Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout194-084STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG '
1a. WeII Status: oil ❑ Gas E] SPLUG ❑ Other ❑ Abandoned ❑Q • Suspended❑
20AAC 25.105 20AAc 25.10
GINJ ❑ WINJ ❑ WAG[-] WDSPL ❑ No. of Completions:
1b. Well Class:
Development Q Exploratory ❑
Service ❑ Stratigraphic Test ❑
2. Operator Name:
Hilcorp Alaska, LLC
6. Date Comp., Susp., or
band.: 8/26/2019
14. Permit to Drill Number / Sundry:
' 194-084 / 319-131
3. Address:
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
7. a e Spudded:
9/24/1994
15. API Number:
50-133-10141-01-00 '
4a. Location of Well (Governmental Section):
Surface: 2300' FNL, 1040' PAL, Sec. 15, T8N, R9W, SM •
Top of Productive Interval:
Total Depth:
2472' FNL, 1905' FEL, Sec. 15, T8N, R9W, SM
8. Date TD Reached:
10/2/1994
16. Well Name and Number:
Swanson River Unfit (SRU) 32A-15
9. Ref Elevations: KB: 329' -
GL: 302.4'. BF:
17. Field / Pool(s): Swanson River
Beluga Undef Gas
10. Plug Back Depth MD/TVD:
0' MD / 0' TVD
18. Property Designation:
FEDA028384 '
4b. Location of Well (State Base Plane Coordinates, NAD 27):
Surface: x- 348887.4 y- 2480034.5 • Zone- 4
TPI: x- y- Zone- 4
Total Depth: x- 351054.0 y- 2480010.2 Zone- 4
11. Total Depth MD/TVD:
.11,590- MD/ 11,187' TVD ,
19. DNR Approval Number:
N/A
12. SSSV Depth MD/TVD:
N/A
20. Thickness of Permafrost MD/rVD:
N/A
5. Directional or Inclination Survey: Yes L (attached) No
Submit electronic and printed information per 20 AAC 25.050
13. Water Depth, if Offshore:
N/A (ft MSL)
21. Re-drill/Lateral Top Window MDfrVD:
N/A
22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days
of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential,
gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and
perforation record. Acronyms may be used. Attach a separate page if necessary
N/A
23. CASING, LINER AND CEMENTING RECORD
WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT
CASING FT GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED
22" Surf 45' Surf 45'
13-3/8" 54.5 K-55 Surf 2,958' Surf 2,958'
7" 25.29 P110 N80 Surf 10,257' Surf 9,938'
5" 18 L-80 9,971' 11,590' 9,673' 11,187'
24. Open to production or injection? Yes ❑ No ❑✓
If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date Perfd):
/ bmha1
M&OWT"
DATE
21 Lwi
VERIFIED
ern!
25. TUBING RECORD
SIZE DEPTH SET (MD) PACKER SET (MD/f VD)
N/A N/A N/A
26. ACID, FRACTURE, CEMENT SQUEEZE, ETC.
Was hydraulic fracturing used during completion? Yes No 4
Per 20 AAC 25.283 (i)(2) attach electronic and printed information
DEPTH INTERVAL (MD) INOUNT AND KIND OF MATERIAL USED
N/A N/A
27. PRODUCTION TEST
Date First Production:
N/A
Method of Operation (Flowing, gas lift, etc.):
Date of Test:
N/A
Hours Tested:
Production for
Test Period
Oil -Bbl:
Gas -MCF:
Water -Bbl:
Choke Size:
Gas -Oil Ratio:
Flow Tubing
Press.
Casing Press:
I
Calculated
24 -Hour Rate
Oil -Bbl:
Gas -MCF:
Water -Bbl:
Oil Gravity - API (corr):
Form 10-407 Revised 5/2077 3�_/ ryCONTINUED ON PAGE 2 9BDMSl�" OCT 0
9 2019
Sub ORIGINAL only
28. CORE DATA Conventional Corals): Yes ❑ No ❑✓ - Sidewall Cores: Yes ❑ No Q
If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form,
if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071.
29. GEOLOGIC MARKERS (List all formations and markers encountered):
30. FORMATION TESTS
NAME
MD
TVD
Well tested? Yes ❑ No ❑Q
If yes, list intervals and formations tested, briefly summarizing test results.
Permafrost - Top
Permafrost - Base
Attach separate pages to this form, if needed, and submit detailed test
Top of Productive Interval
information, including reports, per 20 AAC 25.071.
Formation at total depth:
31. List of Attachments: Operations Summary, Schematic, MIT -IA, Photo document casing cut-off/cement top/welded plate.
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis,
paleontological report, production or well test results, per 20 AAC 25.070.
32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge.
Authorized Name: Bo York 907-777-8345 Contact Name: Ted Kramer, Operations Engineer
Authorized Title: Operations Manager Contact Email: tkramer@hilcoro.com
AuthorizedTaY �' asz� / Contact Phone: 907-777-8420
Signature: -('o, (3p 0r Date: r
INSTRUCTIONS
General: This form and the required attachments provide a complete and concise record for each well drilled 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. All laboratory analytical
reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted.
Item 1 a: 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 1 b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Item 4b: TPI (Top of Producing Interval).
Item 9: The Kelly Bushing, Ground Level, and Base Flange 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 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY -123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of
completion, suspension, or abandonment, whichever occurs first.
Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
Item 24: 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 reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Item 30: 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.
Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Form 10-407 Revised 512017 Submit ORIGINAL Only
Swanson River
SCHEMATIC Well SRU 32A-15
Tagh Casing & Tubing
RKB =15.0' / Surface
Casing
Punch
154'-159'
TD=11,590' PBTD=O'
Max Deviatioo = 24.3- @ 7,815'
Size
Type
Wt
Grade
Thrd
ID
Top
Btm
Hole
Cmt
CmtTo
22"
1 Conductor
$ zPerfs
CIBP w/ 35' cemmt on top (TOC =2,000') 4/9/19 l
C.
2,491'
Surf
45'
Chem inj Sub
Yes
Surf.
7B"
Surf Csg
54.5
K-55
3609'
12.615
Surf
964'
3,912'
1000
4
Perf538-4 Bd.'.
2-1/8" CIBP
D.
5,540'
6
S zPerfe
Slickline A slip stop, Macco Plug, & AD -2 slip stop w/-61'
cement TOC 5479'EL
E.
18
5/8"
SIC
Surf
DV Collor
964' %7'
3 $„
Surf Csg
54.5
K-55
G.
12.615 %7' 2958'
600 sx
G 4'
CIBP
H.
6000'
56-0 Belu
Cut tubing
GLM Q.
6220'
2.347
5.5" x 4.673"
Cmnw MMG-P GLM
7"
Prod Csg
29
-
P110
Brd
6.184
Sorf
39'
10-
5191,8467
1000
Th
DV (r4
6495'
CBL
7"
26
6.276 39' 2097'
7"
29
N-80
6.184 2097' 3439'
7"
26
6.276 3439' 6158'
7"
29
6.184 6158' 7933'
7"
26
P -I 10
6.276 7933' 8467'
DV Collar
Cemto MMG-P GLM
84671 8470'
7
Prod Csg
26
P-110
6.276 8470' 9789'
1000
sxs
9399'
Calculated
7"
29
6.184 9789' 10,257'
5"
Liner
18
1,80
Bunn ss
4.276
9971'
11,590
6"
500
11,250'
1.875"
3.065"
Oris "XA" SidSNe
GLM 07.
11,149'
1.875"
4.125"x
2.781"
Camco KBMG-2 GLM
6.
sxs
CHL
Tubing
15.0' Original RKB to Tbg Hngr
7.
11 226'
1,875"
2.701"
Otis "X" Profile Nile
e.
2-7/8"
2.32"
1 6.4
1 N-80
Buttress
2.441
Surf
5727'
2 7/8"
6.4
N-80
Buttress
2.441
6000'
9766'
2318"
1 4.6
1 N-80 I
Buttress 1
1.995
9766'
11256'
T F w F r. R V n F T d r I.
NO.
Depth
H3
OD
Item
A.
160'
If
C...;ua
CIBP w/ 160' cement on to (In surface) 4/10/19
B.
2,035'
6
$ zPerfs
CIBP w/ 35' cemmt on top (TOC =2,000') 4/9/19 l
C.
2,491'
2.363
Perfs 369A Mua
Chem inj Sub
3,802'
3 603'
4
Pe Ra 369 Bdu
2-78" CHIP w/ of cam t on to TOC = 3,562') 4/6/19
C2.
3609'
4
rerf5369 mu a
2-7/8" Tubing Plug
ug
3,912'
4,980
4
Perf538-4 Bd.'.
2-1/8" CIBP
D.
5,540'
6
S zPerfe
Slickline A slip stop, Macco Plug, & AD -2 slip stop w/-61'
cement TOC 5479'EL
E.
5692'
6
5 z Perfs
BOT 3-1/2" Landing Collar w/ XO's to 2-7/8" box & Pin
F.
5727'
6
Isolated
BOT 3-1/2" Float Shoe w/ XO to 2-7/8" box
G.
5750'
S zPeM
CIBP
H.
6000'
56-0 Belu
Cut tubing
GLM Q.
6220'
2.347
5.5" x 4.673"
Cmnw MMG-P GLM
GLM 02.
6891'
2.347
5.5"x4.673"
Camw MMG-P GLM
L
7000'
68-0 U r Lobe. P&A'd IOMl04
Tbg. plug
1.
7345'
Lw Lobe. P&A'd 10/24/0411,321,336'
EZ Drill CIBP
GLM 03.
7597'
2.347
5.5"x4.673"
Camw MMG-P GLM
GLM 04.
8303'
2.347
5.5" x 4.673"
Cameo MMG-P GLM
GLM 05.
9039'
1 2.347
5.5"x4.673"
Cemto MMG-P GLM
2.
9300'
Cott Retainer OC in tb
3.
9717'
Cmt Retainer
GLM 06.
9726'
2.347
5.5"x4.673"
Camw MMG-P GLM
4.
9766'
1.995"
3.503"
Crossover, 2-7/8" EUE 8rd x 2-3/8" EUE 8rd
5.
10,448'
1.875"
3.065"
Oris "XA" SidSNe
GLM 07.
11,149'
1.875"
4.125"x
2.781"
Camco KBMG-2 GLM
6.
11 186'
2.55"
Otis "BIND" Pla
7.
11 226'
1,875"
2.701"
Otis "X" Profile Nile
e.
11,256'
2.32"
2.872"
WLEG
P F R F O R A T I D N H I S T O R V
lot erval(N D)
A...
Top
Bw
Aart
If
C...;ua
3,493'
3,503'
10'
6
$ zPerfs
3,687'
3,695'
8'
4
Perfs 369A Mua
3,796'
3,802'
6-
4
Pe Ra 369 Bdu
3,812'
3,8.32'
20'
4
rerf5369 mu a
3902'
3,912'
10'
4
Perf538-4 Bd.'.
4,986
4996'
10'
6
S zPerfe
5,014'
5,024'
10'
6
5 z Perfs
5000'
501V
10
6
Isolated
5545'
5555'
IVM6,O
S zPeM
5,555'
5,56T
ITIsolated
56-0 Belu
5554'
5582'
28'If01ate456A
Bel
5590'
S60V
IVs
Nfs
7,267
7,282'
IS'
68-0 U r Lobe. P&A'd IOMl04
7,358'
7,398'
4V68-0
Lw Lobe. P&A'd 10/24/0411,321,336'
10'P&A
11,340'
11346'
6'P&A
11,354'
11364'
10'P&A
Updated by DMA 09-06-19
Hilcorp Alaska, LLC
Well Operations Summary
Well Name
Rig
API Number
Well Permit Number
Start Date End Date
SRU 32A-15
50-133-10141-01
1 194-084
4/6/19 1 8/26/19
Daily Operations:
04/06/2019 -Saturday
R/U Pollard E -line utilizing lubricator and associated crane. SIMOPS: Weaver Brothers trucking on location to begin
moving equipment f/ 44-33 to 32A-15. Rig crews conduct rig move activities in support of Weaver Bros. M/U 2.30" gauge
ring and perform drift run down to 3,609'md ELMD. Tag plug and POOH. Rig crew clean 44-33 location as equipment is
shuffled to 32A-15. M/U CIBP and RIH through 2-7/8" 6.5#/ft TBG down to 3,609'md. P/U until full weight of string is
seen on indicator and set CIBP. Confirmation of CIBP set with weight indicator drop of 50lbs. P/U 20'md and then drop
back down and tag top of plug. (3,603' ELMD). POOH and L/D running tool. M/U cement bailer BHA and mix cement for
dump bail run. RIH w/ cement dump bailer down to top of plug @ 3,603'ELMD. Tag plug, P/U 5'md and activate dump
bailer. Good indication of cement dump (40lbs weight drop on indicator). Slowly POOH for first 50'md and then POOH to
surface at regular speed. Mix cement for dump bailer run #2. Load bailer and RIH down to 3,580'md notice 20lbs weight
drop on indicator. P/U to 3,571'md and dump cement. No weight drop indication seen. P/U 20'md and see 40lbs weight
drop. Slowly P/U another 30'md and then POOH. Bailer empty at surface. R/D, M/0 Pollard E -line. Rig crews L/D felt and
containment in prep for setting equipment. Continue to set containment and spot equipment in place on 32A-15.
04/07/2019 -Sunday
PTW, JSA. Check oils. Fire up rig. Wellhead hand set BPV. Nipple down tree and install 7" BOPS. Rig up Kill and Choke
lines. Fluid pack. Rig up PVT system. Rug up gas alarm system with total safety. Level carrier. Plug in electrical cords.
Finish containment berm. 24 hr BOPE test witness notification send 4/5/19 @ 10:58 am. by Cody Rymut. AOGCC
representative Adam Earl on location to witness. Start BOPE test. Test all rams and valves to 250/2,500 psi. 1 Fail/Pass
on kill line inside manual gate valve. Greased valve and re tested. Bope test complete. Remove Test joint and pull 2 way
check. Break out pump in sub and install pulling joint with TIW valve into hanger. SDFN. Location walk around complete.
04/08/2019 - Monday
PTW, JSA. Location walk around and equipment checks performed. Fill tubing with 4 bbls of lease water. Pressure test 2-
7/8" tubing to 2,500 psi for 30 minutes. Pressure test IA to 2,500 psi for 30 minutes and chart. Check well pressure. 0 psi
on tubing and 0 psi on IA. Pollard E -line on location. SIMOPS completed. RU Pollard E -line. Make up CCL and 2.30" Gauge
ring. Back out hanger lock down screws and pull tubing into tension prior to shooting. Not able to clear collar of test
joint. Re configure setup. Add spacer spool between top of annular bag and slips. Pick up to 31K on weight indicator. Sk
over string weight. Set slips. Rig up Pollard. Stab on well. RIH with 2.30" GR. Tied into existing plug correlation log.
Tagged TOC @ 3,562'. Calculated cement volume should have been 3,570'. POOH to surface. Make up 2.30" jet cutter.
RIH. Tag TOC. Log out of hole and tie into Chemical injection sub at 2,491' . RIH PU and stop CCL at 2,191.5'. Jet cutter at
2,197'. (2,200' had a collar). Fire jet cutter. POOH to surface and rig back E -line. PU on tubing 13k. Pipe is cut. Lay down
test joint and tubing hanger. Rig up wooden spool for control line. Trip OOH. Laying down pipe. Spool up control line. All
tubing out of hole. 68 joints. Secure well. Location walk around complete. SDFN
Hilcorp Alaska, LLC
Well Operations Summary
Well Name Rig
API Number
Well Permit Number Start Date End Date
SRU 32A-15
50-133-10141-01
1 194-084 4/6/19 1 8/26/19
Daily Operations:
04/09/2019 -Tuesday
PTW and safety meeting. with AAO rig crew and AK E -line. Rig up AK E -line. 0 psi tubing 0 psi casing. RIH w/ 5.9" gauge
ring to 2,059' POOH. Junk basket full of mud push from back side of tubing. RIH with 5.72" GR to 2,059'. POOH. Junk
basket full of mud push. Make up 7" CIBP. RIH and log. Correlate depth. Set CIBP @ 2,035' KB. POOH. Fluid pack well.
Pressure test CIBP to 1,500 psi for 30 minutes and Chart. Good test. Make up 5" x 30' bailer. Mix cement kits. RIH and
dump cement at 2,033'. POOH. Mix 2nd batch of cement. RIH and dump cement. 35' of cement placed on top of CIBP.
OOH Rig down dump bailer. Make up 7" CIBP. RIH and set at 160'. POOH. Make up 5'4 spf casing punch. Punch holes
from 154'-159'. POOH to surface. Rig down E -line. Line up to pump down 7" casing and return up 13-3/8" casing. Online
pressure increased to 1,500 psi. No communication between casings. While rigging up return line to 13-3/8" outlet rig
crew saw cement in wellhead. Bleed down pressure. Secure well. Prep for cement job. Location walk around complete.
Locate handling equipment and x overs for next well SRU 14-15.
04/10/2019- Wednesday
Hold safety meeting with rig crew. Perform location walk around. Fire rig and RIH with 160' of tubing. Tag CIBP. PU 1'
Install TIW valve and 1502 pump in sub. Hold safety meeting with Halliburton cementers. Rig up cement pump truck to 2-
7/8" tubing. Mix up 7 bbls of 15.8 ppg class G cement. 1.15 yield, 34.1 sks, 4.99 gallons per sks. Cement mixed and Mud
scale confirmed by BLM Rep and Co Rep to be 15.8 ppg. Online with cement 2 bbls/min. 356 psi. 7 bbls pumped and still
no cement to surface. Shut down. Pull on water and mix 3 additional bbls of 15.8 ppg class G. Pump 3 additional bbls.
Good cement to surface. Sample caught. BLM Rep satisfied with cement returns. Rig down Cement line. Trip tubing OOH
at 30 ft/min laying down joints. Wash inside of BOPE with fresh water to clear any potential cement. Rig down HAK 401.
08/26/2019 - Monday
BLM/AOGCC Inspectors onsite, upon verification of cured cement to surface the wells abandonment plate was welded
i accordance with BLM/State of Alaska requirements.
SRU 32A-15 Wellhead Removed/Cemented to
Surface
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08 27'19:06:50
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14:05:16
-47.9°
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Well S.R.U. 32A-15 Plug & Abandon Memo
Via email
Date: 7/17/2019
To: Hilcorp Alaska LLC .................................................... Attn: Cole Bartlewski
From: James A. Hall. PLS
Project: Swanson River Unit — SRU 32A-15 Well Plug & Abandon Survey
Re: Project Summary
This memo represents the plug and abandon survey performed by McLane Consulting Inc. (McLane) for
Hilcorp's Swanson River Unit SRU 32A-15 well located in Section 15, Township 8 North, Range 9 West,
Seward Meridian, Alaska.
The survey was performed on July 3, 2019. The scope of work consisted of providing accurate field
elevations so the well could be plugged and abandoned per State requirements. Existing survey control
was recovered and positional accuracy was confirmed by comparing (2) check shots on hard targets to
existing data. To establish original ground elevation near the well casing, (2) original ground survey
measurements were observed at the perimeter of the pad in opposite positions from the well location. A
prorated original ground elevation at the well was computed from the (2) pad perimeter original ground
shots. A top of pad elevation was also recorded on or adjacent to the well casing. A measurement and an
"X' to the proposed cutoff elevation was marked on the cellar.
Enclosed is Exhibit A which includes well casing cutoff detail with pad, original ground, and proposed casing
cutoff elevations.
• Mean pad surface grade in vicinity of well casing: 317.4'± "i(2019)
• Original ground elevation in vicinity of well casing: 316.0' t (2019)
• Cutoff depth requirement: 3.0' below original ground elevation
• Minimum casing cutoff elevation: 313.0'
• Casing cutoff elevation as staked in field: 312.0'
The cutoff mark elevation of 312.0', as referenced in the field, exceeds the required minimum cutoff
elevation of 313.0'.
Please feel free to contact me if you have any questions or comments.
Sincerely,
�,,//
X
James A. Hall, PLS
McLane Consulting, Inc.
P.O. Box 468 Soldotna, Alaska 99669 (907) 283-4218 Fax (907) 283-3265
Email jhall@mcianecg.com
ORIGINAL GROUND SHOTti
ELEV=314.2' (2019)X
rm
JAMES A. HALL ._
1) BASIS OF HORIZONTAL, NAD83 US FEET
POSITION (EPOCH 2010) AND VERTICAL
CONTROL (NAV088) IS AN OPUS SOLUTION
FROM NGS STATIONS TBON, TSEA, AND ZAN1 TO
ESTABLISH CPA 5. THE ALASKA STATE PLANE
COORDINATES NAD 83 ZONE4 ARE:
N = 2480030.714 I E = 1488857.9951 ELEV = 318.981
SCP -15
TS 2-15
SRU 242-16
SRU 12-15
SRU 241-16
SRU 32A-15 P&A
ASP NAD83 ZONE
N: 2479796.3
E: 1488910.8
ELEV=317.4' ✓.
XORIGINAL GROUND SHOT
ELEV=317.7' (2019)
GRAPHIC SCALE
0 50 100 200
i im��
1 inch = 100 ft.
WELL CASING
r�TO BE REMOVED
PAD ELEV = 317.4' t
_ _ - _ - _ O.G. ELEV 316.0' t
i
4.0' REFERENCED
WELL CASING
CUTOFF AT
FI FV = 'ii9 n'
PRWJ HILCORP ALASKA, LLC "F'A610N -
Consulting Inc
SWANSON RIVER UNIT MM 7117=1B WELL SRU 32A-15 Bnn"v ;cB
PLUG AND ABANDON EXHIBIT -A mwi 1'100
aECT No. 7pBV1
ENaNEEPoNGIIMPPBlG18VBVEY,NG1TESTING NAD 83, ASP ZONE 4 <>o w 1903
Pp.
vace roeaaeB7)M A2le 18 fNA PI(. BB66Y LO4NTICN
vroc IBmlxwxzBs SECTION 15, TOWNSHIP 8 NORTH, weer
Ew L. Buncw+E®r curEcc. llilcarp Alaska, LLC
RANGE 9 WEST, SEWARD MERIDIAN ALASKA
Remark:
AOGCC
Coordinate Check
29 January 2020
INPUT OUTPUT
State Plane, NAD83 State Plane, NAD27
5004 -Alaska 4, U.S. Feet 5004 -Alaska 4, U.S. Feet
Accuracies of conversions from NAD 83 to NAD 27 are typically 12 to 18 cm.
SWANSON RIV UNIT 3 1/1
NorthingN: 2479796.3 NorthingN: 2480034.484
EastinglX: 1488910.8 EastinglX: 348887.444
Convergence: -0 44 24.03141 Convergence: -0 44 17.07151
Scale Factor: 0.999926121 Scale Factor: 0.999925984
Grid Shift (U.S. ft.): X/Easting = -1140023.4, Y/Northing = 238.2
Datum Shift (m): Delta Lal. = 62.453, Delta Lon = -120.906
Corpscon v6.0.1, U.S. Army Corps of Engineers
MEMORANDUM
State of Alaska
Alaska Oil and Gas Conservation Commission
TO: Jim Regg61t`( DATE:
P. I. Supervisor
FROM: Brian Bixby SUBJECT:
Petroleum Inspector
August 28th 2019
Surface Abandon
SCU 32A-15
Hilcorp Alaska Inc.
PTD 1940840; Sundry 319-131
8/26/2019: 1 arrived at Swanson River Field and met up with Mike Erstrom (Hilcorp
Construction Foreman). We went to the well location and I verified there was good hard
cement to surface and all the correct information was on the marker plate. The cut off is
over 4 feet below grade. I also took pictures of the hard cement, marker plate, marker
plate after welded on and the depth of the cutoff.
Attachments: Photos (4) ,
2019-0826_Surface_Abandon_SRU-32A-15_bb.docx
Page 1 of 3
Surface Abandon — SRU 32A-15 (PTD 1940840)
Photos by AOGCC Inspector B. Bixby
8/26/2019
2019-0826_Surface_Abandon_SRU-32A-15_bb.docx
Page 2 of 3
rV +04 :7 40/847.9150�G" �f
-60
37
► 004 +00.1" ew ` X57 ►—�
x -55
• 047° N47E 0836mi1s TRUE
rrw7"iiiii/ 030 •� 060
-02.2w
35250'/ -150.847583 'T 533ft
1 14:05:16
NIGHT
f..
-50
-47.9° ►
.—
00
35250'/ -150.847583 'T 533ft
1 14:05:16
NIGHT
f..
-50
-47.9° ►
.—
Page 1 of 2
• •
Schwartz, Guy L (DOA)
From: Stan Golis [sgolis @hilcorp.com]
Sent: Monday, April 09, 2012 7:39 AM
To: Schwartz, Guy L (DOA)
Cc: Larry Greenstein; Chet Starkel; Chris Kanyer
Subject: FW: SRU 32A -15 (PTD 194 -084)
Guy,
As requested, listed below is background information for the new perfs on the SRU 32A -15. Please let
me know if you want to discuss further. Thanks. Stan
From: Chris Kanyer
Sent: Monday, April 09, 2012 7:34 AM
To: Stan Golis; Tom Fouts - (C); Donna Ambruz
Cc: Chet Starke)
Subject: RE: SRU 32A -15 (PTD 194 -084)
The isolated 50 -6 sand and the newly perforated 36 -9, 37 -9, 38 -0, & 39 -1 sands are all Beluga Pool
sands. We have not perforated a new pool in this well.
Chris Kanyer; Reservoir [rnniiik: er
X Description:
HAK_Logo
_ I I ,
ckanyer @hilcorp.com APR. 0 9 a12'
Direct: (907) 77743377
Mobile: (907) 250-037 -1
From: Stan Golis
Sent: Friday, April 06, 2012 11:40 AM
To: Tom Fouts - (C); Chris Kanyer; Donna Ambruz
Cc: Chet Starkel
Subject: FW: SRU 32A -15 (PTD 194 -084)
Please assist.
From: Schwartz, Guy L (DOA) [ mailto:guy.schwartz @alaska.gov]
Sent: Friday, April 06, 2012 11:39 AM
To: Stan Golis
Subject: SRU 32A -15 (PTD 194 -084)
Stan,
I have a 10-404 report for setting a CIBP and perforating in SRU 32A -15 (PTD 194 -084) . Need some
background information for the new perfs and if they are in a new pool vs what was open before to
production.
Thanks,
4/9/2012
Page 2 of 2
• •
Guy Schwartz
Senior Petroleum Engineer
AOGCC
793 -1226 (office)
444 -3433 (cell)
,II
4/9/2012
STATE OF ALASKA
ALA. OIL AND GAS CONSERVATION COMMIION
REPORT OF SUNDRY WELL OPERATIONS
1. Operations Abandon U Repair Well U Plug Perforations 11 Stimulate U Other U Plug back
Performed: Alter Casing ❑ Pull Tubing ❑ Perforate New Pool ❑ Waiver ❑ Time Extension ❑
Change Approved Program ❑ Operat. Shutdown p Perforate is Re -enter Suspended Well ❑
2. Operator 4. Well Class Before Work: 5. Permit to Drill Number:
Name: Hillcorp Alaska, LLC Development 0 Exploratory ❑ 194 -084 —
3. Address: 3800 Centerpoint Drive, STE 100, Anchorage , Stratigraphic ❑ Service ❑ 6. API Number:
Alaska 99503 50- 133 - 10141 -01 -00
7. Property Designation (Lease Number): 8. Well Name and Number:
FEDA028384 [Swanson River Unit] Swanson Riv Unit (SRU) 32A -15 `
9. Field /Pool(s): ( ►
c
Swanson River Field/ Hemlock Oil & Beluga Undef Gas Pools
10. Present Well Condition Summary: MAR 5 0 Z Q 1
Total Depth measured 11,590 feet Plugs measured %to, eivivomeWons. C0mmission
true vertical 11,187 feet Junk measured 5,015 (fill) Amilt3V40
Effective Depth measured 4,980 feet Packer measured N/A feet
true vertical 4,980 feet true vertical N/A feet
Casing Length Size MD TVD Burst Collapse
Structural
Conductor 45' 22" 45' 45'
Surface 2,958' 13 -3/8" 2,958' 2,958' 2,730 psi 1,130 psi
Intermediate
Production 10,257' 7" 10,257' 9,938' 7,240 psi 5,410 psi
Liner 1,619' 5" 11,590' 11,187' 10,140 psi 10,500 psi
Perforation depth Measured depth 3.687- 3,695; 3.796- 3.802; 3.812- 3.832: 3,902 -3.912 feet
True Vertical depth 3,687- 3.695; 3,796- 3,802; 3.812- 3.832; 3,902 -3,912 feet
Tubing (size, grade, measured and true vertical depth) 2 -7/8" x 2 -3/8" 6.4# N -80 Surf. - 5,727' Surf.- 5,727'
Packers and SSSV (type, measured and true vertical depth) N/A N/A N/A N/A
11. Stimulation or cement squeeze summary: N/A
Intervals treated (measured): N/A
Treatment descriptions including volumes used and final pressure: N/A
12. Representative Daily Average Production or Injection Data
Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure
Prior to well operation: 0 0 0 80 900
Subsequent to operation: 0 1,208 0 90 1,300
13. Attachments: 14. Well Class after work:
Copies of Logs and Surveys Run N/A Exploratory ❑ Development El ' Service ❑ Stratigraphic ❑
Daily Report of Well Operations Attached 15. Well Status after work: Oil ❑ Gas p -' WDSPL ❑
GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑
16. 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:
Contact Stan Golis Phone 907 - 777 -8356
Printed Name Stan Golis Title Operations Manager
Signature 5 Phone 907 - 777 -8300 Date 3/30/2012
R OOMS APR 0 2 2 ll _
Form 10 -404 Revised 10/2010 Submit Original Only
•
• . Swanson River
Well SRU 32A -15
As Completed 1/24/05
Hi!cora Alaska, LLC
C a s i n g & T u b i n g
RKB =15.0' Size Type Wt Grade Thrd ID Top Btm Hole Cmt Cmt Top
22" Conductor Surf 45' Yes Surf.
13-
3/8" Surf Csg 54.5 K -55 12.615 Surf 964' 1000 Surf
DV Collar 964' 967' 18- sx
5/8"
3/ g„ Surf Csg 54.5 K -55 12.615 967' 2958' 600 sx (Calculated)
a , A 7" 29 P -110 6.184 Surf 39'
0 7" 26 6.276 39' 2097' 1000
7" 29 6.184 2097' 3439'
"r 2 20 C S' * 7" Prod Csg 26 N -80 6.276 3439' 6158' Thru 6495'
,
• 7" 29 8rd 6.184 6158' 7933' 10 DV @ CBL
7" 26 P -110 6.276 7933' 8467' 5/8 8467'
DV Collar 8467' 8470'
7" 26 6.276 8470' 9789' 1000 9399'
i i Prod Csg P -110 -
7" 29 6.184 9789' 10,257' sxs Calculated
1 '', Buttress 500 11,250'
5 Liner 18 L -80 4.276 9971' 11,590 6"
TOF @ SXS C'.13I
5,015' Tubing 15.0' Original RKB to Tbg Hngr
2 -7/8" 6.4 N -80 Buttress 2.441 Surf 5727'
, ;, 2 7/8" 6.4 N -80 Buttress 2.441 6000' 9766'
I I 2 3/8" 4.6 N -80 Buttress 1.995 9,766' 11,256' -
56 - 0„ JEWELRY DETAIL
NO. Depth ID OD Item
4,o• a Tubing Hanger, FMC Type TCM 7 1/16" OD x 2 7/8" EUE
E 16.44' lift and suspension, W/ Cont Cort Line
F 2491' 2.363 Chem In) SO
�n
r Loc 0 4,980 C 2 -1/8" CIBP - i
,t; : ' ' slip stop, Macco Plug, & AD -2 slip stop w /-61'
G B. 5,540' cement (TOC @ 5,479' ELM)
o ter+ C. 5692' BOT 3 -1/2" Landing Collar w/ XO's to 2-7/8" box & Pin
- i i 68 I
D. 5727' BOT 3 -1/2" Float Shoe w/ XO to 2 -7/8" box
�
. • E. 5750' CIBP
F. 6000' Cut tubing
PMIEM^ GLM #1. 6220' 2.347 5.5" x 4.673" Camco MMG -P GLM
' GLM #2. 6891' 2.347 5.5" x 4.673" Camco MMG -P GLM
G. 7000' Tbg. plug
2 in, 1. 7345' EZ Drill CIBP
GLM O. 7597' 2.347 5.5" x 4.673" Camco MMG -P GLM
3 61.1iii ' GLM #4. 8303' 2.347 5.5" x 4.673" Camco MMG -P GLM
mom GLM #5. 9039' 2.347 5.5" x 4.673" Camco MMG -P GLM
2. 9300' Cmt Retainer (TOC in tbg)
f I 1
3. 9717' Cmt Retainer
G LM #6. 9726' 2.347 5.5" x 4.673" Camco MMG -P GLM
4. 9766' 1.995" 3.503" Crossover, 2 -7/8" EUE 8rd x 2 -3/8" EUE 8rd
5. 10,448' 1.875" 3.065" Otis "XA" SIdg Slve
GLM #7. 11,149' 1.875" 4.125" x Camco KBMG -2 GLM
2.781"
6. 11,186' 2.55" Otis "BWD" Pkr
7. 11,226' 1.875" 2.701 Otis "X" Profile Nipple
8. 11,256' 2.32" 2.872" WLEG
l+
PERFORATION HISTORY
r a ,, , ■.. G Interval(MD) Accum.
_
l Top Btm Amt spf Comments
N. 3,493' 3,503' 10' 6 Sqz Perfs
r � m =p 7 3,687' 3,695' 8' 4 Perfs
0
H = 3,796' 3,802' 6' 4 Perfs allik -o f
g 3,812' 3,832' 20' 4 Perfs
-' 3,902' 3,912' 10' 4 Perfs
4,986' 4,996' 10' 6 Sqz Perfs
5,014' 5,024' 10' 6 Sqz Perfs
ps' 5,000' 5,010' 10' 6 Isolated
4Z `c 5,545' 5,555' 10' 6 Sqz Perfs
5,555' 5,567' 12' 18 Isolated 56 -0 Beluga
5,554' 5582' 28' 12.0 Isolated 56 -0 Beluga
i` 1 5,590' 5,600' 10' 6 Sqz Perfs
TD= 11,590' PBTD= 5,750' 7,267' 7,282' 15' 6.0 68 -0 Upper Lobe. P &A'd 10/24/04
7,358' 7,398' 40' 6.0 68 -0 Lwr Lobe. P &A'd 10/24/04
Max Deviation = 24.3° @ 7815' 11,326' 11,336' 10' P &A
11,340' 11,346' 6' P &A
11,354' 11,364' 10' P &A
Revised DMA 3 -29 -2012
• •
Hilcorp Alaska, LLC
Well Operations Summary
Well Name API Number Well Permit Number Start Date End Date
SRU 32A -15 50- 133 - 10141 -01 194 -084 12/29/11 3/1/12
Daily Qtietatto .,
2/29/2012 - Wednesday
Rig up lubricator, pressure test to 250 psi low and 2,500 psi high. RIH w/ 2.3" GR and tagged fill at 5,015'RKB,POOH. RIH w/ 2.
1/8" cast iron bridge plug and set at 4,980'RKB, POOH. Pressure tubing up to 1,650psi and hold for 30 min. for positive test.
Bled pressure down to 650psi and hold for 30 min. for negative test. RD.
3/1/2012 - Thursday
Pressure tubing up to 1,200psi. Rig up lubricator, pressure test to 250 psi low and 2,500 psi high. RIH w/ 2 -1/2 "x10' Hero HC,
4 spf, 60 Deg phase and tie intyo SLB perf record dated April 11th 2008. Fired • erf :un fro s • ! • ' • • 200psi on
tubing. Did not observe a pressure change. POOH. RIH w/ 2 -1/8 "x20' Hero HC, 4 spf, 60 Deg phase and fired perf gun from
3,812' to 3,832'. Pressure increased to 1,450psi in 2 minutes. POOH. Completed two more perf gun runs across the intervals
of 3,796' to 3,802' and 3,687' to 3,695' with no change in pressure. POOH. Rig down and turn well over to production.
3/2/2012 - Friday
No operations to report.
3/3/2012 - Saturday
No operations to report.
3/4/2012 - Sunday
No operations to report.
3/5/2012 - Monday
No operations to report.
3/6/2012 - Tuesday
No operations to report.
ii-/GA-
STATE OF ALASKA r2;a(zora
y ALASKA WAND GAS CONSERVATION COMMISSIOW
REPORT OF SUNDRY WELL OPERATIONS
1. Operations Abandon LJ Repair Well U Plug Perforations 11 Stimulate 11 Other 11
Performed: Alter Casing ❑ Pull Tubing ❑ Perforate New Pool ❑ Waiver ❑ Time Extension ❑
Change Approved Program ❑ Operat. Shutdown Perforate El Re -enter Suspended Well
2. Operator Union Oil Company of California 4. Well Class Before Work: 5. Permit to Drill Number:
Name: Development 0 Exploratory ❑ 194 -084
3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic❑ Service ❑ 6. API Number:
50-133-10141-01-.00
7. Property Designation (Lease Number): 8. Well Name and Number:
FEDA028384 [Swanson River Facility] Swanson Riv Unit (SRU) 3g -15
9. Field /Pool(s):
Swanson River Field / Hemlock Oil, Beluga Undef Gas
10. Present Well Condition Summary:
Total Depth measured 11,590 feet Plugs (measured) 5,540 & 5,750 feet
true vertical 11,187 feet Junk (measured) 5,402 (fill) feet
Effective Depth measured 5,479 feet Packer (measured) 11,186 feet
true vertical 5,476 feet (true vertical) 10,806 feet
Casing Length Size MD / TVD Burst Collapse
Structural
Conductor 45' 22" 45' 45'
Surface 2,958' 13 -3/8" 2,958' 2,958' 2,730 psi 1,130 psi
Intermediate
Production 10,257' 7" 10,257' 9,938' 7,240 psi 5,410 psi
Liner 1,619' 5" 11,590' 11,187' 10,140 psi 10,490 psi
Perforation depth Measured depth 5,000'- ,010/ ) feet
True Vertical depth 4,999' - 5,009' feet
/ 6.4# N -80 x 5,727' & 6,000'- 9,766' x 5,722' & 5,989'- 9,483'x
Tubing (size, grade, measured and true vertical depth) 2 -7/8" x 2 -3/8" 4.6# N -80 9,766'- 11,256' 9,483' - 10,871'
/
Packers and SSSV (type, measured and true vertical depth) Otis BWD Packer 11,186'MD / 10,806'TVD N/A (� E N /A
11. Stimulation or cement squeeze summary: RECEIVED
Intervals treated (measured): DE f. . t
N/A �; }11C� DEC 282010
Treatment descriptions including volumes used and final pressure:
N/A _Masks Oil & Gas Cons. Commissions
12. Representative Daily Average Production or Injection Datq ,nc¢horage
Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure
Prior to well operation: 0 200 0 180 psi 925 psi
Subsequent to operation: 0 560 0 780 psi 950 psi
13. Attachments: 14. Well Class after work:
Copies of Logs and Surveys Run N/A Exploratory❑ Development El • Service ❑ Stratigraphic ❑
Daily Report of Well Operations X 15. Well Status after work: Oil ❑ Gas 0 S WDSPL❑
GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG❑
16. 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:
N/A
Contact Chris Kanyer 263 -7831
Printed Name Timothy C. Brandenburg Title Drilling Manager
Signature Jr Phone 276 -7600 Date 12/28/2010
RBDMS DEC 2 9 29CA
Form 10 -404 Revised 10/2010 Submit Original Only
Chevron • •
1100 Chevron - Alaska
%. Daily Operations Summary
Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft)
SRU 32A -15 SWANSON RIV UNIT 32A -15 FEDA028384 5013310141 QA5309 15.00
Pr J Ty Job Category Objective Actual St Date Actual E Date
Perforation - Re- Perforation Well Re- Perforate the 50-6 sand 11/28/2010 12/1/2010
Services
Primary Wellbore Affected Wellbore UWI Well Permit Number
A -15 U
SR 32 501331014101 1940840
SR 3 b e = : ! , fir ;.
1112812010 00:Oi - 1120010 00 00 ; . ., . �' . ., ..
Operations Summary
RU slickline. Pressure test lubricator to 250psi /2500psi high. RIH w/ 2.3" GR and tagged at 5,335' RKB SLM. RIH w/ 2.25 "x10' bailer and worked to
5,402'RKB SLM. RD slickline.
"01 0100 +w !O 12111204 00= w ,,
Operations Summ
RU Eline Pres test lubricator to 250psi/2500psi high. RIH w/ 2- 11/16" 60deg 6spf perf guns and reperforate 50 -6 sand from 5,000'- 5,010'RKB ELM.
RD Eline.
*. ., • Swanson River
Well SRU 32A -15
UNOC 76 As Completed 1/24/05
C a s i n g & T u b i n g
RKB =15.0' Size Type Wt Grade Thrd ID Top Btm Hole Cmt Cmt Top
1 L 22" Conductor Surf 45' Yes Surf.
13- Surf Csg 54.5 K -55 12.615 Surf 964' 1000
3/8" 18- sx Surf
t DV Collar 964' 967'
13 5 /8„ 2144'
Surf Cs 54.5 K -55 12.615 967' 2958' , 600 sx
g (Calculated)
d?
l A 7" 29 P -110 6.184 Surf 39'
u 7" 26 6.276 39' 2097' 1000
0
TOC @ 7 P rod Cs 29 6.184 2097' 3439' sx 6495'
; y « *- , .. , 2 200' 7 8 26 N -80 6.276 3439' 6158' 10 Thru CBL
t*rr " ^. * i =" 7" 29 8rd 6.184 6158' 7933' DV @
5/8"
� . 7 7" 26 P -110 6.276 7933' 8467' 8467'
l' -,.-40
t "7 . t DV Collar 8467' 8470'
if • • 7" 26 6.276 8470' 9789' 1000 9399'
7 „ Prod Csg 29 P -110 6.184 9789' 10,257', sxs Calculated
'4 500 11,250'
. Buttress 5 Liner 18 L -80 4.276 9971' 11,590 6" sxs C131. F # x .4
o
exl" ` Tubing 15.0' Original RKB to Tbg Hngr
2 -7/8" 6.4 N -80 Buttress 2.441 Surf 5727'
▪ T ' : ' 2 7/8" 6.4 N -80 Buttress 2.441 6000' 9766'
"` � 4,,, 2 3/8" 4.6 N -80 Buttress 1.995 9,766' 11,256'
' : ',C -' . - JEWELRY DETAIL
• • • D . 't NO. Depth ID OD Item
E Tubing Hanger, FMC Type TCM 7 1/16" OD x 2 7/8" EUE
F 16.44' lift and suspension, W/ Cont Cont Line
63 A. 2491' 2.363 Chem Inj Sub
637 0'
B. 5,540' Slickline A slip stop, Macco Plug, & AD -2 slip stop w /--61'
cement (TOC @ 5,479' ELM)
-- 68-t) C. 5692' BOT 3 -1/2" Landing Collar w/ XO's to 2-7/8" box & Pin
_ i
1 D. 5727' BOT 3 -1/2" Float Shoe w/ XO to 2-7/8" box
E. 5750' CIBP
II
F. 6000' Cut tubing
GLM #1. 6220' 2.347 5.5" x 4.673" Camco MMG -P GLM
GLM #2. 6891' 2.347 5.5" x 4.673" Camco MMG -P GLM
G. 7000 Tbg. plug
2 1. 7345' EZ Drill CIBP
GLM #3. 7 597' 2.347 5.5" x 4.673" Camco MMG -P GLM
• 3 G #4. 8 303' 2.347 5.5" x 4.673" Camco MMG -P GLM
✓ 4 GLM #5. 9039' 2.347 5.5" x 4.673" Camco MMG -P GLM
2. 9300' Cmt Retainer (TOC in tbg)
3. 9717' Cmt Retainer
i 1 GLM #6. 9726' 2.347 5.5" x 4.673" Camco MMG -P GLM
4. 9766' 1.995" 3.503" Crossover, 2 -7/8" EUE 8rd x 2 -3/8" EUE 8rd
5. 10,448' 1.875" 3.065" Otis "XA" Sldg Sive
GLM #7. 11,149' 1.875" 4.125" x Camco KBMG -2 GLM
2.781"
5 6. 11,186' 2.55" Otis`BWD" Pkr
2 _ - 7. 11,226' 1.875" 2.701" Otis "X" Profile Nipple
c _ 8. 11,256' 2.32" 2.872" WLEG
PERFORATION HISTORY
Interval Accum.
_� 6 Top Btm Amt spf Comments
3,493' 3,503' 10' 6 Sqz Perfs
i3 = '` '' - 7 4,986' 4,996' 10' 6 Sqz Perfs
. 5,014' 5,024' 10' 6 Sqz Perfs
o = 8 • 5,000' 5,008' 8' 6 11/7/2009, reperf 11/30/2010
5,545' 5,555' 10' 6 Sqz Perfs
5,555' 5,567' 12' 18 Isolated 56 -0 Beluga
5,554' 5582' 28' 12.0 Isolated 56 -0 Beluga
5,590' 5,600' 10' 6 Sqz Perfs
►� 7,267' 7,282' 15' 6.0 68 -0 Upper Lobe. P&A'd 10/24/04
TD= 11,590' PBTD = 5,750' 7,358' 7,398' 40' 6.0 68-0 Lwr Lobe. P &A'd 10/24/04
Max Deviation =24.3° @7815' 11,326' 11,336' 10' P &A
11,340' 11,346' 6' P &A
11,354' 11,364' 10' P &A
SRU 32A -15 Schematic 12- 28- 10.doc REVISED: 12 -28 -10 by CVK
STATE OF ALASKA
ALAS~IL AND GAS CONSERVATION COMMIS~
REPORT OF SUNDRY WELL OPERATIONS
~~~EIVEC~
-vov r 7 ~ofa~1Z~~9
Alaska Oil & Gas Cons. Cammis~ion
1. Operations Abandon Repair Weil Plug Perforations ~ Stimulate Other a~~~~~~ ~
Pertormed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver^ Time Extension^
Change Approved Program ^ Operat. Shutdown ^ Pertorate ^~ Re-enter Suspended Well^
2. Operator Union Oil Company of Califomia 4. Well Class Before Work: . Permit to Driil Number:
Name: Development Q Exploratory^ ' 1 4-084
3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic^ Service^ . API Number:
50-133-7 0141-01
Property Designation (Lease Number): Well Name and Number:
FEDA028384 [Swanson River Facility] Swanson Riv Unit (SRU) 32A-15
1'~ Field/Pool(s):
Swanson River Field / Hemlock Oil, Beluga Undef Gas
11. Present Well Condition Summary:
Totai Depth meas ~~J 11,590 feet Plugs (measured) 5,540 & 5,750 feet
true vertic~l 11,187 feet Junk (measured) N/A feet
Effective Depth measured 5,479 feet Packer (measured) 11,186 feet
true vertical 5,476 feet (true vertical) 10,806 feet
Casing Length Size MD ND Burst Collapse
Structural /
Conductor 45' 22" 45' 45'
Surtace 2,958' 13-3/8" 2,958' 2,958' 2,730 psi 1,130 psi
Intermediate
Production 10,257' 7" 10,257' 9,938' 7,240 psi 5,410 psi
Liner 1,619' S" 11,590' 11,187' 10,140 psi 10,490 psi
Perforation depth: Measured depth: 5,000'-5,008'
True Vertical depth: 4,999'-5,007'
5,727' & 6,000'-9,766' x 5,722' & 5,989'-9,483' x
Tubing (size, grade, measured and true vertical depthj: 2-7/8" x 2-3/8" 6.4# N-80 x 4.6# N-80 9,766'-11,256' 9,483'-10,871'
Packers and SSSV (type, measured and true vertical depth): Otis BWD Packer 1,18,¢"9~AD / 10,806'ND N/A N!A
a~
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
~~~a~~~ ~~ ~~ ~~~~U~
Tr atment descriptions induding volumes used and final pressure:
N/A
13. Representative Daily Average Production or Injection Data
Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure
Prior to well operation: 0 0 0 1,920 psi 2,090 psi
Subsequent to operation: 0 205 0 815 psi 1,060 psi
14. Attachments: 'f~Well Class after work:
Copies of Logs and Surveys Run N/A Exploratory^ Developmenfl Service ^
Daily Report of Well Operations X . Well Status after work: Oil Gas ^~ WDSPL
GSTOR ^ WAG ^ GINJ ^ WINJ ^ SPLU~ ^
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:
309-352 ~
Contact Chris Kanyer 263-7831
Printed Name Timothy C. Brandenburg Title Drilling Manager
./
.
. ~
:~
~
,,
.
_
.._
~r . Phone 276-7600 Date 11/17/09
Signature °` `~~
~
NOV ~ g 2009
Form 10-404 Revised 7/2009 Submit Original Only
~Chevron
Chevron - Alaska
~ Daily Operations Summary
SRU 32A-15 SWANSON RIV UNIT 32A-15 FEDA028384 5013310141 QA5309 329.00
s~ ~; y~., t, ~h =~~;~ r~~~ ~-~~
~ ti , ~.._
Primary Job Type Job Category Objective Adual Start Date Adual End Date
Completion - Reconfigure Well 10/30/2009
Services
Primary Wellbore Affected Wellbore UWI Well Permit Number
SRU 32A-15 501331014101 1940840
C~ 1~Pnt~t1~F r~ ~ "~;f' x. . "' ~ s.:.
~aas~2oo~ oa:oo - ~o~~~r~~ os no:aa ~
Operations Summary
Pressured well to 2400 psi to lower fluid level.
10/30/2009 OO:f~ ~ 10J3112tli~~'OO.i~t1 ~'~ `~ ~ ~ ~~.,, ~ . ~ ~ ~ ~.
Operations Summary
Operatios shut down due to wind. Push fluid away with 2400 psi gas lift.
1 ~17~009~O.f10-~1111/2009~Q0:00 ~~ ~ ~ ~,~._r~'.. "`~ ~, ~~
Operetions Summary ~ ~ ~ ~
RU siickline. Pressure test lubricator to 250psi low/3000psi high. RIH w/ GR, tagged fill at 5,550' RKB SLM. Set MACCO Plug at 5543' to 5540' and dump
41' of cement. Top of Cement 5499'(+/-). RD Slickline. WOC.
,. ,
1111l2a09 00:00 -1'4~ EC08 00.00 ~ ~ ~ ~ ~ ~ ~ ~ ; : : ,. ; ~ ~ ~ "~, :;~ ~~, • ~ ~ ~ ~ ~ ~ `" .n '~ ~ ,r~
Operations Summary
WOC.
r, .., ~ ~~ ~~
~~iar~ooa oo:ot~`~ ~fit~7`~~os n~:d~~ ~> ~ ~~ ~ ~ ~ ~ ~ ~ t.. ~ ~ ~
Operations Summary
Bleed down Annulus from 1850 psi to 50 psi. Bleed down tubing from 2400 psi to 300 psi. Set up chart recorder and perform 12 hr test.
11t3l2009 OQ:00 -11/4I2009 OOt00
Operations Summary
Monitor well with Chart recorder. Production hooking up flow lines. Good Negative test.
11/6t2009 00:00 -11171~t109~00:00 ~ ~ ~ ~ ~ x_ tt~-~ k~~ ,~: ; ~~'~,_.~~ ~
Operetions Summary
Rig up Schlumberger and Pressure test to 250 psi low and 2900 psi high. RIH and tagged top of cement at 5,479' RKB ELM. Attempt to perf 50-6 zone
but had misfire. Pulled out of well and trouble shoot Schlumberger equipment.
t , Sr a. v . w >~a ~~~ ~ `~z ~ . ~ ~~
49I7/2009 00:00?-~~ ! ~ ~ ~IO~~f11"#S~~f#~~ f, ~' ~ ~ t, _ ,
..~ ~_ ~
Operations Summary
Complete trouble shoot on Schlumberger unit. Perorate 50-6 sand 5,000'-5,008'. Monitor tubing pressures. RD Eline. Turned well over to production.
~ • Swanson River
Well SRU 32A-15
As Completed 1/2 O5
C' a c i n o R T u h i n a
RKB =15.0'
Size T e Wt Grade Thrd ID To Btm Hole Cmt Cmt To
22" Conductor Surf 4S Yes Surf.
3~ Surf Csg 54.5 K-55 12.615 Surf 964' 1000
g„ Surf
DV Collar 964' 967' ~g"
8„ sx
3
g„ Surf Csg 54.5 K-55 12.615 96T 2958' 5/ 600 sx
~ Calculat
7" 29 6.184 Surf 39'
7" 26 P-~~~ 6.276 39' 2097'
1000
7" 29 6.184 2097' 3439'
SX
'
7" Prod Csg 26 N-80 6276 3439' 6158' Thru 6495
CBL
7" 29 8rd 6.184 6158' 7933' ~~
5/8" DV @
7" 26 P-I10 6276 7933' 846T 8467'
DV Coli ar 8467' 8470'
7" 26 6.276 8470' 9789' 1000 9399'
~„ Prod Csg 29 P-~ ~~ 6.184 9789' 10 25T sxs Calculated
S' Liner 18 L-80 Buttress 4.276 9971' 11,590 G" 500 11,250'
sss c~3i.
Tubin 15.0' Original RKB to Tbg Hngr
2-7/8" 6.4 N-80 Buttress 2A41 Surf 5727'
2 7/8° 6.4 N-SO BWtress 2.441 6000' 976G
2 3/8" 4.6 N-80 Buttress 1.995 9,766' 11,25G
.IR.W F.I.RY nF.TA II,
NO. De th ID OD Item
16.44' Tubing Hanger, FMC Type TCM 7 1/16" OD x 2 7/8" EUE
lift and sus ension W/ Cont Cont Line
A. 2491' 2363 Chem In' Sub '
B, 5,540' Slickline A slip stop, Macco Plug, & AD-2 slip stop w/ -6~i
cement TOC (a~ 5 J79' ELM ~
C, 5692' BOT 3-1/2" Landin Collar w/?CO's to ~7/8" box & Pin
D. 5727' BOT 3-1/2" Float Shoe w/ ?CO to ~7/S" box
E, 5750' CIBP ~
F, 6000' Cut mbing
GLM #1. 6220' 2347 5.5" x 4.673" Camco MMG-P GLM
GLM #2. 6891' 2347 5.5" x 4.673" Camco MMG-P GLM
G, 7000' Tbg. plu~
I. 7345' E7, Drill CIBP
GLM k3. 759T 2347 5.5" x 4.673° Camco MMG-P GLM
GLM #4. 8303' 2347 5.5" x 4.673" Camco MMG-P GLM
GLM N5. 9039' 2.347 5.5" x 4.673° Camco MMG-P GLM
2. 9300' Cmt Retainer TOC in tb
3. 971T Cmt Retainer
GLM #6. 9726' 2347 5.5" x 4.673° Camco MMG-P GLM
4. 9766' 1.995" 3.503" Crossover, 2-7/S" EUE 8rd x 2-3/8" EUE 8rd
5. 10,448' 1.875" 3.065" Otis "XA" Sld Slve
GLM #7. 11,149' 1.875" 4.125" x
2.781„ Camco KBMG-2 GLM
6. 1 I 186' 2.55" Otis "BWD" Pkr
7. 1 I 226' 1.875" 2.701" Otis "X" Profile Ni le
S. 11,256' 2.32" 2.872" WLEG
P N~. K H-~1 H A l~ 1~1 IV H 1\ 1 1~ K Y
Interval Accum. _
To Bhn Amt s f Comments
3,493' 3,503' 10' 6 Sqz Perfs
4,986' 4,996' 10' 6 Sqz Perfs
5 014' S 024' 10' 6 S z Perfs
5,002' S,008' 8' 6 Il/7/2009
5,545' S,555' 10' 6 Sqz Perfs
5 555' S 567' 12' 18 Isolated 56-0 Belu a
5,554' S582' 28' 12.0 Isolated 56-0 Belu a
5,590' S,600' 10' 6 Sqz Perfs
7,267' 7,282' 15' 6.0 68-0 UpperLobe. P&A'd 1024/04
7,358' 7,398' 40' 6.0 68-0 Lwr Lobe. P&A'd 10/24~04
11326' 11336' . 10' P&A
11,340' 11,346' 6' P&A
11,354' 11,364' 10' P&A
SRU 32A-15 Current Schematic 11-17-09.doc REVISED: 11-17-09 by CVK
TD=11,590' PBTD=5,750'
Max Deviafion =24.3° ,na,7815'
~ • Page 1 of 1
Regg, James B (DOA) ~ ~~q- ~~}
From: Dalebout, Joseph [APRS] [Dalebout1@chevron.com]
Sent: Friday, November 06, 2009 5:46 AM
To: Regg, James B(DOA) ~~~~ ~~~ Q~
I~ ~
Subject: Swanson river 32A-15 Tag and perf
Attachments: Test Chart #2.pdf
/
Jim, This is the Pressure chart after Plug and cement (5499'- 5543') were put in place. As discussed with Chuck
and E-Mailed correspondence we will be Tagging top of plug at around 12:00 Friday and with a good tag we will
be proceeding on with our plans on perforating. I can be reached at the Swanson river drill contact #283-2536 or
my Cell if in the field 398-5234. ~
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; ~~ ~~ ~ ~ w a~~ ~~ ~~ ~c ~ ~~ ~~ ~
-~ ~ f ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~ ' ~~.~ ~ ~ F~ ~~~ SEAN PARNELL, GOVERNOR
(~ ~v ~~ z~ u ~ . ~ ~ ~ ~ a~ u C ~yij y .~~. y g~~ ~ ~ ~p~~
`C~ ~.... ..., i.s: ~s ~..~sm.-~.' 'aav.m ~~ 2-~ L-.._-~... L.~C.~ 'P.m.~G L~? ~ ~ Fa4 5~
{p~
$
ALA~7~A ~IL ~II' V~-7 ~g 333 W. 7th AVENUE, SUITE 100
COi~SEIiQATIOI~T COMl~'IISSIOI~T ~ ANCHORAGE, ALASKA 995013539
~ PHONE (907) 279-1433
€ FAX (907)276-7542
t'VIr. Timothy C. Brandenburg
Drilling Manager
Union 4il Company of California ~~,
t~~.
Re: Swanson River Field, Hemlock Oil, Be~uga Undefined Gas,
Swanson Riv Unit (SRL~ 32A-15
Sundry Number: 309-352
P.O. Box 196247
Anchorage, AK 99519
Dear Mr. Brandenburg: ~~°~6~~~~ i'1l~``1 ~`~ 20Dw1
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 Cornmission grants for good cause
shown, a person affected by it may file with the Cornmission 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 ne~ 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.
Sincerely,
Daniel T. Seamount, Jr.
Chair
1~
DATED this ?~day of October, 2009
Encl.
G~ ~ ~~ ~
~ STATE OF ALASKA ' - v~ ~
ALAS OIL AND GAS CONSERVATION COMMIS~
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
w~~4-
io~2~ ~zoo9
1. Type of Request: Abandon ^ Suspend ^ Operational shutdown ^ Perforate 0• Re-enter Suspended Well ^
Alter casing ^ Repair well ^ Plug Perforations ^Q ' Stimulate ^ Other ^ Specify:
Change approved program ^ Pull Tubing ^ Pertorate New Pool ^ Time Extension ^
2. Operator Name: 4. Current Weli Class: 5. Permit to Drill Number:
Union Oil Company of California Deveiopment Q, Exploratory ~ 194-Q84 -
3. Address: Stratigraphic ~ Service ~ 6. API Number:
PO Box 196247, Anchorage, AK 99519 50-133-10141-01 •
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 ~' Swanson Riv Unit (SRU) 32A-15 ~
9. Property Designation (Lease Number): 10. Field/Pool(s):
FEDA028384 [Swanson River Facility] Swanson River Field ! Hemlock Oil, Beluga Undef Gas '
~ 1• PRESENT WELL CONDITION SUMMARY
Total Depth MD (ft): Total Depth ND (ft): Effective Depth MD (ft): Effective Depth ND (ft): Plugs (measured): Junk (measured):
11,590 11,187 5,565 5,562 5,750' 5,565'
Casing Length Size MD ND Burst Collapse
Structurai
Conductor 45' 22" 45' 45'
Surface 2,958' 13-3/8" 2,958' 2,958' 2,730 psi 1,130 psi
Intermediate
Production 10,257' 7" 10,257' 9,938' 7,240 psi 5,410 psi
Liner 1,619' S" 11,590' 11,187' 10,140 psi 10,490 psi
Perforation Depth MD (ft): PerForation Depth ND (ft): Tubing Size: Tubing Grade: Tubing MD (ft):
5,554'-5,562' 5,551'-5,559' 2-7/8"x2-3/8" ~ 6.4# N-80 x 4.6# N-80 5,727'& 6,000'-9,766' x 9,766'-11,256' ~
Packers and SSSV Type: Packers and SSSV MD (ft) and ND (ft):
Otis BWD Packer/ N/A 11,186'MD (10,806'ND) / N/A
12. Attachments: Description Summary of Proposal ^ 13. Well Class after proposed work:
Detailed Operations Program ^ BOP Sketch ^ Exploratory ^ Development ^~ • Service ^
14. Estimated Date for 15. Well Status after proposed work:
0/26/2
Commencing Operations:
Oil ^ Gas ~ WDSPL ^ Plugged
^
16. Verbal Approval: Date: UVINJ ^ GINJ ^ WAG ^ Abandoned ^
Commission Representative: N/A GSTOR ^ SPLUG ^
17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Chris Kanyer 263-7831
Printed Name Timothy C. Brandenburg Title Drilling Manager
Signature
C~ ~ Phone 276-7600 Date 10/14/2009
~ _ , COMMISSION USE ONLY
Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 30 !~~~~
Plug Integrity [~ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^
Other:
Subsequent Form Required: `D - G~-O 4,
APPROVED BY
Approved b~ COMMISSIONER THE COMMISSION Date: ~ ~
" ~~ /
~~~~ ~ ~ ~~ ~
ORIGINAL
.~ ,~~;_~~~
Form 10-403 Revised 7/2009 Submit in Duplicate
Chevron • ~ Happy Valley
~ Well # SRU 32A-15
~ 10/13/09
OBJECTIVE:
• Plug back 56-0 sand and perforate 50-6 sand. ~ ~
PROCEDURE SUMMARY:
1 Conduct PJSM. RU Slickline and pressure test lubricator 250psi low/2,SOOpsi high.
2 RIH with GR and tag fill at 5,565' (+/-).
3 RIH with dummy bailer and tag fill at 5,565' (+/-).
4 RIH and set slickline plug at 5,540' (+/-). ~
5 RIH & tag plug with dump bailer at 5,540' (+/-). Begin Dump bailin 5'-40''.cement on top of plug.
6 RD slickline. WOC. ~~ ~
7 Bleed tubing pressure off to 300psi for 12 hour charted negative pressure test ~
8 Conduct PJSM. RU Eline and pressure test lubricator 250psi low/2,SOOpsi high.
9 RIH with GR/CCL and perf gun and ti~in and tag cement plug at 5,500' (+/-). Perforate the 50-6 sand. ~
10 Rig down Eline. Turn well over to production.
SRU 32A-15 REVISED BY: CVK 10-13-09
~'~ . ~ Swanson River
Well SRU 32A-15
~ ~ ~ ~ ~' ~ ~ ~ As Com~leted 1/24/05
$ RKB =15.0'
C a s i n g & T u b i n E
Size T e Wt Grade Thrd ID To Btm Hole Cmt Cmt To
22" Conductor Surf 4S' Yes Surf.
13 SurfCsg 54.5 K-55 12.615 Surf 964' 1000
3/8"
~g Surf
DV Collar 964' 96T -
" sx
13
Surf Csg
54.5
K-55
12.615
96T
2958' 5/8
600 sx 2144'
3/g" Calculated)
7" 29 6.184 Surf 39'
7" 26 P~~~~ 6276 39' 2097'
1000
7" 29 6.184 2097' 3439' sx
'
7" Prod Csg 26 N-80 6.276 3439' 6158' ~O Thru 6495
CBL
7" 29 8rd 6.184 6158' 7933'
5/8" Dv @
7" 26 P-I10 6276 7933' 846T 8467'
DV Collar 8467' 8470'
~ 26 6276 8470' 9789' 1000 9399'
~" Prod Cs
g 29 p_~~p 6.184 9789' 10,25T sxs Calculated
5"
Liner
18
L-80 Bu[Vess
4276
9971'
11,590
6" 500 11,250'
s~s Cl?L
Tubin 15.0' Original RKB to Tbg Hngr
2-7/8" 6.4 N-80 13utiress 2.a4I Surf 5727'
2 7/8" 6.4 N-80 [3uttress 2.441 6000' 9766'
2 3/8° 4.6 N-80 [3uttress 1.995 9,766' 11,256'
JEWELRY DETAIL
NO. De th ID OD Item
16.44' Tubing Hanger, FMC Type TCM 7 1/16" OD x 2 7/8" EUE
lift and sus ension, W/ Cont Cont Line
p, 2491' 2.363 Chem In' Sub
B, 5692' BOT 3-1/2" Landin Collar w/ XO's to ~7/8° box & Pin
C. 5727' BOT 3-1/2" Float Shoe w/ ~O to 2-7/S" box
D. 5750' CII3P '
E, 6000' Cut lubing
GLM kl. 6220' 2347 5.5" x 4.673" Camco MMG-P GLM
GLM N2. 6891' 2347 S.S' x 4.673" Camco MMG-P GLM
H, 7000' Tbg. plug
I. 73J5' E7, Drill CIBP
GLM #3. 7597' 2347 5.5" x 4.673" Camco MMG-P GLM
GLM #4. 8303' 2347 5.5" x 4.673" Camw MMG-P GLM
GLM #5. 9039' 2347 5.5" x 4.673" Camco MMG-P GLM
2. 9300' Cmt Retainer TOC in tb
3. 971T Cmt Retainer
GLM #6. 9726' 2347 5.5" x 4.673" Camco MMG-P GLM
4. 9766' I.995° 3.503° Crossover, 2-7/8" EUE Srd x 2-3/8" EUE 8rd
5. 10 448' I.875" 3.065° Otis "XA" Sld Slve
GLM #7. 11,149' 1.875" 4.125" x
2.781„ Camco KBMG-2 GLM
6. 11 186' 2.55" Otis "BWD" Pkr
7. I 1 226' 1.875" 2.701 ° Otis "X" Profile Ni le
8. 11,256' 2.32" 2.87Y' WLEG
PERFORATION HISTORY
Interval Accum
To Btm Amt s f Comments
3,493' 3,503' l0' 6 Sqz Perfs
4,986' 4,996' 10' 6 Sqz Perfs
5,014' S,024' 10' 6 Sqz Perfs
5,545' S,555' 10' 6 Sqz Peds
5,555' S,567' 12' 18 56-0 Beluga (re-perf/add) 4/11/2008
5,554' S582' 28' 12.0 56-0 Beluga (re-perf/add) 4/11/2008
5,590' S,600' 10' 6 Sqz Perfs
7,267' 7,282' 15' 6.0 68-0 Upper L.obe. PBcA'd 10/24/04
7,358' 7,398' 40' 6.0 68-0 Lwr Lobe. PBcA'd 10/24/04
11,326' 11,336' 10' P&A
11,340' 11,346' 6' I .G ~
11,354' 11,364' 10' P~ ~
SRU 32A-15 Fina14-14-08Schematic.doc REVISED: 4/14/08 by BCA
Maz Deviation =24.3° @ 781Y
~J
PROPOSED ~
~ Swanson River
Well SRU 32A-15
As Com~leted 1/24/OS
RKB =15.0'
C a s i n g & T u b i n g
Size T e Wt Grade Thrd ID To Btm Hole Cmt Cmt To
2Y' Conductor Surf 45' Yes Surf.
3~
„ Surf Csg 54.5 K-55 12.615 Surf 964' 1000
8 Surf
DV Collar 964' 967+ l8-
5/8„ sx
3
g„ SurfCsg 54.5 K-55 12.615 96T 2958' 600 sx ~
~ C Ic
ate~
7" 29 6.184 Surf 39'
7" 26 P~~~ 6276 39' 209T
1000
~ Z9 6.184 209T 3439' sx '
7" Prod Cs
g 26 N-80 6276 3439' 6158' Thru 6495
CBL
7" 29 8rd 6.184 6158' 7933' ~~
S/S" DV @
7" 26 P-110 6276 7933' 8467' 8467'
DV Collar 8467' 8470'
7"
P
d C 26
~~~ 6276 8470' 9789' 1000 9399'
~„ ro
sg 29 p 6.184 9789' 10,257' sxs Calculated
5° Liner IS L-80 Buttress 4276 9971' 11,590 ~,•~ 500 I1.250'
sxs CI31.
Tubin I5.0' Original RKB to Tbg Hngr
2-7/8" 6.4 N-80 Duttress 2.d41 Surf 5727'
2 7/8" 6.4 N-80 Buttress 2.441 6000' 976G'
2 3/8" 4.6 N-80 I3uttress 1.995 9,766' 11,256'
JEWELRY DETAIL
NO. De th ID OD Item
16,d9' Tubing Hangeq FMC Type TCM 7 1/16" OD x 2 7/S" EUE
lift and sus ension W/ Cont Cont Line
A. 2491' 2.363 Chem Inj Sub
B, 5,540' +/-) Slickline Plug ~
C. _ 92' BOT 3-1/2" Landin Collar w/ XO's to 2-7/8" box & Pin
D. 5727' BOT 3-1/2" Float Shoe w/ ~O to ~7/8" box
F, 5750' CIBP ~
p, 6000' Cuttubing
GLM #t. 6220' 2347 5.5" x 4.673" Camco MMG-P GLM
GLM #2. 689P 2.347 5.5" x 4.673" Camco MMG-P GLM
(',, 7000' Tbg. plug
I. 7345' EZ Drill CBP
GLM #3. 759T 2.347 5.5" x 4.673" Camco MMG-P GLM
GLM #4. 8303' 2347 5.5" x 4.673° Camco MMG-P GLM
GLM #5. 9039' 2347 S.S' x 4.673" Camw MMG-P GLM
2. 9300' Cmt Retainer TOC in tb
3. 971T Cmt Retainer
GLM #6. 9726' 2347 5.5" x 4.673° Camco MMG-P GLM
4. 9'166' 1.995" 3.503" Crossover, 2-7/8" EUE 8rd x 2-3/8" EUE Srd
5. 10,448' 1.87Y' 3.065" Otis "XA" Sld Slve
GLM #7. I 1,149' 1.875° 4.125" x
2J81" Ca~nw KBMG-2 GLM
6. I 1 186' 2.55" Otis "BWD" Pkr
7. 11,226' 1.875" 2.701" Otis "X" Rofile Ni le
8. 11256' 232" 2.872" WLEG
PERFORATION HISTORY
Interval Accum
To Btm Amt s f Comments
3,493' 3,503' ~0' 6 Sqz F~fs
4,986' 4,996' 10' 6 Sqz Ftrfs
5,014' S,024' 10' 6 Sqz Ptrfs
5,002'(+/-) 5,010'(+/-) 8' 6 PROPOSED -
5,545' S,555' 10' 6 Sqz Ekrfs
5,555' S,567' 12' 18 56~ Beluga (re~afladd) 4/11I2008 •
5,554' S582' 28' 12.0 56-0 Beluga (re~at7add) 4/11I2008
5,590' S,600' 10' 6 Sqz Ptrfs
7,267' 7,282' 15' 6.0 68-0 UpperLobe. P&A'd 1024/04
7,358' 7,398' 40' 6.0 68-0 LwrLobe. P&A'd 10/24/04
11,326' 11,336' 10' P&A
11,340' 11,346' 6' P&A
11354' 11364' 10' P&A
SRU_32A-15 Proposed Schematic 10-14-09.doc REVISED: 10-14-09 by CVK
TD=11,590' PBTD=5,750'
Max Deviation =24.3° (a~ 7815'
~~'lE'Vlrt'?Cl
, ,;
DATE ]une 9, 2008
~ncisco Castro Chevron North erica Exploration and Production
Technical Assistant 909 W. 9th Avenue
Anchorage, AK 99501
Tele: 907 263 7844
Fax: 907 263 7828
E-mail: fcbn@chevron.com
To: AOGCC
Mahnken, Christine R~~,~E® SUN ~. z 2~~~
333 W. 7th Ave. Ste# 1
Anchorage, AK 99501
~4~~- 0~ A,is
R~
WELL LOG TYPE SCALE LOG DATE INTERVAL
LOGGED RUN # B-LINE CD NOTES - L;,,S,
PDS, DLIS
COMPLETION
TB ST A-25RD RECORD 5" 4-Mar-08 6660-7092 1 1 1 PDS
COMPLETION
TB ST A-01 RD RECORD 5" 5-Mar-08 5697-6140 1 1 PDS
COMPLETION
TBU K-18RD RECORD 5" 21-Feb-08 10800-12400 1 1 PDS
COMPLETION
TBU K-26 RD RECORD 5" 24-Feb-08 10303-10323 1 1 PDS
PERFORATING
TBU G-22 RECORD 5" 3-Ma -08 10122-10229 PS-2 i i DLiS-PDS
PERFORATING
TBU M-17 RECORD 5" 16-Feb-08 7298-7381 PS-11 1 1 PDS
PERFORATING
TBU M-17 RECORD 5" 14-Feb-08 7296-7391 PS-9 1 1 PDS
POSISET PLUG
SETTING
TBU M-17 RECORD 5" 11-Feb-08 6889-7430 PS-8 1 1 PDS
PRESSURE
TEMPERATURE
TBU M-17 LOG 5" 15-Feb-08 5636-7398 PS-10 1 1 PDS
DEPTH
TBU M-17 DETERMINATION 5" 3-Feb-08 5782-7374.5 PS-7 1 1 PDS
PERFORATING
TBU M-17 RECORD 5" 19-Feb-08 5832-5856 PS-12 1 1 PDS
POSISET PLUG
SETTING
TBU M-01 RECORD 5" 7-Jan-08 4792-5151 PS-2 1 PDS
PERFORATING
TBU M-01 RECORD 5" 18-Jan-08 4532-4580 PS-3 1 PDS
HAPPY CEMENT BOND PDS, LAS,
VALLEY B-12 LOG - SCMT 5" 18-Mar-08 3559-10315 1 1 1 DLIS
COMPLETION PDS, DLIS,
LRU C-01 RD RECORD 5" 14-Ma -08 4679-4759 1 1 FMA
I
I 1
O 1 ( 1 I 1 I
SRU 32A-15 T RECORD
SHOO 5" 10-Mar-08 5554-5582 1 1 PDS
/ v <l~'`f
---_.
Please acknowledge receipt by signing and returning one copy of this transmittal. or FAX to 907 263 7828.
Received By~ ~ Date:
~hQ~/~'On ancisco Castro Chevron Morth . .rica Exploration and Production
Technical Assistant 909 W. 9th Avenue
'~ 7+ Anchorage, AK 99501
~~"'~~ Tele: 907 263 7844
Fax: 907 263 7828
E-mail: fcbn@chevron,com
DATE May 16, 2008
To: AOGCC
Mahnken, Christine R
333 W. 7t~ Ave. Ste#100 < ~,,~,~>i~i~~~,, ~11i~ ~~ ~~(~a
~ 41kf l.L~ L . y,.., +
Anchorage, AK 99501
ll S~-
,N~4(- ~ N
~ I ~a~3
~(~ -D~
~ /(a~-> >
"d f (oc7~ c7
NOTES_
WELL LOG TYPE SCAtE LOG DATE INTERVAL RUN # ` &LINE `' CD ~S'
LOGGEt) PDS,
OLtS
PLUG SETTING PDS,
RECORD 8.125" LAS,
GP 18742 BAKER PLUG SET PDF,
32RD GR/CCL 5" 29-Feb-OS 9604-9615 PS-3 1 1 DLIS
PDS,
LAS,
GP 18742 DIPOLE SONIC PDF,
32RD IMAGER TOOL - CNL 5" 27-Feb-08
--- 330-4221
--------- PS-2
- 1
------ 1 DLIS
PDS,
LAS,
GP 18742 CASING EVALUATION PDF.
32RD USIT - GR/CCL 5" 27-Feb-08 330-9940 PS-2 1 1 DLIS
PDS,
PERFORATION DLIS,
SRU 32A-15 SHOOT RECORD 5" 11-A r-08 5554-5582 1 1 1 LAS
PDS,
PERFORATING DLIS,
TBU G-32 RECORD 5" 22-A r-08 9423-9432 PS-2 1 1 LAS
PERFORATING PDS,
TBU G-32 RECORD 5" 2-Ma -OS 9620-9706 PS-3 1 1 DLIS
Please acknowledge receipt by signing and returning one copy of this transmittal or FAX. to 907 263 7828.
Received ey~ /I I __--- Date:
y/~ _ __
Page 1 of 1
•
Maunder, Thomas E (DOA)
•
From: Tyler, Steve L [tylersl@chevron.com]
Sent: Monday, May 12, 2008 11:22 AM
To: Maunder, Thomas E (DOA)
Cc: Walsh, Chantal [Petrotechnical]
Subject: RE: SRU 32A-15 (194-084)
Tom _
32A-15 was completed as a 2=.bi±monobore with TOC @ 22001 .The 56-0 sand was perforated on 1/24/05.
In 3/17/2005 we set a retrievable BP @ 40701 in the 2=~pi± tbg monobore, to isolate the reservoir. We conducted
bleed and pressure test and monitored the well for a couple of months and concluded that we were not
communicating the reservoir through a micron annulus.
We measure the leak rate at 0.03 liters/min.
In May of 2005 we ran a special sonic tool (from Norway) to chase down the leak. We utitized_gaslift pressure to
induce the leak. The results were inclusive and could only pin point it between 901 and 1201 from surface
(probably a tbg coupling).
From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov]
Sent: Wednesday, May 07, 2008 5:13 PM
To: Tyler, Steve L
Subject: SRU 32A-15 (194-084)
Steve,
t am reviewing the 404 submitted for this well.
What is the history of the pressure on the annulus?
It seems unusual (although not impossible) to have the
annulus pressure higher than the tubing.
Regards,
Tom Maunder, PE
AOGCC
5/12/2008
STATE OF ALASKA
ALA OiL AND GAS CONSERVATION COM ION
REPORT OF SUNDRY WELL OPERATIONS
tir
f~ECEfVED
MAY 0~' 200$
~.
1. Operations Abandon Repair Well Plug Perforations Stimulate ~ t1S. OmmfSSioirt
Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver ^ Time Extensi~C~p!'~g
Change Approved Program ^ Operat. Shutdown ^ Perforate Q Re-enter Suspended Well ^
2. Operator Union Oil Company of California 4. Current Well Class: 5. Permit to Drill Number:
Name: Development Q Exploratory^ 194-084
3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic^ Service^ 6. API Number:
50-133-10141-01 '
7. KB Elevation (ft): 9. Well Name and Number:
15' RKB to Tbg hng SRU 32A-15 '
8. Property Designation: 10. Field/Pool(s):
Swanson River Production Facility FEDA028384' Swanson River Field /Beluga '
11. Present Well Condition Summary:
Total Depth measured 11,590' ~ feet Plugs (measured) 5,750' (w/cmt on top)
true vertical 11,187' ~ feet Junk (measured) 5,677' WLKB
Effective Depth measured 5,612' feet
true vertical 5,609' feet
Casing Length Size MD TVD Burst Collapse
Structural
Conductor 45' 22" 45' 45'
Surface 2958' 13-318" 2,958' 2,958' 2,730 psi 1,130 psi
Intermediate
Production 10,257' 7" 10,257' 9,938' 7,240 psi 5,410 psi
Liner 1,619' S" 11,590' 11,187' 10,140 psi 10,490 psi
Perforation depth: Measured depth: 5,554' to 5,562'
True Vertical depth: 5,551' to 5,559'
Tubing: (size, grade, and measured depth) 2-7/8" / 2-3/8" N-80 / N-80 surf - 5,727', 6000'-9766' / 9766' - 11,256'
Packers and SSSV (type and measured depth) Otis BWD Packer 11,186'
12. Stimulation or cement squeeze summary: N/A
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:
13. Will return the well to production Representative Daily Average Production or Injection Data
when there is a call for gas. Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure
Prior to well operation: 0 0 0 0 0
Subsequent to operation: 0 120 0 1995 psi 1789 psi
14. Attachments: 15. Well Class after proposed work:
Copies of Logs and Surveys Run Exploratory^ Development^ Service ^
Daily Report of Well Operations X 16. Well Status after proposed 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:
N/A
Contact Steve Tyler - 263-7649
Printed Name Timothy C. Brandenburg Title Drilling Manager
~
Signature ~ ;,~
•,
Date 5/1/2008
hone 907-276-7 00
f
~
Form 10-404 Revised 04/2004 ~Q ~ r I n' ~ ~~4~~~~~~ ~~~ \^ Submit Original Only
Chevron ~
Chevron -Alaska
Daily Operations Summary
Well Name
SRU 32A-15 Field Name
SWANSON API/UWI
501331014101 Lease/Serial
FEDA028384 Orig KB Elev (ftK8)
329.0 Water Depth (ft)
Primary Job Type
Perforating Primary Wellbore Affected
Main Hole
Jobs
AFE No. OC Eng
UWDAK R8019 EXP
Daily Operations
3/5/2008 00:00 - 3/6/2008 00:00
Operations Summary
RU slickline, determine fluid level, prep for perforation, RD slickline.
3/10/2008 00:00 - 3/11/2008 00:00
Operations Summary
Perforate from 5554' to 5582' with 2", 6 spf 60 deg phase.
4/6/2008 00:00 - 4/7/2008 00:00
Operations Summary
Ran 2.3" GR to 5612' RKB and 2-1/4"x5' dummy gun to 5612' RKB.
4/10/2008 00:00 -4/11/2008 00:00
Operations Summary
Mobilize Schlumberger from Happy Valley and rig up on SRU 32A-15
4/11/2008 00:00 - 4/12/2008 00:00
Operations Summary
Re erf B 56-0 sand w/ 2 1/8" s irol EJ uns from 5554' to 5572'.
-~. . • Swanson River
Well SRU 32A-15
UNOCAL 76 As Completed 1/24/05
$ RKB =15.0'
Size T e Wt Grade vThrd ID _ To Btm Hole Cmt Cmt To
Conductor Surf 45' Yes Surf.
Surf Csg 54.5 K-55 12.615 Surf 964'
18- 1000
sx Surf
J C
ll a 964' 96T 5/8"
o
~„ r
Surf Csg
54.5
K-55
12.615
967'
2958'
600 sx 2144'
Calculated)
29 6.184 Surf 39'
26 P-110
6.276
39'
2097'
1000
29 6.184 2097' 3439' sx 6495'
Prod Csg 26 N-80 6.276 3439' 6]58' 10 Thru CBL
29 8rd 6.184 6158' 7933' S/8" Dv @
26 P-110 6.276 7933' 8467' 8467
V C
ll 8467 8470'
o ar 26 6.276 8470' 9789' 1000 9399'
Prod Csg 29 P-I 10 6.184 9789' 10,257' sxs Calculated
Liner
18
L-80 Buttress
4.276
9971'
11,590
~,. 500
~~~ 11,250'
c131_
ubin 15.0' Original RKB to Tbg Hngr
7/g^ 6.4 N-80 Buttress 2.441 Surf 572?'
7/g" 6.4 N-80 Bumess 2.441 6000' 9766
3/8" 4.6 N-80 Buttress 1.995 9,766' 11,256'
n aai rr ^ n v D C T A i r
NO. De th ID OD V Item
16 44' Tubing Hanger, FMC Type TCM 7 1/16" OD x 2 7/8" EUE
lift and sus ension W/ Cont Cont Line
A, 2491' 2.363 Chem Inj Sub
B, 5692' BOT 3-1/2" Landin Collar w/ XO's to 2-718" box & Pin
C. 8727' BOT 3-1/2" Flaat Shae w/ XO to 2-7/8" box
p, 5750' CIBP
E, 6000' Cut tubing
GLM #1. 6220' 2.347 5.5" x 4.673" Camco MMG-P GLM
GLM #2. 6891' 2.347 5.5" x 4.673" Camco MMG-P GLM
F. 7000' Tbg. plug
I. 7345' EZ Drill CIBP
GLM #3. 7597' 2.347 5.5" x 4.673" Camco MMG-P GLM
GLM #4. 8303' 2.347 5.5" x 4.673" Camco MMG-P GLM
GL'Vt #5. 9039' 2.347 5.5" x 4.673" Camco MMG-P GLM
2 9300' Cmt Retainer TOC in tb
3. 9717 Cmt Retainer
GLM #6. 9726' 2.347 5.5" x 4.673" Camco MMG-P GLM
4. 9766' 1.995" 3.503" Crossover, 2-7/8" EUE 8rd x 2-3/8" EUE 8rd
5. 10,448' 1.875" 3.065" Otis "XA" Sld Slve
GLM #7. 11,149' 1.875" 4.125" x
2.781" Camco KBMG-2 GLM
6. 11,186' 2.55" Otis "BWD" Pkr
7. 11,226' 1.875" 2.701" Otis "X" Profile Ni le
8. 11,2>6' 2.32" 2.872" WLEG
n r. n c /~ D A T i /l N II i C T n R V
Interval Accum
To Btm Amt s f Comments
3,493' 3,503' 10' 6 Sqz Perfs
4,986' 4,996' 10' 6 Sqz Perfs
5,014' 5,024' 10' 6 Sqz Perfs
5,545' 5,555' 10' 6 Sqz Perfs
/ 5,555' S,56T 12' 18 56-0 Beluga (re-perf/add) 4/11/2008
/ 5,554' 5582' 28' 12.0 56-0 Beluga (re-perf/add) 4!11/2008
5,590' 5,600' 10' 6 Sqz Perfs
7,267' 7,282' 15' 6.0 68-0 Upper Lobe. P&A'd 10/24/04
7,358' 7,398' 40' 6.0 68-0 Lwr Lobe. P&A'd 10/24/04
11,326' 11,336' 10' P&.a
11,340' 11,346' 6' N ~:1
11,354' 11,364' 10' 1'S:1
SRU 32A-IS Fina14-14-08Schematic.doc REVISED: 4/14/08 by BCA
TD= 11,590' PBTD= 5,750'
Max Deviation = 24.3° (a7 7815'
•
., S. gig... `~i ~ :`' _"1
~~..
- -_ -
Well Name
SRU 32A-15
Primary Job Type
Well Preparation
Jobs
Well Preparation Well 8ervlce
,a'-E IVo. ~ .e~,~.
Daily Operations
~isreooa
uperauora., Lw nu;dry
RU slickline, determine fluid level, prep for perforation, RD slickline.
SWANSON
•
Chevron -Alaska
Weekly Operations Report
API/UWI ~ ~ Lease/Serial
__ 501331014101 FEDA028384
Primary Wellbore Affected
Main Hole
~' q~ oa~-
329.0
eh.... ..,.. Erd~al~ ._ 8~~,
/5/LUU8
I
----
KI::l;t:IVt:U
.4'1 ,.
a STATE OF ALASKA a
ALA_ OIL AND GAS CONSERVATION COM~ION JUN 2 9 2006
REPORT OF SUNDRY WELL OPERATIONS Alaska Oil & Gas Cons. Convnission
1. Operations Abandon Repair Well
Performed: Alter Casing D Pull Tubing D
Change Approved Program D Ope rat. Shutdown D
2. Operator Union Oil Company of California
Name:
3. Address:
PO Box 196247, Anchorage, AK 99519
Plug Perforations
Perforate New Pool D
Perforate D
4. Current Well Class:
Development 0 .
Stratigraphic D
Stimulate Other .¡ - first
WaiverD Time ExtensionD job in field
Re-enter Suspended Well D In Coil WO Campagne
5. Permit to Drill Number:
Exploratory D 194-084
Service D 6. API Number:
50-133-10141-01
9. Well Name and Number:
7. KB Elevation (ft):
15' RKB to Tbg hng
8. Property Designation:
Swanson River Production Facility ~el>A* 1/Þ'5~c./ ~".þ~.L9~
11. Present Well Condition Summary:
SRU 32A-15 .
10. Field/Pool(s):
Swanson River Field 1 Beluga
Total Depth measured 11,590' feet
true vertical 11,187' feet
Effective Depth measured 5,677 feet
true vertical 5,673' feet
Casing Length Size MD
Structural
Conductor 45' 22" 45'
Surface 964' 13-3/8" 2,958'
I ntermed ¡ate
Production 10,257' 7" 10,257'
Liner 1,619' 5" 11,590'
Plugs (measured) 5,750' (w/cmt on top)
Junk (measured) 5,677' WLKB
.'(
TVD
Burst
Collapse
45'
2,958'
2,730 psi
1,130 psi
9,938'
11 ,187'
7,240 psi
10,140 psi
5,410 psi
10,490 psi
Perforation depth:
Measured depth: 5,555' tp 5,567'
SCANt.JED
PUI! n
\;,..' (- ,.
True Vertical depth: 5,552' to 5,564'
Tubing: (size, grade, and measured depth)
2-7/8" 1 2-3/8"
N-80 1 N-80
surf - 5,727',6000'-9766' 1 9766' - 11,256'
Packers and SSSV (type and measured depth)
Otis BWD Packer
11 ,186'
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
N/A
Treatment descriptions including volumes used and final pressure:
13. Will return the well to production /
when there is a call for gas.
Prior to well operation:
Subsequent to operation:
14. Attachments:
Copies of Logs and Surveys Run
Daily Report of Well Operations
Oil-Bbl
o
Representative Daily Average Production or Injection Data
Gas-Mcf Water-Bbl Casing Pressure
o 0 0
Tubing Pressure
o
15. Well Class after proposed work:
ExploratoryD Development 0
16. Well Status after proposed work:
OilD Gas 0 WAG D
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Service D
x
GINJ D WINJ D WDSPL D
Sundry Number or N/A if C.O. Exempt:
306-184
Contact Chantal Walsh (263-7627)
Signature
Title Drilling Manager
AFE 164036
IA"\
Date ¿. -e:7 ~
Phone 907-276-7600
IGIÎ\JJ\L
Submit origpa. I Only
l:: - JO~-Ok::
SRU 32A-15
Primary Job Type
Tubing Repair
Jobs
Primary Job Type
Tubing Repair
Daily Operations
8/25/2005 00:00 - 8/26/2005 00:00
Operations Summary
Prepare well for WLD (wireline leak detect) tool. Attempt to establish leak by pressuring up the tbg pressure to 2300 psi using gas lift gas. Pressure on the csg
195psi. Bled tbg back to 195 psi and ran a base line log for leak detect tool. Bled csg to 0 psi and watched well. No response.
8/27/200500:00 - 8/28/200500:00
Operations Summary
Attempt to establish leak in tbg. MU leak detect tools. Waiting for pressure differential to show. Monitoring the pressure on tbg and csg.
8/28/2005 00:00 - 8/29/2005 00:00
Operations Summary
Pressure tbg to 215 psi and start in hole with leak detect tool. Log to 3000' at 30 fpm. Bled csg to zero and pressured tbg to 2200psi. Had indication of leak at
118' at collar. Made multiple start and stop passes with tool thru suspected leak area. Tried different pressures with csg and tbg. Not a clear indication of leak
location. Pumped fluid on csg x tbg annulus. Ran tool. No clear indication of leak. RD and secured well.
5/21/2006 00:00 - 5/22/2006 00:00
Operations Summary
Pull WRP plug and tag fill with 2.31" GR, at 5075 WLKB. Appears that fluid level is around 4300'.
5/22/2006 00:00 - 5/23/2006 00:00
Operations Summary
Prep for coil tubing
5/23/2006 00:00 - 5/24/2006 00:00
Operations Summary
Move in spot and RU coil test BOP
5/24/2006 00:00 - 5/25/2006 00:00
Operations Summary
SIMOPS with production. PJSM. Complete CT Acceptance at 9:00. RIH with wash nozzle. Tag top of bridge at 5068' and fell to 5487'. Pumped and
circulated working down to 5602'. Jet tbg dry with N2, trapping 2200 psi. POOH with coil. Released Coil Tubing.Spot slickline, and RIH with 2" DD Bailer and
tagged at 5677' WLKB. Talked to town and concluded clear of perfs.
5/25/2006 00:00 - 5/26/2006 00:00
Operations Summary
Demobe
5/26/200600:00 - 5/27/200600:00
Operations Summary
Demode
B RKB =15.0' Wt Grade
54.5 K-55 1000
18- sx
5/8"
54.5 K-55 600 sx
29 P-110
26 1000
Prod Csg 29 6495'
26 N-80 10- CBL
29 8rd 5/8"
26 P-110
26 P-110 6.276 9399'
29 6.184 Calculated
Liner 18 L-80 Buttress 4.276
TD= 11,590' PBTD= 5,750'
Max Deviation = 11.3° @ 5351'
SRU 32A-15 FINAL 01-15-05
NO.
2.347 55" x 4.673"
2.347 5.5" x 4.673"
2.347 5.5" x 4.673"
2.347 5.5" x 4.673"
2.347 5.5" x 4.673"
GLM #6.
4.
5.
GLM #7.
6.
7.
8.
9726'
9766'
10,448'
11,149'
11,186'
] 1,226'
11,256'
2.347
1.995"
1.875"
1.875"
2.55"
1.875"
2.32"
5.5" x 4.673"
3503"
3.065"
4.125" x 2.781"
Cameo MMG-P GLM
Crossover, 2-7/8" EUE 8rdx 2-3/8" EUE 8rd
Otis "XA" S]d S]ve
Cameo KBMG-2 GLM
Otis "BWD" Ph
Otis "X" Profile Ni pIe
WLEG
2701"
2.872"
4,986'
5,014'
5,545'
_5,555'
5,590'
7,267'
7,358'
11 ,326'
11 ,340'
11,354'
Comments
Sqz Perfs
Sqz Perfs
! Sqz Perfs
Sqz Perfs
156-0 Belu~a _
6 Sqz Perfs
6.0 168-0 Upper Lobe. P&A'd 10/24/04
6.0 68-0 Lwr Lobe. P&A'd 10/24/04
P&A
P&A
5,024'
5,555'
5,567'
5,600'
7,282'
7,398'
11,336'
11 ,346'
11 ,364'
REVISED: 01/24105 by SL T
c.
,¡ :;=èj
.
,
''7 <-/ - 0 ~<(
'¡~-,
:i ~=;
~
i
J
J
FRANK H. MURKOWSKI, GOVERNOR
j
AItASHA OIL A1Q) GAS
CONSERVATION COMMISSION i
I
J
J
,/
,
333 W. 7'" AVENUE, SUITE 100
ANCHORAGE, ALASKA 99501-3539
PHONE (907) 279-1433
FAX (907) 276-7542
Timothy Brandenburg
Drilling Manager
Union Oil Company of California
PO Box 196247
Anchorage, AK 99519
Re: Swanson River Field, Beluga Undefined Gas Pool, SRU 32A-15
Sundry Number: 306-184
Sv;¡~ì!NE.Ü {) L
Dear Mr. Brandenburg:
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.
Sincerely,
CÆ¡/~~
Cathy P. Foerster
Commissioner
d
DATED this 1J day of May, 2006
Encl.
~q-q"'ötf(
~. ~ l\ 1'~ vI;
".1. (,'
.. 1\!\\ .
J ~ \./
IIJ~ tj/;:rfr;f)f>¿t
. ·u
1. Type of Request: Abandon U U Operational shutdown U Perforate U Waiver U Dtffer l:J
Alter casing D Repair well D Plug Perforations D Stimulate D Time Extension D CTCO
Change approved program D Pull Tubing D Perforate New Pool D Re-enter Suspended Well D
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
0 . D 194-084 /
Union Oil Company of California Development / Exploratory
3. Address: Stratigraphic D Service D 6. API Number:
PO Box 196247, Anchorage, AK 99519 50-133-10141-01 Æ"/
7. KB Elevation (ft): 9. Well Name and Number:
15' SRU 32A-15 /
8. Property Designation: /"J 1~~·~'" 10. Field/Pools(s):
Swanson River Production Facility A -ó453Bi Swanson River Field/Tyonek, Beluga
11. PRESENT WELL CONDITION SUMMARY
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured):
11,590' , 11,187' 11,560' 11,158' 11,560
,
Casing Length Size MD I TVD Burst Collapse
Structural
Conductor 45' 22" 45' 45'
Surface 964' 13-3/8" 2,958' 2,958' 2,730 psi 1,130 psi
Intermediate
Production 10,257' 7" 10,257 9,938' 7,240 psi 5,410 psi
Liner 1,L619 5" 11 ,590' 11,187' 10,140 psi 10,490 psi
Perforation Depth M~)~ 1J5erforation Depth TVD (ft): f' Tubing Size: Tubing Grade: Tubing MD (ft~0'Ø D
II"'"
5,555 to~ 6:!lf7 5,552 t~ð5b¿¡:~ 1,2-7/8"; 2-3/8" N-80 9,766'; 11,256' ðA/ ¡;; Î
Packers and SSSV Type: Otis BWD packer - , Packers and SSSV MD (ft): 11 ,186' /
12. Attachments: Description Summary of Proposal lj 13. Well Class after proposed work:
Detailed Operations Program D BOP Sketch D Exploratory D Development 0" Service D
14. Estimated Date for 15. Well Status after proposed work: /
,
Commencing Operations: 5/23/2006 Oil D Gas 0 . Plugged D Abandoned D
16. Verbal Approval: Date: WAG D GINJ D WINJ D WDSPL D
Commission Representative:
17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Steve Tyler 263-7649
Printed Name Timothy C. Brandenburg Title Drilling Manager
Signature 7· -¿;.;r J"" ^ c ~e 907-276-7600 Date S.. 'ZOZ-Q.. 5/22/2006
2T /7 COMMISSION USE ONLY
Conditions of approval: Notify Commission so that a representative may witness Sundry Number: <3/)(0-/ S1
Plug Integrity D BOP Test D Mechanical Integrity Test D Location Clearance D
Other:
RBDMs 8Ft MA Y ~ 4 2006
Subsequent Form Required: \0 - t\-o4.
Approved by: (1¡¿A/~~~- APPROVED BY
COMMISSIONER THE COMMISSION Date:Ç,.2Þ~
Form 10-403 ReLed 07/2005 r- ~ð. ç. z. z.óG
Submit in Du licate
. STATE OF ALASKA .
ALA Oil AND GAS CONSERVATION COMMI N
APPLICATION FOR SUNDRY APPROVALS
20 MC 25 280
4
OR\u\f~AL
p
.
.
Swanson River
Well SRU 32A-15
As Completed 1/24/05
SRU 32A-15 FINAL_OI-15-05
Size
22"
13-
318"
Casing &
Thrd ID
Hole
Cmt Cmt Top
Yes Surf.
1000 Surf
sx
2144'
600 sx Calculated
1000
sx 6495'
Thru ŒL
DV@
8467'
1000 9399'
sxs Calculated
500
Tubing
Top Btm
Surf 45'
Type
Conductor
Grade
Wt
Surf Csg
54.5 K-55 Surf 964'
18-
5/8"
K-55 967' 2958'
P-IIO 39'
2097'
3439'
N-80 6158'
7933' 10-
8467' 5/8"
'8470'
9789'
10257'
11,590
13-
7"
7"
7"
7"
7"
7"
7"
7"
5"
2-7/8"
27/8"
2 3/8"
JEWELRY DETAIL
NO. Denth ill OD Item
16.44' Tubing Hanger, FMC Type TCM 71/16" OD x 2 7/8" EVE
lift and su,nen,ion WI Cont Cont Line
A. 2491' 2.363 Chern In.i Sub
B 5692' BOT 3-112" Landing Collar w/XO', to 2-7/8" box & Pin
C. 5727' BOT 3-112" Float Shoe wi XO to 2-7/8" box
D. 5750' CIBP
R 6000' Cut tubing
r.LMli1. 6220' 2.347 5.5" x 4.673" CameoMMG-P GLM
GLMli2 6891 ' 2.347 5 5" x 4.673" Cameo MMG-P GLM
F. 7000' Thg. plug
1. 7345' EZ Drill CIBP
GLM #1. 7597' 2.347 , 5" x 4.673" Cameo MMG-P GLM
GLMli4 8303' 2,47 5.5" x 4.673" CameoMMG-P GLM
r.LM li5 9039' 2.347 5.5" x 4.673" CameoMMG-P GLM
2 9300' Crnt Retainer (TOC in tb2)
'. 9717' Cmt Retainer
r.LM Ii~. a77~' 2,47 , ," y 4 ~71" -PGLM
4 a7~~' 1. aa," , ,0," rm«over 7_7/R" EUE 8rd x 2-3Ls"EUE 8rd
'. 10 44R' I R"" , o~," 0';. "X A" SId2 Slve
r.T.M li7 11 14a' I R"" 4 1""y? 7Rl" r.mcoKBMG-2 GLM
~. 11 lR~' 2 "" Otis" BWD" Pkr
7. 11 ?7~' I R"" 7 70"" Obs "X" Profile NiDDle
8. 11256' 2.32" 2.872" WLEG
Islickline bailed fill from 4815 to 5172' on 3/14/051
PERFORATION HISTORY
Interval Aœum.
Ton Btm Amt sur Comments
,40,' "m' 10' 6 ~n7 Pert.
4986' 4996' 10' 6 Saz Perfs
,014' ,074' 10' 6 ~n7P""'"
5 545' 5 555' 10' 6 Saz Perfs
, "" , ,~7' 12'
5590' 5600' 10' 6 Saz Perfs
7267' 7.782' IS' 6.0 68-0 UDner Lobe. P&A'd 10/24/04
71<R' 7,aR' 40' 60 - DO."~ '0".''0
I J.J26' 11.336' 10' P&A
11 340' 11346' 6' P&A
11 354' 11364' 10' P&A
REVISED: 01/24/05 by SLT
AFE# 164036
Procedure Summary
ttwanson River Field
Swanson River Unit
SRU 32A-15
CTCO
WORK DESCRIPTION:
Project Summary: SRU 32A-15 is the first in a series of wells, in Swanson River, to be worked on
with coil tubing. SRU 32A-15 is to be cleaned out with coil tubing to below the 56-0 sand. ....
· Equalize tbg pressure across WRP. RU slickline. RIH retrieve both WRP's. POOH. RD ,.
· RIH wI GR. Tag fill. POOH. RD
· MIRU CTU & flowback equipment. RIH clean-out to PBTD. POOH. RD equipment.
· Turn well over to production. ,/
SCD 32A-15 ELCT Procedure Summary
Page 1 of 1
5/16/2005
STATE OF ALASKA ~-^ "c.ldÍ
A~ Oil AND GAS CONSERVATION COM.;;
APPLICATION FOR SUNDRY APPROVALS
20 MC 25.280
LIDS
cfcrc
Jf 3oCo - 1?J4
1. Type of Request: Abandon U U Operational shutdown U Perforate U Waiver U Other lj
Alter casing D Repair well D Plug Perforations D Stimulate D Time Extension D CTCO
Change approved program D Pull Tubing D Perforate New Pool D Re-enter Suspended Well D
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Union Oil Company of California Development 0 Exploratory D 194-084
3. Address: Stratigraphic D Service D 6. API Number:
PO Box 196247, Anchorage, AK 99519 50-133-10141-01
7. KB Elevation (ft): 9. Well Name and Number:
15' SRU 32A-15
8. Property Designation: 10. Field/Pools(s):
Swanson River Production Facility Swanson River Field/Beluga
11. PRESENT WELL CONDITION SUMMARY
Total Depth MD (ft): ITotal Depth TVD (ft): I Effective Depth MD (ft): Effective Depth TVD (ft): rlUgS (measured): I:unk (measured):
11,590' 11 ,187' 5,692 5,687 5,750' (wI cmt on top) sand in tbg -5,075'
Casing Length Size MD TVD Burst Collapse
Structural
Conductor 45' 22" 45' 45'
Surface 964' 13-3/8" 2,958' 2,958' 2,730 psi 1 ,130 psi
Intermediate
Production 10,257' 7" 10,257 9,938' 7,240 psi 5,410 psi
Liner 1,619 5" 11,590' 11,187' 10,140 psi 10,490 psi
Perforation Depth MD (ft): l~erfOration Depth TVD (ft): VUbing Size: I~Ubing Grade: ITubing MD (ft):
5,555 to 5,567' 5,552 to 5,564' 2-718"; 2-3/8" N-80 5,727; 6,000-9,766'; 11,256'
Packers and SSSV Type: Otis BWD packer Packers and SSSV MD (ft): 11 ,186'
12. Attachments: Description Summary of Proposal ~ 13. Well Class after proposed work:
Detailed Operations Program D BOP Sketch D Exploratory D Development 0 Service D
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: 5/23/2006 Oil D Gas 0 Plugged 0 Abandoned D
16. Verbal Approval: Date: WAG D GINJ D WINJ D WDSPL D
Commission Representative:
17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Steve Tyler 263-7649
Printed Name Timothy C. Brandenburg..--, Title Drilling Manager
Signature "7 ~1.-/Á /) ~ Phone 907-276-7600 Date 5-26 c.:.:>~ 5/26/2006
c:::.../ /J COMMISSION USE ONLY
-- ISUndry Number:
Conditions of approval: Notify Commission so that a representative may witness
Plug Integrity D BOP Test D Mechanical Integrity Test D Location Clearance D
Other:
,Ü
.f.é
Subsequent Form Required:
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Form 10-403 Revised 07/2005
Submit in Duplicate
UNOCALe
twanson River Field
Swanson River Unit
SRU 32A-15
CTCO
AFE# 164036 Procedure Summary
WORK DESCRIPTION:
Project Summary: SRU 32A-15 is the first in a series of wells, in Swanson River, to be worked on
with coil tubing. SRU 32A-15 is to be cleaned out with coil tubing to below the 56-0 sand.
· Equalize tbg pressure across WRP. RU slickline. RIH retrieve both WRP's. POOH. RD
. RIH wI GR. Tag fill. POOH. RD
· MIRU CTU & flowback equipment. RIH clean-out to PBTD. POOH. RD equipment.
. Turn well over to production.
SCD 32A-15 EL&CT Procedure Summary
Page 1 of 1
5/16/2005
...
RKB =15.0' Hole Cmt Cmt To
45' Yes Sruf
964' 1000 Surf
18- sx
518" 2144'
600 sx Calculated
1000
sx 6495'
111m CBL
10- DV@;
518" 8467'
9399'
Calculated
u .
~~
~~
."
~~)
TD= 11,590' PBTD= 5,750'
Max Deviation = 11.30 @ 5351'
SRU 32A-15 FINAL_Ol-15-05
ameo MMG-P GLM
CrQssover 2-718" EVE 8rdx 2-318" EVE 8rd
Otis "XA" SId Slve
CamcoKBMG,2 GLM
Otis" BWD" Pkr
Otis "X" Profile Ni Ie
WLEG
To
3493'
4986'
50l4'
5,545'
5555'
5590'
7267
7358'
II 326'
II 340'
J 1,354'
4996'
5024'
5,555'
5567'
5600'
7282'
7398'
II 336'
1l,346'
11,364'
10'
6'
10'
REVISED: 01/24/05 by
STATE OF ALASKA .
ALAS~IL AND GAS CONSERVATION COMMI N
WELL COMPLETION OR RECOMPLETION REPORT AND LiOO i3
1a. Well Status: Oil 0 GasE] Plugged 0 Abandoned 0 Suspended 0 WAG 0 1b. well_
20AAC 25.105 20AAC 25.110 Develop . Oil Êj¡pið~~;' ~'"
GINJO WINJO WDSPL 0 Revision #2 Other Recomplete Service 0 Stratlgra'þWêTést0
2. Operator Name: 5. Date Comp., Susp., or N'C 12. Permit to Drill Number:
Union Oil Company of California AbandJ'~ij~ 94-84
3. Address: 6. Date Spudded: 13. API Number:
PO Box 196247, Anchorage, AK 99519 n/a 50-133-10141-01
4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number:
Surface: 2300 FNL, 1040 FWL, Sec. 15 T8N R9W nla SRU 32A-15
Top of Productive Horizon: 8. KB Elevation (ft): 15. Field/Pool(s):
15' Swanson River Fieldl
Total Depth: 2286 FNL, 3161 FWL, Sec. 15 T8N R9W 9. Plug Back Depth(MD+TVD): Tyonek, Beluga
7,336'/7,250' Hemlock
4b. Location of Well (State Base Plane Coordinates): 10. Total Depth (MD + TVD): 16. Property Designation:
Surface: X = 348,884, Y = 2,480,047 5,750/5,744' Swanson River
TPI: 11. Depth Where SSSV Set: 17. Land Use Permit:
Total Depth: X = 351,036, y = 2,480,023 nla A-028384
18. Directional Survey: Yes 0 No E] 19. Water Depth, if Offshore: 20. Thickness of Permafrost:
nla feet MSL nla
21. Logs Run: nla
22. CASING, LINER AND CEMENTING RECORD
WT. PER SETTING DEPTH MD SETTING DEPTH TVD I AMOUNT
CASING GRADE HOLE SIZE CEMENTING RECORD
FT. TOP BOTTOM TOP BOTTOM PULLED
22" 0 45' 0 45' see schematic attached
13-3/8" 54.5 K-55 0 2,958' 0 45' 18-5/8"
7" 26,29 P-110/N-80 0 10,257' 0 9938' 10-5/8"
5" 18 L-80 9,971' 11,590' 9672' 11187' 6"
I
I
23. Perforations open to Production (MD + TVD of Top and Bottom 24. TUBING RECORD
Interval, Size and Number; if none, state "none"): SIZE DEPTH SET (MD) PACKER SET (MD)
Top Bottom Amt SPF Zone Comments 2-7/8" surface-5,727' cement pkr.
5,555' 5,567' 12' 56-0 Beluga 2-7/8", 2-3/8" 6,000-9,766', 11,256' 11,186'
7,267' 7,282' 15' 6 68-0 Upper Lobe P&A 10/24/04 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC.
7,358' 7,398' 40' 6 68-0 Lower Lobe P&A 10/24/04
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
. .i,'A·i~¡¡::::"! see schematic
"v";:,
26. PRODUCTION TEST
Date First Production: Method of Operation (Flowing, gas lift, etc.):
January 30, 2005 Flowina
Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: I Gas-Oil Ratio:
1/25/2003 28 Test Period ....0 1,076 Produced water 8-12 (1/64) nla
Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity - API (corr):
Press. 1705 not available 24-Hour Rate ..... 0 923 unmeasured nla
27. CORE DATA
Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary).
Submit core chips; if none, state "none".
nla I~ RBDMS 8Ft MAY
] 5 ZOO6
L,,",!,; ;~' ,~
¡
î, ~,
1 \lCt1 ¡ ,r'''~''11 if
. .J':ff' . ....
! ~
···~_·"-'··~".._,..··",...._,f
Form 10-407 Revised 12/2003
o RIG' f\fATtUED ON REVERSE
r.;,
28. GEOLOGIC MARKERS
NAME MD TVD
GlaciaLBase_MJF 591 591
Tks_YELLOW 1,472 1,472
A9 2,561 2,561
B2B 3,029 3,028
Beluga 3,504 3,503
41-4ST 4,121 4,120
Mid_Beluga_MJF 4,591 4,590
50-6ST 5,008 5,007
L.L._ Tnk_MJF 5,514 5,511
D1CT 6,050 6,038
61-8ST 6,561 6,526
66-3STE 7,046 6,981
70-8CT 7,524 7,422
mtLmark 8,067 7,920
80-2ST 8,555 8,367
E10 9,247 9,007
Hemlock_MJF 11 ,272 10,887
TO 11,590 11 ,187
29. F ATION TESTS
Include and briefly summari t results. List intervals tested, and attach
detailed supporting data as necessary. If no tests were conducted, state
"None".
nla
30. List of Attachments:
summary of morning reports, schematic.
31. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Printed Name: Tim C. Brandenbura
Signature:
Contact: Steve Tyler 263-7649
Title: Acting Drilling Manager
INSTRUCTIONS
Phone: 907-276-7600
Date: Resubmitted 4/6/06
Follow up to Sundry 304-388
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-Altemating-Gas Injection, Salt Water Disposal, Water Supply
for I 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 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other
spaces on this form and in any attachments.
Item 20: True vertical thickness.
Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
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 reported 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: If no cores taken, indicate "none".
Item 29: List all test information. If none, state "None".
Form 10-407 Revised 12/2003
UNOCALe
e
e
Swanson River
'Veil SRU 32A-15
As Completed 1/24/05
B
RKB =15.0'
Wt
Hole Cmt Cmt To
Yes Surf.
1000 Surf
18- sx
5/8"
600~" 2144'
(C.kulated
!
~
.~
.g,
~
J
'I'D:: 1t.59{ , PBT ):: 5.750'
. Max De.lation = 24.3" iª' 7815'
SRU 32A-15 FTNAL~OJ-]5-05
Size
22"
13-
3i8"
))V Collar
13-
JiB"
7"
Cas i
Grade Thrd
T e
Conductor
Surf Cgg
54.5
K-55
12.615 967' 2958'
6.184 Surf 39:___
6.276 39' 2097'
_2:.~:! 2097' 3439'
6.276 3439' 6158'
6.184 615S' 7933'
6,276 7933' 846"
8467' 8410'
6.276 847(¡' 9789'
6.184 9789' iO,257'
4.276 9971' /1,590
Su:fCsg
54.5 K·55
29 P-i 10
26
29
26 N-RO
29
26 1'-110
26 P-i 10
29
18 Ir80
711
1000
sx 6495'
Thru CBl.
r."V@
8467'
1000 9399'
sxs Calculated
500 11.250'
sxs CBL
Prod Csg
Tf
10-
5/8"
8rd
.,.
T'
DV Cullar
7"
Prod Cs g
7"
Buttress
6"
5"
Lmer
Tubin
2-7/8~
27/8"
2 3/8"
fi~·~~~;::~~·;~:t;~~·· );~~~:c· :.~ .>~~::~~«~~ ~
:::-f:=;:::~?~*r;?~~~: ".i,;:.·r~~;~~~t·K:/ ~c: ,'~i:;g
?,'::.~~~':~"-?-;:.~-:N·t.;,'':5·:' ~"~~v3?/ . ~~' ;).}, ~~?J
tf;i::~~·~"~:i~§).: '::;;t;': 7~~~:f;, .~:,,~v:;.x2~
5727'
9766'
1,256'
.J EWE LR Y
HETAIL
NO. Dent/J -.--.- OD lIem
IV
16.44' Tubing Hanger, liMC Type TCM 7 1116" 00 . 2 71f " f:UE
if! and sU1Incnsioll WI COllI Coni Une
A. 2491' 2.363 Che;;'l~ïSub
B, 56'2' BOT 3-1/2" Landin" <:nHar wi XO',ln 2-71f ~ box & Pill
C. 5727' BOT 3-112" FI...I S....e wi XO In 2·7/8" hn,
D. 5750' OOP
E. 61100' Cui lubbtg
GLM #1. 6220' 2.347 5.5" x 4.673" Cameo MMG-P Gl.M
GLM #2. 6891' 2.347 5.5" ~ 4.673" Cameo MMG-I' OLM
F. 7DOØ" Tbg. plug
-----_.~:_._--------- 7345' --- EZ OrUl ClBP
Gl.M #3. -----7597' ----- 2.347 5.5" ~ 4.67:1" Cameo MMG-p OL1-.1 ---..---~~._.
_.-.m:~!. #4, 8303' 2.347 5.5" x 4.673" Cameo MMO-P Gl.M
Gl.M #5. 9039' 2.347 5.5" ~ 4.673" Cameo ·JvlJvlCi·p OLM
2. 9300' Cm! Retainer IT<!Ç' In Ib !)
3, 9717' Cml Retainer
-- GLM #ó, 9726' 2.347 5.5" x 4.673" Cameo ~MG·P Gl.M
4. 9766' J.995" 3.503" Crossov5, 2-7f8"EUE Srd ~ 2·3iS" EUE 8rd
5. 10448' L875" -- 3.065" Otis "XA" Sldu Slve
GLM #7. ([,149' 1.875" 4.125" x Cameo KI3MG-2 012..1
2.781"
6. 11,186' 2.55" Otis "BWD" Pkr
. 1 L226' 1.875" 2.701" Otis "X" Profile Nipvle
I.
8. 11,256' 2.32" 2.872~' WLEG
PERFORATION HISTORY
. In~~~~_______.__L___ __:\:~~~~_...____...._________
Too i Btm 'Amt su! Comments
~3:~~¿~"'~'¡-"'-~~~:=== _:...:~: .C:::::t____ ~~;~;__..._______ .---.---
__....2!Q!:~'_m.Ln~.:~~~. 10' 6 Sqz Perf~m_________.________________......_.__
5,545' ¡ 5,555' 10' 6 Sqz Perf.,
5,555' T --5~~7;mn J 2' ------------ -56:0 Beluga
~_J 5,600' ¡O', 6 ----iŠ;;p~;¡:;--------n.- ____________.____._
7,267' ¡ 7)..82' 15'. ~:O ¡68:Q_~pE:~_~:.!~&A'd Oi~~__
__'!,?J~~__.J.-_.?!-~?.!..---- _____:~:.___L6.0 ¡68-0 L"T lDbe. P&A'd JOi24f04
~.'.?6' __'....J.!~....j~__! ¡P&A __
11,340' 11,346' 6' I lP&L...________...___m_______.m._____
11,354' 11.364' JO', !P&A
I ---.---¡--...---------
REVISED: 01i24/05 by SLT
10/29/04
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Spot equipment RU and test to 2500 PSI. RIH with 2.25" DD Bailer and tag fill at 7330' KB recovered 1 cup of
sand. RIH with 2.32" gauge ring and tag fill at 7330' KB, RIH w/2 1/2" SB&A stop set at 7000' KB POOH. RIH with
21/2" GS and Pack off plug set at 6999' KB POOH. RIH and make 6 dump bailer runs using a 9' x 2.25" bailer,
dump bail cementfrom 6995' to 6960' 10 gallons. RD Pollard
11/1/04
RU Schlumberger. PT top of cement plug to 3000 PSI held for 20 minutes, bleed off pressure, RU APRS unit
using Pollard mast truck, test lubricator to 3000 PSI. Have PJSM, RIH with 2.25 jet cutter and tagged top of
cement plug at 6974' Tagged witnessed by Jeff Jones with AOGCC. PU using CCL found center of joint at 6012',
pressured up to 500 PSI, fired cutter had good indication of firing, tubing fell to zero PSI instantly, POOH. Jug test
well bore to 3000 PSI for 30 minutes held good. With APRS RD, Schlumberger start pumping down the tubing
taking returns, CBU, (water clean for produced.) Freeze protect annulus and tubing. Pump 5 bbls down backside,
and .5 BBLS down tubing.
12/22/04
RU, Clean snow from Koomey, Tioga, choke hose and other. Prep area for SLB Cementìng foot print.
12/23/04
RU, PJSM, ND tree, and NU 7 1/16" 5M BOP, Choke line and Kill line. Function test same. Move drillers console,
Make up 27/8" test joint. Test Annular, 2 7/8" Rams, Blind rams. choke line valves, kill line valves, choke manifold
and all floor valves to 250/3000 psi. Test gas detectors. AOGCC waived witness to BOP Test. Set cat walk and
pipe racks. RU floor to pull tubing.
12/24/04
Back out lock downs and check annulus for pressure', Pull hanger free, took 95 kip to finish tubing cut. Pu!l hanger
to rig floor up wt 38 kip. Lay down hanger and pups; make up head pin and CBU. Had some bubbles, shut
annular and went through choke manifold and gas buster, pit level dropped enough for charge pump to loose
prime, shut down and blow down lines. Finished CBU. POOH, LD 2 7/8" tubing. Recovered 188 joints + cut off
joint + 5 puped GLMs + 3 Space out pups and tubing hanger. Wire line cut was made at 6012' (did not Strap out
of hole, went off of joint count, pipe came out. Change rams from 2 7/8" to 3 1/2". Test pipe rams and floor valves
. to 250/3000 psi. Blow down and freeze protect test pump, RU to handle BHA and 4 3/4" Drill collars. Pick up 6" bit
7" 29# casing scraper and 4 3/4" Drill collars
12/25/04
Change out handling equipment to handle 3 1/2" PH-6 and Clear off rig floor. RIH bit and scrapper on 3 1/2" PH-6
Tubing. Thaw and Drift pipe with 2,312' rabbit. Continue RIH with bit and scrapper to 5824, (182 total joint 3 1/2"
12,60 # PH-6) RU to change over well bore fluids from 8.4 PPG lease water to 11,7 PPG mud. PJSM. Displace
well bore with 11.7 ppg water base mud, taking lease water returns to Johnson tank, After displaced take returns
back to active system until we had a 60 bbl surface volume. Circulate at 2 bbl per min over shaker; pump
performed well out of big tank and vac trucks. Blow down all surface line and RU choke tine. POOH 53 Stands to
2513'. RU floor to make up storm packer.
12/26104
Run in storm packer and set same 12' below well head, shut pipe rams and test storm packer to 500 psi, back out
joint and close storm valve, Lay down same. Clear off floor, RD floor and prep to ND BOP (includes vac out and
cle~m cellar). Nipple down BOP, remove choke and kill lines. Stump up BOP until ready to NU. Checked voids on
old tubing spool for any trapped pressure. After inspection found 7" 29 PPF casing stub to be badly Kelly worn.
Checked annulus between surface casing and 7" production casing for any pressure found none, checked for any
LEL and found none. With constant LEL monitoring pulled casing hanger seal and replaced with new. NU new
remanufactured tubing spool, and tested void to 2500 PSI. held for 10 minutes, Nipple up BOPs. RU rig floor.
Make up two-way check set tubing hanger and shell test stack, choke line and kill !ine against blind rams at
SRU 32A-15 morning report summary AFE 163075. CONFIDENTIAL: last revised 3/8/2005, Page 1
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250/3000 psi (good test) RU rig tor!o lay down storm valve. PU joint of PH-6, ,I retrieving tool, screw into
storm valve, open Safety valve and check for pressure (none). Unseat storm packer up wt 30 kip. LD same. LD
rig tongs, POOH FROM 2513' - 1073'.
12/27/04
Continue POOH 3 112" PH-6 to drill collars. LD hydraulic tongs, RU manual tongs, slip bowl and 43/4" drill collar
slips. (lay down bit/scrapper) rack drill collars 2 stands. Blow down rig, Nipple down flow nipple and clean out stud
holes to accept studs for shooting flange, RU line from surface casing x 7" casing annulus to choke. PJSM. RU
Schlumberger, PJSM pull tools to floor and PU 7" HES EZ drHl CIBP, RIH to 5770' logged up found collar at 5752'
dropped down and logged back up set EZ drill at 5760', setting tool fired at 11:15 HRS POOH. RU WL BOP found
bad spot in E-Line and SWS rehead. Arm guns and stab up, test to 2000 PSI against EZ drill, held 10 minutes
bleed off pressure. RIH with 2- 10' guns 2" hsd, 6 shots perlft set for selective fire. Make tie in pass. Tie in to
Schlumberger ultrasonic imager log dated September 21-1994. Pressure up on 7" annulus to 1500 psi. Perforate
from 5590' - 5600'. Pressure dropped to 600 psi when gun fired. pull up hole 500'. Attempt to circulate, pump at 1
bbl per min pressure increased to 1740 psi and maintained a rate of 1 bbl per min and put away a total of 10 bbl,
shut down pump. Pressure after 10 sec was 1650 psi. Drop back down tie in and perforate from 5555' - 5545'.
With 1350 psi on 7" annulus, saw no change in pressure when guns fired. POOH with perf guns. Lay down guns
all shots fired. Close blind rams, Attempt to circulate (no go) results were the same pumped 8 bbls away at 1750
psi at 1 bbl per min, Shut down pump, pressure 10 sec after shut down was 1650 psi, and 1242 psi 30 min after
shut down. Bleed off pressure and blow down all lines. Make up setting tool arm same. Make up 7" Halliburton
Fast drill retainer. RIH, Tie into log and set retainer at 5535'. POOH with perf guns. LD guns all shots fired. LD
tools and RD Schlumberger, start nipple down shooting flange,
12128104
Continue RD Schlumberger wire line, ND shooting flange and nipple up flow nipple and install flow line. MU
Halliburton Fast drill cement stinger. RIH cement stinger on 3 1/2" 12,60 # PH-6 Tubing. (Thawing out pipe) Make
up single and tag at 5544' tubing measurements, current RKB. Retainer set at 5535 Wire line measurements.
Space out for cement job, ended up with tool joint in annular at the same time stinger stabs into retainer, RU
stand pipe hose and head pin. Break circulation stab in and perform injection test at 1 bbl per min 1740 PSI. with
rig pump. Pump 4 bbls, no returns noted in 7" annulus. Close annular and pressure up to 650 psi and perform
stab in test and adjust annular to 500 psi or less. PJSM. Break circulation with Schlumberger pump 3 bbls water
shut down and test line to 5000 psi. (good test) pump 2 bbls water for a tota~ of 5 bbl a head of cement. Batch up
cement to go down hole. Pump 21 bbls 15,8 ppg cement slurry holding 650 psi back pressure with rig choke
manifold, pump 5 bbl water + 12 bbls of 11.6 ppg water based mud. Shut down and stab in retainer (held 650 on
back side during squeeze no pressure change during squeeze) squeeze cement away with 23.4 bbls 11,6 ppg
water based mud at 3 bbl per mìn 2000 psi, slowed to a rate of 1 bbl per min 1540 psi, last 4 bbls away. Shut
down pump and unsting from retainer, pressure 10 see after pump shut down was 1504 psi. Reverse circulate 2
tubing volumes, got back unexpected cement took returns to junk tank, gauged tank. Recovered 12 bbls of
contaminated mud, cement, and water. Pump dry job and blow down rig. POOH and Lay down stinger. RU
shooting flange.
12129104
RU shooting flange, wìreline lubricator and grease head, pick up GR/CCL tool and two 10' ft 2",6 shot I ft HDS
perf guns, set for selective fire. Pressure test wireline lubricator and BOPs to 2000 psi, hold pressure for 10
minutes, (good test). Blow down and drain lines, RIHwith wireline. Make tie in pass, tie into Schlumberger
ultrasonic imager log dated Sept 21 1994, made 2 passes to correlate bottom gun to fire from 5014' to 5024' Line
up mud pump to pump down drill pipe and attempt to take returns thru perfs at 5014'-5024' up 7" x 13,625"
annulus through choke to rig pits, Pressure up annulus to 1500 psi, shoot perf gun at 5014' to 5024' lost pressure
from 1500 psi to 350 psi over 10 seconds; pull wireline up to 4800'. Bring up rig pumps to 1,2 bbl/min and 1080
psi, attempting to circulate thru new shot perfs up 13.625" x 7" annulus, thru choke, monitoring for returns at slop
tank, increase pump rate to 2 bbl/mín with no increase in pressure, (injecting) shut down and monitor pressure
after pumping total of 8-9 bbls. correlate wire line ·for·next shot. (pressure dropped from 1000 psi to 750 psi over
25 minutes.) Shoot perfs from 4986' to 4996' while holding 1000 psi on DP x ì" annulus, seen very slight drop in
pressure as guns fired and[pressure remained at 700-900 psi as POOH with wireline. Blow down mud lines, RD
log/perf wireline assembly RU to run on wireline Halliburton 7" Fast drill cement retainer, RIH with wireline. Tie in
to Sch!umberger ultrasonic imager tog dated 9/21/94. Set Halliburton fast drill retainer at 4979'. POOH and RD
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/812005. Page 2
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wire line. NO shooting flange and i~1I flow line. Make up fast drill cement sting Jnd RIH. (thawing out ice plug
in pipe,) RIHto 4950'. PU 5' and 10' pup joints and single joint wìthhead pin, park at 4965', RU squeeze manifold
and pump lines. Ho!d PJSM, break circulation thru choke, stab into fast drill retainer, mark pipe, pressure test
cement lines to 3.5k, pull out of retainer, pump 5 water ahead, 100sx ( 21 bbls) 15.8 class 9 cement, displace
w/5bb! water, 8 bbl mud, hold 450 -750 psi on annulus while spotting cement to retainer. Stab into retainer and
squeeze away cement at 2,5 bbls/min and 1450 psi, last 8 bbls squeezed pressure increased from 1450 psi to
1900 psi with pump rate same. Pressure bled to 1250 when pump shut down, continued 100 psi bleed off/minute
over next 5 minutes. Pull out of retainer, Reverse circulate two tubing volumes Saw 1 bbl cement and several bb!s
clabbered up mud total of 9 bbls dumped, Drain up and blow down lines, RD Schlumberger.
12/30/04
LD pup joints and working single, secure well. Drain .and blow down pump lines, POOH, lay down cement stinger
Blow down lines (wear bushing was puiled by drag blocks on cement stinger as it passed by. Cut and slip drilling
lines, change out 50' choke hose for 3D' hose to Reduce trip and freeze up hazards. Make up test joint and XOs
and test plug/hanger. Pull wear bushing. Test BOPs, choke equipment, floor/dart valves to 250/3000psi, draw
down test on Koomey (good tests), Blow down lines.
12/31/04
Attempt to run wear bushing, pull wear bushing will evaluate after wire' line. RU shooting flange, wireline BOPs,
LubricatOí and wireliners. Hold PJSM, Arm pert guns and CCL, pick up and stab inside lubricator, pressure test to
2000 psi for 5 minutes (good test), RIH, tie into ultrasonic imager log from 9/21/94. Pressure up annulus to 1500
psi and hold, spot 10 ft ,2",6 sp/ft HSD power jet perf guns and shoot 3493' - 3503'. Press. dropped to 30 psi 1
min. after shot. Pump at 1 bbl/min, pressure gradually increased to 1480psi after 10 bbl away. shut down, 10sec
1098 psi and 1 min to 280 psi. No indication of any returns from the 7" x 13 5/8 annulus during pumping. Blow
down IÎnes. POOH with wireline, PU Fast drill retainer, set at 3485' POOH LD wireline and RD shooting flange
and lubricator. RU new built 6" flow line spool, in place of current spool, run wear bushing. PU. Cement stinger,
RIH to above cement retainer, break circulation, sting into retainer establish circulation at 1.25 bbllmin pressure
climbed to 525 psi then broke back to 388 psi after 9 bbls injected. Shut down 10 see pressure dropped to 152
psi, 1 min 122 psi. RU to pump down 7" X 133/8" annulus with lease water, pumped down annulus 30 bbls before
seeing any pressure (25 psi,) After 40 bbls pumped pressure increased to 280 psi, then climbed t01500 psi after
42.8 bbls pumped (fluid est. to be down 390 ft in annulus before fill up) after pump shut down pressure bled to
1470 in 10 see, and 1425 in 30 minutes. PJSM. With cement pump break circulation test lines to 5000psi, pump
10 bbls water, + 23 bbls, cement while holding 780 psi on annulus, sting into retainer and pump 17 bbls cement at
2.2 bbllmin and 400 psi. chase with 5 water and 8 bbls mud at 2 bbl/min and 500 psi. Hesitation squeezed
remaining 13bbls cement in drill pipe over 6 squeezes of2 bbls / squeeze at 1 bbl/min with pressure increasing
every squeeze by approx 50 psi each time, starting at 450 psi and ending at 700 psi. Between squeezes pressure
drop off was also approx 50 psi higher than previous drop-off. monitored for leaking bag or retainer (none,)
Pressure was fairly stable at 575 psi when we pulled out of retainer. Reverse out pipe volumes; saw 1 bbl cement
and all of spacer water. LD single, blow down lines, prepare to POOH.
1/1/05
LD 2 pup joints, And 14 working singles for drill out of retainers and cement. POOH, PU rig tongs, break and LD
cement stinger. Change out handling toots, MU bit, bit sub and 4 DCs. RIH t03460'. RU power swivel, hang
hydraulic hoses in derrick and hook up, RU mud cross on top of flow line, RIH tag retainer at 3485 WLM, 3496"
DPM, drill on retainer, mud pumps jack off shut down. Clean out rubber and junk from suction screen and under
mud pump, replace shaker screens. Continue to drill on retainer, and cement 3530' Broke thru, push and rotate to
3560', wash with out rotating to 3576'. Circulate and condition hole. RD power swivel and LD, RIH to 3616 to
ensure no cement stringers, continue to circulate and condition, rig for test of squeeze,
1/2/05
RU to pressure test squeezed perts from 3493' to 3503'. Pressure test perfs at 3493 to 3503 using rig pump, pop
blew at 2300 psi, RU test pump, bring up pressure with rig pump to 2000 psi, shut in, bring up pressure with test
pump to 3000 PSI Shut in well. After holding pressure for more than 1 min, perfs broke down and bled to 600 psi
Check all lines and possibilities, retest same, Establish injection rates. Circulate across mud cross at 2 bbl per
min no gains or losses noted. Blow down mud lines and choke manifold. Circulate and wait on cementers for
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL:!ast revised 3/8/2005. Page 3
squeeze job. Pump dry job off of V~UCk. (Schlumberger arrive on location, w~ 4!er job sib mix -mix water
ready to cement at 09:30 hrs). Pull off secondary flow nipple and install ware plate on flow nipple. Pull 6 stands,
runìn one joint with circulating head to 3288'. RU lines and manifold, run injection test at 3/4 bbl per min at 896
psi with 11,5 ppg mud. Pumped 5 bbl., pressure 10 see after pump was down 593 psi. one min after pump was
down 175 psi, pressure after another min 150 psi and starting to get stable. PJSM, Pump 3 bbls water and test
line at 3500 psi. Pump remaining 2 bbl of water, Pump 20 bbls Class G 15.8 ppg cement while holding differential
pressure on rig choke manifold as per DSM Pump schedule. Close choke at 20 bbl away and Squeeze. Pump
remaining 5 bbls of cement + 5 bbl of water + 23.7 bbls of 11,5 ppg mud. sa Pressure 575 psi 1 bbl per min
(squeeze last 10 bbl of displacement at 2 bbl intervals, shutting down for 5 min, switched to 1 bbl interval at 1/2
bbf per min shutting down for 5 min, until cement was displaced. (pressure would go to 800-1000 psi at times but
would break again) Shut down and let pressure bleed to a stable pressure of 250 psi. Monitor 5 mín no change.
Switch over to rig pump and circulate tubing by casing volume at 2.7 bbls per min 500 psi. Holding 125 - 200 psi.
on annulus with rig choke. ShLlt down pump and close choke catching 200 psi on tubing and casing, Pressure
very stable Monitor pressure every Hour, pressure still 200 psi on casing and tubing, shut in choke line and stand
pipe, Bleed down surface lines. Wash up lines and blow down rig,
1/3/05
Continue WOC, install 6" flow line, and continue working pipe every half hour. PJSM, break circulation thru choke,
pressure test squeeze to 21 OOpsi FROM 15 minutes (lost 10 psi rock solid), R,U wash down from 3288' find hard
cement 3330', work pipe and circùlate, blow down lines. LD single, pick up power swivel, break circulation. Pre-
treat mud for cement contamination. Drill firm cement (wob 5-6, rpm 120, pump at 4 bbl/min,) from 3330' to 3378',
break thru and wash 3488', drill cement from to 3488' to 3506'. wash to 3512', past bottom perfs, Circulate and
condition mud, continue to treat for contamination. Test casing to 1100 psi, before break down INJECTS at 3/4
BBL per min 670 psi. Wash down from 3512' to 3543', CBU, blow down lines. RD, Pump dry job. POOH, 20
stands, mud in pits gelling up, unable to maintain hole fill circulation. POOH, Treat mud for cement contamination
while circulating over top of hole while tripping,
1/4/05
Lay down BHA, (loose wheel on bit) pick up Halliburton fast drill and running tool. (check 13.3/6" x 7" annulus,
slight blow), RIH, with fast drill at 45-60 see/stand. Tong back up dies slipping, inspect and change, Continue RIH
to 3451', RU squeeze manifold, attempt to pump (trash under suctions and in valves), elean pump. Break
circulation, set retainer at 3447, shear out, stack 20k to set. Establish injection rate at 1 bpm and 675 psi., unsting
from retainer. Hold PJSM, pump 5 bbl water, test lines to 3k, bleed off, pump 10 bbls G cement, followed by 13
bbls cementJcimnet, hold from 250 to 750 psi on annulus while spotting cement to retainer, stab into retainer and
squeeze 7 bbls w/cimnet and 5 bbls G cement (total cement 35 bbls) and 5 bbls water at 2.1 bbl/min with
pressure climbing after stabbing in from 900 to 1000 psi. Displace drill string with 12 bbls mud at 2.1 bbl/min and
pressure climbing from 1150 t01225 psi. Displace with additional 8 bbls mud at 1.1 bbl/min and pressure climbing
from 900 psi to 1125 psi at end of displacement. Reverse circulate 2 tubing volumes, saw 1-2 bbls cement and all
of water at shakers and slop tank. Blow down Hnes, L.D top single wlhead pin. POOH. LD running tool and stinger.
PU 6" six bladed junk mill, with 2 boot baskets and 4drill collars RIH 52 stands ( 3397') PU power swivel, Continue
RIH and tag retainer at 3446' DPM. CBU and condition mud. WOCand work pipe and roll hole mud while
cleaning pits and going thru MP and suction screen and roll surface system across shaker with Vac truck,
1/5/05
Finish cleaning pits, pre-treat surface system for cen:¡ent contamination, Drill retainer from 3446' DPM to 3450'
rotary @ 100, WOB @ 3-5, pump @ 3,1 bbl/min, (attempt different RPM andWOB.) Drill hard cement from 3450'
to 3477' and varying parameters and massaging bottom and treating mud, Circulate 15 minutes, shut down and
change out shaker screen. Continue Drill hard cement from 3477' to 3485' and varying parameters and
massaging bottom and treating mud. Work on pump and chglout all three rod packings. Continue Drill hard
cement from 3485' to 3516' and varying parameters and massaging btm and treating mud- fell thru and wash to
3522'. Circulate clean. Shut in and attempt to test Re-squeezed perf from 3493' - 3503' WLM - while monitoring
open 13-3/8" X 7" annulus - Pressure build to 1700 psi and broke back to 900psì @2.5 bbls away - up pump
speed to 1 bpm and continue pumping and building pressure to 2100 psi @ 10.5 bbls away - dn pump and with in
1 min psi @ 900 and 3 min @ 400 psi.
1/6/05
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005. Page 4
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Blow down lines and LD, Power swivel. Rih to 3805', Mix and spot balanced high visc 10 bbl pill. POOH LD
working singles to 3514' and RU to circulate, CBU and balance same, Continue circulate, Generator feeding
Tioga down, DSM drain water from filters and put back on line, continue circulate until heat back to rig blow down
and drain lines. Monitor well (ok) LD 2 jts and pooh. Work BHA and clean and check same. PU and MU Howco
fast drUl 7" retainer and running tool. RIH to 3482'. Break circ and set retainer #5 @ 3480' DPM and test to 2000
psi - sheer off and extend stinger - stab retainer and' perform injection rate with rig @ 3/4 bpm @ 1820 psi with 3
bbls away - dn pump 30 sec 600 psi 1 min psi to 400 psi. Unsting and circ and discuss job and chg out crew.
1/7/05
Continue to circulate, hold PJSM with new morning tour crew, discuss squeeze, pumping alignments and
contingency plans for possibly having to reverse out a drill pipe volume of cement. Blow down mud lines, blow air
thru all lines needed for possible cement reversal, ri9 up to squeeze cement Break circulation thru choke,
pressure test cement lines to 3500 psi, batch up cement tub to 15.8 ppg, pump 5 water, 10 bbl G and 10.5bbl with
2 ppb Cement holding 450 -900 psi on back side Shut down, sting into retainer, pump 14.5 bbls w/cement. Initial
pressure was 1700 psi @ .75 bbl/min until5bbl gone; it then broke back to approx 1000-1200 psi until 14 gone.
Displace with 5 bbls water and 19.5 bbls mud, Squeezed 3 times, last 10 bbls, @ 1.5 bbl/min and approx 400 to
800 psi. After each hesitation squeeze the pressure would bleed down to a value approx, 150 psi higher than the
previous time. Final pressure, pumps off before unstinging from retainer was @ 10 see, 1000 psi and 1 minute
was 700 psi. Shut down, unsting from retainer, bleed pressure from annulus. Line up to reverse circulate tubing,
approx 1.5 bbis cement taken back to junk tank. Continue to circulate and build and pump dry job. RD Kelly and
hose and blow down lines, POOH, stand back drill collars; lay down fast drill running tool and sUnger, Work BHA
(stand back driH collars, lay down and check fast drill running tool and stinger, ok), Blow down mud lines, pull
wear bushing, run test plug and fill stack with water. Test BOPs - hydril, choke manifold, manual kill and choke
wing valves and floor safety valves to 250/3000 psi. 3.5" pipe rams failed test. Blow dn choke and all lines.
1/8/05
Finish Bop test, test stack, To 250/3000 psi, perform draw down test on Koomey. Blow dn all lines and choke
Rig back on day rate @ noon, Pull test plug/hanger, run wear bushing. Rig up floor, hang wind walls around stack
and cellar, Hook up kill line and gas buster line - Prep floor to PU DCs. PU 6" tooth bit, 2 drill collars (pre bucked
UP), run 4 collars from derrick and LD tongs and PU power tongs. RIH with ph-6 drill pipe, checking each pin
shoulder for damage caused by pulling into closed pipe rams. RIH to 3476' and tag retainer #5, RD power tongs.
1/9/05
Work on air supply restriction of control hose from power swivel to rig floor no go run new hose. Drill on retainer
#5 from 3476' to 3480', Drill hard cement from 3480' to 3509' @ 5,5 min/ft with 7-8k wob and 80-120 rpm and 2.75
bpm (varying parameters for best results). Fell out of cmt @3509',( 5ft past top perf) to 3510'( torque up and take
wt.) make connection - rotate thru stringers from 3510' to 3517' ( 3 ft past bottom perf), pick up and wash down to
3544'. Blow down mud lines. Lay down power swivel and 3 working singles. RIH, take wt @ 3974', rig up and
circulate, apply weight and attempt to wash thru, wi!! not pass 3974' circulate out hi-vise pill spotted from 3800' to
3514' (did not see pill), lay down head pin jnt and Blow down mud lines, PU power swivel. Drilling cement stringer
from 3974' to 3975' and fall thru and wash to 4012'. Make connection, Blow down and LD working single and
power swivel. RIH out of derrick tag @ 4871' work same to 4881'. PU power swivel. Brk Circ and have safety
stand dn - hold school and safety meeting on P/up and LD safety on Power swivel. Drilling cement stringer from
4881' to 4894' and fall thru and wash to 4913' - circulate and wait on relief.
1/10/05
PTSM. Make connection. Continue wash from 4913' to 4924' tag up and drill cement stringer from 4924' to 4932'
and fall thru and wash from 4932' - to 4947' and push to kelly dn @ 4948'. Attempt connect out of balance - circ to
balance. Makè Conn. Continue Clean out hard cement stringer from 4948 to 4955', drill soft cement from 4955' to
4978' (cannot wash thru, but will not take wt. when rotating.) Attempt connection, flow back, circulate. To balance,
shut down pumps. Make Conn. @ 4978'. Drill soft cement from 4978' to 4981' drill firm cement from 4981' to
retainer @ 4989'. Drill retainer #2 from 4989' to 4993'. Drill soft cement from 4993' to 5002' @ 30 seclft with 7 -8k
wob and 80-120 rpm and 2.75 bpm (6' into secondary perfs Adjusted to DPM) - Drill hard cmt from 5004' to 5009'
(from 7ft into secondary perf to 2 ft below secondary perfs @ 4997' to 5001' DPM est) @ 3 min/ft same
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 5
1/11/05
'. ..e .-.
parameters - Droppmg MW as dnHI..~ progresses from î 1.0 to 9.5, 10.2 @ pres\.. .. Clrc and take under flow from
shaker to suction for dry job for connection and make connection. Continue top dríll hard cement @ same
parameters from 5009 to 5019 @ 3 minI ft (2ft. Below bottom of secondary perfs to 6ft above top of bottom set
perfs) ROP picked up to 1 min/ft @ 5021' to 5037'(entire interval of bottom set of perfs @ 5025' to 5035' DPM est)
fell thru cement @ 5037'(2 ft below bottom perf) void continued to connection depth @ 504 î '. Circulate to
balance, make connection, RIH wlo pumping FROM 5041' TO 5056', take wt, wash to 5072', make connection.
RIHw/o pumping to 5î03', Blow down, lD pwr swivel, and working singles, RIH and set dn @ 5522'. PU power
swivel. Drill hard cmt/junk from 5522' to 5523' fell thru wash to connection depth of 5539'. Circ and make
connection and wash from 5539' to tag @ 5545'. Drill retainer #1 from 5545' to 5547' ~ fell free - washed to conn
depth of 5570' (no cmt)- conn - washed to 5600' (no cmt) - conn -wash to 5632' (no cmt) - conn - Wash from
5727', RIH to 5765'. completely void of cement below retainer, tag junk @ 5765', circulate.
Circulate hole, watch shakers for packer parts, finish MW cut back to 9.7, circulate even weight mud all around.
Air lines to rig control freezing up, adding methanol and functioning. Monitor well for flow, PJSM. Pump slug from
vac truck, blow down mud lines, lay down Power swivel. PU circ head and clear floor of rig tongs. CBU. Mix high
vis pill and Pump and spot 10 bbl on btm @ 5764' @ 9.8 Ppg with 35 ppb sea mud and 1 ppb XCD, Pooh to bit
depth of 5600'. CBU and polish off high vis pill @ 5600' (base of perfs). Pump dry job and blow dn lines and thaw
frozen lines. Pooh, stand back in derrick, lay down bit sub and bit. Bit in very bad shape, mill tooth very badly
worn. can see evidence of rotation on metal. Possible slips from retainers. PUHalliburton fast-drill retainer and
start into hole. Work on tongs BU not holding due to ice disassemble, steam, and coat with oil. RIH with retainer.
1/12/05
RIH slow with 7" Howco fast drill retainer. RU Kelly hose and break cìrc and blow.down fines, Set Howco 7" fast
drill retainer @ 5535' and test same 500 psi on back side (ok) blow down. PJSM sheer off and extend stinger and
stab retainer. Establish 20 bbl injection rate 1 bpm @ 2240 psi (shut dn 10 see 2058 psi, 1 min @ 2039 psi, 2min
2030 psi, 3 min 2020 psi, 10 min 1986 psi, ßleed off with 7 bbl back). Unsting circ and blow down fines RU lines
for squeeze and check all lines for clear, Break circulation through choke, pressure test cement lines to 4000 PSI,
batch up cement to 15,8 ppg, pump 5 BBl water, followed by 18 BBl Class G Cement, catching 400 PSI initially
and holding 800 psi on back side at 18 BBLaway, at 1.45 BPM rate, sting into retainer pump pressure rose to
1000 PSI, pump another 18 BBL of Class G cement at 1.45 BPM rate, The highest pressure seen was 1750 PSI,
at SD pressure was at 1350 PSI, pumped 5 BBl H2Q at 1 BPM, Pressure maintaining at 950 - 1000 PSI. SO Mud
line froze had to thaw. Pumped 20 BBL of 9.9 PPG mud to displace at 1.5 BPM rate starting pressure 800 PSI
ending pressure 1900 PSI. SO, pressure fell to 1550 PSI and maintained. waited 15 minutes on hesitation
squeeze, pumped 5 BBL mud at 1 BPM rate with ending pressure of 2250 PSI. SO pressure fell to 1950 PSI.
Waited 15 minutes on hesitation squeeze, Pumped another 9.5 BBL of mud with a final pump pressure of 2975
PSI. SO and pressure fell to 2500 PSI. PU pipe and unsting from retainer. Pressure on casing rose from 800 PSI
to 1000 PSI and settled out at 900 PSI. Reverse circ to pits, when mud turned to water, divert cement to slop tank
(+- 2.5 bbls cmt back) 33.5 BBl Cement below retainer. Blow dn all lines a,nd choke. Pump dry job from ISO tank
(no good)build and pump dry job - blow dn Iines.'POOH, PU bit and scraper; RIH with DC.
1/13/05
RIH with DC, and 2 stands of DP. RIH work scaper from 3163' to 3420' and from 4663' to 4920' continue into hole
and tag top of retainer at 5532'. LD two working singles and RIH with 1stand, P/U power swivel (had problems
with hyd hoses). Drill HOWCO fast drill retainer #6 FROM 5532' to 5538' in about 1 hour looks like approximately
2' of cement below retainer. WOB 6K, 100 RPM, 3BPM, then broke free. Circulate and clean retainer setting area.
Wash down to 5636'. Blow down and RD power swivel. RIH and tag at 5753' set 1 OK down, did not see any
resistance prior to tagging. LD single and PU Kelly joint with head pin, CBU had several BBLS of a very thick
viscous materia! with a very gritty texture to it come across shaker. Circulate and condition mud dropping weight
down to 9.5 PPG, and circulate around. Mix dry job, and monitored well for flow, prior to pulling out of hole, Blow
down. POOH stand back in derrick.
1/14/05
POOH - Work BHA - Blow down. PU champ packer, with single and XO on top, and make up on catwalk, hang
same in elevators. PU single joint 27/8" IBTtubing and set in slips with XO in top, MU same to bottom of champ
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 6
1115/05
'··e .e
packer hanging in elevators. RIH Wt<fl 28 stands and PU multi-service tool and flL..; with single and XO, RIH with
another 49 stands (77 stands total with 2-singles) (1 HR WOO) Champ packer set at 4893'. RU squeeze manifold
and prep for negative pressure test, Pressure up on annulus to 500 PSI felt multi service valve open. Monitor
bubble hose for 25 minutes had a steady increase in flow. Bleed casing pressure off. pump down DP, @ 970
strokes start to pressure up, continue to pump until pressure reached 1000 PSI, line up to choke and bleed off.
PU on DP 3' to open bypass. Reverse circulate BU at approximately 1000 strokes had gas back to surface,
pumping through choke going to gas buster, circulate gas out and an additional BU. Switched over circulating
long way taking returns through choke going to gas buster, Circulate :2. BU with no sign öf gas. Monitor weU, mix
dry job, wel! out of balance tubing light, closed TIW valve. Valve leaked changed out same. Pump dry job, PU
power swivel break out TIW and saver sub lay down same. RU tongs and prep floor for laying down pipe
POOH laying down PH-6 tubing installing protectors on each end.
lD 3.5" PH-6 DP. RU manual rig tongs break out and lay down multi-service tool. RD and lD rig tongs. Continue
to lay down drill pipe, lay down Champ packer and 1 joint of 27/8" tubing. Trip in hole with DC from derrick and
lay down same. Trip in hole with dríll pipe from derrick and lay down same. Change pipe rams from 3.5" to 2.875",
pull wear ring, MU test joint and set test plug, fill stack and choke with water. Test BOP, choke manifold, and floor
valves too 250 PSI low and 3000 PSI high. PJSM. load pipe racks with 2 7/8" IBT tubing, sort and number tubing
(Slick - Centralizer joints) Pick up handling tools. PU and run 2 7/8" tubing, drift with 2.375 OD rabbit
1/16/05
RU fill line and continue to RIH filling tubing going into hole. RU Pollard to run chemical injection line PU mandrel
make up line and test same, Continue to RIH filUng tubing, and banding chemical injection line, RIH and tag
bottom at 5749.95 pick up and space out, MU hanger terminate chemical injection line, land tubing and RllDS
28M up weight and 28M down weight. Total of 178 joints in hole. Total of 156 bands in hole, NU Install additional
7" casing x 27/8" tubing annulus valve on off side of tubing spool. Removed VR plug through valve after
installation. MU Lake Charles Cement head, PU and break out pups used for landing joints and test joints. RO
and LD Foster power tongs, RU squeeze manifold, RU annulus return line through choke going to shaker and
slop tank. Circulate and clean hole. PJSM, Pump 10 BBls diesel down tubing for freeze protection on back side,
followed by 1 BBl mud to flush lines, blow down lines. Pump 3 BBL CW100 to fill and flush lines, and test cement
lines to 4000 PSI, bleed pressure off, pump an additional7BBLS of CW100. Pump 30 BBlS of Mudpush XL @
10,5 PPG. SO and batch up lead cement slurry of 20 BBL of lite-crete with Cement at 12 PPG, pump same at 3.5
BPM, followed by an additional 33 BBlS of lite-crete (No Cement) pumping at 4.5 BPM rate, SD and batch up Tail
cement slurry of class G cement at 15.8 PPG. Batched up to 15.8 PPG, and pumped 25 BBlS of same with
density flux from 14.9 to 16.4 PPG. SO, washed lines, dropped plug displaced with lease water, Burnped plug at
22.30 HRS, pressured tubing to 3500 PSI and held pressure for 10 minutes with no pressure loss, bled off
pressure and checked floats had 1/4 BBl of returns and float held.
Blow down and RD cement lines.
1/17/05
Pressure up and rupture disc at Chemical injection mandrel, (4300 PSI) continue to pump and clear area of any
residual cement. Clean floor, RO Cement head and lay down same, start to clean pits. RU Pollard Wireline
RIH with temp survey tools to 5000' logging in and out at 60' per minute 5 minute stop at hanger and at 5000',
Power wash stack and prep for ND. lD landing joint and Set 2.5" CIW H BPV. NO BOP equipment includíngriser.
Freeze protected 13-3/8" X 7" by Pumping 3.5 bbls Diesel into annulus with test pump work psi @1500 psi broke
and feU to 500 psi and built back to 1000 psi @ shut dn 800 psi and shut valve. NU tree and Test hanger void to
5000 PSI held for 15 minutes with chemical injection port open with no leak. Pull BPV and set TWC test tree to
5000 PSI held for 15 minutes no leaks. Pull TVIIC and freeze protect tree using diesel fuel. Instali BPV. Release
rig at 18:00
lay felt and liner at relief pad to stack rig out on, blow down boiler, continue with pit cleaning and disposal of
solids, palletize equipment and prep to move.
1/19/05
Using triplex test pump and pumping diesel pressure 7" casing x 27/8" tubing annulus to 2000 PSI, SI an hold
pressure for 30 minutes with a 50 PSI pressure drop. Bleed pressure off. Pollard RIH with 2.35" GR tagged at
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: ¡as! revised 3/8/2005, Page 7
# ~ _ J
~.. . ·e
5601' WLM which is 91' high. Noti~ome anomalies with counter, POOH, frol, _,oint were counter was to zero
to where it topped out 100' off. Picked up lubricator and run tool string down to LDS counter off 90'. RIH second
time to verify counter discrepancy, put heater on counter to try and keep it from locking up, Tagged at 5697' WLM
POOH cement LC at 5692' pipe measurement. Lay down lubricator and secure well.
1/20/05
Test BOP to 250 PSI low and 5000 PSI high. PJSM. RIH with coil, whíle cooling down taking returns to Johnson
tank. Start to pump N2 at 240 SCM per minute, monitoring returns in Johnson tank. Tag bottom at 5686'. PU 5'
and increase rate to 600 SCFM rate, max pressure 2580 PSI monitoring returns, at calculated returns had N2 to
surface, put on choke and continued to blow for 10 minutes. POOH, trapping 1800 PSI on tubing, remove injector
head and spooling up coil. ND BOP, stage BOP and injector in transportation rack. Secure well.
1/21105-1/23/05
RD/MO
1124/05
Schlumberger out at 06:00 hrs spot equipment and start to rig up, had PJSM, complete Unocal explosives and
perforating check list. arm guns, .NU, test lubricator to 250 PSI low and 3000 PSI. RIH using Schlumberger
Ultrasonic Imager Log dated 9/21/94, tie in to perforate from 5555' to 5567', Confer with Meg Kremer prior to
perforating. Fired guns at 10:12 HRS had N2 cap of 1778 PSI. within 5 minutes had pressure of 1955 PSI and
built up to 1958 over the next 30 minutes. Schlumberger POOH all guns had fired, rigged down and departed
field. Turned weH over to production.
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/812005, Page 8
SRU 32A-15, 10-407 for 304-388
)
)
Bob-
otö4'
\ C\ l\'~
Here's the 10-407 in all of its entirety. Call me if you are still missing anything.
Thanks
Diane
iSRU32A-15AOGCCformlO-407submitted030905.pdf' Content-Type: application/octet-stream ·
I ¡ Content-Encoding: base64
SCJ\NNED NO\f 0 8 Z005
1 of 1
9/7/20057:30 AM
1 a. Well Status:
STATE OF ALASKA RECEIVED
ALASI<.. 11L AND GAS CONSERVATION COMMit bN SEP 2 9 2005
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
OilD . GasQ Plugged D AbandonedD SuspendedD WAGD 1AJ..kø<ÐDs& Gas Cons. CUlllllli:>:>iulI
20MC 25.105 20MC 25.110 Development [ID1choragE:xploratoryD
No. of Completions Other Recomplete Service D Stratigraphic TestD
5. Date Comp., Susp., or 12. Permit to Drill Number:
Aband.: 10/3/04 94-84
6. Date Spudded: 13. API Number:
n/a 50-133-10141-01
7. Date TD Reached: . 14. Well Name and Number:
nla SRU 32A-15
8. KB Elevation (ft): 15. Field/Pool(s):
151 Swanson River Fieldl
9. Plug Back Depth(MD+ TVD): Tyonek
7,336'/7,250' Hemlock
10. Total Depth (MD + TVD): 16. Property Designation:
5,750/5,744' Swanson River
11. Depth Where SSSV Set: 17. Land Use Permit:
nla A-028384
19. Water Depth, if Offshore: 20. Thickness of Permafrost:
nla feet MSL nla
WDSPL D
GINJD WINJD
2. Operator Name:
Union Oil Com pany of California
3. Address:
POBox 196247, Anchorage, AK 99519
4a. Loca_ael. '....~..I.I (Governmental Section):
Surface:.OO FNL, 1040 FWL, Sec. 15 T8N R9W
Top of Productive'Horizon:
Total Depth:
2286 FNL, 3161 FWL, Sec. 15 T8N R9W
4b. Location of Well (State Base Plane Coordinates):
Surface: X = 348,884, y = 2,480,047
TPI:
Total Depth: X = 351,036, Y = 2,480,023
18. Directional Survey: Yes 0 No Q
21. Logs Run: n/a
22.
CASING WT. PER GRADE
FT.
22"
13-3/8" 54.5 K-55
7" 26,29 P-110/N-80
5" 18 L-80
CASING, LINER AND CEMENTING RECORD
SETTING DEPTH MD SETTING DEPTH TVD
TOP BOTTOM TOP BOTTOM HOLE SIZE
o 45' 0 45'
o 2,958' 0 45'
o 10,257' 0 9938'
9,971' 11,590' . 9672' 111'87'
CEMENTING RECORD
AMOUNT
PULLED
see schematic attached
18-5/8"
10-5/8"
6"
23. Perforations open to Production (MD + TVD of Top and Bottom
Interval, Size and Number; if none, state "none"):
Top Bottom Amt SPF Zone Comments
5,555' 5,567' 12' 56-0 Beluga
7,267' 7,282' 15' 6 68-0 Upper Lobe P&A 10/24/04
7,358' 7,398' 40' 6 68-0 Lower Lobe P&A 10/24/04
24. TUBING RECORD
SIZE DEPTH SET (MD) PACKER SET (MD)
2-7/8" surface-5,727' cement pkr.
2-7/8", 2-3/8" 6,000-9,766', 11,256' 11,186'
25. ACID, FRACTURE, CEMENT SQUEEZE, ETC.
DEPTH INTERVAL (MD) I AMOUNT AND KIND OF MATERIAL USED
see schematic
~J\NNE[; NOV £~ t~ 2005
26. PRODUCTION TEST
Date First Production: Method of Operation (Flowing, gas lift, etc.):
January 30, 2005 FlowinÇJ
Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF:
1/25/2003 28 Test Period ~ 0 1,076
Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF:
Press. 1705 not available 24-Hour Rate ... 0 923
27. CORE DATA
Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary).
Submit core chips; if none, state "none".
nla
Water-Bbl:
Produced water
Water-Bbl:
unmeasured
Choke Size: Gas-Oil Ratio:
8-12 (1/64) nla
Oil Gravity - API (corr):
nla
;RBDMS 8Ft 0 C1 1 0 2005
C)F<\G\~JAL
Form 10-407 Revised 12/2003
CONTINUED ON REVERSE
28. GEOLOGIC MARKERS ')
NAME MD TVD
GlaciaLBase_MJF 591 591
Tks_ YELLOW 1 ,472 1,472
A9 2,561 2,561
B2B 3,029 3,028
Beluga 3,504 3,503
41-4ST 4,121 4,120
Mid_Beluga_MJF 4,591 4,590
50-6ST 5,008 5,007
L.L._ Tnk_MJF 5,514 5,511-.
D1CT 6,050 6,038
61-8ST 6,561 6,526
66-3STE 7,046 6,981
70-8CT 7,524 7,422
mtLmark 8,067 7,920
80-2ST 8,555 8,367
E10 9,247 9,007
Hemlock_MJF 11,272 10,887
TD 11,590 11 ,187
29. Fr-'¥ATION TESTS
Include and briefly summariz.", .ést results. List intervals tested, and attach
detailed supporting data as necessary. If no tests were conducted, state
"None".
nla
30. List of Attachments:
summary of morning reports, schematic.
31. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Printed Name: Tim C. BrandenburQ
Signature: Z ~, " 0 h~. /~3
o ..,
£,/ .-/'"
/
Contact: Steve Tyler 263-7649
Title: Acting Drilling Manager
Phone: 907-276-7600
Date:
Resubmitted 9/28/05
Follow up to Sundry 304-388
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 Injection, 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 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other
spaces on this form and in any attachments.
Item 20: True vertical thickness.
Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
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 før 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 interva'l reported 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: If no cores taken, indicate "none".
Item 29: List all test information. If none, state "None".
Form 10-407 Revised 12/2003
UNOCALe
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TD= 11,590' PBTD= 5,750'
Max Deviation = 24.3° @ 7815'
SRU 32A-15 FINAL-,--Ol-15-05
Size
22"
13-
3/8"
DV Collar
13-
3/8"
Type
Conductor
7"
7"
7"
7"
7"
7"
DV Collar
7"
7"
5"
Tubin~
2-7/8"
27/8"
2 3/8"
NO.
A.
B.
C.
D.
E.
GLM #1.
GLM #2.
F.
I.
GLM #3.
GLM #4.
GLM #5.
2.
3.
GLM #6.
4.
5.
GLM #7.
)
)
Wt
Grade
Casing &
Thrd ID
Tubing
Top Btm
Surf 45'
SurfCsg
54.5 K-55
54,5 K-55
~ P-IIO
26
~
~ N-80
29
26 P-IIO
26 P-IIO
29
18 L-80
Buttress
Surf Csg
Prod Csg
8rd
Prod Csg
Liner
15.0' Original RKB to Tbg Hngr
6.4 N-80 Buttress
6.4 N-80 Buttress
4.6 N-80 Buttress
12.615 Surf 964'
964' 967'
12.615 967' 2958'
6.184 Surf 39'
6.276 39' 2097'
6,184 2097' 3439'
6.276 3439' 6158'
6.184 6158' 7933'
6.276 7933' 8467'
8467' 8470'
6.276 8470' 9789'
6.184 9789' 10,257'
4.276 9971' 11,590
2.441
2.441
I. 995
Surf
6000'
9,766'
5727'
9766'
11,256'
Swanson River
Well SRU 32A-15 .
As Completed 1/24/05
Hole
Cmt Cmt Top
Yes Surf.
1000 Surf
sx
600 sx 2144'
( Calculated)
18-
5/8"
1000
sx 6495'
10- Thru CBL
DV@
5/8" R467'
1000 9399'
sxs Calculated
6" 500 11,250'
]!, 'M.,iIJ:."
~.J~I~_~
JEW E LR Y DETAIL
Depth ID OD Item
16.44' Tubing Hanger, FMC Type TCM 7 1/16" 01> x 2 7/8" EUE
lift and suspension, WI Cont Cont Line
2491' 2.363 Chem Inj Sub
5692' BOT 3-1/2" Landing Coller wi X()'s to 2-7/8" box & Pin
5727' BOT 3-1/2" I110at Shoe wI XO to 2-7/8" box
5750' CIBP
6000' Cut tubing
6220' 2.347 5.5" x 4.673" Cameo MMG-P GLM
6891' 2.347 5.5" x 4.673" Cameo MMG-P GLM
7000' Tbg. plug
7345' EZ Drill ClOP
7597' 2.347 5.5" x 4,673" Cameo MMG-P GLM
8303' 2.347 5.5" x 4.673" Cameo MMG-P GLM
9039' 2.347 5.5" x 4.673" Cameo MMG-P GLM .
9300' Cmt Retainer (TOC in tbg)
9717' Cmt Retainer
9726' 2.347 5.5" x 4.673" Cameo MMG-P GLM
9766' 1.995" 3.503" Crossover, 2-7/8",EUE 8rd x 2-3/8" EUE 8rd
10,448' 1.875" 3.065" Otis "XA" Sldg Slve
11,149' 1.875" 4.125" x Cameo KBMG-2 GLM
2.781"
11,186' 2.55" Otis "BWD" Pkr
11,226' 1.875" 2.701" Otis "X" Profile Nipple
11,256' 2.32" 2.872" WLEG
6.
7.
8.
PERFORATION HISTORY
Interval Accum.
Top Btm Amt spf
3,493' 3,503' 10' 6
4,986' 4,Q96' I A' 6
5,014' 5,024' la' 6
5,545' 5,555' la' 6
5,555' 5,5'67' 12'
5,590' 5,600' 10'
7,267' 7,282' 15'
7,358' 7,398' 40'
11,326' 11,336' 10'
11,340' 11,346' 6'
11,354' 11,364' 10'
Comments
Sqz Perfs
Sqz Perfs
Sqz Perfs
Sqz Perfs
56-0 Beluga
Sqz Perfs
68-0 Upper Lobe. P&A'd 10/24/04
68-0 Lwr Lobe. P&A'd 10/24/04
P&A
P&A
P&A
6
6.0
6.0
REVISED: 01/24/05 by SL T
· 10/29/04
)
)
Spot equipment RU and test to 2500 PSI. RIH with 2.25" DO Bailer and tag fill at 7330' KB recovered 1 cup of
sand. RIH with 2.32" gauge ring and tag fill at 7330' KB. RIH w/2 1/2" SB&A stop set at 7000' KB POOH. RIH with
2 1/2" GS and Pack off plug set at 6999' KB POOH. RIH and make 6 dump bailer runs using a 9' x 2.25" bailer,
dump bail cementfrom 6995' to 6960'10 gallons. RD Pollard
11/1/04
RU Schlumberger. PT top of cement plug to 3000 PSI held for 20 minutes, bleed off pressure. RU APRS unit
using Pollard mast truck, test lubricatorto 3000 PSI. Have PJSM. RIH with 2:25 jet cutter and tagged top of
cement plug at 6974' Tagged witnessed by Jeff Jones with AOGCC. PU using CCl found center of joint at 6012',
pressured up to 500 PSI, fired cutter had good indication of firing, tubing fell to zero PSI instantly, POOH. Jug test
wellbore to 3000 PSI for 30 minutes held good. With APRS RD, Schlumberger start pumping down the tubing
taking returns, CBU, (water clean for produced.) Freeze protect annulus and tubing. Pump 5 bbls down backside,
and .5 BBlS down tubing.
12/22/04
RU, Clean snow from Koomey, Tioga, choke hose and other. Prep area for SlB Cementing foot print.
12/23/04
RU, PJSM, ND tree, and NU 7 1/16" 5M BOP, Choke line and Kill line. Function test same. Move drillers console,
Make up 2 7/8" test joint. Test Annular, 2 7/8" Rams, Blind rams, choke line valves, kill line valves, choke manifold
and all floor valves to 250/3000 psi. Test gas detectors. AOGCC waived witness to BOP Test. Set cat walk and
pipe racks. RU floor to pull tubing.
12/24/04
Back out lock downs and check annulus for pressure. Pull hanger free, took 95 kip to finish tubing cut. Pull hanger
to rig floor up wt 38 kip. lay down hanger and pups; make up head pin and CBU. Had some bubbles, shut
annular and went through choke manifold and gas buster, pit level dropped enough for charge pump to loose
prime. shut down and blow down lines. Finished CBU. POOH, lD 2 7/8" tubing. Recovered 188 joints + cut off
joint + 5 puped GLMs + 3 Space out pups and tubing hanger. Wire line cut was made at 6012' (did not Strap out
of hole, went off of joint count, pipe came out. Change rams from 2 7/8" to 3 1/2". Test pipe rams and floor valves
to 250/3000 psi. Blow down and freeze protect test pump. RU to handle BHA and 4 3/4" Drill collars. Pick up 6" bit
7" 29# casing scraper and 4 3/4" Drill collars
12/25/04
Change out handling equipment to handle 3 1/2" PH-6 and Clear off rig floor. RIH bit and scrapper on 3 1/2" PH-6
Tubing. Thaw and Drift pipe with 2.312' rabbit. Continue RIH with bit and scrapper to 5824, (182 total joint 3 1/2"
12.60 # PH-6) RU to change over well bore fluids from 8.4 PPG lease water to 11.7 PPG mud. PJSM. Displace
well bore with 11.7 ppg water base mud, taking lease water returns to Johnson tank. After displaced take returns
back to active system until we had a 60 bbl surface volume. Circulate at 2 bbl per min over shaker; pump
performed well out of big tank and vac trucks. Blow down all surface line and RU choke line. POOH 53 Stands to
2513', RU floor to make up storm packer.
12/26/04
Run in storm packer and set same 12' below well head, shut pipe rams and test storm packer to 500 psi, back out
joint and close storm valve. lay down same. Clear off floor, RD floor and prep to NO BOP (includes vac out and
clean cellar). Nipple down BOP, remove choke and kill lines. Stump up BOP until ready to NU. Checked voids on
old tubing spool for any trapped pressure. After inspection found 7" 29 PPF casing stub to be badly Kelly worn.
Checked annulus between surface casing and 7" production casing for any pressure found none, checked for any
lEl and found none. With constant LEl monitoring pulled casing hanger seal and replaced with new. NU new
remanufactured tubing spool, and tested void to 2500 PSI, held for 10 minutes. Nipple up BOPs. RU rig floor.
Make up two-way check set tubing hanger and shell test stack, choke line and kill line against blind rams at
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 1
/ 250/3000 psi (good test) RU rig tons ) lay down storm valve. PU joint of PH-6. )retrieving tool, screw into
storm valve, open Safety valve and check for pressure (none). Unseat storm packer up wt 30 kip. LD same. LD
rig tongs. POOH FROM 2513' - 1073'.
12/27/04·
Continue POOH 3 1/2" PH-6 to drill collars. LD hydraulic tongs, RU manual tongs, slip bowl and 4 3/4" drill collar
slips. (lay down bit/scrapper) rack drill collars 2 stands. Blow down rig, Nipple down flow nipple and clean out stud
holes to accept studs for shooting flange, RU line from surface casing x 7" casing annulus to choke. PJSM. RU
Schlumberger. PJSM pull tools to floor and PU r HES EZ drill CIBP, RIH to 5770' logged up found collar at 5752'
dropped down and logged back up set EZ drill at 5760', setting tool fired at 11: 15 HRS POOH. RU WL BOP found
bad spot in E-Line and SWS rehead. Arm guns and stab up, test to 2000 PSI against EZ drill, held 10 minutes
bleed off pressure. RIH with 2- 10' guns 2" hsd, 6 shots perlft set for selective fire. Make tie in pass. Tie in to
Schlumberger ultrasonic imager log dated September 21-1994. Pressure up on 7" annulus to 1500 psi. Perforate
from 5590' - 5600'. Pressure dropped to 600 psi when gun fired. pull up hole 500'. Attempt to circulate, pump at 1
bbl permin pressure increased to 1740 psi and maintained a rate of 1 bbl per min and put away a total of 10 bbl,
shut down 'pump. Pressure after 10 sec was 1650 psi. Drop back down tie in and perforate from 5555' - 5545',
With 1350 psi on r annulus, saw no change in pressure when guns fired. POOH with perf guns. Lay down guns
all shots fired. Close blind rams. Attempt to circulate (no go) results were the same pumped 8 bbls away at 1750
psi at 1 bbl per min. Shut down pump, pressure 10 sec after shut down was 1650 psi, and 1242 psi 30 min after
shut down. Bleed off pressure and blow down all lines. Make up setting tool arm same. Make up 7" Halliburton
Fast drill retainer. RIH, Tie into log and set retainer at 5535'. POOH with perf guns. LO guns all shots fired. LD
tools and RD Schlumberger, start nipple down shooting flange.
12/28/04
Continue RD Schlumberger wire line. NO shooting flange and nipple up flow nipple and install flow line. MU
Halliburton Fast drill cement stinger. RIH cement stinger on 3 1/2"12.60 # PH-6 Tubing. (Thawing out pipe) Make
up single and tag at 5544' tubing measurements, current RKB. Retainer set at 5535 Wire line measurements.
Space out for cement job, ended up with tool joint in annular at the same time stinger stabs into retainer, RU
stand pipe hose and head pin. Break circulation stab in and perform injection test at 1 bbl per min 1740 PSI. with
rig pump. Pump 4 bbls, no returns noted in 7" annulus. Close annular and pressure up to 650 psi and perform
stab in test and adjust annular to 500 psi or less. PJSM. Break circulation with Schlumberger pump 3 bbls water
shut down and test line to 5000 psi. (good test) pump 2 bbls water for a total of 5 bbl a head of cement. Bqtch up
cement to go down hole. Pump 21 bbls 15,8 ppg cement slurry holding 650 psi back pressure with rig choke
manifold, pump 5 bbl water + 12 bbls of 11.6 ppg wé;lter based mud. Shut down and stàb in retainer (held '650 on
back side during squeeze no pressure change during squeeze) squeeze cement away with 23.4 bbls 11.6 ppg
water based mud at 3 bbl per min 2000 psi, slowed to a rate of 1 bbl per min 1540 psi, last 4 bbls away. Shut
down pump and unsting from retainer. pressure 10 sec after pump shut down was 1504 psi. Reverse circulate 2
tubing volumes, got back unexpected cement took returns to junk tank, gauged tank. Recovered 12 bbls of
contaminated mud, cement, and water. Pump dry job and blow down rig. POOH and Lay down stinger. RU
shooti ng flange.
12/29/04
RU shooting flange, wireline lubricator and grease head, pick up GR/CCL tool and two 10' ft 2", 6 shot / ft HDS
perf guns, set for selective fire. Pressure test wireline lubricator and BOPs to 2000 psi, hold pressure for 10
minutes. (good test). Blow down and drain lines, RIH' with wireline. Make tie in pass, tie into Schlumberger
ultrasonic imager log dated Sept 21 1994, made 2 passes to correlate bottom gun to fire from 5014' to 5024' Line
up mud pump to pump down drill pipe and attempt to take returns thru perfs at 5014'-5024' up 7" x 13.625"
annulus through choke to rig pits. Pressure up annulus to 1500 psi, shoot perf gun at 5014' to 5024' Lost pressure
from 1500 psi to 350 psi over 10 seconds; pull wireline up to 4800'. Bring up rig pumps to 1.2 bbl/min and 1080
psi, attempting to circulate thru new shot perfs up 13.625" x 7" annulus, thru choke, monitoring for returns at slop
tank, increase pump rate to 2 bbl/min with no increase in pressure, (injecting) shut down and monitor pressure
after pumping total of 8-9 bbls. correlate wire line 'for-next shot. (pressure d'ropped from 1000 psi to 750 psi over
25 minutes.) Shoot perfs from 4986' to 49961 while holding 1000 psi on DP x 7" annulus, seen very slight drop in
pressure as guns fired and[pressure remained at 700-900 psi as POOH with wireline. Blow down mud lines, RD
log/perf wireline assembly RU to run on wireline Halliburton 7" Fast drill cement retainer. RIH with wireline. Tie in
to Schlumberger ultrasonic imager log dated 9/21/94. Set Halliburton fast drill retainer at 4979'. POOH and RD
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 2
· wire iine. ND shooting flange and i'l ) flow line. Make up fast drill cement stin9~d RIH. (thawing out ice plug
in pipe,) RIHto 4950', PU 5' and 10' pUp joints and single joint with head pin, park at 4965', RU squeeze manifold
and pump lines. Hold PJSM, break circulation thru choke, stab into fast drill retainer, mark pipe, pressure test
cement lines to 3.5k, pull out of retainer, pump 5 water ahead, 100sx ( 21 bbls) 15.8 class g cement, displace
w/5bbl water, 8 bbl mud, hold 450 -750 psi on annulus while spotting cement to retainer. Stab into retainer and
squeeze away cement at 2.5 bbls/min and 1450 psi, last 8 bbls squeezed pressure increased from 1450 psi to
1900 psi with pump rate same. Pressure bled to 1250 when pump shut down, continued 100 psi bleed off/minute
over next 5 minutes. Pullout of retainer, Reverse circulate two tubing volumes Saw 1 bbl cement and several bbls
clabbered up mud total of 9 bbls dumped. Drain up and blow down lines, RD Schlumberger.
12/30/04
LD pup joints and working single, secure well. Drain .and blow down pump lines. POOH, lay down cement stinger
Blow down lines (wear bushing was pulled by drag blocks on cement stinger as it passed by. Cut and slip drilling
lines, change out 50' choke hose for 30' hose to Reduce trip and freeze up hazards. Make up test joint and XOs
and test plug/hanger. Pull wear bushing. Test BOPs, choke equipment, floor/dart valves to 250/3000psi, draw
down test on Koomey (good tests). Blow down lines.
12/31/04
Attempt to run wear bushing, pull wear bushing will èvaluate after wireïine. RU shooting flange, wireline BOPs,
Lubricator and wireliners. Hold PJSM, Arm perf guns and CCL, pick up and stab inside lubricator, pressure test to
2000 psi for 5 minutes (good test). RIH, tie into ultrasonic imager log from 9/21/94. Pressure up annulus to 1500
psi and hold, spot 10ft, 2",6 sp/ft HSD power jet perf guns and shoot 3493' - 3503'. Press. dropped to 30 psi 1
min. after shot. Pumpat1 bbl/min, pressure gradually increased to 1480psi after 10 bbl away. shut down, 10sec
1098 psi and 1 minto 280 psi. No indication of any returns from the 7" x 13 5/8 annulus during pumping. Blow
down lines. POOH with wireline, PU Fast drill retainer, set at 3485' POOH LD wireline and RD shooting flange
andlu bricator. RU new built 6" flow line spool, in place of current spool, run wear bushing. PU. Cement stinger,
RIH to above cement retainer, break circulation, sting into retainer establish circulation at 1.25 bbl/min pressure
climbed to 525 psi then broke back to 388 psi after 9 bbls injected. Shut down 10 sec pressure dropped to 152
psi, 1 min 122 psi. RU to pump down 7" X 13 3/8" annulus with lease water, pumped down annulus 30 bbls before
seeing any pressure (25 psi,) After 40 bbls pumped pressure increased to 280 psi, then climbed to1500 psi after
42.8 bbls pumped (fluid est. to be down 390 ft in annulus before fill up) after pump shut down pressure bled to
1470 in 10 sec. and 1425 in 30 minutes. PJSM. With cement pump break circulation test lines to 5000psi, pump
10 bbls water, + 23 bbls, cement while holding 780 psi on annulus, sting into retain'er and pump 17 bbls cement at
2.2 bbl/min and 400 psi. chase with 5 water and 8 bbls mud at 2 bbl/min and 500 þsi. Hesitation squeezed
remaining 13bbls cement in drill pipe over 6 squeezes of2 bbls / squeeze at 1 bbl/'min with pressure increasing
every squeeze by approx 50 psi each time, starting at 450 psi and ending at 700 psi. Between squeezes pressure
drop off was also approx 50 psi higher than previous drop-off. monitored for leaking bag or retainer (none.)
Pressure was fairly stable at 575 psi when we pulled out of retainer. Reverse out pipe volumes; saw 1 bbl cement
and all of spacer water: LD single, blow down lines, prepare to POOH.
1/1/05
LD 2 pup joints. And 14 working singles for drill out of retainers and cement. POOH. PU rig tongs, break and LD
cement stinger. Change out handling tools, MU bit, bit sub and 4 DCs. RIH t03460'. RU power swivel, hang
hydraulic hoses in derrick and hook up. RU mud cross on top of flow line. RIH tag retainer at 3485 WLM, 3496"
DPM, drill on retainer, mud pumps jack off shut down. Clean out rubber and junk from suction screen and under
mud pump, replace shaker screens. Continue to drill on retainer, and cement 3530' Broke thru, push and rotate to
3560', wash with out rotating to 3576'. Circulate and condition hole. RD power swivel and LD. RIH to 3616 to
ensure no cement stringers, continue to circulate and condition, rig for test of squeeze.
1/2/05
RU to pressure test squeezed perfs from 3493' to 3503'. Pressure test perfs at 3493 to 3503 using rig pump, pop
blew at 2300 psi, RU test pump, bring up pressure with rig pump to 2000 psi, shut in, bring up pressure with test
pump to 3000 PSI Shut in well. After holding pressure for more than 1 min, perfs broke down and bled to 600 psi.
Check all lines and possibilities, retest same, Establish injection rates. Circulate across mud cross at 2 bbl per
min no gains or losses noted. Blow down mud lines and choke manifold. Circulate and wait on cementers for
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 3
· ~queêze job. Pump dry job off of v... )ck. (Schlumberger arrive on location, Wf:.. )er job sib mix -mix water
ready to cement at 09:30 hrs). Pull on secondary flow nipple and install ware plate on flow nipple. Pull 6 stands,
run .in one joint with circulating head to 3288'. RU lines and manifold, run injection test at 3/4 bbl per min at 896
psi with 11.5 ppg mud. Pumped 5 bbl., pressure 10 see after pump was down 593 psi. one min after pump was
down 175 psi, pressure after another min 150 psi and starting to get stable. PJSM, Pump 3 bbls water and test
line at 3500 psi. Pump remaining 2 bbl of water. Pump 20 bbls Class G 15.8 ppg cement while holding differential
pressure on rig choke manifold as per DSM Pump schedule. Close choke at 20 bbl away and Squeeze. Pump
remaining 5 bbls of cement + 5 bbl of water + 23.7 bbls of 11.5 ppg mud. sa Pressure 575 psi 1 bbl per min
(squeeze last 1 0 bbl of displacement at 2 bbl intervals, shutting down for 5 min, switched to 1 bbl interval at 1/2
bbl per min shutting down for 5 min, until cement was displaced. (pressure would go to 800-1000 psi at times but
would break again) Shut down and let pressure bleed to a stable pressure of 250 psi. Monitor 5 min no change.
Switch over to rig pump and circulate tubing by casing volume at 2.7 bbls per min 500 psi. Holding 125 - 200 psi.
on ann ulus with rig choke. Shut down pump and close choke catching 200 psi on tubing and casing, Pressure
very stable Monitor pressure every Hour, pressure still 200 psi on casing and tubing, shut in choke line and stand
pipe, Bleed down surface lines. Wash up lines and blow down rig.
1/3/05
Continue WOC, install 611 flow line, and continue working pipe every half hour. PJSM, break circulation thru choke,
pressu re test squeeze to 21 OOpsi FROM 15 minutes (lost 10 psi rock solid). RU wash down from 3288' find hard
cement 3330', work pipe and circulate, blow down lines. LD single, pick up power swivel, break circulation. Pre-
treat mud for cement contamination. Drill firm cement (wob 5-6, rpm 120, pump at 4 bbl/min.) from 3330' to 3378',
break thru and wash 3488', drill cement from to 3488' to 3506', wash to 3512', past bottom perfs. Circulate and
condition mud, continue to treat for contamination. Test casing to 1100 psi, before break down INJECTS at 3/4
BBL per min 670 psi. Wash down from 3512' to 3543', CBU, blow down lines. RD. Pump dry job. POOH, 20
stands, mud in pits gelling up, unable to maintain hole fill circulation. POOH. Treat mud for cement contamination
while circulating over top of hole while tripping. .
1/4/05
Lay down BHA, (loose wheel on bit) pick up Halliburton fast drill and running tool. (check 13.3/611 x 711 annulus,
slight blow). RIH, with fast drill at 45-60 see/stand. Tong back up dies slipping, inspect and change. Continue RIH
to 3451', RU squeeze manifold, attempt to pump (trash under suctions and in valves), clean pump. Break
circulation, set retainer at 3447, shear out, stack 20k to set. Establish injection rate at 1 bpm and 675 psi., unsting
from retainer. Hold PJSM, pump 5 bbl water, test li·nes to 3k, bleed off, pump 10 bbls G cement, followed by 13
bbls cementlcimnet, hold from 250 to 750 psi on annulus while spotting cement to retainer, stab into retainer and
squeeze 7 bbls w/cimnet and 5 bbls G cement (total cement 35bbls) and 5 bbls water at 2.1 bbl/min with
pressure climbing after stabbing in from 900 to 1000 psi. Displace drill string with 12 bbls mud at 2.1 bbllmin and
pressure climbing from 1150 t01225 psi. Displace with additional 8 bbls mud at 1.1 bbl/min and pressure climbing
from 900 psi to 1125 psi at end of displacement. Reverse circulate 2 tubing volumes, saw 1-2 bbls cement and all
of water at shakers and slop tank. Blow down lines, L.D top single w/head pin. POOH. LD running tool and stinger,
PU 611 six bladed junk mill, with 2 boot baskets and 4drill collars RIH 52 stands ( 3397') PU power swivel, Continue
RIH and tag retainer at 3446' DPM. CBU and condition mud. WOC and work pipe and roll hole mud while
cleaning pits and going thru MP and suction screen and roll surface system across shaker with vac truck.
1/5105
Finish cleaning pits, pre-treat surface system for cel1]ent contamination. Dr~1I retainer from 3446' DPM to 3450'
rotary @ 1 DO, WOB @ 3-5, pump @ 3.1 bbl/min. (attempt different RPM and·WOB.) Drill hard cement from 3450'
to 3477' and varying parameters and massaging bottom and treating mud. Circulate 15 minutes, shut down and
change out shaker screen. Continue Drill hard cement from 3477' to 3485' and varying parameters and
massaging bottom and treating mud. Work on pump and chg/out all three rod packings. Continue Drill hard
cement from 3485' to 3516' and varying parameters and massaging btm and treating mud- fell thru and wash to
3522'. Circulate clean. Shut in and attempt to test Re-squeezed perf from 3493' - 3503' WLM - while monitoring
open 13-3/8" X 7" annulus - Pressure build to 1700 psi and broke back to 900psi @ 2.5 bbls away - up pump
speed to 1 bpm and continue pumping and building pressure to 2100 psi @ 10.5 bbls away - dn pump and with in
1 min psi @ 900 and 3 min @ 400 psi.
1/6/05
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 4
· ' . '), )
Blow down lines and LD. Power swivel: Rih to 3805'. Mix and spot balanced high VISC 10 bbl pill. POOH LD
working singles to 3514' and RU to circulate. CBU and balance same. Continue circulate. Generator feeding
Tioga down, DSM drain water from filters and put back on line, continue circulate until heat back to rig blow down
and drain lines. Monitor well (ok) LD 2 jts and pooh. Work BHA and clean and check same. PU and MU Howco
fast drill T' retainer and running tool. RIH to 3482'. Break circ and set retainer #5 @ 3480' DPM and test to 2000
psi - sheer off and extend stinger - stab retainer and' perform injection rate with rig @ 3/4 bpm @ 1820 psi with 3
bbls away - dn pump 30 sec 600 psi 1 min psi to 400 psi. Unsting and circ and discuss job and chg out crew.
1/7/05
Continue to circulate, hold PJSM with new morning tour crew, discuss squeeze, pumping alignments and
contingency plans for possibly having to reverse out a drill pipe volume of cement. Blow down mud lines, blow air
thru all lines needed for possible cement reversal, rig up to squeeze cement Break circulation thru choke,
pressu re test cement lines to 3500 psi, batch up cement tub to 15.8 ppg, pump 5 water, 10 bbl G and 1 0.5bbl with
2 ppb Cement holding 450 -900 psi on back side Shut down, sting into retainer, pump 14.5 bbls w/cement. Initial
pressu re was 1700 psi @ .75 bbllmin until 5bbl gone; it then broke back to approx 1000-1200 psi until 14 gone.
Displace with 5 bbls water and 19.5 bbls mud. Squeezed 3 times, last 10 bbls, @ 1.5 bbl/min and approx 400 to
800 psi. After each hesitation squeeze the pressure would bleed down to a value approx. 150 psi higher than the
previous time. Final pressure, pumps off before unstinging from retainer was @ 10 sec. 1000 psi and 1 minute
was 700 psi. Shut down, unsting from retainer, bleed pressure from,annulus. Line up to reverse circulate tubing,
approx 1.5 bbls cement taken back to junk tank. Continue tö circulate and build and pump dry job. RD Kelly and
hose and blow down lines. POOH, stand back drill collars; lay down fast drill running tool and stinger. Work BHA
(stand back drill collars, lay down and check fast drill running tool and stinger, ok). Blow down mud lines, pull
wear bushing, run test plug and fill stack with water. Test BOPs - hydril, choke manifold, manual kill and choke
wing valves and floor saf~ty valves to 250/3000 psi. 3.511 pipe rams failed test. Blow dn choke and all lines.
1/8/05
Finish Bop test, test stack. To 250/3000 psi, perform draw down test on Koorney. Blow dn all lines and choke
Rig back on day rate @ noon. Pull test plug/hanger, run wear bushing. Rig up floor, hang wind walls around stack
and cellar. Hook up kill line and gas buster line - Prep floor to PU DCs. PU 6" tooth bit, 2 drill collars (pre bucked
up), ru n 4 collars from derrick and LD tongs and PU power tongs. RIH with ph-6 drill pipe, checking each pin
shoulder for damage cau?ed by pulling into closed pipe rams. RIH to 3476' and tag retainer #5. RD power tongs.
1/9/05
Work on air supply restriction of control hose from power swivel to rig floor no go run new hose. Drill on retainer
#5 from 3476' to 3480'. Drill hard cement from 3480' to 3509' @ 5.5 min/ft with 7-8k wob and 80-120 rpm and'2.75
bpm (varying parameters for best results). Fell out of cmt @3509',( 5ft past top perf) to 3510'( torque up and take
wt.) make connection - rotate thru stringers from 3510'to 3517' ( 3 ft past bottom perf),pick up and wash down to
35441, Blow down mud lines. Lay down power swivel and 3 working singles. RIH, take wt @ 3974\ rig up and
circulate, apply weight and attempt to wash thru, will not pass 39741 circulate out hi-visc pill spotted from 3800' to
3514' (did not see pill), lay down head pin jnt and Blow down mud lines. PU power swivel. Drilling cement stringer
from 3974' to 3975' and fall thru and wash to 4012'. Make connection. Blow down and LD working single and
power swivel. RIH out of derrick tag @ 4877' work same to 4881'. PU power swivel. Brk Circ and have safety
stand dn - hold school and safety meeting on P/up and LD safety on Power swivel. Drilling cement stringer from
4881' to 48941 and fall thru and wash to 4913' - circulate and wait on relief.
1/10/05
PTSM. Make connection. Continue wash from 4913' to 49241 tag up and drill cement stringer from 4924' to 4932'
and fall thru and wash from 4932' - to 4947' and push to kelly dn @ 4948'. Attempt connect out of balance - circ to
balance. Make Conn. Continue Clean out hard cement stringer from 4948 to 4955', drill soft cement from 4955' to
4978' (cannot wash thru, but will not take wt. when rotating.) Attempt connection, flow back, circulate. To balance,
shut down pumps. Make Conn. @ 4978'. Drill soft cement from 49781 to 4981' drill firm cement from 4981' to
retainer @ 4989'. Drill retainer #2 from 4989' to 4993'. Drill soft cement from 4993' to 5002' @ 30 seclft with 7-8k
wob and 80-120 rpm and 2.75 bpm (6' into secondary perfs Adjusted to DPM) - Drill hard cmt from 5004' to 5009'
(from 7ft into secondary perf to 2 ft below secondary perfs @ 4997' to 5007' DPM est) @ 3 min/ft same
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 5
· parameters - Dropping MW as drilli,. )ogresses from 11.0 to 9.5, 10.2 @ prest.. )irc and take under flow from
shaker to suction for dry job for connection and make connection. Continue top drill hard cement @ same
parameters from 5009 to 5019@ 3 minI ft (2ft. Below bottom of secondary perfs to 6ft above top of bottom set
perfs) ROP picked up to 1 min/ft @ 5021' to 5037'(entire interval of bottom set of perfs @ 5025' to 5035' DPM est)
fell thru cement @ 5037'(2 ft below bottom perf) void continued to connection depth @ 5041'. Circulate to
balance, make connection, RIH w/o pumping FROM 5041' TO 5056', take wt, wash to 5072', make connection.
RIH wfo pumping to 5103'. Blow down, LD pwr swivel, and working singles. RIH and set dn @ 5522'. PU power
swivel. Drill hard cmt/junk from 5522' to 5523' fell thru wash to connection depth of 5539'. Circ and make
connection and wash from 5539' to tag @ 5545'. Drill retainer #1 from 5545' to 5547' ..; fell free - washed to conn
depth of 5570' (no cmt)- conn - washed to 5600' (no cmt) - conn -wash to 5632' (no cmt) - conn - Wash from
5727', RIH to 5765', completely void of cement below retainer, tag junk @ 5765', circulate.
1/11/05
Circulate hole, watch shakers for packer parts, finish MW cut back to 9.7, circulate even weight mud all around.
Air lines to rig control freezing up, adding methanol and functioning. Monitor well for flow, PJSM. Pump slug from
vac truck, blow down mud lines, lay down Power swivel. PU circ head and clear floor of rig tongs. CBU. Mix high
vis pill and Pump and spot 10 bbl on btm @ 5764' @ 9.8 Ppg with 35 ppb sea mud and 1 ppb XCD, Pooh to bit
depth of 5600'. CBU and polish off high vis pill @ 5600' (base of perfs). Pump dry job and blow dn lines and thaw
frozen lines. Pooh, stand back in derrick, lay down bit sub and bit. Bit in very bad shape, mill tooth very badly
worn, can see evidence of rotatipn on metaL Possible slips from retainers. PUHalliburton fast-drill retainer and
start into hole. Work on tongs BU not holding due to ice disassemble, steam, and coat with oil. RIH with. retainer.
1/12105
RIH slow with 7" Howco fast drill retainer. RU Kelly hose and break circ and blow down lines. Set Howco 7" fast
drill re1ainer @ 5535' and test same 500 psi on back side (ok) blow down. PJSM sheer off and extend stinger and
stab retainer. Establish 20 bbl injection rate 1 bpm @ 2240 psi (shut dn 10 sec 2058 psi, 1 min @ 2039 psi, 2 min
2030 psi, 3 min 2020 psi, 10 min 1986 psi, Bleed off with 7 bbl back). Unsting circ and blow down lines RU lines
for squeeze and check all lines for clear. Break circulation through choke, pressure test cement lines to 4000 PSI,
batch up cement to 15.8 ppg, pump 5 BBL water, followed by 18 BBL Class G Cement, catching 400 PSI initially
and holding 800 psi on back side at 18 BBL away, at 1.45 BPM rate, sting into retainer pump pressure rose to
1000 PSI, pump another 18 BBL of Class G cement at 1.45 BPM rate. The highest pressure seen was 1750 PSI,
at SO pressure was at 1350 PSI, pumped 5 BBL H2Q at 1 BPM, Pressure maintaining at 950 - 1000 PSI. SO Mud
line froze had to thaw. Pumped 20 BBL of 9.9 PPG mud to displace at 1.5 BPM rate starting pressure 800 PSI
ending pressure 1900 PSI. SO, pressure fell to 1550 PSI and maintained. waited 15 minutes on hesitation
squeeze, pumped 5 BBL mud at 1 BPM rate with ending pressure of 2250 PSI. SO pressure fell to 1950 PSI.
Waited 15 minutes on hesitation squeeze. Pumped another 9.5 BBL of mud with a final pump pressure of 2975
PSI. SO and pressure fell t02500 PSI. PU pipe and unsting from retainer. Pressure on casing rose from 800 PSI
to 1000 PSI and settled out at 900 PSI. Reverse circ to pits, when mud turned to water, divert cement to slop tank
(+- 2.5 bbls cmt back) 33.5 BBL Cement below retainer. Blow dn all lines a,ndchoke. Pump dry job from ISO tank
(no good) build and pump dry job - blow dn Iines.'POOH. PU bit and scraper; RIH with DC.
1/13/05
RIH with DC, and 2 stands of OP. RIH work scaper from 3163' to 3420' and from 4663' to 4920' continue into hole
and tag top of retainer at 5532'. LD two working singles and RIH with 1 stand, P/U power swivel (had problems
with hyd hoses). Drill HOWCO fast drill retainer #6 FROM 5532' to 5538' in about 1 hour looks like approximately
2' of cement below retainer. WOB 6K, 100 RPM, 3BPM, then broke free. Circulate and clean retainer setting area.
Wash down to 5636', Blow down and RO power swivel. RIH and tag at 5753' set 10K down, did not see any
resistance prior to tagging. LO single and PU Kelly joint with head pin. CBU had several BBLS of a very thick
viscous material with a very gritty texture to it come across shaker. Circulate and condition mud dropping weight
down to 9.5 PPG, and circulate around. Mix dry job, and monitored well for flow, prior to pulling out of hole. Blow
down. POOH stand back in derrick.
1/14/05
POOH - Work BHA - Blow down. PU champ packer, with single and XO on top, and make up on catwalk, hang
same in elevators. PU single joint 2 7/8" IBT tubing and set in slips with XO in top, MU same to bottom of champ
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 6
· packer hanging in ,elevators. RIH WI. :~ stands and PU multi-service tool and rv.. ~h single and XO, RIH with
another 49 stands (77 stands total with 2-singles) (1 HR WOO) Champ packer set at 4893'. RU squeeze manifold
and prep for negative pressure test, Pressure up on annulus to 500 PSI felt multi service valve open. Monitor
bubble hose for 25 minutes had a steady increase in flow. Bleed casing pressure off, pump down DP, @ 970
strokes start to pressure up, continue to pump until pressure reached 1000 PSI, line up to choke and bleed off.
PU on OP 3' to open bypass. Reverse circulate BU at approximately 1000 strokes had gas back to surface,
pumping through choke going to gas buster, circulate gas out and an additional BU. Switched over circulating
long way taking returns through choke going to gas buster. Circulate 2 BU with no sign of gas. Monitor well, mix
dry job, well out of balance tubing light, closed TIW valve. Valve leaked changed out same. Pump dry job, PU
power swivel break out TIW and saver sub lay down same. RU tongs and prep floor for laying down pipe
POOH laying down PH-6 tubing installing protectors on each end.
1/15/05
LO 3.5" PH-6 DP. RU manual rig tongs break out and lay down multi-service tool. RD and LO rig tongs. Continue
to lay down drill pipe, lay down Champ packer and 1 joint of 2 7/8" tubing. Trip in hole with DC from derrick and
lay down same. Trip in hole with drill pipe from derrick and lay down same. Change pipe rams from 3.5" to 2.875",
pull wear ring, MU test joint and set test plug, fill stack and choke with water. Test BOP, choke manifold, and floor
valves too 250 PSI low and 3000 PSI high. PJSM. Load pipe racks with 2 7/8" IBT tubing, sort and number tubing
(Slick - Centralizer joints) Pick up handling tools. PU and run 2 7/8" tubing, drift with 2.375 00 rabbit
.1/16/05
RU fill line and continue to RIH filling tubing going in to hole. RU Pollard to run chemical injection line PU mandrel
make up line and test same. Continue to RIH filling tubing, and banding chemical injection line, RIH and tag
bottom at 5749.95 pick up and space out, MU hanger terminate chemical injection line, land tubing and RILDS
28M up weight and 28M down weight. Total of 178 joints in hole. Total of 156 bands in hole. NU Install additional
7" casing x 2 7/8" tubing annulus valve on off side of tubing spool. Removed VR plug through valve after
installation. MU Lake Charles Cement head, PU and break out pups used for landing joints and test joints. RD
and LD Foster power tongs. RU squeeze manifold, RU annulus return line through choke going to shaker and
slop tank. Circulate and clean hole. PJSM. Pump 10 BBLs diesel down tubing for freeze protection on back side,
followed by 1 BBL mud to flush lines, blow down lines. Pump 3 BBL CW100 to fill and flush lines, and test cement
lines to 4000 PSI, bleed pressure off, pump an additional 7BBLS of CW100. Pump 30 BBLS of Mudpush XL @
10:5 PPG. SO and batch up lead cement slurry of 20 BBL of lite-crete with Cement at 12 PPG, pump same at 3.5
BPM, followed by an additional 33 BBLS of lite-crete (No Cement) pumping at 4.5 BPM rate. SD and batch up Tail
cement slurry of class G cement at 15.8 PPG. Batched up to 15.8 PPG, and pumped 2,5 BBLS of same with .
density flux from 14.9 to 16.4 PPG. SO, washed lines, dropped plug displaced with lease water. Bumped plug at
22.30 HRS, pressured tubing to 3500 PSI and held pressure for 10 minutes with no pressure loss, bled off
pressure and checked floats had 1/4 BBL of returns and float held.
Blow down and RD cement lines.
1/17/05
Pressure up and rupture disc at Chemical injection mandrel, (4300 PSI) continue to pump and clear area of any
residual cement. Clean floor, RO Cement head and lay down same, start to clean pits. RU Pollard Wireline
RIH with temp survey tools to 5000' logging in and out at 60' per minute 5 minute stop at hanger and at 5000'.
Power wash stack and prep for NO. LO landing joint and Set 2.5" CIW H BPV. NO BOP equipment including riser.
Freeze protected 13-3/8" X 7" by Pumping 3.5 bbls Diesel into annulus with test pump work psi @1500 psi broke
and fell to 500 psi and built back to 1000 psi @ shut dn 800 psi and shut valve. NU tree and Test hanger void to
5000 PSI held for 15 minutes with chemical injection port open with no leak. Pull BPV and set TWC test tree to
5000 PSI held for 15 minutes no leaks. Pull TWC and freeze protect tree using diesel fuel. Install BPV. Release
rig at 18:00
Lay felt and liner at relief pad to stack rig out on, blow down boiler, continue with pit cleaning and disposal of
solids, palletize equipment and prep to move.
1/19'05
Using triplex test pump and pumping diesel pressure 7" casing x 2 7/8" tubing annulus to 2000 PSI, SI an hold
pressure for 30 minutes with a 50 PSI pressure drop. Bleed pressure off. Pollard RIH with 2.35" GR tagged at
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 7
,. 5601i"WLM which is 91' high. Notic.. )me anomalies with counter, POOH, frol. )t were counter was to zero
towhere it topped out 100' off. Pickell up lubricator and run tool string down to LOti counter off 90'. RIH second
time to verify counter discrepancy, put heater on counter to try and keep it from locking up, Tagged at 5697' WLM
POOH cement LC at 5692' pipe measurement. Lay down lubricator and secure well.
1/20/05
Test BOP to 250 PSI low and 5000 PSI high. PJSM. RIH with coil, while cooling down taking returns to Johnson
tank. Start to pump N2 at 240 SCM per minute, monitoring returns in Johnson tank. Tag bottom at 5686', PU 5'
and increase rate to 600 SCFM rate, max pressure 2580 PSI monitoring returns, at calculated returns had N2 to
surface, put on choke and continued to blow for 10 minutes. POOH, trapping 1800 PSI on tubing, remove injector
head and spooling up coil. NO BOP, stage BOP and injector in transportation rack. Secure well.
1/21105-1/23/05
RD/MO
1124/05
Schlumberger out at 06:00 hrs spot equipment and start to rig up, had PJSM, complete Unocal explosives and
perforating check list, arm guns, ,NU, test lubricator to 250 PSI low and 3000 PSI. RIH using Schlumberger
Ultrasonic Imager Log dated 9/21/94, tie in to perforate from 5555' to 5567'. Confer with Meg Kremerprior to
perforating. Fired guns at 10:12 HRS had N2 cap of 1778 PSI, within 5 minutes had pressure of 1955 PSI and
built up to 1958 overthe next 30 minutes. Schlumberger POOH all guns had fired, rigged down and departed
field. Turned well over to production.
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 8
I( STATE OF ALASKA ('
ALASK. JlL AND GAS CONSERVATION COMMIS N
1a. Well Stat~EL;gOM~~6T~I~g~ gR A~r;o~~MP~:pTn~~~ ~lli~~D LOG
20AAC 25.105 20AAC 25.110 Development 0 Exploratory 0
GINJ 0 WINJ 0 WDSPlD No. of Com'ple~!o~s .,IÓthe~ Service 0 Stratigraphic Test 0 .
2, Operator Name: . 5. Date Com·p., Susp., or 12. Permit to Drill Number: 4I!-:.,-..
Union Oil Company of California Aband.: 10/3/04 94-84::509 -5Be> 9~" :
3. Address: 6. Date Spudded: 13. API Number:
PO Box 196247, Anchorage, AK 99519 n/a 50-133-10141-01
4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number:
Surface: 2300 ~L, 1040 FIL, Sec. 15 T8N R9W L,/.. ~ nla SRU 32A-15
Top of Productive Horiz~rl ~ ßIi-' 9/t:J7to ~ 8. KB Elevation (ft): 15. Field/Pool(s):
~ £J 15' Swanson River Fieldl
Total Depth: 2286 ~L, 3161 il, Sec. 15 T8N R9W 9. Plug Back Depth(MD+TVD): Tyonek
7,336'/7,250' Hemlock
10. Total Depth (MD + TVD): 16. Property Designation:
5,75015,744' Swanson River
11. Depth Where SSSV Set: 17. land Use Permit:
nla A-028384
19. Water Depth, if Offshore: 20, Thickness of Permafrost:
nla feet MSL nla
4b. Location of Well (State Base Plane Coordinates):
Surface: X = 348,884, Y = 2,480,047
TPI:
Total Depth: X = 351,036, Y = 2,480,023
18. Directional Survey: Yes 0 No I 0
21. logs Run: nla
22,
CASING WT. PER GRADE
FT.
22"
13-3/8" 54.5 K-55
7" 26, 29 P-110/N-80
5" 18 l-80
CASING, LINER AND CEMENTING RECORD
SETTING DEPTH MD SETTING DEPTH TVD
TOP BOTTOM TOP BOTTOM HOLE SIZE
o 45' 0 45'
o 2,958' 0 45'
o 10,257' 0 9938' '
9,971' 11,590' 9672' 11187'
CEMENTING RECORD
AMOUNT
PULLED
see schematic attached
18-5/8"
10-5/8"
6"
23. Perforations open to Production (MD + TVD of Top and Bottom
Interval, Size and Number; if none, state "none"):
Top Bottom Amt SPF Zone Comments
5,555' 5,567' 12' 56-0 Beluga
7,267' 7,282' 15' 6 68-0 Upper Lobe P&A 10/24/04
7,358' 7,398'40' 6 68-0 Lower lobe P&A 10/24/04
24. TUBING RECORD
SIZE DEPTH SET (MD) PACKER SET (MD)
2-7/8" surface-5,727' cement pkr.
2-7/8",2-3/8" 6,000-9,766',11,256' 11,186'
25. ACID, FRACTURE, CEMENT SQUEEZE, ETC.
DEPTH INTERVAL (MD) I AMOUNT AND KIND OF MATERIAL USED
see schematic
26. PRODUCTION TEST
Date First Production: Method of Operation (Flowing, gas I i,ft , etc.):
January 30, 2005 Flowing
Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF:
1/25/2003 28 Test Period ..... 0 1,076
Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF:
Press. 1705 not available 24-Hour Rate -tÞ- 0 923
27. CORE DATA
Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary).
Submit core chips; if none, state "none".
nla
unmeasured
Choke Size: Gas-Oil Ratio:
8-12 (1/64) nla
Oil Gravity - API (corr):
rila
Water-Bbl:
Produced water
Water-Bbl:
Form 10-407 Revised 12/2003
CONTINUED ON REVERSE
28.
GEOLOGIC MARKERS (
MD
TVD
NAME
GlaciaLBase_MJF
Tks_ YELLOW
A9
B2B
Beluga
41-4ST
Mid_Beluga_MJF
50-6ST
L.L._ Tnk_MJF
D1CT
61-BST
66-3STE
70-BCT
mtl_mark
BO-2ST
E10
Hemlock_MJF
TD
591
1,472
2,561
3,029
3,504
4,121
4,591
5,OOB
5,514
6,050
6,561
7,046
7,524
B,067
8,555
9,247
11,272
11,590
591
1,472
2,561
3,028
3,503
4,120
4,590
5,007
5,511
6,038
6,526
6,981
7,422
7,920
8,367
9,007
10,887
11,1B7
29.
FOR~'
,ON TESTS
Include and briefly summarize,' results. List intervals tested, and attach
detailed supporting data as nec.::ssary. If no tests were conducted, state
"None".
nla
30. List of Attachments:
summary of morning reports, schematic.
31. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact: Steve Tyler 263-7649
Title: Acting Drilling Manager
Printed Name: T~im C. Brandenburg h ~/:?
.-" (/::'~"
Signature - ~_ , C -..? IN:;:~C:I:~:7600
Date: 3/9/2005
Follow up to Sundry 304-388
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-A07 well compietiot'l repòrt.and 10-404 well sundry report when the
·downhole well design is changed.
Item 1 a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply
for I njection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production
from each pool completely segregate~. Each segregated pool is a completion.
Item 4b: TPI (Top of Producing Interval).
Item ,8: The Kelly Bushing elevation in feet above mean low low water. Use same as r~ference for depth measurements given in other
spaces on this form and in any attachments.
Item 20: True vertical thickness.
Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
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 reported 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: If no cores taken, indicate "none",
Item 29: List all test information. If none, state "None".
Form 10-407 Revised 12/2003
)Ii -=~
UNOCAL.
B
~.
.
ð
~~
®i:
u
~
RKB =15.0'
.-
~
C
~
·lb.
e
~
:¿
@
u
o
¡...
SRU 32A-15 FINAL.:...01-15-05
Size
22"
13-
3/8"
DV Collar
13-
3/8"
7"
Grade
Type
Conductor
Wt
Surf Csg
54.5
SurfCsg
54,5
..lL
26
~
~
29
26
7"
7"
7"
7"
7"
DV Collar
7"
7"
5"
Prod Csg
Prod Csg
~
29
IS
Liner
Tubing
2-7/8"
27/S"
2 3/S"
Casing &
Thrd ID
K-55
K-55
12.615
6.184
6.276
6.184
6.276
Srd 6.184
6.276
P-IIO
N-80
P-IIO
P-I ]0
L-80
Buttress
15.0' Original RKB to Tbg Hngr
6.4 N-80 Buttress
6.4 N-80 Buttress
4.6 N-80 Buttress
t
Swanson River
Well SRU 32A-15
As Completed 1/24/05
6" 500 1 ] ,250'
..
12.615
Tubing
Top Btm
Surf 45'
Surf 964'
964' 967'
967' 295S'
Surf 39'
39' 2097'
2097' 3439'
3439' 615S'
6158' 7933'
7933' 8467'
8467' 8470'
8470' 9789'
9789' 10,257'
1000
sxs
Cmt Top
Surf.
Surf
2]44'
(Calculated)
6495'
CBL
9399'
Calculated
JEW E LR Y DETAIL
NO, Depth ID OD Hern
16.44' Tubing Hanger, F'MC Type TCM 7 1/16" OD x 2 7/8" EVE
11ft and suspension, WI Cont Cont Line
A. 2491' 2.363 Chem Inj Sub
B. 5692' BOT 3-112" Lalldlng Collar wI XO's to 2-7/8" box & Pin
C. 5727' BOT 3-1/2" IIJoal Shoe wI XO Ie) 2-718" box
D. 5750' CIBP
E. 6000' Cut tubing
GLM #1. 6220' 2.347 5,5" x 4,673" Cameo MMG-P GLM
GLM #2. 6891' 2.347 5.5" x 4.673" Cameo MMG-P GLM
F. 7000' Tbg. plug
I. 7345' EZ Drill CJDP
GLM #3. 7597' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #4. 8303' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #5. 9039' 2.347 5.5" x 4.673" Cameo MMG-P GLM
2. 9300' Cmt Retainer (TOC III tbg)
3. 9717' Cmt Retainer
GLM #6. 9726' 2.347 5.5" x 4.673" Cameo MMG-P GLM
4. 9766' 1. 995" 3.503" Crossover, 2-7/8",EUE 8rd x 2-3/8" EUE 8rd
5. 10,448' 1.875" 3.065" Otis "XA" Sldg Slve
GLM #7. 11,149' 1.875" 4.125" x Cameo KBMG-2 GLM
2.781"
6. 11,186' 2.55" Otis "BWD" Pkr
7. 11,226' 1.875" 2.701" Otis "X" Profile Nipple
8. 11,256' 2.32" 2.872" WLEG
Hole
Cmt
Yes
18-
5/8"
1000
sx
600 sx
1000
10-
5/8"
sx
Thru
DV@
R467'
6.276
6.184
4.276
9971 '
11,590
2.441
2.441
1.995
Surf
6000'
9,766'
5727'
9766'
1],256'
PERFORATI.ON HISTORY
Interval
Top Btm
3,493' 3,503'
4,986' 4,996'
5,014' 5,024'
5,545' 5,555'
5,555' 5,5'67'
5,590' 5,600'
7,267' 7,282'
7,358' 7,398'
11,326' 11 ,336'
11 ,340' II ,346'
11,354' 11,364'
Amt
10'
10'
10'
10'
12'
10'
15'
40'
10'
6'
10'
Accum.
spf
6
6
6
6
6
6.0
6,0
Comments
Sqz Perfs
Sqz Perfs
Sqz Perfs
Sqz Perfs
56-0 Beluga
Sqz Perfs
68-0 Upper Lobe. P&A'd 10/24/04
68-0 Lwr Lobe. P&A'd 10/24/04
P&A
P&A
P&A
REVISED: 01/24/05 by SL T
ii
10129104
Spot equipment RU and test to 2500 PSI. RIH with 2.25" DO Bailer and tag fill at 73301 KB recovered 1 cup of
sand. RIH with 2.32" gauge ring and tag fill at 7330' KB. RIH w/2 1/2" SB&A stop set at 7000' KB POOH. RIH with
2 1/2" GS and Pack off plug set at 6999' KB POOH. RIH and make 6 dump bailer runs using a 9' x 2.25" bailer,
dump bail cementfrom 6995' to 6960' 10 gallons. RD Pollard
1111104
RU Schlumberger. PT top of cement plug to 3000 PSI held for 20 minutes, bleed off pressure. RU APRS unit
using Pollard mast truck, test lubricator to 3000 PSI. Have PJSM. RIH with 2.25 jet cutter and tagged top of
cement plug at 6974' Tagged witnessed by Jeff Jones with AOGCC. PU using CCl found center of joint at 6012',
pressured up to 500 PSI, fired cutter had good indication of firing, tubing fell to zero PSI instantly, POOH. Jug test
wellbore to 3000 PSI for 30 minutes held good. With APRS RD, Schlumberger start pumping down the tubing
taking returns, CBU, (water clean for produced.) Freeze protect annulus and tubing. Pump 5 bbls down backside,
and .5 BBlS down tubing.
12122104
RU, Clean snow from Koomey, Tioga, choke hose and other. Prep area for SlB Cementing foot print.
12123104
RU, PJSM, NO tree, and NU 7 1/16" 5M BOP, Choke line and Kill line. Function test same. Move drillers console,
Make up 2 7/8" test joint. Test Annular, 2 7/8" Rams, Blind rams, choke line valves, kill line valves, choke manifold
and all floor valves to 250/3000 psi. Test gas detectors. AOGCC waived witness to BOP Test. Set cat walk and
pipe racks. RU floor to pull tubing.
12/24/04
Back out lock downs and check annulus for pressure. Pull hanger free, took 95 kip to finish tubing cut. Pull hanger
to rig floor up wt 38 kip. Lay down hanger and pups; make up head pin and CBU. Had some bubbles, shut
annular and went through choke manifold and gas buster, pit level dropped enough for charge pump to loose
prime. shut down and blow down lines. Finished CBU. POOH, LD 2 7/8" tubing. Recovered 188 joints + cut off
joint + 5 puped GLMs + 3 Space out pups and tubing hanger. Wire line cut was made at 6012' (did not Strap out
of hole, went off of joint count, pipe came out. Change rams from 2 7/8" to 3 1/2". Test pipe rams and floor valves
,to 250/3000 psi. Blow down and freeze protect test pump. RU to handle BHA and 4 3/4" Drill collars. Pick up 6" bit
7" 29# casing scraper and 4 3/4" Drill collars
12/25/04
Change out handling equipment to handle 3 112" PH-6 and Clear off rig floor. RIH bit and scrapper on 3 1/2" PH-6
Tubing. Thaw and Drift pipe with 2.312' rabbit. Continue RIH with bit and scrapper to 5824, (182 total joint 3 1/2"
12.60 # PH-6) RU to change over well bore fluids from 8.4 PPG lease water to 11.7 PPG mud. PJSM. Displace
well bore with 11.7 ppg water base mud, taking lease water returns to Johnson tank. After displaced take returns
back to active system until we had a 60 bbl surface volume. Circulate at 2 bbl per min over shaker; pump
performed well out of big tank and vac trucks. Blow down all surface line and RU choke line. POOH 53 Stands to
2513'. RU floor to make up storm packer.
12/26/04
Run in storm packer and set same 121 below well head, shut pipe rams and test storm packer to 500 psi, back out
joint and close storm valve. Lay down same. Clear off floor, RD floor and prep to ND BOP (includes vac out and
clean cellar). Nipple down BOP, remove choke and kill lines. Stump up BOP until ready to NU. Checked voids on
old tubing spool for any trapped pressure. After inspection found 7" 29 PPF casing stub to be badly Kelly worn.
Checked annulus between surface casing and 7" production casing for any pressurefound none, checked for any
LEL and found none. With constant LEL monitoring pulled casing hanger seal and replaced with new. NU new
remanufactured tubing spool, and tested void to 2500 PSI, held for 10 minutes. Nipple up BOPs. RU rig floor.
Make up two-way check set tubing hanger and shell test stack, choke line and kill line against blind rams at
SRU 32A-15 morning report summaryAFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 1
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250/3000 psi (good test) RU rig tori"\:,~ to lay down storm valve. PU joint of PH-6, ..1 retrieving tool, screw into
storm valve, open Safety valve and check for pressure (none). Unseat storm packer up wt 30 kip. LD same. LD
rig tongs. POOH FROM 2513' - 1073'.
12/27/04
Continue POOH 3 1/2" PH-6 to drill collars. LD hydraulic tongs, RU manual tongs, slip bowl and 4 3/4" drill collar
slips. (lay down bit/scrapper) rack drill collars 2 stands. Blow down rig, Nipple down flow nipple and clean out stud
holes to accept studs for shooting flange, RU line from surface casing x 7" casing annulus to choke. PJSM. RU
Schlumberger. PJSM pull tools to floor and PU 7" HES EZ drill CIBP, RIH to 5770' logged up found collar at 5752'
dropped down and logged back up set EZ drill at 5760', setting tool fired at 11: 15 HRS POOH. RU WL BOP found
bad spot in E-Line and SWS rehead. Arm guns and stab up, test to 2000 PSI against EZ drill, held 10 minutes
bleed off pressure. RIH with 2- 10' guns 2" hsd, 6 shots perlft set for selective fire. Make tie in pass. Tie in to
Schlumberger ultrasonic imager log dated September 21-1994. Pressure up on 7" annulus to 1500 psi. Perforate
from 5590' - 5600'. Pressure dropped to 600 psi when gun fired. pull up hole 500'. Attempt to circulate, pump at 1
bbl per min pressure increased to 1740 psi and maintained a rate of 1 bbl per min and put away a total of 10 bbl,
shut down pump. Pressure after 10 sec was 1650 psi. Drop back down tie in and perforate from 5555' - 5545'.
With 1350 psi on 7" annulus, saw no change in pressure when guns fired. POOH with perf guns. Lay down guns
all shots fired. Close blind rams. Attempt to circulate (no go)results were the same pumped 8 bbls away at 1750
psi at 1 bbl per min. Shut down pump, pressure 10 sec after shut down was 1650 psi, and 1242 psi 30 min after
shut down. Bleed off pressure and blow down all lines. Make up setting tool arm same. Make up 7" Halliburton
Fast drill retainer. RIH, Tie into log and set retainer at 5535'. POOH with perf guns. LD guns all shots fired. LD
tools and RD Schlumberger, start nipple down shooting flange.
12/28/04
Continue RD Schlumberger wire line. NO shooting flange and nipple up flow nipple and install flow line. MU
Halliburton Fast drill cement stinger. RIH cement stinger on 3 1/2" 12.60 # PH-6 Tubing. (Thawing out pipe) Make
up single and tag at 5544' tubing measurements, current RKB. Retainer set at 5535 Wire line measurements.
Space out for cement job, ended up with tool joint in annular at the same time stinger stabs into retainer, RU
stand pipe hose and head pin. Break circulation stab in and perform injection test at1 bbl per min 1740 PSI. with
rig pump. Pump 4 bbls, no returns noted in 7" annulus. Close annular and pressure up to 650 psi and perform
stab in test and adjust annular to 500 psi or less. PJSM. Break circulation with Schlumberger pump 3 bbls water
shut down and test line to 5000 psi. (good test) pump 2 bbls water for a total of 5 bbl a head of cement. Batch up
cement to go down hole. Pump 21 bbls 1.5,8 ppg cement slurry holding 650 psi back pressure with rig choke
manifold, pump 5 bbl water + 12 bbls of 11.6 ppg w~ter based mud. Shut down and stab in retainer (held 650 on
back side during squeeze no pressure change during squeeze) squeeze cement away with 23.4 bbls 11.6 ppg
water based mud at 3 bbl per min 2000 psi, slowed to a rate of 1 bbl per min 1540 psi, last 4 bbls away. Shut
down pump and unsting from retainer. pressure 10 sec after pump shut down was 1504 psi. Reverse circulate 2
tubing volumes, got back unexpected cement took returns to junk tank, gauged ta'nk. Recovered 12 bbls of
,contaminated mud, cement, and water. Pump dry job and blow down rig. POOH and Lay down stinger. RU
shooting flange.
12/29/04
RU shooting flange, wireline lubricator and grease head, pick up GR/CCL tool and two 10' ft 2", 6 shot / ft HDS
perf guns, set for selective fire. Pressure test wireline lubricator and BOPs to 2000 psi, hold pressure for 10
minutes. (good test). Blow down and drain lines, RIHwith wireline. Make tie in pass, tie into Schlumberger
ultrasonic imager log dated Sept 21 1994, made 2 passes to correlate bottom gun to fire from 5014' to 5024' Line
up mud pump to pump down drill pipe and attempt to take returns thru perfs at 5014'-5024' up 7." x 13.625"
annulus through choke to rig pits. Pressure up annulus to 1500 psi, shoot perf gun at 5014' to 5024' Lost pressure
from 1500 psi to 350 psi over 10 seconds; pull wireline up to 4800', Bring up rig pumps to 1.2 bbl/min and 1080
psi, attempting to circulate thru new shot perfs up 13.625" x 7" annulus, thru choke, monitoring for returns at slop
tank, increase pump rate to 2 bbl/min with no increase in pressure, (injecting) shut down and monitor pressure
after pumping total of 8-9 bbls. correlate wire line 'for'next shot. (pressure d'ropped from 1000 psi to 750 psi over
25 minutes.) Shoot perfs from 4986' to 4996' while holding 1000 psi on DP x 7" annulus, seen very slight drop in
pressure as guns fired and[pressure remained at 700-900 psi as POOH with wireline. Blow down mud lines, RD
log/perf wireline assembly RU to run on wireline Halliburton 7" Fast drill cement retainer. RIH with wireline. Tie in
to Schlumberger ultrasonic imager log dated 9/21/94. Set Halliburton fast drill retainer at 4979', POOH and RD
SRU 3.2A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 2
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wire line. ND shooting flange and ii, ,.;ill flow line. Make up fast drill cement sting ..md RIH. (thawing out ice plug
in pipe,) RIH to 4950', PU 5' and 10' pup joints and single joint with head pin, park at 4965', RU squeeze manifold
and pump lines. Hold PJSM, break circulation thru choke, stab into fast drill retainer, mark pipe, pressure test
cement lines to 3.5k, pull out of retainer, pump 5 water ahead, 100sx ( 21 bbls) 15.8 class g cement, displace
w/5bbl water, 8 bbl mud, hold 450 -750 psi on annulus while spotting cement to retainer. Stab into retainer and
squeeze away cement at 2.5 bbls/min and 1450 psi, last 8 bbls squeezed pressure increased from 1450 psi to
1900 psi with pump rate same. Pressure bled to 1250 when pump shut down, continued 100 psi bleed off/minute
over next 5 minutes. Pull out of retainer, Reverse circulate two tubing volumes Saw 1 bbl cement and several bbls
clabbered up mud total of 9 bbls dumped. Drain up and blow down lines, RD Schlumberger.
12/30104
LD pup joints and working single, secure well. Drain .and blow down pump lines. POOH, lay down cement stinger
Blow down lines (wear bushing was pulled by drag blocks on cement stinger as it passed by. Cut and slip drilling
lines, change out 50' choke hose for 30' hose to Reduce trip and freeze up hazards. Make up test joint and XOs
and test plug/hanger. Pull wear bushing. Test BOPs, choke equipment, floor/dart valves to 250/3000psi, draw
down test on Koomey (good tests). Blow down lines.
12/31/04
Attempt to run wear bushing, pull wear bushing will èvaluate after wire' line. RU shooting flange, wireline BOPs,
Lubricator and wireliners. Hold PJSM, Arm perf guns and CCL, pick up and stab inside lubricator, pressure test to
2000 psi for 5 minutes (good test). RIH, tie into ultrasonic imager log from 9/21/94. Pressure up annulus to 1500
psi and hold, spòt 10ft, 2", 6 sp/ft HSD power jet perf guns and shoot 34931 - 3503'. Press. dropped to 30 psi 1
min. after shot. Pump at 1 bbl/min, pressure gradually increased to 1480psi after 10 bbl away. shut down, 10sec
1098 psi and 1 min to 280 psi. No indication of any returns from the 7" x 13 5/8 annulus during pumping. Blow
down lines. POOH with wireline, PU Fast drill retainer, set at 3485' POOH LD wireline and RD shooting flange
'and lubricator. RU new built 6" flow line spool, in place of current spool, run wear bushing. PU. Cement stinger,
RIH to above cement retainer, break circulation, sting into retainer establish circulation at 1.25 bbl/min pressure
climbed to 525 psi then broke back to 388 psi after 9 bbls injected. Shut down 10 sec pressure dropped to 152
psi, 1 min 122 psi. RU to pump down 7" X 13 3/8" annulus with lease water, pumped down annulus 30 bbls before
seeing any pressure (25 psi,) After 40 bbls pumped pressure increased to 280 psi, then climbed t01500 psi after
42.8 bbls pumped (fluid est. to be down 390 ft in annulus before fill up) after pump shut down pressure bled to
1470 in 10 sec. and 1425 in 30 minutes. PJSM. With cement pump break circulation test lines to 5000psi, pump
10 bbls water, + 23 bbls, cement while holding 780 psi on annulus, sting into retainer and pump 17 bbls cement at
2.2 bbl/min and 400 psi. chase with 5 water and 8 bbls mud at 2 bbl/min and 500 psi. Hesitation squeezed
remaining 13bbls cement in drill pipe over 6 squeezes of2 bbls I squeeze at 1 bbl/min with pressure increasing
every squeeze by approx 50 psi each time, starting at 450 psi and ending at 700 psi. Between squeezes pressure
drop off was also approx 50 psi higher than previous drop-off. monitored for leaking bag, or retainer (none.)
Pressure was fairly stable, at 575 psi when we pulled out of retainer. Reverse out pipe volumes; saw 1 bbl cement
and all of spacer water. LD single, blow down lines, prepare to POOH.
1/1/05
LD 2 pup joints. And 14 working singles fot drill out of retainers and cement. POOH. PU rig tongs, break and LD
cement stinger. Change out handling tools, MU bit, bit sub and 4 DCs. RIH t03460'. RU power swivel, hang
hydraulic hoses in derrick and hook up. RU mud cross on top of flow line.RIH tag retainer at 3485 WLM, 3496"
DPM, drill on retainer, mud pumps jack off shut down. Clean out rubber and junk from suction screen and under
mud pump, replace shaker screens. Continue to drill on retainer, and cement 3530' Broke thru, push and rotate to
3560', wash with out rotating to 3576'. Circulate and condition hole. RD power swivel and LD. RIH to 3616 to
ensure no cement stringers, continue to circulate and condition, rig for test of squeeze.
1/2/05
RU to pressure test squeezed perfs from 3493' to 3503'. Pressure test perfs at 3493 to 3503 using rig pump, pop
blew at 2300 psi, RU test pump, bring up pressure with rig pump to 2000 psi, shut in, bring up pressure with test
pump to 3000 PSI Shut in well. After holding pressure for more than 1 min, perfs broke down and bled to 600 psi.
Check all lines and possibilities, retest same, Establish injection rates. Circulate across mud cross at 2 bbl per
min no gains or losses noted. Blow down mud lines and choke manifold. Circulate and wait on cementers for
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: ,last revised 3/8/2005, Page 3
it.
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squeeze job. Pump dry job off of v~ .ruck. (Schlumberger arrive on location, WI:.. over job sib mix -mix water
ready to cement at 09:30 hrs). Pull off secondary flow nipple and install ware plate on flow nipple. Pull 6 stands,
run.in one joint with circulating head to 3288'. RU lines and manifold, run injection test at 3/4 bbl per min at 896
psi with 11.5 ppg mud. Pumped 5 bbl., pressure 10 see after pump was down 593 psi. one min after pump was
down 175 psi, pressure after another min 150 psi and starting to get stable. PJSM, Pump 3 bbls water and test
line at 3500 psi. Pump remaining 2 bbl of water. Pump 20 bbls Class G 15.8 ppg cement while holding differential
pressure on rig choke manifold as per DSM Pump schedule. Close choke at 20 bbl away and Squeeze. Pump
remaining 5 bbls of cement + 5 bbl of water + 23.7 bbls of 11.5 ppg mud. SQ Pressure 575 psi 1 bbl per min
(squeeze last 10 bbl of displacement at 2 bbl intervals, shutting down for 5 min, switched to 1 bbl interval at 1/2
bbl per min shutting down for 5 min, until cement was displaced. (pressure would go to 800-1000 psi at times but
would break again) Shut down and let pressure bleed to a stable pressure of 250 psi. Monitor 5 min no change.
Switch over to rig pump and circulate tubing by casing volume at 2.7 bbls per min 500 psi. Holding 125 - 200 psi.
on annulus with rig choke. Shut down pump and close choke catching 200 psi on tubing and casing, Pressure
very stable Monitor pressure every Hour, pressure still 200 psi on casing and tubing, shut in choke line and stand
pipe, Bleed down surface lines. Wash up lines and blow down rig.
1/3/05
Continue WOC, install 6" flow line, and continue working pipe every half hour. PJSM, break circulation thru choke,
pressure test squeeze to 2100psi FROM 15 minutes (lost 10 psi rock solid). RU wash down from 3288' find hard
cement 3330', work pipe and circulate, blow down lines. LD single, pick up power swivel, break circulation. Pre-
treat mud for cement contamination. Drill firm cement (wob 5-6, rpm 120, pump at 4 bbl/min.) from 3330' to 3378',
break thru and wash 3488', drill cement from to 3488' to 3506', wash to 3512', past bottom perfs. Circulate and
condition mud, continue to treat for contamination. Test casing to 1100 psi, before break down INJECTS at 3/4
BBL per min 670 psi. Wash down from 3512' to 3543', CBU, blow down lines. RD. Pump dry job. POOH, 20
stands, mud in pits gelling up, unable to maintain hole fill circulation. POOH. Treat mud for cement contamination
while circulating over top of hole while tripping.
114/05
Lay down BHA,(loose wheel on bit) pick up Halliburton fast drill and running tool. (check 13.3/6" x T' annulus,
slight blow). RIH, with fast drill at 45-60 see/stand. Tong back up dies slipping, inspect and change. Continue RIH
to 3451', RU squeeze manifold, attempt to pump (trash under suctions and in valves), clean pump. Break
circulation, set retainer at 3447, shear out, stack 20k to set. Establish injection rate at 1 bpm and 675 psi., unsting
from retainer. Hold PJSM, pump '5 bbl water, test lines to 3k, bleed off, pump 10 bbls G cement, followed by 13
bbls cemenUcimnet, hold from 250 to 750 psi on annulus while spotting cement to retainer, stab into retainer and
squeeze 7 bbls w/cimnetand 5 bbls G cement (total cement 35bbls) and 5 bbls water at 2.1 bbl/min with
pressure climbing after stàbbing in from 900 to 1000 psi. Displace drill string with 12 bbls mud at 2.1 bbl/min and
pressure climbing from 1150 t01225 psi. Displace with additional 8 bbls mud at 1.1 bbl/min and pressure climbing
from 900 psi to 1125 psi at end of displacement. Reverse circulate 2 tubing volumes, saw 1-2 bbls cement and all
of water at shakers and slop tank. Blòw down lines, ~D top single w/head pin. POOH. LD running tool and stinger.
PU 6" six bladed junk mill, with 2 boot baskets and 4drill collars RIH 52 stands ( 3397') PU power swivel, Continue
RIH and tag retainer at 3446' DPM. CBU and condition mud. WOCand work pipe and roll hole mud while
cleaning pits and going thru MP and suction screen and roll surface system across shaker with vac truck.
1/5/05
Finish cleaning pits, pre-treat surface system for cen:)ent contamination. Drm retainer from 3446' DPM to 3450'
rotary @ 100, WOB @ 3-5, pump @ 3.1 bbl/min. (attem"pt different RPM arid·WOB.) Drill hard cement from 3450'
to 3477' and varying parameters and massaging bottom and treating mud. Circulate 15 minutes, shut down and
change out shaker screen. Continue Drill hard cement from 3477' to 3485', and varying parameters and
massaging bottom and treating mud. Work on pump and chg/out all three rod packings. Continue Drill hard
cement from 3485' to 3516' and varying parameters and massaging btm and treating mud- fell thru and wash to
3522'. Circulate clean. Shut in and attempt to test Re-squeezed perf from 3493' - 3503' WLM - while monitoring
open 13-3/8" X r annulus - Pressure build to 1700 psi and broke back to 900psi @ 2.5 bbls away - up pump
speed to 1 bpm and continue pumping and building pressure to 2100 psi @ 10.5 bbls away - dn pump and with in
1 min psi @ 900 and 3 min @ 400 psi.
1/6/05
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 4
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Blow down lines and LD. Power swivel. Rih to 3805'. Mix and spot balanced high vise 10 bbl pill. POOH LD
working singles to 3514' and RU to circulate. CBU and balance same. Continue circulate. Generator feeding
Tioga down, DSM drain water from filters and put back on line, continue circulate until heat back to rig blow down
and drain lines. Monitor well (ok) LD 2 jts and pooh. Work BHA and clean and check same. PU and MU Howco
fast drill 7" retainer and running tool. RIH to 3482'. Break circ and set retainer #5 @ 3480' DPM and test to 2000
psi - sheer off and extend stinger - stab retainer and~perform injection rate with rig @ 3/4 bpm @ 1820 psi with 3
bbls away - dn pump 30 sec 600 psi 1 min psi to 400 psi. Unsting and circ and discuss job and chg out crew.
1/7/05
Continue to circulate, hold PJSM with new morning tour crew, discuss squeeze, pumping alignments and
contingency plans for possibly having to reverse out a drill pipe volume of cement. Blow down mud lines, blow air
thru all lines needed for possible cement reversal, rig up to squeeze cement. Break circulation thru choke,
pressure test cement lines to 3500 psi, batch up cement tub to 15.8 ppg, pump 5 water, 10 bbl G and 1 0.5bbl with
2 ppb Cement holding 450 -900 psi on back side Shut down, sting into retainer, pump 14.5 bbls w/cement. Initial
pressure was 1700 psi @ .75 bbl/min until 5bbl gone; it then broke back to approx 1000-1200 psi until 14 gone.
Displace with 5 bbls water and 19.5 bbls mud. Squeezed 3 times, last 10 bbls, @ 1.5 bbl/min and approx 400 to
800 psi. After each hesitation squeeze the pressure would bleed down to a value approx. 150 psi higher than the
previous time. Final pressure, pumps off before unstinging from retainer was @ 10 sec. 1000 psi and 1 minute
,was 700 psi. Shut down, unsting from retainer, bleed pressure from annulus. Line up to reverse circulate tubing,
approx 1;5 bbls cement taken back to junk tank. Continue to circulate and build and pump dry job. RD Kelly and
hose and blow down lines. POOH, stand back drill collars; lay down fast drill running tool and stinger. Work BHA
(stand back drill collars, lay down and check fast drill running tool and stinger, ok). Blow down mud lines, pull
wear bushing, run test plug and fill stack with water. Test BOPs - hydril, choke manifold, manual kill and choke
wing valves and floor safety valves to 250/3000 psi. 3.5" pipe rams failed test. Blow dn choke and all lines.
1/8/05
Finish Bop test, test stack. To 250/3000 psi, perform draw down test on Koomey. Blow dn all lines and choke
Rig back on day rate @ noon. Pull test plug/hanger, run wear bushing. Rig up floor, hang wind walls around stack
and cellar. Hook up kill line and gas buster line - Prep floor to PU DCs. PU 6" tooth bit, 2 drill collars (pre bucked
up), run 4 collars from derrick and LD tongs and PU power tongs. RIH with ph-6 drill pipe, checking each pin
shoulder for damage caused by pulling into closed pipe rams. RIH to 3476' and tag retainer #5. RD power tongs.
1/9/05
Work on air supply restriction of control hose from power 'swivel to rig floor no go run new hose. Drill on retainer
#5 from 3476' to 3480'. Drill hard cement from 3480' to 3509' @ 5.5 minlft with 7-8k wob and 80-120 rpm and 2.75
bpm (varying parameters for best results). Fell out of cmt @3609',( 6ft past top perf) to 3510'( torque up and take
wt.) make connection - rotate thru stringers from 3510' to 3517' (3 ft past bottom perf), pick up and wash down to
3544'. Blow down mud lines. Lay down power swivel and 3 working singles. RIH, take wt @ 3974', rig up and
circulate, apply weight and attempt to wash thru, will not pass 3974' circulate out hi-vise pill spotted from 3800' to
3514' (did not see pill), lay down head pin jnt and Blow down mud lines. PU power swivel. Drilling cement stringer
from 3974' to 3975' and fall thru and wash to 4012'. Make connection. Blow down and LD working single and
power swivel. RIH out of derrick tag @ 4877' work same to 4881'. PU power swivel. Brk Cirt and have safety
stand dn - hold school and safety meeting on P/up and LD safety on Power swivel. Drilling cement stringer from
4881' to 4894' and fall thru and wash to 4913' - circulate and wait on relief.
1/10/05
PTSM. Make connection. Continue wash from 4913' to 4924' tag up and drill cement stringer from 4924' to 4932'
and fall thru and wash from 4932' - to 4947' and push to kelly dn @ 4948'. Attempt connect out of balance - circ to
balance. Makè Conn. Continue Clean out hard cement stringer from 4948 to 4955', drill soft cement from 4955' to
4978' (cannot wash thru, but will not take wt. when rotating.) Attempt connection, flow back, circulate. To balance,
shut down pumps. Make Conn. @ 4978'. Drill soft cement from 4978' to 4981' drill firm cement from 4981' to
retainer @ 4989'. Drill retainer #2 from 4989' to 499~'. Drill soft cement from 4993' to 5002' @ 30 seclft with 7-8k
wob and 80-120 rpm and 2.75 bpm (6' into secondary perfs Adjusted to DPM) - Drill hard cmt from 5004' to 5009'
(from 7ft into secondary perf to 2 ft below secondary perfs @ 4997' to 5007' DPM est) @ 3 min/ft same
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 5
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parameters - Dropping MW as drilli..~ progresses from 11.0 to 9.5, 10.2 @ prest., .. Circ and take under flow from
shaker to suction for dry job for connection and make connection. Continue top drill hard cement @ same
parameters from 5009 to 5019 @ 3 mini ft (2ft. Below bottom of secondary perfs to 6ft above top of bottom set
perfs) ROP picked up to 1 min/ft @ 5021' to 5031'(entire interval of bottom set of perfs @ 5025' to 5035' DPM est)
fell thru cement @ 5031'(2 ft below bottom perf) void continued to connection depth @ 5041'. Circulate to
balance, make connection, RIH wlo pumping FROM 5041' TO 5056', take wt, wash to 5072', make connection.
RIHw/o pumping to 5103'. Blow down, lD pwr swivel, and working singles. RIH and set dn @ 5522'. PU power
swivel. Drill hard cmt/junk from 5522' to 5523' fell thru wash to connection depth of 5539'. Circ and make
connection and wash from 5539' to tag @ 5545'. Drill retainer #1 from 5545' to 5541' - fell free - washed to conn
depth of 5570' (no cmt)- conn - washed to 5600' (no cmt) - conn -wash to 5632' (no cmt) - conn - Wash from
5727', RIH to 5765', completely void of cement below retainer, tag junk @ 5765', circulate.
1/11/05
1/12/05
Circulate hole, watch shakers for packer parts, finish MW cut back to 9.7, circulate even weight mud all around.
Air lines to rig control freezing up, adding methanol and functioning. Monitor well for flow, PJSM. Pump slug from
vac truck, blow down mud lines, lay down Power swivel. PU circ head and clear floor of rig tongs. CBU. Mix high
vis pill and Pump and spot 10 bbl on btm @ 5764' @ 9.8 Ppg with 35 ppb sea mud and 1 ppb XCD. Pooh to bit
depth of 5600'. CBU and polish off high vis pill @ 5600' (base of perfs). Pump dry job and blow dn lines and thaw
frozen lines. Pooh, stand back in derrick, lay down bit sub and bit. Bit in very bad shape, mill tooth very badly
worn, can see evidence of rotation on metal. Possible slips from retainers. PUHalliburton fast-drill retainer and
startinto hole. Work on tongs BU not holding due to ice disassemble, steam, and coat with oil. RIH with retainer.
RIH slow with 7" Howco fast drill retainer. RU Kelly hose and break circ and blow down lines. Set Howco 7" fast
drill retainer @ 5535' and test same 500 psi on back side (ok) blow down. PJSM sheer off and extend stinger and
, stab retainer. Establish 20 bbl injection rate 1 bpm @ 2240 psi (shut dn 10 sec 2058 psi, 1 min @ 2039 psi, 2 min
2030 psi, 3 min 2020 psi, 10 min 1986 psi, E3leed off with 7 bbl back). Unsting circ and blow down lines RU lines
for squeeze and check all lines for clear. Break circulation through choke, pressure test cement lines to 4000 PSI,
batch up cement to 15.8 ppg, pump 5 BBl water, followed by 18 BBl Class G Cement, catching 400 PSI initially
and holding 800 psi on back side at 18 BBl away, at 1.45 BPM rate, sting into retainer pump pressure rose to
1000 PSI, pump another 18 BBl of Class G cement at 1.45 BPM rate. The highest pressure seen was 1750 PSI,
at SD pressure was at 1350 PSI, pumped 5 BBL H2Q at 1 BPM, Pressure maintaining at 950 - 1000 PSI. SO Mud
line froze had to thaw. Pumped 20 BBl of 9.9 PPG mud to displace at 1.5 BPM rate starting pressure 800 PSI
ending pressure 1900 PSI. SO, pressure fell to 1550 PSI and maintained. waited 15 minutes on hesitation
squeeze, pumped 5 BBl mud at 1 BPM rate with ending pressure of 2250 PSI. SO pressure fell to 1950 PSI.
Waited 15 minutes on hesitation squeeze. Pumped another 9.5 BBl of mud with a final pump pressure of 2975
PSI. SO and pressure fell to 2500 PSI. PU pipe and unsting from retainer. Pressure on casing rose from 800 PSI
to 1000 PSI and settled out at 900 PSI. Reverse circ to pits, when mud turned to water, divert cement to slop tank
(+- 2.5 bbls cmt back) 33.5 BBl Cement below retainer. Blow dn all lines a.nd choke. Pump dry job from ISO tank
(no good)build and pump dry job - blow dn lines.·POOH. PU bit and scraper; RIH with DC.
1/13/05
RIH with DC, and 2 stands of DP. RIH work scaper from 3163' to 3420' and from 4663' to 4920' continue into hole
and tag top of retainer at 5532'. lD two working singles and RIH with 1 stand,P/U power swivel (had problems
with hyd hoses). Drill HaWCa fast drill retainer #6 FROM 5532' to 5538' in about 1 hour looks like approximately
2' of cement below retainer. WaB 6K, 100 RPM, 3BPM, then broke free. Circulate and clean retainer setting area.
Wash down to 5636'. Blow down and RD power swivel. RIH and tag at 5753' set 10K down, did not see any
resistance prior to tagging. lD single and PU Kelly joint with head pin. CBU had several BBlS of a very thick
viscous material with a very gritty texture to it come across shaker. Circulate and condition mud dropping weight
down to 9..5 PPG, and circulate around. Mix dry job, and monitored well for flow, prior to pulling out of hole. Blow
down. POOH stand back in derrick.
1/14/05
POOH - Work BHA - Blow down. PU champ packer, with single and XO on top, and make up on catwalk, hang
same in elevators. PU single joint 2 7/8" IBT tubing and set in slips with XO in top, MU same to bottom of champ
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 6
~'
packer hanging in elevators. RIH \!vILli 28 stands and PU multi-service tool and rv....J with single and XO, RIH with
another 49 stands' (77 stands total with 2·singles) (1 HR WOO) Champ packer set at 4893'. RU squeeze manifold
and prep for negative pressure test, Pressure up on annulus to 500 PSI felt multi service valve open. Monitor
bubble hose for 25 minutes had a steady increase in flow. Bleed casing pressure off, pump down DP, @ 970
strokes start to pressure up, continue to pump until pressure reached 1000 PSI, line up to choke and bleed off.
PU on DP 3' to open bypass. Reverse circulate BU at approximately 1000 strokes had gas back to surface,
pumping through choke going to gas buster, circulat.e gas out and an additional BU. Switched over circulating
long way taking returns through choke going to gas buster. Circulate 2 BU with no sign of gas. Monitor well, mix
dry job, well out of balance tubing light, closed TIW valve. Valve leaked changed out same. Pump dry job, PU
power swivel break out TIW and saver sub lay down same. RU tongs and prep floor for laying down pipe
POOH laying down PH-6 tubing installing protectors on each end.
1/15/05
LD 3.5" PH-6 OP. RU manual rig tongs break out and lay down multi-service tool. RD and LD rig tongs. Continue
to lay down drill pipe, lay down Champ packer and 1 joint of 2 7/8" tubing. Trip in hole with DC from derrick and
lay down same. Trip in hole with drill pipe from derrick and lay down same. Change pipe rams from 3.5" to 2.875",
pull wear ring, MU test joint and set test plug, fill stack and choke with water. Test BOP, choke manifold, and floor
valves too 250 PSI low and 3000 PSI high. PJSM. Load pipe racks with 2 7/8" IBT tubing, sort and number tubing
(Slick - Centralizer joints) Pick up handling tools. PU and run 2 7/8" tubing, drift with 2.375 00 rabbit
1/16/05
RU fill line and continue to RIH filling tubing going in to hole. RU Pollard to run chemical injection line PU mandrel
make up line and test same. Continue to RIH filling tubing, and banding chemical injection line, RIH and tag
bottom at 5749.95 pick up and space out, MU hanger terminate chemical injection line, land tubing and RILDS
28M up weight and 28M down weight. Total of 178 joints in hole. Total of 156 bands in hole. NU Install additional
7" casing x 2 7/8" tubing annulus valve on off side of tubing spool. Removed VR plug through valve after
installation. MU Lake Charles Cement head, PU and break out pups used for landing joints and test joints. RD
and LD Foster power tongs. RU squeeze manifold, RU annulus return line through choke going to shaker and
slop tank. Circulate and clean hole. PJSM. Pump 10 BBLs diesel down tubing for freeze protection on back side,
followed by 1 BBL mud to flush lines, blow down lines. Pump 3 BBL CW100 to fill and flush lines, and test cement
lines to 4000 PSI, bleed pressure off, pump an additional 7BBLS of CW100. Pump 30 BBLS of Mudpush XL @
10.5 PPG. SO and batch up lead cement slurry of 20 BBL of lite-crete with Cement at 12 PPG, pump same at 3.5
BPM, followed by an additional 33 BBLS of lite-crete (No Cement) pumping at 4.5 BPM rate. SD and batch up Tail
cement slurry of class G cement at 15.8 PPG. Batched up to 15.8 PPG, and pumped 25 BBLS of same with
density flux from 14.9 to 16.4 PPG. SO, washed lines, dropped plug displaced with lease water. Bumped plug at
22.30 HRS, pressured tubing to 3500 PSI and held pressure for 10 minutes with no pressure loss, bled off
pressure and checked floats had 1/4 BBL of returns and float held.
Blow down and RO cement lines.
1/17/05 '
Pressure up and rupture disc at Chemical injection mandrel, (4300 PSI) continue to pump and clear area of any
residual cement. Clean floor, RD Cement head and lay down same, start to clean pits. RU Pollard Wireline
RIH with temp survey tools to 5000' logging in and out at 60' per minute 5 minute stop at hanger and at 50001.
Power wash stack and prep for NO., LD landing joint and Set 2.5" CIW H BPV. ND BOP equipment including riser.
Freeze protected 13~3/8" X 7" by Pumping 3.5 bbls Diesel into annulus with test pump work psi @1500 psi broke
and fell to 500 psi and built back to 1000 psi @ shut dn 800 psi and shut valve. NU tree and Test hanger void to
5000 PSI held for 15 minutes with chemical injection port open with no leak. Pull BPV and set TWC test tree to
5000 PSI held for 15 minutes no leaks. Pull TWC and freeze protect tree using diesel fuel. Install BPV. Release
rig at 18:00
Lay felt and liner at relief pad to stack rig out on, blow down boiler, continue with pit cleaning and disposal of
solids, palletize equipment and prep to move.
1/19/05
Using triplex test pump and pumping diesel pressure 7" casing x 2 7/8" tubing annulus to 2000 PSI, SI an hold
pressure for 30 minutes with a 50 PSI pressure drop. Bleed pressure off. Pollard RIH with 2.35" GR tagged at
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 7
(
5601' WLM which is 91' high. NoW.. ,some anomalies with counter, POOH, froi. .,.oint were counter was to zero
to where it topped out 100' off. Picked up lubricator and run tool string down to LOS counter off 90'. RIH second
time to verify counter discrepancy, put heater on counter to try and keep it from locking up, Tagged at 5697' WLM
POOH cement LC at 5692' pipe measurement. Lay down lubricator and secure well.
1/20/05
Test BOP to 250 PSI low and 5000 PSI high. PJSM. RIH with coil, while cooling down taking returns to Johnson
tank. Start to pump N2 at 240 SCM per minute, monitoring returns in Johnson tank. Tag bottom at 5686', PU 5'
and increase rate to 600 SCFM rate, max pressure 2580 PSI monitoring returns, at calculated returns had N2 to
surface, put on choke and continued to blow for 10 minutes. POOH, trapping 1800 PSI on tubing, remove injector
head and spooling up coil. NO BOP, stage BOP and injector in transportation rack. Secure well.
RO/MO
1/21105-1/23/05
1/24/05
Schlumberger out at 06:00 hrs spot equipment and start to rig up, had PJSM, complete Unocal explosives and
perforating check list, arm guns,NU, test lubricator to 250 PSI low and 3000 PSI. RIH using Schlumberger
Ultrasonic Imager Log dated 9/21/94, tie in to perforate from 5555' to 5567'. Confer with Meg Kremer prior to
perforating. Fired guns at 10:12 HRS had N2 cap of 1778 PSI, within 5 minutes had pressure of 1955 PSI and
built up to 1958 over the next 30 minutes. Schlumberger POOH all guns had fired, rigged down and departed
field. Turned well over to production.
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 3/8/2005, Page 8
RE: SRU 32A-15
lCì ,/O'S ¥O(
Subject: RE: SR,:{.J 32A-15
From:uDunham,' Diane En <dunhamd@unocaLcom>
Date: Nlon,29~~g20051~:12:10-0.~OO
To::'R<?bertFl~.ckeJ}stei!l<:1:)oÞ¿f1~~~ens1:etn@~dI11in.state.ak.u.s:>
I was hoping you would say that. I took another look at the sundries there were two jobs filed back-to-back, Just
to be sure I am sending both documents.
Sundry 304-340 should attach the file that references AFEs162944 and 162945 in the name and on the footer.
Sundry 304-388 should attach the file that references AFE 163075 in the name and on the footer,
Thanks Bob!
Diane
Diane E. Dunham
Chevron, 907-263-7604
From: Robert Fleckenstein [mailto:bob_fleckenstein@admin.state.ak.us]
Sent: Monday, August 29, 2005 2:56 PM
To: Dunham, Diane E
Subject: Re: SRU 32A-15
&CI\NNED NO\P 0 a 2DD5
Diane,
Just send them directly to me or if you have electronic copies send them to me as an email attachment.
BobF
Dunham, Diane E wrote:
Bob-
I am going through and reconciling some of our reports. In the process, I reviewed a form 10-407 for this well
filed on 12/15/04-follow-up to sundry #304-340. The daily summary is missing some of the days. It should go
through to 10/29/04 and currently ends with 10/16/04. Can I send you the correct daily summary for this filing or
do I need to resubmit the paperwork?
Thanks
Diane
Diane E. Dunham
Chevron, 907-263-7604
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RE: SRU 32A-15
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1 0/29/04
Spot equipment RU and test to 2500 PSI. RIH with 2.25" DO Bailer and tag fill at 7330' KB recovered 1 cup of
sand. RIH with 2.32" gauge ring and tag fill at 7330' KB. RIH w/2 1/2" SB&A stop set at 7000' KB POOH. RIH with
2 1/2" GS and Pack off plug set at 6999' KB POOH. RIH and make 6 dump bailer runs using a 9' x 2.25" bailer,
dump bail cement from 6995' to 6960' 10 gallons. RD Pollard
11/1/04
RU Schlumberger. PT top of cement plug to 3000 PSI held for 20 minutes, bleed off pressure. RU APRS unit
using Pollard mast truck, test lubricator to 3000 PSI. Have PJSM. RIH with 2.25 jet cutter and tagged top of
cement plug at 6974' Tagged witnessed by Jeff Jones with AOGCC. PU using CCl found center of joint at 6012',
pressured up to 500 PSI, fired cutter had good indication of firing, tubing fell to zero PSI instantly, POOH. Jug test
wellbore to 3000 PSI for 30 minutes held good. With APRS RD, Schlumberger start pumping down the tubing
taking returns, CBU, (water clean for produced.) Freeze protect annulus and tubing. Pump 5 bbls down backside,
and .5 BBlS down tubing.
12/22/04
RU, Clean snow from Koomey, Tioga, choke hose and other. Prep area for SlB Cementing foot print.
12/23/04
RU, PJSM, NO tree, and NU 7 1/16" 5M BOP, Choke line and Kill line. Function test same. Move drillers console,
Make up 2 7/8" test joint. Test Annular, 27/8" Rams, Blind rams, choke line valves, kill line valves, choke manifold
and all floor valves to 250/3000 psi. Test gas detectors. AOGCC waived witness to BOP Test. Set cat walk and
pipe racks. RU floor to pull tubing.
12/24/04
Back out lock downs and check annulus for pressure. Pull hang~hijd.IE!&5 ~ ft$i~'~ t1ttj,iJ~g cut. Pull hanger
to rig floor up wt 38 kip. lay down hanger and pups; make up head pin and CBU. Had some bubbles, shut
annular and went through choke manifold and gas buster, pit level dropped enough for charge pump to loose
prime. shut down and blow down lines. Finished CBU. POOH, lD 2 7/8" tubing. Recovered 188 joints + cut off
joint + 5 puped GlMs + 3 Space out pups and tubing hanger. Wire line cut was made at 6012' (did not Strap out
of hole, went off of joint count, pipe came out. Change rams from 2 7/8" to 3 1/2". Test pipe rams and floor valves
to 250/3000 psi. Blow down and freeze protect test pump. RU to handle BHA and 4 3/4" Drill collars. Pick up 6" bit
7" 29# casing scraper and 4 3/4" Drill collars
12/25/04
Change out handling equipment to handle 3 1/2" PH-6 and Clear off rig floor. RIH bit and scrapper on 3 1/2" PH-6
Tubing. Thaw and Drift pipe with 2.312' rabbit. Continue RIH with bit and scrapper to 5824, (182 total joint 3 1/2"
12.60 # PH-6) RU to change over well bore fluids from 8.4 PPG lease water to 11.7 PPG mud. PJSM. Displace
well bore with 11.7 ppg water base mud, taking lease water returns to Johnson tank. After displaced take returns
back to active system until we had a 60 bbl surface volume. Circulate at 2 bbl per min over shaker; pump
performed well out of big tank and vac trucks. Blow down all surface line and RU choke line. POOH 53 Stands to
2513'. RU floor to make up storm packer.
12/26/04
Run in storm packer and set same 12' below well head, shut pipe rams and test storm packer to 500 psi, back out
joint and close storm valve. lay down same. Clear off floor, RD floor and prep to NO BOP (includes vac out and
clean cellar). Nipple down BOP, remove choke and kill lines. Stump up BOP until ready to NU. Checked voids on
old tubing spool for any trapped pressure. After inspection found 7" 29 PPF casing stub to be badly Kelly worn.
Checked annulus between surface casing and 7" production casing for any pressure found none, checked for any
lEL and found none. With constant lEl monitoring pulled casing hanger seal and replaced with new. NU new
remanufactured tubing spool, and tested void to 2500 PSI, held for 10 minutes. Nipple up BOPs. RU rig floor.
Make up two-way check set tubing hanger and shell test stack, choke line and kill line against blind rams at
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 8/29/2005, Page 1
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250/3000 psi (good test) RU rig tongs to lay down storm valve. PU joint of PH-6 with retrieving tool, screw into
storm valve, open Safety valve and check for pressure (none). Unseat storm packer up wt 30 kip. LD same. LD
rig tongs. POOH FROM 2513' -1073'.
12/27/04
Continue POOH 3 1/2" PH-6 to drill collars. LD hydraulic tongs, RU manual tongs, slip bowl and 4 3/4" drill collar
slips. (lay down biUscrapper) rack drill collars 2 stands. Blow down rig, Nipple down flow nipple and clean out stud
holes to accept studs for shooting flange, RU line from surface casing x 7" casing annulus to choke. PJSM. RU
Schlumberger. PJSM pull tools to floor and PU 7" HES EZ drill CIBP, RIH to 5770' logged up found collar at 5752'
dropped down and logged back up set EZ drill at 5760', setting tool fired at 11 :15 HRS POOH. RU WL BOP found
bad spot in E-Line and SWS rehead. Arm guns and stab up, test to 2000 PSI against EZ drill, held 10 minutes
bleed off pressure. RIH with 2- 10' guns 2" hsd, 6 shots perlft set for selective fire. Make tie in pass. Tie in to
Schlumberger ultrasonic imager log dated September 21-1994. Pressure up on 7" annulus to 1500 psi. Perforate
from 5590' - 5600'. Pressure dropped to 600 psi when gun fired. pull up hole 500'. Attempt to circulate, pump at 1
bbl per min pressure increased to 1740 psi and maintained a rate of 1 bbl per min and put away a total of 10 bbl,
shut down pump. Pressure after 10 sec was 1650 psi. Drop back down tie in and perforate from 5555' - 5545'.
With 1350 psi on 7" annulus, saw no change in pressure when guns fired. POOH with perf guns. Lay down guns
all shots fired. Close blind rams. Attempt to circulate (no go) results were the same pumped 8 bbls away at 1750
psi at 1 bbl per min. Shut down pump, pressure 10 sec after shut down was 1650 psi, and 1242 psi 30 min after
shut down. Bleed off pressure and blow down all lines. Make up setting tool arm same. Make up 7" Halliburton
Fast drill retainer. RIH, Tie into log and set retainer at 5535'. POOH with perf guns. LD guns all shots fired. LD
tools and RD Schlumberger, start nipple down shooting flange.
12/28/04
Continue RD Schlumberger wire line. ND shooting flange and nipple up flow nipple and install flow line. MU
Halliburton Fast drill cement stinger. RIH cement stinger on 3 1/2" 12.60 # PH-6 Tubing. (Thawing out pipe) Make
up single and tag at 5544' tubing measurements, current RKB. Retainer set at 5535 Wire line measurements.
Space out for cement job, ended up with tool joint in annular at the same time stinger stabs into retainer, RU
stand pipe hose and head pin. Break circulation stab in and perform injection test at 1 bbl per min ·1740 PSI. with
rig pump. Pump 4 bbls, no returns noted in 7" annulus. Close annular and pressure up to 650 psi and perform
stab in test and adjust annular to 500 psi or less. PJSM. Break circulation with Schlumberger pump 3 bbls water
shut down and test line to 5000 psi. (good test) pump 2 bbls water for a total of 5 bbl a head of cement. Batch up
cement to go down hole. Pump 21 bbls 15,8 ppg cement slurry holding 650 psi back pressure with rig choke
manifold, pump 5 bbl water + 12 bbls of 11.6 ppg water based mud. Shut down and stab in retainer (held 650 on
back side during squeeze no pressure change during squeeze) squeeze cement away with 23.4 bbls 11.6 ppg
water based mud at 3 bbl per min 2000 psi, slowed to a rate of 1 bbl per min 1540 psi, last 4 bbls away. Shut
down pump and unsting from retainer. pressure 10 sec after pump shut down was 1504 psi. Reverse circulate 2
tubing volumes, got back unexpected cement took returns to junk tank, gauged tank. Recovered 12 bbls of
contaminated mud, cement, and water. Pump dry job and blow down rig. POOH and Lay down stinger. RU
shooting flange.
12/29/04
RU shooting flange, wireline lubricator and grease head, pick up GR/CCL tool and two 10' ft 2",6 shot / ft HDS
perf guns, set for selective fire. Pressure test wireline lubricator and BOPs to 2000 psi, hold pressure for 10
minutes. (good test). Blow down and drain lines, RIH with wireline. Make tie in pass, tie into Schlumberger
ultrasonic imager log dated Sept 21 1994, made 2 passes to correlate bottom gun to fire from 5014' to 5024' Line
up mud pump to pump down drill pipe and attempt to take returns thru perfs at 5014'-5024' up 7" x 13.625"
annulus through choke to rig pits. Pressure up annulus to 1500 psi, shoot perf gun at 5014' to 5024' Lost pressure
from 1500 psi to 350 psi over 10 seconds; pull wireline up to 4800'. Bring up rig pumps to 1.2 bbl/min and 1080
psi, attempting to circulate thru new shot perfs up 13.625" x 7" annulus, thru choke, monitoring for returns at slop
tank, increase pump rate to 2 bbl/min with no increase in pressure, (injecting) shut down and monitor pressure
after pumping total of 8-9 bbls. correlate wire line for next shot. (pressure dropped from 1000 psi to 750 psi over
25 minutes.) Shoot perfs from 4986' to 4996' while holding 1000 psi on DP x 7" annulus, seen very slight drop in
pressure as guns fired and[pressure remained at 700-900 psi as POOH with wireline. Blow down mud lines, RD
log/perf wireline assembly RU to run on wireline Halliburton 7" Fast drill cement retainer. RIH with wireline. Tie in
to Schlumberger ultrasonic imager log dated 9/21/94. Set Halliburton fast drill retainer at 4979'. POOH and RD
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 8/29/2005, Page 2
(I
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wire line. ND shooting flange and install flow line. Make up fast drill cement stinger and RIH. (thawing out ice plug
in pipe,) RIH to 4950', PU 5' and 10' pup joints and single joint with head pin, park at 4965', RU squeeze manifold
and pump lines. Hold PJSM, break circulation thru choke, stab into fast drill retainer, mark pipe, pressure test
cement lines to 3.5k, pull out of retainer, pump 5 water ahead, 100sx (21bbls) 15.8 class g cement, displace
w/5bbl water, 8 bbl mud, hold 450 -750 psi on annulus while spotting cement to retainer. Stab into retainer and
squeeze away cement at 2.5 bbls/min and 1450 psi, last 8 bbls squeezed pressure increased from 1450 psi to
1900 psi with pump rate same. Pressure bled to 1250 when pump shut down, continued 100 psi bleed off/minute
over next 5 minutes. Pull out of retainer, Reverse circulate two tubing volumes Saw 1 bbl cement and several bbls
clabbered up mud total of 9 bbls dumped. Drain up and blow down lines, RD Schlumberger.
12/30/04
lD pup joints and working single, secure well. Drain and blow down pump lines. POOH, lay down cement stinger
Blow down lines (wear bushing was pulled by drag blocks on cement stinger as it passed by. Cut and slip drilling
lines, change out 50' choke hose for 30' hose to Reduce trip and freeze up hazards. Make up test joint and XOs
and test plug/hanger. Pull wear bushing. Test BOPs, choke equipment, floor/dart valves to 250/3000psi, draw
down test on Koomey (good tests). Blow down lines.
12/31/04
Attempt to run wear bushing, pull wear bushing will evaluate after wire line. RU shooting flange, wireline BOPs,
lubricator and wireliners. Hold PJSM, Arm perf guns and CCl, pick up and stab inside lubricator, pressure test to
2000 psi for 5 minutes (good test). RIH, tie into ultrasonic imager log from 9/21/94. Pressure up annulus to 1500
psi and hold, spot 10 ft, 2", 6 sp/ft HSD power jet perf guns and shoot 3493' - 3503'. Press. dropped to 30 psi 1
min. after shot. Pump at 1 bbl/min, pressure gradually increased to 1480psi after 10 bbl away. shut down, 10sec
1098 psi and 1 min to 280 psi. No indication of any returns from the 7" x 13 5/8 annulus during pumping. Blow
down lines. POOH with wireline, PU Fast drill retainer, set at 3485' POOH lD wireline and RD shooting flange
and lubricator. RU new built 6" flow line spool, in place of current spool, run wear bushing. PU. Cement stinger,
RIH to above cement retainer, break circulation, sting into retainer establish circulation at 1.25 bbl/min pressure
climbed to 525 psi then broke back to 388 psi after 9 bbls injected. Shut down 10 sec pressure dropped to 152
psi, 1 min 122 psi. RU to pump down 7" X 13 3/8" annulus with lease water, pumped down annulus 30 bbls before
seeing any pressure (25 psi,) After 40 bbls pumped pressure increased to 280 psi, then climbed t01500 psi after
42.8 bbls pumped (fluid est. to be down 390 ft in annulus before fill up) after pump shut down pressure bled to
1470 in 10 sec. and 1425 in 30 minutes. PJSM. With cement pump break circulation test lines to 5000psi, pump
10 bbls water, + 23 bbls, cement while holding 780 psi on annulus, sting into retainer and pump 17 bbls cement at
2.2 bbl/min and 400 psi. chase with 5 water and 8 bbls mud at 2 bbllmin and 500 psi. Hesitation squeezed
remaining 13bbls cement in drill pipe over 6 squeezes of2 bbls / squeeze at 1 bbl/min with pressure increasing
every squeeze by approx 50 psi each time, starting at 450 psi and ending at 700 psi. Between squeezes pressure
drop off was also approx 50 psi higher than previous drop-off. monitored for leaking bag or retainer (none.)
Pressure was fairly stable at 575 psi when we pulled out of retainer. Reverse out pipe volumes; saw 1 bbl cement
and all of spacer water. lD single, blow down lines, prepare to POOH.
1/1/05
lD 2 pup joints. And 14 working singles for drill out of retainers and cement. POOH. PU rig tongs, break and lD
cement stinger. Change out handling tools, MU bit, bit sub and 4 DCs. RIH t03460'. RU power swivel, hang
hydraulic hoses in derrick and hook up. RU mud cross on top of flow line. RIH tag retainer at 3485 WLM, 3496"
DPM, drill on retainer, mud pumps jack off shut down. Clean out rubber and junk from suction screen and under
mud pump, replace shaker screens. Continue to drill on retainer, and cement 3530' Broke thru, push and rotate to
3560', wash with out rotating to 3576'. Circulate and condition hole. RD power swivel and lD. RIH to 3616 to
ensure no cement stringers, continue to circulate and condition, rig for test of squeeze.
1/2/05
RU to pressure test squeezed perfs from 3493' to 3503'. Pressure test perfs at 3493 to 3503 using rig pump, pop
blew at 2300 psi, RU test pump, bring up pressure with rig pump to 2000 psi, shut in, bring up pressure with test
pump to 3000 PSI Shut in well. After holding pressure for more than 1 min, perfs broke down and bled to 600 psi.
Check all lines and possibilities, retest same, Establish injection rates. Circulate across mud cross at 2 bbl per
min no gains or losses noted. Blow down mud lines and choke manifold. Circulate and wait on cementers for
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 8/29/2005, Page 3
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squeeze job. Pump dry job off of vac truck. (Schlumberger arrive on location, went over job sib mix -mix water
ready to cement at 09:30 hrs). Pull off secondary flow nipple and install ware plate on flow nipple. Pull 6 stands,
run in one joint with circulating head to 3288'. RU lines and manifold, run injection test at 3/4 bbl per min at 896
psi with 11.5 ppg mud. Pumped 5 bbl., pressure 10 sec after pump was down 593 psi. one min after pump was
down 175 psi, pressure after another min 150 psi and starting to get stable. PJSM, Pump 3 bbls water and test
line at 3500 psi. Pump remaining 2 bbl of water. Pump 20 bbls Class G 15.8 ppg cement while holding differential
pressure on rig choke manifold as per DSM Pump schedule. Close choke at 20 bbl away and Squeeze. Pump
remaining 5 bbls of cement + 5 bbl of water + 23.7 bbls of 11.5 ppg mud. sa Pressure 575 psi 1 bbl per min
(squeeze last 10 bbl of displacement at 2 bbl intervals, shutting down for 5 min, switched to 1 bbl interval at 1/2
bbl per min shutting down for 5 min, until cement was displaced. (pressure would go to 800-1000 psi at times but
would break again) Shut down and let pressure bleed to a stable pressure of 250 psi. Monitor 5 min no change.
Switch over to rig pump and circulate tubing by casing volume at 2.7 bbls per min 500 psi. Holding 125 - 200 psi.
on annulus with rig choke. Shut down pump and close choke catching 200 psi on tubing and casing, Pressure
very stable Monitor pressure every Hour, pressure still 200 psi on casing and tubing, shut in choke line and stand
pipe, Bleed down surface lines. Wash up lines and blow down rig.
1/3/05
Continue WOC, install 6" flow line, and continue working pipe every half hour. PJSM, break circulation thru choke,
pressure test squeeze to 21 OOpsi FROM 15 minutes (lost 10 psi rock solid). RU wash down from 3288' find hard
cement 3330', work pipe and circulate, blow down lines. LD single, pick up power swivel, break circulation. Pre-
treat mud for cement contamination. Drill firm cement (wob 5-6, rpm 120, pump at 4 bbl/min.) from 3330' to 3378',
break thru and wash 3488', drill cement from to 3488' to 3506', wash to 3512', past bottom perfs. Circulate and
condition mud, continue to treat for contamination. Test casing to 1100 psi, before break down INJECTS at 3/4
BBL per min 670 psi. Wash down from 3512' to 3543', CBU, blow down lines. RD. Pump dry job. POOH, 20
stands, mud in pits gelling up, unable to maintain hole fill circulation. POOH. Treat mud for cement contamination
while circulating over top of hole while tripping.
1/4/05
Lay down BHA, (loose wheel on bit) pick up Halliburton fast drill and running tool. (check 13.3/6" x 7" annulus,
slight blow). RIH, with fast drill at 45-60 see/stand. Tong back up dies slipping, inspect and change. Continue RIH
to 3451', RU squeeze manifold, attempt to pump (trash under suctions and in valves), clean pump. Break
circulation, set retainer at 3447, shear out, stack 20k to set. Establish injection rate at 1 bpm and 675 psi., unsting
from retainer. Hold PJSM, pump 5 bbl water, test lines to 3k, bleed off, pump 10 bbls G cement, followed by 13
bbls cemenUcimnet, hold from 250 to 750 psi on annulus while spotting cement to retainer, stab into retainer and
squeeze 7 bbls w/cimnet and 5 bbls G cement (total cement 35 bbls) and 5 bbls water at 2.1 bbl/min with
pressure climbing after stabbing in from 900 to 1000 psi. Displace drill string with 12 bbls mud at 2.1 bbllmin and
pressure climbing from 1150 t01225 psi. Displace with additional 8 bbls mud at 1.1 bbl/min and pressure climbing
from 900 psi to 1125 psi at end of displacement. Reverse circulate 2 tubing volumes, saw 1-2 bbls cement and all
of water at shakers and slop tank. Blow down lines, LD top single w/head pin. POOH. LD running tool and stinger.
PU 6" six bladed junk mill, with 2 boot baskets and 4drill collars RIH 52 stands ( 3397') PU power swivel, Continue
RIH and tag retainer at 3446' DPM. CBU and condition mud. WOC and work pipe and roll hole mud while
cleaning pits and going thru MP and suction screen and roll surface system across shaker with vac truck.
1/5/05
Finish cleaning pits, pre-treat surface system for cement contamination. Drill retainer from 3446' DPM to 3450'
rotary @ 100, WOB @ 3-5, pump @ 3.1 bbllmin. (attempt different RPM and WOB.) Drill hard cement from 3450'
to 3477' and varying parameters and massaging bottom and treating mud. Circulate 15 minutes, shut down and
change out shaker screen. Continue Drill hard cement from 3477' to 3485' and varying parameters and
massaging bottom and treating mud. Work on pump and chg/out all three rod packings. Continue Drill hard
cement from 3485' to 3516' and varying parameters and massaging btm and treating mud- fell thru and wash to
3522'. Circulate clean. Shut in and attempt to test Re-squeezed perf from 3493' - 3503' WLM - while monitoring
open 13-3/8" X 7" annulus - Pressure build to 1700 psi and broke back to 900psi @ 2.5 bbls away - up pump
speed to 1 bpm and continue pumping and building pressure to 2100 psi @ 10.5 bbls away - dn pump and with in
1 min psi @ 900 and 3 min @ 400 psi.
1/6/05
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 8/29/2005, Page 4
~t
t
Blow down lines and LD. Power swivel. Rih to 3805'. Mix and spot balanced high visc 10 bbl pill. POOH LD
working singles to 3514' and RU to circulate. CBU and balance same. Continue circulate. Generator feeding
Tioga down, DSM drain water from filters and put back on line, continue circulate until heat back to rig blow down
and drain lines. Monitor well (ok) LD 2 jts and pooh. Work BHA and clean and check same. PU and MU Howco
fast drill 7" retainer and running tool. RIH to 3482'. Break circ and set retainer #5 @ 3480' DPM and test to 2000
psi - sheer off and extend stinger - stab retainer and perform injection rate with rig @ 3/4 bpm @ 1820 psi with 3
bbls away - dn pump 30 sec 600 psi 1 min psi to 400 psi. Unsting and circ and discuss job and chg out crew.
1 n /05
Continue to circulate, hold PJSM with new morning tour crew, discuss squeeze, pumping alignments and
contingency plans for possibly having to reverse out a drill pipe volume of cement. Blow down mud lines, blow air
thru all lines needed for possible cement reversal, rig up to squeeze cement. Break circulation thru choke,
pressure test cement lines to 3500 psi, batch up cement tub to 15.8 ppg, pump 5 water, 10 bbl G and 1 0.5bbl with
2 ppb Cement holding 450 -900 psi on back side Shut down, sting into retainer, pump 14.5 bbls w/cement. Initial
pressure was 1700 psi @ .75 bbl/min until5bbl gone; it then broke back to approx 1000-1200 psi until 14 gone.
Displace with 5 bbls water and 19.5 bbls mud. Squeezed 3 times, last 10 bbls, @ 1.5 bbl/min and approx 400 to
800 psi. After each hesitation squeeze the pressure would bleed down to a value approx. 150 psi higher than the
previous time. Final pressure, pumps off before unstinging from retainer was @ 10 sec. 1000 psi and 1 minute
was 700 psi. Shut down, unsting from retainer, bleed pressure from annulus. Line up to reverse circulate tubing,
approx 1.5 bbls cement taken back to junk tank. Continue to circulate and build and pump dry job. RD Kelly and
hose and blow down lines. POOH, stand back drill collars; lay down fast drill running tool and stinger. Work BHA
(stand back drill collars, lay down and check fast drill running tool and stinger, ok). Blow down mud lines, pull
wear bushing, run test plug and fill stack with water. Test BOPs - hydril, choke manifold, manual kill and choke
wing valves and floor safety valves to 250/3000 psi. 3.5" pipe rams failed test. Blow dn choke and all lines.
1/8/05
Finish Bop test, test stack. To 250/3000 psi, perform draw down test on Koomey. Blow dn all lines and choke
Rig back on day rate @ noon. Pull test plug/hanger, run wear bushing. Rig up floor, hang wind walls around stack
and cellar. Hook up kill line and gas buster line - Prep floor to PU DCs. PU 6" tooth bit, 2 drill collars (pre bucked
up), run 4 collars from derrick and LD tongs and PU power tongs. RIH with ph-6 drill pipe, checking each pin
shoulder for damage caused by pulling into closed pipe rams. RIH to 3476' and tag retainer #5. RD power tongs.
1/9/05
Work on air supply restriction of control hose from power swivel to rig floor no go run new hose. Drill on retainer
#5 from 3476' to 3480'. Drill hard cement from 3480' to 3509' @ 5.5 min/ft with 7-8k wob and 80-120 rpm and 2.75
bpm (varying parameters for best results). Fell out of cmt @3509',( 5ft past top perf) to 3510'( torque up and take
wt.) make connection - rotate thru stringers from 3510' to 351 l' ( 3 ft past bottom perf), pick up and wash down to
3544'. Blow down mud lines. Lay down power swivel and 3 working singles. RIH, take wt @ 3974', rig up and
circulate, apply weight and attempt to wash thru, will not pass 3974' circulate out hi-visc pill spotted from 3800' to
3514' (did not see pill), lay down head pin jnt and Blow down mud lines. PU power swivel. Drilling cement stringer
from 3974' to 3975' and fall thru and wash to 4012'. Make connection. Blow down and LD working single and
power swivel. RIH out of derrick tag @ 4871' work same to 4881'. PU power swivel. Brk Circ and have safety
stand dn - hold school and safety meeting on P/up and LD safety on Power swivel. Drilling cement stringer from
4881' to 4894' and fall thru and wash to 4913' - circulate and wait on relief.
1/1 0/05
PTSM. Make connection. Continue wash from 4913' to 4924' tag up and drill cement stringer from 4924' to 4932'
and fall thru and wash from 4932' - to 4941' and push to kelly dn @ 4948'. Attempt connect out of balance - circ to
balance. Make Conn. Continue Clean out hard cement stringer from 4948 to 4955', drill soft cement from 4955' to
4978' (cannot wash thru, but will not take wt. when rotating.) Attempt connection, flow back, circulate. To balance,
shut down pumps. Make Conn. @ 4978'. Drill soft cement from 4978' to 4981' drill firm cement from 4981' to
retainer @ 4989'. Drill retainer #2 from 4989' to 4993'. Drill soft cement from 4993' to 5002' @ 30 seclft with 7 -8k
wob and 80-120 rpm and 2.75 bpm (6' into secondary perfs Adjusted to DPM) - Drill hard cmt from 5004' to 5009'
(from 7ft into secondary perf to 2 ft below secondary perfs @ 4991' to SOOT DPM est) @ 3 min/ft same
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 8/29/2005, Page 5
~
4'
,{
parameters - Dropping MW as drilling progresses from 11.0 to 9.5, 10.2 @ present. Circ and take under flow from
shaker to suction for dry job for connection and make connection. Continue top drill hard cement @ same
parameters from 5009 to 5019 @ 3 minI ft (2ft. Below bottom of secondary perfs to 6ft above top of bottom set
perfs) ROP picked up to 1 minlft @ 5021' to 5037'(entire interval of bottom set of perfs @ 5025' to 5035' DPM est)
fell thru cement @ 5037'(2 ft below bottom perf) void continued to connection depth @ 5041'. Circulate to
balance, make connection, RIH wlo pumping FROM 5041' TO 5056', take wt, wash to 5072', make connection.
RIH wlo pumping to 5103'. Blow down, lD pwr swivel, and working singles. RIH and set dn @ 5522', PU power
swivel. Drill hard cmUjunk from 5522' to 5523' fell thru wash to connection depth of 5539'. Circ and make
connection and wash from 5539' to tag @ 5545'. Drill retainer #1 from 5545' to 5547' - fell free - washed to conn
depth of 5570' (no cmt)- conn - washed to 5600' (no cmt) - conn -wash to 5632' (no cmt) - conn - Wash from
5727', RIH to 5765', completely void of cement below retainer, tag junk @ 5765', circulate.
1/11/05
Circulate hole, watch shakers for packer parts, finish MW cut back to 9.7, circulate even weight mud all around.
Air lines to rig control freezing up, adding methanol and functioning. Monitor well for flow, PJSM. Pump slug from
vac truck, blow down mud lines, lay down Power swivel. PU circ head and clear floor of rig tongs. CBU. Mix high
vis pill and Pump and spot 10 bbl on btm @ 5764' @ 9.8 Ppg with 35 ppb sea mud and 1 ppb XCD. Pooh to bit
depth of 5600'. CBU and polish off high vis pill @ 5600' (base of perfs). Pump dry job and blow dn lines and thaw
frozen lines. Pooh, stand back in derrick, lay down bit sub and bit. Bit in very bad shape, mill tooth very badly
worn, can see evidence of rotation on metal. Possible slips from retainers. PU Halliburton fast-drill retainer and
start into hole. Work on tongs BU not holding due to ice disassemble, steam, and coat with oil. RIH with retainer.
1/12/05
RIH slow with 7" Howco fast drill retainer. RU Kelly hose and break circ and blow down lines. Set Howco 7" fast
drill retainer @ 5535' and test same 500 psi on back side (ok) blow down. PJSM sheer off and extend stinger and
stab retainer. Establish 20 bbl injection rate 1 bpm @ 2240 psi (shut dn 10 sec 2058 psi, 1 min @ 2039 psi, 2 min
2030 psi, 3 min 2020 psi, 10 min 1986 psi, Bleed off with 7 bbl back). Unsting circ and blow down lines RU lines
for squeeze and check all lines for clear. Break circulation through choke, pressure test cement lines to 4000 PSI,
batch up cement to 15.8 ppg, pump 5 BBl water, followed by 18 BBl Class G Cement, catching 400 PSI initially
and holding 800 psi on back side at 18 BBl away, at 1.45 BPM rate, sting into retainer pump pressure rose to
1000 PSI, pump another 18 BBl of Class G cement at 1.45 BPM rate. The highest pressure seen was 1750 PSI,
at SO pressure was at 1350 PSI, pumped 5 BBl H20 at 1 BPM, Pressure maintaining at 950 - 1000 PSI. SO Mud
line froze had to thaw. Pumped 20 BBl of 9.9 PPG mud to displace at 1.5 BPM rate starting pressure 800 PSI
ending pressure 1900 PSI. SO, pressure fell to 1550 PSI and maintained. waited 15 minutes on hesitation
squeeze, pumped 5 BBl mud at 1 BPM rate with ending pressure of 2250 PSI. SO pressure fell to 1950 PSI.
Waited 15 minutes on hesitation squeeze. Pumped another 9.5 BBl of mud with a final pump pressure of 2975
PSI. SO and pressure fell to 2500 PSI. PU pipe and unsting from retainer. Pressure on casing rose from 800 PSI
to 1000 PSI and settled out at 900 PSI. Reverse circ to pits, when mud turned to water, divert cement to slop tank
(+- 2.5 bbls cmt back) 33.5 BBl Cement below retainer. Blow dn all lines and choke. Pump dry job from ISO tank
(no good) build and pump dry job - blow dn lines. POOH. PU bit and scraper, RIH with DC.
1/13/05
RIH with DC, and 2 stands of DP. RIH work scaper from 3163' to 3420' and from 4663' to 4920' continue into hole
and tag top of retainer at 5532'. lD two working singles and RIH with 1 stand, P/U power swivel (had problems
with hyd hoses). Drill HOWCO fast drill retainer #6 FROM 5532' to 5538' in about 1 hour looks like approximately
2' of cement below retainer. WOB 6K, 100 RPM, 3BPM, then broke free. Circulate and clean retainer setting area.
Wash down to 5636'. Blow down and RD power swivel. RIH and tag at 5753' set 10K down, did not see any
resistance prior to tagging. lD single and PU Kelly joint with head pin. CBU had several BBlS of a very thick
viscous material with a very gritty texture to it come across shaker. Circulate and condition mud dropping weight
down to 9.5 PPG, and circulate around. Mix dry job, and monitored well for flow, prior to pulling out of hole. Blow
down. POOH stand back in derrick.
1/14/05
POOH - Work BHA - Blow down. PU champ packer, with single and XO on top, and make up on catwalk, hang
same in elevators. PU single joint 2 7/8" IBT tubing and set in slips with XO in top, MU same to bottom of champ
SRU 32A-15 morning report summary AFE 163075. CONFIDENTIAL: last revised 8/29/2005, Page 6
{
~
packer hanging in elevators. RIH with 28 stands and PU multi-service tool and MU with single and XO, RIH with
another 49 stands (77 stands total with 2-singles) (1 HR WOO) Champ packer set at 4893'. RU squeeze manifold
and prep for negative pressure test, Pressure up on annulus to 500 PSI felt multi service valve open. Monitor
bubble hose for 25 minutes had a steady increase in flow. Bleed casing pressure off, pump down DP, @ 970
strokes start to pressure up, continue to pump until pressure reached 1000 PSI, line up to choke and bleed off.
PU on DP 3' to open bypass. Reverse circulate BU at approximately 1000 strokes had gas back to surface,
pumping through choke going to gas buster, circulate gas out and an additional BU. Switched over circulating
long way taking returns through choke going to gas buster. Circulate 2 BU with no sign of gas. Monitor well, mix
dry job, well out of balance tubing light, closed TIW valve. Valve leaked changed out same. Pump dry job, PU
power swivel break out TIW and saver sub lay down same. RU tongs and prep floor for laying down pipe
POOH laying down PH-6 tubing installing protectors on each end.
1/15/05
LD 3.5" PH-6 DP. RU manual rig tongs break out and lay down multi-service tool. RD and LD rig tongs. Continue
to lay down drill pipe, lay down Champ packer and 1 joint of 2 7/8" tubing. Trip in hole with DC from derrick and
lay down same. Trip in hole with drill pipe from derrick and lay down same. Change pipe rams from 3.5" to 2.875",
pull wear ring, MU test joint and set test plug, fill stack and choke with water. Test BOP, choke manifold, and floor
valves too 250 PSI low and 3000 PSI high. PJSM. Load pipe racks with 2 7/8" IBT tubing, sort and number tubing
(Slick - Centralizer joints) Pick up handling tools. PU and run 2 7/8" tubing, drift with 2.375 OD rabbit
1/16/05
RU fill line and continue to RIH filling tubing going in to hole. RU Pollard to run chemical injection line PU mandrel
make up line and test same. Continue to RIH filling tubing, and banding chemical injection line, RIH and tag
bottom at 5749.95 pick up and space out, MU hanger terminate chemical injection line, land tubing and RILDS
28M up weight and 28M down weight. Total of 178 joints in hole. Total of 156 bands in hole. NU Install additional
7" casing x 2 7/8" tubing annulus valve on off side of tubing spool. Removed VR plug through valve after
installation. MU Lake Charles Cement head, PU and break out pups used for landing joints and test joints. RD
and LD Foster power tongs. RU squeeze manifold, RU annulus return line through choke going to shaker and
slop tank. Circulate and clean hole. PJSM. Pump 10 BBLs diesel down tubing for freeze protection on back side,
followed by 1 BBL mud to flush lines, blow down lines. Pump 3 BBL CW1 00 to fill and flush lines, and test cement
lines to 4000 PSI, bleed pressure off, pump an additional 7BBLS of CW1 00. Pump 30 BBLS of Mudpush XL @
10.5 PPG. SD and batch up lead cement slurry of 20 BBL of lite-crete with Cement at 12 PPG, pump same at 3.5
BPM, followed by an additional 33 BBLS of lite-crete (No Cement) pumping at 4.5 BPM rate. SD and batch up Tail
cement slurry of class G cement at 15.8 PPG. Batched up to 15.8 PPG, and pumped 25 BBLS of same with
density flux from 14.9 to 16.4 PPG. SD, washed lines, dropped plug displaced with lease water. Bumped plug at
22.30 HRS, pressured tubing to 3500 PSI and held pressure for 10 minutes with no pressure loss, bled off
pressure and checked floats had 1/4 BBL of returns and float held.
Blow down and RD cement lines.
1/17/05
Pressure up and rupture disc at Chemical injection mandrel, (4300 PSI) continue to pump and clear area of any
residual cement. Clean floor, RD Cement head and lay down same, start to clean pits. RU Pollard Wireline
RIH with temp survey tools to 5000' logging in and out at 60' per minute 5 minute stop at hanger and at 5000'.
Power wash stack and prep for ND. LD landing joint and Set 2.5" CIW H BPV. ND BOP equipment including riser.
Freeze protected 13-3/8" X 7" by Pumping 3.5 bbls Diesel into annulus with test pump work psi @1500 psi broke
and fell to 500 psi and built back to 1000 psi @ shut dn 800 psi and shut valve. NU tree and Test hanger void to
5000 PSI held for 15 minutes with chemical injection port open with no leak. Pull BPV and set TWC test tree to
5000 PSI held for 15 minutes no leaks. Pull TWC and freeze protect tree using diesel fuel. Install BPV. Release
rig at 18:00
Lay felt and liner at relief pad to stack rig out on, blow down boiler, continue with pit cleaning and disposal of
solids, palletize equipment and prep to move.
1/19/05
Using triplex test pump and pumping diesel pressure 7" casing x 27/8" tubing annulus to 2000 PSI, SI an hold
pressure for 30 minutes with a 50 PSI pressure drop. Bleed pressure off. Pollard RIH with 2.35" GR tagged at
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 8/29/2005, Page 7
{'
~.
5601' WLM which is 91' high. Noticed some anomalies with counter, POOH, from point were counter was to zero
to where it topped out 100' off. Picked up lubricator and run tool string down to LOS counter off 90'. RIH second
time to verify counter discrepancy, put heater on counter to try and keep it from locking up, Tagged at 5697' WLM
POOH cement LC at 5692' pipe measurement. Lay down lubricator and secure well.
1/20/05
Test BOP to 250 PSI low and 5000 PSI high. PJSM. RIH with coil, while cooling down taking returns to Johnson
tank. Start to pump N2 at 240 SCM per minute, monitoring returns in Johnson tank. Tag bottom at 5686', PU 5'
and increase rate to 600 SCFM rate, max pressure 2580 PSI monitoring returns, at calculated returns had N2 to
surface, put on choke and continued to blow for 10 minutes. POOH, trapping 1800 PSI on tubing, remove injector
head and spooling up coil. NO BOP, stage BOP and injector in transportation rack. Secure well.
1/21/05-1/23/05
RO/MO
1/24/05
Schlumberger out at 06:00 hrs spot equipment and start to rig up, had PJSM, complete Unocal explosives and
perforating check list, arm guns, NU, test lubricator to 250 PSI low and 3000 PSI. RIH using Schlumberger
Ultrasonic Imager Log dated 9/21/94, tie in to perforate from 5555' to 5567'. Confer with Meg Kremer prior to
perforating. Fired guns at 10:12 HRS had N2 cap of 1778 PSI, within 5 minutes had pressure of 1955 PSI and
built up to 1958 over the next 30 minutes. Schlumberger POOH all guns had fired, rigged down and departed
field. Turned well over to production.
SRU 32A-15 morning report summary AFE 163075, CONFIDENTIAL: last revised 8/29/2005, Page 8
)
Unocal Alaska
909 W. 9lh Avenue
Anchorage, AK 99501
Tele:(907) 263-7889
Fax: (907) 263-7828
E-mail: oudeand@unocal.com
UNOCAL~í~)
Debra Oudean
G & G Technician
Date: June 15, 2005
To:
AOGCC
Helen Warman
333 W. ih Ave. Ste#100
Anchorage, AK 99501
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WELL VENDOR PERMIT . API
# NUMBER
LOG TYPE
LOG'·
SCALE DATE
INTERVAL RUN B. NOTES ..
LOGGED # LINE LAS, PDS,
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1 pds t /3 ~ f--ý
, ..
SRU Schlurnberger 194-0840 501331014101 PLUG SETTING HECORD
32A-15 WEATHERFORD RETRIEVABLE
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SCU Schlumberger 199-0540 501331012501 PLUG SETTING RECORD 3.5" 4/30/2005 10530-10675
:21A-09 MAGNA RANGE BRIDGE PLUG
! CEMENT DUMP BAILER
išCtJ" -. Schlumberger 160-0210 SÖ1'á31öiö400 ABANDONMENT RECÖRDJUNK
:314-04 BASKET/GUAGE RING CEMENT
! RETAINER
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Unocal Alaska
909 W. 9th Avenue
Anchorage, AK 99501
Tete: (907) 263-7889
Fax: (907) 263-7828
E-mail: oudeand@unocal.com
UNOCALe
Debra Oudean
G & G Technician
Date: March 10,2005
To: AOGCC
Helen Warman
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
SRU 32A-15 & SCU 32-04
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/SRU 32A-15 (COMPLETION RECORD 2 HSD POWERJETS SET CIBP/FAS '15 INCH . 12/27/200415535-5760 1 1 1 ¡
JDRILL RETAINER ¡
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V i ,RETAINER i ¡ ! 'i i
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: RETAINER.. .. .. . . ¡
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5CANNEC JUN 1 ~7 2005
Ple~e acknOwl~PI by s.~:n:a::py of Ihi~):¡: 10 (907) 263-7828,
, STATE OF ALASKA '
ALA~ )OIL AND GAS CONSERVATION COMM. )ION
WELL COMPLETION OR RECOMPLETION REPORT AND ~Q~~0 '?nns
1 a. Well Status: OilD Gas [2] Plugged 0 Abandoned 0 Suspended U WAG U 1 b. Well CI,a""" S, ,s"",:, ',,'" ",' " "','",, '1"',",,,', ~'" "",:J!.""", ,'",),',:" ,L.""" ".i,U"", ,,'
20AAC25.105 20AAC25.110 ~ Developme~~:':'1~1· n;;! ;')\ «(!t~PI~r~~pry[J,.-
GINJD WINJD WDSPLD No. of Completions '/Othe{Åtllt-,/.tavservice D'" " 'Stràti~~ãéhié~t~~tO~{
2. Operator Name: 5. Date Comp., Susp., or 12. Permit to Drill Numbeir:"":"'~i:':i;:i':;
Union Oil Company of California Aband.: 10/3/04 94-84 ..~Ðl/....3 ~
3. Address: -6. Date Spudded: 13. API Number:
PO Box 196247, Anchorage, AK 99519 n/a 50-133-10141-01
4a. Location of Well (Go:1ernmental Section): n l>I' j 7. Date TD Reached: 14. Well Name and Number:
Surface: 2300 F...., 1040 FW, Sec. 15 T8N R9W I.5)T '-"" nla SRU 32A-15
Top of Productive Horizon: 8. KB Elevation (ft): 15. Field/Pool(s):
_ -J j 15' Swanson River Fieldl
Total Depth: 2286 FIÙ., 3161 F~, Sec. 15 T8N R9W ~ 9. Plug Back Depth(MD+TVD): Tyonek
7,336'/7,250' Hemlock
10. Total Depth (MD + TVD): 16. Property Designation:
11,590/11,187 Swanson River
11. Depth Where SSSV Set: 17. Land Use Permit:
nla A-028384
19. Water Depth, if Offshore: 20. Thickness of Permafrost:
nla feet MSL nla
4b. Location of Well (State Base Plane Coordinates):
Surface: X = 348,884, Y = 2,480,047
TPI:
Total Depth: X = 351,036, Y = 2,480,023
18. Directional Survey: Yes D No I [2]
21. Logs Run:
Gamma RaylCCL, temperature survey
22.
CASING WT. PER GRADE
FT.
22"
13-3/8" 54.5 K-55
7" 26,29 P-110/N-80
5" 18 L-80
CASING, LINER AND CEMENTING RECORD
SETTING DEPTH MD SETTING DEPTH TVD
TOP BOTTOM TOP BOTTOM HOLE SIZE
o 45' 0 45'
o 2,958' 0 45'
o 10,257' 0 9938'
9,971' 11,590' 9672' 11187'
CEMENTING RECORD
AMOUNT
PULLED
see schematic attached
18-5/8"
10-5/8"
6"
23. Perforations open to Production (MD + TVD of Top and Bottom
Interval, Size and Number; if none, state "none"):
Top
7,267'
7,358'
Btm Amt
7,282' 15'
7,398' 40'
spf Zone
6.0 68-0
6.0 68-0
26.
Date First Production:
October, 2004
Date of Test: Hours Tested:
October, 2004
Flow Tubing Casing Press:
Press.
24.
TUBING RECORD
DEPTH SET (MD) PACKER SET (MD)
9,766', 11,256' 11,186
SIZE
2-7/8", 2-3/8"
Comments
Upper Lobe
Lwr Lobe
25. ACID, FRACTURE, CEMENT SQUEEZE, ETC.
DEPTH INTERVAL (MD) I AMOUNT AND KIND OF MATERIAL USED
see schematic
PRODUCTION TEST
Method of Operation (Flowing, gas lift, etc.):
Flowing
Oil-Bbl:
....
Oil-Bbl:
Production for
Test Period
Calculated
24-Hour Rate ...
Gas-MCF:
Gas-Oil Ratio:
Water-Bbl:
Produced water
Water-Bbl:
Choke Size:
Gas-MCF:
Oil Gravity - API (corr):
27. CORE DATA
Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary).
Submit core chips; if none, state "none".
nla
t-..c J i\H\.t"-[\ C) .... 2 0 nï:
,) ...r\r" nt. "'.' .J U L (1 d -. J..;,J
Form 10-407 Revised 12/2003
ODf(-"I~'
, --' : , h ,I
. ¡ \ ' ! ."; I' i \ \
'-..~ .: \. \.
RBDMs BFL FEB 2 4 2005
l·r
"
l;'
f
l_..
CONTINUED ON REVERSE
28. GEOLOGIC MARKERS
NAME MD TVD
Glacial_Base MJF 591 591
Tks_ YELLOW 1,472 1,472
A9 2,561 2,561
B2B 3,029 3,028
Beluga 3,504 3,503
41-4ST 4,121 4,120
Mid_Beluga_MJF 4,591 4,590
50-6ST 5,008 5,007
L. L._ Tnk_MJF 5,514 5,511
D1CT 6,050 6,038
61-8ST 6,561 6,526
66-3STE 7,046 6,981
70-8CT 7,524 7,422
mtl_mark 8,067 7,920
80-2ST 8,555 8,367
E10 9,247 9,007
Hemlock_MJF 11 ,272 10,887
TD 11,590 11,187
29. FnQMA TION TESTS
Include and briefly summa I 1st results. List intervals tested, and attach
detailed supporting data as necessary. If no tests were conducted, state
"None".
n/a
30. List of Attachments:
summary of morning reports, schematic.
31. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Printed Name: Neil Maqee
Signature:
<-IJ. óluvn(ðr
Contact: Steve Tyler 263-7649
Title: Acting Drilling Manager
Phone: 907-276-7600
". 8P- 1./
2/15/200j f ÂJf 1tJi.
Follow up to Sundry 304-340
INSTRUCTIONS
Date:
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 1 a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply
for I 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 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other
spaces on this form and in any attachments.
Item 20: True vertical thickness.
Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
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 reported 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: If no cores taken, indicate "none".
Item 29: List all test information. If none, state "None".
Form 10-407 Revised 12/2003
) ) Swanson River
Well SRU 32A-15
UNOCALfj Completion
Cas i n 9 & Tub n 9
RKB =15.0' Size Type Wt Grade Thrd ID Top Btm Hole Cmt Cmt Top
~~ - -~ 22" Conductor Surf 45' Yes Surf.
13-3/8" Surf Csg 54.5 K-55 12.615 Surf 964' 1000 sx Surf
'" DV Collar 964' 967'
! ·1.... . 18- 5/8"
. 2144'
13-3/8" Surf Csg 54.5 K-55 12.615 967' 2958' 600 sx (Calculated)
![ 7" 22- P-IIO 6.184 Surf 39'
N ~,.( 7" 26 6.276 39' 2097'
@
u 7" Prod Csg 22- 6.184 2097' 3439' 1000 sx 6495'
0
I- 7" 2L- N-80 6.276 3439' 6158' Thru DV CBL
7" 29 8rd 6.184 6158' 7933' 10-5/8" @ R467'
7" 26 P-IIO 6.276 7933' 8467'
DV Collar 8467' 8470'
7" Prod Csg 2L- P-II0 6.276 8470' 9789' 1000 9399'
7" 29 6.184 9789' 10,257' sxs Calculated
5" Liner 18 L-80 Buttress 4.276 9971' 11,590 6" 500 sxs 11,250'
CBL
Tubin~ 15.0' Original RKB to Tbg Hngr
27/8" I 6.4 I N-80 I Buttress 2.441 Surf I 9766'
23/8" 4.6 N-80 Buttress 1.995 9,766' 11,256'
~
@
u
0
I-
NO. Depth
15.0'
GLM #1. 1622'
GLM #2. 3183'
GLM #3. 3948'
GLM #4. 4777'
GLM #5. 5545'
GLM #6. 6220'
GLM #7. 6891'
GLM #8. 7597'
GLM #9. 8303'
GLM #10. 9039'
GLM #11. 9726'
A. 7336'
B. 9300'
C. 9717'
1. 9766'
2. 10,448'
GLM #12. 11,149'
3. 11,186'
4. 11,226'
5. 11,256'
ID
2.347
2.347
2.347
2.347
2.347
2.347
2.347
2.347
2.347
2.347
2.347
1. 995"
1.875"
1.875"
2.55"
1.875"
2.32"
1959
10/94
10/06/96
10,332'
6200' to 6280'
JEWELRY DETAIL
OD Item
Tubing Hanger
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
EZ Drill CIBP
Cmt Retainer (TOC in tbg)
Cmt Retainer
Crossover, 2-7/8" EVE 8rd x 2-3/8" EVE 8rd
Otis "XA" Sldg Slve
Cameo KBMG-2 GLM
Otis "BWD" Pkr
Otis "X" Profile Nipple
WLEG
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
3.503"
3.065"
4.125"x2.781"
2.701"
2.872"
Brief History
Originally Drilled & completed.
P&A'd. Milled window in 7" @ 10,257' & Redrilled
Fish - LlH 39' of Eline tools wi 15' of 1-11/16" strip guns
Tight spot in tubing wi 1-11/16" Dummy guns
Bad spot in 7" esg. Problems getting 5" liner through.
PERFORATION DETAIL
Interval ACCUßL
Top Btm Amt spf
7,267' 7,282' 15' 6.0
7,358' 7,398' 40' 6.0
11,326' 11,336' 10'
11,340' 11,346' 6'
11,354' 11,364' 10'
SRU 32A-15 Actual Schematic 02-05
Comments
68-0 Upper Lobe
68-0 Lwr Lobe
Proposed P&A
Proposed P&A
ProposedP&A
REVISED: 9/1/2004 by SL T
2/17/2005 by CRW
RE: SRU 32A-15
JC;,/Ðg~O(
Subject: RE: SRU 32A-15
From: "Dunham, Diane E" <dunhamd@unoca1.com>
Date: Mon, 29 Aug 2005 15: 12: 10 -0800
To:RQbeitFIeckeristeiri<bob..:.fleckenstein@admin.staie;ak. uS>
I was hoping you would say that. I took another look at the sundries there were two jobs filed back-to-back. Just
to be sure I am sending both documents.
Sundry 304-340 should attach the file that references AFEs162944 and 162945 in the name and on the footer.
Sundry 304-388 should attach the file that references AFE 163075 in the name and on the footer.
Thanks Bob!
Diane
Diane E. Dunham
Chevron, 907-263-7604
S(;J.itN~\!!El~ ¡~ U G ~il 0 2_005
From: Robert Fleckenstein [mailto:bob_fleckenstein@admin.state.ak.us]
Sent: Monday, August 29, 2005 2:56 PM
To: Dunham, Diane E
Subject: Re: SRU 32A-15
Diane,
Just send them directly to me or if you have electronic copies send them to me as an email attachment.
BobF
Dunham, Diane E wrote:
Bob-
I am going through and reconciling some of our reports. In the process, I reviewed a form 10-407 for this well
filed on 12/15/04-follow-up to sundry #304-340. The daily summary is missing some of the days. It should go
through to 10/29/04 and currently ends with 10/16/04. Can I send you the correct daily summary for this filing or
do I need to resubmit the paperwork?
Thanks
Diane
Diane E. Dunham
Chevron, 907-263-7604
Content-Description: SRU32A-15 _MRSummary_AFE 163075.pdf
SRU32A-15 _MRSummary _AFE163075.pdf . Content-Type: application/octet-stream
Content-Encoding: base64
SRU32A-15 _MRSummary _AFE162944-162945.pdf· Content-Description: SRU32A-15 _MRSummary_AFE 162944-162945.pdf
10f2
8/30/2005 7:35 AM
RE: SRU 32A-15
Content-Type:
Content-Encoding:
20f2
app 1 ication/ octet-stream
base64
8/30/2005 7:35 AM
3f 'I-:a ¡D
9/14/04
RU Slickline. RIH with 2.18 GR and cut paraffin from 1000' to 9768' while pumping diesel with test pump. POOH. Change
over to 1.25" tool string. RI wI 1.75" GR out tubing tail.
9/16/04
RU Slickline. RIH retrieve valve(s) in GLM #10 @ 9030', GLM #8 @ 7597', GLM #6 @ 6220', GLM #2 @ 3170', GLM #3
@ 3948', GLM #4 @ 4777' and GLM #1 @ 1622'.
9/17/04
Continue retrieving GLV(s) in GLM #11 at 9726', GLM #5 @ 5545', GLM #9 @ 8303, and GLM #7 @ 6891'.
Run Dummy valves in GLM # 1 thru 11
9/18/04
Retrieve valve from GLM #12 @ 11,149' kb. POOH. RD Slickline.
9/21/04
. , '. ,.... y. \ ~ G '.. ~-, ') Ú· rn:;
5~;J\;NNE:'.j /\U" <j ,~~ :- .\.1,)
RU pump truck and pressure test surface iron to 2000 psi. Established circulation with 100 bbls of lease water at 4 bpm @
182 psi. Found communication between C section valves at surface remedy same. Attempt to circulate down csg,
Pressure csg x tbg annulus to 1500 psi. Monitored for 10 min. Bled to 1480 psi. Pumped 18.7 bbls down tbg at .25 bpm,
1600 psi. Bled tbg to 410 psi in 15 min. Pump 2.3 bbls down annulus. Pressured up to 1600psi. SD 10min 1560psi. RD
Pump Truck and lines secure well for further evaluation. Unable to establish circulation through GLM #12 @ 11,149'.
9/22/04
RU slickline. RU pump truck and pressure test lines to 2500 psi. RIH with 2.33" GR. Set down at 9768 KB (2 7/8"x2 3/8"
XO) POOH. RIH with KOT to 9729' KB. Latched & pulled GLM valve #11. POOH. Saw fluid level at 950'.
Pumped/circulate down tubing at 3 bpm rate at 600 psi. 2- tubing volumes monitor well gas on backside. SD and monitor
well while waiting on Xylene.
9/23/04
Perform Injection test at .5 bpm @ 2300 psi. Displace 20bbls of Xylene to GLM # 11 at 9726' wlm with 43 bbls lease
water. Shut in annulus and bull head Xylene into perfs with 18 bbls lease water. SD and monitor. RIH with dummy valve
on slickline set in GLM #11. Unable to break circ thru open pocket @ GLM #12. RU/RIH with APRS 1-9/16" tubing punch
3' long with 2' loaded with eight (318") shots at zero phased. Place gun on depth and pressure up tubing to 700 psi / perf
2-3/8" tubing fl 10313' to 10315' (15' down from a collar) with good indication of fire and just flicker on pressure gauge /
log perfs (unable to see them clearly) bleed of pressure and pooh with gun.
9/24/04
Attempt to break circulation 5 times at different rates with 5 min bleed off on each max psi 2509 with minimum 5 min bleed
off to 505 psi and no circulation. Bleed off pressure (tubing on vacuum) annulus zero. MI/RU APRS. RIH with 1-9/16" gun.
Place gun on depth. Open annulus bleed off 50 psi gas and pressure up tubing to 700 psi perf 2-3/8" tubing from
10,094.5' to 10,100' (8' down from collar to top shot) good indication of fire lost 100 psi on tubing. POOH (all shots fired).
Pump down tubing 3 bbls to catch psi and pressure up 5 times with 5 min bleed off each time at different rates. No Joy on
establishing circulation through tbg punched holes. RU SLU attempt to RIH to recover Dummy Valve @ 9735'.
9/25/04
Recovered Dummy valve @ 9735'. RD Slickline. Established circulation, pump 100 bbls at 2 bpm at 365 psi. RU E-line.
RIH with Howco 2-7/8" EZ-drill retainer. Set same at 9717' RKB. POOH RD. Pump 20 bbls Xylene and chase with 50 bbls
(15 bbls around corner) shut in annulus and bull head 21 Bbls and shut in well. RU 1-1/2" CTU #2. Install night cap and
secure well.
9/26/04
SRU 32A-15 (162944,162945) morning report summary, CONFIDENTIAL: last revised 8/29/2005, Page 1.
RIH wI Howco centralized stinger on 1-1/2" CT Stab into retainer at 9690' ctm. Pump 25 bbls down coil taking returns on
csg X tubing annulus. Perform injection test at .5 bpm with slow building trend tubing to 3190 psi at 9 bbls away and
annulus 2475 psi (700 psi frictionl water). Mix water and batch up 75 bbls cement. Pump 5 bbls fresh water ahead at
1 bpm @ 2300 psi 2.5 bbl away returns I head down hole with 15.8 ppg cement at 15 bbls away shut csg x tubing annulus
.5 bpm at 4010 psi pump total 45 bbls cement and P&A Hemlock perfs. Open csg x tubing annulus and continue to pump
80 bbls of 15.8 ppg cement thru GLM # 11 at 9726' and up back side. Displace coil to retainer with 5 bbls fresh water
followed by 20 bbls lease water I C.I.P at 23:38 hrs. Un-sting and plup 50' and shut in csg x tubing annulus (noticed 1000
psi on coil X tubing annulus) bleed 200 psi from same and psi came back 1 open csg x tubing annulus and pump 2 bbls
down coil and shut in both annulus and pressure up 100 psi over well head psi = 1400 psi
9/27/04
Continue POOH while maintaining 1400 psi on tbg. LO BHA I set back injector head I Secure CTU. R/up E-line unit Open
well tubing at 1800 psi and annulus at 1 00 psi. RIH Logging at 7700 fph with SWS PBMS tool (temp/pressure/GR/CCL)
while maintaining tbg pressure @ 1800 psi. Observed a temp anomaly at 6370' RKB (TO.C). Set down at 9319' RKB with
temp anomaly spike indicating set down in green cement. Pooh maintaining 1800 psi on tubing with test pump. LD PBMS
logging tool. RD E-line unit. MU CT BHA 2" wash nozzle. RIH with dry stick to 7500' start N2 at 200 scf continue RIH to
soft tag 9252' CTM wash to 9300'. Up N2 rate to 600 scf and monitor and strap returns and work pipe up rate to 800 scf 1
Gas to surface I strap and check volume 84 bbls back. POOH RO CT WOC.
9/29/04
RU pump truck. Pressure annuli to 3000 psi. Monitor for 15 minutes lost 20 psi. Bled annuli to zero. RD pump truck and
secure well.
9/30/04
RU Eline, load guns. RIH with 2" HC, 6spf, 60 degree 20' perf gun. Tied into GR/CCL log dated 9-27-04. Spot perf gun
from 7378' to 7398'. Tubing pressure was 2557 psi. Fired gun and pressure went to 2560 psi. POOH. All shots fired. RIH
with 2" HC, 6spf, 60 degree 20' perf gun. Tied into GR/CCL log dated 9-27-04. Spot perf gun from 7358' to 7378'. WHP
was 2657 psi. Bled pressure down to 2380 psi. Fired gun. Pressure went to 2386 psi. POOH. Perf gun had fluid in it. All
shots fired. RD Schlumberger and turned well over to production. WHP was 2529.5 psi.
1 0/3/04
RU Eline. RIH with Halliburton CIBP (2 1/8" 00). Found fluid level at 4080'. Tied into GR/CCL log 9-27-04. RIH to 7350'.
Pulled up to 7345' (20' from top of joint) and set bridge plug. WHP was 2158 psi. POOH. RIH with 15', 2 " HC, 6spf, 60
degree perf gun to 7315'. Tie in with GR/CCL 9-27-04 and set perf gun from 7267' to 7282'. Found fluid level at 4080'.
WHP was 1657 psi (Production bled well down). Fired gun. Pressure dropped to 1654 psi. POOH All shots fired. RD Eline
and secure well.
10/13/04
RU SLU. RIH w/2.3 LIB. Found fluid at 3280 KB. POOH. RIH w/1 3/4" bailer and caught fluid sample at 7258' KB (mid
perf). POOH. RD SLU and secure well.
10/16/04
RU coil unit. RIH w/coil to 4000'. Starting pumping N2 at 200 SCFM and cont in hole. Jet tubing dry with N2. POOH while
holding 1600 psi on tubing. RD coil.
-End of operations for this job-
SRU 32A-15 (162944, 162945) morning report summary, CONFIDENTIAL: last revised 8/29/2005, Page 2.
9/14/04
')
)
RU Pollard. RIH with 2.18 GR and cut paraffin from 1000' to 3500' while pumping diesel with test pump. Fell free
from 3500' to cross over at 9768'. POOH. Change over to 1.25" tool string and perform diagnostics on 2 3/8"
tubing tail. Made several trips in hole with different tool configuration. Final results is that tubing has mechanical
problem restricting drift. 1.75" GR would not pass with typical 1.25" tool string configuration. 1.75" GR fell free out
tubing tail when knuckle joints were added to tool string between spang jars and oil jars and between two pieces
of stem.
9/16/04
RU Pollard Slickline, lubricator and pressure test to 2500 psi. RIH with L kick over tool and Daniels 1 5/8" pulling
tool down to 7592' (GLM #8). Tool set down. Sheared pin trying to catch valve. POOH. RIH with same setup as
before and set down at 6215' (GLM #6) POOH. Read thru old file records and determined GLM were 2 7/8"
mandrels. RIH with 2-7/8" OM1 kickover tool and Daniels pulling tool and catch valve in #10 GLM at 9030'. Jarred
for 45 minutes and valve came free. POOH; RIH with same set up and catch valve in GLM #8 at 7597'. Jarred
approx 10 licks and valve came free. POOH; RIH with L kickover tool and Daniels pulling tool and pulled valve at
6220' (GLM #6) POOH; RIH with L kickover tool and Daniels pulling tool and pulled valve at 3170' (GLM #2)
POOH; RIH with L kickover tool and Daniels pulling tool and pulled valve at 3948' (GLM #3) POOH; RIH with L
kickover tool and Daniels pulling tool and pulled valve at 4777' (GLM #4) POOH; RIH with L kickover tool and
Daniels pulling tool and pulled valve at 1622' (GLM #1) POOH; RIH with L kickover tool and Daniels pulling tool
and latched valve at 9726' (GLM#11) . Trying to spang valve out.
9/17/04
Spang on GLM valve #11 at 9726'. POOH. Had valve; RIH wlL KOT and Daniels pulling tool and pulled valve at
5545', #5 GLM. Lost valve in hole. RIH wlL KOT and Daniels pulling tool and pulled valve at 8303, GLM #9.
POOH, valve on surface. RIH w KOT and tag all empty pockets to see if dropped valve fell in one. POOH
Made three runs trying to pull valve #7 at 6891'. Made small adjustments each run and finally pulled valve. Valve
on surface. Bled well down from 1000 psi to 50 psi. RIH wlL kot and set dummy valve at 3948' GLM #3. POOH;
RIH w/L kot and set dummy valve at 6217' GLM #6. POOH; RIH w/om1 kot and set dummy valve at 1618' GLM
#1 POOH; RIH w/om1 kot and set dummy valve at 3180' GLM #2. POOH; RIH w/om1 kot and set dummy valve at
4770 GLM#4. POOH; RIH w/om1 kot and set dummy valve at 5540'. GLM#5. POOH; RIH w/om1 kot and set
dummy valve at 6890' GLM #7. POOH; RIH w/om1 kot and set dummy valve at 7596' GLM#8. POOH; RIH w/om1
kot and set dummy valve at 8303' GLM #9. POOH; RIH w/om1 kot and set dummy valve at 9039' GLM#10.
POOH; RIH w/om1 kot and set dummy valve at 9726' GLM #11. POOH; Change tool string around for dummy
runs for perforating. RIH with 1.5 wt bars, knuckled up and 5' dummy gun. Set down at 9782'. POOH and gun had
marks on bottom. RIH with 1 5/8" Daniels pulling tool to 9763'. Worked down to 9782'. POOH and no valve.
9/18/04
RIH w/1 5/8" Daniels pulling tool and set down at 6220' (GLM#6) to check if valve was in pocket. POOH, pin
sheared to verify valve was in pocket. RIH w/1 5/8" Daniels pulling tool and set down at 9038' (GLM#10) to check
if valve was in pocket. POOH, pin sheared to verify valve was in pocket. RIH wll 5/8 Daniels pulling tool and
latched lost valve at 9782'. POOH, valve on surface. RIH w/1.56 5' dummy gun down to 10,321'. Beat down
several times and POOH. RIH with 1 1/2" GR to 10,321'. Could not below this depth. POOH Change tools out
RIH w/RS, 4'x1 1/4" stem, x-over, 1 3/4" kj, x-over, 2' x1 1/2" stem to 10,321. Set down. POOH Change out tools
to 1 1/4" and add kj to every joint. RIH with 1 1/4" Daniels pulling tool to 11,300', pull up to 11,149 and latch GLM
valve and sheared pin. POOH RIH w/1 1/4" Daniels pulling tool to 11,149' kb. Latch GLM valve and pull valve.
POOH. RD.
9/21/04
PJSM, RU Schlumberger pump truck and pressure test to 2000 psi. Pumped 100 bbls of lease water at 4 bpm
with 182 psi when well started to circulate. Fluid was clean and saw no oil. Called Pollard to come out and find a
possible hole or unseated GLM. RU hoses to pump down tubing and up annuals. Pumped 54 barrels at 3 bpm
with 222 psi. DSM came by to check on progress and discovered we had communication between C section
valves while circulating. All the pumping did was fill the well and circulated top of well. RU hoses and tried to
pump down annular. Pressured up to 725 psi. Informed DSM. PU to 1500 psi. Waited 10 min. and pressure bled
SRU 32A-15 (162944, 162945) morning report summary, CONFIDENTIAL: last revised 2/18/2005, Page 1.
to 1480 psi. Switched hoses to Pl.O.)P down tubing. Started to pumping and pn:::;:;lure went to 1434 psi at .25 bpm.
Pum ped 3 bbls. And raised pressure to 1500 psi. Stopped pumping and tubing bled to 700 psi in 5 min and to 410
psi in 10 min.3bbls pumped. Pumped up 1600psi. 10min 400psi.4.5bbls pumped. Pumped up to 1600psi. 10min
344psi.5.2 bbls pumped. Pumped up to 1600psi. 10min 323psi. Total fluid pumped 6bbls. Changed hoses to
pump down annular return out tubing. 1600psi. 10min 1560psi. Total fluid pumped 2.3 bbls. RD Pump Truck and
lines secure well for further evaluation.
9/22/04
PJSM, RU Pollard and pressure test to 2500 psi. RU Schlumberger pump truck and pressure test lines to 2500
psi. RIH with slickline. Tool string was RS, 8'x1 1/4" stem, jars, spangs, 3' stem and 2.33 GR. GR set down at
9768 KB (2 7/8"x2 3/8" XO) POOH. RIH with 2 7/8" OM-1 KOT and 15/8" JDS pulling tool to 9729' KB. Latched
GLM valve #11. Pressured tubing up to 300 psi and pulled valve. Pressured tubing up to 600 psi. Tubing bled
down to 300 psi. POOH. Saw fluid level at 950'. Pumped down tubing at .50 bpm rate up to 2500 psi. Dropped
injection rate to .32 bpm while maintaining 2450 psi. Pumped 5 bbls total without returns. Modified trigger on 2
7/8" om-1 kot. RIH with kot and jds pulling tool down to 9741' kb. Latched GLM valve #11. Put 300 psi on tubing.
Jarred and spanged on valve and pulled valve out. POOH and had 75 Ib drag coming out. Pooh and recovered
valve and rebuild same. Pumped down tubing at 3 bpm rate at 600 psi. 2- tubing volumes monitor well gas on
backside. Timed fluid out of tank (found K- factor off on pump skid pumping closer to 3 bpm when it shows 2 bpm)
SO and monitor well while waiting on Xylene.
9/23/04
SO and monitor well while waiting on Xylene and more lease water (tubing on vacuum right away). PJSM.
Perform Injection test - Attempt to fluid pack well pump 2.5 bbls to catch pressure on tubing and 3.5 bbls for
returns on annulus. Pump at .5 bpm and 7 bbls away to reach 2300 psi (still have spring on annulus with gas)
Shut down and watch tubing bleed down 2300 psi to 1080 in 4 min and bleed tubing to zero and went on vacuum.
Open annulus and bleed off 270 psi Gas with oillwater sprits and Displace Xylene to Glm # 11 at 9726' wlm with
43 bbls lease water. Shut in annulus and bull head Xylene into perfs with 18 bbls lease water as follows 1.75 bpm
at 308 psi at 4 bbls away, 1.75 bpm at 480 psi at 7 bbls away and annulus at 350 psi, 1.75 bpm at 586 psi at 8
bbls away, 1.75 bpm at611 psi at 9 bbls away Ann at 500 psi, 1.75 bpm at 967 psi at 10 bbls away ann. at 800
psi, 1.75 bpm at 1560 psi at 13 bbls away ann. at 1550 psi, .5 bpm at2160 psi at 16 bbls away and ann. at 1550
psi, .5 bpm at2261 psi at17 bbls away and ann. at 2200 psi, .5 bpm at 2317 psi at 18 bbls away and annulus at
2280 psi. SD and monitor bleed down fl 2317 psi to 1106 psi in 10 min and bleed tubing to zero with 8 bbls back
and tubing went on vacuum with 400 psi on annulus, open annulus and bleed same Gasloil and water (belching
and puking same). RIH with re-dressed dummy valve while monitor annulus belching and puking Gas/oil/water for
approx 35 min then calmed down and set 1-1/2" Dummy valve In GLM #11 at 9741 RKB and pooh and check K-
over tool (ok) and LD same. Install tree cap and attempt to break circ thru open pocket of GLM #12 by pumping
down tubing to max psi of 2500 psi attempt 5 times to pressure up to 2500psi at different rates and monitor 5 min
bleed offs between same with no luck. Discuss options with town and MU. RIH with APRS 1 9/16 dummy gun - 1
3/8" sub, 1 7/16" CCL, 1 7/16 Knuckle joint, 1 9/16" perf gun (3' 7") down to 10,3351 on Pollard slick line. Tool set
down and pulled 100 Ibs over to free up. POOH (total APRS tool string -7'.) RIH with APRS 1 9/16" dummy gun-
1 3/8" xo, 1 7/16" go box, 1 9/16" perf gun down to 10,335'. Tool set down. POOH (total tool length 4' 7".) RIH with
APRS 1.46" jet cutter dummy gun - 1 3/8" xo, 1.46" jet cutter (total length 2' 3") down to 11,116'. POOH. RD
Pollard. Rig up lubricator on Pollard mast truck for APRS. Wait on 1" knuckle joints and Pollard wire line valve
rams for 7/32 e-line. Wire hot leads on 1" knuckle joints, put rams in wire line valves and put together 1.46" jet
cutter. PJSM, pressure test to 2000 psi and run in hole with APRS 1.46" tubing cutter to 10,431. Pressured up
tubing to 600 psi and fired cutter at 10,431'. Lost 300 psi. POOH. Logged cut and it looked good for the hole it
was suppose to make. Pooh to 9671' and attempt to circ pressure up tubing to 2000 psi with no circ. Finish POOH
and check tools and lId own cutter (fired ok) and install tree cap. Pump down tubing 3 bbls to catch psi and
pressure up 5 times with 5 min bleed off each time at different rates. Max 2504 psi with minimum bleed of in 5 min
to 339 psi. Arm APRs 1-9/16" tubing punch 3' long with 2' loaded with eight (318") shots at zero phased (Changed
out one bad 1" KJ appears that jet cutter had sheered KJ swivel pin) RIH and work gun by GLM at 7597'.
Continue RIH and set down at 10,325 RKB unable to pass same. Place gun on depth and pressure up tubing to
700 psi I perf 2-3/8" tubing fl 10313' to 103151 (15' down from a collar) with good indication of fire and just flicker
on pressure gauge I log perfs (unable to see them clearly) bleed of pressure and pooh with gun.
9/24/04
SRU 32A-15 (162944,162945) morning report summary, CONFIDENTIAL: last revised 2/18/2005, Page 2.
· Continue POOH with perf gun. c-..lk and LD perf gun (all shots fired) installeu lree cap and attempt to break
circulation 5 times at different rates with 5 min bleed off on each max psi 2509 with minimum 5 min bleed off to
505 psi and no circulation. Bleed off pressure (tubing on vacuum) annulus zero secure well vac out pump truck
lines and secure truck and release hand finish RD of APRS and Pollard mask truck and release hands. Suspend
well operations and wait on variance from state on P&A I police pad berm in tanks. Move APRS unit and prep for
CTU RU. Mobe SLB pump hand, APRS hands and Pollard hands. MI/RU APRS and Pollard boom truck. PJSM I
Arm APRS 1-9/16" tubing punch 7' long with 5.5' loaded with 23 (3/8") shots at zero phased and pressure test
lubricator to 2000 psi (no test pack-off leaking change out same) and re-test to 1500 psi (ok). RIH with gun noting
jewelry tie in to GLM #11 and XO. Place gun on depth. Open annulus bleed off 50 psi gas and pressure up tubing
to 700 psi 10 bbls to catch Psi and perf 2-3/8" tubing from 10,094.5' to 10,100' (8' down from collar to top shot)
good indication of fire lost 100 psi on tubing. Log perfs with GRICCL (ok.) POOH and check tools (all shots fired)
Install tree cap. Use all hands and pull and lay liner for CTU RU. Pump down tubing 3 bbls to catch psi and
pressure up 5 times with 5 min bleed off each time at different rates .7 bpm with 6 bbls away to 2504 psi with 5
min bleed off to 460 psi, 1 bpm at total of 7 bbls away to 2509 bbls with 5 min bleed off to 571 psi, 1.5 bpm at total
of 8.5 bpm to 2504psi with 5 min bleed off to 495 psi, 2 bpm at total of 9 bbls away to 2509 psi with 5 min bleed
off to 510 psi, tried pump at steady rate .3 bpm with total of 11 bbls awayl 2509 psi and 5 min bleed off to 1106
psi. RD APRS and RD Pollard SLU and test lubricator to 2000 psi. RIH with 2-718" OM-1 kick over tool with 1-5/8"
JDS with no problems to 9735' locate and jar on valve I pooh no recovery. Check tools pin not sheered on JDS
and chg out JDS. RIH run #2 with same kick over tool and new 1-5/8" JDS.
9/25/04
Continue RIH run #2 with 2-718" OM-1 Kick over tool with new 1-5/8" JDS with no problems to 9735' locate and jar
on valve 6 oil jar licks and pull valve. Pooh and check tools Recovered dummy valve I install tree cap and RD
Slick line and Pump down tubing 8.5 bbls to catch pressure and 20 bbls returns on annulus (gas and oil) after 45
bbls started cleaning up pump total 1 00 bbls at 2 bpm at 365 psi to clean annulus I shut down and monitor well
tubing went on vacuum and annulus puked water gas for 15 min while finished RU on E-line I Held PJSM PU and
arm retainer. RIH with Howco 2-7/8" EZ-drill retainer noting jewelry Tie in to GLM #11 at 9726' RKB and log 61 pup
on top of GLM place retainer on depth 2' above 6' pup on GLM #11 and set same at 9717' RKB Good indication
cap fire not a good indication of retainer stroke on weight indicator wait 15 min and PU 20' and set back down at
9717'. POOH and check tools (ok). Safety Meeting Load 20 bbls Xylene at P&S and transport to padlpump down
tubing and fluid pack well 3 bbls for returns. Pump 20 bbls Xylene and chase with 50 bbls (15 bbls around corner)
shut in annulus and bull head 21 Bbls and shut in well (see attached pump log). RU SLB 1-1/2" CTU #2 and test
bops. See attached bop test sheet (having some problems with electronics, SLB tech out in AM). Install night cap
and secure well. Secure equipment and release SLB for rest. RU choke manifold and prep for job.
9/26/04
P/up BHA = 1.625" roll on conn and pull test 15k + DFCV + hyd disconnect + straight bar + XO + XO + Howco
centralized stinger stab injector and shell test (ok). RIH circ at .25 bpm with no returns from coil X tubing annulus I
returns fl 6500' to 9500'. PJSM and check lines bleed off 600 psi from csg x tubing annulus and shut in same
Continue RIH circ at .25 bpm taking returns fl coil X tubing annulus tag and stab retainer at 9690' ctm and set
down 2500 Ibs Plup 20 ' and re-stab with same bleed off 750 psi csg X tubing annulus gas/oil/water. Pump 25
bbls down coil taking returns on csg X tubing annulus and clean back side (send truck to get hot water for mixing
cement) noticed electronics no functioning properly. Get man lift and check and clean j-box on injector head and
monitor annulus clean flow quit and was laying dead I shut in csg x tubing annulus. Open coil X tubing annulus
and Pump down coil and perform injection test pumped .5 bpm with slow building trend tubing to 3190 psi at 9
bbls away and annulus 2475 psi (700 psi frictionl water) and monitored open coil X tubing annulus and check
retainer (ok). Shut down and monitor bleed down 2625 - 355 psi in 27 min and call town and discuss cement job
PJSM and discuss job with cementers and CT hands and peak I Mix water and batch up 75 bbls cement
Pump 5 bbls fresh water ahead at 1 bpm a12300 psi 2.5 bbl away returns I head down hole with 15.8 ppg cement
at 15 bbls away shut csg x tubing annulus .5 bpm at 4010 psi pump total 45 bbls cement and PandA hemlock
perfs. Open csg x tubing annulus and continue to pump 80 bbls of 15.8 ppg cement thru GLM # 11 at 9726' and
up back side. Displace coil to retainer with 5 bbls fresh water followed by 20 bbls lease water I C.I.P at 23:38 hrs
Unsting and plup 50' and shut in csg x tubing annulus (noticed 1000 psi on coil X tubing annulus) bleed 200 psi
from same and psi came back I open csg x tubing annulus and pump 2 bbls down coil and shut in both annulus
and pressure up 100 psi over well head psi = 1400 psi
9/27/04
SRU 32A-15 (162944,162945) morning report summary, CONFIDENTIAL: last revised 2/18/2005, Page 3.
)
)
Continue POOH Maintaining 100 psi safety over well head pressure. Shut in and secure well with swab and upper
master with 1400 psi on tubing and 350 psi on annulus I Check and LD BHA I set back injector head I Install night
cap on BOPs I Secure CTU and equipment and release Coil hands for rest. Wait on SWS and work on report and
paper work. PJSM with SWS and Rlup E-line unit and test lubricator to 2000 psi (ok). Open well tubing at 1800
psi and annulus at 1 00 psi (SWS pressure tool shows 1791 psi). Having problems getting tool to fall (grease
head). RIH Logging at 7700 fph with SWS PBMS tool (temp/pressure/GR/CCL) Let WH pressure build to 2000 psi
and then bleed back to 1800 psi 3 times observed a temp anomaly at 6370' RKB (T.O.C) and set down at 9319'
RKB with temp anomaly spike indicating set down in green cement. Pooh maintaining 1800 psi on tubing with test
pump. Shut in and secure well with swab and upper master with 1800 psi on tubing and 100 psi on annulus I
Check and LD PBMS logging tool I Install night cap on CTU BOPs I RD E-line unit and stage at P&S yard. MU
BHA 2" wash nozzle = xo = 61 straight bar + xo + 3' straight bar + DFV + same roll on conn. Stab injector head I
Break circ and shell test 300/3000 psi (ok) I open well 11 00 psi and bleed off slow to zero and monitor (ok). RIH
with dry stick to 7500' start N2 at 200 scf continue RIH to soft tag 9252' CTM wash to 93001 Call it good and up N2
rate to 600 scf and monitor and strap returns and work pipe up rate to 800 scf I Gas to surface I strap and check
volume 84 bbls back.
9/29/04
PJSM, RU Schlumberger pump truck and pressure test to 3000 psi. Pressure annuli to 3000 psi. Took 2.75 bbls
to pressure up. After 15 minutes lost 20 psi. Bled annuli back to tank and got 2.25 bbls back. Tubing had 2550 psi
and annuli had 0 psi before test. RD pump truck and secure well.
9/30/04
PJSM, RU Schlumberger, pressure test to 3000 psi and load guns. RIH with 2" HC, 6spf, 60 degree 20' perf gun.
Tied into GR/CCL log dated 9-27-04. Spot perf gun from 7378' to 7398'. Wait on production to put spider on line.
Tubing pressure was 2557 psi. Fired gun and pressure went to 2560 psi. POOH. All shots fired. RIH with 2" HC,
6spf, 60 degree 20' perf gun. Tied into GRICCL log dated 9-27-04. Spot perf gun from 73581 to 7378'. WHP was
2657 psi. Bled pressure down to 2380 psi. Fired gun. Pressure went to 2386 psi. POOH. Perf gun had fluid in it.
All shots fired. RD Schlumberger and turned well over to production. WHP was 2529.5 psi.
10/3/04
PJSM, RU Schlumberger lubricator, pressure test to 3000 psi. Had leak on pump-in-sub. Fixed and test good
RIH with Halliburton easy drill bridge plug (2 1/8" OD) Found fluid level at 4080'. Tied into GRICCL log 9-27-04.
RIH to 7350'. Did not want to go below perfs at 7358'. Pulled up to 7345' (20' from top of joint) and set bridge plug.
Line wt was 836 Ibs. When plug set line wt dropped to 761 Ibs. Picked up and went back down and tagged plug.
WHP was 2158 psi. POOH. Shot another fluid level and it showed 3900'. RIH with 15',2" HC, 6spf, 60 degree
perf gun to 7315'. Tie in with GRICCL 9-27-04 and set perf gun from 7267' to 7282'. Found fluid level at 4080'.
WHP was 1657 psi (Production bled well down per Mr. Ayer). Fired gun. Pressure dropped to 1654 psi. POOH All
shots fired. RD Schlumberger and secure well.
10/13/04
PJSM, RU Pollard and test lub to 2500 psi. RIH w/2.3 LIB to find fluid level. Found fluid at 3280 KB. POOH. RIH
w/1 3/4" bailer and caught fluid sample at 7258' KB (mid perf). POOH. RD Pollard and secure well.
10/16/04
PJSM, RU Schlumberger coil unit and wait on water to test. Prime pump, fill coil, test BOPs to 3000 psi and put
together BHA. RIH wlcoil to 4000' and start displacing reel. Starting pumping at 200 SCFM and cont in hole. Got
returns at 4900' and tagged plug at 7336'. Increased pump rate to 550 SCFM. Continue to jet tubing dry with
nitrogen and fluid made the turn at 2775 psi circulating pressure. Jetted tubing dry and displaced 24bbls from
tubing. Start out of hole holding 1600 psi on tubing. Coil on surface. Close master, swab and wing valves with
1500# N2 pressure on tubing. Pumped 1000 gallons N2 during job. RD coil and move to P&S yard,
SRU 32A-15 (162944, 162945) morning report summary, CONFIDENTIAL: last revised 2/18/2005, Page 4.
)
)
Subject: SRU 32A-15 Sundry #304-388 Weekend contingency Plan
From: "Tyler, Steve L" <tylersl@unocal.com>
Date: Fri, 14 Jan 2005 15:29:08 -0900
To: Winton Aubert <winton_aubert@admin.state.ak.us>
lqtt-t7~'t
Winton,
Unocal operations are actively working the SRU 32A-15 recompletion to access the Beluga 56-0
sand. Weare working the procedure that was presented to you in the contingency portion of Sundry#
304-388. We squeezed multiple times in the Beluga sands and then began the squeezes for the
Sterling sands. The first set of Sterling squeeze perfs failed to pressure test after multiple cement
squeezes. A final squeeze, tested only to 800 psi, was done. The final completion will utilize
completion packers to straddle the Sterling interval for isolation.
We drilled out the cement retainers to the lower Beluga sands, and found the lowest most set (the 56-0
sand) with no cement below the retainer. A cement retainer was run back in the hole and the zone was
resqueezed. We drilled out and again found no cement below the retainer. We are now running into
the hole to perform a negative test for both Beluga sands. Success of this test will mean we will
complete the well with the tubing isolating our Sterling squeeze perfs and the completion as planned.
The diagram for this forward plan is attached.
If the negative test for the two lower Beluga saIAg~ dæ~IJrt hold, we would like to, move to a
contingency option of cementing in the~:rrom below the 56-0 sand up to approximately 3400
feet. The decision point for this option will occur over the weekend.
Please let us know if you approve.
SCANNED JAN 2 0 2005
Workover Foreman I Engineering Tech
~~3 -7049
RKB =15.0'
,
L
.
!)I
u
0
...
~
A
t
7Æ~
c 5kll¡,~~
a:
II
6
tf'~~~~:¡
TD= 11,590' PBTD= 11,560'
Max Deviation = 24.30 @ 7815'
Size
22"
13-
3/8"
')
¡q4 ,. oJ1
)
Type
Conductor
Grade
Casing & Tubing
Thrd ID Top Btm
Surf 45'
Wt
Surf Csg
54.5 K-55
54.5 K-55
~ P-11O
26
29
26 N-80
29 8rd
26 P-11O
13-
3/8"
7"
7"
7"
7"
7"
7"
7"
7"
5"
Tubin2
!-P .,.'
27/8"
2 3/8"
A..
B.
C.
D.
E.
F.
G.
H.
:t.
J.
GLM #1.
GLM #2.
K.
1.
GLM #3.
GLM #4.
GLM #5.
2.
3.
GLM #6.
4.
5.
GLM #7.
SRU 32A-15 Proposed Schematic_01-12-05.doc
Surf Csg
Prod Csg
Prod Csg
26
29
18
L-80
P-110
Liner
15.0" Original Rh:B 10 Tbg Hngr
ò..J ,-~u HUllrl'"
6.4 N-80 Buttress
4.6 N-80 Buttress
Buttress
12.615
Surf
964'
12.615 967' 2958'
6.184 Surf 39'
6.276 39' 2097'
6.184 2097' 3439'
6.276 3439' 6158'
6.184 6158' 7933'
6.276 7933' 8467'
6.276 8470' 9789'
6.184 9789' 10,257'
4.276 9971' 11,590
!,.L! ~~!Jrf "¡~~;'
2.441 6000' 9766'
1.995 9,766' 11,256'
Swanson River
Wen SRU 32A-15
:Proposed Completion
Hole
Cmt Cmt Top
Yes Surf.
1000 Surf
sx
600 sx 2144'
(Calculated)
1000
sx 6495'
Thru CBL
DV@
8467'
1000 9399'
sxs Calculated
500 11,250'
sxs CBL
18-
5/8"
10-,
5/8"
6"
Depth
15.0'
2500'
3384'
3400'
4893'
4899'
4900'
4913'
4923'
JE'WELHY DETAIL
on Item
Tubing Hanger
Chem Inj Sub
CM!.] sid sleeve
FHL Prod packcl'
X Profilt~ Nipple
Seal Assy wI (5) seal units
Model "D" Prdudìon Pkr wi 5'
XN profile nipple
WLEG
In
2.363
2.31
2.441
2,31
2.406
3.25
2.25
2.441
5750'
6000'
6220'
6891'
7000'
7345'
7597'
8303'
9039'
9300'
9717'
9726'
9766'
10,448'
11,149'
2.347
2.347
2.347
2.347
2.347
2.347
1.995"
1.875"
1.875"
-- ,
.: 4~~~r ~/~s~gs
¡¡¡¡¡:¡;;.;¡¡:; ,.t I NO.
~.1
~, ;> ~~~;;'d~~I¡'~: :~~.'~
I;.¡ '4.1i~:~Þ:if':'-~'"
~ i;: ~;.
!~~JJ
6.
7.
8.
11,186'
11,226'
11,256'
2.55"
1.875"
2.32"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
3.503"
3.065"
4.125"x
2.781"
PERFORATION
Interval I I Accum.
Top Btm Amt spf
3,493' 3,503' 10' I 6
4,986' 4,996' 10' I 6
4,993' 5,005' 12'
5,014' 5,024' 10'
5,545' 5,555' 10'
5,555' 5,567' 12'
5,590' 5,600' 10'
7,267' 7,282' IS'
7,358' 7,398' 40'
11,326' 11,336' 10'
11,340' 11,346' 6'
11,354' 11,364' 10'
SCAJ\H\!EC .¡t\l~ 2 0 2005
xo tl 2-7/8" Butt
ClBP
Cut tubing
Cameo MMG-P GLM
Cameo MMG-P GLM
Tbg. plug
EZ nrm CIBP
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cmt Retainer (TOe in tb~)
Cmt Retainel'
Cameo MMG-P GLM
Crossover, 2-7/8" EUE 8rd x 2-3/8" EUE 8rd
Otis "XA" Sldg Slve
Cameo KBMG-2 GLM
2.701"
2.872"
Otis "BWD" Pkr
Otis "X" Profile Nipple
WLEG
HISTORY
6
6
Comments
Sqz Perfs
Sqz Perfs
! 50-6 Beluga Proposed
I Sqz Perfs
I Sqz Perfs
156-0 Beluga Proposed
I Sqz Perfs
168-0 Upper Lobe. P&A'd 10/24/04
168-0 Lwr Lobe. P&A'd 10/24/04
IP&A
Ip&A
Ip&A
6
6.0
6.0
REVISED: 10/19/2004 by SLT
)
')
Unocal Alaska
909 W. 9th Avenue
Anchorage, AK 9950 I
Tele: (907) 263-7889
Fax: (907) 263-7828
E-mail: oudeand@unocal.com
1', .~!'f()<i9t
I :~),~ ~~(,:,:"'J" II
UNOCAL
Debra Oudean
G & G Technician
Date: November 29, 2004
To:
AOGCC
Helen Warman
333 W. 7th Ave. Ste#100
Anchorage, AK 99501
'. '
WELL .: . C'P"":>',n:::':'?'LOG TYPE' SCALE LOG DATE 1~6:~L' L~E' CD
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lVV 1 I SATURATION TOOL ¡
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r ~~~:lfiSRU 32A-1S- g~~~~~T~~~SRE~CORD2 HSD POWERJET 6SPF 60 ... 5 INCH9/30/200Ù280-760Ó 111
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'\.. ~.;)L",,,,,.-,,,,,,,.,.,,,,,,.",,,,,,,,,,,,,.,,,,,..,,.,,.,,,,.,,.,,,.""".",.",,,,,,,,,,",,,,,,,,,,,,,,,.,,,,,,,,-,,,,,,.,,,,,,,,,,,,,,,,,,,,,,,,,,-"""",,"-" '" '"'' """"""''''-,''''''''''''''''''''''''-'''''''' ,,,,,,,.,,,,,,,,.,,,,,,. '",,,,.,,,. """." "'"'-...''''''''''..''''"''''''-''''' .."..",..."",,,,,,,,,,,,,..,,......,,,-,,,,,,,,,,.,,.,,_,,,,,,,,,.,,,,,,,..,,,,,"'"""",,,,,...,,,,,,,.,J
'~~r--" t,~ li\.í~i_ E. "ii' fl. on 't- c,_ .~ [1 ¡1~~
;;')~',Mn~'1 ~./ ¡U, ~ ~ _ (~ C ~ - .
Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to (907) 263-7828.
Date: /~;> ~ ~
)
)
MEMORANDUM
State of Alaska
Alaska Oil and Gas Conservation Commission
TO: Jim Regg, ?ß~~- IltZb D+ DATE: November 1, 2004
P. I. Supervisor N-tfl
FROM: Jeff Jones,
Petroleum Inspector
SUBJECT:
Perforation P & A
Unocall SRU 32A-15
PTD 1940840
Swanson River Field
Swanson River Unit
November 1, 2004: I traveled to the Swanson River Field to witness a
perforation abandonment operation on Unocal's SRU 32A-15 well.
Steve Lawrence was the Unocal representative for the abandonment operation
today. Prior to my arrival a mechanical SB & A pack-off plug wassetin the 2 7/8"
tubing at 7000' RKB with a wire line unit. 10 gallons of class G cement was then
dump bailed above this plug and allowed to harden. I witnessed a successful
3000-PSI pressure test on this plug and APRS wire line then tagged the top of
cement at 6974' RKB. This cased hole abandonment complies with AOGCC
regulation 20 AAC 25.112(c)(1 )(E).
Summary: I witnessed the pressure test and wire line tag of a perforation
abandonment plug in Unocal's Swanson River Field well SRU 32A-15.
Attachments: Well bore schematics (2)
NON-CONFIDENTIAL
SCANNED DEC 142004
P-A Unocal SRU 32A-15 1-11-04 JJ.doc
). )
',SRU 32A..15 Isolate Sterling & Recomplete S6~ Revision #1
C.$lng & Tubing
R:.KB =15.0' Size Type Wt Grade Thrd ID Top Btm Bole Cmt Cmt Top
2T' Conductor Surf 45' Yes Suñ.
13- Surfesg 54.5 K.55 12615 Surf 964' 1000
3/8" S1D'f
IX
DV Collar 964' 967' 18-518"
. 13- 2144'
3/8" Surfesg 54.5 K-55 12.615 967 295S' 600sx (CaIcu1ated)
s
!I 7" 29 P.II0 6.184 Surf 39'
~ .,. 26 6.216 39' 2f1:Tf 1000
.,. 29 6.184 2f1:Tf 3439' IX
~ .,. Prod Csg 26 N-SO 6.276 3439' 615S' Thru 6495'
CBL
.,. ~ 8rd 6.184 6158' 7933' 10-518" DV@
.,. 26 P-I10 6.216 7933' 846T 8467'
DV Collar 8467' 8470'
7" Prod esg ~ P-II0 6.216 8470' 9789' 1000 9399'
.,. 29 6.184 9789' lO,2ST sxs CaIcuI8ted
S" LiDer 18 L-8O Buttn:ss 4.276 9971' 11.590 6" soo 11,2S0'
sxs CBL
Tobina 15.0' OrIgInal RKB to Tbg Hncr
2718" 16.4 1 N-SO 1 Buttress 12.441 I Surf 1 9766'
2 3/8" 4.6 N-80 Buttress 1.995 9,766' 11,256'
\j-
I
TD= 11,590' PJJI'])-l1,568'
MIlS Dm8Uea - 24,3° @ m5'
JEWELRY DETAIL
NO. Depth ID OD Item
15.0' Tubing Hauger
GLM"I. 1622' 2.347 5.S" x 4.673" Cameo MMG-P GLM
GLM iØ. 3183' 2347 5.S" x 4.673" Cameo MMG-P GLM
GLM .. 3948' 2.347 5.S" x 4.673" Cameo MMG.P GLM
GLM #U. 477T 2347 5.S" x 4.673" Cameo MMG-P.GLM
GlMH. 5545' 2.347 5.S" x 4.673" Cameo MMG-P GLM
GLM tI6. 621JJ' 2347 5.S" x 4.673" Camc:o MMG-P GLM
GLM tn. 6891' 2347 5.S" x 4.673" Cameo MMG-P GLM
GLM #18. 759T 2347. .5.5" x 4.673" Cameo MMG-P GLM
GLM #19. S303' 2.~7 5.S" x 4.673" Cameo MMG-P GLM
GLM NI0. 9039' 2347 5.5" x 4.673" Cameo MMG-P GLM
GLM NI1. 9726' 2347 5,S" x 4.673" Cameo MMG-P GLM
A. 7345' EZ Drill CIBP
B. 9300' . Cmt Retainer (TOC in tbg)
C. 9717' Cmt Retainer
1. 9766' 1.995" 3.503" Crossover, Z. 7/8" EVE 8re1 x 2-3/8" EUE SreI
2. 10,448' 1.87S" 3.065" Otis "XA" Slelg SIve
GLM"12. 11,149' 1.87S" 4.125" x Cameo KBMG-2 GLM
2181"
3. 11,186' 25S" Otis "'BWD" PIa
4. 11,226' 1.87S" 2701" Otis ..X" Profile NIPPle
5. 11.256' 232" 2.872" WLEG
B Í' i e f Hi s tory
Originally DriUed & completed.
PM'd. Milled window in T @ 10,257 &
Redril1ed
10106196 Fisb-LIH39' ofEJinctoolsw/15' of 1-11/16"
strip guns
10.332' Tight spot in1ubíng wI 1.1 1/16" Dummy guns
6200' to Bad spot in T c:ag. Problems gettins S" liDcr
6280' tbrougb.
PERFORATION HISTORY
IDten'aI A.cœnL'
Top Bbn Amt sri a., f-
7;JG1' 7~ 15' 6.0 68-0 Upper Lobe
7~ 7.)98' ... 6.8 Cí8-t Lwr IAtbe
11.326' 11,336' 1(1 P&A M6'04
11,340' 11,346' e P&A 9/J6'N
11.354' 11,364' 1(1 P&.A 9/J6'N
1959
10194
,SRU 32A..lS
)
)
Isolate Sterling & Recomplete 56-0
Revision # 1
PROPOSED
Casing & Tubing
Size Type Wt Grade Thr~ m Top Btm Bole Cmt Cmt Top
22" Conductor Surf 4S' Yes 8uñ.
13- SurfCsg 545 K-5S 12.615 Surf 964' 1000
318" Surf.
SIt
DV Collar 964' 967' 18-5/8"
13- Surf Csg 54.5 K-S5 12.615 96T 2958' 600 SIt 2144'
C 3/8" (CaIcuIIted)
.,. 29 P-1l0 6.184 Surf 39'
.,. ~ 6.276 39' 2f1:Tf 1000
.,. Prod Csg 29 6.184 2097' 3439' SIt 6495'
.,. ~ N-80 6.276 3439' 6158' 1bru CBL
.,. ~ 8ni 6.184 6158' 7933' 10-518" DV@
.,. 26 P-II0 6.276 7933' 8467 8467'
DV CoII8r 846'7' 8470'
.,. Prod Csg 26 P-I10 6.276 8470' 9789' 1000 9399'
.,. ~ 6.184 9789' 10,257 sxs Cak:uIated
-- S" Liner 18 L-SO Butb'ess 4.276 9971' 11,590 6" soo 11,2S0'
CBL
ø F Tubina
15.0' Original RKB to Tbg Hnør
! 2-718" 6.4 N-80 Buttress 2.441 Surf 4782'
@) 2 7/8" 6.4 N-80 Buttress 2.441 6000' 9766'
~ 2 3/8" 4.6 N-80 Butb'ess 1.995 9,766' 11,256'
JE WE LR Y DETAIL
NO. Depth ID on Item
IS.0' Tubing Hauger
GLM ##13. 1622' 2.347 5.S" x 4.~" Cameo MMG-P GLM
GLM ##14. 3183' 2.347 55" x 4.673" Cameo MMG-P GLM
GLM ##15. 3948' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM ##16. 477T 2.347 5.5" x 4.673" Cameo MMG-P GLM
I GLM##17. 5545' 2.347 5.S" x 4.673" Cameo MMG-P GLM
GLM ##18. 6220' 2.347 55" x 4.673" Cameo MMG.P GLM
GLM ##1'. 6891' 2.347 5.S" x 4.673" Cameo MMG-P GLM
~ GLM #.ZO. 7597 2.347 5.5" x 4.613" Cameo MMG-P GLM
@) GLM #.Zt. 8303' 2.347 55" x 4.673" Cameo MMG-P GLM
~ GLM#.Z2. 9039' 2347 S.S" x 4.673" Cameo MMG-P GLM
GLM #.Z3. 9726' 2347 5.5" x 4.673" Cameo MMG-P GLM
A. 2500' Chem Inj Sub
B. 4678' CMU sid sleeve
C. 4690' Prod packer
D. 4740' XN profile nipple
E. 4782' WLEG
F. 5750' cmp
G. 6000' Cut tublDR
IL 7000' ThR. plq
1. 7345' EZ DriO ClBP
2. 9300' Cmt Retainer (TOC In tbR)
3. 9717' Cmt Retainer
4. 9766' 1.995" 3.503" Crossover, 2-718" BUE 8nix2-3I8" BUR 8ni
S. 10,448' 1.87S" 3.06S" Otis "XA" Sldg Slve
GLM #.Z4. 11,149' 1.87S" 4.125" x 2.781" Cameo KBMG-2 GLM
6. 11,186' 2.5S" Otis "BWD" PIa
7. 11,226' 1.875" 2.701" Otis "X" Profile N¡pple
8. 11,256' 2.32" 2.872" WLEG
~c I
1'J)z U,59O' PBTD= 11,560'
Max DeriatioD = 24.3° @ 7815'
PERFORATION BISTORY
IntenaI Aaaa.
Top Btm Amt fIJJI
4,993' !,005'
5,555' 5,567'
7;lG1' 7;J81l
7~ 7~
11,326' 11,336'
11,340' 11,346'
15'
40"
10'
(I
6..
6.0
Qh_- t
56-0 BeIup PropoNd
50-6 BeIup PropoNd
Cí8-O Upper Lobe. Propoted PM
Cí8-O Lwr Lobe. Propoøed P&.A
pü
P&.A
I"
~~!Æ~E J} fÆ~fÆ~~~~
ATIASIiA. OIL AND GAS
CONSERVATION COMMISSION
Tim Brandenburg
Drilling Manager
Union Oil Company of California
P.O. Box 196247
Anchorage, Alaska 99519
Re: Swanson River SRU 32A-15
Sundry Number: 304-388
Dear Mr. Brandenburg:
11.cf-01cf
FRANK H. MURKOWSKI, GOVERNOR
333 W. "JTH AVENUE, SUITE 100
ANCHORAGE, ALASKA 99501-3539
PHONE (907) 279-1433
FAX (907) 276-7542
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.
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.
BY ORDER OF THE COMMISSION
DATED this~ day of October, 2004
Ene!.
-/
SCANNED OCT 2 7 2004
If'
wGÆ ,of2.çl2.-004
STATE OF ALASKA Or$ leI.?tS¡~
ALASKA OIL AND GAS CONSERVATION COMMISSION RECt::tVl::D
APPLICATION FOR SUNDRY APPROVAL OCT 'I 1 2004
20 MC 25.280 tJ ~..
Operational shutdown U Perforate U ka i\ ~~~ei ~ns!1JB~¡S~' U'
Plug Perforations D Stimulate Cf"¥ïme ~xteniiop.' n De Other 0
1\ n v i'roffi ..,
Perforate New Pool 0 Re-enter Suspended Well D Recomplete
4. Current Well Class: 5. Permit to Drill Number: U-~
Development 0 Exploratory D - ~-OOSt1 0 ~. /9~ æ ro
Stratigraphic D Service D 6. API Number: .
/
50-133-10141-01
Suspend U
Repair well D
Pull Tubing D
1. Type of Request:
Abandon U
Alter casing D
Change approved program D
2. Operator Name:
Union Oil Company of California
3. Address:
PO Box 196247, Anchorage, AK 99519
7. KB Elevation (ft):
15'
9. Well Name and Number:
SRU 32A-15 ~
Casing
Structural
CoMuctor
Total Depth TVD (ft):
11 ,187'
Length
10. Field/Pools(s):
,r"
Swanson River Field/Hemlock, Tyonek, Beluga
PRESENT WELL CONDITION SUMMARY
Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured):
11,560' 11,158' 11,560
Junk (measured):
8. Property Designation:
Swanson River Production Facility
11.
Total Depth MD (ft):
11,590'
Size
MD
TVD
Burst
Collapse
Surface
Intermediate
45'
964'
22"
45'
2,958'
45'
2,958'
2,730 psi
1,130 psi
13-3/8"
Production
Liner
10,257' 7"
1,619 5"
Perforation Depth TVD (ft):
10,937' to 10,973'
Otis BWD packer
10,257
11,590'
Tubing Size:
9,938'
11,187'
Tubing Grade:
7,240 psi 5,410 psi
10,140 psi 10,490 psi
Tubing MD (ft):
9,766'; 11,256'
Perforation Depth MD (ft):
11,326' to 11,364'
Packers and SSSV Type:
2-7/8"; 2-3/8"
N-80
Packers and SSSV MD (ft):
11,186'
16. Verbal Approval:
Date:
13. Well Class after proposed work:
Exploratory D Development 0 / Service D
/} 15. Well Status after proposed work:
~004 Oil D Gas 0 Plugged D Abandoned
WAG D GINJ D WINJ D WDSPL
D
0
12. Attachments: Description Summary of Proposal L::J
Detailed Operations Program D BOP Sketch D
14. Estimated Date for
Commencing Operations:
Commission Representative:
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Printed Name. Tim C. Bran~enburg ~. Title Drilling Manager
Signature? .... -þ ç VÞhone 907-274-7600 Date
Þ COMMISSION USE ONLY
Conditions of approval: Notify Commission so that a representative may witness
Contact
Steve Tyler 907-263-7649
10/20/2004
Sundry Number: .3 04- - 3 8'8'
Plug Integrity D
BOP Test D
Mechanical Integrity Test
D
Location Clearance
D
Other:T € sb ßO I) ¡; +0 '~ç 00 tJ!;;'
l
OCT 2 6 70fl4
OR\G\NAL
--
BY ORDER OF OCT 2 i12004
COMMISSIONER THE COMMISSION Date:;O¡~ f
INSTRUCTIONS ON REVERSE Submit in Duplicate
.,. Swanson River
Well SRU 32A-15
UNOCAL8 Actual Completion 10/3/04
Casing & Tubing
RKB =15.0' Size Type Wt Grade Thrd ID Top Btm Hole Cmt Cmt Top
22" Conductor Surf 45' Yes Surf.
13-3/8" Surf Csg 54.5 K-55 12.615 Surf 964' 1000 sx Surf
DV Collar 964' 967' 18-5/8"
13-3/8" SurfCsg 54.5 K-55 12.615 967' 2958' 600 sx 2144'
(Calculated)
7" 29 P-110 6.184 Surf 39'
~ 7" 26 6.276 39' 2097'
7" Prod Csg 29 6.184 2097' 3439' 1000 sx 6495'
7" 26 N-80 6.276 3439' 6158' Thru DV CBL
7" 29 8rd 6.184 6158' 7933' 10-5/8" @ 8467'
7" 26 P-IIO 6.276 7933' 8467'
DV Collar 8467' 8470'
7" Prod Csg 26 P-11O 6.276 8470' 9789' 1000 9399'
7" 29 6.184 9789' 10,257' sxs Calculated
5" Liner 18 L-80 Buttress 4.276 9971' 11,590 6" 500 sxs 11,250'
CBL
,
Tubin2 15.0' Original RKB to Tbg Hngr
27/8" I 6.4 I N-80 I Buttress I 2.441 I Surf I 9766'
23/8" 4.6 N-80 Buttress 1.995 9,766' 11,256'
NO. Depth
15.0'
GLM #1. 1622'
GLM #2. 3183'
GLM #3. 3948'
GLM #4. 4777'
GLM #5. 5545'
GLM #6. 6220'
GLM #7. 6891'
GLM #8. 7597'
~'.,.".'~'T' GLM #9. 8303'
~ f""'..... . ... .. '.. .."1 ¡,.' GLM #10. 9039'
@;itj.... .,'.'... ~ .,< '''";I GLM #11. 9726'
u'....'.r.
~<::4¡'.".'.,: ¡¿,:,,,;-',,,"\.',," ,.::,:",'" ".". ",:~--;-, A. 7345'
R. 9300'
C. 9717'
I. 9766'
2. 10,448'
GLM #12. 11,149'
3. 11,186'
4. 1l,226'
5. 1l,256'
TD= 11,590' PBTD= 11,560'
Max Deviation = 24.3° @ 7815'
ID
2.347
2.347
2.347
2.347
2.347
2.347
2.347
2.347
2.347
2.347
2.347
1.995"
1.875"
1.875"
2.55"
1.875"
2.32"
1959
10/94
10/06/96
10,332'
6200' to 6280'
JEWELRY DETAIL
OD Item
Tubing Hanger
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
EZ Drill CIBP
Cmt Retainer (TOC in tbg)
Cmt Retainer
3.503" Crossover, 2-7/8" EVE 8rd x 2-3/8" EVE 8rd
3.065" Otis "XA" Sldg Slve
4.125" x 2.781" Cameo KBMG-2 GLM
Otis "BWD" Pkr
Otis "X" Profile Nipple
WLEG
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
2.701"
2.872"
Brief History
Originally Drilled & completed.
P&A'd. Milled window in 7" @ 10,257' & Redrilled
Fish - LlH 39' of Eline tools wi 15' of 1-11/16" strip guns
Tight spot in tubing w/l-II/16" Dummy guns
Bad spot in 7" esg. Problems getting 5" liner through.
PERFORATION DETAIL
Interval Accum
Top Rtm Amt spf
7,267' 7,282' 15' 6.0
7,358' 7,398' 40' 6.0
1l,326' 1l,336' 10'
11,340' 11,346' 6'
11,354' 1l,364' 10'
SRU 32A-15 Actual Schematic_lO-04
Comments
68-0 Upper Lobe
68-0 Lwr Lobe
P&A 9/26/04
P&A 9/26/04
P&A 9/26/04
SCANNED OCT 2 7 2004
REVISED: 9/1/2004 by SL T
..
UNOCAL8
~RKB =1~'()'
~ ......... ...... . .I~
. ..7 1.1
f: U Ii
r.' ~. .~. ... A
di :'
~ ~.: t to
~'~.'.. I. 1 ~
~~'."'....'...~......+. C //
g ~!~
¡.. I\: D
~~1
¡~ E'..
~
~)
-:
:;J
~)
~ --
~,'~..-. /
e - ~G
",
~
@
U
S
~
TD= 11,590' PBTD= 11,560'
Max Deviation = 24.30 @ 7815'
Swanson River
Well SRU 32A-15
Proposed Completion
Tubing
Top Btm Hole Cmt Cmt Top
Surf 45' Yes Surf
Surf 964' 1000 sx Surf
964' 967' 18-5/8"
967' 2958' 600 sx 2144'
(Calculated)
Surf 39'
39' 2097'
2097' 3439' 1000 sx 6495'
3439' 6158' Thru DV CBL
6158' 7933' 10-5/8" @ 8467'
7933' 8467'
8467' 8470'
8470' 9789' 1000 9399'
9789' 10,257' sxs Calculated
9971 ' 11,590 6" 500 sxs
Surf I 9766'
9,766' 11,256'
Casing &
Size Type Wt Grade Thrd ID
22" Conductor
13-3/8" SurfCsg 54.5 K-55 12.615
DV Collar
,
13-3/8" SurfCsg 54.5 K-55 12.615
7" 29 P-II0 6.184
7" 26 6.276
7" Prod Csg 29 6.184
7" 26 N-80 6.276
7" 29 8rd 6.184
7" 26 P-110 6.276
DV Collar
7" Prod Csg 26 P-IIO 6.276
7" 29 6.184
5" Liner 18 L-80 Buttress 4.276
Tubing 15.0' Original RKB to Tbg Hngr
27/8" I 6.4 I N-80 I Buttress I 2.441
23/8" 4.6 N-80 Buttress 1.995
NO.
GLM #1.
GLM #2.
GLM #3.
GLM #4.
GLM #5.
GLM #6.
GLM#7.
GLM #8.
GLM #9.
GLM #10.
GLM #11.
A.
B.
C.
D.
E.
F.
G.
H.
1.
2.
3.
4.
5.
GLM #12.
6.
7.
8.
SRU 32A-15 Proposed Schematic_1 0-04
Depth
15.0'
1622'
3183'
3948'
4777'
5545'
6220'
6891'
7597'
8303'
9039'
9726'
2500'
4750'
4760'
4770'
dS?
7000'
7345'
9300'
9717'
9766'
10,448'
11,149'
11,186'
11,226'
11,256'
ID
2.347
2.347
2.347
2.347
2.347
2.347
2.347
2.347
2.347
2.347
2.347
1.995"
1.875"
1.875"
2.55"
1.875"
2.32"
1959
10/94
10/06/96
10,332'
6200' to 6280'
JEWELRY DETAIL
OD Item
Tubing Hanger
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cameo MMG-P GLM
Cbem loj Sub
CMU sid sleeve
Prod packer
XN profile oipple
TCP WLEG
CIBP
Cut tubing
Tbg. ping
EZ DriO CIBP
Cmt Retainer (TOC in tbg)
Cmt Retaine.r
Crossover, 2-7/8" EUE 8rd x 2-3/8" EUE 8rd
Otis "XA" Sldg Slve
Cameo KBMG-2 GLM
Otis "BWD" Pkr
Otis "X" Profile Nipple
WLEG
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
5.5" x 4.673"
3.503"
3.065"
4.125"x2.781"
2.701"
2.872"
Brief History
Originally Drilled & completed.
P&A'd. Milled window in 7" @ 10,257' & Redrilled
Fish - LlH 39' of Eline tools wi 15' of 1-11/16" strip guns
Tight spot in tubing wi 1-11/16" Dummy guns
Bad spot in 7" esg. Problems getting 5" liner through.
PERFORATION DETAIL
Interval Accum.
Top Btm Amt spf
5,555' 5,567'
4,993' 5,005'
7,267' 7,282'
7,358' 7,398'
11,326' 11,336'
11,340' 11,346'
Comments
5(H) Beluga Proposed
50-6 Beluga Proposed
68-0 Upper Lobe. Proposed P&A
68-0 Lwr Lobe. Proposed P&A
P&A
P&A
15'
40'
10'
6'
6.0
6.0
SCANNED OCT 2 7 2004
REVISED: 10/19/2004 by SLT
.! IÞ
SRU 32A-15 Recompletion Work Summary
Recomplete 56-0 Sand, block sqz/isolate Tyonek and Beluga Sands.
MIRU Slickline. Set plug at 7,000' Bail 20' cmt on plug to P&A 68-0 sand.
MIRU Eline. RIH cut tbg@ 6000'. ¡J ~
MIRU Nabors Rig 26. Set BPV. ND Tree&..m:1 BOP. Test. PUMU Land Joint. Unseat Hanger and circulate
well w/returns from annulus. POOH. LD 2-7/8" tbg.
PU bit, scraper, & 3-1/2" DP. RIH to 5,800'. Circ Hole clean & POOH.
RU Eline. RIH and set CIBP @ 5,750. POOH. MIT casing to 2,500 psi. Pull CBL & RST from 5,700 to "
2,900. Perf sqzlcirculation holes 5590 to 5600 & 5550 to 5560. RI set Cmt Retainer @ 5540'. ~
RIH wI polished stinger on workstring. Stab into ret. Establi lícir ulation rates & pressures down workstring
while taking returns out 7" x 13-3/8" annulus. Mix pump 20 b s of"G" Neat cmt (2,100 sx) while taking
returns out 7" x 13-3/8" annuli. Launch wiper ball. Displa / ith lease water.
PU above retainer. CBU. POOH. WOC 12 hrs.
RIH with 6" Clean out bit to TOC. Drill out cement to 5700'. Pressure test sqz holes. /"
.
.
.
.
.
.
.
.
CONTINGENCY
. RU Eline. RIH and set CIBP @ 5070'. WL perf sqz holes 5030 to 5040, & 4990 to 5000. RD SWS.
. RIH 3-1/2" OE DP to 5050'. Mix and pump 50 sx cement and lay in balance plug. Hesitation sqz cement and
hold final pressure 2 hours. POOH with DP.
Start of Sterling Zonal Isolation
. RU E-line. RIH set CIBP at 3561'. RIH and perfsqz holes 3510 - 3520. RD EL.
. RIH 3- Y2" OE DP to 3550'. Miz and pump 50 sx cement and lay in balance plug. Hesitation sqz cement and
hold final pressure 2 hours. POOH with DP.
. RIH Eline & perf sqz holes 3380 - 3390.
. RIH 3-1/2" OE DP to 3410'. Mix and pump 50 sx cement and lay in balance plug. Hesitation Sqz cement and
hold final pressure 2 hours. POOH with DP.
. RIH& Perfsqz holes 3200' - 3210'
. RIH 3-1/2" OE DP to 3230. Mix and Pump 50 sx cement and lay in balance plug. Hesitation Sqz and hold final
pressure 2 hours. POOH with DP
. RIH & perf sqz holes 3040 - 3050.
. RIH 3-1/2" OE DP to 3060'. Mix and pump 50 sx cement and lay in balance plug. Hesitation Sqz and hold
final pressure 2 hours. POOH with DP. WOC 8 hours.
. RIH with 6" Clean out bit to TOC. Drill out cement to 3060'. Test Sqz perfs. Drill out cement to 3240'. Test
Sqz perfs. Drill out cement to 3410'. Test Sqz perfs. Drill out cement to 3550'. Test Sqz perfs.
. Drill out cement to 3720. Test Sqz perfs. Drill out cement to 3950. Test Sqz perfs. Drill out cement to 5050.
Test Sqz perfs. Drill out cement to 5700. Test Sqz perfs..
. Trip bit. PU Scraper. TIH. Circ clean. Displace to Brine. POQH LD DP.
. RU E-line. Pull Bond Log from 5700' to 2900'. RD Eline./
. MU Completion packer, RIH 2-7/8" completion wI sliding sleeve & CIM. Space out and Land Completion.
. RU Slickline. RI wI "N" test plug set in XN profile. Set pkr. Test tubing and annulus. POOH wI slickline. RD
same.
/.
.
Set BPV. ND BOP. NU tree. Test same. Release Rig.
MIRU slick line. Pressure test lub. RIH Gauge Ring & tag PBTD.
RlH shifting tool. Open Sliding sleeve @ 4750'. RU N2. Pump Pkr fluid. Displace tubing with N2. RD
Pumping equipment. RIH and close sliding sleeve. RD Slickline.
MIRU E-line. RIH & Perforate 56-0 sand. RD E-line.
Turn well over to production to unload and test.
Contingency perforations: MIRU ELine RIH & perf 50-6 sand. RD E-line. Turn well over to production.
.
.
.
.
.
1 of 1
SCA,NNED 2 7 2004
\
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>
\
i
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
OilD Gas D Plugged 0 Abandoned D Suspended D WAG 0 1 b. Well Class:
20AAC 25.105 20AAC 25.110 Development 0 Exploratory 0
No. of Completions Other Service 0 Stratigraphic Test 0
5. Date Comp., Susp., or 12. Permit to Drill Number: /
Aband.: 10/3/04 94-0084-0
6. Date Spudded: 13. API Number:
n/a 50-133-10141-01
7. Date TO Reached: 14. Well Name and Number:
nla SRU 32A-15
8. KB Elevation (ft): 15. Field/Pool(s):
15' Swanson River Fieldl
9. Plug Back Depth(MD+ TVD): Tyonek
11,560/11,1 q8 Hemlock
10. Total Depth (MD + TVD): 16. Property Designation:
11,590/11,187 Swanson River
11. Depth Where SSSV Set: 17. Land Use Permit:
nla A-028384
19. Water Depth, if Offshore: 20. Thickness of Permafrost:
nla feet MSL nla
1 a. Well Status:
GINJ 0 WINJ 0
2. Operator Name:
Union Oil Company of California
3. Address:
PO Box 196247, Anchorage, AK 99519
4a. Location of Well (Governmental Section):
Surface: 2300 ~, 1040 FiL, Sec. 15 T8N R9W
Top of Productive Horizon: iJ ~ ¡J
Total Depth: 2286 FjL, 3161 F/.L, Sec. 15 T8N R9W
WDSPLD
4b. Location of Well (State Base Plane Coordinates):
Surface: X = 348,884, Y = 2,480,047
TPI:
Total Depth: X = 351,036, Y = 2,480,023
18. Directional Survey: Yes D No I D
21. Logs Run:
Gamma Ray/CCL, temperature survey
22.
CASING WT. PER GRADE
FT.
22"
13-3/8" 54.5 K-55
7" 26,29 P-110/N-80
5" 18 L-80
CASING, LINER AND CEMENTING RECORD
SETTING DEPTH MD SETTING DEPTH TVD
HOLE SIZE
TOP BOTTOM TOP BOTTOM
0 45' 0 45'
0 2,958' 0 45'
0 10,257' 0 9938'
9,971' 11,590' 9672' 11187'
CEMENTING RECORD
AMOUNT
PULLED
see schematic attached
18-5/8"
10-5/8"
6"
23. Perforations open to Production (MD + TVD of Top and Bottom
Interval, Size and Number; if none, state "none"):
Top Btm Amt
7,267' 7,282' 15'
7,358' 7,398' 40'
24.
TUBING RECORD
DEPTH SET (MD) PACKER SET (MD)
9,766', 11,256' 11,186
SIZE
2-7/8",2-3/8"
spf Zone Comments
6.0 68-0 Upper Lobe
6.0 68-0 Lwr Lobe
25. ACID, FRACTURE, CEMENT SQUEEZE, ETC.
DEPTH INTERVAL (MD) I AMOUNT AND KIND OF MATERIAL USED
see schematic
26.
Date First Production:
nla
Date of Test:
Hours Tested:
Flow Tubing
Press.
Casing Press:
PRODUCTION TEST
Method of Operation (Flowing, gas lift, etc.):
n/a
Oil-Bbl:
Production for
Test Period ...
Calculated Oil-Bbl:
24-Hour Rate ...
Gas-MCF:
Water-Bbl:
Choke Size:
Gas-Oil Ratio:
Gas-MCF:
Water-Bbl:
Oil Gravity - API (corr):
27. CORE DATA
Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary).
Submit core chips; if none, state "none".
nla
Form 10-407 Revised 12/2003
... f.\ ~ t¿OD4
1\.\ ME", 1\\(\\1 u t~
SCA~~~~ \j \~ '.<
CONTINUED ON REVERSE
Gç
~~ ~/~
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
OilD GasD Plugged D AbandonedD SuspendedD WAGD 1b. Well Class:
20AAC 25.105 20AAC 25.110 Development 0 Exploratory 0
No. of Completions Other Service 0 Stratigraphic Test 0
5. Date Comp., Susp., or 12. Permit to Drill Number:
Aband.: 10/3/04 94-0084-0
6. Date Spudded: 13. API Number:
n/a 50-133-10141-01
7. Date TO Reached: 14. Well Name and Number:
nla SRU 32A-15
8. KB Elevation (ft): 15. Field/Pool(s):
15' Swanson River Fieldl
9. Plug Back Depth(MD+ TVD): Tyonek
11,560/11,158 Hemlock
10. Total Depth (MD + TVD): 16. Property Designation:
11 ,590/11 ,187 Swanson River
11. Depth Where SSSV Set: 17. Land Use Perm it:
nla A-028384
19. Water Depth, if Offshore: 20. Thickness of Permafrost:
nla feet MSL nla
:J
1 a. Well Status:
GINJD WINJD
2. Operator Name:
Union Oil Company of California
3. Address:
PO Box 196247, Anchorage, AK 99519
4a. Location of Well (Governmental Section):
Surface: 2300 FSL, 1040 FEL, Sec. 15 T8N R9W
Top of Productive Horizon:
Total Depth:
WDSPL 0
2286 FSL, 3161 FEL, Sec. 15 T8N R9W
4b. Location of Well (State Base Plane Coordinates):
Surface: X = 348,884, Y = 2,480,047
TPI:
Total Depth: X = 351,036, Y = 2,480,023
18. Directional Survey: Yes 0 No I 0
21. Logs Run:
Gamma RayICCL, temperature survey
22.
CASING WT. PER GRADE
FT.
22"
13-3/8" 54.5 K-55
7" 26, 29 P-11 0/N-80
5" 18 L-80
CASING, LINER AND CEMENTING RECORD
SETTING DEPTH MD SETTING DEPTH TVD
HOLE SIZE
TOP BOTTOM TOP BOTTOM
0 45' 0 45'
0 2,958' 0 45'
0 10,257' 0 9938'
9,971' 11,590' 9672' 11187'
CEMENTING RECORD
AMOUNT
PULLED
see schematic attached
18-5/8"
10-5/8"
6"
23. Perforations open to Production (MD + TVD of Top and Bottom
Interval, Size and Number; if none, state "none"):
see schematic for perf record
26.
Date First Production:
nla
Date of Test:
Hours Tested:
Flow Tubing
Press.
Casing Press:
24.
TUBING RECORD
DEPTH SET (MD) PACKER SET (MD)
9,766', 11 ,256' 11 ,186
SIZE
2-7/8", 2-3/8"
25. ACID, FRACTURE, CEMENT SQUEEZE, ETC.
DEPTH INTERVAL (MD) I AMOUNT AND KIND OF MATERIAL USED
see schematic
Production for
Test Period
Calculated
24-Hour Rate
PRODUCTION TEST
Method of Operation (Flowing, gas lift, etc.):
n/a
Oil-Bbl:
...
Oil-Bbl:
...
Oil Gravity - API (corr):
Gas-MCF:
Water-Bbl:
Choke Size:
Gas-Oil Ratio:
Gas-MCF:
Water-Bbl:
27. CORE DATA
Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary).
Submit core chips; if none, state "none".
n/a
Form 10-407 Revised 12/2003
REC I
OCT 1 9 2004
Alaska Oil
nR'Gi~.Jf~,L
CONTINUED ON REVERSE
~8. '
NAME
GEOLOGIC MARKERS
MD
TVD
29. FORMATION TESTS
Include and briefly summarize test results. List intervals tested, and attach
detailed supporting data as necessary. If no tests were conducted, state
"None".
~~d
~
f~~
nla
I
~'
OCT 1 9 2004
30. List of Attachments:
summary of morning reports, schematic.
31. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact: Steve Tyler 263-7649
Printed Name: Tim C. B, rande,nbU~ç \ ""', ,.".." .~ ,..,,,.,,
.,.-? < ..t/ ét/' .,/'
Signature: c::::-- ,/"''/ ~
¡Y -- ,.-..'-- ./:
~'
¡;;....ø~'
Title: Drilling Manager
Phone: 907-276-7600
Date: 10/19/2004
Follow up to Sundry 304-340
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 1 a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for
I 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 8: The Kelly Bushing elevation in feet above mean low low water. 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: True vertical thickness.
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 reported 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: If no cores taken, indicate "none".
Item 29: List all test information. If none, state "None".
Form 10-407 Revised 12/2003
28-.
GEOLOGIC MARKERS
MD
TVD
NAME
GlaciaLBase_MJF ,.
Tks- YELLOW
A9
B2B
Beluga -
41-4ST
Mid.,.,~E&u~_MJF -
50-6ST
L.L.- Tnk_MJF
D1CT
61-8ST
66-3STE
70-8CT
mtLmark
80-2ST
E10
Hemlock_MJF ~
TO
591
1,472
2,561
3,029
3,504
4,121
4,591
5,008
5,514
6,050
6,561
7,046
7,524
8,067
8,555
9,247
11 ,272
11,590
591
1 ,472
2,561
3,028
3,503
4,120
4,590
5,007
5,511
6,038
6,526
6,981
7,422
7,920
8,367
9,007
10,887
11,187
29.
FORMATION TESTS
Include and briefly summarize test results. List intervals tested, and attach
detailed supporting data as necessary. If no tests were conducted, state
"None".
nla
30. List of Attachments:
summary of morning reports, schematic.
31. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Printed Name: Tim C. Brandenburg
Signature:
Contact: Steve Tyler 263-7649
Title: Drilling Manager
Phone: 907-276-7600
Date: 10/19/2004
Follow up to Sundry 304-340
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 1 a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for
I 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 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other
spaces on this form and in any attachments.
Item 20: True vertical thickness.
Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
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 reported 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: If no cores taken, indicate "none".
Item 29: List all test information. If none, state "None".
Form 10-407 Revised 12/2003
¡.
- Swanson River
Well SRU 32A-15
UNOCAL8 Actual Completion 10/3/04
c a s i n 9 & Tu b i n 9
RKB =15.0' Size Type Wt Grade Thrd ID Top Btm Hole Cmt Cmt Top
~r - -~ 22" Conductor Surf 45' Yes Sun.
~t t 13-3/8" Surf Csg 54.5 K-55 12.615 Surf 964' 1000 sx Surf
DV Collar 964' 967'
. i " 18-5/8"
13-318" SurfCsg 54.5 K-55 12.615 967' 2958' 600 sx 2144'
(Calculated)
~ "":'i' 7" ~ 6.184 Surf 39'
:~"'~ P-IIO -
@iI. ~ 7" 26 6.276 39' 2097'
u 7" Prod Csg 29 6.184 2097' 3439' .1000 sx
~ 7" ..lL.. N-80 6.276 3439' 6158' Thm DV 6495'
CBL
7" 29 8rd 6.184 6158' 7933' 10-5/8" @ 8467'
7" 26 P-IIO 6.276 7933' 8467'
DV Collar 8467' 8470'
7" Prod Csg ..lL.. P-IIO 6.276 8470' 9789' 1000 9399'
7" 29 6.184 9789' 10,257' sxs Calculated
5" Liner 18 L-80 Buttress 4.276 9971' 11,590 6" 500 sxs 11,250'
CBL
Tubin~ 15.0' Original RKB to Tbg Hngr Ir~~;trmrm,
~~'.""'"
2 7/8" I 6.4 I N-80 I Buttress I 2.441 Surf I 9766' ..:,-U'fÚj-.- ~ HÍr~ 71 .
23/8" 4.6 N-80 Buttress 1.995 9,766' 11,256'
JEWELRY D E T AI L
NO. Depth ID OD Hem
15.0' Tubing Hanger
GLM #1. 1622' 2,347 5.5" x 4.673" Cameo MMG-P GLM
GLM #2. 3183' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #3. 3948' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #4, 4777' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #5. 5545' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #6. 6220' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #7. 6891' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #8. 7597' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #9. 8303' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #10. 9039' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #11. 9726' :;;.347 5.5" x 4.673" Cameo MMG-P GLM
. A. 7345' EZ Drill CIBP
B. 9300' Cmt Retainer (TOC in tbg)
C. 9717' Cmt Retainer
1. 9766' I. 995" 3.503" Crossover, 2-7/8" EVE 8rd x 2-3/8" EUE 8rd
2. 10,448' 1.875" 3.065" Otis "XA" Sldg Slve
GLM #12. 11,149' 1.875" 4.125" x 2.781" Cameo KBMG-2 GLM
3, 11,186' 2.55" Otis "BWD" Pkr
4. 11,226' 1.875" 2.701" Otis "X" Profile Nipple
5. 11,256' 2.32" 2.872" WLEG
Brief History
1959 Originally Drilled & completed.
10/94 P&A'd. Milled window in 7" @ 10,257' & Redrilled
10/06/96 Fish - LIH 39' of Eline tools wi 15' of 1-11/16" strip guns
10,332' Tight spot in tubing wi 1-11/16" Dummy guns
6200' to 6280' Bad spot in 7" esg. Problems getting 5" liner through.
PERFORATION DETAIL
Interval Accum
Top Btm Amt spf
7,267' 7,282' 15' 6.0
7,358' 7,398' 40' 6.0
11 ,326' 11,336' 10'
11 ,340' 11,346' 6'
11,354' 11,364' 10'
Comments
68-0 Upper Lobe
68-0 Lwr Lobe
P&A 9/26/04
P&A 9/26/04
P&A 9/26/04
SRU 32A-15 Actual Schematic 10-04
REVISED: 9/1/2004 by SL T
9/141104
PJSM & review procedure, Pollard rig up and pressure test.RIH with 2.18 GR and cut paraffin
from 1000' to 3500' while pumping diesel with test pump. Fell free from 3500' to cross over at
9768'. POOHChange over to 1.25" tool string and perform diagnostics on 2 3/8" tubing tail. Made
several trips in hole with different tool configuration. Final results is that tubing has mechanical
problem restricting drift.1. 75" GR would not pass with typical 1.25" tool string configuration.1.75"
GR fell free out tubing tail when Knuckle Joints were added to tool string between spang jars & oil
jars and between two pieces of stem.Final Tool String Is as follows1.25" RS, 1.25" KJ, 1.25"4'
Stem, 1.25" KJ, 1.25" 4' Stem, KJ, Oil Jars, KJ, Spang Jars and 1.75" GR (fell through tubing tail
with out a bobble)Reviewing with town on plan forward and tool string options for perforating
access and kick over tool access. Need to analyses probability of success.
9/161104
No operationsPJSM, RU Pollard Slickline, lubricator and pressure test to 2500 psiRIH wI L kick
over tool and daniels 1 5/8" pulling tool down to 7592' (GLM #8). Tool set down. Sheared pin
trying to catch valve. POOHRIH wI same setup as before and set down at 6215' (GLM #6)
POOHRead thru old file records and determined GLM were 2 7/8" mandrels. RIH w/2 7/8" OM1
kickover tool and daniels pulling tool and catch valve in #10 GLM at 9030'. Jarred for 45 minutes
and valve came free. POOHRIH with same set up and catch valve in GLM #8 at 7597'. Jarred
approx 10 licks and valve came free. POOHRIH with L kickover tool and daniels pulling tool and
pulled valve at 6220' (GLM #6) POOHRIH with L kickover tool and daniels pulling tool and pulled
valve at 3170' (GLM #2) POOHRIH with L kickover tool and daniels pulling tool and pulled valve
at 3948' (GLM #3) POOHRIH with L kickover tool and daniels p.ulling tool and pull~d valve at
4777' (GLM #4) POOHRIH with L kickover tool and daniels pulling tool and pulled valve at 1622'
(GLM #1) POOHRIH with L kickover tool and daniels pulling toól and latched valve at 9726'
(GLM#11) . Trying to spang valve out.
9/171104
Spang on GLM valve #11 at 9726'. POOH. Had valveRIH wlL ~OT and danials pulling tool and
pulled valve at 5545', #5 GLM. Lost valve in hole.RIH wlL KOT and danials pulling tool and pulled
valve at 8303, GLM #9. POOH, valve on surfaceRIH w KOT and tag all empty pockets to see if
dropped valve fell in one. POOH Made three runs trying to pull valve #7 at 6891'. Made small
adjustments each run and finally pulled valve. Valve on surface. Bled well down from 1000 psi to
50 psLRIH wlL kot and set dummy valve at 3948' GLM #3. POOHRIH wlL kot and set dummy
valve at 6217' GLM #6. POOHRIH w/om1 kot and set dummy valve at 1618' GLM #1. POOHRIH
w/om1 kot and set dummy valve at 3180' GLM #2. POOHRIH w/om1 kot and set dummy valve at
4770 GLM#4. POOHRIH w/om1 kot and set dummy valve at 5540'. GLM#5. POOHRIH w/om1
kot and set dummy valve at 6890' GLM #7. POOHRIH w/om1 kot and set dummy valve at 7596'
GLM#8. POOHRIH w/om1 kot and set dummy valve at 8303' GLM #9. POOHRIH w/om1 kot and
set dummy valve at 9039' GLM#10. POOHRIH w/om1 kot and set dummy valve at 9726' GLM
#11. POOHChange tool string around for dummy runs for perforating.RIH with 1,5 wt bars,
knuckled up and 5' dummy gun. Set down at 9782', POOH and gun had marks on bottom.RIH
with 1 5/8" danials pulling tool to 9763'. Worked down to 9782'. POOH and no valve.
9/181104
RIH w/1 5/8" danials pulling tool and set down at 6220' (GLM#6) to check if valve was in pocket.
POOH, pin sheared to verify valve was in pocket.RIH w/1 5/8" danials pulling tool and set down
at 9038' (GLM#10) to check if valve was in pocket. POOH, pin sheared to verify valve was in
pocket.RIH w/l 5/8 danials pulling tool and latched lost valve at 9782'. POOH, valve on
surface.RIH w/1.56 5' dummy gun down to 10,321', Beat down several times and POOH,RIH with
1 1/2" GR to 10,321'. Could not below this depth. POOHChange tools outRIH wIRS, 4'x1 1/4"
stem, x-over, 1 3/4" kj,x-over, 2' x1 1/2" stem to 10,321. Set down. POOHChange out tools to 1
SRU 32A-15, summary, last revised 10/07/104, page 1
1/4" and add kj to every joint.RIH w/11/4" danials pulling tool to 11,300', pull up to 11,149 and
latch GLM valve and sheared pin. POOHRIH w/1 1/4" danials pulling tool to 11,149' kb. Latch'
GLM valve and pull valve. POOH valve on surface.StandbyRig down and secure well
9/201104
Pulled production flow lines and line heater from SRU 241-16 in preparation and make room for
coil unit and work over rig. Laid felt pit liner for Johnson tank, frac tank and cement pump
truck. Started hauling lease water to frac tank to circulate production casing. Peak new Vac truck
broke down, Plan foreword is to get production casing circulated 125% through empty gaslift
mandrel or until production tubing returns are clean lease water, Call Schlumberger to pump and
set EZ Drill Retainer.
9/211104
Blew down well to johnson tank and took heater flange apart. Put blind flange on heater and
line.PJSM, RU Schlumberger pump truck and pressure test to 2000 psi.Pumped 100 bbls of
lease water at 4 bpm with 182 psi when well started to circulate. Fluid was clean and saw no oil.
Discussed with DSM and called town. Called Pollard to come out and find a possible hole or
unseated GLM.Rig up hoses to pump down tubing and up annuals. Pumped 54 barrels at 3 bpm
with 222 psi. DSM came by to check on progress and discovered we had Communication
between C section valves while Circulating. All the pumping did was fill the well and circulated
top of well. Rig up hoses and tried to pump down annular. Pressured up to 725 psi. Informed
DSM. Pressured up to 1500 psi. Waited 10 min. and pressure bled to 1480 psi. Switched hoses
to pump down tubing, Started to pumping and pressure went to 1434 psi at .25 bpm. Pumped?
bbls, And raised pressure to 1500 psi. Stopped pumping and tubing bled to 700 psi in 5 min and
to 410 psi in 10 min,3bbls pumped. Pumped up 1600psi. 10min 400psi.4.5bbls pumped. Pumþed
up T/1600psi. 10min 344psi.5.2 bbls pumped, Pumped up to 1600psi. 10min 323psi. Total fluid
pumped 6bbls.Changed hoses to pump down annular return out tbg. 1600psi. 10min 1560psi.
Total fluid pumped 2.3 bbls.R/D Pump Truck and lines secure well for further evaluation.
9/22//04
PJSM, rig up Pollard and pressure test to 2500 psi. Rig up Schlumberger pump truck and
pressure test lines to 2500 psi.RIH with slickline. Tool string was RS, 8'x1 1/4" stem, jars, sparigs,
3' stem and 2.33 GR. GR set down at 9768 KB (2 7/8"x2 3/8" XO) POOH.RIH with 2 7/811 OM-1
KOT and I 5/8" JDS pulling tool to 9729' KB. Latched GLM valve #11. Pressured tubing up to 300
psi and pulled valve. Pressured tubing up to 600 psi. Tubing bled down to 300 psi. POOH. Did not
have valve. Pulling tool was not sheared. Saw fluid level at 950'Pumped down tubing at .50 bpm
rate up to 2500 psi. Dropped injection rate to .32 bpm while maint 2450 psi. Pumped 5 bbls total
without returns.Modified trigger on 2 7/8" om-1 kot.. RIH with kot and jds pulling tool down to
9741' kb. Latched GLM valve #11. Put 300 psi on tubing. Jarred and spanged on valve and pulled
valve out. POOH and had 75 Ib drag coming out. Pooh & recovered Valve & rebuild
samePumped dn tubing at 3 bpm rate at 600 psi. 2- Tbg Volumes Monitoir Well Gas On Backside.
Timed fluid out of tank (found K- factor off on pump skid Pumping closer to 3 bpm when it shows
2 bpm)Shut dn & mointior well while waiting on Xylene
9/231104
Shut dn & monitor well while waiting on Xylene & more lease water (Tbg on Vacuum right away
took Annulus 1/2 hr to calm dn to just puking gas/oillWaterHold safety meeting on pumping
xylene & fill out chk lists Perform Injection test - Attempt to fluid pack well pump 2.5 bbls to Catch
pressure on tbg & 3.5 bbls for returns on annulus. Pump @ .5 bpm & 7 bbls away to reach 2300
psi (still have spring on annulus wI gas) Shut dn & watch tbg bleed dn 2300 psi tJ 1080 in 4 min &
bleed tbg to zero & went on vacuumOpen annulus & bleed off 270 psi Gas wI oil/water sprits &
Displace Xylene to Glm # 11 @ 9726' wlm wI 43 bbls lease water Shut in annulus & bull head
SRU 32A-15, summary, last revised 10/07/104, page 2
) I.
, '
Xylene into perfs w/18 bbls lease water as follows 1.75 bpm @ 308 psi @ 4 bbls away, 1.75 bpm
@ 480 psi@ 7 bbls away & annulus @ 350 psi, 1.75 bpm @ 586 psi @ 8 bbls away, 1.75 bpm
@611 psi @ 9 bbls away Ann @ 500 psi, 1.75 bpm @ 967 psi@ 10 bbls away ann, @ 800 psi,
1.75 bpm @ 1560 psi @ 13 bbls away ann. @ 1550 psi, .5 bpm @2160 psi @ 16 bbls away &
ann. @ 1550 psi, .5 bpm @2261 psi @17 bbls away & ann. @ 2200 psi, .5 bpm @ 2317 psi @
18 bbls away & annulus @ 2280 psi Shut dn & monitor Bleed dn f/2317 psi t/1106 psi in 10 min
& bleed tbg t/ zero wI 8 bbls back & tbg went on vacuum wI 400 psi on annulus, open annulus &
bleed same Gasloil & water (belching & puking same) RIH wI re-dresseddummy valve while
monitor annulus belching & puking Gas/oil/water for aprox 35 min then calmed dn & set 1-1/2"
Dummy valve In glm #11 @ 9741 RKB & pooh & chk K-over tool (ok) & Ildn same Install tree cap
& attempt to brk circ thru open pocket of glm #12 by pumping dn tbg t/ max psi of 2500 psi
attempt 5 times to pressure up t/ 2500psi @ different rates & monitor 5 min bleed offs between
same with no luck Discuss options wI town & Mlup RIH wI APRS 1 9/16 dummy gun -1 3/8" sub,
1 7/16" CCL, 1 7/16 Knuckle joint, 1 9/16" perf gun (3' 7") down to 10,335' on pollard slick line.
Tool set down and pulled 100 Ibs over to free up. POOH (total APRS tool string - 7')RIH wI APRS
1 9/16" dummy gun - 1 3/8" xo, 1 7/16" go box, 1 9/16" perf gun down to 10,3351. Tool set down.
POOH (total tool length 4' 7")RIH wI APRS 1.46" jet cutter dummy gun - 1 3/8" xo, 1.46" jet cutter
(total length 2' 3") down to 11,116'. Stop there, could have gone deeper. POOH. Rig down Pollard.
Rig up lubricator on Pollard mast truck for APRS.Wait on 1" knuckle joints and pollard wire line
valve rams for 7/32 e-line. Wire hot leads on 1" knuckle joints, put rams in wire line valves and
put together 1.46" jet cutter.PJSM, pressure test to 2000 psi and run in hole with APRS 1.46"
tubing cutter to 10,431. Pressured up tubing to 600 psi and fired cutter at 10,431'. Lost 300 psi.
POOH. Logged cut and it looked good for the hole it was suppose to make. Pooh t/ 9671' &
attempt to circ pressure up tbg t/ 2000 psi wI no circ. finish pooh & chk tools & I/dn cutter (fired
ok) & install tree capPump Dn tbg 3 bbls to catch psi & pressure up 5 times wI 5 min bleed off
each time @ different rates Max 25/04 psi wI minimum bleed of in 5 min to 339 psiArm APRs 1-
9/16" tbg punch 3' long wI 21 loaded wI eight (3/8") shots @ zero phased (Changed out one bad
1" KJappears that jet cutter had sheered KJ swivel pin) Rih & work gun by Glm @ 7597'
Continue Rih& set dn @ 10325 rkb unable to pass same (appears that tight spot is a collar) call
town & discuss options Place gun on depth I pressure up tbg t/700 psi I perf 2-3/8" tbg f/10313'
t/1 0315' (151 dn from a collar) wI good indication of fire & just flicker on pressure gauge I log
perfs (unable to see them clearly) bleed of pressure & pooh wI gun
9/241104
Continue pooh wI perf gun Chk & I/dn perf gun (all shots fired) installed tree cap & attempt to brk
circ 5 times @ different rates wI 5 min bleed off on each max psi 2509 wI minimum 5 min bleed
off t/ 505 psi & no circ I call town & discuss options Bleed off pressure (tbg on vacuum) annulus
zero secure well vac out pump trk lines & secure trk & release hand finish rldn of APRS & pollard
mask trk & release hands Suspend well operations & wait on variance from state on P&A I police
pad burm in tanks Move APRS unit & prep for CTU R/upMobe SLB pump hand, APRS hands &
pollard hands Move in & rlup Aprs & Pollard Boom trkPJSM I Arm APRS 1-9/16" Tbg punch 7'
long wI 5.5' loaded wI 23 (3/8") shots @ zero phased & pressure test lubricator to 2000 psi (no
test pack-off leaking chglout same) & re-test t/1500psi (ok)Rih wI gun Noting jewelry tie in to
Glm #11 & XO Place gun On depth I open annulus bleed off 50 psi gas & pressure up tbg t/ 700
psi 10 bbls to catch Psi & perf 2-3/8" tbg f/1 0094.5' t/1 01 00' (8' dn from collar t/ top shot) good
indication of tire lost 100 psi on tbgLog perfs wI CCL (ok) Pooh & chk tools (all shots fired) Install
tree capUse all hands & pull & lay liner for CTU rlup Pump Dn tbg 3 bbls to catch psi & pressure
up 5 times wI 5 min bleed off each time @ different rates. 7 bpm wI 6 bbls away t/ 25/04 psi wI 5
min bleed off t/ 460 psi, 1 bpm @ total of 7 bbls away t/ 2509 bbls wI 5 min bleed off t/ 571 psi,
1.5 bpm @ total of 8.5 bpm t/ 25/04 psi wI 5 min bleed off t/ 495 psi, 2 bpm @ total of 9 bbls away
t/ 2509 psi wI 5 min bleed off t/ 510 psi, tried pump @ steady rate .3 bpm wI total of 11 bbls awayl
2509 psi & 5 min bleed off t/11 06 psi Rldn APRS & rlup Pollard Slick Line unit & test lubricator t/
2000 psiRih wI 2-7/8" OM-1 Kick over tool wI 1-5/8" JDS wI no problems t/9735' locate & jar on
valve I pooh no recovery Chk tools pin not sheered on JDS & chg out JDSRih run #2 wlsame
Kick over tool & new 1-5/8" JDS
SRU 32A-15, summary, last revised 10/07/104, page 3
. .
9/251104
Continue Rih run #2 wI 2-7/8" OM-1 Kick over tool wI new 1-5/8" JDS wI no problems tJ 9735'
locate & jar on valve 6 oil jar licks & pull valve Pooh & chk tools Recovered dummy valve I install
tree cap & r/dn Slick line & Pump dn tbg 8.5 bbls to catch pressure & 20 bbls returns on annulus
(gas & oil) after 45 bbls started cleaning up pump total 1 00 bbls @ 2 bpm @ 365 psi to clean
annulus I shut dn & monitor well tbg went on vacuum & annulus puked water gas for 15 min while
finished rlup of E-line ¡Held PJSM plup & arm retainer Rihwl Howco 2-7/8" EZ-drill retainer
noting jewelry Tie in to glm #11 @ 9726' rkb & log 6' pup on top of glm place retainer on depth 2'
above 6' pup on glm #11 & set same @ 9717' Rkb Good indication cap fire not a good indication
of retainer stroke on weight indicator wait 15 min & plup 20' & set back dn @ 9717'Pooh & chk
tools (ok)Safety Meeting Load 20 bbls zylene @ P&S & transport to pad I pump dn tbg & fluid
pack well 3 bbls for returnsPump 20 bbls xylene & chase wI 50 bbls (15 bblsaround corner) shut
in annulus & bull head 21 Bbls & shut in well (see attatched pump 10g)R/up SLB 1-1/2" CTU #2 &
test bops See attatched bop test sheet (having some problums wI electronics, SLB tech out in
AM)lnstall night cap & secure weill Secure Equipment & release SLB for restPeak suck out
burms,cellar & work on burming Rlup choke manifold & prep for job
9/261104
Peak work on suck out containments, cellar @ rig & load lease water for pump & mud pit test in
AM clean coil mess & pump equipment away @ pad 43A-4Attend Simops wI production I coil tbg
operator & tech. on location coil tbg operator & tech on location trouble shoot actuation system
CT crew on location Continue trouble shoot actuation system I found & change out corroded
connection on injector head P/up Bha = 1.625" roll on conn & pull test 15k + DFCV + hyd
disconnect + straight bar + XO + XO + Howco centralized stinger stab injector & shell test (ok)
Rih circ @ .25 bpm wI no returns from coil X tbg annulus I returns f/6500' t/ 9500'PJSM & chk
lines bleed off 600 psi from csg x tbg annulus & shut in same Continue rih circ @ .25 bpm taking
returns fl coil X tbg annulus tag & stab retainer @ 9690' ctm & set dn 2500 Ibs P/up 20 ' & re-stab
wI same bleed off 750 psi csg X tbg annulus gas/oil/waterPump 25 bbls dn coil taking returns on
csg X tbg annulus & clean back side (send trk to get hot water for mixing cmt) noticed electronics
no functioning properlygetman lift & chk & clean j-box on injector head & monitor annulus clean
flow quit & was laying dead I shut in csg x tbg annulus Open coil X tbg annulus & Pump dn coil &
perform injection test pumped .5 bpm wI slow building trend tbg t/3190 psi @ 9 bbls away &
annulus 2475 psi (700 psi frictionl water) & monitored open coil X tbg annulus & chk retainer (ok)
Shut dn & monitor bleed dn 2625 - 355 psi in 27 min & call town & discuss cmt job PJSM &
discuss job wI cmters & CT hands & peak I Mix water & batch up 75 bbls cmtPump 5 bbls fresh
water ahead @ 1 bpm @2300 psi 2.5 bbl away returns I head dn hole wI 15.8 ppg cmt @ 15 bbls
away shut csg x tbg annulus ,5 bpm @ 4010 psi pump total 45 bbls cmt & P&A hemlock
perfsOpen csg x tbg annulus & continue tJ pump 80 bbls of 15.8 ppg cmt thru glm # 11 @ 9726' &
up back side Dis place coil t/ retainer w/5 bbls fresh water followed by 20 bbls lease water I C.I.P
@ 23:38 hrsUnsting & plup 50' & shut in csg x tbg annulus' (noticed 1000 psi on coil X tbg
annulus) bleed 200 psi from same & psi came back I open csg x tbg annulus & pump 2 bbls dn
coil & shut in both annulus & pressure up 100 psi over well head psi = 1400 psi
9/271104
Continue Pooh Maintaining 100 psi safety over Well Head Pressure Shut in & secure well wI
swab & upper master wI 1400 psi on tbg & 350 psi on annulus I Chk & Udn bha I set back
injector head I Install night cap on BOP's I Secure CTU & equipment & release Coil hands for
restWait on SWS & work on report & paper workPJSM wI SWS & Rlup E-line unit & test
lubricator t/2000 psi (ok)Open well tbg @ 1800 psi & annulus @ 100 psi (SWS pressure tool
shows 1791 psi) Having problems getting tool to fall (grease head)Rih Logging @ 7700fph wI
SWS PBMS tool (temp/pressure/GRlCCL) Let WH pressure build tJ 2000 psi & then bleed back t/
1800 psi 3 times observed a temp anomaly @ 6370' rkb (T.O.C) & set dn @ 9319' rkb wI temp
SRU 32A-15, summary, last revised 10/07/104, page 4
. . ... ~ ,~
anomaly spike indicating set dn in green cmtPooh maintaining 1800 psi on tbg wI test pump Shut
in & secure well wI swab & upper master wI 1800 psi on tbg & 100 psi on annulus I Chk & LIdn
PBMS logging tool I Install night cap on CTU BOP's I Rldn E-line unit & stage @ P&S yard I
release E-lines hands for restWait on cmt (first batch of cmt to weight @ 1900 hrs 9-26 I
thickening time 6 hrs 11 min I CIP @ 2338 hrs 9/26 I compressive strength of cmt 9 hrs = 500 #
10.5 hrs = 1000 # & 15 hrs = 2000 #)CT crew on location chk & warm equipment I PJSMM/up
bha 2" wash nozzle = xo = 6' straight bar + xo + 3' straight bar + DFV + same roll on conn. Stab
injector head / Brk circ & shell test 300/3000 psi (ok) I open well 11 00 psi & bleed off slow to zero
& monitor (ok) rih wI dry stick tJ 7500' start N2 @ 200 scf continue rih tJ soft tag 9252' CTM wash
tJ 9300' Call it good & up N2 rate tI 600 scf & monitor & strap returns & work pipe up rate tI 800
scf / Gas to surface I strap & chk volume 84 bbls back (7 bbls over cal?)Trap Psi & pooh
9/291104
No Operations. PJSM, rig up Schlumberger pump trk and pressure test to 3000 psi.Pressure
Annuli to 3000 psi. Took 2.75 bbls to pressure up. After 15 minutes lost 20 psi. Bled annuli back
to tank and got 2.25 bbls back. Tubing had 2550 psi and annuli had 0 psi before test. Rigged
down pump truck and secure well.WiII Be peforating 9-30-104
9/30104
PJSM, rig up Schlumberger, pressure test to 3000 psi and load guns.RIH with 2" HC, 6spf, 60
degree 20' perf gun. Tied into GR/CCL log dated 9-27-104. Spot perf gun from 7378' to 7398'.
Wait on produçtion to put spider on line. Tubing pressure was 2557 psi. Fired gun and pressure
went to 2560 psi. POOH, All shots fired.RIH with 2" HC, 6spf, 60 degree 20' perf gun. Tied into
GRICCL log dated 9-27-104. spot perf gun from 7358' to 7378'. WHP was 2657 psi. Bled
pressure doWn to 2380 psi. Fired gun. Pressure went to 2386 psi. POOH. Perf gun had fluid in it.
All shots fired. Rigged Schlumberger down and turned well over to production. WHP was 2529.5
psi.
10/31104
PJSM, Rig up Schlumberger lubricator, pressure test to 3000 psi. Had leak on pump-in-sub.
Fixed and test.goodRIH with Haliburton easy drill bridge plug (2 1/8" OD) Found fluid level at
4080'. Tied into GR/CCL log 9-27-104. RIH to 7350'. Did not want to go below perfs at 7358'.
Pulled up to 7345' (20' from top of joint) and set bridge plug. Line wt was 836 Ibs. When plug set
line wt dropped to 761 Ibs. Picked up and went back down and tagged plug. WHP was 2158 psi.
POOH.Shot another fluid level and it showed 3900'.RIH wI 15', 2 " HC, 6spf, 60 degree perf gun
to 7315'. Tie in with GR/CCL 9-27-104 and set perf gun from 7267' to 7282'. Found fluid level at
4080'. WHP was 1657 psi (Production bled well down per Mr Ayer). Fired gun. Pressure dropped
to 1654 psi. POOH All shots fired. Rigged Schlumberger down and secure well.
SRU 32A-15, summary, last revised 10/07/104, page 5
Winton
Attached are the updated actual wellbore schematic and the old proposed schematic for
SRU 32A-15.
Over the past two weeks, we accomplished the following:
Changed out all GL V's to dummy valves.
Left GLM#12 empty to provide a circulation point in the wellbore.
Established injection into Hemlock at 0.3 bpm @ 2500 psi w/ 8.5 ppg lease water.
~~,~ml ck reservoir pressure is 2900 psi)
. . f:Jo-Ja on being able to circulate the well through GLM#12 @ 11,149'.
. (, --,,' ed dummy valve from GLM#11 @ 9726'. Established circulation thru GLM#11.
Spotted 20 bbl Xylene to GLM#11. Closed csg off. Injected Xylene into Hemlock.
Replace dummy valve in GLM#11. Established injection rate into Hemlock @ 0.5 bpm.
No-joy on establishing circulation thru GLM#12.
Punched hole in 2-3/8" tbg @ 10,431' w/ decentralized jet cutter. No-Joy on establishing
circulation through tbg punch.
Punched hole in tbg @ 10,313' w/3' 1-9/16" gun. No-Joy on establishing circulation
through tbg punch holes.
Forward plan is to punch 2-3/8" tbg @ 10,100' and attempt to establish circulation at this
point. If we are unsuccesfull Unocal would like..,!9,".r~quest to proceed as follows to P&A
Hemlock and place cement pkr in csg x tbg~,"~,~Ji@ 6200':
Pull dummy valve from GLM#11 @ 9726'.
Set 2-7/8" cement retainer @ 9720'.
. With coil stabbed into retainer. Pump 15 bbls of cement (75 sx) and displace same
below retainer with csg annulus closed.
Open csg annulus. Circulate/place 105 bbls of cement (525 sx) in tbg x csg annuli from
9726' to 6200'
Or, if we are succesful in establishing circulation @ 10,100' then we would like to request to
proceed as follows to P&A Hemlock and place cement pkr in csg x tbg annuli @ 6200':
Pull dummy valve from GLM#11 @ 9726'.
Set 2-7/8" cement retainer @ 9720'.
. With coil stabbed into retainer. Pump 15 bbls of cement (75 sx) and displace same
below retainer with csg annulus closed.
Open csg annulus. Circulate/place 115 bbls (575 sx) of cement in tbg x csg annuli from
10,100' to 6200'.
A-pprt1\ted -¡¡'fA. E- ma.( l '1/ Z-t/:w°'t.
\)J 4 ~~t}j
SCANNED OCT 0 9 2004
"I~~~
UNOCAL
Swanson River
Well SRU 32A-15
Proposed Completion
Hole Cmt Cmt Top
Yes Smf
1000 sx Surf
18-5/8"
13-318" Surf Csg 54.5 K-55 12.615 967' 2958' 600 sx 2144'
(Calculated)
7" 29 P-110 6.184 Surf 39'
~ 7" 26 6.276 39' 2097'
7" Prod Csg 29 6.184 2097' 3439' 1000 sx 6495'
7" 26 N-80 6.276 3439' 6158' Thru DV CBL
7" 29 8rd 6.184 6158' 7933' 10-5/8" @ 8467'
7" 26 P-110 6.276 7933' 8467'
7" Prod Csg 26 P-IlO 6.276 8470' 9789' 1000 9399'
7" 29 6.184 9789' 10,257' sxs Calculated
5" Liner 18 L-80 Buttress 4.276 9971' 11,590 6" 500 sxs
Tubing 15.0' Original RKB to Tbg Hngr
27/8" I 6.4 I N-80 I Buttress I 2.441 I Surf I 9766'
23/8" 4.6 N-80 Buttress 1.995 9,766' 11,256'
e
~JEWELRY DETAIL
NO. Ucuth ID on Hem
15.0' - Tubing Hanger
GLM #1. 1622' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #2. 3183' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #3. 3948' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #4. 4777' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #5. 5545' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #6. 6220' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #7. 6891' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #8. 7597' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #9. 8303' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #10. 9039' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #11. 9726' 2.347 5.5" x 4.673" Cameo MMG-P GLM
A. TED emt Retainer
n. 9720' Gmt Retainer
1. 9766' 1.995" 3.503" Crossover, 2-7/8" EVE 8rd x 2-3/8" EVE 8rd
2. 10,448' 1.875" 3.065" Otis "XA" Sldg Slve
GLM #12. 11,149' 1.875" 4.125" x 2.781" Cameo KBMG-2 GLM
3. 11,186' 2.55" Otis "BWD" Pkr
4. 11,226' 1.875" 2.701" Otis "X" Profile Nipple
5. 11,256' 2.32" 2.872" WLEG
RKB =15.0'
I
TD= 11,590' PBTD= 11,560'
Max Deviation = 24.3° @ 7815'
Size
22"
13-3/8"
Casing &
Thrd ID
Type
Conductor
Wt
Grade
1959
10194
10106/96
10,332'
6200' to 6280'
Brief History
Originally Drilled & completed.
P&A'd. Milled window in 7" @ 10,257' & Redrilled
Fish - LIH 39' ofEline tools wi 15' of 1-11/16" strip guns
Tight spot in tubing wi 1-11/16" Dummy guns
Bad spot in 7" esg. Problems getting 5" liner through.
PERFOU,ATION DETAIL
Interval Accurn
Top Btm Amt spf
7,362' 7,402' 40' 4.0
TBD TBD 6' 4.0
11,130' 11,136' 6' 4.0
11,326' 11,336' 10'
11,340' 11,346' 6'
11,354' 11,364' 10'
Comments
Proposed 68-0
Proposed Tbg Punch
Proposed Tbg Punch
Proposed P&A
Proposed P&A
Proposed P&A
SRU 32A-15 Proposed Schematic 08-04.doc
SCANNED OCT 0 9 2004
REVISED: 9/1/2004 by SL T
Swanson River
Well SRU 32~t\-15
As Completed on 10/07/94
Casing &
RKB =15.0' ~¡"7.Q Type Wt Grade Thrd ill Top Btm Hole Cmt Cmt Top
Conductor Surf 45' Yes Smf
1000 sx Surf
18-5/8"
13-318" Surf Csg 54.5 K-55 12.615 967' 2958' 600 sx 2144'
(Calculated)
7" 29 P-II0 6.184 Surf 39'
~ 7" 26 6.276 39' 2097'
7" Prod Csg 29 6.184 2097' 3439' 1000 sx 6495'
7" 26 N-80 6.276 3439' 6158' Thru DV CBL
7" 29 8rd 6.184 6158' 7933' 10-5/8" @ 8467'
7" 26 P-I10 6.276 7933' 8467'
7" Prod Csg 26 P-110 6.276 8470' 9789' 1000 9399'
7" 29 6.184 9789' 10,257' sxs Calculated
5" Liner 18 L-80 Buttress 4.276 9971' 11,590 6" 500 sxs
Tubing 15.0' OriginaJ RKB to Tbg Hngr
27/8" I 6.4 I N-80 I Buttress I 2.441 I Surf I 9766'
2 3/8" 4.6 N-80 Buttress 1.995 9,766' 11,256'
iR
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~- JE\VELRY DETAIL
NO. Del>th In on Item
15.0' - Tubing Hanger
GLM #1. 1622' 2.347 5.5" x 4.673" Cameo MMG-P GLM wi Dummy
GLM #2. 3183' 2.347 5.5" x 4.673" Cameo MMG-P GLM wi Dummy
GLM #3. 3948' 2.347 5.5" x 4.673" Cameo MMG-P GLM wi Dummy
GLM #4. 4777' 2.347 5.5" x 4.673" Cameo MMG-P GLM wi Dummy
. GLM #5. 5545' 2.347 5.5" x 4.673" Cameo MMG-P GLM wi Dummy
GLM #6. 6220' 2.347 5.5" x 4.673" Cameo MMG-P GLM wi Dummy
GLM #7. 6891' 2.347 5.5" x 4.673" Cameo MMG-P GLM wi Dummy
GLM #8. 7597' 2.347 5.5" x 4.673" Cameo MMG-P GLM wi Dummy
GLM #9. 8303' 2.347 5.5" x 4.673" Cameo MMG-P GLM wi Dummy
GLM #10. 9039' 2.347 5.5" x 4.673" Cameo MMG-P GLM wi Dummy
GLM #11. 9726' 2.347 5.5" x 4.673" Cameo MMG-P GLM wi Dummy
1. 9766' 1.995" 3.503" Crossover, 2-7/8" EVE 8rd x 2-3/8" EVE 8rd
2. 10,448' 1.875" 3.065" Otis "XA" Sldg Slve
GLM #12. 11,149' 1.875" 4.125" x 2.781" Cameo KBMG-2 GLM Empty. Left valve out.
3. 11,186' 2.55" Otis "BWD" Pkr
4. 11,226' 1.875" 2.701" Otis "X" Profile Nipple
5. 11,256' 2.32" 2.872" WLEG
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TD= 11,590' PBTD= 11,560'
Max Deviation = 24.30 @ 7815'
1959
10/94
10106/96
10,332'
6200' to 6280'
11/22/04
Brief History
Originally Drilled & completed.
P&A'd. Milled window in 7" @ 10,257' & Redrilled
Fish - LIH 39' ofEline tools wi 15' of 1-11/16" strip guns
Tight spot in tubing wi 1-11/16" Dummy guns
Bad spot in 7" esg. Problems getting 5" liner through.
Unable to circulate thru GLM#12 @ 11,149'. Established Circulation
({¡¡ m M#ll ÍfÌ) 977(,'
PERFORATION BETAIL
Interval Accum.
Top Btm Amt spf
10,313' 10,315' 2' 4.0
10,431' 10,432' l'
11,326' 11,336' 10'
11 ,340' 11 ,346' 6'
11,354' 11,364' 10'
Conunents
1-9/16" Tbg Punch
DeeentraJized Cutter
10/19/1994
10/19/1994
1/9/1995
SRU 32A-15 Actual Schematic 10-94.doc
SCANNED OCT 0 9 2004.
REVISED: 9/112004 by SL T
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/94 - of'-/
FRANK H. MURKOWSKI, GOVERNOR
AI.A.SJiA OIL AND GAS
CONSERVATION COJDIISSION
333 w. -¡m AVENUE, SUITE 100
ANCHORAGE. ALASKA 99501-3539
PHONE (907) 279-1433
FAX (907) 276-7542
September 22, 2004
Mr. Philip J. Krueger
Drilling Manager
Unocal Alaska
PO Box 196247
Anchorage AK 99509-3330
RE: Swanson River Field W orkover HOPE Configuration
Dear Mr. Krueger:
Per 20 MC 25.285 (h), the Alaska Oil and Gas Conservation conunission ("AOGCC"
or "conunission") hereby grants Dnocal Alaska ("Dnocal")'s request for variance from
the workover blowout prevention equipment ("HOPE") requirements of 20 AAC 25.285
(c) and (e), during operations on wells in the subject field.
This variance is applicable to Swanson River Field wells SCD 32-08, SCD 33-33, SCD
312-09, SCD 24A-05, SCD 21-03, SRD 23-27, and SRD 32A-15. AOGCC finds that
Dnocal's requested variance provides at least an equally effective means of ensuring well
control as that required by regulation.
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 Conunission an application for rehearing. A request for rehearing is consid-
ered 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 hoJi.day or weekend. A person may not
appeal a Commission decision to Superior Court uó'Íes\¡,rehearing has been requested.
q~an/
Chairman
SCANNED OCT 1 0 2Q04
~
~
~Tr~TrŒ [ID~ ~~ffi~~æiÆ
AI ASIi& OIL AlQ) GAS
CONSERVATION COMMISSION í
!
I
I
/
I
I
I
I
I
I
FRANK H. MURKOWSKI, GOVERNOR
333 W. 7'" AVENUE, SUITE 100
ANCHORAGE, ALASKA 99501-3539
PHONE (907) 279-1433
FAX (907) 276-7542
September 3, 2004
Philip J. Krueger
Drilling Manager
Union Oil Company of California
P.O. Box 196247
Anchorage, Alaska 99519
qL\;~O'Ölf
Re:
Swanson River SRU 32A-15
Sundry: 304-340
Dear Mr. Krueger:
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.
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.
. Norman
Chairman
Enclosure
~
'fJ(:¡1T-
Do-:)
'1":>I~UV~
'1ïJ/ 1-
STATE OF ALASKA ~
ALAf.. . OIL AND GAS CONSERVATION COM~. jlON
APPLICATION FOR SUNDRY APPROVAL
20 MC 25.280
1. Type of Request: Abandon U Suspend 0 Operational shutdown U Perforate U Waiver U Annular Dispos. U
Alter casing D Repair well D Plug Perforations D Stimulate D Time Extension D Other 0
Change approved program D Pull Tubing D Perforate New Pool 0 Re-enter Suspended Well D Recomplete
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Union Oil Company of California Development 0 / Exploratory D 94-0084-0/
3. Address: Stratigraphic D Service D 6. API Number:
PO Box 196247, Anchorage, AK 99519 50-133-10141-01 /
7. KB Elevation (ft): 9. Well Name and Number:
346 SRU 32A-15 /
8. Property Designation: 10. Field/Pools(s): /"
Swanson River Production Facility Swanson River Field/Hemlock, Tyonek
11. PRESENT WELL CONDITION SUMMARY
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured):
11,590' 11,187' 11,560' 11,158' 11,560
Casing Length Size MD TVD Burst Collapse
Structural
Conductor 45' 22" 45' 45'
Surface 964' 13-3/8" 2,958' 2,958' 2,730 psi 1,130 psi
Intermediate
Production 10,257' 7" 10,257 9,938' 7,240 psi 5,410 psi
Liner 1,619 5" 11,590' 11,187' 10,140 psi 10,490 psi
Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft):
11,326' to 11,364' 10,937' to 10,973' 2-7/8"; 2-3/8" N-80 9,766'; 11,256'
Packers and SSSV Type: Otis BWD packer Packers and SSSV MD (ft): 11,186'
12. Attachments: Description Summary of Proposal ~ 13. Well Class after proposed work: /
Detailed Operations Program D BOP Sketch D Exploratory D Development 0 Service D
14. Estimated Date for 15. we~ Status a&e~ro~:
Commencing Operations: 9/16/2004 Oil J v-l Gas. --- Plugged D Abandoned 0
16. Verbal Approval: Date: WAG D GINJ D WINJ D WDSPL D
Commission Representative:
17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Steve Tyler 907-263-7649
Printed Name Philip J. Krueger Title Drilling Manager
Signature \. ¿:?ko /Þ 7- .--fl:!.pne 907-274-7600 Date 9/2/2004
/ / COMMISSION USE ONLY
¿.
Conditions of approval: Notify Commission so that a representative may witness Sundry Number: .30{j'-.3ÝcJ
Plug Integrity D BOP Test D Mechanical Integrity Test D Location Clearance D
Other: ReCeiVED
IRBDMs BFL SEP 0 8 ?nn~ g[~ ~ J 'lOO4
S"b","em Fo"" Re'"~ 4° Î Aillb all & all ConI. COmm;..ion
App<o"'" bY~ a RIG I N A L,v ORDER OF Anøhorlþ
COMMISSIONER THE COMMISSION Date: Z 3 /ð¥ /
v: ~d 12/2003 INSTRUCTIONS ON REVERSE simit it Duplicate
Form 10-403
/
~
~
SRU 32A-15 Workover Summary
. MIRU Sliekline. co GL V's w/ Dummies in all 11 GLM's.
. MIT Csg to 1500 psi.
. MIRU Eline RIH punch tbg @ 11,175'. RI Set Cmt Ret @ 9,750'. /'
. MIRU CT. PT BOPE. -
. PUMU BHA. RIH. Stab into retainer. Mi~lS of91*;at 15.8 ppg em;:.
. Cire/spot emt to tbg punch. Close tbg x esg'Bnnuli. S~~J/bblS below EaT. Open tbg
x esg annuli. /:
. Cireulate/d~splaee remainin6~lSbls of emt to retainer to bring TOC to 6200' in tbg /~
x esg annulI. Unstab from ret:éBD. POOH.
. RU Sliekline. RIH to retainer w/ temp survey. POOH.
. wac
. RIH w/ jet nozzel on CT. jet fluid out of well.
. RD CTU
. RU Eline. RIH perf 68-0 sand 7362' to 7402'. RD. /
~ ~
Swanson River
Well SRU 32A-15
UNOCALe Proposed Completion
Cas i n
RKB =15.0' Size T e Wt Grade Thrd Hole Cmt Cmt To
22" Conductor Yes Suñ.
\3-3/8" SuñCs 54.5 K-55 12.615 1000 sx Suñ
DV Collar 18-5/8"
13-3/8" SuñCsg 54.5 K-55 12.615 967' 2958' 600 sx 2144'
Calculated)
7" 29 P-IIO 6.184 Suñ 39'
7" 26 6.276 39' 2097'
7" Prod Csg 29 6.184 2097' 3439' 1000 sx 6495'
7" 26 N-80 6.276 3439' 6158' Ibru DV CBL
7" 29 8rd 6.184 6158' 7933' 10-5/8" @8467'
7" 26 P-llO 6.276 7933' 8467'
DV Collar 8467' 8470'
7" Prod Csg 26 P-llO 6.276 8470' 9789' 1000 9399'
7" 29 6.184 9789' 10,257' sxs Calculated
5" Liner 18 L-80 Buttress 4.276 9971' 11,590 6" 500sxs
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JEWELRY DETAIL
/
NO. Deotb ID 00 Item
15.0' - - Tubin~ Han~er
GLM #1. 1622' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #2. 3183' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #3. 3948' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #4. 4777' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #5. 5545' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #6. 6220' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #7. 6891' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #8. 7597' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #9. 8303' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #10. 9039' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #11. 9726' 2.347 5.5" x 4.673" Cameo MMG-P GLM
A. 9750' Cmt Retainer
1. 9766' 1.995" 3.503" Crossover, 2-7/8" EVE 8rd x 2-3/8" EVE 8rd
2. 10,448' 1.875" 3.065" Otis "XA" Sld~ give
GLM #12. 11,149' 1.875" 4.125" x 2.781" Cameo KBMG-2 GLM
3. 11,186' 2.55" Otis "BWD" Pkr
4. 11,226' 1.875" 2.701" Otis "X" Profile NinDle
5. 11,256' 2.32" 2.872" WLEG
1959
10/94
10/06/96
10,332'
6200' to 6280'
PERFORATION DETAIL
Interval AœußL
Top 8tm Amt sor Conunents
11 130' 11 136' 6' 4.0 Pro Punch
11,326' 11,336' 10' Proposed P&A
11 ,340' 11,346' 6' Proposed P&A
11,354' 11,364' 10' Pnloosed P&A
- .
SRU 32A-I5 Proposed Schematic 08-04
REVISED: 9/1/2004 by SL T
~ ,..--..."
Swanson River
Well SRD 32A-15
UNOCAL8 As Completed on 10/07194
Cas i n
RKB =15.0' Size T e Wt Grade Thrd Hole Cmt Cmt To
22" Conductor Yes Surf.
13-3/8" SurfCs 54.5 K-55 12.615 1000 sx Surf
DV Collar 18-5/8"
13-3/8" SurfCsg 54.5 K-55 12.615 967' 2958' 600 sx 2144'
Calculated)
7" 29 P-110 6.184 Surf 39'
7" 26 6.276 39' 2097'
7" Prod Csg 29 6.184 2097' 3439' 1000 sx 6495'
7" 26 N-80 6.276 3439' 6158' Thru DV CBL
7" 29 8rd 6.184 6158' 7933' 10-5/8" @ 8467'
7" 26 P-110 6.276 7933' 8467'
DV Collar 8467' 84'"
7" Prod Csg 26 P-110 6.276 8470' 9789' 1000 9399'
7" 29 6.184 9789' 10,257' sxs Calculated
5" Liner 18 L-80 Buttress 4.276 9971' 11,590 6" 500sxs
'"
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JEWELRY DETAIL
<\t\.1l
NO. OeDth ID 00 Item
15.0' - - Tubin2 Hanlter
GLM #1. 1622' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #2. 3183' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #3. 3948' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #4. 4777' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #5. 5545' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #6, 6220' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #7, 6891' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #8. 7597' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #9, 8303' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #10. 9039' 2.347 5.5" x 4.673" Cameo MMG-P GLM
GLM #11. 9726' 2.347 5.5" x 4.673" Cameo MMG-P GLM
1. 9766' 1.995" 3.503" Crossover, 2-7/8" EVE 800 x 2-3/8" EVE 800
2. 10,448' 1.875" 3.065" Otis "XA" Sldg Sive
GLM #12, 11,149' 1.875" 4.125" x 2.781" Cameo KBMG-2 GLM
3. 11,186' 2.55" Otis "BWD" Pier
4. 11 226' 1.875" 2.701" Otis "X" Profile Nionle
5. 11,256' 2.32" 2.872" WLEG
\ () ~4-.g
1959
10/94
10/06/96
10,332'
6200' to 6280'
PERFORATION DETAIL
Interval ACCURL
Top Btm Amt sp! Comments
11,326' 11,336' 10' 10/19/1994
11,340' 11 ,346' 6' 10/19/1994
11,354' 11,364' 10' 1/9/1995
TD= 11,590' PBTD= 11,560'
Max Deviation = 24.30 @ 7815'
SRU 32A-15 Actual Schematic 10-94
REVISED: 9/1/2004 by SL T
THE MATERIAL UNDER THIS COVER HAS BEEN
MICROFILMED
ON OR BEFORE
JANUARY 03,2001
M
PL
ATE
THIS
E
W
IA L U N D ER
M A R K E R
c' E R M t T
i'
Au,.~uL iiadi'v'Yduai We'I'i
Geological Ma~er"i'ais Inventor"y
DATA T DATA._P L. U S
94 .... 08z:. ~00 T 10250--11560 C,t.i/FIi"qALS
94~.-084 L/DII.~/SFL L 10250-~'11544
94 ..... 084 ~'I~..DT/CNL L 10250-I 1512
94-"-0S4 f.~441..JE, L I 0282--' '1 I 590
D,-z/l:e: 06/ 18/'96
R I..I N D A T ,-:!': .... R E ,~*.... V D
I 1/'i 'l/g4
'i 0/" 3 'I/' g 4
· 10 / 3 1 / 94
Ar'e dr"y ciitch samples r'equir'ed? yes ~--?-'~And r"ecei'ved? ~ r',o
___Anaiysi's & descr'ipti'or~ r'ecei'ved';'
~___Recei' ved?
y ~ F', 0
.~,, STATE OF ALASKA
AL~ , OIL AND GAS CONSERVATION COMk ;ION
REPORT OF SUNDRY WELL OPERATIONS
1. Operations performed: Opera§on shutdown __ Stimulate
Pull tubing _ _ Alter casing__
__ Plugging _ _ Perforate _ _ Cleanout
Repair well _ _ Pulltubing _ _ OtherX_ Perforation
2. Name of Operator
Union Oil Company of California (Unocal)
3. Address
P.O. Box 196247 Anchorage, AK 99519
5. Type of Well:
Development X
Exploratory __
Stratigraphic__
Service
,
Location of well at surface
2300' FNL, 1040' FWL, Sec. 15, T8N, R9W, SM
At top of productive interval
2284' FNL, 3074' FWL, Sec. 15, T8N, R9W, SM
At effective depth
At total depth
2286' FNL, 3161' FWL, Sec. 15, T8N, R9W, SM
6. Datum elevation (DF or KB)
.329' KB
¢'-.-~bl~it-o[ P-r~--p-erty name
/ ~/a~nxs~,n.River Unit
8. Well n~/'L., /
SRU 3~-15 ~ ~
feet
9. Permit number/approval number
94-84/95-001
10. APl number
50-133-10141-01
11. Field/Pool
Swanson River/Hemlock Pool
12. Present well condition summary
Total depth: measured
true vertical
11590' feet
11200' feet
Plugs (measured)
Effective depth: measured 11499' feet
true vertical 11114' feet
Junk (measured)
Casing Length Size Cemented
Structural
Conductor 45' 22" Driven
Surface 2958' 13-3/8" 600 sx
Intermediate 10257' 7" 2000 sx
Production 1589' 5" 500 sx
Liner
Perforation depth: measured 11326'-11336'; 11340'-11346'; 11,354'-11,364'
Measured depth
45'
2958'
10257'
1156O'
True vertical depth
45'
2958'
10757'
11170'
true vertical 10950'- 10960'; 10964'- 10970'; 10978'- 10988'
Tubing (size, grade, and measured depth) 2-7/8", 6.4#, N/L-80, 0'-9768'
Packers and SSSV (type and measured depth) 2-3/8", 4.6#, L-80, 9768'-11182'
13. Stimulation or cement squeeze summary
Intervals treated (measured)
Treatment description including volumes used and final pressure
MAR -9 i995
0il & Gas Cons. Commission
Anchor; '
14.
Prior to well operation
Representative Daily Average Production or Iniection Data
OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure
N/A
Tubing Pressure
Subsequent to operation 300 170 6 820
15. Attachments I 16. Status of well classification as:
Copies of Logs and Surveys run
Daily Report of Well Operations _-- I Oil x_ _ Gas _ _ Suspended _ _
17. I hereby certify that the fo['e~a~'ing i~' ~d-c~t to the best of my knowledge.
Signed G. RussellSchmidt/~l/--~.,ca~y,.~,~.z'~tl. Drilling Manager
Form 10-404 Rev 06/15/88 '
25O
Service
-
Date 3-6-95
SUBMIT IN DUPLICATE
CURRENT STATUS
January 20,1995
SRU 32A-15
KB = 329'
DV 964'
13-3/8" ~ 2958'
2-7/8" GLM'$ AS FOLLOWS:
1) 1622'
2) 3183'
3) 3948'
4) 4777'
5) 5545'
6) 6220'
~) 6891'
8) 7597'
9) 8303'
1o) 9039'
11) 9726'
2-7/8" 6.4//N&L-80 TUBING 0-9,768'
DV 8467'
TOP OF 5' LINER (~ 9,971'
2-3/8" X 2-7/8" XO ~ 9,766'
2-3/8" 4.6# L-80 BTC TUBING 9,768'-11,256'
T' 29# N-80 CASING
10,257' CKOP)
5" 18# L-gO LINER ~ 11,560'
TD @ 11,590'
"XA" SLEEVE ~ 10,448'
2-3/8" GLM (~ 11,149'
"BWD" PACKER ~ 11,186'
"X" NIPPLE (~ 11,226'
2-3/8" TUBING TAIL ~ 11,256'
PERF$11,326'-11,336' 10/19/94
PERF$11,340'-11,346' 10/19/94
PERF$11,354'-11,364' 1/9/95
Tag ~ill ~ 11,497' 8LM RECEI~/-D
¢~3~s~ 0ii & 6as 6ons. f3ommissior~
Anchor~.
32A15DG.DOC 2/24/95
DAY 21
7"¢_, 9745'
PERFORATE HEMLOCK H-13 AT 10,764- 10,776 WITH 1-11/16" PIVOT
GUN AT 4 JSPF. COSTS INCLUDE PERF, P&A, AND RIG MOVE.
SCU 32A-15
FISHING WIRELINE.
SCU 32A-15
(01/06-09/95)
RIH W/1.90" SWEDGE & SET DOWN @ 10,340' (HOWCO). UNABLE
TO WORK THRU. RIH W/1.875' SINKER BARS & WORK F/10331'-
10335'. RIH W/SCRATCHER & WORK TO 10,335'. RIH W/1.875"
SWEDGE & WORK TO 10,345'. RIH W/1-11/16" DUMMY GUN & JAR
THRU TIGHT SPOT. RIH TO 11,370'. RIH W/1.75" BROUCH. WORK
BROACH @ 10,332'. RIH W/1-11/16' DUMMY GUN & SET DOWN @
10332'. RIH W/1-1/4" TOOL STRING & DUMMY GUN W/O MAGNET &
PASSED THRU TIGHT SPOT. TAGGED BOTTOM @ 11497'. RU
S.W.S. & RIH Wi10' STRIP GUN @ 6 SPF. SET DOWN @ 10332'. RD
SWS. RIH W/1.75" BROUCH & WORK THRU TIGHT SPOT @ 10332'.
RIH W/1-11/16" DUMMY GUN & TAG BOTTOM @ 11,497'. RU S.W.S.
RIH W/1-11/16" STRIP GUN @ 6 SPF W/16' OF 1-1/4" SINKER BARS
ON BOTTOM. WORK THRU TIGHT SPOT @ 10316' (WLM).
PERFORATE HEMLOCK H-2 11364'-11354' W/1-11/16" STRIP GUN @
6 SPF. ALL SHOTS FIRED. RD S.W.S. TURN WELL OVER TO
PRODUCTION.
__. STATE OF ALASKA
AL,-,. OIL AND GAS CONSERVATION CON,,.~ ,ON
APPLICA iON FOR SUNDRY AP ROVALS
1. Type of request:
Abandon _ _ Suspend __ Operations shutdown__ Re-enter suspended well__
Alter casing__ Repair well _ _ Plugging __ Time extension __ Stimulate __
Change approved program __ Pull tubing Variance __ Perforate X OtherX
2. Name of Operator
UNION OIL COMPANY OF CALIFORNIA (UNOCAL)
3. Address
P.O. BOX 196247 ANCHORAGE, AK 99519
Location of well at surface
2300' FNL, 1040' FWL, SEC. 15, T8N, R9W, SM
At top of productive interval
2284' FNL, 3074' FWL, Sec. 15, T8N, R9W, SM
At effective depth
2286' FNL, 3161' FWL, Sec. 15, T8N, R9W, SM
At total depth
Same
CLEANOUT
5. Type of Well:
Development X_
Exploratory
Strafigraphic
Service
6. Datum elevation (DF or KB)
329' KB
7. Unit or Property name
Swanson River Unit
8. Well number
SRU 32A- 15
feet
9. Permit number
94
10. APl number
50-133-10141-01
11. Field/Pool
Swanson River Field/Hemlock
12.
Present well condition summary
Total depth: measured
Effective depth:
Casing
Structural
Conductor
Surface
Intermediate
Production
Liner
Perforation depth:
true vertical
measured
true vertical
Length
11,59O'
11,200'
11,499'
11,114'
Size
45' 22"
2958' 13-3/8"
10257' 7"
1589' 5"
feet
feet
feet
feet
Plugs (measured)
Junk (measured)
Cemented
Driven
600 sx
2000 sx
500 sx
measured 11326'- 11336'; 11340'-11346'
true vertical 10950'- 10960'; 10964'- 10970'
Tubing (size, grade, and measured depth) 2-7/8" 6.4# N/L 80 0-9768'
2-3/8" 4.6# L80 9768'- 11182'
Packers and SSSV (type and measured depth) "BWD" packer at 11182'
ORIGINAL
Measured depth
True vertical depth
45'
2958'
10257'
11560'
RECEIVED
JAN - 4 1995
Alaska 0il & Gas Cons. Commission
Anch0r~
45'
2958'
10257'
11170'
13. Attachments
Description summary of proposal x _
Detailed operations program_ _
BOP sketch
-- _
14. Estimated date for commencing operation
ASAP
16. If proposal was verbally approved
Name of approver Blair Wondzell
12/29/94
Date approved
5. Status of well classification as:
Oil x Gas
Suspended __
Service
17. I hereby certJfy that the foregoingj~Jrue and cor[,ect.t0 ~[ne best of my knowledge.
Signed G. Russell Schmld~_~..N~lj~,,~l.{/],/[}{¢~,~¢ ! : Title Drilling Manager
FOR COMMISSION USE ONLY
Date 12/30/94
Conditions of approval: Notify Commission so representative may witness
Plug Integrity __ BOP Test
Mechanical Integrity Test_
Approved by the order of the Commission
Approval No.
~ Location clearance _
Subsequent form required 10- ~_0.._~_(___
Approved Copy
(}rigina! Signed By Returned
David W, Johnston -
Commissioner Date
Form 10-403 Rev 06/15/88
SUBMIT IN TRIPLICATE
SRU 32A-15
COILED TUBING CLEANOUT
PROCEDURE
1. MIRU CTU AND SUPPORT SERVICES.
,
.
NU AND TEST QUAD BOP.
RIH WITH 1-1/4" COILED TUBING AND CLEAN OUT SAND TO 11,499' (ETD) WITH
LEASE WATER.
4. RDMO CTU.
,
NU WlRELINE UNIT AND PERFORATE HEMLOCK (I-t-2) 11,352'-11,362' WITH 1-11/16"
STRIP GUNS AT 6 SPF. ND WlRELINE.
6. PLACE WELL ON PRODUCTION.
RECEIV£D
JAN - 4 199,5
Oil & Gas Cons. Commission
gnchora~.g
SRU 32A- 15
CURRENT STATUS
DECEMBER 29, 1994
.
DV 964'
13-3/8" ~ 2958'
2-7/8" GLM'S AS FOLLOWS:
1) 1622'
2) 3183'
3) 3948'
4) 4777'
S) 5545'
6) 6220'
7) 6891'
8) 7597'
9) 8303'
10) 9039'
ll) 9726'
2-7/8" 6.4# N&L-80 TUBING 0-9,768'
DV 8467'
TOP OF 5" LINER ~ 9,971'
2-3/8" X 2-7/8" XO ~ 9,768'
2-3/8" 4.6# L-gO BTC TUBING 9,768'-11,182'
7" 29# N-80 CASING
10,257' (KOP)
5" 18# L-80 LINER @ 11,560'
TD ~ 11,590' L ::~!~'.-'~!~!~!~i!
"XA" SLEEVE ~ 10,448'
2-3/8" GLM @ 11,149'
"BWD" PACKER ~ 11,186'
"X" NIPPLE ~ 11,226'
2-3/8" TUBING TAIL ~ 11,256'
PERFS 11,326'-11,336'
PERFS 11,340'-11,346'
RECEIVED
JAN - 4 1995
Oil & Gas Cons. Commission
Anchora. :~
sRu 3 2A- 15
PROPOSED STATUS
DECEMBER 29, 1994
DV 964'
13-3/8" ~ 2958'
2-7/8" GLM'S AS FOLLOWS:
~) 1622'
2) 3183'
3) 3948'
4) 4777'
5) 5545'
6) 6220'
7) 6891'
8) 7597'
9) 8303'
10) 9039'
11) 9726'
2-7/8" 6.4# N&L-80 TUBING 0-9,768'
DV 8467'
TOP OF 5" LINER ~ 9,971'
2-3/8" X 2-7/8" XO ~ 9,768'
2-3/8" 4.6# L-gO BTC TUBING 9,768'-11,182'
7" 29# N-80 CASING
10,257' CKOP)
/
5" 18# L-80 LINER @ 11,5601
TD @ 11,590'
"XA" SLEEVE @ 10,448'
2-3/8" GLM @ 11,149'
"BWD" PACKER @ 11,186'
"X" NIPPLE @ 11,226'
2-3/8" TUBING TAIL ~ 11,256'
PERFS 11,326'-11,336'
PERFS 11,340'-11,346'
PROPOSED HEMLOCK H-2 PERFS
11,352'-11,362'
RECEIVED
JAN - 4 1995
Alaska 0il & Oas Cons. Commission
A~ehora, .)
STATE OF ALASKA
ALAS!~':'~OIL AND GAS CONSERVATION COM"-"'SION
WELL COMPLETi OR RECOMPLETION i..LPORT AND LOG
I1. Status of Well
o,L I_x GAS
Classirmation of Service Well
2. Name of Operator
UNION OIL COMPANY OF CALIFORNIA (UNOCAL)
3. Address
P.O. BOX 196247 ANCHORAGE, AK 99519
4. Location of well at surface
2300' FNL, 1040' FWL, SEC. 15, T8N, R9W, SM
At Top Producing Interval (11,326' Projected)
2284' FNL, 3074' FWL, SEC. 15, T8N, R9W, SM
At TotaJ Depth (Projected, See Attached variance)
2286' FNL 3161' FWL, SEC. 15, T8N, R9W, SM
5. Elevation in feet (indicate KB, DF, etc.)
329' KB, 302.4' GL
12. Date Spudded
09/24/94
17. Total Depth (MD+'I'VD) 11590'M D/11200"rVD
7. Permit Number
so-
9. Unit or J
SWANSON R~ER d~/~ ,
10, Well Number
SRU 3~-15
11, Field ~d Pool
SWANSON RNE~EMLOCK POOL
6. Lease Designa~on and SeriaJ No. A-028384
I13.Date T.D. Reached 14. Date Comp, Susp. or Aband. 15. Water Depth, if offshore 15. No. of Completions
10/02/94 /~/,~-.,OJ;~ <~/ ~. I Feet MSL I 1
18. Plug Back Depth (MD+TVD) j19. D~ctional Surv~ 120. Depl~ where SSSV set 121, Thickness o~ Permafrost
11499'(MD)11114'(TVD) iYES II NO~ J ' feetMD I N/A
22. Type Electric or Other Logs Run
D ITFJG R/LDT/C N L/C BI./S P
23.
i FT.
CASING SIZE WT. PER GRADE
22" 15'
13-3/8' 15'
7' 29# N80 14'
5" 18# L80 9971
CASING, UNER AND CEMENTING RECORD
SE'i-TING DEPTH MDI
TOP I BOTTOM HOLESIZE CEMENTING RECORD
I AMOUNT PULLED
45' Driven 0
2958' 18- 5/8" 600 SX 0
10257' (KOP) 10-5/8" 1000 SX & 1000 sx (~ 8457' 0
11560' 6' 5OO SX 0
24. Perforations open to Production (MD+TVD of Top and Bottom and
intervaJ, size and number)
Measured Depth True Vertical Depth
1132~'- 11336' 10950'- 10960'
11340'-11346' 10964'-10970'
25. TUBING RECORD
SIZE I DEPTH SET (MD) I PACKER SET (MD)
2-7/8" 0-9768'
2-3/8" 9768'-11182' 11182'
26. ACID, FRACTURE, CEMENT SQUF~='~=~ ETC.
DEPTH INTERVAL (MD) I AMOUNT & KIND OF MATERIAL USED
Non~
27 PRODUCTION TEST
Date First Production
10/19/94
Date of Test
11/15/94
Hours Tested
24 hours
Flow Tubing Casing Pressure
Press. 260 1000
28.
I Method of Operation (Flowing, gas lift, etc.)
Gas Lift
I PRODUCTION FOl~ OIL-BBL GAS-MCF
TEST PERIOD ! 203 313
CALCULATED ! OIL-BBL GAS- MCF
24-HOUR RATE ! 203 313
CORE DATA
WATER-BBL CHOKE SIZE GAS-OIL RATIO
75 3/4" 1542
WATER-BBL OIL GRAVITY-APl (con)
75 34
Brief description of lifl~ology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips.
RECEIVED
DEC 2 2 199
A!~s~. Oil & Gas Cons, Commission
Anch0r~"
Form 10-407 Submit ~ duplicate
rev. 7-1-80 CONTINUED ON REVERSE SIDE
I
29. 30.
GEOLOGIC MARKER~ FORMATION TESTS
NAME Include intervaJ tested, pressure data. ail fluids recovered and gravity,
MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase.
Top Hemlock Fm. 11,316' 10,941'
¥
31. LIST OF ATTACHMENTS
32. I he re by~ 'rtify~g~~rrect to the best of my knowledge
Signed G. RUSSELL $CHMIDT T'rtle DRILMNG MANAGER Date 11/(:13/94 _
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.
Item 1' Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt
water disposal, water supply for injection, observation, injection for in-situ combustion
Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements
given in other spaces on this form and in any attachments.
Item 16 and 24: if this well is completed for separate production from more than one interval (multiple
completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported
in item 27. Submit a separate form for each additional interval to be separately produced, showing the
data pertinent to such interval.
Item 21' Indicate whether from ground level (GL) or other elevation (DF, KB, etc.).
Item 23: Attached supplemental recordsfor this well should show the details of any multiple stage cement-
ing and the location of the cementing tool.
Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In-
jection, Gas Injection, Shut-in, Other-explain.
item 28: ff no cores taken, indicate 'none'.
SI U 32A-15
CURRENT STATUS
DECEMBER 13, 1994
DV 964'
13-3/8" ~ 2958'
2-7/8" GLM'S AS FOLLOWS:
1) 1622'
2) 3183'
3) 3948'
4) 4777'
5) 5545'
6) 6220'
7) 6891'
8) 7597'
9) 8303'
10) 9039'
11) 9726'
2-7/8" 6.4g N&L-80 TUBING 0-9,768'
DV 8467'
TOP OF 5" LI2qER ~ 9,971'
2-3/8" X 2-7/8" XO (~ 9,768'
2-3/8" 4.6# L-80 BTC TUBING 9,768'-11,182'
7" 29# N-gO CASING @
lO,257' 0coP)
18# L-80 LINER ~ 11,560'
VD @ ~ 1,590' /
"XA" SLEEW @ 1O348'
2-3/8' GLM @ 11,149'
"BWD" PACKER @ 11,186'
%'X" NIPPLE @ 11,226'
2-3/8" TUBING TAIL @ 11,256'
PERFS 11,326'-11,336'
PERF8 11,340'-11,346'
RECEIVED
DEG 2 2_ 1994.
oil & Gas Cons, Commission
Anchort ':
SWANSON RIVER
SRU 32A-15
DAY 1 (9/15/94)
7"¢____. 11,595'
ETD +/- 10,400'
ACCEPTED NABORS RIG #154 AT 0600 HRS: AFTER TURNKEY RIG
MOVE. RIGGED UP TO PRESSURE TEST TUBING AGAINST PLUG AT
145'. PLUG NOT HOLDING. CIRC DIESEL OUT OF TUBING.
RECOVERED PLUG. CIRC. DRESSED COSASCO BPV PROFILE.
INSTALLED AND TESTED BPV TO 5000 PSI.
SRU 32A-15
DAY 2-4 (9/16-18/94)
7"@ 11,595'
ETD +/- 10,400'
REMOVED TREE. DRESSED TBG HANGER THREADS. INSTALLED
AND TESTED BOPE, WITNESSED BY BLM. UNSEATED TUBING
HANGER. RAN FREE POINT TOOL. JET CUT TUBING AT 10,344'.
VERY DIFFICULT PULLING THE TUBING FOR 270'. CIRCULATED
SAND AND PARAFFIN OUT OF HOLE. POOH AND L/D TUBING, LOTS
OF PARAFFIN.
SRU 32A-15
DAY 5 (9/19/94)
7" @ 11,595'
ETD +/- 10,344'
CHANGED FROM 2-7/8' TO 3-1/2' RAMS & TESTED. RIH W/BIT AND
SCRAPER. STOPPED AT 110', PARAFFIN. POOH. INSTALLED
FLOAT. WASHED AND REAMED TO 5160'. WHILE P/U DRILL PIPE.
SRU 32A-15
DAY 6 (9/20/94)
7" @ 11,595'
ETD +/- 10,280'
P/U, 3-1/2" D.P.
10,280', POOH.
9000'.
CLEAN OUT PARAFFIN TO TOP OF TUBING FISH AT
RAN SCHLUMBERGER CCL/GR FROM 10,280' TO
DEC,
0il & Gas Cons. Commis¢or~
Anchor~
DAY 7 (9/21/94)
7" @ 11,595'
ETD +/- 10,280'
RAN USIT/CCL/GR LOG FROM 10,230'TO SURFACE. BOND
ADEQUATE AND CASING IN GOOD SHAPE. TESTED CASING 2300
PSI FOR 30 MIN., OK. P/U BAKER BOTTOM SET WHIPSTOCK WITH
STARTER MILL. RIH SLOWLY BROKE CIRCULATION EVERY 3000'.
SRU 32A-15 U.O. 98.48643% DEV-OIL
DAY 8 (9/22/94)
7" @ 11,595'
ETD +/- 10,280'
ORIENTED WHIP STOCK 30 DEG LEFT OF HIGH SIDE. SET DOWN
ON TUBING STUB AT 10,300' DPM. P/U ATTEMPT TO SET
WHIPSTOCK UNSUCCESSFUL. SET DOWN AND SHEARED OFF
WITH 20K LBS SET W/TOP AT 10,277' CLEANING SUCTION
TANK AND CHANGE OVER TO 9.8 PPG MUD. MILLED WITH
STARTER MILL FROM 10,278'-10,281'. POOH W/MILL TO RUN NEW
BAKER PACKER TYPE WHIPSTOCK DUE TO PROBLEMS SETTING
FIRST WHIPSTOCK. MAKE UP 7" WHIPSTOCK PACKER WITH
SETTING AND ORIENTING TOOL. RIH. TAG TOP OF WHIPSTOCK AT
DAY 9-11 (9/23-25/94)
7" WINDOW @ 10,259'
SET PACKER AT 10,260' WITH 3500 PSi. ATTEMPT TO CIRCULATE
DP PLUGGED. SHEARED CIRCULATING SUB. POOH WITH SETTING
TOOL AND ORIENTING ASSY. RIH W/MULE SHOE GUIDE AND MWD.
WASH TOP OF PACKER, STAB IN AND MEASURE PACKER
ORIENTATION. POOH, RIH W/BAKER WHIPSTOCK AND STARTER
MILL. LATCH INTO PACKER AT 10,260', WHIPSTOCK ORIENTED 30
DEG. LEFT OF HIGH SIDE. MILLED W/STARTED MILL FROM 10,259'-
10,264', TOP OF WHIPSTOCK AT 10,258'. PRESSURE TEST BOPE.
RIH W/WINDOW MILL ASSY. MILLED FOR 10,259'-10,274' POOH.
RIH W/STRING MILL/WATERMELON MILL ASSY. DRESS WINDOW
FROM 10,258' TO 10,282'. POOH.
RECEIVED
DEC: 2 2. /99i~-
.,;...ik~ka. Oil & Gas Cons. Commission
Anchorz
SRU 32A-15
DAY 12 (9/26/94)
7" WINDOW @ 10,259'
COMPLETED POOH. P/U STEERABLE MOTOR ASSY AND BIT. RIH.
UNABLE TO WORK THROUGH OUT OF SPEC CASING AT 6271'
POOH. REMOVED TOP STABALIZER. RIH. DIRECTIONALLY
DRILLED 6' HOLE F/10,282'-336'.
DAY 13 (9/27/94)
7" WINDOW @ 10,259'
DIRECTIONALLY DRILLED 6" HOLE F/10,336'-10,512'. POOH.
DAY 14 (9/28/94)
7" WINDOW @ 10,259'
COMPLETED POOH. P/U ROTATING ASSEMBLY. WORKED
THROUGH OUT OF SPEC CASING F/6200'-6280'. DRILLED 6' HOLE
F/10,512'-715'.
DAY 15 (9/29/94)
7" WINDOW @ 10,259'
DRILLED 6' HOLE F/10,715'-11,096'.
DAY 16-18 (09/30/10/01-02/94)
10.6 PPG (WBM)
7" WINDOW @ 10,259'
DRILLED 6" HOLE FIl1,096'-11,114'. BRING MW UP TO 10.8 PPG
AND TRIP F/BIT. DRILLED 6" HOLE F/11,114'-11,590'. LOST ClRC ON
BOTTOM. SPOTTED LCM PILLS. HOLE CURRENTLY TAKING 3 BPH.
DAY 19 (10/03/94)
TOH FOR LOGS. RU LOGGERS. RAN DIL/SFL/SP/GR/FDC/CNL/CAL/
AMS F/11560'-10276'. RD LOGGERS. PU 5* LINER & HANGER AND
RIH.
DAY 20 (10/04/94)
CONT. RIH W/LINER TO 11560'. APPEARS TO BE TD. CMT LINER
WI500 SX CMT. PARTIAL RETURNS ONLY AT END OF JOB. SET
HANGER & LINER TOP PACKER. POOH. TEST BOP'S.
DAY 21 (10/05/94)
TIH W/CLEANOUT ASSEMBLY. CLEAN OUT TO PLUG 11,499'(DPM).
PRESS TEST CSG TO 1500 PSI/30 MINS, OK. POH. RAN VDL-CBL
FROM 11,477' (WLTD)-9950'. RAN SINGLE SHOT SURVEY AT 11,477'.
RIH W/CLEANOUT ASSBY.
DAY 22 (10/06/94)
8.5 PPG (WBM)
7" WINDOW @ 10,259
CIRCULATE WELL CLEAN WITH 3% KCL. PRESS. TEST LINER TOP
TO 2500 PSI, OK. POOH. RIH WI5' BWD PACKER & SET AT 11,182'
(DPM), 11,160' (DIL). TAIL AT 11,230' (DIL). TEST PKR TO 1500 PSi,
OK. POOH LD DP.
DAY 23-25 (10/07-09/94)
8.5 PPG (WBM)
7" WINDOW @ 10,259'
POOH LD DP. RIH PU 2-3/8" X 2-7/8" GAS LIFT COMPLETION. 2ND
GLM F/BOTTOM WOULD NOT GO IN LINER. POH. REPLACE 2ND
GLM F/BOTTOM W/OTIS "XA" SLEEVE. RIH & STAB INTO PACKER.
TUBING WOULD NOT TEST. RU SLICK LINE & CLOSED "XA"
SLEEVE.TEST TUBINGTO 1500 PSI, OK. SPACED OUT & LANDED
TUBING. ND BOP. NU BOTTOM MASTER VALVE. RIG RELEASED
TO TURNKEY MOVE @ 1800 HRS, 10/09/94.
11590'/0'
DAY 25-27 (10/17-19/94)
7' WINDOW @ 10,259
10/17/94: PERFORATED HEMLOCK H-1 SAND 11,326'-11,336' WI1-
11/16" PIVOT GUN AT 4 SPF. 10/19/94: PERFORATED HEMLOCK H-1
SAND 11,340'-11,346' W/1-11/16' PIVOT GUN AT 4 SPF.
SCU 32A-15
11590'/0'
U.O. 98.48643% DEV-OIL
REDRILL HEMLOCK
DAY 25 (10/20/94)
7' WINDOW @ 10,259
D.C. $ 0
CUM: $ 1,280,617
AFE $ 1,860,000
AFE #7425O7
NO TEST.
11590'/0'
DAY 25 (10/20/94)
10/21:44 BO + 124 BW/24 HRS
10/22:208 BO + 139 BW/24 HRS
10/23:137 BO + 174 BW/24 HRS
11590'/
DAY 25 (10/20/94)
7' WINDOW @ 10,259
10/24:176 BO + 50 BW/24 HRS
11590'/0'
DAY 25 (10/20/94)
7" WINDOW @ 10,259
10/25 NO TEST
11590'/0'
DAY 25 (10/20/94)
7' WINDOW @ 10,259
10/26 NO TEST
SCU 32A-15
11590'/0'
DAY 25 (10/20/94)
7" WINDOW @ 10,259
TIME REQ: 39 DAYS
PLANNED TD + 11,550'
10/28 NO TEST
10/29 152BO&OBW
10/30 257 BO & 0 BW
SCU 32A-15
11590'/0'
DAY 25 (10/20/94)
7" WINDOW @ 10,259
11/03 NO TEST
11590'/0'
DAY 25 (10/20/94)
7" WINDOW @ 10,259
10/31 207 BO & 0 BW
SCU 32A-15
11590'/0'
DAY 25 (10/20/94)
7" WINDOW @ 10,259
11/02 369 BO & 4 BW
SCU 32A-15
11590'/0'
DAY 25 (10/20/94)
7" WINDOW @ 10,259
11/03 NO TEST
SCU 32A-15
11590'/0'
DAY 25 (10/20/94)
7" WINDOW @ 10,259
11/04 407 BO & 129 BW
SCU 32A-15
11590?0'
DAY 25 (10/20/94)
7" WINDOW @ 10,259
11/05 203 BO & 75 BW
REDRILL HEMLOCK
DAY 21
7"@ 9745'
D.C. $ 400,500
CUM: $ 932,089
AFE $ 1,332,589
AFE #742508
REQ: 38 DAYS
PLANNED TD + 11,000'
PERFORATE HEMLOCK H-13 AT 10,764- 10,776 WITH 1-11/16' PIVOT
GUN AT 4 JSPF. COSTS INCLUDE PERF, P&A, AND RIG MOVE.
SCU 32A-15
FISHING WIRELINE.
Unocal Energy Resour :)ivision
Unocal Corporation
909 West 9th Avenue, P.O. Box 196247
Anchorage, Alaska 99519-6247
Telephone (907) 276-7600
UNO .AL
Alaska
DOCUMENT TRANSMITTAL
October 28, 1994
TO: Larry Grant
FROM: Eric Graven
LOCATION: 3001 PORCUPINE DRIVE LOCATION: P.O.BOX 196247
ANCHORAGE, AK 99501 ANCHORAGE AK 99519
ALASKA OIL & GAS CONSERVATION COMM. UNOCAL
.-_-_-:_-_-_-_-.-.-.-:.._-_-_._-.
TRANSMITTING AS FOLLOWS
One blueline and one sepia of the following
'~~~du~ion- S~ ~ ~ ~osk~ 0i/
~mpemated Neutron - Litho Densi~ ~Gas Coa~
PLEASE A~O~DGE ~~mT BY SIG~G ~ ~~G O~ COPY OF
~~~DB~/, ~ ~ /// ~
Unocal North Americar
Oil & Gas Division
Unocal Corporation '
P.O. Box 190247
Anchorage, Alaska 99519-0247
Telephone (907) 276-7600
Alaska Region
UNOCAL
Oct. 3,
1994
Mr. Bob Crandel
Alaska Oil and Gas Conservation Commission
3001 Porcupine Drive
Anchorage, Alaska 99501-3192
Dear Mr. Crandel
On October 3, 1994, I phoned you to receive a verbal variance waiving the requirement
for an end of well directional survey on Swanson River Well SRU 32A-15 Redrill. The
well was originally drilled in 1959 as a producer in the Hemlock formation. In 1991 the
productive zones were abandoned by cementing with a coil tubing unit.
On Sept. 15, 1994, Unocal commenced redrill operations on the well. A casing whipstock
was set at 10,259', a bent housing mud motor and MWD were used to kick off the well
and drill to 10,512'. The well was then drilled with two packed rotary assemblies to TD
at 11,590'. Original plans called for taking single shot surveys at the end of each of these
runs to obtain directional information. The single shot at the end of the first run
malfunctioned. The plan was then modified to drop a multishot survey at TD. At 11,590'
lost circulation was encountered, TD was called at this point. The decision was taken not
to run the multishot survey due to the problem with the losses and the potential of sticking
the BHA. The well was electric line logged and a liner is being run at the present time.
As I mentioned in our phone conversation, the wellbore is well within lease and unit
boundaries. The well plans called for redrilled well to be about 150' from the original
wellbore to give a new sand face for production. We feel that the well should be very
close to plan.
I have also contacted BLM to receive a variance from surveying the well, Mr. Joe Russell
granted the variance for BLM. Unocal would like to thank you and the AOGCC for
cooperating with us by granting this variance. Waiving this requirement eliminates an
expensive and time consuming gyro survey from our operation.
CC
G.R. Schmidt
P.A. Ryan
Sincerely Yours
Dan Williamson
Drilling Supt.
ALASKA OIL AND GAS
CONSERVATION COMMISSION
WALTER J. HICKEL, GOVERNOR
3001 PORCUPINE DRIVE
ANCHORAGE, ALASKA 99501-3192
PHONE: (907) 279-1433
TELECOPY: (907) 276-7542
July 5, 1994
G Russell Schmidt, Drlg Mgr
Unocal
P O Box 196247
Anchorage, AK 99519
Re:
Well #
Company
Permit #
Surf Loc
Btmhle Loc
Swanson River Unit 32A-15
Unocal
94-84
2300'FNL, 1040'FWL, Sec 15, T8N, R9W, SM
2300'FNL, 3167'FWL, Sec 15, T8N, R9W, SM
Dear Mr Schmidt:
Enclosed is the approved application for permit to re-drill the above referenced well.
The permit to re-drill does not exempt you from obtaining additional permits required by law
from other governmental agencies, and does not authorize conducting re-drilling operations
until all other required permitting determinations are made.
Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035.
Sufficient notice (approximately 24 hours) of the BOPE test performed before drilling below the
surface casing shoe must be given so that a representative of the Commission may witness the
test. Notice may be given by contacting the Commission at 279-1433.
David W~J~hnston
Chairman
BY ORDER OF THE COMMISSION
jo/encl
c: Dept of Fish & Game, Habitat Section - w/o encl
Dept of Environmental Conservation - w/o encl
r,,!~C? prird~;d on recy(: (:(J paf)~r b v G. [)
'---, STATE OF ALASKA ]
, _ ~'3SION
ALASKA AND GAS CONSERVATION COM'
PERMIT TO DRILL
20 AAC 25.0O5
la. Type of work Drill ~ Redrill ~ 1 lb. Type of well. Exploratory E~ Stratigraphic Test E] Development Oil []
Re-Entry E] Deepen []I Service E] Development Gas [-1 Single zoneE] Multiple Zone
2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool
Union Oil Company of California (UNOCAL) 334' KB feet Swanson RivedHemlock Po(
3. Address 6. Property Designation
P.O. Box 196247, Anchorage, AK 99519 A-028384
4. Location of well at sudace 7. Unit or property name 11. Type Bond (SE~ ~0ACC25.02~)
2300' FNL, 1040' FWL, Sec. 15, T8N, RDW, SM Swanson River Unit United Pacific Ins. Co.
At top of productive interval (11,316') 8. Well number Number
2300' FNL, 3090' FWL, Sec. 15, T8N, RDW, SM SRU 32A-15 U62-9269
At total depth 9. Approximate spud date Amount
2300' FNL, 3167' FWL, Sec. 15, T8N, RDW, SM July 8, 1994 $200,000
12. Distance to nearest 13. Distance to nearest well 14. N umber of acres in property 15. Proposed depth (~ and TVD)
property line
2180' feet 1300 feet 2560 11,550', 11,155' feet
16. To be completed for deviated wells 17. Anticipated Pressure(s,,~
Kickoff depth 5200 feet Maximu'n holeangle 24 Ma~murnsu~c, 2290 psigAttot~ldepth('l'VD) 11,155' pslg
18. Casing program Setting Depth
size Specifications Top Bottom Quantity of cement
Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data)
Driven 22" 30' 15' 15' 45' 45' Driven
18- 5/8" 13- 3/8" 2943' 15' 15' 2958' 2958' 600 sx
10-5/8" 7" 29# N80 BRD LT&C 11945' 14' 14' 11959' 1000 sx& 1000 sx@8467'
6" 5" 18# L80 Butt 1550' 10000' 9704' 11550' 11155' 16 bbls
(window in7"@ 10350')
19. To be completed for Redrill, Re-entry, and Deepen Operations
Present well condition summary
Total depth: measured 11,982' feet Plugs (measured) Abandoned to +__ 10,800'
true vertical 11,529' feet See schematic
Effective depth: measured 10,800' feet Junk (measured) See schematic
true vertical 10,435' feet
Casing Length Size Cemented Measured depth True vertical depth
Structu'al
Conductor 30' 22" D rive n 45' 45'
Surface
Intermediate 2943' 13-3/8" 600 sx 2958' 2958'
?, 00o RECEIVED
Production
11945'
Liner
Perforation depth: measured Abandoned to + 10,800' d U N '1 7 1994
true vertical No perforations Aisska 0il & Gas Cons. Commission
Ahchura~e
20. Attachments Filing fee [~ Property plat ~ BOP Sketch~ Oiverter Sketch ~ Drilling program L~
Drilling fluid program E~ Time ,vs gepth plot ~ Refraction analysis [] Seabed report
21.1 hereby cer~, ~~d correct tothe best of my knowledge
Signed G. RUSSELLSCHMIDT Title DRILLING MANAGER Date 06/08/94
Commission Use Only
Permit Number APl number IApproval date See cover letter
~/z'- ~.'~/Z 50-/.~'..~ - /0//'//-<~/[ "7-~ -- ~c/ for other requirements
Conditions of approval Samples required ~] Yes 'J~ No Mud Icg required [-] Yes [~ No
Hydrogen sulfide measures [-] Yes [~ No Directional survey required ~] Yes [~ No
Required working pressure for BOPE ~ 2M; [-] 3M; ~ 5M; ~ 10M; LJ 15M
Other:
Original Signed By by the order of
Approved by Fl~virl W ;loh_n_~tr~n Commissioner the commission Date
Form 10-401 Rev. 12-1-85
iplicate
Swanson River Well SRU 32A-15
Rough Procedure
May 18, 1994
1. Prepare location, install BPV, move in the drilling rig.
2. Remove the tree, install and test 13-5/8" 5M BOPE.
3. Put the tubing in tension, rig up wireline, run a free
point and cut the tubing as low as possible (assume
10,350').
4. Pull and lay down the tubing.
5. Pick up drill pipe and run a bit and 7" scraper to
10,350'.
6. Run a CBL and casing inspection log. CBL to 9000' and
casing inspection log to surface (est TOC @ 9436').
7. RIH and set a bottom trip whipstock, orient the whipstock
to the north east +/- N45E.
8. Make the starter mill run and two subsequent milling
runs.
9. Drill 6" hole to approximately 11,550'
10. Log the 6" hole section.
11 Run and cement 5" 15# L-80 butt thread liner with a
· , I ,
12o Pick up a bit and 7" casing scraper, clean out to the
liner top at +/- 10,000'.
13o Pick up 2-7/8" drill pipe, a bit and a 5" casing scraper
and clean out inside the 5" casing.
14. Change over to brine.
15. POOH and lay down drill pipe.
16. Run a tapered string 2-7/8" x 2-3/8" gas lift completion·
17o Install BPV, remove BOPE, install tree & test to 5000 psi
18. Install the production lines.
RECEIVED
Oil & I~a~ Cons. Commission
Anchorage
18. Achieve drawdown with gas lift gas and perforate
underbalanced using 1-11/16" strip guns.
19. Rig down and move out.
20. Clean the location and release the well to production.
SRU 432-15
Current Status
KB-' 15'
DV @ 964'
13-3/8' @ 2958' ~
DV @ 8467'
TOC In annulus caic @ 10,710'
7' @ 11,595'
TD @ 11,982'
L
Otis "S" profile at 145'
Camco MM Mandrel at 1806'
Tubing is 2-7/8" 8rd
Tubing perforatecl from 10,418'-426'
Attempted tubing cuts at 10,490', 10,496' and 10,760'
TOC In tbg @ 10,860'
Tublag retainer at 11,010'
Camco MM Mandrel at 11,192"
Camco MM Mandrel at 11,236'
Tubing perfs 11,265'-270'
Brown "CC' safety joint 11,281'
Tubing retainer 11,286'
Brown HS-16-1 Pm=ker at 11,290'
~ ~' profile at 11,358'
Tubing perf~ 11,414'-424'
Camco MM Mandrel at 11,392'
Camco 'D' nipple at 11,436'
Baker Model 'D' packer at 11,447'
Tubing tail at 11,462'
Model "K' B.P. at 11,634'
TOC @ 11,930'
SRU 32A-15
Proposed Hemlock Completion
DV @ 964'
13-3/8"@ 2958'
KB= 15'
2-7/8" 6.4# L-80 Butt tubing
DV @ 8467'
Side pocket GLM's
Liner hanger with liner top packer at 10,000'
7" Window at 10,350'
2-3/8" 4.6# L-80 Butt tubing
5" stab in packer at 11,200'
"X" type profile below the packer
Top Zone of interest at 11,316'
5" 18# Butt casing
RECEIVED
TD at 11,550'
GRB 5-19-94
SWANSON RIVER WELL # 32A-15 REDRILL
Anticipated Pressures for the 6" hole section
/'Mud weight = 9.3 ppg = 0.484 psi/ft
7" window is proposed to be at 10,350'MD, 10,024' TVD
Total Depth of the 6" hole is 11,550' MD, 11,155' TVD
Estimated Fracture gradient at the window = 0.9 psi/ft
Pore Pressure Gradient = 0.464 psi/ft
Gas Gradient (assume worst case) = 0.0 psi/ft
Kick intensity and type:
Assume a 30 bbl gas entry at TD (worst case)
Assume a kick intensity of 1 ppg
Circulate the gas entry out using the drillers method
Assume no gas entering into solution with the mud
3-1/2" drill pipe x 7" casing annulus = 0.0252 bbl/ft
Gas pressure upon entry =
11,550' ((.480 + 1 (.052)) = 6,144 psi
The shoe will not break down as the fracture pressure at
the shoe is 0.9 psi/ft x 10,350' = 9315 psi
Assume the temperature of the gas remains constant thus:
PV = P'V'
P = 6,144 psi V = 30 bbls
By trial and error keeping the BHP constant at 6,144 psi
P' = 2290 psi V' = 80 bbls
As a check calc BHP from the surface:
Surface Pressure + Gas Column + Mud Column = BHP
Gas Column = 80 bbl/0.0252 = 3175'
Mud Column = 11,155' TVD - 3175' = 7890'
Surface Pressure = 2290 psi
3175' * 0 psi/ft = 0 psi
7890' * .484 psi/ft = 3862 psi
6152 psi
RECEIVED
JUi _ 1 T 1994
;,'~;?~ Oi! & Gas Cons. Commission
Anchorag~
The BHP was kept just above the pore pressure meaning P'
and V' were calculated properly.
Maximum Surface Pressure = 2290 psi at 11,155, TVD
SWANSON RIVER WELL SRU 32A-15
MUD TYPE: PHPA Polymer system
Weight: 9.1 - 9.3 ppg
Funnel Viscosity: 40-50 Sec/Qt
Plastic Viscosity: 15-20
Yield Point: 10-15 #/100 cuft
pH: 9.0 - 9.6
API filtrate < 6 cc
REC£iV£D
Gas Cons. Commission
Anchoragr¢
· 242-16
#CFD
211-15
/~01/
11344
2i-15
3.Z //?v "
~,,A ~90 41A-15
$.Z.
3~, ,-10
~, 41-15
8/9
432-15
'Hem
43-15RD =
ltO0~
LEGEND_'
SWANSON RIVER FIELD
PRODUCTION DATA MAP
CUM. PROD. - MBBLS
HEMLOCK ZONES
PRODUCING WELL
BO + BW + MCFD
4,576
(1-$,8,10)
193 + 56 + 3,944
Gas Cons. Commission
A~cho,ag~
Contract Exhibit E
OPTION I
FILL-UP
ANNULAR
BOP
10' 3000 psi
?IPE RAMS
10" ~000 psi
BLIND P~M$
10" 5000 psi
[~ / DRII.IJNG I
~LL ~ s~oo~ ~
LINE ~ ~ooo psi ~ ~ s" ~ooo psi
~~o' 5000 p~~ CHOKE
PIPE ~si ~
RAMS
~ 10" 5000
I
FLOW,
RECE[VED
LINE~-~
,Anchorago
BOP STACK
10" 5000 psi
Con[fao[ Exhibi[ E
OPTION 2
FILL-UP
NILL
LINE
\.
FLOW
ANNULAR
BOP
13%"3000 pm :
PIPE RAMS
135/s"5000 psi
BLIND RAMS
13%"5000 psi
[~ ~ DRII.I.ING ~
5000 psi ii II 3" 5000
'
I
13%"5000 psi
[
CHOKE
psi
LINE
BOP STACK
13~s" 5000 psi
Items A & B are remote actuated chokes. Ail items are rated to 10,000 psi
GRACE. ~i54
i
Active MUd System
---209' - .............
72 BI]I,
.8111]I,/IN(;II
-.a ~ VOI, UME I::'IT
........ ~ 4.37 BBI,
c.~':-':',
...,~, ~----~.,~ 5.0BBL/INCII
SIICTI()N I',!'1'
,,
2.31111i,/IN(:ii
312'
;' "'"' I'1"1"
I)I,SII.,I I.,I~
140 IIBI.,
1.6IIB/INCll
s,~' 152 BBI,
.[ 5.o~/~NC~
55:
SANI)
'-,,,
.
' rI,RAl)
109' -,--I- 136'
TOTAl. I.JSAIII,E VOLIJME - 1001
II111, - 11.7 IIIII,/INCI!
UNOCAL
Structure : 32A-15 Well : 4,32-15
Field : Swanson River Unit Location : Kenai, Alaska
~o -I
1500_
-
_
-
1
.
'-I,
~osoo_i
1000_~
1500_j
2000 I
0 ~ I000 1500
: ~.oo E a st - - >
1700 175~ 1800 1850 19043 1950 2000 2050 2100 2150 2200 2250
I I I I I I I I I I I I I I I I I I I I I I 150
100
/x
I
o Z
RECEIVED
UNOCAL
32A-15
432-15
slot #32A-15
Swanson River Unit
Kenai, ALaska
PROPOSAL LISTING
by
Baker Hughes INTEQ
Your..ref : 32A-15 Rd Version #1
Our ref : prop858
License :
Date printed : 17-Nay-94
Date created : 5-Aug-93
Last-revised : 17-Hay-~
FieLd is centred on 0.000,0.000,0.00000,+
Structure is centred on 0.000,0.000,0.00000,+
SLot Location is n53 58 39.152,u152 19 2~.267
Slot-Grid coordinates are # 0.000, E 0.000
SLot Local coordinates are 0.00 N 0.00 E
Reference North is True-North
RECEIVED
Ancho;,agc,
UNOCAL
32A-15,432-15
Swanson River Unit,Kenai, Alaska
Measured IncLin. Azimuth True Vert. R E
Depth Degrees Degrees Depth C 0
10350.00 23.39 102.81 10024.73
10400.00 22.31 100.12 10070.81
10500.00 20.31 93.95 10163.98
10555.18 19.32 90.05 10215.89
11000.00 19.32 90.05 10635.66
11316.13 19.32 90.05 10934.00
11449.65 19.32 90.05 11060.00
11500.00 19.32 90.05 11107.51
11550.00 19.32 90.05 11154.70
PRC~OSAL LISTING Page 1
Your ref : 32A-15 Rd Version #1
Last revised : 17-May-94'
C T A N G U L A R Dogleg Vert
0 R D I N A T E S Deg/lOOFt Sect
9.30 N 1724.55 E 0.00 1724.55 KOP
5.43 N 1743.57 E 3.00 1743.57
0.90 N 1779.59 E 3.00 1779.59
0.23 N 1798.27 E 3.00 1798.27 EOC
0.10 N 1945.42 E 0.00 1945.42
0.00 N 2050.00 E 0.00 2050.00 TARGET
0.04 S 2094.17 E 0.00 2094.17
0.06 S 2110.82 E 0.00 2110.82
0.07 S 2127.36 E 0.00 2127.36 TD
ALL data is in feet unless otherwise stated
Coordinates from slot #32A-15 and TVO from wellhead (334.00 Ft above mean sea level).
Vertical section is from wetthead on azimuth 90.00 degrees.
Declination is O.OOdegrees, Convergence is 0.00 degrees.
Calculation uses the minimum curvature method.
Presented by Baker Hughes INTEQ
uN~L
River unit,Kenai,
ALaska
MD TVO Rectangular coords.
10350.00 10024.T5 9.30 N 1724.55 E
10555.18 10215.S9 0.25 N 179827 E
11516.13 1093Y,.00 0.00 N 2050.00 E
11550.00 11154.70 0.07 S 2127.36 E
Target name
32A-15
Position
not sp~ified
PROI~SAL LISTING page 2
Your ref : ~2A-15 Rd Version #1
Last revised : 17-May-94
Ccmne~ts in weklpath
Comnent
KOP
EOC
TARGET
TO
Targets associated with this wellpath
....... T.V.I). L~a[ r~ukar coor~s- Date revis~
............... ...... o,o.oo
.'ECEiVED
ALL data is in feet unless otherwise stated
coordinates from slot #'52A-15 and TVO from wellhead (~4.00 Ft above ~an sea level)-
Bottom hole distance is 2127.36 on azimuth 90.00 degrees from welkhead-
Total Oogleg for we[lpath is 6.16 degrees.
90.00 degrees-
.... - 0 cie r~, Convergence.is O. tees.
Verti section is from wellhead ~q azimuth
ecllnat~un ls.O.O _g.~..ieimt~acurvature
D CaLcuLatlonuses ~.; ....
Presented bY Baker Hughes INTEG
Unocal Energy Resource~-l~ivision
Unocal Corporation /
909 West 9th Avenue, RO. b,.x 196247
Anchorage, Alaska 99519~6247
Telephone (907) 276-7600
Facsimile 263-7698
UNOCAL
June 15, 1994
Kevin A. Tabler
Land Manager
Alaska
Mr. David W. Johnston
Chairman
Alaska Oil and Gas
Conservation Commission
3001 Porcupine Dr.
Anchorage, AK 99501-3192
SRU 32A-15 Application for
Permit to Drill
Dear Mr. Johnston'
Enclosed please find, in triplicate, Union Oil Company of California's application for Permit
to Drill for Swanson River Unit Well No. 32A-15. We also enclose a check in the amount
of $100.00 to cover the application fee.
We note that the proposed location of this redrill is in a quarter section which currently
has three abandoned wells; therefore the spacing acreage as governed by Conservation
Order No. 123 is not affected by our proposed redrill.
Please contact Mr. George Buck at 263-7865 upon your approval or if you have any
questions.
Very truly yours,
Elizabeth A.R. Shepherd
Project Landman
ECEIVED
..~,~..-;itu ~¢~i & (]as C0rls. 0Orllfllissic,
Anchorage ,
1 Status of Well
OIL E~ GAS E~
2 Name of Operator
ARCO Alaska, Inc
SUSPENDED ~ ~'~t.' ABANDONED
3 Address
P.O. Box 100360, Anchorage, AK 99510-O360
4 Location of well at surface
2300' FNL, 1040' FWL, SEC 15, T8N, Rgw, SM
At Top Producing Interval
2410' FNL, 2107' FEL, SEC 15, T8N, Rgw, SM
At Total Depth
2472' FNL, lg05' FEL, SEC 15, TSN, Rgw, SM
5 Elevation in feet (indicate KB, DF, etc.)
334' KB
12 Date Spudded
17 Total Depth (MD+TVD)
11,982' MD, 11,529' TVD
22 Type Electric or Other Logs Run
SERVICE
'.~_ STATE OF ALASKA !' .~_
'SKA OIL AND GAS CONSERVATION COt' SSION
WELL COMI"LETION OR RECOMPLETION REPORT AND LOG ~_____../~ .-~
Classification of Se~ice Well
mi er
SA(10-403) 91-299 5
8 APl Number
50-133-10141-00
g Unit or Lease Name
SWANSON RIVER UNIT
10 Well Number
SRU 432-15
1 Field and Pod
SWANSON RIVER FIELD
6 Lease Designation and Serial No. HEMLOCK OIL POOL
A-028384
13 Date T.D. Reached 11'4Date Comp.,__ Susp. or Aband.m I 15 Water Depth, ii offshore¢ 16 No. of Completiol
11/08/91. NA feet MSLI
18 Plug Back Depth (MD+TVD) lg Directional Survey 20 Depth where SSSV set 21 Thickness of permafrost
10,860'MD,10,489'TVD YES bJ NO xL~J NA feet MD NA
23
CASING SIZE WT. PER FT.
22II
13-3/8"
7"
I SETTING DEPTH MD
GRADE TOP BOTTOM
I SURF 30'
SURF 2958'
SURF 11,959'
24 Pedoratio~s open to Production (MD+TVD of Top and Bottom and
interval, size and number)
Tbg pert'ed f/10,418'-10,428' MD
10,081 '-10,090' TVD
CASING, LINER AND CEMENTING RECORD
HOLE SIZE CEMENTING RECORD AMOUNT PULLED
25 TUBING RECORD
SIZE DEPTH SET (MD) PACKER SET (MD)
26 ACID, FRACTURE, CEMENT SQUEEZE, ETC
DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED
Date First Production
Date of Test Hours Tested
Casing Pressure
Flow Tubing
Press.
PRODUCTION TEST
IMethod of Operation (Flowing, gas lift, etc.)
IPRODUCTION FOR OIL-BBL GAS-MCF
TEST PERIOD ~
CALCULATED OIL-BBL GAS-MCF
24-HOUR RATE
WATER-BBL CHOKE SIZE GAS-OIL RATIO
WATER-BBL OILGRAVITY-API (corr)
28 CORE DATA
Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips.
RECEIVED
MAR 16 1992
Alaska 0il & Gas Cons. Commission
Anchorage
Form 10-407
Rev. 7-1-80
CONTINUED ON REVERSE SIDE
Submit in duplicate
.... ~-"-- 30. t.~ "-'I
GEOLCGIC M.N:iKER~ FORM~I, ~ON TESTS
NAME Include interval tested, pressure data, all fluids recoverd and gravity,
MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase.
.
,.
31. LIST OF ATTACHMENTS
REPORT OF DAILY OPERATIONS
32. I hereby certify that the foregoing is true and correct to the best of my knowledge
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.
Item 1' Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt
water disposal, water supply for injection, observation, injection for in-situ combustion.
Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements
given in other spaces on this form and in any attachments.
Item 16 and 24: if this well is completed for separate production from more than one interval (multiple
completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported
in item 27. Submit a separate form for each additional interval to be separately produced, showing the
data pertinent.to such interval.
·
Item 21' :.ln. dicate_whether from ground level (GL) or other elevation (DF, KB, etc.).
Item 23: Attached Supplemental records for this well should show the details of any multiple stage cement-
ing and the location of the cementing tool.
Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In-
jection, Gas Injection, Shut-in, Other-explain.
SRU 432-15
Lease
10/24/91
(P & A SUMMARY OF OPERATIONS)
Designation/Serial No. A-028384
·
. o,
0700-1900 hrs -
Move bed truck, vac truck & fork lift f/ Veco Kenal to SR field. Move & spot
600 bbl horz tank, fill w/ lease H20, move in choke manifold. Hook up
connections to rig up & prep for CTU clean out. Secure well & shut down until
10/25/91
0700-1930 hrs
MIRU Arctic Recoil, MIRU Baker tank-test Arctic Recoil BOP & lines to 2100
psi, RIH w/2" OD jet nozzle on GLM, by pass tool on 1-1/2" coil tbg, tag fill @
l l,424'-wash down slowly to 11,447'-wash @ 11,447', unable to make
hole,POH w/ coil tbg, secure well shut down until a.m.
10/26/01
0700-1900 hrs
Warm up equip, RU Arctic Recoil, RIH w/1-3/4" OD noz on GLM bypass tool &
1-1/2" coil tbg, circ @ 1/2 BPM while running in, tag @ 11,447', increase
pump rate to 1-1/2 BPM @ 4000 psi, unable to make hole. RD Arctic Recoil &
freeze P, well file shows Camco CDW regulator run & landed in D nipple @
11,436', but does not show it was ever pulled.
RU Precision WL, RIH w/ 2-1/4" JDC pulling tool, attempt to latch CA latch on
CDW reg, set jars off one time & came loose, POH, did not have CDW reg-rerun
pulling tool & beat down on "CA" latch-unable to latch, POH, pulling tool
packed w/ asphaltines, Rill w/2' 1B-jar down one time @ 11,458' WLM, POH,
had good impress of "CA" latch, secure well, shut down until a.m.
10/27/91.
0800-0300 hrs
RU, RIH w/2-1/4' hydrostatic bailer to 11,406' WLM, drove bailer to 11,425',
POH, recovered small amount asphalt, RIH w/ same bailer to 11,425', drive to
11,248' WLM, POH, recovered small amount asphaltine, RIH w/ 2-1/4" S.B.
pulling tool to 11,428', could go no deeper, POH, RIH w/ 1-3/4" drive down
bailer, drive f/11,428' to 11,431', POH, recovered small amount asphaltines,
RD & secure well.
RECEIVED
Alaska Oil & Gas Cons. ~mmission
Ancbora~e
SRU (4)32-1!t7-? &
Summary
A) PAGE 2
of Operations
10/28/91
0700-1200 hrs
RU Arctic Recoil, RIH w/ 2" OD wash noz on GLM bypass tool c/o fill f/11,404'
to 11,436'(orlg tbg mea. to Camco "D" nipple), circ btms up, POH, circ @ 1-1/2
BPM while pulling out, RD Arctic Recoil, RU Atlas WL , make up 2-3/16 OD
Baker cmt retainer on Baker setting tool, R/H-correlate wireline to orgi'tbg
mea & set cmt retainer w/top @ 11,429', POH, make up & R/H w/ 2-1/8" OD x
10' x 4 spf solid carrier tbg gun-corr to orig tbg & perf 40 holes f/11,414'-
11,424', POH, all shots fired, POH, make up 2-3/16 OD Baker cmt retainer on
Baker WL setting tool, R/H, corr to tbg mea @ set retainer in pup it. above top
pkr w/ top of cmt retainer @11,286'-POH & secure well-RD Atlas shut, shut
oper down until a.m.
10/29/91
0700-1330 hrs
RU Arctic Recoil, RIH w/ stab in tool for Baker retainer-rig up Haliburton
cmtrs., stab into retainer @ 11,286', PO retainer, circ-stab into retainer, break
formation down w/ 10 bbls lease H20 @ 1 BPM rate @ 4600 psi. batch mix 21
bbls clas~ G emt w/.20% CFR-3 +.35% Halad 344 +.25% HR-5 mi:red to 18.9
ppg, p.mp 20 bbls down 1-1/2" coil tbg, leave I bbl in mixer, disp w/22-1/2
bbls lease H20-flnal displacement 4800 psi @ I BPM, ISIP 2400 psi-PO
retainer ,pump 3 bbls w/ Haliburton, switch to C-GXj pump & dirc while pulling
out of hole, CIP @ 11:30 a.m. 10-29-91.
1330-2030 hrs
RU Arias WL, RIH w/2-1/8" carrier loaded w/ 5' x 4 spf perf gun, perf tbg from
11,265'-11,270', POH & standby-circ w/ CTU pump down 2-7/8" tbg & out 7"
ann-displace 100 bbls crude & gas-circ 341 bbls until returns were clean,
make up Baker 2-3/16" OD cmt retainer on Atlas WL, R/H & set w/top @
11,010', POH, secure well & RD, shut oper down until a.m.
10/30/91
1300-1900 hfs
RIH w/ Baker stab in tool for cmt retainer-stab into retainer @ l l,010',break
circ thru ret w/ 10 bbls @ 1-1/2 BPM @ 4000 psi-batch mix 19 bbls class G
cmt w/.20% CFR-3 +.35% Halad 344 +.25% HR-5, p.mp 17-1/2 bbls + leave 1-
1/2 bbls in mixer, displace w/20-1/2 bbls H20 thru retainer, out per/s into T'
Cs/i, PO retainer & leave 2 bbls cmt on top of retainer-Calc TOC ixt 7" X 2-7/8'
ann is 10,787', Cale Toe in 2-7/8" i, 10,710'(cire out 1-1/2~,,~~.~~
f/10,710')CIP @ 10:30 a.m., POH, RD Arctic Coil tbg, haul excess--.~ .~---.--~ D
pit, move all equip to SRU 14-15
Alaska Oil & (~as Cons. CommJssjot~
Anchorage
SRU (4)32-15/~l-'
I & A) PAGE 3
Summary of Operations
11/03/91
0800-2400 hrs
MIRU Atlas. RIH w/2-7/8" tbg jet cutter, tag plug @ 10,860' WLM, pull up to
10,760', attempt to cut tbg, mlsrun, POH, MU new cutter. RIH. tag ceramic
ring f/previous cutter run @ 1300', POH, RIH w/junk basket & push junk to
btm @ I0,860'. POH, RIH w/tbg cutter to 10.760', cutter shot but no pressure
indication, POH. press to 2,000# on tbg0 zero on csg-tbg annulus(possible cmt
or tbg not cut, RIH w/cutter & cut @ 10,498', again no press response on
backside, POH, test tbg to 2000#, zero on csg-tbg annulus, rig down Atlas &
move to SRU 14-15 f/perf & retainer set this a.m., will return to recur.
11/04/91
1200-1600 hrs
MIRU, pump 7"x 2-7/8" ann to 1000 psi, tbg zero press, equalized very slowly
after 3 hrs to 850 psi on annulus on tbg, bled press off tbg slow lead. probably
in GLM. RIH w/2-1/4" OD jet cutter, position @ 10, 495'(300' + above calc top
of cmt in annulus cutter fired, 650 psi in ann, zero in tbg, no. press response
on either side, POH & RD
11/07/91
0900-1330 hrs
RU Atlas WL, RIH. RIH w/2-1/8" OD tbg perf. gun to 10,470'-gun stopped,
obtain pick up @ 10,470'-perf tbg w/ 40 holes f/10.418'-10,428', POH. all
shots fired, RD Arias, RU ARCO triplex pump, press down ann to 1000 psi
w/zero psi on tbg, press bled off to 150 psi, tbg press tracked ann press, RD
triplex & secure well.
11/07/01
0900-1300 hfs
Move Hallburton in & RU-disp well w/ 9.7 pg brine thru perf @ 10,418' to
10,428', RD Haliburton & move off
RU ARCO triplex pump, freeze protect well by p.mptng 2 bbls diesel down tbg,
then U-tbging to _~nn, protected to 50+
Signature ~~c~-~ ff~-
Drilling Superlnt~(nt ~3
Date D~/~ ~-~ r~
~~EI V EL~
MAR ] 6 1992
Alaska Oil & (las Cons. Commission
Anchorage
STATE OF ALASKA /%',, ~-: ~,'/ -d~~
' "¢ '
APPLICATION FOR SUN FIY APPRO /ALS
1. Type of Request:
12. Name of Operator
ARCO Alaska. lnG.
3. Address
P. O. Box 100360, Anchorage, AK 99510
Abandon _ Suspend _ Operation Shutdown _ Re-enter suspended well _
Alter casing _ Repair well_ Plugging _ Time extension _ Stimulate '..:.."..- Abandon
Change approved program _ Pull tubing _ Variance _ Perforate Other Hemlock
6. Datum elevation (DF or KB)
4. Location of well at surface
2300' FNL, 1040' FWL, Sec 15, T8N, R9W, SM
At top of productive interval
2410' FNL, 2107' FEL,Sec 15, T8N, R9W, SM
At effective depth
At total depth
2472' FNL, 1905' FEL, Sec 15, T8N, R9W,
5. Type of Well:
Development
Exploratory
Stratigraphic
Service
SM
334' KB
7. Unit or Property name
Swanson River Unit
feet
8. Well number
SRU 432-15
9. Permit numbe?~,,... ~
10. APl number
50-133-10141-00
11. Field/Pool Swanson River Field
Hemlock Oil Pool
11,930' ?,,~e¢.~"~'~,~#
11'634' MODEL "K" B.P. '
12.
Present well condition summary
Total Depth: measured
true vertical
Effective depth: measured
true vertical
1 1,982' feet
11,529' feet
1 1,634' feet
1 1,21 7' feet
Plugs (measured)
Junk (measured)
11,420'-11,444';
11,005'-11,027';
Casing Length Size Cemented
Structural
Conductor 3 0' 2 2" Yes
Surface 2958' 1.3-3/8 '° Yes
Intermediate
Production 11 95 9' 7" Yes
Liner
Perforation depth: measured
11,389'- 11,413';
true vertical
1 0,976'-10,998';
Tubing (size, grade, and measured depth)
2-7/8" 6.5# N-80 EUE 8R RG 2 to 11,462'
Packers and SSSV (type and measured depth)
Brown 'HS-16-1' Pkr @ 11,290'; Baker model "D" @ 11,447'
11,454'- 11,480'
11,036'-11,061'
Measured depth True verti~l depth
3O' 3O'
2958" 2958'
11,959' 11509'
13. Attachments Description summary of proposal _~
Wellbore Schematics, Well History, Area Map
14. Estimated date for commencing operation
OCTOBER 10, 1991
16. If proposal was verbally approved
Name of approver Date approved
Detailed operation program
BOP sketch
15.
Status of well classification as:
Oil Gas
Suspended X
Service
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Signed /,~/ //~~ Title Area Drilling Engineer
FOR COMMISSION USE ONLY
Date
Conditions of approval: Notify Commission so representative may witness
Plug integrity m BOP Test_ Location clearance__
Mechanical Integrity Test_ Subsequent form require
10.,¢cP :7
IApprov~al No.
Approved by the order of the Commission
Form 10-403 Rev 06/15/88
ORIGINAL SIGNED BY
LONNI~ U. SMITH
Commissioner Date /D -'/~ "?/
SUBMIT IN TRIPLICATE
,~ec~ OOgV
SRU 432-15
Brief Well History
SRU 32-15 was drilled and completed in the H4-H5 Sands in October 1959
for 963 BOPD x 156 BWPD. By June 1966 the off rate had dropped to 120
BOPD and this well was converted to a gas injector and was renamed SRU
332-15. A year later inte _rrn_!ttent water injection was tested and by October
1969 this well bec_~_me a full time water injector (SRU 432-15). In July
1973 SRU 432-15 was shut in due to high water production rates in the
SRU 34-10 fault block. Cumulative injection into this well is 9.2 BCF and 4.1
M1VIBW.
As this well has a relatively low cumulative gas injection and high water
injection cumulative, the Hemlock has no future utility. (Note that other
North End injectors, SRU 312-22, SRU 314-27 and SRU 331-27, with
higher gas injection cums have proven unproductive.)
As uphole gas may be present in this well, only the Hemlock is
recommended for abandonment at this time. This abandonment will leave
SRU 432-15 in a safer condition than its current configuration. The
procedure to abandon the Hemlock is identical to that which would be
employed if a full P&A were planned. Thus, no incremental costs will be
incurred through this piecemeal operation.
In 1986 a 2-1/4" gauge was run in this well to 11389' and would go no
further. Asphaltines and scale were recovered. As a result, some work
(xylene/scratcher treatment and/or a tubing perforations) may be required
prior to the cement work to assure successful isolation of the 'Hemlock.
RECEIYEI)
,
SR, U .432-15_ I
General .P&A,.Prgcedur~ fo_r_ 'H~mloc_k Zone
1. RU slickline, R!H with gauge ring [o confirm PBTD of 1t,634' +/-,": :"
2, RIH w/wireline and set retainer @
3. RIH w/CTU and sque¢~ cemen.*,(80 cu.ft.) into the £ormation through end of the tubing. POH w/ CTU.
4, RIlE w/wiretine nnd set retainer @ I1,290',
5. RIH w/CTU and squeeze cement(50 cu.ft.) into the formation through open mandrels. Leave I0 cu.ft.
~low the retainer in tubing, POH w/ Gl'U,
6, RIll w/wireline and perforate tubing @ 1I,~5'+/-. Set retainer @ 11,000',
7. RIH w/CTU and squeeze cement(50 ca.ft.) imo the ¢~i~.g x tubing annulus through the perforations.
Leave 10 cu.ft, in tubing above t.he retainer. POll w/ CTU,
8. I~.IH w/wireline and tag cement. RIH w/ tubing cutter and cut tubing @ 10,000', POH w/wiretine.
1LD.
9, Clean and clem location leaving [he well for future operations in upper zones.
R EEIV D
OCT u ~ 1991
A/aska Oil & 6as Cons. ~
Anchorag~ '
319'_
145.08'
~- DV ~ 964'
-- 1,806.23
2958 '
DV ~ 8467'
TUD1~;¢ H;J;GER an,~l FUP JT.
3 JTS. + Pb'P JT. 2~" Eb]~ TUBR;O
OTIS "S" NIPPLE, Position #2
53 JTS. 2~"-EUE 8rd TUBING
5.92'
120.21 '
1.59'
1659.56'
~'- C;J~CO ~24 ~M~IDEEL
12.92'
301 JTS. 2%" EUE 8rd TUB]31d
9372.93 '
ii
iJ i -
CASING a TUBING DETAIL
SECTION 1.5 T. 8 N~R.9 W,
ii · i
SRU 432- 15
Anchorage
---11,192.08' --f__ CA~3;O }=.[ ~MJ;DREL ..... ' 12.98'
,...z .,,, __] I ~. 2~" E~ 8~ TUBinG 31.51'
~,l~o,~/- ~ C~'E0 ~.~ I.~-D~L . ' ... ' 13,~'
-- --11,281.19'-- ~ I ~. 2~" ~ 8rd TUB~G 31.~~
- ~ BRU~ "CC" ~TY ~. 1.03 '
--11,2~.27, ~ ~ 2%,. x 7, ?~-1~1 PA~R 5.9?'
- ~ ~- ~1,3~.o6'
-~l~, · ~~R ~EL "D" PAC~, =~ SUB &
~: '1 I : /
.~ ~ ~-- 1.1.4~.oz'
~1 ~ILiIQ' ' II '
~- -~o ,,-~' .?f' . .
'-~--~,9~' TOP of PLUG
~ '~" ~ 0 CT - 2
I !~ Alaska 0ii & Gas Cons CommiSs~ea
: .
·
~o~,'i ~
?926
9781'
145.08'
1,806.23' --
2958 '
!
DV ~ 8467'
·
3 JTS. + Pb'P JT. 2~" EUE TUBR;0
~fIS "S" NIP~LE, Position #2
53 JTS. 2~" EUE 8rd TUBING
301 JTS. 2~" EU~ 8rd TUBING
~'- C~CO ~2{ ~LANDEEL
o.
I JT. 2~.. EUE 8rd TUBING
CAJ.~O ~..~ I-i~J~)REL ...
1 ~. 2~" ~ 8rd TUB~G
BR~{ ~CC" ~TY ~.
~P ~. 2~" E~ 8~ T~D;G
~I 2¥' x 7" ;:S-1~1 PA~R
--11,192.08' '~ -- CA~O )~'~ ~J;DREL . .
--- 11,236.57' .
11,281.19t
11,290.27'
2 JTS. 2~" EU~ 8rd TUBLNG
11,338.97' OTIB "S" NIPPLE~ Position #1
,,3.,' I JT. 25" EUE 8rd TUB~EG
,~.,1.,.. 1,392.06'
'"~' 1 JT. 2~," EUE 8rd TUBR~G
~ 11,436.5~' CA~3;O "D" NIPPLE
,,,~. PUP JT. 25~" EUE 8rd TUB]2~G
--~ 11,447.00' RAKER ~DDEL "D" PACkY_J~, LOCA~C~ SUB &
,,,~' SFAH ASSE].~LY w/ STOP SUB.
,462.02' PRODUCTION TUBE v/ ROI]P.o END to 1~"
11,o34' ~ZDEL 'X" B.P.
--11,930' TOPof PLUG RECEIVED
5.92'
120.21,
1.59'
1659.56'
12.92 '
9372.93 '
12.98'
31.51'
13.00'
31.62;
1.03 '
8.05 '
5.97'
62.73 '
1.58 '
31.51'
12.82'
31.72'
.93'
7.94'
11.79'
4.77'
11,~' TD
~/aska Oil & Gas Cons. Commissien
SRU 432- 15
CASING & TUBING DETAIL
SECTION 15 T, 8 N~R, 9 W,
· !
t,.,,.,,.J
I
I
I
I
I
I.,----.,..I
I
I
I
I
I
34-'10
·
,q [FAULT ~BL04:IC ~
J
I
I
I
r-J
SWANSON RIVER FIELD
STRUCTURE MAP
HEMLOCK FORMATION
RECEIVED
OCT - 2 199't
Alaska 0ii & (~as Cons. Commisstor~
./~chorage
WELL PERMIT CHECKLIST
WELL NAME
GEOL AREA
ON/OFF SHORE
, ADMINISTRATION
ENGINEERING
1. Permit fee attached ..................
2. Lease number appropriate ...............
3. Unique well name and number ..............
4. Well located in a defined pool .............
5. Well located proper distance from drlg unit boundaz-y..
6. Well located proper distance from other wells .....
' 7. Sufficient acreage available in drilling unit .....
8. If deviated, is wellbore plat included ........
9. Operator only affected party ..............
10. Operator has appropriate bond in force .........
11. Permit can be issued without conservation order ....
12. Permit can be issued without administrative approval..
13. Can permit be approved before 15-day wait .......
GEOLOGY
14. Conductor strin9 provided ................
15. Surface casing protects all known USDWs .........
16. CMT vol adequate to circulate on conductor & surf csg.
17. CMT vol adequate to tie-in long string to surf csg. .
18. CMT will cover all known productive horizons ......
19. easing designs adequate for C, T, B & pe~afrost ....
20. Adequate tankage or reserve pit .............
21. If a re-drill, has a 10-403 for abndnmnt been approved.
22. Adequate wellbore separation proposed ..........
23. If diverter required, is it adequate ..........
24. Drilling fluid program schematic & equip list adequate
25. BOPEs adequate
26. BOPE press rating adequate; test to ~~ ~ psig.~
27. Choke manifold complies w/~I ~-53 (May 84) .......
28. Work will occur without operation shutdo~ .......
29. Is presence of H2S gas probable .............
30. Permit can be issued w/o hydrogen sulfide measures...
31. Data presented on potential overpressure zones ....
32. Seismic analysis 9f shallow gas zones .........
33. Seabed condition survey (if off-shore) ........
34. Contact name/phone for weekly progress reports .
[exploratory only]
GEOLOGY: ENGINEERING: COMMI SS ION:
'-~OW/jo - A:~FORMS~cheklist rev 03/94
z
Well HistorY File
APPENDIX
Information of detailed nature that is not
particularly germane to the Well Permitting Process
but is part of the history file.
To improve the readability of the Well History file and to
simplify finding information, information of this
nature is accumulated at the end of the file under APPENDIX.
No special effort has been made to chronologically
organize this category of information.
RECEIVED
NOV 1 ~. 1994
_Al~ Oil & Gas Cons. Cemml~on
Anchorage -~ -
'~-O(?.T-1994 12:n7
PAGE:
'~-nCm-lg94 JL2 J 0'1
PAGE~
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FILE NUMB NUMB SIZE REPR ESS
qU~B SA)~P EbE~ CODE (HEX)
I I 4 68 8000000000
1 I 2 ~9 B40nuOoO00
1 I 2 49 80ooon()ooo
1 1 2 49 BO000oOO00
I I 2 49 80000¢)000o
I I 2 ~9 8oo0000000
1 1 2 49 80OO00000o
1 I 2 .t9 8000uO0000
1 1 2 ~9 8402040n00
1 i 4 68 820204o0u0
I I 4 68 8200000000
1 I 4 68 8402040000
1 1 4 68 8442000000
1 I 4 68 8~00000400
1 I 4 68 880000o400
1 1 4 68 8242U0()400
1 I 4 bB 8242000400
I I 4 oB ~242000000
1 I 2 ,49 8000020000
1 1 2 79 BOU.0000000
1 I 2 49 8000000000
1 I 2 49 BO00000OO0
1 I 2 49 8000OOOOOO
1 I 2 49 8000000000
1 t 2 49 BO0000oooo
1 I 2 4q 80ooo000On
1 i 2 49 8000000000
I I 2 49 BO0O000oU0
1 1 2 49 8000000000
1 I 2 49 BO0000uO00
I I 2 49 8000000000
1 1 2 49 8000000000
1, I 2 49 8000000000
1 I 2 49 BO00000000
1 1 2 49 8400000000
I 1 2 49 8000000000
I 1 2 49 8000000000
1. 1 2 49 BO00000000
1 1 2 49 BB000000U0
T. lrttg. Ti{I!
L, g. 'v (> !. !
PEW, '),'<.;:;
TNR/~ .'T'~ ii:
2.~51 I.,b.I'DH 245.125 6tl.TOH
't~.250 SSi.rOil 329.000 S$2.TOH
2.3~g DRHO,rOH O,lb8 DPHI,TON
· 1147.23-m Ci.~Tc.iroii 2000.565 TNPH,TOH
472.000
403.000
0.159
0.296
5-0CT-19O4 12:07
0.326 RFOC,TOH
2bn.25n IDPH.TOH
22.g75 TIR~.TOH
270.00o ILD.TDH
4.950 GR.~OH
!56.25n SP.TDH
2..053 bb,'roH
76.2b0 5$1.TOH
2.31~R DP, NL1. I'OH
I 1.47.7.34 CNTC.TOH
0. 326 P~'OC.TOH
200.750 Ir)Ptl.TO~
25.797
~ c'~t. 625 I f,D.'fOtt
4.621
I 5K. 2'.'~(~ SP.TOtl
156 Lb. TOH
.4:~3 $21. 'i'OH
.q~J5 DRI4L),TOH
,~26.B51 C~I'C.TOH
0.Sug RFOC.TOit
32.563 IDPH. FF)H
2q.n00 II.,i).'fOH
5 U '7 GR. 'fOil
0.192
4.945
252.875
4.898
63.938
-20~.500
245.125
329.000
0.168
2g09 565
0 136
4 801
183 000
4 840
63 938
-205 no0
129.o00
100.688
-0.595
1~73.355
0 735
42 063
27 578
44 938
35 094
73 188
IFRE.TOH
IMPH.TOH
IIXM.TOH
Ib~.TOH
HTEN.IOH
LU.T{]H
SS2.TOH
DPHI.TOH
TNPH.TUH
IFRE.TUH-
IMPH,TOH
IIXH.TOH
IbM.TOH
HTE~.TOH
bU.TON
S52.TUH
DPHI.TOH
TNPN.TOH
IFRE.TOH
IMPH.TON
IlXM.TOH
IbM.TON
HTEN.TOH
PAGE::
20
3.727
14.836
3.699
1190.000
472.000
403.000
0.159
0.29b
20
4.977
13.219
5,137
1379.000
253.500
167.500
0.403
0.474
20
30.688
4.914
34.469
1180.000
IS !rape verification ~,lstt.,,~",~ ·
chlum~ eT' I¢'~ 1', 1,;~k.~ ¢'r~-',~.:'.,~tin<l
~-nc'r-1. 994 12:07
PAGE~
15 1 1 4 68 800000000n
15 1 I 2 49 8400000000
15 I I 2 49 8000000000
15 1 i 2 49 8000000000
1. 5 1 I 2 49 8000000000
I 5 1 1 2 49 8000000000
15 I 1 ' 2 49 8000000000
1 5 i I 2 49 8000000n, oO
1,5 I 1 2 49 8402040000
1 b 1 t 4 68 8202040000
15 1 1 4 68 8200000000
1. 5 I 1. 4 68 8402040000
15 1 ! 4 68 B44700()000
I 5 1 I 4 68
5-OCT-19n4 12:07
PAGE:
r'~UP..!3 SA~'P ELEM CODE (HEX)
I i 4 68 8242000400
1 1 4 68 8242000400
1 I q 68 8242000000
1 I 2 49 8000020000
1 1 2 79 8000000000
I 1 2 49 8000000000
1 1 2 49 '8000000000
1 1 2 49 8000000000
i 1 2 49 8000000000
1 1 2 49 8000000000
I 1 2 49 8000000000
1 1 2 49 8000000000
1 1 2 49 8000000000
l 1 2 49 800o000000
1 1 2 49 8000000000
1. 1 2 49 8o000o0oo0
I 1 2 49 80t)0000000
1 1 2 49 6000000000
1 1 2 49 5000000000
I 1 2 49 8400000000
1 i 2 49 800000000n
1 1 2 49 8000000000
1 l 2 49 8000000000
1 i 2 49 88o0000000
bP ,
PEP.
NPliP.
C! i)P.
CSFI,.
v*
P" I,,, l, J'
6.000 I, b. ::.r 0 H 191.875 h U..qO H
,:,6.6~8 SS1 ."fOtt 249.625 SS2.TOH
2.318 DRFIiJ.I'Oit -0,004 DPHI,TOH
,!1~6.186 CN]'C.TOH 4793,530 TNPH.TOF
o. 2,1.5 RFDC,TOH 0.125 IFRE,TOH
13~.250 IUPH,TOH 6.430 IMPH,TOH
Ii.320 IlRuI.TOi! 127,918 iIX~,TOH
135.315 [ l.,t.), rOM 6.336 ILM.TOH
11.108 GR.TOtt 89.313 HTEN.TOH
1.5n.75o 8P.'I'nH -133,500
ii, 004 1., b. T I! it 138.8 75 b ti. T 0 H
5g.250 SS t.i{OH 240.625 552 TOH
~2S9.6/4 CNTC.TOH 4663.152 TUPH.TOH
0.?27 RFOC.TOI{ 0,092 IFRE.TOH
~t, 6.625 [~PH.TOH 9.609
347,000
339.000
0,165
0,242
20
7,496
8.883
7,379
704.500
268,750
316.000
0.052
0.224
20
9,367
~chl,,, erg,~r AI,3$Ka O pllt.~:ln Center
F'E E 1:
t!. l~l'
12:07
6.891 IIRM.TOH
~07.250 IbD.TOH
10.367 GR.TOH
158.75o SP,TOH
7.477 LL,.TOH
69.125 SSX.TOH
~.5o2 DRHO.TOH
17~9.784
0.247 RFOC.TOtt
218.375 IDPH.TOH
21.000
220.250 ILO.TOM
5.~)27 GR,XOH
~2.125 SP.TOH
8.43t~ b [.,. '1'0tt
07.090 SS1.TOIt
2.533 DRHO.TOH
13o2.525 CNTC~TOH
O. 2 19 RIF[1C~TOtt
189.815 IDPH.TOH
25.625
908.250 IL!).TOH
4.902
~ 5g.625 SP.TOH
6.156 bb. IOH
23.266 SS1 .TDH
!. 8 16 DRtlO.TOH
397.0J0 CNTC.TOH
9.494 RFFJC.TOH
3.4'~9 II)PH,TOH
96.250 TIP;~.TOH
16.9~4 ILD.TOH
,). 64g GR. TOH
156.75r~ SP. TOH
144.625
242.750
0 OO6
3889 655
0 172
4 395
206 750
4.367
37.969
-79.000
LU.TOH
SS2.TOH
DPHI.TOH
TNPH.TOH
IFRE.TON
I~PH.TOH
IIXM.TOH
HTE~.TOH
150 000
249 625
012
0 144
5
19~ 75O
5 402
.95 625
92 375
bU.TOH
SS2.TOH
DPHI TOH
TNPH TOH
IFRE TOH
[MPH TOH
IIXM TOH
IbM TOH
HTEN.TOH
]14
81
-0
1480
-2
16
3O
-3
'779
!
2
94
188
LU TI'ltl,
DPHI.TOH
TNPH.TOH
IFRE.TOH
IMPH.TOH
IbM,TON
HTEN.TOH
PAGE:
3
1264;000
266 750
318:750
0,053
0.243
20
4.574
14.375
4 539
1278:000
285.750
325.000
0,071
0.285
20
5,266
14 078
4:797
t430.000
225.000
130.875
0.469
0.481
2O
289.750
-54 875
58i844
1127 000
g-r~(?q'-1994 1.~o7
PA~E~
