Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout222-153DA
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By James Brooks at 9:12 am, Feb 27, 2023
Completed
2/8/2023
JSB
RBDMS JSB 030223
G
DSR-3/3/23MGR02AUG2023
2.24.2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.02.24 22:14:38 -09'00'
Monty M
Myers
_____________________________________________________________________________________
Edited By: JNL 2/15/2023
SCHEMATIC
Milne Point Unit
Well: MPU B-37
Last Completed: 2/8/2023
PTD: 222-153
TD =13,025’(MD) / TD =4,477’(TVD)
5
20”
Orig. KB Elev.: 57.03’ / GL Elev.: 22.8’
7”
3
7
9-5/8”
1
2
4
See
Screen
Liner
Detail
PBTD =13,023’(MD) / PBTD = 4,477’(TVD)
9-5/8” ‘ES’
Cementer
@ 2,261’
6
4-1/2”
Shoe @
13,023’
8
10
12
9
4-1/2”
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X56 / Weld N/A Surface 114’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,243’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 2,243’ 6,511’ 0.0758
7” Tieback 26 / L-80 / TXP 6.276 Surface 6,334’0.0383
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 6,321’ 13,025’ 0.0149
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / TXP 3.958 Surface 6,321’ 0.0152
OPEN HOLE / CEMENT DETAIL
Driven 20” Conductor
12-1/4"Stg 1 Lead – 565 sx / Tail – 400 sx
Stg 2 Lead – 572 sx / Tail 270 sx
8-1/2” Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 336’
90° Hole Angle = @ 6,867’
TREE & WELLHEAD
Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: 50-029-23740-00-00
Completion Date: 2/8/2023
JEWELRY DETAIL
No. MD Item ID
1 Surface 4-1/2” TCII Tubing Hanger 4.500”
2 5,924’ Viking Sliding Sleeve (opens down) 3.813”
3 5,985’ X Nipple 3.813”
4 6,048’ Baker Zenith Gauge Carrier 3.865”
5 6,116’ Baker Retrievable Packer 3.880”
6 6,186’ XN Nipple, 3.813”, 3.725” No Go 3.725”
7 6,280’ WLEG/Mule Shoe 3.958”
8 6,321’ SLZXP Liner Top Packer 6.190”
9 6,343’ 7” H563 x 4.5” TSH 625 XO 3.820”
10 13,023’ Shoe 3.970”
4-1/2”SCREENS LINER DETAIL
Jts Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
153 6554’ 4434’ 12985’ 4472’
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:MPU B-37 Date:1/29/2023
Csg Size/Wt/Grade:9.625", 40# & 47#, L-80 Supervisor:Yessak/Vanderpool
Csg Setting Depth:6511 TMD 4425 TVD
Mud Weight:9.25 ppg LOT / FIT Press =632 psi
.
LOT / FIT =12.00 Hole Depth =6536 md
Fluid Pumped=1.30 Bbls Volume Back =1.30 bbls
Estimated Pump Output:0.101 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->00 ->00
->142 ->5 283
->3 104 ->10 578
->6 272 ->15 839
->7 325 ->20 1105
->8 387 ->25 1367
->9 449 ->30 1635
->10 494 ->35 1922
->11 543 ->40 2229
->12 593 ->45 2525
->13 636 ->48 2732
-> ->
-> ->
-> ->
Enter Holding Enter Holding Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0 636 ->0 2732
->1 580 ->5 2707
->2 552 ->10 2700
->3 528 ->15 2694
->4 509 ->20 2689
->5 494 ->25 2684
->6 481 ->26 2682
->7 472 ->27 2681
->8 463 ->28 2680
->9 457 ->29 2679
->10 452 ->30 2679
->11 447 ->
->12 445 ->
->13 441 ->
->14 437
->15 434
->
0
1
3
6
7
8
9
10
11
12
13
0
5
10
15
20
25
30
35
40
45
48
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
)
636
580552528509494481472463457452447445441437434
2732 2707 2700 2694 2689 268426822681268026792679
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
1/18/2023 Locate surface riser and cellar trolley cart, remove from snow drifts. Spot wellhead equipment, Tree, MPD orbit valve, knife valve and surface riser behind the Well.
Install Diverter Tee onto Well. Move Rig and spot over B-37. Install the diverter annular onto the diverter tee. Center Rig over Well and shim Level. Secure stairs
and landings. PJSM. Skid rig floor into the drilling position. Spot Rig Matts for Rockwasher. Secure roof top landings and air heater/boiler exhaust stacks. Work on
Rig Acceptance Checklist.
1/19/2023 Install knife valve & begin installing diverter line. Landing ring was installed for Innovation rig RKB in 2016 & diverter line was too low - cut out 1" square tube from
cellar wall opening for clearance. Melt snow and ice from cellar. Sim-ops: Begin loading 5" drill pipe in the pipe shed. Spot service buildings and fuel tank trailer.
Milne electricians hooked up highline and on highline power at 11:15. Install 4" valves on conductor. Install 60' of diverter line and 45 deg elbow. Set containment &
spot rockwasher cuttings tank. Load 8,300 gallons of diesel. Start loading 5" DP in shed. Sim-ops: NOV/Totco technicians changed drawworks encoder cable. Rig
accepted at 15:00. Spot Rockwasher. Install koomey lines on surface bag. Load BHA into shed. N/U riser on surface bag. Perform pre-spud Derrick inspection.
Continue load 5" DP into shed. SimOps: Work on removing links from #1 conveyor and clear ice build up from #2 conveyor. Mobilize saversub, Bit & XO to rig floor.
Change out Saver sub and inspect grabber dies. Spot water uprights & hook up pump house lines. Install rockwasher extension lines for supersuckers. SimOps:
Continue work on removing links from #1 conveyor. Attempt to charge accumulator and air pump stopped working after 1000 psi charge. Troubleshoot and call out
rig mechanic to C/O pump. Continue N/U diverter line - Removing snowpack from pipe sections. P/U 2x jts 5" HWDP and RIH, tag up on ice at 37'. Calibrate block
height & service topdrive. Finish change out accumulator air pump and function test. Continue conveyor work.
1/20/2023 Finished installing the diverter line. Begin loading mud into the pits. P/U 17 joints of 5" HWDP and jars, racking back 6 stands in the derrick. Perform diverter
function test. Knife valve open = 17 sec and Diverter close = 21 sec. System = 2950 PSI, After closure = 1800 PSI, 200 PSI recharge = 36 sec, Full recovery = 152
sec. Test gas alarms, PVT and flow alarms - #1 mud pit PVT sensor fail/pass. MD/Totco repaired wire and sensor working correctly. Initial test notification made at
15:08 on 18 Jan 2023. AOGCC inspector McLeod waived the right to witness at 17:11 on 19 Jan 2023. M/U 12-1/4" rerun Baker VDM mill tooth bit, 8" Sperry mud
motor set at 1.5 AKO, bottle neck XO to 35'. Finish stocking hopper room with mud product, prime mud pumps, function test conveyors & alarms. Finished loading
580 bbls of mud in the pits. Spot super sucker and vac truck and hook up to rock washer. Fill stack and mud lines with water - no leaks. Pressure test mud lines to
3800 PSI - good. Pre-spud with all personnel on location. Discuss muster areas and ensure everyone was on the roster or signed in at the rig. Discuss drilling
hazards and diverter response. Function test rig evacuation alarm - good. Drill ice in conductor with fresh water from 37' to 114'. 400 GPM = 360 PSI & 40 RPM =
1k ft/lbs TQ. Ream back to 40' and trip down with no issues. Pull mouse hole extension to thaw drilled mousehole with steam line. Drill 12-1/4" surface hole from
114' to 219', 115' drilled, 57'/hr AROP. 400 GPM = 380 PSI & 40 RPM = 1k ft/lbs TQ, WOB = 3k. MW = 8.8 ppg & vis = 300+. BROOH from 219' to 128'. POOH on
elevators from 128' to 35'. Blow down top drive. POOH from 35' and L/D bit. Cleanout bit graded 1-1-WT-A-E-3-NO-BHA. PJSM. M/U 12-1/4" Kymera to motor,
M/U, GWD, DM, EWR/DGR/PWD, ILS & TM tools from 33' to 97'. Initialize and download MWD tools.P/U three non-mag flex drill collars to 189'. Make up XO & Std
HWDP. Establish drilling parameters, shallow test MWD, wash to bottom @ 219', 400 GPM, 750 psi. No fill encountered. Obtain first Gyro Svy @ 155'. Drill 12-1/4"
hole from 219' to 324' (324' TVD). Drilled 105' = 42/hr AROP. 400 GPM = 760 PSI, 40 RPM = 1-2K Tq, WOB = 2-5K. MW = 8.9, Vis = 300, ECD = 9.43. PU = 60,
SO = 65k, ROT = 63k. Target 3 deg/100' BUR. Drill 12-1/4" hole from 324' to 869' (857' TVD). Drilled 545' = 90.83/hr AROP. 400 GPM = 1050 PSI, 40 RPM = 3-
5K Tq, WOB = 10-15K. MW = 9.2, Vis = 266, ECD = 9.6. PU = 82, SO = 85k, ROT = 85k. Target 3 deg/100' BUR. Last Gyro survey at 807.64 MD / 799.17 TVD,
17.64 inc, 276.07 azm, 10.46 from plan, 10.36 High and 1.48 Right. Put Rig on Gen power at 05:55, to prevent interference with MPU turbine testing. Daily disposal
to G&I = 82 bbls. Total disposal to G&I = 92 bbls. Daily water hauled from 6 mile = 640 bbls. Total water hauled from 6 mile = 640 bbls. Daily fluid loss = 87 bbls.
Total fluid loss = 87 bbls.
1/21/2023 Drill 12-1/4" surface hole from 869' to 1,417' (1,351' TVD). Drilled = 548' drilled = 91.33'/hr AROP. 400 GPM = 1180 PSI, 60 RPM = 4-6k TQ, WOB = 7-15k. MW =
9.2 ppg, Vis = 181, ECD = 9.87. PU = 93k, SO = 94k, ROT = 95k. 3/100' build section. Last gyro survey at 1,283'. Drill 12-1/4" hole from 1417' to 1893' (1701'
TVD), 476' drilled, 79.33'/hr AROP. 450 GPM = 1220 PSI, 60 RPM = 4-5K TQ, WOB = 10-14K. MW = 9.3, Vis = 213, ECD = 10.99 Max Gas = 7u. PU = 98K, SO =
90K, ROT = 90K. Continue 3/100' build section. Rig back on highline power at 14:00. MPU Fire Department performed walk through of Rig with the Toolpusher.
Drill 12-1/4" hole from 1893' to 2367' (1992' TVD), 474' drilled, 79'/hr AROP. 450 GPM = 1200 PSI, 60 RPM = 5-7K TQ, WOB = 3-5K. MW = 9.3, Vis = 181, ECD =
10.56 Max Gas = 26u. PU = 115K, SO = 85K, ROT = 95K. EOB @ 1987', start 51.58 deg inc tangent. BOPF logged at 2,058 MD / 1,808 TVD. Drill 12-1/4" hole
from 2367' to 3005' (2395' TVD), 638' drilled, 106.33'/hr AROP. 525 GPM = 1360 PSI, 80 RPM = 6-9K TQ, WOB = 3-5K. MW = 9.45, Vis = 151, ECD = 10.40 Max
Gas = 1745u. PU = 124K, SO = 90K, ROT = 106K. High vis sweep at 2652', returned on time with no increase in cuttings. Last Survey, 2866.20' MD / 2318.62'
TVD, 50.57' inc, 289.03 azm, 27.07' from plan, 26.68' High and 4.55' Left. Daily disposal to G&I = 1730 bbls. Total disposal to G&I = 1822 bbls. Daily water hauled
from 6 mile = 1595 bbls. Total water hauled from 6 mile = 2235 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 87 bbls.
1/22/2023 Drill 12-1/4" hole from 3,005' to 3,700' (2,838' TVD), 695' drilled, 115.83'/hr AROP. 525 GPM = 1750 PSI, 80 RPM = 7-8K TQ, WOB = 6-10K. MW = 9.5 ppg, Vis =
158, ECD = 10.7, Max gas = 183u. PU = 130K, SO = 96K, ROT = 115K. High vis sweep at 3,605' back on time w/ 10% increase. Logged SV1 at 3,203' MD / 2,524'
TVD and Ugnu UG4 at 3,654' MD / 2,809' TVD. Drill 12-1/4" hole from 3700' to 4365' (3247' TVD), 665' drilled, 110.83'/hr AROP. 525 GPM = 1890 PSI, 80 RPM =
10-12K TQ, WOB = 10-15K. MW = 9.5, Vis = 132, ECD = 10.27 Max Gas = 132u. PU = 150K, SO = 103K, ROT = 122K. Drill 12-1/4" hole from 4365' to 4745'
(3484' TVD), 380' drilled, 63.33'/hr AROP. 550 GPM = 2010 PSI, 80 RPM = 10-15K TQ, WOB = 10-15K. MW = 9.5, Vis = 124, ECD = 10.22 Max Gas = 92u. PU =
160K, SO = 103K, ROT = 124K. High vis sweep at 4651, returned on time with no increase in cuttings. Drill 12-1/4" hole from 4745' to 5345' (3862' TVD), 600'
drilled, 100'/hr AROP. 540 GPM = 2150 PSI, 80 RPM = 12-14K TQ, WOB = 10-15K. MW = 9.5, Vis = 124, ECD = 10.50 Max Gas = 256u. PU = 170K, SO = 106K,
ROT = 131K. Start pretreating system with screenkleen @ 5000' MD in preparation for L&M sands. Targeting 1% addition. Last Survey, 5265.29' MD / 3810.75'
TVD, 49.78 inc, 290.16 azm, 9.00' from plan, 7.78' High and 4.38' Left. Daily disposal to G&I = 1350 bbls. Total disposal to G&I = 3172 bbls. Daily water hauled
from 6 mile = 1455 bbls. Total water hauled from 6 mile = 3690 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 87 bbls.
50-029-23740-00-00API #:
Well Name:
Field:
County/State:
MP B-37
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
1/20/2023Spud Date:
1/23/2023 Drill 12-1/4" hole from 5,345' to 5,888' (4,197' TVD), 543' drilled, 90.5'/hr AROP. 525 GPM = 1860 PSI, 80 RPM = 13K TQ, WOB = 11-16K. MW = 9.5 ppg, Vis =
102, ECD = 10.14, Max gas = 471u. PU = 185K, SO = 110K, ROT = 145K. Begin 4 deg build & turn at 5,732'. Drill 12-1/4" hole from 5888' to 6269' (4365' TVD),
381' drilled, 63.5'/hr AROP. 540 GPM = 2070 PSI, 80 RPM = 16-18K TQ, WOB = 5-12K. MW = 9.3, Vis = 127, ECD = 9.96 Max Gas = 233u
PU = 190K, SO = 105K, ROT = 141K. Drill 12-1/4" hole from 6269' to 6516' at TD in the SB_NE sand (4426' TVD), 247' drilled, 49.4'/hr AROP. 540 GPM = 1950
PSI, 80 RPM = 15-20K TQ, WOB = 10-15K. MW = 9.3, Vis = 66, ECD = 9.89, Max gas = 398u. PU = 187K, SO = 103K, ROT = 137K. Continue with 4 deg right
turn and build to TD. The SB_NE sand top logged @ 6378' MD (4397' TVD). Final survey at 6464.15 MD, 4416.57 TVD, Inc 77.97, Az 299.77, Distance to Plan =
21.46' Total, 5.27' Low, 20.81' Right. Pump 30 bbl high vis sweep. Rack 2 stands back to 6269' circulating sweep around cleaning up the wellbore at 540 GPM,
1900 psi, 80 rpm, 18k Tq. Sweep back 200 stks late with 10% increase. Condition the mud, 9.3 ppg MW, 59 vis, YP at 23. Wash from 6269' back to bottom, no fill.
Flow check the well, static. BROOH from 6516' to 4675' pulling 5-10 minutes/stand slowing as needed to clean slides/tight spots
550-500 GPM = 1550 psi, 80 RPM = 10-20K ft-bs Tq, Max Gas = 126 units. PU = 170K, SO = 100K, ROT = 125K. Daily disposal to G&I = 1948 bbls. Total
disposal to G&I = 5120 bbls. Daily water hauled from 6 mile = 1855 bbls. Total water hauled from 6 mile = 5545 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 87
bbls.
1/24/2023 BROOH from 4,675' to 2,085', pulling 5-10 minutes/stand slowing as needed to clean slides/tight spots. 500-515 GPM = 1490 PSI, 80 RPM = 6-9K ft-lbs TQ, Max
gas = 61u. PU = 140K, SO = 80K, ROT = 95K. Increase YP to 25 at 2,500' to aid in cleaning/stabilizing the permafrost. Circulate a bottoms up while pulling 2
stands from 2,274' to 2,085', no increase at shakers. BROOH from 2,085' to 753', pulling 5-10 minutes/stand slowing as needed to clean slides/tight spots.
Circulate one bottoms up per stand while pulling from 944 to HWDP at 753'. The hole unloaded on first bottoms up. Perform flow check - static. POOH from 753' to
189' racking back HWDP, blow down top drive after the 1st two stands. L/D XO and 3 NM flex drill collars to 97'. Read MWD tools and L/D remaining BHA. 12 1/4''
bit grade, PDC= 1-1-CT-G-X-I-NO-TD, Tri-cone = 1-1-WT-A-E-I-NO-TD. Total losses BROOH= 105. Clear and clean the rig floor, jet and cleanout flowline. Monitor
well with trip tank, loss rate 3 bph. Load tools to the floor. RU the volante tool, bail extensions, 9-5/8'' handling equipment and DDI casing tongs. Ready FOSV and
crossover. Loss rate at 3 BPH. PJSM. MU 9-5/8", 40#, L-80, TXP-BTC shoe track. Bakerlok connections 1-4 with 21K ft-lbs Tq. HES rep installed "top hat" above
float collar. Pump through shoe track and check floats (good). RIH with 9-5/8", 40# casing from 167' to 2211'. PU = 125K & SO = 88K. TQ = 21K ft-lbs with Volant
tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally. Lost 56 bbls during trip. Daily disposal to G&I = 980 bbls. Total disposal to G&I = 6100
bbls. Daily water hauled from 6 mile = 985 bbls. Total water hauled from 6 mile = 6530 bbls. Daily fluid loss = 182 bbls. Total fluid loss = 269 bbls.
1/25/2023 Stage up pumps to 6 BPM, 180 PSI. Circulate a bottoms up while reciprocating 20'. PU = 125K, SO = 88K. 18.8 bbls lost while circulating. RIH with 9-5/8", 40#
casing from 2,211' to 4,230'. TQ = 21K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally. M/U ES cementer to 4,268',
thread lock top & bottom connections. PU = 215K & SO = 95K. Losses 6.75 BPH avg. RIH with 9-5/8", 47# casing from 4268' to 5093'. TQ = 21K ft-lbs with Volant
tool. Fill on the fly and top off every 10 joints. Installing centralizer per tally. PU = 260K & SO = 110K. Losses 9.3 BPH avg. Circulate a bottoms up, stage pumps up
to 6 BPM, 400 psi. Initial losses at 15 BPH slowing to 8 BPH. Run one jt 47# casing from 5093' to 5135'. Hyd hose on pipe skate failed. Troubleshoot and prep to
replace. Call out Rig Mechanic and remove failed hyd hose. Install new hose and test operation - Good. Circulate 2.5 BPM, 120 psi. Reciprocate string 18-36' while
skate repairs done. Losses at 6 BPH. RIH with 9-5/8", 47# casing from 5135' to 6511' on depth washing last 2 jts down @ 2.5 bpm, verify pipe count. TQ 47# to
24K ft-lbs, Fill on the fly, top off every 10 joints. P/U 330K, S/O 125K. Loss rate 3 bph, 126 bbls total loss while running csg. Stage pumps slowly from 2 BPM to 6
BPM = 270 psi, work string from 6511' to 6461'. Set TD Tq at 18K, establish rotation at 5 RPM while working pipe. Spot and R/U cementers. Condition mud for
cementing, Final 6 BPM = 240 psi with MW 9.4 ppg, YP = 15. Attempt to blow down top drive discovering bleeder line frozen. Cont. circulating while thawing out
bleeder. P/U 310K, S/O 125K, ROT 150K, 6 BPM= 240 PSI. Daily disposal to G&I = 119 bbls. Total disposal to G&I = 6219 bbls. Daily water hauled from 6 mile =
255 bbls. Total water hauled from 6 mile = 6785 bbls. Daily fluid loss = 182 bbls. Total fluid loss = 269 bbls.
1/26/2023 Breakout volante and re-dope cup. Continue to circulate, Hold PJSM with all parties involved. Pump 50 bbls mud treated with desco, Blow air to dement unit, line up
cementers. HES warm up and fill lines with 5 bbls fresh water. PT surface lines to 1,000/4,000 psi, good test. Pump 1st stage cement job: Mix & pump 60 bbls of 10
ppg tuned spacer with 4# red dye & 5# Pol-E-Flake in 1st 10 bbls at 3.5 BPM = 150 psi. Drop bypass plug. Mix and pump 236 bbls of 12.0 ppg lead cement (Type I-
II cement, 2.347ft^3/sk yield, 565 sks total) at 5.5 BPM = 450 psi. Mix & pump 82 bbls 15.8 ppg Premium G tail cement (1.156 ft^3/sk yield, 400 sks total) at 4 BPM
= 580 psi. Rotate 1-2 RPM = 18K TQ & reciprocate 20'. Drop shutoff plug. HES pump 20 bbls water at 4.7 BPM = 180 psi. Displace with 283 bbls (2802 strokes)
9.45 ppg spud mud from rig at 6 BPM = 300 psi. Displace with 80 bbls 9.4 ppg Tuned Spacer from HES at 4.25 BPM = 460 psi. Continue to displace with 9.45 ppg
mud from the rig at 5 BPM = 630 psi ICP, slow to 4 bpm for last 10 bbls, FCP 900 psi. Rotated and reciprocated until 25 bbls into Tuned spacer. Bumped plugs at
3,734 strokes (2.9 bbls early). Pressured up to 1,400 psi, hold for 5 minutes, bleed off pressure, check floats and floats held. Pressure up to 3,490 psi to shift the ES
cementer open. CIP at 10:05. 16 bbl losses cementing and displacing. Pump through ES cementer at 2,263' at 4.5 BPM = 300 psi. Dumped 60 bbls of tuned
spacer, 55 bbls cement and 25 bbls of clabbered mud before diverting returns back to the pits. circulate total of 5 BU. Disconnect knife valve from accumulator.
Drain stack and flush with black water two times. Re-connect knife valve to the accumulator. Continue to circulate through the ESC at 2,263' pumping 5 BPM = 230
psi while prepping for 2nd stage. Break out, inspect and MU the Volant tool. Clean the suction screens. Continue to circulate through the ES cementer at 3 BPM =
120 psi. HES warming up cementing equipment. PJSM. 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 = 300 psi. Mix & pump total 294 bbls 10.7 ppg Arctic Cem lead
cement (572 sx at 2.883 ft^3/sk yield) at 5.2 BPM, ICP= 440, FCP= 600 psi. At 240 bbls pumped start seeing spacer interface returns, dump returns to rock washer.
At 310 bbls pumped start seeing cement interface returns. Mix & pump 56 bbls of 15.8 ppg Premium G tail cement (270 sx at 1.17 ft^3/sk yield) at 3.6 BPM= 480
psi. Drop the closing plug. Pump 20 bbls of 8.34 ppg fresh water at 5 BPM = 235 psi. Displace with 144.73 bbls 9.4 ppg spud mud at 6 BPM = 450 psi ICP, last 10
bbls slow to 3 BPM = 500 psi FCP. Bumped the plug at 1433 strokes, 1.0 bbls under calculated, CIP at 22:50. 60 BBLS spacer, 45 bbls of interface and 205 bbls
good 10.7 ppg cement returned, 100% returns during job. Pressure to 1380 psi shifting ESC closed, hold for 3 minutes, bleed off pressure, open block valve to
casing, no flow. Blow down cement line. Disconnect the koomey lines from the knife valve. Drain the cement from the stack into the cellar box. Flush the stack with
black water three times. Jet the flow line with black water. Power down the accumulator and disconnect lines from diverter annular. RD the Volant tool. Rig down
Diverter lines and clean out 4" conductor valves. Install 4" caps. Raise surface stack and prep for emergency slips. Remove CSG pipe handling equipment from rig
floor. Install emergency slips setting 100K on slips. Cut 9 5/8" joint ( 21.88' ) and L/D. Sim-ops cleaning pits. Remove flow riser and knife valve. Start breaking bolts
below Surface annular.
1/27/2023 ND diverter stack/tee and secure annular in cellar. Load wellhead equipment into cellar. SimOps: clean the mud pits. Install the slip lock casing head and tubing
spool. PT the void to 500 psi for 5 minutes and 3,800 psi for 10 minutes (good test). Torque casing slips. SimOps: clean the mud pits. N/U adaptor spool. Install
MPD Orbit valve on RCD. N/U the BOP stack, install turn buckles. Install the kill and choke lines. Simops: Load out cement Silos, set MPD shack in place. Install
MPD RCD head, choke and kill lines. SimOps: Clean centrifuges. Change out Upper Pipe Rams to 4-1/2"x7" VBR. Hook up Koomey lines. Obtain RKBs. Charge
Accumulator and check for leaks - good. Remove MPD cap, change out lower test plug seal and install test plug. Install 1502 on lower annulus valve. Change out air
boots on bell nipple. Grease Upper IBOP, Choke manifold and Mud cross. Rig up 7" test jt and test equipment. Install TopDrive test sub. Flood system with water
and purge air. Perform shell test 250 psi low/ 3000 psi high for 5 min each. Oteco clamp on choke line leaking. Tightening up to test again. Daily disposal to G&I =
823 bbls. Total disposal to G&I = 9233 bbls. Daily water hauled from 6 mile = 405 bbls. Total water hauled from 6 mile = 7635 bbls. Daily fluid loss = 0 bbls. Total
fluid loss = 285 bbls.
1/28/2023 Finish tightening 4'' oteco flange on choke line, shell test to 3000 psi, good. Witness waived by AOGCC inspector Kam St John via email on 1/27/22 at 08:27 hours.
Test annular to 250/2500 psi 5 min ea, test all other components to 250/3000 psi 5 min ea, chart all tests. Tests: 1. UPR with 7'' test joint, choke valves 1,12, 13, 14,
kill valve 20, 5" TIW (passed). 2. UPR with 7" test joint, HCR kill, 5" Dart valve, choke valves 9, 11 (passed). 3. UPR with 7'' test joint, choke valves 5, 8, 10, Manual
kill, 3 1/2'' FOSV (passed). 4 .Choke valves 4, 6. 7, 3 1/2'' dart valve (passed). 5. Choke valve 2, upper IBOP (passed). 6. HCR Choke, lower IBOP (passed). 7.
Manual Choke (passed. 8. Annular with 4 1/2'' test joint (passed). 9. UPR with 4 1/2'' test joint (passed). 10. LPR with 4 1/2'' test joint (passed). 11. LPR with 5'' test
joint (passed). 12. Blind rams, choke valve 3 (passed). 13. Hydraulic super choke (passed). 14. Manual adjustable choke (passed). Accumulator Test: System
pressure = 2,975 psi. Pressure after closure = 1,700 psi. 200 psi attained in 44 seconds. Full pressure attained in 179 seconds. Nitrogen Bottles - 6 at 2,029 psi.
Rig electrician calibrate and test rig gas alarms. No failures. At 11:00 discovered flo pro mud slightly leaking from under the mud pits on the ODS of the rig, Notify
Security, ACS, the DSO, utilizing a vac truck, empty pits 1 and 2 to determine where the leak is coming from. While testing BOPs Cleanup the visible mud off the rig
mats, approx under 1 gallon, no visible mud on the ground, total amount if any to be determined once the rig is moved off the well. Pull trip nipple, install RCD test
cap, pressure test RCD head to 1,200 psi, good test, RD test cap and test equipment, re-install trip nipple, blow down choke manifold and lines. Simops: clean in
pits 1 and 2 to find leak. Found 1/4'' hole in pit 1 below equalizer brace on floor in pit 1. Welder make repairs in pit 1, weld patch under equalizer brace on pit floor.
Simops: install 9 1/8'' wear bushing. Install mousehole. M/U 8-1/2 Clean-Out assembly to 595'. 8-1/2" Smith XR+CPS Tricone bit, 6-3.4" Mud Motor with ABH set at
1.5 deg, Float Sub, 2 stands 5"HWDP, Jar Stand and final 3 stands 5" HWDP. Trip in hole with clean out assembly on 5" DP f/ 595' t/ 2019. Fill pipe every 20 stds.
Fill the pipe, wash and ream from 2019'. Tag cement at 2255. Drill cement, plug and ES cementer from 2255' to 2263' at 350 GPM = 550 psi, 40 RPM = 5K ft-lbs
TQ, WOB = 5-7K. Wash and ream through ESC 3 times and drift through without pump/rotary. PU=105K, SO= 83K & ROT= 93K. Cont. washing and reaming
through cement stringers from 2263' to 2585' at 400 GPM= 700 PSI, 40 RPM= 3-7K TQ, WOB= 5-8K. Blow down Top Drive and line up on TT. Cont. RIH on
elevators on 5" DP F/2585' T/6302' filling pipe every 20 stds. Wash/Ream F/6302' T/6350' at 375 GPM=700-900 PSI, 40 RPM, 15K TQ, WOB= 5K tagging soft
CMT/CMT stringers @ 6310'. PU 205K, SO 83K, ROT 140K. CBU at 375 GPM, ICP=820 PSI - FCP= 745 PSI, 40 RPM, 15-17K TQ, reciprocating F/6350' T/6302'.
Rack back std and Blow down top drive. Daily disposal to G&I = 77 bbls. Total disposal to G&I = 9310 bbls. Daily water hauled from 6 mile = 190 bbls. Total water
hauled from 6 mile = 7825 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 285 bbls.
1/29/2023 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 4.8 bbls- Bled back 4.8 bbls.
Blow down and R/D testing equipment. Wash/Ream F/6,350' T/6,380' drilling soft CMT and stringers, drill hard cement wi/ 6K WOB @ 6380', Drill out shoe track,
exit shoe at 6,511', all FE on depth. Cleanup rathole to 6,516', Ream FE 3x then without rotary or pumps. 475 GPM= 1,180 PSI, 40 RPM, 16 TQ, WOB= 2-5K. PU
210K, SO 100K, ROT 140K. Drill 20' new 8 1/2'' hole to 6,536', 475 GPM, 1,270 psi, 40 RPM, 16K torque, 10-15K WOB. PU into the 9-5/8" casing shoe at 6,511'.
Circulate and condition the mud at 470 GPM = 1,160 psi, 30 RPM = 16K TQ, reciprocating 90' until good 9.25 ppg MW in/out. Max gas = 0 units. PU = 210K, SO =
100K, ROT = 140K. Parked at 6,492'. BD TD. RU test equipment. Fill lines, purge air and close the UPR. Perform FIT to 12 ppg EMW with existing 9.25 ppg MW,
apply 632 psi at surface, good test, bleed off pressure, open UPR. RD test equipment. Pumped 1.3 bbls, bled back 1.3 bbls. Flow check the well, static. Pump dry
job. BD lines. Simops: PT MPD lines to 1200 psi, good, BD lines. TOOH with cleanout assembly f/ 6492' t/ 659'. Hole took calculated fill. Monitor Well - Static. L/D
all HWDP, Jars and BHA. 8-1/2" MillTooth Bit Grade= 1-1-WT-A-E-3-NO-BHA. Clear and clean the rig floor. Mobilize split bushing and MPD RCD to the rig floor.
Remove the master bushing and install the split bushings. Monitor well via trip tank, static. PJSM, MU 8-1/2" NOV PDC bit, NRP-A2 bit sleeve, 7600 Geo-Pilot,
LWD (ADR & DGR), PWD, Directional tools and stabilizer to 89'. Initialize MWD. Finish making up BHA with NM float sub, 3 NM flex collars, NM float sub and
HWDP/Jar stand to 297'. TIH with lateral BHA from on stands 5'' drill pipe from 297' to 2178'. Fill pipe. Shallow pulse test MWD at 450 GPM = 1040 psi. Break in
the Geo Pilot seals. Attempted to perform download observing actuator valve not functioning on Geo Span. Blow down the top drive. Continue to TIH on stands 5''
drill pipe from 2178' to 6270' filling pipe every 2,000'. Attempted to download again with same results from Geo Span. Will change out prior to installing RCD
bearing. PU 211K, SO 100K. Daily disposal to G&I = 114 bbls. Total disposal to G&I = 9424 bbls. Daily water hauled from 6 mile = 210 bbls. Total water hauled
from 6 mile = 8035 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 285 bbls.
1/30/2023 Mobilize Geo Span and remove staging at beaver slide. Install backup Geo span and R/U lines. Single in 6 jts drill pipe from 6270' to 6463'. PT Geo span- No leaks.
Attempted to downlink- actuator would open but not shut all the way. Functioned it manually with no issues. Troubleshoot coms from Sperry shack to Geo span. C/O
cable from sperry shack to geo span, swap to backup computer. Downlink 4 times with no issues. Blow down top drive, Drain the stack, pull the MPD riser and
install the MPD RCD. Install the RCD head skirt for the drip pan, no leaks. PJSM, RIH to 6,536', pump spacer, Displace well f/ 9.25 ppg spud mud to 8.8 ppg FloPro
at 6 BPM = 370 psi (ICP), 30 RPM = 17K ft-lbs TQ. PU = 210K, SO = 100K & ROT = 135K. With mud out bit pull into 9 5/8" casing to finish displacing. After
displacement 6 BPM = 350 psi (FCP), 30 RPM = 11K ft-lbs TQ. PU =190K, SO = 103K & ROT = 135K. Discovered Geo span valve partially open, over displaced
322 bbls. Rack 1 stand back parking at 6460', blow down the top drive, start slip and cut drilling line. Monitor MPD for pressure build, no pressure. Lost Hi line
power at 17:10, on gen power at 17:25. The Rig PFC 5th trap was getting warm, Rig electrician swapped breakers on 5th trap and the high-line power went down.
Start Rig Generators and put on-line. Find that the drawworks will not power on. Troubleshoot Drawworks power issue. Problem narrowed down to the High-Line
bay in SCR room. Suspect the high-line card is sending a power limit fault to Rig, not allowing the drawworks to power up. Holding the reset button depressed
constantly, bypasses the high-line card and drawworks gets power. Lock in reset button and put a load test on the reset bypass with 2nd generator on-line - Good.
Doyon start working on sourcing out a replacement high-line controller card while rig ops continue. Finish cut and slip 60' drlg line. Unhang blocks, break out of
string and install FOSV. Service Topdrive, inspect saver sub & grabber dies. Calibrate block height and check crown-o-matic. Remove FOSV, M/U TopDrive.
Circulate BU, 500 GPM - 1260 psi. 40 RPM - 6k Tq. PU =165k, SO= 110k, ROT= 123k. Even 8.8 ppg Flowpro in/out. MBT = 0.5. MWD troubleshoot Geo-Span,
find issues with primary computer, back-up system working fine and can drill ahead. Wait on word from Doyon whether a replacement Hi-Line card can be obtained
from in-field. Continue circulate 500 GPM, 1200 psi. No rotary. No replacement card is available from other Rigs. Decision made to proceed with Drilling. Drill 8-1/2"
lateral F/6536' T/6605' (4441' TVD). Drilled 70' = 23'/hr AROP. 500 GPM = 1340 psi, 100 RPM = 9k Tq, WOB = 10-12k. MW = 8.8 ppg, Vis = 46 ECD = 9.8 ppg,
max gas units = 65. PU = 153k, SO = 108k, ROT = 126k. Daily disposal to G&I = 1218 bbls. Total disposal to G&I = 10642 bbls. Daily water hauled from 6 mile =
170 bbls. Total water hauled from 6 mile = 8205 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 285 bbls. Daily metal recovered = 6 lbs. Total metal recovered = 6
lbs.
1/31/2023 Drill 8-1/2" lateral F/6605' T/6796' (4463' TVD). Drilled 191' = 31.8'/hr AROP. 430 GPM = 1000 psi, 80-100 RPM = 9-11k Tq, WOB = 8-13k. MW = 8.8 ppg, Vis =
42 ECD = 9.53 ppg, max gas units = 958. PU = 152k, SO = 103k, ROT = 129k. Drilled through fault 1 @ 6500' md (4424' tvd) throw @ 10' DTE putting OA top @
6583'. Monitor pressure builds for 5 min at 6651'= 0 psi build., 6746'= 53 psi build. MPD choke fully open drilling, trapping 55 psi during connections. Drill 8-1/2"
lateral F/6796' T/7234' (4451' TVD). Drilled 438' = 73'/hr AROP. 450-550 GPM = 1060-1590 psi, 80-120 RPM = 7-10k Tq, WOB = 10-13k. MW = 8.8 ppg, Vis = 42
ECD = 9.71 ppg, max gas units = 1116. PU = 149k, SO = 104k, ROT = 128k. Monitor pressure builds for 5 min at 6842'= 55 psi build. MPD choke fully open
drilling, trapping 55-80 psi during connections. Drill in the OA, target 92 deg. Drill 8-1/2" lateral from 7234' to 7667' (4444' TVD). Drilled 433' = 72.17'/hr AROP. 550
GPM = 1610 psi, 90-120 RPM = 9-12K ft-lbs Tq, WOB = 6-12K. PU = 150K, SO = 95K & ROT = 131K. MW = 8.9 ppg, Vis = 40, ECD = 9.83 ppg, max gas = 1204
units. Up dip target of 90-92 deg. MPD choke full open while drilling and trapping 150 psi on connections. High vis sweep at 7508, return 100 stks late w/ 40%
increase. Drill 8-1/2" lateral from 7667' to 8171' (4430' TVD). Drilled 504' = 84'/hr AROP. 550 GPM = 1630 psi, 120 RPM = 9-11K ft-lbs Tq, WOB = 12K. PU =
150K, SO = 102K & ROT = 128K. MW = 8.8 ppg, Vis = 39, ECD = 9.80 ppg, max gas = 574 units. Up dip target of 90-92 deg. Distance to plan: 36', Low 16.23',
Left 32.13'. We have drilled 16 concretions for a total thickness of 352 (21.6% of the lateral). Last survey 92.10 INC, 305.90 AZM, MWD depth 8008'. Daily disposal
to G&I = 709 bbls. Total disposal to G&I = 11351 bbls. Daily water hauled from 6 mile = 785 bbls. Total water hauled from 6 mile = 8990 bbls. Daily fluid loss = 0
bbls. Total fluid loss = 285 bbls. Daily metal recovered = 9.5 lbs. Total metal recovered = 15.5 lbs.
2/1/2023 Drill 8-1/2" lateral from 8,171' to 8,639' (4,424' TVD). Drilled 468' =78'/hr AROP. 511 GPM = 1,500 psi, 120 RPM = 12K ft-lbs TQ, WOB = 12K. PU = 153K, SO =
98K & ROT = 126K. MW = 8.8 ppg, Vis = 40, ECD = 9.8 ppg, max gas = 619 units. MPD choke fully open drilling, trap 150 psi during connections. Drill in OA
targeting 90-92 deg. Pump 30 bbl hi-vis sweep at 8,553', back 250 strokes late with 40% increase. At 9:45 PU 95' and attempt to go on Hi-line with no success.
Back on Gen power. At 10:40 PU 30' off bottom and the rig was successfully swapped to Hi-line power. Drill 8-1/2" lateral from 8,639' to 9,152' (4,408' TVD). Drilled
513' =85.5'/hr AROP. 500 GPM = 1,580 psi, 120 RPM = 10-13K ft-lbs TQ, WOB = 10-13K. PU = 150K, SO = 95K & ROT = 121K. MW = 8.8 ppg, Vis = 40, ECD =
10.01 ppg, max gas = 602 units. MPD choke fully open drilling, trap 150 psi during connections. Drill in OA, target 90-92 deg. Encountered fault #1 at 8,898' with 5'
DTE throw moving the wellbore from the lower OA to the base of the OA. Exited the base of the OA sand at 8,962' and reentered the OA sand at 8,982'.
Encountered fault #2 at 9,030' with 10' DTE throw moving the wellbore from the lower OA to below the OA sand. Drill 8-1/2" lateral from 9,152' to 9,598' (4,394'
TVD). Drilled 513' =85.5'/hr AROP. 532 GPM = 1,780 psi, 120 RPM = 15K ft-lbs TQ, WOB = 10K. PU = 155K, SO = 80K & ROT = 123K. MW = 8.9 ppg, Vis = 40,
ECD = 10.32 ppg, max gas = 549 units. MPD choke fully open drilling, trap 150 psi during connections. Pump 30 bbl hi-vis sweep at 9,503', back 200 strokes late
with 50% increase. Reentered the OA sand at 9,190'. Drill in OA targeting 87-88 deg. Drill 8-1/2" lateral from 9,598' to 10,170' (4,400' TVD). Drilled 572' =95.3'/hr
AROP. 511 GPM = 1,720 psi, 120 RPM = 14K ft-lbs TQ, WOB = 11K. PU = 160K, SO = 86K & ROT = 122K. MW = 8.9 ppg, Vis = 41, ECD = 10.37 ppg, max gas
= 627 units. MPD choke fully open drilling, trap 150 psi during connections. Exited the base of the OA sand at 9,384' and reentered the OA sand at 9,456'. Drill in
OA targeting 87-88 deg. Drilled 35 concretions for a total thickness of 518 (14.5% of the lateral). Last survey at 9,909.76 MD / 4,388.10 TVD, 88.02 deg INC,
304.65 deg AZM. Distance from WP12 = 13.45, 13.06 low & 3.25 right. Daily disposal to G&I = 1,135 bbls. Total disposal to G&I = 12,486 bbls. Daily water hauled
from 6 mile = 1,200 bbls. Total water hauled from 6 mile = 10,190 bbls. Daily fluid loss = 0 bbls. Total fluid loss = 285 bbls. Daily metal recovered = 12 lbs. Total
metal recovered = 27.5 lbs.
2/2/2023 Drill 8-1/2" lateral from 10,170' to 10,552' (4,408' TVD). Drilled 382' =63.7'/hr AROP. 502 GPM = 1,760 psi, 120 RPM = 15-16K ft-lbs TQ, WOB = 12K. PU = 169K,
SO = 74K & ROT = 120K. MW = 8.9 ppg, Vis = 39, ECD = 10.4 ppg, max gas = 632 units. MPD choke fully open drilling, trapping 150 psi during connections. Drill
in the OA sand targeting 87-89 deg. Pump 30 bbl hi-vis sweep at 10,551', back 350 strokes late with 100% increase. Drill 8-1/2" lateral from 10,552' to 11,135'
(4,447' TVD). Drilled 583' = 97.2'/hr AROP. 511 GPM = 1,850 psi, 120 RPM = 17K ft-lbs TQ, WOB = 10-15K. PU = 170K, SO = 75K & ROT = 125K. MW = 9.0
ppg, Vis = 44, ECD = 10.53 ppg, max gas = 534 units. MPD choke fully open drilling, trapping 150 psi during connections. Drill in the OA sand targeting 87-89 deg.
Perform 490 bbl dump and dilute at 11,170'. Drill 8-1/2" lateral from 11,135' to 11,587' (4,456' TVD). Drilled 452' = 75.3'/hr AROP. 511 GPM = 1,760 psi, 120 RPM
= 16K ft-lbs TQ, WOB = 10-15K. PU = 165K, SO = 85K & ROT = 125K. MW = 8.9 ppg, Vis = 41, ECD = 10.43 ppg, max gas = 535 units. MPD choke fully open
drilling, trapping 150 psi during connections. Drill in the OA sand targeting 87-89 deg to 11,407' and level out at 90 deg. Pump 30 bbl hi-vis sweep at 11,503', back
400 strokes late with 100% increase. Drill 8-1/2" lateral from 11,587' to 12,227' (4,440' TVD). Drilled 640' = 106.7'/hr AROP. 507 GPM = 1,730 psi, 120 RPM = 17K
ft-lbs TQ, WOB = 10-15K. PU = 166K, SO = 75K & ROT = 120K. MW = 8.9 ppg, Vis = 42, ECD = 10.40 ppg, max gas = 646 units. MPD choke fully open drilling,
trapping 150 psi during connections. Drill in the OA sand targeting 90 deg. Drilled 63 concretions for a total thickness of 739 (13.1% of the lateral). Last survey at
11,908.82 MD / 4,449.78 TVD, 91.29 deg INC, 301.05 deg AZM. Distance from WP12 = 4.48, 4.31 low & 1.22 right. Daily disposal to G&I = 1,574 bbls. Total
disposal to G&I = 14,060 bbls. Daily water hauled from 6 mile = 1,120 bbls. Total water hauled from 6 mile = 11,310 bbls. Daily fluid loss = 0 bbls. Total fluid loss =
285 bbls. Daily metal recovered = 13 lbs. Total metal recovered = 40.5 lbs.
2/3/2023 Drill 8-1/2" lateral from 12,227' to 12,644' (4451' TVD). Drilled 417' = 69.5'/hr AROP. 506 GPM = 1,860 psi, 120 RPM = 17K ft-lbs TQ, WOB = 10-12K. PU = 169K,
SO = 69K & ROT = 124K. MW = 8.9 ppg, Vis = 39, ECD = 10.6 ppg, max gas = 526 units. MPD choke fully open drilling, trapping 150 psi during connections.
Pump 30 bbl hi vis sweep @ 12,549', sweep back 700 stks late with 20% increase in cuttings. Drill in the OA sand targeting 87-89 deg. Drill 8-1/2" lateral from
12,644' to TD at 13,025' (4,476' TVD). Drilled 381' = 95.3'/hr AROP. 507 GPM = 1,870 psi, 120 RPM = 17K ft-lbs TQ, WOB = 11K. PU = 173K, SO = 58K & ROT
= 124K. MW = 8.9+ ppg, Vis = 40, ECD = 10.6 ppg, max gas = 505 units. MPD choke fully open drilling, trapping 150 psi during connections. Exited the OA sand
at 13,018'. Obtain final survey. Downlink Geo-Pilot to home position. Drilled 77 concretions for a total thickness of 870' (13.4% of the lateral). Last survey at
13,025.00 MD / 4,476.77 TVD, 93 deg INC, 304.38 deg AZM. Distance from WP12 = 9.37, 9.19 high & 1.47 right. Pump 30 bbl high vis sweep, back 800 strokes
late with 20% increase in cuttings. Circulate a total of 4 bottoms up at 500 GPM = 1,800 psi, 120 RPM = 15K ft-lbs TQ. Reciprocate DP 90' alternating end points.
SimOps: Prep pits for displacement. PJSM. 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 844 bbls of 8.45 ppg viscosified brine with 3% lubes (1.5% 776 and 1.5% LoTorq). 6
BPM = 800 psi (ICP), 60 RPM = 15K ft-lbs TQ & 7 BPM = 660 psi (FCP), 60 RPM = 12K ft-lbs TQ, reciprocating 95' alternating stopping points. Shut down the
pumps with clean 8.45 ppg viscosified brine to surface. No losses. Obtain passing PST: 2.3, 2.1 & 2.4 seconds per 1L sample. Monitor the wellbore pressure with
MPD choke 4 times 5 minutes each = 80, 80.7, 80 & 81.5 psi. EMW = 8.8 ppg. Obtain new SPR's. SimOps: Clean pit #3 and load 8.45 ppg 3% lube brine in pits #3
& 4. BROOH from 13,025' to 10,929' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. Laying down DP in the mouse hole. 500 GPM =
1,430 psi, 120 RPM = 9K ft-lbs TQ, max gas = 783 units. PU = 175K, SO =85K & ROT = 125K. Loss rate = 17 BPH. Daily disposal to G&I = 2,810 bbls. Total
disposal to G&I = 16,870 bbls. Daily water hauled from 6 mile = 1,095 bbls. Total water hauled from 6 mile = 12,405 bbls. Daily fluid loss = 0 bbls. Total fluid loss =
285 bbls. Daily metal recovered = 10 lbs. Total metal recovered = 50.5 lbs.
2/4/2023 BROOH from 10,929' to 7,888' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. Laying down DP in the mouse hole. 500 GPM = 1,380
psi, 120 RPM = 8K ft-lbs TQ, max gas = 816 units. PU = 175K, SO =110K & ROT = 125K. Continue BROOH from 7,888' to 6,653' pulling 5-10 minutes/stand
slowing as needed to clean up slides/tight spots. Laying down DP in the mouse hole. 500 GPM = 1,250 psi, 120 RPM = 6K ft-lbs TQ, max gas = 208 units. PU =
150K, SO =105K & ROT = 125K. Pump into the shoe without rotary at 500 GPM = 1,250 psi from 6,653' to 6463' seeing 15K drag pulling the BHA into the shoe.
Losses while BROOH= 248 BBLS. Pump 30 bbl hi-vis sweep at 500 GPM = 1,320 psi, 60 RPM = 4-7K ft-lbs TQ reciprocating 90' and circulate the 9-5/8'' casing
clean with a total of 3 BU. Sweep back on time with 20% increase. Obtain passing PST. MW in/out = 8.9 ppg. Monitor the wellbore pressure with MPD choke 4
times at 5 minutes each = 90 psi, 79 psi, 66 psi & 79 psi. EMW = 9.23 ppg. Weight up the surface volume to 9.1 ppg. Circulate 9.1 ppg while weighting up the
returns on the fly to 9.1 ppg at 300 GPM = 530 psi, 30 RPM = 5K ft-lbs TQ reciprocating 90'. Good 9.1 ppg in/out. Blow down the top drive. Weight up the surface
volume to 9.3 ppg. Monitor the wellbore pressure with MPD choke 4 times at 5 minutes each = 51 psi, 46 psi, 43 psi & 39 psi. Circulate 9.3 ppg while weighting up
the returns on the fly to 9.3 ppg at 300 GPM = 500 psi, 30 RPM = 3K ft-lbs TQ reciprocating 90'. Good 9.3 ppg in/out. Blow down the top drive. Weight up the
surface volume to 9.5 ppg. Monitor the wellbore pressure with MPD choke 2 times at 5 minutes each = 19 psi & 17 psi. Circulate 9.5 ppg while weighting up the
returns on the fly to 9.5 ppg at 300 GPM = 500 psi, 30 RPM = 2K ft-lbs TQ reciprocating 90'. Good 9.5 ppg in/out. Blow down the top drive. Shut down and monitor
with MPD, 13 psi in 5 minutes and starting to drop. Open the 2" valve on the MPD head and observe the well for flow. Slight flow then no flow after 15 minutes.
PJSM. Remove the RCD and install the MPD riser. Well on a slight vac. Fill the riser and no leaks. Obtain new SPR's and blow down the top drive. Drop 2.45" OD
drift on 100' of wire. TOOH from 6,463' to 279' standing back 65 stands of 5" DP. Lost 16.4 bbls while TOOH. LD HWDP and jars to 186'. Daily disposal to G&I =
385 bbls. Total disposal to G&I = 17,255 bbls. Daily water hauled from 6 mile = 290 bbls. Total water hauled from 6 mile = 12,695 bbls. Daily fluid loss = 268 bbls.
Total fluid loss = 553 bbls. Daily metal recovered = 4.5 lbs. Total metal recovered = 55 lbs.
2/5/2023 LD 3 NMFC and float subs to 89'. Plug in and download MWD data. LD remaining BHA. 8-1/2'' PDC bit grade= 2-1-BT-N-X-I-CT-TD. Normal wear on BHA from
drilling/BROOH. Clear the rig floor of BHA components. Remove the split bushings and install the master bushings. Static loss rate = 4 BPH. Simops: RD MPD.
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 = 4 BPH.
PJSM. PU round nose float shoe, WIV, 4-1/2", 12.6# blank liner joint, crossover and 4-1/2", 13.5#, L-80, H625 pup joint to 39'. RIH with 4-1/2", 13.5#, L-80, Hydril
625 Weatherford 100-micron screens from 39' to 6,676'. Torque to 9,600 ft-lbs with Doyon double stack tongs, verify MU mark. Lost 16.3 bbls while running liner.
Average loss rate = 1.8 BPH. Swap elevators. MU Baker SLZXP liner top packer to 6,719'. TIH one stand to 6,814'. Pump 5 bbls through LTP to ensure clear flow
path, 3 BPM = 220 psi. PU = 125K, SO = 98K, ROT = 100K, 15 RPM = 6K ft-lbs TQ. Blow down top drive. Remove crossover from FOSV. TIH with 4-1/2" screen
liner on 5" DP from 6,814' to 13,025' tagging TD on depth with 15K. PU = 195K & SO = 85K. Lost 10.1 bbls while TIH. LD 1 joint. Drop 1.125"" phenolic setting
ball. MU 9.96' pup joint, FOSV, Side entry sub and 5' DP pup. RU circulating equipment. PT lines to 4,500 psi - good test. Place liner in tension at 13,025' set depth
with 195K. Pump ball down with 30 bbl hi-vis sweep at 3 BPM = 310 psi. Ball on seat 75 strokes early at 997 strokes. Pressure up, observer set at 2,200 psi & hold
for 3 minutes. Set down 45K to confirm set. Pressure up & observe release at 2,950 psi. Continue to pressure up with rig pump and observe ball seat shear at 4,050
psi. PU & observe travel at 145K to confirm release. Top of liner at 6,320.95'. Open kill line & purge lines. Close UPR & PT liner top packer to 1,500 psi for 10
minutes charted - good test. Bleed off pressure & open UPR. Blow down & RD circulating equipment. Pump out of the LTP at 2 BPM = 190 psi. Lay down 1 joint &
5' DP pup. CBU at 450 GPM = 1,030 psi. Sweep back on time with 0% increase. Blow down the top drive. PJSM. Hang the blocks. Slip and cut 59' (9 wraps) of
drilling line. Service the top drive. Static loss rate = 1 BPH.
2/6/2023 Service the top drive and calibrate block height. Static loss rate = 1 BPH. TOOH laying down 5'' drill pipe to the pipe shed from 6,283' to 35'. Lay down and inspect
the liner running tool. Lost 9 bbls while TOOH. Swap to completions. Daily disposal to G&I = 312 bbls. Total disposal to G&I = 17,624 bbls. Daily water hauled from
6 mile = 50 bbls. Total water hauled from 6 mile = 12,805 bbls. Daily fluid loss = 30.5 bbls. Total fluid loss = 655.5 bbls. Daily metal recovered = 0 lbs. Total metal
recovered = 56 lbs.
Activity Date Ops Summary
2/6/2023 MU the stack washer and jet the stack. Flush and clean the flow line. RU and pull the 9-1/8'' ID wear bushing. PU 7'' mandrel casing hanger and landing joint,
perform hanger dummy run as per WHR,,Mobilize casing equipment to the rig floor. RU 7" slips, elevators and Doyon double stack tongs. MU crossover to FOSV.
PJSM. PU 7" tie back seal assembly and RIH with 7", 26#, L-80, TXP-BTC casing from 21' to no-go at 6,335' with 5K. Set down 10K to confirm. PU = 155K & SO =
125K. Torque to 14,750 ft-lbs with Doyon double stack tongs. Lost 8.1 bbls while running 7" casing,LD 3 joints. MU pup joints 2.82' and 7.51'. MU joint #154. MU
7" mandrel casing hanger with landing joint. Land casing hanger 1.76' off no-go. RU circulating equipment to reverse circulate. Close the annular. Pressure up on
the IA to 200 psi and PU until pressure drop exposing the circulating ports. PJSM. Reverse circulate116 bbls of 8.33 ppg corrosion inhibited source water at 6 BPM
= 500 psi.
2/7/2023 Reverse circulate 58 bbls diesel at 6 BPM = 580 psi freeze protecting the 7'' x 9-5/8'' annulus to 2,242'. Strip down through the annular, closing the ports and
landing the 7'' mandrel casing hanger with 85k on hanger (1.76' off the no-go). Bleed off pressure and drain BOP stack. RD circulating equipment. LD 7" landing
joint. MU 2 joints of 5" HWDP and pack-off running tool. Install 7" pack-off as per wellhead rep. Run in lock down screws. PT pack-off void to 500 psi for 5 minutes
and 5,000 psi for 10 minutes - good test. LD HWDP and pack-off running tool. RU injection line and test equipment to the OA. With the rig pump, PT the 7" x 9-5/8"
annulus to 1,500 psi for 30 minutes charted - good test. 2.02 bbls pumped. Bleed off. RD circulating and test equipment. Mobilize 4-1/2" handling equipment,
double stack, spooling unit with TEC wire, job box, cannon clamps, crossovers, pup joint and tubing hanger. MU crossover to 3-1/2" TIW. Monitor well with the trip
tank, the well is static,PJSM. PU mule shoe joint and RIH 2 jts 4-1/2", 12.6#, L-80, TXP-BTC tubing to 124', MU XN nipple, 1 joint, Baker Premier Packer, 1 joint
and Gauge carrier. MU Zenith gauge and TEC wire. MU 1 joint, X nipple, 1 joint and sliding sleeve with covered ports for TEC wire bypass to 405'. Torque to 6,170
ft-lbs with Doyon double stack tongs. RIH with 4-1/2"", 12.6#, L-80, TXP-BTC tubing from 405' to 6,287' spooling TEC wire and installing Cannon clamps per tally.
Checking electrical continuity every 1,000'. PU = 95K & SO = 80K. Torque to 6,170 ft-lbs with Doyon double stack tongs. Change elevator to 5". MU tubing hanger
with BPV installed, crossover and 5" DP landing joint. Terminate the TEC wire and feed through the tubing hanger. SimOps: Drain stack and blow down lines. Land
tubing on hanger with mule shoe at 6,321.31' with 40K on hanger. RLIDS. Lay down the landing joint. Lost 19 bbls while running completion. RD and demobilize
completion running equipment. Pull the mousehole and MPD riser. Remove the drip pan. ND the BOP stack, set on pedestal and secure for transport. Install CTS
plug into the BPV. Mobilize the tree into the cellar. NU the tubing head adapter and tree. Daily disposal to G&I = 114 bbls; Total disposal to G&I = 17,738 bbls. Daily
water hauled from 6 mile = 115 bbls; Total water hauled from 6 mile = 12,920 bbls. Daily fluid loss = 27 bbls; Total fluid loss = 682.5 bbls. Daily metal recovered = 0
lbs; Total metal recovered = 56 lbs. Rig fuel = 6,885 gallons, used = 1,484 gallons & received = 4,000 gallons.
2/8/2023 PT tubing hanger void to 500 psi for 5 minutes and 5,000 psi for 10 minutes - good test. Obtain final Centrilift readings: Pt= 2098.19 psi, Tt= 82.2 deg, Ta= 32 deg,
Vt= 19.6 volts,RU to test and fill Tree with diesel. Pressure test tree to 250/5,000 psi - good test. RD testing equipment. Drain diesel from the tree through the wing
valve. Pull the CTS plug. Unable to pull BPV with the dry rod due to pressure under the BPV. Mobilize the lubricator from A-Pad. RU, pull BPV, secure tree and RD
lubricator. Take rig off hi line and put on generator power at 10:11 hours. RU circulating lines to pump down IA and take returns out tubing. PJSM. Pressure test
lines to 3,500 psi. Reverse circulate 76 bbls 8.6 ppg CI brine down the 4-1/2" x 7" IA, 3 BPM = 600 psi ICP & 650 psi FCP. Line to pump diesel. Attempt to pump
diesel but the line is frozen. Thaw out the line. Pump 85 bbls of diesel at 3 BPM = 600 psi ICP & 750 psi FCP. Line up and U-Tube freeze protect from IA to tubing.
Flush the pump and line with 5 bbls of CI brine. Place the tubing and IA in communication. Allow the diesel to u-tube and equalize. Close the master valve, bleed off
the pressure and drain the tree through the wing valve. Set the 1-7/8" ball & rod with rollers on top of the master valve. Install the lubricator extension. Open the
master valve dropping the ball & rod allowing it to gravitate to seat. Close the master valve and RD the lubricator extension. Pressure up on the tubing 3,500 psi
setting the Premier packer at 2,170 psi. PT the tubing to 3,500 psi for 30 minutes charted - good test. Bleed the tubing to 2,000 psi. PT the 4-1/2" x 7" annulus to
3,500 psi 3,500 psi for 30 minutes charted - good test. Bleed the IA and tubing to 0 psi. Secure the tree. Blow down and RD the squeeze manifold and circulating
lines. SimOps: Empty and clean the pits and rock washer. Clean the cellar box. Rig welder cut off the mouse hole extension and seal weld. SimOps: Prep to skid the
rig floor. RD the rock washer. Move the rock washer and fuel trailer away from the rig. Continue to prep to skid the floor. PJSM. Skid the rig floor into moving
position. Prep to jack up the rig and move off the well. RDMO 24:00.
Well Name:
Field:
County/State:
MP B-37
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
50-029-23740-00-00API #:
Pressure up on the tubing 3,500 psi
setting the Premier packer at 2,170 psi. PT the tubing to 3,500 psi for 30 minutes charted - good test
PT the 7" x 9-5/8"
annulus to 1,500 psi for 30 minutes charted - good test.
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
2
1
1
1
100
1
1
1
53
1
X Yes No X Yes No 30
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:X Yes No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated? 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?X Yes No Vol to Surf:
Cement In Place At: Date: Estimated TOC:
Method Used To Determine TOC:
Post Job Calculations:
Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped:
Cmt returned to surface: Calculated cement left in wellbore:
OH volume Calculated: OH volume actual: Actual % Washout:
Casing (Or Liner) Detail
Shoe
Cut Joint of Casing
10 3/4
356.8 3356.8
SE
C
O
N
D
S
T
A
G
E
Rig
22:50
Returns to Surface
Rotate Csg Recip Csg Ft. Min. PPG9.4
Shoe @ 6511 FC @ Top of Liner6,425.24
Floats Held
387.6 668
260 387.6
Spud Mud/Spacer
CASING RECORD
County State Alaska Supv.C.A. Demoski / J. Vanderpool
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.MP B-37 Date Run 24-Jan-23
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
TXP BTC-SR Innovex 1.59 6,511.00 6,509.41
19.49 52.59 33.109 5/8 47.0 L-80 TXP BTC-SR Tenaris
Csg Wt. On Hook:310 Type Float Collar:Innovex No. Hrs to Run:26
9.4 6
1600
10
10.7 294 5
98
180
Bump Plug?
FI
R
S
T
S
T
A
G
E
10Tuned 60
15.8
1000
3.5
9.45 6 144.73/164
477.1/480
1400
55
Rig
15.8 82
Bump press
Returns to Surface
Bump Plug?
10:05 1/26/2023 2,264
2263.58
6,511.006,516.00
CEMENTING REPORT
Csg Wt. On Slips:100
Spud Mud
Tuned
572 2.88
Stage Collar @
60
Bump press
100
205
HES Closure OK
56
12 236
34.23 RKB to CHF
Type of Shoe:Innovex Casing Crew:Doyon
No. Jts. Delivered No. Jts. Run 154
Length Measurements W/O Threads
Ftg. Delivered Ftg. Run 6,477.90 Ftg. Returned
Ftg. Cut Jt.21.88 Ftg. Balance
www.wellez.net WellEz Information Management LLC ver_04818br
4
ArcticCem
Type
82 total 9-5/8"x12-1/4" bowspring centralizers ran. Two on shoe joint w/ stop rings 10' from each end. One floating on
joint #2. One each with stop rings mid-joint on joints #3 & 4. One each on joints 5 to 25, every other joint to #47 and then
every third joint to #95. One each on joints #98-103, One each w/ stop rings on pup joints above and below the ES
cementer. One each on joints #104-109 and then every third joint #112-154
Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 82.81 6,509.41 6,426.60
Float Collar 10 3/4 TXP BTC-SR Innovex 1.36 6,426.60 6,425.24
Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 40.16 6,425.24 6,385.08
Baffle Adapter 10 3/4 TXP BTC-SR HES 1.40 6,385.08 6,383.68
Casing 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 4,102.70 6,383.68 2,280.98
Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 17.40 2,280.98 2,263.58
ES Cementer 10 3/4 TXP BTC-SR HES 2.82 2,263.58 2,260.76
Pup Joint 9 5/8 40.0 L-80 TXP BTC-SR Tenaris 18.10 2,260.76 2,242.66
Casing 9 5/8 47.0 L-80 TXP BTC-SR Tenaris 2,190.07 2,242.66 52.59
Type I/II Cement 565 2.35
Premium G Cement 400 1.16
5.5
Type I/II Cement 270 1.17
1/26/2023 Surface
Spud Mud/Spacer
2,264
98
Returns to Surface
X
10
205
Surface
X
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Chelsea Wright Digitally signed by Chelsea
Wright
Date: 2023.02.06 08:49:42 -09'00'
Benjamin Hand Digitally signed by Benjamin Hand
Date: 2023.02.06 09:02:15 -09'00'
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: 02/14/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: MPU B-37
PTD: 222-153
API: 50-029-23740-00-00
FINAL LWD FORMATION EVALUATION LOGS (01/20/2023 to 02/03/2023)
ROP, AGR, DGR, ABG, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
Final Definitive Directional Survey
Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
FINAL LWD Subfolders:
FINAL Geosteering Subfolders:
Please include current contact information if different from above.
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner:Rig No.:14 DATE:1/28/23
Rig Rep.:Rig Email:
Operator:
Operator Rep.:Op. Rep Email:
Well Name:PTD #2221530 Sundry #
Operation:Drilling:X Workover:Explor.:
Test:Initial:X Weekly:Bi-Weekly:Other:
Rams:250-3000 Annular:250-2500 Valves:250-3000 MASP:1526
MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1 P
Permit On Location P Hazard Sec.P Lower Kelly 1 P
Standing Order Posted P Misc.P Ball Type 1 P
Test Fluid Water Inside BOP 1 P
FSV Misc 0 NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0 NA Trip Tank P P
Annular Preventer 1 13-5/8"P Pit Level Indicators P P
#1 Rams 1 4-1/2x7"P Flow Indicator P P
#2 Rams 1 Blinds P Meth Gas Detector P P
#3 Rams 1 2-7/8x5"P H2S Gas Detector P P
#4 Rams 0 NA MS Misc 0 NA
#5 Rams 0 NA
#6 Rams 0 NA ACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8 x 5000 P Time/Pressure Test Result
HCR Valves 2 3-1/8 x 5000 P System Pressure (psi)2925 P
Kill Line Valves 2 3-1/8 x 5000 P Pressure After Closure (psi)1700 P
Check Valve 0 NA 200 psi Attained (sec)44 P
BOP Misc 0 NA Full Pressure Attained (sec)179 P
Blind Switch Covers:All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.):6 @ 2029 P
No. Valves 14 P ACC Misc 0 NA
Manual Chokes 1 P
Hydraulic Chokes 1 P Control System Response Time:Time (sec)Test Result
CH Misc 0 NA Annular Preventer 12 P
#1 Rams 6 P
Coiled Tubing Only:#2 Rams 6 P
Inside Reel valves 0 NA #3 Rams 6 P
#4 Rams 0 NA
Test Results #5 Rams 0 NA
#6 Rams 0 NA
Number of Failures:0 Test Time:7.5hrs. HCR Choke 1 P
Repair or replacement of equipment will be made within days. HCR Kill 1 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 1-26-23@4:51am
Waived By
Test Start Date/Time:1/28/2023 6:30
(date)(time)Witness
Test Finish Date/Time:1/28/2023 14:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Kam StJohn
Doyon
Test Annular to 250-2500 psi 5 min ea. with 4-1/2" test jt, upper rams 4-1/2" x 7" Variables with 4-1/2" and 7" test jts. to 250-3000
psi 5 min ea. Test lower rams 2-7/8 x 5" Variables with 5" test jt. 250-3000 psi 5 min ea. Blind rams and all valves tested to 250-
3000 psi 5 min ea. Test PVT and flow paddle alarms, test gas alarms. Kam St.John waived witness to test.
T.Shones / A. Carlo
Hilcorp
D.Yessak / J. Vanderpool
MPU B-37
Test Pressure (psi):
rig14@doyondrilling.com
dyessak@hilcorp.com
Form 10-424 (Revised 08/2022)2023-0128_BOP_Doyon14_MPU_B-37
J. Regg; 5/31/2023
1
Regg, James B (OGC)
From:Alaska NS - Doyon 14 - DSMs <AlaskaNS-Doyon14-DSMs@hilcorp.com>
Sent:Friday, January 20, 2023 4:08 PM
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Cc:Doyon Rig14; Nathan Sperry
Subject:MPU B-37 Diverter Test 20 Jan 2023
Attachments:MPU B-37 Diverter 1-20-23.xlsx
Good afternoon,
Attached is the diverter test report for MPU well B‐37 performed this morning at Doyon 14.
Regards,
C.A. Demoski
Doyon 14 DSM
907‐670‐3090 Office
907‐670‐3092 Rig Floor
907‐378‐7530 Cell
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named
above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this
email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed
above, then promptly and permanently delete this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and
the recipient should carry out such virus and other checks as it considers appropriate.
CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open
attachments unless you recognize the sender and know the content is safe.
Milne Point Unit B-37PTD 2221530
Date: 1/20/2023 Development:X Exploratory:
Drlg Contractor:Rig No.14 AOGCC Rep:
Operator:Oper. Rep:
Field/Unit/Well No.:Rig Rep:
PTD No.:2221530 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 in.
Systems Pressure:2950 psig P Hole Size:12-1/4"in.
Pressure After Closure:1800 psig P Vent Line(s) Size:16 in.P
200 psi Recharge Time:36 Seconds P Vent Line(s) Length:179 ft.P
Full Recharge Time:152 Seconds P Closest Ignition Source:83 ft.P
Nitrogen Bottles (Number of):6 Outlet from Rig Substructure:168 ft.P
Avg. Pressure: 2058 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 FP Valve(s) Auto & Simultaneous:
Flow Monitor:P P Annular Closed Time: 21 sec P
Mud System Misc:0 NA Knife Valve Open Time: 17 sec P
Diverter Misc:P
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:1
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
T. Shones / J. Charlie
phoebe.brooks@alaska.gov
Hilcorp
Diverter test performed with 5" DP, function test gas alarms and all Passed, Mud System Mud Pits 1 F/P pit #1 volume totalizer repaired
connection of plug, re-test and working correctly. Initial test notification made at 15:08 on 18 Jan 2023. AOGCC inspector McLeod waived the
right to witness at 17:11 on 19 Jan 2023
0
C. Demoski / J. Vanderpool
0
907-670-3090
TEST DETAILS
jim.regg@alaska.gov
AOGCC.Inspectors@alaska.gov
Milne Point B-37
Form 10-425 (Revised 05/2021)2023-0120_Diverter_Doyon14_MPU_B-37
J. Regg; 5/31/2023
Alaska LLC jbr
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 CenterPoint Drive, Suite 1400
Anchorage Alaska 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU B-37
Hilcorp, LLC
Permit to Drill Number: 222-153
Surface Location: 5224' FSL, 4293' FEL, Sec. 19, T13N, R11E, UM, AK
Bottomhole Location: 237' FNL, 1967' 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,
Jessie L. Chmielowski
Commissioner
DATED this ___ day of December, 2022. 19
Jessie L.
Chmielowski
Digitally signed by Jessie
L. Chmielowski
Date: 2022.12.19
14:40:59 -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: 13089' TVD: 4487'
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:
8490'
4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 56.5' 15. Distance to Nearest Well Open
Surface: x-572000 y- 6023067 Zone- 4 22.8' to Same Pool: 60'
16. Deviated wells: Kickoff depth: 275 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 94 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
Driven 20" 129.5# X-56 80' Surface 103' Surface 103'
9-5/8" 47# L-80 TXP 2500' Surface 2500' Surface 2100'
9-5/8" 40# L-80 TXP 4350' 2500' 2100' 6850' 4444'
Tieback 7" 26# L-80 TXP 6700' Surface 6700' Surface 4442'
8-1/2" 4-1/2" 13.5# L-80 Hyd 625 6339' 6700' 4442' 13089' 4487'
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 19, 2023
12-1/4"
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 Tieback
Uncemented Screen 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 - 580 sx / T - 395 sx
5104
18. Casing Program: Top - Setting Depth - BottomSpecifications
1974
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
1526
1492' FSL, 1995' FWL, Sec. 13, T13N, R10E, UM, AK
237' FNL, 1967' FWL, Sec. 14, T13N, R10E, UM, AK
81-054
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp Alaska, LLC
5224' FSL, 4293' FEL, Sec. 19, T13N, R11E, UM, AK ADL 047438 & 047437
MPU B-37
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)
On behalf of Monty Myers (1784)
12.9.2022
By Anne Prysunka at 4:11 pm, Dec 09, 2022
X
X
*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 FIT.
X
X
X
X
X
222-153
DLB 12/12/2022 DSR-12/9/22MGR16DEC2022
50-029-23740-00-00
GCW 12/19/22
Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski
Date: 2022.12.19 14:41:10 -09'00'
Milne Point Unit
(MPU) B-37
Application for Permit to Drill
Version 1
12/9/2022
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 10
10.0 N/U 13-5/8” 5M Diverter System ............................................................................................. 11
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 16
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 27
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28
16.0 Run 4-1/2” Screened Liner ...................................................................................................... 33
17.0 Run 7” Tieback ........................................................................................................................ 37
18.0 Run Upper Completion – Jet Pump ........................................................................................ 40
19.0 Doyon 14 Diverter Schematic .................................................................................................. 42
20.0 Doyon 14 BOP Schematic ........................................................................................................ 43
21.0 Wellhead Schematic ................................................................................................................. 44
22.0 Days Vs Depth .......................................................................................................................... 45
23.0 Formation Tops & Information............................................................................................... 46
24.0 Anticipated Drilling Hazards .................................................................................................. 47
25.0 Doyon 14 Rig Layout ............................................................................................................... 50
26.0 FIT Procedure .......................................................................................................................... 51
27.0 Doyon 14 Rig Choke Manifold Schematic ............................................................................... 52
28.0 Casing Design ........................................................................................................................... 53
29.0 8-1/2” Hole Section MASP ....................................................................................................... 54
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 55
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 56
Page 2
Milne Point Unit
B-37 SB Producer
PTD Application
1.0 Well Summary
Well MPU B-37
Pad Milne Point “B” Pad
Planned Completion Type Jet Pump
Target Reservoir(s) Schrader Bluff OA Sand
Planned Well TD, MD / TVD 13,089’ MD / 4,487’ TVD
PBTD, MD / TVD 13,089’ MD / 4,487’ TVD
Surface Location (Governmental) 5224’ FSL, 4293’ FEL, Sec. 19, T13N, R11E, UM, AK
Surface Location (NAD 27) X= 572000, Y=6023067
Top of Productive Horizon
(Governmental)1492’ FSL, 1995’ FWL, Sec. 13, T13N, R10E, UM, AK
TPH Location (NAD 27) X= 567781, Y=6024576
BHL (Governmental) 237' FNL, 1967' FWL, Sec 14, T13N, R10E, UM, AK
BHL (NAD 27) X= 562440, Y=6028080
AFE Drilling Days 17
AFE Completion Days 4
Maximum Anticipated Pressure
(Surface) 1526 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1974 psig
Work String 5” 19.5# S-135 NC 50
Doyon 14 KB Elevation above MSL: 33.7 ft +22.8ft =56.5ft
GL Elevation above MSL: 22.8 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Milne Point Unit
B-37 SB Producer
PTD Application
2.0 Management of Change Information
Page 4
Milne Point Unit
B-37 SB Producer
PTD Application
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
Tieback 7” 6.276” 6.151” 7.656” 26 L-80 TXP 7,240 5,410 604
8-1/2”4-1/2”
Screens 3.920” 3.795” 4.714” 13.5 L-80
Hydril 625 9,020 8,540 279
Tubing 4-1/2" 3.958”3.833”4.729”12.6 L-80
TXP 8,430 7,500 288
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276”3.25” 6.625”19.5 S-135 DS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 30,730 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Milne Point Unit
B-37 SB Producer
PTD Application
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 pmazzolini@hilcorp.com, mmyers@hilcorp,
nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to 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 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
Drilling Engineer Joe Engel 907.777.8395 jengel@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 Manager Carl Jones 907.777.8327 cajones@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
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PTD Application
6.0 Planned Wellbore Schematic
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PTD Application
7.0 Drilling / Completion Summary
MPU B-37 is a grassroots producer planned to be drilled in the Schrader Bluff OA sand. B-37 is part of a
multi well program targeting the Schrader Bluff sand on B-pad
The directional plan is 12-1/4” surface hole with 9-5/8” surface casing set in the top of the Schrader Bluff
OA sand. An 8-1/2” lateral section will be drilled and completed with a 4-1/2” liner. The well will be
produced with a jet pump.
Doyon 14 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately February 19th, 2023, pending rig schedule.
Surface casing will be run to 6,850’ MD / 4,444’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to 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. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test
5. Drill 8-1/2” lateral to well TD
6. Run 4-1/2” production liner
7. Run 7” tieback
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. 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-37. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment
will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
AOGCC Regulation Variance Requests:
x None
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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 (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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9.0 R/U and Preparatory Work
9.1 B-37 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 13-5/8” 5M 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 Ensure TF offset is measured accurately and entered correctly into the MWD software.
x GWD will be the primary gyro tool.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD in the Schrader 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
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates).
x Perform gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled.
x Be prepared for gas hydrates. In MPU they have been encountered typically around 2,100-
2,400’ 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
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x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well.
MW will not control gas hydrates, but will affect how gas breaks out at surface.
x Take MWD and GWD surveys every stand until magnetic interference cleans up. After
MWD surveys show clean magnetics, only take MWD surveys.
x Surface Hole AC:
x There are no wells with a clearance factor of <1.0
11.4 12-1/4” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and
TD with 9.2+ ppg.
Depth Interval MW (ppg)
Surface – Base Permafrost 8.9+
Base Permafrost - TD 9.2+ (For Hydrates if need based on offset wells)
MW can be cut once ~500’ below hydrate zone
x PVT System: PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, Toolpusher
office, and mud loggers office.
x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system
with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at
all times while drilling. Be prepared to increase the YP if hole cleaning becomes an
issue.
x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background
LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the
system while drilling the surface interval to prevent losses and strengthen the wellbore.
x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating
the high-clay content sections of the Sagavanirktok and the heavy oil sections of the
UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of
ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
x Casing Running:Reduce system YP with DESCO as required for running casing as
allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and
swab pressures. Reduce the system rheology once the casing is landed to a YP < 20
(check with the cementers to see what YP value they have targeted).
Depth Intervalp
Surface – Base Permafrost
MW (ppg)
gp
TD with 9.2+ ppg.ppg
8.9+
Base Permafrost -TD 9.2+(For Hydrates if need based on offset wells)(y
MW can be cut once ~500’ below hydrate zone
g p y ( ) ppg
We will start with a simple gel + FW spud mud at 8.8 ppg and
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PTD Application
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 to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity.
11.6 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
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12.0 Run 9-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U 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 8.5” 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.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” 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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12.5 Float equipment and Stage tool equipment drawings:
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12.6 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
x Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost.
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damaged to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 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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12.8 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 Ensure the permafrost is covered with 9-5/8” 47# from BPRF to Surface
x Ensure drifted to 8.525”
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12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.11 Slow in and out of slips.
12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
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Cement Slurry Design (1st Stage Cement Job):
13.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
13.12 Displacement calculation is in step 13.8 above.
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
13.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up
option to open the stage tool.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
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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to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.18 Prepare for the 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. 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):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
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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PTD Application
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 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.28 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips.
13.29 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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PTD Application
14.0 ND Diverter, NU BOPE, & Test
14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.2 NU 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5” VBRs
x NU bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 RU MPD RCD and related equipment
14.4 Run 5” BOP test plug
14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
x Test 4-1/2” x 7” rams with 4-1/2” and 7” test joints
x Test 2-7/8” x 5” rams with the 4-1/2” 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
14.6 RD BOP test equipment
14.7 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.8 Mix 8.9 ppg FloPro fluid for production hole.
14.9 Set wearbushing in wellhead.
14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.11 Ensure 5” liners in mud pumps.
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PTD Application
15.0 Drill 8-1/2” Hole Section
15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure
on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT.
15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned.
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 9.9 ppg provides >25 bbls based on 9.5ppg MW, 8.46ppg PP (swab kick at 9.5ppg BHP)
15.8 POOH and LD cleanout BHA
15.9 PU 8-1/2” directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 NC50.
x Run a ported float in the production hole section.
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 upon completion of FIT. Email: melvin.rixse@alaska.gov
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B-37 SB Producer
PTD Application
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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PTD Application
15.11 TIH with 8-1/2” directional assembly to bottom
15.12 Install MPD RCD
15.13 Displace wellbore to 8.9 ppg FloPro drilling fluid
15.14 Begin drilling 8-1/2” hole section, on-bottom staging technique:
x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor torque and drag with pumps on every stand (confirm frequency with co-man)
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section. Reservoir plan is to stay in OA sand.
x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
x Target ROP is as fast as we can clean the hole without having to backream connections
x Schrader Bluff OA Concretions: 4-6% Historically
x MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Lateral A/C:
x There are no wells with a clearance factor <1.0.
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
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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 at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being
removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + liner volume with viscosified brine.
x Proposed brine blend (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.
15.15 Monitor the returned fluids carefully while displacing to brine. After 1 (or more if needed) BU,
Perform production screen test (PST). The brine has been properly conditioned when it will pass
the production screen test (x3 350 ml samples passing through the screen in the same amount
of time which will indicate no plugging of the screen). Reference PST Test Procedure
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe
x Circulate at full drill rate (less if losses are seen, 350 GPM minimum).
x Rotate at maximum RPM that can be sustained.
x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
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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 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.23 POOH and LD BHA.
15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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PTD Application
16.0 Run 4-1/2” Screened Liner
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” screened liner, the following well control response procedure will be followed:
x 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” screened liner.
x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.
x Proceed with well kill operations.
16.2 R/U 4-1/2” liner running equipment.
x Ensure 4-1/2” 13.5# Hydril 625 x NC50 crossover is on rig floor and M/U to FOSV.
x Ensure all casing has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.3 Run 4-1/2” screened production liner
x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x Fill 4-½” liner with PST passed mud (to keep from plugging screens with solids)
x Install screen joints as per the Running Order (From Completion Engineer post TD).
o Do not place tongs or slips on screen joints
o Screen placement ±40’
o The screen connection is 4-1/2” 13.5# Hydril 625
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe. This is to mitigate difference sticking risk while running inner
string.
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 Hydril 625 Torque
OD Minimum Optimum Maximum
4-1/2 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs
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PTD Application
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PTD Application
16.6. Ensure to run enough liner to provide for approx 150’ overlap inside 9-5/8” casing. Ensure
hanger/pkr will not be set in a 9-5/8” connection.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection.
16.7. 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 (ball seat now located in HRDE setting tool) 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. 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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PTD Application
17.0 Run 7” Tieback
17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder
to be used for tie-back space out calculation. Install 7” solid body casing rams in the upper ram
cavity. RU testing equipment. PT to 250/3,000 psi with 7” test joint. RD testing equipment.
17.2 RU 7” casing handling equipment.
x Ensure XO to DP made up to FOSV and ready on rig floor.
x Rig up computer torque monitoring service.
x String should stay full while running, RU fill up line and check as appropriate.
17.3 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes
above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7”
annulus.
17.4 MU first joint of 7” to seal assy.
17.6 Run 7”, 26#, L-80 TXP tieback tieback to position seal assembly two joints above tieback sleeve.
Record PU and SO weights.
7”, 26#, L-80, TXP
=Casing OD Torque (Min) Torque (Opt)Torque (Max)Torque (Operating)
7”13,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs 20,000 ft-lbs
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PTD Application
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17.7 MU 7” to DP crossover.
17.8 MU stand of DP to string, and MU top drive.
17.9 Break circulation at 1 BPM and begin lowering string.
17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO-
GO DEPTH”.
17.12 PU string & remove unnecessary 7” joints.
17.13 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing
hanger is landed. Ensure one full joint is below the casing hanger.
17.14 PU and MU the 7” casing hanger.
17.15 Ensure circulation is possible through 7” string.
17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus.
17.17 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface
in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure
annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7”
tieback seal assembly).
17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
17.19 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing
joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes.
17.20 RD casing running tools.
17.21 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted.
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PTD Application
18.0 Run Upper Completion – Jet Pump
18.1 RU to run 4-1/2”, 12.6#, L-80 TXP tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 12.6#, TXP x XT-39 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.
x Monitor displacement from wellbore while RIH.
18.2 PU, MU and RH with the following 4-1/2” JP completion (confirm tally with Operations
Engineer):
x WLEG/Mule shoe
x Joints, 4-1/2”, 12.6#, L-80, TXP
x Handling Pup, 4-1/2” TXPM Box x 4-1/2” TXP Pin
x Nipple, 3.813” XN profile (3.750” no-go), 4-1/2”, TXPM (RHC plug body installed Set at
less than 70 degrees)
x Handling Pup, 4-1/2”, TXP Box x 4-1/2”, TXP Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Crossover Pup, 4-1/2” TC-II Box x 4-1/2” TXP Pin
x Retrievable Packer, Baker, 4-1/2”, 12.6#, L-80, TC-II (NOTE: Set at less than 70 degrees)
x Crossover Pup, 4-1/2”, TXP Box x 4-1/2”, TC-II Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Handling Pup, 4-1/2” TXPM Box x 4-1/2” TXP Pin
x Nipple, 3.813” X profile 4-1/2”, TXPM
x Handling Pup, 4-1/2”, TXP Box x 4-1/2”, TXP Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Crossover, 4-1/2”, EUE 8rd Box x 4-1/2”, TXP Pin
x Gauge Carrier, 4-1/2”, 12.6#, L-80, EUE 8rd
x Crossover, 4-1/2”, TXP Box x 4-1/2”, EUE 8rd Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Pup joint, 4-1/2”, 12.6#, L-80, TXP
x Sliding Sleeve, 4-1/2”, 12.6#, L-80 TXP
x Pup joint, 4-1/2”, 12.6#, L-80, TXP
x XXX joints, 4-1/2”, 12.6#, L-80, TXP
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18.3 PU and MU the 4-1/2” tubing hanger. Make final splice of the TEC wire and ensure any unused
control line ports are dummied off.
18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
18.5 Land the tubing hanger and RILDS. Lay down the landing joint.
18.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
18.7 NU the tubing head adapter and NU the tree.
18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
18.9 Pull the plug off tool and BPV.
18.10 Reverse circulate the well over to corrosion inhibited source water follow by diesel freeze protect
to 2,500’ MD.
18.11 Drop the ball & rod.
18.12 Pressure up on the tubing to 3,500 psi to set the packer. PT the tubing to 3,500 psi for 30
minutes (charted).
18.13 Bleed the tubing pressure to 2,000 psi and PT the IA to 3,500 psi for 30 minutes (charted). Bleed
both the IA and tubing to 0 psi.
18.14 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
18.15 RDMO
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19.0 Doyon 14 Diverter Schematic
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20.0 Doyon 14 BOP Schematic
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21.0 Wellhead Schematic
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22.0 Days Vs Depth
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23.0 Formation Tops & Information
TOP
NAME
MD
(FT)
TVD
(FT)
TVDSS
(FT)
Formation
Pressure
(psi)
EMW
(ppg)
Base
Permafrost 2,070 1,827 -1,770 804 8.46
SV3 2,519 2,113 -2,056 930 8.46
UG4 3,628 2,819 -2,762 1,240 8.46
UG_MB 5,670 4,119 -4,062 1,812 8.46
SB NB 6,155 4,351 -4,294 1,914 8.46
SB OA 6,675 4,441 -4,384 1,954 8.46
B-pad Data Sheet Formation Description
8.46 EMW needed = 8.46 ppg
8.46
8.46
8.46
DLB
8.46
8.46
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B-37 SB Producer
PTD Application
24.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates
Gas hydrates are generally not seen on B-pad. Remember that hydrate gas behaves differently from a
gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the
breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill
through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation
time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing
which can increase the amount of hydrates released into the wellbore. Keep the mud circulation
temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale.
The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to
remove hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe
moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after
slide intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any
close approaches on AM report.
Well Specific A/C:
x There are no wells with a clearance factor of <1.0
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.
Page 48
Milne Point Unit
B-37 SB Producer
PTD Application
H2S:
Treat every hole section as though it has the potential for H2S. MPU B-pad is not known for H2S. B-03
had a reading of 43 ppm in 2009. B-06 had a reading of 42 in 2009.
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.
MPU B-pad is not known for H2S. B-03ygp
had a reading of 43 ppm in 2009. B-06 had a reading of 42 in 2009.
20 ppm requires H2S measures. DLB
Page 49
Milne Point Unit
B-37 SB Producer
PTD Application
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There are three (possibly four) planned fault crossings for B-37. The maximum expected throw for a
fault is 50’ on the fault crossed mid-lateral.
H2S:
Treat every hole section as though it has the potential for H2S. MPU B-pad is not known for H2S. B-
03 had a reading of 43 ppm in 2009. B-06 had a reading of 42 in 2009.
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. 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 There are no wells with a clearance factor less than 1.0.
Page 50
Milne Point Unit
B-37 SB Producer
PTD Application
25.0 Doyon 14 Rig Layout
Page 51
Milne Point Unit
B-37 SB Producer
PTD Application
26.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 52
Milne Point Unit
B-37 SB Producer
PTD Application
27.0 Doyon 14 Rig Choke Manifold Schematic
Page 53
Milne Point Unit
B-37 SB Producer
PTD Application
28.0 Casing Design
Page 54
Milne Point Unit
B-37 SB Producer
PTD Application
29.0 8-1/2” Hole Section MASP
Page 55
Milne Point Unit
B-37 SB Producer
PTD Application
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 56
Milne Point Unit
B-37 SB Producer
PTD Application
31.0 Surface Plat (As Built) (NAD 27)
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-1200-6000600120018002400300036004200480054006000South(-)/North(+) (1200 usft/in)-10200 -9600 -9000 -8400 -7800 -7200 -6600 -6000 -5400 -4800 -4200 -3600 -3000 -2400 -1800 -1200 -600 0 600West(-)/East(+) (1200 usft/in)MPU B-37 wp08 tgt7MPU B-37 wp08 tgt6B-37 wp06 tgt5B-37 wp06 tgt4B-37 wp06 tgt3B-37 wp06 tgt2B-37 wp06 tgt19 5/8" x 12 1/4"4 1/2" x 8 1/2"25010001500175020002250250027503000325035003750400042504487MPU B-37 wp09Start Dir 3º/100' : 275' MD, 275'TVDEnd Dir : 1980.87' MD, 1769.79' TVDFault 1 (DTE - 50' throw)Start Dir 4º/100' : 5618.56' MD, 4086.39'TVDFault 2 (DTE - 10' throw)End Dir : 6594.34' MD, 4436.27' TVDStart Dir 2.5º/100' : 6694.34' MD, 4441.5'TVDEnd Dir : 6839.57' MD, 4444.51' TVDStart Dir 2º/100' : 7571.14' MD, 4436.5'TVDEnd Dir : 7682.21' MD, 4433.94' TVDFault 3 (DTE - 40' throw)Start Dir 2º/100' : 9033.37' MD, 4386.5'TVDEnd Dir : 9118.12' MD, 4382.29' TVDStart Dir 2º/100' : 9364' MD, 4366.5'TVDEnd Dir : 9694.51' MD, 4363.27' TVDStart Dir 2º/100' : 10214.65' MD, 4386.5'TVDEnd Dir : 10312.27' MD, 4390.28' TVDFault 4 (DTW - 25' throw)Start Dir 2.5º/100' : 11568.32' MD, 4431.5'TVDEnd Dir : 11690.36' MD, 4435.72' TVDTotal Depth : 13088.8' MD, 4486.5' TVDCASING DETAILSTVDTVDSS MDSize Name4444.39 4387.89 6850.00 9-5/8 9 5/8" x 12 1/4"4486.50 4430.00 13088.80 4-1/2 4 1/2" x 8 1/2"Project: Milne PointSite: M Pt B PadWell: Plan: MPU B-37Wellbore: MPU B-37Plan: MPU B-37 wp09REFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU B-37, True NorthVertical (TVD) Reference: MPU B-37 as built RKB @ 56.50usft (Original Well Elev)Measured Depth Reference:MPU B-37 as built RKB @ 56.50usft (Original Well Elev)Calculation Method:Minimum CurvatureWELL DETAILS: Plan: MPU B-3722.80+N/-S+E/-WNorthing Easting Latitude Longitude0.00 0.006023066.970 571999.850 70° 28' 23.8994 N 149° 24' 42.8697 W
0750150022503000375045005250True Vertical Depth (1500 usft/in)-1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 13500Vertical Section at 304.00° (1500 usft/in)B-37 wp06 tgt1B-37 wp06 tgt2B-37 wp06 tgt3B-37 wp06 tgt4B-37 wp06 tgt5MPU B-37 wp08 tgt6MPU B-37 wp08 tgt79 5/8" x 12 1/4"4 1/2" x 8 1/2"5001000150020002500300035004000450050005500600065007000750080008500900095001000010500110001150012000125001300013089MPU B-37 wp09Start Dir 3º/100' : 275' MD, 275'TVDEnd Dir : 1980.87' MD, 1769.79' TVDFault 1 (DTE - 50' throw)Start Dir 4º/100' : 5618.56' MD, 4086.39'TVDFault 2 (DTE - 10' throw)End Dir : 6594.34' MD, 4436.27' TVDStart Dir 2.5º/100' : 6694.34' MD, 4441.5'TVDEnd Dir : 6839.57' MD, 4444.51' TVDStart Dir 2º/100' : 7571.14' MD, 4436.5'TVDEnd Dir : 7682.21' MD, 4433.94' TVDFault 3 (DTE - 40' throw)Start Dir 2º/100' : 9033.37' MD, 4386.5'TVDEnd Dir : 9118.12' MD, 4382.29' TVDStart Dir 2º/100' : 9364' MD, 4366.5'TVDEnd Dir : 9694.51' MD, 4363.27' TVDStart Dir 2º/100' : 10214.65' MD, 4386.5'TVDEnd Dir : 10312.27' MD, 4390.28' TVDFault 4 (DTW - 25' throw)Start Dir 2.5º/100' : 11568.32' MD, 4431.5'TVDEnd Dir : 11690.36' MD, 4435.72' TVDTotal Depth : 13088.8' MD, 4486.5' TVDBPRFSV3UG4UG3LA3LA2UG MBUG MCSB NASB NBSB NCSB NDSB NESB NFSB OAHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU B-3722.80+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.006023066.970571999.850 70° 28' 23.8994 N 149° 24' 42.8697 WSURVEY PROGRAMDate: 2022-11-29T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.70 1200.00 MPU B-37 wp09 (MPU B-37) GYD_Quest GWD1200.00 6840.00 MPU B-37 wp09 (MPU B-37) 3_MWD+IFR2+MS+Sag6840.00 13088.80 MPU B-37 wp09 (MPU B-37) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1826.50 1770.00 2069.91 BPRF2112.50 2056.00 2519.01 SV32818.50 2762.00 3627.62 UG43222.50 3166.00 4262.01 UG33874.50 3818.00 5285.83 LA33892.50 3836.00 5314.09 LA24118.50 4062.00 5670.00 UG MB4164.50 4108.00 5747.81 UG MC4334.50 4278.00 6109.69 SB NA4350.50 4294.00 6155.46 SB NB4370.50 4314.00 6218.80 SB NC4378.50 4322.00 6246.66 SB ND4392.50 4336.00 6300.24 SB NE4424.50 4368.00 6468.80 SB NF4440.50 4384.00 6675.23 SB OAREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU B-37, True NorthVertical (TVD) Reference:MPU B-37 as built RKB @ 56.50usft (Original Well ElevMeasured Depth Reference:MPU B-37 as built RKB @ 56.50usft (Original Well ElevCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt B PadWell:Plan: MPU B-37Wellbore:MPU B-37Design:MPU B-37 wp09CASING DETAILSTVD TVDSS MD SizeName4444.39 4387.89 6850.00 9-5/8 9 5/8" x 12 1/4"4486.50 4430.00 13088.80 4-1/2 4 1/2" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.002 275.00 0.00 0.00 275.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 275' MD, 275'TVD3 650.00 11.25 270.00 647.60 0.00 -36.70 3.00 270.00 30.424 1980.87 50.44 288.93 1769.79 173.54 -677.98 3.00 22.94 659.11 End Dir : 1980.87' MD, 1769.79' TVD5 5618.56 50.44 288.93 4086.39 1083.51 -3330.92 0.00 0.00 3367.35 Start Dir 4º/100' : 5618.56' MD, 4086.39'TVD6 6594.34 87.00 304.00 4436.27 1494.00 -4121.47 4.00 24.35 4252.29 End Dir : 6594.34' MD, 4436.27' TVD7 6694.34 87.00 304.00 4441.50 1549.85 -4204.26 0.00 0.00 4352.15 B-37 wp06 tgt1 Start Dir 2.5º/100' : 6694.34' MD, 4441.5'TVD8 6839.57 90.63 304.16 4444.51 1631.20 -4324.50 2.50 2.59 4497.33 End Dir : 6839.57' MD, 4444.51' TVD9 7571.14 90.63 304.16 4436.50 2042.00 -4929.79 0.00 0.00 5228.86 B-37 wp06 tgt2 Start Dir 2º/100' : 7571.14' MD, 4436.5'TVD10 7682.21 92.01 302.43 4433.94 2102.95 -5022.59 2.00 -51.41 5339.88 End Dir : 7682.21' MD, 4433.94' TVD11 9033.37 92.01 302.43 4386.50 2827.04 -6162.37 0.00 0.00 6689.70 B-37 wp06 tgt3 Start Dir 2º/100' : 9033.37' MD, 4386.5'TVD12 9118.12 93.68 302.14 4382.29 2872.24 -6233.93 2.00 -9.88 6774.30 End Dir : 9118.12' MD, 4382.29' TVD13 9364.00 93.68 302.14 4366.50 3002.76 -6441.71 0.00 0.00 7019.55 B-37 wp06 tgt4 Start Dir 2º/100' : 9364' MD, 4366.5'TVD14 9694.51 87.44 304.31 4363.27 3183.75 -6718.03 2.00 160.76 7349.83 End Dir : 9694.51' MD, 4363.27' TVD15 10214.65 87.44 304.31 4386.50 3476.65 -7147.23 0.00 0.00 7869.44 B-37 wp06 tgt5 Start Dir 2º/100' : 10214.65' MD, 4386.5'TVD16 10312.27 88.12 306.14 4390.28 3532.92 -7226.90 2.00 69.66 7966.96 End Dir : 10312.27' MD, 4390.28' TVD17 11568.32 88.12 306.14 4431.50 4273.34 -8240.68 0.00 0.00 9221.45 MPU B-37 wp08 tgt6 Start Dir 2.5º/100' : 11568.32' MD, 4431.5'TVD18 11690.36 87.92 303.10 4435.72 4342.63 -8341.03 2.50 -93.82 9343.40 End Dir : 11690.36' MD, 4435.72' TVD19 13088.80 87.92 303.10 4486.50 5105.76 -9511.80 0.00 0.00 10740.74 MPU B-37 wp08 tgt7 Total Depth : 13088.8' MD, 4486.5' TVD
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0.001.002.003.004.00Separation Factor0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125Measured Depth (750 usft/in)MPB-18MPB-27MPB-28MPB-29MPU B-31MPU B-32MPU B-32 PB1MPU B-38 wp05MPU B-39 wp05No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU B-37 NAD 1927 (NADCON CONUS)Alaska Zone 0422.80+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006023066.970571999.85070° 28' 23.8994 N149° 24' 42.8697 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU B-37, True NorthVertical (TVD) Reference: MPU B-37 as built RKB @ 56.50usft (Original Well Elev)Measured Depth Reference:MPU B-37 as built RKB @ 56.50usft (Original Well Elev)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2022-11-29T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1200.00 MPU B-37 wp09 (MPU B-37) GYD_Quest GWD1200.00 6840.00 MPU B-37 wp09 (MPU B-37) 3_MWD+IFR2+MS+Sag6840.00 13088.80 MPU B-37 wp09 (MPU B-37) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 375 750 1125 1500 1875 2250 2625 3000 3375 3750 4125 4500 4875 5250 5625 6000 6375 6750 7125Measured Depth (750 usft/in)MPB-01MPB-02MPB-06MPB-17MPB-25MPB-27MPB-28MPB-29MPU B-30MPU B-31MPU B-32MPU B-33MPU B-35MPU B-39 wp05MPU B-40i wp04GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference33.70 To 13088.80Project: Milne PointSite: M Pt B PadWell: Plan: MPU B-37Wellbore: MPU B-37Plan: MPU B-37 wp09Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name4444.39 4387.89 6850.00 9-5/8 9 5/8" x 12 1/4"4486.50 4430.00 13088.80 4-1/2 4 1/2" x 8 1/2"
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0.001.002.003.004.00Separation Factor6750 7125 7500 7875 8250 8625 9000 9375 9750 10125 10500 10875 11250 11625 12000 12375 12750 13125 13500 13875Measured Depth (750 usft/in)MPB-28MPU B-31MPU B-32MPU B-32 PB1MPU B-38 wp05MPU C-45No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU B-37 NAD 1927 (NADCON CONUS)Alaska Zone 0422.80+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006023066.970571999.85070° 28' 23.8994 N149° 24' 42.8697 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU B-37, True NorthVertical (TVD) Reference: MPU B-37 as built RKB @ 56.50usft (Original Well Elev)Measured Depth Reference:MPU B-37 as built RKB @ 56.50usft (Original Well Elev)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2022-11-29T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1200.00 MPU B-37 wp09 (MPU B-37) GYD_Quest GWD1200.00 6840.00 MPU B-37 wp09 (MPU B-37) 3_MWD+IFR2+MS+Sag6840.00 13088.80 MPU B-37 wp09 (MPU B-37) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)6750 7125 7500 7875 8250 8625 9000 9375 9750 10125 10500 10875 11250 11625 12000 12375 12750 13125 13500 13875Measured Depth (750 usft/in)MPB-28GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference33.70 To 13088.80Project: Milne PointSite: M Pt B PadWell: Plan: MPU B-37Wellbore: MPU B-37Plan: MPU B-37 wp09Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name4444.39 4387.89 6850.00 9-5/8 9 5/8" x 12 1/4"4486.50 4430.00 13088.80 4-1/2 4 1/2" x 8 1/2"
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT B-37Initial Class/TypeDEV / PENDGeoArea890Unit11328On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2221530MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberYes4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For sNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 129.5# X-56 set to 103'18 Conductor string providedYes 9-5/8" casing with shoe set horizontally in the reservoir19 Surface casing protects all known USDWsYes Fully cemented. 2 stages with excess20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes Fully cemented. 2 stages with excess22 CMT will cover all known productive horizonsYes 9-5/8" 47# set across permafrost 40# to reservoir23 Casing designs adequate for C, T, B & permafrostYes Doyon 14 has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grassroots well drilled from surface.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliuburton collision scan shows no close approaches26 Adequate wellbore separation proposedYes 16" diverter27 If diverter required, does it meet regulationsYes All fluids overbalance to pore pressure28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack29 BOPEs, do they meet regulationYes 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 shutdownYes MPU B pad is an H2S pad. Monitors will be required.33 Is presence of H2S gas probableNA This well is a producer.34 Mechanical condition of wells within AOR verified (For service well only)No H2S measures required: B-03 & B-06 measured 42 to 43 ppm H2S in 2009. Rig has H2S sensors and alarms.35 Permit can be issued w/o hydrogen sulfide measuresYes36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate12/12/2022ApprMGRDate12/16/2022ApprDLBDate12/12/2022AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 12/19/2022
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
X
c
MPU B-37
Schrader Bluff Oil
X
222-153
X
