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MEMORANDUM State of Alaska
Alaska Oil and Gas Conservation Commission
DATE:Monday, March 17, 2025
SUBJECT:Mechanical Integrity Tests
TO:
FROM:Austin McLeod
P.I. Supervisor
Petroleum Inspector
NON-CONFIDENTIAL
Hilcorp Alaska, LLC
I-24
MILNE PT UNIT I-24
Jim Regg
InspectorSrc:
Reviewed By:
P.I. Suprv
Comm ________
JBR 03/17/2025
I-24
50-029-23778-00-00
224-001-0
N
SPT
3920
2240010 3650
245 3860 3838 3830
60 94 93 92
OTHER P
Austin McLeod
1/25/2025
MITT to 3650. Jet Pump Conversion. Sundry 324-636.
30 MinPretestInitial15 Min
Well Name
Type Test
Notes:
Interval P/F
Well
Permit Number:
Type Inj TVD
PTD Test psi
API Well Number Inspector Name:MILNE PT UNIT I-24
Inspection Date:
Tubing
OA
Packer Depth
60 365 364 362IA
45 Min 60 Min
Rel Insp Num:
Insp Num:mitSAM250126131829
BBL Pumped:1.3 BBL Returned:1.3
Monday, March 17, 2025 Page 1 of 1
9
9
9
9
9 9
999
9 9
À 9
9
9
9
James B. Regg Digitally signed by James B. Regg
Date: 2025.03.17 10:38:09 -08'00'
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: Convert to Jet Pump
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):
17,129'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
4,199'
SLZXP LTP and N/A 6,312 MD/ 4,005 TVD and N/A
Todd Sidoti
todd.sidoti@hilcorp.com
777-8443
8,472'
Perforation Depth MD (ft):
6,324'
See Schematic
2,160'
4-1/2"
See Schematic
17,129'8,657'
3-1/2"
4,036'5-1/2"
131' 20"
9-5/8"
9-5/8'
2,260'
7"6,293'
4,216'
MD
N/A
7,240psi
6,870psi
5,750psi
1,933'
4,007'
4,006'
2,293'
6,509'
Length Size
Proposed Pools:
165' 165'
9.3 / L-80 / EUE 8rd
TVD Burst
4,264'
9,190psi
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL025515, ADL025517& ADL025906
224-001
3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23778-00-00
Hilcorp Alaska LLC
477.07
AOGCC USE ONLY
9,020psi
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft):
11/25/2024
Subsequent Form Required:
Suspension Expiration Date:
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
MILNE PT UNIT I-24
MILNE POINT SCHRADER BLUFF OIL N/A
4,199' 17,128' 4,199' 1,052 N/A
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 1:12 pm, Nov 06, 2024
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2024.11.06 12:56:56 -
09'00'
Taylor Wellman
(2143)
X
Witnessed BOP Test to 2500 psi.
Witnessed MITT to 3650 psi prior to injection.
X
DSR-11/6/24SFD 11/6/2024
Annular test to 2500 psi.
10-404
MGR27NOV24
* Approved variance to 20 AAC 25.265 (c)(1) SSV on IA will not be located in the vertical run of the tree.
* IA trip pressures to initiate closure on tubing within 2 minutes and visa versa.
* Compliance to CO 808 required.
*&:
Jessie L. Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2024.11.29 09:55:47 -09'00'11/29/24
RBDMS JSB 112924
RWO Convert to JP
Well: MPI-24
Date: 11/5/2024
Well Name: MPU I-24 API Number: 50-029-23778-00-00
Current Status: ESP producer Rig: ASR 1
Estimated Start Date: 11/25/2024 Estimated Duration: 5 days
Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: TBD
Regulatory Contact: Tom Fouts Permit to Drill Number: 224-001
First Call Engineer: Todd Sidoti 907-632-4113
Second Call Engineer: Taylor Wellman 907-947-9533
Current Bottom Hole Pressure: 1370 psi @ 3175’ TVD Gauge data 3/30/2024 (8.30 PPGE)
Max. Anticipated Surface Pressure: 1052 psi Gas Column Gradient (0.1 psi/ft)
Min ID: 2.750” @ 4135’ 3.5” XN Nipple
Brief Well Summary and Objective
I-24 was drilled and completed in March 2024 on Doyon 14. Losses were encountered during the 9-5/8” surface
casing cement job and a remedial cement job was performed. The OA pressure has been limited to a 12.44 PPGE
(MOASP is set at 900 psi). The well has struggled as an ESP producer due to ESP pump size and casing geometry.
The objective of this program is to convert the well to a permanent forward-circulating jet pump producer due to
the constrained pressure limitation of the OA.
Notes on Well Condition
x New 7” installed during initial completion 3/2024.
x 9-5/8” x 7” annular pressure limited to 900 psi.
x SSV Pilot Settings:
o Power fluid SSV high pressure trip will not exceed 3650 psi.
o Power fluid SSV low pressure trip will be set to 50% of header pressure.
o Production SSV high pressure trip will not exceed 650 psi
The IA is set to shut down before it comes close to the 12.44 PPGE pressure restriction
placed on the OA (Sundry 324-172).
o Production SSV low pressure trip will not be below 75 psi.
Pre-Rig Procedure (Non-Sundried steps)
Slickline & Well Support
1. Clear and level pad area in front of well. Spot rig mats and containment.
2. MIRU SL.
3. Pull DPSOV from upper station and dummy off same.
4. Pull dummy from lower station.
5. RDMO SL.
6. RU Little Red Services. RU reverse out skid and 500 bbl returns tank.
7. Circulate at least one wellbore volume with produced water down tubing, taking returns up casing to
500 bbl returns tank.
8. RD Little Red Services and reverse out skid.
9. Set CTS BPV. ND Tree. NU BOPE.
10. NU BOPE house. Spot mud boat.
Procedure (Sundried steps)
RWO
11. MIRU ASR and ancillary equipment.
12. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and
casing. If needed, kill well w/ produced water prior to setting CTS.
13. Test BOPE to 250 psi Low/ 2,500 psi High, 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
9-5/8” x 7” annular pressure limited to 900 psi.
RWO Convert to JP
Well: MPI-24
Date: 11/5/2024
b. Notify AOGCC 24 hours in advance of BOP test.
c. Confirm test pressures per the Sundry Conditions of approval.
d. Test VBR rams and annular on 3-1/2” and 4-1/2” test joints.
e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test.
14. Pull CTS plug. Bleed any pressure off casing to the returns tank. Pull CTS, lubricate if pressure
expected. Kill well with produced water as needed.
15. MU landing joint or spear and BOLDS.
16. POOH with 3-1/2” tubing.
a. PU weight was 77k SO was 65K
17. Rig up ESP spooler.
18. POOH and lay down the 3-1/2’’ ESP completion.
a. Wash and inspect all joints for re-use.
b. Keep gas lift mandrels and nipple for reuse.
c. Make sure to account for all clamps below:
i. 74 Canon Clamps
ii. 3 Protectorlizers
iii. 1 Splice Clamp
19. PU new 4-1/2’’ Jet Pump Completion and RIH.
Nom.
Size ~Length Item Lb/ft Material
4.5 10’ WLEG Pup Joint 12.6 L-80
4.5 10' Pup Joint 12.6 L-80
4.5 XN Nip with RHC profile 12.6 L-80
4.5 10' Pup Joint 12.6 L-80
4.5 10'Pup Joint 12.6 L-80
4.5 7” X 4-1/2” Packer Set ~5800' MD 12.6 L-80
4.5 10' Pup Joint 12.6 L-80
4.5 40’ Joint 12.6 L-80
4.5 10' Pup Joint 12.6 L-80
4.5 BHPG @ ~5750’ MD 12.6 L-80
4.5 10' Pup Joint 12.6 L-80
4.5 10' Pup Joint 12.6 L-80
4.5 Sliding Sleeve @ 5725’ MD 12.6 L-80
4.5 10' Pup Joint 12.6 L-80
4.5 Joints 12.6 L-80
4.5 Space out PUPS 12.6 L-80
4.5 1 Joint 12.6 L-80
4.5 PUP 12.6 L-80
4.5 Tubing Hanger 12.6 L-80
20. Space out and land the hanger.
a. Note PU and SO weights on tally.
21. RILDS and lay down landing joint.
22. Circulate and spot a 100 bbl pill of corrosion inhibited water prior to setting packer.
23. Drop ball and rod and complete loading tubing with FP and hydraulically set the packer as per Vendor
setting procedure.
24. Perform MIT-T to 3650 psi for 30 minutes charted.
lubricate if pressure
expected. Kill well with produced water as needed.
RWO Convert to JP
Well: MPI-24
Date: 11/5/2024
25. Perform MIT-IA to 3650 psi for 30 minutes charted.
26. Set CTS.
27. RDMO ASR.
Post-Rig Procedure:
1. RD mud boat. RD BOPE house. Move to next well location.
2. RU crane. ND BOPE.
3. NU 4-1/16” tree and tubing head adapter.
4. Test both tree and tubing hanger void to 500psi low/5,000psi high. Pull CTS.
5. MIRU SL.
6. RIH and pull ball & rod and RHC plug.
7. Open SS and install JP.
8. RD crane. Move 500 bbl returns tank and rig mats to next well location.
9. Turn well over to production
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Schematic
3. BOP Schematic
_____________________________________________________________________________________
Revised By: TDF 9/23/2024
SCHEMATIC
Milne Point Unit
Well: MPU I-24
Last Completed: 3/28/2024
PTD: 224-001
TD =17,129’(MD) / TD =4,199’(TVD)
4&5
20”
Orig. KB Elev.: 68.06’ / GL Elev.: 33.7’
7”
6&7
8
14
9-5/8”
10&11
1
2
3
5-1/2” XO
4-1/2”
@8,472’
See
Screen/
Solid
Liner
Detail
Perforations:
5,190’ –
5,195’
Remedial
Cement
PBTD = 17,128’(MD) / PBTD = 4,199’(TVD)
9-5/8” ‘ES’
Cementer
@ 2,277’
9
13
12
15
3-1/2”
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 165’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,293’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 2,293’ 6,509’ 0.0758
7” Tieback 26 / L-80 / H563 6.276 Surface 6,324’ 0.0459
5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.778 6,312’ 8,472’ 0.0222
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 8,472’ 17,129’ 0.0149
TUBING DETAIL
3-1/2" Tubing 9.3# / L-80 / EUE 8rd 3.958 Surface 4,264’ 0.0152
OPEN HOLE / CEMENT DETAIL
20” Driven
12-1/4"
Stg 1 Lead – 1063 sx / Tail – 440 sx
Stg 2 Lead – 691 sx / Tail 270 sx
Remedial – 243 sx Class G
8-1/2” Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 250’
90° Hole Angle = @ 6,500’
TREE & WELLHEAD
Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: 50-029-23778-00-00
Completion Date: 3/28/2024
JEWELRY DETAIL
No. MD Item ID
1 107’ GLM 3-1/2” x 1” with OV Installed 2.992”
2 4,076’ GLM 3-1/2” x 1” with DV Installed 2.992”
3 4,135’ XN Nipple 2.813” with 2.75” No Go 2.750“
4 4,188’ Pressure Discharge Sub: Vigilant Sensor
5 4,189’ Discharge Head
6 4,190’ Pump: Summit 538 SJ4200 90S 1:1 AR, HTEM
7 4,213’ Gas Separator
8 4,221’ Upper Tandem Seal 513 Series
9 4,230’ Lower Tandem Seal 513 Series
10 4,239’ Motor: Summit 562 KMS2, 300 HP / 3255 V / 57A
11 4,259’ Baker Zenith Motor Gauge w/ Centralizer
12 6,312’ SLZXP LTP (11.29’ Tieback Sleeve) 6.170”
13 6,313’ Locator Sub and Tie Back Bullet Seals, Mule Shoe 6.140”
14 8,472’ 5-1/2” x 4-1/2” XO 3.910”
15 17,128’ Shoe
5-1/2” x 4-1/2” SCREENS LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2” 6510’ 4007’ 8472’ 4036’
4-1/2” 8474’ 4036’ 17091’ 4197’
_____________________________________________________________________________________
Revised By: TDF 11/5/2024
PROPOSED
Milne Point Unit
Well: MPU I-24
Last Completed: 3/28/2024
PTD: 224-001
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20"Conductor 129.5 / X52 / Weld N/A Surface 165’N/A
9-5/8"Surface 47 / L-80 / TXP 8.681 Surface 2,293’0.0732
9-5/8”Surface 40 / L-80 / TXP 8.835 2,293’6,509’0.0758
7”Tieback 26 / L-80 / H563 6.276 Surface 6,324’0.0459
5-1/2”Liner 100ђ Screens 20 / L-80 / EZGO HT 4.778 6,312’8,472’0.0222
4-1/2”Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 8,472’17,129’0.0149
TUBING DETAIL
4-1/2"Tubing 12.6# / L-80 / EUE 3.958 Surface ~6,300’0.0152
OPEN HOLE / CEMENT DETAIL
20”Driven
12-1/4"
Stg 1 Lead – 1063 sx / Tail – 440 sx
Stg 2 Lead – 691 sx / Tail 270 sx
Remedial – 243 sx Class G
8-1/2”Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 250’
90° Hole Angle = @ 6,500’
TREE & WELLHEAD
Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: 50-029-23778-00-00
Completion Date: 3/28/2024
JEWELRY DETAIL
No.MD Item ID
1 ±X,XXX Sliding Sleeve
2 ±X,XXX Bottom Hole Pressure Gauge
3 ±5,800’7” x 4-1/2” Packer
4 ±X,XXX XN-Nipple w/ RHC Profile
5 ±X,XXX WLEG – Btm @ ±X,XXX’
6 6,312’SLZXP LTP (11.29’ Tieback Sleeve)6.170”
7 6,313’Locator Sub and Tie Back Bullet Seals, Mule Shoe 6.140”
8 8,472’5-1/2” x 4-1/2” XO 3.910”
9 17,128’Shoe
5-1/2” x 4-1/2” SCREENS LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2”6510’4007’8472’4036’
4-1/2”8474’4036’17091’4197’
Milne Point
ASR Rig 1 BOPE
2024
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
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 04/12/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL:
WELL: MPU I-24
PTD: 224-001
API: 50-029-23778-00-00
FINAL LWD FORMATION EVALUATION + GEOSTEERING (03/01/2024 to 03/24/2024)
x ABG, BaseStar GR, DGR, EWR-4, ADR, Horizontal Presentation (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
x Final Geosteering and EOW Report/Plots
SFTP Transfer – Main Folders:
FINAL LWD Subfolders:
FINAL Geosteering Subfolders:g
Please include current contact information if different from above.
224-001
T38703
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.04.16 11:27:18 -08'00'
Stg 2 L - 691 sx / T - 270 sx, 243 sx G
By Grace Christianson at 10:56 am, Apr 16, 2024
Completed
3/28/2024
JSB
RBDMS JSB 042924
GMGR19DEC2025DSR-5/6/24
Drilling Manager
04/16/24
Monty M
Myers
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2024.04.16 10:41:24 -
08'00'
Taylor Wellman
(2143)
_____________________________________________________________________________________
Edited By: JNL 4/2/2024
SCHEMATIC
Milne Point Unit
Well: MPU I-24
Last Completed: 3/28/2024
PTD: 224-001
TD =17,129’(MD) / TD =4,199’(TVD)
4&5
20”
Orig. KB Elev.: 68.06’ / GL Elev.: 33.7’
7”
6&7
8
14
9-5/8”
10&11
1
2
3
5-1/2”XO
4-1/2”
@8,472’
See
Screen/
Solid
Liner
Detail
Perforations:
5,190’ –
5,195’
Remedial
Cement
PBTD = 17,128’(MD) / PBTD = 4,199’(TVD)
9-5/8” ‘ES’
Cementer
@ 2,277’
9
13
12
15
3-1/2”
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 165’ N/A
9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,293’ 0.0732
9-5/8” Surface 40 / L-80 / TXP 8.835 2,293’ 6,509’ 0.0758
7” Tieback 26 / L-80 / H563 6.276 Surface 6,324’ 0.0459
5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.778 6,312’ 8,472’ 0.0222
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 8,472’ 17,129’ 0.0149
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / TXP 3.958 Surface 4,264’ 0.0152
OPEN HOLE / CEMENT DETAIL
20” Driven
12-1/4"
Stg 1 Lead – 1063 sx / Tail – 440 sx
Stg 2 Lead – 691 sx / Tail 270 sx
Remedial – 243 sx Class G
8-1/2” Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 250’
90° Hole Angle = @ 6,500’
TREE & WELLHEAD
Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: 50-029-23778-00-00
Completion Date: 3/28/2024
JEWELRY DETAIL
No. MD Item ID
1 107’ GLM 3-1/2” x 1” with OV Installed 2.992”
2 4,076’ GLM 3-1/2” x 1” with DV Installed 2.992”
3 4,135’ XN Nipple 2.813” with 2.75” No Go 2.750“
4 4,189’ Discharge Head
5 4,190’ Pump: Summit 538 SJ4200 90S 1:1 AR, HTEM
7 4,213’ Gas Separator
8 4,221’ Upper Tandem Seal 513 Series
9 4,230’ Lower Tandem Seal 513 Series
10 4,239’ Motor: Summit 562 KMS2, 300 HP / 3255 V / 57A
11 4,259’ Baker Zenith Motor Gauge w/ Centralizer
12 6,312’ SLZXP LTP (11.29’ Tieback Sleeve) 6.170”
13 6,313’ Locator Sub and Tie Back Bullet Seals, Mule Shoe 6.140”
14 8,472’ 5-1/2” x 4-1/2” XO 3.910”
15 17,128’ Shoe
5-1/2” x 4-1/2”SCREENS LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2” 6510’ 4007’ 8472’ 4036’
4-1/2” 8474’ 4036’ 17091’ 4197’
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 4/4/2024
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20240404
Well API #PTD #Log Date Log Company Log Type AOGCC Eset#
BCU 19RD 50133205790100 219188 2/23/2024 YELLOW JACKET GPT-PERF
BRU 241-23 50283201910000 223061 11/25/2023 AK E-LINE Perf
HV B-13 50231200320000 207151 3/11/2024 YELLOW JACKET GPT
KALOTSA 6 50133206850000 219114 3/2/2024 YELLOW JACKET PERF
KU 13-06A 50133207160000 223112 3/13/2024 YELLOW JACKET GPT-PERF
KU 21-06RD 50133100900100 201097 3/19/2024 YELLOW JACKET GPT-PERF
END MPI 2-62 50029216480000 186158 2/14/2024 YELLOW JACKET PERF
MPU G-18 50029231940000 204020 3/21/2024 READ Caliper Survey
MPU G-18 50029231940000 204020 3/9/2024 AK E-LINE HoistCutter
MPU I-24 50029237780000 224001 3/11/2024 AK E-LINE CBL
NCIU A-18 50883201890000 223033 12/20/2023 AK E-LINE Perf
NCIU A-18 50883201890000 223033 12/18/2024 AK E-LINE GPT/Plug/Perf
PAXTON 3 50133205880000 209168 3/6/2024 YELLOW JACKET GPT
PAXTON 3 50133205880000 209168 3/8/2024 YELLOW JACKET PERF
PAXTON 3 50133205880000 209168 3/12/2024 AK E-LINE PPROF
PAXTON 7 50133206430000 214130 2/26/2024 YELLOW JACKET PERF
PBU 09-52 50029236180000 218168 3/24/2024 HALLIBURTON PPROF
SD-06 50133205820000 208160 2/20/2024 YELLOW JACKET PERF
SRU 222-33 50133207150000 223100 12/19/2023 AK E-LINE Perf
Please include current contact information if different from above
T38683
T38684
T38685
T38686
T38689
T38687
T38690
T38691
T38691T38692
T38963
T38963
T38694
T38694
T38694
T38695
T38696
T38697
T38698
MPU I-24 50029237780000 224001 3/11/2024 AK E-LINE CBL
Meredith Guhl Digitally signed by Meredith Guhl
Date: 2024.04.09 13:48:29 -08'00'
Drilling Manager
03/19/24
Monty M
Myers
By Grace Christianson at 8:01 am, Mar 20, 2024
SFD 3/20/2024MGR20MAR24 DSR-3/21/24
* BOPE test to 3000 psi. Annular to 2500 psi.
* Assure OA pressure does not exceed 12.44 PPGE at perforations in 9-5/8" when pressure
testing OA and during all operations over the life of this well.
10-407
JLC 3/22/2024
Milne Point Unit
(MPU) I-24
Drilling Program
Version 2
3/19/2024
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 ................................................................................................ 8
8.0 Mandatory Regulatory Compliance / Notifications .................................................................. 9
9.0 R/U and Preparatory Work ..................................................................................................... 11
10.0 N/U 13-5/8 5M Diverter System ............................................................................................. 12
11.0 Drill 12-1/4 Hole Section ........................................................................................................ 14
12.0 Run 9-5/8 Surface Casing ...................................................................................................... 17
13.0 Cement 9-5/8 Surface Casing ................................................................................................. 23
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 28
15.0 Drill 8-1/2 Hole Section .......................................................................................................... 29
16.0 Run 5-1/2 x 4-1/2 Screened Liner ........................................................................................ 34
17.0 Run 7 Tieback ........................................................................................................................ 39
18.0 Run Upper Completion ESP ................................................................................................. 42
19.0 Doyon 14 Diverter Schematic .................................................................................................. 45
20.0 Doyon 14 BOP Schematic ........................................................................................................ 46
21.0 Wellhead Schematic ................................................................................................................. 47
22.0 Days Vs Depth .......................................................................................................................... 48
23.0 Formation Tops & Information............................................................................................... 49
24.0 Anticipated Drilling Hazards .................................................................................................. 51
25.0 Doyon 14 Rig Layout ............................................................................................................... 54
26.0 FIT Procedure .......................................................................................................................... 55
27.0 Doyon 14 Rig Choke Manifold Schematic ............................................................................... 56
28.0 Casing Design ........................................................................................................................... 57
29.0 8-1/2 Hole Section MASP ....................................................................................................... 58
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 59
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 60
Page 2
Milne Point Unit
I-24 SB Producer
PTD Application
1.0 Well Summary
Well MPU I-24
Pad Milne Point I Pad
Planned Completion Type ESP
Target Reservoir(s) Schrader Bluff OBa Sand
Planned Well TD, MD / TVD 18,911 MD / 4,277 TVD
PBTD, MD / TVD 18,911 MD / 4,277 TVD
Surface Location (Governmental) 2337' FSL, 1449' FWL, Sec 33, T13N, R10E, UM, AK
Surface Location (NAD 27) X= 551540, Y= 6009451
Top of Productive Horizon
(Governmental)1292' FNL, 2024' FEL, Sec 32, T13N, R10E, UM, AK
TPH Location (NAD 27) X= 548051, Y= 6011079
BHL (Governmental) 578' FSL, 95' FEL, Sec 17, T13N, R10E, UM, AK
BHL (NAD 27) X= 549862, Y= 6023520
AFE Drilling Days 23
AFE Completion Days 3
Maximum Anticipated Pressure
(Surface) 1362 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1762 psig
Work String 5 19.5# S-135 NC 50
Doyon 14 KB Elevation above MSL: 33.7 ft + 33.2 ft = 66.9 ft
GL Elevation above MSL: 33.2 ft
BOP Equipment 13-5/8 x 5M Annular, (3) ea 13-5/8 x 5M Rams
Page 3
Milne Point Unit
I-24 SB Producer
PTD Application
2.0 Management of Change Information
Page 4
Milne Point Unit
I-24 SB Producer
PTD Application
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20 19.25- - - X-52 Weld
12-1/49-5/8 8.8358.67910.62540 L-80 TXP 5,750 3,090 916
9-5/8 8.6818.52510.62547 L-80 TXP 6,870 4,750 1,086
Tieback 7 6.276 6.151 7.656 26 L-80 TXP 7,240 5,410 604
8-1/25-1/2
Screens 4.780 4.653 6.000 20 L-80
EZGO HT 9,189 8,830 466
8-1/24-1/2
Screens 3.920 3.795 4.714 13.5 L-80 Hydril 625 9,020 8,540 279
Tubing 3-1/2 2.9922.8674.5009.3 L-80
EUE 8RD 9289 7399 163
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
54.2763.25 6.62519.5 S-135 DS50 36,100 43,100 560klb
54.2763.25 6.62519.5 S-135 NC50 30,730 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Milne Point Unit
I-24 SB Producer
PTD Application
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
Report covers operations from 6am to 6am
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.
Ensure time entry adds up to 24 hours total.
Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
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
Health and Safety: Notify EHS field coordinator.
Environmental: Drilling Environmental Coordinator
Notify Drilling Manager & Drilling Engineer on all incidents
Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
Send final As-Run Casing tally to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Completion Engineer Brian Glasheen 907.564.5277 Brian.glasheen@hilcorp.com
Geologist Katie Cunha 907.564.4786 Katharine.cunha@hilcorp.com
Reservoir Engineer Almas Aitkulov 907.564.4250 aaitkulov@hilcorp.com
Drilling Env. Coordinator Adrian Kersten 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
_____________________________________________________________________________________
Edited By: JNL 3/19/2024
PROPOSED SCHEMATIC
Milne Point Unit
Well: MPU I-24
Last Completed: TBD
PTD: 224-001
TD =18,911(MD) / TD =4,277(TVD)
4&5
20
Orig. KB Elev.: 68.06 / GL Elev.: 33.2
7
6&7
8
14
9-5/8
10&11
1
2
3
5-1/2 XO
4-1/2
See
Screen/
Solid
Liner
Detail
Perforations:
5,190
5,195
Remedial
Cement
PBTD =18,911(MD) / PBTD =4,277(TVD)
9-5/8 ES
Cementer
@ 2,277
9
13
12
15
3-1/2
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 169 N/A
9-5/8" Surface 47 / L-80 / TXP 8.681 Surface 2,293 0.0732
9-5/8 Surface 40 / L-80 / TXP 8.835 2,293 6,509 0.0758
7 Tieback 26 / L-80 / TXP 6.276 Surface ~6,359 0.0383
5-1/2 Liner 100 Screens 20 / L-80 / EZGO HT 4.780 ~6,359 9,411 0.0222
4-1/2 Liner 100 Screens 13.5 / L-80 / Hyd 625 3.920 9,411 18,911 0.0149
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / TXP 3.958 Surface 4,275 0.0152
OPEN HOLE / CEMENT DETAIL
20 Driven
12-1/4"
Stg 1 Lead 1063 sx / Tail 440 sx
Stg 2 Lead 691 sx / Tail 270 sx
Remedial 243 sx Class G
8-1/2 Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 250
90° Hole Angle = @ 6,500
TREE & WELLHEAD
Tree Cameron 3-1/8" 5M w/ 3-1/8 5M Cameron Wing
Wellhead FMC 11 5K x sliplock bottom w/ (2) 2-1/16 5K outs
GENERAL WELL INFO
API: 50-029-23778-00-00
Completion Date: TBD
JEWELRY DETAIL
No. MD Item ID
1 110 GLM
2 2,165 GLM
3 4,175 3-1/2 X Nipple
4 4,215 Discharge Head
5 4,215 Pump
6 4,235 Adapter
7 4,235 Gas Separator
8 4,240 Upper Tandem Seal
9 4,245 Lower Tandem Seal
10 4,265 Motor
11 4,275 High Temp Motor Gauge w/ Centralizer
12 6,359 SLZXP LTP
13 6,359 SLZXP Hanger
14 9,411 5-1/2 x 4-1/2 XO
15 18,911 Shoe
5-1/2 x 4-1/2SCREENS LINER DETAIL
Size Top
(MD)
Top
(TVD)
Btm
(MD)
Btm
(TVD)
5-1/2
4-1/2
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7.0 Drilling / Completion Summary
MPU I-24 is a grassroots producer planned to be drilled in the Schrader Bluff OBa sand. I-24 is part of a
multi well program targeting the Schrader Bluff sand on I-pad
The directional plan is 12-1/4 surface hole with 9-5/8 surface casing set in the top of the Schrader Bluff
OBa sand. An 8-1/2 lateral section will be drilled and completed with a 5-1/2 x 4-1/2 liner. The well will
be produced with a jet pump.
Doyon 14 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately February 10, 2024, pending rig schedule.
Surface casing will be run to 6,600 MD / 4,012 TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to the Milne Point B pad G&I facility.
General sequence of operations:
1. MIRU Doyon 14 to well site
2. N/U & Test 21-1/4 Diverter and 16 diverter line
3. Drill 12-1/4 hole to TD of surface hole section. Run and cement 9-5/8 surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8 5M BOP & Test
5. Drill 8-1/2 lateral to well TD
6. Run 5-1/2 x 4-1/2 production liner
7. Run 7 tieback
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
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8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that all drilling and completion operations comply with all applicable AOGCC regulations.
Operations stated in this PTD application may be altered based on sound engineering judgement as
wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from
the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation,
do not hesitate to contact the Anchorage Drilling Team.
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.
BOPs shall be tested at (2) week intervals during the drilling and completion of MPU I-24. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment
will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
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.
All AOGCC regulations within 20 AAC 25.033 Primary well control for drilling: drilling fluid
program and drilling fluid system.
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
Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
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:
None
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Summary of BOP Equipment & Notifications
Hole Section Equipment Test Pressure (psi)
12 1/421-1/4 2M Diverter w/ 16 Diverter Line Function Test Only
8-1/2
13-5/8 x 5M Hydril GK Annular BOP
13-5/8 x 5M Hydril MPL Double Gate
o Blind ram in btm cavity
Mud cross w/ 3 x 5M side outlets
13-5/8 x 5M Hydril MPL Single ram
3-1/8 x 5M Choke Line
3-1/8 x 5M Kill line
3-1/8 x 5M Choke manifold
Standpipe, floor valves, etc
Initial Test: 250/3000
Subsequent Tests:
250/3000
Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air
pump, and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
24 hours notice prior to spud.
24 hours notice prior to testing BOPs.
24 hours notice prior to casing running & cement operations.
Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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9.0 R/U and Preparatory Work
9.1 I-24 will utilize a newly set 20 conductor on I-pad. Ensure to review attached surface plat and
make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4 nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4 surface hole section. Ensure mud temperatures are cool (<80 F).
9.10 Ensure 6 liners in mud pumps.
Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @
95% volumetric efficiency.
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10.0 N/U 13-5/8 5M Diverter System
10.1 N/U 21-1/4 Hydril MSP 2M Diverter System (Diverter Schematic attached to program).
N/U 16-3/4 3M x 21-1/4 2M DSA on 16-3/4 3M wellhead.
N/U 21-1/4 diverter T.
Knife gate, 16 diverter line.
Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
Diverter line must be 75 ft from nearest ignition source
Place drip berm at the end of diverter line.
10.2 Notify AOGCC. Function test diverter.
Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
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:
A prohibition on vehicle parking
A prohibition on ignition sources or running equipment
A prohibition on staged equipment or materials
Restriction of traffic to essential foot or vehicle traffic only.
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10.4 Rig & Diverter Orientation:
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:
Ensure BHA components have been inspected previously.
Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
Ensure TF offset is measured accurately and entered correctly into the MWD software.
Use GWD until MWD surveys are clean and then swap to MWD.
Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
Drill string will be 5 19.5# S-135.
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.
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 OBa sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
Monitor the area around the conductor for any signs of broaching. If broaching is observed,
stop drilling (or circulating) immediately notify Drilling Engineer.
Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
Hold a safety meeting with rig crews to discuss:
Conductor broaching ops and mitigation procedures.
Well control procedures and rig evacuation
Flow rates, hole cleaning, mud cooling, etc.
Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
Keep mud as cool as possible to keep from washing out permafrost.
Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
Slow in/out of slips and while tripping to keep swab and surge pressures low
Ensure shakers are functioning properly. Check for holes in screens on connections.
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.
Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates).
Perform gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled.
Be prepared for gas hydrates. In MPU they have been encountered typically around 2,100-
2,400 TVD (just below permafrost). Be prepared for hydrates:
Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
Monitor returns for hydrates, checking pressurized & non-pressurized scales
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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.
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.
Take MWD and GWD surveys every stand until magnetic interference cleans up. After
MWD surveys show clean magnetics, only take MWD surveys.
Surface Hole AC:
There are no wells with a clearance factor of <1.0
11.4 12-1/4 hole mud program summary:
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
PVT System: MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the drillers console, Co Man office, Toolpusher office, and mud
loggers office.
Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but
reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared
to increase the YP if hole cleaning becomes an issue.
Fluid Loss: DEXTRID and/or PAC L 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.
Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to
reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of
the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 9.0 range with
caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not
jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the
system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value
they have targeted).
System Type:8.8 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud
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Properties:
Section Density Viscosity Plastic
Viscosity Yield Point API FL pH
Temp
Surface 8.8 9.8 75-175 20 - 40 25-45 <10 8.5 9.0 70 F
System Formulation: Gel + FW spud mud
Product- Surface hole Size Pkg ppb or (% liquids)
M-I Gel 50 lb sx 25
Soda Ash 50 lb sx 0.25
PolyPac Supreme UL 50 lb sx 0.08
Caustic Soda 50 lb sx 0.1
SCREENCLEEN 55 gal dm 0.5
11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity.
11.6 RIH to bottom, proceed to BROOH to HWDP
Pump at full drill rate (400-600 gpm), and maximize rotation.
Pull slowly, 5 10 ft / minute, adjust as dictated by hole conditions
Monitor well for any signs of packing off or losses.
Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
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12.0 Run 9-5/8 Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U 9-5/8 casing running equipment (CRT & Tongs)
Ensure 9-5/8 TXP x NC50 XO on rig floor and M/U to FOSV.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
R/U of CRT if hole conditions require.
R/U a fill up tool to fill casing while running if the CRT is not used.
Ensure all casing has been drifted to 8.5 on the location prior to running.
Note that 47# drift is 8.525
Be sure to count the total # of joints on the location before running.
Keep hole covered while R/U casing tools.
Record ODs, IDs, lengths, S/Ns of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking 120 shoe track assembly consisting of:
9-5/8 Float Shoe
1 joint 9-5/8 TXP, 2 Centralizers 10 from each end w/ stop rings
1 joint 9-5/8 TXP, 1 Centralizer mid joint w/ stop ring
9-5/8 Float Collar w/ Stage Cementer Bypass Baffle Top Hat
1 joint 9-5/8 TXP, 1 Centralizer mid joint with stop ring
9-5/8 HES Baffle Adaptor
Ensure bypass baffle is correctly installed on top of float collar.
Ensure proper operation of float equipment while picking up.
Ensure to record S/Ns of all float equipment and stage tool components.
This end up.
Bypass Baffle
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12.5 Float equipment and Stage tool equipment drawings:
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12.6 Continue running 9-5/8 surface casing
Fill casing while running using fill up line on rig floor.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
Centralization:
1 centralizer every joint to ~ 1000 MD from shoe
1 centralizer every 2 joints to ~2,000 above shoe (Top of Lowest Ugnu)
Verify depth of lowest Ugnu water sand for isolation with Geologist
Utilize a collar clamp until weight is sufficient to keep slips set properly.
Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100 TVD below
the permafrost.
Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
Do not place tongs on ES cementer, this can cause damaged to the tool.
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
9-5/818,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/821,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
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12.8 Continue running 9-5/8 surface casing
Centralizers: 1 centralizer every 3rd joint to 200 from surface
Fill casing while running using fill up line on rig floor.
Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 Ensure the permafrost is covered with 9-5/8 47# from BPRF to Surface
Ensure drifted to 8.525
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12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.11 Slow in and out of slips.
12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10 from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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13.0 Cement 9-5/8 Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
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
Review test reports and ensure pump times are acceptable.
Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
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Cement Slurry Design (1st Stage Cement Job):
13.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets sticky, cease pipe reciprocation and continue
with the cement job.
13.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
13.12 Displacement calculation:
See calculation in step 13.8
80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the ES
cementer is tuned spacer to minimize the risk of flash setting cement
13.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up
option to open the stage tool.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.18 Prepare for the 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.26 Displacement calculation:
2500 x 0.0732 bpf = 183.0 bbls mud
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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13.27 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.
13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.29 Land closing plug on stage collar and pressure up to 1,000 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips.
13.30 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:
Pre flush type, volume (bbls) & weight (ppg)
Cement slurry type, lead or tail, volume & weight
Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
Note if casing is reciprocated or rotated during the job
Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
Note if pre flush or cement returns at surface & volume
Note time cement in place
Note calculated top of cement
Add any comments which would describe the success or problems during the cement job
Send final As-Run casing tally & casing and cement report to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 ND Diverter, NU BOPE, & Test
14.1 ND the diverter T, knife gate, diverter line & NU 11 x 13-5/8 5M casing spool.
14.2 NU 13-5/8 x 5M BOP as follows:
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
Double gate ram should be dressed with 4-1/2 x 7 VBRs in top cavity,blind ram in
bottom cavity.
Single ram can be dressed with 2-7/8 x 5 VBRs
NU bell nipple, install flowline.
Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 RU MPD RCD and related equipment
14.4 Run 5 BOP test plug
14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
Test 4-1/2 x 7 rams with 4-1/2 and 7 test joints
Test 2-7/8 x 5 rams with the 4-1/2 and 5 test joints
Confirm test pressures with PTD
Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.6 RD BOP test equipment
14.7 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.8 Mix 8.9 ppg FloPro for production hole.
14.9 Set wearbushing in wellhead.
14.10 If needed, rack back as much 5 DP in derrick as possible to be used while drilling the hole
section.
14.11 Ensure 5 liners in mud pumps.
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15.0 Drill 8-1/2 Hole Section
15.1 MU 8-1/2 Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2 cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure
on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20 of new formation.
15.6 CBU and condition mud for FIT.
15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned.
15.8 POOH and LD cleanout BHA
15.9 PU 8-1/2 directional BHA.
Ensure BHA components have been inspected previously.
Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
Ensure TF offset is measured accurately and entered correctly into the MWD software.
Ensure MWD is RU and operational.
Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
Drill string will be 5 19.5# S-135 NC50.
Run a ported float in the production hole section.
Schrader Bluff Bit Jetting Guidelines
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
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15.10 8-1/2 hole section mud program summary:
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.
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.
Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
Dump and dilute as necessary to keep drilled solids to an absolute minimum.
MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the drillers 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:
Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K.
Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2 hole section to section TD per Geologist and Drilling Engineer.
Flow Rate: 350-550 GPM, target min. AVs 200 ft/min, 385 GPM
RPM: 120+
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.
Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
Monitor Torque and Drag with pumps on every 5 stands
Monitor ECD, pump pressure & hookload trends for hole cleaning indication
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.
Use ADR to stay in section. Reservoir plan is to stay in OBA sand.
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.
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Target ROP is as fast as we can clean the hole without having to backream connections
Schrader Bluff OBA Concretions: 4-6% Historically
MPD will be utilized to monitor pressure build up on connections.
8-1/2 Lateral A/C:
I-31 has a 0.485 clearance factor. I-31 is an OA jet pump producer and will remain
online. The close approach interval is in the production hole in a different sand.
J-08A has a 0.107 clearance factor. This well has been reservoir abandoned and
there is no HSE risk.
J-26L1 has a 0.370 clearance factor. This multi-lateral has been P&Ad with cement.
There is no HSE risk associated with a collision.
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
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.
Attempt to lowside in a fast drilling interval where the wellbore is headed up.
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.
Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being
removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + liner volume with viscosified brine.
Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) -
KCl: 7.1ppb for 2%
NaCl: 60.9ppg for 9.4ppg
Lotorq: 1.5%
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Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42ppb
Flo-Vis Plus: 1.25ppb
Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.15 Monitor the returned fluids carefully while displacing to brine. After 1 (or more if needed) BU,
Perform production screen test (PST). The brine has been properly conditioned when it will pass
the production screen test (x3 350 ml samples passing through the screen in the same amount
of time which will indicate no plugging of the screen). Reference PST Test Procedure
15.19 BROOH with the drilling assembly to the 9-5/8 casing shoe
Circulate at full drill rate (less if losses are seen, 350 GPM minimum).
Rotate at maximum RPM that can be sustained.
Pulling speed 5 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
When pulling across any OHST depths, turn pumps off and rotary off to minimize
disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct
hole section, check with ABI compared to as drilled surveys
15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 9-5/8 shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
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
If necessary, increase MW at shoe for any higher than expected pressure seen
Ensure fluid coming out of hole has passed a PST at the possum belly
15.23 POOH and LD BHA.
15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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16.0 Run 5-1/2 x 4-1/2 Screened Liner
NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and run them
slick.
16.1 Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2 screened liner, the following well control response procedure will be followed:
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 screened liner.
P/U & M/U the 5 safety joint (with 4-1/2 crossover installed on bottom, TIW valve in open
position on top, 4-1/2 handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 4-1/2 screened liner.
Slack off and with 5 DP across the BOP, shut in ram or annular on 5 DP. Close TIW.
Proceed with well kill operations.
16.2 R/U 4-1/2 liner running equipment.
Ensure 4-1/2 13.5# Hydril 625 x NC50 crossover is on rig floor and M/U to FOSV.
Ensure all casing has been drifted on the deck prior to running.
Be sure to count the total # of joints on the deck before running.
Keep hole covered while R/U casing tools.
Record ODs, IDs, lengths, S/Ns of all components w/ vendor & model info.
16.3 Run 4-1/2 screened production liner until XO point for 5-1/2 screens (planning 2,000 of 5-
1/2 on top of liner)
Use API Modified or Best O Life 2000 AGthread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens
Utilize a collar clamp until weight is sufficient to keep slips set properly.
Use lift nubbins and stabbing guides for the liner run.
Fill 4-½ liner with PST passed mud (to keep from plugging screens with solids)
Install screen joints as per the Running Order (From Completion Engineer post TD).
o Do not place tongs or slips on screen joints
o Screen placement ±40
o The screen connection is 4-1/2 13.5# Hydril 625
If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe. This is to mitigate difference sticking risk while running inner
string.
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 Torque
OD Minimum Optimum Maximum
5-1/2 6,997 ft-lbs 10,728 ft-lbs
4-1/2 13.5# L-80 Hydril 625 Torque
OD Minimum Optimum Maximum
4-1/2 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs
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16.6. Ensure to run enough liner to provide for approx 150 overlap inside 9-5/8 casing. Ensure
hanger/pkr will not be set in a 9-5/8 connection.
AOGCC regulations require a minimum 100 overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8 connection.
16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.8. M/U Baker SLZXP liner top packer to 4-1/2 liner.
16.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.10. RIH with liner no faster than 30 ft/min this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
Ensure 5 DP/HWDP has been drifted
There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
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16.18. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
16.20. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.23. PU pulling running tool free of the packer and displace at max rate to wash the liner top. Pump
sweeps as needed.
16.24. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
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17.0 Run 7 Tieback
17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder
to be used for tie-back space out calculation. Ensure rams have been tested to 250/3,000 psi with
7 test joint. RD testing equipment.
17.2 RU 7 casing handling equipment.
Ensure XO to DP made up to FOSV and ready on rig floor.
Rig up computer torque monitoring service.
String should stay full while running, RU fill up line and check as appropriate.
17.3 PU 7 tieback seal assembly and set in rotary table. Ensure 7 seal assembly has (4) 1 holes
above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8 x 7
annulus.
17.4 MU first joint of 7 to seal assy.
17.6 Run 7, 26#, L-80 TXP tieback tieback to position seal assembly two joints above tieback sleeve.
Record PU and SO weights.
7, 26#, L-80, TXP
Casing OD Torque (Min) Torque (Opt)Torque (Max)Torque (Operating)
713,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs 20,000 ft-lbs
=
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17.7 MU 7 to DP crossover.
17.8 MU stand of DP to string, and MU top drive.
17.9 Break circulation at 1 BPM and begin lowering string.
17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
17.11 Continue lowering string and land out on no-go. Set down 5 10K and mark the pipe as NO-
GO DEPTH.
17.12 PU string & remove unnecessary 7 joints.
17.13 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing
hanger is landed. Ensure one full joint is below the casing hanger.
17.14 PU and MU the 7 casing hanger.
17.15 Ensure circulation is possible through 7 string.
17.16 RU and circulation corrosion inhibited brine in the 9-5/8 x 7 annulus.
17.17 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500 TVD to surface
in 9-5/8 x 7 annulus by reverse circulating through the holes in the seal assembly. Ensure
annular pressure are limited to prevent collapse of the 7 casing (verify collapse pressure of 7
tieback seal assembly).
17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
17.19 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing
joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes.
17.20 RD casing running tools.
17.21 MU 7 test packer. RIH and test 7 casing to 1,500 psi for 30 minutes charted. POOH LD DP.
Ensure BOP rams have been tested to cover the workstring OD to be used to run the test
packer.
Assure OA pressure does not exceed 12.44 PPGE at perforations in 9-5/8.
NOTE: FIT to 12.44 PPGE at 9-5/8" perforations provides operational limit
for OA over the life of this well.- mgr.
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18.0 Run Upper Completion ESP
18.1 RU to run 3-1/2, 9.3#, L-80 EUE tubing.
Ensure wear bushing is pulled.
Ensure 3-1/2, L-80, 9.3#, EUE 8RD x NC50 crossover is on rig floor and M/U to FOSV.
Ensure all tubing has been drifted in the pipe shed prior to running.
Be sure to count the total # of joints in the pipe shed before running.
Keep hole covered while RU casing tools.
Record ODs, IDs, lengths, SNs of all components with vendor & model info.
Monitor displacement from wellbore while RIH.
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18.2 PU, MU and RH with the following 3-1/2 ESP completion (confirm tally with Operations
Engineer where to place ESP base):
Colors indicate assemblies to be bucked up prior to RWO.
Nom.
Size ~Length Item Lb/ft Material Notes
Centralizer ~L-80
Sensor, Zenith L-80 Baker
Motor L-80 Summit
Lower Tandem Seal L-80 Summit
Upper Tandem Seal L-80 Summit
Gas Avoider L-80 Summit
Gas Seperator L-80 Summit
Pump L-80 Summit
Pump L-80 Summit
3-
1/2''Zenith Ported Sub Press Port L-80 Baker
3-
1/2'' 1 joint L-80
3-
1/2''10'Pup Joint 9.2 L-80
3-
1/2''3-1/2' XN nip L-80
3-
1/2''10'Pup Joint 9.2 L-80
3-
1/2'' 1 joint L-80
3-
1/2GLM with DMY
3-
1/2''Joints 9.2 L-80
3-
1/2GLM with live valve Placed +- 110 MD
3-
1/2''Space out PUPS 9.2 L-80
3-
1/2'' 1 joint 9.2 L-80
3-
1/2''PUP 9.2 L-80
4-
1/2''Tubing Hanger 9.2 L-80
18.3 PU and MU the 4-1/2 tubing hanger. Make final splice of the ESP wire and ensure any unused
control line ports are dummied off.
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18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
18.5 Land the tubing hanger and RILDS. Lay down the landing joint.
18.6 Install 4 HP BPV. ND BOP. Install the plug off tool.
18.7 NU the tubing head adapter and NU the tree.
18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
18.9 Pull the plug off tool and BPV.
18.10 Reverse circulate the well over to corrosion inhibited source water follow by diesel freeze protect
to 2,500 MD.
18.11 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
18.12 RDMO
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19.0 Doyon 14 Diverter Schematic
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20.0 Doyon 14 BOP Schematic
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21.0 Wellhead Schematic
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22.0 Days Vs Depth
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23.0 Formation Tops & Information
MPU I-24 Formations TVD
(ft)
TVDss
(ft)
MD
(ft)
Formation Pressure
(psi)
EMW
(ppg)
BPRF 1803 1736 2064 793 8.46
SV1 2017 1950 2396 887 8.46
UG4 2287 2220 2816 1006 8.46
UG_MB 3482 3415 4782 1532 8.46
SCHRADER NB 3735 3668 5267 1643 8.46
SCHRADER OA 4005 3938 6297 1762 8.46
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24.0 Anticipated Drilling Hazards
12-1/4 Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates
Gas hydrates are generally not seen on I-pad. Remember that hydrate gas behaves differently from a gas
sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout
at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the
hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while
drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can
increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as
cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-
pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove
hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
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 no known wells with a clearance factory <1.0. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any
close approaches on AM report.
Well Specific A/C:
There are no wells with a clearance factor of <1.0
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
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H2S:
Treat every hole section as though it has the potential for H2S. MPU I-pad is not known for H2S. I-
04A had 36 ppm in a 2012 sample. The next highest sample on the pad was 3.2 ppm on I-15 in 2009.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
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8-1/2 Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maint. circulation rate of > 300 gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There are ten planned fault crossings for I-24.
H2S:
Treat every hole section as though it has the potential for H2S. MPU I-pad is not known for H2S. I-
04A had 36 ppm in a 2012 sample. The next highest sample on the pad was 3.2 ppm on I-15 in 2009.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
Well Specific AC:
I-31 has a 0.485 clearance factor. I-31 is an OA jet pump producer and will remain online.
The close approach interval is in the production hole in a different sand.
J-08A has a 0.107 clearance factor. This well has been reservoir abandoned and there is no
HSE risk.
J-26L1 has a 0.370 clearance factor. This multi-lateral has been P&Ad with cement. There
is no HSE risk associated with a collision.
Page 54
Milne Point Unit
I-24 SB Producer
PTD Application
25.0 Doyon 14 Rig Layout
Page 55
Milne Point Unit
I-24 SB Producer
PTD Application
26.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 56
Milne Point Unit
I-24 SB Producer
PTD Application
27.0 Doyon 14 Rig Choke Manifold Schematic
Page 57
Milne Point Unit
I-24 SB Producer
PTD Application
28.0 Casing Design
Page 58
Milne Point Unit
I-24 SB Producer
PTD Application
29.0 8-1/2 Hole Section MASP
Page 59
Milne Point Unit
I-24 SB Producer
PTD Application
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 60
Milne Point Unit
I-24 SB Producer
PTD Application
31.0 Surface Plat (As Built) (NAD 27)
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Alaska NS - Doyon 14 - DSMs
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Cc:Doyon Rig14
Subject:PTD# 224-001_MPU I-24_D14_BOPE test 3-17-24
Date:Monday, March 18, 2024 10:30:28 AM
Attachments:Doyon 14 BOP_ MPU I-24_3-17-24.xlsx
All,
Here is the BOPE test report for MPU I-24, Doyon 14 on 3-17-24.
Regards,
Ian Toomey
DSM Doyon 14 |Hilcorp Alaska, LLC
Office: (907) 670-3090 |Rig: (907) 670-3092 |Cell: (907) 903-3987
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
0LOQH3RLQW8QLW,
37'
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
*All BOPE reports are due to the agency within 5 days of testing*
SSu bmit to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov
Rig Owner: Rig No.:14 DATE: 3/17/24
Rig Rep.: Rig Email:
Operator:
Operator Rep.: Op. Rep Email:
Well Name:PTD #2240010 Sundry #
Operation: Drilling: X Workover: Explor.:
Test: Initial: Weekly: Bi-Weekly: X Other:
Rams:250/3000 Annular:250/3000 Valves:250/3000 MASP:1362
MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES:
Test Result/Type Test Result Quantity Test Result
Housekeeping P Well Sign P Upper Kelly 1P
Permit On Location P Hazard Sec.P Lower Kelly 1P
Standing Order Posted P Misc.NA Ball Type 3P
Test Fluid Water Inside BOP 2P
FSV Misc 0NA
BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm
Stripper 0 N/A NA Trip Tank PP
Annular Preventer 1 13-5/8"P Pit Level Indicators PP
#1 Rams 1 4-1/2" x 7"P Flow Indicator PP
#2 Rams 1 Blinds P Meth Gas Detector PP
#3 Rams 1 2-7/8" x 5"P H2S Gas Detector PP
#4 Rams 0NAMS Misc 0NA
#5 Rams 0NA
#6 Rams 0NAACCUMULATOR SYSTEM:
Choke Ln. Valves 1 3-1/8" X 5000 P Time/Pressure Test Result
HCR Valves 2 3-1/8" X 5000 P System Pressure (psi)3000 P
Kill Line Valves 1 3-1/8" X 5000 P Pressure After Closure (psi)1625 P
Check Valve 0NA200 psi Attained (sec)48 P
BOP Misc 0NAFull Pressure Attained (sec)193 P
Blind Switch Covers: All stations Yes
CHOKE MANIFOLD:Bottle Precharge:P
Quantity Test Result Nitgn. Bottles # & psi (Avg.): 6 @ 1868 P
No. Valves 14 P ACC Misc 0NA
Manual Chokes 1P
Hydraulic Chokes 1P Control System Response Time:Time (sec) Test Result
CH Misc 0NA Annular Preventer 15 P
#1 Rams 7 P
Coiled Tubing Only:#2 Rams 7 P
Inside Reel valves 0NA #3 Rams 7 P
#4 Rams NA
Test Results #5 Rams NA
#6 Rams NA
Number of Failures:0 Test Time:5.5 hours HCR Choke 2 P
Repair or replacement of equipment will be made within 0 days. HCR Kill 2 P
Remarks:
AOGCC Inspection
24 hr Notice Yes Date/Time 3/15/24 @ 15:41
Waived By
Test Start Date/Time:3/17/2024 12:30
(date) (time)Witness
Test Finish Date/Time:3/17/2024 18:00
BOPE Test Report
Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov
Adam Earl
Doyon
Test Annular with 3-1/2" test joint to 250/3000 psi. All other tests performed to 250/3000 psi. Test upper rams with 4-1/2" & 5" test
joint. Test lower rams with 3-1/2" & 5" test joints. Test H2S and LEL gas alarms. Test PVT, Gain/Loss and flow paddle. Test 2ea 4-
1/2" IF TIW & 1ea 4-1/2" IF Dart valve. Test 1ea 3-1/2" IF TIW & Dart. All test performed against test plug. Test #3 the test stump
for the 3-1/2IF Dart leaked, tighten connection at test stump and tested good.
J Hansen / J Charlie
Hilcorp Alaska LLC
I Toomey / Luke Moore
MPU I-24
Test Pressure (psi):
rig14@doyondrilling.com
skaNS-Doyon14-DSMs@hilcorp.c
Form 10-424 (Revised 08/2022)2024-0317_BOP_Doyon14_MPU_I-24
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-5HJJ
STATE OF ALASKA
OIL AND GAS CONSERVATION COMMISSION
BOPE Test Report for:
Reviewed By:
P.I. Suprv
Comm ________MILNE PT UNIT I-24
JBR 04/12/2024
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:0
4.5", 5"and 7" test joints were used. During test #8 the test stump for the TIWs started to leak on the high. The fixed the leak
and went back to the high for a pass.
Test Results
TEST DATA
Rig Rep:J. Hansen/J. CharlieOperator:Hilcorp Alaska, LLC Operator Rep:J. Vanderpool/L. Moore
Rig Owner/Rig No.:Doyon 14 PTD#:2240010 DATE:3/9/2024
Type Operation:DRILL Annular:
250/3000Type Test:INIT
Valves:
250/3000
Rams:
250/3000
Test Pressures:Inspection No:bopGDC240308132738
Inspector Guy Cook
Inspector
Insp Source
Related Insp No:
INSIDE REEL VALVES:
Quantity P/F
(Valid for Coil Rigs Only)
Remarks:
Test Time 7
MASP:
1362
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 2 P
FSV Misc 0 NA
14 PNo. Valves
1 PManual Chokes
1 PHydraulic Chokes
0 NACH Misc
Stripper 0 NA
Annular Preventer 1 13 5/8" 5000 P
#1 Rams 1 4.5"x7" VBR P
#2 Rams 1 Blinds P
#3 Rams 1 2 7/8"x5"VB P
#4 Rams 0 NA
#5 Rams 0 NA
#6 Rams 0 NA
Choke Ln. Valves 1 3 1/8" 5000 P
HCR Valves 2 3 1/8" 5000 P
Kill Line Valves 1 3 1/8" 5000 P
Check Valve 0 NA
BOP Misc 0 NA
System Pressure P3000
Pressure After Closure P1650
200 PSI Attained P40
Full Pressure Attained P189
Blind Switch Covers:PAll Stations
Bottle precharge P
Nitgn Btls# &psi (avg)P6@1890
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 P18
#1 Rams P8
#2 Rams P8
#3 Rams P8
#4 Rams NA0
#5 Rams NA0
#6 Rams NA0
HCR Choke P2
HCR Kill P2
CAUTION: This email originated from outside the State of Alaska mail system. Do not
click links or open attachments unless you recognize the sender and know the content
is safe.
From:Mark Brouillet - (C)
To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC)
Subject:BOPE Test Report
Date:Saturday, March 2, 2024 7:51:20 AM
Attachments:Doyon14 Diverter Report I-24.xlsx
Some people who received this message don't often get email from mark.brouillet@hilcorp.com. Learn why this is
important
Corrections made to report and resending
Thank you
Mark Brouillet
Hilcorp Alaska, LLC
Doyon Rig 14
Office: 907-670-3090
Doghouse: 907-670-3092
Cell: 907-631-9850
mark.brouillet@Hilcorp.com
The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the
individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby
notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please
immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete
this message.
While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the
onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility
is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate.
0LOQH3RLQW8QLW,
37'
Date: 3/1/2024 Development: X Exploratory:
Drlg Contractor: Rig No. 14 AOGCC Rep:
Operator:Oper. Rep:
Field/Unit/Well No.:Rig Rep:
PTD No.: 2240010 Rig Phone:
Rig Email:
MMISCELLANEOUS:DIVERTERR SYSTEM:
Location Gen.: P Well Sign: P Designed to Avoid Freeze-up? P
Housekeeping: P Drlg. Rig. P Remote Operated Diverter? P
Warning Sign P Misc: NA No Threaded Connections? P
24 hr Notice: P Vent line Below Diverter? P
AACCUMULATORR SYSTEM:Diverter Size: 21-1/4" in.
Systems Pressure: 3000 psig P Hole Size: 12-1/4" in.
Pressure After Closure: 1800 psig P Vent Line(s) Size: 16 in. P
200 psi Recharge Time: 31 Seconds P Vent Line(s) Length: 147 ft. P
Full Recharge Time:177 Seconds P Closest Ignition Source: 78 ft. P
Nitrogen Bottles (Number of): 6 Outlet from Rig Substructure: 138 ft. P
Avg. Pressure: 1930 psig P
Accumulator Misc: NA
Vent Line(s) Anchored: P
MMUDD SYSTEM:Visual Alarm Turns Targeted / Long Radius: P
Trip Tank: P P Divert Valve(s) Full Opening: P
Mud Pits: P P Valve(s) Auto & Simultaneous:
Flow Monitor: P P Annular Closed Time: 28 sec P
Mud System Misc: 0 NA Knife Valve Open Time: 15 sec P
Diverter Misc: NA
GGASS DETECTORS:Visual Alarm
Methane: P P
Hydrogen Sulfide: P P
Gas Detectors Misc: 1 FP
Total Test Time: 1.5 hrs Non-Compliance Items: 1
Remarks:
Submit to:
rig14@doyondrilling.com
TTESTT DATA
J Hansen / N Hamilton
phoebe.brooks@alaska.gov
Hilcorp Alaska LLC
Test performed with 5" HWDP, test H2S and LEL gas alarms. F/P Honeywell Control unit, Reset parameters and tested good. Witness waived
by Kam StJohn 2/28/2024 @ 08:20
0
M Brouilliet / J Vanderpool
0
907-670-3096
TTESTT DETAILS
jim.regg@alaska.gov
AOGCC.Inspectors@alaska.gov
Milne Point Unit I-24
SSTATEE OFF ALASK A
AALASK AA OILL ANDD GASS CONSERVATIONN COMMISSION
DDiver terr Systemss Inspectionn Report
GGENERALL INFORMATION
WaivedDoyon
**Alll Diverterr reportss aree duee too thee agencyy w ithinn 55 dayss off testing*
Form 10-425 (Revised 05/2021)2024-0301_Diverter_Doyon14_MPU_I-24
9
9
9
9
9
9
-5HJJ
FPGas Detectors Misc:
F/P Honeywell Control unit
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 I-24
Hilcorp Alaska, LLC
Permit to Drill Number: 224-001
Surface Location: 2336’ FSL, 3830’ FEL, SEC. 33, T13N, R10E, UM, AK
Bottomhole Location: 578’ FSL, 95’ FEL, SEC. 17, T13N, R10E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of January, 2024. 29
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.01.29 13:30:55
-09'00'
5-1/2"x4-1/2"EZGO HT/Hyd 625
Drilling Manager
01/05/24
Monty M
Myers
By Grace Christianson at 8:37 am, Jan 05, 2024
DSR-1/26/24
224-001
* BOPE test to 3000 psi. Annular to 2500 psi.
* Casing test and FIT digital data to AOGCC immediately upon completion of
performing FIT.
A.Dewhurst 26JAN24
50-029-23778-00-00
MGR17JAN2024*&: JLC 1/29/2024
1/29/24
1/29/24
Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2024.01.29 13:28:03 -09'00'
Milne Point Unit
(MPU) I-24
Application for Permit to Drill
Version 1
1/4/2024
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 13-5/8” 5M Diverter System ............................................................................................. 11
11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13
12.0 Run 9-5/8” Surface Casing ...................................................................................................... 16
13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22
14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 27
15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28
16.0 Run 5-1/2” x 4-1/2” Screened Liner ........................................................................................ 33
17.0 Run 7” Tieback ........................................................................................................................ 38
18.0 Run Upper Completion – Jet Pump ........................................................................................ 41
19.0 Doyon 14 Diverter Schematic .................................................................................................. 43
20.0 Doyon 14 BOP Schematic ........................................................................................................ 44
21.0 Wellhead Schematic ................................................................................................................. 45
22.0 Days Vs Depth .......................................................................................................................... 46
23.0 Formation Tops & Information............................................................................................... 47
24.0 Anticipated Drilling Hazards .................................................................................................. 49
25.0 Doyon 14 Rig Layout ............................................................................................................... 52
26.0 FIT Procedure .......................................................................................................................... 53
27.0 Doyon 14 Rig Choke Manifold Schematic ............................................................................... 54
28.0 Casing Design ........................................................................................................................... 55
29.0 8-1/2” Hole Section MASP ....................................................................................................... 56
30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 57
31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 58
Page 2
Milne Point Unit
I-24 SB Producer
PTD Application
1.0 Well Summary
Well MPU I-24
Pad Milne Point “I” Pad
Planned Completion Type Jet Pump
Target Reservoir(s) Schrader Bluff OBa Sand
Planned Well TD, MD / TVD 18,911’ MD / 4,277’ TVD
PBTD, MD / TVD 18,911’ MD / 4,277’ TVD
Surface Location (Governmental) 2336' FSL, 3830' FEL, Sec 33, T13N, R10E, UM, AK
Surface Location (NAD 27) X= 551540, Y=6009451
Top of Productive Horizon
(Governmental)1292' FNL, 2024' FEL, Sec 32, T13N, R10E, UM, AK
TPH Location (NAD 27) X= 548051, Y=6011079
BHL (Governmental) 578' FSL, 95' FEL, Sec 17, T13N, R10E, UM, AK
BHL (NAD 27) X= 549862, Y=6023520
AFE Drilling Days 23
AFE Completion Days 3
Maximum Anticipated Pressure
(Surface) 1362 psig
Maximum Anticipated Pressure
(Downhole/Reservoir) 1762 psig
Work String 5” 19.5# S-135 NC 50
Doyon 14 KB Elevation above MSL: 33.7 ft + 33.2 ft = 66.9 ft
GL Elevation above MSL: 33.2 ft
BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams
Page 3
Milne Point Unit
I-24 SB Producer
PTD Application
2.0 Management of Change Information
Page 4
Milne Point Unit
I-24 SB Producer
PTD Application
3.0 Tubular Program:
Hole
Section
OD (in)ID
(in)
Drift
(in)
Conn OD
(in)
Wt
(#/ft)
Grade Conn Burst
(psi)
Collapse
(psi)
Tension
(k-lbs)
Cond 20” 19.25”---X-52Weld
12-1/4”9-5/8” 8.835”8.679”10.625”40 L-80 TXP 5,750 3,090 916
9-5/8” 8.681”8.525”10.625”47 L-80 TXP 6,870 4,750 1,086
Tieback 7” 6.276” 6.151” 7.656” 26 L-80 TXP 7,240 5,410 604
8-1/2”5-1/2”
Screens 4.780” 4.653” 6.000” 20 L-80
EZGO HT 9,189 8,830 466
8-1/2”4-1/2”
Screens 3.920” 3.795” 4.714” 13.5 L-80 Hydril 625 9,020 8,540 279
Tubing 4-1/2" 3.958”3.833”4.729”12.6 L-80 TXP 8,430 7,500 288
4.0 Drill Pipe Information:
Hole
Section
OD
(in)
ID (in)TJ ID
(in)
TJ OD
(in)
Wt
(#/ft)
Grade Conn M/U
(Min)
M/U
(Max)
Tension
(k-lbs)
Surface &
Production
5”4.276”3.25” 6.625”19.5 S-135 DS50 36,100 43,100 560klb
5”4.276”3.25” 6.625”19.5 S-135 NC50 30,730 34,136 560klb
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 5
Milne Point Unit
I-24 SB Producer
PTD Application
5.0 Internal Reporting Requirements
5.1 Fill out daily drilling report and cost report on WellEz.
x Report covers operations from 6am to 6am
x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area – this will not save the data entered, and will navigate to another data entry.
x Ensure time entry adds up to 24 hours total.
x Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
x Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
x Submit a short operations update each work day to mmyers@hilcorp,
nathan.sperry@hilcorp.com and joseph.lastufka@hilcorp.com
5.3 Intranet Home Page Morning Update
x Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
x Health and Safety: Notify EHS field coordinator.
x Environmental: Drilling Environmental Coordinator
x Notify Drilling Manager & Drilling Engineer on all incidents
x Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
x Send final “As-Run” Casing tally to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.6 Casing and Cement report
x Send casing and cement report for each string of casing to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com
5.7 Hilcorp Milne Point Contact List:
Title Name Work Phone Email
Drilling Manager Monty Myers 907.777.8431 mmyers@hilcorp.com
Drilling Engineer Nate Sperry 907.777.8450 nathan.sperry@hilcorp.com
Drilling Engineer Joe Engel 907.777.8395 jengel@hilcorp.com
Completion Engineer Brian Glasheen 907.564.5277 Brian.glasheen@hilcorp.com
Geologist Katie Cunha 907.564.4786 Katharine.cunha@hilcorp.com
Reservoir Engineer Almas Aitkulov 907.564.4250 aaitkulov@hilcorp.com
Drilling Env. Coordinator Adrian Kersten 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
_____________________________________________________________________________________
Edited By: JNL 1/4/2024
PROPOSED SCHEMATIC
Milne Point Unit
Well: MPU I-24
Last Completed: TBD
PTD: TBD
TD =18,911’(MD) / TD =4,277’(TVD)
4
20”
Orig. KB Elev.: 66.9’ / GL Elev.: 33.2’
7”
5
6
9
9-5/8”
1
2
3
5-1/2”XO
4-1/2”
See
Screen/
Solid
Liner
Detail
PBTD = 18,911’(MD) / PBTD = 4,277’(TVD)
9-5/8” ‘ES’
Cementer
@~2500’
7
8
12
10
4-1/2”
1
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm BPF
20" Conductor 129.5 / X52 / Weld N/A Surface 150’ 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’ 6,600’ 0.0758
7” Tieback 26 / L-80 / TXP 6.276 Surface 6,450’ 0.0383
5-1/2” Liner 100ђ Screens 20 / L-80 / EZGO HT 4.780 6,450’ 9,411’ 0.0222
4-1/2” Liner 100ђ Screens 13.5 / L-80 / Hyd 625 3.920 9,411’ 18,911’ 0.0149
TUBING DETAIL
4-1/2" Tubing 12.6# / L-80 / TXP 3.958 Surface 6,450’ 0.0152
OPEN HOLE / CEMENT DETAIL
20” Driven
12-1/4"Stg 1 Lead – 537 sx / Tail – 395 sx
Stg 2 Lead – 673 sx / Tail 268 sx
8-1/2” Cementless Screened Liner
WELL INCLINATION DETAIL
KOP @ 250’
90° Hole Angle = @ 6,500’
TREE & WELLHEAD
Tree Cameron 3-1/8" 5M w/ 3-1/8” 5M Cameron Wing
Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs
GENERAL WELL INFO
API: TBD
Completion Date: TBD
JEWELRY DETAIL
No. MD Item ID
1 Surface 4-1/2” TCII Tubing Hanger 4.500”
2 5,430’ Haliburton X-Profile Sliding Sleeve (opens down) 2.813”
3 5,440’ Zenith Ported Pressure Sub 2.913”
4 5,470' Baker Retrievable Premier Packer 3.870”
5 5,500’ XN Nipple, 3.813” Packing Bore, 3.725” No-Go 2.750”
6 6,450’ Mule Shoe Joint 3.958”
7 6,450’ SLZXP Liner Top Packer 6.190”
8 6,460’ 7” H563 x 5.5” EZGO HT XO 4.810”
9 9,411’ 5-1/2” x 4-1/2” XO 3.920”
10 18,911’ Shoe 3.970”
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”
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Milne Point Unit
I-24 SB Producer
PTD Application
7.0 Drilling / Completion Summary
MPU I-24 is a grassroots producer planned to be drilled in the Schrader Bluff OBa sand. I-24 is part of a
multi well program targeting the Schrader Bluff sand on I-pad
The directional plan is 12-1/4” surface hole with 9-5/8” surface casing set in the top of the Schrader Bluff
OBa sand. An 8-1/2” lateral section will be drilled and completed with a 5-1/2” x 4-1/2” liner. The well will
be produced with a jet pump.
Doyon 14 will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately February 10, 2024, pending rig schedule.
Surface casing will be run to 6,600’ MD / 4,012’ TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility.
General sequence of operations:
1. MIRU Doyon 14 to well site
2. N/U & Test 21-1/4” Diverter and 16” diverter line
3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing
4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test
5. Drill 8-1/2” lateral to well TD
6. Run 5-1/2” x 4-1/2” production liner
7. Run 7” tieback
8. Run Upper Completion
9. N/D BOP, N/U Tree, RDMO
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
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I-24 SB Producer
PTD Application
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that all drilling and completion operations comply with all applicable AOGCC regulations.
Operations stated in this PTD application may be altered based on sound engineering judgement as
wellbore conditions require, but no AOGCC regulations will be varied from without prior approval from
the AOGCC. If additional clarity or guidance is required on how to comply with a specific regulation,
do not hesitate to contact the Anchorage Drilling Team.
x Review all conditions of approval of the PTD on the 10-401 form. Ensure that the conditions of
approval are captured in shift handover notes until they are executed and complied with.
x BOPs shall be tested at (2) week intervals during the drilling and completion of MPU I-24. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPs.
x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment
will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial
and subsequent tests).Confirm that these test pressures match those specified on the APD.
x If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid
program and drilling fluid system”.
x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements”.
o Ensure the diverter vent line is at least 75’ away from potential ignition sources
x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test
must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a
minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test
pressure must show stabilizing pressure and may not decline more than 10 percent within 30
minutes. The results of this test and any subsequent tests of the casing must be recorded as required
by 20 AAC 25.070(1)”.
AOGCC Regulation Variance Requests:
x None
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PTD Application
Summary of BOP Equipment & Notifications
Hole Section Equipment Test Pressure (psi)
12 1/4”x 21-1/4” 2M Diverter w/ 16” Diverter Line Function Test Only
8-1/2”
x 13-5/8” x 5M Hydril “GK” Annular BOP
x 13-5/8” x 5M Hydril MPL Double Gate
o Blind ram in btm cavity
x Mud cross w/ 3” x 5M side outlets
x 13-5/8” x 5M Hydril MPL Single ram
x 3-1/8” x 5M Choke Line
x 3-1/8” x 5M Kill line
x 3-1/8” x 5M Choke manifold
x Standpipe, floor valves, etc
Initial Test: 250/3000
Subsequent Tests:
250/3000
Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air
pump, and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
x Well control event (BOPs utilized to shut in the well to control influx of formation fluids).
x 24 hours notice prior to spud.
x 24 hours notice prior to testing BOPs.
x 24 hours notice prior to casing running & cement operations.
x Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov
Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov
Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov
Test Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
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Milne Point Unit
I-24 SB Producer
PTD Application
9.0 R/U and Preparatory Work
9.1 I-24 will utilize a newly set 20” conductor on I-pad. Ensure to review attached surface plat and
make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Doyon 14. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF).
9.10 Ensure 6” liners in mud pumps.
x Continental EMSCO FB-1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @
95% volumetric efficiency.
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I-24 SB Producer
PTD Application
10.0 N/U 13-5/8” 5M Diverter System
10.1 N/U 21-1/4” Hydril MSP 2M Diverter System (Diverter Schematic attached to program).
x N/U 16-3/4” 3M x 21-1/4” 2M DSA on 16-3/4” 3M wellhead.
x N/U 21-1/4” diverter “T”.
x Knife gate, 16” diverter line.
x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
x Diverter line must be 75 ft from nearest ignition source
x Place drip berm at the end of diverter line.
10.2 Notify AOGCC. Function test diverter.
x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens
prior to annular closure.
x Ensure that the annular closes in less than 45 seconds (API Standard 64 3rd edition March 2018
section 12.6.2 for packing element ID greater than 20”)
10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the
vent line tip. “Warning Zone” must include:
x A prohibition on vehicle parking
x A prohibition on ignition sources or running equipment
x A prohibition on staged equipment or materials
x Restriction of traffic to essential foot or vehicle traffic only.
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10.4 Rig & Diverter Orientation:
x May change on location
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11.0 Drill 12-1/4” Hole Section
11.1 P/U 12-1/4” directional drilling assembly:
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Use GWD until MWD surveys are clean and then swap to MWD.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing.
x Drill string will be 5” 19.5# S-135.
x Run a solid float in the surface hole section.
11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor.
x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in
conductor.
11.3 Drill 12-1/4” hole section to section TD in the Schrader OBa sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
x Monitor the area around the conductor for any signs of broaching. If broaching is observed,
stop drilling (or circulating) immediately notify Drilling Engineer.
x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100.
x Hold a safety meeting with rig crews to discuss:
x Conductor broaching ops and mitigation procedures.
x Well control procedures and rig evacuation
x Flow rates, hole cleaning, mud cooling, etc.
x Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
x Keep mud as cool as possible to keep from washing out permafrost.
x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
x Slow in/out of slips and while tripping to keep swab and surge pressures low
x Ensure shakers are functioning properly. Check for holes in screens on connections.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
x Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2
minimum at TD (pending MW increase due to hydrates).
x Perform gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled.
x Be prepared for gas hydrates. In MPU they have been encountered typically around 2,100-
2,400’ TVD (just below permafrost). Be prepared for hydrates:
x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
x Monitor returns for hydrates, checking pressurized & non-pressurized scales
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PTD Application
x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple.
x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well.
MW will not control gas hydrates, but will affect how gas breaks out at surface.
x Take MWD and GWD surveys every stand until magnetic interference cleans up. After
MWD surveys show clean magnetics, only take MWD surveys.
x Surface Hole AC:
x There are no wells with a clearance factor of <1.0
11.4 12-1/4” hole mud program summary:
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
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.
Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but
reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared
to increase the YP if hole cleaning becomes an issue.
Fluid Loss: DEXTRID and/or PAC L 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.
Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to
reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of
the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with
caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action.
Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not
jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the
system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value
they have targeted).
System Type:8.8 – 9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud
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PTD Application
Properties:
Section Density Viscosity Plastic
Viscosity Yield Point API FL pH
Temp
Surface 8.8 –9.8 75-175 20 - 40 25-45 <10 8.5 –9.0 70 F
System Formulation: Gel + FW spud mud
Product- Surface hole Size Pkg ppb or (% liquids)
M-I Gel 50 lb sx 25
Soda Ash 50 lb sx 0.25
PolyPac Supreme UL 50 lb sx 0.08
Caustic Soda 50 lb sx 0.1
SCREENCLEEN 55 gal dm 0.5
11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem
sweeps and drop viscosity.
11.6 RIH to bottom, proceed to BROOH to HWDP
x Pump at full drill rate (400-600 gpm), and maximize rotation.
x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions
x Monitor well for any signs of packing off or losses.
x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.7 TOOH and LD BHA
11.8 No open hole logging program planned.
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Milne Point Unit
I-24 SB Producer
PTD Application
12.0 Run 9-5/8” Surface Casing
12.1 R/U and pull wearbushing.
12.2 R/U 9-5/8” casing running equipment (CRT & Tongs)
x Ensure 9-5/8” TXP x NC50 XO on rig floor and M/U to FOSV.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x R/U of CRT if hole conditions require.
x R/U a fill up tool to fill casing while running if the CRT is not used.
x Ensure all casing has been drifted to 8.5” on the location prior to running.
x Note that 47# drift is 8.525”
x Be sure to count the total # of joints on the location before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking 120’ shoe track assembly consisting of:
9-5/8” Float Shoe
1 joint – 9-5/8” TXP, 2 Centralizers 10’ from each end w/ stop rings
1 joint –9-5/8” TXP, 1 Centralizer mid joint w/ stop ring
9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’
1 joint –9-5/8” TXP, 1 Centralizer mid joint with stop ring
9-5/8” HES Baffle Adaptor
x Ensure bypass baffle is correctly installed on top of float collar.
x Ensure proper operation of float equipment while picking up.
x Ensure to record S/N’s of all float equipment and stage tool components.
This end up.
Bypass Baffle
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PTD Application
12.5 Float equipment and Stage tool equipment drawings:
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12.6 Continue running 9-5/8” surface casing
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
x 1 centralizer every joint to ~ 1000’ MD from shoe
x 1 centralizer every 2 joints to ~2,000’ above shoe (Top of Lowest Ugnu)
x Verify depth of lowest Ugnu water sand for isolation with Geologist
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
x Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below
the permafrost.
x Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
x Do not place tongs on ES cementer, this can cause damaged to the tool.
x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8” 40# L-80 TXP Make-Up Torques:
Casing OD Minimum Optimum Maximum
9-5/8”18,860 ft-lbs 20,960 ft-lbs 23,060 ft-lbs
9-5/8” 47# L-80 TXP MUT:
Casing OD Minimum Optimum Maximum
9-5/8”21,440 ft-lbs 23,820 ft-lbs 26,200 ft-lbs
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I-24 SB Producer
PTD Application
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12.8 Continue running 9-5/8” surface casing
x Centralizers: 1 centralizer every 3rd joint to 200’ from surface
x Fill casing while running using fill up line on rig floor.
x Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
x Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 Ensure the permafrost is covered with 9-5/8” 47# from BPRF to Surface
x Ensure drifted to 8.525”
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PTD Application
12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.11 Slow in and out of slips.
12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.13 Lower casing to setting depth. Confirm measurements.
12.14 Have slips staged in cellar, along with necessary equipment for the operation.
12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
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PTD Application
13.0 Cement 9-5/8” Surface Casing
13.1 Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
x Which pumps will be utilized for displacement, and how fluid will be fed to displacement
pump.
x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
x Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
x Review test reports and ensure pump times are acceptable.
x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below
calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated 1st Stage Total Cement Volume:
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PTD Application
Cement Slurry Design (1st Stage Cement Job):
13.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue
with the cement job.
13.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
x Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.11 Ensure rig pump is used to displace cement. To operate the stage tool hydraulically, the plug
must be bumped.
13.12 Displacement calculation:
See calculation in step 13.8
80 bbls of tuned spacer to be left on top of stage tool so that the first fluid through the ES
cementer is tuned spacer to minimize the risk of flash setting cement
13.13 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling
Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up
option to open the stage tool.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
Lead Slurry Tail Slurry
System EconoCem HalCem
Density 12.0 lb/gal 15.8 lb/gal
Yield 2.35 ft3/sk 1.16 ft3/sk
Mix Water 13.92 gal/sk 4.98 gal/sk
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to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
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Second Stage Surface Cement Job:
13.18 Prepare for the 2
nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety
meeting.
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2
nd stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
Estimated 2nd Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.26 Displacement calculation:
2500’ x 0.0732 bpf = 183.0 bbls mud
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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13.27 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.
13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips.
13.30 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump.
Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
x Pre flush type, volume (bbls) & weight (ppg)
x Cement slurry type, lead or tail, volume & weight
x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
x Note if casing is reciprocated or rotated during the job
x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
x Note if pre flush or cement returns at surface & volume
x Note time cement in place
x Note calculated top of cement
x Add any comments which would describe the success or problems during the cement job
Send final “As-Run” casing tally & casing and cement report to nathan.sperry@hilcorp.com and
joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the
AOGCC.
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14.0 ND Diverter, NU BOPE, & Test
14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool.
14.2 NU 13-5/8” x 5M BOP as follows:
x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13-
5/8” x 5M mud cross / 13-5/8” x 5M single gate
x Double gate ram should be dressed with 4-1/2” x 7” VBRs in top cavity,blind ram in
bottom cavity.
x Single ram can be dressed with 2-7/8” x 5” VBRs
x NU bell nipple, install flowline.
x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual
valve
14.3 RU MPD RCD and related equipment
14.4 Run 5” BOP test plug
14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min.
x Test 4-1/2” x 7” rams with 4-1/2” and 7” test joints
x Test 2-7/8” x 5” rams with the 4-1/2” and 5” test joints
x Confirm test pressures with PTD
x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
is trapped underneath test plug
x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.6 RD BOP test equipment
14.7 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.8 Mix 8.9 ppg FloPro for production hole.
14.9 Set wearbushing in wellhead.
14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole
section.
14.11 Ensure 5” liners in mud pumps.
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15.0 Drill 8-1/2” Hole Section
15.1 MU 8-1/2” Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2” cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and
plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure
on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent
pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry
Guidance Bulletin 17-001.
15.5 Drill out shoe track and 20’ of new formation.
15.6 CBU and condition mud for FIT.
15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test.
Document incremental volume pumped (and subsequent pressure) and volume returned.
15.8 POOH and LD cleanout BHA
15.9 PU 8-1/2” directional BHA.
x Ensure BHA components have been inspected previously.
x Drift and caliper all components before MU. Visually verify no debris inside components that
cannot be drifted.
x Ensure TF offset is measured accurately and entered correctly into the MWD software.
x Ensure MWD is RU and operational.
x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
x Drill string will be 5” 19.5# S-135 NC50.
x Run a ported float in the production hole section.
Schrader Bluff Bit Jetting Guidelines
Formation Jetting TFA
NB 6 x 14 0.902
OA 6 x 13 0.778
OB 6 x 13 0.778
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15.10 8-1/2” hole section mud program summary:
x Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
x Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for
sufficient hole cleaning
x Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
x Dump and dilute as necessary to keep drilled solids to an absolute minimum.
x MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller’s console, Co Man office, &
Toolpusher office.
System Type:8.9 – 9.5 ppg FloPro drilling fluid
Properties:
Interval Density PV YP LSYP Total Solids MBT HPHT Hardness
Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100
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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 PU
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
0.5% lubes
15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer.
x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM
x RPM: 120+
x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
x Monitor Torque and Drag with pumps on every 5 stands
x Monitor ECD, pump pressure & hookload trends for hole cleaning indication
x Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
x Use ADR to stay in section. Reservoir plan is to stay in OBA sand.
x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
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x Target ROP is as fast as we can clean the hole without having to backream connections
x Schrader Bluff OBA Concretions: 4-6% Historically
x MPD will be utilized to monitor pressure build up on connections.
x 8-1/2” Lateral A/C:
x I-31 has a 0.485 clearance factor. I-31 is an OA jet pump producer and will remain
online. The close approach interval is in the production hole in a different sand.
x J-08A has a 0.107 clearance factor. This well has been reservoir abandoned and
there is no HSE risk.
x J-26L1 has a 0.370 clearance factor. This multi-lateral has been P&A’d with cement.
There is no HSE risk associated with a collision.
15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons
learned and best practices. Ensure the DD is referencing their procedure.
x Patience is key! Getting kicked off too quickly might have been the cause of failed liner
runs on past wells.
x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so
we have a nice place to low side.
x Attempt to lowside in a fast drilling interval where the wellbore is headed up.
x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working
string back and forth. Trough for approximately 30 minutes.
x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump
tandem sweeps if needed
x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum
15.17 Mix and pump 40 bbl 10 ppb SAPP pill. Line up to a closed loop system and circulate three SAP
pills with 50 bbl in between. Displace out SAP pills. Monitor shakers for returns of mud filter
cake and calcium carbonate. Circulate the well clean.
Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being
removed, including an increase in the loss rate.
15.18 Displace 1.5 OH + liner volume with viscosified brine.
x Proposed brine blend (same as used on M-16, aiming for an 8 on the 6 RPM reading) -
KCl: 7.1ppb for 2%
NaCl: 60.9ppg for 9.4ppg
Lotorq: 1.5%
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Lube 776: 1.5%
Soda Ash: as needed for 9.5pH
Busan 1060: 0.42ppb
Flo-Vis Plus: 1.25ppb
x Monitor well for loss rate and contact Drilling Engineer and/or Ops Engineer if further
discussion needed prior to BROOH.
15.15 Monitor the returned fluids carefully while displacing to brine. After 1 (or more if needed) BU,
Perform production screen test (PST). The brine has been properly conditioned when it will pass
the production screen test (x3 350 ml samples passing through the screen in the same amount
of time which will indicate no plugging of the screen). Reference PST Test Procedure
15.19 BROOH with the drilling assembly to the 9-5/8” casing shoe
x Circulate at full drill rate (less if losses are seen, 350 GPM minimum).
x Rotate at maximum RPM that can be sustained.
x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as
dictated by hole conditions
x When pulling across any OHST depths, turn pumps off and rotary off to minimize
disturbance. Trip back in hole past OHST depth to ensure liner will stay in correct
hole section, check with ABI compared to as drilled surveys
15.20 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH.
15.21 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps.
15.22 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary.
x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
x If necessary, increase MW at shoe for any higher than expected pressure seen
x Ensure fluid coming out of hole has passed a PST at the possum belly
15.23 POOH and LD BHA.
15.24 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit
diameter is sufficient for future ball drops.
Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
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16.0 Run 5-1/2” x 4-1/2” Screened Liner
NOTE: If an open hole sidetrack was performed, drop the centralizers on the lowermost 2-3 joints and run them
slick.
16.1 Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2” screened liner, the following well control response procedure will be followed:
x P/U & M/U the 5” safety joint (with 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” screened liner.
x P/U & M/U the 5” safety joint (with 4-1/2” crossover installed on bottom, TIW valve in open
position on top, 4-1/2” handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 4-1/2” screened liner.
x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW.
x Proceed with well kill operations.
16.2 R/U 4-1/2” liner running equipment.
x Ensure 4-1/2” 13.5# Hydril 625 x NC50 crossover is on rig floor and M/U to FOSV.
x Ensure all casing has been drifted on the deck prior to running.
x Be sure to count the total # of joints on the deck before running.
x Keep hole covered while R/U casing tools.
x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info.
16.3 Run 4-1/2” screened production liner until XO point for 5-1/2” screens (planning 2,000’ of 5-
1/2” on top of liner)
x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint
brush. Wipe off excess. Thread compound can plug the screens
x Utilize a collar clamp until weight is sufficient to keep slips set properly.
x Use lift nubbins and stabbing guides for the liner run.
x Fill 4-½” liner with PST passed mud (to keep from plugging screens with solids)
x Install screen joints as per the Running Order (From Completion Engineer post TD).
o Do not place tongs or slips on screen joints
o Screen placement ±40’
o The screen connection is 4-1/2” 13.5# Hydril 625
x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint
outside of the surface shoe. This is to mitigate difference sticking risk while running inner
string.
x Obtain up and down weights of the liner before entering open hole. Record rotating torque at
10 and 20 rpm
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5-1/2” 20# L-80 EZGO HT Torque
OD Minimum Optimum Maximum
5-1/2 6,997 ft-lbs 10,728 ft-lbs
4-1/2” 13.5# L-80 Hydril 625 Torque
OD Minimum Optimum Maximum
4-1/2 8,000 ft-lbs 9,600 ft-lbs 12,800 ft-lbs
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16.6. Ensure to run enough liner to provide for approx 150’ overlap inside 9-5/8” casing. Ensure
hanger/pkr will not be set in a 9-5/8” connection.
x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection.
16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck
to make sure it coincides with the pipe tally.
16.8. M/U Baker SLZXP liner top packer to 4-1/2” liner.
16.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.10. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and
weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and
avoid surging the hole or buckling the liner. Slow down running speed if necessary.
x Ensure 5” DP/HWDP has been drifted
x There is no inner string planned to be run, as opposed to previous wells. The DP should auto
fill. Monitor FL and if filling is required due to losses/surging.
16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to
bottom.
16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 RPM.
16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.15. Rig up to pump down the work string with the rig pumps.
16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed
1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be
discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker
16.17. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill
pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger.
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16.18. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 BPM). Slow
pump before the ball seats. Do not allow ball to slam into ball seat.
16.19. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in
compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi
to release the HRDE running tool.
16.20. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20
RPM and set down 50K again.
16.21. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted.
16.22. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.23. PU pulling running tool free of the packer and displace at max rate to wash the liner top. Pump
sweeps as needed.
16.24. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LD DP on the TOOH.
Note: Once running tool is LD, swap to the completion AFE.
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17.0 Run 7” Tieback
17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder
to be used for tie-back space out calculation. Install 7” solid body casing rams in the upper ram
cavity. RU testing equipment. PT to 250/3,000 psi with 7” test joint. RD testing equipment.
17.2 RU 7” casing handling equipment.
x Ensure XO to DP made up to FOSV and ready on rig floor.
x Rig up computer torque monitoring service.
x String should stay full while running, RU fill up line and check as appropriate.
17.3 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes
above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7”
annulus.
17.4 MU first joint of 7” to seal assy.
17.6 Run 7”, 26#, L-80 TXP tieback tieback to position seal assembly two joints above tieback sleeve.
Record PU and SO weights.
7”, 26#, L-80, TXP
=Casing OD Torque (Min) Torque (Opt)Torque (Max)Torque (Operating)
7”13,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs 20,000 ft-lbs
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17.7 MU 7” to DP crossover.
17.8 MU stand of DP to string, and MU top drive.
17.9 Break circulation at 1 BPM and begin lowering string.
17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off
pressure. Leave standpipe bleed off valve open.
17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO-
GO DEPTH”.
17.12 PU string & remove unnecessary 7” joints.
17.13 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing
hanger is landed. Ensure one full joint is below the casing hanger.
17.14 PU and MU the 7” casing hanger.
17.15 Ensure circulation is possible through 7” string.
17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus.
17.17 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface
in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure
annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7”
tieback seal assembly).
17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual
weight on hanger on morning report.
17.19 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing
joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes.
17.20 RD casing running tools.
17.21 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted.
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18.0 Run Upper Completion – Jet Pump
18.1 RU to run 4-1/2”, 12.6#, L-80 TXP tubing.
x Ensure wear bushing is pulled.
x Ensure 4-1/2”, L-80, 12.6#, TXP x XT-39 crossover is on rig floor and M/U to FOSV.
x Ensure all tubing has been drifted in the pipe shed prior to running.
x Be sure to count the total # of joints in the pipe shed before running.
x Keep hole covered while RU casing tools.
x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info.
x Monitor displacement from wellbore while RIH.
18.2 PU, MU and RH with the following 4-1/2” JP completion (confirm tally with Operations
Engineer):
x WLEG/Mule shoe
x XX joints, 4-1/2”, 12.6#, L-80, TXP
x Handling Pup, 4-1/2” TXPM Box x 4-1/2” TXP Pin
x Nipple, 3.813” XN profile (3.750” no-go), 4-1/2”, TXPM (RHC plug body installed Below
70 degrees)
x Handling Pup, 4-1/2”, TXP Box x 4-1/2”, TXP Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Crossover Pup, 4-1/2” TC-II Box x 4-1/2” TXP Pin
x Retrievable Packer, Baker, 4-1/2”, 12.6#, L-80, TC-II ( Set Below 70 degrees ~4760 MD 67
degrees)
x Crossover Pup, 4-1/2”, TXP Box x 4-1/2”, TC-II Pin
x 1 joint, 4-1/2”, 12.6#, L-80, TXP
x Pup joint, 4-1/2”, 12.6#, L-80, TXP
x Crossover, 4-1/2”, EUE 8rd Box x 4-1/2”, TXP Pin
x Ported Pressure Sub, 4-1/2”, 12.6#, L-80, EUE 8rd
x Crossover, 4-1/2”, TXP Box x 4-1/2”, EUE 8rd Pin
x Sliding Sleeve, 4-1/2”, 12.6#, L-80 TXP
x Crossover, 4-1/2”, EUE 8rd Box x 4-1/2”, TXP Pin
x Gauge Carrier, 4-1/2”, 12.6#, L-80, EUE 8rd
x Crossover, 4-1/2”, TXP Box x 4-1/2”, EUE 8rd Pin
x Pup joint, 4-1/2”, 12.6#, L-80, TXP
x XXX joints, 4-1/2”, 12.6#, L-80, TXP
18.3 PU and MU the 4-1/2” tubing hanger. Make final splice of the TEC wire and ensure any unused
control line ports are dummied off.
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18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with
band/clamp summary.
18.5 Land the tubing hanger and RILDS. Lay down the landing joint.
18.6 Install 4” HP BPV. ND BOP. Install the plug off tool.
18.7 NU the tubing head adapter and NU the tree.
18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi.
18.9 Pull the plug off tool and BPV.
18.10 Reverse circulate the well over to corrosion inhibited source water follow by diesel freeze protect
to 2,500’ MD.
18.11 Drop the ball & rod.
18.12 Pressure up on the tubing to 3,500 psi to set the packer. PT the tubing to 3,500 psi for 30
minutes (charted).
18.13 Bleed the tubing pressure to 2,000 psi and PT the IA to 3,500 psi for 30 minutes (charted). Bleed
both the IA and tubing to 0 psi.
18.14 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over
with valve alignment as per operations personnel.
18.15 RDMO
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19.0 Doyon 14 Diverter Schematic
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20.0 Doyon 14 BOP Schematic
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21.0 Wellhead Schematic
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22.0 Days Vs Depth
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PTD Application
23.0 Formation Tops & Information
MPU I-24 Formations TVD
(ft)
TVDss
(ft)
MD
(ft)
Formation Pressure
(psi)
EMW
(ppg)
BPRF 1803 1736 2064 793 8.46
SV1 2017 1950 2396 887 8.46
UG4 2287 2220 2816 1006 8.46
UG_MB 3482 3415 4782 1532 8.46
SCHRADER NB 3735 3668 5267 1643 8.46
SCHRADER OA 4005 3938 6297 1762 8.46
Page 48
Milne Point Unit
I-24 SB Producer
PTD Application
Page 49
Milne Point Unit
I-24 SB Producer
PTD Application
24.0 Anticipated Drilling Hazards
12-1/4” Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates
Gas hydrates are generally not seen on I-pad. Remember that hydrate gas behaves differently from a gas
sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout
at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the
hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while
drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can
increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as
cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-
pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove
hydrates from the system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor
ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe
moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after
slide intervals. Do not out drill our ability to clean the hole.
Anti-Collison:
There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any
close approaches on AM report.
Well Specific A/C:
x There are no wells with a clearance factor of <1.0
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
Page 50
Milne Point Unit
I-24 SB Producer
PTD Application
H2S:
Treat every hole section as though it has the potential for H2S. MPU I-pad is not known for H2S. I-
04A had 36 ppm in a 2012 sample. The next highest sample on the pad was 3.2 ppm on I-15 in 2009.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 51
Milne Point Unit
I-24 SB Producer
PTD Application
8-1/2” Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maint. circulation rate of > 300 gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There are ten planned fault crossings for I-24.
H2S:
Treat every hole section as though it has the potential for H2S. MPU I-pad is not known for H2S. I-
04A had 36 ppm in a 2012 sample. The next highest sample on the pad was 3.2 ppm on I-15 in 2009.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen.
Anti-Collision
Take directional surveys every stand, take additional surveys if necessary. Continuously monitor
drilling parameters for signs of magnetic interference with another well. Reference A/C report in
directional plan.
Well Specific AC:
x I-31 has a 0.485 clearance factor. I-31 is an OA jet pump producer and will remain online.
The close approach interval is in the production hole in a different sand.
x J-08A has a 0.107 clearance factor. This well has been reservoir abandoned and there is no
HSE risk.
x J-26L1 has a 0.370 clearance factor. This multi-lateral has been P&A’d with cement. There
is no HSE risk associated with a collision.
g
There are ten planned fault crossings for I-24.
I-31 has a 0.485 clearance factor. I-31 is an OA jet pump producer and will remain online.jp pp
The close approach interval is in the production hole in a different sand.
Page 52
Milne Point Unit
I-24 SB Producer
PTD Application
25.0 Doyon 14 Rig Layout
Page 53
Milne Point Unit
I-24 SB Producer
PTD Application
26.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak-Off Test (LOT) Procedures
Procedure for FIT:
1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1-minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 54
Milne Point Unit
I-24 SB Producer
PTD Application
27.0 Doyon 14 Rig Choke Manifold Schematic
Page 55
Milne Point Unit
I-24 SB Producer
PTD Application
28.0 Casing Design
Page 56
Milne Point Unit
I-24 SB Producer
PTD Application
29.0 8-1/2” Hole Section MASP
Page 57
Milne Point Unit
I-24 SB Producer
PTD Application
30.0 Spider Plot (NAD 27) (Governmental Sections)
Page 58
Milne Point Unit
I-24 SB Producer
PTD Application
31.0 Surface Plat (As Built) (NAD 27)
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Vertical Section at 354.00° (1500 usft/in)
MPU I-24 wp05 heel
MPU I-24 wp05 tgt02
MPU I-24 wp05 tgt03
MPU I-24 wp05 tgt04
MPU I-24 wp05 tgt05
MPU I-24 wp05 tgt06
MPU I-24 wp05 tgt07
MPU I-24 wp05 tgt08 MPU I-24 wp05 tgt24
MPU I-24 wp05 tgt09
MPU I-24 wp05 tgt10
MPU I-24 wp05 tgt11
MPU I-24 wp05 tgt12
MPU I-24 wp05 tgt13
MPU I-24 wp05 tgt14
MPU I-24 wp05 tgt15
MPU I-24 wp05 tgt16
MPU I-24 wp05 tgt17
MPU I-24 wp05 tgt18
MPU I-24 wp05 tgt19
MPU I-24 wp05 tgt20
MPU I-24 wp05 tgt21
MPU I-24 wp05 tgt22
MPU I-24 wp05 tgt23 MPU I-24 wp05 tgt26
MPU I-24 wp05 tgt25
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
5 0 0
1 0 0 0
1 5 0 0
2 0 0 0
2 5 0 0
3 0 0 0
3 5 0 0
4 0 0 0
4 5 0 0
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15500
16000
16500
17000
17500
18000
18500
18912
MPU I-24 wp07
Start Dir 3º/100' : 250' MD, 250'TVD
End Dir : 650' MD, 647.08' TVD
Start Dir 4.25º/100' : 770' MD, 764.46'TVD
End Dir : 1770' MD, 1614.24' TVD
Start Dir 4º/100' : 3100' MD, 2469.15'TVD
End Dir : 3271.65' MD, 2576.09' TVD
Start Dir 4.5º/100' : 4507.85' MD, 3320.01'TVD
End Dir : 6176.95' MD, 3994.44' TVD
Start Dir 3º/100' : 6296.95' MD, 4004.9'TVD
End Dir : 6576.28' MD, 4012.35' TVD
Begin Geosteering
Total De pth : 18911.13' MD, 4276.9' TV
SV6
Base Permafrost
SV1
UG4
UG_MB
SB_NB
SB_OBA
Hilcorp Alaska, LLC
Calculation Method:Minimum Curvature
Error System:ISCWSA
Scan Method: Closest Approach 3D
Error Surface: Ellipsoid Separation
Warning Method: Error Ratio
WELL DETAILS: Plan: MPU I-24
33.20
+N/-S +E/-W
Northing Easting Latitude Longitude
0.00 0.00 6009451.15 551540.09 70° 26' 11.6512 N 149° 34' 47.2244 W
SURVEY PROGRAM
Date: 2020-06-17T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
33.70 900.00 MPU I-24 wp07 (MPU I-24) GYD_Quest GWD
900.00 6600.00 MPU I-24 wp07 (MPU I-24) 3_MWD+IFR2+MS+Sag
6600.00 18911.13 MPU I-24 wp07 (MPU I-24) 3_MWD+IFR2+MS+Sag
FORMATION TOP DETAILS
TVDPath TVDssPath MDPath Formation
829.90 763.00 837.13 SV6
1802.90 1736.00 2063.50 Base Permafrost
2016.90 1950.00 2396.43 SV1
2286.90 2220.00 2816.47 UG4
3481.90 3415.00 4782.40 UG_MB
3734.90 3668.00 5266.93 SB_NB
4004.90 3938.00 6296.95 SB_OBA
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-24, True North
Vertical (TVD) Reference:MPU I-24 as staked @ 66.90usft
Measured Depth Reference:MPU I-24 as staked @ 66.90usft
Calculation Method:Minimum Curvature
Project:Milne Point
Site:M Pt I Pad
Well:Plan: MPU I-24
Wellbore:MPU I-24
Design:MPU I-24 wp07
CASING DETAILS
TVD TVDSS MD Size Name
4011.54 3944.64 6600.00 9-5/8 9 5/8" x 12 1/4"
4276.40 4209.50 18899.00 4-1/2 4 1/2" x 8 1/2"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 33.70 0.00 0.00 33.70 0.00 0.00 0.00 0.00 0.00
2 250.00 0.00 0.00 250.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 250' MD, 250'TVD
3 500.00 7.50 320.00 499.29 12.52 -10.50 3.00 320.00 13.55
4 650.00 12.00 320.00 647.08 31.97 -26.83 3.00 0.00 34.60 End Dir : 650' MD, 647.08' TVD
5 770.00 12.00 320.00 764.46 51.08 -42.86 0.00 0.00 55.28 Start Dir 4.25º/100' : 770' MD, 764.
6 1770.00 50.00 273.00 1614.24 155.60 -513.98 4.25 -56.04 208.47 End Dir : 1770' MD, 1614.24' TVD
7 3100.00 50.00 273.00 2469.15 208.92 -1531.42 0.00 0.00 367.85 Start Dir 4º/100' : 3100' MD, 2469.1
8 3271.65 53.00 280.90 2576.09 225.34 -1664.55 4.00 66.59 398.10 End Dir : 3271.65' MD, 2576.09' TV
9 4507.85 53.00 280.90 3320.01 411.95 -2634.04 0.00 0.00 685.03 Start Dir 4.5º/100' : 4507.85' MD, 3
10 6176.95 85.00 356.00 3994.44 1532.56 -3469.81 4.50 84.98 1886.86 End Dir : 6176.95' MD, 3994.44' TV
11 6296.95 85.00 356.00 4004.90 1651.81 -3478.15 0.00 0.00 2006.33 MPU I-24 wp05 heel Start Dir 3º/100' : 6296.95' MD, 400
12 6576.28 91.94 0.69 4012.35 1930.68 -3486.18 3.00 34.14 2284.51 End Dir : 6576.28' MD, 4012.35' TV
13 7307.68 91.94 0.69 3987.52 2661.60 -3477.33 0.00 0.00 3010.50
14 7325.33 91.50 0.50 3986.99 2679.24 -3477.14 2.75 -156.44 3028.02
15 7405.33 91.50 0.50 3984.90 2759.21 -3476.44 0.00 0.00 3107.48 MPU I-24 wp05 tgt04
16 7758.75 81.74 2.99 4005.72 3111.40 -3465.75 2.85 165.76 3456.63
17 7876.49 81.74 2.99 4022.64 3227.76 -3459.67 0.00 0.00 3571.71
18 8271.70 93.00 2.80 4040.75 3621.41 -3439.76 2.85 -0.98 3961.12
19 8421.70 93.00 2.80 4032.90 3771.02 -3432.45 0.00 0.00 4109.15 MPU I-24 wp05 tgt06
20 8796.31 90.91 12.89 4020.09 4141.41 -3381.38 2.75 101.51 4472.17
21 8877.78 90.91 12.89 4018.80 4220.82 -3363.20 0.00 0.00 4549.25
22 8983.56 88.00 12.90 4019.81 4323.91 -3339.60 2.75 179.88 4649.31
23 9043.56 88.00 12.90 4021.90 4382.36 -3326.21 0.00 0.00 4706.04 MPU I-24 wp05 tgt08
24 9208.32 85.19 9.34 4031.69 4543.70 -3294.49 2.75 -128.49 4863.18
25 9293.38 85.19 9.34 4038.83 4627.33 -3280.73 0.00 0.00 4944.92
26 9450.36 89.50 9.50 4046.11 4781.99 -3255.07 2.75 2.10 5096.05
27 9770.36 89.50 9.50 4048.90 5097.59 -3202.25 0.00 0.00 5404.40 MPU I-24 wp05 tgt10
28 9865.91 86.90 9.91 4051.90 5191.72 -3186.15 2.75 171.01 5496.33
29 10373.68 86.90 9.91 4079.32 5691.19 -3098.88 0.00 0.00 5983.93
30 10428.06 88.40 9.90 4081.54 5744.71 -3089.54 2.75 -0.43 6036.18
31 10978.06 88.40 9.90 4096.90 6286.31 -2995.01 0.00 0.00 6564.93 MPU I-24 wp05 tgt12
32 11053.47 89.43 11.70 4098.33 6360.36 -2980.89 2.75 60.20 6637.10
33 11961.08 89.43 11.70 4107.34 7249.07 -2796.85 0.00 0.00 7501.71
34 11968.75 89.50 11.50 4107.41 7256.58 -2795.31 2.75 -70.96 7509.02
35 12368.75 89.50 11.50 4110.90 7648.54 -2715.57 0.00 0.00 7890.49 MPU I-24 wp05 tgt14
36 12448.34 87.52 11.28 4112.97 7726.53 -2699.85 2.50 -173.64 7966.42
37 12767.83 87.52 11.28 4126.78 8039.55 -2637.42 0.00 0.00 8271.20
38 12847.41 89.50 11.50 4128.85 8117.55 -2621.71 2.50 6.36 8347.12
39 13197.41 89.50 11.50 4131.90 8460.51 -2551.93 0.00 0.00 8680.91 MPU I-24 wp05 tgt16
40 13207.88 89.44 11.78 4132.00 8470.76 -2549.82 2.75 102.47 8690.88
41 14697.95 89.44 11.78 4146.62 9929.36 -2245.61 0.00 0.00 10109.70
42 14717.54 88.90 11.75 4146.90 9948.54 -2241.61 2.75 -176.70 10128.36 MPU I-24 wp05 tgt18
43 14767.61 89.34 12.92 4147.67 9997.45 -2230.92 2.50 69.49 10175.88
44 15480.72 89.34 12.92 4155.90 10692.46 -2071.45 0.00 0.00 10850.41 MPU I-24 wp05 tgt19
45 15580.63 87.25 11.14 4158.88 10790.11 -2050.64 2.75 -139.56 10945.36
46 16152.78 87.25 11.14 4186.34 11350.84 -1940.24 0.00 0.00 11491.47
47 16216.51 89.00 11.20 4188.43 11413.33 -1927.90 2.75 2.00 11552.33
48 16816.51 89.00 11.20 4198.90 12001.82 -1811.37 0.00 0.00 12125.41 MPU I-24 wp05 tgt21
49 16991.13 87.00 7.32 4205.00 12174.01 -1783.30 2.50 -117.34 12293.73
50 17714.39 87.00 7.32 4242.86 12890.39 -1691.30 0.00 0.00 12996.57
51 17715.10 87.00 7.30 4242.90 12891.09 -1691.21 2.50 -86.65 12997.26 MPU I-24 wp05 tgt23
52 17826.86 88.75 5.12 4247.05 13002.12 -1679.14 2.50 -51.37 13106.41
53 18541.29 88.75 5.12 4262.68 13713.53 -1615.43 0.00 0.00 13807.27
54 18552.47 89.00 5.00 4262.90 13724.66 -1614.45 2.50 -24.79 13818.24 MPU I-24 wp05 tgt25
55 18608.35 87.66 5.39 4264.53 13780.28 -1609.39 2.50 163.84 13873.02
56 18911.13 87.66 5.39 4276.90 14081.48 -1580.98 0.00 0.00 14169.59 MPU I-24 wp05 tgt26 Total Depth : 18911.13' MD, 4276.9
0
750
1500
2250
3000
3750
4500
5250
6000
6750
7500
8250
9000
9750
10500
11250
12000
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13500
14250
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-6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000
West(-)/East(+) (1500 usft/in)
MPU I-24 wp05 tgt25
MPU I-24 wp05 tgt26
MPU I-24 wp05 tgt23
MPU I-24 wp05 tgt22
MPU I-24 wp05 tgt21
MPU I-24 wp05 tgt20
MPU I-24 wp05 tgt19
MPU I-24 wp05 tgt18
MPU I-24 wp05 tgt17
MPU I-24 wp05 tgt16
MPU I-24 wp05 tgt15
MPU I-24 wp05 tgt14
MPU I-24 wp05 tgt13
MPU I-24 wp05 tgt12
MPU I-24 wp05 tgt11
MPU I-24 wp05 tgt10
MPU I-24 wp05 tgt09
MPU I-24 wp05 tgt24
MPU I-24 wp05 tgt08
MPU I-24 wp05 tgt07
MPU I-24 wp05 tgt06
MPU I-24 wp05 tgt05
MPU I-24 wp05 tgt04
MPU I-24 wp05 tgt03
MPU I-24 wp05 tgt02
MPU I-24 wp05 heel
9 5/8" x 12 1/4"
4 1/2" x 8 1/2"
5 0 010001500
1750
2000
2250
2500
2750
300035003750
400 0
4250
4277
MPU I-24 wp07
Start Dir 3º/100' : 250' MD, 250'TVD
End Dir : 650' MD, 647.08' TVD
Start Dir 4.25º/100' : 770' MD, 764.46'TVD
End Dir : 1770' MD, 1614.24' TVD
Start Dir 4º/100' : 3100' MD, 2469.15'TVD
End Dir : 3271.65' MD, 2576.09' TVD
Start Dir 4.5º/100' : 4507.85' MD, 3320.01'TVD
End Dir : 6176.95' MD, 3994.44' TVD
Start Dir 3º/100' : 6296.95' MD, 4004.9'TVD
End Dir : 6576.28' MD, 4012.35' TVD
Begin Geosteering
CASING DETAILS
TVD TVDSS MD Size Name
4011.54 3944.64 6600.00 9-5/8 9 5/8" x 12 1/4"
4276.40 4209.50 18899.00 4-1/2 4 1/2" x 8 1/2"
Project: Milne Point
Site: M Pt I Pad
Well: Plan: MPU I-24
Wellbore: MPU I-24
Plan: MPU I-24 wp07
WELL DETAILS: Plan: MPU I-24
33.20
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6009451.15 551540.09
70° 26' 11.6512 N 149° 34' 47.2244 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-24, True North
Vertical (TVD) Reference:MPU I-24 as staked @ 66.90usft
Measured Depth Reference:MPU I-24 as staked @ 66.90usft
Calculation Method:Minimum Curvature
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0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300 6650
Measured Depth (700 usft/in)
MPI-10
MPI-14
MPI-06
MPU I-31
MPU I-38MPI-04AL1
MPI-04
MPI-04A
MPI-12L1
MPI-17
MPI-08
MPI-13
No-Go Zone - Stop Drilling
Collision Avoidance Required
Collision Risk Procedures Req.
WELL DETAILS:Plan: MPU I-24 NAD 1927 (NADCON CONUS)Alaska Zone 04
33.20
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6009451.15 551540.09 70° 26' 11.6512 N 149° 34' 47.2244 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-24, True North
Vertical (TVD) Reference: MPU I-24 as staked @ 66.90usft
Measured Depth Reference:MPU I-24 as staked @ 66.90usft
Calculation Method: Minimum Curvature
SURVEY PROGRAM
Date: 2020-06-17T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
33.70 900.00 MPU I-24 wp07 (MPU I-24) GYD_Quest GWD
900.00 6600.00 MPU I-24 wp07 (MPU I-24) 3_MWD+IFR2+MS+Sag
6600.00 18911.13 MPU I-24 wp07 (MPU I-24) 3_MWD+IFR2+MS+Sag
0.00
30.00
60.00
90.00
120.00
150.00
180.00
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0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300 6650
Measured Depth (700 usft/in)
MPI-03
MPU I-22 wp05
MPU I-29
MPI-10
MPU I-23 wp06
MPU I-32
MPI-05
MPI-01
MPU I-26 wp08
MPI-06
MPI-02
MPU I-31
MPU I-40
MPU I-38
MPU I-39i
MPI-04
MPI-07
MPU I-36
MPI-11
MPU I-30i
MPI-12
MPI-08
MPI-09
MPU I-37i
NO GLOBAL FILTER: Using user defined selection & filtering criteria
33.70 To 18911.66
Project: Milne Point
Site: M Pt I Pad
Well: Plan: MPU I-24
Wellbore: MPU I-24
Plan: MPU I-24 wp07
Ladder / S.F. Plots
1 of 2
CASING DETAILS
TVD TVDSS MD Size Name
4011.54 3944.64 6600.00 9-5/8 9 5/8" x 12 1/4"
4276.40 4209.50 18899.00 4-1/2 4 1/2" x 8 1/2"
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6500 7150 7800 8450 9100 9750 10400 11050 11700 12350 13000 13650 14300 14950 15600 16250 16900 17550 18200 18850
Measured Depth (1300 usft/in)
MPJ-15
MPU I-25 wp09
MPU I-23 wp06
MPU I-33
MPU I-32
MPJ-08A
MPJ-08 MPU I-26 wp08
MPJ-19
MPJ-26L1
MPJ-26
MPU I-31
MPJ-21 MPU I-38
MPU I-39i
MPJ-18
MPU I-30i
MPJ-09
No-Go Zone - Stop Drilling
Collision Avoidance Required
Collision Risk Procedures Req.
WELL DETAILS:Plan: MPU I-24 NAD 1927 (NADCON CONUS)Alaska Zone 04
33.20
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6009451.15 551540.09 70° 26' 11.6512 N 149° 34' 47.2244 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPU I-24, True North
Vertical (TVD) Reference: MPU I-24 as staked @ 66.90usft
Measured Depth Reference:MPU I-24 as staked @ 66.90usft
Calculation Method: Minimum Curvature
SURVEY PROGRAM
Date: 2020-06-17T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
33.70 900.00 MPU I-24 wp07 (MPU I-24) GYD_Quest GWD
900.00 6600.00 MPU I-24 wp07 (MPU I-24) 3_MWD+IFR2+MS+Sag
6600.00 18911.13 MPU I-24 wp07 (MPU I-24) 3_MWD+IFR2+MS+Sag
0.00
30.00
60.00
90.00
120.00
150.00
180.00
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6500 7150 7800 8450 9100 9750 10400 11050 11700 12350 13000 13650 14300 14950 15600 16250 16900 17550 18200 18850
Measured Depth (1300 usft/in)
MPU I-31
MPU I-31
MPJ-09A
NO GLOBAL FILTER: Using user defined selection & filtering criteria
33.70 To 18911.66
Project: Milne Point
Site: M Pt I Pad
Well: Plan: MPU I-24
Wellbore: MPU I-24
Plan: MPU I-24 wp07
Ladder / S.F. Plots
2 of 2
CASING DETAILS
TVD TVDSS MD Size Name
4011.54 3944.64 6600.00 9-5/8 9 5/8" x 12 1/4"
4276.40 4209.50 18899.00 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.
MILNE POINT
MPU I-24
SCHRADER BLUFF OIL POOL
224-001
X
WELL PERMIT CHECKLIST
Company Hilcorp Alaska, LLC
Well Name:MILNE PT UNIT I-24
Initial Class/Type DEV / PEND GeoArea 890 Unit 11328 On/Off Shore On
Program DEVField & Pool Well bore seg
Annular DisposalPTD#:2240010
MILNE POINT, SCHRADER BLFF OIL - 525140
NA1 Permit fee attached
Yes ADL025906, ADL025517, and ADL0255152 Lease number appropriate
Yes3 Unique well name and number
Yes MILNE POINT, SCHRADER BLFF OIL - 525140 - governed by 477, 477.0054 Well located in a defined pool
Yes5 Well located proper distance from drilling unit boundary
NA6 Well located proper distance from other wells
Yes7 Sufficient acreage available in drilling unit
Yes8 If deviated, is wellbore plat included
Yes9 Operator only affected party
Yes10 Operator has appropriate bond in force
Yes11 Permit can be issued without conservation order
Yes12 Permit can be issued without administrative approval
Yes13 Can permit be approved before 15-day wait
NA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For serv
NA15 All wells within 1/4 mile area of review identified (For service well only)
NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)
NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)
Yes 20" 129.5# X-52 driven to 150'18 Conductor string provided
Yes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir19 Surface casing protects all known USDWs
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.20 CMT vol adequate to circulate on conductor & surf csg
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.21 CMT vol adequate to tie-in long string to surf csg
Yes 9-5/8" fully cemented from reservoir to surface. Two stage cement job through ported collar.22 CMT will cover all known productive horizons
Yes 9-5/8" L-80 47# to BOPF, 9-5/8" L-80 40 to SB reservoir23 Casing designs adequate for C, T, B & permafrost
Yes Doyon 14 has adequate tankage and good trucking support24 Adequate tankage or reserve pit
NA This is a grassroots well.25 If a re-drill, has a 10-403 for abandonment been approved
Yes Halliburton collision scan identifies 1 close approach to a producing well near TD. Pressures similar.26 Adequate wellbore separation proposed
Yes 16" Diverter27 If diverter required, does it meet regulations
Yes All fluids overbalanced to expected pore pressure.28 Drilling fluid program schematic & equip list adequate
Yes 1 annular, 3 ram stack tested to 3000 psi.29 BOPEs, do they meet regulation
Yes 13-5/8" , 5000 psi stack tested to 3000 psi.30 BOPE press rating appropriate; test to (put psig in comments)
Yes 1 manual and 1 remote hydraulic choke.31 Choke manifold complies w/API RP-53 (May 84)
Yes32 Work will occur without operation shutdown
No33 Is presence of H2S gas probable
NA This is a development well.34 Mechanical condition of wells within AOR verified (For service well only)
No H2S has been measured in MPU I-04A (36 ppm in 2012)35 Permit can be issued w/o hydrogen sulfide measures
Yes Reservoir anticipated to be normally pressured (8.46 ppg EMW). Could encounter pressures from offset injectors36 Data presented on potential overpressure zones
NA37 Seismic analysis of shallow gas zones
NA38 Seabed condition survey (if off-shore)
NA39 Contact name/phone for weekly progress reports [exploratory only]
Appr
ADD
Date
1/26/2024
Appr
MGR
Date
1/17/2024
Appr
ADD
Date
1/26/2024
Administration
Engineering
Geology
Geologic
Commissioner:Date:Engineering
Commissioner:Date Public
Commissioner Date There are ten planned fault crossings for I-24.
*&: JLC 1/29/2024
