests.
b. Cementers should be alerted as to casing running time and be given as much advance notice as
possible to deliver cement & cementing equipment to location.
c. Will need —100 bbls heated water (70-80 deg) for cementjobs. Get from hot water plant in Prudhoe.
d. Obtain and review the Test Report from cementing lab on the job blend prior to pumping the
cement. DO NOT pump cement if there are any doubts as to cement quality, quantities, pumping
times, or thickening times. If need be, confer with Drilling Superintendent.
e. Do not over displace the cement, no more than %: the shoe joint volume.
Intermediate Cementing Procedure:
1. Perform Rig pump efficiency check and confirm +96% efficiency before pumping and displacing
cement.
2. Ensure Halliburton re -calculates cement volume based on Iceberg Sand actual deaths
➢ Cement volume is based on 50% excess and at least 500' of annular fill above top of the
Kuparuk sand (highest known hydrocarbon bearing zone). Refer to attached cement
detail sheet for volumes.
3. Batch mix cement. Test cement lines and pump cementjob as per Halliburton program.
4. Displace cement with He Pumps and LSND water -based drilling mud.
➢ Ensure that the cement unit and rig pumps are manifolded so there will be redundancy in
case of any pump failure during displacement.
➢ Pump cement at 5 bpm and displace with 8.0 bpm if possible without losing returns. Slow
rate to 3 bpm during last +/- 30 bbls prior to bumping plug.
5. When the plug bumps, pressure the casing to 500 psi over the final displacement pressure and
ensure that the string is holding pressure. Notify the Drilling Superintendent if the string will not
hold pressure. Bleed off pressure and ensure the floats are holding. If the floats leak, pressure
back up to final displacement pressure and shut in cementing head.
6. Close the annular and perform 20 bbl injectivity test with drilling mud down the 9-5/8" x 7"
annulus no later than (4) hours after cement was mixed and started downhole
➢ Ensure injectivity for freeze protect (offset wells have seen cement channel into the
surface casing and prevent freeze protection).
At the completion of the cement job, rig down the cementing equipment; drain the stack. Back
out the landing joint.
41
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
Notify AOGCC of test. Change the upper pipe rams from 7" to 2-7/8" X 5" VBR's. Run test plug &
close blind rams and perform test per AOGCC PTD. Pull test plug.
Install wear bushing. Record all BOP tests on chart and in IADC.
42
150409 SMU M-04 Well Plan Rev 1
Argo Drilling Program
Brooks Range Petroleum SMU M-04
Drill 6-1/8" Production Hole:
Objective: The main objective of the 6-1/9" hole is to efficiently and safely drill the Kuparuk "C" sand and to
maintain circulation and hole stability so that a liner can be run successfully. It is necessary that any fluid
losses to formation be controlled with minimum damage to the formation.
Logging requirements: GR / Res / Neu / Den / MicroScope / PeriScope
Production Drill Pipe
Joint
Body
DP
Pipe
wT
Grade
Conn.
TI OD
V ID
ID
MU TO
Torsional
Torsional
capacity
Tensile
(W)
type
(in)
(in)
(in)
(ft.lbs)
Yield
Yield
w/conn.
Capacity
(ft lbs)
(ft.lbs)
(gal / ft)
(kips)
4" DP*
14.00
S-135
HT38
5.000
2.438
3.340
19,800
33,000
32,800
.440
403.5
Production Mud properties:
Mud Weight
PV
1
Tau 0
R6/3
pH
HPHT FL
12.3
8-10
>6
13/12
9.0-9.5
<6
1. Pick up-12000' of 4" DP.
2. Dress 6-1/8" PDC bit and MU 4-3/4" RSS BHA per directional driller and test.
3. RIH to TOC. Circulate and condition mud. Test casing to 4,000 psi for 30 minutes. Chart the test.
4. Drill shoe track and a minimum of 20' of new formation (but not more than 50').
5. Perform FIT to 15.5 ppg EMW. Minimum acceptable FIT is 13.8 ppg. Record the results. LOT from
Mustang #1 was 16.4 ppg EMW.
6. Continue drilling to a final TD of—12,082' MD/ 6208' TVD, Follow lost circulation decision tree if
losses occur.
7. Circulate and condition mud and hole for running liner. Additions of approved lost circulation
materials or spotting of open hole LCM pills to help strengthen the wellbore and reduce the risk of
losses may be appropriate prior to running the liner.
8. Circulate, pulling one (1) stand per bottoms up until hole cleans up per HXR
9. BROOH to Intermediate Casing Point @ 300 gpm and 120 rpm.
10. Circulate inside 7" casing shoe and ensure the casing is clean.
11. POOH on elevators. LID BHA.
43
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Run 4-1/2" Slotted Liner:
Argo Drilling Program
SMU M-04
Objective: This 4-112"slotted liner will be temporarily produced during the initial flow test. Once production
data has been captured, the well will be secured and suspended to be utilized as a Conventional Horizontal
Producer to support the Mustang field.
Production Liner Program
CsgO/TTbg
Hole Size
Wt/Ft
Grade
Conn.
6-1/8"
4-1/2"
1 12.6
1 L-80
I H521
Production Liner
OD
WT
Conn.
Cplg OD
Collapse
Burst
Tensile Yield
Grade
ID (in)
Drift (in)
(in)
(ppf)
Type
(in)
(psi)
(psi)
(kips)
4-1/2
12.6
L-80
I H521
4.729
3.918
1 3.833
1 7500
8430
288
Production Liner Connection Make Up Torque (ft-Ibs)
OD
WT
Conn.
Min.
Opt.
Max.
Yield
Grade
Make Up
Make Up
Make Up
(in)
(ppfJ
Type
Torque, ft-Ibs
Torque
Torque
Torque
4-1/2
12.6
L-80
H521
3900
6050
6800
15300
Production Liner Centralization
From
To
Centralizers/Joint
Fixed/Floating
Type
Shoe
Linerp
1/joint
Floating between collars
4-1/2" x 5-7/8 Volant
to
H droFORM
Y
Run 4-1/2" liner Running Order
1
Eccentric Nose Guide Shoe
Bakerlock
2
XX joints 4-1/2" Slotted, 12.6#, L80 H521 Slotted Liner
Min 150' Liner Lap
Bakerlock
3
4-1/2" SLZSXP Liner Tip Hanger Packer Assembly
4
4" DP to Surface
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Argo Drilling Program
SMU M-04
Liner Running Notes
a) Ensure VBRs have been tested to 4-1/2" prior to running liner.
b) Do Not run centralizers in or near the liner lap.
c) Use Best-O-Life thread dope or equivalent
d) If needed, apply dope sparingly, so the thread profile is still visible
e) Have XO from DP thread to liner thread made up to a TIW valve on the rig floor
Liner Running Procedure
1. RU Volant casing running tool and run 4-1/2" slotted liner per liner running procedure. Have back
up tools on location in case of equipment failure.
2. RU Volant tool. Pick up the liner and 1 stand of drill pipe. Circulate 1 liner volume.
3. Run in hole with liner.
Obtain SO Weiehts per HXR
4. Slowly and cautiously run 4-1/2" linerto bottom. Minimize surge pressures on the formation caused
by too high a running speed.
5. Specific run speeds to be determined by HXR.
6. At TD get on depth and set ZXP hanger packer assembly as per Baker
7. Pressure test liner lap to 2000 psi for 30 minutes. Chart test.
8. Displace to clean 12.3 ppg completion fluid per program.
9. POH LD 5" DP.
10. RU and prepare to run completion per completion procedure.
Completion:
1. Pull wear bushing.
2. Run 3-1/2" completion per tubing tally
45
150409 SMU M-04 Well Plan Rev 1
Brooks Range Petroleum
Well Overview:
Argo Drilling Program
SMU M-04
Section
Hole
Casing
Wt.
Connection
Mud Type
Mud Weight
Size
Size
Surface
12-1/4"
9-5/8"
40
BTC
Spud Mud
8.8 - 9.6
Intermediate
8-3/4"
7"
26
BTC-M
LSND
9.7 - 10.7
(MLTTQRings)
(ModifiedFloPro)
Production
6-1/8"
4-1/2" SL
12.6
Hydril 521
FloThru
(K+ Formate)
12.3
Tubing
---
3-1/2"
9.3
TC-II
Inhibited Brine
12.3
(K+ Formate)
Test Pressure
LOT/FIT
Casing
Test
Section
Low
High
Min
Expected
Test
Pressure
Chart Time
Diverter
250
2500
BOP
250
4000
Tree
5000
Surface
12.7
15+
3000
30
Intermediate
13.8
15+
4000
30
Liner Lap
2000
30
Tubing
3500
30
MITA
1
4000
30
46
150409 SMU M-04 Well Plan Rev 1
/NIOAN
Brooks Range Petroleum
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NoGo Region Anti -Collision rule used: Minor Risk - Separatlon Factor
280
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TRAVELING CYLINDER PLOT
Client
SMU
Field
Structure
Mustang Pad
Well
Plan (E) SMU M-04
Borehole
Plan SMU M-04
Date
19-Nov-2014
90
00
/A-I�AN
Brooks Range Petroleum
*See Attached Drilling Program
Brooks Range Petroleum Corp. - AOGCC 10-401 Attachments
/NIIOAN
Brooks Range Petroleum
Brooks Range Petroleum Corp. - AOGCC 10-401 Attachments
/*111111*�
Brooks Range Petroleum
Increased Pore Pressure in Kuparuk (High)
The closest offset wells Mustang #1 (M-01) and North Tarn 1A had lost circulation and a kick. It
is believed that high mud weight of 12.5 ppg used to drill the production hole through the
Kuparuk "C" led to fracture and losses in the Kuparuk "A". Subsequently, a kick was taken and
circulated out with 11.8 ppg mud weight. The formation evaluation data from the N Tarn-1A
well shows that the reservoir pressure of Kuparuk "C" is —12.0 ppg and the Kuparuk "A" has
10.4 ppg pressure resulting from the injection activities on neighboring pads and depletion due
to production. Mud weight planned for the production section is 12.2 ppg+ and should provide
a sufficient overbalance across the producing intervals. Mud loggers will monitor pit levels,
background gas and other indicators of increasing pore pressure. Flow checks will be performed
on connections and the well will be monitored during trips to ensure proper fill up and to
minimize swabbing.
Lost Returns (
A risk of losses will be present during drilling the Lipizzan 1 (SMU M-02). The Kuparuk formation
is known to be highly fractured in places. The mud density and rheology will be maintained
according to the mud program. The PWD tool will be used to monitor real-time ECDs close to
the bit and to help identify losses at the earlier stages. Pit levels should be monitored at all
times and tripping speeds will be controlled to reduce surge & swab values. A contingency lost
circulation plan (LCM decision tree) will be utilized to control losses.
Gas Hydrates (
Experience in Tarn area shows that this area has hydrates. The mitigation is to drill the
permafrost section quickly and get surface casing set without delays. The section will need to
be drilled with MW of 9.3 ppg+ to overbalance the gas sands. There is commonly a thin tarry
sand at the 'K-10' level, about 2590' TVD; it is equivalent to the Tabasco sands but being thin
(to non-existent in places) and tarry, it has not shown commercial potential in this area (yet).
Minimum mud weight pre- K-10 sands is 9.8 ppg. In addition, pre -treating mud with Lecithin
and Screen Kleen, known to prevent gas hydrate destabilization. Lecithin and Screen Kleen will
be used in the surface mud system.
Shale Instability (
Known instability issues in this area are associated with drilling the HRZ shales. Mitigation
includes use of "shale inhibitors" (Resinex, Soltex) to coat potentially unstable zones and help
maintain a low fluid loss. Minimizing directional changes through the shales and increasing mud
density at the first sign of shale instability. According to the HRZ shale stability study and based
on the hole inclination and the azimuth, the mud weight required for drilling the HRZ shales in
the Lipizzan intermediate hole should be in a range of 10.4 - 10.7 ppg.
Brooks Range Petroleum Corp. - AOGCC 10-401 Attachments
Brooks Range Petroleum
Hole Cleaning (
In the surface interval, borehole cleaning issues may arise while drilling through the permafrost
due to the presence of loose gravel and boulders. A few mitigation measures can be used: drill
as fast as practical, do not leave the hole open for a long time, keep the mud cold and viscous.
In the intermediate interval maintain fast drilling, practice short trips every 24 hours or
1000'MD, whichever comes first, minimize static times and run the casing as soon as practical
after the borehole is drilled. Plotting torque and drag daily will indicate problematic trends.
Record torque and pick-up, rotating, and slack off weights on every connection.
Stuck Pipe due to Borehole Packoff ( 'lediun )
Borehole packoff can occur due to conglomerate drilling and/or improper hole cleaning.
Monitor cuttings loading in the annulus and control drill and/or circulate out to clean hole and
lower ECD. The use of a PWD tool will help in identifying potential hole cleaning issues in real
time.
Stuck Pipe due to Differential Sticking (
Differential sticking occurs when BHA is across permeable sands. Pipe movement (reciprocation
and/or rotation) at all times helps to prevent sticking. Stabilizer placement should be optimized.
The risk of differential sticking in the Lipizzan well exists; due to the section requirement to drill
with—10.4-10.6 ppg mud, which gives overbalance across normally pressured permeable zones.
Bit Balling (
Bit balling has occurred in the area. In the Lipizzan well, the problem should be mitigated with
use of Nut plug and detergent sweeps which are sometimes effective in reducing clay balling
effect. The addition of SAPP down the drill pipe on connections can also help alleviate this
problem.
Well Proximity Risks (
The closest wellbore to the Lipizzan (M-02) well is Mustang #1 (M-01) and North Tarn #1A
which is located approximately 180 feet away at surface. Directional anti -collision simulation
indicates there is no anticipated interference expected between wellbores.
Brooks Range Petroleum Corp. - AOGCC 10-401 Attachments
Brooks Range Petroleum
Brooks Range Petroleum
LOT/FIT Procedure
1. Drill out the shoe track and clean out any rat hole from the previous hole section below the
shoe. From this depth, drill an additional 20 ft (minimum) to 50 ft (maximum) of new hole.
2. Circulate the wellbore clean and ensure MW in = MW out. Record this value. Line up one
mud pump on the kill line. Isolate the other pump(s).
3. Turn on the pump to flood the kill line and to ensure the hole is full and that no air is present
in the circulating system.
4. While pumping, ensure that the pump pressure gauge and the gauge on the chart recorder
are reading the same pressure.
5. Shut down the pump, position a tool joint at the rig floor and close the upper pipe rams.
6. Bring the mud pump on line slowly at iA -1/z bbl per minute and watch for pressure to start
increasing. CAUTIOUSLY look down the hole to verify no fluid is leaking past the closed pipe
rams. Record the pressure from the char` recorder vs strokes pumped every 2 or 3 strokes
pumped. The pressure should increase in a linear fashion vs strokes (Volume) pumped.
7. To perform a LOT (Leak -off Test), continue pumping and recording pressure vs strokes until
the pressure deviates from a straight line trend. Obtain one or two additional readings to
confirm this deviation from linearity.
8. Shut down the pump and continue to record pressure vs time, initially every 30 seconds for 2
minutes and then every minute for an additional 8 minutes.
9. Plot the points for the pressure build up vs volume pumped on one chart and the pressure
drop vs time on a second chart.
io. By looking at the chart of pressure vs volume pumped, the leak -off pressure is the point at
which the curve deviates from a straight line trend.
:Li. Use the formula: Leak off(EMW = MW + LO Pressure/(Shoe TVDx.052)
12. The FIT follows the same operational steps as previously described, except that the pressure
is increased to a pre -determined value previously calculated, where the plot of pressure vs
volume pumped does not deviate from a straight line. Using the same formula, the FIT value
is obtained. If however, deviation from a straight line does occur, do not keep pumping. The
leak off pressure has been reached and additional pumping may cause the formation to
break down.
13. The final step is to bleed off the pressure from the test and measure the volume of fluid
returned to a small pit such as the trip tank or small pill pit. Depending on well design and
depth, this volume bled back could be small — maybe no more than i bbl.
Brooks Range Petroleum Corp. -AOGCC 10-401 Attachments
Brooks Range Petroleum
Brooks Range Petroleum Corp. - AOGCC 10-401 Attachments
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The Model i Zo Gate Valve
Patented non-elastome
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fluids
Non -rising stem protects
threads from exposure to
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Selective metal -to -
Full metal -to -metal sealing
i-duty, tapered roller
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Replaceable gate lift nut
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feature to lower torque
and enhance sealing
reliability
Model 120 With the growing demands of the oilfield, reliability is a necessity.
At FMC Technologies, we understand your requirements- that's why we provide
solutions to meet your real -world needs. Tested an additional 300 cycles beyond
API 6A PR2 Annex F and ISO 10423: 2003 requirements, the Milo can withstand
temperature ranges of -75 to 35oF. With metal -to -metal seals throughout the valve
and bubble -tight UV stem packing, the M12o's design significantly decreases the
opportunity for any leakage to occur.
Model 125 For working pressures between 500o and 6500 psi, the Model 125 gate valve is a cost -reducing
alternative to a valve with a ioK pressure rating. Adapted from the Milo, the M125 shares the same key
features and operational benefits as the Milo with upgrades to some of the key components. In addition,
the M125 is also tested and qualified to API 6A PR2 (Annex F) ISO 10423:2003 and the FMC Pressure/
Temperature Endurance Cycle Test, passing a total of 500 cycles.
MCTechnologies
f MCTechnologies
Model i Zo
Technical Data
A
Nominal Size
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Working Pres
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Dimensions (inches)
Flanged End
Weight (Ibs)
Threaded End
Weight (Ibs)
# of Turns to
Open/Close
A
B
C
D
2 1/16
2000
11.620
2o.640
5.157
10.000
165
150
12 1/2
3000
14.62o
20.640
5.157
13=0
165
150
12 1/2
5000
14.62o
2o.640
5. 157
13.000
165
150
12 1/2
2 9/16
2000
13.120
22.457
6.140
10.000
275
260
15 1/2
3000
16.620
22.457
6.140
13.000
275
26o
15 1/2
5oco
16.620
22.457
6.140
13.000
275
260
15 1/2
31/8
2000
14.120
25.591
7.234
10.000
330
315
181/2
3000
17.120
25.591
7.234
15.00o
310
315
181/2
.5000
i8.62o
25.591
7.234
15.000
330
315
181/2
41/16
2000
17.120
28.851
8.953
15.0oo
590
-
231/2
3000
20.120
28.851
8.953
18.000
590
2 12
3 /
5000
21.62o
28.851
8.953
18•�
590
231/2
51/8
2000
22.120
34.067
10.430
20.000
880
281/8
3000
24. 120
34.067
10.430
20.000
880
281/8
5000
28.62o
34.o67
10.430
26.00o
880
-
281/8
6 3/8
2000
22.120
45.350
14.010
1335
-
381/4
3000
24.120
45.350
14.010
1315
-
38 1/4
5000
29.000
45.350
14.010
27.000
1335
-
381/4
Model i • Gate Valve,
QUalificatiolls
Material
Class
AA
BB CC
DD
EE
FF
HH
Forged Alloy
Forged Alloy
Forged Stainless
Forged Alloy
Forged Alloy
Forged Stainless
Forged Alloy
Body & Bonnet
Steel
Steel
Steel
Steel
Steel
Steel
Steel w/CRA
Gates & Seats
Alloy Steel
Stainless Steel
Stainless Steel
Alloy Steel
Stainless Steel
Stainless Steel
CRA
Stem
Alloy Steel
Stainless Steel
Stainless aSteel
Alloy Steel
Stainless Steel
Stainless Steel
CRA
Patented UV
Patented UV
Patented UV
Patented UV
Patented UV
Patented UV
Patented UV
Stem Packing
Design
Design
Design
Design
Design
Design
Design
Stainless Steel/
Bonnet Gasket I
Stainless Steel
Stainless Steel
Stainless Steel I
Stainless Steel
Stainless Steel
Stainless Steel
CRA
f MCTechnologies
PDS10002497 - C
PRODUCT DATA SHEET, HY-80 HYDRAULIC PISTON ACTUATOR
Rev
ECN No.
Date
Reviewed By
Approved By
Status
C
4132895
02-DEC-2009
Ang, Chee Poh
Deocampo, Nani
RELEASED
Summary:
This Technical Data Sheet contains the features, design specifications and ratings of the Model HY-80
Hydraulically Operated Piston Actuator.
This actuator is designed to operate the following valve sizes and pressure ratings:
Valve Size (in) Pressure Rating (psi)
1 13/16
10 / 12.5 k
21/16
5/6.7/10/12.5k
29/16
5/6.7k
31/8
5/6.7k
Subject to contractual terms and conditions to the contrary, this document and all the information contained herein are the confidential and exclusive
property of FMC Technologies, and may not be reproduced, disclosed, or made public in any manner prior to express written authorization by FMC.
** RELEASED FOR MANUFACTURE ** -- Published: 12/02/2009_15:09:33
fMCTechnologies
PDS10002497 - C
• Rising Stem Design to provide visual identification
of gate position
• Springs captured in spring container
• Easy and Quick Disconnect Feature allows entire
power section to be removed from the Actuator
bonnet assembly
• AP16A
Valve Key Features
• Bi Directional metal to metal gate to seat and seat
to body
• Metal to metal backseat
• Metal to metal bonnet -body
• FMC patented UV stem packing
• Tested in accordance with API 6A, PR2, Annex F,
and 300 cycle FMC Endurance Test
Technical Description
• Rising stem design for positive identification of gate
position
• Prepped to receive electrical position indicator
Subject to contractual terms and conditions to the contrary, this document and all the information contained herein are the confidential and exclusive
property of FMC Technologies, and may not be reproduced, disclosed, or made public in any manner prior to express written authorization by FMC.
RELEASED FOR MANUFACTURE - -- Published: 12/02/2009_15:09:33
f MCTechnologies
Technical Description
Actuator
• Hydraulic Piston: HY-80
• PSL-1: API Specification Level
• PR2: API Performance Level
• AA : API Material Specification Level
• P-U (-20° F to 250' F, -29°C to 121IC) : API
Temperature Class
• 5,000 psi (345 bar): Cylinder Working Pressure
• 7,500 psi (517 bar): Cylinder Test Pressure
• Cylinder Upper Thread: External Left Hand M64
thread
• API 14" Female fittings on control port
• Repair Kit
• Solid Lock Out Cap
• Fusible Lock Out Cap
• Metal Stem Protector
• Transparent Stem Protector
• Mechanical Over -ride
PDS10002497 - C
Valve
• Valve Size: 1 13/16 (10 & 12.5 k)
2 1/16 (5, 6.7, 10, & 12.5 k)
2 9/16 (5 & 6.7 k)
3 1/8 (5 & 6.7 k)
• PSL 1-4 API Specification Levels
• PR2: API Performance Requirement
• AA-HH: API Material Specifications
• K-X (-75D F to 3500 F, -60°C to 177°C): API
Temperature Classes
• Hydraulic Over -ride
• Hand Pump and Hose
• Electrical Position Indicator
Valve Size Required Actuator Control Pressure Formulas
At Ambient At Maximum Rated Valve Temperature
1 13/16 10/12.5k P=0.195 (VP) + 260 psi P=0.256•(VP) + 260 psi
2 1/16 5/6.7k P=0.246.(VP) + 250 psi P=0.322•(VP) + 250 psi
2 1/16 10/12.5k P=0.214•(VP) + 250 psi P=0.290.(VP) + 250 psi
2 9/16 5/6.7k P=0.327,(VP) + 230 psi P=0.435•(VP) + 230 psi
3 1/8 5/6.7k P=0.474.(VP) + 200 psi P=0.625•(VP) + 200 psi
Where: P = Actuator Control Pressure in psi
VP = Valve Body Pressure in psi
References
Documentation file for the Model HY-80 Hydraulic ADF10004093
Actuator
Subject to contractual terms and conditions to the contrary, this document and all the information contained herein are the confidential and exclusive
property of FMC Technologies, and may not be reproduced, disclosed, or made public in any manner prior to express written authorization by FMC.
** RELEASED FOR MANUFACTURE ** -- Published: 12/02/2009_15:09:33
f MCTechnologies
PDS10002497 - C
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Subject to contractual terms and conditions to the contrary, this document and all the information contained herein are the confidential and exclusive
property of FMC Technologies, and may not be reproduced, disclosed, or made public in any manner prior to express written authorization by FMC.
** RELEASED FOR MANUFACTURE ** -- Published: 12/02/2009_15:09:33
+MCTechnialiogies
PDS10002497 - C
HY-80 113/16-10/12.5K
4000
N
a
3500
----- — - - - -
3000
--- --- ----- —
a
2500
----
0
-
2000
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0
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0
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Break Open (Ambient)
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Cr
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m
1000
3000 5000 7000 9000 11000
13000
Valve Pressure (psi)
HY-80 21/16-5/6.7K
3000
N
a
2500
-
N
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2000
0
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1500
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Hold Open
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500 '� "''
—
w
rr
0
--
u
o:
1000 2000
3000 4000 5000 6000
7000
Valve Pressure (psi)
Subject to contractual terms and conditions to the contrary, this document and all the information contained herein are the confidential and exclusive
property of FMC Technologies, and may not be reproduced, disclosed, or made public in any manner prior to express written authorization by FMC.
** RELEASED FOR MANUFACTURE ** -- Published: 12/02/2009_15:09:33
f MCTechnologies
4500
N
s 4000
d
3500
N
N
d 3000
a
2500
g 2000
« 1500
m
t 1000
Q
m 500
a
0
w
or 1000
HY-80 21/16-10/12.5K
3000 5000 7000 9000 11000 13000
Valve Pressure (psi)
PDS10002497 - C
Break Open (350F)
Break Open (250F)
Break Open (Ambient)
• Hold Open
HY-80 2 9/16-5/6.7K
3500
N
a
w
3000
2500
a`
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c
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`
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Break Open (250F)
1000
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500
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w
__
Cr
0
— ------ T_
1000
2000 3000 4000 5000 6000 7000
Valve Pressure (psi)
Subject to contractual terms and conditions to the contrary, this document and all the information contained herein are the confidential and exclusive
property of FMC Technologies, and may not be reproduced, disclosed, or made public in any manner prior to express written authorization by FMC.
** RELEASED FOR MANUFACTURE ** -- Published: 12/02/2009_15:09:33
f MC Technologies
PDS10002497 - C
HY-80 31/8-5/6.7K
5000
- - -
4500
- - --
N
4000
--
v
3500
----
a
c
3000
c
2500
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c
2000+�
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•
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+..
+
Q
1000 ++..
+'+
---•Hold Open
'
500
Cr
0
v
1000 2000
3000 4000 5000 6000 7000
Valve Pressure (psi)
Subject to contractual terms and conditions to the contrary, this document and all the information contained herein are the confidential and exclusive
property of FMC Technologies, and may not be reproduced, disclosed, or made public in any manner pr or to express written authorization by FMC.
** RELEASED FOR MANUFACTURE ** -- Published: 12/02/2009_15:09:33
Brooks Range Petroleum
Brooks Range Petroleum Corp. - AOGCC 10-401 Attachments
A -
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§I
TRANSMITTAL LETTER CHECKLIST
WELL NAME: S� <. ��{ p n/ / l fiV 1 �v (JA-1 M- O
PTD:
Development Service Exploratory Stratigraphic Test _ Non -Conventional
FIELD:_&U4 JW 6k'wx, _ POOL: -Soi nfi � ddt"� K(_' ����r 6'
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK
OPTIONS
TEXT FOR APPROVAL LETTER
MULTI
The permit is for a new wellbore segment of existing well Permit
LATERAL
No. , API No. 50- - - -
(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 onpermit).
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce/inject is contingent upon issuance of a conservation
Spacing Exception
order approving a spacing exception. (Company Name) Operator
assumes the liability of any protest to the spacing exception that may
occur.
All dry ditch sample sets submitted to the AOGCC must be in no greater
Dry Ditch Sample
than 30' sample intervals from below the permafrost or from where
samples are first caught and 10' sample intervals through target zones.
Please note the following special condition of this permit:
production or production testing of coal bed methane is not allowed for
Non -Conventional
(name of well) until after (Company Name) has designed and
Well
implemented a water well testing program to provide baseline data on
water quality and quantity. (Company Name) must contact the AOGCC
to obtain advance approval of such water well testing program.
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of
well logs to be run. In addition to the well logging program proposed by
(Company Name) in the attached application, the following well logs are
also required for this well:
Well Logging
Requirements
/
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
!/
composite curves for well logs run must be submitted to the AOGCC
within 90 days after completion, suspension or abandonment of this well.
Revised 2/2015
WELL PERMIT CHECKLIST Field & Pool S MILUVEACH, KUPARUK RIVER OIL - 764150
PTD#:2150650 Company BROOKS RANGE PETROLEUM Initial Class/Type
_ Well Name: SOUTHERN MILUVEACH_ UNIT_M-04__- Program DEV Well bore seg ❑
_ DEV / PENDGeoArea 890 Unit 11965 On/Off Shore On Annular Disposal ❑
Administration
I17
Nonconven. gas conforms to AS31.05.030Q.1-.A),0.2.A-D) -
NA.
11
Permit fee attached
NA
2
Lease number appropriate_ - - - - - - - - -
Yes
ADL0390680,_S_u_rf &_Top Prod Interv; ADL0390691, TD- - -
3
Unique well name and number
Yes -
Southern- Miluveach Unit M-04 - -
4
Well located in a_defined.pool-
Yes
S MILUVEACH, KUPARUK_RIVER OIL-- 7641.50,_governed -by Conservation -Order _N_o. 432C-
5
Well located proper distance from drilling unit -boundary - - - - - - - - . -
Yes
CO 432C contains no spacing restrictions with respect to drilling unit boundaries. -
6
Well.locat_ed proper distance from other wells
Yes -
CO 432C has no inte_rwelI- spacing -restrict ions.
7
Sufficient acreage available in -drilling unit_ - - - - - - - - - - - -
Yes
-- ---------------------------------
8
If -deviated, is-wellbore plat_inc_luded
Yes
9
Operator only affected party. -
Yes .
- - - Wellbore_will be- more than 500' from an external property line where- owner_ship or landowners hip- changes. -
10
Operator has -appropriate bond in force - -
Yes -
Appr Date
11
Permit -can be issued without conservation order - - - - - - -
Yes -
- - - - - - - -
I12
- Permit_can be issued -without administrativeapproval- -
Yes -
- - - - - - - - - - - - - - - -
PKB 4/14/2015
13
Can permit be approved before 15-day wait- - - - - - - - - - - . - - -
Yes -
- -
14
Well -located within area and -strata authorized by Injection Order # (put -10# in_ comments) -(For
NA -
- -
15
_All wells _within _1/4_mile -area -of review identified (For service well only)- -
NA_
- - - - - - - - - - - - - - -
16
Pre -produced injector; dur_ation_of pre production Less than 3 months_ (Forservice well only)
NA- -
18
Conductor string -provided - - - - - -
Yes
- I_nsulated_ 20" conductor set -at 110.ft. .
-
Engineering
19
Surface casing_ protects all -known USDWs - - - - -
NA_
No aquifers., Permafrost area. -
20
CMT_vol -adequate to circ_ul_ate_o_n conductor & surf_csg - -
Yes
Surface casing will be fully cemented.- TAM collar at 500fl for -backup._ - -
21
CMT-vol adequate, to tie -in -long string to -surf csg_
No_
7"_intermediate casing will. have 500ft cement at shoe. -
- _
22
CMTwill coverall known -productive horizons - - _
Yes
4.5"_slo_tted liner in horn production Kup-C
23
Casing designs adequate for C,_T, B &- permafrost
Yes
BTC calc provided- - - - - - - - - - - - - - - - - - -
24
Adequate -tankage or reserve pit
Yes -
Rig has steel pits. All waste toapproveddisposal wells.
25
If -a_ re -drill, has- a 1-0-403 for abandonment been approved
NA_ -
- - - - - - Grassroots well. -
26
Adequate wellbore separation -proposed _ - _ - -
Yes -
- - - - - - No issues with collision.- - - - -
27
If-diverter required, does it meet regulations - _ _ _ - -
Yes
- - _ _ _ - N16E_has 16" diverter..._s_ketch of layout is_ prov_id_ed._ - - - -
Appr Date
28
Drilling fluid_ program schematic_& equip list adequate- - - - - -
Yes .
- - - - - - Max formation pressure= 3767_psi_(12 ppg_E_MW)_Will drill _lateral _with 12.3ppg mud -
GLS 4/17/2015
29
BOPEs,-do they meet regulation -
Yes -
- - - - - - N16-E_has 5000_psi_13 5/8" BOPE - - - - - - - - - - - - - - - - - - - - - - - - -
i30
_B_OPE_press rating appropriate; test to.(put psig in comments)_ - - - - -
Yes -
- - - - - MASP = 3163_psi_ Will test BOPE to 4000 psi
31
Choke_man ifold complies w/API_ RP-53 (May 84)- - - - - - - - - - - -
Yes -
- _
32
Work will occur without operation shutdown_ - - -
Yes -
- - - - Need sundry for completion and testing operations... - - - -
133
-Is presence of H2S gas_ probable - - - - - - -
Yes -
- - - Rig has sensors and alarms -
34
Mechanical_ condition of wells within AOR verified (For service well only) - - _
NA_
�35
-Permit can be issued w/o hydrogen_ sulfide measures - - - - - - -
N_o_
H2S measures required.. Wells on nearby KRU 2M-Pad are- H2S-bearing- - - - - - - - - - - - - - -
Geology
36
Data presented on potential overpressure zones -
Yes -
- - - - - -Expected r_eservoirpressure is 12.0 ppg EMW; will be drilled using_9.0 to 12.3 ppg mud.-
Appr Date
37
Seismic -analysis- of shallow gas- zones- -
_NA _ -
- - - - - - - - - - - - - - - - - - - - - - - -
PKB 4/14/2015
38
Seabed condition survey -(if off -shore) - _ - -
NA -
- -
39
Contact name/phone for weekly progress reports_ [exploratory only] - - - - - - - - - - -
NA-
- - - - - - Onshore development well to_be drilled._ - - - -
Geologic Engineering Public Grassroots Kup C producer. Sundry approval for completion and testing operations is required. GLS
Commissioner: Date: C missioner. Date Commissioner Date
��❑�..
