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Home My WebLink About218-028MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, August 18, 2022 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC F-106 MILNE PT UNIT F-106 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 08/18/2022 F-106 50-029-23600-00-00 218-028-0 W SPT 4103 2180280 1500 751 754 750 751 4YRTST P Adam Earl 7/10/2022 Mono-bore injector. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT F-106 Inspection Date: Tubing OA Packer Depth 292 1717 1640 1621IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE220711073752 BBL Pumped:1.9 BBL Returned:2 Thursday, August 18, 2022 Page 1 of 1 9 9 9 9 9 9 9 9 Þ 7HVWGXHZHOO6,VLQFHHDUO\-XQHUHVWDUWLQ-XO\MEU 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Conformance Treatment Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Set Cement Retainer 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Hilcorp Alaska LLC Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 12,505'N/A Casing Collapse Conductor N/A Surface 3,090psi Liner 8,540psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15.W ell Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name: David Haakinson Operations Manager Contact Email: Contact Phone: 777-8343 Date:5/27/2020 Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Tubing MD (ft): dhaakinson@hilcorp.com COMMISSION USE ONLY Authorized Name: See Schematic PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0025509 218-028 50-029-23600-00-00 Length Size 4,148' 12,500' 4,148' 1,320 12,500' MILNE PT UNIT F-106 C.O. 477.05 107'107' 12.6# / L-80 / TXP-SR TVD Burst 5,497' MD 7,023' N/A Tubing Size: 5,750psi 9,020psi 4,139' 4,148' 5,732' 12,505' Tubing Grade: MILNE POINT / SCHRADER BLUFF OIL Liner Top Packer and N/A 5,482 MD / 4,102 TVD and N/A Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. 107'20" 9-5/8" 4-1/2" 5,706' Authorized Signature: 6/2/2020 4-1/2" Perforation Depth MD (ft): See Schematic Perforation Depth TVD (ft): Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 2:52 pm, May 27, 2020 320-215 Chad A Helgeson 2020.05.27 13:49:45 -08'00' DSR-5/27/2020gls 5/28/20 X 10-404 Set Cement Retainer MBE DLB 05/27/2020 Conformance Treatment q C 5/29/2020 dts 5/28/2020 RBDMS HEW 6/4/2020 Conformance Treatment Well: MP F-106 PTD: 218-028 Well Name:MP F-106 API Number: 50-029-23600-00-00 Current Status:Injector (Shut In)Wellwork Unit:(1) SL (2) CTU (3) SL Estimated Start Date:June 2nd, 2020 Estimated Duration:4days Reg.Approval Req’std?N/A Date Reg. Approval Rec’vd:N/A Regulatory Contact:Tom Fouts 777-8398 Permit to Drill Number:218-028 First Call Engineer:David Haakinson (907) 777-8343 (O) (307) 660-4999 (M) Second Call Engineer:Wyatt Rivard (907)-777-8547 (O) (509)-670-8001 (M) AFE Number: WellEZ Entry Required?Yes SBHP: 1,720 psig at 4,000’ TVD | 8.3 PPG EMW MPSP: 1,320 psig (0.1 ppg gas gradient) Max Deviation: 93° at 8,755’ MD Max Dogleg:7°/100’ at 3,816’ MD Last Tag:N/A. Original Drill PBTD @ 12,500’ Minimum ID:3.725” XN Nipple at 5,101’ MD Max Sandface Treatment Pressure: 2,700 psig Max Injection Rate:2,000 BWIPD Brief Well Summary: MP F-106 is a Schrader Bluff injection well drilled and completed in the OA sand. On 8/2/19, an apparent matrix bypass event (MBE) occurred between F-106 and L-46. Early indications of bypassed communication are evident from 6/20/19. In September 2019, an IPROF was completed with no indication of a single ICD contributing to the MBE or confirmation of isolation of the swell packers. CTU followed up by closing individual sleeves beginning at the toe moving uphole with the resultant ICDs #4-10 in the closed position. Over time, L-46’s watercut did improve slightly from 80% to ~60%, but did not drop back to it’s previous 30- 40%. In May 2020, polymer facilities were put in place for F-106, and now the ICDs need to be reopened to support F-107. The MBE between F-106 and L-46 needs to be remediated as well to prevent the watering out of L-46. If the MBE is successfully isolated and proper support reopened to F-106, the net oil benefit is expected to be 200 BOPD Objective: 1) Open ICDs #4-10. 2) Isolate MBE between F-106i and L-46 with cement conformance treatment. Notes: x Prior to the job, only ICDs #1-3 are open. x All ICDs have 3.813” MIN ID and can be shifted. Sleeves are shift-up to close and should take 1,000- 2,000lbs of force to shift. x Cement Conformance Treatment: o Proposal to use 12.0 ppg Fin-Cem to allow for ICD penetration. A four bbl Class G tail will be pumped to assist with compressive strength and to protect against dilution with the source water spacer. Risks: x Exceeding fracture pressure on CTU Job o Do not exceed 800 psig surface injection pressure or 2,000 BWIPD injection rate on source water. On 8/2/19, an apparent matrix bypass event (MBE) occurred between F-106 and L-46 ) Isolate MBE between F-106i and L-46 with cement conformance treatment. Objective: 1) Open ICDs #4-1 e resultant ICDs #4-10 in the closed position. and now the ICDs need to be reopened to support F-107. T polymer facilities were put in place for F-106, Conformance Treatment Well: MP F-106 PTD: 218-028 o Assuming a 0.66 psi/ft fracture gradient, do not exceed 2,700 psig at the sand-face with treatment pressure after accounting for frictional pressures. o The proposed fluid density of the cement is ~12.0 ppg (0.624 psi/ft). With a full column of cement, this leaves approximately 150 psig for treatment pressure until the cement begins to lay horizontally in CT (~15bbls in from surface + CT string reel volume on surface). Once cement hits nozzle, all 20bbls of cement will be in horizontal.DNE 850 psig above circulation pressure assuming Source (Fresh) water flush. x Upsetting the facility: Note that offset producer L-46 may begin producing solids. o Have operations monitor L-46 for solids production while the well. o Shut in L-46 prior to pumping cement. x Cross-flow from ICD #10 to ICDs uphole o After the cement squeeze is pumped, there is a chance of cross-flow between the ICDs. Allowing the cement to partially setup prior to release of the cement retainer should prevent this from occurring. It is a good idea to circulate CTxT backside after un-latching from the retainer and washing on the way out of hole. x Treatment of Incorrect ICD o The injection log of F-106 was not indicative of a MBE through a single ICD. It is possible that multiple ICDs are connected to the conduit through the matrix rock. Most likely, there is communication through the annular space with insufficient swell of the swell packers. x Screen-out of the Cement in the ICD o If plugging of the ICD is encountered, PU CT to release from cement retainer and PU to lay cement in wellbore. Procedure: Slickline & Pump Service 1. RU SL, PT PCE to 250 psig low / 2,500 psig high. 2. Pull MCX injection valve from X-Nipple @ 2,519’ MD. a. Redress and re-pin for reuse after MBE work is complete. 3. RDMO Slickline 4. Leave Well Shut In. CTU & Pumping Unit 5. Restart source water injection on F-106 24 hours prior to CTU arrival. a. Do Not Exceed 800 psig wellhead pressure. b. Document stabilized rate and injection pressures. 6. MIRU CT unit. Ensure BOP test has been completed within the last seven days. a. If BOPE test has not been completed in last 7 days, test BPE to 250 psig low / 2,500 psig high. b. No AOGCC notification required. c. Record BOPE test results on 10-424 form. d. If within the standard 7 day test BOPE test period for Milne Point, a full body test and function test of the rams is sufficient to meet weekly BOPE test requirement. 7. RIH with 2” CTU with CTC, DBPV, Baker Hughes HB3 4-1/2” (3.813” bore) hydraulic shifting tool and tempress agitator. 8. RIH to ICD #4 at 7,784’ MD. Shift sleeve to the open position (shift down to open)Shift ICD 4-10 open . Conformance Treatment Well: MP F-106 PTD: 218-028 9. Repeat step for ICDs #5-10. 10. Flag pipe when landed in the ICD #10 at 12,405’ MD. 11. After stabilized injection pressure change is seen, shut in F-106 injection. 12. POOH to surface to change-out BHA. 13. Confirm that cement mixing unit is ready for pumping. 14. RIH with 2” CTU with CTC, DBPV, and Northern Solutions cement retainer to 11,380’ MD a. (25’ up-hole from flagged pipe at nozzle depth). 15. Once on depth, begin injecting 0.4 BPM source water down CT for baseline injectivity. a. Contact engineering with results for a potential increase in rate. 16. Set Cement Retainer at 11,380’ MD (~20’ up-hole from ICD#10) per pipe flag. 17. Inject down CT string at 0.1 BPM and work pumps up to an equivalent surface pump pressure to pre-retainer set. a. Report results to engineering. b. Document any change in wellhead injection pressure. If no change in injection pressure is seen, re-attempt shifting of ICD to the open position. 18. SD source water injection into F-106. 19. Mix 12.0 ppg Fine Cem Cement Mix and 15.8 ppg Class G. Once cement mixes are at target weights, pump down coiled tubing. a. Max hydrostatic (full vertical column of cement) is anticipated from ~23bbl to 32bbl volume pumped assuming 14,500’ CT Length. Treatment pressure should be minimized to ~150 psig + frictional pressure during this interval. Tentative pump schedules are attached. b. Once cement hits the nozzle, all cement should be in horizontal section.DNE 850 psig above circulation pressure assuming Source (Fresh) water flush. c.Treatment Volumes: i. Source (Fresh) Water Spacer ii. 18 bbls of 12.0 ppg Fine-Cem iii. 4 bbls of 15.8 ppg Class G tail iv. Source (Fresh) Water Spacer d. Volume/Gradient Assumptions: i. Coil Capacity: 2” x 0.156” WT = 0.002768 BBL/F ii. Hole Volumes: 1. 5bbls of annular volume from ICD to the shoe. 2. 30bbls of annular volume back to the swell packer at 11,807’ MD. 3. ~8.5bbls of Surface Reel Volume with 14,500’ of 2” CT. 20. PU and release from cement retainer. 21. Flush CT with source water spacer. Attempt to take all returns to tanks to avoid injecting into the well. Wash on way out of hole. 22. POOH to 2,500’ MD and freeze protect well with 37bbls diesel. 23. RD CTU. 24. Leave injector F-106 Shut in. Slickline 25. RU Slickline. PT PCE to 250 psig Low / 2,500 psig High. retainer at 12380 ft. (gls) Treat ICD #10 12380 ft Conformance Treatment Well: MP F-106 PTD: 218-028 26. Set 4-1/2” MCX injection valve in X-Nipple @ 2,519’ MD. a. Re-run previous MCX injection valve (Serial # NM-15) b. Install 0.75” choke in MCX SSSV. 27. Turn well over to operations to BOL. Function test SSSV. SVS _____________________________________________________________________________________ Revised By: TDF 5/26/2020 PROPOSED Milne Point Unit Well: MPU F-106 PTD: 218-028 API: 50-029-23600-00-00 TD =12,505’ (MD) / TD =4,148’(TVD) 20” KB Elev above MSL: 37.5’ 4-1/2” 6 2 9-5/8” 1 3&4 See ICD & Swell Packer Detail PBTD = 12,500’ (MD) / PBTD =4,148’(TVD) 9-5/8” ‘ES’ Cementer @ 2,426’ 7 4-1/2” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor N/A / X-52 / Weld N/A Surface 107’ N/A 9-5/8" Surface 40 / L-80 / DWC/C 8.75” Surface 5,732’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.85” 5,482’ 12,505’ 0.0149 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / TXP-SR 3.833” Surf 5,497’ 0.0152 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 2,519’ X Nipple MCX injection valve with 0.75” bean and Eq sub installed 9/30/19 3.813 2 5,101’ XN Nipple profile: 3.725” No Go / 3.813 Packing Bore 3 5,487’ 8.26” No-Go Locater on Tieback Assy ([4] - 1” Ported Seal Stem) 3.960 4 5,497’ Tieback Shoe 6.180 Lower Completion 5 5,482’ Liner Top Packer (TVD= 4,108’) - 6 ±12,300’ Cement Retainer - 7 12,500’ WIV (Ball on Seat/ Closed) PBTD OPEN HOLE / CEMENT DETAIL 42" ~270 ft3 12-1/4"Stg 1 – 370 sx Lead / 400 sx Tail Stg 2 – 482 sx Lead / 270 sx Tail (197 bbl surface returns) 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 100’ Max Hole Angle = 93.06° @ 8,565’ MD TREE & WELLHEAD Tree Cameron 4 1/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23600-00-00 Completed by Innovation Depth MD Depth TVD ICD/Swell Packer Detail 5,806’ 4,137’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge 6,198’ 4,134’ Swell Packer –Weatherford Genesis Swell Packer 6,509’ 4,129’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge 6,818’ 4,126’ Swell Packer - Weatherford Genesis Swell Packer 7,170’ 4,137’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge 7,439’ 4,146’ Swell Packer - Weatherford Genesis Swell Packer 7,784’ 4,156’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge 8,261’ 4,158’ Swell Packer - Weatherford Genesis Swell Packer 8,615’ 4,142’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge ( 8,722’ 4,137’ Swell Packer - Weatherford Genesis Swell Packer 9,197’ 4,127’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge 9,459’ 4,132’ Swell Packer - Weatherford Genesis Swell Packer 10,048’ 4,149’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge 10,360’ 4,152’ Swell Packer - Weatherford Genesis Swell Packer 10,753’ 4,141’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge 10,983’ 4,131’ Swell Packer - Weatherford Genesis Swell Packer 11,742’ 4,153’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge 11,807’ 4,154’ Swell Packer - Weatherford Genesis Swell Packer 12,405’ 4,144’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge (Cemented) Cemented lower ICD _____________________________________________________________________________________ DAH 5/26/2020 SCHEMATIC Milne Point Unit Well: MPU F-106 PTD: 218-028 API: 50-029-23600-00-00 TD =12,505’ (MD) / TD =4,148’(TVD) 20” KB Elev above MSL: 37.5’ 4-1/2” 6 2 9-5/8” 1 3 & 4 See ICD & Swell Packer Detail PBTD =12,500’ (MD) / PBTD =4,148’(TVD) 9-5/8” ‘ES’ Cementer @ 2,426’ 4-1/2” 5 CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor N/A / X-52 / Weld N/A Surface 107’ N/A 9-5/8" Surface 40 / L-80 / DWC/C 8.75” Surface 5,732’ 0.0758 4-1/2” Liner 13.5 / L-80 / Hyd 625 3.85” 5,482’ 12,505’ 0.0149 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / TXP-SR 3.833” Surf 5,497’ 0.0152 JEWELRY DETAIL No Top MD Item ID Upper Completion 1 2,519’ X Nipple MCX injection valve with 0.75” bean and Eq sub installed 9/30/19 3.813 2 5,101’ XN Nipple profile: 3.725” No Go / 3.813 Packing Bore 3 5,487’ 8.26” No-Go Locater on Tieback Assy ([4] - 1” Ported Seal Stem) 3.960 4 5,497’ Tieback Shoe 6.180 Lower Completion 5 5,482’ Liner Top Packer (TVD= 4,108’) - 6 12,500’ WIV (Ball on Seat/ Closed) PBTD - OPEN HOLE / CEMENT DETAIL 42" ~270 ft3 12-1/4"Stg 1 – 370 sx Lead / 400 sx Tail Stg 2 – 482 sx Lead / 270 sx Tail (197 bbl surface returns) 8-1/2” Cementless Injection Liner in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 100’ Max Hole Angle = 93.06° @ 8,565’ MD TREE & WELLHEAD Tree Cameron 4 1/16" 5M w/ 4-1/16” 5M Cameron Wing Wellhead Cameron 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API#: 50-029-23600-00-00 Completed by Innovation Depth MD Depth TVD ICD/Swell Packer Detail 5,806’ 4,137’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge 6,198’ 4,134’ Swell Packer –Weatherford Genesis Swell Packer 6,509’ 4,129’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge 6,818’ 4,126’ Swell Packer - Weatherford Genesis Swell Packer 7,170’ 4,137’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge 7,439’ 4,146’ Swell Packer - Weatherford Genesis Swell Packer 7,784’ 4,156’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge (Closed) 8,261’ 4,158’ Swell Packer - Weatherford Genesis Swell Packer 8,615’ 4,142’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge (Closed) 8,722’ 4,137’ Swell Packer - Weatherford Genesis Swell Packer 9,197’ 4,127’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge (Closed) 9,459’ 4,132’ Swell Packer - Weatherford Genesis Swell Packer 10,048’ 4,149’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge (Closed) 10,360’ 4,152’ Swell Packer - Weatherford Genesis Swell Packer 10,753’ 4,141’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge (Closed) 10,983’ 4,131’ Swell Packer - Weatherford Genesis Swell Packer 11,742’ 4,153’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge (Closed) 11,807’ 4,154’ Swell Packer - Weatherford Genesis Swell Packer 12,405’ 4,144’ Halliburton - ICD w/ 250 mesh, (2-0-0 Nozzle) 13.5# bxp 625 Wedge (Closed) CURRENT