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Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 8/27/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240827
Well API #PTD #Log Date Log
Company Log Type AOGCC Eset#
BCU 23 50133206350000 214093 7/18/2024 AK E-LINE PPROF
BRU 222-24 50283201800000 220043 8/8/2024 AK E-LINE Perf
BRU 222-26 50283201950000 224035 8/6/2024 AK E-LINE Perf
BRU 222-26 50283201950000 224035 7/16/2024 AK E-LINE Perf
BRU 241-26 50283201970000 224068 8/12/2024 AK E-LINE Perf
BRU 241-34S 50283201980000 224077 8/2/2024 AK E-LINE Perf
BRU 241-34S 50283201980000 224077 7/28/2024 HALLIBURTON CAST-CBL
IRU 44-36 50283200890000 193022 8/10/2024 AK E-LINE PlugPerf
PBU 18-13D 50029217560400 224039 8/2/2024 HALLIBURTON RBT
PBU 18-33A 50029225980100 204070 8/13/2024 HALLIBURTON RBT
PBU Z-228 50029237180000 222055 7/28/2024 HALLIBURTON PPROF
PBU Z-234 50029237620000 223065 7/29/2024 HALLIBURTON IPROF
PCU 2 50283200229000 179009 7/9/2024 AK E-LINE TubingCut
TBU M-02 50733203890000 187061 8/6/2024 AK E-LINE CBL
TBU M-02 50733203890000 187061 8/12/2024 AK E-LINE Perf
Please include current contact information if different from above.
T39491
T39492
T39493
T39493
T39494
T39495
T39495
T39496
T39497
T39498
T39499
T39500
T39501
T39502
T39502
PBU Z-234 50029237620000 223065 7/29/2024 HALLIBURTON IPROF
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.08.27 11:27:22 -08'00'
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: 09/15/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: PBU Z-234
PTD: 223-065
API: 50-029-23762-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (08/15/2023 to 08/27/2023)
x ROP, AGR, DGR, ABG, ADR, EWR-M5, 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 Z-234 LWD Subfolders:
PBU Z-234 Geosteering Subfolders:
Please include current contact information if different from above.
PTD: 223-065
T37999
9/18/2023Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.09.18
10:02:17 -08'00'
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Tuesday, October 17, 2023
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Austin McLeod
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp North Slope, LLC
Z-234
PRUDHOE BAY UN ORIN Z-234
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 10/17/2023
Z-234
50-029-23762-00-00
223-065-0
G
SPT
4660
2230650 1500
1849 1854 1845 1845
140 459 456 454
INITAL P
Austin McLeod
9/11/2023
Initial test. PKR TVD taken from directional survey.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:PRUDHOE BAY UN ORIN Z-234
Inspection Date:
Tubing
OA
Packer Depth
340 2487 2439 2425IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitSAM230911184358
BBL Pumped:1.4 BBL Returned:1.5
Tuesday, October 17, 2023 Page 1 of 1
"
By Grace Christianson at 12:53 pm, Sep 22, 2023
Completed
8/31/2023
JSB
RBDMS 092823 JSB
GDSR-10/9/23
Drilling Manager
09/20/23
Monty M
Myers
Digitally signed by Torin
Roschinger (4662)
DN: cn=Torin Roschinger (4662),
ou=Users
Date: 2023.09.20 14:46:52 -08'00'
Torin
Roschinger
(4662)
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:PBU Z-234 Date:8/26/2023
Csg Size/Wt/Grade:9.625" 40/47# L-80 Supervisor:Lott/Montague
Csg Setting Depth:8415 TMD 4957 TVD
Mud Weight:9.1 ppg LOT / FIT Press =760 psi
LOT / FIT =12.05 ppg Hole Depth =8444 md
Fluid Pumped=1.7 Volume Back =1.5 bbls
Estimated Pump Output:0.062 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->06 ->00
->260 ->8192
->4115 ->16 426
->6175 ->24 653
->8229 ->32 866
->10 289 ->40 1110
->12 348 ->48 1353
->14 399 ->56 1608
->16 453 ->64 1848
->18 505 ->72 2099
->20 554 ->80 2351
->22 602 ->88 2612
->24 649 ->89 2632
->28 760 ->
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0760 ->02632
->1730 ->12626
->2724 ->22623
->3713 ->32622
->4706 ->42621
->5700 ->52620
->6694 ->10 2613
->7689 ->15 2608
->8684 ->20 2605
->9676 ->25 2602
->10 674 ->30 2600
-> ->
-> ->
-> ->
0
2
4
6
8
10
12
14
16
18
20
22
24
28
0
8
16
24
32
40
48
56
64
72
80
8889
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 102030405060708090100
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
760730724713706700694689684676674
263226262623262226212620 2613 2608 2605 2602 2600
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
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
Activity Date Ops Summary
8/13/2023 PJSM Spot & shim Sub over Z-234. Level diverter tee. Set & level cattle chute, pipe shed, Mud and Gen mod. Set rig matts. Released truck at 20:30. Set SIMOPS
Install new shakers in pits. PJSM Set down stairs and landings around rig. Swap to gen power at 21:00. Scope up derrick and bridle down. Work on rig acceptance
list. Set cutting box, enviro vac and break shack. PJSM Cont rig acceptance check list. Function test all equip. R/U 5" hydraulic elevators. Rebuilt leaking Stucci
fitting. Send down U Tube manifold. P/U Master bushing's. Swap out riser. PJSM Remove RCD head F/ Stack. Move stack under mouse hole opening and suspend
with tuggers. Move stack back to pedestal and set down RCD head. Remove skate flaps and grind out due to binding. PSM P/U Bell Nipple and set on BOP. N/U
BOP to diverter Tee. Secure BOP W/ chain and binders. Install 4" conductor valves. Install riser.
8/14/2023 Install Knife valve on Diverter, add additional Diverter sticks out from under Sub and Catwalk. Take Vent Line measurements, ensuring ignition sources >75' away.
add barriers. Install Short Mousehole. Finalize Straps in Shed on DP and HWDP. Added nitrogen to Accumulator bottles and energize Accumulator. DD/MWD Strap
BHA. SIMOPS: Continue work on installing new Shakers in pits. P/U 264 joints of 5" DP 19.5# S-135 (3.125" OD Drift) and 17 joints of 5" 49.5# HWDP (2.75"
Drift). Load 580 bbls of 8.8ppg Spud Mud into the pits. RKB Ann 11.01' Knife Valve 22.48' GL 26.79'. SIMOPS Cont to install new shakers. PJSM Cut and slip
drilling line. TM 885, ACCOMTM 1631. 10 wraps (63') Left on spool 3,681'. Complete shaker install. Rig Accepted at 23:00. Rig service. Grease crown, blocks,
PH8, TD and spinners. Check oil in rotary table and TD. Derrick inspection. Calibrate blocks. Perform Annular closure 11 sec, knife 8 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 1950 PSI, 200 PSI
increase 18 Sec, full charge 56 sec. Nitrogen 6 bottle average 2,233 PSI. Witnessed waived by AOGCC Rep Sully Sullivan. PJSM W/ all parties. Discuss P/U BHA,
rig evacuation, well control, man down, fire, gas hydrates, broaching and muster area's. P/U M/U BHA #1 Clean Out 12.25"KMX525 Hybrid (Jets 1X13, 3X11,4X12,
TFA 0.8498) & 8" TerraForce 1.5 deg Motor to 33.38'. Flood lines and PT to 3,000 psi. Wash down/ drill 12,25" surface F/ 38' to 220' MD. Tagged fill 41' MD. 350
gpm 280 psi 30 rom Trq 1.5k WOB 1-3.5k ROP 105-200 fpm. P/U 45k SLK 44k ROT 44k. At 117' MD Heavy sand w/ some gravel. At 137' MD started seeing
dynamic losses. Lost 86 bbls. POOH. Jetting flowline. PJSM Inspect Bit 1-1. P/U M/U to motor 8" GWD, 8" DM, 8" EWR-M5 & 8" TM. Daily disposal to G&I: 0 bbls
total 0 bbls. Daily disposal to MPU: 0 bbl total: 0 bbls. Daily H2O Lake 2: 680 bbls total 680 bbls. Daily Lost: 0 bbls Surface total: 0 bbls.
8/15/2023 Continue to M/U 12-1/4" Directional BHA. M/U TM Collar and download MWD. P/U 2x Non-Mag Flex Collars and run in the hole with HWDP. Tag Fill at 199'. MWD
to Motor = 24.35deg, MWD to Gyro = 220.78deg. P/U=54K, S/O=51K. Wash Down F/199' - T/220' MD. Drill ahead F/220' - T/298' MD at 375gpm=900/650psi
on/off with a RF=46%. Spud Mud is at 8.85/8.9ppg in/out with an ECD of 9.62ppg. WOB=3.5K, P/U=53K, S/O=57K, ROTW=55K. Pumping through bleeder as
necessary and mitigating packed off drag chain (2x). Troubleshoot Pulser. MWD Pulser not working, suspecting a stuck pulser. POOH on Elevators F/298' - T/98'
(TM Collar). Download MWD to verify good detection across tools - Yes. Pull Pulser and replace. RIH T/298' and shallow test tools - Good. Drill 12-1/4" Surface
Hole F/298' - T/693' MD 690' TVD (Total=395', AROP=88'). 450gpm=940/915psi on/off. TQ=2-3Kft-lbs with 30RPM (75/25% Slide/Rot), WOB=4-5K. P/U=64K,
S/O=66K, ROTW=65K. Continually jet flowline and pump through bleeder as necessary. Maintain 4deg/100' Build. Loss of 35 bbls. Drill 12-1/4" Surface Hole
F/693' - T/1260' MD 1202' TVD (Total=509', AROP=85'). 475gpm=1245/1150psi on/off. TQ=2-3Kft-lbs with 30RPM (75/25% Slide/Rot), WOB=7-10K. P/U=78K,
S/O=75K, ROTW=76K. Continually jet flowline and pump through bleeder as necessary. Maintain 4deg/100' Build. Last Gyro survey at 1189.42'. Drill 12-1/4"
Surface Hole F/1260' - T/1929' MD 1655' TVD (Total=669', AROP=112'). 525gpm=1530/11400psi on/off. TQ=5-6Kft-lbs with 50RPM (50/50% Slide/Rot), WOB=5-
8K. P/U=84K, S/O=71K, ROTW=79K. Continually jet flowline and pump through bleeder as necessary. Start of tangent section at 1724'. Distance to WP02:
19.65',19.62' high, 1.11' right. Daily fluid lost to formation 413 bbls, total 413 bbls.
8/16/2023 Drill 12-1/4" Surface Hole F/1,929' - T/2,562' MD 2,047' TVD (Total: 633', AROP: 106'). 500gpm=1680/1620psi on/off. TQ=6-8/6-9Kft-lbs with 80RPM (Perform
maintenance slides for 54deg tangent) and 5-8K WOB. ECD's=10.46ppg with 9.4ppg in/out. P/U=100K, S/O=66K, ROTW=82K. Backream Full stands. GEO
confirmed the base of the Permafrost to be at 2,263' MD 1,967' TVD. Drill 12-1/4" Surface Hole F/2,562' - T/3485' MD 2594' TVD (Total: 923', AROP: 153').
500gpm=1660/1530psi on/off. TQ=7-8/6-7Kft-lbs with 80RPM (Perform maintenance slides for 54deg tangent) and 5-8K WOB. ECD's=10.85ppg with 9.8ppg
in/out. P/U=100K, S/O=66K, ROTW=82K. Backream Full stands. Max Gas=4,559u, BGG=2,800-3,600u. Both Centrifuges on to reduce weight back down to
9.5ppg. Drill 12-1/4" Surface Hole F/3485' - T/4152' MD 2959' TVD (Total: 667', AROP: 111'). 400gpm=1320/1220psi on/off. TQ=8/7Kft-lbs with 80RPM (Perform
maintenance slides for 54deg tangent) and 5-8K WOB. ECD's=10.6ppg with 9.8ppg in/ 9.9out. P/U=100K, S/O=66K, ROTW=82K. Backream Full stands. Max
Gas=4,615u, BGG=2,800-3,600u. Both Centrifuges on to reduce weight back down to 9.5ppg. Drill 12-1/4" Surface Hole F/4152' - T/4631' MD 3259' TVD (Total:
479', AROP: 80'). 500gpm=1820/1690psi on/off. TQ=8-11/9-12Kft-lbs with 80RPM (Perform maintenance slides for 54deg tangent) and 6-12K WOB.
ECD's=10.59ppg with 9.6ppg in/out. P/U=130K, S/O=82K, ROTW=103K. Backream Full stands. Max Gas=4,615u, BGG=2,800-3,600u. Did a 100 bbl dump and
dilute and both Centrifuges on to reduce weight back down to 9.5ppg. Distance to plan: 8.99', 4.88' low, 7.55' right.
8/17/2023 Drill 12-1/4" Surface Hole F/4,631' - T/4,885' MD 3,451' TVD (Total: 254', AROP: 43'). 525gpm=2020/1730psi on/off. TQ=9-11/8-11Kft-lbs with 80RPM (Perform
maintenance slides for 54deg tangent) and 4-10K WOB. ECD's=10.21ppg with 9.4/9.6ppg in/out. P/U=136K, S/O=82K, ROTW=105K. Max Gas=2,526u,
BGG=400-1200u. Backream Full stands. Increase Drill N' Slide concentration. Drill 12-1/4" Surface Hole F/4,885' - T/5298' MD 3678' TVD (Total: 413', AROP: 68').
500gpm=1820/1690psi on/off. TQ=8-11/9-12Kft-lbs with 80RPM (Perform maintenance slides for 54deg tangent) and 6-12K WOB. ECD's=10.59ppg with 9.6ppg
in/out. P/U=130K, S/O=82K, ROTW=103K. Max Gas=3,786u, BGG=200-800u. Drilled T/5,170' and pumped a 40 bbl CONDET/Walnut Sweep to help reduce
possible bit balling due to the occasional decreases in ROP. no change in performance. Drill 12-1/4" Surface Hole F/5298' - T/5510' MD 3807' TVD (Total: 212',
AROP: 35'). 550gpm=2140/1998psi on/off. TQ=12-15/11-14Kft-lbs with 80RPM (Perform maintenance slides for 54deg tangent) and 13-28K WOB.
ECD's=10.12ppg with 9.5ppg in/out. P/U=130K, S/O=82K, ROTW=103K. Backream full stands. Max Gas=2731u, BGG=200-800u. F/5420 T/5478 very slow ROP
avg 20'/hr for stand. Vary parameters in an attempt to increase ROP. Perform 290 bbl dump and dilute. Pump 30bbl drill n slide/nut plug sweep to help with
possible bit balling. Drill 12-1/4" Surface Hole F/5510' - T/5997/' MD 4096' TVD (Total: 487', AROP: 81'). 550gpm=2250/2190psi on/off. TQ=14-16/12-14Kft-lbs
with 80RPM, 13-28K WOB. ECD's=10.12ppg with 9.5ppg in/out. P/U=163K, S/O=82K, ROTW=116K. Max Gas=2142u, BGG=200-800u. At 5759' begin 4 deg per
100' turn and build . Backream Full stands. Max Gas=u, BGG=200-800u. Distance to plan: 8.99', 4.88' low, 7.55' right.
8/14/2023Spud Date:
Well Name:
Field:
County/State:
PBW Z-234
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
50-029-23762-00-00API #:
8/18/2023 Drill 12-1/4" Surface Hole F/5,997' - T/6,314' MD 4,278' TVD (Total: 317', AROP: 53'). 550gpm=2290/2220psi on/off. TQ=15-17/13-16Kft-lbs with 80RPM (Sliding
predominantly to maintain turn) and 6-12K WOB. ECD's=10.38ppg with 9.55/9.6ppg in/out. P/U=167K, S/O=83K, ROTW=118K. Max Gas=2,378u, BGG=300-900.
Backeaming Full Stands. Drill 12-1/4" Surface Hole F/6314' - T/6566' MD 4408' TVD (Total: 252', AROP: 42'). 550gpm=1990/1817psi on/off. TQ=15-18/13-16Kft-
lbs with 80RPM (Sliding predominantly for turn) and 8-14K WOB. ECD's=10.13ppg with 9.5/9.55ppg in/out. P/U=173K, S/O=90K, ROTW=119K. Max Gas=2358u,
BGG=500-1100. Drilled down to 6,530' MD and completed a 290bbl mud dilution to help reduce the temperature of the mud system. Backeaming Full Stands. Drill
12-1/4" Surface Hole F/6566' - T/6885' MD 4560' TVD (Total: 319', AROP: 53'). 550gpm=2324/2091psi on/off. TQ=15-18/13-16Kft-lbs with 80RPM and 8-14K
WOB. ECD's=10.26ppg with 9.5/9.55ppg in/out. P/U=179K, S/O=90K, ROTW=119K. Max Gas=2325u, BGG=300-900. Backeaming Full Stands. Drill 12-1/4"
Surface Hole F/6885' - T/7172' MD 4691' TVD (Total: 287', AROP: 48'). 550gpm=2520/2230psi on/off. TQ=16-20/14-17Kft-lbs with 80RPM and 8-14K WOB.
ECD's=10.42ppg with 9.45/9.5ppg in/out. P/U=183K, S/O=84K, ROTW=125K. Max Gas= 977u, BGG=300-700. Backeaming Full Stands. Distance to plan: 5.69',
5.43' low, 1.71' right.
8/19/2023 Drill 12-1/4" Surface Hole F/7,172' - T/7,458' MD 4,813' TVD (Total: 286', AROP: 48'). 550gpm=2480/2210psi on/off. TQ=16/12-15Kft-lbs with 80RPM (Sliding
predominantly to maintain turn) and 10-14K WOB. ECD's=10.45ppg with 9.45/9.55ppg in/out. P/U=173K, S/O=91K, ROTW=126K. Max Gas=2,216u, BGG=200-
600u. Increased lube concentration to 2% to help increase ROP and reduce TQ. TQ reduced ROP did not increase. Drill 12-1/4" Surface Hole F/7,458' - T/7,801'
MD 4,882' TVD (Total: 343', AROP: 29'). 550gpm=2373/2209psi on/off. TQ=15-17/11-15Kft-lbs with 80RPM (Sliding predominantly to maintain turn) and 10-14K
WOB. ECD's=10.45ppg with 9.45/9.55ppg in/out. P/U=174K, S/O=93K, ROTW=124K. Max Gas=3265u, BGG=200-600u. Drill 12-1/4" Surface Hole F/7,801' -
T/8190' MD 4941' TVD (Total: 343', AROP: 51'). 550gpm=2554/2391psi on/off. TQ=15-17/11-15Kft-lbs with 80RPM and 6-16K WOB. ECD's=10.28ppg with
9.55/9.6ppg in/out. P/U=174K, S/O=93K, ROTW=124K. Max Gas=3258u, BGG=200-600u. Drill 12-1/4" Surface Hole F/8109' to TD called as per geologist at
8424' MD 4956' TVD (Total: 315', AROP: 79'). 550gpm=2554/2391psi on/off. TQ=15-17/11-15Kft-lbs with 80RPM and 8-13K WOB. ECD's=10.43ppg with
9.65/9.7ppg in/out. P/U=167K, S/O=93K, ROTW=125K. TD in the Schrader Bluff OBd- Sand. Obtain final survey: 8370.51' 89.09 deg inc 1.80 deg azi. Max
Gas=2855u, BGG=300-600u. Circulate and condition: Work stnd while CBU 1x/stnd F/8424' T/8305'. Pump 30 bbl 9.6ppg 300 vis walnut sweep. Sweep back 35
bbl early with a 10% increase. 550gpm=2550 psi. TQ=15-17Kft-lbs with 80RPM ECD's=10.31ppg P/U=165K, S/O=95K, ROTW=125k Max gas 3346u.
8/20/2023 Continue to finish our cleanup cycle pumping a total of 3x BU. Backreaming F/8,424' - T/8,235' at full drilling parameters. 550gpm=2140psi with a RF of 55%. MW
was a 9.5ppg with an ECD of 10.31ppg. 80RPM=15-17Kft-lbs TQ. P/U=165K, S/O=95K, ROTW=125K. No Losses while circulating. RIH F/8,235' - T/8,424' MD
(TD), checked the well for flow - seeing slight flow with gas breaking out eventually stopping. BROOH F/8,424' - T/5,961' MD. 550gpm=2040psi, MW=9.55ppg with
10.48ppg ECD and RF=60%. 80RPM=12-16Kft-lbs. P/U-155K, S/O80K, ROTW=120K. No losses. Pulling Speed=25-35fpm. BROOH F/5,961' - T/3,821' MD. 485-
550gpm=1370psi. MW=9.65 with 10.48ppg ECD and RF=60%. 80RPM=10-15Kft-lbs TQ. P/U=139K, S/O80K, ROTW=94K. Max Gas=3,172u. Pulling speed=25-
35fpm. At 4,140' we reduced pulling speed down to 10fpm as we encountered 2-3K TQ Spike increases and as ECD's climbed 0.3ppg. BROOH T/3,992' and ECD
spike to 12.4ppg observing wellbore packing off at 2050psi (1770psi clean). no overpull. Returns were 15%. Reduced flow down to 220gpm (498psi) incrementally
until we re-established 100% flow back. Worked Flow up to 480gpm (1306psi) incrementally achieving full returns. Lost a total of 123 bbls with dynamic loss rate
determined at 384bph. No further TQ stalls or overpulls. Continue to BROOH at 480gpm. BROOH F/3821' - T/2275' MD. 485-550gpm=1270psi. MW=9.65 with
10.48ppg ECD and RF=53%. 80RPM=10-15Kft-lbs TQ. P/U=104K, S/O71K, ROTW=80K. Max Gas=3,172u. Pulling speed=10-25fpm. No Losses while
circulating. Pumped a 40bbl 300+ vis nut plug sweep at 3000'. Sweep back 600 strks early with a 25% increase. Slowed RPM's to 50 at 2295' for base of
permafrost. BROOH F/2275' - T/521' MD. 500gpm=1080psi. ECD= 10.41ppg and RF=55%. 50RPM=3-6Kft-lbs TQ. P/U=81K, S/O=62K, ROTW=73K. Max
Gas=1817u. Pulling speed=10-25fpm. Hole unloaded at 887'. Observed heavy sand and wood at shakers. Lost 10bbl. Monitor well at HWDP F/ 10min. Slightly
losing. PJSM. POOH on elevators racking back 5" HWDP F/521'MD. Rack back 9 stands including jars. L/D 2x Flex collars.
8/21/2023 Continued to L/D the BHA, Download MWD and L/D same. Flush and Drain motor and L/D. Bit=1-2-WT-N-E-IN-NO-TD, PDC=2-4-WT-S-X-IN-DL-TD. Clean and
cleared the rig floor. L/D 5" Handling equipment and P/U 9-5/8' Casing Equipment. Install 250T Elevators and 320T Volant. Check all handling equipment and
verify elevators with mandrel. Verify Pipe Count in Shed=205jts+ 4jt (shoe track) + 1 ES Cementer. Bring 70-9-5/8"x12.25" Bow Spring centralizers. Hold PJSM for
casing. M/U Shoe and Float collar (visual inspection of floats). Pump through floats at 5BPM - good. Install Bypass Baffle "Top Hat" above float collar. Forum-lok all
joints of shoe track ~11Kft-lbs (base of diamond). P/U=51K, S/O=48K. RIH with 40# TXP-BTC L-80 Casing, torqueing to 20,960ft-lbs. RIH F/Surface - T/450' CSG
MD on elevators filling every 5 joints and breaking circulation every 10 joints. RIH with 9-5/8" 40# TXP-BTC on elevators F/450' - T/1,099' where we had to begin
reaming down as necessary (5-6.7deg Doglegs F/1,062' - T/1,303'). Wash and Ream F/1,099 - T. Ream at 3BPM (RF=43%) with 9.55ppg MW. Set TQ stall to
10Kft-lbs at 10RPM. P/U= S/O=. Mostly sand at the shakers. On occasion able to run in on Elevators dictated by previous joint ran. Loss of 88 bbls. Max gas=635u.
Wash and Ream F/1099' - T/1770'. Ream at 3BPM (RF=24%) with 9.65ppg MW. Set TQ stall to 10Kft-lbs at 10RPM. RIH with 9-5/8" 40# TXP-BTC on elevators
F/1770' T/3185' filling every 5 joints and breaking circulation every 10 joints. P/U 144k S/O 68k ROT 65K. TQ connections to 20.9k ft-lbs. RIH with 9-5/8" 40# TXP-
BTC on elevators F/3185' - T/5138' filling every 5 joints and breaking circulation every 10 joints. TQ connections to 20.9k ft-lbs P/U 205k S/O 86k. Install
centralizers as per tally. Rotate as needed to work through tight spots. Calc=30 bbl, Act=9 bbl, Loss=39 bbl.
8/22/2023 Continue Running 9-5/8" 40# Casing F/5,138' - T/5,755' CSG MD on elevators and pumped a string volume, staging the pumps up from 3BPM-7BPM. no losses
while circulating, clean returns. 7BPM=230psi, RF=60%, 5RPM=10Kft-lbs (Stall), MW=9.6ppg, Max Gas=1181u. Trip Losses 26bbls. RIH T/5,962' and made up
the ES Cementer (Forum-Lok) connections to TXP-BTC Specs (40# pin, 47# box). Ran in the hole on elevators with 47# 9-5/8" Casing F/5,962' - T/6,967' MD
installing Centralizers as per Tally. Fill every 5 joints, breaking circulation every 10 joints. P/U=205K, S/O=86K. RIH on elevators with 9-5/8" 47# Casing F/6,967' -
T/7,300' CSG MD and circulate a bottoms up staging pumps up to 6BPM=352psi with a RF=34% and Max Gas=577u. 5RPM TQ (stall) at 11Kft-lbs. P/U=275K,
S/O=115K, ROTW=122K. Fill pipe every 5 joints and break circulation every 10 joints. RIH on elevators F/7,300' - T/8,286' and washed down T/8,424' CSG MD
tagging on depth with tag joint #209 (10K down), L/D same. P/U=325K, S/O=115K. 1RPM TQ (stall) at 11Kft-lbs. Circulate and condition mud lowing mud out YP to
19 at 6 bpm, 240 psi, 1-2 rpms with 11Kf-lbs (stall set) reciprocating pipe. P/U 320K, S/O 115K, circulate total 3 bu. Prep for cement job. Rig down casing
equipment. Break out of casing running tool. Rig up cement lines. M/U CRT and break circulation. Pump through bleeder to clear flow line, possum belly. Verify
overboard line and 4" conductor lines good. Pump 5 bbls H20 at 1.75 bpm 150 psi. Attempt to PT cement lines, observe valve leaking. C/O valve. PT surface lines
550/4000 psi - good. Pump cement as per detail:. 60 bbls 10# Tuned spacer at 4.4 bpm, 331 psi, Cement wet at 12:40. Drop Bypass plug. 360 bbls 12# type I/II
lead at 4.7 bpm, 375 psi. 82 bbls 15.8# type I/II tail cement at 3.5 bpm 480 psi. Drop shut-off plug. Displace with 20 bbls water at 5.7 bpm, 370 psi. Swap to rig
pumps and displace at 7 bpm to catch cement ICP 344 psi building to 486 psi. Slow rate to 6 bpm, 380 psi at 310 bbls into displacement and 5 bpm, 393 psi 330
bbls. after observing flow out decrease. 340 bbls into displacement observe complete losses, with pipe getting sticky. Park string on depth and attempt to regain
circulation. Slow rate to 1 bpm 10 psi, ajdust rate from 1-3 bpm and stretch pipe unsuccessfully. Cont. to displace at 1 bpm observing. pressure increasing to 330
psi at 530 bbls into displacing (602 bbls calculated).
8/23/2023 Continue displacing at 1BPM, FCP=354psi. Bumped plug 100 strokes early at 9,615 strokes (Calc Disp=622.1 bbls, Actual=615.8bbls), CIP at 06:57. Increased
pressure to 500 psi over FCP and held for 5 mins. Bled off pressure to check floats - holding. Brought the pumps back on and increased to 2,920psi observing the
ES Cementer shift open. Saw returns upon opening with 3BPM (ICP=850psi) and reduced flow rate to 2BPM as to not add any additional pressure to the wellbore.
No cement returns to surface. Pump at 2BPM=188psi thru the ES Cementer while we wait on cement to set from 1st stage. No losses. Cont. Pump at 2BPM=188psi
thru the ES Cementer while we wait on cement to set from 1st stage. No losses. Cont. Pump at 2BPM=188psi thru the ES Cementer while we wait on cement to set
from 1st stage. At 21:30 slowly stage pumps up to 5.5 bpm 579 psi. No losses. Break out of CRT. Line up to cementers and cement as per detail:. 5 bbls water at 2
bpm 170 psi. 50 bbls 10# Tuned spacer at 3 bpm 235 psi. 452 bbls 11# type I/II ArcticCem at 3 bpm 375 psi, slow to 2 bpm 200 psi 180 bbls in as lead rounds the
corner. 56 bbls 15.8# type I/II tail cement at 2 bpm 150 psi. Drop closing plug. Pump 20 bbls water at 2 bpm 80 psi. Swap to rig pumps and pump 108 bbls 9.9 ppg
spud mud at 2 bpm 250 psi, slow rate at 1645 strokes as tail rounds the corner to 1.5 bpm, 252 psi. Observe green cement at surface. No losses. Daily fluid lost to
formation 310 bbls, total lost on surface 686 bbls.
8/24/2023 Cont. displacing second stage cement with spud mud at 1.5 bpm bumped plug at 153 bbls (158 calculated) FCP 395 psi. Pressure up to 1600 psi to close ES
cementer. CIP at 06:25. 50 bbls of green cement observed at surface. Bleed off pressure and confirm ES cementer closed - good. No losses. Disconnect
accumulator from knife valve. R/D diverter vent line. Drain stack and fill with black water, cycle annular. Suck out 9-5/8 casing. Break stack and set 'E' slips with
70K. Cut casing and L/D cut joint (cut 30.05') Set stack on speed head. P/U stack washing tool and wash stack. Flush surface lines. Start offloading pits. R/D
diverter T and speed head. Pull bushing and riser. Install MPD head on stack and rack back. P/U wellhead adn install. PT void 600/3600 psi - good. SimOps:
Modify possum belly for new shaker beds. Install DSA and test plug. N/U BOP and Tq connections. Hook up choke and kill lines, accumulator lines. clean and clear
rig floor. Install drip pan, MPD hard lines, Center stack and chain down. Install trip nipple, split bushings. SimOps: Modify possum belly for new shaker beds, clean
pits. M/U test joint, top drive sub. Fill stack/lines with water and purge. Function valves. Test BOPE's 250/3000 psi with 4-1/2", 5" and 7" test joints. Right to witness
waived by AOGCC rep Kam St. John. Test gas alarms, gain loss, and flow paddle. Accumulator draw down test: starting pressure 3000 psi, final 1500 psi, 200 psi
recharge 23 sec, full recharge 95 sec. (6) N2 at 2441 psi av. Rig down testing equipment. Blow down choke/kill lines. Pull test plug and set wear bushing. Change
out manual elevators to hydraulic elevators. RIH with 5 stand excess HWDP from shed and L/D.
8/25/2023 P/U BHA: M/U NOV PDC bit and NRP to Geo-Pilot, M/U DM, ASL/CTN, TM. Download MWD. M/U stab, HWDP, shallow pulse test. Rack back HWDP. Install
sources. M/U float subs, drill collars, HWDP and jars to 432'. P/U 47K, S/O 47K. Pick up, drift (3.125") and single in the hole to 1481'. P/U 68K, S/O 66K. Cont. to
Pick up, drift (3.125") and single in the hole from 1481' to 2403'. P/U 92K, S/O 70K. Fill pipe, break in Geo-Pilot. Wash and ream from 2403' to 2428'. Drill plug, ES
Cementer (on depth) and wash down to 2467' at 400 gpm, 845 psi, 60 rpms, 6-10Kft-lbs, WOB 3-5K. Cont. to Pick up, drift (3.125") and single in the hole from
2467' to 4563'. P/U 124K, S/O 77K. RIH with drill pipe from derrick from 4563' to 8250' P/U 215K, s/O 77K. Wash down to 8282'. Ciculate bottoms up at 450 gpm,
1525 psi, 60 rpms, 21Kft-lbs. Rig up and PT casing to 2500 psi for 30 minutes: initial 2632 psi, 15 min 2608 psi, final 2600 psi. Pumped 5.2 bbls bled back 5.0 bbls
- good. Rig down testing equipment. Wash down to 8282' Drill shoe track (FE on depth), cement and 20' of new hole from 8282' to 8444' at 450 gpm, 1400-1900
psi, 60 rpms, 20Kft-lbs, WOB 2-6K. P/U 197K, S/O 120K, ROTW 100K. Pick up off bottom and adjust flow rate as thick clobbered mud returns come to surface.
Ream through FE with and. without rotary without issues. Start displacing to Baradril-N Pump 35 bbls followed by 9.1 Baradril-N at 450 gpm, 1350 psi, 60 rpms,
19Kft-lbs. Total bbls lost 0, total lost on surface section 686 bbls.
8/26/2023 Cont. to displace to 9.1 ppg Baradril-N at 450 gpm, 1350 psi, 60 rpms, 19Kft-lbs. P/U 207K, S/O 97K, ROTW 121K. Flood lines and purge air. Shut UPR's and
conduct FIT to 12.0 ppg EMW with 750 psi - 1.7 bbls pumped, 1.5 bbls back. Monitor well - static. Pull trip nipple set MPD bearing and test 250/1200 psi - good.
Cut and slip drilling line. Calibrate blocks, test crown/floor saver. Grease wash pipe, top drive, crown sheave and blocks. Wash down to 8444'. Drill 8-1/2" hole from
8444' to 8694' (total 250' AROP 125 fph) at 500 gpm, 1615 psi, WOB 3-8K, 120 rpms, 17.5Kft-lbs. Max gas 682U, ECD 10.33 ppg with 9.1 ppg mud. P/U 184K,
S/O 71K, Rotw 112K. Drill 8-1/2" hole from 8694' to 9074' (total 380' AROP 127 fph) at 500 gpm, 1745 psi, WOB 3-12K, 120 rpms, 17.5Kft-lbs. Max gas 1507U,
ECD 10.38 ppg with 9.1 ppg mud. P/U 184K, S/O 81K, Rotw 114K. Crossed fault at 9,020' with 10' DTS throw. Replace liner and swab on pump 1 pod 1.
ROT/REC at 210 gpm, 465 psi, 80 rpms, 13Kft-lbs. Drill 8-1/2" hole from 9074' to 9420' (total 346' AROP 138 fph) at 500 gpm, 1710 psi, WOB 6-13K, 120 rpms,
13-17Kft-lbs. Max gas 898U, ECD 10.44 ppg with 9.1 ppg mud. P/U 182K, S/O 84K, Rotw 114K.Backream 30'. Drill 8-1/2" hole from 9420' to 10219' (total 799'
AROP 133 fph) at 500 gpm, 1831 psi, WOB 6-13K, 120 rpms, 13-17Kft-lbs. Max gas 906U, ECD 10.52 ppg with 9.1 ppg mud. P/U 174K, S/O 94K, Rotw
114K.Backream 30'. Drill 8-1/2" hole from 10219' to 11044' (total 825' AROP 138fph) at 500 gpm, 2027 psi, WOB 6-13K, 120 rpms, 13-15ft-lbs. Max gas 985U,
ECD 10.67 ppg with 9.15 ppg mud. P/U 151K, S/O 89K, Rotw 114K.Backream 30'. Crossed fault at 10,580' with 71' DTS throw. faulted from OBd sand to OBc
Clay. Drilled 11 concretions for a total thickness of 40 (1.6% of the lateral). 2 Faults have been crossed in the lateral: 9,020', 10,580'. Total footage in OBd sand =
2166', total footage out of zone = 360'. Distance to WP2: 47.4', 46.65' low, 8.38' right. Daily fluid lost 0 bbls, lost on production 0 bbls. Total lost on surface hole 686
bbls.
8/27/2023 Drill 8-1/2" hole from 11,044' to 11,999' (total 955' AROP 159fph) at 500 gpm, 2036 psi, WOB 7-15K, 130 rpms, 13-15ft-lbs. Max gas 1010U, ECD 10.83 ppg with
9.2 ppg mud. P/U 153K, S/O 84K, ROTW 111K.Backream 30'. Re-acquired OBd sands at 11064'. Drill 8-1/2" hole from 11,999' to TD at 12,375' (total 376' AROP
125fph) at 500 gpm, 2036 psi, WOB 7-15K, 130 rpms, 13-15ft-lbs. Max gas 1010U, ECD 10.83 ppg with 9.2 ppg mud. P/U 163K, S/O 84K, ROTW
111K.Backream 60'. Obtain final survey. Pump tandem sweeps (on time, 25% increase) and circulate 4 x BU. rack back stand every bottoms up once sweep is out
of hole. At 525, 2160 psi, 120 rpms, 14-26Kft-lbs, ECD 10.45 with 9.2 ppg mud, max gas 1048 P/U 160K, S/O 86K, ROTW 109K. RIH to TD 12,375'. Pump SAPP
train (3X SAPP with Quickdril between pills) and displace to 9.2 ppg QuickDril-N at 500 gpm, 525 psi, 100 rpms, 13-20Kft-lbs, ECD 10.19, max gas 645u. Monitor
well with MPD - no pressure build, static. Drop drift and BROOH from 12,375' to 11,270' at 500 gpm, 1450 psi, 120 rpms, 13-14Kft-lbs, ECD 10.15 ppg. Pulling 20-
35 fpm as hole dictates. P/U 165K,k S/O 85K, ROTW 108K. Cont to BROOH from 11,720' to 8375' at 500 gpm, 1360psi, 120rpms, 10-12Kft-lbs, ECD 9.87 ppg.
Pulling 20-35 fpm as hole dictates. P/U 163K,k S/O 88K, ROTW 120K. Slow pulling speed to 5-20 fpm f/ 11,000' to 10,600' (out of zone) due to slight packoff. Slow
rotary to 60 rpms as BHA comes through shoe. 15 concretions were drilled for a total footage of 45 (1.1% of the lateral). 2 Faults have been crossed in the lateral:
9,020', 10,580'. Total footage in OBd sand = 3477', total footage out of zone = 484'. Distance to WP2 projected to TD: 21.71', 21.58' low, 2.37' right. Daily fluid lost
15 bbls, lost on production 15 bbls. Total lost on surface hole 686 bbls.
8/28/2023 Pump 30 bbls high vis sweep and circulate hole clean at 500 gpm, 1400 psi, 60 rpsm, 16-17Kft-lbs. P/U 163K, S/O 88K, ROTW 120K. Pull MPD Bearing and set
trip nipple. POOH F/ 8375' MD - T/ 5262' MD Racking back in the derrick, verify no swabbing then pump corrosion inhibited dry job (10.2 PPG). Cont POOH laying
down DP F/ 5262' MD - T/ 432' MD P/U 45K S/O 44K. Monitor well for 10 min-static. L/D 7 jts HWDP, Jars, Flex Collars x2, Float Sub, TM, CTN, ALD, DM, DGR
and ADR collars, ILS, Geo Pilot, NRP and 8.5" TK66 Bit. Pulled sources. Retrieve drift in float sub. Bit grade 1-1-CT-A-X-I-WT-TD. Clean and clear rig floor.
Remove Hyd Elev. Rig up Parker TRS pipe handling equipment. P/U M/U Eccenric solid nose shoe and RIH with 4.5" 12.6# L-80 Wedge 563 liner F/ surf- T/ 3996'
MD, TQ to 3800 ft/lbs optimum. P/U 64K S/O 58K. Swap handling equipment to 7" and make up XO Jt 4.5" Wedge 563 pin x 7" Wedge 563 box. Cont RIH with 7"
26# L-80 Wedge 563 F/ 3996' MD - T/ 5381' MD, M/U SLZXP to 5417'. TQ to 9400 ft/lbs. P/U 93K S/O 79K. R/D casing tools. C/O pipe handling equipment. Clean
and clear rig floor. Cont. to RIH with 4-1/2" injection liner conveyed on drill pipe from 5417' to 12,375'. Tag on depth with 10K. P/U 173K, S/O 84K. P/U to set liner in
tension. Break circulation and circulate string volume at 250 gpm, 800 psi. Daily fluid lost 43 bbls, lost on production 58 bbls. Total lost on surface hole 686 bbls.
8/29/2023 PJSM Drop 1.125" OD Phenolic ball. Pump down at 6 bpm 800 psi, slow to 2 bpm 160 psi 1650 strokes (273 strokes early) Press up to 2200 psi to engage pusher
tool. Set down 50k, press up to 3000 psi setting tool released at 2650 psi, held 5 min. Press up sheared seat at 4150 psi. P/U ~6' 144k SLK dogs. set. Flood lines.
Shut in UPR's (2.875" X 5.5"). Test SLZXP 1,500 psi for 10 min on chart, good. TOL 6,972.64' MD. POOH Monitor well 10 min, static. POOH L/D 5" D.P.6,929' to
6,675' MD Pump 25 bbl 10.2 ppg corrosion inhibited slug. B/D. Cont to POOH L/D 5" D.P. F/ 6,675' to running Assy. L/D running Assy. Lost 4.9 bbls. Daily fluid
lost 10 bbls, lost on production 68 bbls. Total lost on surface hole 686 bbls.
Activity Date Ops Summary
8/29/2023 PJSM RIH remaining 5" D.P. F/ derrick to 698' MD. POOH L/D 5" D.P. No losses. PJSM Drain stack, M/U wear ring puller, BOLDS pull wear ring. L/D. PJSM R/D
rig tongs, secure PH8. L/D air slips. M/U X/O to TIW. R/D 5" Hydraulic elevators. PJSM Service rig. Grease crown, TD, blocks, PH8 and spinners. PJSM RIH 7.3"
OD Mule Shoe Tie Back Assy W/ 7" 26# BTC/DWC to 4,139' MD. Baker Loc DWC to BTC connection jnts 33 & 34. Trq DWC 19.7k. BTC Avg 8k. P/U 106k SLK
82k. Calc 31.4 bbls Act 35.1 bbls Lost 3.7 bbls. PJSM RIH 7" 26# BTC F/ 4,139' to 6982' MD. P/U Jnts 168 & 169 tag NoGo 17.68' on 196. L/D Jnts 169, 168 &
167. P/U Pups 9.82', 7.84', 5.82' & jnt 167. P/U M/U Hanger and land. Shoe depth 6,982' MD 1.68' off NoGo. Trq BTC Avg 8k. P/U 158k SLK 108k. Calc 31 bbls
Act 25 bbls Lost 6 bbls.
8/30/2023 Rig up and reverse circulate 9.2 CI brine 7" x 9-5/8" annulus. Pump 134 bbls CI brine @ 3 bpm, 177 ICP, 95 FCP. LRS reverse circulate 62 bbls diesel behind CI
brine. LRS 2.5 bpm, 175 ICP, 375 FCP (200 SICP). Strip down and landout 7" tieback hanger. Monitor well, "Static" indicating seals engaged on depth. R/D
equipment. Release LRS @ 08:30,Landed 7" tieback w/ 73k string wt on hanger assy. Install packoff and test void 500/5000 psi w/ 10/10 min hold ea (test good).
R/U and test 7" x 9-5/8" annulus to 1500 psi w/ 30 min hold. Chart and record same. 2 bbl In / 1.5 bbl out. 1590 psi Initial, 1556 psi @ 15 min, 1542 psi @ 30 min
final. Test good. R/D test equipment. Used FW, MP#2 @ 1/4 BPM rate. R/U Parker Wellbore 4.5" casing equpment. 234 jts in shed. Dump check Tq Turn on power
tongs (good). M/U 4" TIW w/ JFEBear XO. M/U 4.5" cut full mule shoe WLEG. Run 4.5" JFEBear 12.6#, L-80 tubing as per detail F/ surface - T/ 58' MD. 5940 ft/lbs
connections. P/U 35k, S/O 35k,Continue run 4.5" JFEBear 12.6#, L-80 tubing as per detail F/ 58' - T/ 4414' MD. 5940 ft/lbs connections w/ Tq Turn. P/U 67k, S/O
57k. Verify RHC-M "X" nipple. 6 pins w/ packer assy. 60-80 fpm max running speed. Cont RIH 4.5" 12.6# L-80 tubing F/ 4,414'. to 8,270' MD as per tally. P/U M/U
FMC 11" hanger and land at 8,270' MD. Hanger WT 34k. P/U 100k SLK 69k. Trq Turn JFEBear 5,940 ft/lb. Lost 7.4 bbls. Run speed 60-80 fpm. PJSM Vault rep
RILDS. Back out and L/D landing jnt. Install modified BPV W/ CTS plug. R/D 4.5" handling Equip and tongs. PJSM Johnny Whack stack and flush all surface lines.
Drain stack. Pull riser. R/D 4" MPD lines. Remove drain pan. R/D choke and kill lines. Bleed down Koomey and disconnect koomey lines. N/D BOP and secure to
pedestal. Pull DSA, clean and store in cellar. PJSM Clean tubing hanger and ring groove. N/U dry hole tree. Test void to 500/ 5000 psi for 10 min. R/U and test tree
to 250/5000 psi 5 min ea. Pull TWC. SIMOPS Stage squeeze manifold and HP hoses. Clean Pits and haul off excess brine. PJSM R/U squeeze manifold and HP
lines to tree.
8/31/2023 PJSM Reverse Circ 125 bbls corrosion inhibited brine down 7" X 4.5" IA 3 bpm ICP 260 psi FCP 215 psi. LRS pumped 78 bbls Diesel FP 2 bpm ICP 570 psi FCP
433 psi. UTube 1 hour. R/U ball/ rod launcher. Drop 1 7/8" roller rod. SIMOPS R/D tongs. Bridal up. Clean Pits. PJSM R/U test lines and chart. Flood lines and PT.
Pressure up 4.5" tubing to 500 psi for 3 min, Cont pressure up to 3,500 psi W/ MP #2, pressure fell bellow 3,500 psi, pressure up to initial 3,700 psi hold for 30 min.
1st 15 min 3,635 psi, 2nd 15 min 3,610 psi, good. IA Press 160 psi, after 135 psi. Bleed tubing to 1,000 psi. Press up IA 7" X 4.5" to initial 3,700 psi, 1st 15 min
3634 psi, 2nd 15 min 3609 psi, good. Release rig at 12:00.
Well Name:
Field:
County/State:
PBW Z-234
Prudhoe Bay West
Hilcorp Energy Company Composite Report
, Alaska
50-029-23762-00-00API #:
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
2
1
142
59
X Yes No X Yes No 40
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated?X Yes No Reciprocated?X Yes No % Returns during job
Cement returns to surface? Yes X No Spacer returns?Yes X No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns ?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
Casing (Or Liner) Detail
Shoe
Cut Joint
10 3/4 40.0 L-80
463.31
SE
C
O
N
D
S
T
A
G
E
Rig
6:25
Cement Returns to Surface
Rotate Csg Recip Csg Ft. Min. PPG9.8
Shoe @ 8414.55 FC @ Top of Liner8,329.96
Floats Held
501.7 950
50 590
Spud Mud/Water
CASING RECORD
County State Alaska Supv.Steve Carter
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.PBW Z-234 Date Run 21-Aug-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
BTC 1.73 8,414.55 8,412.82
10.58 36.13 25.5547.0 L-80 TXP Tenaris
Csg Wt. On Hook:32,000 Type Float Collar:Conventional No. Hrs to Run:32.5
9.9 6
1600
10
11 452 2
50
354
Bump Plug?
FI
R
S
T
S
T
A
G
E
10Tuned Spacer 60
15.8
395
2
9.9 1.5 153/158
615.8/622.1
854
0
Rig
15.8 82
Bump press
Calculated
Bump Plug?
Y
6:57 8/23/2023 6,227
2432.1
8,414.558,424.00
CEMENTING REPORT
Csg Wt. On Slips:70,000
Spud Mud
Tuned Spacer
1000 2.54
Stage Collar @
50
Bump press
100
50
ES Cementer Closure OK
56
12 360
26.79 RKB to CHF
Type of Shoe:Bullnose Casing Crew:Parker TRS
No. Jts. Delivered No. Jts. Run 204
Length Measurements W/O
Threads
Ftg. Delivered Ftg. Run Ftg. Returned
Ftg. Cut Jt. Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
3.5
Type I/II
Type
(2) on jnt 1, 1 every joint to jnt 25, 1 every other joint to jnt 73, 5 before and after ES cementer, then one every third
joint to jnt 198
Casing 9 5/8 40.0 L-80 TXP Tenaris 81.46 8,412.82 8,331.36
Float Collar 10 3/4 40.0 L-80 BTC 1.40 8,331.36 8,329.96
Casing 9 5/8 40.0 L-80 TXP Tenaris 39.23 8,329.96
Baffle Adapter 10 3/4 40.0 L-80 TXP Halliburton 1.44 8,290.73 8,289.29
Casing 9 5/8 40.0 L-80 TXP Tenaris 5,836.78 8,289.29 2,452.51
Pup Joint 9 5/8 40.0 L-80 BTC Tenaris 17.57 2,452.51 2,434.94
ES Cementer 10 3/4 40.0 L-80 BTC Halliburton 2.84 2,434.94 2,432.10
Pup Joint 9 5/8 40.0 L-80 BTC Tenaris 18.20 2,432.10 2,413.90
Casing 9 5/8 47.0 L-80 TXP Tenaris 2,377.77 2,413.90 36.13
Type I/II 862 2.35
Type I/II 400 1.16
4.7
Type I/II 270 1.17
8/24/2023 Surface
Water/Mud
1
Regg, James B (OGC)
From:PB Wells Integrity <PBWellsIntegrity@hilcorp.com>
Sent:Saturday, September 2, 2023 1:19 PM
To:Brooks, Phoebe L (OGC); Wallace, Chris D (OGC); Regg, James B (OGC)
Cc:PB Wells Integrity
Subject:Hilcorp (PBU) August 2023 MIT Forms
Attachments:Aug 2023.zip
All,
AƩached are the completed AOGCC MIT forms for the tests completed in August 2023 by Hilcorp North Slope, LLC.
Well: PTD: Notes:
X‐24A 1991250 2‐year MIT‐IA per AA AIO 3B.003. Failed and well was shut‐in.
Z‐234 2230650 Rig MIT‐T/MIT‐IA per PTD
Z‐235 2230550 Rig MIT‐T/MIT‐IA per PTD
Please respond with quesƟons or concerns.
Andy Ogg
Hilcorp Alaska LLC
Field Well Integrity
andrew.ogg@hilcorp.com
P: (907) 659‐5102
M: (307)399‐3816
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
PBU Z-234PTD 2230650
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230650 Type Inj N Tubing 0 3700 3635 3610 Type Test P
Packer TVD 4659 BBL Pump 1.8 IA 0 135 135 135 Interval I
Test psi 3500 BBL Return 1.8 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 2230650 Type Inj N Tubing 1000 1450 1450 1450 Type Test P
Packer TVD 4659 BBL Pump 2.0 IA 0 3700 3634 3609 Interval I
Test psi 3500 BBL Return 1.8 OA 0 0 0 0 Result P
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD Type Inj Tubing Type Test
Packer TVD BBL Pump IA Interval
Test psi BBL Return OA Result
TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes
W = Water P = Pressure Test I = Initial Test P = Pass
G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail
S = Slurry V = Required by Variance I = Inconclusive
I = Industrial Wastewater O = Other (describe in notes)
N = Not Injecting
Notes:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Mechanical Integrity Test
jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov
Notes:Rig MIT-IA
Notes:
Notes:
Hilcorp Alaska LLC
Prudhoe Bay / PBU / Z-Pad
Witness Waived by Guy Cook
Shane Barber
08/31/23
Notes:Rig MIT-T
Notes:
Notes:
Notes:
Z-234
Z-234
Form 10-426 (Revised 01/2017)2023-0831_MIT_PBU_Z-234_2tests
J. Regg; 10/12/2023
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, PBU Z-234
Hilcorp Alaska, LLC
Permit to Drill Number: 223-065
Surface Location: 4433' FSL, 2657' FEL, Sec. 19, T11N, R12E, UM, AK
Bottomhole Location: 804' FNL, 2406' FWL, Sec. 17, T11N, R12E, 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 July 2023. 28
Brett W.
Huber, Sr.
Digitally signed by
Brett W. Huber, Sr.
Date: 2023.07.28
16:36:02 -06'00'
1a.
Contact Name:Joe Engel
Contact Email:jengel@hilcorp.comAuthorized Name: Monty Myers
Authorized Title:Drilling Manager
Authorized Signature:
Contact Phone:907-777-8395
Approved by:COMMISSIONER
APPROVED BY
THE COMMISSION Date:
5
21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated
from without prior written approval.
Drill
Type of Work:
Redrill
Lateral
1b.Proposed Well Class:Exploratory - Gas
Service - WAG
5
1c. Specify if well is proposed for:
Development - Oil Service - Winj
Multiple Zone Exploratory - Oil
5
Gas Hydrates
Geothermal
Hilcorp North Slope, LLC Bond No. 107205344
11.Well Name and Number:
PBU Z-234
TVD:12372"4923'
12. Field/Pool(s):
MD:
ADL 028262
85-009 August 8, 2023
4a.
Surface:
Top of Productive Horizon:
Total Depth:
4433' FSL, 2657' FEL, Sec. 19, T11N, R12E, UM, AK
510' FSL, 2383' FWL, Sec. 17, T11N, R12E, UM, AK
Kickoff Depth:350 feet
Maximum Hole Angle: 95 degrees
Maximum Anticipated Pressures in psig (see 20 AAC 25.035)
Downhole:Surface:2179 1683
17.Deviated wells:16.
Surface: x-y- Zone -600018 5959240 4
10. KB Elevation above MSL:
GL Elevation above MSL:
feet
feet
82.5'
56.0'
15.Distance to Nearest Well
Open to Same Pool:
Cement Quantity, c.f. or sacks
MD
Casing Program:
Surface Surface
Surface
2000'
Surface
4632'
19.PRESENT WELL CONDITION SUMMARY
Production
Surface
Seabed Report Drilling Fluid Program 5 20 AAC 25.050 requirements
Shallow Hazard Analysis
55
Commission Use Only
See cover letter for other
requirements:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No
H2S measures Yes No
Spacing exception req'd: Yes No
Mud log req'd: Yes No
Directional svy req'd: Yes No
Inclination-only svy req'd: Yes No
Other:
Date:
Address:
Location of Well (State Base Plane Coordinates - NAD 27):
129.5#
7000'5372'
50-
Intermediate
Conductor/Structural
Single Zone
Service - Disp
No YesPost initial injection MIT req'd:
No Yes 5
Diverter Sketch
Comm.
TVD
API Number:
MD
Sr Pet Geo
804' FNL, 2406' FWL, Sec. 17, T11N, R12E, UM, AK
Time v. Depth Plot555 5Drilling Program
12668'
Stg 2 L - 886 sx / T - 268 sx
(To be completed for Redrill and Re-Entry Operations)
8-1/2"
7"
L-8026#/12.6#7"x4-1/2"
9-5/8"
4632'
12-1/4"
7000'Uncemented Tieback
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stratigraphic Test
Development - Gas Service - Supply
Coalbed Gas
Shale Gas
2.Operator Name:5.Bond Blanket 5 Single Well
3.
3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503
6. Proposed Depth:
7. Property Designation (Lease Number):
8. DNR Approval Number:13.Approximate spud date:
9.Acres in Property: 14. Distance to Nearest Property:
Location of Well (Governmental Section):
4b.
2480
600'
18.Specifications Top - Setting Depth - Bottom
Casing Weight Grade TVDHole Coupling Length TVD (including stage data)
12-1/4"
Tieback
9-5/8" 47#
40#
26#
L-80
L-80
L-80 BTC
Vam 21
Hyd 563
Hyd 563
2500'
5870'
7000'
Surface
2500'
Surface
2500'
8370'
12372'
2000'
4948'
4923'
Stg 1 L - 843 sx / T - 395 sx
Uncemented Slotted Liner
Total Depth MD (ft): Total Depth TVD (ft):
Plugs (measured):Effect. Depth MD (ft): Effect. Depth TVD (ft):Junk (measured):
Casing Length Size MD
Liner
Perforation Depth MD (ft):Perforation Depth TVD (ft):
20. Attachments Property Plat BOP Sketch
Permit to Drill
Number:
Permit Approval
Date:
Reentry
Hydraulic Fracture planned?
Sr Pet Eng Sr Res Eng
Cement Volume
Comm.
105'105'Driven 20"X-52 80'
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval (20 AAC 25.005(g))
PRUDHOE BAY FIELD
SCHRADER BLUFF OIL POOL
ORION DEVELOPMENT AREA
7.18.2023
By Grace Christianson at 9:25 am, Jul 18, 2023
Drilling Manager
07/18/23
Monty M
Myers
MDG 7/27/2023
223-065
* MIT-IA to 3500 psi. 24 hour notice to AOGCC for opportunity to witness.
* AOGCC to witness MIT-IA after 7 days of
stabilized injection.
* Variance to 200' packer placement above the top of perforations approved.
* BOPE test to 3000 psi. Annular to 2500 psi.
MGR20JULY2023
029-23762-00-00
DSR-7/19/23
1683
GCW 07/28/2023JLC 7/28/2023
07/28/23
07/28/23
Brett W. Huber, Sr.
Digitally signed by Brett W. Huber,
Sr.
Date: 2023.07.28 16:36:28 -06'00'
87
1718
20
19
CHEV181112
K071112PB1
W-2
W-44
WET
Z-01
Z-02
Z-03
Z-04
Z-05
Z-06
09
Z-100
Z-102
Z-103
Z-108
Z-11
Z-112PB1
Z-113PB1
Z-114
Z-115 Z-116
Z-12
Z-13
Z-14
Z-15
Z-16
Z-17
Z-18
Z-19
Z-19A
Z-20
Z-21
Z-210
Z-210PB1
-22
Z-23
Z-24
Z-25
Z-26
Z-27
Z-28
Z-29
Z-30
Z-31
Z-32
Z-33
Z-34
-35PB1
38
8PB1
Z-39
Z-40
Z-50
Z-61
Z-65
Z-66
Z-68
Z-69
70
Z-71
Z-220PB1
Z-221
Z-220
Z-228
Z-229
Z-222
Z-223
W-241
W-26B
Z-234_wp01
HILCORP NORTH SLOPE
Greater Prudhoe Bay
AOR MAP
Z-234 Injector (Proposed)
FEET
05001,0001,500
POSTED WELL DATA
Well Label
WELL SYMBOLSINJ Well (Water Flood)
P&A Oil/Gas
J&A
Temporarily Abandoned
Active Oil
Injector Location
Shut in Injector
REMARKS
Well Symbols at top of Schrader Bluff OBd sand (targetof proposed Z-234 well). Black dashed circles andlines = 1320' radius from heel to toe of proposed Z-234lateral injector.
March 22, 2023
PETRA 3/22/2023 3:55:29 PM
Well Name PTD API StatusTop of Oil Pool(SB OBd, MD)Top of Oil Pool(SB OBd, TVD)Top of Cmt (MD) Top of Cmt (TVD)ZonalIsolationCommentsPBU Z-116 211-124 50-029-23455-00-00 WAG Injector 9942' 4916' 8640' 4323' Closed7" TOC logged at 8640' MDwith IBC on 12/22/2011.Kuparuk Injector, not open toSchrader BluffPBU Z-228 222-055 50-029-23718-01-00 Producer 7358' 4906' Surface Surface Open Active SB Producer. 9-5/8"cemented fully from shoe at7492' MD to surface in 12-1/4" hole. 2 stage cement job.14bbls excess seen from 1ststage, 185 bbls excess tosurface on second stage.PBU Z-229 222-104 50-029-23726-00-00 ProducerN/A Obc SandLateralN/A Obc SandLateralSurface Surface Open Active SB Producer. 9-5/8"cemented fully from shoe at7318' MD to surface in 12-1/4" hole. 2 stage cement job.30bbls excess seen from 1ststage, 330 bbls excess tosurface on second stage.PBU W-26B 222-151 50-029-21964-02 Producer 8398' 4961' 6730' 4198' OpenActive SB Producer. 9-5/8"TOC logged at 6,730' withCAST-M.PBU W-241 222-154 50-029-23741-00 WAG Injector 7705' 4999' 6216' 4461' OpenActive SB Producer. 7" CSGcemented with 47 bbls of15.8ppg, full returns notedduring cement job. EST TOC~6216'PBU Z-210PB1 204-181 50-029-23226-70-00 Plugback 7370' 4844' 4810' 3499' Closed2004 USIT found 7" TOC @4810' MD.Area of Review PBU Z-234i
Prudhoe Bay West
(PBU) Z-234
Drilling Program
Version 1
7/13/2023
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 ..................................................................................................... 11
10.0 N/U 13-5/8” 5M Diverter System ............................................................................................. 12
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 14
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 17
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 23
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 28
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 29
16.0 Run 4-1/2” Injection Liner ...................................................................................................... 33
17.0 Run 7” Tieback ........................................................................................................................ 37
18.0 Run Upper Completion/ Post Rig Work ................................................................................. 39
19.0 Innovation Rig Diverter Schematic ......................................................................................... 41
20.0 Innovation Rig BOP Schematic ............................................................................................... 42
21.0 Wellhead Schematic ................................................................................................................. 43
22.0 Days Vs Depth .......................................................................................................................... 44
23.0 Formation Tops & Information............................................................................................... 45
24.0 Anticipated Drilling Hazards .................................................................................................. 47
25.0 Innovation Rig Layout ............................................................................................................. 51
26.0 FIT Procedure .......................................................................................................................... 52
27.0 Innovation Rig Choke Manifold Schematic ............................................................................ 53
28.0 Casing Design ........................................................................................................................... 54
29.0 8-1/2” Hole Section MASP ....................................................................................................... 55
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 56
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 57
Page 2
Prudhoe Bay West
Z-234 SB Injector
Drilling Procedure
1.0 Well Summary
Well PBU Z-234
Pad Prudhoe Bay Z Pad
Planned Completion Type 4-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff OBd Sand
Planned Well TD, MD / TVD 12,372’ MD / 4,922’ TVD
PBTD, MD / TVD 12,362’ MD / 4,922’ TVD
Surface Location (Governmental) 4,433' FSL, 2,657' FEL, Sec 19, T11N, R12E, UM, AK
Surface Location (NAD 27) X= 600,018.4, Y=5,959,239.8
Top of Productive Horizon
(Governmental)510' FSL, 2383' FWL, Sec 17, T11N, R12E, UM, AK
TPH Location (NAD 27) X= 605,034, Y= 5,960,665
BHL (Governmental) 804' FNL, 2406' FWL, Sec 17, T11N, R12E, UM, AK
BHL (NAD 27) X= 604,989, Y= 5,964,631
AFE Number 231-00085
Maximum Anticipated Pressure
(Surface) 1683 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 2179 psig
Work String 5” 19.5# S-135 NC 50
Innovation KB Elevation above MSL: 26.5 ft + 56.0 ft = 82.5 ft
GL Elevation above MSL: 56.0 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Prudhoe Bay West
Z-234 SB Injector
Drilling Procedure
2.0 Management of Change Information
Page 4
Prudhoe Bay West
Z-234 SB Injector
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 BTC 5,750 3,090 916
9-5/8” 8.681”8.525”10.625”47 L-80 VAM 21 6,870 4,750 1,086
Tieback 7” 6.276 6.151 7.565 26 L-80 BTC 7,254 5,410 604
8-1/2”7” 6.276 6.151 7.656 26 L-80 H563 7254 5410 604
4-1/2” 3.958 3.833 5.2 12.6 L-80
H563 7780 6350 267
Tubing 4-1/2” 3.958 3.833 5 12.6 L-80 JFE Bear 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
Z-234 SB Injector
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 Josh Stephens 907.777.8420 josh.stephens@hilcorp.com
Geologist Kevin Eastham 907.777.8316 keastham@hilcorp.com
Reservoir Engineer Natalie Brent 907.564.4313 nbrent@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: JNL 7/14/2023
PROPOSED SCHEMATIC
Prudhoe Bay Unit
Well: PBU Z-234
Last Completed: TBD
PTD: TBD
TD =12,372’(MD) / TD =4,923’ (TVD)
20”
Orig. KB Elev.: 82.5’ / GL Elev.: 56.0’
7”
4
9-5/8”
1
2 3
See
Slotted
Liner
Detail
7”x
4-1/2”
XO
PBTD =12,370’(MD) / PBTD = 4,923’ (TVD)
9-5/8” ‘ES’
Cementer @
±2,500’
4-1/2”8
7
5
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 105’ N/A
9-5/8" Surface 47/ L-80 / BTC 8.681 Surface 2,500’ 0.0732
9-5/8” Surface 40 / L-80 / VAM 21 8.835 2,500’ 8,370’ 0.0758
7” Tieback 26 / L-80 / BTC 6.276 Surface 7,000’ 0.0383
7” Liner 26 / L-80 Hyd 563 6.276 7,000’ 8,370’ 0.0383
4-1/2” Slotted Liner 12.6 / L-80 / H563 3.958 8,370’ 12,372’ 0.0155
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / JFE Bear 3.958 Surface 8,370’ 0.0152
OPEN HOLE / CEMENT DETAIL
Driven Conductor
12-1/4"Stg 1 – Lead – 843 sx / Tail – 395 sx
Stg 2 – Lead – 886 sx / Tail – 268 sx
8-1/2” Uncemented Slotted Liner
WELL INCLINATION DETAIL
KOP @ 350’
90° Hole Angle = @ 8,543’ 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. Top MD Item ID
1 3,000’ X Nipple 3.813”
2 7,130’ X Nipple 3.813”
3 7,000’ 7” x 9-5/8” Liner Hanger w/ Tieback Sleeve
4 7,190’ Production Packer
5 7,250’ X Nipple 3.813”
7 8,370’ WLEG – Bottom
8 12,370’ Shoe
4-1/2” SLOTTED LINER DETAIL
Jts Top (MD) Top (TVD) Btm (MD) Btm (TVD)
TBD TBD TBD TBD TBD
““ “ “ “
“““““
TBD TBD TBD TBD TBD
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Drilling Procedure
7.0 Drilling / Completion Summary
PBU Z-234 is a grassroots injector planned to be drilled in the Schrader Bluff OBd sand. Z-234 is part of a
multi well program targeting the Schrader Bluff sand on PBU Z-pad.
The directional plan is 12-1/4” surface hole and 9-5/8” surface casing set in the OBd. An 8-1/2” section will
be drilled in the OBd. A 4-1/2” slotted injection liner will be run in the open hole section, followed by a 7”
tieback, and the well will be completed with injection tubing. Z-234 will not be pre produced prior to
injection.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately August 8th, 2023, pending rig schedule.
Surface casing will be run to 8,370’ MD / 4,948’ 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” hole to TD
6. Run 4-1/2” injection liner
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 Ops geologist. LWD: GR + Res
2. Production Hole: No mud logging. Remote Ops geologist. LWD: GR + ADR (For geo-steering)
e Schrader Bluff OBd sand.
p,
Z-234 will not be pre produced prior to,
injection.
LWD: GR + ADR (F
LWD: GR + Res
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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 Z-234. 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)”.
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Z-234 SB Injector
Drilling Procedure
AOGCC Regulation Variance Requests:
1) “A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates
pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure
that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the
maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured
depth above the top of the perforations, unless the commission approves a different placement depth as the
commission considers appropriate given the thickness and depth of the confining zone.”
In order to effectively produce this fault block, the current wellplan has the surface casing shoe landing at the
OBd production interval at ~85 degrees inclination. In order to make the ball and rod we land to set the
production packer slickline accessible, the X nipple in the tubing tail must be landed at less than 70 degrees
inclination. The MD we currently have planned for 70 degrees is at ~7,380’ MD / 4782 TVD. The production
packer will be ~50’ MD above the X nipple which puts it at ~7,250’ MD / ~4736’ TVD. The surface casing shoe
is planned at ~8370’ MD / 4948’ TVD which means the planned packer depth is ~1120’ MD away. From a TVD
standpoint, the production tubing packer is ~212’ TVD from the surface casing shoe. With the surface casing set
in the Schrader Bluff sand, and the injection packer set inside the surface casing at a depth below top of Schrader
bluff, injection fluids will be confined to the Schrader bluff sands.
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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.
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)
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Drilling Procedure
9.0 R/U and Preparatory Work
9.1 Z-234 will utilize a prior set 20” conductor on Z-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).
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.
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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. 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.
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.
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Drilling Procedure
10.4 Rig & Diverter Orientation:
x May change on location
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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 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 and offset any gas cut MW, based upon offset wells.
x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
ensure MW is at a 9.5 atjyy y,
base of perm and at TD (pending MW increase due to hydrates). This is to combatp(pg y)
hydrates and free gas risk and offset any gas cut MW, based upon offset wells.
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Drilling Procedure
x Be prepared for gas hydrates. In PBW they have been encountered typically around 1660’
TVD (Base of Perm) to 2740’ TVD (Top Ugnu). Be prepared for hydrates:
x Gas Hydrates are present on L PAD
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 premade 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:
x There are no wells with a clearance factor of <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.
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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 – 9.5 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. Drop mud temp as low as possible as well.
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.
x Ensure mud temp is as low as possible when backreaming before and through the SV 2 & 3
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
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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, and VAM 21 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 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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Drilling Procedure
12.5 Float equipment and Stage tool equipment drawings:
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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 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,500’ 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).
x Confirm depth of first major hydrates seen (possibly SV3) and position stage tool above if
possible, confirm with geo and drilling engineer before adjusting depth and ensure there is
enough 1st stage cement available
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 VAM21 Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”28,400 ft-lbs 31,550 ft-lbs 34,650 ft-lbs
9-5/8” 40# L-80 BTC MUT:
Casing OD Minimum Optimum Maximum
9-5/8”29,800 ft-lbs -34,800 ft-lbs
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Drilling Procedure
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12.8 Continue running 9-5/8” surface casing
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Drilling Procedure
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 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 (8,370'-1,000'-2,500') x 0.0558 bpf x 1.3 353.2 1981.2
Total Lead 353.2 1981.2 843.1
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 81.6 457.8 394.7LeadTail
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Drilling Procedure
Cement Slurry Design (1st Stage Cement Job):
13.9 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.
13.10 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.
a. Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.11 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.
13.12 Displacement calculation:
2500’ x 0.0732 bpf + (8,370’-120’-2500’) x .0758 bpf =
= 619 bbls
80 bbls of tuned spacer to be left behind stage tool for preventing of contamination of
cement in the annulus
13.13 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.
13.14 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.
13.15 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.
13.16 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
Lead Slurry Tail Slurry
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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Drilling Procedure
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.
13.17 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.
13.18 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:
13.19 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.
a. Past wells have seen pressure increase while circulating through stage tool after reduced
rate
13.20 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.21 Fill surface lines with water and pressure test.
13.22 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.23 Mix and pump cmt per below recipe for the 2
nd stage.
13.24 Cement volume based on annular volume + open hole excess (300% for lead based on past Z pad
surface cement jobs and 100% for tail). Job will consist of lead & tail, TOC brought to surface.
However 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):
13.25 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.26 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
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 4 421.7 2365.8
Total Lead 450.3 2526.2 886.4
12-1/4" OH x 9-5/8" Casing (2500 - 2000') x .0558 bpf x 2 55.8 313.0
Total Tail 55.8 313.0 267.6LeadTail
Lead Slurry Tail Slurry
System Arctic Cem HalCem
Density 10.7 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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Drilling Procedure
13.27 Displacement calculation:
2500’ x 0.0732 bpf = 183 bbls mud
13.28 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.
13.29 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.
13.30 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.
13.31 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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Drilling Procedure
14.0 ND Diverter, NU BOPE, & Test
14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.2 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 2-7/8” x 5-1/2” 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
14.3 RU MPD RCD and related equipment
14.4 Run 5” BOP test plug
14.5 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
14.6 RD BOP test equipment
14.7 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.8 Mix 9.5 ppg Baradrill-N fluid for production hole.
14.9 Set wearbushing in wellhead.
14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.11 Ensure 5” liners in mud pumps.
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Drilling Procedure
15.0 Drill 8-1/2” Hole Section
15.1 MU 8-1/2” directional BHA
x Motor and Triple Combo
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 solid float in the production hole section.
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
15.2 TIH w/ 8-1/2” 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)
email casing test and FIT digital data to AOGCC promptly upon completion of FIT. email: melvin.rixse@alaska.gov
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Drilling Procedure
15.8 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
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
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Drilling Procedure
15.9 Install MPD RCD
15.10 Displace wellbore to 9.5 ppg Baradrill-N drilling fluid
15.11 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 Reservior plan is to cross all lobes of the Schrader Bluff sand and TD beneath the OBD.
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.
x Target ROP is as fast as we can clean the hole without having to backream connections
x MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Hole Section A/C:
x Z-235 planned wellpath: CF - .86, Z-235 will be a Schrader Bluff OBc well drilled
before Z-234, giving it geologic separation from Z-234
x Z-116, PB1, PB2 CF 1.03 = Z-116 is a sidetracked active borealis injector, Z-234 lateral
will TD short of crossing the EOU of Z-116. Z-116 will be shut in and a plug set in the
tubing tail
x
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.
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Drilling Procedure
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 to 9.0 ppg minimum
15.17 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
15.18 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.19 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.20 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
15.21 POOH and LD BHA.
15.22 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
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 4-1/2” Injection Liner
16.1 Well control preparedness: In the event of an influx of formation fluids while running the
injection liner, the following well control response procedure will be followed:
x P/U & M/U the 4” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open
position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 4-1/2” 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.
16.2 R/U 4-1/2” liner running equipment.
x Ensure 4-1/2” 12.6# W563 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.
16.3 Run 4-1/2” injection liner
x Use Tenaris approved thread compound. Dope pin end only w/ paint brush. Wipe off
excess.
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 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
x See data sheets on the next page for MU torque for the 4-1/2” liner connections.
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Drilling Procedure
16.4 Confirm with OE whether or not this is required. Ensure to run enough liner to provide for
setting the liner hanger at ~ 150’ MD inside the surface casing shoe
x Confirm set depth with completion engineer.
x 3-5 joints of 7” will be ran under the liner hanger for the production packer. Confirm with
completion engineer.
16.5 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.
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Drilling Procedure
16.6 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.
16.5. M/U Baker SLZXP liner top packer to 4-1/2” liner.
16.6. 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.
16.7. 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 Fill drill pipe on the fly Monitor FL and if filling is required due to losses/surging.
16.8. 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.
16.9. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.10. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.11. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.12. 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
16.13. 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.
16.14. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
16.15. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SLZXP 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.
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Drilling Procedure
16.16. 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.
16.17. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.18. 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.
16.19. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.20. 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.
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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. Install 7” solid body casing rams in the upper ram
cavity. RU testing equipment. PT to 250/3,000 psi with 7” test joint. RD testing equipment.
17.2 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.
17.3 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.
17.4 MU first joint of 7” to seal assy.
17.6 Run 7”, 26#, L-80 BTC tieback to position seal assembly two joints above tieback sleeve.
Record PU and SO weights.
7”, 26#, L-80, BTC
Confirm Torques with casing hand
=
17.7 MU 7” to DP crossover.
17.8 MU stand of DP to string, and MU top drive.
17.9 Break circulation at 1 BPM and begin lowering string.
17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO-
GO DEPTH”.
17.12 PU string & remove unnecessary 7” joints.
17.13 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.
Casing OD Torque (Min) Torque (Opt)Torque (Max)
7”13,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs
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Drilling Procedure
17.14 PU and MU the 7” casing hanger.
17.15 Ensure circulation is possible through 7” string.
17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus.
17.17 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).
17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
17.19 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.
17.20 RD casing running tools.
17.21 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted.
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Drilling Procedure
18.0 Run Upper Completion/ Post Rig Work
18.1 RU to run 4-1/2”, 12.6#, L-80 JFE Bear tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 13.5#, JFE Bear x XT-39 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 RH with the following 4-1/2” GL completion jewelry (tally to be provided by
Operations Engineer):
x Torque Turn All Connections
x Tubing Jewelry to include:
x 2x ‘X’ Nipple
x 1x Production Packer
x 1x X Nipple
x 1x WLEG
x XXX joints, 4-1/2”, 12.6#, L-80, JFE Bear
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 follow by ~150 bbls of diesel freeze
protect for both tubing and IA to 2,500’ TVD.
18.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per
Halliburton’s setting procedure
18.12 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the
tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Bleed off the tubing and observe DCK
* Approved to set packer greater than 200' above perforations but not higher than the reservoir confining zone. - mgr
24 hour notice to AOGCC for opportunity to winess MIT-IA to 3500 psi. -mgr
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Drilling Procedure
shear. Confirm circulation in both directions thru the sheared valve. Record and notate all
pressure tests (30 minutes) on chart.
18.13 Bleed both the IA and tubing to 0 psi.
18.14 Rig up jumper from IA to tubing to allow freeze protect to swap.
18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
18.16 RDMO Innovation
i. POST RIG WELL WORK
1. CTU
a. Pull ball and rod in 4-1/2” production packer
* Approved for 30 days of production before POI.
* After 7 days of stabilized injection, 25 hour notice to AOGCC for opportunity to witness MIT-IA.
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Drilling Procedure
19.0 Innovation Rig Diverter Schematic
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Drilling Procedure
20.0 Innovation Rig BOP Schematic
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Drilling Procedure
21.0 Wellhead Schematic
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Drilling Procedure
22.0 Days Vs Depth
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Drilling Procedure
23.0 Formation Tops & Information
Reference Plan:
COMMENTS
SV5 Ice 2,130 1,779.7 -1697 783 8.46
BPRF Water 2,411 1,946.7 -1864 857 8.46
SV3 Gas Hydrates 2,918 2,248.7 -2166 989 8.46 Gas Hydrates expected SV3, SV2, & SV1 sands: ~2920' - 4220' MD
SV1 Gas Hydrates 3,771 2,756.7 -2674 1213 8.46
Ugnu 4A Heavy Oil 4,475 3,174.7 -3092 1397 8.46 Possible Heavy Oil in Ugnu 4A: ~ 4475' - 4850' MD
UG3 Water 5,000 3,487.7 -3405 1535 8.46
Ugnu LA Water 6,099 4,142.7 -4060 1823 8.46
Ugnu MB Water 6,421 4,331.7 -4249 1906 8.46
NB Schrader Bluff Water 6,828 4,549.7 -4467 2002 8.46
OA Top Schrader Bluff Water 7,180 4,707.7 -4625 2071 8.46
Obb Top Schrader Bluff Water 7,370 4,777.7 -4695 2102 8.46
FAULT 70' DTN Throw 7,830
Obc Top Schrader Bluff Oil 7,820 4,891.7 -4809 2152 8.46
OBd Top (Heel) Schrader Bluff Oil 8,435 4,951.7 -4869 2179 8.46
OBd (Toe) 12,323 4,922.7 -4840 2166
EASTING Est.
Pressure GradientEXPECTED
FLUID
MD
(FT)
TVD
(FT)
TVDSS
(FT)NORTHING
Z-234 wp02ANTICIPATED FORMATION TOPS & GEOHAZARDS
TOP NAME LITHOLOGY
Page 46
Prudhoe Bay West
Z-234 SB Injector
Drilling Procedure
Page 47
Prudhoe Bay West
Z-234 SB Injector
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 been seen on PBU Z Pad. They were reported between 1660’ and 2740’ TVD. MW
has been chosen based upon successful trouble free penetrations of offset wells.
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.
o Reduce flowrate as needed to help control hydrates in the mud column.
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 There are no wells with a clearance factor of <1.0
Page 48
Prudhoe Bay West
Z-234 SB Injector
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 49
Prudhoe Bay West
Z-234 SB Injector
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 Z-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 50
Prudhoe Bay West
Z-234 SB Injector
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 AC:
x Z-235 planned wellpath: CF - .86, Z-235 will be a Schrader Bluff OBc well drilled
before Z-234, giving it geologic separation from Z-234
x Z-116, PB1, PB2 CF 1.03 = Z-116 is a sidetracked active borealis injector, Z-234 lateral
will TD short of crossing the EOU of Z-116. Z-116 will be shut in and a plug set in the
tubing tail
j,
Z-116 will be shut in and a plug set in the
tubing tail
planned w
Page 51
Prudhoe Bay West
Z-234 SB Injector
Drilling Procedure
25.0 Innovation Rig Layout
Page 52
Prudhoe Bay West
Z-234 SB Injector
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 53
Prudhoe Bay West
Z-234 SB Injector
Drilling Procedure
27.0 Innovation Rig Choke Manifold Schematic
Page 54
Prudhoe Bay West
Z-234 SB Injector
Drilling Procedure
28.0 Casing Design
Page 55
Prudhoe Bay West
Z-234 SB Injector
Drilling Procedure
29.0 8-1/2” Hole Section MASP
Page 56
Prudhoe Bay West
Z-234 SB Injector
Drilling Procedure
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 57
Prudhoe Bay West
Z-234 SB Injector
Drilling Procedure
31.0 Surface Plat (As Built) (NAD 27)
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060012001800240030003600420048005400True Vertical Depth (1200 usft/in)-1200 -600 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200Vertical Section at 0.00° (1200 usft/in)Z-234 wp01 tgt1Z-234 wp01 tgt2Z-234 wp01 tgt3Z-234 wp01 tgt49 5/8" x 12 1/4"4 1/2" x 8 1/2"50010001500200025003000350040004500500055006000650070007500800085009000
9500
10000
1 05 00
110 00115001200012372Z-234 wp02Start Dir 3º/100' : 350' MD, 350'TVDStart Dir 4º/100' : 500' MD, 499.85'TVDEnd Dir : 1724.51' MD, 1538.61' TVDStart Dir 4º/100' : 5786.1' MD, 3955.66'TVDFault #1 (70' DTN)End Dir : 8012.57' MD, 4917' TVDStart Dir 3º/100' : 8362.57' MD, 4947.5'TVDEnd Dir : 8543.02' MD, 4954.72' TVDStart Dir 2.5º/100' : 10235.77' MD, 4942.5'TVDEnd Dir : 10536.79' MD, 4928.73' TVDStart Dir 2.5º/100' : 10907.88' MD, 4897.5'TVDEnd Dir : 11178.83' MD, 4889.8' TVDTotal Depth : 12372.08' MD, 4922.5' TVDSV5BPRFSV3SV1Ugnu 4AUG3Ugnu LAUgnu MBNBOAObbObcOBdHilcorp North Slope, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: Z-23456.00+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.005959239.85600018.40 70° 17' 52.9853 N 149° 11' 24.0750 WSURVEY PROGRAMDate: 2023-05-11T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 1200.00 Z-234 wp02 (Z-234) GYD_Quest GWD1200.00 8370.00 Z-234 wp02 (Z-234) 3_MWD+IFR2+MS+Sag8370.00 12372.08 Z-234 wp02 (Z-234) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1779.50 1697.00 2129.30 SV51947.50 1865.00 2411.60 BPRF2249.50 2167.00 2919.08 SV32757.50 2675.00 3772.72 SV13177.50 3095.00 4478.49 Ugnu 4A3490.50 3408.00 5004.45 UG34145.50 4063.00 6103.14 Ugnu LA4334.50 4252.00 6425.47 Ugnu MB4553.50 4471.00 6834.05 NB4711.50 4629.00 7186.83 OA4782.50 4700.00 7381.37 Obb4895.50 4813.00 7837.93 Obc4952.50 4870.00 8436.16 OBdREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: Z-234, True NorthVertical (TVD) Reference:Z-234 as built RKB @ 82.50usft (Original Well Elev)Measured Depth Reference:Z-234 as built RKB @ 82.50usft (Original Well Elev)Calculation Method: Minimum CurvatureProject:Prudhoe BaySite:ZWell:Plan: Z-234Wellbore:Z-234Design:Z-234 wp02CASING DETAILSTVD TVDSS MD SizeName4948.13 4865.63 8370.00 9-5/8 9 5/8" x 12 1/4"4922.50 4840.00 12372.08 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.002 350.00 0.00 0.00 350.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 350' MD, 350'TVD3 500.00 4.50 95.00 499.85 -0.51 5.87 3.00 95.00 -0.51 Start Dir 4º/100' : 500' MD, 499.85'TVD4 700.00 12.50 95.00 697.49 -3.09 35.29 4.00 0.00 -3.095 1724.51 53.48 94.95 1538.61 -50.28 579.27 4.00 -0.07 -50.28 End Dir : 1724.51' MD, 1538.61' TVD6 5786.10 53.48 94.95 3955.66 -331.75 3831.22 0.00 0.00 -331.75 Start Dir 4º/100' : 5786.1' MD, 3955.66'TVD7 8012.57 85.00 2.41 4917.00 973.04 5018.42 4.00 -95.53 973.04 End Dir : 8012.57' MD, 4917' TVD8 8362.57 85.00 2.41 4947.50 1321.40 5033.08 0.00 0.00 1321.40 Z-234 wp01 tgt1 Start Dir 3º/100' : 8362.57' MD, 4947.5'TVD9 8543.02 90.41 2.42 4954.72 1501.48 5040.66 3.00 0.05 1501.48 End Dir : 8543.02' MD, 4954.72' TVD10 10235.77 90.41 2.42 4942.50 3192.69 5111.99 0.00 0.00 3192.69 Z-234 wp01 tgt2 Start Dir 2.5º/100' : 10235.77' MD, 4942.5'TVD11 10536.79 94.83 356.31 4928.73 3493.16 5108.68 2.50 -53.99 3493.16 End Dir : 10536.79' MD, 4928.73' TVD12 10907.88 94.83 356.31 4897.50 3862.16 5084.90 0.00 0.00 3862.16 Z-234 wp01 tgt3 Start Dir 2.5º/100' : 10907.88' MD, 4897.5'TVD13 11178.83 88.43 358.54 4889.80 4132.57 5072.75 2.50 160.76 4132.57 End Dir : 11178.83' MD, 4889.8' TVD14 12372.08 88.43 358.54 4922.50 5324.99 5042.36 0.00 0.00 5324.99 Z-234 wp01 tgt4 Total Depth : 12372.08' MD, 4922.5' TVD
-750
-375
0
375
750
1125
1500
1875
2250
2625
3000
3375
3750
4125
4500
4875
5250
5625
South(-)/North(+) (750 usft/in)0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250
West(-)/East(+) (750 usft/in)
Z-234 wp01 tgt4
Z-234 wp01 tgt3
Z-234 wp01 tgt2
Z-234 wp01 tgt1
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"500100012501500175020002250250027503000325035003750400042504
5
0
0
4750
492 3
Z-234 wp02
Start Dir 3º/100' : 350' MD, 350'TVD
Start Dir 4º/100' : 500' MD, 499.85'TVD
Start Dir 4º/100' : 5786.1' MD, 3955.66'TVD
Fault #1 (70' DTN)
End Dir : 8012.57' MD, 4917' TVD
Start Dir 3º/100' : 8362.57' MD, 4947.5'TVD
End Dir : 8543.02' MD, 4954.72' TVD
Start Dir 2.5º/100' : 10235.77' MD, 4942.5'TVD
End Dir : 10536.79' MD, 4928.73' TVD
Start Dir 2.5º/100' : 10907.88' MD, 4897.5'TVD
End Dir : 11178.83' MD, 4889.8' TVD
Total Depth : 12372.08' MD, 4922.5' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4948.13 4865.63 8370.00 9-5/8 9 5/8" x 12 1/4"
4922.50 4840.00 12372.08 4-1/2 4 1/2" x 8 1/2"
Project: Prudhoe Bay
Site: Z
Well: Plan: Z-234
Wellbore: Z-234
Plan: Z-234 wp02
WELL DETAILS: Plan: Z-234
56.00
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00
5959239.85 600018.40
70° 17' 52.9853 N 149° 11' 24.0750 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: Z-234, True North
Vertical (TVD) Reference:Z-234 as built RKB @ 82.50usft (Original Well Elev)
Measured Depth Reference:Z-234 as built RKB @ 82.50usft (Original Well Elev)
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200 7650 8100 8550Measured Depth (900 usft/in)Z-69Z-235 wp02No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: Z-234 NAD 1927 (NADCON CONUS)Alaska Zone 0456.00+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005959239.85600018.4070° 17' 52.9853 N149° 11' 24.0750 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: Z-234, True NorthVertical (TVD) Reference:Z-234 as built RKB @ 82.50usft (Original Well Elev)Measured Depth Reference:Z-234 as built RKB @ 82.50usft (Original Well Elev)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2023-05-11T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 1200.00 Z-234 wp02 (Z-234) GYD_Quest GWD1200.00 8370.00 Z-234 wp02 (Z-234) 3_MWD+IFR2+MS+Sag8370.00 12372.08 Z-234 wp02 (Z-234) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 4950 5400 5850 6300 6750 7200 7650 8100 8550Measured Depth (900 usft/in)Z-61Z-113Z-115Z-69Z-235 wp02GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 12372.08Project: Prudhoe BaySite: ZWell: Plan: Z-234Wellbore: Z-234Plan: Z-234 wp02Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name4948.13 4865.63 8370.00 9-5/8 9 5/8" x 12 1/4"4922.50 4840.00 12372.08 4-1/2 4 1/2" x 8 1/2"
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0.001.002.003.004.00Separation Factor8325 8550 8775 9000 9225 9450 9675 9900 10125 10350 10575 10800 11025 11250 11475 11700 11925 12150 12375 12600Measured Depth (450 usft/in)W-26BZ-116Z-235 wp02No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: Z-234 NAD 1927 (NADCON CONUS)Alaska Zone 0456.00+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005959239.85600018.4070° 17' 52.9853 N149° 11' 24.0750 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: Z-234, True NorthVertical (TVD) Reference:Z-234 as built RKB @ 82.50usft (Original Well Elev)Measured Depth Reference:Z-234 as built RKB @ 82.50usft (Original Well Elev)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2023-05-11T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 1200.00 Z-234 wp02 (Z-234) GYD_Quest GWD1200.00 8370.00 Z-234 wp02 (Z-234) 3_MWD+IFR2+MS+Sag8370.00 12372.08 Z-234 wp02 (Z-234) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)8325 8550 8775 9000 9225 9450 9675 9900 10125 10350 10575 10800 11025 11250 11475 11700 11925 12150 12375 12600Measured Depth (450 usft/in)Z-235 wp02GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 12372.08Project: Prudhoe BaySite: ZWell: Plan: Z-234Wellbore: Z-234Plan: Z-234 wp02Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name4948.13 4865.63 8370.00 9-5/8 9 5/8" x 12 1/4"4922.50 4840.00 12372.08 4-1/2 4 1/2" 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 no greater
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.
223-065
x
X
Prudhoe Bay
X
Schrader Bluff Oil
PBU Z-234
WELL PERMIT CHECKLISTCompanyHilcorp North Slope, LLCWell Name:PRUDHOE BAY UN ORIN Z-234Initial Class/TypeSER / WAGINGeoArea890Unit11650On/Off ShoreOnProgramSERField & PoolWell bore segAnnular DisposalPTD#:2230650PRUDHOE BAY, SCHRADER BLUF OIL - 640135NA1 Permit fee attachedYes Entire Well lies within ADL0028262.2 Lease number appropriateYes PBU Z-2343 Unique well name and numberYes PRUDHOE BAY, SCHRADER BLUF OIL - 640135 - governed by 505B, 505B.0044 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitYes Governed by AIO 26B, issued May 4, 2010; corrected February 3, 202114 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servYes15 All wells within 1/4 mile area of review identified (For service well only)No Application states well will not be pre-produced.16 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 driven to 105'18 Conductor string providedYes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir19 Surface casing protects all known USDWsYes 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 csgYes 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 csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22 CMT will cover all known productive horizonsYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.23 Casing designs adequate for C, T, B & permafrostYes Innovation rig has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows close approach Z-235 - geosteer in reservoir. Z-116 PB shut in.26 Adequate wellbore separation proposedYes 16" Diverter below BOPE27 If diverter required, does it meet regulationsYes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes Monitoring will be required.33 Is presence of H2S gas probableYes34 Mechanical condition of wells within AOR verified (For service well only)No H2S measures required. Z-Pad wells are H2S bearing.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure is 0.44 psi/ft (8.5 ppg EMW). Operator's planned mud program36 Data presented on potential overpressure zonesNA appears sufficient to control anticipated pressures. Gas Hydrates likely at base of permafrost to top Ugnu.37 Seismic analysis of shallow gas zonesNA See pages 19 and 51. Washouts in permafrost can be severe.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprMDGDate7/27/2023ApprMGRDate7/24/2023ApprMDGDate7/27/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateGCW 07/28/2023JLC 7/28/2023
