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Re: V-201Ai Surface Casing Leak Procedures
Subject: Re: V-201Ai Surface Casing Leak Procedures
From: Thomas Maunder <tom maunder@admin.state.ak.us>
Date: Mon, 19 Mar 2007 11:15:10 -0800 ~ ~`~ ~ ~ ~ ~~ _ ~~'~ ~'
To: "Peltier; Brandon" <Brandon.Pelter@p.com>
Thanks Brandon,
I will look forward to receiving the updated work proposal. One thing to note, by the convention the
Commission uses all the work done so far is "in" V-201. V-201A will exist when the window is milled.
Good luck,
Tom Maunder, PE
AOGCC
Peltier, Brandon wrote, On 3/19/2007 11:07 AM:
Tom
Here is what happened on V-201Ai:
Event Date
Tech Package and SOR issued to Partners 2/2/07
Approve AFE electronically 2/2/07
Develop and submit pre-rig work request to Wells Group 2/6/07
Develop and submit Sundry to AOGCC 2/6/07
Develop and submit Permit to Drill 2/8/06
Sundry approved by AOGCC 2/13/07
Partners fully approve AFE 2128107
Start pre-rig work 2/17/07
P&A (after sundry and partner approval) 3/3/07
Found SC leak during pre-rig OA PT to 2000 psi. OA bled from 2000
psi to 100 psi in 15 minutes. Could smell and see diesel between 9-5/8"
x 20". 3/6/07
Attempt 1St circ out. RU to OA and pump 11 bbls of 9.8 brine and 7
bbls diesel down OA before fluid leak into cellar. Stop operation and
try at later date. 3/8/07
Rig release from W-210 -stand by for pre-rig work on V-201Ai. 3/9/07
Attempt 2nd circ out. RU to pump down OA, 1 to 1 returns taken from
4" conductor ports. Cannot bullhead 9.8 brine down OA. 3/12/07
Divert rig to V-121
Brandon Peltier
BP Exploration (Alaska), Inc.
Operations Drilling Engineer
GPB Rotary Drilling
(907) 564-5912 (Direct)
(907) 748-7838 (Mobile)
1 of 3 4/6/2007 1:54 PM
Re: V-201Ai Surface Casing Leak Procedure
Brandon.Peltier~bp.com
From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us]
Sent: Thursday, March 15, 2007 11:11 AM
To: Peltier, Brandon
Cc: Tirpack, Robert B
Subject: Re: V-201Ai Surface Casing Leak Procedures
Brandon and Rob,
Since the need for V-121 was accelerated, I understand that the situation on V-201 had changed.
I'd appreciate a summary of the recent activities on V-201.
Thanks in advance.
Tom Maunder, PE
AOGCC
Thomas Maunder wrote, On 3/12/2007 8:30 AM:
Brandon,
Interesting. CPAI has experienced shallow surface casing leaks on a number of wells. Their
repair method has been to excavate and weld external sleeves on the surface casing. Your case is
somewhat different since there is a redrill planned for the well. Please note that the following
comments are observations on the document that you forwarded. They are NOT directions on how
to proceed. BP has much greater knowledge regarding the condition of the well and the best way
to propose and conduct repair operations.
I note that there are several activities you propose that would seem to need/require surface casing
integrity in order to accomplish successfully and safely. Early in the work, you plan to bullhead
the OA with KWF. Based on the information you have provided regarding the attempt to pressure
test the OA, it would appear that the OA may be plugged. It is not clear that it was possible to
inject any fluid and it seems if the intent was to pressure test the OA that there was an
expectation/prior knowledge that injection would not be possible. Later in the procedure advise is
given regarding catching/cleaning any spills into the cellar. That advise would seem to apply
throughout the planned operations. Have you considered connecting lines to 4" outlet holes on the
conductor?
Call or message with any questions.
Tom Maunder, PE
AOGCC
Peltier, Brandon wrote, On 3/9/2007 1:56 PM:
Tom
On Tuesday morning a very shallow leak was discoved in the surface casing of V-201 Ai. I have
attached a summary of events and our plan forward to fix this leak. Please review the new
procedures, which are highlighed in blue.. The overall scope of the work is to still eventually drill
the sidetrack, but with a slightly more complicated decomplete. Please call me any time if you
have questions.
2 of 3 4/6/2007 1:54 PM
V-201 Ai Surface Casing Leak Repair Procedure:
During the pre-rig operations on V-201 Ai, a
surface casing leak was discovered. The
leak was found after the well had been P&A'd
and while the Wells Group was conducting
pressure tests of the tubing and cement plug,
the IA, and the OA. The tubing and IA
pressure tested successfully. When 2000 psi
was applied to the OA, the pressure bled
down and gas and diesel was venting out of
the conductor ports.
The leak is believed to be shallow, not more
than a few feet below the cellar floor.
Diagnostics has shown that the leak is most
likely at or just below the collar on the 4' pup
joint. A thread leak or corrosion leak is
suspect because the TOC is -5.5' below the
flutes, which would have allowed water to
corrode this portion of the casing. More
diagnostic work is being conducted pre-rig.
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As part of the pre-rig work the TxIA will be filled with kill weight fluid by circulating through the
tubing cut. The 9.8 ppg brine will be bull headed down the OA for column of KWF. The OA valve
will be lined up to a bleed tank to allow for pressure and flow monitoring.
Once the rig moves on, the tubing and 7" casing will be pulled as part of the pre-approved sundry
operations. After pulling the 7" casing, a cement plug will be placed across the open hole and
into the surface casing shoe. This plug will be tested to 2000 psi to ensure integrity. A storm
packer will be placed at 2000' MD as a second mechanical barrier.
See the detailed procedure below for full details:
V-201Ai - De-complete, Drill, and Complete Procedure Summary -Revision 1: Surface
Casing Leak Procedures.
Pre-Rig Work:
1. R/U slickline. Drift 3.5" tubing (Min ID: 2.812"). Tag and record PBTD below WLEG. Note:
Jet pump pulled and sliding sleeve closed 11/18/04. Removed OGLV and install DGLV
9/23/03. No SSSV installed.
2. PPOT - TxIC. Function test all LDS and repair as needed.
3. Fluid pack the T x IA
4. P&A perfs in 7", 26# casing from top of fill (4854' 1/7/05) to 4350', which is 400' above the top
perforation. RIH with coil tubing to PBTD, lay in 30 bbls of 15.8 ppg cement. Obtain
squeeze, but do not exceed a BHP of 2900 psi at top of perfs. Notes: Well has been frac'ed.
Assuming a water gradient to surface from the top pert and 900 psi applied fracture pressure
(0.45"4400+900=2900psi) gives a max BHP of 2900 psi. If the fracture does open, there is a
good chance the well will go in a vacuum. Cement Calc:.038278 bbl/ft x 504' = 19.3 bbls
hole volume + 5 bbls into perfs + 5 bbls extra.
5. Pressure test the TxIA to 3,500 psi for 30 minutes, after WOC. Pressure test the OA to 2000
psi. Bleed all pressures to zero.
6. R/U slickline to run a full bore drift and tag the TOC.
7. R/U e-line to jet cut the 3.5", 9.3# L-80 tubing in the middle of the 2nd 10' pup joint above the
packer. Estimated cut depth at 4062' md.
8. Circulate the TxIA to seawater through the cut. Freeze protect the TxIA w/ diesel to 2500'
TVD (2700' MD)
9. Set BPV in the tubing hanger and test, secure well.
10. Remove wellhouses and level the pad as needed. Provide well prep costs on hand over
form.
11. Bullhead 9.8 ppg brine down OA. Monitor OA pressure. Hook up line from OA valve to bleed
tank.
Rig Operations:
1. MIRU Nabors 9ES. Circ out diesel FP. Retest barriers. ND tree and tubing adapter. NU
ROPE and test to 4,000 psi / 2500 psi annular.
2. R/U tubing spear, BOLDS, Pull Hanger.
3. Pull Tubing f/ 4062' and dual control lines. RD tubing handling equipment.
4. MU 7", 26# (ID: 6.276") casing scraper, RIH to the 3.5" tubing stub.
5. CBU, POOH, LD scraper.
6. RU a-line USIT, log 7", find cut point
7. RU, run EZSV on a-line, set at 3150', POOH, RD a-line
8. PU, MU BKR csg cut assy, RIH and cut 7" casing (3101' or Mid joint above TOC). Close bag,
circ wellbore w/ warm brine and detergent. POOH. Note: Potential leak/spill path through
surface casing leak.
9. Spear 7" casing hanger. Pull 7" casing from cut and RD csg equip.
10. RIH w/ 4" DP and place 300' of kick-off cement on top of EZSV, POOH. WOC for
compressive strength and test.
New Procedures for Corrosion leak found at or below collar:
11. RiH with RTTS on 4" DF' to cunflrm location of SC leak. Set RTTS below the 4' pup dnd
across the first full joint of casing. Pressure up to 2000 psi below, then above the RTTS.
Note: Leak expected 5-6' below GL at first 9-5/8" coliar, but could be through casing hanger
or due to corrosion below collar. Have catch pans lining the cellar for fluid that escapes the
4" conductor ports. The cellar is 3' deep from the top of the grating floor. The 20" conductor
is exposed 33" above the gravel floor. Two 4" circulation ports are 1' above the gravel floor.
From the open flutes down to cement is 5'6". See attached schematic.
12. R1H and set storm packer at 2000' MD. Test packer.
13. ND BOP and ND wellhead to expose the 9-5/8" casing hanger. Note: There will be a tested
storm packer, a cement plug and KWF acting as barriers prior to ND the BOP and wellhead.
Retest barriers if necessary. Suck out any brine in the 9-5/8" as necessary to prevent spills.
14. NU 20" Hydril Diverter stack on 20" landing ring. This will allow for returns to the .rig. This
must be spotted pre-rig.
15. PU Baker mechanical cutter and cut 9-5/8" casing 1' below the casing hanger. This will leave
a 3' stub looking up. Remove the cut piece. LD casing cutter.
16. P/U burn shoe, two 30' joints of 16" wash-pipe (enough to swallow the 9-518" stub down to
the collar) string mill, and DP per Baker. RIH and scrape the 20" conductor to the 7" stub.
Reverse well clean with 9.2 ppg brine. Burn down to the collar, pump at high rates to ensure
collar OD is clean. POH.
17. RU e-line for string shot across collar. Fire string shot, RD a-line.
~ ~
18. RIH with Baker back-off tool BHA per Baker fishing rep. Locate across the 2"d collar. Back-
aff 9-518" stub per Baker. POH with back-off tool.
19. PU 2 - 9-518" joints and Baker screw-in sub. Baker-lock the collar to the pin and the exposed
threads on the collar. RIH and screw new collar and joints into the 9-518" pin/box looking up.
Apply appropriate make-up torque. Screw in test sub to top of 9-5/8" joint and test casing to
2000 psi.
20. Fill 9-5/8" x 20" annulus with ~2 bbls of 15.8 G cement
21. Install the emergency slips on the 9-5/8" casing. They will fit into the existing landing ring on
the 20" conductor.
22. Use a Wachs cutter to cut the 9-5/8" above the landing ring. Cut high enough above the
landing ring to Leave room for the slip on bell nipple /well head. Typically 5" of the 9-5/8" will
be visble between the landing ring and the bottom of the bell nipple / wellhead, this space
allows room for welding.
23. Install the slip on FMC bell nipple / wellhead. Weld the outside and inside of the bell nipple
as necessary. Test welds per FMC. Follow the Wellhead Welding Guidelines RP.
24. NU the remainder of the wellhead and test. NU BOPE and test. PU BHA as planned and
drill production hole section.
Continue With Drilling Production Hole:
25. MU 8 3/." drilling assembly with MWD/GR/Res/Azi-Den/Neu/DWOB/DTORQ/PWD and RIH to
kick-off plug. Confirm 4,000 psi cement compressive strength prior to kicking off.
26. Displace over to new 8.8 ppg LSND mud. Drill and kick-off from cement plug. Drill ZO' of
formation and conduct LOT. (V-201 LOT was 14.94 ppq EMW)
27. Drill ahead to Production hole Target TD (250' MD below OBe marker). Circulate BU, back-
ream, then POOH to run casing.
28. Run and cement the 7", 26#, L-80, BTC-M x TC-II production casing. Displace the casing
with seawater during cementing operations. Pressure test casing to 4,000 psi for 30 minutes
at plug bump. Confirm 500 psi cement compressive strength prior to freeze protecting.
Freeze protect the 7" x 9 5/8" annulus.
29. PU DPC guns and RIH w/ 160' of 4.5" Power Jet 4505 5 spf, pert guns with Anadrill LWD
GR/CCL for gun correlation.
30. Space out pert guns by tagging PBTD and utilizing GR/CCL and RA tags in 7" casing. Once
correlated correctly, circulate over to 9.0 ppg brine. Confirm cement compressive strength is
at least 1,000 psi before firing. Perforate OA, OBa, OBb, OBc, and OBd. POOH LD DP and
guns.
31. RU Schlumberger E-line. RIH with gauge ring and junk basket to recover any pert debris.
Repeat until clean to at least 50' below the bottom perforation.
32. Run USIT log following Primary Depth Control procedures as USIT log will be primary depth
control for future well work.
33. Run the 3-'/2", 9.2#, L-80, TCII completion with a 7" x 3-%2" straddle packer assembly, I-wire,
gauges, and injection mandrels. Torque turn TC-II threaded tubing. Top packer must be
within 200' of OA perfs.
34. Run in the lockdown screws and set the packers. Give AOGCC 24 hours notice, then test
the production casing/tubing annulus and tubing to 4,000 psi each. Shear the DCR shear
valve and pump both ways to confirm circulation ability.
35. Install and test FMC TWC. Nipple down the BOPE. NU tree with hydraulic actuator, test to
5,000 psi.
36. Freeze protect the well to 2,500' TVD by first pumping corrosion inhibited brine down the IA
with rig pumps followed by diesel down IA w/ Hot Oiler, taking clean brine returns to surface.
Allow diesel to u-tube into tubing.
•
37. Install BPV in tubing hanger. Install a VR plug in the 7"x 3-'/z" annulus valve and secure the
well. Assure that IA/OA are protected with two barriers.
38. Rig down and move off.
Post-Rig Work:
1. R/U Slickline and pull ball and rod / RHC from the tailpipe.
2. Replace the DCR shear valve with a dummy GLV.
3. Pull dummy valves in injection mandrels and replace with injection valves.
4. Pull VR plug.
5. Install wellhouse and flowlines.
__ __
SARA}f P,4LIN, GOVERAIOR
~~ ®~ ~~ 333 W. 7th AVENUE, SUITE 100
~'1®IaTQ~I~s~~-~®~T ~®1~~rIIL+L+j®~
~+ iss~ali~ is A~ -7-7 ANCHORAGE, ALASKA 99501-3539
PHONE (907) 279-1433
FAX (907) 276-7542
Robert Tirpack
Senior Drilling Engineer
BP Exploration (Alaska) Inc.
P.O. Box 196612
Anchorage, AK 99519-6612
Re: Prudhoe Bay Field, Orion Oil Pool, PBU V-201Ai
BP Exploration
Permit No: 207-024
Surface Location: 4838' FSL, 1775' FEL, SEC. 11, T11N, R11E, UM
Bottomhole Location: 1362' FSL, 1540' FEL, SEC. 02, T11N, R11E, UM
Dear Mr. Tirpack:
Enclosed is the approved application for permit to drill 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. When providing notice for a
representative of the Commission to witness any required test, contact the
Commission's petroleum field inspector at (9(y7j~659-3607 (pager).
Chairman
DATED this day of February, 2007
cc: Department of Fish & Game, Habitat Section w/ o encl.
Department of Environmental Conservation w/o encl.
a'cc~.r_~ v w
STATE OF ALASKA
~ ~ 1 3 2007
AL~ OIL AND GAS CONSERVATION CON~SION ~~
PERMIT TO DRILL Alaska Oil & Gas Cons. Commission
20 AAC 25.005
Anrhorage
1 a. Type of work
^ Drill ®Redrill
^ Re-Entry 1 b. Current Well Class ^ Exploratory ^ Development Gas
®Service ^ Multiple Zone
^ Stratigraphic Test ^ Development Oil ^ Single Zone 1 c. Specify if well is proposed for:
^ Coalbed Methane ^ Gas Hydrates
^ Shale Gas
2. Operator Name:
BP Exploration (Alaska) Inc. 5. Bond: ®Blanket ^ Single Well
Bond No. 6194193 / 11. Well Name and Number:
PBU V-201 Ai ~
3. Address:
P.O. Box 196612, Anchorage, Alaska 99519-6612 6. Proposed Depth;
MD 5813 ~ TVD 4923 12. Field /Pool(s):
Prudhoe Bay Field / Orion
4a. Location of Well (Governmental Section):
Surface:
4838' FSL
1775' FEL
SEC
11
T11 N
R11 E
UM ~ 7. Property Designation:
ADL 028240 ~ Schrader Bluff
,
,
.
,
,
,
Top of Productive Horizon:
1136' FSL, 1540' FEL, SEC. 02, T11 N, R11 E, UM ~ 8. Land Use Permit: 13. Approximate Spud Date: J
March 15, 2007
Total Depth:
1362' FSL, 1540' FEL, SEC. 02, T11N, R11E, UM / 9. Acres in Property:
2560 ~ 14. Distance to Nearest Property:
11,215'
4b. Location of Well (State Base Plane Coordinates):
Surface: x-590526 y-5970085 Zone-ASP4 10. KB Elevation Plan
(Height above GL): g2.1 feet 15. Distance to Nearest Well Within Pool:
712'
16. Deviated Wells: Kickoff Depth: 3075 feet
Maximum Hole An le: 61 de rees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035)
Downhole: 2230 Surface: 1737
18 sin P r m: S cifications To - in D th -Bottom uanti of em nt c.f. or sacks
Hole Casin Wei ht Grade Cou lin Len th MD TVD MD TVD includin sta a data
8-3/4" 7" 26# L-80 TC-II / BTC-M 5813' Surface Surface 5813' 4923' 320 sx Class 'G'
19. PRESE NT WELL CONDITION SUMMARY (To be completed for Redrill and Reentry Operations)
Total Depth MD (ft):
5270 Total Depth TVD (ft):
4892 Plugs (measured):
None Effective Depth MD (ft):
5157 Effective Depth TVD (ft):
4785 Junk (measured):
None
'Casing - Length:. ize ement Volume -MD D
Conductor /Structural 107' 34" x 20" 260 sx Arcticset A rox. 1 7' 107'
Surface 2973' 9-5/8" 596 sx AS III Lite 244 sx Class'G' 3001' 2751'
Intermediate
Produ tion 5231' 7" 28 sx CI s 5257' 4 80'
Liner
Perforation Depth MD (ft): 4750' - 4989' Perforation Depth TVD (ft): 4592' -4499'
20. Attachments ®Filing Fee, $100 ^ BOP Sketch ®Drilling Program ^ Time vs Depth Plot ^ Shallow Hazard Analysis
^ Property Plat ^ Diverter Sketch ^ Seabed Report ®Drilling Fluid Program ®20 AAC 25.050 Requirements
21. Verbal Approval: Commission Representative: Date:
22. I hereby certify that the foregoing is true and correct. Contact Brandon Peltier, 56a-5912
Printed Name Robert Tirpack Title Senior Drilling Engineer
Prepared By Name/Number:
Si nature ~.~~=y%, ~ Phone 564-4166 Date ~ /1 `~' 'r" Terrie Hubble, 564-4628
Commission Use Onl
Permit To Drill
Number:,~0 .0 API Number:
50-029-23054-01-00 Permit Appr val See cover letter for
Date: other re uirements
Conditions of Approval: /
If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained shales:
`~'' Sig ~~~.~ ~~~`\~~ \ ~ ~ Samples Req'd: Yes ~ No Mud Log Req'd: ^ Yes No
`C ~ ` HZS Measures: Yes ^ No irecf nal Survey Req'd: Q~ Yes ^ No
Other: ~ ~~~~~E OS~~6 C~~ ~ G {~5 ~ ~. G.C.LCs~ "".i' ~t~ ~ ~\
~ ~~ `~T~ ~ 5~'
~~ff APPROVED BY THE COMMISSION
Date ~^QC '"0 ,COMMISSIONER
Form 10-401 Revised 12/20,5 ~ ~ ~ ~ R ' ~ t V ~ / ~. Submit In Duplicate
• •
Well Name: V-201 Ai
De-complete, Drill, and Complete Plan Summary
T e of Well service / roducer / injector : Injector
Tar et X Y Z TVDss Townshi Ran a Section FSL FEL
Surface As-Built 590526 5970085 0 11 N 11 E 11 4838 1775
Tar et Start: To OA 590740 5971665 4330 11 N 11 E 2 1136 1540
BHL: Below OBe 590737 5971891 4841 11 N 11 E 2 1362 1540
AFE Number: N/A API Number: 50-029-23054-
Estimated Start Date: March 15, 2006 O eratin da s: 13 Ri Nabors 9ES
TMD 5813' TVD rkb: 4923' RKB/GL 28.5'/53.6' RTE 82.1'
Well Design: USH Grassroots Orion Injector
3-'/z", L-80, TC-II, multi acker, zonal injection, and zonal monitorin com letion
Planned Status: Proposed Sidetrack from existing injector V-201 i
General Well Information:
Estimated BHP: 2230 psi (8.7 ppg EMW) at 4923' TVD
Estimated BHT: 85 deg F at 4923' TVD
V-201 i Well History and Information:
Current Well Status: The V-201 i injection well was originally ahydraulically-fractured, conventional production
well which was converted to injection service in February, 2005 to support the heel sections of the V-202 and V-
204 multilateral production wells. Because V-201 i was not originally designed as an injection well, the V-201 i
well completion and location relative to the V-202 production well was not optimal, and a rapid water
breakthrough occurred through the fractured V-201 i OA sand to the V-202 production well. This breakthrough
occurred within a few weeks after V-201 was converted to injection. V-201 i was shut-in in mid March, 2005 and ~
has not been put back on injection service since then. Due to the lack of mechanical zonal isolation in this well,
and its fractured status, there is an open conduit between V-201 and V-202 that will not allow normal waterflood
injection, and there are no wellwork remedial options available to return V-201 i to injection service.
Proposed Sidetrack: V-201 Ai will be a sidetrack well kicked off from below the surface casing shoe of the
existing Orion injection well V-201 i. Before the rig moves on, the existing well needs to be plugged and
abandoned and prepared for the rig. This will be accomplished by placing cement across the existing
perforations and cutting the 3.5" tubing. When the rig moves onto the well, the tubing will be pulled, the 7"
casing cut and pulled, and the well will be sidetracked. New 7" casing will be run and cemented in the 8.75"
hole section and a 3.5" completion will be run in the new well bore.
Information:
Well Name:
API Number:
TD:
Well Type:
Current Status
BHP:
BHT:
V-201i
50-029-23054-00
5257' MD
Injector
Shut in
1650 psi C«~ 44000' TVDss
85° F @ 4400' TVDss
V-201 Ai Permit to Drill Page 1
• •
Current Mechanical Condition:
Tubing: 3.5", 9.3#, L-80. See current schematic for jewelry.
Maximum Angle: 36° at 2380' MD
Max Dogleg of interest: 7.0°/100' at 3144' MD
Tubing. Spool: FMC 11" 5M Gen 5
Tubing. Hanger: FMC 11" x 3-1/8"
Tubing. Head Adapter: FMC 11" x 3-1/8"
Tree: Cameron 3-1/8" 5M
BPV Profile: 3-1/8" Cameron H (To be confirmed)
Perforations: 2-1/2", 4 spf C~ 4740'-4765', 4810'-4830', 4845'-4855', 4954'-4989'
Tubing Fluids: Planned: 9.0 ppg brine /diesel
Annulus Fluids: Planned: 9.0 ppg brine /diesel
Formation Markers:
Est.
Formation
Tops Est.
Formation
Tops Uncertainty Commercial
Hydrocarbon
Bearing Est. Pore
Press. Est.
Pore
Press.
Formation MD (TVDss) (feet) (Yes/No) (Psi) (ppg
EMW
SV4 -1666
SV3 -2051
SV2 -2221
SV7 -2539 Gas hydrates (2670'
- 2800' SS 1143 8.7
KOP 3075 2733
UG4 3199 -2842 +/-25 1279 8.7
UG4A 3236 -2873 +/-25 Heavy Oil (2875 -
2970' SS 1293 8.7
Fault 1 3559 -3150 +/- 100'
M.D. 1418 8.7
UG3 (faulted
to 3559 -3150 +/-25 1418 8.7
UG1 4181 -3610 +/-25 Heavy Oil (3720 -
3910' SS 1625 8.7
UG_Ma 4732 -3918 +/-25 Heavy Oil (3920 -
3960' SS 1763 8.7
UG_Mb1 4801 -3967 +/-25 No (wet) 1785 8.7
UG_Mb2 4885 -4030 +/-25 Heavy Oil (4030 -
4070' SS 1814 8.7
UG_Mc 4975 -4100 +/-25 No (wet) 1845 8.7
SB_Na 5056 -4165 +/-25 No (wet) 1874 8.7
SB_Nb 5084 -4188 +/-25 No (wet) 1885 8.7
SB_Nc 5127 _ -4224 +/-25 No (wet) 1901 8.7
SB_Ne 5135 -4231 +/-25 No (wet) 1904 8.7
SB OA 5252 -4330 +/-25 Yes 1680-1800 7.5-8.0
SB OBa 5331 -4398 +/-25 Yes 1820-1950 8.0-8.5
SB_OBb 5378 -4440 +/-25 Yes 1850-1970 8.0-8.5
SB OBc 5438 -4495 +/-25 Yes 1900 8.1
SB OBd 5492 -4545 +/-25 Yes 1730-1880 7.3-8.0
SB OBe 5559 -4607 +/-25 Yes 2050 8.6
SB OBf 5605 -4650 +/-25 Yes 2070 8.6
Base
SB OBf 5653 -4694 +/-25 No 2090 8.6
~b~'
~~ Q
1!.' ~'
t
V-201 Ai Permit to Drill Page 2
• •
T.D. in 5812 -4841 No 2180 8.7
Colville Shale
Wells within a ~/a mile of this injection well, scanned from the top of the reservoir to TD
Well Name Dist, Ft. Annulus Integrity Comments
V-202, Li , L2 712' @ Top of Pool Offset producer. For V-201 A injection intervals, closest
(Top Na) approach is 855' @OA (V-202L2), 944' @OBa (V-202L1),
1232'@OBd (V-202). Top of cement calculated to be in the
UG3 interval (3685' MD). Good cement isolation.
V-201 794' @ Top of Pool Original hole for V-201 A -will be cemented, P&A'd. Top of
(Top Na) cement calculated to be in the UG3 interval. Bond log shows
good quality of cement along and above Schrader Bluff with
to at 3488' MD. Good cement isolation.
V-105 873' @ Top OBb Dual SB/Kuparuk injector. Top of cement calculated to be in
the UG3 interval. Bond log shows good quality of cement along
and above Schrader Bluff with TOC at 4406' MD. Good
cement isolation.
V-204, Li , L2, 940' @ OBa Offset producer. For V-201 A injection intervals, closest
L3 approach is 960' @OA (V-204L3), 940' @OBa (V-204L2),
1070'@OBb (V-204L1), 1050'@OBd (V-204). Top of cement
calculated to be in the UG3 interval (3480' MD). Good cement
isolation.
V-107 1270' @ Top of Pool Top of cement calculated to be in the UG3 interval (3440' MD).
To Na Good cement isolation.
V-03 1294' @ Top of Pool Top of cement calculated to be in the UG3 interval (3591' MD).
To Na Good cement isolation.
V-111 1309' @ Top of Pool Top of cement calculated to be in the UG3 interval (3490' MD).
To Na Good cement isolation.
Existing Casing/Tubing Program
C'
~~v
~ ~~•~''~
~~-~
Cx~~~S~
~.~~~~(~
Va
Hole Size Csg/
Tbg O.D. WUFt Grade Connection Length
(ft) Top
MD/TVD
RTE ft) Btm
MD/TVD
RTE ft)
42" Insulated 20" 215.5 A-53 WLD 108 GL 108/108
12-~/a" 9-5/8" 40 L-80 BTC 3001 GL 3001/2751
8-3/a" 7" 26 L-80 BTC-M 5257 GL 5257/4880
Tubin 3-'/z" 9.2 L-80 IBT-M 4135 GL 4135/3814
New Casin ubin Pro ram: Note: To production acker within 200' MD of to erforation
Hole Size Csg/
Tbg O.D. WUFt Grade Connection Length
(ft) Top
MD/TVD
RTE ft Btm
MD/TVD
RTE ft
Existin Casin from V-201 i
42" Insulated 20" 215.5 A-53 WLD 108 GL 108/108
12-~/a" 9-5/8" 40 L-80 BTC 3001 GL 3001/2751
Planned New Casin and tubin for V-201 Ai
8-3/a" 7" 26 L-80 TC-II 4731 GL 4731/4000
8-3/a" 7" 26 L-80 BTC-M 1082 4731 /4000 5813/4923
Tubin 3-~h" 9.2 L-80 TC-II 5603 GL 5603/4732
Directional:
Directional Plan: Schlumber er A roved 02/05/07 P4b Ref Elev: 82.1' MD
KOP: 3075' MD, be in 6/100 build
Close A roach Wells: All Wells ass Ma'or Risk Scan, reference anti-collision re ort
V-201 Ai Permit to Drill Page 3
•
•
Surve Pro ram: GYD-GC-SS 99-3048' ,MWD + IFR + MS 3048-5812'
Maximum Hole An le: 61.3 de rees
Distance to Nearest Pro ert Line: 11,215' from PBU bounda
Distance to Nearest Well in Pool: 712' from V-202
Mud Program:
8-3/a" Production Hole Mud Pro erties Freshwater Mud (LSND)
Interval Densit PV YP PH API Filtrate MBT
3075'-5813' OBf Base 8.8-9.0 8-14 18-24 9.0-9.5 4 - 7 < 15
Survev and Loaaina Program:
8-3/a" Hole Section: Sample as required by well site Geologist
MWD / LWD: GR/RES/PWD real time and Azi-Dens/Neu/DWOB/DTORO recorded
O en Hole: None
Cased Hole: USIT in primary depth control mode
Cement Calculations:
Casin Size Intermediate Casing - 7" 26 Ib/ft L-80 BTC-M x TC-II -Single Stage
Basis Lead: None
Tail: O en hole volume + 30% excess + 80' shoe track. TOC 1000' below surface shoe.
Fluid Sequence and This cement job is planned for one stage.
Volume:
1 °' Sta e
Wash None
3 acer 40 bbl of MUDPUSH XL
Lead none
Tail 66 bbl 320 sks 15.8 ~
Temp BHST = 85° F from SOR
weighted to 10.5
lass G cement + Latex - 1.16 cuft/sk
Surface and Anti-Collision Issues:
• Surface Shut-in Wells: The closest existing surface wells are V-102 (15' away), V-02 (45' away), and V-
107 (15' away). The well houses must be removed from those wells.
• Close Approach Shut-in Wells: All wells have passed the major risk scan. No wells will require
subsurface shut-in during drilling operations. Reference the Anti-collision report in the directional plan for a
full list of offset well paths.
V-201 Ai Permit to Drill Page 4
• s
Well Control
The production hole section will be drilled with well control equipment consisting of 5000 psi working pressure pipe
rams(2), blind/shear rams, and annular preventer. This equipment is capable of handling maximum potential
surface pressures. This being an injection well, BOP equipment will be tested to 4,000 psi. The test
frequency during the work-over operation will be on a 7 day period, and 14 days during the D&C operations.
Anticipated surface pressures will not exceed 3,OOOpsi, therefore it will not be necessary to have two sets of pipe
rams installed at all times.
Diverter, BOPE and drilling fluid system schematics on file with the AOGCC.
Intermediate Section Kick Tolerance and Intearity Testin
• BOPE: Hydril, 13-5/8", 5000 psi
• Maximum anticipated BHP: 2230 psi (8.7 ppg EMW) at 4923' TVD
• Maximum surface pressure: 1,737 psi -Based on a full column of gas C~ 0.10 psi/ft
• Planned BOP test pressure: 4,000 psi/250 psi Rams and 2,500 psi/250 psi Annular
• 7" Casing Test: 4,000 psi surface pressure test
• Integrity Test - 8-3/4" hole: LOT 20' - 50' in open hole from the cement kick-off plug (3095' MD)
• Kick Tolerance: 25.0 bbl KT with a 9.0 ppg mud and a 10.75 ppg LOT
• Planned completion fluid: Estimated 9.0 ppg Brine / 6.8 ppg Diesel
Disposal
• No annular disposal in this well.
• Cuttings Handling: Cuttings generated from drilling operations will be hauled to grind and inject at DS-04.
• Fluid Handling: Haul all drilling and completion fluids and other Class II wastes to DS-04 for disposal.
Haul all Class I wastes to Pad 3 for disposal.
V-201 Ai Permit to Drill Page 5
~ •
Drilling Hazards and Contingencies
POST THIS NOTICE IN THE DOGHOUSE
Well Control /Reservoir Pressures:
The Schrader Bluff sands are expected to be pressured at 7.3-8.7 ppg EMW. There is an increased risk of
differential sticking, seepage losses, or lost circulation.
II. Hydrates and Shallow gas:
Gas Hydrates are possible near the V-201 Ai surface casing shoe. The shoe is set in the SVi at 3001' MD, but
hydrates could be as deep as 3150' MD. Recommended practices and precautions for drilling hydrates should
be followed in the production hole. Occasionally hydrates are encountered below the SVi .
III. Lost Circulation /Breathing:
Lost circulation is considered low at the fault in the production hole section. Seepage losses could occur in the
Schrader O-sands. V-201 i is fractured in the Schrader sands. The directional plan maximized distance from
known fractures, but exact extend of fractures is unknown.
IV. Kick Tolerance /Integrity Testing:
Production Section Kick Tolerance and Integrity Testing
• Integrity Test - 8-3/4" hole: LOT 20' - 50' in open hole from the cement kick-off plug (3095' MD)
• Kick Tolerance: 25.0 bbl KT with a 9.0 ppg mud and a 10.75 ppg LOT
V. Stuck Pipe
There could be slight differential sticking across the open hole while running the 7" casing. Keep the casing
moving as much as possible and follow the centralizer program to help with stand-off.
VI. Hydrogen Sulfide
V Pad is not designate site, however..Standard Operating Procedures for H2S prgo uld
be followed at all a .H2S levels ross~t"e pad are typic Ily in the 10 ppm range bated on the latest
samples taken. -102 as read 20 m ahd V-107 60 ppm. he highest reading is fro V-117 at 180 ppm.
_- ~,
VII. Faults
There is a low risk of losses incurred when crossing the fault.
Formation Where Encounter Fault MD
Intersect TVDSS
Intersect Est.
Throw Throw
Direction
Uncertaint
Fault #1 - U nu UG3 V Pad fault 3559' -3150 -115' Southwest +/- 100' M.D.
CONSULT THE V PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION
V-201 Ai Permit to Drill Page 6
• •
V-201 Ai - De-complete, Drill, and Complete Procedure Summary
Pre-Rig Work:
1. R/U slickline. Drift 3.5" tubing (Min ID: 2.812"). Tag and record PBTD below WLEG. Note: Jet pump pulled
and sliding sleeve closed 11/18/04. Removed OGLV and install DGLV 9/23/03. No SSSV installed.
2. PPOT - TxIC. Function test all LDS and repair as needed.
3. Fluid pack the T x IA
4. P&A perfs in 7", 26# casing from top of fill (4854' 1/7/05) to 4350', which is 400' above the top perforation. RIH
with coil tubing to PBTD, lay in 30 bbls of 15.8 ppg cement. Obtain squeeze, but do not exceed a BHP of 2900
psi at top of perfs. Notes: Well has been frac'ed. Assuming a water gradient to surface from the top pert and
900 psi applied fracture pressure (0.45*4400+900=2900psi) gives a max BHP of 2900 psi. If the fracture does
open, there is a good chance the well will go in a vacuum. Cement Calc:.038278 bbl/ft x 504' = 19.3 bbls hole
volume + 5 bbls into perfs + 5 bbls extra.
5. Pressure test the TxIA to 3,500 psi for 30 minutes, after WOC. Pressure test the OA to 2000 psi. Bleed all
pressures to zero.
6. R/U slickline to run a full bore drift and tag the TOC.
7. R/U e-line to jet cut the 3.5", 9.3# L-80 tubing in the middle of the 2nd 10' pup joint above the packer. Estimated
cut depth at 4062' md.
8. Circulate the TxIA to seawater through the cut. Freeze protect the TxIA w/diesel to 2500' TVD (2700' MD)
9. Set BPV in the tubing hanger and test, secure well.
10. Remove wellhouses and level the pad as needed. Provide well prep costs on hand over form.
Rig Operations:
1. MIRU Nabors 9ES. ND tree and tubing adapter. NU BOPE and test to 4,000 psi / 2500 psi annular.
2. R/U tubing spear, BOLDS, Pull Hanger, rev circ 9.0 ppg brine through tube cut.
3. Pull Tubing f/ 4062' and dual control lines. RD tubing handling equipment.
4. Test BOP w/ 4" DP
5. MU 7", 26# (ID: 6.276") casing scraper, RIH to the 3.5" tubing stub.
6. CBU, POOH, LD scraper.
7. RU e-line USIT, log 7", find cut point
8. RU, run CIBP on a-line, set at 3150', POOH, RD a-line
9. PU, MU BKR csg cut assy, RIH and cut 7" casing (3101' or Mid joint above TOC), POOH
10. C/o to 7" rams, test
~~11. Spear 7" casing hanger, close bag, Circ wellbore w/ warm seawater, detergent.
~~ 12. Pull 7" casing from cut and RD csg equip.
13. Test BOP w/ 4" DP
14. RIH w/ 4" DP and place 200' of 17# kick-off cement on top of CIBP, POOH. WOC for compressive strength.
15. MU 8-3/a" drilling assembly with MWD/GR/Res/Azi-Den/Neu/DWOB/DTORO/PWD and RIH to kick-off plug.
Confirm 4,000 psi cement compressive strength prior to kicking off.
16. Displace over to new 8.8 ppg LSND mud. Drill and kick-off from cement plug. Drill 20' of formation and
conduct LOT. (V-201 LOT was 14.94 ppq EMW)
17. Drill ahead to Production hole Target TD (250' MD below OBe marker). Circulate one BU, back-ream out to the
surface shoe, then POOH to run casing.
~~~~ 18. Run and cement the 7", 26#, L-80, BTC-M x TC-II production casing. Displace the casing with seawater during
~~ cementing operations. Pressure test casing to 4,000 psi for 30 minutes at plug bump. Confirm 500 psi cement
compressive strength prior to freeze protecting. Freeze protect the 7" x 9 s/8" annulus.
19. PU DPC guns and RIH w/ 145' of 4.5" Power Jet 4505 5 spf, perf guns with Anadrill LWD GR/CCL for gun
correlation.
20. Space out perf guns by tagging PBTD and utilizing GR/CCL and RA tags in 7" casing. Once correlated
correctly, circulate over to 9.0 ppg brine. Confirm cement compressive strength is at least 1,000 psi before
firing. Perforate OA, OBa, OBb, OBc, and OBd. POOH LD DP and guns.
V-201 Ai Permit to Drill Page 7
• •
21. RU Schlumberger E-line. RIH with gauge ring and junk basket to recover any pert debris. Repeat until clean to
at least 50' below the bottom perforation.
22. Run USIT log following Primary Depth Control procedures as USIT log will be primary depth control for future
well work.
23. Run the 3-'h", 9.2#, L-80, TCII completion with a 7" x 3-'/z" straddle packer assembly, I-wire, gauges, and
injection mandrels. Torque turn TC-II threaded tubing. Top packer must be within 200' of OA perfs.
24. Run in the lockdown screws and set the packers. Give AOGCC 24 hours notice, then test the production
casing/tubing annulus and tubing to 4,000 psi each. Shear the DCR shear valve and pump both ways to
confirm circulation ability.
25. Install and test FMC TWC. Nipple down the BOPE. NU double master valve, test to 5,000 psi.
26. Freeze protect the well to 2,500' TVD by first pumping corrosion inhibited brine down the IA with rig pumps
followed by diesel down IA w/ Hot Oiler, taking clean brine returns to surface. Allow diesel to u-tube into tubing.
27. Install BPV in tubing hanger. Install a VR plug in the 7"x 3-'/z" annulus valve and secure the well. Assure that
IA/OA are protected with two barriers.
28. Rig down and move off.
Post-Rig Work:
1. Nipple up and test the tree to 5,000 psi.
2. R/U Slickline and pull ball and rod / RHC from the tailpipe.
3. Replace the DCR shear valve with a dummy GLV.
4. Pull dummy valves in injection mandrels and replace with injection valves.
5. Pull VR plug.
6. Install wellhouse and flowlines.
V-201 Ai Permit to Drill Page 8
by
Schlumberger
V-201 A (P4b) Proaosai
Report Date: February 5, 2007 Survey 1 DLS Computation Method: Minimum Curvature / Lubinski
Client: BP Exploration Alaska Vertical Section Azimuth: 41.299°
Field:
Structure I Slot: Prudhoe Bay Unit - WOA
V-Pad I V-201 Vertical Section Origin:
'O~ TVD Reference Datum: N 0.000 ft, E 0.000 ft
Rotary Table
Well: V-201 O
~O
~ TVD Reference Elevation: 82.10 ft relative to MSL
Borehole: Plan V-201A ~OV Sea Bed 1 Ground Level Elevation: 53.60 ft relative to MSL
UWIIAPI#: 500292305401 p p Magnetic Declination: 23.738°
Survey Name 1 Date: V-201A (P4) /February 5, 2007 Total Field Strength: 57634.539 nT
Tort 1 AHD 1 DDI 1 ERD ratio: 197.659° 12695.84 ft 15.799 / 0.548 Magnetic Dip: 80.892°
Grid Coordinate System: NAD27 Alaska State Planes, Zone 04, US Feel Declination Date: March 20, 2007
Location LaVlong: N 70.32800924, W 149.26582824 Magnetic Declination Model: BGGM 2006
Location Grid NIE YIX: N 5970085.110 ftUS, E 590525.630 ftUS North Reference: True North
Grid Convergence Angle: +0.69132628° Total Corr Mag North -> True North: +23.738°
Grid Scale Factor: 0.99990931 Local Coordinates Referenced To: Well Head
Measured Vertical Gravity
Comments Inclination Azimuth SuWSeaTVD TVD NS EW DLS Build Rate Walk Rate Northing Easting Latitude Longitude
Depth SecOon Tool Face
R de de ft ft ft R R de de N00 ft de 1100 R de 100 ft ftUS RUS
ue-In survey 3U4/ .y/ Zi5.yi5 3225.14 Z/10. 00 Z/92 .10 /l. lS /'L3. 33 -/15 .51 121i.99K 3.3/ -3.3ti -U.4U 59/U/99. litS 5tf9tfUL51 N 70.32995521 W 149.27163094
KOP Crv 6/100 3075 .00 27.89 331.35 2733. 77 2815 .87 75. 25 734. 44 -722 .00 69.17R 6.95 -4.05 11.88 5970810. 71 589794.89 N 70 .33001556 W 149.27168356
3100 .00 28.45 334.29 2755 .81 2837 .91 79. 58 744. 93 -727 .38 66.58R 6.00 2.26 11.78 5970821. 14 589789.38 N 70 .33004423 W 149.27172725
UG4 3199. 32 31.26 344.87 2842. 00 2924. 10 103. 09 791. 17 -744. 38 57.39R 6.00 2.83 10.65 5970867. 17 589771.82 N 70. 33017054 W 149.27186517
3200 .00 31.28 344.94 2842 .58 2924 .68 103. 29 791. 51 -744 .48 57.34R 6.00 3.24 9.73 5970867. 51 589771.73 N 70 .33017147 W 149.27186592
Crv 6/100 3221 .62 32.00 347.00 2860 .99 2943 .09 109. 74 802. 51 -747 .22 106.27R 6.00 3.32 9.53 5970878. 47 589768.85 N 70 .33020153 W 149.27188821
UG4A 3235. 76 31.77 348.55 2873. 00 2955. 10 114. 18 809. 81 -748. 81 104.95R 6.00 -1.61 10.94 5970885. 76 589767.18 N 70. 33022148 W 149.27190105
3300 .00 30.98 355.80 2927 .86 3009 .96 136. 01 842. 89 -753 .38 98.76R 6.00 -1.24 11.28 5970918. 77 589762.21 N 70 .33031183 W 149.27193815
3400 .00 30.59 7.51 3013. 85 3095 .95 175. 23 893. 82 -751 .94 88.69R 6.00 -0.39 11.71 5970969. 72 589763.03 N 70 .33045099 W 149.27192651
3500 .00 31.25 19.13 3099. 72 3181 .82 220. 44 943. 60 -740 .10 78.71 R 6.00 0.66 11.62 5971019. 62 589774.27 N 70 .33058697 W 149.27183056
Fault Crossing 3559. 07 32.11 25.68 3150. 00 3232. 10 249. 75 972. 23 -728. 27 HS 6.00 1.46 11.09 5971048. 39 589785.75 N 70. 33066519 W 149.25
UG3 3559. 08 32.11 25.68 3150. 01 3232. 11 249. 76 972. 24 -728. 27 73.13R 6.00 1.74 10.80 5971048. 40 589785.75 N 70. 33066520 W 149.27 463
3600 .00 32.90 30.01 3184. 53 3266 .63 271. 14 991. 66 -718 .00 69.48R 6,00 1.92 10.58 5971067. 95 589795.79 N 70 .33071829 W 149.27165133
3700 .00 35.40 39.74 3267. 34 3349 .44 326. 77 1037. 50 -685 .87 61.42R 6.00 2.50 9.73 5971114. 16 589827.36 N 70 .33084350 W 149.27139079
3800 .00 38.58 48.20 3347. 25 3429 .35 386. 74 1080. 59 -644 .07 54.66R 6.00 3.18 8.46 5971157. 75 589868.63 N 70 .33096124 W 149.27105180
3900 .00 42.29 55.48 3423 .39 3505 .49 450. 37 1120. 47 -593 .05 49.11 R 6.00 3.71 7.28 5971198. 24 589919.16 N 70 .33107021 W 149.27063806
4000 .00 46.40 61.75 3494 .93 3577 .03 516. 98 1156. 71 -533 .38 44.62R 6.00 4.11 6.26 5971235. 20 589978.39 N 70 .33116923 W 149.27015412
4100 .00 50.81 67.18 3561 .06 3643 .16 585. 83 1188. 91 -465 .70 41.03R 6.00 4.40 5.44 5971268. 20 590045.66 N 70 .33125720 W 149.26960526
UG1 4180. 68 54.52 71.08 3610. 00 3692. 10 642. 51 1211. 70 -405. 77 38.66R 6.00 4.61 4.83 5971291. 71 590105.31 N 70. 33131946 W 149.26911920
4200 .00 55.43 71.96 3621 .09 3703 .19 656. 18 1216. 71 -390 .77 38.15R 6.00 4.70 4.55 5971296. 90 590120.25 N 70 .33133316 W 149.26899752
4300 .00 60.23 76.23 3674 .33 3756 .43 727, 24 1239. 81 -309 .39 35.88R 6.00 4.79 4.27 5971320. 98 590201.33 N 70 .33139627 W 149.26833753
End Crv 4322 .93 61.34 77.15 3685 .52 3767 .62 743. 55 1244. 42 -289 .92 --- 6.00 4.88 4.01 5971325. 82 590220.75 N 70 .33140886 W 149.26817958
Crv 6/100 4403 .23 61.34 77.15 3724. 03 3806 .13 800. 67 1260. 09 -221 .22 143.89E 0.00 0.00 0.00 5971342. 32 590289.24 N 70 .33145168 W 149.26762243
WeIlDesign Ver SP 2.1 Bld( doc40x_100) V-201\V-201\Plan V-201A\V-201A (P4) Generated 2/5/2007 4:21 PM Page 1 of 2
Measured Vertical Gravity
Comments Inclination Azimuth Sub•Sea TVD Typ NS EW DLS Build Rate Walk Rate Northing Easting latitude longitude
Depth Section Tool Face
ft d de ft ft ft ft ft de de 1100 ft de 1100 ft de 1100 ft ftUS ftUS
4DUU.VU 5b./"I /3.Vd 3//3.25) Sifbb.yS 25Uy.b3 1Y25L34 -141 .Ub 141./i5L t).VV -4./25 -4.Z3 5y/13tl4.53
4600.00 52.09 68.36 3832.05 3914.15 940.27 1308.09 -64.34 139.04E 6.00 -4.63 -4.70 5971392.21
4700.00 47.67 63.04 3896.50 3978.60 1009.80 1339.43 5.34 135.61 L 6.00 -4.42 -5.32 5971424.38
Ma 4731.53 46.34 61.21 3918.00 4000.10 1031.35 1350.21 25.72 134.36E 6.00 -4.24 -5.80 5971435.40
4800.00 43.54 56.94 3966.48 4048.58 1077.36 1375.01 67.21 131.34E 6.00 -4.08 -6.23 5971460.70
Mb1 4800.72 43.51 56.90 3967.00 4049.10 1077.84 1375.28 67.62 131.31E 6.00 -3.96 -6.54 5971460.98
Mb2 4885.35 40.30 51.00 4030.00 4112.10 1132.92 1408.44 113.33 126.91E 6.00 -3.79 -6.97 5971494.68
4900.00 39.78 49.90 4041.22 4123.32 1142.22 1414.44 120.60 126.07E 6.00 -3.57 -7.50 5971500.77
Mc 4975.12 37.28 43.88 4100.00 4182.10 1188.74 1446.33 154.77 121.36E 6.00 -3.33 -8.01 5971533.07
5000.00 36.52 41.74 4119.90 4202.00 1203.66 1457.29 164.92 119.65E 6.00 -3.05 -8.61 5971544.15
Na 5055.56 34.97 36.68 4165.00 4247.10 1236.08 1482.40 185.44 115.54E 6.00 -2.78 -9.10 5971569.51
Nb 5083.51 34.28 33.99 4188.00 4270.10 1251.87 1495.35 194.63 113.33E 6.00 -2.48 -9.61 5971582.57
5100.00 33.90 32.36 4201.66 4283.76 1261.02 1503.09 199.68 111.98E 6.00 -2.31 -9.88 5971590.36
Nc 5126.83 33.33 29.65 4224.00 4306.10 1275.63 1515.81 207.33 109.72E 6.00 -2.14 -10.13 5971603.17
Ne 5135.20 33.16 28.78 4231.00 4313.10 1280.11 1519.82 209.57 108.99E 6.00 -1.99 -10.33 5971607.20
5200.00 32.08 21.85 4285.60 4367.70 1313.65 1551.34 224.52 103.15E 6.00 -1.66 -10.70 5971638.90
Tgt OA 5252.23 31.50 16.00 4330.00 4412.10 1339.07 1577.33 233.44 HS 6.00 -1.11 -11.20 5971665.00
OA 5252.24 31.50 16.00 4330.01 4412.11 1339.08 1577.34 233.44 142.69E 6.00 -4.77 -6.96 5971665.00
5300.00 29.27 12.44 4371.21 4453.31 1360.59 1600.74 239.40 139.62E 6.00 -4.67 -7.44 5971688.47
Oea 5330.50 27.90 9.91 4398.00 4480.10 1373.21 1615.05 242.23 137.39E 6.00 -4.50 -8.31 5971702.81
OBb 5377.59 25.88 5.53 4440.00 4522.10 1390.96 1636.13 245.12 133.48E 6.00 -4.28 -9.31 5971723.93
5400.00 24.97 3.21 4460.24 4542.34 1398.65 1645.72 245.86 131.39E 6.00 -4.05 -10.31 5971733.53
Oec 5438.12 23.52 358.91 4495.00 4577.10 1410.60 1661.37 246.16 127.47E 6.00 -3.81 -11.29 5971749.17
End Drp 5472.44 22.32 354.61 4526.61 4608.71 1420.13 1674.70 245.42 --- 6.00 -3.49 -12.55 5971762.50
Tgt OBd 5492.32 22.32 354.61 4545.00 4627.10 1425.31 1682.22 244.71 --- 0.00 0.00 0.00 5971770.00
OBd 5492.33 22.32 354.61 4545.01 4627.11 1425.31 1682.22 244.71 --- 0.00 0.00 0.00 5971770.01
OBe 5559.34 22.32 354.61 4607.00 4689.10 1442.77 1707.57 242.32 --- 0.00 0.00 0.00 5971795.32
5562.59 22.32 354.61 4610.00 4692.10 1443.62 1708.79 242.20 --- 0.00 0.00 0.00 5971796.54
OBf 5605.83 22.32 354.61 4650.00 4732.10 1454.88 1725.14 240.66 -- 0.00 0.00 0.00 5971812.87
OBf Base 5653.39 22.32 354.61 4694.00 4776.10 1467.28 1743.13 238.96 --- 0.00 0.00 0.00 5971830.83
TD / 7" Csg 5812.59 22.32 354.61 4841.26 4923.36 1508.75 1803.33 233.28 --- 0.00 0.00 0.00 5971890.96
5`JU3by.13 N /U.3;i15Uy/4 W 145."LEifiy7231
590445.52 N 70.33158283 W 149.26635008
590514.81 N 70.33166845 W 149.26578496
590535.05 N 70.33169788 W 149.26561965
590576.24 N 70.33176564 W 149.26528314
590576.65 N 70.33176638 W 149.26527977
590621.95 N 70.33185697 W 149.26490907
590629.14 N 70.33187336 W 149.26485012
590662.92 N 70.33196049 W 149.26457298
590672.94 N 70.33199042 W 149. 65
590693.16 N 70.33205903 W 149. 18
590702.18 N 70.33209441 W 149.26424968
590707.15 N 70.33211554 W 149.26420866
590714.64 N 70.33215030 W 149.26414660
590716.83 N 70.33216124 W 149.26412844
590731.39 N 70.33224734 W 149.26400724
590740.00 N 70.33231836 W 149.26393485
590740.00 N 70.33231837 W 149.26393484
590745.68 N 70.33238230 W 149.26388652
590748.34 N 70.33242139 W 149.26386352
590750.97 N 70.33247900 W 149.26384011
590751.59 N 70.33250520 W 149.26383414
590751.71 N 70.33254793 W 149.26383164
590750.80 N 70.33258437 W 149.26383766
590750.00 N 70.33260491 W 149.26384342
590750.00 N 70.33260492 W 149.26384342
590747.31 N 70.33267415 W 149.26386282
590747.18 N 70.33267750 W 149.276
590745.43 N 70.33272217 W590745.43 N 70.33272217 149.2 7
590743.52 N 70.33277131 W 149.26389004
590737.11 N 70.33293577 W 149.26393612
WeIlDesign Ver SP 2.1 Bld(doc40x_100 } V-201\V-201\Plan V-201A\V-201A (P4) Generated 2/5/2007 4:21 PM Page 2 of 2
by
Schlumberger
WELL FIELD STRUCTURE
V-201A (P4b) Prudhoe Bay Unit - WOA V-Pad
Magnetic Parameters Surtacv Lorslion NAD22 ANSka Stale Planea. Zone 04 US Feel Miscellaneow
Motlel: BGGM 200fi UiP BO 992" Dale Marcb 20. 100) Lar. N]01940933 binq 692009611 flUS Grx]LOnv: .0 fi91][fi19' Slob V-]01 iVD ftel: Rotary Table 182.t01t above MSLI
Mag Doc: .23239" FS 5)fi34.5 nT Lon: W149 16 56 932 Ealing: 90525 fi]M1US Sule Fac1.0999909309] Plan. V-201A 1PQb) Srvy Dale'. February 05. 300]
0 300 600 900 1200 1500
2700
3000
3300
3600
O
O
M
C
ii 3900
a~
U
4200
4500
4800
In Survey;
OP Crv 6IT00
~ rv 61100
.-.._.. .._.._.._.._.._.._.. _.._i. _.._.._.._.._.._.. _..-. .._.._.._..-.._..-..-..i.._.._.._.._.._.._.._.._ _.._.._.._.._.._
.-.._.._ _.._..-..-..-.._.._..-.._ -..-..-..-..-..-.._..-. _..-.._.._.._.._.._.._..t.._.._.._.._..-..-.._.._ _.._.._.. _.._.._
............i ...................................i..................................~..................................i.................................. ..........................
Fault Crossing
._ ~3: ._.._.._.. _.._.._.. _.._ -..-..-..-..-..-..-..-. -..-..-..-..-..-..-..~ -.._.._..-..-.._..-.._ ._.. _.._.._.. _.._
......... ~ ...................................:..................................i..................................<..................................c.........................
End Crv
Crv61100
.._.._.._.f _.._..-..-.. ._.._..-..-,.-..-..-.._..-.._..-..-.. ~..-..-..-..-.._.. _.. ..t..1.._.._.._..-..-..-..-.._..M.. _.._..-.._.. _.. _
.......................... ~................................. ................................ v......
~._.. _.. _.._.._.._. _.._.._.. _.._.._.._.._ .7. ._.._.._.. _.._.._ _.~
''~:is:i::i::i::i::i::i':ii:i::i::i:: i:: i::i::i::i:: i:: -........_...:: S:: i:'~
Tgt OA -
..-..-.._..~..-.._.._.._.._. ~.e .._..a..._.._.._.._.._..-.
:End Drp
..-..-..~..~..-..-..-.._.._.. .. _..Tgta6d.._..-..-.
~-201A Tgt OBd
..-.._.._..;..-.._..-.._.._.._. .~8. . _.._.. _.. _.._.._
..-..-.._..y.. _.._..-.._.._.._.._ 6f ~. _.._..-.._.._..-
_.._..
.._.._.._..i.._.._.._.._.._.._.. . ' _.._..-.._.
_..
...............:............................... . ase..................
-201A (P4b)
TD/7"Csg
300 600 900 1200 1500
Vertical Section (ft) Azim = 41.3°, Scale = 1(in):300(ft) Origin = 0 N/-S, 0 E/-V
2700
3000
3300
3600
3900
4200
4500
4800
by
Schiumherger
WELL
V-201A (P4b) FIELD
Prudhoe Bay Unit - WOA STRUCTURE
V-Pad
Magnallc Parameters sonata Loragon NADP Alasla stale Plarea. zone W. US fear AllacelUneous
Motlel. BGGM 3006 Olp BO B93' Dale'. Martl130. 200] Lal: N]019 do B3J NoItbllg 59)0085.111105 GnE DOnV: •0.191 J363B' Sbt. V~201 TVD Ref Rdary Table 182 t011 above MSLI
Mag Dec: •2J.)]6' FS. 51634.5 nT Lon. Wtd91556.962 Eaalmg. 590515.831105 SFab Fad'. 0.999909]092 Plan. V~301A IPd51 Srvy Date February 05. 200]
-800 -600 -400 -200 0 200
1800
1600
1400
n
n
n
Z
0 1200
0
N
C
_N
(9
U
Cn
~ 1000
V
V
V
800
600
400
1800
1600
1400
1200
1000
800
600
400
-800 -600 -400 -200 0 200
c« W Scale = 1(in):200(ft) E »>
•
Oilfield Services, Alaska
Schlumberger Drilling & Measurements
•
Schlnmberger
2525 Gambell, Suite 400
Anchorage, AK 99503
Tel (907) 273-1766
Fax (907) 561-8367
Monday, February 05, 2007
Brandon Peltier
Prudhoe Bay V-201A (P4b)
BP Exploration (Alaska) Inc.
Nabors 9ES
Close Approach Analysis
We have examined the potential intersections of subject well with all other potentially conflicting wells, according
to the BPA Directional Survey handbook (BPA-D-004) dated 09/99.
Method of analysis:
1. A list of wells to be analyzed is created in Compass by performing a global scan with an initial search radius
of two thousand feet with an increment of one hundred feet for every one thousand feet of measured depth in the
subject well.
2. Wells are analyzed using the Compass Anti-collision module (BP Company setup) with major risk safety
factors applied. For problem wells that are plugged and abandoned or that can be shut in, risk-based safety factor
may be used, with client notification.
3. All depths are relative to the planned well profile.
Survey Program:
Instrument Type Start Depth End Depth
GYD GC SS 99.04'md 3047.97'md
MWD + IFR + MS 3047.97'md 5812.59'md
Close Approach Analysis results:
Under method (2), note.
All wells pass major risk.
All data documenting these procedures is available for inspection at the Drilling & Measurements Directional
Planning Center.
Close Approach Drilling Aids to be provided:
A drilling map and traveling cylinder will be provided.
Checked by: Scott DeLapp 02/05/07
BP Alaska S
Anticollision Report
Company: BP Amoco Date: 2/5/2007 Time: 16:41:42 Page: I
I field: Prudhoe Bay
I Reference Site: PB V Pad Co-ordinate(NE) Reference: Well: V-201, True No rth
Reference Well: V-201 Vertical (TVD) Reference: V-201 82.1
Reference Wellpath: Plan V-201A Db: Oracle
NO GLOBAL SCAN: Using user defined selection & scan criteria Reference: Principal Plan & PLANNED PROGRAM ',
Interpolation Method: MD Interval: 5.00 ft Error Model: ISCWSA Ellipse ',
Depth Range: 3075.00 to 5812.59 ft Scan Method: Trav Cylinder No rth ',
Maximum Rad ius:10000.00 ft Error Surface: Ellip se + Casing
Survey Program for Definitive Wellpath - - - -
Date: 12/14/2006 Validated: No Version: 1
I~ Planned From To Survey Toolcode Tool Name
ft
-- ft
-- - -
__ __
_
__ _
- - 1
99.04 3047.97 Survey #1 M WD+IFR+MS (99.04-51 MWD+IFR+MS MWD +IFR + Multi Station
3047.97 5812.59 Planned: Pla n #4 V1 MWD+IFR+MS MWD + !FR + Multi Station
Casing Points
1\1D TF'D Diameter Hole Sf~e Narnc
ft ft in in
3016.00 2764.28 9.625 12.250 9 5/8" -- ~ - _ I
', 5812.59 4923.37 7.000 8.750 7"
Summary
-
-
-
<----------------- Offset VYellpath ----- -------------> Reference Offset Ctr-Ctr Vo-Go Allowable
Site tVell N~ellpath h1D M11D Distance Area Deviation Warning
ft ft ft ft ft
PB V Pad Plan V-121 (S-R) Plan V-121 V2 Plan: PI 4600.00 3155.00 2274.51 65.52 2208.99 Pass: Major Risk ',
PB V Pad Plan V-215 (S-I) Plan V-215 V1 Plan: PI 4650.00 5335.00 4405.60 63.96 4341.65 Pass: Major Risk
PB V Pad Plan V-218 (N-V) Plan V-218 V4 Plan: PI 4650.00 3155.00 2531.90 65.28 2466.62 Pass: Major Risk
PB V Pad V-01 V-01 V15 4550.00 6225.00 4935.30 59.31 4876.00 Pass: Major Risk ',
', PB V Pad V-02 V-02 V12 3075.76 3390.00 1237.55 41.72 1195.83 Pass: Major Risk ',
!~ PB V Pad V-03 V-03 V7 4657.23 3995.00 1238.55 54.53 1184.02 Pass: Major Risk
PB V Pad V-04 V-04 V7 3076.84 3165.00 275.44 45.94 229.50 Pass: Major Risk
PB V Pad V-100 V-100 V7 4520.81 3690.00 1520.90 60.48 1460.42 Pass: Major Risk
PB V Pad V-101 V-101 V7 3076.74 3200.00 450.19 66.29 383.90 Pass: Major Risk
j PB V Pad V-102 V-102 V5 3080.79 3130.00 711.30 65.54 645.76 Pass: Major Risk
PB V Pad V-103 V-103 V6 4574.98 3490.00 1572.34 59.18 1513.16 Pass: Major Risk j
PB V Pad V-104 V-104 V13 3078.28 3165.00 218.53 66.51 152.02 Pass: Major Risk I
', PB V Pad V-105 V-105 V13 4810.92 4315.00 678.05 60.77 617.28 Pass: Major Risk ~
', PB V Pad V-106 V-106 V10 4675.89 3835.00 1207.23 60.68 1146.54 Pass: Major Risk i
PB V Pad V-106 V-106A V9 4693.69 4050.00 905.01 59.12 845.90 Pass: Major Risk ~
PB V Pad
V-106
V-106AP61 V6
4693.69
4050.00
905.01
59.13
845.89 I
Pass: Major Risk
PB V Pad V-106 V-106AP62 V2 4693.69 4050.00 905.01 59.12 845.90 Pass: Major Risk
PB V Pad
V-106
V-106APB3 V2
4693.69
4050.00
905.01
59.12
845.90 I
Pass: Major Risk
PB V Pad V-107 V-107 V5 3078.41 3200.00 661.73 43.33 618.41 Pass: Major Risk
PB V Pad V-108 V-108 V7 3075.00 3600.00 1389.64 68.23 1321.41 Pass: Major Risk
PB V Pad V-109 V-109 V2 4750.00 4060.00 1502.85 64.64 1438.21 Pass: Major Risk
PB V Pad V-109 V-109PB1 V5 4750.00 4060.00 1502.85 64.64 1438.21 Pass: Major Risk ~
I, PB V Pad V-109 V-109PB2 V2 4750.00 4060.00 1502.85 64.64 1438.21 Pass: Major Risk
', PB V Pad V-111 V-111 V25 4465.54 3875.00 1141.07 50.76 1090.31 Pass: Major Risk I
', PB V Pad
V-111
V-111 PB1 V8
3078.11
3345.00
1178.65
40.30
1138.35 ~
Pass: Major Risk
PB V Pad V-111 V-111 PB2 V2 3078.11 3345.00 1178.65 40.30 1138.35 Pass: Major Risk
PB V Pad V-111 V-111 PB3 V6 4465.54 3875.00 1141.07 50.76 1090.31 Pass: Major Risk
ii PB V Pad V-112 V-112 V7 3076.47 3215.00 656.71 59.48 597.23 Pass: Major Risk
PB V Pad V-113 V-113 V6 3076.45 3350.00 805.03 69.75 735.28 Pass: Major Risk
PB V Pad V-114 V-114 V5 3075.00 4310.00 2626.93 55.25 2571.68 Pass: Major Risk
PB V Pad V-114 V-114A V4 3075.00 4470.00 2832.37 54.09 2778.28 Pass: Major Risk ',
PB V Pad
l V-114 V-114APB1 V4 3075.00 4470.00 2832.31 54.15 2778.16 Pass: Major Risk
i PB V Pad V-114 V-114AP62 V2 3075.00 4470.00 2832.37 54.09 2778.28 Pass: Major Risk
PB V Pad V-115 V-115 V5 4600.00 3350.00 2429.69 59.53 2370.16 Pass: Major Risk
PB V Pad V-115 V-115PB1 V4 4600.00 3350.00 2429.69 59.53 2370.16 Pass: Major Risk
PB V Pad V-117 V-117 V9 4700.00 4265.00 3879.56 66.84 3812.72 Pass: Major Risk
PB V Pad V-117 V-117P61 V6 4700.00 4265.00 3879.56 66.84 3812.72 Pass: Major Risk
I PB V Pad V-117 V-117P62 V6 4700.00 4265.00 3879.56 66.84 3812.72 Pass: Major Risk
I
~ PB V Pad V-119 V-119 V13 4650.00 7895.00 6771.77 65.46 6706.31 Pass: Major Risk
I
', PB V Pad
V-120
V-120 V5
4600.00
3140.00
2083.94
58.13
2025.81 I
Pass: Major Risk ~
PB V Pad V-122 V-122 V10 4714.77 3415.00 2205.85 64.68 2141.18 Pass: Major Risk '
PB V Pad V-122 V-122PB1 V10 4714.77 3415.00 2205.85 64.67 2141.18 Pass: Major Risk
~PB V Pad V-201 V-201 V10 3075.00 3075.00 0.00 0.66 -0.66 FAIL: NOERRORS
BP Alaska
Anticollision Report
Company: BP Amoco Date: 2/5/2007 Time: 16:41:42 Page: 2
Field: Prudhoe Bay
Reference Site: PB V Pad Co-ordinate(NN:) Reference: Well: V-201, True North
Reference WeII: V-201 Vertical (1'VD) Reference:. V-201 82.1
Reference Wellpath: Plan V-201A DV: Oracle
Summary
<---------------- Offset Wellpath --------------> Reference Offset Ctr-Ctr No-C,o Allowable
Site Well Wellpath 1~1D MD Distance Area Deviation Warning
ft ft ft ft ft
PB V Pad V-202 V-202 V9 4260.45 4115.00 198.60 55.94 142.66 Pass: Major Risk
PB V Pad V-202 V-202L1 V5 4260.45 4115.00 198.60 55.91 142.69 Pass: Major Risk
PB V Pad V-202 V-202L2 V5 4260.45 4115.00 198.60 55.91 142.69 Pass: Major Risk
PB V Pad V-203 V-203 V18 3075.06 3310.00 712.72 58.31 654.41 Pass: Major Risk
PB V Pad V-203 V-203L1 V6 3950.00 7715.00 3807.93 No Offset Errors
PB V Pad V-203 V-203L2 V4 3850.00 6965.00 3496.62 No Offset Errors
PB V Pad V-203 V-203L3 V3 3850.00 6915.00 3466.28 No Offset Errors.
PB V Pad V-203 V-203L4 V3 3075.06 3310.00 712.72 58.31 654.41 Pass: Major Risk
~, PB V Pad V-204 V-204 V2 3075.95 3285.00 822.22 53.87 768.35 Pass: Major Risk
~I PB V Pad V-204 V-204L1 V2 3075.95 3285.00 822.22 53.87 768.35 Pass: Major Risk
PB V Pad V-204 V-204L1 P61 V6 3075.95 3285.00 822.22 53.87 768.35 Pass: Major Risk
PB V Pad V-204 V-204L2 V2 3075.95 3285.00 822.22 53.88 768.35 Pass: Major Risk
PB V Pad V-204 V-204L2P61 V5 3075.95 3285.00 822.22 53.88 768.35 Pass: Major Risk
PB V Pad V-204 V-204L3 V3 3075.95 3285.00 822.22 53.88 768.35 Pass: Major Risk
PB V Pad V-204 V-204PB1 V9 3075.95 3285.00 822.22 53.87 768.35 Pass: Major Risk
!, PB V Pad V-204 V-204PB2 V2 3075.95 3285.00 822.22 53.87 768.35 Pass: Major Risk
PB V Pad V-205 drilling Plan V-205L1 OBa V6 PI 3075.00 4395.00 2649.09 54.12 2594.96 Pass: Major Risk
', PB V Pad V-205 drilling Plan V-205L2 OA V6 Pla 3075.00 4395.00 2649.09 55.90 2593.19 Pass: Major Risk
I~ PB V Pad V-205 drilling V-205 V13 5252.23 9625.00 2097.68 79.63 2018.06 Pass: Major Risk
PB V Pad V-210 V-210 V9 3238.04 3300.00 1255.58 63.14 1192.44 Pass: Major Risk
PB V Pad V-211 V-211 V5 3078.61 3100.00 619.31 45.84 573.47 Pass: Major Risk
', PB V Pad V-212 V-212 V7 4700.00 3385.00 1935.53 62.58 1872.94 Pass: Major Risk
PB V Pad V-213 V-213 V5 4700.00 3425.00 1851.83 62.15 1789.68 Pass: Major Risk
PB V Pad V-213 V-213P61 V5 4700.00 3425.00 1851.83 62.15 1789.68 Pass: Major Risk
', PB V Pad V-214 V-214 V3 3239.02 3305.00 1164.25 64.26 1099.99 Pass: Major Risk
PB V Pad V-214 V-214P61 V2 Out of range
', PB V Pad V-214 V-214PB2 V3 3243.37 3305.00 1165.87 64.37 1101.50 Pass: Major Risk
', PB V Pad V-214 V-214PB3 V5 3243.37 3305.00 1165.87 64.37 1101.50 Pass: Major Risk
PB V Pad V-214 V-214PB4 V2 3243.37 3305.00 1165.87 64.36 1101.51 Pass: Major Risk
PB V Pad V-216 V-216 V8 4650.00 3745.00 1535.33 59.33 1476.00 Pass: Major Risk
PB V Pad V-217 V-217 V5 4578.67 3590.00 2033.16 56.05 1977.11 Pass: Major Risk
PB V Pad V-221 V-221 V6 4478.95 3245.00 1825.70 57.88 1767.81 Pass: Major Risk
~ •
FieldPrudhoe Bay',
', SitePB V Pad I
Wel1:V-201
',WellpathElan V-201AI
- - --
n
I
~I
e t
Site: PB V Pad
Drilling Target Conf.: 95%
Description:
Map Northing: 5971665.00 ft
Map Easting :590740.00 ft
Latitude: 70° 19'S6.346N
Shape: Circle
Target: V-201A Tgt OA
ell: V-201
Based on: Planned Program
Vertical Depth: 4330.00 ft below Mean Sea Level
Local +N/-S: 1577.33 ft
Local +E/-W: 233.44 ft
_ _ _ Longihide:149°15'50.166W
_ -_- --
Radius: 50 ft
65
160
0
0
0
c~
0
0
~-
i55
150
Site: PB V Pad
Drilling Target Conf.: 95%
Description:
Map Northing: 5971770.00 ft
Map Easting :590750.00 ft
_ Latitude: 70° 19'57.378N
Shape: Circle
Target: V-201 A Tgt OBd
ell: V-201
Based on: Planned Program
Vertical Depth: 4545.00 ft below Mean Sea Level
Local +N/-S: 1682.21 ft
Local +E/-W: 244.71 ft
Longitude: 149°15'49.836W _ _ _
Radius: 50 ft
;~ 8 5
80
~5
~0
0 0
o ~n
m co
65
60
0
0
TREE= 3-1/2 CW ~ v-2o
WELLHEAD= FMC
ACTUATOR = ____. NA
KB. ELEV = _ 83.5'
BF. ELEV = ~ ~~ 60.3'
KOP = ~~~900'
Max Angle = 36 ~ 2380'
_Datum MD = 4838'
Datum TVD = 4400' SS
9-5/8" CSG, 40/r: L-80 BTC, ID = 8.835" 3001'
Minimum ID = 2.812" ~ 2201'
3-1 /2" CAMCO SSSVN
SAFETY NOTES:
975' H 9-5/8" TA M PORT COLLA R
2201' I-~3-1/2" CAMCO B-61 SSSV N, ID = 2.812"
GAS LIFT MANDRELS
ST MD TVD DEV TYPE VLV LATCH PORT DATE
3 3814 3426 19 NMG DMY RK 0 09/23/03
2 3904 3511 19 MMG DMY RK 0 01 /01 /02
1 3997 3597 19 NMG DMY RK 0 04!27/02
I 4052' I
W/ BX PROF, ID = 2.812"
4077' -~ 7" X 3-1 /2" BKR PREMIER PKR, ID = 2.869"
4102' 3-1/2" HES X NIP, ID = 2.813"
4123' 3-1/2" HES X NIP, ID = 2.813"
13-1/2" TBG, 9.3#, L-80, .0087 bpf, ID = 2.992" I-I 4135'
PERFORATION SUMMARY
REF LOG:
ANGLEAT TOP PERF: 18 ~ 4750'
Note: Refer to Production DB for historical perf data
SQE SPF INTERVAL OpniSgz DATE
2-112" 4 4750 - 4765 O 04/01/02
2-1 /2" 4 4810 - 4830 O 04/01 /02
2-1 /2" 4 4845 -4855 O 04/01 /02
2-1 /2" 4 4954 - 4989 O 03/26/02
4141' I-13-1/2" WLEG, ID = 2.992"
4690' I-{ 7" MARKER JT (20') W/ RA TAG
4871' 1~7" MARKERJT(20') W/ RA TAG
PBTD I-1 5157'
7" CSG, 2s#, L-80, ID = 6.276" ~ 5257'
DATE REV BY COMMENTS DATE REV BY COAiiVfENTS
01/01/02 CWKAK OPoGINAL COMPLETION 04/01/05 ???/TLH JET PUMP/PKRS PULLED 11104
04/01/02 JGIWKK ADPERFS 12/04/06 RAC77LH TREE CORRECTION
08/05/03 DTR/KK PULL JET PUMP
09/23/03 RWL/KK GLV C10
12/20/03 RL/TLH SET JET PUMP (09/23/03)
05/14/04 TW/KAK DATUM MD & TVD CORRECTIONS
ORLON llNIT
WELL: V-201
PERMIT No: 2012220
API No: 50-029-23054-00
SEC 11, T11 N, R11 E, 4838' NSL & 1775' WEL
BP Exploration (Alaska)
TREE = 3-1 /2" CMJ
WE
L
LHEAD
= FMC
_
_
_
_
ACTUATOR = ~W NA
KB. ELEV = 83.5''
_
BF. ELEV = _ s_s 60.3'1
KOP = _____ _-900 I
Max Angle =~ 36 ~ 238
Datum MD = 4838'
_
Datum TVD = _
4400' SS
~~2 01 A i P re ~~' SAFETY NOTES:
975' 9-5/8" TA M PORT COLLAR
O
9-5/8" CSG, 40# L-80 BTC, ID = 8.835" 3001' '
Minimum ID = 2.812" @ 2201'
3-1 /2" CAMCO SSSVN
2201' I-13-1/2" CAMCO B-61 SSSVN, ID= 2.812"
GAS LIFT MANDRELS
ST MD TVD DEV TYPE VLV LATCH PORT DATE
3 3814 3426 19 MMG DMY RK 0 09/23/03
2 3904 3511 19 NMG DMY RK 0 01 /01 /02
1 3997 3597 19 MMG DMY RK 0 04!27/02
BX PROF, ID = 2.812"
Jet Cut in 3.5" tubing above packer ~--~ 4062'
407~~ 7" X 3-1 /2" BKR PREMIER PKR, ID = 2.869"
4102' 3-1/2" HES X NIP, ID = 2.813"
4123' 3-1l2" HES X NIP, ID = 2.813"
~3-1/2" TBG, 9.3#, L-80, .0087 bpf, ID= 2.992" ~-{ 4135'
PERFORATION SUMMARY
REF LOG:
ANGLEAT TOP PERF: 18 ~ 4750'
Note: Refer to Production DB for historical perf data
SQE SPF INTERVAL Opn/Sqz DATE
2-1 /2" 4 4750 - 4765 O 04/01 /02
2-1 /2" 4 4810 - 4830 O 04/01 /02
2-1 /2" 4 4845 -4855 O 04/01 /02
2-1 /2" 4 4954 - 4989 O 03126102
PBTD H 5157'
7" CSG, 26#, L-80, ID = 6.276" ~ 5257'
4141' 1~3-1/2" WLEG, ID = 2.992"
4350' f--ITCC-P8A w/ T5.8ppg cmt
4690' 7" MARKER JT (20') W/ RA TAG
4871' ~-~ T' MARKER JT (20') W/ RA TAG
DATE REV BY COMMENTS DATE REV BY CONN~AENTS
01/01/02 CWKAK ORIGINAL COMPLETION 04!01/05 ???ITCH JET PUMP/PKRS PULLED 11/04
04/01/02 JGIWKK ADPERFS 12/04/06 RAC/TLH TREE CORRECTION
08/05/03 DTRIKK PULL JET PUMP
09/23/03 RVVL/KK GLV Cl0
12/20/03 RL/TLH SET JET PUMP (09123/03)
05/14/04 NV/KAK DATUM MD & TVD CORRECl10N5
ORION UNIT
WE1L: V-201
PERMIT No: 2012220
API No: 50-029-23054-00
SEC 11, T11 N, R11 E, 4838' NSL & 1775' WEL
BP Exploration (Alaska)
TREE = 41 /16" CNV
WtZLHEAD=
A_CT_
UATOR =
~~_ _ FMC
~ Leo
~~_~
_
KB. E
LEV
= 82.1'
_
_
BF. E1EV = __
53.6'
___
KOP= _ __
3075
_ _ _
Max Angle =~
- _
61 @4322'
~
Datum MD = 6812
_
Datum TVD = _ _
_ 4841' ss
V-~1Ai Prop Com pleti~ SAFETY NOTES:
XXX 9-5/8" TAM PORT COLLAR - IF RUN
~ 3-1 /2" HES X NIP, ID = 2.813" ~
9-5/8" CSG, 40# L-80 BTC, ID = 8.835" 3001'
Minimum ID = 2.813"
3-1 /2" HES X NIPPLE
WATERFLOOD/GAS LIFT MANDRELS
ST MD TVD DEV TYPE VLV LATCH PORT DATE
7 MMG DCR-1 RKP °w
6 MMG-W DMY RK U
5 MMG-W AMY RK 0
4 MMG-W i~MY RK 0
3 MMG-W AMY RK 0
2 MMG-W 7MY RK 0
1 MMG-W !AMY RK ^v
XX' 3-1 /2" HES X NIP, ID = 2.813"
XX' 3-1/2" HES X NIP, ID = 2.813"
PERFORATION SUMMARY
REF LOG:
ANGLE AT TOP PERF:
Note: Refer to Production DB for historical pert data
SQE 5PF INTERVAL Opn/Sqz DATE
3-1/2" TBG, 9.3#, L-8D, .0087 bpf, ID = 2.992" 4135'
PBTD 6732'
7" CSG, 26#, L-80, ID = 6.276" 6812'
XX' 3-1/Z" HES X NIP, ID = 2.813"
XX' 3-1/2" HES X NIP, ID = 2.813"
XX' 3-1/2" HES X NIP, ID = 2.813"
XX' 3-1/2" WLEG, ID = 2.905"
DATE I REV BY
track com
ORION UNIT
WELL: V-201 Ai
PERMIT No:
API No: 50-029-2305401
SEC 11, T11 N, R11 E, 4838' NSL & 1775' WEL
1500`00'~'Ip ~
PLA Z
e~
i
1
B
m
z
E 4400
NOTES
s • w E ,J6i~N t
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~~ ° ° °°°
LS 8306
°° °
'mss Iowa- `~
SURVEYOR'S CERTIFICATE
I HEREBY CERTIFY THAT I AM
PROPERLY REGISTERED AND LICENSED
TO PRACTICE LAND SURVEYING IN
THE STATE OF ALASKA AND THAT
THIS PLAT REPRESENTS A SURVEY
MADE 8Y ME OR UNDER MY DIRECT
SUPERVISION ANO THAT ALL
0[MENSIONS AND OTHER DETAILS ARE
CORRECT AS OF NOVEMBER 23, 2001.
1. DATE OF SURVEY: NOVEMBER 23. 2001.
2. REFERENCE FIELD BOOK WO-01-37, PAGES 35-36.
3. ALASKA STATE PLANE COORDINATES ARE ZONE 4, '
NAD 27. GEODETIC POSITIONS ARE NAD '27.
4. BASIS OF HORIZONTAL CONTROL IS V-PAD
OPERATOR MONUMENTATION.
5. BASIS OF ELEVATION IS KUPARUK PIPELINE CONTROL
PER FR BELL ac ASSOCIATES. ELEVATIONS ARE BP MSL DATUM.
6. THE MEAN SCALE FACTOR FOR V-PAD IS 0.999909334.
LEG ND
AS-BUILT CONDUCTOR
^ EXISTING CONDUCTOR
LOCATED WITHIN PROTRACTED SEC. 11 T. 11 N. R. 11 E UMIAT MERIDIAN, ALASKA
WELL A.S.P. PLANT GEOOET[C GEODETIC CELLAR SECTION
ND. COORDINATES COORDINATES POSITION DMS) POSITION{D.DD) BOX ELEV, OFFSETS
5,970,085.11 10,175.89 70'19'40.833" 70.3280092'
53
6. 4,838' FSL
V-201 590,525.63 4,779.58 149'75'58.982" 149.2858280' ' 1,775' FEL
5,970,089.06 10,179.90 70'19'40.870" 70.3280195'
53
8' 4,842' FSL
V-102 590,540.35 4,794,92 149'75'58.550" 149.2857083' ' 1,760' FEL
VICINITY MAP
N.T.S.
Alaska Department of Natural Resources Land Administration System Page 1 of 4
•
r :a=, ~ r' : •r~ °-~ 1 ~.~:;r:.: ,t-~~ ~i=~`s Recc~rde~`s Search Sta#e Cabins ~~~u~~ fi~~1C€~S
Alaska QI~R Case Summary
File Type ADS ~ File Number: 28240 ~ Printable Case File_Summa.ry
See Township, Range, Section and Acreage?
Yes ~'° No
New Search
i-,4S i~1en~, !Case Abstract ~ Case Detai! ! land Abstract
_~,
File: ~DL 2S24f1 '''~' ~~ Searrhfor Status Plat Updates
;~S Cif U?%] 1/~'llO7
Customer. 000107377 BP EXPLORATION (ALASKA) INC
PO BOX 1 966 1 2/900 E. BENSON BL ATTN: LAND MANAGER-
ALASKA
ANCHORAGE AK 995196612
Case Type: 784 OiL & GAS LEASE COMP DNR Unit: 780 OIL AND GAS
File Location: DOG DIV OIL AND GAS
Case Status: 35 ISS/APPRV/ACTV AUTH Status Date: 09/14/1965
Total Acres: 2560.000 Date Irtitiatecl: 05/28/1965
Once of Primary Respof~sibility: DOG D[V OIL AND GAS
I ast Transaction Date: 12/04/2006 Case Sa~btype: N S NORTH SLOPE
Last Traf~saction: AA-NRB ASSIGNMENT AP PROVED
l/eridi~rt~: [_; Township: OLIN Ran~e.~ Olt1. .S'e~~tic~r~: O1 .5'c~clro~7Acres:640 ~eareh
PI<ats
lleridicrn.~ l' Tvtirrr~hrl?: Q 1 I N Rcrj~~Tc~: 0l ~ L~; ~S'rc~tir,ii.~ U~ I S'ecliuil _4crf~e: (i~O
lerida~r~.~ l_~ Toirn.~l~iJ~: Ol I N R~~il~~~.~ I) I I E ,S'~~cli~~n.~ I 1 J .ti'c~~~liurt :4Cf^es.~ (i 11)
JIerICliurl.~ (' 7utr~ts{u/>: U I I N Ruir;~c~: O l t I-; ,S'rc~tluit: l~ .S'c~~~tluf~ ~ 1cr~s: 64f)
Leal llcscription
OS-28-1965 * * *SALE NOTICE LEGAL DESCRIPTION*
C1 ~-19 OLIN-011 E-UM 1,2,11,12 260.00
0=1-01-1977 * * UNITIZED. LEASE AND PARTICIPATING AREA LEGAL DESCRIPTIONS
LEASE COMMITTED IN ENTIRETY TO PR UDHOE BA Y UNIT AND OIL RIM
GAS CAP PA
PR UDHOE BA I' UNIT
http://www.dnr. state.ak.us/las/Case_Summary.cfm?FileType=ADL&FileNumber=28240&... 2/14/2007
' .Alaska Department of Natural Resources Land Administration System Page 2 of 4
TRACT ~ 0
OIL RIMAND GAS C'AP PARTICIPATING AREAS
T. 11 N.. R. 11 E., UMIAT MERIDIAN, ALASKA
SECTION 1: ALL, 6-~O.OOACRES;
SECTION 2: ALL, 6-10.00 ACRES;
SECTION I1: ALL, 640.00 ACRES;
SECTION 12: ALL, 640.00 ACRES:
CONTAINING APPROXIMATELY 2, 560.00 ACRES, MORE OR LESS.
11-01-~ 001 * *FOIZ~IIATION OF BOREALIS PARTICIPATING AREA LEGAL DESCRIPTION
LEASE INCORPORATED IN PART INTO THE BPA
PRUDHOE BAY U.~VIT
BOREALIS PARTICIPATING AREA
TRACT SO (PARTIAL]
T.11 N., R.1 I E., UMIAT MERIDIAN, ALASKA
SECTIO~r 1: W2, W2E2, 480. DO ACRES;
SECTION 2: ALL, 6.10.00 ACRES,
SECTION 11: N2, N2S2, 480.00 ACRES;
SECTION 12: NW4, bV2NE4, 2-10.00 ACRES;
THIS TRACT CONTAINS 1,8=lD.OO.ACRES, MORE OR LESS.
02-01-?004 * *FORMATION OF ORLON PARTICIPATING AREA LEGAL DESCRIPTION*
LEASE COMMITTED IN PART TO ORLON PARTICIPATING AREA
PR UDHOE I3A Y UNIT
TR-~CT SD
ORLON PARTICIPATING AREA
T. 11 N., R. 11 F.., U1~II.1T RERIDIAN, ALASIkA
http://www.dnr.state.ak.us/las/Case_Summary.cfm?FileType=ADL&FileNumber=28240&... 2/ 14/2007
.Alaska Department of Natural Resources Land Administration System Page 3 of 4
•
SECTION 1: ALL. 640.00 ACRES,
SECTION 2: ALL, 610.00 ACRES,
SECTION 11: El/2. E1/?NWI/4, 400.00 ACRES.
SECTION 12: ALL, 6-10.00 ACRES;
CONTAINING APPROXIMATELY2,320.00RCRES, MORE OR LESS.
1 ?-01-2004 * * * *BOREALIS PA EXPANDED, LEASE INCORPORATED IN PART
LEGAL DESCRIPTIONISASFOLLOT~i'S:
PRUDHOE I3AY UNIT
BOREALIS PARTICIPATING AREA
TRACT ~ 0 (PARTIAL)
T 11 N. , R.11 E.. UMIAT MERIDIAN, ALASKA
SECTION 1: E2E2, 160.00 ACRES,
SECTION 11: S2SE4, 80.00 ACRES;
SECTION 12: S2, E2NE4, 400.00 ACRES;
THIS TRACT CONTAINS 640.00 ACRES, MORE OR LESS.
* *THE ACREAGE NOW INCORPORATED INTO THE 13PA IS DESCRIBED AS FOLLOWS:
PRUDHOE BAY UNIT
BOREALIS PARTICIPATING AREA
TRACT ~0 (PARTIAL)
T. I IN, T. ME., UMIAT MERIDIAN, ALASKA
SECTION 1: ALL, 640.00 ACRES;
SECTION 2: ALL, 640.00 ACRES;
SECTION 11: N2, SE4, N2SyV4, ~60ACRES;
SECTION 12: ALL, 6=10.00 ACRES:
http://www. dnr. state.ak.us/las/Case_Summary. cfm?FileType=ADL&FileNumber=28240&... 2/ 14/2007
• ~ Alaska Department of Natural Resources Land Administration System
• •
THIS TRACT CONTAINS 2~l80.00 ACRES, t1IORE C)R LESS.
t"
Page 4 of 4
Last updated on 02114/2007.
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v-2o 1 a
~ •
Subject: V-201A
From: Thomas Maunder <tom_maunder@admin.state.ak.us>
Date: Thu, 15 Feb 2007 15:16:06 -0900
Tn: Grc~ Hobbs ~~Grc~.Hobbs@bp.con~--
Greg,
Would you please pass this message on to Brandon. I don't seem to have his
eddress.
Nice job on the review of the wells within 1/4 mile of the planned wellbore. I
concur with what is stated on page 3. The only items I found that should be
considered in the future is plugbacks and "lost hole sections". On V-111 there are
at least 2 major hole sections that were lost and plugged back. The first appears
to be "steel re-enforced" with a BHA and looks to be below the Schrader. The
second section was plugged back all the way to the shoe. Such hole sections are
usually the wild cards in any integrity review.
Based on the information I could see in our files, which appear to be pretty
complete I do not see any integrity issues with the PBs.
Call or message with any questions.
Tom Maunder, PE
AOGCC
1 of 1 2/15/2007 3:23 PM
•
•
• •
T'RANSIVIIT'~'AL LET'~'Ela CHECICi,IS~'
vv~t.lr ~ AIVIE .or~'L/ / ~d/.q
PTD~ o?o,~ -d~~
Development ~ Service Exploratory Stratigraphic Vest
Yon-Conventional Welt
Circle Appropriate Letter /Paragraphs to be Included in Transmittal Letter
CHECK I ADD-ONS ! TEXT FOR APPROVAL LETTER
LL'HAT j (OPTIONS)
APPLIES
I NRiLTI LATERAL The permit is for a new wellbore segment of existing ~
! ~ well
j ~ (If last two digits in I Permit No. , AP[ No. ~0-
API number are
!between 60-69) Production should continue to be reported as a function of the
i original API number stated above.
PILOT HOLE 7
~ [n accordance with 20 AAC 25A05(f), all records, data and. logs
;acquired for the pilot hole must be clearly differentiated in both
i i well name ( PH) and API number
j ~ ' (50- - -_~ from records, data and logs
~ ' ~ acquired for well
~ i SPACING The permit is approved subject to full compliance with 20 AAC
'EXCEPTION 123.0». Approval to perforate and produce /inject is contingent ~
upon issuance of a conservation order approving a spacing j
i ~ exception. assumes the ~
~ liability of any protest to the spacing exception that may occur.
i
,DRY D[TCH ~ At[ dry ditch sample sets submitted to the Commission must be in
i 'i SA!~IPLE I no greater than 30' sample intervals from below the permafrost or
from where samples are first caught and !0' sample intervals j
,' ~ through target zones.
;Please note the following, special condition of this permit:
jNon-Conventional ~ production or production testing of coal bed methane is not allowed
i j Well ~ for (name of well, until after (Company Name) has designed and
implemented a water well testing program to provide baseline data
j on water quality and quantity. ~Com~any Name) must contact the
~ 'Commission to obtain advance approval of such water well testing
I I ~ program. ~
Rev: 12~i06
C.^ jody