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Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout213-092Davies, Stephen F (DOA)
From: Lastufka, Joseph N <Joseph.Lastufka@bp.com>
Sent: Monday, December 08, 2014 1:49 PM
To: Davies, Stephen F (DOA)
Cc: Nocas, Noel
Subject: FW: 09-31D Permit to Drill #213-092 cancellation
Steve,
Please let me know if you need anything else or have any additional questions. Victoria was out on vacation when I sent
the initial request.
Thanks!
Joe
From: Lastufka, Joseph N
Sent: Monday, November 24, 2014 11:06 AM
To: Victoria,Loepp@alaska.gov
Subject: 09-31D Permit to Drill #213-092 cancellation
Victoria,
We will be submitting a new Permit to Drill for 09-31D due to the sundry expiration for Suspend and a change to the
drilling plan. Please cancel PTD #213-092, we will submit a new sundry for Plug for Redrill of 09-31C (PTD #196-064) and
new Permit to Drill for 09-31D.
Please let me know if you have any questions.
Thanks!
Joe
f-ro ZJ3_og-Z__
Loepp, Victoria T (DOA)
From: Davies, Stephen F (DOA)
Sent: Thursday, December 04, 2014 10:52 AM
To: Nocas, Noel
Cc: Loepp, Victoria T (DOA)
Subject: RE: PBU 09-31D (PTD #213-092)
Follow Up Flag: Follow up
Flag Status: Flagged
Noel,
Considering this further, the original Permit to Drill for PBU 09-31D (PTD #213-092) was approved by AOGCC on July 26,
2013. There is one major disadvantage to considering the current application as a revision to that existing
permit. Permits to Drill are valid for 24 months from the initial approval date. When AOGCC re -issues a Permit to Drill,
the initial approval date remains the same, so if the Permit to Drill PBU 09-31D is re -issued, it will be valid only until July
26, 2015. That may be a problem if unforeseen events cause BP's drilling schedule to change. So, Victoria is correct: it
would be best for BP to cancel existing Permit to Drill #213-092 and to consider the current application to be an
application for a new permit.
Thanks,
Steve Davies
AOGCC
Phone: 907-793-1224
AOGCC: 907-279-1433
Fax: 907-276-7542
333 West 7th Avenue, Suite 100
Anchorage, AK 99501
CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential
and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If
you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware
of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov.
From: Nocas, Noel [maiIto: Noel. Nocas(�bbp. com]
Sent: Thursday, December 04, 2014 10:37 AM
To: Davies, Stephen F (DOA)
Cc: Lastufka, Joseph N; Ramos, Tania (UOSS)
Subject: RE: PBU 09-31D (PTD #213-092)
Steve,
BP would like, and it would be great if we could just change the current PTD (as a revision). However, from my
understanding, communication with Victoria indicated she wished us to cancel the existing and replace it due to the
change in directional plan.
If you believe a revision is ok, we will gladly take it. However if you feel like the old permit should be cancelled then we
can do that as well but it is not preferred on our end.
Thanks,
Noel
From: Davies, Stephen F (DOA)[ma iIto: steve.davies@alaska.gov]
Sent: Thursday, December 04, 2014 10:04 AM
To: Nocas, Noel
Subject: FW: PBU 09-31D (PTD #213-092)
Noel,
I'd like to move this application forward in our review process. Does BP wish to cancel existing Permit #213-092 and
replace it with this application?
Thanks,
Steve Davies
Senior Petroleum Geologist
Alaska Oil and Gas Conservation Commission (AOGCC)
Phone: 907-793-1224
AOGCC: 907-279-1433
Fax: 907-276-7542
333 West 7th Avenue, Suite 100
Anchorage, AK 99501
CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential
and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If
you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware
of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov.
From: Davies, Stephen F (DOA)
Sent: Monday, December 01, 2014 4:54 PM
To: 'noel.nocas@bp.com'
Subject: PBU 09-31D (PTD #213-092)
Noel,
I'm reviewing BP'S application for PBU 09-31D that was received by the AOGCC on November 25th. The AOGCC
approved a Permit to Drill (PTD #213-092) for that same well on July 26, 2013. Does BP wish to cancel Permit #213-092
and replace it with this application? Or is BP's current application simply considered a revision of that existing Permit?
Thanks,
Steve Davies
Senior Petroleum Geologist
Alaska Oil and Gas Conservation Commission (AOGCC)
Phone: 907-793-1224
AOGCC: 907-279-1433
Fax: 907-276-7542
333 West 7th Avenue, Suite 100
Anchorage, AK 99501
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential
and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If
you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware
of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov.
THE STATE ��� a-sk . 'i and Gas
01A L Ab" K A Commassion
GOVERNOR SEAN PARNELL 333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
John Egbejimba
Engineering Team Leader
BP Exploration (Alaska), Inc.
P.O. Box 196612
Anchorage, AK 99519-6612
Re: Prudhoe Bay Field, Prudhoe Bay Oil Pool, PBU 09-31 D
BP Exploration (Alaska), Inc.
Permit No: 213-092
Surface Location: 1587' FSL, 998' FEL, SEC. 02, T1 ON, R15E, UM
Bottomhole Location: 3148' FSL, 4586' FEL, SEC. 34, T11N, R15E, UM
Dear Egbejimba:
Enclosed is the approved application for permit to redrill the above referenced service 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
Commission 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 Commission 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 a Commission order, or the terms and conditions of this permit may
result in the revocation or suspension of the permit.
DATED this'-` day of July, 2013.
STATE OF ALASKA
ALAS, . OIL AND GAS CONSERVATION COMM. ION
PERMIT TO DRILL
20 AAC 25.005
1 a.Type of work:
1 b.Proposed Well Class: ❑ Development Oil ❑ Service - Wini ® Single Zone
1 c. Specify if well is proposed for:
❑ Drill ❑ 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:
BP Exploration (Alaska) Inc.
Bond No 6194193 •
PBU 09-31D
3. Address
6. Proposed Depth:
12. Field / Pool(s)
P.O. Box 196612, Anchorage, Alaska 99519-6612
MD 17534' ' TVD 8729'
Prudhoe Bay / Prudhoe Bay _
4a. Location of Well (Governmental Section):
7. Property Designation (Lease Number):
Surface:
ADL028327, 028328 & 028325'
1587' FSL, 998' FEL, Sec. 02, T10N, R15E, UM`
8. Land Use Permit:
13. Approximate Spud Date:
Top of Productive Horizon:
4979' FSL, 1398' FEL, Sec. 03, T10N, R15E, UM
February 24, 2014
9. Acres in Property:
14.Distance to Nearest Property:
Total Depth
3148' FSL, 4586' FEL, Sec. 34, T11 N, R15E, UM
2560
16800'
4b. Location of Well (State Base Plane Coordinates - NAD 27):
10.KB Elevation above MSL: 60.6' feet
15.Distance to Nearest Well Open
Surface: x 717376 • y- 5943027 - Zone- ASP4
GL Elevation above MSL: 19.8' feet
to Same Pool:
16. Deviated Wells: Kickoff Depth: 4400' feet
17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 93 degrees
Downhole: 3313 - Surface: 2452
18. Casing Program
Specifications
Top - Setting Depth - Bottom
Quantity of Cement, c.f. or sacks
Hole
Casing
Weight
Grade
Coupling
Length
MD
TVD
MD
TVD
(including stage data)
8-1/2"
7"
26#
L-80
Hydril563
7947'
4250'
4250'
12197'
8613'
209 sx Class'G'
6-1/8"
4-1/2"
12.6#
13Cr85
Hydril521
5485'
12047'
8490'
17532'
8729'
657 sx Class'G'
19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-entry Operations)
Total Depth MD (ft):
Total Depth TVD (ft):
Plugs (measured):
Effective Depth MD (ft):
Effective Depth TVD (ft):
Junk (measured)
10946'
8824'
9170', 9390' 9489' 10000',
1090C
8825'
10600'
Casing Length Size Cement Volume MD TVD
Conductor / Structural
111'
20" 1800#
Polyurethane
111'
111'
Surface
2533'
13-3/8" 2500
sx CS III 400 sx CS II
2533'
2533'
Intermediate
8400'
9-5/8" 500
sx Class 'G' 300 sx CS 1
8400'
8132'
Production
Liner
826'
7" 264
cu ft Class 'G'
8234' - 9060'
7973' - 8739'
Liner
2129'
1 2-7/8" 117.5
Bbls Cement
1 8816' - 10945'
1 8525' - 8824'
Perforation Depth MD (ft): 8972' - 10875'
Perforation Depth TVD (ft): 8664' - 8826'
20.Attachments: ❑ Property Plat ® BOP Sketch ® Drilling Program ❑ Time vs Depth Plot ❑ Shallow Hazard Analysis
® Diverter Sketch ❑ Seabed Report ® Drilling Fluid Program ® 20 AAC 25.050 Requirements
21. Verbal Approval: Commission Representative:
Date
22. 1 hereby certify that the foregoing is true and correct:
Contact John Rose, 564-5271
Printed Name John Egbejimba Title Engineering Team Leader Email John.G.Rose@bp.com
Signature S F�'� J e Li Zc ,� OAF3 N Phone 564-5859 Date 6 I v 1 �
Commission Use Only
Permit To Drill r' —�
API Number:
Permit Appr t
See cover letter for
Number: —
50-029-21396-04-00
��%
other requirements:
Conditions of Approval: If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas
Other. & ✓'� t! 6 f f0 4 0 �� %� Samples Re d: D% contained shales:
%� p q' ❑Yes Iyf No Mud Log Req'd: [2'No
,❑—✓Yes
HzS Measures: [; Yes o Directional Survey Req'd: G Yes ❑�,
�No
VNo
Spacing exception req'd: ❑ Yes inclination -only svy Req'd: ❑ Yes L1 No
Ig2
APPROVED BY
APPROVED
4
BY CO TONER THE COMMISSION Date
G
Form 10-401 Revised 10/2012 Thi
pe Nalicbr 4 months from the date of approval (20 AAC 25.005(g)) Submit Form and Attac_prjW Inpuplicate
AN
`a
by
09-31 Di Permit to Drill Application
Well Type: Injector
Current Status: The well is currently shut-in.
Request:
Sundry approval has been requested for the P&A of Prudhoe Bay well 09-31 C well to sidetrack and
complete 09-31 D well.
Reason for Sidetrack:
The prospect is located in the DS O4-13 and 04-15 areas southwest of 09-16. The play concept is to
expend MIST (miscible injection stimulate treatment) to increase MI sweep and capture FOR oil which
was not swept by conventional WAG. The interval targeted is the Victor (42P-26P) which is roughly 80
tvdss. The prospect is consistent with the GPB Depletion plan, and drilling will be covered under the
Prudhoe Annual Drilling FM. Wells available and release by Base are 09-31 and 09-36. This well needs
to be drilled from DS9 since IDS 4 and DS11 do not have current MI injection capabilities.
Well History:
The original production well (09-31) was originally drilled in 1986 prior to a RST in 1993 (the 09-31A well
which included a CTD open -hole completion below a 7" drilling liner) and 2 subsequent coil ST's in 1994
(09-31 B) and 1996 (09-31 Ci). As the current 09-31 Ci well watered -out the 09-35A well, DS-09
conformance reviews determined shutting in this injector would be the best solution for optimization of the
09-15A pattern.
Scope of Work:
The sidetrack plan for the 09-31 D well includes the following:
1. Pre -rig 09-31 C P&A operations, MIT's and a tubing cut as required prior to sidetracking the well as
detailed in the 09-31 C Sundry request.
2. MIRU Doyon 25 and test BOP's.
3. Pull tubing from the pre -rig cut —5000 MD and make run a clean out run to the top of the tubing stub.
4. Sidetrack the well from the 9-5/8" casing.
5. Drill to the planned TSAD casing point and run and cement a 7" drilling liner.
6. Drill the production hole to the planned TD and run and cement a 4-1/2" production liner.
7. Perforate the production liner on drillpipe.
8. Run a 4-1/2" chrome completion.
9. Freeze protect the well prior to RDMO.
MASP: 2390 psi (7.3 ppg @ 8548' TVDss)
Estimated Start Date: 02/24/2014
09-31 Di PTD Page 1 6/18/2013
Planned Well Summary
Well 09-31Di Well MI Injector Objective Ivishak
API Number: 50-029-21396-04
Current Status Shut -In
Estimated Start Date: 02/24/2014 Time to Complete: 49 Days
Surface
Northing
Easting
I Offsets
TRS
Location
5,943,027
717,376
1 1588' FSL / 999' FEL
10N 15E sec 2
Tie -In
Northing
Easting
TVDss
I Offsets
I TRS
(Survey)
1 5,943,041
717,405
4245'
1601' FSL / 969' FEL
1 1 ON 15E sec 2
Northing
Easting
TVDss
Offsets
TRS
Production
5,946,255
711,599
8770'
4979' FSL / 1398' FEL
1 ON 15E sec 3
Tgt
BHL
5,949,613
708,309
8668'
3148' FSL / 4586' FEL
11 N 15E sec 34
Planned KOP: 4400' MD/4338' TVDss Planned TD: 17,534' MD/8668' TVDss
Rig: Doyon 25 BF-RT: 40.8' RTE (ref MSL): 60.6
Directional — Schlumberger P5
KOP: 4400' MD
Maximum Hole Angle:
-64.9° in the 8-1/2" intermediate section
-92.95' in the 6-1/8" production section
Close Approach Wells:
09-05, 09-05A, 09-14, 09-30, 09-30PB1 & 09-32
Survey Program:
106.6' - 4306.6' MD - BOSS GYRO
4306.06' - 4400' MD - BOSS GYRO
4400' - 4700' MD - INC+Trend
4700' - 6200' MD - MWD
4700' - 12,198' MD - MWD+IFR+MS
12,198' - 13,700' MD MWD
12,198' - 17,533' MD MWD+IFR+MS
Nearest Property Line:
16,800'
Nearest Well within Pool:
09-05A
09-31 Di PTD Page 2 6/18/2013
Formation Tops & Pore Pressure Estimate (SOR)
Tops Based on Well Plan #:I 09 31D_wp05
Formation
Estimated
Formation Top
(TV Dss)
Minimum
Pore Pressure
(EMW ppg)
Most Likely
Pore Pressure
(EMW ppg)
Maximum
Pore Pressure
(EMW ppg)
Depth
Uncertainty
TVDft)
Fluid
Type
(for sands)
SV 1
4,320
8.4
8.4
8.5
KOP
4,337
UG4
4,930
8.4
9.2
9.3
UG4A
4,945
8.4
9.2
9.3
UG3
5,235
8.4
9.2
9.3
UG1
5,760
8.4
9.2
9.3
UG_MA
6,205
UG_M B1
6,245
UG_MB2
6,280
UG_MC
6,390
WS2
6,415
8.4
9.0
9.3
M70S
6,435
NA
6,475
NB
6,495
NE
6,565
NF
6,615
WS1
6,605
8.4
9.0
9.5
OA
6,630
OBA
6,675
OBB
6,685
OBC
6,740
OBD
6,775
OBE
6,835
OBF
6,875
CM3
6,885
8.4
9.3
9.5
OBF_BASE
6,945
CM2
7,325
9.2
9.8
10.4
TUFF
7,890
C M 1
7,920
9.8
10.0
10.5
TLBK
8,200
HRZsilt
8,280
THRZ
8,325
9.8
10.0
10.5
20
BHRZ
8.516
9.8
10.0
10.5
20
LCU
8,537
6.8
7.3
9.8
20
TSAD (ST)
8,548
6.8
7.3
7.6
20
44P
8,565
6.8
7.3
7.6
20
43P
8,600
6.8
7.3
7.6
20
42P
8,655
6.8
7.3
7.6
20
31P
8,700
6.8
7.3
7.6
20
27P
8,745
6.8
7.3
7.6
20
invert
8,765
6.8
7.3
7.6
20
revert
8,660
6.8
7.3
7.6
20
26P
8,695
6.8
7.3
7.6
20
TD
8,705
6.8
7.3
7.6
20
09-31 Di PTD Page 3 6/18/2013
Casinq/Tubing Program
Hole
Liner /
Wt/Ft
Grade
Conn
Length
Top
Bottom
Size
Tbg O.D.
MD / TVDss
MD / TVDss
8-1/2"
7"
26#
L-80
56 ril
7948'
4250' / 4251'
12,197: / 8613'
6-1/8"
4'/2"
12.6#
1 85R
Hyd521
5337'
12,047' / 8490'
17,532' / 8729'
Tubing
4'/"
12.6#
1 85R
VamTop
12,052'
Surface
12,052' / 8493'
Mud Program
Intermediate Mud
Properties: LSND 8-1/2" hole section
Depth Interval
Density (ppg)
PV
YP
API FL
HTHP FL
MBT
PH
Window Milling
9.3-9.4
10-18
26-30
<8
NA
<18
9-10
KOP - TCM2
9.3-9.4
10-18
18-26
<8
NA
<20
9-10
TCM2 - THRZ
9.8-10.0
10-18
18-26
<8
NA
<20
9-10
THRZ - 8-1/2"
TD in TSAD
10.4 '
10-18
18-26
<4
<10
<20
9-10
*NOTE: 10.4 ppg MW is needed for HRZ Stability
Production Mud Properties: Reservoir Drill -In Fluid 6-1/8" hole section
Depth Interval
Density
(ppg)
PV
YP
LSRV
API FL
pH
MBT
7" Csg Shoe to TD
8.5 - 9.1 y
<12
10-20
> 15,000
< 10
9.5-10.5
< 4
Loqqinq Program
8-1/2" Intermediate:
Sample Catchers - as required by Geology
Drilling:
Dir / GR / Res
Open Hole:
None
Cased Hole:
Contingency USIT in cement evaluation mode from the 7" shoe to confirm TOC.
6-1/8" Production:
Sample Catchers - as required by Geology
Drilling:
Dir / GR / Res / Neu / Den
Open Hole:
None
Cased Hole:
None
t,.emeni rrogram
Casing Size
7" 26#, L-80, Hydril 563 or Vam Top HC, Intermediate Liner
Basis:
Lead: None
Tail: 80' of shoe track + Annular volume from 7" shoe to 1379' MD above with 30% excess.
Tail TOC: -1379' above the 7" shoe at 10,819' MD
Total Cement
Volume:
Spacer
-40 bbls of Viscosified Spacer weighted to -11.0 ppg (Mud Push II)
Lead
None
Tail
43 bbls, 242 cuft, 209 sks 15.8 lb/gal Class G - 1.17 cuft/sk
Temp
BHST 202' F
09-31 Di PTD Page 4 6/18/2013
Casing Size:
4'/2", 12.6#, 13Cr-80, Hydril 521 or Vam Top, Production Liner
Basis:
Lead: None
Tail: Volume of open hole +40% +80' shoe track + 100' 4-1/2"x7" liner lap +200' of 7"x4" D
excess.
Tail TOC: —12,048' MD (Liner Top, excess will be circulated out)
Total Cement
Volume:
Spacer
25 bbls of Viscosified, 12.0 ppg weighted Spacer (Mud Push II)
Lead
N/A
Tail
135.9 bbls, 761.2 cuft, 656.5 sks 15.8 lb/gal Class G + adds — 1.17 cuft/sk
Temp
BHST = 202' F, BHCT TBD by Schlumberger
Surface and Anti -Collision Issues
Surface Shut-in Wells:
No surface shut-in wells are required.
Close Approach Shut-in Wells:
09-05, 09-05A, 09-14, 09-30, 09-30PB1 and 09-32 fail Major Risk analysis. A TCR will need to be filled out
for each to determine action.
Faults
Faults Based on Well Plan #:I 09-31D_wp05
Formation Where Encounter Fault
MD Intersect
TVDss Intersect
Throw Direction
and Magnitude
Uncertainty
Lost Circ
Potential
Zone 2
12,733.0
8,770.0
SE 10'
+/- 150' MD
Low
Zone 2
1
14,943.0
8,676.0
ISM30'
+/- 150' MD
Med
Zone 2
115,311.0
8,683.0
W 10,
+/- 150' MD
Low
Zone 2
116,382.0
8,704.0
SE 10'
+/- 150' MD
Low
Drilling Waste Disposal
There is no annular injection in this well.
Cuttings Handling: Cuttings generated from drilling operations will be hauled to grind and inject
at DS-04. Any metal cuttings will be sent to the North Slope Borough.
Fluid Handling: Haul all drilling and completion fluids and other Class II wastes to DS-04 for
injection. Haul Class I waste to DS-04 and/or Pad 3 for disposal / Contact the GPB
Environmental Advisors (659-5893) f/guidance.
Y,.
09-31 Di PTD Page 5 6/18/2013
Well Control
Well control equipment consisting of 5,000 psi working pressure pipe rams (2), blind/shear rams, and
annular preventer will be installed and are capable of handling the maximum potential surface pressures.
Based upon calculations below, BOP equipment will be tested to 3500 psi.
BOP regular test frequency will be 14 days during drilling phase and 7 days
during sundry operations.
Intermediate Interval
Maximum anticipated BHP
3313 psi @ TSAD at 8609' TVDss 7.4 ppg EMW)
Maximum surface pressure
2452 psi (.10 psi/ft gas gradient to surface)
Kick tolerance
25.7 bbls with 11.8 ppg frac gradient, assuming an 7.4 ppg pore
pressure in the Sag River + 0.5 ppg Kick intensity and 10.4 ppg MW.
Planned BOP test pressure
Rams test to 3500 psi / 250 psi.
Annular test to 3500 psi / 250 psi
7" Drilling Liner
3500 psi surface pressure
Integrity Test — 8-1/2" hole
LOT after drilling 20'-50' from middle of window
7" Drilling Liner
The VBRs will be changed to 7" rams to accommodate the 7" casing
string.
Production Interval
Maximum anticipated BHP
3313 psi @ TSAD at 8609' TVDss 7.4 ppg EMW r
Maximum surface pressure
2452 psi .10 si/ft gas gradient to surface -v'
Kick tolerance
Infinite with 9.0 ppg frac gradient, assuming an 7.4 ppg pore pressure in
the Ivishak + 0.5 ppg Kick intensity and 8.6 ppg MW.
Planned BOP test pressure
Rams test to 3500 psi / 250 psi.
Annular test to 3500 psi / 250 psi
Integrity Test — 6-1/8" hole
FIT after drilling 20'-50' of new hole
Planned completion fluids
Seawater / 6.8 ppg Diesel
09-31 Di PTD Page 6 6/18/2013
Wellplan Addendum
Contingency for well control when non-shearable equipment is across the BOPE v
shear rams
This document will provide guidance for rig operations when a well control event arises and
there is non-shearable equipment hanging from the derrick across the BOPE shear rams.
Prior to picking up or running any equipment or tools in the hole, a PJSM and discussion is
required to identify and note any equipment which will be run through the BOPE and is non-
shearable.
A risk assessment shall be performed for any equipment which is deemed non-shearable. The
risk assessment must address the following:
1. Can variable bore rams seal against the equipment?
2. Can an annular preventer seal against the equipment?
3. Is a cross -over readily available to make-up into equipment?
4. Is a single joint or full stand of DP readily available to lower equipment below the BOPE
stack?
5. How the equipment can be intentionally dropped down hole.
6. Are weights of equipment known so that hydraulic jacking force of wellbore pressure can
be calculated.
7. Accurate and up to date shearing capabilities for the current shear rams installed is
available.
8. Has each crew member been versed on individual roles and responsibilities?
If there is a well control event happens with non-shearable equipment across the BOPE shear
rams, the following procedure should be followed:
1. Based on the risk assessment above, gain control of the well by either:
a. Closing the appropriate preventer (pipe ram, VBR, or annular) or
b. Placing a sealable piece of equipment across the BOPE and closing the
appropriate preventer or
c. Dropping equipment and closing the Blind or Blind/Shear rams.
2. If well conditions permit, contact appropriate personnel. If not, proceed with well kill
operations. This may include placing shearable equipment (i.e. drillpipe) across the shear
rams by stripping in/out of the hole.
09-31 Di PTD Page 7 6/18/2013
Pre -rig prep work:
1. MIT -IA to 4000 psi, MIT-OA to 2000 psi.
2. PPPOT-T to 5000 psi, PPPOT-IC to 3500 psi, function LDS.
3. Set CIBP at 8922' MD (50' above top pert) and dump -bail 25' of cement on top of the plug.
4. Make tubing punch at -8770' MD and place 15.8 ppg G cement on both sides of the tubing from
-8816' MD to -7700' MD and test TxIA to 4000 psi.
5. Make tubing cut 5000' MD and circulate the well to clean seawater.
6. Freeze protect the well to 2200' MD with diesel.
7. Set BPV and test.
Proposed Procedure:
8. MIRU Doyon 25
9. Pull BPV. Circulate out freeze protection and circulate well to 8.5 ppg seawater.
10. Set a TWC and test from above to 3500 psi for 5 minutes and from below to 3500 psi for 30
minutes.
11. Nipple down tree. Nipple up and test BOPE to 4000 psi
12. Pull TWC with lubricator.
13. RU and pull the 4-1/2" tubing from the pre -rig jet cut at 5000' MD.
14. RIH with clean out assembly down to top of tubing stub.
15. Rig up E-line and GR/CCL/USIT log from tubing stub to surface confirm if cement on back -side of
the 9-5/8" casing, a competent sand for a KOP, casing collar locations and to confirm the general
condition of the 9-5/8" casing above the planned KOP.
16. Set EZSV on E-line at -4400' MD and pressure test to 4000 psi.
17. PU 9-5/8" whipstock and RIH to the top of the EZSV.
18. Shear -off mills and hang -off the drill -string on a storm packer.
19. Change -out the 9-5/8" pack -off and test.
20. Swap the well to the planned milling fluid and mill a window in the 9-5/8" casing plus 20' of
formation.
21. Perform a LOT and POOH for drilling BHA.
22. MU an 8-1/2" drilling BHA with rock bit on a mud motor GR/Res and RIH to sidetrack the well
23. Dull the bit and POH for a PDC bit on a RSS + MWD and drill 8-1/2" intermediate interval to 7"
casing point at TSAD (may be Shublik present).
24. Circulate well clean, short trip as needed and POH for the 7" drilling liner
25. Change out upper 2-7/8" x 5-1/2" VBR to 7" rams and test to 4000 psi.
26. Run and cement a 7", 26#, L-80 liner (will log cement per AOGCC injector well requirements).
27. Change out upper 7" rams to 2-7/8" x 5-1/2" VBR and test to 4000 psi.
28. MU a 6-'/s" drilling assembly with mud motor and insert bit + MWD and RIH to top of the float collar
and test well to 4000 psi prior displacing the well to an 8.5 ppg reservoir drilling in fluid.
29. Drill out shoe and 20' of new formation and perform a FIT.
09-31 D i PTD Page 8 6/21 /2013
30. Drill the 6-1/8" production hole, per directional plan (2 BHA's).
31. Circulate as required at TD prior to a wiper to the shoe and MAD passing as required by
geologist.
32. Trip back to bottom and circulate hole clean and POOH for the production liner.
33. Run and cement a 4-1/2", 12.6#, 13CR production liner from TD to 150' inside the 7" shoe.
34. Set the liner top packer and displace the well to 8.5 ppg seawater.
35. Perforate the well on drillpipe.
36. Run the 4-1/2", 12.6#, 13Cr completion tying into the 4-1/2" liner top.
37. Reverse the well to clean fluids.
38. Drop ball & rod and set the production packer and individually test the tubing to 4000 psi and annulus
to 4000 psi for 30 minutes each.
39. Shear the shear valve in the GLM and confirm circulation.
40. Set and test a TWC to 250 psi low / 3500 psi high above for 5 minutes each and below to 250 psi
low/3500 psi high for 5 min low/ 30 min high.
41. ND BOPE. NU and test the tree to 5000 psi.
42. Pull TWC. Freeze protect the tubing and IA to—2,200' TVD.
43. Install a BPV.
44. Secure the wellbore and RDMO.
Post Rig Work:
1. Pull ball and rod and RHC plug.
2. Pull shear valve from GLM and install dummy valve.
3. Run SBHPS.
4. Perform full -bore injectivity test (150 bbls).
5. Contingency ASRC flowback and/or fullbore HCL treatment. (Foowback attempted only if SBHPS
and facility situation allows).
6. Contingency CTU cleanout and/or CT acid treatment.
09-31 Di PTD Page 9 6/18/2013
09-31 Di Drilling Critical Issues (POST THIS NOTICE IN THE DOGHOUSE)
I. Well Control / Reservoir Pressures (High GOR Well):
A. An off -set injector well review will be performed 2 months prior to spud to determine which wells will
nee to be SI to drill the production hole on this well.
B. Intermediate Hole: Cretaceous pressure at the KOP is expected to be at a 9.2 ppg EMW.
CM2 is expected to be at a 9.8 ppg EMW.
CM is expected to be at a 10.0 ppg EMW.
HRZ will require a 10.4 ppg mud weight for shale stability.
TSAD is expected to be at a 7.3 ppg EMW.
C. Production Hole: Ivishak is expected to be at a 7.3 ppg EMW.
II. Lost Circulation/Breathing
A. Intermediate Hole — There are no expected fault crossings in the intermediate hole section, however,
lost circulation and/or wellbore breathing can always be considered a possibility in many areas of
GPB.
B. Production Hole — Lost circulation is a risk due to the 4 fault crossings in the production hole,
however, lost circulation has not been a significant problem in this area of the field.
III. Faults
Formation Where Encounter Fault
MD Intersect
TVDss Intersect
Throw Direction
and Magnitude
Uncertainty
Lost Circ
Potential
Zone 2
12,733.0
8,770.0
SE 10'
+/- 150' MD
Low
Zone 2
14,943.0
8,676.0
NW30'
+/- 150' MD
Wd
Zone 2
15,311.0
8,683.0
W 10,
+/- 150' MD
Low
Zone 2
16,382.0
8,704.0
SE 10'
+/- 150' MD
Low
IV. Integrity Testing
Test Point
Test Depth
Test t pe
EMW(lb/gal)
9-5/8" window
20'-50' from the 10-3/4" window
LOT
11.8 ppg minimum
T' shoe
20'-50' from the 7" shoe
FIT
9.0 ppg minimum
VI. Hydrogen Sulfide
DS-09 is considered an H2S site. Recent H2S data from the pad is as follows: V
Well Name H2S Level 'q Readina Date Cnmma_nts
Parent Well (if sidetrack'
#1 Closest SHL Well H2S Leve
#2 Closest SHL Well H2S Leve
#1 Closest BHL Well H2S Leve
#2 Closest BHL Well H2S Leve
#3 Closest BHL Well H2S Leve
#4 Closest BHL Well H2S Leve
Max. Recorded H2S on Pad/Facilit)
Other Relevant H2S Data
(112S alarms from rigs, etc.)
VII. Anti -Collision Issues
09-31C
275 ppm
1/4/2011
09-30
325 ppm
7/12/2010
09-33
140 ppm
3/28/2013
09-05A
800 ppm
10/15/2012
04-03
74 ppm
1/12/2013
11-18
130 ppm
4/23/2013
04-30
100 ppm
3/1/2011
09-29
1200 ppm
7/31/2008
consistently > 500
ppm
The 09-05, 09-05A, 09-14, 09-30, 09-30PB1 and 09-32 wells fail Major Risk. A TCR will be done for each
well and the well will be secured as required to Minor Risk the wells.
CONSULT THE DS-09 PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION.
09-31Di PTD Page 10 6/21/2013
09-31 M AOR Summary (06/10/13)
The following information is provided as it relates to the relevant cement jobs on the 9 wells within
114 mile of the 09-31Di injection well at TSAD. Based upon a review of the individual well files, it is
concluded that all wells within this 114 mile review do have adequate cement/isolation potential on
their respective production casing strings to prevent an annular flow path potentially related to the
planned injection from the proposed 09-31Di well:
09-05A - This well is isolated above TSAD to the upper formations by the original cement job on the 09-05
9-5/8" production casing which was run on 6/14/76. This casing was run to a total depth of 11,284' MD (well
designed to set this casing string above TSAD) and cemented with full returns with 750 sxs (-155 bbls) of
15.8 ppg Class G cement with the planned TOC to be 2645' above the casing shoe (gauge hole calculation).
The cement job on this casing string was pumped on 6/15/76 and pumped with full returns while showing
continued lift pressure to 1250 psi and the plug was "bumped" placing the estimate TOC at —8639' MD.
The 09-05A RST kicked -off from this well at 10,740' MD placing this KOP, —2101' below the TOC on the
original 09-05 9-5/8" cement job.
04-15i - This was a long string well where the 9-5/8" casing was set at the final well TD 10,650' MD and the
original cement job included a plan to place a —3000' column of 15.8 ppg G cement above the casing shoe
placing the TOC —500' above TSAD + 450 sxs cement (-1700' gauge hole volume) = 2200' MD above
TSAD. The actual cement job was performed on 05/27/78, where 1000 sxs of Class G cement was pump
around this casing string with no mention of any losses or not bumping the plug, therefore, the TOC should
be at —6950' MD.
09-30 - This well was a 3 string well where the 9-5/8" casing was planned to be set above the TSAD at
—11,588' MD and cemented with 500 sxs 15.9 Class G cement (2000' of gauge hole / —111 bbls of cement).
As the casing was run to 11,748' MD and the cement job was actually pumped on 08/27/85, 500 sxs of
Class G cement were pumped with full returns and the plug was bumped. Therefore, the estimated TOC on
the 9-5/8" casing string on this well is at '9748' MD.
04-03 - With the well TD'ed at 10,715' MD, the 9-5/8" production casing was run to a final depth of 10,669'
MD on 04/04/71 and cemented with 1100 sxs of Class G cement (-222 bbls of cement providing —4000' of
coverage based upon a gauged hole) bringing the estimate TOC to —6715' MD on the 1st stage of this
cement job. The plug was bumped on this cement job and there were no comments regarding any fluid
losses during this cement job. (NOTE: After this 1st stage cement job, a 2nd stage cement job was also
pumped using a DB tool at 6013' MD where another 680 sxs of Class G cement were pumped.)
09-32i - This well was drilled setting the 9-5/8" production casing at 10,672' MD placing the shoe above the
TSAD per the original well plan. Also, per the wellplan, this casing string was cemented with 500 sxs of
Class G cement (-102 bbls) providing —2000' of coverage using a gauge hole calculation. There were no
problems associated with this cement job with the plug bumping at 6492 strokes and 3000 psi with no record
of any losses.
09--39i - This well was designed to set the 9-5/8" production casing —10' TVD above the TSAD and to be
cemented with 410 sxs (-83 bbls cement providing —1500' of pipe coverage using gauged hole
calculations). The actual 9-5/8" casing string was run on 03/14/91 placing the 9-5/8" shoe at 10,923' MD
and cementing the casing with 500 sxs of 15.8 Class G cement placing the TOC at —8923' MD. The plug
was bumped on this cement job and there is no reference to any fluid losses during the job.
04-30 - This well was planned for the 9-5/8" production casing to be set just above TSAD at 9614' MD and
to be cemented with 500 sxs of Class G cement providing —2000' of coverage using gauge hole
calculations. The actual casing was run on 06/04/85 to 9075' MD and cemented with 500 sxs of Class G
cement placing the estimated TOC at 7075' MD (using gauge hole calculations), bumping the plug with no
report of any fluid losses or any other problems.
11-18 - This well was planned for the 9-5/8" production casing to be run as a long -string to the final well
TD (9678' MD) and cemented with 500 sxs of Class G cement (-2000' of coverage based upon gauged hole
calculations) placing the TOC at —. With the actual 9-5/8" casing string run on 06/25/86 to a final depth of
09-31 Di AOR Page 1 6/11/2013
9654' MD, this casing string was cemented with 800 sxs of Class G cement placing the TOC at —6654' MD
using gauge hole calculations. There were no losses and the plug was bumped on this cement job.
04-13i - The 9-5/8" casing was run as a long -string to the final well TD at 10,826' MD and cemented with
900 sxs of Class G cement providing --3400' of coverage based upon gauge hole calculations placing the
estimated TOC at --7426' MD. The PDS did not indicate any problems or issues associated with this cement
job.
NOTE: For the purpose of this AOR summary, TSAD isolation is considered to be sufficient when a
minimum of 50' of good cement can be calculated/estimated/assumed given the details of the actual
cement job on the pertinent casing string as detailed in the existing records/files for each well.
09-31 Di 1/4 mile Schematic:
f
09-31Di AOR Page 2 6/11/2013
Tlff- 5.1ArUbEV0Y
_ ktf-voy
ACTLMT+OR = A
04M KB fL 54'
BF. ( = 23.0'
V" 4f0O 5 i12 TM I M, 3C
Ma Angle ! .... _ 9fi' L-E0, .0232 by/,
O�unAOa 9527
-_.�.-..._ __._._.__......, _. ... 0-4A9T
DatunlVD= 8800'
13-YW CSti, 720, L-80 SUIT. D - 12.349i333'
(FIRST 2 JOINTS AREK-66)
Minimum ID - 2.387" @ 8822'
3-1/2" X 2-718" LNR_XO
@KR G2 TTcBACK SB.V , D = 7.50' 8234'
9-5W X T BKR PKR 8 LNR HM D> 6.190` 8241'
9-W CSa 47*, L-90 M KD - 8.681- 1-4^84W �—
F---;—S—IerCSGMLLOUTWt4WW(Og-31A) 34W
4-117' TSG, 12.8M, 13CRNSCT,
.0152 bpf, D a 3.958'
7" LNR. 290. 13CR-80 NSCG
.0371 bpf, V-GA84'
PERFCRAnON SUkAWRY
RffLOG., SPERRY-SUtM1DLOG CNON27M
ANGLE AT TOP PEW: 30" Q 8977
Now: Refer 9a Pro&wAbn OB for Irsmrical pert dab
SIZE
SPF
HTERVAL
CptVSw
SHOT
9OZ
2'
6
8972 - 8982
0
11124M
2'
6
8807 - 8999
O
11t20"
2'
6
OD04-9104
O
1011601
2'
6
9100 - 9114
0
11P18Rl8
2'
6
9132 - 9142
0
11JM6
2-18'
4
9Q08 - 9228
C
10116101
2-11W
4
9236 - 9254
C
10tt6101
2'
4
9M - 9287
C
101t6101
2-IlAr
4
9710 - 9785
C
05/28t98
2-11V
4
10250-IOM
C
02004197
2-V8'
4
10775-10875
C
IW2196
■
V 9 3 SAFETY NOTES: fGS R{40NIGS AVERAGE 125 ppm
WlIH4ONY"' WILL ANGLE >70'Q921W-4-112'
CHROME T80 3 7' LNR "
3T 5-V7 X 4-1&1 XO. D - 3.95@'
= 3AI2' I
STI
A4)
I TVD
I DEV
TYPE
VLV
LATCH
FORE
DATE
Il
3193
3193
0
TGPD
DW
RK
0
101271M
2
4802
4786
18
TOPD
OW
RK
0
tw7ms
3
5605
5635
23
TGtD
OW
RK
0
03/31M
4
6178
6063
23
TGFD
OW
W
0
05/23%
5
6704
650
23
TGPD
DW
RK
0
03/31196
6
MIS
7038
22
TGPD
DIY
RK
0
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7
TM
7530
21
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0
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8
8059
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19
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9
8202
7942
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0
05t23 w
8767' 4-112' SW8 w. D ■
8774'
8818' h117' C437LOY SL.V, D � 3.00
8822' 11 C2' X 2-7t8" LNR X0, D = 2-M
9242' 4-1l2" SWS NP. D = 3.813'
7' LNR MLLOLtT W140OW (09-3IC) 9080' - 9006'
9/ 2-7t8'C0P(10I10A1)
8390'elm 2-Tt8'CISP(071251CO)
94189' 2-7N3' CDP{0;i/28/98)
10000 otrn 2-7t8" COP(09J04197)
10551'elm 2-7t8'Ct9P(tOt1Z
ti—Now Ft#i -2-118' COP
(LOST 0-25-96)
1oe8r
=7
PR DHOE BAY UW
WELL 09-31C
ffla f Pb: ei960640
AR No: 50.029-21396-03
SM 2, TIM R15F- 1587- FSL8998' FWL
BP 8tpwa ioe (Alaska)
09-31 Di PTD Page 11 6/18/2013
WEVOY
C EHEEE TDG & LNR
Mix ArVk a 96w MiL-- -z P&W HESX NP. ID=3,glr
2 JOINTS ARE
Minknum ID
FERFOFAtTION SUMMARY
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AR No: 50-029-21396-04
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Company:
North America - ALASKA - BP
Project:
Prudhoe Bay
Reference Site:
PB DS 09
Site Error:
0.00usft
Reference Well:
09-31
Well Error:
0.00usft
Reference Wellbore
Plan 09-31D
Reference Design:
Plan #5c 09-31 D
BP
Anticollision Report
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Output errors are at
Database:
Offset TVD Reference:
Site PB DS 09
09-31 D plan @ 60.60usft (D25 plan)
09-31 D plan @ 60.60usft (D25 plan)
True
Minimum Curvature
1.00 sigma
EDM R5K - Alaska PROD - ANCP1
Offset Datum
Reference
Plan #5c 09-31 D
Filter type:
GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
Interpolation Method:
MD Interval 5.00usft Error Model: ISCWSA
Depth Range:
4,100.00 to 17,533.91usft Scan Method: Tray. Cylinder North
Results Limited by:
Maximum center -center distance of 10,000.00usft Error Surface: Elliptical Conic
Survey Tool Program
Date 6/12/2013
From
To
(usft)
(usft) Survey (Wellbore)
Tool Name
Description
106.60
4,306.60 09-31 Srvy 1 BOSS -GYRO (09-31)
BOSS -GYRO
Sperry -Sun BOSS gyro multishot
4,306.60
4,400.00 Plan #5c 09-31 D (Plan 09-31 D)
BOSS -GYRO
Sperry -Sun BOSS gyro multishot
4,400.00
4,700.00 Plan #5c 09-31 D (Plan 09-31 D)
INC+TREND
Inclinometer + known azi trend
4,700.00
6,200.00 Plan #5c 09-31 D (Plan 09-31 D)
MWD
MWD - Standard
4,700.00
12,198.00 Plan #5c 09-31 D (Plan 09-31 D)
MWD+IFR+MS
MWD + IFR + Multi Station
12,198.00
13,700.00 Plan #5c 09-31 D (Plan 09-31 D)
MWD
MWD - Standard
12,198.00
17,533.20 Plan #5c 09-31 D (Plan 09-31 D)
MWD+IFR+MS
MWD + IFR + Multi Station
611212013 11:39:24AM Page 2 of 4 COMPASS 5000.1 Build 61
BP
Anticollision Report
Company:
North America - ALASKA- BP
Local Co-ordinate Reference:
Site PB DS 09
Project:
Prudhoe Bay
TVD Reference:
09-31 D plan @ 60.60usft (D25 plan)
Reference Site:
PB DS 09
MD Reference:
09-31 D plan @ 60.60usft (D25 plan)
Site Error:
0.00usft
North Reference:
True
Reference Well:
09-31
Survey Calculation Method:
Minimum Curvature
Well Error:
0.00usft
Output errors are at
1.00 sigma
Reference Wellbore
Plan 09-31 D
Database:
EDM R5K - Alaska PROD - ANCP1
Reference Design:
Plan #5c 09-31 D
Offset TVD Reference:
Offset Datum
Summary
Reference
Offset
Centre to
No -Go
Allowable
Measured
Measured
Centre
Distance
Deviation
Warning
Site Name
Depth
Depth
Distance
(usft)
from Plan
Offset Well - Wellbore - Design
(usft)
(usft)
(usft)
(usft)
PB DS 04
04-03 - 04-03 - 04-03
15,408.45
9,970.00
672.55
316.73
378.04
Pass - Major Risk
04-06 - 04-06 - 04-06
13,920.34
9,735.00
1,837.89
245.79
1,633.95
Pass - Major Risk
04-13 - 04-13 - 04-13
17,506.11
10,845.00
976.54
703.83
288.94
Pass - Major Risk
04-15 - 04-15 - 04-15
13,676.35
10,685.00
928.30
403.74
543.12
Pass - Major Risk
04-30 - 04-30 - 04-30
15,464.18
10,125.00
734.35
309.69
425.32
Pass - Major Risk
04-30 - 04-30PB1 - 04-30PB1
15,259.05
10,100.00
697.77
300.10
399.36
Pass - Major Risk
04-32 - 04-32A - 04-32A
14,879.20
11,040.00
1.229.36
356.25
882.38
Pass - Major Risk
04-32 - 04-32A - Plan #1
14,900.00
11,016.00
1,309.83
358.91
954.01
Pass - Major Risk
04-45 - 04-45 - 04-45
14,131.62
9,755.00
1,941.51
268.89
1,715.06
Pass - Major Risk
04-47 - 04-47 - 04-47
15,764.29
10,595.00
1,368.51
276.82
1,121.10
Pass - Major Risk
PB DS 09
09-05 - 09-05 - 09-05
12,391.79
12,855.00
555.35
40.20
554.15
Pass - Minor 1/200
09-05 - 09-05A - 09-05A
12,331.42
12,880.00
360.08
45.68
317.27
Pass - Minor 1/200
09-14 - 09-14 - 09-14
4,765.27
5,225.00
118.14
56.69
65.41
Pass - Minor 1/200
09-16 - 09-16 - 09-16
5,283.04
5,885.00
694.12
230.15
468.59
Pass - Major Risk
09-29 - 09-29 - 09-29
8,039.66
7,520.00
616.11
507.45
109.90
Pass - Major Risk
09-30 - 09-30 - 09-30
13,287.49
12,135.00
974.41
53.85
969.92
Pass - Minor 1/200
09-30 - 09-30PB1 - 09-30PB1
11,354.31
10,045.00
1,090.37
63.50
1,089.28
Pass - Minor 1/200
09-31 - 09-31 - 09-31
4,311.60
4,305.00
0.00
0.91
-0.91
FAIL- NOERRORS
09-31 - 09-31A- 09-31A
4,310.60
4,305.00
0.00
1.07
-1.07
FAIL- NOERRORS
09-31 - 09-31 B - 09-31 B
4,310.60
4,305.00
0.00
0.74
-0.74
FAIL - NOERRORS
09-31 - 09-31C - 09-31C
4,310.60
4,305.00
0.00
0.91
-0.91
FAIL- NOERRORS
09-32 - 09-32 - 09-32
9,666.66
9,000.00
593.08
836.29
-235.16
FAIL - Major Risk
09-33 - 09-33 - 09-33
4,100.00
4,185.00
492.61
92.78
424.55
Pass - Major Risk
09-33 - 09-33A- 09-33A
4,100.00
4,185.00
492.61
92.78
424.55
Pass - Major Risk
09-34 - 09-34 - 09-34
4,100.00
4,200.00
650.03
100.81
580.65
Pass - Major Risk
09-34 - 09-34A - 09-34A
4,101.38
4,195.00
651.28
101.16
581.72
Pass - Major Risk
09-35 - 09-35 - 09-35
4,102.07
4,240.00
815.59
59.25
762.55
Pass - Major Risk
09-35 - 09-35A- 09-35A
4,100.25
4,235.00
814.46
59.25
761.43
Pass - Major Risk
09-38 - 09-38 - 09-38
7,858.76
6,830.00
1,631.85
188.67
1,466.31
Pass - Major Risk
09-39 - 09-39 - 09-39
13,564.45
11,500.00
752.92
335.25
431.65
Pass - Major Risk
09-41 - 09-41 - 09-41
4,100.00
5,005.00
2,759.80
107.39
2,673.26
Pass - Major Risk
09-42 - 09-42 - 09-42
4,100.43
4,600.00
1,967.16
87.03
1.892.43
Pass - Major Risk
09-42 - 09-42A- 09-42A
4,100.43
4,600.00
1,967.16
86.82
1,892.65
Pass - Major Risk
09-42 - 09-42APB1 - 09-42APB1
4,100.43
4,600.00
1,967.16
87.03
1,892.43
Pass - Major Risk
09-49 - 09-49 - 09-49
4,100.00
4,305.00
808.54
80.77
732.16
Pass - Major Risk
PB DS 11
11-01 - 11-01 - 11-01
16,863.29
8,270.00
3,511.62
547.38
3,083.45
Pass - Major Risk
11-01 - 11-01A- 11-01A
16,863.29
8,270.00
3,511.62
547.38
3,083.45
Pass - Major Risk
11-01 - 11-01A- 11-01A
17,533.91
32.60
8,797.33
228.95
8,721.25
Pass - Major Risk
11-12 - 11-12 - 11-12
17,533.91
9,630.00
4,523.93
573.20
4,000.51
Pass - Major Risk
11-16 - 11-16 - 11-16
13,516.32
10,260.00
4,033.36
1,073.48
3,020.32
Pass - Major Risk
11-16 - 11-16PB1 - 11-16PB1
13,516.32
10,260.00
4,033.36
1,073.48
3,020.32
Pass - Major Risk
11-17 - 11-17 - 11-17
16,250.35
9,020.00
2,283.61
532.68
1,802.29
Pass - Major Risk
11-17 - 11-17A- 11-17A
16,251.05
9,015.00
2,283.34
532.56
1,802.29
Pass - Major Risk
11-17 - 11-17A- 11-17a wp05
16,251.05
9,015.00
2,283.34
532.56
1,802.29
Pass - Major Risk
11-18 - 11-18 - 11-18
17,502.58
8,995.00
761.12
353.02
423.40
Pass - Major Risk
11-22 - 11-22ALl - 11-22ALl
17,410.87
11,824.00
4,862.43
313.58
4,572.78
Pass - Major Risk
611212013 11:39:24AM Page 3 of 4 COMPASS 5000.1 Build 61
Ferguson, Victoria L (DOA)
From: Rose, John G (ASRC) <John.G.Rose@bp.com>
Sent: Thursday, July 11, 2013 9:38 AM
To: Ferguson, Victoria L (DOA)
Subject: RE: PBU 09-31D(PTD213-092)
Follow Up Flag: Follow up
Flag Status: Flagged
Victoria,
In response to your questions, please note the following:
1. As we will need to test this Prudhoe injector to 4000 psi, we'll also be testing our BOP's to 4000 psi.
2. To Minor Risk a well that has failed Major Risk analysis for anti -collision, the consequences of a collision with
that well "cannot include a risk to personnel or the environment", therefore, it becomes basically a financial
decision to Minor Risk the well for drill -by. As for the 6 wells that currently fail Major Risk AC on the current
directional plan (135c), only 2 of the wells are currently active (09-14 & 09-32 injectors) with the other 4 being
P&A'ed or currently SI. Therefore, to minor risk these wells for drill -by, they will be shut-in and secured with
deep-set plugs per our "Subsurface Close Proximity" SOP to eliminate any well control concerns which may be
associated with a potential collision.
Let me know if you have any other questions or concerns as they may relate to the Sundry or PTD for this well. Thanks -
jr
John G. Rose
BP Staff Engineer
Anchorage, AK
rosel1@bp.com
907/564-5271 Office
907/748-5223 Cell
907/243-8813 Home
From: Ferguson, Victoria L (DOA)[ma iIto: victoria.ferguson0)alaska.4ov]
Sent: Wednesday, July 10, 2013 4:32 PM
To: Rose, John G (ASRC)
Subject: PBU 09-31D(PTD213-092)
John,
In the procedure the BOP test pressure is stated as 4000 psi but under "well control" the BOP test pressure is 3500 psi.
BOP test pressure in 09-31C sundry is also 3500 psi. Please clarify.
What are your plans for major risk close approach wells.
Thanx,
Victoria
Victoria Ferguson
Senior Petroleum Engineer
State of Alaska
Oil & Gas Conservation Commission
333 W. 7th Ave, Ste 100
TRANSMITTAL LETTER CHECKLIST
WELL NAME: Za
PTD: / L_
Development / Service _ Exploratory _ Stratigraphic Test _ Non -Conventional
FIELD: POOL:E�l�x
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.
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce / inject is contingent upon issuance of a
Spacing Exception
conservation 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 Commission must be in no
Dry Ditch Sample
greater 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
Commission 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 5/2013
WELL PERMIT CHECKLIST Field & Pool PRUDHOE BAY, PRUDHOE OIL - 640150
Well Name: PRUDHOE BAY UNIT 09-31D Program SER Well bore seg
PTD#:2130920 Company
BP EXPLORATION (ALASKA) INC
Initial Class/Type
SER / PEND GeoArea 890 Unit 11650 On/Off Shore On Annular Disposal
Administration 1
Permit fee attached
NA
2
Lease number appropriate
Yes
Surface location in ADL 028327, top prod interval in ADL 028328, TD in ADL 028325.
3
Unique well name and number
Yes
4
Well located in a defined pool
Yes
PRUDHOE BAY, PRUDHOE OIL POOL - 64015, governed by CO 341D
5
Well located proper distance from drilling unit boundary
Yes
CO 341 D, Rule 2: There shall be no restrictions as to well spacing except that no pay shall be
6
Well located proper distance from other wells
Yes
opened in a well closer than 500 feet to the boundary of the affected area.
7
Sufficient acreage available in drilling unit
Yes
8
If deviated, is wellbore plat included
Yes
9
Operator only affected party
Yes
10
Operator has appropriate bond in force
Yes
11
Permit can be issued without conservation order
Yes
Appr Date 12
Permit can be issued without administrative approval
Yes
13
Can permit be approved before 15-day wait
Yes
SFD 6/27/2013
14
Well located within area and strata authorized by Injection Order # (put 10# in comments) (For
Yes
Eastern Operating Area is governed by AIO 4E
15
All wells within 1/4 mile area of review identified (For service well only)
Yes
PBU 09-05A, 04-15, 09-30, 04-03, 09-32, 09-39, 04-30, 11-18, and 04-13
16
Pre -produced injector: duration of pre -production less than 3 months (For service well only)
No
17
Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)
NA
18
Conductor string provided
NA
Conductor set in PBU 09-31
Engineering 19
Surface casing protects all known USDWs
NA
Surface casing set in PBU 09731
20
CMT vol adequate to circulate on conductor & surf csg
NA
Surface casing set and fully cemented
21
CMT vol adequate to tie-in long string to surf csg
NA
22
CMT will cover all known productive horizons
Yes
Well will be completed with 7" Intermediate liner and 4-1/2" production liner both cemented.
23
Casing designs adequate for C, T, B & permafrost
Yes
24
Adequate tankage or reserve pit
Yes
Rig has steel tanks; all waste to approved disposal wells
25
If a re -drill, has a 10-403 for abandonment been approved
Yes
PTD 196-064,-Sundry 313-327
26
Adequate wellbore separation proposed
Yes
Proximity analysis performed. Wells 09-05, 09-05A, 09-14, 09-30, 09-30PB1&09-32 wells fail major risk.
27
If diverter required, does it meet regulations
NA
Appr Date
28
Drilling fluid program schematic -& equip list adequate
Yes
Max formation pressure is 3313 psi@8609' TVD(EMW-7.4) Will drill w/ 8.5-10.4 ppg
VLF 7/10/2013
29
BOPEs, do they meet regulation
Yes
30
BOPE press rating appropriate; test to -(put psig in comments)
Yes
MPSP is 2452 psi; will test BOPs to 3500 psi
31
Choke manifold complies w/API- RP-53 (May 84)
Yes
32
Work will occur without_ operation shutdown
Yes
33
Is presence of H2S gas probable
Yes
H2S measures required_
34
Mechanical condition of wells within AOR verified (For service well only) - -
Yes
35
Permit can be issued w/o hydrogen sulfide measures
No
DS 09 wells are H2S-bearing. H2S measures are required.
Geology
36
Data presented on potential overpressure zones
Yes
Interval from CM2 to top Sadl_erochit expected-9.8-10.0 ppg EMW; will be drilled with 9.8-10.4 ppg mud.
Appr Date
37
Seismicanalysisof shallow gas zones -
NA-
Productive- interval expected to be 7.3 ppg E-MW; will be drilled with 8.5 - 9.1 -ppg mud.
SFD 6/27/2013
38
Seabed condition survey -(if off -shore)
NA- - - -
- - -
39
Contact name/phone for weekly. progress reports- [exploratory only] - - - -
- - _ - NA_
Geologic Engineering Pu '
Commissioner: Date: Commissioner: Date Com Date
O1 S -7 J Z5 13�6-��
