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1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Change Approved Program
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ESP Swap
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address: Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Yes No
9. Property Designation (Lease Number): 10. Field:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD):
13,281'N/A
Casing Collapse
Conductor 1,130psi
Surface 4,760psi
Production 5,410psi
Liner 10,540psi
Liner 7,820psi
Liner 10,570psi
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:303-906-5178
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
MILNE PT UNIT L-13A
MILNE POINT KUPARUK RIVER OIL N/A
7,190' 13,252' 7,192' 1,484 N/A
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
Hilcorp Alaska LLC
C.O. 816
AOGCC USE ONLY
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft):
10,390'
7,203'
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0025509
223-017
3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-22335-01-00
Length Size
Proposed Pools:
80' 80'
TVD Burst
50' 13-3/8"
9-5/8"
7"
MD
3,730psi
6,870psi
7,240psi
4,409'
7,095'10,535'
ryan.lewis@hilcorp.com
11,170psi2,257' 13,281'2-7/8"
4-1/2"
Perforation Depth MD (ft):
See SchematicSee Schematic 12.6# / L-80 / EUE 8rd
6,057'
10,508'
6,086'
7" x 2-7/8" Viking & 7" x 4-1/2"Tripoint Hydrotrieve and N/A 2,990 MD/ 2,493 TVD & 10,237 MD/ 6,912 TVD and N/A
Ryan Lewis
8,620psi
7,069' 10,160psi154'
9/16/2025
6.5# / L-60 / EUE 10,136'
531'
10,493'
11,024'
7,190'
3-1/2"
3-1/4"
2-7/8"
B
No
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2025.08.28 14:52:35 -
08'00'
Taylor Wellman
(2143)
325-528
A.Dewhurst 09SEP25
MGR05SEP2025
By Grace Christianson (grace.christianson@alaska.gov) at 8:52 am, Aug 29, 2025
* BOPE test to 2000 psi. 24 hour notice to AOGCC for opportunity to witness.
10-404
DSR-9/10/25JLC 9/10/2025
Gregory C Wilson Digitally signed by Gregory C
Wilson
Date: 2025.09.10 14:09:53 -08'00'
09/10/25
RBDMS JSB 091125
Well: MPL-13A
PTD: 223-017
API: 50-029-22335-01-00
Well Name:MPL-13A API Number:50-029-22335-01-00
Current Status:Shut-in ESP Rig:ASR #1
Estimated Start Date:9/17/2024 Estimated Duration:6days
Regulatory Contact:Tom Fouts Permit to Drill Number:223-017
First Call Engineer:Ryan Lewis (303) 906-5178 (M)
Second Call Engineer:Taylor Wellman (907) 777-8449 (O) (907) 947-9533 (M)
Current Bottom Hole Pressure: 2160 psi @ 6,760’ TVD 8/9/2025 | 6.3 EMW, 6.5 KWF
Max Potential Surface Pressure: 1,484 psi Gas Column Gradient (0.1 psi/ft)
Max Angle: 54° Sail Angle from 8,520’ MD
Brief Well Summary:
MPU L-13 was originally drilled and completed as Kuparuk producer in 1993. The well was sidetracked with
CDR2 to access unswept oil to the North. The CTD lateral was lined with a 3-1/2” x 3-1/4” x 2-7/8” liner and
cemented isolating the parent well. The current ESP completion we lost the DH sensor after 4 months and the
ESP grounded electrically at 2 years.
Objectives:
Pull failed ESP completion and run new ESP completion.
Notes Regarding Wellbore Condition:
- 7” casing test to 3,500 psi on 3/14/2021. 8-year casing test not required.
Pre-Rig Procedure (Non Sundried Work)
Pumping & Well Support
1. Clear and level pad area in front of well. Spot rig mats and containment.
2. RD well house and flowlines. Clear and level area around well.
3. RU Little Red Services. RU reverse out skid and 500 barrel returns tank.
4. Pressure test lines to 3,000 psi.
5. Circulate at least one wellbore volume with produced water down tubing, taking returns up casing
to 500 barrel returns tank. Bullhead down tbg and IA taking returns to formation as needed to
establish and maintain a full column of produced water.
6. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR
arrival.
7. RD Little Red Services and reverse out skid.
8. Set BPV. ND tree. NU BOPE.
Brief RWO Procedure (Begin Sundried Work)
1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 barrel returns tank.
2. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing
and casing.
a. If needed, kill well with produced water prior to setting CTS.
Well: MPL-13A
PTD: 223-017
API: 50-029-22335-01-00
3. Test BOPE to 250 psi low/ 2,000 psi high. Test annular to 250 psi low/ 2,000 psi high (hold each
ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests.
a. Perform test per ASR 1 BOP Test Procedure
b. Notify AOGCC 24 hours in advance of BOP test.
c. Confirm test pressures per the Sundry conditions of approval.
d. Test VBR rams on 2-7/8” test joint.
e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test.
4. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the
returns tank. Kill well with produced water as needed. Pull BPV.
a. If indications show pressure underneath BPV, lubricate out BPV.
5. Call out Baker for ESP pull.
6. RU spoolers to handle ESP cable.
7. MU landing joint or spear, BOLDS, PU on the tubing hanger.
a. Tubing hanger is WKM TDF 10.380" x 2-7/8", 2 7/8 EUE Top and Bottom
b. 2021 tubing PU weight on ASR #1 recorded as 68kip. Slack off weight recorded as 38 kip.
c. 2-7/8” L-80 EUE yield is 144 kip.
8. Confirm hanger free, lay down tubing hanger.
9. POOH and lay down the 2-7/8” tubing.
a. Kick out jt 31-105. Re-use the rest of the tubing for the lower portion of L-80.
b. Keep ported discharge head and centralizer for future use.
c. Note any sand or scale inside or on the outside of the ESP on the morning report.
d. Recorded Clamp Totals:
i. Canon Clamps: 176
ii. 2-7/8" half clamp: 3
iii. Protectolizers: 6
iv. Flat Guards: 2
10. Check the vent valves, if they are Viking junk them if they are Weatherford keep to redress them.
11. Lay Down ESP.
12. RIH to +-10,135’ with ESP completion, used 2-7/8” 6.5# L-80 and 5,000’ of 2-7/8” 6.5# Cr13 and
obtain string weights.
a. Check electrical continuity every 1000’.
b. Note PU and SO weights on tally.
c. Install ESP clamps per Baker, and cross coupling clamps every other joint
Nom. Size Length Item Lb/ft Material Notes
5.85 2 Centralizer 4
4.5 2 Intake Sensor 30
5.62 34 Motor - 150HP 80
5.2 7 Lower Tandem Seal 38
5.2 7 Upper Tandem Seal 38
Assure no pressure under BPV if dry rodding.
-mgr
Well: MPL-13A
PTD: 223-017
API: 50-029-22335-01-00
5.2 8 Gas Separator 52
4 21 Pumps – GINPSHH 45
4 21 Pumps – Flex7ER 45
4 21 Pumps – Flex7ER 45
1 Ported Discharge Head 13 L-80
2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" 30 2-7/8" EUE 8rd L-80 6.5 L-80
2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8"2 XN-nipple 2.313" / 2.205" No-Go 6.5 L-80
2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" 60 2-7/8" EUE 8rd Jt 6.5 L-80
2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8"8 2-7/8" x 1" GLM, DV installed 6.5 L-80
2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" +-4,850 2-7/8" EUE 8rd Jt 6.5 L-80
2-7/8" 10 2-7/8" EUE 8rd pin x JFE Bear box Jt 6.5 9CR
2-7/8" +-4,800 2-7/8" JFE Bear Jt 6.5 13CR
2-7/8"10 2-7/8" JFE Bear Pup Jt 6.5 13CR
2-7/8"8 2-7/8" x 1" GLM, 1/4" OV 6.5 13CR ~200 MD
2-7/8"10 2-7/8" JFE Bear Pup Jt 6.5 13CR
2-7/8" 150 2-7/8" JFE Bear Jt 6.5 13CR
2-7/8" 10 Space out pup 6.5 13CR
2-7/8" 30 Tubing Hanger with full joint 6.5 13CR
13. Land tubing hanger. Use extra caution to not damage cable.
14. Lay down landing joint.
15. Set BPV.
16. RDMO ASR.
Post-Rig Procedure:
Well Support
1. RD mud boat. RD BOPE house. Move to next well location.
2. RU crane. ND BOPE, set CTS plug, and NU tree.
3. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV.
4. RD crane. Move 500 bbl returns tank and rig mats to next well location.
5. RU well house and flowlines.
Attachments:
1. Current Wellbore Schematic
2. Proposed Wellbore Schematic
3. Double BOPE Schematic
_____________________________________________________________________________________
Revised By TDF: 8/8/2025
SCHEMATIC
Milne Point Unit
Well: MPU L-13A
Last Completed: 8/11/2023
PTD: 223-017
TD =13,281’ (MD) / TD =7,190’(TVD)
8 & 9
20”
Orig. KB Elev.: 51’/ Orig. GL Elev.: 17.0’
7”
10 & 11
13 & 14
12
15
20
22 3-1/2” @
10,491’
2
3
9-5/8”
1
4
5
6
7
16
2-7/8”
Tubing Cut &
Pulled @
10,195’
PBTD =13,252’(MD) / PBTD = 7,192’(TVD)
Whipstock
set @
10,530’ Top
of Window
@ 10,535’
3-1/4” @
11,023’
21
23
Top of
Deployment
Sleeve /
Cement
@ 10,339’
17
18
19
OPEN HOLE / CEMENT DETAIL
26” 300 sx of Arctic set I
12-1/4” 1780 sx of Arctic set III, 300 sx Class G
8-1/2” 325 sx Class G”
4-1/4” 179 sx Classs G
WELL INCLINATION DETAIL
KOP @ 10535’
90 deg Hole Angle = 11,251’ MD, Max Angle = 99
TREE & WELLHEAD
Tree 2-9/16”–5M WKM
Wellhead 11” 5M WKM, w/2-7/8” x 11” Tubing Hanger,
2-7/8” EUE 8rd Threads, 2.5” “H” BPV profile.
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
13-3/8" Conductor 54.5 / K-55 / BTRC 12.415 Surface 80'
9-5/8" Surface 47 / N-80 / BTRS 8.681 Surface 6,086’
7" Production 26 / L-80 / BTRC 6.276 Surface 10,535’
3-1/2” Liner 9.2# / L-80 / ST-L 2.992 10,339’ 10,493’
3-1/4” Liner 6.6# / L-80 / TCII 2.850 10,493’ 11,024’
2-7/8” Liner 6.5# / L-80 / ST-L 2.441 11,024’ 13,281’
TUBING DETAIL
2-7/8” Tubing 6.5 / L-80 / EUE 2.441 Surface 10,136’
4-1/2" Tubing 12.6 / L-80 / EUE 8rd 3.883 10,195’ 10,390’
JEWELRY DETAIL
No Depth Item
1 164’ 2-7/8” x 1” GLM, Side Pocket DPSOV
2 2,929’ 2-7/8” x 1” GLM, Side Pocket w/ Dummy
3 2,990’ Viking Packer
4 3,045’ 2-7/8” x 1” GLM, Side Pocket w/ Dummy & BK Latch
5 3,103’ X-Nipple ID = 2.813”
6 9,953’ 2-7/8” x 1” GLM, Side Pocket w/ Dummy & BK Latch
7 10,007’ XN-Nipple ID = 2.205” No-Go
8 10,055’ Discharge Head
9 10,056’ Zenith Ported Sub
10 10,057’ Pump #1
11 10,085’ Pump #2
12 10,095’ Gas Separator
13 10,101’ Upper Tandem Seal
14 10,108’ Lower Tandem Seal
15 10,115’ Motor
16 10,134’ Centralizer –Bottom @10,136’
17 10,237’ 7”x4-1/2” Tripoint Hydratrieve Packer (40k over shear)
18 10,297’ X Nipple –ID=3.813”
19 10,339’ 3-1/2” Deployment Sleeve
20 10,349’ WLEG Bottom @ 10,390’ (Behind 3-1/2” CTD Liner)
21 10,364’ 2.813” X Nipple
22 10,491’ 3-1/2” xo 3-1/4”
23 11,023’ 3-1/4” xo 2-7/8”
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kuparuk
11,102’ 11,602’ 7,207’ 7,206’ 500 6/24/2023 Open
12,235’ 12,405’ 7,227’ 7,222’ 170 6/23/2023 Open
12,600’ 12,835’ 7,217’ 7,204’ 235 6/23/2023 Open
12,930’ 13,233’ 7,199’ 7,192’ 303 6/23/2023 Open
GENERAL WELL INFO
API: 50-029-22335-01-00
Drilled and Cased by Nabors 22E - 5/16/1993
A Sidetrack: 6/6/2023
ESP Install: 8/11/2023
_____________________________________________________________________________________
Revised By TDF: 8/19/2025
PROPOSED
Milne Point Unit
Well: MPU L-13A
Last Completed: 8/11/2023
PTD: 223-017
TD =13,281’ (MD) / TD =7,190’(TVD)
20”
Orig. KB Elev.: 51’/ Orig. GL Elev.: 17.0’
7”
5, 6 & 7
9 & 10
11
8
17
19 3-1/2” @
10,491’
9-5/8”
1
4
2
3
12 & 13
2-7/8”
Tubing Cut &
Pulled @
10,195’
PBTD =13,252’(MD) / PBTD = 7,192’(TVD)
Whipstock
set @
10,530’ Top
of Window
@ 10,535’
3-1/4” @
11,023’
18
20
Top of
Deployment
Sleeve /
Cement
@ 10,339’
14
15
16
OPEN HOLE / CEMENT DETAIL
26” 300 sx of Arctic set I
12-1/4” 1780 sx of Arctic set III, 300 sx Class G
8-1/2” 325 sx Class G”
4-1/4” 179 sx Classs G
WELL INCLINATION DETAIL
KOP @ 10535’
90 deg Hole Angle = 11,251’ MD, Max Angle = 99
TREE & WELLHEAD
Tree 2-9/16”–5M WKM
Wellhead 11” 5M WKM, w/2-7/8” x 11” Tubing Hanger,
2-7/8” EUE 8rd Threads, 2.5” “H” BPV profile.
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
13-3/8" Conductor 54.5 / K-55 / BTRC 12.415 Surface 80'
9-5/8" Surface 47 / N-80 / BTRS 8.681 Surface 6,086’
7" Production 26 / L-80 / BTRC 6.276 Surface 10,535’
3-1/2” Liner 9.2# / L-80 / ST-L 2.992 10,339’ 10,493’
3-1/4” Liner 6.6# / L-80 / TCII 2.850 10,493’ 11,024’
2-7/8” Liner 6.5# / L-80 / ST-L 2.441 11,024’ 13,281’
TUBING DETAIL
2-7/8” Tubing 6.5 / 13CR / EUE 2.441 Surface ±XX,XXX’
2-7/8” Tubing 6.5 / L-80 / EUE 2.441 ±XX,XXX’ ±XX,XXX’
4-1/2" Tubing 12.6 / L-80 / EUE 8rd 3.883 10,195’ 10,390’
JEWELRY DETAIL
No Depth Item
1 ±XXX’ 2-7/8” x 1” GLM, ¼” OV
2 ±X,XXX’ 2-7/8” x 1” GLM, DV Installed
3 ±X,XXX’ XN-Nipple 2.313 ID / 2.205” No-Go
4 ±X,XXX’ Ported Discharge Head:
5 ±XX,XXX’ Pump #3:
6 ±XX,XXX’ Pump #2:
7 ±XX,XXX’ Pump #1:
8 ±XX,XXX’ Gas Separator:
9 ±XX,XXX’ Upper Tandem Seal:
10 ±XX,XXX’ Lower Tandem Seal:
11 ±XX,XXX’ Motor:
12 ±XX,XXX’ Intake Sensor:
13 ±XX,XXX’ Centralizer –Bottom @ ±XX,XXX’
14 10,237’ 7”x4-1/2” Tripoint Hydratrieve Packer (40k over shear)
15 10,297’ X Nipple –ID=3.813”
16 10,339’ 3-1/2” Deployment Sleeve
17 10,349’ WLEG Bottom @ 10,390’ (Behind 3-1/2” CTD Liner)
18 10,364’ 2.813” X Nipple
19 10,491’ 3-1/2” xo 3-1/4”
20 11,023’ 3-1/4” xo 2-7/8”
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kuparuk
11,102’ 11,602’ 7,207’ 7,206’ 500 6/24/2023 Open
12,235’ 12,405’ 7,227’ 7,222’ 170 6/23/2023 Open
12,600’ 12,835’ 7,217’ 7,204’ 235 6/23/2023 Open
12,930’ 13,233’ 7,199’ 7,192’ 303 6/23/2023 Open
GENERAL WELL INFO
API: 50-029-22335-01-00
Drilled and Cased by Nabors 22E - 5/16/1993
A Sidetrack: 6/6/2023
ESP Install: 8/11/2023
Milne Point
ASR Rig 1 BOPE
2025
11” BOPE
4.48'
4.54'
2.00'
CIW-U
4.30'
Hydril GK
11" - 5000
Blin d11'’- 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
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: 08/26/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250826
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BCU 24 50133206390000 214112 7/15/2025 AK E-LINE PPROF
T40803
BR 11-86 50733207370000 225057 7/30/2025 AK E-LINE Hoist
T40804
BR 11-86 50733207370000 225057 8/4/2025 AK E-LINE Perf
T40804
BR 11-86 50733207370000 225057 8/9/2025 AK E-LINE Perf
T40804
BRU 212-35T 50283200970000 198161 8/4/2025 AK E-LINE Perf
T40805
BRU 212-35T 50283200970000 198161 6/28/2025 AK E-LINE Perf
T40805
BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE CBL
T40806
BRU 224-34T 50283202050000 225044 8/5/2025 AK E-LINE CBL
T40806
BRU 224-34T 50283202050000 225044 7/27/2025 AK E-LINE CBL
T40806
BRU 224-34T 50283202050000 225044 8/2/2025 AK E-LINE Punch
T40806
KTU 43-6XRD2 50133203280200 205117 7/26/2025 AK E-LINE Perf
T40807
MPL-13A 50029223350100 223017 8/10/2025 READ CaliperSurvey
T40808
NCIU A-21 50883201990000 224086 1/14/2025 AK E-LINE Plug/Perf
T40809
ODSN-16 50703206200000 210053 8/10/2025 READ CaliperSurvey
T40810
PBU 01-30A 50029216060100 225050 8/7/2025 HALLIBURTON RBT-COILFLAG
T40811
PBU 06-11A 50029204280100 225042 7/13/2025 HALLIBURTON RBT-COILFLAG
T40812
PBU 11-37A 50029227160100 219062 7/27/2025 HALLIBURTON RBT
T40813
PBU 14-43A 50029222960100 225041 7/31/2025 HALLIBURTON RBT-COILFLAG
T40814
PBU F-06B 50029200970200 225054 8/5/2025 HALLIBURTON RBT-COILFLAG
T40815
PBU L1-10A 50029213400100 225032 8/1/2025 HALLIBURTON RBT-COILFLAG
T40816
PCU 02A 50283200220100 224110 7/27/2025 AK E-LINE Perf
T40817
SRU 241-33 50133206630000 217047 7/28/2025 AK E-LINE Perf
T40818
WhiskeyGulch 1 50231200790000 221046 6/18/2025 AK E-LINE Packer
T40819
Please include current contact information if different from above.
T40808MPL-13A 50029223350100 223017 8/10/2025 READ CaliperSurvey
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.08.27 08:12:23 -08'00'
3-1/2"x3-1/4"
By Grace Christianson at 1:52 pm, Aug 25, 2023
Completed
6/23/2023
JSB
RBDMS JSB 083023
G
DSR-9/12/23
Drilling Manager
08/24/23
Monty M
Myers
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2023.08.25 08:40:17 -
08'00'
Taylor Wellman
(2143)
_____________________________________________________________________________________
Revised By JNL: 8/18/2023
SCHEMATIC
Milne Point Unit
Well: MPU L-13A
Last Completed: 8/11/2023
PTD: 223-017
2-7/8
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
13-3/8" Conductor 54.5 / K-55 / BTRC 12.415 Surface 80'
9-5/8" Surface 47 / N-80 / BTRS 8.681 Surface 6,086’
7" Production 26 / L-80 / BTRC 6.276 Surface 10,535’
3-1/2”x3-1/4”x2-7/8” Liner 9.3 x 6.6 x 6.5 / L-80 / STL x TCII 2.441 10,339’ 13,281’
TUBING DETAIL
2-7/8” Tubing 6.5 / L-80 / EUE 2.441 Surface 10,136’
4-1/2" Tubing 12.6 / L-80 / EUE 8rd 3.883 10,195’ 10,390’
JEWELRY DETAIL
No Depth Item
1 164’ 2-7/8” x 1” GLM, Side Pocket DPSOV
2 2,929’ 2-7/8” x 1” GLM, Side Pocket w/ Dummy
3 2,990’ Viking Packer
4 3,045’ 2-7/8” x 1” GLM, Side Pocket w/ Dummy & BK Latch
5 3,103’ X-Nipple ID = 2.813”
6 9,953’ 2-7/8” x 1” GLM, Side Pocket w/ Dummy & BK Latch
7 10,007’ XN-Nipple ID = 2.205” No-Go
8 10,055’ Discharge Head
9 10,056’ Zenith Ported Sub
10 10,057’ Pump #1
11 10,085’ Pump #2
12 10,095’ Gas Separator
13 10,101’ Upper Tandem Seal
14 10,108’ Lower Tandem Seal
15 10,115’ Motor
16 10,134’ Centralizer – Bottom @10,136’
17 10,237’ 7”x4-1/2” Tripoint Hydratrieve Packer (40k over shear)
18 10,297’ X Nipple – ID=3.813”
19 10,339’ 3-1/2”Deployment Sleeve
20 10,349’ WLEG Bottom @ 10,390’ (Behind 3-1/2” CTD Liner)
21 10,364’ 2.813” X Nipple
22 10,491’ 3-1/2” xo 3-1/4”
23 11,023’ 3-1/4” xo 2-7/8”
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kuparuk
11,102’ 11,602’ 7,207’ 7,206’ 500 6/24/2023 Open
12,235’ 12,405’ 7,227’ 7,222’ 170 6/23/2023 Open
12,600’ 12,835’ 7,217’ 7,204’ 235 6/23/2023 Open
12,930’ 13,233’ 7,199’ 7,192’ 303 6/23/2023 Open
GENERAL WELL INFO
API: 50-029-22335-01-00
Drilled and Cased by Nabors 22E - 5/16/1993
A Sidetrack: 6/6/2023
ESP Install: 8/11/2023
TD =13,281’ (MD) / TD =7,190’(TVD)
8 &9
20”
Orig. KB Elev.:51’/ Orig. GL Elev.: 17.0’
7”
10
11
13 &14
12
15
20
22 3-1/2”@
10,491’
2
3
9-5/8”
1
4
5
6
7
16
2-7/8”
Tubing Cut &
Pulled @
10,195’
PBTD = 13,252’(MD) / PBTD =7,192’(TVD)
Whipstock
set @
10,530’ Top
of Window
@ 10,535’
3-1/4” @
11,023’
21
23
Top of
Deployment
Sleeve /
Cement
@ 10,339’
17
18
19
OPEN HOLE / CEMENT DETAIL
26” 300 sx of Arctic set I
12-1/4” 1780 sx of Arctic set III, 300 sx Class G
8-1/2” 325 sx Class G”
4-1/4” 179 sx Classs G
WELL INCLINATION DETAIL
KOP @ 10535’
90 deg Hole Angle = 11,251’ MD, Max Angle = 99
TREE & WELLHEAD
Tree 2-9/16” – 5M WKM
Wellhead 11” 5M WKM, w/ 2-7/8” x 11” Tubing Hanger, 2-7/8” EUE
8rd Threads, 2.5” “H” BPV profile.
Activity Date Ops Summary
5/24/2023 Remove jeeps. Set rig down at 13:00. Begin MIRU checklists. Leak tight test SV and MV with 600 psi well pressure. Remove tree cap, lower BOP stack onto tree
M/U flange bolts. Continue MIRU checklists. Boot e-line. Get on well fill reel forward 0.5 bpm pump 7 bbls MeOH ahead. Reverse circ slack into reel. Cable isn't
moving. Lift injector off and re-boot cable. Pump backwards 3.4 bpm cable is moving. Skid injector back and rig up hydraulic cutter. Cut 280' of CT. Install CT
connector. Pull test to 50k, good. Pump slack forward to re-head. Install BHI cable head.
5/25/2023 Fluid pack coil. PT Inner reel iron, Reel, CTC, UQC to 7K for 5 min. Good test. Stab on and pump slack forward for reel volume. Perform Initial BOPE test
Witnessed waived by AOGCC Sean Sullivan. Test 250 psi / 3500 psi. Test 1: Packoff, IRV, C7, C9, C10, C11 Pass. Test 2: Blind/shear, C15, R2, BL2 (R2 Fail /
Grease / Pass). Test 3: Annular (2-3/8"), TIW#1, B1, B4 Pass. Test 4: Upper 2-3/8" Pipe / Slip, TIW#2, B2, B3 Pass. Test 5: Lower 2-3/8" Pipe/ Slip, C5, C6, C8,
TV2 Pass. Test 6: Choke A, Choke C Pass. Test 7: C1, C4, TV1 Pass. Test 8: 3" Pipe/ Slip, C2, C3 Pass. Accumulator draw down. Tested gas alarms. Rig down
BOPE testing equipment. Remove test risers. Space out for drilling operations. Pressure test off drillers PDL and drilling risers to 3500 psi. Pass. Pressure test
driller PDL to 3500 psi. PT floats, good. Install IA, OA sensors. Load ODS PDL with BHI tools. M/U nozzle w/ stinger, get on well. Open well, 480 psi static. Pump
0.5 bpm = 560 psi. 1.1 bpm = 680 psi. 1.5 bpm = 820 psi climbs reduce rate1.4 bpm to stay < 1200 psi. Pump tbg volume = 160 bbls at 1.4 bpm. Shut MV bleed
off 700 psi. Close SSV. Need to use MV and SSV for deploy due to whipstock length. Skid injector back remove nozzle. Pressure Deploy whipstock. RIH BHA #1 -
whipstock. Verify EDC open. Set pump and slackoff trips close while RIH. Log tie-in from 10200' correct -11.5'. Up wt at 10330' is 51k. Drift down to 10650' prior to
CCL log (no DWOB in CCL mode). Clean pass, PU to 10400' switch to CCL mode log down. Our CCL matches program, no shift needed. RIH to set depth and PU
to just less than breakover. Close EDC. Shears 4000 psi. Slack off set 4.1k DWOB on it solid, good set. WS set with TOWS at 10530' at 0R orientation. PU and
open EDC, swap well to mud. POOH.
5/26/2023 Pooh. Mud Weight: 8.72 ppg in, 8.77 ppg out. Rate: 2.74 bpm in, 2.17 bpm out Window ECD 10.2. Pressure Un-Deploy whipstock setting BHA#1. Deploy window
milling BHA#2. Swap out flow sub. PT break. Pressure Deploy BHA#2. RIH with window milling BHA #2. Rate: 0.36 bpm in, 0.90 bpm out. Circ pressure: 1197 psi.
Mud Weight: 8.72 ppg in, 8.78 ppg out Window ECD: 10.22 ppg. Log down for tie-in from 10230' to 10288.11' MD (formation) with -14' correction. Dry tag
10537.96' . PU and establish parameters. Rate: 2.53 bpm in, 2.48 bpm out. Circ pressure: 2726 psi. Mud Weight: 8.72 ppg in, 8.78 ppg out Window ECD: 10.22
ppg. 10537 begin time milling window. Continue milling window. Pre-load DS PDL for next run while milling. Mill 2.4 / 2.3 bpm w/ 11.77# ECD WHP = 639 psi. 8.70
/ 8.76 ppg In / Out. String reamer has exited 10546' drill rathole to 10555'. Sample from 10555' is 10% formation. Pump 5 bbls lo-vis. Reaming passes 1 ft/min. 1st
up 90 psi motor work 10538.2'. 1st down 65 psi MW 10539.8'. 2nd up 60 psi MW 10538.0'. 2nd down 40 psi MW 10539.4. 3rd up 37 psi MW 10538.0'. Continue
reaming passes. 3rd down 30 psi MW 10539.5'. 4th up 35 psi MW 10537.6'. Dry drift is clean, tag 10555' end of rathole. PU above window and open EDC. POOH
pump 2.5 bpm keep 11.8# ECD at window. Tag stripper and space out. Undeploy BHA #2. Mill and reamer 3.80" Go / 3.79" NoGo. M/U nozzle, jet stack. Pressure
deploy BHA #3.
5/27/2023 Complete pressure deploy of BHA#3 (Build). RIH with 4.25 drilling BHA #3. Rate: 0.45 bpm in, 0.95 bpm out. Circ pressure: 1817psi. Mud Weight: 8.69 ppg in,
8.79 ppg out Window ECD: 11.8 ppg EMW. Log down for tie-in from 10230' to 10287.83' MD (formation) with -14 correction. Close EDC. 48K PUW 15K SOW.
Drill 4.25 build from 10555 MD to 10596'. Free spin: 3456 psi, 2.80 bpm. Rate: 2.80 bpm in, 2.72 bpm out. Circ pressure: 3456 to 3568 psi. Mud weight: 8.70 ppg
in, 8.78 ppg out, Window ECD: 11.82 ppg Wellhead pressure: 626 psi. ROP: 5-10 fph, WOB: 2.6 KLBS. Getting signs of bit balling. Mix drillzone / screenkleen
pill. Pump 10 bbl LoVis Drillzone / Screenkleen pill. Pick up off bottom when pill coming out. Drill 4.25 build from 10596'. Free spin: 3456 psi, 2.80 bpm. Rate: 2.80
bpm in, 2.72 bpm out. Circ pressure: 3456 to 3780 psi. Mud weight: 8.70 ppg in, 8.76 ppg out, Window ECD: 11.78 ppg Wellhead pressure: 647 psi. ROP: 45 - 70
fph, WOB: 1.7 - 2.8 KLBS. Drill 4.25 build from 10780'. Rate: 2.80 bpm in, 2.74 bpm out. Circ pressure: 3500 to 3730 psi. Mud weight: 8.74 ppg in, 8.80 ppg out,
Window ECD: 11.81 ppg Wellhead pressure: 640 psi. ROP: 40 - 60 fph, WOB: 1.7 - 3.4 KLBS. 100' wiper at 10800' clean up/down. 10840' 5 bbls lo/hi vis. Drill to
TD of build 10860' POOH. Jog below window pull through 0.5 bpm clean. Jog above window, open EDC. Pump 3.5 bpm / 3900 psi keep 11.8# ECD at window.
Tag up and space out. Undeploy BHA #3 - Build. Deploy BHA #4 - Lateral w/ 1.1 deg AKO and Agitator. RIH BHA #4 - Lateral 1.1 deg BHA w/ Agitator. Shallow hole
test agitator is good. Tie-in depth from 10230' correct -13.5'. Close EDC near window. Pass window no issues min rate to bottom. Drill 4.25" from 10860'. Free spin:
3880 psi, 2.83 bpm. Rate: 2.82 bpm in, 2.81 bpm out. Circ pressure: 3880 to 4050 psi. Mud weight: 8.78 ppg in, 8.84 ppg out, Window ECD: 11.84 ppg w/644 psi
WHP. ROP: 70 - 90 ft/hr w/ 2-3k DWOB. 10960', 5 bbls lo/hi vis.
5/28/2023 Drill 4.25" from 10988' to 11133' MD. Free spin: 3877 psi, 2.82 bpm. Rate: 2.82 bpm in, 2.79 bpm out. Circ pressure: 3877 to 3891 psi. Mud weight: 8.79 ppg in,
8.88 ppg out, Window ECD: 11.79 ppg w/ 623 psi WHP. ROP: 15 - 90 ft/hr w/ 2-3k DWOB. Drill 4.25" from 11133' MD to 11300' MD. Free spin: 3986 psi, 2.81
bpm (776 psi diff). Rate: 2.82 bpm in, 2.79 bpm out. Circ pressure: 3986 to 4063 psi. Mud weight: 8.79 ppg in, 8.93 ppg out, Window ECD: 11.81 ppg w/ 603 psi
WHP. ROP: 40- 90 ft/hr w/ 2-3k DWOB. Pump 5/5 sweep. Long wiper. Perform long wiper trip to window from 11300 MD. Rate: 2.78 bpm in, 2.61bpm out. Circ
pressure: 4143 psi. Window ECD: 11.82 ppg w/ 608 psi WHP. Perform 100' jog at 10620' MD. Drop rate to minimum coming thru B-shale / Silt and window. Clean
pass. Open EDC. Jet 7" and chase up to tie in. - Log tie in from 10220' to 10252.04 with a +3' correction. PUH to 10050'. Log CCL down to 10500' for liner top
placement. Close EDC. Run through window and B Silt / Shale without issue. Run to bottom. Drill 4.25" from 11300' MD to 11460' MD. Free spin: 4025 psi, 2.83
bpm (833 psi diff). Rate: 2.83 bpm in, 2.79 bpm out. Circ pressure: 4025 to 4227 psi. Mud weight: 8.81 ppg in, 8.91 ppg out, Window ECD: 11.85 ppg w/ 594 psi
WHP. ROP: 50 ft/hr w/ 2-3k DWOB. 150 BHA wiper. Drill 4.25" from 11460' MD. Free spin: 4105 psi, 2.83 bpm (834 psi diff). Rate: 2.83 bpm in, 2.79 bpm out. Circ
pressure: 4105 to 4227 psi. Mud weight: 8.81 ppg in, 8.90 ppg out, Window ECD: 11.84 ppg w/ 592 psi WHP. ROP: 50-100 ft/hr w/ 2-3k DWOB. Drill 4.25" from
11540' MD. Rate: 2.82 bpm in, 2.82 bpm out. Circ pressure: 4100 - 4250 psi. Mud weight: 8.82 ppg in, 8.94 ppg out, Window ECD: 11.84 ppg w/ 558 psi WHP.
ROP: 50-100 ft/hr w/ 2-3k DWOB. 11580', 11620', 11740' 5 bbls lo/hi vis. 11600' 150' wiper clean up/down. Wiper trip to window from 11750' clean pass. Jog
below window reduce rate in B-shale pull through -1.4k DWOB at 10543'. Jog above window at full rate then open EDC / 3.3 bpm. Tie-in depth correct +5'. Close
EDC. RIH, set down in window 10545' once PU and go through. RIH to bottom clean 0.5 bpm. Drill 4.25" from 11750' MD. Rate: 2.83 bpm in, 2.81 bpm out. Circ
pressure: 4150 - 4350 psi. Mud weight: 8.84 ppg in, 8.92 ppg out, Window ECD: 11.81 ppg w/ 481 psi WHP. ROP: 80-100 ft/hr w/ 2-3k DWOB.
50-029-22335-01-00API #:
Well Name:
Field:
County/State:
MP L-13A
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
5/26/2023Spud Date:
5/29/2023 Drill 4.25" from 11879' to 12200' MD. Free Spin: 4250 psi @ 2.84 bpm (782 psi diff). Rate: 2.84 bpm in, 2.81 bpm out. Circ pressure: 4250 - 4293 psi. Mud weight:
8.87 ppg in, 8.97 ppg out, Window ECD: 11.88 ppg w/ 457 psi WHP. ROP: 80-100 ft/hr w/ 2-3k DWOB. Perform long wiper trip to window from 12200 MD. Rate:
2.80 bpm in, 2.67 bpm out. Circ pressure: 4376 psi. Perform jog from 10630' to 10730' MD. Drop pump rate to minimum. Pull through B silt / shale / window. Jet 7"
with open EDC. Log tie in with +4' correction. Attempt to get through window. Oreint both sides of as drilled. No luck. Pooh for window cleanout assembly. Pooh.
Rate: 3.30 bpm in, 2.78 bpm out. Circ pressure: 4063 psi. Mud weight: 8.91 ppg in, 8.98 ppg out, Window ECD: 11.81 ppg. Perform jog at surface. Close EDC.
Shallow test agitator. Good Tag up and space out. Pressure un-deploy lateral BHA. Inspect and secure inner reel iron. Deploy window cleanout BHA w/ D331 mill +
string reamer. RIH BHA #5 - window Cleanout w/ D-331 mill and reamer. Tie-in depth correct -14.5'. Close EDC. Ream down to 10550' 0.5 ft/min 0L TF. Up 0.5
ft/min 0L. Down 0.5 ft/min 0L - Not seeing any motor work go to 1 ft/min. Up 1 ft/min 15L. Down 1 ft/min at 0L. Up 1 ft/min 15R. PU for dry drift. Clean through
window log RA tag on depth. NBI indicates entry into sidetrack. PU above window and jog, open EDC. POOH pump 3 bpm keep 11.8# ECD at window. Tag up and
space out. Undeploy BHA #5 - Window Cleanout BHA. Reamer is 3.80" Go, 3.79" NoGo. Deploy BHA #6 - Lateral Drilling BHA. RIH BHA #6 - Lateral Drilling.
5/30/2023 RIH with 4.25 drilling BHA #6. Rate: 1.09 bpm in, 1.59 bpm out. Circ pressure: 2297 psi. Mud Weight: 8.92 ppg in, 8.98 ppg out. Log down for tie-in from 10220
(formation) with -13 correction. PUW 46K / RIW 15K. Run through window without issue. Send new mud. Drill 4.25 lateral from 12200 MD. Free spin: 3662 psi,
2.83 bpm (754 psi diff). Rate: 2.83 bpm in, 2.82 bpm out. Circ pressure: 3662 3839 psi. Mud weight: 8.69 ppg in, 8.78 ppg out, Window ECD: 11.80 ppg w/ 744
psi WH. ROP: 10-105 fph, WOB: 2.8 KLBS. Varied ROP. Begin increasing lubes to 3%. Drill 4.25 lateral from 12425 MD. Free spin: 3928 psi, 2.83 bpm (790 psi
diff). Rate: 2.83 bpm in, 2.82 bpm out. Circ pressure: 3928 to 4000 psi. Mud weight: 8.71 ppg in, 8.79 ppg out, Window ECD: 11.87 ppg w/ 704 psi WH. ROP: 10-
20 fph, WOB: 2.8 KLBS Increase rate. Drill 4.25 lateral from 12441 MD. Free spin: 4173 psi, 3.03 bpm ( 856 psi diff). Rate: 3.03 bpm in, 3.0 bpm out. Circ
pressure: 4173 to 4563 psi. Mud weight: 8.72 ppg in, 8.79 ppg out, Window ECD: 11.88 ppg w/ 666 psi WH. ROP: 10-80 fph, WOB: 2.8 KLBS. Broke through
12444' MD. Drill 4.25 lateral from 12455 MD. Rate: 2.80 bpm in, 2.80 bpm out. Circ pressure: 3906 - 4200 psi. Mud weight: 8.72 ppg in, 8.79 ppg out, Window
ECD: 11.80 ppg w/ 670 psi WHP. ROP: 50-80 fph, WOB: 2-3 KLBS. PU 12465' 64k pull 100' wiper trip clean up/down. 150' wiper from 12500' + 5 bbls lo/hi vis
clean up/down. Drill 4.25 lateral from 12500 MD. Rate: 2.81 bpm in, 2.76 bpm out. Circ pressure: 3900 - 4200 psi. Mud weight: 8.73 ppg in, 8.83 ppg out, Window
ECD: 11.83 ppg w/ 676 psi WHP. ROP: 50-80 fph, WOB: 2-3 KLBS. Window wiper from 12650' clean pass to window. Jog below B-shale at 10635. then pull
through clean. Jog above window, open EDC pump B/U until tubing clean. Tie-in depth from 10220' correct +5'. Close EDC clean pass through window no issues.
0.5 bpm to bottom. Stack 10576' PU and go through. Drill 4.25 lateral from 12650 MD. Rate: 2.90 bpm in, 2.91 bpm out. Circ pressure: 4000 - 4250 psi. Mud
weight: 8.77 ppg in, 8.84 ppg out, Window ECD: 11.78 ppg w/ 600 psi WHP. ROP: 50-80 fph, WOB: 2-3 KLBS. 12750' 5 bbls lo/hi vis.
5/31/2023 Drill 4.25 lateral from 12831 MD to 13040'. Rate: 2.90 bpm in, 2.91 bpm out. Circ pressure: 4000 - 4250 psi. Mud weight: 8.79 ppg in, 8.90 ppg out, Window ECD:
11.78 ppg w/ 598 psi WHP. ROP: 50-80 fph, WOB: 2-3 KLBS. Drill 4.25 lateral from 13040'. Rate: 2.90 bpm in, 2.91 bpm out. Circ pressure: 4000 - 4451 psi. Mud
weight: 8.83 ppg in, 8.94 ppg out, Window ECD: 11.84 ppg w/ 598 psi WHP. ROP: 10-40 fph, WOB: 2-3 KLBS. Pooh at 13061'. MWD tools intermittently turning
off. Vibrations all over place. Clean trip to window. Perform jog from 10620' to 11720'. Pull up through shale at 1 bpm. Drop rate coming through window. Come
back up on rate once through window. Chase up to tubing tail. Jog to above whipstock. Pooh. Rate: 3.15 bpm in, 2.61 bpm out. Circ pressure: 3716 psi. Mud
weight: 8.83 ppg in, 8.88 ppg out, Window ECD: 11.79 ppg. Perform jog at surface. Close EDC. Shallow test agitator. Good. Tag up and space out. Pressure Un-
Deploy BHA #6. Bit graded 1-1. Perform weekly BOPE function test. Swap out packoffs and lotorq on pump in sub. Pressure deploy BHA#7. Test MWD. RIH with
4.25 drilling BHA #7. Rate: 1.0 bpm in, 1.55 bpm out. Mud Weight: 8.85 ppg in, 8.92 ppg out. Log down for tie-in with -13.5 correction. Close EDC. Clean trip to
bottom. Drill 4.25 lateral from 13061' MD to 13130. Free spin: 4230 psi, 2.90 bpm. Rate: 2.90 bpm in, 2.85 bpm out. Circ pressure: 4230 4320 psi. Mud weight:
8.85 ppg in, 8.93 ppg out, Window ECD: 11.81 ppg w/ 583 psi WH. ROP: 16- 40 fph, WOB: 1-3 KLBS.
6/1/2023 Drill 4.25 lateral from 13130 to 13250'. Free spin: 4230 psi, 2.90 bpm. Rate: 2.91 bpm in, 2.90 bpm out. Circ pressure: 4230 to 4425 psi. Mud weight: 8.86 ppg in,
8.95 ppg out, Window ECD: 11.86 ppg w/ 542 psi WH. ROP: 16- 40 fph, WOB: 1-3 KLBS. Drill 4.25 lateral from 13250' to 13,280'. Free spin: 4344 psi, 2.91 bpm
(802 psi Diff). Rate: 2.91 bpm in, 2.90 bpm out. Circ pressure: 4344 to 4425 psi. Mud weight: 8.86 ppg in, 8.95 ppg out, Window ECD: 11.86 ppg w/ 547 psi WH.
ROP: 16- 40 fph, WOB: 1-3 KLBS. Drill 4.25 lateral to 13,280' and call TD. Wiper trip to window for tie in. Rate: 2.82 bpm in, 2.74 bpm out. Circ pressure: 4344 to
4425 psi. Mud weight: 8.88 ppg in, 8.95 ppg out, Window ECD: 11.87 ppg w/487 psi WHP. Pull through window clean. Circulate sweeps out of hole. Log tie in from
10210' @ 5 fpm. Correct +11'. RIH through window clean. Set down repeatedly at ~ 10,578'. Attempt to work through with different rates and speeds. Pump min rate
to 1 bpm. Unable to pass shale area. Pull through window clean. Pump sweeps from 7" to surface. Pump 10 Lo/Hi vis sweep and work past problem area pumping
1 bpm. Slight bobble at 13,245' on trip to TD. Tag and confirm TD @ 13281'. Wiper trip to window. Pump 10 bbl Lo/Hi vis sweeps off bottom. Rate: 2.83 bpm in,
2.79 bpm out. Circ pressure: 4472 psi. Mud weight: 8.89 ppg in, 8.98 ppg. Overpull at 12,400' and stall motor. Drop rate and RIH. Unable to RIH. Pump Lo/Hi vis
sweep and continue to work coil. Coil free. RIH and circulate sweeps to surface. Continue wiper trip to window. Wiper to 10,620' and jog in hole below shale interval.
Clean pass up through shale and window. Bring rate up above window and clean 7". Pump sweeps and circulate out of well. Pack off when BHA enters the TT. Free
coil and circulate additional bottoms up. Wiper trip to surface to clean long tangent in well. Jog in hole from 500' @ 100 fpm. Heavy cuttings returned. Correct depth
and RIH. Rate: 2.90 bpm in, 3.52 bpm out. Circ pressure: 4598 psi. Mud weight: 8.86 ppg in, 8.96 ppg out, Window ECD: 11.82 ppg w/908 psi WHP.
6/2/2023 Rih. Rate: 2.94 bpm in, 3.41 bpm out. Circ pressure: 4440 psi. Mud weight: 8.87 ppg in, 8.96 ppg out, Window ECD: 11.83 ppg. Decrease rate at 10100' to 0.87
bpm. Log tie in with -14' correction. Ran through window and build without issue. Did not see anything through previous problem area. Saw a 1K bobble at 12843'
and 12867'. Run to 13220' without issue. Bring rate up. Wiper up. Pulled tight and stalled motor at 12838' MD. Drop pump rate. Able to get BHA moving. Jog 100'
in hole. Pulled through. 1.5K drag going by. No motor work. Continue wiper up to 12500'. Jog in hole 100'. Pull up and start hanging up at 12400' . Had to drop rate
to free BHA. Rih and work past. Pull through. Make 2 passes in attempt to clean up area. Initial pass helped. Pack-off started leaking. Increased pressure. Pulled
through window without issue. Pump bottoms up. Put well on MPD. Close both pipe/slip rams. Replace pack-off. Service test to MPD pressure of 900 psi. Equalize.
Open rams. Close EDC. Come online. Jet 7" up to tail. Perform jog down. Chase pills into tubing tail. Log tie in with +10' correction. Run through window clean. Tag
10594' MD. Wash down to 10611' MD. Run down to sump. 10 bbl HiVis sweep coming out. Chase cutting. Perform job below window. Pull through window as
second sweep coming around. Chase up to 10,000'. Log tie in with +8' correction. RIH through window clean. Rate: .47 bpm in, .65 bpm out. Circ pressure: 2160
psi. Mud weight: 8.92 ppg in, 8.98 ppg out, Window ECD: 11.90 ppg. RIH to 13,220'. Trip to bottom was clean. Mix and pump 50 bbls 1.5 ppb Alpine Drilling beads
in liner running pill. Lay in 50 bbl 1.5 ppb liner running pill from 13,220' to 10,800'. Displace well to 11.8 ppg KWF. Flow check well and confirm no flow. POOH
keeping hole full. Rate: .98 bpm in, .45 bpm out. Circ pressure: 678 psi. Mud weight: 11.72 ppg in, 11.81 ppg out, Window ECD: 11.85 ppg. Paint EOP flags at
10,000' (yellow) and 7200' (white). OOH - Flow check well and confirm no flow. Inspect last 30' of coil. L/D lateral BHA. Bit graded 2:1. Remove UQC. Boot eline.
R/U to pump eline slack out. Pump eline slack forward. Cut and recover 225' of eline. Pump 7/8" drift ball. Jet stack and surface lines while pumping ball.
6/3/2023 Revover 7/8" Drift Ball. Lock out Koomey. Swap rams from 3" deployment rams to 2-3/8" x 3.5" Variables. Swap out to test risers and install test joint for 2-3/8". Test
2-3/8" x 3.5" Variables 250 psi / 3500 psi. Both 2-3/8" and 3.5" Test joints. Both passed. Swap risers. Inspect pack offs. Test pack offs. M/U crossover, swivel and
test plate to coil connector. PT swivel and CTC. Pass. R/U liner handling equipment and prep rig floor for liner running. M/U and run 2-7/8" , 6.5# L-80 ST-L Solid
Liner w/SOC and motor/mill. Hold kick while tripping drill and AAR. Fill liner every 10 jts. M/U and run 3-1/4" 6.6#, L-80 TCII Solid Liner w/SOC. M/U and run 3-1/2"
9.2#, L-80, ST-L Liner. M/U and run X nipple, Deployment sleeve and Baker LRT. M/U and run 2-3/8" 5.95# PH-6. M/U lockable swivel and M/U injector to well.
RIH with 2-7/8" liner. In Rate = .71 bpm, Out Rate = .99 bpm. In Mud Weight = 11.68 ppg, Out Mud Weight = 11.9 ppg. IA = 1300 psi, OA = 0 psi. Circ pressure =
451 psi.
6/4/2023 Rih w/ liner. Stop at window flag 10376.73' -35.2' correction. Stop above window. Circulate wellbore over to 8.87 ppg Powerpro. PUW 52.5 K / 16K RIW. Run
through without issue. In Rate = 0.30 bpm, Out Rate = .0.50 bpm. MW in: 8.87 ppg, MW out: 8.98 ppg. Start working liner at 12245', 12395'. Start losing ground. .
Increase rate. Start washing down. Work liner to a hard tag at 13260' MD. Discuss with drilling engineer. Decision to release and cement liner. 5K 13259.83', 62K
13247.2' Breakover. Repeat multiple times. Rih to compression. Launch 3/4" Steel ball. Heard rolling and over gooseneck. Decrease rate to 0.75 bpm at 75%
volume. Pumped 28 bbls past volume. Ball had not landed. Surge reel. PU and set down. Pressure up and shear at 5500#. Verified liner release. Confirm liner free
and circulate 1% KCL around. 1% KCL back to surface. PJSM with HES cement crew and Nabors rig crew. R/U cement line. PT to HES cement line to 5300 psi.
Confirm circulation through cement MM. Begin batching 44.4 bbl cement. Cement at weight at 22:15. Thickening time = 6 hrs, 10 min. Pump Geovis to reel (cement
MM) with rig pump. Pump 5 bbl fresh water lead. Pump 39.4 bbls 15.3 class G cement. 1.3 bpm and 2412 psi circ pressure. Swap to rig pump and displace cement
with Geovis contam pill. 70.8 bbls away zero return MM and take returns to pit #2. 88.7 bbls away, shut down. P/U to breakover +16' set back down 13' higher.
Launch pee-wee dart. P/U 1' and see pressure drop. Pump excess cement and additional 6 bbls contam pill. Set back down and shear LWP. LWP sheared at .6
bbls and 4400 psi. Pump LWP and see bump at 18.8 bbls(18.4 calculated) Cement in place at 00:50. Open pump bleeders and confirm floats holding. Pressure up
coil to 1500 psi and un-sting slowly until pressure drop noted. Pump 1:1 @ 3 BPM and circulate out remaining contam pill. Pump 11.8 ppg KWF to surface. Flow
check well and confirm no flow. 29.4 bbls cement behind pipe. POOH from 10,278' pumping 11.8 KWF. Jet Viking sliding sleeve and cont POOH. In Rate = 2.03
bpm, Out Rate = 1.44 bpm. In Mud Weight = 11.6 ppg , Out Mud Weight = 11.76 ppg. Circ pressure = 1416 psi.
6/5/2023 Laid down 6 joints 2-3/8" PH6. BOT BSELRT. Recovered 3/4" Ball. Cut and boot e-line. Make up nozzle. Jet stack. Inspect dead legs. Reverse circulate coil to
pump slack in. Cut 267' coil for 1.8% slack. Rig down cutting equipment. Make up coil connector. Pull test to 50K. Good test. . Install stinger. Pump e-line forward
for UQC. Make up UQC without floats. Test head. 49.9 / 550 PT to 3500#. Make up FVS, 3.5" Nozzle. RIH with BHA #9. Rate: 1.55 bpm in, 2.09 bpm out. Circ
pressure: 1082 psi. Mud Weight: 11.6 ppg in, 11.73 ppg out. Tag liner top at 10,348'. POOH from 10,348' while displacing well to 1% KCL. R/U and PT LRS pump
unit to 5k. Pump 50 bbls diesel for freeze protect. Freeze protect well from 3000' MD to surface with diesel. Service tree valves and LTT. L/D nozzle BHA. Evacuate
BOP stack. Swap VBR's back to 3" rams. PT doors. Good. Continue offloading fluid and cleaning pits. Blow down surface lines and rig. R/D tiger tank line. R/D
cellar. N/D MP Line. N/D BOP stack.
6/6/2023 Finish nipple down. Complete rigging down. . Install tree cap. Test to 3500#. Rig released 11:00.
ACTIVITYDATE SUMMARY
6/7/2023
***WELL S/I ON ARRIVAL***
GAUGE TBG W/ 3.70'' TO TAG LINER TOP (10,338' MD)
CLOSED SLIDING SLEEVE (10,180' MD) (good ia ddt & tool indication)
DRIFT INTO LINER W/ 2'' GAUGE RING (10,768' MD)
***WELL LEFT S/I ON DEPARTURE / DSO NOTIFIED OF WELL STATUS***
6/20/2023
CTU #9 1.75" Coil Tubing - Job Scope = Drift/Log and Perforate
Stand By for rig move
***Job Continued 6/21/23***
6/21/2023
CTU #9 1.75" Coil Tubing - Job Scope = Drift/Log to TD, Perforate ***Job continued
from 6/20/23
Stand by for rig move. MIRU. MU BOT ctc / MHA. MU HES Mem Tools w/ 2.2"
Carrier w/ 2.25" DJN. RIH
***Continue on WSR 6/22/23***
6/22/2023
CTU #9 1.75" Coil Tubing - Job Scope = Drift/Log to TD, Perforate ***Job continued
from 6/21/23
RIH w/ HES Mem Tools w/ 2.2" Carrier w/ 2.25" DJN. Pump displace CT w/ 10.4
brine. Tag PBTD @ 13,241.1' E / 13,253' M / 13,240.85' HES in Compression 5 min
stop count. Paint YELLOW FLAG 12,679.8' E / 12,692' M / 12,679.50' HES. Log up
50 fpm. Top Interval 10,100.1' E / 10,113' M / 10,099.77' HES. POOH. Good data at
surface, +9' correction. Perfrom flow checks prior to open hole deployment. Deploy
HES gun #1 2" x 500'. Perorm trippping drill. MU injector side to the gun, RIH to the
flag and correlate to top shot. Run past and PUH to top shot depth, shoot 12,733-
12,835' and 12,930-13,233'. POOH. Undeployed 2" guns and missing rest (OOH
39.5' / LIH 470.66' 2" guns). MU BOT motor assembly w/ HES Blow Out Sub to
attempt to fish HES 2" guns LIH. RIH
***Continue on WSR 6/23/23***
6/23/2023
CTU #9 1.75" Coil Tubing - Job Scope = Drift/Log to TD, Perforate ***Job continued
from 6/22/23
RIH w/ BOT motor BHA assembly and HES blow out sub. RIH. Pump thru TOL.
Corr Depth at Yellow Flag. RIH tag Fish @ 12,780' E / 12,801' M. PUH start
pumping RIH twice and stalled. PUH and wgt 1700 more good indication MU to guns.
POOH. Gun recovered. All shots fired. MU gun #2 2" Max Force 60 degree phase 6
SPF gun and RIH. Correlate to the flag. Shoot 12,235-12,405 and 12,600-12733'.
POOH. Undeploy Gun Run #2. Deploy Gun Run #3. RIH.
***Continue on WSR 6/24/23***
6/24/2023
CTU #9 1.75" Coil Tubing - Job Scope = Drift/Log to TD, Perforate ***Job continued
from 6/23/23
RIH w/ Gun Run #3. RIH to flag and correct depth to top shot. PUH and Perf 11,102'
- 11,602'. POOH. Freeze protect the well to 3000' w/ Diesel. RDMO.
***Job Complete***
6/25/2023
T/I/O= 0/0/0 Assist Slickline. Pumped 10 bbls criesel down IA to verify sleeve open.
Slickline in control of well upon departure. Final Whps=600/900/0
Daily Report of Well Operations
PBU MPL-13A
Daily Report of Well Operations
PBU MPL-13A
6/25/2023
*** WELL SHUT-IN ON ARRIVAL.***
MADE 3 RUNS W/ DUAL X-WING MAGNETS, 3.30" FLAT MAGNET. TAG 3-1/2"
XO @ 10,367' SLM,
RECOVERED COIL METAL SHAVINGS.
SHIFT VXD-SS AT 10,18O' MD W/ 4-1/2" 42BO.
LRS PUMPED 10bbls CRIESEL TO CONFIRM SLEEVE IS OPEN.
ATTEMPT TO SET 3" JETPUMP IN VXD-SS AT 10,180' MD (Unable to pass 9,794'
slm).
*** CONTINUE WSR ON 6-26-23.***
6/26/2023
*** CONTINUE WSR FROM 6-25-23.***
MAKE MULTILE ATTEMPTS TO SET JETPUMP, UNABLE TO PASS 9,794' SLM.
RAN DUAL X-WING MAGNETS, 3.30" FLAT MAGNET. TAG 3-1/2" XO @ 10,367'
SLM
MINIMAL RECOVERY OF MAGNETIC/SILTY TYPE MUD.
RAN DUAL X-WING MAGNETS, 3.75" GAUGE RING.TAG 3-1/2" XO @ 10,367'
SLM, NO RESTRICTIONS.
RAN 3.80" GAUGE RING, 2' x 1-7/8" STEM, 3.80" SWAGE. (Clear up tight spot at
9,794' slm).
*** CONTINUE WSR ON 6-27-23***
6/27/2023
T/I/O=200/560/0 Post Jet Pump set. Pumped 2 bbls diesel down IA (TBG Tracked)
to verify Sleeve open to jet pump. (Sleeve Open) Final Whps=415/730/0
6/27/2023
*** WELL SHUT-IN ON ARRIVAL.***
SET 3" JETPUMP (ratio: 11A, sidoti seal, screen. oal -69") IN VXD-SS AT 10,180'
MD.
*** WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFIED.***
7/12/2023
***WELL FLOWING ON ARRIVAL***
RIH W/ 4-1/2" GR
***CONTINUE 7/13/23***
7/13/2023
***CONTINUE FROM 7/12/23***
PULLED JET PUMP FROM 10,180' MD
SET 3" JET PUMP (ratio: 11A, sidoti seal, screen, shock absorber & dual spartek
gauges, 141" lih) IN SSD @ 10,180' MD
***WELL PUT ON PRODUCTION***
7/20/2023
***WELL FLOWING ON ARRIVAL***
PULL JET PUMP/MEMORY GAUGES @ 10,180' MD
***WSR CONTINUED ON 7-21-23***
7/21/2023
***WSR CONTINUED FROM 7-20-23***
SET 4 1/2" X LOCK W/ 3" JET PUMP (RATIO; 12a SIDOTI SEAL,SCREEN, SHOCK
ABSORBER & DUEL SPARTEK GAUGES, 140" LIH ) IN SSD @ 10175' MD.
***WELL TURNED OVER TO DSO ON DEPARTURE***
7/22/2023
***WELL S/I ON ARRIVAL***
R/U SLICKLINE.
***CONTINUED ON 7-23-23***
Daily Report of Well Operations
PBU MPL-13A
7/23/2023
***WSR CONTINUED FROM 7-22-23***
PULLED 3" JET PUMP ( ratio: sidoti seal, screen, shock absorber & duel gauges
ser# 8067 - 6237 battery started @ 18:55 ON 7-20-23 5 SEC SAMPLES FROM
10,164' SLM (nozzle damaged, pin debris in pump).
RE-SET SAME RE-DRESSED JET PUMP & GAUGES @ 10,175' MD.
ATTEMPT TO POP WELL, SLEEVE APPEARS CLOSED.
PULL JET PUMP & GAUGES FROM 10,175' MD.
RAN 3.80" CENT, 3' x 1.875" STEM, AND 3.81" 42BO TO SHIFT SLEEVE OPEN @
10,175' MD.
RE-SET SAME JET PUMP & GAUGES @ 10,175' MD.
POP WELL, LOOKS GOOD.
***WELL FLOWING ON DEPARTURE***
7/29/2023
***WELL S/I ON ARRIVAL***
PULLED JET PUMP w/ GAUGES FROM SSD @ 10,180' MD
DRIFTED FOR CUTTER w/ 3.80" GAUGE RING TO 10,280' SLM
RAN SBHPS W/ SURVEY STOP @ 10,360' MD.
BROUGHT ON POWER FLUID TO IA TO CONFIRM SLEEVE STILL OPEN.
***WELL S/I ON DEPARTURE***
7/30/2023
T/I/O = 287/101/0 Freeze Protect, Pumped 54 bbls criesel down IA, Pumped 46 bbls
criesel down Tubing FWP= 1000/1000/0
7/31/2023
****WELL S/I ON ARRIVAL****
RIH W/ BAKER MECHANICAL CUTTING TOOL MAKE TUBING CUT @ 10195' MD
CORELATED W/ TUBING TALLY CCL OFFSET TO CENTER OF BLADE 16,5',
GOOD INDICATION OF GOOD CUT, TBG PSI DROPPED AND CUTTER BLADE
LOOKED GOOD ON SURFACE
RDMO
****WELL S/I ON ON DEPARTURE****
8/4/2023
***WELL SHUT IN ON ARRIVAL***
RAN 3-1/2'' BLB, 2.74'' G. RING TO 10,712' SLM
RAN CALIPER FROM 10,349' SLM TO SURFACE
***WELL SHUT IN ON DEPARTURE***
8/7/2023
WELLHEAD: Well kill complete, set 4" CTS Bpv w/ dry rod. Bled off tbg hgr void,
Install tree lift cap, ND tree/adapter, install CTS plug and RX54 gasket. Check lift
threads and NU BOP stack.
8/7/2023
T/I/O = 173/155/0 Well Kill Pre RWO, Pumped 10 bbls hot diesel down tubing returns
up ia to tank, Pumped 378 bbls 10.2 down tubing up ia returns to tank, BPV set,
FWP = Vac/Vac/5
8/8/2023
WELLHEAD: Pull CTS plug and Bpv with T bar. PU LJ and MU to Tbg Hgr, BOLDS
and pull to floor, BO Hgr, load onto flatbed and take to shop.
Activity Date Ops Summary
8/9/2023 RD Mast, prep Rig carrier to road. Move Rig off Mud Boat. Move Catwalk. Spot in Crane and truck. Lift Spacer Spools, Floor, Cellar, and Heater. Remove BOP
Flange bolts, lift off BOPs and place on stand. Roll up Koomey lines. RD cribbing to Pits. RD containments, clean up location (F-81),Using Crane: RU primary
stairs, lift HCR hoses, floor, & accumulator lines. NU tree on F-81. Perform final checks. Test TBG HNGR void 500psi/5min, 5000psi/10min - Good. Spot in Rig.
Level out. Raise Mast. Remove Rack stabilizers & install rack pins. Crib up pits. Hook up accumulator lines & purge lines. NU Riser spools and hook up 6" flowline.
RU bird bath. RU pop-off. Lay out Herculite for Catwalk and pipe racks. RU Tongs & Slips for 4-1/2" TBG. Function test Accumulator and BOP Stack. Spot in
Catwalk & Pipe racks. spot in cuttings box. MU test mandrel & install in BOPs, Fill test pump & fluid pack manifold & lines. Shut down and check equipment.
Continue preparing BOPE for testing. Complete Rig Acceptance Checklist. Fill BOP stack with fluid for testing. Accept Rig. Begin testing BOPE. Witness waived by
AOGCC Rep. Guy Cook.
8/10/2023 Testing BOPs to 250/3500psi 250/2500 on annular. 0 failures. witness waived by AOGCC Guy Cook,Rig down test equipment. Blow dry BOP stack and fluid lines.
Ship fresh fluid to flowback tank and take on fluid in pits. Pull CTS plug and BPV. P/U M/U landing joint. BOLDS,P/U on tubing hanger. Hanger off seat @ 65K Pull
up to 95K. Work up to 120K in 5K increments. Work from 65K to 120K 2X. pipe came free. P/U wt 97K free travel. Pump 30BBLs of 10.2 ppg fluid. never seeing
returns to surface. POOH with 4-1/2 DWC tubing F/ 10,183' T/ 6,604' Pump 2x displacement and get returns up TBG. Install Floor Valve & Kelly Hose. Pump
10.3ppg down TBG @ 2bpm. 4bbls away and returns are light at ~9.3ppg w/ Crude. Divert to Tiger Tank until fluid weight returns to ~10.3ppg. Pump TBG volume
= 56bbls. TBG and IA went on vacuum. Continue OOH w/ Completion F/ 6,604' T/ 547'. PUW = 6K - SOW = 5K. 2-7/8" Joints on location = 329,Continue OOH. LD
SSD and 5.02' Cut from Joint #3 placing the Tubing Stub at 10,194.90' ORKB. Swap handling equipment from 4-1/2" to 2-7/8". Remove 4-1/2" Tubing from racks
and confirm count of pulled pipe - 249 JTS. Load and tally pipe on racks. Put jewelry in order. PU motor.
8/11/2023 P/U M/U and service ESP equipment as per ESP hand. Test cable. Good test. Start RIH with 2-7/8 EUE and ESP F/ 88' T/ 6,430' Testing ESP Cable every 1000'.
Check Packer setup - 4ea PTR Screws = 20,000lbs, Verify STS screw value / piston area = 1424psi,Shut down and check fluids. Continue OOH F/ 6430' to Packer
at 7159'. Test Cable - Good. Begin Cable Penetration through Packer. Continue ESP Packer Penetrator MU.
8/12/2023 Baker continue splicing ESP cable through packer. Test cable. good test,Purge air from cap line. Connect and test cap line to 5000 psi for five min. Vent valves
started opening @3800 psi. Bleed off to 500 psi to verify closed. RIH F/ 7,159' T/ 10,118' MU TBG Hanger. Perform Hanger ESP splice. Purge and connect to PVV.
Pressure up and witness PVV start to open at 3800psi. Bring pressure up to 5000psi and test 5min - Good Test. Bleed pressure to 1000psi to land Hanger. Centrilift
monitor ESP while landing. Final PUW = 68K, SOW = 36K. Final PUW = 68K, SOW = 36K. Land Hanger, RILDS. PVV line remaining at 1000psi, ESP
communications - Good. Completion landed w/ base of ESP @ 10,151.03' ORKB. Drop B&R, install Kelly Hose to pump down TBG. 1.5bbls to fill TBG. Pressure
up and see Packer STS @ 1900psi, continue up to 2600psi. Pressure dropped to 2300psi in 15min (IA & OA 0psi). Bleed to 0psi. Pressure back up to 2600psi &
hold for 5min. (dropped to 2400psi) Bleed TBG and PVV to 0psi. 0bbls to fill IA. Use step-rate method 250psi each step & hold 5min. At 1500psi, IA dropped to
500psi in 8min (T & OA 0psi). Bleed down IA. Pressure back up on TBG to 3,600psi. Lost 500psi in 25min, Bump pressure back up to 3600psi. Lost 100psi in
15min (IA & OA 0psi). Bleed TBG to 0psi. Swap back over to IA, couldn't keep 250psi for any length of time. Inform Scott Pessetto. Shut down and check equipment.
Function PVV 3x and vent to atmosphere. Wait 30min for PVV to close before testing. Use step-rate method (250psi/5min). Unable to pressure up past 600psi.
Inform Scott Pessetto. Line up to reverse circulate (returns up TBG to Tiger Tank) in an attempt to clear PVV of any debris. Bring pump up to .25bbl/min @ 100-
200psi. At 2.5bbls, attempt to shut PVV on the fly. Shut down pump at 3bbls away. Wait 30min for valve to close before pumping on IA. Pressure up down IA & get
returns immediately up TBG - PVV not closing. RU Slickline to pull B&R. Slickline RIH & Pull B&R. Inform SL to pull DGLV just below Packer.
8/13/2023 Slickline pull DGLV. and stage out of way. Rig up to pump down tubing. Pressure up on PVV to 5000 psi. Pump down tubing taking returns up PVV and IA to clean
any debris from PVV. pump at 1 BPM @ 100 psi Shut down pumps. Bleed off PVV. Wait 10 min. pump down tubing to try and help PVV close by bringing up
pressure. Staged up pump slowly T/ 1 BPM 700psi. continuing to get returns. Attempt to pressure up on IA. no good. Rig down slickline,Rig up to POOH. Hang
elephant trunk. Tie ropes to spoolers. PJSM. BOLDS. Pull up on hanger. Packer released @ 84K, 16K over string wt. Cut ESP and tie to ropes. cut cap line and tie
to ropes. POOH slowly. 500'/hr. as per ESP rep and OE. F/ 10,151' T/' 8660' pumping single displacement. Troubleshoot issues with Rig Carriage. Continue POOH
@ 500 ft/hr. F/ 8660' T/ 7140' while pumping 1x displacement. LD GLM#3, Disconnect C/L from PVV. PVV appears to be fully closed - has some debris internally.
Packer not fully released - slips slightly protruding out from OD. Cut ESP cable just below Packer. LD Packer. POOH to JT# 224, Install 2ea 10' Pups. RBIH w/
completion to Packer. Feedt ESP cable through Packer.
8/14/2023 While installing packer penetrator, found pup on top of packer to short with the collar on the pup not letting penetrator to be installed. Baker disassembled to
penetrator,Mobilize longer pup to location. Break out pup and install new pup on packer,Baker preform packer splice. Install PVV on packer and test from below to
2400psi,Purge cap line and install on PVV. Pressure up on cap line stepping up 500 psi increments one PVV started opening @ 3000 psi. The other @3500 psi.
pressured up to 5000 psi and held for 5 min to test connection. Bled off pressure and watch both PVV close. PVVs closed in 12min. Plug cable to top of packer
penetrator. lowered into well. Test cable. Cable test good. RIH with 2-7/8 EUE and ESP testing cable every 1,000' to 9097'. Kick While tripping drill. RIH F/ 9097' T/
TBG Hanger clamping every other connection and testing ESP every 1000'. MU TBG Hanger. Feed PVV C/L through Hanger. Begin ESP feedthrough. Purge and
test PVV - Good, Final readings on ESP - Good. Monitor while landing TBG Hanger. Hanger landed all comms are good, RILDS. Drop B&R - 8.65' OAL 1-3/8"
Fishing Neck. Line up down TBG to test Packer. Pressure up and see Packer start to set @ ~2500psi, continue up to 4100psi and hold for 15min. Bleed to 0psi.
Pressure back up to 4100psi and hold for 5min - good. Bleed to 0psi and line up to IA. Pressure up down IA using step-rate method 250psi and hold 5min. Able to
obtain a good test @ 1000psi. Once pressured up to 1200-1250psi, pressure broke over and bled down to ~100psi. Attempt again and unable to achieve 250psi.
Line up and test with the Rig Test pump, same results. Consult OE. Allow time for PVV to shut. Pressure up to 250psi and lost 100psi in 3min. Currently retesting w/
Test Pump.
8/15/2023 Discuss options with OE. Mobilize slickline unit to location. Pressure up on IA to confirm Hanger not leaking. hanger was good. Rig up slickline. Pull ball and rod
and RHC. Set TTP in X-nipple @ 3,103'. Rig up to test TTP to 3500 psi. Fill all line and purge air from the system. Test TTP to 3500 psi. Good test. Rig down test
equipment. RIH W/ slickline and pull DGLV from station @ 2,928'. POOH. Rig down slickline,Circulate diesel around,Combo test tubing and IA. test failed. Cycle
PVV open/closed 3x. Allow to close while vent to atmosphere 30min. Begin step-rate test TxIA. Hold 250psi/5min each step. At ~500psi, found leaking Lo-Torq
Valve on IA. Replace Valve. Attempt test again, PVV broke-over at 1582psi and dropped to 1250psi. Bleed to 0psi and wait 30min for PVV to close. Pressure test
MIT-TxIA to 1500psi for 30 charted min. Lost ~100psi in 30min. Confirm with OE. Good Test, install BPV, cut PVV line and cap. Begin RDMO. FINAL Install: 176ea.
Cross-Coupling Clamps, 3ea. Half Clamps, 2ea. Flat Guards, 6ea. Protectolizers. PUW = 68,000lbs, SOW = 38,000lbs, Packer Shear to Release = 22,057lbs over
string weight. Diesel surf to surf through GLM#3 @ 2928'.
50-029-22335-01-00API #:
Well Name:
Field:
County/State:
MP L-13A
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
ACTIVITYDATE SUMMARY
8/15/2023
*** ASSIST ASR.***
PULL BALL & ROD, 2-7/8" RHC FROM X-NIPPLE AT 3,013' MD
SET 2-7/8" XX PLUG IN X-NIPPLE AT 3,103' MD.
ASR PERFORMED PASSING PRESSURE TEST OF TUBING TO 2500psi.
PULL BK-DGLV FROM ST#3 (2,928' md). ***** POCKET LEFT OPEN.*****
*** ASR STILL IN CONTROL OF WELL,***
8/16/2023
Land 11 x 2-7/8 ESP tubing hanger, Set BPV, removed rig and nipple down BOPs,
Terminate CCL, ESP penetrator is diffrent type can not test Wellhead THA , Send in
new THA to get modified.
8/21/2023
*** WELL S/I ON ARRIVAL ***
SET BK-DMYGLV IN ST # 3 @ 2,928' MD
PULL BK-DMYGLV FROM ST# 4 @ 164' MD
SET BEK-DUAL PORT SO IN ST# 4 @ 164' MD
EQUALIZE XX- PLUG @ 3,103' MD
*** CONTINUE ON 8/22/2023 ***
8/21/2023
Move new adapter to machine shop for mods, Nipple up new modified adapter,
tested to 250 / 5000 psi for 15 mins each. Nipple up tree and tested to 5000 psi for 5
mins. All tests good,
Modification: we welded an overshot sleeve on the inside of the adapter, the sleeve
has ID seals to test adapter against. Drawings in the well file.
8/22/2023
*** CONTINUE FROM 8/21/2023 ***
PULL 2-7/8" XX-PLUG FROM 3,103' MD
*** WELL LEFT S/I ON DEPARTURE, DSO NOTIFIED OF STATUS ***
Daily Report of Well Operations
PBU MPL-13A
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Nolan Vlahovich Hilcorp Alaska, LLC
Geotechnician 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: 08/10/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
Well: MPU L-13A
PTD: 223-017
API: 50-029-22335-01-00
Caliper Survey (8/4/23)
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
PTD: 223-017
T37921
8/10/2023Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.08.10
15:40:43 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geo Tech 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: 07/28/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20230728
Well API #PTD #Log Date Log
Company Log Type AOGCC
Eset#
BCU-23 50133206350000 214093 7/16/2023 HALLIBURTON PPROF
BCU-24 50133206390000 214112 7/15/2022 HALLIBURTON PPROF
BRU 223-34 50283201880000 223041 7/9/2023 HALLIBURTON RMT3D
KBU 23X-6 50133203710000 184109 6/22/2023 HALLIBURTON EPX
KBU 23X-6 50133203710000 184109 6/22/2023 HALLIBURTON MFC
KGSF 7A 50133205380100 204163 6/18/2023 HALLIBURTON EPX
KGSF 7A 50133205380100 204163 6/18/2023 HALLIBURTON MFC
KU 21-6RD 50133100900100 201097 6/24/2023 HALLIBURTON EPX
KU 21-6RD 50133100900100 201097 6/24/2023 HALLIBURTON MFC
MPU B-24 50029226420000 196009 7/24/2023 HALLIBURTON WFL-TMD3D
MPU B-34 50029235690000 216139 7/23/2023 HALLIBURTON WFL-TMD3D
MPU B-50 50029232400000 204252 7/21/2023 HALLIBURTON WFL-TMD3D
MPU E-23 50029225700000 195094 6/17/2023 HALLIBURTON COILFLAG
MPU F-17 50029228230000 197196 7/2/2023 HALLIBURTON COILFLAG
MPU L-13A 50029223350100 223017 6/21/2023 HALLIBURTON COILFLAG
MPU L-39B 50029227860200 223037 6/30/2023 HALLIBURTON COILFLAG
MPU L-39B 50029227860200 223037 6/30/2023 HALLIBURTON RBT
PBU 11-07 50029206870000 181177 6/28/2023 HALLIBURTON RMT3D
SCU 42-05X 50133205610000 206074 6/20/2023 HALLIBURTON EPX
SCU 42-05X 50133205610000 206074 6/20/2023 HALLIBURTON MFC
SCU 42-05Z 50133206950000 220069 6/16/2023 HALLIBURTON EPX
SCU 42-05Z 50133206950000 220069 6/16/2023 HALLIBURTON MFC
Please include current contact information if different from above.
T37886
T37887
T37888
T37889
T37889
T37890
T37890
T37891
T37891
T37892
T37893
T37894
T37895
T37896
T37897
T37898
T37898
T37899
T37900
T37900
T37901
T37901
MPU L-13A 50029223350100 223017 6/21/2023 HALLIBURTON COILFLAG
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.08.01
10:05:02 -08'00'
David Douglas Hilcorp Alaska, LLC
Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 06/28/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
Well: MPU L-13A
PTD: 223-017
API: 50-029-22335-01-00
FINAL LWD FORMATION EVALUATION LOGS (05/24/2023 to 06/03/2023)
x Multiple Propagation Resistivity & Gamma Ray
(2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
PTD: 223-017
T37783
Kayla Junke
Digitally signed by
Kayla Junke
Date: 2023.06.28
10:16:21 -08'00'
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Tubing Cut
Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ESP Completion
2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number:
Exploratory Development
3. Address: Stratigraphic Service
6. API Number:
7. If perforating:8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool?
Will planned perforations require a spacing exception? Yes No
9. Property Designation (Lease Number): 10. Field: Current Pools:
11.
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
11,016'N/A
Casing Collapse
Conductor 1,130psi
Surface 4,760psi
Production 5,410psi
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16. Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title: Wells Manager
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other:
Post Initial Injection MIT Req'd? Yes No
Spacing Exception Required? Yes No Subsequent Form Required:
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
AOGCC USE ONLY
scott.pessetto@hilcorp.com
907-564-4373
Scott Pessetto
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size:
12.6# / L-80 / CDW 10,390'
6/15/2023
7'' x 4.5'' Tri-Point and N/A 10,327 MD/ 6,912 TVD and N/A
See Schematic See Schematic 4-1/2"
Perforation Depth MD (ft):
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0025509
223-017
3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-22335-01-00
Hilcorp Alaska LLC
KUPARUK RIVER OIL N/A
C.O. 432E
MILNE PT UNIT L-13A
7,409' 10,868' 7,311' 3,059 N/A
Proposed Pools:
80' 80'
TVD Burst
PRESENT WELL CONDITION SUMMARY
13-3/8"
MILNE POINT
3,730psi
6,870psi
7,240psi
4,409'
7,396'
9-5/8"
7"
6,086'
10,996'
MD
6,086'
10,996'
Length Size
80'
Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 10:12 am, Jun 06, 2023
323-328
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2023.06.05 13:59:51 -
08'00'
Taylor Wellman
(2143)
Perforate
10-404
MGR13JUN23
* BOPE test to 3500 psi. Annular to 2500 psi.
DSR-6/12/23
3,059
SFD 6/8/2023
* Approved for 30 day production utilizing jet pump. 1.5 wellbore volumes of 10.2 ppg KWF to be available within MP field
for pumping in the event of required well kill. 24/7 man watch during production.
GCW 06/14/2023JLC 6/14/2023
06/14/23
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2023.06.14 09:23:11
-08'00'
RBDMS JSB 061423
Well: MPU L-13A
Scope: Post-CTD APERF + ESP RWO
Well Name:MPU L-13A API Number:50-029-22335-01-00
Current Status:Oil Well Pad:L-Pad
Estimated Start Date:June 15, 2023 Rig:CTU/E-line/ASR
Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd:
Regulatory Contact:Tom Fouts Permit to Drill Number:193-012
First Call Engineer:Scott Pessetto (907) 564-4373 (O)(801) 822-2203 (M)
Second Call Engineer:Taylor Wellman (907) 777-8449 (O)(907) 947-9533 (M)
AFE Number:Job Type:APERF / ESP RWO
Current Bottom Hole Pressure: 3,541 psi @ 6,829’ TVD SBHPS taken 03/18/2022 | 10.0 PPGE
Maximum Expected BHP: 3,767 psi @ 7,075’ TVD MPL-15 SBHP taken 5/2/2020 | 10.2 PPGE
Max Potential Surface Pressure: 3,059 psi Gas Column Gradient (0.1 psi/ft)
Max Angle: 54° @ 9,497’ MD within parent bore
Max Dogleg Severity: 6.15 deg/100’ @ 1,441’ MD within parent bore
Tie in Log: To be provided by Geologist
Brief Well Summary:
MPU L-13 was originally drilled and completed as Kuparuk producer in 1993. The well is currently being
sidetracked with CDR2 to access unswept oil to the North. The CTD lateral will be lined with a 3-3/16” x 2-7/8”
liner and cemented isolating the parent well. After CDR2 moves off the well, the interval will be perforated to
produce the oil bearing zones.
Objective:
Perforate high resistivity intervals within the cemented L-13A using perf guns conveyed on service coil.
Temporary flowback the well for 30 days. Perform Tubing Cut and remove 4-1/2” tubing, run 2-7/8” ESP
completion.
Notes Regarding Wellbore Condition:
x Well was recently worked over in March of 2023 with new 4-1/2” tubing.
x CDR2 has drilled a sidetrack and a cemented 2-7/8” liner in place.
x On initial rig up all formations should be isolated via cement pumped by CDR2.
Procedure (Sundried Work)
Coiled Tubing:
Notes:
x Due to the necessary open hole deployment of Extended Perforating jobs, 24-hour crew and WSS
coverage is required.
x The well will be killed and monitored before making up the initial perfs guns. This is generally done
during the drift/logging run. This will provide guidance as to whether the well will be killed by
bullheading or circulating bottoms up throughout the job. If pressure is seen immediately after
perforating, it will either be killed by bullheading while POOH or circulating bottoms up through the
same port that opened to shear the firing head.
1. After MU MHA and pull testing the CTC, tag-up on the CT stripper to ensure BHA cannot pull through
the brass upon POOH with guns.
3,059 psi
10.0 PPGE|1
Well: MPU L-13A
Scope: Post-CTD APERF + ESP RWO
2.Circulate 176 barrels 10.2 brine during logging run. (Bullheading is not possible prior to first gun run,
but up to WSS discretion to bullhead once a fluid path is created.) Confirm CDR2 did not leave KWF
in hole, current CDR2 procedure calls for KCl water.
a. Wellbore volume to deepest perf = 176 bbls
b. 4-1/2” Tubing – 10,340’ x 0.0152 bpf = 157.2 bbls
c. 3-1/2” Liner – 152’ x 0.0087 = 1.4 bbls
d. 3-3/16” Liner – 532’ x 0.0079 = 4.2 bbls
e. 2-7/8” Liner – 2,227’ x 0.0058 = 12.9 bbls
3. MU and RIH with logging tools and drift BHA: 2” dummy gun & nozzle.
4. Flag pipe as appropriate per WSS for adperf runs.
5. POOH and freeze protect tubing as needed.
6. Confirm good log data. Send to Geologist for depth correction:
a. John Salsbury - jsalsbury@hilcorp.com / 907-350-1088.
7. At surface, prepare for deployment of TCP guns.
8. Confirm well is dead. Bleed any pressure off to return tank. Maintain hole fill taking returns to tank
until lubricator connection is re-established. Fluids man-watch must be performed while deploying
perf guns to ensure the well remains killed and there is no excess flow.
9.*Perform drill by picking up safety joint with TIW valve and space out before MU guns. Review well
control steps with crew prior to breaking lubricator connection and commencing makeup of TCP gun
string. Once the safety joint and TIW valve have been spaced out, keep the safety joint/TIW valve
readily accessible near the working platform for quick deployment if necessary.
a.At the beginning of each job, the crossover/safety joint must be physically MU to the perf guns
one time to confirm the threads are compatible.
10.Break lubricator connection at QTS and begin makeup of TCP guns per schedule below. Constantly
monitor fluid rates pumped in and fluid returns out of the well. Fluids man-watch must be performed
while deploying perf guns to ensure the well remains killed and there is no excess flow.
2” Perf Gun Schedule
Perf Interval Perf
Length Gun Length Weight of Gun (lbs)
Run
1
12,733’-12,835’,
12,930’-13,233’405’ 500’ ~2,790 lbs (5.58ppf)
Run
2
12,235’-12,405’
12,600’-12,733’303’ 498’ ~2,778 lbs (5.58ppf)
Run
3 11,102’-11,602’500’ 500’ ~2,790 lbs (5.58ppf)
Total 1,208’ 1,500’
11. RIH with perf gun and tie-in to coil flag correlation. Pickup and perforate interval per Perf Schedule above.
a. Note any tubing pressure change in WSR.
12. After perforating, PUH to top of liner or into tubing tail to ensure debris doesn’t fall in on the guns and
stick the BHA. Confirm well is dead and re-kill if necessary before pulling to surface.
13. Pump pipe displacement while POOH. Stop at surface to reconfirm well is dead. Kill well if necessary.
14. Review well control steps and Standing Orders with crew prior to breaking lubricator connection and
commencing breakdown of TCP gun string.
15. Ensure safety joint and TIW valve assembly are on-hand before breaking off lubricator to LD gun BHA.
16. RDMO CTU.
17. Freeze protect well.
Circulate 176 barrels 10.2 brine during logging run.
Make up PCE. - MGR
Well: MPU L-13A
Scope: Post-CTD APERF + ESP RWO
Hilcorp requests approval to temporarily flowback L-13A via reverse circulating jet pump for a period
of 30 days. Temporary jet pump flowback will allow for correct sizing of the ESP completion and
clearing out of perf debris from the well that may damage the ESP pump.
- IA SSV high pressure trip not to exceed 10% greater than expected maximum header pressure.
- IA SSV low pressure trip setpoint to be at least 50% of expected maximum header injection pressure.
- In compliance with 20 AAC 25.200(d) a check valve will be installed in the jet pump preventing flow
from tubing to annulus when annular power fluid injection is offline.
- The check valve will be qualified as a barrier through a draw down test on the inner annulus confirming
the annulus does not build pressure after initial pressure is bled off. Inner annulus to be monitored for
30 minutes to confirm no build of pressure.
o This installation will be one of the first trials of a jet pump with check valve installed at Milne
Point.
o To prove the integrity of the check valve, the valve needs to be trialed in a well that has a
reservoir pressure gradient greater than 8.55 ppg. The trial well needs enough reservoir energy
to build IA pressure with source water power fluid hydrostatic column in the annulus.
Slickline
18. MIRU SL, PT PCE to 250 psi low / 3,500 psi high
19. MIT-IA to maximum power fluid pressure of 3,000 psi.
20. Open sliding sleeve at 10,175’.
21. Install 11A jet pump in sliding sleeve at 10,175’.
22. RDMO.
Slickline (After temporary flowback)
23. Pull jet pump from 10,175’. Leave sleeve open for well kill.
24. RIH and tag liner top, obtain 30 minute SBHP.
25. Pull up hole 200' TVD for 15 minute gradient stop.
26. Confirm good data.
27. RDMO.
E-Line (After temporary flowback)
28. MIRU EL, PT PCE to 250 psi low / 3,500 psi high
29. RIH with mechanical cutter
30. Cut 5’ below collar on first full joint of 4.5” 12.6# L-80 DWC above the packer. Estimated cut depth
~10,184’ RKB.
31. RDMO
Pumping and Well Support
32. Clear and level pad area in front of well. Spot rig mats and containment.
33. RD well house and flowlines. Clear and level area around well.
34. RU Little Red Services. RU reverse out skid and 500 bbl returns tank.
35. Pressure test lines to 3,000 psi.
36. Circulate at least one wellbore volume with 10.2 ppg brine (confirm KWF after perforations) down
tubing, taking returns up casing to 500 bbl returns tank.
37. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 MeOH or diesel.
Approved for 30 day production utilizing jet pump. 1.5 wellbore volumes of 10.2 ppg KWF to be available within MP field
for pumping in the event of required well kill. 24/7 man watch on MPU L pad during jet pump production. -mgr
Well: MPU L-13A
Scope: Post-CTD APERF + ESP RWO
38. RD Little Red Services and reverse out skid.
39. Set BPV.
40. ND Tree. NU BOPE.
Brief RWO Procedure
41. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 bbl returns tank.
42. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing and
casing.
a. If required, kill well w/ 10.2 ppg (confirm KWF based on updated SBHP) ppg brine prior to
setting CTS
43. Test BOPE to 250 psi Low/ 3,500 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.
b. Notify AOGCC 24 hours in advance of BOP test.
c. If MPSP falls below 3,000 psi after CTD sidetrack, test to BOP to 3,000 high, remove third set
of pipe rams. Notify AOGCC of change.
d. Confirm test pressures per the Sundry Conditions of approval.
e. Test VBR ram on 2-7/8” and 4-1/2” test joints.
f. Submit to AOGCC completed 10-424 form within 5 days of BOPE test.
44. Bleed any pressure off casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the
returns tank. Kill well w/ 10.2 ppg brine as needed. Pull BPV.
a. If indications show pressure underneath BPV, lubricate out BPV.
45. MU landing joint or spear and PU on the tubing hanger.
a. The PU weight during the 2023 workover was 97K lbs on ASR1.
b. Tri-Point Hydratrieve Packer is pinned for 40K lbs to shear release.
c. PU weights should be ~97K. If hanger is not releasing do not pull 30K lbs over until confirming
good E-Line cut to avoid releasing the packer.
46. Confirm hanger free, lay down tubing hanger.
47. POOH and lay down the 4-1/2” tubing.
a. Keep all jewelry and tubing joints.
b. Note any over-torqued or damaged connections and set aside for disposal.
48. PU new ESP and RIH on 2-7/8” tubing. Set base of ESP at ± 10,150’ MD.
a. Check electrical continuity every 1,000’.
b. Note PU and SO weights on tally.
c. Install ESP clamps per ESP hand, and cross coupling clamps every other joint.
d. Photograph vent packer prior to running in hole.
Nom. (OD) Length Item Lb/ft Material Notes
5.85 2 Centralizer 4 ~10,150’ MD
4.5 2 Intake Sensor 30
5.62 34 Motor 80
5.2 7 Lower Tandem Seal 38
Well: MPU L-13A
Scope: Post-CTD APERF + ESP RWO
5.2 7 Upper Tandem Seal 38
5.2 8 Gas Separator 52
5.38 ~57 Pump 45
1 Ported Discharge Head 13 L-80
2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" 30 2-7/8" EUE 8rd L-80 6.5 L-80
2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" 2 2-7/8” XN-nipple 6.5 L-80
2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" 60 2-7/8" EUE 8rd Jt 6.5 L-80
2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" 8 2-7/8" x 1" GLM, DV installed 6.5 L-80
2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" ~6,800 2-7/8" EUE 8rd Jt 6.5 L-80
2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" 2 2-7/8” X-nipple with RHC profile 6.5 L-80 RHC Installed
2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" 31 2-7/8" EUE 8rd Jt 6.5 L-80
2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" 8 2-7/8" x 1" GLM, DV installed 6.5 L-80
2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" 31 2-7/8" EUE 8rd Jt 6.5 L-80
30 Packer, Viking ESP Retr. Dual Vent ~3,000 MD
2-7/8" ~2,650 2-7/8" EUE 8rd Jt 6.5 L-80
2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" 8 2-7/8" x 1" GLM, DV installed 6.5 L-80 ~150 MD
2-7/8" 10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8" 150 2-7/8" EUE 8rd Jt 6.5 L-80
2-7/8" 10 Space out pup 6.5 L-80
2-7/8" 30 Tubing Hanger with full joint 6.5 L-80
49. PU and MU Viking vented packer. Verify that there are four (4) setting shear pins and confirm with OE
number of release shear pins.
a. Target release pins to shear at 20,000 pounds overpull.
50. Terminate the ESP cable and make up the ESP penetrator to the ESP cable. Ensure the 3/8” NPT control
line feed thru port is dummied off.
51. Make up the control line to the dual vent valves. Pressure up on the control line to 5,000 psi and hold
for 5 minutes checking for leaks (note the opening pressure in the daily report). Bleed the pressure to
500 psi and maintain 500 psi while running in hole.
a. Periodically confirm control line is maintaining 500 psi.
52. Continue running ESP completion per plan.
Well: MPU L-13A
Scope: Post-CTD APERF + ESP RWO
53. PU and MU the 2-7/8” tubing hanger. Make final splice of the ESP cable to the penetrator. MU the
control line to the tubing hanger and dummy off any additional control line ports if present.
54. Land tubing hanger, avoiding any damage to ESP cable or control line. RILDS. Lay down landing joint.
Note PU and SO weights on tally and in daily report.
55. Drop ball and rod.
56. Pressure up on tubing to 4,000 psi and hold for 15 minutes to set the ESP packer.
57. Bleed tubing to 0 psi.
58. Pressure up on tubing to 4,000 psi and hold for 5 more minutes and then bleed to 0 psi.
59. Bleed packer control line to 0 psi, closing packer vent valves.
60. Slowly pressure up IA at 50 psi/min to 1,500 psi and hold for 30 minutes. Chart test.
61. Lay down landing joint.
62. Set BPV.
63. RDMO ASR
Post-Rig Procedure (Non-Sundried Work):
Well Support
64. RD mud boat. RD BOPE house. Move to next well location.
65. RU crane. ND BOPE, set CTS plug, and NU tree.
66. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV.
67. RD crane. Move 500 bbl returns tank and rig mats to next well location.
68. RU well house and flowlines.
Slickline
69. Retrieve ball and rod, pull RHC plug
70. Set screen OV in top GLM
Attachments:
1. Schematic
2. Proposed Schematic
3. Coil Tubing BOPE Schematic
4. Standing Orders for Open Hole Well Control during Perf Gun Deployment
5. Equipment Layout Diagram
6. ASR BOP Schematic
_____________________________________________________________________________________
Revised By JNL: 2/15/2023
SCHEMATIC
Milne Point Unit
Well: MPU L-13A
Last Completed: TBD
PTD: TBD
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
13-3/8" Conductor 54.5 / K-55 / BTRC 12.415 Surface 80'
9-5/8" Surface 47 / N-80 / BTRS 8.681 Surface 6,086’
7" Production 26 / L-80 / BTRC 6.276 Surface 10,535’
3-1/2”x3-1/4”x2-7/8” Liner 9.3 x 6.6 x 6.5 / L-80 / STL x TCII 10,360’ 13,159’
TUBING DETAIL
4-1/2" Tubing 12.6 / L-80 / EUE 8rd 3.958 Surface 10,390’
JEWELRY DETAIL
No Depth Item
1 10,180’ Sliding Sleeve
2 10,250’ Packer
3 10,290’ XN Nipple
4 10,360’ Top 3-1/2” Liner
5 10,388’ WLEG: Bottom @ 10,390’
6 10,510’ 3-1/2” xo 3-1/4”
7 10,775’ 3-1/4” xo 2-7/8”
GENERAL WELL INFO
API: 50-029-22335-01-00
Drilled and Cased by Nabors 22E - 5/16/1993
ESP Change-out by Nabors 4ES – 2/22/1995, 11/17/1999 & 8/3/2003
ESP Change-out by Nabors 3S – 1/27/2008 & 6/14/2008
ESP Change-out by Doyon 16 – 12/12/2013
A Sidetrack:
TD = 13,159’ (MD) / TD =7,199’(TVD)
20”
Orig. KB Elev.: 46’/ Orig. GL Elev.: 16.5’
Nabors 22E / RT to 7”Hanger= 28.5’
7”
6
9-5/8”
1
2-7/8”
PBTD =13,159’(MD) / PBTD =7,199’(TVD)
Whipstock
set @
10530’ Top
of Window
@ 10535’
5
7
Top of Liner /
Cement
@ 10360’
2
3
4
OPEN HOLE / CEMENT DETAIL
26” 300 sx of Arcticset I
12-1/4” 1,780 sx of Arcticset III, 3000 sx Class G
8-1/2” 325 sx Class G”
4-1/4” 168 sx Classs G
WELL INCLINATION DETAIL
KOP @ 10535’
90 deg Hole Angle = 11075’ MD
TREE & WELLHEAD
Tree 2-9/16” – 5M WKM
Wellhead 11” 5M WKM, w/ 2-7/8” x 11” Tubing Hanger, 2-7/8” EUE
8rd Threads, 2.5” “H” BPV profile.
_____________________________________________________________________________________
Revised By TDF: 6/5/2023
PROPOSED
Milne Point Unit
Well: MPU L-13A
Last Completed: TBD
PTD: TBD
TD = 13,159’ (MD) / TD =7,199’(TVD)
20”
Orig. KB Elev.: 46’/ Orig. GL Elev.: 16.5’
Nabors 22E / RT to 7”Hanger= 28.5’
7”
18
9-5/8”
1
Tubing Cut @
±XX,XXX’
2-7/8”
PBTD =13,159’(MD) / PBTD =7,199’(TVD)
Whipstock
set @
10530’ Top
of Window
@ 10535’
17
19
Top of Liner /
Cement
@ 10360’
14
15
16
2
3
6
1
5
7
8
9
10 & 11
12
13
4
JEWELRY DETAIL
No Depth Item
1 ±XXX’ 2-7/8" x 1" GLM, DV installed
2 ±X,XXX’ Packer, Viking ESP Retr. Dual Vent
3 ±X,XXX’ 2-7/8" x 1" GLM, DV installed
4 ±X,XXX’ 2-7/8” X-nipple with RHC profile
5 ±X,XXX’ 2-7/8" x 1" GLM, DV Installed
6 ±X,XXX’ 2-7/8” XN-nipple
7 ±X,XXX’ Ported Discharge Head
8 ±XX,XXX’ Pump
9 ±XX,XXX’ Gas Separator
10 ±XX,XXX’ Upper Tandem Seal
11 ±XX,XXX’ Lower Tandem Seal
12 ±XX,XXX’ Motor
13 ±XX,XXX’ Intake Sensor w/Centralizer – Btm @ ±XX,XXX’
14 ±XX,XXX’ Packer
15 ±XX,XXX’ XN Nipple
16 ±XX,XXX’ Top 3-1/2” Liner
17 ±XX,XXX’ WLEG: Bottom @ ±XX,XXX’
18 ±XX,XXX’ 3-1/2” xo 3-1/4”
19 ±XX,XXX’ 3-1/4” xo 2-7/8”
OPEN HOLE / CEMENT DETAIL
26” 300 sx of Arcticset I
12-1/4” 1,780 sx of Arcticset III, 3000 sx Class G
8-1/2” 325 sx Class G”
4-1/4” 168 sx Classs G
WELL INCLINATION DETAIL
KOP @ 10535’
90 deg Hole Angle = 11075’ MD
TREE & WELLHEAD
Tree 2-9/16” – 5M WKM
Wellhead 11” 5M WKM, w/ 2-7/8” x 11” Tubing Hanger, 2-7/8” EUE
8rd Threads, 2.5” “H” BPV profile.
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
13-3/8" Conductor 54.5 / K-55 / BTRC 12.415 Surface 80'
9-5/8" Surface 47 / N-80 / BTRS 8.681 Surface 6,086’
7" Production 26 / L-80 / BTRC 6.276 Surface 10,535’
3-1/2”x3-1/4”x2-7/8” Liner 9.3 x 6.6 x 6.5 / L-80 / STL x TCII 10,360’ 13,159’
TUBING DETAIL
2-7/8” Tubing 6.4# / L-80 / EUE 8rd 2.441 Surface ±10,150’
4-1/2" Tubing 12.6# / L-80 / EUE 8rd 3.958 ±10,184’ ±10,390’
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kuparuk
±11,102’ ±11,602’ ±7,206’ ±7,206’ ±500 Future Future
±12,235’ ±12,405’ ±7,227’ ±7,222’ ±170 Future Future
±12,600’ ±12,733 ±7,217’ ±7,211’ ±133 Future Future
±12,733’ ±12,835’ ±7,211’ ±7,204’ ±102 Future Future
±12,930’ ±13,233’ ±7,199’ ±7,192’ ±303 Future Future
GENERAL WELL INFO
API: 50-029-22335-01-00
Drilled and Cased by Nabors 22E - 5/16/1993
ESP Change-out by Nabors 4ES – 2/22/1995, 11/17/1999 & 8/3/2003
ESP Change-out by Nabors 3S – 1/27/2008 & 6/14/2008
ESP Change-out by Doyon 16 – 12/12/2013
A Sidetrack by CDR2 - Future
Well: MPU L-13A
Scope: Post-CTD APERF + ESP RWO
Coiled Tubing BOPE
Well: MPU L-13A
Scope: Post-CTD APERF + ESP RWO
Standing Orders for Open Hole Well Control during Perf Gun Deployment
Well: MPU L-13A
Scope: Post-CTD APERF + ESP RWO
Equipment Layout Diagram
Updated 6/21/18
11” BOPE
11'͛-5000
11" - 5000
2-7/8" x 5" VBR
Blind
11'͛- 5000
2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves
HCRManualManual
Stripping Head
ManualManual
Milne Point
ASR 11” BOP w/ Jacks
05/17/2017
Milne Point
ASR 11” BOP (Triple)
5/24/2022
2-3/8" Pipe Ram
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Dr., Suite 1400
Anchorage, AK, 99503
Re: Milne Point Field, Kuparuk River Oil, MPU L-13A
Hilcorp Alaska, LLC
Permit to Drill Number: 223-017
Surface Location: 1916’ FNL, 136’ FWL, Sec. 8, T13N, R10E, Umiat
Bottomhole Location: 764’ FSL, 1833’ FWL, Sec. 31, T14N, R10E, Umiat
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
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 March, 2023. 3
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2023.03.03 09:17:42
-09'00'
1a.
Contact Name:Sean McLaughlin
Contact Email:sean.mclaughlin@hilcorp.comAuthorized Name: Monty Myers
Authorized Title:Drilling Manager
Authorized Signature:
Contact Phone:907-223-6784
Approved by:COMMISSIONER
APPROVED BY
THE COMMISSION Date:
21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated
from without prior written approval.
Drill
Type of Work:
Redrill 5
Lateral
1b.Proposed Well Class:Exploratory - Gas
5
Service - WAG
5
1c. Specify if well is proposed for:
Development - Oil Service - Winj
Multiple Zone Exploratory - Oil
Gas Hydrates
Geothermal
Hilcorp Alaska, LLC Bond No. 22224484
11. Well Name and Number:
MPU L-13A
TVD:13159'7199'
12. Field/Pool(s):
MILNE POINT FIELD
KUPARUK RIVER OIL POOL
MD:
ADL 025509 & 355018
88-002 April 20, 2023
4a.
Surface:
Top of Productive Horizon:
Total Depth:
1916' FNL, 136' FWL, Sec. 08, T13N, R10E, UM, AK
1522' FNL, 847' FWL, Sec. 06, T13N, R10E, UM, AK
Kickoff Depth:10535 feet
Maximum Hole Angle: 90 degrees
Maximum Anticipated Pressures in psig (see 20 AAC 25.035)
Downhole:Surface:3659 3017
17.Deviated wells:16.
Surface: x-y- Zone -544736 6031553 4
10. KB Elevation above MSL:
GL Elevation above MSL:
feet
feet
51.0'
17.0'
15.Distance to Nearest Well
Open to Same Pool:
Cement Quantity, c.f. or sacks
MD
Casing Program:
10360'6986'
19.PRESENT WELL CONDITION SUMMARY
Production
80 300 sx Arctic I
11016 7409 None 10868 7311 Unknown
30 - 110
Surface 1780 sx AS III, 300 sx Class G
7072 - 7213
Seabed Report Drilling Fluid Program 5 20 AAC 25.050 requirements
Shallow Hazard Analysis
5
Commission Use Only
See cover letter for other
requirements:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No
H2S measures Yes No
Spacing exception req'd: Yes No
Mud log req'd: Yes No
Directional svy req'd: Yes No
Inclination-only svy req'd: Yes No
Other:
Date:
Address:
Location of Well (State Base Plane Coordinates - NAD 27):
9.3#/6.6#
6057
10498 - 10719
50-029-22335-01-00
Intermediate
Conductor/Structural
Single Zone
Service - Disp
No YesPost initial injection MIT req'd:
No Yes 5
Diverter Sketch
Comm.
TVD
API Number:
MD
Sr Pet Geo
764' FSL, 1833' FWL, Sec. 31, T14N, R10E, UM, AK
Time v. Depth Plot 5 5 Drilling Program
8871'
(To be completed for Redrill and Re-Entry Operations)
13-3/8"
9-5/8"
STL/TCII
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
Stratigraphic Test
Development - Gas Service - Supply
Coalbed Gas
Shale Gas
2.Operator Name:5.Bond Blanket 5 Single Well
3.
3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503
6. Proposed Depth:
7. Property Designation (Lease Number):
8. DNR Approval Number:13.Approximate spud date:
9.Acres in Property: 14. Distance to Nearest Property:
Location of Well (Governmental Section):
4b.
7616
1868'
18.Specifications Top - Setting Depth - Bottom
Casing Weight Grade TVDHole Coupling Length TVD (including stage data)
x2-7/8" /6.5# /STL
Total Depth MD (ft): Total Depth TVD (ft):
Plugs (measured):Effect. Depth MD (ft): Effect. Depth TVD (ft):Junk (measured):
Casing Length Size MD
30 - 110
29 - 6086 29 - 4409
10969 7"325 sx Class G 27 - 10996 27 - 7396
Liner
Perforation Depth MD (ft):Perforation Depth TVD (ft):
20. Attachments Property Plat BOP Sketch
Permit to Drill
Number:
Permit Approval
Date:
Reentry
Hydraulic Fracture planned?
Sr Pet Eng Sr Res Eng
Cement Volume
Comm.
13159'7199'168 sx Class G4-1/4"3-1/2"x3-1/4"L-80 2799'
Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval (20 AAC 25.005(g))
2.24.2023
By Samantha Carlisle at 10:32 am, Feb 27, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.02.24 22:39:03 -09'00'
Monty M
Myers
DSR-2/27/23SFD 3/1/2023MGR27FEB2023
3017
* Variance to 20 AAC 25.112(i) approved for
alternate plug placement for parent abandonment.
* Separate additional completion sundry required
before POP. *10-407 post liner cementing for parent (MPU L-13) abandonment.
* BOPE test to 3500 psi.
223-017
JLC 3/3/2023
3/3/2023Brett W. Huber, Sr.Digitally signed by Brett W. Huber, Sr.
Date: 2023.03.03 09:18:10 -09'00'
To: Alaska Oil & Gas Conservation Commission
From: Sean McLaughlin
CTD Engineer
Date: February 24, 2023
Re: MPL-13A Permit to Drill Request
Approval is requested for a permit to drill a CTD sidetrack lateral from well MPL-13 with the Nabors CDR2
Coiled Tubing Drilling rig on or around April 2023.
Proposed plan for MPL-13A:
A RWO will be conducted independently of the drilling operation to install a 4-1/2” completion. The whipstock will be set
pre-rig in the 7” casing. The CDR2 rig will move in, test BOPE and kill the well. The well will kick off in the Kuparuk, build
through the C and B intervals to land in the A sands. A ~2,625’ coil tubing drilling sidetrack will be drilled in the A sands. The
sidetrack will be completed with a 3-1/2” x 3-1/4” x 2-7/8” L80 solid liner, cemented in place and selectively perforated post
rig. This completion will completely isolate and abandon the parent perforations.
The following describes the work planned. A wellbore schematic of the current well and proposed sidetrack is attached for
reference.
Pre-Rig Work (scheduled to begin March, 2023)
1.Tubing swap (conducted under separate sundry)
2.Set 7” Whipstock
3.Pre-CTD Tree work.
Rig Work (scheduled to begin April 2023)
1. MIRU and test BOPE 250 psi low and 3,500 psi high (MASP: 3017 psi).
2. Mill single string window @10535’
3. Drill build section: 4.25" OH, ~325' (25 deg DLS planned).
4. Drill lateral section: 4.25” OH, ~2300’ (12 deg DLS planned).
5.
Swap BOP rams from 3” pipe/slip (drilling) to 2-3/8”x3-1/2” VBRs (running liner) and test
to 3500 psi.
6. Run 2-7/8” x 3-1/4” x 3-1/2” L-80 liner to TD.
7. Pump primary cement job: 37 bbls, 15.3 ppg Class G, TOC at TOL (~10,360 MD).*
8. Perforate ~1500.
9. Close in tree, RDMO.
* Approved alternate plug placement per 20 AAC 25.112(i)
Post-Rig Work:
1. V: Valve & tree work
2. S: Set LTP* (if necessary).
3. T: Portable test separator flowback.
Current BHP gradient ~10.0 ppg
24 houir notice for AOGCC to
witness.
mgr
Sundry
PTD 223-017
mgr Eline
s completion will completely isolate and abandon the parent perforations.
Managed Pressure Drilling:
The history of CTD at KRU in the Kuparuk reservoir, has demonstrated the benefits of a managed pressure
drilling technique. Due to uncertainties about the bottom hole pressures and stability concerns, managed
pressure drilling techniques will be employed on this well. The intent is to provide constant bottom hole pressure
by using minimum 8.6 ppg drilling fluid in combination with annular friction losses and applied surface pressure.
Constant BHP will be utilized to reduce pressure fluctuations to help with hole stability. Applying annular friction
and choke pressure also allow use of lighter drilling fluid and minimizes fluid losses and/or fracturing at the end of
the long well bores. A MPD choke for regulating surface pressure is located between the WC choke manifold and
the mud pits and will be independent of the WC choke.
Deployment of the BHA under trapped wellhead pressure will be necessary. Pressure deployment of the BHA will
be accomplished utilizing 3” pipe/slip rams (see attached BOP configuration). The annular preventer will act as a
secondary containment during deployment and not as a stripper.
Operating parameters and fluid densities will be adjusted based on real-time bottom hole pressure measurements
while drilling and shale behavior. The following scenario is expected for MPL-13A:
x Latest reservoir pressure in the parent well: 3659 psi (10.0 ppg)
MPD Pressure at the MPU L-13A Planned Window (10535’ MD - 7095’ TVD)
Operation Details:
Mud Program:
x Drilling: Minimum MW of 8.6 ppg KCL with Geovis for drilling(497 psi under-balance). Managed pressure used to
maintain constant BHP and overbalance.
x KWF will be stored on location. The tankage will contain 1.5 wellbore volumes of KWF (10.5 ppg expected) to
exceed the maximum possible BHP to be encountered as the lateral is drilled. Adjust with real time BHP
monitoring.
x Completion: A minimum MW 10.5 ppg KWF to be used for liner deployment. Will target 11.8 ppg to match
managed pressure target.
Disposal:
x All cuttings & mud generated during drilling operations will be hauled to the Milne Point “B” pad G&I facility.
Hole Size:
x 4.25” for entirety of the production hole section.
Liner Program:
x 2-7/8”, 6.5#, L80 solid liner: 11000’ MD – 13159’ MD
x 3-1/4”, 6.6#, L80 solid liner: 10510’ MD – 11000’ MD
x 3-1/2”, 9.3#, L80 solid liner: 10360’ MD – 10510’ MD
x A planned 37 bbls of 15.3 ppg cement will be used for liner cementing (TOC = TOL at ~10360’ MD).
p, gp
Due to uncertainties about the bottom hole pressures and stability concerns, managedgq
pressure drilling techniques will be employed on this well.
1.5 wellbore volumes of KWF (10.5 ppg expected)
p
3659 psi (10.0 ppg)
x The primary barrier for this operation: a minimum EMW of 10.5 ppg (200 psi over-balance)
x A X-over shall be made up to a safety joint including a TIW valve for all tubulars ran in hole.
Well Control:
x BOP diagram is attached.
x Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3,500 psi.
x The annular preventer will be tested to 250 psi and 3,500 psi.
x 1.5 wellbore volumes of KWF will be always on location during drilling operations.
x Liner Running Ram Change: Change out 3” pipe/slip rams (for drilling) to 2-3/8”x3-1/2” VBR rams for liner run. Test
VBR rams to 250 psi and 3,500 psi.
x 2-3/8” safety joint will be utilized while running 2-7/8”, 3-1/4”, 3-1/2” solid or slotted liner. The desire is to keep the
same standing orders for the entire liner run and not change shut in techniques from well to well (run safety joint
with pre-installed TIW valve). When closing on a 2-3/8” safety joint, 2 sets of pipe/slip rams will be available, above
and below the flow cross providing better well control option.
Directional:
x See attached directional plan. Maximum planned hole angle is 90°, inclination at kick off point is 51°.
x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run.
x Distance to nearest property line – 8871’ & Distance to nearest well within pool – 1868’
Logging:
x MWD directional, Gamma Ray, and Resistivity will be run through the entire open hole section.
x Real time bore pressure to aid in MPD and ECD management.
Perforating:
x Perforating: ~1500’ of perforations – 2”, 60 deg random phasing, 6 spf, perf guns.
x A X-over shall be made up to a safety joint including a TIW valve for all tubulars ran in hole.
Anti-Collision Failures:
x None
Hazards:
x MPL is considered an H2S pad. Most recent H2S reading on MPL-13 was 2 ppm (10/16/22). Max H2S reading on
pad on well MPL-32 at 410 ppm.
x No fault crossings.
x Overall Lost circulation risk is considered low.
Reservoir Pressure:
x The EMW reservoir pressure is expected to be 3659 psi at 7069’ TVDSS (10.0 ppg equivalent at the window).
x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 3017 psi (At TD)
Sean McLaughlin CC: Well File
Drilling Engineer Joseph Lastufka
223-6784
MPL is considered an H2S pad.
_____________________________________________________________________________________
Revised By TDF: 2/6/2023
PROPOSED
Milne Point Unit
Well: MPU L-13
Last Completed: 12/13/2013
PTD: 193-012
TD = 10,996’ (MD) / TD = 7,357’(TVD)
20”
Orig. KB Elev.: 46’/ Orig. GL Elev.: 16.5’
Nabors 22E / RT to 7”Hanger= 28.5’
7”
9-5/8”
1
PBTD = 10,868’(MD) / PBTD = 7,312’(TVD)
KUP B Sands
KUP A Sands
2
3
4
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
13-3/8" Conductor 54.5 / K-55 / BTRC 12.415 Surface 80'
9-5/8" Surface 47 / N-80 / BTRS 8.681 Surface 6,086’
7" Production 26 / L-80 / BTRC 6.276 Surface 10,996’
TUBING DETAIL
4-1/2" Tubing 12.6 / L-80 / EUE 8rd 3.958 Surface ±10,390’
JEWELRY DETAIL
No Depth Item
1 ±10,180’ Sliding Sleeve
2 ±10,250’ Packer
3 ±10,290’ XN Nipple
4 ±10,388’ WLEG: Bottom @ ±10,390’
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kuparuk
10,498’ 10,518’ 7,072’ 7,084’ 20 5/10/1993 Open
10,529’ 10,539’ 7,091’ 7,098’ 10 5/10/1993 Open
10,554’ 10,564’ 7,107’ 7,113’ 10 5/10/1993 Open
10,598’ 10,618’ 7,135’ 7,148’ 20 5/10/1993 Open
10,626’ 10,656’ 7,153’ 7,172’ 30 5/10/1993 Open
10,669’ 10,719’ 7,180’ 7,213’ 50 5/10/1993 Open
4.5” Guns 12SPF
OPEN HOLE / CEMENT DETAIL
13-3/8”" 300 sx of Arcticset I in 26” Hole
9-5/8" 1,780 sx of Arcticset III, 3000 sx Class ‘G’ in 12-1/4” Hole
7” 325 sx Class “G” in 8-1/2” Hole
WELL INCLINATION DETAIL
KOP @ 500’
Max Hole Angle = 54.5 deg. @ 3,811’ MD
TREE & WELLHEAD
Tree 2-9/16” – 5M WKM
Wellhead 11” 5M WKM, w/ 2-7/8” x 11” Tubing Hanger, 2-7/8” EUE
8rd Threads, 2.5” “H” BPV profile.
GENERAL WELL INFO
50-029-22335-00-00
Drilled and Cased by Nabors 22E - 5/16/1993
ESP Change-out by Nabors 4ES – 2/22/1995, 11/17/1999 & 8/3/2003
ESP Change-out by Nabors 3S – 1/27/2008 & 6/14/2008
ESP Change-out by Doyon 16 – 12/12/2013
STIMULATION DETAIL
Frac - 41,146# of 16/20 Carbolite behind pipe
_____________________________________________________________________________________
Revised By JNL: 2/6/2023
PROPOSED
Milne Point Unit
Well: MPU L-13
Last Completed: 12/13/2013
PTD: 193-012
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kuparuk
10,498’ 10,518’ 7,072’ 7,084’ 20 5/10/1993 Open
10,529’ 10,539’ 7,091’ 7,098’ 10 5/10/1993 Open
10,554’ 10,564’ 7,107’ 7,113’ 10 5/10/1993 Open
10,598’ 10,618’ 7,135’ 7,148’ 20 5/10/1993 Open
10,626’ 10,656’ 7,153’ 7,172’ 30 5/10/1993 Open
10,669’ 10,719’ 7,180’ 7,213’ 50 5/10/1993 Open
4.5” Guns 12SPF
GENERAL WELL INFO
50-029-22335-00-00
Drilled and Cased by Nabors 22E - 5/16/1993
ESP Change-out by Nabors 4ES – 2/22/1995, 11/17/1999 & 8/3/2003
ESP Change-out by Nabors 3S – 1/27/2008 & 6/14/2008
ESP Change-out by Doyon 16 – 12/12/2013
TD =10,996’ (MD) / TD = 7,357’(TVD)
20”
Orig. KB Elev.:46’/ Orig. GL Elev.: 16.5’
Nabors 22E / RT to 7”Hanger= 28.5’
7”
5
9-5/8”
1
Whipstock set
@10530’
PBTD = 10,868’(MD) / PBTD = 7,312’(TVD)
KUP B Sands
KUP A Sands
2
3
4
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
13-3/8" Conductor 54.5 / K-55 / BTRC 12.415 Surface 80'
9-5/8" Surface 47 / N-80 / BTRS 8.681 Surface 6,086’
7" Production 26 / L-80 / BTRC 6.276 Surface 10,996’
TUBING DETAIL
4-1/2" Tubing 12.6 / L-80 / EUE 8rd 3.958 Surface ±10,390’
JEWELRY DETAIL
No Depth Item
1 ±10,180’ Sliding Sleeve
2 ±10,250’ Packer
3 ±10,290’ XN Nipple
4 ±10,388’ WLEG: Bottom @ ±10,390’
5 10,530’ Whipstock
OPEN HOLE / CEMENT DETAIL
13-3/8”" 300 sx of Arcticset I in 26” Hole
9-5/8" 1,780 sx of Arcticset III, 3000 sx Class ‘G’ in 12-1/4” Hole
7” 325 sx Class “G” in 8-1/2” Hole
WELL INCLINATION DETAIL
KOP @ 500’
Max Hole Angle = 54.5 deg. @ 3,811’ MD
TREE & WELLHEAD
Tree 2-9/16” – 5M WKM
Wellhead 11” 5M WKM, w/ 2-7/8” x 11” Tubing Hanger, 2-7/8” EUE
8rd Threads, 2.5” “H” BPV profile.
STIMULATION DETAIL
Frac - 41,146# of 16/20 Carbolite behind pipe
_____________________________________________________________________________________
Revised By JNL: 2/15/2023
PROPOSED SCHEMATIC
Milne Point Unit
Well: MPU L-13A
Last Completed: TBD
PTD: TBD
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
13-3/8" Conductor 54.5 / K-55 / BTRC 12.415 Surface 80'
9-5/8" Surface 47 / N-80 / BTRS 8.681 Surface 6,086’
7" Production 26 / L-80 / BTRC 6.276 Surface 10,535’
3-1/2”x3-1/4”x2-7/8” Liner 9.3 x 6.6 x 6.5 / L-80 / STL x TCII 10,360’ 13,159’
TUBING DETAIL
4-1/2" Tubing 12.6 / L-80 / EUE 8rd 3.958 Surface 10,390’
JEWELRY DETAIL
No Depth Item
1 10,180’ Sliding Sleeve
2 10,250’ Packer
3 10,290’ XN Nipple
4 10,360’ Top 3-1/2” Liner
5 10,388’ WLEG: Bottom @ 10,390’
6 10,510’ 3-1/2” xo 3-1/4”
7 10,775’ 3-1/4” xo 2-7/8”
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kuparuk
GENERAL WELL INFO
API: 50-029-22335-01-00
Drilled and Cased by Nabors 22E - 5/16/1993
ESP Change-out by Nabors 4ES – 2/22/1995, 11/17/1999 & 8/3/2003
ESP Change-out by Nabors 3S – 1/27/2008 & 6/14/2008
ESP Change-out by Doyon 16 – 12/12/2013
A Sidetrack:TD =13,159’ (MD) / TD =7,199’(TVD)
20”
Orig. KB Elev.:46’/ Orig. GL Elev.: 16.5’
Nabors 22E / RT to 7”Hanger= 28.5’
7”
6 3-1/2”xo
3-1/4”
@ 10510’
9-5/8”
1
3-1/4xo
2-7/8”
@ 10775’
2-7/8”
PBTD = 13,159’(MD) / PBTD =7,199’(TVD)
Whipstock
set @
10530’ Top
of Window
@ 10535’
5
7
Top of Liner /
Cement
@ 10360’
2
3
4
OPEN HOLE / CEMENT DETAIL
26” 300 sx of Arcticset I
12-1/4” 1,780 sx of Arcticset III, 3000 sx Class G
8-1/2” 325 sx Class G”
4-1/4” 168 sx Classs G
WELL INCLINATION DETAIL
KOP @ 10535’
90 deg Hole Angle = 11075’ MD
TREE & WELLHEAD
Tree 2-9/16” – 5M WKM
Wellhead 11” 5M WKM, w/ 2-7/8” x 11” Tubing Hanger, 2-7/8” EUE
8rd Threads, 2.5” “H” BPV profile.
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Vertical Section at 28.85° (400 usft/in)
L-13A wp06 Polygon
MPL-13A wp06 toe
9 5 0 0
1 0 0 0 0
1 0 5 0 0
1 1 0 0 011016
MPL-13
7" TOW
2 7/8" x 3 1/4"
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MPL-13A wp06
K O P : Start Dir 9º/100' : 10535' M D, 7095'TV D : 0° RT TF
Start Dir 25º/100' : 10555' M D, 7107.3'TV D
Start Dir 12º/100' : 10859.2' M D, 7179.41'TVD
Total Depth : 13159.2' M D, 7199.39' TVD
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: MPL-13
Ground Level: 17.00
+N/-S +E/-W
Northing Easting Latitude Longitude
0.00 0.00 6031552.290 544736.420 70° 29' 49.4599 N 149° 38' 3.0129 W
SURVEY PROGRAM
Date: 2023-02-16T00:00:00 Validated: Yes Version:
Depth From Depth To Survey/Plan Tool
158.00 5993.00 MPL-13 EMS - SH (MPL-13) 3_EMS
6191.00 10535.00 MPL-13 EMS - Prod (MPL-13) 3_EMS
10535.00 13159.20 MPL-13A wp06 (Plan: MPL-13A) 3_MWD
FORMATION TOP DETAILS
No formation data is available
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well Plan: MPL-13, True North
Vertical (TVD) Reference:MPL-13 EMS SR RKB @ 51.00usft
Measured Depth Reference:MPL-13 EMS SR RKB @ 51.00usft
Calculation Method:Minimum Curvature Project:Milne Point
Site:M Pt L Pad
Well:Plan: MPL-13
Wellbore:Plan: MPL-13A
Design:MPL-13A wp06
CASING DETAILS
TVD TVDSS MD Size Name
7095.63 7044.63 10536.00 7 7" TOW
4409.23 4358.23 6086.00 9-5/8 9 5/8"
7199.39 7148.39 13159.20 2-7/8 2 7/8" x 3 1/4"
SECTION DETAILS
Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation
1 10535.00 51.16 314.10 7095.00 5695.44 -4486.35 0.00 0.00 -203.07 KOP : Start Dir 9º/100' : 10535' MD, 7095'TVD : 0° RT TF
2 10555.00 52.96 314.10 7107.30 5706.42 -4497.68 9.00 0.00 -198.93 Start Dir 25º/100' : 10555' MD, 7107.3'TVD
3 10693.87 80.00 338.23 7162.89 5811.74 -4564.91 25.00 45.00 -139.12
4 10859.20 89.00 18.81 7179.41 5972.61 -4568.61 25.00 80.00 0.01 Start Dir 12º/100' : 10859.2' MD, 7179.41'TVD
5 11109.20 89.63 48.81 7182.46 6177.95 -4431.09 12.00 89.00 246.22
6 11409.20 89.56 12.81 7184.65 6431.40 -4279.96 12.00 -90.25 541.13
7 11659.20 89.49 42.81 7186.78 6650.00 -4164.67 12.00 90.25 788.23
8 11909.20 89.43 12.81 7189.18 6868.61 -4049.38 12.00 -90.25 1035.33
9 12159.20 89.44 42.81 7191.70 7087.21 -3934.09 12.00 90.15 1282.43
10 12409.20 89.51 12.81 7194.05 7305.81 -3818.80 12.00 -90.00 1529.53
11 12659.20 89.58 42.81 7196.09 7524.42 -3703.51 12.00 90.00 1776.64
12 12909.20 89.63 12.81 7197.86 7743.03 -3588.21 12.00 -90.00 2023.75
13 13159.20 89.68 42.81 7199.39 7961.63 -3472.92 12.00 90.00 2270.85 Total Depth : 13159.2' MD, 7199.39' TVD
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Well Date
Quick Test Sub to Otis -1.1 ft
Top of 7" Otis 0.0 ft
Distances from top of riser
Excluding quick-test sub
Top of Annular 2.75 ft
C L Annular 3.40 ft
Bottom Annular 4.75 ft
CL Blind/Shears 6.09 ft
CL 2.0" Pipe / Slips 6.95 ft B3 B4
B1 B2
Kill Line Choke Line
CL 2-3/8" Pipe / Slip 9.54 ft
CL 2.0" Pipe / Slips 10.40 ft
TV1 TV2
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Master
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LDS
IA
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LDS
Ground Level
3" LP hose open ended to Flowline
CDR2-AC BOP Schematic
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Fill Line from HF2
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3" HP hose to Micromotion
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2 3/8" Pipe/Slips
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HF
nneceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
MPU L-13A
Milne Point Kuparuk River Oil
223-017
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Da
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:
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Da
t
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JL
C
3
/
3
/
2
0
2
3
