Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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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: 08/11/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL :
WELL: MPU M-60
PTD: 223-040
API: 50-029-23755-00-00
FINAL LWD FORMATION EVALUATION LOGS (06/27/2023 to 07/13/2023)
x ROP, AGR, DGR, ABG, EWR-M5, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x 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.
PTD: 223-040
T37929
8/11/2023Kayla
Junke
Digitally signed
by Kayla Junke
Date: 2023.08.11
15:51:36 -08'00'
By Grace Christianson at 11:12 am, Aug 10, 2023
Completed
7/21/2023
JSB
RBDMS JSB 08142023
GDSR-8/18/23MGR24APRIL2024
Drilling Manager
08/09/23
Monty M
Myers
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2023.08.09 16:04:00 -
08'00'
Taylor Wellman
(2143)
_____________________________________________________________________________________
Edited By: JNL 7/24/2023
SCHEMATIC
Milne Point Unit
Well: MPU M-60
Last Completed: 7/21/2023
PTD: 223-040
TD =14,701’(MD) / TD =3,966’(TVD)
4
20”
Orig. KB Elev.: 57.98’ / GL Elev.: 24.1’
7”
9
6
9-5/8”
1
2
3
See
Screen/
Solid
Liner
Detail
9-5/8”
Casing
Patch
2408’ –
2427’
PBTD =14,699’(MD) / PBTD =3,966’(TVD)
9-5/8” ‘ES’
Cementer @
2,416’
5
7
10
12
8
4-1/2”
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 114’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,399’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 2,399’ 5,791’ 0.0758
7” Tieback 26 / L-80 / TXP 6.276 Surface 5,700’ 0.0383
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 5,690’ 14,701’ 0.0149
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / TXP 3.958 Surface 5,704’ 0.0152
OPEN HOLE / CEMENT DETAIL
42” 15 yds Concrete
12-1/4"Stg 1 Lead – 445 sx / Tail – 400 sx
Stg 2 Lead – 718 sx / Tail 270 sx
8-1/2” Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 350’
90° Hole Angle = @ 6,500’
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: 50-029-23755-00-00
Completion Date: 7/21/2023
JEWELRY DETAIL
No. MD Item ID
1 Surface 4-1/2” TCII Tubing Hanger 4.500”
2 2,408’ 9-5/8” Casing Patch (bottom @ 2427’
3 4,790’ Haliburton X-Line Sliding Sleeve (opens down) w/ Jet Pump 3.813”
4 4,851’ Baker Zenith Gauge Carrier 3.865”
5 4,910’ Tri Point Perm Hyd Packer 3.960”
6 4,968’ XN Nipple, 3.813”, 3.725” No Go 3.725”
7 5,663’ WLEG/Mule Shoe (bottom @5704’) 3.958”
8 5,690’ SLZXP Liner Top Packer (11.27’ Tieback Sleeve) 6.180”
9 5,711’ 7” H563 x 4.5” TSH 625 XO 4.810”
10 14,699’ Shoe 3.970”
4-1/2”SCREENS LINER DETAIL
Jts Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
211 6008’ 3936’ 14659’ 3966’
Activity Date Ops Summary
6/27/2023 Prep to skid the rig floor. PJSM. Skid the rig floor into moving position. PJSM. Jack up the rig and remove the shims. Pull the rig off of well M-64 and stage on the
east end of the pad. Remove mats from around M-64. Lay mats around M-60 and for rig footprint. Build dance floor. PJSM. Spot the rig and center over well M-60.
Shim and level the rig. Lower the stairs and install the handrails. PJSM. Skid the rig floor into drilling position. Work on rig acceptance checklist. RU service lines to
the rig floor. Spot auxiliary shacks and pump house. Install the surface bell nipple. NU knife valve. Install first 3 joints of diverter line. Spot the slop tank, fuel trailer
and rock washer. Rig on highline power at 18:00 hours. Work on rig acceptance check list. RU the rock washer and pump house. Install the riser and mouse hole.
NU the diverter line. Install the 4" conductor valves. Load HWDP and BHA into the DS pipe shed. Load DP in the ODS pipe shed.
6/28/2023 Continue to RU water tanks. Inspect conveyors. MU and rack back 6 stands of 5" HWDP including jar stand. Perform the diverter function test with 5" HWDP. The
test was witnessed by AOGCC inspector Brian Bixby. Knife valve opened in 17 seconds and the annular closed in 34 seconds. Test, gas alarms, PVT and flow
sensors - good. Accumulator Test: System pressure = 3,000 psi. Pressure after closure = 1,800 psi. 200 psi attained in 28 seconds. Full pressure attained in 158
seconds. Nitrogen Bottles - 6 at 1,870 psi (average). Diverter length = 352'. Nearest ignition source = 97' (wellhouse). Changeout hydraulic hose on the pipe skate.
SimOps: Load the pits with spud mud. Fill pit 4 with water. Weld down AR plate on conveyor #2. Perform derrick inspection. Fill pit 4 with water. PT mud lines to
3,500 psi - good test. Inspect the saver sub and grabber dies. Rig accepted at 13:00 hours. Continue to changeout hydraulic hose on the pipe skate. Weld hose
guide bracket. PJSM. MU 12-1/4" tricone bit, 8" mud motor with 1.5 AKO, crossover and 1 stand of 5" HWDP. RIH with stand and tag up at 110' MD. Fill the stack
with water and check for leaks - knife valve flange leaking. Tighten up outside knife valve flange. Flood the stack with spud mud. Clean out conductor from 113' to
114'. Spud well and drill 12-1/4" surface hole from 114' to 219' (219' TVD). 360 GPM = 380 psi, 40 RPM = 1K ft-lbs TQ, WOB = 10K. PU = 50K, SO = 53K & ROT
= 51K. MW = 8.8 ppg, Vis = 300+,. POOH and lay down 12-1/4"VMD-3 tricone bit. Bit grade: 1-1-WT-A-E-I-NO-BHA. Flush the flow line with the cement line. MU
BHA #2, 12-1/4" drilling assembly with Kymera bit, 1.5 AKO motor, Gyro and MWD tools. Scribe motor and obtain tool face offsets for Gyro and MWD. Plug in and
upload MWD tools. TIH to 191', shallow test BHA and obtain first Gyro survey at 153'. Drill 12-1/4" surface hole from 219' to 655' (652' TVD). Drilled 436' = 79.3'/hr
AROP. 410 GPM = 860 psi, 40 RPM = 3K ft-lbs TQ, WOB = 10K. PU = 80K, SO = 80K & ROT = 79K. MW = 9.0 ppg, Vis = 246, ECD = 9.8 ppg. Start 3 deg/100'
build at 282'.
6/29/2023 Drill 12-1/4" surface hole from 655' to 1,200' (1,163' TVD). Drilled 545' = 90.8'/hr AROP. 410 GPM = 1,250 psi, 40 RPM = 3-5K ft-lbs TQ, WOB = 13-15K. PU =
90K, SO = 87K & ROT = 87K. MW = 9.0+ ppg, Vis = 203, ECD = 10.24 ppg. Start 4 deg/100' build at 560'. Drill 12-1/4" surface hole from 1,200' to 1,890' (1,659'
TVD). Drilled 690' = 115'/hr AROP. 448 GPM = 1,420 psi, 60 RPM = 4-8K ft-lbs TQ, WOB = 8-10K. PU = 98K, SO = 85K & ROT = 93K. MW = 9.2+ ppg, Vis =
177, ECD = 10.69 ppg, max gas = 56 units. Start 50.47 deg tangent section at 1,712'. Drill 12-1/4" surface hole from 1,890' to 2,653' (2,147' TVD). Drilled 763' =
127.2'/hr AROP. 502 GPM = 1,530 psi, 80 RPM = 5-6K ft-lbs TQ, WOB = 6-10K. PU = 108K, SO = 90K & ROT = 98K. MW = 9.2 ppg, Vis = 114, ECD = 10.30
ppg, max gas = 96 units. Base of permafrost at 2,226' (1,878' TVD). Pump 30 bbl hi-vis sweep at 2,270', back on time with 30% increase. Begin 4 deg/100' drop
and turn at 2,555'. Drill 12-1/4" surface hole from 2,653' to 3,316' (2,655' TVD). Drilled 663' = 147.3'/hr AROP. 548 GPM = 2,040 psi, 80 RPM = 7K ft-lbs TQ, WOB
= 15K. PU = 127K, SO = 90K & ROT = 120K. MW = 9.2 ppg, Vis = 90, ECD = 10.51 ppg, max gas = 108 units. Pump 30 bbl hi-vis sweep at 3,223', back on time
with 20% increase. Distance from WP06 at survey depth of 3,183 = 14.83' (4.49 high & 14.14 left). Rig went dark. Get generators running. Had trouble syncing
generators 2 &3. Able to sync generators 2 & 3 but unable to get generator 1 to sync. Drill 12-1/4" surface hole from 3,316' to 3,369' (2,688' TVD). Drilled 53' =
106'/hr AROP. 548 GPM = 2,040 psi, 80 RPM = 7K ft-lbs TQ, WOB = 20K. PU = 127K, SO = 90K & ROT = 120K. MW = 9.3 ppg, Vis = 108, ECD = 10.33 ppg,
max gas = 57 units.
6/30/2023 Drill 12-1/4" surface hole from 3,369' to 4,045' (3,212' TVD). Drilled 676' = 112.7'/hr AROP. 523 GPM = 2,050 psi, 80 RPM = 8K ft-lbs TQ, WOB = 20K. PU =
145K, SO = 100K & ROT = 123K. MW = 9.3 ppg, Vis = 119, ECD = 10.6 ppg, max gas = 82 units. Rig back on highline at 09:45 hours. Begin 4 deg/100' build and
continue to turn at 3,500'. Drill 12-1/4" surface hole from 4,045' to 4,655' (3,606' TVD). Drilled 610' = 101.7'/hr AROP. 544 GPM = 2,050 psi, 80 RPM = 12-14K ft-
lbs TQ, WOB = 12-15K. PU = 163K, SO = 102K & ROT = 131K. MW = 9.2+ ppg, Vis = 79, ECD = 10.27 ppg, max gas = 296 units. Pump 30 bbl hi-vis sweep at
4,325', back 500 strokes late with 40% increase. Drill 12-1/4" surface hole from 4,655' to 5,162' (3,829' TVD). Drilled 507' = 84.5'/hr AROP. 548 GPM = 2,190 psi,
80 RPM = 11-14K ft-lbs TQ, WOB = 17-19K. PU = 163K, SO = 98K & ROT = 127K. MW = 9.3+ ppg, Vis = 92, ECD = 10.54 ppg, max gas = 258 units. Drill 12-
1/4" surface hole from 5,162' to 5,696' (3,897' TVD). Drilled 534' = 89'/hr AROP. 548 GPM = 2,300 psi, 80 RPM = 12K ft-lbs TQ, WOB = 13K. PU = 155K, SO =
80K & ROT = 116K. MW = 9.5 ppg, Vis = 83, ECD = 10.88 ppg, max gas = 156 units. Distance from WP06 at survey depth of 5,466.89 = 12.61' (2.64 high & 12.34
left).
7/1/2023 Drill 12-1/4" surface hole from 5,696' to 5,973' (3,932' TVD). Drilled 277' = 92.3'/hr AROP. 553 GPM = 2,330 psi, 80 RPM = 13K ft-lbs TQ, WOB = 15-20K. PU =
157K, SO = 90K & ROT = 120K. MW = 9.3+ ppg, Vis = 74, ECD = 10.79 ppg, max gas = 156 units. Geo called TD at 5,973', 4' TVD below top of Schrader Bluff OA-
sands. Obtain final MWD survey on bottom. Distance from WP06 at survey depth of 5,973 = 4.72' (4.72 high & 4.36 left). Pump 30 bbl High-vs sweep around.
Continue to reciprocate string and alternate stop points from 5,973' to 5,883' to avoid ledges. 550 GPM = 2,080 psi, 80 RPM = 10K ft-lbs TQ. Did not see sweep at
surface. Continue to circulate and condition mud per Mud Engineer. Circulate 2.5x bottoms up strokes. Rack back a stand with each bottoms up. 550 GPM = 2,080
psi, 80 RPM = 12K ft-lbs TQ, MW in/out = 9.4/9.5+ ppg, Vis in/out = 59/144. RIH to bottom with no issues and monitor well for 10 min - static. BROOH from 5,973'
to 3,603' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. 550 GPM = 1,610 psi, 60 RPM = 7-10K ft-bs TQ, max gas = 179 units. PU =
138K, SO = 94K, ROT = 112K. BROOH from 3,603' to 748' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. Circulate 2 bottoms up on
the last stand of DP. 550 GPM = 1,350 psi, 60 RPM = 2-3K ft-bs TQ, max gas = 189 units. PU = 90K, SO = 85K, ROT = 87K. Lost 60.5 bbls while BROOH. Monitor
the well for flow - static. TOOH standing back HWDP and jars from 748' to 191'. POOH laying down 3 NMFC's from 191' to 97'. Plug in and download MWD data.
Lay down remaining BHA from 97' to surface. 12-1/4" Kymera Dull Bit Grade: PDC = 1-1-BT-T-X-I-NO-TD & Cones = 1-1-LT-G-E-I-ER-TD. Clean and clear the
floor. Flush the flowline with the cement hose. Mobilize casing running equipment to rig floor. Make up Volant CRT, bail extensions, elevators, spiders and tongs.
Make up crossover to FOSV. Verify pipe counts and tally. Static loss rate = 3 BPH. PJSM with rig crew, DDI Casing and Halliburton Cementing. PU the float shoe to
42'.
6/28/2023Spud Date:
Well Name:
Field:
County/State:
MP M-60
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
50-029-23755-00-00API #:
7/2/2023 MU 1 joint of 9-5/8" casing and float shoe. Fill the casing and check floats - good. Install the top hat and MU the baffle adapter to 165'. BakerLok connections 1-4
with 9K ft-lb TQ. RIH with 9-5/8", 40#, L-80, BTC casing from 165' to 2,373' installing centralizers per tally. TQ = 9K ft-lbs with Volant tool. Fill on the fly and top off
every 10 joints. PU = 140K & SO = 100K. Circulate BU while RIH from 2,373' to 2,455' at 5 BPM = 160 psi. RIH with 9-5/8", 40#, L-80, BTC casing from 2,455' to
3,534' installing centralizers per tally. TQ = 9K ft-lbs with Volant tool. Fill on the fly and top off every 10 joints. PU = 195K & SO = 112K. MU the ES cementer and
BakerLoc the connections to 3,572'. RIH with 9-5/8", 47#, L-80, BTC casing from 3,572' to TD at 5,973' installing centralizers per tally. TQ = 9K ft-lbs with Volant
tool. Fill on the fly and top off every 10 joints. PU = 270K & SO = 135K. Lost 66.5 bbls while running casing. Stage the pumps up to 6 BPM = 390 psi (ICP).
Circulate and condition the mud while reciprocating 30'. FCP = 160 psi. MW = 9.3 ppg, Vis = 47 & YP = 12. SimOps. Cementer spotted in and RU. Prep the mud
pits for cement job. Break out the Volant clean the cup and dies. Redope the cut and reengage the Volant. Blow down the top drive and RU cement line to the
Volant. PJSM with all parties involved. SimOps: Continue to circulate at 6 BPM and reciprocating 30'. Shut down the pumps. HES flood line with fresh water and
break circulation with 5 bbls. PT lines to 1,000/4,500 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 BPM = 110 psi. Drop bypass plug. Mix and pump 182 bbls of 12.0 ppg lead cement (EconoCem, Type I/II), 2.347ft^3/sk yield, 445
sks total) at 4 BPM = 261 psi. Mix and pump 82 bbls of 15.8 ppg tail cement (HalChem type 1-2 cement, 1.155 ft^3/sk yield, 400 sks total) at 3 BPM = 305 psi. Drop
shut off plug. HES pump 20 bbls water at 6 BPM = 380 psi. Displace with 230 bbls of 9.3 ppg spud mud from the rig at 6 BPM = 190 psi.
7/3/2023 Shut down and displace with 80 bbls tuned spacer from cementers. Continue to displace with 108 bbls mud from rig pumps. 6 BPM = 800 psi (ICP) & 830 psi
(FCP), reduced rate to 5 BPM for last 15 bbls. Observe plug bump on calculated strokes at 830 psi. Increase pressure to 1,330 psi (500 psi over bump). Pressure
bleed to 500 psi over 1 min. Check floats - not holding. Attempt to pressure up and seat plug. Pressure up to 1,500 psi and observe flow bypassing plug. Verify
floats not holding. CIP at 06:37. Discuss with HES Cementers and Drilling Engineer. Decision made to wait for tail cement to thicken and check floats again. Wait on
cement to thicken. SimOps: General housekeeping. Check floats - no flow. Un-sting Volant CRT and drop free-fall opening plug and allow to fall for 20 minutes.
Bring on pumps at 4 BPM and observe ES Cementer open at 1,280 psi. Establish circulation through ES Cementer at 4 BPM = 300 psi. Stage up to 5 BPM = 210
psi and circulate 5 bottoms up. 60 bbls of tuned spacer, 41 bbls of cement (10.4 ppg density) and 103 bbl of interface returned to surface. Shut down and flush
stack and surface equipment with blackwater pills. Clean cement valves and drip pan. Reestablish circulation through ES Cementer and stage up to 5 BPM = 200
psi. Prep for 2nd stage cement job. Break out the Volant, dope the cup and MU the Volant. Hold PJSM with all parties involved. Continue circulating while finish
staging H2O truck and prime up. Blow air through the cement line to the cement unit. Shut down the pumps. HES flood line with fresh water and break circulation
with 5 bbls. PT lines to 1,000/4,500 psi - good test. Pump 2nd stage cement job: . Mix & pump 60 bbls of 10.0 ppg Tuned Spacer with 4# red dye & 5# Pol-E-Flake
in 1st 10 bbls at 3 BPM = 151 psi. Mix & pump total 363 bbls 10.7 ppg ArcticCem lead cement (718 sx at 2.855 ft^3/sk yield) at 7 BPM = 680 psi (ICP) & 800 psi
(FCP). At 270 bbls of cement pumped start seeing spacer returns, dump returns to rock washer. At 350 bbls of cement pumped seeing good cement returns. Mix &
pump 56 bbls of 15.8 ppg HalCem tail cement (270 sx at 1.165 ft^3/sk yield) at 3 BPM= 287 psi. Drop the closing plug. Pump 20 bbls of 8.34 ppg fresh. Pump 20
bbls of 8.34 ppg fresh at 6 BPM = 380 psi. Displace cement with 9.4 ppg spud mud. 6 BPM = 210 psi (ICP) & 750 psi (FCP). Slowed to 5 BPM = 760 psi for last 10
bbls. Bumped plug at 1,534 strokes (2.6 bbls early). Pressure up & shift ES cementer closed at 2,030 psi. Pressure up to 2,200 psi, shut off the pump and pressure
quickly dropped to 1,350 psi. Bring the pressure up to 2,500 psi, shut off the pumps and the pressure dropped to 1,035 psi in 30 seconds. Quickly bleed the
pressure to 0 psi. Shu.t in & pressure jumped to 257 psi. Quickly pressuring up to 2,500 psi & observed flow up the annulus. Shut down the pumps & pressure
dropped rapidly. Check for flow, still flowing out the casing. Shut in the casing. CIP at 21:45 hours. Had 60 bbls of tuned spacer, 247 bbls 10.7 pg ArcticCem
cement and 118 bbls of interface returned to surface. Discuss with HES Cementers and Drilling Engineer. Decision made to wait for tail cement to get to 50 psi
compressive strength and check floats again. Blow down lines. Disconnect the knife valve from the accumulator. Drain the cement from the stack to the cellar and
flush with black water. Demobilize casing running equipment off the rig floor. Wait on cement. Clean and clear. General housekeeping around the rig. Load test
joints and BHA into the pipe shed. Open up the well and check for flow - none. Observe the well for flow for 30 minutes - static. RD circulating and Volant tool.
7/4/2023 Continue to rig down cement line and volant tool. Suck out mud from last joint utilizing the rig vac. ND diverter stack and PU. Install casing slips and set casing with
100K on the slips. Cut 9-5/8" casing joint and lay down. Cut joint = 37.29'. Continue to nipple down the diverter stack, riser, knife valve and diverter "T". Install slip-
loc wellhead per wellhead rep. Pressure test wellhead void to 500/3,800 psi per wellhead rep - good test. NU the casing & tubing head. NU the BOP stack. Install
the kill liner and riser. Obtain RKB's. Install 1502 flange on the OA. RU BOPE testing equipment. Install the test plug. Flood the BOP stack, lines and choke
manifold with fresh water. Purge air from the system. Shell test the BOP stack to 250/3,000 psi (passed). Conduct initial BOPE test to 250/3,000 psi: UPR (4-1/2 x
7 VBRs) with 4-1/2 & 7 test joints, LPR (2-7/8 x 5 VBRs) with 4-1/2 & 5 test joints, annular with 4-1/2 & 7 test joints, accumulator drawdown test and test gas alarms.
All tests performed with fresh water against test plug. The states right to witness was waived by AOGCC inspector Sully Sullivan via email on 7/04/23 at 16:55
hours. Tests:. 1.Annular with 4-1/2 test joint, 3 Demco kill, 5 FOSV, choke valves 1, 12, 13 & 14 (passed). 2.UPR with 4-1/2 test joint, 5 dart valve, HCR kill,
choke valves 9 & 11 (passed). 3.LPR with 4-1/2 test joint (passed). 4.UPR with 7 test joint, upper IBOP, manual kill, choke valves 5, 8 & 10 (passed). 5.Lower
IBOP, choke valves 4, 6 & 7 (passed). 6.3-1/2 FOSV, Choke valve 2 (passed). 7.HCR choke, 3-1/2 dart valve (passed). 8.Manual choke (passed). 9.LPR
with 5 test joint (passed). 10.Blind rams, choke valve 3 (passed). 11.Hydraulic super choke (fail/pass). 12.Manual adjustable choke (passed). Accumulator
Test:. System pressure = 3,125 psi. Pressure after closure = 1,700 psi. 200 psi attained in 47 seconds. Full pressure attained in 202 seconds. Nitrogen Bottles - 6
at 1,981 psi. Control System Response Time:. Annular = 19 seconds. UPR, blind rams & LPR = 7 seconds. HCR choke & kill = 2 second. Pull the test plug and
install the wear ring (ID = 9"). Blow down and RD testing equipment. Mobilize BHA components to the rig floor. M/U 8-1/2" Cleanout BHA: 8-1/2" tricone bit, 6-3/4"
mud motor with non-ported float installed in top and ABH set at 1.5 deg to 32'. TIH with 6 stands 5" HWDP including jar stand to 589'.
At 350 bbls of cement pumped seeing good cement returns
Observe plug bump on calculated strokes at 830 psi. Increase pressure to 1,330 psi (500 psi over bump). Pressure
bleed to 500 psi over 1 min. Check floats - not holding
Check floats - no flow
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 BPM = 110 psi. Drop bypass plug. Mix and pump 182 bbls of 12.0 ppg lead cement (EconoCem, Type I/II), 2.347ft^3/sk yield, 445
sks total) at 4 BPM = 261 psi. Mix and pump 82 bbls of 15.8 ppg tail cement (HalChem type 1-2 cement, 1.155 ft^3/sk yield, 400 sks total) at 3 BPM = 305 psi. Drop
shut off plug. HES pump 20 bbls water at 6 BPM = 380 psi. Displace with 230 bbls of 9.3 ppg spud mud from the rig at 6 BPM = 190 psi.
103 bbl of interface returned to surface
7/5/2023 TIH with 8-1/2" cleanout BHA from 589' to hard tag with 20K down at 2,383' (33' above ES cementer). Stand back a stand to 2,301'. Circulate surface to surface to
condition the mud for PT. RU testing equipment and purge air. Attempt to PT the casing to 2,500 psi, once pressure reached 2,200 psi the pressure dropped to 775
psi in 1 minute. Then bled down to 395 psi over the next 5 minutes. Blow down and rig down test equipment. Discuss options with town Engineer. Decision is to
proceed with drilling out the ES cementer. RIH from 2,301' to top of the ES at 2,416' - no cement observed. Drill out plugs, cement and ES cement to 2,437' at 400
GPM = 720 psi, 50 RPM = 5K ft-lbs TQ, WOB = 3-7K, PU = 105, SO = 80K & ROT = 80K. Wash down to 2,682' without rotation. Drift through ES cementer without
pumps and rotation. Pump 30 hi-vis sweep and circulate out of the hole at 400 GPM = 760 psi, 40 RPM = 5K ft-lbs TQ. Sweep back on time with 50% increase.
Pump dry job and blow down the top drive. TOOH from 2,682' to 589'. Stand back 6 stands of HWDP including jars. Drain the mud motor and break out the bit. Bit
grade: 1-1-WT-A-E-2-NO-BHA. Clear and clean the rig floor. MU 9-5/8" Model 'B' retrievamatic (test packer) to 15'. TIH with test packer from 15' to 2,411'. Set the
test packer with center of element at 2,405' (11' above the ES cementer). Fill lines and purge the air. Close the UPR. PT the 5" x 9-5/8" annulus to 2,500 psi for 10
minutes - good test. Bleed pressure to 0 psi and open UPR. RIH to 2432'. Set the test packer with center of element at 2,426' (7' below the ES cementer). Fill lines
and purge the air. Pressure up on the DP, PT the 9-5/8" casing below the test packer to 2,500 psi for 10 minutes - good test. Bleed to 0 psi. Line up to the IA. Close
the UPR. Bring the pump on and establish a leak rate of 2 BPM = 640 psi. Bleed off the pressure and open the UPR. Release the test packer and manipulate into
run mode. Blow down the top drive. TOOH from 2,432' and lay down the test packer. Clear and clean rig floor. Mobilize CIBP in shed and prep with proper mandrel.
M/U Baker 9-5/8" N-1 CIBP to 12'. TIH with CIBP from 12' to 2,457'. PUW = 91K, SOW = 76K. Drop 1-7/16" phenolic ball and let gravity fall for 5 min. Line up to rig
pumps and pressure up to 2,000 psi at 1 BPM, setting CIBP. Hold for 2 min. Pull up 145K and release from bridge plug. Top of CIBP at 2,455'. Rack back 2 stands.
Blow down the top drive. TOOH from 2,294' and lay down the running tool. PUW = 86K, SOW = 75K. High Line power in field went down @ 00:32. Put Rig on Gen
power @ 00:37. Clear and clean rig floor. Redress running tool for cast iron cement retainer. M/U 9-5/8" CICR to 12'. TIH with CICR from 12' to 2,379'. PUW = 89K,
SOW = 76K. Drop 1-7/16" phenolic ball and let gravity fall for 5 min. Line up to rig pumps and pressure up to 2,200 psi at 1 BPM, setting CICR. Hold for 2 min. Pull
up 105K and release from retainer. Top of cement retainer at 2,377'. Rack back 1 stand. Blow down the top drive. TOOH from 2,295' and lay down the running tool.
Clear and clean rig floor. Mobilize cement stinger to floor & M/U same. TIH with cement stinger to 480'.
7/6/2023 TIH with cement stinger from 480' to 2,354'. PU = 86K & SO = 75K. MU side entry sub, FOSV and 10' DP pup joint. RU circulating equipment. Obtain pumping
parameters at 1 BPM = 30 psi, 2 BPM = 70 psi & 3 BPM = 100 psi. RIH to 2,379' and snap in cement stinger into the retainer. Establish injection rates at 1 BPM =
480 psi, 2 BPM = 650 psi & 3 BPM = 680 psi. PJSM. HES fill line with 2 bbls and PT to 1,000/4,000 psi - good test. Pump 8 bbls of fresh water at 3 BPM = 650 psi.
Pump a total of 60 bbls of 15.8 HalChem cement at 3 BPM = 670 psi (ICP) & 210 psi (FCP) for the first 40 bbl then slowed to 1 BPM = 100 psi for the remaining 20
bbls. Pump 10 bbls of fresh water at 1.5 BPM = 280 psi. Swap to the rig to displace. Pump the first 10 bbls at 3 BPM = 670 psi. Pump the next 10 bbls at 1 BPM =
500 psi (ICP) & 650 psi (FCP). Shut down the pump, pressure dropped to 580 psi and wait 15 minutes. Pressure bled down to 480 psi. Bring the pump on at 1
BPM and pump 2 bbls with FCP = 880 psi. Shut down the pumps, pressure dropped to 680 psi and wait 5 minutes. Pressure bled down to 620 psi. Bring the pump
on at 1 BPM and pump 2 bbls with FCP = 830 psi. Shut down the pumps and pull the cement stinger from the retainer. Final pressure prior to pulling out was 770
psi. Pump 1.5 bbls under calculated displacement. Slowly PU 25' to 2,354'. CIP at 11:32 hours. Circulate 2 BU at 10 BPM = 620 psi. No cement observed at
surface. RD and blow down circulating equipment. Break out pup joint, FOSV and side entry sub. Load wiper ball and pump DP volume at 5 BPM = 210 psi. Blow
down the top drive. TOOH from 2,354' to 5'. Lay down cement stinger. Clean and clear the floor. Wait on cement. General housekeeping and maintenance.
Processing 4.5" screens. Needle gunning second level floor. Install MPD drip pan. Rig back on hi-line power at 16:50 hours. Wait on cement. General
housekeeping and maintenance. Continue processing screens & needle gunning second level floor. Adjust mud bucket counterweight.
7/7/2023 Wait for magnet and boot baskets to arrive. General housekeeping. Needle gunning floor on the second level. Add weight to the mud bucket counterweight. Work on
MP2's. Mobilize BHA components to the rig floor. Strap, OD and ID all components. PJSM. MU cleanout #2 assembly (BHA#4): 8-1/2" tricone, mud motor, string
magnet and 3 boot baskets to 63'. TIH with 5" HWDP from 63' to 620'. TIH with BHA#4 from 620' to 2,332'. PU = 110K & SO = 80K. Fill the DP. Wash down at 2
BPM = 190 psi tagging hard cement at 2,374' with 5K down. Drill cement from 2,374' to the top of the cement retainer at 2,377' at 400 GPM = 780 psi, 40 RPM =
6K ft-lbs TQ, WOB = 5-10K. Drill 9-5/8" cement retainer from 2,377' to 2,379', 350-400 GPM = 680-780 psi, 40-50 RPM = 3-10K TQ, 5-12k WOB. Drill hard
cement and possible retainer debris from 2,378' to 2,386'. 350-500 GPM = 680-1100 psi, 40-50 RPM = 3-10K Tq, 3-12K WOB, PU = 105K, SO = 80K & ROT =
90K. Stroke sting up to 2,332' w/ no rotary. Slack off and tag up, taking 15K Wt @ 2,353'. Attempt to work string down with & w/o rotary, tagging up each time @
2K353'. no differential increase. 40 RPM = 3-10K Tq, 385 GPM = 685 psi. Rack back 1 stand, PU t/ 2,235' and take Wt @ 2,244' when slack off. Blow down TD.
POOH on elevators f/ 2235' t/ 65'. Observe 10-25k overpull bobbles at ~40' intervals from 2201' to 1967' indicating debris catching at casing connections. PU.
Inspect motor & bit. Both clean with no abnormal wear or debris. Clean string magnet& break down boot baskets. Clean boot baskets & make back up. Recovered
49 lbs of metal shavings and debris up to 2.5"x3" removed from Magnet & a cup of metal debris up to 2"x2" removed from boot baskets. TIH with 5" HWDP from 63'
to 620'. Continue TIH on 5" DP from 620' to 2,332'. PU = 100K & SO = 70K. Wash/Ream down f/ 2,332' t/ 2,386' 400 GPM=720 psi, 40 RPM=2-5K TQ. Drill Hard
cement & debris f/ 2,386' t/ 2,389' @ 3 FPH 400 GPM=740 psi, 40 RPM=3-8K TQ, 5-8K WOB. Drill cement f/ 2,389' t/ 2,424' @ 5-50 FPH 400 GPM=740 psi, 40
RPM=3-8K TQ 5-10K WOB. ROP slowed to 5 FPH from top of ESC at 2,416'.
7/8/2023 Drill cement from 2,424' to 2,455' at 350--450 GPM = 730-923 psi, 30-40 RPM = 5-10K ft-lbs TQ, WOB = 5-15K. Drill CIBP from 2,455' to 2,457' at 200 GPM =
410 psi, 5 RPM = 5-7K ft-lbs TQ, WOB = 10-15K. Wash down to 2,523' without issue. Circulate 2 BU at 550 GPM = 1,190 psi. TIH with cleanout #2 assembly
(BHA #4) from 2,523' to 5,665'. PU = 215K & SO = 75K. Wash down from 5,665' to 5,725', tagging on soft cement at 5,712'. Drill hard cement from 5,725' to 5,835'
at 200-550 GPM = 460-1,640 psi, 2-40 RPM = 5-20K ft-lbs TQ, WOB = 5-20K. Circulate and condition the mud. Stand back 1 stand of DP. RU testing equipment,
fill lines and purge air. Attempt to PT the casing to 1,000 psi but the pressure bled off. Discuss results with Drilling Engineer. RD and blow down testing equipment.
MU stand of DP. Wash down to cement at 5,835'. Drill cement, baffle adapter and float collar from 5,835' to 5,959' at 500 GPM = 1,540 psi, 40 RPM = 14-15K ft-lbs
TQ, PU = 197K, SO = 85K & ROT = 120K. BA and FC on depth. Reamed through each twice and drifted once. Pump 35 bbls Hi-Vis sweep and circulate hole
clean. 550 GPM, 1550 psi. 50 RPM, 15-16k Tq. Rot and recip string 70'. Sweep retuned on time with 20% increase. Monitor well while finish build dryjob. Well
static. Pump dryjob and lay down single 5" DP to put string on even stands. POOH on elevators from 5948' to HWDP at 620'. Monitor well - Static. POOH laying
down all HWDP and Jars. Clean magnet and break down boot baskets. Break bit and lay down Motor. Bit grade: 3-2-BT-N-E-I-WT-BHA. Empty boot baskets and
send off floor. 35lbs of metal removed from magnet and 32lbs recovered from boot baskets. Correct hole fill recorded on trip out of hole. Clean rig floor & clear rig
floor. Remove master bushings and Install split bushing. MU 8-1/2" NOV PDC bit, NRP-A2 bit sleeve, 7600 Geo-Pilot, ADR, ILS, DGR, PWD, GWD, Directional &
Telemetry collars and IBS to 102'. Plug in and initialize MWD. M/U remaining BHA #5, NM float sub, NM flex collars, NM float sub, NM flex collars and 2 HWDP
with jars to 257'. TIH with 8-1/2" RSS lateral BHA from 257' to 1208' on 5'' drill pipe. M/U top drive fill pipe, Break in geo pilot seals, shallow pulse test MWD tools,
430 gpm, 870 psi, 40 rpm, 2K torque. 75k PU, 70k SO, 72k ROT. Continue trip in hole from 1208' to 2541'.
MU 9-5/8" Model 'B' retrievamatic (test packer
PT the 9-5/8" casing below the test packer to 2,500 psi for 10 minutes - good test.
Drill 9-5/8" cement retainer from 2,377' to 2,379',
Attempt to PT the casing to 1,000 psi but the pressure bled off
7/9/2023 TIH with 8-1/2" RSS lateral BHA from 2,541' to 5,587'. PU = 196K & SO = 80K. Single in the hole with 5" DP from the pipe shed from 5,587' to 5,937'. Wash down
from 5,937' to 5,9599'. Drill cement, shoe and rat hole to 5,973'. Drill 20' of new formation to 5,993' at 500 GPM = 1,630 psi, 60 RPM = 14K ft-lbs TQ, WOB = 5K.
CBU racking back 1 stand to 5,969'. PJSM. Drain the stack to below the riser and pull the MPD riser. Install the MPD RCD bearing and drip pan skirt. PJSM. Pump
pit 4 empty. Pump 30 bbl hi-vis spacer. Displace the well from 9.3 ppg spud mud to 8.8 ppg FloPro at 6 BPM = 640 psi (ICP), 40 RPM = 15K ft-lbs TQ. Wash to
bottom when spacer is at the bit then pull up slowly to the shoe when new mud is coming up the backside. Reciprocating 80'. Pumped a total of 466 bbls of 8.8 ppg
FloPro dumping 30 bbls of spacer and 75 bbls of interface. FCP at 7 BPM = 640 psi, 40 RPM = 7K ft-lbs TQ. Shut in and monitor for pressure build with MPD -
none. PJSM. Slip and cut 73' (11 wraps) of drilling line. Service the top drive. Inspect the saver sub - good. Changeout door side grabber dies. Calibrate block
height. Check the crown saver. SimOps: Clean pit 4 and surface equipment. Flush mud pump #1 with new mud. Obtain SPR's. Drill 8-1/2" lateral from 5993' to
6158 (3949' TVD). Drilled 165' = 82.5'/hr AROP. 500 GPM = 1490 psi, 80 RPM = 6K ft-lbs TQ, WOB = 14-17K. PU = 125K, SO = 105K & ROT = 112K. MW = 8.8
ppg, Vis = 47, ECD = 10.10 ppg, max gas = 383u. Drill down section through the OA-1. MPD choke full open while drilling, shut in w/ no psi build on conn. Drill 8-
1/2" lateral from 6158' to 6635' (3962' TVD). Drilled 477' = 79.5'/hr AROP. 550 GPM = 1540 psi, 120 RPM = 7K ft-lbs TQ, WOB = 10K. PU = 135K, SO = 85K &
ROT = 115K. MW = 8.99 ppg, Vis = 43, ECD = 10.36 ppg, max gas = 553u. Continue to drill down section from the OA-1 entering the OA-3 at 6390'. MPD choke
full open while drilling, shut in with no psi build on connection. Drill 8-1/2" lateral from 6635' to 7355' (3961' TVD). Drilled 720' = 120'/hr AROP. 550 GPM = 1600
psi, 120 RPM = 7K ft-lbs TQ, WOB = 10K. PU = 165K, SO = 87K & ROT = 115K. MW = 8.9 ppg, Vis = 42, ECD = 10.28 ppg, max gas = 532u. MPD choke full
open while drilling, start trapping 80 psi on connection. Undulate back up, exiting the OA-3 at 6705' and reacquiring the OA-1 at 6870'. Drilled through fault #1 at
6920' with a 6' DTW throw moving wellbore from the lower OA-1 to the upper OA-1. Pump Hi-Vis sweep at 7015'. Return on time with 100% increase. We have
drilled 15 concretions for a total thickness of 96 (7.2% of the lateral). Last survey at 7231.99 MD / 3962.59' TVD, 89.02 inc, 334.04 azm, 19.56 from plan, 19.44' low
and 2.16 left.
7/10/2023 Drill 8-1/2" lateral from 7,355' to 8,061' (3,971' TVD). Drilled 706' = 117.7'/hr AROP. 540 GPM = 1,680 psi, 120 RPM = 8K ft-lbs TQ, WOB = 13K. PU = 145K, SO
= 85K & ROT = 115K. MW = 8.9+ ppg, Vis = 44, ECD = 10.58 ppg, max gas = 659 units. MPD choke full open while drilling, trapping 80 psi on connections. Begin
planned undulation down at 7,586', exiting the OA-1 at 7,822' and entering the OA-3 at 8,054'. Drill 8-1/2" lateral from 8,061' to 8,725' (3,993' TVD). Drilled 664' =
102.2'/hr AROP. 548 GPM = 1,800 psi, 120 RPM = 10K ft-lbs TQ, WOB = 13K. PU = 147K, SO = 82K & ROT = 112K. MW = 8.9+ ppg, Vis = 40, ECD = 10.69
ppg, max gas = 608 units. MPD choke full open while drilling, trapping 80 psi on connections. Pump 30 bbl hi-vis sweep at 8,062', back on time with 100%
increase. Steady drop to the lower middle section of the OA-3, geo-steering to formation dip @ ~89.1 deg. Lost Hi-Line power to Rig at 18:24. Start and warm up
Rig Generator. Doyon call out Rig electrician to put Rig onto Gen power. On Rig Gen power at 18:43. Troubleshoot lack of power to Drawworks. Swap SCR
assignments and obtain full power. Drill 8-1/2" lateral from 8725' to 9098' (3993' TVD). Drilled 373' = 74.6'/hr AROP. 550 GPM = 1,860 psi, 120 RPM = 9K ft-lbs
TQ, WOB = 11K. PU = 148K, SO = 82K & ROT = 115K. MW = 9.0 ppg, Vis = 40, ECD = 10.63 ppg, max gas = 647 units. MPD choke full open while drilling,
trapping 80 psi on connections. Pump 30 bbl hi-vis sweep at 9014', back on time with 100% increase. Maintain OA-3 and then start building at 8935', to revert up to
OA-1. Drill 8-1/2" lateral from 9098' to 9900' (3986' TVD). Drilled 802' = 133.7'/hr AROP. 550 GPM = 2000 psi, 120 RPM = 9K ft-lbs TQ, WOB = 12K. PU = 147K,
SO = 75K & ROT = 110K. MW = 9.05 ppg, Vis = 44, ECD = 11.03 ppg, max gas = 811 units. MPD choke full open while drilling, trapping 80 psi on connections.
Exiting the OA-3 at 9172' and enter the OA-1 at 9265'. We have drilled 33 concretions for a total thickness of 245 (6.5% of the lateral). Last survey at 9800.82' MD /
3985.60' TVD, 89.46 deg inc, 337.22 deg azm, 30.41' from plan, 27.61' low and 12.75' left. **Rig back on Hi-Line power at 00:20**.
7/11/2023 Drill 8-1/2" lateral from 9,900' to 10,535' (3,952' TVD). Drilled 635' = 105.8'/hr AROP. 536 GPM = 2,070 psi, 120 RPM = 11K ft-lbs TQ, WOB = 12-15K. PU =
148K, SO = 68K & ROT = 105K. MW = 9.0+ ppg, Vis = 41, ECD = 11.12 ppg, max gas = 811 units. MPD choke full open while drilling, trapping 80 psi on
connections. Begin undulation up at 10,086' in preparation for upcoming fault. Pump 30 bbl hi-vis sweep at 10,060', back on time with 100% increase. Encountered
fault #2 at 10,458' with 45' DTE throw moving the wellbore from the OA-1 to below the OA sand. Drill 8-1/2" lateral from 10,535' to 11,086' (3,909' TVD). Drilled 551'
= 91.8'/hr AROP. 550 GPM = 2,360 psi, 120 RPM = 10K ft-lbs TQ, WOB = 12K. PU = 150K, SO = 70K & ROT = 107K. MW = 9.1 ppg, Vis = 42, ECD = 11.67 ppg,
max gas = 408 units. MPD choke full open while drilling, trapping 80 psi on connections. Entered the OA-3 at 10,587'. Encountered fault #3 at 10,675' with 31' DTE
throw moving the wellbore from OA-3 to below the OA sand. Entered the OA-3 at 10,990'. Pump 30 bbl hi-vis sweep at 11,010', back on time with 100% increase.
Drill 8-1/2" lateral from 11,086' to 11,584' (3,901' TVD). Drilled 498' = 83'/hr AROP. 550 GPM = 2,220 psi, 120 RPM = 12K ft-lbs TQ, WOB = 8-9K. PU = 152K, SO
= 50K & ROT = 105K. MW = 9.0 ppg, Vis = 40, ECD = 11.22 ppg, max gas = 514 units. MPD choke full open while drilling, trapping 80 psi on connections. Dump
and dilute 230 bbls at 11,153', dropped MBT from 7.5 to 5.5. Continue drill up section, entering the OA-1 @ 11,260'. Drill 8-1/2" lateral from 11,584' to 12,153'
(3932' TVD). Drilled 569' = 94.83'/hr AROP. 550 GPM = 2,290 psi, 120 RPM = 14K ft-lbs TQ, WOB = 8K. PU = 156K, SO = 56K & ROT = 104K. MW = 9.05 ppg,
Vis = 46, ECD = 11.25 ppg, max gas = 573 units. MPD choke full open while drilling, trapping 80 psi on conn. Undulate down and enter the OA-3 at 11943'. Pump
30 bbl hi-vis sweep at 12,054', back on time with 100% increase. We have drilled 49 concretions for a total thickness of 350 (5.7% of the lateral). Last survey at
1284.70' MD / 3930.55' TVD, 87.79 deg inc, 333.16 deg azm, 22.18' from plan, 19.29' low and 10.96' right.
7/12/2023 Drill 8-1/2" lateral from 12153' to 12411' (3942' TVD), 258' drilled, 43'/hr AROP. 550 GPM = 2200 PSI, 120 RPM = 14K ft-lbs Tq, 5-15K WOB. MW = 9.05 ppg, vis
= 39, ECD = 10.98, Max Gas = 550u. PU = 156K, SO = 0K ROT = 106K. MPD choke full open while drilling, trapping 80 psi on connections. Drill down from upper
toward the middle-lower OA-3. Drill 8-1/2" lateral from 12411' to 12802' (3932' TVD), 391' drilled, 65.2'/hr AROP. 550 GPM = 2150 PSI, 120 RPM = 13K ft-lbs Tq, 5-
15K WOB. MW = 9.0 ppg, vis = 38, ECD = 10.94, Max Gas = 572u. PU = 165K, SO = 0K ROT = 113K. MPD choke full open while drilling, trapping 80 psi on
connections. Drill down to the middle-lower OA-3 until 12500 then build angle and drill upward undulation, entering the OA-1 at 12725'. Perform 290 bbl dump and
dilute at 12630', drop MBT f/ 6.5 t/ 5.0. Drill 8-1/2" lateral from 12802' to 13272' (3938' TVD), 470' drilled, 78.3'/hr AROP. 550 GPM = 2140 PSI, 120 RPM = 13K ft-
lbs Tq, 5-15K WOB. MW = 8.95 ppg, vis = 44, ECD = 11.28, Max Gas = 575u. PU = 165K, SO = 0K ROT = 107K. MPD choke full open while drilling, trapping 80
psi on connections. Hi-Vis sweep at 13009', returned on time with 50% increase. Continue drilling up through OA-1, peaking at 13,000' then drop angle and start
downward undulation. Drill 8-1/2" lateral from 13272' to 14025' (3950' TVD), 753' drilled, 125.5'/hr AROP. 550 GPM = 2360 PSI, 120 RPM = 13K ft-lbs Tq, 5-13K
WOB. MW = 9.0 ppg, vis = 42, ECD = 11.35, Max Gas = 483u. PU = 170K, SO = 0K ROT = 103K. MPD choke full open while drilling, trapping 80 psi on
connections. Continue drilling downward, undulation through OA-1. Fault #4 at 13,390' with 5' DTE throw moving the wellbore from the OA-1 to the OA-2. Fault #5
at 13,730' with 8' DTW throw moving the wellbore from the OA-3 to the OA-2. Last survey at 13891.63' MD / 3952.05' TVD, 89.20 deg inc, 333.34 deg azm, 26.95'
from plan, 25.47' low and 8.81' left. We have drilled 72 concretions for a total thickness of 539' (6.8% of the lateral).
7/13/2023 Drill 8-1/2" lateral from 14025' to 14150' (3962' TVD), ' drilled, 21'/hr AROP. 550 GPM = 2200 PSI, 120 RPM = 14K ft-lbs Tq, 5-13K WOB. MW = 8.9 ppg, vis = 42,
ECD = 10.90, Max Gas = 572u. PU = 173K, SO = 0K ROT = 110K. Sweep at 14055' 200 strks late 50% increase in cuttings. MPD choke full open while drilling,
trapping 80 psi on connections. Level off in OA-3 targeting 88 deg. Drill 8-1/2" lateral from 14150' to 14411' (3964' TVD), 261' drilled, 43.5'/hr AROP. 550 GPM =
2190 PSI, 120 RPM = 14K ft-lbs Tq, 5-15K WOB. MW = 8.9 ppg, vis = 42, ECD = 10.90, Max Gas = 776u. PU = 174K, SO = 0K ROT = 112K. MPD choke full
open while drilling, trapping 80 psi on connections. Continue geo-steering to OA-3 dip. Drill 8-1/2" lateral from 14411' to TD at 14701' (3965' TVD), 290' drilled,
52.7'/hr AROP. 550 GPM = 2320 PSI, 80-120 RPM = 17K ft-lbs Tq, 5-15K WOB. MW = 9.0 ppg, vis = 41, ECD = 11.25, Max Gas = 634u. PU = 187K, SO = 0K
ROT = 104K. Maintained the OA-3 to TD. Obtain SPRs & final survey. Pump 30 bbls high vis sweep - back 800 stks late with 40% increase. Circulate a total of 3x
bottoms up, racking back a stand every bottoms up from 14701' to 14438' at 550 GPM = 2470 psi, 120 RPM = 16K ft-lbs Tq. PU 171k, SO 0k, Rot 106k. Final
survey at 14630.84' MD / 3965.26' TVD, 89.55 deg INC, 331.93 deg AZM. 37.80' from plan, 37.36' low & 5.74' left. We have drilled 94 concretions for a total
thickness of 782' (9% of the lateral). Wash/ream to bottom, 420 GPM, 1580 psi. 40 RPM, 12k Tq. Continue circulate at 530 GPM, 2250 psi, 120 RPM while hold a
PJSM for displacing with all personnel. Make final preparations in mud pits, clean suction pots and purge both pumps with clean brine. 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.
Start displace with of 8.45 ppg viscosified brine with 3% lubes (1.5% 776 and 1.5% LoTorq).
7/14/2023 Continue to displace with 1011 bbls 8.45 ppg viscosified brine with 3% lubes pumping 6 bpm, 910 psi ICP, 80 rpm, 17k tq working pipe 90' from 14,701' alternating
stopping points. PU 170K, ROT 108K. Final 80 RPM = 16K ft-lbs TQ & 6 BPM = 660 psi (FCP), 67 bbl of interface. Shut down the pumps with clean 8.45 ppg
viscosified brine to surface. 0 losses. Parked at 14,684' monitor wellbore for pressure build with MPD choke 4 times 5 min each, 40 psi, 42 psi, 58 psi with the final
building to 45 psi. EMW= 8.7 ppg. Record new SPRs, wash and ream to TD. PU 190K, SO 45K, ROT 116K. Simops: Clean pit 3 and load 8.45 ppg 3% lube brine
in pits 3 & 4. BROOH from 14701' t/ 14272' pulling 5-10 minutes/stand slowing as needed to clean up tight spots. Laying down DP in the mouse hole. 425 GPM
=1150 psi 120 RPM = 16k ft-lbs TQ max gas = 156 units. PU = 190K SO = 45K ROT 116K. Choke full open while reaming. Holding 150 psi during connection.
While breaking down a stand in the mouse hole the ST-80 blew a hydraulic line. Work pipe and circulate at a reduced rate while repairing hose. 330 GPM = 924
PSI 77RPM 15k ft-lbs TQ. BROOH from 14272' t/ 13963' pulling 5-10 minutes/stand slowing as needed to clean up tight spots. Laying down DP in the mouse hole.
425 GPM =1150 psi 120 RPM = 16k ft-lbs Tq. Max gas = 156 units. PU = 190K SO = 45K ROT 116K. Choke full open while reaming. Holding 150 psi during
connection. BROOH from 13963' t/ 11010' pulling 5-10 minutes/stand slowing as needed to clean up tight spots. Laying down DP in the mouse hole. 425 GPM
=1150 psi 120 RPM = 16k ft-lbs TQ max gas = 206 units ~10 bbl/hr loss rate. PU = 157K SO = 75K ROT 116K. At 11308' encountered tight spot. Stalled rotary.
Slacked off re-established rotary and was able to work through tight spot without issue. BROOH from 11010' to 8445' pulling 5-10 minutes/stand slowing as needed
to clean up tight spots. Lay down DP to shed via the 90' mouse hole. 425-475 GPM =1160 psi 100 RPM = 10k ft-lbs Tq. Max gas = 536 units ~10 bbl/hr loss rate.
PU = 150K SO = 92K ROT 116K. BROOH from 8445' to 5971' pulling 5-10 minutes/stand slowing as needed to clean up slides/tight spots. Laying down DP in the
mouse hole. 470 GPM = 1210 psi, 120 RPM = 9K ft-lbs Tq, max gas = 642 units. PU = 150K, SO = 95K & ROT = 120K. Lost total of 224 bbls BROOH. Pump 30
bbl hi-vis sweep at 500 GPM = 1270 psi, 60 RPM = 5K ft-lbs Tq reciprocating 85' and circulate the casing clean with 2x BU. Sweep back on time with 30%
increase. Monitor the wellbore pressure build with MPD choke 3 times 5 minutes each = 73, 69, & 63. Hold choke shut in while weight up the surface system to 8.9
ppg. Pressure level off at 68 psi in 15 min. Current MW 8.7ppg. EMW = 9.0 ppg & KWF = 9.2 ppg.
7/15/2023 Weight up the surface system to 8.9 ppg. Circulate 8.9 ppg while weighting up the returns on the fly to 8.9 ppg at 6 BPM = 400 psi, 80 RPM = 3K ft-lbs TQ
reciprocating 90' until good 8.9 ppg in/out. Monitor the wellbore pressure with MPD choke 4 times 5 minutes each = 25, 20, 15 & 37 psi. Current MW 8.9ppg. EMW
= 9.1 ppg. Weight up the surface system to 9.1 ppg. Circulate 9.1 ppg while weighting up the returns on the fly to 9.1 ppg at 6 BPM = 420 psi, 80 RPM = 3K ft-lbs
TQ reciprocating 90' until good 9.1 ppg in/out. Monitor the wellbore pressure with MPD choke 4 times 5 minutes each = 33, 31, 22 11 psi. Current MW 9.1ppg.
EMW = 9.1 ppg. Weight up the surface system to 9.25 ppg. Circulate 9.25 ppg while weighting up the returns on the fly to 9.25 ppg at 6 BPM = 450 psi, 80 RPM =
3K ft-lbs TQ reciprocating 90' until good 9.25 ppg in/out. Monitor the wellbore pressure with MPD choke 2 times 5 minutes each = 0, 0 psi. Current MW 9.25ppg.
EMW = 9.25 ppg. Open 2" valve at the RCD head and monitor well. 1/4" stream going static in 1 hour. PJSM. Remove the RCD and install the MPD riser. Well
static. Fill the riser and no leaks. Pump 20 bbl dry job (10.2) blow down top drive and Geo skid. Drop 2.45" hollow drift w/100' of wire. POOH, racking back 5" DP in
Derrick, from 5969' to 320'. Monitor well - static. Rack back final stand DP to 259'. L/D HWDP, jars, float subs and NMDCs from 259' to 55'. Download MWD data.
L/D remaining BHA. Bit grade = 1-1-WT-A-X-I-NO-TD. Drift recovered from from top of Jars. 8 bbls total loss TOH. Clear and clean Rig floor. Remove split bushings
and install master bushings. Mobilize casing equipment, crossovers to the rig floor. R/U 4-1/2" double stack tongs and elevators. M/U FOSV & XOs to safety joint.
Static loss rate = 1 BPH. PJSM with all parties involved. P/U round nose float shoe on 4 1/2'' crossover joint (H625 box x BTC pin) to 40'. RIH with Cal IV 4-1/2",
13.5#, L-80, Hydril 625, 100-micron screens from 40' to 5779'. Torque to 9,600 ft-lbs with Doyon double stack tongs. Loss rate = 2.5 BPH.
7/16/2023 RIH with Cal IV 4-1/2", 13.5#, L-80, Hydril 625, 100-micron screens from 5779' to 8983'. Torque to 9,600 ft-lbs with Doyon double stack tongs. Loss rate = 1.5-2
BPH. 22.8 bbl lost on trip. MU Baker SLZXP liner top packer at 8983', RIH to 9022' then RIH with one stand of DP to 9117'. Obtain parameters, P/U 135 S/O 85K
ROT 110K, 10RPM = 6K TQ, 15RPM = 7K TQ. Pump 7 bbls at 3 BPM = 220 psi to ensure clear flow path through the packer. Blow Down TD. Sim Ops: R/D
casing tongs. RIH with 4-1/2" screen liner out of derrick on 5" DP from 9022' to 10926'. 2.2 bbls lost on trip. Cont to RIH with 4-1/2" screen liner out of derrick on 5"
DP from 10926' to tag at 14701' (TD) with 10K. P/U 200K S/O 80K. 6.7 bbl lost on trip. LD 1 joint DP. Pump 3 bbls at 3 BPM = 470 psi to ensure clear flow path.
Drop 1.125" phenolic setting ball. RU 5' pup, FOSV, side entry sub, 10' pup joint & circulating equipment. Place liner in tension at 14701' set depth. Pump ball
down with 20 bbl hi-vis sweep at 1.5 BPM = 240 psi. Ball on seat 264 strokes early at 686 strokes. Pressure up to 2,140 psi, observer set & hold for 5 minutes. S/O
to 40K to confirm set. Pressure up 3000 psi & observe release at 2510 psi. Hold for 5 minutes. Continue to pressure up with rig pump and observe ball seat shear at
3900 psi. Observe free travel at 132K. Liner top at 5690.01'. Blow down and R/D circulating equipment. Pump out of the LTP at 2 BPM = 310 psi. Once the liner
running tool is out of the LTP bring pumps up to 500 GPM = 1360 psi and circulate the sweep out of the hole. Sweep back on time w/ no increase. MW out dropped
to 9.1 ppg. Cont circulate 4x BU while weight up system, ensuring even 9.25 ppg in/out. Monitor Well - Static in 30 min. SimOps: Mobilize casing scraper to rig
floor. L/D a double to put string on even stands, rack back 5 stands to 5169' and pump a dry job. Proceed to POOH to 2158', laying pipe down to shed. POOH
racking remaining stands in the Derrick. L/D LTP running tool. . 3 bbls loss on TOH. Clear and clean rig floor. Mobilize remaining scraper assembly to Rig floor.
PJSM on BHA. M/U Casing scraper assembly: 8-1/2" Milltooth Bit, Baker 9-5/8" 40/47# casing scraper, bit sub, and 8-1/2" string mill. Trip in hole with casing
scraper assembly from 45' to 2614'. Worked scraper past ESC 3x from 2390' to 2485'. 85k PU, 81k SO. Did not see any indication of assembly taking wt going past
or hanging up when P/U. 4 bbls loss on TIH. Pump 25 bbls hi-vis sweep and circulate out of hole. 425 GPM - 1775 psi. Sweep back on time - no increase in
cuttings return. Monitor Well - Static. PJSM and start Slip and Cut drilling line.
Drill 8-1/2" lateral from 14411' to TD at 14701' (3965' TVD
Place liner in tension at 14701' set depth.
Activity Date Ops Summary
7/17/2023 Slip and cut drill line. Slip off 72'. Service Top drive Calibrate block height. Inspect brakes. Grease draw works and baylor linkage. POOH with drift assembly from
2610' to 45',Flow check well- static. L/D casing scraper / drift BHA,Clean and clear rig floor, pull mouse hole, and prep for upcoming casing patch operations. Spot
HES pumping unit and R/U hard line to the cellar Spot vac truck loaded with 150 bbl of source water. Mobilize hardline to the rig floor. M/U Casing patch tool,
PJSM. P/U casing patch tools and M/U on a single of 5" DP. Surface pressure test patch assembly to 3000 psi charted to check integrity- test good,RIH w/ 5" DP
out of the derrick from 63.65 to 2442', P/U 10' pup jt and RIH t/ 2452'. Fill pipe on the fly with clean source water, and top off every 4 stands. 80k PU, 80k SO. 1 bbl
loss on TIH,PJSM. Install headpin on string and R/U remaining hard line. P/U and put working depth indicator marks on string as per SLB procedure. Flood lines
and pressure test from HES pump unit to headpin @ 600/7000 psi good. Set 9-5/8 casing patch as per SLB rep. Pressure up to 5850 psi setting anchor. Proceed
to incrementally expand patch as per SLB rep and procedure. Top of patch @ 2407.96 Bottom of patch @ 2426.98. Blow down & rig down hard line from floor to
pump unit. Mobilize hardline off Rig floor. Rig up mud bucket & Lay down 10' pup joint. POOH, laying down drillpipe to the shed from 2442' to the casing patch
running tool at 63'. L/D the casing patch running tool. 5.5 bbls loss on TOH, 1.3 BPH.
7/18/2023 L/D casing patch assembly. M/U stack flushing tool and flush stack at 380GPM, 70PSI 40RPM, 1K TQ. Clear rig floor,Pull wear ring. Dummy run 7" hanger- good
seat. Sim Ops: Mobilize 7" casing equipment to rig floor,PJSM. Make up Baker bullet seal assembly. RIH w/ 7", 26#, L-80, TXP BTC casing from 15' to 2308' torque
to 14750 ft-lbs with Doyon double stack tongs. RIH w/ 7" 26# L-80 TXP BTC casing from 2308' to 5669' torque to 14750 ft-lbs with Doyon double stack tongs.
Change to DP elevators. M/U 5' DP pup to FOSV to XO on jt #143. RIH and No-Go out at 5702.30. 9 bbls loss while RIH. Rig up testing equipment. Shut UPR on 7"
casing. Purge air from system and PT 7"x9-5/8" OA to 2500 psi for 30 charted min. Good Test. 3.2 bbls pumped. 3.2 bbls bleed back. Blow down and rig down
lines. L/D joint #143, rig down FOSV and XO. Change to casing elevators. L/D joints #142 & 141. Make up space out pup joints (1.85', 2.80', 3.88', 7.61' & 14.84').
M/U joint #141. M/U 7-5/8" mandrel casing hanger with 7" XO pup and landing jt. Land the casing hanger. 2.14' off no-go. Change to DP elevators. M/U crossover,
side entry sub and 10' DP pup joint. R/U cement hose and circulating equipment. PJSM. Flood lines. PT to 1,500 psi - good test. Close the annular and apply 300
psi on OA. P/U and expose circulating port. Reverse circulate 229 bbls of 9.3 ppg corrosion inhibited brine at 6 BPM = 1220 psi (ICP) & 1150 psi (FCP) followed by
74 bbls diesel at 5 BPM = 740 psi. Strip down through the annular, closing the ports and land the casing hanger with 77K on the hanger (2.14' off no-go). Bleed off
the pressure and drain the BOP stack. Blow down and R/D the circulating lines and equipment. Lay down the landing joint. MU 2 joints of 5" HWDP and pack-off
running tool. Install 7-5/8" pack-off and RILDS. PT pack-off void to 500 psi for 5 minutes and 5,000 psi for 10 minutes - good test. L/D HWDP and pack-off running
tool. Rig up injection line and test equipment. Flood lines. PT 7" x 9-5/8" OA to 1,500 psi for 30 minutes charted - good test. Pumped 2.2 bbls, bled back 2.2 bbls.
Bleed off pressure. R/D circulating and test equipment. Reposition circulating lines to from OA to IA. Rig up to test BOPE. M/U FOSV / Dart on Test manifold.
7/19/2023 RU to test BOPE with 4-1/2" test joint. Conduct Bi-weekly BOPE test to 250/3,000 psi: UPR (4-1/2" x 7" VBRs), LPR (2-7/8" x 5" VBRs), annular with 4-1/2",
accumulator drawdown test and test gas alarms. All tests performed with fresh water against test plug. The states right to witness was waived by AOGCC inspector
Guy Cook via email on 7/18/23 at 10:50 hours. 1.Annular with 4-1/2" test joint, choke valves 1, 12, 13 & 14, kill line valve 20, 5" TIW (passed). 2.UPR with 4-
1/2" test joint, choke valves 9 & 11 HCR kill (passed). 3.Choke valves 5,8,10, manual kill, Upper IBOP (passed). 4.Choke valves 4, 6, 7, lower IBOP
(passed). 5.Choke valve 2, 3-1/2" TIW (passed),6.HCR choke, 3-1/2" dart valve (passed). 7.Manual choke (passed). 8.LPR (2-7/8" x 5" VBR) w/ 4-1/2" test
joint (passed). 9.Blind rams, choke valve 3 (passed). 11.Hydraulic super choke valve A (passed). 12.Manual choke valve B (passed),Accumulator Test:.
System pressure = 2950 psi. Pressure after closure = 1,625 psi. 200 psi attained in 34 seconds. Full pressure attained in 199 seconds. Nitrogen Bottles - 6 at 1,916
psi. Control System Response Time:. Annular = 17 seconds. UPR, blind rams & LPR = 8 seconds. HCR choke & kill = 8 second,RD test equipment and blow down
lines. Pull test plug and drain stack. Clean and clear rig floor. Mobilize TEC wire spool, cannon clamps, Baker Centrilift tools, Doyon tubing running equipment to rig
floor and rig up same. PJSM. RIH with 4-1/2", 12.6#, L-80, TXP tubing from 41' to 725'. Torque to 6,170 ft-lbs using Doyon double stack tongs. MU XN nipple.
Galed the box and pin while making up joint #19. Replace collar and joint. MU Tripoint permanent packer, 1 joint and gauge carrier. MU Zenith gauge and Tec wire.
MU 1 joint and sliding sleeve with covered ports for TEC wire bypass to 921'. RIH on 4-1/2", 12.6#, L-80, TXP-BTC tubing from 921' to 5,669' spooling TEC wire,
installing cannon clamps per tally and checking electrical continuity of the TEC wire every 1,000'. Torque to 6,170 ft-lbs with Doyon double stack tongs. PU = 98K
and SO = 81K. Lost 3.4 bbls while running tubing. MU 4-1/2" landing joint. MU tubing hanger with BPV installed and landing joint. Terminate the TEC wire and feed
through the tubing hanger. Land the tubing hanger with mule shoe at 5,703.66' with 41K on the hanger. RILDS. Lay down the landing joint. RD and demobilize
completion running equipment. Clear and clean the floor. PJSM. Pull the MPD riser. ND the BOP stack and rack back on the stump.
7/20/2023 Install CTS on BPV. Mobilize tree into the cellar. NU the tubing head adapter and tree. RU test equipment, fill the tree with water and purge the air. PT tubing hanger
void to 500 psi for 5 minutes and 5,000 psi for 10 minutes - good test. PT the tree to 250/5,000 psi - good test. Obtain final Zenith gauge readings: Tubing =
1,788.92 psi, 74.6 deg F & 20.4 volts,RD testing equipment. Drain the tree through the wing valve. Pull the CTS plug. Check for pressure under the BPV- the well is
on a slight vac. Pull the BPV with dry rod. Close Master valve. Set the 1-1/2" ball & rod on top of the master valve. Put tree cap on and open the master valve
dropping the ball & rod allowing it to gravitate to seat. Close the master valve. PJSM. RU and test circulating lines 3,800 psi. Pressure up on the tubing to 3,700 psi
initialize the Tripoint packer at 2,700 psi set at 3,700 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 3,650 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. Final well pressures: tubing, IA & OA = 0 psi. Clean the cellar box. Rig welder cut off the mouse hole extension and seal weld plate. Rig off highline
and on generators at 15:00 hours. Blow down and RD the rig floor service lines. Prep for skidding the rig floor. PJSM. Skid the rig floor into moving position. Prep to
jack up and move the rig. Move the rock washer. PJSM. Jack up the rig and remove the shims. Move the rig off M-60 and stage the rig on the southwest end of the
pad. Remove the mats from around the well.
7/21/2023 Place work platform for slickline on M-60. Spot slickline unit, perform post rig well work and RD. SimOps: Perform general rig maintenance and housekeeping.
Wells support tie in the well into production. SimOps: Perform general rig maintenance and housekeeping. Rig released @ 06:00.
Well Name:
Field:
County/State:
MP M-60
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
50-029-23755-00-00API #:
Set 9-5/8 casing patch as per SLB rep
PT 7" x 9-5/8" OA to 1,500 psi for 30 minutes charted - good test.
incrementally expand patch as per SLB rep and procedure. Top of patch @ 2407.96 Bottom of patch @ 2426.98.
ACTIVITYDATE SUMMARY
7/21/2023
SHIFT XD-SS OPEN AT 4,790' MD W/ 4-1/2" 42BO.
PULL BALL & ROD, 4-1/2" RHC FROM XN NIPPLE AT 4,968' MD.
SET 3" JETPUMP(ratio: 13B) IN XD-SS AT 4,790' MD.
*** WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED.
Daily Report of Well Operations
PBU MPM-60
TD Shoe Depth: PBTD:
No. Jts. Returned
RKB RKB to BHF RKB to THF
Jts.
1
1
1
1
1
92
1
1
1
58
1
Yes X No X Yes No
Fluid Description:
Liner hanger Info (Make/Model): Liner top Packer?: Yes No
Liner hanger test pressure:Yes X No
Centralizer Placement:
Preflush (Spacer)
Type: Density (ppg) Volume pumped (BBLs)
Lead Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Tail Slurry
Type:Sacks: Yield:
Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm):
Post Flush (Spacer)
Type: Density (ppg) Rate (bpm): Volume:
Displacement:
Type: Density (ppg) Rate (bpm): Volume (actual / calculated):
FCP (psi): Pump used for disp:X Yes No
Casing Rotated?X Yes No Reciprocated? 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:
1.17
7/3/2023 Surface
Spud Mud
EconcCem 445 2.35
HalCem 400 1.16
4
2,398.66
Casing 9 5/8 47.0 L-80 TXP-BTC 2,328.00 2,398.66 70.66
2,419.01 2,416.19
Casing Pup Joint 9 5/8 40.0 L-80 TXP-BTC 17.53 2,416.19
17.91 2,436.92 2,419.01
ES Cementer 10 3/4 TXP-BTC Halliburton 2.82
Casing Pup Joint 9 5/8 40.0 L-80 TXP-BTC
5,844.94
Casing 9 5/8 40.0 L-80 TXP-BTC 3,408.02 5,844.94 2,436.92
5,885.88 5,846.34
Baffle Adapter 10 3/4 TXP-BTC Halliburton 1.40 5,846.34
1.30 5,887.18 5,885.88
Casing 9 5/8 40.0 L-80 TXP-BTC 39.54
Float Collar 10 3/4 TXP-BTC Innovex
78 total 9-5/8" x 12"1/4" bowspring centralizers ran. Two in shoe joint w/ stop rings 10' from each end. One floating on
joint #2. One each with stop rings mid-joint on joint #3 & 4. One each on joints 5 to 25, every other joint to #47 then
every third joint to #77. One on joint #79. One each on joints #81 to #91. One each with stop rings on pup joints above
and below ES cementer. One each on every third joint #94 to #142. One on joint #144.
Casing 9 5/8 40.0 L-80 TXP-BTC 82.28 5,969.46 5,887.18
www.wellez.net WellEz Information Management LLC ver_04818br
3
Ftg. Returned
Ftg. Cut Jt.37.29 Ftg. Balance
No. Jts. Delivered No. Jts. Run 145
Length Measurements W/O Threads
Ftg. Delivered Ftg. Run
33.88 RKB to CHF
Type of Shoe:Float Casing Crew:Doyon
12 182
ES Cementer Closure OK
56
ArcticCXem
Type
HalCem 270
Tuned Spacr
718 2.85
Stage Collar @
60
Bump press
100
247
5,971.005,973.00
CEMENTING REPORT
Csg Wt. On Slips:100,000
Spud Mud
6:37 7/3/2023 3,416
2419.19
15.8 82
Bump press
cement returns to surface
Bump Plug?
No
3
9.4 6 117.6/175
188/188
1330
41
Rig
FI
R
S
T
S
T
A
G
E
10Tuned Spacer 60
15.8
750
9.3 6
2030
10
10.7 363 7
100
833
Bump Plug?
Csg Wt. On Hook:270,000 Type Float Collar:Innovex No. Hrs to Run:16.5
9 5/8 47.0 L-80 TXP-BTC
TXP-BTC Innovex 1.54 5,971.00 5,969.46
37.29 70.66 33.37
Setting Depths
Component Size Wt. Grade THD Make Length Bottom Top
Hilcorp Energy Company
CASING & CEMENTING REPORT
Lease & Well No.MP M-60 Date Run 2-Jul-23
CASING RECORD
County State Alaska Supv.B. Anderson / I. Toomey
5,885.88
Floats Held
366.88 767
288 479
Spud Mud
Rotate Csg Recip Csg Ft. Min. PPG9.3
Shoe @ 5971 FC @ Top of Liner
SE
C
O
N
D
S
T
A
G
E
Rig
21:45
Cement to surface
326.55 438.66 34.33
Casing (Or Liner) Detail
Shoe
Cut Joint
10 3/4
100
Cement to surface
247
cement returns to surface
ment:
Type:
100
00
2
4
6
8
10
12
14
16
18 20 22 24 26
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
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2200
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2400
2500
2600
2700
2800
2900
3000
0102030
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
)
0
100
200
300
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500
600
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1300
1400
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1700
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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
00
2
4
6
8
10
12
14
16 18 20 22 24
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
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1700
1800
1900
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2200
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2900
3000
0102030
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
)
0
100
200
300
400
500
600
700
800
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1100
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1300
1400
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2200
2300
2400
2500
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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
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Complete as JP Producer
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address: Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Will planned perforations require a spacing exception? Yes No
9. Property Designation (Lease Number): 10. Field: Current Pools:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
±14691 N/A
Casing Collapse
Conductor N/A
Surface 4,760psi
Surface 3,090psi
Tieback 5,410psi
Liner 8,540psi
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title: Wells Manager
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other:
Post Initial Injection MIT Req'd? Yes No
Spacing Exception Required? Yes No Subsequent Form Required:
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
7"±5550
±9141 4-1/2"
9-5/8"
9-5/8"
±2500
±3200
9,020psi
MD
N/A
7,240psi
6,870psi
5,750psi
±2053
±3907
±3893
±2500
±5700
±3928±14691
±5550
Length Size
Proposed Pools:
±114 ±114
TVD Burst
PRESENT WELL CONDITION SUMMARY
±3928 ±14691 ±3928 1,300 N/A
±80 20"
Milne Point
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL025514 & ADL 388235
223-040
3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23755-00-00
Hilcorp Alaska LLC
Schrader Bluff Oil N/A
C.O. 477.05
MPU M-60
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size:
12.6 / L-80 / TXP ±5,550'
7/15/2023
Baker Retrievable & SLZXP LTP and N/A 4,350 MD/ 3,450 TVD & 5,500 MD/ ±3,90 TVD and N/A
See Schematic See Schematic 4-1/2"
Perforation Depth MD (ft):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
AOGCC USE ONLY
todd.sidoti@hilcorp.com
777-8443
Todd Sidoti
Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 11:09 am, Jun 20, 2023
323-350
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2023.06.20 09:36:33 -
08'00'
Taylor Wellman
(2143)
SFD 7/13/2023 DSR-6/21/23
1,300
10-404
MGR22JUN2023
• Approved for reverse circulating jet pump.
• 30 Minute charted inner casing pressure test from surface to tie-back seal assembly tested to maximum power fluid injection pressure
• IA SSV high pressure trip pressure not to exceed 3650 psi. IA low pressure trip pressure not to be lower than 1800 psi.
• Production tubing SSV low pressure trip to to be lower than 100 psi.
• SSV closure on IA will intiate closure withing 2 minutes on SSV on production tubing and visa versa.
• Reservoir pressure gradient to remain below 8.55 BHPE to operate well with jet pump.
• Quadrennial MIT-IA to 3650 psi
JLC 7/21/2023
07/21/23
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2023.07.21
15:31:50 -05'00'
RBDMS JSB 072523
Well: MPU M-60
Scope: Post-Drill JP Install
Well Name:MPU M-60 API Number:50-029-23755-00-00
Current Status:Oil Well Pad:M-Pad
Estimated Start Date:July 15, 2023 Rig:SL
Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd:
Regulatory Contact:Tom Fouts Permit to Drill Number:223-040
First Call Engineer:Todd Sidoti (907) 777-8443 (O) (007) 632-4113 (M)
Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M)
AFE Number:Job Type:JP Install
Est Bottom Hole Pressure: 1,700 psi @ 4,000’ TVD Estimated from Offsets |8.10 PPGE
Max Potential Surface Pressure: 1,300 psi Gas Column Gradient (0.1 psi/ft)
Brief Well Summary:
MPU M-60 is a Schrader producer that will be drilled in July 2023. Once drilled slickline will install a jet pump in
the completion.
Objective:
Prepare well for JP production.
Notes Regarding Well
x IA SSV high pressure trip not to exceed 10% greater than expected maximum header pressure.
x IA SSV low pressure trip to be at least 50% of expected maximum header injection pressure.
Procedure
Slickline
1. MIRU SL, PT PCE to 250 psi low / 2,500 psi high.
2. Pull Ball & rod and RHC plug at ±4,400’.
3. Open sliding sleeve at ±4,250’.
4. Install 13B jet pump in sliding sleeve at 4,250’.
5. RDMO.
_____________________________________________________________________________________
Edited By: JNL 4/25/2023
PROPOSED SCHEMATIC
Milne Point Unit
Well: MPU M-60
Last Completed: TBD
PTD: TBD
TD =14,691’(MD) / TD =3,928’(TVD)
4
20”
Orig. KB Elev.: 57.9’ / GL Elev.: 24.2’
7”
6
9-5/8”
1
2
3
See
Screen/
Solid
Liner
Detail
PBTD =14,691’(MD) / PBTD =3,928’(TVD)
9-5/8” ‘ES’
Cementer @
2,500’
5
7
9
12
8
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 ~2,500’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 ~2,500’ 5,700’ 0.0758
7” Tieback 26 / L-80 / TXP 6.276 Surface ~5,550’ 0.0383
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 ~5,550’ 14,691’ 0.0149
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / TXP 3.958 Surface ~5,550’ 0.0152
OPEN HOLE / CEMENT DETAIL
42” ±270 ft3
12-1/4"Stg 1 Lead – 381 sx / Tail – 395 sx
Stg 2 Lead – 673 sx / Tail 268 sx
8-1/2” Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 350’
90° Hole Angle = @ 6,500’
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: TBD
Completion Date: TBD
JEWELRY DETAIL
No. MD Item ID
1 Surface 4-1/2” TCII Tubing Hanger 4.500”
2 ~4,250’ Haliburton X-Line Sliding Sleeve (opens down) 3.813”
3 ~4,300’ Baker Gauge Carrier 3.865”
4 ~4,350’ Baker Retrievable Packer 3.880”
5 ~4,400’ XN Nipple, 3.813”, 3.725” No Go 3.725”
6 ~5,460’ WLEG/Mule Shoe 3.958”
7 ~5,500’ SLZXP Liner Top Packer 6.180”
8 ~5,525’ 7” H563 x 4.5” TSH 625 XO 4.810”
9 ~14,691’ Shoe 3.970”
4-1/2”SCREENS LINER DETAIL
Jts Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
DIVERTER Test Report for:
Reviewed By:
P.I. Suprv
Comm ________MILNE PT UNIT M-60
JBR 08/07/2023
MISC. INSPECTIONS:
GAS DETECTORS:
DIVERTER SYSTEM:MUD SYSTEM:
P/F
P/F
P/F
Alarm
Visual Alarm
Visual Time/Pressure
Size
Number of Failures:0
Remarks:Tested with 5" HWDP, Tested all gas alarms and PVT's.
TEST DATA
Rig Rep:D. YessakOperator:Hilcorp Alaska, LLC Operator Rep:J. Hansen
Contractor/Rig No.:Doyon 14 PTD#:2230400 DATE:6/28/2023
Well Class:DEV Inspection No:divBDB230628154503
Inspector Brian Bixby
Inspector
Insp Source
Related Insp No:
Test Time:1
ACCUMULATOR SYSTEM:
Location Gen.:P
Housekeeping:P
Warning Sign P
24 hr Notice:P
Well Sign:P
Drlg. Rig.P
Misc:NA
Methane:P P
Hydrogen Sulfide:P P
Gas Detectors Misc:0 NA
Designed to Avoid Freeze-up?P
Remote Operated Diverter?P
No Threaded Connections?P
Vent line Below Diverter?P
Diverter Size:21.25 P
Hole Size:12.25 P
Vent Line(s) Size:16 P
Vent Line(s) Length:352 P
Closest Ignition Source:97 P
Outlet from Rig Substructure:344 P
Vent Line(s) Anchored:P
Turns Targeted / Long Radius:P
Divert Valve(s) Full Opening:P
Valve(s) Auto & Simultaneous:
Annular Closed Time:32 P
Knife Valve Open Time:17 P
Diverter Misc:0 NA
Systems Pressure:P3000
Pressure After Closure:P1800
200 psi Recharge Time:P28
Full Recharge Time:P158
Nitrogen Bottles (Number of):P6
Avg. Pressure:P1870
Accumulator Misc:NA0
P PTrip Tank:
P PMud Pits:
P PFlow Monitor:
0 NAMud System Misc:
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, AK, 99503
Re: Milne Point, Schrader Bluff Pool, MPU M-60
Hilcorp Alaska, LLC
Permit to Drill Number: 223-040
Surface Location: 4913’ FSL, Sec. 14, T13N, R09E, UM, AK
Bottomhole Location: 1674’ FNL, 2566’ FEL, Sec.02, T13N, R09E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of June, 2023. 14
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2023.06.14 09:24:34
-08'00'
4.25.2023
By Kayla Junke at 8:59 am, Apr 26, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.04.25 14:25:03 -08'00'
Monty M
Myers
DSR-4/26/23
223-040 029-23755-00-00
* BOPE test to 3000 psi. Annular to 2500 psi.
* Casing test and FIT digital data to AOGCC
immediately upon completion of performing FIT.
* Separate 10-403 to POP well with jet pump
artificial lift.
MGR13JUNE2023 SFD 6/9/2023GCW 06/13/2023
JLC 6/13/2023
06/14/23
06/14/23
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.06.14 09:24:50 -08'00'
Milne Point Unit
(MPU) M-60
Application for Permit to Drill
Version 1
4/25/2023
Table of Contents
1.0 Well Summary ........................................................................................................................... 2
2.0 Management of Change Information ........................................................................................ 3
3.0 Tubular Program:...................................................................................................................... 4
4.0 Drill Pipe Information: .............................................................................................................. 4
5.0 Internal Reporting Requirements ............................................................................................. 5
6.0 Planned Wellbore Schematic ..................................................................................................... 6
7.0 Drilling / Completion Summary ................................................................................................ 7
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 8
9.0 R/U and Preparatory Work ..................................................................................................... 10
10.0 N/U 13-5/8” 5M Diverter System ............................................................................................. 11
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 16
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 27
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28
16.0 Run 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 .................................................................................................. 48
25.0 Doyon 14 Rig Layout ............................................................................................................... 51
26.0 FIT Procedure .......................................................................................................................... 52
27.0 Doyon 14 Rig Choke Manifold Schematic ............................................................................... 53
28.0 Casing Design ........................................................................................................................... 54
29.0 8-1/2” Hole Section MASP ....................................................................................................... 55
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 56
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 57
Page 2
Milne Point Unit
M-60 SB Producer
PTD Application
1.0 Well Summary
Well MPU M-60
Pad Milne Point “M” Pad
Planned Completion Type Jet Pump
Target Reservoir(s) Schrader Bluff OA Sand
Planned Well TD, MD / TVD 14,690’ MD / 3,928’ TVD
PBTD, MD / TVD 14,690’ MD / 3,928’ TVD
Surface Location (Governmental) 366’ FNL, 201’ FEL, Sec. 14, T13N, R9E, UM, AK
Surface Location (NAD 27) X= 533694, Y= 6027766
Top of Productive Horizon
(Governmental) 846’ FSL, 1459’ FWL, Sec. 12, T13N, R9E, UM, AK
TPH Location (NAD 27) X= 535618, Y= 6028986
BHL (Governmental) 1674' FNL, 2566' FEL, Sec 2, T13N, R9E, UM, AK
BHL (NAD 27) X= 531550, Y= 6037006
AFE Drilling Days 18
AFE Completion Days 4
Maximum Anticipated Pressure
(Surface) 1328 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1719 psig
Work String 5” 19.5# S-135 NC 50
Doyon 14 KB Elevation above MSL: 33.7 ft + 24.2 ft = 57.9 ft
GL Elevation above MSL: 24.2 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Milne Point Unit
M-60 SB Producer
PTD Application
2.0 Management of Change Information
Page 4
Milne Point Unit
M-60 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
M-60 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 mmyers@hilcorp,
nathan.sperry@hilcorp.com,and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to 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 Todd Sidoti 907.777.8443 Todd.Sidoti@hilcorp.com
Geologist Katie Cunha 907.564.4786 Katharine.cunha@hilcorp.com
Reservoir Engineer Reid Edwards 907.777.8421 reedwards@hilcorp.com
Drilling Env. Coordinator Keegan Fleming 907.777.8477 kfleming@hilcorp.com
EHS Director Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
_____________________________________________________________________________________
Edited By: JNL 4/25/2023
PROPOSED SCHEMATIC
Milne Point Unit
Well: MPU M-60
Last Completed: TBD
PTD: TBD
TD =14,691’(MD) / TD =3,928’(TVD)
4
20”
Orig. KB Elev.: 57.9’ / GL Elev.: 24.2’
7”
6
9-5/8”
1
2
3
See
Screen/
Solid
Liner
Detail
PBTD =14,691’(MD) / PBTD =3,928’(TVD)
9-5/8” ‘ES’
Cementer @
2,500’
5
7
9
12
8
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 ~2,500’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 ~2,500’ 5,700’ 0.0758
7” Tieback 26 / L-80 / TXP 6.276 Surface ~5,550’ 0.0383
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 ~5,550’ 14,691’ 0.0149
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / TXP 3.958 Surface ~5,550’ 0.0152
OPEN HOLE / CEMENT DETAIL
42” ±270 ft3
12-1/4"Stg 1 Lead – 381 sx / Tail – 395 sx
Stg 2 Lead – 673 sx / Tail 268 sx
8-1/2” Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 350’
90° Hole Angle = @ 6,500’
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: TBD
Completion Date: TBD
JEWELRY DETAIL
No. MD Item ID
1 Surface 4-1/2” TCII Tubing Hanger 4.500”
2 ~4,250’ Haliburton X-Line Sliding Sleeve (opens down) 3.813”
3 ~4,300’ Baker Gauge Carrier 3.865”
4 ~4,350’ Baker Retrievable Packer 3.880”
5 ~4,400’ XN Nipple, 3.813”, 3.725” No Go 3.725”
6 ~5,460’ WLEG/Mule Shoe 3.958”
7 ~5,500’ SLZXP Liner Top Packer 6.180”
8 ~5,525’ 7” H563 x 4.5” TSH 625 XO 4.810”
9 ~14,691’ Shoe 3.970”
4-1/2”SCREENS LINER DETAIL
Jts Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
Page 7
Milne Point Unit
M-60 SB Producer
PTD Application
7.0 Drilling / Completion Summary
MPU M-60 is a grassroots producer planned to be drilled in the Schrader Bluff OA sand. M-60 is part of a
multi-well program targeting the Schrader Bluff sand on M-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 June 23rd, 2023, pending rig schedule.
Surface casing will be run to 5,700’ MD / 3,907’ 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)
Page 8
Milne Point Unit
M-60 SB Producer
PTD Application
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 M-60. 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 M-60 will utilize a newly set 20” conductor on M-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).
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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. Plan to take GWD surveys to TD; however, if
there are any issues, swap to MWD as soon as magnetic interference cleans up.
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 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: M-I gel 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 UL should be used for filtrate control. Background
LCM (10 ppb total) nut plug fine & medium, M-I-X II fine & medium 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 SCREENKLEEN 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 TANNATHIN / CF DESCO II as required for
running casing as allowed (do not jeopardize hole conditions). Run casing carefully to
minimize surge and swab pressures. Reduce the system rheology once the casing is
landed to a YP < 20 (check with the cementers to see what YP value they have targeted).
System Type:8.8 – 9.2 ppg Pre-Hydrated M-I gel / freshwater spud mud
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Properties:
Section Density Viscosity
Plastic
Viscosity Yield Point API FL pH
Temp
Surface 8.8 –
9.8
75-175 20 - 40 25-45 <10 8.5 –
9.0
70 F
System Formulation: Gel + FW spud mud
Product Concentration
Fresh Water
soda Ash
M-I GEL
caustic soda
SCREENKLEEN
MI WATE
PAC-UL /DEXTRID LT
ALDACIDE G
0.967 bbl
0.125 ppb
35 ppb
0.1 ppb (8.5 – 9.0 pH)
as needed
as required for 8.8 – 9.2 ppg
if required for <10 FL
0.1 ppb
11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity.
11.6 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
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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
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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13.17 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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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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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 NT 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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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 digital data for casing test and FIT to AOGCC immediately upon completion of FIT.
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15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to a minimum. 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 ppb or (% liquids)
Water 0.916 bbls/bbl
Soda Ash 0.17 ppb
FLO-VIS PLUS 0.5 –0.75 ppb
FLO-TROL 6.0 ppb
Potassium Chloride (KCl)10.7 ppb
SCREENKLEEN 0.5% v/v
SAFE-CARB 20 10 ppb
SAFE-CARB 40 10 ppb
SALT As needed
Onyxide 200 2.1 gals/100 bbls
Sodium Metabisulfite 0.25 ppb
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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 Include GWD in the BHA
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 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 less than 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.
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x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 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
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.15 Monitor the returned fluids carefully while displacing to brine. 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.
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x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
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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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
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 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 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 liner with PST passed mud (to keep from plugging screens with solids)
x Install screen joints as per the Running Order (From Operations Engineer post TD).
o Do not place tongs or slips on screen joints
o Screen placement ±40’
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
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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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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 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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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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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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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
Below 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 Below 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.
18.13 Bleed the tubing pressure to 2,000 psi and PT the IA to 3,650 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
Separate 10-403 to POP well with jet pump artificial lift.
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19.0 Doyon 14 Diverter Schematic
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20.0 Doyon 14 BOP Schematic
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PTD Application
21.0 Wellhead Schematic
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22.0 Days Vs Depth
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23.0 Formation Tops & Information
TOP
NAME
TVD
(FT)
TVDss
(FT)
MD
(FT)
Formation
Pressure
(psi)
EMW
(ppg)
Base
Permafrost 1878 1820 2225 826 8.46
SV1 1909 1851 2273 840 8.46
UG4 2165 2108 2671 952 8.46
UG_MB 3470 3412 4413 1527 8.46
SB NB 3767 3709 5000 1657 8.46
SB OA 3906 3848 5690 1718 8.46
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L-Pad Data Sheet Formation Description (Closest & Most Analogous MPU Pad to Moose Pad)
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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 M-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.
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H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
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. Maint. 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 M-60. 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. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. 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.
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25.0 Doyon 14 Rig Layout
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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 53Milne Point UnitM-60 SB ProducerPTD Application27.0 Doyon 14 Rig Choke Manifold Schematic
Page 54
Milne Point Unit
M-60 SB Producer
PTD Application
28.0 Casing Design
Page 55
Milne Point Unit
M-60 SB Producer
PTD Application
29.0 8-1/2” Hole Section MASP
Page 56
Milne Point Unit
M-60 SB Producer
PTD Application
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 57
Milne Point Unit
M-60 SB Producer
PTD Application
31.0 Surface Plat (As Built) (NAD 27)
6WDQGDUG3URSRVDO5HSRUW
0DUFK
3ODQ 0380ZS
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-1200
-600
0
600
1200
1800
2400
3000
3600
4200
4800
5400
6000
6600
7200
7800
8400
9000
9600
10200
South(-)/North(+) (1200 usft/in)-4200 -3600 -3000 -2400 -1800 -1200 -600 0 600 1200 1800 2400 3000 3600
West(-)/East(+) (1200 usft/in)
M-60 wp04 tgt18
M-60 wp04 tgt16
M-60 wp04 tgt14
M-60 wp04 tgt12
M-60 wp04 tgt7
M-60 wp04 tgt5
M-60 wp04 tgt3
M-60 wp04 tgt1
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"7501000150017502000225025002750300
0
3250
3500
3 7 5 0
3 9 2 8
M P U M -6 0 w p 0 5
Start Dir 3º/100' : 350' MD, 350'TVD
Start Dir 4º/100' : 550' MD, 549.63'TVD
End Dir : 1711.91' MD, 1551.2' TVD
Start Dir 4º/100' : 2516.03' MD, 2063.01'TVD
End Dir : 5539.52' MD, 3892.83' TVD
Start Dir 3º/100' : 5689.52' MD, 3905.9'TVD
Begin Geosteering
End Dir : 5726.41' MD, 3909.05' TVD
Total Depth : 14690.53' MD, 3927.9' TVD
CASING DETAILS
TVD TVDSS MD Size Name
3906.81 3848.91 5700.00 9-5/8 9 5/8" x 12 1/4"
3927.90 3870.00 14690.91 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site: M Pt Moose Pad
Well: Plan: MPU M-60
Wellbore: MPU M-60
Plan: MPU M-60 wp05
WELL DETAILS: Plan: MPU M-60
24.20
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00
6027765.650 533963.810 70° 29' 12.7769 N 149° 43' 20.6494 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU M-60, True North
Vertical (TVD) Reference:MPU M-60 as staked rkb @ 57.90usft
Measured Depth Reference:MPU M-60 as staked rkb @ 57.90usft
Calculation Method:Minimum Curvature
07501500225030003750True 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 345.62° (1500 usft/in)M-60 wp04 tgt1M-60 wp04 tgt3M-60 wp04 tgt5M-60 wp04 tgt7M-60 wp04 tgt12M-60 wp04 tgt14M-60 wp04 tgt16M-60 wp04 tgt189 5/8" x 12 1/4"4 1/2" x 8 1/2"5001000150020002500300035004000450050005500600065007000750080008500900095001000010500110001150012000125001300013500140001450014691MPU M-60 wp05Start Dir 3º/100' : 350' MD, 350'TVDStart Dir 4º/100' : 550' MD, 549.63'TVDEnd Dir : 1711.91' MD, 1551.2' TVDStart Dir 4º/100' : 2516.03' MD, 2063.01'TVDEnd Dir : 5539.52' MD, 3892.83' TVDStart Dir 3º/100' : 5689.52' MD, 3905.9'TVDBegin GeosteeringEnd Dir : 5726.41' MD, 3909.05' TVDTotal Depth : 14690.53' MD, 3927.9' TVDSV6Base PermafrostSV1UG4UG_MBSB_NBSB_OAHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU M-6024.20+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.006027765.650533963.810 70° 29' 12.7769 N 149° 43' 20.6494 WSURVEY PROGRAMDate: 2022-08-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool33.70 1500.00 MPU M-60 wp05 (MPU M-60) GYD_Quest GWD1500.00 5700.00 MPU M-60 wp05 (MPU M-60) 3_MWD+IFR2+MS+Sag5700.00 14690.53 MPU M-60 wp05 (MPU M-60) GYD_Quest GWDFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation841.60 783.70 848.42 SV61877.51 1819.61 2224.60 Base Permafrost1908.51 1850.61 2273.30 SV12165.47 2107.57 2670.96 UG43470.21 3412.31 4412.77 UG_MB3767.07 3709.17 4999.77 SB_NB3905.94 3848.04 5689.92 SB_OAREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU M-60, True NorthVertical (TVD) Reference:MPU M-60 as staked rkb @ 57.90usftMeasured Depth Reference:MPU M-60 as staked rkb @ 57.90usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt Moose PadWell:Plan: MPU M-60Wellbore:MPU M-60Design:MPU M-60 wp05CASING DETAILSTVD TVDSS MD SizeName3906.81 3848.91 5700.00 9-5/8 9 5/8" x 12 1/4"3927.90 3870.00 14690.91 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 0.002 350.00 0.00 0.00 350.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 350' MD, 350'TVD3 550.00 6.00 145.00 549.63 -8.57 6.00 3.00 145.00 -9.79 Start Dir 4º/100' : 550' MD, 549.63'TVD4 650.00 10.00 145.00 648.64 -19.97 13.98 4.00 0.00 -22.825 1711.91 50.47 110.78 1551.20 -251.45 470.88 4.00 -39.97 -360.51 End Dir : 1711.91' MD, 1551.2' TVD6 2516.03 50.47 110.78 2063.01 -471.44 1050.76 0.00 0.00 -717.61 Start Dir 4º/100' : 2516.03' MD, 2063.01'TVD7 5539.52 85.00 332.93 3892.83 1079.84 1727.91 4.00 -128.79 616.92 End Dir : 5539.52' MD, 3892.83' TVD8 5689.52 85.00 332.93 3905.90 1212.90 1659.91 0.00 0.00 762.70 M-60 wp04 tgt1 Start Dir 3º/100' : 5689.52' MD, 3905.9'TVD9 5726.41 85.20 334.02 3909.05 1245.79 1643.49 3.00 79.39 798.64 End Dir : 5726.41' MD, 3909.05' TVD10 6010.16 85.20 334.02 3932.77 1499.97 1519.64 0.00 0.00 1075.6111 6111.51 88.22 333.63 3938.58 1590.77 1475.01 3.00 -7.40 1174.6512 6411.51 88.22 333.63 3947.90 1859.43 1341.83 0.00 0.00 1467.96 M-60 wp04 tgt313 6566.59 92.09 333.44 3947.48 1998.23 1272.73 2.50 -2.78 1619.5814 6769.26 92.09 333.44 3940.08 2179.40 1182.17 0.00 0.00 1817.5615 6883.60 89.25 333.14 3938.74 2281.52 1130.79 2.50 -173.94 1929.2416 7583.60 89.25 333.14 3947.90 2905.95 814.55 0.00 0.00 2612.64 M-60 wp04 tgt517 7704.18 86.49 334.35 3952.38 3014.00 761.25 2.50 156.40 2730.5418 7896.87 86.49 334.35 3964.19 3187.36 677.99 0.00 0.00 2919.1519 8037.84 89.77 333.06 3968.79 3313.67 615.59 2.50 -21.40 3057.0020 8812.84 89.77 333.06 3971.90 4004.58 264.51 0.00 0.00 3813.45 M-60 wp04 tgt721 8923.03 92.50 333.39 3969.71 4102.93 214.89 2.50 6.91 3921.0422 9174.79 92.50 333.39 3958.71 4327.81 102.25 0.00 0.00 4166.8523 9282.07 89.83 333.59 3956.53 4423.78 54.38 2.50 175.82 4271.7024 9907.07 89.83 333.59 3958.38 4983.55 -223.61 0.00 0.00 4882.9725 10113.10 94.97 333.28 3949.75 5167.61 -315.64 2.50 -3.45 5084.1226 10815.44 94.97 333.28 3888.89 5792.59 -630.25 0.00 0.00 5767.6427 11039.17 89.39 332.92 3880.38 5991.88 -731.36 2.50 -176.31 5985.8128 11464.17 89.39 332.92 3884.90 6370.27 -924.82 0.00 0.00 6400.38 M-60 wp04 tgt1229 11614.94 85.68 333.57 3891.39 6504.75 -992.63 2.50 170.14 6547.4930 11754.80 85.68 333.57 3901.93 6629.63 -1054.71 0.00 0.00 6683.8731 11887.34 88.98 333.31 3908.11 6748.03 -1113.90 2.50 -4.45 6813.2732 12437.34 88.98 333.31 3917.90 7239.35 -1360.90 0.00 0.00 7350.54 M-60 wp04 tgt1433 12574.35 92.40 333.40 3916.25 7361.78 -1422.33 2.50 1.44 7484.3934 12792.81 92.40 333.40 3907.08 7556.94 -1520.08 0.00 0.00 7697.7035 12900.26 89.72 333.29 3905.09 7652.95 -1568.27 2.50 -177.73 7802.6736 13475.26 89.72 333.29 3907.90 8166.58 -1826.72 0.00 0.00 8364.40 M-60 wp04 tgt1637 13604.76 86.48 333.31 3912.19 8282.20 -1884.86 2.50 179.56 8490.8338 13777.23 86.48 333.31 3922.77 8436.01 -1962.17 0.00 0.00 8659.0239 13915.53 89.94 333.35 3927.09 8559.52 -2024.20 2.50 0.58 8794.0740 14690.53 89.94 333.35 3927.90 9252.19 -2371.82 0.00 0.00 9551.36 M-60 wp04 tgt18 Total Depth : 14690.53' MD, 3927.9' TVD
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0.001.002.003.004.00Separation Factor0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175Measured Depth (650 usft/in)MPU M-28MPU M-13M-09DSW wp02- AP HillMPU M-61 wp05No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU M-60 NAD 1927 (NADCON CONUS)Alaska Zone 0424.20+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006027765.650 533963.81070° 29' 12.7769 N149° 43' 20.6494 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU M-60, True NorthVertical (TVD) Reference: MPU M-60 as staked rkb @ 57.90usftMeasured Depth Reference:MPU M-60 as staked rkb @ 57.90usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2022-08-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1500.00 MPU M-60 wp05 (MPU M-60) GYD_Quest GWD1500.00 5700.00 MPU M-60 wp05 (MPU M-60) 3_MWD+IFR2+MS+Sag5700.00 14690.53 MPU M-60 wp05 (MPU M-60) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175Measured Depth (650 usft/in)MPU M-28MPU M-28MPU M-12MPU M-35iMPU M-30MPU M-14MPU M-45MPU M-13MPU M-27MPU M-29MPU M-29MPU M-11MPU M-61 wp05NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 14690.95Project: Milne PointSite: M Pt Moose PadWell: Plan: MPU M-60Wellbore: MPU M-60Plan: MPU M-60 wp05Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name3906.81 3848.91 5700.00 9-5/8 9 5/8" x 12 1/4"3927.90 3870.00 14690.91 4-1/2 4 1/2" x 8 1/2"
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0.001.002.003.004.00Separation Factor5700 6175 6650 7125 7600 8075 8550 9025 9500 9975 10450 10925 11400 11875 12350 12825 13300 13775 14250 14725Measured Depth (950 usft/in)MPU M-28MPU M-27Kup N1 from Slot 34MPU M-61 wp05No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU M-60 NAD 1927 (NADCON CONUS)Alaska Zone 0424.20+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006027765.650533963.810 70° 29' 12.7769 N149° 43' 20.6494 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU M-60, True NorthVertical (TVD) Reference: MPU M-60 as staked rkb @ 57.90usftMeasured Depth Reference:MPU M-60 as staked rkb @ 57.90usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2022-08-18T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool33.70 1500.00 MPU M-60 wp05 (MPU M-60) GYD_Quest GWD1500.00 5700.00 MPU M-60 wp05 (MPU M-60) 3_MWD+IFR2+MS+Sag5700.00 14690.53 MPU M-60 wp05 (MPU M-60) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)5700 6175 6650 7125 7600 8075 8550 9025 9500 9975 10450 10925 11400 11875 12350 12825 13300 13775 14250 14725Measured Depth (950 usft/in)NO GLOBAL FILTER: Using user defined selection & filtering criteria33.70 To 14690.95Project: Milne PointSite: M Pt Moose PadWell: Plan: MPU M-60Wellbore: MPU M-60Plan: MPU M-60 wp05Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name3906.81 3848.91 5700.00 9-5/8 9 5/8" x 12 1/4"3927.90 3870.00 14690.91 4-1/2 4 1/2" x 8 1/2"
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
223-040
MPU M-60
SCHRADER BLUFF OILMILNE POINT
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT M-60Initial Class/TypeDEV / PENDGeoArea890Unit On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2230400MILNE POINT, SCHRADER BLFF OIL - 525140NA1 Permit fee attachedYes Surf Loc, Top PI & TD lie within ADL0025514.Top Prod Int & TD lie within ADL0388235.2 Lease number appropriateYes3 Unique well name and numberYes4 Well located in a defined poolYes Milne Point Schrader Bluff Oil Pool (525140), governed by CO 477, amended by CO 477.05.5 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) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 20" 129.5# X-52 driven to 114'18 Conductor string providedYes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir19 Surface casing protects all known USDWsYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20 CMT vol adequate to circulate on conductor & surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21 CMT vol adequate to tie-in long string to surf csgYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22 CMT will cover all known productive horizonsYes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.23 Casing designs adequate for C, T, B & permafrostYes Doyon 14 rig has adequate tankage and good trucking support24 Adequate tankage or reserve pitNA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows no close approaches.26 Adequate wellbore separation proposedYes 16" Diverter below Annular27 If diverter required, does it meet regulationsYes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequateYes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulationYes 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA This well is a Oil Development well.34 Mechanical condition of wells within AOR verified (For service well only)No H2S not anticipated from drilling of offset wells; however, rig has H2S sensors and alarms.35 Permit can be issued w/o hydrogen sulfide measuresYes Gas hydrates have not been encountered in M-Pad wells drilled to date, but mitigation measures are36 Data presented on potential overpressure zonesNA discussed in the "Anticipated Drilling Hazards" section.37 Seismic analysis of shallow gas zonesNA Normal pressure gradient is expected; however, abnormal pressure has been encountered in M-Pad38 Seabed condition survey (if off-shore)NA wells due to nearby injection. Managed Pressure Drilling will be used to monitor and control pressure.39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate6/9/2023ApprMGRDate6/13/2023ApprSFDDate6/9/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateFour fault crossings anticipated. LCM and materials sufficient to build system to 1 ppg above highest anticipated mud weight will be onsite. SFDGCW 06/13/2023JLC 6/13/2023
