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Post Office Box 244027
Anchorage, AK 99524-4027
3800 Centerpoint Drive
Suite 1400
Anchorage, AK 99503
Phone: (907) 564-4891
07/16/2024
Mr. Mel Rixse
Alaska Oil and Gas Conservation Commission
333 West 7th Avenue, Suite 100
Anchorage, Alaska 99501
Re: Prudhoe Bay Surface Casing by Conductor Annulus Top-offs of Cement, Corrosion Inhibitor
through 07/16/2024.
Dear Mr. Rixse,
Enclosed please find a copy of a spreadsheet with a list of Prudhoe Bay wells that were topped-off
with cement, corrosion inhibitor in the surface casing by conductor annulus through 07/16/2024.
Cement top-offs are executed as needed to mitigate the void space left at surface by minor cement
fallback during the primary surface casing by conductor cement job. The remaining void space
between the top of the cement and the top of the conductor is filled with a heavier than water
corrosion inhibitor to reduce the risk of external surface casing corrosion. The attached
spreadsheets include the well names, API and PTD numbers, treatment dates and volumes.
As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that
the treatments took place and meet the requirements of form 10-404 Report of Sundry Operations.
If you have any additional questions, please contact me at 564-4891 or
oliver.sternicki@hilcorp.com.
Sincerely,
Oliver Sternicki
Well Integrity Supervisor
Hilcorp North Slope, LLC
Digitally signed by Oliver Sternicki
DN: cn=Oliver Sternicki, c=US, o=Hilcorp North Slope
LLC, ou=PBU, email=oliver.sternicki@hilcorp.com
Date: 2024.07.16 13:47:34 -08'00'
Hilcorp North Slope LLC.
Surface Casing by Conductor Annulus Cement, Corrosion Inhibitor
Top-off
Report of Sundry Operations (10-404)
7/16/2024
Well Name PTD #API #
Initial top
of cement
(ft)
Vol. of
cement
pumped
(gal)
Final top
of cement
(ft)
Cement top
off date
Corrosion
inhibitor
(gal)
Corrosion
inhibitor/ sealant
date
L-246 223078 500292376500 11 3/23/2024
L-247 223081 500292376600 14 3/23/2024
L-252 223095 500292376800 17 3/23/2024
L-295 223115 500292377400 11 3/23/2024
RBDMS JSB 071924
L-247 223081 500292376600 14 3/23/2024
"
By Grace Christianson at 7:53 am, Nov 30, 2023
Completed
11/1/2023
JSB
RBDMS JSB 120823
GDSR-1/26/24
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662),
ou=Users
Date: 2023.11.27 14:38:16 -09'00'
Torin
Roschinger
(4662)
Drilling Manager
11/27/23
Monty M
Myers
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBU L-247 Date:10/18/2023
Csg Size/Wt/Grade:9 5/8 47 & 40 #L-80 Supervisor:James Lott
Csg Setting Depth:6140 TMD 4492 TVD
Mud Weight:9.15 ppg LOT / FIT Press =665 psi
LOT / FIT =12.00 ppg Hole Depth =6166 md
Fluid Pumped=2.3 Bbls Volume Back =2.3 bbls
Estimated Pump Output:0.062 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter P9.15ressure Enter Strokes 665
Here Here Here Here
->00 ->031
->263 ->277
->4133 ->4143
->6218 ->6223
->8299 ->8305
->10 374 ->10 373
->12 433 ->12 445
->14 502 ->14 517
->16 567 ->16 580
->18 627 ->18 647
->20 660 ->20 715
->21 665 ->45 1643
-> ->65 2448
-> ->70 2702
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0665 ->02702
->1645 ->52684
->2635 ->10 2678
->3627 ->15 2672
->4619 ->20 2667
->5613 ->25 2663
->6607 ->30 2658
->7603 ->
->8597 ->
->9593 ->
->10 588 ->
-> ->
-> ->
-> ->
0
2
4
6
8
10
12
14
16
18
2021
0
2
4
6
8
10
12
14
16
18
20
45
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
0 1020304050607080
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
665645635627619613607603597593588
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
0 5 10 15 20 25 30
Pr
e
s
s
u
r
e
(
p
s
i
)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
Wellname: PBW L-247
Rig: Innovation
API Number: 50-029-23766-00-00
Well Permit Number: 223-081
Spud Date: 10/10/23
Date Summary
10/08/23
Move sub to L-247. Spot and level Sub over L-247. Set rig matts and spot catwalk, pipe shed, gen mod &
mud mod. Trucks released at 19:30. SIMOPS remove old bridal lines. Paint new shaker rack in shop.
Adjust stompers on Sub and stage Sub. Move rig matts to L-247. PJSM Electrician start plugging in leads
to main board. Safe out stairs and landings. Install inner connects. Rig on Gen power at 20:30. Install
flow line, cement and gas buster lines in pits. Turn on steam and H2O throughout rig. Cont taking down
old bridal lines. Spot break shack and enviro vac. PJSM Send down old bridal lines. Install new bridal
lines (X6). Bridal up top drive. Install DSA, Tee and stack. Secure stack. Start installing diverter sections
under mods.
10/09/23
Continue with Rig Acceptance Check List. R/U Knife Valve, install 16 vent line to edge of Pad. R/U
Bleeder on manifold. NOV Rep and Mech trouble shoot Hyd Elevators. Take on Spud Mud to Pits.
Function tested all surface equipment in pits, re-plumb jest in Possum Belly. Install 4 Ball Valve on
conductor w/black water hook up. Verify DP Ser. No.'s. Continue to N/U Diverter System. Crane on
location @ 1300 hrs released at 16:30. Utilize crane to set vent line sections/stands and mat board off
Pad. Line up and pump through bleeder with MP 1 & 2. Install trip nipple flange on stack. Install trip
nipple. work on Hyd Plumbing to Elevators on TD. PJSM Remove old kelly hose from pipe shed. Install
solid bushing in rotary table. Obtain RKB. Pressure up Koomey and set Annular to 300 psi. Install mouse
hole in rotary table. Bring on 290 bbls 8.8 ppg Spud Mud to pits. Calibrate Bale angle sensor. Wire tie
safety clips for Bail angle adjusters, install Hyd Elevator inserts. Plumb in HP Cement line in Mezzanine.
Rig accepted at 20:00. PJSM P/U M/U 80 jnts (40 stands) 5" 19.5# S-135 NC50 D.P. and rack back in
derrick. Drift off skate 3.125" OD. Adjusted kelly hose and hydraulic elevator harness. PJSM P/U M/U
120 jnts (60 stands) 5" 19.5# S-135 NC50 D.P. & 17 jnts & jar (9 stands) 5" HWDP 49# S-235 NC50 HWDP
and rack back in derrick. Drift off skate 3.125" OD & 2.75" OD. Use 5 D.P. Perform Annular closure 11
sec, knife 6 sec. Test H2S 10-20 ppm, LEL 20-40%, PVT high/ low level alarms. Checked PVT sensors and
return flow. Koomey draw drown Initial System 3,000 PSI, after System 2,000 PSI, 200 PSI increase 11
Sec, full charge 44 sec. Nitrogen 6 bottle average,2,292 PSI. Witnessed by AOGCC Brian Bixby. PJSM R/U
rig tongs, double lines & sensator. P/U Bottle nose X/O, 1.5 deg motor and 12.25" bit.
Hilcorp Alaska, LLC
HEC Composite
Well Operations Summary
10/10/23
Pull Bushing and make up wear ring running tool and set wear ring. Daily disposal G&I: 0. Total disposal
G&I: 0. Daily disposal MPU G&I: 0. Total disposal MPU G&I: 0. Daily H2O Lake 2: 180 bbls. Total H2O
Lake 2: 180 bbls,Pickup 12.25" Kymera (K5M633) bit and 8" Motor (4/5 Lobe). Run in the hole and tag
fill at 76'. Pressure test surface lines to 3,000psi - Good. Wash down F/76' - T/107'. Drill 12.25" Surface
hole F/107' - T/218'. 400gpm=525psi, RF=56%. 40RPM=1-2Kft-lbs TQ at 1-5K WOB. P/U=44K,
ROTW=45K, S/O=43K. Pumping down the bleeder and jetting the flowline as necessary. Backream
F/218' - T/Surface. Racking back 3 stands of 5" HWDP. 400gpm=525psi, RF=55%. 40RPM=1Kft-lbs TQ.
P/U=44K, ROTW=45K S/O=43K. PJSM - P/U Directional BHA. RIH with 12.25" Bit and Motor. Pickup 8"
GWD and 8" BaseStar as per Sperry Reps. Continue Picking up BHA - Pickup 8" Resistar, I-Star Battery,
EWR, TM, and NM Flex Collars. RIH on 5" HWDP. Motor to MWD 14.66deg, MWD to Gyro 151.8deg.
Wash Down F/189' - T/217' MD, No fill. Drill F/217' - T/244' MD. 400gpm=730/685psi on/off,
ECD=9.17ppg, 40RPM, TQ=1.5/1Kft-lbs on/off, WOB=3-6K, ROTW=54K, P/U=58K, S/O58K. KOP=217'.
Slide/Drill F/244' - T/432 control drilling at 100fph. At 244' POOH 2 stands (TM Collar) to verify scribe
location for correlation. MWD Real time reading 60deg difference from Gyro - Verified and validated
data on programs. RIH T/244' pumped a survey and verified Gyro and MWD reading same. Stopped
observing gravels at the shakers at 392'. 400gpm=740/695psi on/off, ECD=9.53ppg, RF=66%. 40RPM=2-
2.5/1.5Kft-lbs on/off TQ, WOB=3-5K. ROTW=57K, P/U=59K, S/O=62K. Pumping through the bleeder to
reduce the flowline packing off. Slide/Drill F432' - T/964' MD (934' TVD), Total: 532' (AROP: 89').
450gpm=1235/1125psi on/off, ECD=9.71ppg, RF=56%. 40RPM=4-5/1-2Kft-lbs on/off TQ, WOB=6-12K.
RTOW=46K, P/U=76K, S/O=58K. Jetting Flow line continuously and pumping through the bleeder as
needed.
10/11/23
Slide/Drill 12-1/4" Surface Hole F/964' - T/1,546' MD (1,430' TVD). Total 582' (AROP: 97fph). Last Gyro
Survey was at 1,085'. Finished the 4deg/100' build at 1,254'. 450gpm=1256/1101psi on/off,
ECD=10.8ppg, RF=58%. 80RPM=5-7/3Kft-lbs on/off TQ, WOB=8-14K. ROTW=76K, P/U=82K, S/O=73K.
Daily disposal G&I: 171. Total disposal G&I: 171. Daily disposal MPU G&I: 57. Total disposal MPU G&I:
57. Daily H2O Lake 2: 300 bbls. Total H2O Lake 2: 480 bbls,Distance from WP05: 22.96', 22.96 Low, 0.09'
Left. Drill 12-1/4" Surface Hole F/1,546' - T/2,327' MD (2,054' TVD). Total 781' (AROP: 131fph).
Maintaining ~36deg tangent as per DD/WP05. BPRF at 1,930' per GEO. Backreaming full stands.
550gpm=1695/1595psi on/off, ECD=10.8ppg, RF=72%. 80RPM=5-6/5Kft-lbs on/off TQ, WOB=8-12K.
ROTW=87K, P/I=96K, S/O=81K. Drill 12-1/4" Surface Hole F/2,327' - T/3,353' MD (2,866 TVD). Total
1,026' (AROP: 171fph). Maintaining ~36deg tangent as per DD/WP05. Backreaming full stands.
550gpm=2010/1810psi on/off, ECD=10.85ppg, RF=64%. 80RPM=8/6-7Kft-lbs TQ, WOB=6-12K.
ROTW=97K, P/U=117K, S/O=82K. Drill 12-1/4" Surface Hole F/3,353' - T/3,970 MD (3,294' TVD). Total
617' (AROP: 103fph). Maintaining ~36deg tangent as per DD/WP05. Backreaming full stands. Close
approach at 3,490' MD to L-100, 1.41SF and 34.25' Edge of Separation - No issues.
10/12/23
Daily disposal G&I: 684. Total disposal G&I: 855. Daily disposal MPU G&I: 285. Total disposal MPU G&I:
342. Daily H2O Lake 2: 820 bbls. Total H2O Lake 2: 1300 bbls,550gpm=1935/1762psi on/off,
ECD=10.65ppg, RF=66%. 80RPM=8-10/8-10Kft-lbs on/off TQ, WOB=7-12K. Max Gas=809u. ROTW=108K,
P/U=134K, S/O=92K. Distance from WP05: 21.82' from plan, 0.08' Low, 21.82' Right. Drill/Slide 12-1/4"
Surface Section F/3,970' - T/4,337' MD (3,670' TVD). Total: 367' (AROP:62fph). Maintaining the 36deg
Tangent as per DD/WP05. Backreaming 60'. 550gpm=1971/1890psi on/off, ECD=10.85ppg, RF=62%.
80RPM=8-10/6-7Kft-lbs on/off TQ, WOB=6-12K. ROTW=101K, P/U=142K, S/O=90K. Drill/Slide 12-1/4"
Surface Section F/4,337' - T/4,747' MD (3,981' TVD). Total: 410' (AROP:69fph). Begin 5deg/100'
build/turn at 4,430' MD as per DD/WP05. Backreaming 60'. 550gpm=2010/1925psi on/off,
ECD=10.32ppg, RF=64%. 80RPM=9-12/8-10Kft-lbs on/off TQ, WOB=6-12K. ROTW=115K, P/U=150K,
S/O=99K. Drill/Slide 12-1/4" Surface Section F/4,747' - T/5,131' MD (4,244' TVD). Total: 384'
(AROP:64fph). Maintain 5deg/100' build/turn as per DD/WP05. Backreaming 60'. 550gpm=1850/1790psi
on/off, ECD=10.13ppg, RF=64%. 80RPM=10-13/9-12Kft-lbs on/off TQ, WOB=6-10K. ROTW=126K,
P/U=155K, S/O=98K. Drill/Slide 12-1/4" Surface Section F/5,131' - T/5,512' MD (4,410' TVD). Total: 381'
(AROP:64fph). Maintain 5deg/100' build/turn as per DD/WP05. Backreaming 60'. 550gpm=1960/1830psi
on/off, ECD=10.17ppg, RF=65%. 80RPM=10-13/11-13Kft-lbs on/off TQ, WOB=4-8K. ROTW=125K,
P/U=151K, S/O=98K.
10/13/23
Drill/Slide 12-1/4" Surface F/5,512' - T/5,894' MD (4,480' TVD). Total: 382' (AROP:64fph). Maintain
5deg/100' build/turn as per DD/WP05. 550gpm=2050/1890psi on/off, MW=9.6/9.75ppg in/out,
ECD=10.36ppg, RF=63%, Max Gas=868u. 80RPM=10-14/10-13Kft-lbs on/off TQ, WOB=5-10K.
ROTW=118K, P/U=148K, S/O=94K. Daily disposal G&I: 897. Total disposal G&I: 1752. Daily disposal MPU
G&I: 313. Total disposal MPU G&I: 655. Daily H2O Lake 2: 1230 bbls. Total H2O Lake 2: 2530
bbls,Pumped a 50bbl Hi-Vis Walnut sweep to aid in Slide ROP at 5,220' MD - No noticeable help.
Distance from WP05: 9.08' from plan, 4.6' Low, 7.8' Right. Drill/Slide 12-1/4" Surface F/5,894' - T/6,146'
MD (4,494' TVD). Total: 252' (AROP:42fph). Maintain 5deg/100' build/turn as per DD/WP05.
550gpm=2231/1986psi on/off, MW=9.6/9.7ppg in/out, ECD=10.30ppg, RF=63%, Max Gas=1032u.
80RPM=12-15/10-13Kft-lbs on/off TQ, WOB=5-12K. ROTW=110K, P/U=150K, S/O=91K. GEO called
Surface TD - Obtained Final Survey projections at 6,146' MD (4,494' TVD): 88.40 INC, 298.65 AZM.
Projection from WP05: 5.17' from plan, 1.5' Low, 4.95' Left. POOH F/6,146' - T/6,075' MD racking back 1
stand and circulate a bottoms up. Rack back another stand and pump 50 bbl Hi-Vis sweep. observed on
time with no increase in cuttings at shakers. Circulate another bottoms up while holding PJSM for
Backreaming operations. 550gpm=1470psi, RF=60%, ECD=10.32ppg. Max Gas=1457u. 80RPM=8-12Kft-
lbs TQ. ROTW=112K, P/U=150K, S/O=91K. RIH with 2 stands and flow checked the well for 10min -
Good. BROOH F/6,146' - T/4,110' MD, pulling 25-35fpm. Reduced from 80RPM to 60RPM at 40deg
inclination at 4500' MD. 550gpm=1830psi, MW=9.45/9.75ppg in/out, ECD=10.02ppg, RF=55%. Max
Gas=382u. 60RPM=7-10Kft-lbs TQ. ROTW=118K, P/U=152K, S/O=92K. BROOH F/4,110' - T/1,550' MD,
pulling 15-25fpm. At 2,266' reduced pulling speed for 4 stands to ensure 2x BU have been pumped prior
to coming up into the BPRF (1,930' MD). Observed erratic torque swings from 6-11Kft-lbs TQ F/2,060' -
T/1,910 as we pulled up through the BPRF.
10/14/23
BROOH F/1,550' - T/188' MD, pulling 2-10fpm. Hole unloaded at 500' with heavy sands. 450gpm=820psi,
MW=9.55/9.75ppg in/out, ECD=9.99ppg, RF=60%. Max Gas=533u. 30RPM=2-9ft-lbs TQ. ROTW=58K,
P/U=62K, S/O=52K. No losses. Daily disposal G&I: 746. Total disposal G&I: 2498. Daily disposal MPU
G&I: 689. Total disposal MPU G&I: 1344. Daily H2O Lake 2: 1280 bbls. Total H2O Lake 2: 3810
bbls,500gpm=1266psi, MW=9.6/9.75ppg in/out, ECD=10.46ppg, RF=66%. Max Gas=725u. 60RPM=6-
12Kft-lbs TQ. ROTW=85K, P/U=127K, S/O=72K. Flow check well for 10 mins at BHA - No flow. L/D BHA:
NM Flex, Stabilizers, TM, DM, PWD, GWD collars, Mud Motor and Bit (PDC: 1-3-CT-A-X-I-ER-TD, Roller: 2-
3-WT-A-F-I-LT-TD). No losses. Clean and clear rig floor. Clean and clear the rig floor. Pressure wash floor
and surface equipment. Remove 5" Elevators. Haul 60 centralizers to rig floor. Move FH-80 out of the
way. Swap floor bushings. Rig down rig tongs. PJSM - Picking up Casing handling equipment. R/U 9-5/8"
Volant (TQ to 30Kft-lbs), Casing tongs, slips, elevators (250 ton) and verify with mandrel - Good. 159
joints in shed including shoe track and ES Cementer. PJSM - Run 9-5/8" 40# L-80 TXP Casing F/Surface -
T/1,177 MD, running ~50fpm. Torquing 40# to 20,960ft-lbs. Check Floats on Shoe and Float collar -
Good. Fill pipe and drop bypass baffle in Float collar joint. M/U HES Baffle adaptor. Applied Forum-Lok
to all joints of shoe track and Joint #5 pin. Filling Every 5 joints and breaking circulation every 10 joints.
Loss of 5.6bbls on Trip. RIH with 9-5/8" encountering tight spot F/1,062' - T/1,177' (6/6/9/7/4deg
Doglegs). Wash Down at 1-3BPM, TQ Stalling 15Kft-lbs at 3RPM, working thru at 1-5fpm. Continue
washing down and working tight spot F/1,177' - T/1,242' at 1-5fpm. 1-3BPM=100psi. 3-5RPM, TQ
stalling at 15Kft-lbs. RIH F/1,242' - T/1,359' Washing down at 1-3BPM=105psi, no rotary and running at
25fpm. RIH F/1,359' - T/2,265' MD on Elevators running at 20-40fpm. P/U=108K, S/O=73K,
ROTW=86K,RIH T/2,265' CSG MD. Staged pumps up to 6BPM=135psi. Circulated 1.5x bottoms up while
rotating and reciprocating at 5RPM=6-8Kft-lbs TQ. observing heavy sand at the shakers. Max
Gas=1063u. RF=29%. Reciprocate F/2,265' - T/2,307' MD. P/U=110K, S/O=78K, ROTW=90K. No Losses.
Run 9-5/8" 40# L-80 TXP Casing F/2,307' - T/2,783' MD Torquing to 20,960ft-lbs and installing
centralizers as per tally. Running Speed 20-40fpm. P/U=114K, S/O=82K, ROTW=94K. Continue to fill
every 5 joints and break circulation every 10 joints.
10/15/23
Run 9-5/8" 40# L-80 TXP Casing F2,783' - T/4,078' MD Torquing to 20,960ft-lbs and installing centralizers
as per tally. M/U ES Cementer as per HES Rep. RIH with 47# CSG torquing to 23,820ft-lbs F/4,078'-
T/4,491' MD Running Speed 35-45fpm. P/U=180K, S/O=98K. Circulate a bottoms up while rotating and
reciprocating F/4,491' - T/4,532' CSG MD. Stage pump up to 7BPM=195psi, RF=38%, MW 9.5/9.6ppg
in/out. 3RPM=14Kft-lbs TQ Stall set. Max Gas=805u. P/U=195K, S/O=105K, ROTW=125K. No losses.
Heavy sands at shakers. RIH with 47# L-80 TXP-BTC CSG torquing to 23,820ft-lbs F/4,532'-T/5,260' CSG
MD Running Speed 35-45fpm. P/U=242K, S/O=118K. RIH with 47# L-80 TXP-BTC CSG torquing to
23,820ft-lbs F/5,260'-T/6,141' CSG MD Running Speed 35-45fpm. Loss=35.5bbls, Calc=85.9, Act=59.3.
P/U=228K, S/O=118K. Condition Mud <20YP while rotating and reciprocating F/6,141' - T/6,127' CSG
MD. Stage pump up to 6BPM=244psi, RF=27%, MW 9.5/9.6ppg in/out. 3RPM=14Kft-lbs TQ Stall set.
P/U=224K, S/O=134K. Dynamic loss rate of 10bph. loss of 30bbls. Heavy sands at shakers. R/D CSG
Equipment. PJSM - 1st stage Cement Job. Fill lines and Pressure test to 1000/4000psi 5/5mins - Good.
HES Pump 60bbls 10.0ppg Tuned Spacer (4#Red dye, 5#Pol-E-Flake, 1.23 yield) at 5bpm (ICP=330psi,
FCP=439psi). Drop Bypass Plug. HES Pumped 222bbls 12.0ppg EconoCem Lead Cement (2.347 Yield,
531sxs) at 6bpm (ICP=696psi, FCP=648psi). Wet at 18:04. Loss of 55bbls during the duration of the job.
Observed 60bbls of contaminated mud/spacer to surface and 5bbls of cement at surface. Rotated and
reciprocated during the entire job at 3RPM=14Kft-lbs TQ Stall set. Started losing down weight
S/O=100k, decision was made to park it at 6,138'. Circulate and condition for 2nd stage cement at
3bpm=470psi for 3x BU RF=29%. Stage pumps up to 5bpm=577psi, RF=33%. SIMOPS: Process 5" DP in
shed. Rest Cementers. HES Pump 82bbls HalCem Tail Cement (1.155 Yield, 400sxs) at 4.6bpm
(ICP=780psi, FCP=834psi) Wet at 18:48. Drop Shutoff Plug. HES Pump 24bbls H2O to clear lines. Rig
Pump 238bbls (3,839 Strokes) 9.5ppg Mud, initially at 6bpm (ICP=288psi, FCP=331psi), observing a loss
of 1-2bbls for every 10bbls pumped. Reduce Rate to 5bpm (ICP=232psi, FCP=240psi), Reduce rate to
4bpm (ICP=175psi, FCP=200psi). HES Pump 80bbls of Tuned Spacer (17.39 Yield) at 3bpm (ICP=190psi,
FCP=350psi). Rig Pump 108bbls (1,742 strokes, 4 bbls early from excess water pumped) at 3bpm
(ICP=400psi, FCP=780psi) Bumped plug on time. CIP 21:02. Increased pressure to 1,306psi against plug
and held for 5 mins. Bleed pressure off - Floats holding. Pressure up to 2,833psi seeing ES cementer
shift open at 6bpm, observing flow at flowline. Reduce rate to 3bpm=450psi and circulate and condition
for 2nd stage cement Job. Continue to circulate and condition for 2nd stage cement job at
6bpm=555psi, dynamic loss rate of 1-2bph. Observing some Cement stringers and Cement balls at
surface occasionally. Shut down and flush stack with Black water 3x. Resumed circulating. Tail 500psi
Compressive strength at 06:31 10/16/23.
10/16/23
Daily disposal G&I: 57. Total disposal G&I: 3301. Daily disposal MPU G&I: 600. Total disposal MPU G&I:
2058. Daily H2O Lake 2: 610 bbls. Total H2O Lake 2: 4990 bbls,PJSM. Pump 2nd stage cement job as per
detail: flood lines with 5 bbls water at 5 bpm, 250 psi. Pump 60 bbls 10 ppg tuned spacer (with 4# red
dye, 5# polyflake in first 10 bbls) at 4.5 bpm, 380 psi. pump 335 bbls (790 sxs) 11 ppg ArcticCem lead
cement at 6 bpm, 896psi. Saw spacer and contaminated mud @ 270 bbls into total pumped. Good lead
cement @ 345 total bbls pumped,Pump 56 bbls Type I/II 15.8 ppg tail cement at 4.5 bpm, 782 psi. Drop
closing plug. HES displace with 20 bbls water at 5 bpm, 337 psi. Swap to rig pumps and bump plug with
132.3 bbls (132.3 calculated) of 9.6 ppg spud mud, slow rate to 3 bpm last 12 bbls,500 FCP. Pressure up
and observe tool shift close at 1748 psi. Hold 1875 psi for 3 minutes. Bleed off to static indicated tool
shifted close. CIP at 09:00. No losses. 306 bbls cement to surface. Full returns during job. Disconnect
Knife Valve, Drain and flush stack with black H2O. Blow down to cementers. R/D Volant and Parker TRS
equipment. Clean surface equipment and empty pits for cleaning. Lift stack and set emergency slips
with 55K set in slips. SIMOPS: work on Shaker #1, weld on cracks at motor mounts. Clean out Cellar box
and continue cleaning pits. L/D Cut joint (29.30'). Install Split bushings and R/U 5" handling equipment.
Johnny Whack the stack 3x at 15BPM. Process 5" DP. SIMOPS: continue working on shaker #1. Rack back
stack on pedestal. R/D Diverter Tee. Vault Wellhead Rep polish 9-5/8" Casing stump. R/D Diverter
Sections. M/U MPD Head on Annular - TQ. N/U Wellhead - TQ and Test void. Land DSA and Stack, N/U
BOPe/MPD and associated equipment. Open up all 6 Ram doors, clean and inspect. UPR=2-7/8"x5-1/2"
VBR's. LPR=7" SBR's. Grease Ram seals and close doors. Load Test Joints (4.5", 5.5", 7") in shed. Check
Pump, Chart, sensators, manifold and hoses. Obtain RKB's. Ground:26.6', LLDS:24.31', ULDS:22.15',
LPR:20.1' (7" SBR), Blinds:16.62', UPR:15.6' (VBR), Annular:12.1'. Finish N/U BOPe and R/U Lines. Button
up Ram Doors. M/U 4.5" Test joint to Dart/TIW/Side entry sub and screw into test plug. Flood Lines and
Purge. Conduct low pressure test, Grey lock leaking - tighten up MPD Grey-Lock. Complete shell test to
250/3000psi - Good. PJSM - Perform BOPe Testing - Test with 4.5", Annular, UPR, CMV 11-15, UPR I-
BOP, CMV 7-10, HCR/Mezz Kill. Currently on Test #3 of 9. Witness waived by AOGCC Rep Josh Hunt.
10/17/23
Continue w/Test #3. 4.5" and 5.5" TJ, CMV1-6, Man Kill, Man/HCR/Super Choke, Blinds, 5.5" UPR, 7"
LPR, 4" and 5" TIW. Test #4: Dart #2 Fail (removed). ACC Drawdown, Initial: ACC=3000, Man=1450,
ANN=1300. Final: ACC=1500, Man=1450, ANN=1300. 200psi recharge=23s, Full=90s. 6 bottle N2
average=2283. R/D BOP Test. Bleed off and open all rams. R/D Test Hoses, Breakdown side entry sub
and crossovers. Pull Test plug and Lay down test joint. Blowdown Choke and kill lines. Line up Choke for
Hard shut-in. Test Gas Alarm lights and audibles, H2S: 10ppm & 20ppm. LEL: 20% and 40%. Test PVT
sensors/alarms and flow paddle alarms. Witness waived by AOGCC rep Josh Hunt. Troubleshoot
hydraulic elevators. Adjust bale clamps and function test. Work on Link tilt adjustment on bales. Finish
working on hydraulic elevators. Open coffin on TD and adjust controls for elevators. Check Crown Saver
and floor Saver. Drain stack, BOLDS, pull bushings - Install Wear ring. Wear Ring: ID=9", OD=10.8",
Len=38". P/U BHA #2: 8.5" Clean out BHA. M/U 8.5" Smith Roller cone to 1.5deg Motor, HWDP and Jars.
RIH F/Surface - T/589'. P/U=54K, S/O=52K. Single in the hole with 5" 19.5# S-135 DP F/589' - T/1,987'
MD using 3.125" Rabbit. P/U=80K, S/O=69K. Wash Down F/1,987' - T/2,078' MD tagging ES Cementer on
depth. Encountered Cement stringers at 2,075'. Drill out ES Cementer as per Sperry Rep. Wash and
ream T/2,113', trip back up through and down ES cementer without pumps - no issues. Chase Debris
down T/2,272' MD. 400GPM=565psi, RF=39%. 40RPM=4-6Kft-lbs TQ, WOB=3-5K. P/U=85K, S/O=69K,
ROTW=76K. Continue singling in the hole with 5" DP out of the shed F/2,272' - T/5,863' MD P/U=150K,
S/O=63K. Wash down F/5,863' - T/5,987' MD. 330GPM=550psi, RF=39%. 30RPM=15Kft-lbs TQ Stall. Over
boarding thick mud as necessary. Circulate 2.25x Bottoms up to shear out and clean up clabbered mud
for CSG Test. 414GPM=669psi, RF=36%. 40RPM=13-15Kft-lbs TQ. PJSM -Test 9-5/8" Casing. Blowdown
Top Drive and R/U Test Equipment. Shut Upper Pipe Rams. Flood Surface lines and purge air out
through choke. Pump down string and kill line with MP#1. Conduct casing test on 9-5/8" Surface casing
to 2500psi for 30 mins (Charted) - Good. R/D Testing Equipment.
10/18/23
Conduct casing test on 9-5/8" Surface casing to 2500psi for 30 mins (Charted) - Good. Pumped=4.0bbls,
Bled Back=4.0bbls. Initial=2702psi, 15min=2672psi, 30min=2658psi. R/D Testing Equipment. Daily
disposal G&I: 114. Total disposal G&I: 4377. Daily disposal MPU G&I: 0. Total disposal MPU G&I: 2809.
Daily H2O Lake 2: 160 bbls. Daily Downhole Loss: 0bbls. Cumulative Surface Loss:121. Total H2O Lake 2:
5970 bbls,R/D Casing testing equipment - Clean and clear rig floor,Drill Cement and Shoe track F/5,978' -
T/6,146' MD. Tagged Baffle Adaptor (6,013'), Float Collar (6,056') and Shoe (6,140' DP MD) on depth.
Ream through 2x without pumps on - No issues. 450GPM=850psi, RF=38%. 40RPM=14-17Kft-lbs TQ,
WOB=3-5K. P/U=179K, S/O=80K, ROTW=110K. Drill 20' of new formation T/6,166' DP MD. Pumped a
50bbl Hi-Vis Spacer and displaced on the fly to 9.15ppg BaraDril-N Mud. Obtain SPR's. Monitor well for
10mins - Good. Blow down Top Drive. 370GPM=560psi, RF=36%. 40RPM=11-14Kft-lbs TQ, WOB6-10K.
P/U=183K, S/O=80K, ROTW=110K. R/U for Formation Integrity Test. Shut UPR's, flood surface lines and
purge through choke. Pump down string and kill line, pressuring up to 665psi=11.8ppg EMW for 10 mins
(charted). Pumped=2.3bbls, bled back=2.3bbls. R/D Testing equipment - Clean and clear rig floor. Blow
down Choke/Kill Lines. Monitor well for 10 mins - Good. SIMOPS: Work on FH80. PJSM - POOH with 5"
DP F/6,113' - T/5,470' MD. Pulling 5 stands to check for swabbing - No joy. Pull 5 more stands - Good.
Pumped 27bbl Dry-Job and POOH on elevators F/5,470' - T/589' MD (BHA) racking back stands in the
Derrick. P/U=165K, S/O=95K. No losses on trip. L/D BHA. Monitor well for 10 mins at 598' - Good. Rack
back 3 stands of 5" HWDP, L/D 2 stands 5" HWDP to shed along with Jar. Flush Motor and L/D Bit: 1-1-
WT-A-E-I-NO-BHA. P/U=52K, S/O=48K. Clean and Clear the Rig Floor. Pressure wash floor and
equipment. Bring up tools needed to P/U BHA and stage components. Load BHA in shed. PJSM - P/U
BHA. M/U 8.5" NOV TK66 and Sleeve. P/U GEO-Pilot 7600, ADR, DGR, PWD, DM. ALD, CTN, TM and
Float Subs. Upload to MWD. P/U=52K, S/O=52K. Loss of 1.2bbls. Continue making up BHA as per Sperry
Reps. Clear the floor, Pickup and load sources per HES. RIH with MWD T/430' MD. Single in the hole
with 5" DP F/430' - T/5,758' MD using 3.125" Drift. Break in GEO-Pilot at 2,007' MD. shallow pulse test
at 400GPM - Good. P/U=143K, S/O=84K, Loss of 1.5bbls. B/D Top Drive. .
10/19/23
POOH on Elevators racking back in the Derrick F/5,758' - T/2,007' MD. P/U=110K, S/O=71K.
CALC=96.9bbls, ACT=98.2bbls, LOSS=1.3bbls. Single in the hole with 5" DP F/2,007' - T/2,890' MD,
drifiting with 3.125" Drift. P/U=143K, S/O=84K. CALC=83bbls, ACT=82.5bbls, LOSS=0.5bbls. Stop to
adjust bale clamps. Function Test Elevators, and link tilt. Monitor Well on Trip Tank - Static. ,Single in
the hole with 5" DP F/2,890' - T/5,815' MD. P/U=152K, S/O=92K. No loss. ,RIH out of the Derrick F/5,815'
- T/6,009' MD. P/U=152K, S/O=92K. ,Install MPD's RCD Bearing. Pull Slips and bushings. Drain Stack and
Un-bolt Grey clamp. Pull Riser and install bearing. M/U Grey Clamp. PT MPD Hardlines to 250/1250psi -
Good. ,Slip and Cut the drilling line. Remove 15 wraps totalling 94'. Check Brakes and calibrate blocks.
,Grease and Inspect Crown sheaves. Check Top Drive Gear Oil - Good. Grease blocks and Top Drive.
Grease overhead pipe spinners. Adjust link tilt on Top Drive. Check Crown Saver and Floor Saver - Good.
,Wash and Ream F/6,009' - T/6,166' MD. 475GPM=1235psi, RF=48%. 80RPM=6-8Kft-lbs TQ. P/U=152K,
S/O=94K, ROTW=101K. ,Drill 8.5" Production Lateral F/6,166' - T/6,582' MD (4,487' TVD), Total: 416
(AROP: 70'fph). 525GPM=1737/1645psi on/off, RF=525gpm. MW=9.1/9.2ppg in/out, ECD=10.13ppg.
120RPM=14-17/13-15Kft-lbs on/off TQ, WOB=8-12K. Max Gas=998u. P/U=154K, S/O=72K, ROTW=102K.
,Drill 8.5" Production Lateral F/6,582' - T/6,835' MD (4,481' TVD), Total: 253' (AROP: 102'fph).
525GPM=1750/1720psi on/off, MW=9.1/9.2ppg in/out, ECD=10.37ppg, RF=525GPM. 120RPM=11-12/11-
12Kft-lbs on/off TQ, WOB=2-12K. P/U=159K, S/O=77K, ROTW=103K. ,MWD signal seeing large increase
in Noise. Troubleshoot MP#2 to find a bad #1 dampener - Replace. Rotate and Reciprocate at
309GPM=710psi, RF=306GPM, ECD=9.67ppg. 100RPM=12Kft-lbs TQ. ,Cont to replace mud pump
dampener. Rotate and reciprocate at 309 gpm=710 psi, ECD=9.67 ppg EMW. 100 RPM= 12Kft-lbs TQ.
Drill 8.5" Production lateral F/6,835' - T/7,025' MD (4,481' TVD), Total: 190' (AROP: 95fph).
525GPM=1750/1720psi on/off, MW=9.1/9.2ppg in/out, ECD=10.01ppg, RF=525GPM. 120RPM=11-12/11-
13Kft-lbs on/off TQ, WOB=2-12K. P/U=163K, S/O=81K, ROTW=106K.
10/20/23
Drill 8.5" Production lateral F/7,025' - T/7,980' MD (4,457' TVD), Total: 955' (AROP: 159fph).
550GPM=2112/2065psi on/off, MW=9.0/9.1ppg in/out, ECD=10.37ppg, RF=550GPM. 120RPM=11-14/11-
13Kft-lbs on/off TQ, WOB=2-12K. Max gas 1812u. P/U=145K, S/O=79K, ROTW=102K. Drill 8.5"
Production lateral F/7,980' - T/8,999' MD (4,457' TVD), Total: 1019' (AROP: 170fph).
550GPM=2182/2091psi on/off, MW=9.1/9.2ppg in/out, ECD=10.73ppg, RF=550GPM. 120RPM=11-14/11-
13Kft-lbs on/off TQ, WOB=2-12K. Max gas 1816u. P/U=141K, S/O=83K, ROTW=101K. Drill 8.5"
Production lateral F/8,999' - T/9,759' MD (4,413' TVD), Total: 760' (AROP: 126fph).
550GPM=2387/2219psi on/off, MW=9.1+/9.1+ppg in/out, ECD=10.0ppg, RF=550GPM. 120RPM=11-
14/11-13Kft-lbs on/off TQ, WOB=2-12K. Max gas 347u. P/U=139K, S/O=75K, ROTW=99K. Drill 8.5"
Production lateral F/9,759' - T/10,660' MD (4,388' TVD), Total: 901' (AROP: 150fph).
550GPM=2650/2515 psi on/o , MW=9.1/9.1ppg in/out, ECD=11.26 ppg, RF=550 GPM. 120 RPM. 11-
sands,with zero footage out of zone: . OBd-1 = 0.0' . OBd-2 = 132'. OBd-3 = 2,275'. OBd-4 = 383'. OBd-5
= 1,680'. .
10/21/23
Drill 8.5" Production lateral F/10,660' - T/11,539' MD (4,367' TVD), Total: 879' (AROP: 147fph).
550GPM=2660/2615psi on/off, MW=9.1+/9.1+ppg in/out, ECD=11.11ppg, RF=545GPM. 120RPM=11-
15/11-14Kft-lbs on/off TQ, WOB=2-12K. Max gas 2013u. P/U=154K, S/O=52K, ROTW=93K. Beyond
chokes wide open. Drill 8.5" Production lateral F/11,539' - T/12,170' MD (4,365' TVD), Total: 639' (AROP:
105fph). 550GPM=2884/2731 psi on/off, MW=9.2/9.2ppg in/out, ECD=11.37ppg, RF=540GPM.
120RPM=14-17/12-13Kft-lbs on/off TQ, WOB=5-14K. Max gas 1994u. P/U=150K, S/O=71K, ROTW=96K.
Beyond chokes wide open. Drill 8.5" Production lateral F/12,170' MD - T/12,874' MD (4,333' TVD), Total:
704' (AROP: 117 fph). 550 GPM=2891/2793 psi on/off, MW=9.2/9.2+ ppg in/out, ECD=11.51 ppg,
S/O=52K, ROTW=96K. Back Reaming full stand prior to connection. Beyond chokes wide open. Drill 8.5"
Production lateral F/12,874' MD - T/13,800' MD (4,321' TVD), Total: 926' (AROP: 154 fph). 550
GPM=2510/2476 psi on/o , MW=9.1/9.2 ppg in/out, ECD=11.31 ppg, RF=540 GPM. 120 RPM. 15-19/13-
16Kft-lbs on/off TQ, WOB=8K. Max gas 2,084u. P/U=156K, S/O=N/AK, ROTW=93K. Back Reaming full
wellbore positioning is 26.31’ from plan (WP05), 7.68’ High and 25.17’ Right. - GEO targeting 90.5°
drilling in the OBD-3 formation. Forward plan will be to undulate down to OBd -5 formation at around
13,800’ MD. We have drilled 4,470’ in the OBd formation with no footage drilled out of zone. 65
concretions in the lateral totaling 258’, making up 3.84% of the lateral. .
10/22/23
Drill 8.5" Production lateral F/12,874' MD - T/13,800' MD (4,321' TVD), Total: 926' (AROP: 154 fph). 550
GPM=2510/2476 psi on/o , MW=9.1/9.2 ppg in/out, ECD=11.31 ppg, RF=540 GPM. 120 RPM. 15-19/13-
16Kft-lbs on/off TQ, WOB=8K. Max gas 2,084u. P/U=156K, S/O=N/AK, ROTW=93K. Back Reaming full
wellbore positioning is 26.31’ from plan (WP05), 7.68’ High and 25.17’ Right. - GEO targeting 90.5°
drilling in the OBD-3 formation. Forward plan will be to undulate down to OBd -5 formation at around
13,800’ MD. We have drilled 4,470’ in the OBd formation with no footage drilled out of zone. 65
concretions in the lateral totaling 258’, making up 3.84% of the lateral. ,Drill 8.5" Production lateral
F/13,800' MD - T/14,523' MD (4,323' TVD), Total: 723' (AROP: 121 fph). 550 GPM=2768/2712 psi on/off,
14K. Max gas 2,032u. P/U=151K, S/O=N/AK, ROTW=93K. Back Reaming full stand prior to connection.
Beyond chokes wide open. ,Drill 8.5" Production lateral F/14,523' MD - T/15,225' MD (4,303' TVD),
Total: 702' (AROP: 117 fph). 550 GPM=2812/2703 psi on/off, MW=9.25/9.3 ppg in/out, ECD=11.51 ppg,
S/O=N/AK, ROTW=92K. Back Reaming full stand prior to connection. Beyond chokes wide open. ,Drill
8.5" Production lateral F/15,225' MD - T/16,052' MD (4,283' TVD), Total: 827' (AROP: 137 fph). 500
GPM=2569/2504 psi on/o , MW=9.25/9.3 ppg in/out, ECD=11.74 ppg, RF=485 GPM. 120 RPM. 18-
22/15-19Kft-lbs on/off TQ, WOB=6-13K. Max gas 2,305u. P/U=149K, S/O=N/AK, ROTW=91K. Back
Processing pipe in pipeshed, prepping pits for 580 bbl. dump & dilute.
10/23/23
Drill 8.5" Production lateral F/16,052' MD - T/16,750' MD (4,283' TVD), Total: 698' (AROP: 116 fph). 500
GPM=2647/2590 psi on/o , MW=9.2/9.3 ppg in/out, ECD=11.72 ppg, RF=486 GPM. 120 RPM. 18-22/15-
20Kft-lbs on/off TQ, WOB=6-14K. Max gas 2,792u. P/U=155K, S/O=N/AK, ROTW=92K. Back Reaming full
& dilute dependant on current mud properties. Drill 8.5" Production lateral F/16,750' MD - T/17,454'
MD (4,272' TVD), Total: 704' (AROP: 117 fph). 500 GPM=2499/2450 psi on/off, MW=9.1/9.2 ppg in/out,
P/U=158K, S/O=N/AK, ROTW=92K. Back Reaming full stand prior to connection. Beyond chokes wide
(4,255' TVD), Total: 631' (AROP: 105 fph). 500 GPM=2629/2521 psi on/off, MW=9.1/9.2+ ppg in/out,
P/U=159K, S/O=N/A ROTW=91K. Back Reaming full stand prior to connection. Beyond chokes wide
fph). 475- GPM=2436/2404 psi on/off, MW=9.1/9.2+ ppg in/out, ECD=11.67 ppg, RF=455 GPM. 120
in pipeshed, Painting on rig floor.
10/24/23
Drill 8.5" Production lateral F/18,721' MD - T/19,300' MD (4,250' TVD), Total: 579' (AROP: 96 fph). 500
GPM=2765/2690 psi on/o , MW=9.1/9.2+ ppg in/out, ECD=11.95 ppg, RF=485 GPM. 120 RPM. 18-
24/18-23Kft-lbs on/off TQ, WOB=6-15K. Max gas 2,966u. P/U=161K, S/O=N/A ROTW=92K. Back
pipeshed. Drill 8.5" Production lateral F/19,300' MD - T/19,863' MD (4,233' TVD), Total: 563' (AROP: 94
fph). 450 GPM=2430/2400 psi on/o , MW=9.2/9.2+ ppg in/out, ECD=12.05 ppg, RF=436 GPM. 110 RPM.
21-24/20-23Kft-lbs on/off TQ, WOB=6-11K. Max gas 2,435u. P/U=163K, S/O=N/A ROTW=92K. Back
reaquired at 19514',Drill 8.5" Production lateral F/19,863' MD - T/20,370' MD (4,228' TVD), Total: 507'
(AROP: 85 fph). 425 GPM=2310/2280 psi on/off, MW=9.2/9.3 ppg in/out, ECD=11.98 ppg, RF=413 GPM.
F/20,370' MD - T/20,6000' MD (4,221' TVD), Total: 230' (AROP: 76 fph). 425 GPM=2310/2280 psi on/off,
12K. Max gas 2,370u. P/U=163K, S/O=N/A ROTW=91K. Back Reaming full stand prior to connection.
Beyond chokes wide open. . T.D. at 20,600' MD @ 21:00 hrs. . Final survey taken- survey depth 20,531'
MD 4,223' TVD.. ,well at T.D. 20,600' MD 4,221' TVD. Circulate and rack back 1 stand F/20,600' MD-T/
20,559' MD. Pump 40 bbbl. low vis sweep 30 visfollow with 145 vis sweep both sweeps 9.95 ppg. Rotate
& Reciprocate F/20,559' MD - T/ 20,491' MD. 425 GPm, 2,250 PSI, Beyond flow return 413 GPM, 115
rpm, torque 21k, Max gas 1,086 units. up weight 177k down wt. N/A Rot weight 91k. Coninue
circulating 3 X bottoms up, Racking back stand each bottoms up. 450 gpm, 2,450 psi Beyond return flow
437 gpm. 120 rpm, torque 22k ft/lbs. max gas units 1,086. Up weight - 170k. Down weight - N/A,
Sim-Ops Prepare pits for quick-drill displacemen, empty and flush pit #5, fioll pit #5 & trip tanks w/9.1
viscosified quick-drill brine. Pump SAPP Train, 40 bbl. SAPP pill chase with 20 bbl. quick-dril 9.1 ppg
viscous brine, pump 2nd SAPP 40 bbl pill chase with another 20 bbl quick -dril 9.1 ppg viscouis brine,
Pump 3rd. 40 bbl. SAPP pill chase with quick dril 9.1 ppg viscous brine. Displacing drilling mud.
10/25/23
Cont. displacing to 9.1 ppg QuickDril at 450 gpm, 1540 psi, 120 rpms, 24-27Kft-lbs Tq. Increase lube
concentration to 3.5%. Monitor well with MPD, no pressure gain - static. Drop drift. BROOH from
20,600' to 18,848' at 475 gpm, 1630 psi, 120 rpms, 18-19Kft-lbs Tq, max gas 153u, ECD's 10.95 ppg
EMW. Pulling 20-30 fpm as hole dictates. P/U 163K, S/O N/A, ROTW 93K. Loss rate 18 bph. BROOH from
18,848' to 17,305' at 475 gpm, 1606 psi, 120 rpms, 15-19Kft-lbs Tq, max gas 433u, ECD's 10.60 ppg
EMW. P/U 152K, S/O N/A, ROTW 93K. Pulling 20-30 fpm as hole dictates. MPD chokes wide open. Loss
rate 15 bph.. MD PASS from 18,398' to 18,227' at 180 fph. BROOH F/17,305'MD -T/14,706' MD, 475
gpm, 1625 psi, 120 rpms, 15-19Kft-lbs Tq, max gas 702u, ECD's 10.65 ppg EMW. P/U 141K, S/O N/A,
ROTW 89K. Pulling 20-30 fpm as hole dictates. MPD chokes wide open. Loss rate 15 bph.. Sim-Ops
Process pipe in pipeshed. BROOH F/14,706'MD -T/11,090' MD, 475 gpm, 1,375 psi, 120 rpms, 12-15Kft-
lbs Tq, max gas 251 units, ECD's 10.54 ppg EMW. P/U 142K, S/O 70k, ROTW 100K. Pulling 35-45 fpm as
hole dictates. MPD chokes wide open. Loss rate went from 15 bph. down to 1.5 bph. Got down weight
back at 14,325' MD. (down wt at 14,325' = 54k.). Sim-Ops Process pipe in pipeshed.
10/26/23
BROOH F/10,090'MD -T/7,902 MD, 475 gpm, 1,225 psi, 120 rpms, 7-10Kft-lbs Tq, max gas 344 units,
ECD's 9.85 ppg EMW. P/U 123K, S/O 88k, ROTW 105K. Pulling 35-45 fpm as hole dictates. MPD chokes
wide open. BROOH F/7,902'MD -T/6,136 MD, 475 gpm, 1,120 psi, 120 rpms, 6-7Kft-lbs Tq, max gas 220
units, ECD's 9.7 ppg EMW. P/U 120K, S/O 102k, ROTW 110K. Pulling 35-45 fpm as hole dictates. MPD
chokes wide open. Slow rotary to 60 rpms as BHA comes through shoe. Pump high vis sweep (on time
20% increase) and circulate hole clean at 475 gpm, 100 rpms, 4.5Kft-lbs. Max gas 76U. P/U 124K,
S/O110K, ROTW 102K. Monitor well with MPD - static. Blow down mudline & top drive, Pull Beyond
RCD Bearing, Install trip nipple w/ spare 20" air boot, Turn on hole fill check for leaks, Clear aand clean
rig floor. T.O.O.H. laying down 5" drillpipe, F/6,076' MD - T/.5,776' MD. Culling drillpipe as needed for
Cat 5 inspection. Verify hole not swabbing, pump 20 bbl. 9.8 ppg dry job w/corrosion inhibitor. Blow
down top drive and Sperry Geo-span. Install stripping rubbers. Up wt. 122k down wt. 89k, 2 bbl loss.
T.O.O.H. laying down 5" drillpipe, F/5,776' MD - T/.995' MD. Culling drillpipe as needed for Cat 5
inspection. Up wt 70k down wt. 69k. Calculated hole fill 42 bbls. Actaul hole fill 59.7 Total losses 17.7
bbls. T.O.O.H. laying down 5" drillpipe, F/995' MD - T/430' MD. Culling pipe for cat 5 inspection. up
weight 57k dowwn weight 53k. 10 minute ow check at BHA. Well taking minimal uid. Lay down 5"
HWDP & Jars, Retrieve corrosion ring from top of drill collars, Lay down flex collars & float sub, PJSM,
WT-A-X-I-CT-TD,Grease Crown, Traveling blocks, Top Drive & overhead spinners, Inspect tong dies,
Inspect slip dies.
10/27/23
RIH with excess drill pipe from derrick to 5,718'. (90 stands) Monitor well 10 minutes (Static) Pump 30
bbl 10.2 ppg corrosion inhibited dry job. Blow down mud line & Top drive. Up wt.123k down weight
108k,Lay down 5" Drillpipe F/5,718' MD- T/3,812' MD (60 Joints) up wt. 101k dn wt. 86k. Culling pipe for
Cat 5 inspection. TIH F/3,812' MD - T/5,655' MD. P/U 123k dn wt 107k. lay down 5" drillpipe F/5,655'
MD - T/ Surface. culling pipe for Cat 5 inspection. Pick up Parker casing hydraulic tongs, Slips, dog collar
clamp, air slips, elevators & Miscelaneous crossoversfor running completion W/4-1/2' 6-5/8" & 7" liner.
Hole lined up on trip tank w/ continuops fill 2.5 bph loss rate. Make up floor safety joints and
crossovers 4-1/2" & 6-5/8" stage in pipeshed. PJSM/ Make Up Eccentric aluminum solid shoe, & X-O,
RIH w/L-80 slotted DWC slotted liner, 4-1/2" TXP solid liner, 4-1/2 H563 slotted liner per tally. F/surface
-T/4,655' MD, All liner made up to required torque specs. DWC Torque 6,150 ft/lbs. TXP 6,150 ft/lbs.
H563 3,800 ft/lbs. Up weight 70k Down weight 62k. calculated displacement 17.1 bbls, Actual = 4 bbls.
losses 13.1 bbls. RIH W/ Lower completion F/4,655' - T/10,112' MD per running detail. Torque H-563
T/3,800 ft/lbs. M?u crossover, change elevators, air slip inserts and tong dies. Begin running the 6-5/8"
slotted Vam top liner torque Vam top - 6,870 ft/lbs. F/10,112' MD - T/12,330' MD up wt. 110k dn wt.
64k.
10/28/23
Cont. to RIH with 6-5/8" slotted, 24#, L-80 VAMTOP, M/U TQ 6870 ft-lbs. from 12,330' to 14352'. M/U
XO, change out pipe handling equipment. RIH 7", 26#, l-80, w563 TO 14,772'. M/U SLZXP LINER TOP.
RIH with 1 stand drill pipe. Break circulation to ensure clear. P/U 149K, S/O 84K. RIH with lower
completion conveyed on drill pipe from 14,759' to 16,539'. RIH with liner conveyed on HWDP picking up
and drifting from 16,539' to 17,398'. P/U 182K, S/O 85K. Cont to RIH with liner picking up and drifting
HWDP from 16,539' to 20,600'. P/U 264K, S/O 100K. Calculated displacement 57.2 bbls, actual 36.3 bbls.
Tag bottom on depth w/ 10K. Pump drill string volume at 4 bpm, 490 psi. Drop 1-1/8" phenolic ball and
pump down at 3 bpm 340 psi. Slow rate to 1.5 bpm, 200 psi at 600 strokes. Observe ball on seat at 848
strokes. Pressure up to 2100 psi for 5 minutes to set slips, Set 50K down. Cont pressure up to 3100 psi
to nuetralize pusher tool, and to 4000 psi to shear out ball seat. Pick up 5' to expose dog sub and
observe P/U weight down to 218K. Rotate 10 and rpms and set 60K down on liner top. TOL 5856'. Rig
up and PT liner top packer to 1500 psi for 10 minutes - good. 1.5 bbl's. pumped 1.5 bbl's. returned. Rack
back 1 stand drillpipe, F/5,856' MD - T/ 5,818' MD. Blow down choke, kill line & top drive. Line up to
circulate, 2 bbl. per hr. static loss. Grease washpipe, RLA, Crown & Traveling blocks, link tilt assembly,
overhead spinners, Check gear oil. static loss rate remaining at 2 bph. Pump 20 bbl. dry job, Blow down
topdrive, Install stripping rubbers. TOOH laying down 5" HWDP F5/818' MD - T/ 1.935' MD. Calculated
hole fill 61 bbl's. actual hole fill 78 bbl's. losses = 17 bbl's. TOOH Laying down 5" drillpipe F/1,935' MD -
T/ Surface.Culling pipe for cat 5 inspection. Lay down Liner running tool per Baker rep.Clear & Clean rig
floor. RIH 88 stands 5" drillpipe T/5,592' MD. Up wt. 141k. Dn wt. 109k.Calculated displacement 49
bbl's. Actual displacement 42.7 bbl's. 6.3 bbl. loss. PJSM, Slip & Cut 94' of drill line 15 wraps, Check
brakes, deadman clamptorque to 85 ft/lbs. Set & Check Crown & Floor saver. Monitor well via trip tank.
Wellname: PBW L-247
API Number: 50-029-23766-00-00
Well Permit Number: 223-081
Date Summary
10/29/23
Cont. to cut and slip. Adjust air gap on brakes. 3 bph static loss rate,POOH laying down drill pipe from
5592' to surface. Cull out pipe for cat IV inspectioin. Calc displacement 48.2 bbls, actual 60.9 bbls. Pull
wear bushing. Rig up to RIH with 7" tie-back. Change pipe handling equipment. Rig up Tq turn
equipment. Bring up torque turn equipment, Plug in and poerform calibration. Sim-Ops: Strap & Taly 4-
1/2" Chrome pipe in shed. RIH W/ 7" Vam Top 29# tieback and baker seal assembly F/Surface - T/2,115'
MD. Torque turn connections to 9,400 ft/lbs. Up wt. 79k Dn wt. 76k, Calculated displacement 17.2 bbl's
Actual displacement 9.1 bbl's. 8.1 bbl. loss. Lined up on trip tank with continuos hole fill. RIH W/ 7"
Vam Top 29# tieback and baker seal assembly F/2,115' MD - T/5,826' MD Torque turn connections to
9,400 ft/lbs. Up wt. 165k Dn wt. 125k, Calculated displacement 60 bbl's Actual displacement 35.4 bbl's.
24.6 bbl. loss. Lined up on trip tank with continuos hole fill. T,Ran 7"Vantop tieback tagged no go 17.4'
in on joint #136. Riggged up to reverse circulate, Shut hydril element, Pressure up to 400 psi, Strip up
and observe pressure drop verifying seals were engaged. laid down joints 136,135&134 space out with
5.87' and 19.81' piup joints, picked joint # 134 back up, made up hanger and landing joint to string.
Drained stack& verified hanger landing per Vault wellhead rep. Space out 2.16' of no go. Last up wt.
167k. dn 125k. PJSM, Close bag - R/U to reverse circulate. Pump 95 bbl's.8.9 ppg. corrosion inhibited
brine, pumping 4 bbl's per minute with 377 psi. Shut down, line up and chase with 65 bbl's. diesel
freeze protect w/little red services at 2 bpm- 370 psi. Shut down strip through bag and land 7" tieback
string,Set Packoff, RILDS, Lay down joint of 5" HWDP used to set packoff, Test packoff void.
10/30/23
Test 9-5/8" X 7" Annulus to 1,500 psi. Chart for 30 min. Initial 1,620 psi, 15 min, 1,582 psi, final 1,570
psi. Good test. PJSM, P/U Centralift tools & equipment, Bring up 80 cannon clamps, R/U cannon clamp
closing tool,and air chisel, Bring up tech wire spooler, hange sheave off with yellow tugger and tie back
in derrick. R/U side door elevators, Bring crossovers to floor, dress liner running equipment for 4-1/2"
verify pipe count in shed. Stage jewelry for run in pick up order. PJSM, Run 4-1/2" 12.6# 13CR-80
VamTop upper completion per tally. torque turn connections T/4,440 ft/lbs. Run shoe, 23 joints tubing
X-Nipple W/RHC -M installed one joint tubing with 7" packer W/crossover F/Vamtop - T/ JFEBEAR,
Jfebear torque to 5,400 ft/lbs. M/U gauge carrier install Tech Wire and test same. Run 4-1/2" JFEBEAR
tubing install cannon clamp M/U sliding sleeve T/1,120' MD up wt. 47k dn wt. 44k. Continue RIH with
upper completion & Tech wire, M/U assorted jewelry per tally. RIH F/1,120' MD - T/ 1,984' MD. up wt.
51k dn wt. 50k calculated displacement 7.6 bbl's. actual loss of 11 bbl's. Total loss 18.6 bbl's. Trouble
shoot torque turn graphics isues with proper torque specifications, replaced load cell. Continue RIH
with upper completion & Tech wire, M/U assorted jewelry per tally. RIH F/1,984' MD - T/ 4,978' MD. up
wt. 81k dn wt. 68k calculated displacement 17.1 bbl's. actual loss of 14.4 bbl's. Total loss 31.5 bbl's.
Continue running upper completion F/4,978' MD - T/ 6,235' MD Testing TCH wire every 1,000'. M/U
tubing hanger, up wt. 92k dn wt. 74k. Calculated displacement 29 bbl's. Loss 15 bbl's. Total losses 44
bbl's. Terminate Tech Wire & perform final test, Drain stack, land Hanger per Vault wellhead rep, RILDS,
Pressure test top seal to 500 psi (Good), Pull landing joint 40k on hanger. Total of 73 cannon clamps
used. R/U T/reverse circulate Neat corrosion inhibited brine down 7" X 4-1/2" Annulus taking returns
through 4-1/2" tubing. Pump 95 bbl's. 9.1 ppg. neat brine & 107 bbl's. 9.1 corrosion inhibited brine ICP
@ 2.4 BPM = 345 FCP =264 psi.
Hilcorp Alaska, LLC
HEC Composite
Well Operations Summary
10/31/23
Make up landing joint, Drop ball & rod, Pull landing joint, Pressure up set packer, Continue to build
pressure on tubing for MIT test, Initial pressure 3,738 psi, 15 min,. 3,678 psi, final pressure = 3,652 psi.
Bleed dowwn tubing pressure to 2,000 psi, pressure up annulus for MIT test Initial pressure 3,692 psi,
15 min. 3,644 psi, Final pressure 3,625 psi. Both tests charted. 2.8 bbl's pumped same returned when
pressure bled off. Tubing pressure bled off shear plug in GLM. Install BPV & Rig down test equipment.
Flush all lines, mud pumps, choke & kill lines, cement line, gas buster and stack with corrosion inhibited
soap pill. N/D BOPE,. Sim-Ops: Offload fluid from pits. Inspect hanger, Terminate Tech wire, Install dry
hole tree. Sim-Ops. Bridle up TD. Clean pits, Start suction cleaning on Hyd pumps. Test hanger void 500
psi low 5,000 psi high. Good test. Fill tree purge air, test tree 250 psi low, 5,000 psi high Good Test, R/D
test equipment,Pull BPV & CTS. Sim-Ops continuie cleaning pits, Prep new rig location, Continue with
MP Inspection. Rig up to reverse circualte down tree, Pump at 2 bpm 610 psi down the annulus taking
returns out the tubing and into cellar box pumped 85 bbl's diesel FCP - 600 psi. Allow well to U-
tube,RDMO activities, Scope down derrick, disconnect interconnect at pits. All tasks PJSM prior to
starting. Sim-ops: Cleaning pits, finish inspections, work on rig move checklist, Rebuild kill valve. Rig
down all interconnects between modules, Cruz on location 9:00. Seperate and stage modules on pad. .
11/01/23 Prep to pull substructure off well. RDMO 01:00.
David Douglas Hilcorp North Slope, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Hilcorp North Slope, LLC
Date: 11/16/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL:
WELL: PBU L-247
PTD: 223-081
API: 50-029-23766-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (10/10/2023 to 10/24/2023)
x RST(EWR), BST(GR), ABG, DGR, ADR, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
PBU L-247 LWD Subfolders:
PBU L-247 Geosteering Subfolders:
Please include current contact information if different from above.
PTD: 223-081
T38134
11/21/2023Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.11.21
10:45:36 -09'00'
Drilling Manager
10/23/23
Monty M
Myers
By Grace Christianson at 11:56 am, Oct 23, 2023
SFD
SFD 10/23/2023
Orion
Oct 23, 2023
MGR23OCT23
10-407 (for PTD)
DSR-10/23/23
PB Schrader Bluff, Orion Development Area
*&:
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.10.23 15:06:43 -08'00'
RBDMS JSB 102623
KƵƌŵŽĚĞůŝŶŐƐŚŽǁƐƉŽƚĞŶƟĂůĨŽƌƐŝŶƵƐŽŝĚĂůďƵĐŬůŝŶŐǁŚŝůĞƌƵŶŶŝ ŶŐϱ͘ϱ͟ůŝŶĞƌĐŽŵƉůĞƟŽŶŝŶ>-247. We
ĂƌĞƌĞƋƵĞƐƟŶŐƚŽĐŚĂŶŐĞŽƵƌůŝŶĞƌĚĞƐŝŐŶƚŽϳ͟yϲ-5/8” x 4-1/2” reduce the chances of buckling while
ƌƵŶŶŝŶŐŽƵƌůŝŶĞƌĐŽŵƉůĞƟŽŶ͘
Cheers,
Marshall Brown
Well Name:L-247 API Number: 50-029-23766-00-00
Current Status:Drilling Rig:Innovation
Estimated Start Date:October 25, 2023
Regulatory Contact:Joe Lastufka Permit to Drill Number:223-081
First Call Engineer:Marshall Brown (907) 777-8419
Drilling Engineer:Joe Engel (907) 777-8395
_____________________________________________________________________________________
Revised By: JNL 10/20/2023
PROPOSED SCHEMATIC
Prudhoe Bay Unit
Well: PBU L-247
Last Completed: TBD
PTD: 223-081
TD =20,540’(MD) / TD =4,248’ (TVD)
5
20”
Orig. KB Elev.: 73.6’ / GL Elev.: 47.1’
7”
4
13
9-5/8”
1
2
3
See
Slotted
Liner
Detail
6-5/8”x
4-1/2” XO
PBTD =20,540’(MD) / PBTD = 4,248’ (TVD)
9-5/8” ‘ES’
Cementer @
2,082’
7” x 6-
5/8”XO
12
11
10
9
6
8
7
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 107’ N/A
9-5/8" Surface 47/ L-80 / TXP 8.681 Surface 2,062’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 2,062’ 6,140’ 0.0758
7” Tieback 29 / L-80 / VamTop 6.184 Surface ~5,850’ 0.0383
7” Liner 26 / L-80 / Hyd 563 6.276 5,850’ 6,200’ .0383
6-5/8” Liner 20 / L-80 / Hyd 563 6.049 ~6,200’ ~10,800’ 0.0355
4-1/2” Liner 12.6 / L-80 / H563 X DWC 3.958 ~10,800’ ~20,540’ 0.0152
TUBING DETAIL
4-1/2" Tubing
12.6# / L-80 / JFE Bear-
VamTop 3.958 Surface 6,250’
0.0152
OPEN HOLE / CEMENT DETAIL
Driven Conductor
12-1/4"Stg 1 – Lead – 531 sx / Tail – 400 sx
Stg 2 – Lead – 740 sx / Tail – 270 sx
8-1/2” Cementless Slotted Liner
WELL INCLINATION DETAIL
KOP @ 250’
90° Hole Angle = @ 6,184’ MD
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: 50-029-23766-00-00
Completion Date: TBD
JEWELRY DETAIL
No. Est Top MD Item ID
1 3,000’ X Nipple 3.813”
2 TBD GLM (2375’ TVD)
3 TBD GLM (3500’ TVD)
4 TBD GLM (4000’ TVD)
5 TBD GLM (4200’ TVD)
6 ~5,120’ HES XD Sliding Sleeve 3.813”
7 ~5,180’ Downhole Gauge Carrier 3.813”
8 ~5,240 HES AHR Production Packer 3.813”
9 ~5,300 X Nipple (at 65 degs inc)3.813”
10 ~5,850’ Liner Top Packer
11 ~5,850’ 7” x 9-5/8” Liner Hanger w/ Tieback Sleeve
12 ~6,250’ WLEG – Bottom @ TBD
13 ~20,540’ Shoe
4-1/2” SLOTTED LINER DETAIL
Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD)
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Prudhoe Bay Field, Schrader Bluff Oil Pool, Orion Development, PBU L-247
Hilcorp Alaska, LLC
Permit to Drill Number: 223-081
Surface Location: 2440' FSL, 4204' FEL, Sec 34, T12N, R11E, UM, AK
Bottomhole Location: 2453' FNL, 680' FEL, Sec 30, T12N, R11E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above-referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of September 2023. 13
Brett W.
Huber, Sr.
Digitally signed by Brett W. Huber,
Sr.
Date: 2023.09.13 19:11:21 -05'00'
PBU L-247
9.5.2023
Drilling Manager
09/05/23
Monty M
Myers
By Grace Christianson at 10:47 am, Sep 05, 2023
50-029-23766-00-00
* BOPE test to 3000 psi. Annular to 2500 psi.
* 9-5/8" casing test and FIT to AOGCC upon completing FIT.
* Approved for gas lift production. Sundry approval required for
jet pump production.
A.Dewhurst 13SEP23
223-081
MGR05SEP2023 DSR-9/12/23*&:
09/13/23
09/13/23Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.09.13 19:11:38 -05'00'
Prudhoe Bay West
(PBU) L-247
Drilling Permit
Version 1
8/23/2023
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 10
10.0 N/U 13-5/8” 5M Diverter System ............................................................................................. 11
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 16
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 27
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28
16.0 Run 5-1/2”Liner ....................................................................................................................... 33
17.0 Run 7” Tieback ........................................................................................................................ 37
18.0 Run Upper Completion/ Post Rig Work ................................................................................. 40
19.0 Innovation Rig Diverter Schematic ......................................................................................... 44
20.0 Innovation Rig BOP Schematic ............................................................................................... 45
21.0 Wellhead Schematic ................................................................................................................. 46
22.0 Days Vs Depth .......................................................................................................................... 47
23.0 Formation Tops & Information............................................................................................... 48
24.0 Anticipated Drilling Hazards .................................................................................................. 50
25.0 Innovation Rig Layout ............................................................................................................. 54
26.0 FIT Procedure .......................................................................................................................... 55
27.0 Innovation Rig Choke Manifold Schematic ............................................................................ 56
28.0 Casing Design ........................................................................................................................... 57
29.0 8-1/2” Hole Section MASP ....................................................................................................... 58
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 59
31.0 Surface Plat (NAD 27) ............................................................................................................. 60
Page 2
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
1.0 Well Summary
Well PBU L-247
Pad Prudhoe Bay L Pad
Planned Completion Type 4-1/2” Gas Lift
Target Reservoir(s) Schrader Bluff OBd Sand
Planned Well TD, MD / TVD 20,540’ MD / 4,248’ TVD
PBTD, MD / TVD 20,530’ MD / 4,491’ TVD
Surface Location (Governmental) 2,440' FSL, 4,204' FEL, Sec 34, T12N, R11E, UM, AK
Surface Location (NAD 27) X= 582,711.55, Y= 5,978,156.28
Top of Productive Horizon
(Governmental)1300' FSL, 1906' FEL, Sec 33, T12N, R11E, UM, AK
TPH Location (NAD 27) X=579,745, Y=5,976,983
BHL (Governmental) 2453' FNL, 680' FWL, Sec 30, T12N, R11E, UM, AK
BHL (NAD 27) X= 566,835, Y= 5,983,664
AFE Number 231-00107
AFE Drilling Days 27
AFE Completion Days 4
Maximum Anticipated Pressure
(Surface) 1526 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1975 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft +46.7ft =73.2ft
GL/ Pad Elevation above MSL: 46.7 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
Tieback 7” 6.184 6.125 7.644 29 L-80
VAMtop 8160 7030 676
8-1/2”5-1/2”
slotted 4.892 4.767 6.05 17 L-80
JFEbear 7740 6290 397
Tubing
4-1/2” 3.958 3.833 4.937 12.6 L-80
JFE Bear 8,430 7,500 288
4-1/2” 3.958 3.833 4.937 12.6
L-80
13Cr VAMTOP 8430 7500 288
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276”3.25” 6.625”19.5 S-135 DS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 30,730 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com
jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Completion Engineer Wyatt Rivard 907.777.8547 wrivard@hilcorp.com
Geologist Kevin Eastham 907.777.8316 keastham@hilcorp.com
Reservoir Engineer Michael Mayfield 907.564.5097 mmayfield@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 kfleming@hilcorp.com
EHS Manager Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
_____________________________________________________________________________________
Revised By: JLS 8/29/2023
PROPOSED SCHEMATIC
Prudhoe Bay Unit
Well: PBU L-247
Last Completed: TBD
PTD: TBD
TD =20,540’(MD) / TD =4,248’ (TVD)
5
20”
Orig. KB Elev.: 73.6’ / GL Elev.: 47.1’
7”
4
13
9-5/8”
1
2
3
See
Slotted
Liner
Detail
7”x
5-1/2” XO
PBTD =20,540’(MD) / PBTD = 4,248’ (TVD)
9-5/8” ‘ES’
Cementer @
±2,500’
12
11
10
9
6
8
7
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 107’ N/A
9-5/8" Surface 47/ L-80 / TXP 8.681 Surface 2,500’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 2,500’ 6,200’ 0.0758
7” Tieback 29 / L-80 / VamTop 6.184 Surface 5,850’ 0.0383
7” Liner 26 / L-80 / Hyd 563 6.276 5,850’ 6,200 0.0383
5-1/2” Liner 17 / L-80 / JFE Bear 6.049 6,200’ 20,540’ 0.0355
TUBING DETAIL
4-1/2" Tubing
12.6# / L-80 / JFE Bear-
VamTop 3.958 Surface 6,250’
0.0152
OPEN HOLE / CEMENT DETAIL
Driven Conductor
12-1/4"Stg 1 – Lead – 467 sx / Tail – 395 sx
Stg 2 – Lead – 679 sx / Tail – 268 sx
8-1/2” Cementless Slotted Liner
WELL INCLINATION DETAIL
KOP @ 250’
90° Hole Angle = @ 6,184’ MD
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: TBD
Completion Date: TBD
JEWELRY DETAIL
No. Est Top MD Item ID
1 3,000’ X Nipple 3.813”
2 TBD GLM (2375’ TVD)
3 TBD GLM (3500’ TVD)
4 TBD GLM (4000’ TVD)
5 TBD GLM (4200’ TVD)
6 ~5,120’ HES XD Sliding Sleeve 3.813”
7 ~5,180’ Downhole Gauge Carrier 3.813”
8 ~5,240 HES AHR Production Packer 3.813”
9 ~5,300 X Nipple (at 65 degs inc)3.813”
10 ~5,850’ Liner Top Packer
11 ~5,850’ 7” x 9-5/8” Liner Hanger w/ Tieback Sleeve
12 ~6,250’ WLEG – Bottom @ TBD
13 ~20,540’ Shoe
5-1/2” SLOTTED LINER DETAIL
Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD)
Page 7
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
7.0 Drilling / Completion Summary
PBU L-247 is a grassroots producer planned to be drilled in the Schrader Bluff OBd sands. L-247 is part of a
multi-well program targeting the Schrader Bluff sand on PBU L-Pad
The directional plan is 12-1/4” surface hole and 9-5/8” surface casing set into the top of the Schrader Bluff
OBd sand. An 8-1/2” lateral section will be drilled. A 5-1/2” slotted liner will be run in the open hole
section, followed by a 7” tieback and 4-1/2” gas lift tubing.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately September 26, 2023, pending rig schedule.
Surface casing will be run to 6,200’ MD / 4,491’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to one of two locations:
Primary: Prudhoe G&I on Pad 4
Secondary: the Milne Point “B” pad G&I facility
General sequence of operations:
1. MIRU Innovation Rig to well site
2. N/U & Test 13-5/8” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test
5. Drill 8-1/2” lateral to well TD
6. Run lower completion
7. Run 7” tieback
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. Remote geologist. LWD: GR + Res
2. Production Hole: No mud logging. Remote geologist. LWD: GR + ADR (For geo-steering)
Page 8
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations,
specific regulations are listed below. If additional clarity or guidance is required on how to comply with
a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
x BOPs shall be tested at (2) week intervals during the drilling and completion of PBU L-247. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment
will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program
and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
AOGCC Regulation Variance Requests:
No variances requested at this time.
Page 9
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
Summary of Innovation BOP Equipment & Test Requirements
Hole Section Equipment Test Pressure (psi)
12-1/4”x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only
8-1/2”
x 13-5/8” x 5M Control Technology Inc Annular BOP
x 13-5/8” x 5M Control Technology Inc Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Control Technology Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3,000
Subsequent Tests:
250/3,000
Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric
triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs and changing rams
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 10
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
9.0 R/U and Preparatory Work
9.1 L-247 will utilize a 20” conductor on L-Pad. Ensure to review attached surface plat and make
sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Innovation. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
x Cold mud temps are necessary to mitigate hydrate breakout
9.10 Ensure 5” liners in mud pumps.
x White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @
96.5% volumetric efficiency.
Page 11
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
10.0 N/U 13-5/8” 5M Diverter System
10.1 N/U 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program).
x N/U 20” x 13-5/8” DSA
x N/U 13 5/8”, 5M diverter “T”.
x NU Knife gate & 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
x Utilized extensions if needed.
10.2 Notify AOGCC with 24 hour notice to witness. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure – AOGCC Regulation requirement
x Ensure that the annular closes in less than 30 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID less than or equal to 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
Page 12
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
10.4 Rig & Diverter Orientation:
x May change on location
Page 13
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD, in the Schrader OBd sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x There have been ‘directional dead zones’ noted in PBW. Directional plan has a build up in
DLS from 2 – 4, to allow gradual build. If possible get ahead of build rates while still
meeting tangent hold target.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability,ensure MW is at a 9.5 at
base of perm and at TD (pending MW increase due to hydrates). This is to combat
hydrates and free gas risk, based upon offset wells.
x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
Page 14
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
x Gas hydrates are not present at PBU L-Pad. But be prepared for gas hydrates. In PBW
they have been encountered typically around 1660’ TVD (Base of Perm) to 2740’ TVD (Top
Ugnu) and below. Be prepared for hydrates:
x Keep mud temperature as cool as possible, Target 60-70*F.
x Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as
cold pre-made mud on trucks ready.
x Drill through hydrate sands and quickly as possible, do not backream.
x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the
well. MW will not control gas hydrates, but will affect how gas breaks out at surface.
x Take MWD and GWD surveys every stand until magnetic interference cleans up. After
MWD surveys show clean magnetics, only take MWD surveys.
x Surface Hole AC, CF <1.0 :
x No wells with a CF < 1.0
11.4 12-1/4” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and
TD with 9.5+ ppg. MW for free gas and hydrates based upon offset wells
Depth Interval MW (ppg)
Surface – Base Permafrost 8.9+
Base Permafrost - TD 9.5+ (For Hydrates/Free Gas based on offset
wells)
x PVT System: PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, Toolpusher
office, and mud loggers office.
x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system
with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at
all times while drilling. Be prepared to increase the YP if hole cleaning becomes an
issue.
x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background
LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the
system while drilling the surface interval to prevent losses and strengthen the wellbore.
Page 15
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating
the high-clay content sections of the Sagavanirktok and the heavy oil sections of the
UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of
ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
x Casing Running:Reduce system YP with DESCO as required for running casing as
allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20
(check with the cementers to see what YP value they have targeted).
System Type:8.8 – 9.8 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp
Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F
System Formulation: Gel + FW spud mud
Product Concentration
Fresh Water
soda Ash
AQUAGEL
caustic soda
BARAZAN D+
BAROID 41
PAC-L /DEXTRID LT
ALDACIDE G
0.905 bbl
0.5 ppb
15 - 20 ppb
0.1 ppb (8.5 – 9.0 pH)
as needed
as required for 8.8 – 9.2 ppg
if required for <10 FL
0.1 ppb
11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity.
11.6 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
Page 16
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
12.0 Run 9-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” BTC x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8.75” on the location prior to running.
x Top 2,500’ of casing 47# drift 8.525”
x Actual depth to be dependent upon base of permafrost and stage tool
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” , 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” , 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint – 9-5/8” , 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
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Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
12.5 Float equipment and Stage tool equipment drawings:
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L-247 SB Producer
Drilling Procedure
12.6 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x Bowspring Centralizers only
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
x Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost (~ 2,500’ MD, actual depth based upon base of permafrost)
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damaged to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 47# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
9-5/8” 40# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8”18860 20960 23060
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L-247 SB Producer
Drilling Procedure
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L-247 SB Producer
Drilling Procedure
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L-247 SB Producer
Drilling Procedure
12.8 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 The last 2,500’ of 9-5/8” will be 47#, from 2,500’ to Surface
x Actual length of 47# may change due to depth of permafrost as drilled
x Ensure drifted to 8.525”
12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.11 Slow in and out of slips.
12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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Drilling Procedure
13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
12-1/4" OH x 9-5/8" Casing (6,200'-1,000'-2,500') x 0.0558 bpf x 1.3 195.8 1098.4
Total Lead 195.8 1098.4 467.4
12-1/4" OH x 9-5/8" Casing 1000' x 0.0558 bpf x 1.3 = 72.5 406.8
9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.0
Total Tail 81.6 457.8 394.7
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Drilling Procedure
Cement Slurry Design (1st Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very
accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool
hydraulically, the plug must be bumped.
13.11 Displacement calculation:
2500’ x 0.0732 bpf + (6,200’-120’-2500’) x .0758 bpf =
= 454.5 bbls
80 bbls of tuned spacer to be left behind stage tool for preventing of contamination of
cement in the annulus
13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer.
13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening
plug is available if needed. This is the back-up option to open the stage tool if the plugs are not
bumped.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Drilling Procedure
Second Stage Surface Cement Job:
13.18 Prepare for the 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
x Past wells have seen pressure increase while circulating through stage tool after reduced
rate
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. Cement will continue to be pumped until
clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
Section Calculation Vol (bbl) Vol (ft3) Vol (sks)
20" Cond x 9-5/8" Casing 110' x 0.26 bpf 28.6 160.4
12-1/4" OH x 9-5/8" Casing (2000' - 110) x .0558 x 3 316.4 1775.0
Total Lead 345.0 1935.5 679.1
12-1/4" OH x 9-5/8" Casing (2500 - 2000') x .0558 bpf x 2 55.8 313.0
Total Tail 55.8 313.0 267.6
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Lead Slurry Tail Slurry
System Arctic Cem HalCem
Density 11.0 lb/gal 15.8 lb/gal
Yield 2.85 ft3/sk 1.17 ft3/sk
Mixed
Water 14.6 gal/sk 5.08 gal/sk
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L-247 SB Producer
Drilling Procedure
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.26 Displacement calculation:
2500’ x 0.0732 bpf = 183 bbls mud
13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips.
13.30 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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L-247 SB Producer
Drilling Procedure
14.0 ND Diverter, NU BOPE, & Test
14.1 Give AOGCC 24hr notice of BOPE test, for test witness.
14.2 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.3 NU 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams
x NU bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve.
14.4 RU MPD RCD and related equipment
14.5 Run 5” BOP test plug
14.6 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
x Test with 5” test joint and test VBR’s with 3-1/2” test joint
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.7 RD BOP test equipment
14.8 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.9 Mix 8.9 ppg Baradrill-N fluid for production hole.
14.10 Set wearbushing in wellhead.
14.11 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.12 Ensure 5” liners in mud pumps.
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L-247 SB Producer
Drilling Procedure
15.0 Drill 8-1/2” Hole Section
15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure
on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT.
15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned. Submit
casing test and FIT digital data to AOGCC.
x 12.0 ppg desired to cover shoe strength for expected ECDs. A 9.9 ppg FIT is the minimum
required to drill ahead
x 9.9 ppg FIT provides >>25bbls based on 9.5ppg MW, 8.46ppg PP (swabbed kick at 9.5 BHP)
15.8 POOH and LD cleanout BHA
15.9 PU 8-1/2” directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 NC50.
x Run a ported float in the production hole section.
Email casing test and FIT digital data to AOGCC upon completion of FIT. email: melvin.rixse@alaska.gov
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Drilling Procedure
Schrader Bluff Bit Jetting Guidelines
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid
Properties:
Interval Density PV YP
LSYP Total Solids MBT HPH
T
Hardness
Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100
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L-247 SB Producer
Drilling Procedure
System Formulation:
Product Concentration
Water
KCL
KOH
N-VIS
DEXTRID LT
BARACARB 5
BARACARB 25
BARACARB 50
BARACOR 700
BARASCAV D
X-CIDE 207
0.955 bbl
11 ppb
0.1 ppb
1.0 – 1.5 ppb
5 ppb
4 ppb
4 ppb
2 ppb
1.0 ppb
0.5 ppb
0.015 ppb
15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Install MPD RCD
15.13 Displace wellbore to 9.2 ppg Baradrill-N drilling fluid
x Density may change based upon TD of surface hole section
15.14 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section. Reservoir plan is to stay in OBd sand.
x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
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L-247 SB Producer
Drilling Procedure
x Target ROP is as fast as we can clean the hole without having to backream connections
x Schrader Bluff OBd Concretions: 4-6% Historically
x MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Lateral A/C, CF < 1.0:
x There are no wells with CF <1.0
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being
removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + liner volume with viscosified brine.
x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) -
KCl: 7.1ppb for 2%
NaCl: 60.9ppg for 9.4ppg
Lotorq: 1.5%
Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42ppb
Flo-Vis Plus: 1.25ppb
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L-247 SB Producer
Drilling Procedure
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.15 Monitor the returned fluids carefully while displacing to brine.
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe
x Circulate at full drill rate (less if losses are seen, 350 GPM minimum).
x Rotate at maximum RPM that can be sustained.
x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
x If backreaming operations are commenced, continue backreaming to the shoe
15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.23 POOH and LD BHA.
15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
x Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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Drilling Procedure
16.0 Run 5-1/2”Liner
16.1 Note: If there are any OHST performed, remove the centralizers on the first 3 joints
16.2 Well control preparedness: In the event of an influx of formation fluids while running the 5-
1/2” liner, the following well control response procedure will be followed:
x P/U & M/U the 5” safety joint (with 5-1/2” crossover installed on bottom, TIW valve in open
position on top, 5-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 5-1/2” liner.
x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.
x Proceed with well kill operations.
16.3 R/U 5-1/2” liner running equipment.
x Ensure 5-1/2” 17# JFE Bear x NC50 crossover is on rig floor and M/U to FOSV.
x Ensure all casing has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.4 Run 5-1/2” slotted liner
x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x Install joints as per the Running Order (From Completion Engineer post TD).
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
5-1/2” 17# JFEbear Torque – ftlbs
OD Minimum Optimum Maximum Yield Torque
5-1/2” 6660 7400 8140 11100
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Drilling Procedure
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Drilling Procedure
16.6. Ensure to run enough liner to provide for sufficient overlap inside 9-5/8” casing for gas lift
completion. Tentative liner set depth ~ 6000’ MD
x Confirm set depth with completion engineer.
x 3-5 joints of 7” may be ran under the liner hanger for the production packer. Confirm with
completion engineer.
16.7. Ensure hanger/pkr will not be set in a 9-5/8” connection.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection.
16.8. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.9. M/U Baker SLZXP liner top packer to 5-1/2” liner.
x Confirm with OE any 7” joints between liner top packer and 5-1/2” liner for GLM
and packer setting depth
16.10. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.11. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
x Ensure 5” DP/HWDP has been drifted
x There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
x Use HWDP as needed for running liner
16.12. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.13. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.14. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
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Drilling Procedure
16.15. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.16. Rig up to pump down the work string with the rig pumps.
16.17. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
16.18. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.19. Shut down pumps. Drop setting ball (ball seat now located in HRDE setting tool and not at the
WIV) down the workstring and pump slowly (1-2 BPM). Slow pump before the ball seats. Do
not allow ball to slam into ball seat.
16.20. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
16.21. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
16.22. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.23. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.24. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.25. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
Page 37
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
17.0 Run 7” Tieback
17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder
to be used for tie-back space out calculation.
17.2 Notify AOGCC 24hrs prior to ram change
17.3 Install 7” solid body casing rams in the upper ram cavity if needed. RU testing equipment. PT
to 250/3,000 psi with 7” test joint. RD testing equipment.
17.4 RU 7” casing handling equipment.
x Ensure XO to DP made up to FOSV and ready on rig floor.
x Rig up computer torque monitoring service.
x String should stay full while running, RU fill up line and check as appropriate.
17.5 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes
above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7”
annulus.
17.6 MU first joint of 7” to seal assy.
17.6 Run 7”, 29#, L-80 VAMTOP 6.125” Drift tieback to position seal assembly two joints above
tieback sleeve. Record PU and SO weights.
17.7 Tieback to be Torque turned.
7”, 29#, L-80, VAMTOP 6.125” drift
=Casing OD Torque (Min) Torque (Opt)Torque (Max)
7”8460 9400 10340
Page 38
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
17.8 MU 7” to DP crossover.
17.9 MU stand of DP to string, and MU top drive.
17.10 Break circulation at 1 BPM and begin lowering string.
17.11 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
17.12 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO-
GO DEPTH”.
17.13 PU string & remove unnecessary 7” joints.
17.14 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing
hanger is landed. Ensure one full joint is below the casing hanger.
17.15 PU and MU the 7” casing hanger.
Page 39
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
17.16 Ensure circulation is possible through 7” string.
17.17 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus.
17.18 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface
in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure
annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7”
tieback seal assembly).
17.19 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
17.20 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing
joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes.
17.21 RD casing running tools.
17.22 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted.
Page 40
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
18.0 Run Upper Completion/ Post Rig Work
18.1 RU to run 4-1/2”, 12.6#, L-80 JFEBEAR tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 12.6#, JFEBEAR x NC50 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.
x Monitor displacement from wellbore while RIH.
18.2 PU, MU and RIH with the following 4-1/2” completion jewelry (tally to be provided by
Operations Engineer):
x Tubing Jewelry to include:
x 1x X Nipple
x 4x GLM
x 1x SSD
x 1x Gauge Carrier
x 1x X Nipple with RHC
x 1x Production Packer
i. Confirm packer set depth with OE for post rig wire line ball and rod retrieval.
x 1x X Nipple with RHC
x XXX joints, 4-1/2”, 12.6#, L-80, JFEBEAR
x XX joints 4-1/2”, 12.6# 13cr VAMTOP
x 1x WLEG
Page 41
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
Page 42
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
18.3 PU and MU the 4-1/2” tubing hanger.
18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
18.5 Land the tubing hanger and RILDS. Lay down the landing joint.
18.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
18.7 NU the tubing head adapter and NU the tree.
18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
18.9 Pull the plug off tool and BPV.
18.10 Reverse circulate the well over to corrosion inhibited KCL.
18.11 Drop the ball & rod and land in X-Nip between gauge carrier and packer
18.12 Pressure up and test the tubing to 3500 psi for MIT-T.
18.13 Bleed both the IA and tubing to 0 psi.
Page 43
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
18.14 RDMO Innovation
i. POST RIG WELL WORK
1. Slickline
a. Pull RHC plug Body
b. Drop B&R to set Packer
c. MIT-T to 3,500psi
d. Bleed TBG to 2,000psi, MIT-IA to 3,500psi
e. Bleed TBG pressure to shear SOV
f. U-Tube FP
g. Change out GLV per GL ENGR
h. Pull ball and rod and RHC
2. Well Tie in
30 minute charted - mgr
Page 44
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
19.0 Innovation Rig Diverter Schematic
Page 45
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
20.0 Innovation Rig BOP Schematic
Page 46
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
21.0 Wellhead Schematic
Page 47
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
22.0 Days Vs Depth
Page 48
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
23.0 Formation Tops & Information
Reference Plan:
COMMENTS
SV5 Ice 1,762 1,605.0 -1531 706 8.46
BPRF Water 1,939 1,748.0 -1674 769 8.46
SV3 Gas Hydrates 2,304 2,042.0 -1968 898 8.46 Gas Hydrates expected SV3, SV2, & SV1 sands: ~2300' - 3050' MD
SV1 Gas Hydrates 2,886 2,512.0 -2438 1105 8.46
Ugnu 4A Heavy Oil 3,268 2,821.0 -2747 1241 8.46 Possible Heavy Oil in Ugnu 4A: ~ 3300' - 3400' MD
UG3 Water 3,678 3,152.0 -3078 1387 8.46
Ugnu LA Water 4,357 3,700.0 -3626 1628 8.46
Ugnu MB Water 4,614 3,903.0 -3829 1717 8.46
NA Schrader Bluff Water 4,900 4,108.0 -4034 1808 8.46
OA Top Schrader Bluff Water 5,172 4,270.0 -4196 1879 8.46
Obc Top Schrader Bluff Oil 5,599 4,439.0 -4365 1953 8.46
OBd Top (Heel) Schrader Bluff Oil 5,988 4,489.0 -4415 1975 8.46
OBd (Toe) 20,394 4,249.0 -4175 1870 8.46
L-247 wp05ANTICIPATED FORMATION TOPS & GEOHAZARDS
TOP NAME LITHOLOGY EXPECTED
FLUID
MD
(FT)
TVD
(FT)
TVDSS
(FT)NORTHING EASTING Est.
Pressure Gradient
Page 49
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
Page 50
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
24.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates/Free Gas
Gas hydrates have not been seen on PBU L Pad. Be prepared for them. They have been reported
between 1660’ and 3140’ TVD across Prudhoe. MW has been chosen based upon successful trouble free
penetrations of offset wells.
x Be prepared for gas hydrates
o Keep mud temperature as cool as possible, Target 60-70*F
o Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as
cold premade mud on trucks ready
o Drill through hydrate sands and quickly as possible, do not backream.
Remember that hydrate gas behaves differently from a gas sand. Additional fluid density will not
prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been
disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible
while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone.
Excessive circulation will accelerate formation thawing which can increase the amount of hydrates
released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with
both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud
cut weight. Isolate/dump contaminated fluid to remove hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe
moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after
slide intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any
close approaches on AM report.
Well Specific A/C:
x No wells with CF < 1.0
Page 51
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-Pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 52
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
Crossing faults, known or unknown, can result in drilling into unstable formations that may impact
future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared
for accordingly.
H2S:
Treat every hole section as though it has the potential for H2S. PBU L-Pad has a history of H2S on
wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion
Pool.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 53
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
Well Specific A/C:
x No wells with CF < 1.0
Page 54
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
25.0 Innovation Rig Layout
Page 55
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
26.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 56
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
27.0 Innovation Rig Choke Manifold Schematic
Page 57
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
28.0 Casing Design
Page 58
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
29.0 8-1/2” Hole Section MASP
Page 59
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 60
Prudhoe Bay West
L-247 SB Producer
Drilling Procedure
31.0 Surface Plat (NAD 27)
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1000
2000
3000
4000
5000
6000
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-1000 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000 18000
Vertical Section at 298.00° (2000 usft/in)
L-247 wp02 tgt1
L-247 wp02 tgt2
L-247 wp02 tgt3
L-247 wp02 tgt4
L-247 wp02 tgt
9 5/8" x 12 1/4"
6 5/8" x 8 1/2"
5 0 0
1 0 0 0
1 5 0 0
2 0 0 0
2 5 0 0
3 0 0 0
3 5 0 0
4 0 0 0
4 5 0 0
5 0 0 0
5500
6000
6500
7000
7500
8000
8500
9000
9500
10000
10500
11000
115
00
12000
12500
13000
13500
14000
14500
15000
15500
16000
16500
17000
17500
18000
18500
19000
19500
20000
20540
L-247 wp05
Start Dir 3º/100' : 250' MD, 250'TVD
Start Dir 4º/100' : 550' MD, 548.77'TVD
End Dir : 1272.5' MD, 1208.93' TVD
Start Dir 5º/100' : 4416.37' MD, 3746.87'TVD
End Dir : 5887.76' MD, 4483.37' TVD
Start Dir 2º/100' : 5987.76' MD, 4488.6'TVD
End Dir : 6187.38' MD, 4492.1' TVD
Begin geosteering lateral
Total Depth : 20540.19' MD, 4248.6' TVD
SV5
BPRF
SV3
SV1
Ugnu 4A
UG3
Ugnu LA
Ugnu MB
NA OA
Obc
Obd
Hilcorp North Slope, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: Plan: L-247
47.10
+N/-S +E/-W
Northing Easting Latitude Longitude
0.00 0.00 5978156.28 582711.55 70° 21' 1.1022 N 149° 19' 42.5029 W
SURVEY PROGRAM
Date: 2023-05-18T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
26.50 1500.00 L-247 wp05 (L-247) GYD_Quest GWD
1500.00 6200.00 L-247 wp05 (L-247) 3_MWD+IFR2+MS+Sag
6200.00 20540.19 L-247 wp05 (L-247) 3_MWD+IFR2+MS+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
1604.60 1531.00 1762.64 SV5
1747.60 1674.00 1939.78 BPRF
2041.60 1968.00 2303.97 SV3
2511.60 2438.00 2886.18 SV1
2820.60 2747.00 3268.95 Ugnu 4A
3151.60 3078.00 3678.97 UG3
3699.60 3626.00 4357.81 Ugnu LA
3902.60 3829.00 4614.12 Ugnu MB
4107.60 4034.00 4900.37 NA
4269.60 4196.00 5172.12 OA
4438.60 4365.00 5599.34 Obc
4488.60 4415.00 5987.76 Obd
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: L-247, True North
Vertical (TVD) Reference:L-247 as built RKB @ 73.60usft
Measured Depth Reference:L-247 as built RKB @ 73.60usft
Calculation Method:Minimum Curvature
Project:Prudhoe Bay
Site:L
Well:Plan: L-247
Wellbore:L-247
Design:L-247 wp05
CASING DETAILS
TVD TVDSS MD Size Name
4491.88 4418.28 6200.00 9-5/8 9 5/8" x 12 1/4"
4248.60 4175.00 20540.19 6-5/8 6 5/8" x 8 1/2"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.00
2 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD
3 550.00 9.00 250.00 548.77 -8.04 -22.10 3.00 250.00 15.73 Start Dir 4º/100' : 550' MD, 548.77'TVD
4 800.00 19.00 250.00 791.03 -28.70 -78.86 4.00 0.00 56.15
5 1272.50 36.17 232.05 1208.93 -141.77 -262.76 4.00 -34.15 165.44 End Dir : 1272.5' MD, 1208.93' TVD
6 4416.37 36.17 232.05 3746.87 -1282.73 -1725.95 0.00 0.00 921.72 Start Dir 5º/100' : 4416.37' MD, 3746.87'TVD
7 5887.76 87.00 297.96 4483.37 -1192.51 -2880.44 5.00 71.89 1983.43 End Dir : 5887.76' MD, 4483.37' TVD
8 5987.76 87.00 297.96 4488.60 -1145.69 -2968.65 0.00 0.00 2083.29 L-247 wp02 tgt1 Start Dir 2º/100' : 5987.76' MD, 4488.6'TVD
9 6187.38 90.99 297.96 4492.10 -1052.13 -3144.91 2.00 -0.03 2282.84 End Dir : 6187.38' MD, 4492.1' TVD
10 11008.09 90.99 297.96 4408.60 1207.60 -7402.36 0.00 0.00 7102.83 L-247 wp02 tgt2
11 11049.63 91.81 298.13 4407.59 1227.13 -7439.01 2.00 11.60 7144.35
12 14190.06 91.81 298.13 4308.60 2706.79 -10207.24 0.00 0.00 10283.22 L-247 wp02 tgt3
13 14251.74 90.57 298.08 4307.32 2735.84 -10261.63 2.00 -177.95 10344.88
14 19119.65 90.57 298.08 4258.60 5027.15 -14556.30 0.00 0.00 15212.55 L-247 wp02 tgt4
15 19150.05 90.40 297.50 4258.34 5041.32 -14583.18 2.00 -106.43 15242.94
16 20540.19 90.40 297.50 4248.60 5683.15 -15816.25 0.00 0.00 16633.00 L-247 wp02 tgt5 Total Depth : 20540.19' MD, 4248.6' TVD
-5000
-4000
-3000
-2000
-1000
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4000
5000
6000
7000
8000
9000
So
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-17000 -16000 -15000 -14000 -13000 -12000 -11000 -10000 -9000 -8000 -7000 -6000 -5000 -4000 -3000 -2000 -1000 0 1000
West(-)/East(+) (2000 usft/in)
L-247 wp02 tgt5
L-247 wp02 tgt4
L-247 wp02 tgt3
L-247 wp02 tgt2
L-247 wp02 tgt1
9 5/8" x 12 1/4"
6 5/8" x 8 1/2"
250
1
0
0
0
1
5
0
02
0
0
02
5
0
03
0
0
03
5
0
04
0
0
0
4250
4249L-247 wp05
Start Dir 3º/100' : 250' MD, 250'TVD
Start Dir 4º/100' : 550' MD, 548.77'TVD
End Dir : 1272.5' MD, 1208.93' TVD
Start Dir 5º/100' : 4416.37' MD, 3746.87'TVD
End Dir : 5887.76' MD, 4483.37' TVD
Start Dir 2º/100' : 5987.76' MD, 4488.6'TVD
End Dir : 6187.38' MD, 4492.1' TVD
Begin geosteering lateral
Total Depth : 20540.19' MD, 4248.6' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4491.88 4418.28 6200.00 9-5/8 9 5/8" x 12 1/4"
4248.60 4175.00 20540.19 6-5/8 6 5/8" x 8 1/2"
Project: Prudhoe Bay
Site: L
Well: Plan: L-247
Wellbore: L-247
Plan: L-247 wp05
WELL DETAILS: Plan: L-247
47.10
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 5978156.28 582711.55
70° 21' 1.1022 N 149° 19' 42.5029 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: L-247, True North
Vertical (TVD) Reference: L-247 as built RKB @ 73.60usft
Measured Depth Reference:L-247 as built RKB @ 73.60usft
Calculation Method:Minimum Curvature
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0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175
Measured Depth (650 usft/in)
L-205A
L-246 wp05
L-100
NWE1-01
No-Go Zone - Stop Drilling
Collision Avoidance Required
Collision Risk Procedures Req.
WELL DETAILS:Plan: L-247 NAD 1927 (NADCON CONUS)Alaska Zone 04
47.10
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 5978156.28 582711.55 70° 21' 1.1022 N 149° 19' 42.5029 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: L-247, True North
Vertical (TVD) Reference: L-247 as built RKB @ 73.60usft
Measured Depth Reference:L-247 as built RKB @ 73.60usft
Calculation Method:Minimum Curvature
SURVEY PROGRAM
Date: 2023-05-18T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
26.50 1500.00 L-247 wp05 (L-247) GYD_Quest GWD
1500.00 6200.00 L-247 wp05 (L-247) 3_MWD+IFR2+MS+Sag
6200.00 20540.19 L-247 wp05 (L-247) 3_MWD+IFR2+MS+Sag
0.00
30.00
60.00
90.00
120.00
150.00
180.00
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0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175
Measured Depth (650 usft/in)
L-292
L-05 wp06
L-294 wp03
L-231
L-253
L-233
GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
26.50 To 20540.19
Project: Prudhoe Bay
Site: L
Well: Plan: L-247
Wellbore: L-247
Plan: L-247 wp05
Ladder / S.F. Plots
1 of 2
CASING DETAILS
TVD TVDSS MD Size Name
4491.88 4418.28 6200.00 9-5/8 9 5/8" x 12 1/4"
4248.60 4175.00 20540.19 6-5/8 6 5/8" x 8 1/2"
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6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 15000 15750 16500 17250 18000 18750 19500 20250
Measured Depth (1500 usft/in)
L-246 wp05
No-Go Zone - Stop Drilling
Collision Avoidance Required
Collision Risk Procedures Req.
WELL DETAILS:Plan: L-247 NAD 1927 (NADCON CONUS)Alaska Zone 04
47.10
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 5978156.28 582711.55 70° 21' 1.1022 N 149° 19' 42.5029 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: L-247, True North
Vertical (TVD) Reference: L-247 as built RKB @ 73.60usft
Measured Depth Reference:L-247 as built RKB @ 73.60usft
Calculation Method:Minimum Curvature
SURVEY PROGRAM
Date: 2023-05-18T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
26.50 1500.00 L-247 wp05 (L-247) GYD_Quest GWD
1500.00 6200.00 L-247 wp05 (L-247) 3_MWD+IFR2+MS+Sag
6200.00 20540.19 L-247 wp05 (L-247) 3_MWD+IFR2+MS+Sag
0.00
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60.00
90.00
120.00
150.00
180.00
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6750 7500 8250 9000 9750 10500 11250 12000 12750 13500 14250 15000 15750 16500 17250 18000 18750 19500 20250
Measured Depth (1500 usft/in)
GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
26.50 To 20540.19
Project: Prudhoe Bay
Site: L
Well: Plan: L-247
Wellbore: L-247
Plan: L-247 wp05
Ladder / S.F. Plots
2 of 2
CASING DETAILS
TVD TVDSS MD Size Name
4491.88 4418.28 6200.00 9-5/8 9 5/8" x 12 1/4"
4248.60 4175.00 20540.19 6-5/8 6 5/8" x 8 1/2"
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
SCHRADER BLUF OIL, ORION DEVELOPMENT
223-081
PRUDHOE BAY
PBU L-247
X
WELL PERMIT CHECKLIST
Company Hilcorp North Slope, LLC
Well Name:PRUDHOE BAY UNIT L-247
Initial Class/Type DEV / PEND GeoArea 890 Unit 11650 On/Off Shore On
Program DEVField & Pool Well bore seg
Annular DisposalPTD#:2230810
PRUDHOE BAY, SCHRADER BLUF OIL - 640135
NA1 Permit fee attached
Yes2 Lease number appropriate
Yes ADL028239 and ADL0474493 Unique well name and number
Yes PRUDHOE BAY, SCHRADER BLUF OIL - 640135 - governed by 505B, 505B.0044 Well located in a defined pool
Yes5 Well located proper distance from drilling unit boundary
NA6 Well located proper distance from other wells
Yes7 Sufficient acreage available in drilling unit
Yes8 If deviated, is wellbore plat included
Yes9 Operator only affected party
Yes10 Operator has appropriate bond in force
No Pending issuance of CO 505C (Expansion of Schrader Bluff Oil Pool)11 Permit can be issued without conservation order
Yes12 Permit can be issued without administrative approval
Yes13 Can permit be approved before 15-day wait
NA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For serv
NA15 All wells within 1/4 mile area of review identified (For service well only)
NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)
NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)
Yes 20" 129.5# X-52 grouted to 107'18 Conductor string provided
Yes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir19 Surface casing protects all known USDWs
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20 CMT vol adequate to circulate on conductor & surf csg
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21 CMT vol adequate to tie-in long string to surf csg
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22 CMT will cover all known productive horizons
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.23 Casing designs adequate for C, T, B & permafrost
Yes Innovation rig has adequate tankage and good trucking support24 Adequate tankage or reserve pit
NA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approved
Yes Halliburton collision scan shows no close approaches.26 Adequate wellbore separation proposed
Yes 16" Diverter below BOPE27 If diverter required, does it meet regulations
Yes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequate
Yes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulation
Yes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)
Yes Innovation has 2-9/16" piper ball valves, 1 manual and 1 remote hydraulic choke.31 Choke manifold complies w/API RP-53 (May 84)
Yes32 Work will occur without operation shutdown
Yes PBU L pad has H2S history. Monitoring will be required.33 Is presence of H2S gas probable
NA This well is a Oil Development well.34 Mechanical condition of wells within AOR verified (For service well only)
No PBU L-Pad is H2S bearing. Max reading at L-204 (2021) is 300ppm35 Permit can be issued w/o hydrogen sulfide measures
Yes No overpressure anticicpated. Poetential for gas hydrates and heavy oil in 12.25" hole section.36 Data presented on potential overpressure zones
NA37 Seismic analysis of shallow gas zones
NA38 Seabed condition survey (if off-shore)
NA39 Contact name/phone for weekly progress reports [exploratory only]
Appr
ADD
Date
13-Sep-23
Appr
MGR
Date
06-Sep-23
Appr
ADD
Date
13-Sep-23
Administration
Engineering
Geology
Geologic
Commissioner:Date:Engineering
Commissioner:Date Public
Commissioner Date
*&:
