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HomeMy WebLinkAbout221-018DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20072-60-00Well Name/No. GRANITE PT ST 31-23L1Completion Status1-OILCompletion Date7/4/2021Permit to Drill2210180Operator Hilcorp Alaska, LLCMD11096TVD9804Current Status1-OIL9/30/2021UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:MWD / GR / RESNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF8/18/202110138 11097 Electronic Data Set, Filename: GP 31-23L1 GAMMA RES.las35512EDDigital DataDF8/18/2021 Electronic File: GP 31-23L1 2MD Final Log.cgm35512EDDigital DataDF8/18/2021 Electronic File: GP 31-23L1 2TVDSS Final Log.cgm35512EDDigital DataDF8/18/2021 Electronic File: GP 31-23L1 5MD Final Log.cgm35512EDDigital DataDF8/18/2021 Electronic File: GP 31-23L1 5TVDSS Final Log.cgm35512EDDigital DataDF8/18/2021 Electronic File: GP 31-23L1 Coman Final Log.cgm35512EDDigital DataDF8/18/2021 Electronic File: GP 31-23L1 GAMMA RES.ASC35512EDDigital DataDF8/18/2021 Electronic File: GP 31-23L1 2MD Final Log.PDF35512EDDigital DataDF8/18/2021 Electronic File: GP 31-23L1 2TVDSS Final Log.PDF35512EDDigital DataDF8/18/2021 Electronic File: GP 31-23L1 5MD Final Log.PDF35512EDDigital DataDF8/18/2021 Electronic File: GP 31-23L1 5TVDSS Final Log.PDF35512EDDigital DataDF8/18/2021 Electronic File: GP 31-23L1 Coman Final Log.PDF35512EDDigital DataDF8/18/2021 Electronic File: GP_31-23L1 Definitive Surveys.pdf35512EDDigital DataDF8/18/2021 Electronic File: GP_31-23L1 Definitive Surveys.xlsx35512EDDigital DataDF8/18/2021 Electronic File: GP 31-23L1 2MD Final Log.tif35512EDDigital DataThursday, September 30, 2021AOGCCPage 1 of 2GP 31-23L1 GAMMA RES.las
DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-733-20072-60-00Well Name/No. GRANITE PT ST 31-23L1Completion Status1-OILCompletion Date7/4/2021Permit to Drill2210180Operator Hilcorp Alaska, LLCMD11096TVD9804Current Status1-OIL9/30/2021UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:7/4/2021Release Date:6/9/2021DF8/18/2021 Electronic File: GP 31-23L1 2TVDSS Final Log.tif35512EDDigital DataDF8/18/2021 Electronic File: GP 31-23L1 5MD Final Log.tif35512EDDigital DataDF8/18/2021 Electronic File: GP 31-23L1 5TVDSS Final Log.tif35512EDDigital Data0 0 2210180 GRANITE PT ST 31-23L1 LOG HEADERS35512LogLog Header ScansThursday, September 30, 2021AOGCCPage 2 of 2M. Guhl9/30/2021
1a. Well Status:Oil SPLUG Other Abandoned Suspended
1b. Well Class:
20AAC 25.105 20AAC 25.110 Development Exploratory
GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test
2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry:
Aband.:
3. Address: 7. Date Spudded: 15. API Number:
4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number:
Surface:
Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s):
GL: N/A BF:
Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation:
4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number:
Surface: x- y- Zone- 4
TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD:
Total Depth: x- y- Zone- 4
5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD:
Submit electronic information per 20 AAC 25.050 (ft MSL)
22.Logs Obtained:
23.
BOTTOM
18" B 603'
13-3/8" J-55 3,665'
9-5/8"N-80/S-95 7,287'
7" N-80 9,758'
24. Open to production or injection? Yes No 25.
26.
Was hydraulic fracturing used during completion? Yes No
DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED
27.
Date First Production: Method of Operation (Flowing, gas lift, etc.):
Hours Tested: Production for Gas-MCF:
Test Period
Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr):
Press. 24-Hour Rate
7/1/2021
6/23/2021
ADL 018761
19-001
N/A
11,027' / 9,758'75
319' / 319'
11,096' / 9,804'
MWD / GR / RES
Sr Res EngSr Pet GeoSr Pet Eng
Oil-Bbl: Water-Bbl:
Oil-Bbl:
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
N/A
11,027' - 11,096' 9,758' - 9,804'
Fish (BHA)
Water-Bbl:
PRODUCTION TEST
Not on Production
Date of Test:
Flow Tubing
70.59#
61#
604'
Surface 8,062'
Gas-Oil Ratio:Choke Size:
11,028'
Per 20 AAC 25.283 (i)(2) attach electronic information
40# / 43.5#
11,027'
Surface
7,117'
DEPTH SET (MD)
9,799' / 8,742'
PACKER SET (MD/TVD)
Surface
CASING WT. PER
FT.GRADE
29#
259926
259881
TOP
SETTING DEPTH MD
Surface
SETTING DEPTH TVD
2541172
BOTTOM TOP
12-1/4"
Surface
16"
HOLE SIZE AMOUNT
PULLED
50-733-20072-60-00
GP 31-23 L1
263287 2544567
519' FNL, 2041' FEL, Sec. 23, T10N, R12W, SM, AK
CEMENTING RECORD
2541202
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
7/4/2021
2365' FNL, 1253' FWL, Sec. 13, T10N, R12W, SM, AK
549' FNL, 2085' FEL, Sec. 23, T10N, R12W, SM, AK
221-018
Granite Point Field / Middle Kenai Oil Pool
105.0'
11,096' / 9,804'
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
WELL COMPLETION OR RECOMPLETION REPORT AND LOG
Hilcorp Alaska, LLC
WAG
Gas
22"
Surface 3,933' 2435 sx Class 'G'
670 sx Class 'G'
800 sx Class 'G'
7,867'
10,199'4-1/2" 12.6# L-80
SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation
Size and Number; Date Perfd):
ACID, FRACTURE, CEMENT SQUEEZE, ETC.
CASING, LINER AND CEMENTING RECORD
List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion,
1182 sx Class 'G'8-1/2"
TUBING RECORD
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
By Samantha Carlisle at 3:39 pm, Aug 18, 2021
RBDMS HEW 8/19/2021
Completion Date
7/4/2021
HEW
GBJM 9/29/21 SFD 8/23/2021 DSR-8/23/21
Conventional Core(s): Yes No Sidewall Cores:
30.
MD TVD
Top of Productive Interval 11017' 9750'
11017' 9750'
11027' 9758'
Tyonek C7 11017' 9750'
31. List of Attachments:
32. I hereby certify that the foregoing is true and correct to the best of my knowledge.
Contact Name: Cody Dinger
Contact Email:cdinger@hilcorp.com
Authorized Contact Phone: 777-8389
General:
Item 1a:
Item 1b:
Item 4b:
Item 9:
Item 15:
Item 19:
Item 20:
Item 22:
Item 23:
Item 24:
Item 27:
Item 28:
Item 30:
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.
Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29.
Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool.
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
producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,
showing the data pertinent to such interval).
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.
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.
The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00).
Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain).
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.
Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion,
suspension, or abandonment, whichever occurs first.
Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection,
Observation, or Other.
Formation at total depth:
Kicked off from Parent Well
Drilling Reports, Definitive Directional Survey, Wellbore Schematic
Signature w/Date:
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.
INSTRUCTIONS
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.
TPI (Top of Producing Interval).
Yes No
Well tested? Yes No
28. CORE DATA
If yes, list intervals and formations tested, briefly summarizing test results.
Attach separate pages to this form, if needed, and submit detailed test
information, including reports, per 20 AAC 25.071.
NAME
(GP 31-23)
Tyonek C7
This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram
with each 10-407 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.
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.
If Yes, list formations and intervals cored (MD/TVD, From/To), 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.
Authorized Name: Monty Myers
Authorized Title: Drilling Manager
Permafrost - Base
29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS
Permafrost - Top
Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment
8.18.2021
Digitally signed by Monty M Myers
DN: cn=Monty M Myers, c=US,
o=Hilcorp Alaska, LLC, ou=Technical
Services - AK Drilling,
email=mmyers@hilcorp.com
Reason: I am approving this document
Date: 2021.08.18 15:09:42 -08'00'
Monty M
Myers
_____________________________________________________________________________________
Revised By: JNL 8/11/21
SCHEMATIC Granite Point Platform
Well No: GP 31-23 / L1 / L2
Completed: 04/29/21
GP 31-23L2
TD = 10,469’ MD / 9,249’ TVD
PBTD = 10,469’ MD / 9,249’ TVD
GP 31-23L1
TD = 11,096’ MD / 9,804’ TVD
PBTD = 11,096’ MD / 9,804’ TVD
ADL: 18761 PTD: 167-084 / 221-018 / 221-020 API: 50-733-20072-00 / -60-00 / -62-00
CASING DETAIL
Size Wt Grade Conn ID Top Bottom
18" 70.59 B Surf. 604’
13-3/8" 61 J-55 DV Tool 12.515” Surf. 2,230’
13-3/8” 61 J-55 Buttress 12.515” 2,230’ 3,933’
9-5/8"
40 N-80 Buttress 8.835” Surf. 295’
40 N-80 LTC 8.835” 295’ 3,801’
43.5 N-80 LTC 8.755 3,801’ 5,173’
43.5 S-95 STC 8.755 5,173’ 8,062’
7" 29 P-110 X-line 6.184” 7,867’ 11,196’
TUBING DETAIL
4-1/2" 12.6 L-80 IBT 3.833 Surf. 9,783’
4-1/2" 12.6 L-80 IBT 3.833 9,799’ 10,199’
Jewelry Detail
#Depth
(MD)
Depth
(TVD)ID OD Item
1 319’ 319’ 3.813 5.960 TRSV, NE-SLIM (Halliburton)
2
2,604’ 2,509’ 3.958” 7.000” GLV #1 – IPO-15
4,784’ 4,416’ 3.958” 7.000” GLV #2 – IPO-15
6,364’ 5,800’ 3.958” 7.000” GLV #3 – IPO-15
7,384’ 6,687’ 3.958” 7.000” GLV #4 – IPO-15
8,203’ 7,408’ 3.958” 6.000” GLV #5 – IPOC-1
8,926’ 8,006’ 3.958” 6.000” GLV #6 – IPO-1
9,644’ 8,612’ 3.958” 6.000” GLV - Orifice
3 9,783’ 8,729’ 4.000” 6.000” 15' 5.000 PBR w/ 4 1/2 LTC Pin
9,799’ 8,742’ 4.000” 5.870” 7 x 4 1/2" 23-32# Hydraulic Isolation Packer
4 9,873’ 8,805’ 3.810” 5.820” X Nipple
5 9,886’ 8,816’ 3.810” 5.500” Sliding Sleeve (Open Up)
6 10,199’ 9,078’ 3.960” 5.170” WLEG
7 10,361’ 9,204’ FISH (BHA)
8 11,028’ 9,759’ FISH (BHA)
Perforations
Top(MD) Btm(MD) Top(TVD) Btm(TVD) Detail
9,860’ 9,861’ 8,794’ 8,795’ Squeezed
9,866’ 9,867 ‘ 8,799’ 8,800’ Water Shut Off
9,911’ 9,921’ 8,837’ 8,846’ Open
9,941’ 9,971’ 8,863’ 8,888’ Open
10,100’ 10,101’ 8,996’ 8,997’ Squeezed
10,254’ 10,260’ 9,124’ 9,129’ Open
10,260’ 10,275’ 9,129’ 9,142’ Open
10,275’ 10,280’ 9,142’ 9,146’ Open
10,280’ 10,445’ 9,146’ 9,281’ Open
10,561’ 10,578’ 9,376’ 9,390’ Open
10,654’ 10,681’ 9,452’ 9,474’ Open
10,730’ 10,731’ 9,515’ 9,515’ Squeezed
10,895’ 10,897’ 9,650’ 9,651’ Open
10,897’ 10,987’ 9,651’ 9,725’ Open
11,014’ 11,016’ 9,747’ 9,749’ Open
11,016’ 11,176’ 9,749’ 9,878’ Open
10,283’ 10,469’ 9,149’ 9,249’ Open Hole (L2)
11,027’ 11,096’ 9,758’ 9,804’ Open Hole (L1)
KB: 105’ MWL
PBTD = 11,147’ TD = 11,200’
5
18”
2
3
4
Top of whipstock
(L1) 11,021’
Top of whipstock
(L2) 10,283’
9-5/8”
6
7
8
1
13-3/8”
7”
CBL 4/25/21
EST TOC
6,740’
Clean out
to 11,094’
04/25/21
TOL 7,867’
Activity Date Ops Summary
6/8/2021 MIRU. NU 3' and 4' shooting flange on top of annular. RU 2" MPD line to annulus valve. Modify stair case for CT ops cab. Weld and secure injector stand in
preparation for stabbing coil. Start and commission CT power pack. Modify hatch cover for MPD line. Install stack on PFMS MGS.
6/9/2021 Install tee and 1502 low torque to choke manifold. Install annular secondary control valve and hoses. Install well head transducer and purged hydraulic line. Begin
setting up Pason system. Roll and inspect coiled tubing injector chains. Run Pason control lines. RU reverse circulating lines.
6/10/2021 Installed pack off assembly. Plumb stack. Reposition jacking frame 7" to center up with stack. Roll kill line HCR to clear jacking frame. Pasan continue installing
EDR. Quadco installed gas detection system and tested. Modify injector stand. Dress end of coil and install clamps. Prep to stab coil. Attempt to secure coil in reel
horse head. Rollers and pivot pin were bound and locked. Secure coil. Fill out permit to work, confined space, hot work and LOTO with operations team. Remove
all scale, debris and residual fluid from pits. Straighten reverse circulating line. Complete pit cleaning. Service and oil horses head with AeroKroil. Work adjusting
screw and rollers free. Install SRL Jib on level wind platform. Install hand rails.
6/11/2021 Install Pason PVT system. Set up coil data acquisition system. Terminate eline in reel collector. Remove and rebuild leaking injector traction cylinder. Merika out
to measure for installation of pit and PFMS cover system. Install pressure bulkhead. MEG eline and found eline and collector good. Test replaced traction cylinder.
Install inner reel valve and iron. Load pits 4,5,6 with 80 bbls of FIW to test. Found leaking flange and nipple externally and repair. Found seized valves and valve
handles internally in tank. Work on repairing.
6/12/2021 MEG e-line circuit after collector and pressure bulkhead. Finish installation of inner reel iron. Swap pop offs on test pump. Continue working on replacing 10"
butterfly valves on KWF pit system. Continue working on PVT system. MU Kendall 2 3/8" coil connector. Troubles shoot CTU power pack. Find bad alternator. Pull
test connector to 50k and test plate failed. Complete swapping out 10" butterfly valves in KWF pit system. Repair misc leaks on pit system. Fabricate new valve
handles for pit system.
6/13/2021 Repair coiled tubing test plate and pull test injector to 80k without any issue. Cut coil and install CTC. Pull test to 44k. MU UQC without floats. Continue work on
repairs in pit 4, 5, and 6. Install slip blind below 4 1/16" adapter flange. Continue repairs on KWF pits system. Install injector drain hose.
6/14/2021 Install studs and slip blinds below 4 1/16" adapter flange. Replace isolation valves on KWF tank. Swap out risers for lubricator. Re-install inspected hard line Fill
KWF fluid tank and PFMS shaker skid with Filtered Inlet Water. Fix leaking flange. Function both mud pumps and unable to disengage pumps. Repair leak in flow
box gap on PFMS.
6/15/2021 Fluid pack PFMS. Re-seal around shaker boxes. Troubleshoot and repair misc. small leaks. Fluid pack surface lines and coiled tubing. Re-position guard on mud
pump #1 drive line. Run and function test mud pump #1 without any issue. Run and function test mud pump #2 and find pump press not reading correctly.
Continue pressure testing operations and fluid pack MGS. Shell test BOPE and choke skid. Repair multiple leaks.
6/16/2021 Circulate through all flow paths and verify both in and out Micro Motion flow and density correct. Circulate with both mud pumps and confirm operation. Continue
testing BOP stack and iron. Fix leaks. Pressure test eline bulkhead 3 times and fail every time. Test riser and Master valve to 5k. Function test SSV. Weld leaking
trough in shaker skid. Continue working on Nordic rig acceptance check list.
6/17/2021 Continue welding leaking shaker trough. Install hose over discharge into PFMS. Label all valves in choke and PFMS manifold. MU and cut 2 3/8" test joint to length.
PT each individual BOP ram to 250/5000 - pass. PT Annular to 250/3500 - pass Install new alternator in CTU power pack. Install new pressure bulkhead and PT.
Fail at 2300 psi. PT SSV to 4000 psi - pass. Install chain and pack-off lube system on injector.
6/18/2021 Inspect, service and PT TIW valves to 5k. One pass one fail. Function test pack off lube system. Install QTS fittings and test. Level jacking frame and install storage
pins. MU pressure bulkhead and PT to 4500 psi. Pass PT pressure bulkhead to 5k. Pass. Terminate eline from junction box to reel collector. Test and good test.
Install injector tarps. RU control line and manifold for SSSV. Replace leaking ball valve on MGS drain. Clean and organize deck area.
6/19/2021 MU pressure bulkhead. PT to 4500 psi. Pass. Isolate MM and test bulkhead and IRV to 5k. Pass. Terminated eline to into collector and test. Good. Install injector
tarps. Installed controls for SSV and SSSV on jacking frame. Finished labeling valves. Built and installed air manifold to feed PRT and Swaco controls. MU BHI
blow down equipment to service tools. Ran both mud pumps and control boxes with crews. Calibrate Pason PVT system. Begin inventory of subs and crossovers.
6/20/2021 Continue prepping for BOPE test. AOGCC Inspector Adam Earl arrived for for inspection. Walked through rig up. Perform gas alarm test with Quadco and Inspector
Initial BOPE test. Shell test 250# Low / 5000# High. Drip coming from Annular flange on high. Floor Valve #1 Fail, Needs to be replaced. Bleed down and tighten.
Close Floor Valve #2. Retest Passed. Test:#1 Kill line Valve, CM10, CM. Complete BOPE test with AOGCC Inspector Earl Adams. No issues. Remove blind flange.
MU and test BHA #1 Nozzle and stinger. Test break to 4k. Test BHI check valves to 4k. Test SSV to 3300 psi and chart per state request. Open SSV and install
fusable cap. Open Master Valve. RIH with BHA #1. Calibrate coil tubing counters.
6/21/2021 RIH to 1800' without any returns. Counters suspect. Pooh and inspect pipe. Close master valve Circulate slack forward at 2.5 bpm. Circulate full volume.
Rih to 6000' before getting returns. Continue to a hard tag All three counters reading something different. 11160' Mechanical, 10686' Orion, 10923' BHI
Pick off bottom. Assuming this is the previous cleanout depth. Break circulation. Circulate diesel out to PFMS and pumping to platform cleanout tank. Foamy diesel
coming back. Pinch choke in. Finish bottoms up. Increase rate to 3.0 bpm. Circulate one bottoms up. Perform extended flow check while pumping remaining
diesel to production. Well Static Fill hole 5 bph loss rate. Break circulation. In Rate: 1.14 bpm, Out Rate: 0.66 bpm. MW in: 8.49 ppg , MW out: 8.43 ppg.
Circulating pressure: 422 psi. POOH OOH. Service CTU powerpack. Troubleshoot Orion acquisition system. Depth not reading in CT U. Install scaffolding/working
deck on jacking frame for BHA changeout. LD Nozzle and stinger BHA. MU 4 1/2" x 7" Baker Gen II Whipstock w/BHI Coiltrack BHA. MU QTS and PT. Install
fusable cap RIH with 4 1/2" x 7" Baker Gen II Whipstock w/BHI Coiltrack BHA.
6/23/2021Spud Date:
Well Name:
Field:
County/State:
GPF GP 31-23L1 & L2
Granite Point Field
Hilcorp Energy Company Composite Report
, AK
Complete BOPE test with AOGCC Inspector Earl Adams.
AOGCC Inspector Adam Earl arrived for for inspection.
Test SSV to 3300 psi and chart per state request.
6/22/2021 Continue in hole with whipstock Log GR log from 10100' to 11019' MD. One wrap from tag. Correlate logs with town and on site Geo. Correct depth with +33.5'
correction. PUH to 10160' MD (10090' CCL depth) Log CCL to 11052.69' MD (10982.69' CCL Depth). Discuss logs with Geology and engineer Put whipstock on
depth of 11041' MD (11023' TOWS, 10° LOHS). Pick up just under breakover. Close EDC. Pressure up to 2495# Observe WOB increase to 4.5K. and sheared
out. Stack 4.5K on whipstock. Good set. Pick off whiptock clean. Circulate bottoms up POOH OOH. PJSM. Remove fusable cap. Break QTS and slide injector
back LD Whipstock setting tool. MU BHA #3 Baker window milling BHA with 3.80" window mill and 3.79" string reamer. RIH to 10000' ctmd and get RIH speeds
and parameters for driller. Continue to tie in depth of 10900' Log tie in from 10900'. Correct +25.5' Tag pinchpoint of whipstock @ 11027.5'. PUH and establish
milling parameters at 2.8 bpm viscosified sea water and 2149 psi circ pressure. RIH and begin time milling at .1 ft/6 min. at 11026.2 MD.
6/23/2021 Continue milling window. Free Spin: 2.82 bpm @2300 psi. Rate in: 2.82 bpm in, Rate out: 2.82 bpm . MW in: 8.58 ppg, MW out 8.43 ppg Mill window from
11026.2' to 11032.7'. Confirmed formation sand in 11033' bottoms up sample. Mill rathole from 11032.7' to 11042.7'. Ream window at drilled and 15 deg L/R of
drilled. Dry drift to TD of 11043' MD without issue POOH keeping hole full OOH - Secure well. Crane unable to perform BHA swap due to high winds. Perform
routine maintenance on equipment. Send 50 bbls of milling fluid to platform well clean out tank for disposal. Stop transfer due to high level alarm. Operations
currently troubleshooting.
6/24/2021 Chugger Viscosified FIW returns to production for injection. Run cables for MPD chokes. Work on getting operational. Assist Merika with pit enclosure. Evacuate
Drilling tanks of water. Covering is in place. LD Window milling BHA. MU Build Section Drilling BHA. Transfer 7.4 ppg OBM system to pits 9 and 10. Work Boat
with mud system and chemicals. Offload empty ISO containers. Load 2, 120 bbl ISO tanks with LVT. Load pallets of miscellaneous mud additives and chemicals
Transfer 100 bbls of FIW to Well Clean Out Tank on platform. Continue cleaning pit 4 in preparation for OBM system RIH w/Build Drilling BHA. Hycalog 3.75 x 4.25
Bi-Center SR3211M-B10 w/3.2 degree motor. Taking displacement to PFMS.
6/25/2021 Continue in hole with build BHA. Log tie in with +9' correction. Bring LVT from ISO's into pits to start mixing OBM. PJSM with all involved on mixing OBM. Go over
recipe and PPE needed to work with fluid. Start adding dry product. on 1st batch. Continue mixing 1st batch of OBM. Start on 2nd batch of OBM. Fill well with 8.5
bbls of filtered seawater. Calibrate and visually verify MI-Swaco drilling chokes(#1 & #2) actuation. Continue rolling 2nd mud batch. Transfer old OBM and LVT to
iso tank to prep for mixing 3rd batch.
6/26/2021 Continue making up batch 3 and 4 of OBM. RU to trip out of hole from PFMS. Pooh. Rate in 1.50 bpm, Rate out: 1.08 bpm. MW in: 8.53 ppg, MW out: 8.51 ppg.
Injector tripped out at 9101' MD. Driller saw chain tension pressure jump. Stop and inspect chains. Tabs from blocks found in sump. Stop circulating and close both
sets of pipe rams. Investigate further. Inspect chains. Slack off injector weight to ensure pipe / slip rams holding, then reduce chain traction. Tabs on injector chains
that hold the gripper blocks in place have broken off. Mobilize a new set of injector chains from Cruz yard in Kenai. New chains arrive, load onto rig. PJSM then start
swapping chains. Start on reel side. Break old chain apart. Pin the new chain to the old one and roll it into injector. New chain is 4 links short, get from the other
chain. Install first injector chain.
6/27/2021 Continue working on chains in injector. Replace gooseneck side chain. Start building replacement chain for rear of injector. Fill well with 5.5 bbls @ 13:15, Finish
installing rear chain. Install gripper blocks. Roll chains and inspect blocks. Get up weight 45k. Open both sets of pipe / slip rams. Start circulating, roll back slowly
about 50' to inspect CT. Some minor scrape marks found. CT is seen tracking over to the off driller's side again. Getting some crude in the returned seawater.
Close upper pipe / slip rams. Line up CT to pump filtered seawater to clean up well, take returns to production. Returns clean up after 20 bbls. Pump 1 B/U. Small
amount of light returns then solid 8.5 ppg out. Shut down pump. Close lower pipe / slip rams and lock. Use Hydra-Rig procedure to adjust gooseneck. Pump
residual crude out of pits 1,2,3 to production. Put 80 bbls filtered seawater in pits 1,2,3. After adjusting gooseneck CT is still pulling to one side. Wait on coil
mechanic. Purge MPD choke WHP gauge lines. Keep well full periodically.
6/28/2021 Work on plan with Nordic / Hycalog 4 point BOPE stack. Check level of PRT. Minute adjustment. Rotate injector 3/4" to center bay side. Increase traction. Take
control of pipe. Open both sets of pipe rams. Break Circulation Took 7 bbls to fill well. Rate In: 1.80 bpm, Rate out:1.80 bpm. MW in 8.52 ppg, MW out: 8.50 ppg.
Pull OOH slowly while monitoring both chains to gooseneck and cast tabs / spring clips on carrier blocks Lay down BHA. Remove floats from UQC. M/U nozzle, get
on well. Repair hydraulic hose on CTU power pack. Grease choke valves and tree valves for BOP test. Fill well with 11 bbls at 19:30. Service CTU power pack. LO /
TO reel and grease inner reel valve. Fluid pack all lines for shell test. Fill well then shut swab and SSV. Shell test against swab/SSV, CT stripper, outside choke
manifold valve, and outside kill line valve to 300 / 4200 psi, good. Fill well every 2-3 hrs, taking about 1 bbl/hr. Make up TIW valves to BOP test joint. Secure felt
down in walkways to prevent OBM getting tracked around the rig.
6/29/2021 Continue to prep for BOP Test and wait for AOGCC Rep to arrive on 07:30 chopper Start testing BOPE as per AOGCC & Hilcorp requirements 250 psi low and
4000 psi high. AOGCC Lou Laubenstein witnessed BOP Test. Test #2 BOP2 F/P - Grease & Function, retest passed RD Test equipment. Verify where Hydra-Rig
Mechanic wants us to be in or OOH when he gets here and he would like us to be at surface. Install BHI Floats and make up CT riser to well. PT floats to 3500 psi,
good. Continue with housekeeping and general rig maintenance while waiting on Hydra-Rig Mechanic. Fill well every 3 hrs, taking about 1-2 bbls / hr.
6/30/2021 Continue with housekeeping and general rig maintenance while waiting on Hydra-Rig Mechanic to inspect the Injector. Fill well every 3 hrs, taking about 1-2 bbls /
hr. Hydra-Rig Mech arrived by boat, given Platform orientation & video then started working on injector. PJSM with Nordic crew. Pick up injector drive hoses near
injector and secure them to take weight off fittings. POOH from 290 ft. Tag up with nozzle BHA. Take off nozzle, M/U BHA #5, build BHA. While M/U BHA perform
kick drill with crews. After drill is announced BHA is pulled from well and SSV shut. 1 min to secure well. M/U injector to well. 4-point injector with chains front and
back. RIH. Inspect injector chains and gripper blocks while RIH. Weight check and look at chains and gripper blocks every 2000'. Tie-in depth, correct -4.5'. PJSM
with all crews then start displacement of CT and well to OBM. Problems with both pumps during displacement, on 1 pump most of the time. LVT at surface, shut
down and purge surface lines.
7/1/2021 LVT at surface, purge all surface lines to OBM. Prime pump lines Surface lines flooded with OBM, online with pumps at 2.88 bpm ECD at the TOWS = 8.05. ECD
Yellow Jacket - Pump #1 shut down, shut down pump #2 both pump packings are smoking, verify plungers are getting proper lubrication. Online, pumps at 2.94
bpm, ECD = 8.10, this is the ECD we will maintain while with pumps off and tripping. 08:30 Shut down pumps, packing is smoking again, Work on pumps Pump
packing is too tight, back off packing nuts and roll pumps. Still getting hot & smoking, back off packing nuts again Pumps are running good, close EDC to establish
rates & parameters. Shut down pump, RIH fairly clean through window and tagged bottom on depth. PU and bring pumps to rate and start drilling At 11051' PU off
bottom, BHI counter is looked up and not tracking depth. PUH to the 7" and check counter wheel. Continue drilling to 11097'. ROP is 10 ft/hr with ~2k DWOB. 2.58 /
2.58 BPM. MW 7.3 / 7.24 ppg In / Out At 11097' pump #2 shuts down. Pick up off bottom about 67k and start other pump. Run back in, stack 4k weight at 11092'.
Try to pick up, Injector stops moving at 70K. No BHA movement. -4K on DWOB Not able to pick up more than 70K, injector pressure max is 3200 psi. Should be
able to get to 4750psi on that circuit which = 100K. Troubleshoot power pack and injector drive circuit. Swap relief valves, still can't get enough pressure. Continue
pumping with full returns, able to orient freely. Increase CTU power pack charge pressure to injector drive pump, able to get 88k pull a couple times then goes back
to 70k max. Shut down mud pump after 1.5X B/U and pull 75 - 80K, no movement. Remove and rebuild relief valves for injector circuit. Resume pumping down CT.
Redressed relief valves not working. Prep to replace pump on CTU power pack injector drive circuit.
While M/U BHA perform
kick drill with crews. After drill is announced BHA is pulled from well and SSV shut. 1 min to secure well. M
start drilling At 11051'
Continue drilling to 11097'
wait for AOGCC Rep to arrive on 07:30 chopper Start testing BOPE as per AOGCC & Hilcorp requirements 250 psi low and
4000 psi high. AOGCC Lou Laubenstein witnessed BOP Test.
t At 11097' pump #2 shuts down.
Ream window at drilled and 15 deg L/R w
Getting some crude in the returned seawater.
r Put whipstock on
depth of 11041' MD (11023' TOWS, 10° LOHS)
7/2/2021 Continue working on CTU 1 Hydraulics to get max pull on stuck BHA. Swapped hoses on the pump to the side that was getting 5000psi. PU to 92k, shut down and
swap relief valves. PU to 99k, cycle pumps to max rate then dump the pressure 3x. RIH and stack to -10k and pump at max rate BHI pressures - Ann = 3912psi
Bore = 4659psi Diff = 746psi. Shut down pump. PU to 20k surface WT and open the EDC. Online at max rate. Pump #1 ran for ~9 min and it shut down from
overheating Close the EDC, pull max WT to 100k, no movement. Set down 15k from neutral weight and send command to disconnect. Online at 2.5 bpm, PU to
was out of the fishing profile. PU and we are free - Top of BHA at ~11,028.3' (window 11,026 - 11,033'). Left in hole 64.69' of BHA from 11,028.31 to 11,093' PU
100' and RIH to tag to jet out any debris. POOH slow in 7" to TT. Recip TT 2x 50' in both directions then POOH. Tag stripper. Lift injector, skid it back. D1 drill with
Karsten crew. Drill is announced, BHA is removed from the well and the SSV is closed. Verify SSV closure. Well secure in 1.5 min. AAR for well control drill and
BHA laydown. Break down BHA #5. Nordic crew perform chain inspection. Wait on fishing tools. Unhook air, hydraulic and electric line from 2 MPD choke panels so
they can be relocated. Review valve checklist with new crew.
7/3/2021 Walk fishing BHA with Driller, verify OD's & lengths. PU Fishing BHA, open SSV and deploy BHA. Hold State Required KWT Drill closing the SSV. Drill completed
in 2 min, MU Fishing BHA BHA MU, fill hole, apply 3450psi WHP, open SSSV, did not see any change in pressure or return rate. Apply 400psi to SSSV, no
change, RIH slow to SSSV depth. Passed through clean, SSSV is open, RIH 10900' get up and down WT's - Up = 62k Dn = 25k. Online at 1.7 bpm at 3860psi.
RIH to tag, tag at 11,031.5' with 4.84k WOB. Shut down pump and PU to confirm we are latched on to fish. Pulled to 75k, latched on, RIH and start jarring down with
5k WOB Jar down at 5k WOB 5x no movement. Jar down at 10k WOB 5x no movement. Jar down at 8-11k WOB (that's all we can get down) no movement Jar up
at 10k over 5x no movement. Jar up at 20k over 3x popped free continue PUH to see if we see any drag coming through the window with the fish. Saw a little WT
drop off at the calculated depth if the fish was on but nothing obvious. RIH to see if we tag at the window wit the 3.2° bent motor RIH to tag at 11031' where we
started. PU to see if we are latched on and didn't get an over pull. RIH and try to latch on to fish, PU nothing. RIH again, PU and we are latched on again. Allow jars
to fire and popped off or pulled the BHA free POOH to see if we have the fish or if the GS is damaged. Line up to hold 300psi W HP for TOOH OOH, close the SSSV
with 300 psi on WHP. Bleed off WHP, remove fusible cap. Remove the injector, pull the BHA. No fish and GS looks fine Stand back BHA, chopper bringing out
tools. Tools arrive on chopper. GS fishneck sub was not included. Mobilize the sub to OSK, schedule another flight out. PJSM then M/U BHA #7 - Fishing BHA w/
overshot. Verify no pressure then open swab. Run tools in, M/U injector. Install fusible cap. Line up valves for normal circulation. Start pumping through open EDC
0.3 bpm. Adjust MPD choke to open around 300 psi WHP. Open SSSV, no pressure change. 4-pt injector. RIH, pump 0.3 bpm through EDC follow MPD pressure
schedule. Slow to 20 ft/min past SSSV, nothing seen. Get up/down weights just above fish. Line up to pump down kill keep 270 psi on WHP. RIH and find top fish at
11031'. Try to engage overshot, not getting over it. Up weight is 60-65K each time no sign grapple is on it. RIH stop just above fish and pump jars open. Stack
down, no sign of down jar action. Repeat 2X no down jar. Try running in different speeds, different weights. Stack wt down and pump through CT, no latch. Open
EDC and pump high rate, ease down to fish neck. No latch.
7/4/2021 Continue trying to engage fish with Overshot Not able to stay engaged to the fish, POOH holding 260psi WHP to inspect the OS, cut pipe and re-head. OOH, close
SSSV with 260psi WHP. Bleed off WHP and prep to pull BHA BHA OOH, Over Shot shows definite signs that it was over the fish but didn't grab it. Cut 250' of coil
to move the wear spot. Prep coil for CTC. MU Dimple Connector. Pull test test to 50k. MU BHI Lower Quick Connect, install floats and PT to 4000psi Discuss plan
forward with ODE. Decision is made to set whipstock because the remaining GS spear is not compatible with the BHI fish neck. L/D fishing BHA. Prep whipstock.
Whipstock is missing a brass shear screw that secures the top whipstock to the setting tool. Make one from brass shear stock. Remove tree cap, set on deck. Rig
up BHA #8 and swing over to well deck, have to lay it down to re-rig it twice to get it to pick up right. Make up injector to well. Install fusible cap. Open EDC. Line up
valves. Start pumping through CT. Stripper is leaking. Shut down and clean up OBM on and around tree. Pump WHP to 270 psi, open SSSV. RIH, pump min rate
through open EDC with pump trips set low. Slow down through SSSV, nothing seen. While RIH follow MPD schedule as a training exercise for Driller. Log GR tie-in
from 9840'.
Stripper is leaking. Shut down and clean up OBM on and around tree.
Drill is announced, BHA is removed from the well and the SSV is closed.
Vert Uncert 1sd[ft]0.005.00Start MDEnd MDSurvey Date[ft][ft]0.008000.0006/04/218000.0011000.0006/04/2111000.0011096.0007/06/21MDInclinationAzimuthTVDTVDSSNorthEastGrid EastGrid NorthLatitudeLongitudeDLSToolfaceBuild RateTurn RateVert SectMajor SemiMinor SemiVert SemiMinor AzimComments[ft][°][°][ft][ft][ft][ft][US ft][US ft][°/100ft][°][°/100ft][°/100ft][ft][ft][ft][ft][°]0.00 0.00 171.00 0.00 -105.00 0.00 0.00 263287.17 2544567.62 60°57'29.4603"N151°19'54.6774"W0.00 0 0.00 0.00 0.00 100.00 100.00 10.00 0.0075.00 0.25 171.00 75.00 -30.00 -0.16 0.03 263287.19 2544567.46 60°57'29.4587"N151°19'54.6769"W0.33 -146.283 0.33 0.00 0.13 100.00 100.00 10.09 171.00100.00 0.17 150.00 100.00 -5.00 -0.25 0.05 263287.22 2544567.37 60°57'29.4579"N151°19'54.6764"W0.44 115.5 -0.32 -84.00 0.19 100.00 100.00 10.09 168.23125.00 0.17 201.00 125.00 20.00 -0.31 0.06 263287.22 2544567.30 60°57'29.4572"N151°19'54.6763"W0.59 170.51 0.00 204.00 0.24 100.01 100.01 10.09 169.60150.00 0.08 351.00 150.00 45.00 -0.33 0.04 263287.21 2544567.29 60°57'29.4571"N151°19'54.6766"W0.97 -154.082 -0.36 600.00 0.27 100.01 100.01 10.09 352.60175.00 0.33 203.00 175.00 70.00 -0.38 0.01 263287.17 2544567.24 60°57'29.4566"N151°19'54.6772"W1.60 106.037 1.00 -592.00 0.32 100.01 100.01 10.09 178.54200.00 0.42 260.00 200.00 95.00 -0.46 -0.11 263287.05 2544567.16 60°57'29.4558"N151°19'54.6796"W1.47 169.569 0.36 228.00 0.45 100.02 100.02 10.09 192.78225.00 0.17 43.00 225.00 120.00 -0.45 -0.17 263286.99 2544567.17 60°57'29.4559"N151°19'54.6809"W2.26 -62.61 -1.00 572.00 0.48 100.02 100.02 10.09 22.21246.00 0.75 352.00 246.00 141.00 -0.29 -0.17 263286.99 2544567.33 60°57'29.4574"N151°19'54.6809"W3.13 -76.933 2.76 -242.86 0.34 100.02 100.02 10.09 17.44300.00 1.00 322.00 299.99 194.99 0.43 -0.51 263286.67 2544568.06 60°57'29.4645"N151°19'54.6877"W0.95 -28.242 0.46 -55.56 -0.12 100.03 100.03 10.09 327.62400.00 3.75 301.00 399.90 294.90 2.80 -3.85 263283.38 2544570.50 60°57'29.4879"N151°19'54.7554"W2.84 -89.761 2.75 -21.00 -0.50 100.06 100.06 10.10 305.08500.00 6.25 248.00 499.56 394.56 2.45 -11.71 263275.52 2544570.30 60°57'29.4844"N151°19'54.9145"W4.99 24.445 2.50 -53.00 3.73 100.10 100.09 10.10 278.02600.00 6.50 249.00 598.94 493.94 -1.62 -22.04 263265.11 2544566.45 60°57'29.4444"N151°19'55.1237"W0.27 180 0.25 1.00 12.42 100.14 100.14 10.11 262.51700.00 6.00 249.00 698.34 593.34 -5.52 -32.20 263254.87 2544562.75 60°57'29.4059"N151°19'55.3296"W0.50 -90.497 -0.50 0.00 20.88 100.19 100.19 10.12 257.96800.00 6.00 248.00 797.80 692.80 -9.35 -41.93 263245.06 2544559.12 60°57'29.3682"N151°19'55.5265"W0.10 -170.191 0.00 -1.00 29.06 100.25 100.24 10.14 255.62900.00 4.00 243.00 897.41 792.41 -12.90 -49.88 263237.04 2544555.74 60°57'29.3333"N151°19'55.6876"W2.05 159.626 -2.00 -5.00 36.10 100.31 100.31 10.15 253.961000.00 3.25 248.00 997.21 892.21 -15.54 -55.62 263231.25 2544553.21 60°57'29.3073"N151°19'55.8038"W0.81 -33.256 -0.75 5.00 41.26 100.39 100.38 10.17 252.981100.00 6.00 232.00 1096.88 991.88 -19.82 -62.36 263224.42 2544549.07 60°57'29.2651"N151°19'55.9404"W3.01 -32.137 2.75 -16.00 48.34 100.47 100.46 10.19 250.881200.00 9.25 220.00 1195.99 1090.99 -29.20 -71.65 263214.94 2544539.88 60°57'29.1728"N151°19'56.1285"W3.60 12.346 3.25 -12.00 61.10 100.56 100.54 10.21 245.721300.00 11.00 222.00 1294.43 1189.43 -42.45 -83.20 263203.13 2544526.87 60°57'29.0423"N151°19'56.3625"W1.78 8.221 1.75 2.00 78.35 100.67 100.64 10.24 240.181400.00 12.50 223.00 1392.33 1287.33 -57.45 -96.97 263189.06 2544512.15 60°57'28.8946"N151°19'56.6412"W1.51 9.175 1.50 1.00 98.23 100.78 100.74 10.27 236.261500.00 14.00 224.00 1489.66 1384.66 -74.07 -112.75 263172.94 2544495.86 60°57'28.7309"N151°19'56.9609"W1.52 8.829 1.50 1.00 120.51 100.91 100.84 10.32 233.571600.00 15.75 225.00 1586.31 1481.31 -92.37 -130.75 263154.57 2544477.93 60°57'28.5507"N151°19'57.3254"W1.77 13.19 1.75 1.00 145.35 101.06 100.96 10.37 231.761700.00 17.00 226.00 1682.25 1577.25 -112.12 -150.87 263134.06 2544458.59 60°57'28.3562"N151°19'57.7328"W1.28 9.259 1.25 1.00 172.51 101.23 101.08 10.43 230.591800.00 19.00 227.00 1777.35 1672.35 -133.38 -173.29 263111.21 2544437.79 60°57'28.1469"N151°19'58.1869"W2.02 -50.273 2.00 1.00 202.14 101.42 101.20 10.50 229.861900.00 21.25 220.00 1871.25 1766.25 -158.37 -196.85 263087.15 2544413.29 60°57'27.9008"N151°19'58.6640"W3.29 -84.522 2.25 -7.00 235.56 101.64 101.33 10.58 228.722000.00 21.50 215.00 1964.38 1859.38 -187.27 -219.01 263064.41 2544384.85 60°57'27.6163"N151°19'59.1128"W1.84 0 0.25 -5.00 271.66 101.90 101.47 10.68 226.932100.00 22.50 215.00 2057.10 1952.10 -217.95 -240.50 263042.30 2544354.61 60°57'27.3141"N151°19'59.5479"W1.00 21.803 1.00 0.00 308.98 102.18 101.61 10.80 225.202200.00 23.50 216.00 2149.15 2044.15 -249.76 -263.19 263018.97 2544323.27 60°57'27.0009"N 151°20'0.0075"W 1.07 15.77 1.00 1.00 347.87 102.51 101.76 10.93 223.872300.00 25.00 217.00 2240.32 2135.32 -282.76 -287.63 262993.86 2544290.77 60°57'26.6759"N 151°20'0.5024"W 1.56 0 1.50 1.00 388.67 102.89 101.91 11.07 222.912400.00 27.00 217.00 2330.20 2225.20 -317.77 -314.01 262966.78 2544256.31 60°57'26.3311"N 151°20'1.0366"W 2.00 0 2.00 0.00 432.18 103.33 102.07 11.24 222.152500.00 28.75 217.00 2418.59 2313.59 -355.11 -342.15 262937.89 2544219.55 60°57'25.9634"N 151°20'1.6064"W 1.75 18.61 1.75 0.00 478.58 103.85 102.23 11.44 221.512600.00 30.25 218.00 2505.63 2400.63 -394.17 -372.13 262907.12 2544181.11 60°57'25.5788"N 151°20'2.2136"W 1.58 0 1.50 1.00 527.39 104.45 102.40 11.66 221.032700.00 31.00 218.00 2591.68 2486.68 -434.31 -403.49 262874.95 2544141.61 60°57'25.1835"N 151°20'2.8487"W 0.75 -134.789 0.75 0.00 577.84 105.14102.57 11.90 220.682800.00 30.50 217.00 2677.62 2572.62 -474.87 -434.62 262843.01 2544101.70 60°57'24.7841"N 151°20'3.4791"W 0.72 90.431 -0.50 -1.00 628.53 105.91102.75 12.16 220.342900.00 30.50 218.00 2763.78 2658.78 -515.14 -465.51 262811.30 2544062.07 60°57'24.3876"N 151°20'4.1047"W 0.51 116.739 0.00 1.00 678.84 106.77 102.93 12.44 220.053000.00 30.25 219.00 2850.06 2745.06 -554.71 -496.99 262779.03 2544023.15 60°57'23.9979"N 151°20'4.7421"W 0.56 116.911 -0.25 1.00 728.85 107.72103.12 12.73 219.913100.00 30.00 220.00 2936.55 2831.55 -593.44 -528.91 262746.33 2543985.08 60°57'23.6165"N 151°20'5.3885"W 0.56 -90.866 -0.25 1.00 778.35 108.75103.32 13.03 219.873200.00 30.00 218.00 3023.15 2918.15 -632.29 -560.37 262714.08 2543946.87 60°57'23.2339"N 151°20'6.0256"W 1.00 -180 0.00 -2.00 827.72 109.88 103.52 13.34 219.793300.00 29.75 218.00 3109.87 3004.87 -671.54 -591.04 262682.63 2543908.26 60°57'22.8474"N 151°20'6.6466"W 0.25 180 -0.25 0.00 877.05 111.10 103.73 13.67 219.653400.00 29.50 218.00 3196.79 3091.79 -710.49 -621.47 262651.41 2543869.93 60°57'22.4638"N 151°20'7.2629"W 0.25 -117.441 -0.25 0.00 926.00 112.42 103.95 14.00 219.523500.00 29.25 217.00 3283.94 3178.94 -749.41 -651.34 262620.76 2543831.63 60°57'22.0806"N 151°20'7.8676"W 0.55 -117.623 -0.25 -1.00 974.63 113.84 104.18 14.33 219.383600.00 29.00 216.00 3371.29 3266.29 -788.53 -680.29 262591.03 2543793.11 60°57'21.6953"N 151°20'8.4538"W 0.55 180 -0.25 -1.00 1022.98 115.35 104.41 14.68 219.193700.00 28.25 216.00 3459.07 3354.07 -827.29 -708.45 262562.09 2543754.93 60°57'21.3137"N 151°20'9.0240"W 0.75 180 -0.75 0.00 1070.62 116.95 104.65 15.02 218.993800.00 28.00 216.00 3547.26 3442.26 -865.42 -736.15 262533.61 2543717.37 60°57'20.9381"N 151°20'9.5851"W 0.25 180 -0.25 0.00 1117.51 118.64 104.90 15.37 218.813900.00 27.75 216.00 3635.66 3530.66 -903.25 -763.64 262505.37 2543680.11 60°57'20.5656"N151°20'10.1415"W0.25 120.403 -0.25 0.00 1164.00 120.42 105.15 15.72 218.654000.0026.75220.003724.573619.57-939.33-791.79262476.492543644.6160°57'20.2103"N151°20'10.7116"W2.090-1.004.001209.32122.27105.4116.07218.61BH CoilTrak (2019) (Standard) GP 31-23L1 <CoilTrak MWD 11000-11096> GP 31-23L1OWSG Camera Based Film Gyro Multi-Shot rev1 GP-31-23PB1 CB-Film-GMS <0-8000> GP-31-23PB1OWSG Camera Based Film Gyro Multi-Shot rev1 GP-31-23 CB-Film-GMS <8100-11200> GP31-23Positional Uncertainty Model Log Name / CommentWellbore151°19'54.6774"W151°20'20.0745"W151°18'33.1120"WHoriz Uncert 1sd[ft]0.0050.00[US ft]2544567.622546957.332557407.98Latitude60°57'29.4603"N60°57'52.7464"N60°59'36.7310"N[ft]1254.04Grid East[US ft]263287.17262081.75267571.89Slot LocationFacility Reference PtField Reference PtLocal North[ft]-2364.67209.99°included50-733-20072-60Local East Grid North LongitudeSection AzimuthSurface Position UncertaintyAPI#NAD27 / TM Alaska SP, Zone 4 (5004), US feetTrue0.9999641.16 WestSlotActual Datum, Orig RKB = 105 (RKB)Actual Datum, Orig RKB = 105 (RKB)mean sea level105.00 ft105.00 ft105.00 ftE 0.00 ftN 0.00 ftMagnetic North is 15.17 degrees East of True North2.00Std DevWA_ANC_DefnProjection SystemNorth ReferenceScaleConvergence at SlotHorizontal Reference PointVertical Reference PointMD Reference PointField Vertical ReferenceActual Datum, Orig RKB = 105 (RKB) To Facility Vertical DatumActual Datum, Orig RKB = 105 (RKB) To mean sea levelActual Datum, Orig RKB = 105 (RKB) to Mud Line at Slot (slot #1-0Section Origin XSection Origin YDeclinationEllipse Confidence LimitDatabase07/26/21 at 11:12 using WellArchitect 6.0Hilcorp Alaska, LLCCook Inlet, Alaska (Offshore)Granite Point FieldGRANITE POINT Platformslot #1-04GP 31-23L1GP 31-23L1GP 31-23L107/07/2021GP31-23 at 11000.00 MDUlricardMinimum curvatureWellpathWellbore last revised Sidetrack fromUserCalculation methodFieldFacilitySlotWellWellboreActual Wellpath Geographic Report - including Position UncertaintyReport by Baker HughesOperatorAreaPage 1 of 2
4100.00 27.25 220.00 3813.67 3708.67 -974.10 -820.97 262446.61 2543610.44 60°57'19.8679"N151°20'11.3025"W0.50 32.17 0.50 0.00 1254.03 124.22 105.68 16.43 218.684200.00 28.00 221.00 3902.27 3797.27 -1009.36 -851.09 262415.78 2543575.80 60°57'19.5207"N151°20'11.9123"W0.88 0 0.75 1.00 1299.62 126.31 105.95 16.79 218.774300.00 28.50 221.00 3990.36 3885.36 -1045.08 -882.14 262384.01 2543540.72 60°57'19.1689"N151°20'12.5411"W0.50 0 0.50 0.00 1346.08 128.55 106.23 17.17 218.884400.00 28.75 221.00 4078.13 3973.13 -1081.24 -913.57 262351.85 2543505.21 60°57'18.8128"N151°20'13.1775"W0.25 136.778 0.25 0.00 1393.10 130.94 106.51 17.56 218.984500.00 28.25 222.00 4166.02 4061.02 -1116.97 -945.18 262319.52 2543470.13 60°57'18.4609"N151°20'13.8177"W0.69 0 -0.50 1.00 1439.86 133.43 106.80 17.95 219.104600.00 28.25 222.00 4254.10 4149.10 -1152.15 -976.85 262287.14 2543435.60 60°57'18.1145"N151°20'14.4590"W0.00 90.44 0.00 0.00 1486.15 136.03 107.10 18.35 219.234700.00 28.25 223.00 4342.19 4237.19 -1187.04 -1008.83 262254.46 2543401.37 60°57'17.7709"N151°20'15.1064"W0.47 -90.44 0.00 1.00 1532.36 138.74 107.40 18.75 219.384800.00 28.25 222.00 4430.28 4325.28 -1221.94 -1040.81 262221.79 2543367.13 60°57'17.4272"N151°20'15.7539"W0.47 118.379 0.00 -1.00 1578.56 141.57 107.71 19.15 219.514900.00 28.00 223.00 4518.48 4413.48 -1256.70 -1072.65 262189.24 2543333.03 60°57'17.0849"N151°20'16.3987"W0.53 -137.481 -0.25 1.00 1624.58 144.52 108.03 19.55 219.645000.00 27.50 222.00 4606.98 4501.98 -1291.02 -1104.11 262157.10 2543299.35 60°57'16.7469"N151°20'17.0356"W0.68 -43.404 -0.50 -1.00 1670.03 147.54 108.35 19.95 219.765100.00 28.00 221.00 4695.47 4590.47 -1325.89 -1134.96 262125.55 2543265.11 60°57'16.4035"N151°20'17.6602"W0.68 91.324 0.50 -1.00 1715.66 150.68 108.67 20.36 219.835200.00 28.00 224.00 4783.77 4678.77 -1360.50 -1166.67 262093.14 2543231.16 60°57'16.0627"N151°20'18.3022"W1.41 43.871 0.00 3.00 1761.48 153.96 109.01 20.77 219.945300.00 28.50 225.00 4871.86 4766.86 -1394.25 -1199.84 262059.29 2543198.09 60°57'15.7303"N151°20'18.9740"W0.69 0 0.50 1.00 1807.29 157.38 109.34 21.18 220.125400.00 28.50 225.00 4959.74 4854.74 -1427.99 -1233.58 262024.87 2543165.04 60°57'15.3980"N151°20'19.6572"W0.00 62.882 0.00 0.00 1853.38 160.94 109.69 21.61 220.315500.00 28.75 226.00 5047.52 4942.52 -1461.57 -1267.75 261990.03 2543132.17 60°57'15.0673"N151°20'20.3490"W0.54 0 0.25 1.00 1899.54 164.64 110.03 22.04 220.515600.00 29.00 226.00 5135.09 5030.09 -1495.11 -1302.49 261954.62 2543099.34 60°57'14.7369"N151°20'21.0524"W0.25 -63.25 0.25 0.00 1945.96 168.48 110.39 22.47 220.715700.00 29.25 225.00 5222.45 5117.45 -1529.23 -1337.20 261919.22 2543065.94 60°57'14.4010"N151°20'21.7552"W0.55 0 0.25 -1.00 1992.85 172.47 110.74 22.91 220.895800.00 29.50 225.00 5309.59 5204.59 -1563.91 -1371.89 261883.84 2543031.97 60°57'14.0594"N151°20'22.4575"W0.25 -136.095 0.25 0.00 2040.23 176.61 111.11 23.35 221.055900.00 29.00 224.00 5396.84 5291.84 -1598.76 -1406.14 261848.89 2542997.82 60°57'13.7162"N151°20'23.1509"W0.70 44.778 -0.50 -1.00 2087.53 180.87 111.47 23.80 221.176000.00 29.50 225.00 5484.09 5379.09 -1633.61 -1440.39 261813.94 2542963.68 60°57'13.3730"N151°20'23.8444"W0.70 84.536 0.50 1.00 2134.83 185.25 111.85 24.25 221.296100.00 29.75 229.00 5571.02 5466.02 -1667.30 -1476.52 261777.13 2542930.73 60°57'13.0412"N151°20'24.5761"W1.99 -105.979 0.25 4.00 2182.08 189.77 112.22 24.71 221.496200.00 29.25 225.00 5658.07 5553.07 -1700.86 -1512.53 261740.45 2542897.92 60°57'12.7107"N151°20'25.3050"W2.03 0 -0.50 -4.00 2229.13 194.41 112.61 25.16 221.686300.00 30.00 225.00 5745.00 5640.00 -1735.81 -1547.48 261704.79 2542863.68 60°57'12.3665"N151°20'26.0127"W0.75 180 0.75 0.00 2276.88 199.19 112.99 25.62 221.806400.00 29.75 225.00 5831.71 5726.71 -1771.03 -1582.70 261668.86 2542829.18 60°57'12.0196"N151°20'26.7258"W0.25 0 -0.25 0.00 2324.99 204.13 113.39 26.09 221.906500.00 29.75 225.00 5918.53 5813.53 -1806.12 -1617.79 261633.07 2542794.82 60°57'11.6740"N151°20'27.4362"W0.00 0 0.00 0.00 2372.92 209.18 113.78 26.56 222.016600.00 30.00 225.00 6005.24 5900.24 -1841.34 -1653.01 261597.14 2542760.32 60°57'11.3272"N151°20'28.1493"W0.25 90.866 0.25 0.00 2421.03 214.36 114.19 27.03 222.106700.00 30.00 227.00 6091.84 5986.84 -1876.07 -1688.98 261560.48 2542726.33 60°57'10.9851"N151°20'28.8774"W1.00 0 0.00 2.00 2469.08 219.67 114.59 27.50 222.236800.00 30.00 227.00 6178.45 6073.45 -1910.17 -1725.54 261523.23 2542692.98 60°57'10.6493"N151°20'29.6178"W0.00 0 0.00 0.00 2516.89 225.09 115.00 27.97 222.386900.00 30.00 227.00 6265.05 6160.05 -1944.27 -1762.11 261485.98 2542659.64 60°57'10.3134"N151°20'30.3581"W0.00 180 0.00 0.00 2564.70 230.63 115.42 28.45 222.537000.00 29.75 227.00 6351.76 6246.76 -1978.24 -1798.54 261448.87 2542626.41 60°57'9.9789"N151°20'31.0957"W0.25 117.785 -0.25 0.00 2612.33 236.26 115.84 28.93 222.667100.00 29.25 229.00 6438.80 6333.80 -2011.19 -1835.13 261411.62 2542594.21 60°57'9.6544"N151°20'31.8364"W1.10 -76.576 -0.50 2.00 2659.16 241.94 116.27 29.40 222.827200.00 29.50 227.00 6525.94 6420.94 -2044.01 -1871.57 261374.52 2542562.14 60°57'9.3311"N151°20'32.5743"W1.01 136.095 0.25 -2.00 2705.80 247.71 116.70 29.87 222.977300.00 29.00 228.00 6613.19 6508.19 -2077.02 -1907.59 261337.84 2542529.87 60°57'9.0060"N151°20'33.3035"W0.70 105.387 -0.50 1.00 2752.40 253.57 117.14 30.34 223.107400.00 28.75 230.00 6700.76 6595.76 -2108.70 -1944.03 261300.76 2542498.94 60°57'8.6940"N151°20'34.0412"W1.00 -119.594 -0.25 2.00 2798.05 259.46 117.58 30.81 223.277500.00 27.75 226.00 6788.86 6683.86 -2140.34 -1979.20 261264.96 2542468.03 60°57'8.3824"N151°20'34.7534"W2.14 -135.835 -1.00 -4.00 2843.03 265.34 118.03 31.27 223.397600.00 26.00 222.00 6878.06 6773.06 -2172.80 -2010.62 261232.89 2542436.21 60°57'8.0626"N151°20'35.3894"W2.52 60.864 -1.75 -4.00 2886.85 271.09 118.49 31.71 223.417700.00 26.25 223.00 6967.84 6862.84 -2205.27 -2040.37 261202.48 2542404.36 60°57'7.7429"N151°20'35.9917"W0.51 -24.68 0.25 1.00 2929.84 276.79 118.95 32.14 223.397800.00 27.25 222.00 7057.14 6952.14 -2238.45 -2070.77 261171.42 2542371.80 60°57'7.4161"N151°20'36.6071"W1.10 43.849 1.00 -1.00 2973.78 282.70 119.41 32.58 223.377900.00 28.25 224.00 7145.64 7040.64 -2272.49 -2102.53 261138.97 2542338.41 60°57'7.0808"N151°20'37.2501"W1.37 0 1.00 2.00 3019.13 288.91 119.88 33.04 223.368000.00 29.75 224.00 7233.10 7128.10 -2307.37 -2136.21 261104.59 2542304.23 60°57'6.7374"N151°20'37.9319"W1.50 -75.533 1.50 0.00 3066.17 295.46 120.35 33.51 223.388100.00 30.50 219.00 7319.61 7214.61 -2344.94 -2169.42 261070.63 2542267.34 60°57'6.3673"N151°20'38.6042"W2.62 -86.481 0.75 -5.00 3115.31 298.87 120.59 33.78 223.388200.00 31.00 211.00 7405.58 7300.58 -2386.75 -2198.67 261040.54 2542226.13 60°57'5.9555"N151°20'39.1962"W4.12 -28.014 0.50 -8.00 3166.15 299.06 120.61 33.84 223.378300.00 32.00 210.00 7490.85 7385.85 -2431.78 -2225.18 261013.12 2542181.66 60°57'5.5121"N151°20'39.7328"W1.13 -72.398 1.00 -1.00 3218.39 299.45 120.66 33.91 223.348400.00 32.75 206.00 7575.31 7470.31 -2479.04 -2250.29 260987.06 2542134.92 60°57'5.0466"N151°20'40.2411"W2.27 29.155 0.75 -4.00 3271.88 300.06 120.76 34.00 223.288500.00 33.75 207.00 7658.94 7553.94 -2528.10 -2274.76 260961.60 2542086.36 60°57'4.5635"N151°20'40.7363"W1.14 0 1.00 1.00 3326.60 300.90 120.92 34.09 223.188600.00 35.00 207.00 7741.48 7636.48 -2578.41 -2300.39 260934.95 2542036.59 60°57'4.0680"N151°20'41.2551"W1.25 57.885 1.25 0.00 3382.99 302.01 121.13 34.19 223.058700.00 35.75 209.00 7823.02 7718.02 -2629.51 -2327.57 260906.73 2541986.05 60°57'3.5647"N151°20'41.8053"W1.38 38.574 0.75 2.00 3440.84 303.42 121.38 34.30 222.908800.00 36.50 210.00 7903.79 7798.79 -2680.82 -2356.61 260876.66 2541935.34 60°57'3.0595"N151°20'42.3930"W0.95 142.889 0.75 1.00 3499.79 305.15 121.67 34.42 222.728900.00 35.00 212.00 7984.95 7879.95 -2730.90 -2386.68 260845.58 2541885.89 60°57'2.5662"N151°20'43.0016"W1.90 156.104 -1.50 2.00 3558.20 307.17 121.95 34.56 222.529000.00 33.75 213.00 8067.48 7962.48 -2778.52 -2417.01 260814.29 2541838.89 60°57'2.0972"N151°20'43.6155"W1.37 165.284 -1.25 1.00 3614.60 309.43 122.23 34.70 222.339100.00 31.75 214.00 8151.58 8046.58 -2823.64 -2446.85 260783.54 2541794.40 60°57'1.6529"N151°20'44.2196"W2.07 65.594 -2.00 1.00 3668.59 311.86 122.49 34.85 222.149200.00 32.25 216.00 8236.39 8131.39 -2867.04 -2477.25 260752.27 2541751.62 60°57'1.2255"N151°20'44.8349"W1.17 100.175 0.50 2.00 3721.37 314.52 122.72 35.00 221.959300.00 32.00 219.00 8321.08 8216.08 -2909.22 -2509.61 260719.06 2541710.11 60°57'0.8101"N151°20'45.4899"W1.61 180 -0.25 3.00 3774.08 317.46 122.91 35.17 221.799400.00 31.75 219.00 8406.00 8301.00 -2950.26 -2542.84 260685.00 2541669.76 60°57'0.4059"N151°20'46.1625"W0.25 55.659 -0.25 0.00 3826.23 320.65 123.05 35.34 221.649500.00 32.50 221.00 8490.70 8385.70 -2990.98 -2577.02 260650.00 2541629.74 60°57'0.0048"N151°20'46.8545"W1.30 65.544 0.75 2.00 3878.59 324.14 123.18 35.52 221.509600.00 32.75 222.00 8574.92 8469.92 -3031.36 -2612.75 260613.46 2541590.10 60°56'59.6071"N151°20'47.5776"W0.59 85.114 0.25 1.00 3931.42 327.94 123.27 35.72 221.399700.00 33.00 226.00 8658.91 8553.91 -3070.38 -2650.44 260574.98 2541551.85 60°56'59.2228"N151°20'48.3406"W2.19 109.749 0.25 4.00 3984.06 332.05 123.30 35.92 221.319800.00 32.00 232.00 8743.27 8638.27 -3105.62 -2690.92 260533.80 2541517.44 60°56'58.8757"N151°20'49.1600"W3.37 98.446 -1.00 6.00 4034.81 336.34 123.21 36.12 221.329900.00 31.75 236.00 8828.20 8723.20 -3136.65 -2733.62 260490.48 2541487.29 60°56'58.5700"N151°20'50.0243"W2.13 41.436 -0.25 4.00 4083.03 340.75 123.03 36.33 221.4210000.00 33.00 238.00 8912.66 8807.66 -3165.79 -2778.53 260444.99 2541459.06 60°56'58.2829"N151°20'50.9335"W1.65 60.128 1.25 2.00 4130.72 345.41 122.84 36.55 221.5910100.00 34.00 241.00 8996.05 8891.05 -3193.78 -2826.08 260396.88 2541432.05 60°56'58.0072"N151°20'51.8961"W1.93 115.056 1.00 3.00 4178.72 350.41 122.64 36.78 221.8310200.00 33.50 243.00 9079.20 8974.20 -3219.87 -2875.12 260347.32 2541406.97 60°56'57.7502"N151°20'52.8890"W1.22 48.43 -0.50 2.00 4225.83 355.63 122.48 37.02 222.1310300.00 34.00 244.00 9162.35 9057.35 -3244.65 -2924.84 260297.11 2541383.20 60°56'57.5061"N151°20'53.8955"W0.75 -18.505 0.50 1.00 4272.15 361.05 122.38 37.26 222.4710400.00 35.75 243.00 9244.39 9139.39 -3270.17 -2976.01 260245.44 2541358.72 60°56'57.2546"N151°20'54.9313"W1.84 180 1.75 -1.00 4319.82 366.89 122.37 37.52 222.8410500.00 34.75 243.00 9326.05 9221.05 -3296.37 -3027.43 260193.49 2541333.57 60°56'56.9965"N151°20'55.9723"W1.00 0 -1.00 0.00 4368.22 373.08 122.44 37.79 223.2110600.00 35.00 243.00 9408.09 9303.09 -3322.33 -3078.38 260142.03 2541308.66 60°56'56.7407"N151°20'57.0036"W0.25 0 0.25 0.00 4416.16 379.47 122.59 38.07 223.6010700.00 35.00 243.00 9490.01 9385.01 -3348.37 -3129.48 260090.41 2541283.66 60°56'56.4842"N151°20'58.0382"W0.00 -90.41 0.00 0.00 4464.26 386.16 122.81 38.35 224.0010800.00 35.00 242.00 9571.92 9466.92 -3374.86 -3180.36 260039.01 2541258.22 60°56'56.2232"N151°20'59.0681"W0.57 90.41 0.00 -1.00 4512.63 393.12 123.09 38.64 224.3910900.00 35.00 243.00 9653.84 9548.84 -3401.34 -3231.23 259987.61 2541232.77 60°56'55.9623"N 151°21'0.0980"W 0.57 -114.026 0.00 1.00 4560.99 400.35 123.42 38.94 224.7911000.00 34.75 242.00 9735.88 9630.88 -3427.74 -3281.95 259936.37 2541207.41 60°56'55.7022"N 151°21'1.1247"W 0.62 0 -0.25 -1.00 4609.21 407.82 123.81 39.25 225.19 Tie On to GP 31-2311021.00 35.01 242.00 9753.11 9648.11 -3433.38 -3292.55 259925.65 2541201.99 60°56'55.6467"N 151°21'1.3393"W 1.24 -13.498 1.24 0.00 4619.39 408.63 124.02 39.75 225.22 TOWS/KOP11043.00 40.44 240.00 9770.50 9665.50 -3439.91 -3304.31 259913.76 2541195.69 60°56'55.5823"N 151°21'1.5774"W 25.30 -29.773 24.68 -9.09 4630.93408.63 124.03 39.77 225.22 Interpolated Azimuth11096.0059.57228.009804.489699.48-3464.07-3336.55259881.042541172.2060°56'55.3443"N151°21'2.2299"W39.93N/A36.09-22.644667.96408.63124.0639.89225.22Projection to TDPage 2 of 2
David Douglas Hilcorp Alaska, LLC
Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400
Anchorage, AK 99503
Tele: (907) 777-8337
E-mail: david.douglas@hilcorp.com
Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 564-4422.
Received By: Date:
Date: 8/16/2021
To: Alaska Oil & Gas Conservation Commission
Natural Resource Technician
333 W 7th Ave Suite 100
Anchorage, AK 99501
DATA TRANSMITTAL
GP ST 31-23L1 (PTD 221-018)
FINAL LWD FORMATION EVALUATION LOGS (06/21/2021 to 07/02/2021)
x Multiple Propagation Resistivity/Gamma ray (2” & 5” MD/TVD Color Logs)
x Final Definitive Directional Survey
SFTP Transfer - Data Folders:
Please include current contact information if different from above.
37'
(6HW
eceived By:
08/19/2021
By Abby Bell at 4:17 pm, Aug 18, 2021
1
Davies, Stephen F (CED)
From:Davies, Stephen F (CED)
Sent:Tuesday, July 6, 2021 6:28 PM
To:Joseph Lastufka
Cc:Rixse, Melvin G (CED)
Subject:RE: GP 31-23L1 (PTD #221-018)
Joe,
GP 31‐23L1 is considered to be a very short, but active, well branch as it may contribute to production because it is not
isolated. Hopefully drilling of the GP 31‐23L2 well branch will be uneventful.
Thanks and and stay safe,
Steve Davies
Senior Petroleum Geologist
Alaska Oil and Gas Conservation Commission (AOGCC)
CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission
(AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use
or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding
it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov.
From: Joseph Lastufka <Joseph.Lastufka@hilcorp.com>
Sent: Tuesday, July 6, 2021 5:25 PM
To: Davies, Stephen F (CED) <steve.davies@alaska.gov>
Subject: GP 31‐23L1 (PTD #221‐018)
Steve,
We had an issue drilling GP 31‐23L1. We lost the BHA approximately 50’‐60’ after kickoff and have decided to stop any
additional drilling on L1. Is it a very short lateral with a restriction in the hole, per our discussion it will have the API as ‐
60‐00 as it is not technically plugged since it isn’t isolated, and will be proceeding to set the whipstock and drill L2 as
planned.
Thanks,
Joe Lastufka
Sr. Drilling Technologist
Hilcorp North Slope, LLC
Office: (907)777-8400, Cell:(907)227-8496
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Alaska Oil and Gas
Conservation Commission
333 West Seventh Avenue
Anchorage, Alaska 99501-3572
Main: 907.279.1433
Fax: 907.276.7542
www.aogcc.alaska.gov
Monty M. Myers
Drilling Manager
Hilcorp Alaska, Inc.
3800 Centerpoint Drive, Suite 400
Anchorage, AK 99503
Re: Granite Point Field, Middle Kenai Oil Pool, GP 31-23 L1
Hilcorp Alaska, LLC
Permit to Drill Number: 221-018
Surface Location: 2365' FNL, 1253' FWL, Sec 13, T10N, R12W, SM, AK
Bottomhole Location: 2610' FSL, 1972' FEL, Sec 23, T10N, R12W, SM, AK
Dear Mr. Myers:
Enclosed is the approved application for the permit to drill the above referenced well.
Conditions of approval:
1. Initial BOP test to Rated working pressure or rating of the tree, whichever is lower.
2. Subsequent BOP tests are to 4000 psi.
3. All annular preventer tests (initial and subsequent) to 3500 psi.
4. BOP test frequency is once every 7 days.
5. Daily operations reports to be submitted to the AOGCC every day.
6. Lift Plan for lifting the CT reel onto and off the platform to be prepared and documented
by a 3rd party crane lifting consultant with current API RP 2D Certifications and sent
to the AOGCC before lifting. Lifting equipment to have current certifications and rated
for the load.
7. A second annular preventor control panel located near the injector is required in
addition to the control panel in the CT ops cab.
8. The proposed Granite Point CTD rig accumulator pump is, according to Hilcorp,
capable of closing the BOP rams without the use of the accumulator, and the AOGCC
therefore considers it a backup to the accumulator, satisfying the requirement of the
second clause in 20 AAC 25.036(c)(2)(A)(iii) as follows “A BOPE assembly must
include a hydraulic actuating system with an accumulator pump system consisting of
… an accumulator backup system having sufficient capacity to close all BOPs and hold
them closed”. AOGCC regulations do not require a nitrogen system as backup to the
accumulator.
9. A variance to 20 AAC 25.036(c)(4)(A)(ii) is required and approved, with the following
conditions, for the following clause within this regulation: A BOPE assembly must
include a hydraulic actuating system with an accumulator pump system consisting of
one or more pumps with independent primary and secondary power sources;
Permit to Drill: 221-018
Page 2 of 3
a. BOP closing times must meet the requirements of API 16D third edition, 6.2.3,
for both the accumulator pump (without the aid of the accumulator) and
accumulator (without the aid of the pump).
b. If the accumulator pump power supply fails, the well will be secured
immediately, and all downhole work will cease until the accumulator pump is
fully operational.
c. The accumulator system useable volume (30 gallons – approximately 3 times
that required to close all BOP rams and annular) and BOP stack are the same as
the proposed system submitted to the AOGCC (attached to this PTD).
10. Coiled Tubing BHA deployment using a closed Sub-Surface Safety Valve (SSSV) to
contain wellbore pressure where hydrostatic pressure exerted by the drilling fluid is
less than the reservoir pressure, is Pressure Deployment. A variance to 20 AAC
25.036(c)(2)(A)(iii) is required and approved with the following conditions:
a. The BHA lifting equipment must be capable of lifting the full length of the BHA
above a remotely controlled surface safety valve (SSV) that is installed in the
vertical run of the tree.
b. The remotely controlled SSV must be functional during BHA deployment and
removal. A fuseable cap or other device designed to lock open the SSV during
CT operations must be removed before the BHA is deployed or removed from
the well. Rigsite BHA deployment procedures must reflect this requirement
and be available on the rigsite for review upon request by the AOGCC.
c. The remotely controlled SSV must be function-pressure tested as part of the
BOP test, and at the same frequency as the BOP test.
d. Pressure Deployment drills required with both tours before switching to drilling
mud having hydrostatic pressure less than the reservoir pressure. Drills must
simulate a leaking SSSV with a partially deployed BHA and test crews’ ability
to identify when the well is flowing.
e. SSSV must be tested with a 10-minute flow check prior to each BHA
deployment, with visual confirmation of no flow from the returns stream
pipework.
11. Variance request to 20 AAC 25.005(c)(4)(A) is not required for this well due to MPSP
less than the proposed BOP test pressure and MPSP will not impact the API RP 16ST
pressure class (PC-2).
These allowances and variances are for this well only, based on its unique operating and well
conditions, and should not be considered a precedent for future CTD operations.
The permit is for a new wellbore segment of existing well Permit Number 167-084, API Number
50-733-20072-00-00. Production should continue to be reported as a function of the original API
number stated above.
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.
Permit to Drill: 221-018
Page 3 of 3
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,
Jeremy M. Price
Chair
DATED this ___ day of June, 2021.
Jeremy
Price
Digitally signed by
Jeremy Price
Date: 2021.06.09
11:37:34 -08'00'
1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for:
Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates
Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas
2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number:
Bond No.
3. Address:6. Proposed Depth: 12. Field/Pool(s):
MD: 13,886' TVD: 10,301'
4a. Location of Well (Governmental Section):7. Property Designation:
Surface:
Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date:
Total Depth:9. Acres in Property: 14. Distance to Nearest Property:
4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 105' 15. Distance to Nearest Well Open
Surface: x-263287 y- 2544567 Zone-4 N/A to Same Pool: 0' - GP 31-23
16. Deviated wells:Kickoff depth: 11,016 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035)
Maximum Hole Angle: 84 degrees Downhole: Surface:
Hole Casing Weight Grade Coupling Length MD TVD MD TVD
4-1/4" 2-7/8" 6.5# L-80 STL 2,425' 11,025' 9,754' 13,450' 10,236'
19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations)
Junk (measured):
N/A
TVD
603'
3,665'
7,287'
9,894'
Hydraulic Fracture planned?Yes No
20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis
Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements
Contact Name:
Contact Email:
Contact Phone:
Date:
Permit to Drill API Number: Permit Approval
Number:50- Date:
Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:
Samples req'd: Yes No Mud log req'd: Yes No
H2S measures: Yes No Directional svy req'd: Yes No
Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No
Post initial injection MIT req'd: Yes No
APPROVED BY
Approved by: COMMISSIONER THE COMMISSION Date:
Sr Pet Eng Sr Pet Geo Sr Res Eng
GL / BF Elevation above MSL (ft):
9,860' - 11,176'8,794' - 9,878'
8,062'8,062'
2435 sx
Effect. Depth MD (ft):
See cover letter for other
requirements.
Perforation Depth MD (ft):
11,196'
21. I hereby certify that the foregoing is true and the procedure approved herein will not be
deviated from without prior written approval.
3,329'
Perforation Depth TVD (ft):
Commission Use Only
Authorized Signature:
7"
800 sx
1182 sx
Surface
Production
Liner
Casing
11,147'
Intermediate
3,933'
9-5/8"
670 sx 604'
3,933'13-3/8"
11,147'9,855'
Effect. Depth TVD (ft):
Conductor/Structural 18"604'
11,200'9,897'
Length
4326
Total Depth MD (ft):Total Depth TVD (ft):
Cement Quantity, c.f. or sacks
Cement Volume MDSize
Plugs (measured):
(including stage data)
N/A
STATE OF ALASKA
ALASKA OIL AND GAS CONSERVATION COMMISSION
PERMIT TO DRILL
20 AAC 25.005
2369
524' FNL, 2051' FEL, Sec 23, T10N, R12W, SM, AK
2610' FSL, 1972' FEL, Sec 23, T10N, R12W, SM, AK
LOCI 19-001
5089
GP 31-23 L1
Granite Point Field
Middle Kenai Oil Pool
3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503
Hilcorp Alaska, LLC
2365' FNL, 1253' FWL, Sec 13, T10N, R12W, SM, AK ADL018761
022224484
3104' to nearest unit boundary
6/3/2021
Authorized Name: Monty Myers
Authorized Title: Drilling Manager
Sean Mclaughlin
Sean.Mclaughlin@hilcorp.com
777-8401
18. Casing Program:Top - Setting Depth - BottomSpecifications
s N
ype of W
L
l R
L
1b
S
Class:
os N s No
s N o
D s
s
sD
84
o
well is p
G
S
S
20
S S
S
s No s No
S
G
y E
S
s No
s
Form 10-401 Revised 3/2020 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g)
By Samantha Carlisle at 11:41 am, Mar 11, 2021
Digitally signed by Cody Dinger
(2323)
DN: cn=Cody Dinger (2323),
ou=Users
Date: 2021.03.11 09:24:24 -09'00'
Cody Dinger
(2323)
XX
X
X
DLB 03/16/2021
X
X
X
10,343' DLB
221-018
DSR-3/11/21
733-20072-60-00
Slotted liner
See conditions of approval on transmittal letter.
Additional requirements annotated onto Sundry procedure.
BJM 6/7/21
6/9/21
Jeremy Price
Digitally signed by Jeremy
Price
Date: 2021.06.09 11:37:57
-08'00'
To: Alaska Oil & Gas Conservation Commission
From: Sean McLaughlin
Drilling Engineer
Date: March 10, 2021
Re: Granite Point Platform 31-23 L1, L1-01, L2, and L2-01 Permit to Drill Request
Approval is requested for drilling sidetrack laterals from well GP31-23 with Coiled Tubing
Drilling equipment on or around June 2021.
Proposed plan for GP31-23 production add laterals:
Prior to drilling activities the wellbore will be prepared for a sidetrack (see GP31-23 Sundry request). The 3-1/2
and 2-7/8” dual string completion will be pulled and packer recovered. A 4-1/2” gas lift production string will be
run. An E-line unit will set a CTD whipstock in the Tyonek C7 interval at 11,016’.
CDR2 will mill a 3.80” window through 7” casing and into the C7 sand. Two laterals will be drilled from this
window. The laterals will be completed with a 2-7/8” slotted liner brought back to the casing. A second whipstock
will be set in the C5 interval at 10,279’. Two laterals will be drilled from this window. The laterals will be completed
with a 2-7/8” slotted liner brought back to the tubing.
The following describes the work planned. A wellbore schematic of the current well and proposed sidetrack is
attached for reference.
Pre-Rig Work:
1. Reference GP31-23 Sundry submitted in concert with this PTD request
2.General work scope of Pre-Rig work:
a.Rig: Pull dual string completion
b.Rig: Run 4-1/2” production string
i.A TRSSSV in the completion will aid in maintaining constant bottom hold pressure while
drilling.
c.E-line: Set 4-1/2” x 7” whipstock at 11,016’, 15 deg LOHS (-15 deg)
Rig Work:
3. MIRU and test BOPE to 4000 psi. MASP (using alternative calculation) is 3584 psi
a. Give AOGCC 48hr notice prior to BOPE test
b.Annular will be tested to 3500psi
c. Test against swab and master valves (No TWC)
d.Load pits with 8.4 ppg milling fluid
e.Open well and ensure zero pressure
4. Mill L1 3.80” single string window plus 10’ of rathole.
a.TOWS at 11016’, 15 LOHS.
b.Mill window with straight motor
c. Pressure deployment is not required for the L1 window milling run
i. 8.0 ppg EMW expected
ii.8.4 ppg milling fluid is 216 psi overbalanced
5.Drill and complete the L1 lateral
a. 3.0” BHA with GR/RES
b.Swap well to 7.2 ppg OBM
c. Drill with bicenter bit (4.25”)
i. Target constant bottom hole pressure of 9.5 ppg for entire sidetrack
ii.Pressure deployment will be utilized to maintain constant bottom hole pressure
d. 40 deg/100’ build section – 160’
e. 12 deg/100’ lateral section - 2,715’
f. Planned TD 13,450’
g.After TD and on the last trip out of hole lay in 9.5 ppg completion fluid in preparation for the liner run
h.Perform no flow test prior to laying down drilling BHA
i. Run 2-7/8” slotted liner with aluminum liner top billet placed at 11,160’
i. Have 2-3/8” safety joint with TIW valve ready to be picked up while running liner
Swap well to 7.2 ppg OBM
from well GP31-23 with Coiled
CDR2
It will not be drilled with CDR2. It will be drilled with an unnamed rig that was sourced from multiple parties and assembled by Hilcorp.
pg
A TRSSSV in the completion will aid in maintaining constant bottom hold pressure while
drilling. It will be used for pressure deployment of the BHA, but not during drilling.
,
After TD and on the last trip out of hole lay in 9.5 ppg completion fluid in preparation for the liner run
4.d Perform well control drill simulating a leaking SSSV with entire length of BHA deployed. Both tours to be drilled before swapping to drilling mud.
bjm
5.g.i. Perform no-flow
test prior to POOH. bjm
4.a.i. Displace well
to 8.4 ppg milling fluid
bjm
Surface Safety valve to be tested as part of well control equipment. BJM
f. Perform well control drill simulating a leaking SSSV with entire length of BHA deployed with both tours - bjm
This Pre-Rig work performed under Sundry 321-107.
Note that 2.c. was not performed under Sundry 321-107. It will be performed as part of this PTD.
This PTD is only covering the GP 31-23 L1 lateral. Each lateral will have its own PTD.
After the new tubing was installed, the tubing was pressure tested to 3600 psi and
IA was tested to 1500 psi. - bjm
ii. Liner may be run in two sections if weight transfer or hole conditions is poor
6.Drill and complete the L1-01 sidetrack
a.Recover KWF and swap well to 7.2 ppg OBM
b.Mill off billet with bicenter bit and continue drilling lateral
i. Planned lateral length of 2,106’ and 12 deg/100’
c.Planned TD of 13,226’
d.After TD and on the last trip out of hole lay in 9.5 KWF in preparation for liner run
e. Run 2-7/8” slotted liner with liner top placed in the 7” casing
i. Have 2-3/8” safety joint with TIW valve ready to be picked up while running liner
ii. Liner may be run in two sections if weight transfer or hole conditions is poor
7. Mill L2 3.80” single string window plus 10’ of rathole.
a. Run 4-1/2” x 7” whipstock and set 10,279’ and 15 LOHS.
b.Swap well to 8.4 ppg milling fluid
c. Mill window with straight motor
d. Pressure deployment is not required for the L1 window milling run
i.8.0 ppg EMW expected at the window
ii.8.4 ppg milling fluid is 209 psi overbalanced
8.Drill and complete the L2 lateral
a.Drill with bicenter bit (4.25”)
i.Target constant bottom hole pressure of 9.5 ppg for entire sidetrack
ii.~750’ from the window there is a small possibility that past injection, from 1973, may elevated
the pressure in the area to 10.5 ppg EMW. It is unknown if the pressure was there or has
dissipated. Drill with caution through the area utilizing real time BHP to monitor pressure. If
necessary, use MPD choke to elevate EWM as necessary to maintain overbalance.
iii. Pressure deployment will be utilized to maintain constant bottom hole pressure
b. 40 deg/100’ build section – 300’
c.12 deg/100’ lateral section - 3,349’
d. Planned TD 13,928’’
e.After TD and on the last trip out of hole lay in 9.5 ppg completion fluid in preparation for the liner run
f. Perform no flow test prior to laying down drilling BHA
g. Run 2-7/8” slotted liner with aluminum liner top billet placed at 10,429’
i. Have 2-3/8” safety joint with TIW valve ready to be picked up while running liner
9.Drill and complete the L2-01 sidetrack
a.Recover KWF and swap well to 7.2 ppg OBM
b. Mill off billet with bicenter bit and continue drilling lateral
i.Planned lateral length of 2,361’ and 12 deg/100’
c.Planned TD of 12,790’
d. After TD and on the last trip out of hole lay in 9.5 KWF in preparation for liner run
e. Run 2-7/8” slotted liner with liner top placed in the 4-1/2” tubing tail
i. Have 2-3/8” safety joint with TIW valve ready to be picked up while running liner
ii. Liner may be run in two sections if weight transfer or hole conditions is poor
10. After releasing from the liner swap the well over to diesel
i. Expect 600 psi on the wellhead after the fluid swap.
Post Rig:
1.V: Tree work as necessary
2. S: Install LTP
Managed Pressure Drilling:
Due to concerns with wellbore stability managed pressure drilling techniques will be employed on this well. The
intent is to provide constant bottom hole pressure by using 7.2 ppg drilling fluid in combination with annular friction
losses and applied surface pressure. Constant BHP will be utilized to reduce pressure fluctuations to improve
hole stability. Applying annular friction and choke pressure also allow use of lighter drilling fluid and minimizes
g p ppg
~750’ from the window there is a small possibility that past injection, from 1973, may elevatedpypj, ,y
the pressure in the area to 10.5 ppg EMW. It is unknown if the pressure was there or hasp ppg p
dissipated. Drill with caution through the area utilizing real time BHP to monitor pressure. Ifpggp
necessary, use MPD choke to elevate EWM as necessary to maintain overbalance.
Steps 6-10 will be permitted under separate PTDs. BJM
Separate Sundry required for post-rig work.
5.j. Perform NFT before before LD BHA. Operations for the GP 31-23 L1 PTD end when liner running BHA is out of the hole. bjm
fluid losses and/or fracturing at the end of the long well bores. A MPD choke for regulating surface pressure is
located between the WC choke manifold and the mud pits and will be independent of the WC choke.
Deployment of the BHA under trapped wellbore pressure will be necessary to maintain constant wellbore pressure.
A TRSSSV in the completion will be used to maintain wellbore pressure during trips to surface. The annular
preventer will act as a secondary containment during deployment and not as a stripper.
Operating parameters and fluid densities will be adjusted based on real-time bottom hole pressure measurements
while drilling. The following is a range in scenarios expected:
x Expected reservoir pressure in L1: 4326 psi (8.0 ppg)
MPD Pressure at the GP31-23 Planned Window (11,016’ MD - 9761’ TVD)
Pumps
On Pumps Off
A Target BHP at Window (ppg) 4,822 psi 4,822 psi
9.5
B Annular friction - ECD (psi/ft) 991 psi 0 psi
0.09
C Mud Hydrostatic (ppg) 3,655 psi 3,655 psi
7.2
B+C 4,646 psi 3,655 psi
(no choke pressure)
A-(B+C) Choke Pressure Required to
Maintain 176 psi 1,167 psi
Target BHP at window and deeper
x High side case in L2: 5476 psi (10.5 ppg)
Pumps
On Pumps Off
A Target BHP at Window (ppg) 4,995 psi 4,995 psi
10.5
B Annular friction - ECD (psi/ft) 926 psi 0 psi
0.09
C Mud Hydrostatic (ppg) 3,425 psi 3,425 psi
7.2
B+C 4,351 psi 3,425 psi
(no choke pressure)
A-(B+C) Choke Pressure Required to
Maintain 644 psi 1,570 psi
Target BHP at window and deeper
Operation Details:
Reservoir Pressure:
x The maximum potential reservoir pressure while drilling will occur ~750’ into Lateral 2. Past injection may
have elevated pressure in this area and it is unknown if it has dissipated. The pressure may be as high as
5476psi at 10062’ TVD (10.5 ppf EMW).
x See Alternative MASP variance request below
x Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 3584 psi.
maximum potential reservoir pressure while drilling will occur ~750’ into Lateral 2.jy
pressure may be as high asp
5476psi at 10062’ TVD (10.5 ppf EMW).
Reservoir pressure at TD is less
than Target BHP for all 8.0 ppg
laterals (L1, L1-01, L2-01). OK.
This max of 3584 psi is assuming the 2/3 gas alternative calc and is calculated for the L2 lateral (not part
of this PTD). The MASP for this PTD is 3285 psi, assuming a full column of gas - bjm
A MPD choke for regulating surface pressure isgg
located between the W C choke manifold and the mud pits
TVD of top of overpressured zone
=9429' TVD
TVD at bottom of overpressured zone
=10955' TVD.
TVD of 10.5 ppg reservoir is deeper
than window, so Target BHP should be
calculated at that TVD, not at window.
TVD at window = 9149' TVD
Annular preventer will not be effective means of secondary containment during deployment because the BOP will not have slip rams sized to hold the
BHA in place. bjm
BHP is > Target BHP in 10.5 ppg
section of the reservoir.
Well will begin to flow if 10.5 ppg
reservoir is encountered.
Confirm calcs with Hilcorp for
L2 lateral. Not relevant for the L1
lateral.
Pressure deployment
GP31-23 MASP
Lateral TVD BHP EMW MASP Alt MASP
feet psi ppg 100% gas 2/3 gas
L1 10407 4326 8.0 3285 2369
L1-01 11371 4731 8.0 3594 2593
L2 10062 5476 10.5 4470 3584
L2-01 10808 4495 8.0 3414 2463
Mud Program:
x Drilling: Minimum MW of 7.2 ppg OBM for drilling. Managed pressure used to maintain constant BHP.
x KWF will be stored on location. The tankage will contain 1.5 wellbore volumes of KWF (9.5 ppg expected)
to exceed the maximum possible BHP to be encountered as the lateral is drilled. Adjust with real time
BHP monitoring.
x Sufficient weighting material will be on location to elevate to KWF to 10.5 ppg if necessary.
x Completion: A minimum MW 9.5 ppg KWF to be used for liner deployment.
Disposal:
x All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field
G&I facility for disposal / beneficial reuse depending on test results
Hole Size:
x 4.25” bicenter hole for entirety of the sidetrack.
Liner Program:
x 2-7/8”, 6.5#, L-80 slotted liner planned for all laterals
x No Cement
Completion
Section
Completion
Size
Length
(ft) Top (ft) Bottom (ft) Type
L1 2-7/8 2731 11,160 13,891 Slotted
L1-01 2-7/8 2250 11,016 13,266 Slotted
L2 2-7/8 3499 10,429 13,928 Slotted
L2-01 2-7/8 2690 10100 12,790 Slotted
Well Control:
x 1.5 wellbore volumes of KWF will be on location at all times during drilling operations.
x 4 Ram BOP diagram is attached. MPD and deployment using the TRSSSV is planned.
x Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 4,000 psi.
x The annular preventer will be tested to 250 psi and 3,500 psi.
x An X-over shall be made up to a 2-3/8” safety joint including a TIW valve for all tubulars ran in hole.
Directional:
x Directional plan attached. Maximum planned hole angle is 91° (L1 lateral)
x Inclination at kick off point is 35° for L1 and 34° for L2.
x Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run.
x Distance to nearest property line – 3,104’
x Distance to nearest well within pool – 0’ (GP 31-23)
Logging:
x MWD directional, Gamma Ray, and Resistivity will be run through the entire open hole section.
x Real time bore pressure to aid in MPD and ECD management.
Managed Pressure Drilling calcs. DLB
100% gas
(See variance request, next page) SFD
2/3 gas
2369
Alt MASP
1.5XWBV=343 bbls
ggp
4 Ram BOP diagram is attached. MPD and deployment using the TRSSSV is planned.
Max TVD
10235'
11180
10955
10808
ppp
An X-over shall be made up to a 2-3/8”safety joint including a TIW valve for all tubulars ran in hole.
Verified calcs as presented, but TVD of the laterals does not
match TVD on directional plan, MASP may be different for
those laterals - bjm
Wellbore capacity of motherbore is 181 bbls. Volume of L1 lateral open hole = 48 bbls.
Perforating:
x No perforating, slotted liner.
Anti-Collision Failures:
x GP 31-23L1 fails AC scan with well GP 32-23. The minimum ctr-ctr distance is 614’. GP32-23 was P&A’d
in 1973 and the close approach in below the lower cement plug. No action to be taken on GP32-23.
x No AC failures for any of the other 3 planned sidetracks.
Hazards:
x Granite Point is not considered a high H2S platform. The highest recorded H2S well on the platform was
from gas lift (2ppm). Drilling sidetracks from GP31-23 has a low H2S risk.
x Medium lost circulation risk. MPD used to minimize overbalance while drilling.
Variance Requests:
x 20 AAC 25.005(c)(4)(A) - The calculated MASP for this wellbore when completely evacuated to gas is
4470 psi. However, for Granite Point Operations, the assumption is that the well can never flow 100% gas.
Using an alternative MASP calculation yields to 3584 psi which assumes that 2/3 of the wellbore is
evacuated to gas and 1/3 to 7.0 ppg reservoir fluid.
x Exemption request to 20 AAC 25.036(c)(2)(A)(iv) - 2-7/8” liner rams in the BOPE. A 2-3/8” safety joint will
be utilized while running 2-7/8” slotted liner. When closing on a 2-3/8” safety joint 2 sets of pipe/slip rams
will be available, above and below the flow cross providing better well control options.
x 20 AAC 25.036(c)(4)(A)(ii) – Factory built coiled tubing units are designed to operate on live wells and
harsh conditions without an accumulator back up system. The coiled tubing unit that will be utilized does
not have an OEM backup accumulator system. The nature of the rig up allows for an air shield between
the wellhead and unit with zero enclosed space. It is possible to install a backup system but will add risk
and complexity to the operating system. It is requested to operate the unit without an accumulator backup
system. The accumulator will have independent primary and secondary power sources.
x 20 AAC 25.036(c)(4)(E)- The coil tubing operations cab will be placed on the drill deck ~120’ away from
the 8’ x 8’ work platform (also on the drill deck) and in direct line of sight of the platform. With line of sight
to the work platform and all equipment located on the same level a second annular closing control will not
be installed.
x 20 AAC 25.036(c)(10)(F) – It is requested that due to the modular nature of the equipment hammer
unions may be utilized on the choke lines downstream from the choke. Only connections with Non-
Pressure seal threads will be used (Figure 1502). Flanged connections will be used from the wellhead to
the choke.
Sean McLaughlin CC: Well File
CTD Engineer Cody Dinger
907-223-6784
evacuated to gas and 1/3 to 7.0 ppg reservoir fluid.
)( )py g
for Granite Point Operations, the assumption is that the well can never flow 100% gas.p,
Using an alternative MASP calculation yields to 3584 psi which assumes that 2/3 of the wellbore is gy
p ,p
Variance is not required. MPSP of 3285 psi < BOP test pressure of 4000 psi, and
does not change API Spec 16ST pressure class of PC-2.
Variance request denied.
Variance request withdrawn. bjm
Variance request withdrawn. bjm
Variance request withdrawn. bjm
Variances required and conditionally approved for 20 AAC 25.036(c)(2)(A)(iii) and 20 AAC 25.036(c)(4)(A)(ii). See conditions of approval
_____________________________________________________________________________________
Revised By: CJD 3/10/2021
PROPOSED
Granite Point Platform
Well: GP 31-23/ L1 / L1-01/ L2 / L2-01
Last Completed: Future
PTD: TBD
JEWELRY DETAIL
No Depth Item
1 350’ TRSSSV
2 2,595’ GLV
3 4,765’ GLV
4 6,364’ GLV
5 7,398’ GLV
6 8,199’ GLV
7 8,916 GLV
8 9,631’ GLV - Orifice
9 9,794’ PBR / Seal Assembly
10 9,809 Tripoint Packer
11 9,885’ X Nipple
12 10,195’ WLEG – Bottom @ ±10,197’
CASING DETAIL
Size Type Wt/ Grade/ Conn ID Top Btm
18" Conductor - N/A Surface 604'
13-3/8" Surface 61 / J-55 / BTC 12.515 Surface 3,933’
9-5/8" Intermediate 40, 43.5 / N-80, S-95 /
BTC, LTC, STC 8.755 Surface 8,062’
7” Liner 29 / P-110 / X-Line 6.184 7,867’ 11,196’
L1: 2-7/8” Slotted Liner 6.5 / L-80 / STL 2.441 ±11,025’ ±13,886’
L1-01: 2-7/8” Slotted Liner 6.5 / L-80 / STL 2.441 ±11,160’ ±13,206’
L2: 2-7/8” Slotted Liner 6.5 / L-80 / STL 2.441 ±10,280’ ±13,929’
L2-01: 2-7/8” Slotted Liner 6.5 / L-80 / STL 2.441 ±9,850’ ±12,790’
TUBING DETAIL
4-1/2" Tubing 12.6 / L-80 / TXP 3.958 ±9,809’ ±10,100’
4-1/2” Tieback 12.6 / L-80 / TXP 3.958 Surface ±9,815
GP 31-23 L2
TD = 13,929’ (MD) / 10,062’ (TVD)
PBTD = 13,929’ (MD) / 10,062’ (TVD)
GP 31-23 L2-01
TD = 12,790’ (MD) / 10,809’ (TVD)
PBTD = 12,790’ (MD) / 10,809’ (TVD)
GP 31-23 L1
TD = 13,450’ (MD) / 10,236’ (TVD)
PBTD = 13,450’ (MD) / 10,236’ (TVD)
GP 31-23 L1-01
TD = 13,206’ (MD) / 11,181’ (TVD)
PBTD = 13,206’ (MD) / 11,181’ (TVD)
Liner Top Billet @10,429’
Liner Top Billet @11,160’
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Well GP31-23 Date
Jacking frame Deck
Flow check line to trip tank
7-1/16" Combi
Kill Line Choke Line
7-1/16" Combi
Drill Deck 4-1/16" Tree x 7-1/16" Riser
18' top tubing spool to drill deck Swab
MPD line in
Master
IA
OA
Wellhead Room
4 Ram BOP Schematic 18-May-21
Drip Pan
7-1/16" 5k Flange X 7" Otis Box
Hydril 7 1/16"
Annular
2-3/8" Pipe/Slips
2-3/8"Pipe/Slips
Blind/Shear
7-1/16"
5 Mud
Cross
2-3/8"x3-1/2" VBR
SHAKER (2)PBDHCRHILCORP CTD FLOW DIAGRAMLEGENDCHOKECAPFILTER/SCREENACCUMULATORVALVELOW PSI LINEHIGH PSI LINECHECK VALVEPSI GAUGELOW PSI CHARGEC PUMPPOPOFFMMMICRO MOTIONRELIEF VALVE LINE20’ VENT4.06” 5K TREEMPD lineCHOKE LINE VALVES FLANGED TO CHOKE2” 1502 HIGH PRESSURE LINES2” 5K PSI CHOKE LINEHOPPERHAND CHOKEHYD CHOKEBLEEDER LINETWS600S PUMP8000 PSICIRC PressureC-PUMPAGITATORANNULAR7.06” CombiINJECTOR HEADTWS600S PUMP8000 PSIMM7.06” CombiMPD AMPD BDrilling Fluid SupplyKWF StorageMMCENTRIFUGETrip Tank
April 12, 2021
Sean McLaughlin
Hilcorp Alaska, LLC
3800 Centerpoint Dr. #1400
Anchorage, AK 99503
E-mail: sean.mclaughlin@hilcorp.com
RE: CTU 1 – Accumulator volume calculations
Dear Mr. McLaughlin:
As requested, please find below the accumulator calculations for the coiled tubing unit planned
for the Granite Point CTD program.
The accumulator should have sufficient usable hydraulic fluid volume (with pumps inoperative)
to close one annular-type preventer, all ram-type preventers from a full-open position, and open
one HCR valve. After closing one annular preventer, all ram-type preventers, and opening one
HCR valve, the remaining pressure shall be 200 psi or more above the minimum recommended
precharge pressure.
Hydril 7-1/16” Annular 3.86 gal to close
TOT 7-1/16” Blind/Shear 3.50 gal to close
TOT 7-1/16” Pipe /Slip 0.70 gal to close
TOT 7-1/16” VBR 0.70 gal to close
TOT 7-1/16” Pipe /Slip 0.70 gal to close
CIW 3 1/8” HCR 0.61 gal to open
Total fluid volume required 10.07 gal
Four 15-gallon (1,000 psi precharge) accumulator bottles are incorporated in the coiled tubing
unit. Total usable volume while maintaining 200 psi above the precharge pressure is 30 gallons.
Regards,
Udo Cassee
General Manager
Test Report for Tenaris BlueCoil 2.375” OD HT-125 0.190” WT with 5/16” E-Line
EG 7.063” Combi BOP Shear & PT Performance Test
Prepared By: Caleb Hudson – FE1
Summary
The following is a review of the results of the shear and pressure test of multiple sections of
2.375” OD Tenaris BlueCoil with E-Line inside by a set of 7.063” Combi BOPs. 4 tests were
performed. The last was a definitive pass after putting the E-Line in tension inside of the test
coil. We sheared at an average of 1900 PSI and held a pressure test for a low of 200-300 PSI
for 5 minutes followed by a high of 5000 PSI for 5 minutes.
Equipment Used
Tenaris BlueCoil CoilTubing 2.375” OD, 0.190” Wall Thickness, HT-125 grade
EG 7.0625” Combi BOP S/N 013-16561R
Sample of 0.3125” Diameter, 0.19 lb/ft monocable E-line
Hydraulic Testing Station with system pressure of 3000 PSI max
Test Setup/Procedure
1) The BlueCoil sample was brought in and a hole drilled above the bottom of the pipe. The
E-line was fed through it and a horseshoe clamp put on to prevent the E-line from being
pulled through. Then a loop formed at the top end with another clamp (refer to picture
below).
2) The BOPs were flooded up with water to the top.
3) The BlueCoil was inserted into the BOPs and suspended a couple of inches from the
bottom so it could drop a little when sheared. The Pipe/Slip rams were closed onto the
coil to hold it in place and the overhead crane was hooked up to the loop and applied
tension to the E-line.
4) The blind/shears were then closed, cutting the pipe and E-line. The shears cut at a
uniform 1900-1950 PSI on the hydraulics system.
5) The hydraulics system was brought up to a pressure of 2500 PSI and then the
blind/shears were locked in to hold that pressure.
6) The pipe/slip rams were opened up.
7) A low PT of 200-300 PSI was performed for 5 minutes with 25 PSI or less loss, with less
than 5 PSI a minute loss.
8) A high PT of 5000 PSI was performed for 5 minutes with 50 PSI or less loss, with less
than 10 PSI a minute loss.
Results
With the E-line in tension, using the pipe/slip rams and the overhead crane, the blind/shear
rams successfully cut the coil and E-line at 1900 PSI, which is over 1000 PSI below our max
applicable pressure. It was a clean cut with nothing staying across the rams. A low PT was held
for 5 minutes with a 15 PSI pressure drop from 330 PSI to 315 PSI. A high was held for 5
minutes with a 24 PSI pressure drop from 5131 PSI to 5107 PSI.
As long as the E-line is held in tension it will be cut much easier and with great reliability and
won’t get pulled across the ram face.
Pressure Test Charts
Test Attempts
Test 1 – Cut Success, PT Fail. The E-line was not held in tension. The pipe and E-line was
successfully cut at 1900 PSI and held a low PT but could not hold a high PT. Upon further
inspection the rubber on the blind/shear ram was previously torn and allowed pressure to leak
by.
Test 2 – Cut Fail, PT Fail. In the second test the E-line was not held in tension and the E-line
was not successfully cut and could not hold the pressure test.
Test 3 – Cut Success, PT Fail. The E-line was not held in tension. It did cut the E-line but part of
it got pulled across the ram face and it could not pass the pressure test.
Test 4 – Cut Success, PT Success. The E-line was pulled into tension and the cut happened at
1900 PSI. Low PT from 330-315 PSI for 5 minutes, and a high PT from 5131-3107 PSI for 5
minutes.
Lessons Learned
It was recommended to us to put the E-line into tension to recreate the real world scenario.
During out tests the only definitive pass was when the true real situation was replicated and the
E-line was put into tension. When the E-line is in tension it creates a much more reliable cut
when the blind/shears are closed.
Granite Point CTD Choke manifold
Revised 2/2015
TRANSMITTAL LETTER CHECKLIST
WELL NAME: ______________________________________
PTD: _____________________________________________
___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional
FIELD: ____________________________ POOL: ______________________________________
Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter
CHECK OPTIONS TEXT FOR APPROVAL LETTER
MULTI
LATERAL
(If last two digits
in API number are
between 60-69)
The permit is for a new wellbore segment of existing well Permit
No. _____________, API No. 50-_______________________.
Production should continue to be reported as a function of the original
API number stated above.
Pilot Hole
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 name (_______________________PH) and API number
(50-_____________________) from records, data and logs acquired for
well (name on permit).
Spacing
Exception
The permit is approved subject to full compliance with 20 AAC 25.055.
Approval to produce/inject is contingent upon issuance of
a conservation order approving a spacing exception.
(_____________________________) as Operator assumes the liability
of any protest to the spacing exception that may occur.
Dry Ditch Sample
All dry ditch sample sets submitted to the AOGCC must be in no greater
than 30' sample intervals from below the permafrost or from where
samples are first caught and 10' sample intervals through target zones.
Non-
Conventional
Well
Please note the following special condition of this permit:
Production or production testing of coal bed methane is not allowed for
well ( ) until after ( )
has designed and implemented a water well testing program to provide
baseline data on water quality and quantity.
(________________________) must contact the AOGCC to obtain
advance approval of such water well testing program.
Well Logging
Requirements
Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types
of well logs to be run. In addition to the well logging program proposed
by (_______________________________) in the attached application,
the following well logs are also required for this well:
Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,
composite curves for well logs run must be submitted to the AOGCC
within 90 days after completion, suspension or abandonment of this
well.
X
733-20072-00-00
X
Granite Point
X
X
221-018
Middle Kenai Oil
GP 31-23L1
167-084
WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:GRANITE PT ST 31-23L1Initial Class/TypeDEV / PENDGeoArea820Unit11954On/Off ShoreOffProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2210180GRANITE PT, MIDDLE KENAI OIL - 280150NA1 Permit fee attachedYes2 Lease number appropriateYes3 Unique well name and numberYes4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes Directional plan view included, no land plat.8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For servNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NA N/A18 Conductor string providedNA N/A - Sidetrack19 Surface casing protects all known USDWsNA N/A - Sidetrack20 CMT vol adequate to circulate on conductor & surf csgNA N/A21 CMT vol adequate to tie-in long string to surf csgNo No. Slotted liner will be run.22 CMT will cover all known productive horizonsYes Need to pressure test production tubing to MPSP23 Casing designs adequate for C, T, B & permafrostYes 1.5 X wellbore volume of fluid and weighting material available on location.24 Adequate tankage or reserve pitNA N/A - Motherbore will not be abandoned25 If a re-drill, has a 10-403 for abandonment been approvedYes Anti-collision analysis included with permit26 Adequate wellbore separation proposedNA N/A - sidetrack27 If diverter required, does it meet regulationsYes Piping schematics attached.28 Drilling fluid program schematic & equip list adequateYes CTD BOP stack meets regs for <5000 psi MPSP29 BOPEs, do they meet regulationYes 5000 psi rated BOP stack30 BOPE press rating appropriate; test to (put psig in comments)Yes Yes31 Choke manifold complies w/API RP-53 (May 84)Yes Yes32 Work will occur without operation shutdownNo No33 Is presence of H2S gas probableNA N/A34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S is not expected. Spartan 151 has H2S sensors and alarms.35 Permit can be issued w/o hydrogen sulfide measuresYes36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA Offshore well but lateral from existing wellbore.38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprDLBDate3/15/2021ApprBJMDate6/7/2021ApprDLBDate3/15/2021AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDatedts 6/8/2021JLC 6/8/2021
