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HomeMy WebLinkAbout219-082Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 5/29/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250529
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
BCU 19RD 50133205790100 219188 5/10/2025 AK E-LINE GPT/CIBP/Perf
HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL
IRU 241-01 50283201840000 221076 5/7/2025 AK E-LINE Plug/Perf
KBU 22-06Y 50133206500000 215044 5/6/2025 AK E-LINE Perf
KBU 22-06Y 50133206500000 215044 5/7/2025 AK E-LINE Perf
KBU 24-06RD 50133204990100 206013 4/8/2025 YELLOWJACKET GPT-PLUG
MPI 1-61 50029225200000 194142 5/10/2025 AK E-LINE Perf
MPU E-42 50029236350000 219082 5/3/2025 AK E-LINE Patch
MPU S-55 50029238130000 225006 5/13/2025 AK E-LINE CBL
OP16-03 50029234420000 211017 4/25/2025 READ LeakDetect
PAXTON 13 50133207330000 225021 4/29/2025 YELLOWJACKET SCBL
PBU 01-12B 50029202690200 223090 4/8/2025 HALLIBURTON RBT
PBU D-08B 50029203720200 225007 3/22/2025 BAKER MRPM
PBU H-17B
(REVISION)50029208620100 197152 4/10/2025 HALLIBURTON RBT-COILFLAG
PBU J-25B 50029217410200 224134 3/10/2025 BAKER MRPM
PBU K-19C
(REVISION)50029225310300 224004 3/27/2025 BAKER MRPM
PBU K-19C 50029225310300 224004 3/27/2025 HALLIBURTON RBT
SRU 241-33B 50133206960000 221053 3/12/2025 YELLOWJACKET PERF
Revision Explanation: Both wells had wrong side stack well name and API#/PTD on previous upload
H-17b was marked as H-17A and K-19C was marked as K-19B. Well name now reflets correct
sidetrack and has correct SPI# and PTD.
T40489
T40490
T40491
T40492
T40492
T40493
T40494
T40495
T40496
T40497
T40498
T40499
T40500
T40501
T40502
T40503
T40503
T40504
MPU E-42 50029236350000 219082 5/3/2025 AK E-LINE Patch
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.05.29 14:33:01 -08'00'
Nolan Vlahovich Hilcorp Alaska, LLC
Geotech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 564-4558
E-mail: nolan.vlahovich@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal.
Received By: Date:
Date: 3/18/2025
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
SFTP DATA TRANSMITTAL T#20250318
Well API #PTD #Log Date Log
Company Log Type AOGCC
E-Set#
AN-51 50733204640000 195004 3/1/2025 READ CAliperSurvey
AN-51 50733204640000 195004 3/1/2025 READ CaliperSurvey/SBHPS
BCU 18RD 50133205840100 222033 2/25/2025 AK E-LINE Perf
BCU 18RD 50133205840100 222033 2/26/2025 AK E-LINE Plug/Perf
BRU 212-26 50283201820000 220058 2/28/2025 AK E-LINE PT Survey
BRU 221-26 50283202010000 224098 2/27/2025 AK E-LINE PPROF
BRU 241-34S 50283201980000 224077 3/1/2025 AK E-LINE PPROF
IRU 11-06 50283201300000 208184 2/26/2025 AK E-LINE DepthDetermination
IRU 11-06 50283201300000 208184 3/8/2025 AK E-LINE PlugSetting
MPU E-42 50029236350000 219082 2/22/2025 AK E-LINE Caliper
MRU A-12RD 50733200760100 171029 3/7/2025 AK E-LINE Correlation
MRU A-13 (REVISED)50733200770000 168002 2/6/2025 AK E-LINE TubingPunch
MRU M-32RD2 50733204620200 217091 3/4/2025 AK E-LINE Correlation
PBU 13-24B 50029207390200 224087 1/4/2025 HALLIBURTON RBT
PBU 16-24A 50029215360100 224158 2/23/2025 HALLIBURTON RBT-COILFLAG
PBU F-21 50029219490000 189056 2/25/2025 READ CaliperSurvey
SD37-DSP01 50629234510000 211089 2/28/2025 HALLIBURTON WFL-TMD3D
Revision explanation: Fixed API# on log and .las files
Please include current contact information if different from above.
T40221
T40221
T40222
T40222
T40223
T40224
T40225
T40226
T40226
T40227
T40228
T40229
T40230
T40231
T40232
T40233
T40234
MPU E-42 50029236350000 219082 2/22/2025 AK E-LINE Caliper
Gavin Gluyas Digitally signed by Gavin Gluyas
Date: 2025.03.18 15:55:41 -08'00'
Samuel Gebert Hilcorp Alaska, LLC
GeoTech Assistant 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
Fax: 907 777-8510
E-mail: sam.gebert@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510
Received By: Date:
DATE: 10/15/2020
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
MPU E-42 (PTD 219-082)
Production Profile 06/01/2020
ANALYSIS
FIELD DATA
Please include current contact information if different from above.
Received by the AOGCC 10/15/2020
PTD: 2190820
E-Set: 34101
Abby Bell 10/15/2020
1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown
Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program
Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Convert to Jet Pump
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 11,960 feet N/A feet
true vertical 4,300 feet N/A feet
Effective Depth measured 11,945 feet 7,761 & 7,852 feet
true vertical 4,195 feet 4,285 & 4,300 feet
Perforation depth Measured depth See Schematic feet
True Vertical depth See Schematic feet
Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6 / L-80 / Hyd 521 7,781' 4,288'
Packers and SSSV (type, measured and true vertical depth)SLXP & MLZXP 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
13.
Prior to well operation:
Subsequent to operation:
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:
Chad Helgeson
Contact Name:
Authorized Title:Operations Manager
Contact Email:
Contact Phone:
TVD
107'
Oil-Bbl
measured
true vertical
Packer
11,960'
WINJ WAG
170
Water-Bbl
MD
107'
measured
3800 Centerpoint Dr, Suite 1400
Anchorage, AK 99503
3. Address:
4. Well Class Before Work:
249
Representative Daily Average Production or Injection Data
1851,102
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
REPORT OF SUNDRY WELL OPERATIONS
219-082
50-029-23635-00-00
Plugs
ADL0028231 & ADL0380110
5. Permit to Drill Number:
MILNE POINT / SCHRADER BLUFF OIL
17. I hereby certify that the foregoing is true and correct to the best of my knowledge.
319-473
219
Authorized Signature with date:
Authorized Name:
Stan Porhola
sporhola@hilcorp.com
1,684 2,386
MILNE PT UNIT E-42
14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283)
228
Gas-Mcf
200
Casing Pressure Tubing Pressure
60
N/A
measured
4,108'
N/A
Liner
Casing
Conductor
Size
Junk
Length
107'
8,311'
7,769'
Surface
Intermediate
20"
9-5/8"
7-5/8"
4-1/2"
4,355'
4,285'
4,194'
8,311'
7,769'
8,540psi
Burst
N/A
5,750psi
6,890psi
9,020psi
777-8412
Hilcorp Alaska LLC
2. Operator Name
Senior Engineer: Senior Res. Engineer:
Collapse
N/A
3,090psi
4,790psi
PL
G
Form 10-404 Revised 3/2020 Submit Within 30 days of Operations
Chad A Helgeson
2020.04.24
13:08:35 -05'00'
By Samantha Carlisle at 10:25 am, Apr 24, 2020
SFD 4/24/2020
4,194
SFD 4/24/2020
11,969
DSR-4/27/2020
RBDMS HEW 4/24/2020
Pull Tubing
gls 4/29/20
Convert to Jet Pump
_____________________________________________________________________________________
Revised By: STP 4/06/2020
Schematic
Milne Point Unit
Well: MPU E-42 & L1
Last Completed: 3/30/2020
PTD: 219-082 & 219-091
22
23
20
21
TD =11,950’(MD) / TD =4,223’(TVD)
9-5/8”
7
6
8
9
16
20”
2
4
13
17
19
“OA” Lateral
PBTD =11,945’(MD)/ PBTD =4,223’(TVD)
“OB” Lateral
10
11
Orig. KB Elev.: 48.4’/ Orig. GL Elev.: 21.5’
RKB-THF: 23.87’ (Innovation#1)
12
12
14
13
15
Min ID = 3.813”
7-5/8”
3
Tecwire
3/8”5
1
18
Min ID = 3.563”
Min ID = 3.688”
13C Jet Pump
Set 4/04/2020
FISH:
¼” Nubbin
Lost 4/04/2020
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
20" Conductor 215 / X-42 / Welded N/A Surface 107'
9-5/8” Surface 40 / L-80 / TXP 8.835 Surface 8,311’
7-5/8" Tieback 29.7 / L-80 / Hyd 521 6.875 Surface 7,769'
4-1/2”
Liner “OA”
Predrilled w/
76 holes/ft
13.5 / L-80 / Hyd 625 3.920 7,795’ 11,852’
4-1/2”
Liner “OB”
Predrilled w/
76 holes/ft
13.5 / L-80 / Hyd 625 3.920 7,852’ 11,960’
TUBING DETAIL
4-1/2” Tubing 12.6 / L-80 / Hyd 521 3.958 Surface 7,781’
JEWELRY DETAIL
No Top MD Item
GLM’s: KBG-4-5 4-1/2” w/ 1” valves w/ BK Latch
1 23.78’ Tubing Hanger: 4-1/2" FMC, TC 1A (4-1/2” TC-II Top x Btm) w/ Blast Jt
2 2,970’STA 3: GLM w/ dummy valve (Set 4/04/20)
3 5,013’STA 2: GLM w/ dummy valve (Set 3/30/20)
4 6,618’STA 1: GLM w/ dummy valve (Set 3/30/20)
5 6,682’ 4-1/2" Baker Hughes Discharge Gauge (Tubing Read)
6 6,693’
4-1/2” XD Sliding Sleeve (Min ID=3.813) [OPEN] (13C Jet Pump
SN#: HC-00023 set 4/04/20)
7 6,703’ 4-1/2" Baker Hughes Suction Gauge (Tubing Read)
8 6,716’ 4-1/2” X Nipple (Min ID=3.813)
9 6,777’ 7-5/8” x 4-1/2” HES TNT Permanent Packer
10 6,802’ 4-1/2” X Nipple (Min ID=3.813)
11 7,740’ 4-1/2” Joint & WLEG (5.20” OD) Btm @ 7,781’ (Buried inside SLZXP)
12 7,770’ 7-5/8” Tieback Seal Assembly (ID=6.190”; Drift = 6.151”); SO 1’ above TOL
13 7,761’ 7”x9-5/8” SLZXP Liner Top Packer (ID=6.200”) TOL
14 7,795’ OA Lateral LEM #1 (Lateral Entry Module) (ID=3.720”; Drift = 3.640”)
15 7,795’ 7”x9-5/8” RAM Hanger (Lateral Drift ID=5.960”) (Mainbore Drift ID=3.688”)
16 7,799’ 4-1/2”x9-5/8” RAM Sealbore Diverter (SBD) (Sealbore ID=3.688”)
17 7,846’ OSDB-6 Nipple Profile (Min ID = 3.563”)
18 7,852’ 7”x9-5/8” MLZXP Liner Hanger Packer w/ Sealbore Receptacle (ID=4.750”) TOL
19 7,884’ Bottom of locator seal assembly (ID=3.875”)
20 11,813’ OA Lateral 4-1/2” Solid Joint
21 11,850’ OA Lateral 4-1/2” Round Nose Shoe Btm @ 11,852’
22 11,927’ OB Lateral 4-1/2” Drillable Packoff Sub
23 11,959’ OB Lateral 4-1/2” WIV Valve LTC BXB (1” Ball on Seat/Closed)
OPEN HOLE / CEMENT DETAIL
20" ~270 ft3 of Arcticset I cmt in 42” Hole
9-5/8" Stg 1 L – 798 sx / T – 400 sx
Stg 2 L - 550 sx/ T – 270 sx
WELL INCLINATION DETAIL
KOP @ 350’ MD
Max Wellbore Angle = 92.4 deg @ 8,386’ MD
Hole Angle @ Sliding Sleeve = 63° @ 6,693’ MD
Hole Angle @ Lower X Profile = 70° @ 6,802’ MD
WELLHEAD
Tree 4-1/16” Cameron, 5M
Wellhead FMC Gen 5 11” x 11” 5M Tubing Spool, 4-1/2” TC-II Top
& Btm Threads w/ 4.0 “H” BPV Profile
GENERAL WELL INFO
API: 50-029-23635-00-00 & 50-029-23635-60-00
Drilled and Completed by Innovation Rig – 7/8/19
Convert to Jet Pump by ASR #1 – 3/30/20
LATERAL WINDOW DETAIL
Top of “OA” Window @ 7,805’ MD; Bottom @ 7,822’ MD; Angle @ top of window is 79 deg
Jet pump set.
Well Name Rig API Number Well Permit Number Start Date End Date
MP E-42 ASR#1 50-029-23635-00-00 219-082 3/19/2020 3/30/2020
3/20/2020 - Friday
NContinue rigging up ASR - installing spools and flowline on top of BOP, connecting back-up 300kw generator, Installing stairs
to rig floor,. Witness waived by Jeff Jones for BOP test. Continue to MIRU, complete spotting catwalk, connecting jumper
lines and final winterization. Clear snow and install pipe sheds. Start BOP Testing, Test with 2-2/8" and 4-1/2" test mandrel.
Test 2-7/8" x 5" VBR Pipe rams, Blinds, All choke and kill valves, and Annular for a 250 low pressure test and 2500psi high
pressure test as per Sundry. Tested all LEL and Gas detectors. Safety Meeting with evening crew. Conduct Sundry discussion
for well E-42. Strong winds and blowing snow, Milne Point in Phase 2. Weather hold due to strong winds, blinding snow. Stop
crew from rigging up Sheave for spooling the cable as it is pulled out of hole. Move pipe shed into place, rig up heaters, flag
off hazards. Water truck is delayed due to pumping operation on another well site. Rig status questionable due to error code
on rig computer - VMS called out for repair (will take ~3 hrs to shut down and re-load program into computer). Field still in
Phase 2, winds slowed to 18 mph but visibility poor. Fluid on location, fill pits. Computer download paused while rig coolant
temps continue to cool off (software cannot be loaded until engine temps are lowered). Rig operational. Rig up equipment
for spooling operation. Check IA, slight pressure, bleed and immediately fell off. Circ 20 bbls down backside. 0psi. Pull BPV,
well on vac. Install landing joint with TIW, circ down tubing volume at 3 bpm. Back out lockdown screws, pull hanger to floor.
3/18/2020 - Wednesday
Hilcorp Alaska, LLC
Weekly Operations Summary
No operations to report.
3/19/2020 - Thursday
Start Well Kill. Casingpsi = 1120, tbgpsi = 950. Bleed tubing and casing to zeropsi. Pump 60 bbls 8.3ppg P/W down tubing @ 5
bpm @ 0psi. Swap and pump 450 bls 8.3ppg P/W down backside @ 5 bpm @ 0psi. Swap and pump 50 bbls 8.3ppg P/W
down tubing @ 5bpm and 0psi. Install BPV - RDMO Little Red. Continue MIRU ASR, Install Well hut, N/D tree, and start N/U
BOP. Continue moving equipment to E pad and staging equipment with Roads and Pads trucks and equipment. Conduct pre-
tour safety meeting with crew, crew swap out. Complete BOP NU. Use crane to move in wellhouse and rig floor. Continue to
move in and stage equipment on E-42, move in rig and raise Derrick. Hang Sheave for spooler, install Derrick pins. Stage in
pits, take on fresh water for BOP test.
Morning Safety Meeting, Daily Plan forward, fluid checks on all equipment. Continue to POOH w/ 2-7/8" 6.5# EUE tubing
while threading rope to spooler for ESP cable. Pumping double displacement or 5bbls 8.3ppg source water every 20-30 mins
while pulling slowly and threading lines to spooler. 30 joints out of hole @ 0800 hours. POOH w/ 2-7/8" 6.5# EUE tubing.
Unclamping and Spooling old cable and cap line Pumping 10bbls 8.3ppg source water every 20-30 mins while pulling out of
hole. 105 joints out of hole @ 1200 hours. POOH w/ 2-7/8" 6.5# EUE tubing. Unclamping and Spooling old cable and cap line
Pumping 10bbls 8.3ppg source water every 20-30 mins while pulling out of hole. 215 joints out of hole @ 1700 hours. POOH
w/ 2-7/8" 6.5# EUE tubing. Unclamping and Spooling old cable and cap line Pumping 10bbls 8.3ppg source water every 20-30
mins while pulling out of hole. Conduct safety meeting with night crew, crew swap out. POH with 2-7/8" tubing. Pick up and
break out pup below GLM. As assembly was being picked up out of stump for lowering to ground, crew noticed ESP cable
unspooling at rapid rate. Looked to hole, tubing stump gone. Make notifications of fishing job. 4 joints of 2-7/8" tubing, XN
assembly, ESP pump assembly with approximately 1,000' of 1-1/4" ESP cable above gone downhole. Inspect rig components
and spooler equipment while making notifications and discussing plan forward. Take statements, send initial report to ODE
and Operations Superintendent. Mobilize fishing equipment from Deadhorse. Look for and find 4-3/4" slip and bowl
assembly for fishing equipment. Pump down 25 bbls of 8.3 ppg source water per hour. Fishing rep on location, discuss fish
downhole and develop fishing BHA. Mobilize fishing equipment to rig floor. MU fishing BHA: Rope spear with 6-5/8" stop
ring, Bumper sub, Hydraulic Jars made up to 2-7/8" tubing. Pump down 25 bbls 8.3 ppg source water per hour. RIH with
fishing BHA on 2-7/8" tubing.
3/21/2020 - Saturday
Start Well Kill. C
Start BOP Testing, Test with 2-2/8" and 4-1/2" test mandrel.
NContinue rigging up ASR -
Back out lockdown screws, pull hanger to floor.Pull ESP
Well Name Rig API Number Well Permit Number Start Date End Date
MP E-42 ASR#1 50-029-23635-00-00 219-082 3/19/2020 3/30/2020
Hilcorp Alaska, LLC
Weekly Operations Summary
3/22/2020 - Sunday
Morning Safety Meeting, Daily plan Forward, Fluid Checks on all equipment. Continue to RIH w/ fishing BHA and set down @
740' with 5 foot in on joint # 24 - pick up 5' and set back down to stack out. Pick up weight of free pipe = 4K up. Pull up easy
and find 4000# over pull, pull 3 joints slowly and weight fall off. RIH w/ 3 joints to fish @ 740' - continue pumping 15 bbls per
hour into well of 8.3ppg source water. Stack out on fish and put ten turns in pipe noting torque of 1,500 ft/lbs then fall off
and pick up of +12,000lbs. Pull up slowly 15' and weight fall off to +2,000lbs. POOH and find 50' cable tangled onto fishing
spear/grab. Installl 4' 2-7/8 EUE 6.5# L-80 pup joint on top of fishing BHA to allow full removal of fishing BHA from well w/out
swapping handling gear. RIH w/ fishing BHA. RIH w/ fishing BHA to joint 5' in on 25 and tag up. Set down and put 1 turn to
right in string, pick up 6.3K up and set down with 1 more turn to right. Pull up and 10.5K on the hook. Pull up slowly and
reach 12K up. Lose weight but have aprrox 1K still on hook, POOH. POOH continuing to see +/- 1K weight on fishing tool. Pull
to surface and find 25' of ESP Cable, continues to be single strand. Inspect fishing spear and RIH. Continue to RIH w/ 2-7/8'
EUE 6.5# tubing and fishing BHA. RIH to 20' in on joint 25 (770'), set down 1.5K and make turns to right. Pull up to 8k and set
back down to 1.5K down and make 2 turns to right , pull up slowly holding 12.5K in upweight. (Free pipe 6.3K up). Weight fell
off as wire parted, pull out of hole to inspect. POOH w/ fishing BHA on 2-7/8" EUE 6.5# tubing. - fish on surface. Single strand
17.5 feet long. Shut blinds and pup 25 bbls 8.3 ppg source water. Crew meeting. Fill well with 15 bbls 8.3 ppg fluid. Crew
meeting via conference call with Rig Manager, IWS Owner, all Co Reps to discuss current safety concerns and to get feedback
on mitigation measures and how to move forward as a team. Crew changeout, check fluids and equipment. Fill well with 25
bbls 8.3 ppg fluid. Swap out 2-7/8" tubing - joints that had made 3 roundtrips were showing indications of thread wear. Pull
25 joints out of shed and set aside. RIH with wire spear fishing assembly on 2-7/8" workstring. Fill well with 25 bbls 8.3 ppg
source water every hour. Dies on tongs losing bite. Swap out to new dies. Take on fluids, fill well. RIH with fishing BHA to 22 '
in on joint 26, ~818', and take weight. PUW before tag 6k. Set down 2k, rotate string to engage fish, breakover with PUW a
13k, 6k over initial PUW. Continue to pick up and cable parted, PUW now 7.2k. Pull out of hole with the workstring and cable.
Retrieve 22' of ESP cable. RIH with Fishing BHA on 2-7/8" workstring. Tag wire and set down 1.5K. Put 10 turns in fishing tool
to the right. then pull up to 8K up weight, set back down and then 5 turns to right. Pull up to 13K and see wire part, POOH w/
2-7/8" work-string and fishing BHA.
. RIH with fishing BHA to 22'
in on joint 26, ~818', and take weight. PUW before tag 6k. Set down 2k,
Fish ESP
Well Name Rig API Number Well Permit Number Start Date End Date
MP E-42 ASR#1 50-029-23635-00-00 219-082 3/19/2020 3/30/2020
Hilcorp Alaska, LLC
Weekly Operations Summary
Morning Safety meeting and daily plan forward. Fluid checks on all equipment. Continue to POOH w/ 2-7/8" EUE work-string
and fishing BHA. Pull to surface and find 26' of ESP cable. Remove cable from fishing tool and RIH. Continue to RIH w/ fishing
BHA on 2-7/8" 6.5# L-80 EUE tubing. - find top of wire At 820' push down 20 feet to 1.5K down weight. (free pipe = 6K
up.)and put 20 turns to right in BHA, lower 10 more ' and 2 more turns. Pull up to 10.5K up and hear wire part in pipe. POOH.
POOH to surface, necessary to swap out 2-7/8 EUE 6.5# L-80 work-string with new pipe of same specs and tally. Swap out 2-
7/8" EUE to 3-1/2 IF X-over with 2-7/8 EUE x 2-7/8 PH-6 and 2-7/8 PH-6 to 3 -1/2 IF X-overs. 16.5' of cable on fishing tool.
Shut blinds and monitor well for crew to eat lunch. Monitor well and crew eat lunch. Pump 40 bbls 8.3 ppg source water into
well- well on vac. Start RIH with fishing assembly on replacement 2-7/8" EUE 6.5# L-80 tubing. Tag Fish @ 861'. Set down
from 6.0 free weight to 3.0 down weight. Make 4 turns, Set back down to 3.0K down and make 2 turns, pull up and fish
moving at 8.7K up weight for 30 feet, keep pulling slowly and ESP parted. POOH to inspect. POOH 1.5 K heavy, (7.5K up
weight) - get to surface with 27' ESP cable. (total pulled so far- 184') RIH w/ fishing BHA on 2-7/8 EUE 6.5# L-80 tubing.
Continue to RIH w/ fishing BHA and 2-7/8 EUE tubing. Tag up with joint 29. PUW 6.2k, move down until taking weight to 912'.
Place 5 wraps, move down to 922', 5 more wraps and pick up. Continue to pick up until cable parts, parted at 15k PUW. POH.
Pull to surface, retain 47' of ESP cable, no capillary line. Total of 231' feet recovered after 8 runs. Change out 2-7/8"
workstring due to thread wear. Strap 42 joints of tubing. RIH with run #9 of Wire Rope Spear fishing BHA on 2-7/8" tubing.
Hydraulic hose on Tongs burst while making up joint 25 (immediate response, all fluid into containment). Conduct well
control drill and stab TIW. Fill down backside with 8.3 ppg source water. Change out hydraulic hose - bad position, have to
remove all other hoses first and then go to warehouse to make new hose. RIH with run #9 of Wire Rope Spear fishing BHA on
2-7/8" tubing., MU joint 25. Take weight at joint 928', Tag up with joint 31. PUW 6.2k, move down until taking weight to 928'
and set down to 950'. Place 6 wraps, move down to 960', 5 more wraps and pick up. Continue to pick up until cable parts,
parted at 15k PUW. POH. POH with Wire Rope Spear BHA run #9. At surface, ESP cable and Capillary Tubing is hanging off of
Wire Rope Spear vertically and very heavy. Install false bowl, make up clamps to secure and use for lifting. Use clamps to
secure and lift cable out. 31' of Capillary Tubing retrieved. 277' feet of ESP cable retrieved as of 0600 hrs for total off 508'
(job total).
3/23/2020 - Monday
Well Name Rig API Number Well Permit Number Start Date End Date
MP E-42 ASR#1 50-029-23635-00-00 219-082 3/19/2020 3/30/2020
Hilcorp Alaska, LLC
Weekly Operations Summary
Morning Safety Meeting, Daily Plan Forward, fluid checks on all equipment. Check well, pump 10 bbls 8.3ppg source water
down, well static. Start RIH w/ fishing spear/grab run 10 on 2-7/8" 6.5# EUE tubing. Tag fish @ 1,020' with free pipe weight of
6.0 down. set down 1.5K and able to hear fish on pipe. Make 4turns to right and pull up 15 feet - lower back down making 4
turns as lowering pipe. P/U and weight show 1.5K heavy. POH and lose 500# at welll head. NO fish on spear. RIH for run #11.
Continue to RIH with multi angle fishing spear BHA run #11 on 2-7/8" 6.5# EUE tubing - Pumping 10-15 bbls per hour hour of
8.3ppg Source water. - Well static. RIH and tag fish @ 1,040', keep working down @ 2K down (free down weight 6.1), work
down to 1090' putting 4-5 turns every 10' with 2K down with torque of 600 ft/lbs (free torqe = 250), @ 1,090' put in 3 turns
@ 600ft/lbs and POOH. Appears fish may be pushing down. POOH w/ fish and pulling 2K above free up weight of 7.1K. -
pulling 8.9-9K. POOH and find substantial amount of capstring. - estimate 120-150 feet. Call town and decision made to make
another run w/ multi-angle grab and potentially LIB depending on findings of next run. Start RIH run #12 w/ 2-7/8" 6.5# eue
tubing and multi-angle grab to attempt to catch more capstring. Continue pumping 15 bbls per hour into well. Well static.
Safety Meeting wth evening crew. Discuss plan forward, contingency for the Phase 2 weather and incoming winds tonight
and tomorrow. Crew change, check fluid levels. RIH run #12 w/ 2-7/8" 6.5# EUE tubing and multi-angle grab to attempt to
catch more capstring. Continue pumping 15 bbls per hour into well. Well static. Tag fish @ 1071', taking weight at 1120' and
work down to 1138'. Squat down with 4.5k. Put in 3 wraps, torque at 1200 ft/lbs. Set down with ~2k to neutral weight.
Picked up and set down at 1138' 3 times. PUW 7.6k and apparent that wire parted at 11k. POH w/ fish and pulling ~1.5K
above free up weight of 7.1K. - pulling 8.1 - 8.2k while coming up hole with fish. At surface, 25' of Capillary Tubing retrieved.
RIH with Wire Rope Spear Fishing BHA run #13 on 2-7/8" 6.5# EUE tubing. Pump 15 bbls per hour into well. Well static when
open IA to Flowback tank. Tag fish @ ~1,162' with 8' in on joint #39, taking weight and set down to 1,172' and place 6 wraps
in to 1000 ft/lbs torque. Pick up and down several times, weight off in same spot. Work down to 1201', squat down pretty
hard with 4.5k. Put in 3 wraps, torque at 1,300 ft/lbs. Pick up , note a breakover at 13k. Pump down 10 bbls 8.3 ppg source
water. Conduct well control drill, stab in TIW, well secure. Give crew time to eat lunch, clean off snow from walkways. POH
with fishing BHA run #13 pulling 9.1 - 10.1k while coming up hole with fish, normal PUW ~7.1-7.2k. Heavier than normal pick
up weight. Slight increase in drag up to 11.8k at ~860' but still pulling steady; PUW ranging between 8.6-11.8k. Weight
dropped off by 1k with BHA 4 joints below floor. At surface, 44' of Capillary Tubing and 35' of ESP Cable retrieved. Total after
13 runs: 536' ESP Cable, 250' Cap Tubing. Pump 20 bbls down IA. RIH with Wire Rope Spear Fishing BHA for run #14 on 2-
7/8" 6.5# EUE tubing.
3/24/2020 - Tuesday
Continue to RIH with multi angle fishing spear BHA run #11 on
r. At surface, 44' of Capillary Tubing and 35' of ESP Cable retrieved.
Well Name Rig API Number Well Permit Number Start Date End Date
MP E-42 ASR#1 50-029-23635-00-00 219-082 3/19/2020 3/30/2020
3/25/2020 - Wednesday
Hilcorp Alaska, LLC
Weekly Operations Summary
Safety Meeting, Daily plan forward, Fluid checks on all equipment. POOH w/ fishing BHA. NO ESP cable or cap-string. Found
wear ring on fishing spear . Calipered wear ring and wear groove measured 2.5". Hook at wear groove bent in as well
indicating a set down in 2-7/8" collar.( ID= 2.67") - call town. Decision made to run overshot and attempt fish the collar.
Start to lay down fishing BHA, SIMOPS arrange truck to haul / move drill collars and work-string. Had to dig out drill collars.
Truck broke down and had to arrange another truck through Doyon Rig. Make up fishing BHA up to collars, Collars on
location, tally and start P/U drill collars, intensifier and RIH on 2-7/8" 7.9# PH-6 tubing. Pumping 15 bbls per hour
displacement. Well Static. RIH Run #14 with BHA consisting of 5-3/4" S150 Overshot w/ cut-lip guide 5-3/4". Bumper Sub,
Hydraulic Jars, 6-drill collars 4-3/4" diameter, Intensifier, XO 3-1/2 IFp to 2-7/8" PH-6b. Swap out all lifting gear and slips -
RIH w/ 2-7/8" PH-6 Safety meeting with crew, conduct crew changeout and inspect equipment, fluid levels. RIH with
Overshot fishing BHA run #1 on 2-7/8" PH6 work string. Fishing BHA: 5-3/4" Overshot, Bumper Sub, Oil Jar, 6 Drill Collars,
Intensifier, XO to the 2-7/8" PH6 work string. Tag up with fish on depth at 1,201'. PUW 18k, SOW 13k. Pick up and slack off
several times to confirm fish set at depth. Move down and slack off to neutral at 13.5' in on joint 32. Set down and pick up
several times, no latch. Engage swivel, move down and rotate 1/2 turn, pick up and fish latched. Set down several times and
pick up to confirm. PUW to 28k. Slowly pick up to ensure set and to avoid jars firing. Pick up string and gain weight to 38k,
then smooth breakover back down to 28k. Disengage from swivel. POH with fish, initial PUW 28k. Lay down Fishing BHA.
Fish at surface. Lay down ESP Assembly per Centrilift rep.
3/26/2020 - Thursday
Safety Meeting, Daily Plan Forward, Hazaed Discussion w/ laying down fished ESP. Continue Laying Down ESP assembly w/
Centrilift. All ESP Components out of hole, visually inspected and all clamps accounted for. 4 Motor CLamps, 4 Seal Clamps,
and 6 Pump clamps all accounted for. Visual inspected revealed small corners and edges torn away. Conference call w/
Town decision made to R/U and run slick-line w/ magnets to remove any small rements out of well. Break down all fishing
BHA, X-overs, move out fishing tubing string, dig out snow, clear work area on location to prep for slick-line moving in and
testing BOP's. Notified Weatherford Casing to run tubing, HES for packer hand, Centrilift to run gauges and tech-line, prep to
build hooch for tech-line spooler. Gathered lifting buttons for 521 hydril tubing and Take on 30 bbls fresh water and begin
BOP Testing. Test blinds, 2-7/8" x 5" VBR's, 11" Annular w/ 2-7/8" " and 4.5" test mandrels to 250 low and 2,500psi high
pressure test for 5 mins each test. Test the Pit levels and LEL and H2S detectors. Tested all choke and kill valves, and HCR fo r
250 low and 2500psi high for 5 mins each test. Complete test at 1730 hrs. RD and clean up area. Safety Meeting with night
crew. Discussion around focus on wireline operations and non-typical liner run coming up. Change out crews. Fluid and
equipment checks, clean up around pipe shed in order to move equipment in and also prepare for Wireline Operations. RU
wireline equipment. Code 99 called over radio, cease operations due to medical emergency at I-rig location. Given all clear
at 2030 hrs. Continue to RU wireline. Pre-job meeting on wireline run, depths to target, stop work contingencies, well
control with wireline in the well. RIH Run #1 with 3.60" OD magnet to 1,200', POH with nothing. RIH again Run # 2 to 1500',
again nothing but very minimal metal shavings. RIH Run #3 and tag up at 1,642'. Cannot move past. POH, pick up weight
now ~900 lbs normal PUW ~250 lbs from 1,600'. Wireline at surface. Nothing remarkable other than dirty reside on the line.
Discuss with Operations, decide to try 4-prong wire grab. RIH Run #4 with 4-prong wire grab with 3.60" magnet above. RIH
and stack out at 1,573'. Pick up, make second attempt to move past and no-go. PUW from 1,573' 575 lbs, ~125 over. POH to
surface without noticing a drop, nothing. Run back down for Run #5 and tag up at 1,430'. Seems like it is pushing downhole.
Pick up and set down numerous times, stop pushing at 1,490'. Pick up is clean, PUW 425-450 lbs. POH, nothing. Go to
warehouse, look at options. RIH with Run #6 with Barbed spear and magnets above it. PUW before tag 430 lbs. Tag up at
1,430' and able to push down to 1,710' until it won't move any further. POH at 30 fpm, ~700 lbs PUW. Weight fell off at 900'
md. Pull to surface, nothing on BHA assembly. Make calls to ODE, Operations supervisors, Day Rep to consult on plan
forward. Crew working on circulating out spent hydraulic fluid from Pit jacking legs fluids reservoir while gathering
equipment for next operation.
fish at
surface
Test blinds, 2-7/8" x 5" VBR's, 11" Annular w/ 2-7/8" " and 4.5" test mandrels to 250 low and 2,500psi high
pressure test for 5 mins each test. Test the Pit levels and LEL and H2S detectors. Tested all choke and kill valves, and HCR for
Fish at surface. Lay down ESP Assembly per Centrilift rep.
Well Name Rig API Number Well Permit Number Start Date End Date
MP E-42 ASR#1 50-029-23635-00-00 219-082 3/19/2020 3/30/2020
Hilcorp Alaska, LLC
Weekly Operations Summary
Morning Safety Meeting, daily plan forward. Discussed hazards of laying down pipe, discussed upcoming scope change from
pulling scraper to begin run completion. Continue to POOH w/ 3.5" 10.4# work-string, pumping 15 bbls per hour
displacement, well static. SIMOPS stacking and arranging tubulars and equipment on location in prep for running
completion. Continue to POOH w/ 3.5" 10.4# work-string, pumping 15 bbls per hour displacement, well static. - Continue to
prep for running completion. Counted 205 joints of 4.5" 12.6# Hydril 521 range 3 joints of completion tubing on location.
Verified all jewelry, verified RHC plug installed, in lower X nipple, walked down floor with Weatherford Torque Turn crew.
Break crew for lunch and start moving out work-string, pipe sheds, rig down tongs, MIRU Weatherford torque turn, R/U
centrilift spooler and hooch for tech-wire. Safety meeting with night crew to discuss upcoming operations. Crew changeout.
Check fluids and equipment. Make changes to supports for legs of Catwalk for stability. Stage in jewelry, confirm running
order. Place tubing support stands, move in 4-1/2" tubing. Rig down upper sheave and re-rig up at lower level for Techline.
Conduct pre-job meeting with entire crew, emphasis on running order, pipe MU, STOP the job authority. Fill backside with
10 bph of 8.3 ppg Source Water. Make up WLEG (Wireline Entry Guide) with muleshoe. Thread covers on Box end of tubing
completely cover threads. Pick up first three joints of 4-1/2" 12.6# L-80 Hydril 521 tubing and make up to proper optimal
torque of 4,700 ft/lbs, measure where average stop is to determine average thread make-up loss. Thread loss is consitent to
specs on data sheet. Strap pipe. Continue to make up next 20 joints of 4-1/2" 12.6# L-80 Hydril 521 tubing. At joint 23, pick
up Landing Nipple assembly with RHC Plug. Rabbit inadvertenly inserted. Lower assembly to retrieve rabbit, when tipped up
the RHC plug fell to ground. Make call to Wells Support team to ask for assistance technician to come out and reinsert RHC
plug. Crew loading next row of pipe for strapping loosening Box end thread protectors and cutting rope off pipe on staging
racks. Load in Baracor for packer fluid pill that will be run at completion. Re-load RHC, set properly.. Pick up and make up
the Landing Nipple with RHC plug installed. PU and MU the HES 7-5/8" x 4-1/2" TNT Packer assembly -verified 3 start to set
pins- followed by one joint of 4-1/2" tubing. PU and MU X-Nipple assembly followed by Gauge assembly with sliding sleeve
and gauge mandrel. Continue with making up Jet Pump completion on 4-1/2" 12.6# L-80 Hydril 521 tubing per running
order.
3/28/2020 - Saturday
3/27/2020 - Friday
Morning Safety Meeting , daily Plan forward, discuss hazards on swapping operations and communication. RDMO Slick-line,
start moving in pipe sheds, move out completion completion equipment, Prostar flashing fail safes into rig for tong / slips
interaction. Move in 3.5" work-string and tally. Start RIH w/ 7-5/8" scraper assembly w/ 2-3/8" muleshoe on bottom, RIH on
3.5" 10.4# work-string. Pumping 15bbls per hour displacement. RIH w/ 60 joints to ~2,446' and shut in well for hot water
wash. R/U Worley trucks and pump a 25 bbl pill w/ 1 drum barraclean as a lead pill, then pump 580 bbls 145 degree 1% kcl
at 5-6 bpm Max pumppsi = 300psi (line friction). Well on strong vacuum. Conduct Safety Meeting with night crew. Two
replacements on Tour, focus on current ops, slips and trips, working with large workstring. change out crews. Complete
pumping down "hot" water with little pump pressure. Conduct Equipment walk down, check fluids. RIH with Scraper BHA on
3-1/2" workstring Continue to RIH with 3-1/2" workstring. PU joint 191 to place Scraper BHA at 7,680' md, PUW 61k, SOW
23k. RU to circulate, circulate down 50 bbls 8.3 ppg Source Water down workstring to flush. Pump @ 5bpm @ 0psi. Well
Static. POH with the 7-5/8" Scraper BHA on the 3-1/2" workstring.
. PU and MU the HES 7-5/8" x 4-1/2" TNT Packer assembly -verified 3 start to set
pins- followed by one joint of 4-1/2" tubing. PU and MU X-Nipple assembly followed by Gauge assemblyrun tubing
packer
Start RIH w/ 7-5/8" scraper assembly w/ 2-3/8" muleshoe on bottom,
prep for running
completion. C
Well Name Rig API Number Well Permit Number Start Date End Date
MP E-42 ASR#1 50-029-23635-00-00 219-082 3/19/2020 3/30/2020
Hilcorp Alaska, LLC
Weekly Operations Summary
No operations to report.
Morning Safety Meeting and Daily plan forward. Discussed hazards of upcoming move and importance of getting good
pressure test on tubing and casing in finalizing ops on E-42. - SIMOPS continue to hold pressure test on tubing @ 3,100psi.
Complete 30 minute charted tubing test to 3,100psi, bleed tubing to 2,000psi and lock in pressure, pump 22 bbls down
backside and load casing / annulus. Test pump broke down, fluid end leaking badly, utilize rig pump to pressure up casing to
3,100psi and chart test for 30 minutes while holding 2,000psi on tubing. Bleed off tubing to 500psi and see shear valve
shear, bleed off tubing and casing thru shear valve to zeropsi. Blow down all lines and set BPV BPV Installed - Begin RDMO
ASR-1 -End of WELL OPS on E-42.
3/31/2020 - Tuesday
3/29/2020 - Sunday
Morning Safety Meeting and Daily plan forward. Discussed the hazards of handling this particular tubing. The steps of push
up "old style" slide on catwalk - leaving thread protectors on pipe and then removing thread protector and installing lift
buttons on floor. Body position installing dog collar. Continue to RIH w/ 4.5" 12.6# 521 Thread tubing. Installed lower GLM
w/ Dummy valve between joint 25 and 26 as per running order. Clamping tech wire and testing wire every 1000'. Pumping
15 bbls per hour displacement. Well Static. Torque Turn all threads to 4700 ft/lbs. Continue to RIH w/ 4.5" 12.6# 521 Thread
tubing. Installed middle GLM w/ Dummy valve between joint 64 and 65 as per running order. Clamping tech wire and testing
wire every 1,000'. Pumping 15 bbls per hour displacement. Well Static 69 joints in hole @ 1230 hrs.Torque Turn all threads
to 4,700 ft/lbs. Continue to RIH w/ 4.5" 12.6# 521 Thread tubing. Installed middle GLM w/ Dummy valve between joint 114
and 115 as per running order. Clamping tech wire and testing wire every 1,000'. Pumping 15 bbls per hour displacement.
Well Static 116 joints in hole @ 1700 hrs.Torque Turn all threads to 4,700 ft/lbs. Continue to RIH w/ 4.5" 12.6# 521 Thread
tubing - Clamping tech wire and testing wire every 1,000'. Pumping 15 bbls per hour displacement. Torque Turn all threads
to 4,700 ft/lbs. - Well Static. Safety meeting with night crew. Emphasis on making connections, handling jewelry and pups.
Swap out crews. RIH w/ 4.5" 12.6# Hydril 521 tubing, use Torque Turn for all threads to 4700 ft/lbs. Clamp Techwire every
other joint and test wire every 1,000'. Pumping 15 bbls per hour displacement. Well has been Static. Slips are not engaging.
Troubleshoot, check hydraulics, hydraulic lines and pressure good. Engage and hoses are moving. Inspect hinge
mechanisms on slips, wire brush and lubricate. All good. Continue to RIH w/ 4.5" 12.6# Hydril 521 tubing, use Torque Turn
for all threads to 4,700 ft/lbs. Clamp Techwire every other joint and test wire every 1,000'. Pumping 15 bbls per hour
displacement. Make up last joint at 0100 hrs. Swap out elevators, MU landing joint to tubing hanger on skate, bring to rig
floor. Mix Baracor corrosion inhibitor pill. RIH with completion and keep hanger just above landing profile. Pump down 175
bbl Baracor pill down IA. Land Tubing Hanger, run in lockdown screws - SOW 38k. Drop Ball-and-Rod, pressure up tubing to
1800 while chart running and see start to set screws shear on Packer, continue to pressure to 3100psi and hold for tubing
test and final set on HES TNT packer.
3/30/2020 - Monday
Complete 30 minute charted tubing test to 3,100psi, bleed tubing to 2,000psi and lock in pressure, pump 22 bbls down
backside and load casing / annulus. T
3,100psi and chart test for 30 minutes while holding 2,000psi
MU landing joint to tubing hanger o
MIT-IA
MIT-T
Surface Casing by Conductor Annulus Fill Coat Corrosion Inhibitor (Cl) Applications
Well
Field
API
-
PTD
FCementtft.)
Corrosion
Inhibitor
Fill Volume
(gal)
Final CI Top
(ft.)
Corrosion
Inhibitor
Treatment
Date
E-35
Milne Point
50029236150000
2181520
Surface
22.5
Top of Cond
10/24/2019
E-36
Milne Paint
50029236200000
2190050
Surface
15
Top of Cond
10/24/2019
E-38
Milne Point
50029236260000
2190440
Surface
20
Top of Cond
10/24/2019
E-39
Milne Point
50029236400000/60-00
2190960
Surface
20
Top of Cond
10/24/2019
E-40
Milne Point
50029236260000
2190440
Surface
25
Top of Cond
10/25/2019
E-41
Milne Point
50029236220000
2190310
Surface
15
Top of Cond
10/24/2019
E-42
Milne Point
50029236350000/60-00
2190820
Surface
17
Topof Cond
10/25/2019
M-18
Milne Point
50029236320000
2190700
3
50
Top of Cond
10/26/2019
M-06
Milne Point
50029236460000
2191130
3
30
Top of Cond
10/26/2019
Cement to surface means cement is up to the 4" outlets below the wellhead. From the 4" outlets up to the top of conductor was filled with Fill Coat
Notes: #7
Initial top of Cement footage measurement was taken from the 4" outlet down to the TOC
The 4" conductor outlets are any where from 1 to T down from the top of the conductor
RECEIVED
DEC 0 6 2019
AOGCC
THE STATE
01ALASKA
GOVERNOR MIKE DUNLEAVY
Chad Helgeson
Operations Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU E-42
Permit to Drill Number: 219-082
Sundry Number: 319-473
Dear Mr. Helgeson:
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.00gcc.alaska.gov
Enclosed is the approved application for the sundry approval relating to the above referenced well.
Please note the conditions of approval set out in the enclosed form.
As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further
time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC
an application for reconsideration. A request for reconsideration is considered timely if it is
received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if
the 23rd day falls on a holiday or weekend.
Sincerely,
Jere y6rice
Chair
DATED this?;Zday of October, 2019.
RBDMS�` OCT 2 2 2019
SCANNED OCT 2 3 2019
STATE OF ALASKA DT 5 10 12.2 I j�
ALASKA OIL AND GAS CONSERVATION COMMISSION
APPLICATION FOR SUNDRY APPROVALS
20 AAC 25.280
1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑
Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing 0 Change Approved Program ❑
Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Convert to GL Q
2. Operator Name:
4. Current Well Class:
5. Permit to Drill Number:
Hilcorp Alaska LLC
Exploratory ❑ Developments Q
Stratigraphic ❑ Service ❑
219-082 '
3. Address: 3800 Centerpoint Dr, Suite 1400
6. API Number:
Anchorage Alaska 99503
50-029-23635-00-00
7. If perforating:
8. Well Name and Number:
What Regulation or Conservation Order governs well spacing in this pool? C.O.432D
Will planned perforations require a spacing exception? Yes ❑ No U
MILNE PT UNIT E-42 '
9. Property Designation (Lease Number): RD L- L10. Field/Pool(s):
ADL0028231 - 0.3 SO l 10 (TV tZb f MILNE POINT/ SCHRADER BLUFF OIL POOL
11. PRESENT WELL CONDITION SUMMARY
Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD):
11,960' 4,300' 11,945' 4,195' 953. N/A N/A
Casing Length Size MD TVD Burst Collapse
Conductor 107' 20" 107' 107' N/A N/A
Surface 8,311' 9-5/8" 8,311' 4,355' 5,750psi 3,090psi
Intermediate 7,769' 7-5/8" 7,769' 4,285' 6,890psi 4,790psi
Liner J4 ' 108' 4-1/2" 11,960' 4,194' 9,020psi 8,540psi
Perforation Depth MD (ft):Perforation
Depth TVD (ft):
Tubing Size:
Tubing Grade:
Tubing MD (ft):
See Schematic
See Schematic
2-7/8"
6.5# / L-80 / EUE 8rd
7666
Packers and SSSV Type:
Packers and SSSV MD (ft) and TVD (ft):
SLZXP & MLZXP
7,761 MD/ 4,285 TVD & 7,852 MD/ 4,300 TVD and N/A
12. Attachments: Proposal Summary j Wellbore schematic w
13. Well Class after proposed work:
Detailed Operations Program ❑ BOP Sketch 0
Exploratory ❑ Stratigraphic ❑ Development ❑� Service ❑
14. Estimated Date for
15. Well Status after proposed work:
Commencing Operations: 11/1/2019
OIL ❑� . WINJ ❑ WDSPL ❑ Suspended ❑
GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑
16. Verbal Approval: Date:
Commission Representative:
GINJ ❑ Op Shutdown ❑ Abandoned ❑
17. 1 hereby certify that the foregoing is true and the procedure approved herein will not
be deviated from without prior written approval.
Authorized Name: Chad Helgeson Contact Name: Taylor Wellman -7"r✓
Authorized Title: Operations Manager Contact Email: twellman hilcor .Com
Contact Phone: 777-8449
Authorized Signature: Mc Date: (c' IL I `!
IF COMMISSION USE ONLY
Conditions of approval: Notify Commission so that a representative may witness Sundry Number: I ^ q-75
Plug Integrity ❑ BOP Test LD Mechanical Integrity Test ❑ Location Clearance ❑
Other: fc LSOO 15Z �,/901,0 --Ir—e- ST-
tl �t '-f/�//�,.//
RBDMS' OCT 2 Z 2019
Post Initial Injection MIT Req'd? Yes ❑ No ❑
,,J r,../
Spacing Exception Required??Yes ❑ No � Subsequent Form Required: ( O' I L)
APPROVED BY
Approved by: Y t 1 \� COMMISSIONER THE COMMISSION Date:
iv az I ISI lo-zz R
N A !_- ,�a17` 1V Submit Form and
Form 0-403 Revised 4/2017 Approved application is d o 1 nt s from the date of approval. An hmegt. Duplicate
16�i�
IPA
tfilaorn Alaska. LU
Convert to GasLift
Well: MPU E-42
Date: 10-10-19
Well Name:
MPU E-42
API Number:
50-029-23635-00
Current Status:
Shut-in ESP Producer
Pad:
E -Pad
Estimated Start Date:
Nov 1, 2019
Rig:
ASR
Reg. Approval Req'd?
Yes
Date Reg. Approval Rec'vd:
BPV Profile:
Regulatory Contact:
Tom Fouts
Permit to Drill Number:.2jy
First Call Engineer:
Taylor Wellman
(907) 777-8449 (0)
(907) 947-9533 (M)
Second Call Engineer:
David Haakinson
(907) 777-8343 (0)
(307) 660-4999 (M)
AFE Number:
Job Type:
ESP Swap
Current Bottom Hole Pressure:
1,380 psi @ 4,270' TVD
Downhole Gauge (8/29/19) 6.3 PPG
Maximum Expected BHP:
1,380 psi @ 4,270' TVD
Downhole Gauge (8/29/19) 6.3 PPG
MPSP:
953 psi
Gas Column Gradient (0.1 psi/ft)
Max Inclination
95° @ 9,426' MD (Reaches
70° at 6,800' md)
Max Dogleg:
8.3'/100ft @ 6,971' MD
BPV Profile:
2-1/2" CIW Type H
Brief Well Summary:
MPU producer E-42 was drilled and completed as a dual lateral horizontal producer from the Schrader OA and
OB sands in July 2019. The well came online producing-1,800bopd at a GOR = 700. Following the Milne Point
TAR, the production rates have declined to—600bopd at a GOR = 1500. The changed flow characteristics and
increased total gas/GOR indicated a possible loss of one of the laterals.
Notes Regarding Wellbore Condition
• The 9-5/8"x7-5/8" annulus passed an MIT to 1,000 psig on 7/8/19
Objective:
• Pull 2-7/8" Tubing String and ESP
• Install a 4-1/2" Gas Lift (Jet Pump contingency) completion
Pre -Rig Procedure: Non-Sundried Operations
1. RU SL and pull DGLV from Sta #1 at 7,414' md. Pull GLV Sta #2 at 128' and and set DGLV in Sta #2 at 128'
md. RD SL.
2. RU LRS and PT lines to 3000 psi.
3. Well is expected to go on a vacuum but have a gas head on the IA. Pump 1 IA volume (300 bbls) with
8.3 ppg source -water down IA, taking fluids to formation.
4. Clear and level pad area in front of well. Spot rig mats and containment.
S. RD well house and flowlines. Clear and level area around well.
6. Bleed off any residual pressure and confirm well is dead. Freeze protect tubing/casing as needed with
60/40 McOH.
a. Freeze protect is up to the discretion of the Wellsite Supervisor depending on timing for arrival of
the ASR.
7. RD Little Red Services.
8. RU crane. Set BPV. ND Tree. NUS PE. RD Crane.
9. NU BOPE house. Spot mud boat.
Convert to GasLift
Well: MPU E-42
IIilcorp Alaska. LLQ Date: 10-10-19
Brief RWO Procedure: Sundried Operations (Approved 10-403 required prior to starting)
10. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to returns tank.
11. Check for pressure and if 0 psi, pull BPV. If needed, bleed off any residual pressure off tubing and
casing. If needed, kill well w/ 8.3 ppg source -water prior to pulling BPV.
12. Set BPV plug (converting BPV to TWC).
13. Test BOPE to 250 psi Low/ 2,500 psi High, annular to 250,psi Low/ 2,500 psi High (hold each ram/valve
and test for 5 -min). Record accumulator pre -charge pressures and chart tests.
/} a. Notify AOGCC 24 hours in advance of BOP test.
b. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015.
fn's
C. Confirm test pressures per the Sundry Conditions of approval.
d. Test VBR rams on 2-7/8" and 4-1/2" test joints.
e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test.
14. Contingency.jf BOPE test fails
a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via
email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to
send an inspector to witness test.
b. With stack out of the test path, test choke manifold per standard procedure
c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the
surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere
at surface.)
d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record
the pumping rate and pressure.
e. Once the BOP ram and annular tests are completed, test the remainder of the system following the
normal test procedure (floor valves, gas detection, etc.)
f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile /
penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list
items, pressures and rates.
15. Bleed any pressure off casing to returns tank. Pull BPV plug and BPV. Kill well w/ 8.3 ppg source -water
asneeded.
16. Rig up spoolers for ESP #2 RD cable.
a. Baker Hughes representative should be onsite for ESP pull.
17. MU landing joint or spear and PU on the tubing hanger.
a. The PU weight during the 2019 ESP completion was 73K lbs / SOF = 54K lbs (block wt = 35k lbs).
b. If needed, circulate (long or reverse) pill with lubricant, source -water, and/or baraclean pill prior to
laying down the tubing hanger.
18. Recover the tubing hanger.
Contingency (If a rolling test was conducted): MU new hanger or test plug to the
completion tubing. Re -land hanger (or test plug) in tubing head. Test BOPE per standard
procedure.
PUP19. POOH and lay down the 2-7/8" tubing. Lay down ESP and motor. a. ESP will be sent to Baker Hughes for inspection and reuse on another well.
b. Send all tubing to G&I for washing and reuse. Send —5% of random joints to Tuboscope for full
inspection.
0
Convert to GasLift
Well: MPU E-42
lfik. o M.A., LU Date: 10-10-19
c. Note any sand or schmoo/asphaltenes inside or on the outside of the ESP on the morning report.
d. Look for over -torqued connections from previous tubing runs.
e. The completion has the following amount of clamps/guards/cap-string:
i. 162 Cross Collar Cannon Clamps
ii. 4 Motor Clamps
iii. 4 Seal Calamps
iv. 6 Pump Clamps
20. PU 7-5/8" casing scraper BHA and TIH. TIH and reciprocate around 6,700'— 6,820' md.
21. Circulate a minimum of x1.5BU or until returns are clean from above the sealbore receptacle at 7,769'
md. TOOK
Ra,�Y— 22. RU spoolers, MU 4-1/2" completion and deploy as per the finalized Completion Running Order. The
VY Ipacker will be at ±6,770' md.
C L �23. Record PU and SO weights prior to spacing out the WLEG to be below the 7-5/8"x9-5/8" liner top
packer at ±7,780' md.
24. Reverse circulate 175bb1s of 2% KCI with corrosion inhibitor down the annulus.
25. Land tubing hanger. RILDS. Lay down landing joint. Test tubing hanger packoff to 5000psi.
v 26. Drop the ball & rod to set the packer. Increase the pressure and test the tubing to 3�psi.
27. Bleed down the tbg pressure to 2,OOOpsi and pressure test the IA to 3,OOOpsi for 30 min (charted).
28. Bleed down the tubing pressure to shear out the shear out GLV from Sta #3 at ±3,000' md. Pump
90bbls of diesel down the IA and U -Tube to the tbg to freeze protect the well.
29. Set BPV.
Post -Rig Procedure:
30. RD mud boat. RD BOPE house. Move to next well location.
31. RU crane. ND BOPE.
32. NU existing 2-9/16" 5,000# tree. Test tubing hanger void to 500 psi low/5,000 psi high.
33. Pull BPV.
34. RD crane. Move 500 bbl returns tank and rig mats to next well location.
35. Replace gauge(s) if removed.
36. Turn well over to production. RU well house and flowlines.
Attachments:
1. As -built Schematic
2. Proposed Schematic
3. BOP Schematic
..,dne Point Unit
Well:MPU E-42 & L1
Lasto
Schematic Last Completed: 7/8/2019
IlilcorP Aloske. LLC PTD: 219-082 & 219-091
WELLHEAD
Wellhead I FMCGenS
Orig. KB Elev.: 48.4'/ Orig, GL Elev.: 21.5'
OPEN HOLE/ CEMENT DETAIL WELL INCLINATION DETAIL
rcticset I curt in 42" Hole KOP @ 350' MD
sx/T-400 sx Max Wellbore Angle = 92.wde @8,38fi'MD
sx/ T - 270 sx
TD=11,950 (MD) /TD=4,223'M)
PBTD=11,945' (MD) / PBTD=4,223'(7VD)
CASING DETAIL
Size
Type
Wt/Grade/Conn
ID
Top
Btm
20"
Conductor
215/X-42/Welded
N/A
Surface
107'
9-5/8"
Surface
40/L-80/TXP
8.835
Surface
8,311'
7-5/8"
Tieback
29.7 / L-80 / Hyd 521
6.875
Surface
7,769'
8 1
Liner "OA"
1 Upper Tandem Seal: GS83DB H6 SB/AB PFSA
9
7,629'
Lower Tandem Seal: GSB3DB H6 SB/AB PFSA
4-1/2"
Predrilled w/
13.5 / L-80 / Hyd 625
3.920
7,795'
11,852'
12
76 holes/ft
Centralizer: Bottom @ 7,666'
13
7,769'
Sealbore Receptacle 110=6.00")
14
Liner "OB"
7"x9-5/8" SLZXP Liner Top Packer
15
7,795'
OA Lateral LEM 41 (Lateral Entry Module) (ID=3,68")
4-1/2"
Predrilled w/
13.5 / L-80 / Hyd 625
3.920
7,852'
11,960'
18
76 holes/ft
7"z9-5/8" MLZXP Liner Hanger Packer w/ Sealbore Receptacle
(ID=4.75") TOL
19
7,884'
Bottom of locator seal assembly(ID=3.875")
TUBING DETAIL
2-7/8" Tubing 6.5 / L-80 / EUE 1 2.441 1 Surface 1 7,666'
JEWELRY DETAIL
No
Depth
Item
1
128'
ST 2: 2-7/8" GLM w/ 1" DPSOV BK Latch
2
7,414'
ST 1: 2-7/8" GUM w/ DV, BK Latch
3
7,534'
2-7/8" XN Profile -2.205" No -Go
4
7,586'
Discharge Head: PMP 400P
5
7,587'
Pump: 538PMSXD 93 Flex47 HS
6
7,609'
Pump: 538PMSXD 20 H6
7
7,619'
Gas Separator: Gas Avoider 538GS
8 1
7,622'
1 Upper Tandem Seal: GS83DB H6 SB/AB PFSA
9
7,629'
Lower Tandem Seal: GSB3DB H6 SB/AB PFSA
30
7,636'
Motor: 562 XP- 40GHp/ 2,785V/ 88A
11
7,661'
Sensor: Zenith
12
7,664'
Centralizer: Bottom @ 7,666'
13
7,769'
Sealbore Receptacle 110=6.00")
14
7,761'
7"x9-5/8" SLZXP Liner Top Packer
15
7,795'
OA Lateral LEM 41 (Lateral Entry Module) (ID=3,68")
16
7,795'
7"x9-5/8" RAM Hanger (Lateral Drift lD=5.960") (Mainbore
Drift ID=3.688") TOL
17
7,799'
4-1/2"x9-5/8" RAM Sealbore DiverterSBD) (Sealbore
ID=3.68")
18
7,852'
7"z9-5/8" MLZXP Liner Hanger Packer w/ Sealbore Receptacle
(ID=4.75") TOL
19
7,884'
Bottom of locator seal assembly(ID=3.875")
20
11,927'
OB Lateral 4-1/2" Drillable Packoff Sub
21
11,959'
OR Lateral 4-1/2" WIV Valve LTC BXB (1" Ball on Seat/Closed)
LATERAL WINDOW DETAIL
Top of "OA" Window @ 7,805' MD; Bottom @ 7,822' MD; Angle @ top of window is 79 deg
GENERAL WELL INFO
API: 50-029-23635-00-00 & 50-029-23635-60-00
Drilled and Completed by Innovation Rig -7/8/19
Revised By: CJD 8/6/2019
Milne Point Unit
✓ell: MPU E- & L1
Proposed Schematic Last Completed:
liilconAlaska. LLC PTD: 219-082 & 219-091
WELLHEAD
Wellhead I FMC Gen 5
Orig. KB Elev.: 48.4'/ Orig. GL Elev.: 21.5'
OPEN HOLE / CEMENT DETAIL WELL INCLINATION DETAIL
rcticset I cmt in 42" Hole KOP @ 350' MD
sx / T— 400 sx Max Wellbore Angle= 92.4 deg @ 8,386' MD
sx/ T— 270 sx
TD=11,950' (MD) /TD=4,223'(TVD)
PBTD=11,945' (MD) / PBTD=4,223'(TVD)
CASING DETAIL
Size
Type
Wt/Grade/Conn
ID
Top
Btm
20"
Conductor
215/X-42/Welded
N/A
Surface
lOT
9-5/8"
Surface
40/L-80/TXP
8.835
Surface
8,311'
7-5/8"
Tieback
29.7 / L-80 / Hyd 521
6.875
Surface
7,769'
7
Liner "OA"
7-5/8"x4-1/2" Packer
8
±6,800
4-1/2" X Nipple (ID=3-813")
4-1/2"
Predrilled w/
13.5 / L-80 / Hyd 625
3.920
7,795'
11,852'
11
76 holes/ft
12
13
Liner "OB"
Sealbore Receptacle(ID=6.00")
14
7,761'
7"x9-5/8" SLZXP Liner Top Packer
4-1/2"
Predrilled w/
13.5 / L-80 / Hyd 625
3.920
7,852'
11,960'
17
76 holes/ft
4-1/2"x9-5/8" RAM Sealbore Diverter (SBD) (Sealbore
ID=3.68")
18
7,852'
7"x9-5/8" MLZXP Liner Hanger Packer w/ Sealbore Receptacle
(ID=4.75") TOL
TUBING DETAIL
4-1/2" Tubing 12.6/L-80/Hyd521 1 3.958 1 Surface 1 ±7,780'
JEWELRY DETAIL
No
Depth
Item
GLM's: 4-1/2" w/ 1" valves
1
±3,000'
ST 4: GLM w/ dome valve, BK Latch
2
±5,000'
ST 3: GLM w/ dome valve, BK Latch
3
±6,630'
ST 2: GLM w/ shear out valve, BK Latch
4
±6,690'
4-1/2" Sliding Sleeve (Min ID=3.813)
5
±6,710'
Downhole Gauge Mandrel
6
±6,740'
4-1/2" X Nipple(ID=3.813")
7
±6,770'
7-5/8"x4-1/2" Packer
8
±6,800
4-1/2" X Nipple (ID=3-813")
9
±7,780
4-1/2" WLEG
10
11
12
13
7,769'
Sealbore Receptacle(ID=6.00")
14
7,761'
7"x9-5/8" SLZXP Liner Top Packer
15
7,795'
OA Lateral LEM #1 (Lateral Entry Module) (ID=3.68")
16
7,795'
7"x9-5/8" RAM Hanger (Lateral Drift ID=5.960")(Mainbore
Drift ID=3.688") TOL
17
7,799'
4-1/2"x9-5/8" RAM Sealbore Diverter (SBD) (Sealbore
ID=3.68")
18
7,852'
7"x9-5/8" MLZXP Liner Hanger Packer w/ Sealbore Receptacle
(ID=4.75") TOL
19
7,884'
Bottom of locator seal assembly (ID=3.875")
20
11,927'
OB Lateral 4-1/2" Drillable Packoff Sub
21
11,959'
OB Lateral 4-1/2" WIV Valve LTC BXB (1" Ball on Seat/Closed)
LATERAL WINDOW DETAIL
Top of "OA" Window @ 7,805' MD; Bottom @ 7,822' MD; Angle @ top of window is 79 deg
GENERAL WELL INFO
API: 50-029-23635-00-00 & 50-029-23635-60-00
Drilled and Completed by Innovation Rig -7/8/19
Revised By: TTW 10/10/2019
H
A1,A.. ta.c
11" BOPE
Milne Point
ASR Rig 1 BOPE
2019
Updated 1/05/2018
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STATE OF ALASKA '
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
1a. Well Status: Oil ❑� • Gas El SPLUG ❑ Other ❑ Abandoned ❑ Suspended E]
1b. Well Class.
20AAC 25.105 20AAC 25.110
Development Q Exploratory ❑
GINJ ❑ WINJ ❑ WAGE] WDSPL ❑ No. of Completions: _ 1 '
Service ❑ Stratigraphic Test ❑
2. Operator Name:
6. Date Comp., Susp., or
14. Permit to Drill Number/ Sundry:
Hilcorp Alaska, LLC
Abend 7/8/2019
219-082 '
3. Address:
7. Date Spudded:
15. API Number:
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
June 10, 2019
50-029-23635-00-00 '
4a. Location of Well (Governmental Section):
8. Date TD Reached:
16. Well Name and Number:
Surface: 3704' FSL, 2008' FEL, Sec 25, T13N, R10E, UM, AK
June 23, 2019
MPU E-42 "
Top of Productive Interval:
9. Ref Elevations: KB: 48.4' •
17. Field / Pool(s): Milne Point Field
2216' FNL, 1338' FWL, Sec 36, T13N, R10E, UM, AK
GL: 21.5' BF, 21.5'
Schrader Bluff Oil Pool
Total Depth:
670' FNL, 429' FWL, Sec 6, T12N, R11 E, UM, AK
10. Plug Back Depth MD/TVD:
11,959' MD / 4,193' TVD
18. Property Designation:
- ADL025518, ADL3501fi5�
4b. Location of Well (State Base Plane Coordinates, NAD 27):
Surface: x- 569137 y- 6016241 • Zone- 4
11. Total Depth MD1TVD:
. 11,969' MD / 4,194' TVD
19. DNR Approval Number:
LONS 94-017
TPI: x- 567260 y- 6010303 Zone- 4
12. SSSV Depth MD/TVD:
20. Thickness of Permafrost MD/TVD:
Total Depth: x- 566381 y- 6006561 Zone- 4
N/A
2,154' MD 11,778' TVD
5. Directional or Inclination Survey: Yes ✓ (attached) No
13. Water Depth, if Offshore:
21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic and printed information per 20 AAC 25.050
N/A (ft MSL)
N/A
22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days
of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential,
gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and
perforation record. Acronyms may be used. Attach a separate page if necessary
ROP/ABG/DGR/EWR/ADR 275" MD
ABG/DGR/EWR/ADR 2"/5" TVD
23. CASING, LINER AND CEMENTING RECORD
CASING
WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD AMOUNT
FT TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED
20"
215 X-42 Surface
107' Surface
107' 42" ±270 ft3
9-5/8"
40# L-80 Surface
8,311' Surface
4,355' 12-1/4" Stg1 L-798 sx/T-400 sx
Stg 2 L - 550 sx / T - 270 sx 406 bbls
7-5/8"
29.7# L-80 Surface
7,769' Surface
4,285' Tieback Assy
4-1/2"
13.5# L-80 7,852'
11,960' 4,300'
4,194' 8-1/2" Cementless PreDrilled Liner
24. Open to production or injection? Yes Q ' No ❑
25. TUBING RECORD
If Yes, list each interval open (MD/fVD of Top and Bottom; Perforation
SIZE DEPTH SET (MD) PACKER SET (MD/TVD)
Size and Number; Date Perfd):
2-7/8" 7,666' MD N/A
4-1/2" PreDrilled Liner 76 holes/ft run on 6/26/19
8,099' - 11,922' MD / 4,340' - 4,195' TVD
COMPLETION
D TE
it/% fo(q
26, ACID, FRACTURE, CEMENT SQUEEZE, ETC.
Was hydraulic fracturing used during completion? Yes No
Per 20 AAC 25.283 (1)(2) attach electronic and printed information
VE I IED
DEPTH INTERVAL (MD) 1AMOUNT AND KIND OF MATERIAL USED
27. PRODUCTION TEST
Date First Production:
Method of Operation (Flowing, gas lift, etc.):
7/21/2019
ESP
Date of Test:
Hours Tested:
Production for
Oil -Bbl:
Gas -MCF:
Water -Bbl:
Choke Size:
Gas -Oil Ratio:
7/25/2019
24
Test Period
1522
1057
95
N/A
694
Flow Tubing
Casing Press:
Calculated
Oil -Bbl:
Gas -MCF:
Water -Bbl:
Oil Gravity -API (corr):
Press. 213
250
24 -Hour Rate -.*
1522
1057
95
18
Form 10-407 Revised 5/2017 _ %% et-,,cs CONTINUED ON PAGE 2 Submit ORIGINAL only
�7�" ioAltrj RBDMS±AUG 121019
28. CORE DATA Conventional Core(s): Yes ❑ No Q • Sidewall Cores: Yes ❑ No ❑✓ -
If Yes, list formations and intervals cored (MD/TVD, Fromrro), and summarize lithology and presence of oil, gas or water (submit separate pages with this form,
if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071,
29. GEOLOGIC MARKERS (List all formations and markers encountered):
30. FORMATION TESTS
NAME
MD
TVD
Well tested? Yes ❑ No ❑� '
If yes, list intervals and formations tested, briefly summarizing test results.
Permafrost - Top
Permafrost - Base
2,154'
1,778'
Attach separate pages to this form, if needed, and submit detailed test
Top of Productive Interval
SB OB 8,099'
4,343'
information, including reports, per 20 AAC 25.071.
SV5
1,936'
1,660'
Sv1
3,597'
2,512'
Ugnu LA3
5,971'
3,729'
SB NA
7,138'
4,208'
SB OA
7,890'
4,307'
SB OB
8,235'
4,351'
Formation at total depth:
SB OB
31. List of Attachments: Wellbore Schematic, Drilling Reports, Definitive Directional Surveys, Csg and Cmt Report.
—Completion Reports filed under MPU E-42 L1 10-407**
Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis,
paleontological report, production or well test results, per 20 AAC 25.070.
32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge.
Authorized Name: Monty Myers Contact Name: Cody Dinger
Authorized Title: Drilling Manager Contact Email: Cdin er hilCor .Com
Authorized _ Contact Phone: 777-8389
/s
Signature: — Date:
INSTRUCTIONS
General: This form and the required attac s provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram
with each 10407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical
reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted.
Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each
segregated pool is a completion.
Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Item 4b: TPI (Top of Producing Interval).
Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements
given in other spaces on this form and in any attachments.
Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY -123), Land Use Permit (LAS 12345),
and/or Easement (ADL 123456) number.
Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of
completion, suspension, or abandonment, whichever occurs first.
Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the
intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
producing
showing the data pertinent to such interval).
Item 27: Method of Operation: Flawing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit
detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity,
permeability, fluid saturation, fluid composition, Fluid fluorescence, vitrinite reflectance, geochemical, or paleontology.
Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical
laboratory information required by 20 AAC 25.071.
Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and
other tests as required including, but not limited to: core analysis, paleontological report, production or well test results.
Form 10-407 Revised 512017 Submit ORIGINAL Only
Nf
Orig. KB Elev.: 48.4'/ Orig. GL Elev.: 215'
Milne Point Unit
Well: MPU E-42 & L1
Schematic Last Completed: 7/8/2019
PTD: 219-082 & 219-091
WELLHEAD
Wellhead I FMC Gen5
OPEN HOLE / CEMENT DETAIL WELL INCLINATION DETAIL
cticset I cmt in 42" Hole KOP @ 350' MD
.x /T-400 sx Max Wellbore Angle = 92.4 deg @ 8,386' MD
;x/ T - 270 sx
TD=11,950' (MD) / TD=4,223'(7VD)
PBTD = 11,945'(MD) / PBT) =4,223'(TVD)
CASING DETAIL
Size
Type
Wt/Grade/Conn
ID
Top
Btm
20"
Conductor
215/X-42/Welded
N/A
Surface
107'
9-5/8"
Surface
40/L-80/TXP
8.835
Surface
8,311'
7-5/8"
Tieback
29.7/L-80/Hyd 521
6.875
Surface
7,769'
8
Liner "OA"
Upper Tandem Seal: G5B3DB H6 SB/AB PFSA
9
7,629'
Lower Tandem Seal: GSB3DB H6 SB/AB PFSA
4-1/2"
Predrilled w/
13.5 / L-80 / Hyd 625
3.920
7,795'
11,852'
12
76 holes/ft
Centralizer: Bottom @ 7,666'
13
7,769'
Sealbore Receptacle(ID=6.00")
14
Liner "OB"
7"x9-5/8" SLZXP Liner Top Packer
15
7,795'
OA Lateral LEM #1 (Lateral Entry Module) (ID=3,68")
4-1/2"
Predrilled w/
13.5 / L-80 / Hyd 625
3.920
7,852'
11,960'
18
76 holes/ft
7 x9-5/8" MLZXP Liner Hanger Packer w/ Sealbore Receptacle
(ID=4.75") TOL
19
7,884'
Bottom of locator seal assembly (ID=3.875")
TUBING DETAIL
2-7/8" Tubing 6.5 / L-80 / EUE 1 2.441 1 Surface 1 7,666'
JEWELRY DETAIL
No
Depth
Item
1
128'
ST 2: 2-7/8" GLM w/ 1" DPSOV BK Latch
2
7,414'
ST 1: 2-7/8" GLM w/ DV, BK Latch
3
7,534'
2-7/8" XN Profile- 2.205" No -Go
4
7,586'
Discharge Head: PMP 400P
5
7,587'
Pump: 538PMSXD 93 Flex47 HIS
6
7,609'
Pump: 538PMSXD 20 H6
7
7,619'
Gas Separator: Gas Avoider 538GS
8
7,622'
Upper Tandem Seal: G5B3DB H6 SB/AB PFSA
9
7,629'
Lower Tandem Seal: GSB3DB H6 SB/AB PFSA
10
7,636'
Motor: 562 XP- 400Hp/ 2,785V/ 89A
11
7,661'
Sensor: Zenith
12
7,664'
Centralizer: Bottom @ 7,666'
13
7,769'
Sealbore Receptacle(ID=6.00")
14
7,761'
7"x9-5/8" SLZXP Liner Top Packer
15
7,795'
OA Lateral LEM #1 (Lateral Entry Module) (ID=3,68")
16
7,795'
7x9-5/8" RAM Hanger (Lateral Drift ID=5.960") (Mainbore
Drift ID=3.688") TOL
17
7,799'
4-1/2"x9-5/8" RAM Sealbore Diverter (SBD) (Sealbore
ID=3.68")
18
7,852'
7 x9-5/8" MLZXP Liner Hanger Packer w/ Sealbore Receptacle
(ID=4.75") TOL
19
7,884'
Bottom of locator seal assembly (ID=3.875")
20
11,927'
OB Lateral 4-1/2" Drillable Packoff Sub
21
11,959'
OB Lateral 4-1/2" W IV Valve LTC BXB (1" Ball on Seat/Closed)
LATERAL WINDOW DETAIL
Top of "OA" Window @ 7,805' MD; Bottom @ 7,822' MD; Angle @ top of window is 79 deg
GENERAL WELL INFO
API: 50-029-23635-00-00 & 50-029-23635-60-00
Drilled and Completed by Innovation Rig -7/8/19
Revised By: CH) 8/6/2019
U
Well Name: MP E-42
Field: Milne Point Field
County/State: , Alaska
(LAT/LONG):
;vation (RKB):
API #:
Spud Date: 6/10/2019
Job Name: 1910942D MPU E-42 Drilling
Contractor Innovation
AFE #:
AFF 4
Hilcorp Energy Company Composite Report
. ;,:.Late
Ops S40MWY
. 1 ..
6/8/2019
PJSM Raise Beaver Slide and scope back cattle chute. Blown rig lines. Come off high line and go to cold start. Move cutting box, break room and Envirovac.
Peak trucks split and stage Gen , Pits, Pipe Shed and Catwalk Mods. Walk Sub off E-38.;PJSM Cont walk off Sub F/ E-38. Rotate Sub & install tow hitch. Spot
Sub on E-42. Set Matt Boards and spot Catwalk, Pipe Shed, Pits and Gen Mods. Install Sub outriggers. Spot cutting box, break room and Envirovac. M/U inner
connects. Plug in Rig at Plug Boards. Spot Beyond skid.;PJSM Safe out roof tops, stairs and landings. Swap rig F/ cold start to Gen at 00:30. Bring on steam,
water and air. Scope up Derrick and bridle down. C/O oil and filter in lop drive. C/O Saver Sub. SIMOPS C/O jets and suction rubbers in Pits. Put together MP
#1. Berm cutting box.
6/9/2019
NIU Diverter: Set stack on diverter Tee Tq Same. Install knife valve. N/U Diverter Line to Cattle Chute. Install 4" valves on conductor. SIMOPS: Finish C/O
Saver Sub and Grabber dies. Service Rig. C/O suction Pod Rubbers. Begin Flooding and testing lines in Pits .;Work on Rig Acceptance Check List. Accept Rig
@ 12:00 hm.;PJSM Cont. M/U Diverter line. Crane Matt Boards off location and set weighted diverter clamp. Set final diverter section W/ Peak crone. Install
Bell Nipple and riser on Stack. Cont. working on rig acceptance check list. Drain and flush rotary table oil. Remove link in dreg chain and service.;PJSM P/U
Hawk Jaws. RIH Mouse Hole and close Annular. P/U MIU 5" NC50 D.P. F/ Pipe Shed and rack back in Derrick. Drift 3.125". (Total 74 stands, 148 Jnts).;PJSM
P/U M/U 5" NC50 D.P. F/ Pipe Shed and rack back in Derrick. (51 Stands, 102 Jnts) Drift 3.125". P/U M/U 5" HWDP and Jars. ( 10 stands, 19 Jnts, 1 Jar)
Drift 2.75". UD Mouse Hole and Hawk Jaws.;PJSM BOPE Test, Perform Stack and Knife Valve test W/ 5" D.P. Function Annular 11 Sec, Knife Valve 2 sec.
Check Bag W/ H2O. Draw down 200 PSI increase 16 sec, full charge 52 sec. 6 bottle Nitrogen average 2,308 PSI Witnessed waived by Matt Herrera. SIMOPS
Prep rig floor for BHA.;Hauled 0 bbls Fluid to MP G&I total = 0 bbls
Hauled 650 bbls H2O from B -Pad Creek total = 650 bbls
Lost 0 bbls to formation Total fluid lost = 0 bbls
6/10/2019
Pre spud meeting. M/U bit to 1.5' bend 8" Sperrydrill motor. Stage TM, DM and UBHO on rig floor. RIH with 1 stand HWDP and Tag Fill at 59'. Fill conductor
and stack with water. PT high pressure lines to 3000 psi.; Establish circulation 400 gpm and rotary 30 rpms. Drill out conductor to 114' swapping to spud mud
on the fly. Continue drilling 12-1/4" hole from 114'to 220'; 400 gpm/400 psi with 155 psi diff, 40 rpms/2000 ft-Ibs. POOH to 33' to make up MWD tools. P/U
47K, SLK 46K, ROT 47K.;PJSM P/U the rest of BHA #1, 8" DM, 8" DGR, 8" EWR-P4, 8" PWD, 8" HCIM, 8" TM, 8" NM UBHO, 2 as 8" NM FC, X/O and 5"
HWDP to 149' MD.;Measure RFO = 1.6/ 8.05 = 71.55°, orientate UBHO. RIH with 5" Hi Shallow pulse test. RIH and tag fill at 219, wash down to
220'.;Rotate and slide 12.25" Surface F/ 220'to 771' MD ( 765' TVD) Total 551' (68.9' AROP) 450 GPM, 1,150 PSI, 40 RPM, TRQ ON 2K, TRQ OFF 1.5K,
WOB 5K, Max Gas OU. ECD 9.8 ppg. P/U 73K, SLK 73K, ROT 75K. MW 8.8 Flog. Running water at 50 bph. Heavy gravel with large rocks encountered st
Shakers.;Shakem showing more clay and slight gravel at —58V MD. Start Gyro surveys and 4°/100 build at 223' MD, start build turn 220° MTF at 423' MD. Cont
Gyro every connection. SIMOPS load Pipe Shed W/ 9 5/8" Csg.; Rotate and slide 12.25" Surface F/ 771'to 1,277' MD ( 1,026 TVD) Total 50V ( 84.3' AROP)
500 GPM, 1,375 PSI, 50 RPM, TRO ON 4K, TRQ OFF 2.8K, WOB 11 K. Max Gas OU. ECD 9.74 ppg. P/U 82K, SLK 77K, ROT 78K. MW 8.85 ppg. Running
water at 50 bph.;Cont. build turn 5.2"/100 build, Last Gyro survey at 603' at USHO, 768' MD, Released Scientific at 957' MD 03:00 after 5 clean surveys from
MWD. SIMOPS load Pipe Shed W/ 9 5/8" Csg.;Distance to WP#7 18.41', 1.8" High. 18.30' Right. Slide His 4.25. ROT Hrs 2.3, total 6.55 Hm.;Hauled 288
bbls Fluid to MP G&I total = 288 bible
Hauled 390 bbls H2O from B -Pad Creek total = 1,040 bbls
Lost 0 bbls to formation Total fluid lost = 0 bbls
6/11/201
to and sli a 12.25" Surface F/i 277' to 1.821' MD 9 ' VD) Total 544' ( 90.6' AROP) 550 GPM, 1,590 PSI, 80 RPM, TRQ ON 5K, TRQ OFF 4.4K,
WOB 6K, Max Gas 10u. ECD 9.92 ppg. P/U 87K, SLK 75K, ROT 77K. MW 9.0 ppg. Running water at 50 bph.; Rotate and slide 12.25" Surface F/1,821'to
2,427' MD ( 1,923' TVD) Total 606' ( 1 01'AROP) 515 GPM, 1,410 PSI, 80 RPM, TRQ ON 6-7K, TRQ OFF 6-7K, WOB 8K, Max Gas 118u. ECD 10.0 ppg.
P/U 106K, SLK 65K, ROT 81 K. MW 9.1 ppg. Running water at 50 bph.;Log base of permafrost @ 2,154' MD, 1,718' TVD. End Build/Tum @ 1,890' MD and
start Tangent @ 1,890'.;Rotate and slide 12.25" Surface F/ 2,427' to 2,960' MD ( 2,189 TVD) Total 533' ( 88.8' AROP) 530 GPM, 1,610 PSI, 80 RPM, TRQ
ON 7K, TRQ OFF 5.5K, WOB 4-7K, Max Gas 196U. ECD 10.2 ppg. P/U 104K, SLK 73K, ROT 86K. MW 9.3 ppg. Running water at 50 bph.;Control drill 150
FPH F/ 2,678' to 2,806' MD (2 Stands CBU ea) to control ECD's F/ 10.35 ppg to 10.1 ppg. Holding 59° for tangent.;Rotate and slide 12.25" Surface F/ 2,960'
to 3,511' MD ( 2,468' TVD) Total 551' ( 91.8' AROP) 475 GPM, 1,360 PSI, 80 RPM, TRQ ON 9.3K, TRQ OFF 8.5K, WOB 7-8K, Max Gas 724U. ECD 9.94
ppg. P/U 113K, SLK 76K, ROT 90K. MW 9.3 ppg. Running water at 50 bph. Cont holding 59" for tangent.; Distance to WP#7 9.81', 4.52' High, 8.70' Right.
Slide Hrs 4.42. ROT His 7.98, total 12.40 Hm.;Hauled 1,211 bbls Fluid to MP G&1 total = 1,499 bbis
Hauled 1,300 bbls H2O from B -Pad Creek total = 2,340 bbls
Lost 15 bbls to formation Total fluid lost = 15 bbls
6/12/2019
Rotate and slide 12.25" Surface Fl 3,511' to 4,082' MD ( 2,761' TVD) Total 571'( 95.2' AROP) 515 GPM, 1,650 PSI, 80 RPM, TRQ ON 9.51K, TRQ OFF 9-
10K, WOE 3-6K, Max Gas 240U. ECD 10.12 ppg. P/U 125K, SLK 77K, ROT 92K. F/O 56%. MW 9.3 ppg. Running water at 50 bph. Cont holding 59" for
tangent.;Rotate and slide 12.25" Surface F/ 4,082' to 4,653' MD ( 3,060' TVD) Total 571' ( 95.2' AROP) 530 GPM, 1,738 PSI, 80 RPM, TRQ ON 11.81K, TRQ
OFF 12K, WOB 8K, Max Gas 201U. ECD 10.0 ppg. PIU 144K, SLK 79K, ROT 105K. F/058%. MW 9.3 ppg. Running water at 50 bph. Cont holding 59° for
F/4,653! to 5,229 MD ( 3,354' TVD) Total 576' (96' AROP) 530 GPM, 1,830 PSI, 80 RPM, TRQ ON 13.3K, TRO
tangent.;Rotate and slide 12.25" Surface
OFF 14-15K, WOB 8-10K, Max Gas 154U. ECD 10.0 ppg. P/U 150K, SLK 79K, ROT 108K. F/O 58%. MW 9.3 ppg. Running water at 50 bph. Cont holding
59° for tangent.; Rotate and slide 12.25" Surface FI 5,229' to 5,610' MD ( 3,540' TVD) Total 381' ( 63.5' AROP) 530 GPM, 2,040 PSI, 80 RPM, TRQ ON 13.4K,
TRQ OFF 13-14K, WOB 9K, Max Gas 492U. ECD 10.59 ppg. PIU 155K, SLK 81 K, ROT 106K. F/O 58%. MW 9.3 ppg. Running water at 50 bph. Cont
holding 59° for tangent.;Distance to WP#7 10.29', 6.01' High, 8.35' Right.
Slide Hrs 2.05. ROT Hrs 12.08, total 14.13 Hrs.;Hauled 1,096 bbis Fluid to MPG&I total = 2,595 bbis
Hauled 130 bbis H2O from L-Lake total = 130 bbis
Hauled 1,000 bbis H2O from B-Pad Creek total = 3,340 bbis
6/13/2019
Lost 15 bbis to formation Total fluid lost = 15 bible
Rotate and slide 12.25" Surface F/ 5,610' to 6,183' MD (3,84Y TVD) Total 573' ( 95.5' AROP) 530 GPM, 2,150 PSI, 80 RPM, TRQ ON 15.5K, TRQ OFF 14-
16K, WOB 8-16K, Max Gas 974U. ECD 10.24 ppg. P/U 166K, SLK 89K, ROT 116K. F/O 58%. MW 9.3 ppg. Running water at 50 bph. Cont holding 59° for
Vis High Vis sweep back as Calc W/ 25% increase at Shakers. with oil, clay and sand.;Rotate and
tangent.;At 5,745' MD Pumped 40 bbl 9.3 ppg 350 sweep,
slide 12.25" Surface F/ 6,183' to 6,502' MD ( 4,006' TVD) Total 319' ( 53.2' AROP) 530 GPM, 1,895 PSI, 80 RPM, TRQ ON 15.5K, TRQ OFF 14-16K, WOB
6,502'
8K, Max Gas 786U. ECD 10.0 ppg. P/U 170K, SLK 88K, ROT 118K. F/O 58%. MW 9.3 ppg. Running water at 50 bph. Cont holding 59° for tangent.;At
MD Pumped 45 bbl 9.3 ppg 380 Vis High Vis sweep, sweep back 31 bbis early W/5% increase at Shakers. with oil, clay and sand.; Rack back one stand F/
6,502' to 6,438' MD CBU 530 GPM, 1,810 PSI, 80 RPM, TRQ 16-18K, P/U 175K, SLK 88K, ROT 120K. Max Gas 285U. ECD 10.0 ppg. Wash back to 6,502'
MD. No increase seen at BU. Slight dynamic loss seen about 18 bbis lost, reduced pumps during moving string down slowed Iosses.;Rotate and slide 12.25"
Surface F/ 6,502'to 6,789 MD ( 4135' TVD) Total 287' ( 57.4' AROP) 540 GPM, 2,040 PSI, 80 RPM, TRQ ON 18-20K, TRQ OFF 18-20K, WOB 4-10K, Max
Gas 1,068U. ECD 9.95 ppg. P/U 188K, SLK 84K, ROT 119K. F/O 57%. MW 9.3 ppg. Running water at 50 bph.;Started build/ turn @ 6,499' MD with BY Inc,
198° Azi. 5°1109.;Rotate and slide 12.25" Surface F/ 6,789' to 7,076' MD ( 4,195' TVD) Total 287 (57.4! AROP) 530 GPM, 2,000 PSI, 80 RPM, TRQ ON 18-
OFF 17-19K, WOB 4-10K, Max Gas 1,068U. ECD 9.79 ppg. P/U 188K, SLK 82K, ROT 112K. F/O 56%. MW 9.2 ppg. Running water at 50
20K, TRQ
bph.;Reduced ROP due to build/turn. Build/ turn at 83° Inc, 198° Azi. 5"/100'.;Distance to WP#7 14.33', 5.8' Low, 13.10' Right.
Slide Hrs 5.44. ROT Hrs 6.66, total 12.10 Hrs.; Hauled 923 bbis Fluid to MP G&I total = 3,518 bbis
Hauled 1,300 bbis H2O from A-Pad reserve total = 1,300 bible
Hauled 0 bbls H2O from L-Lake total = 130 bbls
Hauled 0 bbis H2O from B-Pad Creek total = 3,340 bbls
Lost 18 bbis to formation Total fluid lost = 33 bbls
6/14/2019
Drill 12.25" Surface F/ 7,076' to 7,458' MD ( 4,247' ND) Total 382' ( 63.6' AROP) 530 GPM, 2170 PSI, 80 RPM, TRQ ON 17-20K, TRQ OFF 1860K, WOB
12-14K, Max Gas 380U. ECD 10.5 ppg. PIU 183K, SLK 78K, ROT 113K. F/O 57%. MW 9.35 ppg. Running water at 50 bph.;Drill 12.25" Surface F/ 7,458' to
7,909 MD ( 4,312' TVD) Total 451' (75.2- AROP) 530 GPM, 2160 PSI, 80 RPM, TRQ ON 17-18K, TRQ OFF 16-18K, WOB 12K, Max Gas 457U. ECD 10.28
ppg. P/U 186K, SLK 74K, ROT 115K. FIO 57%, MW 9.4 ppg. Running water at 50 bph. Pump tangent at 7,300' to 7,736' MD 83°.;Drill 12.25" Surface F/
7,909'to 8,191' MD (4,346 TVD) Total 282' (47' AROP) 530 GPM, 2049 PSI, 80 RPM, TRQ ON 19K, TRQ OFF 18-19K, WOE 5-7K, Max Gas 914U. ECD
9.98 ppg. P/U 188K, SLK 77K, ROT 116K. F/O 57%. MW 9.4 ppg. Running water at 50 bph.;Drill 12.25" Surface F/ 8,191' to 8,321' MD ( 4,355' TVD) Total
130' (65' AROP) 530 GPM, 2,062 PSI, 80 RPM, TRQ ON 18.8K, TRQ OFF 18.5K, WOE 7-81K, Max Gas 415U. ECD 10.1 ppg. P/U 187K, SLK 81 K, ROT
117K. F/O 57%. MW 9.35 ppg. Running water at 50 bph.;Slructural tops of OA and OBa ran -21' deep TVD to prognosis Landed in zone. Distance to WP#7
Hrs 8.84, total 12.39 Hrs.;PJSM BROOH racking back 2 stands CBU per stand F/ 8,321' to 8,159' MD,
24.13', 21.60' Low; 11.59 Right. Slide Hrs 3.55. ROT
580 GPM, 1,803 PSI, 60 RPM, 18.8K TRQ, Max Gas 737U. Pump 54 bbl 9.35 ppg 300+ Vis sweep. Rotate and reciprocate F/ 8,159' to 8,095' MD 580 GPM,
2,102 PSI, 60 RPM, TRQ 18.8K, Max Gas 225U. P/U 186K, SLK 77K, ROT 117K. FIG 58%.;Hauled 1,039 bbis Fluid to MP G&I total = 4,557 bbls
Hauled 780 bbis H2O from A-Pad reserve total = 2,080 bbls
Hauled 0 bbis H2O from L-Lake total = 130 bbls
Hauled 520 bbis H2O from B-Pad Creek total = 3,860 bbis
Lost 0 bbls to formation Total fluid lost = 33 bbis
6/1512019
Continue Pump 54 bbl 9.35 ppg 300+ Vis sweep to surface. Rotate and reciprocate F/ 8,159'to 8,095' MD 580 GPM, 2,102 PSI, 60 RPM, TRQ 18.8K, Max
Gas 225U. P/U 186K, SLK 77K. ROT 117K. F/O 58%. Sweep back on time with no notable increase at shakers. Wash 2 112 skis back to Btm 1/8095 to
8321'.;BROOH from 8,321' to 6,375'. GPM 600/2040 SPP, 80 RPM/16.5 TO, Max gas 403u. P/U 200K, SLK 90K, ROT 118K, Pulling 20-40 fpm. Work thru
tight spots until clean.;BROOH from 6,375' to 4,019. GPM 600, 1,820 PSI, 80 RPM, 9-11 K TRQ, Max gas 350U. Pulling 15-30 fpm. PIU 140K, SLK 79K,
ROT 100K. Work thru tight spots until clean.;Rotate and reciprocate F/ 4,019 to 3,955' MD pump 43 bbl 9.35 ppg 300+ Vis sweep at 600 GPM, 1,690 PSI, 80
RPM, 9.8K TRQ, Max Gas 150U. P/U 140K, SLK 79K, ROT 100K. Sweep back 24.8 bbls early with 30% increase of clay at Shakers.;BROOH from 4,019' to
2,300' MD. GPM 580, 1,480 PSI, 80 RPM, 5-7K TRQ, Max gas 80U. Pulling 101Vmin. PIU 103K, SLK 70K, ROT 83K. Work thru tight spots until clean. At
2,680' Reduced pulling 10 ft/min and flow to 580 GPM, 1,570 PSI and CBU due slight dynamic loss, ECD 10.19.;Saw increased cutting clay and gravel at
Shakers. Disp Calc 27.8 bbis, actual 38.8 bbis, Total 11.8 bbis lost.;BROOH from 4,019'to 771' MD. GPM 600, 1,375 PSI, 80 RPM, 4-5K TRQ, Max gas
ROT 70K. Pumped 43 bbls 9.4 300+ Vis Hi Vis sweep at 2,300' MD, 600 GPM, 1,450 PSI, 20% increase
111 U. Pulling 10-30 ft/min. P/U 75K, SLK 73K, ppg
sand clay.;Encountered tight spot at 2,162' and 2,100' MD work W/ 10.5 to 20K stall, 50.80 RPM, 550-600 GPM, 1,240-1,542 PSI pulling 27K over working
string. No packing off encountered. ROT 80K, ROT SLK 77K. Premafrost at 2,154'. Cont. without issue.;Hauled 676 bbis Fluid to MP G&I total = 5,233 bbls
Hauled 0 bbls H2O from A-Pad reserve total = 2,080 bbls
Hauled 0 bbis H2O from L-Lake total = 130 bbis
Hauled 780 bbis H2O from B-Pad Creek total = 4,640 bbls
Lost 32 bbls to formation Total fluid lost = 65 bbis
g
6/16/2019
Rack back 5" HWDP and Jars on Elevators F/ 771' to 148' MD. P/U 53K, Monitor well on Trip Tank. Static loss about 4 BPH.;PJSM C/O Tongs for BHA. LID
BHA as Sperry DD and MWD onsite. Download data F/ MWD. Bit Grade 1-3-LT-G-F-I-CT-TD Calc Disp 8.3 bbis, actual 30.2 bbis, Total lost 21.9 bbls. Monitor
well on trip tank, Static loss slowing from 4 BPH to 2 BPH. Lost 12 bbls.;Clean and clear rig floor of BHA components and rig tongs. Service rig and inspect
drilling line �PJSM for running 9 5/8" CSG P/U M/U Volant, bail ext., elevators, power longs and X/O. Stage 79 Centralizers. Static loss 2 BPH.;PJSM P/U M/U
Bakerloc Shoe, Float Collar and Baffle Adapter W/ By Pass as per Cc Rep onsite. M/U 9 5/8" 40# L-80 TXP BTC jnt and check Floats. Make up torque
20,960ft-lbs (Optimal), installing solid bow spring centralizers as per tally, filling a/ 5 joints. Static loss 2 BPH.;PJSM W/ all parties for running Csg. Cont. RIH
W/ Volant 9 518" 40# L-80 TXP BTC F/ 158'to 797' MD. Make up torque 20,960ft-lbs (Optimal). Installing solid bow spring centralizers as per tally. Filling
every 5 Jnts and breaking Circ every 15 Jnts.; Did not place centralizers on Jnts 12,13,14,15 (TD Depth 7,710' to 7,870' MD). Run speed 40 ft/min. Calc Disp
8.5 bbis, actual 0 bbis, total lost 8.5 bbls. Static loss 2 bph.;RIH W/ Volant 9 5/8" 40# L-80 TXP BTC F/ 797' to 2,389' MD. Make up torque 20,960ft-lbs
(Optimal). Installing solid bow spring centralizers as per tally. Filling every 5 Jnts and breaking Circ every 15 Jnts.;Calc Disp 35 bbls, actual -30 bbls, total lost
25 bbls. Static loss 2 bph. Slow Run speed F/ 40 to 20 ft/min due to pushing fluid away.;At 2,398' MD Work string and break Circ. CBU 2X staging pump rate
up F/ 2 bpm ICP 135 PSI to 7 BPM FCP 295 PSI. No dynamic losses seen. PIU 125K, SLK 80K. Heavy coagulated mud, clay and slight gravel seen at
Shakers, Circ, till hole was clean.;RIH W/ Volant 9 5/8" 40# L-80 TXP BTC F/ 2,389' to 2,508' MD. Make up torque 20,960ft-lbs. Installing solid bow spring
L
centralizers as per tally. Filling every 5 Jnts and breaking Circ every 15 Jnts. Calc Disp 10.7 bbls, actual 9.7 bbis, lost 1 bbl bbis. Static loss .5 bph. P/U 125K,
l/
SLK 80K.;RIH W/Volant 9 5/8" 40# L-80 TXP BTC F/ 2,508' to 4,542' MD. Makeup torque 20,960ft-lbs. Run speed 25 ft/min due to pushing fluid away.
Filling every 5 Jnts and breaking Circ every 15 Jnts. Calc Disp 24.2 bbls, actual 6.4 bbls, lost 17.8 bbl bbis. P/U 125K, SLK 80K.;At 4,542' MD Work string
and break Circ. for BU staging pump rate F/ 2 BPM to 7 BPM. 2 bpm ICP 260 PSI to 5 BPM 319 PSI. P/U 185K, SLK 88K.;Hauled 173 bbls Fluid to MP G&I
total = 5,406 bbls
Hauled 0 bbls H2O from A-Pad reserve total = 2,080 bbls
Hauled 0 bbls H2O from L-Lake total = 130 bbis
Hauled 260 bbls H2O from B-Pad Creek total = 4,800 bbls
Lost 25 bbis to formation Total fluid lost = 90 bbis
6/17/2019
At 4,542' MD Work string and break Circ. for BU staging pump rate F/ 2 BPM to 7 BPM. 2 bpm ICP 260 PSI to 7 BPM 280 PSI. F/O 49%. P/U 195K, SLK
I OOK. No losses.;RIH W/ Volant 9 5/8" 40# L-80 TXP BTC FI 4,542' to 6,334' MD. Make up torque 20,960ft-lbs. Run speed 20-35 ft/min due to pushing fluid
away. Filling every 5 Jnts and breaking Circ every 15 Jnts. Calc Disp 22.5 bbis, actual 48.7 bbls, lost 27.2 bbl bbis. P/U 258K, SLK 92K.; PJSM RIH W/
Volant 9 5/8" 40# L-80 TXP BTC F/ 6,334'to 6,569' MD. Make up torque 20,960ft-lbs. Run speed 25 ft/min due to pushing fluid away. Filling every 5 Jnts and
breaking Circ every 15 Jnts. P/U 258K, SLK 92K.;At 6,569' MD Work string and break Circ. for BU staging pump rate F/ 1 BPM to 7 BPM. 2 bpm ICP 260 PSI
to 7 BPM 440 PSI. F/O 45%. P/U 260K, SLK 110K. No dynamic losses.;PJSM RIH W/ Volant 9 5/8"40# L-80 TXP BTC F/ 6,569' to 8,312' MD. Make up
torque 20,960ft-lbs. Run speed 25 ft/min due to pushing fluid away. Filling every 5 Jnts and breaking Circ every 15 Jnts. Calc Disp 28.8 bbls, actual bbis,
lost 23.7 bbl bbls. P/U 330K, SLK 80K.;Break Circ staging up to 6 BPM, ICP 540 PSI FCP 350 PSI. Max Gas 153U. Condition Mud to X25 YP W/ 20 BPH
H2O. No Dynamic losses. SIMOPS RID Bail Ext, Elevators, Power Tongs, prep rig floor and pits for cement job. Flush thru 4" Conductor valve.;PJSM with all
parties for cement job. Blow down TD and cement lines. R/U Cement line to Volant.;HAL fill lines W/ 5 bbl H2O PT 1,248 PSI low, 4,000 PSI stall, 4000 PSI
high. HAL mix and pump 53 bbl 10.0 ppg Clean Spacer W/ Red Dye and 0.5 ppb Pol-E-Flake at 2.5 BPM, 250 PSI. Pump 334 bbl (763 sx) 12.0 ppg Type III
Lead at 6 bpm 530 PSI Short on lead by 15.3 bbls Pump 71 bbl (400 sx) 15.8 ova Class G T it at 3 BPM, 420 PSI. Short on Tail by 11.4 bbls. Shut down
disengage Volant and drop Shut Off Plug. Engage Volant and HAL pump 20 bbl H2O 5 bpm, 350 PSI. Switch to Rig, pump 248 bbls 9.3 ppg Spud Mud at
7bpm 520 PSI as of report time.; Hauled 576 bbis Fluid to MP G&I total = 5,982 bbis
Hauled 0 bbls H2O from A-Pad reserve total = 2,080 bible
Hauled 0 bbls H2O from L-Lake total = 130 bbls
Hauled 390 bbis H2O from B-Pad Creek total = 5,290 bbis
Lost 51 bbls to formation Total fluid lost = 141 bbis
6/18/2019
Rig pumped 398 bbls additional bbl 9.3 ppg Spud Mud at 6 bpm, 815 PSI. Hal pumped 80 bbis Spacer at 5 BPM, 796 PSI. Rig pumped 128 bbls at 4 BPM,
�
1090 PSI. Slow pumps to 2 bpm with 10 bbis to go FCP 1033 PSI.;Bump plug 7 bbis over calculated. Inc Press to 1300 PSI and hold for 5 minutes. Check
VV/
Floats good, bled back 2 bbls. CIP @ OT30 Lost 17 bbis during d'Splacamen+ Using rig pump, stage pressure up 2500 psi see ES Cginenter Open o
Returns at first, work pipe and establish returns @ 4bpm. Stage pump to Sbpm/1340 psi. CBU and bring all of spacer and 46 bbls Green CMT to surface.
Circulate 2 additional Btms Up, observing observe pressure drop to 630 psi while;maintaining full returns. Shut Down Pump. Flush Stack/Surface Equipment
with black water. Continue to Circulate thru stage tool while prepping for 2nd stage cement job @ 5 bpm/630 psi. Reduce surface volume in pits, heat rig
water.;PJSM 2nd stage cement job as per detail: HAL fill lines with 5 bbls H2O PT 1000 psi low, 4200 psi high -good. Pump 56 bbls 10.0 ppg Clean Spacer
with red dye at 5 bpm/490 psi, Pump 431.7 bbls 10.7 ppg Perm L lead cement at 7bpm/940 psi. observe cerrigal back at surface 273 bbis into lead Pump
56.2 bbis 15.8 gpa Class G tail cement at 3 5bpm/570 ns. Shut down and drop ESICP closing plug. HAL displace with 20 bbls H2O, rig displaced with 171.2
bbis 9.3 ppg spud mud at 5 bpm/920 psi. Reduce pump rate last 10 We to 3 bpm FCP 785psi bump plug (171.2 act/173.4 talc) and pressure up;to 2200 psi,
observe good indication of tool shifting close. Hold pressure for 3 minutes and bled back (1 bbl) tool confirmed closed. CIP 18:57. No losses ding cement
job, 406 bbls of cement/contaminate at surface.;Disconnect Knife valve from accumulator. Drain stack and flush with black water x 2 while cycling annular 3
times. Flush surface lines. RID chains on stack and deflate air boots. RID volant tool. Suck out casing joint for cut.;Disconnect diverter line. Lift stack, DSA
and adapter. Install 'E' slips and set 115K on slips. Set stack back down. Disconnect DSA. Lift stack and cut casing (30.56').;Set stack back dwon and air
upper boot. Install 5" DP elevators. Pick up stack washing tool, wash stack and clean flow box. Pull riser. Remove nuts on diverter T. SimOp: Continue
cleaning pits. Remove diverter counter weight and mat with crane. N/D diverter. Inspect saver sub. C/O Wash pipe.;Remove knife valve. P/U stack and set
back on pedestal. Remove riser adapter. Send diverter'T' out side door. Sim Ops: LID surface riser and master bushing, WOT elevators and slips. P/U split
bushings and riser for MPD.;Hauled 1889 bbls Fluid to MP G&I total = 7,871 We
Hauled 0 bbls H2O from A-Pad reserve total = 2,080 bbls
Hauled 0 bbls H2O from L-Lake total = 130 bbls
Hauled 1090 bbis H2O from B-Pad Creek total = 6,380 bbls
Lost 17 bbis to formation Total fluid lost = 158 bbls
6/19/2019
Install wellhead, set 9-5/8" slip lock head. Test voids 500/2470 psi (80% casing collapse) for 5/15 min. N/U tubing head. continue cleaning pits, bring test
plugs, wear ring and running tool to rig floor.;N/U BOPE: install DSA and torque. Prep stack to set: remove bell nipple adapter. Hoist MPD RCD above stack
and secure. Set slack on well head.;Cont. N/U SOPE. Set MPD head an annular and torque. Center stack. Remove MPD test cap. Hook up choke and kill
lines. Install drip pan. Install MPD hard lines. SimOps: wire tire retainer bolts for TD teflons. C/O pin on TO carriage extend frame. Cont. cleaning pits.;RIH
with stand of HWDP. Hang blocks. Remove deadman clamp and wraps from anchor. Spool line onto drum from drill line spooler bringing snake to rig floor.
Remove mechanical crown saver,;Cont. changing out drill line. Cut line and snake off drilling line. Un-spool old drilling line. Install mechanical crown saver.
Spool new drilling line on drum - 23 wraps. Re-wrap deadman and install anchor. Un-hang blocks. Calibrate travelling equipment.;Rig up to test BOPE. Set
test plug. Pick up and make up 5" test joint, side entry, TIW, Dart. Flood stack and purge lines. Tighten kill Iine.;Hauled 226 bbis Fluid to MP G&I total =
8,097 bbis
Hauled 0 bbls H2O from A-Pad reserve total = 2,080 bbls
Hauled 0 bbls H2O from L-Lake total = 130 bbls
Hauled 260 bbis H2O from B-Pad Creek total = 6,640 bbls
Lost 0 bbis to formation Total fluid lost = 158 bbis
6/20/2019
Test 135/8" stack along with associated equipment 250 low 13000 high on 5" lost joint w/ 5 min hold on each as per permit. Failed upper IBOP (Change out),
Failed manual kill (rebuild), Lower pipe rams had F/P. Test gas alarms - LEL 20/40%, H2S 10/20 ppm (test good).;Test PVT and flow paddle (test good).
Accumulator draw down: Initial 3000 psi, final 1550 psi, first 200 psi recharge 28 sec, final 94 seconds. (6) N2 bottles at 2350 psi ave. BOP test witnessed by
AOGCC rep Brian Bixby.;Set MPD test capon RCD. Flood lines and test MPD 25011500 psi. Remove test cap. Modify flow nipple.;Rebuild manual kill.
Remove saver sub, lower IBOP, Upper IBOP actuator and valve. Change out damaged actuator cam. Install new upper IBOP valve, install lower IBOP.;Install
saver sub. Torque Saver sub, lower and upper IBOP. Install compression clamps, M/U and Tq. to spec. Wire tie all bolts.;R/U test equipment. Flood lines
and purge. Test Upper IBOP and inside manual choke 250/3000 psi - good.;R/D testing equipment. drain TO and breakout test sub. Pickup test joint. Pull
test plug. Breakout TIW and dart. Install bell nipple. Blow down choke and kill lines. Set wear bushing.; Hauled 57 bbis Fluid to MP G&I total = 8,154 bbls
Hauled 0 bbis H2O from A-Pad reserve total = 2,080 bbis
Hauled 0 bbls H2O from L-Lake total = 130 bbis
Hauled 1300 bbls H2O from B-Pad Creek total = 6,770 bbis
Lost 0 bbls to formation Total fluid lost = 158 bbis
6/21/2019
M/U 8.5" drillout assy - 8.5 Smith XR+PS (milltooth), 6-3/4" mtr (.31 rev/gal) w/ 1.5° bend, 6 jts HWDP, SLB jars, 13 jts HWDP = 655' total length.;Trip in out
of derrick F/ 655' - T/ 2501' MD without issue. 101k up, 65k dn.;Wash down F/ 2501' to tag depth of 2520' MD. Drill cement (stringers) down to top of ESICP
(stg tool) @ 2545' MD. Drill stage tool and trip thru clean with no pump/rotary. Wash down to 2560' MD. Parameters - 400 gpm, 730 psi, 40 rpm, 5.5k tq,
k
56%, 4k wob.;Continue trip out of derrick F/ 256U -tag depth of 7915' MD w/ 9k set down. P/U and establish parameters 234k up, 56k dn.; Drill stringers and
h
green cement F/ 7915' - T/ 8170' MD. 500 gpm, 930 psi, 50 rpm, 20k tq, 58% Flow. Green cement seen at shakers @ btms up. Drilled @ 350-400 fph w/ 4-
k4`y
6k wob.;Circulate out green cement @ max rate of 588 gpm, 1130 psi, 50 rpm, 20k tq w/ 1.2x btms up.;R/U and test 9-518", 40# L-80 casing to 2500 psi w/ 30
min hold (lest good). 6 bbis pumped, 5 bbls bled back. Initial shut in psi 2,593 psi, 15 min psi @2.562, final psi @ 2,555. Chart and record same. See "O"
drive for test chart and form. Pressures read on digital gauge.;Svc rig. Replace manual elevators w/ hydraulic elevators.;Drill cement shoe track and 20' of new
hole from 8170' to 8341'. Tag upon float equipment on depth. 414 gpm/1020psi, 30rpms/19.5Kft-lbs, PUW 225K, SOW 68K, WOB 0-81K.; Displace to
Baradril-N drilling fluid, pump high vis spacer followed by new mud at 370gpm/ 720 psi. Circulate additional BU for even 8.9 ppg mud weight.;Rack back one
stand. Rig up to perform FIT. Flood and purge lines. Perform FIT to 700 Psi = 12.0 flog FMW_ 3 3 bbis. pumped 2.3 bbis bled back. Monitor well, static.
Obtain SPR's. Pump dryjob. Blow down choke/kill Iines.;POOH from 8291' to 3775' on elevators. PUW 187K, SOW 78K, calculated displacement.;Continue
to POOH from 3775'. UD 16 joints HWDP and BHA, Bit grade 1-1-NO-A-E-1-NO-BHA.;Clean and clear rig floor. Mobilize BHA components to floor.; Pickup
RSS drilling BHA. M/U 8-112" NOV PDC bit, NRP, Geopilot 7600 XL, ADR/HCIM, inline stab, DGR, PWD, DM collar TM Collar and float sub. Plug in.;Hauled
1155 bbis Fluid to MPG&I total = 9,309 bbls
Hauled 0 bbis H2O from A-Pad reserve total = 2,080 bbis
Hauled 0 bbis H2O from L-Lake total = 130 bible
Hauled 430 bbis H2O from B-Pad Creek total = 7,200 bbis
Lost 0 bbis to formation Total fluid lost = 158 bbis
6/22/2019
Continue M/U 8.5" RSS (HES 7600 Geo Pilot) w/ MWD-LWD assy. 2x NM flex DC, Float sub (no ported), 2x HWOP, SLB jars, ix HWDP = 275.06' total
length. Download MWD. Shallow pulse test MWD (test good). Break in Geo-Pilot w/ 10,20,30, & 40 rpms.;Trip in F/ 275'- T/ 2880' MD w/ 8.5" RSS picking
up 5", NC50, 19.5#, S-135 drill pipe from shed. Drift 3.125'. PUW 98K, SOW 69K.;Continue to Trip in F/ 2880'- T/ 4468' MD w/ 8.5" RSS picking up 5",
NC50, 19.5#, S-135 drill pipe from shed. Drift 3.125". PUW 123K, SOW 68K.;Trip in hole from 4468' to 8288' with 8.5" RSS with stands from derrick. Filling
pipe every 2509.;Pull riser. Install MPD rotating head. Center stack. Flood Iines.;Wash down to bottom at 8341', no issues. Drill 8-1/2' lateral from 8341' to
8416, total 75' (AROP 150 fph), 450 gpm/1300 psi, 60 rpms/18Kft-lbs on bottom, 17.4Kft-lbs off. WOB 6K. Max gas 485U, ECD 10.1 ppg with 8.9 ppg mud.
PUW 178K, SOW 78K, ROT 110K.;Drill 8-1/2" lateral from 8416'to 8989', total 573' (AROP 96 fph), 450 gpm/1420 psi, 140 rpms/16-23Kft-lbs on bottom,
18Kft-lbs off. WOB 10K. Max gas 2171U, ECD 10.53 ppg with 8.9 ppg mud. PUW 179K, SOW 54K, ROT 109K.;Drill 8-1/2" lateral from 8989' to 9559, total
570' (AROP 95 fph), 480 gpm/1554 psi, 150 rpms/22Kft-lbs on bottom, 23Kft-lbs off. WOB 5K. Max gas 2469U, ECD 10.5 ppg with 8.9 ppg mud. PUW
208K, SOW 53K, ROT 107K.;Distance to WP 7 24.28', 24.07' low, 3.12' Right. 15 concretions drilled so far for a total footage of 73' (6.2%). 57' Drilled in OB-1,
59' drilled in OB-2, 1067' drilled in OB-3.; Hauled 57 bbis Fluid to MP G&I total = 9,366 bbis
Hauled 0 bbis H2O from A-Pad reserve total = 2,080 bbls
Hauled 0 bbis H2O from L-Lake total = 130 bbis
Hauled 200 bbls H2O from B-Pad Creek total = 7,400 bbls
Lost 0 bbis to formation Total fluid lost = 158 bbis
6/23/2019
Drill 8-1/2" lateral from 9559to 10,269, total 701' (AROP 117 fph), 510 gpm/1810 psi, 150 rpms/22Kft-lbs on bottom, 22Kft-lbs off. WOB 7K. Max gas 2593U,
ECD 10.7 ppg with 9 ppg mud. PUW 208K, SOW 53K, ROT 107K. Backream 30' everystand.;Drill 8-1/2" lateral from 10,260' to 10,898', total 638' (AROP
106 fph), 540 gpm/2110 psi, 150 rpms/18Kft-Ibs on bottom, 17Kft-lbs off. WOB 8K. Max gas 2620U, ECD l l ppg with 9 ppg mud. PUW 157K, SOW 68K,
ROT 107K. Pump 45 bbl 15% lube pill @ 10,761' MD. Saw 4-6k drop in tq, 173k up, 57k do prior to;Drill 8-1/2" lateral from 10,898' to 11,663', total 735'
(AROP 123 fph), 540 gpm/2150 psi, 150 rpms/19Kft-lbs on bottom, 17Kft-lbs off. WOB 14K. Max gas 2506U, ECD 11.1 ppg with 9 ppg mud. PUW 152K,
SOW 65K, ROT 104K. Backream 30' every stand.;Drill 8-1/2" lateral from 11,663to 11,969', total 306' (AROP 102 fph), 540 gpm/2160 psi, 150 rpms/23.5Kft-
Ibs on bottom, 22Kft-lbs off. WOB 12K. Max gas 2723U, ECD 11.4ppg with 9 ppg mud. PUW 161K, SOW 50K, ROT 101K. Backream 30' every
stand.;Obtain final survey. Pump tandem low vis/high vis sweep (12 bbls late, 10% increase), circulate hole clean 4 x annular volume at 540gpm/2050 psi, 160
rpms/21000 ft-Ibs reciprocating pipe. Racking back stand 2 stands.;Distance to WP 7: 32.66', 32.52' High, 2.49' Right. 34 concretions drilled so far for a total
footage of 166'(4.5%). 1489' Drilled in 03-1, 207' drilled in OB-2, 1952' drilled in OB-3.;Hauled 462 bbis Fluid to MP G&I total = 9,828 bbis
Hauled 0 bbis H2O from A-Pad reserve total = 2,080 bbis
Hauled 0 bbis H2O from L-Lake total = 130 bbis
Hauled 660 bbis H2O from B-Pad Creek total = 8,060 bbls
Lost 0 bbis to formation Total fluid lost production = 0 bbls
6/24/2019
Circulate and condition hole (rot/recip pipe) @ TD (11,969' MD, 4194' TVD). 540 gpm, 2051 psi, 54% flow, 150 rpm, 21.8k to, 10.9 ECD w/ 9# MW.
Background gas dropped to negligible count after cleanup cycle. Slowly pull and rack back 2 stds during cleanup cycle (ending depth 11,840' MD).;Monkor well
@ 11,840' MD (static). Remove rotating head and install trip nipple.; Beckmann out of hole F/ 11.840'- T/ 8228' MD. 540 gpm, 1640 psi, 52% flow, 160 rpm,
17.2k tq, 9.9 ECD w/ 9# MW. Gas count negligible. 15 fpm pulling speed. Packoff at 8640', wipe through and slow pulling speed - good. Stop rotation and
pull into 9-5/8" shoe clean without issue.;Pump 40 bbl high vis sweep (on time 0% increase in cuttings) and circulate hole clean at 580 gpm/1830 psi, 55
rpms/12K ft-Ibs.;POOH on elevators from 8228' to 7970' - calculated fill. Pump dry job, blow down top drive and geo-span. Drop drift. Monitor well,
static.;Continue to POOH from 797U to 275'. Calculated hole fill.; Rack back HWDP. Retrieve drift on top of jars. Rack back jars and flex collars. Plug in and
download MW D. Pull MWD probe and install new probe. Rack back MWD. Breakout bit and UD Geo-Pilot. Bit grade 1-1-CT-N-X-I-NO-TD.;Clean and clear
rig floor.;Service rig; Grease TD, crown and blocks. Inspect TD extend frame. Check TD oil.;Change out pipe handling equipment. Rig up Weatherford power
tongs. M/U safety joint.;PJSM. P/U Float shoe, joint, drillable packoff and XO. RIH with 4-1/2" 13.5# L-80 625W predrilled liner to 968'. PUW 45K, SOW
44K.;Hauled 173 bbls Fluid to MPG&I total= 10,001 bbis
Hauled 0 bbis H2O from A-Pad reserve total = 2,080 bbis
Hauled 0 bbls H2O from L-Lake total = 130 bbls
Hauled 390 bbis H2O from B-Pad Creek total = 8,450 bible
Lost 0 bbls to formation Total fluid lost production = 0 bbls
6/25/2019
Continue running 4.5" 625 wedge pre drilled liner, 13.5#, L-80 F/ 968' - T/ 4,068' MD. P/U 70k, S/O 58k.;R/D 4.5" handling equipment. Redress power tongs
and R/U 2-3/8" handling equipment. False table, elevators and slips. M/U safety joint for 2-3/8" inner string. M/U slick stick, xo and 2 jts 2-3/8 PH6 drill pipe
to 74'.; Perform BOP drill. P/U 5" safety it w/ triple connect. M/U xo w/ swivel, M/U to inner string. PIU and remove false table and M/U triple connect to 4.5"
liner string. SIO and secure the well for drill.; Perform choke drill with both crews. Rotate out hands on choke. Practice staging pumps up (1.5and down while
holding choke psi @ 75 psi (100 psi max = .4 EMW). Post discussion with both crews.; UD safety it. Continue RIH w/ 2-3/8" PH6, 5.95# F/ 74' to landout
depth of 4038' (no go). Drift pipe = 1.66". 50k P/U, 44k S/O.;PJSM for PIU M/U MLZXP and MWD. Obtain slim hole MWD tool dimensions. Tagged 13' up on
Jnt 130. UD Jnts 130 & 129. Calc. space out W/ 10.36'(6.19'& 4.17' Pups) 7.72' off no/go, 6.28' stung in. P/U M/U Pups, X/O's, Swivel, MWD and
MLZXP.;Orientate MWD to MLZXP Helix RFO 4.72"/ 8.3"=204.73'. RID false rotary table. C/O handling Equip. RID Power Tongs. Inner and MLZXP P/U 55K,
SLK 48K.;PJSM RIH W/5" D.P. F/ Derrick F/ 4,119'to 4,406' MD. P/U 95K, SLK 75K. No Iosses.;PJSM Shallow hole test MWD tool. Max Press, set at 1,000
PSI due to Flex Lock set at 1,644 PSI. 42 GPM, 258 PSI, 84 GPM, 505 PSI, 125 GPM, 885 PSI. MWD tool had no detection less then 125 GPM, P/U 95K,
SLK 75K.;PJSM Cont. RIH W/ 5" D.P. and 4.5" Liner F/ 4,406' to 5,125' MD at 30 ft/min. Filling every 1,009. P/U 100K, SLK 78K.;PJSM Cont. RIH W/ 5"
D.P. and 4.5" Liner F/ 5,125' to 9,585' MD at 30-50 ft/min. Filling every 1,009. P/U prior to open hole, P/U 138K, SLK 82K. P/U 147K, SLK 92K.;Hauled 171
bbis Fluid to MPG&I total= 10,172 bbls
Hauled 0 bible H2O from A-Pad reserve total = 2,080 bbis
Hauled 0 bbis H2O from L-Lake total = 130 bible
Hauled 130 bbls H2O from B-Pad Creek total = 8580 bbis
Lost 0 bible to formation Total fluid lost production = 0 bbis
6/26/2019
Cont trip in hole w/ 4.5" predrilled 625W, 13.50, L-80 liner on 5" DP F/ 9,585' to 11,930' MD. 50-80 ft/min running speed. 154k UP, 78k SIO (pumps off).;Pick
up working single and wash down F/ 11,930' to tag depth of 11,969' MD. Orient TF to 20° LOHS while washing down. Work string slowly several times to
ensure TF and minimize chance of trapped downhole tq for upcoming displacement. Circulate @ 3 bpm, 1055 psi. Park string on depth @ 11,960' MD.;PJSM,
Displace 9.05 drilling fluid w/ 9.2 Brine. 3 BPM, 1050 psi (1100 psi max as per BOT rep to prevent premature setting of packer). Pump 40 bbl vis spacer, 3x
Sapp Pills during displacement.; PJSM Shut down and drop 1.625" down string. Pump ball on seat 1,487 stokes. Press up to 2,000 PSI and hold for 5 Min. Set
down 50K. Stage up 200 PSI in 1 min increments, at 2,350 PSI hydraulic setting tool set. Neutralizer sheared at 3,750 PSI.;Bleed off and pick up string
breaking over 144k. TOL at 7,852' MD. TF is 20° LOHS.;PJSM Test 9.625" X 5" IA and MLZXP. R/U test Equip and flood. Pumped 2.5 bbis to 1,500 PSI on
chart, hold for 10 min. Good. Bleed back 2.5 bible. RID test Equip and blow down choke manifold. Monitor well for 10 Min. Static.;PJSM POOH 5" D.P. racking
back in Derrick F/ 11,934' to 4,095' MD. P/U 145K, SLK 84K. Calc disp 67 bbls, actual 74 bbis. Lost 7 bbls.;PJSM Break down X/O's, MWD and liner running
tool as per Baker Rep onsite. P/U M/U 1 single joint 5" D.P. and triple connect to 2 318" inner string. Monitor well, static.;Service rig. Grease Crown, Blocks and
Top Drive. Obtain serial numbers on Crown sheaves.;PJSM Move MWD and NM FC from off driller side to driller side to make access to 5" D.P. RIH 2 3/8" W/
5" D.P. from Derrick F/ 4,058' to 10,418' MD. P/U 143K, SLK 88K. Took parameters before entering TOL at 7,852' MD PIU 108K, SLK 83K. Entered TOL
without issue. No Iosses.;Hauled 171 bbls Fluid to MP G&I total = 10,343 bible
Hauled 0 bible H2O from A-Pad reserve total = 2,080 bbis
Hauled 0 bbis H2O from L-Lake total = 130 bbis
Hauled 230 bbis H2O from B-Pad Creek total = 8,810 bbis
Lost 7 bbis to formation Total fluid lost production = 7 bbis
H
Well Name: MPE-42
Field:
County/State: Alaska
i (LAT/LONG):
evation (RKB):
API #:
Spud Date:
Job Name: MPU E42 Completion
Contractor
AFE #:
Hilcorp Energy Company Composite Report
Aroma:
Activity Date
Ops Summary
7/6/2019
Continue RIH with SLZXPILEM on 5" DP. Tag to of RAM r Too � 7$22' MD P11NL L37K, SOW105K. Set Dn 20K and PIU 10K over, work in and out x2 &
-Lin
confirm latch. Drop 1.375" Ball and Chase on seat at 5 bpm staging down to 1.5 bpm. W/ball on seat walk pressure up and see PKR set @ 2450 psi, shear
neutralizer @ 3100 psi. Release from PKR @ 3500 psi. Blow ball seat @ 4150 psi. P/U and confirm Release.,PT Casing to top of PKR to 1500 psi on chart for 10
min. Good Test. P/U 50' to confirm release form PKR. New TOL @ 7761.50.,Monitor well, Well static. Pump 15 bbl slug and chase with FW to flush pipe. R/U
Hawk Jaw. RID Manual Elevators and R/U Hyd Elevators. POOH UD DP from 7721'to 4255' MD. Lost 3 bbls.,Continue to UD DP f/4255 to surface. UD BOT
/1
1
SLZXP PKR running tool. Lost 6.6 bbls.,Drain Stack. Pull Wear bushing. RID hawk Jaw 7 remove from floor. Remove BOT tools.,C/0 Upper Pipe Rams fNBR's
, J
t 7 5/8" Solid body.,PJSM R/U test Equip. WU 7 5/8" test Jnt. Test Upper 7 5/8" Rams to 250 PSI low and 3,000 PSI high for 5 Min on chart. Good.,PJSM P/U
J
/U Weatherford tools and Equip. RN Torque Turn.,PJSM M/U Tie Back Assy to 7.625" 29.7# L-80 W521 and RIH to 851' MD. Torque Turn set 10,100 ft/Ib. P/U
54K, SLK 54K. Calc Disp 8.6 bbis, actual 6.8 bbis. Lost 1.8 bbls.,PJSM RIH Tie Back Assy on Z§25" 29.7# L-80 W521 F/ 851'to 4,885' MD. Torque Tum set
10,100 fVlb. P/U 126K, SLK 105K. Calc Disp 51 bbis, actual 46 bbis. Lost 5 bbls.,Hauled 0 bbis Fluid to MP G&I total = 5,105 bbis
Hauled 0 bbis H2O from A -Pad reserve total = 2,080 bbis
Hauled 0 bbis H2O from L -Lake total = 0 bbis
Hauled 0 bbis H2O from B -Pad Creek total =130 bbis
Lost 10 bola to formation Total fluid lost production= 319 bbis
Total Metal: 345#
7!7/2019
P/U and RIH w/ 7 5/8" Wedge 521, 29.7# L-80 casing f/ 4448' to 7763' MD (TOL). Lost 3 bbls.,Land on no go with Tag joint # 195, 18.50'in . Set down 10K verify
tag. UD jts. 195,194 & 193. M/U Space out pups (14.84')(14.86') and it 193 placing No -Go 3.38' off when landed. M/U Landing joint and Hanger. Land Hanger
as per NOS Rep onsite, XO landing jt to DP, M/U 5' DP Pup to landing jt, MtU Top Drive. PUW 165K, SOW 115K.,Rig up to reverse circulate. Close bag and
PT Annulus to 300 psi to ensure proper space out and seal engagement, strip up hole until pressure dumps, exposing seal ports to annulus. Using the Kill Line,
Establish reverse circulation through ported seals with fluid from rig pits. Line up on and pump 100 bbis Corrosion inhibited 9.2 ppg KCL 5 bpm/480 psi, Line up
on VAC Truck with DSL and Reverse in 60 bola DSL 4 bpm/500.,chase surface lines with 10 bbis Brine. Strip in hole and land out Tieback seals As 3.38' off
go w/ Mule Shoe @2 7769'. (TOL @ 7763') PU/SO 165k/1 15k. 82K on hanger.,Open lower annulus valve, Open bag, drain stack, RID Reversing equipment, Pull
& U 5' D 7 5/8" landing joint, MU pack off running tool to jt of DP. Land and test pack off to 500/5000 psi. 10 min ea. Rig up lest pump. Test 9-5/8" x 7-5/8"
annulus to1000 si for 30 minutes - ood. P mped 1 bbl, bled back 1 bbl. Rig down testing equipment.,Shut blinds. Bleed of accumulator. C/O UPR's from 7-
✓
5/8" SB to 2-7/8"x5.5" VBR's. Re-energize accumulator.,Pick up 2-7/8" TJ. Set test plug. Rig up testing equipment. Test UPR's on 2-7/8" test joint 250/3000 psi.
Had a leak on DS Ram Door. Tighten door. Pull test plug. UD test joint.,PJSM P/U R/U ESP and CAP Sheave. Pull ESP and 3/8" CAP through sheave to rig
floor. Spot and plug in spooling unit. R/U Weatherford tools and Equip. P/U M/U Baker ESP 5.85" Centralizer, Motor Gauge (Zenith) and 562XP Motor 400 HP as
per tally. Static loss rate 1.5 bph.,PJSM Cont. P/U M/U 5.13" Lower and Upper Tandem Seal, 5.38" Gas Separator, 538PMSXD Pump, 538PMSXD 93 Flex 47
HS Pump, Ported Discharge Head, Bolt on Discharge Head and 10'2 7/8" handling pup 90.51' MD. Attached Pothead to MTR Assy and Installed ESP
cable.,lnstalled 3/8" CAP to Check Valve on Centralizer. Ran Discharge 1/4" Press line F/ Sensor and terminate at discharge port. Perform initial ESP continuity
and press. reading test, good. MTR Clamp -4, Seal Clamp -4, Pump Clamps.,PJSM RIH ESP Pump, ESP round Cable and 3/8" CAP line W/ 2 718"6.5# L-80 EUE
8rd F/ 90.51' to 569' MD. XN between Jnt 1 & 2, GLM W/ Dummy Valve between Jnt 4 & 5. PN 40K, SLK 40K. Install Cannon Clamps every Jnt for ESP and
CAP. Weatherford TRO to 2,300 fl/Ib. Lost 6 bbis for tower.,Hauled 228 bbls Fluid to MP G&I total = 5,333 bbis
Hauled 0 bbis H2O from A -Pad reserve total = 2,080 bbis
Hauled 0 bbis H2O from L -lake total = 0 bbis
Hauled 0 bbis H2O from B -Pad Creek total =130 bbis
Lost 12 bbls to formation Total fluid lost production = 331 bola
Total Metal: 345#
7/8/2019
PJSM RIH ESP Pump, ESP round Cable and 3/8" CAP line W/ 2 7/81'6.5# L-80 EUE 8rd F/ 569'to 2,155' MD. P/U 48K, SLK 45K. Install Cannon Clamps every
Jnt for ESP and CAP. Weatherford TRQ to 2,300 Mb. Lost 6.5 bbls. At 725' MD pinched CAP line in TO Cradle during P/U Jnt. Spliced and tested CAP. Test
ESP and CAP every 1,000'.,PJSM RIH ESP Pump, ESP round Cable and 3/8" CAP line W/ 2 7/8" 6.5# L-80 EUE 8rd F/ 2,155'to 7,637' MD, P/U 76K, SLK 58K.
Install Cannon Clamps every other JIM at 2,155' MD for ESP and CAP. Weatherford TRQ to 2,300 f llb. Lost 1.5 bbls. Fill 2 7/8', Test ESP and CAP every
2,000'.,M/U GLM 1" Side Pocket KBMM W/ DPSOV between Jnts 245 & 246 as per tally. SIMOPS Fill in subsiding area around cellar box under Mat
Boards.,PJSM At 7,637' P/U M/U Tubing Hanger W/ 2 7/8" landing joint. Baker terminate ESP and CAP lines. Splice penetrator plug to ESP cable. M/U CAP to
Hanger penetration. Total Cannon Clamps = 162, Motor Clamps = 4, Deal Clamps = 4 and Pump Clamps 6. SIMOPS lower ESP and CAP line to Spooler.,PJSM
Cont W/ ESP splice. Baker check continuity on ESP after installing to Penetrator. Drain stack and land hanger as per NOS Rep onsite. ESP at 7,666' MD. RILDS.
•
Set BPV. Baker checked continuity on ESP after landing, good. P/U 73K, SLK 54K. Weight in Wellhead 19K.,PJSM L/D running tools. Remove sheave from
Derrick. Start flushing all surface llnes,TD and Stack. Start loading 5" D.P. in Pipe Shed.,PJSM N/D BOPE. Remove Riser, Choke and Kill Lines. Install RCD
Plug. R/D Beyond hard lines. SIMOPS Start cleaning Pits. Cont loading 5" D.P.,Hauled 25 bbls Fluid to MP G&I total = 5,358 bbis
Hauled 0 bbls H2O from A-Pad reserve total = 2,080 bbls
Hauled 0 bbis H2O from L-Lake total = 0 bbis
Hauled 0 bbls H2O from B-Pad Creek total =130 bbis
Lost 14 bbis to formation Total fluid lost production = 345 bbis
Total Metal: 345#
7/9/2019
Cont. to N/D BOPE. raise MPD rotating head with top drive. R/U bridge cranes. Remove safety chains. N/D and set BOP stack on stump. Lower rotating head.
Remove DSA. Install tree flange and master valve. Test tubing void 500/5000 psi - good. SimOps: finish cleaning pits. B/D steam and water. R/D pits
interconnect. R/D tongs. Lay mats and herculite for E-39.,Bridle up and scope derrick down. Went on Gen power at 14:30. Start jacking up Mods. Peak trucks
on location at 17:OO.,Pull mods away from sub base. Jack up sub base and remove rig mats to fill in subsiding area around cellar. Spot mats. Walk sub base off
E-42. Attach steering arm to sub tires. Sim Ops: inspect mud pump 2. Change out Geo-Spans in lower utilidoor. Release Rig from MP E-42 at 0:00 7/10/19.
Final report for E42.,Hauled 554 bbis Fluid to MP G&I total = 5,912 bbis
Hauled 0 bbis H2O from A-Pad reserve total = 2,080 bbis
Hauled 0 bbis H2O from L-Lake total = 0 bbis
Hauled 0 bbis H2O from B-Pad Creek total =130 bbls
Lost 0 bbis to formation Total fluid lost production = 345 bbis
Total Metal: 345#
Hilcorp Alaska, LLC
Milne Point
MPtEPad
MPU E-42
500292363500
Sperry Drilling
Definitive Survey Report
27 June, 2019
FiALLIBURTON
Sperry Drilling
Halliburton
Definitive Survey Report
Company:
Hilcorp Alaska, LLC
Local Co-ordinate Reference:
Well Rig: MPU E42
Project:
Milne Point
TVD Reference:
MPU E42 Actual RKB @ 48.43usft (Innovation)
Site:
M Pt E Pad
MD Reference:
MPU E42 Actual RKB @ 48.43usft (Innovation)
Well:
Rig: MPU E-42
North Reference:
True °
Wellbore:
MPU E42
Survey Calculation Method:
Minimum Curvature
Design:
MPUE42
Database:
NORTH US+CANADA
Project
Milne Point, ACT, MILNE POINT
11,899.06 MPU E42 MWD+IFR2+MS+Sag (2) (MP
2_MWD+IFR2+MS+Sag
Map System:
US State Plane 1927 (Exact solution) •
System Datum:
Mean Sea Level
Geo Datum:
NAD 1927 (NADCON CONUS)
(ft)
Using Well Reference Point
Map Zone:
Alaska Zone 04
0.00
Using geodetic scale factor
-21.50
0.00
0.00
6,016,241.23
Well
Rig: MPU E-42, Dual Let
0.00
UNDEFINED
Well Position
+N/5 0.00 usft Northing:
6,016,241.23 usft
Latitude: 70° 27'17.033 N
51.57
+E/ -W 0.00 usft Easting:
569,137.72 usft
Longitude: 149'26'8.887W
Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft
Ground Level: 21.50 usft
-0.05
2_Gyro-NS-GC_Drill collar (1)
165.00
0.180
Wellbore
MPU E-42
116.57
0.13
Magnetics
Model Name Sample Date
Declination
Dip Angle Field Strength
-0.14
2_Gyro-NS-GC_Dnll collar (1)
228.00
0.250
312.78
BGGM2018 7/5/2019
16.63
80.96 57,424.40945014
Design
MPU E-42
569,137.60
0.11
Audit Notes:
2 Gyro-NS-GC_Dnll collar(1)
291.00
0.420
Version:
1.0 Phase:
ACTUAL Tie On Depth: 26.93
Vertical Section:
Depth From (TVD)
-N/-S +PJ -W
Direction
0.27
(usft)
(usft) (usft)
(°)
1.640
26.93
0.00 0.00
193.90
Survey Program
Date 6/2412019
From
To
Map
Map
(usft)
(usft) Survey (Wellbore)
Tool Name
Description
Survey Date
100.00
603.00 MPU E42 SDI Gyro (MPU E42)
2_Gyro-NS-GC_Drill collar
H029Ga: North seeking single shot in drill collar
06/05/2019
668.47
8,281.05 MPU E42 MWD+IFR2+MS+Sag(1)(MP
2_MWD+IFR2+MS+Sag
A013Mb: IIFR dec & multi -station analysis +sag
06/11/2019
8,343.89
11,899.06 MPU E42 MWD+IFR2+MS+Sag (2) (MP
2_MWD+IFR2+MS+Sag
A013Mb: IIFR dec&multi-station analysis +sag
06/17/2019
Survey
6272019 4:44:11PM Page 2 COMPASS 5000.15 Build 91
Map
Map
Vertical
MD
Inc
Azi
TVD
TVDSS
+N/ -S
+FJ -W
Northing
Easting
DIS
Section
(usft)
(')
(°)
(usft)
(usft)
(usft)
(usft)
(ft)
(ft)
(°/tool
(ft)
Survey Tool Name
26.93
0.000
0.00
26.93
-21.50
0.00
0.00
6,016,241.23
569,137.72
000
0.00
UNDEFINED
10000
0.120
65.42
100.00
51.57
0.03
0.07
6,016,241.26
569,137.79
0.16
-0.05
2_Gyro-NS-GC_Drill collar (1)
165.00
0.180
310.79
165.00
116.57
0.13
0.05
6,016,241.36
569,137.77
0.39
-0.14
2_Gyro-NS-GC_Dnll collar (1)
228.00
0.250
312.78
228.00
179.57
0.28
-0.12
6,016,241.51
569,137.60
0.11
-0.25
2 Gyro-NS-GC_Dnll collar(1)
291.00
0.420
WT78
291.00
242.57
0.52
-0.41
6,016,241.75
569,137.31
0.27
-0.41
2_Gyrc-NS-GC_Dn1l collar (1)
353.00
1.640
231.20
352.99
304.56
0.10
-1.28
6,016,241.32
569,136.44
2.57
0.21
2_ Gyro-NS-GC_Dnll.0ar(1)
41600
4.250
220.90
415.90
367.47
-2.23
-0.51
6,016,238.97
569,134.23
4.21
3.00
2_Gyro-NS-GC_DHll Collar (1)
47800
6.440
221.40
477.63
429.20
6.57
-7.31
6,016,234.59
569,130.47
3.53
8.14
2_Gyro-NS-GC_DHll collar (1)
540.00
8.540
220.76
539.09
490.66
-12.67
-12.62
6,016,228.45
569,125.22
3.39
15.33
2_Gyro-NS-GC_DHll collar (1)
603.00
9.830
221.43
601.29
552.86
-20.24
-19.23
6,016,220.81
569,118.68
2.05
24.27
2_Gyrc-NS-GC_DH1l collar(1)
668.47
11.480
219.93
665.62
617.19
-29.43
-27.11
6,016,211.55
569,110.89
2.56
35.08
2_MWD+IFR2+MS+Sag(2)
729.76
11.880
220.53
725.65
677.22
-38.90
-35.12
6,016,202.01
569,102.96
0.68
46.20
2_MWD+IFR2+MS+Sag(2)
6272019 4:44:11PM Page 2 COMPASS 5000.15 Build 91
Halliburton
Definitive Survey Report
Company:
Project:
Site:
Well:
Wellbore:
Design:
Hilcorp Alaska, LLC
Milne Point
M Pt E Pad
Rig: MPU E-42
MPU E-42
MPU E-42
Local Coordinate Reference:
TVD Reference: -
MD Reference:
North Reference:
Survey Calculation Method:
Database:
Well Rig: MPU E-42
MPU E-42 Actual RKB @ 48.43usft (Innovation)
MPU E-42 Actual RKB @ 48.43usft (Innovation)
True
Minimum Curvature
NORTH US +CANADA
Survey
Map
Map
Vertical
MD
Inc
Azi
TVD
TVDSS
+N/S
+E/ -W
Northing
Easting
DLS
Section
(usft)
0
(')
(usft)
(usft)
(usft)
(usft)
(ft)
(ft)
(°/100')
(ft) Survey Tool Name
792.38
13.920
215.38
786.68
738.25
49.94
43.68
6,016,190.89
569,094.51
3.74
58.97 2_MWD+1FR2+MS+Ssg(2)
857.25
16.800
209.63
849.23
800.80
-64.46
-52.83
6,016,176.29
569,085.49
5.02
75.26 2_MWD+1FR2+MS+Sag(2)
920.91
19.460
207.02
909.73
861.30
-81.91
-62.20
6,016.158.76
569,076.29
4.37
94.45 2_MWD+IFR2+MS+Sag(2)
98460
20.830
206.10
969.52
921.09
-101.53
-72.00
6,016,139.05
569,066.67
2.21
115.65 2_MWD+IFR2+MS+Sag(2)
1,049.15
24.270
204.00
1,029.13
980.70
-123.96
-82.45
6,016,116.52
569,056.43
5.47
140.14 2_MWD+1FR2+MS+Sag(2)
1,113.10
26.560
202.89
1,086.89
1,03846
-149.14
-93.36
6,016,091.24
569,045.76
3.66
167.20 2_MWD+1FR2+MS+Ssg(2)
1,177.05
31A10
201.68
1,142.92
1,094.49
-177.64
-105.01
6,016,062.65
569,034.37
7.02
197.88 2_MWD+IFR2+MS+Sag(2)
1,240.07
34.640
200.46
1,195.87
1,147.44
-209.51
-117.27
6,016,030.66
569,022.41
5.85
231.55 2_MWD+IFR2+MS+Sag(2)
1,303.41
38.730
198.69
1,246.65
1,198.22
-245.16
-129.92
6,015,994.89
569,010.09
6.67
269.20 2_MWD+IFR2+MS+Sag(2)
1,367.02
43.080
197.63
1,294.72
1,246.29
-28494
-142.88
6,015.955.21
568,997.50
6.92
310.72 2_MWD+IFR2+MS+Sag(2)
1,430.27
44.170
197,95
1,340.50
1,292.07
-326.29
-156.22
6,015,913.54
568,984.55
1.76
354.26 2_MWD+IFR2+MS+Sag(2)
1,494.48
47.010
198.36
1,385.43
1,337.00
-369.87
-170.51
6,015,869.83
568,970.67
4.45
400.00 2_MWD+IFR2+MS+Sag(2)
1,557.55
47.170
198.77
1,428.37
1,379.94
413.66
-185.22
6,015,825.91
568,956.37
0.54
446.04 2_MWD+IFR2+MS+Sag(2)
1,621.14
47.650
199.10
1,471.41
1,422.98
457.94
-200.41
6,015,781.50
568,941.59
0.85
492.67 2_MWD+IFR2+MS+Sag(2)
1,684.77
50.400
198.96
1,513.13
1,464.70
-503.35
-216.07
6,015,735.95
568,926.35
4.33
540.52 2_MWD+IFR2+MS+Sag(2)
1,749.15
52.260
198.71
1,553.35
1,50492
-550.92
-232.30
6,015,688.23
568.910.57
2.90
590.59 2_MWD+IFR2+MS+Sag(2)
1,812.58
54.300
198.49
1,591.28
1,542.85
-599.11
-248.51
6,015,639.90
568,894.80
3.23
641.26 2_MWD+IFR2+MS+Sag(2)
1,874.88
56.620
198.08
1,626.60
1,578.17
-647.83
-264.61
6,015,591.03
568,879.16
3.76
69243 2_MWD+IFR2+MS+Sag(2)
1,939.92
57.730
197.87
1,661.85
1,613.42
-699.82
-281.47
6,015,538.90
568,862.78
1.73
746.94 2_MWD+IFR2+MS+Sag(2)
2,004.37
58.080
197.99
1,696.10
1,647,67
-751.77
-298.28
6,015,486.80
568.846.45
0.57
80141 2_MWD+IFR2+MS+Sag(2)
2,067.46
56.390
196.55
1,730.24
1,681.81
-802.42
-314.04
6,015,436.01
568,831.17
3.30
854.36 2_MWD+1FR2+MS+Sag(2)
2,130.86
56.230
196.37
1,765.41
1,716.98
.853.01
-328.99
6,015,385.28
568,816.70
0.35
907.06 2_MWD+IFR2+MS+Sag(2)
2,194.94
57.770
197.17
1,800.31
1,751.88
-904.46
-344.49
6,015,333.69
568,801.67
2.62
960.73 2_MWD+IFR2+MS+Sag(2)
2,258.70
57.690
197.05
1,834.35
1,785.92
-955.99
-360.36
6,015,282.03
568,786.28
0.20
1,014.56 2_MWD+IFR2+MS+Sag(2)
2,320.87
58.680
197.84
1,867.03
1,818.60
-1,006.44
-376.21
6,015,231.44
568,770.90
2.20
1,067.35 2_MWD+IFR2+MS+Sag(2)
2,385.63
57.330
198.30
1,901.25
1,852.82
-1,058.71
-393.26
6,015,179.02
568,754.33
2.47
1,122.18 2_MWD+IFR2+MS+Sag(2)
2,449.12
58.970
198.60
1,934.75
1,886.32
-1,109.87
410.33
6,015,127.71
568,737.74
2.61
1,175.94 2_MWD+IFR2+MS+Sag(2)
2,513.13
59.570
199.22
1,967.46
1,919.03
-1,161.92
428.16
6,015,075.50
568,720.40
1.25
1,230.75 2 MWD+IFR2+MS+Sag(2)
2,576.48
61350
199.29
1,998.69
1,950.26
-1,213.95
-446.34
6,015,023.31
568,702.71
2.81
1,285.62 2_MWD+IFR2+MS+Sag(2)
2,639.95
60.790
199.62
2,029.40
1,980.97
-1,266.33
464.84
6,014,970.77
568,684.69
0.99
1,340.91 2_MWD+IFR2+MS+Sag(2)
2,703.65
60.170
200.38
2,060.78
2,012.35
-1,318.41
483.80
6,014,918.51
568,666.22
1.42
1,396.03 2_MWD+IFR2+MS+Sag(2)
2,766.87
57.770
20027
2,093.37
2,044.94
-1,369.21
502.61
6,014,86255
568,647.88
3.80
1,449.86 2_MWD+IFR2+MS+Sag(2)
2,831.08
60350
200.26
2,126.38
2,077.95
-1,420.67
-521.69
6,014,815.72
568,629.29
4.02
1,504.59 2_MWD+IFR2+MS+Sag(2)
2,894.74
60.500
200.35
2,157.80
2,109.37
-1,472.79
540.90
6,014,763.62
568,610.56
0.27
1,559.61 2_MWD+IFR2+MS+Sag(2)
2,958.25
61.110
198.72
2,188.78
2,140.35
-1,525.04
-559.44
6,014,711.21
568,592.51
2.44
1,614.78 2_MWD+IFR2+MS+Sag(2)
3,021.82
60.340
198.32
2,219.87
2,171.44
-1,577.62
-577.05
6,014,658.47
568,575.39
1.33
1,670.05 2_MWD+IFR2+MS+Sag(2)
3,085.63
60.270
198.16
2,251.48
2,203.05
-1,630.27
-594.40
6,014,605.67
568,558.53
0.24
1,725.32 2_MWD+IFR2+MS+Sag(2)
3,148.98
59.370
197.83
2,283.32
2,234.89
-1,682,35
-611.32
6,014,553.44
568,542.10
1.49
1,779.94 2_MWD+IFR2+MS+Sag(2)
3,212.81
57.820
198.45
2,316.58
2,268.15
-1,734.12
-628.28
6,014,501.52
568,525.62
2.57
1,834.27 2_MWD+IFR2+MS+Sag(2)
3,276.35
59.740
198.52
2,349.52
2,301.09
-1,785.65
-645.50
6,014,449.83
568,508.87
3.02
1,888.43 2MWD+1FR2+MS+Sag(21
6/27/2019 4:44:11PM
Page
3
COMPASS 5000.15 Build 91
Halliburton
Definitive Survey Report
Company:
Project:
Site:
Well:
Wellbore:
Design:
Hilcorp Alaska, LLC
Milne Point
M Pt E Pad
Rig: MPU E-42
MPU E-42
MPU E-42
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Database:
Well Rig: MPU E-42
MPU E-42 Actual RK6 @ 48.43usft (Innovation)
MPU E-42 Actual RKB @ 48.43usft (Innovation)
True
Minimum Curvature
NORTH US+CANADA
Survey
Map
Map
Vertical
MD
Inc
Azi
TVD
T/DSS
+N/ -S
+E! -W
Northing
Easting
DLS
Section
(usft)
(°)
(1)
(usft)
(usft)
(usft)
(usft)
(ft)
(ft)
(-1100-)
(ft) Survey Tool Name
3,339.94
59.050
198.57
2,381.89
2,333.46
-1,837.54
-662.91
6,014,397.79
568,491.95
1.09
1,942.98 2_MWD+IFR2+MS+Sag(2)
3,403.24
59.290
198.74
2,414.33
2,36590
-1,889.04
-680.30
8,014,346.14
568,475.04
0.44
1,997.15 2_MWD+IFR2+MS+Sag(2)
3,467.48
59.970
199.35
2,446.81
2,398.38
-1,941.43
-698.38
6,014,293.59
568,457.45
1.34
2,052.35 2_MWD+IFR2+MS+Sag(2)
3,531.39
59.650
198.73
2,478.95
2,430.52
-1,993.65
-716.41
6,014,241.21
568,439.91
0.98
2,107.37 2_MWD+IFR2+MS+Sag(2)
3,595.28
59.000
199.13
2,511.54
2,463.11
-2,045.63
-734.23
6,014,189.07
568,422.57
1.15
2,162.11 2_MWD+IFR2+MS+Sag(2)
3,659.17
57.760
19884
2,545.04
2,496,61
-2,097.07
-751.93
6,014,137.47
568,405.35
1.98
2,216.30 2_MWD+IFR2+MS+Sag(2)
3,722.71
59.100
198.90
2,578.30
2,529.87
-2,148.30
-769.44
6,014,08609
568,388.32
2.11
2,270.23 2_MWD+IFR2+MS+Sag(2)
3,786.56
59.050
199.17
2,611.12
2,56269
-2,200.08
-787.30
6,014,034.15
568,370.94
0.37
2,324.78 2_MWD+IFR2+MS+Sag(2)
3,85003
58.770
200.07
2,643.89
2,595.46
-2,251.27
-805.55
6,013,982.79
568,353.17
1.29
2,378.86 2_MWD+IFR2+MS+Sag(2)
3,913.72
59.630
198.18
2,676.51
2,628.08
-2,302.96
-823.47
6,013,930.95
568.335.73
2.88
2,433.34 2_MWD+IFR2+MS+Sag(2)
3,978.01
59.900
197.84
2,708.88
2,660.45
-2,355.78
-840.65
6,013,877.97
568,319.05
0.62
2,488.74 2_MWD+IFR2+MS+Sag(2)
4,041.17
59.340
198.15
2,740.82
2,69239
-2,407.60
-857.48
6,013,826.00
568,302.70
0.98
2,543.09 2_MWD+IFR2+MS+Sag(2)
4,104.31
58.280
198.38
2,773.52
2,72509
-2,458.89
-874.41
6,013,774.56
568,286.25
1.71
2,596.95 2_MWD+IFR2+MS+Sag(2)
4,168.21
58.920
198.72
2,806.81
2,758.38
-2,510.60
-891.76
6,013,722.70
568,269.38
1.10
2,651.31 2_MWD+IFR2+MS+Sag(2)
4,231.85
58.260
198.96
2,839.98
2,791.55
-2,562.01
-909.30
6,013,671.14
568,252.32
1.09
2,705.42 2_MWD+1FR2+MS+Sag(2)
4,295.51
58.680
199.39
2,873.27
2,824.84
-2,613.26
A27.12
6,013.619+73
568,234.98
0.88
2,759.45 2_MWD+IFR2+MS+Sag (2)
4,359.66
58.150
199.33
2.906.87
2,858.44
-2,664.81
-945.24
6,013,568.01
568,217.34
0.83
2,813.85 2_MWD+IFR2+MS+Sa9(2)
4,423.27
59.220
498.64
2,939.93
2,891.50
-2,716.20
-962.91
6,013,516.47
568,200.14
1.92
2,867.98 2_MWD+IFR2+MS+Sag(2)
4,487.40
58.860
198.24
2,972.92
2,924.49
-2,768.37
-98031
6,013,464.15
568,183.24
0.78
2,922.80 2_MWD+IFR2+MS+Sag(2)
4,550.98
59.060
198.63
3,005.70
2,957.27
-2,820.05
-997.53
6,013412.31
568,16649
0.61
2,977.10 2_MWD+IFR2+MS+Sag(2)
4,614.50
56.860
199.10
3,039.40
2,990.97
-2,871.00
-1,014.94
6,013,361.21
568,149.56
3.52
3,030.74 2_MWD+IFR2+MS+Sag(2)
4,677.75
58.850
198.61
3,073.05
3,02462
-2,921.68
-1,032.24
6,013,310.38
568,132.73
3.21
3,084.09 2_MWD+IFR2+MS+Sag(2)
4,741.46
59.120
198.68
3,105.88
3,057.45
-2,973.41
-1,049.70
6,013,258.49
568,115.75
0.43
3,138.51 2_MWD+IFR2+MS+Sag(2)
4,805.42
59.530
196.59
3,138.51
3,090.08
-3,025.54
-1,D67.28
6,013,206.20
568,098.66
0.65
3,193.33 2_MWD+IFR2+MS+Sag(2)
4,869.03
58.340
199.25
3,171.33
3,122.90
-3,077.08
-1,084.94
6,013,154.50
568,081.48
2.07
3,247.61 2_MWD+IFR2+MS+Sag(2)
4,932.88
59.680
198.26
3,204.21
3,155.78
-3,128.91
-1,102.54
6,013,102.52
568,064.37
2.48
3,302.15 2_MWD+IFR2+MS+Sag(2)
4,995.97
59.140
198.56
3,236.31
3,18288
-3,180.44
-1,119.69
6,013,050.84
568,047.70
0.95
3,356.29 2_MWD+IFR2+MS+Sag(2)
5,080.18
59.130
198.37
3,269.26
3,220.83
-3,232.72
-1,137.15
6,012,998.40
568,030.73
0.25
3,411.23 2_MWD+IFR2+MS+Sag(2)
5,124.30
59.460
198.78
3,302.00
3,253.57
-3.284.98
-1,154.71
6,012,945.99
568,013.65
0.75
3.466.18 2_MWD+IFR2+MS+Sag(2)
5,187.84
59,410
199.10
3,334.31
3,285.88
-3,336.73
-1,172.47
6,012,894.08
567,996.38
0.44
3,520.68 2 MWD+IFR2+MS+Sag(2)
5.251.05
61.120
197.82
3,365.66
3,31223
-3,386.79
-1,189.84
6,012,841.87
567,979.49
3.23
3,575.39 2_MWD+IFR2+MS+Sag(2)
5,314.67
61.050
197.51
3,396.42
3,347.99
-3,441.85
-1206.74
6,012,788.66
567,963.08
0.44
3,630.95 2_MWD+IFR2+MS+Sag(2)
5,378.25
61.470
197.32
3,426.99
3,378.56
-3,495.04
-1,223.42
6,012,735.32
567.946.90
0.71
3,686.60 2_MWD+IFR2+MS+Sag(2),
5,442.06
61.840
197.91
3,457.29
3,408.86
-3,548.57
-1,240.42
6,012,681.64
567,930.40
1.00
3,742.64 2_MWD+IFR2+MS+Sag(2)
5,505.96
61.010
198.09
3,487.85
3,439.42
-3,601.94
-1,257.76
6,012,628.12
567,913.56
1.32
3,798.61 2_MWD+IFR2+MS+Sag(2)
5,569.28
59.560
198.05
3,519.24
3,470.81
-3,654.22
-1,274.82
6,012,575.69
567,896.99
2.29
3,853.46 2_MWD+IFR2+MS+Sag(2)
5,633.03
58.330
197.61
3,552.12
3,503.69
-3,706.21
-1,291.54
6,012,523.55
567,880.75
2.02
3,907.94 2 MWD+IFR2+MS+Sag(2)
5,897.02
58.480
198.00
3,585.65
3,537.22
-3,758.10
-1,308.21
6,012,471.51
567,884.56
0.57
3,962.32 2_MWD+IFR2+MS+Sag(2)
5,760.39
59.240
198.11
3,618.42
3,569.99
-3,809.67
-1,325.02
6,012,419.79
567,848.24
1.21
4,016.41 2MWD+IFR2+MS+Sag(2)
5.823.75
58.260
19226
3,651.29
3,60286
-3,861.27
-1,341.47
6,012,368.04
567,832.26
1.93
4,070.46 2_MWD+IFR2+MS+Sag(2)
6/272019 4:44:11PM
Page 4
COMPASS 5000.15 Build 91
Halliburton
Definitive Survey Report
Company:
Project:
Site:
Well:
Wellbore:
Design:
Hilcorp Alaska, LLC
Milne Point
M Pt E Pad
Rig: MPU E-42
MPU E42
MPU E-42
Local Coordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Database:
Well Rig: MPU E-42
MPU E42 Actual RKS @ 48.43usft (Innovation)
MPU E-42 Actual RKB @ 48.43uSft (Innovation)
True
Minimum Curvature
NORTH US+CANADA
Survey
Map
Map
Vertical
MD
Inc
Azi
TVD
TVDSS
+N/S
+EI•W
Northing
Easling
DLS
Section
(usft)
(`)
(1
(usft)
(usft)
(usft)
(usft)
(ft)
(ft) (-/low)
(ft) Survey Tool Name
5,887.40
58.460
197.64
3,684.68
3,636.25
-3,912.97
-1,357.72
6,012,316.20
567,816.49
0.60
4,124.55 2_MWD+IFR2+MS+Sag(2)
5,951.38
58.420
197.94
3,716.16
3,669.73
-3,964.88
-1,374.38
6,012,264.14
567,800.32
0.40
4,178.94 2_MWD+IFR2+MS+Sag(2)
6,015.04
58.360
197.93
3,751.53
3,703.10
4.016.46
-1,391.07
6,012,212.42
567,784.11
0.10
4,233.02 2_MWD+IFR2+M8+Sa9(2)
6,078.96
58.240
198.16
3,785.12
3,736.69
4,068.17
-1,407.92
6,012,160.56
567,767.74
0.36
4,287.26 2_MWD+IFR2+MS+Sag(2)
6,142.40
58.060
198.62
3,818.60
3,770.17
4,119.30
-1,424.92
6,012,109.27
567,751.22
0.68
4,340.98 2_MWD+IFR2+MS+Sag(2)
6,206.58
58.130
199.09
3,852.52
3,804.09
-0,170.86
-1,442.53
6,012,057.56
567,734.09
0.63
4,39526 2_MWD+IFR2+MS+Sag(2)
6,270.37
58,470
199.28
3,886.04
3,837.61
4,222.12
-1,460.36
6,012,006.14
567,716.73
0.59
4,449.30 2 MWD+IFR2+MS+Sag(2)
6,333.91
57910
199.70
3,919.53
3,871:10
4,273.02
-1,478.38
6,011,955A8
567,699.19
1.05
4,503.04 2_MWD+IFR2+MS+Sa9(2)
6,397.75
58.930
198.39
3,952.96
3,904.53
4,324.43
-1.496+12
6,011,903.51
567,681.93
2.37
4,557.21 2_MWD+IFR2+MS+Sag(2)
6,459.84
59.190
198.26
3,984.88
3,936.45
4,374.99
-1,512.87
6,011,852.81
567,665.66
0.46
4,610.30 2_MWD+IFR2+MS+Sag(2)
6,524.75
59.850
199.09
4,017.81
3,969.38
-0,427.98
-1,530.78
6,011,799.66
567,648.24
1.50
4,666.05 2_MWD+IFR2+MS+Sag(2)
6,586.71
62.270
199.38
4,047.79
3,999.36
4,479.17
-1,548.64
6,011,748.31
567,630.85
3.93
4,720.03 2_MWD+IFR2+MS+Sag(2)
6,652.49
61130
199.55
4,078.67
4,030.24
4,533.93
-1,568.00
6,011,693.37
567,612.01
0.85
4,777.84 2_MWD+IFR2+MS+Sag(2)
6,715.28
65.260
198.48
4,106.69
4,058.26
-0,587.05
-1.586.29
6,011,640.09
567,594.21
5.82
4,833.80 2_MWD+IFR2+MS+Sag(2)
6,780.34
68.710
198.12
4,132.12
4,083.69
4,643.89
-1,605.09
6,011,583.08
567,575.94
5.33
4,893.49 2_MWD+IFR2+MS+Sag(2)
6,843.97
71.340
198.51
4,153.86
4,105.43
4,700.66
-1,623.88
6,011,526.15
567,557.68
4.17
4,953.11 2_MWD+IFR2+MS+Sa9(2)
6,907.48
75.220
198.36
4,172.12
4,123.69
4,758.35
-1,643.11
6,011,468.28
567,538.99
6.11
5,013.73 2_MWD+IFR2+MS+Sag(2)
6,971.45
80310
196.90
4,185.68
4,137.25
4,817.92
-1,662.03
6,011,408.56
567,520.62
826
5,076.10 2_MWD+IFR2+MS+Sag(2)
7,035.26
81.840
195.17
4,195.58
4,147.15
4,878.50
-1,679.44
6,011,347.82
567,503.78
3.59
5,139.09 2_MWD+IFR2+MS+Sag(2)
7,099.07
83.570
192.70
4,203.68
4,155.25
4,939.92
-1,694.68
6,011,286.26
567,489.11
4.70
5,202.37 2_MWD+IFR2+MS+Sag(2)
7,160.77
83.150
192.46
4,210.81
4,162.38
4,999.74
-1,708.03
6,011,226.33
567,476.32
0.78
5,263.64 2_MWD+IFR2+MS+Sag(2)
7,226.26
83.020
192.82
4,218.70
4,170.27
-5,063.17
-1,722.25
6,011,162.77
567,462.68
0.5a
5,328.64 2_MWD+IFR2+MS+Sag(2)
7,290.11
82.530
193.41
4,226.73
4,17830
-5,124.86
-1,736.63
6,011,100.96
567,448.88
1.20
5,391.98 2_MWD+IFR2+MS+Sag(2)
7,353.89
83.130
192.73
4,234.69
4,186.26
5,186.51
-1,750.94
6,011,039.19
567.435.15
1.42
5,45525 2_MWD+IFR2+MS+Sag(2)
7,417.85
82.830
193.68
4,242.51
4,194.08
-5,248.31
-1,765.44
6,010,977.26
567,421.22
1.55
5,518.73 2_MWD+IFR2+MS+Sag(2)
7,481.54
82.490
194.00
4,250.64
4,202.21
-5,309.64
-1,780.55
6,010,915.80
567,406.68
0.73
5,581.89 2_MWD+IFR2+MS+Sa9(2)
7,545.28
83.240
193.26
4,258.56
4,210.13
-5,371.10
-1,795.45
6,010,854.20
567,392.35
1.65
5,645.14 2_MWD+IFR2+MS+Sag(2)
7,608.70
83890
193.97
4,265.78
4,217.35
-5,432.34
-1,810.28
6,010,792.84
567,37&W
1.32
5,708.14 2_MWD+IFR2+MS+Sag(2)
7,672.42
83.320
193.84
4,272.99
4,224.56
5,493.W
-1,825.50
6,010,731.25
567,363.45
0.62
5,771.46 2_MWD+IFR2+MS+Sag(2)
7,736.11
82.630
194.48
4,280.78
4,23235
-5,555.09
-1,840.96
6,010,669.82
567,348.56
1.47
5,834.67 2_MWD+IFR2+MS+Sag(2)
7,800.37
79.790
194.23
4,290.59
4,242.16
.5.616.60
-1,856.71
6,010,608.17
567,333.39
4.44
5,898.16 2_MWD+IFR2+MS+Sag(2)
7,863.49
79.020
19443
4,302.20
4,253.77
-5,676.72
-1,872.06
6,010,547.92
567,318.59
1.26
5,960.20 2_MWD+IFR2+MS+Sag(2)
7,927.25
79.810
193.88
4,313.91
4,265.48
-5,737.49
-1,887.39
6,010,487.02
567,303.63
1.50
6,022.88 2_MWD+IFR2+MS+Sag(2)
7,988.20
80.470
194.04
4,324.35
4,275.92
-5,795.76
-1,901.67
6,010.428.62
567,289.89
1.11
6,082.93 2_MWD+IFR2+MS+Sag(2)
8,054.50
81.890
194.00
4,334.52
4,286.09
-5,859.33
-1,917.75
6,010,364.91
567,274.61
2.14
6.148.44 2 MWD+IFR2+MS+Sag(2)
8,118.07
83.060
193.69
4,342.84
4,294.41
-5,920.52
-1,932.83
6,010,303.59
567,260.10
1.90
6,211.46 2_MWD+IFR2+MS+Sag(2)
8,181.68
87.110
193.26
4,348.29
4,299.86
-5,982.14
-1,947.59
6,010,241.85
567,245.91
6.40
6,274.82 2_MWD+IFR2+MS+Sag(2)
8,245.46
87.020
193.56
4,351.55
4,303.12
-6,044.10
-1,962.36
6,010,179.76
567,231.71
0.49
6,338.52 2_MWD+IFR2+MS+Sag(2)
8,281.05
86,380
193.50
4,35160
4,305.17
-6,078.64
-1,970.68
6,010,145.14
567,223.72
1.81
6,374.05 2_MWD+IFR2+MS+Sag(2)
8,343.89
86.920
193.23
4,357.28
4,308.85
-6,139.67
-1,985.18
6,010,083.98
567,209.79
0.96
6,436.78 2_MWD+IFR2+MS+Sa9(3)
W712019 4:44:11PM Page 5 COMPASS 5000.15 Build 91
Halliburton
Definitive Survey Report
Company:
Project:
Site:
Well:
Wallbore:
Design:
Hilcorp Alaska, LLC
Milne Point
M Pt E Pad
Rig: MPU E-42
MPU E-42
MPU E-42
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Database:
Well Rig: MPU E42
MPU E-42 Actual RKB @ 48.43usft (Innovation)
MPU E-42 Actual RKB @ 48.43usft (Innovation)
True
Minimum Curvature
NORTH US+CANADA
Survey
Y
Map
Map
Vertical
MD
(pmt)
8,407.38
8,470.54
8,534.02
Inc
(°)
87.850
89.820
91.610
Azi
(°)
193.98
195.00
195.25
TVD
(usft)
4,360.17
4,361.46
4,360.66
TVDSS
(usft)
4,31174
4,313.03
4,312.23
+N/ -S
(usft)
-6,201.32
-6,262.45
-6,323.72
+E/ -W
(usft)
-2,000.09
-2,015.89
-2,032.46
Northing
(ft)
6,010,022.21
6,009,960.94
6,009,899.52
Easting DLS
(ft) (°/100')
567,195.44 1.88
567,180.21 3.51
567,164.22 2.85
Section Survey Tool Name
(ft)
6,500.20 2_MWD+IFR2+MS+Sag(3)
6,563.34 2_MWD+IFR2+MS+Sa9 (3)
6,626.80 2_MWD+IFR2+MS+Sag(3)
8,597.81
8,661.58
8,725.35
8,789.48
8,852.84
92.600
92.780
92.600
92.720
93.530
195.07
195.25
194.14
194.81
194.75
4,358.32
4,355.33
4,352.34
4,349.36
4,345.91
4,309.89
4,306.90
4,30301
4,300.93
4,297.48
-6,385.25
-6,446.74
-6,508.35
-6,570.38
-6,631.55
-2,049.13
-2,065.78
-2,081.94
-2,097.96
-2,114.10
6,009,837.84
6,009,776.21
6,009,714.46
6,009,652.29
6,009,590.98
567,148.12
567,132.04
567,116.45
567,101.02
567,085.45
1.58
0.40
1,76
1.06
1.28
6,690.53 2MWD+IFR2+MS+Sa9(3)
6,754.21 2 MWD+IFR2+MS+Sa9(3)
6,817.90 2_MWD+IFR2+MS+Sag(3)
6,881.96 2_MWD+IFR2+MS+Sag(3)
6,945.22 2_MWD+IFR2+MS+Sag(3)
8,916.62
8,980.32
9,043.87
9,107.23
9,171.59
93.830
94.270
93,580
93.580
92530
194.54
193.47
191.80
191.88
190.81
4,341.81
4,337.31
4,332.96
4,329.01
4,325.58
4,293.38
4,288.88
4,284.53
4,280.58
4,277.15
-6,693.13
-6,754.78
-6,816.64
-6,878.54
-6,941.55
-2,130.19
-2,145.56
-2,159.43
-2,172.41
-2,185.05
6,009,529.26
6,009,467.47
6,009,405.49
6,009,343.48
6,009,280.36
567,069.93
567,055.13
567,041.64
567,02944
567,017.38
0.57
1.81
2.84
0.13
2.33
7,008.86 2_MWD+IFR2+MS+Sag(3)
7,072.40 2 MWD+IFR2+MS+Sag(3)
7,135.79 2_MWD+IFR2+MS+Sag(3)
7,198.98 2_MWD+IFR2+MS+Sag(3)
7,263.18 2_MWD+1FR2+MS+Sag(3)
9,234.96
9,299.44
9,362.49
9,426.10
9,490.11
93.090
92.840
93.150
95.200
95,010
189.65
190.14
189.83
191.41
191.92
4,322.47
4,319.13
4.315.84
4,311.21
4,305.51
4,274.04
4,270.70
4,267.41
4,262.78
4,25108
-7,003.83
-7,067.27
-7,129.28
-7,191.63
-7,254.07
-2,196.29
-2,207.36
-2,218.27
-2,229.96
-2,242.85
6,009,217.98
6,009,154.45
6,009,092.35
6,009,029.90
6.008,967.35
567,006.72
566,996.24
566,985.90
566,974.79
566.962.49
2.03
0.85
0.69
4.06
0.85
7,326.35 2_MWD+IFR2+MS+Sag(3)
7,390.58 2_MWD+IFR2+MS+Sag(3)
7,453.40 2_MWD+IFR2+MS+Sag(3)
7,516.73 2_MWD+IFR2+MS+Sag(3)
7,580.44 2 MWD+IFR2+MS+Sag(3)
9,553.21
9,615.38
9,678.84
9,742.64
9,808.66
94.520
94.450
93.830
93400
93.150
191.73
192.16
191.78
191.63
192.45
4,300.27
4,295.41
4,290.83
4,286.81
4,283.03
4,251.84
4,246.98
4,242.40
4,238.38
4,234.60
-7,315.61
-7,376.25
-7,438.17
-7,500.52
-7,564.98
-2,255.74
-2,268.57
-2,281.69
-2,294.61
-2,308.36
6,008,905.69
6,008,844.94
6,008,782.91
6,008,720.45
6,008,655.87
566,950.17
566,937.91
566.925.36
566,913.02
566,899.87
0.83
0.70
1.15
0.71
1.30
7,643.28 2_MWD+IFR2+MS+Sag(3)
7,705.22 2_MWD+IFR2+MS+Sag(3)
7,768.48 2 MWD+IFR2+MS+Sag(3)
7,832.11 2_MWD+IFR2+MS+Sag(3)
7,897.98 2_MWD+IFR2+MS+Sag(3)
9,872.23
9,935.41
9,999.73
10,063.41
10,126.86
92.470
92.780
92350
92.160
91.300
192.65
193.31
193.90
195.59
196.07
4,279.92
4,277.02
4,274.15
4,271.64
4,269.72
4,23149
4,228.59
4,225.72
4,223.21
4,221.29
-7,626.96
-7,688.46
-7,750.91
-7,812.44
-7,873.46
-2,322.16
-2,336.33
-2,351.45
-2,367.64
-2,384.94
6,008,593.78
6,008,532.15
6,008,469.57
6,008,407.89
6,008,346.73
566,886.65
566,873.05
566,858.52
566,842.89
566,826.16
1.11
1.15
1.13
2.67
1.55
7,961.46 2_MWD+IFR2+MS+S39(3)
8,024.56 2_MWD+IFR2+MS+Sag(3)
8,068.82 2_MWD+IFR2+MS+Sag(3)
8,152.44 2_MWD+IFR2+MS+Sa9(3)
8,215.82 2_MWD+IFR2+MS+Sa9(3)
10,188.82
10,253.69
10,316.73
10,382.01
10,445.74
91.610
91.950
90.430
91,360
91.240
196.69
196.26
193.98
193.80
193.55
4,268.15
4,266.64
4,265.83
4,264.81
4,263.36
4,219.72
4,218.21
4,217.40
4,21638
4,214.93
-7,932.88
-7,995.07
-8,055.92
-8,119.28
-8,181.19
-2,40241
-2,420.80
-2.37.24
-2,452.91
-2,467.97
6,008,287.15
6,008,224.80
6,008,163.80
6,008,100.30
6,008,038.27
566,809.25
566,791.44
566,775.56
566,760.48
566,746.00
1.12
1.09
3.75
1.45
0.44
8,277.71 2_MWD+4FR2+MS+Sag(3)
8,342.49 2_MWD+IFR2+MS+Sag(3)
8,405.51 2_MWD+IFR2+MS+Sag(3)
8,47D.78 2_MWD+IFR2+MS+Sag(3)
8,534.49 2_MWD+IFR2+MS+Sag(3)
10,509.19
10,573.15
10,635.73
10,700.83
10,764.12
92.600
92.780
93.160
93.090
93.590
194.03
194.27
194.52
194.81
194.82
4,261.24
4,258.24
4,254.99
4,251.45
4,247.76
4,212.81
4,209.81
4,206.56
4,203.02
4,199.33
-8,242.77
-8,304.73
-8,365.26
-8,428.14
-8,489.23
-2,483.09
-2,498.71
-2,514.24
-2,530.70
-2.546.86
6,007,976.55
6,007,914.46
6,007,853.79
6,007,790.76
6,007,729.54
566,731.46
566,716.41
566,701.44
566,685.57
566,669.98
2.27
0.47
0.73
0.46
0.79
8,597.91 2_MWD+IFR2+MS+Sag(3)
8,661.79 2_MWD+IFR2+MS+Sag(3)
8,724.29 2_MWD+IFR2+M5+Sag(3)
8,789.28 2 MWD+IFR2+MS+Sag(3)
8,852.46 2 MWD+IFR2+MS+Ssg(3)
10,828.26
10,891.55
93.460
92.160
194.27
194.57
4,243.82
4,240.71
4,195.39
4,192.28
-8,551.19
-8,612.41
-2,562.93
-2,578.68
6,007,667.43
6,007.606.07
566,654.48
566,639.31
0.88
2.11
8,916.47 2_MWD+IFR2+MS+Sag(3)
8,979.68 2_MWD+IFR2+MS+Sag(3)
6272019 4:44:11PM
Page 6
COMPASS 5000.15 Build 91
Halliburton
Definitive Survey Report
Company: Hilcom Alaska, LLC Local Co-ordinate Reference: Well Rig: MPU E-42
Project: Milne Paint TVD Reference: MPU E-42 Actual RKB @ 48.43usft (Innovation)
Site: M Pt E Pad MD Reference: MPU E-42 Actual RKB @ 48.43usft (Innovation)
Well: Rig: MPU E-42 North Reference: True
Wellbore: MPU E-42 Survey Calculation Method: Minimum Curvature
MPII E42 Database: NORTH US+CANADA
Survey
Map Map Vertical
MO Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section Survey Tool Name
(usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft)
10,955.51 90.800 193.41 4,239.06 4,190.63 -8,674.45 -2,594.13 6,007,543.90 566,624.43 2.79 9,043.62 2_MWD+IFR2+MS+Sag(3)
11,018.96 89.820 193.61 4,238.72 4,190.29 -8,736.15 -2,608.96 6,007,482.08 566,610.19 1.59 9,107.07 2_MWD+IFR2+MS+Sag(3)
11,082.50 89.940 194.13 4,238.85 4,190.42 -8,797.83 -2,624.19 6,007,420.26 566,595.53 0.84 9,170.61 2_MWD+IFR2+MS+Sag(31
11,146.20 91.680 195.79 4,237.95 4,189.52 -8,859.36 -2,640.63 6,007,358.58 566,579.66 3.77 9,234.28 2_MWD+IFR2+MS+Sa9(3)
11,210.22 91.920 196.75 4,235.94 4,187.51 .8,920.79 -2,658.55 6,007,297.00 566,562.31 1.54 9,298.22 2_MWD+IFR2+MS+Sag(3)
11,273.59 92.040 197.11 4,233.75 4,185.32 -8,981.38 -2,677.00 6,007,236.25 566,544.43 0.60 9,361.46 2_MWD+IFR2+MS+Sag(3)
11,337.62 92.910 196.22 4,230.98 4,182.55 -9,042.66 -2,695.34 6,007,174.81 566,526.65 1.94 9,425.35 2_MWD+IFR2+MS+Sag(3)
11,400.98 92.850 194.55 4,227.80 4,179.37 -9,103.67 -2,712.13 6,007,113.65 566,510.44 2.63 9,488.61 2_MWD+IFR2+MS+Sag(3)
11,465.32 93.900 193.66 4,224.01 4,175.58 9,165.96 -2,727.78 6,007,051.22 566,495.36 2.14 9,552.84 2 MWD+IFR2+MS+Sag(3)
11,528.78 94.390 193.93 4,219.43 4,171.00 -%227.43 -2,742.87 6,006,989.62 566,480.84 0.88 9,616.13 2_MWD+IFR2+MS+Sag(3)
11,592.23 93,830 193.59 4,214.88 4,16645 -9,288.90 -2,757.93 6,006,928.02 566,466.36 1.03 9,679.42 2_MWD+IFR2+MS+Sag(3)
11,655.78 93.890 194.74 4,210.60 4,162.17 -9,350.37 -2,773.44 6,006,866.41 566,451.42 1.81 9,742.82 2_MWD+IFR2+MS+Sag(3)
11,719.52 92910 194.44 4,206.82 4,158.39 -9,411.95 -2,789.47 6,006,804.69 566,435.97 1.61 9,806.44 2_MWD+IFR2+MS+Sag(3)
11,783.84 92.530 193.73 4,203.77 4,155.34 -9,474.27 -2,805.11 6,006,742.24 568,420.91 1.25 9,870.69 2_MWD+IFR2+MS+Sag(3)
11,847.09 93.280 193.18 4,200.56 4,152.13 -9,535.70 -2,819.80 6,006,680.68 566,406.78 1.47 9,933.86 2_MWD+IFR2+MS+Sag(3)
11,899.06 93.090 192.59 4,197.67 4,149.24 -9,586.28 -2,831.38 6,006,630.00 566,395.68 1.19 9,985.74 2_MWD+IFR2+MS+Sag(3)
11,969.00 93.090 192.59 4,193.90 4,145.47 -9,654.44 -2,846.60 6,006,561.70 566,381.10 0.00 10,055.56 PROJECTEDto TD
6/27/19
Checked By: Mitch Laird _ -- Approved By: ^`�'°°�1knfph"""""°"`""' Date:
61272019 4:44r11PM Page 7 COMPASS 5000.15 Build 91
!a
Lease & Well No.
County
Hilcorp Energy Company
CASING & CEMENTING REPORT
MP E42 Date Run 16Jun-19
State Alaska Supv. J. Lott/ O Amend
CASING RECORD
Surface
TO
8,321.00
er) Detail
Casing (OrOr Liner)
Top of Liner #NIA
Setting Depths
Jts.
Component
Size
Wt.
Grade
THD
Make
Length
Bottom
Top
Shoe
95/8
334 Mixing / Pumping Rate (bpm): 6
TAP BTC
1.57
8,311.00
8,309.43
1
2
Casing
95/8
40.0
L-80
TXP BTC
Tenaris
78.59
8,309.43
8,230.84
1
Float Collar
95/8
n
TXP BTC
9.3 Rate(bpm):
1.29
8,230.84
8,229.55
1
Casing
95/8
40.0
L-80
TAP BTC
Tenaris
36.17
8,229.55
8,193.38
1
Baffle Adapter
95/8
X Yes _No Vol to SUR:
TXP BTC
Date: 6/18/2019
1.46
8,193.38
8,191.92
130
Casing
95/8
40.0
L-80
TAP BTC
Tenaris
5,620.01
8,191.92
2,571.91
Pup
95/8
40.0
L-80
TXP BTC
13.38
2,571.91
2,558.53
1
431.7 Mixing /Pumping Rate (bpm): 7
95/8
Density (ppg)
TXP BTC
12.75
2,558.53
2,545.78
1
ES Cementer
95/8
40.0
L-81
TXP BTC
pumped
14.27
2,545.78
2,531.51
1
64
Pup
Casing
95/8
40.0
L-80
TXP BTC
Tenaris
2,497.33
2,531.51
34.18
1
Cut Joint I
95/8
1 40.0
1 L-80
TXP BTC
1 19.48
34.18
No His to Run'
Casing Rotated? _Yes
Csg Wt, On Hook: 220 Type Float Collar: Conventional
Csg M. On Slips: 115,000 Type of Shoe: Bullnose _ Casing Crew: Weatherford
Rotate Csg Yes X No Recip Csg _ Yes X No _ Ft. Min. 9.3 PPG
Fluid Description: Spud Mud
Liner lop Packet Yes No
Liner hanger Into (MakelMotlel):
Liner hanger test pressure: Floats Held X Yes No
Centralizer Placement: 2 on joint 1 and 3, 1 every joint to joint to joint 11, 0 Joints 12-15, 1 every joint from joint 15-27, 1 every otherjoint to Joint
57, 1 everjoint from oint 141-150, 1 every other from pint 150 - 206.
CEMENTING REPORT
Ceiculluld Cmt Vol @ 0% excess: 496,6 Total Volume trot Pumpaa:
Cast returned to surface: 452 Calwlated cement left in wellbore:
nu 1-11- colt, naeod- 487.6 OH volume actual: 431.9 Actual % t
440.9
Shoe @ 8312
FC @ 8,230.00
Top of Liner #NIA
Preeush (Spacer)
Density (ppg)
10 Volume pumped (BBLs) 53
Type: Clean Spacer
Lead Slurry
Sacks: 798 Yield: 2.35
Type: Type 1/II
Volume pumped (BBLs)
334 Mixing / Pumping Rate (bpm): 6
Density (ppg) 12
Tail Slurry
Sacks: 400 Yield: 1.16
w
Type Class G
158
Volume pumped (BBLs)
71 Mixing / Pumping Rate (bpm): 3
F
Density (ppg)
Post Flush (Spacer)
Density(ppg)
834 Rat.(bpm): 5 Volume: 20
is
Type: Water
n
Displacement:
9.3 Rate(bpm):
4 Volume (actual /ralwiated): 606/601
Type' Spud Mud Density(ppg)
Rig
Bump Plug? X Yes Bump press 1300
FCP(psi): 1033 Pump used for
disp:
_No
X No %Ralumstluri gjob 98.4
Casing Rotated? _Yes
X No Reciprocated? _Ves
46
Cement returns to surface? X
Yes No Spacer returns?
X Yes _No Vol to SUR:
Cement In Place At: 730
Date: 6/18/2019
Estimated TOC: 2,546
Method Used To Determine TOC:
Returns
Stage Collar@ 2546
Type ES Cementer
Closure OK Y
Pre0ush(Spacer)
Density(ppg)
10 Volume pumped (BBLs) 56
Type: Clean Spacer
Lead Slurry
Sacks: 550 Yield : 4.41
Type' PermL
10.7
Volume pumpetl (BBLs)
431.7 Mixing /Pumping Rate (bpm): 7
Density (ppg)
Tail Slurry
Sacks: 270 Yield: 1.17
Type: Class G
Volume (BBLs)
56.2 Mixing / Pumping Rate (bpm): 3.5
N
Density (ppg) 15.8
pumped
o
p
Post Flush (Spacer)
Density (ppg)
8.34 Rate (bpm): 20 Volume: 4
U
Type: Water
m
Displacement:
9.3 Rate (bpm)
5 Volume (actual /calculated): 171.2/173.4
Type: Spud Mud Density(ppg)
Bump u9? X Yes No Bump press 2200
PI
FCP (psi): 785 Pump used for
disp: Rig
X No % Returns during job 100
Casing Rotated? _Yes
X No Reciprocated? -Yes
4066
Cement returns to surface? X
Yes No Spacer returns?
X Yes _No Vol to Surf.
Cement In Place At: 18.57
Date: 6/1812019
Estimated TOC:
Method Used To Determine TOC:
Returns
Ceiculluld Cmt Vol @ 0% excess: 496,6 Total Volume trot Pumpaa:
Cast returned to surface: 452 Calwlated cement left in wellbore:
nu 1-11- colt, naeod- 487.6 OH volume actual: 431.9 Actual % t
440.9
219082
Debra Oudean Hilcorp Alaska, LLC 3 1 0 12
GeoTech 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: 907 777-8337
NIh„rn :cl,,.►v, ca.c Fax: 907 777-8510
E-mail: doudean@hilcorp.com
DATE 07/18/2019
To: Alaska Oil & Gas Conservation Commission
Abby Bell
Natural Resource Technician II
333 W 7th Ave Ste 100
Anchorage, AK 99501
MPU E-42 (PTD 219-082)+ E -42L1 (PTD 219-091 )
Is] ri 111
_Log Viewers 7/18.,20191 D,23 AM RECEIVED
MPU E-42 7/18/20191D:25AM JUL 19 2019
MPU E-421_1 7/18/20191 D:26 AM AO G C C
Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337
THE STATE
ALASKA
GOVERNOR MIKE DUNLEAVY
Monty Myers
Drilling Manager
Hilcorp Alaska, LLC
3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
w .aogcc.alaska.gov
Re: Milne Point Field, Schrader Bluff Oil Pool, MPU E-42
Hilcorp Alaska, LLC
Permit to Drill Number: 219-082
Surface Location: 3704' FSL, 2008' FEL, SEC. 25, T13N, R10E, UM, AK
Bottomhole Location: 658' FNL, 434' FWL, SEC. 6, T12N, RI 1E, UM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced development well.
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs
run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment
of this well.
This permit to drill does not exempt you from obtaining additional permits or an approval required
by law from other governmental agencies and does not authorize conducting drilling operations
until all other required permits and approvals have been issued. In addition, the AOGCC reserves
the right to withdraw the permit in the event it was erroneously issued.
Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska
Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply
with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code,
or an AOGCC order, or the terms and conditions of this permit may result in the revocation or
suspension of the permit.
Sincerely,
2s',ie L. Chmielowski
Commissioner
DATED this 31 day of May, 2019.
STATE OF ALASKA
A KA OIL AND GAS CONSERVATION COMM. .ION
PERMIT TO DRILL
20 AAC 25.005
MAY 2 2 2019
1a. Type of Work:1
b. Proposed Well Class: Exploratory - Gas Ll Service - WAG Service - Disp E]1
c. Specify if well is proposed for:
Drill El - Lateral ❑
Stratigraphic Test ❑ Development -Oil Q Service- Winj ❑ Single Zone Q
Coalbed Gas ❑ Gas Hydrates ❑
Redrill ❑ Reentry ❑
Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑
Geothermal ❑ Shale Gas ❑
2. Operator Name:
5. Bond: Blanket 0 • Single Well ❑
11. Well Name and Number:
Hilcorp Alaska, LLC
Bond No. 022035244 •
MPU E-42 ( 06)
3. Address:
6. Proposed Depth:
12, Field/Pool(s):
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
MD: 11,950' - TVD: 4,223'
Milne Point Field
Schrader Bluff Oil Pool
4a. Location of Well (Governmental Section):
7. Property Designation:
Surface: 3704' FSL, 2008' FEL, Sec 25, T13N, R10E, UM, AK
ADL025518 / ADL380110 -
DkJ4.1-- Chr.444 ( -
Top of Productive Horizon:
8. DNR Approval Number:
13. Approximate Spud Date:
2202' FNL, 1354' FWL, Sec 36, T13N, R10E, UM, AK
LONS 94-017
6/8/2019 -
9. Acres in Property:
14. Distance to Nearest Property:
Total Depth:
658' FNL, 434' FWL, Sec 6, T12N, R11 E, UM, AK
4997
9725' to nearest unit boundary
4b. Location of Well (State Base Plane Coordinates - NAD 27):
10. KB Elevation above MSL (ft): 47.3' •
15. Distance to Nearest Well Open
Surface: x- 569137 • y- 6016240 • Zone -4
GL / BF Elevation above MSL (ft): 20.8' .
to Same Pool: 1170' C-- Z
16. Deviated wells: Kickoff depth: 350 feet
17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 92.4 degrees
Downhole: 1905 Surface: 1468 -
18. Casing Program: Specifications
Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks
Hole
Casing Weight Grade
Coupling I Length
MD TVD
MD
TVD (including stage data)
Cond
20" 215# X-42
Weld 80'
Surface Surface
107'
107' ±270 ft3
Sig 1 L - 1873 ft3 / T - 458 ft3
12-1/4"
9-5/8" 40# L-80
TXP 8,100'
Surface Surface
8,100' .
4,319' Sig 2 L - 1937 ft3 / T - 314 ft3
8-1/2"
4-1/2" 13.5# L-80
Hyd 625 4,150'
7,835' 4,294'
11,950'
4,223' Cementless PreDrilled Liner
19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations)
Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured):
Casing Length Size Cement Volume MD TVD
Conductor/Structural
Surface
Intermediate
Production
Liner
Perforation Depth MD (ft): Perforation Depth TVD (ft):
Hydraulic Fracture planned? Yes E] No ❑4
20. Attachments: Property Plat O BOP Sketch
Drilling Program Time v. Depth Plot v Shallow Hazard Analysis
Time
Diverter Sketch
e
Seabed Report a Fluid Program e 20 AAC 25.050 requirements e✓
21. Verbal Approval: Commission Representative: Date
22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval. Contact Name: Joe Engel
Authorized Name: Monty Myers Contact Email: 'enclelidlhilcorp.com
Authorized Title: Drilling Manager Contact Phone: 777-8395
Foo rnor✓!Y MYC-N'-S
Authorized Signature: Date: .S -•L2-1 q
Commission Use Only
Permit to Drill �l
API mberp '7 / (,� Permit Approval
�(��J -b I
See cover letter for other
Number: z'L�Z
50- d"< ` 'f Date:
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: Er
E,/
Other: p �� Samples req'd: Yes ❑ No[J Mud log req'd: Yes ❑ o (Jv
Sod VNo,❑�/
�5" G`3 HzS measures: Yes ❑ No[��i/ Directional svy req'd: Yes
Spacing exception req'd: Yes ❑ No IJ Inclination -only svy mq'd: Yes❑ No Lv�
Post initial injection MIT req'd: Yes ❑ No ❑
V APPROVED BY
Date:
Approved by: COMMISSIONER THE COMMISSION
Submit Dane
Form 10 1 Revised 5/20 ThisPem IS vol rIoGIr hAi fapproyalper 20 AAC 25.005 AttachmentsDuplicate
Hilcorp Alaska, LLC
Milne Point Unit
(MPU) E-42
Drilling Program
Version 1
5/22/2019
Table of Contents
1.0
Well Summa
`
2.0
Management of Change Information............................................................................................3
3.0
Tubular Program: ....................................................................................................................
*"****4
4.0
Drill Pipe Information: ...................................................................................................................
4
5.0
Internal Reporting Requirements..................................................................................................5
6.0
Planned Wellbore Schematic..........................................................................................................6
7.0
Drilling / Completion Summa
7
8.0
Mandatory Regulatory Compliance / Notifications.....................................................................8
9.0
R/U and Preparatory Work..........................................................................................................10
10.0
NIU 13-5/8" 5M Diverter Configuration.....................................................................................11
11.0
Drill 12-1/4" Hole Section.............................................................................................................13
12.0
Run 9-5/8" Surface Casing...........................................................................................................16
13.0
Cement 9-5/8" Surface Casing.....................................................................................................21
14.0
BOP N/U and Test.........................................................................................................................26
15.0
Drill 8-1/2" Hole Section...............................................................................................................27
16.0
Run 4-1/2" Production Liner........................................................................................................31
17.0
End of E-42 Operations / Begin E -42L1 Operations (Separate
PTD)......................................35
18.0
Innovation Rig Diverter Schematic.............................................................................................36
19.0
Innovation Rig BOP Schematic....................................................................................................37
20.0
Wellhead Schematic......................................................................................................................38
21.0
Days Vs Depth................................................................................................................................39
22.0
Formation Tops & Information...................................................................................................40
23.0
Anticipated Drilling Hazards.......................................................................................................42
24.0 Innovation Rig Layout..................................................................................................................45
25.0 FIT Procedure................................................................................................................................46
26.0 Innovation Rig Choke Manifold Schematic................................................................................47
27.0 Casing Design.................................................................................................................................48
28.0 8-1/2" Hole Section MASP............................................................................................................49
29.0 Spider Plot AD 27 Governmental Sections 50
30.0 Surface Plat (As Built) (NAD 27).................................................................................................51
31.0 Schrader Bluff OA Sand Offset MW vs TVD Chart..................................................................52
Milne Point unit
E-42 SB Producer
HilCorp Drilling Procedure
1.0 Well Summary
Well
MPU E-42
Pad
Milne Point "E" Pad
Planned Completion Type
ESP on 2-7/8" Production Tubing
Target Reservoir(s)
Schrader Bluff OB Sand
Planned Well TD, MD / TVD
11,950' MD / 4,223' TVD
PBTD, MD / TVD
Surface Location (Governmental)
11,939' MD / 4,222' TVD
3704' FSL, 2008' FEL, Sec 25, TUN, R10E, UM, AK
Surface Location (NAD 27)
X= 569,137.33, Y= 6,016,240.99
Top of Productive Horizon
(Govemmental)
TPH Location (NAD 27)
2202' FNL, 1354TWL, Sec 36, T13N, R10E, UM, AK
X= 567,275.91 Y= 6,010,317.77
BHL Govemmental)
658' FNL, 434' FWL, Sec 6, T12N, RI IE, UM, AK
BHL (NAD 27)
AFE Number
X= 566,385.99, Y=6,006,574
1910942
AFE Drilling Das
22 days
AFE Completion Das
0 days
AFE Drilling Amount
$4,827,644
AFE Completion Amount
$0
AFE Facility Amount
$391,000
Maximum Anticipated Pressure
(Surface)
Maximum Anticipated Pressure
(Downhole/Reservoir)
Work String
1468 psig
1905 psig
5" 19.5# S-135 DS -50 & NC 50
KB Elevation above MSL:
26.5 ft + 20.8 ft = 47.3 ft
GL Elevation above MSL:
20.8 ft -
BOP Equipment
13-5/8" x 5M Annul— (3) ea 13-5/8" x 5M Rams
Page 2
Milne Point Unit
E-42 SB Producer
Hilcorp Drilling Procedure
. M,m,
2.0 Management of Change Information
H
Hilcorp Alaska, LLC LUC=
Changes to Approved Permit to Drill
Date: 5/2312019
Subject: Changes to Approved Permit to Drill for MPU E-42
File #: MPU E-42 Drilling and Completion Program
Any modifications to MPU E-42 Drilling & Completion Program wi71 be documented and approved belmv.
Changes to an approved APD vfill be approved in advance to the AOGCC.
Approval
Drilling Manager
Prepared:
Drilling Engineer
Page 3
Date
n
Hile
E� X22rp
3.0 Tubular Program:
Milne Point Unit
E-42 SB Producer
Drilling Procedure
Hole
Section
OD (in)
ID
in
Drift
in
Conn OD
is
Wt
#/ft
Grade
Conn
BurstColha
si
si
k -lbs
Cond
20"
19.25'
-
-
-X-52
Weld
Min
m
k -lbs
12-1/4"
9-5/8"
8.835"
8.679"
10.625'
40
L-80
TXP
5,750
3,090
916
Tieback
7-5/8"
6.875'
6.75'
7.947
29.7
L-80
Hydril521
6,890
4,790
683
8-1/2"
4-1/2"
3.920
3.795
4.714
13.5
L-80
Hydril625
9020
8540
279
4.0 Drill Pipe Information:
Hole
OD
ID (in)
TJ ID
T.7 OD
Wt
Grade
Conn
M/U
M/U
Tension
SAO&],
in
in
in(#/ft)
Min
m
k -lbs
Surface&
5"
4.276"
3.25'
6.625'
19.5
5-135
GPDS50
36,100
43,100
560kib
Production
5"
4.276"
3.25'
6.625'
19.5
5-135
NC50
31,032
34,136
560k1b
All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery).
Page 4
ff
Hilcorp
Eo Cm Wy
5.0 Internal Reporting Requirements
Milne Point Unit
E-42 SB Producer
Drilling Procedure
5.1 Fill out daily drilling report and cost report on Wel1Ez.
• Report covers operations from 6am to 6am
• Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left
of the data entry area — this will not save the data entered, and will navigate to another data entry.
• Ensure time entry adds up to 24 hours total.
• Try to capture any out of scope work as NPT. This helps later on when we pull end of well
reports.
• Enter the MD and TVD depths EVERY DAY whether you are making hole or not.
5.2 Afternoon Updates
• Submit a short operations update each work day to 12mazzolini(2hilcorp com mmyers hilcorp,
jenszel@hilco[p.com and cdinger@ ilcorp.com
5.3 Intranet Home Page Morning Update
• Submit a short operations update each morning by 7am on the company intranet homepage. On
weekend and holidays, ensure to have this update in before 5am.
5.4 EHS Incident Reporting
• Health and Safety: Notify EHS field coordinator.
• Environmental: Drilling Environmental Coordinator
• Notify Drilling Manager & Drilling Engineer on all incidents
• Submit Hilcorp Incident report to contacts above within 24 hrs
5.5 Casing Tally
• Send final "As -Run" Casing tally to mm ers hilcorp,com 'e! neel@hilcorp.com and
cdinizer@hilc=.com
5.6 Casing and Cement report
• Send casing and cement report for each string of casing to mmyers&a hilcorp.com
iengel@hilcorp.com and cdineg_rna hilcoM.com
5.7 Hilcorp Milne Point Contact List:
Title
Name Work Phone
Cell Phone
Email
Drilling Manager
Monty Myers 907.777.8431
907.538.1168
mmyers@hilcorp.com
Drilling Engineer
Joe Engel 907.777.8395
805.235.6265
lenge) hilcorp.com
Completion Engineer
Taylor Wellman 907.777.8449
907.907.9533
twellman@hilcorp.com
Geologist
Kevin Eastham 907.777.8316
907.360.5087
keastham@hilcorp.com
Reservoir Engineer
Reid Edwards 907.777.8421
907.250.5081
reedwards@hilcorp.com
Drilling Env. Coordinator
Keegan Fleming 907.777.8477
907.350.9439
kfleming@hilcorp.com
EHS Manager
Carl Jones 907.777.8327
907.382.4336
calones@hilcoro.Com
Drilling Tech
Cody Dinger 907.777.8389
509.768.8196
cdinger@hilcor Cocom
Page 5
H
Hilc2,T
e� �P.ar
6.0 Planned Wellbore Schematic
Milne Point Unit
E-42 SB Producer
Drilling Procedure
Milne Point Unit
Well: MPU E-42
PROPOSED Last Completed: xK/xx/�R=
PTD: x -lax
O'P IP Eea: Si3;�D'�GLEtv.:318
OPEN HOLE/CEMENT DETAIL WELLINCUNATION DETAIL
20' I ^270n ApAbd I in42"lick KDP@350MD
-45(8'_ Styli -18735 ru/T _458 k3__-___—________.-_ Maa aA1c-2.4 f8@8,386'N1D
1 2L-1937 k3 T-31dfd
ffi
N3
ti
i
1ls U
;u
r �
v: Vas!
I>
1E
9518'
� lr4
TD=]]�P" IN'DIlro=4,ZZ3•(IVCj
P6ro= sa,%s' Inn2} / P61o=a�'[1vD1
Page 6
23
LATERAL WINDOW
F.oriud 61.M 5,2Z 2D13
-----
JEWELRY DETAIL
NO
Dep1N
Nem
1
2160
ST 2:2-7I8"GLM W 1'DP50V BK LmN
2
36,650
Srk2-70 GLM w1 DV, ML
3
16,7110'
2-7/r 8N Pnek- L205' WO
4
17,31:
Ohch Ikad:PNIP JOOP
5
t7,318
Pm ..S3ePMPNO sM
6
x],336'
P m. d00Iri19iD
7
17,348'
Gas Secaratw G. Aivleer 53BGS
8
x7,357
U o-Tandem5eal: G5830¢1165B)ABPFSA
9
x]563'
lower Tan6em Seal: G5D3q IIb58/AB PFSA
10
17,M
Mrtor:562 XP-40DIPl2,]85V; e80.
11 1
t7,M'
ISenmr: Zenieh
12
x7,404
C tl irer: Baham @
13
0,750'
ScalkwxP 6(10=6.00')
14
9,760
Fe SXSMPlinm Ta Parley
IS
x7,780
(Mlnerral LCM tl1 Sl-ireralE 6k�dulr) 11163.68"i
I6
9,800
PA41 11an8v lLaAerY Drik IOS 960'IIE1CiDAlYe
Orin 12360fi")
17
x7,81(Y
4 Vr2 5,r MM 5ca&= Dive rIMO) IkOWM
I6_i66")
18
x7,820
D9 Ni Ie fm=3.5&'n
19
17,835'
]'E 5l9"Ml P liner l .1 $,A4= ReeeP
m
911x'
9anamdlmarar xalammdv ODa3175'I
21
x3L9tn
LW Lvera14-112'Na6lk Sub
22
S1 L9CC
OA Weml 4-112' WIV Va6e LTC 8681' Ball m Seat/Ck )
23
11L9W
061�r+14.1/r WI!ablrp4daS5ab
24
11L945
I M81 14-1(r WMVa1m LTCB%B1'8allan Seav0Oa
LATERAL WINDOW
F.oriud 61.M 5,2Z 2D13
n
Hid=
Milne Point Unit
E-42 SB Producer
Drilling Procedure
7.0 Drilling / Completion Summary
MPU E-42 is a grassroots ESP dual lateral producer planned to be drilled in the Schrader Bluff OB/OA sand.
1-42 is part of an eight well program targeting the Schrader Bluff sand on E -Pad.
The directional plan is a catenary well path build, 12.25" hole with 9-5/8" surface casing set into the top of
the Schrader Bluff OA sand. An 8.5" lateral section will then be drilled. A 4-1/2" pre drilled liner will be
run in the open hole section. Once liner is ran, operations for the second lateral, E -42L1, will begin and will
be included on a separate PTD.
The Innovation Rig will be used to drill and complete the wellbore.
Drilling operations are expected to commence approximately June 8, 2019, pending rig schedule.
Surface casing will be run to 8,100' MD / 4,319' TVD and cemented to surface via a 2 stage primary cement
job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed,
necessary remedial action will then be discussed with AOGCC authorities.
All cuttings & mud generated during drilling operations will be hauled to the Milne Point `B" pad G&I facility.
General sequence of operations:
1. MIRU Innovation to well site
2. NIU & Test 13-5/8" Diverter and 16" diverter line
3. Drill 12-1/4" hole to TD of surface hole section. Run and cement 9-5/8" surface casing.
4. N/D diverter, N/U & test 13-5/8" x 5M BOP.
5. Drill 8-1/2" lateral to well TD. Run 4-1/2" production liner.
Note: Remaining operations will be covered under the E -42L 1 PTD application
Reservoir Evaluation Plan:
1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res '
2. Production Hole: No mud logging. On site geologist. LWD: GR + ADR (For geo-steering)
Page 7
H
Hilcorp
Eo Comp.vy
Milne Point Unit
E-42 SB Producer
Drilling Procedure
8.0 Mandatory Regulatory Compliance / Notifications
Regulatory Compliance
Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations,
specific regulations are listed below. If additional clarity or guidance is required on how to comply with
a specific regulation, do not hesitate to contact the Anchorage Drilling Team.
• BOPs shall be tested at (2) week intervals during the drilling and completion of MPU E-42. Ensure
to provide AOGCC 24 hrs notice prior to testing BOPS.
• The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment
will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial
and subsequent tests). Confirm that these test pressures match those specified on the APD.
• If the BOP is used to shut in on the well in a well control situation or control fluid flow from the
well bore, AOGCC is to be notified and we must test all BOP components utilized for well control
prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP
test.
• All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program
and drilling fluid system".
• All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and
completion: blowout prevention equipment and diverter requirements".
o Ensure the diverter vent line is at least 75' away from potential ignition sources
• Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office.
AOGCC Regulation Variance Requests:
None requested
Page 8
Milne Point unit
E-42 SB Producer
Hilcorp Drilling Procedure
E��Wr
Summary of BOP Equipment and Test Requirements
Hole Section
Equipment
Test Pressure si
12 1/4"
13-5/8" 5M CTI Annular BOP w/ 16" diverter line
Function Test Only
13-5/8" x 5M Control Technology Inc Annular BOP
• 13-5/8" x 5M Control Technology Inc Double Gate
Initial Test: 250/3000
o Blind ram in him cavity
• Mud cross w/ 3" x 5M side outlets
13-5/8" x 5M Control Technology Single ram
• 3-1/8" x 5M Choke Line
Subsequent Tests:
• 3-1/8" x 5M Kill line
250/3000
• 3-1/8" x 5M Choke manifold
• Standpipe, floor valves, etc
Primary closing unit: Control Technology Inc. (CTI), 6 station, 3000 psi, 220 gallon accumulator unit.
Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric
triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen.
The remote closing operator panels are located in the doghouse and on accumulator unit.
Required AOGCC Notifications:
• Well control event (BOPS utilized to shut in the well to control influx of formation fluids).
• 24 hours notice prior to spud.
• 24 hours notice prior to testing BOPS.
• 24 hours notice prior to casing running & cement operations.
• Any other notifications required in APD.
Regulatory Contact Information:
AOGCC
Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.regglct�,alaska.gov
Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guuy.schwartz@alaska.gov
Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.loeppna alaska.eov
Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-xxx-xxxx / Email: melvin.rixse@alaska.gov
Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov
Test/Inspection notification standardization format: h_ptt :Hdoa alaska gov/o¢c/forms/T estWitnessNotifhtml
Notification / Emergency Phone: 907-793-1236 (During normal Business Hours)
Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours)
Page 9
9.0 R/U and Preparatory Work
9.1 E-42 will utilize a newly set 20" conductor on E Pad Expansion. Ensure to review attached
surface plat and make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4" nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Innovation Rig. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<800F).
9.10 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is
accidentally dropped.
9.11 Ensure 5" liners in mud pumps.
• White Star Quattro 1300 Hp mud pumps are rated at 4097 psi, 381 gpm @ 140 spm @
96.5% volumetric efficiency.
Page 10
Milne Point unit
E-42 SB Producer
Hilcorp
T-
Drilling Procedure
Eiw�p Cv
9.0 R/U and Preparatory Work
9.1 E-42 will utilize a newly set 20" conductor on E Pad Expansion. Ensure to review attached
surface plat and make sure rig is over appropriate conductor.
9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor.
9.3 Install landing ring.
9.4 Insure (2) 4" nipples are installed on opposite sides of the conductor with ball valves on each.
9.5 Level pad and ensure enough room for layout of rig footprint and R/U.
9.6 Rig mat footprint of rig.
9.7 MIRU Innovation Rig. Ensure rig is centered over conductor to prevent any wear to BOPE or
wellhead.
9.8 Mud loggers WILL NOT be used on either hole section.
9.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<800F).
9.10 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is
accidentally dropped.
9.11 Ensure 5" liners in mud pumps.
• White Star Quattro 1300 Hp mud pumps are rated at 4097 psi, 381 gpm @ 140 spm @
96.5% volumetric efficiency.
Page 10
Milne Point Unit
E-42 SB Producer
Hilcorp Drilling Procedure
10.0 N/U 13-5/8" 5M Diverter Configuration
10.1 N/U 13-5/8" CTI BOP stack in diverter configuration (Diverter Schematic attached to program).
• N/U 20" x 13-5/8" DSA
• N/U 13 5/8", 5M diverter "T".
• NU Knife gate & 16" diverter line.
• Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C).
• Diverter line must be 75 ft from nearest ignition source
• Place drip berm at the end of diverter line.
• Utilized extensions if needed.
10.2 Notify AOGCC. Function test diverter. Ensure that the knife gate and annular are operated on
the same circuit so that knife gate opens prior to annular closure.
10.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the
vent line tip. "Warning Zone" must include:
• A prohibition on vehicle parking
• A prohibition on ignition sources or running equipment
• A prohibition on staged equipment or materials
• Restriction of traffic to essential foot or vehicle traffic only.
10.4 Set wear bushing in wellhead.
Page 11
Milne Point unit
E-42 SB Producer
Hilcorp Drilling Procedure
SMT
10.5 Rig & Diverter Orientation:
• Note: Diverter Orientation May Change On Locatoin
7S' Radius Clear of Ignition Sources
— Diverter Line
Page 12
E-42
MPU E Pad Expansion
27 ■
■ 32
10 ■
IS 31
28 ■
■ 4
22 ■
■ 1
295 ■
13 ■
11115
26 ■
■ 30
■ 6
E-42
■ 21
11
■ 7
is 111
■ 16
20 ■
■ 23
24 ■
■ 19
14 ■
, 12
34
*Drawing Not To Scale
H
Hileorp
E.v ,m
11.0 Drill 12-1/4" Hole Section
Milne Point Unit
E-42 SB Producer
Drilling Procedure
11.1 P/U 12-1/4" directional drilling assembly:
• Ensure BHA components have been inspected previously.
• Drift and caliper all components before M/U. Visually verify no debris inside components
that cannot be drifted.
• Ensure TF offset is measured accurately and entered correctly into the MWD software.
• Be sure to run a UBHO sub for wireline gyro
• Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
• Drill string will be 5" 19.5# 5-135.
• Run a solid float in the surface hole section.
11.2 5" Drill string, HWDP, and Jars will come from Weatherford.
11.3 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor.
11.4 Drill 12-1/4" hole section to section TD, in the Schrader OB sand. Confirm this setting depth
with the Geologist and Drilling Engineer while drilling the well.
• Monitor the area around the conductor for any signs of broaching. If broaching is observed,
Stop drilling (or circulating) immediately notify Drilling Engineer.
• Efforts should be made to minimize dog legs in the surface hole. ESP equipment can be
damaged if run through high dog legs. Keep DLS < 6 deg / 100.
• Hold a safety meeting with rig crews to discuss:
• Conductor broaching ops and mitigation procedures.
• Well control procedures and rig evacuation
• Flow rates, hole cleaning, mud cooling, etc.
• Pump sweeps and maintain mud rheology to ensure effective hole cleaning.
• Keep mud as cool as possible to keep from washing out permafrost.
• Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can
handle the flow rate.
• Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if
packoffs, increase in pump pressure or changes in hookload are seen
• Slow in/out of slips and while tripping to keep swab and surge pressures low
• Ensure to leave a "Pump Tangent" section that is approx. 300' long in the directional plan
The ESP will need a straight section to sit. Target location of ESP pump tangent is 1000'
MD and 200' TVD above target reservoir.
• Ensure shakers are functioning properly. Check for holes in screens on connections.
• Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea
gravel, clay balling or packing off.
• Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 '
minimum at TD (pending MW increase due to hydrates).
Page 13
H
Hilcorp
E.[ CLT
Milne Point Unit
E-42 SB Producer
Drilling Procedure
• Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand
drilled.
• Gas hydrates have been encountered on E -Pad, typically around 2100-2.100' TVD (Oust ✓
below permafrost). Be prepared for hydrates:
• Gas hydrates can be identified by the gas detector and a decrease in MW or ECD
• Monitor returns for hydrates, checking pressurized & non -pressurized scales
Do not stop to circulate out gas hydrates — this will only exacerbate the problem by
washing out additional permafrost. Attempt to control drill (150 fph MAX) through the
zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be
reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to
allow the gas to break out.
Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well.
MW will not control gas hydrates, but will affect how gas breaks out at surface.
11.5 12-1/4" hole mud program summary:
• Density: Weighting material to be used for the hole section will be barite. Additional
barite or spike fluid will be on location to weight up the active system (1) ppg above
highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg and
TD -
Page 14
with 9.[+ ppg.
Depth Interval MW g)
Surface — Base Permafrost 8.9+
Base Permafrost - TD 9.0-9.2 (Increase if needed)
• PVT System: MD Totco PVT will be used throughout the drilling and completion phase.
Remote monitoring stations will be available at the driller's console, Co Man office,
Toolpusher office, and mud loggers office.
• Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system
with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times
while drilling. Be prepared to increase the YP if hole cleaning becomes an issue.
• Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10
ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling
the surface interval to prevent losses and strengthen the wellbore.
• Wellbore and mud stability: Additions of CON DET PRE-MLY/DRIL N SLIDE are
recommended to reduce the incidence of bit balling and shaker blinding when penetrating the
high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A.
Maintain the pH in the 8.5 — 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-
CIDE 207 MUST be made to control bacterial action.
• Casing Running: Reduce system YP with DESCO as required for running casing as allowed
(do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures.
n
Hilcorp
E, Coa
Milne Point Unit
E-42 SB Producer
Drilling Procedure
Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to
see what YP value they have targeted).
System Type: 8.8 — 9.8 ppg Pre -Hydrated AquageUfreshwater spud mud
Properties
Section
Density
Viscosity
Plastic Viscosity
Yield Point
AN FL
pH
Tem
Surface
8.8 — 9.8 '1
75-175
1 20-40
1 25-45
<10
8.5-9.0
<_ 70 F
System Formulation: Gel + FW spud mud
Product
Concentration
Fresh Water
0.905 bbl
soda Ash
0.5 ppb
AQUAGEL
15 - 20 ppb
caustic soda
0.1 ppb (8.5 — 9.0 pH)
BARAZAN D+
as needed
BAROID 41
as required for 8.8 — 9.2 ppg
PAC -L /DEXTRID LT
if required for <10 FL
ALDACIDE G
0.1 ppb
11.6 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity.
11.7 RIH t/ bottom, proceed to BROOH t/ HWDP
• Pump at full drill rate (400-600 gpm), and maximize rotation.
• Pull slowly, 5 — 10 ft / minute.
• Monitor well for any signs of packing off or losses.
• Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay
balling.
• If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until
parameters are restored.
11.8 TOOH and LD BHA
11.9 No open hole logging program planned.
Page 15
H
Hilcorp
Em C® Y
12.0 Run 9-5/8" Surface Casing
12.1 R/U and pull wearbushing.
Milne Point Unit
E-42 SB Producer
Drilling Procedure
12.2 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs)
• Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV.
• Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
• R/U of CRT if hole conditions require.
• R/U a fill up tool to fill casing while running if the CRT is not used.
• Ensure all casing has been drifted to 8.75" on the location prior to running.
• Be sure to count the total # of joints on the location before running.
• Keep hole covered while R/U casing tools.
• Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info.
12.3 P/U shoe joint, visually verify no debris inside joint.
12.4 Continue M/U & thread locking 120' shoe track assembly consisting of:
9-5/8"
Float Shoe
1 joint
— 9-5/8" DWC, 2 Centralizers 10'
from each end w/ stop rings
1 joint
— 9-5/8" DWC, 1 Centralizer mid
joint w/ stop ring
9-5/8"
Float Collar w/ Stage Cementer Bypass
Baffle 'Top Hat'
1 joint
— 9-5/8" DWC, 1 Centralizer mid
joint with stop rilI
9-5/8"
HES Baffle Adaptor
• Ensure bypass baffle is correctly installed on top of float collar.
This end up. -�
Bypass Baffle
CD
• Ensure proper operation of float equipment while picking up.
• Ensure to record S/N's of all float equipment and stage tool components.
Page 16
Milne Point unit
E-42 S8 Producer
Hilcox Drilling Procedure
n.� o-
12.5 Float equipment and Stage tool equipment drawings:
Type H ES Cementer
Part No.
SO No.
Closing Sleeve
No. Shear Pins
Opening Sleeve
No. Shear Pins
ES Cementer
Depth
Baffle Adapter ("tf used)
ID
Depth
Bypass or Shut -oft Baffle
ID
Depth
Float Collar
Depth
Float Shoe
Depth
Hole To
'Reference Casing
Sales Manual
Secton 5
Page 17
"A
Riker, ESI] Mooing order
Overall Length
B
SMrt on,lug
Alin. ID After Drillout
C
Mat, Taol OD
D
Openorg Seat lD
E
Mat Collar
Closing Seat ID
Plug Set
Part No.
SO No.
Closing Plug
OD
Opening Plug
OD
OD
Shut-off Plug
OD
Bypass Plug
(if used)
oD
Riker, ESI] Mooing order
ES41 Cementer
SMrt on,lug
BaBle Adapter
eyAass,Wg
�L.
C
By Pass saHk
Mat Collar
Mat 5hae
H
Hilcorp
mover
12.6 Continue running 9-5/8" surface casing
Milne Point Unit
E-42 SB Producer
Drilling Procedure
• Fill casing while running using fill up line on rig floor.
• Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
• Centralization:
• 1 centralizer every joint t/ — 1000' MD from shoe
• 1 centralizer every 2 joints to 2,000' above shoe (Top of Uenu)
• Ensure there are no centralizers on joints above or below planned window depth of
7776' MD
• Verify depth of lowest Ugnu water sand for isolation with Geolol?ist
• Utilize a collar clamp until weight is sufficient to keep slips set properly.
• Break circulation prior to reaching the base of the permafrost if casing run indicates poor
hole conditions.
Any packing off while running casing should be treated as a major problem. It is preferable
to POH with casing and condition hole than to risk not getting cement returns to surface.
12.7 Install the Halliburton Type H ES -11 Stage tool so that it is positioned at least 100' TVD below
the permafrost (— 2,500' MD).
• Install centralizers over couplings on 5 joints below and 5 joints above stage tool.
• Do not place tongs on ES cementer, this can cause damaged to the tool.
• Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi.
9-5/8" 40# L-80 TXP Make Up Torques:
Casing OD
Minimum
Optimum
Maximum
9-5/8"
18,860 ft -lbs
20,960 ft -lbs
23,06011 -lbs
Page 18
H
Hilc0rp
Ev�Compmy
TXP® BTC
Milne Point Unit
E-42 SB Producer
Drilling Procedure
Outside Diameter
9.625 in.
Min. Wall
87.5%
I'1 Grade L80
I
cceneew OD
Make-up Loss
Thiekress
coupling Length
Threads per E
Type d
£ Wall Thickness
0395in.
Connection00
REGULAR
DDUPLIRG
Option
Edi Red
Grade
L80 Type P
Drift
AN Standard
15 Sa IS.
2nd Band: -
Type
Casing
3m Band'. -
PIPE BODY DATA
GEOMETRY
Nominal DD
9625 in.
Nominal Weight
40 Went
Dtl8
No sinal ID
8.835 in.
Wag Thickness
0.195 N.
Plain End Might
OD Tolerance
API
Page 19
�,.--11108/2018
PIPE BODY
1st SarA'. Red
2rA Band:
Brown
and Sand -
41h Band: -
8.679 m.
38.97 Ibelft
PERFORMANCE
Body Yevid Strength 916 xi 000 Its ImemalYudd 5750 psi SMYS amps,
collapse 3090 psi
GEOMETRY
I
cceneew OD
Make-up Loss
10.625 in.
4.891 in.
coupling Length
Threads per E
10.825 in.
5
Connection ID
Cennecuon OD Option
8 823 in.
REGULAR
PERFORMANCE
Tension EOeienry 100.05 bmrYkif SUenglh 916.000x1000 Internal Pressure Capacity nl 5750.000 psi
lbs
Compression Efficiency 100 Compresaion Strength 916.000 x1000 1Aaxmo v be Sending 38 `,100 R
Itis
EnemaI Presses Capacity 3090.0011 psi
MAKE-UP TORQUES
Iduanium 188609-Afs Optimum 20960ft4bs Maximum 23080 Nibs
OPERATION LIMIT TORQUES
Opem ig Toque 35600 Albs Yield Toque 43400 fi4bs
Notes
This connection is fully interchangeable with:
TXPt BTC - 9-625 in. - 36143.5147153.5158.4 lbs/ft
[11 Internal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API
5C3 I ISO 10400 - 2007.
Datasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load, which will be reduced.
Please contact a local Tenons technical sales representative.
Milne Point Unit
E-42 SB Producer
Drilling Procedure
12.8 Continue running 9-5/8" surface casing
• Fill casing while running using fill up line on rig floor.
• Use BOL 2000 thread compound. Dope pin end only w/ paint brush.
• Centralization:
o 1 centralizer every 2 joints to base of conductor
12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if
necessary.
12.10 Slow in and out of slips.
12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10' from TD. Strap the
landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference
when getting the casing on depth.
12.12 Lower casing to setting depth. Confirm measurements.
12.13 Have slips staged in cellar, along with necessary equipment for the operation.
12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement
job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible
reciprocate casing string while conditioning mud.
Page 20
N
Hilo
rp
Evu -ZT
13.0 Cement 9-5/8" Surface Casing
Milne Point Unit
E-42 SB Producer
Drilling Procedure
13.1 Hold a pre job safety meeting over the upcoming cement operations. Make room in pits for
volume gained during cement job. Ensure adequate cement displacement volume available as
well. Ensure mud & water can be delivered to the cementing unit at acceptable rates.
• How to handle cement returns at surface. Ensure vac trucks are on standby and ready to
assist.
• Which pumps will be utilized for displacement, and how fluid will be fed to displacement
PUMP.
• Ensure adequate amounts of water for mix fluid is heated and available in the water tanks.
• Positions and expectations of personnel involved with the cementing operation.
i. Extra hands in the pits to strap during the cement job to identify any losses
• Review test reports and ensure pump times are acceptable.
• Conduct visual inspection of all hard lines and connections used to route slurry to rig floor.
13.2 Document efficiency of all possible displacement pumps prior to cement job.
13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will
help ensure any debris left in the cement pump or treating iron will not be pumped downhole.
13.4 RAJ cement line (if not already done so). Company Rep to witness loading of the top and
bottom plugs to ensure done in correct order.
13.5 Fill surface cement lines with water and pressure test.
13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.7 Drop bottom plug (flexible bypass plug) — HEC rep to witness. Mix and pump cement per below
calculations for the l5r stage, confine actual cement volumes with cementer after TD is reached.
13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead &
tail, TOC brought to stage tool.
Estimated lst Stage Total Cement Volume:
Page 21
✓W st-
3
Section
Calculation
Vol (bbl)
Vol (ft3)
12-1/4" OH x 9-5/8"
(7,100' - 2500') x .0558 bpf x 1.3 =
333.7
1873.5
v
Casing
J
Total Lead
333.7
1873.5
12-1/4" OH x 9-5/8"
(8,100'-7, 100')x.0558bpfx1.3=
72.5
407
Casing
~
9-5/8" Shoe Track
120'x .0758 bpf =
9.1
51.09
Total Tail
I
81.6
458
Page 21
✓W st-
3
Hilcorp
eon, c��,
Milne Point unit
E-42 SB Producer
Drilling Procedure
Tail Slurry
Cement Slurry Design (V Stage Cement Job):
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very
accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool
hydraulically, the plug must be bumped.
13.11 Displacement calculation:
7,980' x .0758 bpf = 604.8 bbls
80 bbls of water to be left behind stage tool
13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, t4.5 bbls before consulting with Drilling
Engineer.
13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening
plug is available if needed. This is the back-up option to open the stage tool if the plugs are not
bumped.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
Page 22
Lead Slurry
Tail Slurry
System
ExtendaCEM `M System
SwiftCEM rM System
Density
11.7 lb/gal
15.8 lb/gal
Yield
4.298 ft3/sk
1.16 ft3/sk
Mixed
Water
21.13 gal/sk
5.04 gal/sk
13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch
reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue
with the cement job.
13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of
mud pits, spotting water across the HEC stage cementer.
Ensure volumes pumped and volumes returned are documented and constant communication
between mud pits, HEC Rep and HES Cementers during the entire job.
13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very
accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool
hydraulically, the plug must be bumped.
13.11 Displacement calculation:
7,980' x .0758 bpf = 604.8 bbls
80 bbls of water to be left behind stage tool
13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any
point during the job. Be prepared to pump out fluid from cellar. Have black water available to
contaminate any cement seen at surface.
13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over
displace by no more than 50% of shoe track volume, t4.5 bbls before consulting with Drilling
Engineer.
13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening
plug is available if needed. This is the back-up option to open the stage tool if the plugs are not
bumped.
13.15 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats
are holding. If floats do not hold, pressure up string to final circulating pressure and hold until
Page 22
n
Hilcorp
ElCmvW^Y
Milne Point Unit
E-42 SB Producer
Drilling Procedure
cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating
pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened.
13.16 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure
may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns
to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation
for the 2nd stage of the cement job.
13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker
bypass line to the cuttings tank. Have black water available and vac trucks ready to assist.
Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact
with the cement.
Page 23
Second Stage Surface Cement Job:
Milne Point Unit
E-42 SB Producer
Drilling Procedure
13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive
strength. Hold pre job safety meeting.
13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing
head.
13.20 Fill surface lines with water and pressure test.
13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer.
13.22 Mix and pump cmt per below recipe for the 2"d stage.
13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail).
Job will consist of lead & tail, TOC brought to surface. However cement will continue to be
pumped until clean spacer is observed at surface.
--, 5 & -) V -
Estimated 2"d Stage Total Cement Volume:
Cement Slurry Design (2nd stage cement job):
Section
Calculation
Vol (bbl)
Vol (ft3)
SwiftCEM TM System (Hal Cem)
20" Conductor x 9-5/8" Casing
(110') x.26 bpf x 1=
28.6
161
v
J
12-1/4" CH x 9-5/8" Casing
(2000'- 110') x.0558 bpf x 3 =
316.4
1776.3
Total Lead
345
1937
12-1/4" CH x 9-5/8" Casing
(2500'- 2000') x .0558 bpf x 2 =
55.8
314
~
Total Tail
55.8
314
Cement Slurry Design (2nd stage cement job):
Page 24
Lead Slurry
Tail Slurry
System
Permafrost L
SwiftCEM TM System (Hal Cem)
Density
10.71b/gal
15.8 lb/gal
Yield
4.3279 ft3/sk
1.16 ft3/sk
Mixed
Water
21.405 gal/sk
5.08 gal/sk
Page 24
Milne Point Unit
E-42 SB Producer
Drilling Procedure
13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail.
13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out
of mud pits.
13.26 Displacement calculation:
2500' x .0758 bpf = 190 bbls mud
13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side
outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out
fluid from cellar. Have black water available to retard setting of cement.
13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should
circulate approximately 100 - 150 bbls of cement slurry to surface.
13.29 Land closing plug on stage collar and pressure up to 1000 — 1500 psi to ensure stage tool closes.
Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool
has closed. Slips will be set as per plan to allow full annulus for returns during surface cement
job. Set slips
13.30 Make initial cut on 9-5/8" final joint. L/D cut joint. Make final cut on 9-5/8". Dress off stump.
Install 9-5/8" wellhead. If transition nipple is welded on, allow to cool as per schedule.
Ensure to report the following on wellez:
• Pre flush type, volume (bbls) & weight (ppg)
• Cement slurry type, lead or tail, volume & weight
• Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration
a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type
of displacing fluid
b. Note if casing is reciprocated or rotated during the job
c. Calculated volume of displacement , actual displacement volume, whether plug bumped & bump
pressure, do floats hold
d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating
pressure
e. Note if pre flush or cement returns at surface & volume
f Note time cement in place
g. Note calculated top of cement
h. Add any comments which would describe the success or problems during the cement job
Send final "As -Run" casing tally & casing and cement report to ien eellna.hilcorp.com and
cdingerghilcoWcom This will be included with the EOW documentation that goes to the AOGCC.
Page 25
14.0 BOP NX and Test
14.1 N/D the diverter T, 16" knife gate, 16" diverter line & N/U 11" x 13-5/8" 5M casing spool.
14.2 NX 13-5/8" x 5M CTI BOP as follows:
• BOP configuration from top down: 13-5/8" x 5M annular / 13-5/8" x 5M double gate / 13-
5/8" x 5M mud cross / 13-5/8" x 5M single gate
• Double gate ram should be dressed with 2-7/8" x 5.5" VBRs in top cavity, blind ram in
bottom cavity.
• Single ram should be dressed with 2-7/8" x 5.5" VBRs or 5" Solid Body Rams
• N/U bell nipple, install flowline.
• Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
• Install (1) manual valve & HCR valve on choke side of mud cross. (manual valve closest to
mud cross)
14.3 Run 5" BOP test plug (if not installed previously).
n • Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
'C • Confirm test pressures with PTD
/ • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
(\ &I is trapped underneath test plug
• Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.4 R/D BOP test equipment
14.5 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.6 Mix 8.9 ppg Baradrill-N fluid for production hole.
14.7 Set wearbushing in wellhead.
14.8 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section.
14.9 Ensure 5" liners in mud pumps.
Page 26
Milne Point unit
E-42 SB Producer
Hilcorp
En Compmy
Drilling Procedure
14.0 BOP NX and Test
14.1 N/D the diverter T, 16" knife gate, 16" diverter line & N/U 11" x 13-5/8" 5M casing spool.
14.2 NX 13-5/8" x 5M CTI BOP as follows:
• BOP configuration from top down: 13-5/8" x 5M annular / 13-5/8" x 5M double gate / 13-
5/8" x 5M mud cross / 13-5/8" x 5M single gate
• Double gate ram should be dressed with 2-7/8" x 5.5" VBRs in top cavity, blind ram in
bottom cavity.
• Single ram should be dressed with 2-7/8" x 5.5" VBRs or 5" Solid Body Rams
• N/U bell nipple, install flowline.
• Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to
mud cross).
• Install (1) manual valve & HCR valve on choke side of mud cross. (manual valve closest to
mud cross)
14.3 Run 5" BOP test plug (if not installed previously).
n • Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min.
'C • Confirm test pressures with PTD
/ • Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure
(\ &I is trapped underneath test plug
• Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech
14.4 R/D BOP test equipment
14.5 Dump and clean mud pits, send spud mud to G&I pad for injection.
14.6 Mix 8.9 ppg Baradrill-N fluid for production hole.
14.7 Set wearbushing in wellhead.
14.8 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section.
14.9 Ensure 5" liners in mud pumps.
Page 26
Milne Point unit
E-42 SB Producer
Hilcorp Drilling Procedure
� max.
15.0 Drill 8-1/2" Hole Section
15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.22° PDM)
15.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out
stage tool or ESIPC.
15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report.
/15.4 1W and test casing to 2500 psi / 30 min. Ensure to record volume / pressure and plot on FIT
sc graph. AOGCC reg is 50% of burst = 6870 / 2 = —3500 psi, but max test pressure on the well is
\vy y 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and
a0 volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin
17-001.
15.5 Drill out shoe track and 20' of new formation.
15.6 CBU and condition mud for FIT.
15.7 Conduct FIT to 12 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT.
Document incremental volume pumped (and subsequent pressure) and volume returned.
15.8 POOH & LD Cleanout BHA
15.9 P/U 8-1/2" directional BHA.
• Ensure BHA components have been inspected previously.
• Drift and caliper all components before M/U. Visually verify no debris inside components that
cannot be drifted.
• Ensure TF offset is measured accurately and entered correctly into the MWD software.
• Ensure MWD is R/U and operational.
• Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics
calculations and recommended TFA is attached below.
• Drill string will be 5" 19.54 S-135 DS50 & NC50.
• Run a ported float in the production hole section.
15.10 8-1/2" hole section mud program summary:
Density: Weighting material to be used for the hole section will be calcium carbonate.
Additional calcium carbonate will be on location to weight up the active system (1) ppg
above highest anticipated MW.
Page 27
Milne Point Unit
E-42 SB Producer
Hilcorp Drilling Procedure
e�comvmr
• Solids Concentration: It is imperative that the solids concentration be kept low while
drilling the production hole section. Keep the shaker screen size optimized and fluid
running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure
we are running the finest screens possible.
• Rheology: Keep viscosifier additions to an absolute minimum (N -VIS). Data suggests
excessive viscosifier concentrations can decrease return permeability. Do not pump high
vis sweeps, instead use tandem sweeps. Ensure 6 r12m is > 8.5 (hole diameter) for
sufficient hole cleaning
• Run the centrifuge continuously while drilling the production hole, this will help with
solids removal.
• Dump and dilute as necessary to keep drilled solids to an absolute minimum.
• MD Totco PVT will be used throughout the drilling and completion phase. Remote
monitoring stations will be available at the driller's console, Co Man office, &
Toolpusher office.
System Type: 8.9 — 9.5 ppg Baradrill-N drilling fluid
Properties:
Section
Densi
Plastic Vtscosi
Yield Point
Total Solids
MBT
HPHT
Production
1 8.9-9.5
15-25
1 20-25
1 <10%
<7
4 ppb
System Formulation: Baradrill-N
Product
Concentration
Water
0.955 bbl
KCL
11 ppb
KOH
0.1 ppb
N -VIS
1.0 — 1.5 ppb
DEXTRID LT
5 ppb
BARACARB 5
4 ppb
BARACARB 25
4 ppb
BARACARB 50
2 ppb
BARACOR 700
1.0 ppb
BARASCAV D
0.5 ppb
X-CIDE 207
0.015 ppb
Page 28
15.11 TIH with 8-1/2" directional assembly to bottom
15.12 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid
15.13 Begin drilling 8.5" hole section, on -bottom staging technique:
• Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k.
• Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
• If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
.5% lubes
15.14 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer.
• Flow Rate: 350-550 gpm, target min. AV's 200 ft/min, 385 gpm
• RPM: 120+
• Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
• Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
• Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
• Monitor Torque and Drag with pumps on every 5 stands
• Monitor ECD, pump pressure & hookload trends for hole cleaning indication
• Surveys can be taken more frequently if deemed necessary.
• Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
• Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
• Target ROP is as fast as we can clean the hole without having to backream connections
• Schrader Bluff NB Concretions: Historically 4-6% of lateral
• MPD will be used to monitor for abnormal pressure on connections
15.15 Reference: Open hole sidetracking practice:
• If a known fault is coming up, put a slight "kick-off ramp" in wellbore ahead of the fault so
we have a nice place to low side.
• Attempt to lowside in a fast drilling interval where the wellbore is headed up.
• Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string
back and forth. Trough for approx. 30 min.
• Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump
tandem sweeps if needed
• Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
Page 29
Milne Point unit
E-42 S8 Producer
Hilcorp
Drilling Procedure
Enema'( wy
15.11 TIH with 8-1/2" directional assembly to bottom
15.12 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid
15.13 Begin drilling 8.5" hole section, on -bottom staging technique:
• Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k.
• Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations
• If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U
off bottom and restart on bottom staging technique. If stick slip continues, consider adding
.5% lubes
15.14 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer.
• Flow Rate: 350-550 gpm, target min. AV's 200 ft/min, 385 gpm
• RPM: 120+
• Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly
wet to maximize solids removal efficiency. Check for holes in screens on every connection.
• Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low
• Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex:
concretion deflection
• Monitor Torque and Drag with pumps on every 5 stands
• Monitor ECD, pump pressure & hookload trends for hole cleaning indication
• Surveys can be taken more frequently if deemed necessary.
• Good drilling and tripping practices are vital for avoidance of differential sticking. Make
every effort to keep the drill string moving whenever possible and avoid stopping with the
BHA across the sand for any extended period of time.
• Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but
when concretions are hit when drilling this fast, cutter damage can occur.
• Target ROP is as fast as we can clean the hole without having to backream connections
• Schrader Bluff NB Concretions: Historically 4-6% of lateral
• MPD will be used to monitor for abnormal pressure on connections
15.15 Reference: Open hole sidetracking practice:
• If a known fault is coming up, put a slight "kick-off ramp" in wellbore ahead of the fault so
we have a nice place to low side.
• Attempt to lowside in a fast drilling interval where the wellbore is headed up.
• Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string
back and forth. Trough for approx. 30 min.
• Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the
openhole sidetrack is achieved.
15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump
tandem sweeps if needed
• Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent
stream, circulate more if necessary
Page 29
Milne Point unit
E-42 SB Producer
Hilcorp Drilling Procedure
EM�g Compmy
Ensure mud has necessary lube % for running liner
If seepage losses are seen while drilling, consider reducing MW at TD to 9.Oppg minimum
15.17 BROOH with the drilling assembly to the 9-5/8" casing shoe
• Circulate at full drill rate (385 gpm max).
• Rotate at maximum rpm that can be sustained.
• Limit pulling speed to 5 —10 min/std (slip to slip time, not including connections).
• If backreaming operations are commenced, continue backreaming to the shoe
15.18 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while
BROOH
15.19 CBU minimum two times at 9-5/8" shoe and clean casing with high vis sweeps.
15.20 Monitor well for flow. Increase mud weight if necessary. If abnormal pressure has been seen,
displace to higher MW (determined on closed connections) from surface shoe to surface.
Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to
determine if well is breathing, treat all flow as an influx until proven otherwise
15.21 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball
drops.
15.22 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is
sufficient for future ball drops.
Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any
additional logging runs conducted.
Page 30
Milne Point unit
E-42 SB Producer
HilHilcorp Drilling Procedure
CmnP°°Y
16.0 Run 4-1/2" Production Liner
16.1. Well control preparedness: In the event of an influx of formation fluids while running the 4-
1/2" liner, the following well control response procedure will be followed:
• P/U & MM the 5" safety joint (with 4-1/2" crossover installed on bottom, TIW valve in open
position on top, 4-1/2" handling joint above TIW). This joint shall be fully M/U and
available prior to running the first joint of 4-1/2".
• Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close
TIW valve.
• Proceed with well kill operations.
16.2. Well control preparedness: In the event of an influx of formation fluids, while running the 2-
3/8" inner string inside the 4-1/2" liner:
• P/U & M/LT the 5" safety joint (with 4-1/2" x 2-3/8" triple connect crossover installed on
bottom, TIW valve in open position on top, 2-3/8" handling joint above TIW). M/U 2-3/8"
and then 4-1/2" to triple connect.
• This joint shall be fully M/U with crossovers prior to running the first joint of wash pipe.
• Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close
TIW valve. Proceed with well kill operations.
16.3. R/L14-1/2" running equipment.
• Ensure 4-1/2" x DS -50 crossover is on rig floor and M/U to FOSV.
• Ensure all casing has been drifted on the deck prior to running.
• Be sure to count the total # of joints on the deck before running.
• Keep hole covered while R/U casing tools.
• Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info.
16.4. Run 4-1/2" production liner — Reference handling and running procedure.
• Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only w/ paint
brush. Wipe off excess.
• Use Hydril 625 stabbing guide
• Utilize a collar clamp until weight is sufficient to keep slips set properly.
• Run packoff and float shoe on bottom.
• 4-1/2" pre drilled liner should auto —fill, top off with completion brine if needed
• Swell packers will not be required on this completion unless the well is drilled out of zone
Page 31
H
Hilcorp
U=
4-'h" Lower Completion Running Order
Milne Point Unit
E-42 SB Producer
Drilling Procedure
• 4-'/2" Float Shoe, BTC box (Bakerlok all 4-V2" shoe track connections below the last semi-
premium/premium connection)
• 4-'/2" WIV (wellbore isolation valve), BTC box x pin
• 4-'/2" spacer joint, —30 - 40', IBT-M box x BTC pin
• 4-'/2" Drillable Pac Off Sub, IBT-M box x pin
• 5' 4.5" 13.5# Hydril 625 Box X 4.5" 12.6# IBT Pin crossover
• 1 joint 4-'/2" 13.5#/ft L-80 Hydril 625 Liner (optional)
• 4-%2' 13.5#/ft L-80 Hydril 625
• Joints of 4-%2" 13.5#/ft Hydril 625 L-80 Liner (liner lap) as needed
•
4'4.5" 13.5# Hydril 625 Box X Pin pup joint (safety joint)
• 7" 26# HYD 563 Box x 4.5" 13.5# Hydril 625 Pin crossover
• Baker SLZXP Liner Hanger/Liner Top Packer w/ 7" 26# Hydril 563 pin
4-1/21113.5 # L-80 H dril 625 Tor ue
OD
Minimum
Maximum Operating Torque
8,000 ft -lbs
11,300 ft -lbs 1 11,300 ft -lbs
Page 32
Milne Point Unit
E-42 SB Producer
Hilcorp Drilling Procedure
e r -
Wedge 6250 m,.aai013112017
ONside Diameter
4.500 in.
Min. Wall
87.5%
GEOMETRY
Thickness
(') Grade LBO
Nominal OD
1.500 in.
Nominal Weight
13.501bs1R
Type 1
3.795 i,
Wall Thickness
0.290 in.
Conimnion OD
REGULAR
COUPLING
PIPE BODY
OD Tolerance
A%
Option
Body. Red
ts[BanQ Red
Grade
L80 Type 1'
Drift
API Standard
1st Barts: Brown
2nd Band:
Body Yield St enp
307.1000 �
haemal Yield
9020 psi
2nd Band: -
&own
Cdlapse
8540 psi
3rd Band: -
3rd Band: -
CONNECTIONDATA
TYpe
Casing
4th Bond :-
FIFE BODY DATA
GEOMETRY
Nominal OD
1.500 in.
Nominal Weight
13.501bs1R
Drift
3.795 i,
N.al ID
3.920 in.
WPI Thielress
0290 in
Plain End W"M
13.051bsdt
OD Tolerance
A%
PERFORMANCE
Body Yield St enp
307.1000 �
haemal Yield
9020 psi
SMYS
80000 psi
Cdlapse
8540 psi
CONNECTIONDATA
GEOMETRY
Comenri0n oo
4.714 in.
Connection ID
19491,
Make-up Loss
4.8301,
Threads per in
3.%
Coarenson OD OpEon
REGULAR
PERFORMANCE
T.. Effioeney
91096
Join Y.A ShertBth
279.170.1000
Internal Pressure C PacKy
9020.000 psi
roe
Canyression ElStieney
915 %
Compression Strength
290115.1000
.Max. All.abls Bandag
73.7 °;1008
miss
External Pressure Capacity
8540.000 Psi
MAKE-UP TORQUES
Minimum
80008-Itrs
Opanam
9800fi-16s
Madrsan
12800 ftd
OPERATION LIMITTORQUES
operating1bra-
12600 ft-rbs
Yield Tolve
15000Mbs
Page 33
Milne Point unit
E-42 SB Producer
Hilcorp Drilling Procedure
�z�>
Note: Blank Pipe and Swell Packers may be ran if any out of zone excursion occur during lateral drilling
16.6. Pick up enough liner to provide to account for a liner hanger depth of 7835' MD.
• AOGCC regulations require a minimum 100' overlap between the inner and outer strings as
per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8" connection.
16.7. R/U false rotary and run 2-3/8" 6.4 # Inner String
• Drift 2-3/8" inner string with minimum 1.5" drift (WIV closing ball 1.25")
Note: Once inner string in run and set inside packoff, displace 9-5/8" casing back to PST passed
drilling mud with lubricants added.
16.8. Before picking up Baker SLZXP liner hanger / packer assembly, count the # of joints on the pipe
deck to make sure it coincides with the pipe tally.
16.9. M/U liner hanger/liner top packer to inner string and 4-1/2" liner. Fill liner tieback sleeve with
"Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff.
Wait 30 min for mixture to set up.
16.10. Note PUW, SOW, ROT and torque. Run liner in the hole one stand and pump through liner
hanger to ensure a clear flow path exists.
16.11. RIH w/ liner on DP no faster than 30 ft/min — this is to prevent buckling the liner and drill string.
Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down
running speed if necessary.
16.12. The liner and inner string will prevent the DP from auto filling. Fill DP with PST passed mud
every 5 stands, more frequently if SOW trend indicates.
16.13. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe
depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string
to bottom.
16.14. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10,
& 20 rpm
16.15. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure
shoe enters correct hole.
16.16. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in
tension.
16.17. Rig up to pump down the work string with the rig pumps.
Page 34
H
Hitco2Xrp
Milne Point Unit
E-42 SB Producer
Drilling Procedure
16.18. Break circulation and begin displacing wellbore to 2% KCl/NaCI brine, ensure weight matches
MW or previous brine weights. Begin circulating at —1 BPM and monitor pump pressures.
Slowly bring rate up while swapping the lateral to brine. Pump train as follows: 20 bbl high vis
sweep / 2 x OH volume brine / 40 bbl SAPP pill #1 / 50 bbl brine / 40 bbl SAPP pill #2 / 50 bbl
brine / 40 bbl SAPP pill #3.
16.19. Ensure circulation pressures do not exceed set pressure for liner hanger pusher tool.
16.20. Monitor pump pressures closely and adjust pump rate if the well appears to be packing off at the
swell packers (if run). Note all losses. Confirm all circulating pressures with Baker. Capture mud
for reconditioning and reuse if possible
16.21. Monitor the returned fluids carefully during displacement.
16.22. Circulate out SAPP pills prior to setting the hanger and packer. Double check all pipe tallies and
record amount of drill pipe left on location. Ensure all numbers coincide with proper setting
depth of liner hanger.
16.23. Shut down pumps. Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow
pump before the ball seats. Do not allow ball to slam into ball seat. Pressure up to 1,500 psi to
shift the wellbore isolation valve closed.
16.24. Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes.
Slack off 20K lbs on the SLZXP to ensure the HRDE setting tool is in compression for release
from the SLZXP liner hanger/packer. Continue pressuring up to 4500 psi to activate the
hydraulic pusher tool to set the SLZXP packer. This will also release the HRDE running tool.
16.25. Bleed DP pressure to zero, Pick up to expose Rotating Dog Sub and set down 50k4 without
pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 rpm
and set down 50k# again,
16.26. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same.
16.27. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If
packer did not test, rotating dog sub can be used to set packer. If running tool cannot be
hydraulically released, apply LH torque to mechanically release the setting tool.
16.28. P/U above liner top packer and displace well to completion fluid.
16.29. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned,
LDDP on the TOH. L/D 2-3/8" inner string.
f7.0 End of E-42 Operations / Begin E -42L1 Operations (Separate PTD)
Page 35
H
Hilcorp
U47
18.0 Innovation Rig Diverter Schematic
3-1/8' Kill L
13.58'
Technology ;
13-
Page 36
Milne Point Unit
E-42 SB Producer
Drilling Procedure
ontra Technology
!�
3-518' 5M contra
ethnology Donde Ram
•t/8' Chace Line
_-16' DNerter Line
0
MOONM�
19.0 Innovation Rig BOP Schematic
3-118" Kill
9-518" DBL D Seal
Casing Hanger
S-22
13-518" NOM
9-518" BTC Btm x
10.5"-4 SA Pin Top
W/ Primary Seal
Page 37
i
C
R
Milne Point Unit
E-42 SB Producer
Drilling Procedure
c
13-5/8" 5M Control Technology
Annular BOP
~�-13-5/8' 5M Control
Technology Double Ram
'—�-3-1/8' Choke Line
�--13-518" 5M Control
Technology Single Ram
5/8" x 5M
1"x 5M
x5M
x 5
\— 2-1/16" x 5M
-20" Casing
9-518" Casing
Milne Point unit
E-42 SB Producer
HHCO2 Drilling Procedure
E��
20.0 Wellhead Schematic
.r eL
1 "- f1UL b -d
r r l
._�............ .,....,.. •.i u_ox.li'riou 'err. u-., em
Y sv.
' •rr
4;
{. Na r, Y ll fll!IFv
1 V 1` Iefv 9 IItV
__ 1 SF314L tl' 1'
IIS aA Y w nry Fi r
^ � rvt-` z e- ,r..
� o e
0' S
iCk fR[c -. 1
�6 SGIr B1V W[° •
per 01.
i+.f4 1C d.2r eex:
�} 1�Y F•aJ
IL _U SNI
EII 5 SL 111 HOLE /
Door[ Larpul
eco! oulnms�efx
' - L AHO EUUGINNTIAL
101: Y•en..
_OE`_+iF1n
IIRFA NELLHELE L An)I71
-25-1 I
'
n
IIA
!. o! rw n w a cL o L
Y:
Cf llC. fF LFM1AI, M,
C.
11 5• 4 I Ib'S'. C. M1icl£1 10-2t-,7
Yx.0 SIWAv-ViRYL.f
•. `a `a �i�c.miiu
eYRaou.lx •a.m...
oe¢1
:o! •Sev e•.
�� oo:.`a¢w %ui �:
In -2>" I i G
ur
.nwf 77 0�t I r
j1Ab GG2,72p� I
l �! ��u•�a .. •-.�.x,.-
d.-GGF.d G 25 17
Page 38
Milne Point Unit
E-42 SB Producer
Hilcorp Drilling Procedure
E.v C®p�oy
21.0 Days Vs Depth
-1000
1000
3000
5000
O
-� 7000
v
G
Page 39
9000
11000
13000
15000
MPU E-42 SB Dual Lat OA/OB Producer
Days vs Depth
—MPU E-42 SB Dual Lat OA/OB
0 5 10 15 20 25
Days
Milne Point Unit
E-42 SB Producer
Hilcorp Drilling Procedure
rI
22.0 Formation Tops & Information
MPU E-42 Formations
(wp06)
MD
(ft)
TVDss
(ft)
ND
(ft)
Formation Pressure
(psi)
EMW
(ppg)
Base Permafrost
2115
-1707
1755
772.2
8.46
LA3
5861
3628
3676
1617.44
8.46
Schrader Bluff NB
6945
-4128
4176
1837.44
8.46
Schrader Bluff OA
7750
-4239
4286
1885.84
8.46
Schrader Bluff OB (Target)
8225
-4284
4331
1905.64
8.46
Page 40
Milne Point Unit
E-42 SB Producer
HilcoTp Drilling Procedure
Eneay Cm,pmy
GENERALIZED GEOLOGICAL
FORECAST
SS
GEOLOGICAL
TSD
FM
LITH
DESCRIPTION
At (seal.
oacam
Gubl
Unconsolidated coarse to medium sand and small gravel wIM
Tolera c
«.too•.
600
•minor
ailtstone.
Heavy gravel conglomerate to 1400'. Wood fragments
ft.
1,000,•
throughout permafrost zone- Abundant pyrite at 1500
a
RUNNING GRAVELS
1700
Base permafrost
2.000'
Be prepared for HYDRATE gas cut
HYDRATESII
Saga
nlktok
C
m.id 2000 to 2500'sa (E -rand Ea)
3s1)•3�a-29j'E"�'
`38E2HYDRATES!
L
GAS CUT MUD
A
Predominantly clay to N- 3000' with Interbeds of sand, clays
and sinhumnes with occasional shows of coal.
Y
3,000
Continued imitobeds of sand, clays and slffstones with occasional
shows of coal. Clay, si tslone and sand interbeds between 3000 and
6000'. Lignite 3400-3500lt_ SV ir%ervals mrxe ratty ("muddier"Ithan
those In Me Prudhoe Say area.
Csua.
UG41K15
SWABBING/STICKY
L i,1
A
UgnU: Thick package -200 to 300 N In some areas, mostly waterJllkd at E -pea although
9
some zones are tilled with hydrocarbon. The Ugnu section (Imerbedded fluvial sandsiare
a
A
and shale) represents the Initial Iaogradatlon d the Ugnu deltaic system over the underlying CLAYfGUM80' E-200. -28.
"
0
3 °
C x
difficult to determine top
shallow marine Schrader Bluff section. fluvial native can make H mi
the Ugnu Is -32 8 -12.
D
Y
and base of InrErldual units. Bottom bounding surface of entire package picked
ro'
A
at the regional unconlomlty M70S Isile the RFsands below). GAS CUT MUD E-24 AT 3996
7
M -Sands: Fluvial, deltaic channel sandstones prograded over the underlying shallow TVD; E-1 3B @ 3618 tvd.
4,000
6
marine sandstones of the Schrader Stuff. The M-5anas are subdivided Into three TIGHTIPACKING OFF, E -25A.,
Yithostfabgrapre, units (Hs. Mb. Mc from top to bottan) that can be difficult to correlate due
a0t°
A
to their lfuviel.datac nature. The M70S marks the lower most boundary. 6Fsarld intervals
Surface casing seat
e
x
are typically coarsening upward packages of varylrrgg thicknesses, rang reg from 5060"thck
All zones are highly unconsolidated sandstones w2l porosKSes range m the 30-38%and far Schrader Bluff
D
`.
A14b,
5
permeablltses reaching upwards of 2000-5000 mid. Each M sand Inlerval acts as a completion.
Lfz,s.
hydtaulically separate reservolr based on cunent understanding. TIGHTILEDGES (COAL)
-Sands: The Noends are composed d sleeked, marine shoreface sandstones that RUNNING SURFACE
CN
A
a
coarsen upwanlahom thin, silty mudslones Into thin, low net,gross very fine to medium- CASING,
of clean
�
grained sandstones. The N4 NC d Iffi-sands are the best quality reservoir rock
p
Yhigh
a
netgross fine to medium grained sandfiforfe. Ns®nd poroelty ranges from 12-21M4 and
tl
pemteablliuea range from 100-3000 Ind. The NC d NDiands are me pin nary largeL with
3
j Z
E
Secondary targets In the NB -sand. The more unconsolidated sands (typicalty the NB, NC d
ND) terd to washout, and the 8rxr grained slay mudstohea can cause slow ROP.
Each N -sand Bets as a hydraulically isolated separate reservoir.
azr°•-
a5)S
O-SOnds: The O -sands consist d stacked, tower shoelace marine sands that clean
A
A
ranted
shags) to thin bedded, very gine to sFth
upwards Mom airy mudand
•-
O sancixming
sandstolxa These OA and 08sardstoraes are 25-30'thick,andthe OAsantl is primary
V
oprimary
target for horizontal wells at E -pad Osand porosities range from 12-35% and pemxatvloss
U)
9
d the OB -sand reach upwards of 80o and whereas pemxatlilibes In the OA -said reach only
350 md. There are underlying OB sands (013b -W that Correlate over the region.
m
0
May contain light nodules and lenses that cause directional deflection (especially when
horUx orteq and slow ROP. Each Oland Interval acts as a hydraulically Isolated reservoir.
The numerous sub -seismic 500 f faults and the lateral dlsecn study of the NS -sands make it
D
essential for clear pick identification down through the Ugnu and Nsards, as well as careful
4800,
geosteering In hdn crual wells.
o-100'
Page 41
Milne Point unit
E-42 SB Producer
Hilcorp Drilling Procedure
E.v Com2
23.0 Anticipated Drilling Hazards
12-1/4" Hole Section:
Lost Circulation
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Gas Hydrates ✓
Gas hydrates have been seen on E Pad. Remember that hydrate gas behave differently from a gas sand.
Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at
surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the
hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while
drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can
increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as
cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -
pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb Lecithin to the system to
help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the
system.
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize
solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs
to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is
critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to
avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide
intervals. Do not out drill our ability to clean the hole.
Anti -Collison:
There are a number of wells in close proximity. Take directional surveys every stand, take additional
surveys if necessary. Continuously monitor proximity to offset wellbores and record any close
approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in
adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well.
Wellbore stability (Permafrost, running sands and gravel, conductor broaching):
Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of
time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH
speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and
swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching.
Maintain mud parameters and increase MW to combat running sands and gravel formations.
H2S:
Treat every hole section as though it has the potential for H2S. No 142S events have been documented
on drill wells on this pad.
Page 42
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements /
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 43
Milne Point Unit
E-42 SB Producer
Hilcorp
U.
Drilling Procedure
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements /
of 20 AAC 25.066.
3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Page 43
Milne Point unit
E-42 SB Producer
Hilcorp Drilling Procedure
� �zT
8-1/2" Hole Section:
Hole Cleaning:
Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up
with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor
ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe
rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe
moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation
after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of> 300
gpm
Lost Circulation:
Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost
circulation. For minor seepage losses, consider adding small amounts of calcium carbonate.
Faulting:
There is at least (1) fault that will be crossed while drilling the well. There could be others and the
throw of these faults is not well understood at this point in time. When a known fault is coming up,
ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed,
we'll need to either drill up or down to get a look at the LWD log and determine the throw and then
replan the wellbore.
H2S:
Treat every hole section as though it has the potential for 1-12S. No H2S events have been documented
on drill wells on this pad.
1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during
drilling operations.
2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements
of 20 AAC 25.066.
3. In the event 1-12S is detected, wellwork will be suspended and personnel evacuated until a
detailed mitigation procedure can be developed.
Abnormal Pressures and Temperatures:
Abnormal pressure has been seen on E -Pa Utilize MPD to miti e any abnormal pressure seen.
Anti -Collision
There are no wells with a clearance factor <1.0 on this lateral. Take directional surveys every stand, take
additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic
interference with another well.
Page 44
24.0 Innovation Rig Layout
Milne Point Unit
E-42 SB Producer
Drilling Procedure
Page 45
Milne Point unit
E-42 SB Producer
Hilcorp Drilling Procedure
Envy' Cmepvey
25.0 FIT Procedure
Formation Integrity Test (FIT) and
Leak -Off Test (LOT) Procedures
Procedure for FIT:
I. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe).
2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe.
3. Close the blowout preventer (ram or annular).
4. Pump down the drill stem at 1/4 to 1/2 bpm.
5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs.
drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe.
6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes.
Record time vs. pressure in 1 -minute intervals.
7. Bleed the pressure off and record the fluid volume recovered.
The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at
least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick
tolerance in case well control measures are required.
Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of
stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid;
at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure
monitored as with an FIT.
Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental
volume pumped and returned during test.
Page 46
26.0 Innovation Rig Choke Manifold Schematic
Milne Point Unit
E-42 SIR Producer
Drilling Procedure
Page 47
H
Hilcolp
Epp czjx
Milne Point Unit
E-42 SB Producer
Drilling Procedure
27.0 Casing Design 11orp
Calculation & Casing Design Factors
DATE: 5/22/2019
WELL: MPU E-42
DESIGN BY: Joe Engel
Desiqn Criteria:
Hole Size 12-1/4" Mud Density: 9.2 ppg
Hole Size 8-1/2" Mud Density: 9.2 ppg
Hole Size Mud Density:
Drilling Mode
MASP: 1468 psi (see attached MASP determination & calculation)
MASP:
Production Mode
MASP: 1468 psi (see attached MASP determination & calculation)
Collapse Calculation:
Section Calculation
1 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress
Page 48
Cas ng Section
Calculation/Specification
1 1
2 3 4
Casing OD
9-5/8" 1
4 -1/2 -
Top (MD)
0
7,835
Top (TVD)
0
4,315
Bottom (MD)
8,100
11,949
Bottom (TVD)
4,319
4,222
Length
8,100
4,114
Weight (ppo
40
13.5
Grade
L-80
L-80
Connection
T)p
M525
Weight w/o Bouyancy Factor Obs)
324,000
55,539
Tension at Top of Section Obs)
324,000
55,539
Min strength Tension (1000 lbs)
916
279
Worst Case Safety Factor (Tension)
2.83
5.02
Collapse Pressure at bottom (Psi)
2,134
2,086
Collapse Resistance w/o tension (Psi)
3,090
8,540
Worst Case Safety Factor (Collapse)
1.45 ✓
4.09
MASP (psi)
1,468
1,468
Minimum Yield (psi)
5,750
9,020
Worst case safety factor (Burst)
1 3.92 yj
6.14
Page 48
Milne Point unit
E-42 SB Producer
HilcDrilling Procedure
W=
28.0 8-1/2" Hole Section MASP
14
Maximum Anticipated Surface Pressure Calculation
8-1/2" Hole Section
HIcor�p MPU E-42
Milne Point Unit
MD TVD
Planned Top: 8100 4319
Planned TD: 11949 4222
Anticipated Formations and Pressures:
Formation TVD Est Pressure Oil/Gas/Wet ARG Grad
Schrader Bluff OB Sand 4,319 1959 Oil 8.72 0.440
Offset Well Mud Densities
Well
MW range
Top (TVD)
Bottom (ND)
Date
MPU E-24
9.1-9.3
Surface
4208
2001
Assumptions:
1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW.
2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg.
3. Calculations assume full evacuation of wellbore togas
Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface:
4,319 (ft) x 0.78(psi/ft)= 3369
3369(psi) - [0.1(psi/ft)*4319(ft)]= 2937 psi
MASP from pore pressure (complete evacuation of wellbore to ga�jfom-Sdiirader Bluff OA sand)
4319 (ft) x 0.44(psi/ft)= 1900 psi
1900(psi) - 0.1(psi/ft)*4319(ft) 1468 psi
Summary:
1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation
of entire wellbore togas at 0.1 psi/ft.
Page 49
H
Hilcorp
29.0 Spider Plot (NAD 27) (Governmental Sections)
Milne Point Unit
E-42 SB Producer
Drilling Procedure
Milne Point Unit
MPE 42 Well o i.aoo 2.000
esy am. syarmis Feet
wn n5
Page 50
Milne Point unit
E-42 SB Producer
Hilcorp Drilling Procedure
UCox
30.0 Surface Plat (As Built) (NAD 27)
Page 51
f, I
pep
208
p7
3■
•
2 DO8' FEL
■ !]
■ 2
3
27/
■ u
TM PFXOXJEWCra
IO ■
■ 31 I
a
r
28 /
■ A
22 ■
■ ,
291 ■
u /
■ 5
VICINITY MAP
20 ■
■ I
NT.S
9 /
■ 6
-N-
■21
IE-42�
n
■ 7
I9 IN
■ ,8
NFU E -PAD
I
20 ■
■ v
1A /
1;
).FND
1! ■
I
AS -STAKED CpW1UCTON
'� ■
■ !T
■ FASTING CONDUCUR
39 /
/ 36
AI ■
■ ]5
%
1
IIa■
`---
GRAPHIC SCALE
NOTES:
p 100 200
WC
,. AASKA STAR PIAIE pKFEIINATE3 AX 2p4 b MW27.
2 fl195 M U%AT IS IKINAENTS W-] AND E-1.
N �u� I
! BA9! AeM YUE PONT 0AN1 KSI.
a p
1 X,� i
A 40EFTC mTMNS w NWT2. /
S, PAD " SEAS FAC]0N IS 0.9HM64
6. 4NKEY "114. WY & 2pI4
1. IS/EISM.£ FEED 1XIM: NCt2-01 PG U.
LOCATED
HITHIN PROTRACTED SEC. 25, T. 13 N., R.
10 E_, UMIAT MERIDIAN, ALASKA
HELL
A.S.P.
PLANT
GEODETIC
GEODETIC
GRAVEL
SECTION
NO,
COORDINATES
COORDINATES
POSITION(DMS)
POSITION(D.DD)
PAD ELEV.
OFFSETS
Y'60/6,240.99'
N. 2,094.95'
70'2717-031-
70.4547308'
3,704'FSL
E-42
X=569,137.33'
E= 1 292.01'
149«6'08.699'
149.4358053
.AAlNMT
Hilcorp Alaska
�I
P
IAN
P�
MPU E -PAD
AS -STAKED CONDUCTOR
1• . y7e
®
st
WELL E-42
Page 51
208
"
•
2 DO8' FEL
31.0 Schrader Bluff OA Sand Offset MW vs TVD Chart
Schrader Bluff OA Sand Offset MW vs ND
MW,ppg
8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.110-3 10.5
0 1 nin
m
1000
1500
2000
4=
0
2500
M
3500
4500
Page 52
—MPU L-46 (2015)
—MPU L-47 (2015)
—MPU L-48 (2015)
MPU L-49 (2015)
—MPU L-50 (2015)
—MPU F-106 (2017)
—MPU F-107 (2017)
—MPU F-108 (2017)
—MPU F-109 (2017)
—MPU F-110 (2017)
Milne Point Unit
E-42 SB Producer
Hilcorp
Drilling Procedure
� �®oe,
31.0 Schrader Bluff OA Sand Offset MW vs TVD Chart
Schrader Bluff OA Sand Offset MW vs ND
MW,ppg
8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.110-3 10.5
0 1 nin
m
1000
1500
2000
4=
0
2500
M
3500
4500
Page 52
—MPU L-46 (2015)
—MPU L-47 (2015)
—MPU L-48 (2015)
MPU L-49 (2015)
—MPU L-50 (2015)
—MPU F-106 (2017)
—MPU F-107 (2017)
—MPU F-108 (2017)
—MPU F-109 (2017)
—MPU F-110 (2017)
Hilcorp Alaska, LLC
Milne Point
M Pt E Pad
Plan: MPU E-42
MPU E-42
Plan: MPU E-42 wp06
Standard Proposal Report
14 May, 2019
HALLIBURTON
Sperry Drilling Services
HALLIBURTON
Spor'r`y Orllling
Sec MDI Axi WD ♦NI -S *EFW DIe9 TFam Vs. Tar9A
1 28.50 000 26 50 0.00 0.00 000 D. W TOO
2 350D0 0.00 0.00 350.00 0.00 0.00 000 ON 000
3 55000 6.00 220.00 549.63 -8.01 6.73 3.00 220.00 9.40
4 1890.71 59.19 19866 1640.51 -655.12 -254.31 4.00 -22.84 697.03
5 6523.36 59.19 198.66 4013.38 -"24.79 -1527.30 0.00 0.00 4662.12
6 7128.97 03.00 193.90 420029 4971.11 -0685.06 4.00 11.58 523D.33
7 7026.97 8100 19390 4293.60 -5645.54 -1051.97 OOD 0.00 5925.12 MPE42 M05 -LI OA Heel
8 7858.97 83.00 193.90 4297.26 -5674.45 -1859.12 600 BOO 5954.89
9 7908.97 85.00 193.90 430248 -5722.71 -1871.07 4.00 0.00 6004.62
10 8201,76 6500 193.90 432800 -W0584 -1941.13 0.00 0.00 6296.29
11 0386.22 92.30 193.90 433222 -6184.73 -1985.41 4.00 0.02 6480.57
12 1029890 92.30 193.90 4252.84 -8039.77 -24 .60 000 D.W 8391.60 MPE42 w*05-CPI
13 10332.46 91.04 193.90 4251.84 9072.34 -2452.65 4.W -179.99 8425.15
4 11949.71 9104 19390 422260 -9641,95 -2041.19 0,00 0.00 10042.14 MPE42 v e05 - Oe Toe
Project:
Milne Point
Site:
MPtEPad
Well:
Plan:E-42
Wellbore:
PU E42
Design:
MPU E-42 WP06
Sec MDI Axi WD ♦NI -S *EFW DIe9 TFam Vs. Tar9A
1 28.50 000 26 50 0.00 0.00 000 D. W TOO
2 350D0 0.00 0.00 350.00 0.00 0.00 000 ON 000
3 55000 6.00 220.00 549.63 -8.01 6.73 3.00 220.00 9.40
4 1890.71 59.19 19866 1640.51 -655.12 -254.31 4.00 -22.84 697.03
5 6523.36 59.19 198.66 4013.38 -"24.79 -1527.30 0.00 0.00 4662.12
6 7128.97 03.00 193.90 420029 4971.11 -0685.06 4.00 11.58 523D.33
7 7026.97 8100 19390 4293.60 -5645.54 -1051.97 OOD 0.00 5925.12 MPE42 M05 -LI OA Heel
8 7858.97 83.00 193.90 4297.26 -5674.45 -1859.12 600 BOO 5954.89
9 7908.97 85.00 193.90 430248 -5722.71 -1871.07 4.00 0.00 6004.62
10 8201,76 6500 193.90 432800 -W0584 -1941.13 0.00 0.00 6296.29
11 0386.22 92.30 193.90 433222 -6184.73 -1985.41 4.00 0.02 6480.57
12 1029890 92.30 193.90 4252.84 -8039.77 -24 .60 000 D.W 8391.60 MPE42 w*05-CPI
13 10332.46 91.04 193.90 4251.84 9072.34 -2452.65 4.W -179.99 8425.15
4 11949.71 9104 19390 422260 -9641,95 -2041.19 0,00 0.00 10042.14 MPE42 v e05 - Oe Toe
AnnoM4an
pan Dir 3.1109:359 MD. 3W WD
Sled Dir 4.1100' : SW MD, 549 VWD
End Dir :INO.71- M0,180051' TVD
Sun Be 4°1100':6523,36 M0, 4013,U1-
EM Dir : 7126.9T MD, 420829' TVD
hurt Be 4°1100': 78569T MD, 4297.26WD
EM Dir : ]9089T MD, 4302A8' TVD
Start Dir 4°1109: 82096 MO, <PFW0
EM or :838822' MD, 4332.22' TVD
Sutt Dir 4°1100':10298 B M0, 4=14WD
EM Dir :10332.46' MD, 4251.84' WD
Total oepN :1194971'MD, 42225 rvo
REFERENCE INFORMATION
A
CoaN'na+e INRI pel¢renx: Wtll Phn MPU Ed2, Trve NOM
D
4bE]0 43fiB.10 Afi7.T Top SBOA
..-IReldervz: MPU EAx AssbkeO RHB®47.31h156
(100)
GrcurA Evatllew^
p
20.80
LatlLarbwde
MPUEd2AS5bked R103®d].3CUN 0.045 0.00
Me'dwMOepM R¢luenm 0.00 0. 0.00
NnMly
601624.29601624.29 569137,33
$.Dv3a100:z50'MD.3A D
CalrulalM MeV": Minimum Cwreeue
YIR,.EY %MGR44
600
GBING DETAILS
orae. ]n1N0.1aemmm WWeatl: vn vows.
-..Di941W':S0'MD, 549.6]'ND
0.p 1eU
D.nplp MPU
"y.50
rvo Tvnss
S+sv 4zn B3
ID sirs u.me
e+aow esre 95re•x+x vd
1Dp0
zu eo dl]s ]D
1200
9100.01Ill41.71 MPU E42 v+C6 NFU E42 3MN0•IFP2M40bq
' EM04: 109011MD.1040.51' ND
100D
i
0 2400
v
3000
F
AnnoM4an
pan Dir 3.1109:359 MD. 3W WD
Sled Dir 4.1100' : SW MD, 549 VWD
End Dir :INO.71- M0,180051' TVD
Sun Be 4°1100':6523,36 M0, 4013,U1-
EM Dir : 7126.9T MD, 420829' TVD
hurt Be 4°1100': 78569T MD, 4297.26WD
EM Dir : ]9089T MD, 4302A8' TVD
Start Dir 4°1109: 82096 MO, <PFW0
EM or :838822' MD, 4332.22' TVD
Sutt Dir 4°1100':10298 B M0, 4=14WD
EM Dir :10332.46' MD, 4251.84' WD
Total oepN :1194971'MD, 42225 rvo
REFERENCE INFORMATION
WELL GETNLE: PNn: MPU E12
CoaN'na+e INRI pel¢renx: Wtll Phn MPU Ed2, Trve NOM
CelutleU.n Wheel Mi.. LurvaWn
4bE]0 43fiB.10 Afi7.T Top SBOA
..-IReldervz: MPU EAx AssbkeO RHB®47.31h156
(100)
GrcurA Evatllew^
p
20.80
LatlLarbwde
MPUEd2AS5bked R103®d].3CUN 0.045 0.00
Me'dwMOepM R¢luenm 0.00 0. 0.00
NnMly
601624.29601624.29 569137,33
]0'21- 2T 1 1 ].0310.0 Id8'28'Bb90.5
CalrulalM MeV": Minimum Cwreeue
YIR,.EY %MGR44
GBING DETAILS
orae. ]n1N0.1aemmm WWeatl: vn vows.
0.p 1eU
D.nplp MPU
"y.50
rvo Tvnss
S+sv 4zn B3
ID sirs u.me
e+aow esre 95re•x+x vd
E -Q^ xSGG_Mu cNa,
W4Y vu Hxvµd Dd°UEtlI
W]m upu ell wu.lO) ZMND•IFfix•Ma•aq
zu eo dl]s ]D
++9dsw d.tn 4+rs•xel/Y
9100.01Ill41.71 MPU E42 v+C6 NFU E42 3MN0•IFP2M40bq
FORMATION TOP OET.VLE
kknry AleaN, LLL
PaM MOaaPeM MOPe. fonnnbn
CelutleU.n Wheel Mi.. LurvaWn
4bE]0 43fiB.10 Afi7.T Top SBOA
E1mr 3yabm: ISCWBA
Scan MetlM: C..M AppmaM ]O
Emr 9alece: Poral C-
.prMetlw]: E.r RMu
Top MOA
YPE>2v 5 -LI OAXeeI $
OW12111
YPEJ2 v{05 -OB Heel
1800 2400 3000 3600 4200 4800 5400 6000 6600
Vesical Section at 193.90- (1200 usfiln)
�tQ Zo go
a d�
8^, z
, u,
^ d
41Q'eBW
8 9 MPU E4 u
MPEAx xyDS� OB Tae
WE42w 5 -CPI
78M 0400 9000 9600 10200
0
-3200
CASING .ILS
TVDSS MD Size Name
L43719.1334271.83 8100.00 9-5/8 9 5/8' x 12 114"
4175.30 11949.71 41/2 41/2"x812'
REFERENCE INFORMATION
C n inale Ina) Reference: Well Plan: MPU Ed2, Tme North
Veniral (NDI Reference: MPU Ed2 As-Btaked RKB ® 47.30ueX
Meawred Depth Relererce: MPU Ed2 Aa -Staked RKB ® 47.3 It
Calculation Method: Minimum Curvature
WELL DE7F B : Plan: MPU 1 -02
Onn nd Lcvel: 20.80
ff.NI-S ♦v -W Northing Fasting 1a00ude Longitude
0.00 6016240.99 569137.33 70"27' 17.0310 N 149° 26 8.8985 W
asl orllllna
j00 Start Dir4°/100': 55V MD, 549.63 -TVD
/250
�0,
17SO EadDir: 18N.71'MD, 1640.51'TVD
Start Da 4°/100' : 6523.36' MD. 4013.389 V D
End Dir : 7128.97' MD, 4208.29' TVD
MPE42 wp05 - LI OA Heel 42SO
Stan Dir 4°/100': 7858.97 MD, 4297.267
--End Dir : 7908ST MD, 430148' TVD
95/8"x121/4_
_ _ - Stan Dir 4°/100': 820L76' MD, 43284
MPE42 WPOS-OB llml _
End Dir 8386.22' MD, 4332.22'TVD
MPE-42 wp05 - CPI
Stan Dir 4°/ 100' : 10298.9' MID, 4252.847 V Ll
End Dir : 10332.46' MD, 4251.84' TVD
WE42 wp05 - OB Toe
Total Depth : 11949]1' MD, 4222.6' TVD
4 xavr'—
MPU E42 Wp06223 -
-5600 4800 4000 -3200 -2400 -1600 -800 0 800 1600 2400
West( -)/East(+) (1200 usft/in)
Project:
Milne Point
Site:
M Pt E Pad
Well:
Plan: MPU E-42
Wellbore:
MPU E-42
Plan:
MPU E-42 wp06
NALLIBURTON
asl orllllna
j00 Start Dir4°/100': 55V MD, 549.63 -TVD
/250
�0,
17SO EadDir: 18N.71'MD, 1640.51'TVD
Start Da 4°/100' : 6523.36' MD. 4013.389 V D
End Dir : 7128.97' MD, 4208.29' TVD
MPE42 wp05 - LI OA Heel 42SO
Stan Dir 4°/100': 7858.97 MD, 4297.267
--End Dir : 7908ST MD, 430148' TVD
95/8"x121/4_
_ _ - Stan Dir 4°/100': 820L76' MD, 43284
MPE42 WPOS-OB llml _
End Dir 8386.22' MD, 4332.22'TVD
MPE-42 wp05 - CPI
Stan Dir 4°/ 100' : 10298.9' MID, 4252.847 V Ll
End Dir : 10332.46' MD, 4251.84' TVD
WE42 wp05 - OB Toe
Total Depth : 11949]1' MD, 4222.6' TVD
4 xavr'—
MPU E42 Wp06223 -
-5600 4800 4000 -3200 -2400 -1600 -800 0 800 1600 2400
West( -)/East(+) (1200 usft/in)
HALLIBURTON
Database:
NORTH US+CANADA
Company:
Hilcorp Alaska, LLC
Project:
Milne Point
Site:
M Pt E Pad
Well:
Plan: MPU E-42
Wellbore:
MPU E-42
Design:
MPU E-42 wp06
Halliburton
Standard Proposal Report
Local Co-ordinate Reference: Well Plan: MPU E-42
TVD Reference:
MPU E-42 As -Staked RKB @ 47.30usft
MD Reference:
MPU E-42 As -Staked RKB @ 47.30usft
North Reference:
True
Survey Calculation Method:
Minimum Curvature "
3roject Milne Point, ACT, MILNE POINT
Nap System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level
Seo Datum: NAD 1927 (NADCON CONUS) - Using Well Reference Point
Nap Zone: Alaska Zone 04 Using geodetic scale factor
Site M Pt E Pad, TR -13-10
Site Position:
From: Map
Position Uncertainty:
Northing:
Easting:
0.00 usft Slot Radius:
6,013,798.68usft Latitude:
569,440.72usft Longitude:
0" Grid Convergence:
Well Plan: MPU E-42, Dual Lat
Model Name Sample Date
Declination
Well Position +N/ -S 0.00 usft
Northing:
6,016,240.99 usfl
Latitude:
+E/ -W 0.00 usft
Basting:
569,137.33 usfl
Longitude:
Position Uncertainty 0.00 usft
Wellhead Elevation:
0.00 usfl
Ground Level:
Wellbore MPU E-42
Magnetics
Model Name Sample Date
Declination
BGGM2018 7/5/2019
Design
MPU E-42 wp06
Audit Notes:
Version:
Phase:
PLAN
Vertical Section:
Depth From (TVD)
+N/ -S
Vertical
(usft)
(usft)
26.50
0.00
Dip Angle
16.63
Tie On Depth:
+E/ -W
(usft)
0.00
80.96
70° 26'52.9824 N
149° 26'0.6546 W
0.53 °
70° 27' 17.0310 N
149° 26'8.8985 W
20.80usft
Field Strength
(nT)
57 424.41504716
26.50
Direction
(°)
193.90
Plan Sections
Measured
Vertical
TVD
Dogleg
Build
Turn
Depth
Inclination Azimuth
Depth
System
+NI -S
+E/.W
Rate
Rate
Rate
Tool Face
(usft)
(°)
(°)
(usft)
usft
(usft)
(usft)
(°I100usft)
(°/100usft)
(°1100usft)
(°)
26.50
0.00
0.00
26.50
-2080
0.00
0.00
0.00
0.00
0.00
0.00
350.00
0.00
0.00
350.00
302.70
0.00
0.00
0.00
0.00
0.00
0.00
550.00
6.00
220.00
549.63
502.33
-8.01
-6.73
3.00
3.00
0.00
220.00
1,890.71
59.19
198.66
1,640.51
1,593.21
-655.12
-254.31
4.00
3.97
-1.59
-22.84
6,523.36
59.19
198.66
4,013.38
3,966.08
-4,424.79
-1,527.30
0.00
0.00
0.00
0.00
7,128.97
83.00
193.90
4,208.29
4,160.99
-4,971.11
-1,685.06
4.00
3.93
-0.79
-11.58
7,828.97
83.00
193.90
4,293.60
4,246.30
-5,645.54
-1,851.97
0.00
0.00
0.00
0.00
7,858.97
83.00
193.90
4,297.26
4,249.96
-5,674.45
-1,859.12
0.00
0.00
0.00
0.00
7,908.97
85.00
193.90
4,302.48
4,255.18
-5,722.71
-1,871.07
4.00
4.00
0.00
0.00
8,201.76
85.00
193.90
4,328.00
4,280.70
$,005.84
-1,941.13
0.00
0.00
0.00
0.00
8,386.22
92.38
193.90
4,332.22
4,284+92
-6,184.73
-1,985.41
4.00
4.00
0.00
0.02
10,298.90
92.38
193.90
4,252.84
4,205.54
-8,039.77
-2,444.60
0.00
0.00
0.00
0.00
10,332.46
91.04
193.90
4,251.84
4,204.54
-8,072.34
-2,452.66
4.00
-4.00
0.00
-179.99
11,949.71
91.04
193.90
4,222.60
4,175.30
-9,641.95
-2,841.19
0.00
0.00
0.00
0.00
51142019 3:28.'09PM
Page 2
COMPASS
5000.15 Build 91
HALLIBURTON
Database:
NORTH US+CANADA
Company:
Hiloorp Alaska, LLC
Project:
Milne Point
Site:
M Pt E Pad
Well:
Plan: MPU E-42
Wellbore:
MPU E-42
Design:
MPU E-42 wp06
Planned Survey
Local Co-ordinate Reference:
TVD Reference:
MD Reference:
North Reference:
Survey Calculation Method:
Halliburton
Standard Proposal Report
Well Plan: MPU E-42
MPU E-42 As -Staked IRKS @ 47.30usft
MPU E-42 As -Staked IRKS @ 47.30usft
True
Minimum Curvature
Measured
Vertical
Map
Map
Depth
Inclination
Azimuth
Depth
TVDss
+NI -S
+El -W
Northing
Easting
DLS
Vert Section
(usft)
V)
(I
(usft)
usft
(usft)
(usft)
(usft)
(usft)
-20.80
26.50
0.00
0.00
26.50
-20.80
0.00
0.00
6,016,240.99
569,137.33
0.00
0.00
100.00
0.00
0.00
100.00
52.70
0.00
0.00
6,016,240.99
569,137.33
0.00
0.00
200.00
0.00
0.00
200.00
152.70
0.00
0.00
6,016,240.99
569,137.33
0.00
0.00
300.00
0.00
0.00
300.00
252.70
0.00
0.00
6,016,240.99
569,137.33
0.00
0.00
350.00
0.00
0.00
350.00
302.70
0.00
0.00
6,016,240.99
569,137.33
0.00
0.00
Start Dir
31/100':
350'
MD,
350'TVD
.
400.00
1.50
220.00
399.99
352.69
-0.50
-0.42
6,016,240.48
569,136.91
3.00
0.59
500.00
4.50
220.00
499.85
452.55
4.51
-3.78
6,016,236.45
569,133.59
3.00
5.29
550.00
6.00
220.00
549.63
502.33
-8.01
-6.73
6,016,232.91
569,130.68
3.00
9.40
Start
Dir
4.1100'
: 550'
MD,
549.63'TVD
600.00
7.88
214.33
599.27
551.97
-12.85
-10.34
6,016,228.05
569,127.11
4.00
14.96
700.00
11.76
208.52
697.78
650.48
-27.47
-19.07
6,016,213.35
569,118.51
4.00
31.25
800.00
15.70
205.58
794.91
747.61
-48.64
-29.79
6,016,192.08
569,108.00
4.00
54.37
900.00
19.67
203.80
890.17
842.87
-76.25
-42.42
6,016,164.35
569,095.62
4.00
84.21
1,000.00
23.64
202.59
983.09
935.79
-110.17
-56.92
6,016,130.30
569,081.44
4.00
120.62
1,100.00
27.62
201.72
1,073.23
1,025.93
-150.24
-73.21
6,016,090.10
569,065.52
4.00
163.42
1,200.00
31.61
201.05
1,160.15
1,112.85
-196.25
-91.21
6,016,043.92
569,047.95
4.00
212.41
1,300.00
35.60
200.52
1,243.42
1,196.12
-247.98
-110.84
6,015,992.01
569,028.81
4.00
267.35
1,400.00
39.59
200.09
1,322.64
1,275.34
-305.19
-132.00
6,015,934.62
569,008.18
4.00
327.96
1,500.00
43.58
199.72
1,397.42
1,350.12
-367.59
-154.58
6,015,872.02
568,986.18
4.00
393.96
1,600.00
47.58
199.40
1,467.40
1,420.10
434.88
-178.48
6,015,804.51
568,962.91
4.00
465.02
1,700.00
51.57
199.12
1,532.24
1,484.94
-506.73
-203.57
6,015,732.44
568,938.49
4.00
540.80
1,800.00
55.56
198.87
1,591.61
1,544.31
-582.79
-229.75
6,015,656.15
568,913.02
4.00
620.92
1,890.71
59.19
198.66
1,640.51
1,593.21
-655.12
-254.31
6,015,583.60
568,889.13
4.00
697.03
End
Dir
: 1890.71' MD, 1640.51' TVD
1,900.00
59.19
198.66
1,645.26
1,597.96
-662.68
-256.87
6,015,576.02
568,886.65
0.00
704.98
2,000.00
59.19
198.66
1,696.48
1,649.18
-744.05
-284.35
6,015,494.40
568,859.93
0.00
790.57
2,100.00
59.19
198.66
1,747.71
1,700.41
-825.42
-311.82
6,015,412.79
568,833.21
0.00
876.16
2,200.00
59.19
198.66
1,798.93
1,751.63
-906.80
-339.30
6,015,331.17
568,806.49
0.00
961.75
2,300.00
59.19
198.66
1,850.15
1,802.85
-988.17
-366.78
6,015,249.56
568,779.77
0.00
1,047.34
2,400.00
59.19
198.66
1,901.37
1,854.07
-1,069.54
-394.26
6,015,167.94
568,753.05
0.00
1,132.93
2,500.00
59.19
198.66
1,952.59
1,905.29
-1,150.91
-421.74
6,015,086.32
568,726.33
0.00
1,218.52
2,600.00
59.19
198.66
2,003.81
1,956.51
-1,232.28
-449.22
6,015,004.71
568,699.61
0.00
1,304.11
2,700.00
59.19
198.66
2,055.03
2,007.73
-1,313.65
-476.70
6,014,923.09
568,672.89
0.00
1,389.70
2,800.00
59.19
198.66
2,106.25
2,058.95
-1,395.03
-504.17
6,014,841.48
568,646.17
0.00
1,475.29
2,900.00
59.19
198.66
2,157.47
2,110.17
-1,476.40
-531.65
6,014,759.86
568,619.45
0.00
1,560.88
3,000.00
59.19
198.66
2,208.69
2,161.39
-1,557.77
-559.13
6,014,678.25
568,592.73
0.00
1,646.47
3,100.00
59.19
198.66
2,259.91
2,212.61
-1,639.14
-586.61
6,014,596.63
568,566.01
0.00
1,732.06
3,200.00
59.19
198.66
2,311.13
2,263.83
-1,720.51
-614.09
6,014,515.01
568,539.29
0.00
1,817.65
3,300.00
59.19
198.66
2,362.35
2,315.05
-1,801.89
-641.57
6,014,433.40
568,512.57
0.00
1,903.24
3,400.00
59.19
198.66
2,413.57
2,366.27
-1,883.26
-669.05
6,014,351.78
568,485.85
0.00
1,988.83
3,500.00
59.19
198.66
2,464.79
2,417.49
-1,964.63
-696.52
6,014,270.17
568,459.13
0.00
2,074.42
3,600.00
59.19
198.66
2,516.01
2,468.71
-2,046.00
-724.00
6,014,188.55
568,432.41
0.00
2,160.01
3,700.00
59.19
198.66
2,567.23
2,519.93
-2,127.37
-751.48
6,014,106.94
568,405.69
0.00
2,245.60
3,800.00
59.19
198.66
2,618.46
2.571.16
-2,208.75
-778.96
6,014,025.32
568,378.97
0.00
2,331.19
51142019 3:28:09PM Page 3 COMPASS 5000.15 Build 91
Halliburton
HALLI B U RTO N
Standard Proposal Report
Database:
NORTH US
+ CANADA
Local Co-ordinate Reference: Well Plan: MPU E-42
Company:
Hilcorp Alaska, LLC
TVD Reference:
MPU
E-42 As -Staked RKB @ 47.30usft
Project:
Milne Point
MD Reference:
MPU
E-42 As -Staked RKB @ 47.30usft
Site:
M Pt E Pad
North Reference:
True
Well:
Plan: MPU E-42
Survey Calculation
Method: Minimum Curvature
Wellbore:
MPU E-42
Design:
MPU E-42 wp06
Planned Survey
Measured
Vertical
Map
Map
Depth Inclination Azimuth
Depth
TVDss
+N/ -S
+E/ -W
Northing
Easting
OLS
Vert Section
(usft)
V)
(0)
(usft)
usft
(usft)
(usft)
(usft)
(usft)
2,622.38
3,900.00
59.19
198.66
2,669.68
2,622.38
-2,290.12
-806.44
6,013,943.71
568,352.25
0.00
2,416.78
4,000.00
59.19
198.66
2,720.90
2,673.60
-2,371.49
-833.92
6,013,862.09
568,325.53
0.00
2,502.37
4,100.00
59.19
198.66
2,772.12
2,724.82
-2,452.86
-861.39
6,013,780.47
568,298.81
0.00
2,587.96
4,200.00
59.19
198.66
2,823.34
2,776.04
-2,534.23
-888.87
6,013,698.86
568,272.09
0.00
2,673.55
4,300.00
59.19
198.66
2,874.56
2,827.26
-2,615.60
-916.35
6,013,617.24
568,245.37
0.00
2,759.14
4,400.00
59.19
198.66
2,925.78
2,878.48
-2,696.98
-943.83
6,013,535.63
568,218.65
0.00
2,844.73
4,500.00
59.19
198.66
2,977.00
2,929.70
-2,778.35
-971.31
6,013,454.01
568,191.93
0.00
2,930.32
4,600.00
59.19
198.66
3,028.22
2,980.92
-2,859.72
-998.79
6,013,372.40
568,165.21
0.00
3,015.91
4,700.00
59.19
198.66
3,079.44
3,032.14
-2,941.09
-1,026.27
6,013,290.78
568,138.50
0.00
3,101.50
4,800.00
59.19
198.66
3,130.66
3,083.36
-3,022.46
-1,053.74
6,013,209.16
568,111.78
0.00
3,187.09
4,900.00
59.19
198.66
3,181.88
3,134.58
-3,103.84
-1,081.22
6,013,127.55
568,085.06
0.00
3,272.68
5,000.00
59.19
198.66
3,233.10
3,185.80
-3,185.21
-1,108.70
6,013,045.93
568,058.34
0.00
3,358.28
5,100.00
59.19
198.66
3,284.32
3,237.02
-3,266.58
-1,136.18
6,012,964.32
568,031.62
0.00
3,443.87
5,200.00
59.19
198.66
3,335.54
3,288.24
-3,347.95
-1,163.66
6,012,882.70
568,004.90
0.00
3,529.46
5,300.00
59.19
198.66
3,386.76
3,339.46
-3,429.32
-1,191.14
6,012,801.09
567,978.18
0.00
3,615.05
5,400.00
59.19
198.66
3,437.99
3,390.69
-3,510.70
-1,218.62
6,012,719.47
567,951.46
0.00
3,700.64
5,500.00
59.19
198.66
3,489.21
3,441.91
-3,592.07
-1,246.09
6,012,637.85
567,924.74
0.00
3,786.23
5,600.00
59.19
198.66
3,540.43
3,493.13
-3,673.44
-1,273.57
6,012,556.24
567,898.02
0.00
3,871.82
5,700.00
59.19
198.66
3,591.65
3,544.35
-3,754.81
-1,301.05
6,012,474.62
567,871.30
0.00
3,957.41
5,800.00
59.19
198.66
3,642.87
3,595.57
-3,836.18
-1,328.53
6,012,393.01
567,844.58
0.00
4,043.00
5,900.00
59.19
198.66
3,694.09
3,646.79
-3,917.55
-1,356.01
6,012,311.39
567,817.86
0.00
4,128.59
6,000.00
59.19
198.66
3,745.31
3,698.01
-3,998.93
-1,383.49
6,012,229.78
567,791.14
0.00
4,214.18
6,100.00
59.19
198.66
3,796.53
3,749.23
-4,080.30
-1,410.97
6,012,148.16
567,764.42
0.00
4,299.77
6,200.00
59.19
198.66
3,847.75
3,800.45
-4,161.67
-1,438.44
6,012,066.55
567,737.70
0.00
4,385.36
6,300.00
59.19
198.66
3,898.97
3,851.67
4,243.04
-1,465.92
6,011,984.93
567,710.98
0.00
4,470.95
6,400.00
59.19
198.66
3,950.19
3,902.89
-4,324.41
-1,493.40
6,011,903.31
567,684.26
0.00
4,556.54
6,500.00
59.19
198.66
4,001.41
3,954.11
-4,405.79
-1,520.88
6,011,821.70
567,657.54
0.00
4,642.13
6,523.36
59.19
198.66
4,013.38
3,966.08
-4,424.79
-1,527.30
6,011,802.63
567,651.30
0.00
4,662.12
Start Dir 40/100': 6523.36' MD,
4013.38'TVD
6,600.00
62.19
197.96
4,050.89
4,003.59
-4,488.23
-1,548.29
6,011,739.01
567,630.90
4.00
4,728.74
6,700.00
66.12
197.11
4,094.47
4,047.17
-4,574.04
-1,575.39
6,011,652.97
567,604.60
4.00
4,818.54
6,800.00
70.05
196.31
4,131.79
4,084.49
-4,662.88
-1,602.05
6,011,563.89
567,578.76
4.00
4,911.19
6,900.00
73.98
195.55
4,162.65
4,115.35
-4,754.32
-1,628.15
6,011,472.22
567,553.52
4.00
5,006.22
7,000.00
77.92
194.82
4,186.92
4,139.62
-4,847.93
-1,653.54
6,011,378.39
567,529.00
4.00
5,103.19
7,100.00
81.86
194.10
4,204.47
4,157.17
-4,943.24
-1,678.11
5,011,282.86
567,505.31
4.00
5,201.61
7,128.97
83.00
193.90
4,208.29
4,160.99
-4,971.10
-1,685.06
6,011,254.94
567,498.63
4.00
5,230.33
End Dir :
7128.97' MD, 4208.29' TVD
7,200.00
83.00
193.90
4,216.95
4,169.65
-5,039.54
-1,702.00
6,011,186.35
567,482.33
0.00
5,300.83
7,300.00
83.00
193.90
4,229.13
4,181.83
-5,135.89
-1,725.84
6,011,089.80
567,459.38
0.00
5,400.08
7,400.00
83.00
193.90
4,241.32
4,194.02
-5,232.23
-1,749.69
6,010,993.24
567,436.43
0.00
5,499.34
7,500.00
83.00
193.90
4,253.51
4,206.21
-5,328.58
-1,773.53
6,010,896.68
567,413.49
0.00
5,598.59
7,600.00
83.00
193.90
4,265.70
4,218.40
-5,424.93
-1,797.37
6,010,800.13
567,390.54
0.00
5,697.85
7,700.00
83.00
193.90
4,277.88
4,230.58
-5,521.28
-1,821.22
6,010,703.57
567,367.60
0.00
5,797.10
7,800.00
83.00
193.90
4,290.07
4,242.77
-5,617.63
-1,845.06
6,010,607.02
567,344.65
0.00
5,896.36
7,828.97
83.00
193.90
4,293.60
4,246.30
-5,645.54
-1,851.97
6,010,579.04
567,338.00
0.00
5,925.12
5(142019 3:28:09PM
Page
4
COMPASS 5000.15 Build 91
5f14/2019 3:28:09PM Page 5 COMPASS 5000.15 Build 91
Halliburton
HALLIBURTON
Standard Proposal Report
Database:
NORTH US
+ CANADA
Local Co-ordinate Reference: Well Plan: MPU E-42
Company:
Hilcom Alaska, LLC
7VD Reference:
MPU
E-42 As -Staked
RKB @ 47.30usft
Project:
Milne Point
MD Reference:
MPU
E-42 As -Staked
RKB @ 47.30usft
Site:
M Pt E Pad
North Reference:
True
Well:
Plan: MPU E-42
Survey Calculation
Method: Minimum Curvature
Wellbore:
MPU E-42
Design:
MPU E-42 wp06
Planned Survey
Measured
Vertical
Map
Map
Depth Inclination Azimuth
Depth
TVDss
+N/.S
+E/ -W
Northing
Easting
DLS
Vert Section
(usft)
V)
(1)
(usft)
usft
(usft)
(usft)
(usft)
(usft) 4,249.96
7,858.97
83.00
193.90
4,297.26
4,249-96
-5,674.44
-1,859.12
6,010,550.08
567,331.12
0.00
5,954.89
Start Dir 401100' : 7858.97' MD,
4297.26'TVD
7,908.97
85.00
193.90
4,302.48
4,255.18
-5,722.71
-1,871.07
6,010,501.71
567,319.62
4.00
6,004.61
End Dir :
7908.97' MD, 4302.48' TVD
7,957.37
85.00
193.90
4,306.70
4,259.40
-5,769.51
-1,882.65
6,010,454.80
567,308.48
0.00
6,052.83
Top SBOA
8,000.00
85.00
193.90
4,310.42
4,263.12
-5,810.74
-1,892.85
6,010,413.49
567,298.66
0.00
6,095.30
8,100.00
85.00
193.90
4,319.13
4,271.83
-5,907.44
-1,916.78
6,010,316.58
567,275.63
0.00
6,194.91
9 518" x 12
1/4"
8,201.76
85.00
193.90
4,328.00
4,280.70
-6,005.84
-1,941.13
6,010,217.96
567,252.19
0.00
6,296.29
Start Dir 401100' : 8201.76' MD,
4328'TVD
8,300.00
88.93
193.90
4,333.20
4,285.90
-6,101.06
-1,964.70
6,010,122.54
567,229.51
4.00
6,394.37
8,386.22
92.38
193.90
4,332.22
4,284.92
-6,184.73
-1,985.41
6,010,038.69
567,209.58
4.00
6,480.57
End Dir :
8386.22' MD, 4332.22' TVD
8,400.00
92.38
193.90
4,331.64
4,284.34
-6,198.10
-1,988.72
6,010,025.29
567,206.40
0.00
6,494.34
8,500.00
92.38
193.90
4,327.49
4,280.19
-6,295.08
-2,012.73
6,009,928.10
567,183.29
0.00
6,594.25
8,600.00
92.38
193.90
4,323.34
4,276.04
-6,392.07
-2,036.73
6,009,830.90
567,160.19
0.00
6,694.17
8,700.00
92.38
193.90
4,319.19
4,271.89
-6,489.06
-2,060.74
6,009,733.71
567,137.08
0.00
6,794.08
8,800.00
92.38
193.90
4,315.04
4,267.74
-6,586.04
-2,084.75
6,009,636.51
567,113.98
0.00
6,894.00
8,900.00
92.38
193.90
4,310.89
4,263.59
-6,683.03
-2,108.76
6,009,539.31
567,090.88
0.00
6,993.91
9,000.00
92.38
193.90
4,306.74
4,259.44
-6,780.02
-2,132.76
6,009,442.12
567,067.77
0.00
7,093.82
9,100.00
92.38
193.90
4,302.59
4,255.29
-6,877.00
-2,156.77
6,009,344.92
567,044.67
0.00
7,193.74
9,200.00
92.38
193.90
4,298.44
4,251.14
-6,973.99
-2,180.78
6,009,247.72
567,021.56
0.00
7,293.65
9,300.00
92.38
193.90
4,294.29
4,246.99
-7,070.98
-2,204.79
6,009,150.53
566,998.46
0.00
7,393.56
9,400.00
92.38
193.90
4,290.14
4,242.84
-7,167.96
-2,228.79
6,009,053.33
566,975.35
0.00
7,493.48
9,500.00
92.38
193.90
4,285.99
4,238.69
-7,264.95
-2,252.80
6,008,956.14
566,952.25
0.00
7,593.39
9,600.00
92.38
193.90
4,281.84
4,234.54
-7,361.94
-2,276.81
6,008,858.94
566,929.15
0.00
7,693.31
9,700.00
92.38
193.90
4,277.69
4,230.39
-7,458.92
-2,300.82
6,008,761.74
566,906.04
0.00
7,793.22
9,800.00
92.38
193.90
4,273.54
4,226.24
-7,555-91
-2,324.82
6,008,664.55
566,882.94
0.00
7,893.13
9,900.00
92.38
193.90
4,269.39
4,222.09
-7,652.90
-2,348.83
6,008,567.35
566,859.83
0.00
7,993.05
10,000.00
92.38
193.90
4,265.24
4,217.94
-7,749.88
-2,372.84
6,008,470.16
566,836.73
0.00
8,092.96
10,100.00
92.38
193.90
4,261.09
4,213.79
-7,846.87
-2,396.85
6,008,372.96
566,813.62
0.00
8,192.88
10,200.00
92.38
193.90
4,256.94
4,209.64
-7,943.86
-2,420.85
6,008,275.76
566,790.52
0.00
8,292.79
10,298.90
92.38
193.90
4,252.94
4,205.54
-8,039.78
-2,444.60
6,008,179.64
566,767.67
0.00
8,391.60
Start Dir
40/100' : 10298.9' MD,
4252.84'TVD
10,300.00
92.33
193.90
4,252.79
4,205.49
-8,040.84
-2,444.86
6,008,178.57
566,767.42
4.01
8,392.70
10,332.46
91.04
193.90
4,251.84
4,204.54
-8,072.34
-2,452.66
6,008,147.01
566,759.91
4.00
8,425.15
End Dir
: 10332.46' MD, 4251.84' TVD
10,400.00
91.04
193.90
4,250.62
4,203.32
-8,137.89
-2,468.88
6,008,081.31
566,744.30
0.00
8,492.68
10,500.00
91.04
193.90
4,248.81
4,201.51
-8,234.94
-2,492.91
6,007,984.05
566,721.18
0.00
8,592.66
10,600.00
91.04
193.90
4,247.00
4,199.70
-8,332.00
-2,516.93
6,007,886.78
566,698.06
0.00
8,692.64
10,700.00
91.04
193.90
4,245.19
4,197.89
-8,429.05
-2,540.96
6,007,789.52
566,674.94
0.00
8,792.63
10,800.00
91.04
193.90
4,243.39
4,196.09
-8,526.11
-2,564.98
6,007,692.26
566,651.82
0.00
8,892.61
10,900.00
91.04
193.90
4,241.58
4,194.28
-8,623.16
-2,589.00
6,007,594.99
566,628.70
0.00
8,992.60
11,000.00
91.04
193.90
4,239.77
4,192.47
-8,720.22
-2,613.03
6,007,497.73
566,605.58
0.00
9,092.58
5f14/2019 3:28:09PM Page 5 COMPASS 5000.15 Build 91
HALLIBURTON
Halliburton
Standard Proposal Report
Database:
NORTH US + CANADA
Local Co-ordinate Reference:
Well Plan: MPU E-42
Company:
Hiloorp Alaska, LLC
TVD Reference:
MPU E42 As -Staked IRKS @ 47.30usft
Project:
Milne Point
MD Reference:
MPU E42 As -Staked RKB @ 47.30usft
Site:
M Pt E Pad
North Reference:
True
Well:
Plan: MPU E-42
Survey Calculation Method:
Minimum Curvature
Wellbore:
MPU E-42
-Shape
(°)
Design:
MPU E-42 wp06
(usft)
(usft)
Planned Survey
Measured Vertical
Depth Inclination Azimuth Depth TVDss +NIS +E/ -W
(usft) (°) (°) (usft) usft (usft) (usft)
11,100.00 91.04 193.90 4,237.96 4,190.66 -8,817.27 -2,637.05
11,200.00 91.04 193.90 4,236.15 4,188.85 -8,914.32 -2,661.08
11,300.00 91.04 193.90 4,234.35 4,187.05 -9,011.38 -2,685.10
11,400.00 91.04 193.90 4,232.54 4,185.24 -9,108.43 -2,709.12
11,500.00 91.04 193.90 4,230.73 4,183.43 -9,205.49 -2,733.15
11,600.00 91.04 193.90 4,228.92 4,181.62 -9,302.54 -2,757.17
11,700.00 91.04 193.90 4,227.11 4,179.81 -9,399.60 -2,781.20
11,800.00 91.04 193.90 4,225.31 4,178.01 -9,496.65 -2,805.22
11,900.00 91.04 193.90 4,223.50 4,176.20 -9,593.71 -2,829.24
11,949.71 • 91.04 193.90 4,222.60 • 4,175.30 -9,641.95 -2,841.19
Total Depth: 11949.71' MD, 4222.6' TVD - 4 112" x 8112"
Map
Northing
(usft)
6,007,400.46
6,007,303.20
6,007,205.94
6,007,108.67
6,007,011.41
6,006,914.14
6,006,816.88
6,006,719.62
6,006,622.35
6,006,574.00
Map
Easting DLS
(usft) 4,190.66
566,582.46 0.00
566,559.34 0.00
566,536.21 0.00
566,513.09 0.00
566,489.97 0.00
566,466.85 0.00
566,443.73 0.00
566,420.61 0.00
566,397.49 0.00
566,386.00 0.00
Vert Section
9,192.56
9,292.55
9,392.53
9,492.51
9,592.50
9,692.48
9,792.46
9,892.45
9,992.43
10,042.13
Targets
Target Name
-hit/miss target Dip
Angle Dip
Dir. TVD
+NI -S +E/ -W
Northing
Easting
-Shape
(°)
(°) (usft)
(usft) (usft)
(usft)
(usft)
MPE-42 wp05 - OB Toe
0.00
0.00 4,222.60
-9,641.95 -2,841.19
6,006,574.00
566,386.00
- plan hits tarqet center
- Circle (radius 50.00)
MPE-42 wp05 - L1 OA Heel
0.00
0.00 4,293.60
-5,645.54 -1,851.97
6,010,579.04
567,338.00
- plan hits target center
- Circle (radius 50.00)
MPE-42 wp05-CP1
0.00
0.00 4,252.84
-8,039.77 -2,444.60
6,008,179.64
566,767.67
- plan hits target center
- Circle (radius 50.00)
MPE-42 wp05 - OB Heel
0.00
0.00 4,325.60
-5,979.21 -1,934.54
6,010,244.65
567,258.54
- plan misses tarqet center by 0.01 usft at 8174.22usft MD (4325.60 TVD, -5979.21
N, -1934.54 E)
- Circle (radius 50.00)
Casing Points
Measured Vertical
Casing Hole
Depth Depth
Diameter Diameter
(usft) (usft)
Name
("1 (11)
11,949.71 4,222.60 41/2"x81/2"
4-1/2 8-1/2
8,100.00 4,319.13 95/8"x121/4"
9-5/8 12-1/4
Formations
Measured Vertical Vertical
Dip
Depth Depth Depth SS
Dip
Direction
(usft) (usft)
Name
Lithology (°)
(°)
7,957.37 4,30670
Top SBOA
0.00
511412019 3:28 09PM
Page 6
COMPASS 5000.15 Build 91
HALLIBURTON
Halliburton
Standard Proposal Report
Database:
NORTH US + CANADA
Local Co-ordinate Reference: Well Plan: MPU E-42
Company:
Hilcorp Alaska, LLC
TVD Reference: MPU E-42As-Staked RKB @ 47.30usft
Project:
Milne Point
MD Reference: MPU E-42As-Staked RKB @ 47.30usft
Site:
M Pt E Pad
North Reference: True
Well:
Plan: MPU E-42
Survey Calculation Method: Minimum Curvature
Wellbore:
MPU E-42
Design:
MPU E-42 wp06
Plan Annotations
Measured Vertical
Local Coordinates
Depth Depth
+N/ -S
+EI -W
(usft) (usft)
(usft)
(usft)
Comment
350.00 350.00
0.00
0.00
Start Dir 30/100': 350' MD, 350'TVD
550.00 549.63
-8.01
-6.73
Start Dir 4-/100': 550' MD, 549.63'TVD
1,890.71 1,640.51
-655.12
-254.31
End Dir : 1890.71' MD, 1640.51' TVD
6,523.36 4,013.38
-4,424.79
-1,527.30
Start Dir 4-/100': 6523.36' MD, 4013.38'TVD
7,128.97 4,208.29
-4,971.10
-1,685.06
End Dir : 7128.97' MD, 4208.29' TVD
7,858.97 4,297.26
-5,645.54
-1,851.97
Start Dir 4°/100' : 7858.97' MD, 4297.26'TVD
7,908.97 4,302.48
-5,674.44
-1,859.12
End Dir :7908.97' MD, 4302.48' TVD
8,201.76 4,328.00
-5,722.71
-1,871.07
Start Dir 4°/100' : 8201.76' MD, 4328T/D
8,386.22 4,332.22
-6,005.84
-1,941.13
End Dir : 8386.22' MD, 4332.22' TVD
10,298.90 4,252.84
-6,184.73
-1,985.41
Start Dir 4°1100' : 10298.9' MD, 4252.84'TVD
10,332.46 4,251.84
-8,039.78
-2,444.60
End Dir : 10332.46' MD, 4251.84' TVD
11,949.71 4,222.60
-8,072.34
-2,452.66
Total Depth : 11949.71' MD, 4222.6' TVD
5/14/2019 3:28:09PM Page 7 COMPASS 5000.15 Build 91
Hilcorp Alaska, LLC
Milne Point
M Pt E Pad
Plan: MPU E-42
MPU E-42
MPU E-42 wp06
Sperry Drilling Services
Clearance Summary
Anticollision Report
14 May, 2019
Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)
Reference Design: M Pt E Pad - Plan: MPU E42 - MPU E42 - MPU E42 wp06
Well Coordinates: 6,016,240.99 N, 569,137.33 E (70' 27' 1].03" N, 149' 26' 08.90" W)
Datum Height: MPU E42 As -Staked RKB @ 47.30ush
Scan Range: 26.50 to 8,100.00 usft. Measured Depth.
Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited Max Ellipse Separation is 1,500.00 usft
Geodetic Scale Factor Applied
Version: 5090.15 Build: 91
Scan Type:
Scan Type: 25.00
HALLIBURTON
Sperry Orilling servilses
HALLIBURTON
Anticollision Report for Plan: MPU E-42 - MPU E-42 wpO6
f Hilcorp Alaska, LLC
Milne Point
Closest Approach 30 Proximity Scan on Current Survey Data (North Reference)
Reference Design: MPt E Pad - Plan: MPU E42 -MPU E -42 -MPU E42 wp06
Scan Range: 26.50 to 8,100.00 usff. Measured Depth.
Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited.
Max Ellipse
Separation is 1,500.00 us%
Measured
Minimum
@Measured
Ellipse
§Measured
Clearance Summary Based on
Site Name
Depth
Distance
Depth
Separation
Depth
Factor Minimum
Separation Warning
Comparison Well Name - Wellbore Name -Design
(usff)
(usff)
salt)
(usff)
usff
EX KAVEAR32-25
KAVEAR32-25-KAVEAR32-25-KAVEARAK PT 32-2
326.50
217.31
326.50
212.28
316.20
43.144 Centre Distance
Pass-
KAVEAR32-25-KAVEAR32-25-KAVEARAK PT 32-2
376.50
217.47
376,50
211,79
36620
38.265 Ellipse Separation
Pass-
KAVEAR32-25-KAVEAR32-25-KAVEARAK PT 32-2
976.50
325.00
976.50
307.72
95471
ta.809 Clearance Factor
Pass -
M Pt E Pad
MPE-04 - MPE-04 - MPE-04
26.50
232.81
26.50
231.89
36.92
253.540 Centre Distance
Paw -
MPE-04-MPE-04-MPE-04
376.50
233.62
376.50
229.63
386.77
55.908 Ellipse Separation
Pass-
MPE-04 - MPE-04 - MPE-04
826.50
302.63
826.50
294.15
817.24
35.677 Clearance Factor
Pass-
MPE-05-MPE-05-MPE-05
26.50
211.49
26.50
210.57
37.85
230.358 Centre Distance
Pass -
MPE-0S-MPE-0S-MPE-05
376.50
213.59
376.50
209.40
388.13
51.017 Ellipse Separation
Pass-
MPE-05-MPE4)5-MPE-05
851.50
288.50
851.50
279.71
853.38
32.813 Cleaance Factor
Pass -
MPE-06 - MPE-06 - MPE-06
331.70
161.64
331.70
157.05
342.43
35.205 Centre Distance
Pass-
MPE-06 - MPE-06 - MPE-06
376.50
161.84
376.50
156.67
387.06
31.309 Ellipse Separation
Pass -
MPE-06 - MPE-06 - MPE-06
726.50
211.82
726.50
202.16
719.17
21.930 Clearance Factor
Pass -
MPE-07 - MPE-07 - MPE-07
356.49
160.10
356.49
ISSAS
367.70
32.583 Centre Distance
Pass -
MPE-07 - MPE-07 - MPE-07
376.50
160.19
376.50
155.02
387.75
30.969 Ellipse Separation
Pass -
MPE-07-MPE-07-MPE-07
826.50
216.71
826.50
205.63
831.92
19.558 Clearance Factor
Pass-
MPE-09-MPE-09-MPE-09
361.97
34.91
361.97
31.53
368.72
10.332 Centre Distance
Pass -
MPE-09-MPE-09-MPE-09
451.50
35.34
451.50
31.27
458.39
8.672 Ellipse Separation
Pass-
MPE-09-MPE-09-MPE-09
576.50
39.01
576.50
33.88
583.22
7605 Clearance Factor
Pass -
MPE-09-MPE-09PB1-MPE-09PB1
361.97
34.91
361.97
31.53
368.72
10.332 Centre Distance
Pass -
MPE-09-MPE-09PB1-MPE-09PB1
451.50
35.34
451.50
31.27
458.39
8.672 Ellipse Separation
Pass -
MPE-09 - MPE-09PB1 - MPE-09PB1
576.50
39.01
576.50
33.88
583.22
7.605 Clearance Factor
Pass -
MPE-10 - MPE-10 - MPE-10
26.50
215.28
26.50
214.36
32.79
233.727 Centre Distance
Pass -
MPE-10 - MPE-10 - MPE-10
576.50
215.67
576.50
209.55
590.76
35.280 Ellipse Separation
Pass-
MPE-10-MPE-10-MPE-10
901.50
248.26
901.50
238.99
912.81
26.789 Clearance Factor
Pass -
MPE-11 - MPE-1 1 - MPE-11
544.77
24.56
544]7
18.81
550.95
4.266 Centre Distance
Pass -
MPE-1 1 - MPE-1 1 - MPE-1 1
601.50
24.88
601.50
1859
607.40
3.953 Ellipse Separation
Pass -
14 May, 2019 - 15:28 Page 2 01 10 COMPASS
HALLIBURTON
t Hileorp Alaska, LLC
Milne Point
Anticollision Report for Plan: MPU E-42 - MPU E-42 wp06
26.50
95.27
26.50
94.20
Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)
88.428 Centre Distance
Pass-
MPE-13-MPE-13A-MPE-13A
226.50
96.66
Reference Design: M PI E Pad - Plan: MPU E-42 -MPU E42 -MPU E42 wp06
93.88
232.15
34.740 Ellipse Separation
Pass-
MPE-13-MPE-13A-MPE-13A
Scan Range: 26.50 to 8,100.00 usft. Measured Depth.
120.64
751.50
112.87
755.09
15.532 Clearance Factor
Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft
MPE-13-MPE-IMPB7-MPE-13AP81
26.50
95.27
26.50
Measured Minimum
@Measuretl
Ellipse
®Measured
Clearance Summary Based on
226.50
Site Name Depth Distance
Depth
Separation
Depth
Factor Minimum
Separation Warning
Comparison Well Name - Wellbore Name -Design (usft) (usft)
(usft)
(..it)
usft
112.87
755.09
MPE-11 - MPE-11 - MPE-11 626.50 25.41
626.50
18.88
632.15
3.890 Clearance Factor
Pass-
MPE-12-MPE-12-MPE-12 26.50 214.10
26.50
213.02
36.52
198.363 Centre Distance
Pass -
MPE-12 - MPE-12 - MPE-12 351.50 216.18
351.50
211.35
359.42
44.777 Ellipse Separation
Pass-
MPE-12-MPE-12-MPE-12 726.50 25323
726.50
246.33
711.37
36.696 Clearance Factor
Paw -
MPE-13-MPE-13-MPE-13 26.50 95.27
26.50
94.20
32.99
88.428 Centre Distance
Pass -
MPE-13-MPE-13-MPE-13 226.50 96.66
226.50
93.88
232.15
34.740 Ellipse Separation
Pass-
MPE-13-MPE-13-MPE-13 751.50 120.64
751.50
112.87
755.09
15.532 Clearance Factor
Pass -
MPE-13-MPE-13A-MPE-13A
26.50
95.27
26.50
94.20
32.99
88.428 Centre Distance
Pass-
MPE-13-MPE-13A-MPE-13A
226.50
96.66
226.50
93.88
232.15
34.740 Ellipse Separation
Pass-
MPE-13-MPE-13A-MPE-13A
751.50
120.64
751.50
112.87
755.09
15.532 Clearance Factor
Pass -
MPE-13-MPE-IMPB7-MPE-13AP81
26.50
95.27
26.50
94.20
32.99
88.428 Centre Distance
Pass -
MPE-13-MPE-I3APB1-MPE-IMPB1
226.50
96.66
226.50
93.88
232.15
34.740 Ellipse Separation
Pass -
MPE-13-MPE-I3APB1-MPE-1 MPB1
751.50
120.64
751.50
112.87
755.09
15.532 Clearance Factor
Pass-
MPE-13-MPE-I3APB2-MPE-IMPS2
26.50
95.27
26.50
94.20
32.99
88.428 Centre Distance
Pass -
MPE-13-MPE-I3APR2-MPE-I3APB2
226.50
96.66
226.50
93.88
232.15
M.740 Ellipse Separation
Pass -
MPE-13-MPE-I3APW-MPE-I3APB2
751.50
120.64
751.50
112.87
755.09
15.532 Clearance Factor
Pass -
MPE-13 - MPE-13B - MPE-13B
26.50
95.27
26.50
94.35
38.16
103.427 Centre Distance
Pass -
MPE-13-MPE-13B-MPE-138
226.50
96.66
226.50
94.04
237.32
36.807 Ellipse Separation
Pass -
MPE-13 - MPE-13B - MPE-13B
751.50
120.64
751.50
113.03
760.26
15.851 Clearance Factor
Pass -
MPE-1 4 - MPE-1 4 - MPE-14
829.26
135.96
829.26
129.15
83230
19.973 Centre Distance
Pass -
MPE-14 - MPE-14 - MPE-14
851.50
136.11
851.50
129.13
853.25
19.504 Ellipse Separation
Paw -
MPE-14-MPE-14-MPE-14
951.50
141.54
951.50
133.89
946.07
18.493 Clearance Factor
Pass -
MPE-14 - MPE-14A - MPE-14A
829.26
135.96
829.26
129.15
832.30
19.973 Centre Distance
Pass -
MPE-14 - MPE-14A - MPE-14A
851.50
136.11
851.50
129.13
853.25
19.503 Ellipse Separa0on
Pass -
MPE-14 - MPE-14A - MPE-14A
951.50
141.54
951.50
133.89
946.07
ISA93 Clearance Factor
Pass -
MPE-14 - MPE-14APB1 - MPE-14APBI
829.26
135.96
829.26
129.15
832.30
19.973 Centre Distance
Pass -
MPE-14-MPE-I4APB1-MPE-I4APB1
851.50
136.11
851.50
129.13
853.25
19.503 Ellipse Separation
Pass -
MPE-14-MPE-I4APB1-MPE-I4APB1
951.50
14154
951.50
133.89
946.07
18.493 Clearance Factor
Pass -
MPE-1 5 - MPE-1 5 - MPE-1 5
983.25
157.57
983.25
142.69
978.68
10.593 Centre Distance
Pass-
MPE-15-MPE-15-MPE-15
1,001.50
157.68
1,001.50
142.56
996.25
10.432 Ellipse Separation
Pass-
MPE-15-MPE-15-MPE-15
1,151.50
167.99
1,151.50
151.04
1,140.61
9.911 Clearance Factor
Pa6s-
14 May, 2819 - 15:28 Page 3 of 10 COMPASS
HALLIBURTON
Hilcorp Alaska, LLC
Milne Point
Anticollision Report for Plan: MPU E-42 - MPU E-42 wp06
MPE-19 - MPE-19
432.73
194.20
432.73
Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)
449.78
51.531
Centre Distance
Pass -
MPE-19-MPE-19-MPE-19
Reference Design: M Pt E Pad - Plan: MPU E42 -MPU E42 -MPU E42 Wp06
476.50
194.43
476.50
190.32
494.65
Scan Range: 26.50 to 8,100.00 usft. Measured Depth.
Ellipse Separation
Pass -
MPE-19-MPE-19-MPE-19
976.50
Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft
976.50
227.41
1,000.18
28.666
Measured Minimum
@Measured
Ellipse
QMeasumd
Clearance Summary Based on
83.96
Site Name Depth Distance
Depth
Separation
Depth
Factor Minimum
Separation Warning
Comparison Well Name -Wellbore Name - Design (usft) (usft)
(usft)
(usft)
Usti
726.50
77.54
MPE-16-MPE,16-MPE-16 116.06 167.89
116.06
166.30
1U.76
105.566 Centre Distance
Pass -
M PE -1 6 - MPE-1 6 - MPE-1 6 301.50 168.36
30150
165.03
306.67
50.553 Ellipse Separation
Pass -
MPE-16 - MPE-16 - MPE-16 726.50 226.31
726.50
218.95
706.76
MISS Clearance Factor
Pass -
MPE-18 - MPE-18 - MPE-18 811.94 26.01
811.94
19.25
822.67
3.847 Ellipse Separation
Pass -
MPE-18-MPE-18-MP&16 826.50 2621
826.50
19.32
836.96
3.806 Clearance Factor
Pass -
MPE-19 -
MPE-19 - MPE-19
432.73
194.20
432.73
190.43
449.78
51.531
Centre Distance
Pass -
MPE-19-MPE-19-MPE-19
476.50
194.43
476.50
190.32
494.65
47.259
Ellipse Separation
Pass -
MPE-19-MPE-19-MPE-19
976.50
235.63
976.50
227.41
1,000.18
28.666
Clearance Factor
Pass -
MPE-20 -
MPE-20 - MPE-20
707.20
83.96
707.20
77.64
710.53
13.266
Centre Distance
Pass -
MPE-20-MPE-20-MPE-20
726.50
84.02
726.50
77.54
729.56
12.966
Ellipse Separation
Pass -
MPE-20 -
MPE-20 - MPE-20
876.50
90.15
876.50
82.47
876.44
11.729
Clearance Factor
Pass -
MPE-20 -
MPE-20A - MPE-20A
707.20
83.96
707.20
77.64
715.28
13.266
Centre Distance
Pass-
MPE-20-MPE-20A-MPE-20A
726.50
84.02
726.50
77.54
734.31
12.966
Ellipse Separation
Pass -
MPE-20-MPE-20A-MPE-20A
076.50
WAS
876.50
82.47
881.19
11.728
Clearance Factor
Pass -
MPE-20-MPE-20AL1-MPE-20AL1
707.20
83.96
707.20
77.63
715.28
13.266
Centre Distance
Pass -
MPE-20-MPE-20AL1-MPE-20AL1
726.50
84.02
726.50
77.54
734.31
12.966
Ellipse Separation
Pass-
MPE-20-MPE-20AL1-MPE-20AL1
876.50
90.15
876.50
82.47
881.19
11.728
Clearance Factor
Pass-
MPE-20-MPE-20AL1PB1-MPE-20AL1PB1
707.20
83.96
707.20
77.64
715.28
13.266
Centre Distance
Pass -
MPE-20-MPE-20AL1PB1-MPE-20AL1PB1
726.50
84.02
726.50
77.54
73431
12.966
Ellipse Separation
Pass -
MPE-20-MPE-20AL1P81-MPE-20ALIPB1
Si
90.15
676.50
82.47
881.19
11.728
Clearance Factor
Pass -
MPE-21 -
MPE-21 - MPE-21
363.21
156.01
363.21
154.03
373.98
56.573
Centre Distance
Pass -
MPE-21 -
MPE-21 - MPE-21
376.50
156.86
376.50
153.99
387.06
54.602
Ellipse Separation
Pass -
MPE-21 -
MPE-21 - MPE-21
701.50
194.10
701.50
188.77
701.46
36.407
Clearance Factor
Pass-
MPE-22-MPE-22-MPE22
26.50
154.68
26.50
153.76
32.97
167.962
Centre Distance
Pass -
MPE-22 -
MPE-22 - MPE-22
401.50
15634
401.50
151.94
407.57
35.465
Ellipse Separation
Pass -
MPE-22-MPE-22-MPE-22
876.50
191.98
876.50
182.97
885.17
21.308
Clearance Factor
Pass-
MPE-23-MPE-23-MPE-23
26.50
179.80
26.50
178.88
33.28
195.067
Centre Distance
Pass -
MPE-23 -
MPE-23 - MPE-23
351.50
181.18
351.50
177.37
357.38
47.614
Ellipse Separation
Pass -
MPE-23 -
MPE-23 - MPE-23
901.50
248.38
901.50
239.31
895.92
27.379
Clearance Factor
Pass -
MPE-24 -
MPE-24 - MPE-24
1,139.01
86.85
1,139.01
76.78
1,132.14
8.628
Centre Distance
Pass -
14 May, 2019 - 15:28 Page 4 of COMPASS
HALLIBURTON
Ailcorp Alaska, LLC
Milne Point
Anticollision Report for Plan: MPU E-42 - MPU E-42 wp06
1,139.01
86.85
1,139.01
76.88
Closest Approach 3D Proximity Scan on Cement Survey Data (North Reference)
8.714 Centre Distance
Pass -
MPE-24-MPE-24AL1-MPE-24ALI
1,151.50
86.91
Reference Design: MPt E Pad - Plan: MPU E42 -MPU E42 -MPU E42 state
76.84
1,140.71
8.629 Ellipse Separation
pass -
MPE-24-MPE-24AL1-MPE-24AL1
Scan Range: 26.50 to 8,100.00 usfi. Measured Depth.
870.46
4,801.50
727.23
4,872.03
6.077 Clearance Factor
Seen Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 miff
MPE-25 - MPE-25 - MPE-25
394.25
4.52
Measured Minimum
@Measured
Ellipse
@Measured
Clearance Summary Based on
MPE-25 - MPE-25 - MPE-25
Site Name Depth Distance
Depth
Separation
Depth
Factor Minimum
Separation Warning
Comparison Well Name -Wellbore Name - Design (usft) (mitt)
(usfi)
(usfi)
usfi
394.25
1.00
MPE-24 - MPE-24 - MPE-24 1,151.50 8691
1,151.50
76.74
1,144.11
8.545 Ellipse Separation
Pass -
MPE-24 - MPE-24 - MPE-24 4,801.50 870.46
4,801.50
726.52
4,875.43
6.048 Clearance Factor
Pass-
MPE-24-MPE-24A-MPE-24A 1,139.01 86.85
1,139.01
76.89
1,128.74
8.720 Centre Distance
Pass -
MPE-24 - MPE-24A - MPE-24A 1,151.50 86.91
1,151.50
76.85
1,140.71
8.634 Ellipse Separation
Pass-
MPE-24-MPE-24A-MPE-24A 4,801.50 870.46
4,801.50
727.38
4,872.03
6.084 Clearance Factor
Pass -
MPE-24-MPE-24AL1-MPE-24AL1
1,139.01
86.85
1,139.01
76.88
1,128.74
8.714 Centre Distance
Pass -
MPE-24-MPE-24AL1-MPE-24ALI
1,151.50
86.91
1,151.50
76.84
1,140.71
8.629 Ellipse Separation
pass -
MPE-24-MPE-24AL1-MPE-24AL1
4,801.50
870.46
4,801.50
727.23
4,872.03
6.077 Clearance Factor
Pass -
MPE-25 - MPE-25 - MPE-25
394.25
4.52
394.25
1.00
398.98
1.283 Centre Distance
Pass -
MPE-25 - MPE-25 - MPE-25
426.50
4.66
426.50
0.89
431.22
1.236 Clearance Factor
Pass -
MPE-25 - MPE-25A - MPE-25A
394.25
4.52
394.25
1.00
403.93
1.283 Centre Distance
pass -
MPE-25-MPE-25A-MPE-25A
426.50
4.66
426.50
0.89
436.17
1.236 Clearance Factor
Pass-
MPE-25-MPE-251-1-MPE-251-1
394.25
4.52
394.25
1.00
398.98
1.283 Centre Distance
Pass -
MPE-25 - MPE-251-1 - MPE-251-1
426.50
4.66
426.50
0.89
431.22
1.236 Clearance Factor
Pass-
MPE-25-MPE-251-1 PBI -MPE-25L1PB1
394.25
4.52
394.25
100
398.98
1.283 Centre Distance
Pass-
MPE-25-MPE-25LIPB1-MPE-25L1PB1
426.50
4.66
426.50
0.89
431.22
1.236 Clearance Factor
Pass -
MPE-25-MPE-25PB1-MPE-25PB1
394.25
4.52
394.25
0.89
398.98
1.244 Centre Distance
Pass -
MPE-25-MPE-25PB1-MPE-25PB1
426.50
4.66
426.50
0.76
431.22
1.201 Clearance Factor
Pass -
MPE-25 - MPE-25PB2 - MPE-25PB2
39425
4.52
394.25
190
398.98
1283 Centre Distance
Pass-
MPE-25-MPE-25PB2-MPE-25PB2
426.50
466
428.50
0.89
431.22
1.236 Clearance Factor
Pass -
MPE-25 - MPE-25PB3 - MPE-25PB3
394.25
4.52
39425
190
398.98
1.283 Centre Distance
Pass -
MPE-25 - MPE-25PB3 - MPE-25PB3
426.50
4.66
426.50
0.89
431.22
1.236 Clearance Factor
Pass-
MPE-26-MPE-26-MPE-26
197.73
65.12
197.73
62.87
203.03
28,970 Centre Distance
Pass -
MPE-26 - MPE-26 - MPE-26
376.50
65.86
376.50
62.22
381.45
18.130 Ellipse Separation
Pass -
MPE-2fi-MPE-26-MPE-26
651.50
77.77
651.50
72.00
654.94
13.461 Clearance Factor
Pass -
MPE-28 - MPE-28 - MPE-28
169.10
184.67
169.10
182.04
178.66
70.287 Centre Distance
Pass -
MPE-28 - MPE-28 - MPE-28
301.50
185.55
301.50
181.23
308.86
42.952 Ellipse Separation
Pass -
MPE-28 - MPE-28 - MPE-28
701.50
205.76
701.50
198.33
696.25
27.695 Clearance Factor
Pass-
MPE-29-MPE-29-MPE-29
612.41
119.71
612.41
114.36
624.24
22.345 Centre Distance
Pass -
MPE-29 - MPE-29 - MPE-29
626.50
119.76
626.50
114.29
638.16
21.876 Ellipse Separation
Pass -
14 May, 2019 - 15:28 Page 5 of 10 COMPASS
HALLIBURTON
Hilcorp Alaska, LLC
Milne Point
Anticollision Report for Plan: MPU E-42 - MPU E-42 wpO6
363.68
168.45
363.68
165.53
Closest Approach 30 Proximity Scan on Current Survey Data (North Reference)
57.752 Centre Distance
Pass -
MPE-30 - MPEdOA - MPE-30A
376.50
168.50
Reference Design: MPt E Pad - Plan: MPU E42 -MPU E42 -MPU E-42 wp06
165.49
387.11
55.891 Ellipse Separation
Pass -
MPE-30-MPE,3OA-MPE-30A
Scan Range: 26.50 to 0,100.00 usft. Measured Depth.
231.35
776.50
225.18
771.47
37.497 Clearance Factor
Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,500.00 usft
MPE-30-MPE-30AL1-MPE-30AL1
363.68
168.45
363.68
Measured Minimum
@Measured
Ellipse
@Measured
Clearance Summary Based on
376.50
Site Name Depth Distance
Depth
Separation
Depth
Factor Minimum
Separation Warning
Comparison Well Name - Wellbore Name - Design (usft) (usft)
(usft)
(usft)
usft
225.18
771.47
MPE-29 - MPE-29 - MPE-29 3,876.50 507.59
3,876.50
408.62
4,102.93
5.129 Clearance Factor
Pass -
MPE-29-MPE-29PB1-MPE-29PB1 612.41 119.71
612.41
114.36
624.24
22.344 Centre Distance
Pa" -
MPE-29-MPE-29PB1-MPE-29PB1 626.50 119.76
626.50
114.29
638.16
21.876 Ellipse Separation
Pass-
MPE-29-MPE-29PB1-MPE-29PB1 3,551.50 403.86
3,551.50
317.46
3,765.73
4.674 Clearance Factor
Pass -
MPE-30-MPE-30-MPE-30 363.68 168.45
363.68
165.53
374.65
57.753 Centre Distance
Pass -
MPE-30-MPE-30-MPEaO 376.50 168.50
376.50
165.49
387.11
55.892 Ellipse Separation
Pass -
MPE-30-MPE3O-MPE-30 776.50 23135
776.50
225.18
771.47
37.498 Clearance Factor
Pass -
MPEJO-MPE-30A-MPEJOA
363.68
168.45
363.68
165.53
374.65
57.752 Centre Distance
Pass -
MPE-30 - MPEdOA - MPE-30A
376.50
168.50
376.50
165.49
387.11
55.891 Ellipse Separation
Pass -
MPE-30-MPE,3OA-MPE-30A
776.50
231.35
776.50
225.18
771.47
37.497 Clearance Factor
Pass -
MPE-30-MPE-30AL1-MPE-30AL1
363.68
168.45
363.68
165.53
374.65
57353 Contra Distance
Pass -
MPE-30-MPEd0AL1-MPE-30AL1
376.50
168.50
376.50
165.49
387.11
55.892 Ellipse Separation
Pass-
MPE-30-MPE-30AL1-MPE-30AL1
776.50
231.35
776.50
225.18
771.47
37.498 Clearance Factor
Pass-
MPE-30-MPE-30AL1 PB1 -MPE-30AL1 Pal
363.68
168.45
363.68
165.53
374.65
57.752 Centre Distance
Pass -
MPE-30-MPE-30AL1 Pat -MPE-30AL1 Pal
376.50
168.50
376.50
165.49
387.11
55.891 Ellipse Separation
Pass-
MPE-30-MPE-WAL1 Pat -MPE-30ALlPBI
776.50
231.35
776.50
225.18
77147
37.497 Clearance Factor
Pass -
MPE-30-MPE-30APB1-MPE�OAPB1
363.68
16&45
363.68
165.53
374.65
57.752 Centre Distance
Pass -
MPE-30-MPE1OAPB1-MPE3OAPBi
376.50
168.50
376.50
165.49
387.11
55.891 Ellipse Separation
Pass -
MPE-30-MPE�OAPBi-MPE-30APB1
776.50
231.35
776.50
225.18
771.47
37.497 Clearance Factor
Pass -
MPU Edi -MPU E41 -MPU E41
448.17
263.91
448.17
260.00
446.77
67.523 Centre Distance
Pass -
MPU E41 -MPU Edi -MPU E-41
476.50
263.98
476.50
259.86
472.90
64.103 Ellipse Separation
Pass -
MPU Edi -MPU E-41 -MPU E-41
2,726.50
692.80
2,726.50
657.72
2,444.16
19.749 Clearance Factor
Pass -
MPU E41 -MPU E41 Pat -MPU E41 PB1
448.17
263.91
448.17
260.00
446.77
67.523 Centre Distance
Pass -
MPU E41 -MPU E41 P81 -MPU E41 PB1
476.50
263.98
476.50
259.86
472.90
64.103 Ellipse Separation
Pass -
MPU Edi -MPU E41 P81 -MPU E41 P01
2,726.50
692.80
2,72&50
657.72
2,444.16
19.745 Clearance Factor
Pass-
MPU E41 -MPU E41 PB2-MPU E41 PB2
448.17
263.91
448.17
260.00
446.77
67.523 Centre Distance
Pass -
MPU E41 -MPU E41PB2-MPU E41PB2
476.50
263.98
476.50
259.86
472.90
64.103 Ellipse Separation
Pass -
MPU E41 -MPU E41PB2-MPU E41PB2
2,726.50
692.80
2,726.50
657.72
2,444.16
19.745 Clearance Factor
Pass -
MPU E41 -MPU E41PB3-MPU E41PB3
448.17
263.91
448.17
260.00
446.77
67.523 Centre Distance
Pass -
MPU E41 -MPU E41PB3-MPU E41PB3
476.50
263.98
476.50
259.86
472.90
64.103 Ellipse Separation
Pass -
MPU E41 -MPU E41PB3-MPU E-41PB3
2,726.50
692.80
2,726.50
657.72
2,444.16
19.745 Clearance Factor
Pass -
14 May, 2019 - 1528 Page 6 o 10 COMPASS
I Hilcorp Alaska, LLC
HALLIBURTON Milne Point
Anticollision Report for Plan: MPU E-42 - MPU E-42 wp06
Closest Approach 3D Proximity Scan an Current Survey Data (North Reference)
Bp76S0
23.27
Reference Design: MPt EPad - Plan: MPU E -42 -MPU E -02 -MPU E42 xm06
21.36
8,074.52
Scan Range: 26.50 to 8,100.00 use. Measured Depth.
Pass -
Prelim DualLatPlan: MPU E-39 -MPU E -39i- MPU E-:
Scan Radius is Unlimited. Clearance Feet orcutoff is Unlimited. Max Ellipse Separation
is 1,500.00 usft
348.43
Measured Minimum
@Measured Ellipse
@Measured Clearance Summary Based on
Site Name Depth Distance
Depth Separation
Depth Factor Minimum Separation Warning
Comparison Well Name -Wellbore Name - Design (usft) (usft)
(usft) (usft)
usft
Plait MPU E42 -MPU E4211 - MPU E42L1 wp04
Bp76S0
23.27
8,076.50
21.36
8,074.52
12.217 Clearance Factor
Pass -
Prelim DualLatPlan: MPU E-39 -MPU E -39i- MPU E-:
348.43
235.20
348.43
231.79
349.33
68.828 Can" Distance
Pace -
Prelim DuallatPlan:MPU E -39 -MPU EJ9i-MPU E-:
376.50
235.29
376.50
231.66
375.33
64926 Ellipse Separation
Pass -
Prelim Duall-atPlan:MPU E -39 -MPU E -39i -MPU E-:
8,100.00
1,017.27
8,100.00
850.00
7,898.01
6.082 Clearance Factor
Pass -
Prelim: MPU E -Pad Expansion Placeholder- Wellbore
1,090.73
293.62
1,090.73
284.97
1,101.81
33.945 Centre Distance
Pass -
Prelim: MPU E -Pad Expansion Placeholder- Wellbore
1,101.50
293.66
1,101.50
284.96
1,111.36
33.762 Ellipse Separation
Pass -
Prelim MPU E -Pad Expansion Placeholder- Wellbore
1,326.50
317.40
1,326.50
307.29
1,301.63
31.404 Clearance Factor
Pass -
Rg: MPU E -38 -MPU E -38 -MPU EJ8
79.74
204.73
79.74
203.41
80.74
154.505 Centre Distance
Pass -
Rig: MPU EJ8 - MPU EJB - MPU E-38
101.50
204.75
101.50
203.26
100.00
137.738 Ellipse Separation
Pass -
Rig: MPU E38 -MPU E38 -MPU E-38
276.60
270.97
276.50
266.82
100.00
65.413 Clearance Factor
Pass -
Rig: MPUEJ8-MPU E -38 -MPU EJ8 wpO9a
531.90
203.73
531 AD
198.49
531.27
38.879 Centre Distance
Pass -
Rig: MPU E -38 -MPU E -38 -MPU E-38 wp09a
551.50
203.78
551.50
19BAl
550.00
37.982 Ellipse Separation
Pass -
Rig: MPU E38 -MPU E -38 -MPU EJ8 wpose
776.50
214.69
776.50
208.31
750.90
33.626 Clearer. Factor
Pass -
M Pt S Pad
From
To
Survey/Plan
Survey Tool
(usft)
(usft)
26.50
900.00
MPU E42 wp06
2_Gyro-NS-GC_Dnll collar
900.00
8,100.00
MPU E-02 wp06
2_MWD+IFR2+MS+Sag
8,100.00
11,949.71
MPU E42 wp06
2_MWD+IFR2+MS+Sag
14 May, 2019 - 15:28 Page 7 o 10 COMPASS
HALLIBURTON
Anticollision Report for Plan: MPU E-42 - MPU E-42 wp06
Ellipse error terms are or elaled across survey tool fie -on points.
Calwlated ellipses incorporate surface einem.
Separation is the actual distance between ellipsoids.
Distance Between centres is the straight line distance between wellbore centres.
Clearance Factor= Distance Between Profiles / (Distance Between Profiles - Ellipse Sepambom.
All station coordinates were calculated using the Minimum Curvature method.
Hilcorp Alaska, LLC
Milne Point
14 May, 2018 - 1528 Page 8 of to COMPASS
IIALLIBURTCN
Project Milne Paint
REFERENCE INFORMPTON
nEr/JLS:%¢n: MPIl FA3 N.N IVP MADCIINCONLSI wlaWa IDU
Site: MPt E Pad
e°°,oss M6lgmw .P6rc MMIP4x. rro. uo.n
No., Oellling
Well: Plan: MPU E-42
I.M.Oeussue MPI1H3As5bYeE qNB®e)YFM
^Mewee
Vi.µ es: wxw nze®ar=
GIN!Lu"I $O.fiO
a s .ol Nonmma F.rerms LuolooN l-'s,s,
Wellbore: MPU E-42
gwgr
" —le.
e914z49.99 So4111r3 rl1°tillluluN 11ry11ss 85
Plan: MPU E-42 wp08
sugvEV PaoGgnM NO GLOINL FILTER: Using user deflusa susuo oq 8 mNnrg crrie, a
mm
Dab: R01&10.16TW:00:00 4gMeletl: Ves VersMn'. 2650 To 11949.11
Ladder / S.F. Plots
Degm From Deol6 To SuI,#Flen Tem CASING DETAILS
SH(1 of 2)
26.50 BOO.W MPUE42 sryp6(MPU trot 2_AIGy NSGC Dill IN,
Sis N
90600 810000 MPU E42 spN6(MPU E42) 2WO+IFRZ+Ma+Sp D TVDMO N.
8100.W 1190.71 MPU E42"06(MPU EAU) 2MWD+IFg2-MS+sp 4319.13 421183 8100.00 9-518 95a'x121A.
4222.0 4175.30 119,19]1 4-10 412'a81rz'
100.00
c MPE-2 l
r
y150.00
p
i
i
MPE-2
G
S120,00
i
c MPE-2
r
MPE-t
@ MPE-1
VMPE-2P
i
M'MPE-2
`w 60.00
0
y MPE-0 I I MPU E<ZL1 9.404
311.00
-" —--- _ —
U MPE-1 MPE+10
MPE-25L
MPE-?&&
MPEQ5 0 425 850 1275 1100 2125 25M 2975 3400 3025 4250 4675 5100 M25 5950 6375 6000 7225 76M 0075
Measured Depth (850 usf Uin)
lT
00PNOERRR'Sk'
_
_3.Do0g
etlures
Reqso2.00e
Req.
1.00
Drilling
0.00
0 425 850 12>5 1700 2125 2550 2975 3400 3025 4250 4675 5100 5525 5950 6375 6800 7225 7650 8075
Measured Depth (850 usfUin)
Hilcorp Alaska, LLC
Milne Point
M Pt E Pad
Plan: MPU E-42
MPU E-42
MPU E-42 tyl
Sperry Drilling Services
Clearance Summary
Anticollision Report
14 May, 2019
Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)
Reference Design: MPt E Pad - Plan: MPU E42 -MPU E42 -MPU E42 wp06
Well Coordinates: 6,016,240.99 N, 569,137.33 E (70° 27 17.03" N, 149° 26' 08,90" W)
Datum Height: MPU E42 As Staked IRKS @ 47.30usff
Scan Range: 8,100.00 to 11,949.71 raft. Measured Depth.
Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited Max Ellipse Separation is 1,509.00 usff
Geodetic Scale Factor Applied
version: 5000.15 Solid: 91
Scan Type:
,
Scan Type: 25.00
HALLIBURTON
Sperry Orllling Services
HALLIBURTON
Anticollision Report for Plan: MPU E-42 - MPU E-42 wp06
Hilcorp Alaska, LLC
Milne Point
Closest Approach 3D Proximity Scan on Current Survey Data (North Reference)
8,990.92
Reference Design: M Pt E Pad - Plan: MPU Ed2-MPU E42 -MPU E42 1p06
8,990.92
Scan Range: 8,100.00 to 11,949.71 usft. Measured Depth.
10,550.00
Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation
Is 1,500.00 usft
Measured Minimum
Site Name
@Measured Ellipse ®Measured Clearance Summary based on
Depth Distance
Depth Separation Depth Factor Minimum Separation Warning
Comparison Well Name -Waltham Name - Design (usft (usft)
(usft) (usft) usft
EX KAVEAR32-25
Paw -
M Pt E Pad
MPE
8,100.00
-25-MPE-25-MPE-25
8,990.92
443.93
8,990.92
166.35
10,550.00
1.599 Centre Distance
Pass-
MPE-25-MPE-25-MPE-25
9,000.00
444.02
9,000.00
166.21
10,550.00
1.598 Clearance Factor
Paw -
MPE-25-MPE-25PB2-MPE-25PM
8,100.00
1,498.75
8,100.00
1,237.29
8,905.00
5.732 Clearance Factor
Pass -
Plan: MPU E32 -MPU Ei2L1-MPU E4211 wp04
8,100.00
2626
8,100.00
24.36
8,097.83
13.804 Ellipse Separation
Pass -
Plan: MPU E42 -MPU E4211 - MPU E4211 wp04
11,949.71
64.97
11,949.71
52.77
11,946.61
5.326 Clearance Factor
Pass -
Prelim Duall-atPlan: MPU E-39- MPU E -39i- MPU E-:
11,949.71
990.10
11,949.71
742.8
11,786.10
3.998 Clearance Factor
Pass -
M Pt 5 Pad
MPS -I9 -MPS -I9 -MPS -19
11,949.71
830.98
11,949.71
714.42
8,123.00
7.129 Clearance Factor
Pass -
MPS-I9-MPS-I9A-MPS-19A
11,949.71
71634
11,949.71
505.58
8,457.95
3.394 Clearance Factor
Pass -
MPS-I9-MPS-19AL1-MPS-19AL1
11,949.71
970.70
11,949.71
887.80
7,961.84
11.709 Clearance Factor
Pass -
MPS-I9-MPS-I9APB1-MPS-I9APB1
11,949.71
716.74
11,949.71
505.70
8,457.95
3.396 Clearance Factor
Pass-
SU DI program
From To
Survey/Plan
Survey Tool
(usft) (usft)
26.50 900.00
MPU E42 wp06
2_Gyro-NS-GG_Orill collar
900.00 8,100.00
MPU E42 wp06
2 MWD+IFR2+MS+Sag
8,100.00 11,949.71
MPU E-02 wp06
2_MWD+IFR2+MS+Sag
14 May, 2019 - 1529 Page 2 of 5
COMPASS
HALLIBURTON
Anticollision Report for Plan: MPU E-42 - MPU E-42 wp06
Ellipse error terms are comeefixf across survey tool fie -on points.
Calculated ellipses incorporate surface errors.
Separation is the actual distance between ellipsoids.
Distance Between centres is the straight line distance between wellbore centres.
Clearance Factor = Distance Between profiles / (Distance Between Profiles - Ellipse Separation).
All station coordinates were calculated using the Minimum Curvature method.
Hilcorp Alaska, LLC
Milne Point
14 May, 2019 - 15.29 Page 3 of 5 COMPASS
MALLIBURTON
Project: Milne Point( REFERENCE INFORAMT1.
nETPp.S'.PIav MPUE43 KAD 193]IN'ApCOY C0.W53 AIVFa2•mM
Site: MPtEPad —'eim'. INalw'— ruse Nou 11
ePeery eruuns
No aekee.m,.x 41
.an o lone No. NPU HxAs31NMX1(B® �]PW Or•uN le.el. 3080
Well: Plan: MPU E-42 wt.•"�e1 MsM ., Ms e.xA,4.wm aeMs . w„:nNonn;oa
®
se r ;,, 1.6��•a.
Wellbore: MPU E42 """'e0u1 "^BNOOI M"'""man'° npp I. 6p16�4p.99 s6vI'M ]m2Tl7ul.N Iw°u ss9sa
Plan: MPU E42 wp06
PROGRAM NO GLOBAL FILTER: Thing user corned aeleclon 0 fiMnlg colors
®
usUu`uEynnorw
oaM: 1018-t0I6T00Op:00 bliCaleE:Y Versbn: 00.50 To 119!9]1
Ladder/ S.F. Plots Oeplh Fnm CePN To ..... .n Tool CASING DETAILS
2830 900.00 MPU E92xrese(MPU Ei2) 2 GM-NaraL Diel"No
PH(2of2) ese00 919nM MPUE,12up0E(NAUE<2) 3_MWa-I 2iMsa5ap TMD TVD55 Mp Sia, Name
BUses 1194871 MPUEE42.0B(MFUE42j 2_MWetlFRNMs5a9 4319.13 4271.93 u0).00 9-5/8 95/8"x121]4"
423260 4175.30 11949]1 4JR 412"v 812"
180.00
P. 15o 00
c
.120 00
I
I
I
I
c
o
N
j
290.00
so
MPU
IIE421.1 so
30.00
'
so
so
I j
i`
0.00
8100 B325 8550
8]]5 900o 9225 9450 9675 9900 10125 10350 10575
10000 11025 11250 11475 11700 11925 12150 12375
Measured Depth (450 UsfUin)
4.00
3.00
_co
�
I
02,00
Collision Risk Procedures Req.
Collision Avoidance Req.
too
No -Go Zone -Stop Drilling I
NOERROR$I
o.00
( j
0100 8325 0550 8]]5 9000 9225 9450 9875 9900 10125 10350 10575 10800 11025 11 50111 7p0 11925 12150 12375
Measured Depth (450 USfUln)
Davies, Stephen F (CED)
From: Joe Engel <jengel@hilcorp.com>
Sent: Thursday, May 23, 2019 3:18 PM
To: Schwartz, Guy L (CED); Davies, Stephen F (CED)
Cc: Cody Dinger
Subject: HAK MPU E-42 (PTD: TBD) PTD Update
Attachments: MPU E Pad Cond 42 AS-Built.pdf; HAK MP E-42 wp06.xlsx
Guy/Steve —
Hilcorp submitted the PTD for E-42 yesterday. E-42 is a planned dual lateral (E-42 & E-421-1). The E-42 PTD submitted is
for all operations for the first lateral. We will be submitting the PTD for E -42L1 next week.
Regarding the E-42 PTD, we forgot to fill out information in one cell in the 10-401 form. Our apologies.
Box 15: Distance to nearest well open to same pool
1970' to E -24A
The program was submitted with the as -staked surface location. We have now received the as -built and it is attached.
Attached is the excel version of the E-42 wp06.
Please let me know if you have any questions.
Thank you for your time.
-Joe
Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC
3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503
Office: 907.777.8395 1 Cell: 805.235.6265
The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this
communication maybe legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review,
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While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission,
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the recipient should carry out such virus and other checks as it considers appropriate.
NOTES,
I. ALASKA STATE PLANE COORDINATES ARE ZONE 4, NAD27.
2 BASS OF LOCATION IS MONUMENTS CFP -3 AND E-1.
3. BASIS OF ELEVATION MILNE POINT DATUM MSL
4. GEODETIC POSITIONS ARE NAD27.
S PAD MEAN SCALE FACTOR IS 0.9999054
6. SURVEY DATE MAY 16, 2019.
7. REFERENCE RED BOOK: HC19-03 PGs 20-21.
SURVEYOR'S CERTIFICATE
I HEREBY CERTIFY THAT I AM
PROPERLY REGISTERED AND LICENSED
TO PRACTICE LAND SURVEYING IN
THE STATE OF ALASKA AND THAT
THIS AS -BUILT REPRESENTS A SURVEY
MADE BY ME OR UNDER MY DIRECT
SUPERVISION AND THAT ALL
DIMENSIONS AND OTHER DETAILS ARE
CORRECT AS OF MAY 18, 2019.
LOCATED WITHIN PROTRACTFn SFC 95 T 1i M IZ to r 13I.AT urminiAAi
WELL
A.S.P.
PLANT
l
A -PAD
SECTION
PAD
CELLAR
N0.
COORDINATES
COORDINATES
POSITION(DMS)
POSITION(D.DD)
OFFSETS
3■
11111
II
I
-
.CI
70'27'17.033"
1 70.4547314'
3,704'FSL
.HiD
—
E= 1 292.46'
149'26'08.887"
■ 33
2 007' FEL
C
�
■ 2
I
e
27 ■
■ 32
■ 31
I
1
28 ■
■ 4
a p
22 ■
■ 1
v
291 ■
I
6
a
3 ■
■ 5
TH3
PROXCT
26 ■
■ 30
—N—
9 ■
■ 6
E— 42
■ 21
I
n
■ 7
VICINITY MAP
MPU E -PAD
18 ■
■ 16
N.T.S.
20 ■
■ 23
24 ■
■ 19
14
12
15 ■
'117
38 ■
■ 37
a9
�5
I
O F A 4'
3536
�P\�
400
im�5thyrF;arm;nh�(
— —
—
ic'•
10
GRAPHIC SCALE
0 100
LEGEND
•J,
200
400
�- AS -BUILT CONDUCTOR
IONP�
( IN FEET)
■ EXISTING CONDUCTOR
1 Inch - 200 k.
NOTES,
I. ALASKA STATE PLANE COORDINATES ARE ZONE 4, NAD27.
2 BASS OF LOCATION IS MONUMENTS CFP -3 AND E-1.
3. BASIS OF ELEVATION MILNE POINT DATUM MSL
4. GEODETIC POSITIONS ARE NAD27.
S PAD MEAN SCALE FACTOR IS 0.9999054
6. SURVEY DATE MAY 16, 2019.
7. REFERENCE RED BOOK: HC19-03 PGs 20-21.
SURVEYOR'S CERTIFICATE
I HEREBY CERTIFY THAT I AM
PROPERLY REGISTERED AND LICENSED
TO PRACTICE LAND SURVEYING IN
THE STATE OF ALASKA AND THAT
THIS AS -BUILT REPRESENTS A SURVEY
MADE BY ME OR UNDER MY DIRECT
SUPERVISION AND THAT ALL
DIMENSIONS AND OTHER DETAILS ARE
CORRECT AS OF MAY 18, 2019.
LOCATED WITHIN PROTRACTFn SFC 95 T 1i M IZ to r 13I.AT urminiAAi
WELL
A.S.P.
PLANT
GEODETIC
GEODETIC
SECTION
PAD
CELLAR
N0.
COORDINATES
COORDINATES
POSITION(DMS)
POSITION(D.DD)
OFFSETS
ELEVATIONJ
BOX ELEV.
E_42
Y=6,016,241.23'
N=2,094.89'
70'27'17.033"
1 70.4547314'
3,704'FSL
X= 569.137.72
E= 1 292.46'
149'26'08.887"
149.4358019'
2 007' FEL
rc R-2W
ecorp �$$MPU E PAD AS -BUILT CONDUCTOR
A
DALE ..,,",.Tao�o�WELL E-42 1 t
I
GRID
TRANSMITTAL LETTER
/CHECKLIST
WELL NAME:
PTD:
Development _ Service _ Exploratory _ Stratigraphic Test Non -Conventional
FIELD: µ'�! �<l ¢ POOL:�� (�
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK
OPTIONS
TEXT FOR APPROVAL LETTER
MULTI
The permit is for a new wellbore segment of existing well Permit
LATERAL
(If last two digits
No. API No. 50-
Production should continue to be reported as a function of the original
in API number are
API number stated above.
between 60-69
In accordance with 20 AAC 25.005(f), all records, data and logs
acquired for the pilot hole must be clearly differentiated in both well
Pilot Hole
name ( PH) and API number (50-_
_) from records, data and logs acquired for well
name on emit .
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce/inject is contingent upon issuance of a conservation
Spacing Exception
order approving a spacing exception. (Comnanv Name) Operator
assumes the liability of any protest to the spacing exception that may
occur.
All dry ditch sample sets submitted to the AOGCC must be in no greater
Dry Ditch Sample
than 30' sample intervals from below the permafrost or from where
mLn les are first caw ht and 10' sample intervals through tar et zones.
Please note the following special condition of this permit:
production or production testing of coal bed methane is not allowed for
Non -Conventional
(name of weld until after (Company -Name has designed and
Well
implemented a water well testing program to provide baseline data on
water quality and quantity. (Company Name) must contact the AOGCC
to obtain advance approval of such water well testing progam.
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
(Company Name) in the attached application, the following well logs are
also required for this well:
Well Logging
Requirements
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for well logs run must be submitted to the AOGCC
within 90 days after completion, suspension or abandonment of this well.
Revised 2/2015
WELL PERMIT CHECKLIST Field & Pool MILNE POINT, SCHRADER BLFF OIL - 525140
Well Name: MILNE PT UNIT E-42 Program DEN _ .__ _ Well bore seg ❑
PTD#:2190820 Company HILCORPAL6SK4kJLC Initial Class/Type
DEV / PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal ❑
Administration
1
Permit fee attached ...... _ _ _ _ _ _ _ _
NA...
S( 3l1
2
Lease number appropriate_ _ _ _ _ _ _ _ _ _ .......... . . . _ _ _ _ _ _ _ _ ..
Yes
_ Surf Loc &_Top Prod Int lie in ADL0025518; TO lies in ADLO380110._
3
Unique well. name and number - - - - - - - - - - - - - - - - - -
Yes
4
Well located in a defined pool _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Yes
_ _ Milne Point Schrader Bluff Oil Pool (525140), governed by CO 477, amended by CO 477.05,
5
Well located proper distance from drilling unit boundary_____ _ _ _ _ _ _ _ _ _ _ _
Yes
CO 477.05 specifies:. "There are no restrictions as to well spacing except that no pay shall
6
Well located proper distance from other wells _ ..........
Yes
be opened in a well closer than. 500 feet from the exterior boundary of the affected area."_
7
Sufficient acreage available in drilling unit _ _ _ _ _ _ . _ ......
Yes
As planned, well conforms to spacing requirements
8
If deviated, is wellbore plat. included _ _ _ _ _ ..
Yes
9
Operator only affected party........ ..............................
Yes
_.._._______..__......__....._..__...... _____._.. __...._____.
10
Operator has. appropriate bond in force _ _ _ _ _ _ _ _ _ _ _ _ _ _
Yes
11
Permit can be issued without conservation order_ _ _ _ _ _ _ _ _ _ _
YeS
Appr Date
12
Permit can be issued without administrative approval _ _ _ _ _ _ _ _ _ _ _ _
Yes
13
Can permit be approved before 15-day wait......... ....
Yes
SFD 5/23/2019
14
Well located within area and strata authorized by Injection Order# (put. IO# in comments) (For.
NA
15
All wells. within 1/4. mile area of review identified (For service well only) ...........
NA
............. ............. _ _ _ _ _ _ _ _ _ _
16
Pre-produced injector; duration of pre-production less than 3 months (For service well only) _ _
NA_
17
Nonconven, gas conforms to AS31,05.030&-l-A).(L2.A-D) _ _ _ _ - - - _ _ _ _ _
NA
18
Conductor string.provided........................................
Yes
20" conductor set at 10717t
Engineering
19
Surface casing. protects all known USDWa _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
NA..
20
CMT. vol. adequate to circulate on conductor & surf csg ......................
Yes .
9 5/8". surface casing will use ES, 2 stagejob. ES. at 2500 R,
21
CMT vol adequateto tie-in long string to surf cs9 - - - - - - - - - - - - - - - - - - - - - - - - - - -
No
22
CMT_will cover all known productive horizons _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Yes _
_ Slotted liner will. be using in the 8.5in Lateral section.
23
Casing designs adequate for C. T. B A, permafrost ... .........
Yes
24
Adequate tankage, or reserve pit _ .. _ _ _ _ _ _ _ _ _ _
Yes
_ _ Rig has steel pits..
25
If a_re-drill, has_a 10-403 for abandonment been approved . . ......... . ....... .
NA.
26
Adequate wellbore separation proposed _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Yes _
_ _ _ no issues
27
Ifdiverterrequired,doesitrrteetregulations_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Yes_
_ Diverter layout provided... drilling surface_ hole.to top OAwith diverter..
Appr Date
28
Drilling fluid, program schematic & equip list adequate.... ..... . ........ .....
Yes
Max form pressure =_1900 psi ( 8.7 ppg. EMW) will drill with 8.9-9.5 ppg mud and MPD system.
GLS 5/31/2019
29
BOPEs,. do they meet regulation _ _ ..... . . ....... . . ..............
Yes .
_ _ Innovation has 11"5000_PSI DOPE......... ..... _ ...... _
30
DOPE press rating appropriate; test to _(put psig in comments)... _ _ _ _ ...... _
Yes _
_ _ MASP= 1400 PSI. Test DOPE to 3000 psi
31
Choke manifold complies w/API_RP-53 (May 84)_ _ _ _ _ _ _ _ _ .. _ _ _
YeS
32
Work will occur without operation shutdown. .... _ _ _ _ _ _ _ _ _ _
Yes _
_ _ _ OA lateral will be drilled under separate PTD.
33
Is presence. of H2S gas probable------------- - - - - - - - - - - - - - - - - - - - - - - -
NO...
34
Mechanical condition of wells within.4,019t verified (For. service well only) _
NA
_ . ..................... .
35
Permit can be issued w/o hydrogen sulfide measures .... . .... . . . . . . . . . . . ..
Yes ..
_ H2S not anticipated from drilling of offset wells; however, rig will have H26 sensors and alarms._
Geology
36
..
Data. presented on potential overpressure zones....... ........... .....
Yes .......
Gas hydrates expected at. base permafrost; mitigation discussed in Drilling Hazards_ section. _
Appr Date
37
Seismic analysis of shallow gas zones_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
NA _
_ Abnormal pressures have been encountered_ onE-Pad; will be managed using. Managed. Pressure
SFD 5/23/2019
38
Seabed condition survey (if off-shore) . . . .................... . .
NA..
. Drilling Technique. One fault will be crossed while drilling this well.......
39
Contact name/phone for weeklyprogressreports_ [exploratory only] _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
NA
Geologic
Engineering
Public Will be dual lateral in OB and OA sand. Additional PTD required for OA lateral ESP completion. Using MPD for pressure
Commissioner:
Date:
Commissioner:
Date Date
Commissioner anomolies on E -Pad. GIs.
►�iS
S( 3l1
b jSO -1
