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Alaska Oil and Gas Conservation Commission
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MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
TO: Jim Regg DATE: 6/8/2025
P. I. Supervisor
FROM: Josh Hunt SUBJECT: Surface Abandonment
Petroleum Inspector Sterling Unit 43-09X
Hilcorp Alaska LLC
PTD 2070730; Sundry 319-174
5/20/2025: I traveled to the Sterling Unit (SU) 43-09X location and met with Mike
Erstrom representing Hilcorp Alaska LLC. The well had cement in all annuli. I had Mike
pound on the cement with a big hammer to verify. At this time, he did not have
paperwork on hand but was able to email me the sundry. I checked the information on
the marker plate and found some errors in the Well # and API #. I advised him that this
needs to be fixed prior to welding the plate on. He then told me that he had surveyors
coming at some point to check the cutoff depths.
5/27/2025: I was notified that this well was cut off below the required minimum of 3 feet
below original grade.
6/03/2025: I traveled back to location and verified the information on the marker plate
was correct and gave them the go ahead to bury this well.
6/8/2025: I traveled back to location for a site clearance after the well was completely
buried. Normally there is a mound on top of the well location. The pad was leveled flat
above the well. I asked why there was no mound; Mike explained that this location is a
current construction area and because they will have a drilling rig coming on location
soon, Hilcorp wishes to keep this location level with the pad grade and add material as
needed to maximize the usable space. They have to area coned off to keep heavy
equipment, vehicles, and people clear.
Original ground level around SU 43-09X in 2019 was 226.2 feet. The cut off depth is
222.4 feet putting the cut at 4 feet below original grade.
Attachments: Photos (3)
2025-0608_Surface_Abandon_SU_43-09X_jh
Page 2 of 3
Surface Abandonment – SU 43-09X (PTD 2030730)
Photos by AOGCC Inspector J. Hunt
6/3/2025; 6/8/2025
Cut off prior to welding the plate Marker plate installed on
surface casing stub
2025-0608_Surface_Abandon_SU_43-09X_jh
Page 3 of 3
Site clearance for SU 43-09X
MEMORANDUM
TO: Jim Regg
P.I. Supervisor
State of Alaska
Alaska Oil and Gas Conservation Commission
FROM: Bob Noble
Petroleum Inspector
Section: 9 Township: 5N
Drilling Rig: Hilcorp 401 Rig Elevation: 21 ft AGL
Operator Rep: Phil Rafferty '
DATE: November 20, 2019
SUBJECT: Well Bore Plug & Abandonment
Sterling Unit 43-09X
Hilcorp
PTD 2070730; Sundry 319-174
Range: 10W
Total Depth: 6185 ft MD
Suspend:
Meridian: Seward
Lease No.: FEDA028063
P&A: X
Casing/Tubing Data (depths are MD):
NA
NA
NA
Casing Removal:
Conductor:
20"
O.D.
Shoe@
103
Feet
Csg Cut@
Feet
Surface:
13 3/8"
O.D.
Shoe@
1990
Feet
Csg Cut@
Feet
Intermediate:
O.D.
Shoe@
Feet
Csg Cut@
Feet
Production:
9 5/8"
O.D.
Shoe@
6174
Feet
Csg Cut@
Feet
Liner:
O.D.
Shoe@
Feet
Csg Cut@
Feet
SS Tubing:
2 3/8"
O.D.
Tail@
5605
Feet
Tbg Cut@
Surface Feet
LS Tubing:
2 7/8"
O.D.
Tail@
5764
Feet
Tbg Cut@
5520 ft ' Feet
Plugging Data:
Test Data:
Type Plug Founded on Denth Btm De th To MW Above Verified
Initial 15 min ,in min as min ao�.at
Tubing
NA
NA
NA
IA
2650
2650
2650
P '
OA
0
10
0
Remarks:
Initial wellbore plug for this P&A. According to Hilcorp representative P4107 Rafferty, the work done before this plug verification
was cut the long string tubing at 5620 ft and pull together with the entire short string tubing, set a retainer at 5610 ft MD, and
pump 24 bbls cement were below and 4bbls above the retainer (100% excess). A plug tag was not required by AOGCC.
Attachments: none
rev. 11-28-18 2019-1120_Plug_Verification_Sterling_43-09X_bn
THE STATE
°fALASKA
GOVERNOR MIKE DUNLEAVY
Bo York
Operations Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Sterling Field, Sterling Undefined Gas Pool, SU 43-09X
Permit to Drill Number: 207-073
Sundry Number: 319-174
Dear Mr. York:
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
�.a ogcc.a loska.gov
Enclosed is the approved application for the sundry approval relating to the above referenced well.
Please note the conditions of approval set out in the enclosed form.
As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further
time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC
an application for reconsideration. A request for reconsideration is considered timely if it is
received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if
the 23rd day falls on a holiday or weekend.
Sincerely,
Jessie L. Chmielowski
Commissioner
DATED this ID day of April, 2019.
gBDMSH�""APR 10 2019
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
DECEIVED
APR 0 4019
1. Type of Request: Abandon ❑Z - Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑
Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑
Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Venting Other: ❑
2. Operator Name:
4. Current Well Class:
5. Permit to Drill Number:
Hilcorp Alaska, LLC
Exploratory ❑ Development ❑� -
Stratigraphic ❑ Service ❑
207-073 -
3. Address: 3800 Centerpoint Dr, Suite 1400
6. API Number:
Anchorage Alaska 99503
50-133-20569-00-00 '
7. If perforating:
8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool? N/A
No
Will planned perforations require a spacing exception? Yes El No
Sterling Unit (SU) 43-09X
9. Property Designation (Lease Number):
10. Field/Pool(s):
FEDA028063
Sterling Unit / Sterling Undefined Gas Pool '
11. PRESENT WELL CONDITION SUMMARY
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
6,185' 5,698' 6,114' 5,627' 1,956 psi N/A N/A
Casing Length Size MD TVD Burst Collapse
Structural
Conductor 103' 20" 103' 103' 3,060 psi 1,500 psi
Surface 1,990' 13-3/8" 1,990' 1,870' 3,450 psi 1,950 psi
Intermediate
Production 6,174' 9-5/8" 6,174' 5,68T 5,750 psi 3,090 psi
Liner
Perforation Depth MD (ft):
Perforation Depth TVD (ft):
Tubing Size:
Tubing Grade:
Tubing MD (ft):
See Attached Schematic
See Attached Schematic
Short: 2-3/8" / Long: 2-7/8"
6.49 / L-80 (short & long)
Short: 5,605' / Long: 5,764'
Packers and SSSV Type:
Packers and SSSV MD (ft) and TVD (ft):
Baker GT Dual, Baker SC -1 Gravel Pack (x2) & Baker Model D Sump Pkrs
5,588' MD, 5,627' MD, 5,738' MD & 5,784' MD
12. Attachments: Proposal Summary ❑✓ Wellbore schematic
13. Well Class after proposed work:
Detailed Operations Program ❑ BOP Sketch ❑Z
Exploratory ❑ Stratigraphic ❑ Development Service ❑
14. Estimated Date for
15. Well Status after proposed work:
Commencing Operations: May 1, 2019
OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑
GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑
16. Verbal Approval: Date:
Commission Representative:
GINJ ❑ Op Shutdown ❑ Abandoned Q -
17. 1 hereby certify that the foregoing is true and the procedure approved herein will not
be deviated from without prior written approval.
Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer
Authorized Title: Operations Manager Contact Email: tkramer(o)hilcoro.com
Contact Phone: 777-8420
�
Authorized Signature: � Date: / �� � d 1 �I
COMMISSION USE ONLY
Conditions of approval: Notify Commission so that a representative may witness Sundry Number:
51`1-11-74
Plug Integrity BOP Test ICJ Mechanical Integrity Test El Location Clearance
-1 r
Other: ♦rv /JS
J zo
Post Initial Injection MIT Req'd? Yes ❑ No❑y RBDMS-) fWgPR 1 01019
q
Spacing Exception Required? Yes ❑ No [0,6y f5ubsequent Form Required: 16-d-107
APPROVED BY
Approved by: '
COMMISSIONER THE COMMISSION Date: (' Q
a �-ec IR ,�# �G1�IApp
Form 10-403 Revised 4/2017 Approved applica i li r h t e date of approval. Submit Form and
Attachments in Duplicate
H
Qikora Alaska, LU
Well Prognosis
Well: SU 43-09X
Date:03/27/2019
Well Name:
SU 43-09X
API Number:
50-133-20569-00
Current Status:
Shut -In Gas Well
Leg:
N/A
Estimated Start Date:
May 1, 2019
Rig:
401
Reg. Approval Req'd?
10-403
Date Reg. Approval Rec'vd:
Regulatory Contact:
Donna Ambruz 777-8305
Permit to Drill Number:
207-073
First Call Engineer:
Ted Kramer
(907) 777-8420 (0)
(985) 867-0665 (M)
Second Call Engineer:
Bo York
(907) 777-8345 (0)
(907) 727-9247 (M)
AFE Number:
Current Bottom Hole Pressure:
Maximum Expected BHP:
Max. Potential Surface Pressure:
Brief Well Summary:
- 2,480 psi @ 5,243' TVD
- 2,480 psi @ 5,243' TVD
- 1,956 psi
(Based upon a 0.473 psi/ft gradient to
the deepest open perforation)
(Based upon a normal gradient)
(Based upon max. expected BHP and
a 0.10 psi/ft gas gradient to surface)
Sterling Unit 43-09X was spud (June 2007) and completed in October 2007. SU 43-09X was a dual string,
gravel -packed completion in the Sterling B4 sand. The lower B4 interval (5,766'-5,776') proved to be wet and
after initial testing has remained shut-in. The upper B4 interval (5,724'- 5,730') produced gas up the 2-3/8"
Short String in November and December, 2007 and from January through November, 2009. The well briefly
produced gas for a few days in 2013, but otherwise has remained shut-in. There has been no production since
January 2014.
The purpose of this Sundry is to permanently P&A SU 43-09X. 11Z
Pre - Rig Work:
1. Provide 24 hour notice to the AOGCC that Plug and Abandonment of well will commence per
AOGCC regulations 20 AAC 25.112 (h). Notify the BLM of P&A as per 43 CFR 3160 G.
2. RU Pump Truck. RU on the tubing and casing and conduct an IA pressure test to 2,500 psi on chart
`{' s for 30 min. SU 43-09X is a dual string completion, so the Long String (2-7/8") and Short String (2-
3/8") tubing will both need to be monitored during the IA test. Bleed down pressure.
S 3. MIRU E -line, on the Short String (2-3/8" tubing).
5 4. PU & RIH w/ Tubing Punch to "'5,580'. Punch holes from "'5,580' to -5,576'. POOH.
5. RU E -line on the Long String (2-7/8" tubing).
6. PU & RIH w/ Tubing Cutter to 5,620'. Cut Long String @ 5,620' & POOH.
7. RU Pump Truck onto Short String and circulate the well with 9.8 ppg kill weight fluid.
Workover Rig 401:
8. MIRURig401.
9. Notify AOGCC and BLM 24 hours in advance of test to extend the opportunity to witness.
10. Set back pressure valve. Z S°"
11. ND wellhead, NU 13-5/8" BOP and test to 250 psi low & psi high, annular to 250 psi low &
2,500 psi high. Record accumulator pre -charge pressures and chart tests.
H
lblmro A6.kn, LU
a. Perform Test.
Well Prognosis
Well: SU 43-09X
Date:03/27/2019
b. Test Dual VBR rams on 2-7/8" and 2-3/8" test joints.
c. Submit completed form 10-424 to AOGCC within 5 days of BOPE test. Copy to BLM.
12. PU and POOH with dual tubing strings, laying down GLM's, laying down 2-3/8" Short String, and
racking back the 2-7/8" Long String. P p (
a. Pull Baker GT Dual Packer, set @ 5,588'.
b. Pull Long String from tubing cut @ 5,620'.
Note: The Long and Short Strings were run together and are reported to contain 7 GLM's, each. As such,
Hilcorp feels more comfortable pulling the two strings together, rather than separately.
13. PU 9-5/8" Cement Retainer & RIH on 2-7/8" tubing.
14. Set Cement Retainer @ —5,610'.
a. Cement Retainer should be set —10' above the 2-7/8" tubing stub. � S
15. RU cementers and squeeze the B4 water and gas sands by down squeeze method, with 24 bbls of
15.8 ppg cement.
a. Note: Tubing + Annular volume = —12 bbls.
b. 100% excess pumped/squeezed to ensure perforation isolation.
16. Pull out of cement retainer and leave an additional 4 bbls of cement ("'53') on top of the retainer.
POOH & WOC.
ss
ori CBL's indicate that cement was not brought up past t e surface shoe so running a new CBL is not
r necessary. Work scope will proceed as if there is no cement across the surface casing shoe (behind the 9-5/8"
casing).
17. RU E -line.
18. PU & RIH w/ 9-5/8" CIBP to —2,140'. Set same depth. POOH.
19. PU 1'i casing punch and RIH to 2,139'. Punch holes from 2,139' —2,135'. POOH.
20. PU 2"d casing punch and RIH to 1,880'. Punch holes from 1,880' to 1,876'. POOH.
L 21. PU and RIH w/ 2-7/8" tubing (open ended) to 2,139'.
22. RU cementers & place a 450' ("'34 bbls) balanced plug of cement on top of the CIBP.
23. Pressure up 500 psi on the well and hold for 30 min. POOH & WOC.
24. RU slickline & RIH to tag top of cement. Verify that TOC is at or above 1,890' to ensure at least 100'
of cement extends above the surface casing shoe. POOH.
25. RU E -line.
26. PU & RIH with 9-5/8" CIBP. Set plug at 160'. POOH.
�\ ✓� 27. PU 3rd casing punch and RIH to 159'. Punch holes from 159'— 155'. POOH.
28. RU cementers and circulate cement down the IA and up the 9-5/8" casing, through the holes at
1591-1551. WOC.
a. If circulation can't be established, PU & RIH with 2-7/8" tubing (open ended) and place a
160' balanced plug of cement from the CIBP to surface. POOH and lay down pipe. WOC.
29. Place dry hole tree on well.
30. RDMO Workover Rig 401.
Well Prognosis
Well: SU 43-09X
IIDeoru AI.A., LU
Date: 03/27/2019
Post - Rig Abandonment Procedures:
31. Excavate cellar, cut off casing 3' below natural GL.
32. Notify AOGCC and BLM 48hrs in advance.
33. Create well abandonment marker per 20 AAC 25.120 and BLM Onshore Order No. 2 111.6.10. The
r
owin bead -welded directly to the marker plate:
a. Hilcorp Alaska, LLC
b. PTD: 207-073
c. Well Name: SU 43-09X
d. API:50-133-20569-00
34. Set marker plate per 20 AAC 25.120 and BLM Onshore Order No. 2 III.G.10, collect GPS coordinates.
35. Photo document casing cut-off and Welded Plate install.
36. Backfill excavation, close out location.
Attachments:
Actual Schematic
Proposed Schematic
BOPE Schematic
RWO Sundry Revision Change Form
R
Ililcorp Alaska, LLC
API #:
50-133-20569-00-00
PlOperty Des:
A-028063
KB elevation:
245' (21'AGL)
SDud:
6/9/2007 16:30 him
Latitude:
6(r 32' 15.628" N
Longitude:
151° 01' 51.465" W
Rig Released:
tat 6/24/2007 09:00 him
-Baker GT Dual Packer w160K shear ring @ 5,588'
-XN-nipple @5,600' (ID =1,75")
2nd 10/30/2007 06:00 him
Reached TD:
8/17/2007 6,185' MD
Sterling 84 Perforations:
MD R Gun Type Data
5724'-5.]30' 6'TCP, 7'OD, 18spf, 20'11a (10 M)
(S5.10%7=)
5,766-5,776' 10TCP.T'00.18a,4 20 pla (10119107)
• Baker SC -1 gravel pack packer @ 5,627'
" Knock out isolation valve @ 5,660'
SU 43-9x
Sterling Pad
2,408' FSL, 426' FEL
Sec. 9, T5N, R10W, S.M.
ACTUAL
SCHEMATIC
Drive Pipe
20" K-55 133 ppf
122 Bottom
MD 0' 103'
WD 0' 103'
Surface Casing
13-318" J-55 68ppf BTC
Top Bottom
MD 0' 1,990'
WD 0' 1,870'
Cmt w/ 620 sks, 12ppg, Type 1
Production casing
9-518" L-80 40ppf BTC
Toe Bottom (8.835- 1D)
MD 0' 6,174'
WD 0' 5,687'
Cmtw/210sks, 12.5ppg, ClassG
Cmt w/ 400 sks, 15.8ppg, Class G
B4 SAND yl� 5-1/2" x 18'x 12 ga BakerWeld 140 Screen @ 5.720'
4,990' SSND
Longstrtng: 2-7/8"x 10'longstring Blasi
Shanstring Perts (Sterling B4 Gas)'
5r724'-5730' (6')
Lonastrmci Pets (Sterling B4 Water).
5,766'-5,776' (10')
PBTD TD
6,114' MD 6,185' MD
5,627' ND 5,698' ND
Baker SC -1 gravel pack packer @ 5,738'
5-1/2" x 18' x 12 ga BakerWeld 140 Screen
c /@ 5,,-764'
Baker Model D sump packer
GWC @ 5,035'
SSND
SBHP =1,990 si
-5,066 SSND
Well Name & Number:
-'
Lease:
Sterling Unit
short string
Kenai Penisula Borough
State:
Alaska I Country: USA
S.S. Perforations (MD):
2-318- L40 8.4ppf EUE tubing
(ID =1.995"(
Short String (ND):
5,237' - 5,243'
L.S. Perforations (MD):
(10') 5,766'-5,776'
-Baker GT Dual Packer w160K shear ring @ 5,588'
-XN-nipple @5,600' (ID =1,75")
5,280'-5,290'
Angle @ KOP and Depth:
Car / 100R 200'
An le/Perfs:
-Wireline re-entry guide @ 5,605'
BHP:
1,980 BHT:
Lona String
6% KCL
Date Completed:
08/08/07
Kelly Bushing:
2-718" L410 6.4ppf EUE tubing
Revised by:
Kevin Skiba
Last Revision Date:
Brtl (I1)=2.441")
-GLM'sBaker ID 1,740', , 3,884', 4,658'arrin, 5,030', 5,433'
Pecker
-Baker GT Dual Packer w/BOK shear ring @ 5,588'
B4 SAND yl� 5-1/2" x 18'x 12 ga BakerWeld 140 Screen @ 5.720'
4,990' SSND
Longstrtng: 2-7/8"x 10'longstring Blasi
Shanstring Perts (Sterling B4 Gas)'
5r724'-5730' (6')
Lonastrmci Pets (Sterling B4 Water).
5,766'-5,776' (10')
PBTD TD
6,114' MD 6,185' MD
5,627' ND 5,698' ND
Baker SC -1 gravel pack packer @ 5,738'
5-1/2" x 18' x 12 ga BakerWeld 140 Screen
c /@ 5,,-764'
Baker Model D sump packer
GWC @ 5,035'
SSND
SBHP =1,990 si
-5,066 SSND
Well Name & Number:
Sterling Unit 43-9x
Lease:
Sterling Unit
County or Parish:
Kenai Penisula Borough
State:
Alaska I Country: USA
S.S. Perforations (MD):
(6') 5,724' -5,730'
Short String (ND):
5,237' - 5,243'
L.S. Perforations (MD):
(10') 5,766'-5,776'
Long String D).
5,280'-5,290'
Angle @ KOP and Depth:
Car / 100R 200'
An le/Perfs:
1.45°
BHP:
1,980 BHT:
Completion Fluid:
6% KCL
Date Completed:
08/08/07
Kelly Bushing:
21' (AGL)
Revised by:
Kevin Skiba
Last Revision Date:
09/02/09
U
flilcom Alaska. LLC
207-073
50-133-20569-00-00
A-028063
245' (21'AGL)
6/9/2007 16:30 hrs
60e 32' 15.628" N
151° 01' 51.465" W
1st 6/24/2007 09:00 hrs
2nd 10/30/2007 06:00 hrs
6/17/2007 6,185'MD
CIBP @ 160'w/ Cement to Surface
CIBP @ -2,140' w/ 450' of cement on top
(TOC @ or above 1,890')
Cement Retainer @ -5,610' w/ 4 bbls of cement (-53')
on top (TOC @ -5,557')
Top of 2-7/8" tbg stub @ -5,620'
a: Squeeze 24 bbls o1 cement thru retainer, into B4 sand
orations (200% of calculated Tubing +Annular Volume).
SU 43-9x
Sterling Pad
2,408' FSL, 426' FEL
Sec. 9, T5N, R10W, S.M.
Casing Punches:
A F 1591-155
Cut 2-7/8" Long String @ -5,620'
Baker SC -1 gravel pack packer @ 5,627' D
Knock out isolation valve @ 5,660'
STERLING B4 SAND
Shortslring Perfs (Sterling B4 Gas)
5,724'-5,730' (6')Squeezed
Longslrinq Perfs (Sterling B4 Water)'.
5,766'-5,776' (10')Squeezed
PROPOSED
SCHEMATIC
Drive Pipe
PBTDTD
20" K-55
0' MDMD
6,185' MD
0' ND
5,698' ND
PROPOSED
SCHEMATIC
Production Casino
9S/8" L-80 40ppf BTG
Tee Bottom (8.835" ID)
MD 0• 6,174'
ND 0' 5,687'
Cmtw/210sks, 12.6ppg, ClassG
Cmtw/400sks, 15.8ppg, ClassG
Sterling 84 Perforations,
MD ":UP
Typo Dew
5,]24'-5,730' 6' TCP.]"OD,18 f'20 -w 1022)7)
5,]SB' 6,]61' 1--nsss °4'�' S^" ^-• (sy mmme)
5,76F-5]76 10' TCP, 7 -OD, 18ePL 200 phz JM7)
5-1/2" x 18'x 12 ga BakerWeld 140 Screen @ 5,720'
4,990' SSND
! Lol�rinq:
2-718"x 10' lonOstring Blast _
736' (1 D = 2.3
Baker SC -1 gravel pack packer@ 5,738'
/2" x 18'x 12 ga BakerWeid 140 Screen
@ 5,764'
Baker Model D sump packer
GWC @ 5,035'
SSND
SBHP = 1 990 si
-5 066 SSTVD
Well Name & Number:
Drive Pipe
Lease:
20" K-55
133 ppf
134/8" J-55 68ppf BTC
T02
Bottom
S. S. Perforations (MD):
MD 0'
103'
ND 0' 1,870
TvD 0'
103'
Production Casino
9S/8" L-80 40ppf BTG
Tee Bottom (8.835" ID)
MD 0• 6,174'
ND 0' 5,687'
Cmtw/210sks, 12.6ppg, ClassG
Cmtw/400sks, 15.8ppg, ClassG
Sterling 84 Perforations,
MD ":UP
Typo Dew
5,]24'-5,730' 6' TCP.]"OD,18 f'20 -w 1022)7)
5,]SB' 6,]61' 1--nsss °4'�' S^" ^-• (sy mmme)
5,76F-5]76 10' TCP, 7 -OD, 18ePL 200 phz JM7)
5-1/2" x 18'x 12 ga BakerWeld 140 Screen @ 5,720'
4,990' SSND
! Lol�rinq:
2-718"x 10' lonOstring Blast _
736' (1 D = 2.3
Baker SC -1 gravel pack packer@ 5,738'
/2" x 18'x 12 ga BakerWeid 140 Screen
@ 5,764'
Baker Model D sump packer
GWC @ 5,035'
SSND
SBHP = 1 990 si
-5 066 SSTVD
Well Name & Number:
Sterling Unit 43-9x
Lease:
Surface Casing
County or Parish:
134/8" J-55 68ppf BTC
State:
Tom Bottom
S. S. Perforations (MD):
MD 0' 1,990'
Casing Punches:
ND 0' 1,870
1,880' - 1,876'
Cent w/ 620 sks, 12ppg, Type 1
2,139'-2,135'
5,280' -5,290'
Production Casino
9S/8" L-80 40ppf BTG
Tee Bottom (8.835" ID)
MD 0• 6,174'
ND 0' 5,687'
Cmtw/210sks, 12.6ppg, ClassG
Cmtw/400sks, 15.8ppg, ClassG
Sterling 84 Perforations,
MD ":UP
Typo Dew
5,]24'-5,730' 6' TCP.]"OD,18 f'20 -w 1022)7)
5,]SB' 6,]61' 1--nsss °4'�' S^" ^-• (sy mmme)
5,76F-5]76 10' TCP, 7 -OD, 18ePL 200 phz JM7)
5-1/2" x 18'x 12 ga BakerWeld 140 Screen @ 5,720'
4,990' SSND
! Lol�rinq:
2-718"x 10' lonOstring Blast _
736' (1 D = 2.3
Baker SC -1 gravel pack packer@ 5,738'
/2" x 18'x 12 ga BakerWeid 140 Screen
@ 5,764'
Baker Model D sump packer
GWC @ 5,035'
SSND
SBHP = 1 990 si
-5 066 SSTVD
Well Name & Number:
Sterling Unit 43-9x
Lease:
Sterling Unit
County or Parish:
Kenai Penisula Borough
State:
Alaska F Country: USA
S. S. Perforations (MD):
6') 5,724'-5,730'
Short String (TVD):
5,237'-5,243'
L . Perforations (MD):
(10') 5,766' - 5,776'
Long String (ND):
5,280' -5,290'
Angle @ KOP and Depth:
1.83-1 100ft0'
20
Angle/Perfs:
1.45°
BHP:
1,980 BHT:
Completion Fluid:
6% KCL
Date Completed:
08/08/07
Kelly Bushing:
21' (AGL
Revised by:
Paul Winslow
Last Revision Date:
03/26/19
HILCORP ALASKA
13-5/8" 5M BOPE
13-5/8" 5M HYDRIL GK ANNULAR
54-1/8" TALL, FLANGE TO FLANGE
13-5/8" SM CAMERON TYPE U
DOUBLE GATE BOP
DRESSED 2-3/8" - 3-1/2" RAMS IN TOP
DRESSED BLIND RAMS IN BOTTOM
55-7/8" TALL, FLANGE TO FLANGE
13-5/8" SM DRILLING SPOOL
® W/2 EA. 3-1/8" 5M OUTLETS
24" TALL, FLANGE TO FLANGE
134" TOTAL STACK HEIGHT
ANNULAR STYLE BOP SPECS:
- 14.16 gallon open chamber volume
-17.98 gallon close chamber volume
GATE STYLE BOP SPECS:
- 5.5 gallons to open per gate
- 5.8 gallons to close per gate
- 7.0:1 closing ratio
- 2.3:1 opening ratio
HHilcorp Alaska, LLC
Hilcorp Alaska, LLC
Changes to Approved Rig Work Over Sundry Procedure
Subject: Changes to Approved Sundry Procedure for Well SU 43-09X (PTD 207-073)
Sundry #: XXX -XXX
Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the
AOGCC by the rig workover (RWO) "first call' engineer. AOGCC written approval of the change is required before implementing the change.
Sec
Page
Date
Procedure Change
New 403
Required?
Y / N
HAK
Prepared
By
Initials
-HA K
Approved
By
Initials
AOGCC Written
Approval Received
(Person and Date)
Approval:
Prepared:
Asset Team Operations Manager
Date
First Call Operations Engineer Date
10,000,000
1,000,000
t
Y
c�
L
L
CL 100,000
LL
u
o
H M 10,000
M
LO O
o
O M
d
ti C 1,000
u
d
3
U
a
m 100
0
0
t
F
10
1 i
Jan -2005
HILCORP ALASKA LLC, STERLING UNIT 43-09X (207-073)
STERLING, STERLING UNDEF GAS
Monthly Production Rates
Cum. Prod Oil (bbls): 0
Cum. Prod Water (bbls): 102,902
Cum. Prod Gas (md): 101,725
Jan -2010 Jan -2015
A Produced Gas(MCFM) o GOR Produced Water(BOPM) .Produced Oil (BOPM)
10,000,000
W
v
1,000,000
O
O
100,000 m
Z
0
0
3
T=r
10,000
0
p 1
Jan -2020
SPREADSH EET_2070730_SU_43-09X_Prod-I nject_Cu"es_W el I_Gas_V 120_20190405.xlsx
4/5/2019
0 0
0,„szizt,4„ United States Department of the Interior „�LIMO 5
Siii.1:.":;, 111111M'��
4'4'4'-: M^
vi :,111”
x BUREAU OF LAND MANAGEMENT .
'',.....v.-___7.
.�1 9 Alaska State Office
4, 111.-, 222 West Seventh Avenue,#13
Anchorage,Alaska 99513-7504 `"'�(`�� �� k ��
http://www.blm.goviak
APR I ZQ18
tUlli DIVISION OF
In Reply Refer To:
sawsJUN 2 0 OIL AND GAS
3180 (AK930) APR 1 0 2013
Sterling Unit, AA0508871
CERTIFIED MAIL 7003 0500 0005 3216 1072
RETURN RECEIPT REQUESTED
DECISION
Hilcorp Alaska, LLC.
Dave Wilkins, Senior Vice President •
3800 Centerpoint Drive, Suite 1400
Anchorage,Alaska 99503-5826
Federal Oil and Gas Unit Terminated
Leases Extended
The Sterling Unit, located in Kenai, Alaska, was approved as a Federal oil and gas unit, effective
July 7, 1961 and currently contains 2,760 acres. There are Federal, State, private, and fee lease
ownerships located within the unit boundary and three (3) development wells. Hilcorp Alaska,
LLC. (Hilcorp) has been the designated operator for this field since February 2013.
Per 43 CFR 3183.4(b), a unit agreement shall remain in effect as long as the public interest
requirement is satisfied. Since April 2015,Hilcorp has not produced any unitized substance
from this unit in paying quantity. In October 2017, the Bureau of Land Management(BLM) sent
a 60-day Notice for Unit Termination to Hilcorp, allowing 60 days from receipt of the letter to
commence reworking or drilling operations in the unit. Hilcorp did not respond to the Notice.
Therefore,the BLM Authorized Officer has determined the P ublic interest requirement for this
unit has not been met.
The Federal Sterling Unit Agreement,AA050887,is hereby terminated by the BLM,
effective December 15, 2017. The Sterling Unit leases are extended for an additional two (2)
years from the unit agreement termination date.
• •
Hilcorp will continue to be bound by all lease terms, Federal, State, and private. Upon
termination or relinquishment of said leases,Hilcorp will assume the responsibility to plug and
abandon all wells, reclaim the lease site including pad(s),pipelines and roads, and remediate any
environmental concerns to the satisfaction of the surface estate owner, Salamatof Native
Association,Inc, and per terms of any Surface Use Agreement between Hilcorp and Salamatof.
The existing Federal lease, A028135,will convert to annual rental status, with payment due to
the Office of Natural Resources Revenue(ONRR) October 1St .
Hilcorp will no longer report any production or royalty to the Office of Natural Resources
Revenue(ONRR)unless production occurs from the Federal lease A028135.
This decision may be appealed to the Interior Board of Land Appeals, Office of the Secretary, in
accordance with the regulations contained in the enclosed 43 CFR,Part 4, and Form 1842-1. If
an appeal is taken,the notice of appeal must be filed in this office(at the above address)within
30 days from receipt of this decision. The appellant has the burden of showing that the decision
appealed from is in error.
Failure to file the notice of appeal with the Bureau of Land Management within the time allowed
will result in dismissal of the appeal. In order to avoid dismissal of the appeal, there must be
strict compliance with the regulations.
C.‘%:tzzg/C1
-12 12t. (-71 ifir*
W yne . Svejnoha
Br Chief of Energy and Minerals
Division of Resources
Enclosures:
43 CFR,Part 4 and Form 1842-1
cc w/o enclosures:
Hilcorp Alaska, LLC
Kevin Tabler, Land Manager
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Alaska Department of Natural Resources
Division of Oil and Gas
Chantal Walsh,Director
550 West 7th Avenue, Suite 1100
Anchorage, AK 99501-3563
. • •
cc w/o enclosures:
Cook Inlet Region, Inc.
Colleen Miller
725 E. Fireweed Lane, Suite 800
Anchorage,AK 99503
Salamatof Native Association, Inc
Chris Monfor, President/CEO
PO Box 2682
Kenai, AK 99611
Office of Natural Resources Revenue
Diane Germain, Minerals Revenue Specialist
MS 63300B
PO Box 25165
Denver, CO 80225-0627
1A028063 A028135 AA050887A/B/C
• •
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
TO: Jim Regg [ 4- (' DATE: March 16, 2013
P. I. Supervisor
FROM: Jeff Turkington SUBJECT: Defeated SVS
Petroleum Inspector Sterling 43 -9X -
Hilcorp Alaska LLC
PTD 2070730
3/15/2013: Met with Hilcorp representative Warren Camp and a couple other
operators at Beaver Creek for safety valve system (SVS) tests at Beaver Creek
and Sterling fields. I introduced myself and with no safety briefing from the
Hilcorp representatives, we went immediately to the first well in Beaver Creek
(BC -9; PTD 1921220). A separate report describes the SVS testing (see
Inspection Reports # sysJAT130307181130 and retest #sysJAT130317115227).
Once we arrived at Sterling pad, I went into 43 -9X well house and noticed that
the well was flowing but the operators were over by the control room rather than
at the well house. After waiting a few minutes I asked what was going on and
was told that the well was pinned out and wouldn't trip. The Hilcorp operators
said they thought it was a computer problem, so they had called I &E Tech Billy
Davis to figure out what was wrong. They must've been able to see the well's
status on SCADA because we hadn't set up to test at the well yet. The operators
asked what they had to do next and I told them the well would need to be shut in
until they got the SVS fixed and then to notify AOGCC as required once the well
was flowing again. Later when I returned to Beaver Creek on 3/16/2013 for the
retest of BC -9 I asked about 43 -9X and operator Warren Camp confirmed that it
had been pinned out on my previous visit but they hadn't fixed the problem yet.
Summary: SVS on Sterling 43 -9X was found defeated; well was shut in and no SVS
performance test was witnessed. -
Attachments: none -
SCANNED JUL 10 2013
2013 -0315_ SVS_ defeated_Sterling_43- 9X _jt.docx
•
~~`~ `
~~ ~
~~ "= "" ~
~.s'
~~} ~'~~
4 ~ P ~v
~~ ~~ ~.
~~ ~
MICROFILMED.
6/30/2010
DO NOT PLACE
ANY NEW MATERIAL
UNDERTHISPAGE
C:\temp\Temporary Internet Files\OLK9\Microfilm_Marker.doc
~ ~
DATA SUBMITTAL COMPLIANCE REPORT
7/20/2009
Permit to Drill 2070730 Well Name/No. STERLING UNIT 43-09X Operator MARATHON OIL CO API No. 50-133-20569-00-00
MD 6185 ND 5698 Completion Date 8/8/2007 Completion Status 1-GAS Current Status 1-GAS UIC N
REQUIRED INFORMATION
Mud Log Yes
Samples No
Directional Survey
DATAINFORMATqN
Types Electric or Other Logs Run: Quad Combo, RFT, CBL, GR, CCL
Well Log Information:
Log/ Electr
Data Digital Dataset Log Log Run
(data taken from Logs Portion of Master Well Data Maint
Interval OH /
T Med/Frmt Number ~~e Sca~e nneaia No Start Stop cH Received comments
ED C 15338 Report: Final Well R Open 8/23/2007 Finai Well Report in digital
form, with digital Mudlog in
~ PDF and Wireline in PDF
and LAS format
Well Cores/Samples Information:
Sample
Interval Set
Name Start Stop Sent Received Number Comments
~ Cores and/or Sampies are required to be
, submitted. This record automatically created
~_ from Permit to Drill Moduie on: 6/8/2007.
ADDITIONAL INFORM~ION
Well Cored? Y Daily History Received? ~ N
Chips Received? /~ Formation Tops N
Analysis .~F~,+-itF---
Received?
Comments:
~
~
~ •
Marathon Oil Company
Alaska Asset Team
Marathon P.O. Box 7949
M
.
MARATHON Oil Company Kenai, AK 99611
Telephone 907/283-1371
Fax 907/283-1350
June 2, 2009
Mr. Winton Aubert ~E~~~~~~
Alaska Ohl & Gas Conservation Commission ~U~ o~~G~~
333 W 7 Ave
Anchorage, Alaska 99501 ~(aska ~Dil & Gas C~,~s. ~;~~~;f:~;<;,;~;;~f,
~A~chs~ra~~
Reference: 10-404 Report of Sundry Well Operations
Field:
Well:
Dear Mr. Maunder:
Sterling Unit
Sterling Unit 43-9x
Attached for your records is the 10-404 Sundry covering the recent acidizing
operation on SU 43-9x well. A combined enzyme, HCL acid, and mutual solvent i
treatment was displaced across the long string gravel pack section. The purpose
of this operation was to promote water production by removing the remnants of the
HEC polymer pill that was spotted, to reduce fluid loss, during completion
operations.
Please contact me at (907) 283-1371 if you have any questions or need additional
information.
Sincerely,
.
~~T1~• ~ ~
Kevin J. Skiba
Regulatory Compliance Technician
Enclosures: 10-404 Report of Sundry Well Operations cc: Houston Well File
Operations Summary Kenai Well File
Well Schematic KJS
STATE OF ALASKA ~~~~~~'~~~~
ALA~ OIL AND GAS CONSERVATION COM~ION ~~~
REPORT OF SUNDRY WELL OPERATIONS JUN 0~~~p~ ~/~/~De~
1. Operations Abandon Repair Well Plug Perforations Stimulate ~_ QI1S, ~;~~mj~~j~~
Performed: Alter Casing ~ Pull Tubing ~ Perforate New Pool ^ Waiver~ Time Extension ~G~lq~,~~~y
Change Approved Program ~ Operat. Shutdown ~ Perforate ^ Re-enter Suspended Well ~
2. Operator
Marathon Oil Company
N 4. Well Class Before Work: 5. Permitto Driil Number:
ame: Development Q. Exploratory^ 207-073~
3. Address: PO BOX 1949 Stratigraphic ^ Service ^ 6. API Number:
Kenai Alaska, 99611-1949 50-133-20569-00-00 -
7. KB Elevation (ft): 9. Well Name and Number:
245' - 21' AGL Sterlin Unit 43~9x-
8. Property Designation: 10. Field/Pool(s):
A- 028063 - Sterling Field / Sterling Pool
11. Present Welf Condition Summary:
Total Depth measured 6,185' - feet Plugs (measured) NA
true vertical 5,698'- feet Junk (measured) NA
Effective Depth measured 6,114' - feet
true vertical g,g27' _ feet
Casing Length Size MD TVD Burst Collapse
Structural
Conductor g2' 20" 103' 103' 3,060 psi 1,500 psi
Surface 1,969' 13-3/8" 1,990' 1,871' 3,450 psi 1,950 psi
Intermediate 6,153' 9-5/8" 6,174' S,687' S,750 psi 3,090 psi
ProducYion
Liner
Perforation depth: Measured depth: 5,724' - 5,776' gross
True Vertical depth: 5,237' - 5,289'
SS 2-3/8" L-80 5,588'
Tubing: (size, grade, and MD) LS 2-7/8" L-80 5,627'
Packers and SSSV (type and measured depth) Baker GT Dual Packer 5,588'
Baker SC-1 Gravel Pack Packer 5,627'
Baker SC-1 Gravel Pack Packer 5,738'
Baker Model B Sump Packer 5,784'
12. Stimulation or cement squeeze summary: A combined enzyme, HCL acid, and mutual solvent treatment was
Intervals treated (measured): displaced across long string gravel pack section. The purpose of this
operation was to promote water production by removing the remnants
Treatment descriptions including volumes used and final pressure: of the HEC polymer pill that was spotted, to reduce fluid loss, during
completion operations.
13. Representative Daily Average Production or Injection Data
Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure
Long String Prior to well operation 0 340 462 0 385
Long String Subsequent to operation 0 188 - 0 397
14. Attachments: 15. Well Class after work:
Copies of Logs and Surveys Run Exploratory [] Development Q- Service ~
Daily Report of Well Operations X 16. Well Status after work:
Oil^ Gas Q- WAG ^ GINJ ^ WINJ ^ WDSPL ^
17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt:
NA
Contact Kevin Skiba (907) 283-1371 ~?~~~ ~~ ,f ~~ (~ ~ Z~Q~
Printed Name Kevin J. Skiba Title Regulatory Compliance Technician
Signature ~„ ,~ 0) 8-1371 Date June 2, 2009
Frm1- S
~ ~~~~ ~perations Summary Report
,,,~,,~„T,~, *D~~~n~~ VMtell Name: STERLING UNIT 43~8X
Report Uate: 519r2009 Job Category: R&M MAINTENANCE
2l H r S~mmary
MIftU BJ, pump acid treatmerit, RDMO BJ, turn well back to production.
sr~rtrme
e~arme
o~r
o coa~
acw Coae o~s
stada
TroiDkCOtle
canme~t
07:00 08:00 1.00 SAFETY MTG AF Held PJSM wI BJ and ASRC. Discussed jab procedures, chemical
handlingMlSDS sheets, musterlsmoking area, stop the job obligation, and
emer enc rocedures. Obtained safe work armit.
08:00 09:30 1.5~ RURa STIM AF RU BJ pumping unit, acid tanks, and KCL trucks. Tie in to flowline w!
companion flange.
09:30 10:9 5 0.75 TEST EQIP AF Pressure test lines to 20d psi low, 4500 psi high. Good test. ~
10:15 12:00 1.75 PUMP ACID AF Pump acid treatmer~t as fallows:
30 bbls Gel Breaker Pill -7.5% HCL, 495 gal MI Swaco Mutual
Solverrt
45 bbls 6% KCL Displacemerrt
24 bbls FW cleanup
en pumping acid, caught fluid after 19 bbls away. Initial pump rate 2 bpm
~rn 1320 psi. Lawest pressure accured after 30 bbls away (2 bpm ~ 940 ~
psi). Pressure steadily climbed afterwards and stabilixed ~ 1410 psi.
Finished ob ISIP 23d si. ~
12:00 15:00 3.00 RURD STIM AF RD BJ pumping equipmerrt while monitoring well for 3 hrs. Sign out and
leave location.
www.peloton.com
Report Prirrted: 5282009
~ •
50-133-20569-00-00
: A - 028063
245' (21' AGL)
6/9/2007 16:30 hrs
60° 32' 15.628" N
151° 01' S1.465" W
I: 15t 6/24/2007 09:00 hrs
2nd 10/30/2007 06:00 hrs
6/17/2007 6,185' MD
S U 43-9x
Sterlinq Pad
2,408' FSL, 426' FEL
Sec. 9, T5N, R10W, S.M.
~
MAtt~rMOM
Drive Pioe
20" K-55 133 ppf
Ton Bottom
MD 0' 703'
TVD 0' 103'
Surface Casina
133/8" J-55 68ppf BTC
Top Bottom
MD 0' 7,990'
TVD 0' 1,870'
Cmt wl 620 sks, 72PP9~ Type 1
Production Casinq
9-5/8" L-80 40ppf BTC
Top Bottom (8.835" ID)
MD 0' 6,174'
TVD 0' S,687'
Cmt w/ 210 sks, 12.Sppg, Class G
Cmt w/ 400 sks, 15.8ppg, Class G
MD Ft Gun Type Date
?4'-5,730' 6' TCP, 7"OD, 18spf, 20° phz (10/22/07)
. (SQZ 10/17/08)
i6'-5,776' 10' TCP. 7"OD, 18spt, 20° phz (10/19/07)
" Baker SC-1 gravel pack packer @ 5,627'
` Knock out isolation valve @ 5,660'
I STERLING B4 SAND I
~ rr _ ~
,''h ;.~
~~. .` .,. •i'. ~
Shortstrinq Perfs (Sterlinq B4 Gasl:
h. . ~~
5,724' - 5,730' (6') ~ ,
r.+ 'Y
„. ~, S' }
. ':;
5,766' - 5,776' (10')
Short Strina
2-318" L-80 6.4ppf EUE tubing
(ID = 1.995")
-Baker GT Dual Packer w/60K shear ring @ 5,588'
-XN- nipple @ 5,600' (ID = 1.75")
-Wireline re-entry guide @ 5,605'
Lonq Strinq
2-7/8" L-80 6.4ppf EUE tubing
8rd (ID = 2.447")
-GLM's @ 1,740', 2,943', 3,884', 4,558', 5,030', 5,433'
-Baker GT Dual Packer w/60K shear ring @ 5,588'
5-1/2" x 18' x 12 ga BakerWeld 140 Screen @ 5,720'
;.-.~..a_ _.,~'= :~ 1 :> ~ - -4,990' SSTVD
;~~•d ~~..': LonQStnn4: 217/8" x 10' longstring Biast
'~-" joint @ 5,~24' SBHP = 1,980
i sq trinq - X-nipple @ 5,736' (ID = 2.313")
Baker SC-1 gravel pack packer @ 5,738'
~2" x 1~8' x 12 ga BakerWeld 140 Screen
@ s,~sa~
Baker Model D sump packer @ 5,784'
PBTD TD
6,114' MD 6,185' MD
5,627' TVD 5,698' TVD
GWC @ 5,035'
SSTVD
SBHP = 1,990 psig
-5,066' SSTVD
Well Name & Number: Sterling Unit 43-9x Lease: Sterling Unit
County or Parish: Kenai Penisula Borough State: Alaska Country: USA
S.S. Perforations (MD): (6') 5,724' - 5,730' Short String (ND): 5,237' - 5,243'
L.S. Perforations (MD): (10') 5,766' - 5,776' Long String (ND): 5,280' - 5,290'
Angle @ KOP and Depth: 1.83° I 100ft ~ 200' Angle/Perfs: 1.45°
BHP: 1,980 BHT: Completion Fluid: 6% KCL
Date Completed: 08108107 Kelly Bushing: 21' (AGL)
Revised by: Kevin Skiba Last Revision Date: 01127109
!
M Marathon
MARATHON Oil Company
April 7, 2009
Mr. Tom Maunder
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, Alaska 99501
Reference: 10-404 Report of Sundry Well Operations
Field: Sterling Unit
Well: Sterling Unit 43-9x
Dear Mr. Maunder:
~
Marathon Oil Company
Alaska Asset Team
P.O. Box 1949
Kenai, AK 99611
Telephone 907/283-1371
Fax 907/283-1350
~,~~~
~~f,~ ~~~~
~~~~~~ ~f~~ ~~'~ ?40
~:°,a,., k 9
~n~~~,~~-~~ ~'o,~iess,
~~~
Attached for your records is the 10-404 Sundry covering the recent acidizing
operation on SU 43-9x well. A combined enzyme, HCL acid, and mutual solvent
treatment was displaced across the long string gravel pack section. The purpose
of this operation was to promote water production by removing the remnants of the
HEC polymer pill that was spotted, to reduce fluid loss, during completion
operations.
Based on the communications that you and Ken Walsh had on 3/6/09, Marathon
was granted permission to perform the treatment and directed to submit a Report
of Sundry Well Operations, 10-404, upon completion of the work. Consequently,
this report is being submitted without an associated sundry number.
Please contact me at (907) 283-1371 if you have any questions or need additional
information.
Sincerely,
~
~ •~
~Qi!'J~~
~ Kevin J. Skiba
Engineering Technician
Enclosures: 10-404 Report of Sundry Well Operations
Operations Summary
Well Schematic
~~
~,O
~~
cc: Houston Well File
Kenai Well File
KJS
JKM
• STATE OF ALASKA ~Ev~~ V GD•~~5~~-
ALAS~IL AND GAS CONSERVATION COMMI~ON ~9~~
qP~ p ~ 2009
REPORT OF SUNDRY WELL OPERATIONS
~iaska Oil & 6as Cons. Commission
1. Operations Abandon Repair Well Plug Perforations Stimulate ~ Other C tOCB~E
Performed: Alter Casing ~ Pull Tubing ~ Perforate New Pool ~ Waiver^ Time Extension ~
Change Approved Program ^ Operat. Shutdown ~ Perforate ^ Re-enter Suspended Well ~
2. Operator
Marathon Oil Company
Name 4. Well Class Before Work: 5. Permit to Drill Number:
: Development ~ Exploratory^ 207-073 -
3. Address: p0 Box 1949 Stratigraphic ~ Service ^ 6. API Number:
Kenai Alaska, 99611-1949 50-133-20569-00-00-
7. KB Elevation (ft): 9. Well Name and Number:
245' - 21' AGL Sterlin Unit 43-9x -
8. Property Designation: 10. Field/Pool(s):
A- 028063 ' Sterling Field / Sterling Pool
11. Present Well Condition Summary:
Total Depth measured 6,185' ~ feet Plugs (measured) NA
true vertical 5,698' - feet Junk (measured) NA
Effective Depth measured 6,114' - feet
true vertical g,627~ - feet
Casing Length Size MD TVD Burst Collapse
Structural
Conductor $2' 20" 103' 103' 3,060 psi 1,500 psi
Surface 1,969' 13-3/8" 1,990' 1,871' 3,450 psi 1,950 psi
Intermediate 6,153' 9-5/8" 6,174' 5,687' 5,750 psi 3,090 psi
Production
Liner
Perforation depth: Measured depth: 5,724' - 5,776' gross
True Vertical depth: 5,237' - 5,289'
SS 2-3/8" L-80 5,588'
Tubing: (size, grade, and MD) LS 2-7/8" L-80 5,627'
Packers and SSSV (type and measured depth) Baker GT Dual Packer 5,588'
Baker SC-1 Gravel Pack Packer 5,627'
Baker SC-1 Gravel Pack Packer 5,738'
Baker Model B Sump Packer 5,784'
12. Stimulation or cement squeeze summary: A combined enzyme, HCL acid, and mutual solvent treatment was
Intervals treated (measured): displaced across long string gravel pack section. The purpose of this
operation was to promote water production by removing the remnants
Treatment descriptions including volumes used and final pressure: of the HEC polymer pill that was spotted, to reduce fluid loss, during
completion operations.
13. Representative Daily Average Production or Injection Data
Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure
Long String Prior to well operation 0 500 500 Lift psi 918 395
L.ong String Subsequent to operation 0 400 650 Lift psi 865 386
14. Attachments 15. Well Class afterwork:
Copies of Logs and Surveys Run Exploratory ~ Development Q- Service ~
Daily Report of Well Operations X 16. Well Status after work:
Oil ^ Gas Q~ WAG ^ GINJ ^ WINJ ^ WDSPL ^
17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt:
NA
Contact Kevin Skiba (907) 283-1371 ~~` ~~ ~,~~, ~ !, ,} `~ ~~Q~
Printed Name Kevin Skiba Title Engineering Technician
,
Signature ~ •~
Phone (907) 283-1371 Date April 7, 2009
Frm1- S i
E
- ° A ~-~~4 y~~~
~
•
~ IVlarathon
M„M ~~~ Cp~~~ Operations Summary Report
Well Name: STERLING UNIT 43-9X
Re ort Date: 4/12009 Jo6 Cate o: R&M MAINTENANCE
24 Hr S~mmary
MIRU BJ to pump enzymelacid breaker treatment to break HEC polymer.
Start Time
End Time
Dar a
O s Code
Adivi
Code Ops
Ststus T rouble
Code
Comment
08:30 09:30 1.00 SAFETY MTG AF Hold PJSM. Discuss alarms, muster area, and emergency response.
Discuss BJ JSA and specific job hazards Make job assignments. Obtain
SWP.
09:30 11:30 2.00 RURD STIM AF Lay liner under acid transport and pumping equipment. Spot equipment. RU
pumping equipment. RU tanks and manifold equipment. Isolate and bleed
flow line. Install companioin flange xo to 2" 15~2 unioin. RU 2" hard lines.
11:30 11:45 0.25 SAFETY MTG Hold PJSM to discuss PTest, pump schedule, and safety hazards. Make job
assignments.
11:45 13:15 1.50 TEST EQIP AF Prime up equipment. PTest 2" hard lines to 4000 psi. Test good.
13:15 14:30 1.25 PUMP ACID AF Pump: 24 bbls. Enzyme Breaker Pill
30 bbls.6% KCL Spacer
15 bbls. Gel Breaker Pill-3% HCL 495 gals MI-Swaco Mutual solvent.
38 bhls.6% KCL Displacement (5 bbls over flush)
Most of treatment pumped at 1.6 bpm 1200-1500 psi.
Pressure dropped from 1570 psi-acid on formation to 1020 psi by end of
displacement. ISIP ~~0 psi.
14:30 15:45 1.25 RURD STIM AF Pumping complete. Shut down for 1 hour. Clean up and rinse tanks.
15:45 16:00 0.25 PUMP ACID AF Pump: 25 bbls KCUtank bottoms. 1.6 hpm-800 psi.
16:OC1 17:00 1.00 RURD STIM AF RD pump equipment 2" hard line. Install blind flange on ilow line.
17:00 1? 15 0 25 SECURE WELL AF Close wing valve Secure welt head and turr~ well over to operation
www.peloton.com Report Printed: 4/6/2009
~ ~
50-133-20569-00-00
; A - 028063
245' (21' AGL)
6/9/2007 1630 hrs
60° 32' 15.628" N
151° 01' 51.465" W
I: 15t 6/24/2007 09:00 hrS
2nd 10/30/2007 06:00 hrs
6/17/2007 6,185' MD
S U 43-9x
SterlinQ Pad
2,408' FSL, 426' FEL
Sec. 9, T5N, R10W, S.M.
M
Maw-nioN
Drive Pipe
20" K-55 133 ppf
TOD eottom
MD 0' 103'
TVD 0' 103'
Surface Casina
13-318" J-55 68ppf BTC
TOp Bottom
MD 0' 1,990'
TVD 0' 1,870'
Cmt wl 620 sks, 12ppg, Type 1
Production Casina
9-5/8" L-80 40ppf BTC
Top Bottom (8.835" ID)
MD 0' 6,174'
ND 0' S,687'
Cmt w/ 270 sks, 12.Sppg, Class G
Cmt w/ 400 sks, 15.8ppg, Class G
Sterlinq 64 Perforations:
MD Ft Gun Type Date
5.~24'-5,730' 6' TCP, 7"OD, '18spf, 20° phz (10l22/07)
. (Sqz 70/77/08)
5,766'-5,776' 10' TCP, 7"OD. 18spf, 20° phz (10/'19/07)
' Baker SC-1 gravel pack packer @ 5,627'
' Knock out isolation valve @ 5,660'
STERLING B4 SAND
Short Strina
2-318" L-80 6.4ppf EUE tubing
(ID = 1.995")
•Baker GT Dual Packer w160K shear ring @ 5,588'
-XN- nipple @ 5,600' (ID = 1.75")
-Wireline re-entry guide @ 5,605'
Lona Strina
2-7I8" L$0 6.4ppf EUE tubing
8rd (ID = 2.441")
-GLM's ~ 1,740', 2,943', 3,884', 4,558', 5,030', 5,433'
-Baker GT Dual Packer w/60K shear ring @ 5,588'
5-1/2" x 18' x 12 ga BakerWeld 140 Screen @ 5,720'
'•'.r„~a 4:;Y, w ^1 ~.:- i ~~4~~-'sy ~`,•E':%•' _t},99~' SSTVD
I~ ~'` Longstring 2 7/8 x 10 longstring Blast
r"~"~.;f joint @ 5,724' SBHP = 1,980
i sp trinq - X-nipple @ 5,736' (ID = 2.313")
Baker SC-1 gravel pack packer @ 5,738'
'2" x 18' x 12 ga BakerWeld 140 Screen
@ s,~sa~
GWC @ 5,035'
SSTVD
SBHP = 1,990 psig
-5,066' SSTVD
Baker Model D sump packer @ 5,784'
PBTD TD
6,114' MD 6,185' MD
5,627' TVD 5,698' TVD
Well Name & Number: Sterling Unit 43-9x Lease: Sterling Unit
County or Parish: Kenai Penisula Borough State: Alaska Country: USA
S.S. Perforations (MD): (6') 5,724' - 5,730' Short String (ND): 5,237' - 5,243'
L.S. Perforations (MD): (10') 5,766' - 5,776' Long String (ND): 5,280' - 5,290'
Angle @ KOP and Depth: 1.83° / 100ft ~ 200' Angle/Perfs: 1.45°
BHP: 1,980 BHT: Completion Fluid: 6% KCL
Date Completed: 08I08107 Kelly Bushing: 21' (AGL)
Revised by: Kevin Skiba Last Revision Date: 01/27/09
From: Walsh, Ken [kdwalsh@marathonoil.com]
Sent: Friday, March 06, 2009 2:18 PM
To: Maunder, Thomas E (DOA)
Subject: RE: Sterling Unit #43-9X, PTD 207-073: HEC Pill Removal
Tom,
Will do and thanks.
~~
Ken D. Walsh
Senior Production Engineer
Marathon Oil Company~Alaska Asset Team
9@7-283-1311 (office}
907-394-3060 (cell)
From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov]
Sent: Friday, March 06, 2009 2:10 PM
To: Walsh, Ken
Cc: Ostroot, James G.; Dammeyer, Michael D.; Henry, Nancy J.; Ibele, Lyndon; Miranda, Kyle; Mullin, Mickey;
Rang, Craig L.; Skiba, Kevin J.; Sulley, Michael
Subject: RE: Sterling Unit #43-9X, PTD 207-073: HEC Pill Removal
Ken,
Please file a 404 reporting the work. Good luck removing the damage.
Tom Maunder, PE
AOGCC
From: Walsh, Ken [mailto:kdwalsh@marathonoil.com]
Sent: Friday, March 06, 2009 1:44 PM
To: Maunder, Thomas E (DOA)
Cc: Ostroot, James G.; Dammeyer, Michael D.; Henry, Nancy J.; Ibele, Lyndon; Miranda, Kyle;, Mullin, Mickey;
Rang, Craig L.; Skiba, Kevin J.; Sulley, Michael
Subject: Sterling Unit #43-9X, PTD 207-073: HEC Pil~ Removal
Tom,
This email is a follow-up to our telephone conversation today regarding my question of whether
AOGCC sundry approval is necessary for proposed work on the Sterling Unit #43-9X (PTD
#207-073) well. The proposed work entails pumping an HCL acid with mutual solvent
treatment down the long string (~S) side of this dual tubing wellbore. The treatment is
considered necessary to break down and remove an HEC pill that was spotted across the
3/6/2009
Sterling Unit #43-9X, PTD 2(~73: HEC Pill Removal ~ Page 2 of 2
screen and near wellbore after pumping the gravei pack. The pili was spotted to reduce the
excessive fluid loss into the LS perforation interval to facilitate the ins#allation and gravel pack
work across the short string (SS} perforations during the initial completion.
The acid treatment is expected to greatly reduce or eliminate the restriction to deiiverability
from the LS perforations which will allow for increased water production from the lower portion
of the sand. Increased water production from the LS should prevent formation water from
coning up into the SS and allow for continuous gas production.
Please provide direction as #o how you would like Marathon to handle the permitting or
documentation of this work.
Best regards,
~~
Ken D. Walsh
Senior Production Engineer
Marathon Oil Company-Alaska Asset Team
907-283-1311 (officej
907-394-3060 {cell)
3/6/2009
~ ~ ~
M Marathon
MARATHON Oil Company
MAR 1 2 200~
March 11, 2008
RECEIVEC~
14le~ka Oil & Gas Cons. Cammission
Anchorage
Mr. Tom Maunder
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, Alaska 99501
Reference: 10-421 Open Flow Potential Test Report
Field: Sterling Field
Well: Sterling Unit 43-9x
Dear Mr. Maunder:
Marathon Oil Company
Alaska Asset Team
P.O. Box 1949
Kenai, AK 99611
Telephone 907/283-1371
Fax 907/283-1350
Enclosed is the 10-421 Open Flow Potential Test Report for SU 43-9x well. SU 43-9x
was completed into the Sterling formation as a co-production well. Presently this well is
not on production while the operational issues relating to this co-production concept are
worked through. In an effort to submit the required documentation to your agency in a
timely fashion, data was utilized from a 1-point flow test to complete this report.
Please contact me at (907) 283-1371 if you have any questions or require additional
information.
Sincerely,
! - ~~
~~iLrl/~°
Kevin J. Skiba
Production Technician
Enclosures: 10-421 Open Flow Report cc: AOGCC
Houston Well File
Kenai Well File
KJS
~ MAR 1 2 2008
I ~ ~ STATE OF ALASKA ~~~_^~
ALASi~A OIL AND GAS CONSERVATION COMMfSSION Cp~, Cptf1tCltSS1011
a 0+1 & Gas
GAS WELL OPEN FLOW POTENTIAL TEST ~~PORpTicnorage
I
1a. Test: ~ Initial Annual Special 1b. Type Test: ~ Stabilized Non Stabilized Multipoint
^ Constant Time ~ Isochronal ^ Other
2. Operator Name: 5. Date Completed: 11. Permit to Drill Number:
Marathon Oil Company
sisi~oo7 Zo~-o~s
3. Address: p0 BOX 1949 6. Date TD Reached: 12. API Number:
Kenai, Alaska 99611-1949 6/17/2007 50- 133-20569-00-00
4a. Location of Well (Governmental Section): 7. KB Elevation (ft): 13. Well Name and Number:
SurFace: 2,408' FSL, 426' FEL, Sec. 9, TSN, R10W, S.M. 245' above MSL Sterling Unit 43-9x
Top of Productive Horizon: 8. Plug Back Depth (MD+ND): 14. Field/Pool(s):
1,262' FNL, 1,226' FEL, Sec. 15, T5N, R10W, S.M. 6,114' MD 5,627' TVD
li
Fi
ld / St
li
P
l
St
Total Depth: 9. Total Depth (MD + TVD): er
ng
er
ng
oo
e
1,251' FNL, 1,219' FEL, Sec. 15, T5N, R10W, S.M. 6,185' MD 5,698' ND
4b. Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation:
Surface: x- 314,749.39 y- 2,390,723.37 Zone- 4 A- 028063
TPI: x- 313,976.56 y- 2,391,980.99 Zone- 4 16. Type of Completion (Describe):
Total Depth: x- 313,983.17 y- 2,391,991.78 Zone- 4 Dual Gravel Pack
17. Casing Size Weight per foot, Ib. I.D. in inches Set at ft. 19. Perforations: (MD) From To
9-5/8" 40# L-80 8.835" 6,174' MD 5,724' S,730'
18. Tubing Size Weight per foot, Ib. I.D. in inches Set at ft. 5,766' 5,776'
SS 2-3/8" 4.7# L-80 1.995" 5,588' MD
LS 2-7/8" 6.4# L-80 2.441" 5,627' MD
20. Packer set at ft: (MD) 21. GOR cf/bbl: 22. API Liquid Hydrocardbons: 23. Specific Graviry Flowing Fluid (G):
5,588' - -
5,627'
5,738' 0.56
5,784'
24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa):
~^ Tubing ~ Casing 150 F° 689 psia @ Datum 5627' TVDSS 14.73 psia
25. Length of Flow Channel (L): Vertical Depth (H): Gg: % CO2: % N2: % HZS: Prover. Meter Run: Taps:
5,724' MD 5,238' TVD 0.56 0 0.81 0 Facility
26. FLOW DATA TUBING DATA CASING DATA
No. rover o e
Line X Orifice pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow
Size in. Size in. psig Hw F° psig F° psig F° Hr.
~• 3.826 X 0.500 613 5.82 50 - - - - 4.00
2. X
3. X
4. X
5. X
No. Basic Coefficient
(24-Hour)
hwPm
Pressure Flow Temp.
Factor Gravity Factor Super Comp.
Factor
Rate of Flow
Fb or Fp Pm Ft Fg Fpv (2~ Mcfd
1. 62.84175292 17.0587221 627.73 1.00 1.33631 1.054 1072
2.
3.
4.
5.
Temperature for Separator for Flowing
No. Pr T Tr z Gas Fluid
Gg G
1. 0.93 510 1.49 0.9 0.56
2.
3. Critical Pressure 673.1
4. Critical Temperature 343.2
5.
~~i~ ~.
Form 10-421 Revised 1/2004
~ ~ i~ 1~~~
CONTINUED ON REVERSE SIDE
~ ~ ~l~j Submit in Duplicate
Pc 1765 PcZ 3114272
P~
No. Pt Pt~ Pcz-Pt~ PW Pv~ Pc2-Pv~ PS Psz Pi~-Ps2
~ • 628 394044.95
2.
3.
4.
5.
25.
AOF (Mcfd) 1,186
Remarks:
I hereby certif~ that the foregoing is true ~
Signed
correct to the best of my knowledge.
Title Production Technician
0.750
Date 3/11/2008
DEFINITIONS OF SYMBOLS
AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole
pressure opposite the producing face were reduced to zero psia
Fb Basic orifice factor Mcfd/ hwPm
Fp Basic critical flow prover or positive choke factor Mcfd/psia
Fg Specific gravity factor, dimensionless
Fpv Super compressibility factor= /1 Z dimensionless
Ft Flowing temperature factor, dimensionless
G Specific gravity of flowing fluid (air=1.000), dimensionless
Gg Specific gravity of separator gas (air=1.00), dimensionless
GOR Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F)
hw Meter differential pressure, inches of water
H Vertical depth corresponding to L, feet (TVD)
L Length of flow channel, feet (MD)
n Exponent (slope) of back-pressure equation, dimensionless
Pa Field barometric pressure, psia
Pc Shut-in wellhead pressure, psia
Pf Shut-in pressure at vertical depth H, psia
Pm Static pressure at point of gas measurement, psia
Pr Reduced pressure, dimensionless
Ps Flowing pressure at vertical depth H, psia
Pt Flowing wellhead pressure, psia
Pw Static column wellhead pressure corresponding to Pt, psia
Q Rate of flow, Mcfd (14.65 psia and 60 degrees F)
Tr Reduced temperature, dimensionless
T Absolute temperature, degrees Rankin
Z Compressibility factor, dimensionless
Recommended procedures for tests and calculations may be found in the Manual of
Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma
City, Oklahoma.
Form 10-421 Revised 1/2004 Side 2
Page 1 of 1
~
Maunder, Thomas E (DOA)
~
From: Ibele, Lyndon [Icibele@ma~athonoil.com]
Sent: Wednesday, January 02, 2Q08 11:27 AM
To: Maunder, Thomas E (DOA)
Cc: Skiba, Kevin J.; Rang, Craig L.
Subject: FW: SU 43-9X (207-073)
From: Maunder, Thomas E (DOA) [maiito:tom.maunder@ataska.gav]
Sent: Tuesday, December 18, 2007 3:17 PM
To: Skiba, Kevin J.; Donovan )r, Dennis M.
Cc: .lim Regg
Subject: SU 43-9X (207-473)
Dennis,
I am reviewing the completion report recentiy submitted for this well. I have a question on casing
test pressures and fluid used to fill the hote.
1. According to the report for 6/22/07, the plug was bumped to 1450 psi with mud in the hole.
On 6/23/07, the mud was displace with fresh water and the casing was tested to 9500 psi.
On 8/8l07 when the water was dispfaced with nitrogen, the surFace pres5ure is reported as
high as 2358 psi. On 10/26/07, after running the tubing the annulus was tested to 2000 psi.
The variety of surFace pressure test values is not consistent. Could you and your
colleagues provide some insight into the variety of pressure values?
{9bele, Lyndon} Tom--pressure tests are conducted at various steps of the operatic~n, not
due to regulatory requirement for BOP or casing tests, but simply as operational safety
steps. Various surface pressures are due to the purpose for the test, and fluids in the hole
at the time. Please inform us if you feel we did not meet some specific regulatory
requirement or sundry stipulation.
2. On 8/11107 coil is being used to fill the 9-5/8° casing. A signi~icant fluid volume was pumped
without returns. Would you provide some comments regarding this event? Is it presumed
that the well was near{y empty prior to RU coi(?
[Ibefe, Lyndon~ As no#ed in question #3, the well flowed gas during ths test immediately prior,
so yes, it was necessary to fill the hole to perform the next step.
3. A small interval (5750 - 5751') was shot and tested between 8/9/07 - 8/10/07 as proposed in
Sundry 307-220. Was the gas and water volume reported as production?
[Ibele, Lyndon) yes, this information was submitted on form 10-422. it was submitted to tl~e
AOGCC under signature of Randy Jindra on 9/17/2007, Are you ur~able to find it in your
files?
Thanks in advance. Call or message with any questions.
Tom Maunder, PE
AOGCC
~~
~~~~ ~.
~ ~~
9/23/2009
~~
~ Page 1 of 1
Maunder, Thomas E (DOA)
_ _ . . . _ _.
From: Ibele, Lyndon (Icibele@marathonoil.com]
Sent: Monday, December 17, 2007 11:37 AM
To: Maunder, Thomas E (DOA)
Subject: Sundry status
Tom--
FYI, just wanted to let you know that we have had an on-going, company-wide IT problem that may affect our
ability to file sundry notices timely for a few wells. The data-base system that is used to generate all of our
downhole activity reports crashed on December 8th, and all the king's horses and all the king's men haven't been
able to put Humpty-Dumpty back together yet and we have been given no timeline for completion.
We know we are close to the 30 day deadlines for submitting Form 404 for recent work performed on Wells G03
and G05, and the 407 for G06. However, should the afore-mentioned database not be functional in the next few
days, we will be unable to retrieve operations summaries that are required with the sundries, and it is likely these
sundry reports could be tardy. I will keep you posted if that looks likely to occur.
RE Forms 10-421, there are several pending. However, we have not yet achieved stable production rates and
have been unable to perform multi-point tests on Sterling Unit wells 41-15rd and 43-9x. Those tests will be
performed and submitted as soon as possible. For Wells NS-3 and GO-6, we have single-point tests only to
report, because the wells are producing at maximum capacity but at very low rate. The only means to achieve
multiple flow points would require that the wells be choked-back, but doing so would cause them to be produced
below the unloading rate. This would not only be meaningless from a multi-point test perspective, but would also
jeopardize killing the wells. We will submit a cover letter with this explanation when we submit the form 10-421 for
these two wells.
~~`
~~~~ ~L~
~
4/9/2009
.~
~.,..: ~,~=.
~
w
M Marathon
MARATHON Oil Company
December 13, 2007
Mr. Tom Maunder
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, Alaska 99501
Reference: 10-407 Well Completion Report
~Marathon Oil Company
Alaska Asset Team
P.O. Box 1949
Kenai, AK 99611
Telephone 907/283-1371
Fax 907/283-1350
~~~ ~~~ ~~~~~ ~,~
, _ ~~
j~~ ~J ~ ~ 2~~~
Field: Sterling Field
Well: Sterling Unit 43-9x
Dear Mr. Maunder:
+~~;Et~'~~ '~`~`
8~~~} '~' j"3~ ~.~t14.~ ~
~i~s~~ ~~ ~,z~;~;~~~~~
Enclosed please find the 10-407 Well Completion Report for SU 43-9x well. The dual
gravel pack completion work was perFormed under Sundry # 307-220. Gas production
from SU 43-9x has been intermittent while we work through the process of bringing this
well on-line. This sundry does not contain gas production data due to the production
fluctuations.
Also attached for your records are the operations summary, current well schematic,
directional survey, and formation data.
Please contact me at (907) 283-1371 if you have any questions or require additional
information.
Sincerely,
• ~ ~~Xl~'
~.,e~U~'~
Kevin J. Skiba
Production Technician
Enclosures: 10-407 Well Completion Report cc: Houston Well File
Well Schematic Kenai Well File
Operations Summary KJS
Directional Survey DMD
Formation Data
~.~E~aClVr~L
,~• ~~OT
STATE OF ALASKA ~ ~ ~ ~ 7 ~~~7
ALA OIL AND GAS CONSERVATION COM SION
4 WELL COMPLETION OR RECOMPLETION REPOF~T~r~~l~~~~• ~~~+~+~~~~~
1a. Well Status: Oil ~ Gas~ Plugged ~ Abandoned ~ Suspended ~
20AAC 25.105 20AAC 25.110
GINJ^ WINJ ^ WDSPL[] WAG ^ Other^ No. of Completions: 1b. Well Class: ~~~Ea ~
Development ~ Exploratory ^
Service ^ Stratigraphic Test ^
2. Operator Name:
Marathon Oil Company 5. Date Comp., Susp., or •
Aband.: 8/8/2007 12. Permit to Drill Num r•
~~1'~ a~~~~207-073 '
3. Address: p0 Box 1949, Kenai Alaska, 99611-1949 6. Date Spudded:
6/9/2007 13. API Number ,
-~~ -133-20569-00-00
4a. Location of Well (Governmental Section):
Surface: 2,408' FSL, 426' FEL, Sec. 9 T5N, R10W, S.M. 7. Date TD Reached:
6/17/2007 14. Well Name and Number:
Sterling Unit 43-9x °
Top of Productive Horizon: ~~~~ 7
1,262' FNL, 1,226' FEL, Sec. TSN, R10W, S.M. 8. KB (ft above MSL): 245'
Ground (ft MSL): 2~' 15. Field/Pool(s): '
Total Depth: ~~~J ~ Z~~~7
1,251' FNL, 1,219' FEL, Sec. TSN, R10W, S.M~ 9. Plug Back Depth(MD+TVD):
6,114' MD 5,627' TVD Stgrllllg FI@Id / Ste~llllg POOI
4b. Location of Well (State Base Plane Coordinates, NAD 27):
Surface: x- 314,749.39 y- 2,390,123.37 Zone- 4 10. Total Depth (MD + TVD):
6,185'- 5,698' 16. Property Designation:
A- 028063
TPI: x- 313,976.56 y- 2,391,980.99 Zone- 4
Total Depth: x- 313,983.17 y- 2,391,991.78 Zone- 4 11. SSSV Depth (MD + TVD):
NA NA 17. Land Use Permit:
18. Directional Survey: Yes ~ No
(Submit electronic and printed information per 20 AAC 25.050) 19. Water Depth, if Offshore:
Nq (ft MSL) 20. Thickness of Permafrost (TVD):
NA
21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071):
Quad Combo, RFT, CBL, GR, CCL
22. CASING, L INER AND CEMENTING RECORD
CASING WT. PER
GRADE SETTING DEPTH MD SETTING DEPTH ND
HOLE SIZE
CEMENTING RECORD AMOUNT
FT TOP BOTTOM TOP BOTTOM pULLED
0
20" 133 K-55 0' 103' 0' 103' Drive NA NA
13-3/8" 68 J-55 0' 1,990' 0' 1,871' 16" 620 sks, 12ppg, Type 1 66 sks
9-5/8"
40
L-80
0'
6,174'
0'
5,687'
12-1/4" 210 sks, 12.5ppg, Class G
400 sks, 15.8ppg, Class G
NA
0
0
23. Open to production or injection? YesQ No~ If Yes, list each 24. TUBING RECORD
interval open (MD+TVD of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER SET (MD)
MD ND Size Spf Phase 2-3/8" 5,588' S,588'
5,724'-5,730' 5,237'-5,244' 7" 18spf 140-20 deg.
'
'
'
'
" y_7/g^ 5,627' S,588' & 5,627'
5,766
-5,776
5,279
-5,289
7
18spf 140-20 deg. 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC.
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
5,750' - 5,751' S8 sks, 15.8ppg, Class G
75 sks, 15.8ppg, Class G
26. PRODUCTION TEST
Date First Production: 11/17/2007 Method of Operation (Flowing, gas lift, etc.):
Flowin
Date of Test:
NA Hours Tested: Production for
Test Period Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio:
Flow Tubing
Press. Casing Press: Calculated
24-Hour Rate ~ Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity - API (corr):
27. CORE DATA Conventional Core(s) Acquired? Yes ^ No ~^ Sidewall Cores Acquired? Yes ^ No ~^
If Yes to either question, list formations and intervals cored (MD+ND of top and bottom of each), and summarize lithology and presence of oil, gas or water
(submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071.
.~uY ~ ~~~ION
~~:-~:.~
~ ~
;„ti ,.;:~.W,.=...~..,.~..~
Form 10-407 Revised 2/2007 CONTINUED ON REVERSE
~ ~~~. ~~~ ~ ~ ~007 G
28. GEOLOGIC MARKERS (List all formations and ma ncountered): 29. FORMATION TESTS
NAME MD ND Well tested? ~ Yes N ff yes, list intervals and formations tested, briefly
summarizing test results. Attach separate sheets to this form, if needed, and submit
permafrost`- Top detailed test information per 20 AAC 25.071.
Permafrost - Base
See Attachment: SU 43-9x Formation Tests
Sterling B4 5,723' 5,236'
Upper Beluga 6,068' 5,581'
Formation at total depth:
30. List of Attachments:
Operations Summary, Well Schematic, Directional Survey, Formation Tests
31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Kevin Skiba (907) 283-1371
Printed Name: BIlI71S M. DOII V817 Titie: Production Engineer
Signature: ~ Phone: (907) 283-1333 Date: December 13, 2007
INSTRUCTIONS
General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic
diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed.
Item 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for 1 njection, Observation, or
Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool
is a completion.
Item 4b: TPI (Top of Producing Interval).
Item S: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form
and in any attachments.
Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and ND for the top and base of permafrost in Box 28.
Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool.
Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals
for only the interval repoRed in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such
interval).
Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Item 27: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed
description and analytical laboratory information required by 20 AAC 25.071.
Item 29: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and
analytical laboratory information required by 20 AAC 25.071.
Form 10-407 Revised 2/2007
• •
Permit #: 207-073
API #: 50-133-20569-00-00
Propertv Des: A - 028063
KB elevation: 245' (21' AGl)
wes n:
Spud: 6/9/2007 16:30 hrs
Latitude:
Lons~itude:
Riq Released: 1st 6/24/2007 09:00 hrs
2nd 10/30/2007 06:00 hrs
TD: 6/17/2007 6,185' MD
Short Strina
2-3/8" L-BO 4.7ppf IBT-M tubing
(ID = 1.995")
-Baker GT Dual Packer w/60K shear Ang (d 5,588'
•XN• nipple @ 5,600' (ID = 1.75")
-Wlreline re-entry guide ~ 5,605'
SU 43-9x
Sterlinq Pad
2,408' FSL, 426' FEL
Sec. 9, T5N, R10W, S.M.
Lona SMna Tubina
2-718" L-80 6.4ppf EUE tubing
Brd (ID = 2.441")
-GLM's ~ 1,740', 2,943', 3,884', 4,558', 5,030', 5,433'
-Baker GT Dual Packer w/60K shear ring ~ 5,588'
B4
J5724 5730' (6') I - _
I ~ ,T }
p, ~ ~ -
~ . ,,
r ' .r' t '
. . . . k ~'•~C .. .. 4 . 1. .. \ TK.
- 5776' (10')
6,114' MD
5,627' TVD
M
Marun~oM
DAve Pioe
20" K-55 133 ppf
T~o Bottom
MD 0' 103'
TVD 0' 103'
SurFace Casina
733/8" J-55 68ppf BTC
~ eottom
MD 0' 1,990'
TVD 0' 1,870'
Cmt w/ 620 sks, 12ppg, Type 1
Intermediate Casina
9-5/B" L-80 40ppi BTC
~ig Bottom (8.835" ID)
MD 0' 6,174'
TVD 0' S,687'
Cmt w/ 210 sks, 12.5ppg, Class G
Cmt w/ 400 sks, 15.Sppg, Class G
nock out isolation valve @ 5660'
x 18' x 12 pa BakerW eld 140 Sc
~ 1,'_: ,; "''
• _ Lonqstrinq: 2-7/8^ x 10' bngstring Blast ;
SBHP = 1,980 psig
~^;; joint @ 5724'
a. ,
//:~ ., _ .
f
:F ~~
.
~.~
~
,
.
~
~ Lonqstrinq - X-nipple @ 5736' (ID = 2.313")
~ GWC @ 5,035'
. Baker SC-1 gravel pack packer @ 5738 ;
4 Y #
~ SSTVD
~
5-1/2" x 18' x~12 ga BakerWeld 140 Screen @ 5764'
~ SBHP = 1,990 psig
~
-5,066' SSTVD
Baker Model D sump packer @ 5784'
Well Name 8 Number: Sterling Unit 43-9x Lease: Sterling Unit
County or Parish: Kenai Penisula Borough State/Prov: Alaska Country: USA
Perforations (MD): 5,724' - 5,730' (6') SS 8 5,766' - 5,776' (10') LS (TVD): 5,237' - 5,243' SS 8 5,280' - 5,290' LS
Angle/Perfs: 0 deg Angle @KOP and Depth: 0 deg @ 200' KOP TVD: 200'
BHP: 1,980 BHT: 0 Completion Fluid: 6% KCL
FWHP: FBHP: FWHT: FBHT: Other:
Date Completed: RKB:
Prepared By: Kevin Skiba Last Revision Date: 12H3/07
~ ~ y .v
SU 43-9x Directional Survey
W ELLPATH DATA (77 stations)
MD Inclination Azimuth TVD Vert Sect North East DLS
[feet] [°] [°] [feet] (feet] [feet] [feet] [°/100ft]
0 0 0 0 0 0 0 0
151 0.17 270.11 151 0.09 0 -0.22 0.11
212 1.12 355.2 212 0.69 0.59 -0.36 1.83
273 2.2 356.77 272.97 2.36 2.36 -0.48 1.77
333 3.36 348.6 332.9 5.16 5.23 -0.89 2.04
394 5.33 341.49 393.72 9.73 9.67 -2.15 3.34
454 6.76 341.35 453.38 16.03 15.66 -4.16 2.38
514 8.22 340.56 512.87 23.83 23.05 -6.72 2.44
575 9.43 339.88 573.15 33.17 31.86 -9.89 1.99
635 10.73 338.33 632.22 43.67 41.66 -13.64 2.21
695 11.77 335.66 691.07 55.37 52.43 -18.23 1.94
754 13.39 334.41 748.65 68.21 64.07 -23.66 2.78
817 14.75 335.76 809.76 83.52 77.97 -30.1 2.22
880 15.42 334.23 870.59 99.91 92.82 -37.03 1.24
943 16.94 334.97 931.09 117.45 108.68 -44.56 2.43
1006 17.96 335.21 991.19 136.33 125.82 -52.52 1.62
1070 19.51 336.47 1051.8 156.88 144.57 -60.92 2.5
1133 20.73 335.5 1110.95 178.55 164.37 -69.74 2.01
1196 21.31 335.21 1169.76 201.14 184.9 -79.17 0.94
1259 22.91 336.17 1228.12 224.85 206.52 -88.92 2.6
1322 24.1 336.23 1285.9 249.97 229.51 -99.06 1.89
1385 25.29 337.17 1343.13 276.29 253.68 -109.47 1.99
1449 26.13 337.41 1400.8 304.05 279.29 -120.19 1.32
1512 26.87 337.55 1457.18 332.16 305.26 -130.95 1.18
1575 27.98 337.32 1513.1 361.18 332.05 -142.09 1.77
1638 28.78 337.85 1568.52 399.12 359.74 -153.5 1.33
1701 29.49 336.96 1623.55 421,79 388.05 -165.29 1.32
1764 30.52 336.73 1678.11 453.29 417.02 -177.68 1.65
1827 31.43 335.98 1732.12 485.71 446.72 -190.69 1.57
1890 31.85 336.21 1785.76 518.76 476.93 -204.08 0.69
1943 31.09 336.49 1830.96 546.43 502.28 -215.18 1.46
2003 30.25 337.61 1882.57 577.03 530.46 -227.11 1.69
2067 31.19 337.81 1937.59 609.72 560.71 -239.51 1.48
2194 32.89 339.24 2045.24 677.06 623.41 -264.16 1.47
2320 32.74 339.11 2151.14 745.28 687.23 -288.43 0.13
2447 32.37 339.65 2258.18 813.55 751.19 -312.5 0.37
2573 31.55 337.1 2365.09 880.21 813.18 -337.06 1.25
2699 31.18 337.87 2472.67 945.78 873.76 -362.18 0.43
2825 30.82 335.87 2580.68 1010.67 933.44 -387.66 0.87
2952 30.42 335.66 2689.97 1075.35 992.42 -414.21 0.33
3077 30.8 334.74 2797.55 1138.97 1050.2 -440.91 0.48
3203 30.26 334.87 2906.08 1202.94 1108.12 -468.16 0.43
3330 30.54 336.56 3015.63 1267.18 1166.69 -494.58 0.71
~ ~
MD Inclination Azimuth TVD Vert Sect North East DLS
[feet] [°] [°] [feet] [feet] [feet] [feet] [°/100ft]
3456 32.11 336.5 3123.26 1332.69 1226.78 -520.67 1.25
3582 31.53 336.38 3230.32 1399.12 1287.67 -547.23 0.46
3708 30.82 336.93 3338.12 1464.34 1347.55 -573.07 0.61
3834 30.31 337.06 3446.61 1528.42 1406.53 -598.12 0.41
3960 29.69 336.96 3555.73 1591.42 1464.53 -622.72 0.49
4086 29.28 337.19 3665.41 1653.43 1521.65 -646.88 0.34
4149 28.99 337.63 3720.44 1684.1 1549.96 -658.66 0.57
4213 28.62 337.23 3776.52 1714.94 1578.44 -670.5 0.65
4276 27.02 336.92 3832.24 1744.34 1605.52 -681.95 2.55
4339 25.9 336 3888.64 1772.41 1631.25 -693.15 1.89
4402 25.13 335.32 3945.5 1799.54 1655.98 -704.34 1.31
4465 23.26 332.37 4002.96 1825.32 1679.16 -715.69 3.53
4528 21.61 329.87 4061.19 1849.24 1700.22 -727.28 3.02
4592 19.62 330.18 4121.09 1871.61 1719.73 -738.55 3.11
4656 17.68 331.08 4181.73 1891.96 1737.56 -748.59 3.06
4718 16.12 330.63 4241.05 1909.88 1753.31 -757.36 2.52
4781 14.29 329.79 4301.84 1926.3 1767.65 -765.57 2.93
4844 13.1 328.78 4363.05 1941.08 1780.47 -773.18 1.93
4907 11.78 328.21 4424.57 1954.51 1792.05 -780.27 2.1
4970 10.63 327.59 4486.37 1966.61 1802.42 -786.77 1.84
5033 9.89 327.48 4548.36 1977.68 1811.89 -792.79 1.18
5097 8.33 328.02 4611.55 1987.69 1820.45 -798.2 2.44
5159 6.34 331.3 4673.04 1995.53 1827.27 -802.23 3.28
5222 4.54 338.52 4735.75 2001.49 1832.64 -804.81 3.05
5284 2.68 350.19 4797.63 2005.35 1836.35 -805.96 3.21
5347 1.14 28.3 4860.59 2007.17 1838.35 -805.91 3.04
5473 1.19 27.14 4986.57 2008.79 1840.62 -804.72 0.04
5600 1.2 32.32 5113.54 2010.39 1842.92 -803.41 0.09
5726 1.49 32.14 5239.5 2012.06 1845.42 -801.83 0.23
5854 1.36 30.71 5367.47 2013.91 1848.14 -800.17 0.11
5979 1.63 28.74 5492.42 2015.88 1850.97 -798.56 0.22
6106 1.76 30.85 5619.37 2018.13 1854.23 -796.69 0.11
6128 1.79 32.07 5641.36 2018.53 1854.81 -796.33 0.22
6185 1.79 32.07 5698.33 2019.54 1856.32 -795.39 0
6106 1,76 30.85 5619.37 2018.13 1854.23 -796.69 0.11
6128 1.79 32.07 5641.36 2018.53 1854.81 -796.33 0.22
6185 1.79 32.07 5698.33 2019.54 1856.32 -795.39 0
SU 43-9X Formation Tests
~
~
Test No.
Depth(ft)
TVD(ft Quartz
Pressure
Before psi
Quartz Pressure
Final Shut-in psi Quartz
Pressure After
psi
Comments
33 500 258 15 258 CASING CHECK/GOOD SEAL
1 500.1 252 13 251 CASING CHECK/GOOD SEAL
2 1849.76 871 31 871 CASING CHECK/GOOD SEAL
30 5730 2626 1971/1971 2626 GOOD TEST/GOOD TEST
16 5733 5246.5 2625 1971/1971 2626 GOOD TEST/GOOD TEST
27 5737 5250.5 2628 1973/1973 2628 GOOD TEST/GOOD TEST
26 5741 5254.5 2629 1994/1975 2628 SLOW LEAK/GOOD TEST
25 5745 5258.5 2631 1976/1976 2631 GOOD TEST/GOOD TEST
24 5749 5262.49 2634 1978/1978 2633 GOOD TEST/GOOD TEST
23 5753 5266.49 2636 1980/1980 2636 GOOD TEST/GOOD TEST
21 5757 5270.49 2638 1982/1982 2637 GOOD TEST/GOOD TEST
20 5770 5283.49 2644 1988/1988 2644 GOOD TEST/GOOD TEST
19 5774 5287.49 2646 1989/1989 2646 GOOD TEST/GOOD TEST
18 5778 5291.49 2647 1991/1991 2648 GOOD TEST/GOOD TEST
17 5782 5295.49 2650 2619/1992/1992 2649 ERROR/GOOD TEST/GOOD TEST
15 5782.04 5295.49 2649 2649/1993 2649 NO SEAUGOOD TEST
13 5786.01 5299.49 2650 1997/1994 2650 GOOD TEST/GOOD TEST
12 5790.05 5303.48 2653 1999/1996/1996 2652 GOOD TEST/GOOD TEST/GOOD TEST
11 5793.03 2655 2655/2655 2655 NO SEAL/NO SEAL
10 5794 5307.48 2654 2654/2035/1998 2655 NO SEAL/NO TEST/NO TEST
14 5794.01 5307.48 2656 1998/1998 2655 GOOD TEST/GOOD TEST
9 6089.01 2800 40 2799 TIGHT
8 6115.12 2812 2815 2812 NO SEAL
7 6116.09 5629.36 2812 2808 2812 NO SEAL
31 6116.99 2813 2812/2812 2813 NO SEAL/NO SEAL
6 6118.07 2811 2636 2812 LOST SEAL
32 6119 2813 2767/2102 2819 SLOW LEAK/SLOW LEAK
28 6120 5633.36 2811 2811 2811 NO SEAL
5 6120.05 5633.36 2811 59 2811 TIGHT
29 6123 2811 2811 2813 NO SEAL
4 6123.05 2812 68 2813 TIGHT
3 6124.01 5637.36 2813 2620 2812 NO SEAL
Operationai Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date
------------------------•------------------- --------------- Activity_-------------..._...---- Depth----
--------... .__.. - ._...._..-------------------------------------------------------------..
Drilling Event:
-----------------------•--------------------
--------------...----...----------------------------------------------
-------------------•------------------------------------•------------
06/07/07 1 00:00 06:00 6.00 RIG_ AF 103
MIRU RURD Move in rig from KBU 34-6
_ PJSM with crews and drivers. Spot generator, boiler,
water tank, pump room/pits, and sub structure. Prep sub
and scope up.
06/08/07 2 06:00 12:00 6.00 RDMO RURD RIG AF 103 Continue RU. Raise and rig-up gas buster. MU dresser
sleeves and pop-off valves in pits. Plumb in #2 cooling
~ tower. Trouble shoot and fix fuel problem on #2 carrier
motor. Spot mud boat and carrier and level same. RU
camp trailers.
06/08/07 2 12:00 16:00 4.00 RDMO RURD RIG AF 103 Crew change PJSM. Continue RU camp trailers Set
Hansen tank, cuttings tank and MI solids control van. Prep
carrier to raise derrick.
06/08/07 2 16:00 00:00 8.00 RDMO RURD_ RIG_ AF 103 PJSM with crane operator. Installl carrier platForm and
staris. Install Grey iorn, fuel tank, dog and choke house,
raise back wind walls.
Changeout 37 pin control cable for pit aggitators. Finish
RU camp trailers.
06/08l07 2 00:00 06:00 6.00 RDMO RURD_ RIG AF 103 Crew change PJSM. Pull wires to carrier, dog and choke
houses. Prep and scope up derrrick. RU derrick board.
Secure guide lines. Spot cafinralk RU beaver slide and
stairs.RU mud manifold to choke house. Same time
trouble shooting problem w/rig's computer PLC.
•06/09/07 3 06:00 12:00 6.00 MIRU RURD_ RIG_ AF 103
06/09/07 3 12:00 13:00 1.00 MIRU SAFETY MTG_ AF 103
06/09/07 3 13:00 18:00 5.00 MIRU RURD_ RIG_ AF 103
PJSM. Install cylinder sock"T" bar. P/U and M/U torque
tube. Install turnbuckles and adjust torque tube. Spot
cement silo and mud pump#3. Unload trailers. Spot
Epoch unit and Baker MWD unit. R/U service lines to
pump#3 and prep to C/O bladder for pulsation dampner on
pump#3. R/U Gaitronics and R/U Geolograph. P/U top
drive and slide.
One hour weekly safety meeting for both crews.
Hang top drive and slide. Hook up service lines.
Page 1 of 33 - Printed 12/13/2007
Operational Detaiis for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date _.
----------------------
- ._ ActivitY------------------------- Depth---- -------- ----------.._..---------------------------------------
----------
----
----------•----------------------------
06/09/07 3 18:00 21:30 3.50 MIRU RURD RIG AF 103 Fill pits w/ make-up water. RU misc equipment. (Have
_ been trouble shooting PLC system at the drillers consol for
most of the day. Finally contacted tech w/ Electric Power
Systems f/ ANC. flew him to rig and problem fixed within
1/2hr. PLC system needs updated and made more user
friendly. Tech made copy of program and will update later.
No actual downtime)
06/09/07 3 21:30 00:00 2.50 SURDRL NUND BOPE AF 103 Make final cut/trim on 20" conductor. Install Vetco 20" x 21-
~ 1/4" SO starting head. Pressure test to 500psi / 10 min
LJ
06/09/07 3 00:00 05:00 5.00 SURDRL NUND BOPE AF 103 Crew change. PJSM. Continue NU diverter system. Install
bell nipple, flow line, fill-up line and trip tank lines. Mixing
spud mud.
06/09/07 3 05:00 06:00 1.00 SURDRL PULD DP AF 103 InstaN mousehole. PJSM prep to PU 5" DP.
"
06/10/07 4 06:00 07:00 1.00 SURDRL _
PULD_ _
DP_ AF 103 Set pipe racks. Changeout saver sub. PJSM R/U to P/U 5
DP.
06/10/07 4 07:00 08:00 1.00 SURDRL TEST_ BOPE AF 103 Test 21 1/4" diverter. Perform koomey test(AOGCC
waved witness by Lou Gramaldi).
06/10/07 4 08:00 10:30 2.50 SURDRL PULD_ DP_ AF 103 PJSM/JSA. P/U, drift and standback 5" DP(total 70 joints).
06/10/07 4 10:30 11:00 0.50 SURDRL PULD DP_ AF 103 Rack and tally 5" HWDP and Jars. Test gas alarms.
06/10/07 4 11:00 12:00 1.00 SURDRL _
PULD DP_ AF 103 P/U/JSA P/U, drift and rack back 5" HWDP and jars.
06/10/07 4 12:00 13:00 1.00 SURDRL _
PULD__ DP_ AF 103 Cont. P/U 5" HWDP(total 21 jnts and Jars).
06/10/07 4 13:00 13:30 0.50 SURDRL SAFETY MTG AF
TA 103
MSFL 103 Pre-spud safety meeting.
C/O top drive gooseneck. Rebuild damaged
PJSM/JSA
~6/10/07 4 13:30 15:00 1.50 SURDRL REPAIR RIG_ .
rig berm. Repair trip tank mechanical pit monitor.
06/10/07 4 15:00 16:30 1.50 SURDRL PULD BHA AF 103 PJSM/JHA. P/U BHA.
'
06/10/07 4 16:30 18:00 1.50 SURDRL DRILL ROT AF 130 to
Spud well 16:30hrs 6/9/2007. Clean conductor F/47
103' Drill new hole f/ 103' to 130'. ART= .3hrs
06/10/07 4 18:00 18:40 0.67 SURDRL DRILL_ ROT_ AF 200 Drill f/ 130' - 200'. ART .5hrs 380 - 420 gpm pp= 550psi
06/10/07 4 18:4018:50 0.17 SURDRL CIRC_ MUD_ AF 200 CBU
06/10/07 4 18:50 19:10 0.33 SURDRL TRIP_ DP_ AF 200 TOH to motor.
06/10/07 4 19:10 20:45 1.58 SURDRL PULD BHA AF 200 PU BHA #2 RIH no fill.
06/10/07 4 20:45 22:00 1.25 SURDRL _
DRILL _
ROT AF 279 Directionally drill f/ 200' to 279'. 380-420 gpm 750psi Tq=1-
_ 3k wob= 5-10k Experiencing problems with MWD
" decoding signals.
06/10/07 4 22:00 23:00 1.00 SURDRL REPAIR EQtP TA MDMW 279 Diagnos and correct MWD problems. Software reboot.
.. Page 2 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date __ ActivitY------------------------- Depth.------------
•----------------------------------------------------------------- - -------- ----------------
06/10/07 4 23:00 00:00 1.00 SURDRL DRILL ROT AF 308 Directionall drill ahead f/ 279' to 308'. Still having MWD
problem mainly from interferance.
ART= 0.2 hrs AST= 0.9 hrs
06/10/07 4 00:00 06:00 6.00 SURDRL DRILL_ ROT AF 732 Crew change. PJSM. Continue drilling ahead f/ 30$' to
732'. Up wt 50k Dw wt 50k rot wt 50k pp 900psi 550 gpm
ART= 1.0 hrs AST= 2.5 hrs
06/11/07 5 06:00 12:00 6.00 SURDRL DRILL ROT AF 1,130 Dir drill and survey F/732' to 1130'(ART=1.6hrs
AST=1.8hrs).
~06/11/07 5 12:00 14:30 2.50 SURDR~ DRILL_ ROT_ AF 1,252 Dir drill and survey F/1130' to 1252'(ART=.9hrs
AST=.9hrs).
06/11I07 5 14:30 15:00 0.50 SURDRL CIRC_ MUD_ AF 1,252 Circ, clean(CBUX2, 650GPM 1400psi).
06/11/07 5 15:00 16:00 1.00 SURDRL REPAIR RIG_ TA MSFL 1,252 Flo check. Trip tank valve would not open. Attempt to
repair. Align troughs in pits so that the trip can be
monitored from the pill pit.
06/11/07 5 16:00 17:30 1.50 SURDRL TRIP_ DP AF 1,252 POOH to 200'(hole in good condition).
06/11/07 5 17:30 18:15 0.75 SURDRL SERVIC RIG_ AF 1,252 Service rig. Change fuel filters on lopping #1 Carrier
engine, sems better.
06/11/07 5 18:15 19:15 1.00 SURDRL TRIP DP_ AF 1,252 PJSM. TIH w/ DP. No fill.
06/11/07 5 19:15 20:45 1.50 SURDRL _
REPAIR EQIP TA MSDE 1,252 BHI computers/software not sychronizing data f/ MWD.
Changeout standpipe transducer/cable. Reboot computers
and started working again. Intial problem unknown could
have been faulty or loose transducer connection.
~'J6/11/07 5 20:45 00:00 3.25 SURDRL DRILL ROT AF 1,492 Continue directionallydrilling ahead f/ 1252'. 3 pumps @
_ _ 110 spm 640 gpm 1360 psi off bottom. WOB= 20-25k Up
wt 67k Dwn Wt 62k Rt Wt 64k Double ream each std.
ART= 1.0 hrs AST= .8 hrs
06/11/07 5 00:00 06:00 6.00 SURDRL DRILL ROT AF 1,903 Crew change. PJSM. Continue directional drill ahead f/
1492' to 1902'.
ART=1.8 AST=1.5
06/12/07 6 06:00 07:00 1.00 SURDRL DRILL_ ROT_ AF 2,000 Dir drill and survey F/1903' to 2000' (ART=.6hrs
AST=Ohrs).
06/12/07 6 07:00 08:00 1.00 SURDRL CIRC MUD AF 2,000 Circ. clean (CBUX2, 650GPM, 1450psi, MW 10.5ppg).
06/12/07 6 08:00 11:00 3.00 SURDRL _
TRIP_ DP_ AF 2,000 PJSM. POOH w/DP to 200' (SLM no correction). Clean
floor.
06/12/07 6 11:00 12:00 1.00 SURDRL TRIP_ DP_ AF 2,000 RIH to 2000'.
- Page 3 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date
------------
-------- -----------
--- ------------ Activity-- ------------ ----------- Depth.--.. .----...----------------------...-------------------------------._...._
------------
06/12/07 --------
6 ----
12:00 13:30 1.50 SURDRL CIRC MUD AF 2,000 Pump 40bbls hi vis sweep w/nut plug and circ. out. Cont.
to circ untill shakers clean (C8UX2, 650GPM,1200psi, MW
10.3ppg). Sweep indicated +/-20% washout. Flow check
and pump dry job.
06/12/07 6 13:30 16:00 2.50 SURDRL TRIP_ DP_ AF 2,000 POOH w/DP.
06/12/07 6 16:00 18:00 2.00 SURDRL TRIP_ BHA_ AF 2,000 PJSM. UD BHA and bit.
06/12/07 6 18:00 18:20 0.33 SURDRL CLEAN_ RIG AF 2,000 Clean rig floor.
06/12/07 6 18:20 20:40 2.33 SURCSG RURD CSG AF 2,000 PJSM. RU long bales. RU casing running tools.
~6/12/07 6 20:40 21:10 0.50 SURCSG SAFETY DRIL AF 2,000 PJSM. Review past incident handling tongs. Review new
procedures.
06/12/07 6 21:10 00:00 2.83 SURCSG RUN_ CSG_ AF 2,000 Run 13-3/8" 68# J55 surface csg. (26 of 47 jts)
06/12/07 6 00:00 00:20 0.33 SURCSG SAFETY DRIL AF 2,000 Crew change. PJSM review same as above with oncoming
crew.
06/12/07 6 00:20 01:45 1.42 SURCSG RUN_ CSG_ AF 2,000 Continue running casing. Total 47jts 1992.27'. Landed
2.27' above KB(shoe @ 1990').
06/12/07 6 01:45 03:30 1.75 SURCSG RURD_ CSG_ AF 2,000 RD Weatherford equipment. RU to run 5" DP inner string.
06/12/07 6 03:30 06:00 2.50 SURCSG TRIP_ DP_ AF 2,000 PJSM MU stab-in sub on 5' pup jt RIH with 5" DP. Stab-in
to float collar. Spaceout with pup jts.
06/13/07 7 06:00 07:00 1.00 SURCSG CIRC_ MUD AF 2,000 Circ. condition mud for cementing(217gpm, 205psi}.
06/13/07 7 07:00 07:30 0.50 SURCSG SAFETY MTG_ AF 2,000 PJSM for cementing while transfer mud to hansen tank.
06/13/07 7 07:30 09:30 2.00 SURCSG PUMP CMT AF 2,000 Break circ. w/BJ. Pump 5bbls Mud Cleanll ahead. Test
BJ lines to 2000psi. Pump 31 bbls Mud Cleanll ahead. Mix
~ and Pump 620SXS Type 1 cement w/.005#/SX Static Free,
2% CaCI, 22%LW-6, .3%CD-32, 1 gphs FP-6L, 1% SMS,
20%MPA-1 to yield 280bb1s 12ppg slurry. Dispalce
w/30bbls 9.3ppg mud. Full returns durinq entire job
w/30bbls cement to surface. CIP@09:30hrs.
06/13/07 7 09:30 11:00 1.50 SURCSG CIRC_ MUD AF 2,000 Check floats. Sting-out from stab-in collar. Got flow up DP
about 6bbls. Fluid in DP was lighter than fluid on
annulus(appears BJ pumped some water instead of all
mud). L/D pups and pull 1 stand DP. Drop sponge and
circ. out.
06/13/07 7 11:00 14:00 3.00 SURCSG TRIP_ DP_ AF 2,000 POOH w/5" DP and cement stinger.
06/13/07 7 14:00 14:30 0.50 SURCSG CLEAN RiG_ AF 2,~Q0 Reflush stack and lines.
06/13/07 7 14:30 15:00 0.50 SURCSG SLPCUT DLIN AF 2,000 Slip drilling line.
_ Page 4 of 33 - Printed 12/13/2007
' Operational Details for Weii: STERLING UNIT 43-9X
Re ort
p
II Re t#
p From To Hours Phase Activity Sub Status T Type To Operations
Date
-----•-----
--------
----------------
--------•
------------•
-----------. ' '
Activity---
-----
-----------
----------- De th
---~------..
_...------------------------------------------------------------------
-
06/13/07 7 15:00 19:30 4.50 SURCSG WAITON CMT_ AF 2,000 WOC.
PJSM. review procedures for ND diveter system. While
WOC RD 16" blooie line, trip tank line. Check bridge
cranes. Prep to cut csg and ND diverter sytem.
6/13/07
7
9:30 21:15
.75
URCSG
UN~
~~E
F
A
2 000
, levators no i e movement.
- I te from under es e p p
Pull C a g
~ ~
Open 16" knife valve and cut 13 3/8" csg. Remove drilling
nipple. ND 20" diverter and set out.
1 7
06/ 3/0
7
21:15 00:00
2.75
SURCSG
NUND
WLHD AF 2 000
, PJSM. Remove Vetco 20" starting head. Make rough cut
" nd remove.
n 20 conductor a
~6/13/07 7 00:00 00:10 0.17 SURCSG SAFETY DRIL AF 2,000 Crew Change. PJSM review NU procedures.
06/13/07 7 00:10 03:00 2.83 SURCSG NUND WLHD AF 2,000 Make final cut and dress 9-5/8" casing. Install Vetco Multi-
Bowt SLC 13 5/8" 5M fwellhead. Test 1500psi f/ 10 min.
Good test.
Rebuilding boiler.
06/13/07 7 03:00 06:00 3.00 SURCSG NUND BOPE AF 2,000 NU 3' x 13-5/8" 5m spacer spool, 13 5/8" 5M single gate,
mud X, double gate, and annular.
06/14/07
8
06:00 09:30
3.50
SURCSG
NUND
BOPE
AF
2,000 ~~
Continue NU 13-5/8 5M BOPE.
06/14/07
E
09:3010:30
1.00
SURCSG
TEST_
~~~E
AF 2 000
,
W/
M/U test 'oint, set test plug. Fill Bop stack and lines
1
H2o
06/14/07 8 10:30 15:30 5.00 SURCSG TEST BOPE AF 2,000 Test BOPE and all related components 250/2000psi f/
10min ea. Test gas alarms
LEL, H2S and PVT system. Perform Accumulator
' Drawdown test. Witness waved Lou Grimaldi AOGCC.
BLM Notified but no response.
~6/14/07 8 15:30 16:00 0.50 SURCSG RUNPUL WBSH AF 2,000 Set wear bushing RILDS. L/D test jt.
06/14/07 8 16:00 18:00 2.00 SURCSG TEST_ CSG TA CSTF 2,000 Attempt to test casing to 1500psi f/ 30min Test failed. CK
surface lines, re-test to
1500psi test failed.
06/14/07 8 18:00 19:30 1.50 SURCSG PULD DP AF 2,000 PJSM. P/U Drift and tally 5" drillpipe
06114/07 8 19:30 21:30 2.00 SURCSG _
TRIP_ _
DP TA CSTF 2,000 PJSM. PU Howco RTTS and cire sub. TIH to 1940' and
set RTTS. (top of float collar at 1947')
06/14/07 8 21:30 22:30 1.00 SURCSG TEST_ CSG AF 2,000 Close annutar. Test 13-3/8" 68# surface casina to 1540 nsi
for 30 min. aood test final pressure 1520psi.
06/14/07 8 22:30 00:30 2.00 SURCSG TRIP DP_ TA CSTF 2,000 Release RTTS and TOH.
06/14/07 8 00:30 01:30 1.00 SURCSG _
TRIP_ DP_ TA CSTF 2,000 Crew change. PJSM. Continue TOH. LD loadout Howco
equipment.
4/07
06/1 8 01:30 05:00 3.50 SURCSG PULD_ DP AF 2,000 PJSM Continue picking up RIH w/ drifted 5" dritlpipe.
_
06/14/07 8 05:00 06:00 1.00 SURCSG TRIP_ DP_ AF 2,000 TOH standing back DP and tally.
06/15/07 9 06:00 06:30 0.50 SURCSG TRIP_ DP_ AF 2,000 Continue TOH and strap 5" DP.
- Page 5 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date
-
-----
---
-------------• ._
---------- Activ_ity-- ----------- -------------Depth---
---
----- -
-
06/15/07 ----------•-----------
9 06:30 07:00 -
0.50 SURCSG SERVIC RIG AF
AF 2,000
000
2 Service rig. lube carrier, dwks.
PJSM; P/U and M/U 12 1/4 bha . Scribe motor/ mwd. Rih
06/15/07 9 07:00 08:30 1.50 SURCSG TRIP_ BHA_ ,
and pulse test.
06/15/07 9 08:30 10:00 1.50 SURCSG TRIP_ DP AF 2,000
000
2 Tih W/ 5" drillpipe to 1940'
of F/C at 1942' Drill shoe track f-1946'-1988' Drill
Ta
to
06/15/07 9 10:00 11:30 1.50 SURCSG DRILL_ CMT AF , p
g
soft cement
f 1946-1960' Drill firm cement f-1960-1986' (Top of float
shoe), Drill out float
~
9
00
30 12
11
50
0
SURCSG
TEST
LOT
TA
CSTF 2,000 shoe to 1988'.
Perform precautionary FIT at 1990' 9.1 MW 380psi at
6/15/07 :
: . _ _ 1880TVD=13pp9 EMW
06/15/07 9 12:00 12:30 0.50 SURCSG REPAIR RIG_ TA MSFL 2,000 Repair Bleeder valve on #2 mud pump
t f-1988' to 2000' Drill new hole f-2000'-2020' art=
Cl
06/15/07 9 12:30 13:15 0.75 SURCSG DRILL_ ROT_ AF 2,020 ean ou
.2
06/15/07 9 13:15 15:00 1.75 SURCSG CIRC_ MUD AF 2,020 Circ Clean up and Displace hole With new 9.Oppg flow pro
mud
06/15/07 9 15:00 15:30 0.50 SURCSG TEST_ LOT_ AF 2,020 Perform FIT test 9.Omw 390psi at 1880TVD = 13.OEMW
06/15/07 9 15:30 15:50 0.33 PR1 DRL MfX_ MUD_
06/15/07 9 15:50 18:00 2.17 PR1 DRL DRILL_ ROT_
~6/15/07 9 18:00 00:00 6.00 PR1DRL DRILL_ ROT_
06/15/07 9 00:00 06:00 6.00 PR1 DRL DRILL_ ROT_
06/16/07 10 06:00 12:00 6.00 PR1 DRL DRILL_ ROT_
AF 2,020 Build 100bb1 mud volume
AF 2,124 Directionally drill f/ 2020' to 2124' WOB= 5-10k PP= 7-
800psi 390 - 410gpm. Mud slowly thining with circulation.
ART= .2 AST= .7
AF 2,546 Directionally drill f/ 2124' to 2546' WOB= 5-10k ROP 70-
100'/hr PP= 800-900psi 380 >420gpm Up wt= 88k Dwn
wt= 73k Rot wt= 80k
ART= 3.3 AST= .8
AF 2,945 Directionally drill f/ 2546' to 2945' ROT= 70 WOB 5-10k
ROP 100-120'/hr PP 1100-1250psi 450 > 590 gpm Up wt=
95k Dwn wt= 75k Rot wt= 85k
ART= 3.2 AST= .3
AF 3,290 Continue directionally drill ahead f/ 2945' to 3290' Up Wt.
95k Dn. Wt. 85k
Rt. Wt 90 Tq 6-7k Rop 90- 100 fph. Art 2.7hr. Ast 1.1 hr.
Page 6 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date Activity------------------------- Depth---------------------------.,
---------------------------------------------------------------------------- -----..__..
06/16/07 10 12:00 18:00 6.00 PR1 DRL DRILL_ ROT AF 3,764 Directionally drili f/ 3290'- 3764' RPM= 72 WOB 5-10k
ROP= 110-130'/hr 630-650 gpm PP 1450psi Up wt 120k
Dwn wt =90k Rot wt= 104k ART= 3.5 AST= .3
Note: pump Hi- vis sweep at 3350' 1.5x increase in
cuttings. Increase pump rate to 650gpm. dress shakers
with 200 screens
6/16/07 ROT_ AF
10 18:00 20:45 2.75 PR1 DRL DRILL 4,017 Directionally drill f/ 3764' to 4017'. RPM= 72 WOB 5-15k
~ _ ROP= 120-140'/hr 620-640gpm PP= 1550psi Up wt=
124k Dwn wt= 93k Rot wt= 107k
ART= 1.9 AST= 0
06/16/07 MUD AF
10 20:45 21:30 0.75 PR1 DRL CIRC 4,017 CBU check f/ flow. PJSM to TOH
06/16/07 _
10 21:30 00:00 2.50 PR1 DRL TRIP_ WIPR AF 4,017 Wiper trip. Normal expected overpulls 10-25k no
backreaming.
06/16/07 10 00:00 00:30 0.50 PR1 DRL TRIP_ WIPR AF 4,017 Crew change. PJSM. Continue wiper into casing shoe
1947'. 20-35k overpull through shoe.
06/16/07 10 00:30 02:40 2.17 PR1 DRL SERVIC RIG_ AF 4,017 Service rig. Chg oil in #2 carrier motor. Service topdrive.
06/16/07 10 02:40 04:30 1.83 PR1 DRL TRIP_ WIPR AF 4,017 TIH. Wash last stand to bottom. +/- 5' fill. Check SPR's
Survey.
06/16/07 ROT AF
10 04:30 06:00 1.50 PR1 DRL DRILL 4,142 Directionally drill ahead f/ 4017' to 4080'. Pump high vis
_ sweep. Continue drilling. RPM= 70 WOB 5-10k ROP
140-150'/hr 640gpm PP= 1560psi Up wt 130k Dwn wt
~ 95k Rot wt= 110k
ART= 1.0 AST= 0
06/17/07 AF
ROT
11 06:00 12:00 6.00 PR1 DRL DRILL 4,341 Continue directionally drilling ahead f/ 4142' -4341'
_
_ RPM=70 WOB 5-20 Up Wt.130k Dn. Wt. 105k .RT. Wt.
115 Tq 6-7 Ast 2.3hr Art 1.2hr.
Sweep coming over at 4135' 1.5x normal GPM= 650 . PP=
1550psi. Note add 1% lubetex to increase penetration rate
during slides.
06/17/07 11 12:00 18:00 6.00 PR1 DRL DRILL_ ROT_ AF 4,585 Driectionally drill ahead f/ 4341'- 4585'. 550gpm PP= 1400
psi ART=1.3 AST= 2.6
Note : Reduce pump rate to 565gpm 95spm per pump due
to overheating problems. ambient air temp 75-80deg. # 3
- mud pump shut down due to over heating. Cool down and
- run at 95spm. Increase lubetex to 1.5%
_ Page 7 of 33 - Printed 12/13/2007
Operational Details for Weil: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date __ Activity------------------------- Depth_....-
-------------------- -..._
- -----------------.._.._..-----------------------------------•---------
-----------•
06/17/07 ---
--------------------------------
11 18:00 00:00 6.00 PR1 DRL DRILL_ ROT_ AF 4,848 Directionally drill ahead f/ 4585' to 4848. 600gpm PP=
1550psi ART= 1.2 AST= 2.6
06/17/07 11 00:00 06:00 6.00 PR1 DRL DRILL ROT AF 5,090 Directionally drill f/ 4848' to 5090'. 620gpm 1600psi WOB 5-
25 Up wt=150k Dwn wt= 115k Rot wt= 130k Tq on bot 7k
off 3k ART= 1.4 AST= 2.3
Making 1/2% additions of Lube-tex every 5-6hrs
06/18/07 AF 5,220
ROT
12 06:00 12:00 6.00 PR1 DRL DRILL Continue directionally drilling f/ 5090' -5220' Up Wt. 150k
_
_ Dn. Wt. 117k Rt. Wt. 131 k Tq. 8-10k Ast=3.Ohr. Art =.6
~
658
5 hr Increase lubetex to 3% Valve drill= 25 sec
Up wt 165k dwn wt 120k
drill f/ 5220'- 5658'
Directionall
6/18/07 ,
00 PR1 DRL DRILL ROT AF
12 12:00 18:00 6 .
y
. Rot wt 142k Tq= 9k. Make another 1% inc in Lubetex (8
drums). 3x 108 spm= 630 gpm W06= 7-10k 140'/hr
Pumped Hi Vis sweep at 5470' 2X increase in cuttings
returned over shakers
ART= 2.7 AST= .8
06/18/07 AF 5,993
ROT
12 18:00 22:00 4.00 PR1 DRL DRILL Directionally drill f/ 5658' to 5993'. Tq= 9-12k W06= 5-
_
_ 12k ROP= 120-140'/hr 3x 108 spm= 630gpm 1640psi off
btm 1875psi on btm ART= 3.5 AST= 0
06/18/07 12 22:00 22:20 0.33 PR1 DRL REPAIR RIG TA MSPW 5,993 Found 1/2" long crack on hydraulic discharge line coming
from pump f/ mud pump #2. Determine fixable. Estimate 2
gallons of hyd oil leaked out. All fluids contained within
area surrounding leak.
06/18/07 12 22:20 23:10 0.83 PR1 DRL DRILL_ ROT AF 6,035 Continue control drilling ahead f/ 5993 to 6035' 70'/hr with
2 pumps at 118spm /ea.
• Same time throughly clean residual hydraulic oil on floor
W ill
i
rs.
and pipe area. Prep to spot weld crack. Make repa
need to rebuild during rig move.
ART= .3 AST= 0
06/18/07 12 23:10 00:00 0.83 PR1 DRL DRILL ROT AF 6,098 Continue drilling ahead with 3 pumps. f/ 6035' to 6098'.
Up wt=173k Dwn wt=129k Rot wt= 148k Tq 7-9k
ART= ..3 AST= 0
06/18/07 12 00:00 00:15 0.25 PR1 DRL SAFETY DRIL AF 6,098 New crews. PSJM review slow driving in residental areas.
Problem areas to watch on the rig and Plan Forward for
the next 24hrs.
06/18/07 12 00:15 01:30 1.25 PR1 DRL DRILL_ ROT_ A~ 6,185 Continue drilling ahead f/ 6098' to 6185'. WOB 10-15k Tq
9k ART= .4 AST= 0
06/18/07 12 01:30 02:50 1.33 PR1DRL CIRC_ CFLD AF 6,185 CBU
.. Page 8 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date
-------•- Activity---
-------- ---------- ------------ Depth------ -------._...__.._..-----------------------------------------•---------
-----------------------------------
06/18/07 12 02:50 06:00 ---------
3.17 -------------
PR1 DRL --
TRIP_ WIPR AF 6,185 Wiper trip 3940'. 25k over first 4 stds. Good remainder of
TOH.
06119/07 13 06:00 07:00 1.00 PR1DRL TRIP WIPR AF 6,185 RIH wiper trip 3940'.-6185' Hole slick,no bridges. Wash f-
_ 6125'-6185'. tag 8' of fill correct displacement. No gains or
losses
06/19/07 13 07:00 09:00 2.00 PR1 DRL CIRC CFLD AF 6,185 Circ pump hi vis sweep. circ untill shakers clean up.
' mointor well. Pull 5 stands pump dry job. Max gas on B/U
20u
~~G/19/07 13 09:00 14:45 5.75 PR1 DRL TRIP_ DP_ AF 6,185 POH SLM (no correction) for logging suite. f/ 5880' to BHA
LJ
06/19/07 13 14:45 17:45 3.00 PR1 DRL TRIP
~ BHA_ AF 6,185 POH Stand back HWDP lay down monels,stablizer and
pony collar. B/O bit. UD mwd and motor.
06/19/07 13 17:45 18:15 0.50 PR1 DRL CLEAN RIG AF 6,185 Clean-up rig floor.
06/19/07 13 18:15 18:30 025 PR1 EVL _
SAFETY MTG_ AF 6,185 Hold PJSM with Weatherford and righands . Review RU
procedures and hazards.
06/19/07 13 18:30 20:00 1.50 PR1 EVL LOG OH_ AF 6,185 RU Weatherford logging truck and tools.
06/19/07 13 20:00 02:00 6.00 PR1 EVL _
LOG OH_ AF 6,185 RIH with Quad-Combo logging tools. Tag bottom at 6172'.
~ Log f/ TD to surface csg shoe. Repeat to 5450'. Hole
taking 4 bbls mud per hour.
06/19/07 13 02:00 02:10 0.17 PR1 EVL SAFETY DRIL AF 6,185 PJSM review log tool LD procedures.
06/19/07 13 02:10 03:00 0.83 PR1EVL LOG_ OH_ AF 6,185 LD Quado-Combo tools. Prep log and e-mail to Houston.
06/19/07 13 03:00 06:00 3.00 PR1 EVL LOG OH AF 6,185 Prep RFT tools and wait on orders on pick points RFT
06/20/07 14 06:00 06:30 0.50 PR1 EVL LOG_ OH_ AF 6,185 Wait on MOC Geo for RFT pick points. Fluid loss 1.8bbls
per hr.
~6/20/07 14 06:30 16:30 10.00 PR1 EVL LOG OH_ AF 6,185 Rlh on Wire line with RFT logging tools. Pressure test at
, 5733', 5737', 5741', 5745', 5749', 5753, 5757', 5770',
5774', 5778', 5782', 5786', 5790', 5794', 6116', 6120', And
6124' POH w Wire line RFT tools and Rig Down.
Fluid Loss to hole 2 bbl per hr. Move rig to completion
phase at 1630hrs 6-19-07
Page 9 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date------- -•--------------------------------------------------------Activi~X.._ .._..----------------. Depth-------.._..------------------------------------------------------•---------
Rig Comp letion - Case:
- --------------
--- -
-------•--------------------.._.._.__..
--------------•---•------------------------------------------- . ~
185 M/U 12 1/4 Clean out assy. RIH break circulation at 2650
AF 6
06/20/07 1 16:30 21:15 4.75 PR1CSG TRIP_ DP_ ,
and 5100'
06/20/07 1 21:15 21:35 0.33 PR1 CSG WASH_ FILL AF 6,185 Wash last stand to bottom +/- 5' of fill
Spot 30bb1 LCM pill on bottom
as 37units
185 CBU 2X Max
06/20/07 1 21:35 23:30 1.92 PR1CSG CIRC_ MUD_ .
g
AF 6,
6/20/07
~ 1 23:30 05:00 5.50 PR1 CSG TRIP_ DP
- AF 6,185 Monitor well. Pull 5 stands. Tight first 3 stands off bottom.
Pump dry job TIH no over pulls. L/D bit and bit sub
06/20/07 1 05:00 06:00 1.00 PR1CSG RUNPUL WBSH AF 6,150 PJSM; Pull wear bushing Prep to change out pipe rams to
9 5/8
06/21/07 2 06:00 14:30 8.50 PR1 CSG RURD_ CSG_ AF 6,185 PJSM; C/O 5" pipe rams to 9 5/8 Csq. rams and Test to
2000 psi. Move torque tube back. Make dummy run with 9
5/8 hanger. C/O red tugger Iine.Remove short bails and
install long bails and fill up tool. P/U 9 5/8 Csg elevators
and spider. R/U Csg. tongs. Note Repair Fill up
tool,Leaking mud. ( weatherfords tool)
06/21/07 2 14:30 14:50 0.33 PR1CSG SAFETY MTG_ AF 6,185 PJSM; Hold safety meeting discuss hazards and review
procedure for running Csg.
06/21/07 2 14:50 16:00 1.17 PRICSG RUN_ CSG_ AF 6,185 Make up 9 5/8 40# BTC CSG. shoe track and baker lok,
Ck Floats RIH
06/21/07 2 16:00 02:30 10.50 PR1CSG RUN_ CSG_ AF 6,185 OOO~C3ct Cont RIH To 6150' MakeSup la d ng J Sand 9 5/8
~ hanger. Wash & work hanger through BOP stack. Tag 5' of
fill Land csg at 0250hrs. Csg. shoe at 6174'. Float collar at
6090'. Fluid loss to hole 2bbls per hr.
06/21/07 2 02:30 03:30 1.00 PR1CSG CIRC_ MUD AF 6,185 Circ Csg at 5bbls min 350psi
06/21 /07 2 03:30 04:00 0.50 PR1 CSG RURD_ CMT AF 6,185 Installl cement head and lines
Mix and pump 40bbls MCS-
ment lines to 3000psi
T
t
06/21/07 2 04:00 06:00 2.00 PR1CSG PUMPi CMT_ .
ce
es
AF 6,185
40 Sweep. Drop 1 plug,pump 210 sx 78.58 bbls 12.5ppg
class G Lead cement with a yield of 2.101. Followed by
400 sx 82.63 bbls 15.8 ppg Class G tail cement with a
yieldof 1.16. Drop #2 plug. pump 5 bbls H2o. Switch to rig
pumps, begin displacement.
Page 10 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date ._..._ Activity------------------------- Depth-------------- ------------------------------------------------
-------------------•----------•----------------------------.._ . ---------... .
06/22/07 3 06:00 06:30 0.50 PR1 CSG PUMP CMT AF 6,185 Cont displacing 9 5/8 Csg. with rig pump. Bump plug W/
780psi increase to 1450psi. Hold pressure for 5min. Bleed
pressure off floats held. Cement in place at 0630hrs 6-21-
07. Lost 30bbls during Displacement before cement left
shoe, 100% returns after cement turned corner.
06/22/07 3 06:30 12:00 5.50 PR1 CSG RURD CSG AF 6,185 Pull landing joint, set pack off and test to 5000 psi/10min.
_ _ Clean pits. R/D csg tools C/O bails. Re set Torque tube.
Clean pits.
~6/22/07 3 12:00 13:00 1.00 PR1 CSG SAFETY MTG 0 6,185 One hour weekly safety meeting with both rig crews.
06/22/07 3 13:00 18:00 5.00 PR1CSG CLEAN_ _
TANK AF 6,185 Flush out and clean pits and all suction and discharge
lines.
06/22/07 3 18:00 20:30 2.50 PR1CSG TEST BOPE AF 6,185 Change out and test varible rams 250 psi low and 2000 psi
high, install wear bushing.
06/22/07 3 20:30 22:00 1.50 PR1CSG PULD BHA_ AF 6,185 PJSM; Measure and caliper BHA. and pick up BHA. Place
scraper at 3000'
06/22/07 3 22:00 01:00 3.00 PRICSG TRIP_ BHA_ AF 6,185 PJSM; RIH with Scraper assy. and drill pipe to 6088'
Up wt.=170K Dn. Wt.=155K
06/22/07 3 01:00 02:30 1.50 PR1CSG CIRC CFLD AF 6,185 Pump Sweep and displace Flo pro mud with fresh water.
Sweep returned with cement sand pipe dope
06/22/07 3 02:30 06:00 3.50 PR1CSG TRIP_ DP AF 6,185 PJSM; POOH with scrapers to 3000'
06/23/07 4 06:00 06:35 0.58 PR1 CSG SERVIC RIG_ AF 6,185 Srevice rig. inspect torque tube
06/23/07 4 06:35 08:00 1.42 PR1CSG TRIP DP AF 6,185 RIH F- 3000' Scraper run #2 to 6090'
06/23/07 4 08:00 10:30 2.50 PR1CSG _
CUT_ WIRE AF 6,185 Slip and cut drilling line. Had to make two cuts ( bad line)
~6/23/07 4 10:30 11:30 1.00 PR1CSG CIRC CFLD AF 6,185 Circ Pump 50bb1 Hi Vis sweep Displace wellbore with H2O.
_ at 6090' Sweep returned with cement sand and drill pipe
dope
06/23/07 4 11:30 12:15 0.75 PR1CSG TEST_ CSG_ AF 6,185 Test 9 5/8 Csg. to 1500psi/30min. final psi 1500. test good
06/23/07 4 12:15 19:30 7.25 PR1 CSG TRIP DP AF 6,185 PJSM; Poh lay down drillpipe F-6090'
06/23/07 4 19:30 20:00 0.50 PR1CSG RUNPUL WBSH AF 6,185 PJSM;PuII Wear Bushing
06/23/07 4 20:00 22:30 2.50 PR1CSG RURD RIG AF 6,185 PJSM; Clean Pits,Rig down move pump #3,Rig down
move M-I solids van,and cuttings tank,stack 5" driil pipe
and HWDP on trailers,rig down floor.
06/23/07 4 22:30 03:30 5.00 PR1CSG NUND BOPE AF 6,185 PJSM; Nipple down BOP,
06/23/07 4 03:30 04:30 1.00 PRICSG NUND WLHD AF 6,185 Nipple up Ported Flange for Wellhead with Vetco grey
06/23/07 4 04:30 06:00 1.50 RDMO RURD_ R1G_ AF 6,185 Prep for move to SU41-15 Clean cellar and pick-up tools.
. Page 11 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date---------------------•--------------------------------...--------Activity-------..,__...__..._..._ Depth..--------------------------------------.._..----------------•--------------
06/24/07 5 06:00 06:00 24.00 RDMO RURD RIG AF 6,185 Cont. Rig down GD-1 prep for move to 41-15. Rig down
top drive, and torque tube. Remove berm. Move EPOC
unit out. move weldingshop. Lay felt and liner on 41-15 well
pad. Set BPV 41-15. Shut in and Bleed off flow line & set
BPV on 32- 9. R/D choke lines, remove beaverslide. Prep
rig floor for scope down of mast. Set
matting boards.Lay backderrick split pits,set down diesel
tank. Crane off choke house, doghouse.Move Carrier off
~ mud boat.
06/25/07 6 06:00 09:00 3.00 RDMO RURD_ RIG_
i
AF 6,185 Set Final matting boards. Move sub off well center Release
rig to SU41-15 At 0900hrs 6-24-07 Repair jack stand on
carrier (broke off backing carrier from mud boat.) Liner cut
too short reweld .
Page 12 of 33 - Printed 12/13/2007
Operational Detaiis for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date
------------
-------
-----------------
--------
--------------
------------ ActivitY---
----•-- ---------------------- Depth---- -------------------------.._..------------------------------------------
Post-Rig Completion Event:
--
------------
-
------------
-----------
--------------------- -
------------
07/25/07 -------
1 -----------------
08•00 09•15 ------
1 25 -
PRDTST SAFETY MTG_ AF Arrive Sterling Pad. Sign in at rig. Hold PJSM and obtain
Safe W ork Perm it.
07/25/07 1 09:15 10:05 0.83 PRDTST RURD ELEC AF MIRU equipment. PU Pump-in sub, and Grease head.
PU CBL/ GR. RIH
07/25/07 1 10:05 10:30 0.42 PRDTST LOG_ CSG_ AF Run free pipe pass @ 1000'-800'.
07/25/07 1 10:30 11:40 1.17 PRDTST TAG_ BOTM AF RIH tag TD @ 6070' KB.
~?7/25/07 1 11:40 11:50 0.17 PRDTST LOG_ CSG_ AF Run repeat sections.
07/25/07 1 11:50 13:30 1.67 PRDTST LOG CSG AF Run main pass (radials)
~-~ ~~`~` ,c'~
RIH
07/25/07 1 13:30 14:03 0.55 PRDTST RUNPUL ELEC AF
F
.
Run 2nd part of main pass(VDL). POOH.
07/25/07 1 14:03 15:40 1.62 PRDTST LOG CSG A
07/25/07 1 15:40 16:10 0.50 PRDTST RUNPUL ELEC AF OOH.
07/25/07 1 16:10 16:20 0.17 PRDTST SAFETY MTG AF Hold rig down Safety Meeting.
07/25/07 1 16:20 17:00 0.67 PRDTST RURD ELEC AF RD. Sign out and leave location.
Sign in at rig. Hold PJSM and obtain
Arrive Sterling Pad
08/04/07 2 11:00 11:30 0.50 PRDTST SAFETY MTG CS .
Safe Work Permit.
08/04/07 2 11:30 14:45 3.25 PRDTST RUNPUL COIL CS Moved equipment from Beaver Creek #9 to this location in
three trips. Spotted in coil unit and N2 unit. Parked crane
off the side of location.
08/04/07 2 14:45 15:00 0.25 PRDTST SECURE WELL CS Signed out at Sterling Facility office. left location.
08/05/07 3 08:00 08:45 0.75 PRDTST SAFETY MTG_ CS Arrive Sterling Pad. Sign in at rig. Hold PJSM and obtain
Safe Work Permit.
08/05/07 3 08:45 13:45 5.00 PRDTST RURD_ COIL CS Rig up coil unit and Nitrogen combo pump truck.
~ Roustabouts rigged up flowback manifold to flowback tank.
08/05/07 3 14:4518:00 3.25 PRDTST TEST_ BOPE
CS Function Test BOP's. BOP Pipe Rams and Blind Rams
Function tested ok. Test Accumulator. Pressure Test BOP
Blind Rams to 250 psi/4500 psi. Accumulator and Both
Low and High Pressure BOPE, Blind, Pipe Ram, Choke,
and Kill Lines. Test Held Pressure. Jim Regg with AAOGC
waived inspector for this test.
08/05/07 3 18:00 18:15 0.25 PRDTST SECURE WELL
08/08/07 4 07:00 08:00 1.00 PRDTST SAFETY MTG_
08/08/07 4 08:00 09:00 1.00 PRDTST RURD_ COIL
CS Rig back coil injector. Signed out at the Sterling Pad
office. Locked the gates on the way out.
CS Arrive Sterling Pad. Sign in at rig. Hold PJSM and obtain
Safe Work Permit.
CS PU ejector and stab on W H.
Page 21 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operatlons
Date Activity------------------------- Depth------._..._...-----..__._...------------------------------------.._..------
-------------•--------------------------------------------------._...__... ..
08/08/07 4 09:00 10:00 1.00 PRDTST RURD COIL TS MSCT Operator let coil spool roll forward in craddle and a loose
wrap became wedge into bracket in cornor of frame.
08/08/07 4 10:0011:00 1.00 PRDTST REPAIR EQIP
08/08/07 4 11:00 12:00 1.00 PRDTST RURD_ COIL
08/08/07 4 12:0012:10 0.17 PRDTST TEST_ EQIP
08/08/07 4 12:10 12:45 0.58 PRDTST RUNPUL COIL
I~08/08/07 4 12:4513:02 0.28 PRDTST JET_ N2_
08/08/07 4 13:0214:00 0.97 PRDTST JET_ N2_
08/08/07 4 14:0014:12 0.20 PRDTST JET_ N2_
08/08/07 4 14:1214:26 0.23 PRDTST JET_ N2_
08/08/07 4 14:2614:45 0.32 PRDTST JET_ N2_
08/08/07 4 14:4515:25 0.67 PRDTST JET_ N2_
08/08/07 4 15:2515:55 0.50 PRDTST JET_ N2_
08/08/07 4 15:5516:10 0.25 PRDTST JET_ N2_
08/08/07 4 16:1016:25 0.25 PRDTST JET_ N2_
•
08/08/07 4 16:2518:39 2.23 PRDTST JET_ N2_
08/08/07 4 18:3918:51 0.20 PRDTST JET_ N2
08/08/07 4 18:51 18:53 0.03 PRDTST JET_ N2_
08/08/07 4 18:53 19:45 0.87 PRDTST RUNPUL COIL
08/08/07 4 19:45 20:13 0.47 PRDTST JET_ N2_
08/08/07 4 20:13 20:52 0.65 PRDTST JET_ N2_
08/08/07 4 20:52 21:30 0.63 PRDTST JET_ N2_
TS MSCT Cut 146' of coil off spool.
TA MSCT Install new dimple on conection. Pull test to 18k. Test
good. Install BHA.Set ejector up on well head.
CS Shell test to 1000 psi. Test good.
CS Open upper master. Open swab. RIH with Blanked off
nozzle w/ 3- 3/8" jets.
CS @1470' Start N2 @ 700 scfm 1370 psi WH. 25.7 barrels
in flow back tank.
CS Tubing @ 1470' Pumping N2 @ 700 good returns to
flowback tank. Recovered 46 bbls.
CS Tubing @ 1492' Pumping N2 750 scf WHP 1465 psi.
recovered 89 bbls.
CS RIH to 2000'. N2 @ 750 WHP 1535 psi
CS RIH 2616'. Pumping N2 @750 scf. WHP 1600.
Recovered 137 bbls
CS @ 2616'. Pumping N2 @750 scf. WHP 1593. Recovered
162 bbls.
CS RIH to 4500', WHP 1696 psi, Recovered 214 bbls
CS Tubing parked 4500', WHP 1718 psi, pumping N2 2 750
scf, 234 bbls reccovered
CS 4500', N2 750 scf, WHP 1740 psi, 249 bbls recovered.
CS @ 4500' N2 762 scf, WHP 1743 psi, 266 bbls water
recovered.
CS Parked @ 4500', N2 @ 762 scf, WHP 1840 psi, recovered
329 bbls.
CS Parked @ 4500', N2 @ 762 scf, WHP 1840 psi, recovered
348 bbls.
CS RIH.
CS @ 6000', Pumping N2 @ 1000 scf, WHP 1935 psi, 376
bbls, recovered.
CS Tubing parked @ 6000' Pumping N2@ 1000 scf, WHP
2139 psi, 400 bbls recovered.
CS @ 6000', Pumping N2 @ 1000 scf, WHP 2245 psi.
recovered 428 bbls.
Page 22 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date
----
----
•--------
--------------
-----------. Activity_
.._..._ . --- Depth----
..---..__...-------- ------------------------------------------------------------------------
------------
08/08/07 -------
4 -----•
-•
21:30 21:55 0.42 PRDTST JET_ N2_ CS 6000', N2 @ 1000 scf, WHP 2336 psi. recovered 457 bbls.
08/08/07 4 21:55 22:05 0.17 PRDTST JET, N2_ CS Parked 6000', N2 @ 1000 scf, WHP 2358 psi, 477 bbls
recovered.
08/08/07 4 22:05 22:50 0.75 PRDTST RUNPUL COIL CS Gas break out to buster, Shut down N2, POOH. 480 bbis
recovered.
08/08/07 4 22:50 23:27 0.62 PRDTST RUNPUL COIL CS Tubing at surface. WHP 1710 psi. Bleeding WHP to 1100
psi.
~08/08/07 4 23:27 23:40 0.22 PRDTST RURD_ COIL CS Shut in well 1160 psi. Begin RD.
08/08/07 4 23:40 23:55 0.25 PRDTST RURD COIL CS Set ejector in craddle. Secure well head.
08/08/07 4 23:55 00:00 0.08 PRDTST SECURE WELL CS Leave location. ciose gate.
08/09/07 5 08:30 09:30 1.00 CMPPRF SAFETY MTG_ CS Arrive Sterling Pad. Sign in at rig. Hold PJSM and obtain
Safe Work Permit.
08/09/07 5 09:30 10:45 125 CMPPRF RURD_ ELEC CS Install WH crossover adapters. PU lubricator and
CCL/Gamma tool string.
08/09/07 5 10:45 11:34 0.82 CMPPRF TEST BOPE CS PTest lubricator to 3000 psi. Test good.
08/09/07 5 11:34 12:35 1.02 CMPPRF RUNPUL ELEC CS Open well.(1150 psi.) RIH.
08/09/07 5 12:35 14:07 1.53 CMPPRF LOG_ CSG CS Tag TD @ 6070'. Start log. POOH
08/09/07 5 14:07 14:47 0.67 CMPFLW SAFETY MTG_ CS OOH. Hold explossives safety meeting. Inform all
personnel on location. Shut down cells.
08/09/07 5 14:47 16:00 1.22 CMPPRF PERF_ CSG_ CS PU 3-3/8" x 1" HSC EXP (990 psi on well)
08/09/07 5 16:00 16:10 0.17 CMPPRF PERF_ CSG_ CS Pull into position to shoot 5750'-5751'.( 20 psi increase on
well after shooting)
08/09/07 5 16:10 16:20 0.17 CMPPRF RUNPUL ELEC CS POOH.
~08/09/07 5 16:20 16:25 0.08 CMPPRF RUNPUL ELEC CS WHP 1055 psi.
08/09/07 5 16:25 16:40 0.25 CMPPRF RUNPUL ELEC CS Pressure increasing to 1075 psi. @ 16:20
08/09/07 5 16:40 16:42 0.03 CMPPRF RUNPUL ELEC CS Pressure increased to 1100
08/09/07 5 16:42 17:00 0.30 CMPPRF RURD ELEC 0 Expro OOH. RD.
08/09/07 5 17:00 17:15 0.25 PRDTST FLOW TEST CS Pressure continues to bulid to 1160 psi.
08/09/07 5 17:15 17:25 0.17 PRDTST FLOW TEST CS Open well on 12/64 choke. 1140 psi W H, 1100 choke
08/09/07 5 17:25 17:37 0.20 PRDTST FLOW TEST CS Well flowing on 12/64 choke 960 psi WH, 960 choke.
08/09/07 5 17:37 17:40 0.05 PRDTST FLOW_ TEST CS Well flowing on 12/64 choke 780 psi WH, 770 choke.
Pinch back to 8/64
08/09/07 5 17:40 17:47 0.12 PRDTST FLOW_ TEST CS Well flowing on 12/64 choke 740 psi WH, 745 choke.
^ Pinch back to 8/64
- Page 23 of 33 - Printed 12/13/2007
Operational Details for Well: STERLlNG UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date
-
-----
-
-------------•- --------- ------------- ----------- -- Activity---
----- --.....---..__...------Depth----
-------------•---------
-------------------------...__...----------------
-----------
08/09/07 --
5 17:47 18:00 0.22 PRDTST FLOW_ TEST CS Well flowing N2 on 6/64 choke 670 psi WH, 670 choke.
Pinch back to 4/64
08/09/07 5 18:00 18:07 0.12 PRDTST FLOW_ TEST CS Well flowing N2 on 4/64 choke 560 psi WH, 560 choke.
Pinch back to 4/64
08/09/07 5 18:07 18:25 0.30 PRDTST FLOW
- TEST CS Well flowing N2 on 4/64 choke 510 psi WH, 510 choke.
Pinch back to 4/64
08/09/07 5 18:25 18:30 0.08 PRDTST FLOW TEST CS Well flowing N2. choke open 10% ( 1" choke-10 turns to
full open, open 1 turn) 460 psi WH, 475 psi.
08/09/07 5 18:30 18:45 0.25 PRDTST FLOW_ TEST CS Well flowing N2. choke open 10% ( 1" choke-10 turns to
~ full open, open 1 turn) 450 psi WH, 460 psi.
08/09/07 5 18:45 19:00 0.25 PRDTST FLOW TEST CS Well flowing N2. choke open 10% ( 1" choke-10 turns to
full open, open 1 turn) 445 psi W H, 460 psi.
OS/09/07 5 19:00 19:35 0.58 PRDTST FLOW_ TEST CS Gas to surface on LEL meter. choke open 10% ( 1" choke-
10 turns to fufi open, open urn) 445 psi WH, 460 psi.
08/09/07 5 19:35 20:00 0.42 PRDTST FLOW_ TEST
08/09/07 5 20:00 20:30 0.50 PRDTST FLOW_ TEST
08/09/07 5 20:30 21:00 0.50 PRDTST FLOW_ TEST
CS Water to surface. Estimated @ 1/2 bpm choke open 20%
( 1" choke-10 turns to full open, open 2 turn) 600 psi WH,
620 psi.
CS Switch out with night operator, WH 800 psi, choke 700 psi
well making gas and water.
CS WH 840 psi, choke 760 psi well making gas and water.
08/09/07 5 21:00 21:30 0.50 PRDTST FLOW` TEST
~08/09/07 5 21:30 22:00 0.50 PRDTST FLOWi TEST
08/09/07 5 22:00 22:30 0.50 PRDTST FLOW_ TEST
08/09/07 5 22:30 23:00 0.50 PRDTST FLOW` TEST
08/09/07 5 23:00 23:30 0.50 PRDTST FLOW_ TEST
08/09/07 5 23:30 00:00 0.50 PRDTST FLOW_ TEST
CS WH 880 psi, choke 880 psi well making gas and water.
Well ~roduce 32.6 bbls in the one hour period from 20:00
to 21:00.
CS W~ H 920 psi, choke 920 psi well making gas and water.
CS WH 900 psi, choke 900 psi well making gas and water.
Well produce 18.9 bbls in the one hour period from 21:00
to 22:00.
CS WH 920 psi, choke 900 psi well making gas and wafer.
CS WH 850 psi, choke 820 psi well making gas and water.
Well produce 18.1 bbls in the one hour period from 22:00
to 23:00.
CS WH 880 psi, choke 880 psi well making gas and water.
Page 24 of 33 - Printed 12l13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date ------- --------------- --------- ---------•--- ----...__.. .. Activity--- -------------....------Depth._.. .-------....---•----- ---------------------------------------------------
-------
08/09/07 -
5 00:00 00:30 0.50 PRDTST FLOW TEST CS WH 1020 psi, choke 1020 psi well making gas and
water. Well produce 23.1 bbls in the one hour period from
23:00 to 24:00. Total water produced 93 bbls.
08/09/07 5 00:30 01:00 0.50 PRDTST FLOW_ TEST CS WH 1180 psi, choke 1200 psi well making gas and
water.
08/09/07 5 01:00 01:30 0.50 PRDTST FLOW_ TEST CS WH 1160 psi, choke 1200 psi Choke froze well making
qas, NO water
08/09/07 5 01:30 02:00 0.50 PRDTST FLOW_ TEST CS WH 1160 psi, Choke froze well making gas, NO water
r
08/09/07
5
02:00 02:30
0.50
PRDTST
FLOW_
TEST
CS
WH 1100 psi,
choke 1120 psi well making gas, NO
water
08/09/07 5 02:30 03:00 0.50 PRDTST FLOW_ TEST CS WH 1100 psi, choke 1100 psi well making gas, NO
water
08/09/07 5 03:00 03:30 0.50 PRDTST FLOW_ TEST CS WH 990 psi, choke 1000 psi well making gas, NO water
08/09/07 5 03:30 04:00 0.50 PRDTST FLOW_ TEST CS WH 970 psi, choke 990 psi well making gas, NO water
08/09/07 5 04:00 04:30 0.50 PRDTST FLOW_ TEST CS
08/09/07 5 04:30 05:00 0.50 PRDTST FLOW_ TEST CS
08/09/07 5 05:00 05:30 0.50 PRDTST FLOW_ TEST CS
08/09/07 5 05:30 06:00 0.50 PRDTST FLOW_ TEST CS
~ DTST FLOW TEST CS
8/10/07 6 06:00 06:30 0.50 PR _
08/10/07 6 06:30 07:00 0.50 PRDTST FLOW_ TEST CS
08/10/07 6 07:00 07:30 0.50 PRDTST FLOW_ TEST CS
08/10/07 6 07:30 08:00 0.50 PRDTST FLOW_ TEST CS
08/10/07 6 08:00 08:30 0.50 PRDTST FLOW_ TEST CS
W H 900 psi, choke 900 psi well making gas, NO water
WH 950 psi, choke 950 psi well making gas, NO water
WH 950 psi, choke 950 psi well making gas, NO water
WH 980 psi, choke 1000 psi well making gas, NO water
WH 900 psi, choke 900 psi well making gas, NO water
W H 830 psi, choke 850 psi well making gas, NO water
WH 815 psi, choke 820 psi well making gas, NO water.
Started making water @ 7:15
WH 880 psi, choke 900 psi well making qas, and some _
water. estimated at 1/2 bbl. Waterstopped at 07:30
WH 840 psi, choke 860 psi well making gas, NO water
Page 25 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date-----------------------------------------------------------------ActivitY...---------------------- Depth--------..__...----------------------------.._...---------------------------
08/10/07 6 08:30 09:00 0.50 PRD7ST FLOW_ TEST CS . WH 780 psi, choke 810 psi well making gas, NO water
08/10/07 6 09:00 09:30 0.50 PRDTST FLOW_ TEST
08/10/07 6 09:30 10:00 0.50 PRDTST SAFETY MTG_
CS WH 725 psi, choke 745 psi well making gas, NO water
CS Expro Arrive Sterling Pad. Sign in at rig. Hold PJSM and
obtain Safe Work Permit.
' 08/10/07 6'10:00 10:46 0.77 PRDTST RUNPUL ELEC
~ 08/10/07 6 10:46 11:00 0.23 PRDTST LOG_ CSG_
08/10/07 6 11:00 11:15 0.25 PRDTST FLOW_ TEST
08/10/07 6 11:15 12:00 0.75 PRDTST RUNPUL ELEC
08/10/07 6 12:00 12:25 0.42 PRDTST FLOW_ TEST
08/10/07 6 12:25 12:57 0.53 PRDTST FLOW^ TEST
08/10/07 6 12:57 13:16 0.32 PRDTST RUNPUL ELEC
CS RU. W H 760 psi, and choke 760 psi, 10/64" choke,
slu~~,ina wate~.
CS PU PLT string. PTest lubricator to 2000 psi. Test good.
0
CS
CS
CS
CS
08/10/07 6 13:1613:22 0.10 PRDTST LOG_ CSG_ CS
08/10/07 6 13:22 13:28 0.10 PRDTST FLOW_ TEST CS
08/10/07 6 13:28 13:36 0.13 PRDTST FLOW_ TEST CS
08/10/07 6 13:36 13:42 0.10 PRDTST FLOW_ TEST CS
~
08/10/07 6 13:4213:58 0.27 PRDTST FLOW TEST CS
08/10/07 6 13:5814:04 0.10 PRDTST FLOW
~ TEST CS
08/10/07 6 14:04 14:37 0.55 PRDTST FLOW TEST CS
08/10/07 6 14:37 14:43 0.10 PRDTST FLOW_ TEST CS
08/10/07 6 14:43 15:14 0.52 PRDTST FLOW_ TEST CS
08/10/07 6 15:14 15:20 0.10 PRDTST RUNPUL ELEC CS
08/10/07 6 15:20 15:25 0.08 PRDTST RUNPUL ELEC CS
08/10/07 6 15:25 16:30 1.08 PRDTST RURD_ ELEC CS
08C10/07 6 16:30 17:00 0.50 PRDTST RURD_ ELEC CS
WH 770 psi, choke 760 psi., 10/64" choke Small amount
of water.
Open well. Surface pressure 834 psi., 64.5 deg
WH 750 psi, choke 750 psi., 10/64" choke water
slugging. Recovered 26 bbls water.
WH 760 psi, choke 760 psi., 10/64" choke water
slugging. Recovered additional 5 bbls water by 12:25.
Unloading tank to vac truck..
Tag TD @ 5972. 1794 psi and 105 deg. Start simulation
pass @5740 1694 psi and 100 deg.
5740' psi end simulation pass 1694 psi and 100 deg.
5500' Sta~t 5 min bench 1683 psi, and 99 deg.
5500' End 5 min bench 1694 psi and 98 deg.
5000' Start 5 min bench 1631 psi, and 96 deg.
5000' End 5 min bench 1610 psi, 96 deg.
4000' Start 5 min bench 1490 psi. and 89 deg.
4000' End 5 min bench 1494 psi and 89 deg.
2000' Start 5 min bench 1123 psi and 70 deg. 14:15
W HP 850 psi, choke 860 psi on 10/64 choke. Recovered
i 34 bbls. of water from 12:50 to 14:15 65 bbls total
recovery since 11:00 am.
2000' End 5 min bench 1118 psi and 70 deg.
50' Start 5 min bench 888 psi and 54 deg.
50' End 5 min bench 886 psi and 54 deg,
OOH. Close swab. Close master. Shut in well with 840
psi.
WHP 1190 psi @ 16:30. Turn in Permits.
Page 26 of 33 - Printed 12/13/2007
Operational Detaiis for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date
-------
---
---------
-------------
------------ Activity-
-------- - -----------Depth----
------------- -----------------------------------------------------•--------------•---
------------
08/11/07 --------
7 --
---
07:00 08:00 1.00 PRDTST SAFETY MTG_ AF Held PJSM, discussed safety issues and procedure with
personnel.
08/11/07 7 08:00 10:30 2.50 PRDTST TEST BOPE AF RU on well. PU injector and go to well. PT shell and flow
_ back iron low @ 200 psig/ high at 4300 psig. Good test.
Bled down to 1300 prior to open up well.
08/11/07 7 10:30 11:00 0.50 PRDTST PUMP_ WTR_ AF Open well, RIH with coil pumping at 1.4 BPM, 3500 psig.
08/11/07 7 11:00 11:45 0.75 PRDTST WORK_ COIL
:~
08/11/07 7 11:45 15:30 3.75 PRDTST PUMP_ WTR_
08/11/07 7 15:30 15:45 0.25 PRDTST PUMP_ WTR_
08/11/07 7 15:45 17:20 1.58 PRDTST PUMP_ WTR_
08/11/07 7 17:20 18:10 0.83 PRDTST PUMP_ WTR_
08/11/07 7 18:10 18:45 0.58 PRDTST RUNPUL COIL
~8/11 /07 7 18:45 19:30 0.75 PRDTST RUNPUL COIL
08/11/07 7 19:30 20:00 0.50 PRDTST RURD_ COI~
08/12/07 8 07:00 08:00 1.00 PRDTST SAFETY MTG_
08/12/07 8 08:00 10:00 2.00 PRDTST RURD_ COIL
08/12/07 8 10:0010:30 0.50 PRDTST WORK COIL
TA MSCT Coil @ 3406' CTM. Problem with electrical counter, stop to
fix. WHP= 787 psig, continue to open choke to displace
fluid in well bore.
AF Coil @ 5950', PIP = 4400 psig, PIR= 2.10 BPM. WHP= 0
psig.
AF No returns during pumping. Cut PIR to 1.0 BPM, PIP =
4395 psig. Total fluid pumped down well= 474 bbls. Shut
down pumping. Empty Hole volume calculated at 439 bbls.
Pumped 39 bbls over hole volume.
AF Have vac truck mix more KCL, Supply tank down to 9"
loosing suction to pumps. Discussed operation with
Anchorage about hole taking fluid.
AF Problem with water well, slower than anticiapated. Called
another vac truck from town to mix KCL. Decided to lay
down coil for night.
AF POOH with coil, vac truck continue to mix 500 BBLS of
KCL before leaving lease.
AF OOH with coil, Rig back coil for night, secured well, shut
down all equipment. WHP= 0 psig.
AF BJ crew left lease.
AF Held PJSM, discussed safety issues and procedure with
personnel.
AF Start to RU on well. Found Hydrolick hoses on Coil Tubing
Real Broken because bearings frozen up and connections
and hoses wrapped up when Goil tubing Reel turned.
Shutdown for Repairs.
AF Secured well, shut down all equipment. WHP= 0 psig.
~
a
Page 27 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Nours Phase Activity Sub Status T Type To Operations
Date----------------------•----------------------------...---...-----Activity----------•-------------- Depth------------------------------...-------------------------------------------
08/12/07 8 10:30 11:00 0.50 PRDTST RURD COIL AF BJ crew left lease. Called Jeff Jones and Jim Regg with
AOGCC @ 6:30 pm Sunday, August 12, 2007 to give
notice for 7 day Retest on BOPE tommorrow Monday,
August 13, 2007 @ 10:00 am. Jeff Jones Called back @
8:00 pm and Waived AOGCC Witnessing Test if no one
called or showed up by 10:00 am on Monday, August 13th.
08/13/07 9 07:00 08:00 1.00 PRDTST SAFETY MTG_
~ ~
AF Arrive Sterling Pad. Sign in at rig. Hold PJSM and obtain
Safe Work Permit. Talked by phone to Jim Regg and He
concurred with Jeff Jones. Jim Regg and Jeff Jones with
AAOGC waived inspector for this test. Jim Regg told me I
could start the BOPE test before 10: am if I was Ready.
08/13/07 9 08:0010:00 2.00 PRDTST TEST BOPE
AF Function Test BOP's. BOP Pipe Rams and Blind Rams
Function tested ok. Test Accumulator. Pressure Test BOP
Blind Rams to 250 psi/3500 psi. Accumulator and Bot
Low and High Pressure BOPE, Blind, Pipe Ram, Choke,
and Kill Lines. Test Held Pressure.
08/13/07 9 10:00 11:00 1.00 PRDTST PUMP_ WTR_ AF
08/13/07 9 11:00 12:30 1.50 PRDTST RUNPUL COIL
~
08/13/07 9 12:30 15:00 2.50 PRDTST SPOT_ SAND
RU injector on wellhead. Load Coil Tubing with 6% KCL
Water. Shell Test Connections to 1000 psi. Held Pressure.
AF Start in hole wtih Coil Tubing with 2" Full open nozzel. RIH
@ 900'/min Pumping 1/2 BPM to keep coil tubing filled.
Continue to taq sand (a~ 6051' coil Tubing depth. PUH 10'
w/ Coil Tubing and Continue to Pump 1/2 BPM through
Coil Tubing.
AF Start Prepairing Water PH of Water for Gel. Gel up Water
and Add Sand to mix up Gel Sand Plug Slurry. Mix 24 bbl
Gel Sand Plug Slurry. Bottom of Coil Tubing to 6038'.
Page 28 of 33 - Printed 12/13/2007
Operational Detaiis for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date----------------------------------------------------------------- Activity--------------....__....__Depth------------------------...__...--------------------------------------
08/13/07 9 15:00 16:30 1.50 PRDTST SPOT SAND AF Start Pumping 1st 24 bbl Gel Sand Plug Slurry (3,000#
~ sand) @ 1.5 BPM mixing Breaker in Sand Plug While
pumping. Finish Pumping 24 bbl Sand Gel Sand Plug
Slurry out of Mixing Tub and into Coil Tubing. Decreased
Pump Rate to 1/2 bpm when all 24 bbl Gel Sand Plug
Slurry is in coil tubing and before Gel Sand Plug Slurry
exits coil tubing. Displace 24 bbl Gel Sand Plug Slurry out
of Coil Tubing w/ 28 bbls 6% KCL Water @ 1/2 BPM while
~ Pulling Coil Tubing up Hole Slowly. Finish Pumping
Displacement. PUH 50' wait 15 minutes to let Sand Plug
Settle. RIH Tag Top of Sand Fill Top @ 6004'. Sand Fill
46'. PUH 12'. Gel up Water and Add Sand to mix up Gel
Sand Plug Slurry. Mix 24 bbl Gel Sand Plug Slurry. Bottom
of Coil Tubing to 5992'.
08/13/07 9 16:30 18:30 2.00 PRDTST SPOT SAND AF Start Pumping 2nd 24 bbl Gel Sand Plug Slurry (3,000#
sand) @ 1.5 BPM mixing Breaker in Sand Plug While
pumping. Finish Pumping 24 bbl Sand Gel Sand Plug
Slurry out of Mixing Tub and into Coil Tubing. Decreased
Pump Rate to 1/2 bpm when all 24 bbl Gel Sand Plug
Slurry is in coil tubing and before Gel Sand Plug Slurry
exits coil tubing. Displace 24 bbl Gel Sand Plug Slurry out
of Coil Tubing w/ 28 bbls 6% KCL Water @ 1/2 BPM while
Pulling Coil Tubing up Hole Slowly. Finish Pumping
~ Displacement. PUH 100' wait 15 minutes to let Sand Plug
Settle. RIH Tag Top of Sand Fill Top @ 5979'. Sand Fitf
25'. PUH 9'. Gel up Water and Add Sand to mix up Gel
Sand Plug Slurry. Mix 24 bbl Gel Sand Plug Slurry. Bottom
of Coil Tubing to 5970'.
Page 29 of 33 - Printed 12/13/2007
Operational Detaits for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date----------------------•-•--------------------•----...-----...----Activity------------------------- Depth.--- -----------...---....__...--------...------------------...--------------
08/13/07 9 18:30 20:30 2.00 PRDTST SPOT_ SAND AF Start Pumping 3rd 24 bbl Gel Sand Plug Slurry (3,000#
sand) @ 1.5 BPM mixing Breaker in Sand Plug While
pumping. Finish Pumping 24 bbl Sand Gel Sand Plug
Slurry out of Mixing Tub and into Coil Tubing. Decreased
Pump Rate to 1/2 bpm when all 24 bbl GeI Sand Plug
Slurry is in coil tubing and before Gel Sand Plug Slurry
exits coil tubing. Displace 24 bbl Gel Sand Plug Slurry out
of Coil Tubing w/ 28 bbls 6% KCL Water @ 1/2 BPM while
~ Pulling Coil Tubing up Hole Slowly. Finish Pumping
Displacement.
08/13/07 9 20:30 22:00 1.50 PRDTST RUNPUL COIL AF POOH w/ Coil Tubing. Coil Tubing Came out of Injector.
Close Flowing Tree Valves. Secured Coil Tubing. RD and
Set down Injector. Restab Coil Tubing in Injector.
08/13/07 9 22:00 22:30 0.50 PRDTST SECURE WELL AF Secure Well. SDFN. Signed out at the Sterling Pad office.
Locked the gates on the way out. Dumped Total of 9,000 #_
20/40 Mesh Sand Today.
08/14/07 10 09:00 09:45 0.75 PRDTST SAFETY MTG_ AF Arrive Sterling Pad. Sign in at rig. Hold PJSM and obtain
Safe Work Permit.
08/14/07 10 09:45 11:30 1.75 PRDTST PUMP WTR_ AF Pick Up Injector and Install 2-1/8" Jetting Nozzel on Bottom
of Coil Tubing. RU injector on wellhead. Load Coil Tubing
with 6% KCL Water. Shell Test Connections to 1000 psi.
Held Pressure.
08/14/07 10 11:30 13:00 1.50 PRDTST RUNPUL COIL AF Start in hole wtih Coil Tubing with 2-1/8" Jetting nozzel.
RIH @ 100'/min Taq sand Top of Sand Fill @ 5955' coil
~ Tubing depth. PUH 100' w/ Coil Tubing.
08/14/07 10 13:00 13:30 0.50 PRDTST SPOT_ SAND AF Start Prepairing Water PH of Water for Gel. Gel up Water
and Add Sand to mix up Gel Sand Plug Slurry. Mix 24 bbl
Gel Sand Plug Slurry. RIH w/ Coil Tubing. Bottom of Coil
Tubing to 5935'.
Page 30 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date---------------------------••------...-----...-----...----..._.__Activity.----------...----------- Depth-------..._.....---------------------------------------...------------------
08/14/07 90 13:3017:00 3.50 PRDTST SPOT SAND
~
08/14/07 10 17:00 19:00 2.00 PRDTST RUNPUL COIL
08/14/07 10 19:00 19:30 0.50 PRDTST SECURE WELL
~8/15/07 11 07:00 08:00 1.00 PRDTST SAFETY MTG_
AF Start Pumping 1 st for the day and 4th total 24 bbl Gel Sand
Plug Slurry (3,000# sand) @ 1.5 BPM mixing Breaker in
Sand Plug While pumping. Finish Pumping 24 bbl Sand
Gel Sand Plug Slurry out of Mixing Tub and into Coil
Tubing. Decreased Pump Rate to 1/2 bpm when all 24 bbl
Gel Sand Plug Slurry is in coil tubing and before Gel Sand
Plug Slurry exits coil tubing. Displace 24 bbl Gel Sand Plug
Slurry out of Coil Tubing w/ 28 bbls 6% KCL Water @ 1/2
BPM while Pulling Coil Tubing up Hole Slowly. Finish
Pumping Displacement. PUH 100' wait 30 minutes to let
Sand Plug Settle. RIH Tag Top of Sand Fill Top @ 5928'.
Sand Fill 27'. PUH 100'. Gel up Water and Add Sand to
mix up Gel Sand Plug Slurry. Mix 24 bbl Gel Sand Plug
Slurry. Bottom of Coil Tubing to 5828'. Sand Fill Continue
to rise. Final Tag @ 5832'. After 2 days and 12,000 # Sand
Dumped gained 218' at last tag from 6050' to 5832'.
AF POOH w/ Coil Tubing. Close Valves. Circulate Gel out of
Mixing Tub and through Coil Tubing into Gas Buster Tank.
Flush Coil Tubing with Water. RD Injector. Wash Sand out
of Cement Pump Truck. Close all Well Head Valves. Install
Night Cap on Well Flowing Tree.
AF Secure Well. SDFN. Signed out at the Sterling Pad office.
Locked the gates on the way out.
AF Arrive on location. Obtain Work permit. Hold tailgate safety
meeting.
Page 31 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date ... Activity-•----------------------- Depth.----------...._....----------•--...---------------------------...----------
------•------------------•-------•---------------------...--------- ----- -
~~
08/15/07 11 08:00 12:00 4.00 PRDTST PUMP_ WTR_
L~
AF RU injector on wellhead. Start in hole wtih cement head.
Continue to RIH w/ Coil Tubing. Tag Top of Sand Fill @
5783" coil depth @ 9:30 am. Coil Tubing Displacing fluid
out of Hole while running in Hole. After Tagging top of
Sand Fill @ 5783'. PUH w/ Coil Tubing 100' to 5700' with
Cement Nozzle on Coil Tubing. Which is 50' above
Perforations @ 5750' to 5751'. Start Pumping down coil
tubing @ 1 bpm Getting about 100% Returns. Pumped 7
bbls in got about 7 bbls back in returns. Stopped Pumping
6°/a KCL Water. Start Pumping w/ 6% KCL water after not
pumping for 45 minutes. Well broke circulation almost
immediatly and getting full returns. Well did not take any
fluid while static for 45 minutes. Start Mixing 10 bbls of
Cement. Jet through PerForations with Cement Nozzle with
side holes in nozzle to possibly unplug perforations. Finish
Mixinq Cement. Readv to Pump. PUH w/ Coil Tubing. oi
Tubing Cement Nozzle set @ 5770'.
Page 32 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date
--
------
-------------------------•---------------------ActivitY..--------------------... Depth---- --------------------------------------------------...-------------------
-
-------
--
CMT_ AF
08/15/07 11 12:00 14:00 2.00 PRDTST PUMP Start Pumping 10 bbls Fresh Water Pad. Pump 11-1/4 bbls
_ of cement @ 15.8 tb/gal (58 sks of Class G cement w/
0.7% FL-63 + 0.3% CD-32 + 0.4% R-3 + 0.3% EC-1 +
0.1 % ASA-301 + 1 ghs FP-6L). Yield 1.158 ft3/sk & 4.913
gal/sk. Tail with 4 bbls Fresh water spacer and Displaced 2-
1/2 bbls cement out bottom of Coil Tubing with 15 bbls 6%
KCL water. Pump 1 bpm rate down coil with CT Cement
Nozzle @ 5770'. Return line open to establish 1 to 1
~ displacement to track cement in coil. Pumped @ 1 bpm
Pulling Coil up Hole @ 13'/min Pumped Remaining 8-3/4
bbls Cement (11-1/4 Total BBIs Cement Pumped) out of
the nozzle while moving up hole with nozzle Stop @ 5636'
pumped full cement load. PUH 336' Cement Nozzle @
5300' while pumping on well @ min rate to keep hole full.
Wait on Cement for 15 minutes. Start Pumping @ 1 BPM
rate Broke Circulation immediatly but Lost Circulation and
Pumped about 1 bbl to regain circulation. Perforations
Between 5750' to 5751' drank 3/4 to 1 bbl Cement before
startinq Sqeeze. Close Valves and pressure Cement
Squeeze to 500 psi. Held Pressure for 15 minutes. Did not I
08/15/07 11 14:00 16:30 2.50 PRDTST RUNPUL COIL
~8/15/07 11 16:30 18:00 1.50 PRDTST RURD_ COIL
08/15/07 11 18:00 18:30 0.50 PRDTST SAFETY MTG_
08/16/07 12 08:00 08:30 0.50 PRDTST SAFETY MTG_
08/16/07 12 08:30 11:30 3.00 PRDTST RURD_ COIL
08/i6/07 12 11:30 12:00 0.50 PRDTST SECURE WELL
AF POOH w/ Coil Tubing. Shut in Master Valve on Flowing
Christmas Tree. Blow water out of Coil Tubing through
choke into gas buster tank. Close all Well Head Valves.
AF Remove and Laydown Coil Tubing Injector. Remove and
Laydown BOPE. Install Night Cap on Well Flowing Tree.
RD BJ Cement Equipment. RD BJ Coiltech Coil Tubing
Equipment. RD Crane. Empty flowback Tank. Disconnect
Surface Iron. Prepair to Road Equipment Tomorrow.
AF Secure location for the night. Sign out and leave location.
AF Arrive on location, sign in, obtain work permit and hold pre-
job safety meeting.
AF RDMO Coil Tubing, Surface Equipment, Gas 8uster,
Tanks, and Crane
AF Secured well. Leave Well Shut in. Signed out for the night.
Page 33 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date----------------------------------------------------------------- ActivitY..-------.......---------.Depth.....---...------------------------------------------------------...--------
Rig Completion Event - Gravel Pack Operatioms
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
10/13/07 7 10:00 06:00 20.00 MIRU RURD RIG CS 6,185 PJSM; Finish moving equip. to location, Clean snow off
mats, raise and pin sub base, Spot over well, pin mud boat
to sub, flip over rarnp, put carrier on mud boat, level and
secure, Move in pits, and pull together, wire up, pits, pump
room, and carrier, spot and set camp trailers, Set up mech.
shop and parts trailer, PJSM; for crane operations, crane in
~ fuel tank, derrick house, raise derrick, continue rigging up.
10/14/07 8 06:00 06:00 24.00 MIRU RURD RIG CS 6,185 PJSM;Continue Rig up , Scope up mast, Pull wires, make
up service loops, Rig up guy wires, Poor boy gas buster,
Pjsm; Spot and rig up power water, and air to #3 pump,
Install dresser sleeves, pop-offs, shock hoses, spot beaver
slide, and catwalk, PJSM; rig up torque tube, change out
front crankshaft seal # 1 generator, Pick up top drive, Rig
up pumps, Rig up floor, gauge lines, Set containment, and
matting boards for frac tanks and equipment.
10/15/07 9 06:00 12:00 6.00 MIRU RURD RIG CS 6,185 PJSM; Test run top drive (Good) Rig up pipe spinners, rig
tongs, bails, Hyd. elevators, cellar grading, set welding
shop.
10/15/07 9 12:00 04:30 16.50 XMBO NUND BOPE CS 6,185 PJSM; Check well for press., Remove tree, remove csg.
hanger, install test plug, Nipple up BOP, Continue to rig up
~ Filter unit, and frac tanks, Wash thru all pit equip. Install
new flex joint # 2 carrier engine
10/15/07 9 04:30 05:00 0.50 XMBO TEST BOPE CS 6,185 PJSM; Pick up test tools, function test BOP
10/15/07 9 05:00 06:00 1.00 XMBO TEST BOPE CS 6,185 Make up test tools, Test BOP and gas alarms, Test to 250
psi low, 3500 psi high for 10 minutes.Test plug not holding
10/16/07 10 06:00 07:00 1.00 XMBO TEST_ BOPE TA MSBO 6,185 Change out lower pipe rams to 5", and Test plug
10/16/07 10 07:00 08:00 1.00 XMBO TEST_ BOPE TA MSBO 6,185 Attempt to retest door seals leaked, Change out both door
seals,
10/16/07 10 08:00 08:30 0.50 XMBO SAFETY MTG CS 6,185 Hold safety Meeting with all venders about traffic and
speed on road coming to location.
10/16/07 10 08:30 14:30 6.00 XMBO TEST BOPE CS 6,185 PJSM; Test BOP Lower rams, HCR, Manual choke, Blind
rams, perfomance test Koomey unit, all test 250psi low,
- 3500psi high, 10 mins.
- . Page 13 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date
------------
-------
----------------
--------- -----------
-- ------------- ActivitY... ..---•----- ------------Depth----- -------.........----------------------...---------------...------------
10/16/07 10 14:30 16:00 1.50 PR1 CSG RUNPUL WBSH CS 6,185 Set wear bushing, and blow down all mud lines, choke,
Top drive, choke line
10/16/07 10 16:00 19:30 3.50 PR1CSG PULD_ BHA_ CS 6,185 PJSM;Pick up and make up BHA RIH
10/16/07 10 19:30 05:30 10.00 PR1CSG PULD_ DP_ CS 6,185 PJSM; Pick up 5" drill pipe (158 Jts.) jagged at 5640'
10/16/07 10 05:30 06:00 0.50 PR1 CSG DRILL_ CMT_ CS 6,185 Drilling out cement from 5640' to 5682' Up wt. =135K Dn.
wt=110K
10/17/07 11 06:00 13:00 7.00 PR1 CSG DRILL_ CMT_ CS 6,185 Drill out cmt., sand, F/5640' to 5775'(Note Perfs. at 5750'-
5751')
10/17/07
~ 11 13:00 13:30 0.50 PR1CSG MIX PILL CS 6,185 Pump Hi visc. sweep.
10/17/07 11 13:30 15:00 1.50 PR1 CSG DRILL_ CMT_ CS 6,185 Cont. to drill out from 5775' to 5780' Up wt.=148K Dn. wt.
140K Rt wt.=133K Tq.=8-14K
10/17/07 11 15:00 15:30 0.50 PR1CSG TEST_ CSG_ CS 6,185 PJSM;Test sqeezed perfs. broke down at 340 psi. started
takinq fluid. 30 bbls. hr.
10/17/07 11 15:30 17:00 1.50 PR1CSG SPOT_ PILL CS 6,185 Mix and spot LCM pill, and spot. 30 bbls. at perfs in
annulus
10/17/07 11 17:00 18:00 1.00 PR1CSG FLOW_ CHEK CS 6,185 PJSM;LCM pill in place, at 1700 hrs., Watch fluid level,well
stopped taking fluid, well static.
10/17/07 11 18:00 00:00 6.00 PR1CSG TRIP_ DP_ CS 6,185 PJSM;POOH Lay down jars, string mill, bit sub, bit.
40/17/07 11 00:00 02:00 2.00 PR1CSG TRIP_ DP_ CS 6,185 PJSM; :Make up Halib. EZ drill RIH to 2200'
10/17/07 11 02:00 03:00 1.00 PR1 CSG REPAIR RIG_ TA MSHS 6,185 Trouble shoot fuel on carrier.
10/17/07 11 03:00 05:30 2.50 PR1CSG TRIP_ DP CS 6,185 Continue RIH from 2200' to 5730' with retainer
10/17/07 11 05:30 06:00 0.50 PR1CSG SETREL PLUG CS 6,185 Set Halib. Cmt. retainer at 5730'
10/18/07 12 06:00 06:30 0.50 PR1CSG TEST_ EQIP CS 6,185 PJSM; Test cmt lines to 3000 psi, Est. injection rate 1/2 bbl
min, 940 psi , Perfs at 5750' to 5751'
~10/18/07 12 06`30 09:00 2.50 PR1CSG SQUEZE CMT_ CS 6,185 Mix and pump 75 sx. Class G+.4% FL-63, .4%CD-32,
.1 %R-3, .1 %ASA-301, .05% Static Free, 1 ghs FP-6L, 15.8
ppg, 1,152 cu/ft./sk, yield, 4.925 gal/H20/sk.. Pump 11.8
bbls. cmt in perFs w/ final pressure of 1500 psi.ClP (a~0900
, hrs.
90/18/07 12 09:00 11:00 2.00 PR1CSG SQUEZE CMT_ CS 6,185 Unsting from cmt. retainer. Rev. out cmt.Circ. wiper ball
down drill pipe long way.
10/18/07 12 11:00 12:00 1.00 PR1 CSG CLEAN_ RIG_ CS 6,185 Blow down pumps, choke, gas buster.
10/18/07 12 12:00 16:00 4.00 PR1 CSG TRIP_ DP_ CS 6,185 PJSM; POOH lay down cmt. retainer running tool.
10/18/07 12 16:00 17:00 1.00 PR1CSG PULDi BHA CS 6,185 Pick up 8 1/2 bit and 8 3/4 string mill.
10/18/07 12 17:00 19:30 2.50 PR1CSG TRIP_ DP_ CS 6,185 RIH with 5" drill pipe to 5580'
Page 14 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date-----------------------------------------------------------------Activ_itY_.......------.....------ Depth...-----.......-------------------------....------...-------------.....-----
10/18/07 12 19:30 06:00 10.50 PR1CSG WAITON CMT_ CS 6,185 Wait on cement. Drill out at 0900 hrs., Service rig and top
drive, Service carrier, greased hyd. IBOP, Steam clean top
drive. Replace dennison on #1 Mud pump.lnsulate #3 mud
lines, change oil, fuel filters, #1 generator. Clean rig
10/19/07 13 06:00 09:00 3.00 PR1CSG WAITON CMT_ CS 6,185
10/19/07 13 09:00 09:30 0.50 PR1CSG TRIP_ DP_ CS 6,185
10/19/07 13 09:3016:00 6.50 PR1CSG DRILL_ CMT_ CS 6,185
10/19/07 13 16:0017:00 1.00 PR1CSG MIX_ PILL CS 6,185
!10/19/07 13 17:0017:30 0.50 PR1CSG TEST_ CMT_ CS 6,185
10/19/07 13 17:30 21:30 4.00 PR1CSG DRILL CMT
10/19/07 13 21:30 22:00 0.50 PR1 CSG CLNOUT CSG
10/19/07 13 22:00 01:00 3.00 PRICSG CIRC_ CFLD
10/19/07 13 01:00 04:00 3.00 PR1CSG CIRC_ CFLD
10/19/07 13 04:00 04:30 0.50 PR1 CSG CLEAN_ TANK
10/19/07 13 04:30 06:00 1.50 PR1CSG TRIP_ DP_
10/20/07 14 06:00 09:00 3.00 PR1 CSG TRIP DP
10/20/07 14 09:00 10:00 1.00 PR1 CSG RURD ELEC
.10/20/07 14 10:00 12:00 2.00 PR1 CSG RUNPUL ELEC
10/20/07 14 12:00 14:00 2.00 PR1 CSG RUNPUL ELEC
10/20/07 14 14:00 20:00 6.00 PR1 CSG PERF_ CSG_
CS
AF
AF
AF
AF
AF
AF
AF
AF
AF
AF
6,185
6,185
6,185
Wait on Cement Serv. rig.
RIH w/ 5" drill pipe f/ 5580' to 5680'
Drill out cement from 5680' to 5766'
Mix and pump hi visc. pill.
Test sgeezed perfs at 5750' to 5751' at 627 psi F/ 5 min.
no leak off.
Cont. to drill out cement F/ 5766'-5818'
Circ. out sand from 5818'-5930' Up wt.=154K Dn wt.=110K
Rt wt.=133K Tq.=9-14K
Mix and pump hi visc. sweep.Clean out frac sand.@5930'
6,185 PJSM;Mix and pump Caustic Wash, followed by Hi-
Visc.sweep, and displaced with filtered KCL 6% 30 NTU.
Coming back.
6,185 PJSM; finish cleaning trip tank, and pipe rack, and fill trip
tank.
6,185 POOH with bit and string mill.Blow down equip.
6,185 POOH to run Wireline
6,185 PJSM; Rig up Expro wireline and make up wireline junk
basket and gauge ring.8.5 OD
6,185 PJSM; RIH W/Gauge ring and junk basket 8.5 OD, to
5918' , POOH
6,185 PJSM;Make up and run in hole with Baker 194-47 Model
"B" sump packer and set at 5784' Wireline Measurement
POOH, rig down witeline.
6,185 PJSM; Pick up 7" perf. gun assy. and RIH to 5784' Wireline
measurement, tag and space out perfs. top shot at 5766'
bottom shot at 5776', 10' of perfs.18 spf.
TVD depths reported to BLM for perto~ations: 5289.5' -
5279.5 TVD. Compass soffinrare used to convert the
measured depth to TVD.
~ 0/20/07 14 20:00 21:00 1.00 PR1 CSG FLOW_ CHEK AF 6,185 Monitor well for losses, well taking 6 bbls. hour.
- ~ Page 15 of 33 - Printed 12/9 3/2007
Operational Details for Well: STERLlNG UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date ------- ------- ---------------- --------- ------------- ------------ - ActivitY.. ...-----.... .-----------Depth----- --------._....---------------....-----------------------------....-----
10/20/07 14 21:00 02:00 5.00 PR1CSG TRIP_ DP_ AF 6,185 POOH with perf. guns.
10/20/07 14 02:00 03:00 1.00 PR1 CSG PULD_ BHA_ AF 6,185 Lay down perf,. guns and pick up scraper assy.
10/20/07 14 03:00 06:00 3.00 PR1CSG TRIP_ DP_ AF 6,185 RIH with scraper assy. to circ. well clean with filtered 6%
KCL to 20 NTU's
10/21/07 15 06:00 07:00 1.00 PR1CSG TRIP_ DP_ A~ 6,185 RIH with 9 5/8-40# Scraper assy. to 5740'
10/21/07 15 07:00 09:00 2.00 PR1 CSG MIX_ FLD_ AF 6,185 Clean pits and filter 6% KCL brine for volume.
10/21/07 15 09:00 12:00 3.00 PR1CSG REPAIR RIG_ TA MSFL 6,185 PJSM;Start displacing fluid in well and found suction valve
for #2 charge pump in pit #3 leaking, and repair.
10/21/07 15 12:00 17:00 5.00 PR1CSG CIRC_ CFLD AF 6,185 PJSM; Start displacing fluid in well with filtered KCL Tag
~ packer at 5791' Drill pipe measurement, 5784" wireline
measurement.Circ. filtered fluid until 17 NTU's returned
from well bore.
10/21 /07 15 17:00 17:30 0.50 PR1 CSG FLOW_ CHEK AF 6,185 PJSM; Check for flow, blow down top drive.
10/21/07 15 17:30 22:30 5.00 PR1CSG TRIP_ DP_ AF 6,185 POOH tay down jars, bit sub,scraper assy..Up wt.=155K
Dn. wt.=110K
10/21/07 15 22:30 00:00 1.50 PR1CSG PULD_ EQIP AF 6,185 PJSM; Pick up Baker gravel pack assy.
10/21/07 15 00:00 06:00 6.00 PR1CSG TRIP_ DP AF 6,185 PJSM; RIH with Baker G~avel pack assy two min. std.
10/22/07 16 06:00 06:30 0.50 PR1 CSG SETREL PKR_ AF 6,185 PJSM; Est.parameters 155K up wt. 110K dn wt., Snap into
sump packer, pull 20K over to snap out.Packer at5791"
drill pipe measurement.
10/22/07 16 06:30 07:30 1.00 PR1CSG CHANGE EQIP AF 6,185 Change out bails,Make up head pin, Floor valve, snap
back into packer.
10/22/07 16 07:30 09:30 2.00 PR1CSG RURD CMT_ AF 6,185 PJSM;Rig up BJ iron for pumping gravel pack.
10/22/07 16 09:30 10:30 1.00 PR1CSG SAFETY MTG_ AF 6,185 PJSM;For gravel pack with all personel, Test lines to 4800
psi.
~'10/22/07 16 10:30 12:00 1.50 PR1CSG SETREL PKR_ AF 6,185 PJSM; Drop 1 7/16 ball and set SC-1 packer at 5738'
wireline measurement.
10/22/07 16 12:00 13:30 1.50 PR1CSG PICKLE TUBE AF 6,185 PJSM; Pump 10 bbls. viscous pill, 10 bbl. safe sol OM, 500
gal. of 15% HCL with inhibitor and 7 Ibs. of citric acid,
pump to bottom of drill pipe and revrse out 3 drill pipe
volumes.
10/22/07 16 13:30 21:00 7.50 PR1 CSG PUMP_ FRAC AF 6,185 Put 30K on Gravel pack packer and perform circ.rate,
Close choke and do step rate test, Pump gravel pack at 12
bbls. min. with 1/2 bbl returns,put away 2750 Ibs.proppant,
1470# proppant in place, Pick-up and reverse out 1280 Ibs.
Rig down BJ and blow down lines.
, Page 16 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date
------------ - ----
------- - Activity.
-- ---
------- ------------ Depth__.._ _.._ .
- ----------------------------
------------
10/22/07 --------------•-----------------
96 21:00 22:00 1.00 -
PR1CSG FLOW CHEK AF 6,185 Change out bails and monitor well . Well taking fluid went
from 13 bbls. hr. to 60 bbls, hr. and increasing.While
POOH U4943'
10/22/07 16 22:00 23:30 1.50 PR1CSG MIX LCM AF 6,185 Mix and pump 30 bbl. 2.5 ppb. HEC pill.
10/22/07 16 23:30 03:00 3.50 PR1CSG TRIP_ DP
' AF 6,185 Cont. to POOH f/4943'(Fluid losses down to 4 bbls.
hr. @0300hrs. )
10/22/07 16 03:00 04:30 1.50 PR1CSG PULD BHA_ AF 6,185 Lay down Gravel pack X-over tool.
10/22/07 16 04:30 05:00 0.50 PR1CSG PULD_ BHA AF 6,185 Pick up Packer plug and RIH
•10/22/07 16 05:00 06:00 1.00 PR1CSG TRIP_ DP_ AF 6,185 RIH w/ packer plug on drill pipe.
i
e
ill
d
Pl
P
k
10/23/07 17 06:00 08:00 2.00 PR1 CSG TRIP DP AF 6,185 p
.
p
r
ug on
er
RIH with
ac
10/23/07 17 08:00 08:30 0.50 PR1 CSG _
SETREL PLUG AF 6,185 Set packer plug in SC-1 packer shear off at 5749'D.P.
depth, Test to 500 psi
10/23/07 17 08:30 09:00 0.50 PR1 CSG SERVIC RIG_ AF 6,185 Blow down surface equip.
10/23/07 17 09:00 13:00 4.00 PR1CSG TRIP DP AF 6,185 POOH with running tool, Lay down setting tool.
10/23/07 17 13:00 19:00 6.00 PR1 CSG TEST _
BOPE AF 6,185 PJSM;PuII wear bushing, Ria up test equip., Test t/ 250- _
_ ~000 psi for 10 min. Test annulus,upper pipe rams, blind
rams, Good, Test floor valves, iibop, test, inside, outside
kill line, check valves, HCR, manual choke, CMV's, 1-12,
Koomey test,Rig down test equip. InstaN wear bushing.
10/23/07 17 19:00 20:00 1.00 PR1CSG SLPCUT DLIN
10/23/07 17 20:00 01:00 5.00 CMPPRF PERF_ CSG_
~10/23/07 17 01:00 01:30 0.50 CMPPRF TRIP_ DP_
AF
AF
6,185
6,185
PJSM, Slip 33' Drlg. line, set crown O matic, adjust brakes.
Pick up make up perF. gun, RIH Pick up HWDP, Drilling
jars.RlH with HWDP , 5" drill pipe. Shoot perfs. at
5724'Top shot. Wireline depth.
PJSM; For perF. tag top of packer at 5738' wireline
measurement.Shoot prefs at 18 spf 140-20 deg. phasing,
39.0 grams, Entry hole 1.06" penetration-7.43', 6.00' gun
length.
AF
6,185
10/23/07 17 01:30 02:00 0.50 CMPPRF FLOW_ CHEK AF 6,185
10/23/07 17 02:00 06:00 4.00 CMPPRF TR1P_ DP_ AF 6,185
10/24/07 18 06:00 06:30 0.50 PR1CSG TRIP_ DP_ AF 6,185
10/24/07 18 06:30 08:00 1.50 PR1CSG PULD_ BHA_ AF 6,185
10%24/07 18 08:0010:30 2.50 PRICSG TRIP_ DP,_ AF 6,185
~10/24/07 18 10:3011:00 0.50 PR1CSG CIRC_ CFLD AF 6,185
TVD depths reported to BLM for perforations: 5237.5' -
5231.5 TVD. Compass soffinrare used to convert the
measured depth to TVD.
Monitor well for losses, no losses.
PJSM; POOH from 5745'
POOH w/ Perf, assy.
PJSM;Make up scraper and overshot RIH
PJSM; RIH to 5746'
Route pill pit returns to hanson tank, clean trip tank.
Page 17 of 33 - Printed 12/13/2007
Operational Details for Well: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date------- ------- ---------------- --------- ------------- ----------- --Activity-- ----------- ------------ Depth.---- -----------------------------------------------------------------------
10/24/07 18 11:00 12:00 1.00 PR1 CSG CIRC CFLD AF 6,185 Circ. one hole volume 400 bbis. to hanson tank.Got 28
bbls. of HEC pill back to surface.
10/24/07 18 12:00 21:00 9.00 PR1CSG CIRC CFLD AF 6,185 Circ. and filtered brine from 110 NTU's to 20 NTU's
10/24/07 18 21:00 21:30 0.50 PR1 CSG PULL EQIP AF 6,185 Pull Baker SB plug from SC-1 packer at 5749' Monitor well
no losses
10/24/07 18 21:30 01:00 3.50 PR1CSG TRIP_ DP_ AF 6,185 POOH W/ scraper and SB packer plug. started losing 2
bbls. hr.
10/24/07 18 01:00 02:30 1.50 PR1CSG PULD_ BHA_ AF 6,185 Lay down 1 jt. HWDP drilling jars, and scraper, plug assy.
~10/24/07 18 02:30 04:30 2.00 PR1CSG PULD PKR AF 6,185
10/24/07 18 04:30 05:00 0.50 PR1CSG SERVIC RIG_ AF 6,185
10/24/07 18 05:00 06:00 1.00 PR1CSG 7RIP DP_ AF 6,185
10/25/07 19 06:0011:30 5.50 PR1CSG TRIP DP AF 6,185
10/25/07 19 11:30 12:00 0.50 PR1 CSG TRIP DP AF 6,185
10/25/07 19 12:0012:30 0.50 PR1CSG SETREL PKR_ AF 6,185
10/25/07 19 12:30 13:30 1.00 PR1 CSG RURD OTHR
AF
6,185
10/25/07 19 13:30 00:00 10.50 PR1 CSG PUMP FRAC
•
10/25/07 19 00:00 00:30 0.50 PR1CSG RURD_ STIM
10/25/07 19 00:30 01:00 0.50 PR1 CSG TRIP_ DP_
10/25/07 19 01:00 02:30 1.50 PR1 CSG CIRC CFLD
AF
AF
AF
AF
10/25/07 19 02:30 06:00 3.50 PR1 CSG TRIP DP_ AF
10/26/07 20 06:00 11:30 5.50 PR1 CSG TRIP_ DP_ AF
10/26/07 20 11:30 12:30 1.00 CMPRUN SAFETY MTG_ AF
10,'~L6/07
-. - 20 12:30 13:00 0.50 CMPRUN RUNPUL WBSH AF
6,185
Pick up SC-1 Gravel pack assy. and 18.77', 5 1/2- .012
ga.screen.
Serv. Top drive and Carrier.
PJSM; RIH with SC-1 Gravel pack assy.
Continue RIH with SC-1 gravel pack assy.
Space out drill pipe for rigging up BJ.
PJSM;Snap into lower packer at 5765' Drop 1 7/16 steel
ball
PJSM; Change bails, elevators, Install pup jt., pump in sub.
floor valve
PJSM;R/U BJ lines, test lines to 4500 psi. Set packer,Test
annulus to 2500 psi, Pump 10 bbls. Hi visc. sweep, 8
bbls.safe solv OM, 12 bbls. 15% HCL, displace with 100
bbls.Reverse out.Circ. and filter brine clean to 20 NTU's.
Pump and spot breaker pill, get injection rates. Pump
gravel pack sand. Screen out with 3750 psi, Pumped
3150# with 1689 in place, reversed out 1461 #.
6,185 Rig down BJ frac equip. monitor well.
6,185 PJSM; Un sting from SC1 packer. Monitor well. Hole
taking 30bb1 per hr.
6,185 Monitor well, P/U circulation Head and pressure up on hole
to 150psi, Isolation valve closed Hold for 5 min. No fluid
lossses , Bleed off pressure. no losses
6,185 Poh, lay down 5" drillpipe F- 5716- 3000' at 0600 hrs
6,185 Continue POH and lay down 5" drillpipe F-3000' And SC1
setting tools and stinger
6,185 Safety stand down. Hold weekley Safety meeting
6,185 Pull wear bushing
~, . Page 18 of 33 - Printed 12/13/2007
Operational Details for Weli: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date--•-------------•-------------------•----------------------------Activity.-----------------------. Depth.---------------------------------------------------------------------------
10/26/07 20 13:00 18:00 5.00 CMPRUN RURD_ OTHR AF 6,185 R/D Frac tanks and Mi swaco filter units and load out R/D
rig floor
10/26/07 20 18:00 03:30 9.50 CMPRUN DRlFT_ TBG_ AF 6,185 PJSM; Load pipe racks with 2 7/8 and 2 3/8 Tubing Drift
and strap, prep for running .Test floor valve and dart va(ve,
250 psi low, 3500 psi high, Make dummy run dual hanger,
problems with installing mandrels, cutting O-rings,
10/26/07 20 03:30 06:00 2.50 CMPRUN TEST_ BOPE TA MSBO 6,185 Install Dual Ram 2 7/8 and 2 3/8. Make up test plug. Test
• 2 7/8 and 2 3/8.
Tubin rams 250/3500. Test faild,rams leaked. Pull test
joint. 2 3/8 side o dual ram itting up set on crossover.
Remove dual test body and Repair
10/27/07 21 06:00 12:30 6.50 CMPRUN TEST BOPE TA MSBO 6,185 Continue Repair test plug. Install and attempt to test rams.
No test. Remove Test plug and repair ( collar cracked on 2
7/8 side )
10/27/07 21 12:30 13:00 0.50 CMPRUN TEST_ BOPE AF 6,185 Test 2 7/8 and 2 3/8 dual ram 250/3500psi 5min. Test
good
10/27/07 21 13:00 00:30 11.50 CMPRUN RUNPUL TBG AF 6,185 oI~~M discuss procedures for running dual strings of
tubing. P/U blast joint 3jts 2 7/8 tubing and make up to
Packer. Run 2 7/8 and 2 3/8 dual tubing strings. with 7ea
gas lift mandrels and pups.
10/27/07 21 00:30 04:30 4.00 CMPRUN REPAIR RIG_ TA MSPW 6,185 Lost electrical power to lights in mast. Troubleshoot and
repair
10/27/07 21 04:30 06:00 1.50 CMPRUN RUNPUL TBG AF 6,185 Continue running dual Completion f-2956'
~0/28/07 22 06:00 13:00 7.00 CMPRUN RUNPUL TBG_ AF 6,185 Continue running Dual completion to 5657' top of KOIV tag
and break KOIV monitor well losing 42 bbls hr.
10/28/07 22 13:00 15:30 2.50 CMPRUN RUNPUL TBG AF 6,185 RIH stab seal assy. into packer bore at 5737' Space out
install pups and tubing hanger. Cameron Dual 11" 5K
#H136716-15
10/28/07 22 15:30 18:30 3.00 CMPRUN RUNPUL TBG AF 6,185 Work on installing hanger. Mandref seals tearing while
putting in master bowl.Repair and test to 5000 psi for 10
min. good
10/28/07 22 18:30 20:00 1.50 CMPRUN RUNPUL TBG AF 6,185 Land tubing hanger, test to 5000 psi for 15 min. good
10/28/07 22 20:00 21:30 1.50 CMPRUN RUNPUL SLIK AF 6,185 PJSM; Rig up Pollard wireline and, RIH with "N" test
tool,set at 5600' and POOH.
10/28/07 22 21:30 22:30 1.00 CMPRUN PUMP_ WTR_ AF 6,185 PJSM; Rig up BJ, pump, Test lines to 4500 psi, Pressure
to 3500 psi~ Set packer
10/~8/07 22 22:30 00:00 1.50 CMPRUN RURD_ SLIK AF 6,185 PJSM; Rig up wireline on long string, RIH with plug and
,- prong, set at 5755' Rig up to test annulus.
a +
r Page 19 of 33 - Printed 12/13/2007
Operational Details for Weli: STERLING UNIT 43-9X
Report Rept # From To Hours Phase Activity Sub Status T Type To Operations
Date
------------
-------
----
------------ --------- -------------- ------------ Activity.-- ------..... ...__.......Depth----- --------...------...------...---------------...------------------------
10/28/07 22 00:00 01:00 1.00 CMPRUN TEST_ CSG AF 6,185 Test 9 5/8 Annulus 2000psi. Test good
10/28/07 22 01:Ob 03:30 2.50 CMPRUN SETREL PLUG AF 6,185 RIH Pollard wire line and pull 2 7/8 plug POH. Rih Pull 2
3/8 plug. POH and R/D pollard wire line
10/28/07 22 03:30 04:00 0.50 CMPRUN SETREL PLUG AF 6,185 Lay Down landing joints and Set back pressure valves.
10/28/07 22 04:00 05:00 1.00 CMPRUN RURD_ CSG_ 0 6,185 WD Weatherford dual string tubing tools
10/28/07 22 05:00 06:00 1.00 CMPRUN NUND BOPE AF 6,185 PJSM; Nipple down BOP
10/29/07 23 06:00 10:00 4.00 CMPRUN NUND BOPE AF 6,185 Continue N/D BOP Move out of sub. Clean pits
10/29/07 23 10:00 17:00 7.00 CMPRUN NUND TREE AF 6,185 PJSM; N/U Dual tubing tree . Test Void ,Wellhead and tree
~ to 5000psi/10min. All test good. Freeze protect tree.
Complete cleaning of pits
10/29/07 23 17:00 06:00 13.00 RDMO RURD_ RIG_ AF 6,185 Rig down GD-1. R/D #3 mud pump, cuttings tank, Hanson
tank and load out. R/D pits and pump modules. Move out
BJ cement van. Remove berm from rig. R/D Top Drive and
torque tube. Pull service lines from sub. Blown Down all
tines and boiler. L/D stairs on bop conex L/D beaver slide.
R/D carrier frame and tarps. Prep mast for scope down.
10/30/07 24 06:00 18:00 12.00 RDMO RURD_ RIG_ AF 6,185 R/D GD-1 Hold PJSM; Discuss hazards working with
crane. Scope down mast Set crane and remove dog,
choke house,Gray iron and wind walls,load out. Lay mast
down on carrier. Split pits. Complete removing all steam,
water and electrical lines. Crane down stairways. Load and
move pit,pumps dog ,choke, boiler,hanson Water tank and
generator units to 14-6 pad load out beaver slide ,catwalk
~ stain~vays bop's and ship to 14-6pad.
10/30/07 24 18:00 06:00 12.00 RDMO RURD_ RIG_ AF 6,185 Move carrier off mud boat .Scope down sub.Release rig
from SU 43-9x 0600hrs 10 -30-07
~
+
~« Page 20 of 33 - Printed 12/13/2007
,
SU 43-9X: Post Meeting Pian For~Ci Plan . Page 1 of 1
Regg, James B (DOA)
From: Waish, Ken [kdwalsh@marathonoil.com] i~
Sent: Monday, December 17, 2007 12:54 PM ~~~~~t ~Z,~~ T ~u~
To: Ibele, Lyndon; Martens, Dave; Mullin, Mickey; Paxton, Todd D.; Johnson, Edward C.; Sweet, Welby C.;
Yadav, Sharad
Cc: Rang, Craig L.; Regg, James B(DOA); Cheek, Ben; Ophus, Tim
Subject: SU 43-9X: Post Meeting Plan Forward Plan
All,
Thanks to all c~f yc~u for your input regarding tl~is project, T(~e pla~ forward beginning around n~on
~oday, December 17, is as follows:
1. Qper~ the ~~erling Unit 43-9X shc~rt string {S~) side ~o fi1c~w tc~ #he productic~n facilities at a fixed fluid
unlr~ading rate af ~.7 M~9scfd for fc~ur ~tours. F~ecord the SS gas ~nd water rafies during fihe flc~w
test. Confiinue metering ~U 41-15rd ~as production through fihe sand ~us~er ar~d Exprc~ V1Te(( Testers
tc~ lift the SU ~~-9X LS side tfl atmc~sphere venting through the gas buster. fmmediately upon ~he ;/
completior~ 4#~ ti~e fQ~r-hc~ur test c~f the SS, discc~r~r~ect the SU 41-'15rd from the SU 43-9x ann~lus_and
discontinue venting gas, Release the Expro 1IVel1 Testers. _ _ _ _
2. If the SS is flovuinc~ dry ~as ~~ °~ .7 MMscfc~ abcave 1090 psi ~TP at the end o~ the fi~~ar-hc~ur flc~w
~est, ~hen direct fihe S~ ~lc~vv tc~ the annulus tc~ lift ~rater frc~m tk~~ LS ~c~ the prod~ctian ~Facilities. [f ~~~
S~ begins to ~roduce w~t~r ~~er the fc~ur-hc~ur test ~eric~d and ~rl~il~ ~~ir~g dir~ct~d to t~~ ar~nuf~s,
c~a~tinue ~iftir~g L~ i~ li~k i~ sustainable. If LS lift cann~~ ~~ sustainec~, sh~t in L~ ar~d prs~duc~ ~S to
pr~sduction faci~ities.
3. If t~e SS ~eg~ns to ~roduce vvater before ths four-hc~ur t~st period has p~st, t~en contir~ue tc+ flow
th~ S~ tr~ th~ pr~c~uctior~ facilities and shc~t ir~ ~.~.
Ple~s~ canfiact m~ immec~iat~ly ~f I h~rr~ nc~t ca~tured t~e plan accur~tely.
x
K~~, ~. ~i~n
Senior Producti~r~ Engi~~~r
t~tarathor~ Oi~ Cc~~pany-Ataska ~s~ef Team
9Q7-Z83-13'~ 1 (vfFice)
9~7-394-306~ {csllj
12/17/2007
Report 41-1 SRd Support 43-9X 1~-07.x1s . Page 1 of 1
Regg, James B (DOA)
From: Walsh, Ken [kdwalsh@marathonoii.com]
Sent: Monday, December 17, 2007 1:39 PM ~~C lZ' ~~1~ ~
To: Regg, James B (DOA} ~
Subject: Report 41-15Rd Support 43-9X 12-17-07.x1s
Attachments: Report 41-15Rd Support 43-9X 12-17-07.x1s
Jim,
Ken ~. alsh
S~rciar Pra~i~acti~>n Engineer
arat~~n ~3i1 Co~pa~y-Aiaska ~,ss~t Teas~n
9Q7-283-131 °f (office)
9~~-394-3£l~#~ {c~ll}
«Report 41-15Rd Support 43-9X 12-17-07.x1s»
12/17/2007
COMPANY.• Ma~athon Oil Company
_ ......... . _ _ _ .
EXPRO : ' FIELD: Sterling Unit
SURFACE WELL TEST/NG REPORT l-, :.~~~:~~, ;~ ~~~ LEASE: Sport Lake
_ '_ ''~KQ~ ~~'~~ wELL#: 41-15RD Support 43-9x
Co. REP.: Mickey Mullins
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Open 41-15Rd to Inlet of Separator
12/11/2007 6:15 3390
Trap Pressure in Separator, Lite
12/11 /2007 6:20 Burner 3390
Liquid Rates from 43-9X
12/11 /2007 9:00 3390
Start Flowing 41-15RD, Sending Gas
12/11 /2007 10:15 to 43-9X, choke 4/64 3390
Ffowing 41-15RD, Sending Gas to 43
1 2/11/2007 1 0:30 9X 3190 42 4 1280 38 88 1.000 0.642 1458.14 20.25 38.40 0.40
Flowing 41 •15RD, Sending Gas to 43
12/11/200711:00 9X 2950 42 4 1260 44 84 1.000 0.642 1565.61 52.87 1632.00 34.40
Flowing 41-15RD, Sending Gas to 43
12/11/200711:30 9X 2850 42 4 1200 44 78 1.000 0.642 1537.62 84.90 907.68 53.31
Flowing 41 •15RD, Sending Gas to 43
12/11/200712:00 9X 2750 44 4 1150 44 76 1.000 0.642 1504.86 116.25 907.68 72.22
Flowing 41-15RD, Sending Gas to 43
12/11/200712:30 9X 2700 46 4 1110 44 77 1.000 0.642 1471.32 146.91 878.40 89.27
Continue flowing 41-15RD, Open
12I11I2007 13:00 choke to 6164 2650 46 6 1110 49 77 1.000 0.642 7552.71 179.25 782.88 105.58
Continue flowing 41-15RD, Flowing
12/11I2007 13:30 gas to 43-9X 2800 48 6 1110 59 77 1.000 0.642 1703.90 214.75 903.36 124.40
Continue flowing 41-15RD, flowing
12/11/2007 14:U0 gas to 43-9X 2800 46 6 1116 60 77 1.000 O.6A2 1718.29 250.55 1211.04 149.63
Continue flowing 41-15RD, New gas
12/11/200714:30 gravity 2800 47 6 1110 60 77 1.000 0.563 1789.91 287.84 650.40 163.18
Continue flowing 41-15RD, flowing
12/11/2007 15:00 gas to 43•9X 2800 47 6 1110 60 77 1.000 0.563 1789.91 325.13 896.16 181.85
Continue flowing 41-15RD, flowing
12/11/2007 15:30 gas to 43-9X 2800 48 6 1110 59 77 1.000 0.563 1774.92 362.11 1010.88 202.91
Continue flowing 41-15RD, flowing
12/11/2007 16:00 gas to 43-9X 2800 48 6 1100 59 77 1.000 0.563 1765.98 398.90 960.00 222.91
Continue flowing 41-15RD, flowing
12/11/2007 16:30 gas to 43-9X 2800 47 6 1100 59 77 1.000 0.563 1765.98 435.69 790.08 239.37
Continue flowing 41-15RD, flowing
12/11/2007 17:00 gas to 43-9X 2790 48 6 1090 59 78 1.000 0.563 1754.40 472.24 960.00 259.37
Co~tinue flowing 41-15RD, flowing
12/11/2007 17:30 gas to 43-9X 2790 48 6 1080 59 78 1,000 0.563 1745.42 508.60 1120.80 282.72
Continue flowing 41-15RD, flowing
12/11/2007 18:00 gas to 43-9X, 27g0 47 6 1080 59 76 1.000 0.563 1750.60 545.07 483.84 292.80
Estimated liquid rate due to vac
12/11/2007 18:30 truck pulling load 2790 47 6 1080 57 76 1.000 0.563 1720.65 580.92 816.00 309.80
~
Page 1
coMPANY.• Marathon Oil Company
EXPRO • g`~ FIELD: Sterling Unit
SURFACE WELL TEST/NG REPORT 1~~. :~~~~~'.: ,;~~~,~ lEasE: Sport Lake
~< ~""~ ~~`~~~~ WELL#: 41-15RD Support43-9x
CO. REP.: Mickey Mullins
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choke to 8164, Estimated liquid rate,
12/11/2007 19:00 vac truck pulling load 2790 47 6 1080 56 76 1.000 0.563 1705.48 616.45 816.00 326.80
Continue flowing 41-15RD, flowing
12/11/2007 19:30 gas to 43-9X 2750 47 8 1080 57 76 1.000 0.563 1720.65 652.30 672.00 340.80
Continue flowing 41-15RD, flowing
12/11 /2007 20:00 gas to 43-9X 2740 47 S 1080 57 76 1.000 0.563 1720.65 688.14 846.24 358.43
Estimated liquid rate due t vac truck
12/11/200720:30 pullingload 2720 47 8 1080 56 76 1.000 0.563 1705.48 723.68 768.00 374.43
Continue flowing 41-15RD, flowing
12/11/2007 21:00 gas to 43-9X 2700 46 8 1080 62 76 1.000 0.563 1794.59 761.06 823.68 391.59
choke to 6/64, Estimated liquid rate
12/11/2007 21:30 due to vac truck pulling load 2700 47 8 1080 62 76 1.000 0.563 1794.59 798.45 816.00 408.59
Continue flowing 41-15RD, flowing
12/11/2007 22:00 gas to 43-9X 2690 48 6 1080 62 76 1.000 0.563 1794.59 835.84 816.00 425.59
Continue flowing 41-15RD, flowing
12/11 /2007 22:30 gas to 43-9X 2670 48 6 1080 60 76 1.000 0.563 1765.39 872.62 806.88 442.40
Continue flowing 41-15RD, flowing
12/11 /2007 23:00 gas to 43-9X 2660 48 6 1080 59 76 1.000 0.563 1750.60 909.09 768.00 458.40
Continue flowing 41-15RD, flowing
12/11/2007 23:30 gas to 43-9X 2640 48 6 1080 59 76 1.000 0.563 1750.60 945.56 768.00 474.40
Continue flowing 41-15RD, flowing
12/12/2007 0:00 gas to 43-9X 2640 48 6 1080 59 76 1.000 0.563 1750.60 982.03 907.20 493.30
Continue flowing 41-15RD, flowing
12/12/2007 0:30 gas to 43-9X 2640 48 6 1080 59 76 1.000 0.563 1750.60 7078.50 756.48 509.06
Continue flowing 41-15RD, flowing
12/12/2007 1:00 gas to 43-9X 2630 48 6 1070 59 76 1.000 0.563 1741.55 1054.78 958.08 529.02
Continue flowing 41-15RD, flowing
12/12/2007 1:30 gas to 43-9X 2620 48 6 1070 58 76 1.000 0.563 1726.71 1090.76 812.64 545.95
Continue flowing 41 •15RD, flowing
12/12/2007 2:00 gas to 43-9X 2620 48 6 1070 58 76 1.000 0.563 1726.71 1126.73 815.52 562.94
Continue flowing 41-15RD, flowing
12112I2007 2:30 gas to 43-9X 2620 48 6 1070 58 76 1.000 0.563 1726.71 1162.70 790.56 579.41
Continue flowing 41-15RD, flowing
1211212007 3:00 gas to 43-9X 2600 48 6 1070 57 76 1.000 0.563 1711.75 1198.36 803.04 596.14
Continue flowing 41-15RD, flowing
12/12/2007 3:30 gas to 43-9X 2600 48 6 1070 57 76 1.000 0.563 1711.75 1234.02 903.36 614.96
Continue Flowing, Increased choke
12/12/2007 4:00 to 8/64 2600 48 6 1070 56 76 1.000 0.568 1691.46 1269.26 618.24 627.84
flowing 41-15RD, flowing gas to 43-
12/12/2007 4:30 9X, choke to 7/64 2550 48 8 1080 64 76 1.000 0.568 1817.76 1307.13 1070.88 650.15
I Continue flowing 41-15RD, flowing
12/12/2007 5:00 gas to 43-9X 2550 48 7 1080 59 76 1.000 0.568 1745.26 1343.49 555.84 661.73
~
Page 2
COMPANY.• Marathon Oil Company
EXPRO ` ~ ' FIELO: Sterling Unit
SURFACE WELL TESTING REPORT 1~-. >~~~~~, >~~~~~ LEASE: Sport Lake
~
~ ~~`~~
~~~~ WELL#: 41-15RD Support43-9x
co. REP.: Mickey Mullins
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Continue flowing 41-15RD, flowing
72/12/2007 5:30 gas to 43-9X 2500 47 7 1070 58 76 1.000 0.568 1721.42 1379.36 790.56 678.20
Continue flowing 41-15RD, flowing
1 211 2/2007 6:00 gas to 43-9X 2500 46 7 1060 58 76 1.000 0.568 1712.41 1415.03 1185.60 702.90
Continue flowing 41-15RD, flowing
1 211 2/2007 6:30 gas to 43-9X 2500 46 7 1060 58 76 1.000 0.668 1712.41 1450.71 732.96 718.17
Continue flowing 41-15RD, flowing
12/12/2007 7:00 gas to 43-9X, Rock choke 2500 46 7 1060 58 76 1.000 0.568 1712.41 1486.38 903.84 737.00
Continue flowing 41-15RD, flowing
12/1212007 7:30 gas to 43-9X 2500 46 7 1070 64 76 1.000 0.568 1808.33 1524.05 790.56 753.47
Continue flowing 41-15RD, flowing
12/12/2007 8:00 gas to 43-9X 2450 45 7 1080 64 76 1.000 0.568 1817.76 1561.92 790.08 769.93
Continue flowing 41-15RD, flowing
12/12/2007 8:30 gas to 43-9X 2400 46 7 1080 62 76 1.000 0.568 1789.11 1599.20 903.36 788.75
Estimated liquid rate due to vac
12/1212007 9:00 truck pulling load 2400 46 7 1080 62 75 1.000 0.568 1791.81 1636.53 828.00 806.00
Estimated liquid rate due to vac
12/12/2007 9:30 truck pulling load 2400 46 7 1080 62 76 1.000 0.568 1789.11 1673.80 840.48 823.51
Continue Flowing 41-15RD, flowing
12/12/2007 10:00 gas to 43~X 2400 46 7 1080 61 76 1.000 0,568 1774.62 1710.77 621.60 836.46
Continue Flowing 41-15RD, flowing
12/12/2007 10:30 gas to 43-9X 2400 46 7 1080 60 76 1.000 0,568 1760.00 1747.44 903.36 855.28
Continue Fiowing 41-15RD, flowing
1 2/1 212007 11:00 gas to 43-9X 2350 46 7 1080 60 76 1.000 0,568 1760.00 1784.11 732.96 870.55
Continue Flowing 41-15RD, flowing
1 211 2/2007 11:30 gas to 43-9X 2350 46 7 1080 60 76 1.000 0.568 1760.00 1820.77 790.56 887.02
Estimated liquid rate due to vac
12/12/2007 12:00 truck putiing load 2350 46 7 1070 60 76 1.Q00 0.568 1750.87 1857.25 808.80 903.87
Estimated liquid rate due to vac
1 2/1 2/2007 1 2:30 truck pulling load 2350 46 7 1070 58 76 1.000 0.568 1721.42 1893.11 847.20 921.52
Continue flowing 41-15RD, flowing
1 211 2/2007 13:00 gas to 43-9X, Rock choke 2300 46 7 1070 56 76 1.000 0.568 1691.46 1928.35 860.64 939.45
Continue flowing 41-15RD, flowing
12/12/2007 13:30 gas to 43-9X, 2300 46 7 1070 60 76 1.000 0.568 1750.87 1964.83 860.16 957.37
Continue flowing 41-15RD, flowing
12/12/2007 14:00 gas to 43-9X, 2300 46 7 1070 60 76 1.000 0.568 1750.87 2001.30 719.52 972.36
Continue flowing 41-15RD, flowing
12/12/2007 14:30 gas to 43-9X, 2250 46 7 1070 58 75 1.000 0.568 1724.00 2037.22 790.56 988.83
Continue flowing 41-15RD, gas to 43
1 2/1 2/2007 1 5:00 9X, rocked choke 2250 46 7 1070 57 75 1.000 0.568 1709.07 2072.83 677.76 1002.95
Continue flowing 41-15RD, flowing
1 2/1 2/2007 1 5:30 gas to 43-9X, 2200 46 7 1070 64 75 1.000 0.568 1811.05 2110.56 902.88 1021.76
.
~ ~
Page 3
COMPANY.• Marathon Oil Company
EXPRO FIELD: Sterling Unit
SURFACE WELL TESTING REPORT y~~~. `> ~~~~~';, ,,~ ~~ LEASE: Sport Lake
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CO. REP.: Mickey Mullins
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Estimated liquid rate due to vac
12112l2007 16:00 truck pulling load 2200 46 7 1080 62 76 1.000 0.568 1789.11 2147.83 845.76 1039.38
Estimated liquid rate due to vac
12/12/2007 16:30 truck pulling load 2150 46 7 1080 60 76 1.000 0.568 1760.00 2184.50 808.80 1056.23
Continue flowing 41-15RD, flowing
12/12/2007 17:00 gas to 43-9X, 2150 46 7 1080 60 76 1.000 0.568 1760.00 2221.16 752.16 1071.90
Continue flowing 41-15RD, flowing
12/12/2007 17:30 gas to 43-9X, 2150 46 7 1070 60 76 1.000 0.568 1750.87 2257.64 754.56 1087.62
Continue flowing 41-15RD, flowing
1 2/1 212007 1 8:00 gas to 43-9X, 2130 46 7 1070 58 76 1.000 0.568 1721.42 2293.50 563.04 1099.35
Estimated liquid rate due to vac
1 211 2/2007 1 8:30 truck pulling load 2120 46 7 1060 57 75 1.000 0.568 1697.58 2328.87 600.96 1111.87
Increased Choke to 8/64
1 2/1 2/2007 1 9:00 2100 46 7 1060 57 75 1.000 0.568 1697.58 2364.23 984.00 1132.37
Increased Choke to 9/64
1 2/1 2/2007 1 9:30 2100 46 8 1060 57 75 1.000 0.568 1697.58 2399.60 651.84 1145.95
Continue flowing 41-15RD, gas to 43
12/12/2007 20:00 9X, rocked choke 2100 46 9 1060 53 75 1.000 0.568 1636.89 2433.70 852.96 1163.72
Continue flowing 41-15RD, gas to 43
12/12/2007 20:30 9X, rocked choke 2100 46 9 1060 57 75 1.000 0.568 1697.58 2469.07 718.56 1178.69
, Continue flowing 41-15RD, gas to 43
' 12/12/2007 21:00 9X 2100 46 9 1060 64 75 1.000 0.568 1798.87 2506.54 636.48 1191.95
Continue flowing 41-15RD, gas to 43
12/12/2007 21:30 9X 1975 46 9 1060 60 75 1.000 0.568 1741.71 2542.83 713.76 1206.82
Continue flowing 41-15RD, gas to 43
12/12/2007 22:00 9X 1950 46 9 1060 57 75 1.000 0.568 1697.58 2578.20 857.28 1224.68
Increased Choke to 11/64
12/12/2007 22:30 1900 46 9 1060 60 75 1.000 0.568 1741.71 2614.48 554.40 1236.23
Continue flowing 41-15RD, gas to 43
12/12/2007 23:00 9X 1940 46 11 1060 60 75 1.000 0.568 1741.71 2650.77 806.88 1253.04
Continue flowing 41-15RD, gas to 43
1 211 212007 23:30 9X, rocked choke 1900 46 11 1060 58 75 1.000 0.568 1714.97 2686.50 553.92 1264.58
Continue flowing 41 •15RD, gas to 43
12/13/2007 0:00 9X 1850 46 11 1070 68 75 1.000 0.568 1866.83 2725.39 1186.08 1289.29
Decreased choke to 10/64
12/13/2007 0:30 1820 46 11 1080 65 75 1.000 0.568 1834.64 2763.61 655.68 1302.95
Continue flowing 41-15RD, gas to43-
1 2/1 3/2007 1:00 9X 1820 46 10 1070 58 75 1.000 0.568 1724.00 2799.53 737.28 1318.31
Continue flowing 41-15RD, gas to43-
1 2/1 3/2007 1:30 9X 1820 46 10 1060 58 75 1.000 0.568 1714.97 2835.26 691.68 1332.72
Continue flowing 41-15RD, gas to43-
12/13/2007 2:00 9X 1830 46 10 1060 58 75 1.000 0.568 1714.97 2870.98 554.88 1344.28
C~
\ J
Page 4
CoMPANY.• Marathon Oil Company
EXPRO ~ ' F~e~~: Sterling Unit
SURFACE WELL TESTING REPORT I~< :~~~~~',, >~ ~~ ' LEASe: Sport Lake
~% `~~~~ ~~~ WELL#: 41-15RD Support43-9x
CO. REP.: Mickey Mullins
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Continue flowing 49-15RD, gas to43-
~ 12/13/2007 2:30 9X 1830 46 10 1060 58 75 1.000 0.568 1714.97 2906.71 508.80 1354,88
Continue flowing 41-15RD, gas to43-
12/13l2007 3:00 9X 1800 46 10 1060 64 75 1.000 0.568 1801.56 2944.24 518.40 1365.68
Continue flowing 41-15RD, gas to43-
12/13/2007 3:30 9X 1780 46 10 1060 61 75 1.000 0.568 1758.80 2980.89 778.08 1381,89
Continue flowing 41-15RD, gas to43-
1 211 312007 4:00 9X 1750 46 10 1060 60 75 1.000 0.568 1741.71 3017.17 605.76 1394,51
Continue flowing 41-15RD, gas to43-
12/13/2007 4:30 9X 1730 46 10 1060 57 75 1.000 0.568 1700.11 3052.59 604.32 7407.10
Continue flowing 41-15RD, gas to43-
12/13/2007 5:00 9X 1750 46 10 1050 60 75 1.000 0.568 1735.10 3088.74 700.80 1421.70
Continue flowing 41-15R0, gas to43-
12l13/2007 5:30 9X 1740 46 10 1050 60 75 1.000 0.568 1735.10 3124.89 609.12 1434.39
Continue flowing 41-15RD, gas to43-
12/13/2007 6:00 9X 1750 48 10 1050 58 75 1.000 0.568 1705.91 3160.43 1008.00 1455.39
Continue flowing 41-15RD, gas to43-
12/1312007 6:30 9X 1725 47 10 1050 58 75 1.000 0.568 1705.91 3195.97 908.16 1474.31
Well Starting to produce sand and
12113/2007 7:00 water, open choke to 13/64 1950 46 10 1000 28 76 1.000 0.568 1151.57 3219.96 731.04 1489.54
Liquid rate estimated, open choke to
12/13/2007 7:30 16/64 1825 45 13 1020 42 76 1.000 0.568 1426.13 3249.67 605.76 1502.16
Continue dumping sand buster,
1211312007 8:00 Rocked Choke 1700 42 16 1030 32 76 1.000 0.568 1251.53 3275.74 504.00 1512.66
Continue dumping sand buster,
12/13/2007 8:30 Rocked Choke 1650 45 16 1040 52 77 1.000 0.568 1601.85 3309.11 907.20 1531.56
Dumped sand buster, Rocked
12/13/2007 9:00 Choke, estimated water rate 1600 45 16 1040 48 75 1.000 0.568 1543.53 3341.27 791.52 1548.05
Continued Flowing 41-15RD
12/13/2007 9:30 Dumped sand buster, 1550 45 16 1050 64 75 1.Op0 0.568 1792.04 3378.61 1163.04 1572.28
Continued Flowing 41-15RD
12/13/2007 10:00 Dumped sand buster, 1550 45 16 1040 62 75 1.000 0.568 1754.40 3415.16 1310.88 1599.59
Estimated Fluid Rate, Dumped sand
12/13/200710:30 buster, 1550 44 16 1060 60 75 1.000 0.568 1744.31 3451.49 847.20 1617.24
Continue Fiowing 41 •15RD, Dumped
12/13/2007 11:00 sand buster, 1400 46 16 1080 60 76 1.000 0.568 1760.00 3488.16 1109.76 1640.36
Flowing 41-15RD, Dumped sand
1 211 312007 11:30 buster,Rocked choke 1350 45 16 1080 60 76 1.000 0.568 1760.00 3524.83 604.32 1652.95
Continue Flowing 41 •15RD, Open
12/13/2007 12:00 choke to 20/64 1300 44 16 1070 54 76 1.000 0.568 1660.96 3559.43 806.88 1669.76
Continue Flowing 41-15RD,
12/13/2007 12:30 Continue dumping sand buster 1300 45 20 1060 62 76 1.000 0.568 1770.52 3596.32 818.40 1686.81
~
~
Page 5
CoMPANY: Marathon Oii Company
EXPRO ~ ' FIELD; Sterling Unit
SURFACE WELL TESTWG REPORT 1~-. >~~~~~', ,~~~~~ LEASE: Sport Lake
. .. . ... '
" ~"~~ ~~~~' WELL#: 41-15RD Support43-9x
_
CO. REP.: Mickey Mullins
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12/13/2007 13:00 Estimated Fluid rate 1300 44 20 1080 68 76 1.000 0.568 1873.75 3635.35 743,04 1702.29
Continue Flowing 41-15RD,ciose
12/13/2007 13:30 choke to 19/64 1300 44 20 1080 68 76 1.000 0.568 1873.75 3674.39 604.80 1714.89
Continue Flowing 41-15RD,dumping
12/13/2007 14:00 sand buster 1300 43 19 1080 62 75 1.000 0.568 1789.11 3711.66 554.88 1726.45
Continue Flowing 41-15RD,dumping
12/13/2007 14:30 sand buster 1300 43 19 1080 64 74 1.000 0.568 1823.26 3749.65 504.48 1736.96
Continue Flowing 41-15RD,dumping
12/13/2007 15:00 sand buster 1325 44 19 1080 68 75 1.000 0.568 1876.58 3788.74 806.88 1753.77
Continue Flowing 41-15RD,dumping
12/13/2007 15:30 sand buster 1325 44 19 1080 68 75 1.000 0.568 1876.58 3827.84 655.68 1767.43
Continue Flowing 41 •15RD,dumping
12/13I2007 16:00 sand buster 1350 44 19 1080 68 75 1.000 0.568 1876.58 3866.93 705.60 1782.13
Continue Flowing 41-15RD,dumping
12/13/2007 16:30 sand buster 1350 44 19 1080 67 74 1.000 0.568 1865.54 3905.80 706.08 1796.84
Continue Flowing 41-15RD,dumping
12/13/2007 17:00 sand buster 1350 44 19 1080 69 75 1.000 0.568 1890.34 3945.18 688.80 1811.19
Continue Flowing 41 •15RD,dumping
12/13/2007 17:30 sand buster 1350 43 19 1080 68 75 1.000 0.568 1876.58 3984.28 806.88 1828.00
Continue flowing 41 •15RD,dumping
12/1 312007 1 8:00 sand buster 1350 43 19 1080 68 75 1.000 0.568 1876.58 4023.37 406.56 1836.47
Continue Flowing 41-15RD,dumping
12113I2007 18:30 sand buster 1340 43 19 1080 65 75 1.000 0.568 1834.68 4061.60 615.84 1849.30
Continue Flowing 41-15RD,dumping
12/13/2007 19:00 sand buster 1340 43 19 1080 64 75 1.000 0.568 1820.50 4099.52 818.40 1866.35
Continue Flowing 41-15RD,dumping
12/13/2007 19:30 sand buster 1340 43 19 1070 65 75 1.000 0.568 1825.15 4137.55 396.48 1874.61
Continue Flowing 41-15RD,dumping
12/13/2007 20:00 sand buster 1330 43 19 1070 65 75 1.000 0.568 1825.15 4175.57 806.68 1891.42
Estimated Fluid Rate,Continue
12113/2007 20:30 dumping sand buster 1320 43 19 1070 60 75 1.000 0.568 1753.50 4212.10 496.32 1901.76
Continue Flowing 41-15RD,dumping
12/13/2007 21:00 sand buster 1320 43 19 1070 63 75 1.000 0.568 1796.83 4249.54 779.04 1917.99
Continue Flowing 41-15RD,dumping
12/13/2007 21:30 sand buster 1320 43 19 1070 63 75 1.000 0.568 1796.83 4286.97 605.28 1930.60
Continue Flowing 41-15RD,dumping
12/13/2007 22:00 sand buster 1320 42 19 1070 64 75 1.000 0.568 1811.05 4324.70 806.88 1947.41
Continue Flowing 41-15RD,dumping
12/13/2007 22:30 sand buster 1320 42 19 1070 62 75 1.000 0.568 1782.50 4361.83 907.68 1966.32
Continue Flowing 41-15RD,dumping
72/13/2007 23:00 sand buster 1320 42 19 1070 60 75 1.000 0.568 1753.50 4398.37 800.64 1983.00
~~
~
Page 6
COMPANY.• Marathon Oil Company
EXPRO • ,g~' FIELD: Sterling Unit
SURFACE WELL TESTING REPORT 1~~. ~ ~~
> ~~~~~I ;; .~, LEASE: SportLake
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12/13/2007 23:30 sand buster 1320 42 19 1065 60 75 1.000 0.568 1748.91 4434.80 690.72 1997.39
Continue Flowing 41-15RD,dumping
12/14/2007 0:00 sand buster 1300 42 19 1070 62 75 1.000 0.568 1782.50 4471.94 554.88 2008.95
Continue Flowing 41-15RD,dumping
12114/2007 0:30 sand buster 1275 40 19 1070 61 73 1.000 0.568 1768.06 4508.77 756.48 2024.71
Continue Flowing 41-15RD,dumping
12I14/2007 1:00 sand buster 1285 40 19 1065 64 73 1.000 0.568 1811.77 4546.52 605.28 2037.32
Estimated Fluid Rate,Continue
12/14/2007 1:30 dumping sand buster 1285 40 19 1065 62 73 1.000 0.568 1783.21 4583.67 873.60 2055.52
Continue Flowing 41-15RD,dumping
12114/2007 2:00 sand buster 1280 41 19 1065 62 73 1.000 0.568 1783.21 4620.82 655.68 2069.18
Continue Flowing 41-15RD,dumping
12/14/2007 2;30 sand buster 1280 41 19 1065 62 73 1.000 0.568 1783.21 4657.97 705.60 2083.88
Continue Flowing 41-15RD,dumping
12/14/2007 3:00 sand buster 1280 41 19 1065 62 73 1.000 0.568 1783.21 4695.12 750.24 2099.51
Continue Flowing 41-15RD,dumping
12/14/2007 3:30 sand buster 1280 41 19 1060 60 73 1.000 0.568 1749.57 4731.57 691.68 2713.92
Continue Flowing 41-15RD,dumping
12/14/2007 4:00 sand buster 1280 40 19 1060 64 73 1.000 0.568 1807.00 4769.21 806.88 2130.73
Continue Flowing 41-15RD,dumping
12/14/2007 4:30 sand buster 1260 40 19 1050 59 74 1.000 0.568 1723.14 4805.17 655.20 2144.38
Continue Flowing 41-15RD,dumping
1211412007 5:00 sand buster 1270 40 19 1060 62 74 1.000 0.568 1775.86 4842.17 806.88 2161.19
Estimated Fluid Rate,Continue
1211412007 5:30 dumping sand buster 1280 40 19 1060 61 74 1.000 0.568 1761.44 4878.81 719.52 2176.18
Continue Flowing 41-15RD,dumping
12/14/2007 6:00 sand buster 1280 40 19 1060 64 74 1.000 0.568 1807.27 4916.46 338.40 2183.23
Continue Flowing 41-15RD,dumping
12/14/2007 6:30 sand buster 1290 40 19 1060 61 74 1.000 0.568 1761.44 4953.15 1160.16 2207.40
Continue Flowing 41-15RD,dumping
12/14/2007 7:00 sand buster 1290 39 19 1060 61 74 1.000 0.568 1761.44 4989.85 705.60 2222.10
Continue Flowing 41-15RD,dumping
12/1412007 7:30 sand buster 1290 39 19 1060 61 74 1.000 0.568 1761.44 5026.55 655.20 2235.75
Continue Flowing 41-15RD,dumping
12/14/2007 8:00 sand buster 1290 38 19 1060 61 74 1.000 0.568 1761.44 5063.24 772.32 2250.59
Continue Flowing 41-15RD,dumping
12/14/2007 8:30 sand buster 1290 38 19 1060 60 74 1.000 0.568 1746.93 5099.64 700.32 2265.18
Continue Flowing 41-15RD,dumping
12/1412007 9:00 sand buster 1290 38 19 1060 60 74 1.000 0.568 1746.93 5136.03 805.92 2281.97
Continue Flowing 41-15RD,dumping
12/14I2007 9:30 sand buster 1280 37 19 1060 60 73 1.000 0.568 1749.57 5172.48 703.20 2296.62
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~
Page 7
COMPANY.• Marathon Oil Company
_.....
_ _
..__
EXPRO • ~" ' ' FIELD: Sterling Unit
SURFACE WELL TESTING REPORT f~%. >~~~~~',, >~~~~ LEASE: SportLake
~ ~"~~ ~~~'~~ wELL#: 41-15RD Support 43-9x
Co. REP.: Mickey Mullins
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Continue Flowing 41-15RD,dumping
12/14/2007 10:00 sand buster 1270 37 19 1060 60 72 1.000 0.568 7752.23 5208.99 702.24 2311.25
Continue Flowing 41-15RD,dumping
12/14/2007 10:30 sand buster 1280 38 19 1060 61 74 1.000 0.568 1761.44 5245.68 602.40 2323.80
Continue Flowing 41-15RD,dumping
12114/2007 11:00 sand buster 1290 38 19 1060 61 75 1.000 0.568 1758.80 5282.32 665.28 2337.66
Continue Flowing 41-15RD,dumping
12/14/2007 11:30 sand buster 1270 38 19 1060 61 75 1.000 0.568 1758.80 5318.97 697.44 2352.19
Continue Flowing 41-15RD,dumping
12/1412007 12:00 sand buster 1275 38 19 1060 60 75 1.000 0.568 1744.31 5355.31 714.24 2367.07
Continue Flowing 41-15RD,dumping
12/1412007 12:30 sand buster 1275 39 19 1060 60 75 1.000 0.568 1744.31 5391.65 675.84 2381.15
Estimated Fluid Rate,Continue
1 2/14/2007 1 3:00 dumping sand buster 1275 40 19 1060 63 75 1.000 0.568 7787.42 5428.88 695.52 2395.64
Continue Flowing 41-15RD,Continue
1 2/1412007 1 3:30 dumping sand buster 1275 40 19 1060 61 75 1.000 0.568 1758.80 5465.53 648.00 2409.14
Continue Flowing 41-15RD,Continue
12/1412007 14:00 dumping sand buster 1270 40 19 1060 60 75 1.000 0.568 1744.31 5501.87 552.96 2420.66
Continue Flowing 41-15RD,Continue
12/14/2007 14:30 dumping sand buster 1275 40 19 1060 60 75 1.000 0.568 1744.31 5538.21 708.96 2435.43
Continue Flowing 41-15RD,Continue
12114/2007 15:00 dumping sand buster 1275 40 19 1060 61 74 1.000 0.568 1761.44 5574.90 899.04 2454.16
Estimated Fluid Rate,Continue
1 2114/2007 1 5:30 dumping sand buster 1275 40 19 1060 60 74 1.000 0.568 1746.93 5611.30 720.48 2469.17
Estimated Fluid Rate,Continue
12/14/2007 16:00 dumping sand buster 1275 40 19 1055 60 75 1.000 0.568 1739.71 5647.54 776.16 2485.34
Continue Fowing 41-15RD,Continue
12/14/2007 16:30 dumping sand buster 1275 40 19 1050 60 74 1.000 0.568 1737.69 5683.74 782.88 2501.65
Estimated Fluid Rate,Continue
12/14/2007 17:00 dumping sand buster 1275 40 19 1050 60 74 1.000 0.568 1737.69 5719.94 759.84 2517.48
Continue Fowing 41-15RD,Continue
12/14I2007 17:30 dumping sand buster 1275 39 19 1050 61 74 1.000 0.568 1752.13 5756.45 705.60 2532.18
Continue Fowing 41-15RD,Continue
12/14/2007 18:00 dumping sand buster 1275 37 19 1050 57 74 1.000 0.568 1693.66 5791.73 252.96 2537.45
Continue Fowing 41-15RD,Continue
12/14/2007 18:30 dumping sand buster 1275 37 19 1050 59 74 1.000 0.568 1723.14 5827.63 655.20 2551.10
i Continue Fowing 41-15RD,Continue
~ 12/14/2007 19:00 dumping sand buster 1275 37 19 1050 58 74 1.000 0.568 1708.47 5863.22 717.12 2566.04
Estimated Fluid Rate,Continue
1 2114/2007 1 9:30 dumping sand buster 1275 37 19 1050 58 74 1.000 0.568 1708.47 5898.82 519.36 2576.86
Continue Fowing 41-15RD,Continue
12114/2007 20:00 dumping sand buster 1275 35 19 1050 58 72 1.000 0.568 1708.47 5934.41 762.72 2592.75
~~
~
Page 8
CoMPANY.• Marathon Oil Company
_
EXPRO ~ ' FtE~o: Sterling Unit
SURFACE WELL TESTING REPORT ~~~. :~~~~~ >~~~,~~ LEASE: Sport Lake
" `~K~a ~'~~~~' WELL#: 41-15RD Support 43-9x
CO. REP.: Mickey Mullins
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Continue Fowing 41-15RD,Continue
12114I2007 20:30 dumping sand buster 1275 35 19 1050 57 72 1.000 0.568 1698.78 5969.80 706.08 2607.46
Estimated Fluid Rate,Continue
12/14/2007 21:00 dumping sand buster 1275 37 19 1050 59 72 1.000 0.568 1728.34 6005.81 690.72 2621.85
Continue Fowing 41-15RD,Continue
12/14/2007 21:30 dumping sand buster 1275 37 19 1049 58 71 1.000 0.568 7715.31 6041.54 454.08 2631.31
Continue Fowing 41-15RD,Continue
12114/2007 22:00 dumping sand buster 1275 37 19 1049 57 71 1.000 0.568 1700.45 6076.97 553.92 2642.85
Continue Fowing 41-15RD,Continue
12/14/2007 22:30 dumping sand buster 1275 37 19 1049 57 72 1.000 0.568 1697.87 6112.34 706.56 2657.57
Estimated Fluid Rate,Continue
12/14/2007 23:00 dumping sand buster 1275 37 19 1049 57 72 1.000 0.568 1697.87 6147.71 6~6.24 2670.20
Estimated Fluid Rate,Continue
12/14/2007 23:30 dumping sand buster 1275 35 19 1049 62 72 1.000 0.568 1770.83 6184.61 302.40 2676.50
Continue Fowing 41-15RD,Continue
12/15/2007 0:00 dumping sand buster 1275 34 19 1050 57 77 1.000 0.568 1686.12 6219.73 605.28 2689.11
Continue Fowing 41-15RD,Continue
12/15/2007 0:30 dumping sand buster 1275 34 19 1049 56 77 1.000 0.568 1670.36 6254.53 806.88 2705.92
~ 12/15/20071:00 Increased Choke to 22/64
1275
33
19
1047
48
76
1.000
0.568
1544.73
6286.71
706.08
2720.63
~ Increased Choke to 32/64
12/15/20071:30 1200 30 22 1046 50 77 1.000 0.568 1575.77 6319.54 696.00 2735.13
Increased Choke to 64/64
1211512007 2:00 1160 25 32 1044 60 78 1.000 0.568 1721.90 6355.42 604.80 2747.73
Increased Choke full open 128 bean
12/15/2007 2:30 1140 22 64 1010 60 77 1.000 0.568 1514.11 6386.96 806.88 2764.54
Continue Fowing 41-15RD,dumping
12/15/2007 3:00 sand buster 1120 23 128 1046 65 77 1.000 0.568 1796.86 6424.39 806.88 2781.35
ASRC Pumping MEOH @ Well
12/15/2007 3:30 Head,Reduced Choke to 64/64 1110 29 64 1100 80 78 1.000 0.568 2047.32 6467.05 663.84 2795.18
Decreased Choke to 24/64
12/15/2007 4:00 1110 34 32 1080 65 79 1.000 0.568 1823.74 6505.04 705.60 2809.88
Continue Fowing 41-15RD dumping
12115/2007 4:30 sand buster 1110 35 24 1060 66 79 1.000 0.568 1818.69 6542.93 555.36 2821.45
Continue Fowing 41-15RD dumping
12/15/2007 5:00 sand buster 1110 35 24 1050 62 79 1.000 0.568 1753.41 6579.46 655.20 2835.10
Decreased Choke to 22/64
12/15/2007 5:30 1110 35 24 1050 63 79 1.000 0.568 1767.50 6616.28 622.56 2848.07
Continue Flowing 41-15RD, Dumped
1 211 5/2007 6:00 sand buster, 1110 35 22 1050 62 79 1.000 0.568 1753.41 6652.81 1211.04 2873.30
Continue Flowing 41-15RD, Dumped
12/15/2007 6:30 sand buster, 1110 35 22 1050 62 79 1.000 0.568 1781.48 6689.93 806.88 2890.11
~
•
Page 9
coMPaNY.• Marathon Oil Company
EXPRO ~ ' FIE~D: Sterling Unit
SURFACE WELL TESTING REPORT s~~. >~~~~~': ,~~~~ LEASE: Sport Lake
~-
.:.
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'
'
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WELL#: 41-15RD Support 43-9x
Co. REP.: Mickey Mullins
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Continue Flowing 41-15RD, Dumped
12115I2007 7:00 sand buster, 1110 36 22 1050 65 79 1.000 0.568 1795.36 6727.33 706.56 2904.83
Continue Flowing 41-15RD, Dumped
12/15/2007 7:30 sand buster, 1110 36 22 1060 66 79 1.000 0.568 1818.69 6765.22 554.40 2916.38
Continue Flowing 41-15RD, Dumped
12/15/2007 8:00 sand buster, 1110 36 22 1060 63 79 1.000 0.568 1776.85 6802.24 762.24 2932.26
Continue Flowing 41-15RD, Dumped
12/1512007 8:30 sand buster, 1110 36 22 1050 63 79 1.000 0.568 1767.50 6839.06 756.48 2948.02
Continue Flowing 41-15RD, Dumped
12/15/2007 9:00 sand buster, 1110 37 22 1050 64 79 1.000 0.568 1781.48 6876.17 548.64 2959.45
Continue Flowing 41-15RD, Dumped
12/15/2007 9:30 sand buster, 1110 38 22 1050 64 79 1.000 0.568 1781.48 6913.29 653.76 2973.07
Continue Flowing 41-15RD, Dumped
1 2/1 512007 1 0:00 sand buster, 1110 38 22 1050 63 79 1.000 0.568 1767.50 6950.71 952.80 2992.92
Estimated Fluid Rate,Continue
1 211 512007 1 0:30 dumping sand buster 1110 39 22 1050 62 79 1.000 0.568 1753.41 6986.64 718.08 3007.88
Continue Flowing 41-15RD, Dumped
12I1512007 11:00 sand buster, 1110 39 22 1050 62 80 1.000 0.568 1750.85 7023.12 806.88 3024.69
Continue Flowing 41-15RD, Dumped
12115I2007 1130 sand buster, 1115 40 22 1050 62 80 1.000 0.568 1750.85 7059.59 604.80 3037.29
Continue Flowing 41-15RD, Dumped
12115I2007 12:00 sand buster, 1140 40 22 1045 64 80 9.000 0.568 1774.17 7096.56 603.36 3049.86
Continue Flowing 41-15RD, Dumped
12/15/2007 12:30 sand buster, 1140 40 22 1045 62 80 1.000 0.568 1746.21 7132.93 702.24 3064.49
Continue Fiowing 41-15RD, Start43-
12/15/2007 13:00 9X WHP 1150 41 510 22 1045 63 80 1.000 0.568 1760.25 7169.61 903.36 3083.31
Continue Flowing 41-15RD, Dumped
12/15/2007 13:30 sand buster, 1150 41 510 22 1045 63 80 1.000 0.568 1760.25 7206.28 514.56 3094.03
Continue Flowing 41-15RD, Dumped
12/15/2007 14:00 sand buster, 1150 41 510 22 1045 63 80 1.000 0.568 1760.25 7242.95 706.56 3108.75
Continue Flowing 41-15RD, Dumped
1 211 5/2007 14:30 sand buster, 1150 41 510 22 1045 64 81 1.000 0.568 1771.60 7279.86 755.52 3124.49
Continue Flowing 41-15RD, Dumped
1 211 512007 1 5:00 sand buster, 1150 41 510 22 1045 62 81 1.000 0.568 1743.68 7316.19 902.88 3143.30
Continue Flowing 41-15RD, Dumped
12/15/2007 15:30 sand buster, 1150 41 510 22 1045 62 80 1.000 0.568 1746.21 7352.56 501.60 3153.75
Continue Flowing 41-15RD, Dumped
12l15/2007 16:00 sand buster, 1150 40 510 22 1045 62 80 1.000 0.568 1746.21 7388.94 559.20 3165.40
Continue Flowing 41-15RD, Dumped
12/15/2007 16:30 sand buster, 1150 40 510 22 1045 61 80 1.000 0.568 1732.06 7425.03 486.24 3175.53
Continue Flowing 41-15RD, Dumped
12/15/2007 17:00 sand buster, 1150 40 510 22 1045 63 80 1.000 0.568 1760.25 7461.70 676.80 3189.63
•
~
Page 10
CoMPANY.• Marathon Oil Company
EXPRO ' FIELD: Sterling Unit
SURFACE WELL TESTING REPORT f~~. >~~~~~I, ;~ ~~ : LEASE: Sport Lake
~
~
~~~~~ WELL#: 41-15RD Support 43-9x
~ '~"~~
co. REP.: Mickey Mul/ins
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Continue Plowing 41-15RD, Dumped
12/15/2007 17:30 sand buster, 1150 40 510 22 1045 61 80 1.000 0.568 1732.06 7497.78 661.92 3203.42
Estimated Fluid Rate,Continue
12/15/2007 18:00 dumping sand buster 1150 40 510 22 1045 65 80 1.000 0.568 1787.99 7535.03 605.76 3216.04
Increased choke to 24/64
12/15/200718:30 1150 40 510 22 1045 53 80 1.000 0.568 1614.41 7568.67 704.64 3230.72
Continue Fiowing 41-15RD, Dumped
12I15/2007 19:00 sand buster, 1150 40 510 24 1030 62 80 1.000 0.568 1732.25 7604.76 539.52 3241.96
Continue Flowing 41-15RD, Dumped
1 2115/2007 1 9:30 sand buster, 1150 40 510 24 1035 60 80 1.000 0.568 1708.25 7640.35 612.96 3254.73
Continue Flowing 41-15RD, Dumped
12/T5/2007 20:00 sand buster, 1150 40 510 24 1035 62 80 1.000 0.568 1736.91 7676.53 710.88 3269.54
Estimated Fluid Rate,Continue
12/1512007 20:30 dumping sand buster 1150 39 510 24 1035 61 80 1.000 0.568 1722.84 7712.42 595.20 3281.94
Estimated Fluid Rate,Continue
12/15/2007 21:00 dumping sand buster 1150 39 510 24 1040 61 80 1.000 0.568 1727.45 7748.41 663.36 3295.76
Continue Flowing 41-15RD, Dumped
12/15/2007 21:30 sand buster, 1150 39 510 24 1035 59 79 1.000 0.568 1696.80 7783.76 665.28 3309.62
Continue Flowing 41-15RD, Dumped
12/15/2007 22:00 sand buster, 1150 39 510 24 1035 60 79 1.000 0.568 1711.13 7819.41 697.44 3324.15
Continue Flowing 41-15RD, Dumped
1 211 5/2007 22:30 sand buster, 1150 39 510 24 1035 61 79 1.000 0.568 1722.84 7855.30 602.88 3336.71
Continue Flowing 41-15RD, Dumped
1211512007 23:00 sand buster, 1150 39 510 24 1035 62 79 1.000 0.568 1739.44 7891.54 618.24 3349.59
Estimated Fluid Rate,Continue
12/1512007 23:30 dumping sand buster 1150 36 510 24 1035 60 79 1.000 0.568 1711.13 7927.19 660.48 3363.35
Continue Flowing 41-15RD, Dumped
12/16/2007 0:00 sand buster, 1150 37 510 24 1030 60 79 1.000 0.568 1706.53 7962.74 507.36 3373.92
Continue Flowing 41-15RD, Dumped
12/16/2007 0:30 sand buster, 1150 38 510 24 1030 60 79 1.000 0.568 1706.53 7998.30 977.28 3394.28
Continue Flowing 41-15RD, Dumped
12116/2007 1:00 sand buster, 1150 38 510 24 1030 60 79 1.000 0.568 1706.53 8033.85 443.52 3403.52
Continue Flowing 41-15RD, Dumped
12I1612007 1:30 sand buster, 1150 38 500 24 1030 58 79 1.000 0.568 1677.83 8068.$0 564.00 3415.27
Increased choke to 26164, Estimated
12/16/2007 2:00 Fluid Rate 1150 38 490 24 1015 60 80 1.000 0.568 1690.26 8104.02 702.72 3429.91
Continue Flowing 41-15RD, Dumped
12/16/2007 2:30 sand buster, 1150 39 490 26 1025 60 80 1.000 0.568 1699.47 8139.42 568.32 3441.75
Continue Flowing 41-15RD, Dumped
12/16/2007 3:00 sand buster, 1150 39 500 26 1035 62 80 1.000 0.568 1736.91 8175.61 694.72 3454.14
Continue Flowing 41-15RD, Dumped
12116/2007 3:30 sand buster, 1150 39 500 26 1030 62 80 1.000 0.568 1732.25 8211.70 943.68 3473.80
.
•
Page 11
CoMPANY: Marathon Oil Company
__ _ __
EXPRO ~' FIELD: Sterling Unlt
SURFACE WELL TESTING REPORT F~~. >~~~~~, ,~~~~ ' LEASE: Sport Lake
'
~~
`~"~~
~'~~ wE~~#: 41-15RD Support 43-9x
co. ReP.: Mickey Mullins
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Continue Flowing 41-15RD, Dumped
12/16I2007 4:00 sand buster, 1150 38 500 26 1030 63 78 1.000 0.568 1751.26 8248.18 621.12 3486.74
Estimated Fluid Rate,Continue
12/1612007 4:30 dumping sand buster 1150 38 500 26 1030 59 78 1.000 0.568 1694.71 8283.49 734.40 3502.04
Continue Flowing 41-15RD, Dumped
12/1612007 5:00 sand buster, 1150 38 500 26 1020 55 80 1.000 0.568 1622.66 8317,29 355.68 3509.45
Continue Flowing 41-15RD, Dumped
12/1612007 5:30 sand buster, 1150 37 500 26 1035 60 80 1.000 0.568 1708.65 8352.89 731.52 3524.69
Continue Flowing 41-15RD, Dumped
1211612007 6:00 sand buster, 1155 39 500 26 1040 60 80 1.000 0.568 1773.22 8388.58 888.96 3543.21
Estimated Fluid Rate,Continue
12116/2007 6:30 dumping sand buster 1155 39 500 26 1040 60 79 1.000 0.568 1715.72 8424.33 658.56 3556.93
Continue Flowing 41-15RD, Dumped
12/16/2007 7:00 sand buster, 1155 39 500 26 1040 58 79 1.000 0.568 1686.86 8459.47 659.52 3570.67
Continue Flowing 41-15RD, Dumped
12/16/2007 7:30 sand buster, 1155 39 500 26 1040 60 79 1.000 0.568 1715.72 8495.21 732.48 3585.93
Continue Flowing 41-15RD, Dumped
12/16/2007 8:00 sand buster, 1155 39 500 26 1040 62 79 1.000 0.568 1744.10 8531.55 648.96 3599.45
Continue Flowing 41-15RD, Dumped
12/16/2007 8:30 sand buster, 1155 39 500 26 1040 57 79 1.000 U.568 1672.24 8566.39 555.84 3611.03
Estimated Fluid Rate,Continue
12116/2007 9:00 dumping sand buster 1150 39 500 26 1040 60 79 1.000 0.568 1715.72 8602.13 645.60 3624.48
Continue Flowing 41-15RD, Dumped
12/16/2007 9:30 sand buster, 1150 39 500 26 1040 60 79 1.000 0.568 1715.72 8637.88 803.52 3641.22
Continue Flowing 41-15RD, Open
1 2/1 6/2007 1 0:00 Choke to 27/64 1150 40 500 26 1040 59 79 1.000 0.568 1701.35 8673.32 641.76 3654.59
Continue Flowing 41-15RD, Dumped
1 211 612007 10:30 sand buster, 1150 40 500 27 1040 59 79 1.000 0.568 1701.35 8708.76 667.20 3668.49
Continue Flowing 41-15RD, Dumped
12/16/2007 11:00 sand buster, 1150 40 500 27 1040 60 79 1.000 0.568 1715.72 8744.51 600.96 3681.01
Continue Flowing 41-15RD, Dumped
12/16/2007 11:30 ~ sand buster, 1150 40 500 27 1040 59 80 1.000 0.568 1698.88 8779.90 617.76 3693.88
Estimated Fluid Rate,Continue
12/16/2007 12:00 dumping sand buster 1150 40 500 27 1040 60 80 1.000 0.568 1713.22 8815.59 624.96 3706.90
Continue Flowing 41-15RD, Dumped
12/16/2007 12:30 sand buster, 1150 40 500 27 1040 60 80 1.000 0.568 1713.22 8851.29 606.72 3719.54
Continue Flowing 41-15RD, Dumped
1 2/1 6/2007 13:00 sand buster, 1150 40 500 27 1040 60 80 1.000 0.568 1773.22 8886.98 589.44 3731.82
Continue Flowing 41-15RD, Dumped
12/16/2007 13:30 sand buster, 1150 40 500 27 1040 60 80 1.000 0.568 1713.22 8922.67 568.80 3743.67
Continue Flowing 41-15RD, Dumped
12/16/2007 14:00 sand buster, 1950 40 500 27 1D40 60 80 1.000 0.568 1713.22 8958.36 658.56 3757.39
•
•
Page 12
CoMPANY; Marathon Dil Company
EXPRO ~" ' ' FIE~o: Sterling Unit
, ,.
SURFACE WELL TESTING REPORT ~~-. >~~~~~ ,~~~~ LEASE; Sport Lake
~ '?'~"~~ ~~~~ wELL#: 41-15RDSupport43-9x
CO. REP.: MiCkey Mullins
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Estimated Fluid Rate,Continue
1 2/1 6/2007 14:30 dumping sand buster 1140 40 500 27 1040 59 80 1.000 0.568 1698.88 8993.76 600.00 3769.89
Continue Flowing 41-15RD, Open
12/16/2007 15:00 Choke to 28/64 1125 40 500 27 1040 60 80 1.000 0.568 1713.22 9029.45 653.76 3783.51
Continue Flowing 41-15RD, Dumped
12/16/2007 15:30 sand buster, 1125 40 500 28 1035 59 79 1.000 0.568 1696.80 9064.80 528.00 3794.51
Continue Flowing 41-15RD, Dumped
12I16I2007 16:00 sand buster, 1125 40 500 28 1035 59 79 1.000 0.568 1696.80 9100.15 727.20 3809.66
Continue Flowing 41-15RD, Open
12/16/2007 16:30 Choke 30/64 112p 40 50~ 28 1035 59 79 1.000 0.568 1696.80 9135.50 547.20 3821.06
Continue Flowing 41-15RD, Dumped
12I16I2007 17:00 sand buster, 1110 40 500 30 1035 59 79 1.000 0.568 1696.80 9170.85 561.12 3832.75
Continue Flowing 41-15RD, Dumped
12/16/2007 17:30 sand buster, 1110 40 500 30 1035 60 79 1.000 0.568 1711.13 9206.50 733.92 3848.04
Estimated Fluid Rate,Continue
12/16/2007 18:00 dumping sand buster 1110 39 500 30 1030 60 78 1.000 0.568 1706.53 9242.05 605.76 3860.66
Increased choke to34/64
12I161200718:30 1110 39 500 30 1030 58 75 1.000 0.568 1787.70 9279.29 688.32 3875.00
Continue Flowing 41-15RD, Dumped
12/16/2007 19:00 sand buster, 1110 39 500 34 1030 56 72 1.000 0.568 1665.76 9314.00 877.92 3893.29
Incresed choke to 38/64
12/16/200719:30 1110 40 500 38 1030 58 70 1.000 0.568 1700.39 9349.42 281.76 3899.16
Continue Flowing 41-15RD, Dumped
12/16/2007 20:00 sand buster, 1110 41 500 38 1030 55 69 1.000 0.568 1658.32 9383.97 677.76 3913.28
Incresed choke to 42I6A
12/16/2007 20:30 1110 41 500 38 1030 57 66 1.000 0.568 1696.03 9419.30 677.28 3927.39
Estimated Fiuid Rate, Incresed
12I1612007 21:60 choke to A4164 1110 40 500 42 1030 60 73 1.000 0.568 1721.68 9455.17 655.20 3941.04
Estimated Fluid Rate, Incresed
12/16/2007 21:30 choke to 48/64 1100 40 500 44 1030 60 72 1.000 0.568 1724.27 9491.09 663.36 3954.86
Continue Flowing 41-15RD, Dumped
12116/2007 22:00 sand buster, 1100 40 500 48 1030 56 70 1.000 0.568 1670.80 9525.90 601.44 3967.39
Continue Flowing 41-15RD, Dumped
12/16/2007 22:30 sand buster, 1090 38 500 48 1030 58 72 1.000 0.568 1695.26 9561.22 554.40 3978.94
Continue Flowing 41-15RD, Dumped
12/16/2007 23:00 sand buster, 1090 41 500 48 1030 60 69 1.000 0.568 1732.12 9597.31 688.32 3993.28
Continue Flowing 41-15RD, Dumped
12I16I2007 23:30 sand buster, 1090 40 500 48 1030 59 69 1.000 0.568 1717.61 9633.09 614.40 4006.08
Estimated Fluid Rate,Continue
12/17/2007 0:00 dumping sand buster 1090 39 500 48 1030 55 63 1.000 0.568 1673.81 9667.96 629.76 4019.20
Estimated Fluid Rate, Choke Full
12/17/2007 0:30 Open 128 1090 39 500 48 1030 55 62 1.000 0.568 1676.45 9702.89 622.08 4032.16
~
•
Page 13
COMPANY: Marathon Oil Company
EXPRO ~~` ,~~~ FIELD: Sterling Unit
SURFACE WELL TESTING REPORT r~-. >~~~~~;, ; „~ ! l,eASE: Sport Lake
j~~~~. ~~~ WELL#: 41-15RD SuppOrt 43-9x
co. REP.: Mickey Mullins
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12117/2007 1:00 Continue Flowing 41-15RD, Dumped
sand buster,
1090
39
500
128
1030
50
60
1.000
0.568
1603.48
9736.29
622.08
4045.12
12/17/2007 1:30 Continue Flowi~g 41-15RD, Dumped
sand buster,
1090
39
500
128
1030
52
60
1.000
0.568
1635.26
9770.36
554.40
4056.67
12/17/2007 2:00 Continue Flowing 41-15RD, Dumped
sand buster,
1090
39
500
128
1030
55
62
1.000
0.568
1676.45
9805.29
704.16
4071.34
12/17/2007 2:30 Continue Flowing 41-15RD, Dumped
sand buster,
1090
39
500
128
1030
55
65
1.000
0.568
1668.58
9840.05
451.20
4080.74
12/17/2007 3:00 Continue Flowing 41-15RD, Dumped
sand buster,
1090
40
500
128
1030
54
64
1.000
0.568
1655.91
9874.55
700.80
4095.34
12/17/2007 3:30 Continue Fiowing 41-15RD, Dumped
sand buster,
1090
40
500
128
1030
55
65
1.000
0.568
1668.58
9909.31
759.84
4111.17
12/17/2007 4:00 Continue Flowing 41-15RD, Dumped
sand buster,
1090
39
500
128
1030
58
65
1.000
0.568
1713.51
9945.01
486.24
4121.30
1 2/1 7/2007 4:30 Estimated Fluid Rate,Continue
dumping sand buster
1090
38
500
128
1030
55
64
1.000
0.568
1671.19
9979.82
663.36
4135.12
,
12/17/2007 5:00 Continue Flowing 41-15RD, Dumped
sand buster,
1090
38
500
128
1025
55
65
1.000
0.568
1664.00
10014.49
402.24
4143.50
12117/2007 5:30 Continue Flowing 41-15RD, Dumped
sand buster,
1090
39
500
128
1025
57
66
1.000
0.568
1691.39
10049.73
651.36
4157.07
12/17(2007 6:00 Continue Flowing 41-15RD, Dumped
sand buster,
1090
39
500
128
1025
55
66
1.000
0.568
1676.47
10084.65
753.12
4172.76
~
~
Page 14
•
~ ~ ~ k 3p ~-~ yg]{~ )`3{~ jQj
`},R~ ~ ~ ~ ~ ~ ~ +~ ! ~~ p k"'^~ ~ { ; t ^ y ~ ~~ . ~ .
f ~
~ ~ ~ ~ ~ ~~~ ~ ~1 ~~ ~~ ~ ~
ALASSA OII,1~1~TD G~5
co~SERVAr~or~ corn-IIS5~o~
Ken Walsh
Senior Production Engineer
Marathon Oil Company
PO Box 1949
Kenai, AK 99611-1949
u
SARAH PAL/N, GOVERNOR
333 W 7th AVENUE, SUITE 100
ANCHORAGE, ALASKA 99501-3539
PHONE (907) 279-1433
FAX (907) 276-7542
Re: Sterling Gas Field, Sterling Gas Pool, Sterling Unit 43-9X
Sundry Number: 307-371
Dear Walsh:
Enclosed is the approved Application for Sundry Approval relating to the
above referenced well. Please note the conditions of approval set out in the
enclosed form.
When providing notice for a representative of the Commission to witness any
required test, contact the Commission's petroleum field inspector at (907)
659-3607 (pager).
As provided in AS 31.05.080, within 20 days after written notice of this
decision, or such further time as the Commission grants for good cause
shown, a person affected by it may file with the Commission an application
for rehearing. A request for rehearing is considered timely if it is received by
4:30 PM on the 23rd day following the date of this letter, or the next working
day if the 23rd day falls on a holiday or weekend. A person may not appeal
a Commission decision to Superior Court unless rehearing has been
requested.
DATED this ~day of December, 2007
Encl.
;=~~- v.~3
*
r
•
Marathon
MARATHON C1i1 Campany
December 12, 2007
Mr. Jim Regg
Alaska Oil & Gas Conservation Commission
333 W 7~' Ave
Anchorage, Alaska 99501
Reference: 10-403 Sundry Notice
Field:
Well:
PTD:
Ste~iing Gas Field
SU 43-9X
207-073
Dear Mr. Regg,
•
Marathon Oil Company
Alaska Asset Team
P.O. Box 1949
Kenai, AK 99611
Telephone 907/283-1326
Fax 807/283-1350
~~~~~~~~
E~~r ~ 2 ~~~7
Alaska Qil ~ ~;a~ Cnns> ~~~r~mi~~i~~
AnChQr~ge
Enclosed please find an Application for Sundry Approvals form 10-403 and a current
wellbore diagram for Sterling Unit well 43-9X. Request for approval is being made to
vent gas during operations to establish gas flow from the long string side of this dual
gravel pack completion in the Sterling B4 Sand.
You granted verbal approval to Marathon to continue to vent gas from this well during our
telephone conversation the afternoon of December 11, 2007. This sundry request is to
vent gas for five full days up to a maximum vent volume of 10 MMSCF beginning on
December 11. Specifics related to this request can be found in an email that I sent to
you on December 11.
If you require further information, you can reach me at 907-394-3060 or by e-mail at
kdwalshfa~marathonoil.com. Alternatively you may contact Kevin Skiba in our Kenai, AK
field office at 907-283-1371 or by e-mail at kskiba@marathonoil.com.
Sincerely,
I~:~D w ~~
Ken D. Walsh
Senior Production Engineer
Enclosures: 10-403 Sundry Notice
Wel1 Schematic
cc: AOGCC
Kenai Well File
Houston Well File
K. Walsh
K. Skiba
'~
~~ 'll~ /I~'~~ ~J~~ ,2,\~~~r~~ °~~~~
, ~~~ ~ STATE OF ALASKA ~~~~~
'~~ ALASKA OIL AND GAS CONSERVATION COMMISSION ~ ~~, ~ 1~~~0~
D~ ~3' ~~` ~ APPUGATION FQR SUNQRY APPRCIVALS ~~~`'~
~~7 2o aac 2s.z~ ~ ~I~~k~ ~il & G~s ~~n~e C~~~~~~i~n
1. Type of Request: Abandon ^ Suspend ^ OperatiQ~a! shufcbwn ^ PerforaEe ^ Waiver I~C ~11'c~g Other ~
Alter casing ~ Repair well ^ Plug Perforations ^ Stimutate ^ Time EMension ^ Venting
Change approved program ~ Pull Tubing ^ Perforate New Poa! ^ Re-enter Suspended Well ~
2. Qperator Name:
Marathon Oil Campany 4. Current Welt qass: 5. Permit to Drill Number.
'
Deveb
pment ~ Exploratory ~ 207-073
3. Address: pQ gpX 1949 Stra6graphic ~ See-vice ~ 6. API Number:
Kenai Alaska, 99611-1949 52-133-20569-00-00
7. If perForating, dosest approach in pool(s} oper~ed by this operation to nearest 8. Well Name and Number.
property line where ownership ar landownership changes:
Spacing Exception Required? Yes ^ No 0 Sterfing Unit 43-9X `
9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): ,
A- Q28063 ' 245' (21' AGL) Sterling FieEd / Sterling Poo!
12• PRESENT WELL CONDITION SUMMARY
Total Depth MD (ft): Total Depth TVD (ft): Effective ~epth MD (ft): Effective Depth TVD (ft}: Plugs (measured): Junk (measured):
6,185' ~ 5,698' 6,114' 5,627' NA AIA
Casing l.ength Size MD ND Burst Gollapse
Structural
Conductor 82` 20" 103' 1Q3' 3,06~ psi 1,500 psi
Surface 1,969' 13-3/8" 1,990' 1,870' 3,450 psi 1,950 pst
Intermediate 6,153' 9-5/8" 6,174' S,687' 5,750 psi 3,090 psi
ProducBon
Liner
Perforatlon Depth MD (ft): Pertoration Depth TVD (ft): Tubing Size: $g 2_g/g^ Tubing Grade: ~-g0 Tubing MD (ft): 5,5$8'
5,724' - 5,776' gross 5,231.5' - 5,289.5' LS 2-7/8" L-80 5,627'
Packers and SSSV Type: gaker GT Dual Packer Fackers and SSSV MD (ft): 5,588'
Baker SC-1 Gravel Pack Packer 5,627'
Baker SC-1 Gravel Pack Packer 5,738'
Baker Model B Sump Packer 5,784'
13. Attachments: Description Summary of Proposal ~ 14. Well Class after proposed work:
Detailed Operations Program Q BOP Sketch ^ Exploratory ^ Development Q Service ^
15. Estimated Date for 16. Well Status after proposed wark:
Commencing Operafions: 12/11/2007 Oil ~ Gas ^~ Plugged ^ Abandoned ^
17. Verbal Approval: Date: 12/11/2007 WAG ~ GINJ ^ WINJ ^ WDSPL ~
Commission Representative: Jim Regg
18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba (90~ 283-7371
Printed Name Ken D. Walsh Title Senior Production Engineer
Signature (~ ,~ r ~ Phone (907) 283-1311 Date December 12, 200T
~,,"
COMMISSION USE ONLY
Conditions of approval: Notif
Commission so that a re
resentative ma
witness Sund
Number
~~ ^~ ~ l
y
p
.
y
ry
Piug Integrity ~ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ~
Other: ~~{;~~Z,p,rl ~~~ ~~ ~~ ~~S ('by1;~l~ ! Z~ I"~?.~JG'~
SubsequentFortnRequired: Sr~L~v~E ~~~~v~c~~'~jn'~C~C``,~~ ~D-ya~-
APPROYED BY
Approved by: GOMMISSIONER THE COMMISSION Date: /p~-~,~' Q~
Form 10-403 Revised 06/2006 ([~ ~~~;~ ~ Submit in Duplicate
V R . i _ ~ ~~~_ ~~~~ ~ ': 200~
/
• •
SU 43-9X (Proposed WBD)
M Co-Production Well Dual Gas Lift
MAi~TYOM I I I II ~ ~~I I I I
J ~ ICmt w/ 280 bbls of Type 1 cmt I
Shortstrina - 2.375", 4.7#, L-80, IBT-M Tubing
(ID = 1.995")
GT dual packer w/ 60K shear ring @ 5588'
f ~- i
-
XN-nipple Q 5600' (ID = 1.75')
W ireline re-entry guide at 5605' ,~ ~
," ~ ,
SAND
724' - 5730' (6') r -~
~ ~~r -1`; '`
t ~; - 4 ~.:.t T i,'
., _
. '. _ . ..~. . .
- 5776' (10')
r~2 d,~ ~~~ w*.•.
. +
.. . s `'~ .._ 3 :: . t_'~: .~ . .
I I -~-~'-~T ~
-6114' PBTD
~Vi_gr - 2.875`, 6.4#, L-80, EUE Brd Tbg (ID =
.~
s@ 1740', 2943', 3884', 4558', 5030', 5433' ,
~ GT Dual packer w/ 60k shear ring @ 5588' I
8aker SC-1 gravel pack packer (a~ 5627'
Knodc out isolation valve Q 5680'
5-1/2" x 18' x 12 pa BakerWeld 140 Screen (o~ 5720'
in1c ~. 2-7/8" x
5724'
- X-nipple @ 5736' (ID = 2.31
o-uz x ie~ x iz ga tiakervveid iau screen (N 5764'
Baker Model D sump packer @ 5784'
~ 9-5/8" 40ppf, L80 BTC @ 6174' (ID =
8.835")
Cmt w/ 210 sx (78.6 bbls) 12.5 ppg
Class G Lead cmt followed by 400 sx
82.6 bbls 15.8 Class G tail cmt.
= 1980
@ 5035' SSND
= 1990 ~sia
Well Name 8, Number: SU 43-9X Lease Sterling Unit
County or Parish: Kenai StatelProv. Alaska Country:
Perfarations: (MD) 5724' - 5730' (6') SS 8 5766' - 5776' (10') LS (ND) 5237' - 5243' SS 8 5280' - 5290' LS
AnglelPerfs 0 deg Angle @KOP and Depth 0 deg @ 200' KOP ND 200'
BHP: 1980 BHT: 0 Completion Fluid: 6% KCL
FW HP: FBHP: FW HT: FBHT: Other:
Date Completed: RKB:
Prepared By: C Meese Last Revision Date: 11/09/07
FW: Sterling Unit Field: Gas Vent~ ~ ~ Page 1 of 2
~
t Regg, James B (DOA)
From: Waish, Ken [kdwalsh@marathonoil.comJ ` 'Z ( `~i~~
Sent: Tuesday, December 11, 2007 4:35 PM ~~ ~
To: Regg, James B (DOA)
Cc: Ibele, Lyndon; Mullin, Mickey; Skiba, Kevin J.; Maunder, Thomas E(DOA)
Subject: FW: Sterling Unit Field: Gas Venting
Jim,
As a follo~nr-up to s~ur telephc~ne conversation regardir~g this matter and at yaur request, IVlarathcsn wili
issue a 10-403 s~ndry tarriorrav~r ~o the A(JGCC t1~at st~tes that yc~u provide~ verbal approval to
cantinue venting gas per Marathon's request beiow.
C~~l -~w~ (~:-~ U.~~t ~
From: Walsh, Ken
Sent: Tuesday, December 11, 2007 4:10 PM
To: AOGCC (jim_regg@admin.state.ak.us)
Cc: Ibele, Lyndon; Mullin, Mickey; Skiba, Kevin J.; Maunder, Thomas E(DOA)
Subject: Sterling Unit Field: Gas Venting
T~~ ~ituatic~n is ~~ fc~~lt~vvs;
~r~.~:~,w r~~~ ~~+ ~Z j~~ ~L~ .~
~
~~.~'~L~ ~1~~"j~~r~
~
J ct~ ~~CS ~
,
~1,~. 43_<.1X ~~,i.~il i2~~~~~~.
1~F,~a~<~-~ ~ --~, ~
~ Sccc.sS ~(~.~ s
'G°J 4~~; ~ ~ ~L~ IZ'~7~~'7
1 l=~.G r~ ~
t C~ C~ i~ ~
~~G~ C.i"~ k-.S ~.p
~~ ~C~ ~r.r ~ !
C; J`C~~" ~1.~'C._1~
, ~ W-.~ °'~ ~~~(~~.~,SC~;..~y
_9
- It was decidsd to meter the ~~s ~roduc~ic~~ frc~m the ~LJ 41-~~rd ~rvel~ (PTD #207-08$0 ) thrc~ugh the
~xpro V1~ell Tester's equipment tc~ ~se ~s ~he rr~c~tive g~s source t~ ~ift ~~e long strint~. It v+r~s
~nticipat~d th~t ~raductic~~, k~c~~h r~rater and ~as, vvould b~ ro~~ed t~r~ug~ #he pre~ductior~ equipmenf
without hav~ng to ver~t any o~ th~ c~as. Un~c~~tunat~~y, ~he s~arfac~ faciliti~s w~r~ ~an~~~~ ~o hanc~l~ th~
p~odt~c~i~n sfu~s and ~nras ~hut c~c~r~n irnmediafiely aft~r di~c~v~rsr~g a~igh de~nr ~c~ir~t at th~ sales
12/17/2007
FW: Sterling Unit Field: Gas Vent~
p~int.
~
Page 2 of 2
C~ur question is dcaes t~is situa~ic~n ree~uire 10-40~ approval far the v~l~ames ~nd rates
aforem~ntioned? If so, c~n Maratl~on continue venting t~is g~s as propc~sed above vuith your verbal
~~pro~al and submi~ a~ 0-403 s~r~dry tomorraw as follow ~ap to the verbal? Mara~hc~n did not
v anticipat~ this situ~tior~ and t~erefc~re c~id nat request a~~raval for ve~~ing the gas previously.
Z
K~n Q. alsh
Seni~r Pr~sductior~ Engine~r
arath€~n C1ri Cc~~pa~ay~-~tia~ka Asset T~am
9~7-2~~-13~ 1 {office}
9U7-39~-3{~60 (ceil}
12/17/2007
SU 41-15RD & SU 43-9x 10-42~dry Status ~ Page 1 of 1
Maunder, Thomas E (DOA)
From: Maunder, Thomas E (DOA)
Sent: Thursday, December 06, 2007 3:23 PM
To: 'Skiba, Kevin J.'
Cc: Ibele, Lyndon; Rang, Craig L.; Donovan Jr, Dennis M.; Walsh, Ken
Subject: RE: SU 41-15RD (207-088) & SU 43-9x (207-073) 10-421 Sundry Status
Kevinw
Thanks much for the update. I will place a copy of this message in the files.
Call or message with any questions. Please remember to include the PTD numbers in
the message header. It helps with the filing.
Tom Maunder, PE
AOGCC
From: Skiba, Kevin J. [mailto:kskiba@marathonoil.com]
Sent: Thursday, December 06, 2007 3:13 PM
To: Maunder, Thomas E (DOA)
Cc: Ibele, Lyndon; Rang, Craig L.; Donovan Jr, Dennis M.; Walsh, Ken
Subject: SU 41-15RD & SU 43-9x 10-421 Sundry Status
Tom,
I wanted to update you on our progress status for the 10-421 Sundries for SU 41-15RD and SU 43-9x. A 4-point
test was perFormed on SU 41-15RD well resulting in erroneous data. We will have to retest the well after we work
through the issues that are preventing us from bringing it on production. We are still working to kick-off SU 43-
9x. A 4-point test will be perFormed once gas production stabiiizes from this well.
I will start working on the 10-421 Sundries, for both of these wells, once the proper data is available.
Thanks,
Kevin Slaba
Production Technician
Marathon Oil Company
Office (907) 283~1371
Cell (907) 394-1332
Fax (907) 283~1350
12/6/2007
,
MARATHON
• Al~a Asset Team
United States Production Operations
ar1th01~
ol~ C0111,9a11~/
August 23, 2007
Alaska Oil & Gas Conservation Commission
Attn: Howard Okland
333 W. 7`~' Avenue, Suite 100
Anchorage, AK 99501
RE: Marathon SU #43-9X - API 50-133-20569-00
CONFIDENTIAL
Dear Mr. Okland:
P.O. Box 3128
Houston, TX 77253
Telephone 713-296-3597
Fax 713-235-6322
Hand Delivery
Enclosed is one CD containing confidential digital well data for the above referenced well, as described on
the attached CD Contents document.
Please indicate your receipt of this data by signing below and returning one copy to my attention at the
letterhead address or fax to 713-235-6322.
Thank you,
~
~~~~
Courtney McElmoyl
Received by: "" ,- -~
aa~ -0~3
~
~. ~.~~:~:
~ 1533~f ~~~~ : ~
Date:
;f,~,, ~. ~ ,r~j~~
~
j 1':m 'v~
Enclosures =:1S~SC~ :
'" :T1iY:
~I~ ~ '=%'~"~ ~ "~
~~~~.~ ~/
,y3":~:~ v~~~
t ~ .
~ •wvw• s r~
AU G~, 4 2007 Marathon 0ii Cor~p~ny Pa~~.~ of 4
`-Aiaska 0il & Gas Co~s~ Comrmssion Operations Summ~~ Report
LegaTVllell Name: STERttI~~ ~JNIT 43-9X ~ /~
Common Well Name: STERLWG UNIT 43-9X ~~ -~I ~~ Spud Date:
Event Name: ORIGINAL COMPLETION Start: 7/1/2007 End:
Contractor Name: Rig Release: Group:
Rig Name: Rig Number:
Date ~rn''- To Hours,: ;~~ * ~~~ Phase Description of C3pera~ofns
7/25/2007 08:00 - 09:15 1.25 SAFETY MTG_ WRLN Arrive Sterling Pad. Sign in at rig. Hold PJSM and obtain Safe Work
Permit.
09:15 - 10:05 0.83 RURD ELEC WRLN MIRU equipment. PU Pump-in sub, and Grease head. PU CBU GR.
RIH
10:05 - 10:30 0.42 RUNPU ELEC WRLN Run free pipe pass @ 1000'-800'.
10:30 - 11:40 1.17 RUNPU ELEC WRLN RIH tag TD @ 6070' KB.
11:40 - 11:50 0.17 RUNPU ELEC WRLN Run repeat sections.
11:50 - 13:30 1.67 RUNPU ELEC WRLN Run main pass (radials)
13:30 - 14:03 0.55 RUNPU ELEC WRLN RIH.
14:03 - 15:40 1.62 RUNPU ELEC WRLN Run 2nd part of main pass(VDL). POOH.
15:40 - 16:10 0.50 RUNPU ELEC WRLN OOH.
16:10 - 16:20 0.17 SAFETY MTG WRLN Hold rig down Safety Meeting.
16:20 - 17:00 0.67 RURD ELEC WRLN RD. Sign out and leave location.
8/4/2007 11:00 - 11:30 0.50 SAFETY MTG_ CMPFLW Arrive Sterling Pad. Sign in at rig. Hold PJSM and obtain Safe Work
Permit.
11:30 - 14:45 3.25 RUNPU COIL CMPFLW Moved equipment from Beaver Creek #9 to this location in three trips.
Spotted in coil unit and N2 unit. Parked crane off the side of location.
14:45 - 15:00 0.25 SECUR WELL CMPFLW Signed out at Sterling Facility office. Left location.
8/5/2007 08:00 - 08:45 0.75 SAFETY MTG_ CMPFLW Arrive Sterling Pad. Sign in at rig. Hold PJSM and obtain Safe Work
Permit.
08:45 - 13:45 5.00 RURD COIL CMPFLW Rig up coil unit and Nitrogen combo pump truck. Roustabouts rigged up
flowback manifold to flowback tank.
14:45 - 18:00 3.25 TEST BOPE CTBG Function Test BOP's. BOP Pipe Rams and Blind Rams Function tested
ok. Test Accumulator. Pressure Test BOP Blind Rams to 250 psi/4500
psi. Accumulator and Both Low and High Pressure BOPE, Blind, Pipe
Ram, Choke, and Kill Lines. Test Held Pressure. Jim Regg with
AAOGC waived inspector for this test.
18:00 - 18:15 0.25 SECUR WELL CTBG Rig back coil injector. Signed out at the Sterling Pad office. Locked
the gates on the way out.
8/8/2007 07:00 - 08:00 1.00 SAFETY MTG_ CMPFLW Arrive Sterling Pad. Sign in at rig. Hold PJSM and obtain Safe Work
Permit.
08:00 - 09:00 1.00 RURD COIL CMPFLW PU ejector and stab on WH.
09:00 - 10:00 1.00 RURD COIL CTBG Operator let coil spool roll forward in craddle and a loose wrap became
wedge into bracket in cornor of frame.
10:00 - 11:00 1.00 REPAIR EQIP CTBG Cut 146' of coil off spool.
11:00 - 12:00 1.00 RURD COIL CTBG Install new dimple on conection. Pull test to 18k. Test good. Install
BHA.Set ejector up on well head.
12:00 - 12:10 0.17 RURD COIL CTBG Shell test to 1000 psi. Test good.
12:10 - 12:45 0.58 RUNPU COIL CTBG Open upper master. Open swab. RIH with Blanked off nozzle w/ 3-
3/8"jets.
12:45 - 13:02 0.28 RUNPU COIL CTBG @1470' Start N2 @ 700 scfm 1370 psi WH. 25.7 barrels in flow back
tank.
13:02 - 14:00 0.97 RUNPU COIL CTBG Tubing @ 1470' Pumping N2 @ 700 good returns to flowback tank.
Recqvered 46 bbls.
14:00 - 14:12 0.20 RUNPU COIL CTBG Tubing @ 1492' Pumping N2 750 scf WHP 1465 psi. recovered 89
bbis.
14:12 - 14:26 0.23 RUNPU COIL CTBG RIH to 2000'. N2 @ 750 WHP 1535 psi
14:26 - 14:45 0.32 RUNPU COIL CTBG RIH 2616'. Pumping N2 @750 scf. WHP 1600. Recovered 137 bbls
14:45 - 15:25 0.67 RUNPU COIL CTBG @ 2616'. Pumping N2 @750 scf. WHP 1593. Recovered 162 bbls.
95:25 - 15:55 0.50 RUNPU COIL CTBG RIH to 4500', WHP 1696 psi, Recovered 214 bbls
15:55 - 16:10 0.25 RUNPU COIL CTBG Tubing parked 4500', WHP 1718 psi, pumping N2 2 750 scf, 234
bbls reccovered
16:10 - 16:25 0.25 RUNPU COIL CTBG 4500', N2 750 scf, WHP 1740 psi, 249 bbls recovered.
Printed: 8/13/2007 2:5632 PM
• •
r. _ Marathon; 0il Company Pag~ 2 0~ 4
~ ,
t~~r~:~at~ons Summary Report
Legal Well Name: STERLING UNIT 43-9X
Common Well Name: STERLING UNIT 43-9X Spud Date:
Event Name: ORIGINAL COMPLETION Start: 7/1/2007 End:
Contractor Name: Rig Release: Group:
Rig Name: Rig Number:
Da~' Fram - To
Hours Code Code Phase ~ :~.
~e~cr~~ `;~ tio { r,~,a
:~..F
8/8/2007 16:25 - 18:39 2.23 RUNPU COIL CTBG @ 4500' N2 762 scf, WHP 1743 psi, 266 bbis water recovered.
18:39 - 18:51 0.20 RUNPU COIL CTBG Parked @ 4500', N2 @ 762 scf, WHP 1840 psi, recovered 329 bbls.
18:51 - 18:53 0.03 RUNPU COIL CTBG Parked @ 4500', N2 @ 762 scf, WHP 1840 psi, recovered 348 bbis.
18:53 - 19:45 0.87 RUNPU COIL CTBG RIH.
19:45 - 20:13 0.47 RUNPU COIL CTBG @ 6000', Pumping N2 @ 1000 scf, WHP 1935 psi, 376 bbls. recovered.
20:13 - 20:52 0.65 RUNPU COIL CTBG Tubing parked @ 6000' Pumping N2@ 1000 scf, WHP 2139 psi, 400
bbis recovered.
20:52 - 21:30 0.63 RUNPU COIL CTBG @ 6000', Pumping N2 @ 1000 scf, WHP 2245 psi. recovered 428 bbls.
21:30 - 21:55 0.42 RUNPU COIL CTBG 6000', N2 @ 1000 scf, WHP 2336 psi. recovered 457 bbls.
21:55 - 22:05 0.17 RUNPU COIL CTBG Parked 6000', N2 @ 1000 scf, WHP 2358 psi, 477 bbls recovered.
22:05 - 22:50 0.75 RUNPU COIL CTBG Gas break out to buster, Shut down N2, POOH. 480 bbls recovered.
22:50 - 23:27 0.62 RUNPU COIL CTBG Tubing at surface. WHP 1710 psi. Bleeding WHP to 1100 psi.
23:27 - 23:40 0.22 RURD COIL CTBG Shut in well 1160 psi. Begin RD.
23:40 - 23:55 0.25 RURD COIL CTBG Set ejector in craddle. Secure well head.
23:55 - 00:00 0.08 SECUR WELL CTBG Leave location. close gate.
8/9/2007 08:30 - 09:30 1.00 SAFETY MTG_ CMPPRF Arrive Sterling Pad. Sign in at rig. Hold PJSM and obtain Safe Work
Permit.
09:30 - 10:45 1.25 RURD ELEC CMPFLW Install WH crossover adapters. PU lubricator and CCUGamma tool
string.
10:45 - 11:34 0.82 RURD ELEC CMPFLW PTest lubricator to 3000 psi. Test good.
11:34 - 12:35 1.02 RUNPU ELEC CMPFLW Open well.(1150 psi.) RIH.
12:35 - 14:07 1.53 RUNPU ELEC CMPFLW Tag TD @ 6070'. Start log. POOH
14:07 - 14:47 0.67 SAFETY MTG_ CMPFLW OOH. Hold explossives safety meeting. Inform all personnel on
location. Shut down cells.
14:47 - 16:00 1.22 RUNPU ELEC CMPFLW PU 3-3/8" x 1" HSC EXP (990 psi on well)
16:00 - 16:10 0.17 RUNPU ELEC CMPFLW Pull into position to shoot 5750'-5751'.( 20 psi increase on well after
shooting)
16:10 - 16:20 0.17 RUNPU ELEC CMPFLW POOH.
16:20 - 16:25 0.08 RUNPU ELEC CMPFLW WHP 1055 psi.
16:25 - 16:40 0.25 RUNPU ELEC CMPFLW Pressure increasing to 1075 psi. @ 16:20
16:40 - 16:42 0.03 RUNPU ELEC CMPFLW Pressure increased to 1100
16:42 - 14:00 21.30 RURD ELEC CMPFLW Expro OOH. RD.
17:00 - 17:15 0.25 FLOW TEST CMPFLW Pressure continues to bulid to 1160 psi.
17:15 - 17:25 0.17 FLOW TEST CMPFLW O en well on 12/64 choke. 1140 psi WH, 1100 choke
17:25 - 17:37 0.20 FLOW TEST CMPFLW Well flowing on 12/64 choke 960 psi WH, 960 choke.
17:37 - 17:40 0.05 FLOW TEST CMPFLW Well flowing on 12/64 choke 780 psi WH, 770 choke. Pinch back to
8/64
17:40 - 17:47 ~ 0.12 I FLOW_I TEST ~ CMPFLW ~ Well flowing on 12/64 choke 740 psi WH, 745 choke. Pinch back to
8/64
17:47 - 18:00 0.22 FLOW TEST CMPFLW Well flowing N2 on 6/64 choke 670 psi WH, 670 choke. Pinch back to
4/64
18:00 - 18:07 0.12 FLOW TEST CMPFLW Well flowing N2 on 4/64 choke 560 psi WH, 560 choke. Pinch back to
4/64
18:07 - 18:25 0.30 FLOW TEST CMPFLW Well flowing N2 on 4/64 choke 510 psi WH, 510 choke. Pinch back to
4/64
18:25 - 18:30 0.08 FLOW TEST CMPFLW Well flowing N2. choke open 10% ( 1" choke-10 turns to full open,
open 1 turn) 460 psi WH, 475 psi.
18:30 - 18:45 0.25 FLOW TEST CMPFLW Well flowing N2. choke open 10% ( 1" choke-10 turns to full open,
open 1 turn) 450 psi WH, 460 psi.
Printed: 8/13/2007 2:5632 PM
•
~
Marathon `C~i~ ~ci' ra~ _
Operatians ~~~~~~ Re.
Legal Well Name: STERLING UNIT 43-9X
Common Well Name: STERLING UNIT 43-9X
Event Name: ORIGINAL COMPLETION
Contractor Name:
Rig Name:
Pag~~~f 4
~r t
Spud Date:
Start: 7/1/2007 End:
Rig Release: Group:
Rig Number:
Date From - To Hours Cod~ ~~, P#~as~ D~s~i'~ption of Operations .
8/9/2007 18:45 - 19:Q0 0.25 FLOW TEST CMPFLW Well flowing N2. choke open 10% ( 1" choke-10 turns to full open,
open 1 turn) 445 psi WH, 460 psi.
19:00 - 19:35 0.58 FLOW TEST CMPFLW Gas to surface on LEL meter, choke open 10% ( 1" choke-10 turns to
full open, open 1 turn) 445 psi WH, 460 psi.
19:35 - 20:00 0.42 FLOW TEST CMPFLW Water to surFace. Estimated @ 1/2 bpm choke open 20% ( 1"
choke-10 turns to full open, open 2 turn) 600 psi WH, 620 psi.
20:00 - 20:30 0.50 FLOW TEST CMPFLW Switch out with night operator, WH 800 psi, choke 700 psi well
making gas and water.
20:30 - 21:00 0.50 FLOW TEST CMPFLW WH 840 psi, choke 760 psi well making gas and water.
21:00 - 21:30 0.50 FLOW TEST CMPFLW WH 880 psi, choke 880 psi well making gas and water. Well
produce 32.6 bbls in the one hour period from 20:00 to 21:00.
21:30 - 22:00 0.50 FLOW TEST CMPFLW WH 920 psi, choke 920 psi well making gas and water.
22:00 - 22:30 0.50 FLOW TEST CMPFLW WH 900 psi, choke 900 psi well making gas and water. Well
produce 18.9 bbls in the one hour period from 21:00 to 22:00.
22:30 - 23:00 0.50 ~LOW_ TEST CMPFLW WH 920 psi, choke 900 psi well making gas and water.
23:00 - 23:30 0.50 FLOW TEST CMPFLW WH 850 psi, choke 820 psi well making gas and water. Well
produce 18.1 bbls in the one hour period from 22:00 to 23:00.
23:30 - 00:00 0.50 FLOW TEST CMPFLW WH 880 psi, choke 880 psi well making gas and water.
00:00 - 00:30 0.50 FLOW TEST CMPFLW WH 1020 psi, choke 1020 psi well making gas and water. Well
produce 23.1 bbls in the one hour period from 23:00 to 24:00. Total
water produced 93 bbls.
0030 - 01:00 0.50 FLOW_ TEST CMPFLW WH 1180 psi, choke 1200 psi well making gas and water.
01:00 - 01:30 0.50 FLOW TEST CMPFLW WH 1160 psi, choke 1200 psi Choke froze well making gas, NO
water
01:30 - 02:00 0.50 FLOW TEST CMPFLW WH 1160 psi, Choke froze well making gas, NO water
02:00 - 02:30 0.50 FLOW_ TEST CMPFLW WH 1100 psi, choke 1120 psi well making gas, NO water
02:30 - 03:00 0.50 FLOW TEST CMPFLW WH 1100 psi, choke 1100 psi well making gas, NO water
03:00 - 03:30 0.50 FLOW TEST CMPFLW WH 990 psi, choke 1000 psi well making gas, NO water
03:30 - 04:00 0.50 CMPFLW WH 970 psi, choke 990 psi well making gas, NO water
04:00 - 04:30 0.50 CMPFLW WH 900 psi, choke 900 psi well making gas, NO water
04:30 - 05:00 0.50 CMPFLW WH 950 psi, choke 950 psi well making gas, NO water
05:00 - 05:30 0.50 CMPFLW WH 950 psi, choke 950 psi well making gas, NO water
05:30 - 06:00 0.50 CMPFLW WH 980 psi, choke 1000 psi well making gas, NO water
8/10/2007 06:00 - 06:30 0.50 FLOW TEST CMPFLW WH 900 psi, choke 900 psi well making gas, NO water
06:30 - 07:00 0.50 FLOW TEST CMPFLW WH 830 psi, choke 850 psi well making gas, NO water
07:00 - 07:30 0.50 FLOW TEST CMPFLW WH 815 psi, choke 820 psi well making gas, NO water.
Started making water @ 7:15
07:30 - 08:00 0.50 FLOW TEST CMPFLW WH 880 psi, choke 900 psi well making gas, and some water.
estimated at 1/2 bbl. Waterstopped at 07:30
08:00 - 08:30 0.50 FLOW~TEST CMPFLW WH 840 psi, choke 860 psi well making gas, NO water
08:30 - 09:00 0.50 FLOW TEST CMPFLW WH 780 psi, choke 810 psi well making gas, NO water
09:00 - 09:30 0.50 CMPFLW WH 725 psi, choke 745 psi well making gas, NO water
09:30 - 10:00 0.50 SAFETY MTG_ CMPPRF Expro Arrive Sterling Pad. Sign in at rig. Hold PJSM and obtain Safe
Work Permit.
10:00 - 10:46 0.77 RURD ELEC CMPFLW RU. WH 760 psi, and choke 760 psi, 10/64" choke, slugging water.
10:46 - 11:00 0.23 RURD ELEC CMPFLW PU PLT string. PTest lubricator to 2000 psi. Test good.
11:00 - 11:15 0.25 FLOW_ TEST CMPFLW WH 770 psi, choke 760 psi., 10/64" choke Small amount of water.
11:15 - 12:00 0.75 RUNPU ELEC CMPFLW Open well. Surface pressure 834 psi., 64.5 deg
12:00 - 12:25 0.42 FLOW TEST CMPFLW WH 750 psi, choke 750 psi., 10/64" choke water slugging. Recovered
26 bbls water.
12:25 - 12:57 0.53 FLOW TEST CMPFLW WH 760 psi, choke 760 psi., 10/64" choke water slugging. Recovered
Printed: 8/13/2007 2:56:32 PM
~ ~ •
Marathon 0il C~ . any ` Pag~ ~ af ~
4pe~~~~s ~ummary ~~rt
Legal Well Name: STERLING UNIT 43-9X
Common Wel( Name: STERLING UNfT 43-9X Spud Date:
Event Name: ORIGINAL COMPLETION Start: 7/1/2007 End:
Contractor Name: Rig Release: Group:
Rig Name: Rig Number:
~~ S~k~ ~ "
Dat~` From~-~~`~` E~c~~rs Code
~hase Descriptio~r~~{{~~peratio`"
Co~~
8/10/2007 12:25 - 12:57 0.53 FLOW TEST CMPFLW additional 5 bbls water by 12:25. Unloading tank to vac truck..
12:57 - 13:16 0.32 RUNPU ELEC CMPFLW Tag TD @ 5972. 1794 psi and 105 deg. Start simulation pass @5740
1694 psi and 100 deg.
13:16 - 13:22 0.10 SAFETY MTG CMPFLW 5740' psi end simulation pass 1694 psi and 100 deg.
13:22 - 13:28 0.10 RUNPU ELEC CMPFLW 5500' Start 5 min bench 1683 psi, and 99 deg.
13:28 - 1336 0.13 RUNPU ELEC CMPFLW 5500' End 5 min bench 1694 psi and 98 deg.
13:36 - 13:42 0.10 RUNPU ELEC CMPFLW 5000' Start 5 min bench 1631 psi, and 96 deg.
13:42 - 13:58 0.27 RUNPU ELEC CMPFLW 5000' End 5 min bench 1610 psi, 96 deg.
13:58 - 14:04 0.10 RUNPU ELEC CMPFLW 4000' Start 5 min bench 1490 psi. and 89 deg.
14:04 - 14:37 0.55 RUNPU ELEC CMPFLW 4000' End 5 min bench 1494 psi and 89 deg.
14:37 - 14:43 0.10 RUNPU ELEC CMPFLW 2000' Start 5 min bench 1123 psi and 70 deg. 14:15 WHP 850 psi,
choke 860 psi on 10/64 choke. Recovered 34 bbls. of water from 12:50
to 14:15 65 bbis total recovery since 11:00 am.
14:43 - 15:14 0.52 RUNPU ELEC CMPFLW 2000' End 5 min bench 1118 psi and 70 deg.
15:14 - 15:20 0.10 RUNPU ELEC CMPFLW 50' Start 5 min bench 888 psi and 54 deg.
15:20 - 15:25 0.08 RUNPU ELEC CMPFLW 50' End 5 min bench 886 psi and 54 deg,
15:25 - 16:30 1.08 RURD ELEC CMPFLW OOH. Close swab. Close master. Shut in well with 840 psi.
16:30 - 17:00 0.50 RURD ELEC CMPFLW WHP 1190 psi @ 16:30. Turn in Permits.
8/11/2007 07:00 - 08:00 1.00 SAFETY MTG CTBG Held PJSM, discussed safety issues and procedure with personnel.
08:00 - 10:30 2.50 RURD COIL CTBG RU on well. PU injector and go to well. PT shell and flow back iron low
@ 200 psig/ high at 4300 psig, Good test. Bled down to 1300 prior to
open up well.
10:30 - 11:00 0.50 WORK COIL CTBG Open well, RIH with coil pumping at 1.4 BPM, 3500 psig.
11:00 - 11:45 0.75 WORK COIL CTBG Coil @ 3406' CTM. Problem with electrical counter, stop to fix. WHP=
787 psig, continue to open choke to displace fluid in well bore.
11:45 - 15:30 3.75 WORK COIL CTBG Coil @ 5950', PIP = 4400 psig, PIR= 2.10 BPM. WHP= 0 psig.
15:30 - 15:45 0.25 WORK COIL CTBG No returns during pumping. Cut PIR to 1.0 BPM, PIP = 4395 psig.
Total fluid pumped down well= 474 bbis. Shut down pumping. Empty
Hole volume calculated at 439 bbls. Pumped 39 bbls over hole
volume.
15:45 - 17:20 1.58 WORK COIL CTBG Have vac truck mix more KCL, Supply tank down to 9" loosing suction
to pumps. Discussed operation with Anchorage about hole taking fluid.
17:20 - 18:10 0.83 WORK COIL CTBG Problem with water well, slower than anticiapated. Called another vac
truck from town to mix KCL. Decided to lay down coil for night.
18:10 - 18:45 0.58 WORK COIL CTBG POOH with coil, vac truck continue to mix 500 BBLS of KCL before
leaving lease.
18:45 - 19:30 0.75 WORK COIL CTBG OOH with coil, Rig back coil for night, secured well, shut down all
equipment. WHP= 0 psig.
19:30 - 20:00 0.50 RURD COIL CTBG BJ crew left lease.
Printed: 8/13/2007 2:5632 PM
SU 43-9X ~ Page 1 of 1
~
Maunder, Thomas E (DOA)
From: Maunder, Thomas E (DOA)
Sent: ~riday, Juty 20, 2007 11:41 AM
To: 'Olson, Mike'
Cc: Skitra, Kevin J.; Walsh, Ken
Subject: RE: SU 43-9X
Mike, Kevin and Ken,
Thanks for the update on the plans. This work is within the scope of sundry 307-220. Good luck with the work.
Tom Maunder, PE
AOGCC
From: Ofson, Mike [mailto:mrolsan@marathonoPi.com]
Sent: Friday, ]uly 20, 20Q7 11:24 AM
To: Maunder, Thomas E (DOA)
Cc: Skiba, Kevin 3.; Walsh, Ken
Subjett: SU 43-9X
Tom,
Per our conversation yesterday> we wouid like to test the Ster[ing B-4 sand before we proceed w! the Dual Gravei
Pack Comptetion of the Sterting B-4 (Permit to Dritl Number 207-073). l'he reason for the test is to conflrm
whether the zone is gas or water bearing. The open hote logs look good (gas bearing), however multiple RFTs
confirm a water gradient fram top to bottom.
Our proposal is to RU the C7U and displace the KCL fluid in ths wellbore w/ N2. We wauld perforate the Sterting
B-4 underbatanced, from g,750-5,751' (1' at 4 SPF). Plans woufd be t4 fEow test the welf for a short period (well
will likely load up in the 9-5/8" casing) and run SHP gauges in the well to canfirm gas/fluid entry. Based on the
results of this work, we wiH have a better understanding of which direction ta proceed. Assuming gas entry, the
perfs woutd be squeezed and tested so that they do not iRterfere w/ the GP camptef~on, and the ~est of the work
wi8 be completed as previously submifted. !f the zvne is wet, we probably not cantir~ue w/ the Gravef Pack
Compietian.
If you have any questions, or need any additional information, pfease let rne or Ken know.
Thanks!
Mike Olson
Completions Engineer
Marathon Oil Company
Worldwide Drifling & Completions - USPO
e-mail: MROlson@MarathonOil.com
work: (713) 296-2327
cell: (713) 408-6931
fax: (713) 499-6740
7/20/2007
~ ,
~
M Marathan
MARATHbN ~~~ ~~a~~
July 5, 2007
Mr. Tom Maunder
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, Alaska 99501
Reference: Dual Gravel Pack Procedure
Field: Sterling Field
Well: SU 43-9x
Dear Mr. Maunder:
~
Marath~l Company
Alaska Asset Team
P.O. Box 1949
Kenai, AK 99611
Telephone 907/283-1371
Fax 907/283-1350
~C~.SGIVGD
JUL 0 ~ Zp~~
~A~aska Oil & Gas Cons. Cammissi~an
Anchorag~
Attached and submitted for your records is the SU 43-9x Dual Gravel Pack Procedure.
Marathon is currently discussing options to verify the gas / water contact. Notification of
the plan will be forwarded when finalized.
If you have any questions or need further information please call me at (907) 283-1371.
Sincerely,
_ `~
Kevin Skiba
Production Technician
Enclosures: Dual Gravel Pack Procedure
cc: AOGCC
Houston Well File
Kenai Well File
KJS
~
~
Well SU 43-9X
Sterling Field
WBS DD.07.15309.CAP.CMP
Completion as Dual S~erling B4 Co-Producer
Objective: Complete well SU 43-9X as a dual co-producer completion in the Sterling
B4 reservoir.
Well Name: Sterling Field, 43-9X
Proposed Completion: Two (2} High Rate Water Packs
Rig: Glacier I
Perforations: Lower Zone (LZ): 5766-5776' (10')
Upper Zone (UZ): 5724-5730' (6')
Deviation @ Perforations: 0, 0°
BHP: LZ: 1990, UZ: 1980 psi
Completion Fluid: 8.6# KCl
BHST: 125°F
Casing: 9-5/8", 40#, L/TC, L-80
Production Tubing: 2-7/8", 6.5#, L-80, EUE 8rd
2-3/8", 4.7#, L-80, IBT-M
Workstring: 4", 14#, 5-135, HT-38
Gravel Pack Packer: Baker "SC-1" GP Packer @ 5,738, 5,621'
Blank Pipe: UZ: 60' of 5-1/2" 23# SLHT L-80
Gravel Pack Screen: LZ: 18' of 5-1/2" SLHT 12-GA Bakerweld
140 (316L wrap / L-80 base)
UZ: 18' of 5-1/2" SLHT 12-GA Bakerweld
140 (316L wrap / L-80 base)
Sump Packer: 5,782' MD Baker Model `D' Packer
Carrier Fluid: 8.6 ppg 6% KCL
Crravel: 20/40 mesh Ceramic Proppant
~il~lt Prafile [.~a#a
a~ tn) i~c f) ~z (°f ~(tc) ~occ~ N(~} ~ E(~~ t~ ~°r~oc~~p k~s t~,
~~ ~ ~.raa o.~~~ a~a.~s-r ~.a~ o.ac o.~+c~ c.c~ e.Qa
k~ asxa.~~ c.a~ ~.as z~n.a~ o.oc, 4.oc ~.~c a.aa
Eru1 cateuild ~957.99 ~.t~ 3~457 1766.96 ~~7.d~ -1~.35 2.[~.^i 4~.53
~+~~SP 38d~.t6 ?i.4~ '~3t3.45~ ~i33.~ 1~~.5fi -62°.i6 G~~ ~535.1~i
E~i of fxc~ SSi~.13 o.~c~ ?3C.~5' €~.nc 1853.35 -8~r.51 :.t9~ ~?1.~~3
T~ ~it~.13 o.~aa ~e.~s ~.cro 185~.~a -64d.51 0.~0 ~?9.~3
m &15~ "~ ~.oa~ ~~.~5* ~8.[~ 18~r.36 -84?~.51 G.~?~ iJ?1.~3
Summary Completion Procedure
• MIRU Glacier Rig.
• Remove dry hole tree.
1
. ~
~ Install and test BOP.
• PU workstring and TIH.
• Displace to clean 6% KCL. C&C brine. ST. C&C brine. POOH with workstring.
• RU E/L. Correlate and set sump packer.
• Perforate 10' interval below GWC in Sterling B4 sand. RD E/L.
• TIH with screen and gravel pack assembly. Set gravel pack packer.
• Pump lower zone annular pack. PU and reverse workstring contents. POOH.
• TIH with packer plug. Set and dump sand on fishing neck. POOH.
~ RU E/L. Perforate 6" interval in top of Sterling B4 sand. RD E/L.
• TIH. Pull packer plug. POOH.
• TIH with screen and gravel pack packer assembly. Set gravel pack packer.
• Pump upper zone annular pack. PU and reverse workstring contents. POOH and
LD workstring.
~ PU dual packer, and TIH with 2-7/8" x 2-3/8" tubing strings. Space out gas lift
mandrels in longstring per design.
• Space out and land dual tubing strings in tubing hanger.
• Set dual packer.
• ND BOP's and NU CT spool and dual tree.
• RDMO Glacier Rig.
SAFETY
The safety of all personnel involved with all operations in this procedure is of highest
priority. The following points should be noted and are applicable to all stages of the
completion.
- Pre:job safety talks should be conducted prior to the start of any operation. All
personnel involved with the operation should attend. Safety talks should be repeated
prior to the start of tour every day.
- Crews should be encouraged to use the `Timeout' approach if unsure of anything or if
operations diverge from the original plan.
- Crews should be actively encouraged to use the FORC program.
- Any safety concerns or improvements raised by the crews should be highlighted
during the tour meetings.
- Man riding operations need to be carefully controlled. Good communication is
essential at all times.
- During the movement of objects by crane or air-tugger, all personnel should be aware
of their positions with regard to the suspended load and fixed objects. Tag lines
should be used for directional control at all times.
2
~
~1
~
- MSDS information for chemicals used during the completion should be supplied and
be available for review by rig personnel. Prior to storage and use these should be read
and understood by any personnel involved in their use.
Reference•
• Appendix "A": Proposed Wellbore Diagram
• Appendix "B": Sterling B-4 Log Section
• Appendix "C": Weatherford 4" Drill Pipe Specs
• Appendix "D": MI Proposed Tank and Equipment Layout Diagram
• Appendix " E": Baker Sand Control Downhole Equiprnent Schematic
• Appendix "G": Completion Fluid Volume Requirement Estimate
• Appendix "G": Baker Sieve Analysis and Acid Solubility Report
• Appendix "H": Gas Lift Design
• Appendix "I": Vetco Dual Tree and Intervention Spool
• Appendix "J": Sterling B4 Pressure MFT Pressure Data Point Summary
• Call Out List
• MI Swaco: Filtration and Gravel Pack Proposal
• BJ Services: Gravel Pack Pumping Proposal
• Baker Sand Control: Gravel Pack Procedure
Procedure:
Wellbore Clean-up:
1. MIRU Glacier I rig.
Note: Please reference MI Swaco proposed tank and equipment layout
diagram.
2. Prior to ND dry hole tree confirm that no trapped pressure exists below. NU
adaptor spool (11", SM x 135/8", SM) and 135/8", SM BOPs. Upper pipe rams
should be equipped with variable bore (2'/8"- 51/2" range), SM pipe rams. Lower
pipe rams should be equipped with 4", SM single pipe rams. Test BOPE to
250/3500 psi. LD test joint.
3. Install wear bushing.
4. RU single elevators, slips, and tongs for running 4", 14.0 ppf, 5-135, HT-38
workstring. Lay out, tally, and rabbit 6000' of 4" workstring.
3
~
~
5. PU 8-1/2" bit and scraper assembly and PU 4" workstring. Insert additional
scraper halfway to PBTD.
Note: Please reference MI Swaco wellboYe displacement p~-oposal.
6. Clean wellbore per MI Swaco recommended procedure and displace to
clean/filtered 6% KCI.
7. Consider short trip and additional cleanup pills to ensure brine clarity to <20
NTU's.
8. Pressure test casing to 3000 psi.
9. POOH and LD bit and scraper assemblies.
Setting Sumu Packer:
10. RU electric line unit.
1 l. Make up +/- 8,47" OD Gauge Ring (supplied by BOT) and Junk Basket to
electric line unit and RIH to below planned setting depth of Sump Packer, 5,782'
MD or as close to existing packer as comfortable.
12. Initiate radio silence. Ensure that all un-necessary personnel are kept clear of
the rig floor during setting tool handling operations and barriers are in
place. MiJ Baker 194-47 Model "B" Sump Packer Assembly with E-4 wire line
setting tool. RIH with packer. RIH with wire line and correlate packer to make
sure it is on depth. Set sump at 5,782' MD. Rig down the wire line unit. Pull out
of the hole with setting tooL
Note: If unable to get down on wireline to set Sump Packer, make up the
packer with wireline adapter kit to "J" Hydraulic Setting Tool. Run in
the hole to place packer on depth, using wireline to log on depth. Drop
1-7/16" ball down workstring and allow it to fall to setting tool
(approximately 50 minutes), pump at 1/ BPM to push ball on seat if
needed. PYessure up to approximately 3, 000 psi, and while maintaining
pressure on the drill pipe, pull approximately 25K until setting tool
releases form the packer. Pull out of the hole with setting tool. Do not
slack back off onto packer.
Perforating of "Lower" Sand:
Note: The lubricator for perforating will be a 20' x 9-S/8 " casing pup joint
from Marathons pipe inventory with casing collars on both ends.
4
• ~
Adapters will be obtained to reduce casing to a purnp in tee and wireline
packoff on one end. The otheY end will function as a stop below where
the hydril boot will close on the lubricator. Initially, the e-line will be
stripped thYOUgh the lubricator, the latter picked up then the sump
packer or perf gun will be picked up in the lubricator and both will be
simultaneously lowered into BOPs with blind rams closed. The hydril
boot will then be closed on the lubricator ensuring there is well
containment.
13. Initiate radio silence. Ensure that all un-necessary personnel are kept clear
of the rig floor during gun operations and barriers are in place. Makeup
Lower Zone Wireline perforating gun assembly. Position guns across the
"Lower" sand at 5,766' - 5,776' MD.
14. Detonate guns. Pull out of hole with perforating guns, rig down and release
wireline unit.
15. Monitor well for pressure and/or fluid loss after perforating as per Marathon
instructions. If fluid losses are excessive, contact Marathon's Completion
Engineer to discuss if LCM pill is needed, and if so, what type and the amount
required.
Note: Please reference MI Swaco LCMpill recommendation.
16. Make up casing scraper assembly and run in hole to clean perforations prior to
running gravel pack assembly. Reverse circulate well with scraper on bottom until
fluid returns are clean (return NTU's approximately 20 NTU higher than inlet
NTU). When fluid returns are clean, pull out of hole with casing scraper
assembly.
Running & Setting Gravel Pack Assembly:
17. Make up and run in hole with Gravel Pack Assembly, screen and seal assembly as
per BOT schematic. Hang off in screen table.
18. Make up the following Washpipe assembly and hang off with safety clamps
inside the screen assembly:
a. 3-1/2", 9.2# Hydri1511 Half Muleshoe
b. 3-1/2", 9.2# Hydril 511 Washpipe Pup Joints as required to spaceout
washpipe Muleshoe as close to end of screen as possible.
19. Pick up remainder of Baker Gravel Pack assembly as listed on BOT schematic,
connect washpipe to bottom of crossover tool, connect screen/blank pipe
assembly to bottom of packer assembly, and connect packer assembly to
5
• ~
workstring. Run in to the hole at approximately 3 minutes/stand. Do not rotate
packer assembly. Rabbit all drill pipe when running into the hole (only have one
rabbit on rig floor).
Note: Caliper and check tool connections, screen gauge and record all lengths.
Do not use pipe dope on workstring, screen oY GP assembly.
20. Get pick up and slack off weight of assembly one stand prior to tagging sump
packer.
21. Gently snap into sump packer at 5,782' MD, set down l OK, and check pipe
figures to verify correct depth. Snap out w/ 10-15K over pull (Do not exceed
31,500# - 50% of the shear value), and then slack back into sump packer and set
down SK. Rig up the Pumping Equipment, and thoroughly flush all lines and GP
manifold. Test lines to 7,000 psi, break circulation, and drop a 13/" packer setting
ball down the workstring. Set Pop-off valves on tubing @ 5,500 psi, and on
casing @ 3,500 psi.
22. Allow the ball to fall for approximately 50 minutes (±5 min. per 1,000 ft) before
setting packer. Pressure up to 1,800, 2,400, & 2,900 psi holding each for 5 min,
then bleeding off to 0 psi in between. Pumping may be required to land setting
ball on ball seat. If so, do not exceed 1 BPM or 500 PSI. Ma7cimum setting
pressure is 3,500 psi while service tool is still attached to packer.
23. Pick up and slack off 20-25K to test packer slips. Pressure backside to 1,000 psi
fo test packing element. Increase backside pressure to 1,500 psi to actuate
hydraulic release. Tool can be rotated 12-15 turns to the right if hydraulic release
fails.
24. PU tool to rnake sure it moves freely. Then locate and mark the following
positions:
a) Slack off 30K on packer to locate SQUEEZE/CIRCULATING position.
b) Pick up weight off packer, slack in pipe and then an additional9' to
REVERSE position. Reverse out packer setting balL
Gravel Pack Pumping Procedure:
25. With tool in the REVERSE position, pump the chemical pickle treatment as
follows down tubing:
Note: If backup ball was used to set packer reverse out ball.
Note: The sen~ice pumps will do all pumping down the tubing, and the rig pumps
will do all reversing.
6
• ~
Note: Workstring pickle procedure as per MI Swaco and BJ Services
recommendations.
Note: Gravel pack Pumping procedure as per BJ Services ~ecommendation.
26. LCM Pill Breaker: If a pill was pumped to control fluid losses, pump 5.95 BBL
of 10% HCl w/ additives (=~5 gals/ft) to within 5 BBLS of the packer. Shut
down pumps, slack off to SQUEEZE/CIRCULATING position, close the Hydril,
open the choke valve in the manifold and begin circulating acid down across
entire perforation interval. Close the choke and inject acid into formation until
trailing edge of acid is at top perforation. Allow acid to soak for 10-15 minutes.
27. Circulatin~ Rate Test: With tool in CIIZCULATING/SQUEEZE position, open
choke and obtain circulating rates and pressures with filtered completion fluid at
lh, 3/, 1 and 2 BPM. Record stabilized circulating rates and pressures.
CIRCULATING RATE TEST
Step Rate
(BPM) Tubing
Pressure Annular
Pressure
1 %z
2 3~
3 1
4 2
28. Step Rate Test: With tool remaining in the CIRCULATING/SQUEEZE
position, close the choke valve on the manifold, and perform the Step Rate Test
(SRT) with the following volumes and rates. Hold each rate constant for 2
minutes. Execute a hard shut down at the end of the Step Rate Test and let the
fracture close, record ISIP and pressure decline on the tubing. Discuss outcome
with Marathon Completion Engineer.
STEP RATE TEST
Step Rate
(BPM) Tubing
Pressure Annular
Pressure Cumulative
Vol. (BBL)
1 1 2
2 2 6
4 3 12
5 4 20
7 6 30
8 8 42
9 10 78
10 ~ Max (12) TBD
7
~ ~
ISIP 0
Note: Plan to pump job at 2 BPM above break-over rate. If break-over is not
observed, plan on pumping job at max rate while staying ~l S00 psi below
maximum treating pressure.
29. Gravel Pack Treatment: With the crossover tool in the
CIRCULATE/SQUEEZE position, Hydril and choke closed bullhead 1,412 lbs of
20/40 mesh Ceramic Proppant infused in 34 BBL of completion fluid at 1.0
PPA (35.1 BBL of Slurry). Pump rate to be as determined in by Step Rate Test.
Open choke to allow 1/ BPM returns, and record circulating rates. Once 250 psi
pressure increase is observed over initial circulating pressure, shut down
pump and immediately pull up to REVERSE position and reverse out all
excess slurry. There is no blank pipe and very minimal extension between the
Gravel Pack Port and top of screen.
Note: Prior to performing job, Baker and Marathon will agYee upon method of
inducing screen-out.
When screen out occurs calculate the density above the crossover and determine
the desired pressure needed on the backside to prevent U-tubing before pulling up
to the REVERSE position.
30. Following screen-out, apply 1000 to 1500 psi overbalance on the annulus at the
tool (corrected for hydrostatic differences). Pick up and locate the REVERSE
position observe pressure Ioss on Annulus while continuing to pick up to
REVERSE position, reverse out until returns are clean (monitor returns vs. pump
rate). Pump 11/2 to 2 times the drill pipe volume to ensure cleanliness.
31. Flush the lines and manifold and rig down Baker pumping equipment.
Note: Have 100% Excess sand on location to do a top off job if required:
32. After returns are clean, shut down pumps, bleed off all pressure and pick up tool
until all seals of the Crossover tool out of the packer body. Monitor well for fluid
loss. If losses are not acceptable, discuss LCM options.
Note: Please refeYence MI Swaco LCMpill recommendation.
33. Pull out of the hole and lay down the crossover tool/setting tools.
Perforating of "Upper" Sand:
• ~
34. Make up SB Packer Plug and Surge Chamber on drill pipe, run in hole and set in
Lower Zone SC-1 Packer set at 5,264'. Pull out of hole with drill pipe and SB
running tool.
35. Rig up electric line unit.
Note: The lubricator for peYforating will be a 20' x 9-5/8 " casing pup joint
from Marathons pipe inventory with caszng collars on both ends.
Adapters will be obtained to reduce casing to a pump in tee and wireline
packoff on one end. The other end will function as a stop below where
the hydril boot will close on the lubricator. Initially, the e-line will be
stripped through the lubricator, the latter picked up then the perf gun
will be picked up in the lubricator and both will be simultaneously
lowered into BOPs with blind rams closed. The hydril boot will then be
closed on the lubricator ensuYing there is well containment
36. Initiate radio silence. Ensure that all un-necessary personnel are kept clear
of the rig floor during gun operations and barriers are in place. Makeup
Lower Zone Wireline perforating gun assembly. Position guns across the
"Upper" sand at 5,724' -5,730' MD.
37. Detonate guns. Pull out of hole with perforating guns, rig down and release
wireline unit.
38. Monitor well for pressure and/or fluid loss after perforating as per Marathon
instructions. If fluid losses are excessive, contact Marathon's Completion
Engineer, to discuss if LCM pill is needed, and if so, what type and the amount
required.
Note: Please reference MI Swaco LCMpill recommendation.
Retrieve Packer Plu~:
39. Make up casing scraper assembly and run in hole to clean perforations prior to
pulling SB Packer Plug and Surge Chamber. Reverse circulate well with scraper
on bottom until fluid returns are clean (return NTU's approximately 20 NTU
higher than inlet NTU). When fluid returns are clean, pull out of hole with casing
scraper assembly.
40. Make up SB retrieving tool and run in hole to SB Packer Plug location, check up
and down weights. Reverse circulate well, and wash down over packer plug until
pump fluid returns are clean (return NTU's approximately 20 NTU higher than
inlet NTU). When fluid returns are clean, pick up to release SB packer plug and
pull out of hole with casing scraper assembly.
9
• ~
Running & Setting Gravel Pack Assemblv:
41. Make up and run in hole with blank, screen and seal assembly as per BOT
schematic. Hang off in screen table.
42. Make up the following Washpipe assembly and hang off with safety clamps
inside the screen assembly:
a. 80-32 Rental seal assembly
b. 3-1/2", 9.2# Hydri1511 Washpipe, P-110
c. 3-1/2", 9.2# Hydri1511 Pup Joints as required to space out rental seal
assembly into S-22B Sealbore.
43. PU remainder of Baker Gravel Pack assembly as listed on BOT schematic,
connect washpipe to bottom of crossover tool, connect screen/blank pipe
assembly to bottom of packer assembly, and connect packer assembly to
workstring. Run in to the hole at approximately 3 minutes/stand. Do not rotate
packer assembly. Rabbit all drill pipe when running into the hole (only have one
rabbit on rig floor).
Note: Caliper and check tool connections, screen gauge and record all lengths.
Do not use pipe dope on workstring, screen oY GP assembly.
44. Get pick up and slack off weight of assembly one stand prior to tagging sump
packer.
45. Gently snap into GP packer at 5,738' MD, set down l OK, and check pipe figures
to verify correct depth. Snap out w/ 10-15K over pull (Do not exceed 31,500# -
50% of the shear value), and then slack back into sump packer and set down SK.
Rig up the Baker Pumping Equipment, and thoroughly flush all lines and GP
manifold. Test lines to 7,000 psi, break circulation, and drop a 1%" packer setting
ball down the workstring. Set Pop-off valves on tubing @ 5,500 psi, and on
casing @ 3,500 psi.
46. Allow the ball to fall for approximately 50 minutes (±5 min. per 1,000 ft) before
setting packer. Pressure up to 1,800, 2,400, & 2,900 psi holding each for 5 min,
then bleeding off to 0 psi in between. Pumping may be required to land setting
ball on ball seat. If so, do not exceed 1 BPM or 500 PSI. Maximum setting
pressure is 3,500 psi while service tool is still attached to packer.
47. Pick up and slack off 20-25K to test packer slips. Pressure backside to 1,000 psi
to test packing element. Increase backside pressure to 1,500 psi to actuate
hydraulic release. Tool can be rotated 12-15 turns to the right if hydraulic release
fails.
10
. ~
48. PU tool to make sure it moves freely. Then locate and mark the following
positions:
c) Slack off 30K on packer to locate SQUEEZE/CIRCULATING position.
d) Pick up weight off packer, slack in pipe and then an additional9' to
REVERSE position. Reverse out packer setting ball.
Gravel Pack Pumping Procedure:
49. With tool in the REVERSE position, pump the chemical pickle treatment as
follows down tubing:
Note: If backup ball was used to set packeY reverse out ball.
Note: The service pumps will do all pumping down the tubing, and the rig pumps
will do all reverszng.
Note: Workstring pickle procedure as per MI Swaco and BJ Services
recommendations.
Note: Gravel pack Pumping pYOCedure as per BJ Services recommendation.
50. LCM Pill Breaker: If a pill was pumped to control fluid losses, pump 3.57 BBL
of 10% HCl w/ additives (~5 gals/ft) to within 5 BBLS of the packer. Shut
down pumps, slack off to SQUEEZE/CIRCULATING position, close the Hydril,
open the choke valve in the manifold and begin circulating acid down across
entire perforation interval. Close the choke and inject acid into formation until
trailing edge of acid is at top perforation. Allow acid to soak for 10-15 minutes.
51. Circulatin~ Rate Test: With tool in CIRCULATING/SQUEEZE position, open
choke and obtain circulating rates and pressures with filtered completion fluid at
%2, 3/, 1 and 2 BPM. Record stabilized circulating rates and pressures.
CIRCULATING RATE TEST
Step Rate
(BPM) Tubing
Pressure Annular
Pressure
1 1/2
'Z 3~
3 1
4 2
52. Step Rate Test: With tool remaining in the CIRCULATING/SQUEEZE
position, close the choke valve on the manifold, and perform the Step Rate Test
(SRT) with the following volumes and rates. Hold each rate constant for 2
minutes. Execute a hard shut down at the end of the Step Rate Test and let the
11
•
~
fracture close, record ISIP and pressure decline on the tubing. Discuss outcome
with Marathon Completion Engineer.
STEP RATE TEST
Step Rate
(BPM) Tubing
Pressure Annular
Pressure Cumulative
Vol. (BBL)
1 1 2
2 2 6
4 3 12
5 4 20
7 6 30
8 8 42
9 10 78
10 Max (12) TBD
ISIP 0
Note: Plan to pump job at 2 BPM above break-over Yate. If break-over is not
observed, plan on pumping job at max rate while staying ~l S00 psi below
maximum treating pressure.
53. Gravel Pack Treatment: With the crossover tool in the
CIRCULATE/SQUEEZE position, Hydril and choke closed bullhead 1,273 lbs of
12/20 mesh Ceramic Proppant infused in 30 BBL of completion fluid at 1.0
PPA (31.7 BBL of Slurry). Pump rate to be as determined by Step Rate Test.
Open choke to allow 1/Z BPM returns, and record circulating rates. Once sand hits
the perforations, monitor pressure until it increases 1,500 psi above circulating
pressure. Shut down Pump and immediately Pull up to REVERSE position and
reverse out all excess slurry.
Note: PrioY to performing job, Baker and Marathon will agree upon method of
inducing screen-out.
When screen out occurs calculate the density above the crossover and determine
the desired pressure needed on the backside to prevent U-tubing before pulling up
to REVERSE position.
54. Following screen-out, apply 1000 to 1500 psi overbalance on the annulus at the
tool (corrected for hydrostatic differences). Pick up and locate the REVERSE
position observe pressure Ioss on Annulus while continuing to pick up to
REVERSE position, reverse out until returns are clean (monitor returns vs. pump
rate). Pump 11/2 to 2 times the drill pipe volume to ensure cleanliness.
55. Flush the lines and manifold and rig down Baker pumping equipment.
12
• ~
Note: Have 100% Excess sand on location to do a top off job if required.
56. After returns are clean, shut down pumps, bleed off all pressure and pick up tool
until all seals of the Crossover tool out of the packer body and KOIV closes.
Monitor well for fluid loss. If losses are not acceptable, discuss LCM options.
Note: Please Yeference MI Swaco LCMpill recomrnendation.
57. Pu11 out of the hole, lay down drill pipe workstring the crossover tool/setting
tools.
Production Tubing:
58. Close blind rams. Change out upper pipe rams to 2-7/8" x 2-3/8, SM dual rams.
Open blind rams. Retest BOPE as needed.
59. Pull wear bushing.
60. RU dual elevators, dual spiders, and two sets of tongs for running 2-7/8", 6.5 ppf,
L-80, EUE 8rd tubing (longstring), and 2-3/8", 4.7 ppf, L-80, IBT-M tubing
(shortstring). Install dual mousehole. Lay out, drift, and tally tubing on separate
pipe racks.
61. Pick up and run in to the hole with 2-7/8", 6.50#, L-80, EUE 8rd Long String and
2-3/8" 4.7#, L-80, IBT-M dual tubing strings and Baker Model "GT" Dual
Packer and associated production equipment as per BOT Schematic Drawing.
The 2-7/8" longstring will include six 2-7/8" SFO-2 Mandrels with R-2 pressure
valves and RO-2 Orifice valve (lower most mandrel) installed and spaced out as
per attached gas lift design from Pollard.
Note: Prior to load out to rig, Pollard to load and test mandrels with valves, and
makeup and torque 12' pups above and below each mandrel (for ease of
handling).
Note: Caliper and check all tool connections and record lengths. Rabbit all
tubulars. Only one rabbit on rig floor.
62. Prior to locating KOIV set inside Upper Zone Gravel Pack assembly, record pick
up and slack off weights. Gently break KOIV with racheting muleshoe, pick up
tubing above Upper zone SC-1 packer at 5,627' MD, and allow debris to settle
into casing rathole below Model "D" Sump Packer at 5,782' MD for 30 minutes.
63. Lower tubing so that 80-32 "GS-22" Bonded Seal Units and Racheting Muleshoe
is located just above Lower Zone SGl Packer at 5738' MD. Prior to stinging 80-
32 "GS-22" Bonded Seal Units into packer, record pick up and slack off weights.
13
• ~
Gently slack off into Lower Zone SC-1 Packer. Will not be able to test annulus
since Upper Zone is exposed on the annulus.
64. Bleed off pressure, space out and install Vetco tubing hanger (using pin x pin
crossovers from National).
65. Rig up Pollard Wireline Unit to set Baker "GT" Packer as per BOT procedures
with N-Stop set in 1.75" ID "XN " Nipple in 2-3/8" Short String at 5,600'. Bleed
pressure and POOH with N-Stop.
66. RU on long string side and set PX plug in 2.323" ID "X" Nipples in 2-7/8" Long
String. Set prong in PX plug. Pressure up annulus and test dual packer to 2000 psi
against wireline pack-of£ Pull prong and PX plug. Rig down and release Pollard
Wireline Unit.
67. Install BPVs in tubing hanger. ND BOPE, NU 9-5/8" x 3-1/2" x 1-3/4" Dual Coil
Tubing Spool and dual tree. Pull BPVs, install 2-way checks in tubing hangers.
Test dual tree to 3000 psi using methanol. Pu112-way checks, reinstall BPVs.
RDMO Glacier rig.
14
~
•
~ ll ~ ~
o SARAH PAUN GOVERNOR
,
~as~ca~.7~ 0~ ~~S 333 W. 7thAVENUE, SUITE 100
C011TSERQ~7`I011T CO1rIItIISSI011T ANCHORAGE, ALASKA 99501-3539
PHONE (907) 279-1433
FAX (907) 276-7542
Craig Meese
Senior Completions Engineer
Marathon Oil Company
PO Box 1949
Kenai, AK 99611-1949
Re: Sterling Gas Field, Sterling Gas Pool, Sterling Unit 43-9X
Sundry Number: 307-220
Dear Meese:
Enclosed is the approved Application for Sundry Approval relating to the
above referenced well. Please note the conditions of approval set out in the
enclosed form.
When providing notice for a representa.tive of the Commission to witness any
required test, contact the Commission's petroleum field inspector at (90'7)
659-3607 (pager).
As provided in AS 31.05.080, within 20 days after written notice of this
decision, or such further time as the Commission grants for good cause
shown, a person affected by it may file with the Commission an application
for rehearing. A request for rehearing is considered timely if it is received by
4:30 PM on the 23rd day following the date of this letter, or the next working
day if the 23rd day falls on a holiday or weekend. A person may not appeal
a Commission decision to Superior Court unless rehearing has been
requested.
DATED this ~ day of July, 2007
Encl.
~ o~-- ~~-~
~in~PrPlv
~
M Marathon
MARATHON Oil Company
June 22, 2007
Mr. Tom Maunder
Alaska Oil & Gas Conservation Commission
333 W 7th Ave
Anchorage, Alaska 99501
Reference: 10-403 Sundry Notice
Field: Sterling Gas Field
Well: SU 43-9X
Dear Mr. Maunder,
~
Marathon Oil Company
Alaska Asset Team
P.O. Box 1949
Kenai, AK 99611
Telephone 907/283-1326
Fax 907/283-1350
Enclosed please find an Application for Sundry Approvals form 10-403 for Sterling Unit
well 43-9X and associated attachments. This well has been drilled, logged, cased, and
temporarily abandoned. Request for approval is being made to re-enter and complete
the well as a dual gravel pack completion in the Sterling B4 Sand.
If you require further information, you can reach me at 713-296-2214 or by e-mail at
cameese(a~marathonoil.com. Alternatively you may contact Kevin Skiba in our Kenai, AK
field office at 907-283-1371 or by e-mail at kskiba@marathonoil.com.
Sincerely,
~ . J Q. ~~"``t
Craig Meese
Completions Engineer
Enclosures: 10-403 Sundry Notice cc: AOGCC
Well Schematic Houston Well File
Description summary of proposal Kenai Well File
CAM
KJS
~ ~~ 1' ~".~S~ATE OF ALASKA 6-a~s~ ~~CEI V~L~
J- ALA~~~A OIL AND GAS CONSERVATION COM~SION
~ APPLICATION FOR SUNDRY APPROVALS ~~~~0 ~~UN 2 6~00?
20 AAC 25.280
ala~ka tlil R Gas C~ns. Cammission
1. Type of Request: Abandon ^ Suspend ^ Operational shutdown ^ Perforate ^~ Waiver [~~G~~~~~~~ Other ^~
Alter casing ~ Repair well ~ Plug Perforations ^ Stimulate ~ Time Extension ^
Change approved program ~ Pull Tubing ~ Perforate New Pool ^ Re-enter Suspended Well ^~
2. Operator Name:
Marathon Oil Company 4. Current Well Class: 5. Permit to Drill Number:
Develo ment
p ~ Exploratory ~
207-073 "
3. Address: Stratigraphic ~ Service ~ 6. API Number:
PO Box 1949, Kenai Alaska, 99611-1949 50-133-20569-00-00 ~
7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number:
property line where ownership or landownership changes:
Spacing Exception Required? Yes ^ No 0 Sterling Unit 43-9X `
9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s):
A- 028063 ~ 245' ~(21' AGL) Sterling Field / Sterling Unit Pools
12• PRESENT WELL CONDITION SUMMARY
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured):
6,185' S,698' 6,114' S,627' NA NA
Casing Length Size MD ND Burst Collapse
Structural
Conductor g2~ 20" 103' 103' 3,060 psi 1,500 psi
SurFace 1,969' 13/3/8" 1,990' 1,870' 3,450 psi 1,950 psi
Intermediate 6,153' 9-5/8" 6,174' S,687' 5,750 psi 3,090 psi
Production
Liner
PerForation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft):
N/A N/A N/A N!A N/A
Packers and SSSV Type: Packers and SSSV MD (ft):
N/A N/A
13. Attachments: Description Summary of Proposal 0 14. Well Class after proposed work:
Detailed Operations Program ~ BOP Sketch ~ Exploratory ~ Development ^~ Service ~
15. Estimated Date for 16. Well Status after proposed work:
Commencing Operations: 7~20/2007 Oil ~ Gas ^~ Plugged ^ Abandoned ^
17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^
Commission Representative:
18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba (907) 283-1371
Printed Name Craig Meese Title Senior Completions Engineer
Signature _ Q,' ~{ Phone (713) 296-2214 Date 6/22/2007
COMMISSION USE ONLY
Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~"~ ~~ a O
Plug Integrity ^ BOP Test ~ Mechanical Integrity Test ~ Location Clearance ^
Other. ~~vV ~ ~ Z b ~ ~,S (
., -r-
~~ JUL fl 9 ?OD7
Subsequent Form Required: ~O~ ~, ~~ ,
A
roved b
: APPROVED BY ~
COMMISSIONER THE COMMISSION Date:
~O
pp
y ~
Form 10-403 Revised 06/2006 ~~~ r~A! ~
v ~ v i~
~~,~~~ g~mit in Duplicate
~
~
SU 4
M Co-Prod
~uwnioM I I I
J
Shortstrinq - 2.375", 4.7#, L-80, IBT-M Tubing
(ID = 1.995")
GT dual packer wl 60K shear ring @ 5588'
XN-nipple @ 5600' (ID = 1.75")
Wireline re-entry guide at 5605'
STERLING B4 SAND
;I5724' - 5730' (6') t . -~--
~~~~ I
i, ' ;~ ; "
"::
~ : S' •. F'
- 5~7s' (io')
sta rina - 2.875", 6.4#, L-80, EUE 8rd Tbg (ID =
1")
I's @ 1740', 2943', 3884', 4558', 5030', 5433'
;r GT Dual packer w/ 60k shear ring @ 5588'
Baker SC-1 gravel pack packer @ 5627'
Knock out isolation valve @ 5660'
5-1/2" x 18' x 12 ga BakerWeld 140 Screen @ 5720'
~ ~ Lonqstrinq: 2-7/8" x 10' longstring Blast
~ ioint (a~ 5724'
_onqstrinq - X-nipple @ 5736' (ID = 2.31:
Baker SC-1 gravel pack packer @ 5738'
I5-1/2" x 18' x 12 ga BakerWeld ~40 Screen (~ 5764' ~
hI
~ Baker Model D sump packer @ 5782'
~ ° ~ 9-5/8" 40ppf, L80 BTC @ 6174' (ID =
-6114' PBTD 8~835")
Cmt w/ 210 sx (78.6 bbls) 12.5 ppg
Class G Lead cmt followed by 400 sx
82.6 bbls 15.8 Class G tail cmt.
-4990' SSTVD
SBHP = 1980
GWC @ 5035' SSTVD
SBHP = 1990 nsip
SSTVD
Well Name & Number: SU 43-9X Lease Sterling Unit
County or Parish: Kenai State/Prov. Alaska Country:
Perforations: (MD) 5724' - 5730' (6') SS & 5766' - 5776' (10') LS (TVD) 5237' - 5243' SS & 5280' - 5290' LS
Angle/Perfs 0 deg Angle @KOP and Depth 0 deg @ 200' KOP TVD 200'
BHP: 1980 BHT: 0 Completion Fluid: 6% KCL
FW HP: FBHP: FW HT: FBHT: Other:
Date Completed: RKB:
Prepared By: C Meese Last Revision Date: 06/22/07
~
3-9X (Proposed WBD)
uction Well Dual Gas Lift
Surface Casinq: 13-3/8", 68 ppf, J-55,
BTC @ 1990'
Cmt w/ 280 bbis of Type 1 cmt
•
~
Maunder, Thomas E (DOA)
From: Maunder, Thomas E (DOA)
Sent: Thursday, July 05, 2007 4:08 PM
To: 'Kevin Skiba'; Dennis Donovan; Ken Walsh
Subject: RE: SU 43-9X
Dennis and Ken,
I have not heard back from Kevin.
Thought I would try you guys.
Thanks for the help.
Tom
-----Original Message-----
From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us]
Sent: Thursday, June 28, 2007 1:06 PM
To: Kevin Skiba
Subject: Re: SU 43-9X
Kevin,
Not sure you got the original send on this message. I got a bounceback on Craig's
eddress. Please pass this on to him.
Tom
Thomas Maunder wrote, On 6/28/2007 1:05 PM:
> Kevin and Craig,
> I am reviewing a sundry filed for this well. A sundry was required
> since the completion procedure was not described in the permit to
> drill package. I am requesting that you provide the procedure for
> what is planned. Email is fine. Just stating that you plan to
> complete with a dual gravel pack and providing the well drawing is not
> sufficient information.
>
> Also, temporarily abandoned is not a recognized well status by the
~ AOGCC. I recognize that the drilling program is prepared in Houston
> and the completion program is likely prepared in Kenai. Is it
> possible to meld the two procedures so that approval can be given with
> the drilling permit? That could save time for all involved.
>
> Thanks for your attention to this matter. Call or message with any
> questions.
>
> Tom Maunder, PE
> AOGCC
>
1
SU 43-9x NAD 27 Surface Coordinates
Art,
Please find attached the printout from the NADCON-based program that converts NAD83 coordinates to
NAD27. The State Plane coordinates for NAD27 are on that document.
I will start reporting NAD27 coordinates for you on future drilling permits, but would like to show both if
possible. If ! modified the 10-401 so that I could put both in, would that be a problem, or would the
AOGCC prefer that the document not be changed? Which ever is your choice is fine. I don't want to
modify the document if that is not OK. I'll just make sure you get NAD27 and have NAD83 elsewhere if
you don't want me to change the form.
Thanks,
Will Tank
«SU 43-9X Surface Coordinates.pdf»
' SU 43-9X Surface Coordinates.pdf
Content-Description: SU 43-9X Surface Coordinates.pdf
Content-Type: application/octet-stream
Content-Encoding: base64
1 of 1 6/13/2007 7:39 AM
~ ~:
~ ~
Marathon Oil Company
Sterling Unit
13 June 2007
INPUT
State Plane, NAD83
5004 - Alaska 4, U.S. Feet
OUTPUT
State Plane, NAD27
5004 - Alaska 4, U.S. Feet
Accuracies of conversions from NAD 83 to NAD 27 are typically 12 to ?8 cm.
SU 43-9X Surface 1/1
NOI'thltlg/Y: 2389868 NOYthlllg/Y: 2390106 _ 729
Easting/X: i454~~z.si Easting/X: 314~5z.1~~
Convergence:-o 53 51.58090
ScaleFactor: 0.999939zzi
Convergence: -o s3 44.62954
SC81@ FOCtOC 0.999939051
Grid Shift (U.S. ft.): X/Easting =-1140020.3, Y/Northing = 238.7
Datum Shift (m.): Delta Lat. = 63.550, Delta Lon =-122.043
Remark: SU 43-9X Surface Coordinates
Corpscon v6.0.1, U.S. Army Corps of Engineers
~ ~
~ ~ ~ ~ ~ ~~
~ ~ SARAH PA N
~; ~. ~ ~ U , GOVERNOR
°~~ ~uI ~ Vra*7 333 W. 7th AVENUE, SUITE 100
CO1~T5ERQA~'I011T COri1~IISSIOI~T ANCHORAGE, ALASKA 99501-3539
l PHONE (907) 279-1433
FAX (907) 276-7542
Willard Tank
Advanced Senior Drilling Engineer
Marathon Oil Company
3201 C. Street, Suite 800
Anchorage, AK 99503
Re: Sterling Gas Field, Sterling Pool, SU 43-9X
Marathon Oil Company
Permit No: 207-073
Surface Location: 2399' FSL, 428' FEL, SEC. 9, TSN, R l OW, S. M.
Bottomhole Location: 4252' FSL, 1236' FEL, SEC. 9, TSN, R10W, S.M.
Dear Mr. Tank:
Enclosed is the approved application for permit to drill the above referenced
development we1L
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 witnes any required test, contact the
Commission's petroleum field inspector at (9~7 ~E;~607 (pager).
~ 1 ~2
J n K. Norman
DATED this~ day of June, 2007
cc: Department of Fish & Game, Habitat Section w/ o encl.
Department of Environmental Conservation w/o encl.
STATE OF ALASKA
AL~,4 OIL AND GAS CONSERVATION CO~SION
PERMIT TO DRILL
2o aac ~s nn~
~~ RE~E11~~t~
~ MAY 2~ 2Q~
l~
A(aska A~( & Gas Cons. Commi~si
1a. Type of Work:
Drill ~ Redrill ~
Re-entry ~ 1b. Current Well Class: Exploratory ~ Development Oil ~
Stratigraphic Test ~ Service ~ Development Gas ~
Multiple Zone ~ Single Zone 0 1c. Specify if well is proposed for:
Coalbed Methane ~ Gas Hydrates ~
Shale Gas ^
2. Operator Name:
Marathon Oil Company 5. Bond: 8lanket ~ Single Well ~
Bond No. 5194234 / 11. Well Name and Number:
SU 43-9X
3. Address:
3201 C. Street, Suite 800, Anchorage, AK 99503 6. Proposed Depth:
MD: 6,151 TYD: 5,645 12. Field/Pool(s):
Sterling Field
4a. Location of Well (Governmental Section):
Surtace: 2,399' FSL, 428' FEL, Sec. 9, T5N, R10W, S.M. 7. Property Designation:
A-028063 ~ Sterling Unit Pool
Top of Productive Horizon:
4,252' FSL, 1,236' FEL, Sec. 9, TSN, R10W, S.M. 8. Land Use Permit: 13. Approximate Spud Date:
June 8, 20Q7
Total Depth:
4,252' FSL, 1,236' FEL, Sec. 9, T5N, R10W, S.M. 9. Acres in Property:
1,878.06 ~ 14. Distance to Nearest
Property: 1,245 ft
4b. Location of Well (State Base Plane Coordinates):
Surtace: x- 1,454,772.5' y- 2,389,868.00 Zone - 4 10. KB Elevation
(Height above GL): (21' AGL) 245 feet 15. Distance to Nearest Well
Within Pool: 1,982 ft to SU 43-9
16. Deviated wells: Kickoff depth: 200 feet
Maximum Hole Angle: 33.16 degrees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035)
Downhole: 2,466 Surtace: 1,243
18. Casing Program: Specifications To p - Setting Depth - Bottom Cement Quantity, c.f. or sacks
Hole Casing Weight Grade Coupling Length MD TVD MD ND (including stage data)
Driven 20" 133 K-55 PE 79' 0' 0' 100' 100'
16" 13 3/8" 68 L-80 BTC 1,979' 0' 0' 2,000' 1,886' 608 sacks
12 1/4" 9 5/8" 40 L-80 BTC 6,130' 0' 0' 6,151' 5,645' sacks
i `1~ '~
19. PRESENT WELL CONDITlON SUMMARY (To be completed for Redrill and Re-Entry Operations)
Total Depth MD (ft): Total Depth ND (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth ND (ft): Junk (measured):
Casing Length Size Cement Volume MD ND
C o n d u cto r/ Stru ctu ra I
Surface
Intermediate
Production
Liner
Perforation Depth MD (ft): Perforation Depth ND (ft):
20. Attachments: Filing Fee 0 BOP Sketch 0 Drilling Program Q Time v. Depth Plot ~ Shallow Hazard Analysis ~
Property Plat Q Diverter Sketch Q Seabed Report ^ Driliing Fluid Program Q 20 AAC 25.050 requirements ~
21. Verbal Approval: Commission Representative: Date
22. I hereby certify that the foregoing is true and correct. Contact
Printed Name Willard J. Tank Title Advanced Senior Drilling Engineer
~
Signature ,~,~%c~ <`~~~L~ Phone 713-296-3273 Date May 24, 2007
Commission Use Only
Permit to Drill
Number: aO~(~r~O API Number:
50-f~„3'p~OS69 OOpQ Permit Approv
Date: See cover letter for other
requirements.
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, s hydrates, or gas contained in shales:[~]
Other: ~~~~ S` 3~~ ~~~ Samples req'd: Yes[ ~ No Mud log req'd: Ye4 No~
~ HzS measures: Yes^ No Directional svy req'd: Yes[~] No~
~~~ cAODl1CS~'~i0`l~ t~~Q~ L!~ ~~ ~ \fc~\~"t~ ~Q ~J ~
~ i ~~ ~ 0 .
APPROVED BY THE COMMISSION
DATE: ^~ o~ , COMMISSIONER
Form 10-401 Revised 12/2005 p R~~~ N A L `~ ~ ~ Submit in Duplicate
~
M Marathon
MARATHON Oil Company
May 24, 2007
John Norman
Commissioner
State of Alaska
Alaska Oil & Gas Conservation Commission
333 West 7th Ave, Suite 100
Anchorage, AK 99501
Reference: Drilling Permit Application
Field: Sterling Field
Well: SU 43-9X
Dear Mr. Norman
~
Worldwide Drilling
North America
P.O. Box 3128
Houston, TX 77253-3128
Telephone 713-629-6600
Fax 713-499-6737
~~~~~~~~
M~~ ~ ~
~~~~~7
~li~sk~ OiI ~ ~~~ ~~t~~, t~
~~°1miS~j~~
~1~~hv~~~~
Enclosed please find the PERMIT TO DRILL application, along with the associated
attachments and filing fee of $100. The intent is to drill a well in the Sterling pool in the
Sterling Field. No completion is desired in the Beluga or Tyonek pools.
Please note that the surface coordinates for this well and the directional plan are now
utilizing North American Datum 1983 (NAD 83) as required in the latest BLM 43 CFR Part
3160, Onshore Order No. 1, dated March 7, 2007. Getting well and surface equipment
coordinates on this GPS based standard (NAD 83) has been an effort that Marathon has
been working on and will continue fio progress.
If you require further information, I can be reached at 713-296-3273 or by e-mail at
wjtank@marathonoil.com.
Sincerely,
~2'~.C~~ ~~_~~/~---
Willard J. Tank
Advanced Senior Drilling Engineer
Enclosures
SU 43-9X
Drilling Program
~ ~
/ `
MARATHON
MARATHON OIL COMPANY
DRILLING PROGRAM
Sterling Field
SU 43-9X
Originator:
Will Tank ~
Reviewed by:
Pete Berga
Mav 24, 2007
Date
Date
Brian Rov
Date
Marathon Oil Company
Alaska
5/24/2007 CONFIDENTIAL MATERIAL Page 1 of 18
SU 43-9X ~ ~ Marathon Oil Company
Drilling Program Alaska
TABLE OF CONTENTS
1. Emergency Response Information .................................................................................................................. 2
1.1 Directions to Location ...................................................................................................................................... 2
1.2 Rig Contact Numbers ...................................................................................................................................... 2
1.3 Marathon Emergency Response Contacts ..................................................................................................... 2
1.4 Outside Emergency Response ....................................................................................................................... 2
1.5 Marathon Contact List ..................................................................................................................................... 2
2. Regulatory Agency Contacts .......................................................................................................................... 2
2.1.1. Internal Regulatory Contact ............................................................................................................................ 2
2.1.2. External Regulatory Confacf ........................................................................................................................... 2
3. Regulatory Compliance ................................................................................................................................... 2
4. Drilling Program Summary .............................................................................................................................. 2
4.1 General Well Data ........................................................................................................................................... 2
4.2 Working Interest Owners Information ............................................................................................................. 2
4.3 Geologic Program Summary ........................................................................................................................... 2
4.4 Summary of Potential Drilling Hazards ...........................................:............................................................... 2
4.5 Formation Evaluation Summary ...................................................................................................................... 2
4.6 Drilling Program Summary .............................................................................................................................. 2
4.7 Casing Program Summary .............................................................................................................................. 2
4.8 Casing Design ................................................................................................................................................. 2
4.9 Calculation of Maximum Anticipated Pressures (MAWP and MASP) ............................................................. 2
4.10 Casing Test Pressure Calculations ................................................................................................................. 2
4.11 Blowout Prevention Equipment, Testing and General Procedures ................................................................. 2
4.11.1. Function Testing .............................................................................................................................................. 2
4.11.2. Pressure Testing ............................................................................................................................................. 2
4.12 Wellhead Equipment Summary ..................................................................................................................... 2
4.13 Directional Program Summary ........................................................................................................................ 2
4.14 Directional Surveying Summary ...................................................................................................................... 2
4.15 Drilling Fluid Program Summary ..................................................................................................................... 2
4.16 Drilling Fluid Specifications ............................................................................................................................. 2
4.17 Solids Control Equipment ................................................................................................................................ 2
4.18 Cement Program Summary ............................................................................................................................ 2
4.19 Bit Summary .................................................................................................................................................... 2
4.20 Hydraulics Summary ....................................................................................................................................... 2
4.21 Formation Integrity Test Procedure ................................................................................................................ 2
5/24/2007 CONFIDENTIAL MATERIAL Page 2 of 18
SU 43-9X
Drilling Program
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Marathon Oil Company
Alaska
Attachments
Group Attachment Attached
Commercial Information AFE
Da s/Cost vs. Depth Curves X
Project Objectives and Scorecard
RSO Coding Information X
Re uisitions
Vendor List
Bonus Pro ram
Drilling Contract
Regulato / HES Information Emergency Evacuation Plan X
H2S Contin enc Plan n/a
Re ulato Permits X
Regulato Rules and Regulations
Risk Anal sis
Miscellaneous Programs (Vendors) Bit Pro osal X
Cement Proposal X
Directional Plan X
Fluids Pro ram X
Wellhead Equipment - Description/Drawings
Drill String and BHA Summa
Rig Mobilization/Mooring Procedure n/a
Geolo ical Information Location Map w/ offsets X
Offset Data
Proposed Formation Pore Pressure, Mud Wt & Fracture Gradient X
Tem erature Curves
Geologic Structure Maps
Geolo ic Cross Section
Bath met Map n/a
Anal sis Riser Anal sis n/a
Station Kee in Anal sis - Mooring/DP n/a
Stress Check Casing Design File X
Maximum Allowable Overpull
Miscellaneous Information Wellbore Diagram n/a
Rig Elevations X
Well Location Dia ram X
BOP Schematic X
BOP Well Control Bridging Document
Detailed Casin Specifications X
Detailed Drill Pipe Specifications
5/24/2007 CONFIDENTIAL MATERIAL Page 3 of 18
SU 43-9X ~
Drilling Program
1. Emerqencv Response Information
1.1 Directions to Location
~
Marathon Oil Company
Alaska
Method Directions
Air Latitude - 60°32'15.628"N Longitude - 151 °01'51.465"W
From the Kenai airport, go 0.4 mile South on North Willow Street. Turn East on Airport Way, go 0.5 miles. Turn East on Kenai
Ground Spur Highway and go 7.8 miles. Turn East on Sports Lake Road and go 0.9 miles. Turn North on Conner Road and go 2.5 miles
to Sterling pad 43-9.
1.2 Riq Contact Numbers
Contact Office Cell
Glacier Drilling Rig 1
Inlet Drilling Tool Pusher 907-283-1314 907-394-1321
Marathon Supervisor 907-283-1312 907-394-1317
1.3 Marathon Emerpencv Response Contacts
Individual Postion Main Phone Alternative
Kenai Gas Field Emergency Number 907-283-6465
CERT 24 hrs Notification 1-800-MOC-CERT
CERT Crisis Center Houston 713-296-4230 713-296-4237
1.4 Outside Emerqency Response
Location Gontact Phone
Fire Kenai / Soldotna, Alaska 907-262-4792
Ambulance
Hospital Kenai / Soldotna, Alaska Central Peninsula Hospital 907-262-4404
Police
Kenai / Soldotna, Alaska Kenai Police
Soldotna Police
State Police 907-283-7879
907-262-4455
907-262-4453
Coast Guard 800-478-5555
Spill and Contamination Alaska Alaska State Spill Reporting
National Response Center Oil / Toxic Chemical Spills 800-424-8802
Best Practices:
1 Policy: Post emergency notification information on rig floor, company man's and tool pushers'
office
Comments:
5/24/2007 CONFIDENTIAL MATERIAL Page 4 of 18
SU 43-9X
Drilling Program
r i
Marathon Oil Company
Alaska
1.5 Marathon Contact List
Contact Title Office Mobile Facsimile Home
Will Tank Drilling Engineer 713-296-3273 713-203-8398 713-499-6737 832-934-2617
Pete Berga Drilling Superintendent 907-565-3032 907-529-0551 907-565-3076 907-346-3763
Bryan Roy Drilling Manager 713-296-3256 832-444-4772 713-499-6707 281-246-4686
Jennifer Enos Geologist 713-296-3319 713-408-3583
Moksh Dani Reservoir Engineer 713-296-3140 832-692-4700
Craig Meese Completion Engineer 713-296-2214 713-725-7114
Ken Walsh Production Engineer 907-283-1311 907-394-3060 907-283-3050
John Nicholson Drilling Supervisor 907-283-1312 907-394-2641 907-283-1313
Dan Byrd Drilling Supervisor 907-283-1312 907-394-2641 907-283-1313
Mike Feketi Drilling Superoisor 907-283-1312 907-394-2641 907-283-1313
Rowland Lawson Drilling Supervisor 907-283-1312 907-394-0953 907-283-1313
2. Requlatorv Aqencv Contacts
2.1.1. Internal Requlatorv Contact
Contact Title O~ce Phone Cell Phone Home Phone Facsimile
Chick Underwood Re ulato Com liance 713-296-3254 979-830-7927 979-836-9390 713-499-6748
2.1.2. External Requlatorv Contact
Contact Title Office Phone Facsimile 24 hr Emergenc Pager
AOGCC 907-793-1236
BLM 907-267-1442
3. Requlatorv Compliance
Regulation Requirement
20 AAC 25.035 e 10 A BOP testing interval requirement is now 14 days.
20 AAC 25.035 e 10 F Requirement for a 24 hour notice to AOGCC prior to BOP test.
Comments
5/24/2007 CONFIDENTIAL MATERIAL Page 5 of 18
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SU 43-9X
Drilling Program
Marathon Oil Company
Alaska
4. Drillinq Proqram Summarv
4.1 General Well Data
Well Name SU 43-9X Lease / License
Surface Location 2,399' FSL, 428' FEL, Sec. 9, T5N, R10W, S.M. WBS Code DD.07.15309.CAP.DRL
SIoUPad Sterling Pad 43-9 Field Sterling Field Spud Date 06/08/07 (est.)
KB (above MSL) 245' County/Province Kenai Peninsula API No.
GL (above MSL) 224' State / Country Alaska Permit No.
Perm. Datum KB Total MD 6,151' Weli Class Development
Water Depth N/A Total TVD 5,645' Rig Contractor Glacier Drilling
Water Protection Depth Rig Name Glacier Rig 1
Best Practices:
Comments:
4.2 Workinq Interest Owners Information
Compan Workin Interest Address Phone Facsimile
Marathon 100% P.O. Box 196168 g07-561-5311 907-565-3076
Anchorage,AK 99519-6168
4.3 Geoloqic Proqram Summarv
SurFace Location Coordinates - NAD 83
From LeaselBlock Lines 2,399' FSL, 428' FEL, Sec. 9, T5N, R10W, S.M.
Latitude 60° 32' 15.628" N
Longitude 151 ° 01' 51.465" W
UTM North (Y) 2,389,868.00'
UTM East (x) 1,454,772.51'
Tolerance
Pore Pore
MD - RKB ND - RKB Pressure Pressure Possible
Formation (ft) (ft) (psi) (ppg) Lithology Fluid Content ,
Sterling B-4 (Primary Target) 5,769 5,263 7.7 - 8.3 Sandstone Gas
Beluga (Not a Prod Target) 6,106 5,600 7.7 - 8.3 Sandstone Gas
5/24/2007 CONFIDENTIAL MATERIAL Page 6 of 18
SU 43-9X
Drilling Program
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Marathon Oil Company
Alaska
Depth (KB) Horizontal
Displacement (ft)
Target MD
(ft) ND
(ft)
Location +N/-S
(Y) +E/-W
(X) Tolerance
(ft)
Sterling B-4 5,769 5,263 4,252' FSL, 1,236' FEL, Sec. 9, T5N, R10W, S.M. 1,853 -808 Circle 200' radius
Beluga 6,106 5,600 4,252' FSL, 1,236' FEL, Sec. 9, T5N, R10W, S.M. 1,853 -808 Circle 200' radius
TD 6,151 5,645 4,252' FSL, 1,236' FEL, Sec. 9, T5N, R10W, S.M. 1,853 -808 Circle 200' radius
4.4 Summarv of Potential Drillinq Hazards
Depth KB
Hazard Event Discussion Precautions
~p~
Lost Circulation in High Perm Production Control losses by using sufficiently sized LCM, Take care not to surge the hole during
Sterling sands Hole including fibrous and calcium carbonate types. tripping operations.
Potential Hazards Statement
To comply with state regulations the Potential Hazards section and the well shut-in procedures must be posted in the
driller's dog house. The man on the brake (driller or relief driller) is responsible for shutting the well in (BOPE or diverter
as applicable) as soon as warning signs of a kick are detected and an influx is suspected or confirmed. A copy of the
approved permit to drill must be kept on location and be readily available to the AOGCC or BLM inspector.
This well's primary objective is gas and no oil sands are expected to be encountered. No HZS is anticipated.
Gas sands will be encountered from +/- 5,769' MD (5,263' TVD) to total depth of the well. These sands will run from
slightly depleted to normal pressure. Lost circulation and differential sticking are potential hazards in some of the Sterling
sands. The Flo-Pro mud system that will be used to drill the well will help reduce these risks and lost circulation materials
will be on location. Weighting material will available on location for proper well control.
Best Practices:
1
Comments:
4.5 Formation Evaluation Summarv
Interval LWD Electric Logs Mud Logs
SurFace
0' - 2,000' MD None None None
Production
2,000' - 6,151' MD None Reeves Quad Combo, MFT. Pull GR-
Neutron to surFace. Basic with GCA, shale density, temperature in and
out, sample collection (10' samples).
Completion N/A GR, CCL, CBL N/A
Comments:
5/24/2007 CONFIDENTIAL MATERIAL Page 7 of 18
SU 43-9X
Drilling Program
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Marathon Oil Company
Alaska
4.6 Drillinq Proqram Summary
Drive Pipe: N/A
Conductor: 20" set to approximately 100', prior to drilling rig move. MIRU drilling rig. NU diverter.
1. RU crane and hammer. Drive 20" conductor to +/-100 ft. RKB. RD crane and hammer.
2. Move in and rig up rotary drilling rig.
3. Install starting head 20" SLC x 21 1/4", 2M flanged.
4. Nipple up 21 1/4", 2M diverter, 16" diverter valve, and 16" diverter line.
5. Function test diverter and diverter valve.
Best Practices:
1
Comments:
Surface: Drill 16" hole to +/- 2,000' set 13-3/8" casing.
1. Drill a 16" hole to 2,000' MD (1,886' ND) per the directional plan.
2. RIH with 13 3/8" casing and hang off in the elevators. Make up stab-in sub and centralizer on 5" drill pipe. TIH with inner
string and latch into stab-in float collar. Cement 13 3/8" casing. Sting out, shear out drill pipe wiper plug, and circulate drill
pipe clean. TOOH with inner string.
3. Cut off 13 3/8" casing. ND diverter.
4. Install 13 3/8" slip lock connection X 13 5/8" 5M flanged multibowl wellhead.
5. NU 13 5/8" 5M BOP'S. Test BOP'S and choke manifold to 250/2,000 psi.
6. Set wear bushing. ~"-"-°
7. Test surFace casing to 1,500 psi.
Best Practices:
1 During cementing operations, take returns in the cellar, instead of into the pits. Eliminates the
clean up of pits from cement that circulated to surface. Vac trucks will pull from cellar.
Comments:
Production: Drill 12 1/4" hole to +/- 6,151' set 9-5/8" casing.
1. PU 12 1/4" bit and directional BHA. Drill float equipment and 20' of new formation. CBU.
2. Test shoe to leak off. Estimated EMW 13.5 ppg.
3. Drill 12 1/4" hole to an anticipated TD of 6,151' MD (5,645' TVD) as per the directional program, short tripping as required.
4. At TD circulate hole clean. Make wiper trip. TOOH.
5. RU Precision. Run open hole logs as per plan. RD logging company.
6. TIH w/ 12 1/4" bit to TD for wiper trip. TOOH and lay down BHA and drill pipe. Pull wear bushing. ~~QQ~g'~
7. Change out variable pipe rams with 9 5/8" casing rams. Run test plug and test casing rams to 2 psi. ,/~
8. RU and run 9 5/8" casing string. Cement 9 5/8" casing while reciprocating. /;,~ ~`~~
9. Bump plug with 500 psi over displacement pressure. Land hanger in multibowl wellhead. WOC.
10. Back out landing joint. ND BOP stack.
11. NU 13 5/8" 5M X 13 5/8" 5M tubing head, 13 5/8" 5M X 3 1/16" 10M tubing head adapter, and dry hole flange. Test tubing
head to 5,000 psi.
12. Rig down and move out drilling rig.
Best Practices:
1 Drill all hole sections with 5" drillpipe to maximize hole cleaning hydraulics.
2 Pre-heat mud mix water to help in early shaker screen blinding issues with the mud.
5/24/2007 CONFIDENTIAL MATERIAL Page 8 of 18
SU 43-9X
Drilling Program
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Marathon Oil Company
Alaska
3 Do not circulate on bottom longer than 1 hour prior to moving pipe on a short trip to minimize
hole washout. This is important when waiting on log analysis to give EXCAPE module
placement points.
4 Put lubricant in prior to drill out of production shoe. 5°/a Lubetex is normally required, possibly
more depending on solids in the mud.
Comments: Due to possible losses in the Sterling, both calcium carbonate and fibrous material may be
needed. Care must be taken on trips to minimize the possibility of surging the hole.
Complefion: The completion will be handled by the rig, after work is completed on the next well, SU 41-
15RD. The rig will be moved back on to the well to run a dual tubing string and packers,
with sand control. A separate procedure will follow.
Best Practices:
1
Comments:
5/24/2007 CONFIDENTIAL MATERIAL Page 9 of 18
~
SU 43-9X
Drilling Program
4.7 Casinq Proqram Summarv
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Marathon Oil Company
Alaska
MD (ft) Connection A PI Ratings
Casing Makeup Hole ~.~ n., o~,
Size Weight ID Drift O. D. Torque Size m a o a ~:~'
(in) Top Bottom (Ibs/ft) {in) (in) Grade Type (in) (ft-Ibs) (in) V ~
I 133/8 0 2,000 68 12.415 12.259 L-80 BTC 14.375 N/A" 16 5,020 2,260 1,545
9 5/8 0 6,151 40 8.835 8.679 L-80 BTC 10.625 N/A "` 12 1/4 5,750 3,090 979
Best Practices:
1 Have float equipment made up at Tubescope's yard prior to bringing casing to location. Buck
on all equipment to the pin end and not make up to box below, due to rig height restrictions.
2*- Make up buttress connection to proper mark, not to a torque value.
Comments:
4.8 Casinq Desiqn
Casing Shoe Safety Factors
Setting Maximum
Casing
Depth
Mud Wt
Fraa
Form
Surface N
a c
o
'
Size Weight TVD When Set Grad Press Pressure ~ o ~
(in) (Iblft) Grade (ft) (Ib/gal) (Ib/gal) (Ib/gal) (psi) m U ~
13 3/8 68 L-80 1, 886 9.4 13.5 8.4 1,135 3.08 2.46 4.33
9 5/8 40 L-80 5,645 9.5 13.0 8.4 1,243 1.15 1.11 2.03
4.9 Calculation of Maximum Anticipated Pressures (MAWP and MASP)
Setting
Casing Depth
Size ND MAWP * MASP "* Mud/Gas
(in) (ft) (psi) (psi} Percentage
13 3/8 1,886 3,406 1,135 30/70
9 5/8 5,645 3,996 1,243 30/70
* MAWP = Maximum allowable working pressure
"* MASP = Maximum anticipated surface pressure
The calculation method for MASPBHP has been modified from the standard AOGCC use of a Bottom Hole Pressure - 0.1 psi/ft
gas gradient to what Marathon considers a more accurate Bottom Hole Pressure - 30% Mud Column - 70% Gas Column. This
method follows the MMS standard for any well with a ND of 12,000' or less. Marathon believes that constant gas monitoring
and proper rig supervisor well control training will prevent the possibility of a wellbore being completely evacuated with only
a gas gradient remaining.
5/24/2007 CONFIDENTIAL MATERIAL Page 10 of 18
~ ~
SU 43-9X
Drilling Program
Surface casinq: 13 3/8" (2,000' MD, 1,886' TVD)
MASPf~a~ _((Fracture gradient at shoe) x.052 x TVDsnoe) - Hydrostatic pressure of gas column at the shoe.
MASPfrac =(13.5 ppg x.052 x 1,886') -(0.1 psi/ft x 1,886')
MASPtrac = 1,324 psi - 189 psi
MASPfrac = 1,135 pSi.
MASPbnP = BHPoPe~ noie cd - Hydrostatic pressure of mud portion - Hydrostatic pressure of gas portion
MASPbnP =(8.40 ppg x.052 x 5,645') -(0.3 x 9.4 ppg x.052 x 5,645') -(0.7 x 0.1 psi/ft x 5,645')
MASPbnP = 2,466 psi - 828 psi - 395 psi
MASPbnp = 1,243 psi ,~,,~'\~~ +
SG`~ O+l~.~~ ' = ~~~ ~ ~ \
MASP = MASPfrac = 1,135 psi ~~ {q ~~~
MAWP =(0.7 x Casing Burst) -(Mud Wt. - Backup Fluid Wt.) x.052 x TVD
MAWP =(0.7 x 5,020) -(9.4 - 8.3) x.052 x 1,886'
MAWP = 3,514 psi -108 psi = 3,406 psi
Production casinp: 9 5/8" (6,151' MD, 7,582' ND1
MASPf~a~ _((Fracture gradient at shoe) x.052 x TVDsnoe) - Hydrostatic pressure of gas column at the shoe.
MASPfrac =(13.0 ppg x.052 x 5,645') -(0.1 psi/ft X 5,645')
MASPfrac = 3,816 psi - 565 psi
MASPfrac = 3,251 psi.
MASPbnP = BHPope~ no~e cd - Hydrostatic pressure of mud portion - Hydrostatic pressure of gas portion
MASPbnP =(8.40 ppg x.052 x 5,645') -(0.3 x 9.4 ppg x.052 x 5,645') -(0.7 x 0.1 psi/ft x 5,645')
MASPbnp = 2,466 psi - 828 psi - 395 psi
MASPbhp = 1,243 psi
MASP = MASPbnp = 1,243 psi
MAWP =(0.7 x Casing Burst) -(Mud Wt. - Backup Fluid Wt.) x.052 x TVD
MAW P=(0.7 x 5,750) -(9.5 - 9.4) x.052 x 5,645'
MAWP = 4,025 psi - 29 psi = 3,996 psi
Best Practices:
1
Comments:
4.10 Casinp Test Pressure Calculations
Marathon Oil Company
Alaska
Casing test pressure calculations are based on the lesser of (1) MASP, or (2) 70% of rated burst pressure of the casing adjusted for
the mud weight used during the test less a 8.3 ppg back-up unless otherwise noted. AOGCC regulations state that casing pressures
must be 50% of the BOP working pressure documented on the approved permit to drill.
Best Practices:
1
Comments:
5l24/2007 CONFIDENTIAL MATERIAL Page 11 of 18
SU 43-9X ~
Drilling Program
4.11 Blowout Prevention Equipment, Testinq and General Procedures
~
Marathon Oil Company
Alaska
BOP PROGR AM
Casing Test Test
Casing Test Fluid Pressure
Size MAWP MASP Press Density g~PS LowlHigh
Casing (in) (psi) (ps~) (psi) (Ib/gal) Size & Rating (psi)
(1) 13-5/8" 5M annular
(1) 13-5/8" 5M pipe ram
Surface 13 3/8 3,406 1,135 1,500 9.4 25012,000
(9) 13 5/8" 5M blind ram
(1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets
(1) 13-5/8" 5M annular
(1) 13-5/8" 5M pipe ram
Production g 5/8 3,996 1,243 1,500 9.5 250/2,000
(1) 13 5/8" 5M blind ram
(1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets
Blowout Preventers
The blowout preventer stack will consist of a 13-5/8" x 5000 psi annular preventer, a 13-5/8" x 5000 psi double gate ram type preventer
with blind rams in the bottom and pipe rams in the top and a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-1/8" x 5000 psi outlets.
The choke manifold will be rated 3-1/8" x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke. Also
included is a poor-boy gas buster, and a vacuum-type degasser. A flow sensor will be installed in the flowline and the mud pits will
contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers
console.
4.11.1. Function Testinq
Function Regularly.
5/24/2007 CONFIDENTIAL MATERIAL Page 12 of 18
• •
SU 43-9X
Drilling Program
Marathon Oil Company
Alaska
4.11.2. Pressure Testinq
The Marathon Drilling Supervisor will verify all pressure tests of BOP's, surface lines, seals, casings and FIT or LOT tests.
All tests are to be recorded on the IADC and daily drilling reports.
Best Practices:
1
Comments:
4.12 Wellhead Equipment Summarv
Component Description Casing Hanger Type
Casing Head
13-5/8" 5M X 13-3/8" Slip Loc W/ 2, 2" LPO, Landing Base for 20" Conductor, U, AA, PSL1, PR1 13 5/8" x 9 5/8" Fluted
Mandrel
Tubing Head 13-5/8" 5M Studded Bottom X 13-5/8" 5M Flg Top, W/ 2, 2-1/16" 5M Studded Outlets, 13 5/8" x 2 7/8" x 2 3/8" ,
U,AA,PSL1,PR1 Dual Hanger
Adapter Flange 13-5/8" 5M X 3-1/16" 10M W/ Seal Pocket and 3" H BPV Threads
Best Practices:
1
Comments:
4.13 Directional Proqram Summarv
Build Turn Coordinates
Sec.
No.
Description MD
(ft) ND
(ft) Rate
(°/100') Rate
(°/100') Dogleg
(°/100') Inclination
(deg) Azimuth
(deg) +N/-g
(ft) +E/_W
~ft~ VS
(ft)
1 Tie On 0 0 0 0 0 0 336.457 0 0 0
2 KOP 200.00 200.00 0 0 0 0 336.457 0 0 0
3 Build up Section 2.00 0 2.00 336.457
4 End of Build 1,857.99 1,766.97 2.00 0 2.00 33.16 336.457 427.70 -186.35 466.53
5 Hold Secfion 0 0 0 33.16 336.457
6 End of Hold 3,848.15 3,433.03 0 0 0 33.16 336.457 1,425.66 -621.16 1,555.10
7 Drop Section -2.00 0 2.00 336.457
8 End of Drop 5,506.14 5,000.00 -2.00 0 2.00 0 336.457 1,853.36 -807.51 2,021.64
9 TD 6,151.14 ~5,645.00 0 0 0 0 336.457 1,853.36 -807.51 2,021.64
5/24/2007 CONFIDENTIAL MATERIAL Page 13 of 18
SU 43-9X
Drilling Program
• ~
Marathon Oil Company
Alaska
o ~ - ----
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SU 43-9X Sterling B4 I '
5000 -- ~--- _ _" _~
SU 43-9X Belug~ `` ` ~ i
~ ---- ----9 5/8" i .
__
SU 43-9X T~ - i
6000 -
,
; ! i
-1000 0 1000 2000 3000 4000
Vertical Section at 336.46° (1800 ft/in)
c
~
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Comments:
Vertical section calculated from a reference azimuth of 336.46° taken from surFace location to bottom hole location.
Potential Well Interference:
Well Distance (ft1 Depth (MD)
SU 43-9 72.54 788
SU 41-15 72.99 Surface
SU 32-9 86.63 269
No serious interFerence exists. See attached directional plan and anticollision analysis for more details.
Best Practices:
1
Comments:
4.14 Directional Survevinq Summary
Other Survey
Interval MD (ft) MWD Survey Magnetic Multishot Gyro Multishot Remarks
Tool
SurFace 0 - 2,000' X
Production 2,000' - 6,151' X
Best Practices:
1
Comments:
5/24/2007 CONFIDENTIAL MATERIAL Page 14 of 18
-1500 -1000 -500 0 500
West(-)/East(+) (750 ff/in)
i ~
SU 43-9X
Drilling Program
Marathon Oil Company
Alaska
4.15 Drillinq Fluid Proqram Summarv
Interval - ND Minimum Inventory
From To Density Gel
(ft) (ft) (Ib/gal) Fluid Description Additives Viscosifier Barite
Gel, Gelex, Soda Ash, Caustic, Barite, Polypac
0 1,886 8.6 - 9.4 Gel / Gelex Spud Mud
Supreme UL, Sodium Meta Bisulfate
Flo-Vis, PolyPac Supreme UL, KCI, SafeCarb
1,886 5,645 9.0 - 9.5 6% Flo-Pro NT w/ Safecarb 10,40,250, Mix II, Barite, Caustic, Conqor 404,
Sodium Meta Bisulfate, Lubetex
Best Practices:
1
Comments:
4.16 Drillinq Fluid Specifications
Interval - TVD LSRV Drill
From
(ft) To
(ft) Density
(Ib/gal) Vis
(seGqt) 1 min
(Ib.l100ft2) PV
(cP) YP
(Ib/100 ft~) Fluid Loss
(cc)
pH Solids
(%)
0 1,886 8.6 - 9.4 60 - 100 N/A 25 - 35 NC - 12 +/- g.5 < 7.5
1,886 5,645 9.0 - 9.5 40,000 + 8- 12 7- 9 +/- 9.5 +/- 5
Best Practices:
1 As a standard practice for long string completions, the drilling mud that will remain above the
top of cement on the 9 5/8" production casing will be treated with corrosion inhibitor (Conqor
303A) at a concentration of 1 drum per 100 barrels of drilling fluid.
Comments: See mud prognosis for details. Sized CaCOs (SafeCarb) will be used to control leakoff.
5/24/2007 CONFIDENTIAL MATERIAL Page 15 of 18
SU 43-9X
Drilling Program
4.17 Solids Control Equipment
~ ~
Marathon Oil Company
Alaska
~
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Comments
0- 6,151' MD X X X X Closed Loop System, Full Containment, Run shakers with finest screens possible
Item Equipment Specifications
(quantity, design type, brand, model, flow capacity, etc)
Shaker 2- Swaco Mongoose PT
Desander N/A
Desilter 1- Derrick Model 0522
Mud Cleaner N/A
Centrifuge 2 - MI/Swaco units
Cuttings Dryer N/A
Cuttings Injection Marathon G&I Facility
Zero Discharge N/A
Best Practices:
1 Have vacuum trucks pull fluids from trough above slop pit to more efficiently pull fluids for
disposal. This minimizes water added to the solids to suspend for pickup by the trucks, thus
minimizing total volume to be disposed of.
Comments:
5/24/2007 CONFIDENTIAL MATERIA~ Page 16 of 18
~ ~
SU 43-9X
Drilling Program
Marathon Oil Company
Alaska
4.18 Cement Propram Summarv
De pth Gauge Top of Cement Gauge Ann Vol Slurry
Casing
Size
(~n)
MD
(ft)
TVD
(ft) Hole
Size
(~n)
MD
(ft)
TVD
(ft) Ann Vol
To TOC
(ft3) With OH
Excess
(ft3) Density
Lead/Tail
(PP9) Open Hole
Excess
(%a) Thickening
Time
(hrs)
20 100 100 Driven N/A
13 3/8 2,000 1,886 16 0 0 893 1,526 12.0 75 8
9 5/8 6,151 5,645 12 1/4 4,200 3,739 611 891 12.5 / 15.8 40 8
Mix Water Compressive
Casing
Size
Density
Qty
Yield Slurry
Vol TOC
MD
Qty
WL
FW Strength
(psi)
(in) Slurry Cement Description (Ib/gal) (sx) (ft3/sx) (ft3) (ft) (gal/sx) Type (cc) (%) 8 hr 24 hr
13 3/8 Tail Type I Cement 12.0 608 2.51 1,526 0 11.28 Fresh 812 0 196 818
Lead Class "G" 12.5 177 2.47 438 4,200 13.78 Fresh 559 0 92 645
9 5/8
Tail
Class "G"
15.8
387
1.17
453
5,200
4.99
Fresh
40
0
428
3,437
Best Practices:
1 Pump several fluid calipers at TD to help with the hole volume determination from the open
hole caliper log.
Comments: See cement prognosis for details and spacer specifications.
4.19 Bit Summarv
Interval - MD TYpe Recommended Estimated
From
(ft)
To
(ft)
Size
(in)
Manufacturer
Model No.
IADC
WOB
(kips)
RPM
Rotating
Hours ExpecTed '
Minimum ROP
(ft/hr}
0 2,000 16 Christensen MX-1 115 1- 4 80 - 350
2,000 6,151 12 1/4 Christensen HCM 506Z M323 Up to 52 Motor
Best Practices:
1
Comments: See bit prognosis for additional information. If a second bit is necessary for the 12'/4" hole a MX-C3 (IADC
137} should be used to finish this section. Back up bits for the 8%" hole section will consist of mill tooth and TCI tricone
bits.
5/24/2007 CONFIDENTIAL MATERIAL Page 17 of 18
SU 43-9X
Drilling Program
4.20 Hvdraulics Summarv
~ ~
Marathon Oil Company
Alaska
Qty
Make
Model
Liner ID
(in}
Stroke
(inj Max Press @
g0% WP
(psi) Displacement @
95% Vol. eff
(gal/stroke) Max Rate @
95% Vol. eff
(spm/gpm)
Hole Sections Used
On
5 8 2,597 2.04 125 / 255 Surface
3 National Oil Well A600PT 5 8 2,597 2.04 125 / 255 Intermediate
5 8 2,597 2.04 125 / 255 Production
Est.
Hole Pump Standpipe Openhole Nozzle
Depth-MD Size Rate Pressure Min AV MW ECD Size ~P at
bit
(ft) (in) (gpm) (psi) (fpm) (ppg) (ppg) (32"s) ( si) Remarks (Drill string configuration)
0- 2,000 16 650+ 1,400 69 9.3 2- 18's Actual Data KBU 24-7X (@ 1,636' MD)
1-16
2,000 - 6,151 12 1/4 663 2,050 130 9•5 6- 13's Actual Data KBU 24-7X (@ 6,077' MD)
Best Practices:
1 Drill all hole sections with 5" drillpipe to maximize hole cleaning hydraulics.
Comments: See separate hydraulics calculations. Annular velocities in the 16" and 12'/4" holes were
calculated using 5" drillpipe.
4.21 Formation Inteqritv Test Procedure
Surface and Intermediate casing shoes witl be tested to Leak-off. Prior to drilling out of casing strings, test BOPs and casing to the
specified pressure listed in the BOP Program section. Plot test and record volume required on the drilling report.
Leak-off tests (LOT) are to be conducted as described below:
1. Drill 20' to 25' of new formation below the casing shoe and condition the mud to the same properties in and out.
2. Pull drill string into the casing shoe and close ram preventer, and line up to the choke manifold with a closed choke.
3. Begin slowly pumping fluid down the drill string at 1/2 bpm while recording casing and drillpipe pressures at 1/2 bbl intervals.
A running plot of pressure versus volume should be kept by the drilling foreman while the test is in progress.
4. Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record
as ppg equivalent mud density in the IADC and morning reports. ~
5. Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes.
Best Practices:
1
Comments:
5/24/2007 CONFIDENTIAL MATERIAL Page 18 of 18
~ Marathon Oil ~
Well SU 43-9X
Diverter
21 1/4" 2M Diverter _~
Knife Valve
Diverter Spool
~ Marathon Oil ~
Well SU 43-9X
BOP Stack
13 5/8" 5M Cross
~ Marathon Oil •
Well SU 43-9X
Choke Manifold
To Gas Buster To Blooey Line
X ) ~ X
I
2 9/16" 10M Swaco
Hydraulically Operated
Choke
oo~ o ~
0
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~ ~
3" 5M Valves
Bleed off Line to
Shakers
X
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x
x
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00
~ °°° x x
x
I
3 1/8" 5M Manually
Adjustable Choke
From BOP Stack
~ ~
Surface Use Plan for Sterling Unit, well SU 43-9X
SurFace Location: 2,399' FSL, 428' FEL, Sec. 9, T5N, R10W, S.M.
1) Existing Roads
Existing roads which will be used for access to SU 43-9X are shown on the attached map.
Soldotna, Alaska is the nearest town to the site and is also shown on the map.
2) Access Roads to be Constructed or Reconstructed
No new roads will be required to access SU 43-9X.
3) Location of existing wells
Well SU 43-9X will be drilled on Sterling Field pad 43-9. A pad drawing is enclosed that shows
existing wells and the proposed location of SU 43-9X.
4) Location of existing and/or proposed facilities
The locations of existing production facilities on Sterling pad 43-9 are shown on the enclosed pad
drawing. A flowline will be installed from the SU 43-9X wellhead and additional treating equipment
will be installed to process the production from this well.
5) Location of Water Supply
A water supply well exists on the pad that SU 43-9X will be drilled from.
6) Construction Materials
No major construction is planned on the pad at this time. Leveling of the pad for this work will be
done with minimal materials needed.
7) Methods of handling waste disposal;
a) Mud and Cuttings
Cuttings will be dewatered on location. The cuttings and excess mud will be hauled to
Pad 41-18 of the Kenai Gas Field for disposal into Well KU 24-7, a Class II disposal well
(AOGCC Disposal Injection Order No.9, Permit #81-176).
b) Garbage
All household and approved industrial garbage will be hauled to the Kenai Peninsula
Borough Soldotna Landfill.
c) Completion Fluids
Clear fluids will be hauled to Pad 41-18 of the Kenai Gas field and injected in Well WD #1,
an approved disposal well (AOGCC Permit #7-194).
d) Chemicals
Unused chemicafs will be returned to the vendors that provided them. Efforts will be
made to minimize the use of all chemicals.
~ ~
e) Sewage
Sewage will be hauled to the Kenai sanitation facility.
8) Ancillary Facilities
A minimal camp will be established on the pad to house various supervisory and service company
personnel. Approximately four trailer house type structures will be required for this purpose.
Bottled water will be used for human consumption. Potable water will be obtained from the
existing water well on the pad. S& R will collect and transport sanitary wastes to their ADC
approved disposal facility. No additional structures will be necessary.
9) Plans for reclamation of the surface
SU 43-9X will be drilled from an existing pad. Reclamation of the pad will occur after the
abandonment of SU 43-9X and the other existing wells on the pad. Approval of the plan of
reclamation will be obtained from Salamatof Nafive Association prior to any reclamation work
beginning.
10) Surface ownership
The surface owner of the land in the Sterling Unit is the Salamatof Native Association.
11) Operator's Representative and Certification
I hereby certify that I, or persons under my direct supervision, have inspected the proposed drill
site and access route; that I am familiar with the conditions that currently exist; that the statements
made in this plan are, to the best of my knowledge, true and correct; and that the work associated
with operations proposed herein will be performed by Marathon Oil Company and its contractors
and subcontractors in conformity with this plan and the terms and conditions under which it is
approved. This statement is subject to the provisions of 18 U.S.C. 1001 for the filing of a false
statement.
Date: ~ Z Q 7
Name and Title: .l~.~~P
Willard J. Tank, dvanced Senior Drilling Engineer
Marathon Oil Company
P.O. Box 3128
Houston, TX 77253
(713) 296-3273
NORTH
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O
S.U. 43-9
0
AS-BUILT 8' C.M.P.
SU 43-9X
N= 2389868.00
E= 1454772.51
Lat: 60'32'15.628"N
S.U. 41-15RD ~o Long: 151'01'51.465"W
OO Elev.= 224.0'
S.U. 32-09
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NOTES
1. BA515 OF COORDINATES IS NGS STA. AUDRY. NAD83 ALASKA
STATE PLANE ZONE 4.
2. BASIS OF VERTICAL CONTROL IS NGS BENCH MARK MONUMENT
U 80, EL,EVATION = 161.16 FEET (NGVD 29).
3. THE CONDUCTOR FOR WELL 43-9X WAS NOT SURVEYED AND
THE LOCATION IS COMPUTED FROM THE CENTER OF THE CMP.
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1937
X=1455 167.16
SECTION LINE Y=2387 462.89 S9 :
NOTE: SECTION LINES
NOT TO SCALE S 16 ~
0
5
~i1iON PROJECT ~ REVISION: N/A
.~ryy^^ '~~vT STERLING UNIT PAD DATE: 5124/07
O~ VV~AL \ 1 DR4WN BY: JZW
w-w-~-ia+ ~ ~~ ~ S U 43-9X AS-B U I LT
scn~e r=~oa
PROJECT NO. 073023
BOOK NO. 07-OS
ENGINEERING - TESTING SURVEYING - MAPPING
Consultiny Inc P.O.BOX468SOLDOTNA,AK.99669 LOCATION SURFACE LOCATION DIAGRAM SHEET
~ VOICE: (907) 283-4218 FAX: (907) 2833265
~MNW.MCLANECG.COM SECTION 9, T5N, R10W,SEWARD MERIDIAN, ALASKA '~ oF ~
SCALE
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X=1455203.89
Y= 2390102.78
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SU 43-9X prop loc:
B4 = -5020'
TD = -5400'
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Top of Sterling B4 Structure
Sterling Field, AK
C1=25ft
0.25 mi
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TOPO! map printed on 04/26/07 from "Marathon SU 43-9x_SU 41-15RD.tpo"
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NATIONAL 0.0 0.5 1.0 1.5 miles I/19~/z°
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GLACIER DRILLING RIG #1
MUD PITS AND PUMP ROOM LAYOUT
.
i
MARATHON
MA ATHON Oil Company
Location: Cook Inlet, Alaska (Kenai Penninsula) Slot: SU43-9X
Field: Sterling Gas Field (NAD83) Well: SU43-9X
Facili : Pad 43-9 Wellbore~ SU43-9X
~~~
MV~iN~Y
INTEQ
Plot reference wellpath is SU43-9X Version #3
True vertical depths are referenced to Glacier #1 (RKB) Grid System: NAD83 / TM Alaska State Plane, Zone 4(5004), US feet
Measured depths are referenced to Glacier #1 (RKBj North Reference: True north
Glacier #1 (RKB) to mean sea level: 244.8 feet Scale: True distance
mean sea level to Mud line (Facility - Pad 43-9): O feet Depths are in feet
Coordinates are in feet referenced to Slot Created by: MichWilG on 5/24/2007
~~~
N
Q ~
~~
9~
1350
1800
2250
~
L
Q
~ 2700
R
U
t'
j 3150
N
3
LL
r
3600
4050
4500
4950
Oft
of Drop
Sterling B4
Beluga
i.625in Casing
~D
0 450 900 1350 1800 2250 2700
Vertical Section (ft) s`a'e„"`"=asssss"
Azimuth 336.46° with reference 0.00 N, 0.00 E from wellhead
Well Profile Data ~
Oealgn Comment MO (fl Inc (') Az (°) NO (R Local N(tt) Local E(ft) DLS (•/100fl) VS (R)
Tie On 0.00 0.000 33G.45] 0.00 0.00 0.00 0.00 0.00
KOP 20000 0.000 33G.45] 200.00 0.00 0.00 4.00 0.00
Entl of euim 1657.99 33.160 338.45] 176687 42].]0 -186.35 2.00 488.53
Be9inH~gleOrop 3848.15 33.760 336A51 3a33.03 7425.66 -621.16 0.00 ~555.10
Enaot~rop 5506.14 0.000 336.a51 5000.00 7853.36 ~807.57 2.00 2~31.64
Tar9et 6106.14 0.000 336.a5] SWO.oo 7853.36 A07S7 0.00 2021.64
TD 6151.14 0.000 336.a5] 56M15.ao 7853.36 ~807.57 0.00 20]i.6d
s a~e„ n=aoon Easting (ft)
MARATHON
~J
~
Planned Wellpath Report
SU43-9X Version #3
Page 1 of 4
~~~
BAKE R
~uc~NEs
INTEQ
~ ~
MARATHON
Planned Wellpath Report
SU43-9X Version #3
Page 2 of 4
rr-rr
BAKER
NVGNES
INTEQ
WELLPATH DATA (68 stations) -~ = interpolated/extrapolated station
MD Inclination Azimuth TVD Vert Sect North East Grid East Grid North DLS Build Rate Turn Rate
[feet]
_ [°I ~°1 ~~ [feet~ [feet] [feet] ~feet] [us survey feet] [us survey feet] ~,[
_ °/100ft] [
_. °/100ft] [°/]OOft]
0.00 0.000 336.457 0.00 0.00 0.00 0.00 1454772.51 2389868.00 0.00 0.00 0.00
100.00~ _
0.000 0.000 100.00 _
0.00:
0.00 0.00
1454772.51 __
2389868.00
0.00
0.00;
0.00
200.00 0.000 336.457 200.00 0.00 :
_
, 0.00 0.00 1454772.51 2389868.00 0.00 0.00' 0.00
300.00~'
400
00-
2.000 336.4~7 299.98
4
000 336
457 394
8
' _
1 75 ;
* ~
1.60 -0.70
4
2
9
1454771.84
4
4
69
82 _
2389869.61
238
~`
2.00
2
OQ
2.00
2
00
0.00
0
00
.
~
500.00~ .
4
.
.
6.000 336.457 499.45 _. _._ ._ __~
15.69 ; ` 6.
.7
0 -
_
14.39 -6.27 1
5
7
.
1454766.47 9$
__ _
2389882.48 .
2.00 .
2.00 .
0.00
600.00-~
8.000 336.457 598.70 _.
27.88 ;
~
25.56 -11.14
1454761 J8
2389893.73
_
2.00
2.00
0.00
700.00~' 10.000 336.457 697.47 -
43 52 ! -- _
39.90 -1738 1454755.75 _
2389908.16 2.00 2.00 0.00
800.00-~
900
OO 12.000 336.457 795.62
14
4
000 336 62.60
1 57.39 -25.01 1454748.41 2389925.77
4 2.00
2 2.00
2 0.00
0
00
.
t
1000.00~' .
.
57 893.06
16.000 336.4~7 989.64 0
$5,
110.98 78A1 -33.99
101.74 -44.33 1454739.75
14~4729.78 23899
6.53
2389970.42 .40
2.00 .00
2.00 .
0.00
1100.00~' 18.000 336.457 1085.27 140.21 128.54 -56.01 1454718.53 2389997.40 2.00 2.40 0.00
1200.00# 20.000 336.457 1179.82 172.77 158.39 -69.01 1454705.99 2390027.44 2.00 2.00 0.00
1300.00~
1400
00
' 22.000 336.457 1273.17
24
000 336
457 1365
21 208.60
247
67 l 9l .24 -83.32
227
06
98
93 1454692.20
14
4677
16 2390060.51
2390096
57 2.00
2
00 2.00
2
00 0.00
0
00
.
j
1500.00~' .
.
.
26.000 336.457 1455.84 .
289.93 .
-
.
265.80 -115.81 5
.
1454660.89 .
2390135.57 .
2.00 .
2.00 .
0.00
1600.00~' 28.000 336.457 1544.94 335.33 307.42 -133.94 1454643.41 2390177.46 2.00 2.00 0.00
1700.00~' 30.000 336.457 1632.39 383.81 351.86 -153.31 1454624.74 2390222 20 :
__. 2 00 i
_ __ 2 OOi
________.. 0.00
1800.00~
~857
99 32.000 336.457 1718.11
160 336
4
1
33
6
9 435.31
466
53 399.08 l 73.88
~; <,•
~
~
~ 1454604.92
4
92
90 ~
2390269 73 t
.,
2390
~ 2.00 ,
. f. .
~ 2.00~
~,. _ 0.00
0
.
1900.OOt .
.
57
7
6.
7
33.160 336.457 1802.14 .
~
489.51 ,~ r
;~
448.77~-195.53 145
5
.
1454584.05 ~, _
2390319J5 ~ 0.00 j ~ O.OOj ~n, ti~~~.0
0.00
2000.00~
33.160 336.457 1885.85
544.21 ~ - -
498 ~ ~~~
.91 -21738
1454562.99 _ __,_
2390370 23 ~ . _~~_
0 00 ~ ~ _ _ ;.
0.00
0.00
2100.OOt 33.160 336.457 1969.57 598.91 549.06 -239.22 1454541.93 2390420.70 ~i 0.00 i 0.00 0.00
2200.OOt 33.160 336.457 2053.28 653.61 599.20 -261.07
" 1454520.87 2390471.18 0.00 0.00 0.00
2300.00~
2400.OOt 33.160 336.457 2137.00 ?~~ ~°';~
33.160 336.457 2220.71 763.00 ,
.35 =282.92
699.49 -304.77 1454499.81
1454478.76 2390521.66
2390572.14 O.dO
0.00 0.00
0.00 4.00
0.00
2500.OOt 33.160 336.457 2304.43 817.70 ' 749.64 -326.62 1454457.70 2390622.61 0.00 0.00 0.00
2600.OOj' 33.160 336.457 2388.14 872.40 799J8 -348.46 1454436.64 2390673.09 0.00 0.00 0.00
2700.00~
2800
00
' 33.160 336.457 2471.86
160 336
457 2555
33
57 927.09
981 J9 849.92 -370.31
900
0
392
6 1454415.58
1
54394
52 2390723.57
2390774
05 0.00
__ _
O
~TQ ` 0.00
___
0
00 0.00
0
00
.
~
2900.00~ .
.
.
33.160 336.457 2639.29 1036.49 .
7 -
.1
950.21 -414.01 4
.
1454373.46 .
2390824.52 .
0.00 ' .
0.00 .
0.00
3000.00 j~
33.160 336.457 2723.00
1091.19 1000.36 -435.86
1454352.41
2390875.00
0.00 ; -_ .
0.00
0.00
3100.00 j'
33.160 336.457 2806.72
1145.88
1050.50 -457.70
1454331.35
2390925.48 _ _. --_ _
0.00
0.00
0.00
3200.00-~ 33.160 336.457 2890.43 1200.58 l 100.65 -479.55
"~9
4 1454310.29 2390975.96
~ .' 0.00 0.00
'~~ 0
00
~ 0.00
O
3300.00~
3400.00~ 33.160 336.457 2974,15 ~
33.160 336.457 3057.86 12~5.,~8
1309.98 1150.
-S~i.
4
1200.94 -523.25 .,1454289.23
1454268.17 2~'~
2391076.91 ; ~
0.00 .
,,
0.00 Q~~
0.00
3500.00~'
33.160 336.457 3141.58 _-
1364.67 1251.08 -545.10
1454247.11 _
239ll27.39 i .
0.00 ~
0.00
0.00
3600.00~
33.160 336.457 3225.29 _
1419.37 _ _
1301.23 .-566.94
' 1454226.05 _ ____. ~__ _____ _
239ll 77.87 ; _ ,_._
0 00 __. _
0.00
0.00
3700.00~
33.160 336.457 3309.01
1474.07 : ~ _
135137 -588.79
1454205.00
2391228.34 i
0.00'
0.00
0.00
On
~~
MARATHON
Operator MARATHON Oil ~
Area Cook Inlet, Alaska
Field Sterling Gas Field
Facilitv Pad 43-9
~
Planned Wellpath Report g ~/%~
AKER
SU43-9X Version #3 NVGHES
Page 3 of 4 INTEQ
~
- ----- -_ - _- -_ ._- - --- ---
iy Slot SU43-9X
ell
ellbore
VELLPATH DATA (68 stations) ~= interpolated/extrapolated station
MD Inclination Azimuth TVD Vert Sect North East Grid East Grid North DLS Build Turn
~feet~ ~°~ [°~ [feet] [feet~ [feet~ (feet~ (us survey feet~ ~us survey feetJ `~ °/100ft~' Rate Rate
'
,._ ' ~°/100ft1fI°/100f
_ _.._._.___
848.15 33.160 336.457 3433.03 1555.10 ',1425.66 -621.16 1454173.80 2391303.13 0.00 0.00 0.0
900.00~ 32.123 336.457 3476.69 '1583.07 I1451.30 -632.33
; ' 1454163.03 2391328.93 2.00 -2.00; 0.0
OOO.OOt _
30.123 336.457 3562.29 1634.75 r1498.68 -652.98
1454143.13
2391376.63 '
w
2.00
-2.00~
_._ ._
0.0
.____ _
100.00t 28.123336.457~~3649.65 ~~~1683.42 j154330 -672.41
~
`~ ' r 1454124.40 __
____, ._
2391421.541
' _
2.00
~
:4 -2.00~~
~ 0.0
p
200.00~
300.OOt 26.123 33~r:4
# ~
-590.62
_ ._, . _.,
_ ~_
24.123 336.457 3829.18 ;1771.46 .1624.01 -707.58 1454106.85
1454090.50 23914
~ ~
2391502.79 • ,
,
0
N
2.00 _
~Qp
-2.00' . Q,
0.0
400.00~ 22.I23 336.457 3921 14 ~1810.73 ~1660.01 -723.27 1454075.38 2391539.03 ~~ 2.00 -2.00 0.0
500.00~ 20.123 336.457 4014.42 1846.76 l 693.04 -737.66 1454061.51 2391572.28 2.00 -2.00 0.0
600.00 j~
700
OO 18.123 336.457 4108.90 1879.52 l 723.07 -750.74
16
123 336
4
42
4
96 1
8
62
0 1454048.90
3
6 2391602.52
239
29
68 2.00
2
00 -2.00
2
00 0.0
0
0
t
.
800.OOt .46 190
.
.
57
0
.
750.06 -7
.5
14.123 336.457 4300.99 1935.05 1773.98 -772.92 14540
7.5
1454027.52 16
.
2391653J6 .
2.00 -
.
-2.00 .
0.0
900.00~ 12.123 336.457 4398.38 1957.75 1794.79 -781.99 1454018.78 2391674.71 2.00 -2.00 0.0
000.00~- 10.123 336.457 4496.49 1977.04 1812.48 -789.70 1454011.35 2391692.51 2.00 -2.00 0.0
100.00~-
200
00 8.123 336.457 4595.22 1992.90 1827.01 -796.03
6
123 336
457 4694
4
2005
30 1838
38
800
98 1454005.25
1
54000
48 2391707.14
2391718
59 2.00
90 -2.00
-2
0 0.0
0
0
.
~
300.00~ .
.
.
5
.
.
-
.
4.123 336.457 4794.04 2014.22 1846.56 -804.55 4
.
1453997.04 .
2391726.83 ~
--
2.00
___ _ 0
.
-2.00
.--_ .
0.0
400.00~- 2.123 336.457 4893.89 2019.67 1851.56 -806.72 ] 453994.94 2391731.85 2.00 -2.00 0.0
500.00~ 0.123 336.457 4993.86 2021.63 1853.35 -807.51 1453994.19 2391733.66 2.00 -2.00 0.0
506.14
600
00 0.000 336.457 5000.00 2021.64 1853.36 -807.51
0
000 0
000 50
21
4 18
51
3
36
807 1453994.18
1453994
18 2391733.67
2391
33
67 2.00
0
00 -2.00
00
Q 0.0
0
.
~
700.00-~ .
.
.6
5
.
-
.
93 ~~e ~(~
0.000 0.000 5193.86 ,2021.64 1853.36 -807.51 .
1453994.18 7
.
2391733.67 .
0.00 „
.
0.00 0.
0.0
769.14-~ _ _ _____ n_ __ . _ _ _
0.000336.457 5263.00 ,2021.64'1853.36 !-807.51
1453994.18
2391733.67
0.00 ~_
0.00;
_..__ __ __ __ _
0.0
800.00~ , _.__
0.000 0.000 5293.86 `2021 64 ;185336 --807.51 1453994.18 2391733.67 0.00 0^00~ 0 0
~
900.OOt
000
00
' 0.000 0.000 5393.86 '2021.64 I1853.36 '-807.51
0
000 OA00 5493
86 ~24 ~
~'f
~~
8~7
51 1453994.18
1453994
18 2391733.67
239173' 0.00
~
t}Q 0.00~
~~~~ 0.0
~~
.
j
100.00t
~ .
.
~ .
r
-
.
0.000 0.000 5593.86 2021.64 1853.36 -807.51 .
1453994.18 ~ ~,,
2391733.67 ?~
~0.00 ;
0.00' 0.0
106.14 0.000336.4575600.0012021.64 1853.36 -807.51 1453994.18 2391733.67 0.00 0.00 O.a
151.14 0.000336.457 5645.00 2021.64 1853.36 -807.51 1453994.18 2391733.67 0.00 0.00 0.0
HOLE & CASING SECTIONS Ref Wellbore: SU43-9X Ref Wellpath: SU43-9X Version #3
of
B4
String/Diameter Start MD End MD Interval Start TVD End TVD Start N/S Start E/W End N/S End E/W
[feet] ~ [feet] [feet~ ~ ~feet] ~feet] [feet] -feet] [feet] [feet]
20in Conductor 0.00 80.00 80.00 0.00 80.00 0.00 0.00 0.00 0.00
___
13.375in Casing Surface
0.00
2000.17
2000.17
0.00
1886.00
0.00
0.00
499.00
-217.41
_ _..___..
9.625in Casing Productton ___~ ~__.___
~ 0.00
6151.09
6151.09
0.00
5644.95 __..
0.00
0.00
1853.36
-807.51 ;
MARATHON
Operator MARATHON Oil i
_ _ _ _ ____
Area Cook Inlet, Alaska
_ _ _- ___.
Field ~ Sterling Gas Field ~
_ ----
Facilitv Pad 43-9
~ •
Planned Wellpath Report
SU43-9X Version #3
Page 4 of 4
ot
ell
ellbore
fame MD ; TVD ' North East Crid East Grid North Latitude Longitude Shape'
; ~feet] _ ~feet] ; ~feet~ ~ ~feet] ~ (us survey feet] ~~us survey feet] [°] ~ [°]
_ _ _. _.___...___ t .._
5263.00' 1853.36 -807.51 1453994.18 2391733.67' 60 32 33.879N 151 02 07.610W circle
3-9X Sterling B4 29-Mar-07 -- -
_ __ _ .;
',6106.14 5600.00 1853.36 -807.S1 1453994.18 2391733.67 60 32 33.879N 151 02 07.610W circle ~
) 43-9X Beluga 29-Mar-07 `- - -
_ _._ ._ ~ _ _ ___ _.__. _. ;~_ __
i 5645.00 1853.36 -807.51 1453994.18 2391733.67; 60 32 33.879N,151 02 07.610W circle
3-9X TD 29-Mar-07 --_ -
- ---- _ _.___ _ _._-------------- ---- _ __ __ _ _ _~ _
URVEY PROGRAM Ref Wellbore: SU43-9X Ref Wellpath: SU43-9X Version #3
___ _ ___._____ _ --- --
Start MD End MD Positional Uncertainty Model Log Name/Comment Wellbore
(feetJ [feet]
. _ _ _ _ _ .. _
0.00 2000.17 NaviTrak (Standard) SU43-9X
-- __ _ __ --
2000.17 6151.14NaviTrak (Standardl SU43-9X
~ ~
Wellpath Design Summary Report
Wellpath: SU43-9X Version #3
MARATHON Page 1 of 2
Operatar :MARATHON Oil Company
_.__._ ~,_.~ _ _
Area Cook Inlet, Alaska (Kenai Pen
__..__.__. __ _
Field ~Sterling Gas Field (NAD83)
Facility Pad 43-9
HOLE & CASING
__. ..
String/Diameter
20in Conductor
13.375m Casing Surface~
_ __ _ _ ___
9.625in Casing Production
S Ref Wellbore: SU43-9X Ref Wel
_.._ . _._. _ .
Start MD End MD Interval Start TVD
0.00 80.00 80.00 0.00
0.00 2000.17 2000.17 0.00
0.00 6151.09' 6151.09 0.00
rr-rr
BAKER
NVGHES
INTEQ
~th: SU43-9X Version #3
_
_.__ .
.
End TVD _ _ .__~.____ __
Start N/S Start E/W End N/S ; End E/W
[feet] ~feet] [feet] ~feetJ (feetJ
80.00 0.00 0.00 0.00 0.00
1886.00 0.00 0.00 499.00 -217.41
5644.95 0.00 0.00 185336 -807.51
~ •
TARGETS
Name MD I TVD North East Grid East Grid North ~ Latitude Longitude Shape'
_ _.__._ i [feet~ ~
._ [feet] [feet~ ~feetj [us survey feetJ [us survey feet] ~ [°] ' ~°]
_ ._.__.__ __ _ - _
~5263.00' l 85336 -807.51 1453994.18 2391733.67:60 32 33.879N 151 02 07.610W circle
43-9X Sterling B4 29-Mar-07 -
~
___. ~
~6106.14 5600.00 1853.36 -807.51 1453994.18 2391733.67 60 32 33.879N' 151 02 07.610W circle
~1) 43-9X Beluga 29-Mar-07 ~ --
_- _
43-9X TD 29-Mar-07 _~m .
5645.00 1853.36 -807.51 i
_ - -_
1453994.18 ~~ 2391733.67 60 32 33.879N 151 02 07.610W circle
_ __
[~VEY PROGRAM Ref Wellbore: SU43-9X Ref Wellpath: SU43-9X Version #3
_ _ _ _ _
Start MD End MD Positional Uncertainty Model Log NamelComment Wellbore
, . . ----- ----_
0.00 2000.17 NaviTrak (Standard) SU43-9X
--- - -- -
2000.17 6151.14NaviTrak (Standard) SU43-9X
Well ath Desi n Summar Re ort B r~~r
p Wellpath: SgU43-9X Version 3 p NV6IR~IES
MARATHON Page 2 of 2 INTEQ
~ •
MARATHON
MARATHON Oil Company
Location: Cook Inlet, Alaska (Kenai Pennmsula) Slot: SU43-9X
Field: Sterling Gas Field (NAD83) Well~. SU43-9X
Facilitv: Pad 43-9 Wellbore SU43-9X
~~ ~~
BAKER
NI~GNES
INTEQ
Plot reference wellpath is SU43-9X Version #3
True vertical depths are referenced to Glacier #1 (RKB) Grid System: NAD83 / TM Alaska State Plane, Zone 4(5004), US feet
Measured depths are referenced to Glacier #1 (RKB) NoRh Reference: True north
Glacier #1 (RKB) to mean sea level: 244.8 feet Scale: True distance
mean sea level to Mud line (Facility - Pad 43-9): O feet Depths are in feet
Coordinates are in feet referenced to Slot Created by: MichWilG on 5/24/2007
~
s
~o
z
0
~
~
5
~
s~~e„ n=~ft Easting (ft)
~ ~
MARATHON
MARATHON Oil Company
Location: Cook Inlet, Alaska (Kenai Penninsula) Slot: SU43-9X
Field: Sterling Gas Field (NAD83) Well: SU43-9X
Facilit : Pad 43-9 Wellbore SU43-9X
r~~~
BAKER
N1~6NE5
INTEQ
Plot reference wellpath is SU43-9X Version #3
True vertical depths are referenced to Glacier #'I (RKB) Grid System: NAD83 / TM Alaska State Plane, Zone 4(5004), US feet
Measured depths are referenced to Glacier #1 (RKB) North Reference: True north
Glacier #'I (RKB) to mean sea level: 244.8 feet Scale: True distance
mean sea level to Mud line (Facility - Pad 43-9): 0 feet Depths are in feet
Coordinates are in feet referenced to Slot Created by: MichWilG on 5/24/2007
s~a~e,,~~~=zsssssn Easting (ft)
~ ~
MARATHON
MARATHON Oil Company
Location: Cook Inlet, Alaska (Kenai Penninsula) Slot: SU43-9X
Field: Sterling Gas Field (NAD83) Well SU43-9X
Facilit Pad 43-9 Wellbore SU43-9X
~~ ~~
BAKER
NuGNES
INTEQ
Plot reference wellpath is SU43-9X Version #3
True vertical depths are referenced to Glacier #'i (RKB) Grid System: NAD83 / TM Alaska State Plane, Zone 4(5004), US feet
Measured depths are referenced to Glacier #1 (RKB) North Reference: True north
Glacier #1 (RKB) to mean sea level: 244.8 feet Scale: True distance
mean sea level to Mud line (Facility - Pad 43-9): O feet Depths are in feet ~
Coordinates are in feet referenced to Slot Created by: MichWilG on 5/24/2007
Traveling Cylinder: Map North
~~
MARATHON
Clearance Report
Closest Approach
SU43-9X Version #3
Page 1 of 6
~~~~
BAKE R
-NUa~Es
IN'TEQ
POSITIONAL UNCERTAINTY CALCULATION SETTINGS
~~m
~Ellipse Confidence Limit ,~3.00 Std Dev jEllipse Start Depth~
»_.~._..._W,_~~._
.,....
~
0.00 feet~jSurface Position Uncertainty
.
..
..., .
............._
..._........,
:
_
:
included~
.
j
.
..._...W....._ .................._~..~..«~..
.
; Declination ~ 19.28° East of TN ~ Dip Angle . ~.~
.
.
.
.
_~u
-..
.
73.48° j Magnetic Field Strength ....._........
55487 nT
ANTI-COLLISION RULE
~_ _ _ _. ~ _.d____
____ __ _. _ ,~ . ~_____ __~ ______ __. _ a__J ~ __ _ ~ ._W____
~ -.__~._____w__~
Rule Name i E-type Closest Approach w/Hole&Csg L~mit:0 StdDev:3.00 iRule Based On ~ Ellipsoid Separation
~ ,w/Surface Uncert
, _ __..__~__..~.._,. ;.______~_-__ _.~ ~. .~.__ ~._._... _... __ _~.~~ .~.__~_ ... ...._... _
~Plane of Rule Closest Approach ~Threshold Va1ue 0.00 feet
~ ___ ._~._ , .. ..._ _. _____m_ ___ __ ~._ __. ______ ___ _ _ ~ _._ _ -__ __ _~_____ r.__ _____ ________
~ Subtract Casing & Hole Size ; yes , Apply Cone of Safety ~no ,
HOLE & CASING SECTIONS Ref Wellbore: SU43-9X Ref Wellpath: SU43-9X Version #3
- - _ .____
~_.~ __...___
_~._~.__ _. _ _
String/Diameter Start MD End MD '; Interval Start TVD End TVD Start N/S , Start E/W End N/S End E/W
~ [feet] [feet] ~ [feet] [feet] ~ [feet] [feet] '; [feet] ~ [feet] ~ [feet]
_ _____ _. __~~. _ ~___ ~.
20in Conductar 0.00 80.00 ~~ 80.00 ~ 0 00 ~ 80.00 i 0.00 ~.00 0 00 0.00
..~. _.__ __._~---,_ ~. __ . ______
~_~ .. ~ .._.~_ ~________~,___~ ___ _ ~ __.
13.375in Casing Surface ~ 0.00 2000.17 _ 2000 17 ~4 „ 0 00 1886.00 ~ 0.00 j~~ 0.00 499 00 -217.41
_._. __.__ ._ _~~ _ ...
~_____ , ...w_~_.._ ~.... . ~
j9.625in Casin~ Production ~~ 6151.09 ~ 6151.09 ~ 0.00 5644.95 s 0.00 E 0.00 ~ 1853.36 ~ -807.51 ~
•
\J
MARATHON
Clearance Report
Closest Approach
SU43-9X Version #3
Page 2 of 6
0~.00~ 2000.17jNaviTrak
2000.17~ 6151.14 aviTrak
' CALCULATION RANGE & CUTOFF
= om: 0 00 MD~~ ~ ~~~To: 6151.14 MD
OFFSET WELL CLEARANCE SUMMARY (3 Offset Wellpaths selected)
u
~~~~
BAKEit
Nu~N~s
INTEQ
43-9X
_._.
43-9X
C-C Cutoff: 500.00 feet
Offset Offset Offset Offset Offset Ref Min C-C Diverging Ref MD of Min C-C Min C-C ACR
Facility Slot Well Wellbore Wellpath MD Clear Dist' from MD Min GC Ell Sep Ell Sep Status
[feet] [feet] [feet] Ell Sep [feet] Dvrg from
[feet] [feet]
~ _~____..~_~__.._ . _______~_.___.~
i Pad 43-9 slot #SU32 9: SU32-9 SU32-9
~ Pad 43-9 slot #SU41 15 SU41-15 SU41-15
~
; MWD <0-6858>
~~___
. __~ _.
' MWD <0-12600> ~_
~ 268 66 (
._. _ _ .______~
0.00
~ _..
86 63
_ ~ _. ~____
72 99 _.__ __ _~
268 66 i
_
0.00
~ r _.__
~
0.00
~73.41
~ _ _.____
5933 .
~68 70 PASS
,,_~ ___. ~.
..~ _
0 00 PASS
~ _.
.__
? Pad 43-9 j slot #SU43-9 a ____- ~_
SU43-9 j SU43-9 ; _--- --_ _ _..
; Totco Incl. Surveys <0-62 ~ ~ _..._._
02'> ! 787.86 ~ ~ ~ ~
72 54 ! _._ _
787.86 ;
842.72
35.25 _.__._ ._ .,_._
~~ 842.72 PASS
SURVEY PROGRAM Ref Wellbore: SU43-9X Ref Well a~_th__SU43-9X Version #3 '
Start MD ~~End MD Positional Uncertainty Model ~~~~ Log Name/Comment Wellbore
~ ~
Clearance Report ~/%r
Closest Approach BAKER
MARATHON SU43-9X Version #3 1~IVGMES
Page 3 of 6 ~NTEQ
Operatar MARATHON Oil Company Slot SU43-9X
_
Area Cook Inlet, Alaska (Kenai Penninsula)
.
_ _ _ _-_--. -
Well SU43-9X
_.__ .
_
Field Sterling Gas Field (NAD83)
__ _.___---~~ ._ _
___
____. ,.. _ ... -__ _
Wellbore SU43-9X
-
---
_
Facility Pad 43-9 _..._ _ .
_
-
CLEARANCE DATA - Offset Wellbore: SU32-9 Offset Wellpath: MWD <0-6858>
Facility: Pad 43-9 Slot: slot #SU32-9 Well: SU32-9 Threshold Value=0.00 feet
~ = interpolated/extrapolated station
ry
Ref Ref Ref Ref Offset Offset Offset Offset Horiz C-C Clear Dist Ellipse ACR MASD ACR
MD TVD North East MD TVD North East Bearin~ ffeetl Sep ffeetl Status
OFFSET WELLPATH MD REFERENCE - Offset Wellbore: SU32-9 Offset Wellpath: MWD <0-6858
Reference: Nabors #160 (RKB) Offset TVD & local coordinates use Reference Wellpath settings
(See WELLPATH DATUM on page l of this report)
GC Clearance Distance Cutoff: 500.00 feet
WELLPATH COMPOSITION Offset Wellbore: SU32-9 Offset Wellpath: MWD <0-6858>
_d_.. _.___ _.___.______. .m . __ _ _.__ _ _... . _ _ _ _ ___
__ _ _
f Start MD End MD Positional Uncertainty Model Log Name/Comment Wellbore
~ [feet] [feet]
-- -- -- ___.._ _ __~
~- 0.00 6858.00 NaviTrak (Standard) MWD <0-6858> SU32-9
~ .
MARATHON
~erator ~MARATHON Oil Compan~
~----_ _.
°ea Cook Inlet, Alaska (Kenai P
eld ~Sterling Gas Field (NAD83)
___ _.,__--~__ _ --- _____. -----.__.
~cility ~Pad 43-9
Slot 'SU43-9X
------ _ .____.__.._._
Well ;SU43 9X
___ _ --
Wellbore SU43 9X
CLEARANCE DATA - Offset Wellbore: SU41-15 Offset Wellpath: MWD <0-12600> ~
Facility: Pad 43-9 Slot: slot #SU41-15 Well: SU41-15 Threshold Value=0.00 feet
-~ = interpolated/extrapolated station
Ref Ref Ref Ref Offset Offset Offset Offset Horiz GC Clear Dist Ellipse ACR MASD ACR
MD TVD North East MD TVD North East Bearing [feet] Sep [feet~ Status
HOLE & CASING SECTIONS Offset Wellbore: SU41-15
---------_
String/Diameter _~
Start MD j _______--
End MD
Interval
- _ ___ ' [feet]
- [feet~
__--. ~feet~
20in Conductor
_ I -9.00
_ 49.00 58.00
_
13 375in Casing Surface ___.
9 00' _
2262.00
2271.00
-- _
9 625in Casmg Intermediate
_
-9.00
10303.00
10312.00
.- - _ __
7in Liner - -_ _
r 10099.00
12581.00
2482.00
Offset Wellpath: MWD <0-12600>
Start TVD End TVD Start N/S Start E/W End N/S End E/W
[feet] [feet~ [feet] ~feet~ [feet] [feet~
_ ---__
-18.20 39.80
-44.17
-5.40
-44.18 _
-5.37
- --
-18.20 2252.08
-44.17
-5.40 __
-57.88
1.59
-18.20 8525.93 -44.17 -5.40 -899J1 1152.38
8369.10 ] 0531.42 -877.22 1119.601 -1082.06 ~ 1416.58
CLLPATH COMPOSITION Offset Wellbore: SU41-15 Offset Wellpath: MWD <0-12600>
_ __., _-- __ _._._ _ _._ __. _ _.~,. __ ____.
Start MD End MD Positional Uncertainty Model Log Name/Comment Wellbore
[feet] ~feet~
_ _.___ __----..------ _-_ __.__ _ __.____....
-9.00 12591.00 NaviTrak (Standard) ; MWD <0 - 12600> SU41-IS
OFFSET WELLPATH MD REFE]
Reference: Glacier #l (RKB)
Clearance Report rfi%~
Closest Approach BAKER
SU43-9X Version #3 NYGMES
Page 4 of 6 INTEQ
- Offset Wellbore: SU41-15 Offset Wellpath: MWD <0-12600>
~ffset TVD & local coordinates use Reference Wellpath settings ~
'See WELLPATH DATUM on page 1 of this report)
GC Clearance Distance Cutoff: 500.00 Feet
i •
Clearance Report ~/~r
Closest Approach BAKER
SU43-9X Version #3 i~IVGNES
MARATHON Page 5 of 6 INTEQ
-- - - -- --- -- - -
__,~-- _ __ ___ _
Operator iMARATHON Oil Company
- --- _ _ -
_---
- -__ --
_ .._
Slot
----
_
SU43-9X
__..._ _ _--- ---
---
-
Area Cook Inlet, Alaska (Kenai Penninsula) Well SU43-9X
Field _--_ ~
Sterling Gas Field (NAD83) ____ __
Wellbore _ __ _..
SU43-9X
iFacility Pad 43-9 -
CLEARANCE DATA - Offset Wellbore: SU43-9 Offset Wellpath: Totco Incl. Surveys <0-6202'> ~
Facility: Pad 43-9 Slot: slot #SU43-9 Well: SU43-9 Thresh old Value=0.00 feet
j~ = interpolated/extrapolated station #
Ref Ref Ref Ref Offset Offset Offset Offset Horiz GC Clear Dist Ellipse ACR MASD ACR ~
MD TVD North East MD TVD North East Bearing [feet] Sep [feet] Status{
[feet] [feet] [feet] [feet] [feet] [feet] [feet] [feet] [°~ [feet] ~
0.00
0.00
0.00,
0.00
0.00 _
9.10;
22.19 _
-95.78 _
283.04s -_
98.74
85.58
13.15 PASS
IOO.OOfi
100.00
0.00
0.00'
91.79
]00.88
22.46
-95.03 s
283.30' .__.
97.65
83.79
13.86 PASS
200.00 200.00 0.00 0.00 191.61 200.71 22.77 -94.18' 283.59i 96.90 80.43 16.47 PASS
300.00 fi
400
00
299.98
399
84
1.60
40
6
-0.70
2
79
291.59
~9i
44
300.68'
400
52
23.07
23
37
-9336
54
92 _.
283.04'
280
71 _._
95. ] 2
135
75.51
47
68
19.61 PASS ~
22
88 PASS '
.
~
500.00 f .
499.45 .
1439 -
.
-6.27 .
491.04 .
500.12 .
23.66 -
.
-91.72 .
_
276.19; ~~rrm: . 9
___.____.. :
8596 .
5I.94 .
26.02 PASS
600.OOf
598J0
25.56
-11.14
590.22
599.30
23.94
-90.95
268.84 _ _..~__
79.83
50.43
29.40 PASS
700.OOt
697.47
39.90
-17.38 _ _
688.91
697.98
24.20
-90.26
257.84 __._.._T_--
74.55
41.60
32.95 PASS
787.86t
800
00 783.75
795
62 ~ 55.10 -24.01
2
1 774.77 783.84 24.39
24
42 -89.72 244.95
242
7 72.54
72
57 36.40
35
98 36.13 PASS
59 PASS
36
.
~
842.72t .
837.34 5739
65.82 -
5.0
-28.68 786.99
828.68 796.07
837.75 .
24.50 -89.65
-89.42 .4
235J8 .
73.46 .
35.25 .
38.21 PASS
900.OOt 893.06 78.01 -33.99 884.36 893.42 24.61 -89.13 225.91 76.76 36.31 40.46 PASS
1000.00 f 989.64 101.74 -44.33 980.88 989.95 24.77 -88.68 2099~ 88.84 44.37 44.46 PASS
1100.00t
1
00
00 1085.27
1179
82 128.54
1 -56.01
1
9 ]076.49
11
1 1085.56 2491 -88.29
9 197.31
18
07 108.~4
34
67 60.07
82
29 48.48 PASS
52
37 PASS
2
.
~
1300.00 f .
1273.17 58.39
191.24 -6
.0
-83.32 .02
7
1264.37 1180.09
1273.43 25A5
25.19 -87.
0
-87.52 8.
181.45 .
1
~ 166.10 .
109.94 .
56.16 PASS
1400.00 j~ 1365.21 227.06 -98.93 1356.48 1365.54 25.34 -87.12 176.65 202.06 142.32 59.74 PASS
;1500.00~- 1455.84 265.80 -115.81, 1447.22 1456.28 25.55 -86.53 173.05'; 242.03 178.63 63.40 PASS `
_ _
;1600.OOj-
'~
1544.94
307.42
-133.94
~'
1536.58
_ ry
1545.64
~
25.88
-85.64 _
170.27j
~ ._ __ __ _
285.66
204.90
80.76 PASS !
''
~
1800.00-~
_._ .~_ 1632.39
1718.11 351.86
399.08 -
~
-173 88i ~~
1710.18,
----- ~ ,~~~~
~.33
1719.21
--- 26.39
27.07 -84.24
-82.35 ~~
~~.u~, ~b8 b
=
166.18~~
_.__ ~~,~2 ~0.56
__
~ 383.10 259.96
_____ _.. 102.17 PASS
123.14 PASS :
1857.99 176697 427.70 -18635' 1759.11 1768.11 27.55 -81.04 165.26 413.78 279.]0 134.67 PASS
1900.OOj~
1802.14
448.77
-195.53 _ _
1794.32',
1803.31
27.93 ~
-80.00~ _ . _
164.65 _ --- _
436.41
293.17
143.24 PASS E
2000.00-~ 1885.85 498.91 -217.38 1878.06 1886.99 2896 -77.17; 163.39j 490.42 326.82 163.61 PASS
C-C Clearance Distance Cutoff: 500.00 feet
HOLE & CASING SECTIONS Offset Wellbore: SU43-9 Offset Wellpath: Totco Incl. Surveys <0-6202'>
String/Diameter Start MD End MD ~ Interval ~ Start TVD End TVD Start N/S Start E/W End N/S ' End E/W ~
~ [feet] [feet] [feet] (feet) ~ (feet] [feet] ~ [feet] ~feet~ [feet~
-
12.25in Open Hole _ -
0.00 1272.00 1272.00
9.10 - __ _ _
1281.07 13.52 -5839
14.44 --
55.86;
-
8.625in Casing Surface -----
~ 0.00 1272.00' 1272.00
9.10 __ ___
1281.07 13.52 -5839
14.44
-55.86
__ ---
7.875in Open Hole ~--- __
I 0.00 6202.00 6202.00
9.10 _ _
6210.08 13.52 -58.39
22.73
-33.10'
S.Sin Casing Production ~ 0 00 6202.00 6202.00 9.10 6210.08 13.52' -58.39 22.73 -33.1 ~
WELLPATH COMPOSITION Offset Wellbore: SU43-9 Offset Wellpath: Totco Incl. Surveys <0-6202'>
Start MD End MD _.___________..__. _
; Positional Uncertainty Model _,.__________ __
` Log Name/Comment _~
Wellbore
[feet] ~feet] '
~~ r,~0.00 6202.00 ---
; Alaska, Dnft Indicator Surveys
Totco Surveys <0-6202'>
SU43-9
~
MARATHON
Clearance Report
Closest Approach
SU43-9X Version #3
Page 6 of 6
~
OFFSET WELLPATH MD REFERENCE - Offset Wellbore: SU43-9 Offset W
~~~~
sa~cER
Nu~NEs
IN~'EQ
ith: Totco Incl. Surveys <0-6202'>
fMD Reference: Santa Fe Drilling(1963) (RKB) fOffset TVD & local coordinates use Reference Wellpath settings ~
i i(See WELLPATHDATUMon paQe 1 ofthis report)
• •
~ :'~ Marathon Oil Company
~ Well Name: SU 43-9X
- Location: Sterling, Alaska.
INTEGRATED FLUIDS
ENGINEERING PRO~ECT PLAN
M~ ~~NAGt~ ~. :r..
_.... ~ : ~
___
Prepared For:
MARATHON OIL COMPANY
Well SU 43-9X
Prepared by: Tony Tykalsky
Reviewed by: Hal Martens
Presented to: Will Tank May 23, 2007
Kenai Peninsula, Alaska
~ ~
~'~ Marathon Oil Company
~~ Well Name: SU 43-9X
_ Location: Sterling, Alaska.
Marathon Oil Company
PO Box 190168
Anchorage, Alaska 99519
ATT`N: Will Tank
Will:
Enclosed is the revised drilling fluid program for the SU 43-9X Well to be drilled this year as per your email on
May 23rd, 2007. The following is a brief synopsis of the program.
Overview:
SU 43-9X is a gas production well in the Sterling Field. The well will be drilled in two intervals, with 9-5/8"
casing being set in the production interval. Standard F1oPro fluid (with DualFlo), typically used on Ninilchik
production intervals will be used in this interval.
Surface Interval:
The surface interval will be drilled with the standard Gel/Gelex spud mud. No problems are anticipated in this
interval.
Production Interval:
New F1oPro fluid will be used to drill this interval. Although this well targets the Sterling sand, this field has not
been depleted to the degree the Kenai Gas Field has. Therefore no large fluid losses to the formation are
anticipated. Fluid loss should be maintained @ 5- 7 cc's API for this interval.
Completion:
The cement will be displaced with 6% KCl brine for the completion phase of the program. This fluid will be
treated with Conqor 303A and Sodium Meta Bisulfate for corrosion control
Tony Tykalsky
Project Engineer /M-I SWACO
NOTE: This pro~ram is provided as a~uide onlv. Well conditions will alwavs dictate fluid
properties required.
EXECUTIVE SUMMARY
~
•
~'~ Marathon Oil Company
Well Name: SU 43-9X
_ Location: Sterling, Alaska.
Our overall goal is no spills and no incidents while providing fluids and solids
control services to Marathon Oil Company.
_ ~ ..,
t~ur goal fc~r SlJ 43-9X is to r~mcav~ d~itl sQlids frorr~ th~ mud ~yst~m at a cost of
I~ss than ~0.34 per pound.
i ~
Mud pragram projecti~n~ ~stimate the product ~ost ~r fo~c~t fe~r this w~IN at $26.76.
We estimate the use of less that 5655 barrels to complete this well, not
~ withstanding any un-anticipated losses to the formation.
~'~
Use of the MI-SWACO centrifuge van for the last five years has provided an
~ estimated savings in dilution and disposal costs to Marathon Oil of over
~ I~ $1,250,000. With continued usage of our equipment, we expect to provide more
savings to you during future operations. In addition, the installation of Mongoose
- shakers has allowed the utilization of finer mesh screens on intermediate and
production intervals. Running finer mesh screens has reduced the need for the
centrifuge van.
• ~
Marathon Oil Company
~'~ Well Name: SU 43-9X
_ Location: Sterling, Alaska.
Interval Benchmarks and Targets
Drilling
Intervals
Depth
Benchmark 1'
Benchmark 2 ~~
Benchrri ~ 3~ r~ .
Benchmack 4
Interval
~ft)
Fluid cost per foot Volume Usage Solids Removal
0- 2000' <$4.93 ft < 2390 bbls
2000 - <$37.29 < 2815 bbls
6151'
Total Avg. Max.
Project <$26.76 ft <5655 bbls <$0.34 Ib No Spills from
Targets for Centrifuge Van
Drilling Operation
Interval
• •
~~ :'~ Marathon Oil Company
Well Name: SU 43-9X
- Location: Sterling, Alaska.
Project Summary
Casing Hole Casing Depth ND Mud Mud Sum Interval
Size Size Program System Weight Days Mud Cost
(i~) (in) (ft) (ft) Solids Control (ppg)
13-3/8" 16" 2000' 1886' Gel/Gelex Spud
Mud 8.6 - 9.4 6 $16,330
Screens 165/175
mesh
Desilter
Centrifuge Van
9-5/8" 12-1/4" 6151' S645' Flo-Pro
w/SafeCarb 9.0 - 7 $162,331
Screens 200 mesh < 9.5
Desilter
Centrifuge Van
9-5/8" 12-1/4" Completion 6151' S645' 6% KCl
8.55 4 $14,070
~ Utilize all solids control equipment to minimize the build up of drill solids in the system (if possible,
centrifuge the surface mud during trips to reduce drill solids).
- Condition the mud prior to running casing for all intervals.
> Cost does not include any provision for whole mud losses in the production intermediate interval.
r Cost includes 1% Lubetex concentration in intermediate and production interval.
• ~
~~:'~ Marathon Oil Company
= ° ~ Well Name: SU 43-9X
- Location: Sterling, Alaska.
Estimated Product Usage Summary
PRODUCT Surface
16" Production
8-1/2" Completion~
3-1/2" jTotal Usage % of
Total Cost
M-I Bar 0 282 ~ 0 ~ 282 '~ 1.33
M-I Gel 478 0 0 478 2.86
Gelex 30 0 0 30 0.29
Soda Ash 12 14 0 26 0.28
Caustic Soda 12 42 0 56 1.38 '
Conqor 404 0 8 0 i 8 6.06
Sodium Meta
Bisulfate 24
' 28 5 ~ 57 2.23 ~
Bicarb 0 14 0 14 0.25
Conqor 303 0 0 4 4 01.18
F1oVis 0 225 0 225 27.99
Desco CF 10 0 0 10 0.27
Polypac UL 12 0 0 12 1.12
KCl 0 1182 189 1372 15.22
Safecarb 0 1267 0 1267 14.52
Lubetex 0 22 0 22 9.88
Asphasol 0 56 0 56 2.86
DualFlo 0 169 0 169 8.32
Defoam X 0 6 0 6 0.35
Freight
Surchar e 3.70
Engineer Service 6 7 4 17
~ ~
~'~ Marathon Oil Company
~ Well Name: SU 43-9X
_ Location: Sterling, Alaska.
Plans & Procedures
~ COMMUNICATION - The Field Mud Engineer will communicate daily with the In-Town Project
Engineer. The Project Engineer will then communicate daily with the rig Drilling Engineer.
Communications should be about, but not limited to, fluid properties, hole difficulties, possible
changes to the mud program, and proposals to use products not included in the mud program.
~ FLUID LOSS CONTROL - In the production interval the API fluid will be maintained between 6- 8
cc's at all times. In addition to sufficient fluid loss agent additions, this may require adequate
dilution of the mud system in order to keep reactive drill solids to a minimum .
~ DRILL SOLIDS - MBT - The MBT should be kept at less than 7.5 ppb in the intermediate and
production intervals through aggressive use of solids equipment and dilution as needed.
~ MIXING CONDITIONS - Whenever possible all treatments to the mud system should be made as
pre-mix additions. Polymers and KCI should first be mixed in fresh water in that order and then
blended into the active system over one or two circulations as needed.
~ CORROSION - Conqor 404 additions should be made daily when drilling with FloPro fluid in order
to maintain a Conqor 404 concentration of +/- 2000 PPM.
~ CORRISION - Sodium Meta Bisulfate additions should be made daily as needed with any fluid in
the hole. Maintain a DO (dissolved oxygen) reading of less than 3 ppm
~ SOLIDS VAN USAGE - The Solids Van should be used whenever drill solids become un-
acceptably high and reduction of drill solids in the mud can be more economically done with
centrifuging and dilution then just with dumping and diluting. The weight of the drilling fluid alone
should not be the determining condition for when to use the Solids Van.
~ WEIGHTING UP - All increases in mud weight should be accomplished with barite additions. In
the production interval, insure chloride concentration is maintained at 30,000 to minimize the need
for barite additions. Remove 325 mesh shaker screens when adding Barite.
~ ~
~'~ Marathon Oil Company
Well Name: SU 43-9X
_ Location: Sterling, Alaska.
Interval Summary -16" hole
~x
4 - 2000' ~
Drilling Fluid System GeUGelex Spud Mud
Key Products MI Gel / Gelex / Soda Ash / Caustic Soda / MI Bar / PolyPac
Supreme LTL / Sodium Meta Bisulfate
5olids Control Shale Shakers / Desilter / Centrifuge Van
Recommended shaker screens - 165 mesh
Potential Problems Lost circulation, coal sloughing, drill solids build-up, hole cleaning.
~ ~ ti
n~erval Drillin~ ~'luid ~~rt~p~~~es ~ :~
u. ~ ,.~
Depth Mud Funnel Yield API Drill
Interval Weight Viscosity Point Fluid Loss pH Solids
(ft) (ppg) (sec./qt) (Ib./100ftz) (ml/30min) (°/a)
0- 2000' 8.6 - 9.4 60 - 100 25 - 35 NC - 12 +/- 9.5 < 7.5%
- Treat drill water with Soda Ash to reduce hardness.
- Build spud mud with 20 - 25 PPB M-I Gel to +/- 100 seconds/quart funnel viscosity.
- Lower funnel viscosity to +/- 75 after gravel zone has been drilled.
- Add Gelex as needed to maintain sufficient viscosity for hole cleaning.
- Increase funnel viscosity if fill on connections begins to occur.
- Reduce fluid loss with additions of Polypac Supreme UL prior to running surface casing.
- Add Sodium Meta Bisulfate to maintain a DO (dissolved oxygen) of < 3 PPM.
- Condition mud prior to cementing casing to reduce yield point and gel strengths.
- Estimated volume usage for interval - 2390 barrels.
- Estimated haul off volume - 3979 barrels.
~
~
~'~
~
Marathon Oil Company
Well Name: SU 43-9X
Location: Sterling, Alaska.
Interval Summary -12-1/4" hole
zoou ~~ s~ ~
~~
~~ _ _
Drilling Fluid System Flo-Pro Fluid
Key Products Flo-Vis / PolyPac Supreme UL / KCl / SafeCarb 10, 40, 250 /
Mix II /MI Bar / Caustic Soda / Conqor 404 / Sodium Meta Bisulfate
Lubetex
Solids Control Shale Shakers / Desilter / Centrifuge Van
Recommended shaker screens - 200 mesh
Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight
hole conditions
,.~
nterval ~ri~~ing Fluid Properties ~
t
Depth Mud Plastic LSRV API Drill
Interval Weight Viscosity 1 min Fluid Loss MBT Solids
(ft) (ppg) (cp.) (cps) (mU30min) (%)
2000 - 6151' 9.0 -< 9.5 8- 12 40,000+ 7- 9 <'7.5 +/- 5%
- Use one rig pit to drill out surface casing. In other rig pits, build new Flo-Pro fluid using the enclosed
fluid formula. Pre-heat makeup water with steam hoses as much as possible.
- After drilling out surface casing, displace hole to Flo-Pro fluid prior to running leak off test
- As mud heats up, increase F1oVis concentration to 2 PPB as needed.
- If torque or sliding problems occur, add 1- 2% Lubetex.
- Estimated volume usage for interval - 2815 barrels.
- Estimated haul off volume - 4151 barrels.
- Condition mud prior to running 9-5/8" casing.
NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor.
•
~ 1~
~
~
Marathon Oil Company
Well Name: SU 43-9X
Location: Sterling, Alaska.
Fluid Formula -12-1/4" Interval
;~~~~~~~~,.r,~- MUDCALC 4.5 - Water-Based Mud Calculatian
M-I L.L.C.
12-1l4" Interval from 2000 - 6151'
_ ~ -- ~- In ut _ ___ __ ~
~
C~escri tian SU 43-9X Production Inter~al Formula „_. __ __
Mutl 4~ei ht 9.1 reh drated Gel No
_ __
VYei ht Material Code MI Bar drated Gel ~anc:
__ , ___ _ _
U1fei ht MateriaJ SG 4.2 KG! Chloride
1~}ei ht M atarial Price KCi'a~It°fo 6
. _ _ _ _ __
~ut ut -1 bbl
~rder of Products G~ncentra#ion Volume P'roduct'
,~dditian Field, lb Lab, m ~ie1d, bbl Lab ml Usa e
1 Water 317.07 317.O1 0.906 317.07
! 2 Soda Ash 0.25 0.25 0.00~ 0.10 Reduce Hardness
' 3 Flavis 2.0~ 2.00 0.050 1.67 Viscosit
' 4 DualFlo 3.0~ 3.00 0.1~0 3.34 Fluid Loss Control
~ Caustic Soda ~.50 0.5~ 0.001 0.23 H Cantrol
6 KlaGard 4.00 4.00 0.120 4.00 Inhibition
? As hasol Su reme 2.00 2.0~ ~.O~Q 1.67 Vlfellbore Stabilit
8 Potassium Chloride 20.24 2~.24 ~.024 8.41 Inhibition
9 Con or 40~ 2.Q0 2.00 ~.004 1.43 Corrosion Control
10a SafeCarb 10 5.~0 5.a0 0.05~ 1.19 Brid in A ent
10b SafeCarb 40 10.00 10.00 O.Q10 3.~7 Brid in A ent
10c SafeCarb 250 ~.DO 5.00 ~a.000 1.79 Brid in A ent
12 Sodium Meta Bisulfate O.aO 0.50 0.002 0.56 Ox en Scaven er
If tor ue becoines a roblem add u to 2g~o of the followin :
' 13 Lubetex 7.00 1.00 0.020 7.21 Lubricit
Total 411.6 411.6 E~imatE~d Volume t~ e 2$15 barrels
_ Calculat~tl ~ud VYsi ht 9.800
_ . . _ , ..
._ __
Tat~l Chloti+de 29600
~
~~ '~
~~
HSE Issues
~
Marathon Oil Company
Well Name: SU 43-9X
Location: Sterling, Alaska.
HANDLING OF DRILLING FLUID PRODUCTS
HEALTH AND SAFETY
1. Drilling crews should be instructed in the proper procedures for handling fluid products.
2. Personal Protective Equipment (PPE) charts should be posted in the pit room, the mud lab,
and the office of the Drilling Forman.
3. PPE must be in good working order and be utilized as recommended by the PPE charts.
4. Product additions should be made with the intent to use complete unit amounts of products
(sacks, drums, cans) as much as possible in order to minimize inventory of partial units.
5. Insure all MSDS sheets are up to date and readily available for workers to access for
information.
ENVIRONMENTAL
1. Insure that all product stored outside is protected from the weather.
2. Do not store partial units (sacks, etc) outside if possible.
3. Properly secure all products for shipment between job sites.
4. When transferring fluid and or cuttings from the rig to trucks, insure all hoses are properly
secured.
5. When utilizing the centrifuge solids van, insure all hoses and connections between the van
and the rig are secure.
i i
~:'~ Marathon Oil Company
Well Name: SU 43-9X
- Location: Sterling, Alaska.
Product Health and Safety Reference
HMIS HAZARD RATINGS
Product Function Health Flammabilit Reactivit PPE
M-I BAR Weighting Agent *~ ~ ~ E
M-I GEL Viscosity control *1 1 0 E
GELEX Bentonite Extender 1 1 0 E
FLOVIS Viscosifier 1 1 0 E
DUAL-FLO Modified Starch 1 1 0 E
POLYPAC Fluid Loss Reducer *1 1 0 E
HEC ~oss Circulation Material 1 1 0 E
Safe-Carb 10,40,250 Bridging and weighting agent *1 0 0 ~ E
Nut Plug Loss Circulation Material *1 1 ~ E
M-I Seal F, M, C Loss circulation Material *1 1 0 E
Mix II F,M,C Loss circulation Material *1 1 0 E
DESCO CF Dispersant 1 1 0 E
SALT (Solar) Densifier 1 0 0 E
POTASSIUM CHLORIDE Shale Inhibitor 1 0 0 E
CAUSTIC SODA Alkalinity control 3 0 1 i X
BORAX Inorganic Borate 1 0 0 E
SAPP Sodium Pyrophosphate *1 0 0 ~ E
SODA ASH Alkalinity control 1 1 0 E
SODIUM BICARBONATE Alkalinity control 1 0 0 E
CITRIC ACID pH Adjuster 1 0 0 E
BIOBAN BP-PLUS Biocide *2 0 0 J
GREEN CIDE 25G - Biocide 3 0 0 .1
DEFOAM X- Defoamer 1 1 0 .1
G-SEAL Sized graphite LCM 1 1 0 E
SteelLube Lubricant 1 1 0 .l
LUBE TEX Lubricant 1 1 Q J
D-D CWT Detergent 2 1 Q ~
Concor 404 Corrosion Inhibitor 1 1 0 .1
SAFEKLEEN Drilling fluid additive 1 1 0 J
Asphasol Supreme Shale Inhibitor 1 1 0 .l
Sodium Meta Bisulfate Oxygen Scavenger 1 1 0 J
•
~ 1~
~C
.
Marathon Oil Company
Well Name: SU 43-9X
Location: Sterling, Alaska.
Product Health and Safety Reference
HMIS HAZARD RATINGS
HAZARDOUS MATERIALS IDENTIFICATION SYSTEM
(HMIS) HAZARD RATINGS
4 - Severe hazard
3 - Serious hazard
2 - Moderate hazard
1 - Slight hazard
0 - Minimal hazard
* An asterisk next to the health rating indicates that a chronic hazard is associated with the material.
HMIS PERSONAL PROTECTIVE EQUIPMENT INDEX
A - Safety Glasses
B - Safety Glasses, Gloves
C- Safety Glasses, Gloves, Synthetic Apron
D- Face Shield, Gloves, Synthetic Apron
E- Safety Glasses, Gloves, Dust Respirator
F- Safety Glasses, Gloves, Synthetic Apron, Dust Respirator
G- Safety Glasses, Gloves, Vapor Respirator
H- Splash Goggles, Gloves, Synthetic Apron, Vapor Respirator
I- Safety Glasses, Gloves, Dust and Vapor Respirator
J- Splash Goggles, Gloves, Synthetic Apron, Dust and Vapor Respirator
K- Air Line Hood or Mask, Gloves, Full Suit, Boots
X- Consult your supervisor for special handling directions
~- •
~'~ Marathon Oil Company
Well Name: SU 43-9X
_ Location: Sterling, Alaska.
Contacts
Contact Title e-mail Work Cellular
Pete Berga Drilling pkberga@marathonoil.com 907 565-3032 907 231-0663
Marathon Superintendent
Will Tank Drilling Engineer wjtank@marathonoil.com 713 296-3273 713 203-8398
Marathon
Jim Dwyer Project Engineer ttykalsky@miswaco.com 907 274-5011 907 317-4556
MI SWACO
Bob Myles Warehouse Manager rmyles@miswaco.com 907 776-8722 907 252-4218
MI SWACO
Oliver Amend Field Engineer amend@acsalaska.net 907 283-0895 907 398-9474
MI SWACO (home)
Locke Rooney Field Engineer Irooneyl@alaska.net 907 235-0598 907 398-9474
MI SWACO (home)
John Nicholson / Dan Drilling Foremen alaska_drilling@marathon 907 283-1312
Byrd oil.com
Marathon
Responsibilities
- MI Project Engineer and will coordinate daily between the Marathon office, rig, warehouse, and the M-I
field engineers.
- Well progress will be monitored to look for any changes, which will improve the efficiency of the
operation or avert trouble.
- Field Engineers will monitor and supervise product inventory to include re-palletizing any products for
shipment to other locations at the end of the well.
- Field Engineers will communicate with office personnel (Marathon & MI SWACO) for approval of any
changes in the mud program (including introduction of new products).
- Field Engineers will produce a recap at the end of the well based on daily activities. Recap should
include any lessons learned that may be used to provide better service on future wells. Lessons learned
can include changes in procedures, product additions, equipment usage, and/or utilization of any third
party service.
Cheek No Check Date Bank sa~ r,o v~~ Marathon Oil Company o~~~t ~ uiries to:
ACCOU~S PAYABLE DEPARTMENT Hf1CII
9
P. O. Box 22164 Accts Payable Contact Centar
1271593 05/24/2007 NCBAS 7780 50 01123 Tu~sa,orc ~at2~-2~sa Pry~~e: 9~8_925-609~ AL
;
;:Gsvn1C@llfilftbw
_.
hiyW69;fl~
f7elCUin~rtt,No
.:, ;
A9tt~RfikJtlt~d '`.` ? . „
< ~nosSAi~wunt
,.. _
Cbs~apuM
';hivacelf?ey,Amount
L 100. 00 05/23/2007 1900023305 100.00 100.0
TOTAL: 100.00 100.0
(FOLD ON PERFORATION BELOW AND OETACH CHECK STUB BEFORE DEPOSITING)
~i'000 L 27 1593~~' ~:04 L 203895~: O 1834B4~~'
~
.
TRAYSMITTAL LE'~'T~R CH~CKLIST
i~VELL ~ANIE <SL/ ~,3- 9X
PTD# ao ~O~,~D
/ Devetopment Service Exploratory• Stratigraphic Test
iYon-Conventio~al Wel!
Circte 4ppropriste Letter / Paragraphs to be inctuded ia Transmittal Letter
' Cf{ECK i ADD-ONS
; W'~T I (OPTIOIvS)
; APPLtES I
MliLT'I LATERAL
(If ta..st two digits in
AP[ number are
between 60-69)
T'EXT FOR APPROVAL LET'i'ER
The permit is for a new we(tbare segment of existing
welt ~
Permit Yo. , APi No. ~0- . ~
Production shoutd continue to be reported as a function of the ~
original 4PI number stated above.
~ PILOT E[OLE i[n accordance with 20 A.AC 2~.OU~(~, all cecords, data and to~s
i ~ acquired for the pilot hote must be clearty diffeccntiated in both
i ; Well name ( PF~ and AP[ number
;
~ '(S4- - -_,) from records, data and logs
~
acquired for we(!
.
~ SPACING The permit is approved subject to full compliancc with 20 AAC
! EXCEPTION ~ 23.OS~. Approval to perforate and r ee / i'_ is contingent
i
~ I upoa issuance of a conservarion order approving a spacing ~
; exception
'
~ . assumes tfre
i liabiiity of any protest to the spacing exception thac may occur. (
F
~
; DRY D[TCH ;
~ Ali dry ditch sample sets subrnitted to tt~e-Eomrnission must be in ;
SAMPLE I no greater than 30' sampte intervals from betow the permafrost or '
I from where samp(es are first caught and 10' sample int~rvals ;
, through target zones. ;
!
~`j Conventional ~ Ptease note the following_ special condition oP this permit: ;
~~ productioR or production tastiag of coa! bed methane is not altowed i
~ foc (name of welh until after ~,Cocnpanv Name) has designed and !
~~mp(emented a water weil testing program to provrde base[ine data
; on water quality and quantity. (Com~y Nam~) must contact the I
~ Commission to obtain advance approval of such water we11 testing !
~
_ pcOgl'attl, ~
Rev: l'2~i0b
C:+jody~transmictal checklist
~: ,
~ ~r ~
~ e . .~ . ,, , .,
Alaska Department of Natural Resources Land Administration System Page 1 of 2
~ ~
3 ~ ~ ~
~~ ~~~fs_"R~~sC~~r~~~~arch State Gabins 1~1~#IU1~I ~5~~.1 S
~ _.. _._
.. ..,~ ~.. ,,.~,~ ~.....a.. . . .,_.~, ~ , .. .
,Alas~ca DNR Cas~ ~ummary
File T e• ADL ; File Number: 28063 ~ Printable Case File_$ummary
YP • ..__. ~ _~ . ....~ .. . . .. .... . ...
See Township, Range, Section and Acreage? P~ „ sr ~,., ,;.
c' Yes ("° No '~ ~~,. . ..~~~~~~': , ~
Enti of ~a~~ ~tt~tma~~
Last updated on 05/31/2007.
http://www.dnr.state.ak.us/las/Case_Summary.cfm?FileType=ADL&FileNumber=28063&... 5/31 /2007
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