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MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Friday, May 12, 2023
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Sully Sullivan
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
B-38
MILNE PT UNIT B-38
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 05/12/2023
B-38
50-029-23743-00-00
223-001-0
W
SPT
4424
2230010 1500
211 211 213 214
INITAL P
Sully Sullivan
4/13/2023
Monobore well.
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-38
Inspection Date:
Tubing
OA
Packer Depth
875 1756 1716 1705IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitSTS230413162856
BBL Pumped:1.7 BBL Returned:1.6
Friday, May 12, 2023 Page 1 of 1
MILNE POINT FIELD /
SCHRADER BLUFF OIL POOL
2/10/2023
By James Brooks at 9:46 am, Apr 11, 2023
Completed
2/28/2023
JSb
RBDMS JSB 050223
GMGR03AUG2023DSR-5/9/23
4.11.2023
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: 2023.04.11 06:41:25 -08'00'
Monty M
Myers
_____________________________________________________________________________________
Revised By: JNL 2/28/2023
SCHEMATIC
Milne Point Unit
Well: MPU B-38
Last Completed: 2/28/2023
PTD: 223-001
SLOTTED LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
4-1/2” 6640’ 4441’ 13313’ 4497’
GENERAL WELL INFO
API#: 50-029-23743-00-00
Completion Date: 2/28/2023
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 2,191’ 0.0732
9-5/8" Surface 40 / L-80 / TXP 8.679” 2,191’ 6,638’ 0.0758
4-1/2” Solid / Slotted Liner 13.5 / L-80 / Hyd 625 3.920” 6,449’ 13,356’ 0.0149
TUBING DETAIL
3-1/2" Tubing 9.3 / L-80 / EUE 8RD 2.992” Surface 6,463’ 0.0087
OPEN HOLE / CEMENT DETAIL
Driven 20” Conductor
12-1/4"Stg 1 –Lead 595 sx / Tail 400 sx
Stg 2 –Lead 665 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
WELL INCLINATION DETAIL
KOP @ 338’
90° Hole Angle @ 6,771’ MD
TD =13,363’(MD) / TD =4,500’(TVD)
20”
Orig. KB Elev.: 57.8’ / GL Elev.: 23.6’
3-1/2”
7
2
9-5/8”
1
4/5
See
Slotted
Liner
Detail
PB1:
10995’ –
11691’
PBTD =13,354’(MD) / PBTD =4,500’(TVD)
9-5/8” ‘ES’
Cementer @
2,209’
4-1/2”
6
3
JEWELRY DETAIL
No Top MD Item ID
Upper Completion
1 5,818’ Sliding Sleeve 2.813” X profile, covered ports (opens down) 2.870”
2 5,871’ Zenith Gauge Carrier 3.865”
3 5,929’ X Nipple, 2.813” 2.840”
4 6,452’ 8.24” No Go Locater Sub (spaced out 1.73’) 6.170”
5 6,453’ Bullet Seals – TXP Top Box x Mule Shoe 6.200”
Lower Completion
6 6,449’ 9-5/8” SLZXP Liner Top Packer 6.210”
7 13,354’ Shoe
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:MPU B-38 Date:2/18/2023
Csg Size/Wt/Grade:9.625", 40# & 47#, L-80 Supervisor:Demoski/Vanderpool
Csg Setting Depth:6638 TMD 4440 TVD
Mud Weight:9.3 ppg LOT / FIT Press =624 psi
.
LOT / FIT =12.00 Hole Depth =6661 md
Fluid Pumped=1.20 Bbls Volume Back =1.20 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
->0 ->039
->148 ->5 282
->290 ->10 569
->3 173 ->15 802
->4 216 ->20 1051
->5 273 ->25 1307
->6 3626 ->30 1558
->7 377 ->35 1845
->8 446 ->40 2142
->9 501 ->45 2432
->10 538 ->49 2697
->11 572 ->
->12 624 ->
-> ->
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 624 ->0 2697
->1 613 ->5 2688
->2 598 ->10 2682
->3 581 ->15 2680
->4 569 ->20 2678
->5 558 ->25 2676
->6 547 ->26 2676
->7 539 ->27 2676
->8 529 ->28 2676
->9 523 ->29 2675
->10 517 ->30 2675
->11 510 ->
->12 503 ->
->13 497 ->
->14 491
->15 485
->16 483
1
2
3
4
5
7
8
9 1011
12
0
5
10
15
20
25
30
35
40
45
49
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
)
624613598581569558547539529523517510503497491485483
2697 2688 2682 2680 2678 267626762676267626752675
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
0 5 10 15 20 25 30 35
Pr
e
s
s
u
r
e
(p
s
i
)
Time (Minutes)
LOT / FIT DATA CASING TEST DATA
Activity Date Ops Summary
2/9/2023 Move rig onto well B-38. Center and shim rig level. Mobilize equipment into the cellar. Spot and hook up service buildings. Provided 24 hour notification to the
AOGCC for the diverter test at 06:00. PJSM and skid rig floor into drilling position. On highline power at 12:00. RU rig floor steam, air, water and mud lines. Install
knife valve and diverter line. Spot fuel trailer and rock washer. Load 5" HWDP and BHA into the pipe shed. Work on rig acceptance checklist. Work on rig
acceptance checklist. Load 5" DP in the ODS pipe shed. RU the rock washer. Spot water tanks and cement silos. RU diverter liner. NU surface riser extension and
install riser. Install rock washer suction extensions. Work on rig acceptance checklist. Install rock washer suction extensions.RU diverter liner. Th diverter line is 176
long and 79 from the closet ignition source (Sperry shack). Inspect grabber dies and changeout the saver sub. Daily disposal to G&I = 0 bbls. Total disposal to G&I
= 0 bbls. Daily water hauled from 6 mile = 280 bbls. Total water hauled from 6 mile = 280 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 0 bbls. Daily metal
recovered = 0 lbs. Total metal recovered = 0 lbs.
2/10/2023 PU and rack back 6 stands of HWDP with jars. Rig accepted at 06:00. Perform diverter test. AOGCC inspector A. McLeod waived witness at 09:29 on 2/9/23. Test
performed on 5" DP. 14 sec knife valve opening and 24 sec annular closing. 2910 psi system pressure, 1800 psi after closing. 200 psi recovery = 34 sec & full
recovery = 147 sec. 6 bottle nitrogen avg = 2025 psi. 16" diverter line, 176' total length, 168' from substructure and 79' from nearest ignition source (Sperry unit).
Tested rig LEL and H2S gas alarms - good. Tested PVT and flow sensors - good. MU 12-1/4" Kymera bit and crossover sub to 36'. Hold pre-spud meeting with all
parties involved - identify safe briefing areas and emergency response duties. Fill stack with fresh water - no leaks. Flood mud lines with fresh water and pressure
test lines to 3,800 psi - good test. Tag ice in the conductor at 85'. Clean out conductor from 85' to 114' with 400 GPM and 40 RPM. Drill 12-1/4" surface hole from
114' to 219' (219' TVD). Drilled 115' = 76.67'/hr AROP. 400 GPM = 550 psi, 40 RPM = 2K ft-lbs TQ, WOB = 5K. PU = 50K, SO = 55K & ROT = 55K. MW = 8.9
ppg, Vis = 300. BROOH from 219' to 130' then pull on elevators to 36'. Blow down top drive. PU and inspect bit, found 3"x4"x3/8" plate steel lodged in bit. Remove
from bit and found no cutters damaged. MU MWD tools with Dir, Gamma, Res, PWD and Gyro While Drilling to 98'. Initialize MWD tools. MU non-mag drill collars
and crossover to 193'. Shallow pulse test MWD tools then wash down to bottom at 219'. Drill 12-1/4" surface hole from 219' to 821' (707' TVD). Drilled 602' =
80.3'/hr AROP. 450 GPM = 1,180 psi, 40 RPM = 23K ft-lbs TQ, WOB = 5-10K. PU = 77K, SO = 85K & ROT = 80K. MW = 9.1 ppg, Vis = 300, ECD = 9.86 ppg. At
470' start to build 3 deg/100'. Drill 12-1/4" surface hole from 821' to 1,414' (1,350' TVD). Drilled 593' = 98.8'/hr AROP. 480 GPM = 1,430 psi, 60 RPM = 3-5K ft-lbs
TQ, WOB = 10-15K. PU = 89K, SO = 92K & ROT = 89K. MW = 9.1 ppg, Vis = 300, ECD = 10.1 ppg. At 843' start to build 4 deg/100'. Last gyro survey at 994'. Last
survey at 1,171.81' MD / 1,147.51' TVD, 27.55 deg INC, 271.27 deg AZM. Distance from WP11 = 18.98', 16.60' high & 9.20' right. Daily disposal to G&I = 298
bbls. Total disposal to G&I = 298 bbls. Daily water hauled from 6 mile = 545 bbls. Total water hauled from 6 mile = 825 bbls. Daily fluid loss = 0 bbls. Total fluid loss
= 0 bbls.
2/11/2023 Drill 12-1/4" surface hole from 1,414' to 2,174' (1,887' TVD), Drilled 760' = 126.67'/hr AROP. 525 GPM = 1,680 psi, 80 RPM = 5K ft-lbs TQ, WOB = 7-15K. PU =
100K, SO = 90K & ROT = 95K. MW = 9.4 ppg, Vis = 89, ECD = 10.44 ppg, max gas = 13 units. Begin 48.72 degree tangent at 1,824'. Base of permafrost at 2,035'
(1,792' TVD). Drill 12-1/4" surface hole from 2,174' to 3,127' (2,497' TVD), Drilled 760' = 158.83'/hr AROP. 550 GPM = 1,860 psi, 80 RPM = 7K ft-lbs TQ, WOB =
10K. PU = 120K, SO = 98K & ROT = 106K. MW = 9.3 ppg, Vis = 142, ECD = 10.25 ppg, max gas = 381 units. Pump 30 bbl hi-vis sweep at 3,067', back on time
with 0% increase. Drill 12-1/4" surface hole from 3,127' to 3,794' (2,927' TVD), Drilled 667' = 111.2'/hr AROP. 550 GPM = 1,960 psi, 80 RPM = 8K ft-lbs TQ, WOB
= 10K. PU = 132K, SO = 102K & ROT = 112K. MW = 9.4 ppg, Vis = 105, ECD = 10.5 ppg, max gas = 33 units. B-pad power outage and rig on generators at 18:40
hours. Rig back on hi-line power at 22:35 hours. Drill 12-1/4" surface hole from 3,794' to 4,364 (3,345' TVD), Drilled 570' = 162.9'/hr AROP. 570 GPM = 2,000 psi,
80 RPM = 6-10K ft-lbs TQ, WOB = 5-15K. PU = 145K, SO = 106K & ROT = 125K. MW = 9.3 ppg, Vis = 91, ECD = 10.3 ppg, max gas = 57 units. Pump 30 bbl hi-
vis sweep at 4,267', back on time with 30% increase. Wash pipe on the top drive leaking. Blow down the top drive. Steam and grease the wash pipe. Drill 12-1/4"
surface hole from 4,364 to 4,555' (3,470' TVD), Drilled 191' = 95.5'/hr AROP.
580 GPM = 2,160 psi, 80 RPM = 10K ft-lbs TQ, WOB = 10K. PU = 148K, SO = 105K & ROT = 125K. MW = 9.3 ppg, Vis = 115, ECD = 10.3 ppg, max gas = 47
units. Last survey at 4,502.5 MD / 3,435.43 TVD, 47.42 deg INC, 263.21 deg AZM. Distance from WP11 = 9.81, 9.35 high & 2.98 right. Daily disposal to G&I =
1,546 bbls. Total disposal to G&I = 1,844 bbls. Daily water hauled from 6 mile = 1,580 bbls. Total water hauled from 6 mile = 2,405 bbls. Daily fluid loss = 0 bbls.
Total fluid loss = 0 bbls.
2/12/2023 Drill 12-1/4" surface hole from 4.555' to 5,240' (3,920' TVD). Drilled 685' = 114.2'/hr AROP. 575 GPM = 2,230 psi, 80 RPM = 15K ft-lbs TQ, WOB = 10-15K. PU =
155K, SO = 113K & ROT = 130K. MW = 9.3 ppg, Vis = 101, ECD = 10.0 ppg, max gas = 606 units. Pump 30 bbl hi-vis sweep at 5,030', not observed at the
shakers. Pre-treat mud with 1% ScreenKleen at 5,050' to prevent screen blinding. Logged Ugnu L3 at 5,174' (3,876' TVD). Observed 606 units gas & thick mud at
the shakers. Milne Point power issues, asked to take rig off highline power at 09:50. Drill 12-1/4" surface hole from 5,240' to 5,886' (4,249' TVD). Drilled 646' =
107.7'/hr AROP. 550 GPM = 2,160 psi, 80 RPM = 15K ft-lbs TQ, WOB = 10-15K. PU = 180K, SO = 110K & ROT = 135K. MW = 9.2 ppg, Vis = 118, ECD = 10.2
ppg, max gas = 257 units. Begin 4 deg/100' build and turn at 5,220'. Rig back on highline power at 16:00 hours. Drill 12-1/4" surface hole from 5,886' to 6,362'
(4,397' TVD) in the SB_OA sand. Drilled 476' = 79.3'/hr AROP. 550 GPM = 2,180 psi, 80 RPM = 17K ft-lbs TQ, WOB = 20K. PU = 172K, SO = 105K & ROT =
130K. MW = 9.2 ppg, Vis = 88, ECD = 10.2 ppg, max gas = 408 units. Pump 30 bbl hi-vis sweep at 6,171', back 500 strokes late with 50% increase. Drill 12-1/4"
surface hole from 6,362' to TD at 6,641' (4,440' TVD). Drilled 279' = 93'/hr AROP. 550 GPM = 2,340 psi, 80 RPM = 17K ft-lbs TQ, WOB = 10-15K. PU = 165K, SO
= 105K & ROT = 130K. MW = 9.1 ppg, Vis = 57, ECD = 10.1 ppg, max gas = 284 units. Top of the SB_OA sand at 6,526' (4,432' TVD). Obtain final survey at
6,641 MD / 4,440 TVD, 89.00 deg INC, 307.41 deg AZM. Distance from WP11 = 5.17, 4.30 high & 2.88 left. 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 = 22. Max gas 334
units. BROOH from 6,641' to 6,280' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM = 1,850 psi, 80 RPM = 15K ft-bs TQ,
ECD= 10.06 ppg, max gas = 92 units. PU = 165K, SO = 105K, ROT = 130K.
50-029-23743-00-00API #:
Well Name:
Field:
County/State:
MP B-38
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
2/10/2023Spud Date:
2/13/2023 BROOH from 6,280' to 4,364' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM = 1,790 PSI, 80 RPM = 10-14K ft-lbs TQ, ECD
= 10.72 ppg, max gas = 334 units. PU = 140K, SO = 104K, ROT = 115K. BROOH from 4,364' toto 660' pulling 5-10 minutes/stand slowing as needed to clean up
slides/tight spots. 550 GPM = 1,100 PSI, 80 RPM = 5-15K ft-lbs TQ, ECD = 10.58 ppg, max gas = 56 units. PU = 90K, SO = 80K, ROT = 85K. Increase the mud
YP to >30 at 2,400' to help clean / stabilize the permafrost. Pull slow from 2,270' to 2,079' while circulating a bottom ups before the build and below the permafrost.
Hole unloaded from 1,036' to 750'. BROOH with first stand of HWDP due to torque to 660'. TOOH with HWDP from 660' to 568'. Blow down the top drive. Continue
to TOOH from 568' to 193'. Lay down crossover and 3 NMFCs to 98'. 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 75 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 166' 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, TXP-BTC casing from 166' to 455'. TQ = 21K ft-lbs with Volant
tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally. Daily disposal to G&I = 1,048 bbls. Total disposal to G&I = 4,640 bbls. Daily water
hauled from 6 mile = 1,310 bbls. Total water hauled from 6 mile = 3,715 bbls. Daily fluid loss = 75 bbls. Total fluid loss = 75 bbls.
2/14/2023 Run 9-5/8", 40#, L-80, TXP-BTC casing from 455' to 2,183'. TQ = 21K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizers as per
tally. PU = 112K & SO = 90K. 47 bbls lost running casing to this point, 7.25 BPH avg. Galled threads on pin of joint #54 and box of #53. Change out joint #54 and
casing coupler on joint #53. Run joint #54 to 2,224' then stage up pumps to 6 BPM = 330 psi ICP and 200 psi FCP. Reciprocate 30' and circulate a bottoms up.
Lost 5 bbls while circulating. Run 9-5/8", 40#, L-80, TXP-BTC casing from 2,224' to 3,625'. TQ = 21K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints.
Installing centralizers as per tally. Galled threads on pin of joint #89 and box of #88. Change out joint #89 and casing coupler on joint #88. Run 9-5/8", 40#, L-80,
TXP-BTC casing from 3,625' to 4,408'. TQ = 21K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizers as per tally. MU the ES
cementer to 4,446' Baker Lok top & bottom connection. PU = 225K & SO = 115K. Lost 92 bbls RIH with 40# casing. Run 9-5/8", 47#, L-80, TXP-BTC casing from
4,408' to 4,957'. TQ = 24K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizers as per tally. CBU staging the pumps up to 6 BPM =
460 psi ICP & 300 psi FCP reciprocating 30'. Lost 3.5 bbls while circulating. Run 9-5/8", 47#, L-80, TXP-BTC casing from 4,957' to 6,581'. TQ = 24K ft-lbs with
Volant tool. Fill on the fly and top off every 10 joints. Installing centralizers as per tally. PU = 325K & SO = 120K. Lost 27 bbls RIH with 47# casing. Total losses
while running casing = 119 bbls. Wash down from 6,581' to 6,641' at 1.5 BPM = 350-460 psi. Stage the pumps up to 6 BPM = 480 psi. Establish rotation at 1-3
RPM = 18K ft-lbs TQ reciprocating 30'. Circulate and condition the mud for the cement job.
2/15/2023 Circulate & condition mud while preparing for the cement job. 6 BPM = 480 psi ICP / 300 psi FCP, 1-3 RPM = 18K ft/lbs TQ, Reciprocate 30'. PU = 275K, SO =
125K & ROT = 150K. Halliburton finished offloading re-blended tail cement, staged & rigged up cement trucks & equipment. MW 9.4 in & MW 9.55 out. Blow down
top drive. Rig up cement lines to Volant tool cement swivel. Re-dope Volant cup and clean dies. Continue to circulate. Hold PJSM with all parties involved. Prime
Halliburton equipment. Pump 50 bbls of mud treated with Desco. Warm HES cement lines with 5 bbls water to the pits then 5 bbls downhole. Pressure test lines to
1000/4000 PSI - good test. Pump 1 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 3.7 BPM
= 280 PSI. Drop by-pass plug. Mix and pump 249 bbls of 12.0 ppg lead cement (Type I-II cement, 2.347 ft^3/sk yield, 595 sks total) at 5.5 BPM = 620 PSI. Mix and
pump 82 bbls of 15.8 ppg tail cement (Premium G cement, 1.152 ft^3/sk yield, 400 sks total) at 2.4 BPM = 425 PSI.
Drop shut off plug. HES pump 20 bbls water at 6 BPM = 350 PSI. Displace with 296 bbls of 9.3 ppg spud mud from the rig at 6 BPM = 160 psi ICP, 210 psi FCP
observing 20% losses which increased to 40%. Slowed to 4 BPM = 130 psi CIP, 200 psi FCP. Rotated and reciprocated until started pumping 80 bbls of Tuned
Spacer. Parked casing at 6,638'. Pumped 80 bbls of 9.4 ppg Tuned Spacer from Halliburton at 2.75 BPM = 330 psi ICP, 535 psi FCP. Pumped 89.6 bbls 9.3 mud
from the rig at 4 BPM = 650 psi ICP, 880 psi FCP. Bumped plug 2.3 bbls early. Pressure up to 1400 psi & hold for 3 min. Bleed off & check floats - holding. CIP @
15:17. 35 bbls lost during cement job. Pressure up and observed ES cementer shift open at 3590 PSI. Stage up pump to 5 BPM = 280 PSI. Circulate through the
ES cementer at 2,211' with heavy sand returns. Calculated 1463 strokes bottoms up in gauge hole. Observed trace Pol-E-Flake from 1600-2400 strokes. Observed
spacer and trace cement back at 3400 strokes, 1937 strokes late, 2.3 bottoms up. Slow to 3600 strokes due to thick returns. 10.7 ppg weight out from 4300 to 4600
strokes. Dump contaminated mud until 6100 strokes then take returns to mud pits. Stage up to 5 BPM, 220 psi. Pump a total of 3x calculated BU (10,000 stks).
Disconnect knife valve from accumulator. Drain stack and flush with black water 3x. Re-connect knife valve to the accumulator. Clean rig floor cement valves. Break
out the Volant, clean, dope the cup and M/U same. Fuel cementers, continue to circulate 4 bpm, 180 psi while prep pits for 2nd stage then W/O last load of water to
arrive. PJSM with all parties involved for 2nd stage cement job. Lineup to cementers. Blow air through the cement line to the cementers. Pump 2nd stage cement
job: Pump 5 bbls of water and PT lines to 1,000/4,000 psi (good test). 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 = 345 psi. Mix & pump total 346 bbls 10.7 ppg Arctic Cem lead cement (665 sx at 2.917 ft^3/sk yield) at 4.25 BPM, ICP= 400, FCP= 526 psi. At 260 bbls
pumped start seeing spacer returns, dump returns to rock washer. At 310 bbls pumped start seeing cement returns. Mix & pump 56 bbls of 15.8 ppg Premium G tail
cement (270 sx at 1.156 ft^3/sk yield) at 2.75 BPM= 523 psi.
Drop the closing plug. Pump 20 bbls of 8.34 ppg fresh water at 5 BPM = 288 psi. Daily disposal to G&I = 1539 bbls. Total disposal to G&I = 6397 bbls. Daily water
hauled from 6 mile = 710 bbls. Total water hauled from 6 mile = 6285 bbls. Daily fluid loss = 181 bbls. Total fluid loss = 334 bbls.
2/16/2023 Displace cement with 9.4 ppg spud mud. 6 BPM = 540 psi ICP, 710 psi FCP. Slowed to 4 BPM = 530 PSI for last 10 bbls. Bumped plug at 1385 strokes, 2.2 bbls
early. Pressure up & shift ES cementer closed at 1350 PSI. Hold for 5 min. then bleed off. No flow confirm cementer closed. CIP at 06:18. 215 bbls of cement
returned to surface. 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 before cutting. Hoist the diverter stack. Install casing slips as per wellhead rep with 110K on
the slips. Cut 9-5/8" casing and L/D cut joint and pup joint. Cut joint length = 17.05'. N/D diverter line. Empty and clean mud pits. Remove 90' mouse hole. N/D
surface riser, diverter stack and diverter tee. Clean cement from knife valve. Wellhead rep install slip lock wellhead and torque to spec. PT void to 3800 psi for 10
min. - good test. N/U adapter flange, 2' spacer spool and BOP stack. Hook up kill line and annular hyd lines. Install turn buckles. Install the trip nipple, center up the
stack. Change out UPR to 2-7/8" x 5" VBR. SimOps: Thawing ice from mud pits so they can be cleaned. Rig up test equipment & install the test plug. Flood stack
and lines with fresh water. Purge air from system & perform shell test to 250/3000 psi, good. SimOps: Thawing ice from mud pits and cleaning same. Conduct initial
BOPE test to 250/3,000 psi: LPR (2-7/8 x 5 VBRs) and UPR (2-7/8 x 5 VBRs) with 3-1/2 & 5 test joints. Annular with 3-1/2 test joint, All tests performed w/ fresh
water against test plug. Test witnessed by AOGCC inspector Kam St John. Test rig gas alarms. Test: 1. Annular with 3-1/2 test joint, 5 TIW, choke valves 1, 12, 13,
14, kill valve 20 (Pass). 2. UPR with 3 1/2 test joint, choke valves 9, 11, HCR kill, 5" dart valve (Pass). 3. Manual kill, choke valves 5, 8 & 10, upper IBOP (Fail/Pass)
PSI dropping on low test. Bleed air, cycle IBOP. 4. Lower IBOP, choke valves 4, 6 & 7 (Fail) Lower IBOP not holding on low test. 5. Choke valves 4, 6 & 7 (Pass). 6.
Choke valve 2 (Pass). 7. HCR choke (Pass). 8. Manual choke (Pass). Daily disposal to G&I = 879 bbls. Total disposal to G&I = 7276 bbls. Daily water hauled from L-
Lake = 295 bbls. Total water hauled from L-Lake = 2490 bbls. Total water hauled from 6 mile = 4090 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 334 bbls.
2/17/2023 Continue BOPE test to 250/3,000 psi: LPR (2-7/8 x 5 VBRs) and UPR (2-7/8 x 5 VBRs) with 5 inch test joints. All tests performed w/ fresh water against test plug.
Test witnessed by AOGCC inspector Kam St John. Test PVT and flow alarms. 9. LPR with 3-1/2 inch test joint (Pass). 10. UPR with 5 inch test joint (Pass). 11.
LPR with 5 inch test joint (Pass). 12. Blind rams & choke valve 3 (Pass). 13. Manual choke valve B (Pass). 14. Super choke valve A (Fail/Pass) function & flush.
Accumulator test: System pressure = 3,050 psi. After closure = 1,700psi. 200 psi recovery = 47sec. Full psi recovery = 195 sec. 16 bottle N avg = 1,988 psi.
Change out lower IBOP and retest. (Fail/Pass) Grease then cycle IBOP. 11 hour total test time. 3 fail passes. Install Ringfeder locking assemblies on IBOP. Change
grabber dies. Remove choke manifold gauge and perform annual certification. Re-install and P/T to 5,000 psi. R/D test equipment. Blow down lines. Breakout dart
valve from FOSV. L/D test joint and test plug. Install wear bushing (9-1/8" I.D.). PJSM. P/U 8-1/2" Smith XR+CPS mill tooth bit, 6-3/4" mud motor. TIH with 6 stand
of HWDP to 588'. Trip in hole with clean out assembly on 5" DP f/ 588' t/ 2111'. PU=95k, SO=80k. Fill the pipe, wash and ream from 2111'. Tag cement at 2206'.
Drill cement, plug and ES cementer from 2206' to 2212' at 400 GPM = 600psi, 30 RPM = 3-5K ft-lbs Tq, WOB = 5-7K. Wash and ream through ESC 3 times and
drift through without pump/rotary. TIH w/ 5" DP f/ 2211' t/ 6296' filling pipe every 20 stds.
PU 202k, SO 92k. Wash/Ream f/ 6296' t/ firm cement at 6475' 320-425 GPM, 500-900 PSI. 30 RPM, 15k Tq, WOB= 5K, started seeing soft CMT/stringers @
6340'. CBU at 400 GPM, 1000 PSI, 40 RPM, 15-17k Tq, reciprocating F/6475' T/6386'. PU 205k, SO 90k, ROT 137k. Rack back stand and Blow down top drive.
R/U cement line and head pin, fill all lines and purge air. P/T 9 5/8" CSG to 2500 psi for 30 charted min- good test. Pumped 4.9 bbls- Bled back 4.9 bbls. Blow
down and R/D testing equipment. Establish drilling parameters, wash/ream down t/ 6475'. Drill cement and tag BA on depth at 6511'. Drill FE & shoe track to 6520'.
450-475 GPM,1150-1250 PSI. 40 RPM, 16 Tq, WOB= 2-8k. Daily disposal to G&I = 171 bbls. Total disposal to G&I = 7447 bbls. Daily water hauled from L-Lake =
200 bbls. Total water hauled from L-Lake = 2690 bbls. Total water hauled from 6 mile = 4090 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 334 bbls.
2/18/2023 Drill cement and 9-5/8" shoe track from 6,520' to 6,638', 475 GPM = 1,330 PSI, 40 RPM = 16K ft-lbs TQ. Encounter equipment on depth with float collar at 6,554'
and shoe at 6,636'. Ream equipment 3x times. Clean out rat hole from 6,638' to 6,641'. Drill 20' of new 8-1/2" hole from 6,641' to 6,661'. 480 GPM = 1275 PSI, 40
PRM = 16.5K ft-bs TQ, 6K WOB. 20' drilled, 125'/hr AROP. Circulate and condition prior to FIT with 600 GPM = 1750 PSI and 40 RPM = 18K ft-lbs TQ. Good 9.3
ppg MW in and out. Rack back stand to 6,581'. Rig up test equipment. Close upper pipe rams on 5" drill pipe. Perform 12.0 ppg FIT with 9.3 ppg MW at 6,638' MD
/ 4,440' TVD with 624 PSI applied at surface - good test. Rig down test equipment and blow down lines. Perform flow check - static. Pump dry job and POOH from
6,581' to 588'. Pulled 1st 5 stands wet with good hole fill before pumping dry job. Perform flow check at HWDP - static.
L/D excess HWDP and BHA. Bit graded: 1-1-WT-A-E-1-NO-BHA. Sim-ops: pressure test MPD lines to 1,500 PSI. Clear rig floor. Mobilize split master bushings to
the rig floor and install in the rotary table. Remove master bushings from the rig floor. Mobilize stabilizer and MPD bearing to the rig floor. PJSM. M/U 8-1/2" NOV
TK66 PDC bit, 8-1/2" bit sleeve, 7500 Geo-Pilot and MWD tools to 91'. Initialize MWD tools. Continue to M/U float sub, 3 non-max flex collars, float sub, Jars and
HWDP to 277'. TIH from 277' to 2080. Fill pipe. Shallow pulse test MWD at 450 GPM = 1030 psi. Break in the Geo Pilot seals. PU 94k, SO 80k, ROT 85k. Blow
down the top drive. Continue to TIH on stands 5'' drill pipe from 2080' to 6365'. Single in 6 jts drill pipe from 6367' to 6587'
Fill pipe and confirm good downlink to tools at 4081. PU 210K, SO 95K. Monitor Well. Rig up and jet flow line clean with cement hose. Inspect, grease and verify
wash-pipe tight. Drain the stack. Pull the trip nipple and install the MPD RCD. Install the RCD head skirt for the drip pan, no leaks. PJSM, M/U jt DP t/ 6619. Pump
spacer, displace well f/ 9.3 ppg spud mud to 8.8 ppg Flo-Pro at 6 BPM = 640/490 psi ICP/FCP, 30 RPM = 16k/10k ft-lbs Tq. PU 170K, SO 105K, ROT 140K. Divert
all 9.3 ppg spud mud, 28 bbls interface and 35 bbls spacer to RW before taking returns to mud pits. Obtain SPRs. Monitor MPD for pressure build, no pressure.
L/D jt DP, Pull up t/ 6555 and rack 1 stand back. Blow down the top drive, start slip and cut drilling line. Daily disposal to G&I = 223 bbls. Total disposal to G&I =
7670 bbls. Daily water from L-Lake = 275 bbls. Total water from L-Lake = 2965 bbls. Total water from 6 mile = 4090 bbls. Daily fluid loss = 0 bbls. Total fluid loss =
334 bbls. Daily metal recovered = 10 lbs. Total metal recovered = 10 lbs.
2/19/2023 Slip and cut 66' of drilling line. Re-calibrate block height on Totco system. Perform full service on top drive. MPD monitor pressure - no build. Wash down from
6,555' to 6,661', 450 GPM = 1,100 PSI and 80 RPM = 10K ft-lbs TQ. Obtain new slow pump rates. Drill 8-1/2" lateral from 6,661' to 6,843' (4,441' TVD), 182'
drilled, 60.7'/hr AROP. 500 GPM = 1,360 PSI, 100 RPM = 10K ft-lbs TQ, 8-12K WOB. MW = 8.9 ppg, vis = 44, ECD = 9.89, max gas = 48u. PU = 150K, SO =
105K & ROT = 125K. Drill 8-1/2" lateral from 6843' to 7439' (4428' TVD), 596' drilled, 99.33'/hr AROP. 550 GPM = 1630 PSI, 110 RPM = 10-12K ft-lbs Tq, 8-15K
WOB. MW = 8.9 ppg, vis = 42, ECD = 10.11, max gas = 1269u. PU = 148K, SO = 97K & ROT = 123K. MPD full open while drilling, closed on connections with no
psi build. Crossed unexpected fault at 7,050' MD / 4,445' TVD with 13' DTE throw. Build to 95 deg and reacquired sand at 7,251' MD / 4,439' TVD. Drill 8-1/2"
lateral from 7439' to 7770' (4424' TVD), 331' drilled, 55.17'/hr AROP. 550 GPM = 1650 PSI, 120 RPM = 10-15K ft-lbs Tq, 8-15K WOB. MW = 8.9 ppg, vis = 41,
ECD = 10.04, max gas = 1250u. PU = 148K, SO = 98K, ROT = 124K. MPD full open while drilling, closed on connections with 20 psi build. Pump 30 bbl hi-vis
sweep @ 7506. Return on time w/ 40% increase. Drill 8-1/2" lateral from 7770' to 8508' (4407' TVD), 738' drilled, 123'/hr AROP. 550 GPM = 1850 PSI, 115 RPM =
10-11K ft-lbs Tq, 7-15K WOB. MW = 9.0 ppg, vis = 44, ECD = 10.43, max gas = 1883u. PU = 150K, SO = 96K, ROT = 124K. Maintain the OA with 91-92 deg inc.
MPD full open while drilling, trapping 150 psi on connections. Last survey at 8387.91 MD / 4409.10' TVD, 91.03 inc, 304.21 azm, 20.58 from plan, 14.51 High and
14.59 right. We have drilled 20 concretions for a total thickness of 204 (11.6% of the lateral). Daily disposal to G&I = 1123 bbls. Total disposal to G&I = 8793 bbls.
Daily water hauled from L-Lake = 470 bbls. Total water hauled from L-Lake = 3435 bbls. Total water hauled from 6 mile = 4090 bbls. Daily fluid loss = 0 bbls. Total
fluid loss = 334 bbls. Daily metal recovered = 11 lbs. Total metal rec.
2/20/2023 Drill 8-1/2" lateral from 8,508' to 9,260' (4,371' TVD), 752' drilled, 125.3'/hr AROP. 550 GPM = 1940 PSI, 120 RPM = 10-12K ft-lbs TQ, WOB = 7-11K. MW = 9.2
ppg, vis = 40, ECD = 10.74, max gas = 1547u. PU = 150K, SO = 89K, ROT = 120K. MPD choke full open while drilling and hold 150 PSI on connections. Pump
high vis sweep at 8,552', back 100 strokes late with 60% increase. Fault # 2 at 8,650' with 3' DTE throw, sand to sand. Encountered fault #3 at 8,826' with 20' DTE
throw, back in OA at 8,991' (165' out of zone). Drill 8-1/2" lateral from 9260' to 9862' (4396' TVD), 602' drilled, 100'/hr AROP. 550 GPM = 2080 PSI, 120 RPM = 11-
14K ft-lbs Tq, 8-13K WOB. MW = 9.1 ppg, vis = 40, ECD = 10.84, max gas = 1418u. PU = 147K, SO = 87K & ROT = 115K. Pumped high vis sweep at 9,503',
back on time with 50% increase. Encountered fault #4 at 9,463' with 46' DTW throw. Encountered fault #5 at 9,860' with 20' DTW throw. MPD choke full open while
drilling and hold 150 PSI on connections. Drill 8-1/2" lateral from 9862' to 10287' (4430' TVD), 425 drilled, 71'/hr AROP. 550 GPM = 2190 PSI, 120 RPM = 12-15K
ft-lbs Tq, 7-12K WOB. MW = 9.2 ppg, vis = 40, ECD = 10.95, max gas = 134u. PU = 150K, SO = 91K & ROT = 120K. MPD choke full open while drilling and hold
150 PSI on connections. Drop trajectory to 83 deg inc while descending to reacquire the OA sand. Re-enter the OA at 10181. Total of 718 drilled above the OA after
fault #4. Build to formation dip at 88.6 deg and hold. MBT >7 @ 10263'. Pump Hi-Vis sweep and start 230 bbl dump & dilute. Sweep back on-time with 50%
increase. Drill 8-1/2" lateral from 10287' to 10930' (4469' TVD), 643' drilled, 107'/hr AROP. 550 GPM = 2090 PSI, 120 RPM = 10-15K ft-lbs Tq, 7-15K WOB. MW =
9.2 ppg, vis = 38, ECD = 10.04, max gas = 1250u. PU = 160K, SO = 85K & ROT = 120K. MPD choke full open while drilling and hold 150 PSI on connections.
Dump & dilute reduced MDT to 6.25. Pump sweep at 10739 return on time w/ 50% increase. Continue to maintain 86-87 deg formation dip. Last survey at
10765.09 MD / 4455.54' TVD, 85.90 inc, 298.90 azm, 25.20 from plan, 22.20' Low and 12.31 right. We have drilled 32 concretions for a total thickness of 330
(7.9% of the lateral). Daily disposal to G&I = 961 bbls. Total disposal to G&I = 9754 bbls. Daily water from L-Lake = 825 bbls. Total water from L-Lake = 4260 bbls.
Total water hauled from 6 mile = 4090 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 334 bbls. Daily metal recovered = 6 lbs. Total metal recovered = 27 lbs.
2/21/2023 Drill 8-1/2" lateral from 10,930' to 11,365' (4,442), 435' drilled, 72.5'/hr AROP. 550 GPM = 2290 PSI, 120 RPM = 12-13K ft-lbs TQ, 10-18K WOB. MW = 9.2 ppg,
vis = 39, ECD = 11.09, max gas = 1185 units. PU = 155K, SO = 85K, ROT = 120K. MPD choke full open while drilling & hold 120 PSI on connections. Fault at
10,845' with 11' DTE throw placed wellbore at the base of the OA, then drilled out the bottom at 10,893'. Drill 8-1/2" lateral from 11,365' to 11,691' (4,402' TVD),
325' drilled, 72.2'/hr AROP. 550 GPM = 2390 PSI, 120 RPM = 12-14K ft-lbs TQ, 10-15K WOB. MW = 9.3 ppg, vis = 39, ECD = 11.29, max gas = 634 units. PU =
148K, SO = 70K, ROT = 112K. MPD choke full open while drilling & hold 120 PSI on connections. Steer up with 96 deg inc. Fault #7 observed at 11,246' MD /
4,457' TVD with 34' DTW throw placing the wellbore above the OA sands. Pump high vis sweep at 11,595', back on time w/ 20% increase. Increase to 99 deg inc.
Drill and confirm wellbore in NF sands. Geologist called plug back TD of 11,690'. Obtain final MWD survey and set Geo-Pilot to home position. Circulate a bottoms
up. Line up injection line to MPD flow to provide pressure while tripping. Rack back stand to 11,596'. Blow down the top drive. Pump through MPD to hold 120 PSI
static and 160 PSI while pulling pipe. POOH on elevators from 11,596' to 10,995', laying down a single on stand #113. PU = 175K and SO = 90K. Trough at 160R
TF from 10995' to 11025', then time drill to 11088', 1.66'/min ROP, 540 GPM -2140 psi, 120 RPM 12K Tq. Observe 1.8 deg inc separation from parent wellbore at
11025' w/ 87.49 ABI. Pull up to 10995' and p/u single DP. RIH past sidetrack with w/o pumps no issues, tag bottom at 11088'. Obtain drilling parameters, confirm in
sidetrack bore with ABI <88 deg. Drill 8-1/2" lateral from 11088' to 11207' (4484' TVD), 119' drilled, 59.5'/hr AROP. 550 GPM = 2300 PSI, 120 RPM = 11-12K ft-lbs
Tq, 11-12K WOB. MW = 9.2 ppg, vis = 37, ECD = 10.83, max gas = 233u. PU = 155K, SO = 87K & ROT = 121K. MPD choke full open while drilling and hold 150
PSI on connections. Drill 8-1/2" lateral from 11207' to 11667' (4469' TVD), 460' drilled, 77'/hr AROP. 550 GPM = 2380 PSI, 120 RPM = 13-18K ft-lbs Tq, 15K
WOB. MW = 9.2 ppg, vis = 36, ECD = 11.09, max gas = 276u. PU = 160K, SO = 71K & ROT = 116K. MPD choke full open while drilling and hold 150 PSI on
connections. Last survey at 11525.79 MD / 4472.48' TVD, 91.09 inc, 304.61 azm, 32.30 from plan, 20.80' Low and 24.72 right. We have drilled 32 concretions for a
total thickness of 330 (6.7% of the lateral). Daily disposal to G&I = 1155 bbls. Total disposal to G&I = 10909 bbls. Daily water from L-Lake = 1255 bbls. Total water
from L-Lake = 5515 bbls. Total water from 6 mile = 4090 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 334 bbls. Daily metal recovered = 8 lbs. Total metal
recovered = 35 lbs.
2/22/2023 Drill 8-1/2" lateral from 11,667' to 12,265' (4,469' TVD), 598' drilled, 99.7'/hr AROP. 550 GPM = 2,110 PSI, 120 RPM = 10-14K ft-lbs TQ, WOB = 10-14K. MW =
9.4 ppg, vis = 40, ECD = 10.87, max gas = 1104u. PU = 165K, SO = 65K & ROT = 118K. MPD choke full open while drilling and hold 120 PSI on connections.
Perform 475 bbls new mud dilution at 11,977'. Back in OA sand at 11,667'. Drill 8-1/2" lateral from 12265' to 12955' (4479' TVD), 690' drilled, 115'/hr AROP. 550
GPM = 2170 PSI, 120 RPM = 12-15K ft-lbs Tq, 12-15K WOB. MW = 9.2 ppg, vis = 38, ECD = 10.81, max gas = 905u. PU = 170K, SO = 70K & ROT = 117K.
Perform 290 bbls new mud dilution at 12738'. MPD choke fully open drilling, trapping 120 psi during connections. Drill 8-1/2" lateral from 12955' to TD @ 13363'
(4499' TVD), 408' drilled, 116'/hr AROP. 550 GPM = 2220 PSI, 120 RPM = 14K ft-lbs Tq, 12-15K WOB. MW = 9.15 ppg, vis = 38, ECD = 11.03, max gas = 1078u.
PU = 170K, SO = 70K & ROT = 120K. MPD choke fully open drilling, trapping 120 psi during connections. Encountered unexpected fault #8 at 13350', placing bit
out of the OA sand, TD was subsequently called. Obtain final MWD survey. Downlink Geo-Pilot to home position. Final survey at 13294.53 MD / 4496.29' TVD,
87.01 deg inc, 303.03 deg azm, 7.56 from plan, 6.23' Low and 4.27 left. Drilled 42 concretions for a total thickness of 402 (6% of the lateral). Pump 30 bbl high vis
sweep, back 100 strokes late with 10% increase in cuttings. Continue circulating 4x BU at 550 GPM = 2200 psi, 80 RPM = 10-11K ft-lbs Tq. Rack std in Derrick
each BU. SimOps: Prep pits and Stg/wait on trucks for displacement. Trip back to BTM on elevators f/ 12928' t/ 13363' and continue circulating, 550 GPM, 2280
psi. Rot and reciprocate 45', 120 RPM, 13k Tq. PU 170k, SO 75k, Rot 117k. PJSM for displacing and finish staging final trucks arriving on location. 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 8.45 ppg vis brine with 3% lubes (1.5% 776 & 1.5% LoTorq). 6 BPM = 915 psi (ICP), 60 RPM = 12K ft-lbs TQ & 7 BPM = 1040 psi (ICP), 60
RPM = 12K ft-lbs TQ, reciprocating 45' alternating stopping points. All returns dumped to the rockwasher. No losses recorded while drilling, circulating and
displacing. Daily disposal to G&I = 2022 bbls. Total disposal to G&I = 12931 bbls. Daily water from L-Lake = 825 bbls. Total water from L-Lake = 6340 bbls. Total
water from 6 mile = 4090 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 334 bbls. Daily metal recovered = 8 lbs. Total metal recovered = 43 lbs.
2/23/2023 Cont. displacing to 8.45 ppg lubed vissed brine at 7 BPM = 880 psi (FCP), 60 RPM = 12K ft-lbs TQ, reciprocating 45' alternating stopping points holding 200 PSI
back pressure to maintain 10.0 PPG ECD. All returns dumped to the rockwasher. No losses recorded while drilling, circulating and displacing. BROOH 1 stand
parking at 13,308', blow down TD and Geo Span, monitor MPD for pressure build 4x with the final building from 34 psi to 102 psi in 3 min, EMW with trip margin=
9.1 ppg. Record new SPRs. In brine PU= 170k, SO= 85K, ROT= 120K. BROOH from 13,308' to 9693' pulling 5-10 minutes/stand slowing as needed to clean up
slides/tight spots. Laying down DP in the mouse hole. 500 GPM = 1560 psi, 120 RPM = 10K ft-lbs Tq, max gas = 257 units. PU = 157K, SO =90K & ROT = 125K.
Loss rate = 10-17 BPH. MPD hold 100 psi on connections. BROOH from 9693' to 7835' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight
spots. Laying down DP in the mouse hole. 500 GPM = 1500 psi, 110 RPM = 8K ft-lbs Tq, max gas = 257 units. PU = 155K, SO =107K & ROT = 120K. Loss rate =
10-12 BPH. MPD hold 100 psi on connections. High winds blew the Top Drive service loop over and one line got hung up on a standpipe connection guard while
slacking off blocks. Reposition line and secure remaining service loop. BROOH from 7835' to 6557' pulling 5-10 min/std slow as needed to clean up slides/tight
spots. L/D DP in the mouse hole. 500 GPM = 1500 psi, 110 RPM = 8K ft-lbs Tq, max gas = 224u. PU = 155K, SO =107K & ROT = 120K. Total 136 bbl losses
while BROOH. MPD hold 100 psi on conn. MPU in Phase 2 at 03:45. Pump 30 bbl hi vis sweep and circulate the casing clean at 500 GPM = 1350 psi, 80 RPM =
5K ft-lbs Tq. Max Gas = 74u. Sweep back on time with 10% increase. Monitor pressure with MPD choke closed with 9.0 ppg MW. 5 min built 40 psi, bleed off, 5 min
built 30 psi, bleed off, 5 min built 25 psi, bleed off = 9.1 ppg EMW. KWF = 9.3 ppg. Prep hopper room and pits to weight up system. MPU phase condition reduced
to Phase 1 @ 05:32. Daily disposal to G&I = 1676 bbls. Total disposal to G&I = 14607 bbls
Daily water from L-Lake = 680 bbls. Total water from L-Lake = 7020 bbls. Total water from 6 mile = 4090 bbls. Daily fluid loss = 99 bbls. Total fluid loss = 433 bbls.
Daily metal recovered = 5 lbs. Total metal recovered = 48 lbs.
2/24/2023 Weight up brine from the shoe up from 9 ppg to 9.3 ppg, 550 gpm, 1490 psi, 60 rpm, 5k torque working the pipe, shut down pump. Monitor MPD for pressure build
5 times at 5 min each= 24 psi, 20 psi, 16 psi, 8 psi and 3 psi, open 2'' valve on the MPD head and monitor flow. pencil size stream and going static in 50 minutes.
PJSM. Remove the RCD and install the MPD riser. Fill the riser and no leaks. Well is static. Obtain new SPR's, pump dry job and blow down the top drive. Drop
2.45" OD drift on 100' of wire. Fill trip tank with 9.3 ppg brine. BD MPD lines and RD same. Slight loss rate. TOOH from 6,555' to 277' racking stands drill pipe in
derrick, flow check the well before pulling BHA, well is static. 11.9 bbl losses TOOH. Recover drift and wire, LD HWDP and jars, 3 NMFC and float subs to 91'. Plug
in and download MWD data. LD remaining BHA. 8-1/2'' PDC bit grade= 2-2-CT-A-X-1-TD. Normal wear on BHA from drilling and BROOH. Clear the rig floor of
BHA components. Remove the split bushings and install the master bushings. Static loss rate = 1.5 BPH. Mobilize casing equipment and crossovers to the rig floor.
RU 4-1/2" double stack tongs, elevators and slips. MU crossover sub on FOSV. Static loss rate = 1.5 BPH. MU & RIH round nose float shoe/blank joint 4-1/2 liner.
RIH WITH 4-1/2", 13.5#, L-80, H625 slotted injection liner as per tally installing a free-floating stop ring & centralizer on every joint to 4987'. MU to optimum TQ @
9,600 ft-lbs. PU = 88K, SO = 74K. Loss rate RIH= 1.5 BPH. Daily disposal to G&I = 319 bbls. Total disposal to G&I = 14926 bbls. Daily water from L-Lake = 180
bbls. Total water from L-Lake = 7200 bbls. Total water from 6 mile = 4090 bbls. Daily fluid loss = 20.5 bbls. Total fluid loss = 453.5 bbls. Daily metal recovered = 1
lbs. Total metal recovered = 49 lbs.
2/25/2023 Continue RIH with 4-1/2", 13.5#, L-80, H625 slotted injection liner as per tally installing a free-floating stop ring & centralizer on every joint from 4987' to 6681'. MU
to optimum TQ @ 9,600 ft-lbs. Lost 11.5 bbls while running liner. Ave loss rate = 1 BPH. Verify pipe count in pipe shed. Swap elevators. MU Baker SLZXP LTP, TIH
one stand to 7,011'. Pump 10 bbls through LTP to ensure clear flow path, 2 BPM = 100 psi. PU = 105K, SO = 90K, ROT = 95K, 10 RPM= 3K TQ, 20 RPM= 4K
TQ. Blow down top drive. Remove crossover from FOSV. R/D double stack tongs. TIH with 4-1/2", 13.5#, L-80, H625 slotted liner on 5" DP from 7,011' to 13,363'
tagging TD on depth with 7K. Perform space out 7' off BTM shoe depth 13656'. PU = 160K & SO = 97K. Lost 9 bbls while TIH. Submit 24 hr notification to AOGCC
for pre-injection MIT. Break circulation with 10 bbls at 2 BPM = 250 psi. PU =160K & SO = 100K. L/D single jt DP. Blow down the top drive. Drop 1.125" phenolic
ball. M/U 10 pup jt, FOSV & side entry sub below 5' DP pup joint. R/U cement line and test pump. PT lines - Good. Pump ball down w/ 30 bbl hi-vis sweep. Ball on
seat at 1036 stks. Pressure up to 2100 psi & observed shear at 1980 psi. Hold for 5 min. and SO 100K. Cont to pressure up with the rig pumps, neutralizer shear at
2890 psi & ball seat shear at 4003 psi. PU to confirm release with PU = 140K. Top of the SLZXP LTP at 6,449'. Purge air from lines. Close the UPRs. PT the IA/LTP
to 1,500 psi for 10 minutes charted (good test). R/D the circulating equipment. Blow down the cement line. R/D FOSV, side entry sub and pup jts. Pull the running
tool out of the SLZXP while circulating at 3 BPM = 310 psi. Lay down 2x 5 DP singles and continue to circulate a total of 1.5 BU at 400 GPM = 1780 psi. Observe
the well for flow - static. Blow down the top drive and choke/kill line. PJSM. Slip and cut 57' of drilling line. Service the draw works and Top drive. Monitor Well via
TT, Static loss rate = 1.5 BPH. Calibrate blocks height. Pump a dry job and blow down the top drive. TOOH from 6407' to 4957', laying down drillpipe to the shed.
Loss @ 1.5 BPH. Daily disposal to G&I = 320 bbls. Total disposal to G&I = 15246 bbls. Daily water from L-Lake = 205 bbls. Total water from L-Lake = 7405 bbls.
Total water from 6 mile = 4090 bbls. Daily fluid loss = 26.5 bbls. Total fluid loss = 480 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 49 lbs.
Activity Date Ops Summary
2/26/2023 Continue TOOH from 4957' to surface laying down drill pipe to the shed. LD and inspect LRT, good. Losses TOOH= 10.5 bbls,Clean and clear the rig floor,
mobilize 3 1/2'' tubing tools and equipment to the rig floor. Pull the wear bushing, RU 3 1/2'' power tongs and handling equipment. Centrilift RU spooler on rig floor,
ready XO on FOSV. Monitor well, 1 bph loss rate,PJSM, PJSM, PU bullet seal assembly and RIH on 3-1/2, 9.3#, L-80, EUE 8rd tubing as per tally to 522'. Torque to
optimum @ 3,130 ft-lbs with Doyon double stack tongs. Loss rate = 1 bph,MU X nipple assembly, 1 joint, gauge carrier assembly to 603', Install gauge and MU tec
wire to gauge. MU 1 joint and sliding sleeve assembly to 650'. 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 650' to 4790'. Torque to optimum @ 3,130 ft-lbs. SO = 65K. Loss rate = 1 bph,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 4790' to 6464 and no-go out. Torque to optimum @ 3,130
ft-lbs. PU = 80K & SO = 73K. Loss rate = 1 bph,Lay down joints #204, #203, #202 and #201. MU 5.09, 10.22, 6.22 & 8.19 pup joints. M/U joint #201. Lost 11 bbls
while running 3-1/2" completion. Change elevators to 5" DP. P/U 5" DP landing joint. M/U crossover to the landing joint and M/U the tubing hanger. M/U the tubing
hanger to the completion string. Terminate the Tec wire, feed through the tubing hanger and secure. Drain the BOP stack. Add two clamps on first jt tubing to
remove excess slack in control line. Rig up snubbing line to center string and Land the tubing hanger. Wellhead Rep verify Landed. Rig up to reverse circulate.
FOSV, Side entry sub & 5' pup jt. Daily disposal to G&I = 0 bbls. Total disposal to G&I = 15246 bbls. Daily water from L-Lake = 150 bbls. Total water from L-Lake =
7555 bbls. Total water from 6 mile = 4090 bbls. Daily fluid loss = 25 bbls. Total fluid loss = 505 bbls. Daily metal recovered = 0 lbs. Total metal recovered = 49 lbs.
2/27/2023 Finish RU to reverse circulate down the IA and taking returns out tubing, reduce closing pressure on annular to 500 psi, close bag, apply 300 psi on annulus, strip
up exposing ports on the seal assembly observing pressure drop. Hold PJSM, Purge and test lines to 1200 psi, good. Thaw super sucker line to cellar box, empty
cellar box. Reverse circulate 271.6 bbls of 8.5 ppg CIB at 4 BPM = 740 psi ICP, 860 psi FCP followed by 135 bbls diesel at 3 BPM = 610 psi ICP, 700 psi FCP.
freeze protecting the 3 1/2'' x 9 5/8'' annulus to 2,200',Strip through annular closing ports ports, Drain stack, blow down lines, open annular and rinse stack. Land
tubing on hanger at 6,462.74' with 33k on hanger @ 1.73' off NO-GO. RILDS. RD and BD circulating lines from landing joint. Crew C/O, PJSM, RU testing
equipment. PT the IA to 3,500 psi for 30 minutes charted - good test. 6.8 bbls pumped, 6.8 bbls bled back. RD circulating and test equipment, breakout XOs and LD
the landing joint, WHR install the BPV with dry rod. Take rig off hi line @ 14:16 and put on gen power. PJSM. Pull the MPD riser and 90' mousehole. Remove the
drip pan, turn buckles and kill line. ND the BOP stack. ND the spacer spool. Set BOP on pedestal and secure for transport. Install the CTS plug in the BPV.
SimOps: Clean and clear the rig floor of completion running equipment. Clean the mud pits. Nipple up adapter flange and tree. Test Hanger void to 500/5000 f/ 10
min each - Good. Centrilift obtain final reading - Pt = 1989.12 psi, Tt = 81.1 degF, Vt = 20.2v,Fill the tree with diesel. PT the tree to 250/5,000 psi (good test). Pull
the CTS plug and BPV. R/U & Bullhead 20 bbls of diesel down the tubing. ICP at 2 BPM = 810 psi, FCP at 1.5 BPM = 1000 psi. Blow down and RD circulating
lines. Shut in and secure the well. Final Wellhead readings: Tubing = 500 psi, IA = 0. Daily disposal to G&I = 969 bbls. Total disposal to G&I = 16215 bbls. Daily
water from L-Lake = 270 bbls. Total water from L-Lake = 7825 bbls. Total water from 6 mile = 4090 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 505 bbls. Daily
metal recovered = 0 lbs. Total metal recovered = 49 lbs.
2/28/2023 Flush mud pumps. Clean the cellar box. SimOps: Clean Rockwasher, prep mud pits and Rig down service shacks. Rig welder cut off the mouse hole and seal weld
the bottom of the cellar box. Move fuel trailer, cuttings box and Rockwasher. Prep to skid floor into moving position. SimOps: Move support buildings. Blow down rig
floor steam/water. Rig released from Well B-38 @ 06:00.
50-029-23743-00-00API #:
Well Name:
Field:
County/State:
MP B-38
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
PT the IA to 3,500 psi for 30 minutes charted - good test.
ACTIVITYDATE SUMMARY
2/28/2023
WELLHEAD: MU 11 x 3 1/2 tbg hgr to LJ and comp. string term. 1/4" CL through hgr.
Land in profile, RILDS, set 3" CTS bpv w/ T bar. RIG ND stack. Install CTS plug,
RX54 gasket and SBMS metal neck seal. PU tree/adapter, land w/ CL out the
backside term. sleeve. Torque to spec. Test hgr void 500/5000 (PASS). RIG test tree
(PASS). Pull CTS plug and bpv, manifolds installed on tree cap and IA.
2/28/2023
***WELL S/I ON ARRIVAL***(shift viking ss/set jet pump)
STBY FOR RIG MOVE
RAN DUAL 3-1/2" BO SHIFTING TOOL, OPEN VIKING SLIDING SLEEVE AT 5,818'
MD (see psi change, see log)
PUMP ON IA TO VERIFY SLEEVE OPEN
SET 3-1/2" JET PUMP IN SLIDING SLEEVE AT 5,818' MD (no sn:, 12 B ratio)
ASSIST WELL SUPPORT INSTALLING FLANGE AND CHOKE TO IA
***WELL LEFT S/I ON DEPARTURE***
4/2/2023
Well Support techs R/D temporary hardline for the power fluid line and prodcution
line. Support techs set foundation, well house, and installed injection piping.
Pressure tested injection piping to 3650 psi with no issues, Serviced tree.
4/5/2023
T/I/O= 650/0/NA (Assist Slickline) TFS U-3, Pumped 40 BBLS DSL down TBG .
FWHP=0/0
4/5/2023
***WELL S/I UPON ARRIVAL*** (wellwork)
PULL JET PUMP FROM 5,818' MD
***CONT WSR ON 04/06/2023***
4/6/2023
***CONT WSR FROM 04/05/2023***
LRS LOAD IA 180 BBLS KCL & 190 BBLS DIESEL
SHIFT SLD SLV CLOSED @ 5,818' MD
***WELL LEFT S/I ON DEPARTURE, PAD OP NOTIFIED ON WELL STATUS***
4/6/2023
T/I = 63/Vac Load IA with Inhibited Brine, Pumped 180 bbls Inhibited Brine down
IA, Pumped 190 bbls diesel down IA, MIT-IA to 2000 psi Passed FWP = 95/100
Daily Report of Well Operations
PBU MPB-38
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
1
1
1
1
103
1
1
1
53
1
X Yes No X Yes No 245
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure: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? Yes X No Reciprocated? Yes X No % Returns during job
Cement returns to surface?X Yes No Spacer returns?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
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:
1.16
2/16/2023 Surface
Spud Mud
Type I/II 595 2.35
Premium G 400 1.15
5.5
2,191.03
Casing 9 5/8 47.0 L-80 TXP Tenaris 2,134.17 2,191.03 56.86
2,211.44 2,208.62
Casing Pup Joint 9 5/8 40.0 L-80 TXP 17.59 2,208.62
17.69 2,229.13 2,211.44
ES Cementer 10 3/4 TXP Halliburton 2.82
Casing Pup Joint 9 5/8 40.0 L-80 TXP
6,511.96
Casing 9 5/8 40.0 L-80 TXP Tenaris 4,282.83 6,511.96 2,229.13
6,554.21 6,513.36
Baffle Adapter 10 3/4 TXP Halliburton 1.40 6,513.36
1.30 6,555.51 6,554.21
Casing 9 5/8 40.0 L-80 TXP Tenaris 40.85
Float Collar 10 3/4 TXP Innovex
Casing 9 5/8 40.0 L-80 TXP Tenaris 80.90 6,636.41 6,555.51
www.wellez.net WellEz Information Management LLC ver_04818br
2.4
Ftg. Returned
Ftg. Cut Jt.17.05 Ftg. Balance
No. Jts. Delivered No. Jts. Run
Length Measurements W/O Threads
Ftg. Delivered Ftg. Run
RKB to CHF
Type of Shoe:Innovex Casing Crew:Doyon
12 249
HES ES Cemente Closure OK
56
ArcticCem
Type
Premium G 270
Tuned Spacer
665 2.92
Stage Collar @
60
Bump press
100
215
6,638.006,641.00
CEMENTING REPORT
Csg Wt. On Slips:110,000
Spud Mud
15:17 2/15/2023 2,211
2211.44
15.8 82
Bump press
Trace cement to surface
Bump Plug?
Y
2.75
9.3 4 159.89/162.09
363.6/395.9
1400
1
Rig #2
FI
R
S
T
S
T
A
G
E
10Tuned Spacer 60
15.8
530
9.3 6
1350
10
10.7 346 4.25
92
880
Bump Plug?
Csg Wt. On Hook:275,000 Type Float Collar:Innovex No. Hrs to Run:27
9 5/8 47.0 L-80 TXP
TXP Innovex 1.59 6,638.00 6,636.41
24.44 56.86 32.42
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.MP B-38 Date Run 15-Feb-23
CASING RECORD
County State Alaska Supv.C.A. Demoski / I. Toomey
6,654.97
Floats Held
404.37 733
215 518
Spud Mud
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ 6638 FC @ Top of Liner
SE
C
O
N
D
S
T
A
G
E
Rig #2
6:18
Cement to surface
394.82 517 24
Casing (Or Liner) Detail
Shoe
Cut joint
10 3/4
Trace cement to surface
2,211
X
215
Surface
92
Cement to surface
X
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: 03/09/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: MPU B-38
PTD: 223-001
API: 50-029-23743-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING LOGS (02/10/2023 to 02/22/2023)
EWR-M5, AGR, ABG, DGR, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
MPU B-38 FINAL LWD Subfolders:
MPU B-38 FINAL Geosteering Subfolders:
Please include current contact information if different from above.
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:
WELL: MPU B-38PB1
PTD: 223-001
API: 50-029-23743-70-00
FINAL LWD FORMATION EVALUATION LOGS (02/10/2023 to 02/21/2023)
EWR-M5, AGR, ABG, DGR, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
MPU B-38PB1 LWD Subfolders:
Please include current contact information if different from above.
Submit to:
OPERATOR:
FIELD / UNIT / PAD:
DATE:
OPERATOR REP:
AOGCC REP:
Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min.
PTD 223-001 Type Inj N Tubing 0 0 0 0 Type Test P
Packer TVD 4423 BBL Pump 6.8 IA 0 3540 3510 3505 Interval O
Test psi 3500 BBL Return 6.8 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:
Hilcorp Alaska LLC
Milne Point , MPU, B Pad
Douglas Yessak
02/27/23
Notes:Pre-Injection MIT-IA on rig. Witness waived by Guy Cook on 2/25/23 at 11:59 am. Monobore, No OA. Test to 3500 psi as per PTD.
Notes:
Notes:
Notes:
B-38
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:
Notes:
Form 10-426 (Revised 01/2017)2023-0227_MIT_MPU_B-38
J. Regg; 5/3/2023
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________MILNE PT UNIT B-38
JBR 04/04/2023
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:3
Used 3-1/2 and 5-1/2 JT. Upper kelly failed, cycled retest good, Lower Kelly failed, changed out retest good and super choke
failed, cycle and flush retest good. Accumulator pre charge 18 @1000 psi Avg
Test Results
TEST DATA
Rig Rep:Shones / HamiltonOperator:Hilcorp Alaska, LLC Operator Rep:Demoski/Vanderpool
Rig Owner/Rig No.:Doyon 14 PTD#:2230010 DATE:2/17/2023
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopKPS230219090827
Inspector Kam StJohn
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 11
MASP:
1511
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 FP
Lower Kelly 1 FP
Ball Type 1 P
Inside BOP 1 P
FSV Misc 0 NA
14 PNo. Valves
1 PManual Chokes
1 FPHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13-5/8"P
#1 Rams 1 2-7/8" X 5"P
#2 Rams 1 Blinds P
#3 Rams 1 2-7/8" x 5"P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 3-1/8"P
Kill Line Valves 2 3-1/8"P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3050
Pressure After Closure P1700
200 PSI Attained P47
Full Pressure Attained P195
Blind Switch Covers:PAll Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P6@1988
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer P15
#1 Rams P6
#2 Rams P6
#3 Rams P6
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P1
HCR Kill P1
9
9
9
9 9999
9
9
9
9
Lower Kelly failed,super choke
failed,
1
Regg, James B (OGC)
From:Alaska NS - Doyon 14 - DSMs <AlaskaNS-Doyon14-DSMs@hilcorp.com>
Sent:Saturday, February 11, 2023 5:24 AM
To:Regg, James B (OGC); Brooks, Phoebe L (OGC); DOA AOGCC Prudhoe Bay
Subject:MPU B-38 Diverter Test 2-10-23
Attachments:MPU B-38 Diverter 2-10-23.xlsx
Good morning,
Attached is the diverter test report for Hilcorp, Doyon 14, MPU B‐38.
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-38PTD 2230010
Date: 2/10/2023 Development:X Exploratory:
Drlg Contractor:Rig No.14 AOGCC Rep:
Operator:Oper. Rep:
Field/Unit/Well No.:Rig Rep:
PTD No.:2230010 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:2910 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:176 ft.P
Full Recharge Time:147 Seconds P Closest Ignition Source:79 ft.P
Nitrogen Bottles (Number of):6 Outlet from Rig Substructure:168 ft.P
Avg. Pressure: 2025 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: 24 sec P
Mud System Misc:0 NA Knife Valve Open Time: 14 sec P
Diverter Misc:NA
GAS DETECTORS:Visual Alarm
Methane:P P
Hydrogen Sulfide:P P
Gas Detectors Misc:0 NA
Total Test Time:0.5 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*
AlaskaNS-Doyon14-DSMs@hilcorp.co
TEST DATA
J. Hansen / A. Carlo
phoebe.brooks@alaska.gov
Hilcorp
Test preformed with 5" HWDP, test H2S and LEL gas alarms, PVT and flow alarms, AOGCC Rep Austin McLeod waived witness to test.
Notification given 0600 hrs on 2/9/23.
0
C. Demoski / I. Toomey
0
907-670-3092
TEST DETAILS
jim.regg@alaska.gov
AOGCC.Inspectors@alaska.gov
Milne Point Unit B-38
Form 10-425 (Revised 05/2021)2023-0210_Diverter_Doyon14_MPU_B-38
Alaska LLC
J. Regg; 6/12/2023
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 Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU B-38
Hilcorp Alaska, LLC
Permit to Drill Number: 223-001
Surface Location: 638' FSL, 746' FWL, Sec. 18, T13N, R11E, UM, AK
Bottomhole Location: 576' FNL, 1284' 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. 2
Brett W. Huber.
Sr.
Digitally signed by Brett W.
Huber. Sr.
Date: 2023.02.02 12:19:36 -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: 13587' TVD: 4497'
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): 57.3' 15. Distance to Nearest Well Open
Surface: x-571820 y- 6023760 Zone- 4 23.6' to Same Pool: 180'
16. Deviated wells: Kickoff depth: 450 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 95 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' 2110'
40# L-80 TXP 4300' 2500' 2110' 6800' 4450'
8-1/2" 4-1/2" 13.5# L-80 Hyd 625 7087' 6650' 4435' 13587' 4497'
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
February 7, 2023
8728'
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 - 572 sx / T - 395 sx
5104
18. Casing Program: Top - Setting Depth - BottomSpecifications
1955
Total Depth MD (ft): Total Depth TVD (ft):
22224484
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stg 2 L - 673 sx / T - 268 sx
1511
952' FSL, 1759' FWL, Sec. 13, T13N, R10E, UM, AK
576' FNL, 1284' FWL, Sec. 14, T13N, R10E, UM, AK
81-054
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp Alaska, LLC
638' FSL, 746' FEL, Sec. 18, T13N, R11E, UM, AK ADL 047438 & 047437
MPU B-38
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)
1.11.2023
By Meredith Guhl at 10:54 am, Jan 11, 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: 2023.01.11 10:36:16 -09'00'
Monty M
Myers
FWL SFD
50-029-23743-00-00
MGR01FEB2023
SFD
DSR-1/12/23SFD 1/24/2023
* 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 3500 psi. 24 hour notice to AOGCC for opportunity
to witness.
* Approved for 30 days pre-producing with jet pump. * State witnessed MIT-IA to 2000 psi after 5 days of stabilized injection.
1511
223-001
GCW 02/02/23
JLC 2/2/2023
2/2/23
2/2/23Brett W. Huber. Sr.Digitally signed by Brett W. Huber. Sr.
Date: 2023.02.02 12:20:26 -09'00'
RBDMS JSB 020323
Notes on map
•Purple cylinder represents area within ¼
mile of proposed injector B-38
•Wellsymbols are postedat TopSchrader
OA location
•Purple wells B-28 andB-32 are Schrader
N sand laterals and do not penetrate the
Schrader OA
•B-37 wellplanis posted andis anticipated
to be drilledprior to drillingB-38
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
216-151 50-029-23570-00-00 MPU B-32 Active producer- Schrader NC N/A N/A N/A N/A N/A
Well TD'd above the OA. 9-5/8" Casing first stage cement job pumped 263 bbls of
11.7# lead cement followed by 43 bbls of 15.8 # tail cement. Plug bumped. Second
stage cement job pumped 230 bbls of 10.7# lead cement followed by 60 bbls of
15.8# tail cement. 140 bbls of cement returned to surface.
216-027 50-029-23566-00-00 MPU B-28 Active producer- Schrader ND N/A N/A N/A N/A N/A
Well TD'd above the OA zone. 9-5/8" Casing first stage cement job pumped 236 bbls
of 11.7# lead cement followed by 44 bbls of 15.8 # tail cement. Plug bumped.
Second stage cement job pumped 251 bbls of 10.7# lead cement followed by 55 bbls
of 15.8# tail cement. 90 bbls of cement returned to surface.
185-229 50-029-21450-00-00 MPU B-18 Active injector- Kuparuk 6128 4406 2450 2304 Closed
9-5/8" casing set at 6,407' MD / 4,638' TVD. The 9-5/8" casing was cemented with
1715 sacks (601 bbls) of permafrost cmt and 275 sacks (56 bbls) of class G. Estimated
cement top is 2,450' MD. Returns were lost while pumping the tail slurry. A top job
was performed with 30 sacks Perm E cement.
7" cement job was 78 bbls 15.8 ppg class G cement. Estimated TOC assuming 30
percent washout is 8,491' MD.
217-092 50-029-23579-00-00 MPU C-45 Active injector- Kuparuk 6446 4411 Surface Surface Closed
TOC at Surface. The 9-5/8" surface casing was set at 7,015' and cemented to surface
in 2017 with 224 barrels to surface.
185-269 50-029-21479-00-00 MPU C-18 P& A Injector- Kuparuk 5422 4303 Surface Surface Closed
9-5/8" set @ 5726' MD / 4574' TVD. Pumped 540 barrels of 12.3 ppg Permafrost E
with 5 lb/sak gilsonite. Pump 56 barrels of 15.8 ppg Class G with 3% NaCl and 1% CFR
2. Displaced with 5 barrels water and 434 barrels of 10.4 ppg mud. Lost returns with
250 barrels of mud pumped. Bumped plug. Performed top job with 7 barrels 15.6
ppg Permafrost C. Good cement returns to surface.
7" 9656' MD/7242' TVD - Pumped 350 sacks Class G with 1% CFR-2 and 0.3% Halad-
24, displaced with 366 barrels of 10.2 ppg brine. Bumped plug to 3000 psi, floats
held. Estimated top of cement at 8100'.
222-084 50-029-23723-00-00 MPU B-31 Active injector- Schrader OA 6393 4396 Surface Surface Open
9-5/8" set at 6,493' MD / 4,402 TVDSS. 9-5/8" casing first stage cement job was 249
bbls of 12.0 ppg Type I/II lead cement (595 sxs) followed by 78 bbls 15.8 ppg tail
cement. Plug bumped and floats held.
Second stage cement job was 349 bbls 10.7 ppg ArcticCem lead cement followed by
56 bbls 15.8 ppg tail cement. Plug bumped. ES cementer confirmed closed. 218.5
bbls cement to surface.
Area of Review MPU B-38 SB OA
Milne Point Unit
(MPU) B-38
Application for Permit to Drill
Version 1
1/10/2023
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
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1.0 Well Summary
Well MPU B-38
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 13,587’ MD / 4,497’ TVD
PBTD, MD / TVD 13,587’ MD / 4,497’ TVD
Surface Location (Governmental) 638’ FSL, 746’ FWL, Sec. 18, T13N, R11E, UM, AK
Surface Location (NAD 27) X= 571820 Y= 6023760
Top of Productive Horizon
(Governmental)952' FSL, 1759’ FWL, Sec 13, T13N, R10E, UM, AK
TPH Location (NAD 27) X= 567550 Y= 6024034
BHL (Governmental) 576' FNL, 1284' FWL, Sec 14, T13N, R10E, UM, AK
BHL (NAD 27) X= 561760 Y=6027735
AFE Drilling Days 17 days
AFE Completion Days 3 days
Maximum Anticipated Pressure
(Surface) 1511 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1955 psig
Work String 5” 19.5# S-135 DS-50 & NC 50
KB Elevation above MSL: 33.7 ft +23.6ft =57.3ft
GL Elevation above MSL: 23.6 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
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2.0 Management of Change Information
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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).
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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
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6.0 Planned Wellbore Schematic
124? See Form 401.
SFD
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7.0 Drilling / Completion Summary
MPU B-38 is a grassroots injector planned to be drilled in the Schrader Bluff OA sand. B-38 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 7th, 2023, pending rig schedule.
Surface casing will be run to 6,800’ MD / 4,450’ 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-38. 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-38 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.
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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-38 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.
be prepared for them. Gas hydrates have not been seen on B-pad.
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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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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 All wells pass with a CF greater than 1.0.
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.
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.
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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.
x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but
adjust as hole conditions dictate.
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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-38
Formations
MD
(ft)
TVD
(ft)
TVDss
(ft)
Formation Pressure
(psi)
EMW
(ppg)
BPRF 2,069 1,827 1,770
804 8.46
SV3 2,510 2,116 2,059
931 8.46
UG4 3,583 2,821 2,764
1,241 8.46
UG MB 5,609 4,119 4,062
1,812 8.46
UG MC 5,689 4,160 4,103
1,830 8.46
SB NA 6,115 4,337 4,280
1,908 8.46
SB NB 6,168 4,353 4,296
1,915 8.46
SB NC 6,245 4,373 4,316
1,924 8.46
SB ND 6,280 4,382 4,325
1,928 8.46
SB NE 6,336 4,396 4,339
1,934 8.46
SB OA target 6,674 4,444 4,387
1,955 8.46
Page 46
Milne Point Unit
B-38 SB Injector
Drilling Procedure
B-pad Data Sheet Formation Description
Page 47
Milne Point Unit
B-38 SB Injector
Drilling Procedure
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.
Page 48
Milne Point Unit
B-38 SB Injector
Drilling Procedure
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 49
Milne Point Unit
B-38 SB Injector
Drilling Procedure
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
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 All wells pass with a clearance factor greater than 1.0.
Page 50
Milne Point Unit
B-38 SB Injector
Drilling Procedure
26.0 Doyon 14 Layout
Page 51
Milne Point Unit
B-38 SB Injector
Drilling Procedure
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.
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Page 53
Milne Point Unit
B-38 SB Injector
Drilling Procedure
29.0 Casing Design
Page 54
Milne Point Unit
B-38 SB Injector
Drilling Procedure
30.0 8-1/2” Hole Section MASP
Page 55
Milne Point Unit
B-38 SB Injector
Drilling Procedure
31.0 Spider Plot (NAD 27) (Governmental Sections)
Page 56
Milne Point Unit
B-38 SB Injector
Drilling Procedure
32.0 Surface Plat (As-Staked) (NAD 27)
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1500
2250
3000
3750
4500
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-1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750
Vertical Section at 292.12° (1500 usft/in)
MPU B-38i wp07 Heel
MPU B-38i wp07 CP1
MPU B-38i wp07 CP2 MPU B-38i wp07 TDMPU B-38i wp08 CP3
MPU B-38i wp09 AC Nudge
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
500
1 0 0 0
1 5 0 0
2 0 0 0
2 5 0 0
3 0 0 0
3 5 0 0
4 0 0 0
4 5 0 0
5 0 0 0
5500
6000
6500
70
0
0
75
0
0
80
0
0
85
0
0
90
0
0
9500
10000
10500
11000
11500
12000
12500
13000
13500
13587
MPU B-38 wp09
Start Dir 3º/100' : 450' MD, 450'TVD
Start Dir 4º/100' : 850' MD, 847.08'TVD
End Dir : 1788.21' MD, 1642.61' TVD
Fault 1 : 50' Throw DTE
Start Dir 4º/100' : 5071.11' M D, 3798.26'TVD
End Dir : 6209.66' M D, 4364.39' TVD
Fault 2 : 25' Throw DTE
Start Dir 4º/100' : 6339.92' M D, 4397.36'TV D
End Dir : 6631.72' M D, 4442.07' TV D
Start Dir 2.5º/100' : 6731.72' M D, 4447.3'TVD
End Dir : 6902.77' M D, 4450.99' TVD
Start Dir 2º/100' : 8091.56' M D, 4440.04'TV D
End Dir : 8427.54' M D, 4423.55' TVD
Start Dir 2º/100' : 8951.13' M D, 4374.76'TVD
End Dir : 9737.83' M D, 4376.51' TVD
Start Dir 2º/100' : 10577.13' M D, 4422.33'TVD
End Dir : 10963.19' M D, 4437.3' TV D
Total Depth : 13587.33' M D, 4497.3' TVD
BPRF
SV3
UG4
UG3
LA3
LA2
UG MB
UG MC
SB NA SB NB
SB NCSB ND
SB NESB NF
SB OA target
Hilcorp Alaska, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: Plan: MPU B-38i
23.60
+N/-S +E/-W
Northing Easting Latitude Longitude
0.00 0.00 6023759.790 571819.610 70° 28' 30.7305 N 149° 24' 47.9727 W
SURVEY PROGRAM
Date: 2022-07-14T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
33.70 1000.00 MPU B-38 wp09 (MPU B-38) GYD_Quest GWD
1000.00 6800.00 MPU B-38 wp09 (MPU B-38) 3_MWD+IFR2+MS+Sag
6800.00 13587.33 MPU B-38 wp09 (MPU B-38) 3_MWD+IFR2+MS+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
1827.30 1770.00 2069.48 BPRF
2116.30 2059.00 2509.61 SV3
2821.30 2764.00 3583.27 UG4
3222.30 3165.00 4193.97 UG3
3885.30 3828.00 5206.18 LA3
3904.30 3847.00 5236.43 LA2
4119.30 4062.00 5608.76 UG MB
4160.30 4103.00 5689.11 UG MC
4337.30 4280.00 6114.56 SB NA
4353.30 4296.00 6168.11 SB NB
4373.30 4316.00 6244.85 SB NC
4382.30 4325.00 6280.42 SB ND
4396.30 4339.00 6335.75 SB NE
4426.30 4369.00 6481.06 SB NF
4444.30 4387.00 6674.40 SB OA target
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU B-38i, True North
Vertical (TVD) Reference:MPU B-38 as built rkb @ 57.30usft
Measured Depth Reference:MPU B-38 as built rkb @ 57.30usft
Calculation Method: Minimum Curvature
Project:Milne Point
Site:M Pt B Pad
Well:Plan: MPU B-38i
Wellbore:MPU B-38
Design:MPU B-38 wp09
CASING DETAILS
TVD TVDSS MD Size Name
4450.04 4392.74 6800.00 9-5/8 9 5/8" x 12 1/4"
4497.30 4440.00 13587.33 4-1/2 4 1/2" x 8 1/2"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00
2 450.00 0.00 0.00 450.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 450' MD, 450'TVD
3 850.00 12.00 280.00 847.08 7.25 -41.10 3.00 280.00 40.81 Start Dir 4º/100' : 850' MD, 847.08'TVD
4 1788.21 48.96 264.05 1642.61 -13.24 -505.78 4.00 -19.89 463.59 End Dir : 1788.21' MD, 1642.61' TVD
5 5071.11 48.96 264.05 3798.26 -269.96 -2968.45 0.00 0.00 2648.43 Start Dir 4º/100' : 5071.11' MD, 3798.26'TVD
6 6050.79 69.00 304.00 4315.78 -43.65 -3745.56 4.00 71.58 3453.56 MPU B-38i wp09 AC Nudge
7 6209.66 75.34 304.40 4364.39 41.32 -3870.57 4.00 3.50 3601.36 End Dir : 6209.66' MD, 4364.39' TVD
8 6339.92 75.34 304.40 4397.36 112.52 -3974.56 0.00 0.00 3724.51 Start Dir 4º/100' : 6339.92' MD, 4397.36'TVD
9 6631.72 87.00 305.00 4442.07 276.40 -4211.19 4.00 2.96 4005.43 End Dir : 6631.72' MD, 4442.07' TVD
10 6731.72 87.00 305.00 4447.30 333.68 -4292.99 0.00 0.00 4102.78 MPU B-38i wp07 Heel Start Dir 2.5º/100' : 6731.72' MD, 4447.3'TVD
11 6902.77 90.53 302.58 4450.99 428.77 -4435.08 2.50 -34.45 4270.21 End Dir : 6902.77' MD, 4450.99' TVD
12 8091.56 90.53 302.58 4440.04 1068.91 -5436.74 0.00 0.00 5439.16 Start Dir 2º/100' : 8091.56' MD, 4440.04'TVD
13 8383.72 94.47 306.90 4427.30 1235.16 -5676.49 2.00 47.50 5723.86 MPU B-38i wp07 CP1
14 8427.54 95.35 306.90 4423.55 1261.38 -5711.40 2.00 -0.05 5766.08 End Dir : 8427.54' MD, 4423.55' TVD
15 8951.13 95.35 306.90 4374.76 1574.38 -6128.30 0.00 0.00 6270.14 Start Dir 2º/100' : 8951.13' MD, 4374.76'TVD
16 9218.46 90.00 306.90 4362.30 1734.65 -6341.76 2.00 179.99 6528.24 MPU B-38i wp07 CP2
17 9737.83 86.87 296.99 4376.51 2009.00 -6781.69 2.00 -107.62 7039.08 End Dir : 9737.83' MD, 4376.51' TVD
18 10577.13 86.87 296.99 4422.33 2389.34 -7528.47 0.00 0.00 7874.11 Start Dir 2º/100' : 10577.13' MD, 4422.33'TVD
19 10963.19 88.69 304.50 4437.30 2586.42 -7859.76 2.00 76.54 8255.22 MPU B-38i wp08 CP3 End Dir : 10963.19' MD, 4437.3' TVD
20 13587.33 88.69 304.51 4497.30 4072.49 -10021.72 0.00 92.65 10817.58 MPU B-38i wp07 TD Total Depth : 13587.33' MD, 4497.3' TVD
-1800
-1200
-600
0
600
1200
1800
2400
3000
3600
4200
4800
5400
So
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(
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N
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-10800 -10200 -9600 -9000 -8400 -7800 -7200 -6600 -6000 -5400 -4800 -4200 -3600 -3000 -2400 -1800 -1200 -600 0 600
West(-)/East(+) (1200 usft/in)
MPU B-38i wp09 AC Nudge
MPU B-38i wp08 CP3
MPU B-38i wp07 TD
MPU B-38i wp07 CP2
MPU B-38i wp07 CP1
MPU B-38i wp07 Heel
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
1000
150
0
1
7
5
0
2
00
0
2
25
0
2
50
0
27
5
0
30
0
0
32
5
0
35
0
0
37
5
0
40004250
4497
MPU B-38 wp09
Start Dir 3º/100' : 450' MD, 450'TVD
Start Dir 4º/100' : 850' MD, 847.08'TVD
End Dir : 1788.21' MD, 1642.61' TVD
Fault 1 : 50' Throw DTE
Start Dir 4º/100' : 5071.11' MD, 3798.26'TVD
End Dir : 6209.66' MD, 4364.39' TVD
Fault 2 : 25' Throw DTE
Start Dir 4º/100' : 6339.92' MD, 4397.36'TVD
End Dir : 6631.72' MD, 4442.07' TVD
Start Dir 2.5º/100' : 6731.72' MD, 4447.3'TVD
End Dir : 6902.77' MD, 4450.99' TVD
Start Dir 2º/100' : 8091.56' MD, 4440.04'TVD
End Dir : 8427.54' MD, 4423.55' TVD
Start Dir 2º/100' : 8951.13' MD, 4374.76'TVD
End Dir : 9737.83' MD, 4376.51' TVD
Start Dir 2º/100' : 10577.13' MD, 4422.33'TVD
End Dir : 10963.19' MD, 4437.3' TVD
Total Depth : 13587.33' MD, 4497.3' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4450.04 4392.74 6800.00 9-5/8 9 5/8" x 12 1/4"
4497.30 4440.00 13587.33 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site: M Pt B Pad
Well: Plan: MPU B-38i
Wellbore: MPU B-38
Plan: MPU B-38 wp09
WELL DETAILS: Plan: MPU B-38i
23.60
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00
6023759.790 571819.610 70° 28' 30.7305 N 149° 24' 47.9727 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU B-38i, True North
Vertical (TVD) Reference: MPU B-38 as built rkb @ 57.30usft
Measured Depth Reference:MPU B-38 as built rkb @ 57.30usft
Calculation Method:Minimum Curvature
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0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125
Measured Depth (750 usft/in)
MPB-23
MPB-28
MPU B-32
MPU B-32 PB1
MPU B-35
MPU B-37 wp09
No-Go Zone - Stop Drilling
Collision Avoidance Required
Collision Risk Procedures Req.
WELL DETAILS:Plan: MPU B-38i NAD 1927 (NADCON CONUS)Alaska Zone 04
23.60
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6023759.790 571819.610
70° 28' 30.7305 N 149° 24' 47.9727 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU B-38i, True North
Vertical (TVD) Reference: MPU B-38 as built rkb @ 57.30usft
Measured Depth Reference:MPU B-38 as built rkb @ 57.30usft
Calculation Method:Minimum Curvature
SURVEY PROGRAM
Date: 2022-07-14T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
33.70 1000.00 MPU B-38 wp09 (MPU B-38) GYD_Quest GWD
1000.00 6800.00 MPU B-38 wp09 (MPU B-38) 3_MWD+IFR2+MS+Sag
6800.00 13587.33 MPU B-38 wp09 (MPU B-38) 3_MWD+IFR2+MS+Sag
0.00
30.00
60.00
90.00
120.00
150.00
180.00
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0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125
Measured Depth (750 usft/in)
MPB-07
MPB-08
MPB-11
MPB-18
MPU B-35
MPU B-36
MPU B-40 wp06
GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
33.70 To 13587.33
Project: Milne Point
Site: M Pt B Pad
Well: Plan: MPU B-38i
Wellbore: MPU B-38
Plan: MPU B-38 wp09
Ladder / S.F. Plots
1 of 2
CASING DETAILS
TVD TVDSS MD Size Name
4450.04 4392.74 6800.00 9-5/8 9 5/8" x 12 1/4"
4497.30 4440.00 13587.33 4-1/2 4 1/2" x 8 1/2"
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6750 7125 7500 7875 8250 8625 9000 9375 9750 10125 10500 10875 11250 11625 12000 12375 12750 13125 13500
Measured Depth (750 usft/in)
MPB-28
MPU B-32MPU B-32 PB1
MPU B-37 wp09
MPU B-39 wp08
MPU B-40 wp06
MPC-16
MPU C-45
No-Go Zone - Stop Drilling
Collision Avoidance Required
Collision Risk Procedures Req.
WELL DETAILS:Plan: MPU B-38i NAD 1927 (NADCON CONUS)Alaska Zone 04
23.60
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6023759.790 571819.610 70° 28' 30.7305 N 149° 24' 47.9727 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU B-38i, True North
Vertical (TVD) Reference: MPU B-38 as built rkb @ 57.30usft
Measured Depth Reference:MPU B-38 as built rkb @ 57.30usft
Calculation Method:Minimum Curvature
SURVEY PROGRAM
Date: 2022-07-14T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
33.70 1000.00 MPU B-38 wp09 (MPU B-38) GYD_Quest GWD
1000.00 6800.00 MPU B-38 wp09 (MPU B-38) 3_MWD+IFR2+MS+Sag
6800.00 13587.33 MPU B-38 wp09 (MPU B-38) 3_MWD+IFR2+MS+Sag
0.00
30.00
60.00
90.00
120.00
150.00
180.00
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6750 7125 7500 7875 8250 8625 9000 9375 9750 10125 10500 10875 11250 11625 12000 12375 12750 13125 13500
Measured Depth (750 usft/in)
GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference
33.70 To 13587.33
Project: Milne Point
Site: M Pt B Pad
Well: Plan: MPU B-38i
Wellbore: MPU B-38
Plan: MPU B-38 wp09
Ladder / S.F. Plots
2 of 2
CASING DETAILS
TVD TVDSS MD Size Name
4450.04 4392.74 6800.00 9-5/8 9 5/8" x 12 1/4"
4497.30 4440.00 13587.33 4-1/2 4 1/2" x 8 1/2"
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in 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.
Milne Point Unit
223-001
Schrader Bluff Oil
MPU B-38
WELL PERMIT CHECKLIST
Company Hilcorp Alaska, LLC
Well Name:MILNE PT UNIT B-38
Initial Class/Type SER / PEND GeoArea 890 Unit 11328 On/Off Shore On
Program SERField & Pool Well bore seg
Annular DisposalPTD#:2230010
MILNE POINT, SCHRADER BLFF OIL - 525140
NA1 Permit fee attached
Yes Surface Location lies within ADL0047438; Top Prod Int & TD lie within ADL0047437.2 Lease number appropriate
Yes3 Unique well name and number
Yes Milne Point Schrader Bluff Oil Pool (525140), governed by CO 477, amended by CO 477.05.4 Well located in a defined pool
Yes5 Well located proper distance from drilling unit boundary
Yes6 Well located proper distance from other wells
Yes7 Sufficient acreage available in drilling unit
Yes8 If deviated, is wellbore plat included
Yes9 Operator only affected party
Yes10 Operator has appropriate bond in force
Yes11 Permit can be issued without conservation order
Yes12 Permit can be issued without administrative approval
Yes13 Can permit be approved before 15-day wait
Yes Area Injection Order No. 10-B14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For
Yes MPU KR B-18 (185-229), MPU B-31 (222-084), MPU B-37 (222-153), MPU KR C-18 (185-269),15 All wells within 1/4 mile area of review identified (For service well only)
Yes MPU C-45 (217-092)16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)
NA Well will be pre-produced for 30 days17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)
Yes 20" 129.5# X-52 Conductor set to 106'18 Conductor string provided
Yes 9-5/8" surface casing set horizontally in the reservoir. Fully cemented.19 Surface casing protects all known USDWs
Yes 9-5/8" surface casing set horizontally in the reservoir. Fully cemented.20 CMT vol adequate to circulate on conductor & surf csg
Yes 9-5/8" surface casing set horizontally in the reservoir. Fully cemented.21 CMT vol adequate to tie-in long string to surf csg
Yes 9-5/8" surface casing set horizontally in the reservoir. Fully cemented.22 CMT will cover all known productive horizons
Yes23 Casing designs adequate for C, T, B & permafrost
Yes Doyon 14 has adequate tankage and good trucking support.24 Adequate tankage or reserve pit
NA This is a grass roots well.25 If a re-drill, has a 10-403 for abandonment been approved
Yes Halliburton collision scan recognizes no close approaches.26 Adequate wellbore separation proposed
Yes 16" diverter27 If diverter required, does it meet regulations
Yes All fluids overbalanced to pore pressure.28 Drilling fluid program schematic & equip list adequate
Yes 1annular, 3 ram, 1 flow cross tested to 3000 psi.29 BOPEs, do they meet regulation
Yes 5000 psi stack tested to 3000 psi30 BOPE press rating appropriate; test to (put psig in comments)
Yes31 Choke manifold complies w/API RP-53 (May 84)
Yes32 Work will occur without operation shutdown
No No H2S anticipated.33 Is presence of H2S gas probable
Yes34 Mechanical condition of wells within AOR verified (For service well only)
Yes H2S not anticipated from drilling of offset wells; however, rig has H2S sensors and alarms.35 Permit can be issued w/o hydrogen sulfide measures
Yes Planned mud program appears adequate to control operator's forecast formation pressures.36 Data presented on potential overpressure zones
NA Managed Pressure Drilling will be used to monitor and mitigate any abnormal pressure encountered.37 Seismic analysis of shallow gas zones
NA Other mitigation measures are discussed in drilling hazards section on pages 47-49.38 Seabed condition survey (if off-shore)
NA39 Contact name/phone for weekly progress reports [exploratory only]
Appr
SFD
Date
1/24/2023
Appr
MGR
Date
2/1/2023
Appr
SFD
Date
1/24/2023
Administration
Engineering
Geology
Geologic
Commissioner:Date:Engineering
Commissioner:Date Public
Commissioner Date
JLC 2/2/2023
