Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation Commission
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HomeMy WebLinkAbout223-037DA
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1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program
Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ESP Completion
Development Exploratory
Stratigraphic Service 6. API Number:
7. Property Designation (Lease Number): 8. Well Name and Number:
9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s):
11. Present Well Condition Summary:
Total Depth measured 13,462 feet N/A feet
true vertical 7,080 feet N/A feet
Effective Depth measured 13,434 feet 11,901 & 12,102 feet
true vertical 7,080 feet 6,646 & 6,821 feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5 / L-80 / EUE 11,798' 6,554'
7" x 4-1/2" D&L Perm. Hydro ISO
Packers and SSSV (type, measured and true vertical depth)LTP N/A See Above N/A
12. Stimulation or cement squeeze summary: N/A
Intervals treated (measured):
Treatment descriptions including volumes used and final pressure: N/A
13a.
Prior to well operation:
Subsequent to operation:
13b. Pools active after work:
15. Well Class after work:
Daily Report of Well Operations Exploratory Development Service Stratigraphic
Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL
Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG
Sundry Number or N/A if C.O. Exempt:
Authorized Name and
Digital Signature with Date: Contact Name:
Contact Email:
Authorized Title: Wells Manager Contact Phone:
324-231
Sr Pet Eng:
11,170psi
Sr Pet Geo: Sr Res Eng:
WINJ WAG
0
Water-BblOil-Bbl
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
N/A
Ryan Lewis
ryan.lewis@hilcorp.com
303-906-5178
measured
true vertical
Packer
Representative Daily Average Production or Injection Data
Casing Pressure Tubing Pressure
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
266
Gas-Mcf
MD
114'
540
Size
114'
4,165'
164 32050
0 3340
340
measured
TVD
3-1/2"
10,570psi
3-1/4"
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
223-037
50-029-22786-02-00
3800 Centerpoint Dr, Suite 1400
Anchorage, AK 99503
3. Address:
Hilcorp Alaska LLC
N/A
5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work:
ADL0025509, ADL0025514 & ADL0025515
MILNE POINT / KUPARUK RIVER OIL
MILNE PT UNIT L-39B
Plugs
Junk measured
Length
Liner
Liner
67'
413'
1,603'
Casing
Conductor
6,882'
1,089'
2-7/8"
12,172'
12,585'
13,462' 7,079'
12,194'
8,649'Surface
Intermediate
Liner
20"
9-5/8"
7"
80'
8,613'
10,540psi
7,900psi
5,750psi
7,240psi
10,160psi
8,620psi
12,277' 6,932'
Burst
N/A
Collapse
N/A
3,090psi
5,410psi
PL
G
Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2024.07.02 14:30:44 -
08'00'
Taylor Wellman
(2143)
By Grace Christianson at 2:53 pm, Jul 02, 2024
RBDMS JSB 070324
DSR-7/8/24WCB 12-3-2024
_____________________________________________________________________________________
Revised By: TDF 7/1/2024
SCHEMATIC
Milne Point Unit
Well: MPU L-39B
Last Completed: 6/1/2024
PTD: 223-037
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20" Conductor 91.1 / H-40 / N/A N/A Surface 114'
9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’
7" Production 26 / L-80 / NSCC 6.276 Surface 12,227’
3-1/2” Liner 9.2 / L-80 / STL 2.992 12,105’ 12,172’
3-1/4” Liner 6.6 / L-80 / TCII 2.805 12,172’ 12,585’
2-7/8” Liner 6.5 / L-80 / Hyd 511 2.441 12,585’ 13,462’
TUBING DETAIL
2-7/8” Tubing 6.5 / L-80 / EUE 2.441 Surface 11,798’
4-1/2” Tubing 12.6/L-80/TXPxEZGOxDWC 3.958 11,859’ 12,136’
JEWELRY DETAIL
No Depth Item
1 158’ 2-7/8" x 1" GLM, 1/4" OV
2 11,625’ 2-7/8" x 1" GLM, DV installed
3 11,681’ XN-nipple 2.313" / 2.205" No-Go
4 11,732’ Discharge Head: B/O Pump 400
5 11,733’ Press Port: Zenith Head
6 11,734’ Pump #2: 400PMSSD 126 FLEX7 ER
7 11,756’ Pump #1: 400PMSXD 92 G4 HS FER
8 11,766’ Gas Separator: 400GM2TV X MT HS FER NO_PNT
9 11,770’ Intake: GAS AVOIDER 400 GRAVITY CUP LS H6
10 11,772’ Upper Tandem Seal: GS3 B/B/L SB H6 PFSA HL FER 12CRC
11 11,779’ Lower Tandem Seal: GS3 B/B/L SB H6 PFSA HL FER 12CRC
12 11,785’ Motor: 562XP 100/1820/34/4R 12CRC
13 11,794’ Zenith Sensor W/ Centralizer: E7 MW 456 – Btm @ 11,798’
14 11,901’ 7” x 4-1/2” D&L Permanent Hyd ISO Packer
15 11,201’ X Nipple Min ID = 3.813”
16 12,102’ Liner Top Packer
17 12,105’ Deployment Sleeve – 3.70” x 3.00” Polish Bore
18 12,094’ Wireline Entry – Mule Shoe – Bottom @ 12,136’ (Behind CTD Liner)
OPEN HOLE / CEMENT DETAIL
24" 250 sx of Arcticset I (Approx)
12-1/4" 2199 sx PF E, 550 sx Class G
8-1/2” 275 sx Class G
4-1/4” 93 sx Class G
WELL INCLINATION DETAIL
KOP @ 12,227’
90 deg Hole Angle = 12,620’
TREE & WELLHEAD
Tree 5M Cameron 2-9/16”
Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH
Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile
TD = 13,462’ (MD) / TD = 7,080’(TVD)
14
20”
TOC @
12,320 (CBL
dated
6/30/23
KB Elev.: 51.42’, GL Elev.: 17.1’
7”
16 & 17
18
15
2
4& 5
10 & 11
9-5/8”
1
12
13
3-1/2” xo
3-1/4”
8& 9
3
Top of
Deployment
Sleeve @
12,105’, LTP
@ 12,102’
Whipstock
set / TOW @
12,227’
Tubing Cut @
11,859’
3-1/4” xo
2-7/8”A Whipstock
set @
12,255’
PBTD = 13,434’ (MD) / PBTD = 7,080’(TVD)
6 & 7
GENERAL WELL INFO
API: 50-029-22786-02-00
Drilled and Cased by Nabors 27E - 6/29/1997
A Sidetrack CDR2: 6/13/2023
B Sidetrack: 6/20/2023
ESP Install by ASR: 9/9/2023
ESP Swap by ASR: 6/1/2024
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kuparuk 12,867’ 12,880’ 7,066’ 7,064’ 13 7/1/2023 Open
12,935’ 13,195’ 7,058’ 7,061’ 260 7/1/2023 Open
13,252’ 13,315’ 7,065’ 7,072’ 63 7/1/2023 Open
Well Name Rig API Number Well Permit Number Start Date End Date
MP L-39B ASR#1 50-029-22786-02-00 223-037 5/29/2024 6/2/2024
No operations to report.
Completed reel to reel ESP cable splice. Test cable (good) Cont. RIH W/ ESP F/ 7,890' T/ 11,747'. P/U HANGER.
Completed hanger splice. Land hanger with BPV installed. Final P/U wt = 82K S/O wt = 28K End of ESP completion = 11,798'.
RILDS w/ wellhead rep. Begin RDMO of L-39B. Begin cleaning & maintenance tasks prior to rig move while I-06 in prepped for
RWO.
6/1/2024 - Saturday
WELLHEAD; N/U adaptor/ tree test void 500 low 5000 high 5/10 min (good test). IA and TB was dead pull BPV with T-Bar.
6/4/2024 - Tuesday
6/2/2024 - Sunday
No operations to report.
6/3/2024 - Monday
5/31/2024 - Friday
RIH w/ slick line. Tag at 3,065' Set down. Attempt to pump down. Not advancing down hole. POOH. AT surface with tools.
Protectolizer "door " recovered on magnet. R/D tools & slick line. P/U Motor install cent. & service motor. P/U & service lower
& upper tandem seals. Attach MLE. P/U, intake, gas sep. , 2 pump & DS head. XO to 2-7/8" EUE
Completed ESP assembly 76' total length, RIH w/ 2-7/8" 6.5# L-80 EUE RIH T/ 7,890'. Monitor fluid displacement. Running in
at 60 FPM. Test ESP cable every 1000' S/O wt = 13K BEGIN ESP reel to reel splice.
5/29/2024 - Wednesday
Hilcorp Alaska, LLC
Weekly Operations Summary
Begin BOPE testing as per approved sundry. AOGCC waived witness to test. Test t/ 250 psi low & 2500 psi high f/ 5/5 charted
mins. Completed BOPE testing w/ 1 fail/pass test & perform accumulator drawdown test. L/D test tools. B/D fluid lines & line
up BOPE equip. for well operations. Remove fresh water from pits. Hang ESP sheave in derrick. Pulls CTS & BPV. IA & tubing
static. Shut blinds, open tubing to choke to monitor. Cont. to prep for ESP pull, while waiting on trucks for brine. Load brine
into pits & fill gas buster w/ 9.0 ppg NA/CL brine. P/U & M/U landing joint. BOLDS. Pull hanger to rig floor. P/U wt = 83K. L/D
hanger attach ESP cable to spooler. POOH ESP completion laying down 2-7/8" 6.5# L-80 EUE tubing. F/ 11,870' T/ 8,713' P/U
wt = 58K Pump double displacement for pipe pulled OOH.
5/30/2024 - Thursday
Cont. POOH ESP completion laying down 2-7/8" 6.5# L-80 EUE tubing. F/ 8,713' t/ discharge head at 88' Begin laying down ESP
assy. Completed laying down ESP DS head, zenith ported sub, 2 pumps, gas sep., Intake, upper & lower seals, motor, gauge &
cent. observed a missing "door" for protectolizer clamp. Clean & clear rig floor of ESP equip. Remove ESP sheave from derrick.
Remove containment hose & drip pan. Load up dutch riser & prep for slick line. P/U dutch riser & space out. Shut in & Lock in
rams. Spot in slick line unit. P/U & M/U slick line tools. Magnet roller, roller bars & spang jars. & 3.98" centralizer.
Cont. RIH W/ ESP F/ 7,890' T/ 11,747'. P/U HANGER.
Completed hanger splice. Land hanger with BPV installed. Final P/U wt = 82K S/O wt = 28K End of ESP completion = 11,798'.
RILDS w/ wellhead rep. Begin RDMO
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 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?
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):
13,462'N/A
3 Collapse
Conductor N/A
Surface 3,090psi
Intermediate 5,410psi
Liner 10,540psi
Liner 7,900psi
Liner 11,170psi
Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft):
12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work:
Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service
14. Estimated Date for 15. Well Status after proposed work:
Commencing Operations: OIL WINJ WDSPL Suspended
16.Verbal Approval: Date: GAS WAG GSTOR SPLUG
AOGCC Representative: GINJ Op Shutdown Abandoned
Contact Name:
Contact Email:
Contact Phone:
Authorized Title: Wells Manager
Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number:
Plug Integrity BOP Test Mechanical Integrity Test Location Clearance
Other Conditions of Approval:
Post Initial Injection MIT Req'd? Yes No
APPROVED BY
Approved by: COMMISSIONER THE AOGCC Date:
Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng
7,079'
7" x 4-1/2" D&L Perm. Hydro ISO & LTP and N/A 11,901 MD/ 6,646 TVD & 12,102 MD/ 6,821 TVD and N/A
Ryan Lewis
ryan.lewis@hilcorp.com
303-906-5178
2-7/8" 6.5 / L-80 / EUE 11,801'
12,585'
Perforation Depth MD (ft):
12,172'
See Schematic
413'
2-7/8"
See Schematic
13,462'1,603'
4-1/2"
1,089'3-1/4"
80' 20"
9-5/8"
7"
8,613'
3-1/2"67'
12,194'
MD
N/A
10,160psi
5,750psi
7,240psi
4,165'
6,932'
6,882'
8,649'
12,277'
Length Size
Proposed Pools:
114' 114'
12.6 / L-80 / TXPxEZGOxDWC
TVD Burst
12,136'
8,620psi
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0025509, ADL0025514 & ADL0025515
223-037
3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-22786-02-00
Hilcorp Alaska LLC
C.O. 432E
AOGCC USE ONLY
10,570psi
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft):
5/19/2024
Subsequent Form Required:
Suspension Expiration Date:
Will perfs require a spacing exception due to property boundaries?
Current Pools:
MPSP (psi): Plugs (MD):
17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval.
Authorized Name and
Digital Signature with Date:
Tubing Size:
PRESENT WELL CONDITION SUMMARY
MILNE PT UNIT L-39B
MILNE POINT KUPARUK RIVER OIL N/A
7,080' 13,434' 7,080' 1,633 N/A
No
Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov
By Grace Christianson at 1:16 pm, Apr 19, 2024
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2024.04.19 12:41:13 -
08'00'
Taylor Wellman
(2143)
324-231
DSR-4/23/24
1,633
* BOPE test to 2500 psi.
MGR19APR24 SFD 4/22/2024
10-404
*&:
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2024.04.25 14:28:34
-08'00'04/25/24
RBDMS JSB 042624
Well: MPL-39B
PTD: 223-037
API: 50-029-22786-02-00
Well Name:MPL-39B API Number:50-029-22786-02-00
Current Status:Shut-in Producer Rig:ASR #1
Estimated Start Date:5/19/23 Estimated Duration:5 days
Regulatory Contact:Tom Fouts Permit to Drill Number:223-037
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: 2,288 psi @ 6,553’ TVD 2/12/2024 | 6.8 EMW, 7.0 KWF
Max Potential Surface Pressure: 1,633 psi Gas Column Gradient (0.1 psi/ft)
Max Angle:79° Sail Angle from 6,050’ MD
Brief Well Summary:
MPU L-39A is a slant producer in the Kuparuk A-sand that was sidetracked across a fault to the South to access
unswept oil (PTD 223-036). That fault block was found to be wet and not contain economic quantities of oil.
MPU L-39A was sidetracked into the existing block (PTD# 223-037) to the North to gain more footage in the
block becoming MPU L-39B. September 2023, a RWO was performed to install an ESP. The ESP failed after 4
months and will be replaced.
Objectives:
Pull failed ESP completion, run new ESP completion.
Notes Regarding Wellbore Condition:
- 7” casing test to 3,600 psi on 5/14/2023 at 11,901’ MD.
Pre-Rig Procedure (Non Sundried Work)
Slickline
1. RU slickline, pressure test PCE to 250psi low / 2,500psi high.
2. Drift and tag with sample bailer.
3. Attempt to pull dummy valve from GLM at 11,584’ MD and leave open.
4. Pull GLV and set dummy valve in upper GLM at 144’ MD.
5. RDMO.
Coiled Tubing (Contingency)
1. Pressure test PCE to 250 psi low / 2,500 psi high.
2. PU 1.75” jet nozzle.
3. Jet down to discharge head at 11,720’ MD.
4. Following best practices in PE manual, pump gel sweeps to clean up tubing.
5. Chase gel out of hole.
6. PU tubing punch.
7. RIH and tag discharge head.
8. Pump down ball to fire tubing punch.
9. Confirm circulation by pumping down backside of coil.
10. Freeze protect tubing as POOH.
11. RDMO.
Pumping & Well Support
Well: MPL-39B
PTD: 223-037
API: 50-029-22786-02-00
1. Clear and level pad area in front of well. Spot rig mats and containment.
2. RD well house and flowlines. Clear and level area around well.
3. RU Little Red Services. RU reverse out skid and 500 barrel returns tank.
4. Pressure test lines to 3,000 psi.
5. Circulate at least one wellbore volume with produced water down tubing, taking returns up casing
to 500 barrel returns tank.
6. Confirm well is dead. Contact operations engineer if freeze protection is needed prior to ASR
arrival.
7. RD Little Red Services and reverse out skid.
8. Set BPV. ND tree. NU BOPE.
Brief RWO Procedure (Begin Sundried Work)
1. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment, and lines to 500 barrel returns tank.
2. Check for pressure and if 0 psi set CTS plug. If needed, bleed off any residual pressure off tubing
and casing.
a. If needed, kill well with produced water prior to setting CTS.
3. Test BOPE to 250 psi low/ 2,500 psi high. Test annular to 250 psi low/ 2,500 psi high (hold each
ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests.
a. Perform test per ASR 1 BOP Test Procedure
b. Notify AOGCC 24 hours in advance of BOP test.
c. Confirm test pressures per the Sundry conditions of approval.
d. Test VBR rams on 2-7/8” test joint.
e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test.
4. Bleed any pressure on casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the
returns tank. Kill well with produced water as needed. Pull BPV.
a. If indications show pressure underneath BPV, lubricate out BPV.
5. Call out Centrilift for ESP pull.
6. RU spoolers to handle ESP cable.
7. MU landing joint or spear, BOLDS, PU on the tubing hanger.
a. Tubing hanger is an FMC 11” x 2-7/8”, with 2-7/8” EUE thread.
b. 2023 tubing PU weight on ASR #1 recorded as 78 kip. Slack off weight recorded as 33 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. Re-use all visually good tubing.
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: 190
ii. Protectolizers: 6
Well: MPL-39B
PTD: 223-037
API: 50-029-22786-02-00
iii. Flat Guards: 2
10. Lay Down ESP.
11. RIH with new 2-7/8” 6.5# L-80 ESP completion to +/- 11,800’ 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 - 100HP 80
5.2 7 Lower Tandem Seal 38
5.2 7 Upper Tandem Seal 38
5.2 8 Gas Separator 52
5.38 71 Pumps – Flex-7 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" 11,300 2-7/8" EUE 8rd Jt 6.5 L-80
2-7/8"10 2-7/8" EUE 8rd Pup Jt 6.5 L-80
2-7/8"8 2-7/8" x 1" GLM, 1/4" OV 6.5 L-80 ~200 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
12. Land tubing hanger. Use extra caution to not damage cable.
13. Lay down landing joint.
14. Set BPV.
15. RDMO ASR.
Post-Rig Procedure:
Well Support
Well: MPL-39B
PTD: 223-037
API: 50-029-22786-02-00
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. BOPE Schematic
_____________________________________________________________________________________
Revised By: TDF 4/5/2024
SCHEMATIC
Milne Point Unit
Well: MPU L-39B
Last Completed: 9/9/2023
PTD: 223-037
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20" Conductor 91.1 / H-40 / N/A N/A Surface 114'
9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’
7" Production 26 / L-80 / NSCC 6.276 Surface 12,227’
3-1/2” Liner 9.2 / L-80 / STL 2.992 12,105’ 12,172’
3-1/4” Liner 6.6 / L-80 / TCII 2.805 12,172’ 12,585’
2-7/8” Liner 6.5 / L-80 / Hyd 511 2.441 12,585’ 13,462’
TUBING DETAIL
2-7/8” Tubing 6.5 / L-80 / EUE 2.441 Surface 11,801’
4-1/2” Tubing 12.6/L-80/TXPxEZGOxDWC 3.958 11,859’ 12,136’
JEWELRY DETAIL
No Depth Item
1 144’ 2-7/8” x 1” Side Pocket GLM w/ DPSOV & BK Latch
2 11,584’ 2-7/8” x 1” Side Pocket GLM w/ Dummy and BK Latch
3 11,670’ XN Nipple Min ID = 2.205”
4 11,720’ Discharge Head
5 11,721’ Zenith Ported Sub
6 11,721 Pump #1
7 11,749’ Pump #2
8 11,759’ Gas Separator
9 11,765’ Intake
10 11,766’ Upper Tandem Seal
11 11,772’ Lower Tandem Seal
12 11,779’ Motor
13 11,796’ Motor Gauge
14 11,799’ Centralizer
15 11,901’ 7” x 4-1/2” D&L Permanent Hyd ISO Packer
16 11,201’ X Nipple Min ID = 3.813”
17 12,102’ Liner Top Packer
18 12,105’ Deployment Sleeve – 3.70” x 3.00” Polish Bore
19 12,094’ Wireline Entry – Mule Shoe – Bottom @ 12,136’ (Behind CTD Liner)
OPEN HOLE / CEMENT DETAIL
24" 250 sx of Arcticset I (Approx)
12-1/4" 2199 sx PF E, 550 sx Class G
8-1/2” 275 sx Class G
4-1/4” 93 sx Class G
WELL INCLINATION DETAIL
KOP @ 12,227’
90 deg Hole Angle = 12,620’
TREE & WELLHEAD
Tree 5M Cameron 2-9/16”
Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH
Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile
TD = 13,462’ (MD) / TD = 7,080’(TVD)
15
20”
TOC @
12,320 (CBL
dated
6/30/23
KB Elev.: 51.42’, GL Elev.: 17.1’
7”
16 & 17
19
18
2
4
9 & 10
11
9-5/8”
1
12
13
14
3-1/2” xo
3-1/4”
8
3
Top of
Deployment
Sleeve @
12,105’, LTP
@ 12,102’
Whipstock
set / TOW @
12,227’
Tubing Cut @
11,859’
3-1/4” xo
2-7/8”A Whipstock
set @
12,255’
PBTD = 13,434’(MD)/ PBTD = 7,080’(TVD)
5& 6& 7
GENERAL WELL INFO
API: 50-029-22786-02-00
Drilled and Cased by Nabors 27E - 6/29/1997
A Sidetrack CDR2: 6/13/2023
B Sidetrack: 6/20/2023
ESP Install by ASR: 9/9/2023
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kuparuk 12,867’ 12,880’ 7,066’ 7,064’ 13 7/1/2023 Open
12,935’ 13,195’ 7,058’ 7,061’ 260 7/1/2023 Open
13,252’ 13,315’ 7,065’ 7,072’ 63 7/1/2023 Open
_____________________________________________________________________________________
Revised By: TDF 4/5/2024
PROPOSED
Milne Point Unit
Well: MPU L-39B
Last Completed: 9/9/2023
PTD: 223-037
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20" Conductor 91.1 / H-40 / N/A N/A Surface 114'
9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’
7" Production 26 / L-80 / NSCC 6.276 Surface 12,227’
3-1/2” Liner 9.2 / L-80 / STL 2.992 12,105’ 12,172’
3-1/4” Liner 6.6 / L-80 / TCII 2.805 12,172’ 12,585’
2-7/8” Liner 6.5 / L-80 / Hyd 511 2.441 12,585’ 13,462’
TUBING DETAIL
2-7/8” Tubing 6.5 / L-80 / EUE 8rd 2.441 Surface ±11,800’
4-1/2” Tubing 12.6/L-80/TXPxEZGOxDWC 3.958 11,859’ 12,136’
JEWELRY DETAIL
No Depth Item
1 ±200’ 2-7/8" x 1" GLM, 1/4" OV
2 ±XX,XXX’ 2-7/8" x 1" GLM, DV installed
3 ±XX,XXX’ XN-nipple 2.313" / 2.205" No-Go
4 ±XX,XXX’ Discharge Head:
5 ±XX,XXX’ Press Port:
6 ±XX,XXX’ Pump #1
7 ±XX,XXX’ Pump #2
8 ±XX,XXX’ Gas Separator
9 ±XX,XXX’ Intake
10 ±XX,XXX’ Upper Tandem Seal
11 ±XX,XXX’ Lower Tandem Seal
12 ±XX,XXX’ Motor
13 ±XX,XXX’ Zenith Sensor W/ Centralizer
14 11,901’ 7” x 4-1/2” D&L Permanent Hyd ISO Packer
15 11,201’ X Nipple Min ID = 3.813”
16 12,102’ Liner Top Packer
17 12,105’ Deployment Sleeve – 3.70” x 3.00” Polish Bore
18 12,094’ Wireline Entry – Mule Shoe – Bottom @ 12,136’ (Behind CTD Liner)
OPEN HOLE / CEMENT DETAIL
24" 250 sx of Arcticset I (Approx)
12-1/4" 2199 sx PF E, 550 sx Class G
8-1/2” 275 sx Class G
4-1/4” 93 sx Class G
WELL INCLINATION DETAIL
KOP @ 12,227’
90 deg Hole Angle = 12,620’
TREE & WELLHEAD
Tree 5M Cameron 2-9/16”
Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH
Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile
TD = 13,462’ (MD) / TD = 7,080’(TVD)
14
20”
TOC @
12,320 (CBL
dated
6/30/23
KB Elev.: 51.42’, GL Elev.: 17.1’
7”
15 & 16
18
17
2
4& 5
10 & 11
9-5/8”
1
12
13
3-1/2” xo
3-1/4”
8& 9
3
Top of
Deployment
Sleeve @
12,105’, LTP
@ 12,102’
Whipstock
set / TOW @
12,227’
Tubing Cut @
11,859’
3-1/4” xo
2-7/8”
A Whipstock
set @
12,255’
PBTD = 13,434’ (MD) / PBTD = 7,080’(TVD)
6 & 7
GENERAL WELL INFO
API: 50-029-22786-02-00
Drilled and Cased by Nabors 27E - 6/29/1997
A Sidetrack CDR2: 6/13/2023
B Sidetrack: 6/20/2023
ESP Install by ASR: 9/9/2023
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kuparuk 12,867’ 12,880’ 7,066’ 7,064’ 13 7/1/2023 Open
12,935’ 13,195’ 7,058’ 7,061’ 260 7/1/2023 Open
13,252’ 13,315’ 7,065’ 7,072’ 63 7/1/2023 Open
Milne Point
ASR Rig 1 BOPE
2023
11” BOPE
4.48'
4.54'
2.00'
CIW-U
4.30'
Hydril GK
11" - 5000
VBR or Pipe Rams
Blind11'’- 5000
DSA, 11 5M X 7 1/16 5M (If Needed)
2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves
HCRManualManualHCR
Stripping Head
2-7/8” x 5” VBR
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Change to Appoved Program
Suspend Perforate Other Stimulate Pull Tubing Cut Tubing
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):
12,740'N/A
Casing Collapse
Conductor N/A
Surface 3,090psi
Intermediate 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
12,136'
9-5/8"
7"
8,613'
12,684'
4-1/2"
MD
N/A
5,750psi
7,240psi
4,165'
7,380'
8,649'
12,717'
Length Size
Proposed Pools:
114' 114'
TVD Burst
PRESENT WELL CONDITION SUMMARY
7,390' 12,634' 7,305' 3,260 N/A
80' 20"
MILNE POINT
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0025509, ADL0025514, ADL0025515 & ADL0388235
223-037
3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-22786-02-00
Hilcorp Alaska LLC
KUPARUK RIVER OIL N/A
C.O. 432E
MILNE PT UNIT L-39B
Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size:
9.3 / L-80 / EUE Mod 8rd 12,312'
6/19/2023
7" x 4-1/2" D&L Perm. Hydro ISO & Baker SB-3 and N/A 11,901 MD/ 6,646 TVD & 12,271 MD/ 6,970 TVD and N/A
See Schematic See Schematic 3-1/2"
Perforation Depth MD (ft):
12.6 / L-80 / TXP, EZGO HT & DWC
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
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 2:13 pm, Sep 01, 2023
323-501
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2023.09.01 11:44:26 -
08'00'
Taylor Wellman
(2143)
DSR-9/1/23
* Approved for 30 day reverse circulation jet pump production.
* BOPE pressure test to 2500 psi.
2191
A.Dewhurst 01SEP2023MGR01SEP23JLC 9/1/2023
09/01/23
Brett W.
Huber, Sr.
Digitally signed by Brett
W. Huber, Sr.
Date: 2023.09.01
16:38:48 -08'00'
RBDMS JSB 090523
Well: MPU L-39B
Scope: Post-CTD APERF + ESP RWO
Well Name:MPU L-39A or L-39B API Number:50-029-22786-02-00
Current Status:Oil Well Pad:L-Pad
Estimated Start Date:Sep 1st, 2023 Rig:CTU/E-line/ASR
Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd:
Regulatory Contact:Tom Fouts Permit to Drill Number:223-036 / 223-037
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:2,852 psi @ 6,610’ TVD Gauge data taken 08/29/2023 |8.29 PPGE
Maximum Expected BHP:2,852 psi @ 6,610’ TVD
Max Potential Surface Pressure:2,191 psi Gas Column Gradient (0.1 psi/ft)
Max Angle:79° @ 6,050’ MD within parent bore
Max Dogleg Severity: 6.32 deg/100’ @ 3,000’ MD within parent bore
Tie in Log: To be provided by Geologist
Brief Well Summary:
MPU L-39A is a slant producer in the Kuparuk A-sand that will be sidetracked across a fault to the South to
access unswept oil (PTD 223-036). It is believed the fault to the South is not in communication with the current
MPU L-39 parent block. There are no existing penetrations into the fault block which MPU L-39A will access.
There is a risk the new fault block will be wet and not contain economic quantities of oil. In the event of no oil
in the sidetrack block upon production, MPU L-39A will need to be sidetracked into the existing block (PTD#
223-037) to the North to gain more footage in the block becoming MPU L-39B.
Objectives:
x Perforate high resistivity intervals within the cemented L-39A lateral using perf guns conveyed on
service coil.
x Temporary flowback the well for 30 days, confirming water cut and rule out the need to drill an
additional coil sidetrack.
x 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 May of 2023 with new 4-1/2” tubing.
x On initial rig up all formations should be isolated via cement pumped by CDR2.
x 7” production casing tested to 3,600 psi on 5/14/2023
x LTP reset on 8/24/2023, parent block isolated from lateral.
Procedure (Non-Sundried Work)
SL:
1. RIH tag TOC or drift as deep as possible
2. Brush deployment sleeve
3. RIH with LTTP and test Liner lap
4. Drift with LTP drift
5. RDMO
CT:
Well: MPU L-39B
Scope: Post-CTD APERF + ESP RWO
1. Job will be modeled after GPB 09-24. Review WSR’s prior to job and look over lessons learned.
2. RIH with a piranha and or 3 blade junk mill sized for 3 ½ liner. Mill down to XO.
3. RIH with a piranha and or 3 blade junk mill sized for 3 ¼ liner. Mill down to XO.
4. RIH with a piranha and or 3 blade junk mill sized for 2-7/8 liner. Mill to TD.
5. RIH with GR/CCL and CBL and nozzle sized for 2’’ gun drift. Log from TD to top of liner. Flag pipe for
perf run.
a. Note: This will serve as the tie in run below. We will use the CBL to adjust perf depths if
needed and correlate tie in log to CBL.
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.
2.Circulate ~194 bbls 10.2 brine (Confirm CDR2 KWF used) 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 procedure calls for KCl water.
a. Estimated Wellbore volume to top perf = 194 bbls
b. 4-1/2” Tubing – 12,000’ x 0.0152 bpf = 182 bbls
c. 3-1/2” Liner – 150’ x 0.0087 = 1.3 bbls
d. 3-3/16” Liner – 500’ x 0.0079 = 4 bbls
e. 2-7/8” Liner – 1,200’ x 0.0058 = 7 bbls
3.Skip step as this was performed with the CBL run. 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 and Graham Emerson
graham.emerson@hilcorp.com.
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.
Well: MPU L-39B
Scope: Post-CTD APERF + ESP RWO
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.
Perf Schedule
Perf
Interval Perf Length Gun Length Weight of Gun
(lbs)Comments
Run
1 TBD*~500’ 500’ 2000 lbs (4ppf)Final lengths TBD after analyzing
open hole and cement log data.
BHAs will be limited to 500’ for
any individual run.
Run
2 TBD*~200’ 200’ 800 lbs (4ppf)
Total ~700’ 700’
*Perf intervals will stay within the permitted Kuparuk interval of the MPU L-39A CTD sidetrack.
11. Perf intervals to shoot per Geo John Salsbury.
a. KUP A3 perf depths: 336’ total
b. 12867-12880 - 13’
c. 12935-13195 - 260’
d. 13252-13315 - 63’
12. 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.
13. 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.
14. Pump pipe displacement while POOH. Stop at surface to reconfirm well is dead. Kill well if necessary.
15. Review well control steps and Standing Orders with crew prior to breaking lubricator connection and
commencing breakdown of TCP gun string.
16. Ensure safety joint and TIW valve assembly are on-hand before breaking off lubricator to LD gun BHA.
17. RDMO CTU.
18. Freeze protect well.
Hilcorp requests approval to temporarily flowback L-39A via reverse circulating jet pump for a period
of 30 days. Temporary jet pump flowback will allow ruling out of need for a second CTD sidetrack
through the 4-1/2” tubing, 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 to be set at at least 50% of expected maximum header injection
pressure.
Slickline
19. MIRU SL, PT PCE to 250 psi low / 3,500 psi high
20. MIT-IA to maximum power fluid pressure of 3,000 psi.
21. Open sliding sleeve at 11,839’.
22. Install 11A jet pump with Sidoti Seal in sliding sleeve at 11,839’with gauges.
23.Perform Draw down test.
24. RDMO.
Well: MPU L-39B
Scope: Post-CTD APERF + ESP RWO
Slickline (After temporary flowback)
25. Pull jet pump from 11,839’.Leave sleeve open for well kill.
26. RIH and tag liner top, obtain 30 minute SBHP.
27. Pull up hole 200' TVD for 15 minute gradient stop.
28. Confirm good data.
29. RDMO.
E-Line (After temporary flowback)
30. MIRU EL, PT PCE to 250 psi low / 3,500 psi high
31. RIH with mechanical cutter
32. Cut 5’ below collar on first full joint of 4.5” 12.6# L-80 DWC above the packer. Estimated cut depth
~11,859’ RKB.
33. RDMO
Pumping and Well Support
34. Clear and level pad area in front of well. Spot rig mats and containment.
35. RD well house and flowlines. Clear and level area around well.
36. RU Little Red Services. RU reverse out skid and 500 bbl returns tank.
37. Pressure test lines to 3,000 psi.
38. Circulate at least one wellbore volume with 8.6 ppg brine (confirm KWF after perforations) down
tubing, taking returns up casing to 500 bbl returns tank.
39. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 MeOH or diesel.
40. RD Little Red Services and reverse out skid.
41. Set BPV.
42. ND Tree. NU BOPE.
Brief RWO Procedure
43. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to 500 bbl returns tank.
44. 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/ 8.6 ppg (confirm KWF based on updated SBHP) ppg brine prior to
setting CTS
45. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve
and test for 5-min). Record accumulator pre-charge pressures and chart tests.
a. Perform Test per ASR 1 BOP Test Procedure.
b. Notify AOGCC 24 hours in advance of BOP test.
c. Confirm test pressures per the Sundry Conditions of approval.
d. Test VBR ram on 2-7/8” and 4-1/2” test joints.
e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test.
46. Bleed any pressure off casing to the returns tank. Pull CTS plug. Bleed any pressure off tubing to the
returns tank. Kill well w/ 8.6 ppg brine as needed. Pull BPV.
Steps 1 thru 33 were completed under approved sundry 323-320
Well: MPU L-39B
Scope: Post-CTD APERF + ESP RWO
a. If indications show pressure underneath BPV, lubricate out BPV.
47. MU landing joint or spear and PU on the tubing hanger.
a. The PU weight during the 2023 workover was 100K lbs on ASR1.
48. Confirm hanger free, lay down tubing hanger.
49. 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.
50. PU new ESP and RIH on 2-7/8” tubing. Set base of ESP at ± 11,810’ 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.
Nom. (OD)Length Item Lb/ft Material Notes
5.85 2 Centralizer 4 ~11,810’ MD
4.5 2 Intake Sensor 30
5.62 34 Motor 80
5.2 7 Lower Tandem Seal 38
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" ~11,200 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, SO 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
51. Continue running ESP completion per plan.
52. 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.
Well: MPU L-39B
Scope: Post-CTD APERF + ESP RWO
53. 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.
54. Lay down landing joint.
55. Set BPV.
56. RDMO ASR
Post-Rig Procedure (Non-Sundried Work):
Well Support
57. RD mud boat. RD BOPE house. Move to next well location.
58. RU crane. ND BOPE, set CTS plug, and NU tree.
59. Test tubing hanger void to 500 psi low/5,000 psi high. Pull CTS and BPV.
60. RD crane. Move 500 bbl returns tank and rig mats to next well location.
61. RU well house and flowlines.
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
Coiled Tubing BOPE
_____________________________________________________________________________________
Revised By: TDF 5/16/2023
SCHEMATIC
Milne Point Unit
Well: MPU L-39
Last Completed: 5/15/2023
PTD: 197-128
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20" Conductor 91.1 / H-40 / N/A N/A Surface 114'
9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’
7" Production 26 / L-80 / NSCC 6.276 Surface 12,717’
TUBING DETAIL
4-1/2” Tubing 12.6 / L-80 / TXP 3.958 Surface 733’
4-1/2” Tubing 12.6 / L-80 / EZGO HT 3.958 733’ 8,500’
4-1/2” Tubing 12.6 / L-80 / DWC 3.958 8,500 12,136’
3.5" Tubing 9.3/L-80/EUE Mod 8rd 2.992 12,264’ 12,312’
JEWELRY DETAIL
No Depth Item
1 11,839’ Sliding Sleeve
2 11,901’ 7" x 4½" D&L PERM. HYD. ISO Packer COE 7.8' from PIN "threads off"
3 12,001 X Nipple Min ID - 3.813'' w/ RHC Installed
4 12,094’ Wireline Entry – Mule Shoe –Bottom @ 12,136’
5 12,271’ 3.5” Baker SB-3 Packer
6 12,295’ 3.5” HES XN Nipple (No Go 2.750” ID)
7 12,307 3.5” Otis WLEG
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kup. A2 &A3 12,362’ 12,402’ 7,062’ 7,098’ 40 6/27/1998 Open
OPEN HOLE / CEMENT DETAIL
20" 250 sx of Arcticset I (Approx) in 24” Hole
9-5/8" 2,199 sx PF “E”, 550 sx Class “G” in 12-1/4” Hole
7” 275 sks Class “G” in 8-1/2” Hole
WELL INCLINATION DETAIL
KOP @ 300’ to 4,500’
Max Hole Angle = 78 deg.
Max Hole Angle through perforations = 27 deg.
TREE & WELLHEAD
Tree 5M Cameron 2-9/16”
Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH
Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile
GENERAL WELL INFO
API: 50-029-22786-00-00
Drilled and Cased by Nabors 27E - 6/29/1997
3.5” Injection Completion by Nabors 27E – 7/1/1998
Conversion to Jet Pump – 10/16/2014
Convert to Producer – 4/23/2015
Install Kill String by ASR#1 – 11/24/2016
Run ESP Doyon 14 – 2/7/2017
Completed by ASR - 5/15/2023
STIMULATION SUMMARY
Kuparuk “A” Sand: 59,000# of 20/40
Carbo Bond frac proppant behind pipe.
TD =12,740’ (MD) / TD = 7,401’(TVD)
20”
Orig. KB Elev.: 34.3’
7”
2
4
9-5/8”
1
5
3
Top of
Tubing Cut
@ 12,264’
PBTD = 12,634’ (MD) / PBTD = 7,305’(TVD)
6
7
NOTE:
ALL TUBING AND JEWELRY DEPTHS
ADJUSTED TO ASR RKB.
_____________________________________________________________________________________
Revised By: TDF 9/1/2023
PROPOSED
Milne Point Unit
Well: MPU L-39B
Last Completed: Future
PTD: 223-037
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20" Conductor 91.1 / H-40 / N/A N/A Surface 114'
9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’
7" Production 26 / L-80 / NSCC 6.276 Surface 12,717’
TUBING DETAIL
2-7/8” Tubing 6.4 / L-80 / EUE 8rd 2.441 Surface ±11,810’
3.5" Tubing 9.3/L-80/EUE Mod 8rd 2.992 12,264’ 12,312’
JEWELRY DETAIL
No Depth Item
1 ±150’ 2-7/8" x 1" GLM, DV installed
2 ±3,071’ 2-7/8" x 1" GLM, DV installed
3 ±3,130’ 2-7/8” X-nipple with RHC profile
4 ±8,560’ 2-7/8" x 1" GLM, DV installed
5 ±8,648’ 2-7/8” XN-nipple -Min ID 2.313”
6 ±x,xxx’ Ported Discharge Head
7 ±x,xxx’ Pump
8 ±x,xxx’ Gas Separator
9 ±x,xxx’ Upper Tandem Seal
10 ±x,xxx’ Lower Tandem Seal
11 ±x,xxx’ Motor
12 ±x,xxx’ Intake Sensor w/ Centralizer
13 11,901’ 7" x 4½" D&L PERM. HYD. ISO Packer COE 7.8' from PIN "threads off"
14 12,001 X Nipple Min ID - 3.813'' w/ RHC Installed
15 ±12,054’ 4-1/2” x 3-1/2” LTP
16 12,094’ Wireline Entry – Mule Shoe –Bottom @ 12,136’
17 12,271’ 3.5” Baker SB-3 Packer
18 12,295’ 3.5” HES XN Nipple (No Go 2.750” ID)
19 12,307 3.5” Otis WLEG
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kuparuk
12,867’ 12,880’ 7,065’ 7,063’ 13 7/2/2023 Open
12,935’ 13,195’ 7,057’ 7,060’ 260 7/2/2023 Open
13,252’ 13,315’ 7,064’ 7,071’ 63 7/2/2023 Open
OPEN HOLE / CEMENT DETAIL
20" 250 sx of Arcticset I (Approx) in 24” Hole
9-5/8" 2,199 sx PF “E”, 550 sx Class “G” in 12-1/4” Hole
7” 275 sks Class “G” in 8-1/2” Hole
WELL INCLINATION DETAIL
KOP @ 300’ to 4,500’
Max Hole Angle = 78 deg.
Max Hole Angle through perforations = 27 deg.
TREE & WELLHEAD
Tree 5M Cameron 2-9/16”
Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH
Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile
GENERAL WELL INFO
API: 50-029-22786-02-00
CTU Sidetrack - Future
STIMULATION SUMMARY
Kuparuk “A” Sand: 59,000# of 20/40
Carbo Bond frac proppant behind pipe.
TD = 12,740’ (MD) / TD = 7,401’(TVD)
20”
Orig. KB Elev.: 34.3’
7”
3
9-5/8”
1
4
2
PBTD = 12,634’ (MD) / PBTD = 7,305’(TVD)
5
16
6
7
8
9& 10
11
12
13
See
Whipstock
Summary
17
18
19
Top of
Tubing Cut
@ ±11,859’
14 & 15
Top of
Tubing Cut
@ 12,264’
NOTE:
ALL TUBING AND JEWELRY DEPTHS
ADJUSTED TO ASR RKB.
WHIPSTOCK SUMMARY
Whipstock Set @ ±12, 254’ Top of
Window @ ±12,256’ For L-39A or L-39B
Well: MPU L-39B
Scope: Post-CTD APERF + ESP RWO
Standing Orders for Open Hole Well Control during Perf Gun Deployment
Well: MPU L-39B
Scope: Post-CTD APERF + ESP RWO
Equipment Layout Diagram
Well: MPU L-39B
Scope: Post-CTD APERF + ESP RWO
Updated 8/11/2020
Milne Point
ASR Rig 1 BOPE
2022
11” BOPE
4.48'
4.54'
2.00'
CIW-U
4.30'Hydril GK
11" - 5000
VBR or Pipe Rams
Blind11'’- 5000
DSA, 11 5M X 7 1/16 5M (If Needed)
2 1/16 5M Kill Line Valves 2 1/16 5M Choke Line Valves
HCRManualManualHCR
Stripping Head
2-7/8” x 5” VBR
3-1/2"x3-1/4"
Recieved by James Brooks on 9/14/2023 at 12:48PM
Completed
7/1/2023
JSB
RBDMS JSB 092623
GDSR-10/10/23
Drilling Manager
09/14/23
Monty M
Myers
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2023.09.14 12:35:46 -
08'00'
Taylor Wellman
(2143)
_____________________________________________________________________________________
Revised By: JNL 9/13/2023
SCHEMATIC
Milne Point Unit
Well: MPU L-39B
Last Completed: 9/9/2023
PTD: 223-037
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kuparuk 12,867’ 12,880’ 7,066’ 7,064’ 13 7/1/2023 Open
12,935’ 13,195’ 7,058’ 7,061’ 260 7/1/2023 Open
13,252’ 13,315’ 7,065’ 7,072’ 63 7/1/2023 Open
GENERAL WELL INFO
API: 50-029-22786-02-00
Drilled and Cased by Nabors 27E - 6/29/1997
A Sidetrack CDR2: 6/13/2023
B Sidetrack: 6/20/2023
ESP Install by ASR: 9/9/2023
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20" Conductor 91.1 / H-40 / N/A N/A Surface 114'
9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’
7" Production 26 / L-80 / NSCC 6.276 Surface 12,227’
3-1/2” Liner 9.2 / L-80 / STL 2.992 12,105’ 12,172’
3-1/4” Liner 6.6 / L-80 / TCII 2.805 12,172’ 12,585’
2-7/8” Liner 6.5 / L-80 / Hyd 511 2.441 12,585’ 13,462’
TUBING DETAIL
2-7/8” Tubing 6.5 / L-80 / EUE 2.441 Surface 11,801’
4-1/2” Tubing 12.6/L-80/TXPxEZGOxDWC 3.958 11,859’ 12,136’
JEWELRY DETAIL
No Depth Item
1 144’ 2-7/8” x 1” Side Pocket GLM w/ DPSOV & BK Latch
2 11,584’ 2-7/8” x 1” Side Pocket GLM w/ Dummy and BK Latch
3 11,670’ XN Nipple Min ID = 2.205”
4 11,720’ Discharge Head
5 11,721’ Zenith Ported Sub
6 11,721 Pump #1
7 11,749’ Pump #2
8 11,759’ Gas Separator
9 11,765’ Intake
10 11,766’ Upper Tandem Seal
11 11,772’ Lower Tandem Seal
12 11,779’ Motor
13 11,796’ Motor Gauge
14 11,799’ Centralizer
15 11,901’ 7” x 4-1/2” D&L Permanent Hyd ISO Packer
16 11,201’ X Nipple Min ID = 3.813”
17 12,102’ Liner Top Packer
18 12,105’ Deployment Sleeve – 3.70” x 3.00” Polish Bore
19 12,094’ Wireline Entry – Mule Shoe – Bottom @ 12,136’ (Behind CTD Liner)
OPEN HOLE / CEMENT DETAIL
24" 250 sx of Arcticset I (Approx)
12-1/4" 2199 sx PF E, 550 sx Class G
8-1/2” 275 sx Class G
4-1/4” 93 sx Class G
WELL INCLINATION DETAIL
KOP @ 12,227’
90 deg Hole Angle = 12,620’
TREE & WELLHEAD
Tree 5M Cameron 2-9/16”
Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH
Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile
TD = 13,462’ (MD) / TD = 7,080’(TVD)
15
20”
TOC @
12,320 (CBL
dated
6/30/23
KB Elev.: 51.42’, GL Elev.: 17.1’
7”
16 & 17
19
18
2
4
9 & 10
11
9-5/8”
1
12
13
14
3-1/2” xo
3-1/4”
8
3
Top of
Deployment
Sleeve @
12,105’, LTP
@ 12,102’
Whipstock
set / TOW @
12,227’
Tubing Cut @
11,859’
3-1/4” xo
2-7/8”A Whipstock
set @
12,255’
PBTD = 13,434’(MD)/ PBTD = 7,080’(TVD)
5& 6& 7
Activity Date Ops Summary
6/6/2023 Pull mud module off. Pull sub off. Prepare cellar. Pull over and set down with rig. Rig accepted at 14:00. RU checklists. LTT tree to 3500#. Install extra wing valve
for MPD line. N/U BOPE. Grease and service all choke and kill valves. Take on KWF and rig water. Install new pack offs and clean stripper brass. R/U and PT
return line to tiger tank to 4200 psi. Hold Pre-Spud with Kaleos crew. Displace coil to fresh water. Start initial BOPE test. Test witness was waived by AOGCC
representative Guy Cook. Test 1: IRV, Stripper, C7, C9, C10, C11. Replace leaking whitey valve on test pump. Test again and Pass. Test 2: Blind/Shears, R2, B2,
C15. Pass. Test 3: Annular (2 3/8"), TIW #1, Bravo #1, Bravo #4.
6/7/2023 Test 3: Annular (2 3/8"), TIW #1, Bravo #1, Bravo #4. Bravo #1 fail/pass. Test 4: Upper 2 3/8" Pipe/Slips, TIW#2, Bravo #2, Bravo #3. Test 5: Lower 2 3/8"
Pipe/Slips, C5, C6, C8, TV2. Test 6: Choke A, Choke C. - Test 7: Charlie 1, Charlie 4, TV1.F23 Test 8: Pipe/Slips, Charlie 2, Charlie 3. Draw Down Test on
Accumulator. Test Rig Gas Alarms. R/D BOP test joint and equipment. Swap test risers to drilling risers. R/U and test PDL's to 3500 psi. Not able to see pump
pressure to test PDL's. RU to read pressure at the lubricator while troubleshooting Pump Transducer. PDL's tested to 3500psi. Install BHI Floats and Test. Good
test, MU nozzle BHA on coil to RIH and displace well to source water then perform FIT Test to see if the parent Perfs will support the 11.8 ECD required to drill the D-
Shale. Open up to well, WHP = 770psi. RIH with nozzle BHA holding 900psi WHP. 2000' online with pump. 2600' getting a lot of gas back, maintain <150psi
downstream of the choke. Tag tubing stump at 12,280'. Circulate source water to surface. In Rate = 1.95 bpm, Out Rate = 1.91 bpm. In Mud Weight = 8.36 ppg, Out
Mud Weight = 8.83 ppg. IA = 662, OA = 0. Shut in tubing pressure (WHP) fell to 735 psi after bumping up twice. EMW ~ 10.4 ppg. Pump down coil with closed
choke and establish loss rate at 1300 psi. LLR = 20 bph at 1300 psi. Swap well over to used mud system from 12,269'. Continue displacing source water from well
with used mud from 12,269'. In Rate = 2 bpm, Out Rate = 1.94 bpm. In Mud Weight = 8.70 ppg, Out Mud Weight = 8.41 ppg. IA = 881, OA = 0. Mud back to
surface. POOH from 12,269'. In Rate = 1.51 bpm, Out Rate = .98 bpm. In Mud Weight = 8.70 ppg, Out Mud Weight = 8.77 ppg. IA = 1014, OA = 0. OOH - Secure
well and L/D nozzle BHA. M/U and pressure deploy BHI DGS and HOT with Baker whipstock drift. RIH with BHA #2 - 3.70" Baker Whipstock Drift. In Rate = .76
bpm, Out Rate = 1.21 bpm. In Mud Weight = 8.72 ppg, Out Mud Weight = 8.79 ppg. IA = 773, OA = 79. WHP = 837 psi.
6/8/2023 Continue RIH with WS Drift BHA. Log tie in, correct depth -5' and RIH. Clean drift to tag at 12276', PU and retag to confirm. Tag at same depth. POOH for WS BHA.
OOH, PUD the drift BHA, maintain 11.8 ECD. RIH with WS BHA. Log Tie in, correct depth -6'. RIH and lightly tag 3.5" stub at 12274'. PUH to 122655', PUW = 51k.
RIH to 12266' (BOWS), PU to 48k (12264') close EDC and set WS at 0deg ROHS. WS set and sheared at 5338psi, set down 7k WOB with no movement. Open
EDC and POOH maintaining 11.8 ECD at the window. OOH - PJSM. PUD NSAK WS setting tool. Pressure Deploy NSAK window milling BHA #3. NSAK 2 7/8
straight motor w/3.80" string reamer and window mill. RIH with window milling BHA. In Rate = .80 bpm, Out Rate = 1.25 bpm. In Mud Weight = 8.73 ppg, Out Mud
Weight = 8.81 ppg. IA = 641 psi, OA = 23 psi. WHP = 1027 psi. Log Tie In from 11,780' @ 5 fpm. Correct -8'. Close EDC
RIH and dry tag whipstock pinch point @ 12,257'. PUH and establish milling paramaters. Begin milling window from 12,256'. In Rate = 2.50 bpm, Out Rate = 2.50
bpm. In Mud Weight = 8.73 ppg, Out Mud Weight = 8.81 ppg. IA = 825 psi, OA = 98 psi. WHP = 550 psi. Milling estimated mid-point of window at 12,260'. In Rate
= 2.58 bpm, Out Rate = 2.52 bpm. In Mud Weight = 8.72 ppg, Out Mud Weight = 8.78 ppg. IA = 1289 psi, OA = 431 psi. WHP = 519 psi
6/9/2023 Milling window at 12,262.7'. In Rate = 2.54 bpm, Out Rate = 2.52 bpm. In Mud Weight = 8.72 ppg, Out Mud Weight = 8.85 ppg. IA = 1363 psi, OA = 483 psi
WHP = 478 psi, ECD = 11.81. Exit the bottom of the window at 12263.7' continue milling at 1 fph for 1' to dress bottom of window with string mill. 12265' start
milling 10' of Rat Hole and increase rate to 2.85 bpm. Very slow milling Rat Hole and high vibration on the tool. Reduce rate to 2.65 bpm to reduce vibration. Milled
10' of Rat hole to 122675' start ream passes. Ream passes completed, dry drift window. Seeing WOB at the TOW, continue dressing TOW until clean
BOW sample 2% formation. 12274' sample 40% formation. Made 2 slow ream passes through window, dry drift is clean, POOH for the build BHA. OOH PUD the
milling BHA. String Reamer and window mill both gauged 3.80" GO 3.79" NO GO. M/U and RIH with swizzle stick to jet stack and surface lines. Pressure deploy
build BHA with 2.1 deg motor bend and re-run HCC 4.25" bi-center bit. RIH with build BHA #5. In Rate = .95 bpm, Out Rate = 1.52 bpm. In Mud Weight = 8.75 ppg,
Out Mud Weight = 8.81 ppg. IA = 22 psi, OA = 157 psi. WHP = 528 psi, ECD = 11.73. Log tie in from 11170' @ 5 fpm. Correct - 7'. Close EDC and RIH through
window clean. Bring pump up to rate and establish parameters. Drill 4.25" lateral from 12274'. In Rate = 2.79 bpm, Out Rate = 2.80 bpm. In Mud Weight = 8.75
ppg, Out Mud Weight = 8.81 ppg. IA = 753 psi, OA = 244 psi. WHP = 420 psi, ECD = 11.76. Drill 4.25" lateral from 12331' to 12,351'. In Rate = 2.80 bpm, Out Rate
= 2.77 bpm. In Mud Weight = 8.76 ppg, Out Mud Weight = 8.83 ppg. IA = 748 psi, OA = 436 psi. WHP = 413 psi, ECD = 11.70. ROP = 10 - 30.
6/10/2023 Continue Drilling 4.25" build from at 12356'. In Rate = 2.80 bpm, Out Rate = 2.77 bpm. In Mud Weight = 8.78 ppg, Out Mud Weight = 8.85 ppg. IA = 799 psi, OA =
495 psi. WHP = 406 psi, ECD = 11.82. ROP = 8-10 fph. 12380' ROP increasing entering the A3 Sand. In Rate = 2.82 bpm, Out Rate = 2.79 bpm. In Mud Weight =
8.79 ppg, Out Mud Weight = 8.84 ppg. IA = 801 psi, OA = 502 psi. WHP = 406 psi, ECD = 11.84. ROP = 45-75 fph. Landed the build at 12508', POOH chasing
pills to the window. Jog 100' below the window, pull EDC above the TOWS and open. Jet WS Tray and POOH slow in the 7" up into the 4-1/2. OOH - PJSM and
PUD build BHA. Bit graded 1:1 with one plugged nozzle. M/U and PD lateral BHA. RIH with lateral BHA #6 - 1.1 deg motor and HYC 4.25" bi-center bit. In Rate =
.98 bpm, Out Rate = 1.25 bpm. In Mud Weight = 8.86 ppg, Out Mud Weight = 8.91 ppg. IA = 847 psi, OA = 332 psi. WHP = 476 psi, ECD = 11.84. Log tie in from
11,170'@ 5 fpm. Correct - 6'. Close EDC and RIH through window. Log RA Tag from 12,254' @ 5 fpm. Found RA Tag 1' deeper at 12,265'. Drill 4.25" lateral from
12,508' while displacing to new mud. In Rate = 2.80 bpm, Out Rate = 2.82 bpm. In Mud Weight = 8.83 ppg, Out Mud Weight = 8.95 ppg. IA = 827 psi, OA = 510
psi. WHP = 493 psi, ECD = 11.76. Drill from 12,731' wiping BHA every 150'. In Rate = 2.78 bpm, Out Rate = 2.81 bpm. In Mud Weight = 8.83 ppg, Out Mud
Weight = 8.96 ppg. IA = 829 psi, OA = 511 psi. WHP = 491 psi, ECD = 11.76.
50-029-22786-02-00API #:
Well Name:
Field:
County/State:
MP L-39B
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
6/14/2023Spud Date:
6/11/2023 Continue Drilling 4.25" Lateral from at 12781'. In Rate = 2.77 bpm, Out Rate = 2.75 bpm. In Mud Weight = 8.78 ppg, Out Mud Weight = 8.94 ppg. IA = 823 psi, OA
= 547psi. WHP = 492 psi, ECD = 11.76. ROP = 50 - 70 fph. Drilled to 12950' pull wiper trip to window. Jog below window, pull EDC above TOWS and open. Jet
across WS Tray then PUH at 20 fpm in the 7" to the TT. Log tie in at 11770', +5' correction. CCL log from 11800' to 12250' then RIH. Continue Drilling 4.25" Later
from at 12950'. In Rate = 2.84 bpm, Out Rate = 2.84 bpm. In Mud Weight = 8.91 ppg, Out Mud Weight = 8.99 ppg. IA = 878 psi, OA = 622 psi. WHP = 463 psi,
ECD = 11.80. ROP = 30 - 60 fph. Continue Drilling 4.25" lateral from 13205' to 13,400'. In Rate = 2.84 bpm, Out Rate = 2.92 bpm. In Mud Weight = 8.93 ppg, Out
Mud Weight = 9.04 ppg. IA = 878 psi, OA = 701 psi. WHP = 435 psi, ECD = 11.83. Long wiper trip to window from 13,400'. Pump sweeps off bottom. In Rate =
2.84 bpm, Out Rate = 2.92 bpm. In Mud Weight = 8.93 ppg, Out Mud Weight = 9.04 ppg. IA = 878 psi, OA = 701 psi. Jog below window and pump sweeps. Open
EDC and jet whipstock at max rate. Overpulls and packing off pulling into tubing tail. RIH and pump additional sweeps. Increase rate to 4 bpm and circulate sweeps
out of hole. Heavy shale returns at surface - when clean log tie in. Correct +5'. Pump additional 5 bbl Hi/Lo vis sweep from bottom of 7" at 4 bpm. Close EDC and
RIH through window clean. RIH to TD. In Rate = 1.76 bpm, Out Rate = 1.96 bpm. In Mud Weight = 8.99 ppg, Out Mud Weight = 9.06 ppg. Drill ahead from 13,404'
to 13,520'. In Rate = 2.84 bpm, Out Rate = 2.81 bpm. In Mud Weight = 8.99 ppg, Out Mud Weight = 9.06 ppg. IA = 874 psi, OA = 743 psi. WHP = 404 psi, ECD =
11.81. Drill ahead from 13,520' to 13,572'. In Rate = 2.78 bpm, Out Rate = 2.83 bpm. In Mud Weight = 9.0 ppg, Out Mud Weight = 9.07 ppg. IA = 880 psi, OA =
743 psi. WHP = 383 psi, ECD = 11.82. Wiper trip to window from 13,572'. In Rate = 2.80 bpm, Out Rate = 2.67 bpm. In Mud Weight = 9.01 ppg, Out Mud Weight =
9.08 ppg. IA = 854 psi, OA = 736 psi. WHP = 361 psi, ECD = 11.80.
6/12/2023 Drilled into the B-Shale, decision made to POOH and prep for running a protections string. Cleanout the OH and 7" then lay in KWF. 13190' packing off and pulling
heavy, work pipe down until clean then keep working towards the window. Jog in hole below the window 2x clean passes down. Pull through the window open the
EDC and increase rate. 1:1 return PUH slow to clean up the 7". Packing off RIH and reduce pump rate, stacking WT but no WOB change so we are packed off
above the BHA and below the Sliding Sleeve as IAP has bled off. Pull to 70k and hold at 0.5 bpm to see if get any movement. No movement, shut down pump and
try working down again monitoring the ECD on the tool. Set down -35k got about 3k WT back. Work pipe up and down from 45k just below PU WT to -40k. Allow
ECD to dissipate from 14.5 ECD to 11.0 ECD. Stack out to -49.5k. Slowly got back 2.5k surf WT. Continue working up to just under PU WT and stack out. Try
stacking -20k down weight. 11.82 ECD. Exhausted attempts to go down ECD at the tool = 11.3ppg. Start PU to 100k in 10k increments starting at 75k. PU to 76k at
12232.81'. PU to 83k at 12231.85'. PU to 93k at 12230.73'. PU to 100k at 96k we are moving up hole then started pulling heavy to max pull at 100k, RIH and try
going down. Try working down. Not getting any movement going down. Try coming up again. Line up to pump with field triplex down IA to check for communication
with tubing. Triplex out of source diesel. Call for LRS pump truck and more diesel. LRS on location - PJSM and R/U to IA. PT to 2000 psi. Begin pumping and
confirm communication between IA and production tubing. At ~ 750 psi WHP, able to RIH 80'. Reciprocate pipe and back to original stuck point. Circulate 20 bbls of
90 deg diesel down IA. R/D LRS. R/U line from rig MPD to circulate down IA. PT line to IA casing valve to 3000 psi. Begin pumping down IA taking returns from
production tubing. 5 bpm and 2000 psi pump pressure. Maintain -15k on coil. Able to RIH with coil. Begin reciprocating coil between 12,220 and 12,260. Pull coil
free through TT and into tubing. POOH while continuing to circulate down IA @ 5 bpm taking returns to tiger tank. Drop rate to 2.77 bpm and bring mud back inside
to pits. IA = 1521 psi, OA = 512 psi. ECD = 11.82. OOH - PJSM with Nabors crew. R/D line to IA and R/U MPD line. PT to 3500 psi. Pass. Pressure undeploy
lateral BHA #6. Line up on MPD and maintain 11.8 ECD at window. Inspect CTC. Good. L/D BHA #6. Bit graded 2:1 BT. Flush and service Choke B. Replace pack-
offs and test. M/U and RIH with 2.70" JSN with 3/4" ball on seat.
6/13/2023 Continue RIH with Nozzle BHA to clean out 7" down to the window. WHP = 1178 psi to maintain 11.8 ECD at the window. Stop at 11800', correct depth with our
normal tie in correction of -6' and RIH dry to tag. PU WT = 51k, RIH WT = 14k. WHP = 1178 psi to maintain 11.8 ECD at the window. Clean drift to the window, tag
at 12266'. PUH inside the TT. Pulling 7k over in the TT, RIH clean and PU inside the TT at 12149' CCL depth. Online at a low rate until we see an increase in
WHP, increase rate and pump a bottoms up inside the TT at 12145'. In Rate = 3.12 bpm Out Rate = 3.25 bpm. Circ psi = 4007 psi, WHP = 479 psi, IAP = 1060 psi.
Choke cycling, Out MM packing off, bypass out MM and blow down. Continue PUH to the SS while clearing out the choke line. Choke line cleared, line up through
the Out MM and RIH to clean out 7" taking 10-15' bites pumping low high vis pills. In Rate = 3.06 bpm Out Rate = 3.17 bpm. Circ psi = 3774 psi, WHP = 434 psi,
IAP = 1024 psi. Pills bringing up small pebbles of shale and fine silty shale. Cleaned out down to 12255' TOWS, chase last of the cuttings up to 4-1/2 with pills.
Clean pass to TT, RIH to 12255' 1 last pass, clean to TOWS. POOH 80 fpm at max rate to surface. OOH, close in the MV trapping 1200psi WHP to accommodate
the length of the NSAK WS BHA. LD the Nozzle BHA, recover 3/4" Ball from Nozzle. PD WS BHA. RIH with the WS BHA. In Rate = .42 bpm Out Rate = 1.06 bpm.
Mud Weight In = 9.04 ppg, Mud Weight Out = 8.97 ppg. Circ psi = 1892 psi, WHP = 686 psi, IAP = 1106 psi. Log Tie In from 11770' @ 5 fpm. Correct - 7'. RIH to
WS setting depth. Set TOWS @ 12,228' and 30 deg ROHS. Shear setting tool at 6900 psi. Set 5k down and confirm set. POOH with WS setting tool. Pump 51
bbls of diesel into IA for freeze protect. In Rate = 1.09 bpm Out Rate = .73 bpm. Mud Weight In = 9.04 ppg, Mud Weight Out = 8.98 ppg. OOH - PJSM and Pressure
undeploy NSAK WS setting BHA. Pressure deploy NSAK window milling BHA with straight motor and 3.80" reamer and window mill. RIH with window milling BHA.
In Rate = 1.0 bpm, Out Rate = 1.04 bpm. In Mud Weight = 9.05 ppg , Out Mud Weight = 8.94 ppg. IA = 1355, OA = 241. Circ pressure = 1807, WHP = 535. Log tie
in and correct -7'. Uncertainty about correction. PUH and re-log GR interval. Correct +12'. RIH to tag WS pinch point.
6/14/2023 RIH with window milling BHA, log tie in and dry tagged pinch point at 12233'. PU, pumps on line at see first motor work at 12231.3', start milling window. In Rate =
2.72 bpm, Out Rate = 2.85 bpm. In Mud Weight = 9.04 ppg , Out Mud Weight = 8.95 ppg. IA = 1271, OA = 284. Circ pressure = 3681, WHP = 403. Continue
milling window at 12235.0'. In Rate = 2.75 bpm, Out Rate = 2.85 bpm. In Mud Weight = 9.03 ppg , Out Mud Weight = 8.95 ppg. IA = 1257, OA = 390. Circ pressure
= 3749, WHP = 412, EDC = 11.76. Continue milling window at 12235.9'. In Rate = 2.74 bpm, Out Rate = 2.84 bpm. In Mud Weight = 9.03 ppg , Out Mud Weight =
8.95 ppg. IA = 1257, OA = 438. Circ pressure = 3691, WHP = 416, EDC = 11.76. Milled 4.8' to 12236.3' now very little to no progress in the last couple hours. PU
200' to make sure we aren't hanging up on the BHA above the mill. Set back down with lighter WOB 2-2.5k and we are milling again. Continue milling window at
12236.77'. In Rate = 2.75 bpm, Out = 2.83 bpm. In Mud Weight = 9.02 ppg , Out = 8.94 ppg. IA = 1262, OA = 535
Circ pressure = 3885, WHP = 427, ECD = 11.74. BOW is 12239.0' based on parameters. Drill rathole 3-5 ft/hr to 12248.8'. Pump 5 lo/hi vis. Ream window up,
down, up 1 ft/min nothing seen. Dry drift is clean, tag bottom rathole. PU above whipstock and function annular then lower 2-3/8" P/S rams. Open EDC, circ 11.8#
fluid around. Circ 11.8# fluid around. 10 min no-flow is good. POOH. At surface, 10 min no-flow is good. L/D BHA #9 - window milling BHA. Mill and reamer 3.80"
Go / 3.79" NoGo. Finish BOP function test. M/U nozzle, jet stack. M/U BHA #10 - Build BHA.
6/15/2023 MU Build BHA and RIH. Log tie in at 11760', correct depth -8', RIH to tag bottom of Rat Hole at 12249'. PU WT = 56k, RIH WT = 19k. Passed through window with
some WOB as expected w/3.0 Motor. PU above the TOWS and displace the well to mud. Well swapped to mud with 3% Hydahib and 2 ppb Black Product , close
the EDC, RIH, tag bottom, bring pumps on line and start drilling the build. PU WT = 55k. Drill 4.25" Build from 12249'. In Rate = 2.80 bpm, Out Rate = 2.90 bpm. In
Mud Weight = 9.29 ppg, Out Mud Weight = 9.59 ppg. IA = 1261 psi, OA = 283 psi. WHP = 326 psi, ECD = 11.75. ROP = 10 - 15 fph. Drill 4.25" Build from 12269'.
In Rate = 2.82 bpm, Out Rate = 2.99 bpm. In Mud Weight = 9.50 ppg, Out Mud Weight = 9.44 ppg. IA = 1260 psi, OA = 439 psi. WHP = 358 psi, ECD = 11.78.
ROP = 8 - 10 fph. Drill 4.25" Build from 12284' drilling break. In Rate = 2.82 bpm, Out Rate = 2.99 bpm. In Mud Weight = 9.47 ppg, Out Mud Weight = 9.29 ppg. IA
= 1255 psi, OA = 497 psi. WHP = 297 psi, ECD = 11.76. ROP = 80 - 110 fph. Drill 4.25" Build from 12323'. In Rate = 2.81 bpm, Out = 2.89 bpm. In Mud Weight =
9.47 ppg, Out = 9.36 ppg. IA = 1278 psi, OA = 525 psi. WHP = 345 psi, Window ECD = 11.88. 12335', 12370', 12385' 5 bbls lo/hi vis. 100' wiper from 12400'
clean up/down. Drill 4.25" Build from 12400'. In Rate = 2.91 bpm, Out = 2.95 bpm. In Mud Weight = 9.42 ppg, Out = 9.37 ppg. WHP = 293 psi, Window ECD =
11.88. 12535' 5 bbls lo/hi vis.
6/16/2023 Continue drilling 4.25" Build from 12563'. In Rate = 2.91 bpm, Out = 3.09 bpm. In Mud Weight = 9.39 ppg, Out = 9.41 ppg. IA = 1249 psi, OA = 595 psi. WHP =
305 psi, Window ECD = 11.82. 12635' ~90 deg, Geo's want to start coming up sooner than plan, come up to 95 deg and finish turn. 12690', build landed, pills
going down, PUH to the 7"and chase up to the TT. Open the EDC and wash across the tray at 2.0 bpm, PUH to the TT at 4.0 bpm. RIH to TOWS and circ a
bottoms up. Bottoms up is clean, start KWF down hole. Well swapped to 11.8 KWF with slight losses, dynamic flow check well. Loss rate at 8 bph, POOH for lateral
BHA. OOH, flow check well. Good no flow, well on <2 bph static loss rate. LD the build BHA and PU the lateral BHA. RIH with lateral BHA. Tie-in depth correct -7'. At
window, swap well to mud keep 11.8# ECD. Close EDC. RIH pass window no issues. 0.35 bpm to bottom. Drill 4.25" lateral from 12692'. In Rate = 2.84 bpm, Out =
2.91 bpm. In Mud Weight = 8.77 ppg, Out = 8.74 ppg. 12805' 5 bbls lo/hi vis. WHP = 635 psi, Window ECD = 11.84. 12850' pull 150' wiper, clean up/down. Drill
4.25" lateral from 12850'. In Rate = 2.82 bpm, Out = 2.91 bpm. In Mud Weight = 8.85 ppg, Out = 8.88 ppg. WHP = 538 psi, Window ECD = 11.85. 12940', 12965'
5 bbls lo/hi vis. 13000' pull 150' wiper, clean up/down. Drill 4.25" lateral from 13000'. In Rate = 2.84 bpm, Out = 2.89 bpm. In Mud Weight = 8.91 ppg, Out = 8.86
ppg. WHP = 438 psi, Window ECD = 11.84. Wiper trip to window from 13150' clean pass. Jog below D-shale(12300') pull through 0.5 bpm clean. Jog above
window, open EDC jet 7" at 3.5 bpm. Tie-in +4.5' close EDC. Pass window 0.5 bpm to bottom. Stack wt 12320' - 12327' work past continue RIH to bottom. Drill
4.25" lateral from 13150'. In Rate = 2.86 bpm, Out = 2.97 bpm. In Mud Weight = 8.89 ppg, Out = 8.82 ppg. WHP = 454 psi, Window ECD = 11.83.
6/17/2023 Continue drilling 4.25" lateral from 13175'. In Rate = 2.86 bpm, Out = 2.94 bpm. In Mud Weight = 8.88 ppg, Out = 8.83 ppg. WHP = 450 psi, Window ECD = 11.82.
ROP slowed at 13160' holding 88 deg, drilled into a shale, 13235' start dropping down to 83 deg. 13240' ROP increasing dropped below shale. Continue drilling
4.25" lateral from 13260'. In Rate = 2.87 bpm, Out = 2.95 bpm. In Mud Weight = 8.89 ppg, Out = 8.85 ppg. WHP = 459 psi, Window ECD = 11.84. Continue drilling
4.25" ROP dropped at 13405' possibly drilled into a shale. In Rate = 2.82 bpm, Out = 3.04 bpm. In Mud Weight = 8.90 ppg, Out = 8.87 ppg. WHP = 403 psi,
Window ECD = 11.76. 13463' PU slow for Geo Wiper, looks like we might have faulted into the B-Shale. Geo's called TD, continue PUH to the window to clean out
the OH. Jog below the window then pull through the window at 0.5 bpm. PUH to the TT at rate, RIH to the TOWS and open the EDC, wash across tray with pills circ
bottoms up. Bottoms up is clean POOH to clean up the tubing to surface. POOH to surface cleaning up the tubing. OOH, tag up, zero depths and blow down return
line then RIH. Tie-in 11770' correct -8'. Pass window no issues. RIH to bottom 0.4 bpm as drilled TF. Stack 12276' 4x, run past 1.5 bpm then continue past D-shale.
Stack wt 12309' go to 1.5 bpm and work past. Tag 13462' corrected drilled depth. Pick up and repeat, same depth. PU to clean A3 sand area and circ liner pill to bit
followed by 11.8#. Lay in liner pill from TD to 12600' followed by 11.8# to surface. Pull through build clean, above window pull -3.8 DWOB at 12226' RIH then PU
clean. Jog in 7" then open EDC pump 11.8# to surface. Good 10 min no flow. POOH flag pipe:
White 10528.9' EOP for window. Yellow 11758.9' EOP for TD. At surface, good 10 min no-flow. Lift injector, inspect CT. L/D BHA #11 - Lateral Drilling, bit 3-1.
Remove BHI cable head and boot cable. M/U 1 jt of 2-3/8" PH-6, M/U injector. Pump slack out, recover 190'. Boot e-line. M/U nozzle, pump 7/8" ball around.
6/18/2023 Continue with Ram Swap to VBR's. Swap out lubricators to test VBR's. Shell test BOPE then test VBR's for 2-3/8" and 3-1/2 to 250 low and 3500 high. Good test,
RD test equipment. RU to run liner. MU liner as per approved summary. Motor & Mill, 27 jts 2-7/8", 13 jts 3-1/4", 1 jt 3-1/2". 39 jts left in PS all accounted for. MU
upper BHA. MU injector the BHA. RIH with liner. Start mud down CT while RIH. Correct -2.7' at window flag to 12085.3'. Swap well to mud keep > 11.8# ECD. Up
wt at window 57k. RIH pump 1 bpm. No issue past window. Stack at 12333' PU 53k and RIH slower. See some motor work periodically in B-shale. Stack 13192' (B-
shale) PU and work past. TD flag seen 13310.1'. Stack 13338' up wt 61k. Work past tag 13453' 2x (Drilled TD is 13462'). Pick up and tag 13453' 2x at different
rates, appears to be hard bottom. Up wt 58k. Launch 3/4" ball, heard rolling. After 60 bbls ball not on seat. Surge pump. Re-launch w/ 2000 psi. Rock reel and
pump. Surge w/ 3000 psi under tension. Ball on seat at 109 bbls shears at 5200 psi. New up wt is 44k. Swap well to source water w/ D204 added. Offload mud from
rig and load exhaust pill into pits.
6/19/2023 Continue circulating while waiting on a Worley Vac Truck with fresh water and to pull fluids off a broke down Vac Truck that we need for the CMT job. Hold PJSM to
pump CMT job. Fluid Pack & PT CMT Line to 5500psi. 09:00 CMT Wet, 6:22 Thickening Time expires at 15:22. Batch up 26 bbls of 15.3 ppg CMT
CMT to WT, pump 3 bbls of Exhaust Pill to the CMT MM and shut down. Line up HES CMT Pump to the coil and pump 20.5 bbls of CMT into the coil. 20.5 bbls
pumped, shut down pump with 952 psi WHP and flush CMT line. Online with rig pump displacing CMT. 60.2 bbls away, zero out MM and take returns to 1 pit. 68.9
bbls away, shut down the pump with 923 psi WHP. PU and set back down to launch Pee Wee Dart, dart on seat. PU to pressure loss and exhaust 3 bbls of CMT
and 4.5 bbls of contam. Crack open pump bleeder and set back down with 820 psi WHP. Close bleeder, pressure up to launch LWP, need to bypass the CMT MM
to shear the LWP. LWP won't shear, cycle pumps to 7200psi, PU with pressure and no pressure nothing is moving and we can't pump
BOT Rep thinks we are pulling a vacuum with the CMT and the LWP, leave bleeder open PU and no movement. Lower WHP to formation pressure and pressure
up coil, no shear. Bleed off WHP to 500psi while pressuring up on the coil, LWP still not shearing out. Pull to 55k, 75k, 80k, several times with no movement.
Cement placement info. 20.5 bbls pumped = 8.7 bbls out the shoe - 8.8 bbls in the liner - 3 bbls exhausted. 8.7 bbls behind pipe = TOC in the OH at 12,537' ~50'
above the 2-7/8" x 3-1/4" X-O. We have exhausted what we can do, pull 100k then pressure up to 7300psi. No movement no and shear out, bleed off coil pressure
and work pipe to 100k. Pulled free after 2x at 100k, online with pump to circ out 3 bbls of exhausted CMT and PUH to wash across the SS with the 150 bbls of
exhaust pill. Continue circulating CMT OOH and a bottoms. 3 bbls of exhausted CMT at surface and some crude. Take returns out to the TT while circulating a
bottoms up. Swap to KWF down the coil. KWT to surface, purge lubricator then flow check well. Good no flow check, well took 0.8 bbls in 10 min 4.8 bph. POOH to
LD the LRT BHA. Spill Drill with Jones Crew. 10 min no-flow at surface is good. Skid injector back, L/D 6 jts 2-3/8" PH-6 inspect running tools. Recover LWP and
3/4" ball. Pee-Wee dart has hung up in the side exhaust ports, did not travel down to the LWP. L/D and offload running tools back to BTT shop for further
inspection. M/U nozzle, jet stack. Pump excess slack backwards. M/U hydraulic cutter. Cut 250' of CT = 1.74% slack. Wire isn't found. Install CT connector, pull test
50k good. M/U stinger, pump slack forward + 1 reel volume. Lift injector off, skid back. Install BHI cable head w/ no floats. PT CT connector and UQC to 6k, good.
M/U nozzle BHA w/ FVS. M/U injector. RIH BHA #13 - Freeze Protect. Recover 11.8# brine from well.
6/20/2023 Continue RIH with nozzle BHA to recover KWF. Tag at 12110', PU and retag same depth. With our tie in corrections of -6', TOL at 12104' on depth with liner
summary. Displace well to source water. POOH while displacing well. 5300' start 50 bbls of diesel down the coil. 2997, swap to rig pump. 2850' displace well to
diesel. Diesel to surface POOH at pipe displacement. OOH, hold PJSM with the grease crew and service tree valves. Tree valves serviced, PT the Master and lower
Swab to secure the well. Good PT, well secured. Blow down stack to swap VBR's to 3" Combi's and Kill Line HCR. Shell test Ram Doors and Kill HCR. Good shell
test, blow down surface lines. Remove BOPs, install tree cap and test. Release rig at 21:00.
ACTIVITYDATE SUMMARY
6/21/2023
T/I/O=930/845/0 Pressure test TBG/deployment sleeve. (Post RWO) Pumped 1.2 bls
diesel down TBG to reach 1646 psi . Let pressures sabalize at 1581 psi. TBG lost 13
psi in 15 min. Final Whps= 930/980/0
6/21/2023
*** WELL SHUT-IN ON ARRIVAL.***
RAN 5' x 1-7/8" ROLLER STEM (2.60" whls), 2.70" CENT, 1-3/4" SAMPLE BAILER.
DEVIATE OUT @ 6,070' SLM (78 degrees).
LRS PRESSURE TESTED TUBING TO 1500psi.
TAG DEPLOYMENT SLEEVE AT 12,105' MD W/ 3' x 2-1/8" ROLLER STEM (3.50"
whls), 3.70" GAUGE RING.
*****HIGH DEVIATION FROM 3,500'-8,000' MD. 2-1/8" ROLLER STEM W/ 3.50"
whls RECOMMENDED.*****
*** WELL SHUT-IN ON DEPARTURE, PAD OP NOTIFED.***
6/28/2023
LRS CTU #2 - 1.75" Blue Coil
Job Objective: Mill Cement, CBL, Ext. Perforating
MIRU CTU. Make up milling 2-1/8" BHA with 2.80" PDC mill and RIH. Diagnose TxIA
communication and confirm inflow from liner lap. Tag liner top at 12099' CTMD and
spin into. Tag cement stringers at 12107' CTMD and begin milling cement. Mill to
12454' CTMD.
...Job in Progress...
6/29/2023
LRS CTU #2 - 1.75" Blue Coil
Job Objective: Mill Cement, CBL, Ext. Perforating
Continue milling from 12,455 to 12,574' CTMD with 2-1/8" milling BHA and 2.80"
PDC. Tag 3-1/4" x 2-7/8" XO at 12,574'. POOH to swap mill. At surface - LD 2-1/8"
milling BHA and 2.80" PDC. PU & RIH w/ 1.69" milling BHA and 2.30" PDC for
milling in 2-7/8" liner. Tag Cement at 12583' begin milling with frequent gel sweeps.
Mill to 13,268' CTMD. Continue milling on next day.
...Job In Progress...
6/30/2023
LRS CTU #2 - 1.75" Blue Coil
Job Objective: Mill Cement, CBL, Ext. Perforating
Continue milling from 13,268' to13,414' CTMD with 1.69" milling BHA and 2.30" PDC.
Pump gel sweep and chase OOH. Make up RBT cement bond log BHA and RIH. Tag
TD and log up to 11750', painting a red tie-in flag at 12750'. Confirm +1' correctiong
and PBTD of 13430'. Make up 2-1/8" milling BHA with 2.95" Polish mill and RIH. Tag
X-Nipple at 12126' CTMD. Mill across LT 12,080 - 12,124' CTMD X6 (3 up passes &
3 down). Chase 16 bbls gel OOH from 12,124' CTMD to surface at 80%. BD BOT
millig assy. MU NS 4-1/2" LTP and RIH to set.
...Job In Progress...
7/1/2023
LRS CTU #2 - 1.75" Blue Coil
Job Objective: Mill Cement, CBL, Ext. Perforating
Continue RIH w/ 4-1/2" LTP. Set LTP @ 12,105¿ CTMD. Perform inflow test ¿
inflow stabilized @ ~0.3 bbls. POOH w/ LTP setting tool. Make up fishing BHA with
Hydraulic release spear and RIH. Circulate in KWF and confirm well kill in place. Pull
RSG from LTP and POOH, maintaining hole fill. Deploy 448' of 1.56" perf guns. RIH
to PBTD and correct to bottom shot. Perf ints: 12,867' - 12,880' MD, 12,935' - 13,195'
MD, 13,252' - 13,315' MD. POOH pumping pipe displacement. Undeploy 448' of
1.56" perf guns.
...Job In Progress...
7/2/2023
LRS CTU #2 - 1.75" Blue Coil
Job Objective: Mill Cement, CBL, Ext. Perforating
Continue POOH pumping pipe displacement. Undeploy 448' of 1.56" perf guns.
RDMO.
...Job Complete...
Daily Report of Well Operations
PBU MPL-39B
Daily Report of Well Operations
PBU MPL-39B
7/2/2023
Assist Slickline, Pumped 56 bbls Produced Water down Tubing returns up IA into
Flowline to push Slickline down Hole
7/2/2023
***WELL S/I ON ARRIVAL***
RAN 4-1/2 42-BO MADE SEVERAL PASSES THROUGH SLEEVE @ 11858' MD
(sleeve was open)
SET 3'' JET PUMP (ratio:11A, sidoti seal, sec. loc., screen, soft set, bhp's ser#
78059, 77867 batt. in @ 11:55 AM, oal= 150''), IN XD-SS @ 11877' SLM / 11858' MD
***WELL S/I ON DEPARTURE***
7/22/2023
**** WELL S/I ON ARRIVAL *****
PULLED 3" JET PUMP ( ratio: 11A, sidoti seal, sec, loc., sceen, soft set, bhp's ser#
78059, 77867 ) oal 150" ),in XD-SS @ 11842' SLM/ 11858' MD
REBUILD AND DOWNLOADED GAUGES
SET NEW 4 1/2" X-LOCK, W/3" JET PUMP ( ratio, 12A, sidoti, seal, sec. lock down,
screen, soft set, bhp's ser# 78059, 77867 oal 135" ) in XD-SS @ 11842 SLM, 11858
MD.
DSO POP'd WELL TO ENSURE GOOD SET.
***WELL FLOWING ON DEPARTURE***
8/19/2023
*** WELL FLOWING ON ARRIVAL ***
START PUMPING DISPLACEMENT WITH POWER FLUID
*** CONTINUE ON 8/20/2023 ***
8/20/2023
*** CONTINUE FROM 8/19/2023 ***
PULL 3.81" X- LOCK, JET PUMP, SHOCK ABSORBER & GAUGES (missing 3
pieces of pkg)
RAN KJ, BLB, 2.80 " GAUGE RING TO LTP, SD @12,081' SLM (no pkg recovered)
MAKE MULTIPLE ATTEMPTS WITH GR TO PULL LTP (unsuccessful)
*** CONTINUE ON 8/21/2023 ***
8/21/2023
*** CONTINUE FROM 8/20/2023 ***
MADE MULTIPLE ATTEMPTS TO PULL LTP W/ GS & GR (unsuccessful),
TURNING OVER TO COIL
*** WELL LEFT S/I ON DEPARTURE, DSO NOTIFIED OF STATUS ***
8/21/2023
T/I/O=240/0/0 Freeze protect IA. Pumpe 48 bbls criesel down IA taking returns up
TBG to production. Final Whps=240/0/0
8/22/2023
LRS CTU #2 - 2.0" Blue Coil
Job Objective: Pull LTP
MIRU CTU. Make up 2-7/8" Yellowjacket fishing BHA with 4" hydrualic GS spear. RIH
and tag the LTP at ~ 12086' CTM / 12098' MD. Pull free on the 5th jar lick to 60k.
POOH and recover the LTP (see log for details). Freeze protect the tubing to 2500'
TVD with diesel. RDMO.
***Job Complete*******
8/23/2023
***WELL S/I ON ARRIVAL***
DRIFT & BRUSH DEPLOYMENT SLEEVE FOR LTP W/ QC, 3.73" CENT, 10' x
1.875" stem, 3.66" CENT, 8' x 1.5" stem, 3.5" BLB, BULL NOSE (22' OAL) 12,105'
MD)
*** CONTINUE ON 8/24/2023 ***
Daily Report of Well Operations
PBU MPL-39B
8/24/2023
*** CONTINUE FROM 8/23/2023 ***
RAN DPU W/ NORTHERN SOLUTIONS 4-1/2" LINER TOP PACKER TO 12102'
PULLED 2-7/8" XX PLUG FROM LTP
RAN 4-1/2" JET PUMP(11B W/SIDOTI SEAL) SOFT SET, W/PRESSURE & TEMP
GUAGES
***CONTINUE ON 8/25/2023***
8/25/2023
***CONTINUE FROM 8/24/2023***
FINISH RIG DOWN, DROP OFF TOOLS AT FIRE HALL, TRAVEL TO PRUDHOE
***WELL FLOWING ON DEPARTURE, LOCATION INSPECTED, DSO NOTIFIED,
CLOSE PERMIT***
8/29/2023
Assist Slickline, Pumped 123 bbls Criesel down Tubing, Pumped 18 bbls Criesel
down IA, Pumped 22 bbls Criesel down IA taking returns up Tubing into Production
8/29/2023
***WELL S/I ON ARRIVAL***
PULL 3'' JET PUMP @ 11869' SLM / 11858' SLM
RAN 3.25'' CENT., 8' X 1-1/4'' STEM, 2.75'' CENT., 8' X 1-1/4'' STEM 2.84'' CENT.,
(18.3'), WENT DOWN TO PACKER @ 11930' SLM / 11919' MD
***WELL S/I ON DEPARTURE***
8/30/2023
Freeze Protect, Pumped 84 bbls criesel down IA up Tubing to production, U-Tube
TxIA, Pumped 2 bbls diesel down Flowline
8/30/2023
***WELL S/I ON ARRIVAL***
OBJECTIVE CUT TUBING @11859'
MIRU E-LINE, INITIATE PERMIT
R/U WELL HEAD GAIN CONTROL OF 9/32' WL CHD,2 X WHEEL SUBS, 1 11/16"
WB, WELTEC CUTTING TOOL
STAB ON WELL PT PCE 300 PSI LOW/ 3000 PSI HIGH OPEN SWAB VALVE RIH
CUT TUBING @ 11858.8', CCL DEPTH 11840.5, CCL TO CUTTER 18.3'
CUT COMPLETE POOH WELTEC MEASUREMENT 4.65"
R/D SURFACE EQUIPMENT
CLOSEOUT PERMIT
***WELL S/I ON DEPARTURE***
9/1/2023
***WELL S/I ON ARRIVAL***
3.25'' CENT., BHP's
GOOD DATA
***WELL S/I ON DEPARTURE***
9/2/2023
WELLHEAD: Pump open SSV, verify tubing 0 psi. Set 4" CTS Bpv with T bar for
upcoming work over.
9/5/2023
WELLHEAD; Bled off tree adapter void, N/D tree and adapter cleaned up tubing
hanger set CTS plug, checked lift threads, cycled LDS, placed new ring gasket and
put on BOP loaded tree on truck. S/B for rig up.
Activity Date Ops Summary
9/7/2023 Move rig to L-pad. spot in crane. fly rig floor and stairs, N/D BOPE. N/U tree test void to 500/5000 psi. Baker perform final checks. fly cellar and LKoomey lines. Spot
pit on L-39B,Level out pits. Spot in crane. Fly cellar, rig floor and stairs. Lay out Koomey hoses. Spot Rig on mud boat and level out. Install comms. Raise Mast.
install locking pins on mast, tighten guy lines. Take on 240bbls of 8.4ppg Source Water to pits. Install stairs on ODS. Spot in Pipe Skate and sheds. RU Tongs and
handling equipment. Install gauge on IA, 80psi. Nipple up flow line spool. Tighten Jumper hoses and Pop-Off. Crew change - PJSM, review Sundry. Shut down and
check equipment. NU Spacer Spools, Bird Bath, Accumulator lines to BOP. RU line to Tiger Tank. Bleed IA from 80psi to 25psi. Unable to bleed lower due to height
of tank piping, call for smaller bleed trailer. R&P Fresh Water truck is inop. Grease Manifold and valves. MU TIW VLV to 2-7/8" & 4-1/2" Test Mandrels. Run 1/2"
Bleed hose from IA to Bleed trailer. Flow decreased considerably in the first 10min to a slight dribble. Continue to monitor while BOPE testing. Install 2-7/8" Test
Mandrel. Close Pipe Rams & Back-up. Complete Rig Acceptance Checklist. STBY for water truck coming from D-14. Accept Rig at 06:00.
9/8/2023 Take on fresh water. Fill stack Shell test BOP. good test. Test BOPE 250 low 2500 high as per approved sundry. Tested with 2-7/8" and 4-1/2" test joints. AOGCC
Adam Earl waived witness. 0 failures,Rig down test equipment. Blow down fluid lines. Pull CTS plug. No pressure observed under BPV. Pulled BPV. Pump 75
BBLs @ 3 BPM 1000 psi down IA taking returns up tubing until returns clean up. Swap vales and pump 180 BBLs down tubing. Shut down pump flowback tank
getting full. fluid was not clean yet. Vac truck suck out flow back tank. Pump another 30 BBLs until returns are clean. Blow down lines. Prep landing joint to pull
hanger. Install Landing Joint. BOLDS. Ensure well is static. Unseat Hanger w/ 83K, 100K Break-over, 97K PUW. TBG on vac. BO Hanger & LD. Install stripping
rubber. Pipe Shed cleaning and applying BOL 2000 to threads. Marking Pipe w/ thread type. Fill hole & establish well parameters. POOH w/ 4-1/2", 12.6#, L, TXP /
EZGO / DWC Completion from cut @ 11,859' ELMD T/ 10,899'. C/O slipping Tong Dies. Fill hole & establish well parameters - pump single displacement.
Continue POOH F/ 10,899' - T/ 9,842' while pumping single displacement. Crew change - check equipment, daily inspections. Continue POOH F/ 9,842' - T/ 5400'
while pumping single displacement.
9/9/2023 Continue POOH F/ 5400' T/ 4,200' while pumping single displacement. 30 min rig service. Change out make/break selector on tongs,Change out make break
selector on tongs,Continue POOH F/4,200' T/ surface while pumping single displacement. Filled hole W/ 12 BBLs,Swap over handling equipment. Run ESP cable
through sheave. Hang sheave. Set up ESP completion on catwalk. PU & fill ESP w/ Dielectric Mineral Oil. RIH w/ 2-7/8", 6.5#, L, EUE Centrilift ESP Completion.
JT# 1 - XN Nipple Assy. JTS# 2,3 GLM#1 - DGLV w/ BK Latch. Testing every 1000', installing clamps every-other connection, pumping single displacement. T/
1,587' MD. Check equipment, daily inspections. RIH F/ 1587' - T/ 2140' ESP test - good. RIH F/ 2140' - T/ 4100' Currently testing ESP.
9/10/2023 Continue to RIH W/ 2-7/8" and ESP F/ 4,100' T/ 7,900'. Clamping every other joint. Checking cable every 1,000',Baker perform reel to reel splice. Continue to RIH
W/ 2-7/8" and ESP F/ 7,900' T/ 8650'. Clamping every other joint. Checking cable every 1,000' Splice hit halfway up joint 245. 3,720' from surface,Rig service.
Replace backup ram bolt. Continue RIH F/ 8650' - T/ 11,641' - JT# 354. PU & MU GLM#2 - 1" DPSOV w/ BK Latch. Last ESP test @ 10,464' - Good. Continue RIH
T/ 11,765'. PU & MU Hanger - BPV installed, 2-7/8" EUE Landing Joint. Measure and cut Cable. Perform termination through hanger. Flush & pump out stack. Blow
down lines. Land Hanger while monitoring ESP. RILDS. PUW = 78K | SOW = 33K. 190 OTC Clamps. 6 Protectolizers. 2 Flat Guards,LD Landing Joint. RDMO.
Move pipe sheds, clean & suck out pits w/ vac. truck. RD Flow Spools.
50-029-22786-01-00API #:
Well Name:
Field:
County/State:
MP L-39B
Milne Point
Hilcorp Energy Company Composite Report
, Alaska
ACTIVITYDATE SUMMARY
9/11/2023
WELLHEAD: Pee install 2.5 Bpv into Hgr and MU to LJ. PU and MU to comp string,
Centralift cut and splice ESP cable. Five ft into profile 18.34' RILDS, BOLJ.
9/11/2023
WELLHEAD: BOP stack removed, clean Hgr void, install seal subs and RX54 gasket.
PU and land 2 9/16" tree/adapter, torque to spec and test 500/5000 (PASS). Pull Bpv
with T bar. All valves closed.
9/12/2023
MPU Well Support tied well back into process,Post-RWO. Serviced wellhead and
PT'd surface lines 1150# psi. Handed well over to E&I Group
No issues
Daily Report of Well Operations
PBU MPL-39B
WELL NAME
Date :
Shoe @ :FC @ :Top Liner @ :
Type:
Type :
Type :
Type :
Type :
Yes X No
Yes X No Yes X No
X Yes No Yes X No
Date :
Volume lost during displacement (bbls) :
CEMENT REPORT
19-Jun-23 Hole Size :4.25 Casing Size :3-1/2" x 3-1/4" x 2-7/8"
FI
R
S
T
S
T
A
G
E
13462 13,477' & 13,436' 12105
Preflush (Spacer)
Source Water Density (ppg) : 8.35 Volume pumped (bbls) : 140
Lead Slurry
Class G Volume (bbls): 20.5 Density (ppg) : 15.3
Yield : 1.235 Sacks : 93.2 Mixing / Pumping Rate (bpm) : 2
Tail Slurry
Volume (bbls) : Density (ppg) :
2
Yield : Sacks : Mixing / Pumping Rate (bpm) :
8.34 Rate (bpm) : 2 Volume (actual / calculated) : 8.8 / 8.8
Post Flush (Spacer)
1.5 ppb Geovis Density (ppg) : 8.34 Rate (bpm) :
3960 Pump used for disp : GD Plug Bumped? Bump press :
Volume : 150
Displacement :
1.5 ppb Geovis Density (ppg) :
0
Casing Rotated? Reciprocated? % Returns during job : 100%
Cement returns to surface? Spacer returns? Vol to Sur : 3
FCP (psi) :
Cement In Place At : 10:00 6/19/2023 Estimated TOC : 12,537
Method Used To Determine TOC : Calculated
0 bbls
Remarks: Liner wiper plug did not shear, liner filled with cement from 13462 to 12105'
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-39B 50029227860200 223037 6/30/2023 HALLIBURTON COILFLAG
MPU L-39B 50029227860200 223037 6/30/2023 HALLIBURTON RBT
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: 07/14/2023
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
Well: MPU L-39B
PTD: 223-037
API: 50-029-22786-02-00
FINAL LWD FORMATION EVALUATION LOGS (06/14/2023 to 06/18/2023)
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: 223-037
T37851
Kayla
Junke
Digitally signed by
Kayla Junke
Date: 2023.07.17
09:19:38 -08'00'
1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown
Suspend Perforate Other Stimulate Pull Tubing Cut Tubing
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):
12,740'N/A
Casing Collapse
Conductor N/A
Surface 3,090psi
Intermediate 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:
9.3 / L-80 / EUE Mod 8rd 12,312'
6/19/2023
7" x 4-1/2" D&L Perm. Hydro ISO & Baker SB-3 and N/A 11,901 MD/ 6,646 TVD & 12,271 MD/ 6,970 TVD and N/A
See Schematic See Schematic 3-1/2"
Perforation Depth MD (ft):
12.6 / L-80 / TXP, EZGO HT & DWC
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
ADL0025509, ADL0025514 & ADL0025515
223-037
3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-22786-02-00
Hilcorp Alaska LLC
KUPARUK RIVER OIL N/A
C.O. 432E
MILNE PT UNIT L-39B
Length Size
Proposed Pools:
114' 114'
TVD Burst
PRESENT WELL CONDITION SUMMARY
7,390' 12,634' 7,305' 3,260 N/A
80' 20"
MILNE POINT
MD
N/A
5,750psi
7,240psi
4,165'
7,380'
8,649'
12,717'
12,136'
9-5/8"
7"
8,613'
12,684'
4-1/2"
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 4:30 pm, May 31, 2023
323-320
Digitally signed by Taylor
Wellman (2143)
DN: cn=Taylor Wellman (2143)
Date: 2023.05.31 14:46:43 -
08'00'
Taylor Wellman
(2143)
MGR20JUN23 SFD 6/8/2023
ADL0388235 SFD
DSR-6/1/23
* BOPE pressure test to 3500 psi. Annular to 2500 psi.
* Approved for 30 day reverse circulation jet pump production with 24/7 man watch and 1.5 wellbore volumes of KWF available at MPU
while on jet pump production.
Perforate
3,260
10-404
GCW 06/20/2023
06/21/23
Jessie L.
Chmielowski
Digitally signed by Jessie L.
Chmielowski
Date: 2023.06.21 09:41:50
-08'00'
RBDMS JSB 062223
Well: MPU L-39A or MPU L-39B
Scope: Post-CTD APERF + ESP RWO
Well Name:MPU L-39A or L-39B API Number:50-029-22786-01-00
Current Status:Oil Well Pad:L-Pad
Estimated Start Date:June 19, 2023 Rig:CTU/E-line/ASR
Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd:
Regulatory Contact:Tom Fouts Permit to Drill Number:223-036 / 223-037
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: 3,672 psi @ 7,062’ TVD SBHPS taken 04/21/2022 |10.0 PPGE
Maximum Expected BHP:3,966 psi @ 7,062’ TVD 220psi WHP with 10.2 KWF |10.8 PPGE
Max Potential Surface Pressure: 3,260 psi Gas Column Gradient (0.1 psi/ft)
Max Angle:79° @ 6,050’ MD within parent bore
Max Dogleg Severity: 6.32 deg/100’ @ 3,000’ MD within parent bore
Tie in Log: To be provided by Geologist
Brief Well Summary:
MPU L-39A is a slant producer in the Kuparuk A-sand that will be sidetracked across a fault to the South to
access unswept oil (PTD 223-036). It is believed the fault to the South is not in communication with the current
MPU L-39 parent block. There are no existing penetrations into the fault block which MPU L-39A will access.
There is a risk the new fault block will be wet and not contain economic quantities of oil. In the event of no oil
in the sidetrack block upon production, MPU L-39A will need to be sidetracked into the existing block (PTD#
223-037) to the North to gain more footage in the block becoming MPU L-39B.
Objectives:
x Perforate high resistivity intervals within the cemented L-39A lateral using perf guns conveyed on
service coil.
x Temporary flowback the well for 30 days, confirming water cut and rule out the need to drill an
additional coil sidetrack.
x 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 May of 2023 with new 4-1/2” tubing.
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
3,260 psi
Well: MPU L-39A or MPU L-39B
Scope: Post-CTD APERF + ESP RWO
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.
2.Circulate ~194 bbls 10.2 brine (Confirm CDR2 KWF used) 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 procedure calls for KCl water.
a. Estimated Wellbore volume to top perf = 194 bbls
b. 4-1/2” Tubing – 12,000’ x 0.0152 bpf = 182 bbls
c. 3-1/2” Liner – 150’ x 0.0087 = 1.3 bbls
d. 3-3/16” Liner – 500’ x 0.0079 = 4 bbls
e. 2-7/8” Liner – 1,200’ x 0.0058 = 7 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.
Perf Schedule
Perf
Interval Perf Length Gun Length Weight of Gun
(lbs)Comments
Run
1 TBD*~500’ 500’ 2000 lbs (4ppf)Final lengths TBD after analyzing
open hole and cement log data.
BHAs will be limited to 500’ for
any individual run.
Run
2 TBD*~200’ 200’ 800 lbs (4ppf)
Total ~700’ 700’
*Perf intervals will stay within the permitted Kuparuk interval of the MPU L-39A CTD sidetrack.
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.
L-39B SFD
*Perf intervals will stay within the permitted Kuparuk interval of the MPU L-39A CTD sidetrack.
Well: MPU L-39A or MPU L-39B
Scope: Post-CTD APERF + ESP RWO
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.
Hilcorp requests approval to temporarily flowback L-39A via reverse circulating jet pump for a period
of 30 days. Temporary jet pump flowback will allow ruling out of need for a second CTD sidetrack
through the 4-1/2” tubing, 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 to be set at at least 50% of expected maximum header injection
pressure.
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 11,839’.
21. Install 11A jet pump in sliding sleeve at 11,839’.
22. RDMO.
Slickline (After temporary flowback)
23. Pull jet pump from 11,839’.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
~11,859’ 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.
38. RD Little Red Services and reverse out skid.
39. Set BPV.
30 days maximum approved.
Well: MPU L-39A or MPU L-39B
Scope: Post-CTD APERF + ESP RWO
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 100K lbs on ASR1.
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 ± 11,810’ 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 ~11,810’ MD
4.5 2 Intake Sensor 30
5.62 34 Motor 80
5.2 7 Lower Tandem Seal 38
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
Contact AOGCC with new BHP for possible approval to BOPE
change.
Well: MPU L-39A or MPU L-39B
Scope: Post-CTD APERF + ESP RWO
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" ~8,550 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.
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.
Well: MPU L-39A or MPU L-39B
Scope: Post-CTD APERF + ESP RWO
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: TDF 5/16/2023
SCHEMATIC
Milne Point Unit
Well: MPU L-39
Last Completed: 5/15/2023
PTD: 197-128
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20" Conductor 91.1 / H-40 / N/A N/A Surface 114'
9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’
7" Production 26 / L-80 / NSCC 6.276 Surface 12,717’
TUBING DETAIL
4-1/2” Tubing 12.6 / L-80 / TXP 3.958 Surface 733’
4-1/2” Tubing 12.6 / L-80 / EZGO HT 3.958 733’ 8,500’
4-1/2” Tubing 12.6 / L-80 / DWC 3.958 8,500 12,136’
3.5" Tubing 9.3/L-80/EUE Mod 8rd 2.992 12,264’ 12,312’
JEWELRY DETAIL
No Depth Item
1 11,839’ Sliding Sleeve
2 11,901’ 7" x 4½" D&L PERM. HYD. ISO Packer COE 7.8' from PIN "threads off"
3 12,001 X Nipple Min ID - 3.813'' w/ RHC Installed
4 12,094’ Wireline Entry – Mule Shoe –Bottom @ 12,136’
5 12,271’ 3.5” Baker SB-3 Packer
6 12,295’ 3.5” HES XN Nipple (No Go 2.750” ID)
7 12,307 3.5” Otis WLEG
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kup. A2 &A3 12,362’ 12,402’ 7,062’ 7,098’ 40 6/27/1998 Open
OPEN HOLE / CEMENT DETAIL
20" 250 sx of Arcticset I (Approx) in 24” Hole
9-5/8" 2,199 sx PF “E”, 550 sx Class “G” in 12-1/4” Hole
7” 275 sks Class “G” in 8-1/2” Hole
WELL INCLINATION DETAIL
KOP @ 300’ to 4,500’
Max Hole Angle = 78 deg.
Max Hole Angle through perforations = 27 deg.
TREE & WELLHEAD
Tree 5M Cameron 2-9/16”
Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH
Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile
GENERAL WELL INFO
API: 50-029-22786-00-00
Drilled and Cased by Nabors 27E - 6/29/1997
3.5” Injection Completion by Nabors 27E – 7/1/1998
Conversion to Jet Pump – 10/16/2014
Convert to Producer – 4/23/2015
Install Kill String by ASR#1 – 11/24/2016
Run ESP Doyon 14 – 2/7/2017
Completed by ASR - 5/15/2023
STIMULATION SUMMARY
Kuparuk “A” Sand: 59,000# of 20/40
Carbo Bond frac proppant behind pipe.
TD =12,740’ (MD) / TD = 7,401’(TVD)
20”
Orig. KB Elev.: 34.3’
7”
2
4
9-5/8”
1
5
3
Top of
Tubing Cut
@ 12,264’
PBTD = 12,634’ (MD) / PBTD = 7,305’(TVD)
6
7
NOTE:
ALL TUBING AND JEWELRY DEPTHS
ADJUSTED TO ASR RKB.
_____________________________________________________________________________________
Revised By: TDF 5/31/2023
PROPOSED
Milne Point Unit
Well: MPU L-39B
Last Completed: Future
PTD: 223-037
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20" Conductor 91.1 / H-40 / N/A N/A Surface 114'
9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’
7" Production 26 / L-80 / NSCC 6.276 Surface 12,717’
TUBING DETAIL
2-7/8” Tubing 6.4 / L-80 / EUE 8rd 2.441 Surface ±11,810’
3.5" Tubing 9.3/L-80/EUE Mod 8rd 2.992 12,264’ 12,312’
JEWELRY DETAIL
No Depth Item
1 ±150’ 2-7/8" x 1" GLM, DV installed
2 ±3,000’ Packer, Viking ESP Retr. Dual Vent
3 ±3,071’ 2-7/8" x 1" GLM, DV installed
4 ±3,130’ 2-7/8” X-nipple with RHC profile
5 ±8,560’ 2-7/8" x 1" GLM, DV installed
6 ±8,648’ 2-7/8” XN-nipple -Min ID 2.313”
7 ±x,xxx’ Ported Discharge Head
8 ±x,xxx’ Pump
9 ±x,xxx’ Gas Separator
10 ±x,xxx’ Upper Tandem Seal
11 ±x,xxx’ Lower Tandem Seal
12 ±x,xxx’ Motor
13 ±x,xxx’ Intake Sensor w/ Centralizer
14 11,901’ 7" x 4½" D&L PERM. HYD. ISO Packer COE 7.8' from PIN "threads off"
15 12,001 X Nipple Min ID - 3.813'' w/ RHC Installed
16 ±12,054’ 4-1/2” x 3-1/2” LTP
17 12,094’ Wireline Entry – Mule Shoe –Bottom @ 12,136’
18 12,271’ 3.5” Baker SB-3 Packer
19 12,295’ 3.5” HES XN Nipple (No Go 2.750” ID)
20 12,307 3.5” Otis WLEG
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kup. TBD TBD TBD TBD 700 Future Pending
OPEN HOLE / CEMENT DETAIL
20" 250 sx of Arcticset I (Approx) in 24” Hole
9-5/8" 2,199 sx PF “E”, 550 sx Class “G” in 12-1/4” Hole
7” 275 sks Class “G” in 8-1/2” Hole
WELL INCLINATION DETAIL
KOP @ 300’ to 4,500’
Max Hole Angle = 78 deg.
Max Hole Angle through perforations = 27 deg.
TREE & WELLHEAD
Tree 5M Cameron 2-9/16”
Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH
Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile
GENERAL WELL INFO
API: 50-029-22786-02-00
CTU Sidetrack - Future
STIMULATION SUMMARY
Kuparuk “A” Sand: 59,000# of 20/40
Carbo Bond frac proppant behind pipe.
TD = 12,740’ (MD) / TD = 7,401’(TVD)
20”
Orig. KB Elev.: 34.3’
7”
2
4
9-5/8”
1
5
3
PBTD = 12,634’ (MD) / PBTD = 7,305’(TVD)
6
17
7
8
9
10 & 11
12
13
14
See
Whipstock
Summary
18
19
20
Top of
Tubing Cut
@ ±11,859’
15 & 16
Top of
Tubing Cut
@ 12,264’
NOTE:
ALL TUBING AND JEWELRY DEPTHS
ADJUSTED TO ASR RKB.
WHIPSTOCK SUMMARY
Whipstock Set @ ±12, 254’ Top of
Window @ ±12,256’ For L-39A or L-39B
Well: MPU L-39A or MPU L-39B
Scope: Post-CTD APERF + ESP RWO
Coiled Tubing BOPE
Well: MPU L-39A or MPU L-39B
Scope: Post-CTD APERF + ESP RWO
Standing Orders for Open Hole Well Control during Perf Gun Deployment
Well: MPU L-39A or MPU L-39B
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 Myers
Drilling Manager
Hilcorp Alaska LLC
3800 Centerpoint Dr, Suite 1400
Anchorage, AK, 99503
Re: Milne Point, Kuparuk River Oil, MPU L-39B
Hilcorp Alaska, LLC
Permit to Drill Number: 223-037
Surface Location: 3334' FSL, 5137' FEL, Sec. 08, T13N, R10E, UM, AK
Bottomhole Location:286' FSL, 1441' FEL, Sec. 12, T13N, R09E, UM, AK
Dear Mr. Meyers:
Enclosed is the approved application for the permit to drill the above referenced well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well
logs run must be submitted to the AOGCC within 90 days after completion, suspension, or
abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
Brett W. Huber, Sr.
Chair, Commissioner
DATED this ___ day of June, 2023. 05
Brett W.
Huber, Sr.
Digitally signed by Brett W.
Huber, Sr.
Date: 2023.06.05 14:22:18
-08'00'
1a.
Contact Name:Trevor Hyatt
Contact Email:trevor.hyatt@hilcorp.comAuthorized Name: Monty Myers
Authorized Title:Drilling Manager
Authorized Signature:
Contact Phone:907-777-8396
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-39B
TVD:14944'7125'
12. Field/Pool(s):
MILNE POINT, KUPARUK
RIVER OIL
MD:
ADL 025509, 025515, 025514 & 388235
88-002 June 5, 2023
4a.
Surface:
Top of Productive Horizon:
Total Depth:
3334' FSL, 5137' FEL, Sec. 08, T13N, R10E, UM, AK
1665' FNL, 1841' FEL, Sec. 13, T13N, R09E, UM, AK
Kickoff Depth:12297 feet
Maximum Hole Angle: 90 degrees
Maximum Anticipated Pressures in psig (see 20 AAC 25.035)
Downhole:Surface:3800 3100
17.Deviated wells:16.
Surface: x-y- Zone -544743 6031523 4
10. KB Elevation above MSL:
GL Elevation above MSL:
feet
feet
51.42
17.1
15.Distance to Nearest Well
Open to Same Pool:
Cement Quantity, c.f. or sacks
MD
Casing Program:
12145'6860'
19.PRESENT WELL CONDITION SUMMARY
Production
77 250 sx Arctic Set (Approx.)
12740 7390 None 12634 7294 None
37 - 114
Surface 2199 sx PF E, 550 sx Class G
7051 - 7087
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#
8613
12362 - 12402
50-029-22786-02-00
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
286' FSL, 1441' FEL, Sec. 12, T13N, R09E, UM, AK
Time v. Depth Plot 5 5 Drilling Program
2237'
(To be completed for Redrill and Re-Entry Operations)
20"
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.
9557
3381'
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
37 - 114
36 - 8649 36 - 4162
12684 7"275 sx Class G 33 - 12717 33 - 7369
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.
14944'7125'172 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))
4.17.2023
By Kayla Junke at 10:18 am, Apr 18, 2023
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2023.04.17 12:46:46 -08'00'
Monty M
Myers
BOPE test to 3500 psi.
DSR-4/18/23
Variance to 20 AAC 25.112(i) approved for alternate
plug placement for abandonment of parent.
SFD 5/27/2023
223-037
MGR01JUNE2023GCW 06/02/23JLC 6/2/2023
06/05/23
06/05/23
Brett W. Huber, Sr.Digitally signed by Brett W. Huber,
Sr.
Date: 2023.06.05 14:22:41 -08'00'
To: Alaska Oil & Gas Conservation Commission
From: Trevor Hyatt
Drilling Engineer
Date: April 17, 2023
Re: MPU L-39B Permit to Drill
Approval is requested for drilling a CTD sidetrack lateral from well MPU L-39A with the
Nabors CDR2 Coiled Tubing Drilling.
Proposed plan for MPU L-39B Producer:
See MPU L-39 Sundry request for complete pre-rig details - Prior to drilling activities, a RWO will be conducted
to swap to 4-1/2" tubing and mill the lower completion packer and push to bottom. Screening will be conducted to
MIT and drift for whipstock. E-line will then set a 4-1/2"x7" flow through whipstock (rig will set if needed). Service
Coil will mill the window (rig will mill if needed).
A coil tubing drilling sidetrack will be drilled with the Nabors CDR2 rig. The rig will move in, test BOPE and kill the
well. If unable to set or mill pre-rig, the rig will set a 4-1/2"x7" flow through whipstock and mill a single string 3.80"
window + 10' of formation. The well (L-39A) will kick off drilling and land in the Kuparuk. The lateral will continue
in the Kuparuk to TD. If the reservoir is not as expected, an anchored billet will be set in the open hole of L-39A
and the well will be sidetracked to the north (L-39B - contingency). The lateral will continue in the Kuparuk to a
northern target and TD. The proposed sidetrack (L-39B – contingency) will be completed with a 3-1/2"x3-1/4"x2-
7/8” L-80 solid liner and cemented. This completion WILL abandon the parent (L-39) Kuparuk perfs and the L-39A
lateral. The well will be perforated post rig (see future perf sundry).
The following describes the work planned. A wellbore schematic of the current well and proposed sidetrack is
attached for reference.
Pre-Rig Work:
x Reference MPU L-39 Sundry submitted in concert with this request for full details.
x General work scope of Pre-Rig work:
1. RWO: Tubing Swap and MITs (see preceding RWO sundry)
2. Slickline: Dummy WS drift
3. E-Line: Set whipstock
4. Coil: Mill window
5. Valve Shop: Pre-CTD Tree Work as necessary
Rig Work - (Estimated to start in June 2023):
1. MIRU and test BOPE to 3500 psi. MASP with gas (0.10 psi/ft) to surface is 3,100 psi
a. Give AOGCC 24hr notice prior to BOPE test
b. Test against swab and master valves (No TWC)
c. Load pits with drilling fluid
d. Open well and ensure zero pressure
2. Only if not done pre-rig – Set 4-1/2"x7" whipstock.
a. Top of whipstock at 12,295’ MD oriented at 0° ROHS.
3. Only if not done pre-rig – Mill 3.80” single string window (out of 7”) plus 10’ of rathole.
a. Top of window (whipstock pinch point 2’ down from top) at 12,297’ MD.
4. Drill – Build & Lateral (L-39A)
a. 3” BHA with GR/RES / Bi-center Bit (4.25”)
b. 30° DLS build section – 214’ MD / Planned TD 12,511’ MD
c. 12° DLS lateral section – 1,594’ MD / Planned TD 14,105’ MD
d. Drill with a constant bottom hole pressure for entire sidetrack
e. Pressure deployment will be utilized
f. After TD and on the last trip out of hole lay in completion/kill weight fluid in preparation for liner run
g. No flow test prior to laying down drilling BHA. Assure well is dead prior to picking up liner.
p,
(L-39B - contingency).
Sundry 323-299
(gy)p
This completion WILL abandon the parent (L-39) Kuparuk perfs and the L-39A
lateral.
PTD 223-037
5. Sidetrack from L-39A to L-39B
a. Set anchored billet at ~12,450’ MD.
6. Drill – Build & Lateral (L-39B)
a. 3” BHA with GR/RES / Bi-center Bit (4.25”)
b. 30° DLS build section – 443’ MD / Planned TD 12,893’ MD
c. 12° DLS lateral section – 2,051’ MD / Planned TD 14,944’ MD
d. Drill with a constant bottom hole pressure for entire sidetrack
e. Pressure deployment will be utilized
f. After TD and on the last trip out of hole lay in completion/kill weight fluid in preparation for liner run
g. No flow test prior to laying down drilling BHA. Assure well is dead prior to picking up liner.
7. Run and Cement Liner (L-39B)
a. Have 2-3/8” safety joint with TIW valve ready to be picked up while running liner
b. Swap BOP rams from 3” pipe/slip (drilling) to 2-3/8”x3-1/2” VBRs (running liner) and test to 3500 psi.
c. Run 3-1/2”x3-1/4”x2-7/8” 13Cr solid liner to TD
d. Swap well over to KCl
e. Cement Liner with 38 bbls - 15.3 ppg Class G cement (TOC to TOL)*
f. Only if not able to do with service coil post rig - Perforate well ~500’
g. Freeze protect well from ~2200’ TVD (min)
h. RDMO
Post Rig:
1. V: Valve & tree work
2. C: Post rig perforate (~500’)
3. S: Set LTP* (if necessary)
4. T: Portable Test Separator Flowback
* Approved alternate plug placement per 20 AAC 25.112(i)
Managed Pressure Drilling:
Managed pressure drilling techniques will be employed on this well. The intent is to provide constant bottom hole
pressure by using minimum 8.4 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 and is 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” (bighole) & 2-3/8” (slimhole) pipe/slip rams (see attached BOP configurations). 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:
MPD Pressure at the Planned Window (12,282’ MD - 6,909’ TVD)
Pumps
On Pumps Off
A Target BHP at Window (ppg)4,239 psi 4,239 psi
11.8
B Annular friction - ECD (psi/ft)737 psi 0 psi
0.06
C Mud Hydrostatic (ppg)3,090 psi 3,090 psi
8.6
B+C Mud + ECD Combined 3,827 psi 3,090 psi
(no choke pressure)
A-(B+C)Choke Pressure Required to Maintain 413 psi 1,150 psi
Target BHP at window and deeper
Separate sundry required if
post rig perforating. - mgr
Operation Details:
Reservoir Pressure:
x The estimated reservoir pressure is expected to be 3,800 psi at 7,000’ TVD (10.5 ppg equivalent).
x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 3,100 psi (from estimated
reservoir pressure).
Mud Program:
x Drilling: Minimum MW of 8.4 ppg KCL with Geovis for drilling. Managed pressure used to maintain
constant BHP.
x KWF will be stored on location. The tankage will contain 1.5 wellbore volumes of KWF 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 10.7 ppg KWF to be used for liner deployment. Will target 11.8 ppg to
match managed pressure target.
Disposal:
x All Class l & II non-hazardous and RCRA-exempt drilling and completion fluids will go to GNI at DS 4.
x Fluids >1% hydrocarbons or flammables must go to GNI.
x Fluids >15% solids by volume must go to GNI.
x Fluids with solids that will not pass through 1/4” screen must go to GNI.
x Fluids with PH >11 must go to GNI.
Hole Size:
x 4.25” hole for the entirety of the production hole section.
Liner Program:
x 3-1/2”, 9.3#, L-80 solid/cemented liner: 12,145’ MD – 12,290’ MD (145’ liner)
x 3-1/4”, 6.6#, L-80 solid/cemented liner: 12,290’ MD – 12,600’ MD (310’ liner)
x 2-7/8”, 6.5#, L-80 solid/cemented liner: 12,600’ MD – 14,944’ MD (2,344’ liner)
x The primary barrier for this operation: Kill Weight Fluid to provide overbalance as necessary
x A X-over shall be made up to a 2-3/8” safety joint including a TIW valve for all tubulars ran in hole.
Well Control:
x BOP diagram is attached. MPD and pressure deployment is planned.
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 2,500 psi.
x 1.5 wellbore volumes of KWF will be on location at all times during drilling operations.
x Solid 2-7/8” 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 A X-over shall be made up to a 2-3/8” safety joint including a TIW valve for all tubulars ran in hole.
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 Directional plan attached. Maximum planned hole angle is 90°. Inclination at kick off point is 70°.
x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run.
x Distance to nearest property line – 2,237’
x Distance to nearest well within pool – 3,381’
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 ~500’ perforated post rig (See future perforating sundry request – if extended perforating is used)
x 2” perf guns, 6 SPF, 60 deg phasing
x If extended perforating is not an option, the well will be perforated with the rig or post rig under this PTD.
Anti-Collision Failures:
x No failures for MPU L-39B WP05
Hazards:
x MPU L-pad is an H2S pad.
o The highest recorded H2S well on the pad was from L-32 (410 ppm) in 2009.
o No recorded H2S on L-39.
x No fault crossings expected.
x Medium lost circulation risk.
Trevor Hyatt CC: Well File
Drilling Engineer Joseph Lastufka
907-223-3087
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
T1 T2
Flow Tee
Master
Master
LDS
IA
OA
LDS
Ground Level
3" LP hose open ended to Flowline
CDR2-AC BOP Schematic
CDR2 Rig's Drip Pan
Fill Line from HF2
Normally Disconnected
3" HP hose to Micromotion
Hydril 7 1/16"
Annular
Blind/Shear
2-3/8" Pipe/Slips
2 3/8" Pipe/Slips
2 3/8" Pipe/Slips
7-1/16"
5k Mud
Cross
2-3/8" Pipe/Slips
3.0" Pipe / Slip
HF
nneceeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeeee
_____________________________________________________________________________________
Revised By: JNL 4/10/2023
PROPOSED
Milne Point Unit
Well: MPU L-39
Last Completed: 2/7/2017
PTD: 197-128
GENERAL WELL INFO
API: 50-029-22786-00-00
Drilled and Cased by Nabors 27E - 6/29/1997
3.5” Injection Completion by Nabors 27E – 7/1/1998
Conversion to Jet Pump – 10/16/2014
Convert to Producer – 4/23/2015
Install Kill String by ASR#1 – 11/24/2016
Run ESP Doyon 14 – 2/7/2017
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kup. A2 &A3 12,362’ 12,402’ 7,051’ 7,087’ 40 6/27/1998 Open
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20" Conductor 91.1 / H-40 / N/A N/A Surface 114'
9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’
7" Production 26 / L-80 / NSCC 6.276 Surface 12,717’
TUBING DETAIL
4-1/2” Tubing 12.6/L-80/TXP 3.958 Surface ±12,170’
JEWELRY DETAIL
No Depth Item
1 ±12,000’ 3.813” X Sliding Sleeve
2 ±12,050’ 7” x 4-1/2” Packer
3 ±12,160’ 3.813” X Nipple
4 ±12,168’ Wireline entry guide – Btm @ ±12,170’
5 12,295’ Whipstock
OPEN HOLE / CEMENT DETAIL
20" 250 sx of Arcticset I (Approx) in 24” Hole
9-5/8" 2,199 sx PF “E”, 550 sx Class “G” in 12-1/4” Hole
7” 275 sks Class “G” in 8-1/2” Hole
WELL INCLINATION DETAIL
KOP @ 300’ to 4,500’
Max Hole Angle = 78 deg.
Max Hole Angle through perforations = 27 deg.
TREE & WELLHEAD
Tree 5M Cameron 2-9/16”
Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH
Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile
STIMULATION SUMMARY
Kuparuk “A” Sand: 59,000# of 20/40
Carbo Bond frac proppant behind pipe.
TD = 12,740’ (MD) / TD = 7,401’(TVD)
20”
KB Elev.: 51.42’, GL Elev.: 17.1’
7”
2
4
9-5/8”
1
Whipstock set
@ 12,295’5
3
Fish:
3-1/2” Tubing
Tail w/ Packer
(Depth
Unknown)
PBTD = 12,297’ (MD)/ PBTD = 6,993’(TVD)
_____________________________________________________________________________________
Revised By: JNL 4/10/2023
PROPOSED
Milne Point Unit
Well: MPU L-39B
Last Completed: TBD
PTD: TBD
GENERAL WELL INFO
API: 50-029-22786-02-00
Drilled and Cased by Nabors 27E - 6/29/1997
B Sidetrack:
PERFORATION DETAIL
Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status
Kup. A
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20" Conductor 91.1 / H-40 / N/A N/A Surface 114'
9-5/8" Surface 40 / L-80 / Btrc. 8.835 Surface 8,649’
7" Production 26 / L-80 / NSCC 6.276 Surface 12,717’
3-1/2” Liner 9.3 / 13Cr85 / STL 2.992 12,175’ 12,290’
3-1/4” Liner 6.6 / 13Cr85 / TCII 2.805 12,290’ 12,600’
2-7/8” Liner 6.5 / 13Cr85 / Hyd 511 2.441 12,600’ 14,944’
TUBING DETAIL
4-1/2” Tubing 12.6/L-80/TXP 3.958 Surface ±12,170’
JEWELRY DETAIL
No Depth Item
1 ±12,000’ 3.813” X Sliding Sleeve
2 ±12,050’ 7” x 4-1/2” Packer
3 ±12,160’ 3.813” X Nipple
4 ±12,168’ Wireline entry guide – Btm @ ±12,170’
5 12,295’ Whipstock (pinch point = 12,297’)
6 12,290’ 3-1/2” xo 3-1/4”
7 12,600’ 3-1/4” xo 2-7/8”
OPEN HOLE / CEMENT DETAIL
42" 250 sx of Arcticset I (Approx)
12-1/4" 2,199 sx PF E, 550 sx Class G
8-1/2” 275 sx Class G
4-1/4” 172 sx Class G
WELL INCLINATION DETAIL
KOP @ 12,297’
90 deg Hole Angle = 12,540’
TREE & WELLHEAD
Tree 5M Cameron 2-9/16”
Wellhead FMC 11”x 11” 5M Gen 5 w/ 11” x 2-7/8” FMC Tbg. Hngr. w/ 3” LH
Acme top and 2-7/8” EUE-8rd bottom and 2.5” CIW H BPV Profile
TD = 14,944’ (MD) / TD = 7,125’(TVD)
20”
KB Elev.: 51.42’, GL Elev.: 17.1’
7”
2
4
9-5/8”
1
2-7/8”
3-1/4” xo
2-7/8”
12,600’
5
3 Top of
Cement /
Liner @
12,145’
Whipstock set
@ 12,295’,
Top of Window
@ 12,297’
3-1/2” xo
3-1/4”
12,290’
PB1: TBD
PBTD = 14,924’ (MD) / PBTD = 7,125’(TVD)
6
7
!
68006850690069507000705071007150720072507300True Vertical Depth (100 usft/in)-125 0 125 250 375 500 625 750 875 1000 1125 1250 1375 1500 1625 1750 1875 2000 2125 2250Vertical Section at 14.08° (250 usft/in)MPU L-39B wp05 tgt1MPU L-39B wp05 Polygon12500MPL-391 2 5 0 0
MPL-39A wp052-7/8" x 4-1/2"1 2 5 0 01300013500140001450014944MPL-39B wp05Start Dir 30º/100' : 12450' MD, 7095.5'TVD : 45° RT TFStart Dir 12º/100' : 12892.93' MD, 7112.11'TVDTotal Depth : 14944' MD, 7124.59' TVDHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: MPL-39Ground Level: 17.10+N/-S +E/-W Northing EastingLatitudeLongitude0.00 0.00 6031523.14 544743.4670° 29' 49.1728 N149° 38' 2.8110 WSURVEY PROGRAMDate: 2023-04-10T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool50.00 10000.00 SDI Gyro (MPL-39) 3_Gyro-CT_Drill pipe10038.40 12297.00 Original MWD surveys below SDI Gyro Run (MPL-39) 3_MWD12297.00 12450.00 MPL-39A wp05 (Plan: MPL-39A) 3_MWD12450.00 14944.00 MPL-39B wp05 (Plan: MPL-39B) 3_MWDFORMATION TOP DETAILSNo formation data is availableREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well MPL-39, True NorthVertical (TVD) Reference:51.42 RKB @ 51.42usft (51.42 RKB)Measured Depth Reference:51.42 RKB @ 51.42usft (51.42 RKB)Calculation Method:Minimum CurvatureProject:Milne PointSite:M Pt L PadWell:MPL-39Wellbore:Plan: MPL-39BDesign:MPL-39B wp05CASING DETAILSTVD TVDSS MD Size Name7124.60 7073.18 14944.00 2-7/8 2-7/8" x 4-1/2"SECTION DETAILSSecMD Inc Azi TVD +N/-S +E/-W Dleg TFace VSectTargetAnnotation1 12450.00 69.49 233.97 7095.50 -5043.43 -7229.46 0.00 0.00 0.00 Start Dir 30º/100' : 12450' MD, 7095.5'TVD : 45° RT TF2 12542.95 90.00 253.28 7112.12 -5083.19 -7310.79 30.00 45.00 -58.363 12892.95 90.00 358.28 7112.12 -4906.01 -7556.63 30.00 90.00 53.67Start Dir 12º/100' : 12892.93' MD, 7112.11'TVD4 13242.95 89.83 40.28 7112.65 -4582.99 -7443.63 12.00 90.25 394.485 13467.95 89.62 13.28 7113.74 -4383.98 -7343.19 12.00 -90.50 611.95613692.95 89.55 40.28 7115.39 -4184.97 -7242.75 12.00 90.25 829.427 13942.95 89.49 10.28 7117.54 -3961.50 -7137.20 12.00 -90.25 1071.868 14167.95 89.54 37.28 7119.48 -3757.51 -7047.31 12.00 90.00 1291.599 14417.95 89.60 7.28 7121.39 -3528.82 -6953.61 12.00 -90.00 1536.2110 14667.95 89.66 37.28 7123.04 -3300.12 -6859.90 12.00 90.00 1780.841114917.95 89.70 7.28 7124.47 -3071.42 -6766.20 12.00 -90.00 2025.461214944.00 89.70 10.41 7124.60 -3045.69 -6762.19 12.00 90.00 2051.40 Total Depth : 14944' MD, 7124.59' TVD
-5250
-5075
-4900
-4725
-4550
-4375
-4200
-4025
-3850
-3675
-3500
-3325
-3150
-2975
-2800
-2625
South(-)/North(+) (350 usft/in)-8400 -8225 -8050 -7875 -7700 -7525 -7350 -7175 -7000 -6825 -6650 -6475 -6300 -6125 -5950
West(-)/East(+) (350 usft/in)
MPU L-39B wp05 Polygon
MPU L-39B wp05 tgt2
MPU L-39B wp05 tgt1
MP
L-
3
9MPL-39A wp052-7/8" x 4-1/2"
4
7
5
0
5
0
0
0
5
2
50
5
5
0
0
5
7
5
0
6
0
0
0
6
2
5
0
6
5
0
0
675
07
0
0
0
7125
MPL-39B wp05
Start Dir 30º/100' : 12450' MD, 7095.5'TVD : 45° RT TF
Start Dir 12º/100' : 12892.93' MD, 7112.11'TVD
Total Depth : 14944' MD, 7124.59' TVD
CASING DETAILS
TVD TVDSS MD Size Name
7124.60 7073.18 14944.00 2-7/8 2-7/8" x 4-1/2"
Project: Milne Point
Site: M Pt L Pad
Well: MPL-39
Wellbore: Plan: MPL-39B
Plan: MPL-39B wp05
WELL DETAILS: MPL-39
Ground Level: 17.10
+N/-S +E/-W Northing Easting Latitude Longitude
0.00 0.00 6031523.14 544743.46 70° 29' 49.1728 N 149° 38' 2.8110 W
REFERENCE INFORMATION
Co-ordinate (N/E) Reference:Well MPL-39, True North
Vertical (TVD) Reference:51.42 RKB @ 51.42usft (51.42 RKB)
Measured Depth Reference:51.42 RKB @ 51.42usft (51.42 RKB)
Calculation Method:Minimum Curvature
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0.001.002.003.004.00Separation Factor12450 12600 12750 12900 13050 13200 13350 13500 13650 13800 13950 14100 14250 14400 14550 14700 14850 15000 15150 15300Measured Depth (300 usft/in)MPL-39A wp05No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:MPL-39 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 17.10+N/-S +E/-W Northing EastingLatitudeLongitude0.000.006031523.14 544743.46 70° 29' 49.1728 N149° 38' 2.8110 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well MPL-39, True NorthVertical (TVD) Reference:51.42 RKB @ 51.42usft (51.42 RKB)Measured Depth Reference:51.42 RKB @ 51.42usft (51.42 RKB)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2023-04-10T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool50.00 10000.00 SDI Gyro (MPL-39) 3_Gyro-CT_Drill pipe10038.40 12297.00 Original MWD surveys below SDI Gyro Run (MPL-39) 3_MWD12297.00 12450.00 MPL-39A wp05 (Plan: MPL-39A) 3_MWD12450.00 14944.00 MPL-39B wp05 (Plan: MPL-39B) 3_MWD0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)12450 12600 12750 12900 13050 13200 13350 13500 13650 13800 13950 14100 14250 14400 14550 14700 14850 15000 15150 15300Measured Depth (300 usft/in)MPL-39NO GLOBAL FILTER: Using user defined selection & filtering criteria12450.00 To 14944.00Project: Milne PointSite: M Pt L PadWell: MPL-39Wellbore: Plan: MPL-39BPlan: MPL-39B wp05CASING DETAILSTVD TVDSS MD Size Name7124.60 7073.18 14944.00 2-7/8 2-7/8" x 4-1/2"
Revised 7/2022
TRANSMITTAL LETTER CHECKLIST
WELL NAME:______________________________________
PTD:_____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD:__________________________POOL:____________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
Number _____________, API Number 50-______________________.
Production from or injection into this wellbore must be reported under
the original API Number stated above.
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce or inject is contingent upon issuance of a
conservation order approving a spacing exception. The Operator
assumes the liability of any protest to the spacing exception that may
occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in nogreater
than 30-foot sample intervals from below the permafrost or from where
samples are first caught and 10-foot sample intervals through target
zones.
Non-
Conventional
Well
Please note the following special condition of this permit: Production or
production testing of coal bed methane is not allowed for this well until
after the Operator has designed and implemented a water-well testing
program to provide baseline data on water quality and quantity. The
Operator must contact the AOGCC to obtain advance approval of such
a water-well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by the Operator in the attached application, the following well logs are
also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for all well logs run must be submitted to the AOGCC
within 90 days after completion, suspension, or abandonment of this
well, or within 90 days of acquisition of the data, whichever occurs first.
KUPARUK RIVER OIL
MPU L-39B
223-037
MILNE POINT
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:MILNE PT UNIT L-39BInitial Class/TypeDEV / PENDGeoArea890Unit11328On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2230370MILNE POINT, KUPARUK RIVER OIL - 525100NA1 Permit fee attachedYes Surface Location lies within ADL0025509; Portion of Well Passes Thru ADL0025515;2 Lease number appropriateYes Top Productive Interval lies in ADL0025514; TD lies in ADL0388235.3 Unique well name and numberYes4 Well located in a defined poolYes MILNE POINT, KUPARUK RIVER OIL - 525100, governed by CO 432E.5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes This well is a CTD inzone sidetrack from an existing wellbore.18 Conductor string providedYes This well is a CTD inzone sidetrack from an existing wellbore.19 Surface casing protects all known USDWsYes This well is a CTD inzone sidetrack from an existing wellbore.20 CMT vol adequate to circulate on conductor & surf csgYes This well is a CTD inzone sidetrack from an existing wellbore.21 CMT vol adequate to tie-in long string to surf csgYes All production liner x OH annuli to be fully cemented to confining zones.22 CMT will cover all known productive horizonsYes This well is a CTD inzone sidetrack from an existing wellbore.23 Casing designs adequate for C, T, B & permafrostYes CDR2 has adequate tankage and good trucking support.24 Adequate tankage or reserve pitYes See sundry 323-29925 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan shows no collision risks.26 Adequate wellbore separation proposedNA This well is a CTD inzone sidetrack from an existing wellbore.27 If diverter required, does it meet regulationsYes MPD to be utilized to maintain overbalance during drilling. Heavier liner running fluids for liner deployment28 Drilling fluid program schematic & equip list adequateYes 1 CT packoff, 1 annular, 4 ram coiled tubing stack29 BOPEs, do they meet regulationYes 5M coiled tubing drilling stack tested to 3500 psi.30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownYes MPU L Pad is an H2S pad. Personal monitoring and rig monitoring to be in place.33 Is presence of H2S gas probableNA This well is a producer.34 Mechanical condition of wells within AOR verified (For service well only)No H2S: high risk; H2S measures required; see p. 5.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected Pressure Range is 0.55 psi/ft (10.5 ppg EMW). Operator's planned mud program with MPD36 Data presented on potential overpressure zonesNA appears sufficient to control anticipated pressures and maintain wellbore stability.37 Seismic analysis of shallow gas zonesNA will be used to mitigate wellbore instability and any over-pressure encountered.38 Seabed condition survey (if off-shore)NA Medium lost circulation risk; 1.5 wellbore volumes of kill-weight fluid will be available. (See p.4-5.)39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate5/27/2023ApprMGRDate6/1/2023ApprSFDDate5/27/2023AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateGCW 06/02/23JLC 6/2/2023
