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2
5
MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Thursday, June 1, 2023
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Austin McLeod
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
B-40
MILNE PT UNIT B-40
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 06/01/2023
B-40
50-029-23745-00-00
223-009-0
W
SPT
4443
2230090 1500
357 358 359 359
INITAL P
Austin McLeod
5/4/2023
MITIA. Monobore.
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:MILNE PT UNIT B-40
Inspection Date:
Tubing
OA
Packer Depth
443 1717 1649 1627IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitSAM230506123123
BBL Pumped:2.5 BBL Returned:2.5
Thursday, June 1, 2023 Page 1 of 1
9
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James B. Regg Digitally signed by James B. Regg
Date: 2023.06.02 10:46:21 -08'00'
MILNE POINT FIELD /
SCHRADER BLUFF OIL POOL
2
By James Brooks at 1:10 pm, May 01, 2023
Completed.
3/20/2023
JSB
RBDMS JSB 051623
GDSR-5/22/23MGR08AUG2023
5.1.2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.05.01 12:34:20 -08'00'
Monty M
Myers
_____________________________________________________________________________________
Revised By: JNL 3/24/2023
SCHEMATIC
Milne Point Unit
Well: MPU B-40
Last Completed: 3/20/2023
PTD: 223-009
SLOTTED LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
4-1/2” 6496’ 4462’ 13325’ 4446’
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X-52 / Weld N/A Surface 114’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.525” Surface 2,240’ 0.0732
9-5/8" Surface 40 / L-80 / TXP 8.679” 2,240’ 6,494’ 0.0758
4-1/2” Solid / Slotted Liner 13.5 / L-80 / Hyd 625 3.920” 6,305’ 13,368’ 0.0149
TUBING DETAIL
3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.992” Surface 6,327’ 0.0087
OPEN HOLE / CEMENT DETAIL
Driven 20” Conductor
12-1/4"Stg 1 –Lead 556 sx / Tail 400 sx
Stg 2 –Lead 870 sx / Tail 270 sx
8-1/2” Cementless Slotted Liner
TREE & WELLHEAD
Tree Cameron 3 1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API#: 50-029-23745-00-00
Completion Date: 3/20/2023
WELL INCLINATION DETAIL
KOP @ 242’
90° Hole Angle @ 7,592’ MD
TD =13,368’(MD) / TD =4,447’(TVD)
20”
Orig. KB Elev.: 57.65’ / GL Elev.: 23.3’
3-1/2”
7
2
9-5/8”
1
4/5
PB2:
10327’–
11372’
See
Slotted
Liner
Detail
PBTD =13,366’(MD) / PBTD =4,447’(TVD)
9-5/8” ‘ES’
Cementer @
2,296’
PB 1:
6454’–
6497’
4-1/2”
6
3
JEWELRY DETAIL
No Top MD Item ID
Upper Completion
1 5,804’ Sliding Sleeve 2.813” X profile, covered ports (opens down) 2.870”
2 5,857’ Zenith Gauge Carrier 2.865”
3 5,916’ X Nipple, 2.813” 2.820”
4 6,316’ 8.24” No Go Locater Sub (spaced out 2.00’) 6.170”
5 6,317’ Bullet Seals – TXP Top Box x Mule Shoe 6.200”
Lower Completion
6 6,305’ 9-5/8” SLZXP Liner Top Packer 6.190”
7 13,366’ Shoe
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:MPU B-40 Date:3/11/2023
Csg Size/Wt/Grade:9.625", 40# & 47#, L-80 Supervisor:Demoski/Toomey
Csg Setting Depth:6494 TMD 4462 TVD
Mud Weight:9.25 ppg LOT / FIT Press =637 psi
.
LOT / FIT =12.00 Hole Depth =6497 md
Fluid Pumped=1.70 Bbls Volume Back =1.70 bbls
Estimated Pump Output:0.101 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->00 ->00
->260 ->4 182
->4 101 ->8 425
->6 188 ->12 652
->8 298 ->16 827
->9 339 ->20 1029
->10 385 ->24 1232
->11 454 ->28 1462
->12 481 ->32 1705
->13 516 ->36 1908
->14 573 ->40 2170
->15 601 ->44 2426
->16 635 ->48 2623
->17 674 ->50 2720
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 648 ->0 2720
->1 580 ->5 2711
->2 533 ->10 2704
->3 505 ->15 2700
->4 483 ->20 2694
->5 463 ->25 2691
->6 446 ->26 2691
->7 434 ->27 2690
->8 426 ->28 2690
->9 414 ->29 2690
->10 406 ->30 2689
->11 404 ->
->12 395 ->
->13 394 ->
->14 384
->15 384
->
0
2
4
6
8 9
10
111213
14151617
0
4
8
12
16
20
24
28
32
36
40
44
48
50
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 102030405060
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
Pr
e
s
s
u
r
e
(
p
s
i
)
648
580
533505483463446434426414406404395394384384
2720 2711 2704 2700 2694 269126912690269026902689
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
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2200
2300
2400
2500
2600
2700
2800
2900
3000
0 5 10 15 20 25 30 35
Pr
e
s
s
u
r
e
(p
s
i
)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
Activity Date Ops Summary
3/1/2023 Finish up spotting the rig over the well, shim and level the rig. PJSM and skid rig floor to drill position. RU rig floor steam, air, water and mud lines. Set diverter
annular on Tee, Install knife valve. Spot 5 star and MI shack. Work on rig acceptance checklist. Spot remaining shacks, power up same. Spot slop tank and water
pump house. Install 1st section of diverter, Berm & spot cuttings box, Re-connect #1 drag chain. Put rig on highline power at 15:35 hours. Load 5" DP into the pipe
shed, strap and tally pipe. Rig electrician calibrate and test the rig gas alarms. Work on rig acceptance checklist. Work on rig acceptance checklist. Spot fuel trailer
and rock washer. Spot 2 water up right tanks and cement silos. Process 5" DP. Perform derrick inspection. Work on rig acceptance checklist. Process 5" DP.
Inspect the save sub and grabber dies. Obtain RKB's. RU water house and upright tanks. Install diverter riser.
3/2/2023 Work on acceptance checklist. Finish loading DP into the shed, strap and tally same. Get the rock washer operational. Install the remaining diverter line. RU
accumulator lines to diverter and knife valve. Slip and cut pullback cable on skate. PJSM, place mousehole in rotary table, PU 5'' drill pipe from the pipe shed
racking stands in the derrick. SimOps: stock hopper room for spudding, MWD ready BHA, continue to work on acceptance checklist. Continue to PU and rack
stands 5'' drill pipe in the derrick. Pull mousehole from rotary table. SimOps: Haliburton offload surface cement to silos. Load the pits with 580 bbls 8.8 ppg spud
mud into pits. Place rig diverter warning signs. Perform diverter test. AOGCC inspector Austin McLeod waived witness at 05:40 on 3/1/23. Test performed on 5" DP.
Knife valve open in 17 second, annular closed in 21 seconds. 2,950 psi system pressure, 1,800 psi after closing. 200 psi recovery = 34 seconds & full recovery =
158 seconds. 6 N2 bottle avg= 1,983 psi. Tested rig LEL and H2S gas alarms - good. Tested PVT and flow sensors - good. 16" diverter line length= 197.1', from
substructure= 188.7'. Nearest ignition source= 87.4' (Sperry unit). Re-install mousehole in rotary table. Continue to PU 5'' drill pipe and rack back a total of 70
stands, PU and rack back 6 stands of HWDP and jars. Rig accepted at 15:30 hours. PU and rack back 6 stands of HWDP and jar. Lay down 30' mouse, remove
thread protector from the floor and install 10' hole. Mobilze 12-1/4" tricone and Kymera to the rig floor. Hold pre-spud meeting with all parties involved - identify safe
briefing areas and emergency response duties. MU 12-1/4" tricone bit, motor, crossover and 1 stand of 5" HWDP. RIH and tag a 110'. Flood mud lines with fresh
water and fill stack with fresh water. PT lines to 3,800 psi - good test. Cleanout the conductor from 110' to 114' at 400 GPM and 40 RPM. Drill 12-1/4" surface hole
from 114' to 219' (219' TVD). Drilled 105' = 70'/hr AROP. 400 GPM = 300 psi, 40 RPM = 1K ft-lbs TQ, WOB = 5-10K. PU = 50K, SO = 50K & ROT = 50K. MW =
8.9 ppg, Vis = 300. BROOH from 219' to 126'. POOH on elevators from 126' to 36'. Blow down the top drive. Break out the tricone. Bit grade: 0-0-NO-A-E-I-RR-
BHA. MU the 12-1/4" Kymera bit. MU MWD tools with Dir, Gamma, Res, PWD and GWD to 97'. Initialize MWD tools. MU NM flex collars to 128'. Daily disposal to
G&I = 0 bbls. Total disposal to G&I = 0 bbls. Daily water hauled from L-pad lake= 750 bbls. Total water hauled from L-pad lake = 750 bbls. Daily fluid loss = 0 bbls.
Total fluid loss = 0 bbls.
3/3/2023 Continue to MU NM flex collars from 128' to tag at 160'. Attempt to work through with no success. LD 3rd NM flex collar. PU stand of 5" HWDP wash and ream from
157' to 219'. 380 GPM = 640 psi, 40 RPM = 2-5K ft-lbs TQ. Reamed stand 2 times and rack back stand of HWDP. MU last NM flex collar and RIH to 187'. Wash to
down to 219'. Drill 12-1/4" surface hole from 219' to 466' (466' TVD). Drilled 247' = 54.8'/hr AROP. 450 GPM = 980 psi, 40 RPM = 2-3K ft-lbs TQ, WOB = 5-10K.
PU = 68K, SO = 76K & ROT = 75K. MW = 9 ppg, Vis = 277, ECD = 9.64 ppg. At 350' start to build 3 deg/100'. Drill 12-1/4" surface hole from 466' to 980' (975'
TVD). Drilled 514' = 85.7'/hr AROP. 450 GPM = 1,190 psi, 40 RPM = 3K ft-lbs TQ, WOB = 11K. PU = 80K, SO = 92K & ROT = 85K. MW = 9.0 ppg, Vis = 139,
ECD = 9.63 ppg. At 750' build 4 deg/100'. Drill 12-1/4" surface hole from 980' to 1,504' (1,361' TVD). Drilled 514' = 85.7'/hr AROP. 500 GPM = 1,470 psi, 60 RPM
= 5K ft-lbs TQ, WOB = 10-15K. PU = 90K, SO = 95K & ROT = 90K. MW = 9.2 ppg, Vis = 300, ECD = 10.0 ppg, max gas = 6 units. Last gyro survey at 989'. Drill
12-1/4" surface hole from 1,504' to 2,171' (1,856' TVD). Drilled 667' = 111.2'/hr AROP. 465 GPM = 1,340 psi, 80 RPM = 4-6K ft-lbs TQ, WOB = 2-5K. PU = 105K,
SO = 98K & ROT = 100K. MW = 9.1+ ppg, Vis = 247, ECD = 10.42 ppg, max gas = 10 units. Begin 47 degree tangent section at 1,560'. Last survey at 2023.91
MD / 1,752.70 TVD, 46.42 deg INC, 229.51 deg AZM. Distance from WP12 = 18.73, 8.19 high & 16.85 left. Daily disposal to G&I = 1,174 bbls. Total disposal to
G&I = 1,174 bbls. Daily water hauled from L-pad lake= 1,250 bbls. Total water hauled from L-pad lake = 2,000 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 0
bbls.
3/4/2023 Drill 12-1/4" surface hole from 2,171' to 2,795' (2,282' TVD). Drilled 624' = 104'/hr AROP. 507 GPM = 1,490 psi, 80 RPM = 4-9K ft-lbs TQ, WOB = 4K. PU = 125K,
SO = 90K & ROT = 107K. MW = 9.2 ppg, Vis = 160, ECD = 10.6 ppg, Max gas=3,592 units. Pumped 30 bbl hi-vis sweep at 2,457', back on time with 50%
increase in cuttings. Continue to maintain 47 deg tangent section. Base of the permafrost logged at 2,118' MD (1,818' TVD). Drill 12-1/4" surface hole from 2,795' to
3,409' (2,688' TVD). Drilled 614' = 136.4'/hr AROP. 510 GPM = 1600 psi, 80 RPM = 9K ft-lbs TQ, WOB = 4K. PU = 130K, SO = 95K & ROT = 107K. MW = 9.3
ppg, Vis = 175, ECD = 10.65 ppg, Max gas=734 units. Continue to maintain 47 deg tangent section. During a connection, rig electrician attempted to put power
factor corrector online tripping out hi line breaker. Rig put on generator power in about 10 minutes. Circulate and work pipe until back on highline power. All
equipment back online and running. Drill 12-1/4" surface hole from 3,409' to 3,536' (2,777' TVD). Drilled 127' = 127'/hr AROP. 527 GPM = 1,690 psi, 80 RPM = 8K
ft-lbs TQ, WOB = 10K. PU = 132K, SO = 98K & ROT = 110K. MW = 9.3 ppg, Vis = 158, ECD = 10.48 ppg, Max gas= 132 units. Continue to maintain 47 deg
tangent section. Pumped 30 bbl hi-vis sweep at 3,536', back 300 strokes late with 20% increase in cuttings. Drill 12-1/4" surface hole from 3,536' to 4,264' (3,198'
TVD). Drilled 728' = 121.3'/hr AROP. 557 GPM = 1,960 psi, 80 RPM = 10K ft-lbs TQ, WOB = 12K. PU = 152K, SO = 105K & ROT = 153K. MW = 9.3 ppg, Vis =
147, ECD = 10.07 ppg, Max gas= 130 units. Continue to maintain 47 deg tangent section. Drill 12-1/4" surface hole from 4,264' to 4,739' (3,643' TVD). Drilled 475'
= 79.2'/hr AROP. 548 GPM = 2,147 psi, 80 RPM = 12K ft-lbs TQ, WOB = 12-15K. PU = 163K, SO = 110K & ROT = 131K. MW = 9.3 ppg, Vis = 125, ECD = 10.38
ppg, Max gas= 212 units. Continue to maintain 47 deg tangent section. Pumped 30 bbl hi-vis sweep at 4,549', back on time with 40% increase in cuttings. Last
survey at 4,687.33 MD / 3,605.31 TVD, 45.66 deg INC, 239.67 deg AZM. Distance from WP12 = 10.57, 9.73 low & 4.14 left. Daily disposal to G&I = 1,958 bbls.
Total disposal to G&I = 3,132 bbls. Daily water hauled from L-pad lake= 1,850 bbls. Total water hauled from L-pad lake = 3,850 bbls. Daily fluid loss = 0 bbls. Total
fluid loss = 0 bbls.
50-029-23745-00-00API #:
Well Name:
Field:
County/State:
MP B-40
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
3/2/2023Spud Date:
3/5/2023 Drill 12-1/4" surface hole from 4,739' to 5,165' (3,931' TVD). Drilled 426' = 71'/hr AROP. 553 GPM = 2,060 psi, 80 RPM = 12-15K ft-lbs TQ, WOB = 7-13K. PU =
175K, SO = 112K & ROT = 139K. MW = 9.3 ppg, Vis = 117, ECD = 10.1 ppg, Max gas = 207 units. Maintain 47 deg tangent section to 4985' then start build and
turn at 4.2 deg/100'. Drill 12-1/4" surface hole from 5,165' to 5,787' (4,288' TVD). Drilled 622' = 103.7'/hr AROP. 553 GPM = 2,000 psi, 80 RPM = 16K ft-lbs TQ,
WOB = 15K. PU = 195K, SO = 110K & ROT = 140K. MW = 9.2 ppg, Vis = 66, ECD = 9.88 ppg, Max gas = 634 units. Continue to build and turn at 4.2 Deg/100'.
Logged top of Ugnu L-sand at 5,108' (3,909' TVD). Pumped 30 bbl hi-vis sweep at 5,548', back 500 stokes late with no increase. Drill 12-1/4" surface hole from
5,787' to 6,263' (4,403' TVD). Drilled 476' = 79.3'/hr AROP. 548 GPM = 2,260 psi, 80 RPM = 16K ft-lbs TQ, WOB = 20K. PU = 190K, SO = 105K & ROT = 135K.
MW = 9.2 ppg, Vis = 92, ECD = 10.07 ppg, Max gas = 455 units. Continue to build and turn at 4.2 Deg/100'. Drill 12-1/4" surface hole from 6,263' to TD at 6,497'
(4,455' TVD). Drilled 234' = 78'/hr AROP. 544 GPM = 2,030 psi, 80 RPM = 15K ft-lbs TQ, WOB = 10-13K. PU = 185K, SO = 103K & ROT = 140K. MW = 9.3 ppg,
Vis = 69, ECD = 10.0 ppg, Max gas = 246 units. Logged the top of the SB_OA sand at 6,378'. Obtain final survey at 6,497.00 MD / 4,455.26 TVD, 90.20 deg INC,
292.38 deg AZM. Distance from WP12 = 24.84, 4.15 high & 24.49 right. Pump 30 bbl hi-vis sweep and circulate out of the well at 550 GPM = 1,500 psi, 80 RPM =
11-18K ft-lbs TQ reciprocating 90'. Back 500 strokes late with 0% increase. Good 9.3 ppg in/out vis 53 & YP = 25. Max gas 283 units. While RIH while circulating
bit took weight and had a torque increase at 6,423'. PU and attempt to work past. Wash and ream back to TD.
3/6/2023 Continue to wash and ream from 6454' back to TD at 6497', 544 GPM = 1,800 psi, 80 RPM = 14-15K ft-lbs TQ. Obtain new final survey: 6,444.36' / 4,457.58' TVD,
84.46 deg INC, 290.29 deg AZM. Distance from WP12 = 25', 2.08' low & 24.16' right. Reamed out approximately 6 deg from previous survey. BROOH from 6,497'
to 4,076' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM = 1,690 psi, 60 RPM = 14-16K ft-bs TQ, ECD= 10.29 ppg, max gas
= 1,126 units. PU = 190K, SO = 105K, ROT = 140K. BROOH from 4,076' to 1,507' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. 550
GPM = 1,400 psi, 60 RPM = 8K ft-bs TQ, ECD = 10.29 ppg, max gas = 107 units. PU = 100K, SO = 88K, ROT = 92K. BROOH from 1,507' to 745' (HWDP) pulling
5-10 minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM = 1,150 psi, 60 RPM = 2K ft-bs TQ, ECD = 10.23 ppg, max gas = 31 units. PU =
90K, SO = 80K, ROT = 85K. Attempt to POOH on elevator but unable to. BROOH from 745' to 468' at 450 GPM = 900 psi, 40 RPM = 15K ft-lbs TQ. TOOH on
elevators from 468' to 375'. Blow down the top drive. TOOH from 375' to 190'. Lay down crossover and 3 NMFCs to 97'. Download MWD data. Lay down remaining
BHA components. 12-1/4"" bit grade: PDC = 1-1-CT-N-X-I-NO-TD & Tri-cone = 1-1-WT-A-E-I-NO-TD. Lost 57 bbls while BROOH. Clean and clear the rig floor. Jet
the flow line. Monitor the well with the trip. Static loss rate = 3.5 BPH. Mobilize casing running tools to the rig floor. RU Volant CRT, bail extensions, 9-5/8" handling
equipment and casing tongs. MU crossover to FOSV. PJSM. MU 9-5/8"", 40#, L-80, TXP-BTC shoe track to 162' Baker Lok connections 1-4 with 21K ft-lbs TQ.
HES rep installed top hat above float collar. Pump through shoe track and check floats - good. Static loss rate = 3.5 BPH. RIH with 9-5/8", 40#, L-80, DWC/C casing
from 162' to 861'. TQ = 32.3K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally. Daily disposal to G&I = 1,616 bbls. Total
disposal to G&I = 6,131 bbls. Daily water hauled from L-pad lake= 1,680 bbls. Total water hauled from L-pad lake = 7,060 bbls. Daily fluid loss = 57 bbls. Total fluid
loss = 57 bbls.
3/7/2023 Continue RIH with 9-5/8", 40#, L-80, DWC/C casing from 861' to 2,293'. TQ = 32.3K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing
centralizer per tally. Loss rate = 3-5 BPH. CBU, staging to 5 BPM = 160 psi and working pipe slow from 2,293' to 2,335'. Lost 10 bbl while circulating. Continue RIH
with 9-5/8", 40#, L-80, DWC/C casing from 2,335' to 3,065'. TQ = 32.3K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer per
tally. PU= 145K, SO= 85K. Loss rate = 3-5 BPH. Continue RIH with 9-5/8", 40#, L-80, DWC/C casing from 3,065' to 4,177'. TQ = 32.3K ft-lbs with Volant tool. Fill
on the fly and top off every 10 joints. Installing centralizer per tally. Baker loc and MU ESC with pup joints as per HES rep to 4,253', TQ 40# TXP to 21K ft-lbs.
Continue RIH with 9-5/8", 47#, L-80, TXP casing from 4,253' to 5,037'. TQ = 24K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer
per tally. PU = 245K & SO = 120K. Loss rate = 5 BPH. CBU staging the pumps up to 6 BPM = 420 psi ICP & 280 psi FCP reciprocating 30'. Lost 15 bbls while
circulating. RIH with 9-5/8", 47#, L-80, TXP-BTC casing from 5,078' to 6,437'. TQ = 24K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing
centralizers as per tally. Wash down from 6,437' to TD at 6,497' at 3 BPM = 450 psi. PU = 325K & SO = 125K. Lost 87 bbls while running casing. Stage the pumps
up to 6 BPM = 450 psi. Establish rotation at 1-5 RPM = 19K ft-lbs TQ reciprocating 30-60'. Circulate and condition the mud for the cement job. SimOps: Cementer
spotted in and RU. Blow down top drive. Rig up cement lines to Volant tool cement swivel. Re-dope Volant cup and clean dies. Continue to circulate and condition
the mud 6 BPM = 350 psi FCP. Hold PJSM with all parties involved. Pump 50 bbls of mud treated with Desco. Shut down the rig pumps. HES flood lines with fresh
water and pump 5 bbls downhole. PT lines to 1,000/4,000 psi - good test. MW = 9.4 ppg in & 9.6 ppg out. Pump 1st stage cement job: Mix and pump 60 bbls of
10.0 ppg tuned spacer with 4# red dye & 5# Pol-E-Flake in 1st 10 bbls at 3.5 BPM = 209 psi. Drop by-pass plug. Mix and pump 232 bbls of 12.0 ppg lead cement
(EconoCem cement, 2.347 ft^3/sk yield, 556 sks total) at 4 BPM = 365 psi. Daily disposal to G&I = 599 bbls. Total disposal to G&I = 6,730 bbls. Daily water hauled
from L-pad lake= 470 bbls. Total water hauled from L-pad lake = 7,530 bbls. Daily fluid loss = 87 bbls. Total fluid loss = 144 bbls.
3/8/2023 Continue pumping 1st stage: Mix and pump 82 bbls of 15.8 ppg tail cement (Premium G cement, 1.152 ft^3/sk yield, 400 sks total) at 3.5 BPM = 500 psi. Drop shut
off plug. HES pump 20 bbls water at 5 BPM = 500 psi. Displace with 279 bbls of 9.4 ppg spud mud from the rig at 6 BPM = 180 psi ICP & 311 psi FCP. Pumped 80
bbls of 9.4 ppg tuned spacer from Halliburton at 4 BPM = 230 psi. Pumped 96.2 bbls 9.4 ppg mud from the rig at 5.5 BPM = 230 psi ICP & 850 psi FCP. Slow rate
to 3 BPM = 730 psi FCP, Bumped the plug at 953 stks, 1.7 bbls early, CIP @ 08:01. Pressure to 1,230 psi, Hold 3 min, bleed off pressure, floats held. Rotate and
reciprocate until 5 bbls into spacer, PU = 420K. Shoe set at 6,494'. Pressure up to 3,900 psi attempting to shift open ESC, bleed off, then pressure to 4,000 psi,
bleed off same. breakout volant, drop free fall opening device, MU volant, let fall 15 minutes, pressure to 2,340 psi shifting cementer tool open. No losses cementing
or displacing. Stage up pump to 6 BPM = 340 psi. Circulate through the ES cementer at 2,296' with heavy sand returns. Calculated 1,500 strokes bottoms up in
gauge hole. Observed trace Pol-E-Flake at 3,490 strokes. Observed spacer at 3,845 strokes, dump returns, at 4,000 strokes observe interface & trace of cement, at
4,600 strokes take returns to pits. Dumped total 76 bbls. Continue to circulate through ES cementer, 5.5 bpm = 150 psi for 4 BU total. Disconnect knife valve from
accumulator. Drain stack and flush with black water 3 times. Re-connect knife valve to the accumulator. Clean rig floor cement valves. Break out the Volant, clean,
dope the cup and MU the Volant. Circulate through the ES cementer at 2,296' at 4 BPM = 100 psi while prepping for the 2nd stage cement job. SimOps: Fuel the
cement equipment. Continue to circulate. Hold PJSM with all parties involved. Warm up cement units. Break out the Volant, dope the cup and MU the Volant. Clean
both pumps suction screens. Blow air through the cement line to the cement unit. Pump 2nd stage cement job: HES flood lines and pump 5 bbls of water downhole.
Mix & pump 60 bbls of 10.0 ppg Tuned Spacer w/ 4# red dye & 5# Pol-E-Flake in 1st 10 bbls at 4 BPM = 175 psi. Mix & pump total 447 bbls 10.7 ppg ArcticCem
lead cement (870 sx at 2.917 ft^3/sk yield) at 5 BPM= 430 psi ICP & 6 BPM = 621 psi FCP. At 290 bbls pumped start seeing spacer returns, dump returns to rock
washer. Mix & pump 56 bbls of 15.8 ppg Premium G tail cement (270 sx at 1.156 ft^3/sk yield) at 3 BPM= 200 psi. Drop the closing plug. Pump 20 bbls of 8.34 ppg
fresh water at 5 BPM = 260 psi. Displace cement with 9.4 ppg spud mud at 6 BPM = 300 psi ICP & 530 psi FCP. Slowed to 3 BPM = 430 psi for last 10 bbls. 500
strokes into the displace got cement to surface. Bumped plug at 1,470 strokes - on time. Pressure up 1,630 psi. The ES cementer shifted closed at 1,410 psi. Hold
for 5 minutes. Bleed off and check for flow - no flow. CIP at 22:19 hours. Cement returned to surface = 98 bbls. Blow down lines. Disconnect the knife valve from the
accumulator. Drain the cement from the stack to the cellar and flush with black water three times. Rig down the Volant CRT and vacuum out mud from the casing.
SimOps: Empty and clean the pits. ND the knife valve. Hoist the diverter stack. Install the casing slips per wellhead rep with 100K on the slips. Remove 4"
conductor valves and install 4" conductor outlet caps. SimOps: ND the diverter line. Empty and clean the pits. RD rock washer super sucker extensions. Welder cut
the 9-5/8" casing. Lay down the cut joint and 20' pup joint. Cut joint length = 17.09'. Clear the rig floor of casing running equipment. ND the surface riser, diverter
stack and diverter tee. Daily disposal to G&I = 1,368 bbls. Total disposal to G&I = 8,098 bbls. Daily water hauled from L-pad lake= 595 bbls. Total water hauled from
L-pad lake = 8,125 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 144 bbls.
3/9/2023 Finish ND diverter stack. Remove knife valve and diverter tee from the cellar. Mobilize the wellhead into the cellar. Wellhead rep install slip lock wellhead and torque
to spec. PT void to 500 for 5 minutes and 3,800 psi for 10 minutes - good test. NU BOP stack. Install kill line and riser. SimOps: check wash pipe and adjust Kelly
hose. Jet flow line clean and blow down cement line. Install test plug and 3-1/2" test joint. Rig up test equipment. Fill stack and flood lines with fresh water. Perform
250/3,000 psi shell test - good. Conduct initial BOPE test to 250/3,000 psi: UPR & LPR (2-7/8 x 5 VBRs) with 3-1/2 & 5 test joints, annular with 3-1/2 & 5 test joints,
accumulator drawdown test and test gas alarms. All tests performed with fresh water against test plug. The states right to witness was waived by AOGCC inspector
Kam St. John via email on 3/7/23 at 18:22 hours. Tests: 1. Annular with 3-1/2 test joint, 3 Demco kill, 5 TIW, choke valves 1, 12, 13 & 14 (passed). 2. UPR with 3-
1/2 test joint, HCR kill, 5 dart valve, choke valves 9 & 11 (passed). 3.Upper IBOP, manual kill, choke valves 5, 8 & 10 (passed). 4. Choke valves 4, 6 & 7 (passed).
Lower IBOP failed low PT. It will be changed out and retested. 5. LPR with 2-1/2 test joint (passed). 6. UPR with 5 test joint, choke valve 2 (passed). 7. HCR choke
(passed). 8. Manual choke (passed). 9. LPR with 5 test joint (passed). 10. Blind rams, choke valve 3 (passed). 11. Manual adjustable choke (passed). 12. Hydraulic
super choke (passed). Accumulator Test: System pressure = 3,075 psi. Pressure after closure = 1,700 psi. 200 psi attained in 45 seconds. Full pressure attained in
183 seconds. Nitrogen Bottles - 6 at 1,917 psi. PJSM. Changeout the upper/lower IBOP assembly and saver sub. Attempt to PT new upper IBOP but would not hold
pressure. Breakout new upper IBOP and install rebuilt upper IBOP. Daily disposal to G&I = 781 bbls. Total disposal to G&I = 8,879 bbls. Daily water hauled from L-
pad lake= 275 bbls. Total water hauled from L-pad lake = 8,400 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 144 bbls.
3/10/2023 Rebuild and bench test upper IBOP in the shop. Mobilize and install replacement upper IBOP. Rig up test equipment and re-test 2nd replacement upper IBOP.
250/3,000 psi, 5 minutes each test - good. Replace IBOP actuator damaged during IBOP replacement. Install ring Feder locking assemblies and safety wire.
Attached link tilt bails. Pull the test plug and install wear bushing (ID = 9"). Blow down choke manifold and lines. Install 5" elevators. PJSM. PU used 8-1/2" Smith
XR+CPS mill tooth bit and 6-3/4" Sperry mud motor set at 1.5 AKO to 32'. TIH 6 stands of HWDP with jars from 32' to 587'. Single in the hole with 30 joints of 5" DP
from 587' to1,539'. TIH with 5" DP from the derrick from 1,539' to 2,205'. Wash and ream down from 2,205' to tag 2,298' at 400 GPM = 620 psi 30 RPM = 1K ft-lbs
TQ. PU = 105K, SO = 78K and ROT = 94K. Drill cement plug, free fall closing device and ES cementer from 2,298' to 2,310' at 400 GPM = 700 psi, 30 RPM = 5K ft-
lbs TQ & WOB = 5-10K. Wash and ream through ES cementer 3 times. Drift through without pumps or rotary. TIH to 2,491' and blow down the top drive. TIH from
2,491' to 6,104' filling DP every 2,000'. Adjust the Kelly hose. TIH from 6,104' to 6,202'. Wash and ream down from 6,202' to hard cement at 6,293' (started seeing
soft cement/strings at 6,268'). Drill cement from 6,293' to 6,359' at 400 GPM = 1,050 psi, 30 RPM = 17K ft-lbs TQ, WOB = 15K. PU = 215K, SO = 90K and ROT =
137K. CBU at 400 GPM = 980 psi, 30 RPM = 17K ft-lbs TQ reciprocating 90'. Blow down the top drive. RU head pin, cement line and testing equipment. Flood the
lines and purge the air. PT the 9-5/8" casing to 2,500 psi for 30 minutes charted - good test. Pumped 4.9 bbls & bled back 4.7 bbls. Blow down and RD testing
equipment. Drill cement, plugs, BA and float equipment from 6,359' to 6,494' at 450 GPM = 1,260 psi, 50 RPM = 17K ft-lbs TQ, WOB =10-15K. All equipment on
depth. Wash and ream through all equipment 3 times. Drill out rat hole from 6,494' to 6,497'. PU = 205K, SO = 95K & ROT = 135K. Drill 20' of new formation from
6,497' to 6,517' at 450 GPM = 1,210 psi, 50 RPM = 17K ft-lbs TQ, WOB = 8-10K. Lay down a single to 6,485'. Circulate and condition the mud for the FIT at 450
GPM = psi, 30 RPM = ft-lbs TQ reciprocating 80'. Good 9.2+ ppg MW in & out. Blow down the top drive.
3/11/2023 Perform flow check - static. RU testing equipment, flood lines and purge the air. Close UPR on 5" DP, pump down DP and the kill line. Perform 12.0 ppg FIT with
9.25 ppg MW at 4,462' TVD with 638 psi applied at surface - good test. Blow down and RD testing equipment. TOOH from 6,485' to 587'. Perform flow check -
static. LD 5" HWDP and jars from 587' to 32'. LD mud motor and bit. Bit graded: 1-1-WT-A-E-2-NO-BHA. Lost 12.4 bbls TOOH. Remove master bushings and
install split bushings. Mobilize BHA components to the rig floor. State loss rate = 2 BPH. PJSM. MU 8-1/2" NOV TK66 bit, NRP, 7600 Geo-Pilot and MWD with GR,
Res, PWD and Dir to 82'. Initialize MWD tools. MU MWD iStar tool suite (recorded only) to 148'. Initialize iStar tools. MU BHA with 2 float subs, 3 NM flex collars,
HWDP and jars to 336'. SimOps: Pressure test MPD to 300/1,500 psi. RIH with 8-1/2" lateral BHA on 5" DP from the pipe shed from 336' to 2,239'. Fill pipe.
Shallow pulse test MWD and break in the Geo Pilot seal at 450 GPM = 1,150 psi, 30 RPM = 4K ft-lbs TQ. PU = 103K, SO = 82K & ROT = 85K. Blow down the top
drive. RIH with 5" DP from the pipe shed from 2,239' to 6,137'. TIH with 5" DP from the derrick from 6,137' to 6,423'.
Lost 17 bbls while RIH with DP. Daylight saving time. PJSM. Drain the riser. Pull the MPD riser and install the MPD RCD. Install the RCD head skirt for the drip
pan. Fill pipe, break circulating and check for leaks - no leaks. PJSM. Pump pit 4 empty. Pump spacer. Displace the well from 9.3 ppg spud mud to 8.8 ppg FloPro
at 7 BPM = 850 psi ICP, 30 RPM = 17K ft-lbs TQ.
3/12/2023 Finish displacement to 8.8 ppg FloPro NT at 7 BPM = 600 psi, 30 RPM = 11K ft-lbs TQ. Shut down and close MPD choke - no pressure build observed. Blow down
lines. Slip and cut 59' drilling of line. SimOps: Clean underneath shakers and pit #4. PU laid down single and RIH from 6,486' to 6,517'. Obtain new slow pumps
rates. Drill 8-1/2" lateral from 6,517' to 6,899' (4,475' TVD), Drilled 382' = 127.3'/hr AROP. 450 GPM = 1,310 psi, 80-120 RPM - 10K ft-lbs TQ, WOB = 7-18K. PU =
150K, SO = 103K & ROT = 122K. MW = 8.9 ppg, vis = 47, ECD = 10.2 ppg, max gas = 99 units. MPD full open while drilling and closed on connections with no
pressure build. Drill 8-1/2" lateral from 6,899' to 7,640' (4,496' TVD), Drilled 741' = 123.5'/hr AROP. 511 GPM = 1,530 psi, 120 RPM - 11K ft-lbs TQ, WOB = 5-
15K. PU = 152K, SO = 102K & ROT = 125K. MW = 8.9 ppg, vis = 38, ECD = 9.96 ppg, max gas = 775 units. MPD full open while drilling and closed on
connections with no pressure build. Pump 30 bbl hi-vis sweep at 7,565', back on time with 300% increase. Drill 8-1/2" lateral from 7,640' to 8,327' (4,503' TVD),
Drilled 687' = 114.5'/hr AROP. 515 GPM = 1,590 psi, 120 RPM - 10K ft-lbs TQ, WOB = 5-15K. PU = 152K, SO = 97K & ROT = 125K. MW = 8.9 ppg, vis = 40,
ECD = 9.92 ppg, max gas = 735 units. MPD full open while drilling and trapping a 9.3 ppg EMW on connections. Drill 8-1/2" lateral from 8,327' to 8,899' (4,480'
TVD), Drilled 572' = 95.3'/hr AROP. 523 GPM = 1,810 psi, 120 RPM - 13K ft-lbs TQ, WOB = 10-16K. PU = 145K, SO = 95K & ROT = 121K. MW = 9.0 ppg, vis =
38, ECD = 10.2 ppg, max gas = 796 units. MPD full open while drilling and trapping a 9.3 ppg EMW on connections. Exited the OA sand at 8,676' and entered the
NF clays. At 8,707' begin turning up targeting 95 deg in preparation for the upcoming fault. Pump 30 bbl hi-vis sweep at 8,613', back on time with 100% increase.
Drilled 13 concretions for a total thickness of 104 (4.4% of the lateral). Last survey at 8,637.52' MD / 4,495.22' TVD, 91.20 deg INC, 293.00 deg AZM. Distance from
WP12 = 15.21', 14.71' low & 3.87' left. Daily disposal to G&I = 1,130 bbls. Total disposal to G&I = 10,262 bbls. Daily water hauled from L-pad lake= 640 bbls. Total
water hauled from L-pad lake = 9,210 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 149 bbls. Daily metal recovered = 12 lbs. Total metal recovered = 16 lbs.
3/13/2023 Drill 8-1/2" lateral from 8,899' to 9,565' (4,474' TVD), Drilled 666' = 111'/hr AROP. 515 GPM = 1,890 psi, 120 RPM - 13K ft-lbs TQ, WOB = 5-15K. PU = 150K, SO
= 98K & ROT = 125K. MW = 9.0 ppg, Vis = 40, ECD = 10.5 ppg, max gas = 532 units. MPD full open while drilling and trapping a 9.3 ppg EMW on connections.
Continued at 95 inclination but did not encounter the sands. Observed fault #1 at 9,075' with 20 DTE throw and leveled off at 90 deg at 9,079'. Turned down to 87
deg at 9,185'. Entered the OA sand at 9,460' (784' out of zone) and leveled off at 90 deg. Drill 8-1/2"" lateral from 9,565' to 9,945' (4,473' TVD), Drilled 380' =
63.3'/hr AROP. 527 GPM = 1,830 psi, 120 RPM - 13K ft-lbs TQ, WOB = 5-15K. PU = 165K, SO = 85K & ROT = 123K. MW = 8.9 ppg, Vis = 36, ECD = 10.23 ppg,
max gas = 733 units. MPD full open while drilling and trapping a 9.3 ppg EMW on connections. Pumped hi-vis sweep at 9,659', back 100 strokes late with 40%
increase. Mud MBT at 5.5 ppb, perform 290 bbl new mud dump & dilute at 9,755'. At 9,735', began seeing 300 psi pressure increase on bottom & squeezing some
fluid away. Suspect balling of BHA. Raise flow to 575 GPM and work pipe - no improvement. Lower flow to 425 with good results. Drill 8-1/2"" lateral from 9,945' to
10,515' (4,468' TVD), Drilled 570' = 95'/hr AROP. 456 GPM = 1,550 psi, 120 RPM - 17K ft-lbs TQ, WOB = 5-15K. PU = 160K, SO = 85K & ROT = 125K. MW =
9.1 ppg, Vis = 39, ECD = 10.26 ppg, max gas = 759 units. MPD full open while drilling and trapping a 9.3 ppg EMW on connections. At 10,420' begin climbing in
structure targeting 98 deg. The objective is to log the top of the NC sand. Drill 8-1/2"" lateral from 10,515' to 11,085' (4,377' TVD), Drilled 570' = 95'/hr AROP. 525
GPM = 2,070 psi, 120 RPM - 14K ft-lbs TQ, WOB = 7-13K. PU = 148K, SO = 77K & ROT = 112K. MW = 9.1 ppg, Vis = 39, ECD = 10.99 ppg, max gas = 809
units. MPD full open while drilling and trapping a 9.3 ppg EMW on connections. Pumped hi-vis sweep at 10,515', back 100 strokes late with 20% increase. Exited
the OA sand at 10,700' entering the NF clays. Logged the top of the NF clays at 10,893'. Drilled 19 concretions for a total thickness of 189' (4.2% of the lateral). Last
survey at 10,921.57' MD / 4,406.12' TVD, 100.02 deg INC, 300.90 deg AZM. Distance from WP12 = 5.69', 5.69' low & 0.2' right. Daily disposal to G&I = 964 bbls.
Total disposal to G&I = 11,226 bbls. Daily water hauled from L-pad lake= 775 bbls. Total water hauled from L-pad lake = 9,985 bbls. Daily fluid loss = 0 bbls. Total
fluid loss = 149 bbls. Daily metal recovered = 9.5 lbs. Total metal recovered = 25.5 lbs.
3/14/2023 Drill 8-1/2" lateral from 11,085' to 11,372' (4,327' TVD). Drilled 287' = 114.8'/hr AROP. 525 GPM = 2,130 psi, 120 RPM = 15K ft-lbs TQ, WOB = 7-15K. PU =
145K, SO = 75K & ROT = 112K. MW = 9.1 ppg, Vis = 40, ECD = 11.3 ppg, max gas = 657 units. Logged the top of the NC sand at 11,220'. Obtain final survey.
BROOH from 11,372' to 10,327' with 525 GPM = 2,090 psi and 120 RPM = 10K ft-lbs TQ. Perform open hole sidetrack with 525 GPM = 2,090 psi, 120 RPM = 11K
ft-lbs TQ. Utilize 100% deflection at 165R and ream down at 75'-90' per hour from 10,327'. Observed 1.5 reduction of inclination from 91.28 deg to 89.70 deg at
10,389' with 3.9' of separation. Reduced deflection to 50% then 89 with inc cruise. Lowest inclination of 88.8 deg at 10,415' with 6.5' of separation. Perform 495 bbl
new mud dilution to lower MBT from 10.5 ppb. Drill 8-1/2" lateral from 10,415' to 11,055' (4,462' TVD). Drilled 640' = 106.7'/hr AROP. 532 GPM = 1,920 psi, 120
RPM = 15K ft-lbs TQ, WOB = 14K. PU = 160K, SO = 80K & ROT = 120K. MW = 9.1 ppg, Vis = 37, ECD = 10.47 ppg, max gas = 924 units. MPD full open while
drilling and trapping a 9.3 ppg EMW on connections. Drill 8-1/2" lateral from 11,055' to 11,717' (4,456' TVD). Drilled 640' = 106.7'/hr AROP. 525 GPM = 2,020 psi,
120 RPM = 13-16K ft-lbs TQ, WOB = 7-15K. PU = 165K, SO = 80K & ROT = 120K. MW = 9.1 ppg, Vis = 40, ECD = 10.55 ppg, max gas = 799 units. MPD full
open while drilling and trapping a 9.3 ppg EMW on connections. Pumped 30 bbl hi-vis sweep at 11,466', back 300 strokes late with 50% increase. Drill 8-1/2"
lateral from 11,717' to 12,419' (4,455' TVD). Drilled 702' = 117'/hr AROP. 523 GPM = 2,060 psi, 120 RPM = 13-14K ft-lbs TQ, WOB = 7-12K. PU = 161K, SO =
75K & ROT = 116K. MW = 9.1 ppg, Vis = 39, ECD = 10.69 ppg, max gas = 786 units. MPD full open while drilling and trapping a 9.3 ppg EMW on connections. At
12,323' start 290 bbl dump and dilute. Drilled 26 concretions for a total thickness of 239 (4.1% of the lateral). Last survey at 12,064.80' MD / 4,453.53' TVD, 89.10
deg INC, 309.19 deg AZM. Distance from WP12 = 11.9', 9.3' low & 7.42' left. Daily disposal to G&I = 1,165 bbls. Total disposal to G&I = 12,391 bbls. Daily water
hauled from L-pad lake= 880 bbls. Total water hauled from L-pad lake = 10,865 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 149 bbls. Daily metal recovered = 6
lbs. Total metal recovered = 31.5 lbs.
3/15/2023 Drill 8-1/2" lateral from 12,419' to 12,988' (4,446' TVD), 569' drilled = 94.8'/hr AROP. 525 GPM = 2040 PSI, 120-150 RPM = 14-15K ft/lbs TQ, WOB = 7-13K. PU =
170K, SO = 70K & ROT = 120K. MW = 9.1 ppg, Vis = 38, ECD = 10.69, max gas = 708 units. Sweep at 12,608', back 400 strokes late with 40% increase. MPD
choke open while drilling and maintaining 9.3 EMW on connections. Drill 8-1/2" lateral from 12,988' to 13,368' (4,446' TVD), drilled 380' = 108.6'/hr AROP. 525
GPM = 2080 PSI, 120 RPM = 14K ft/lbs TQ, WOB = 10-15K. PU = 165K, SO = 65K & ROT = 120K. MW = 9.1 ppg, Vis = 40, ECD = 10.77, max gas = 846 units.
MPD maintaining 9.3 EMW on connections. Obtain final survey. Pump 30 bbls high vis sweep, back 700 strokes late with 60% increase. Circulate 4 bottoms up,
reciprocating pipe and racking back a stand every bottoms up from 13,368' to 13,086'. 525 GPM = 2070 PSI, 120 RPM = 13K TQ. MW = 9.1, Vis = 42, ECD =
10.8, max gas = 574 units. Trip back to BTM on elevators f/ 12988' t/ 13086' and continue circulating, 525 GPM, 2130 psi. Rot and reciprocate 90', 120 RPM, 12k
Tq. PU 160k, SO 80k, Rot 125k. Finish prep mud pits & stage final truck arriving on location. PJSM for displacing. Pump 30 bbls high vis spacer, 25 bbls 8.45 ppg
vis brine, 30 bbls SAPP pill #1. 25 bbls brine, 30 bbls SAPP pill #2, 25 bbls brine, 30 bbls SAPP pill #3 then 30 bbls high vis spacer. Displace with 995 bbls of 8.45
ppg viscosified brine with 3% lubes (1.5% 776 and 1.5% LoTorq). 6 BPM = 900 psi (ICP), 60 RPM = 11K ft-lbs Tq & 7 BPM = 690 psi (FCP), 60 RPM = 12K ft-lbs
Tq. reciprocating 95' alternating stopping points. Shut down the pumps with clean 8.45 ppg viscosified brine to surface. No losses recorded. Blow down TD and
Geo Span, monitor MPD for pressure build 4x with the final building from 14 psi to 73 psi in 5 min, EMW with trip margin= 9.0 ppg. Record new SPRs. In brine
P/U= 170k, SO= 90K, ROT= 127K. SimOps: Clean Pit #3. BROOH from 13368' to 11777' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight
spots. Rack stands in Derrick. 450-475 GPM = 1380-1560 psi, 120 RPM = 10K ft-lbs Tq, MW in 8.7, Max gas = 501 units. PU = 165K, SO =93K & ROT = 125K.
Loss rate = 12-20 BPH. MPD trap 120 psi on connections. Daily disposal to G&I = 2241 bbls. Total disposal to G&I = 14632 bbls. Daily water hauled from L-pad
lake= 1010 bbls. Total water hauled from L-pad lake = 11875 bbls.Daily fluid loss = 0 bbls. Total fluid loss = 149 bbls. Daily metal recovered = 5 lbs. Total metal
recovered = 36.5 lbs.
3/16/2023 BROOH from 11,777' to 10,232' pulling 3-5 minutes/stand slowing as need to clean up tight spots. Rack stands in the derrick. 450 GPM = 1300 PSI, 120 RPM = 16-
17K ft/lbs TQ, MW = 8.7 ppg, ECD = 9.83, max gas = 104 units. MPD maintain 9.3 ppg EMW on connections with 145 PSI. 5 BPH loss rate. Perform check trip
from 10,232' to 10,420'.across openhole sidetrack point at 10,327'. ABI at 10,404' = 88.73 deg inclination verifying correct wellbore. BROOH from 10,420' to
10,232'. BROOH from 10,232' to 6,804' at 30'/min. 450 GPM = 1240 PSI, 120 RPM = 8K ft/lbs TQ, MW = 8.9 ppg, ECD = 9.76, max gas = 182 units. Higher loss
rate attributed to MW increasing from 8.7 to 8.9 ppg while reaming out of zone interval in the NF clay from 9,460' to 8,676'. MPD maintain 9.3 ppg EMW on
connections with 145 PSI. 89.2 bbls total lost on trip out. Pump BHA into the 9-5/8" casing shoe from 6,804' to 6,423' with 410 GPM = 1020 GPM. BHA pulled good
into the casing shoe. Pump 30 bbl high vis sweep and circulate the casing clean with 550 GPM = 1500 PSI, 80 RPM = 6K ft/lbs TQ. Sweep back on time with 75%
increase. Rack stand back to 6,423' then finished 2nd bottoms up. 8.8 ppg MW in/out. Blow down top drive & geo-span. Monitor well with MPD choke closed. 1st 5
minutes built 31 PSI. Bleed off and 2nd 5 minutes built 23 PSI. Bleed off and 3rd 5 minutes built 17 PSI. Calculated 8.9 ppg EMW with 8.8 MW and 17 PSI. Weight
up the surface active volume to 9.1 ppg. Circulate 9.1 ppg while weighting up the returns on the fly to 9.1 ppg at 220 GPM = 450 psi, 30 RPM = 4-6K ft-lb Tq
reciprocating 90'. Good 9.1 ppg in/out. Blow Down TopDrive. Monitor pressure with MPD. 4 psi build in 5 min. Bleed off and observe no psi build next 5 min. Open
the RCD head bleeder, drain the line and well is static in 25 min. Continue observe the well for flow while PJSM and prep to pull RCD and well remain static.
Remove MPD RCD & install trip nipple. Pump dry job and blow down the top drive & MPD lines. POOH laying down 5" DP singles to shed from 6,498' to HWDP at
336'. 18.75 bbls total loss, 2.9 BPH avg. Monitor Well - Slight losses. Daily disposal to G&I = 372 bbls. Total disposal to G&I = 15004 bbls. Daily water hauled from
L-pad lake= 135 bbls. Total water hauled from L-pad lake = 12010 bbls. Daily fluid loss = 85 bbls. Total fluid loss = 234 bbls. Daily metal recovered = 2.5 lbs. Total
metal recovered = 39 lbs.
3/17/2023 L/D HWDP and jars, 3 non-mag drill collar and float subs to 148'. Read MWD iStar tools. L/D iStar tools from 148' to 82'. Read MWD tools. L/D MWD tools, Geo-
Pilot, NRP and bit. 8-1/2" PDC grade: 1-1-CT-A-X-I-NO-TD. 5 bbls losses during BHA, 1.7 BPH. Clear rig floor. Remove split bushings and install master bushings.
Mobilize casing equipment to the rig floor. Rig up 4-1/2" tongs, elevators and slips. M/U 4-1/2" H625 XO on FOSV. Hold PJSM with all parties involved. 1.8 BPH
static loss rate. M/U 4-1/2" round nose float show and crossover blank joint to 42'. Run 4-1/2", 13.5#, L-80, Hydril 625 liner as per tally to 7037' - alternate one 20'
slotted joint and two 40' solid joints. Torque to 9,600 ft/lbs with Doyon double stack tongs. Install a free-floating stop ring and 7-1/2" O.D. centralizer on each joint.
Lost 21.7 bbls while running liner. Ave loss rate = 2.1 BPH. Verify pipe count in pipe shed. Swap elevators. M/U Baker SLZXP LTP, R/D double stack tongs & R/U
Drift for DP from Derrick. Remove crossover from FOSV. TIH one stand to 7169'. Pump 5 bbls through LTP to ensure clear flow path, 2 BPM = 100 psi. PU = 105K,
SO = 86K, ROT = 90K, 10 RPM= 4K TQ, 20 RPM= 4K TQ. Blow down top drive. TIH with 4-1/2", 13.5#, L-80, H625 slotted liner on 5" DP from 7169' to 12974'.
Drift Stands from Derrick. PU = 160K & SO = 105K. 1.5 BPH Losses. Daily disposal to G&I = 35 bbls. Total disposal to G&I = 15039 bbls. Daily water hauled from L-
pad lake= 90 bbls. Total water hauled from L-pad lake = 12100 bbls. Daily fluid loss = 46 bbls. Total fluid loss = 280 bbls. Daily metal recovered = 1 lbs. Total metal
recovered = 40 lbs.
3/18/2023 TIH with 4-1/2", 13.5#, L-80, H625 slotted liner on 5" drill pipe from 12,974' and tag bottom on depth at 13,368' with 10K. Drift stands from the derrick. PU = 160K &
SO =105K. 11.2 bbls total losses running liner on drill pipe / 1.5 BPH avg. Rack back stand. M/U 5" pup joints (9.64' and 4.65'), FOSV, side entry sub and 19.69'
pup joint. Pump 10 bbls at 4 BPM = 570 PSI to verify clear flow path. Drop 1.125" phenolic setting ball. Pump down with 27 bbl high vis sweep, 4 BPM = 600 PSI.
Slow to 2 BPM = 290 PSI at 670 strokes. Ball on seat at 831 strokes. Pressure up to 2300 PSI and hold for 2 min, observed tool set at 2000 PSI. Set 30K down 2'
higher than previous - verified set. Pressure up to 3000 PSI and hold for 2 min, observed tool neutralize at 2700 PSI. P/U & observer travel at 148K to confirm
release. Pressure up and shear out ITTS at 4210 PSI. Flood kill and choke lines. Close upper 2-7/8" x 5" VBR on 5" pipe. PT the IA/LTP to 1500 PSI for 10 minutes
charted (good test). RD circulating equipment and pup joints. Blow down lines. Top of liner at 6,305.05'. L/D pump out of liner tie-back and L/D drill pipe joint to
6,282' at 3 BPM = 300 PSI. Circulate out high vis sweep at 10 BPM = 1170 PSI while reciprocating pipe from 6,281' to 6,286'. Sweep back on time with no increase.
Circulate a total of 1.5 bottoms up. Slip and cut 66' of drilling line and calibrate block height. Service blocks and top drive. 1 BPH losses. Pump dry job. POOH
laying down 5" drill pipe from 6,282' to 5,267'. TIH 11 stands of excess drill pipe from 5,267' to 6,218'. Continue to POOH, lay down drill pipe from 6,218' and L/D
LRT. Provide 24 hour notice to AOGCC for upcoming MIT/IA. Loss 16.8 bbls. Clean and clear the rig floor, mobilize 3 1/2'' tubing tools and equipment to the rig
floor. Pull the wear bushing, R/U 3 1/2'' power tongs and handling equipment. Centrilift R/U spooler on rig floor, ready XO on FOSV. Monitor well, 1.75 bph static
loss rate. PJSM, P/U bullet seal assembly and RIH on 3-1/2, 9.3#, L-80, EUE 8rd tubing as per tally to 399'. Torque to optimum @ 3130 ft-lbs with Doyon double
stack tongs. Loss rate = 2 bph. M/U X nipple assembly, 1 joint, gauge carrier assembly to 480'. Install gauge and M/U Tec wire to gauge. MU 1 joint and sliding
sleeve assembly to 528'. Orient Tec wire across blanked section of sleeve. RIH with injection completion on 3-1/2" tubing spooling tec wire, installing cannon
clamps as per tally and testing the Tec wire every 1,000' from 528' to 2218'. Torque to optimum @ 3130 ft-lbs. PU = 52K & SO = 55K. Loss rate = 1.75 bph. Daily
disposal to G&I = 404 bbls. Total disposal to G&I = 15443 bbls. Daily water hauled from L-pad lake= 65 bbls. Total water hauled from L-pad lake = 12165 bbls.
Daily fluid loss = 30 bbls. Total fluid loss = 310 bbls. Daily metal recovered = 1 lbs. Total metal recovered = 41 lbs.
Activity Date Ops Summary
3/19/2023 Run 3-1/2", 9.3#, L-80, EUE 8rd tubing as per tally from 2,218' to 6,328.57' and no-go with 10K (6,318.99' locator sub, 13.94' deep to liner tally). Install Cannon
clamps as required to secure TEC wire. Test continuity every 1,000'. Torque to 3130 ft/lbs optimum. Observe seal drag when entering the liner tie-back. 15.9 bbls
lost on liner run, 1.6 BPH avg. Space out: L/D joints #200 to 197. M/U four pup joints (10.28', 8.18', 6.19' and 3.10') and joint #197 to 6,288'.
M/U 5" landing joint and XO subs, tubing hanger and perform TEC wire penetration. 2069.6 PSI & 85.1 deg F on tubing and 18.8 volts. 1 BPH static losses. Drain
BOP stack. Land tubing string on hanger, observed 4-6K drag with seals entering the tie-back. R/U equipment to reverse circulate and flood lines. Unseat hanger,
close annular and apply 400 PSI through the kill line to the IA. Strip up through the annular 9' but did not see the pressure dump. Picked up high enough to pull
seals out of the liner tie-back. Bleed pressure off, open annular and land hanger. Observed drag as seals entered the tie-back on depth. Verify all surface equipment
lined up correctly. Unseat hanger. Pump through kill line again and confirm open flow path. Line up and pump down the tubing to verify clear flow path. Observed
pressure begin to build at 33 strokes. Pressure increased from 320 at 1 BPM to 470 while injecting 5 bbls. Shut down pump and observed immediate 150 PSI
pressure drop then slowly dropping. Bleed off pressure and blow down the top drive. Close annular & pressure up to 500 PSI. Strip up 8' through annular with no
pressure drop. Line up to pump down tubing, pick seals up another 5' and circulate freely with 1 BPM, 230 PSI. Slack off, observe seal drag with pressure increase
as seal entered liner top. All depths corresponded with original depths. Blow down the top drive. Set hanger 1' off seat. Close annular and pressure up to 400 PSI on
IA. Strip up 9' and observed pressure bleed off. PJSM for displacement. Reverse circulate 256.4 bbls of 8.5 ppg CIB at 5 BPM = 350 psi ICP, 490 psi FCP followed
by 140.7 bbls diesel at 5 BPM = 490 psi ICP, 520 psi FCP- freeze protecting the 3 1/2'' x 9 5/8'' annulus to 2,295',Strip through annular to 2' off landing, closing
circulating ports, Drain stack, open annular & rinse stack. Stack quit draining while blowing down Kill line. Fill stack via IA w/ corrosion inhibited brine. Attempt to
drain stack, stopped draining after several feet down. Hook Vac truck up to IA and drain stack until Hanger visible. Wash hanger with water hose. Add H2O through
Kill line & stack stopped draining again,Empty stack from top via Vac truck. Flush hanger top and R/D circulating lines on IA. Open IA valve and visually inspect, no
abnormalities observed. Did find sand and small rubber in vac hose when disconnected. Flush hanger with water hose and clean with Vac truck from top. Land
tubing on hanger at 6,326.57' with 30k on hanger @ 2.0 off NO-GO. WH Rep RILDS. R/D and B/D circulating lines from landing joint. R/U testing equipment. Fill &
PT lines. Perform MIT IA to 3,500 psi for 30 minutes charted - good test. 6.6 bbls pumped, 6.6 bbls bled back. R/D circulating and test equipment. Pull landing joint.
WHR install the BPV with dry rod. B/D & R/D injection line and kill line. Breakout XOs and L/D the landing joint. Suck out stack with Vac truck. PJSM. Pull the MPD
riser. Remove the drip pan, turn buckles. N/D the BOP stack. N/D the spacer spool. Set BOP on pedestal and secure for transport. Install the CTS plug in the BPV.
SimOps: Clean the Rockwasher & mud pits. Daily disposal to G&I = 471 bbls. Total disposal to G&I = 15914 bbls. Daily water hauled from L-pad lake= 120 bbls.
Total water hauled from L-pad lake = 12285 bbls. Daily fluid loss = 17.4 bbls. Total fluid loss = 297.4 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 41
lbs.
3/20/2023 Mobilize wellhead equipment into the cellar. N/U adapter flange & tree. Pressure test hanger void to 500 PSI for 5 minutes and 5000 PSI for 10 minutes - good test.
Obtain final Centrilift readings: 1972.58 PSI, 82 deg F and 20.3 volts. Fill stack with diesel. Pressure test tree to 250 PSI low / 5000 PSI high - good test. On gen
power at 09:45,Remove BPV/CTS plug. Rig up circulating equipment and pressure test lines to 1500 PSI. Bullhead 24.6 bbls of diesel freeze protection down the
tubing at 1.5 BPM = 250 PSI ICP / 770 PSI FCP. Blow down lines and rig down circulating equipment. Secure well and obtain final readings: tubing 500 PSI and IA
0 PSI. Released rig at 13:00.
50-029-23745-00-00API #:
Well Name:
Field:
County/State:
MP B-40
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
Perform MIT IA to 3,500 psi for 30 minutes charted - good test. 6.6 bbls pumped, 6.6 bbls bled back.
ACTIVITYDATE SUMMARY
3/21/2023
*** WELL SHUT-IN ON ARRIVAL.***
SHIFT VIKING-SD AT 5,804' MD w/ 3-1/2" 42BO (positive pressure change, appears
open).
SET 3" JETPUMP (ratio: 12B), IN VIKING-SD AT 5,804' MD.
*** WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED.***
4/23/2023
Well Support Techs R/D the temporary production lines and power fluid lines.
Installed new injection line and pressure tested line to 3650 psi. Well house and
foundation was already set.
4/23/2023
***WELL S/I ON ARRIVAL***
RAN 3'' GR (steel), SEE FLUID @ 2400' SLM, REALLY THICK FLUID (T-BIRD going
to displace tubing)
T-BIRD PUMPED 60 bbls PRODUCED WATER
PULL 3'' JET PUMP @ 5789' SLM / 5804' MD
CONTINUE WSR ON 4-24-23
***WELL S/I ON DEPARTURE***
4/23/2023
T/I= 300/0 Assist Slickline (Wellwork) Pumped 4 bbls of 60/40 methanol followed by
60 bbls of 90* produced water and 2 bbls of 60/40 down the tubing. Slickline in control
of well upon departure.
4/24/2023
***WELL S/I OM ARRIVAL***
2' X 1-7/8'' STEM, 3-1/2 42-BO SHIFTING TOOL, TAG THICK FLUID @ 2100' SLM,
TOOLS FALLING @ 30 fpm, (lrs pump 60 bbls diesel)
CLOSE SLEEVE @ 5789' SLM / 5804' MD
LRS PRESSURED UP ON IA TO 1500# HELD FOR 10 mins, 11# BLEED OFF (good
test)
***WELL S/I ON DEPARTURE***
4/24/2023
T/I=155/0 Load IA (Post RWO) Flushed TBG with 60 bbls of diesel. Pumped 160 bbls
of 120* Inhibited 1% KCL followed by 196 bbls diesel down IA to load. Slickline slid
sleeve shut. Pressured up IA to 1521 psi with 2.3 bbls diesel. IA lost 11 psi in 10 min.
Bled IA to 300 psi and recovered 2 bbls. Final Whp's= 200/300
4/26/2023
T/I=0/0 MIT-IA Passed to 2121 psi. (Post RWO) Pressured up IA to 2226 psi with 4.6
bbls diesel. 1st 15 min IA lost 77 psi. 2nd 15 min IA lost 28 psi for a total loss of 105
psi in 30 min. Bled IA to 200 psi and recovered 3.4 bbls. Final Whps=0/200
Daily Report of Well Operations
PBU MPB-40
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
1
1
1
1
98
1
1
1
56
1
X Yes No X Yes No
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?X Yes 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? Yes X 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
678.77 90.74355.86
SE
C
O
N
D
S
T
A
G
E
Rig
22:19
Cement to surface
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ 6494 FC @ Top of Liner6,410.00
Floats Held
396.09 817
98 719
Spud Mud
CASING RECORD
County State Alaska Supv.D. Yessak / I. Toomey / C. Yearout
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.MP B-40 Date Run 7-Mar-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
TXP Innovex 1.59 6,494.00 6,492.41
24.46 56.81 32.359 5/8 47.0 L-80 TXP
Csg Wt. On Hook:325,000 Type Float Collar:Innovex No. Hrs to Run:17.5
9.4 6
1630
10
10.7 447 5
100
730
Bump Plug?
FI
R
S
T
S
T
A
G
E
10Tuned Spacer 60
15.8
530
3
9.4 6 168.43/168.43
445.6/447.3
1230
0.1
Rig
15.8 82
Bump press
trace of cement at surface
Bump Plug?
8:01 3/8/2023 2,298
2296
6,494.006,497.00
CEMENTING REPORT
Csg Wt. On Slips:100,000
Spud Mud
Tuned Spacer
870 2.92
Stage Collar @
60
Bump press
100
98
ES Cementer Closure OK
56
12 232
RKB to CHF
Type of Shoe:Innovex Casing Crew:Doyon
No. Jts. Delivered No. Jts. Run
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
ArcticCem Cement
Type
83 total 9-5/8" x 12"1/4" bowspring centralizers ran. Two in shoe joint w/ stop rings 10' from each end. One floating on
joint #2. One each with stop rings mid-joint on joint #3 & 4. One each on joints 5 to 25, every other joint to #47 then
every third joint to #95. One each on joints #98 to #107. One each with stop rings on pup joints above and below ES
cementer. One each on every third joint #110 to #155.
Casing 9 5/8 40.0 L-80 TXP Tenaris 80.97 6,492.41 6,411.44
Float Collar 10 3/4 TXP Innovex 1.30 6,411.44 6,410.14
Casing 9 5/8 40.0 L-80 TXP Tenaris 39.43 6,410.14 6,370.71
Baffle Adapter 10 3/4 TXP Halliburton 1.39 6,370.71 6,369.32
Casing 9 5/8 40.0 L-80 TXP Tenaris 4,052.92 6,369.32 2,316.40
Casing Pup Joint 9 5/8 40.0 L-80 TXP 17.54 2,316.40 2,298.86
ES Cementer 10 3/4 TXP Halliburton 2.81 2,298.86 2,296.05
Casing Pup Joint 9 5/8 40.0 L-80 TXP 17.57 2,296.05 2,278.48
Casing 9 5/8 47.0 L-80 TXP Tenaris 2,221.67 2,278.48 56.81
EconoCem Cement 556 2.35
Premium G Cement 400 1.15
4
Premium G Cement 270 1.16
3/9/2023 38
Spud Mud
X
2,298
Cement to surface
100
100
98
38
trace of cement at surface
David Douglas Hilcorp Alaska, 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:
Date: 04/11/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: MPU B-40
PTD: 223-009
API: 50-029-23745-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (02/26/2023 to 03/15/2023)
• ROP, AGR, DGR, ABG, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
• Final Definitive Directional Survey
• Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
MPU 40 FINAL LWD Subfolders:
MPU B-40 FINAL Geosteering Subfolders:
David Douglas Hilcorp Alaska, 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:
Please include current contact information if different from above.
WELL: MPU B-40PB1
PTD: 223-009
API: 50-029-23745-70-00
FINAL LWD FORMATION EVALUATION LOGS (03/01/2023 to 03/06/2023)
• ROP, AGR, EWR-M5, (2” & 5” MD/TVD Color Logs)
• Final Definitive Directional Survey
MPU B-40PB1 LWD Subfolders:
WELL: MPU B-40PB2
PTD: 223-009
API: 50-029-23745-71-00
FINAL LWD FORMATION EVALUATION LOGS (02/26/2023 to 03/14/2023)
• ROP, AGR, DGR, ABG, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
• Final Definitive Directional Survey
MPU B-40PB2 LWD Subfolders:
Please include current contact information if different from above.
1
Regg, James B (OGC)
From:Brooks, Phoebe L (OGC)
Sent:Thursday, March 23, 2023 2:40 PM
To:Doug Yessak - (C)
Cc:Regg, James B (OGC)
Subject:RE: Doyon 14 diverter 3-2-2023
Attachments:Diverter Doyon 14 03-02-23 Revised.xlsx
Doug,
Attached is a revised report changing the AOGCC Rep to Waived per the remarks. Please update your copy.
Thank you,
Phoebe
Phoebe Brooks
Research Analyst
Alaska Oil and Gas Conservation Commission
Phone: 907‐793‐1242
CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas
Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential
and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you
are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the
mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov.
From: Doug Yessak ‐ (C) <dyessak@hilcorp.com>
Sent: Thursday, March 2, 2023 4:23 PM
To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>;
Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>
Cc: Nathan Sperry <Nathan.Sperry@hilcorp.com>; Ian Toomey ‐ (C) <itoomey@hilcorp.com>; Cody Dinger
<cdinger@hilcorp.com>; Alaska NS ‐ Doyon 14 ‐ DSMs <AlaskaNS‐Doyon14‐DSMs@hilcorp.com>
Subject: Doyon 14 diverter 3‐2‐2023
Doug Yessak
Hilcorp DSM
Doyon 14
907‐670‐3090
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
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.
Milne Point Unit B-40PTD 2230090
Date: 3/2/2023 Development:X Exploratory:
Drlg Contractor:Rig No.14 AOGCC Rep:
Operator:Oper. Rep:
Field/Unit/Well No.:Rig Rep:
PTD No.:2230090 Rig Phone:
Rig Email:
MISCELLANEOUS:DIVERTER SYSTEM:
Location Gen.:P Well Sign:P Designed to Avoid Freeze-up?P
Housekeeping:P Drlg. Rig.P Remote Operated Diverter?P
Warning Sign P Misc:NA No Threaded Connections?P
24 hr Notice:P Vent line Below Diverter?P
ACCUMULATOR SYSTEM:Diverter Size:21 1/4 in.
Systems Pressure:2950 psig P Hole Size:12 1/4 in.
Pressure After Closure:1800 psig P Vent Line(s) Size:16 in.P
200 psi Recharge Time:34 Seconds P Vent Line(s) Length:189 ft.P
Full Recharge Time:158 Seconds P Closest Ignition Source:86 ft.P
Nitrogen Bottles (Number of):6 Outlet from Rig Substructure:181 ft.P
Avg. Pressure: 1983 psig P
Accumulator Misc:NA
Vent Line(s) Anchored:P
MUD SYSTEM:Visual Alarm Turns Targeted / Long Radius:P
Trip Tank:P P Divert Valve(s) Full Opening:P
Mud Pits:P P Valve(s) Auto & Simultaneous:
Flow Monitor:P P Annular Closed Time: 21 sec P
Mud System Misc:0 NA Knife Valve Open Time: 17 sec P
Diverter Misc:NA
GAS DETECTORS:Visual Alarm
Methane:P P
Hydrogen Sulfide:P P
Gas Detectors Misc:0 NA
Total Test Time:1 hrs Non-Compliance Items:0
Remarks:
Submit to:
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
Diverter Systems Inspection Report
GENERAL INFORMATION
WaivedDoyon
*All Diverter reports are due to the agency within 5 days of testing*
dyessak@hilcorp.com
TEST DATA
J. Hansen / J Charlie
phoebe.brooks@alaska.gov
Hilcorp
Test preformed with 5" drill pipe, test H2S and LEL gas alarms ,AOGCC Rep Austin McLeod waived witness to test. Notification given 18:48 hrs
on 2/28/23.
0
D Yessak/ I. Toomey
0
907-670-3096
TEST DETAILS
jim.regg@alaska.gov
AOGCC.Inspectors@alaska.gov
Milne Point Unit B-40
Form 10-425 (Revised 05/2021)2023-0302_Diverter_Doyon14_MPU_B-40
Hilcorp Alaska LLC======jbr
J. Regg
1
Regg, James B (OGC)
From:Alaska NS - Doyon 14 - DSMs <AlaskaNS-Doyon14-DSMs@hilcorp.com>
Sent:Tuesday, March 21, 2023 6:02 PM
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC)
Cc:Nathan Sperry
Subject:MPU B-40 MIT IA 3-20-2023
Attachments:MIT IA MPU B-40 3-20-23.xlsx
Attached is the pre‐injection MIT IA report performed after rig installation for MPU B‐40.
Regards,
C.A. Demoski
Hilcorp Alaska | Milne Point | Doyon Rig 14 DSM
907‐670‐3090 Office
907‐670‐3092 Rig Floor
907‐378‐7530 Personal Cell
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.
Milne Point Unit B-40PTD 2230090
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 223-009 Type Inj N Tubing 0 0 0 0 Type Test P
Packer TVD 4443 BBL Pump 6.6 IA 0 3670 3625 3620 Interval O
Test psi 3500 BBL Return 6.6 OA 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
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:
Notes:
Hilcorp Alaska LLC
Notes:
Milne Point , MPU, B Pad
C.A. Demoski
03/20/23
Notes:Pre-Injection MIT-IA on rig. Witness waived by Sean T Sullivan on 3/18/23 at 18:25. Monobore, No OA. Test to 3500 psi as per PTD.
Notes:
Notes:
Notes:
B-40
Form 10-426 (Revised 01/2017)2023-0320_MIT_MPU_B-40
J. Regg; 5/5/2023
1
Regg, James B (OGC)
From:Alaska NS - Doyon 14 - DSMs <AlaskaNS-Doyon14-DSMs@hilcorp.com>
Sent:Friday, March 10, 2023 2:21 PM
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Cc:Doyon Rig14
Subject:MPU B-40 Initial BOP test report
Attachments:MPU B-40 Doyon 14 BOP Test 3-10-23.xlsx
Good afternoon,
Attached is the BOP test report for Hilcorp Alaska LLC well MPU B‐40 on rig Doyon 14 completed on 10 March 2023.
Regards,
C.A. Demoski
Hilcorp Alaska LLC | Milne Point | Doyon 14 DSM
907‐670‐3090 Office
907‐670‐3092 Rig Floor
907‐378‐7530 Cell
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.
Milne Point Unit B-40PTD 2230090
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner:Rig No.:14 DATE:3/10/23
Rig Rep.:Rig Email:
Operator:
Operator Rep.:Op. Rep Email:
Well Name:PTD #2230090 Sundry #
Operation:Drilling:X Workover:Explor.:
Test:Initial:X Weekly:Bi-Weekly:Other:
Rams:250-3000 Annular:250-3000 Valves:250-3000 MASP:1514
MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1 FP
Permit On Location P Hazard Sec.P Lower Kelly 1 FP
Standing Order Posted P Misc.NA Ball Type 1 P
Test Fluid Water Inside BOP 1 P
FSV Misc 0 NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0 NA Trip Tank P P
Annular Preventer 1 13-5/8"P Pit Level Indicators P P
#1 Rams 1 2-7/8 X 5"P Flow Indicator P P
#2 Rams 1 Blind P Meth Gas Detector P P
#3 Rams 1 2-7/8 X 5"P H2S Gas Detector P P
#4 Rams 0 NA MS Misc 0 NA
#5 Rams 0 NA
#6 Rams 0 NA ACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8x5000 P Time/Pressure Test Result
HCR Valves 2 3-1/8x5000 P System Pressure (psi)3075 P
Kill Line Valves 2 3-1/8x5000 P Pressure After Closure (psi)1700 P
Check Valve 0 NA 200 psi Attained (sec)45 P
BOP Misc 0 NA Full Pressure Attained (sec)183 P
Blind Switch Covers:All stations Yes
CHOKE MANIFOLD:Bottle Precharge:1000 P
Quantity Test Result Nitgn. Bottles # & psi (Avg.):1917 P
No. Valves 14 P ACC Misc 0 NA
Manual Chokes 1 P
Hydraulic Chokes 1 P Control System Response Time:Time (sec)Test Result
CH Misc 0 NA Annular Preventer 16 P
#1 Rams 7 P
Coiled Tubing Only:#2 Rams 7 P
Inside Reel valves 0 NA #3 Rams 7 P
#4 Rams NA
Test Results #5 Rams NA
#6 Rams NA
Number of Failures:2 Test Time:7.5 HCR Choke 2 P
Repair or replacement of equipment will be made within days. HCR Kill 2 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 3-7-23 / 18:18
Waived By
Test Start Date/Time:3/9/2023 16:30
(date)(time)Witness
Test Finish Date/Time:3/10/2023 12:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Kam StJohn
Doyon
All test performed 250-3000psi for rams and choke valves with 3-1/2" & 5" test jt., Annular 250-3000 with 3-1/2" test jt. Test gas
alarms and PVT's. Fail pass on lower and upper IBOP, Changed out-repaired & tested good. Test time does not include repair
time.
Hansen / Charlie
Hilcorp
Demoski / Toomey
MPU B-40
Test Pressure (psi):
rig14@doyondrilling.com
skaNS-Doyon14-DSMs@hilcorp.c
Form 10-424 (Revised 08/2022)2023-0310_BOP_Doyon14_MPU_B-40
Alaska LLC jbr
J. Regg; 6/13/2023
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 North Slope, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU B-40
Hilcorp North Slope, LLC
Permit to Drill Number: 223-009
Surface Location: 608' FSL, 754' FWL, Sec. 18, T13N, R11E, UM, AK
Bottomhole Location: 2455' FSL, 1823' FWL, Sec. 14, T13N, R10E, 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 February, 2023. 17
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.02.17 10:09:00 -09'00'
1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address: 6. Proposed Depth: 12. Field/Pool(s):
MD: 13369' TVD: 4457'
4a. Location of Well (Governmental Section): 7. Property Designation:
Surface:
Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date:
Total Depth: 9. Acres in Property: 14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 57.0' 15. Distance to Nearest Well Open
Surface: x-571827 y- 6023730 Zone- 4 23.3' to Same Pool: 510'
16. Deviated wells: Kickoff depth: feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Driven 20" 129.5# X-52 80' Surface Surface 106' 106'
47# L-80 TXP 2500' Surface Surface 2500' 2085'
40# L-80 TXP 4200' 2500' 2085' 6700' 4463'
8-1/2" 4-1/2" 13.5# L-80 Hyd 625 6819' 6550' 4453' 13369' 4457'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
TVD
Hydraulic Fracture planned? Yes No
20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name: Nathan Sperry
Monty Myers Contact Email:nathan.sperry@hilcorp.com
Drilling Manager Contact Phone:907-777-8450
Date:
Permit to Drill API Number: Permit Approval
Number:Date:
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 Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
2/28/2023
8278'
12-1/4" 9-5/8"
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
Surface
Perforation Depth TVD (ft):
GL / BF Elevation above MSL (ft):
Perforation Depth MD (ft):
Uncemented Slotted Liner
Effect. Depth MD (ft): Effect. Depth TVD (ft):
Authorized Title:
Authorized Signature:
Production
Liner
Intermediate
Authorized Name:
Conductor/Structural
LengthCasing Cement Volume MDSize
Plugs (measured):
(including stage data)
Stg 1 L - 554 sx / T - 395 sx
5104
18. Casing Program: Top - Setting Depth - BottomSpecifications
Total Depth MD (ft): Total Depth TVD (ft):
2224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stg 2 L - 673 sx / T - 268 sx
1016' FNL, 2276' FWL, Sec. 24, T13N, R10E, UM, AK
2455' FSL, 1823' FWL, Sec. 14, T13N, R10E, UM, AK
81-054
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp Alaska, LLC
608' FSL, 754' FWL, Sec. 18, T13N, R11E, UM, AK ADL 047438 & 047437
MPU B-40
Milne Point Field
Schrader Bluff Oil Pool
Cement Quantity, c.f. or sacks
Commission Use Only
See cover letter for other
requirements.
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
2.1.2023
By Meredith Guhl at 9:05 am, Feb 02, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.02.01 16:58:49 -09'00'
Monty M
Myers
* BOPE test to 3000 psi. Annular to 2500 psi.
* Casing test of 9-5/8" surface casing and FIT digital data to AOGCC
immediately upon performing the FIT.
* MIT-IA to 3000 psi. 24 hour notic to AOGCC for opportunity to witness.
* Approved to pre-produce for 30 days with reverse circulating jet pump. 24/7 manned monitoring on MPU B-pad if
no surface safety valve while on IA power fluid injection when on 30 day pre-production.
223-009
X
X
X
DSR-2/2/23
350
MGR15FEB2023
94
X
X
1514 DLB
50-029-23745-00-00
1960
X
DLB
DLB 02/07/2023
X
DLB
* Offset well B-25 shut in plans to AOGCC after gyro
survey completed and before drilling 8.5" OH
GCW 02/17/23JLC 2/17/2023
2/17/2023Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.02.17 10:09:43 -09'00'
2/17/2023
22224484
RBDMS JSB 021723
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PTD API WELL STATUS
Top of SB
OA (MD)
Top of SB
OA
(TVDss)
Top of
Cement
(MD)
Top of
Cement
(TVD)
Schrader OA
status Zonal Isolation
189-016 50-029-21915-00-00 MPU B-23 Shut In Producer- Kuparuk 5880 -4424 Surface Surface Closed
The 9-5/8" surface casing was set at 6,254' RKB / 4,678' TVD. The 9-5/8" casing was
cemented with 1654 sacks (580 bbls) 12.3 ppg cement followed by 272 sacks (60
bbls) 15.8 ppg class G cement. Returns were lost after pumping 31 barrels of the
displacement. Cement top estimated at 4400' MD. A top job was performed with 100
sacks 15.6 ppg Permafrost C cement. After 50 sacks of cement pumped, 100%
cement returns were observed.
197-233 50-029-22841-00-00 MPU B-25 Active Injector- Kuparuk 7200 -4413 Surface Surface Closed
The 9-5/8" surface casing was set at 7,420' MD / 4,574' TVD. The 9-5/8" casing was
cemented in two stages with 1992 sacks Permafrost E cement and 335 sacks class G.
218-158 50-029-23616-00-00 MPU E-37 Active Producer- Schrader OA 7842 -4346 Surface Surface Open
The 9-5/8" surface casing is set at 8,056' MD / 4,403' TVD. The 9-5/8" casing was
cemented in two stages with the first stage consisting of 763 sacks Type I/II 12 ppg
lead cement and 398 sacks G tail cement. Plug bumped, floats held, and full returns
throughout the first stage. The second stage pumped through the stage tool
consisted of 400 sacks 11.1 ppg lead cement and 289 sacks 15.8 ppg G tail cement.
Positive indication of stage tool closure observed. 240 barrels of cement returned to
surface.
185-034 50-029-21297-00-00 MPU B-09 Shut In Producer- Kuparuk 5782 -4383 Surface Surface Closed
The 9-5/8" surface casing is set at 6,210' MD / 4,721' TVD. The 9-5/8" casing was
cemented with 806 barrels 12 ppg ArcticSet, 56 barrels 15.8 ppg Class G cement.
Cement was displaced with 463 barrels of mud, plug bumped, and floats held.
Returns were lost 231 barrels into the displacement. A 15 barrel Arctic Set II top job
was pumped.
185-062 50-029-21324-00-00 MPU B-07 Reservoir Abandoned Producer- Kuparuk 5958 -4402 Surface Surface Closed
The 9-5/8" surface casing is set at 6,206' MD / 4,606' TVD. The 9-5/8" casing was
cemented with 888 barrels of 12.2ppg Arctic Set III and 56 barrels of 15.8ppg Class G.
Plug bumped, floats held, and circulation was lost with 888 barrels pumped away. A
top job was pumped with 15 barrels of Arctic Set I, 2 barrels of cement returns to
surface.
Area of Review MPU B-40 SB OA
Milne Point Unit
(MPU) B-40
Application for Permit to Drill
Version 1
2/1/2023
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 21-1/4” 2M 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 BOP N/U and Test.................................................................................................................... 28
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 29
16.0 Run 4-1/2” Injection Liner (Lower Completion) .................................................................... 34
17.0 Run 3-1/2” Tubing (Upper Completion) ................................................................................. 38
18.0 RDMO ...................................................................................................................................... 39
19.0 Post-Rig Work ......................................................................................................................... 40
20.0 Doyon 14 Diverter Schematic .................................................................................................. 41
21.0 Doyon 14 BOP Schematic ........................................................................................................ 42
22.0 Wellhead Schematic ................................................................................................................. 43
23.0 Days Vs Depth .......................................................................................................................... 44
24.0 Formation Tops & Information............................................................................................... 45
25.0 Anticipated Drilling Hazards .................................................................................................. 47
26.0 Doyon 14 Layout ...................................................................................................................... 50
27.0 FIT Procedure .......................................................................................................................... 51
28.0 Doyon 14 Choke Manifold Schematic ..................................................................................... 52
29.0 Casing Design ........................................................................................................................... 53
30.0 8-1/2” Hole Section MASP ....................................................................................................... 54
31.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 55
32.0 Surface Plat (As-Staked) (NAD 27) ......................................................................................... 56
Page 2
Milne Point Unit
B-40 SB Injector
Drilling Procedure
1.0 Well Summary
Well MPU B-40
Pad Milne Point “B” Pad
Planned Completion Type 3-1/2” Injection Tubing
Target Reservoir(s) Schrader Bluff Oa Sand
Planned Well TD, MD / TVD 13,369’ MD / 4,457’ TVD
PBTD, MD / TVD 13,369’ MD / 4,457’ TVD
Surface Location (Governmental) 608’ FSL, 754’ FWL, Sec. 18, T13N, R11E, UM, AK
Surface Location (NAD 27) X= 571827 Y= 6023730
Top of Productive Horizon
(Governmental) 1016' FNL, 2276’ FWL, Sec 24, T13N, R10E, UM, AK
TPH Location (NAD 27) X= 568086 Y= 6022070
BHL (Governmental) 2455' FSL, 1823' FWL, Sec 14, T13N, R10E, UM, AK
BHL (NAD 27) X= 562320 Y=6025491
AFE Drilling Days 17 days
AFE Completion Days 3 days
Maximum Anticipated Pressure
(Surface) 1514 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1960 psig
Work String 5” 19.5# S-135 DS-50 & NC 50
KB Elevation above MSL: 33.7 ft + 23.3 ft = 57.0 ft
GL Elevation above MSL: 23.3 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Milne Point Unit
B-40 SB Injector
Drilling Procedure
2.0 Management of Change Information
Page 4
Milne Point Unit
B-40 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” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
8-1/2” 4-1/2” 3.960”3.795”4.714”13.5 L-80 H625 9020 8540 279
Tubing 3-1/2” 2.992”2.867”4.500”9.3 L-80
EUE 8RD 9289 7399 163
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 GPDS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 31,032 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Milne Point Unit
B-40 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
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 nathan.sperry@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
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Completion Engineer Scott Pessetto 907.564.4373 Scott.Pessetto@hilcorp.com
Geologist Graham Emerson 907.564.5242 Graham.Emerson@hilcorp.com
Reservoir Engineer Joleen Oshiro 907.777.8486 Joleen.Oshiro@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 kfleming@hilcorp.com
EHS Director Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
Page 6
Milne Point Unit
B-40 SB Injector
Drilling Procedure
6.0 Planned Wellbore Schematic
Page 7
Milne Point Unit
B-40 SB Injector
Drilling Procedure
7.0 Drilling / Completion Summary
MPU B-40 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. B-40 is part of a
multi well development program targeting the Schrader Bluff sand on B-pad. Hilcorp requests to pre-
produce for up to 30 days.
The directional plan is a horizontal well with 12-1/4” surface hole with 9-5/8” surface casing set into the top
of the Schrader Bluff OA sand. An 8-1/2” lateral section will be drilled. An injection liner will be run in the
open hole section.
The Doyon 14 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately February 28th, 2023, pending rig schedule.
Surface casing will be run to 6,700’ MD / 4,463’ 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 be discussed with AOGCC engineers.
All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility.
General sequence of operations:
1. MIRU Doyon 14 to well site
2. N/U & Test 21-1/4” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section.
4. Run and cement 9-5/8” surface casing
5. N/D diverter, N/U & test 13-5/8” x 5M BOP. Install MPD Riser
6. Drill 8-1/2” lateral to well TD.
7. Run 4-1/2” injection liner.
8. Run 3-1/2” tubing.
9. N/D BOP, N/U Tree, RDMO.
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
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8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that all drilling and completion operations comply with all applicable AOGCC regulations.
Operations stated in this PTD application may be altered based on sound engineering judgement as
wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from
the AOGCC. 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 Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU B-40. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 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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AOGCC Regulation Variance Requests:
1) Hilcorp is requesting approval for a test period of pre-producing B-40 for up to 30 days via a reverse
circulating jet pump completion. This will allow us to measure skin and evaluate the benefits of pre-
producing our injectors in the future. During flow back, Hilcorp will have a 24/7 man watch while the well is
online and producing. Section 19 details the steps required to make this happen. Note also that the MIT-IA
has been changed from 2,500 psi to 3,500 psi.
* Approved to pre-produce for 30 days with reverse circulation jet pump.
* 24/7 manned monitoring on MPU B pad if no surface safety valve while on IA power fluid injection when on
30 day pre-production period.
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Summary of BOP Equipment & Notifications
Hole Section Equipment Test Pressure (psi)
12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only
8-1/2”
x 13-5/8” x 5M Hydril “GK” Annular BOP
x 13-5/8” x 5M Hydril MPL Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Hydril MPL 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: 250/3000
Subsequent Tests:
250/3000
Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air
pump, 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 (BOP’s 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 PTD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@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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9.0 R/U and Preparatory Work
9.1 B-40 will utilize a newly set 20” conductor on B-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 Doyon 14. 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 6” liners in mud pumps.
x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @
95% volumetric efficiency.
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10.0 N/U 21-1/4” 2M Diverter System
10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program).
x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead.
x N/U 21-1/4” diverter “T”.
x 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.
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 45 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID greater than 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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10.4 Rig & Diverter Orientation:
x May change on location
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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 Use GWD until MWD surveys are clean.
x Confirm with engineer whether or not to continue capturing GWD surveys to TD
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
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.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD, in the Schrader OA 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 Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoff’s, 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 9.2
minimum at TD (pending MW increase due to hydrates).
x Drill ahead using GWD. Take MWD surveys every stand drilled and swap to MWD when
MWD surveys clean up.
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x Gas hydrates have not been seen on B-pad. However, be prepared for them. In MPU they
have been encountered typically around 2100’-2400’ TVD (just below permafrost). Be
prepared for hydrates:
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 AC:
x There are no wells with clearance factors < 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 9.2+ ppg.
Depth Interval MW (ppg)
Surface –Base Permafrost 8.9+
Base Permafrost - TD 9.2+
MW can be cut once ~500’ below hydrate zone
x PVT System: 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, 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) SafeCarb’s/Fibrous LCM/Graphite can be used in the system while
drilling the surface interval to prevent losses and strengthen the wellbore.
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.
Minimum EMW needed = 8.46 ppg. DLB
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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 – 9.2 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- Surface hole Size Pkg ppb or (%
liquids)
M-I Gel 50 lb sx 25
Soda Ash 50 lb sx 0.25
PolyPac Supreme UL 50 lb sx 0.08
Caustic Soda 50 lb sx 0.1
SCREENCLEEN 55 gal dm 0.5
11.5 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity.
11.6 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute.
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
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12.0 Run 9-5/8” Surface Casing
12.1 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” TXP 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 8-1/2” on the location prior to running.
x Note that 47# drift is 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.
12.2 P/U shoe joint, visually verify no debris inside joint.
12.3 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” TXP, 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint –9-5/8” TXP, 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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12.4 Float equipment and Stage tool equipment drawings:
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12.5 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 ~2,000’ above shoe (Top of Lowest Ugnu)
x Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.6 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost.
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damage 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” 40# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8” 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
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12.7 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
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12.8 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.9 Slow in and out of slips.
12.10 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.
12.11 Lower casing to setting depth. Confirm measurements.
12.12 Have slips staged in cellar along with all necessary equipment for the operation.
12.13 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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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 amount 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.
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Estimated 1st Stage Total Cement Volume:
Cement Slurry Design (1st Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
13.11 Displacement calculation is in the Stage 1 Table in step 13.7.
80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the
ES cementer is tuned spacer to minimize the risk of flash setting cement
13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer. 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.
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.15 Increase pressure to 3300 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.
13.16 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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Second Stage Surface Cement Job:
13.17 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Hold pre-job safety meeting.
13.18 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.19 Fill surface lines with water and pressure test.
13.20 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.21 Mix and pump cmt per below recipe for the 2
nd stage.
13.22 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. 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):
13.23 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.24 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.25 Displacement is in the Stage 2 table in step 13.22.
Lead Slurry Tail Slurry
System ArcticCem HalCem
Density 10.7 lb/gal 15.8 lb/gal
Yield 2.88 ft3/sk 1.17 ft3/sk
Mixed
Water 22.02 gal/sk 5.08 gal/sk
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13.26 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.
13.27 Land closing plug on stage collar and pressure up to 1000 – 1500 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
13.28 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 nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 BOP N/U and Test
14.1 N/D the diverter T, knife gate, diverter line & N/U 11” x 13-5/8” 5M casing spool.
14.2 N/U 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” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5” VBRs
x N/U 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 Run 5” BOP test plug
14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Test 2-7/8” x 5” rams with the 3-1/2” and 5” test joints
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
14.5 R/D BOP test equipment
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 8.9 ppg FloPro fluid for production hole.
14.8 Set wearbushing in wellhead.
14.9 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.10 Ensure 6” liners in mud pumps.
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Drilling Procedure
15.0 Drill 8-1/2” Hole Section
15.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 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. Pump at least one high vis sweep at maximum rate to surface to
clean up debris.
15.7 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT.
Document incremental volume pumped (and subsequent pressure) and volume returned.
x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.9 ppg FIT is the minimum
required to drill ahead
x 9.8 ppg provides >25 bbls based on 9.5ppg MW, 8.46ppg PP (swab kick at 9.5ppg BHP)
15.8 POOH & LD Cleanout BHA
15.9 P/U 8-1/2” RSS directional BHA.
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 Ensure MWD is R/U 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 DS50 & NC50.
x Run a ported 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
Email casing test and FIT digital data to AOGCC promptly upon completion of FIT. email: melvin.rixse@alaska.gov
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15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type:8.9 – 9.5 ppg FloPro drilling fluid
Properties:
Interval Density PV YP LSYP Total Solids MBT HPHT Hardness
Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100
System Formulation:
Product- production Size Pkg ppb or (% liquids)
Busan 1060 55 gal dm 0.095
FLOTROL 55 lb sx 6
CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2
FLO-VIS PLUS 25 lb sx 0.7
KCl 50 lb sx 10.7
SMB 50 lb sx 0.45
LOTORQ 55 gal dm 1.0
SAFE-CARB 10 (verify)50 lb sx 10
SAFE-CARB 20 (verify)50 lb sx 10
Soda Ash 50 lb sx 0.5
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15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Displace wellbore to 8.9 ppg FloPro drilling fluid
15.13 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 P/U
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 stand (confirm frequency with co-man)
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Surveys can be taken more frequently if deemed necessary.
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section.
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 (under 250 fph) without having to backream
connections
x Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up
on connections
x 8-1/2” Lateral A/C:
x MPU B-25 has a clearance factor of 0.547. B-25 is a Kuparuk injector. Hilcorp plans to
run a gyro in B-25 to improve the positional uncertainty. If B-25 fails AC after running
the gyro, Hilcorp will either modify the wellplan to steer around B-25 or will secure it
with a downhole plug to isolate Kuparuk pressure.
x Schrader Bluff OA Concretions: 4-6% Historically
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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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 sidetrack low and right 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 (minimum 4X, more if needed) at 200 ft/min AV (385+ gpm) and rotation (120+
rpm). Pump tandem sweeps if needed
x Rack back a stand at each bottoms up and reciprocate a full stand in between (while
circulating the BU). Keep the pipe moving while pumping.
x Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a
consistent stream so circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
x Losses during the cleanup of the wellbore are a good indication that the mud filter cake is
being removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + Liner volume with viscosified brine.
x Proposed brine blend (aiming for an 8 on the 6 RPM reading) -
KCl: 7.1bbp for 2%
NaCl: 60.9 ppg for 9.4 ppg
Lotorq: 1.5%
Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42 ppb
Flo-Vis Plus: 1.25 ppb
Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe
x Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses)
x Rotate at maximum rpm that can be sustained.
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x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but
adjust as hole conditions dictate.
x When pulling across any OHST depths, turn pumps off and rotary off to minimize
disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct
hole section, check with ABI compared to as drilled surveys
15.20 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.21 Monitor well for flow. Increase mud 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
15.22 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball
drops.
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16.0 Run 4-1/2” Injection Liner (Lower Completion)
NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and
run them slick.
16.1.Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2” injection liner with slotted liner, the following well control response procedure will be
followed:
x With a slotted joint across the BOP: P/U & M/U the 5” 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 With 4-1/2” solid joint across BOP: Slack off and position the 4-1/2” solid joint to MU the
TIW valve. Shut in ram or annular on 4-1/2” solid joint. Close TIW valve.
16.2. Confirm VBR’s have been tested to cover 4-1/2” and 5” pipe sizes to 250 psi low/3000 psi high.
16.3. R/U 4-1/2” liner running equipment.
x Ensure 4-1/2” Hydril 625 x DS-50 crossover is on rig floor and M/U to FOSV.
x Ensure the liner has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.4. Run 4-1/2” injection liner.
x Injection liner will be a combination of slotted and solid joints. Every third joint in the open
hole is to be a slotted joint. Confirm with OE.
x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each jt
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
4-1/2” 13.5# L-80 H625
Casing OD Minimum Optimum Maximum
Operating Torque
4.5” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs
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16.6. Verify with OE whether or not to set liner top packer at less than 70 degree inclination.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8” connection.
x AOGCC regulations require the packer to be placed within 200’ of the top reservoir
perforation (casing shoe) as per 20 AAC 25.412(b). Ensure hanger/packer will not be set in a
9-5/8” connection
16.7. 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.
16.8. M/U Baker SLZXP liner top packer to 4-1/2” liner.
16.9. 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.
16.10. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
x Ensure 5” DP/HWDP has been drifted
x There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
16.11. 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.
16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
16.16. 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
16.17. 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.
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16.18. 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.
16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
16.20. Bleed DP pressure to 0 psi. If necessary (and per vendor procedure), 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.
16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.22. 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.
16.23. PU pulling running tool free of the packer and displace with at max rate to wash the liner top.
Pump sweeps as needed.
16.24. 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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17.0 Run 3-1/2” Tubing (Upper Completion)
17.1 Notify the AOGCC at least 24 hours in advance of the IA pressure test after running the
completion as per 20 AAC 25.412 (e).
17.2 M/U injection assembly and RIH to setting depth. TIH no faster than 90 ft/min.
x Ensure wear bushing is pulled.
x Ensure 3-½” EUE 8RD x NC-50 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 R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
x Monitor displacement from wellbore while RIH.
3-1/2” 9.3# L-80 EUE 8RD
Casing OD Minimum Optimum Maximum
Operating Torque
3.5” 2,350 ft-lbs 3,130 ft-lbs 3,910 ft-lbs
3-½” Upper Completion Running Order
x 3-½” Baker Ported Bullet Nose seal (stung into the tie back receptacle)
x 3 joints (minimum, more as needed) 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” “X” nipple at TBD (ensure X-nipple and not an XN)
x 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x 3-½” SGM-FS XDPG Gauge at TBD
x 3-½” 9.3#/ft, L-80 EUE 8RD space out pups
x 3-1/2” sliding sleeve with jet pump
x 1 joint 3-½” 9.3#/ft, L-80 EUE 8RD tubing
x Tubing hanger with 3-1/2” EUE 8RD pin down
17.3 Locate and no-go out the seal assembly. Close annular and test to 400 psi to confirm seals
engaged.
17.4 Bleed pressure and open annular. Space out the completion (+/- 1’ to 2’ above No-Go). Place all
space out pups below the first full joint of the completion.
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17.5 Makeup the tubing hanger and landing joint.
17.6 RIH. Close annular and test to 400 – 500 psi to confirm seals are engaged. Bleed pressure down
to 250 psi. PU until ports in seal assembly exposed.
17.7 Reverse circulate the well with brine and 1% corrosion inhibitor.
17.8 Freeze protect the tubing and IA to ~3000’ MD with ±210 bbl of diesel.
17.9 Land hanger. RILDs and test hanger.
17.10 Continue pressurizing the annulus to 3500 psi and test for 30 charted minutes.
i. Note this test must be witnessed by the AOGCC representative.
17.11 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and
tree.
17.12 Install test dart. Test tree to 5000 psi.
17.13 Pull test dart. Bullhead tubing freeze protect.
17.14 Secure the tree and cellar.
18.0 RDMO
18. RDMO Doyon 14
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19.0 Post-Rig Work
Operations-Convert well on surface with hard line to a jet pump producer.
19.1 MU surface lines from power fluid header to existing IA.
a. Pressure test lines at existing power fluid header pressure (3,600 psi)
19.2 Rig up hardline to neighboring wells production header and test header. Pressure test to 3600 psi.
19.3 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.4 Shift Sliding sleeve open
19.5 Set 12B jet pump
19.6 RDMO
SL/FB- After 30 days of production
19.7 MIRU SL and Little Red Pumping Unit. PT lines to 3,000 psi.
19.8 FB circ IA with corrosion inhibited brine down to SS with a FP cap down to 2000’ on IA
19.9 Pull Jet Pump
19.10 Shift SS closed
19.11 MIT-IA test to 2000 psi
19.12 POI
19.13 After 5 days of stabilized injection MIT-IA to 2000 psi (Charted and state witnessed)
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20.0 Doyon 14 Diverter Schematic
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21.0 Doyon 14 BOP Schematic
2-7/8” x 5” VBR
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22.0 Wellhead Schematic
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23.0 Days Vs Depth
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24.0 Formation Tops & Information
MPU B-40
Formations
TVD
(ft)
TVDss
(ft)
MD
(ft)
Form. Pressure
(psi)
EMW
(ppg)
BPRF 1827 1770 2123
804 8.46
SV3 2117 2060 2547
931 8.46
UG4 2839 2782 3603
1,249 8.46
UG MB 4123 4066 5472
1,814 8.46
UG MC 4319 4262 5887
1,900 8.46
SB NA 4335 4278 5931
1,907 8.46
SB NB 4357 4300 5997
1,917 8.46
SB NC 4369 4312 6036
1,922 8.46
SB ND 4389 4332 6107
1,931 8.46
SB NE 4433 4376 6325
1,950 8.46
SB OA target 4454 4397 6563
1,959 8.46
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B-pad Data Sheet Formation Description
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25.0 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
Gas hyrates have not been seen on the pad. However, be prepared for them. Remember that hydrate gas
behave 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 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 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 a number of wells in close proximity. Take directional surveys every stand, take additional
surveys if necessary. Continuously monitor proximity to offset wellbores and record any close
approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in
adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well
specific A/C:
x There are no wells with a CF < 1.0
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. No H2S events have been documented
on drill wells on this pad.
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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.
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8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
appropriately 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:
There is at least (1) fault that will be crossed while drilling the well. There could be others and the
throw of these faults is not well understood at this point in time. When a known fault is coming up,
consider putting a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed,
we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then
replan the wellbore.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
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.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on M-
Pad. 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 MPU B-25 has a clearance factor of 0.547. B-25 is a Kuparuk injector. Hilcorp plans to run a
gyro in B-25 to improve the positional uncertainty. If B-25 fails AC after running the gyro,
Hilcorp will either modify the wellplan to steer around B-25 or will secure it with a downhole
plug to isolate Kuparuk pressure.
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26.0 Doyon 14 Layout
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27.0 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 52
Milne Point Unit
B-40 SB Injector
Drilling Procedure
28.0 Doyon 14 Choke Manifold Schematic
Page 53
Milne Point Unit
B-40 SB Injector
Drilling Procedure
29.0 Casing Design
Page 54
Milne Point Unit
B-40 SB Injector
Drilling Procedure
30.0 8-1/2” Hole Section MASP
DLB
Page 55
Milne Point Unit
B-40 SB Injector
Drilling Procedure
31.0 Spider Plot (NAD 27) (Governmental Sections)
Page 56
Milne Point Unit
B-40 SB Injector
Drilling Procedure
32.0 Surface Plat (As-Staked) (NAD 27)
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Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
X
MPU B-40
222-009
Schrader Bluff Oil
Milne Point Unit
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