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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: 07/11/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL:
WELL: MPU R-142
PTD: 224-045
API: 50-029-23790-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING (05/30/2024 to 06/13/2024)
x ABG + BASESTAR (GAMMA RAY), RESISTAR + STRATASTAR (RESISTIVITY), ROP
x 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:g
Please include current contact information if different from above.
224-045
T39176
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2024.07.11 15:33:07 -08'00'
5-1/2"x4-1/2"
By Grace Christianson at 7:58 am, Jun 28, 2024
Completed
6/19/2024
JSB
RBDMS JSB 070924
GDSR-7/17/24MGR23DEC2025
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2024.06.26 14:41:41 -
08'00'
Taylor Wellman
(2143)Drilling Manager
06/26/24
Monty M
Myers
_____________________________________________________________________________________
Revised By: JNL 6/21/2024
SCHEMATIC
Milne Point Unit
Well: MPU R-142
Last Completed: 6/19/2024
PTD: 224-045
TD =16,315’(MD) / TD =4,173’(TVD)
4/5/6
20”
Orig. KB Elev.: 63.6’ / GL Elev.: 16.8’
7”
7/8/9
10
4
9-5/8”
1
2
3
See
Screen/
Solid
Liner
Detail
PBTD = 16,313’(MD) / PBTD = 4,173’(TVD)
9-5/8” ‘ES’
Cementer @
2,349’ MD
4-1/2”
11
13
12
14
15
2-7/8”CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X56 / Weld N/A Surface 126’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,370’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 2,370’ 5,766’ 0.0758
7” Tieback 26 / L-80 / TXP 6.276 Surface 5,610’ 0.0383
5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.778 5,601’ 6,693’ 0.0222
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 6,693’ 16,314’ 0.0149
TUBING DETAIL
2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,516’ 0.0058
OPEN HOLE / CEMENT DETAIL
42” 17 yds Cement
12-1/4"Stg 1 Lead – 445 sx / Tail – 379 sx
Stg 2 Lead – 727 sx / Tail 270 sx
8-1/2” Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 180’
Max Hole Angle = 94° @7328’
TREE & WELLHEAD
Tree FMC 11” x 4-1/2” TC-II Tubing Hanger x 2-7/8” EUE
Wellhead 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: 50-029-23790-00-00
Completion Date: 6/19/2024
JEWELRY DETAIL
No. Top MD Item ID
1 151’ 2-7/8” x 1” BK-2 GLM w/ SOV 2.440”
2 5014’ 2-7/8” x 1” GLM Dummy Valve w/ BK Latch 2.440”
3 5073’ XN Nipple, 2.313” w/ 2.205” No-Go 2.205”
4 5438’ Discharge Sub
5 5439’ Discharge Bolt-On
6 5439’ Pump: 538, SJ2800
7 5463’ Pump Intake GS, 538
8 5470’ Upper Tandem Seal: 513 Series
9 5479’ Lower Tandem Seal: 513 Series
10 5488’ Motor: 562 Series, KMS2, 360HP
11 5512’ Sensor, 177C 8KPSI, 2x Press / Temp / Vib
12 5514’ Anode Centralizer: Bottom @ 5,516’ MD
13 5501’ SLZXP LTP w/ DG Slips 6.180”
14 5623’ 7” H563 x 5.5” EZGO HT XO 4.850”
15 16,313’ Shoe
5-1/2” x 4-1/2”SCREENS LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2” 5756’ 4111’ 6693’ 4137’
4-1/2” 6735’ 4138’ 16274’ 4173’
CASING AND LEAK-OFF FRACTURE TESTS
Well Name:MPU R-142 Date:6/7/2024
Csg Size/Wt/Grade:9.625" 40/47# L-80 TXP BTC Supervisor:Anderson/Amend
Csg Setting Depth:5,766 TMD 4,111 TVD
Mud Weight:9.1 ppg LOT / FIT Press =660 psi
LOT / FIT =12.19 ppg Hole Depth =5775 md
Fluid Pumped=2.0 Bbls Volume Back =2.0 bbls
Estimated Pump Output:0.093 Barrels/Stroke
LOT / FIT DATA CASING TEST DATA
Enter Strokes Enter Pressure Enter Strokes Enter Pressure
Here Here Here Here
->00 ->2 90
->380 ->4 200
->5180 ->8 460
->7280 ->12 740
->9380 ->16 1000
->11 500 ->20 1200
->13 660 ->24 1440
-> ->28 1690
-> ->32 1950
-> ->36 2200
-> ->38 2320
-> ->42 2590
-> ->45 2790
-> ->
Enter Holding Enter Holding
Time Here Pressure Here Time Here Pressure Here
->0660 ->02790
->1640 ->12780
->2620 ->22780
->3610 ->32770
->4600 ->42770
->5600 ->52770
->6590 ->10 2760
->7590 ->15 2750
->8590 ->20 2750
->9580 ->25 2750
->10 580 ->30 2740
-> ->
-> ->
-> ->
0
3
5
7
9
11
13
2
4
8
12
16
20
24
28
32
36
38
42
45
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
0 1020304050
Pr
e
s
s
u
r
e
(
p
s
i
)
Strokes (# of)
LOT / FIT DATA CASING TEST DATA
660640620610600600590590590580580
279027802780277027702770 2760 2750 2750 27502740
0
100
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
0 5 10 15 20 25 30
Pr
e
s
s
u
r
e
(
p
s
i
)
Time (Minutes)
LOT / FIT
DATA
CASING TEST
DATA
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: ESP Swap
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?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
16,315'N/A
Casing Collapse
Conductor N/A
Surface 4,760psi
Surface 3,090psi
Tieback 5,410psi
Liner 8,830psi
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 Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
Taylor Wellman
twellman@hilcorp.com
777-8449
See Schematic
9,621'
See Schematic 2-7/8"
SLZXP LTP and N/A 5,501 MD/ 4,091 TVD and N/A
80' 20"
9-5/8"
9-5/8"
2,324'
5-1/2"1,092'
3,396' 4,112'
4,137'
2,370'
5,766'
4,173'4-1/2" 16,314'
6,693'
Proposed Pools:
126' 126'
6.5 / L-80 / EUE 8rd
TVD Burst
5,516'
9,020psi
MD
N/A
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL025509, ADL355018 & ADL388235
224-045
3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23790-00-00
Hilcorp Alaska LLC
C.O. 477.05
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft):
7/1/2024
Perforation Depth MD (ft):
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
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:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
Length Size
16,313' 4,173' 1,315 N/A
Subsequent Form Required:
Suspension Expiration Date:
9,190psi
6,870psi
5,750psi
2,022'
5,566' 7' 5,610' 4,099' 7,240psi
MPU R-142
Milne Point Schrader Bluff N/A
4,173'
No
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 3:01 pm, Jun 26, 2024
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2024.06.26 14:50:36 -
08'00'
Taylor Wellman
(2143)
324-369
DSR-6/26/24
BOPE test to 2500 psi.
MGR26JUN24
10-404
SFD 7/1/2024*&:
Brett W. Huber,
Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.07.01 10:35:06 -08'00'07/01/24
RBDMS JSB 070224
ESP Swap
Well: MPU R-142
Date: 06/25/2024
Well Name:MPU R-142 API Number:50-029-23790-00-00
Current Status:SI – ESP Grounded Pad:R-Pad
Estimated Start Date:07/01/24 Rig:ASR
Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd:-
Regulatory Contact:Tom Fouts Permit to Drill Number:224-045
First Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M)
Second Call Engineer:Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (M)
AFE Number:Job Type:FCO
Current Bottom Hole Pressure:1,720 psi @ 4,050’ TVD Recently Drilled (4/3/24) |8.2 PPGE
MPSP:1,315 psi (0.1 psi/ft gas gradient)
Max Inclination: 94° @ 9,679’ MD (Reaches >70 deg at 5,060’ MD)
Brief Well Summary:
MPU R-142 is a Schrader Oa production well that was drilled and completed on 06/17/24. This was the first
ESP that was run on Parker 273. While running the ESP, no hangups were encountered. Once landed the ESP
electrical tests passed as well as after the tree was on the well. Upon startup of the ESP, the well grounded
downhole. Diagnostics have indicated the electrical fault to be downhole and not on surface.
Objectives:
Pull failed ESP completion, diagnose cause of failure and run new ESP completion.
Notes Regarding Wellbore Condition:
- 9-5/8”x7” casing test to 1,620 psi on 06/19/2024
Pre-Rig Procedure (Non Sundried Work)
Slickline
1. RU slickline, pressure test PCE to 250psi low / 2,500psi high.
2. Pull DPSOV and set dummy valve in upper GLM at 151’ MD.
3. Pull DGLM at 5,014’ MD.
4. RDMO.
Pumping & Well Support
1. Clear and level pad area in front of well. Spot rig mats and containment.
2. RD well house and flowlines. Clear and level area around well.
3. RU Little Red Services. RU reverse out skid and 500 barrel returns tank.
4. Pressure test lines to 3,000 psi.
5. Circulate at least one wellbore volume with produced water down tubing, taking returns up casing
to 500 barrel returns tank.
6. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR
arrival.
7. RD Little Red Services and reverse out skid.
8. Set BPV. ND tree. NU BOPE.
ESP Swap
Well: MPU R-142
Date: 06/25/2024
Brief RWO Procedure (Begin Sundried Work)
1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 barrel returns tank.
2. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing
and casing.
a. If needed, kill well with produced water prior to setting CTS.
3. Test BOPE to 250 psi low/ 2,500 psi high. Test annular to 250 psi low/ 2,500 psi high (hold each
ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests.
a. Perform test per ASR 1 BOP Test Procedure
b. Notify AOGCC 24 hours in advance of BOP test.
c. Confirm test pressures per the Sundry conditions of approval.
d. Test VBR rams on 2-7/8” test joint.
e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test.
4. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the
returns tank. Kill well with produced water as needed. Pull BPV.
a. If indications show pressure underneath BPV, lubricate out BPV.
5. Call out Summit for ESP pull.
6. RU spoolers to handle ESP cable.
7. MU landing joint or spear, BOLDS, PU on the tubing hanger.
a. Tubing hanger is an FMC 11” x 4-1/2” TCII thread.
b. 2024 tubing PU weight on Parker 273 (Block wt 42k) recorded as 84 kip. Slack off weight
recorded as 66 kip.
c. 2-7/8” L-80 EUE yield is 144 kip.
8. Confirm hanger free, lay down tubing hanger.
a. Check the penetrator for damage and the ESP cable for electrical continuity. If the
penetrator is deemed to be the failure point, contact OE Taylor Wellman for discussion
907-947-9533. Decision to replace and re-land may be made.
9. POOH and lay down the 2-7/8” tubing.
a. Pulling speed to be reduced as per Summit recommendation to minimize chances for
rupturing seals.
b.High priority to inspect cable and MLE for damage. Note depths and description in
report. If cable damage is found in top ±1,800’ MD (±1,000’ TVD of seals movement) of
cable pulled, possibility to cut, splice and re-run ESP will be considered.
c. All tubing to be re-used.
d. Summit will direct which components need to be replaced and which will be re-run based
on failure point identified and which test electrically.
e. Recorded Clamp Totals:
i. Canon Clamps: 99
ii. SS Superbands = 4
10. Lay Down ESP.
11. RIH with new 2-7/8” 6.5# L-80 ESP completion to +/- 5,516’ and obtain string weights.
a. Check electrical continuity every 1000’.
b. Note PU and SO weights on tally.
c. Watch for any unanticipated weight changes and make note in the report.
ESP Swap
Well: MPU R-142
Date: 06/25/2024
d. Install ESP clamps per Summit, and cross coupling clamps every joint.
i.Contingency: If cable damage is observed and deemed to be the failure, use of
multiple mid-joint clamps may be required from ±2,300 – 5,516’ MD.
Nom. Size Length Item Lb/ft Material Notes
5.62 2 Centralizer 4 ±5,516’
4.52 2 Intake Sensor 30
5.62 24 Motor - 360HP 80
5.13 9 Lower Tandem Seal 38
5.13 9 Upper Tandem Seal 38
5.38 8 Gas Separator 52
5.38 24 Pumps – 538 SJ2800 45
4.5 1.5 Ported Discharge Head 13 L-80
2-7/8" 330 11jts of 2-7/8" EUE 8rd Jt 6.5 L-80
2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8"1 2-7/8" XN Nipple (ID=2.205”)6.5 L-80 <70 deg
2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" 30 2-7/8" EUE 8rd Jt 6.5 L-80
2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8"8 2-7/8" x 1" GLM, Dummy Valve 6.5 L-80 ±5,020’
2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" 4,800 2-7/8" EUE 8rd Jt 6.5 L-80
2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8"8 2-7/8" x 1" GLM, 1/4" OV 6.5 L-80 ±200’
2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" 150 2-7/8" EUE 8rd Jt 6.5 L-80
2-7/8" 10 Space out pup 6.5 L-80
2-7/8" 30 Tubing Hanger with full joint 6.5 L-80
12. Land tubing hanger. Use extra caution to not damage cable.
a. Test ESP electrically.
13. Lay down landing joint.
14. Set BPV.
15. RDMO ASR.
Post-Rig Procedure:
Well Support
1. RD mud boat. RD BOPE house. Move to next well location.
2. RU crane. ND BOPE, set CTS plug, and NU tree.
3. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV.
4. Test ESP electrically.
ESP Swap
Well: MPU R-142
Date: 06/25/2024
5. RD crane. Move 500 bbl returns tank and rig mats to next well location.
6. RU well house and flowlines.
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Schematic
3. BOPE Schematic
_____________________________________________________________________________________
Revised By: JNL 6/21/2024
SCHEMATIC
Milne Point Unit
Well: MPU R-142
Last Completed: 6/19/2024
PTD: 224-045
TD =16,315’(MD) / TD =4,173’(TVD)
4/5/6
20”
Orig. KB Elev.: 63.6’ / GL Elev.: 16.8’
7”
7/8/9
10
4
9-5/8”
1
2
3
See
Screen/
Solid
Liner
Detail
PBTD =16,313’(MD) / PBTD = 4,173’(TVD)
9-5/8” ‘ES’
Cementer @
2,349’ MD
4-1/2”
11
13
12
14
15
2-7/8”CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X56 / Weld N/A Surface 126’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,370’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 2,370’ 5,766’ 0.0758
7” Tieback 26 / L-80 / TXP 6.276 Surface 5,610’ 0.0383
5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.778 5,601’ 6,693’ 0.0222
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 6,693’ 16,314’ 0.0149
TUBING DETAIL
2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,516’ 0.0058
OPEN HOLE / CEMENT DETAIL
42” 17 yds Cement
12-1/4"Stg 1 Lead – 445 sx / Tail – 379 sx
Stg 2 Lead – 727 sx / Tail 270 sx
8-1/2” Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 180’
Max Hole Angle = 94° @7328’
TREE & WELLHEAD
Tree FMC 11” x 4-1/2” TC-II Tubing Hanger x 2-7/8” EUE
Wellhead 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: 50-029-23790-00-00
Completion Date: 6/19/2024
JEWELRY DETAIL
No. Top MD Item ID
1 151’ 2-7/8” x 1” BK-2 GLM w/ SOV 2.440”
2 5014’ 2-7/8” x 1” GLM Dummy Valve w/ BK Latch 2.440”
3 5073’ XN Nipple, 2.313” w/ 2.205” No-Go 2.205”
4 5438’ Discharge Sub
5 5439’ Discharge Bolt-On
6 5439’ Pump: 538, SJ2800
7 5463’ Pump Intake GS, 538
8 5470’ Upper Tandem Seal: 513 Series
9 5479’ Lower Tandem Seal: 513 Series
10 5488’ Motor: 562 Series, KMS2, 360HP
11 5512’ Sensor, 177C 8KPSI, 2x Press / Temp / Vib
12 5514’ Anode Centralizer: Bottom @ 5,516’ MD
13 5501’ SLZXP LTP w/ DG Slips 6.180”
14 5623’ 7” H563 x 5.5” EZGO HT XO 4.850”
15 16,313’ Shoe
5-1/2” x 4-1/2”SCREENS LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2” 5756’ 4111’ 6693’ 4137’
4-1/2” 6735’ 4138’ 16274’ 4173’
_____________________________________________________________________________________
Revised By: TDF 6/24/2024
PROPOSED
Milne Point Unit
Well: MPU R-142
Last Completed: 6/19/2024
PTD: 224-045
TD =16,315’(MD) / TD =4,173’(TVD)
4/5/6
20”
Orig. KB Elev.: 63.6’ / GL Elev.: 16.8’
7”
7/8/9
10
4
9-5/8”
1
2
3
See
Screen/
Solid
Liner
Detail
PBTD =16,313’(MD) / PBTD = 4,173’(TVD)
9-5/8” ‘ES’
Cementer @
2,349’ MD
4-1/2”
11
13
12
14
15
2-7/8”CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X56 / Weld N/A Surface 126’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,370’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 2,370’ 5,766’ 0.0758
7” Tieback 26 / L-80 / TXP 6.276 Surface 5,610’ 0.0383
5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.778 5,601’ 6,693’ 0.0222
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 6,693’ 16,314’ 0.0149
TUBING DETAIL
2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,516’ 0.0058
OPEN HOLE / CEMENT DETAIL
42” 17 yds Cement
12-1/4"Stg 1 Lead – 445 sx / Tail – 379 sx
Stg 2 Lead – 727 sx / Tail 270 sx
8-1/2” Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 180’
Max Hole Angle = 94° @7328’
TREE & WELLHEAD
Tree FMC 11” x 4-1/2” TC-II Tubing Hanger x 2-7/8” EUE
Wellhead 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
JEWELRY DETAIL
No. Top MD Item ID
1 ±151’ 2-7/8” x 1” BK-2 GLM w/ SOV 2.440”
2 ±5014’ 2-7/8” x 1” GLM Dummy Valve w/ BK Latch 2.440”
3 ±5073’ XN Nipple, 2.313” w/ 2.205” No-Go 2.205”
4 ±5438’ Discharge Sub
5 ±5439’ Discharge Bolt-On
6 ±5439’ Pump: 538, SJ2800
7 ±5463’ Pump Intake GS, 538
8 ±5470’ Upper Tandem Seal: 513 Series
9 ±5479’ Lower Tandem Seal: 513 Series
10 ±5488’ Motor: 562 Series, KMS2, 360HP
11 ±5512’ Sensor, 177C 8KPSI, 2x Press / Temp / Vib
12 ±5514’ Anode Centralizer: Bottom @ ±5,516’ MD
13 5501’ SLZXP LTP w/ DG Slips 6.180”
14 5623’ 7” H563 x 5.5” EZGO HT XO 4.850”
15 16,313’ Shoe
5-1/2” x 4-1/2” SCREENS LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2” 5756’ 4111’ 6693’ 4137’
4-1/2” 6735’ 4138’ 16274’ 4173’
GENERAL WELL INFO
API: 50-029-23790-00-00
Completion Date: 6/19/2024 by Parker 273
Milne Point
ASR Rig 1 BOPE
2023
11” BOPE
4.48'
4.54'
2.00'
CIW-U
4.30'
Hydril GK
11" - 5000
VBR or Pipe Rams
Blind11'’- 5000
DSA, 11 5M X 7 1/16 5M (If Needed)
2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves
HCRManualManualHCR
Stripping Head
2-7/8” x 5” VBR
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________MILNE PT UNIT R-142
JBR 07/24/2024
MISC. INSPECTIONS:
FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK:
ACCUMULATOR SYSTEM:MUD SYSTEM:
P/F P/F
P/FP/FP/F
Visual Alarm
QuantityQuantity
Time/Pressure
SizeQuantity
Number of Failures:1
2-7/8" & 5" joints. Blinds & CMV 14 tested to 5000psi. Annular closing time FP. Cycle & increase pressure for a pass @ 27.
Test Results
TEST DATA
Rig Rep:King/HerbertOperator:Hilcorp Alaska, LLC Operator Rep:Anderson/Herbert
Rig Owner/Rig No.:Parker 273 PTD#:2240450 DATE:6/6/2024
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopSAM240607121003
Inspector Austin McLeod
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 6.5
MASP:
1398
Sundry No:
Control System Response Time (sec)
Time P/F
Housekeeping:P
PTD On Location P
Standing Order Posted P
Well Sign P
Hazard Sec.P
Test Fluid W
Misc NA
Upper Kelly 1 P
Lower Kelly 1 P
Ball Type 3 P
Inside BOP 1 P
FSV Misc 0 NA
15 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13-5/8"P
#1 Rams 1 2-7/8"x5"P
#2 Rams 1 Blinds P
#3 Rams 1 2-7/8"x5"P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3-1/8"P
HCR Valves 2 3-1/8"P
Kill Line Valves 2 3-1/8"&2-1/1 P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3000
Pressure After Closure P2000
200 PSI Attained P18
Full Pressure Attained P68
Blind Switch Covers:PAll stations
Bottle precharge P
Nitgn Btls# &psi (avg)P14@2550
ACC Misc NA0
P PTrip Tank
P PPit Level Indicators
P PFlow Indicator
P PMeth Gas Detector
P PH2S Gas Detector
NA NAMS Misc
Inside Reel Valves 0 NA
Annular Preventer FP32
#1 Rams P7
#2 Rams P7
#3 Rams P7
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
9
9
9
9999
9
9
9
Annular closing time FP Cycle & increase pressure for a pass @ 27
32 FP
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK, 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU R-142
Hilcorp Alaska, LLC
Permit to Drill Number: 224-045
Surface Location: 5174' FSL, 4066' FEL, Sec 07, T13N, R10E, UM, AK
Bottomhole Location: 1404' FNL, 282' FWL, Sec 36, T14N, 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 May 2024.
Brett W. Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.05.10 09:33:02 -08'00'
10th
5-1/2"x4-1/2"EZGOHT/Hyd625
Drilling Manager
05/03/24
Monty M
Myers
By Grace Christianson at 12:24 pm, May 03, 2024
A.Dewhurst 09MAY24
DSR-5/6/24
224-045
MGR09MAY2024
* BOPE test to 3000 psi. Annular to 2500 psi.
* 9-5/8" casing test and FIT to AOGCC upon completing FIT.
50-029-23790-00-00
JLC 5/10/2024
Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2024.05.10 10:09:28 -08'00'
05/10/24
05/10/24
RBDMS_PLB 05/10/24
Milne Point Unit
(MPU) R-142
Drilling Program
Version 0
4/20/2024
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 21-1/4” 2M 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 N/U BOP and Test.................................................................................................................... 27
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28
16.0 Run 5-1/2” x 4-1/2” Screened Liner (Lower Completion) ...................................................... 33
17.0 Run Tieback ............................................................................................................................. 38
18.0 Run 2-7/8” Tubing (Upper Completion) ................................................................................. 41
19.0 RDMO ...................................................................................................................................... 42
20.0 Parker 273 Diverter Schematic ............................................................................................... 43
21.0 Parker 273 BOP Schematic ..................................................................................................... 44
22.0 Wellhead Schematic ................................................................................................................. 45
23.0 Days vs Depth ........................................................................................................................... 46
24.0 Formation Tops & Information............................................................................................... 47
25.0 Anticipated Drilling Hazards .................................................................................................. 50
26.0 Parker 273 Layout ................................................................................................................... 53
27.0 FIT Procedure .......................................................................................................................... 54
28.0 Parker 273 Choke Manifold Schematic................................................................................... 55
29.0 Casing Design ........................................................................................................................... 56
30.0 8-1/2” Hole Section MASP ....................................................................................................... 57
31.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 58
32.0 Surface Plat (As-Built) (NAD 27) ............................................................................................ 59
Page 2
Milne Point Unit
R-142 SB Producer
Drilling Procedure
1.0 Well Summary
Well MPU R-142
Pad Milne Point “R” Pad
Planned Completion Type 2-7/8” Production Tubing
Target Reservoir(s) Schrader Bluff Oa Sand
Planned Well TD, MD / TVD 16,166’ MD / 4,179’ TVD
PBTD, MD / TVD 16,166’ MD / 4,179’ TVD
Surface Location (Governmental) 5,175' FSL, 4,066' FEL, Sec. 07, T13N, R10E, UM, AK
Surface Location (NAD 27) X= 540,512.98 Y=6,033,340.01
Top of Productive Horizon
(Governmental)285' FNL, 269' FEL, Sec 12, T13N, R9E, UM, AK
TPH Location (NAD 27) X= 539,147.00 Y= 6,033,152.00
BHL (Governmental) 1,404' FNL, 282' FWL, Sec 36, T14N, R9E, UM, AK
BHL (NAD 27) X= 534,369.00 Y= 6,042,568.00
AFE Drilling Days 20 days
AFE Completion Days 3 days
Maximum Anticipated Pressure
(Surface) 1398 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1809 psig
Work String 5” 19.5# S-135 XT-50
KB Elevation above MSL: 46.95 ft + 16.7 ft = 63.65 ft
GL Elevation above MSL: 16.8 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Milne Point Unit
R-142 SB Producer
Drilling Procedure
2.0 Management of Change Information
Page 4
Milne Point Unit
R-142 SB Producer
Drilling Procedure
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.681” 8.525” 10.625” 47 L-80 TXP 6,870 4,750 1,086
9-5/8” 8.835” 8.679”10.625”40 L-80 TXP 5,750 3,090 916
8-1/2”5-1/2” 4.780”4.653”6.000”20 L-80 EZGO HT 9,190 8,830 466
4-1/2” 3.920”3.795” 4.500”13.5 L-80
H625 9,020 8,540 307
Tubing 2-7/8” 2.441”2.347”3.688”6.5 L-80
EUE 8RD 10,570 11,170 105
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” 3.500” 6.500” 19.5 S-135 XT50 44,000 52,800 712klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Milne Point Unit
R-142 SB Producer
Drilling Procedure
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp.com,
frank.roach@hilcorp.com,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 mmyers@hilcorp.com,frank.roach@hilcorp.com,
nathan.sperry@hilcorp.com, and joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to mmyers@hilcorp.com,
frank.roach@hilcorp.com,nathan.sperry@hilcorp.com, and joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Frank Roach 907.777.8413 Frank.roach@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Completion Engineer Taylor Wellman 907.777.8449 twellman@hilcorp.com
Geologist Graham Emerson 907.564.5242 graham.emerson@hilcorp.com
Reservoir Engineer Alan Abel 907.564.4621 alan.abel@hilcorp.com
Drilling Env. Coordinator Adrian Kersten 907.564.4820 adrian.kersten@hilcorp.com
EHS Director Laura Green 907.777.8314 lagreen@hilcorp.com
Drilling Tech Joe Lastufka 907.777.8400 Joseph.Lastufka@hilcorp.com
_____________________________________________________________________________________
Revised By: FVR 5/3/2024
PROPOSED SCHEMATIC
Milne Point Unit
Well: MPU R-142
Last Completed: TBD
PTD: TBD
TD =16,166’(MD) / TD =4,179’(TVD)
4/5/6
20”
Orig. KB Elev.: 63.65’ / GL Elev.: 16.7’
7”
7/8/9
10
4
9-5/8”
1
2
3
See
Screen/
Solid
Liner
Detail
PBTD =16,166’(MD) / PBTD = 4,179’(TVD)
9-5/8” ‘ES’
Cementer @
~2,500’ MD
4-1/2”
11
13
12
14
15
2-7/8”CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X56 / Weld N/A Surface 107’ 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’ 5,650’ 0.0758
7” Tieback 26 / L-80 / TXP 6.276 Surface 5,500’ 0.0383
5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.778 5,500’ 6,666’ 0.0222
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 6,666’ 16,166’ 0.0149
TUBING DETAIL
2-7/8" Tubing 6.5 / L-80 / EUE-8rd 2.441 Surface 5,393’ 0.0087
OPEN HOLE / CEMENT DETAIL
42” ±270 ft3
12-1/4"Stg 1 Lead – 373 sx / Tail – 395 sx
Stg 2 Lead – 673 sx / Tail 268 sx
8-1/2” Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 300’
Max Hole Angle = 95° @6793’
TREE & WELLHEAD
Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: TBD
Completion Date: TBD
JEWELRY DETAIL
No. Top MD Item ID
1 128’ 3-1/2” x 1” BK-2 GLM w/ 1” SOV 2.915”
2 4688’ 3-1/2” x 1” GLM Dummy Valve w/ BK Latch 2.920”
3 4810’ XN Nipple, 2.813” Profile, 2.75” No Go 2.750”
4 5393’ Ported Pressure Sub
5 5395’ Discharge Head: 513, MS1-015
6 5396’ Pump: 513 Series 111 Stage SG2000
7 5418’ Gas Separator: Tandem 400 Series
8 5424’ Upper Tandem Seal: 513 Series
9 5433’ Lower Tandem Seal: 513 Series
10 5441’ Motor: 562 Series, KMS2, 300HP
11 5462’ Sensor, Vigilant, 150C w/ Discharge
12 5464’ Summit Centralizer / Anode: Bottom @ 5,466’ MD
13 5500’ SLZXP LTP / Liner Hanger Lap ~178’ 6.190”
14 5530’ 7” H563 x 5.5” EZGO HT XO 3.850”
15 16,166’ Shoe
5-1/2” x 4-1/2”SCREENS LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2”
4-1/2”
Page 6
Milne Point Unit
R-142 SB Producer
Drilling Procedure
6.0 Planned Wellbore Schematic
Superseded by higher resolution version. -A.Dewhurst 09MAY24
Page 7
Milne Point Unit
R-142 SB Producer
Drilling Procedure
7.0 Drilling / Completion Summary
MPU R-142 is a grassroots producer planned to be drilled in the Schrader Bluff OA sand. R-142 is part of a
multi well development program targeting the Schrader Bluff sand on R-pad.
The directional plan is a horizontal well with 12-1/4” surface hole with 9-5/8” surface casing set into the top
of the Schrader Bluff sand. An 8-1/2” lateral section will be drilled. A production liner will be run in the
open hole section.
The Parker 273 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately May 30st, 2024, pending rig schedule.
Surface casing will be run to 5,650’ MD / 4,113’ TVD and cemented to surface via a 2-stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will be discussed with AOGCC 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 Parker 273 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 & test 13-5/8” x 5M BOP. Install MPD Riser
5. Drill 8-1/2” lateral to well TD.
6. Run 5-1/2” x 4-1/2” production liner.
7. Run 2-7/8” ESP tubing.
8. 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
R-142 SB Producer
Drilling Procedure
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 R-142.
Ensure to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14-day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
AOGCC Regulation Variance Requests:
x None
Page 9
Milne Point Unit
R-142 SB Producer
Drilling Procedure
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 Annular BOP
x 13-5/8” x Double Gate
o Blind/Shear ram in btm cavity
x Mud cross w/ 3-1/8” x 5M side outlets
x 13-5/8” x Single ram
x 3” x 5M Choke Line
x 2” x 5M Kill line
x 3” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
Annular: 250/2500
Subsequent Tests:
250/3000
Annular 250/2500
Primary closing unit: Sara Koomey Control Unit, 3,000 psi, 316 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an air-driven
pump, and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOP’s utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in PTD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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9.0 R/U and Preparatory Work
9.1 R-142 will utilize a newly set 20” conductor on R-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 Parker 273. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
9.10 Ensure 5-3/4” liners in mud pumps.
x NOV 12-P-160 1,600 HP mud pumps are rated at 5,085 psi, 466 gpm @ 120 spm @ 96%
volumetric efficiency.
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10.0 N/U 21-1/4” 2M Diverter System
10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program).
x N/U 20” riser to BOP Deck
x N/U 20”, 5M diverter “T”.
x NU Knife gate & 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
10.2 Notify AOGCC. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID greater than 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
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10.4 Rig & Diverter Orientation:
x May change on location
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11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Use GWD until 1,500’ or MWD surveys clean up, whichever is deeper.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD, in the Schrader OA sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm, staying between 400 and 450 gpm through the permafrost. 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, increases 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 permafrost (pending MW increase due to hydrates).
x Drill ahead using GWD. Take MWD surveys every stand drilled and swap to MWD when
MWD surveys clean up or after 1,500’ (whichever is deeper).
x Gas hydrates have not been seen on pads adjacent to R-Pad (F-Pad and L-Pad). However, be
prepared for them. In MPU they have been encountered typically around 2100’-2400’ TVD
(just below permafrost). Be prepared for hydrates:
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x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well.
MW will not control gas hydrates, but will affect how gas breaks out at surface.
x AC: All wells have a clearance factor greater than 1.0 in the surface interval.
12-1/4” hole mud program summary:
x Density: Weighting material to be used for the hole section will be barite. Additional barite
or spike fluid will be on location to weight up the active system (1) ppg above highest
anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and TD with
9.2+ ppg.
Depth Interval MW (ppg)
Surface – Base Permafrost 8.9+
Base Permafrost - TD 9.2+
MW can be cut once ~500’ below hydrate zone
x PVT System: MD Totco PVT will be used throughout the drilling and completion phase.
Remote monitoring stations will be available at the driller’s console, Co Man office,
Toolpusher office, and mud loggers office.
x Rheology: MIGEL and Flow-Vis 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: M-I PAC UL should be used for filtrate control. Background LCM (10 ppb
total) 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 SCREENKLEAN / LO-TORQ 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 BUSAN 1060 MUST be
made to control bacterial action.
x Casing Running:Reduce system YP with DESCO as required for running casing as allowed
(do not jeopardize hole conditions). Run casing carefully to minimize surge and swab
pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with
the cementers to see what YP value they have targeted).
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System Type:8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud
Properties:
Section Density Viscosity Plastic
Viscosity Yield Point API FL pH
Temp
Surface 8.8 –9.8 75-300 20 - 40 25-45 <10 8.5 –9.0 70 F
System Formulation:Gel + FW spud mud
Product- Surface hole Size Pkg ppb or (% liquids)
M-I Gel 50 lb sx 25
Soda Ash 50 lb sx 0.25
PolyPac Supreme UL 50 lb sx 0.08
Caustic Soda 50 lb sx 0.1
SCREENCLEEN 55 gal dm 0.5
11.4 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity.
11.5 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm) and maximize rotation.
x Pull slowly, 5 – 25 ft / minute.
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.6 TOOH and LD BHA
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12.0 Run 9-5/8” Surface Casing
12.1 R/U Parker Wellbore 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” TXP x XT50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8-1/2” on the location prior to running.
x Note that 47# drift is 8.525” and 40# is 8.679”
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.2 P/U shoe joint, visually verify no debris inside joint.
12.3 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” TXP, 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
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12.4 Float equipment and Stage tool equipment drawings:
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12.5 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
x Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.6 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost.
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damage to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 40# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8” 18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8” 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8” 21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
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12.7 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 300’ from surface
o Ensure conductor is free of centralizers
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.
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12.8 Ensure the permafrost is covered with 9-5/8” 47#. Estimated XO depth is 2500’.
x Ensure 47# Casing is drifted to 8.525”
12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.10 Slow in and out of slips.
12.11 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.
12.12 Lower casing to setting depth. Confirm measurements.
12.13 Have slips staged in cellar along with all necessary equipment for the operation.
12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible,
reciprocate casing string while conditioning mud.
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13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amount of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom
plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 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.
x Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
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Estimated 1st Stage Total Cement Volume:
Cement Slurry Design (1st Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (shutoff plug) and displace cement with spud mud out of
mud pits, spotting tuned spacer across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant
communication between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
13.11 Displacement calculation is in the Stage 1 Table in step 13.7.
80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the
ES cementer is tuned spacer to minimize the risk of flash setting cement
13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up
option to open the stage tool if the plugs are not bumped.
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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13.14 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.15 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for
the 2nd stage of the cement job.
13.16 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.17 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Hold pre-job safety meeting.
13.18 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.19 Fill surface lines with water and pressure test.
13.20 Pump remaining 10.5 ppg tuned spacer.
13.21 Mix and pump cmt per below recipe for the 2
nd stage.
13.22 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However, cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.23 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.24 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.25 Displacement is in the Stage 2 table in step 13.22.
Lead Slurry Tail Slurry
System ArcticCem HalCem
Density 10.7 lb/gal 15.8 lb/gal
Yield 2.88 ft3/sk 1.17 ft3/sk
Mixed
Water 22.02 gal/sk 5.08 gal/sk
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13.26 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.27 Land closing plug on stage collar and pressure up to 1000 – 1500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips with 50K in slips.
13.28 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job. If intermittent, note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to frank.roach@hilcorp.com,
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 N/U BOP and Test
14.1 N/D the diverter T, knife gate, diverter line & N/U 11” x 13-5/8” 5M casing spool.
14.2 N/U 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 2-7/8” x 5” VBRs or 5” solid body rams in top
cavity,blind/shear ram in bottom cavity.
x Single ram can be dressed with 2-7/8” x 5” VBRs
x N/U bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual
valve
14.3 Install BOP test plug
14.4 Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
x Test 2-7/8” x 5” rams with the 3-1/2” and 5” test joints
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
x Ensure weekly BOP Function tests are completed and documented in the IADC, noting
Blind/Shear rams to be functioned on the next possibility when out of the hole.
14.5 R/D BOP test equipment
14.6 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.7 Mix 8.9 ppg 3% KCl FloPro fluid for production hole.
14.8 Set wearbushing in wellhead.
14.9 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.10 Ensure 5-3/4” liners in mud pumps.
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15.0 Drill 8-1/2” Hole Section
15.1 M/U 8.5” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = ~2875 psi, but max test pressure on
the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT. Pump at least one high vis sweep at maximum rate to surface to
clean up debris.
15.7 Conduct FIT to 12.0 ppg EMW. Chart test. Ensure test is recorded on same chart as FIT.
Document incremental volume pumped (and subsequent pressure) and volume returned.
x 12.0 ppg desired to cover shoe strength for expected ECD’s. A 9.9 ppg FIT is the minimum
required to drill ahead
x 9.9 ppg provides >25 bbls based on 9.2ppg MW, 8.46ppg PP (swabbed kick at 9.2ppg
BHP)
15.8 POOH & LD Cleanout BHA
15.9 P/U 8-1/2” RSS directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is R/U and operational.
x Ensure GWD is included in the BHA
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 XT50.
x Run>2 non-ported floats in the production hole section to ensure MPD can hold pressure.
Email casing test and FIT digital data to AOGCC immediately upon completion of FIT. email: melvin.rixse@alaska.gov
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Schrader Bluff Bit Jetting Guidelines
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (Flo-VIS Plus). 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
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System Formulation:
Product- production Size Pkg ppb or (% liquids)
Busan 1060 55 gal dm 0.095
FLOTROL 55 lb sx 6
CONQOR 404 WH (8.5 gal/100 bbls)55 gal dm 0.2
FLO-VIS PLUS 25 lb sx 0.7
KCl 50 lb sx 10.7
SMB 50 lb sx 0.45
LOTORQ 55 gal dm 1.0
SAFE-CARB 10 (verify)50 lb sx 10
SAFE-CARB 20 (verify)50 lb sx 10
Soda Ash 50 lb sx 0.5
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 P/U
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.15 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 Utilize GWD surveys for entire 8-1/2” hole section
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Surveys can be taken more frequently if deemed necessary.
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section.
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x Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
x Target ROP is as fast as we can clean the hole (under 250 fph) without having to backream
connections
x Watch for higher than expected pressure. MPD will be utilized to monitor pressure build up
on connections
x Schrader Bluff OA Concretions: 4-6% Historically
x 8-1/2” Lateral A/C:
x F-80 has a 0.413 CF. F-80 was a Kuparuk well drilled in 1998 and was P&A’d in 2011.
15.16 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to sidetrack low and right in a fast drilling interval where the wellbore is headed up.
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.
15.17 At TD, CBU (minimum 4X, more if needed) at 200 ft/min AV (385+ gpm) and rotation (120+
rpm). Pump tandem sweeps if needed
x Rack back a stand at each bottoms up and reciprocate a full stand in between (while
circulating the BU). Keep the pipe moving while pumping.
x Monitor BU for increase in cuttings. Cuttings in laterals will come back in waves and not a
consistent stream so circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.18 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbls Mud in between. Displace out SAP pills. Monitor shakers for returns of mud
filter cake and calcium carbonate. Circulate the well clean.
x Losses during the cleanup of the wellbore are a good indication that the mud filter cake is
being removed, including an increase in the loss rate.
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15.19 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.
15.20 BROOH with the drilling assembly to the 9-5/8” casing shoe. Note: PST test is NOT required.
x Circulate at full drill rate unless losses are seen (350 gpm minimum if on losses)
x Rotate at maximum rpm that can be sustained.
x Target pulling speed of 5 – 10 min/std (slip to slip time, not including connections), but
adjust as hole conditions dictate.
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
15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow through MPD. Increase mud weight if necessary
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
15.23 Rig down MPD Equipment.
15.24 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball
drops.
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16.0 Run 5-1/2” x 4-1/2” Screened Liner (Lower Completion)
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 With 4-1/2” joint across BOP: P/U & M/U the 5” safety joint (with 4-1/2” crossover installed
on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW). This joint
shall be fully M/U and available prior to running the first joint of 4-1/2” liner.
x With a 5-1/2” joint across the BOP: P/U & M/U the 5” safety joint (with 5-1/2” crossover
installed on bottom, TIW valve in open position on top, 5-1/2” handling joint above TIW).
This joint shall be fully M/U and available prior to running the first joint of 5-1/2” liner.
x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” drillpipe. Close TIW.
x Proceed with well kill operations
16.2. Confirm VBR’s have been tested to cover pipe sizes to 250 psi low/3000 psi high.
16.3. R/U 5-1/2” and 4-1/2” liner running equipment.
x Ensure 4-1/2” Hydril 625 and 5-1/2” JFE Bear x XT-50 crossovers are on rig floor and M/U
to FOSV.
x Ensure the liner has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.4. Run 5-1/2” x 4-1/2” screened production liner.
x Use Appropriate dopes based upon thread type. Dope pin end only w/ paint brush. Wipe off
excess. Thread compound can plug the screens.
x 5-1/2” JFE Bear requires BOL 4010NM or Jet Lube
x 4-1/2” H625 requires API Modified Best-O-Life 2000 AG.
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).
x Do not place tongs or slips on screen joints
x Screen placement ±40’
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each jt
outside of the surface shoe. This is to mitigate differential 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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5-1/2” 20# L-80 EZGO HT
Casing OD Minimum Optimum Maximum
Operating Torque
5.5” 6,997 ft-lbs 10,728 ft-lbs
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4-1/2” 13.5# L-80 H625
Casing OD Minimum Optimum Maximum
Operating Torque
4.5” 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs
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16.5. Ensure that the liner top packer is set ~150’ MD above the 9-5/8” shoe. Also ensure that the liner
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). Ensure hanger/packer will not be set in a 9-5/8” connection.
16.6. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.7. M/U Baker SLZXP liner top packer to liner.
16.8. 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.
16.9. 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.
16.10. 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.
16.11. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.12. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.13. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.14. Rig up to pump down the work string with the rig pumps.
16.15. 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
16.16. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
16.17. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
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16.18. 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.
16.19. 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.
16.20. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.21. 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.
16.22. PU pulling running tool free of the packer and displace at max rate to wash the liner top. Pump
sweeps as needed.
16.23. 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 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.
17.5 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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17.6 MU 7” to DP crossover.
17.7 MU stand of DP to string, and MU top drive.
17.8 Break circulation at 1 BPM and begin lowering string.
17.9 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
17.10 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO-
GO DEPTH”.
17.11 PU string & remove unnecessary 7” joints.
17.12 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.
17.13 PU and MU the 7” casing hanger.
17.14 Ensure circulation is possible through 7” string.
17.15 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus.
17.16 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).
17.17 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
17.18 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.
17.19 RD casing running tools.
17.20 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted.
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18.0 Run 2-7/8” Tubing (Upper Completion)
18.1 Perform BOP Test on the VBR’s and annular for running 2-7/8” tubing to 250/3500psi.
18.2 M/U production assembly and RIH to setting depth. TIH no faster than 90 ft/min.
x Ensure wear bushing is pulled.
x Ensure 2-7/8” EUE 8RD x NC-50 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Ensure that the ESP Cable spooler is rigged up on the rig floor.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
x Monitor displacement from wellbore while RIH.
2-7/8” EUE Make-Up Torques
Casing OD Minimum Optimum Maximum
Operating Torque
2.875” 1,690 ft-lbs 2,250 ft-lbs 2,810 ft-lbs
2-Ǭ” Upper Completion Running Order
x Centralizer (OD = ±5.85”), Base at ±5,500’ MD
x Intake Sensor
x 360Hp 456 Motor (OD = 4.56”)
x Lower Seal Section
x Upper Seal Section
x Intake / Gas Separator
x Pump Section 3
x Pump Section 2
x Pump Section 1
x Discharge Head
x Joints 2-7/8”, 6.5#, L-80, EUE 8rd tubing
x ±10’ Pup Joint 2-7/8”, 6.5#, L-80, EUE 8rd
x 2-7/8” GLM (+/-140’ MD)
x ±10’ Pup Joint 2-7/8”, 6.5#, L-80, EUE 8rd
x 1 joint 2-7/8”, 6.5#, L-80, EUE 8rd tubing
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x 2-7/8”, 6.5#, L-80, EUE 8rd space out pups (if needed)
x 1 joint 2-7/8”, 6.5#, L-80, EUE 8rd tubing
x Tubing hanger with 2-7/8”, 6.5#, L-80, EUE 8rd pin down
18.3 Follow all service company procedures for handling, make up and deployment of the ESP
system.
x Typical clamping is every joint for the first 15 joints and then every other joint to surface.
Make note of clamping performed in tally.
x Perform electrical continuity checks every 2,000’ MD.
18.4 Land hanger. RILDs and test hanger.
18.5 Set BPV, ensure new body seals are installed each time. ND BOPE and NU adapter flange and
tree.
18.6 Pull BPV. Set TWC. Test tree to 5000 psi.
18.7 Pull TWC. Set BPV. Bullhead tubing & IA freeze protect if/as needed.
18.8 Secure the tree and cellar.
19.0 RDMO
19.1 RDMO Parker 273
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20.0 Parker 273 Diverter Schematic
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21.0 Parker 273 BOP Schematic
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22.0 Wellhead Schematic
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23.0 Days vs Depth
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24.0 Formation Tops & Information
TOP NAME TVD
(FT)
TVDSS
(FT)
MD
(FT)
Formation Pressure
(psi)
EMW
(ppg)
SV5 1,414 1,350 1,489 622 8.46
Base Permafrost 1,892 1,828 2,166 832 8.46
SV1 2,102 2,038 2,456 925 8.46
LA3 3,399 3,335 3,948 1495 8.46
UG_MB 3,684 3,620 4,336 1621 8.46
SB_Na 3,929 3,865 4,782 1728 8.46
SB_Oa 4,109 4,045 5,608 1807 8.46
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L-Pad and F-Pad Data Sheets Formation Descriptions (Closest & Most Analogous MPU Pads to Moose Pad)
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25.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates
Gas hyrates have not been seen on Moose pad. However, be prepared for them. 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 ECDs
to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU and keep pipe moving to
avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are a number of wells in close proximity. Take directional surveys every stand, take additional
surveys if necessary. Continuously monitor proximity to offset wellbores and record any close
approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in
adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Well
specific A/C:
x There are no wells with a CF < 1.0
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
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1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
appropriately to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to
determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU and keep pipe moving to
avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There is one mapped fault that will be crossed while drilling the well. There could be others and the
throw of these faults is not well understood at this point in time. When a known fault is coming up,
ensure to put a “ramp” in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed,
we’ll need to either drill up or down to get a look at the LWD log and determine the throw and then
replan the wellbore.
H2S:
Treat every hole section as though it has the potential for H2S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Abnormal (offset injection) pressure has been seen on R-
Pad. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan. Well specific AC:
x There are no wells with a CF < 1.0
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26.0 Parker 273 Layout
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27.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
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28.0 Parker 273 Choke Manifold Schematic
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29.0 Casing Design
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30.0 8-1/2” Hole Section MASP
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31.0 Spider Plot (NAD 27) (Governmental Sections)
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32.0 Surface Plat (As-Built) (NAD 27)
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075015002250300037504500True Vertical Depth (1500 usft/in)-2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750Vertical Section at 326.66° (1500 usft/in)Well wp04 tgt1Well wp04 tgt3Well wp04 tgt5Well wp04 tgt6Well wp04 tgt7Well wp04 tgt9Well wp04 tgt11Well wp04 tgt13Well wp04 tgt15Well wp04 tgt16Well wp04 tgt17Well wp04 tgt199 5/8" x 12 1/4"4 1/2" x 8 1/2"500100015002 0 0 0
2500300035004000450050005500600065007000750080008500900095001000010500110001150012000125001300013500140001450015000155001600016166MPU R-142 wp06Start Dir 3º/100' : 300' MD, 300'TVDEnd Dir : 1968.54' MD, 1764.24' TVDStart Dir 4º/100' : 2114.72' MD, 1858.09'TVDEnd Dir : 5319.18' MD, 4076.73' TVDBegin GeosteeringTotal Depth : 16165.69' MD, 4178.65' TVDSV5Base PermafrostSV1LA3UG_MBSB_NaSB_OaHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: MPU R-14216.70+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.006033340.05540512.96 70° 30' 7.2817 N 149° 40' 7.0569 WSURVEY PROGRAMDate: 2024-03-23T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool46.95 1500.00 MPU R-142 wp06 (MPU R-142)GYD_Quest GWD1500.00 5650.00 MPU R-142 wp06 (MPU R-142)3_MWD+IFR2+MS+Sag5650.00 16165.69 MPU R-142 wp06 (MPU R-142)GYD_Quest GWDFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1413.65 1350.00 1488.98 SV51891.65 1828.00 2166.07 Base Permafrost2101.65 2038.00 2456.51 SV13398.65 3335.00 3948.42 LA33683.65 3620.00 4336.41 UG_MB3928.65 3865.00 4781.57 SB_Na4108.65 4045.00 5608.24 SB_OaREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU R-142, True NorthVertical (TVD) Reference:R-142 as staked @ 63.65usftMeasured Depth Reference:R-142 as staked @ 63.65usftCalculation Method:Minimum CurvatureProject:Milne PointSite:M Pt Raven PadWell:Plan: MPU R-142Wellbore:MPU R-142Design:MPU R-142 wp06CASING DETAILSTVD TVDSS MD SizeName4113.26 4049.61 5650.00 9-5/8 9 5/8" x 12 1/4"4178.31 4114.66 16129.23 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 46.95 0.00 0.00 46.95 0.00 0.00 0.00 0.00 0.002 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD3 1968.54 50.06 178.92 1764.24 -683.54 12.89 3.00 178.92 -578.11 End Dir : 1968.54' MD, 1764.24' TVD4 2114.72 50.06 178.92 1858.09 -795.59 15.00 0.00 0.00 -672.88 Start Dir 4º/100' : 2114.72' MD, 1858.09'TVD5 5319.18 83.66 333.64 4076.73 -429.97 -1243.54 4.00 147.32 324.32 End Dir : 5319.18' MD, 4076.73' TVD6 5599.18 83.66 333.64 4107.65 -180.62 -1367.10 0.00 0.00 600.54 Well wp04 tgt17 5704.18 83.66 333.64 4119.24 -87.11 -1413.43 0.00 0.00 704.138 5915.52 90.00 333.64 4130.93 101.86 -1507.08 3.00 0.00 913.479 5924.83 89.88 333.44 4130.94 110.20 -1511.23 2.50 -122.08 922.7110 6587.95 89.88 333.44 4132.37 703.35 -1807.70 0.00 0.00 1581.1811 6792.92 95.00 333.37 4123.65 886.40 -1899.34 2.50 -0.81 1784.48 Well wp04 tgt312 6915.74 91.96 333.54 4116.20 996.07 -1954.13 2.50 176.78 1906.2013 7311.45 91.96 333.54 4102.70 1350.12 -2130.33 0.00 0.00 2298.8314 7499.39 87.24 333.34 4104.02 1518.17 -2214.34 2.50 -177.56 2485.3915 7699.39 87.24 333.34 4113.65 1696.70 -2303.97 0.00 0.00 2683.80 Well wp04 tgt516 7778.35 85.21 333.23 4118.85 1767.08 -2339.39 2.58 -176.80 2762.0617 7803.68 85.21 333.23 4120.97 1789.61 -2350.76 0.00 0.00 2787.1418 8010.72 90.54 333.51 4128.651974.49 -2443.47 2.58 3.05 2992.54 Well wp04 tgt619 8028.59 90.09 333.53 4128.55 1990.49 -2451.44 2.50 177.97 3010.2820 8874.67 90.09 333.53 4127.17 2747.85 -2828.62 0.00 0.00 3850.2921 9068.74 94.94 333.30 4118.65 2921.17 -2915.36 2.50 -2.66 4042.77 Well wp04 tgt722 9217.75 91.22 333.45 4110.65 3054.17 -2982.04 2.50 177.73 4190.5223 9881.81 91.22 333.45 4096.53 3648.05 -3278.82 0.00 0.00 4849.7724 10117.73 85.32 333.38 4103.65 3858.84 -3384.31 2.50 -179.34 5083.84 Well wp04 tgt925 10245.83 88.52333.51 4110.53 3973.24 -3441.48 2.50 2.39 5210.8426 11080.72 88.52 333.51 4132.11 4720.25 -3813.71 0.00 0.00 6039.4827 11345.77 95.14 333.23 4123.65 4956.94 -3932.38 2.50 -2.45 6302.4428 11345.78 95.14 333.23 4123.65 4956.95 -3932.38 0.00 0.00 6302.45 Well wp04 tgt1129 11537.32 90.36 333.45 4114.47 5127.88 -4018.19 2.50 177.31 6492.4130 12284.10 90.36 333.45 4109.82 5795.91 -4351.93 0.00 0.00 7233.9231 12344.37 88.85 333.48 4110.24 5849.84 -4378.86 2.50 179.02 7293.7732 12514.36 88.85 333.48 4113.65 6001.91 -4454.74 0.00 0.00 7462.52 Well wp04 tgt1333 12567.43 87.52 333.44 4115.33 6049.36 -4478.45 2.50 -178.08 7515.1934 13682.20 87.52 333.44 4163.49 7045.52 -4976.51 0.00 0.00 8621.1335 13876.51 92.38 333.57 4163.65 7219.37 -5063.18 2.50 1.59 8814.0036 13876.51 92.38 333.57 4163.65 7219.37 -5063.18 0.00 0.00 8814.00 Well wp04 tgt1537 13894.44 92.83 333.59 4162.84 7235.41 -5071.15 2.50 3.06 8831.7838 14065.27 92.83 333.59 4154.41 7388.22 -5147.02 0.00 0.00 9001.1539 14165.72 90.32 333.46 4151.65 7478.10 -5191.78 2.50 -176.94 9100.83 Well wp04 tgt1640 14180.94 90.70 333.49 4151.51 7491.72 -5198.58 2.50 4.71 9115.9441 14741.60 90.70 333.49 4144.67 7993.39 -5448.80 0.00 0.00 9672.5742 14889.93 87.00 333.23 4147.65 8125.93 -5515.29 2.50 -175.96 9819.84 Well wp04 tgt1743 14921.82 87.77 333.04 4149.10 8154.35 -5529.68 2.50 -13.60 9851.4944 15497.80 87.77 333.04 4171.47 8667.36 -5790.59 0.00 0.00 10423.4745 15565.69 89.47 332.96 4173.10 8727.83 -5821.40 2.50 -2.78 10490.9246 16165.69 89.47 332.96 4178.65 9262.22 -6094.16 0.00 0.00 11087.26 Well wp04 tgt19 Total Depth : 16165.69' MD, 4178.65' TVD
-1800
-1200
-600
0
600
1200
1800
2400
3000
3600
4200
4800
5400
6000
6600
7200
7800
8400
9000
9600
South(-)/North(+) (1200 usft/in)-7200 -6600 -6000 -5400 -4800 -4200 -3600 -3000 -2400 -1800 -1200 -600 0 600 1200
West(-)/East(+) (1200 usft/in)
Well wp04 tgt19
Well wp04 tgt17
Well wp04 tgt16
Well wp04 tgt15
Well wp04 tgt13
Well wp04 tgt11
Well wp04 tgt9
Well wp04 tgt7
Well wp04 tgt6
Well wp04 tgt5
Well wp04 tgt3
Well wp04 tgt1
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
1000
1500
1750
2000
2250
275030003250350037504 0 0 0
4 1 7 9MPU R -1 4 2 w p 0 6
Start Dir 3º/100' : 300' MD, 300'TVD
End Dir : 1968.54' MD, 1764.24' TVD
Start Dir 4º/100' : 2114.72' MD, 1858.09'TVD
End Dir : 5319.18' MD, 4076.73' TVD
Begin Geosteering
Total Depth : 16165.69' MD, 4178.65' TVD
CASING DETAILS
TVD TVDSS MD Size Name
4113.26 4049.61 5650.00 9-5/8 9 5/8" x 12 1/4"
4178.31 4114.66 16129.23 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site: M Pt Raven Pad
Well: Plan: MPU R-142
Wellbore: MPU R-142
Plan: MPU R-142 wp06
WELL DETAILS: Plan: MPU R-142
16.70
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6033340.05 540512.96 70° 30' 7.2817 N 149° 40' 7.0569 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU R-142, True North
Vertical (TVD) Reference: R-142 as staked @ 63.65usft
Measured Depth Reference:R-142 as staked @ 63.65usft
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700Measured Depth (600 usft/in)MPU F-110No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU R-142 NAD 1927 (NADCON CONUS)Alaska Zone 0416.70+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006033340.05540512.9670° 30' 7.2817 N149° 40' 7.0569 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU R-142, True NorthVertical (TVD) Reference:R-142 as staked @ 63.65usftMeasured Depth Reference:R-142 as staked @ 63.65usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-03-23T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool46.95 1500.00 MPU R-142 wp06 (MPU R-142) GYD_Quest GWD1500.00 5650.00 MPU R-142 wp06 (MPU R-142) 3_MWD+IFR2+MS+Sag5650.00 16165.69 MPU R-142 wp06 (MPU R-142) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 3900 4200 4500 4800 5100 5400 5700Measured Depth (600 usft/in)MPU R-105 wp02MPU R-112 wp02MPU R-113 wp02MPU R-110 wp02MPU R-104 wp02MPU R-107 wp02MPU R-111 wp02MPU R-106 wp02MPU R-103 wp02MPU R-108 wp02MPU R-109 wp02NO GLOBAL FILTER: Using user defined selection & filtering criteria46.95 To 16165.69Project: Milne PointSite: M Pt Raven PadWell: Plan: MPU R-142Wellbore: MPU R-142Plan: MPU R-142 wp06Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name4113.26 4049.61 5650.00 9-5/8 9 5/8" x 12 1/4"4178.31 4114.66 16129.23 4-1/2 4 1/2" x 8 1/2"
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0.001.002.003.004.00Separation Factor6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 16800Measured Depth (1200 usft/in)MPU R-141 wp07MPU R-12 wp03MPU R-145 wp03MPF-06MPU R-115 wp02MPU R-119 wp02MPU R-114 wp02MPU R-144 wp03MPU R-143 wp04MPF-85MPF-80MPU R-117 wp02MPU R-118 wp02MPU R-116 wp02No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: MPU R-142 NAD 1927 (NADCON CONUS)Alaska Zone 0416.70+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006033340.05 540512.96 70° 30' 7.2817 N 149° 40' 7.0569 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: MPU R-142, True NorthVertical (TVD) Reference:R-142 as staked @ 63.65usftMeasured Depth Reference:R-142 as staked @ 63.65usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-03-23T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool46.95 1500.00 MPU R-142 wp06 (MPU R-142) GYD_Quest GWD1500.00 5650.00 MPU R-142 wp06 (MPU R-142) 3_MWD+IFR2+MS+Sag5650.00 16165.69 MPU R-142 wp06 (MPU R-142) GYD_Quest GWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 16800Measured Depth (1200 usft/in)NO GLOBAL FILTER: Using user defined selection & filtering criteria46.95 To 16165.69Project: Milne PointSite: M Pt Raven PadWell: Plan: MPU R-142Wellbore: MPU R-142Plan: MPU R-142 wp06Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name4113.26 4049.61 5650.00 9-5/8 9 5/8" x 12 1/4"4178.31 4114.66 16129.23 4-1/2 4 1/2" x 8 1/2"
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: __________________________ POOL: ____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
SCHRADER BLUFF OIL
224-045
MPU R-142
MILNE POINT
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT R-142Initial Class/TypeDEV / PENDGeoArea890Unit11328On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2240450MILNE POINT, SCHRADER BLFF OIL - 525140NA1Permit fee attachedYesADL025509, ADL388235, and ADL3550182Lease number appropriateYes3Unique well name and numberYesMILNE POINT, SCHRADER BLFF OIL - 525140 - governed by 477, 477.0054Well located in a defined poolYes5Well located proper distance from drilling unit boundaryNA6Well located proper distance from other wellsYes7Sufficient acreage available in drilling unitYes8If deviated, is wellbore plat includedYes9Operator only affected partyYes10Operator has appropriate bond in forceYes11Permit can be issued without conservation orderYes12Permit can be issued without administrative approvalYes13Can permit be approved before 15-day waitNA14Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15All wells within 1/4 mile area of review identified (For service well only)NA16Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes20" 129.5# X-52 driven to 135'18Conductor string providedYes9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40# to SB reservoir19Surface casing protects all known USDWsYes9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20CMT vol adequate to circulate on conductor & surf csgYes9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21CMT vol adequate to tie-in long string to surf csgYes9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22CMT will cover all known productive horizonsYes9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir23Casing designs adequate for C, T, B & permafrostYesParker 273 rig has adequate tankage and good trucking support24Adequate tankage or reserve pitNAThis is a grassroots well.25If a re-drill, has a 10-403 for abandonment been approvedYesHalliburton collision scan shows no close approaches with HSE risk.26Adequate wellbore separation proposedYes16" Diverter27If diverter required, does it meet regulationsYesAll fluids overbalanced to expected pore pressure.28Drilling fluid program schematic & equip list adequateYes1 annular, 3 ram stack tested to 3000 psi.29BOPEs, do they meet regulationYes13-5/8" , 5000 psi stack tested to 3000 psi.30BOPE press rating appropriate; test to (put psig in comments)YesParker 273 has 3-1/8" manual gate valves, 1 x 3-1/8" manual choke and 1x3-1/8" remote hydraulic choke.31Choke manifold complies w/API RP-53 (May 84)Yes32Work will occur without operation shutdownNo33Is presence of H2S gas probableNA34Mechanical condition of wells within AOR verified (For service well only)YesH2S not anticipated; however, rig will have H2S sensors and alarms.35Permit can be issued w/o hydrogen sulfide measuresYesAnticipating normally pressured reservoir. MPD to mitigate any abnormal pressures.36Data presented on potential overpressure zonesNA37Seismic analysis of shallow gas zonesNA38Seabed condition survey (if off-shore)NA39Contact name/phone for weekly progress reports [exploratory only]ApprADDDate10-May-24ApprMGRDate09-May-24ApprADDDate09-May-24AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 5/10/2024
