Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout200-1301. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Replace Tubing
Development Exploratory
Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number): 8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 11658'feet None feet
true vertical 6542' feet None feet
Effective Depth measured 11450'feet 7989', 10893', 11370'feet
true vertical 6445'feet 4757', 6174', 6406'feet
Perforation depth Measured depth
True Vertical depth
Tubing (size, grade, measured and true vertical depth) 3-1/2"
3-1/2"
L-80
L-80
7982'
10926'
4754'
6190'
Packers and SSSV (type, measured and true vertical depth)7989'
10893'
11370'
4757'
6174'
6406'
12. Stimulation or cement squeeze summary:
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure:
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work: Kuparuk Oil Pool
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date: Contact Name:
Contact Email:
Authorized Title: Contact Phone:
7047' 4297'
Burst Collapse
Liner
11007'
771'
Casing
6245'
6541'
11038'
11656'
7013'
121'Conductor
Surface
Production
20"
9-5/8"
88'
measured
TVD
7"
3-1/2"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
200-130
50-029-22973-00-00
P.O. Box 100360
Anchorage, AK 99510
3. Address:
ConocoPhillips Alaska, Inc.
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
ADL0025650, ADL0025661
Kuparuk River Field/ Kuparuk Oil Pool
KRU 1D-36
Plugs
Junk measured
Length
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
N/A
Gas-Mcf
MDSize
121'
Well Shut-In
324-315
Sr Pet Eng: Sr Pet Geo: Sr Res Eng:
WINJ WAG
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
N/A
Packer: Baker Premium
Packer: ZXP Liner Top
Packer: Weatherford WS-R-BB
SSSV: None
Shane Germann
shane.germann@conocophillips.com
(907) 263-4597Staff RWO/CTD Engineer
11410-11420', 11420-11484'
6426-6430', 6430-6461'
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
Digitally signed by Shane Germann
DN: O=ConocoPhillips, CN=Shane
Germann, E=shane.germann@
conocophillips.com
Reason: I am the author of this document
Location:
Date: 2024.09.04 10:56:14-08'00'
Foxit PDF Editor Version: 13.0.0
By Grace Christianson at 1:05 pm, Sep 04, 2024
Page 1/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
7/16/2024
19:00
7/16/2024
20:00
1.00 MIRU, MOVE MOB P Complete rig maintenance, Cruz trucks
showed up to move rig. Hold PJSM.
7/16/2024
20:00
7/16/2024
21:30
1.50 MIRU, MOVE MOB P Hook up Cruz trucks to pits and pull to
far side of 1D-36 and stage on pad.
remove items away from sub and
prepare for sub move
7/16/2024
21:30
7/16/2024
23:00
1.50 MIRU, MOVE MOB P Pull sub away from middle of pad over
to 1B-16. Set Mats under both ends of
sub and set down.
7/16/2024
23:00
7/17/2024
00:00
1.00 MIRU, MOVE MOB P MIRU pits release trucks at 0000.
7/17/2024
00:00
7/17/2024
03:00
3.00 MIRU, WELCTL RURD P Spot pits and released trucks at 0000.
Complete pre acceptance check list.
Berm in around rig.
Hook up inter connect.
Connect circulating lines in cellar.
Spot in and tie in surface lines to kill
tanks.
Called out vac trucks for seawater at
0030 trucks mobillized to load seawater.
Record RKB measurments for riser.
Accept rig at 0300.
7/17/2024
03:00
7/17/2024
07:00
4.00 MIRU, WELCTL RURD P Blow air to tanks.
Organize location
Finish rigging up cellar
Double tap hardline to kill tanks.
Start bleeding off OA to bleed trailer.
Record initial pressures
T/IA/OA/OOA=300/250/500/50
7/17/2024
07:00
7/17/2024
08:30
1.50 MIRU, WELCTL RURD P Finish taking on fluid in the pits. Build 40
BBL deep clean pill.
7/17/2024
08:30
7/17/2024
09:30
1.00 MIRU, WELCTL RURD P Attempt to swap over to high line.
Encountered issues while swapping
over. blacked out the rig. unable to
operate any drives during the swap.
7/17/2024
09:30
7/17/2024
10:00
0.50 MIRU, WELCTL SFTY P PJSM for killing well.
7/17/2024
10:00
7/17/2024
12:00
2.00 MIRU, WELCTL KLWL P Pump 40 BBL deep clean pill chase with
seawater.
Pumped 213 BBL at 3BPM = 1000 PSI.
7/17/2024
12:00
7/17/2024
12:30
0.50 MIRU, WELCTL OWFF P OWFF Monitor at wellhead.
7/17/2024
12:30
7/17/2024
13:00
0.50 MIRU, WELCTL MPSP P PU T-bar and BPV set BPV. Test BPV to
1000 PSI through the IA for 10 minutes.
7/17/2024
13:00
7/17/2024
13:30
0.50 MIRU, WELCTL RURD P Blow down surface lines RD circulating
lines in the cellar and floor.
7/17/2024
13:30
7/17/2024
21:00
7.50 MIRU, WELCTL NUND P ND tree and adapter. Install test dart in
HP-BPV. Dart sticks up above the flange
13". Dropped out the test spool to get
over the well.
Plan to test 3 1/2" and 5 1/2" Test Jnt,
Test 7" after tubing is removed.
MU test jnts, install riser, Fill stack and
surface lines.
7/17/2024
21:00
7/17/2024
21:45
0.75 MIRU, WHDBOP NUND P Continue to fill lines watching for leaks,
setup testing equipment. prepare for
state witnessed BOPE test.
7/17/2024
21:45
7/17/2024
22:15
0.50 MIRU, WHDBOP BOPE P begin low pressure test on shell, 250psi,
hold. Leak on Kill hose, repair
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 2/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
7/17/2024
22:15
7/18/2024
00:00
1.75 MIRU, WHDBOP BOPE P Start testing BOPE.
Initial BOPE test, Tested BOPE at
250/3000 PSI for 5 Min each, Tested
annular on 3.5" and 5.5" test joint,
UVBR's, w/3.5" and 5.5" test joint. Test
blinds rams. Choke valves #1 to #16,
upper IBOP and lower top drive well
control valves. Test 3 1/2" HT-38 safety
valve, 3.5" FOSV, and IBOP. Test 2" rig
floor Demco kill valves. Test manual and
HCR kill valves & manual and HCR
choke valves. Test hydraulic and
manual choke valves to 1500 PSI and
demonstrate bleed off. Perform
accumulator test. Initial pressure=3100
PSI, after closure=1600 PSI, 200 PSI
attained =19 sec, full recovery attained
= 115 sec. UVBR's= 6 sec, Annular= 21
sec. Simulated blinds= 6 sec. HCR
choke & kill= 1 sec each. 5 back up
nitrogen bottles average = 1970 PSI.
Test gas detectors, PVT and flow show.
Test Witnessed by AOGCC rep Austin
McLeod.
7/18/2024
00:00
7/18/2024
03:45
3.75 MIRU, WHDBOP BOPE P Finish testing BOPE.
Initial BOPE test, Tested BOPE at
250/3000 PSI for 5 Min each, Tested
annular on 3.5" and 5.5" test joint,
UVBR's, w/3.5" and 5.5" test joint. Test
blinds rams. Choke valves #1 to #16,
upper IBOP and lower top drive well
control valves. Test 3 1/2" HT-38 safety
valve, 3.5" FOSV, and IBOP. Test 2" rig
floor Demco kill valves. Test manual and
HCR kill valves & manual and HCR
choke valves. Test hydraulic and
manual choke valves to 1500 PSI and
demonstrate bleed off. Perform
accumulator test. Initial pressure=3100
PSI, after closure=1600 PSI, 200 PSI
attained =19 sec, full recovery attained
= 115 sec. UVBR's= 6 sec, Annular= 21
sec. Simulated blinds= 6 sec. HCR
choke & kill= 1 sec each. 5 back up
nitrogen bottles average = 1970 PSI.
Test gas detectors, PVT and flow show.
Test Witnessed by AOGCC rep Austin
McLeod.
7/18/2024
03:45
7/18/2024
04:30
0.75 COMPZN, RPCOMP RURD P Blow down surface lines, R/D testing
equipment.
BD Test Jnts
Bring T-bar to the floor, RI and pull test
dart/ HP BPV
7/18/2024
04:30
7/18/2024
06:00
1.50 COMPZN, RPCOMP RURD P Install elevators, ready rig floor for
pulling pipe.
7/18/2024
06:00
7/18/2024
07:00
1.00 COMPZN, RPCOMP PULL P Screw landing joint into tubing hanger.
BOLDS and pull hanger to floor.
PUW=85K PU clean.
7,826.9 7,800.0
7/18/2024
07:00
7/18/2024
07:15
0.25 COMPZN, RPCOMP OWFF P OWFF for 15 minutes. 7,800.0 7,800.0
7/18/2024
07:15
7/18/2024
14:30
7.25 COMPZN, RPCOMP PULL P L/D completion F/7826.9' T/1621'
strapping all joints on the way out of the
hole.
7,800.0 1,621.0
7/18/2024
14:30
7/18/2024
15:00
0.50 COMPZN, RPCOMP SFTY P Nabors safety stand down to review L-
48 incidents
1,621.0 1,621.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 3/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
7/18/2024
15:00
7/18/2024
16:00
1.00 COMPZN, RPCOMP PULL P Continue to POOH W/3.5" TBG F/1621'
T/surface
1,621.0 0.0
7/18/2024
16:00
7/18/2024
17:00
1.00 COMPZN, RPCOMP RURD P RD floor RU to test 7" LPR.
Suck out stack, PU/ MU test Jnt
Close LPR
0.0
7/18/2024
17:00
7/18/2024
18:30
1.50 COMPZN, RPCOMP BOPE P Test LPR fixed 7" 250/ 3000psi
Test Annular against 7" test Jnt 250/
3000psi
Witness waived by Austin McLeod
7/18/2024
18:30
7/18/2024
20:45
2.25 COMPZN, RPCOMP RURD P LD 7" test Jnt, RU to test casing taking
returns from the IA valve out to the tiger
tank.
7/18/2024
20:45
7/18/2024
21:30
0.75 COMPZN, RPCOMP PRTS P Begin 30min PT on 5.5" x 7" casing
while holding pressure on 5.5" due to
SOV - Charted
Pressure up through IA, 5 1/2" casing,
to 2000psi block in reading pressure on
recorder
pressure up OA, 5.5" x 7" Ann, to
2700psi, block in (5.5" climbed but did
not track)
7/18/2024
21:30
7/18/2024
22:15
0.75 COMPZN, RPCOMP CIRC P Line up 5.5" to squeeze manifold, dump
pressure to tiger tank and shear SOV.
Leak on low pressure side of squeeze
manifold. Blow down line to tiger tank
with air and repair 1502 gasket.
Report .5 gallon spill outside of
containment.
7/18/2024
22:15
7/19/2024
00:00
1.75 COMPZN, RPCOMP CIRC P Circulate down OA with a 30 Bbls deep
clean pill taking returns through sheared
SOV up 5.5" casing at 2 BPM @
2500psi. Follow pill with 11.7ppg FWP
STS
Gas/ crude observed in returns
340Bbls pumped to return 11.7ppg
7/19/2024
00:00
7/19/2024
01:00
1.00 COMPZN, RPCOMP OWFF P Open 5.5" and 5.5" x 7" to atmosphere
and observe for 30 minutes after flow
stopped.
7/19/2024
01:00
7/19/2024
01:30
0.50 COMPZN, RPCOMP RURD P Blow down lines and RD circulating
equipment.
7/19/2024
01:30
7/19/2024
03:30
2.00 COMPZN, RPCOMP NUND P Blow down kill, pull riser, break bolts on
DSA, kill line and remove turn buckles.
ND BOPS set back on stump.
7/19/2024
03:30
7/19/2024
06:30
3.00 COMPZN, RPCOMP NUND P ND tubing head and attempt to pull pack
off unable to remove pack off with press.
Spear casing and pull casing 125K
PUW casing moving PU till slips clear of
wellhead. removed slips.
Pulled packoff to rig floor and set casing
in slips. Removed pack off at floor.
Set casing down.
7/19/2024
06:30
7/19/2024
08:30
2.00 COMPZN, RPCOMP NUND P NU DSA, test spool and BOP's. Torque
all flanges and install turn buckles and
riser.
7/19/2024
08:30
7/19/2024
09:00
0.50 COMPZN, RPCOMP PRTS P RU to test and pressure test flanges to
1000 PSI for 5 minutes.
22 Strokes Total
7/19/2024
09:00
7/19/2024
09:30
0.50 COMPZN, RPCOMP RURD P RU to pull casing.
7/19/2024
09:30
7/19/2024
10:00
0.50 COMPZN, RPCOMP PULL P Spear casing and pull to floor. LD spear
and 10.15' cut joint.
7,948.0 4,000.0
7/19/2024
10:00
7/19/2024
15:00
5.00 COMPZN, RPCOMP PULL P POOH with 5.5" 15.5# casing F/7948
T/Surface
7,948.0 0.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 4/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
7/19/2024
15:00
7/19/2024
15:30
0.50 COMPZN, RPCOMP RURD P RD floor from pulling casing prep to test
BOPE flange break. Change elevators.
remove GBR casing tongs from floor.
0.0 0.0
7/19/2024
15:30
7/19/2024
16:30
1.00 COMPZN, RPCOMP BOPE P Install lower test plug. Test BOPE
Flange Breaks to full pressure,
250/3000 psi - Test Good
0.0 0.0
7/19/2024
16:30
7/19/2024
18:00
1.50 COMPZN, RPCOMP RURD P Service rig, Pull test plug and install
wear ring in 7" spool. 10.75"OD x 6
3/8"ID x 12" Long
0.0 0.0
7/19/2024
18:00
7/19/2024
21:00
3.00 COMPZN, RPCOMP RURD P MU BHA #3, Cleanout BHA: 6 1/16" x 3
1/2" Packer Mill, Scraper, Boot Baskets
x2, 6 1/8" String Mil, String Magnet x2,
LBS, Jar, 3 ea. DC. l
0.0 0.0
7/19/2024
21:00
7/20/2024
00:00
3.00 COMPZN, RPCOMP PULD P RIH with BHA#3 on 3 1/2" DP on
singles.
0.0 1,921.0
7/20/2024
00:00
7/20/2024
00:30
0.50 COMPZN, RPCOMP SVRG P Hydraulic leak found on iron roughneck,
repair
1,921.0 2,132.0
7/20/2024
00:30
7/20/2024
05:00
4.50 COMPZN, RPCOMP PULD P RIH w/ DP. down to 7050' RKB 2,132.0 7,050.0
7/20/2024
05:00
7/20/2024
06:00
1.00 COMPZN, RPCOMP REAM P MU to head pin, wash and ream down 2
stands
Rot 22RPMs at 8K ft-lbs
pumping 6BPM at 1350psi
7,050.0 7,250.0
7/20/2024
06:00
7/20/2024
07:00
1.00 COMPZN, RPCOMP PULD P Continue to RIH on singles 3 1/2" DP
down to 7963' RKB PUW=175K
SOW=75K
Jet inside PBR at 8 BPM Rot at 80 RPM
7,250.0 7,963.0
7/20/2024
07:00
7/20/2024
08:30
1.50 COMPZN, RPCOMP CIRC P Circulate out 11.7# W/ seawater
PR=8 BPM at 1900 PSI.
7,963.0 7,963.0
7/20/2024
08:30
7/20/2024
09:00
0.50 COMPZN, RPCOMP OWFF P OWFF for 30 minutes 7,963.0 7,963.0
7/20/2024
09:00
7/20/2024
09:15
0.25 COMPZN, RPCOMP TRIP P POOH 1 stand F/7964 T/7869 PUW
erratic and weight swings to 200K
7,864.0 7,869.0
7/20/2024
09:15
7/20/2024
10:00
0.75 COMPZN, RPCOMP CIRC P Circulate SxS clean up the hole
PR=8BPM at 1800 PSI. Reciprocate DP.
7,869.0 7,869.0
7/20/2024
10:00
7/20/2024
12:30
2.50 COMPZN, RPCOMP TRIP P TOOH F/7869' T/171.6' PUW= 175K
SOW=70K
7,869.0 171.6
7/20/2024
12:30
7/20/2024
13:30
1.00 COMPZN, RPCOMP BHAH P LD BHA rack back collars 171.6 0.0
7/20/2024
13:30
7/20/2024
14:30
1.00 COMPZN, RPCOMP ELNE P PJSM with E-Line RU E-line
Hoist CBL in 7" casing F/7200' to
surface.
0.0 0.0
7/20/2024
14:30
7/20/2024
20:15
5.75 COMPZN, RPCOMP ELOG P Run CBL log on E-line down to 7200'
ELMD to surface.
Due to deviation, tool centralizers
collapsed at 2000'. By manipulation, log
cleaned up, continue logging pass
down.
Good data. Note: Review log with on
call engineer
0.0 0.0
7/20/2024
20:15
7/20/2024
21:15
1.00 COMPZN, RPCOMP ELOG P RD AK E-line, RU floor to TIH w/ G-Lock
Plug
0.0 0.0
7/20/2024
21:15
7/20/2024
21:45
0.50 COMPZN, RPCOMP SFTY P Hold PJSM for picking up BHA #4, RBP,
7" G-Lock
0.0 0.0
7/20/2024
21:45
7/20/2024
22:15
0.50 COMPZN, RPCOMP RURD P PU BHA #4, RBP 0.0 0.0
7/20/2024
22:15
7/21/2024
00:00
1.75 COMPZN, RPCOMP TRIP P TIH w/ BHA #4, To Mid night depth 5600' 0.0 5,600.0
7/21/2024
00:00
7/21/2024
01:30
1.50 COMPZN, RPCOMP TRIP P Cont RIH w/G-Lock to a set depth of
7100' RKB
5,600.0 7,100.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 5/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
7/21/2024
01:30
7/21/2024
01:45
0.25 COMPZN, RPCOMP MPSP P Set G-plug @ 7100' RKB.
PUW = 150K, SOW = 70K, Rot 7 ft-lbs
Free
Pull 10K over, set down 10K. 3.5 LH
wraps, P/U free
7,100.0 7,100.0
7/21/2024
01:45
7/21/2024
02:15
0.50 COMPZN, RPCOMP RURD P Lay down 1 stand, RU to test plug.
MU sub to DP, close VBR's. RU test
chart to IA valve.
7,100.0 7,117.3
7/21/2024
02:15
7/21/2024
02:30
0.25 COMPZN, RPCOMP PRTS P Test plug to 1000psi f/ 15minutes - 17
strokes
Test good, bleed down and open VBR's
7,117.3 7,117.3
7/21/2024
02:30
7/21/2024
03:00
0.50 COMPZN, RPCOMP RURD P RU floor to dump sand - R/D test sub,
R/U sandhopper w/ fill line, R/U trash
pump to IA
7,117.3 7,117.3
7/21/2024
03:00
7/21/2024
06:00
3.00 COMPZN, RPCOMP CIRC P Dump 20 sacks of sand - 15 minutes per 7,117.3 7,117.3
7/21/2024
06:00
7/21/2024
08:30
2.50 COMPZN, RPCOMP TRIP P TOOH W/DP F7117.3' T/55.32 7,117.3 55.3
7/21/2024
08:30
7/21/2024
09:00
0.50 COMPZN, RPCOMP BHAH P LD BHA #4 MU BHA#5 MSC 55.3 36.9
7/21/2024
09:00
7/21/2024
09:30
0.50 COMPZN, RPCOMP TRIP P TIH F/36.91 T/190' 36.9 190.0
7/21/2024
09:30
7/21/2024
10:30
1.00 COMPZN, RPCOMP TRIP T Lost all power to SCR's Diagnosed and
repaired
190.0 190.0
7/21/2024
10:30
7/21/2024
11:30
1.00 COMPZN, RPCOMP TRIP P TIH F/190' T/590' 590.0 590.0
7/21/2024
11:30
7/21/2024
12:30
1.00 COMPZN, RPCOMP SVRG P Service HPU system. 590.0 590.0
7/21/2024
12:30
7/21/2024
14:00
1.50 COMPZN, RPCOMP TRIP P TIH F/590' T/6852' 590.0 6,852.0
7/21/2024
14:00
7/21/2024
15:00
1.00 COMPZN, RPCOMP CIRC P Circulate 7" casing to 9.8# NaCl PR=5
BPM at 1175 PSI.
RU OA to tiger tank.
6,852.0 6,852.0
7/21/2024
15:00
7/21/2024
15:30
0.50 COMPZN, RPCOMP SFTY P Safety meeting to review operations for
cutting and circulating 7" x 9-5/8"
casing.
6,852.0 6,852.0
7/21/2024
15:30
7/21/2024
16:00
0.50 COMPZN, RPCOMP CUTP P Locate to cut casing
PUW= 155K SOW=70K
RIH locate collar at 6889.4' PUH T/6870'
Rot at 100 RPM Torque = 8K-8.2K
6BPM = 1300 PSI
6,889.4 6,870.0
7/21/2024
16:00
7/21/2024
16:15
0.25 COMPZN, RPCOMP RURD P RU to circ 140* seawater down 7" up 9-
5/8" to kill tanks.
6,870.0 6,870.0
7/21/2024
16:15
7/21/2024
18:15
2.00 COMPZN, RPCOMP CIRC P 6BPM at 1500 PSI
Pump 40 BBL's Deep clean pill. - no
flow observed out OOA
close annular and attempt circulation to
1500psi. no loss
Open Annular
Circ 8.6 around up backside and
attempt cut again.
Circ 80 SPM @ 1150psi, shut down rot,
set weight down on slips
attempt circ up OOA with ann closed -
1500psi, LO 50psi
6,870.0 6,870.0
7/21/2024
18:15
7/21/2024
18:45
0.50 COMPZN, RPCOMP TRIP T RU floor and TOOH w/ MSC and
inspect.
6,870.0 6,806.0
7/21/2024
18:45
7/21/2024
20:00
1.25 COMPZN, RPCOMP CIRC T Stop tripping due to U tube up DP, MU
headpin and circulate SxS w/ 8.6ppg.
6,806.0 6,806.0
7/21/2024
20:00
7/21/2024
22:30
2.50 COMPZN, RPCOMP TRIP T TOOH w/ MSC, BHA #5 6,806.0 0.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 6/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
7/21/2024
22:30
7/21/2024
23:15
0.75 COMPZN, RPCOMP RURD T RD MSC, take pictures of the knives, all
indications on knives shows cut was
successful
MU FMC PO pulling tool, MU BHA#6, 7"
Casing grapple and PO.
0.0 0.0
7/21/2024
23:15
7/22/2024
00:00
0.75 COMPZN, RPCOMP RURD T Pull wear ring, BOLDs, 0.0
7/22/2024
00:00
7/22/2024
01:00
1.00 COMPZN, RPCOMP FISH T Pull Pack off to Floor L/D same M/U
BHA #6
27.0 25.0
7/22/2024
01:00
7/22/2024
02:00
1.00 COMPZN, RPCOMP FISH T RIH latch up @ 27' Pick up t/ 315K
Hanger move up Hole 30" set bock
down Attempt to Circ No go Bleed off all
pres release Spear POOH L/D same.
25.0 0.0
7/22/2024
02:00
7/22/2024
03:00
1.00 COMPZN, RPCOMP TRIP T M/U BHA#7 - Baker cutter
RIH and locate collar @ 2642' ELMD
0.0 0.0
7/22/2024
03:00
7/22/2024
03:15
0.25 COMPZN, RPCOMP CPBO T Locate to cut casing
PUW= 68K SOW=60K
RIH locate collar at 2639' RKB PUH
T/2637' RKB
Rot at 100 RPM Torque = 8K-8.2K
5 BPM = 920PSI, drop pressure to 408
after cut.
2,639.0 2,637.0
7/22/2024
03:15
7/22/2024
04:30
1.25 COMPZN, RPCOMP TRIP T TOOH with MSC, L/D same 2,637.0 0.0
7/22/2024
04:30
7/22/2024
05:00
0.50 COMPZN, RPCOMP RURD T PU BHA #8, Spear and PO, Latch 7"
Casing and RU to circulate
0.0 27.0
7/22/2024
05:00
7/22/2024
06:00
1.00 COMPZN, RPCOMP CIRC P Pump down 7" casing up 9-5/8" casing
to kill tanks
6BPM at 200 PSI 140* seawater till
clean. 200 BBL's pumped 100 BBL's
returned.
27.0
7/22/2024
06:00
7/22/2024
07:00
1.00 COMPZN, RPCOMP OWFF P Blow down lines drain BOP stack and
RD lines to OWFF. OWFF for 30
minutes. no flow at wellhead.
7/22/2024
07:00
7/22/2024
09:30
2.50 COMPZN, RPCOMP NUND P ND stack at tubing head flange
Pull turn buckles on stack lift stac.
PU casing PUW=85K retrieve casing
slips from wellhead.
Install BOP's back on tubing head and
torque all connections. Install
turnbuckles and riser air up riser boots.
7/22/2024
09:30
7/22/2024
10:00
0.50 COMPZN, RPCOMP SVRG P Service Draw works RU GBR and floor
7/22/2024
10:00
7/22/2024
10:30
0.50 COMPZN, RPCOMP SFTY P PJSM to LD casing W/GBR and Nabors.
7/22/2024
10:30
7/22/2024
14:00
3.50 COMPZN, RPCOMP PULL P L/D casing F/2600' T/surface PUW=85K
62 joints 1 cut joint and 17 centralizers.
2,600.0 0.0
7/22/2024
14:00
7/22/2024
17:00
3.00 COMPZN, RPCOMP RURD T Clear floor RU to test break at BOP's to
250/3000 PSI. BOP leak on the drlling
spool flange retorque retest all good
0.0 0.0
7/22/2024
17:00
7/22/2024
18:45
1.75 COMPZN, RPCOMP BHAH T Install W.R and Make up BHA #9 W/
Short catch O,S, LBS, Jar, 6 ea. DC,
Acc
0.0 0.0
7/22/2024
18:45
7/22/2024
20:00
1.25 COMPZN, RPCOMP TRIP T TIH to Fish 7" casing down to 2637'
RKB
0.0 2,637.0
7/22/2024
20:00
7/22/2024
20:45
0.75 COMPZN, RPCOMP FISH T On bottom w/ short catch
PUW = 70K, SOW = 63K
Work to latch casing stub
2,637.0 2,637.0
7/22/2024
20:45
7/22/2024
22:45
2.00 COMPZN, RPCOMP FISH T Begin Jarring on Fish - Start Jarring
130K - pulling 230K
Final Jarring 260K, pulling to 300K No
go Release O.S Monitor well 15 mins
No Flow
2,637.0 2,637.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 7/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
7/22/2024
22:45
7/23/2024
00:00
1.25 COMPZN, RPCOMP TRIP T POOH 2,637.0 300.0
7/23/2024
00:00
7/23/2024
00:30
0.50 COMPZN, RPCOMP RURD T PU BHA #10, MSC & 6 1/8" String Mill. 0.0 0.0
7/23/2024
00:30
7/23/2024
02:30
2.00 COMPZN, RPCOMP TRIP T TIH w/ BHA#10, MSC & String Mill. 0.0 4,742.0
7/23/2024
02:30
7/23/2024
03:00
0.50 COMPZN, RPCOMP CUTP T PUW = 95 SOW = 70
Locate Collar @ 4755' RKB
Start Cutting 7" casing @ 4751' RKB
w/89 sk min w/1200 psi rot @ 80 rpm Tq
4700 Pres drop after 10 mins all good
4,742.0 4,751.0
7/23/2024
03:00
7/23/2024
05:00
2.00 COMPZN, RPCOMP TRIP T Monitor well 10 mins POOH Stand
Back 3 1/2" DP
4,751.0 42.0
7/23/2024
05:00
7/23/2024
06:30
1.50 COMPZN, RPCOMP BHAH T L/D Cutter Make up BHA # 11 42.0 0.0
7/23/2024
06:30
7/23/2024
08:00
1.50 COMPZN, RPCOMP TRIP T RIH W/BHA 11 XO 3 1/2" DP Continue
t/RIH to 2600'
0.0 2,600.0
7/23/2024
08:00
7/23/2024
10:00
2.00 COMPZN, RPCOMP SVRG T Slip and Cut D.L Service rig 2,600.0 2,600.0
7/23/2024
10:00
7/23/2024
10:15
0.25 COMPZN, RPCOMP TRIP T Continue RIH 2,600.0 2,637.0
7/23/2024
10:15
7/23/2024
11:30
1.25 COMPZN, RPCOMP FISH T Spear into fish and no-go out @ 2,637'
Set down 5k/pull 100k, set down 10k
pull T/130k
Brake over to 105k
2,637.0 2,648.0
7/23/2024
11:30
7/23/2024
13:30
2.00 COMPZN, RPCOMP CIRC T Circulate well clean w/225 bbls of
heated SW, pump Clean sweep pill 45
bbl
Retrurns clean
*** Note: Still losing 50% returns.
2,648.0 2,635.0
7/23/2024
13:30
7/23/2024
15:00
1.50 COMPZN, RPCOMP TRIP T TOOH, L/D 7" casing 2,635.0 231.0
7/23/2024
15:00
7/23/2024
16:00
1.00 COMPZN, RPCOMP BHAH T At surface with BHA #11 L/D BHA # 11
and R/U t/ L/D 7" casing w/ GBR Equip
231.0 0.0
7/23/2024
16:00
7/23/2024
21:00
5.00 COMPZN, RPCOMP PULD T L/D Tot 50 Jts 7" casing w/ cut jt 39.39'
so 50 jts + cut joint Clean up floor R/U t/
Make up BHA # 12 w/spear
0.0
7/23/2024
21:00
7/23/2024
23:00
2.00 COMPZN, RPCOMP TRIP T RIH t/4749'
7/23/2024
23:00
7/24/2024
00:00
1.00 COMPZN, RPCOMP JAR T Tag up @ 4749' wash off top of fish @
88sk min w600 psi Slick off latch up on
fish @ 4751' PUW 90K SOW 70K
Attempt To work Pipe Free w/ jarring w/
75k over and Straight pulled 250 /300K
over w/ 1000 PSI on string Work string
severalTimes and jarred 30 times with
no movement
4,751.0 4,751.0
7/24/2024
00:00
7/24/2024
01:00
1.00 COMPZN, RPCOMP JAR T Continue Jarring w/200k and 300k
straight pull w/no movement Release
Spear 60 Tot Jar hits
4,751.0 4,751.0
7/24/2024
01:00
7/24/2024
02:00
1.00 COMPZN, RPCOMP CIRC T Circ B/U @ 6 BBLs min w/no issue 4,751.0 4,751.0
7/24/2024
02:00
7/24/2024
04:00
2.00 COMPZN, RPCOMP TRIP T TOOH, F/4,751' PUW 90k, T/231' PUW
38k
4,751.0 231.0
7/24/2024
04:00
7/24/2024
04:30
0.50 COMPZN, RPCOMP BHAH T LD BHA F/231' T/Surface 231.0 0.0
7/24/2024
04:30
7/24/2024
05:00
0.50 COMPZN, RPCOMP OTHR T Clean RF 0.0 0.0
7/24/2024
05:00
7/24/2024
05:30
0.50 COMPZN, RPCOMP SVRG T Rig Service Top Drive and assoc.
equipment.
0.0 0.0
7/24/2024
05:30
7/24/2024
06:00
0.50 COMPZN, RPCOMP BHAH T MU BHA #13 w/Baker 7" MSC 0.0 40.7
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 8/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
7/24/2024
06:00
7/24/2024
10:45
4.75 COMPZN, RPCOMP TRIP T TIH on 3.5" DP stands F/Surface
T/5,800''
Observing debris every 43' assuming
string mill is hanging up, rotate and
continue IH, might be cutter flopping
around as well, baker assures me of a
good cut if it is a cutter blade, F/5,800
T/6,948', Kelly up on a single from Pipe
Shed
40.7 6,948.0
7/24/2024
10:45
7/24/2024
12:15
1.50 COMPZN, RPCOMP TRIP T Pressure up to open blades 600 psi,
unable to brake circulation to locate
collar at 6,971', PUH to find cut. bring
pressure up to 1,500 psi, still unable to
brake circulation. bleed pressure off to
zero, bring pressure up to 800 psi, work
pipe, still unable to brake circulation and
unable to locate cut or collar.
PUW 130k, SOW 75k
6,948.0 6,985.0
7/24/2024
12:15
7/24/2024
16:15
4.00 COMPZN, RPCOMP TRIP T TOOH, wet attempting to find blockage. 6,985.0 40.7
7/24/2024
16:15
7/24/2024
18:45
2.50 COMPZN, RPCOMP BHAH T LD BHA #13 Plug up pipe 10' above the
Baker cutter Clean out Assy
w/Formation sand
40.7 0.0
7/24/2024
18:45
7/24/2024
18:45
COMPZN, RPCOMP BHAH T M/U BHA #14 w/ 6 1/8 " Bit 0.0 25.1
7/24/2024
18:45
7/24/2024
22:15
3.50 COMPZN, RPCOMP TRIP T RIH t/ 6915' Brake Circulation ever700'
in the 7" Start Washing down
25.1 6,915.0
7/24/2024
22:15
7/24/2024
23:15
1.00 COMPZN, RPCOMP COND T Wash down F/6915 t/6998' and pump Hi
Vis Sweep around 25bbls @ 10 bbls
min w/ 1850 psi in 7" casing
6,915.0 6,998.0
7/24/2024
23:15
7/25/2024
00:00
0.75 COMPZN, RPCOMP TRIP T POOH T/5985' 6,998.0 5,985.0
7/25/2024
00:00
7/25/2024
01:00
1.00 COMPZN, RPCOMP TRIP T TOOH, F/5,985' T/4,751' 5,985.0 4,751.0
7/25/2024
01:00
7/25/2024
02:00
1.00 COMPZN, RPCOMP CIRC T Pump 25 bbls sweep Around at top of
fish @ 4751' Hi rate 10 bbl min w/1680
psi All good
4,751.0 4,751.0
7/25/2024
02:00
7/25/2024
03:00
1.00 COMPZN, RPCOMP TRIP T Continue TOOH, F\4,751' T/BHA 4,751.0 25.1
7/25/2024
03:00
7/25/2024
03:45
0.75 COMPZN, RPCOMP BHAH T L/D BHA Clean up Floor M/U BHA
w/Baker cutter
25.1 0.0
7/25/2024
03:45
7/25/2024
04:45
1.00 COMPZN, RPCOMP BHAH T MU Baker 7" MSC 0.0 40.8
7/25/2024
04:45
7/25/2024
08:45
4.00 COMPZN, RPCOMP TRIP T TIH F/Surface T/5,224'
Set down weight, rotate through collar,
continue IH F/5,224' to T/6,300' PUW
170k, SOW 70k
40.8 6,300.0
7/25/2024
08:45
7/25/2024
10:15
1.50 COMPZN, RPCOMP TRIP T PUH to 5,865' Cut casing
PUW 170k
6,300.0 5,865.0
7/25/2024
10:15
7/25/2024
13:45
3.50 COMPZN, RPCOMP TRIP T TOOH, F/5,865' T/BHA 5,865.0 40.8
7/25/2024
13:45
7/25/2024
14:15
0.50 COMPZN, RPCOMP BHAH T LD MSC BHA #15 40.8 0.0
7/25/2024
14:15
7/25/2024
14:45
0.50 COMPZN, RPCOMP BHAH T MU Baker ITCO Spear 0.0 231.3
7/25/2024
14:45
7/25/2024
16:15
1.50 COMPZN, RPCOMP TRIP T TIH, F/Surface T/4,751', latch into fish,
attempt to pull casing.
231.3 4,751.0
7/25/2024
16:15
7/25/2024
17:15
1.00 COMPZN, RPCOMP TRIP T Engage fish PUW 95' Pulled 4' PUW
140K All good
4,751.0 5,865.0
7/25/2024
17:15
7/25/2024
19:45
2.50 COMPZN, RPCOMP CIRC T Circulate SXS w/25 BBLS clean sweep
Around @ 10 bbls min w/185 sk min
w1769 psi
5,865.0 5,865.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 9/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
7/25/2024
19:45
7/25/2024
22:00
2.25 COMPZN, RPCOMP TRIP T POOH 5,865.0 1,346.0
7/25/2024
22:00
7/25/2024
23:00
1.00 COMPZN, RPCOMP BHAH T Stand Back BHA 1,346.0 1,346.0
7/25/2024
23:00
7/26/2024
00:00
1.00 COMPZN, RPCOMP CUTP P R/U GBR casing Equip and L/D 7"
Casing
1,346.0 0.0
7/26/2024
00:00
7/26/2024
01:30
1.50 COMPZN, RPCOMP BHAH T Clean up Floor R/D GBR casing Equip. 0.0 0.0
7/26/2024
01:30
7/26/2024
03:30
2.00 COMPZN, RPCOMP BHAH T M/U BHA w/Baker spear RIH to top of
Fish @ 5865'
0.0 40.1
7/26/2024
03:30
7/26/2024
06:00
2.50 COMPZN, RPCOMP TRIP T Latch up on Fish @ 5865' PUW 105K
SOW 65K Start jarring w/100k over and
Straight pull up t/ 350K w/no movement
w/ 1000 psi on string Jar for 2 Hr
release spear
5,865.0 5,865.0
7/26/2024
06:00
7/26/2024
09:00
3.00 COMPZN, RPCOMP TRIP T TOOH F/5865' T/BHA 5,865.0 231.0
7/26/2024
09:00
7/26/2024
09:45
0.75 COMPZN, RPCOMP BHAH T LD and inspect BHA 231.0 0.0
7/26/2024
09:45
7/26/2024
10:30
0.75 COMPZN, RPCOMP BHAH T MU Baker MSC w/7" (1.30") cutter
blades
0.0 40.1
7/26/2024
10:30
7/26/2024
14:30
4.00 COMPZN, RPCOMP TRIP T TIH, w/BHA #18 40.1 6,435.0
7/26/2024
14:30
7/26/2024
15:15
0.75 COMPZN, RPCOMP TRIP T PUH, make cut 6,435', Rotate 80 rpm,
RoWt 7,900 ft/lbs, PUW 140, SOW 75,
pump 4 bpm/760 psi
6,435.0 6,435.0
7/26/2024
15:15
7/26/2024
17:45
2.50 COMPZN, RPCOMP SLPC T PUH to above cut F/6,435' T/5,815', Slip
and cut Drill Line
6,435.0 5,815.0
7/26/2024
17:45
7/26/2024
19:45
2.00 COMPZN, RPCOMP TRIP T TOOH F/5,815'' T/BHA L/D CUTTER 5,815.0 40.7
7/26/2024
19:45
7/26/2024
20:15
0.50 COMPZN, RPCOMP BOPE T Weekly Function BOP Stack All BOP
Components All Good w/no issues
0.0 0.0
7/26/2024
20:15
7/26/2024
21:15
1.00 COMPZN, RPCOMP BHAH T M/U Baker spear 0.0 231.0
7/26/2024
21:15
7/26/2024
23:45
2.50 COMPZN, RPCOMP FISH T RIH w/spear t/5815' and Latch up @
5865'
231.0 6,435.0
7/26/2024
23:45
7/27/2024
00:00
0.25 COMPZN, RPCOMP COND T P/U 5' W/ 17000K over PUW w/ no
issue w/ cut puw clean
6,435.0 6,435.0
7/27/2024
00:00
7/27/2024
01:30
1.50 COMPZN, RPCOMP COND T Continue t/circ pump 44 bbls Hi vis
sweep around case w/ s/w 550 bbls
6,435.0 6,435.0
7/27/2024
01:30
7/27/2024
04:00
2.50 COMPZN, RPCOMP TRIP T POOH w/ fish 6,435.0 231.0
7/27/2024
04:00
7/27/2024
06:00
2.00 COMPZN, RPCOMP BHAH P L/D BHA #19 spear assy cut jt 3.35'
R/U casing equip L/D 13 jts and cut jt
34.15'/ clean Floor
231.0 0.0
7/27/2024
06:00
7/27/2024
09:00
3.00 COMPZN, RPCOMP TRIP T P/U BHA Baker cutter RIH t/ 6435' tag
fill
0.0 6,435.0
7/27/2024
09:00
7/27/2024
12:00
3.00 COMPZN, RPCOMP WASH T Wash Down F/6451' t6724 sand @ 4
bbls min w/ 800 psi t/ clean up
6,435.0 6,724.0
7/27/2024
12:00
7/27/2024
12:30
0.50 COMPZN, RPCOMP MILL T Set Perameters PUW 135K SOW 70K
TQ 8K ROT 95 CUT CSG 6720'
6,724.0 6,720.0
7/27/2024
12:30
7/27/2024
17:00
4.50 COMPZN, RPCOMP TRIP T Pooh L/D cutter and m/u Baker spear 6,720.0 231.0
7/27/2024
17:00
7/27/2024
20:30
3.50 COMPZN, RPCOMP TRIP T RIH and latch up @ 6435' PUW 140K
SOW 75K FISH ON PUW @ 155K
231.0 6,435.0
7/27/2024
20:30
7/27/2024
21:30
1.00 COMPZN, RPCOMP CIRC T Circ B/U @ 10 bbls min w/ 1800 psi 6,435.0 6,435.0
7/27/2024
21:30
7/28/2024
00:00
2.50 COMPZN, RPCOMP TRIP T POOH w/ fish 6,435.0 2,000.0
7/28/2024
00:00
7/28/2024
01:00
1.00 COMPZN, RPCOMP TRIP T POOH 2,000.0 231.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 10/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
7/28/2024
01:00
7/28/2024
02:00
1.00 COMPZN, RPCOMP TRIP T L/D BHA # 21 No Fish Clean and
inspect Grapple All good M/U BHA # 22
spear Assy
231.0 231.0
7/28/2024
02:00
7/28/2024
04:00
2.00 COMPZN, RPCOMP TRIP T RIH t/ 6435' 231.0 6,435.0
7/28/2024
04:00
7/28/2024
04:45
0.75 COMPZN, RPCOMP FISH T B.C @ 4 bbls w/ 800 psi Shut down and
Latch up @ 6435' Pull Fish PUW 15K
over Monitor well 15 mins All good
6,435.0 6,435.0
7/28/2024
04:45
7/28/2024
07:15
2.50 COMPZN, RPCOMP TRIP T POOH 6,435.0 516.0
7/28/2024
07:15
7/28/2024
09:45
2.50 COMPZN, RPCOMP BHAH T LD Spear BHA #22 516.0 285.0
7/28/2024
09:45
7/28/2024
11:15
1.50 COMPZN, RPCOMP PULL P RU GBR, L/D 7" casing
Cut Joint 37.84'
285.0 0.0
7/28/2024
11:15
7/28/2024
12:30
1.25 COMPZN, RPCOMP BHAH T M/U 7" Baker ITCO Spear 0.0 231.0
7/28/2024
12:30
7/28/2024
15:00
2.50 COMPZN, RPCOMP TRIP T TIH, w/Baker 7" Spear, BHA #23
F/Surface T/6,720',
231.0 6,720.0
7/28/2024
15:00
7/28/2024
16:30
1.50 COMPZN, RPCOMP FISH T Engage fish, PUW 135k, SOW 75k,
Straight pull to 250k no movement,
Jar 75k-100k, straight pull 250k over
string weight, no movement, pressure
up down the DP 1,000 psi, continue
jarring on fish, 75k-100k, straight pull to
250k over, Total jar hits 30, no
movement. Release Spear POOH
6,720.0
7/28/2024
16:30
7/28/2024
20:00
3.50 COMPZN, RPCOMP TRIP T POOH t/ Surf No Fish
7/28/2024
20:00
7/28/2024
21:00
1.00 COMPZN, RPCOMP BHAH T L/D Spear M/U BHA # 24
7/28/2024
21:00
7/29/2024
00:00
3.00 COMPZN, RPCOMP TRIP T RIH t/6721' 0.0 6,721.0
7/29/2024
00:00
7/29/2024
05:00
5.00 COMPZN, RPCOMP WASH T Start washing down F/ TOF @ 6721'
w/2bbls min w/250 psi w/ no issue and
locate collars F/
6810,6852,6889,6927,6966 and 7006'
POOH t/ 6950' cut casing and @ 6871'
6,721.0 7,006.0
7/29/2024
05:00
7/29/2024
08:00
3.00 COMPZN, RPCOMP TRIP T TOOH F/6,871' T/Surface 7,006.0 40.7
7/29/2024
08:00
7/29/2024
08:30
0.50 COMPZN, RPCOMP BHAH T L/D Baker MSC 40.7 0.0
7/29/2024
08:30
7/29/2024
10:00
1.50 COMPZN, RPCOMP BHAH T M/U Baker ITCO Spear 0.0 231.0
7/29/2024
10:00
7/29/2024
12:00
2.00 COMPZN, RPCOMP TRIP T TIH w/ITCO Spear BHA #25 231.0 6,668.0
7/29/2024
12:00
7/29/2024
13:00
1.00 COMPZN, RPCOMP FISH T Wash down F/6,668' T/6,720', set down
15k, SOW 75k, engage fish @ 6,720',
pumping 5 bpm/733 psi, good returns
thought cut, PUW 115k, Fish free
6,668.0 6,720.0
7/29/2024
13:00
7/29/2024
15:30
2.50 COMPZN, RPCOMP TRIP T TOOH, PUW 115k, 6,720.0 381.0
7/29/2024
15:30
7/29/2024
16:30
1.00 COMPZN, RPCOMP BHAH T L/D BHA #25 w No fish Redress Spear
RIH
381.0 150.0
7/29/2024
16:30
7/29/2024
19:00
2.50 COMPZN, RPCOMP TRIP T RIH t/ 6400' 150.0
7/29/2024
19:00
7/29/2024
21:00
2.00 COMPZN, RPCOMP SLPC T Cut and Slip Drilling line and service rig
7/29/2024
21:00
7/29/2024
23:30
2.50 COMPZN, RPCOMP FISH T Cont RIH and Latch up on fish @ 6720
pick up look good
7/29/2024
23:30
7/30/2024
00:00
0.50 COMPZN, RPCOMP TRIP T Monitor well 15 mins POOH 0.0 6,720.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 11/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
7/30/2024
00:00
7/30/2024
04:30
4.50 COMPZN, RPCOMP TRIP T POOH Fish on 6,720.0 150.0
7/30/2024
04:30
7/30/2024
05:30
1.00 COMPZN, RPCOMP BHAH P R/U GBR casing Equip and L/D 150' 7"
casing
150.0 0.0
7/30/2024
05:30
7/30/2024
06:30
1.00 COMPZN, RPCOMP BHAH T M/U spear RIH T/ retrieve the last
section of fish the 7" casing f/ 6871
t/6950'
0.0 0.0
7/30/2024
06:30
7/30/2024
09:30
3.00 COMPZN, RPCOMP TRIP T RIH T/ Top Fish@ 6871' 0.0 6,871.0
7/30/2024
09:30
7/30/2024
11:30
2.00 COMPZN, RPCOMP TRIP T Engage fish, Pump at 5 BPM/720 PSI to
verify cut. PU to 155K with no over pull.
POOH Fish on
6,871.0 4,000.0
7/30/2024
11:30
7/30/2024
12:00
0.50 COMPZN, RPCOMP SVRG T Grease draw works and iron rough neck 4,000.0 4,000.0
7/30/2024
12:00
7/30/2024
14:30
2.50 COMPZN, RPCOMP TRIP T TOOH F/4,000' T/80.71' 4,000.0 80.7
7/30/2024
14:30
7/30/2024
16:00
1.50 COMPZN, RPCOMP BHAH P LD one cut 7" Jt 18.10', one full 7" Jt
and one cut 7" Jt 26.36'. RD Casing
tongs.
80.7 0.0
7/30/2024
16:00
7/30/2024
16:30
0.50 COMPZN, RPCOMP RURD P RU and clean rig floor in prep to Drift 9-
5/8".
0.0 0.0
7/30/2024
16:30
7/30/2024
18:00
1.50 COMPZN, RPCOMP BHAH P PU 9-5/8" Drift BHA #28 0.0 287.5
7/30/2024
18:00
7/30/2024
22:30
4.50 COMPZN, RPCOMP TRIP P RIH W/ BHA #28 F/ 287.5' to 6915'.
Obtain
PUWT: 165 K
SOWT: 70 K
287.5 6,915.0
7/30/2024
22:30
7/30/2024
23:15
0.75 COMPZN, RPCOMP WASH P Kelly up to string, and wash down F/
6915K to 6951.5' Pumping at 10
BBL/min @ 2500 PSI. Set down 15K.
P/U 15' start rotary @ 15 RPM @ 6K
TQ. Tag @ 6951.5 and set down 15K.
6,915.0 6,951.5
7/30/2024
23:15
7/30/2024
23:30
0.25 COMPZN, RPCOMP OWFF P P/U and space out Flow check 10 min.
Grease crown during flow check.
6,951.5 6,915.0
7/30/2024
23:30
7/31/2024
00:00
0.50 COMPZN, RPCOMP TRIP P POOH F/ 6915' to 6700' Racking back
DP.
6,915.0 6,700.0
7/31/2024
00:00
7/31/2024
02:30
2.50 COMPZN, RPCOMP TRIP P POOH F/ 6700' to 256'. 6,700.0 256.0
7/31/2024
02:30
7/31/2024
04:30
2.00 COMPZN, RPCOMP BHAH P L/D BHA # 28. No major wear noted on
BHA.
256.0 0.0
7/31/2024
04:30
7/31/2024
05:30
1.00 COMPZN, RPCOMP RURD P Clean and clear rig floor.
Remove wear bushing.
0.0 0.0
7/31/2024
05:30
7/31/2024
08:30
3.00 COMPZN, RPCOMP RURD P PU test tools for BOPE test. MU XO's,
test joints, 3.5" TIW valve and dart. 7"
donut test joint, 3.5" FOSV, RU test
chart. Test pump hoses. Set test plug.
Fill stack and grease manifold valves.
Work air out of system and shell test
BOP's.
0.0 0.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 12/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
7/31/2024
08:30
7/31/2024
14:00
5.50 COMPZN, RPCOMP BOPE P Start testing BOPE.
Initial BOPE test, Tested BOPE at
250/3000 PSI for 5 min each. Test blind
rams, CMV 1, 2, 3, &16, IBOP. Test
blind rams, CMV 4, 5, & 6, manual
IBOP, inner test spool valve and HCR
kill. Test upper rams, CMV 7, 8, & 9 with
3.5 test joint. Test hydraulic and manual
choke valves to 1500 PSI and
demonstrate bleed off. Test Upper rams,
CMV 10 &11, manual kill & TIW. Test
Upper rams, CMV 12, 13 &15. Test
Upper rams & CMV 14. Test Upper rams
& HCR choke. Test Upper rams &
Manual choke. Tested Annular on 3.5
test joint. Test Lower rams on 7 test
joint and 3.5 FOSV. Test above lower
rams on 7 test joint with annular closed.
Perform accumulator test. Initial
pressure=3,150 PSI, after
closure=1,750 PSI, 200 PSI attained
=14 sec, full recovery attained = 97 sec.
UVBR's= 5 sec, Annular= 26 sec.
Blinds= 5 sec. LVBRs=5 sec. HCR
choke & kill= 1 sec each. 5 back up
nitrogen bottles average = 2,000 PSI.
Test gas detectors, PVT and flow show.
Test Witness Waived by AOGCC rep
Brian Bixby.
Note: Tested Upper rams with 3.5 test
joint and test Lower rams with 7" test
joint. Tested Annular with 3.5" and 7
test joints.
All alarms tested good.
0.0 0.0
7/31/2024
14:00
7/31/2024
16:00
2.00 COMPZN, RPCOMP RURD P LD test tool and break down test
equipment. Drain stack. Pull test plug.
Blow down lines to stack. Break down
test joints.
0.0 0.0
7/31/2024
16:00
7/31/2024
16:30
0.50 COMPZN, RPCOMP SVRG P Rig service, replace Demco seat and
paddle on rig floor. Test to 250/5000 psi.
0.0 0.0
7/31/2024
16:30
7/31/2024
18:00
1.50 COMPZN, RPCOMP BHAH P P/U Dress off BHA per Baker fishing
rep.
0.0 265.2
7/31/2024
18:00
7/31/2024
22:00
4.00 COMPZN, RPCOMP TRIP P RIH w/ Dress of BHA F/ 265.23' to
6883'.
265.2 6,883.0
7/31/2024
22:00
7/31/2024
22:30
0.50 COMPZN, RPCOMP MILL P Obtain parameters, Ream down F/
6883' to Tag top of stump with Burning
shoe @ 6952', P/U and rotate over and
dress off stump to 6952.9'.
PUWT: 155K
SOWT: 75K
ROTWT: 95K
Pumping @ 4 BBL/Min @ 500 PSI
40 RPM @ 8-9K TQ.
6,883.0 6,953.0
7/31/2024
22:30
7/31/2024
23:00
0.50 COMPZN, RPCOMP CIRC P Pick up off bottom, and circulate at 8
BPM @ 1600 PSI to clean shavings
away from Stump, and BHA. Spot 20
BBL high vis pill Underdisplacing pill out
of drill pipe.
6,950.0 6,950.0
7/31/2024
23:00
7/31/2024
23:30
0.50 COMPZN, RPCOMP TRIP P POOH 4 Stands at 20'/ min to lay in the
rest of pill.
6,950.0 6,595.0
7/31/2024
23:30
8/1/2024
00:00
0.50 COMPZN, RPCOMP SVRG P Rig service, grease crown. 6,595.0 6,595.0
8/1/2024
00:00
8/1/2024
03:00
3.00 COMPZN, RPCOMP TRIP P POOH F/ 6595' to 265' 6,595.0 265.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 13/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
8/1/2024
03:00
8/1/2024
04:30
1.50 COMPZN, RPCOMP BHAH P L/D Dress off BHA. 265.0 0.0
8/1/2024
04:30
8/1/2024
05:00
0.50 COMPZN, RPCOMP RURD P Clean and clear rig floor, pull wear
bushing.
0.0 0.0
8/1/2024
05:00
8/1/2024
08:00
3.00 COMPZN, RPCOMP RURD P R/U GBR on rig floor, change elevators
to long bails, and rig up other equipment
to run 7" Casing tie back.
0.0 0.0
8/1/2024
08:00
8/1/2024
09:00
1.00 COMPZN, RPCOMP PUTB P Run 7", 26#, HYD563 CSG.
Best of life 2000 thread compound.
Torque connections to 9400 ft-lb
0.0 283.0
8/1/2024
09:00
8/1/2024
09:30
0.50 COMPZN, RPCOMP PUTB T POOH F/ 283 to ES cementer.
Haliburton hand was not called to the
floor when picking up tools to inspect
HAL CMNT. Run back in to 283'
283.0 283.0
8/1/2024
09:30
8/1/2024
11:00
1.50 COMPZN, RPCOMP PUTB P Cont. to RIH W/ 7", 26#, HYD563 CSG.
Best of life 2000 thread compound.
Torque connections to 9400 ft-lb
283.0 1,747.0
8/1/2024
11:00
8/1/2024
12:00
1.00 COMPZN, RPCOMP SVRG P Service rig and remove/replace 4"
Demco Valve on Floor from stand pipe.
1,747.0 1,747.0
8/1/2024
12:00
8/1/2024
14:00
2.00 COMPZN, RPCOMP OTHR T Remove & replace 4" Demco Valve on
rig floor stand pipe.
PT to 250 low /4000 psi high for 5 min
1,747.0 1,747.0
8/1/2024
14:00
8/1/2024
19:30
5.50 COMPZN, RPCOMP PUTB P Run 7", 26#, HYD563 CSG.
Best of life 2000 thread compound.
Torque connections to 9400 ft-lb
F/1,747 T/6953'
PUWT 180 K
SOWT: 95K
1,747.0 6,840.0
8/1/2024
19:30
8/1/2024
21:00
1.50 COMPZN, RPCOMP PUTB P Pick up space out joints. Pick up final
joint (174), M/U X/O to 7", and Kelly up
to top drive.
6,840.0 6,945.0
8/1/2024
21:00
8/1/2024
22:00
1.00 COMPZN, RPCOMP CIRC P Circulate out Hi vis sweep previously
spotted on bottom. Pump @ 225 GPM
@ 130 PSI.
6,945.0 6,945.0
8/1/2024
22:00
8/1/2024
22:45
0.75 COMPZN, RPCOMP PUTB P Obtain parmeters, and engugage 7"
Casing stump @ 6950.1'. Rotate over
stump w/ 10 RPM @ 11K TQ. Set down
70 K. Stop rotary, release torque. Pick
up and over pull to 50 K over (230 K).
Slack off to 70 K, and P/U to 230 K 2
more times to confirm. Pressure up
string to 500 PSI and monitor to verify
Casing patch, and seals engauged.
PUWT: 180 K
SOWT: 95 K
ROTWT: 125 K
10.5K TQ @ 10 RPM.
6,945.0 6,950.0
8/1/2024
22:45
8/1/2024
23:00
0.25 COMPZN, RPCOMP OTHR P R/U to test Casing patch, set ICP, and
test casing.
6,950.0 6,950.0
8/1/2024
23:00
8/2/2024
00:00
1.00 COMPZN, RPCOMP PRTS P PT Casing patch to 1500 PSI for 5 min:
GOOD.
Stage up pressure to 2240 PSI:
Observe shear, and pressure curve
flatline as packer inflated. Continue to
pressure up 2600 PSI and hold for 5
min: GOOD. Bleed pressure to 500
PSI and hold for 5 min: GOOD. Bleed
pressure to 0 PSI. Bled back 3 BBLS of
3.5 pumped.
6,950.0 6,950.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 14/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
8/2/2024
00:00
8/2/2024
00:30
0.50 COMPZN, RPCOMP PRTS P Pressure test CSG to 2500 PSI for 10
min: GOOD.
6,950.0 6,950.0
8/2/2024
00:30
8/2/2024
01:00
0.50 COMPZN, RPCOMP OTHR P B/O top drive from X/O in 7". 6,950.0 0.0
8/2/2024
01:00
8/2/2024
01:30
0.50 COMPZN, RPCOMP OTHR T X/O stuck in top stump. Rig up rig
tongs, and snubbing line, and break out
X/O and remove.
0.0 0.0
8/2/2024
01:30
8/2/2024
03:30
2.00 COMPZN, RPCOMP OTHR P R/U CMNT head and hard lines on the
rig floor. Purge, and pressure test lines
to 4000 PSI.
0.0 0.0
8/2/2024
03:30
8/2/2024
04:00
0.50 COMPZN, RPCOMP CMNT P Line up and pressure up to shift open
ES cementer. Cementer open @ 3180
PSI.
0.0 0.0
8/2/2024
04:00
8/2/2024
05:00
1.00 COMPZN, RPCOMP CIRC P CBU @ 5 BBL/ Min @ 300 PSI. Have
PJSM for CMNT job with rig crew and
HAL.
0.0 0.0
8/2/2024
05:00
8/2/2024
08:00
3.00 COMPZN, RPCOMP CMNT P Pump 10 BBLS died spacer. Pump 355
15.3 PPG lead cement w/ ~5.3 PPG
Bridge Maker 2 LCM. Pump 55 BBLS of
15.3 PPG cement. Pump CMNT @ 3.8
BBL/ Min @ 483 FCP. Release plug
and chase w/ 20 BBLS of fresh water.
Line up rig pumps on the hole. Catch
pressure @ 3 BBLs pumped. ICP 500
PSI. Observe good lift pressure. Plug
bump 1.7 BBLS earlier than calculated.
FCP 2150 PSI. Continue to pressure
up. ES Cementer closed @ 2900 PSI,
Pressure up to 3000 PSI, and hold 5
min. Bleed pressure to 0. Check for
flow, at possum belly with bleeder open.
No flow.
Cement wet @ 04:44
ICP 500 PSI
FCP 2150.
ES cementer closed: 2900 PSI.
65 BBLS of cement returned to surface.
112 BBLS of cement lost through holes
in 9-5/8"
0.0 0.0
8/2/2024
08:00
8/2/2024
16:30
8.50 COMPZN, RPCOMP WOC P Flush lines out to the tiger tank with
black water, followed by seawater. Blew
down lines to tiger tank and open top
tank. Flush mud manifold on floor with
black water. B/D lines on floor. RD
cement head. MU floor valve to stump.
RD lines in cellar and prep for ND stack.
Prep tubing in pipe shed. Break down
squeeze manifold and clean. Replace
upper jaw on rough neck. continue
sending black water to trucks to clean
out cement. Weld splice in drilling line.
0.0 0.0
8/2/2024
16:30
8/2/2024
17:00
0.50 COMPZN, RPCOMP OWFF P Drain stack, Opened 7x9-5/8" annulus
to flow for 30 minutes. Good - No Flow.
0.0 0.0
8/2/2024
17:00
8/2/2024
18:00
1.00 COMPZN, RPCOMP NUND P Suck out casing joint in prep for cutting
7" casing with Wachs cutter.
0.0 0.0
8/2/2024
18:00
8/2/2024
19:00
1.00 COMPZN, RPCOMP NUND P N/D BOPS. and raise stack. 0.0 0.0
8/2/2024
19:00
8/2/2024
23:30
4.50 COMPZN, RPCOMP OTHR P FMC rep drop slips. Rig up Wach's
cutter, and make cut. L/D Cut joint.
Change out bails on top drive.
0.0 0.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 15/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
8/2/2024
23:30
8/3/2024
00:00
0.50 COMPZN, RPCOMP OTHR T Attempt to set pack off, observe
emergency slips set in incorrect well
head. Pack off will not fit.
0.0 0.0
8/3/2024
00:00
8/3/2024
03:00
3.00 COMPZN, RPCOMP OTHR T P/U Spear, and engage casing P/U to
90 K R/U come alongs on CSG, and
center in well head. Pull Slips. N/D
Spool. P/U to 135 K (10K over neutral).
Set slips. Release spear.
0.0 0.0
8/3/2024
03:00
8/3/2024
07:30
4.50 COMPZN, RPCOMP OTHR P Rig up Wachs cutter, and make cut on
7". Rig down Wachs cutter, bevel 7"
casing and install packoffs. install tubing
spool.
0.0 0.0
8/3/2024
07:30
8/3/2024
09:30
2.00 COMPZN, RPCOMP PRTS P PT 7" casing pack off to 4200 psi for 10
minutes. Had to PT and hammer up the
tubing head nuts 3 times. Retest good.
0.0 0.0
8/3/2024
09:30
8/3/2024
14:00
4.50 COMPZN, RPCOMP NUND P NU BOPE. PU test tools. PT breaks
250/3000 psi and chart. LD test tools.
RD test equipment and drain stack. Pull
test plug.
0.0 0.0
8/3/2024
14:00
8/3/2024
14:30
0.50 COMPZN, RPCOMP RURD P Installed wear ring. 0.0 0.0
8/3/2024
14:30
8/3/2024
16:30
2.00 COMPZN, RPCOMP BHAH P MU BHA #31 to drill out cement and
HES Cementer.
0.0 258.0
8/3/2024
16:30
8/3/2024
19:30
3.00 COMPZN, RPCOMP TRIP P Trip in hole with BHA #31 F/258' T/
6600'.
PUWT: 160 K
SOWT: 75 K
258.0 6,600.0
8/3/2024
19:30
8/3/2024
20:00
0.50 COMPZN, RPCOMP WASH P Wash from 6600' to 6692' @ 2 BPM @
200 PSI. Tag stringer @ 6692'. Set
down 5K.
6,600.0 6,692.0
8/3/2024
20:00
8/3/2024
21:00
1.00 COMPZN, RPCOMP REAM P P/U to 6680'. Start rotary @ 20 RPM,
and ream through stringers/ green
cement to 6885' Tag competent
cement. Tag depth matches with
calculated top of cement.
ROTWT 98 K.
20 RPM @ 8.5 K TQ.
20 BPM @ 200 PSI.
6,692.0 6,885.0
8/3/2024
21:00
8/3/2024
23:30
2.50 COMPZN, RPCOMP COCF P Drill out cement F/ 6885' to 6915'.
Pumping 4.5 BPM @ 729 PSI
8-10 K WOB
80 RPM @ 8-9 K TQ
ROTWT 98 K
6,885.0 6,915.0
8/3/2024
23:30
8/4/2024
00:00
0.50 COMPZN, RPCOMP REAM P Continue to wash and ream F/ 6915' to
7057'. Tag top of sand.
6,915.0 7,057.0
8/4/2024
00:00
8/4/2024
01:00
1.00 COMPZN, RPCOMP REAM P Clean out sand to 7047'. Dry drill on
sand/ remaining CMNT for 10 MIN @ 40
RPM 9K TQ.
181 GPM @ 798 PSI
40 RPM 8-9 K TQ
ROTWT 98K
7,057.0 7,047.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 16/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
8/4/2024
01:00
8/4/2024
02:30
1.50 COMPZN, RPCOMP CIRC P Circulate hole clean @ 210 GPM @
1000 PSI. Rack back one stand while
circulating.
7,047.0 6,970.0
8/4/2024
02:30
8/4/2024
03:00
0.50 COMPZN, RPCOMP SVRG P Service top drive, and rig floor
equipment. Flow check while
performing rig service.
6,970.0 6,970.0
8/4/2024
03:00
8/4/2024
03:30
0.50 COMPZN, RPCOMP CIRC P Pump dry job, and allow for slug to fall. 6,970.0 6,970.0
8/4/2024
03:30
8/4/2024
06:30
3.00 COMPZN, RPCOMP TRIP P POOH F/ 6970' to 258'
UWT 160K, DWT 70K
6,970.0 258.0
8/4/2024
06:30
8/4/2024
07:00
0.50 COMPZN, RPCOMP BHAH P LD BHA #31 (6.125" roller cone bit, 2
boot baskets and 2 string magnets)
258.0 0.0
8/4/2024
07:00
8/4/2024
08:00
1.00 COMPZN, RPCOMP BHAH P PU BHA #32 (RCJB, 6.125 OD string
mill, 2 boot baskets and 2 string
magnets).
0.0 74.0
8/4/2024
08:00
8/4/2024
09:00
1.00 COMPZN, RPCOMP PRTS P PT 7" casing to 2500 psi for 30 minutes
and chart.
RD test equipment.
74.0 74.0
8/4/2024
09:00
8/4/2024
09:30
0.50 COMPZN, RPCOMP BHAH P Finish PU BHA #32 74.0 272.0
8/4/2024
09:30
8/4/2024
11:30
2.00 COMPZN, RPCOMP TRIP P Trip in the hole F/272' -T/6042'
PUW ,SOW
272.0 6,042.0
8/4/2024
11:30
8/4/2024
12:00
0.50 COMPZN, RPCOMP SVRG P Service rig draw works and iron rough
neck.
6,042.0 6,042.0
8/4/2024
12:00
8/4/2024
12:30
0.50 COMPZN, RPCOMP TRIP P Trip in the hole F/6042' -T/6898
PUW ,SOW
6,042.0 6,898.0
8/4/2024
12:30
8/4/2024
14:00
1.50 COMPZN, RPCOMP REAM P Rotate 40 RPM, 9.5k TQ, 95 ROW,
165K PUW, 75K SOW,
Tag sand at 7047', PU and wash down.
Wash and ream T/7060', 10 BPM, 1029
PSI, 20 RPM, 9.8K TQ, 95 ROW
6,898.0 7,060.0
8/4/2024
14:00
8/4/2024
15:00
1.00 COMPZN, RPCOMP CIRC P Circulating to clean up the well. 7,060.0 7,060.0
8/4/2024
15:00
8/4/2024
16:30
1.50 COMPZN, RPCOMP SLPC P Slip and cut 12 wraps of drill line. 7,060.0 7,060.0
8/4/2024
16:30
8/4/2024
18:30
2.00 COMPZN, RPCOMP TRIP P TOOH F/7060 T/271'.
PUW165K, SOW 75K.
7,060.0 271.0
8/4/2024
18:30
8/4/2024
19:30
1.00 COMPZN, RPCOMP BHAH P Open RCJB, no debris in basket. B/D
and empty boot baskets, found debris,
and cement from drill out.
271.0 0.0
8/4/2024
19:30
8/4/2024
20:00
0.50 COMPZN, RPCOMP CLEN P Empty out boot baskets, and clean
string magnets. Clean rig floor prior to
RIH w/ BHA.
0.0 0.0
8/4/2024
20:00
8/4/2024
21:00
1.00 COMPZN, RPCOMP BHAH P M/U RCJB, and boot baskets, RIH w/
remaining BHA.
0.0 271.0
8/4/2024
21:00
8/5/2024
00:00
3.00 COMPZN, RPCOMP TRIP P RIH F/ 271' to 6993'.
PUWT: 160 K
SOWT: 70 K
271.0 6,993.0
8/5/2024
00:00
8/5/2024
01:00
1.00 COMPZN, RPCOMP WASH P Wash F/ 6993' to 7088'. @ 7088' set
down 10K.
7.5 BPM @ 2500 PSI.
6,993.0 7,088.0
8/5/2024
01:00
8/5/2024
02:30
1.50 COMPZN, RPCOMP CIRC P Pump 20 BBL Hi-Vis sweep, and
circulate surface to surface. Sand
brought back to surface.
7,088.0 7,088.0
8/5/2024
02:30
8/5/2024
02:45
0.25 COMPZN, RPCOMP OWFF P Flow check well 15 Min: Static. 7,088.0 7,088.0
8/5/2024
02:45
8/5/2024
05:45
3.00 COMPZN, RPCOMP TRIP P POOH F/ 7088' to 271'. 7,088.0 271.0
8/5/2024
05:45
8/5/2024
08:00
2.25 COMPZN, RPCOMP BHAH P LD BHA #33 second RCJB run 271.0 0.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 17/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
8/5/2024
08:00
8/5/2024
08:30
0.50 COMPZN, RPCOMP BHAH P PU BHA #34 to retrieve G-lock 0.0 13.0
8/5/2024
08:30
8/5/2024
11:30
3.00 COMPZN, RPCOMP TRIP P TIH F/13' T/7018'
UWT 160 K, DWT 70K
13.0 7,018.0
8/5/2024
11:30
8/5/2024
13:30
2.00 COMPZN, RPCOMP CIRC P Retrieve RBP at 7096'
RPM 5, Free TQ 6800K,
4.5 BPM at 500 psi
Allow elements to relax while circulating
bottoms up 4BPM at420 psi.
7,018.0 7,096.0
8/5/2024
13:30
8/5/2024
14:00
0.50 COMPZN, RPCOMP OWFF P Flow check well for 15 minutes- No flow 7,096.0 7,096.0
8/5/2024
14:00
8/5/2024
17:30
3.50 COMPZN, RPCOMP TRIP P POOH F/ 7096' to 13'. 7,096.0 13.0
8/5/2024
17:30
8/5/2024
18:00
0.50 COMPZN, RPCOMP BHAH P L/D RBP, and running tool. 13.0 0.0
8/5/2024
18:00
8/5/2024
18:30
0.50 COMPZN, RPCOMP BHAH P P/U and Make up 2 7/8" Mule shoe, and
RIH w/ DC out of the derrick.
0.0 202.0
8/5/2024
18:30
8/5/2024
21:30
3.00 COMPZN, RPCOMP TRIP P RIH F/ 202' to 7950'
PUWT: 185 K
SOWT: 70 K
202.0 7,950.0
8/5/2024
21:30
8/5/2024
22:00
0.50 COMPZN, RPCOMP WASH P Wash into PBR w/ Mule shoe. @ 2
BPM @ 90 PSI. Observe Pressure
increase to 180 PSI entering top of
PBR. Did not observe bobble entering
top of PBR. Continue to slack off to
7983.62'. No Go out on Stop sub in
BHA. Set down 10K to confirm. Places
top of PBR @ 7963.76'.
7,950.0 7,983.6
8/5/2024
22:00
8/5/2024
23:45
1.75 COMPZN, RPCOMP CIRC P P/U 2' and line up to and pump 20 BBL
High Vis sweep. Circulate hole clean.
Pump @ 210 GPM @ 670 PSI.
7,983.6 7,981.0
8/5/2024
23:45
8/6/2024
00:00
0.25 COMPZN, RPCOMP OWFF P Flow check 10 min: Static. Blow down
Top drive, and prep to pull out of the
hole L/D DP.
7,981.0 7,981.0
8/6/2024
00:00
8/6/2024
03:30
3.50 COMPZN, RPCOMP PULD P POOH L/D 3.5" DP F/ 7981' to 5380' 7,981.0 5,380.0
8/6/2024
03:30
8/6/2024
03:45
0.25 COMPZN, RPCOMP OTHR P Unannounced drill on rig crew. Kick
while laying down drill pipe. Personnel
in different positions. CRT: 100
seconds. AAR with rig crew.
5,380.0 5,380.0
8/6/2024
03:45
8/6/2024
08:00
4.25 COMPZN, RPCOMP PULD P Continue to POOH L/D 3.5" DP F/ 5380'
T/ 202'.
5,380.0 202.0
8/6/2024
08:00
8/6/2024
08:30
0.50 COMPZN, RPCOMP BHAH P LD BHA #34 2-7/8" mule shoe 202.0 0.0
8/6/2024
08:30
8/6/2024
11:30
3.00 COMPZN, RPCOMP RURD P Pull wear bushing.
RU casing tongs.
RU Haliburton Spooling unit.
0.0 0.0
8/6/2024
11:30
8/6/2024
12:00
0.50 COMPZN, RPCOMP SFTY P PJSM to run tubing. 0.0 0.0
8/6/2024
12:00
8/6/2024
13:00
1.00 COMPZN, RPCOMP RURD P Test power tongs. Pancake flat.
Replaced pancake still flat replaced
pancake Third pancake good.
0.0 0.0
8/6/2024
13:00
8/6/2024
14:00
1.00 COMPZN, RPCOMP SVRG P Service rig. 0.0 0.0
8/6/2024
14:00
8/6/2024
15:30
1.50 COMPZN, RPCOMP RURD P Tested torque on power tongs.
MU gauge assembly installed tec wire to
gauge. Test continuity on tec wire.
0.0 0.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 18/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
8/6/2024
15:30
8/6/2024
18:00
2.50 COMPZN, RPCOMP PUTB P RIH W/3.5" completion w/ Tech wire.
F/surface T/ 1347'. 1 Cannon clamp per
joint
0.0 1,347.0
8/6/2024
18:00
8/6/2024
18:15
0.25 COMPZN, RPCOMP OTHR P Unannounced emergency drill with rig
crew. Man down drill. CRT 5min 30
seconds. AAR with crew.
1,347.0 1,347.0
8/6/2024
18:15
8/6/2024
23:00
4.75 COMPZN, RPCOMP PUTB P RIH w/ 3.5" completion w/ tech wire
from 1347' to 2681'. 1 Cannon clamp
per joint.
1,347.0 2,681.0
8/6/2024
23:00
8/6/2024
23:30
0.50 COMPZN, RPCOMP PUTB P Bad make up on JT. 97. L/D, P/U Joint
C. attempted to make up to stump. Bad
make up. Damage to box of Jt. 96.
Attempt to change out collar on Jt. 96,
wouldn't break. L/D Joint 96. Run
Spare joints.
2,681.0 2,681.0
8/6/2024
23:30
8/7/2024
00:00
0.50 COMPZN, RPCOMP PUTB P RIH w/ 3.5" completion with Tech wire
from 2681' to 2849'. 1 Cannon clamp
per joint.
2,681.0 2,850.0
8/7/2024
00:00
8/7/2024
09:30
9.50 COMPZN, RPCOMP PUTB P RIH w/ 3.5" completion with Tech wire
from 2849' T/7933' PUW=120K SO 50K
2,850.0 7,933.0
8/7/2024
09:30
8/7/2024
12:30
3.00 COMPZN, RPCOMP HOSO P Space out PU joints 251 and 252. roll
pump at 1 BPM pressure increased to
300 PSI. Shut down pump. PUH till
pressure fell off. Mark pipe and 5' in to
tag
Locate top of PBR got 21.5' of travel.
Lay down 3 joints PU 24.57' of pup
joints. MU to string. PU joint 250.
PU and MU hanger to string. Terminate
control line through hanger.
Test control line fitting to 5000 PSI for 10
minutes.
0.0 0.0
8/7/2024
12:30
8/7/2024
14:30
2.00 COMPZN, RPCOMP CIRC P Circulate CI SxS at 3 BPM 300 PSI. 0.0 0.0
8/7/2024
14:30
8/7/2024
15:00
0.50 COMPZN, RPCOMP HOSO P Land TBG hanger RILDS. 0.0 0.0
8/7/2024
15:00
8/7/2024
16:30
1.50 COMPZN, RPCOMP PRTS P Pressure test tubing to 3000 PSI for 30
minutes. bled pressure back to 1500
PSI. Pressured up on IA to 2500 PSI for
30 minutes.
Dumped TBG pressure sheared SOV.
0.0 0.0
8/7/2024
16:30
8/7/2024
18:30
2.00 COMPZN, RPCOMP MPSP P RU to test BPV. Set BPV and test under
BPV to 1000 PSI for 10 minutes. Rd
testing equipment.
0.0 0.0
8/7/2024
18:30
8/8/2024
00:00
5.50 COMPZN, WHDBOP OTHR P Between wells maintenance of BOP.
Clean pits, and rig down equipment
through out the rig.
0.0 0.0
8/8/2024
00:00
8/8/2024
01:00
1.00 COMPZN, WHDBOP OTHR P Between wells maintenance on BOP. 0.0 0.0
8/8/2024
01:00
8/8/2024
01:30
0.50 COMPZN, WHDBOP NUND P N/D BOP, and rack back. 0.0 0.0
8/8/2024
01:30
8/8/2024
03:00
1.50 COMPZN, WHDBOP THGR P FMC hand, and HAL rep terminate Tech
wire at well head.
Pull pits away from Sub. Start to lay
mats for next well.
0.0 0.0
8/8/2024
03:00
8/8/2024
04:30
1.50 COMPZN, WHDBOP NUND P N/U adaptor flange, and set tree on top
of adaptor flange. FMC test hanger
neck seals to 5000 PSI for 10 min:
GOOD. HAL hand run final checks on
Tech wire. N/U tree.
Lay mats infront of 1D 42.
0.0 0.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Page 19/19
1D-36
Report Printed: 9/3/2024
Operations Summary (with Timelog Depths)
Job: RECOMPLETION
Time Log
Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB)
8/8/2024
04:30
8/8/2024
07:00
2.50 COMPZN, WHDBOP RURD P R/U circulating lines, and LRS. flood
and PT lines. PT tree to 5000 PSI:
Pulled BPV.
0.0 0.0
8/8/2024
07:00
8/8/2024
08:30
1.50 COMPZN, WHDBOP FRZP P Freeze protect well. Pump 71 BBLS of
diesel, 2BPM FCP=800 PSI. allow to U-
tube for one hour.
0.0 0.0
8/8/2024
08:30
8/8/2024
10:00
1.50 DEMOB, MOVE RURD P RD off 1D-36 MIRU on 1D-42. Final
pressures T/IA/OA=0/0/0 PSI
0.0
Rig: NABORS 7ES
RIG RELEASE DATE 8/8/2024
Last Tag
Annotation Depth (ftKB) Wellbore End Date Last Mod By
Last Tag: 11,450.0 1D-36 4/30/2005 WV5.3
Conversion
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Installed Post RWO GLD. Pulled catcher & RBP 1D-36 8/30/2024 fergusp
Notes: General & Safety
Annotation End Date Last Mod By
NOTE: View Schematic w/ Alaska Schematic9.0 1/8/2009 ninam
NOTE: MULTI-LATERAL WELL: 1D-36, 1D-36L1,1D-36L2 ALL C-SANDS 8/1/2005 lmosbor
Casing Strings
Csg Des OD (in) ID (in) Top (ftKB)
Set Depth
(ftKB)
Set Depth
(TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread
CONDUCTOR 20 19.25 33.0 121.0 121.0 72.00 H-40 Welded
SURFACE 9 5/8 8.70 34.4 7,046.8 4,297.1 40.00 L-80 BTCM
PRODUCTION 7 6.28 31.4 11,038.4 6,244.8 26.00 L-80 BTCM
WINDOW L2 3 1/2 2.99 11,360.0 11,364.0 6,403.2 9.30 L-80 SLHT
WINDOW L1 3 1/2 2.99 11,407.0 11,411.0 6,426.0 9.30 L-80
LINER 3 1/2 2.99 10,885.2 11,656.0 6,541.2 9.30 L-80 SLHT
Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string
Top (ftKB)
0.0
Set Depth
7,982.1
String Max No
3 1/2
Set Depth
4,754.0
Tubing Description
Tubing Completion Upper
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
29.2 29.2 0.03 Hanger 10.880 FMC GEN 5 Tubing hanger
3.5" EUE lift threads.
FMC Gen V 3.060
3,798.8 2,690.4 57.56 Mandrel GAS
LIFT
5.928 3.5" X 1.5" GLM Camco MMG 2.920
6,556.9 4,052.5 60.63 Mandrel GAS
LIFT
5.867 3.5" X 1.5" Camco MMG 2.920
7,826.3 4,679.1 61.00 Mandrel GAS
LIFT
5.872 3.5" X 1.5" GLM Camco MMG 2.920
7,886.6 4,708.4 61.03 Sensor -
Discharge
Gauge
4.856 OPSIS Gauge mandrel HAL OPSIS 2.938
7,942.9 4,735.4 61.66 Nipple - X 4.506 X/Nipple S/N 005011991-10 HAL X-nipple 2.813
7,960.2 4,743.7 61.75 Locator 4.200 Locator Baker locator 2.867
7,960.7 4,743.9 61.75 Seal Assembly 3.700 Baker 80 40 GBH 22 Seal assy.
21.41' from bottom to locator
Baker 80-40 2.867
Top (ftKB)
7,963.4
Set Depth
10,926.2
String Max No
3 1/2
Set Depth
6,190.0
Tubing Description
Tubing Production
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE 8RD
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
7,963.4 4,745.2 61.74 PBR 5.000 Baker 80-40 PBR Baker 80-40 4.000
7,988.9 4,757.2 61.68 PACKER 5.970 Baker 3½ x 7'' Premier Packer Baker 598-287
Premier
2.860
9,420.2 5,454.8 60.66 GAS LIFT 4.730 Camco MMG 2.915
10,839.4 6,147.7 60.99 NIPPLE 3.500 Landing Nipple 2.813 DS Profile Camco 2.813
DS
2.813
10,888.8 6,171.7 60.83 LOCATOR 4.000 Baker locator sub with 3-ft spaceout Baker 80-40 2.990
10,890.0 6,172.3 60.83 SEAL ASSY 3.980 80-40 Baker Seal Assy. Baker 80-40 2.990
Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.)
Top (ftKB)
Top (TVD)
(ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in)
31.4 31.4 0.03 EMERGENCY
SLIPS
7" x 11" emergency slips FMC 8/3/2024 7.000
11,370.0 6,406.1 60.85 PACKER Weatherford WS-R-BB
Packer Set in Main Bore Liner
7/22/2005 1.250
11,410.0 6,425.5 61.26 Whipstock WHIPSTOCK TO L1, set
7/22/2005
7/22/2005 1.250
Mandrel Inserts : excludes pulled inserts
Top (ftKB)
Top (TVD)
(ftKB)
Top
Incl (°)
St
ati
on
No
/S Serv
Valve
Type
Latch
Type
OD
(in)
TRO Run
(psi) Run Date Com Make Model
Port
Size (in)
3,798.8 2,690.4 57.56 1 GAS LIFT GLV RK 1 1/2 1,290.0 8/25/2024 Camco MMG 0.250
6,556.9 4,052.5 60.63 2 GAS LIFT OV RK 1 1/2 0.0 8/24/2024 Camco MMG 0.250
7,826.3 4,679.1 61.00 3 GAS LIFT DMY RK 1 1/2 0.0 8/24/2024 Camco MMG 0.000
Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal ID
(in)
10,885.2 6,169.9 60.84 TIE BACK 6.000 LINER TIE BACK SLEEVE 5.500
10,892.5 6,173.5 60.82 PACKER 5.980 BAKER ZXP LINER TOP
PACKER
4.408
10,971.2 6,212.0 60.62 NIPPLE 4.540 HES 'XN' NIPPLE w/2.75 NO GO
PROFILE
2.750
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft)Type Com
11,410.0 11,420.0 6,425.5 6,430.3 C-2, 1D-36 10/28/2000 4.0 IPERF 2.5" BH HSD
1D-36, 9/3/2024 2:27:38 PM
Vertical schematic (actual)
LINER; 10,885.1-11,656.0
APERF; 11,420.0-11,484.0
IPERF; 11,410.0-11,420.0
FRAC; 11,410.0
WINDOW L1; 11,407.0-11,411.0
Whipstock; 11,410.0
LINER L1; 11,394.5-13,310.0
IPERF; 11,406.0-12,261.0
PACKER; 11,370.0
WINDOW L2; 11,360.0-11,364.0
PRODUCTION; 6,952.9-
11,038.4
NIPPLE; 10,839.4
GAS LIFT; 9,420.2
PACKER; 7,988.9
Seal Assembly; 7,960.7
Nipple - X; 7,942.9
Sensor - Discharge Gauge;
7,886.6
Mandrel GAS LIFT; 7,826.3
SURFACE; 34.4-7,046.8
7"Tie back string; 0.0-6,955.9
Mandrel GAS LIFT; 6,556.8
Mandrel GAS LIFT; 3,798.8
Production String 1 Cement;
32.0 ftKB
CONDUCTOR; 33.0-121.0
EMERGENCY SLIPS; 31.4
Hanger; 29.2
KUP PROD
KB-Grd (ft)
36.30
RR Date
9/18/2000
Other Elev
1D-36
...
TD
Act Btm (ftKB)
11,658.0
Well Attributes
Field Name
KUPARUK RIVER UNIT
Wellbore API/UWI
500292297300
Wellbore Status
PROD
Max Angle & MD
Incl (°)
62.25
MD (ftKB)
4,980.84
WELLNAME WELLBORE1D-36
Annotation
Last WO:
End Date
8/8/2024
H2S (ppm)
50
Date
12/16/2013
Comment
SSSV: NONE
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft)Type Com
11,420.0 11,484.0 6,430.3 6,460.7 C-2, C-1, 1D-36 7/12/2003 6.0 APERF 2.5"HSD 2506 PJ HMX 60
Deg Ph
Stimulation Intervals
Top (ftKB) Btm (ftKB)
Inter
val
Num
ber Type Subtype Start Date
Proppant
Designed (lb)
Proppant
Total (lb)
Vol Clean
Total (bbl)
Vol Slurry
Total (bbl)
11,410.0 11,420.0 1 FRAC 10/30/2000 0.0 0.00 0.00
Cement Squeezes
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Des Com
Pump Start
Date
32.0 6,914.0 32.0 4,230.8 Production
String 1
Cement
8/2/2024
1D-36, 9/3/2024 2:27:38 PM
Vertical schematic (actual)
LINER; 10,885.1-11,656.0
APERF; 11,420.0-11,484.0
IPERF; 11,410.0-11,420.0
FRAC; 11,410.0
WINDOW L1; 11,407.0-11,411.0
Whipstock; 11,410.0
LINER L1; 11,394.5-13,310.0
IPERF; 11,406.0-12,261.0
PACKER; 11,370.0
WINDOW L2; 11,360.0-11,364.0
PRODUCTION; 6,952.9-
11,038.4
NIPPLE; 10,839.4
GAS LIFT; 9,420.2
PACKER; 7,988.9
Seal Assembly; 7,960.7
Nipple - X; 7,942.9
Sensor - Discharge Gauge;
7,886.6
Mandrel GAS LIFT; 7,826.3
SURFACE; 34.4-7,046.8
7"Tie back string; 0.0-6,955.9
Mandrel GAS LIFT; 6,556.8
Mandrel GAS LIFT; 3,798.8
Production String 1 Cement;
32.0 ftKB
CONDUCTOR; 33.0-121.0
EMERGENCY SLIPS; 31.4
Hanger; 29.2
KUP PROD 1D-36
...
WELLNAME WELLBORE1D-36
ORIGINATED
TRANSMITTAL
DATE: 8/8/2024
ALASKA E-LINE SERVICES
TRANSMITTAL
#: 4942
42260 Kenai Spur Hwy
PO BOX 1481 - Kenai, Alaska 99611 FIELD Kuparuk
PH: (907) 283-7374 FAX: (907) 283-7378
DELIVERABLE DESCRIPTION
TICKET # WELL # API #
LOG
DESCRIPTION
DATE OF
LOG
4942 1D-36 50029229730000 Cement Bond Log 20-Jul-2024
RECIPIENTS
Conoco
DIGITAL FILES PRINTS CD'S
1 FTP Transfer 0 0 USPS
Attn: NSK-69
tom.osterkamp@conocophillips.com 700 G Street
Anchorage, AK 99503
Received
By: Received By:
Signature Signature
AOGCC
DIGITAL FILES PRINTS CD'S
1 SharePoint
Link 0 0 USPS
Attn: Natural Resources Technician II
abby.bell@alaska.gov Alaska Oil & Gas Conservation Commision
333 W. 7th Ave, Suite 100 - Anchorage, AK 99501
Received
By: Received By:
Signature Signature
200-130
T39381
Gavin Gluyas
Digitally signed by Gavin
Gluyas
Date: 2024.08.08 13:19:39
-08'00'
DNR
DIGITAL FILES PRINTS CD'S
1 SharePoint
Link 0 0 USPS
Attn: Natural Resource Tech II
DOG.Redata@alaska.gov 550 West 7th Ave, Suite #802 - Anchorage, AK 99501
Delivery Method: USPS
Received
By: Received By:
Signature Signature
Please return via e-mail a copy to both:
AR@ake-
line.com tom.osterkamp@conocophillips.com
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________KUPARUK RIV UNIT 1D-36
JBR 08/30/2024
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:1
3-1/2" & 5-1/2" joints. Bag FP-cycle/increase pressure for pass. 7" LPR not pressure tested due to height restrictions w/ donut
joint. Gave them the OK to test once tubing pulled & test plug used.
Test Results
TEST DATA
Rig Rep:Morales/YearoutOperator:ConocoPhillips Alaska, Inc.Operator Rep:Adams/Tuttle
Rig Owner/Rig No.:Nabors 7ES PTD#:2001300 DATE:7/18/2024
Type Operation:WRKOV Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopSAM240719141547
Inspector Austin McLeod
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 5.5
MASP:
2404
Sundry No:
324-315
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 2 P
Inside BOP 1 P
FSV Misc 0 NA
16 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13-5/8"FP
#1 Rams 1 3-1/2"x5-1/2"P
#2 Rams 1 Blinds P
#3 Rams 1 7"NT
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 3-1/8"P
Kill Line Valves 2 2"&3-1/8"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3100
Pressure After Closure P1500
200 PSI Attained P19
Full Pressure Attained P115
Blind Switch Covers:PAll stations
Bottle precharge P
Nitgn Btls# &psi (avg)P5@1970
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P21
#1 Rams P6
#2 Rams P6
#3 Rams P6
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
9
9 9 9999
9
9
9
9
Bag F 7" LPR not pressure tested due to height restrictions
test once tubing pulled & test plug used
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Replace Tubing
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address:Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?N/A
Yes No
9. Property Designation (Lease Number): 10. Field:
Kuparuk Oil Pool Kuparuk Oil Pool
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
11658 6542' 11450' 6445'2404 None
None
Casing Collapse
Conductor
Surface
Production
Tie-Back String
Liner
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone: 907-263-4597
Authorized Title:
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
KRU 1D-36
11410'-11420'
11420'-11484'
7949'
3-1/2"
6426'-6430'
6430'-6461'
11656'771'
3-1/2"
3-1/2"
6541'
Baker Premier
Baker ZXP Liner Top
Weatherford WS-R-BB
7"11007'
7013'
7978'
Perforation Depth MD (ft):
11038' 6245'
121'
7047'
4752'5-1/2"
20"
9-5/8"
88'
Burst
7827'
10926'
MD
121'
4297'
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0025650, ADL0025661
200-130
P.O. Box 100360, Anchorage, AK 99510 50-029-22973-00-00
ConocoPhillips Alaska, Inc
Proposed Pools:
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):
7989'MD/4757'TVD
10893'MD/6174' TVD
11370'MD/6406'TVD
Perforation Depth TVD (ft):
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Length Size
Kuparuk River Field
Shane Germann
shane.germann@conocophillips.com
CTD/RWO Engineer
Subsequent Form Required:
Suspension Expiration Date:
L-80
L-80
TVD
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
6/28/2024
By Grace Christianson at 8:58 am, May 29, 2024
Digitally signed by Shane Germann
DN: O=ConocoPhillips, CN=Shane
Germann, E=shane.germann@
conocophillips.com
Reason: I am the author of this document
Location:
Date: 2024.05.28 12:37:53-08'00'
Foxit PDF Editor Version: 13.0.0
324-315
X
VTL 6/24/2024 DSR-5/29/24
X
10-404
SFD 5/29/2024
BOP test to 3000 psig
Annular preventer to 2500 psig
*&:
Brett W. Huber, Sr.
Digitally signed by Brett W. Huber,
Sr.
Date: 2024.07.01 14:31:37 -08'00'07/01/24
RBDMS JSB 070224
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
May 23, 2024
Commissioner
State of Alaska
Alaska Oil & Gas Conservation Commission
333 West 7th Avenue Suite 100
Anchorage, Alaska 99501
Dear Commissioner:
Shane Germann
Senior Wells Engineer
CPAI Drilling and Wells
ConocoPhillips Alaska, Inc. hereby submits an Application for Sundry Approval to work over Kuparuk Producer 1D-36
(PTD# 200-130).
Well 1D-36 was drilled and completed in September of 2000 by Nabors 16E as a Kuparuk C-sand gas-lifted producer. In
2005, a dual lateral CTD sidetrack was performed in the C-sands. In 2015, a RWO was performed to fix a production
casing leak (just below 8074') by replacing the tubing and stacking a packer above the leak. In 2022, another RWO was
performed to address a surface casing leak at 132' by installing a 5-1/2" tieback liner to surface to provide a competent
OA for gas lift.
In August 2022, bubbling in the conductor was first noted then went dormant for ~5 months. The bubbling re-developed
in Spring 2023. A recent leak detect log showed a dominant signature at ~2700'.
If you have any questions or require any further information, please contact me at +1-406-670-1939.
In order to remedy the OOA x ATM communication we request approval to proceed with a RWO to perform a
subsidence-style repair on the 7" production casing and cement to surface. Tubing will be replaced with new as needed.
The 5.5" tieback liner will be re-ran as needed based on 7" casing condition.
Digitally signed by Shane Germann
DN: O=ConocoPhillips, CN=Shane
Germann, E=shane.germann@
conocophillips.com
Reason: I am the author of this
document
Location:
Date: 2024.05.28 12:38:20-08'00'
Foxit PDF Editor Version: 13.0.0
went dormant for ~5 months bubbling re-developed
in Spring 2023
bubbling in the conductor
1D-36 RWO Procedure
Kuparuk Producer - RWO
PTD #200-130
Page 1 of 3
Pre-Rig Work
1. SBHP
2. Set RBP
3. CMIT, DDT
4. MIT-OA
5. IC-POT, IC-PPPOT, T-PPPOT and T-POT tests.
6. Open lowest GLM in upper completion
7. Prepare well within 48 hrs of rig arrival.
Rig Work
MIRU
1. MIRU Nabors 7ES on 1D-36
2. Record shut-in pressures on the T & IA. If there is pressure, bleed off IA and/or tubing pressure and complete
30-minute NFT. Verify well is dead. Circulate KWF as needed.
3. Set BPV and confirm as barrier if needed, ND Tree, NU BOPE and test to 250/3,000 psi. Test annular 250/2,500
psi.
Retrieve 3.5” Tubing and 5.5” liner
4. Pull BPV, MU landing joint and BOLDS.
5. Pull 3-1/2” tubing from seal assembly (~7814’ MD)
6. Circulate well clean through 5.5” liner and 5.5”x7” annulus. Complete 30-minute NFT.
7. ND BOP stack, ND upper tubing head and remove packoffs. NU BOP stack to lower tubing head.
a. Unable to test BOPE flange break at this point due to removal of packoffs, will test after 5.5” has been
retrieved.
8. Spear 5.5” liner and POOH laying down. Install test plug and test flange break to 250/3000 psi. Remove test
plug.
7” Casing Subsidence-Style Repair
9. RU E-line: Run CBL and log from ~7500’ MD back to surface. Confirm if any fill behind 7” casing.
10. Set RBP at or below surface casing shoe depth, confirm plug is set and perform 30 min NFT, dump 50’ of sand
on top of RBP.
11. ND BOPE and ND tubing head. Remove packoffs. NU BOPE to production casing head.
a. Unable to test BOPE flange break at this point due to removal of packoffs, will test after 7” has been
retrieved.
12. RIH to cut 7” casing above the surface casing shoe and any fill observed from CBL, TOOH and stand back DP
13. Spear the casing and circulate out the OA until clean.
14. POOH and lay down the 7” casing.
15. Install test plug and test flange break to 250/3000 psi. Remove test plug.
16. RIH w/ tandem string mills to gauge the 9-5/8” casing for the ES cementer, ICP, and Sealing Overshot.
17. RIH and dress off 7” casing stump.
18. RU casing crew and RIH w/ new 7” casing, ES Cementer, 7” x 9-5/8” inflatable casing packer, and sealing
overshot. PT casing to 2500 psi. Set packer.
19. RU cementer and cement 7” x 9-5/8” annulus to surface
1D-36 RWO Procedure
Kuparuk Producer - RWO
PTD #200-130
Page 2 of 3
20. Perform 30 min NFT. ND BOPE, pull 7” casing in tension and land in the slips. Cut excess 7” casing with Wachs
cutter and install IC packoffs.
21. NU new tubing head and BOP stack. Test flange break to 250/3000 psi.
22. Mill cement/plugs in cementer. POOH standing back drillpipe.
23. Pressure test the casing to 2500 psi, chart for 30 minutes
24. RIH w/ wash string assembly and circulate out sand on top of RBP. POOH standing back drillpipe.
25. Pull RBP
Install in 3-½” Completion
19. MU 3 ½” completion with seal assembly, nipple profiles, DHG, control line, and GLM’s. RIH with completion.
a. Note: Depending on 7” casing integrity, there will be a contingency plan to re-run a 5.5” liner to surface
like how the well is currently constructed.
20. Once on depth, circulate CI brine, space out as needed, land hanger, RILDS.
21. Pressure test tubing to 3000 psi for 30 minutes and chart.
22. Pressure test inner annulus to 2500 psi for 30 minutes and chart.
ND BOP, NU Tree
23. Confirm pressure tests, then shear out SOV with pressure differential.
24. Install BPV.
25. ND BOPE. NU tree. PT tree.
26. Pull BPV, freeze protect well at opportune time, and set BPV if necessary.
27. RDMO.
Post-Rig Work
28. Install GLD.
29. Pull Ball and Rod if necessary.
30. Pull any remaining plugs in well.
31. Turn over to operations.
1D-36 RWO Procedure
Kuparuk Producer - RWO
PTD #200-130
Page 3 of 3
Following subject to change/be updated with pre-rig work:
MIT results:
MIT-T: Passed (3000 psig, 6/16/2022)
MIT-IA: Passed (2500 psig, 6/16/2022)
MIT-OA: Passed (1800 psig, 7/29/2023)
IC POT & PPPOT: TBD
TBG POT & PPPOT: TBD
MPSP: 2404 psi using 0.1 psi/ft gradient
Static BHP: 3034 psi / 6300’ TVD measured on 08/08//2023
General Well info:
Wellhead type/pressure rating:FMC Gen V, 5M psi top flange x 5M bottom flange
Production Engineer:Banabas Dogah
Reservoir Development Engineer:Cody Keith
Estimated Start Date:6/28/2024
Workover Engineer:Shane Germann (406-670-1939 / shane.germann@conocophillips.com)
Current Operations:This well is currently shut in.
Well Type:Producer
Scope of Work:Pull the existing 3-1/2” completion and 5-1/2” liner, perform subsidence-style repair on 7” production
casing, and install a new 3-1/2” completion. Contingency to re-install 5-1/2” liner based on 7” casing condition.
BOP configuration:Annular / Pipe Rams / Blind Rams / Pipe Ram
Last Tag
Annotation Depth (ftKB) Wellbore End Date Last Mod By
Last Tag:11,450.0 1D-36 4/30/2005 WV5.3
Conversion
Last Rev Reason
Annotation Wellbore End Date Last Mod By
Rev Reason: Pull RBP 1D-36 8/7/2023 praffer
Notes: General & Safety
Annotation End Date Last Mod By
NOTE: MULTI-LATERAL WELL: 1D-36, 1D-36L1,1D-36L2 ALL C-SANDS 8/1/2005 lmosbor
Casing Strings
Csg Des OD (in) ID (in) Top (ftKB)
Set Depth
(ftKB)
Set Depth
(TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread
CONDUCTOR 20 19.25 33.0 121.0 121.0 72.00 H-40 Welded
SURFACE 9 5/8 8.70 34.4 7,046.8 4,297.1 40.00 L-80 BTCM
PRODUCTION 7 6.28 31.4 11,038.4 6,244.8 26.00 L-80 BTCM
Tie-Back String 5 1/2 4.90 29.2 7,977.7 4,751.9 15.50 L-80 HYD 563
WINDOW L2 3 1/2 2.99 11,360.0 11,364.0 6,403.2 9.30 L-80 SLHT
WINDOW L1 3 1/2 2.99 11,407.0 11,411.0 6,426.0 9.30 L-80
LINER 3 1/2 2.99 10,885.2 11,656.0 6,541.2 9.30 L-80 SLHT
Tubing Strings: string max indicates LONGEST segment of string
Top (ftKB)
27.1
Set Depth …
7,826.9
Set Depth …
4,679.4
String Ma…
3 1/2
Tubing Description
Tubing – Production
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE-M
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
27.1 27.1 0.03 Hanger 7.125 Tubing Hanger, FMC 3.5" x 7 1/16",
3 1/2" EUE Box x Box
FMC TC-1A-
EN
2.952
515.9 515.5 6.37 Nipple - X 3.770 2.813" X-Nipple SN# 0004180362-
19
HES X 2.813
3,452.2 2,494.7 54.35 Mandrel – GAS
LIFT
4.730 Camco KBG-2-9 2.818
5,655.2 3,603.0 59.39 Mandrel – GAS
LIFT
4.730 Camco KBG-2-9 2.818
6,959.4 4,253.4 60.32 Mandrel – GAS
LIFT
4.740 Camco KBG-2-9 2.818
7,699.2 4,617.7 60.59 Mandrel – GAS
LIFT
4.740 Camco KBG-2-9 2.818
7,757.5 4,646.0 61.26 Nipple - X 3.770 2.813" X-Nipple SN# 0004180362-
14
HES X 2.813
7,809.7 4,671.1 61.11 Locator 4.510 Baker GBH-22 Locator 3 1/2" EUE
Box
Baker GBH-22 2.990
7,811.0 4,671.7 61.10 Seal Assembly 3.980 Baker 80-40 GBH-22 Seal Assembly
(2.41' from fully located)
Baker GBH-22
80-40
2.990
Top (ftKB)
7,963.4
Set Depth …
10,926.2
Set Depth …
6,190.0
String Ma…
3 1/2
Tubing Description
Tubing – Production
Wt (lb/ft)
9.30
Grade
L-80
Top Connection
EUE 8RD
ID (in)
2.99
Completion Details: excludes tubing, pup, space out, thread, RKB...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal
ID (in)
7,963.4 4,745.2 61.74 PBR 5.000 Baker 80-40 PBR Baker 80-40 4.000
7,988.9 4,757.2 61.68 PACKER 5.970 Baker 3½ x 7'' Premier Packer Baker 598-287
Premier
2.860
9,420.2 5,454.8 60.66 GAS LIFT 4.730 Camco MMG 2.915
10,839.4 6,147.7 60.99 NIPPLE 3.500 Landing Nipple 2.813 DS Profile Camco 2.813
DS
2.813
10,888.8 6,171.7 60.83 LOCATOR 4.000 Baker locator sub with 3-ft spaceout Baker 80-40 2.990
10,890.0 6,172.3 60.83 SEAL ASSY 3.980 80-40 Baker Seal Assy. Baker 80-40 2.990
Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.)
Top (ftKB)
Top (TVD)
(ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in)
29.2 29.2 0.03 EMERGENCY
SLIPS
5 1/2" x 11 emergency slips FMC 6/1/2022 5.500
31.4 31.4 0.03 EMERGENCY
SLIPS
7" x 11" emergency slips FMC 5/29/2022 7.000
7,855.6 4,693.4 60.81 MANDREL
INSERT
3 1/2" x 1" KBG-2-9 GLM, Set
DMY on BTM latch 07-08-22.
GLM station # 5. [EXCEPTION
of Mandrel in CASING]
CAMCO KBG-2-9 23057
-02
6/1/2022 2.818
11,370.0 6,406.1 60.85 PACKER Weatherford WS-R-BB
Packer Set in Main Bore Liner
7/22/2005 1.250
11,410.0 6,425.5 61.26 Whipstock WHIPSTOCK TO L1, set
7/22/2005
7/22/2005 1.250
Mandrel Inserts : excludes pulled inserts
Top (ftKB)
Top (TVD)
(ftKB)
Top
Incl (°)
St
ati
on
No
/S Serv
Valve
Type
Latch
Type
OD
(in)
TRO Run
(psi) Run Date Com Make Model
Port
Size (in)
3,452.2 2,494.7 54.35 1 GAS LIFT GLV INT 1 1,279.0 7/3/2023 Schlumb
erger
KBG-2-9 0.188
5,655.2 3,603.0 59.39 2 GAS LIFT GLV INT 1 1,274.0 7/3/2023 Schlumb
erger
KBG-2-9 0.188
6,959.4 4,253.4 60.32 3 GAS LIFT OV INT 1 0.0 7/2/2023 Schlumb
erger
KBG-2-9 0.250
7,699.2 4,617.7 60.59 4 GAS LIFT DMY INT 1 0.0 6/12/2022 Schlumb
erger
KGB-2-9 0.000
1D-36, 8/8/2023 5:35:11 AM
Vertical schematic (actual)
LINER; 10,885.1-11,656.0
SHOE; 11,654.2-11,656.0
LINER COLLAR; 11,621.8-
11,623.2
LINER COLLAR; 11,589.7-
11,591.0
APERF; 11,420.0-11,484.0
FRAC; 11,410.0
IPERF; 11,410.0-11,420.0
WINDOW L1; 11,407.0-11,411.0
Whipstock; 11,410.0
LINER L1; 11,394.5-13,310.0
WINDOW to L1; 11,407.0-
11,411.0
IPERF; 11,406.0-12,261.0
DEPLOY; 11,394.5-11,395.3
PACKER; 11,370.0
WINDOW L2; 11,360.0-11,364.0
WINDOW to L2; 11,360.0-
11,364.0
PRODUCTION; 6.2-11,038.4
NIPPLE; 10,971.2-10,972.6
SBE; 10,912.5-10,934.4
SEAL ASSY; 10,890.0
HANGER; 10,900.0-10,912.5
PACKER; 10,892.5-10,900.0
LOCATOR; 10,888.8
TIE BACK; 10,885.1-10,892.5
NIPPLE; 10,839.4
GAS LIFT; 9,420.2
PACKER; 7,988.9
Tie-Back String; 29.2-7,977.7
PBR; 7,963.4
Seal Assembly; 7,963.6-7,977.7
Locator; 7,962.4-7,963.6
Tubing; 7,924.9-7,962.4
Tubing; 7,914.7-7,924.9
Nipple - X; 7,913.7-7,914.7
Tubing; 7,862.5-7,913.7
MANDREL INSERT; 7,855.6
Mandrel – GAS LIFT; 7,855.6-
7,862.5
Tubing; 7,845.3-7,855.6
Tubing; 7,835.1-7,845.3
Tubing; 7,833.5-7,835.1
Tubing; 7,832.1-7,833.5
SBR; 7,814.0-7,832.1
Seal Assembly; 7,811.0
Locator; 7,809.7
Nipple - X; 7,757.5
Mandrel – GAS LIFT; 7,699.2
SURFACE; 34.4-7,046.8
FLOAT SHOE; 7,045.1-7,046.8
FLOAT COLLAR; 6,967.5-
6,969.1
Mandrel – GAS LIFT; 6,959.4
Mandrel – GAS LIFT; 5,655.2
Annular Fluid - Seawater;
2,000.0-7,988.9; 5/29/2022
Annular Fluid - Seawater;
2,000.0-7,811.0; 6/2/2022
Mandrel – GAS LIFT; 3,452.2
Annular Fluid - Diesel; 29.2-
2,000.0; 6/2/2022
Annular Fluid - Diesel; 27.1-
2,000.0; 6/2/2022
Nipple - X; 515.9
CONDUCTOR; 33.0-121.0
HANGER; 34.4-36.5
EMERGENCY SLIPS; 31.4
EMERGENCY SLIPS; 29.2
Hanger; 27.1
KUP PROD
KB-Grd (ft)
36.30
RR Date
9/18/2000
Other Elev…
1D-36
...
TD
Act Btm (ftKB)
11,658.0
Well Attributes
Field Name
KUPARUK RIVER UNIT
Wellbore API/UWI
500292297300
Wellbore Status
PROD
Max Angle & MD
Incl (°)
62.25
MD (ftKB)
4,980.84
WELLNAME WELLBORE1D-36
Annotation
Last WO:
End Date
6/3/2022
H2S (ppm)
50
Date
12/16/2013
Comment
SSSV: NONE
Mandrel Inserts : excludes pulled inserts
Top (ftKB)
Top (TVD)
(ftKB)
Top
Incl (°)
St
ati
on
No
/S Serv
Valve
Type
Latch
Type
OD
(in)
TRO Run
(psi) Run Date Com Make Model
Port
Size (in)
9,420.2 5,454.8 60.66 5 PROD DMY RK 1 1/2 0.0 11/17/2015 0.000
Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe...
Top (ftKB)
Top (TVD)
(ftKB)
Top Incl
(°) Item Des
OD
Nominal
(in)Com Make Model
Nominal ID
(in)
7,812.3 4,672.3 61.10 XO Reducing 6.020 5 1/2" Hyd 563 Box x 5" H521 Box
xo (1.76" No-go at 1.11')
4.370
7,814.0 4,673.2 61.08 SBR 4.990 Baker 80-40 SBR, 5" H521 Pin x 4
1/2" H521 Box
Baker 80-40 SBR 4.000
7,855.6 4,693.3 60.81 Mandrel – GAS
LIFT
4.720 Camco KBG-2-9 2.818
7,913.7 4,721.5 61.34 Nipple - X 3.770 HES 3.5" x 2.813" X Nipple SN#
0004180362-12
HES X Nipple 2.813
7,962.4 4,744.7 61.75 Locator 4.510 Baker GBH-22 Locator ( Located
1' off tag @ 7963.4')
Baker Locator 2.990
10,885.2 6,169.9 60.84 TIE BACK 6.000 LINER TIE BACK SLEEVE 5.500
10,892.5 6,173.5 60.82 PACKER 5.980 BAKER ZXP LINER TOP
PACKER
4.408
10,971.2 6,212.0 60.62 NIPPLE 4.540 HES 'XN' NIPPLE w/2.75 NO GO
PROFILE
2.750
Perforations & Slots
Top (ftKB) Btm (ftKB)
Top (TVD)
(ftKB)
Btm (TVD)
(ftKB) Linked Zone Date
Shot
Dens
(shots/ft)Type Com
11,410.0 11,420.0 6,425.5 6,430.3 C-2, 1D-36 10/28/2000 4.0 IPERF 2.5" BH HSD
11,420.0 11,484.0 6,430.3 6,460.7 C-2, C-1, 1D-36 7/12/2003 6.0 APERF 2.5"HSD 2506 PJ HMX 60
Deg Ph
Stimulation Intervals
Top (ftKB) Btm (ftKB)
Inter
val
Num
ber Type Subtype Start Date
Proppant
Designed (lb)
Proppant
Total (lb)
Vol Clean
Total (bbl)
Vol Slurry
Total (bbl)
11,410.0 11,420.0 1 FRAC 10/30/2000 0.0 0.00 0.00
1D-36, 8/8/2023 5:35:12 AM
Vertical schematic (actual)
LINER; 10,885.1-11,656.0
SHOE; 11,654.2-11,656.0
LINER COLLAR; 11,621.8-
11,623.2
LINER COLLAR; 11,589.7-
11,591.0
APERF; 11,420.0-11,484.0
FRAC; 11,410.0
IPERF; 11,410.0-11,420.0
WINDOW L1; 11,407.0-11,411.0
Whipstock; 11,410.0
LINER L1; 11,394.5-13,310.0
WINDOW to L1; 11,407.0-
11,411.0
IPERF; 11,406.0-12,261.0
DEPLOY; 11,394.5-11,395.3
PACKER; 11,370.0
WINDOW L2; 11,360.0-11,364.0
WINDOW to L2; 11,360.0-
11,364.0
PRODUCTION; 6.2-11,038.4
NIPPLE; 10,971.2-10,972.6
SBE; 10,912.5-10,934.4
SEAL ASSY; 10,890.0
HANGER; 10,900.0-10,912.5
PACKER; 10,892.5-10,900.0
LOCATOR; 10,888.8
TIE BACK; 10,885.1-10,892.5
NIPPLE; 10,839.4
GAS LIFT; 9,420.2
PACKER; 7,988.9
Tie-Back String; 29.2-7,977.7
PBR; 7,963.4
Seal Assembly; 7,963.6-7,977.7
Locator; 7,962.4-7,963.6
Tubing; 7,924.9-7,962.4
Tubing; 7,914.7-7,924.9
Nipple - X; 7,913.7-7,914.7
Tubing; 7,862.5-7,913.7
MANDREL INSERT; 7,855.6
Mandrel – GAS LIFT; 7,855.6-
7,862.5
Tubing; 7,845.3-7,855.6
Tubing; 7,835.1-7,845.3
Tubing; 7,833.5-7,835.1
Tubing; 7,832.1-7,833.5
SBR; 7,814.0-7,832.1
Seal Assembly; 7,811.0
Locator; 7,809.7
Nipple - X; 7,757.5
Mandrel – GAS LIFT; 7,699.2
SURFACE; 34.4-7,046.8
FLOAT SHOE; 7,045.1-7,046.8
FLOAT COLLAR; 6,967.5-
6,969.1
Mandrel – GAS LIFT; 6,959.4
Mandrel – GAS LIFT; 5,655.2
Annular Fluid - Seawater;
2,000.0-7,988.9; 5/29/2022
Annular Fluid - Seawater;
2,000.0-7,811.0; 6/2/2022
Mandrel – GAS LIFT; 3,452.2
Annular Fluid - Diesel; 29.2-
2,000.0; 6/2/2022
Annular Fluid - Diesel; 27.1-
2,000.0; 6/2/2022
Nipple - X; 515.9
CONDUCTOR; 33.0-121.0
HANGER; 34.4-36.5
EMERGENCY SLIPS; 31.4
EMERGENCY SLIPS; 29.2
Hanger; 27.1
KUP PROD 1D-36
...
WELLNAME WELLBORE1D-36
1D-36 Proposed RWO Schematic
COMPLETION INFO OD
(in)
Nom. ID
(in)
MD
(ft RKB)
TVD
(ft RKB)
Weight
(lb/ft)Grade Thread
Conductor 20 19.25 121 121 72 H-40 Welded
Surface Casing 9-5/8"8.7 7047 4297 40 L-80 BTCM
Production Casing 7"6.28 11038 6245 26 L-80 BTCM
Production Liner 3-1/2"2.992 11656 6541 9.3 L-80 SLHT
Tie-Back Liner 5-1/2"4.9 7977 4752 15.5 L-80 HYD563
Tubing 3-1/2"2.992 7827 4679 9.3 L-80 EUE-Mod
PROPOSED COMPLETION
Production Tubing:
3-1/2" 9.3# L-80 EUETubing to surface
3-1/2" x 1.5" MMG GLM @ 3789'
3-1/2" x 1.5" MMG GLM @ 6562'
3-1/2" x 1.5" MMG GLM @ 7850'
3-1/2" Gauge @ ~7890'
2.813" X-nipple @ 7913'
3-1/2" Baker 80-40 GBH-22 seal assembly @ 7963'
Lower Completion:
3-1/2" x 7" Baker Premier packer @ 7963'
3-1/2" x 1-1/2" MMG GLM @ 9240'
2.813" DS-nipple @ 10,839'
Surface Casing
Production Liner
Conductor
1D-36L2 TD @ 13,302'
1D-36L1 TD @ 13,548'
Production Casing
1D-36 Plan Forward AOGCC ReviewApril 4, 2024
1D-36 Overview•Well History/ ConditionKuparuk gas lifted producer Drilled and completed in 2000 (frac’d producer)Dual-lat CTD in 2005 (L2 = C3/4, L1 = C1/2)Open SC shoe (7” x 9-5/8” is open to overburden)West Sak formation is behind surf csg & cementedSurface casing leak identified in Jan 2021Spill in conductor, SCLD locates SCL at ~132’Waivered for natural production with OAxATM but didn’t flow. RWO in June 2022New 3.5” and 5.5”. Grow & stretch 7” casing3.5”, 5.5” & 7” all have integrityWaivered for gas lift production with OOAxATMO9-5/8” Surface casing leak at ~132’ (OOAxAtm) remainsSC TD at 7047’MD/4297’TVDEst. Subsidence = 88.3” (3.7” per year)COMPLETION INFOOD (in)Nom. ID (in)MD (ft RKB)TVD (ft RKB)Weight (lb/ft)Grade Thread Conductor20 19.25 121 121 72 H-40 WeldedSurface Casing9-5/8" 8.7 7047 4297 40 L-80 BTCMProduction Casing 7" 6.28 11038 6245 26 L-80 BTCMProduction Liner3-1/2" 2.992 11656 6541 9.3 L-80 SLHTTie-Back Liner5-1/2" 4.9 7977 4752 15.5 L-80 HYD563Tubing3-1/2" 2.992 7827 4679 9.3 L-80 EUE-ModWest Sak 5807' MD/ 3680' TVD6438' MD/ 3995' TVDCURRENT COMPLETIONProduction Tubing:3-1/2" 9.3# L-80 EUETubing to surface3-1/2" 2.813" 'X' Nipple ~500' RKB3-1/2" x 1" Camco KBG-2-9 GLM @ 3452'3-1/2" x 1" Camco KBG-2-9 GLM @ 5655'3-1/2" x 1" Camco KBG-2-9 GLM @ 6959'3-1/2" x 1" Camco KBG-2-9 GLM @ 7699'2.813" X-nipple @ 7757'3-1/2" Baker 80-40 GBH-22 seal assembly @ 7810'Tie-Back Liner:5-1/2" 15.5# L-80 HYD563 MS to surfaceBaker 80-40 SBR @ 7814'XO to 3-1/2" EUE3-1/2" x 1" Camco KBG-2-9 GLM @ 7855'2.813" X-nipple @ 7913'3-1/2" Baker GBH-22 Locator and seal assembly @ 7963'Lower Completion:3-1/2" x 7" Baker Premier packer @ 7963'3-1/2" x 1-1/2" MMG GLM @ 9240'2.813" DS-nipple @ 10,839'3-1/2" x 7" Baker ZXP packer @ 10,912'2.75" XN-nipple @ 10,971'Surface CasingProduction LinerConductor1D-36L2 TD @ 13,302'1D-36L1 TD @ 13,548' Production Casing7047’MD/4297’TVD11038’MD/6245’TVD121’MD/121’TVDKnown Surface casing leak at ~132’
1D-36 Overview•Later 2022, intermittent bubbling in conductor Bubbling developed post-RWOStandard and Isotopic gas samples taken. Indicate:Not process gas or Kuparuk reservoir gasNot consistent with biogenic/swamp gasMore consistent to shallow sand origin. Lacking data to characterize exclusively.Bubbling stopped in December 2022 (assume froze path to surface. Then re-developed in May 2023.)Run VIVID Seal log July 2023, reviewed details with AOGCC Sept 2023.Acoustic signal depths were located at ~600, ~2000’ & ~2700’.Geologist have interpreted the ~2700' depth as a hydrate zoneBased off the acoustic responses ~90% of the leaks to surface are coming from above the K-15 markerIncreased acoustic responses were observed when bleeding pressure off the OOA.COMPLETION INFOOD (in)Nom. ID (in)MD (ft RKB)TVD (ft RKB)Weight (lb/ft)Grade Thread Conductor20 19.25 121 121 72 H-40 WeldedSurface Casing9-5/8" 8.7 7047 4297 40 L-80 BTCMProduction Casing 7" 6.28 11038 6245 26 L-80 BTCMProduction Liner3-1/2" 2.992 11656 6541 9.3 L-80 SLHTTie-Back Liner5-1/2" 4.9 7977 4752 15.5 L-80 HYD563Tubing3-1/2" 2.992 7827 4679 9.3 L-80 EUE-ModWest Sak 5807' MD/ 3680' TVD6438' MD/ 3995' TVDCURRENT COMPLETIONProduction Tubing:3-1/2" 9.3# L-80 EUETubing to surface3-1/2" 2.813" 'X' Nipple ~500' RKB3-1/2" x 1" Camco KBG-2-9 GLM @ 3452'3-1/2" x 1" Camco KBG-2-9 GLM @ 5655'3-1/2" x 1" Camco KBG-2-9 GLM @ 6959'3-1/2" x 1" Camco KBG-2-9 GLM @ 7699'2.813" X-nipple @ 7757'3-1/2" Baker 80-40 GBH-22 seal assembly @ 7810'Tie-Back Liner:5-1/2" 15.5# L-80 HYD563 MS to surfaceBaker 80-40 SBR @ 7814'XO to 3-1/2" EUE3-1/2" x 1" Camco KBG-2-9 GLM @ 7855'2.813" X-nipple @ 7913'3-1/2" Baker GBH-22 Locator and seal assembly @ 7963'Lower Completion:3-1/2" x 7" Baker Premier packer @ 7963'3-1/2" x 1-1/2" MMG GLM @ 9240'2.813" DS-nipple @ 10,839'3-1/2" x 7" Baker ZXP packer @ 10,912'2.75" XN-nipple @ 10,971'Surface CasingProduction LinerConductor1D-36L2 TD @ 13,302'1D-36L1 TD @ 13,548' Production Casing7047’MD/4297’TVD11038’MD/6245’TVD121’MD/121’TVDKnown Surface casing leak at ~132’
1D-36 Overview•Intermittent bubbling in conductor Plan forward review with AOGCC in Sept 2023Pump heavy brine down OOA and monitor over the Winter.Pumped 10ppg brine down OOA Sept 2023Diagnostics to inform on remediation109 out of 199 bbls pumped due to unknown fluid path (no returns)Subsequent pumping heavy brine the bubbling in the conductor was not observed for several weeks and then only rarely until approximately mid-January 2024 when bubbling was once again observed at a regular interval.Overall the bubbling has continued to be minimal and intermittent.COMPLETION INFOOD (in)Nom. ID (in)MD (ft RKB)TVD (ft RKB)Weight (lb/ft)Grade Thread Conductor20 19.25 121 121 72 H-40 WeldedSurface Casing9-5/8" 8.7 7047 4297 40 L-80 BTCMProduction Casing 7" 6.28 11038 6245 26 L-80 BTCMProduction Liner3-1/2" 2.992 11656 6541 9.3 L-80 SLHTTie-Back Liner5-1/2" 4.9 7977 4752 15.5 L-80 HYD563Tubing3-1/2" 2.992 7827 4679 9.3 L-80 EUE-ModWest Sak 5807' MD/ 3680' TVD6438' MD/ 3995' TVDCURRENT COMPLETIONProduction Tubing:3-1/2" 9.3# L-80 EUETubing to surface3-1/2" 2.813" 'X' Nipple ~500' RKB3-1/2" x 1" Camco KBG-2-9 GLM @ 3452'3-1/2" x 1" Camco KBG-2-9 GLM @ 5655'3-1/2" x 1" Camco KBG-2-9 GLM @ 6959'3-1/2" x 1" Camco KBG-2-9 GLM @ 7699'2.813" X-nipple @ 7757'3-1/2" Baker 80-40 GBH-22 seal assembly @ 7810'Tie-Back Liner:5-1/2" 15.5# L-80 HYD563 MS to surfaceBaker 80-40 SBR @ 7814'XO to 3-1/2" EUE3-1/2" x 1" Camco KBG-2-9 GLM @ 7855'2.813" X-nipple @ 7913'3-1/2" Baker GBH-22 Locator and seal assembly @ 7963'Lower Completion:3-1/2" x 7" Baker Premier packer @ 7963'3-1/2" x 1-1/2" MMG GLM @ 9240'2.813" DS-nipple @ 10,839'3-1/2" x 7" Baker ZXP packer @ 10,912'2.75" XN-nipple @ 10,971'Surface CasingProduction LinerConductor1D-36L2 TD @ 13,302'1D-36L1 TD @ 13,548' Production Casing7047’MD/4297’TVD11038’MD/6245’TVD121’MD/121’TVDKnown Surface casing leak at ~132’~2700’
1D-36 RWO Scope•SScopeSubsidence-like, cut and pull 7” and cement to surface•Assumptions:Isolated from formation via plug•RWOO StepsPull 3.5” tubing from sealsPull 5.5” liner from sealsSet RBP in 7”Cut and pull 7” from below West SakPerform cleanout/milling runs through 9-5/8” SCRun new 7” casing w/ overshot, 7 x 9-5/8” packer and H ES cementerCement 7” to surfaceRun 5.5” liner and 3.5” tubing•Considerations:Cut/Pull, Set packer above WSPressure build-up under packerRe-run 5.5” and 3.5” tubulars/jewelryShallow SC leak complicating cementing ops•Otherr Scopess Considered:Perf 7” and squeeze through cement retainerTwo rig-up RWO, cementing/diagnostics done off-rigStraddling multiple HE packers across leak points in 9-5/8”HybridCOMPLETION INFOOD (in)Nom. ID (in)MD (ft RKB)TVD (ft RKB)Weight (lb/ft)Grade Thread Conductor20 19.25 121 121 72 H-40 WeldedSurface Casing9-5/8" 8.7 7047 4297 40 L-80 BTCMProduction Casing 7" 6.28 11038 6245 26L-80 BTCMProduction Liner3-1/2" 2.992 11656 6541 9.3 L-80 SLHTTie-Back Liner5-1/2" 4.9 7977 4752 15.5 L-80 HYD563Tubing3-1/2" 2.992 7827 4679 9.3 L-80 EUE-ModWest SakPROPOSED COMPLETIONProduction Tubing:3-1/2" 9.3# L-80 EUETubing to surface3-1/2" 2.813" 'X' Nipple ~500' RKB3-1/2" x 1" Camco KBG-2-9 GLM @ 3452'3-1/2" x 1" Camco KBG-2-9 GLM @ 5655'3-1/2" x 1" Camco KBG-2-9 GLM @ 6959'3-1/2" x 1" Camco KBG-2-9 GLM @ 7699'2.813" X-nipple @ 7757'3-1/2" Baker 80-40 GBH-22 seal assembly @ 7810'Tie-Back Liner:5-1/2" 15.5# L-80 HYD563 MS to surfaceBaker 80-40 SBR @ 7814'XO to 3-1/2" EUE3-1/2" x 1" Camco KBG-2-9 GLM @ 7855'2.813" X-nipple @ 7913'3-1/2" Baker GBH-22 Locator and seal assembly @ 7963'Lower Completion:3-1/2" x 7" Baker Premier packer @ 7963'3-1/2" x 1-1/2" MMG GLM @ 9240'2.813" DS-nipple @ 10,839'3-1/2" x 7" Baker ZXP packer @ 10,912'2.75" XN-nipple @ 10,971'Surface CasingProduction LinerConductor1D-36L2 TD @ 13,302'1D-36L1 TD @ 13,548' Production CasingW
TT RR AA NN SS MM II TT TT AA LL
FROM::Sandra D. Lemke, ATO-704 TO:: Meredith Guhl
ConocoPhillips Alaska, Inc. AOGCC
P.O. Box 100360 330 W. 7
th Ave., Suite 100
Anchorage AK 99510-0360 Anchorage, Alaska 99501
RE: Schlumberger Wireline Backlog – Kuparuk River Unit
DATE: 12/19/2023
Transmitted:
North Slope, Kuparuk River Unit
Via hard drive data drop
1D-07 50-029-20430-00
179112_1D-07_SCMT_14Oct23
1D-11 50-029-22946-00
199072_1D-11_IPROF_04Apr2022
1D-117 50-029-22844-00
197237_1D-117_RBP_10Jun2022
1D-135 50-029-22816-00
197184_1D-135_LDL_05Jun2022
1D-30 50-029-22965-00
2000104_1D-30_Plug_11May2023
1D-34 50-029-22975-00
200143_1D-34_CHC_02Aug2022
1D-36 50-029-22973-00
200130_1D-36_RBP_19Jul2023
_1E-02 50-029-20472-00
180050_1E-02_CHC_29Mar2023
180050_1E-02_RBP_24Mar2023
_1E-102 50-029-23236-00
204231_1E-102_Pres-Temp_29Jul2023
_1E-12L1 50-029-20736-60
210004_1E-12_JetCutter_12Jun2022
210004_1E-12_MechCutter_06Jun2022
210004_1E-12_SBHPS-RBP-LDL_03Jun2022
2of 12
Transmittall instructions: please promptly sign, scan, and e-mail to Sandra.D.Lemke@conocophillips.com
Receipt: Date:
Alaska/IT-Support Services GGRE |ConocoPhillips Alaska |Office: 907.265.6947; Mobile 907.440.4512
T38317
T38318
T38321
T38322
T38323
T38324
T38325
T38326
T38327
T38328
2/29/2024
1D-36 50-029-22973-00
200130_1D-36_RBP_19Jul2023
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2024.02.29
11:18:42 -09'00'
C:\Users\kmjunke\AppData\Local\Microsoft\Windows\INetCache\Content.Outlook\H2LGR515\2023-07-25_22108_KRU_1D-36_ArcherAcousticVivid_VividSeal_Day7-8_Transmittal.docx
DELIVERABLE DISCRIPTION
Ticket # Field Well # API # Log Description Log Date
22108 KRU 1D-36 50-029-22973-00 Archer Acoustic VIVID and Vivid Seal 25-Jul-23 (Day 7&8)
DELIVERED TO
Company & Address
DIGITAL FILE
# of Copies
LOG PRINTS
# of Prints
CD’s
# of Copies
1
AOGCC
Attn: Natural Resources Technician
333 W. 7th Ave., Suite 100
Anchorage, Ak. 99501-3539
Delivered By: CPAI Sharefile
______________________________ ______________________________________
Date received Signature
PLEASE RETURN COPY VIA EMAIL TO:
DIANE.WILLIAMS@READCASEDHOLE.COM
READ CASED HOLE, INC., 4141 B STREET, SUITE 308, ANCHORAGE, AK 99503
PHONE: (907)245-8951
E-MAIL : READ-Anchorage@readcasedhole.com WEBSITE : WWW.READCASEDHOLE.COM
PTD: 200-130
T37919
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.08.10
13:29:26 -08'00'
C:\Users\kmjunke\AppData\Local\Microsoft\Windows\INetCache\Content.Outlook\H2LGR515\2023-07-23_22107_KRU_1D-36_ArcherAcousticVivid_VividSeal_Day5-6_Transmittal.docx
DELIVERABLE DISCRIPTION
Ticket # Field Well # API # Log Description Log Date
22107 KRU 1D-36 50-029-22973-00 Archer Acoustic VIVID and Vivid Seal 23-Jul-23 (Day 5&6)
DELIVERED TO
Company & Address
DIGITAL FILE
# of Copies
LOG PRINTS
# of Prints
CD’s
# of Copies
1
AOGCC
Attn: Natural Resources Technician
333 W. 7th Ave., Suite 100
Anchorage, Ak. 99501-3539
Delivered By: CPAI Sharefile
______________________________ ______________________________________
Date received Signature
PLEASE RETURN COPY VIA EMAIL TO:
DIANE.WILLIAMS@READCASEDHOLE.COM
READ CASED HOLE, INC., 4141 B STREET, SUITE 308, ANCHORAGE, AK 99503
PHONE: (907)245-8951
E-MAIL : READ-Anchorage@readcasedhole.com WEBSITE : WWW.READCASEDHOLE.COM
PTD: 200-130
T37919
Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.08.10
13:23:03 -08'00'
C:\Users\kmjunke\AppData\Local\Microsoft\Windows\INetCache\Content.Outlook\H2LGR515\2023-07-08_20272_KRU_1D-36_ArcherAcousticVivid_VividSeal_Day1-3_Transmittal.docx
DELIVERABLE DISCRIPTION
Ticket # Field Well # API # Log Description Log Date
20272 KRU 1D-36 50-029-22973-00 Archer Acoustic VIVID and Vivid Seal 08-Jul-23 (Day 1-3)
DELIVERED TO
Company & Address
DIGITAL FILE
# of Copies
LOG PRINTS
# of Prints
CD’s
# of Copies
1
AOGCC
Attn: Natural Resources Technician
333 W. 7th Ave., Suite 100
Anchorage, Ak. 99501-3539
Delivered By: CPAI Sharefile
______________________________ ______________________________________
Date received Signature
PLEASE RETURN COPY VIA EMAIL TO:
DIANE.WILLIAMS@READCASEDHOLE.COM
READ CASED HOLE, INC., 4141 B STREET, SUITE 308, ANCHORAGE, AK 99503
PHONE: (907)245-8951
E-MAIL : READ-Anchorage@readcasedhole.com WEBSITE : WWW.READCASEDHOLE.COM
PTD: 200-130
T37919
Kayla
Junke
Digitally signed
by Kayla Junke
Date:
2023.08.10
13:16:15 -08'00'
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STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSu b m i tt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Owner/Contractor: Rig No.:7ES DATE: 5/29/22
Rig Rep.: Rig Phone: 670-6132
Operator: Op. Phone:670-6130
Rep.: E-Mail
Well Name: PTD #22001300 Sundry #322-298
Operation: Drilling: Workover: x Explor.:
Test: Initial: x Weekly: Bi-Weekly: Other:
Rams:250/2500 Annular:250/2500 Valves:250/2500 MASP:2179
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result Test Result Quantity Test Result
Location Gen.P Well Sign P Upper Kelly 1P
Housekeeping P Rig P Lower Kelly 1P
PTD On Location P Hazard Sec.P Ball Type 2P
Standing Order Posted P Misc.NA Inside BOP 1P
FSV Misc 0NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0NATrip Tank PP
Annular Preventer 1 13 5/8" T 90 FP Pit Level Indicators PP
#1 Rams 1 3 1/2" x 5 1/2"P Flow Indicator PP
#2 Rams 1 Blinds P Meth Gas Detector PP
#3 Rams 1 2 7/8" x 5 NT H2S Gas Detector PP
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NA Quantity Test Result
Choke Ln. Valves 1 3 1/8" Gate P Inside Reel valves 0NA
HCR Valves 2 3 1/8" Gate FP
Kill Line Valves 2 3 1/8" & 2"P
Check Valve 0NAACCUMULATOR SYSTEM:
BOP Misc 2 2 1/16 Gate P Time/Pressure Test Result
System Pressure (psi)3000 P
CHOKE MANIFOLD:Pressure After Closure (psi)1600 P
Quantity Test Result 200 psi Attained (sec)15 P
No. Valves 16 P Full Pressure Attained (sec)110 P
Manual Chokes 1P Blind Switch Covers: All stations Yes
Hydraulic Chokes 1P Nitgn. Bottles # & psi (Avg.): 5@1900 P
CH Misc 0NA ACC Misc 0NA
Test Results
Number of Failures:2 Test Time:23.0 Hours
Repair or replacement of equipment will be made within 0 days.
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 5-27-22/ 13:00
Waived By
Test Start Date/Time:5/28/2022 2:30
(date) (time)Witness
Test Finish Date/Time:5/29/2022 1:30
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Adam Earl
Nabors
Tested with 3 1/2" & 5 1/2" Annular Preventer failed on 3 1/2" test JT. high test , Replaced annular preventer element.
HCR Kill failed high test. Replaced HCR kill valve.
Tony Morales/Sean Holcomb
ConocoPhillips
Mark Adams / Kevin Barr
KRU 1D-36
Test Pressure (psi):
nskrwo.cm@conocophillips.com
Form 10-424 (Revised 02/2022) 2022-0528_BOP_Nabors7ES_KRU_1D-36
9
999
9
9
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9
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9
9
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9
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FP
5/29/22
Replaced annular preventer element.
HCR Kill failed high test.
Annular Preventer failed on 3 1/2" test JT.
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2105445
WELL LOG TRANSMITTAL#902980405
To: Alaska Oil and Gas Conservation Comm. December 11, 2015
Attn.: Makana Bender y= f t e
333 West 7th Avenue, Suite 100
DATAOD
Anchorage, Alaska 995010 1 5201.5" iMK_ R
RE: Tubing Cut and String Shot Records: 1D-36
Run Date: 11/11/2015
The technical data listed below is being submitted herewith. Please address any problems or
concerns to the attention of:
Fanny Sari, Halliburton Wireline &Perforating, 6900 Arctic Blvd., Anchorage, AK 99518
FRS_ANC@halliburton.com
1D-36
Digital Data in LAS format, Digital Log Image file 1 CD Rom
50-029-22973-00
SCONE -
PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE
TRANSMITTAL LETTER TO THE ATTENTION OF:
Halliburton
Wireline &Perforating
Attn: Fanny Sari
6900 Arctic Blvd.
Anchorage, Alaska 99518
Office: 907-275-2605
Fax: 907-273-3535
FRS_ANC@halliburton.com
Date: Signed: / ,J4"__ Alb !
�TE OF ALASKA KRU 1D-36
Alli KA OIL AND GAS CONSERVATION COMry 'SION
REPORT OF SUNDRY WELL OPERATIONS
1 1.Operations
Abandon I Plug Perforations fa Fracture Stimulate , Pull Tubing � Operations Shutdown
Performed:
Suspend j Perforate 1 Other Stimulate ( ., C`` Alter Casing r� Change Approved Program
Plug for Redrill F.__ Perforate New Pool P Repair Well Re-enter Susp Well P Other: PC Leak 1,0
2.Operator Name: 4.Well Class Before Work: 5. Permit to Drill Number:
ConocoPhillips Alaska, Inc. Development F Exploratory 200-130
3.Address: 6.API Number:
Stratigraphic r"
Service
P. O. Box 100360,Anchorage,Alaska 99510 50-029-22973-00
7.Property Designation(Lease Number): 8.Well Name and Number:
ADL 25661,25650 KRU 1 D-36
9. Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s):
none Kuparuk River Field/Kuparuk River Oil Pool
11.Present Well Condition Summary:
Total Depth measured 11658 feet Plugs(measured) None
true vertical 6542 feet Junk(measured) None
Effective Depth measured 11589 feet Packer(measured) 7989, 10892, 11370
true vertical 6510 feet (true vertical) 4757,6173,6406
Casing Length Size MD TVD Burst Collapse
CONDUCTOR 88 20 121 121 0 0
SURFACE 7012 9.625 7047 4297 0 0
PRODUCTION 11007 7 11038 6244 0 0
LINER 771 3.5 11656 6541 0 0
SCANNED APR 0 8 zoRECEIVED
Perforation depth: Measured depth: 11410-11420, 11420-11484
True Vertical Depth: 6425-6430,6430-6461 DEC 0 4 2015
Tubing(size,grade, MD,and TVD) 3.5, L-80, 10926 AOGCC
Packers&SSSV(type,MD,and TVD) PACKER Baker Premier Packer@ 7989 MD,4757 TVD, BAKER ZXP Liner Top Packer,
@ 10892 MD,6173 TVD,Weatherford WS-R-BB Packer @11370 MD, 6406 TVD
SSSV: NONE
12.Stimulation or cement squeeze summary:
Intervals treated(measured): none
Treatment descriptions including volumes used and final pressure:
13. Representative Daily Average Production or Injection Data
Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure
Prior to well operation shut-in
Subsequent to operation waiting fac hookup
14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work:
Daily Report of Well Operations F Exploratory [" Development 1—. Service (i Stratigraphic (......
16.Well Status after work: r''
Copies of Logs and Surveys Run ��" Oil Gas F WDSPL
Printed and Electronic Fracture Stimulation Data
GSTOR r WINJ 1 WAG r GINJ I._._ SUSP 1 SPLUG r
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:
315-623
Contact Andrew Beat(a�265-6341 Email Andrew.T.Beata(�conocophillips.com
Printed Name Andrew Beat Title Sr. Wells Engineer
Signature ( h .2656341 Da9015i4x/2°/5
Pr-i-TL 3/i DLRBDMS DEC 0 2
Form 10-404 Revised 5/2015 �_�/ Submit Original Only
KUPOD 1D-36
ConocoPhitlips s Well Attrib Max Ang D TD
Alaska Inc. Wellbore API/UWI Field Name Wellbore Status ncl C) MD(ftKB) Act Btm(ftKB)
COrwmPhi9ips 500292297300 KUPARUK RIVER UNIT PROD 62.25 4,980.84 11,658.0
I -„ `.� Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date
1D-36,.17142015 x.56:16 PM SSSV:NONE 50 12/16/2013 Last WO: 11/18/2015 36.30 9/18/2000
varitcai ggiwragac itigluafi
Annotation Depth(ftKB) End Date Annotation Last Mod By End Date
Last Tag: 11,450.0 4/30/2005 Rev Reason:WORKOVER,PULLED PLUG, lehallf 12/2/2015
HANGER;29.2 ,of GLV 0/0
Casing Strings
1 Casing OD(in) ID(in) Top(ftKB) Set Depth(ftKB) •Set Depth(TVD)...Wt/Len(I...Grade Top Thread
nCONDUCTORDescription
1I • • •• 20 19.250 33.0 121.0 121.0 72.00 H-40 Welded
1.-. Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread
SURFACE 9 5/8 8.697 34.4 7,046.8 4,297.1 40.00 L-80 BTCM
■■1•I a/ OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)...Wt/Len(I...Grade Top Thread
.R..�� .�.:J ••••r • 7 6.276 31.4 11,038.4 6,244.8 26.00 L-80 _BTCM
I Casin 4,297.1(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Dapth(ND)...WtlLen(I...Grade Top Threatl
31/2 2.992 11,360.0 11,364.0 6,403.2 9 30 L 80 SLHT
OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)... WtlLen(I...Grade Top Thread
CONDUCTOR;330-1210 I I 3 1/2 2.992 11,407.0 11,411.0 6,426.0 9.30 L-80
Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)... Wt/Len(I...Grade Top Thread
LINER 31/2 2.992 10,885.2 11,656.0 6,541.2 9.30 L-80 SLHT
GAS LIFT;3,433.2It Liner Details
Nominal ID
Top(ftKB) Top(TVD)(ftKB) Top Incl(°) Item Des Com (In)
10,885.2 6,169.9 60.84 TIE BACK LINER TIE BACK SLEEVE 5.500
10,892.5 6,173.5 60.82 PACKER BAKER ZXP LINER TOP PACKER 4.408
GAS LIFT;5,637.3 - 10,900.0 6,177.1 60.80 HANGER BAKER FLEX-LOCKLINER HANGER w/RS NIPPLE 4.400
10,912.5 6,183.3 60.77 SBE BAKER 80-40 SBE 4.000
I10,971.2 6,212.0 60.62 NIPPLE HES'XN'NIPPLE w/2.75 NO GO PROFILE 2.750
Tubing Strings
SURFACE;31.4-7,0/6.6
Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft..Set Depth(ND)I...Wt(Ib/ft) Grade Top Connection
TUBING RWO 3 1/2 3 112 2.992 29.2 7,978.1 4,752.1 9.30 L-80 EUE 8RD
Gas Lift Completion
2015
GAS LIFT;7,050.7 Completion Details
Nominal ID
II I
Top(ftKB) Top(ND)(ftKB) Top Incl(°) Item Des Corn (in)
29.2 29.2 0.03 HANGER FMC TC-IA-EMS,11"X 3-1/2"EUE 8RD W/2-3/8"X 2.992
1/2"CCL PORT TBG HANGER
GAS LIFT;7,898.6 7,955.4 4,741.4 61.76 LOCATOR Baker locator sub with 7-ft spaceout. 2.990
'. 7,963.4 4,745.2 61.74'SEAL ASSY 80-40 Baker Seal Assy. 2.990
Tubing Description String Ma...ID(in) Top(ftKB) Set Depth(ft..Set Depth(TVD)(...Wt(1b/ft) Grade Top Connection
I TUBING RWO 2015 31/2 2.992 7,963.4 10,926.2 6,190.0 9.30 L-80 EUE 8RD
(Straddle Packer
Assy)
LOCATOR,7,955.4 -:::
SEAL ASSY;7,983.4. ('�=I Completion Details
PBR;7,963.41..+i Nominal ID
Top(ftKB) Top(NO)(ftKB) Top Incl C) Item Des Com (in)
PACKER;7,988.9 7,963.4 4,745.2 61.74 PBR Baker 80-40 PBR 4.000
II 7,988.9 4,757.2 61.68 PACKER Baker 3%x 7"Premier Packer 2.860
GAS LIFT;9,420.2 II 10,839.4 6,147.7 60.99 NIPPLE Landing Nipple 2.813 DS Profile 2.813
10,888.8 6,171.7 60.83 LOCATOR 'Baker locator sub with 3-ft spaceout 2.990
NIPPLE;10,839.4 I
10,890.0 6,172.3 60.83 SEAL ASSY 80-40 Baker Seal Assy. 2.990
Other In Hole(Wireline retrievable plugs,valves,pumps,fish,etc.)
To (ND) Top Incl
Top(ftKB) (ftKB) CI Des Corn Run Date ID(in)
LOCATOR;10,988.8 5--1 11,370.0 6,406.1 60.85 PACKER Weatherford WS-R-BB Packer Set in Main Bore 7/22/2005 1.250
I Liner
11,410.0' 6,425.5 61.26 Whipstock WHIPSTOCK TO L1,set 7/22/2005 7/22/2005 1.250
SEAL ASSY;10,890.D- f Perforations&Slots
'1,i
i4 Shot
Dens
F' Top(ND) Btm(TVD) (shots/
Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date ft) Type Com
11,410.0 11,420.0 6,425.5 6,430.3 C-2,1D-36 10/28/2000 4.0 IPERF 2.5"BH HSD
E 11,420.0 11,484.0 6,430.3 6,460.7 C-2,C-1,1D- 7/12/2003 6.0 APERF 2.5"HSD 2506 PJ HMX
36 60 Deg Ph
Stimulations&Treatments
Min Top Max Btm j
Depth Depth Top(TVD) Bhn(NO)
PRODUCTION;31.4-11,038.4 (ftKB) (ftKB) (MB) (ftKB) Type Date Corn
11,410.0 11,420.0 6,425.5 6,430.3 FRAC 10/30/200 INITAL'C'SAND FRAC I
0
WINDOW L2;11,360.011,364.0
Mandrel Inserts
PACKER;11,370.0 St
ati
N111Top(TVD) Valve Latch Port Side TRO Run
Top(ftKB) (ftKB) Make Model OD(In) Sery Type Type (in) (psi) Run Date Com
1� 3,433.2 2,483.7 Camco MMG 1 1/2 GAS LIFT GLV RK 0.188 1,222.0 11/24/2015
2 5,637.3 3,593.9 Camco MMG 1 1/2 GAS LIFT GLV RK 0.188 1,217.0 11/24/2015
IPERF;11,408.0-12,261.0 3 7,050.7 4,299.0 Camco MMG 1 1/2 GAS LIFT OV RK 0.250 0.0 11/24/2015
LINER L7;11,394.513,310.0, � ) 1
Whipstock;11,410.0
WINDOW L1;11,407.0-11,411.0 ;s! 4 7,898.6 4,714.3 Camco MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 11/18/2015
IPERF;11,410.011,420.0
FRAC;11,410.0
5 9,420.2 5,454.8 Camco MMG 1 1/2 GAS LIFT DMY RK 0.000 0.0 11/17/2015
APERF;11,420.0-11,484.0
Notes:General&Safety
End Date Annotation
8/1/2005 NOTE:MULTI-LATERAL WELL:1D-36,1D-36L1,1 D-36L2 ALL C-SANDS
1/8/2009 NOTE:View Schematic w/Alaska Schematic9.0
LINER;10,885.1-11,656.0
KUP PROD • 1 D-36L1
ConocoPhillips n Well Attributes Max Angle&MD TD
Alaska,Inc. Wellbore API/UWI Field Name Wellbore Status ncl 7) MD(ftKB) Act Btm(ftKB)
4„..,..., 500292297360 KUPARUK RIVER UNIT PROD 94.72 11,709.84 13,310.0
--. Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date
1D-36L1,12/4/20159:40'46 AM SSSV:NIPPLE 50 12/16/2013 Last WO 36.30 9/18/2000
Verhf.919ohemebc(acWal). Annotation Depth(ftKB) End Date Annotation Last Mod By End Date
Last Tag. Rev Reason'WORKOVER,PULLED PLUG, lehallf 12/2/2015
HANGER;29.2 GLV C/O
Casing Strings
Casing Descriptio IOD(in) IID(in) Top(BKB) Sot Depth(5KB) Set Depth(TVD)...I WI/Len(I...I Grade ITop Thread
Ell LINER L1 2 3/8 992 11 394.5 3,310.0 6 524.0 4.60 L-80 STL
IJ'i.
Liner Details
Nominal ID
, /
., . , ,, . , A . Ej,,.: Top(ftKB) Top(TVD)(ftKB) Top Incl 7) Item Des Corn (in)
11,394.5 6,418.0 61.10 DEPLOY BTT SEAL BORE DEPLOYMENT SLEEVE 2.250
13,276.5 6,520.1 83.56 0-RING BTT 0-RING SUB 1.000
CONDUCTOR;33.0-121.0 -'-'•Perforations&Slots
Shot
Dens
Top(TVD) Btm(TVD) (shcts/f
GAS LIFT;3,433.2 Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date t) Type Corn
dt 11,406.0 12,261.0 6,423.6 6,440.4 '7/22/2005 40.0 IPERF SLOTTED TBG
Ii 12,356.0 12,832.0 6,441.7 6,478.6 7/22/2005 40.0 IPERF SLOTTED TBG
12,927.0 13,276.0 6,486.6 6,520.1 7/22/2005 40.0 IPERF SLOTTED TBG
GAS LIFT;5,637.3 it- Notes:General&Safety
End Date Annotation
8/1/2005 NOTE:MULTI-LATERAL WELL'1D-36,1D-36L1,1 D-36L2 ALL C-SANDS
1/8/2009 'NOTE:View Schematic w/Alaska Schematic9.0
SURFACE;34.4-7,048.8—A `
GAS LIFT;7,050.7
I
I
I
GAS LIFT;7,888.6
I
I
LOCATOR;7,955.4
SEAL ASSY;7,963.4-., =1
PBR;7,963.4 -`1
PACKER;7,988.8
I
GAS LIFT;9,420.1 a
II
NIPPLE;10,839.4
LOCATOR,10,888.8
illi
SEAL ASSY;10,890.0 414,
V.,
W.
PRODUCTION;31.4-11,038.4 A
WINDOW U;11,360.0-11,364.0
PACKER; —111
i'
I
LINER;10,885.1-11,656.0 -
WINDOW L7;11,407.0-11,411.0
IPERF;11,406.0-12,261.0
r 1—
.] ...—
IPERF 12,356.0-12,832.0—H
r
IPERF;12,927.0-13,276.0
-1
LINER L1;11,394.5-13,310.0
KUP PROD • 1 D-36L2
IConocoPhillips )Well Attributes Max Angle&MD TD
Alaska inc. Wellbore API/UWI Field Name Wellbore Status ncl 7) MD(ftKB) Act Blot(ftKB)
cmoc&HlINgs • 500292297361 KUPARUK RIVER UNIT PROD 93.82 11,711 02 13,300.0
... Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date
1D-36L2,12/4/2015 9;39:49 AM SSSV NIPPLE 50 12/16/2013 Last WO: 36.30 9/18/2000
VeNCel Schematic(actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date
Last Tag: Rev Reason:WORKOVER,PULLED PLUG, lehallf 12/2/2015
HANGER 29.2 Cj( GLV C/O
Casing Strings
I
gg Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)... WE/Len(I...Grade Top Thread
i! LINER L22 3/8 1.992 11,374.6 13,210.0 6,482.9 4.60 L-80 STL
8 II
I Liner Details
Nominal ID
Top(ftKB) Top(TVD)(ftKB) Top net 7) horn Das Com (in)
UuuauAi CC,'
-t ' 11,374.6 6,407.9 65.00 DEPLOY BTT SEAL BORE DEPLOYMENT SLEEVE w/3"GS 2.250
� �'
ll II
13,176.3
Perforations&Slots 6,480.0 86.27 0-RING PROFILE
BTT O-RING SUB 1.000
CONDUCTOR:33.0-121.0 I I Shot
Dens
Top(TVD) Btm(TVD) (shots/f
Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date t) Type Com
GAS LIFT,3,433.211,376.0 12,005.0 6,408.5 6,413.2 7/22/2005 40.0 IPERF SLOTTED TUBING
12,100.0 12,638.0 6,413.5 6,449.5 7/22/2005 40.0 IPERF SLOTTED TUBING
12,733.0 13,176.0 6,459.2- 6,480.0 7/22/2005 40.0 IPERF SLOTTED TUBING
Notes:General&Safety
GAS LIFT;5,637.3 End Date Annotation
V. 8/1/2005 NOTE:MULTI-LATERAL WELL:1D-36,1D-36L1,1D-36L2 ALL C-SANDS
1/8/2009 NOTE'View Schematic w/Alaska Schematic9.0
SURFACE',34.4-7,046.8-+
GAS LIFT;7,0507
I
I
I
GAS LIFT;7,898.6
I
I
I
LOCATOR;7,955.4
SEAL ASSY;7,963.4, Ir
PBR;7,963.4 _.
PACKER;7,986.8
GAS LIFT;9,420.1 1
I
NIPPLE;10,8391
1
1 II
LOCATOR,10,886.8 qqJ
ill
Ilk
SEAL ASSY,10,890 0 yl�lili tl
iII.
I
PRODUCTION;31.4-11,038.4 + 4
LINER;10,885.1-11,656.0
IPERF;11,370.0-12,005.0
IPERF;12,100.0-12.638.0
IPERF;12.733.0-13,176.0
LINER L2;11,374.8-13,210.0
• •
Daily Operations Summary
&Wells
1D-36
ConocoPhillips
Rig: NABORS 9ES Job: RECOMPLETION
Daily Operations
Start Date Last 24hr Sum
11/8/2015 Bridal up the blocks and lower the cattle chute. Pay out the tugger,man rider, and bridal lines. Remove A-leg pins. Lower the derrick. Pull the pits
away from the sub and install the jeep. Remove the driller side(DS)bridal line with the crane. Move the pits, mechanic shop,welding shop,
electrical shop,and satellite office to 1D pad.
11/9/2015 Finish removing the driller side bridal line, install new driller side bridal line, remove off driller side bridal line,and install new off driller side bridal
line with crane. Jack up the sub and move the sub off well 1J-103. Pick up herculite and rig mats from around the 1J-103. Clean up around the
well. Move the sub from 1J pad to 1D pad.Spot the sub over well 1D-36,install mats under the sub,and set the sub down. Spot the pits to the
sub,install mats under the pits,lay out herculite,and set the pits down. Inspect the derrick for loose items,raise the derrick,and pin the A-legs.
Spool and inspect tugger, man rider,and bridal lines. Raise and pin the cattle chute. RU interconnect. Bridal down, pin the blocks to the TD,and
pin the torque tube.
11/10/2015 Continue to RU,set up berming,go over rig acceptance checklist, and accept the rig. Load the pits with 9.8 ppg NaCI brine. Pull the BPV and kill
the well. ND the tree, NU the BOP stack,and test the BOPE to 250/3000 psi with 3-1/2"test joint. The states right to witness was waived by
AOGCC inspector Jeff Jones via email on 11/8/15 at 13:19 hours. Door seal failed on LPR's
11/11/2015 Continue to repair door seals on LPR's,Conduct Initial BOP test w/3-1/2 test joint. Un land hanger and unable to pull seals,work pipe. RU Eline
and attempt to string shot at 10,848-ft-unable past 10,827-ft,temporally detained-reverse circulate @ 1 bpm @ 90 psi and fire string shot-
POOH
11/12/2015 RIH w/2nd string shot-shoot over 10,800-ft and cut at same depth w/RCT cutter. RD Eline, POOH with 3-1/2 de completion to 3,500-ft
11/13/2015 Continue to POOH laying down 3-1/2 De completion from 3,500-ft to cut joint. Finish loading 4"HT Drill pipe and RIH w/fishing BHA#1 to 8,240-ft
11/14/2015 Continue to RIH from 8,235-ft to 9,346-ft. Pull wear ring and MU test plug. Hang off drill string from test plug. Test Annular, UPR's and LPR's with
4"test jt. RIH and engage TOF @ 10,832-ft and jar seals free from SBE @ 10,912-ft. Circulate surface to surface. POOH to 5,980-ft.
11/15/2015 Continue to POOH from 5,980-ft to 303-ft. Pooh laying down drill collars,fishing tools and 86-ft of 3-1/2 Tbg fish. PU, MU and RIH w/3-1/2
cleanout string and Test packer on 4"HT Drill pipe to 8,074-ft and set packer at 8,801-ft and test back to surface at 2,500 psi.-Good test.
Continue to RIH to 8,837-ft and set packer at 8,762-ft test at 2,500 psi-pumping away at 1,000 psi. Continue to 10,895-ft,set packer,no set and
Pull 1 jt to 10,825-ft and set test packer at 10,790-ft. PT down DP to 2,500 psi.-Good test,Release packer. RIH to 10,927-ft. Reverse circulate
218 bbls @ 2 bpm @ 265 psi. Slip and cut 66-ft of 1-1/8"Drill line.
11/16/2015 Finish slip and cut. Adjust brakes. POOH laying down to 8,710-ft. Set packer at 8,632-ft and test IA at 2,500 psi-pumping away at 1,600 psi.
POOH to 8,540-ft and test IA at 2,500 psi-pumping away at 1,600 psi. POOH to 8,420-ft and test IA at 2,500 psi-pumping away at 1,600 psi.
POOH to 8,074-ft and test to 2,500 psi-good test. POOH laying DP to Test packer. Lay down test packer and tail pipe. Clean and Clear rig floor.
PU and RIH w/3-1/2 Gas Lift completion as per Run orders to 3,629-ft 54K Up wt,50 Dn wt.
11/17/2015 Continue to PU and RIH w/3-1/2 Gas Lift completion as per 2nd Run order from 3,629-ft to 10,933-ft. Locate,Spot 105 bbls of CI Brine from
10,933-ft to 7,963-ft, Pressure up and set Primer Packer. Shear out of PBR and Close annular -PT IA to 2,500 psi. Bleed off TBG and IA,Space
out, MU Tubing hanger,spot seals above PBR and Change hole over to 280 bbls of CI Brine. Stab seals and land hanger. RILDS. PT Tubing at
3,000 psi for 30 minutes,bleed back to 1,500 psi and Pressure up IA to 2,500 psi for 30 minutes. Was not able to shear the SOV. Set BPV.
Clean mud circulating system from the rotary table to the pits. ND BOPE. NU Tree and set Test plug-test for surface leaks.
11/18/2015 Call out Slick line to set catcher sub @ 10,842-ft and pull SOV @ 7,052-ft,Continue on with RD Mode while conducting slick line operations.
Freeze protect well after slick line is RD out of the way. Allow well to swap. RDMO
Page 1/1 Report Printed: 12/4/2015
• •
Operations Summary (with Timelog Depths)
&Wens
1D-36
I 0.-
ConocoPhiiiips iob
Rig: NABORS 9ES Job: RECOMPLETION
Time Log
Start Depth
Start Time End Time Dur(hr) Phase Op Code Activity Code Time P-T-X Operation (ftK6) End Depth(ftKe)'.
11/8/2015 11/8/2015 4.00 MIRU MOVE RURD P Bridal up the blocks and lower the 0.0 0.0
12:00 16:00 cattle chute. Pay out the tugger,man
rider,and bridal lines. Remove A-leg
pins.
11/8/2015 11/8/2015 1.50 MIRU MOVE RURD P Lower the derrick. 0.0 0.0
16:00 17:30
11/8/2015 11/8/2015 1.50 MIRU MOVE MOB P Pull the pits away from the sub and 0.0 0.0
17:30 19:00 install the jeep.
11/8/2015 11/9/2015 5.00 MIRU MOVE SVRG P Remove the driller side(DS)bridal line 0.0 0.0
19:00 00:00 with the crane.
SimOps: Move the pits,mechanic
shop,welding shop,electrical shop,
and satellite office to 1D pad.
11/9/2015 11/9/2015 8.00 MIRU RIGMNT SVRG P Finish removing the driller side bridal 0.0 0.0
00:00 08:00 line,install new driller side bridal line,
remove off driller side bridal line,and
install new off driller side bridal line
with crane. Work conducted under
IADC code 8
11/9/2015 11/9/2015 1.00 MIRU MOVE MOB P Jack up the sub,move the sub off well 0.0 0.0
08:00 09:00 1J-103,and stag the sub in the middle
of the pad.
11/9/2015 11/9/2015 1.00 MIRU MOVE RURD P Pick up herculite and rig mats from 0.0 0.0
09:00 10:00 around the 1J-103. Clean up around
the well.
11/9/2015 11/9/2015 4.00 MIRU MOVE MOB P Move the sub from 1J pad to 1D pad. 0.0 0.0
10:00 14:00
11/9/2015 11/9/2015 2.50 MIRU MOVE RURD P Set rig mats around well 1D-36 and 0.0 0.0
14:00 16:30 lay out herculite.
11/9/2015 11/9/2015 1.50 MIRU MOVE MOB P Spot the sub over well 1D-36,install 0.0 0.0
16:30 18:00 mats under the sub,and set the sub
down.
11/9/2015 11/9/2015 2.00 MIRU MOVE MOB P Spot the pits to the sub,install mats 0.0 0.0
18:00 20:00 under the pits,lay out herculite,and
set the pits down.
11/9/2015 11/9/2015 2.00 MIRU MOVE RURD P Inspect the derrick for loose items, 0.0 0.0
20:00 22:00 raise the derrick,and pin the A-legs.
11/9/2015 11/9/2015 1.00 MIRU MOVE RURD P Spool and inspect tugger,man rider, 0.0 0.0
22:00 23:00 and bridal lines. Raise and pin the
cattle chute. RU interconnect.
SimOps: Drilling Tool House spotted
kill tank and choke house. RU
hardline from kill tank to choke house
and from choke house to the rig.
11/9/2015 11/10/2015 1.00 MIRU MOVE RURD P Bridal down,pin the blocks to the TD, 0.0 0.0
23:00 00:00 and pin the torque tube.
11/10/2015 11/10/2015 6.00 MIRU MOVE RURD P Close the cellar door and install 0.0 0.0
00:00 06:00 insulation. RU berming around the
cellar and pits. Spot LEPD tank and
cuttings box. RU berming around
LEPD tank and cuttings box. Hang
bridal lines in the derrick.
Accept Nabors 9ES @ 06:00 hrs on
11-10-15
11/10/2015 11/10/2015 3.00 MIRU WELCTL RURD P Rig up circulating lines from tree to kill 0.0 0.0
06:00 09:00 tank. Load 570 bbls of 9.8 ppg NaCI
Brine into the rig pits.
Page 1/8 Report Printed: 3/15/2016
• •
Operations Summary (with Timelog Depths)
&Wells
1 D-36
ConocoPhillips
A3:ssA:s
Rig: NABORS 9ES Job: RECOMPLETION
Time Log
Start Depth
Start Time End Time Dur(hr) Phase Op Code Activity Code Time P-T-X Operation (ftKB) End Depth(ftKB)
1.50MIRUWELCTL MPSP P PU and RU lubricator and PT at 2 000 0.0 0.0
11/10/2015 11/10/2015 ,
09:00 10:30 psi-no leaks,lubricate out the 3"type
H BPV. RD lubricator.
Open up well-700 psi SITP,650 psi
SICP and 475 psi SIOCP.
11/10/2015 11/10/2015 1.00 MIRU WELCTL SEQP P Pressure test Pumps and pop offs to 0.0 0.0
10:30 11:30 3,700 psi-good test. Purge
circulating lines to kill tank from the
well head and PT to 1,000 psi.-good
test
11/10/2015 11/10/2015 3.25 MIRU WELCTL KLWL P Bleed IA and TBG to kill tank,reverse 0.0 0.0
11:30 14:45 circulate 95 bbls at 3 bpm at 125 psi.
Change over and circulate 405 bbls at
4 bpm at 387 psi. Shut down pumping
operations.
11/10/2015 11/10/2015 1.25 MIRU WELCTL OWFF P Monitor well for flow-Blow down all 0.0 0.0
14:45 16:00 circulation lines. No flow
11/10/2015 11/10/2015 0.50 MIRU WHDBOP MPSP P Dry rod 3"BPV into place and set 0.0 0.0
16:00 16:30
11/10/2015 11/10/2015 2.00 MIRU WHDBOP NUND P ND tree and adapter-inspect lifting 0.0 0.0
16:30 18:30 threads and screw in FMC Blanking
plug. Prep and inspect TBG head.
11/10/2015 11/10/2015 3.00 MIRU WHDBOP NUND P NU 13-5/8 BOP Class IV Stack,install 0.0 0.0
18:30 21:30 turn buckles,mouse hole and riser.
11/10/2015 11/10/2015 1.00 MIRU WHDBOP RURD P RU HT 40!BOP and FOSV, FMC 3- 0.0 0.0
21:30 22:30 1/2 test joint.
11/10/2015 11/11/2015 1.50 MIRU WHDBOP BOPE T Attempt to test Choke Valves 1,2,3 0.0 0.0
22:30 00:00 and 16, Demco Kill valve and Blinds-
LPR door seals were found to be
leaking,open and inspect,change out
1 door seal and clean and inspect the
other.
11/11/2015 11/11/2015 3.00 MIRU WHDBOP BOPE T Attempt to test Choke Valves 1,2,3 0.0 0.0
00:00 03:00 and 16, Demco Kill valve and Blinds-
LPR door seals were found to be
leaking,open and inspect,change out
1 door seal and clean and inspect the
other.
11/11/2015 11/11/2015 5.00 MIRU WHDBOP BOPE P Conduct Initial BOP test at 250/3,000 0.0 0.0
03:00 08:00 psi with 3-1/2 test joint. 24 hr Notice
was given to AOGCC @ 13:04 hrs on
11-8-15,The states right to witness
was waived by AOGCC inspector Jeff
Jones via email on 11/8/15 at 13:19
hours.
Sys.psi=3000
after closure-1600
200 psi gain-25 seconds
full pressure gain-140 seconds
N2=6 bottles Ave-2025 psi
RD Test equipment.
11/11/2015 11/11/2015 8.75 COMPZN RPCOMP WAIT T Un land hanger and attempt to pull 0.0 0.0
08:00 16:45 seals with no success with max pull of
200k and circulating at 3 bpm at 275
psi-call out Eline. Work up to 10 bpm
@ 2,169 psi for 84 bbls pumped-No
luck. Suspend operations for RU of
eline.
Page 2/8 Report Printed: 3/15/2016
• •
Operations Summary (with Timelog Depths)
&Wells
1 D-36
ConocoPhittips
Rig: NABORS 9ES Job: RECOMPLETION
Time Log
Start Depth
Start Time End Time Dur(hr) Phase Op Code Activity Code Time P-T-X Operation (ftKB) End Depth(ftKB)
11/11/2015 11/12/2015 7.25 COMPZN RPCOMP ELNE P Space out and land in slips with 175k 0.0 0.0
16:45 00:00 35k to 40k osw. RU Eline and make
string shot. RIH to 10,827-ft and set
down. Pick up and pulled over.
Reverse circulate in attempt to wash
off debris-no luck. Fire string shot-
free POOH with wire line
11/12/2015 11/12/2015 12.00 COMPZN RPCOMP ELNE P Continue to reverse circulate at 1 bpm 0.0 0.0
00:00 12:00 at 90 psi while POOH with eline.
Inspect tools-all good. Build new
string shot and RIH to 10,795-ft(CCL
Depth)and shoot 5-ft string shot
across 10,800-ft. POOH lay down the
"fired"string shot. PU,MU and RIH w/
RCT cutter to 10,850-ft and cut tbg.
POOH and RD Eline.
11/12/2015 11/12/2015 1.00 COMPZN RPCOMP PULL P Lay down landing joint pup and TBG 10,850.0 10,830.0
12:00 13:00 hanger 128K Up wt,62K Dn wt
11/12/2015 11/12/2015 2.50 COMPZN RPCOMP CIRC P Circulate surface to surface at 6 bpm 10,830.0 10,830.0
13:00 15:30 at 1,146 psi. Blow down circ lines and
RD circulating equipment.
11/12/2015 11/12/2015 1.00 COMPZN RPCOMP PULL P POOH laying down 3-1/2 De 10,830.0 10,650.0
15:30 16:30 completion from 10,830-ft to 10,650-ft
128KUpwt,62K Dn wt.
11/12/2015 11/12/2015 0.50 COMPZN RPCOMP EQRP T Repair Weatherford Tongs-Change 10,650.0 10,650.0
16:30 17:00 out with back up set due to Failed
brake band pin
11/12/2015 11/13/2015 7.00 COMPZN RPCOMP PULL P Continue to POOH with 3-1/2 De 10,650.0 3,500.0
17:00 00:00 Completion from 10650-ft to 3500-ft
62K Up wt.
11/13/2015 11/13/2015 5.00 COMPZN RPCOMP PULL P Continue to POOH with 3-1/2 De 3,500.0 0.0
00:00 05:00 Completion from 3500-ft to cut jt-
15.56-ft
Recovered 339 jts of 3-1/2 TBG
Pitting started at jt 277-8,828-ft
Found hole in jt#278-8,860-ft to
8,891-ft
in jt#302-9,618-ft to 9,649-
ft
Estimated TOF @ 10,831-ft by strap
11/13/2015 11/13/2015 0.50 COMPZN RPCOMP RURD P Install wear ring 0.0 0.0
05:00 05:30
11/13/2015 11/13/2015 2.00 COMPZN RPCOMP OTHR 'P Load pipe shed with 64 jts of Drill pipe, 0.0 0.0
05:30 07:30 9 Drill collars. Rack and Tally the
same. RU floor for running DP.
11/13/2015 11/13/2015 2.25 COMPZN RPCOMP BHAH P PU fishing BHA#1 (Overshot Assy)to 0.0 303.0
07:30 09:45 303-ft 44k Up and Dn wt.
11/13/2015 11/13/2015 3.75 COMPZN RPCOMP PULD P PU, MU and RIH w/BHA#1 on 4"HT 303.0 3,310.0
09:45 13:30 Drill Pipe from 303-ft to 3,310-ft 75K
Up wt,67K Dn wt.
11/13/2015 11/13/2015 2.50 COMPZN RPCOMP PULD P Load pipe shed with110 jts of Drill 3,310.0 3,310.0
13:30 16:00 pipe. Rack and Tally the same.
11/13/2015 11/13/2015 1.00 COMPZN RPCOMP SVRG P Grease, Inspect Top drive, Draw 3,310.0 3,310.0
16:00 17:00 works and Iron Roughneck
11/13/2015 11/13/2015 2.00 COMPZN RPCOMP RGRP T Replace Proximity switch on Top Drive 3,310.0 3,310.0
17:00 19:00
11/13/2015 11/14/2015 5.00 COMPZN RPCOMP PULD P Continue to PU, MU and RIH w/BHA 3,310.0 8,240.0
19:00 00:00 #1 on 4"HT Drill Pipe from 3,310-ft to
8,240-ft 169K Up wt,77K Dn wt.
Page 3/8 Report Printed: 3/15/2016
• •
y_,
Operations Summary (with Timelog Depths)
aWeUs
1D-36
Coex►ccehikiips
Rig: NABORS 9ES Job: RECOMPLETION
Time Log
Start Depth
Start Time End Time Dur(hr) Phase Op Code Activity Code Time P-T-X Operation (ftKB) End Depth(ftKB)'
11/14/2015 11/14/2015 2.50 COMPZN RPCOMP PULD P Continue to PU, MU and RIH w/BHA 8,240.0 9,346.0
00:00 02:30 #1 on 4"HT Drill Pipe from 8,240-ft to
9,346-ft 190K Up wt,80K Dn wt.
11/14/2015 11/14/2015 7.75 COMPZN RPCOMP BOPE T MU wear ring pulling tool to drill string 9,346.0 9,346.0
02:30 10:15 and recover wear ring. Install Test
plug and hang DP off test plug.
Unable to fill stack,found to have a X-
0 that would not allow test to seat in
profile. Change out X-O and shell
test.
11/14/2015 11/14/2015 0.75 COMPZN RPCOMP BOPE P PU 4"test joint and test LPR's, UPR's 9,346.0 9,346.0
10:15 11:00 and Annular at 250/3,000 psi.
11/14/2015 11/14/2015 2.00 COMPZN RPCOMP BOPE P Pull test plug,X-O's and lay down the 9,346.0 9,346.0
11:00 13:00 same. Blow down test lines. Install
wear ring.
11/14/2015 11/14/2015 2.00 COMPZN RPCOMP PULD P Continue to PU and RIH w/4"HT Drill 9,346.0 10,807.0
13:00 15:00 pipe from 9,346-ft to 10,807-ft 223K
Up wt,85K Dn wt.
11/14/2015 11/14/2015 0.50 COMPZN RPCOMP FISH P Continue to PU and RIH w/4"HT Drill 10,807.0 10,832.0
15:00 15:30 pipe and wash down from10,807-ft
223K Up wt,85K Dn wt.to 10,832-ft at
3 bpm @ 400 psi.and engage fish.
11/14/2015 11/14/2015 2.25 COMPZN RPCOMP JAR P Jar from 50K osw to125k osw for 10,832.0 10,929.0
15:30 17:45 several jar hits. Then applied 500 psi
to assist in hydraulic the seals from
the seal bore extension. seals pulled
free at 175k osw and was able to un
sting from 10,929-ft-bottom of the
SBE.
11/14/2015 11/14/2015 1.25 COMPZN RPCOMP CIRC P Circulate surface to surface from 10,929.0 10,895.0
17:45 19:00 10,895-ft at 6 bpm at 1245 psi.
11/14/2015 11/14/2015 0.50 COMPZN RPCOMP OWFF P Monitor well for flow-No flow Stand 10,895.0 10,775.0
19:00 19:30 back 1 stand to allow the blowing
down of the top drive prior to Post
jarring inspection.
11/14/2015 11/14/2015 1.00 COMPZN RPCOMP SFTY P Conduct Post jar ring inspection of the 10,775.0 10,775.0
19:30 20:30 derrick and top drive. Inspect and
grease the crown.
11/14/2015 11/15/2015 3.50 COMPZN RPCOMP TRIP P POOH from 10,775-ft at 190K Up wt to 10,775.0 5,980.0
20:30 00:00 5,980-ft 133K Up wt,75K Dn wt.
11/15/2015 11/15/2015 3.25 COMPZN RPCOMP TRIP P POOH from 5,980-ft 133K Up wt,75K 5,980.0 303.0
00:00 03:15 Dn wt.to 303-ft.
11/15/2015 11/15/2015 2.00 COMPZN RPCOMP BHAH P POOH from 303-ft laying down DC's, 303.0 0.0
03:15 05:15 fishing tools
11/15/2015 11/15/2015 1.25 COMPZN RPCOMP PULL P POOH with 86-ft of 3-1/2 TBG fish. 303.0 0.0
05:15 06:30 Remove fish from OS.Clean and clear
rig floor.
11/15/2015 11/15/2015 0.75 COMPZN WELLPR BHAH P Load pipe shed with BHA, PU,MU 0.0 79.0
06:30 07:15 and RIH w/3-1/2 mule shoe joint, 1
full joint of 3--1/2 tubing,Crossover to
3-1/2 IF,test packer to 79-ft. 35K Up
wt,35K Dn wt.
11/15/2015 11/15/2015 6.25 COMPZN WELLPR TRIP P RIH with Testing BHA on 4"HT Drill 79.0 8,074.0
07:15 13:30 pipe from 79-ft to 8,074-ft 150K Up
wt,77K Dn wt.
11/15/2015 11/15/2015 1.00 COMPZN WELLPR PRTS P Set test packer at 8,001-ft and PT @ 8,074.0 8,074.0
13:30 14:30 2,500 psi on the IA for 15 minutes.
Good Test.PU and Release packer
Page 4/8 Report Printed: 3/15/2016
• 0
Drilling Operations Summary (with Timelog Depths)
4 a Wellls
1D-36
ConocoPhillips
Rig: NABORS 9ES Job: RECOMPLETION
Time Log
Start Depth
Start Time End Time Dur(hr) Phase Op Code Activity Code Time P-T-X Operation (ftKB) End Depth(ftKB)
11/15/2015 11/15/2015 0.50 COMPZN WELLPR TRIP P RIH from 8,074-ft to 8,837-ft 166K Up 8,074.0 8,837.0
14:30 15:00 wt,78K Dn wt.
11/15/2015 11/15/2015 0.75 COMPZN WELLPR PRTS P Set test Packer at 8,762-ft and PT @ 8,837.0 8,837.0
15:00 15:45 2,500 psi--pressure leak off at 1,000
psi testing down the DP and the IA.
Release packer
11/15/2015 11/15/2015 1.75 COMPZN WELLPR TRIP P RIH from 8,837-ft to10,895-ft 210K Up 8,837.0 10,895.0
15:45 17:30 wt,83K Dn wt.
11/15/2015 11/15/2015 2.00 COMPZN WELLPR PRTS P Set packer at 10,825-ft,packer 10,895.0 10,790.0
17:30 19:30 wouldn't set,lay down 1 jt and set @
10,790-ft PT down DP to 2,500 psi for
15 minutes -Good Test. Release
packer.
11/15/2015 11/15/2015 1.00 COMPZN WELLPR TRIP P PU and RIH to 10,927-ft while 10,790.0 10,927.0
19:30 20:30 circulating down @ 1 bpm @ 65 psi,
Tag no-go @ 10,896-ft,4-7/16"ID in
the ZXP LT Packer w/3-1/2 cplg.
Seen pressure increase to 300 psi, PU
2-ft off no-go.
11/15/2015 11/15/2015 2.50 COMPZN WELLPR CIRC P RU and reverse circulate 2 DP 10,927.0 10,925.0
20:30 23:00 volumes of 218 bbls at 2 bpm @ 265
psi.
11/15/2015 11/16/2015 1.00 COMPZN WELLPR SLPC P Lay down 1 jt DP to 10,900-ft. Slip 10,925.0 10,900.0
23:00 00:00 and cut 66-ft of Drill line
11/16/2015 11/16/2015 1.50 COMPZN WELLPR SLPC P Finish slip and cut. Adjust brakes. 10,900.0 10,900.0
00:00 01:30
11/16/2015 11/16/2015 2.50 COMPZN WELLPR PULD P POOH laying down from 10,900-ft to 10,900.0 8,710.0
01:30 04:00 8,710-ft.
11/16/2015 11/16/2015 3.50 COMPZN WELLPR PRTS P Set packer at 8,632-ft and test IA at 8,710.0 8,074.0
04:00 07:30 2,500 psi-pumping away at 1,600 psi.
POOH to 8,540-ft and test IA at 2,500
psi-pumping away at 1,600 psi.
POOH to 8,420-ft and test IA at 2,500
psi-pumping away at 1,600 psi.
POOH to 8,074-ft and test IA at 2,500
psi-Good Test. Bleed off and Blow
down lines.
11/16/2015 11/16/2015 7.50 COMPZN WELLPR PULD P POOH laying 4"HT 40 DP from 8,074- 8,074.0 79.0
07:30 15:00 ft @ 80K Up wt,63K Dn wt and POOH
to 79-ft 35K Up wt,35K Dn wt.
11/16/2015 11/16/2015 1.00 COMPZN WELLPR BHAH P RU Weatherford Power tongs and 79.0 0.0
15:00 16:00 POOH Breaking down Test packer
and 1-jt 3-1/2 TBG and 31-ft 3-1/2
Mule shoe jt. Clean and clear rig floor.
Pull wear ring.
11/16/2015 11/16/2015 0.50 COMPZN WELLPR SVRG P Service inspect,and Grease Top 0.0 0.0
16:00 16:30 Drive and fill brake fluid reservoir
11/16/2015 11/16/2015 0.50 COMPZN RPCOMP OTHR P Verify running order of Jewelry and 0.0 0.0
16:30 17:00 place in order of PU. Count and verify
Tubing racked in pipe shed
11/16/2015 11/16/2015 1.50 COMPZN RPCOMP PUTB P PJSM,PU and RIH with 3-1/2,9.3#,L- 0.0 1,487.0
17:00 18:30 80 EUE 8rd Mod Tubing Gas lift
completion as per run order to 1,487-ft
Page 5/8 Report Printed: 3/15/2016
• I
Operations Summary (with Timelog Depths)
We
1 D-36
ConocoPhitlips
Rig: NABORS 9ES Job: RECOMPLETION
Time Log
Start Depth
Start Time End Time Dur(hr) Phase Op Code Activity Code Time P-T-X Operation (ftKB) End Depth(ftKB)
11/16/2015 11/16/2015 0.25 COMPZN RPCOMP PULD T During conversation with RWO 1,487.0 1,516.0
18:30 18:45 engineer,an email was discussed
about the placement of GLM being
installed above lower seal assy for CI
packing the void between stacker
packers. The Run order did not have
this in place-Stopped operations and
installed a GLM setup 1,500-ft above
the seal assy.
11/16/2015 11/16/2015 3.00 COMPZN RPCOMP PUTB P Continue to RIH as per run order to 1,516.0 3,000.0
18:45 21:45 3,000-ft(wt hanging below Packer/
PBR 19K) and wait for New run order
11/16/2015 11/16/2015 1.50 COMPZN RPCOMP WAIT T Wait for New Run order to be built in 3,000.0 3,000.0
21:45 23:15 order to stay on track with equipment
lay out in the pipe shed due to GLM
placement and corrupt Master copy of
run order.
11/16/2015 11/17/2015 0.75 COMPZN RPCOMP PUTB P Continue to RIH as per"New Revised 3,000.0 3,629.0
23:15 00:00 5 GLM"Run order from 3,000-ft to
3,629-ft 54K Up wt,50K Dn Wt RIH
with packer at 90 ft/min.max.speed
and easy on/off the slips.
11/17/2015 11/17/2015 12.00 COMPZN RPCOMP PUTB P Continue to RIH as per"New Revised 3,629.0 10,931.0
00:00 12:00 5 GLM"Run order from 3,629-ft to
10,889-ft 116K Up wt,66K Dn Wt RIH
with packer at 90 fUmin. max.speed
and easy on/off the slips. Locate
SBE with seals @ 10,915-ft @ 1.4
bpm and No-go with seals 10,931-ft
11/17/2015 11/17/2015 1.50 COMPZN RPCOMP CRIH P PJSM, Pump 110 bbls of CI 9.8 ppg 10,931.0 10,931.0
12:00 13:30 NaCI Brine followed 67 bbls Neat
Brine to Spot between Packer and
SBE. 3 bpm @ 440 psi.
11/17/2015 11/17/2015 2.00 COMPZN RPCOMP PACK P PJSM,Set 3-1/2 x 7"Baker Premier 10,931.0 7,966.0
13:30 15:30 Packer at 7,991-ft by pressuring up to
2,000 psi,while Slacking off to 50K
and increasing pressure to 3,000 psi.
Pull over and shear seal assembly
from the PBR at 7,966-ft.
11/17/2015 11/17/2015 1.25 COMPZN RPCOMP HOSO P Space out 7-ft from PBR and mark 7,966.0 7,964.0
15:30 16:45 pipe. POOH and pu, MU and RIH w/
14.41-ft of space out pups below jt#
337. PU and MU FMC Tubing
Hanger. Locate seal entry and PU 2-
ft.
11/17/2015 11/17/2015 0.75 COMPZN RPCOMP SFTY P Held 2015 4th quarter assesment 7,964.0 7,964.0
16:45 17:30 review with town management and
Nabors day light crew.
11/17/2015 11/17/2015 1.50 COMPZN RPCOMP CRIH P PJSM, Pump 280 bbls of CI 9.8 ppg 7,964.0 7,964.0
17:30 19:00 NaCI Brine above PBR at 6 bpm @
325 psi.
11/17/2015 11/17/2015 1.50 COMPZN RPCOMP THGR P PJSM, Insert seal assembly and land 7,964.0 7,981.0
19:00 20:30 TBG Hanger. RILDS.
Page 6/8 Report Printed: 3/15/2016
• •
Operations Summary (with Timelog Depths)
&We11s
1 D-36
ConocoPhillips
At; s
Rig: NABORS 9ES Job: RECOMPLETION
Time Log
Start Depth
Start Time End Time Dur(hr) Phase Op Code Activity Code Time P-T-X Operation (ftKB) End Depth(ftKB)'.
11/17/2015 11/17/2015 3.00 COMPZN RPCOMP PRTS P Close Blind rams and pressure up to 7,981.0 0.0
20:30 23:30 3,000 psi on tubing for 30 minutes-
good test. Reduce pressure to 1,500
psi and Pressure test the IA to 2,500
psi for 30 minutes-Good test. Bleed
off IA first then the TBG and ramp up
the pressure on the IA to 2,700 psi
with no shear. Attempt multiple times
and never able to shear the SOV.
Also tried TBG dumps with pressure
on the IA. Decide to move forward
with operation.
11/17/2015 11/18/2015 0.50 COMPZN RPCOMP OTHR P RD and Blow down all circulating 0.0 0.0
23:30 00:00 system
11/18/2015 11/18/2015 0.50 COMPZN WHDBOP MPSP P Dry rod BPV into place. 0.0 0.0
00:00 00:30
11/18/2015 11/18/2015 1.00 COMPZN WHDBOP OTHR P Conduct multiple sim ops- 0.0 0.0
00:30 01:30 Continue to clean out mud system
from rotary table throughout the pits.
Blow down kill line,choke line,stand
pipe and hole fill line. Offload all
Weatherford equipment.
11/18/2015 11/18/2015 2.00 COMPZN WHDBOP OTHR P Lift rotary floor cover and clean out 0.0 0.0
01:30 03:30 from underneath in ditch pan.
11/18/2015 11/18/2015 1.75 COMPZN WHDBOP NUND P Pull mouse hole and riser. Remove 0.0 0.0
03:30 05:15 turn buckles and ND BOP stack.
11/18/2015 11/18/2015 2.00 COMPZN WHDBOP NUND P Load adapter in cellar with loader 0.0 0.0
05:15 07:15 assistance. Clean surface area for
metal to metal seal to be installed. NU
well head adapter for tree.
11/18/2015 11/18/2015 1.00 COMPZN WHDBOP PRTS P Pressure test the adapter and seals at 0.0 0.0
07:15 08:15 250/5,000 psi,had surface leaks-
fixed and retested-good test.
11/18/2015 11/18/2015 1.00 COMPZN WHDBOP NUND P NU Tree to adapter,tighten flanges, 0.0 0.0
08:15 09:15 install 1502 integral on wing valve.
11/18/2015 11/18/2015 0.50 COMPZN WHDBOP MPSP P Dry rod out thye BPV and install tree 0.0 0.0
09:15 09:45 test plug(TWC)
11/18/2015 11/18/2015 2.00 COMPZN WHDBOP PRTS P RU to test hydro test tree,found 0.0 0.0
09:45 11:45 bleeder line to be froze,thaw out and
continue to test tree at 250/5,000 psi
for 10 minutes.and bleed off. RD test
equipment and bleed 3 gallons of
diesel back from the wing valve to Top
cap.
11/18/2015 11/18/2015 0.25 COMPZN WHDBOP MPSP P Dry rod out the TWC. 0.0 0.0
11:45 12:00
11/18/2015 11/18/2015 4.00 COMPZN WHDBOP SLKL T PJSM,RU Halliburton Slick line 0.0 0.0
12:00 16:00 services and MU tools to pull Dummy
valve from station#1 to freeze protect
well. Pull valve and RD slick line
services.
11/18/2015 11/18/2015 4.00 COMPZN WHDBOP FRZP P PJSM with LRS on freeze protecting 0.0 0.0
16:00 20:00 well thru Station#1 at 3,433-ft MD and
2,000-ft TVD. Pump 90 bbls to the
open pocket at 1,400 psi while
maintaining 350 psi back pressure on
the choke,30 bbls at 1,200 while
maintaining 350 psi back pressure on
the choke. Close well in and RU and
U-tube well for 1 hr.
Page 7/8 Report Printed: 3/15/2016
• •
ing Operations Summary (with Timelog Depths)
&W
1 D-36
Conor:Whilliips
Rig: NABORS 9ES Job: RECOMPLETION
Time Log
Start Depth
Start Time End Time Dur(hr) Phase Op Code Activity Code Time P-T-X Operation (ftKB) End Depth(ftKB)
11/18/2015 11/18/2015 1.50 COMPZN WHDBOP MPSP P Lubricate in BPV,and Pressure test in 0.0 0.0
20:00 21:30 the direction of flow w/1.6 bbls
pumped to obtain 1,000 psi below the
BPV-no returns through tree. Bleed
off pressure and RD lubricator and
LRS.
11/18/2015 11/18/2015 2.49 DEMOB MOVE RURD P Obtain well SIP's 0.0 0.0
21:30 23:59
TBG=0, IA=0 and OA=470 psi
Secure well and clean and clear cellar
area, Pull fluid from kill tank and prep
rig for pulling off well.
Release Nabors 9ES at 23:59 hrs on
11-18-15
Page 8/8 Report Printed: 3/15/2016
2-.00- 3
z,/-12.3
WELL LOG TRANSMITTAL#902780133
DATA LOGGED
A / /2015
K.BENDER
To: Alaska Oil and Gas Conservation Comm. October 30, 2015
Attn.: Makana Bender
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
ECEIVED
RE: Leak Detect Log with TMD3D: 1D-36 NOV 0 3 2015
Run Date: 9/26/2015
AOG CC
The technical data listed below is being submitted herewith. Please address any problems or
concerns to the attention of:
Fanny Sari, Halliburton Wireline &Perforating, 6900 Arctic Blvd., Anchorage, AK 99518
FRS_ANC@halliburton.com
1D-36
Digital Data in LAS format, Digital Log file 1 CD Rom
50-029-22973-00
SCANNED ; t.
Leak Detect Log with TMD3D (Field print) 1 Color Log
50-029-22973-00
PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE
TRANSMITTAL LETTER TO THE ATTENTION OF:
Halliburton
Wireline &Perforating
Attn: Fanny Sari
6900 Arctic Blvd.
Anchorage, Alaska 99518
Office: 907-275-2605
Fax: 907-273-3535
FRS_ANC@halliburton.com
Date: Signed: /1/ Q/Zee lea.., -` / ,/
vOF r�� • •
• w��\I%% s THE •
STATE AlaskaOit n Gas
41.14t- �� of ASKA
T Conservation Commission
_ 333 West Seventh Avenue
Anchorage, Alaska 99501-3572
� GOVERNOR BILL WALKER g
*.' Main: 907.279.1433
LAS Fax: 907.276.7542
U V3 www.aogcc.alaska.gov
Andrew Beat *
Sr. Wells Engineer ^
ConocoPhillips Alaska, Inc. :7 )00 ^ ` 30
P.O. Box 100360
Anchorage, AK 99510
Re: Kuparuk River Field, Kuparuk River Pool, KRU 1D-36
Sundry Number: 315-623
Dear Mr. Beat:
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 AOGCC grants for good cause shown, a person affected by it may file with the
AOGCC an application for reconsideration. A request for reconsideration is considered timely if
it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working
day if the 23rd day falls on a holiday or weekend.
Sincerely,
Cathy . Foerster
Chair
DATED this /3y of October, 2015
Encl.
3C-
RBDMS OCT 14 2015
F f. t
STATE OF ALASKA
' - ' A•KA OIL AND GAS CONSERVATION COM•ION OC1 0 6 2015
APPLICATION FOR SUNDRY APPROVALS 10 d l !S
20 AAC 25.280 ar G
CG
1.Type of Request: Abandon r Rug Perforations r Fracture Stimulate r Pull Tubing p„ Operations Shutdown r
Suspend r Perforate r Other Stimulate r Alter Casing V Change Approved Rogram r
Plug for Redrill r Perforate New Pool
Repair Well p.. Re-enter Susp Well r Other: PG kak ff."'
2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number:
ConocoPhillips Alaska, Inc. - Exploratory r Development p 1 200-130 -
3.Address: Stratigraphic r Service 1"--
6.API Number:
P.O. Box 100360,Anchorage,Alaska 99510 50-029-22973-00
7.If perforating, 8.Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Will planned perforations require spacing exception? Yes r No J KRU 1 D-36 4
9.Property Designation(Lease Number): 10.Field/Pool(s):
ADL 25661,25650 Kuparuk River Field/Kuparuk River Oil Pool
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):
11658 6542 11589' 6510' none none
Casing Length Size MD TVD Burst Collapse
CONDUCTOR 88 20 121' 121'
SURFACE 7012 9.625 7047' 4297'
PRODUCTION 11007 7 11038' 6245'
LINER 771 3.5 11656' 6541'
Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft):
11410-11484 - 6426-6461 3.5 L-80 10918
Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft)
PACKER-BAKER ZXP LINER TOP PACKER MD=10893 TVD=6174
PACKER-WEATHERFORD WS-R-BB PACKER MD=11370 TVD=6406
NIPPLE-CAMCO'DS'NIPPLE w/2.875"NO GO PROFILE MD=545 TVD=544 -
12.Attachments: Description Summary of Proposal p' 13. Well Class after proposed work:
Detailed Operations Program r BOP Sketch r Exploratory r Stratigraphic r Development F. Service r
14.Estimated Date for Commencing Operations: 15. Well Status after proposed work:
11/1/2015 OIL p, WINJ r WDSPL r Suspended r
16.Verbal Approval: Date: GAS r WAG r GSTOR r SPLUG r
Commission Representative: GINJ r Op Shutdown r Abandoned r
17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Andrew Beat @ 265-6341
Email: Andrew.T.Beat(cr�conocoohillips.com
Printed Name An Beat Title: Sr. Wells Engineer
Signature Phone:265-6341 Date /V/'j/ZOI5
Commission Use Only
Sundry Number:
Conditions of approval: Notify Commission so that a representative may witness ?j 1;—4013
Plug Integrity r BOP Test 1w Mechanical Integrity Test r Location Clearance r
Other: al,p 1t --f t' Uf7O p5/4,- c1
1-1/7 ��dCf., �Jr�Cr���-tom ' �� 1251,
Spacing Exception Required? Yes ❑ No 2/ Subsequent Form Required: /O_-'" ft
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date: /0 —/3 —/
A v a I II for 12 months fro the date of a royal.
p G
� 4t6P i 7-a �
!� I !dJ/ pp Submit For and
Form 10-40� d 520157-7 .0 _ A)0/ t 111ttel 14 2015
• •
lopv E
ConocoPhillips
Alaska
P.O. BOX 100360 AOGCC
ANCHORAGE,ALASKA 99510-0360
October 5,2015
Commissioner
State of Alaska
Alaska Oil&Gas Conservation Commission
333 West 7th Avenue Suite 100
Anchorage,Alaska 99501
Dear Commissioner:
ConocoPhillips Alaska,Inc.hereby submits an Application for Sundry Approval to work over Kuparuk Producer
1D-36(PTD#200-130).
1D-36 was originally drilled and completed in 2000 as a'C' sand,gas lifted producer in Kuparuk.In 2005,Coil
Tubing Drilling drilled two laterals into the C sand. The well was shut in in September 2015 when it failed a CMIT.
A LDL identified tubing leaks between 9,770' KB and 9,810' KB and a production casing leak between 8,125' KB
and 8,250' KB.
The proposed workover scope for 1D-36 will cover pulling the existing 3-1/2"completion from the SBE located
below the liner top packer and installing a new 3-1/2"completion with a packer set above the production casing leak
for isolation. v
If you have any questions or require any further information,please contact me at 265-6341.
Sincerely
7Ak,
Andrew Beat
Wells Engineer
CPAI Drilling and Wells
• 1D-36 Rig Workover •
P&R Tubing w/Stack Packer
(PTD#:200-130)
Current Status: This well has been shut in since September 2015 and is currently waiting to be worked over to
replace tubing and isolate a production casing leak.
Scope of Work: Pull the existing 3-1/2"tubing, install new 3-1/2"completion with a stacked packer to isolate
production casing leak.
General Well info:
Well Type: Producer
MPSP: 2,464 psi using 0.1 psi/ft gradient
Reservoir Pressure/TVD: 3,103 psi/6,390' TVD(9.4 ppg EMW)measured on 08/19/2013
Wellhead type/pressure rating: FMC Gen V, 11"5M psi top flange
BOP configuration: Annular/Pipe Rams/Blind Rams/Mud Cross/Pipe Rams
MIT results: CMIT-TxIA failed-9/17/2015
Earliest Estimated Start Date: November 12,2015
Production Engineer: Trey Sylte
Workover Engineer: Andrew Beat(263-6341/Andrew.T.Beat@ConocoPhillips.com)
Pre-Rig Work
1. Inspect pad and work area for hazards. Complete the PJSM.
2. RU Slickline.
3. Replace valves with DV's in GLM#1-4 and leave GLM#5 open.
4. RD Slickine.
5. PT POs and FT LDS.
Set BPV w/i 24 hrs of rig arrival.
Workover Procedure
1. MIRU.
2. Pull BPV.Reverse circulate KWF. Obtain SITP&SICP,if still seeing pressure at surface,calculate new KWF,
weight up,and repeat circulation as necessary.Verify well is dead.
3. Set BPV,ND tree,NU BOPE&test to 250/3,000 psi.
a. If the lower pipe rams are unable to be tested because of the blanking plug position,the lower pipe
rams will be tested upon pulling the completion.
4. Pull BPV,screw in landing joint,BOLDS's,unland tubing hanger.
5. POOH laying down 3 '/2"tubing.
6. RIH with new completion and isolating packer to just above SBE.
7. Spot a balanced pill of corrosion inhibited brine in the Tbg and IA from the SBE up to surface.
8. Slowly cycle the charge pump and look for pressure increase or lack of returns as the seals engage. Shut down
charge pump and space out.Drop the ball and pressure up to set the packer.
a. PT the IA to confirm packer set.
9. Shear the PBR,space out,mark the pipe,and pull seals from PBR.
10. Install space out pups below the tubing hanger,MU tubing hanger.
11. Land the til in'g hanger,RILDS. 7
12. PT the tubing,bleed tubing,PT the IA,and record.Bleed the IA to zero,then tubing.Ramp up the IA pressure
quickly to shear the SOV.
13. Pull the landing joint, install BPV.Pressure test the BPV from below.
14. ND BOPE.
1
• 1D-36 Rig Workover •
P&R Tubing w/Stack Packer
(PTD#:200-130)
15. NU tree.Pull BPV and install tree test plug.Test tree and pull test plug.
16. Freeze protect well with diesel. Set BPV.
17. RDMO.
Post-Rig Work
1. Pull BPV.
2. RU Slickline to pull ball and rod, SOV,and run gas lift design.
3. Reset well house(s)and flowlines of adjacent wells.
4. Turn well over to operations.
2
. . . . • • 1 D-36
ConocoPhillups KRU Producer
P&R Tubing w/
Well Details: Stacked Packer
API: 500292297300 PROPOSED
PTD: 200-130
Wellhead: FMC Gen V 5M COMPLETION
Tree: WKM 3" 5M
Casing/Tubing Details:
20" 72# H-40 Conductor to 121' KB
9-5/8"40# L-80 Surface to 7,046' KB -
7"26#L-80 Production to 11,038' KB
3-1/2" 9.3# L-80 Tubing to 10,918' KB
Misc Details:
Max Inclination: 62.25° — Camco 3-1/2" x 1-1/2" MMG GLM's
Max Dogleg: 6.77 °/100'
Last Tagged Fill: 11,450' KB
Total Depth: 11,658' KB
Perforation Details:
11,410'-11,420' KB–C 2 Sand ---
11,420'-11,484' KB–C 1-2 Sands –8,080' PBR
. _ 8,100' Isolation Packer
8,125'-8,250' Production Casing Leak
10,800' Nipple
if10,892' Existing Liner Top Packer w/ SBE
a
CTD Laterals
-
C Sand Perfs
—
Date: October 5,2015 I Drawn By: Andrew Beat
KUP PROD ID-36
6
ConocoPhillips 2 Well Attributes Max Angle&MD TD
Alaska,Inc. Wellbore API/UWI Field Name Wellbore Status ncl(') MD(ftKB) Act Btm(f(KB)
G.....%tdhpl 500292297300 KUPARUK RIVER UNIT PROD 62.25 4,980.84 11,658.0
.-. Comment H2S(ppm) Date Annotation End Date KB-Grd(U) Rig Release Date
1D-36.9/920153:52:17 PM SSSV:NIPPLE 50 12/162013 Last WO: 36.30 9/18/2000
Vertical schematic(actual) Annotation Depth(ftKB) End Date Annotation Last Mod By End Date
Last Tag: 11,450.0 4/30/2005 Rev Reason:GLV C/O lehallf 9/9/2015
HANGER 29.2 - -ir
Fri asing rings
U.S.1, - l`J Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)... Wt/Len(I...Grade Top Thread
AI CONDUCTOR 20 19.250 33.0 121.0 121.0 72.00 H-40 Welded
Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...Wt/Len(I...Grade Top Thread
kilokilo SURFACE 95/8 8.697 34.4 7,046.8 4,297.1 40.00 L-80 BTCM
CONDUCTOR;33 0-121.0 1 '''ilii p Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(TVD)... Wt/Len(I...Grade Top Thread
PRODUCTION 7 6.276 31.4 11,038.4 6,244.8 26.00 L-80 BTCM
Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...Wt/Len(I...Grade Top Thread
at WINDOW L2 312 2.992 11,360.0 11,364.0 6,403.2 9.30 L-80 SLHT
Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...WtlLen(I...Grade Top Thread
NIPPLE;544.7 WINDOW LI 312 2.992 11,407.0 11,411.0 6,426.0 9.30 L-80
Casing Description OD(in) ID(in) Top(ftKB) Set Depth(ftKB) Set Depth(ND)...Wt/Len(I...Grade Top Thread
II LINER 312 2.992 10,885.2 11,656.0 6,541.2 9.30 L-80 SLHT
a Liner Details
1 Nominal ID
GAS LIFT;3,654.7 Top(ftKB) Top(ND)(ftKB) Top Incl(°) Item Des Com (in)
l 10,885.2 6,169.9 60.84 TIE BACK LINER TIE BACK SLEEVE 5.500
10,892.5 6,173.5 60.82 PACKER BAKER ZXP LINER TOP PACKER 4.408
1 ill
10,900.0 6,177.1 60.80 HANGER BAKER FLEX-LOCKLINER HANGER w/RS NIPPLE 4.400
GAS LIFT;5.481.1 10,912.5 6,183.3 60.77 SBE BAKER 80-40 SBE 4.000
1111 10,971.2 6,212.0 60.62 NIPPLE HES'XN'NIPPLE w/2.75 NO GO PROFILE 2.750
Tubing Strings
Tubing DescriptionString Ma... Top(ftKB) Set Depth In..Set Depth(TVD)(...Wt(Ib/ft) Grade Top Connection
TUBING I 3 1/21ID(in)2.9921 29.21 10.918.01 6,185.9, 9.301 L-80 I EUE8rdMOD
Completion Details
SURFACE;34.4-7,046.8- Nominal ID
Top(ftKB) Top(ND)(ftKB) Top Incl(3 Item Des Com (in)
29.2 29.2 0.03 HANGER FMC GEN V TUBING HANGER 3.500
GAS LIFT;8,236.8 E.r. 544.7 544.1 7.45 NIPPLE CAMCO'DS'NIPPLE w/2.875"NO GO PROFILE 2.813
I 10,870.9 6,163.0 60.88 NIPPLE CAMCO'DS'NIPPLE w12.813"NO GO PROFILE 2.813
10,917.0 6,185.4 60.76 SEAL ASSY BAKER GBH NO GO LOCATOR SEAL ASSEMBLY 3.000
Other In Hole(Wireline retrievable plugs,valves;pumps,fish,etc.)
GAS LIFT;9,705.6 Top(ND) Top Incl
ell Top(ftKB) (ftKB) (`) Des Com Run Date ID(in)
11,370.0 6,406.1 60.85 PACKER Weatherford WS-R-BB Packer Set in Main Bore 7/22/2005 1.250
Liner
® 11,410.0 6.425.5 61.26 Whipstock WHIPSTOCK TO L1,set 7/22/2005 7/22,2005 1.250
GAS LIFT;10,818.7
Perforations&Slots
Shot
Dens
Top(TVD) Bttn(ND) (shotslf
®
Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date tl Type Com
NIPPLE;10,870.9III
11,410.0 11,420.0 6,425.5 6,430.3 C-2,1D-36 10/28/2000 4.0 IPERF 2.5"BH HSD
® 11,420.0 11.484.0 6,430.3 6,460.7 C-2,C-1,10- 7/12/2003 6.0 APERF 2.5"1-1SO 2506 PJ HMX
36 60 Deg Ph
B s
Stimulations&Treatments
Min Top Max Btm
'iDepth Depth Top(ND) Btm(ND)
II (ftKB( (ftKB) (ftKB) (ftKB) Type Date Corn
m
l 11,410.0 11 420.0 6,425.5 6,430.3 FRAC 10/30/200 INITAL'C'SAND FRAC
0
SEAL Asst;,0.917.0
Ink= Mandrel Inserts
St
0 ah
on Top(IVO) Valve Latch Port Size TRO Run
N Top(ftKB) (ftKB) Make Model OD(in) Sery Type Type (in) (psi) Run Date Com
1 3,654.7 2,611.1 CAMCO MMG 11/2 Gas Lift GLV RK 0.188 1,222.0 8/21/2012
2 6,481.1 4,015.5 CAMCO MMG 11/2 Gas Lift GLV RK 0.188 1,221.0 8/21/2012
3 8,236.8 4,876.0 CAMCO MMG 1 1/2 Gas Lift OV RK 0.250 0.0 9/8/2015
4 9,705.6 5,592.8 CAMCO MMG 1 1/2 Gas Lift DMY RK 0.000 0.0 7/11/2005
5 10,818.7 6,137.6 CAMCO MMG 11/2 Gas Lift DMY RK 0.000 0.0 7/13/2008
Notes:General&Safety
PRODUCTION;31.4-11.038.d End Date Annotation
8/1/2005 NOTE.MULTI-LATERAL WELL 1D-36,10-36L1,10-36L2 ALL C-SANDS
1/8/2009 NOTE.View Schematic w/Alaska Schematic9.0
WINDOW L2;11.360.0-11,364.0
PACKER;11.370.0
III18
IPERF;11,406.0-12,261.0
LINER LI;11,394.5-13,310.0
Whipstock;11,410.0 I
WINDOWERF;11,44.0.11,420.0.0-11,411D X ;N. 1
FRAC;11,410.0
APERF;11,420.0-11,484.0
LINER;10,885.1-11,656.0
XHVZE
Project Well History File C~" -" age
This page identifies those items that were not scanned during the initial production scanning
phase. They are available in the original file, may be scanned during a special rescan activity or
are viewable by direct inspection of the file.
~_ ~)O- _~__ (~ Well History File Identifier
Organizing
RESCAN
Color items:
[] Grayscale items:
Poor Quality Originals:
Other:
NOTES:
Diskettes, No.
[] Other, No/Type
BY:
BEVERLY ROBIN VINCENT SHERYL ~ WINDY
OVERSIZED (Scannable)
[] Maps:
rn Other items scannable by
large scanner
OVERSIZED (Non-Scannable)
[] Logs of various kinds
[] Other
Project Proofing
BY:
BEVERLY ROBIN VINCENT SHERYI..~INDY
Scanning Preparation L~ x 30 = ~ + (:~-. = TOTAL PAGES
BY'. BEVERLY ROBIN VINCENT SHERYi~~'VINDY DATE:(3~/~II~O~S/ ~f~p
Production Scanning
Stage I PAGE COUNT FROM SCANNED FILE:
BY:
Stage 2
BY;
(SCANNING IS COMPLETE AT THIS POINT UNLESS SPECIAL ATTENTION IS REQUIRED ON AN INDIVIDUAL PAGE BASIS
DUE TO QUALITY, GRAYSCALE OR COLOR IMAGES)
PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: /,~ YES NO
BEVER'~~VINCENT SHERYL MARIA WINDY
IF NO IN STAGE 1, PAGE(S)DISCREP~I~'~V~RE FOUND: YES NO
RESCANNEDBY: BEVERLY ROBIN VINCENT SHERYL MARIA WINDY DATE:
Is~
General Notes or Comments about this file:
Quality Checked
12/10/02Rev3NOTScanned.wpd
1D-01 (PTD 1790590) & 1D-36 (PI2001300) failed TIFL's
Regg, James B (DOA)
.
Page 1 of 1
From: NSK Problem Well Supv [n1617@conocophillips.com]
Sent: Friday, August 17, 200710:15 AM
To: Maunder, Thomas E (OOA); Regg, James B (OOA)
Cc: NSK Well Integrity Proj; NSK Problem Well Supv
Subject: 10-01 (PTO 1790590) & 10-36 (PTO 2001300) tailed TIFL's
Attachments: 10-36 schematic. pdt; 10-3690 day TIO plot.jpg; 10-01 schematic. pdt; 10-01 90 day TIO plot.jpg
Tom & Jim,
,/
Kuparuk gas lifted producer 10-01 (PTO 1790590) tailed a TIFL on 08/16/07 and has been added to the SCP report. The TIO
immediately prior to SI tor the TIFL was 135/1150/740. A leaking GLV check is suspected. Slickline will troubleshoot the tubing
leak and repair it possible.
¡./'
Kuparuk gas lifted producer 10-36 (PTO 2001300) tailed a TIFL on 08/16/07 and has been added to the SCP report. The TIO .,/
immediately prior to SI tor the TIFL was 145/1290/540. A leaking GL V check is suspected. Slickline will troubleshoot the tubing
leak and repair it possible.
Attached are the schematics and 90 day TIO plots tor both wells.
Please let me know it you have questions.
«10-36 schematic. pdt» «10-3690 day TIO plot.jpg» «10-01 schematic. pdt» «10-01 90 day TIO plot.jpg»
Brent Rogers
Problem Wells SupeNisor
659-7224
SCANNED AUG 2 3 2007
8/21/2007
.
.
KRU 1 D-36
API: 500292297300 Well Type: PROD Anole (â) TS: 61 dea (â) 11358
SSSV Type: NIPPLE Orio Completion: 9/18/2000 AnQle (â) TD: 62 deo (â) 11658
NIP (545-546. Annular Fluid: Last W/O: Rev Reason: GLVC/O
00:3.500) Reference Loa: 29.22' RKB Ref Loo Date: Last Update: 12/15/2005
Last Taa: 11450 TD: 11658 ftKB
laDate: 4/30/2005 Max HOle,-11560
Gas Lift DescriDtion Size TOD Bottom TVD Wt Grade Thread
MandrelNalve SURFACE 9.625 0 7047 4297 40.00 L-80 BTCM
1 PRODUCTION 7.000 0 11038 6245 26.00 L-80 BTCM
(3655-3656, CONDUCTOR 20.000 0 121 121 72.00 H-40 Welded
LINER 3.500 10885 11656 6541 9.30 L-80 SLHT
Gas Lift WINDOW to L2 3.500 11360 11364 6403 9.30 L-80 SLHT
MandrelNalve VVII~UVVV IO L 1 3.500 11410 114 15 6428 9.30 L-80 SLHT
2
(6481-6482, I Size I TOD I Bottom I TVD Wt I Grade I Thread 1
1 3.500 1 0 I 10885 1 6170 9.30 1 L-80 1 Bìï
Gas Lift
MandrelNalve I Interval I TVD 1 Zone 1 Status 1 Ft 1 SPF I Date 1 TVDe 1 Comment I
3 1 11410-11420 1 6425 - 6430 C-2 10 4 10/28/2000 IPERF 12.5" BH HSD
(8237-8238, 11420 - 11484 6430 - 6461 1 C-2,C-1 1 1 64 1 6 I 7/12/2003 APERF 12.5" HSD 2506 PJ HMX, 60
j¡¡Irval I ~ TYDe ~ Comment
- 1420
St MD TVD Man Mfr Man Type V Mfr V Type V OD Latch Port TRO Date Vlv
Run Cmnt
1 3655 2611 CAMCO MMG CAMCO GLV 1.5 RK 0.250 1285 12/4/2005
2 6481 4015 CAMCO MMG CAMCO GLV 1.5 RK 0.250 1280 12/4/2005
3 8237 4876 CAMCO MMG CAMCO OV 1.5 RK 0.313 0 12/4/2005
~ 1.5 RK 0.000 0 7/11/2005
NIP .5 RK 0
(10871-10872, , ~,,"
00:3.500) Depth TVD Type Description ID
545 544 NIP Camco 'DS' Nipple wiNo-Go Profile 2.875
TUBING 10871 6163 NIP Camco 'DS' Nipple wiNo-Go Profile 2.813
(0-10885, 10885 6170 Tie Back BAKER TIE BACK SLEEVE 5.250
00:3.500, Sleeve
10:2.992) 10892 6173 PACKER BAKER ZXP LINER TOP PACKER 5.000
10912 6183 SBE BAKER SBE '80-40' wlTKC couplinos 4.000
10918 6186 SEAL Baker GBH-22 Seal Assemblv: 17' lono: 15' stroke 3.000
10971 6212 NIP 'XN' Nipple w/2.75" No-Go 2.750
11370 6406 PACKER WEATHERFORD WS-R-BB PACKER set 8/1/2005 1.250
11394 6418 Deploy Sub BTT SEAL BORE DEPLOYMENT SLEEVE TO LATERAL LEG L 1 set 8/1/2005 2.250
L1
11410 6425 Whipstock LSX FL -THRU WHIPS_8/1/2005 1.250
Date I Note
8/1/2005 1 MULTI-LATERAL WELL: MAIN LEG 10-36, CI/C2-SANDS 1D-36L1!, C3/C4-SANDS l1D-36L2
SEAL
(10918-10919,
00:5.125)
NIP
(10971-10972,
00:3.500)
, =>
FRAC ~ ~
:11410-11420)
Perf
:11410-11420! ª
Perf - -
:11420-11464) -- -
.
.
Conoc;Phillips
Alaska
RECEIVED
AUG 1 3 2007
Alaska OD & Gas Cons. Commission
Anchorage
P.O. BOX 100360
ANCHORAGE, ALASKA 99510-0360
August 9,2007
Mr. Tom Maunder
Alaska Oil & Gas Commission
333 West 7th Avenue, Suite 100
Anchorage, AK 99501
aDÙ- t3D
sCANNED AUG 14'2007
Dear Mr. Maunder:
Enclosed please find a spreadsheet with a list of wells from the Kuparuk field (KRU). Each of
these wells was found to have a void in the conductor. These voids were filled with a corrosion
inhibiter, RG2401, engineered to prevent water from entering the annular space. As per previous
agreement with the AOGCC, this letter and spreadsheet serves as notification that the treatments
took place and meets the requirements of form 10-404, Report of Sundry Operations.
The corrosion inhibitor/sealant was pumped August 8, 2007. The attached spreadsheet presents
the well name, top of cement depth prior to filling, and volumes used on each conductor.
Please call me at 907-659-7043, if you have any questions.
Sincerely,
~-
ConocoPhillips Well Integrity Projects Supervisor
~
.
.
ConocoPhillips Alaska Inc.
Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off
Report of Sundry Operations (10-404)
Kuparuk Field
Corrosion
Initial top of Vol. of cement Final top of Cement top off Corrosion inhibitorl
Well Name PTO# cement pumped cement date inhibitor sealant date
ft bbls ft aal
1 0-32 200-173 10" n/a n/a n/a 6.8 8/8/2007
1 0-36 200-130 20" nIa n/a n/a 4.2 8/8/2007
10-37 200-204 20" n/a n/a n/a 4.2 8/8/2007
1 0-38 200-077 24" n/a n/a n/a 4.2 8/8/2007
1 0-39 200-216 27" n/a n/a n/a 7.6 8/8/2007
1 0-40 200-190 13" n/a n/a n/a 3.4 8/8/2007
10-41 205-188 12" n/a n/a n/a 1.7 8/8/2007
10-42 200-164 16" n/a n/a n/a 3.4 8/8/2007
10-131 198-110 6" n/a n/a n/a 2 81812007
Date
8/9/2007
11/21/06
Sc~lIIRbepgep
NO. 4049
Schlumberger -DCS
2525 Gambell Street, Suite 400
Anchorage, AK 99503-2838
A TTN: Beth
9 ?DOG
Company: Alaska Oil & Gas Cons Comm
Attn: Christine Mahnken
333 West 7th Ave, Suite 100
Anchorage, AK 99501
[)ÖO -l3õ
Sf""' t ~'!\'C~¡;;n
...;.v¿~ '", lie.......
Kuparuk
_f) r ..' r-~_ F
t::-" -Field:
l
Well
Job#
Log Description
Date
Color
CD
BL
2U-09 11416231 SBHP SURVEY 10/29/06 1
3J-18 11483494 GLS 11/13/06 1
3J-13 11483495 INJECTION PROFILE 11/14/06 1
1R-07 11486070 SBHP SURVEY 11/11/06 1
2X-17 11486068 PRODUCTION PROFILE 11/09/06 1
1 D-36 . 11486077 SBHP SURVEY 11/19/06 1
1D-120 - 11486073 INJECTION PROFILE 11/14/06 1
1 R-35 - 11486074 PROD PROFILE-INCOMPLETE OPERATION 11/15/06 1
1;
Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you.
o /,It-
.
.
F:\LaserFiehe\CvrPgs _I nserts\M ierof¡ I m _ Marker.doe
MICROFILMED
04/01/05
DO NOT PLACE
ANY NEW MATERIAL
UNDER THIS PAGE
¡fI'
.'bI;'Ii,r
)
)
ConocOPhillips
Mike Mooney
Wells Group Team Leader
Drilling & Wells
P. O. Box 100360
Anchorage, AK 99510-0360
Phone: 907-263-4574
August 11,2003
Commissioner
State of Alaska
Alaska Oil & Gas Conservation Commission
333 West 7th Avenue Suite 100
Anchorage, Alaska 99501
Subject: Report of Sundry Well Operations for 1D-36 (APD # 200-130)
Dear Commissioner:
ConocoPhillips Alaska, Inc. submits the attached Report of Sundry Well Operations
for the recent perforating operations on the Kuparuk well 1 D-36.
If you have any questions regarding this matter, please contact me at 263-4574.
Sincerely,
M. Mooney
Wells Group Team Leader
CPAI Drilling and Wells
MM/skad
SCANNE SEP 0 ~ 2,003
OR!GINA
.,
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
1. Operations Performed: Abandon [--] Suspend E~] Operation Shutdown ~] Perforate E~ variance [] Annular Disp.
Alter Casing E~] Repair Well E] Plug Perforations E~ Stimulate [~ Time Extension [~ Other []
Change Approved Program r'] Pull Tubing D Perforate New Pool r-1 Re-enter Suspended Well
2. Operator Name: 4. Current Well Status: 5. Permit to Drill Number:
ConocoPhillips Alaska, Inc. Development r~ Exploratory [] 200-130 /
3. Address: Stratigraphic E~ Service E~ 6. APl Number:
P. O. Box 100360, Anchorage, Alaska 99510 50-029-22973-00
7. KB Elevation (ft): 9. Well Name and Number:
RKB 105' 1 D-36
8. Property Designation: 10. Field/Pool(s):
ADL 25661 & 25650, ALK 471 Kuparuk River Field / Kuparuk Oil Pool
11. Present Well Condition Summary:
Total Depth measured 11658' feet
true vertical 6542' feet Plugs (measured)
Effective Depth measured 11564' feet Junk (measured)
true vertical 6498' feet
Casing Length Size MD TVD Burst Collapse
Structural
CONDUCTOR 121' 20" 121' 121'
S U RFACE 7012' 9-5/8" 7047' 4297'
PRODUCTION 11003' 7" 11038' 6245'
LINER 771' 3-1/2" 11656' 6541'
Perforation depth: Measured depth: 11410' - 11484' , , ,
, ,,
,
,
,
true vertical depth: 6425' - 6461'
f" ~ ~ "'~ ":'i!~ t~~ '-~: :i: '~
I,,:, I, -: ,~ ,/ ( '~ i,, , '
Tubing (size, grade, and measured depth) 3-1/2", L-80, 10885' MD. .;.
Packers & SSSV (type & measured depth) no packer .
SSSV= NIP SSSV= 545'
12. Stimulation or cement squeeze summary:
Intervals treated (measured) N/A
Treatment descriptions including volumes used and final pressure:
13. Representative Daily Average Production or Injection Data
Oil-Bbl Gas-Mcr Water-Bbl Casin.q Pressure Tubing Pressure
Prior to well operation 167 696 217 - 232
Subsequent to operation 208 518 197 - 209
14. Attachments 15. Well Class after proposed work:
Copies of Logs and Surveys run __ Exploratory F"] Development ['~ Service r'-]
Daily Report of Well Operations __X 16. Well Status after proposed work:
Oil F~-I Gas F-1 WAG F-I GINJ r-'l WINJ ~ WDSPL r-'-~
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:
Contact Mike Mooney @ 263-4574
Printed Name Mike Mooney Title Wells Group Team Leader
Signature ,/~/,~ Phone Date
Prepared bY Sharon AIIsu~;Drake 263'4612
SUBMIT IN DUPLICATE
GConocoPhillips Alaska, Inc.
ID-36
KRU
1 D-36
NIP (545-546,
0D:3.500)
VlandrelNalvE
1 (3656-3~,
OD:5.968)
VlandrelNalvE
2 (6481-6482,
0D:5.968)
Gas L~t
VlandrelNalvE
3 (8237-8238,
OD:5.968)
Gas Lift
VlandrelNalv~
4 (97O6-97O7,
0D:5.968)
NIP
(10871-10872,
0D:3.500)
SEAL
(10918-10.c. 1[.
0D:5.125~
rj.-~
(10971-1072
OD:3.5: :'..
FRAC
(11410-11420)
Peri
(11420-11484)
APl: 500292297300
SSSV Type: NIPPLE
Annular Fluid:
Reference Log:
Last Tag: 11564
Last Tag Date: 7/12/2003
Casing String - ALL STRINGS
Description
CONDUCTOR 20.000 121 121
SURFACE 9.625 0 7047 4297
PRODUCTION 7.000 0 11038 6245
3.500 10885 11656 6541
LINER
Well Type:I PROD
Orig 19/18/2000
Completion:I
Last W/O:I
Ref Log Date:I
TD:111658 ftKB
Max Hole An~lle:162 deg (~ 11560
Size
Top
0
Bottom TVD
Angle @ TS:161 deg @ 11358
Angle @ TD:I62 deg @ 11658
I
Rev Reason:I Post FCO Tag,
IPERFS
Last Update:l 7/19/2003
I
Wt Grade
172.OOl H-40
14o.ool L-8o
I 26.00 I L-80
I 9.30 I L-80
Thread
Welded
BTCM
BTCM
SLHT
Tubing String -TUBING
Size I Top Bottom TVD Wt IGrade I Thread
3.500 I 0 10885 6170 9.30 I L-80 I BTCM
Perforations Summary
Interval TVD I Zone I StatuslFt ISPF Date / Type Comment
11410-11420 6425-6430 I C-2 I I 10 I 4 110/28/20001 IPERF 12.5"BHHSD
11420-11484 6430-6461 I C-2,C-1 I 1641 6 17/12/20031APERFI2.5"HSD2506PJHMX, 60
I I I I I / I Deg Phase
stimulations&Treatments: : :: :: ;::::i: :: ;: ::: : :: :;::: ::::; :;::; :; :::.:: :: ::::::::::
Interval I Date I Type I Comment
11410 - 11420 11013012000 1FRAC I INITAL 'C' SAND FRAC
· ..
Gas·Lift' Mandrels/Valves · .
st l MD I TVD I Man I Man I V Mfr Iv Type I V OD I LatchI Po. I TROI Date I vlv
I I IMfrI Type I I I I I I I Run I Cmnt
1 136551 26111CAMCOI GLM ICAMCOI GLV I 1.5 IRK 10.1881127017/14/20011
2 164811 40151CAMCOI GLM I CAMCOI GEV I 1.5 IRK 10.188 1127817/14/20011
3 I 82371 48761CAMCOI GLM I CAMCOI GLV I 1.5 IRK 10.188 1127617/14/20011
4 I97061 55931CAMCOI GLM I CAMC°I GLV I 1.5 IRK 10.250 11311 17114120011
5 1108191 61381CAMCOI GLM I CAMCOI OV I 1.5 IRK 10.2501 0 17/14/20011
Other (plugs, equip., etc.) - JEWELRY
Depth ITvD I Type Description ID
545 I 544 I NIP I Camco'DS' Nipplew/No-Go Profile 2.875
10871 I 6163 I NIP ICamco 'DS' Nipple w/No-Go Profile 2.813
10912 I 6183 I SBE I BAKER SBE '80-40' w/TKC couplings 4.000
10918 I 6186 I SEAL IBaker GBH-22 Seal Assembly; 17' long; 15' stroke 3.000
10971 I 6212 I NIP I'XN' Nipple w/2.75" No-Go 2.750
Date
Comment
1 D-36 Event History
07/11/03
07/12/O3
07/14/O3
PERFORMED A FCO TO 11,575.2' CTMD. REVERSED TO BO'I-rOM OF PERFS THAN JETTED SUMP TO
SURFACE WITH 2 PPG XCD @ 3 BPM. WASHED MANDRELS ON WAY TO SURFACE. WELL LEFT SHUT
IN FOR ADD PERFS. [FCO]
TAG RH @ 11564' RKB, DRIFT TBG W/20' X 2.25" DUMMY GUN DRIF'I-I'O 11564' RKB [TAG]
PERFORATING. PERFORATE THE INTERVAL 11420 - 11484 (C1 & C-2 SANDS) IN THREE RUNS USING
2.5" HSD GUNS LOADED 6 SPF, 60 DEG PHASING, RANDOM ORIENTATION. CHARGES ARE 2506
POWER JET HMX CHARGES -- APl DATA: 25.2" PENETRATION, 0.32" ENTRANCE HOLE. ALL SHOTS
FIRED.
Page 1 of I 8/11/2003
DATA SUBMITTAL COMPLIANCE REPORT
111612003
Permit to Drill 2001300 Well Name/No. KUPARUK RIV UNIT ID-36
Operator CONOCOPHILLIPS ALASKA INC APl No. 50-029-22973-00-00
MD 11658 TVD 6542 Completion Dat 10/2812000 Completion Statu 1-OIL Current Status 1-OIL UIC N
REQUIRED INFORMATION
Mud Log N.._~o Sample N._.~o Directional Survey Nc)
~- ........................................................................................... .__'"-_--~'.'- '--'~__--T~.~--'~_'._.~__ ~ '~-"-... '~'-'.~- ...................................... '-..---,--~--~'~-~ .... .-~'.'--7---_"2.. --.'_"~_'-~'~-_T'-'~"-'-'
DATA INFORMATION
(data taken from Logs Portion of Master Well Data Maint
Types Electric or Other Logs Run:
Well Log Information:
Log/
Data Digital Digital
Type Media Fmt
-D D
R R
L L
L L
L L
L L
D D
R R
T
L L
D D
R R
D D
Interval
Log Log Run OH I
Name Scale Media No Start Stop CH
Directional Survey FINAL ch
Directional Survey FINAL ch
;~P,/ 5 FINAL 7047 11658 OH
RES
~ G~.ROP/RES 5 FINAL 7047 11658 OH
'~R/DEN/-NEU 5 FINAL 7047 11658 OH
I~ID GR/DEN/NEU 5 FINAL 7047 11658 OH
10122 FINAL 7017 11605 CH
LIS Verification FINAL CH
7017 11605 Open
~Press/Temp 5 FINAL 11150 11570 CH
Directional Survey FINAL ch
GYRO
Directional Survey FINAL ch
Directional Survey FINAL
MWD
Dataset
Received Number Comments
3/1/2001
3/1/2001
5/1/2001
5/1/2001
5/1/2001
5/1/2001
5/1/2001
5/1/2001
5/1/2001
1/3/2001
3/1/2001
3/1/2001
10122
10122
Directional Survey Digital
Data
Directional Survey Paper
Copy
7047-11658 BL, Sepia
7047-11658 BL, Sepia
7047-11658 BL, Sepia
7047-11658 BL, Sepia
7017-11605 Digital Data
LIS Verification
7017-11605
11150-11570 BL, Sepia
Directional Survey Digital
Data
Directional Survey Paper
Copy
Directional Survey Digital
Data
Well Cores/Samples Information:
Name
Interval Dataset
Start Stop Sent Received Number
Comments
ADDITIONAL INFORMATION
Permit to Drill 2001300
DATA SUBMITTAL COMPLIANCE REPORT
1116~2O03
Well Name/No. KUPARUK RIV UNIT 1D-36
Operator CONOCOPHILLIPS ALASKA INC
APl No. 50.029-22973-00.00
MD 11658 TVD 6542 Completion Dat 10/28/2000 Completion Statu 1-OIL Current Status 1-OIL
Well Cored? y ~ Daily History Received? ~ N
Chips Received? ,--Y-f'N--- Formation Tops ~ / N
Analysis ~
R ~.c.~.iv~.d ~
...................................................... -~.. - _-~_..--~----..-. -._-_- -- -..-_-j. _ ...~.. ............ . ................................................................ .._
Comments:
UIC N
Compliance Reviewed By:
PHILLIPS Alaska, Inc'
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Po~t Offioe Box 100360
Anchorage, Alaska 99610-0360
R. Thomas
Phone (907) 265-6830
Fax: (907) 265-6224
January 16, 2002
Cammy Occhsli Taylor
Commissioner
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
Re: Kuparuk Area Annular Disposal, Fourth Quarter, 2001
Dear Commissioner:
Please find attached the report with the volumes disposed into surface casing by produCtion casing
annuli during the fourth quarter of 2001, as well as total volumes disposed into annuli for which'
disposal authorization expired during the fourth quarter of 2001.
Please call me at 265-6830 should you have any questions.
Sincerely,
R. Thomas
Greater Kuparuk Team Leader
RT/skad
CC:
Marty Lemon
Mike Mooney
Paul Mazzolini
Chip Alvord
Kuparuk Environmental: Engel / Snodgrass
B. Morrison and M. Cunningham
Sharon Allsup-Drake
Well Files
Annular Disoosal durin the fourth quarter of 2001:
· · ~ · ?
h(l) h(2) h(3) Total for Freeze Previous New Start End Source Wells
Well Name Volume Volume Volume Quarter Protect Total Total Date Date
Volumes
CD2-42 2193 100 0 2293 385 31314 33992 June October CD2-15, CD2-24, CD2-33
2001 2001
2P-417 5331 100 O 5431 0 627 6058 Sept 2001 December 2P-420, 2P-448
2001
CD2-24 2981 100 0 3081 375 30543 33999 July 2001 October CD2-15, CD2-33, CD2-39,
... 2001 CD2-14
1C-16 12338 100 0 12438 0 19679 32117 Sept 2001 October 1C-131, 1C-125, 1C-102
~ 2001
CD2-39 27400 100 0 27500 379 0 27879 October November CD2-15, CD2-47
2001 2001
CD2-14 14359 100 0 14459 376 0 14835 November December CD2-45, CD2-47
2001 2001
... 1C-14 22389 100 0 22489 0 0 22489 Oct 20ol Nov 2001 1C-109'
, 2P-438 30331 100 0 30431 212 0 30643 Oct 2OOl Dec 2001 2P-420, 2P-415, 2P-429
CD2-15 0 0 0 0 371 0 ' 371 NA* NA* *Freeze protect CD2-15 only
.~ CD2-47 10315 100 0 10415 375 0 10790 Dec 2001 Dec 200.1 CD2-34
Total Volume, into Annuli tor which Di
~ ,,o,,o ,,,,,,,,,,~o ,,,,u, ~,u,m~jo, ~vmcn a.,ta-l.,Oa-ut nutrmrtautton ~ptrea aurmg tnefourtn t ~er z~l:
Fr~ P~ct To~ Volme S~ End Source We~
Total h(l) Total h(2) To~ h(3) Flui~ I~ec~ Da~ Date
Well Name Volume Volume Volume Volume S~s of Ann~
2L-313 262~ 1~ 0 0 26390 O~n, F~'~o~ M~ch 1999 ~ 2~ 2~317, 2~307
1D-36 301~ 1~ 0 0 302~ ~n, F~ ~o~ ~t 2~ Nov 2~ 1D42, ID-34
CD1-31 6698 1~ 0 392 7190 O~n, F~ ~o~ Feb 2~1 M~h ' ' 'CDI-14 '
2~1
2N-~5 0 0 0 380 380 O~n, F~ ~o~ ~A** NA** ** ~ pm~t
volu~es only
ID-~ 31915 1~ 0 218 "32233 Open, F~ ~mc~ Nov 2~ D~ 2~ 1D-32, ID~OA
2N-349A 0 0 0 0 0 O~n, F~ ~~ ......
lDO2 32~0 1~ 0 265 '32405 O~n, Fr~ ~o~t~ D~ 2~ ~ 2~1 1D-37, 1D-39
_q.$
~.
Annular Dis ~osal durin r the fourth quarter of 2001:
· h(1) ~ !~(2) ' h(3) ~ Total for Freeze Previous New Start End Source Wells
Well Name Volume Volume Volume Quarter Protect Total Total Date Date
Volumes
CD2-42 2193 100 0 2293 385 31314 33992 June October CD2-15, CD2-24, CD2-33
2001 2001
2P-417 5331 100 0 5431 0 627 6058 Sept 2001 December 2P-420, 2P-448
2001
CD2-24 2981 100 0 3081 375 30543 33999 July 2001 October CD2-15, CD2-33, CD2-39,
2001 CD2-14
IC-16 12338 100 0 12438 0 19679 32117 Sept 2001 October 1C-131, 1C-125, 1C-102
2001
CD2-39 27400 100 0 27500 379 0 27879 October November CD2-15, CD2-47
2001 2001
CD2-14 14359 100 0 14459 376 0 14835 November December CD2-45, CD2-47
2001 2001
1C-14 22389 100 0 22489 0 0 22489 Oct 2001 Nov 2001 1C-109
- 2P-438 30331 100 0 30431 212 0 30643 Oct 2001 Dec 2001 2P-420, 2P-415, 2P-429
CD2-15 0 0 0 0 371 0 371 NA* NA* *Freeze protect CD2-15 only
CD2-47' 10315 100 0 10415 375 0 10790 Dec 2001 Dec 2001 CD2-34 '
t otat votumes tnto Annutt for wntcn ~.tsPosat ,,tutnortzanon v~xptrea aurtng tnefourtn {,uarter zooz'
Freeze Protect Total Volume Start End Source Wells
Total h(1) Total h(2) Total h(3) Fluids Injected Date Date
Well Name Volume Volume Volume Volume Status of Annulus
, ,,
21~'313 26290 100 0 0 26390 Open, Freeze Protected March 1999 Dec 2000 2L-317, 2L-307
'~' 1 D-36 30104 100 0 0 30204 Open, Freeze Protected Oct 2000 Nov 2000 1D-42, 1D-34
, ,,
(;1')1-31 6698 100 0 392 7190 Open, Freeze Protected Feb 2001 March CDI-14
2001
,
2N-305 0 0 0 380 380 Open, Freeze Protected NA** HA** ** fi'eeze protect
......... ~ volumes only
~ I I)-.M 31915 100 0 218 32233 Open, Freeze Protected Nov 2000 Dec 2000 1D-32, 1D-40A
2N-349A 0 0 0 0 0 Open, Freeze Protected ......
1.1)-42' 32040 100 0 265 32405 Open, Freeze Protected Dec 2000 Jan 2001 1D-37, 1D-39
WELL LOG TRANSMITTAL
To: State of Alaska April 27, 2001
Alaska Oil and Gas Conservation Comm.
Atm.: Lisa Weepie
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
RE: MWD Formation Evaluation Logs 1D-36, AK-MM-00172
c2oc,-I$o
The technical data listed below is being submitted herewith. Please address any problems or
concerns to the attention of:
Jim Galvin, Sperry-Sun Drilling Services, 6900 Arctic Blvd., Anchorage, AK 99518
1D-36:
2" x 5" MD Resistivity & Gamma Ray Logs:
50-029-22973-00
2"x 5" TVD Resistivity & Gamma Ray Logs:
50-029-22973-00
2"x 5"MD Neutron & Density Logs:
50-029-22973-00
2"x 5" TVD Neutron & Density Logs:
50-029-22973-00
1 Blueline
1 Rolled Sepia
1 Blueline '
1 Rolled Sepia
1 Blueline
· 1 Rolled Sepia
1 Blueline
1 Rolled Sepia
2001
WELL LOG TRANSMITTAL
To:
State of Alaska
Alaska Oil and Gas Conservation Comm.
Atm.: Lisa Weepie
333 West 7th Avenue, Suite 100
Anchorage, Alaska
April 24, 2001
MWD Formation Evaluation Logs
1D-36, AK-MM-00172
1 LDWG formatted Disc with verification listing.
APl#: 50-029-22973-00
PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL
LETTER TO THE ATTENTION OF:
Sperry-Sun Drilling Service
Attn:' Jim Galvin
6900 Arctic Blvd.
Anchorage, Alaska 99518
Date:
RECEIVED
I Y'0,1 2001
Aim~Oil&Gas Coas.~
01-Feb-01
AOGCC
3001 Porcupine Drive
Anchorage, AK 99501
Re: Distribution of Survey Data for Well 1D-37 MWD
Dear Dear Sir/Madam:
Enclosed are two survey hard copies and 1 disk
Tie-on Survey:
Window / Kickoff Survey:
Projected Survey:
230.00' MD
'MD
11,003.00' MD
(if applicable
Please call me at 273-3545 if you have any questions or concerns.
Regards,
Survey Manager
Attachment(s)
RECEIVED
~.,~':,~ ~ 2001
,.~ ~ ;'-' i"\ ,
Oil .& Gas ~ns. C0mm~ssm~
~ch0rage
01-Feb-01
AOGCC
3001 Porcupine Drive
Anchorage, AK 99501
Re: Distribution of Survey Data for Well 1D-37 GYRO
Dear Dear Sir/Madam' ¢:~ 00-~..~
Enclosed are two survey hard copies and 1 disk
Tie-on Survey:
Window / Kickoff Survey:
Projected Survey:
0.00' MD
'MD
0.00' MD
(if applicable
Please call me at 273-3545 if you have any questions or concerns.
Regards,
Survey Manager
Attachment(s)
RECEIVED
r,,}AR ! ,..,.,01
N. as~ Oil:.& Gas Cons. Co~rnissl~
Anchorage
01-Feb-01
AOGCC
3001 Porcupine Drive
Anchorage, AK 99501
Definative Survey
Re: Distribution of Survey Data for Well 1D-37
Dear Dear Sir/Madam:
Enclosed are two survey hard copies and I disk
Tie-on Survey:
Window / Kickoff Survey:
Projected Survey:
230.00' MD
'MD
11,003.00' MD
(if applicable
Please call me at 273-3545 if you have any questions or concerns.
Regards,
Survey Manager
Attachment(s)
RECEIVED
~.O.i/.& 8as Cons,
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Post Office Box 100360
Anchorage, Alaska 99510-0360
P. Mazzolini
Phone (907) 203-4603
Fax: (907) 265-6224
January 23, 2001
Ms. Wendy Mahan
Natural Resource Manager
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
Re: Kuparuk Area Annular Disposal, Fourth Quarter, 2000 (Revision 1)
Dear Ms. Mahan:
Please fred the revised report below with the volumes disposed into surface casing by production
casing annuli during the fourth quarter of 2000, as well as total'volumes disposed into annuli for
which disposal authorization expired during the fourth quarter of 2000. The revision is for the
annulus of Well 1D-42. An annular disposal report for 12/26/00 of 2437 barrels was not counted in
the total for the Quarter. The revised total for Well 1D-42 is 15,118 from 12,681 barrels as noted in
the table below.
~'2000:
Annular Disposal aunng m~ jo., ,,, ~--, oo, ~ .....
h(1) h(2) h(3) Total for Previous New
Well N~me Volume Volume Volume Quarter Total Total
2N-343 13713 100 0 13813 17995' 31808
2I,-313 9017 100 ' 0 9117 17273 26390
CD1'45 26735 100 0 26835 5501 32336
CD1-42 26~7 100 0 26547 4807 .31354
CDI-~ 22410 100 0 22810 0 22510
' 2N-347. 16434 100 0 16534 15106 31~0
1D-30 1030 100 0 1130 30592 31722 ·
2N-318 1199 100 0 1299 320 1619'
1D.36 30104 100 0 30204 0 30204
2N-305 280 100 0 380 0' 380 ..
- 1D-34 32133 100 0 32233 0 32233
1D-42 15018 100 0 15118 0 15118
/
129-//?
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Post Office Box 100360
Anchorage, Alaska 99510-0360
P. Mazzolini
Phone (907) 263-4603
Fax: (907) 265-6224
January 19, 2001
Ms. Wendy Mahan
Natural Resource Manager
Alaska Oil and Gas Conservation Commission
333 West 7~ Avenue, Suite 100
Anchorage, Alaska 99501
Re: Kupamk Area Annular. Disposal, Fourth QUarter, 2000
Dear Ms. Mahan:
Please find reported below the volumes injected into surface casing.by production casing annuli
during the fourth quarter of 2000, as well as total volumes injected into annuli for which disposal
authorization expired during the fourth quarter of 2000.
Annular Disposal during.th :.fourth quarter of 2000:
h(1)' h(2)' hi3) Totalfor Previous New
Well Name Volume Volume . Volume Quarter 'Total Total
2N-343 13713 100 0 13813 17995 '31808
'2L-313 9017 100 0 9117 17273 .26390
CD1-45 26735 .100 0 26835. 5501 32336
CD1-42 26447 100 0 26547 4807 31354
CD1-44 22410' 100 0 22510 '0 22510
2N-347 16434 100 0 16534 15106. 31640'
1D-30 1030 '100 0 1130 30592 "31722
2N-318 1199 100 0 1299 320 1619
1D-36 30104 100 0 30204 0 '30204.
2N-305 280 100 0 380 0 380.
1D-34 32133 100 0 32233 0 32233
1D-42 12581 100 0 12681 0 12681
Ms. Wendy Mahan
AOC~C
Fourth Quarter 2000 Annular Disposal Report
Page Two
Total Volumes into Annuli for which Disposal Authorization Expired during the fourth quarter 2000:
Total
Total h(1) Total h(2) Total h(3) Volume
Well Name Volume Volume Volume Injected Status of Annulus
CDI-16 28950 100 0 29050 Open, Freeze Protected
CD1-45 32236 100 0 32336 Open, Freeze Protected
CD1-32 33413 100 0 33513 Open, Freeze Protected
CD1-42 31234 100 0 31334 Open, Freeze Protected
CD 1-36 33567 100 0 33667 Open, Freeze Protected
Please call me at 263-4603 should you have any questions.
Sincerely,
Paul Mazzolini
Drilling Team Leader
CC.'
Marty Lemon
Mike Mooney
Paul Mazzolini
Randy Thomas
Chip Alvord
Scott Reynolds
Kupamk Environmental: Engel / Snodgrass.
B. Morrison and M. Winfree
Sharon Allsup-Drake
Well Files
11/8/O0
Schlumberger
NO. 680
Schlumberger Technology Corporation, by and through is Geoquest Division
3940 Arctic Blvd, Suite 300
Anchorage, AK 99503-5711
ATTN: Sherrie
Company:
Alaska Oil & Gas Cons Comm
Attn: Lori Taylor
3001 Porcupine Drive
Anchorage, AK 99501
Field: Kuparuk
Well Job # Log Description Date BL
Color
Sepia Print
,1 B-17 PRODUCTION PROFILE/GLS 001021 I 1
1 D-34 STATIC RECORD/PRESS/TEMP 001026 I 1
!1 D-36 STATIC RECORD/PRESS/TEMP 001028 1 1
1G-17 PRODUCTION PROFI LE/G LS 001022 I 1
1H-02 PSP PRODUCTION PROFILE 001030 I 1
3G-08 PRODUCTION PROFILE/G LS 001023 I 1
3Q-04 GAS LIFT SURVEY 001029 I I
I qq'
I gO-OL, 5
IOi-i~.7'
SIGNE~
DATE:
Please sign and return one copy of this transmittal to Sherrie at the above address or fax to (907) 561-8317. Thank you.
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Post Office Box 100360
Anchorage, Alaska 99510-0360
J. Trantham
Phone (907) 265-6434
Fax: (907) 265-6224
December 5, 2000
Mr. Daniel T. Seamount, Jr.
Commissioner
State of Alaska
Alaska Oil & Gas Conservation Commission
3001 Porcupine Drive
Anchorage, Alaska 99501
Subject: Completion Report for 1D-36 (200-130)
Dear Mr. Commissioner:
Phillips Alaska, Inc. submits the attached Completion Report for the drilling operations on 1D-36.
If you have any questions regarding this matter, please contact me at 265-6434 or Todd Mushovic at
265-6974.
Sincerely,
Trantham
Drilling Engineering Supervisor
PAI Drilling
JT/skad
RECEIVED
DEC 06 2000
Alaska 0il & Gas Cons. Commission
Anchorage
l' STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION coMMISsION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
1. Status of well Classification of Service Well
o,, E! as D Susp.nded D Abandoned D Service D
2. Name of Operator 7. Permit Number
3. Address ~ ............. , 8. APl Number
P. O. Box 100360, Anchorage, AK 99510-0360 i /O, ~'.~) ~ ~...~T~'~,~ ' 50-029-22973-00
4.
Location of well at surface ~. ~,~i~I~c:.q~ .~ , '~~ 9. Unit or Lease Name
Kuparuk
River
Unit
2556' FNL, 2364' FWL, Sec. 25, T11 N, R10E, UM (ASP: 563519, 5951857) ~'-~""'~ 1 D-36
At Total Depth 11. Field and Pool
2465' FSL, 2408' FWL~ Sec. 25, T11 N, R10E, UM (ASP: 563566, 5951596) Kuparuk River Field
5. Elevation in feet (indicate KB, DF, etc.) 16. Lease Designation and Serial No. Kuparuk River Pool
RKB 35 feetI ADL 25661 & 25650 ALK 471
12. Date Spudded 13. Date T.D. Roached 14. Date Como., Susa. Or Aband. 115. Water Depth, if offshore 16. No. of Completions
September 2, 2000 September 15, 2000 Se~000/~ I N/A feet MSL 1
17. Total Depth (MD + TVD) 18. Plug Back Depth (MD + TVD) 19. Directional Survey 120. Depth where SSSV set 21. Thickness of Permafrost
YES El No DI N/A feetUD 1870'
11658' MD / 6542' TVD
11589' MD / 6510' TVD
22. Type Electric or Other Logs Run
GR/Res/Neu Dens
!23. CASING, LINER AND CEMENTING RECORD
SE'I-rING DEPTH MD
CASING SIZE WT. PER FT. GRADE TOP BO'I-rOM HOLE SIZE CEMENTING RECORDI AMOUNT PULLED
20" 91.5# H-40 Surface 121' 30' 14 cu yds ABI Type III
9.625" 40# L-80 Surface 7047' 12.25" 850 sx AS III Lite, 415 sx LiteCRETE
7" 26# L-80 Surface 11038' 8.5" 17o sx Class G
3.5# 9.3# L-80 11885' 11656' 6.125" 174 sx Class G
ORiG!! AL
inte~al, si:~® and n~ber) SIZE DEPTH SET (MD) PACKER SET (MD)
DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED
wellbore
~?. PRODUCTION TEST
Date First Production Method of Operation (Flowing, gas lift, etc.) jltiJaska 0~1 & C.-.-.-.-.-.-.-.-.-~s Cons. ColT~SSiOrl
November 19, 2000 Flowing
Date of Test Hours Tested Production for OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE IGAS-OIL RATIO
11/19/2000 3.0 Test Period > 444 278 0 60I 788
Row Tubing Casing Pressure Calculated OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY - APl (corr)
press. 350 psi not available 24-Hour Rate > 3536 2222 16 23.8°
28. CORE DATA
Brief description of lithology, porosity, fractures, apparent dips and pressence of oil, gas orwater. Submit core chips.
N/A
Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit In duplicate
29.
NAME
Top Kuparuk C
Base Kuparuk C
Top Kuparuk A
Base Kuparuk A
GEOLOGIC MARKERS
MEAS. DEPTH
11358'
11488'
11658'
11658'
TRUE VERT. DEPTH
6400'
6463'
6542'
6542'
FORMATION TESTS
Include Interval tested, pressure data, all fluids recovered and gravity.
GOR, and time of each phase.
Annulus left open - freeze protected with diesel.
31. LIST OF A'r'TACHMENTS
Summary of Daily Operations, Directional Survey
32. I hel~by certify that the following is true and correct to the best of my knowledge.
Signed i ~ vt~GZ'~~ Title Drtllin¢l Enaineerin,q Supervisor
~J-' J. Trantham
Questions? Call Todd Mushovic 265-6974
Date 5~ b ~c-.- ~
Prepared by Sharon AIIsup-Drake
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 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 records for this well should show the details of any multiple stage cementing and the location
of the cementing tool.
Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection,
Shut-in, Other-explain.
Item 28: If no cores taken, indicate "none".
RECEIVED
Form o- o7 DEC 0 6 2000
Alaska Oil & Gas Cons. Commission
Anchorage
Date: 11/14/00
ARCO ALASKA INC.
WELL SUMMARY REPORT
Page: 1
WELL:ID-36
STATE:ALASKA
COUNTY: NORTH SLOPE EAST
FIELD: KUPARUK RIVER UNIT
SPUD:09/02/00 START COMP:
RIG:NABORS 16E
BLOCK:
FINAL:
WI: 0% SECURITY:0
API NUMBER: 50-029-22973-00
09/02/00 (D1)
TD/TVD: 275/0
SUPV:FRED HERBERT
MW: 8.8 VISC: 305 PV/YP: 57/55
(275) DRILLING AHEAD @ 275'
APIWL: 7.8
Rig down cellar, prep rig to move, jack up rig, move to
1D-40. Spot ball mill. Nipple up diverter stack. Function
test diverter. Drilling 12.25" hole from 154' to 275'.
09/03/00 (D2) MW: 9.7 VISC: 311 PV/YP: 77/87 APIWL: 5.2
TD/TVD: 2275/1838 (2000) DRILLING AHEAD $ 2907'
SUPV:FRED HERBERT
Drilling 12.25" hole from 275' to 2024'. Circ sweep around
for wiper trip. POOH, pump & rotate to 807'. Monitor well,
hold diverter drill. RIH to bottom. No problems. Drilling
12.25" hole from 2024' to 2275'.
09/04/00 (D3) MW: 9.6 VISC: 284 PV/YP: 46/47
TD/TVD: 3589/2574 (1314) DRILLING AHEAD @ 3915'
SUPV:FRED HERBERT
APIWL: 438.0
Drilling 12.25" hole from 2275' to 3436'. having trouble
backreaming from 3380' to 3400'. Finish circ sweep around.
No excess cuttings. Drilling 12.25" hole from 3436' to
3589'. Motor @ stall pressure, would not drill. Attempt to
clear, unable to clear. POOH to check motor. Change out
motor, bit, choke on pulser sub. RIH slow. Bridge @ 2080'
Wash & ream thru bridge from 2080' to 2090'
09/05/00 (D4) MW: 9.7 VISC: 220 PV/YP: 52/61 APIWL: 4.8
TD/TVD: 5580/2574 (1991) DRILLING @ 5919'
SUPV:M. WINFREE
RIH slowly, circ hole clean. Drill from 3589' to 5503'.
Circ around sweep. POOH to 3550'(tight from 4150'-4100').
RIH. Drill from 5503' to 5580'.
09/06/00 (D5) MW: 9.7 VISC: 182 PV/YP: 36/49 APIWL: 5.0
TD/TVD: 7056/4302 (1476) AT HWDP ON SHORT TRIP
SUPV:M. WINFREE
Drill from 5580' to 7056'. Circ and condition mud. Observe
well, pump dry job, POOH.
09/07/00 (D6)
MW: 9.7 VISC: 170 PV/YP: 35/48
APIWL: 4.8
RECEIVED
DEC 06 2000
Alaska Oil & Gas Cons. Commission
Anchorage
Date: 11/14/00
ARCO ALASKA INC.
WELL SUMMARY REPORT
Page: 2
TD/TVD: 7056/4302 (
SUPV:M. WINFREE
0) PREP TO CEMENT 9-5/8"
POOH to 1620', trying to swab, pump out to 900', POOH to
807'. RIH to TD break circ slowly. Circ and condition mud
for 9-5/8" casing, pump sweep. Pump dry job. RU to run
casing. PJSM. Run 9-5/8" casing.
09/08/00 (D7)
TD/TVD: 7056/4302 (
SUPV:M. WINFREE
MW: 9.6 VISC: 46 PV/YP: 19/13
0) PU DP
APIWL: 5.6
Run 9-5/8" casing. PJSM. Pump cement. Bump plug. Check
floats, OK. RD diverter. Nipple up stack. Test BOPs.
09/09/00 (D8) MW: 8.5 VISC: 43 PV/YP: 11/12 APIWL: 9.2
TD/TVD: 7647/4593 (591) DRILLING AHEAD @8121'
SUPV:M. WINFREE
Finish testing BOPE's. PJSM. RIH and tag cement at 6957'.
CBU. Drill cement and float equipment and 20' new hole.
Circ and condition for LOT, perform LOT to EMW=13.2 ppg.
Drill 7080' to 7647'. Circ hole clean for PWD baseline.
09/10/00 (D9) MW: 9.0 VISC: 44 PV/YP: 14/15 APIWL: 7.4
TD/TVD: 9150/5323 (1503) DRILLING ~ 9587
SUPV:M. WINFREE
Circ BU for PWD baseline. Perform PWD baseline. Drill from
7647' to 8961'. Pump weighted sweep around circ hole clean,
pump dry job. POOH 8961' to 6991'. RIH to TD, hole good
fill good. circ. Drill from 8961' to 9150'.
09/11/00 (D10) MW: 9.8 VISC: 45 PV/YP: 15/16 APIWL: 4.5
TD/TVD:l1048/6247 (1898) CIRC FOR 7"CASING
SUPV:M. WINFREE
Drill 9150' to 11048'. Pump weighted sweep, circ 2 BU.
09/12/00 (Dll) MW: 1.0 VISC: 53 PV/YP: 20/25 APIWL: 4.2
TD/TVD:l1048/6247 ( 0) RUNNING 7" CSG
SUPV:M. WINFREE
Circ for short trip, monitor well, pump dry job. Short trip
to 8600', run back to TD. Circ for 7" casing, gas on BU.
Monitor well for flow, OK. POOH slow. Monitor well at shoe,
OK, POOH.
09/13/00 (D12)
TD/TVD:l1048/6247 (
SUPV:M. WINFREE
MW: 9.9 VISC: 47 PV/YP: 18/19
0) PU 4" DP
APIWL: 4.6
Rig up to run casing PJSM. Run 7" to shoe at 7000', circ
casing. Run casing to 11038'. Pump cement. Install packoff,
test to 50009, OK.
RECEIVED
DEC 06 000
Alaska 0il & Bas Cons. Commission
Anchora[le
Date: 11/14/00
ARCO ALASKA INC.
WELL SUMMARY REPORT
Page: 3
09/14/00 (D13) MW: 11.1 VISC: 48 PV/YP: 21/18 APIWL: 3.8
TD/TVD:l1048/6247 ( 0) DRILLING FLOAT EQ.
SUPV:M. WINFREE
Test BOPE. PJSM. RIH, tag @ 10612'. PJSM. Drill plug and
cement.
09/15/00 (D14) MW: 11.2 VISC: 56 PV/YP: 22/23
TD/TVD:l1660/6543 (612) POOH FOR LINER
SUPV:M. WINFREE
APIWL: 3.4
Drill cement to 10951', tag FC. Circ BU. Test casing to
35009, ok. Drill out FC & FS plus 20' of new hole to
11068'. Circ for LOT. Do FIT, EMW=16.0 ppg. Swap out mud.
Drill from 11068' to 11152'. CBU. Drill from 11152' to
11660'.
09/16/00 (D15) MW: 11.2 VISC: 52 PV/YP: 21/20 APIWL: 3.4
TD/TVD:l1660/6543 ( 0) CEMENTING LINER
SUPV:M. WINFREE
Monitor well POOH to shoe. RIH to TD. Circ and cond mud,
monitor well. RU to run liner. Run liner.
09/17/00 (D16) MW: 11.1 VISC: 48 PV/YP: 48/18 APIWL: 3.5
TD/TVD:l1660/6543 ( 0) RUNNING 3-1/2" TUBING
SUPV:M. WINFREE
Run liner. Circ @ shoe. RIH tag bottom. Circ and condition
mud. PJSM. Pump cement. Pressure up set hanger and packer
w/liner shoe at 11656'. Unsting circ out cement
contaminated mud. POOH.
09/18/00 (D17)
TD/TVD:l1660/6543 (
SUPV:M. WINFREE
0)
MW: 8.8 VISC:
0 PV/YP: 0/ 0
APIWL: 0.0
PJSM. Run 3.5" tubing. Test liner lap to 3500 psi, OK.
Displace mud to seawater. Test tubing to 30009, OK.
09/19/00 (D18) MW: 8.8 VISC: 0 PV/YP: 0/ 0 APIWL: 0.0
TD/TVD:l1660/6543 ( 0) RIG RELEASED @ 08:30 HRS 9-19-2000
SUPV:M. WINFREE
L.D. landing jr. Set BPV. N/D BOPs. NU tree and test to
250/5000 psi. Finish cleaning pits and injecting fluid.
Freeze protect 1D-30 annulus. Rig release @ 0830 hrs.
9/19/00.
RECEIVED
DEC 06 000
Alaska 011 & Sas Cons. Commission
Anchorage
(
Page 1 of 2
Well Service Report
Well ]lJob Scope ]lJob Nomber
1D-36 IIounmo SUPPORT-CA~n'AL11~025001650.5
10128/2000 IIDRILLING SUPPORT-CAPITAL: PERFOATION/STATIC 112128
0 Il T~ II rm~ II sws-~oEI-Im~ II ~R~USON
IllInit Tbg Press IIn-~ ~bg P~' IlIlat Inner Ann Ilnnai Inner Ann III,it Outer Ann
700 II ~200 II 550 II 600 II 800
Ilmn~ Outer Ann
II ~oo
Daily 2-1/2" BH HSD GUN 4SPF- PERFED INTERVAL: 11410'-11420: WI 4000g PSI
Summary @ SURFACE PRIOR TO SHOT. STATIC PRESSURE AND TEMPERATURE'
RECORDED MID-PERFS, 100'TVD ABOVE PERFS, AND 100'TVD.
~ime IlI~°g Ent~ I
07:30 II'mu SWS uNrr 2128- BOEHME,LISTER,MINOGUE-SAFETY MEETING I
09:30 ' PT 3000g. OK. RIH W/HEAD/SWIVLE/6FT - 1-11/16" WT'BAR/PGGTC! SAFE.
FI-I/10FT - 2-1/2" BH HSD GUN'4SPF/2;61" ROLLERS.
.
11:30' PILL INTO POSITION/PRESSURE TUBING TO 4000g/SHOOT GUN/
PERFORATION INTERVAL:' 11410'-11420' / POOH,
12:15', lion SURFACE-VERIFIED HOLES/RU SECOND RUN I
13:15 RIH W/HEAD/SWlVLE/2.61" ROLLERS/2- 1-11/16"WT BARS/PBMS/2-1/8"
ROLLERS. '.
15:00. LOG JEWELRY FROM TD TO 9600'. RIH. LOG REPEAT PASS. COLLARS
APPEAR ERRATIC NEAR BOTTOM.
15:25 START STATION STATIC COUNTS2 SC#1 P/T SENSORS IN MID-PERF. SCg2.
P/T SENSORS @ 100'TVD ABOVE MID-PERF. SC#3 P/T SENSORS @ 100,'TVD
,
17:00 lion SURFA.CE. RIG DOWN.
18:00 [IMOVE OFF'LOCATION.' ,..,
RECEIVED.
DEC 06 ~000,
Alaska, 0il. & {las I}Ons..Commissiofi
Anchorage,
PHILLIPS Alaska, Inc.
KUPARUK RIVER UNIT
WELL SERVICE REPORT
K1(1D-36(W4-6))
WELL JOB SCOPE JOB NUMBER
1 D-36 DRILLING SUPPORT-CAPITAL 1025001650.5
UNIT NUMBER
DATE
10/30/00
DAY
2
DAILY WORK
FRACTURE 'C' SAND-INITIAL FRAC
OPERATION COMPLETE I SUCCESSFUL
YES I YES
Initial Tbg Press I Final Tbg PresS I Initial Inner Ann
1200 PSI 120 PSI 0 PSI
DAILY SUMMARY
KEY PERSON
DS-YOAKUM
Final Inner Ann I
I
0 PSI
SUPERVISOR
FERGUSON
Initial Outer Ann I Final Outer Ann
0 PSII 0 PSI
PUMP BREAKDOWN AT MAX RATE OF 35 BPM AND 8300 PSI. PUMP DATAFRAC FOR ANALYSIS AND STAY WITH DESIGN
PAD AND SCHEDULE. PAD VOLUME= 200 BBLS. COMPLETE PROP RAMP AT 15 BPM AND GO TO FLUSH. REDUCE RATE TO
2 BPM AND DID NOT SCREENOUT WELL. PLACE 162,508#'S BEHIND PIPE WITH MAX CONC OF 10.2 PPA ON FORMATION OF
12/18. LEFT 1730#'S PROP IN WELLBORE.[Frac-Refrac]
TIME
07:45
08:30
10:15
10:50
11:05
11:30
12:00
12:30
LOG ENTRY
ARRIVE LOCATION. DOWELL RU PUMP EQUIP. MEET WITH ONSITE COORDINATOR TO WORK OUT EQUIP
LOCATION TO MINIMIZE REDUCED ACCESS TO RIG.
SAFETY MEETING
PT LINES TO 9500 PSI
COME ON LINE FOR BREAKDOWN. GOOD BREAKBACK AT 38BPM
PERFORM SDT AT END OF BREAKDOWN, ISIP=2390 PSI, FG=0.81 PSI/FT. XS FRICTION= 317 PSI, ALL PERFS.
PERFORM PULSES
START DATAFRAC AT 20 BPM WITH 50# X/L GEL.
SD TO ANALYZE DATAFRAC
ATTEMPT TO ANALYZE DATAFRAC. STIMPLAN CRASHED DURING DATA ANALYSIS. FLUID EFFICIENCY
LOOKED GOOD. WILL PUMP JOB PER DESIGN.
12:40 COME ONLINE FOR FRAC AT 15 BPM, USING ORIGINAL DESIGN. PAD VOLUME OF 200 BBLS
14:15 COMPLETE FRAC AND GO TO FLUSH. ABLE TO COMPLETE FLUSH . REDUCE RATE ON END OF FLUSH TO 2
BPM AND DID NOT SCREENOUT WELL.
14:20 PLACE 162,508#'S PROP BEHIND PIPE. LEFT 1730 #'S IN WELLBORE. MAX CONC ON FORMATION OF 10.4
PPA OF 12/18
15:30 JOB COMPLETE. RDMO
RECEIVED
DEC 2000
Alaska 0i/& (}as Cons. Commission
Anchorage
DEFINITIVE
Kuparuk River Unit
Phillips Alaska
Kuparuk 1D, Slot ~D.37
~D-37
Surveyed: fl January, 2001
SURVEY REPORT
1 February, 2001
Your Ref: AP1500292299200
Surface Coordinates: 5959174.03 N, 560570.65 E (70° 17' 56.3585" N,
Kelly Bushing: 104.90ft above Mean Sea Level
~49°30'31.1956"W)
n Fi ILl_ I N I~; B E I:lVl r' ES
Survey Reft svy9377
A H~,lllburlon Company
Kuparuk River Unit
Measured
Depth
(ft)
Incl.
Azim.
Sub-Sea
Depth
(ft)
Sperry-Sun Drilling Services
Survey Reportfor fD-37
Your Ref: APl 500292299200
Surveyed: f f January, 2001
Vertical Local Coordinates Global Coordinates
Depth Northings Eastings Northings Eastings
(ft) (ft) (ft) (ft) (ft)
230.00 0.250 78.000 125.10 230.00
295.59 0.280 76.270
383.09 0.220 303.770
475.43 0.840 295.990
572.23 3.170 290.240
190.69
278.19
370.52
467.26
559.04
647.97
742.95
836.06
927.00
1021.46
1114.12
1205.69
1298.62
1394.41
1489.44
1581.29
1675.71
1770.28
1866.01
664.28 5.430 287.550
753.62 5.600 288.170
849.09 6.010 281.440
942.57 4.210 292.790
1033.69 2.990 297.780
1128.22 1.320 290.050
1220.90 0.590 296.880
1312.47 0.430 286.660
1405.40 0.420 279.450
1501,20 0.390 278.470
1596.23 0.370 260.670
1688.08 0.370 265.460
1782.50 0.410 262.030
1877.07 0.460 271.000
1972.81 0.340 259.120
295.59
383.09
475.42
572.16
663.94
752.87
847.85
940.96
1031.90
1126.36
1219.02
1310.59
1403.52
1499.31
Phillips Alaska
Kuparuk 1 D
1594.34
1686.19
1780.61
1875.18
1970.91
Dogleg
Rate
(°llOOft)
Vertical
Section
Comment
2068.16 0.440 278.500 1961.36 2066.26
2162.22 0.520 271.600 2055.42 2160.32
2255.97 2.410 87.540 2149.15 2254.05
2349.79 3.930 92.720 2242.82 2347.72
2446,06 5.010 98.370 2338.80 2443.70
0.05 N 0.23 E
0.12 N 0.53 E
0.26 N 0.60 E
0.66 N 0.16 W
1.89 N 3.31 W
5959174.08 N 560670.88 E
5959174.15 N 560671.18 E
5959174.30 N 560671.25 E
5959174.69 N 560670.49 E
5959175.90 N 560667.33 E
0.05
0.52
0.67
2.41
0.12
0.28
0.22
-0.59
-3.64
Tie on point
AK-6 BP_IFR-AK
2540.83 7.060
2633.39 9.610
2725.58 12.100
2821.79 13.470
2911,93 14.900
4.09 N 9.85 W
6.72 N 18.02 W
9.17 N 27.34 W
11.47 N 35.31 W
13.87 N 40.49 W
5959178.04N 560660.77 E
5959180.61N 560652.58 E
5959182.97 N 560643.23 E
5959185.21N 560635.25 E
5959187.57 N 560630.05 E
2.46
0.20
0.83
2.20
1.38
-9.72
-17.23
-25.4O
-32.52
-37.82
2433.04
2524.61
2615.15
2708.97
2796.36
15.39 N 43.70W
15.97 N 45.12W
16.29 N 45.87W
16.44 N 46.54W
16.55 N 47.21W
-5959189.07N 560626.83 E
5959189.64N 560625.40 E
5959189.94 N 560624.65 E
5959190.09 N 560623.97 E
5959190.19 N 560623.30 E
1.79
0.80
0.20
0.06
0.03
-41.12
-42.53
-43.27
-43.84
-44.37
106.520
113.580
116.650
116.470
116.600
16.54 N 47.84W
16.47 N 48.42W
16.40 N 49.06W
16.36 N 49.78W
16.31N 50.44W
5959190.19 N 560622.68 E
5959190.11N 560622.09 E
5959190.04 N 560621.46 E
5959189.99 N 560620.74E
5959189.94 N 560620.08 E
0.13
0.03
0.O5
0.09
0.15
-44.80
-45.15
-45.53
-45.99
-46.41
16.32 N 51.08W
16.38 N 51.86W
16.48 N 50.32W
16.41N 45.14W
15.64 N 37.68W
5959189.93 N 560619.44 E
5959189.99 N 560618.65 E
5959190.10 N 560620.20 E
5959190,07 N 560625.38 E
5959189.37 N 560632.84 E
0.17
0.10
3.12
1.65
1.21
-46.85
-47.44
-46.45
-42.85
-37.19
2537.94
2629.51
2720.05
2813.87
2901.26
13.38 N 28.00 W
8.67 N 15.47 W
1.26 N 0.22 E
8.26 S 19.27 E
18.13 S 39.03 E
5959187.19 N 560642.54 E
5959182.58 N 560655.11E
5959175.29 N 560670.86 E
5959165.93 N 560689.98 E
5959156.22 N 560709.82 E
2.34
2.96
2.77
1.42
1.59
-28.92
-16.91
-0.77
19.21
39.93
February, 2001 - 10:26
Page 2 of 6
..
DrillQuest 2.00.06
Sperry-Sun Drilling Services
Survey Report for 1D-37
Your Ref: APl 500292299200
Surveyed: t l January, 2001
Kuparuk River Unit
Measured
Depth
(ft)
Incl.
Azim.
Sub-Sea
Depth
(ft)
3009.37 16.750 116.330 2890.10
3102.30 18.340 119.390 2978.71
3197.54 21.220 121.510 3068.32
3291.28 24.060 121.890 3154.83
3387.45 26.640 124.350 3241.73
3475.60 29.670 126.320 3319.45
3566.82 32.830 128.510 3397.42
3660.41 36.520 128.960 3474.38
3754.48 39.270 129.370 3548.61
3850.95 40.630 130.610 3622.56
3946.05 44.710 132.620 3692.47
4042.83 46.460 132.080 3760.20
4136.10 49.520 134.000 3822.62
4229.54 51.970 135.580 3881.74
4324.17 53.340 136.450 3939.15
4418.39 55.850 135.400 3993.73
4509.28 59.450 136.070 4042.36
4603.93 63.080 138.070 4087.86
4693.59 67.000 138.380 4125.68
4790.63 67.310 139.480 4163.36
4884.20 67.630 138.520 4199.21
4981.86 67.180 138.530 4236.73
5047.54 67.070 138.340 4262.27
5139.59 67.350 137.400 4297.92
5234.22 66.440 138.670 4335.06
5325.54 66.180 137.750 4371.75
5415.57 68.180 138.680 4406.67
5508.70 68.400 138.380 4441.12
5593.38 68.100 137.530 4472.49
5690.65 67.710 138.910 4509.08
Vertical Local Coordinates Global Coordinates
Depth Northings Eastings Northings Eastings
(ft) (ft) (ft) (ft) (ft)
2995.00 29.97 S 62.82 E 5959144.57 N 560733.71E
3083.61 43.08 S 87.56 E 5959131.66 N 560758.55 E
3173.22 59.45 S 115.32 E 5959115.52 N 560786.44 E
3259.73 78.41S 146.01E 5959096.80 N 560817.29 E
3346.63 100.94 S 180.46 E 5959074.55 N 560851.92 E
3424.35 125.02 S 214.37 E 5959050.75 N 560886.02 E
3502.32 153.79 S 251.92 E 5959022.27 N 560923.80 E
3579.28 187.11S 293.44 E 5958989.29 N 560965.59 E
3653.51 223.60 S 338.23 E 5958953.16 N 561010.67 E
3727.46 263.42 S 385.68 E 5958913.73 N 561058.44 E
3797.37 306.24 S 433.82 E 5958871.30 N 561106.93 E
3865.10 352.81S 484.91E 5958825.15 N 561158.39 E
3927.52 400.12 S 535.53 E 5958778.25 N 561209.40 E
3986.64 451.10 S 586.86 E 5958727.68 N 561261.14 E
4044.05 505.23 S 639.10 E 5958673.98 N 561313.81E
4098.63 560.39 S 692.52 E 5958619.25 N 561367.68 E
4147.26 615.37 S 746.10 E 5958564.70 N 561421.70 E
4192.76 676.14 S 802.60 E 5958504.39 N 561478.68 E
4230.58 736.75 S 856.74E 5958444.22 N 561533.31E
4268.26 804.17 S 915.49 E 5958377.28 N 561592.60 E
4304.11 869.40 S 972.19 E 5958312.51N 561649.83 E
4341.63 936.95 S 1031.91E 5958245.44 N 561710.09 E
4367.17 982.23 S 1072.05 E 5958200.49 N 561750.60 E
4402.82 1045.17 S 1128.98 E 5958138.01N 561808.03 E
4439.96 1109.88 S 1187.18 E 5958073.77 N 561866.76E
4476.65 1172.23 S t242.91E 5958011.87 N 561922.98 E
4511.57 1234.11S 1298.20 E 5957950.45 N 561978.77 E
4546.02 1298.94S 1355.50 E 5957886.08 N 562036.59 E
4577.39 1357.35 S 1408.17 E 5957828.10 N 562089.73 E
4613.98 1424.55 S 1468.22 E 5957761.38 N -562150.32 E
Dogleg
Rate
(°/'tOOff)
1.90
1.98
3.12
3.03
2.90
3.60
3.68
3.95
2.94
1.63
4.52
1.85
3.62
2.93
1.62
2.81
4.01
4.26
4.38
1.09
1.01
0.46
0.31
O.99
1.56
0.97
2.42
0.38
1.00
1.37
Vertical
Section
64.84
91.33
122.26
157.09
197.09
237.85
284.53
337.24
394.50
456.00
520.18
589.09
658.23
730.53
805.75
882.53
959.29
1042.26
1123.50
1212.87
1299.23
1389.36
1449.85
1534.70
1621.71
1705.31
1788.27
1874.75
1953.39
2043.48
Phillips Alaska
Kuparuk ID
Comment
DrillQuest 2.00.06
I February, 2001 - 10:26 Page 3 of 6
Sperry-Sun Drilling Services
Survey Report for 1D-37
Your Reft APl 500292299200
Surveyed: f f January, 200f
Kuparuk River Unit
Measured
Depth
(ft)
Incl.
Azim.
Sub-Sea
Depth
(ft)
5780.12 67.480 139.130 4543.19
5878.19 68.910 137.980 4579.61
5973.74 68.960 138.820 4613.96
6072.57 68.430 138.580 4649.87
6168.06 68.130 138.770 4685.20
6262.55 67.700 137.840 4720.73
6356.49 67.300 137.650 4756.68
6452.40 67.000 138.520 4793.92
6543.10 66.970 139.380 4829.39
6640.53 69.120 138.500 4865.81
6738.10 68.570 139.880 4901.02
6829.49 68.720 137.650 4934.31
6925.84 69.650 136.670 4968.55
7020.96 69.440 136.990 5001.79
7113.68 69.240 137.970 5034.50
7205.26 69.050 136.450 5067.11
7301.88 68.970 136.250 5101.72
7396.41 68.720 137.590 5135.83
7489.68 68.490 136.830 5169.86
7582.17 68.430 137.930 5203.82
7677.27 68.210 137.950 5238.95
7770.98 68.200 136.960 5273.74
7864.23 68.190 136.840 5308.38
7958.45 68.330 137.060 5343.28
8052,78 67.790 137.470 5378.52
8146.45 67.440 136.950 5414.20
8239.48 66.940 136.890 5450.26
8333.71 66.610 137.960 5487.42
8428.30 67.720 136.750 5524.13
8524.33 68.250 137.100 5560.13
Vertical Local Coordinates Global Coordinates
Depth Northings Eastings Northings Eastings
(ft) (ft) (ft) (ft) (ft)
4648.09 1487.00 S 1522.46 E 5957699.37 N 562205.07 E
4664.51 1555.24S 1582.73 E 5957631.62 N 562265.89 E
4718.86 1621.92 S 1641.93 E 5957565.42 N 562325.62 E
4754.77 1691.09 S 1702.70 E 5957496.74 N 562386.95 E
4790.10 1757.71S 1761.28 E 5957430.59 N 562446.06 E
4825.63 1823.09 S 1819.52 E 5957365.69 N 562504.82 E
4861.58 1887.33 S 1877.87 E 5957301.92 N 562563.70 E
4898.82 1953.10 S 1936.92 E 5957236.64 N 562623.27 E
4934.29 2016.05 S 1991.74E 5957174.13 N 562678.60 E
4970.71 2084.18 S 2051.09 E 5957106.48 N 562738.50 E
5005.92 2153.05 S 2110.56 E 5957038.09 N 562798.53 E
5039.21 2217.05 S 2166.66E 5956974.55 N 562855.14 E
5073.45 2283.08 S 2227.90 E 5956909.01N 562916.91E
5106.69 2348.08 S 2288.88 E 5956844.50 N 562978.41E
5139.40 2412.03 S 2347.51E 5956781.04N 563037.56 E
5172.01 2474.83S 2405.64E 5956718.71N 563096.19 E
5206.62 2540.10 S 2467.91E 5956653.94N 563158.99 E
5240.73 2604.49 S 2528.12 E 5956590.04 N 563219.72 E
5274.76 2668.22 S 2587.12 E 5956526.79 N 563279.22 E
5308.72 2731.52 S 2645.37 E 5956463.95 N 563337.98 E
5343.85 2797.13 S 2704.57E 5956398.82 N 563397.71E
5378.64 2861.24S 2763.40 E 5956335.20 N 563457.06 E
5413.28 2924.45 S 2822.56 E 5956272.46 N 563516.73 E
5448.18 2988.41S 2882.30 E 5956208.99 N 563576.99 E
5483.42 3052.68 S 2941.68 E 5956145.20 N 563636.88 E
5519.10 3116.24 S 3000.52 E 5956082.12 N 563696.23 E
5555.16 3178.87 S 3059.09 E 5956019.96 N 563755.30 E
5592.32 3242.64S 3117.67 E 5955956.67 N 563814.40 E
5629.03 3306.75 S 3176.73 E 5955893.03 N 563873.97 E
5665.03 3371.79 S 3237.53 E 5955828.49 N 563935.30 E
Dogleg
Rate
(°llOOft)
0.34
1.82
0.82
0.58
0.36
1.02
0.47
0.89
0.87
2.36
1.43
2.28
1.35
0.38
1.01
1.56
0.21
1.35
0.80
1.11
0.23
0.98
0.12
0.26
0.7O
0.63
0.54
1.10
1.66
0.65
Vertical
Section
2126.14
2217.15
2306.28
2398.30
2486.97
2574.49
2661.27
2749.63
2833.05
2923.35
3014.26
3099.32
3189.38
3278.50
3365.25
3450.83
3541.03
3629.19
3716.03
3802.05
3890.41
3977.41
4O63.99
4151.51
4239.00
4325.61
4411.37
4497.96
4585.12
4674.15
Phillips Alaska
Kuparuk ID
Comment
DrillQuest 2.00.06
February, 2001 - 10:26 Page 4 of 6
Sperry-Sun DnTling Services
Survey Report for rD-37
Your Ref: AP1500292299200
Surveyed: 11 January, 2001
Kuparuk River Unit
Measured
Depth
(ft)
Incl.
Azim.
Sub-Sea
Depth
(ft)
Vertical Local Coordinates Global Coordinates
Depth Northings Eastings Northings Eastings
(~t) (fi) (ft) (ft) (rt)
8615.81 67.530 136.600 5594.56 5699.46
8709.11 67.450 137.110 5630.28 5735.18
8800.36 67.100 137.400 5665.53 5770.43
8895.59 66.690 137.620 5702.90 5807.80
8989.13 67.480 137.260 5739.32 5844.22
9082.66 67.550 138.520 5775.09 5879.99
9177.24 67.270 139.340 5811.42 5916.32
9271.83 67.200 139.120 5848.03 5952.93
9364.32 67.040 138.780 5883.99 5988.89
9458.27 66.810 138.950 5920.81 6025.71
9551.42 68.080 138.810 5956.54 6061.44
9645.07 68.160 137.990 5991.44 6096.34
9743.23 68.060 136.320 6028.04 6132.94
9837.17 67.670 137.710 6063.43 6168.33
9931.98 68.950 138.030 6098.47 6203.37
10025.19 68.660 138.740 6132.17 6237.07
10194.84 68.150 138.190 6194.61 6299.51
10294.22 68.240 137.450 6231.53 6336.43
10390.22 68.050 136.240 6267.26 6372.16
10485.97 68.410 136.100 6302.78 6407.68
10578.14 67.880 136.190 6337.09 6441.99
10674.34 67.680 137.280 6373.47 6478.37
10771.45 67.290 137.250 6410.65 6515.55
10866.87 66.670 138.640 6447.97 6552.87
10961.55 67.270 138.610 6485.01 6589.91
11003.00 67.270 138.610 6501.02 6605.92
3433.62 S 3295.50 E
3496.51S 3354.44E
3558.32 S 3411.56 E-
3622.91S 3470.73 E
3686.37 S 3529.00 E
3750.48 S 3586.95 E
3816.31S 3644.32 E
3882.36S 3701.28 E
3946.63 S 3757.24E
4011.72 S 3814.10 E
4076.53 S 3870.67 E
4141.51S 3928.37 E
4208.29 S 3990.30 E
4271.95 S 4049.63 E
4337.28 S 4108.72 E '
4402.25 S 4166.44E
4520.33 S 4271.03 E
4588.70 S 4332.99 E
4653.70 S 4393.93 E
4717.85 S 4455.51E
4779.53 S 4514.78 E
4844.38 S 4575.81E
4910.27 S 4636.69 E
4975.48 S 4695.52 E
5040.86S 4753.11E
5069.54S 4778.39 E
5955767.13 N 563993.76 E
5955704.72 N 564053.21E
5955643.37 N 564110.83 E
5955579.26 N 564170.51 E
5955516.28 N 564229.30 E
5955452.64 N 564287.76 E
5955387.27 N 564345.66 E
5955321.67 N 564403.15 E
5955257.87 N 564459.63 E
5955193.23 N 564517.01E
5955128.88 N 564574.10 E
5955064.37 N 564632.32 E
5954998.09 N 564694.80 E
5954934.92 N 564754.64 E
5954870.06 N 564814.26 E
5954805.56 N 564872.49 E
5954688.33 N 564978.04 E
5954620.46 N 565040.54 E
5954555.95 N 565102.01E
5954492.31N 565164.10 E
5954431.10 N 565223.87 E
5954366.75 N 565285.42 E
5954301.35 N 565346.83 E
5954236.62 N 565406.18 E
5954171.71N 565464.30 E
5954143.23 N 565489.81E
Dogleg
Rate
(°/'lOOft)
Phillips Alaska
Kuparuk ID
Vertical
Section Comment
0.94 4758.90
0.51 4845.10
0.48 4929.26
0.48 5016.84
0.92 5103.00
1.25 5189.40
0.85 5276.66
0.23 5363.81
0.38 5448.96
0.30 5535.34
1.37 5621.31
0.82 5708.18
1.58 5799.25
1.43 5886.27
1.39 5974.35
0178 6061.22
0.43 6218.89
0.70 6311.15
1.19 6400.25
0.40 6489.16
0.58 6574.70
1.07 6663.76
0.40 6753.46
1.49 6841.26
0.63 6928.35
0.00 6966.56 Pr~ected suwey
February, 2001 - 10:26 Page 5 of 6 DrillQuest 2.00.06
Sperry-Sun Drilling Services'
Survey Report for rD-37
Your Ref: AP1500292299200
Surveyed: ff January, 200f
Kuparuk River Unit
Phillips Alaska
Kuparuk 1 D
All data is in feet unless otherwise stated. Directions and coordinates are relative to True North.
Vertical depths are relative to Well. Northings and Eastings are relative to Well.
Magnetic Declination at Surface is 26.341° (23-Dec-00)
The Dogleg Severity is in Degrees per 100 feet.
Vertical Section is from Well and calculated along an Azimuth of 136.820° (True).
Based upon Minimum Curvature type calculations, at a Measured Depth of 11003.00ft.,
The Bottom Hole Displacement is 6966.58ft., in the Direction of 136.693° (True).
Comments
Measured
Depth
(ft)
230.00
11003.00
Station Coordinates
TVD Northings Eastings
(ft) (ft) (ft)
230.00 0.05 N 0.23 E
6605.92 5069.54 S 4778.39 E
Comment
Tie on point
Projected survey
Survey tool program for rD-3?
From To
Measured Vertical Measured
Depth Depth Depth
(ft) (ft) (ft)
Vertical
Depth
(ft)
0.00 0.00 230.00 230.00
230.00 230.00 11003.00 6605.92
Survey Tool Description
Tolerable Gyro (1D-37 GYRO)
AK-6 BP_IFR-AK (1D-37)
._
f February, 2001 - 10:26
Page 6 of 6
DrillQuest 2.00.06
DEFINITIVE
Kuparuk River Unit
Phillips Alaska
'Kuparuk fD, Slot 1D-37
1D-37 MWD
Surveyed: 11 January, 2001
SURVEY REPORT
February, 2001
Your Ref: AP1500292299200
Surface Coordinates: 5959174.03 N, 560670.65 E (70° 17' 56.3585" N,
Kelly Bushing: 104.90ft above Mean Sea Level
149°30'31.1956"W)
DFllLLINI3 S ~ FI',~ Ii i::: lS'S
A Hilllburlon Complny
Survey Ref: svy9378
Kuparuk River Unit
Measured
Depth
(ft)
Incl.
Azim.
Sub-Sea
Depth
(ft)
Sperry-Sun Drilling Services
Survey Report for 1D-37 MWD
Your Ref: AP1500292299200
Surveyed: f f January, 200f
Vertical Local Coordinates Global Coordinates
Depth Northings Easflngs Northings Eastings
(ft) (ft) (ft) (ft) (rt)
230.00 0.250 78.000 125.10 230.00
190.69
278.19
370.52
467.26
295.59 0.280 75.520
383.09 0.220 302.980
475.43 0.840 295.700
572.23 3.170 289.880
559.04
647.97
742.95
836.06
927.00
664.28 5.430 287.230
753.62 5.600 287.850
849.09 6.010 281.130
942.57 4.210 292.460
1033.69 2.990 297.460
295.59
383.09
475.42
572.16
663.94
752.87
847.85
940.96
1031.90
1128.22 1.320 289.710 1021.46 1126.36
1220.90 0.590 296.560 1114.12 1219.02
1312.47 0.430 288.360 1205.69 1310,59
1405.40 0.420 279.350 1298.62 1403.52
1501.20 0.390 278.530 1394.41 1499.31
,
1596.23 0.370 260.670 1489.44 1594.34
1688.08 0.370 265.500 1581.29 1686.19
1782.50 0.410 281.450 1675.71 1780.61
1877.07 0.460 270.640 1770.28 1875.18
1972.81 0.340 258.900 1866.01 1970.91
2068.16 0.440 278.320 1961.36 2066.26
2162.22 0.520 271.220 2055.42 2160.32
2255.97 2.410 87.230 2149.15 2254.05
2349.79 3.930 92.310 2242.82 2347.72
2446.06 5.010 97.960 2338.80 2443.70
2540.83 7.060 106.080 2433.04 2537.94
2633.39 9.610 113.100 2524.61 2629.51
2725.58 12.100 116.240 2615.15 2720.05
2821.79 13.470 116.300 2708.97 2813.87
2911.93 14.900 115.930 2796.36 2901.26
0.05 N 0.23 E 5959174.08 N 560670.88 E
0.12 N 0.53 E 5959174.15 N 560671.18 E
0.26 N 0.60 E 5959174.30 N 560671.24 E
0.65 N 0.16W 5959174.68 N 560670.48 E
1.87 N 3.32W 5959175.88 N 560667.32 E
4.03 N 9.87W 5959177.98 N 560660.74 E
6,62 N 18.06W 5959180.50 N 560652.54 E
9,01N 27.40W 5959182.82 N 560643.18 E
11.27 N 35.37W 5959185.01N 560635.19 E
13,64 N 40.57W 5959187.34 N 560629.97 E
15,14 N 43.78W 5959188.82 N 560626.74 E
15.72 N 45.22W 5959189.38 N 560625.31E
16.04 N 45.96W 5959189.69 N 560624.56 E
16.20 N 46.63W 5959189.85 N 560623.89 E
16.31N 47.30W 5959189.95 N 560623.22 E
16.30 N 47.92W 5959189.95 N 560622.60 E
16.23 N 48.51W 5959189.87 N 560622.01E
16.16 N 49.15W 5959189.79 N 560621.37 E
16.11N 49.86W 5959189.74 N 560620.66 E
16.06 N 50.53W 5959189.68 N 560620.00 E
16.06 N 51.17W 5959189.68 N 560619.36 E
16.12 N 51.95W 5959189.73 N 560618.57 E
16.23 N 50.41W 5959189.85 N 560620.11E
16.19 N 45.22W 5959189.86 N 560625.30 E
15.48 N 37.76W 5959189.20 N 560632.76 E
13.29 N 28.07W 5959187,09 N 560642.48 E
8.68 N 15,49W 5959182.59 N 560655.09 E
1.39 N 0.25 E 5959175,42 N 560670.89 E
8.03 S 19.34 E 5959166.15 N 560690.06 E
17.75 S 39.18 E 5959156.59 N 560709.97 E
DEFINITIVE
Phillips Alaska
Kuparuk 1D
Dogleg Vertical
Rate · Section
(°/lOOft)
0.12
0.05 0.28
0.52 0.21
0.67 -0.59
2.41 -3.64
2.46 -9.69
0.20 -17.18
0.83 -25.32
2.20 -32.42
1.38 -37.71
Comment
Tie on point
MWD Magnetic
1.79 -41.00
0,80 -42.40
0.19 -43.15
0.07 -43.72
0.03 -44.26
0.13 -44.68
0.03 -45.03
0.05 -45.42
0.09 -45.87
0.15 -46.29
0.17 -46.72
0.11 -47.31
3.12 -46.33
1.65 -42.75
1.21 -37.13
2.34 -28.90
2.96 -16.93
2.78 -0.84
1.42 19.10
1.59 39.76
1 February, 2001 - 10:26 Page 2 of 6 DrillQuest 2.00.06
Sperry-Sun Drilling Services
Survey Report for 1D-37 MWD
Your Ref: AP1500292299200
Surveyed: f f January, 2001
Kuparuk River Unit
Measured
Depth
(ft)
Incl.
Azim.
Sub-Sea
Depth
(ft)
Vertical
Depth
(ft)
3009.37 16.750 115.750 2890.10 2995.00
3102.30 18.340 118.720 2978.71 3083.61
3197.54 21.220 120.710 3068.32 3173.22
3291.28 24.060 120.890 3154.83 3259.73
3387,45 26.640 123.220 3241.73 3346.63
3475.60 29.670 125.600 3319.45 3424.35
3566.82 32.830 127.600 3397.42 3502.32
3660.41 36.520 127.980 3474.38 3579.28
3754.48 39.270 128.750 3548.61 3653.51
3850.95 40.630 129.570 3622.56 3727.46
3946.05 44.710 131.570 3692.47 3797.37
4042.83 46.460 131.440 3760.20 3865.10
4136.10 49.520 133.530 3822.62 3927.52
4229.54 51.970 134.490 3881.74 3986.64
4324.17 53.340 134.720 3939.14 4044.04
4418.39 55.850 133.050 3993.73 4098.63
4509.28 59.450 134.140 4042.36 4147.26
4603.93 63.080 135.990 4087.85 4192.75
4693.59 67.000 135.720 4125.68 4230.58
4790.63 67.310 136.810 4163.36 4268.26
4884.20 67.630 135.720 4199.21 4304.11
4981.86 67.180 134.970 4236.73 4341.63
5047.54 67.070 135.900 4262.27 4367.17
5139.59 67.350 135.130 4297.92 4402.82
5234.22 66.440 136.550 4335.06 4439.96
5325.54 66.180 135.610 4371.75 4476.65
5415.57 68.180 136.340 4406.67 4511.57
5508.70 68.400 135.950 4441.12 4546.02
5593.38 68.100 135.080 4472.50 4577.40
5690.65 67.710 136.460 4509.08 4613.98
Local Coordinates Global Coordinates
Northings Eastings Northings Eastings
(ft) (ft) (ft) (ft)
29.33 S 63.10 E 5959145.21 N 560733.98 E
42.18 S 87.98 E 5959132.57N 560758.97 E
58.18 S 115.95 E 5959116.79 N 560787.06 E
76.66 S 146.94 E 5959098.56 N 560818.20 E
98.54 S 181.80 E 5959076.96 N 560853.24 E
122.07 S 216.08 E 5959053.70 N 560887.71E
150.31S 254.04E 5959025.77 N 560925.90 E
182.94 S 296.11E 5958993.49 N 560968.23 E
218.81S 341.40 E 5958957.99 N 561013.81E
257.93 S 389.43 E 5958919.25 N 561062.14 E
299.87 S 438.34E 5958877.71N 561111.40 E
345.68 S 490.11E 5958832.32 N 561163.54 E
392.49 S 541.19 E 5958785.92 N 561214.99 E
442.77 S 593.21E 5958736.07 N 561267.42 E
495.60 S 646.77 E 5958683.67 N 561321.40 E
548.81S 702.13 E 5958630.90 N 561377.18 E
601.76 S 757.72 E 5958578.41N 561433.20 E
660.51S 816.30 E 5958520.13 N 561492.26 E
718.83 S 872.91E 5958462.27 N 561549.33 E
783.44 S 934.73 E 5958398.16 N 561611.68 E
845.89 S 994.48 E 5958336.19 N 561671.93 E
910.03 S 1057.85 E 5958272.57 N 561735.81E
953.14 S 1100.31E 5958229.80 N 561778.62 E
1013.69 S 1159.78 E 5958169.74 N 561838.58 E
1076.12 S 1220.42 E 5958107.79 N 561899.71E
1136.36S 1278.42E 5958048.03 N 561958.20 E
1196.03S 1336.09 E 5957988.83 N 562016.35 E
1258.42 S 1396.03 E 5957926.92 N 562076.80 E
1314.53 S 1451.15 E 5957871.26 N 562132.36 E
1379.11 S 1514.01 E 5957807.19 N 562195.75 E
Dogleg
Rate
("/tOOft)
1.90
1.96
3.11
3.03
2.88
3.67
3.65
3.95
2.97
1.51
4.52
1.81
3.68
2.74
1.46
3.03
4.09
4.20
4.38
1.08
1.13
0.85
1.32
0.83
1.68
0.98
2.34
0.46
1.02
1.37
Vertical
Section
64.56
90.96
121.77
156.45
196.26
236.88
283.45
336.03
393.17
454.56
518.62
587.45
656.54
728.80
8O3.97
880.66
957.31
1040.24
1121.50
1210.92
1297.35
1387.48
1447.98
1532.82
1619.84
1703.46
1786.42
1872.94
1951.57
2041.68
Phillips Alaska
Kuparuk 1D
Comment
..
February, 2001 - 10:26
Page3 of 6
· .
DrillQuest 2.00.06
Sperry-Sun Drilling Services
Survey Report for ID-37 MWD
Your Ref: AP1500292299200
Surveyed: f f January, 2001
Kuparuk River Unit
Measured
Depth
Incl.
Azim.
Sub-Sea
Depth
(ft)
5780.12 67.480 136.470 4543.19
5878.19 68.910 135.060 4579.61
5973.74 68.960 136.190 4613.96
6072.57 68.430 135.930 4649.87
6168.06 68.130 137.750 4685.21
6262.55 67.700 134.840 4720.74
6356.49 67.300 134.610 4756.69
6452.40 67.000 135.440 4793.93
6543.10 66.970 136.350 4829.40
6640.53 69.120 135.540 4865.82
6738.10 68.570 136.810 4901.03
6829.49 68.720 134.530 4934.32
6925.84 69.650 133.560 4968.56
7020.96 69.440 133.860 5001.80
7113.68 69.240 134.620 5034.51
7205.26 69.050 133.210 5067.12
7301.88 68.970 133.190 5101.73
7396.41 68.720 134.330 5135.84
7489.68 68.490 133.610 5169.87
7582.17 68.430 134.630 5203.83
7677.27 68.210 134.580 5238.96
7770.98 68.200 133.640 5273.75
7864.23 68.190 133.680 5308.39
7958.45 68.330 133.880 5343.29
8052.78 67.790 134.270 5378.53
8146.45 67.440 133.810 5414.20
8239.48 66.940 133.790 5450.27
8333.71 66.610 134.950 5487.43
8428.30 67.720 133.730 5524.14
8524.33 68.250 133.920 5560.14
Vertical Local Coordinates Global Coordinates
Depth Northings Eastings Northings Eastings
(ft) (ft) (ft) (ft) (ft)
4648.09 1439.07S 1570.99 E' 5957747.69 N 562253.20 E
4684.51 1504.30 S 1634.51E ' 5957682.97N 562317.25 E
4718.86 1568.03 S 1696.86 E -5957619.75 N 562380.12 E
4754.77 1634.33 S 1760.75 E 5957553.96 N 562444.54 E
4790.11 1699.04S 1821.43 E 5957489.75 N 562505.74 E
4825.64 1762.33 S 1881.92 E 5957426.95 N 562566.73 E
4861.59 1823.40 S 1943.58 E 5957366.38 N 562628.89 E
4898.83 1885.93 S 2006.05 E 5957304.36 N 562691.86 E
4934.30 1945.87 S 2064.15 E 5957244.89 N . 562750.44 E
4970.72 2010.80 S 2126.98 E 5957180.46 N 562813.80 E
5005.93 2076.45 S 2189.99 E 5957115.33 N 562877.34E
5039.22 2137.33 S 2249.47 E 5957054.93 N .562937.30 E
5073.46 2199.94S 2314.20 E 5956992.85 N 563002.54 E
5106.70 2261.52 S 2378.62 E 5956931.79 N 563067.45 E
5139.41 2322.05 S 2440.78 E 5956871.76N 563130.10 E
5172.02 2381.40 S 2502.42 E 5956812.91N 563192.22 E
5206.63 2443.16 S 2568.18 E 5956751.69 N 563258.47 E
5240.74 2504.13 S 2631.86 E 5956691.23 N 563322.64 E
5274.77 2564.42 S 2694.36 E 5956631.44 N 563385.62 E
5308.73 2624.31S 2756.11E 5956572.05 N 563447.86 E
5343.86 2686.37 S 2819.03 E 5956510.51N 563511.28 E
5378.65 2746.93 S 2881.51E 5956450.45 N 563574.24 E
5413.29 2806.70S 2944.14 E 5956391.19 N 563637.36 E
5448.19 2867.26 S 3007.33E 5956331.15 N 563701.03 E
5483.43 2928.12 S 3070.19 E 5956270.79 N 563764.38 E
5519.10 2988.33 S 3132.45 E 5956211.09N 563827.13 E
5555.17 3047.68 S 3194.35 E 5956152.24N 563889.50 E
5592.33 3108.23 S 3256.25 E 5956092.19 N 563951.88 E
5629.04 3169.16 S 3318.60 E 5956031.77 N 564014.72 E
5665.04 3230.81S 3382.82 E 5955970.64N 564079.45 E
Dogleg
Rate
(°llOOft)
0.26
1.98
1.10
0.59
1.80
2.89
0.48
0.86
0.92
2.34
1.34
2.33
1.35
0.37
0.80
1.45
0.09
1.16
0.76
1.03
0.24
0.93
0.O4
0.25
0.69
0.59
0.54
1.18
1.67
0.58
Vertical
Section
2124.40
2215.43
23O4.57
2396.64
2485.34
2572.89
2659.62
2747.96
2831.42
2921.77
3012.76
3097.85
3187.80
3276.79
3363.46
3448.93
3538.96
3626.99
3713.72
3799.66
3887.96
3974.88
4061.32
4148.72
4236.12
4322.63
4408.26 .
4494.77
4581.86
4670.77
Phillips Alaska'
Kuparuk 1 D
Comment
DrillQuest 2.00.06
1 February, 2001- 10:26 Page 4 of 6
Sperry-Sun Drilling Services
Survey Report for rD-37 MWD
Your Ref: APl 500292299200
Surveyed: ff January, 200f
Kuparuk River Unit
Measured
Depth
(ft)
Incl.
Azim.
Sub-Sea
Depth
(ft)
Vertical Local Coordinates Global Coordinates
Depth Northings Eastings Northings Eastings
(~t) (ft) (ft) (ft) (ft)
8615.81 67.530 133.560 5594.57 5699.47
8709.11 67.450 134.110 5630.29 5735.19
8800.36 67.100 134.540 5665.54 5770.44
8895.59 66.690 134.960 5702.91 5807.81
8989.13 67.480 134.690 5739.33 5844.23
9082.66 67.550 135.930 5775.10 5880.00
9177.24 67.270 136.730 5811.43 5916.33
9271.83 67.200 133.610 5848.04 5952.94
9364.32 67.040 135.550 5884.00 5988.90
9458.27 66.810 135.200 5920.83 6025.73
9551.42 68.080 135.270 5956.56 6061.46
9645.07 68.160 135.390 5991.46 6096.36
9743.23 68.060 135.190 6028.05 6132.95
9837.17 67.670 134.000 6063.45 6168.35
9931.98 68.950 135.510 6098.49 6203.39
10025.19 68.660 141.430 6132.22 6237.12
10194.84 68.150 137.230 6194.68 6299.58
10294.22 68.240 134.670 6231.60 6336.50
10390.22 68.050 134.710 6267.34 6372.24
10485.97 68.410 132.730 6302.85 6407.75
10578.14 67.880 132.720 6337.16 6442.06
10674.34 67.680 133.500 6373.54 6478.44
10771.45 67.290 135.390 6410.73 6515.63
10866.87 66.670 134.760 6448.04 6552.94
10961.55 67.270 136.060 6485.09 6589.99
11003.00 67.270 136.060 6501.10 6606.00
3289.40 S 3~.06
3349.10 S 3506.23
3407.91S 3566.44
3469.57 S 3628.65
3530.31S 3689.76
3591.74S 3750.53
3654.91S 3810.83
3716.75S ' 3872.31
3776.56S 3933.00
3838.08S 3993.72
3899.15 S 4054.29
3960.96S 4115.39
4025.69S 4179.47
4086.78 S 4241.43
4148.81S 4303.98
4213.83 S 4361.57
4333.44S 4464.33
4399.75 S 4528.48
4462.41S 4591.83
4523.87 S 4656.09
4581.91S 4718.93
4642.77 S 4783.95
4705.58 S 4847.99
4767.76S 4910.00
4829.81S 4971.17
4857.34S 4997.70
E 5955912.54 N 564141.15 E
E 5955853.35 N 564203.80 E
E 5955795.03 N 564264.49 E
E 5955733.87 N 564327.19 E
E 5955673.63 N 564388.79 E
E 5955612.68 N 564450.06 E
E 5955550.01N 564510.86 E
E 5955488.66 N 564572.84E
E 5955429.34N 564634.01E
E 5955368.32 N 564695.22 E
E 5955307.73 N 564756.29 E
E 5955246.43 N 564817.88 E
E 5955182.22 N 564882.48 E
E 5955121.62 N 564944.93 E
E 5955060.10 N 565007.99 E
E 5954995.55 N 565066.10 E
E 5954876.77 N 565169.82 E
E 5954810.98 N 565234.51E
E 5954748.83 N 565298.35 E
E 5954687.90 N 565363.11E
E 5954630.37 N 565426.42 E
E 5954570.04 N 565491.92 E
E 5954507.75N 565556.47 E
E 5954446.07 N 565618.99 E
E 5954384.51N 565680.65 E
E 5954357.20 N 565707.40 E
Dogleg
Rate
('llOOft)
0.87
0.55
0.58
0.59
0.89
1.23
0.84
3.04
1.94
0.42
1.37
0.15
0.21
1.24
2.00
5.93
2.32
2.39
0.20
1.96
0.58
0.78
1.84
0.89
1.41
0.00
Vertical
Section
4755.40
4841.47
4925.56
5013.o9
5099.20
5185.59
5272.91
5360.08
5445.22
5531.63
5617.62
57O4.49
5795.54
5882.49
5970.53
6057.35
6214.89
6307.14
6396.18
6484.96
6570.29
6659.16
6748.78
6836.56
6923.67
Phillips Alaska
Kuparuk 1D
Comment
6961.90 Projected survey
DrillQuest 2.00.06
I February, 2001- 10:26 Page 5 of 6
Sperry-Sun Drilling Services
Survey Report for 1D-37 MWD
Your Ref: AP1500292299200
Surveyed: fl January, 200t
Kuparuk River Unit
Phillips Alaska
Kuparuk 1D
All data is in feet unless otherwise stated. Directions and coordinates are relative to True North.
Vertical depths are relative to Well. Northings and Eastings are relative to Well.
Magnetic Declination at Surface is 26.341° (23-Dec-00)
The Dogleg Severity is in Degrees per 100 feet.
Vertical Section is from Well and calculated along an Azimuth of 136.820° (True).
Based upon Minimum Curvature type calculations, at a Measured Depth of 11003.00ft.,
The Bottom Hole Displacement is 6969.27ff., in the Direction of 134.184° (True).
Comments
Measured Station Coordinates
Depth TVD Northings Eastings
(ft) (ft) (ft) (ft)
230.00 230.00 0.05 N 0.23 E
11003.00 6606.00 4857.34 S 4997.70 E
Comment
Tie on point
Projected survey
Survey tool program for rD-37 MWD
From To
Measured Vertical Measured Vertical
Depth Depth Depth Depth
(ft) (ft) (ft) (ft)
0.00 0.00 230.00 230.00
230.00 230.00 11003.00 6606.00
Survey Tool Description
Tolerable Gyro (1D-37 GYRO)
MWD Magnetic (1D~37 MWD)
I February, 2001.10:26 Page 6 of 6 DrillQuest 2.00.06
19-Oct-00
AOGCC
Lori Taylor
3001 Porcupine Drive
Anchorage, AK 99501
MW+IIFR surveys (Definitive)
Re: Distribution of Survey Data for Well 1 D-36
Dear Lori Taylor:
Enclosed are two survey hard copies.
Tie-on Survey:
Window / Kickoff Survey
Projected Survey:
0.00' MD
0.00' MD
11,658.00' MD
(if applicable)
Please call me at 273-3545 if you have any questions or concerns.
Regards,
Kenneth W. Allen
Survey Manager
Attachment(s)
RECEIVED
Anchorage
19-Oct-00
AOGCC
Lori Taylor
3001 Porcupine Drive
Anchorage, AK 99501
MWD surveys (Not Definitive)
Re: Distribution of Survey Data for Well 1D-36 MWD
Dear Lori Taylor:
Enclosed are two survey hard copies.
Tie-on Survey:
Window / Kickoff Survey
Projected Survey:
0.00' MD
0.00' MD
11,658.00' MD
(if applicable)
Please call me at 273-3545 if you have any questions or concerns.
Regards,
Kenneth W. Allen
Survey Manager
Attachment(s)
0 CT 2 4 2000
Oil,& Gas Cons. Commission
Anchorage
APPLICATION FOR SUNDRY APPROVALS
1. Type of request:
Abandon _ Suspend _ Operational shutdown _ Re-enter suspended well _
Alter casing _ Repair well _ Plugging _ Time extension _ Stimulate _
Change approved program _ Pull tubing _ Variance _ Perforate _
Other_X
Annular Injection
2. Name of Operator
Phillips Alaska, Inc.
3. Address
P. O. Box 100360
Anchorage, AK 99510-0360
5. Type of Well:
Development _X
Exploratory _
Stratigraphic __
Service m
4. Location of well at surface
477' FNL, 420' FEL, Sec. 23, T11 N, R10E, UM (ASP: 560671,5959189)
At top of productive interval
2601' FNL, 2379' FWL, Sec. 25, T11N, R10E, UM (per APD)
At effective depth
At total depth
2464' FSL, 2408' FWL, Sec, 25, T11 N, R10E, UM (ASP: 563566, 5951596)
6. Datum elevation (DF or KB feet)
RKB 34' feet
7. unit or Property name
Kuparuk River Unit
8. Well number
1 D-36
9. Permit number / approval number
200-130 /
10. APl number
50-029-22973-00
11. Field / Pool
Kuparuk River Field / Kuparuk River Pool
12. Present well condition summary
Total depth: measured 11658' feet Plugs (measured)
true vertical 6542' feet
Effective depth: measured 11589' feet Junk (measured)
true vertical 6509' feet
Casing Length Size Cemented
Conductor 86' 20" 14 cubic yds ABI Type III
Surface 7012' 9.625" 850 sx AS III Lite, 415 sx
LlteCRETE
Production 11003' 7" 17o sx Class G
Liner 791' 3.5" 174 sx Class G
Measured Depth Truevertical Depth
121' 121'
7047' 4291'
11038' 6242'
11656' 6542'
Perforation depth: measured N/A
true vertical N/A
Tubing (size, grade, and measured depth
Packers & SSSV (type & measured depth)
3.5#, 9.3#, L-80 @ 10885'
No SSSV, No packer
RECEIVED
SEP 27 2000
Alaska 0il & Gas Cons. Co~mission
Anchorage
13. Attachments Description summary of proposal m Detailed operations program m BOP sketch
Refer to attached morning drilling report for LOT test, surface cement details and casing detail sheets _ X
14. Estimated date for commencing operation
September 29, 2000
16. If proposal was verbally approved
Name of approver
Date approved
15. Status of well classification as:
Oil __X Gas __ Suspended __
Service
17. I hereby ~ertify that the foregoing i~s true and correct to the best of my knowledge.
Signed Title: Drilling Engineering Supervisor
FOR COMMISSION USE ONLY
Questions? Call Tom Brockway 263-4135
Prepared by Sharon All, up-Drake
Conditions of approval: Notify Commission so representative may witness
Plug Integrity m BOP Test _ Location clearance m
Mechanical Integrity Test _ Subsequent form required 10- (~) '~-.'~
ORIGINAL SIGNED i~'~
_ Approved by order of the Commission O Taylor Seamount Commissioner
Form 10-403 Rev 06/15/88 · SUBMIT IN TRI PLI CATE
CASING TEST and FORMATION' INTEGRITY TEST
Well Name: 1D-36 Date: 9/9/00
Supervisor. M. Winfree
Reason(s) for test:
[] Initial Casing Shoe Test
[] Formation Adequacy for Annular Injection
[] Deep Test: Open Hole Adequacy for Higher Mud Weight
Casing Size and Description: 9-5/8' 408 L-80 BTC
Casing Setting Depth: 7,046' TMD
4,297' TVD
Hole Depth: 7,080' TMD
4,314' 'FVD
Mud Weight: 9.3 ppg Length of Open Hole Section: 34'
EMW =
Leak-off Press. + Mud Weight
0.052 x TVD
= 860 psi + 9.3 ppg
0.052 x 4,314'
EMW for open hole section = 13.1 ppg
..
Pump output = 0.0846 bps Fluid Pumped = 3.6 bbl
....... ! ..................... l...l...i...~ ...... L..I .......... L..L..L I I I' '
....... T ..................... I'"!"'! .......... l"'l .......... I"T"I' I I I
o--a~'-~ ....... l.~ I i I I I I
~ , -,- , i I I I
J , ...........
r '1 ~~
I~ I il [I I I I ~
~ i II ~~-OFF TEST
I ~ r ~ I ~ LOT ~UT !N TIME-
I ~ ~ I
,I Fa ~ Ii ~, ~ [- - - ~ C~NG ~ST SH~ IN gME
~ ~ I 1~2: I ~MEUNE
~ G. Irn I'"" ' i i i
j' ~ ~ -~ I ~' ~ IJ '. I
~ ~ t? ~ ~-1 I
STROKES
LEAK-OFF DATA
MINUTE8
FOR
LOT
STROKES PRESSURE
, 0 sttm .... .O_psi
2 stks 50
4 8tks ._...~__ps_[~
e ~ ._.~_~.~j.._
8 stks 185 E~_.
10 arks 255..1~.]._
12 stks ._.3.._.~..iEsi_.
........... .14 stks_.__,._.3~_5_ ..l~,.]_..j
16stks : ' ,
, 435DSl ,
I ~ ~-~ J ,570 Rsi ~
~itT~ 'i
34 aas _Z..oo_j~:L.]
..... 29.-----~--_~... ..... Z_~L.J,'
2~ .... L~._~_,i
38stks i 860 psi j
4ostb =..8.~__~_i .... '
'
t I J I
SHUT IN TIME SHUT IN PRESSURG
~_o.omin ] 8so~i _j
1.0m~n ; ~ 750Dm ;
.... I ,f----~--J- ....
2.0 rain j : .7_~._,i ~
3.0 min; j_.s_so__~i _j
4.0 min~'
; ,j sso psi._!
5.0 min~ i 650 p.~.i...
7.0rain J J 600D8i
_S:Omn. ~ i .... -~----~-s-L-,
t0.0 min ' i S00.p_s.i
CASING TEST DATA
MINUTES
r-off
CSG TEST
STROKES PRESSURE
0 stks 0 psi
4 stks 100 psi
i......~._...i, .........~,a=== ....... ~...~.,i
.._.8.._.t..~. ..... _2.~_5_.~L_i
12 ,tks _.4~....Rs_.L
._!.q.:.t.~ ..... _585 R.s. L4'
20 stks 770.~L.j
24
................. 2.8. ~_t..k?_,~,_~_o.E
32 stks
40 Mks 1,565 p_sLj
............... 44,tks ~,?4o.I~.Lj
__ 48 stks ...l_,9_!O_._p.sJ.L],,'
............ ~.~.~_ ~,_._o~.j~_U
....,~..._Sl:..l~....., 2,300 pS1
68 Mk~ ! 2,820.pB_L
72 elks ~' ~'--~---E i
i
I
I I I
Bur IN TIMI= SHlYr IN PI:II=SSURE
0.0 min ...3_.,~0
1.0 min
: : : 7Z :-/.-_-.L Z ;
3.0 min ................ ._.2,.c95_0_p,,,___j
~...4_.._o_m!n ................... ~.,_9s.O_mLj
5.0 min
........... · - .................. I ......... :'!
..s;.o__m.,n. ........... ;...2.~._s..~,
?.0 rain .............. i_.2.,__~0._~!.~
8.0 rain .............. ~.._2_, ...~0. _ ~i...,,'
,. _ .~...o_m_Ln_ ................
·
10.0 mln = 2,900 ~sl
~....~ ..........
15.0min i ~ 2,900~si ~
....... =' ,~ ............ '! ......... ' ....
. _..2.0_._0_mj.n_; .............. , ...2_, _~[0._p..s.[
....~..s:.o...mj.n.. j. .............
30.0 rain ' 1 2,900 ..l~.i.~
NOTE: STROKES TURN TO MINUTES DURING 'SHUT IN TIME':see time line above NOTE: TO CLEAR DATA, HIGHLIGHT AND PRESS THE DELETE KEY
Phillips Alaska Drilling Cementing Details
Well Name: 1~ Report Date: 0~/0a/20O0 Report Number: 1
Rig Name: NaOom 16E AFC No.: AK0106 Field: KRU
"i ! i ..............
9-5/8" 40~ I_ 12-114" 7048 I 696/'
, ,, ,,
c~ntmll~lr~ ' .. , ... State type used. intervals covered and spacing
, ,, .. , , ,
C°m'~.e~ts: ' .. 12# 9.~/e' x 12- W]dMd SplraGIIder bottom 500' one/Jt....S2 ee e-S/~" X 12-114' b~waprlng, one on every ~d Jt to IuH
.... :...
I '
Mad ' · Weight: PV(prio~ tend): PV(aftsr tend): YP(prim' ~ond): YP(,.fter cond):
Comment~ :. 9.6 ~5 20 48 15
,, .....
· ' ""; '""' :' .'. ' Gels before: Gels after: Total Volume Circulated:
:.'...
:..': .r.. ; '. 20/40 8/8
' ": ' ' ' ': ' ' ': ' ' Type: Volume: Weight:
Wash 20" ·
Comments;, ' .... . ', ' ARCO Wash 20 6.6 e~t
.,
, ,, ,,,
~"."' 0 .::' .... · Type: Volume: We~ht:
.Comments: · ARCO B45 ' 40.5bble 10.$
":!: ','Il ::. '/: ::' '., , ':.
i,,,.',!:.;. ~,~::'. !: .": ,.":'"
; ,
Leald.CIl~.,' 0 : ' ," , :;i Type: Mix wtr temp: No, of Sa~s: Weight: Yield:
Core,ten,si: :'.:..: .;: ' . · ' ':?'." AS III Ute 70 853 10.7 4.44
:' '.':..":..; i ." .' 'i ". : :""
: ':...~'.',",: i.,',i,.'.::,,','. ~':'"~ ':'.'! ';", '! ~,~s: ......
. i' !':.'..:'i.':'..' :. i i' "'..':'... ' :". ':::: ! '.' :' ::i 50~D124, 9~D,14, 0.4%D46, $0~, 053,1.5%61,
? .i:'i: 'i '. !:~, i'.." :'?::: '! : i:: i': !:!: .: '.i::'i. ': '~":'": u.c,~E . 7o
, .
:':'~:::::i.":. :::' ':i'::.::.'?.:::~::i:.=::.:"::.'i:.'::'.'::.~:'~:::~;i.'i.:' ,,d,,t~,.:
~.,,;i;:; i:i ;, :; :',i ::i,:. I: :,i:':','; :. :.. i: '.:.'. !. ,',. :: :: ?
,t,i ~, ,: = t , l = :. i .:; i ,, .. ,., .i ; . · .... iii i i i i
:~~'=: P:' :' 'i' :'" :" ::i= ' "'" Rate(before tail at $1~e): I Rate(Ceil around shoe): Str. Wt. Up:
"~i~i~t~i,! ': .'":'": ,.i~:"~'":'!!'.:" e~m .ebpm
.:, ; ,, .;,~. :.,:, :,,,, ,, .... ,, : ': ,.,.:, . ,.,
,i' ,' ,:',: ~:~' ": !,~. ii:. :' ,, ,,, ,:,: ~, ..... ' ':' ':': "' ': Reciprocation length: R~lpror. ation speed: Str. Wt. Down:
:.. ::.'i':~: !:;"=:':::.! i?.:'::i!.:' ::." i.' :::~' ','i ::.'i :,.::. ;' :~:,.,~:: o o , t53
, '=,r::; 'i.,:r,i., ,' ',::i,:: ' v,; '::: ii,: ,:: ;,,, ::! r:, Theoretir'al DlspleCement: Actual Displacement: Str. Wt. in mud:
:,' ,.. ,,. i.',; ..... ' ,' ,:.
:.,:., ,.,:.:1:. ~...!:,: =i,..r...'. '..'.:.: i.: ii.'.:: :.';'.:::= ;ii.i:!.i i sas iai
, ,, ,, , , ,
,
Calculated top of cement: CP: Buml~:l plug: Floats held:
Cmt to luff 10.7# Date:l/&'00 y~ yN
Time: 1~00 hr.
,em.,,s:W. ,or ,,, to ,.~,~r.=,. ,~p...'Pu,ed 47OK# got ~. o~
I.-. ...... ~' --_ '" ' ' ,_. _ '"".",~III',~ ' ,h'h I '-,, ,"
Cement Company: I Rig Contractor: J Approved By:
Dowell I NABOR$ I M.Winfree
RECEIVED
SEP 2 7 2000
Alaska 0ii & Gas Cons. Commission
Anchorage
{.i Casino D®~il
9-5/8" surface casina WELL: 1
Phillips Alosko Inc Date; 09/05/00
! OF ! PAGES
# ITEMS ..... COMPLETE DEscRIPTION OF EQUIPMENT RUN LENGTH DEPTH
Nabors 16E RKB = 34.40' TOPS
9-$18" Landing Joint (RKB) $4.40
9-518" FMC GEN V FLUTED MANDREL HANGER 2.10 34.40
Its 3-! 7 !' 9-5/8",'40#, L-SO BTC-MOD' (! 69 its) ....... 6931.00 36.50
Oemeco FlOat Colla~' " 1.58 ~967.50
its 1-2 9-5/8", 40#, L-80'BTC'-MOD (2 jts) 76.02 6969.08
oemeco Float Shoe .... 1172 70451'10
,,,
BTIM OF SHOE ~ 7046.82
' Shoe ~ 7046.82 MD 4302TVD ...... i ., ,
m ~ 12- li~" hole = 705~ 'MD ~2' TVD "'
R~n 1' e~ch' 9.$[r x 12. W~ord SpiraGlider c®n~llz®~ on Ioin~ ........
.... Ran 9-5/8" X 'i2. I/,, bowSPring'~entralizer on every 3rd"joi~ ,..
., Starling WI Il #16 and ending,.wi, th joint # 169 (52 tota!) ......
..... )~er~ ....
Remarks: String Weigl~'~s'w#h Blocks, l ~Ok~ Dn, 70k Blocks. Ran 171 Joints of caSing. Drifted .....
casing with 8.679" plastic rabbit. Used Best-o-Life 2000 thread compound on all connections.
CASING TEST and FORMATION INTEGRITY TEST
Well Name: 1D-36
Date: 9114100 Supervisor: Mike Winfree
Reason(s) for test:
[] Initial Casing Shoe Test
[] Formation Adequacy for Annular Injection
[] Deep Test: Open Hole Adequacy for Higher Mud Weight
Casing Size and Description: 7", 26#, L-80, BTC mod
Casing Setting Depth: 11,038' TMD
6,249' TVD
Hole Depth: 11,068' TMD
6,264' TVD
Mud Weight: 9.8 ppg Length of Open Hole Section: 30'
EMW =
Leak-off Press. + Mud Weight
0.052 x TVD
-- 2,025 psi + 9.8 ppg
0.052 x 6,264'
EMW for open hole section = 16.0 ppg
Pump output = 0.0846 bps Fluid Pumped = 3.2 bbl
4,000 psi
3/~0 psi
3.800 psi -
3.700 ps;- --e-- LEAK-OFF TEST
3,000 psi -
3.5oo ps~ - --~--CASlNG TEST
3,400 psi -
3.3oopsi - .._~_ LOT SHUT IN TIME
3,200 psi -
3.100psi- ~CASlNG TEST SHUT IN TIME
3,000 psI -
2.g00 p~ -
2,800 psi -
2,700 psi
2.~X3
2.500 psi
2,400
2,300 psi -
2,200 psi
2.100
2,000
1.g00
1.800
1,700
] .(:~0 psi
],500 psi
1,400 psi
1,300
1,200 psi
1,100 psi
1,000 psi
800 psi
700 psi
5OO psi
3~0 psi -
0 psi
STROKES
NOTE: STROKES TURN TO MINUTES DURING "SHUT IN TIME":see time line above
._
LEAK-OFF DATA
CASING TEST DATA
MINUTES MINUTES
FOR
LOT STROKES PRESSURE
..................... .o.?..Lk.?. .......... .o..p..s.i. .....
2 stks 140 Esi
i .................&.
.................... .4..s..t.k..s. ....... .2.Z.s...i?.?i ....
..................... .6..?.t.k..s_ ....... .3. .8. .5. ~.sj ....
.................... .S.?..t.k.?. ....... .s..2..s...R?. i ....
.................... .1..O.?_t.k..s. ....... .s.~.o...ij. sj ....
.................... .T.2..s.!.k..s. ....... ZZ.o..~i ....
14 stks 875 psi
.1. ...............
................... ].~.]~[[ ..... J. 'lPl6..0.. P.?J.. l
26 stks 1,440 psi
I ................
28 stks
................
i i ' l
, 30 stksI 1,640 nSl ,
................
I i · l
, 32stks j 1,745 $1,
................... ~l ~l ]~[[ ...... J. :. .8.4.15. ip_sj..]
38 stks 2,025 psi
I
SHUT IN TIME SHUT IN PRESSURE
... ~:J..~] ~. ..................... .2. : g. .2. .5. R.S.l..j
1.0 min 2,000 Esi !
....3.:.°...m. Ln... ! ................... 12.'1917.0..Pl?J.. ]
................
i i I
6.0 mln
8.0 min
................................ .j,,
FOR
CSG TEST STROKES PRESSURE
ZZZZZZZ . 3ZZE C3
5 stks i 315 psi l
I,, ................ l. ............... J .......... ~. ...... J
10stks j 635 psi j
....................:1' ~ '~'t~"l'" '~,~'~'~'" l
.................... ][l
.s.t..k?... mil. ,1.4..5.0...P. ?.i.. l
I · i
30 stks I 1,768
................................. 4 ...........
....................
40 stks J 2,394 psi !
................. r ............... I ................. !
, 45stks , 2,720 psi ,
................. ~ ............... ~ ................. .j
· !
1
!
i
................. l. .................................
.1
SHUT IN TIME I SHUT IN PRESSURE
3.0 min[ 3,500
4 0 mm ~ 3,500 o$1
5.0 min i i 3,500 psi
..................................................
· ! ! ·
7.0 mln : : 3,450 psi
,....8:.O...m.j.n...l[ ............... 1.. ]:~--~--R
i... l?.'2.1mlJln, l ..j ...............
i lOOmin j j 3,450 psi i
',...2.0..'lO..Dj.n. llj ................... ]]~.?].R[[--, J
J
9.0 min : 25.0 min 3,400 p. si
................ · ,- ............... ~ ................. .lI r ................ r .................................
· ' : i 30.0 mini . 3,40.O...p..s.i_i
NOTE: TO CLEAR DATA, HIGHLIGHT AND PRESS THE DELETE KEY
Phillips Alaska Drilling Cementing Details
Well Name: 1D-,15 Report Date: 09/14/2000 Report Number:. 2
Rig Name: Nabom 16E AFC No.: AK01O9 Field: KRU
-- , .. .
..
Casing SIZeT. H°ieDiameter: Anglo thru KRU: I Sh°e[:)epth: J LCDepth: ! %wash°ut: ~-1J'21 60 11038 , I O956
C;en!mllzem .. .. sram type used, intervals covered anrJ spacing
c,~mmenw.: .: '.
..... :. :: ~ - .?xJ.1/4, wxford Iplmgllaer, 1 per It I~ttm 5o9';17 each 7" centering guide from eurflae to K~P.
:: .... .. , ,
M#d.'.:':. ::': ': ": Weight: PV(prlor cond): PV(after cond): YP(prior cond): YP(aher cond):
~i~.,ntS:. :.:...:.' lO,O 2o 18
· i~ .::.::'" ': '- . '" , .:-i' ' ""
"::' :':'ii' ? . i". :' iI'.. : :.' '. ' ", ' ' Gala before: GMs after: Total Volume ¢irculatacl:
· .- ..'. :.~ 12/18 7110 2 bottoms up
.... . ..
Wlih : .'.::0 ' .:.Type: Volume: Weight:
ARCO
Weah
20
0.6
:.
': .,:, ...,,.~,. '..~,
$~',':";::=','0~: .:." '"=':' .~t Typo: 'Volume: Weight:
Comments: : . ARCO 945 30 12.0Pl)B
':....' .. . ..
! ,;.;, :'.,. ... .
i~ld ~,llltiItt .: 9 ':' .' . :' 'i...::::~:. Type: Mix Mr tamp: No. of $aoks: Weight: Yield:
,=c, ommefl~... =..' ,., '.:,, '=: ,.:.' =: .:,,'. '..,. :i o 7/ 170 15.8 1.17
. .::..:.i':.::.:...~.i".:..";: :. ~.":,!:i'i" :.':.':'":;"! ::'1 Add,Ives:
i '~'. ~!::~':.::= i~::.:;: '!. ":.'.'~. :i.:.: ...."' ":: .' Type: M'X wtr'i~p: No. of Sacks: Weight: Yield';
.CM~m~tmi':.':. i.:':. ::... ::..: .= ':.. ::' :..
,
~~M:i::'O:r '~:.:::'.'.. ':'" :':.: ::' Ratelbefore tail at shoe): Rateltail around shoe): Str. Wt. Up:
~.m.,.M~:!!.i!i. i...::,: :. !:::: :?..: ': 'i :: :i:'....~ 7 bpm 7
bpm
2~0
!i": ii¥,,:'::, ,',': :...~,,: ;, :' :"':.':'"~i:"? !,:[ ::!:':['",:::: R~olpro~afion len~h: ' %olprooa~lon apead: ...... 8tr. Wt. Do~:
.;i,:~',:.::'i:~'::,:,,i'.:.':,,:..::.i:i':::...,::,.:::.::/:II' .: :'.:,:,i: ~.
ii':::.,, :. :: ,? ~:~i:":,:~ :.::::'/.':~: ~.':. ~,aore~,~, .......
!; :,'::'.!'i: ::, ::: DisplaCement: Aotu,I Displacement: Str. Wt. in mud:
h,':',':," ~:.':". :' ":..!.;'~:.:.:..:'" ;,' '.':.,.i :..:. 419bbls 419
,
Calculated top of oement: CP: 'Bumped plug: FlOats held:
10344 Date:a/13/00 no yea
Time: 1030
Remarks:Pipe quit rM=lp, after epa~lr turned oboe. tagged cement 344' high In pipe
i. i i i i ,11 i iiii ill i i i i i i
Oement Company: I Rig Contractor: IApproved By:
Dowell INABOR$ IM. Winfme
SEP 2 7 2-000
Oil & Gas Cons. Commission
,~chorc-,ge
Casing Detail
Intermediate casinu
WELL: 1 D-36
Phillips Alaska Inc.
DATE: 9/11/2000
OF 1 PAGES
# ITEMS COMPLETE DESCRIPTION OF EQUIPMENT RUN LENGTH DEPTH
Nabors 16E RT to LDS = 33.80' TOPS
7" Landing Joint (RKB) 31.41
7" FMC GEN V FLUTED MANDREL HANGER 1.86 31.41
jts 3-268 7", 26#, L-80 BTC-MOD (266jts) 10922.83 33.27
Gemeco Float Collar 1.26 10956.10
jts 1-2 7", 26#, L-80 BTC-MOD (2 jts) 79.58 10957.36
Gemeco Float Shoe 1.46 11036.94
BTrM OF SHOE @ 11'038.40
Shoe @ 11037.06 :
TD of 8-1/2" hole = 11048.00' MD 6247' TVD :
,,
Run 1 spiraglider per joint on joints 1 -14 w/stop collars.
(Note; joints 1 & 3 will have bow springs do to float equipment)
.'
Run 1 centering guide on joints 21.6,219,222,225,228, 231,234,23i
240, 243, 246, 249. 252, 255, 258, 261,264
Do not run its 10, 20..PU jt 268 and put hanger on top
,'
,
,
,,
.'
.
,
Remarks: String Weights with Blocks: ~k Up, 160kk Dn, 70k Blocks. Ran 266 joints Of casing.
Drifted casing with 6. 151 "plastic rabbit. Used Best-o-Life 2000 thread compound on all
connections. ..
,
·
Nabors 16E Drilling Supervisor: Fred Herbert ..
Phillips Alaska~ ][nc. ~00 G Street, Anchorage, AK 99501
-- -- I IIII I - -- IIII
FAX
Number of pagcs including cover sheet: &
To;
Phone;
CC:
mi
RI~MAlZX$: I-I Ur/~e.n~ ~For yo~ r:vi~w i-1
From:
Wells_G.roup
Fax phone:
265-6224
Location;
ATO-J
Reply ASAP
_ III II IIIII --
I-] Please comment
IO'd cl8~,:~0 00-c;0-0I ¢:~'c:Ic:9~;Z06 :'ON ~O_-I )ILl S;dI"I'IIHd '-b108-4
~0/05/00 15:10
'ID 36,
NA~,OR~ 1~
~mLk~
Cementing
55O0 I~1
AJL,~'__-~J_'~n = $33,424,00
Tdml: SS~,~ 021
Cementing Servloe Report
-.
i_ " .1'=. l"°.i''".
OilI Land
Old I wo~v~'
~ ~ ~aing
0 pei ~/3'F O'F G pa~ft
0 In ~
OIt
Casing VoL .Annular VoL
ORB I~1 393 DI~I
OixnM
0 Ut)
Job
'i'd I,b~ ,g~ Oin
,T~Iv,,I; Obbl
PAUSE
Voll - 20,3B b~l
0, !
~O"d d8~=~0 00-gO-OT g~GTGg~ZOG :'ON XUd ~U Sd1991Hd :NO~
10/05/00
Cum
AR, CO AUL~ INC
003
[Stags V,,1~,.,40.54 bbl
Volume
RM~i 07
P~ge 2 of $
~'O'd d8~;~0 00-c:0-8T' c:~c:Tc:gz:Z06 ;'ON ~:U..-I )IU SdI"l"lIHd :IdOl-4
004
ARCO At.A,~KA INC
,, IP.o~ Volum~
o I
~O'd d6~:~0, 00-~0-01 ~gB~Bg~Z06 :'OH XUJ ~U SdI~IHd :HO~d
10/05/00 L$;1~ I"AX
I~00~
'ID f36
I~dd
0
0 i 0
c:0'd d6V:~O 00-~0-0~ c:£c:~c:9~:/.06 :'0N :~ld_-J >Ill SdI'i'lIHd :WO~-~
10/05/00 15:14
10~ ARCOALASKAINC
0 I
roll = 1 I11,e bbl
~Glume
90'd dOC:~,O 00-c:0-01 c:~'c:Ic:9~:/-06 -''0N XU_-I )ILl Sdl'l'llHd :ldO~l_-I
_Phillips Alaska, ~nc. 700 G Street, Anchorage, AK 99501
__ __ I IIII I - - III
FAX
Date:
Number of pages including cover sheet:
Phone:
Yax phon~:
CC:
27~-
Wells Group
Fax phone:
265-6224
Location: ATO-;iIIII
II IIIII II
REMARKS: ri Urgent
[~For your review D Reply ASAP r'l Please comment
_ ----'- · II --IIII __. II II
IS"d d8~:~8 88-g8-0! g£glgg:z06 :".0H XUd . NB SdlqqlHd IN0a~
~002
1D 36
Cementing Servloe Report
AK 0 pai,~ 80 "F 0 "F A IMd/ft
~50D I~1
A]bGdJon =
TM-I = $102,M1.~
0217-7009
0 psi Ooubla cament hea
CMk~en~e~,s~nnM [] 1 ~ ~ aM
8/t9/00
Op~nHo~ V~
O~t
0 in
oft
r.d,r ~.~ 6~7.5 fl ~ tWJVM;.
0 bbl
AFTER PAUSE
Lines
Voium~
Vol] - 20,3B ~,l,l
O. I
Piga t afb
~O'd d8~:~0 08-GS-ST G£GTG9~Z06 :'0H %~d 3U SdX77XHd :N0~d
10/05/00
ARCO ALASKA
0O3
VobJr~
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AI,AS~IA O!I, AID GAS
James TrantharnCONSElgVA~ION COI~ll~llSSIOI
Drilling Engineering Supervisor
Phillips Alaska, Inc.
P O Box 100360
Anchorage, AK 99510-0360
TONY KNOWLE$, GOVERNOR
3001 PORCUPINE DRIVE
ANCHORAGE. ALASKA 99501-3192
PHONE: (907) 279-1433
FAX: (907) 276-7542
Re:
Kuparuk River Unit 1 D-36
Phillips Alaska, Inc.
Permit No: 200-130
Sur Loc: 477'FNL, 420'FEL, Sec. 23, T11N, R10E, UM
Btmhole Loc. 2498'FSL, 2413'FWL, Sec. 25, T1 IN, R10E, UM
Dear Mr. Trantham:
Enclosed is the approved application for permit to drill the above referenced well.
The permit to drill does not exempt you from obtaining additional permits required by law from
other governmental agencies, and does not authorize conducting drilling operations until all other
required permitting determinations are made.
Annular disposal has not been requested as part of the Permit to Drill application for Kupamk
River Unit Well No. 1D-36. Please. note that any disposal of fluids generated from this drilling
operation which are pumped down the surface/production casing annulus of a well approved for
annular disposal on Drill Site 1D must comply with the requirements and limitations of 20 AAC
25.080. Approval of this permit to drill does not authorize disposal of drilling waste in a volume
greater than 35,000 barrels through the annular space of a single well or to use that well for
disposal purposes for a period longer than one year.'
Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25 035.
Sufficient notice (approximately 24 hours) must be given to allow a representative of the
Commission to witness a test of BOPE installed prior to drilling new hole. Notice may be given
by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607.
Daniel T. Seamount, Jr.
Commissioner
BY ORDER OF THE COMMISSION
DATED this ] £~ day of September, 2000
dlf/Enclosures
cc: Department of Fish & Game, Habitat Section w/o end.
Department of Environmental Conservation w/o encl.
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PER IT TO DRILL
20 AAC 25.005
la. Type of worlc Drill r~! Redrill F1 I lb. Type of well. Exploratory D Stratigraphic Test [-1 Development Oil ~i
Re-entry E] Deepen DI Service [~ Development Gas [~ Single Zone ~1 Multiple Zone ~]
2. Name of Operator 5. Datum elevation (DF or KB) 10. Field and Pool
Phillips Alaska, Inc. RKB 35 feet
3. Address 6. Property Designation ~> 7_.~'~,~'1:b Kuparuk River Field
P.O. Box 100360 Anchorage, AK 99510-0360 ADL 25661 ALK 471 ~ /5~ Kuparuk River Pool
4. Location of well at surface 7. Unit or property Name 11. Type Bond (see 20 AAC 25.0251)
477' FNL, 420' FEL, Sec. 23, T11 N, R10E, UM Kuparuk River Unit Statewide
At top of productive Interval 8. Well number Number
2601' FNL, 2379' FWL, Sec. 25, T11 N, R10E, UM 1 D-36 #U-630610
At total depth 9. Approximate spud date Amount
2498' FSL, 2413' FWL, Sec. 25, T11 N, R10E, UM September 1,2000 $200,000
12. Distance to nearest property line I 13. Distance to nearest well 14. Number of acres in properly 15. Proposed depth (MD and TVD)
2601 @ TargE feetI 1D-38 30' @ 120' feet 2560 11624' MD /6530' TVD
16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2))
Kickoff depth: 250 MD Maximum hole angle 60.7° Maximum surface 3465 psig At total depth (TVD) 4171 psig
18. Casing program Setting Depth
size Specifications Top Bottom Quantity of Cement
Hole Casin~l Wei~lht Grade coupIin~l Length MD TVD MD 'rVD (include sta~le data)
30" 20" 91.5# H-40 Weld 85' 35' 35' 120' 120' 230 sx ASI
12.25" 9.625" 40# L-80 BTCM 7017' 35' 35' 7052' 4299' 820 sx AS III
8.5' 7' 26# L-80 BTCM 11034' 35' 35' 11069' 6259' 180 sx Class G
6.125' 3.5# 9.3# L-80 SHLT 555' 11069' 6259' 11624' 6530' 140 sx Class G w/Gasblock
19. To be completed for Redrill, Re-entnJ, and Deepen Operations.
Present well condition summary
Total Depth: true measured vertical feet feet Plugs(measured) ORIGINAL
Effective Depth: measured feet Junk (measured)
true vertical feet
Casing Length Size Cemented Measured depth True Vertical depth
Conductor
Surface
Production RECEIVED
Liner AUG 2 4. 2000
Perforation depth: measured ,~$,~ ~;~' :'.q: ' ' '
true vertical
20. Attachments Filing fee r~! Property Plat [~ BOP Sketch r~l Diverter Sketch [] Drilling program r~1
Drilling fluid program r~ Time vs depth plot DRefraction analysis [-! Seabed report r"l 20 AAC 25.050 requirements r-~
21. i hereby ce~ :ify that the foregoing is true and correct to the best of my knowledge Questions? Call Tom Brockway263.4135
Signed % J. Trantham Prener~d h /lll~un. Drel~
Commission Use Onl~
ISee cover letter
Permit Number ~_ {~1 APl$;.umb~.~..,,~.....~_.~~_~ I /~proval date~...~/~. ~2 I,orotherrequirerr~nts
RequlredworklngpressureforBOPE D2M: D D ,oM:D O
Other.
ORIGINAL SIGNED BY byorderof
/I.
/
D
... ~provedby D Taylor Seamount Commissioner the commission Date T''"= I "' ~
....
Form 10-401 Rev. 12/1/85 · Submit in triplicate
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
August 22, 2000
Alaska Oil and Gas Conservation Commission
3001 Porcupine Drive
Anchorage, AK 99501
(907) 279-1433
Re:
Application for Permit to Drill:
Surface Location:
Target Location:
Bottom Hole Location:
KRU 1D-36
477' FNL, 420' FEL, Sec 23, T11N, R10E, UM
2601' FNL, 2379' FWL, Sec. 25, T11N, R10E, UM
2498' FSL, 2413' FWL, Sec. 25, T11N, R10E, UM
Dear Sirs:
Phillips Alaska, Inc. hereby applies for a Permit to Drill an onshore development well to the
Kuparuk interval from 1D Pad in the Kuparuk River Unit ("KRU"). The well is designed to
penetrate and further develop the production potential of the Kuparuk sands in the vicinity of 1D
pad.
The well is designated as a conventional producer and is planned for a 9-5/8" surface casing
string, a 7" intermediate casing string, and a 3-1/2" production liner to penetrate the Kuparuk
sands. The well will be drilled and completed using Nabors 16E. Completion plans call for
running a 3-1/2" gas lift tubing string.
Please find attached information as required by 20 AAC 25.005 (a) and (c) for your review.
Pertinent information attached to this application includes the following:
1 ) Form 10-401 Application for Permit to Drill per 20 AAC 25.005 (a).
2) Fee of $100 payable to the State of Alaska per 20 AAC 25.005 (c) (1).
3) A directional plat showing the surface and bottomhole locations proposed for the well
per 20 AAC 25.005 (c) (2).
4) Directional plots and proximity calculations in accordance with the requirements of 20
AAC 25.050.
5) Diagrams and descriptions of the BOP and diverter equipment to be used as required
by 20 AAC 25.035 (a) (1) and (b).
6)
A complete proposed casing and cementing program is attached as per 20 AAC
25.030. A wellbore schematic is also attached visually depicting the proposed well
and completion design.
7)
The drilling fluid program, in addition to the requirements set forth in 20 AAC 25.033
are attached in this APD package. ~'~ECE~VE~
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
8)
9)
10)
11)
A copy of the proposed drilling program, including a request for approval of annular
pumping operations is attached.
A description of the procedure for conducting formation integrity tests, as required
under 20 AAC 25.030(f).
Also note that Phillips does not anticipate the presence of H2S in the formations to be
encountered in this well. However, there will be H2S and combustible gas monitoring
equipment functioning on the rig as is the standard operating procedure in the Kuparuk
River Unit drilling operation.
Please note that because of the large volume of regional information available in this
area, Phillips considers this well to be a development well, and as such, no
mudlogging operations such as type log generation and sample catching are planned.
The following are the Phillips designated contacts for reporting responsibilities to the
Commission:
A)
Completion Report
(20 AAC 25.070)
Sharon AIIsup-Drake, Drilling Technologist
263-4612
B) Geologic Data and Logs Bill Raatz, Geologist
(20 AAC 25.071) 263-4952
Please note that the anticipated spud date for this well is September 5, 2000 If you have any
questions or require further information, please contact Tom Brockway at (907) 263-4135 or
James Trantham at (907) 265-6434.
Sincere~ ...... ,/
Thomas A Brockway '~
Operations Drilling Engineer
Attachments:
CC:
KRU 1D-36 Well File
Tom Brockway ATO-1040
GENERAL DRILL AND COMPLETE PROCEDURE
EBA PRODUCER
KRU 1D-36
General Procedure:
1. Excavate cellar, install cellar box, set and cement 20" conductor to +/- 150' RKB. Weld
landing ring on conductor.
2. Move in / rig up Nabors Rig 16E Install diverter & function test same.
3. Spud and directionally drill 12-1/4" hole to 9-5/8" surface casing point (+/- 7052 MD')
according to directional plan. Run MWD / LWD logging tools in drill string as required for
directional monitoring and formation data gathering.
4. Run and cement 9-5/8" 40.0# L-80 BTCM casing to surface using lightweight permafrost
cement lead slurry to assure cement returns to the surface. Adequate excess cement will be
pumped to ensure cement reaches the surface during the first stage cement job. Displace
cement with mud.
5. Nipple down diverter and install wellhead. Nipple up BOPE and test to 5000 psi. Record
results.
6. Shut in BOP's and pressure test casing to 3000 psi for 30 minutes per AOGCC regulations.
Record results.
7. Drill out cement and 20' of new hole. Perform formation integrity test not to exceed 16.0 ppg
EMW. This establishes a maximum allowed drilling mud weight below the casing shoe per 20
AAC 25.030 (0.5 ppg less than the FIT or LOT EMW).
8. Directionally drill 8-1/2" hole to mid-point of the HRZ (+/- 10903' MD) according to directional
plan. Run MWD / LWD logging tools in drill string as required for directional monitoring and
formation data gathering. Perform second LOT to evaluate long string option. If LOT is
adequate to long string, drill to well total depth (+/- 11624' MD), run 7" 26.0# L-80 BTCM
casing to surface and cement, and continue with step #17.
Note: If significant hydrocarbon zones are present above the Kuparuk, sufficient cement
will be pumped for isolation in accordance with Rule 20 AAC 25.030
9. If LOT is inadequate to long string, drill to 7" intermediate casing point (+/- 11069' MD).
10. Run 7" 26.0# L-80 BTCM casing to surface and cement.
Note: If significant hydrocarbon zones are present above the Kuparuk, sufficient cement
will be pumped for isolation in accordance with Rule 20 AAC 25.030
11. Nipple up BOPE and test to 5000 psi. Record results.
12. Shut in BOP's and pressure test casing to 3500 psi for 30 minutes per AOGCC regulations.
Record results.
13. Drill out cement and 20' of new hole. Perform formation integrity test not to exceed 16.0 ppg
EMW. This establishes a maximum allowed drilling mud weight below the casing shoe per 20
AAC 25.030 (0.5 ppg less than the FIT or LOT EMW).
14. Drill 6-1/8" hole to well total depth (+/- 11624' MD) according to directional plan, running LWD
logging equipment as needed. Circulate and condition hole. POOH
15. Run open hole e-line or drill pipe conveyed logs as needed.
16. Run and cement 3-1/2" 9.3# L-80 SHLT liner and Baker ZXP/Flexlock hanger/packer
assembly. Set packer +/- 150' above intermediate casing shoe to provide appropriate liner
lap.
17. RIH with clean out BH^. Scrape casing. Displace well to completion brine.
18. Run and land 3-1/2" tubing with gas lift completion.
TAB, 08/22/00, v3
19. Pull landing joint. Install BPV. Nipple down BOP stack, and nipple up production tree. Pull
BPV. Install test plug. Pressure test production tree. Pull test plug. Secure well.
20. Freeze protect well. Set BPV. Release rig and turn well over to production.
21. Clean location and RDMO in preparation for coiled tubing cleanout and perforating
TAB, 08/22/00, v3
('
DRILLING FLUID PROGRAM, PRESSURE CALCULATIONS, &
DRILLING AREA RISKS
KRU 1 D-36
Drillina Fluid Properties:
Density
PV
YP
Viscosity
Initial Gel
10 Minute Gel
APl Filtrate
pH
% Solids
Spud to 9-5/8"
Surface Casing
8.5-10.2
16-26
25-50
100-200'
10-20
15-40
7-15
9.5-10
6-8%
Drill out to 7"
Intermediate Casing
8.8-9.8
5-25
8-25
35-55
3-10
10-15
5-15
8.5-9.5
6-8%
Drill Out
to TD
11.3-13.0
25-35
20-30
50-65
4-7
4-8
8-10
8.0-8.5
4-7%
Drillin,q Fluid System - Nabors 16E
3 - Derrick Shale Shakers
Desander
Desilter
Mud Cleaner
Centrifuge
Degasser
Pit Level Indicator (w/visual and audible alarms)
Trip Tank
Fluid Flow Sensor
Fluid Agitators
*Spud mud should be adjusted to a FV between 180-250 sec/qt to drill gravel beds
Notes:
Drilling fluid practices will be in accordance with the appropriate regulations stated in 20 AAC 25.033.
Maximum Anticipated Surface Pressure:
Three possibilities exist for the possible maximum anticipated surface pressure (MASP) seen by the surface
casing string along the 1 D-36 well path.
1)
MASP can be calculated using an expected leak-off of 13.7 ppg EMW (0.71 psi/ft) and a gas gradient of 0.11
psi/ff. This shows that formation breakdown would occur at a surface pressure of 2536 psi. The leak off
EMW was chosen based on an open hole LOT on well, 1 D-38, taken to 13.5 ppg at 4279' TVD (0.70 psi/ft).
MASP = (4299 ft)(0.70 - 0.11)
= 2536 psi
2)
3)
If the well is drilled out of surface casing to TD as planned and surface shoe LOT is higher than expected,
the MASP can be calculated based on a reservoir pressure of 3550 psi at 6427' TVD (0.56 psi/fi) and a gas
gradient of 0.11 psi/ff. In this case, MASP would occur at 2892 psi.
MASP = (6427 ft)(0.56 - 0.11 )
= 2892 psi
Some prior EBA and GSA wells in this area have experienced gas charged sands in the D-shale as a result
of historic Gas Storage Area injection. These sands are located above the Kuparuk reservoir and are
expected to occur at +/- 6417' TVD along the proposed well path in the 1 D-36 target area. There is a strong
possibility that gas charging will be encountered in this well and if this occurs, MASP would be based on a
12.5 ppg equivalent pressure (0.65 psi/fi). Based on this pressure gradient and a gas gradient of 0.11 psi/fi,
MASP would occur at 3465 psi.
MASP = (6417 ft)(0.65 - 0.11 )
= 3465 psi
Therefore, based on the possibility of a MASP greater than 3000 psi, Phillips Alaska, Inc. will test the BOP
equipment to 5000 psi prior to drilling out of surface casing.
In the event that the well must be topset above the Kuparuk, the maximum anticipated pressure for the
intermediate casing string would continue to be the pressure exerted by the gas charged D-shale sands at the
surface and would remain at 3465 psi as calculated previously.
Therefore, based on the possibility of a MASP greater than 3000 psi, Phillips Alaska, Inc. will test the BOP
equipment to 5000 psi prior to drilling out of intermediate casing if an intermediate string is needed.
Based the anticipated pressures shown, a maximum mud weight requirement for this well is established based
on the potential charging of the D-shale sands. Assuming a 150 psi overbalance is required to safely drill and
trip in this formation, then a required mud weight of 13.0 ppg can be predicted as the maximum mud weight
needed to safely conduct rig operations, assuming a TVD of 6417'.
MW = [(6417 ft)(0.65)+150]/6417/.052
= 13.0 ppg
In order to allow for a long string design, the minimum LOT in the Mid-HRZ or surface casing shoe must be
greater than ECD (equivalent circulating density) with a 13.0 ppg drilling fluid as modeled or as measured with
the Pressure While Drilling (PWD) sub, plus adequate safety margin.
Well Proximity Risks:
The nearest existing well to 1 D-36 is 1 D-38. As designed, the minimum distance between the two wells would
be 30.0' at 120' MD.
Drilling Area Risks:
Risks in the 1 D-36 drilling area include surface interval hydrates, lost circulation, and potential borehole instability
in and below the permafrost zone as well as through the intermediate shales. Hydrate risks will be minimized by
the use of sufficient mud weights to allow for tripping of pipe, controlled drilling rates, and rheological properties
which safely appropriate gas breakout. Lost circulation will be addressed with lost circulation material (LCM),
reduced circulating rates, and reduced mud weights as needed. Shale instability will be controlled primarily with
the planned fluid densities. Additional risk exists with unpredictable charging of the D-shale sands during historic
gas injection. These gas pressure risks are mitigated with mid-HRZ LOT's and a top set option above the D-
shale based upon those results. ~"~, ~=~,~ ~,~.= ~, .., ~.~.
Annular Pumping Operations:
Incidental fluids developed from drilling operations will be either injected into an approved annulus on the same
pad or hauled to the nearest permitted Class II disposal well. (Note that cement rinseate will not be iniected
down the dedicated disposal well but will be recycled or held for an open annulus.) The open annulus will be left
with a non-freezing fluid during any extended shut down (>4 hr) in pumping operations. The 1D-36
surface/production casing annulus will be filled with diesel after setting production casing and prior to the drilling
rig moving off of the well. If isolation is required per regulations over significant hydrocarbons, then sufficient
cement volume will be pumped during the production cement job to cover those formations.
At the end of drilling operations, a request for 1D-36 to be permitted for annular pumping of fluids occurring as a
result of future drilling operations on 1D pad, per regulation 20 AAC 25.080, will be submitted. Any zones
containing significant hydrocarbons will be isolated prior to initiating annular pumping. There will be no USDW's
open below the shoe or potable/industrial water wells within one mile of the receiving zone. Reference the
enclosed directional drilling plan for other formation markers in this well.
Surface casing will be set in the Cretaceous shales below the base of the West Sak Sands. These 300-500'
thick shales are part of the Colville Group and are known to provide vertical barriers to fluid flow. The surface
casing shoe will be set a minimum of 200' vertically below the base of the West Sak into the heart of the shales.
The surface and production casing strings exposed to the annular pumping operations have sufficient strength
by using the 85% collapse and burst ratings listed in the following table:
Wt Connection 85% of 85% of
OD (ppf) Grade Range Type Collapse Collapse Burst Burst
9-5/8" 40 L-80 3 BTC 3,090 psi NA 5,750 psi 4,888 psi
7" 26 L-80 3 LTC-Mod 5,410 psi 4,599 psi 7,240 psi 6,154 psi
3Y2"* 9.3 L-80 2 8rd EUE Mod 10,530 psi 8,951 psi 10,160 psi 8,636 psi
*ifneeded
Fluids to be disposed of in the annulus will be limited to drilling wastes associated with drilling a well as defined in
20 AAC 25.080 (h).
KRU 1D-36 Prod ,. r
Proposed Completion Schematic
Topset Base Case
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
20" 91.5# H-40
@ +/- 120' MD
Depths are
based on
Nabors 16E
RKB
Surface csg.
9-5/8" 40.0# L-80 BTCM
(+/- 7052' MD / 4299' TVD)
3-1/2" FMC Gen V Tubing Hanger, 3-1/2" L-80 EUE8RD pin down
3-1/2" 9.3# L-80 EUE8RD Spaceout Pups as Required
3-1/2" 9.3# L-80 EUE8RD Tubing to Surface
3-1/2" Camco 'DS' nipple w/2.875" No-Go Profile. 3-1/2" x 6' L-80 pup
installed above. 3-1/2" x 6' L-80 flow coupling installed below, EUE8RD
set at +/- 500' MD
3-1/2" 9.3# L-80 EUE8RD tubing to landing nipple
3-1/2" x 1-1/2" Camco 'MMG' Mandrels w/DV's and RK latch's (Max. OD 5.968",
ID 2.92"), 6' L-80 handling pups installed above and below on GLM. Spaced out w/
3-1/2" 9.3# L-80 EUE8RD tubing as follows:
GLM # TVD-RKB MD-RKB
GLM Numbers and Spacing To Be Determined
Intermediate csg.
7" 26.0# L-80 BTCM
(+/- 11069' MD / 6259' TVD)
Future Perforations
Production Liner
3-1/2" 9.3# L-80 SLHT
(+/- 11624' MD / 6530' TVD)
3-1/2" x 1-1/2" Camco 'MMG' mandrel w/shear valve and latch (Max. OD 5.968",
ID 2.92"), pinned for 3000 psi shear (casing to tubing differential), 6' L-80 handling
pups installed above and below.
1 jt 3-1/2" 9.3# L-80 EUE8RD tubing
3-1/2" Camco 'DS' nipple w/2.813" No-Go profile. 3-1/2" x 6' L-80 EUE8RD
handling pups installed above and below
1 jt 3-1/2" 9.3# L-80 EUE8RD tubing
5.125" x 3" Baker Iocator sub
4-1/2" Baker GBH-22 casing seal assembly w/12' stroke, 3-1/2" L-80
EUE8RD box up
Liner Assembly (run on drillpipe), set @ +/- 10919' MD
Baker 7" x 5" 'ZXP' Liner Top Isolation Packer with HR profile
Baker 7" x 5" 'Flexlock' Liner Hanger
Baker 20' Seal Bore Extension
XO Sub, 5" Stub Acme box x 3-1/2" SLHT pin
1 jt 3-1/2" 9.3# L-80 SLHT tubing
3-1/2" Halliburton 'XN' nipple w/2.75" No-Go Profile, 3-1/2" SLHT box x pin
3-1/2" 9.3# L-80 SLHT liner as needed
3-1/2" Baker Landing Collar
1 jt 3-1/2" 9.3# L-80 SLHT tubing
3-1/2" Baker Float Collar
1 jt 3-1/2" 9.3# L-80 SLHT tubing
3-1/2" Baker Float Shoe
£
KRU 1D-36 Prodd,.dr
Proposed Completion Schematic
Long String Contingency Case
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
20" 91.5# H-40
@ +/- 120' MD
Depths are
based on
Nabors 16E
RKB
Surface csg.
9-5/8" 40.0# L-80 BTCM
(+/- 7052' MD / 4299' TVD)
Future Perforations
Production csg.
7" 26.0# L-80 BTCM
(+/- 11624' MD / 6530' TVD)
3-1/2" FMC Gen V Tubing Hanger, 3-1/2" L-80 EUE8RD pin down
3-1/2" 9.3# L-80 EUE8RD Spaceout Pups as Required
3-1/2" 9.3# L-80 EUE8RD Tubing to Surface
3-1/2" Camco 'DS' nipple w/2.875" No-Go Profile. 3-1/2" x 6' L-80 pup installed
above. 3-1/2" x 6' L-80 flow coupling installed below, EUE8RD
set at +/- 500' MD
3-1/2" 9.3# L-80 EUE8RD tubing to landing nipple
GLM # TVD-RKB MD-RKB
GLM Numbers and Spacing To Be Determined
3-1/2" x 1-1/2" Camco 'MMG' Mandrel w/shear valve and latch (Max. OD 5.968",
ID 2.92"), pinned for 3000 psi shear (casing to tubing differential), 6' L-80 handling
pups installed above and below.
1 jt 3-1/2" 9.3# L-80 EUE8RD tubing
3-1/2" Camco 'DS' nipple w/2.813" No-Go profile. 3-1/2" x 6' L-80 EUE8RD
handling pups installed above and below
1 jt 3-1/2" 9.3# L-80 EUE8RD tubing
7" x 3-1/2" Baker 'SAB-3' permanent packer w/KBH-22 seal assembly, 3-1/2" x 6'
L-80 EUE8RD handling pup on top
1 jt 3-1/2" 9.3# L-80 EUE8RD tubing
3-1/2" Camco 'D' nipple w/2.75" No-Go Profile. 3-1/2" x 6' L-80 EUE8RD handling
pups installed above and below
3-1/2" x 10' L-80 EUE8RD pup joint
3-1/2" Baker Shear Out Ball Seat Sub. Tubing tail +/- 50' above top of proposed
perforations
TAB, 8/21/00, v3
AUG 2'?
Phillips Alaska, Inc.
Structure: Pad 1D Well: :56
Field: Kuparuk River Unit Looation: North Slope, Alaska
PROFILE COMMENT DATA
Point
KOP
Beg. 5/100 Bid
Beg. 4/100 Bid
BId/Trn 5/100
Bose Permafrost
Drop/Turn
EOC
Begin 'Right Turn
EOC
Top West Sok
Bose West Sok
9 5/8 Casing Pt
Begin Left Turn
C80
EOC
C50
C40
C50
C20
7 Casing Pt
K- 1 Marker
Top Kuporuk D
Target-Top C4
Top C5
Top C2
Top Cl
Top B Shale
TD - Csg Pt
MD
250.00
550.00
600.00
1650.00
1869.87
2000.00
4219.56
5450.00
5681.00
5717.51
6645.17
7051.85
7500.00
7519.38
7642.45
9504.00
9957.18
10605.12
10902.50
11068.60
11228.55
11592.59
11415.08
11458.21
11476.67
11515.65
11521.78
11624.51
Inc Dir TVD North
0.00 0.00 250.00 0.00
1.50 90.00 549.99 0.00
9.00 90.00 598.76 0.00
51.00 90.00 1487.87 0.00
57.04 95.27 1617.00 -5.27
60.66 95.00 1684.51 - 15,55
60,70 175,05 2912,79 -1194,41
60,70 175,05 5514,95 -2259,56
60,70 181,00 5628,15 -2460,49
60.70 1 81.00 5646.00 -2492.35
60.70 1 81,00 4099,00 -5299.44
60.70 181,00 4299,00 -5655,79
60.70 .1 81.00 4420.44 -5872.1 6
60,65 175,45 4528,00 -4065,00
60,81 1 69,22 4588.18 -41 69,09
60,81 1 69,22 5496,00 -5765,65
60,81 169,22 5717,00 -6154,29
60,81 1 69.22 6052,00 -6708,26
60,81 1 69,22 6178,00 - 6965,02
60,81 1 69,22 6259.00 -7107.47
60.81 1 69.22 6557.00 -7244.65
60.81 1 69.22 6417,00 -7585,54
60,81 1 69,22 6426.99 -7402.91
60.81 1 69.22 · 6449.00 -7441.62
60.81 1 69,22 6458.00 -7457.45
60,81 1 69,22. 6477,00 -7490,86
60.81 169.22 6480.00 -7496,14
60.81 1 69,22 6550,00 -7584,07
East
0,00
1,51
24,17
557,49
715,22
826.27
2047,77
2177,57
2188,01
2187.46
2175,57
2167,15
2163.37
2172,62
2188,79
2492.70
2566,68
2672.14
2721,01
2748.15
2774.24
2801,02
2804.57
2811.73
2814.75
2821.11
2822,11
2858.85
V. Sect
0.00
0.46
8.56
190.41
258.30
505.18
1842.38
2884.44
5076.04
5105.61
5855.4O
4186.45
4587.45
4569.1 7
4674.10
6274.77
6664.45
7219.84
7477.27
7620.08
7757.61
7898.67
791 6.28
7955.09
7970.96
8004.46
8009.75
8097.91
Deg/1C
0.00
1.50
3.00
4.00
3.00
3,00
5.00
0,00
3.00
0.00
0.00
0.00
0.00
3.00,-,.
5.0
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0 ~ RKB Elevation: 106'
450
900
1550
1600
2250
t" 2700
--I--
5150
0
~_ 5600
Q) 4050
I 450o
V
4950
5400
5850
6500
6750
KOP
0.75
3.00' Beg. 3/100 Bid
6.00
Beg. 4/100 Bid
16.00 DLS: 4.00 dog per 100 ft
20.00
28.00 DLS: 4.00 dog per 100 ft
36.00
44.00
52.37 BId/Trn 5/100
57.68 Base Permafrost
59.59 Drop/Turn
57.71
56.19 DLS: 5.00 dog per 100 ft
55.07
54.38
54.15
54.34
55.00
56.09
57.57
59.45
EOC
Phillips Alaska, Inc.
Struature: Pad 1D Well: 56
Field: Kuparuk River Unit Loaaflon: North Slope, Alaska
Crmoled by r~xBe For: T Brockway
I~te plotted: 24-Aug-2000
Plot RgfEmn~e rn 38 Ver~ ~4.
~in~w om ~ f~ r~er~ ~ot ~
60.66 Begin Right Turn
EOC
Top West Sok
Bose West Sok
9 5/8 Casing Pt
60.65 Begin Left Turn
60.74 C80
EOC
159.25 AZIMUTH
7916' (TO TARGET)
***Plane of Proposale**
C50
C40
7 Casing Pt
Target-Top C4
C30
C20
K-1 Marker
Top Kuporuk D Top C5
Top~C2
/ap C1
Top B Shale
i i i i i i ! i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i · i i
0 450 900 1550 1800 2250 2700 ;51,50 3600 4050 4500 4950 5400 5850 6500 6750 7200 7650 81 O0 8550 9000 9450 9900
Vertical Section (feet) ->
Azimuth 159.25 with referen=e 0.00 N, 0,00 E from slot #56
o
SURFACE LOCATION:
477' FNL, 420' FEL
SEC. 23, T11N, RIOE
Phillips Alaska, Inc.
Structure: Pad 1D Well: 36
Field: Kuparuk River Unit Loaafion : North Slope, Alaska
East (feet) ->
400 800 1200 1600 2000 2400 2800 5200 5600
I I I I I I I I I I I I I I I I I I
159.25 AZIMUTH
7916' (TO TARGET)
**.Plane of Proposal***
ITARGET LOCATION:
2601' FNL, 2579' FWL
SEC. 25, T11N, RIOE
TD LOCATION:
2498' FSL, 2413' FWL
SEC. 25, T11N, RIOE
Begin Right Tum
EOC
Top West Sak
Base West Sak
J g 5/8 Cosing Pt
Begin Left Turn
C80
, EOC
50
ii, C20
7 Casing Pt ~
-/..-1~'-~ K-1 Marker
.... / ~ ~ Top Kuparuk D
Torge~-,a. ~4( t. ) Top C3
\ I~Ik / Top C2
· . a~/' Top C1
5-1/2 bner Top B Shale
TD - Csg Pt
o
4oo
8oo
12oo
16oo
2000
24o0
2800
3200
5600
4ooo
44o0
4800
5200
5600
6000
6400
6800
7200
7600
8000
For: T Brockway
East (feet) ->
?
iPhillips Alaska, lac.
i Structure : P(ld 1D We 36
140 160 180 200 220
IX. 700 800 900 ~ ~ 1 ~i~C~%2~_.. ~ 1400 1100
1300 1400 1500
0
V
o~ ~ooJ~ /~;oo .... - ~w°°
180
\
220 \
\
\
180
- 200
- 220
240
260
\ }~ 1900 ,
6oD.8o ~oo ....... ;8 40' ~;o ' 2~o~°°
East (feet) ->
8O
100
120
V
120
240
200
160
--°4
U~
V 80 '"'%. ' %~1900
Easf (feel) ->
150 200 240 280 520 360 400 440 4~0 520 560 600 640 680 720 760 800 840 880 920
......... ~oo
........ 2bo~
East (feel) ->
.~o ~o ~o ~oo ~.o ~o do
960
I 24O
200
240
28O
95O
80 V
V
Structure : Pad ID Well : .36
Field ' Kuporuk River Unit Locotion ' North Slope Alosko
East (feet) ->
500 600 700 80D 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2!00 2200 2300 2400 2500 2800
20O 200
i 9020/00
..... ._ 2100 100
o ~ Oo ...... ..... 5300 ...... o
-'N ~ 2._3_00 --- ..... 2500
,oo~ '/~- ...'2;-
~ N 1900
q- - ~_~,
X"X Nx2100~, ~ ........... ~00 3500~~an<~x5900 4100 ~---~00
~'x%2900
~X250°
2oo
0
300
400
V
PH~LLIPS
600 ~x, 3300 X 600
~30o
Ees+ (feet) ->
Phillips Alaska, Inc,
East (feet) ->
800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 5200 3400 5600
\
27oo~
0
O0
2000
2200 4
5000
JE k 5500
3200
\ i ~ 6soo
800 1000 1200 1400 1600 1800 2000
3100
~oo
%?500
i 4~o'~ ~ .~70o
~5700 x\
2200 2400 2600
East ('feet)
% 38oo
800
1000
1200
-1600
22OO
2400
2600
2800
5000
5200
4200
2800 5000 3200 3400 5600
4000
5600
3900
!~oo
4480
4800
5200
5800
5000
6400
5800
720O
7600
8000
8800
9200
';Phillips Alaska, Inc.i
~ Structure : Pod 19 Welt : 36 '
4500
4500
4700
~¢900
\
East (feet) ->
5200 8600 z;O00 44-00 4800 5200
3500 x x, %"e 4700 ~ 2800
I ~% 3900
~4700
4900
?~ 55oo
5900
61oo
5300
~,365oo
\
\
~,4300
%~oo
· ~, 4500 4000
\ 6800
760O
8000
8400
4400
4800
5200
5600
6000
6400
,- 9200
800 1200 1600 2000 2400 2800 5200 3600 4000 4400 4800 5200
East (feet) ->
Phillips Alaska, Inc.
Structure : Pod 10 Well : 36
Loootio,: .o~h
TRUE NORTH
5O
300
290<
4O
5O
6O
7O
280
8O
270
26O
0
90
100
25O
220
210
130
110
120
140
Normal Pione Travelling Cylinder Feet
All depths shown are Measured depths on Reference Well
Phillips Alaska, Inc.
Pad 1D
36
slot #36
Kuparuk River Unit
North S1 ope, A1 aska
PROPOSAL LISTING
INCLUDING POSITION UNCERTAINTIES
Baker Hughes INTEQ
Your ref: 36 Version
Our ref : prop4021
License :
Date printed : 24-Aug-2000
Date created : lO-Aug-2000
Last revised : 24-Aug-2000
Field is centred on n70 16 18.576,w150 5 56.536
Structure is centred on n70 18 1.316,w149 30 18.908
Slot location is n70 17 56.625,w14g 30 31.152
Slot Grid coordinates are N 5959189.177, E 560670.815
Slot local coordinates are 477.00 S 420.00 W
Projection type: alaska - Zone 4, Spheroid: Clarke - 1866
Reference North is True North
Phillips Alaska. Inc. ~::.i:-'.~'~."~.i~:c,L~e~.k.:C..~.~-:~-:-:~.:,.-.:.:~..~.P..ROPOSAL LISTING Page 1
Pad 1D.36 ~', .... h..-~ ...... Your ref : 36 Version #4
Kuparuk River Unit,North Slope, Alaska ~,"~ ~i? Last revised : 24-Aug-2000
Measured Inclin. Azimuth True Vert R E C T A N G U L A R Vert
Depth Degrees Degrees Depth C OORD I NATES Sect
Ellipse Semi Axes Minor
Major Minor Vert. Azi.
0.00 0.00 0.00 0.00 0.00 N 0.00 E 0.00 0.00 0.00 0.00 N/A
250.00 0.00 0.00 250.00 0.00 N 0.00 E 0.00 1.19 1.19 0.65 N/A
300.00 0.75 90.00 300.00 0.00 N 0.33 E 0.12 1.50 1.43 0.77 0.00
350.00 1.50 90.00 349.99 O.OO N 1.31E 0.46 1.90 1.67 0.90 0.00
400.00 3.00 90.00 399.95 0.00 N 3.27 E 1.16 2.34 1.91 1.03 0.00
500.00 6.00 90.00 499.63 0.00 N 11.12 E 3.94 3.28 2.39 1.30 0.00
600.00 9.00 90.00 598.76 0.00 N 24.17 E 8.56 4.25 2.89 1.58 0.00
675.00 12.00 90.00 672.50 0.00 N 37.83 E 13.40 4.98 3.27 1.80 0.00
775.00 16.00 90.00 769.51 0.00 N 62.02 E 21.97 5.95 3.82 2.13 0.00
875.00 20.00 90.00 864.59 0.00 N 92.92 E 32.92 6.91 4.43 2.51 0.00
975.00 24.00 90.00 957.29 0.00 N 130.37 E 46.18 7.84 5.13 2.94 0.00
1075.00 28.00 90.00 1047.15 0.00 N 174.20 E 61.71 8.76 5.97 3.42 0.00
1175.00 32.00 gO.O0 1133.74 0.00 N 224.19 E 79.42 9.64 6.99 3.95 0.00
1275.00 36.00 90.00 1216.63 0.00 N 280.10 E 99.22 10.50 8.26 4.55 0.00
1375.00 40.00 90.00 1295.41 0.00 N 341.65 E 121.03 11.31 9.82 5.20 0.00
1475.00 44.00 90.00 1369.71 0.00 N 408.55 E 144.73 12.09 11.75 5.90 0.00
1575.00 48.00 90.00 1439.16 0.00 N 480.47 E 170.21 14.12 12.83 6.66 90.00
1650.00 51.00 90.00 1487.87 0.00 N 537.49 E 190.41 16.20 13.35 7.26 90.00
1700.00 52.37 90.79 1518.87 0.27 S' 576.72 E 204.56 17.70 13.70 7.67 90.14
1800.00 55.11 92.29 1578.01 2.45 S 657.31E 235.15 21.15 14.35 8.51 90.70
1869.87 57.04 93.27 1617.00 5.27 S 715.22 E 258.30 23.94 14.78 9.12 91.14
1900.00 57.88 93.68 1633.21 6.81S 740.57 E 268.72 25.15 14.96 9.39 91.34
2000.00 60.66 95.00 1684.31 13.33 S 826.27 E 305.18 29.77 15.54 10.29 92.04
2100.00 59.59 98.23 1734.13 23.31 S 912.38 E 345.01 34.20 16.13 11.19 92.98
2200.00 58.60 101.54 1785.50 38.03 S 996.90 E 388.71 38.43 16.72 12.08 94.05
2300.00 57.71 104.91 1838.27 57.44 S 1079.57 E 436.16 42.41 17.31 12.96 95.19
2400.00 56.90 108.34 1892.30 81.50 S 1160.19 E 487.22 46.15 17.91 13.83 96.36
2500.00 56.19 111.84 1947.45 110.14 S 1238.53 E 541.75 49.64 18.51 14.69 97.55
2600.00 55.58 115.38 2003.55 143.28 S 1314.37 E 599.61 52.88 19.10 15.54 98.74
2700.00 55.07 118.98 2060.46 180.83 S 1387.51 E 660.63 55.88 19.69 16.39 99.92
2800.00 54.67 122.62 2118.02 222.69 S 1457.74 E 724.66 58.64 20.28 17.24 101.09
2900.00 54.38 126.28 2176.07 268.74S 1524.88 E 791.50 61.17 20.87 18.08 102.24
3000.00 54.20 129.97 2234.45 318.86 S 1588.73 E 860.99 63.49 21.44 18.92 103.36
3100.00 54.13 133.67 2293.01 372~90 S 1649.13 E 932.93 65.59 22.01 19.76 104.45
3200.00 54.18 137.38 2351.58 430.73 S 1705.90 E 1007.11 67.50 22.58 20.60 105.50
3300.00 54.34 141.07 2410.00 492.17 S 1758.90 E 1083.35 69.23 23.13 21.44 106.52
3400.00 54.62 144.74 2468.12 557.08 S 1807.98 E 1161.43 70.77 23.67 22.29 107.49
3500.00 55.00 148.38 2525.76 625.25 S 1852.99 E 1241.13 72.15 24.21 23.14 108.42
3600.00 55.49 151.98 2582.78 696.52 S 1893.83 E 1322.24 73.37 24.74 23.99 109.29
3700.00 56.09 155.54 2639.02 770.68 S 1930.37 E 1404.54 74.44 25.26 24.85 110.11
3800.00 56.78 159.04 2694.32 847.53 S 1962.52 E 1487.79 75.37 25.78 25.71 110.86
3900.00 57.57 162.49 2748.54 926.85 S 1990.19 E 1571.78 76.18 26.30 26.58 111.56
4000.00 58.46 165.87 2801.52 1008.44 S 2013.30 E 1656.26 76.86 26.81 27.46 112.18
4100.00 59.43 169.18 2853.11 1092.07 S 2031.80 E 1741.02 77.43 27.33 28.35 112.73
4200.00 60.48 172.43 2903.19 1177.51S 2045.62 E 1825.81 77.89 27.86 29.25 113.20
4219.56 60.70 173.05 2912.79 1194.41 S 2047.77 E 1842.38 77.98 27.97 29.42 113.29
4500.00 60.70 173.05 3050.03 1437.18 S 2077.35 E 2079.88 79.29 29.54 31.95 114.57
5000.00 60.70 173.05 3294.72 1870.01 S 2130.10 E 2503.33 81.78 32.58 36.45 116.91
5450.00 60.70 173.05 3514.95 2259.56 S 2177.57 E 2884.44 84.22 35.47 40.50 119.06
5500.00 60.66 174.77 3539.43 2302.90 S 2182.20 E 2926.61 84.47 35.80 40.95 119.28
All data is in feet unless otherwise stated.
Coordinates from slot#36 and TVD from RKB (Nabors 16E) (106.00 Ft above mean sea level).
Bottom hole distance is 8097.97 on azimuth 159.48 degrees from wellhead.
Vertical section is from wellhead on azimuth 159.25 degrees.
Calculation uses the minimum curvature method.
Presented by Baker Hughes INTEQ
Phillips Alaska, Inc.
Pad 1D,36
Kuparuk River Unit,North Slope, Alaska
Measured Inclin. Azimuth True Vert R E C T A
Depth Degrees Degrees Depth C 0 0 R D
5600.00 60.65 178.21 3588.45 2389.89 S
5681.00 60.70 181.00 3628.13 2460.49 S
5717.51 60.70 181.00 3646.00 2492.33 S
6000.00 60.70 181.00 3784.25 2738.64 S
6500.00 60.70 181.00 4028.94 3174.61S
6643.17 60.70 181.00 4099.00 3299.44 S
7000.00 60.70 181.00 4273.63 3610.58 S
7051.85 60.70 181.00 4299.00 3655.79 S
7300.00 60.70 181.00 4420.44 3872.16 S
7400.00 60.63 177.56 4469.45 3959.31S
7500.00 60.64 174.12 4518.50 4046.21S
7519.38 60.65 173.45 4528.00 4063.00 S
7600.00 60.74 170.68 4567.46 4132.62 S
7642.43 60.81 169.22 4588.18 4169.09 S
8000.00 60.81 169.22 4762.55 4475.75 S
8500.00 60.81 169.22 5006.38 4904.56 S
9000.00 60.81 169.22 5250.22 5333.38 S
9500.00 60.81 169.22 5494.05 5762.19 S
9504.00 60.81 169.22 5496.00 5765.63 S
9957.18 60.81 169.22 5717.00 6154.29 S
10000.00 60.81 169.22 5737.88 6191.01S
10500.00 60.81 169.22 5981.71 6619.82 S
10603.12 60.81 169.22 6032.00 6708.26 S
10902.50 60.81 169.22 6178.00 6965.02 S
11000.00 60.81 169.22 6225.55 7048.64 S
11068.60 60.81 169.22 6259.00 7107.47 S
11228.55 60.81 169.22 6337.00 7244.65 S
11392.59 60.81 169.22 6417.00 7385.34 S
11413.08 60.81 169.22 6426.99 7402.91S
11413.10 60.81 169.22 6427.00 7402.93 S
11458.21 60.81 169.22 6449.00 7441.62 S
11476.67 60.81 169.22 6458.00 7457.45 S
11500.00 60.81 169.22 6469.38 7477.46 S
11515.63 60.81 169.22 6477.00 7490.86 S
11521.78 60.81 169.22 6480.00 7496.14 S
11624.31 60.81 169.22 6530.00 7584.07 S
PROPOSAL LISTING Page 2
Your ref : 36 VersionS/4
Last revised : 24-Aug-2000
NGULAR
INATES
Vert Ellipse Semi Axes Minor
Sect Major Minor Vert. Azi.
2187.53 E 3009.84 84.87 36.49 41.85 119.63
2188.01E 3076.04 85.16 37.06 42.58 119.89
2187.46 E 3105.61 85.30 37.32 42.91 120.02
2183.16 E 3334.43 86.36 39.36 45.45 120.98
2175.55 E 3739.43 88.37 43.06 49.94 122.83
2173.37 E 3855.40 89.00 44.14 51.23 123.40
2167.94 E 4144.43 90.57 46.84 54.44 124.83
2167.15 E 4186.43 90.82 47.23 54.90 125.05
2163.37 E 4387.43 91.98 49.11 57.13 126.11
2164.47 E 4469.32 92.53 49.85 58.03 126.57
2170.79 E 4552.82 93.21 50.53 58.93 127.11
2172.62 E 4569.17 93.37 50.66 59.10 127.22
2182.32 E 4637.72 94.03 51.17 59.83 127.69
2188.79 E 4674.10 94.41 51.44 60.21 127.95
2247.16 E 4981.56 97.68 53.61 63.43 130.01
2328.79 E 5411.48 102.41 56.56 67.92 132.70
2410.42 E 5841.40 107.34 59.43 72.42 135.15
2492.04 E 6271.33 112.41 62.22 76.92 137.38
2492.70 E 6274.77 112.46 62.25 76.95 137.40
2566.68 E 6664.43 117.18 64.73 81.03 139.22
2573.67 E 6701.25 117.63 64.96 81.41 139.40
2655.30 E 7131.17 122.96 67.65 85.91 141.22
2672.14 E 7219.84 124.08 68.20 86.84 141.56
2721.01E 7477.27 127.33 69.79 89.53 142.54
2736.93 E 7561.10 128.38 70.31 90.41 142.86
2748.13 E 7620.08 129.14 70.67 91.02 143.07
2774.24 E 7757.61 130.90 71.51 92.46 143.55
2801.02 E 7898.67 132.71 72.37 93.94 144.04
2804.37 E 7916.28 132.93 72.48 94.12 144.10
2804.37 E 7916.30 132.93 72.48 94.12 144.10
2811.73 E 7955.09 133.43 72.72 94.53 144.23
2814.75 E 7970.96 133.64 72.81 94.69 144.28
2818.56 E 7991.02 133.90 72.94 94.90 144.35
2821.11E 8004.46 134.07 73.02 95.04 144.39
2822.11 E 8009.75 134.14 73.05 95.10 144.41
2838.85 E 8097.91 135.28 73.59 96.02 144.69
All data is in feet unless otherwise stated.
Coordinates from slot #36 and TVD from RKB (Nabors 16E) (106.00 Ft above mean sea level).
Bottom hole distance is 8097.97 on azimuth 15g.48 degrees from wellhead.
Vertical section is from wellhead on azimuth 159.25 degrees.
Calculation uses the minimum curvature method.
Presented by Baker Hughes INTEQ
Phillips Alaska, Inc.
Pad 1D,36
Kuparuk River Unit,North Slope, Alaska
PROPOSAL LISTING Page 3
Your ref : 36 Version#4
Last revised : 24-Aug-2000
POSITION UNCERTAINTY SUMMARY
Depth Position Uncertainty
From To Survey Tool Error Model Major Minor Vert.
0 11624 MWD + IFR (Alaska) - Corrected Dat User specified 135.28 73.59 96.02
1. Ellipse dimensions are half axis.
2. Casing dimensions are not included.
3. Ellipses are calculated on 2.58 standard deviations.
4. Uncertainty calculations start at drill depth zero.
5. Surface position uncertainty is not included.
6. Where two surveys are tied together the errors of one are considered
to have a systematic relationship to the corresponding errors of the other.
7. Detailed description of the INTEQ error models can be found
in the Ec*Trak manual.
Comments in wellpath
MD TVD Rectangular Coords. Comment
250.00 250.00 0.00 N 0.00 E KOP
350.00 349.99 0.00 N 1.31E Beg. 3/100 Bld
600.00 598.76 0.00 N 24.17 E Beg. 4/100 Bld
1650.00 1487.87 0.00 N 537.49 E Bld/Trn 3/100
1869.87 1617.00 5.27 S 715.22 E Base Permafrost
2000.00 1684.31 13.33 S 826.27 E Drop/Turn
4219.56 2912.79 1194.41S 2047.77 EEOC
5450.00 3514.95 2259.56 S 2177.57 E Begin Right Turn
5681.00 3628.13 2460.49 S 2188.01E EOC
5717.51 3646.00 2492.33 S 2187.46 E Top West Sak
6643.17 4099.00 3299.44 S 2173.37 E Base West Sak
7051.85 4299.00 3655.79 S 2167.15 E g 5/8" Casing Pt
7300.00 4420.44 3872.16 S 2163.37 E Begin Left Turn
7519.38 4528.00 4063.00 S 2172.62 E C80
7642.43 4588.18 4169.09 S 2188.79 E EOC
9504.00 5496.00 '5765.63 S 2492.70 E C50
9957.18 5717.00 6154.29 S 2566.68 E C40
10603.12 6032.00 6708.26 S 2672.14 E C30
10902.50 6178.00 6965.02 S 2721.01E C20
11068.60 6259.00 7107.47 S 2748.13 E 7" Casing Pt
11228.55 6337.00 7244.65 S 2774.24 E K-1 Marker
11392.59 6417.00 7385.34 S 2801.02 E Top Kuparuk D
11413.08 6426.99 7402.91S 2804.37 E Target-Top C4
11413.10 6427.00 7402.93 S 2804.37 E 1D-36 Tgt Rvsd 15-Aug-O0
11458.21 6449.00 7441.62 S 2811.73 E Top C3
11476.67 6458.00 7457.45 S 2814.75 E Top C2
11515.63 6477.00 7490.86 S 2821.11E Top C1
11521.78 6480.00 7496.14 S 2822.11E Top B Shale
11624.31 6530.00 7584.07 S 2838.85 ETD - Csg Pt
Casing positions in string 'A'
Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing
0.00 0.00 O.OON O.OOE 11624.30 6530.00 7584.06S 2838.85E 3-1/2" Liner
0.00 0.00 O.OON O.OOE 11068.60 6259.00 7107.47S 2748.13E 7" Casing
0.00 0.00 O.OON O.OOE 7051.85 4299.00 3655.79S 2167.15E g 5/8" Casing
Targets associated with this wellpath
Target name Geographic Location T.V.D. Rectangular Coordinates Revised
1D-36 Tgt Rvsd 15-Au 563535.000,5951810.000,0.0000 6427.00 7402.93S 2804.37E 31-Mar-2000
Phillips Alaska, Inc.
Pad 1D
36
slot #36
Kuparuk River Unit
North Slope, Alaska
SUMMARY CLEARANCE
Baker Hughes INTEQ
REPORT
Your ref : 36 Vets#4
Our ref : prop4021
License :
Date printed : 23-Aug-2000
Date created : 10-Aug-2000
Last revised : 23-Aug-2000
Field is centred on n70 16 18.576,w150 5 56.536
Structure is centred on n70 18 1.316,w149 30 18.908
Slot location is n70 17 56.625,w149 30 31.152
Slot Grid coordinates are N 5959189.177, E 560670.815
Slot local coordinates are 477.00 S 420.00 W
Projection type: alaska - Zone 4, Spheroid: Clarke - 1866
Reference North is True North
Object wellpath
PMSS <0-12044'>,,30,Pad 1D
42 Version 0.a,,42,Pad 1D
32 Version 0.a,,32,Pad 1D
PMSS <377 - 6224'>,,134,Pad 1D
16 Wp2 Sperry,,134,Pad 1D
PMSS <0-4414'>,,121,Pad 1D
PMSS <0-5015'>,,135,Pad 1D
34 Version 0.a (17D),,34,Pad 1D
137 PMSS <0 - 5615'>,,137,Pad 1D
PGMS <0-7502'>,,4,Pad 1D
PGMS <0 - 6400'>,,WS-8,Pad 1D
PMSS <0 - 7340'>,,10,Pad 1D
PMSS <256 - 5973'>,,110,Pad 1D
PMSS <0-5205'>,,117,Pad 1D
PMSS <4674'-5639'>,,125A, Pad 1D
PGMS <0-8850'> 28-May-81,,MP i 17-ii-ii,Pad 1D
PMSS <0-5142'>,,115,Pad 1D
PMSS <0 - 6270'>,,114,Pad 1D
PMSS <293 - 6866'>,,113,Pad 1D
PMSS <294 - 8250'>,,112,Pad 1D
PMSS <556-7024'>,,9,Pad 1D
PMSS <0-8702'>,,14,Pad 1D
PMSS <0-9250'>,,12,Pad 1D
PMSS<0-7045'>,,111,Pad 1D
PMSS <0-4850'>,,109,Pad 1D
PMSS <0 - 7150'>,,108,Pad 1D
PGMS <0-8365'>,,1,Pad 1D
PMSS <291 - 5795'>,,125,Pad 1D
PMSS <0-5047'>,,124,Pad 1D
Closest approach with 3-D Minimum Distance method
Last revised Distance M.D. Diverging from M.D.
8-Aug-2000 88.7 500.0 4166.7
14-Jun-2000 90.0 250.0 250.0
14-Jun-2000 55.4 965.0 4460.0
3-Aug-1998 183.7 250.0 7180.0
11-Jul-2000 592.4 250.0 250.0
2-jun-1998 345.4 100.0 100.0
2-Jun-1998 187.2 262.5 262.5
19-Jun-2000 30.0 262.5 5522.2
2-Jun-2000 238.3 220.0 6600.0
4-Aug-1992 397.4 262.5 262.5
27-Apr-2000 219.7 262.5 262.5
28-Apr-1998 197.5 100.0 100.0
24-Apr-2000 549.9 100.0 100.0
2-Jun-1998 424.6 100.0 100.0
24-Apr-2000 261.8 100.0 100.0
23-Apr-1999 6845.0 4122.2 4122.2
2-Jun-1998 452.1 160.0 160.0
2-Sep-1998 465.8 275.0 275.0
22-Sep-1998 479.8 100.0 100.0
21-Sep-1998 493.5 100.0 100.0
29-Apr-1998 384.7 100.0 100.0
6-0ct-1999 708.0 100.0 100.0
21-Jan-2000 720.3 500.0 500.0
3-Sep-1998 535.7 100.0 100.0
2-Jun-1998 564.2 100.0 100.0
28-0ct-1998 578.4 100.0 100.0
10-Dec-1997 736.3 287.5 287.5
19-Aug-1998 261.8 100.0 100.0
2-Jun-1998 272.9 100.0 100.0
PMSS <290-6245'>,,l16,Pad 1D
GSS <0-175'>,,116,Pad 1D
PMSS <287-6055'>,,123,Pad 1D
GSS <0-173'>,,123,Pad 1D
PMSS <0 - 5445'>,,122,Pad 1D
PMSS <0 - 6580'>,,128,Pad 1D
PMSS <0 - 7432'>,,127,Pad iD
PMSS <0 - 6716'>,,126,Pad 1D
PMSS <0-4530'>,,120,Pad 1D
PGMS <0-8070'>,,3,Pad iD
PMSS <0-4515'>,,119,Pad 1D
PMSS <0-5462'>,,129,Pad iD
MSS <3311-8200'>,,7,Pad iD
PMSS <0-4778'>,,130,Pad 1D
PMSS <0 - 6472'>,,131,Pad 1D
PMSS <467 - 5802'>,,132,Pad 1D
PMSS <1957-5265'>,,133,Pad 1D
PGMS <0-9783'>,,2,Pad 1D
PMSS <381-6092'>,,105,Pad 1D
PMSS <0-5126'>,,106,Pad 1D
PGMS <0-8930'>,,5,Pad 1D
PMSS <0-4590'>,,liS,Pad 1D
PMSS <5155'- 5905'>,,110A, Pad iD
28 Version #3,,28,Pad 1D
136 PMSS <519 - 5680'>,,136,Pad 1D
PMSS <0-14324'>,,38,Pad 1D
139 <PMSS 515 - 4838'>,,139,Pad 1D
PGMS <0-8610'>,,6,Pad 1D
L1 PMSS <4338-7400'> Sperry,,102L1,Pad 1D
PMSS <0-5354'>,,102PB1,Pad 1D
PMSS <5181-6454'>,,102PB2,Pad 1D
PMSS <6143-6767'>,,102PB3,Pad 1D
PMSS <6527-7378'>,,102,Pad 1D
PMSS <0-11234'>,,11,Pad iD
PMSS <0-1288'>,,138PB1,Pad 1D
PMSS <0-6543'>,,138,Pad 1D
141 PMSS <704' - 2308'>,,141,Pad 1D
40 Version #l,,40,Pad 1D
PMSS <0-???'>,,40,Pad 1D
17-SED-1998
8-SED-1998
13-SED-1998
4-SED-1998
29-Aug-1998
17-Aug-1998
6-Ju1-1998
1-Ju1-1998
2-Jun-1998
13-Aug-1998
2-Jun-1998
2-Jun-1998
6-Nov-1997
2-Jun-1998
23-Ju1-1998
6-Aug-1998
2-Jun-1998
4-Aug-1992
2-Jun-1998
2-Jun-1998
13-Nov-1997
2-Jun-1998
17-May-2000
9-Aug-2000
5-Jun-2000
24-Jul-2000
18-May-2000
13-Nov-1997
27-Jul-2000
28-Jul-2000
27-Jul-2000
27-Jul-2000
28-Jul-2000
30-Dec-1999
18-May-2000
1S-May-2000
21-Aug-2000
25-Jul-2000
20-Aug-2000
438.3
438.3
319.0
319.8
332.6
231.0
240.8
251.0
358.3
507.4
371.4
199.4
181.1
193.3
188.5
184.6
181.9
620.9
634.9
606.8
294.9
410.7
549.9
120.0
228.1
30.0
258.4
213 6
678 2
678 2
678 2
678 2
678 2
157 3
247 7
247 7
330 9
60 0
59 4
100.0
100.0
275.0
160.0
100.0
100.0
100.0
100.0
100.0
0.0
262.5
200.0
250.0
262.5
100.0
100.0
100.0
262.5
287.5
100.0
275.0
262 5
100 0
455 6
2O 0
120 0
140 0
250 0
600 0
600 0
600 0
600 0
600 0
3822 2
20 0
20.0
2733.3
250.0
422.2
100.0
100.0
275.0
160.0
100.0
100.0
100.0
100.0
100.0
262.5
262 5
200 0
250 0
262 5
100 0
100 0
5700 0
262 5
287 5
100 0
275 0
262 5
100 0
455 6
4760 0
7960.0
4740.0
6380.0
6020.0
5000.0
6060.0
6240.0
6220.0
3822.2
20.0
6840.0
6200.0
250.0
422.2
LEAK OFF ! FIT TEST PROCEDURE
Kuparuk River Unit (KRU) EBA Operations
.
After cementing casing and nippling up BOPE, RIH to top of cement and pressure test the
casing to the test pressure specified in the well plan (usually 3000 psi or 3500 psi) for 30
minutes and record on chart (AOGCC required casing integrity test). Record the information
on the PAl LOT form (you can locate on the drilling web page). Plot Casing Pressure Test
(volume vs. pressure and time holding pressure on casing). Verify that the test indicates a
linear line and that there is no air entrained in the mud. Repeat Casing pressure test if
needed.
2. Drill 20' of new hole below the casing shoe.
.
Circulate the hole to establish a uniform mud density throughout the system (required for a
good FIT or LOT). PU into the shoe.
4. Close the blowout preventer (ram or annular).
5. Pump down the drill stem at 1/4 to 1/2 bpm.
.
.
On the LOT form, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until the
formation begins to take fluid; at this point the pressure will continue to rise, but at a slower
rate.
Note: If 16.0. ppg EMW is reached, shut down and hold the pressure there. This
becomes the data for a formation integrity test (FIT) instead of a LOT
At leak off pump 3 bbls of mud into formation prior to shutting down the pump.
Shut down when the leak-off point is clearly seen and 3 bbls of mud has been pumped into the
formation. Record initial shut-in pressure. With the pump shut down monitor, record and
report the shut -in pressures for a minimum of 10 minutes or until the shut -in pressure
stabilizes. Record time vs. pressure in 1-minute intervals and plot information. Bleed the
pressure off and record the fluid volume recovered. Forward the data to the Drilling
Engineer in Anchorage. The Drilling Engineer will forward the information to the Agencies.
1 8/4~00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Diverter Schematic
Nabors 16E
211~4" 2,000 psi WP
DRILLING SPOOL
w/16" Outlet
h
Flowline ~
211~" HYDRIL MSP 2,000 psi WP
ANNULAR PREVENTER
16" 200 psi WP
HYDRAULIC KNIFE VALVE
16" 62 ppf PEB CONDUCTOR PIPE
set at 80' (GL)
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Nabors #16E
13-5/8" 5,000 PSI
BOP COMPONENTS
3" 5,000 psi WP OCT MANUAL GATE
KILL LINE
3" 5,000 psi WP Shaffer GATE VALVE L
w/hydraulic actuator
/
1
/
DSA 13-5/8" 5,000 psi WP "'"'"~L
x 11" 3,000 psi WP
13-5/8" 5,000 psi WP, HYDRIL Type GK
ANNULAR PREVENTER
w/companion flange to bell nipple
AUG 2
__1 CHOKE LINE
~.1~.~..~~T~3, ~,~0 psi WP OCT
r..j~ MANUAL GATE VALVE
..
DESCRIPTION
~'~0045ACS
D.S. 1-D
12 14
~ I~2
·
105 ~ 15
2
106
· 16
141 ~ Ill
114~ 113
116~ !15
112
119
122~ 121
123
124
126
128
6
129
132
18
19
1~5
lO
I1
136
14 15
·
·
~ 28
·
· 38.
· 40
· 42
11
West
OS-1E Sak-1
· VIC/N/TY MAP
SCALE: I" -. I MILE
N
LEGEND
0 EXISTING CONDUCTORS
· "AS-BUlL T" CONDUCTOR LOCA T/ON
ARCO Alaska, Inc.
CADD FILE NO. DRAWING NO:
LK6104D28
SEE SHEET J 2 FOR NOTES AND LOCATION INFORMATION,
CEA- D1 DX-6104D28
.~'" LOUNSBURY
& ASSOCIATES, INC.
~i~iNZ=ES PIANNER~ SURYEYO{.
AREA: 10 XXXX UNIT: O1
DS1D
EBA CONDUCTORS 28 5e 52 54,56 58 '4{~ 42
ASBUILT LOCATIONS"
SHEET: REV:.
10r2 1
~[:VI DATE / BY I CK ! APP I ~'~'' D£SCRIPTION
I
~ ,
II. ~A~S ~0~ ARE A.S.P. ZONE 4, N.~D. 27.
ELEVATi~S SHO~ ARE BRITI~ PETR~EUM MEAN
SEA LEAL. ALL DIST~S SHO~ ARE ~UE.
2. ~O~APHIC CO,DINArS ARE NAD 2Z
3. BASIS ~ LO~TI~S ~D ELEVATI~S ARE D.S I-D
MONUMEN~ ~R LHD AND ASS~iA~
4. C~DUCT~S A~ LO~D Wi~IN P~AC~D ~CTI~
2J, TO~IP II N~, RAN~ IB EAS~ U.M.
DA~S ~ SUR~ 6/16/BB, F.B. LBB-19 ~ 71-72,
6/17/~, F.B. LBB-19 Pp 71 6/28-22/BB, F.B. LBB-21
6. DRILL SI~ I-D ~ID N~ IS ROTA~D BB' BI' ~5'
~ST FR~..A.~P. Z~ 4 ~iD N~.
Z ~E DRA~NG NSK-3.5-1 F~ AS-BUILT LO~TI~S ~
C~DUCT~S I-~ CEA-DIDX-61~4DIB F~ CONDUCTUS
185,186,189,115,1~7-121,124,129,13~,133 · 135;
CEA-DIDX-61B4DI3 ~ C~CT~S 9 · I~
~A-DIDX-61B4DI5 F~ C~DUCT~S 12~, ~28 ·
~A-DIDX-61B4DI6 F~ CON~CT~S IB~" 11~-I14. I16,
122, · 12~' ~A-DIDX-61B4DI8 F~ C~DUCT~S
~A-DIDX-61B4D2B F~ C~DUCT~ 14:~A-DIDX-61B4D23
F~ CONDUCTUS I82, · 136-141 ANO ~A-DIDX-61B4D26
F~ CONDUCTUS 15 AND ~8-2~.
'.
Sec. 23, T. 11
No.] Y
I.Jol
34 5,959,218.83
X LotitUde
56B. 6?B. 72 7~' 17' 57.8B5'
568,678.91 78' 17. 57.5B8'
$68,67R66 . 7B' 17. 57.214'
56~.67R62
568, 6 78. 7.t
568, 6 78. 82
7~' 17. 56.916'
56.622'
?~' 17' 56.328'
17. 56.831'
568,678.87 78'.
568,678.81. 78' 17' 55.748'
O[$CRIPTIOl~I
West
DS- 1E Sok- 1
22
VICINITY MAP'
,
SC~L~;J'~. 4 ~z~. .,,.~, ..,.
· ~" "~ ~'~ fi: '~': ~" I~" .... '~"""~
Longifude
. Hg' Jg'
Hg' ~ Jt.
~49' ~" Jt. t5B" '
~49~ 3g
149' JB' Jl. 164~
149' 3~'
SURVEYOR'S C£RTIFiCA TE
I HEREBY CERTIFY THAT I AM PROPERLY REGISTERED AND
LICENSED TO PRACTICE LANO SURVEYING IN THE ST~IT£ OF
4L~SK~ 4NO TH4T THIS PL4T REPRESENTS
BY ~ OR UNDER ~ DIRECT SUPERVI$1~ ~ND T~T 4LL
DI~NSIONS AND OTHER DETAILS ARE CORRECT AS OF
JUNE ~. ~000.
ARCO Alaska, Inc.
CAOD FILE NO. I _ · ..... I DRAWING NO:
LOUNSBURY
Jr ASSOCIATES, INC. '
AREA: lO XXXX
DS1D
EBA CONDUCTORS 28 3la 32 ,34 ,36 38 4la 42
ASBUILT LOCATIONS
!T: REV:
UNIT: 1~1
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1 D-36
EBA Producer
AFC - AK0108
Well 1D-36 is the fourth of an original eight wells planned in Phase 1 of a program that will prove-
up 23 MMBO of additional reserves in the Eastern Boundary Area (EBA). If successful, this will
expand development of the Kuparuk C sands in the southeast part of the Kuparuk Field in and
beyond the Gas Storage Area (GSA). 1D-36 is located within the geologic area known as the
"central block" and will provide the producer compliment to the 1D-38 injector drilled earlier in the
program. Additional data will also be gathered on the seismic amplitude/net sand relationship in
the area.
EBA Phase 1 Drilling Plan
5/12/00
South EBA Expansion
Top (2 Depth
gyr2 depth C
$/12/00
Proportional Faults
TAB. 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1D-36
EBA Producer
AFC - AK0108
The well is planned as a top set producer to be drilled and completed using Nabors Rig 16E and will
utilize all the other existing Kuparuk approved contractors normally supporting the KRU
development drilling operation. The well design consists of a 9-5/8" surface casing string, a 7"
intermediate casing string run from surface, and a 3-1/2" liner. The completion is planned as a
standard 3-1/2" gas lift tubing string. In case of an acceptable open hole LOT above the Kuparuk,
a contingency plan exists in which the well will be drilled from the surface casing shoe to TD and a
7" production casing long string will be set from surface to TD across the Kuparuk.
Based on the 1999 GSA drilling program, hole stabilitY problems shOuld be eXpected while drilling
the 1D-36 surface hole. Running gravel zones below the permafrost have historically caused
problems in both GSA and West Sak drilling from 1D Pad. In addition, recent wells drilled from the
original well row have had wet conductors and serious broaching incidents. However, no broaching
problems have been seen to date on EBA wells drilled from the new conductor row. Running gravel
zones remain a concern even though 1D-36 is targeting the same fault block as well 1D-38, drilled
earlier in the EBA program, which did not experience this problem. It should be noted that the
second well of the program, 1D-30 encountered significant sticky hole problems below the base of
the permafrost resulted in a hole opener clean out run prior to running surface casing.
After drilling out of surface casing, few problems are expected to the mid-HRZ. Some previous wells
(including 1D-38) have experienced significant shaker screen blinding after drilling past the the top
of the HRZ. Rig down time resulting from this blinding has been reduced through the use of screen
pre-treatments, but has not been completely resolved. Also, some prior EBA and GSA wells in this
area have experienced gas charged sands in the D-shale (up to 13.0 ppg) as a result of historic Gas
Storage Area injection. The risk of encountering any gas charging in the 1D-36 target area is
considered to be moderate to high due to it's proximity to the original Gas Storage Area and the rig
should be prepared to weight up the mud system if fluid influx is encountered. For this reason, an
intermediate topset is planned prior to drilling into the D-shale. In addition, well 1D-40 encountered
a small gas charged fracture zone at approximately midoHRZ which was believed due to the early
gas injection and which resulted in a 0.2 ppg increase over the planned mud weight to control.
A contingency plan is in place to drill 8-1/2" hole and run a 7" casing long string to TD with the
decision to long string dependant upon an acceptable open hole LOT (14.5 ppg) taken at the HRZ
mid-point. This is not considered to be a likely possibility based on previous open hole LOT results
on this project, the highest of which resulted in formation breakdown at 12.3 ppg. In addition, 1D-38
encountered hole stability problems in the transition zone between the K-1 shale and the top of the
Kuparuk D-shale requiring a mud weight up to control stability. This area will need to monitored
carefully while drilling 1D-36 in order to minimize hole problems while drilling the production interval.
It should be noted that this area of the EBA has not been extensively drilled in the past and the
formation pressures and geological makeup are still relatively unknown. Based on data acquired
during the drilling of 1D-38, reservoir pressure is predicted to be +!- 3550 psi (10.7 ppg) but rig
crews should be alert at all times to the possibility of a kick due to higher than expected pressures
or differential sticking if pressures are significantly lower than predicted.
Close Crossings and Offset Well Interception Risks
positional uncertainty calculations were performed on the proposed 1D-36 wellbore using worst
case 3D elliptical error models. Based on these criteria, there are two significant close crossings
associated with this well. The closest proximity concerns are listed below with calculations
resulting in the following minimum edge to edge ellipse separations:
6 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1 D-36
EBA Producer
AFC - AK0108
Well Name
Close Crossing Depth
MD' ft
4OO
Planned Ellipse
Separation
28.1
Required Separation
(Unsecured Well)
6.0
1 D:38
lDO0 500 54,8 7.5
All planned Separations meet the criteria ~SpeCified :in Vl .of the. PAl Drilling Anti, COllision
Management Guidelines. It. is:important 'that the .wellbore' remains, close to the planned well path
as:. 'any major deviatiO:nS .from"the :profile may adversely affect:th.e'.abili.ty.' to drill 'future' wells .:.and Still
adhere;to th:e. cu ~ren't' Cl.O~'ei"ci~Os~ing g. ui:de!i.nesl: '!t"is;'the: re,s,,PO'nSibi ii ,tY':Of the: 'DireCtiOnal
DHIlerandPhillips,:'re:p~esentati~/6'.''On:':locatiOnto ensure .that the. aP.ProVed dOWn hOle
D roXim:i~'.. Criteria:· :is: adhered::.':.toat a'li .tim es:.:~:': El'liPse. s ~).aCih~ ':req'uirem ~;htS. 'mav,n0t~ :be
viol' ated: ::With' Out::: prior .:a p:ptova !,.:fro ~m ::'!the; PhillipS:d:.' ti'llin_(i i. en-qineeriOr ::e.n~ inee r on:: Call:
Well 1D-40 is a Kuparuk EBA injector which is currently shut-in. The well was originally
completed in September 2000, but has not been perforated. The most recent data for this
well (8/8/00) showed no pressure on the wellhead.
Drilling Fluids Disposal
Incidental fluids developed from drilling operations will be either injected into an approved annulus
on the 1D pad or hauled to the nearest permitted Class II disposal well. (Note that cement
rinseate will not be iniected down the dedicated disposal well but will be recycled or held for an
open annulus.) The open annulus will be left with a non-freezing fluid during any extended shut
down (> 4 hr) in pumping operations. The '1D-$6 surface/production casing annulus will be filled
with diesel after setting production casing and prior to the drilling rig moving off of the well.
1 D-38 is currently the only approved disposal annulus available on ID Pad and was
used for cuttings disposal for both well 1D-40 and the ongoing West Sak Multi-lateral well
1D-141. Do not exceed the state mandated 35000 bbl disposal limit on 1D-38.
The disposal permit for 1D-30 has been submitted to the state, but has not yet been
approved. Do Not begin disposal into this wellbore annulus prior to obtaining state permit
approval.
Suggested class II disposal wells are 1R-18 and 3R-11.
· Contact Kuparuk environmental group before hauling to dedicated disposal well
· All fluids hauled from the rig to the dedicated disposal well must be properly
manifested.
7 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1 D-36
EBA Producer
AFC - AK0108
H2S Contin.qenc¥ Measures
The AOGCC has classified this location as a Hydrogen Sulfide area and has required that
approved Hydrogen Sulfide contingency measures remain in effect during the drilling of
1D'361 The key pointS of these requirements are as follows:
during drilling operations.
2...... :The:... rig ...Will. :have. fullY., functioning automatic H2S".'detectio'nI ..equipment meeting, the
requirements of'.20'AAC..25;066 (attaChed)... Manual .detectors.' Will 'alSo '.be.. maintained On
3.':.". :.':..:S~if :.C0nt~in'ed:':Bre~th i:~:g:.:Appa:ratu s:'f°r.'ai:i'::::~ig;' P'e[~onneli'~iWi!i'bemai::nta?eson'10Cati0n.
4. :."':':'::::~1'[::i !~e~:n~n:e~::~:~:~:~eng~:ed:?i:n~!ith~e:~?~d~1~iing:~:::~perati~ n:.:'.::.'wi:li':'::'.~se.':'. ttai.n::~d: :: in' ':' H.2S :~: .em.er;gency
...... pr~.8,~.~e~...!.:~:~:d;::.i:~..::.u.~. ::.b~:~;:~e:i:~n.~:i.:~:~.~t~ti~e'..e:qU ip~:~.~t~ ......
5. A standard H2S contingency plan will be posted at the rig. Nabors Alaska Drilling has
developed an H2S contingency plan for North Slope drilling operations (attached). All rig
personnel should read and familiarize themselves with this document and copies should
be posted in the rig floor doghouse and in the camp on location.
6. H2S treating material fOr the drilling mud system will be available on location in the event
that any H2S is encountered.
It is expected that for standard KRU drilling operations, the rig and personnel will have the
equipment and training to identify and contain a H2S emergency situation. If it becomes
necessary to notify the AOGCC of an H2S encounter, drilling will be suspended and will resume
only after the development of detailed remedial and contingency procedures, full compliance with
20 AAC 25.065 (attached) and the applicable referenced sections of APl RP49, and approval of
the AOGCC.
Pre-Ri_~ Work:
Inspect location and insure that conductor has been properly set and that all pad gravel work
has been completed prior to Nabors 16E arrival. Confirm that the identification markings on
the conductor match the planned surface location.
· If identification markings are not present on the conductor as per PAl Drilling conductor
setting SOP, contact the Phillips Drilling Engineer prior to moving the rig onto the well.
8 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1 D-36
EBA Producer
AFC - AK0108
RIG WORK
Surface Hole: 12-114" Hole / 9-518" Casinq
Inte~al Risks:
.
potential -'MODERATE
I'1..'.i' :GraVel..and.:.sand.. sl°Ughing'-..elevated. ..mud. Viscosity frOm.Spud; Hi dens sweeps;
contingent, t.3.,318", caSing String.. 'RiSk PotentiaI.'~MODERATE
IIl::,'.:.:.sh::aker~t0Ugh .'Ball:. Mill:OveEIi0w.:c'o:ntr°lled. ROP.i:"Risk potential- LOW
I¥~ .'ShOe: :":.:fract'Ure::".t LOst..: ':RetUrnS.'~": :during:'..~Cement .jOb:i: :.:,.: :.:..redu:ced~.:.'.. pumping. 'schedule~ · ' li.;h~ei~t:!tai:i;:ceme.~t?Risk:pOtential?..HiGH
Move in and rig up Nabors 16E. Record move distance and RKB distances to pad and sea
level on morning and IADC reports. Post drilling permit and SPCC plan in the rig office
· Notify AOGCC prior to spudding well and 24 hours prior to performing diverter
function test,
Install 21-1/4" diverter system on starting head and function test.
Prior to spud, a safety meeting should be held with the rig crews to discuss open hole
drilling procedures. Suggested topics include:
- Conductor broaching operations and contingencies
- Subsidence holes around wellheads - use of buddy system
- Hole fill calculations with various sizes of pipe and tubing
- Well control procedures
- Proper tripping practices
- Flow rates and hole cleaning
- Correct and accurate documentation of all BOP tests, LOT's, and safety drills
A 'Diverting Shallow Gas' drill should be held with rig crews prior to spud as per PAl
Drilling 'Drill Expectations and Procedures' document Version 1.0 unless each crew on
tour has completed this drill within the past 3 months. Document drill and record on
morning report.
An 'Accumulator' drill should be held with rig crews prior to spud as per PAl Drilling Drill
Expectations and Procedures document Version 1.0 Document drill and record on
morning report.
Shut-in drills should be held on a regularly scheduled basis. A suggested minimum is
once per day on alternating tours. Document and record on morning report,
Trip sheets must be competed and submitted to the Phillips Drillinq Supervisor after each
9 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1 D-36
EBA Producer
AFC - AK0108
· The tdp tank system should be checked for leaks prior to spud. Confirm that all trip tank
gauges are Calibrated and working properly, Make sure that all crews understand how to
Utilize and interpret the tdP tank system on Nabors 16E.
· All drills Shall be performed and documented as Per the written procedures listed
.
Build 8.5 ppg spud mud keeping funnel viscosities between 250 and 300 sec/qt to drill past
the base of the permafrost. No changes to the mud system should be attempted without
the prior consent of the Phillips company representative on location. Use all available
solids control equipment to control solids buildup and maintain mud weight.
Refer to the detailed Baroid Mud Program (attached). Maintain mud viscosities
between 250 and 300 sec/qt to help minimize gas cut mud and running gravels. Keep
make-up water as cold as possible.
Drill the 12-1/4" hole from spud to surface casing TD at +/- 7052' MD / 4299' TVD. Two bit
runs are planned for this hole section. Pick up 5" DP and a steerable BHA using tri-cone bits,
INTEQ 9-1/2" MlC PDM mud motors, and Sperry Sun MWD/LWD. Use welded blade
stabilizers to minimize clay bailing and swabbing. Use maximum/optimum hydraulics without
exceeding maximum allowed by rig contract with sufficient flow rate to clean hole. Historical
data from this pad indicates that surface hole stability problems should be expected in the
areas around 1D pad. Be aware that excessive annular velocities may aggravate hole
erosion.
The selected bits to drill this interval are as follows: Spud the well with a Hughes MX-1
Tri-cone jetted to TFA=1.402. The second bit should be a Smith Gemini FGS+21C bit
jetted to TFA=1.402. Planned circulating rates while drilling are 670- 730 gpm with the
optimum theoretical flowrate occurring at 680 gpm.
· The suggested BHA to drill this hole section is as follows:
12-1/4" HTC MX-1 or STC FGS+2C (TFA=I.402)
9-1/2" MlC w/1.4° AKO
Restrictor Sub
MWD
NM String Stab
3 - 7-3/4" NMDC's
3 - 8" DC's
XO
6 - 5" HWDP
Dailey Jars
17 - 5" HWDP
Offset wells in the primary well row have experienced a high incident rate of conductor
broaching. The cellar area must be monitored continually for broaching. The Conductor
Broaching Contingency plan (attached) will be implemented immediately upon discovery
of a broach condition.
10 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1 D-36
EBA Producer
AFC - AK0108
If broaching occurs, stop drilling immediately. Contact the AOGCC field
inspector, the Phillips Drilling Engineer, and the Phillips Drilling Team Leader
to inform them of the broach.
Sperry LWD GR tools will be run in this hole section.
· Insure that the 5" pipe has been inspected and checked for damage prior to runninq in the
hole. An earlier EBA well, 1D-38 experienced a washout in the tube in the slip setting
area on a joint of the 5" S135 drill string.
· Be prepared for heavy oil / tar blinding of the shaker screens while drilling the shallow tar
sands at +/- 2200' TVD. Attempts to pre-treat the screens with detergent and DriI-N-Slide
prior to drilling into the interval to help minimize blinding problems have proved to be
largely unsuccessful. Therefore, plan to by-pass the primary "Derrick" shakers, taking
returns only across the scalper shakers while drilling across the tar sand interval.
:> Based on the previous wells, begin looking for tar returns at +/-2800' MD / 2118' TVD
with an expected tar sand thickness of 50' -100' TVD.
.:'..::.~,: i ::...::;:":,B~::~.~ia~:~:,!~h:a~':: i:t~e[;~:~"~ i.s.:!:.::.a,,::.~ h'iSt~:~.::.;0f .'~'ha:ilow:':~s:::::.hyd;:mte§:;~a~ ~,~!.D:~:'~:P;ad'~:~ a.l:tho~g' h' ~yd~ate~ :::ha~e
"~:~t~::::::~:~s~d:~:~:~::~:~a~:~?;:~:~~;~::~;~:;~b~:;~:~:~::~h~:~:~:~::p~rb~i~:~:~s~::~::~::~BA~::~::;:~e;~s~;~;~:;~:~::~:~:~::f;::~::::~hyd::~e~:~:~::~:~?:~:~nc~:u:~e[ed:~:~;::~::~h~
f~:i{ 8~i: ~ ~?' ~:~ ~ d:i ~ t;. ~;~ ;.~ Cfi 6~;~ ~: :;' ;.~ ~::~b ~i~87 ~ b~'.';.: ~ al;~ ~t~d ~:::?.~ ~;: :::~ ~: :. ~;~:: ;.'?~ il~ a; ;; ~:.:B ~ rb:~d:' ~. ;; ~'"~ d ;: :; ~; P;i a;~:. ~. ;:':'~ ;:~.
Control drilling to limit cuttings and reduce the amount of instantaneous gas breakout.
Reduced pump rates - should coincide with reduced ROP's
Reduce drilling fluid temperatures if possible
Increase mud weight to reduce sloughing through the hydrate interval
Increased circulating time at kelly down prior to making a connection
Reduction of fluid viscosities. Viscosity reductions should only be attempted if
significant sand and gravel zones are not present below the base of the permafrost.
The followin~ drillin~ ~ractices will maintain ~ood hole conditions for the casinq and
cementin~ operations to follow:
· The mud weight should reach 9.6 ppg by the base of the permafrost due to possible
running gravels and potential influx from the Ugnu and West Sak formations in this area.
If hole instabili~ problems or hydrates are encountered, increase mud weights to +/- 9.9
11 TAB, 8/28~00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1 D-36
EBA Producer
AFC - AK0108
ppg. Do not change mud weight without the prior consent of the Phillips company
man on location.
In optimal conditions, viscosity may be reduced below the initial gravel and sand intervals
to the 150 - 190 sec/qt range. Viscosity reductions should not be considered if significant
sand and gravel zones are present below the base of the permafrost. In general,
offsetting wells on 1D Pad indicate high propensity of gravel and sand sloughing,
indicating the need to maintain high viscosity throughout the surface interval. Use high
density sweeps (>2 ppg above existing mud weight) throughout the interval to monitor
hole cleaning. If gravel sloughing and hole cleaning problems persist, do not reduce mud
viscosity until surface casing has been run to TD. No changes should be made to mud
viscosity without the prior consent of the Phillips representative on location. Any
reduction in viscosity should be performed in staqes, checking for hole instability
for a few circulations before dropping it further.
Be aware that there is a 13-3/8" Contingency plan in place: In the event surface
gravels and sands slough to the point of compromised 20" conductor integrity,
refer to the "13-3/8" Inner Conductor Contingency String" plan (attached).
Proper hole cleaning should be emphasized while drilling this high angle surface hole.
Short trips should be utilized to clean up tight spots. If reduced shaker returns indicate
that hole loading is occurring, stop drilling and sweep the hole to remove as many cuttings
as possible. Use high density sweeps (>_2 ppg above existing mud weight). Sweeps
should be pumped a minimum of once every 4 hours while drilling. If significant hole
cleaning is noted during a sweep, pump additional sweeps until returns are clean. While
pumping sweeps, rotate the pipe at 100+ rpm to optimize hole cleaning efficiency. If 100
rpm is not possible due to BHA or rig limitations, rotate the pipe at the maximum
allowable rpm. Do not resume drillinq until the hole has been cleaned to the satisfaction
of the Phillips Company man on location.
Attempt to keep the pipe moving at all times to minimize the effects cuttings settling and
the build up of cuttings beds. Keep shut down times to a minimum during connections.
When surveying in the tangent section, keep the pipe in the slips only long enough for the
MWD tools to obtain a survey, then reciprocate the pipe slowly while the survey is
transmitted uphole. Keep the pipe rotating whenever possible.
Control drilling may be necessary through this hole section in order to keep from loading
the hole with cuttings.
The mud should be kept as clean as possible. Use barite to keep the weight at an
appropriate level rather than drill solids.
Remember that surface hole stability degrades rapidly with time.
Keep mud and mix water as cold as possible to minimize the effects of running gravels
and hole washout.
Circulate weighted barafiber high viscosity sweeps at TD until the hole is clean. Short trip
to HWDP or to the previous trip point. Once on bottom circulate additional sweep(s) as
needed to clean the hole.
12 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1 D-36
EBA Producer
AFC - AK0108
· After landing casing on bottom, circulate and condition mud system until hole is clean
prior to pumping surface cement job.
Condition the wellbore for surface casing. Circulate hole clean and condition mud, short trip
to HWDP, circulate hole clean again. Reciprocate drill pipe slowly while circulating. POOH
and lay down BHA. Check hole fill volume while POOH and avoid swabbing.
A stage type cementing tool (port collar or stage tool) will not be run in the surface
casing string so it is extremely important that the hole is good shape prior to
running casing. If signs of sticking or running gravels are present, a hole opener run
may be necessary to improve the chances of getting casing to TD and bringing the single
stage cement job back to the surface. If needed, the hole opener should be run with a
short bullnose (+/- 5') to minimize the chances of sidetracking the hole.
Inspect and drift surface casing. Casing type is 9-5/8" 40.0# L-80 BTCM.
Run surface casing to TD as follows:
Run one 9-5/8" x 12" Weatherford SpiraGlider centralizer per joint of casing for a
minimum of 500' above the casing shoe. Past this point, run one 9-5/8" x 12-1/4"
bowspring centralizer per every three joints of casing to surface.
· Control casing running speed to minimize surge pressures
· Circulate and reduce mud viscosity after running casing to bottom and prior to
pumping cement. This will increase the chances for a successful cement job.
Prior to beginning the surface casing cement job, make sure that the mud properties
meet the following target criteria to help ensure effective mud removal:
Mud Wt.<10.0ppg Pv<20 Ty<20
Any packing off while running casing, and especially while above the base permafrost,
should be treated as a very serious problem if major returns are lost. It is preferable to
pull casing out until circulation can be re-established rather than risk not getting cement to
surface. Contact the Drilling Engineer or the Engineer on call if the casing packs off up
high for discussion of the options.
· Keep the shut down time periods (dropping the plug, switching to rig displacement) as
short as possible.
· Keep reciprocating the casing as long as possible. (Note that once the top plug is
dropped it is very rare to be able to move the pipe again.)
8. Pump surface cement job as per the Drilling Plan and Dowell cementing plan.
· Be aware that there is no staqe cementinq device (port collar of staqe tool) being run on
this well.
AOGCC, Phillips Drilling Team Leader, and Phillips drilling engineer (or engineer
on call) must be contacted prior to beginning top job. Do not proceed with top iob
without AOGCC approval.
13 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subs[diary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1 D-36
EBA Producer
AFC - AK0108
Carefully review the cement plan for surface casing string with the Dowell and Baroid
personnel on location. Do not deviate from this plan without prior approval of the Phillips
drilling engineer or engineer on call.
· Displace cement with kill weight mud.
Note: 9-5/8" casing capacity- 0.0758 bbl/ft
If plug does not bump, do not overdisplace by more than 2.0 bbl. It is preferable
to spend additional time cleaning out surface casing than risking a poor cement job
around the shoe.
9. Nipple down diverter and flush lines.
10. Orient and nipple up casinghead and tubinghead assemblies. A FMC Gen 5 wellhead system
will be used on this well.
Refer to the attached wellhead orientation diagram for this well. Contact FMC,
Production7 and Facilities personnel before settinq the casinqhead and tubin_qhead
to confirm wellhead orientations.
l'n:.tlermediateHbi~.!. 8-1/2" Hole / 7" Casing
Interval Risks:
l i~.':::.'::~:i:::::!:':::S;hi~:l~:,i;::~ta::'b.i.l':i~~i~i:h~:~i~iH~i:!:~;~;~iBbn~tE~il:;~:~it~h~t~:~hi§h~?::.MW.i~?~d:~:~::p~R~:~pe~r~/~d~i:~i~h~pra~ti~es~:~(see
"'~t/~'~'):~:.:~;;:~R'i~:k;t~::~i~:.~ii~.!:.;.~'?M0.D'E~E ................................................................
II. Hole cleaning in long, high angle tangent- Good drilling practices. Risk potential -
MODERATE
III. High ECD and Swabbing if higher MW is required - Pumping and rotating out on all
trips to reduce swab and barite sag potential. Risk potential - LOW
IV. D-Shale gas - Do not drill into the D-shale in this inte~al. Risk potential - HIGH
11. Nipple up the 11" 5M BOP stack as per Phillips Drilling Policy. Test all BOP and choke
manifolds to a minimum of 5000 psi.
· Notify AOGCC 24 hours prior to performing BOP test
12. Install wear bushing. Pick up 6-3/4" Inteq M1XL PDM, 8-1/2" bit and Sperry MWD/LWD.
Clean out to the top of the float equipment. Pressure test casing to 3000 psi as per AOGCC
requirements following the attached casing testing procedure.
The selected bit for this interval will be a Hughes DP0390 jetted to TFA=0.819. Planned
circulating rates while drilling are 540-600 gpm with the optimum theoretical flowrate
occurring at 580 gpm.
· The suggested BHA to drill this hole section is as follows:
14 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1 D-36
EBA Producer
AFC - AK0108
HTC DP0393 (TFA=0.819)
6-3/4" MlXL w/1.2° AKO
NM Sting Stab
Restrictor Sub
LWD
MWD
3 - 6-1/4" NMDC's
XO
6 - 5" HWDP
Jars
6 - 5" HWDP
Accelerators
17 - 5" HWDP
13. Drill out the float collar, landing collar, shoe, and 20' of new hole and perform leak off test as
per AOGCC requirements following the attached LOT Procedure.
If the pressure continues to rise past 16 ppg EMW, shut down and conduct a FIT per the
attached FIT Guidelines. Once a good FIT is established, contact the drilling engineer or
engineer on call for a discussion of options.
Prior to drilling ahead, Phillips Rig Supervisor should calculate current kick tolerance
based on LOT/FIT outcome and communicate results to rig personnel and Drilling
Engineer.
~!?¢:ili?!'iDrill enough new hole to bury the 8-1/2" BHA. Perform a PWD Baseline Test (attached) to
evaluate clean hole/clean fluid conditions. Targeted hardline above the HRZ should be the
lesser of 1/2 ppg above clean fluid tests or the LOT value. The upper Cretaceous shales are
not anticipated to develop "breathing" characteristics at the upper interval mud weights.
Sperry Sun will provide a "Modeled ECD Hardline vs Depth" graph specific to this well.
Baseline test data should be compared against this graph and all variations noted prior to
drilling ahead.
15. Drill the 8-1/2" hole to the HRZ mid-point at +/- 10903' MD / 6178' TVD. Use optimum
hydraulics without exceeding the maximum flow rates / pressures allowed by rig contract and
with sufficient flow rate to clean the hole.
· Sperry LWD GR/RES/PWD tools will be run in this hole section.
Proper hole cleaning should be emphasized while drilling intermediate hole. Short trip
and sweep frequency should be optimized based on current PWD data. Keep
actual ECD's recorded with the PWD tool within 0.5 ppg of the calculated ECD's.
Short trips should be optimized to clean up tight spots.
Mud weight should be maintained as Iow as possible to the top of the HRZ in order to
maximize ROP. Prior to the top of the HRZ, the mud weight should be increased to 9.8
ppg and fluid loss decreased to <5 cc/30 min to insure shale stability at the required hole
angle.
· Use only high density, high viscosity sweeps in this hole section as per the attached
Baroid mud plan. If significant hole cleaning is noted during a sweep, pump additional
15 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1D-36
EBA Producer
AFC - AK0108
sweeps until returns are clean. While pumping sweeps, rotate the pipe at 100+ rpm to
optimize hole cleaning efficiency. If 100 rpm is not possible due to BHA or rig limitations,
rotate pipe at the maximum allowable rpm.
Be prepared for shaker screen blinding while drilling through the HRZ as has been
experienced on the previous EBA wells. Pre-treat the screens with detergent, DriI-N-Slide
and/or other lubricants prior to drilling into the interval to help minimize blinding problems.
If this does not help, it may be necessary to run larger mesh screens through this interval.
As with the surface hole, attempt to keep the pipe moving at all times to minimize the
effects cuttings settling and the build up of cuttings beds. Keep shut down times to a
minimum during connections. When surveying in this hole section, keep the pipe in the
slips only long enough for the MWD tools to obtain a survey, then reciprocate the pipe
slowly while the survey is transmitted uphole. Keep the pipe rotating whenever possible.
Optimized nozzles and flow rate improve hole cleaning and reduce washout. This
interval is typically drilled with PDC bits that have nozzles designed at a substantial
angle from the bit axis. This offset may result in significant fluid/wellbore impact and
high rates of washout when HSI or HHP is optimized.
Optimized hole cleaning occurs during periods of high rotary rpm's (>90 rpm's or as
fast as possible) and high flow rates.
Highest ECD spikes are developed after a) a period of sliding followed by b) reaming
the connection down with pumps on at normal drilling rates. This is due to the
reduced hole cleaning efficiencies during a slide (no rotation), and subsequent
cuttings bed buildup in the higher angled sections of the well bore. To counteract
these effects, prior to making a connection after a period of sliding, rotate the
string at maximum rpm's with pumps maintained at maximum fiowrate for a
minimum of 5 minutes prior to making the connection, back-reaming, or
reaming the stand down. When reaminq a stand, pump rate should be reduced to
50 - 60% of normal pump rate during the downstroke of the string.
"Bottoms Up" circulation is meaningless for high angle/high departure wells, since the
cuttings move much slower up the hole than the fluid. "Bottoms up" prior to tripping
will simply shift the cuttings beds uphole or worse, create a "dune" up the hole rather
than cleaning the hole. Best practices require 2 - 4 bottoms up prior to a trip to
properly clean the hole in a well deviated above 45°. Rely upon PWD data to
determine required circulating duration for cleaning the hole prior to drilling ahead.
When circulating and reciprocating for extended periods, pull 1 stand per hour
to minimize wash out effects of circulation across a single area. On past wells
significant hole enlargement has occurred in areas where repetitive circulation
and reciprocation was used as evidenced by real-time acoustic caliper logs.
These zones of enlargement create areas of reduced annular velocity, cuttings
bed build-up and a potential pack off threat later in the well.
When a tight spot is encountered during a trip, assume the tight spot is associated
with cuttings bed buildup. RIH until the BHA is clear of the tight spot, circulate and
rotate for approximately 30 minutes and attempt to POOH again. If the tight spot has
disappeared or moved up hole, then the tight spot was most likely cuttings. If the tight
spot is in the same place, then it is most likely a formation condition and back
16 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHiLLiPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1 D-36
EBA Producer
AFC - AK0108
reaming should be undertaken. If back reaming is necessary, use normal drilling
flowrates.
It is important to recognize that none of these are independent variables and
optimized drilling practices are achieved when all targets are attained. Hole cleaning
conditions can be monitored by pump pressure and PWD spikes, torque, drag, etc.
and practices modified to improve hole conditions. Adherence to these guidelines
throughout this interval will reduce trouble time.
16..'.At the..: m.id~HRZ obtain .:a flowline, fluid tem. perature'..and..:record....POOH'.ito.the, base'.of, the
surface.:..:.:...¢asing.. .....shoe:..:.and::.pe:rfOrm...a.....: F.I:TILOT '::;to.:. '1.$.0.. :...ppg.....maximum.. per.....:AOGCC
:re:quir~ments and':,.?A:l:..;Dril'li.ng :..L'O:T1F I:T .. GUide!inesi.:..' Based;::'..u:pon..::.m0.de!ed.'.:E.CD ;'. a..... FIT .to..:.. 14.5
ppg'. wil:l~:i:;::allOW: :.'. al.'.: 7 '.:::':t0ng:.':.:Stdng.; ::Wh.i.le:i.:',.a ..LOT'.: to..a ;:'l'eSSei~.'.':Value.::Wil!:::defi ne .'thei:~hardline ..fo.[:.:. the
r~e'm'a.i'ndei~ :0f:.'.th.e'::i'nte:.[m.edi:ate.:.'h01e::
17.
If a LOT > 14.0 pD_~ is obtained, drill ahead to well TD at +/- 11624' MD / 6530' TVD.
Continually monitor PWD for adequate hole cleaning, torque, drag and cuttings characteristics
for shale stability. Pump high density sweeps as needed for supplemental hole cleaning.
Sweeps must be accompanied by maximum rotation until sweep is seen at surface.
· A well plan completion addendum for 7" production casing will be provided if the decision
is made to long string.
18. If a 1,4..0 pp~ FIT is not attained, the well will be topset above the Kuparuk. Drill ahead to
intermediate hole TD of +/- 11069' MD / 6259' TVD. Do not drill below the base of the
HRZ due to the risk of gas pressure in the D-shale sands. Continually monitor PWD for
adequate hole cleaning, torque, drag and cuttings characteristics for shale stability. Pump
high density sweeps as needed for supplemental hole cleaning. Sweeps must be
accompanied by maximum rotation until sweep is seen at surface.
19. Condition the wellbore for intermediate casing. Circulate the hole clean and condition the
mud, short trip to the surface casing shoe, circulate the hole clean again. Reciprocate the drill
pipe slowly while circulating. Fax a 5" log to the project geologist (x4566).
Make sure that the hole is good shape prior to running casing. Continue to circulate
and short trip until the Phillips supervisor is comfortable with hole conditions. If the hole is
tight or packing off, an additional clean out or hole opening run may be necessary to
improve the chances of getting liner to TD. Do not POOH without the prior consent of the
Phillips Rig Supervisor on location.
20.
POOH, lay down BHA and stand back drill pipe. Check hole fill volume while POOH and
avoid swabbing. When out of hole, LWD tools should be downloaded to a 3-1/2" floppy, sent
to the geologist in town, and placed on the server. Pull wear bushing.
21. Inspect and drift intermediate casing. Casing type is 7" 26.0# L-80 BTCM
22. Pick up casing and RIH. Make up and Bakerlock the bottom two joints as follows:
I. Float shoe
II. 2 joints 7" 26.0# L-80 BTCM casing
17 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1 D-36
EBA Producer
AFC - AK0108
III. Float collar
23. Fill pipe and break circulation, then PU 30' to check floats.
24. RIH, filling casing a minimum of every 5 joints. RIH very slowly and avoid any surge or swab
pressures when setting or picking up slips.
Run one Weatherford 7"x 8-1/4" SpiraGlider centralizer per joint of casing for a minimum
of 500' above the casing shoe. Place a stop collar in the center of each joint and let the
centralizers float between it and the collars.
· Run one centering guide every fifth joint from surface down to KOP and one centering
guide every third joint from KOP to +/- 2000' TVD in intermediate/surface casing lap.
· Gently break circulation a minimum of every +/- 2000' and check flow through
floats. Keep casing full at all times while running in the hole.
· Monitor mud flow while running in hole. Reduce running speed if decrease or loss of flow
is noted.
· Monitor PU and SO weights while running in hole. Record hanging weight, PU weight and
SO weights with casing at TD.
If casing does not go to bottom, POOH and pick up a hole opener clean out assembly.
The hole opener should be run with a short bullnose (+/- 5') to minimize the chances of
sidetracking the hole and PWD tools should be included in the BHA to monitor hole
cleaning and cuttings removal.
25. Lay down fill-up tool, make up hanger and landing joint, and land casing. Make up cement
head assembly and slowly break circulation.
26. Establish circulation rate and pressure while circulating at least 1-1/2 bottoms up volume to
condition hole. Reciprocate casing while circulating and cementing. Batch mix cement.
Prior to beginning the production casing cement job, make sure that the mud properties
meet the following target criteria to help ensure effective mud removal:
Mud Wt. < 10.0 ppg Pv < 20 Ty < 20
Review LWD log results across the Campanian sands with the project geologist
prior to beginning cement job. If logs indicate the presence of hydrocarbons, cement
will brought back above the Campanian Sands. If LWD logs indicate that no Campanian
hydrocarbons are present (expected case), plan to bring cement back to +/- 800' above
the casing shoe.
27. Test cement lines and pump cement job. Drop wiper plug. Displace cement with kill weight
:~i~i~!"~ Have the casing near bottom before the cement leaves the shoe.
· Slowly reciprocate the pipe while pumping cement. If the hole becomes sticky,
immediately land casing on bottom.
· Pump cement as per the Drilling Plan and the attached Dowell cement program.
18 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1 D-36
EBA Producer
AFC - AK0108
28.
29.
A pressure increase may occur when the liner wiper plug is picked up. Reduce the pump
rate just prior to picking up the plug so that strokes may be checked at this point in the
displacement, but pick rate up again as soon as possible as the cement will be around the
shoe.
Resume higher pump rate and continue to displace cement. Note pick up and slack off
weights. Slow displacement and set liner on bottom just prior to bumping plug. Bump plug
and check that floats are holding.
· If plug does not bump, do not overdisplace by more than 1.0 bbls
Flush 9-5/8" x 7" annulus with 50-100 bbls of drilling mud to ensure that cement is not present
in the 9-5/8" casing shoe. Note: This step may be eliminated if cement was not brought
back above the Campanian sands as per step 26 above.
Production Hole: 6-1/8" Hole 1 3-1/2" Liner
I.n.te~a:l.Ri:sks:::
'1:.:::?. i"..i:.!'.:i.',s.hai~:::~.~: ~a'b i!ity i:. :~: :::..'~C:r O SS :;i i.i'~ ~:~1 ::. i::', :it ira:n: s. i tioh...i:i~:z0 n e,:?~': ~. ::;~:.. c~ :.~ i~i':~: :. i~ it h:i.~.:.:h..igher::':: MW:.:'and.. prOper
· " d.rilling:::i~ip~a~ti~es?:~?(see~:.., prog ~a:m).::..RiSk: ~otential...~:~:H. iG:H
II. High ECD and Swabbing if higher MW is required - Pumping and rotating out on all
trips to reduce swab and possible barite sag. Risk potential - MODERATE
III. D-Shale Gas related to GSA gas injection - may require MW increase to +1- 13.0 ppg.
Need to confirm for future planning purposes. Risk potential - HIGH
30. Nipple up the 11" 5M BOP stack as per Phillips Drilling Policy. Install pack off and test to
5000 psi. Test all BOP and choke manifolds to a minimum of 5000 psi.
· Notify AOGCC 24 hours prior to performing BOP test
31. Lay down excess 5" drill pipe. Install wear bushing. Pick up 4-3/4" Inteq M1XL PDM, 6-1/8"
bit and Sperry MWD/LWD on 4" drill pipe. Clean out to the top of the float equipment.
Pressure test casing to 3500 psi as per AOGCC requirements following the attached casing
testing procedure.
Plan to pick up Weatherford 4" drill pipe and handling tools for this hole section. Drill pipe
is 4" 14# S-135 with HT-38 connections. See attached specification sheet for additional
drill pipe data. Visually inspect and rabbit pipe prior to RIH.
The selected bit for this interval will be a HTC STR554 PDC jetted as follows: 2 x 12's, 2 x
14's (TFA-0.522). Planned circulating rates while drilling are 260-310 gpm with the
optimum theoretical flowrate occurring at 280 gpm.
· The suggested BHA to drill this hole section is as follows:
STR554 PDC (TFA=0.522)
4-3/4" M1XL w/1.2° AKO
19 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1D-36
EBA Producer
AFC - AK0108
NM Sting Stab
LWD
MWD
Hang Off Sub
3- NM Comp Svc DP
Jars
XO
39 - 4" DP
Jars
12- 4" DP
Accelerators
32. Drill out the float collar, landing collar, shoe, and 20' of new hole and perform leak off test as
per AOGCC requirements following the approved LOT Procedure.
If the pressure continues to rise past 16 ppg EMW, shut down and conduct a FIT per the
attached FIT Guidelines. Once a good FIT is established, contact the drilling engineer or
engineer on call for a discussion of options.
33.
Drill enough new hole to bury the 6-1/8" BHA. Perform a PWD Baseline Test (attached) to
evaluate clean hole/clean fluid conditions. Targeted hardline above the Kuparuk C4 should
be the lesser of 1/2 ppg above clean fluid tests or the LOT value.
Sperry Sun will provide a "Modeled ECD Hardline vs Depth" graph specific to this well.
Baseline test data shold be compared against this graph and all variations noted prior to
drilling ahead.
34. Drill 6-1/8" hole to well TD at +/- 11624' MD / 6530' TVD. Continually monitor PWD for
adequate hole cleaning, torque, drag and cuttings characteristics for shale stability. Pump
high density sweeps as needed for supplemental hole cleaning. Sweeps must be
accompanied by maximum rotation until sweep is seen at surface.
Mud weight should be increased to 11.1 ppg prior to drilling into the K-1 transition
zone and should be maintained at this level through the Kuparuk C4 target to well
TD as per the attached Baroid mud plan. Keep the mud in good shape in order to
maintain a thin wall cake and to minimize gel strengths and PV's for ECD control. If
needed, weight up slowly in 0.3 ppg increments or less. Trip slowly and carefully and
break circulation gently in order to minimize surge and swab pressures.
· No MAD passes are planned through the production zone.
· Sperry LWD GR/RES/PWD/NEU/DEN tools will be run in this hole section. Neutron and
Density tools should be run in memory only mode.
Monitor rotary torque while drilling and reaming and add torque reducers to the mud
system as needed. Make sure that connections are made up to the proper specifications
during RIH. Record torque values and fax to town.
20 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU '1 D-36
EBA Producer
AFC - AK0108
Be prepared for potential gas in the D shale sands. Drill ahead slowly and monitor the
well carefully. If gas is present be prepared to increase MW. It is important to evaluate if
.qas is present prior to any MW increase. This will help to determine the feasibility of any
future Ion_q strin.q completions in this fault block.
Use only high density, high viscosity sweeps in this hole section as per the attached
Baroid mud plan. If significant hole cleaning is noted during a sweep, pump additional
sweeps until returns are clean. While pumping sweeps, rotate the pipe at 100+ rpm to
optimize hole cleaning efficiency. If 100 rpm is not possible due to BHA or rig limitations,
rotate pipe at the maximum allowable rpm.
As with the intermediate hole, attempt to keep the pipe moving at all times to minimize the
effects cuttings settling, the build up of cuttings beds, and the risk of differential sticking.
Keep shut down times to a minimum during connections. When surveying in this hole
section, keep the pipe in the slips only long enough for the MWD tools to obtain a survey,
then reciprocate the pipe slowly while the survey is transmitted uphole. Keep the pipe
rotating whenever possible.
.~i.?~!!?ii!lf any sticking problems are seen immediately notify the Phillips or Nabors
supervisors. Attempt to keep the pipe moving and circulation established. M.a!~e
S.~:re :::;i. th:at::~ :ali:.~:.':~. qg::?.:;t:ea~.i.. ::~::.mem ber~.:~.~.:are:.::: c~m:mu:0icat :i:',ng. ::.:.:.Wi' ~biii:.. );~aCh?:~ :O:~he, r,,.'..~'o ,n::::.:. any'~.i':.obse~ed
d',~il;ii~:~:~:;ti~e~q~::~.;~.nd:i.that;.e~e~0:,~ei i:Und.e~st~:~qs ;.th'e:i:pot~fitia!:ove;~bal'a~ce~?d:sk:;:.
· Heavy Oil Tar is not expected in this target area. However, if it is observed in the cuttings,
a DPC CMR log may be run on a contingency basis.
Notify SWS a minimum of 24 hours prior to needing logging tools on location
The potential of a sidetrack exists in the event of poor reservoir quality or reservoir
thickness below the minimum economic requirements. A sidetrack contingency program
will be developed prior to reaching TD and is initially planneds as a cut and pull of the 7"
intermediate casing followed by an open hole sidetrack off of a cement plug to the "40A"
BHL north of the current target.
35. Condition the wellbore for production liner. Circulate the hole clean and condition the mud,
short trip to the intermediate casing shoe, circulate the hole clean again. Reciprocate the drill
pipe slowly while circulating. Fax a 5" log to the project geologist (x4566).
Make sure that the hole is good shape prior to running liner. Continue to circulate
and short trip until the Phillips supervisor is comfortable with hole conditions. If the hole is
tight or packing off, an additional clean out or hole opening run may be necessary to
improve the chances of getting liner to TD. Do not POOH without the prior consent of the
Phillips Rig Supervisor on location.
36. POOH, lay down BHA and stand back drill pipe. Check hole fill volume while POOH and
avoid swabbing. When out of hole, LWD tools should be downloaded to a 3-1/2" floppy, sent
to the geologist in town, and placed on the server. Pull wear bushing.
37. Inspect and drift production liner. Liner type is 3-1/2" 9.3# L-80 SLHT
21 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1 D-36
EBA Producer
AFC - AK0108
38. Hold safety meeting prior to running liner. Rig up casing running equipment and check
calibration of casing tongs. Insure tieback line is installed on power tongs and is level and
secured at right angle for accurate torque measurement. Have at least one backup for power
tongs, hydraulic unit and spider/elevator on location.
39. Pick up liner and RIH. Liner assembly should be made up as follows:
Baker 3-1/2" SLHT Float Shoe
1 jt. 3-1/2" 9.3# L-80 SLHT liner
Baker 3-1/2" float collar, SLHT
1 jt. 3-1/2" 9.3# L-80 SLHT liner
Baker Landing collar
3-1/2" 9.3# SLHT solid liner to nipple
Halliburton 'XN' nipple w/2.75" No-Go profile, SLHT
1 jt. 3-1/2" 9.3# L-80 SLHT liner
Baker 20' Seal Bore Extension
Baker 7" x 5" 'Flexlock' liner hanger
Baker 7" x 5" 'ZXP' Liner Top Isolation Packer w/HR profile
Run one Weatherford 3-1/2" x 5-7/8" (3.8" ID x 5.875" OD) Straight Blade Rigid Slip-on
centralizer per joint of liner back to the intermediate casing shoe. Place a stop collar in
the center of each joint and let the centralizers float between it and the collars.
The Flexlock hydraulic hanger should be pinned for +2625 psi and the 'HR' setting tool
pinned for +/- 3300 psi.
· Baker lock float equipment and shoe joints.
40.
Make up hanger assembly, tieback sleeve, and rotating dog sub. Fill pipe and break
circulation to ensure liner is free of obstructions, then PU 30' to check floats. Fill tieback
sleeve with "temblok" to serve as a debris barrier to keep cuttings, etc. out of the sleeve.
Install drill pipe wiper on setting string to prevent foreign objects from falling into wellbore
during TIH.
41. RIH, filling liner a minimum of every 5 joints. RIH very slowly and avoid any surge or swab
pressures when setting or picking up slips.
· Gently break circulation a minimum of every +/- 2000' and check flow through
floats. Keep casing full at all times while running in the hole.
· Monitor mud flow while running in hole. Reduce running speed if decrease or loss of flow
is noted.
· Monitor PU and SO weights while running in hole. Record hanging weight, PU weight and
SO weights with liner at TD.
· Always bring blocks to a complete stop prior to setting slips
· Maximum pull at the liner is 80% of connection or pipe yield, whichever is less
· With liner on bottom, circulate the wellbore and condition the mud to the YP to the 6 range
with Therma-Thin
22 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1D-36
EBA Producer
AFC - AK0108
· Record up and down weights of the liner at intermediate casing shoe before
entering open hole and at TD
After rotating liner, release stored torque by backing out very slowly. Do not allow
drill string to backlash as this may result in a mechanical release of the setting tool
from the liner.
42. Set the hanger +/- 150' above the intermediate shoe depth. Do not set the liner
hanger/packer assembly inside the intermediate float collar.
43. Circulate with mud at the maximum possible rate until returns are clean, monitoring loss rate
vs. circulation rate. Circulate 2-3 annular volumes. Reciprocate while conditioning and
cementing as hole conditions permit. Batch mix cement.
Prior to beginning the production liner cement job, make sure that the mud properties
meet the following target criteria to help ensure effective mud removal:
Mud Wt. < 13.0 ppg Pv < 20 Ty < 20
44.
RU Dowell cementers and insure the rig-up configuration permits a seamless transition
between fluid types. Test cementing lines with water to 4500 psi and flush with mud to
overflow (slop) tank.
45.
Pick up Baker Model TD cement head and pump cement job. Dowell will pump the entire job,
including displacement, until the liner top packer is set. The rig will be used to displace above
the liner.
· Slowly reciprocate the pipe while pumping cement. If the hole becomes sticky,
immediately land liner on bottom.
· Pump cement as per the Drilling Plan and the attached Dowell cement program.
46. Kick out the wiper plug and displace at 5 - 7 bpm while below the liner hanger setting
pressure.
47.
Resume higher pump rate and continue to displace cement. Note pick up and slack off
weights. Slow displacement and set liner on bottom just prior (+/- 10 bbl) to bumping plug.
Bump plug and check that floats are holding.
· If plug does not bump, do not overdisplace by more than 1.0 bb!.s..
48. Increase pressure to +/- 2900 psi to set the liner hanger. Slack off to validate hanger setting.
Bleed pressure to zero.
49.
To set the liner top packer, pick up at the tool to clear the rotating dog sub from the 6' tieback
sleeve. Rotate 10-15 rpm and set down +/- 50,000 lbs at the tool. The rotation will break the
static friction between the DP and the casing.
· Rotation is through the dog sub (dogs are on a bearing pack) and the slick stinger will still
be packed off in the RS bushing while rotating.
23 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1D-36
EBA Producer
AFC - AK0108
50. Once hanger and packer are set, pick up to release the RS seal assembly. Note weight
indicator and confirm release of liner weight.
Do Not hold pressure on tubing while picking up to release the RS seal assembly.
This creates a condition known as dynamic unloading which may result in the seal
elements detaching from the RS seal assembly unit.
If plug does not bump or tool does not hydraulically release, slack off and set liner on
bottom. Apply +/- 3500 fi-lbs of left hand torque at the tool combined with 1/4 turn of left
hand rotation at the tool to release.
If mechanical problems occur and circulation is not possible after releasing from the
hanger and packer, POOH in stands to clear green cement ASAP and prepare for a
cleanout run.
51.
Circulate a minimUm of 20 bbls at maximum rate at the top of the liner. Continue circulation
(with reciprocation) until returns are clean. Circulate at least 150% of the annular volume to
surface or 2X the DP volume, whichever is greater.
· Watch for cement returns and estimate the volume returned on the morning report.
52.
Observe well for 15 minutes to confirm that well is static. POOH laying down drill pipe.
Perform the AOGCC-required pressure test after running tubing to avoid creating a micro-
annulus between the cement and liner
24 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1D-36
EBA Producer
AFC - AK0108
Running Completion - 3-112" tubing
53. The completion is a single 3-1/2", 9.3#, L-80 EUE 8RD-Mod assembly to be run as follows
(producer completion; see schematic):
· Nabors 16E will need a 3-1/2" EUE landing joint and pup for 35' RKB.
· All connections to be EUE Modified. All pipe to be L-80.
· Verify all completion equipment has been operationally and pressure tested.
· Drift all 3-1/2" tubing and completion equipment with 2.867" drift.
· Record ODs and IDs of all auxiliary equipment on tubing detail.
· Record ODs and IDs of all auxiliary equipment on tUbing detail.
· Use APl modified pipe dope if tubing has APl modified dope from the mill. Use Cats Paw
Grey if mill dope is Cats Paw Grey. Avoid mixing pipe dopes.
· For 3-1/2" 9.3# tubing, torque tubing according to procedure recommended by Atlas
Bradford: On the first 15 or 20 joints, mark a 1/8" wide white paint band on the pin end at
the last scratch on the pin thread. For 3-1/2" tubing, the length from the end of the pipe to
the vanish point or last scratch is 2.375". Average the torque values to find the optimum
value.
Note: Torque values for Mod connections are expected to be 70% of comparable APl
connections whose torque values are listed below.
Tubing Type Minimum Optimum Maximum
3-1/2" 9.3# L-80 EUE 8RD 2350 fi-lbs 3130 fi-lbs 3910 fi-lbs
A. 4.0" x 3.0" Baker 'GBH-22 Seal Assembly', 17' long w/15' stroke, 3-1/2" EUE 8RD-Mod
box up
B. 5.125" x 3" Baker Locator sub
C. 1 jt 3-1/2" 9.3# L-80 EUE 8RD-Mod tubing
D. 3-1/2" Camco 'DS' landing nipple with 2.813" No-Go profile. 3-1/2" x 6' L-80 handling
pups installed above and below, EUE 8RD-Mod
E. 1 jt 3-1/2" 9.3# L-80 EUE 8RD-Mod tubing
F. 3-1/2" x 1-1/2" Camco 'MMG' mandrel w/shear valve and latch (Max. OD 5.968", ID
2.92"), pinned for 3000 psi shear (casing to tubing differential), 3-1/2" x 6' L-80 handling
pups installed above and below.
G. 3-1/2" x 1-1/2" Camco 'MMG' mandrels w/DV's and RK latch's (Max. OD 5.968", ID
2.92"), 6' L-80 handling pups installed above and below on GLM's, spaced out w/3-1/2"
9.3# L-80 tubing as follows:
25 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subslcllary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1D-36
EBA Producer
AFC - AK0108
54.
H. 3-1/2" 9.3~ L-80 EUE 8RD-Mod tubing to landing nipple
I. 3-1/2" Camco 'DS' landing nipple with 2.875" No-Go profile set at +/- 500' MD. 3-1/2" x
6' L-80 handling pups installed above and below, EUE 8RD-Mod
G. 3-1/2" 9.3~ L-80 EUE 8RD-Mod tubing to surface
H. 3-1/2" 9.3~ L-80 EUE 8RD-Mod spaceout pups as required
I. 3-1/2" 5M FMC 'Gen V' tubing hanger with 3-1/2" L-80 EUE-Mod pin down
Prior to stinging seals into the seal bore extension and with the seal assembly just above the
SBE, test the production liner and casing to 3500 psi for 30 minutes for the AOGCC required
integrity test. Record test on pressure chart for well files and note results on morning report.
Notify Anchorage office if pressure loss is greater than 10% in 30 minutes.
55. Displace mud with seawater; circulate at high rate for good removal. Observe well for 15
minutes to ensure that no leakage is occurring.
56.
Circulate down looking for pressure increase as seals enter SBE. Shut down pumps. Bleed
pressure off tubing and continue RIH until Iocator sub tags up (strap pipe to verify seals travel
entire stroke of SBE). Space out with tubing pups. Space out should leave Iocator 1' above
fully located position when tubing hanger is landed in tubin.q spool.
57. Sting back into PBR and land tubing hanger. RILDS.
58.
With the annulus open, pressure 3-1/2" tubing to 3000 psi. Hold pressure for 15 minutes and
monitor annulus for returns. Bleed down pressure in tubing to 500 psi. While holding 500 psi
on tubing, pressure 3-1/2" x 7" annulus to 3000 psi for 15 minutes. Record test on pressure
chart for well files and note results on morning report.
· If returns are seen or unable to pressure test, contact Phillips Drilling Engineer or
engineer on call to discuss options.
59. Bleed down pressure in tubing to zero. With tubing open, increase annulus pressure and
shear DCR valve.
60.
Freeze protect well by pumping a minimum of 74 bbls diesel down annulus taking returns
from tubing, holding back pressure as necessary to maintain constant BHP. Shut down
pumps. Put tubing and annulus into communication across choke manifold and allow diesel to
swap over to tubing, equalizing at approximately +/- 2038' TVD / +/- 2100' MD. Be sure to
allow sufficient time for diesel to fully swap.
Note:
3-1/2" Tubing Capacity
3-1/2" x 7" Annular Capacity
Tubing + Annular Capacity
= .0087 BBL/FT
= .0264 BBIJFT
= .0351 BBIJFT
61. Pull landing joint. Install BPV. ND stack. NU tree. Pull BPV. Install test plug. Test tree to 250
and 5000 psi. Test packoff to 5000 psi. Pull test plug.
62. Shut in well. Monitor and record SICP and SITP. Set BPV. Prior to rig down, install a 5000 psi
chart recorder on the 9-5/8" x 7" annulus and perform a leak off test on the annulus for
26 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1D-36
EBA Producer
AFC - AK0108
obtaining Al permitting data. Use diesel for injection fluid and record and submit all pertinent
data on the standard LOT Excel spreadsheet. RDMO Nabors 16E. Turn well over to
Production via Handover Form.
63. Complete all necessary completion reports and hand-over notes with all depths and
equipment. Reference all depths back to the original drilling rig RKB. Fax one copy to the
Anchorage office with final daily report.
Note: Handover Form Accuracy and Completeness is Essential.
27 TAB, 8/28/00, v2
PHILLIPS Alaska, Inc.
A Subsidiary of PHILLIPS PETROLEUM COMPANY
Drill and Complete Procedure
KRU 1D-36
EBA Producer
AFC - AK0108
Attachments
Wellbore Schematic
Drilling Plan
Drilling Fluids Program
Cement Program
Time & Cost Curves
Directional Program
LOT / FIT Casing Test Guidelines
Conductor Broaching Plan
Contingency Inner Conductor Plan
Lost Circulation Decision Tree
PWD Baseline Procedure
Wellhead Orientation Diagram
Wellhead Diagram
As-Built Diagram
Drill Pipe Data Sheet
^pproved Permit to Drill
28 TAB, 8/28/00, v2
,C
I I : ... , . . II
i~'.-" ''" .......... '' ' · ~'I :~V~'~1C~ DR~kE'T 117
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:~'.'." ":'..:'...'..i.'..i~'"?'..'.'.~.!.'.'":.:.'.... '.,' '.'.'.": .... . .' /--~...":.'.'-~ "~... ". ',.' ..
";'~"~':'i~:~."~'~', ~ "'""".' :".'"' ''''''~''~''''''''' ''''~ .... .'" ''~'''-' ~:'~:,:~,,>,,.,~.".. "" "" "."'""~' '
~~ ~~.~~, ~~ . .,'.~....':.'.'...~'~:.......'.~... ~ ~',............... ~.~....~.,.~.~^. ~...i~.....:.......:....?.
!iii:i'i,':,.~.!i~ii:!,:~'.:iiiil.'ii:~.:~.'al~,~ ~~ . :. :...... ,,,......., ..,...,..,..:..,
..`::;...:~!.:!:~:~.:.~:::::~:.~:....:`:~:i.:~:`.:i.~i~ii..~.~`..:~..;:i. :'.':..~~.'~°',.'' :':~",'.:'~.': \~L~ ~ou, .n.t' ovE~.'$~.0~,~..... '., :.'.'
., ~i:!i ~...~;~..~!~.~i~:~..~..~ ~.~.~~~.~..~.~.~..~..~..~'~:~.~..:~:.~.. ....:.....~.~'...~....:~ ~.~:..., ', :.'.:..,'.,...~. ' , .: ~ .,''~ .? :.. ': ,',',..'. :,'...'': .~.~, :....~:~.'?
DATE
WELL PERMIT CHECKLIST
FIELD & POOL
ADMINIS._._..__TRATION 1. Permit fee attached ....................... N
2. Lease number appropriate ................... N
3. Unique well name and.number .................. N
4. Well located in a defined pool .................. , N
5. Well located proper distance from drilling unit boundary... '. ,N
6. Well located proper distance from other wells .......... N
7. Sufficient acreage available in drilling unit ............ N
8. If deviated, is wellbore plat included ............... N
9. Operator only affected party ................... 'N
10. Operator has appropriate bond in force .............
11. Permit can be issued without conservation order ........ FY) N
DATE 12. Permit can be issued without administrative approval ......
~, Z.~'.~ 13. Can permit be approved before 15-day wait ...........
.
ENGINEERING 14. Conductor string provided ................... trY'') N
15. Surface casing protects all known USDWs ........... ~ N
16. CMT vol adequate to circulate on conductor & surf csg ..... N
17. CMT vol adequate to tie-in long string to surf csg ........
18. CMT will cover all known productive horizons ..........
19. Casing designs adequate for C, T, B & permafrost .......
20. Adequate tankage or reserve pit .................
21. If a re-drill, has a 10-403 for abandonment been approved... '
22. Adequate wellbore separation proposed .............
23. If diverter required, does it meet regulations ..........
24. Drilling fluid program schematic & equip list adequate .....
25. BOPEs, do they meet=regulation ................
26. BOPE press rating appropriate; test to.__CC:)C3 ~ psig.
27. Choke manifold complies w/APl RP-53 (May 84) ........
28. Work will occur without operation shutdown ...........
29. Is presence of H2S gas probable ................. {~ N
G_EOLOGY 30.
31.
32.
33.
34.
UNIT#__ ON/OFF SHORE
O
('
O
, -.-I
-!-
Permit can be issued wlo hydrogen sulfide measures .....
Data presented on potential overpressure zones .......
Seismic analysis of shallow gas zones .......... "
,7-----"-A-~<~.'Z~.. c3c:>DATE ContactSeabed name/phoneC°nditi°n su~eYfor (if.off-shore) ..........
weekly progress repo,s~~at6~ only]
ANNULAR DISPOSAL35. With proper ~menting re~rds, this plan ~~
(A) will contain waste ina suitable re~iving zone; .......
APPR DATE (B) ~lls~tam,nate freshwater; or cause drilling waste ....
~ ~ (C) will not impair mechanical inteoritv of the well used for disnosal. [~
'
~ ~. pool, and ·
~ will not circumv
GEOLOGY: ENGINEERING: UICIAnnular COMMISSION:
c:~soffice\wordian~iana\checklist (rev. 02117100)
Sperry-Sun Drilling Services
LIS Scan Utility
SRevision: 3 $
LisLib SRevision: 4 $
Thu Apr 19 09:30:56 2001
Reel Header
Service name ............. LISTPE
Date ..................... 01/04/19
Origin ................... STS
Reel Name ................ UNKNOWN
Continuation Number ...... 01
Previous Reel Name ....... UNKNOWN
Comments ................. STS LIS Writing Library. Scientific
Technical Services
Tape Header
Service name ............. LISTPE
Date ..................... 01/04/19
Origin ................... STS
Tape Name ................ UNKNOWN
Continuation Number ...... 01
Previous Tape Name ....... UNKNOWN
Comments ................. STS LIS Writing Library. Scientific
Technical Services
Physical EOF
Comment Record
TAPE HEADER
Kuparuk River Unit
MWD/MAD LOGS
WELL NAME:
API NUMBER:
OPERATOR:
LOGGING COMPANY:
TAPE CREATION DATE:
JOB DATA
JOB NUMBER:
LOGGING ENGINEER:
OPERATOR WITNESS:
#
SURFACE LOCATION
SECTION:
TOWNSHIP:
RANGE:
FNL:
FSL:
FEL:
FWL:
ELEVATION (FT FROM MSL 0)
KELLY BUSHING:
DERRICK FLOOR:
GROUND LEVEL:
MWD RUN 3
AKMM00172
T. MCGUIRE
M. WINFREE
1D-36
500292297300
PHILLIPS Alaska, Inc.
Sperry Sun
19-APR-01
MWD RUN 4
AKMM00172
R. MCNEILL
M. WINFREE
23
liN
10E
477
420
.00
105.30
70.90
WELL CASING RECORD
OPEN HOLE CASING DRILLERS
BIT SIZE (IN) SIZE (IN) DEPTH (FT)
1ST STRING 8.500 9.625 7047.0
2ND STRING 6.125 7.000 11040.0
3RD STRING
PRODUCTION STRING
REMARKS:
1. ALL DEPTHS ARE MEASURED DEPTHS UNLESS OTHERWISE
NOTED.
2. MWD RUNS 1 & 2 WERE DIRECTIONAL ONLY AND ARE NOT
PRESENTED.
3. MWD RUN 3 WAS DIRECTIONAL WITH DUAL GAMMA RAY (DGR)
UTILIZING
GEIGER-MUELLER TUBE DETECTORS, AND ELECTROMAGNETIC
WAVE
RESISTIVITY PHASE-4 (EWR4).
4. MWD RUN 4 WAS DIRECTIONAL WITH DGR, EWR4,
COMPENSATED THERMAL
NEUTRON POROSITY (CTN), AND STABILIZED LITHO-DENSITY
(SLD) .
5. MWD DATA ARE CONSIDERED PDC PER E-MAIL FROM D.
SCHWARTZ, PHILLIPS
ALASKA, DATED 11/13/00.
6. MWD RUNS 3 & 4 REPRESENT WELL 1D-36 WITH
API9:50-029-22973-00.
THIS WELL REACHED A TOTAL DEPTH (TD) OF 11658'MD /
6542'TVD.
SROP = SMOOTHED RATE OF PENETRATION WHILE DRILLING.
SGRC = SMOOTHED GAMMA RAY COMBINED..
SEXP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (EXTRA
SHALLOW SPACING).
SESP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVIT (SHALLOW
SPACING).
SEMP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (MEDIUM
SPACING).
SEDP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (DEEP
SPACING).
SFXE = SMOOTHED FORMATION EXPOSURE TIME.
TNPS = SMOOTHED THERMAL NEUTRON POROSITY (SANDSTONE
MATRIX, FIXED HOLE SIZE).
CTFA = SMOOTHED AVERAGE OF FAR DETECTOR'S COUNT RATE.
CTNA = SMOOTHED AVERAGE OF NEAR DETECTOR'S COUNT RATE.
SBD2 = SMOOTHED BULK DENSITY-COMPENSATED (LOW-COUNT
BIN).
SCO2 = SMOOTHED STANDOFF CORRECTION (LOW-COUNT BIN).
SNP2 = SMOOTHED NEAR DETECTOR ONLY PHOTOELECTRIC
ABSORPTION FACTOR
(LOW-COUNT BIN).
PARAMETERS USED IN POROSITY LOG PROCESSING:
HOLE SIZE: 6.125"
MUD WEIGHT: 11.2 PPG
MUD SALINITY: 600-650 PPM CHLORIDES
FORMATION WATER SALINITY: 13000 PPM CHLORIDES
FLUID DENSITY: 1.0 G/CC
MATRIX DENSITY: 2.65 G/CC
LITHOLOGY: SANDSTONE
$
File Header
Service name ............. STSLIB.001
Service Sub Level Name...
Version Number ........... 1.0.0
Date of Generation ....... 01/04/19
Maximum Physical Record..65535
File Type ................ LO
Previous File Name ....... STSLIB.000
Comment Record
FILE HEADER
FILE NUMBER: 1
EDITED MERGED MWD
Depth shifted and clipped curves; all bit runs merged.
DEPTH INCREMENT: .5000
FILE SUMMARY
PBU TOOL CODE START DEPTH
RPX 7009.5
RPS 7009.5
RPM 7009.5
RPD 7009.5
GR 7017.0
ROP 7056.5
FET 7057.5
NCNT 10948.0
FCNT 10948.0
NPHI 10948.0
PEF 11025.0
RHOB 11034.0
DRHO 11034.0
$
BASELINE CURVE FOR SHIFTS:
CURVE SHIFT DATA (MEASURED DEPTH)
BASELINE DEPTH
$
MERGED DATA SOURCE
PBU TOOL CODE
MWD
MWD
$
REMARKS:
STOP DEPTH
11612.0
11612.0
11612 0
11612 0
11605 0
11657 5
11612 0
11557 5
11557.5
11557.5
11572.5
11572.5
11572.5
EQUIVALENT UNSHIFTED DEPTH
BIT RUN NO MERGE TOP MERGE BASE
3 7009.5 11047.5
4 10948.0 11657.5
MERGED MAIN PASS.
$
Data Format Specification Record
Data Record Type .................. 0
Data Specification Block Type ..... 0
Logging Direction ................. Down
Optical log depth units ........... Feet
Data Reference Point .............. Undefined
Frame Spacing ..................... 60 .liN
Max frames per record ............. Undefined
Absent value ...................... -999
Depth Units .......................
Datum Specification Block sub-type...0
Name
DEPT
GR
ROP
RPX
RPS
RPM
RPD
FET
NPHI
FCNT
NCNT
RHOB
DRHO
PEF
Service Order Units Size Nsam Rep
FT 4 1 68
MWD A?I 4 1 68
MWD FT/H 4 1 68
MWD OHMM 4 1 68
MWD OHMM 4 1 68
MWD OHMM 4 1 68
MWD OHMM 4 1 68
MWD HOUR 4 1 68
MWD PU-S 4 1 68
MWD CNTS 4 1 68
MWD CNTS 4 1 68
MWD G/CM 4 1 68
MWD G/CM 4 1 68
MWD BARN 4 1 68
Code,Offset Channel
0 1
4 2
8 3
12 4
16 5
20 6
24 7
28 8
32 9
36 10
40 11
44 12
48 13
52 14
Last
Name Service Unit Min Max
Reading
DEPT FT 7009.5 11657.5
11657.5
GR MWD API 48.23 448.19
11605
ROP MWD FT/H 0 39883.5
11657.5
RPX MWD OHMM 0.3 79.11
11612
RPS MWD OHMM 1.22 1755.61
11612
RPM MWD OHMM 0.89 2000
11612
RPD MWD OHMM 0.41 2000
11612
FET MWD HOUR 0.21 85.29
11612
NPHI MWD PU-S 24.17 58.27
11557.5
FCNT MWD CNTS 129.5 627
11557.5
NCNT MWD CNTS 16511.4 33192.9
11557.5
RHOB MWD G/CM 2.047 3.314
11572.5
DRHO MWD G/CM -0.331 0.55
11572.5
PEF MWD BARN 4.07 15.5
11572.5
Mean Nsam
9333.5 9297
137.592 9177
170.615 9203
3.96531 9206
4.71044 9206
10.3494 9206
19.8299 9206
1.56069 9110
38.8076 1220
276.363 1220
22258.2 1220
2.45972 1078
0.0577718 1078
6.62786 1096
First
Reading
7009.5
7017
7056.5
7009.5
7009.5
7009.5
7009.5
7057.5
10948
10948
10948
11034
11034
11025
First Reading For Entire File .......... 7009.5
Last Reading For Entire File ........... 11657.5
File Trailer
Service name ............. STSLIB.001
Service Sub Level Name...
Version Number ........... 1.0.0
Date of Generation ....... 01/04/19
Maximum Physical Record..65535
File Type ................ LO
Next File Name ........... STSLIB.002
Physical EOF
File Header
Service'name ............. STSLIB.002
Service Sub Level Name...
Version Number ........... 1.0.0
Date of Generation ....... 01/04/19
Maximum Physical Record..65535
File Type ................ LO
Previous File Name ....... STSLIB.001
Comment Record
FILE HEADER
FILE NUMBER: 2
RAW MWD
Curves and log header data for each bit run in separate files.
BIT RUN NUMBER: 3
DEPTH INCREMENT: .5000
#
FILE SUMMARY
VENDOR TOOL CODE START DEPTH STOP DEPTH
RPX 7009 5 11000.5
RPS 7009 5 11000.5
RPD 7009 5 11000.5
RPM 7009 5 11000.5
GR 7017 0 11007.5
ROP 7056 5 11047.5
FET 7057 5 11000.5
$
LOG HEADER DATA
DATE LOGGED: ll-SEP-00
SOFTWARE
SURFACE SOFTWARE VERSION:
DOWNHOLE SOFTWARE VERSION:
DATA TYPE (MEMORY OR REAL-TIME):
TD DRILLER (FT):
TOP LOG INTERVAL (FT):
BOTTOM LOG INTERVAL (FT):
BIT ROTATING SPEED (RPM):
HOLE INCLINATION (DEG
MINIMUM ANGLE: 59.6
MAXIMUM ANGLE: 61.8
TOOL STRING (TOP TO BOTTOM)
VENDOR TOOL CODE TOOL TYPE TOOL NUMBER
Insite
65.4099960327148
Memory
11048.0
7056.0
11048.0
DGR
EWR4
$
DUAL GAMMA RAY
ELECTROMAG. RESIS. 4
BOREHOLE AND CASING DATA
OPEN HOLE BIT SIZE (IN):
DRILLER'S CASING DEPTH (FT):
BOREHOLE CONDITIONS MUD TYPE:
MUD DENSITY (LB/G):
MUD VISCOSITY (S):
MUD PH:
MUD CHLORIDES (PPM):
FLUID LOSS (C3):
RESISTIVITY (OHMM) AT TEMPERATURE (DEGF)
MUD AT MEASURED TEMPERATURE (MT):
MUD AT MAX CIRCULATING TERMPERATURE:
MUD FILTRATE AT MT:
MUD CAKE AT MT:
NEUTRON TOOL
MATRIX:
MATRIX DENSITY:
HOLE CORRECTION (IN):
TOOL STANDOFF (IN):
EWR FREQUENCY (HZ):
REMARKS:
$
Data Format Specification Record
Data Record Type .................. 0
Data Specification Block Type ..... 0
Logging Direction ................. Down
Optical log depth units ........... Feet
Data Reference Point .............. Undefined
Frame Spacing ..................... 60 .lin
Max frames per record ............. Undefined
Absent value ...................... -999
Depth Units ........................
Datum Specification Block sub-type...0
PB01599HWGR6
PB01599HWGR6
8.500
Water Based
9.00
44.0
8.5
600
7.4
4.500
2.012
4.500
3.300
66.0
156.0
62.0
66.0
Name Service Order Units Size Nsam Rep Code Offset Channel
DEPT FT 4 1 68 0 1
GR MWD030 API 4 1 68 4 2
ROP MWD030 'FT/H 4 1 68 8 3
RPX MWD030 OHMM 4 1 68 12 4
RPS MWD030 OHMM 4 1 68 16 ,5
RPM MWD030 OHMM 4 1 68 20 6
RPD MWD030 OHMM 4 1 68 24 7
FET MWD030 HOUR 4 1 68 28 8
Last
Name Service Unit Min Max Mean Nsam
Reading
DEPT FT 7009.5 11047.5 9028.5 8077
First
Reading
7009.5
11047.5
GR MWD030 API 54.45 448.19
11007.5
ROP MWD030 FT/H 0 39883.5
11047.5
RPX MWD030 OHMM 0.46 79.11
11000.5
RPS MWD030 OHMM 1.22 1755.61
11000.5
R?M MWD030 OHMM 0.89 953.6
11000.5
RPD MWD030 OHMM 1.17 2000
11000.5
FET MWD030 HOUR 0.21 6.58
11000.5
141.886
180.99
3.51281
4.11771
4.30333
13.9766
0.646881
7982
7983
7983
7983
7983
7983
7887
7017
7056.5
7009.5
7009.5
7009.5
7009.5
7057.5
First Reading For Entire File .......... 7009.5
Last Reading For Entire File ........... 11047.5
File Trailer
Service name ............. STSLIB.002
Service Sub Level Name...
Version Number ........... 1.0.0
Date of Generation ....... 01/04/19
Maximum Physical Record..65535
File Type ................ LO
Next File Name ........... STSLIB.003
Physical EOF
File Header
Service name ............. STSLIB.003
Service Sub Level Name...
Version Number ........... 1.0.0
Date of Generation ....... 01/04/19
Maximum Physical Record..65535
File Type ................ LO
Previous File Name ....... STSLIB.002
Comment Record
FILE HEADER
FILE NUMBER: 3
RAW MWD
.Curves and log header data for each bit run in separate files.
BIT RUN NUMBER.: 4
DEPTH INCREMENT: .5000
#
FILE SUMMARY
VENDOR TOOL CODE START DEPTH STOP DEPTH
NPHI 10948.0 11557.5
FCNT 10948.0 11557.5
NCNT 10948.0 11557.5
RPD 11001.0 11612.0
RPX 11001.0 11612.0
RPM 11001.0 11612.0
FET 11001.0 11612.0
RPS 11001.0 11612.0
GR 11008.0
PEF 11025.0
RHOB 11034.0
DRHO 11034.0
RO? 11048.0
$
LOG HEADER DATA
DATE LOGGED:
SOFTWARE
SURFACE SOFTWARE VERSION:
DOWNHOLE SOFTWARE VERSION:
DATA TYPE (MEMORY OR REAL-TIME):
TD DRILLER (FT):
TOP LOG INTERVAL (FT):
BOTTOM LOG INTERVAL (FT):
BIT ROTATING SPEED (RPM):
HOLE INCLINATION (DEG
MINIMUM ANGLE:
MAXIMUM ANGLE:
11605.0
11572.5
11572.5
11572.5
11657.5
TOOL STRING (TOP TO BOTTOM)
VENDOR TOOL CODE TOOL TYPE
DGR DUAL GAMMA RAY
EWR4 ELECTROMAG. RESIS. 4
SLD STABILIZED LITHO DEN
CTN COMP THERMAL NEUTRON
$
BOREHOLE AND CASING DATA
OPEN HOLE BIT SIZE (IN):
DRILLER'S CASING DEPTH (FT):
BOREHOLE CONDITIONS MUD TYPE:
MUD DENSITY (LB/G):
MUD VISCOSITY (S):
MUD PH:
MUD CHLORIDES (PPM):
FLUID LOSS (C3):
RESISTIVITY (OHMM) AT TEMPERATURE (DEGF)
MUD AT MEASURED TEMPERATURE (MT):
MUD AT MAX CIRCULATING TERMPERATURE:
MUD FILTRATE AT MT:
MUD CAKE AT MT:
NEUTRON TOOL
MATRIX:
MATRIX DENSITY:
HOLE CORRECTION (IN):
TOOL STANDOFF (IN):
EWR FREQUENCY (HZ):
REMARKS:
$
Data Format Specification Record
Data Record Type .................. 0
Data Specification Block Type ..... 0
Logging Direction ................. Down
15-SEP-00
Insite
0.41
Memory
11658.0
11048.0
11658.0
60.8
62.3
TOOL NUMBER
1643/1645
1643/1645
1643/1645
1643/1645
6.125
Water Based
11.20
56.0
8.8
6OO
3.4
2.000
1.112
4.000
2.200
74.0
138.5
74.0
74.0
Optical log depth units ........... Feet
Data Reference Point .............. Undefined
Frame Spacing ..................... 60 .liN
Max frames per record ............. Undefined
Absent value ...................... -999
Depth Units .......................
Datum Specification Block sub-type...0
Name
DEPT
GR
ROP
RPX
RPS
RPM
RPD
FET
NPHI
FCNT
NCNT
RHOB
DRHO
PEF
Service Order Units Size Nsam Rep Code Offset Channel
FT 4 1 68 0 1
MWD040 API 4 1 68 4 2
MWD040 FT/H 4 1 68 8 3
MWD040 OHMM 4 1 68 12 4
MWD040 OHMM 4 1 68 16 5
MWD040 OHMM 4 1 68 20 6
MWD040 OHMM 4 1 68 24 7
MWD040 HOUR 4 1 68 28 8
MWD040 PU-S 4 1 68 32 9
MWD040 CNTS 4 1 68 36 10
MWD040 CNTS 4 1 68 40 11
MWD040 G/CM 4 1 68 44 12
MWD040 G/CM 4 1 68 48 13
MWD040 BARN 4 1 68 52 14
Last
Name Service Unit Min Max Mean Nsam
Reading
DEPT FT 10948 11657.5 11302.8 1420
11657.5
GR MWD040 API 48.23 250.61 108.912 1195
11605
ROP MWD040 FT/H 0.8 806.86 102.723 1220
11657.5
RPX MWD040 OHMM 0.3 42.13 6.91897 1223
11612
RPS MWD040 OHMM 1.85 1257.04 8.57946 1223
11612
RPM MWD040 OHMM 0.96 2000 49.8147 1223
11612
RPD MWD040 OHMM 0.41 2000 58.0368 1223
11612
FET MWD040 HOUR 0.34 85.29 7.45379 1223
11612
NPHI MWD040 PU-S 24.17 58.27 38.8076 1220
11557.5
FCNT MWD040 CNTS 129.5 627 276.363 1220
11557.5
NCNT MWD040 cNTS 16511.4 33192.9 22258.2 1220
11557.5
RHOB MWD040 G/CM 2.047 3.314 2.45972 1078
11572.5
DRHO MWD040 G/CM -0.331 0.55 0.0577718 1078
11572.5
PEF MWD040 BARN 4.07 15.5 6.62786 1096
11572.5
First
Reading
10948
11008
11048
11001
11001
11001
11001
11001
10948
10948
10948
11034
11034
11025
First Reading For Entire File .......... 10948
Last Reading For Entire File ........... 11657.5
File Trailer
Service name ............. STSLIB.003
Service Sub Level Name...
Version Number ........... 1.0.0
Date of Generation ....... 01/04/19
Maximum Physical Record..65535
File Type ................ LO
Next File Name ........... STSLIB.004
Physical EOF
Tape Trailer
Service name ............. LISTPE
Date ..................... 01/04/19
Origin ................... STS
Tape Name ................ UNKNOWN
Continuation Number ...... 01
Next Tape Name ........... UNKNOWN
Comments ................. STS LIS Writing Library.
Technical Services
Reel Trailer
Service name ............. LISTPE
Date ..................... 01/04/19
Origin ................... STS
Reel Name ................ UNKNOWN
Continuation Number ...... 01
Next Reel Name ........... UNKNOWN
Comments ................. STS LIS Writing Library.
Technical Services
Scientific
Scientific
Physical EOF
Physical EOF
End Of LIS File
