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163-011
2025-0608_Surface_Abandon_Sterling_Unit_43-09_jh Page 1 of 3 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 6/8/2025 P. I. Supervisor FROM: Josh Hunt SUBJECT: Surface Abandonment Petroleum Inspector Location Clearance Sterling Unit 43-09 Hilcorp Alaska LLC PTD 1630110; Sundry 319-233 5/20/2025: I traveled to the Sterling Unit (SU) 43-09 location and met with Mike Erstrom representing Hilcorp Alaska LLC. The well had cement in all annuli. I had Mike pound on the cement with a big hammer to verify. At this time, he did not have paperwork on hand but was able to email me the sundry. I checked the information on the marker plate and found some errors in the Well # and API #. I advised him that this needs to be fixed prior to welding the plate on. He then told me that he had surveyors coming at some point to check the cutoff depths. 5/27/2025: I received a few pictures from Mike Erstrom of the well after the survey was completed. It needed cut off a few feet deeper. He assured me the well would be capped and ready when I arrived home from the North Slope. The well was cut off just below the surface conductor. 6/03/2025: I traveled back to location and verified the information on the marker plate was correct and gave them the go ahead to bury this well. 6/8/2025: I traveled back to location for a site clearance after the well was completely buried. Normally there is a mound on top of the well location. The pad was leveled flat above the well. I asked why there was no mound; Mike explained that this location is a current construction area and because they will have a drilling rig coming on location soon, Hilcorp wishes to keep this location level with the pad grade and add material as needed to maximize the usable space. They have to area coned off to keep heavy equipment, vehicles, and people clear. Original ground level around SU 43-09 in 2019 was 223.4 feet. The cut off depth is 219.4 feet putting the cut depth at 4 feet below original grade. Attachments: Photos (3) 2025-0608_Surface_Abandon_Sterling_Unit_43-09_jh Page 2 of 3 Surface Abandonment – Sterling Unit 43-09 (PTD 1630110) Photos by AOGCC Inspector J. Hunt 5/27/2025; 6/3/2025; 6/8/2025 6/3/2025 – Marker plate on casing stub at proper cutoff depth 5/27/2025 – Initial cutoff after excavation (courtesy of Hilcorp) 2025-0608_Surface_Abandon_Sterling_Unit_43-09_jh Page 3 of 3 Site clearance for SU 43-09 6/3/2025 - Marker plate installed on 85/8-inch casing PTD 1630110 Hilcorp Alaska, LLC 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907-777-8300 Fax: 907-777-8580 June 30, 2022 Mr. Chris Wallace, Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Subject: 2021 Annual Disposal Report Sterling Unit 43-09 (DIO 25.001) Dear Mr. Wallace: In accordance with Disposal Injection Order (“DIO”) 25.001 Rule 5, Hilcorp Alaska, LLC hereby submits the annual disposal report for Sterling Unit 43-09 (PTD 163-011) for the year 2021. No disposal fluid was injected into SU 43-09 in 2021. Additionally, this well is currently in the process of being abandoned (Sundry 319-233) and has downhole cement plugs placed in accordance with the approved Sundry. Should you have questions, please contact Josh Allely at 777-8505. Sincerely, Josh Allely Well Integrity Engineer Hilcorp Alaska, LLC June 30, 2020 Mr. Chris Wallace, Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 1U 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: RULE 5, DIO 25.001: SU 43-09 Dear Mr. Wallace: 3800 Centerpolnt Drive Suite 1400 Anchorage, AK 99503 Phone: 907-777-8322 Fax: 907-777-8580 RECEIVE® JUL 0 6 2020 A00GCv Attached please find the report required by Rule 5 of DID 25.001 establishing the DIO for the Class II Water Disposal well SU 43-09 (PTD 163-011) for the calendar year of 2019. Surveillance Summary No fluid was injected into SU 43-09 within the year 2019. A passing mechanical integrity test was performed on the well on 4/4/2019 with the next MIT due in April 2023. Sincerely, Trudi Hallett Reservoir Engineer MEMORANDUM TO: Jim Regg g�l) g P.I. Supervisor FROM: Bob Noble Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: July 18, 2019 SUBJECT: Well Bore Plug & Abandonment Sterling Unit 43-09 Hilcorp PTD 1630110; Sundry 319-233 Section: 9 Township: 5N Range: 10W Drilling Rig: NA Rig Elevation: NA Total Depth: 6202 ft MD Operator Rep: Wade Hudgens Suspend: Casing/Tubing Data (depths are MD): Conductor: O.D. Shoe@ Csg Feet Surface: 8 5/8" O.D. Shoe@ 1,272 Feet Intermediate: O.D. Shoe@ Cut@ Feet Production: 51/2" O.D. Shoe@ 5,380 Feet Liner: O.D. Shoe@ Feet Tubing: 2 3/8" O.D. Tail@ 5250 Feet Plugging Data: Test Data Meridian: Seward Lease No.: FEDA 028063 Type Plug Founded on Casino Removal: Csg Cut@ Feet Csg Cut@ Feet Csg Cut@ Feet Csg Cut@ Feet Csg Cut@ Feet Tbg Cut@ 5234 Feet Type Plug Founded on Depth Btm De th To MW Above Verified Fullbore Bridge plug ' 5,220 ft MD' 5,147 ft MD " Wireline tag Initial 15 min 30 min 45 min Result 5 1/2" csg 2550 2500 - 2500 - I I P Remarks: Tubing was cut anhd pulled and cement plug laid in on bridge plug set at 5220 ft. Tagged with wireline bailer; cement came back somewhat green. Good pressure test. Attachments: none rev. 11-28-18 2019-0718_Plug_Verification_Sterling_43-09_bn THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Sterling Field, Undefined WDSP Pool, SU 43-09 Permit to Drill Number: 163-011 Sundry Number: 319-233 Dear Mr. York: 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 Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this /1-1ay of May, 2019. RBE)mS 0V MAY 15 2019 RECEIVED STATE OF ALASKA MAY 0 8 2019 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AC GCC 20 AAr: 25 91111 1. Type of Request: Abandon Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Venting Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development ❑ Stratigraphic ❑ Service Q' 163-011 3. Address: 3800 Centerpoint Dr, Suite 14006. API Number: Anchorage Alaska 99503 Was Cl• 50-133-10011-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes ❑ No ❑✓ Sterling Unit (SU) 43-09 S � W 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA028063 Sterling Unit / Undefined WDSP 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth ND (ft): Effective Depth MD: Effective Depth ND: MPSP (psi): Plugs (MD): Junk (MD): 6,202' 6,201' 5,337' 5,337' 190 psi N/A N/A Casing Length Size MD ND Burst Collapse Structural Conductor Surface 1,272' 8-5/8" 1,272' 1,272' 2,950 psi 1,370 psi Intermediate Production 5,380' 5-1/2" 5,380' 5,380' 5,320 psi 4,9100 psi Liner Perforation Depth MD (ft): Perforation Depth ND (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 5,262'- 5,272' MO 5,262'- 5,272' ND 2-3/6' 4.7# / J-55 5,250' Packers and SSSV Type: Packers and SSSV MD (ft) and ND (ft): Baker model N Packer 5,241' MD/ND 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic ❑ Development ❑ Service ❑Q 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: June 1, 2019 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned 0 - 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer - hilcoro.com Contact Phone: 777-8420 Authorized Signature: Date: ( 1 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 2 33 ,�,// Plug Integrity BOP Test LIR Mechanical Integrity ❑ Location Clearance ❑ Test Other:*' z j Ol) Pc,i .60 Pgs f-- C6,/ ��� S%L` c s:na ABDMS6/MAY 152019 Post Initial Injection MIT Req'd? Yes ❑ No ❑ �/ 7 Spacing Exception Required? Yes ❑ No Q Subsequent Form Required: / C) -q(3 t7 T APPROVED BY / Approved by. COMMISSIONER THE COMMISSION Date: 57 '-'Jt"1 `7� 1/ S I h f Q ,� �rr � �1 relI � / Xh Submit Form and Form 10-003 Revised 4/2017 Approved applicati s f n date of approval. `/7// //7�r� Attachments in Du icate H H lmo p Alaska, LL Well Prognosis Well: SU 43-09 Date:05/07/2019 Well Name: SU 43-09 API Number: 50-133-20569-00 Current Status: Shut-in Class 2 Disposal/ Injection Well Leg: N/A Estimated Start Date: June 1, 2019 Rig: 401 Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 163-011 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) Second Call Engineer: Bo York (907) 777-8345 (0) (907) 727-9247 (M) AFE Number: Current Bottom Hole Pressure: Maximum Expected BHP: Max. Potential Surface Pressure: Brief Well Summary: - 2,494 psi @ 5,272' TVD - 2,494 psi @ 5,272' TVD 1,966 psi (Based upon a 0.473 psi/ft gradient to the deepest open perforation) (Based upon a normal gradient) (Based upon max. expected BHP and a 0.10 psi/ft gas gradient to surface) Sterling Unit 43-09 was spud in June of 1963 and completed in October 1966. SU 43-09 produced Sterling gas (Sterling Undefined Gas Pool) from 10/66 until 02/98. In 2004, SU 43-09 was converted to a Class 2 injection/ disposal well, with first injection commencing in March 2004. The well was used for disposal from 03/04 through 04/14. SU 43-09 has remained shut-in since April 2014. - Note that SU 43-09 has last been used as a disposal well, so the well/tubing is likely filled with disposal fluids. Since the well initially produced gas from the existing Sterling perforations, the MPSP was calculated assuming a tubing column of gas. The purpose of this Sundry is to permanently P&A SU 43-09. Pre - Rig Work: 1. Provide 24 hour notice to the AOGCC that Plug and Abandonment of well will commence per AOGCC regulations 20 AAC 25.112 (h). Notify the BLM of P&A as per 43 CFR 3160 G. 2. RU Pump Truck. RU on the tubing and casing and conduct an IA pressure test to 2,500 psi on chart for 30 min. Bleed down pressure. Workover Rig 401: 3. MIRURig 401. 4. Notify AOGCC and BLM 24 hours in advance of test to extend the opportunity to witness. 5. Set back pressure valve. 6. ND wellhead, NU 7-1/16" BOP and test to 250 psi low & 2,600 psi high, annular to 250 psi low & 2,500 psi high. Record accumulator pre -charge pressures and chart tests. a. Perform Test. b. Test VBR rams on 2-3/8" test joint. c. Submit completed form 10-424 to AOGCC within 5 days of BOPE test. Copy to BLM. H IIil., Alaska, LU Well Prognosis Well: SU 43-09 Date: 05/07/2019 7. MIRU E -line. Pressure test lubricator to 2,500 psi. 8. PU & RIH w/ Tubing Cutter to —5,240' (iust above Baker model N packer). Cut tubing at same depth & POOH. 9. PU tubing and circulate the hole with 9.8 ppg kill weight fluid. 10. POOH with 2-3/8" tubing strings, racking back. 11. RU E -line. Pressure test lubricator to 2,500 psi. 12. PU & RIH w/ 5-1/2" CIBP to —5,240' (just above tubing stub). Set CIBP at same depth and POOH. 13. PU & RIH w/ Dump Bailer to 5,239'. Dump bail 35' of cement on top of the CIBP. POOH. a. TOC at —5,205'. _ Note: Completion records indicate th t the 5-1/2" Production Casing was cemented with 450 sacks of cement, yielding a calculated top of cement @ 3,300'. Marathon also performed a 100 sack "Top Job", so the Production Casing may have cement behind pipe across the surface casing. No bond log was found to confirm this. Due to the "Top Job", it is uncertain as to whether or not any cement will be able to be placed/circulated between the 5-1/2" and 8-5/8" casing strings. Hilcorp proposes to punch holes in the 5-1/2" casing (below the surface casing shoe and just above the surface CIBP) and attempt to circulate the cement. If circulation can't be achieved, the cement will be placed/spotted via tubing. )5 b- P/zss. � t- 15dZ7 ,,, 5 L A J .-roe--r. 14. PU & RIH w/ 5-1/2" CIBP to 1,400'. Set CIBP at ^'1,400' and POOH. a. Note that this is -128' below the surface casing shoe (@ 1,272'). �U1 15. PU & RIH w/ 1" casing punch to -1,399'. Punch holes in the 5-1/2" casing from 1,399' -1,395'. r POOH. MStc;k 16. RU cement pumps and try to establish communication between the 5-1/2" x 8-5/8" inner annulus and 5-1/2" casing. a. If communication can be established, reverse circulate 250' of cement on top of the CIBP (@ 1,400'), leaving 250' of cement in the IA across the surface casing shoe. Go to Step 21. b. If communication can't be established, proceed to Step 17. 17. PU & RIH w/ 2nd casing punch to -1,150'. Punch holes in the 5-1/2" casing from 1,150' -1,146'. POOH. a. Note that the upper casing punched holes are -122' above the surface casing shoe. 18. PU & RIH w/ 2-3/8" tubing (open ended) to "'1,400'. PU -5'. 19. RU cementers and test lines. Spot a 350' plug of 15.8 ppg cement from 1,400' to 1,050'. 20. Pressure up on well 500 psi for 30 minutes. Bleed down, POOH and WOC. RU E -line. RIH and tag top of cement (TOC). Make sure TOC is at or above 1,150', to ensure at least 100' of cement above the surface casing shoe. 22. PU & RIH with 5-1/2" CIBP to -160'. Set CIBP at "'160' & POOH. 23. PU 31d casing punch and RIH to 159'. Punch holes from 159'- 155'. POOH. 24. RU cementers and circulate cement down the IA and up the 5-1/2" casing, through the holes at V s 159'- 155'. Extend cement plug to surface. WOC. a. If circulation can't be established, PU & RIH with 2-7/8" tubing (open ended) and place a 160' plug of cement from the CIBP (@ ^'160') to surface. POOH and laying down pipe. WOC. 25. Place dry hole tree on well. 26. RDMO Workover Rig 401. Well Prognosis Well: SU 43-09 IIilcara Alaska, LU Date: 05/07/2019 Post - Ria Abandonment Procedures: 27. Excavate cellar, cut off casing 3' below natural GL. 28. Not0L6PGCC and BLM 48hrs in advance. 29. Create well abandonment marker per 20 AAC 25.120 and BLM Onshore Order No. 2 III.G.10. The following e bead=nvelded directly to the marker plate: a. Hilcorp Alaska, LLC b. PTD: 163-011 c. Well Name: SU 43-09 d. API: 50 -133 -10011 -OC 30. Set marker plate per 20 AAC 25.120 and BLM Onshore Order No. 2 III.G.10, collect GPS coordinates. 31. Photo document casing cut-off and Welded Plate install. 32. Backfill excavation, close out location. Attachments: Actual Schematic Proposed Schematic BOPE Schematic RWO Sundry Revision Change Form Hilcora Alaska, LLC 50-133-10011-00-00 163-011 11.7' cxn = 2-3/8" EUE 8rd J-55, EUE 8rd tubing 5,250' ' Otis "A" sliding side -door @ 5,226' ' Otis S-1 nipple @ 5,238' Baker N-1 packer @ 5,241' . Tubing tail @ 5,250' E -line tagged fill at 5,336' MD (2/18/00) Cement plug 5,337' - 5,380' (7/2/63) SU 43-9 (Vertical Hole) 2,422' FSL, 528' FEL Sec. 9, TSN, R1OW, S.M. 3 C 3 c TD MD= 6,202' TVD = 6,201' ACTUAL SCHEMATIC Surface Casino: 8-5/8", 24 ppf, J-55 casing @ 1272' Cmt w/ 450 sks plus 100 sk top -job Production Casing: 5-1/2", 17 ppf, LTC casing @ 5380' J-55: 0'- 3755' N-80: 3755' - 5380' Cmt w/ 550 sks C Calculated cement top = 3,301' assuming 100% excess in5- 1/2" annulus 5 41 Perfs: 5257'(squeezed) 5262'- 5272'(4 spl) 7.625" open hole below shoe @ 5,380' Well Name & Number: Sterling Unit 43-9 Lease: Sterling Unit County or Parish: Kenai Peninsula State: Alaska Count USA Perforations: (MD) 5,262'. 5,272' (ND): 5,261'.5,271' Angle @KOP and Depth: NA Angle/Perfs: 0° KOP ND: NA Date Completed: Spud: June 19, 1963 RKB: 11.7' Revised by: Kevin Skiba Last Revision Date: 1 08108/11 flilcoru Alaska. LLC API: 50-133-1 AOGCC: 163-011 KB -GL: 11.7' Tree cxn = 2-3/8" Tubing Detail: to 5,250' • Baker N-1 pac 'Tubing tail @ E -line tag SU 43-9 (Vertical Hole) 2,422' FSL, 528' FEL Sec. 9, T5N, ROW, S.M. PROPOSED SCHEMATIC TD MD= 6,202' TVD = 6,201' 5 casing @ 1272' is 100 sk top -job L casing @ 5380' 380' nt top = 3,301' zxcess in 7-5/8" x Depth 160' op 1,400' p 5,240' Well Name & Number: Sterling Unit 43-9 Lease: Sterling Unit County or Parish: Kenai Peninsula State: Alaska I Country: USA Perforations: (MD) 5,262' - 5,272' (ND): 5,261' - 5,271' Angle @KOP and Depth: NA Angle/Perfs: 0°1 K0PTVD:J NA Date Completed: Spud: June 19, 1963 1 RKB-1 11.7' Revised by: Paul Winslow Last Revision Date: 1 05107/19 HILCORP ALASKA 7-1/16" 5M BOPE 7-1/16" 5M HYDRIL GK ANNULAR 32" TALL, FLANGE TO FLANGE 7-1/16" 5M LWS DBL GATE BOP DRESSED W/VARIABLE RAMS IN TOP DRESSED W/BLIND RAMS IN BOTTOM FLANGE TO FLANGE 7-1/16" SM DRILLING SPOOL W/2-1/16" SM OUTLETS 18" TALL, FLANGE TO FLANGE —77" TOTAL STACK HEIGHT ANNULAR STYLE BOP SPECS: - 3.30 gallon open chamber volume - 3.86 gallon close chamber volume GATE STYLE BOP SPECS: - 1.45 gallons to close per gate -1.18 gallons to open per gate - 5.45:1 closing ratio -1.93:1 opening ratio HHilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well SU 43-09 (PTD 163-011) Sundry #: XXX -XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first calf' engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By Initials HAK Approved By Initials AOGCC Written Approval Received (Person and Date) Approval: Prepared: Asset Team Operations Manager Date First Call Operations Engineer Date r Y C c0 C d CL LL V m m 0 a w LL 3 V C r0 3 O L H 100,000 10,000 1,000 100 10 1 Jan -2000 HILCORP ALASKA LLC, STERLING UNIT 43-09 (163-011) STERLING, UNDEFINED WDSP Monthly Injection Rates Jan -2005 Jan -2010 Jan -2015 Jan -2020 —r— Injected Gas (MCFM) Injected Water (BOPM) 100,000 1,000 100 10 1 Jan -2025 m A O m m v m 3 0 3 s SPREADSHEET _3630110_SU_43-09_lnject_Curve_W ell_V 120_20190509.xlsx 5/9/2019 7+:7 ii■■I B` aJ ie • I (]I 1 I1 Jan -2005 Jan -2010 Jan -2015 Jan -2020 —r— Injected Gas (MCFM) Injected Water (BOPM) 100,000 1,000 100 10 1 Jan -2025 m A O m m v m 3 0 3 s SPREADSHEET _3630110_SU_43-09_lnject_Curve_W ell_V 120_20190509.xlsx 5/9/2019 /Co 3 - b /1 NT OF United States Department of the Interior to INV 101, r1ppy BUREAU OF LAND MANAGEMENT 1111111We or _ 1 Alaska State Office _ r - 7 4Rc �� C 3*. 222 West Seventh Avenue,#13 F ('�''��a �\ Anchorage, Alaska 99513-7504 http://www.blm.gov/ak APk 1 ' 2018 DIVISION OF OIL AND GAS In Reply Refer To: 3180 (AK930) APR 1 0 2013 Sterling Unit, AA050887' CERTIFIED MAIL 7003 0500 0005 3216 1072 RETURN RECEIPT REQUESTED DECISION Hilcorp Alaska, LLC. SCANNED JUN 2 0 LUlii Dave Wilkins, Senior Vice President 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503-5826 Federal Oil and Gas Unit Terminated Leases Extended The Sterling Unit, located in Kenai, Alaska, was approved as a Federal oil and gas unit, effective July 7, 1961 and currently contains 2,760 acres. There are Federal, State, private, and fee lease ownerships located within the unit boundary and three (3) development wells. Hilcorp Alaska, LLC. (Hilcorp) has been the designated operator for this field since February 2013. Per 43 CFR 3183.4(b), a unit agreement shall remain in effect as long as the public interest requirement is satisfied. Since April 2015, Hilcorp has not produced any unitized substance from this unit in paying quantity. In October 2017, the Bureau of Land Management (BLM) sent a 60-day Notice for Unit Termination to Hilcorp, allowing 60 days from receipt of the letter to commence reworking or drilling operations in the unit. Hilcorp did not respond to the Notice. Therefore,the BLM Authorized Officer has determined the public interest requirement for this unit has not been met. The Federal Sterling Unit Agreement,AA050887,is hereby terminated by the BLM, effective December 15, 2017. The Sterling Unit leases are extended for an additional two (2) years from the unit agreement termination date. • • Hilcorp will continue to be bound by all lease terms, Federal, State, and private. Upon termination or relinquishment of said leases,Hilcorp will assume the responsibility to plug and abandon all wells, reclaim the lease site including pad(s),pipelines and roads, and remediate any environmental concerns to the satisfaction of the surface estate owner, Salamatof Native Association, Inc, and per terms of any Surface Use Agreement between Hilcorp and Salamatof. The existing Federal lease,A028135,will convert to annual rental status, with payment due to the Office of Natural Resources Revenue(ONRR) October 1St Hilcorp will no longer report any production or royalty to the Office of Natural Resources Revenue(ONRR)unless production occurs from the Federal lease A028135. This decision may be appealed to the Interior Board of Land Appeals, Office of the Secretary, in accordance with the regulations contained in the enclosed 43 CFR,Part 4, and Form 1842-1. If an appeal is taken,the notice of appeal must be filed in this office (at the above address)within 30 days from receipt of this decision. The appellant has the burden of showing that the decision appealed from is in error. Failure to file the notice of appeal with the Bureau of Land Management within the time allowed will result in dismissal of the appeal. In order to avoid dismissal of the appeal, there must be strict compliance with the regulations. • L-2--t. W yne . Svejnoha Br Chief of Energy and Minerals Division of Resources Enclosures: 43 CFR,Part 4 and Form 1842-1 cc w/o enclosures: Hilcorp Alaska, LLC Kevin Tabler, Land Manager 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Department of Natural Resources Division of Oil and Gas Chantal Walsh, Director 550 West 7th Avenue, Suite 1100 Anchorage,AK 99501-3563 • • cc w/o enclosures: Cook Inlet Region, Inc. Colleen Miller 725 E. Fireweed Lane, Suite 800 Anchorage, AK 99503 Salamatof Native Association, Inc Chris Monfor, President/CEO PO Box 2682 Kenai,AK 99611 Office of Natural Resources Revenue Diane Germain, Minerals Revenue Specialist MS 63300B PO Box 25165 Denver, CO 80225-0627 1A028063 A028135 AA050887A/B/C • 3 G AkivEtVLD Hilcorp Alaska, LLC 3800 Centerpoint Drive MAR 3 1 ?O1? Suite 1400 Anchorage,AK 99503 AUGi Phone: 907-777-8322 Fax: 907-777-8580 January 30, 2017 Ms. Cathy P. Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: RULE 5, DIO 25.001: SU 43-09 %ANNE) ` � `120 Dear Ms. Foerster: Attached please find the report required by Rule 5 of DIO 25.001 establishing the DIO for the Class II Water Disposal well SU 43-09 (PTD 163-011) for the calendar year of 2016. Surveillance Summary No fluid was injected into SU 43-09 within the year 2016. A passing mechanical integrity test was performed on the well on 5/10/2016. Sincerely, /006, krivijt Trudi Hallett Jim Young Reservoir Engineer Reservoir Engineer • • Alaska Asset Team /A x Marathon P.O. Box 196168 Alaska Production LLC Anchorage. AK 99519-6168 Telephone 907/561 -5311 Fax 907/565 -3078 June 26, 2012 Attn: Jim Regg 0000v Alaska Oil & Gas Conservation Commission 333 W. 7 Avenue, Suite 100 g Nnr Anchorage, AK 99501 Q3A 1 wia Reference: Report on Disposal Injection Operations Well Sterling Unit 43 -09, Sterling Unit Permit to drill #163 -011 • Val 8 2U`iZ Dear Mr. Regg, 4 Well Sterling Unit 43 -09 (SU 43 -09) is governed by Disposal Injection Order (DIO) No. 25, revised on May 31, 2011. This report covers disposal injection operations for SU 43 -09 from January 1, 2011 until December 31, 2011. Fluid injected into SU 43 -09 is typically produced water originating from the Sterling Unit 32 -9 well. No drilling mud slurries have been injected to date. The last mechanical integrity test on SU 43 -09 was conducted on May 4th 2011 and the next test is due by May 4 2015. Attached are three graphs showing injection volume, injection pressure, and inner annulus pressure for SU 43 -09 in 2011. As shown from these graphs and the accompanying summary, injection volume for SU 43 -09 averaged <2 bwpd throughout 2011, for a total of 545 bbls of fluid injected during the calendar year. Please contact me with any questions at 713 -296 -2541. Sincerely, ir T usan B. Miller Acting NAPO Regulatory Compliance Manager • Marathon Alaska Productii7T l LC June 26, 2012 Report on Disposal injection Operations Page 2 of 4 Well SU 43 -09, Sterling Unit Injection pressures (daily average, maximum and minimum) Injection Injection Injection Year Pressure, Pressure, Pressure, Average (psig Maximum (psig) Minimum (psig) 2011 21 1221 0 SU 43 -9 Injection Pressure (2011) 1400 —__ f ^ - ..Tubing Pressure Average (psig) 1200 _ — — — -- ....Tubing Pressure Maximum (ps,gj 9i 1333 1 a _ _ i a e 600 _._ _ __ — _.. —.__ _ _ _____ _._. - -- -__ - -_ _._.- _---- -- _— _ .Q 5 400 200 - - -- — — — —_ ------ -- 0 _ _ ._.-_________ ___ ---- 1 ti~ tit ti~ 1 1 1 1 1 1 �1 ~~ 1, 1 4. F�� �a� PQ "., 1JC , J� PJb „eQ 0' 4/. • • Marathon Alaska Production LLC June 26, 2012 Report on Disposal Injection Operations Page 3 of 4 Well SU 43 -09, Sterling Unit Annuli pressures (daily average, maximum and minimum) Inner Annulus Inner Annulus Inner Annulus Year Pressure, Pressure, Pressure, Average (psig) Maximum (psig) Minimum (psig) 2011 152 205 25 SU 43 -9 Annuli Pressure (2011) -.rte- Annulus Pressure Average tpsigt —111— Annulus Pressure Maxim =,n - t,psig{ 200 _ — • a N — a -� N N k a 100 _._.._ a a Q 50 — -- -_. _ _. __ rt.._ - ------ - -_Y. __ . _ 0 _ ~ ~ ~ ~ 1 ~ , '0‘. ~ ~ O O O O O1 O O 1 1 0 4 O 1 ti ti ti 1 7 ti la F¢ 4a , 4 a l`) 1J PJ h e p / O ¢ The outer annulus showed negligible pressure throughout 2011. Marathon Alaska Productii'LLC June 26, 2012 • Report on Disposal Injection Operations Page 4 of 4 Well SU 43 -09, Sterling Unit Fluid volumes injected (disposal and clean sweeps) Year Fluid Volumes Injected, (bbl) 2011 545 SU 43 -9 Injection Volume (2011) 129.100 - _ _- �. 500 129.330 -i -Total Cummulatis,e rjectton Volume �bbli 128.900 -0- -Total Injection Volume, Month (bblin•+onthl 400 128.830 .^3 e, 128,700 s 0 333 o 128,603 128.500 — — 2 200 E 128.433 - -- —_ - — -- Aft c 128,300 128.200 i30 '41 128.139 128.0'00 -- - - - -- ^1 ti N ti t ti t. tiN ti ti~ �.. �ti �N ti %. ti la keo 4‘ac P Q� �a� � ��� P °Ie ') oc` 431' peu Fracture Geometry and Zone of Influence In 2002 BJ Services was contracted to model the hydraulic fracture potential of the SU 43 -09 disposal operation in the Sterling B4 sand. This study yielded an initial fracture pressure estimated at 4436 psi. Currently this well operates under minimal use and at low injectivity pressures and rates. With the data listed in this report showing average injection pressures of 20psi, we believe the injected fluids are being lost to leak off. Without fracturing there is no concern or indication of fluids migrating out of the target zone. . • • AOGCC Docket 10 -12 MIT Test Anniversary Dates Marathon Oil Company Request Dated May 26, 2010 . t ,� .. E .-; � ZQ'('; Background Marathon requested changing the anniversary dates of eight Kenai Peninsula injection wells to allow the mechanical integrity test (MIT) required by regulation/order to be performed during summer months. Marathon proposed the wells be adjusted to show a September 1 anniversary date. Action Marathon's email request dated May 26, 2010 followed several telephone discussions between Kevin Skiba (Marathon; 907 - 283 -1371) and Jim Regg (AOGCC; 907 - 793 - 1236). Subsequent to the email request, telephone discussions were held on June 1, 2010, February 7, 2011 and February 8, 2011. Mr. Skiba was told that the following during discussions: - MIT due date can be changed by simply scheduling the test during the summer months; - Tests must be completed in advance of the next due date; - Make sure to give AOGCC Inspectors the required advance notice to allow for opportunity to witness; AOGCC witness is required to adjust the anniversary date; - Industry Guidance Bulletin 10 -002 provides details about testing injectors for mechanical integrity. Marathon was told the proposed September 1 anniversary date would not work for all wells since some MITs would be performed later than the currently required anniversary date. Resulting from the guidance provided to Marathon, the anniversary date for each of the eight injection wells has been changed based on successful, witnessed MITs as shown below: Well PTD MIT Completed Next MIT Due Beaver Creek Unit 2 1670260 5/4/2011 5/4/2015 Kenai Beluga Unit 23x -6 1841090 5/25/2011 5/25/2015 Kenai Unit 11 -17 1811760 5/3/2011 5/3/2013 Kenai Unit 12 -17 2080890 5/3/2011 5/3/2013 Kenai Unit 24 -07RD 2050990 5/3/2011 5/3/2015 Kenai Unit 31 -7X 2001480 5/25/2011 5/25/2015 Kenai Unit WD -1 1811070 5/3/2011 5/3/2015 r io> Sterling Unit 43 -09 1630110 5/4/2011 5/4/2015 With MITs completed on these wells during May 2011, Docket 10 -12 can be closed. ---- -------- 7 --- ; - r - James B. Regg / f ° October 6, 2011 • Colombie, Jody J (DOA) From: Regg, James B (DOA) Sent: Wednesday, May 26, 2010 11:25 AM To: Colombie, Jody J (DOA) Subject: FW: MIT tests anniversary date setup Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907 - 793 -1236 From: Skiba, Kevin J. [mailto:kskiba @marathonoil.com] Sent: Wednesday, May 26, 2010 11:10 AM To: Regg, James B (DOA) Subject: MIT tests anniversary date setup Jim, Below is a list of Marathon Alaska's injection well MIT dates. Well Last test Frequency Next test BC -2 1/15/08 4 -year 1/15/12 KBU 23x -6 6/4/07 4 -year 6/4/11 KU 11 -17 5/12/10 1 -year 5/12/11 KU12 -17 8/27/09 2 -year. 8/27/11 KU 24 -7RD 2/12/10 2 -year 2/12/12 KU 31 -7x 8/8/07 4 -year 8/8/11 SU 43 -9 5/13/09 2 -year 5/13/11 WD -1 5/12/10 4 -years 5/12/14 As per our telephone conversation, we would like to set up an anniversary date for the MIT tests on these wells. As stated, the anniversary date would allow us to complete the MIT tests in the summer months without having the forward movement affect on the test dates. With that said, we are interested in a September 1 date as the anniversary date. Please let me know if you need any additional information concerning this request. Thanks again, Kevin Skiba Regulatory Compliance Representative Marathon Alaska Production LLC 1 Office (907) 283 -1371 Cell (907) 394 -1880 Fax (907) 283 -1350 2 • • CO C-7 of / sEANPARNELLGovERNoR ALASKA OIL A/VD GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COM1 IISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 ADMINISTRATIVE APPROVAL NO. DIO 25.001 Mr. Kevin Skiba Regulatory Compliance Representative Marathon Alaska Production LLC P.O. Box 1949 Kenai, AK 99611 � ��' ..lr.! '6 2111 Re: Mechanical Integrity Test Time Interval Revision DIO 25 — Sterling Unit 43 -09 (1630110) Dear Mr. Skiba: Marathon submitted an Application for Sundry Approvals (Form 10 -403) dated April 11, 2011 requesting the 2 -year Mechanical Integrity Test (MIT) interval in Rule 3 of Disposal Injection Order (DIO) 25 be changed to the standard 4 -year test interval contained in 20 AAC 25.252 (d). Since the MIT interval is set forth in a Commission order, Marathon's request cannot be granted via Sundry Approval. The Commission will treat the request as an application for administrative approval under Rule 7 of DIO 25. Marathon's request to change the MIT interval is GRANTED. This request is granted based upon Marathon's representation that no solids -laden fluids have been injected into the well to date and that it has no plans to inject solids into this well. In addition, the Commission has revised the text of Rules 3, 4 and 5 to conform to the integrity requirements incorporated into more recent injection orders. NOW, THEREFORE, as provided by Rule 7 of DIO 25, Rules 3, 4 and 5 are revised as follows: RULE 3: Demonstration of Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, and before returning a well to service following a workover affecting mechanical integrity. After injection is commenced for the first time in a well, when injection conditions (temperature, pressure, rate, etc.) have stabilized, a Commission - witnessed MIT must be performed. Subsequent tests must be performed at least once every four years (except at least once every two years for a slurry injection well). The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing /casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi /ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. Results of mechanical integrity tests must be readily available for Commission inspection. DIO 25.001 • • May 31, 2011 Page 2 of 3 RULE 4: Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by the injection rate, an operating pressure observation, a test, a survey, a log, or any other evidence, the operator shall immediately notify the Commission, obtain Commission approval to continue injection and submit a plan of corrective action on Form 10 -403 for Commission approval. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating any well integrity failure or lack of injection zone isolation. RULE 5: Surveillance The operator shall run a baseline temperature log and perform a baseline step -rate test prior to initial injection. A subsequent temperature log must be run one month after injection begins to delineate the receiving zone of the injected fluids. Surface pressures and rates must be monitored continuously during injection for any indications of anomalous conditions. Results of daily wellhead pressure observations in the injection well must be documented and available to the Commission upon request. The conduct of subsequent temperature surveys or other surveillance logging (e.g., water flow; acoustic) will be based on the results of the initial and follow -up temperature surveys and injection performance monitoring data. A report evaluating the performance of the disposal operation must be submitted to the Commission by July 1 of each year. The report shall include data sufficient to characterize the disposal operation, including, among other information, the following: injection and annuli pressures (daily average, maximum and minimum); fluid volumes injected (disposal and clean fluid sweeps); injection rates; an assessment of fracture geometry; a description of any anomalous injection results; and a calculated zone of influence for the injection fluids. Except as otherwise specifically modified herein, the statutes and regulations of the Commission, as well as the provisions of DIO 25, remain in full force and t. DONE at Anchorage, Alaska and • . ted ■ a , , 01 . Daniel T. Se- ount, Jr. lzpr 1W "Norman Cathy '. Fo -rster Chair, Co missioner ommis • : er Com issioner ` e,IL � Ott !�'" O • et DIO 25.001 • • May 31,2011 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • • Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton President 408 18 Street 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Circle P.O. Box 69 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 g 'il \1C1\' e\o' • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Thursday, June 02, 2011 10:04 AM To: Campbell, Rianne A (DOA); 'Aaron Gluzman'; 'Ben Greene'; Bruno, Jeff J (PCO); 'CA Underwood'; 'Dale Hoffman'; 'David Lenig'; 'Donna Vukich'; 'Elizabeth Bluemink'; 'Eric Lidji'; 'Gary Orr; Heusser, Heather A (DNR); 'Jason Bergerson'; 'Joe Longo'; King, Kathleen J (DNR); 'Lara Coates'; 'Lois Epstein'; 'Marc Kuck'; 'Marie Steele'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; Ostrovsky, Larry Z (DNR); 'Patricia Bettis'; 'Richard Garrard'; 'Ryan Daniel 'Sandra Lemke'; 'Talib Syed'; 'Wayne Wooster'; 'Wendy Wollf; 'William Van Dyke'; '( michael .j.nelson @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWelllntegrityCoordinator'; 'Alan Dennis'; 'alaska @petrocalc.com; 'Anna Raff; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer'; 'Bill Penrose'; 'Bill Walker'; 'Bowen Roberts'; 'Brady, Jerry L'; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce Webb'; 'Chris Gay'; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Matthews; 'David Boelens'; 'David House'; 'David Scott'; 'David Steingreaber'; 'ddonkel @cfl.rr.com'; 'Dennis Steffy'; 'Elowe, Kristin'; 'Erika Denman'; 'eyancy'; 'Francis S. Sommer; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Schultz (gary.schultz @alaska.gov); 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jeffery B. Jones (jeff.jones @alaska.gov)'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John Katz (john.katz @alaska.gov); 'John S. Haworth'; 'John Spain'; 'John Tower'; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant (Iaura.gregersen @alaska.gov)'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer (meg.kremer @alaska.gov)'; 'Michael Dammeyer; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover'; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; 'Rena Delbridge'; 'Renan Yanish'; ' rob.g.dragnich @exxonmobil.com'; 'Robert Brelsford'; 'Robert Campbell'; 'Rudy Brueggeman'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothart (steve.moothart@alaska.gov)'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler'; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjr1 ; 'Vicki Irwin'; 'Walter Featherly'; 'Will Chinn'; Williamson, Mary J (DNR); 'Yereth Rosen'; Aubert, Winton G (DOA) (winton.aubert @alaska.gov); Ballantine, Tab A (LAW); Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov); Colombie, Jody J (DOA) (jody.colombie @alaska.gov); Crisp, John H (DOA) (john.crisp @alaska.gov); Davies, Stephen F (DOA) (steve.davies @alaska.gov); Foerster, Catherine P (DOA) (cathy.foerster @alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi @alaska.gov); Herrera, Matt F (DOA); Johnson, Elaine M (DOA) (elaine.johnson @alaska.gov); Jones, Jeffery B (DOA) (jeff.jones @alaska.gov); Laasch, Linda K (DOA) (Iinda.laasch @alaska.gov); Maunder, Thomas E (DOA) (tom. maunder @alaska.gov); McIver, Bren (DOA) (bren.mciver @alaska.gov); McMains, Stephen E (DOA) (steve.mcmains @alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.noble @alaska.gov); Norman, John K (DOA) (John.norman @alaska.gov); Okland, Howard D (DOA) (howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) ( tracie.paladijczuk @alaska.gov); Pasqua!, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA) (jim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saltmarsh, Arthur C (DOA) (art.saltmarsh @alaska.gov); Scheve, Charles M (DOA) (chuck.scheve @alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov); Seamount, Dan T (DOA) (dan.seamount @alaska.gov) Subject: dio25 -001 Sterling Unit Attachments: dio25 -001. pdf Swvvtrx f fisher 1 • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission ( DATE: Friday, May 27, 2011 TO: Jim Regg C 5) 27 ' P.I. Supervisor 't SUBJECT: Mechanical Integrity Tests MARATHON OIL CO 43 -09 FROM: John Crisp STERLING UNIT 43 -09 Petroleum Inspector Src: Inspector Reviewed By: P.I.Suprv ice' NON - CONFIDENTIAL Comm Well Name: STERLING UNIT 43 - 09 API Well Number: 50 133 - 10011 - 00 - 00 Inspector Name: John Crisp Insp Num: mitJCr110505143349 Permit Number: 163 - 011 - Inspection Date: 5/4/2011 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 1 43 -09 'Type Inj. j W ` TVD 5241 IA 140 1630 , 1560 1520 , I 1490 P. 1 rTypeTest SPT I Test psi ' 1500 OA 0 0 0 0 ---1- o Interval OTI ' Tubing i 920 970 1 1065 1100 1140 Notes: 27 gal 80/20 methanol pumped for MIT. Production pumped into this well approximately 1 hour prior to our MIT IA. Well show no pressure stabilization. 2 year MIT required per DIO 25. MOLL) JuN: I, 2U31 Friday, May 27, 2011 Page 1 of 1 • • p m l C —tom( SU 43 -9 API: 50. 133- 10011 -00 -00 AOGCC: 163-011 (Vertical Hole) 2,422' FSL, 528' FEL KB - GL: 11.7' Sec. 9, T5N, R10W, S.M. MARATNON Tree cxn = 2 -3/8" EUE 8rd Surface Casing: 8 -5/8 ", 24 ppf, J -55 casing @ 1272' ° Cmt w/ 450 sks plus 100 sk top -job Production Casing: 5 -1/2 ", 17 ppf, LTC casing @ 5380' J -55: 0' - 3755' N -80: 3755' - 5380' Cmt w/ 550 sks Tubing Detail: 2 -3/8 ", 4.7 ppf, J -55, EUE 8rd tubing to 5,250' Otis "A" sliding side -door @ 5,226' Otis S -1 nipple @ 5,238' Baker N -1 packer @ 5,241' S yi d -rep 4 Tubing tail @ 5,250' Calculated cement top = 3,301' assuming 100% excess in 7 -5/8" x 5- 1/2" annulus 1 Perfs: If= 5257' (squeezed) fiC 5262' - 5272' (4 spf) E -line tagged fill at 5,336' MD (2/18/00) Cement plug 5,337' - 5,380' (7/2/63) y *' 7.625" open hole below shoe © 5,380' TD MD= 6,202' TVD = 6,201' Well Name & Number: Sterling Unit 43 -9 Lease: Sterling Unit County or Parish: Kenai Peninsula State: Alaska 1 Country:I USA Perforations: (MD) 5,262' - 5,272' (TVD): 5,261' - 5,271' Angle ©KOP and Depth: NA Angle /Perfs: 0° KOP TVD:J NA Date Completed: Spud: June 19, 1963 RKB: 11.7' Revised by: Kevin Skiba Last Revision Date: 08/08/11 • (: t 117n 11 1 1:57.7' P+i9' t00 ps, • (4/19/2011 12:15 :13 AM) 179 psi .1 psi (62 days, 23.18:00) 100 1000 1000 2G00 • • i 0 0 0 2/1/2011 2/19/2011 3/9/2011 3/27/2011 4/14/2011 5/2/2011 12:06:13 PM 11:54:73 AM 11:42:13 AM 12:30:13 PM 12:18:13 PM 12:06:13 PM T Name t 8� j Server Cara 1 Units l (- t } 10addre.,s 1 Time offset I STR Injection Wet 43-9 Inner Casing Pressure KGFR5969 +Oar ,0 psi 0 1000 11KGFR5 %911nSQL MD... 0:00:00.... El AK SIR W eA 43 9.CSG Outer PT STR Injection WeA 43.9 Otter Cask %) Pressure KGFRS969 psi 0 100 11KGFR5969jln5QL MD.,. 0:00:00.... ® Ad' AK_STR W ell_43 9.FlowRete STR Injection Well 43 -9 Injection Flow Rate KGFR5969 BPD 0 1000 11KGFR596911nSQL MD... 0:00:00.... El G.I AK STR WeA 43_9.TBG PT STR Injection Wet 43 -9 Tubing Pressure KGFRS969 psi 0 1000 11KGFR596911n5QL MD.., 0:00:00.... ®{ AK_STR We t_43 9. TBG TT STR Injection Wet 43-9 Tubing Temp KGPR5969 2d of 0 100 11KGFR5%9jIn5QL MD... 0:00:00,... 0 fi+ AK STR W et 43 9.TVol STR Injection Wet 43-9 Today's Total Injection KGFRS969 BBLS 0 2000 ® AK_STRWell 43 9.Wol STR Injection Wet 43-9 Yesterday's Total Injection 11KGFRS96911n5QL MD... 0:00:00.... !action KGFRS %9 � WS 0 2 000 11KGFR5 9691InSQLMD.., 0:00:00.... l(c;5- of l • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Friday, May 27, 2011 TO: Jim Rem t 5 P.I. Supervisor Z SUBJECT: Mechanical Integrity Tests MARATHON OIL CO 43 -09 FROM: John Crisp STERLING UNIT 43 -09 Petroleum Inspector Src: Inspector Reviewed B pii pp�� P.I.Supry \1 NON- CONFIDENTIAL Comm Well Name: STERLING UNIT 43 - 09 API Well Number: 50 - 133 - 10011 - 00 - 00 Inspector Name: John Crisp Insp Num: mi0Cr110505143837 Permit Number: 163 - 011 - Inspection Date: 5/4/2011 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. We1l7 4349 Type Inj. W TVD 5241 ' IA i 1490 1630 - 1610 1600 P.T.D 1630110 ' ITypeTest SPT Test psi j 1500 - OA 0 0 0 0 Interval OTHER p/F P Tubing 1140 1180 1180 1210 Notes: 2 gal pumped for this retest MIT. Retest showed pressure stabilization of IA without stable tubing pressure. Jim Regg will make pass /fail determination. Jim Regg determined test was a pass. A i , t 20 Friday, May 27, 2011 Page 1 of 1 • • Marathon Alaska Production LLC Alaska Asset Team M Marathon P.O. Box 1949 MARATHON Alaska Production LLC Kenai, AK 99611 Telephone 907/283 -1371 Fax 907/283 -1350 April 11, 2011 RECEIVED Mr. Winton Aubert Alaska Oil & Gas Conservation Commission APR 13 2U1± 333 W 7 Ave Anchorage, Alaska 99501 Wm IN &fias Caw &mission .i3 Reference: 10 -403 Application for Sundry Approvals �b Field: Sterling Unit Well: Sterling Unit 43 -9 siulthiNED JUN 46 2 2011 Dear Mr. Aubert: Submitted for your approval is the10 -403 Application for Sundry Approvals for SU 43 -9 well. Marathon request that the MIT test schedule be converted from its present 2 -year cycle to a 4 -year testing cycle keeping it consistent with requirements stated in Section -D of 20 AAC 25.252. Please contact me at (907) 283 -1371 if you have any questions or need additional information. Sincerely, -4 e—e/U11- 4-1- r / 4-1)-41% Kevin J. Skiba Regulatory Compliance Representative Enclosures: 10 -403 Application for Sundry Approvals cc: AOGCC Current Well Schematic Houston Well File • Summary of Proposal Kenai Well File KJS STATE OF ALASKA '/ ALASKA OIL GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS A1sa Oil &fias Can mission 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair well ❑ Ch ng.Vi5t a� =' cgram El Suspend ❑ Plug Perforations ❑ Perforate [I] Pull Tubing El ea ime Extension ❑ Operational shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter casing ❑ Conver o ��� y ////// r, % IT test cycle El 2. Operator Name: 4. Current Well Class: 5. Pe Drill lumber: Marathon Alaska Production LLC Development Ex lorato ❑ Exploratory ❑ 163 -011 3. Address: PO Box 1949 Stratigraphic ❑ Service ❑ 6. A u x.er: Kenai Alaska, 99611 -1949 /50- 133 - 10011 -00 -00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Nurfst3�r: \/ property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No �� eriing Unit 43 -9 9. Property Designation (Lease Number): 10. Field /Pool(s): FED A - 028063 S ti g . nit . ndefined WDSP 11. PRESENT WELL CONDITION SUMM t RY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth T' i ft): • (r�e ured): Junk (measured): 6,202' 6,201' 5,337' 5,336 \ 1 5,337' NA Casing I Length Size MD V Burst Collapse Structural Conductor Surface 1,260' 8 - 5/8" 1,272' 1,272' 2,950 psi 1,370 psi Intermediate Production 3,743' 5 -1/2" I \ 3,754' 5,320 psi 4,910 psi Production I 1,625' 5 -1 / 2 " 5,379' I 7,740 psi 6,290 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): u.'n iz • Tubing Grade: Tubing MD (ft): 5,262' 5,272' 5,261' 5,271' - 8" J - 55 5,250' Packers and SSSV Type: SSSV: NA 'ack: an S MD (ft) and TVD (ft): NA NA Packers: Baker N - 1 52,41' 5,240' 12. Attachments: Description Summary of Proposal 0 \3. Class after proposed work: Detailed Operations Program ❑ BOP Sketch orato ❑ oratory ❑ Development ❑ Service 0 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: Oil ❑ Gas ❑ WDSPL 0 Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and corr ct to the best of my knowledge. Contact Kevin Skiba (907) 283 -1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Representative Si na ture Date 9 (907) 283 - 1371 April 11, 2011 COMMISSION USE ONLY �f 2onditions of approval: Notify Com . • .sion so that a representative may witness Sundry Number: ' ) ( I A ' lug Integrity ❑ :•P Test ❑ Mechanical Integrity Test 11 Location Clearance ❑ Jther: subsequent For 'equired: APPROVED BY a pproved by: hiBr 11AS JUN 0 2 Z01�O MMISSIONER THE COMMISSION Date: ORIGINAL Form 10 -403 Revised 1/2010 Submit in Duplicate • • April 8, 2011 M MARATHON Marathon Oil Corporation Field: Sterling Unit SU 43 -9 Convert to 4 -year MIT Test Schedule Well Status: Class -2 Injection Well Objective: Convert MIT test schedule from 2 -year to 4 -year test cycle History: The last MIT test was perfonned on May 13, 2009. Rule -3 of the DIO #25 states that an MIT test must be performed every two years as listed below. 20 AAC 25.252 states that an MIT test must be performed every four years. Disposal Injection Order No. 25 Correspondence dated January 24, 2003 to the Alaska Oil and Gas Conservation Commission RULE 3: Demonstration of Tubing/Casinq Annulus Mechanical Integrity Within 180 days of initiating disposal service, the Commission must be contacted to allow a representative of the Commission to witness an additional mechanical integrity test in SU 43-9. In addition to the requirements of 20 AAC 25.252 (d), mechanical integrity of the disposal well must be demonstrated at least once every two years. 20 AAC 25.252. Underground disposal of oil field wastes and underground storage of hydrocarbons (d) The mechanical integrity of a disposal or storage well must be demonstrated under 20 AAC 25.412 before disposal or storage operations are begun, after a well workover affecting mechanical integrity is conducted, and at least once every four years. Request:, Marathon requests that the MIT test schedule, for SU 43 -9, be converted to a 4 -year cycle from its present 2 -year cycle keeping it consistent with requirements stated in Section -D of 20 AAC 25.252. SU 43 -9 is only used for the disposal of produced water. It has consistently past previously MIT tests confirming its integrity. Conversion to a 4 -years schedule would place the next MIT test date as May 13, 2013. • • . • API: 50- 133- 10011 -00 -00 SU 43 -9 AOGCC: 163 -011 (Vertical Hole) 2,422' FSL, 528' FEL KB -GL: 11.7' Sec. 9, T5N, R1OW, S.M. MARAT110 Tree cxn = 2 -3/8" EUE 8rd Surface Casing: 8 -5/8 ", 24 ppf, J -55 casing @ 1272' _ Cmt w/ 450 sks plus 100 sk top -job Production Casing: 5 -1/2 ", 17 ppf, LTC casing @ 5380' J -55: 0' - 3755' N -80: 3755' - 5380' Cmt w/ 550 sks Tubing Detail 2 -3/8 ", 4.7 ppf, J -55, EUE 8rd tubing to 5,250' * Otis "A" sliding side -door @ 5,226' * Otis S -1 nipple @ 5,238' * Baker N -1 packer @ 5,241' * Tubing tail @ 5,250' Calculated cement top = 3,301' assuming 100% excess in 7 -5/8" x 5- '� 1/2" annulus $r ' , 1 1 Perfs: 5257' (squeezed) __= 5262' - 5272' (4 spf) E -line tagged fill at 5,336' MD (2/18/00) Cement plug 5,337' - 5,380' (7/2/63) lilr 7.625" open hole below shoe @ 5,380 TD MD= 6,202' TVD = 6,201' Well Name & Number: Sterling Unit 43 -9 Lease: Sterling Unit County or Parish: Kenai Peninsula State: Alaska Country:I USA Perforations: (MD) 5,262' - 5,272' (TVD): 5,261' - 5,271' Angle @KOP and Depth: NA Angle/Perfs: 0 KOP TVD:I NA Date Completed: Spud: June 19, 1963 RKB: 11.7 Revised by: Kevin Skiba Last Revision Date: 08/08/11 • • Page 1 of 1 Maunder, Thomas E (DOA) From: Stebbins, Tiffany A. [tastebbins @marathonoil.com] Sent: Friday, March 04, 2011 1:36 PM To: Maunder, Thomas E (DOA) Subject: RE: SU 43 -09 (163 -011) Disposal Report Tom, a) The source of the water injected into SU 43 -9 in 2010 was a combination of: • SU water produced in 2009 that remained in the tanks until 2010; the tanks hold several hundred barrels • SU water produced in 2010 (a small amount) • Rinse water from cleaning production facilities b) The reason we had Tess injection at SU this year is because we had less water production at SU in 2010, and this is because we shut in wells that make considerable water. Thanks, `( t l Regulatory Compliance Representative Marathon Alaska Production, LLC Phone 907 -565 -3043 Cell 907-529-0522 Fax 907 -565 -3076 From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Wednesday, March 02, 2011 11:58 AM To: Stebbins, Tiffany A. Subject: SU 43 -09 (163 -011) Disposal Report Hi Tiffany, Thanks for submitting the 2010 report. After review, I have a couple of questions. 1. The disposal volume is greatly reduced from 2009 (290 bbls versus 91870 bbls). I suspect this is related just to the reduced production time. Is that the case? Are the 3 gas wells in the SU more or less being used for "swing production "? 2. From the production reporting volumes, 32 -09 shows 5 bw in May 2010. Our records do not show the remaining 285 bbls (injected in April 2010) in the production record from any of the 3 gas wells. Do you know the source of that water volume? Thanks in advance. Call or message with any questions. Tom Maunder, PE AOGCC 3/7/2011 • Alaska Asset Team 2011 + ��" MC Marathon t � P.O. Box 196168 �` f� Alaska Production Anchorage, AK 99519 -8168 Telephone 907 /561 -5311 Anchorage Fax 907/565 -3076 February 28, 2011 Daniel T. Seamount, Jr., Commission Chair Alaska Oil & Gas Conservation Commission Attn: Tom Maunder 333 W. 7 Avenue, Suite 100 Anchorage, AK 99501 Reference: Report on Disposal Injection Operations Well Sterling Unit 43 -09, Sterling Unit Permit to drill #163 -011 Dear Mr. Maunder, Well Sterling Unit 43 -09 (SU 43 -9) is governed by Disposal Injection Order (DIO) No. 25, approved June 5, 2004. This report covers disposal injection operations for SU 43 -9 from January 1, 2010 until December 31, 2010. Fluids injected into SU 43 -9 typically come from well Sterling Unit 32 -9. No drilling mud slurries have been injected to date. The last mechanical integrity test on SU 43 -9 was conducted on May 13 2009 and the next test is due by May 13 2011. Attached are three graphs showing injection volume, injection pressure, and inner annulus pressure for SU 43 -9 in 2010. As shown from these graphs and the accompanying summary, injection volume for SU 43 -9 averaged <1 bwpd throughout 2010, for a total of 290 bbls of fluid injected during the calendar year. Please contact me with any questions at 907- 565 -3043. Sincerely, Tiffany Stebbins Compliance Representative cc: M. D. Dammeyer L. Ibele Well file • • Marathon Alaska Production LLC February 28, 2011 Report on Disposal Injection Operations Page 2 of 4 Well SU 43 -09, Sterling Unit Injection pressures (daily average, maximum and minimum) Injection Injection Injection Year Pressure, Pressure, Pressure, Average (psig) Maximum (psig) Minimum (psig) 2010 69 1822 0 SU 43 -9 Injection Pressure (2010) 2000 1800 Tubing Pressure Average (psig) ` Tubing Pressure Maximum (psig) 1600 — 7, ,0 1400 — a v 1200 -- L a 1000 a c ° 600 400 200 �O y 0 , , y 0 , y 0 y 0 y 0 y 0 0 ,0 , , L O L O , , , , , , L O , la c � � PQ c � a J \\) ,J� P �� 4, O o : � o � �c 1 Marathon Alaska Production LLC February 28, 2011 Report on Disposal Injection Operations Page 3 of 4 Well SU 43 -09, Sterling Unit Annuli pressures (daily average, maximum and minimum) Inner Annulus Inner Annulus Inner Annulus Year Pressure, Pressure, Pressure, Average (psig) Maximum (psig) Minimum (psig) 2010 155 160 91 SU 43 -9 Annuli Pressure (2010) 200 180 _._..� 160 00 140 N o. v 120 -_ — 3 0, 100 a, Annulus Pressure Average (psig) o. 80 Annulus Pressure Maximum (psig) Q 60 40 20 0 —_ y O y O y 0 y O y O , y O y O y 0 y O y O , � '\, , , , L O ti O , ti 0 L O L O , ti O , �� � a � P Q � � a J , J C , �� P J� fie, oc- The outer annulus showed negligible pressure throughout 2010. • • Marathon Alaska Production LLC February 28, 2011 Report on Disposal Injection Operations Page 4 of 4 Well SU 43 -09, Sterling Unit Fluid volumes injected (disposal and clean sweeps) Year Fluid Volumes Injected, (bbl) 2010 290 SU 43 -9 Injection Volume (2010) 128,500 ---- __..__. __. _...._- - - - - -- _ _____- __._____------- __.._._.__ 500 128,400 __._._- ____.__. __.____�_.__ ___ -__.- 400 m Total Cummulative Injection Volume (bbl) 4 1 Total Injecti V olu me, Month (bbl /month) 300 o ci a, o cn r 1 ' 3 128,200 - 200 c E a, I v' • • ■ to a 128,100 100 Q I 128,000 — — - -, 0 y 0 y 0 y 0 , y 0 y 0 y 0 y 0 y 0 , , ,.Q A so c" c Q a A J CS J� J% s e O i.c O e¢5-' > Q > > O — - ‘ , ....7 s wct `.,+..,E c- -c., O c-.. -- SZc�.i t 5 CJ J c� v�� \kCGi 5 Lov)\. ,. 0 \ `\ „ �c�. �c y .5 v ©\ J r", E s`5\. c_ck� \..1 rc_ .. C) VLF) 0 CY\ \-...-" `3- a p IZ S \ k O \N\NS Sow CCCaS"-'1 • ~ ~~ ~ Marathon i~nanTMON ®Alaska Production LLC June 1, 2010 --,~ ~ ~ '~~ ,f~; J~1N 1 2010 Daniel T. Seamount, Jr., Commission Chair Alaska Oil & Gas Conservation Commission Attn: Jim Regg 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 Reference: Report on Disposal Injection Operations Well SU 43-09, Sterling Unit Dear Mr. Regg, Ia~s~~ ~! ~. Co °~~con ~~hhr~Al 11p3-011 Well SU 43-09 in the Sterling Unit is governed by Disposal Injection Order (DIO) No. 25, approved June 5, 2004. This report covers the final disposal injection operations for SU 43-9 from January 1, 2009 until December 31, 2009 (including operations to date). Currently, wells SU 32-09, SU 41-15RD, and SU 43-9x produce the fluids injected via SU 43-09. Although permitted for injection of drilling mud slurries as well as other Class II production wastes, no drilling mud slurries have been injected to date in SU 43-09. The last mechanical integrity test was conducted on May 13th 2009 and the next test is due by May 13th 2011. Attached are four graphs showing injection volume, injection pressure, inner annulus pressure, and outer casing pressure for SU 43-9 in 2009 and YTD 2010. As shown from these graphs and accompanying summary, injection volume for SU 43-9 averaged 252 bwpd throughout 2009 for a total of 91,870 bbls of fluid injected during calendar year 2009. 2009 YTD 2010 (as of 6/1/10) Total 'acted Volume [bbl 91,870 92,159 Ave` a In'ected Dail Volume ] 252 179 Alaska AssetTeam P.O.Box196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565-3076 Injection Pressure (psig) N N O O O O O O O 1 /1 /2009 -..~-r--~-^ ; ~ 2/1 /2009 - ~~ ~ i ~ 3/1/2009 4/1/2009 -~ i 1 G 5/1/2009 ~- r.. 6/1/2009 ~~ ~ { ~ ~ { 7/1/2009 _ J ` ~. 8/1/2009 L ': ` ° C ~ i' o ~ ~ 9/1/2009 .,f- , ~ . ~ ~ ~ ~ m ._ ~ ~ '~~ Nb I 10/1/2009 t ,~ ~ ~ ~ o m o ~ 11/1/2009 - ~~ ` ' ,' ~ 12/1/2009 ' j f ~ ~ 1/1/2010 ~ 2/1/2010 -,, ~ 3/1/2010 f `~} i M1/2010 ' ~ E i ~~ ~ 5/1/2010 _ _h_. I.. . `. _.. Injection Volume (bwpd) N W .A (T W J W O O O O O O O O O O O O O 1/1/2009 ~ f 2/1/2009 ~ 1 3/1/2009 i {~' 1 1 4/1/2009 ~ 3 ~ i 5/1/2009 ! ~ i i 6/1/2009 ~ I {{ ~ 1 ~ 7/1/2009 , [ 8/1/2009 ~ 9/1/2009 t ~ f d I .. ~ ~ 10/1/2009 i ~ ~_ t 11/1/2009 - ~ ~ ~ ~ C~ ' ~ 12/1/2009 ~ ~ i { j ' S !~ 1/1/2010 i4 I {~ ~ ! ~I r l i 2/1/2010 ~ ~, 3/1/2010 ~ ~ ~ r t i ~ ~ 1 4/1/2010 ~ ~ { III i i ~ 5/1/2010 ! I l # ~ ~ ~ 0 m i f 0 ~' ... J N 0 m o~ To' 0 0 c 3 m ~~ v -O w Coo ~ j 7 . vD ~~~ ~ ~ ~ O ~ m~?~ ?. n C A •~~• 7 O O _. > O -~ r m o' w ~J c ~~ m ~ c~ 1 i N O O W O Marathon Alaska Production L~ • Report on Disposal Injection Operations Well SU 43-09, Sterling Unit June 11, 2010 Page 3 of 3 Disposal Well Sterling Unit 43-09 Inner Annulus Pressure 1/1/2009 -6/1/2010 1000 900 ~ a g00 700 7 N ~ 600 a 500 H 400 Q 300 200 d c ~ 100 0 rn rn rn rn rn rnpp pprn rn N N N N N N N N (~ M ~ to (O n W Disposal Well Sterling Unit 43-09 Outer Annulus Pressure 1/1/2009 -6/1/2010 100 - -- ----- ---- -- - _ -_ _--- - ---- --- -- -- ---- ---- rn 90 - -- - - ~ - - - - --- _ _ _ ~- - -- 70 ~ `... ----, -~-- --~-~-- - d 60 ___ ~ _ _ _ - ~._--- - - -- a ~- 50 -- - - -_ - --~--- ....__ - -~, __ _ ___.. ._ .- - ~~ - ~ 40 __ .~~_ _... __ ~ _ _ .-.., - - - - .~ _. ~.w____ -_ - c Q 20 - -'-~-°'-° - d .. - - - - -, T ~- ~~ _ p 10 _ ~ _ ---- -- -- _. - - -- _- 0 rn rn rn rn rn rn rn rn rn rn rn rn o 0 0 0 0 S S o 0 0 0 8 0 0 0 0 o s 0 0 0 0 N N N N N N N N N N N N N N N N N C~ M ~ ~ CO t` ~ ~ O .~- a ,~- a 0~ V ~ Date Please contact me with any questions at 907-565-3043. Sincerely, ~~~~~.d Tiffany Stebbins Compliance Representative cc: M. D. Dammeyer Well file rn rn rnpp rn o 0 0 0 0 N N N N N N N N N O~ O ~ C~ r l11 M ~ ~ Date MIT frequency • • Maunder, Thomas E (DOA) From: Regg, James B (DOA) Sent: Tuesday, February 16, 2010 1:29 PM To: Miranda, Kyle Cc: Maunder, Thomas E (DOA); DOA AOGCC Prudhoe Bay Subject: RE: MIT frequency Page 1 of 2 Reviewed your list against AOGCC well records and injection orders; edits in red below. KU 24-07RD test cycle is 2 years; only info in our files indicates well is a slurry injector. Looks like only 2 remaining test due this year: - KU 11-17, due on or before 5/13/2010 - KU WD -1, due on or before 5/18/2010 Jim Regg AOGCC 333 W.7th Avenue, Suite 100 UjW OCT Anchorage, AK 99501 907-793-1236 From: Miranda, Kyle [mailto:kmiranda@marathonoil.com] Sent: Monday, February 15, 2010 2:52 PM To: Regg, James B (DOA) Subject: MIT frequency Jim, I wanted to verify that we were both on the same page regarding our MIT frequency requirements. Below is what believe to be correct, with our most up to date well files. When you get the chance, could you please verify? In the meantime however, there was a discrepancy on KU 24-7rd whether it was a 2 or a 4 year. Searching your well file database I still believe it to be every 4 years, but wanted to confirm this as your inspector indicated he thought it was 2 years. We will send out our completed MIT test form for our recent test on KU 24-7rd when we have confirmed. Thanks. -------------------------------- -------------------------------- Well Freq PTD ------------------------------------------------------- KU 24-7rd (4 year) 205-099 KU 11-17 (1 year) 181-176 NO�1 (4 year) 181-107 F SU 43-9 (2 year) — + 63- KBU 23x-6 (4 year 184-109 KU 31-7x (4 year) 200-148 KU 12-17 (2 year) 208-089 BC 2 (4 year) 167-026 9/28/2010 2yr, next due 2/12/2012 next due 5/13/2010 next due 5/18/2010 next due 5/13/2011 next due 6/20/2011 next due 8/8/2011 next due 8/27/2011 next due 1/15/2012 MEMORANDUM To: Jim Regg `~ , 5~~~~0~ P.I. Supervisor FROM: Lou Grimaldi Petroleum Inspector State of Alaska • Alaska Oil and Gas Conservation Commission DATE: Thursday, May 14, 2009 SUBJECT: Mechanical Integrity Tests MARATHON OIL CO 43-09 STERLING UNIT 43-09 Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv~~'r'~~ Comm Well Name: STERLING UNIT 43-09 API Well Number: 50-133-10011-00-00 Inspector Name: Lou Grimaldi Insp Num: mitLG090514073130 Permit Number: 163-O1 l-0 Inspection Date: 5/13/2009 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 43-09 Type Inj. W TVD 5241 IA 395 1695 1690 1690 P.T.D~ 1630110 TypeTest SPT Test psi I69s OA zo zo zo zo Interval oT~R P/F P ~ Tubing 1760 1610 1600 I6oo NOtes: Two yeaz test. Fluid to surface in IA. Observed pretest conditions for thirty minutes with no change in IA/OA (tubing fell 150 psi due to injection changes). Pressure IA to 1695 psi and observe solid test of IA for 30 minutes. Could not verify Surface casing valve position due to casing head being covered with mud and gravel. ~/ ('n-,. Thursday, May 14, 2009 Page 1 of 1 MIT results KU 11-17, SU 43-~ • Page 1 of 2 ~(~ Q3.-c~`~ Regg, James B (DOA) ~ ~b ~-~ ~ ~ From: Miranda, Kyle [kmiranda@marathonoil.com] Sent: Thursday, May 28, 2009 3:39 PM ~~ C~I~`~' To: Regg, James B (DOA); Skiba, Kevin J. ~(~ Cc: Fleckenstein, Robert J (DOA); Aubert, Winton G (DOA) Subject: RE: MIT results KU 11-17, SU 43-9 Attachments: KU 11-17 MIT 05-13-09.x1s; SU 43-9 MIT 05-13-09.x1s; KU 11-17 MIT 2-12-09 to 5-12-09 Pressure Plot.xls; RE: upcoming MITs Jim, Sorry about that I had the PTD's ready and accidentally cleared the cell before I sent. I have re-attached the MIT files. There was 1050 psi on the IA of KU 11-17 at the beginning of the test because apre-test was performed the day prior at 1000+ psi was left on the IA, it was not bled off. This 1000 psi was left on the well overnight merely for convenience and time saving for the witnessed test the following day. Also attached is a 90 day plot of tubing, IA, and OA pressures for KU 11-17 prior to the MIT. Piease let me know if you need anything else. Likewise, have you found the "MIT guidelines" as described in the attached email message? I am preparing a roles and responsibilities worksheet for Marathon employees regarding MIT's and will finalize it when I receive all the information from the Commission. Thank you, Kyle Miranda _ r~ .R, r:; Production Engineer I L~~~t~~ " ~} ` ~` " ~ ~~'"' Marathon Oil Company-Alaska Asset Team 907-283-1370 (office) 907-394-8271 (cell) From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Thursday, May 28, 2009 2:40 PM To: Miranda, Kyle; Skiba, Kevin J. Cc: Fleckenstein, Robert J (DOA); Aubert, Winton G (DOA) Subject: RE: MIT results KU i1-17, SU 43-9 Kyle - Please make sure to include required info on forms, namely the PTD. We cannot import the incomplete form into our inspection database. KU 11-17 PTD 1811760 SU 43-09 PTD 1630110 What was the reason for high pre-test IA pressure (>1000psi) in KU 11-17? Please provide for Commission review a plot of tubing, inner annulus and outer annulus pressures for the 90 days prior to MIT . Jim Regg AOGCC 5/29/2009 MIT results KU 11-17, SU 43-. • Page 2 of 2 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Miranda, Kyle [mailto:kmiranda@marathonoil.com] Sent: Thursday, May 28, 2009 11:53 AM To: Regg, James B (DOA) Cc: Skiba, Kevin J. Subject: MIT results KU 11-17, SU 43-9 Mr. Regg, Please find attached the MIT results for wells KU 11-17 and SU 43-9. Thanks, Kyle Miranda Production Engineer I Marathon Oil Company-Alaska Asset Team 907-283-1370 (office) 907-394-8271 (cell) «KU 11-17 MIT 05-13-09.x1s» «SU 43-9 MIT 05-13-09.x1s» 5/29/2009 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:jim.regg@alaska.gov; tom.maunder@alaska.gov;bob.fleckenstein@alaska.gov;doa.aogcc.prudhoe.bay@alaslka.gov OPERATOR: Marathon Oil Company ~ ~ +Z`~ 1 ~~ FIELD /UNIT /PAD: Sterling Unit ~~ DATE: 05/13/09 OPERATOR REP: AOGCC REP: Kyle Miranda Louis Grimaldi Packer Depth Pretest Initial 15 Min. 30 Min. Well SU 43-9 Type Inj. W TVD X5,241' Tubin 1,760 1,700 1,660 1,660 Interval 2 P.T.D. 1630110 ~ Type test P Test psi /1500 Casing 395 395 395 395 P/F P Notes: OA 20 20 20 20 Well SU 43-9 Type Inj. W TVD 5,241' Tubing 1,600 1,600 1,600 1,600 Interval 2 P.T.D. 1630110 Type test P Test psi 1500 Casing 1,695 1,695 1,690 1,690 P/F P Notes: OA 20 20 20 20 Well Type Inj. TVD Tubing Interval P.T,D. Type test Test psi Casin P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPEINJ Codes D =Drilling Waste G=Gas I =Industrial Wastewater N =Not Injecting W =Water TYPE TEST Codes M =Annulus Monitoring P =Standard Pressure Test R =Internal Radioactive Tracer Survey A =Temperature Anomaly Survey D =Differential Temperature Test INTERVAL Codes I =Initial Test 4 =Four Year Cycle V =Required by Variance T =Test during Workover O =Other (describe in notes) MIT Report Form BFL 11/27/07 2009-0513_MIT_SU_43-09_Ig.xls " . Alaska A.Team RECEIVED JUN 2 8 2007 (!f!) Marathon IUIIIÐHOII Oil Company PO BOX 196168 Alaska Oil & Gas Cons. Commissi Anchorage, AK 99519-6168 Anchorage Telephone 907/561-5311 Fax 907/565-3076 June 25,2007 f~ I (ç3 -- 0 I ( Tom Maunder AOGCC 333 West ¡th Ave, Suite 100 Anchorage, AK 99501 .~JUL (J:) Q;;Df)'7 Reference: Report on Disposal Injection Operations Well Sterling Unit 43-9, Sterling Unit Dear Mr. Maunder: This annual report of disposal injection operations covers the period of January 15t 2006 through December, 31 5t 2006 for the Sterling Unit (SU) #43-9. Disposal via this well is governed by Disposal Injection Order (010) No. 25 for the Sterling Unit Gas Field (approved June 15, 2004). Attached are three plots showing injection volume, injection pressure and casing pressure for this well in the calendar year 2006. Although permitted for injection of drilling mud slurries as well as other Class" production wastes, no drilling mud slurries have been injected to date in SU 43-9. The last mechanical integrity test was conducted on June 4th 2006 and the next such test is due by June 4th 2008. As shown from the attached graphs, injection volumes in 2006 were sporadic; less than 300 bbls of fluids were injected last year. In 2006 surface injection pressures averaged 1190 psig, due to the low produced fluid volumes from the sole gas well producers SU #32-9 and SU #41-15. Later in 2007, Marathon intends to drill two (2) new Sterling Unit wells: SU #41-15rd and SU #43-9X. Production from these wells could possibly boost the SU 43-9 injection rates and frequency in the coming year. Sincerely, ~~£ A. B. Schoffmann Operations Superintendent Marathon Oil Company L:\Sterling\Wells\SU 43-9 Pad\ReguJatory\SterJing Unit 43-9 Annuallnj Rept - 05-2007.doc Enclosures CD c:: c:: 5 o 1 .. . . . . . . 1 1 1 . 1 1 o ~ 1 1 o ~ ~ 1 2006 . MEMORANDUM . TO: Jim Regg Q P.I. Supervisor 'I\~( M ZI( C 7 State of Alaska . Alaska Oil and Gas Conservation Comm DATE: Wednesday, June 20, 2007 SUBJECT: Mechanical Integrity Tests MARATHON OIL CO 43-09 STERLING UNIT 43-09 Src: Inspector /0\\ \\0 "J Reviewed By: P.I. Suprv ::51512- Comm FROM: Jeff Jones Petroleum Inspector NON-CONFIDENTIAL Well Name: STERLING UNIT 43-09 API Well Number: 50-133-10011-00-00 Inspector Name: Jeff Jones Insp Num: mitlJ070608101002 Permit Number: 163-011-0 Inspection Date: 6/4/2007 Rei Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 43-09 Type Inj. N TVD I 5241 IA 50 1675 1675 I 1675 P.T.D, 1630110 TypeTest SPT Test psi i 1500 OA 0 0 0 I 0 Interval OTHER P/F P ,/" Tubing 20 20 20 I 20 Notes: 2 year cycle MIT. < 1 BBL water pumped. SCANNED JUN 2 '7 20ü7 Wednesday, June 20, 2007 Page 1 of! MITs Due . . Commission records indicate the following MITs are due: Kenai Unit 11-17 (PTD 181-176) - Annual MIT required by Sundry approval 398-300 (well integrity) - Last MIT performed was 5/18/2006 (Pass); witnessed by AOGCC Sterling Unit 43-09 (PTD 163-011) - 2 year MIT required by DIO 25 - Last MIT performed was 5/27/2005 (Pass); witnessed by AOGCC Please contact me to make arrangements for witnessed MITs on both wells within the next 2 weeks. Jim Regg AOGCC ~MAY2 9 2007 . ..., .-.! ,~_r,._...........t·,'Y"':" 1 of 1 5/21/20071:59 PM lV.1~lVl U .KAl~ U U lVI ) Alaska Oil and Gas Conservation Commb, ') ~tate ot Alaska TO: Jim Regg i? P.I. Supervisor l<!11 b{ li/a{ DATE: Monday, June 06, 2005 SUBJECT: Mechanical Integrity Tests MARATHON OIL co 43-09 STERLING UNIT 43-09 r /0\\ \",3 FROM: Jeff Jones Petroleum Inspector Src: Inspector Reviewed By: /'< tI P.I. Suprv --J¡?~ Comm Well Name: STERLING UNIT 43-09 Insp Num: mitJJ050603132427 Rei Insp Num: NON-CONFIDENTIAL API Well Number: 50-133-10011-00-00 Permit Number: 163-011-0 Inspector Name: Jeff Jones Inspection Date: 5/27/2005 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well I 43-09 ¡Type Inj. I N TVD 5241 I IA 1675 1675 1675 1675 P.T. /1630110 JTypeTest fAMT Test psi 1310.25 -TOA 0 0 0 -.!!!terval OTHER P/F p Tubing 20 20 20 20 Notes: Well 43-09 IA was already pressured up to 1675 PSI on my arrival. I verified pressures and monitored for 30 minutes with no change. The IA was then bled to 1000 PSI and monitored for 30 minutes with no change. This well is on a 2 year test cycle. There was no OA pressure guage installed and I instructed Denise Titus (Marathon) to install equipment to enable OA pressure monitoring, which was done immediately. '/' SCANNED JUN 2 1 200~i Monday, June 06, 2005 Page 1 of 1 SU 43-9 Wellbore Diagram . r--, /'\ Bob, Here is the wellbore Diagram you requested. Conversion of the well from gas to water disposal took place February 2nd, 2004 when we started injecting produced water. No other modifications were made to the well. The well was permitted to inject into the same zone we were producing. Should you have any further questions or need further clarification, please don't hesitate to call or email. Thanks, Don Eynon 907-283-1337 Office 907-398-9954 Cell 907-260-6456 Home «8U43-9.zIP» . Content-Description: SU43-9.ZIP SU43-9.ZIP' Content-Type: applicationlx-zip-compressed Content-Encoding: base64 1 of 1 5/25/2004 8:03 AM 'M MARATION ì ,~ ... TubinQ Detail: 2-3/8", 4.7 ppf, J-55, EUE 8rd tubing to 5250' Otis "A" sliding side-door @ 5226' Otis S-1 nipple @ 5238' Tubing tail @ 5250' Baker N-1 packer@ 5241' I Icement plug 5337' - 5380' (7/2/63) I IE-line tagged fill at 5336' MD (2/18/00) 17.625" open hole below shoel @ 5380' Well Name & Number: County or Parish: Perforations: (MD) ~ngle/Perfs BHP: FWHP: Date Completed: Prepared By: SU 43-9 Kenai Peninsula I Angle @KOP and Depth BHT: I FBHP: Spud: June 19, 1963 Gary Eller Well SU 43-9 .. ~ API: NIA AOGCC: 163-11 KB-GL: 11.7' 2422'FSL,528'FEL See.9,T5N,R10VV,S.M. Tree exn = 2-3/8" EUE 8rd Surface CasinQ: 8-5/8", 24 ppf, J-55 casing @ 1272' Cmt wI 450 sks plus 100 sk top-job Calculated cement top = 3301' assuming 100% excess in 7-5/8" x 5- 1/2" annulus mJ !J ....... - C I¡ Perfs: 5257' (squeezed) 5262' - 5272' (4 spf) Production CasinQ: 5-112",17 ppf, LTC casing @ 5380' J-55: 0' - 3755' N-80: 3755' - 5380' Cmt wI 550 sks I TD = 6202' I State/Prov. Lease I Alaska I (TVD) vertical hole Completion Fluid: FWHT: I I Last Revision Date: FBHT: Sterling Unit I Country: I I KOPTVD I I Other: RKB: 07/29/021 11.7 ,-...., r'\ , Marathon Oil Company Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 April 30, 2004 /63- 01 J Jim Regg State of Alaska Alaska Oil & Gas Conservation Commission 333 West th Ave, Suite 100 Anchorage, AK 99501 Reference: 010 No. 25 Field: Sterling Unit Gas Field Well: Sterling Unit No. 43-9 Well RECEIVED MAY 202004 Alaska Oil & Gas Cons. Commission Anchorage Dear Mr. Regg Enclosed please find documentation to fulfill requirements of Disposal Injection Order Number 25 for the Sterling Unit Gas Field, Sterling Unit Number 43-9 Well. A 10-404 Report of Sundry Operations is also included. Attachments include an initial Report of Operations, Step Rate Test and a basèline temperature survey which was performed February 25,2000. A mechanical integrity test verified mechanical reliability of the casing-tubing annulus and was witnessed by Jeff Jones of the AOGCC on March 5, 2004. Should you require the data electronically or need further information, I can be reached at 907-283-1337 or bye-mail at DEEynon@MarathonOil.com. Sincerely, -,~:~~ I' ".~ ~ ~-' , -' " Donald Eynon Operations Engineer Enclosures: Report of Operations Temp-Press Survey Step Rate Te~t Results "~ r'\ "! Report of Operations: Injection Facility: The injection facility construction was completed in late January 2004 with a final check out performed on the injection equipment January 30th, 2004. Safety features on the equipment include high / low pressure discharge alarm set points at the injection skid and tubing and casing pressure alarm set points. The alarms are present to notify personnel at our operations center on Kalifornsky Beach Road in the Kenai Gas Field (KGF). The KGF facility is manned 24 hours a day with performing gas well and pipeline surveillance ready respond to alarms. Anyone of the injection facility alarms will shut down the water injection pump and render it inoperable until the alarms are reset. A mechanical relief valve on the pump discharge is set to release at 2800 psi with injection fluid returning into the injection supply tank. The injection supply tank is a double walled 200 bbl tank inline with a 70 bbl suction tank equipped with low and high level switches. The system is automated to start and stop the injection equipment when the tank level reaches predetermined levels. On a typical day the unit will cycle through six injection periods as the produced water tank volume increases with daily production until the tank reaches a high level switch to start the injection equipment. As produced fluid is injected" the tank level lowers until reaching the low level shut down switch, at which time the production-injection cycle starts over. Injection Summary Injection operations began February 2nd, 2004 after a step rate test was conducted on January 30th, 2004. Unfortunately, communication to our historical database through our SCADA system was not functioning properly and the step rate data was lost. As a result the Step Rate Test was re-ran February 4th, 2004 with the data being stored successfully. The average daily injection volume for the first month was 173 bwpd, at a maximum well head pressure of 2090 psi. The maximum volume of produced water injected daily was 390 bbls with a minimum of 93 bbls. Injection equipment is set to start up at a daily rate of 880 bwpd. During the first month of operation 5,200 barrels of produced water was injected. MIT Test A Mechanical Integrity Test was performed on March 5th, 2004 with Jeff Jones of the AOGCC present as a witness. The casing was pressured to 1535 psi and held for 30 minutes. No communication to the tubing casing annulus has been observed during injection operations. - , r'\ ~ Step Rate Test Results The step rate test was conducted on February 4, 2004, produced water from the Sterling Unit Gas Field was used~for the test. A positive displacement pump with a variable speed drive controller was used to establish four injection rates. Approximate rates were .19, .41, .58 and .75 barrels per minute. A pressure and rate versus time graph is shown in Figure 1. SU 43-9 Step Rate Test 2000 00 -----~ ,- "~ ~-~,~ ..- ~-~ -, 1800,00 - , ,- ,-" ----- .... "",~~_'__~4~'" ¡ --~"'.;;JiJØfJ""~" ; ð-<'~~~ f'~ 09 1600 00 - 0,8 C ) 140000 u_- ~ ::; :g 1200,00 - C ) ~ ~ a.. .S? 1000 00 C ~ 0- ;: (,) C ) ï: 600 00 - --~- - _.f """"'~-;.--- ".'~ " 07 800 00 ,,~," '\ "'" '."""""~", 03 ~'0"2 C ) - 06 CIS ~ 0:: .: c E - 0,5 0 Ùi ;::ä 04 g a. ..... .E i, i, ~ 40000 - ,- ¡ J 11 20000 ~ 0,1 000 120838 "'-'-'-. .. ---" 1223 02 1237"26 1251'50 130614 132038 133502 TIME (hrs:min:sec) - Casing Pressure -Injection Rate ~~' Tubing Pressure Figure 1: Pressure and Rate versus Time An initial casing pressure of 164 psi rose to 178 psi during the test due to ballooning of the 23/8" tubing as a result of the 1 ,714 psi increase in injection pressure. Approximately 30.8 bbls of produced fluid were injected during the test. Baseline Temperature Survey A Schlumberger PSP Temperature and Pressure log dated Feb 25,2000, is attached. A baseline temperature survey was logged prior to performing injection conformance tests on this date. @ b d en tn ~ b.- ~ .2> tJ) 6 c. 0- .~ ~ (,) CD .~ 6 SU 43-9 Step Rate Test ,,_un". . r-~,=~::=:;~.-~.,.._",l("" 2000,00 - "" - --", ."". 1800.00 Un' . 1600.00 u -,- - ,-'-' I", ,,--- f ,-J ,- ~) ~""~ " 1400.00 un 1200.00 ,,- - - 1000.00 un- --- 800.00 " ,; -y" ~----_. ---, u -"---- -- 600.00 " - ,,_--_n"- -- "---,, ..-- -.- .- -~ ".. ----_..,,- - 400.00 ------ "......-~_"m-------"U"- ---- u-_,,_m ..,n-""-"'-' ",- ! - \ '-r---" ¡ . --,-_. \ . - _F ~r ---- " '- .----.-n-- ,"" --.",- 1 - ---- 0.9 ------- ----. - ---'-- -0.7 -- 0.6 ------- ---------- 0.5 ------ -- n---n - 200.00 --';;'~.__c---",-,--,~:=-::, .=;::::;;;.:.::.:::""=~".. _m.",,""""', -,-"---,',""-~-"--"""~"""--,,,,-,,,~,,,,-,,,,"~-,,,"'~"-'---'--"", 0.00-."""" ,..,....!,.... ,-----."..---,.-------.."-.--.-,,-,,,.-,.-..- 12:08:38 12:23:02 12:37:26 12:51 :50 TIME (hrs:min:sec) ,-,~~~~~-"~~"'.'" 13:06:14 13:20:38 - "_n_un 0.4 -_u- 0.3 ..-------- um__' 0.2 0.8 ) .",--~~,"'-", ". '-,,'-~=. 13:35:02 CI) ..... CO r:t:- t: r:: .- O~ ..:E (.)8- CI) "- r: ) 0.1 0 l ~--- Casing Pressure" -- '.0- Tubing Pressure -Injection Rate! 2500.00 - 2250.00 -- -- 2000.00 - 1750.00 n (j)- b (j) :2i (.) 1500.00- tn m IJ)t e :J f:l. UI 1250.00--- I::- 0 tV ,- C) .... ,- (.) (/) 1000.00- (j) t:l '2'- 750.00 - -- - 500.00 - 250.00 -- _m 0.00 - 0 SU 43...9 Step Rate Test -.."" - ---~---- - - ---- -- - - ---- -- --- ---------- 118~5 PSi_~ - ------- ------------ . Æ - ----- ---- - -.-- -~~~-- " , ----- -- ----- --~-- " -------- - - ----~----- --- ---- --------- ------ --------- A - - ----- --- - ------------ -- ~--- -- ---- ---------- - --- ----- ------- --- - --- n---- --- -- --- ---- - ------..- î \ ------------- , . '. ., 6 ) ------------ - ---- -- ¡ -------~--- ) 0.1 0.2 0.3 0.4 0.5 --" ---,,'----" -- 'm_... --""-,, --_0_' ...- ""--"'--"'-" -----,,--,--.. 0.8 "" -. ..- -----""""----"-,,,,,--- --. --,.._.-----.--- """'----"-'-"'" --,------""",--- Injection Rate (bpm) 0.6 0.7 ~ r'\ I"\1::\."t:1 Vt:U MAY 202004 , # - --,. . ... 1. Operations Performed: AbandonD Alter CasingD Change Approved programD 2. Operator Name: 3. Address: Suspend D Repair Well 0 Pull TubingD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY OPERATIONS Alaska Oil & Gas Cons. Commission Anchorage perforateD varianceD Annular DisposalO StimulateD Time ExtensionO OtherlEJ Re-enter Suspended WeliO 5. Permit to Drill Number: 163-11 6. API Number: 50- 133-10011-00 Operation ShutdownO Plug perforationsD Perforate New POOIO 4. Current Well Class: Development~ stratigraPhicD EXPloratoryD serviceD Marathon Oil Company PO Box 196168, Anchorage, Alaska 7. KB Elevation (ft): 11.7' GLto KB 8. Property Designation: FED A028063 11. Present Well Condition Summary: 9. Well Name and Number: SU 43-9 10. Field/Pools(s): Sterling Unit, Sterling Pool Total Depth MD (ft.) measured 6202' feet true vertical 6202' feet Plugs (measured) Cement 5336' Effective Depth measured 5337' feet Junk (measured) true vertical 5337' feet Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1272' 8-5/8" 1272' 1272' 2,950 psi 1,370 psi Intermediate Production 5,380' 5.5" 5,380' 5,380' 5,320 psi 4,910 psi Liner Perforation depth: Measured depth: B-4 Sand: 5262'-5272' MD True vertical depth: B-4 Sand: 5262'-5272' TVD Tubing: (size, grade, and measured depth) 23/8",4.7 ppf, J-55, EUE at 5,250 MD Packers and SSSV (type and measured depth) Baker Model N-1 Packer at 5,241' 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation 14. Attachments: Copies of Logs and Surveys Run Step rate test results Temperature survey 15. Well Class after proposed work: Exploratory D Development E] Service D Daily Report of Well Operations 16. Well Status after proposed work: Oil 0 GasD WAGD GINJD WINJDWDSPLE] 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. SUndry Number or N/A if C.O. Exempt: Contact (907) 283-1337 Printed Name Donald Eynon s;g"',,, ~ ~ Form 10-404 Revised 2/2003 Title Operations Engineer Phone 907-283-1337 Date 5/3/2004 ORIGINAL RBDMS BFL MAY! a 6 100\ State of Alaska TO: Randy ârich Co issioner . !'hIM' Jim Regg i2'/¡t! .3 P.I. Supervisor \ '1 ( Alaska Oil and Gas Conservation Commission FROM: JJ Petroleum Inspector DATE: Monday, March 15,2004 SUBJECT: Mechanical Integnty Tests MARATHON OIL CO 43-09 STERLING UNIT 43-09 THRU: Sre: Inspector NON-CONFIDENTIAL API Well Number 50-133-10011-00-00 Insp No mitJJ040315114338 Inspection Date: 3/5/2004 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well: 43-09 Type Inj. P TVD 5241 IA 310 1550 1550 1550 P.T. 1630110 TypeTest SPT Test psi 1500 OA Interval Four Year Cycle P/F Pass Tubing 260 260 250 250 Notes: March 5, 2004: I traveled to Marathon Oil Co.'s Sterling Gas Field to witness an MIT on water injection well SU 43-9. Rick Fortneywas the Marathon representative in charge of the test today which he performed in a safe and proficient manner. The pre-test pressures were momtored for 15 minutes and found to be stable. The casing was then pressured up to 1550 PSI and monitored for thirty minutes with no significant pressure loss noted, passing the MIT. Summary: I witnessed a successful MIT on Marathon Oil Co.'s Sterling Gas Field produced water injection well 43-9 in the Sterling Unit. Type INJ. Fluid Codes F =FRESH WATER INJ. G=GAS INJ. S=SALTWATERINJ. N=NOT INJECTING Type Test M=Annulus MOIÙtoring P=Standard Pressure Test R=lntemal Radioactive Tracer Survey Interval 1=lnitial Test A=Temprature Anomaly Survey D=[)¡fferential Tempratnre Test 4=Four Year Cycle. V=Required by Variance W=Test dwing WOIkover O=Other (describe in notes) Monday, March 15,2004 Page I of! MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Camille O. Taylor ~b DATE: October 23, 2002 Chair SUBJECT: Mechanical Integrity Tests THRU: Tom Maunder ~/~/~/~ Marathon Oil Co. P.I. Supervisor · Sterling Pad ~c~ SU 43-9 FROM: Jeff Jones Sterling Unit Petroleum Inspector Sterling Gas Field NON- CONFIDENTIAl- Packer Depth Pretest Initial 15 Min. 30 Min. Wa l Su43-9 I Ty, pelnj. I N I T.V.D. I 5241 '1 Tubing I 22' I '25 ! 25 ] 25' I lntervall I ,F;.T'.D.I 163'011 I'T)iPetest. I, S' ITestpsil 1500 I.CasingI 400 I 16501 16501 ~6501 pIE I_P Notes: Pre. injection conversion MIT. Type INJ. Fluid Codes F = FRESH WATER INJ. G = GAS INJ. S = SALT WATER INJ. N = NOT INJECTING Type Test M= Annulus Monitoring P= Standard Pressure Test R= Intemal Radioactive Tracer Survey A= Temperature Anomaly Survey D= Differential Temperature Test Interval I= Initial Test 4= Four Year Cycle V= Required by Variance W= Test during Workover O= Other (describe in notes) Test's Details October 23, 2002: I traveled to MarathOn Oil Co.'s Sterling Gas Field to witness an MIT on gas production well SU 43-9. Bill Wolf was the Marathon representative in charge of the test today which he performed in a safe and proficient manner. The pre-test pressures were monitored for 15 minutes and found to be stable. The casing was then pressured up to 1650 PSI and monitored for thirty minutes with no significant pressure loss noted, passing the MIT. Mr. Wolf indicated Marathon,s intent is to convert this gas .production well to a produced water disposal injection well for the Sterling Gas Field. Summary: ! witnessed a successful MIT on Marathon Oil Co.'s Sterling Gas Field well 43-9 in the Sterling Unit. M.I.T.'s performed: 1_ Number of Failures: g Total Time during tests: 1.5 Attachments: Marathon circular pressure chart copy (1) cc: MIT report form 5/12/00 L.G. MIT SU 43-9 10-23-02 JJ.xls 10/25/2002 w Attach to file" MIT SU 43-9 10-23-02 JJ.xls g:~cmn\d rig~kgt~wells~ku 11-8s~AOGCC01 A. xls STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation Shutdown__ Stimulate , Plugging__ Perforate., Pull Tubing Alter Casing Repair Well,, Other X 2. Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168, Anchorage, AK 99519-6168 4. Location of Well at Surface 5. Type of Well: 2421.7' FSL, 527.5' FEL, Sec. 9, T5N, R10W, S.M. At top of Productive Interval vertical hole At Effective Depth vertical hole At Total Depth vertical hole Development .~X Exploratory __ Stratigraphic __ Service IRun Injectivity Log I 12. Present Well Condition Summary Total Depth: measured true vertical 6202 feet 6202 feet Plugs (measured) 5337' Effective Depth: measured true vertical 5337 feet 5337 feet Junk (measured) Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth: measured Length Size 1272' 8-5/8" 5380' 5-1/2" B-4 Sand: 5262' - 5272' MD Cemented Measured Depth 6. Datum Elevation (DF or KB) 1 1.7 feet 7. Unit or Property Name Steding Unit 8. Well Number SU 43-9 true vertical B-4 Sand: 5262' - 5272' TVD Tubing (size, grade, and measured depth) 9. Permit Number 163-11 10. APl Number N/A 11. Field/Pool Sterling Unit, Sterling Pool ORIGINAL True Vertioal Depth 550 sks 1272' 1272' 550 sks 5380' 5380' 2-3/8", 4.7 ppf, J-55, EUE at 5250' MD Packers and SSSV (type and measured depth) Baker model N-1 packer @ 5241' RECEIVED MAR 17 000 0il & Gas C0115. C0mmia 13. Stimulation or Cement Squeeze Summary Intervals Treated (measured) B-4 Sand (5262' - 5272' MD), water injection only, no stimulation Treatment Description Including Volumes Used and Final Pressure Max rate: 3.25 bpm (4,680 bbl/day equivalent) at 2450 psi OiI-Bbl 14. Prior to Well Operation N/A Subsequent to Operation N/A Total volume used = 90 bbl fresh water Representative Daily Averaae Production or Injection Data Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure 15. Attachments 116. Status of Well Classification as: I Copies of Logs and Surveys run Daily Report of Well Operations X Oil ..... Gas X 17. I here .,~fy~e foregoin~e and correct to the best of my knowledge. Signed" ~'~',,.~~,~ ~,~., J. Gary Eller Form 10-404 Rev. 06/1 , Suspended__ Title Production Engineer Service Date 3/14/00 Submit in Duplicat~ i~IARATHON OIL COMPANY DALLY WELL OPERATIONS REPO~~'' PAGE I OF I DATE: 2/25/00 FIELD: Sterling Gas Field WELL #: SU 43-9 FILL DEPTH/DATE 5336' KB (2/18/00) TUBING: 2-3/8" CASING: 5-1/2" DATE LAST WL WORK: 2/18/00 TREE CONDITION: WORK DONE: Pull choke, gauge run to bottom BENCHES OPEN: Sterling B-4 PRESENT OPERATION: Injectivity Icg to confirm B-4 Zonal Isolation OTHER: AFE 0487000 SUMMARY OF OPERATIONS MIRU Schlumberger on well SU 43-9. SITP = 1755 psia, CP = 40 psi. Held operations/safety meeting. Prepare to run RST/Temp log; had to drop off centralizers because tool string too long. Pressure test lubricator to 3000 psi with methanol. RIH with RST/temp log. Tag bottom at 5300' KB, and tie into Halliburton log of 8/9/90. Difficult to accurately tie into open-hole logs. Make a baseline log and repeat log from 5300" to 4900'. Fluid level is in the vicinity of the perfs. RIH to bottom. MIRU Dowell pump truck onto Schlumberger pump-in sub. Test lines to 3000 psig. Filled the tubing (20 bbl) with 100-deg fresh water, then pumped an additional 5 bbl at 3.2 bpm at 2300 psig. All fluids filtered to 3-microns. Shut down pumping, log from 5300' to 400'. Occasionally pumped small volumes of fresh water to keep the surface lines thawed. RIH to bottom when logging complete. Pump 20 bbl slug of fresh water mixed with 7 Ib/bbl borax at 3.25 bpm with 2450 psig pump pressure. Displaced with 20 bbl fresh water at same rate. Annulus pressure stead at 40 psi. After borax was displaced from the tubing, logged from 5300' - 4800' with RST/temp log while pumping at minimum rate. No sign of fluid channeling out of zone; clear indication of borax entering the Sterling B4 interval. Ran repeat log over same interval. Made stationary oxygen-activation surveys at 5238', 5248', and 5218' KB while pumping at minimum rate (0.2 bpm) at 1200 psig pump pressure. No indication of upward flow (i.e. behind pipe flow) at any of the stations. POOH, RDMO Schlumberger and Dowell. RECEIVED MAR 1 7 2.000 Alaska 0il & Gas Cons. Commission Vendor Equipment Daily Cost Cumulative Cost Dowell pump truck $12,020 $12,020 M-I Drilling Fluids borax $600 $600 Misc. hot shots, etc. $1,000 $1,000 R&K vac truck, lights $1,600 $1,600 Schlumberger electric line, RST/Temp log $34,417 $34,417 DAILY COST: $49,637 CUM: $49,637 REPORTED BY: Eller/Affinito STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request Abandon Alter Casing O:'EXCELV~OG CC01 .xls ~.~ Change Approved Program Suspend Operation Shutdown Repair Well Plugging Pull Tubing Vadance Re-enter Suspended Well Time Extension Stimulate Perforate Other X 2. Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168, Anchorage, AK 99519-6168 4. Location of Well at Surface 5. Type of Well: Development X Exploratory Stratigraphic Service 2421.7' FSL, 527.5' FEL, Sec. 9, T5N, R10W, S.M. At top of Productive Interval vertical hole At Effective Depth vertical hole At Total Depth vertical hole I Run Injectivity Log J 6. Datum Elevation (DF or KB) 11.7 feet 7. Unit or Property Name Sterling Unit 8. Well Number SU 43-9 9. Permit N,~er 163-11 10. APl Number 11. Field/Pool Sterling Unit, Sterling Pool 12. Present Well Condition Summary Total Depth: measured true vertical Effective Depth: measured true vertical 6202 feet 6202 feet 5337 feet 5337 feet Plugs (measured) 5337' Junk (measured) Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth: measured Length Size Cemented Measured Depth True Vertical Depth 1272' 8-5/8" 550 sks 1272' 1272' 5380' 5-1/2" 550 sks 5380' 5380' B-4 Sand: 5262' - 5272' M D true vertical B-4 Sand: 5262' - 5272' TVD Tubing (size, grade, and measured depth) 2-3/8", 4.7 ppf, J-55, EUE at 5250' MD Baker model N-1 packer @ 5241' Packers and SSSV (type and measured depth) 13. Attachments Description Summary of Proposal__ Detailed Operations Program X BOP Sketch 14. Estimated Date for Commencing Operation 115. Status of Well Classification as: 1/12/00 I 16. If Prop~)sal was Verbally Approved I Oil m Gas X Name of,~Approver \' Date Approved ~ rvic .... 17. I hereby'~ify that the foregoing is true and correct to the best of my knowledge. Signed ~ \ ~ ~[~'~ Gary Eller Title Advanced Production Engineer Suspended~ ~' ~ - - FOR COMMISSION USE ONLY Conditions of Approval:~ Commission so representative may witness Plug Integri~ BOP Test Location Clearance Mechanical Integrity Test ~ Subsequent Form Required 10- ~pproved by Order of the Commission '"',10-40~ Rev. 06/15/88 ORIGINAL SIGNED BY .~_oh~rt N ~hrist~nson Date 1/14/00 Injectivity Log Procedure Well SU 43-9 Sterling Unit AFE 0487000 Objective: Run an injection log across the Sterling B-4 interval of well SU 43-9 to confirm that injected fluids are confined in that sand. Procedure: 1. MIRU slickline on well SU 43-9. Test lubricator and BOPs to 2,000 psi using methanol. RI/-I with i~A'' impression block down to the top of the downhole choke at 5238' KB. Take impression of fishing neck and POOH. Record fluid level if observed. 2. RIH with retrieving tool. Retrieve downhole choke installed in S-1 nipple (ID = 1.875"?) at 5238' KB. POOH. (Note: Choke includes a Baker equalizing device. Contact Gary Eller for more information if needed.) 3. RIH with PA" gauge ring. Tag fill (estimated at 5272' KB). POOH, RDMO slickline. 4. MIRU electric line unit. Test BOPs and lubricator to 2000 psig with methanol. RIH with TDT-Waterflow log to top of fill. Make tie-in pass. 5. MIRU pump truck on pump-in sub of electric line lubricator. Pressure up casing string to 1500 psig using separate pump. Blend 75 bbl of 3% KC1 with borax additive. Heat fluid as necessary to avoid freezing. Inject at least one tubing-volume of filtered KC1 fluid down the tubing into the Sterling B-4 formation at a rate and pressure dictated by the onsite engineer. While injecting, make passes with the TDT-Waterflow log as necessary to determine whether the injected fluid is staying in zone. 6. When complete, POOH and RDMO electric line and pump truck. Haul remaining KC1 fluid to Kenai Gas Field for disposal. JGE - January 13, 2000 NSDRLG\STERLING\SU43-9~injecflog.wpd KB = STERLING 11.70' UNIT #43-9 SPUD JUNE 19, 1963 100 S× TOP JOB FROM 60' 12 1/4." HOLE ~ ~/8°', ,1-55, 24# II} 1272" CEMENTED WITH 450 7 7/8" HOLE TO 2230' 7 5/8" HOLE TO T.D. TOP OF RUNNING PLUG AT 5337' 5 1/2% 17#, J-55 & N-80 SET AT 5380' CUT~ W/ 550 SX 'ID = 6202' OTIS TYPE "A" SLIDING SIDE DOOR AT 5226' OPENS UP AND CLOSES DOWN (THIS COULD BE 10' BEEPER) ._%~_,,,,,,,,,~.... OTIS "S" NIPPLE AT 5238' _-"' "..¢_._~_\--,~__~,,'.("~" O'HIS COULD BE 10' DEEPER) BAKER MODEL N-1 PACKER AT 524.1' SET WITH 1' COMPRESSION 2 3/8" EUE 4..7#, J-55 TUBINC TAIL AT 5250' 5262°- 5272' 4SPF ~-~ ~ MAXIMUM INCLINATION IS 2.75 BEG GRB 8/10/90 STERLING KB = 11.70' UNIT #45-9 SPUD JUNE 19, 1963 I 100 SX TOP JOB FROM 12 1/4" HOLE 8 5/8", J-55, 24~ t} '1272" CEMENTED WITH 450 S× 7 7/8" HOLE TO 2230' 7 5/8" HOLE TO T.D. OTIS TYPE "A" SLIDING SIDE DOOR AT 5226' OPENS UP AND CLOSES DOWN (m~s COULD BE lo' nEEPLm) OTIS "S" NIPPLE AT 5238' O'I'IIS COULD BE 10' DEEPER) BAKER MODEL N-1 PACKER AT 524.1' SET WITH 1' COMPRESSION . 2 3/8" EUE 4.7#, J-55 TUBING TAIL AT 5250' ~' - 5~' TOP OF EUNNING PLUG AT 5337' 'ID = 6202' MAXIMUM INCLINATION IS 2.75 DEG ~RE~ ~/~o/9o Alaska 1~' .~n Domesti~ r'roduction Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 January 14, 2000 Mr. Blair E. Wondzell State of Alaska Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Reference: Proposed Injection Log, Well SU 43-9, Sterling Unit Dear Mr. Wondzell: Marathon Oil Company is requesting your approval to run an injection log in well SU 43-9. The log is necessary to verify that the Sterling B-4 Sand is adequately isolated during injection. If zone isolation is confirmed, Marathon will, at a later date, propose converting well SU 43-9 into a disposal well in the Sterling B-4 Sand. If you have any questions on the attachments or this project, please give me a call at 564-6315. Sincerely, J ~n~~e Enginee~r RECEIVED Anchorage Attachments A subsidiary of USX Corporation Environmentally aware for the long run. January 19, 2000 1420 Finish reviewing Marathon 403 for SU 43-9 (300-013), original PTD (163-011). Meet with Blair. Proposal is to conduct an injection survey using TDT-Water Flow log. Only have 10' of perforations -12' below the tailpipe. A successful WSO test was conducted when the well was originally completed. Marathon may propose to convert the well to disposal service. Checked well file, no bond log reported run. 7-5/8" hole was drilled to 6202'. 5-1/2" casing was set off bottom at 5380' and cemented with 450 sx. Blair would like them to add a temperature survey in the initial log suite. Place call to Gary Eller to let him know. Left message. February 10, 2000 1035 Place call to Gary Eller (564-6315) regarding SU 43-9 water flow log. Still have sundry...thought Gary was going to get back a week or so ago regarding further discussions. February 23, 2000 1200 Call from Gary Eller SU 43-9. Planning to do log tomorrow...have procedure ready. Plan to use RST tool...baseline log from bottom to 2000' with fresh water in hole. Fluid level is about 200' above the bottom. Then will pump as much as a tubing volume of Borax and displace the tubing. Then will log up looking for where the bleach solution has gone. Another component of the log is oxygen activation. Will set up above the perfs at various stations and during an injection cycle will look for oxygen movement. Pull tool out of hole and reverse it and look below the perforations. Will also employ a temperature log. Gave him verbal approval. Marathon OilCompany November 15, 1993 Alas(' ._~gion Domestic Production RO. Box 190168 Anchorage, AK 99519-0168 Telephone 907/561-5311 Tuckerman Babcock Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Dear Commissioner Babcock: In respons~~ur letter of November 5, 1993 regarding the flaring of gas from the The flaring resulted from a well production test which was conducted between September 6 and September 10, 1993. The purpose of the test was to evaluate the well potential to ensure that the well could sustain a projected 3 MMSCFD rate without producing water. The test was necessary to assure the $864,000 investment Marathon and our partners are making to install facilities for sale of gas to Enstar is justified. No significant water was produced, however, the well was not able to sustain the production rate. A hydrate plug, approximately 150-ft downhole, unexpectedly formed during the test. The formation of this hydrate plug resulted in an extension of the test duration from 3-days planned to 5-days actual. Downhole modifications to the well are being considered in order to allow sustained production at the desired rate. In order to justify the investment in production facilities for this well, this test was operationally necessary and the flaring should be allowed under 20 AAC 25.235 (a)(3). Further, in many respects the purpose and goals of this test are similar to those which allow the venting of gas for initial weii testing in 20 AAC 25.235 (a)(2). While Marathon believes that this particular test qualifies as allowable flaring for operational necessity, Marathon also believes that well tests have safety purposes. If, for example, a well potential test is conducted for purposes which include properly sizing safety equipment, we believe the flaring of gas from such a test would constitute flaring for safety under 20 AAC 25.235 (a)(1). If you have any further questions on this issue please do not hesitate to contact me. Sincerely, T. J. KO'vacevich Operations Superintendent XC: N. L Calvert Well File REC£1VED NOV 2 2 199~, Ataska Oil & Gas Cons. Commission Anchorage A subsidiary of USX Corporation ALASKA OIL AND GAS CONSERVATION CO~I~liSSION November 5, 1993 'WALTER J. HICKEL, GOVERNOR 3OOl PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-14.33 TELECOPY: (907) 276-7542 Lyndon Ibele Operations Supervisor Marathon Oil Company PO Box 190168 Anchorage, AK 99519-0168 Dear Mr. Ibele: We have received the September, 1993 Monthly Production and Gas Disposition reports for the Sterling Unit 43-9 well. These documents indicate the well flared 6.9 mmcf of gas during a five day period in September. Flaring of gas without Commission authorization is prohibited except in certain eases; however, 20 AAC 25.235 (a)(3) allows flaring for operational necessity for not more than five days in a 30 day period. A determination that the flaring was in fact an operational necessity and was not waste is still the responsibility of the Commission. Please advise us in writing of the circumstances which caused this flaring to justify your conclusion that the flaring was an operational necessity. In the future, if you can share your justification with the Commission before you flare, you may be more confident we sham your opinion that the flaring is not waste and is an operational necessity. Sincerely, Tuckerman Babcock Commissioner ~ printed on recycled paper ~ STATE OF ALASKA © ~;{ I A~ ~, OILAND GAS CONSERVATION COMMI~' .)N REPO OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown __ Stimulate__ Plugging m Pull tubing __ Alter casing __ Repair well ~ Pull tubing 2. Name of Operator ! 5. Type of Well: Union Oil Company of California (U~OCAL~)e_~l.°pm.ent~--- .... . ~-x~oratory 3. Address ! Stratigraphic P.O. BOX 190247, Anch., AK, 99519-~247 Se~ice Perforate __ Other __ 6. Datum elevation (DF or KB) 4. Location of well at sudace 2421.6' N & 527.5' W, SE Cur. Sec. 9, T5N, R10W, SM At top of productive interval Same straight hole At effective depth Same straight hole At total depth Same straight hole 246.36' (KB) 7. Unit or Property name Sterling Unit feet 8. Well number 43-9 9. Permit number/approval number 90-601 10.' APl number 50-- 11. Field/Pool Sterling 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical 6,202 feet Plugs (measured) 6,202 feet 5,3 3 7 feet Junk (measured) 5,3 3 7 feet Casing Length Structural 1261 ' Conductor Sudace 6191 ' Intermediate Production Liner Perforation depth: measured true vertical Size 8-5/8" 5-1/2" 5257 ' SSPF 6262'-5272' Tubing (size, grade, and measured de pth) Packers and SSSV (type and measured depth) Cemented Measured depth True vertical depth 450 SX 1272' 1272' 550 SX 6202' 6202' 13. Stimulation or cement squeeze summary ( wso ) 4 SPF 2-3/8" EUE, 4.7#, J-55 Baker Model N-1 Packer , Intervals treated (measu red) None Treatment description including volumes used and final pressure None 14. Represe .ntative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation 0 0 0 0 1840 psi Subsequent to operation 0 0 0 15. Attachments 16. Status of well classification as: Copies of Logs and Surveys run ~ Daily Report of Well Operations ..~ Oil __ Gas 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed % . ,..,.~ Title ~e_9, Form 10-404 0 2000 psi Service ~,. Date ~ - I"l - ~ b SUBMIT IN DUPLICATE KB= STERLING 11.70' UNIT #43--9 SPUD JUNE 19, 1963 100 SX TOP JOB FROM 60' 12 1/4" HOLE 8 5/8% J-55, 24# CEMENTED WITH 450 SX 7 7/8" HOLE TO 2230' 7 5/8" HOLE TO T.D. OTIS TYPE "A" SLIDING SIDE DOOR AT 5226' OPENS UP AND CLOSES DOWN (THIS COULD BE 10' DEEPER) OTIS "S" NIPPLE AT 5238' O'HIS COULD BE 10' DEEPER) BAKER MODEL N-1 PACKER AT 5241' SET WITH 1' COMPRESSION 2 3/8" EUE 4.7#, J-55 TUBING TAIL AT 5250' 5257' 5SPF WSO 5262' - 5272' 4SPF TOP OF RUNNING PLUG AT 5337' 5 1/2% 17#, J-55 & N-80 SET AT 5380' CblTq:) W/ 550 SX 'rD= 6202' MAXIMUM INCLINATION IS 2.75 DEG GRB a/10/90 STERLING UNIT 43-9 COILED TUBING CLEAN OUT 8/8/90 Arctic Recoil and BJ on location at 1330 hrs for initial rigup of equipment (plan to start operations at 0700 hfs on 8/9/90). Spotted equipment rig up the flow line to the bermed tank. Shut down operations at 1700 hrs. 8/9/90 Started operations at 0700 hrs. Rigged Arctic Recoil on the well. Nippled up the coiled tubing BOP an~ pressure tested to 3000 psi (OK). RIH with 1 1/4" coiled tubing while pumping at 1/2 bbl per min and 2500 psi. Taking returns to the tank and held aproximately 1000 psi back pressure on the well. As flow started to taper off due to the well filling with 3% KC1 the choke was opened until only water was returning. Circulated down with coiled tubing. Tagged fill at 5250' CTM (5260' KB). Circulated well clean to ETD at 5337'. Pulled to 5250' CTM (tbg tail) and blew the well dry with nitrogen, While unloading with nitrogen the tubing pressure was increased to 2000 psi. When the well was dry POOH with coiled tubing. Rigged up HLS and ran the TMD log as directed by Ralph Holman. Fluid level before starting job = 4880' Fluid level after unloadinf the well at 1600 hfs = 5250' Fluid level after logging the well at 2100 hfs = 5239' STATE OF ALASKA COMj' ,ON 0 5' IN 4, [ ' ' AI~, ;A OILAND GAS CONSERVATION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon __ Suspend __ Operation shutdown __ Re-enter suspended well __ Alter casing __ Repair well Plugging ~ Time extension __ Stimulate __ Change approved program __ Pull tubing __ Variance __ Pedorate __ Other ~ 2. Name of Operator ! 5. Type of Well: 6. Datum elevation (DF or KB) Union Oil Company of California (U~OCAL)Devel0pment- 246.36' (KB) feet ,, I Exploratory__ 3. Address t~ Stratigraphic __ 7. Unit or Prop~, rty name P.O. Box 190247, Anch., AK, 99519- 247 Se~ice__ SterIing Unit / 4. Location of well at surface 8. Well number 2421.6' N & 527.5' W, SE Cur. Sec. 9, T5N, R10W, SM At top of productive interval 9. Permit number Same straight hole 63-11 At effective depth 10. APl number Same straight hole 50-- At total depth 11. Field/PoObter1 Same straight hole ing 12. Present well condition summary Total depth: measured 6,202 ' feet Plugs (measured) true vertical 6,202 ' feet Effective depth: measured 5,337 ' feet Junk (measured) true ver[ical 5,337 ' feet Casing Length Size Cemented Measured depth True vertical depth Structural 1261' 8-5/8" 450 SX 1272 ' 1272' Conductor Surface 6191' 5-1/2" 550 SX 6202 ' 6202 ' Intermediate Production Liner ~ Perforation depth: measured 5257' SSPF (WSO) true vertical 6262'-5272' 4 SPF ,~. ,, ,,-~ i'!,: ~ ...... ,...,,, ,~,., "' .~., ,~ :,, t...~ ~,, .. Tubing (size. grade, and measured depth) 2-3/8" EUE, 4.7#, J-55 @ 5250' Packers and SSSV (type and measured depth) Baker Mo~el N-1 :Packer @ 5241' 13. Attachments Description summary of proposal ~ Detailed operations program ~ BOP sketch 14. Estimated date for commencing operation J 15. Status of well classification as: August 9, .~90 16. If proposal was verbally approved :'~' Oil __ Gas __ Suspended ~ Name of approver Date approved Service 17. I hereby certify that the foregcng is true and correct to the best of my knowledge. SI-ned ~~'~~~ "-~ 'g GARY S. BUSH //~ ~. ~ Title REGIONAL DRILLING MANAGER Date FOR COMMISSION USE ONLY ' " Conditions of approval: Notify Commission so representative may witness I Approval No.?~..., Plug integrity __ BOP Test __ Location clearance __ Mechanical IntegrityTest __ Subsequent form required 10-. /¢¢/-~' ~,.,,.,rove6 Oog¥ ORIGINAL SIGNED BY Approved by order of the Commissioner LONNIE C. SM!TH ~Commissioner gate ~).-" Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE PROCEDURE i · · · · · MIRU. Coiled Tubing Unit (1-1/4"). Test BOPE to 5000 psi. Run the coiled tubing and a 1.75" wash nozzle to the fill and wash through with N2 foam and 3% KCL water. Breaking up the fill may require a small mud motor, if this is the case straight 3% KCL water will be used until the fill is broken up and then nitrogen foam will be used to lift the sand. Minimum c/o depth is 5310', 5337' is preferred. Once "TD" is achieved blow the well dry with nitrogen and POOH. Confirm c/o depth w/ W/L measurement prior to releasing CTU. RDMO KB- STERLI 11.70' NG UNIT #Zl-3-9 SPUD JUNE 19, 1963 100 SX TOP JOB FROM 60' 12 1/4" HOLE 8 5/8", J-55, 24# O 1272' CEMENTED WITH 450 SX 7 7/8" HOLE TO 2230' 7 5/8" HOLE TO T.D. i I OTIS TYPE "A" SLIDING SIDE DOOR AT 5226' OPENS UP AND CLOSES DOWN (THIS COULD BE 10' DEEPER) OTIS "S" NIPPLE AT 5238' (THIS COULD BE 10' DEEPER) BAKER MODEL N-1 PACKER AT 5241' SET WITH 1' COMPRESSION TOP OF RUNNING PLUG AT 5337' 5 1/2", 17~, J-55 & N-80 SET AT 5380' CblT'D W/ 550 SX TD -- 6202' 2 3/8" RUE 4.7#, J-55 TUBING TAIL AT 5250' 5257' 5SPF WSO 5262' - 5272' 4SPF POSSIBLE SAND PLUG AT 5270' 7/10/90 MAXIMUM INCLINATION IS 2.75 DEG GRB 7/12/90 TEXAS ®~: TOOLS OCT. S4 ; UNIT 1058 l®l)teeee 1024 TUBING STRIPPER/PAC~~R 5,000 psi Working Pressure H~S Service L.._J 1.00'Series DS322 I .1.25 ~eries DS323 Telex: 790905 TX TOOLS HOU phone: (713) 6206 UNION OIL & GAS DIVISION WESTERN REGION A N C It'0 R A G E ~,! S T R I C T TRANS,',I ITTAL TO' Tom Marshall FRO~I: Jack Badgett Transmitted herewith are the followi, ng- Run No. Sepia Blue Scale ea. I ea. DATE- ~~_ 1969_ _- _ WELL N)OtE: Ster!in~ Unit 43~9''~-'- Knik ^tm Si~i'~"#r, TSterling Ut. 43-28 ~h' Creek 12-8,';:<:~na$. Ufiit 33-3o~, qK~ii"-'bfli t ~'i[~72~. ~f'"'unit 13 - 87. RECEIVED Induction Electrical ~og Dual Induction Laterlog BHC Sonic/Caliper Log BHC Sonic/Gamma Ray BttC Sonic/Caliper/gammi Ray Log Formation Sonic I,og Formation Compensated Sonic Log (Gamma Ga. mnm) Formation Density Log (Fd) Neutron Log Formation Neutron Log (Fn) High Resolution Dipmeter (HDT) 'CD~! Sa£et7 Print CD~4 or Printout- CDM or Po!ywog Plot CDM Polar Plots Proximity ¢!icrolog/Caliper Log Gamma Ray-Neutron Log Gamma Ray Collar Log Cement Bond Log Sidewall Neutron Porosity Log Laterlog 3 Mud log Core Descriptions, Conventional, Core Descriptions, Sidewall Core Ana.lysis Formation Tests Directiona!. Surveys' Core Chips San~ple Cut RECEIPT ACKNOWLEDGED'_ .~~-~/~ ~_~ DATE'~_7~~~~ REFUR, RECEIPT TO' Union Oil & Gas Di. vis~on- Anchorage t~istri, c.t 2805 Denali Street Ancho'rage, Alaska 99503 Attn: Rochelle Carlton Form P--3 STAT{ ,F ALASKA SUBMIT IN TRIPI~ (Other instructionalL OIL AND GAS COh~-:RVATION COMMITTEE verse aide) SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen or plug back to a different reservoir. Use "APPLICATION FOR PERMIT--" for such proposals.) OIL [~ OAS [] OTHER WELL WELL 2. NAME OF OPERATOR Union Oil Company of California Effective: July 1, 1964 5. LRA~E-DESIGNATZON ina SERIAL NO. A-028063 6. IF INDIAN, ALLOTTEE OR TRIBE NAME 7. UNIT AGREEMENT NAME Sterling Unit 8. FARM OR LEASE NAME ADDRESS OF OPERATOR 9. WELL NO. 507 W. Northern Lights Blvd.; Anchora2e, Alaska SU 43-9 4. LOCATION OF WELL (Report location clearly and in accordance with any State requirements.* See also space 17 below.) At surfece 2421.6'N & 527.5'W, SE Corner Sec. 9, TSN, R10W, SM 10. FIELD AND POOL~ OR WILDCAT Sterling Gas Field 11. 8EC,,T.,R., M.,OR BLK. AND SURVEY OR AREA Sec. 9, TSN, R10W, SM 14. PERMIT NO. 15. E~VATION8 (Show whe~er DF, aT, Ga, et~) 12. BOROUGH ] 18. STATE 63-11 246.63' KB Kenai Penin. [Alaska 16. C~e¢~ Appropriate Box lolndicate Nature o[ Notice, Repo~,orOther Data NOTICE OF INTENTION TO: TEST WATER SHUT-OFF ] I PULL OR ALTER CASING FRACTURE TREAT I [ MULTIPLE COMPLETE SHOOT OR ACIDIZE ]__~ ABANDONS REPAIR WELL CHANGE PLANS (Other) SUBSEQUENT REPORT OF :' WATER SHUT-OFF ~ REPAIRING WELL ~ FRACTURE TREATMENT ALTERING CASING SHOOTING OR ACIDIZING ABANDONMENTS (Other) Place on Production NOTE: Report results of multiple completion on Well ompletion or Reeompletlon Report and Log form.) 17. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, including estimated date of starting any proposed work. If well is direetionally drilled, give subsurface locations and measured and true vertical depths for all markers and zones perti- nent to this work.) * SU 43-9 was placed on production October 24, 1966. The well is flowing into- Consolidated Utilities' metering facilities. / 18. I hereby ~~/~~~t~~ certify e f e~ng ts true and correct SIGNED . TITLE Production Supervi DATE October 25, 1966 (This space for Federal. ~~.~~ APPROVED BY .,. -TITLE CONDITIONS OF/APPROVAL, IF ANY: DATE *See Instructions on Reverie Side RECE!V O OCT 2 6 DIVISION OF MINI:~5 ANCHORAGE Form P--3 STAT[ ,: ALASKA SUBMIT IN TRIPI~ (Other lnstruction~[ OIL AND GAS cONSERVATION COMMITTEE verse side) Effective: July 1, 1964 5. L~"~SE-~ESi0~*--~'0~ i~FS,aiAL NO, A-028063 6. IF INDIAN, ALLOTTEE OR TRIBE NAME SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen or plug back to a different reservoir. Use "APPLICATION FOR PERMIT--" for such proposals.) 1. 7. UNIT AGREEMENT NAME 0ILwELL IqWELLGAS [k~ OTHER Sterling Unit 2. NAME OF OPERATOR 8. FARM OR LEASE NAME Union 0il Company of California 8. ADDRESS OF OPERATOR 9. WELL NO. 507 W. Northern Lights Blvd.; Anchorage, Alaska SU 45-9 4. LOCATION OF WELL (Report location clearly and in accordance with any State requirements.* See also space 17 below.) At surf, ce 2421.6'N and 527.5'W, SE corner Sec. 9, TSN, RiOW, SM 15. ELEVATZONS (Show whether ~F, BT. OR, ~) 246.65' KB 14. PERMIT NO. 65-11 10. FIELD AND POOL, OR WILDCAT Sterling Gas Field 11. SEC., T., a., M., 0a BLK. AND SURVEY OR AREA Sec. 9, TSN, RIOW, SM 12. BOROUGH I 18. S~ATE Renal Penin. I Alaska 16. Check Appropriate Box To Indicate Nature o[ Notice, Report, or Other Data NOTICE OF INTENTION TO: TEST WA~ER SH~T'OFF { { PULL OR ALTER CASING FRACTURE TREAT j [ MULTIPLE COMPLETE SHOOT OR ACIDIZE : ARANDON* REPAIR WELL CHANGE PLANS (Other) Place on Production SUBSEQUENT REPORT OF :- WATER SHUT-OFF : REPAIRING WELL FRACTURE TREATMENT ALTERING CASING SHOOTING OR ACIDIZING ABANDONMENT* (Other) NoTE: Report results of multiple completion on Well ompletion or Recompletion Report and Log form.) 17. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, including estimated date of starting any proposed work. If well is directionally drilled, give subsurface locations and measured and true vertical depths for all markers and zones perti- nent to this work.) * SU B5-9 will be placed on production in the near future. ? SIGNED K* -~-. narunann TITLE Production Supervisor . DATE Oct, 20:. 1966 CONDITIONS OF APPROVAL, IF ANY: TITLE *See Instructions on Reverse Side DATE /~ '" ~. & RECEIVED OCT 2 6 19'66 DIVISION OF MINES & ~IN~ ~O~GE 3001 l~z'cupiu8 Dr. Re: lit11 mine chn8~,. ~,.,. mud eozTeeZed oa our recordo. 'b thud ~ of fora 1~3 is KLV~kp Form P--3 STA ~F ALASKA SUBMIT IN TRI~ (Other instruction~ OIL AND GAS CONSERVATION COMMISSION verse ~tde) SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen or plug back to a different reservoir. Use "APPLICATION FOR PERMIT--" for such proposalL) OIL [[~ OAS ~--] WELL WELL OTHER 2. NAME OF OPERATOR Union Oil Company of California ADDRESS OF OPERATOR 2805 Denali Street, Anchorage, Alaska 99503 4. LOCATION OF WELL (Report location clearly and in accordance with any State requirements.* See also space 17 below.) At surfs ce 2421.6' N and 527.5' W, SE corner Sec. 9, T5N, R10W 14. PERMIT NO. 63-11 15. E~.~.VA~ONS (Show whether DF, .R?, OR, eta) 246.63' (KB) Effective: July 1, 1964 . 5. LEASE DESIGNATION AND S~RL~ NO. A-028063 6. IF INDIAN, ALLOTTEE OR TRIBE NAME 7. UNIT AGREEMENT NAME . Sterlinq Unit 8. FARM OR LEASE NAME 9. W~LL NO. SU~. 43'-9 10. FIELD AND POOL, 0R WILDCAT Sterling Gas Field 11. SEC. T., l., M., Oi ELI. AND SURVEY OR AREA Sec. 9, T5N, Ri0W 12. BOaOUGH ;~ ~8. s,,,, Kenai P ~a s ka 16. Check Appropriate Box T° Indicate .Nature of Notice, Report, or Other Data ' NOTICE OF INTENTION TO: TEST WATER SHUT-OFF I I PULL OB 'ALTER CASING FRACTURE TREAT MULTIPLE COMPLETE SHOOT OR ACIDIZE ABANDONS REPAIR WELL CHANGE PLANS (Other) SUBSEQUENT REPOR~ OF: WATER SHUT-OF, ~ . REPAIRING WELL SHOOTING OR ACZDI:ING ~-2 " AE~'DoN~EN~* ' (Other)' Chance desionati0n:': '5 '.. (No,z: Repor~results of ~ultlgiei~mPletion on::We~ Completion or Recompletion Re~6~ g~d, Log'f0rm~:) 17. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertineut details, and give pertinent dates, tncludl.n~ e~t~m~tted date .of...s~.~ng any proposed work. If well Is dlreetionally drilled, give subsurface locations and measured and true vertical depths fo'r' ~alkmark~rs grid zones perti- nent to this work,) * · · . Re: Telephone conversation of this date: Subject well, formerly called Kenai Unit 43-9~ shall hereafter bdi Sterling Unit 43-9 to correspond with recent change in operating~:Unit:s bOundary.:r . 18. I hereby eertify/~ SIGNED .,~ , / ;'. Hartmann TITLE Production Engineer (This space for Federal or SMte ottlee use) CONDITIONS OF'~PROVAL, IF ANY: 4,', *See Instructions on Reverse Side GAS :LL OPEN FLOW POTENTIAL TEST 4-POINT TEST Test Initial [~3 Annual [~] ORT 'RECl IVED' Special OEC 13 1963 ['~roleum Branch Division of MinesJa~st~&bt~6,1s Field [ Reservoir Sterl, ing Gas Field Sandstone Operator I Lease Union Oil Co. of California Anchorage 028063 County [ Location I Completi0nDate enai Precinct 12421.6'N & 527.5'W SE cor Sec 9 TSN. R10WI 7-5-63 TBG. I CSG. Temperature ' Temperature X 103'F 49 'F 15-1/2" 17.~ 4.892 S380' TBG. Size ] Wt/Ft. O.D. I.D. Set @ Gas Gravity Avg. Prod. GL (Separator) Length (L) 2 .-. 3/8" ..4.7%t .2-3/8" 1.995 5250' .560 Pipeline Connection [ Type Taps None IXVell No. KU 43-~ III~rval 6202' 10 5282-72 Gas-Liquid Hydrocarbon . ] Gravity of ' Ratio MCF per Bbl. I Liquid (Apt) No liauid ' Multiple Completion (Dual or Triple) [ Type production from each zone Dr_v natural aa g - -- OBSERVED DATA Flow Data Time (Prover) ~ Press. at ~x Pf ~ : : Casing :.: F!pwing No. of Flow ~ (Orifice)' Prover Ill XI~dItDf Press. Temp. Hours Size Size psig xxPsia Pr2 ~': :~ psi~ . oF si - , ...... - -,, 194,0 2256 5096' .,,, ' !. ,, 1 hr ~0 mtn 2 3Z8 1363 : ':'/" 540 ~. ~ ,, 5 ,, 2 5/] 6 1 S99 ...... 52° ~. 36, 2 174 .... 177~ ~ :' :' '";' ..... g2° , FLO%V CALCULATIONS Coeffi- Flow TemP'i Gravity [ ......'compress.' "' "'"' ' ::':' No. cient ----x/ h p Pressure Factor Factor Factor Rate of Flow (24 Hr.)V w m psia F F F t g pr;' ::, !. -.Q M:CF/D~ ', e. ,2.2050 ....1614 . 1.0078 "I, o33'i · 1 '[~ 1' i4:' :',/=: 4:1 d2 / a. I1.436o .... 1790 1.0078 ..... 1.0351,,. 1.122 3009 ,., ,,, .soa ............ ss9 .ooss 1..0as lYss PRESSURE CALCULATIONS H P Cal. w · ~' (psia) P" F Q (F q)-* ~lks{l~ix~ ~5~54l~'. p · :t c c c ". '~~:! : "':' ,:LW~ : IF t , Psia [Thsnds) ~ . ~., ...... .1...955. 3822 .126'8.' ,,,, ~-. . ........ 204.9 4198 .892 .... a. . ..... 2124 ..... ~' [ :45tl .. '579'.. ,::', :.,-:; ~: 4. , ,, , 2188 4787 30,3 ,,,_ Absolute Potential n .18,000 CERTIFICATE: I, the undersigned, state that I am tb (company), and that I am authorized by said company to make this report; and that this report was pre- ,, the facts stat th ein e tru , correct and complete to pared under my supervision and direction and that ~~~~/~ . the best of my knowledge. . ,.:: Signatdr~ ~"'~'- ' ' ' Alalka Off and Gas Conservation Commission Gas Wen Open Flow Potential Test Report (4-Point Test) Form No. G-1 Authorized by Order No. 1 Effective October 1, 1958 Al3 N ,c-W AND 3914 GILMORE AVENUE BAKERSFIELD. CALIFORNIA FAIRvlEw 7-226' SUBSURFACE PRESSURE SURVEY ow~E~ Union 0ii Co:.%:any of California ~,ELo Stcr!in_g Gas w~uu N~.~E K j% &3-9 ~~~~ Perf' : 5262'-5272' · ~ -' _.~.oo~' .olocv% r.~, 5226.~' zo~ · ,~,~,~o o~,~, 2-3/g" ~'~th Otis S~dinE Side ...... ' Otis Position #l "S" Nioole ~ 5238'; gaker '~.~'~ ::u. ................................. - orlZU7 ~_~os~ Per~p.~._~z~e~re_.~u_~e~ ~ APP ~4rJ_ng ~. Point C~ti.c~ Fl~,¢ Test, PICK UP ~-- _52~J _ MAXIMU~ TEMPERATURE .... 105 °r e ~2Z~ ....... 33;0,'r~ '/'~ ;Element TR¢ ' S~ri~ No. 3916 ................. ~:00 l:O0 3:00 5:00 7:00 9:~ : ~ ~. ~ ' : ,/ ~ ~ ~ .~ ~ ~ .- ~ . :; ........................... . " ~ .~L,4 , ~ : . . : . ~E ~ ~ ' ~ z,/ ' ''~ ~:!0 20Z8 !~" ~-3~ 2037 ~ ~~¢~ ~_~,_ZG~ ~/~ OAVF/CE ~'~71G ...... ~:15 206~ t/8"- 7~20 2032 5/16" il.'45~ "- P~OPPING 8:11~.' ,' 1777, ' 22=~5 '20~ ]iS" ?;~5 20% ~'~ /Z:/&P~ ,, /307 9¢Z7~. ,, :/77~'. ' ~,~.~ 9~2~ ~/~, 0 fl l:O0 1957 SI 8:~!P9 1L~ 4 44PM ,, I~Z~ 9: 14PN ,, 1874 'El*f: ............. ~:,, ~5:~op~/7 P/~ ,," /3~//a4e ~4'F ~/ ?~. // '~ ' ~:32 20:~'3/.,... 9:00 2..~ 3/16 Un ton Off Co. of Calif., Operator Kenai Unit 943-9 Page 2 HISTORY Casing record at he~inning of work Cast. nc record at_end .of w_o6k ......... New Well TD 6202' Plug 5337' 8-5/8" cemented 1272' 5-1/2" cemented 5380' WSO perf 5257' 'OK Perf 5262-5272' Da, re 19 6-19 695 _Remarks ............................... Spudded in with 12-1/4" bit at 11:50 A.M., June 19, 1963. 6-20 1310 Drilled 12-1/4" hole to 1310'. Cemented new 8-5/8", 24~ J-55 ST&C, Youngstown R-3 casing thru Baker guide shoe at 1272' with 450 sacks Meal construction cement then pumped'in 100 sacks ditto type cement thru 2" pipe hung at 60' in 8-5/8" - 12-1/4" annulus. 6-21 1479 Installed Baash Ross 8" - 3000 FL castnghead and dual 8" - 3000 Shaffer LWS BOP with GX-8 Hydril. Tested both BOP. Drilled ahead with 7-7/8" bit. 6-22 2268 Drilled 7-7/8" hole to 2230' and drilled ahead with 7-7/8" bit. 1469'- 1/2o, 1998' - 2-3/4o. 6-29 6202 Drilled 7-5/8" hole to 6202'. 4130' - 1/4o, 5660' - 3/40. Mud 834~, 51 sec., 5.2 ml/15 mtn, 2% sand. Ran Schlumberger logs 1272-6202'. 7-1 6202 Cemented new 5-1/2", 17%, J-55 and N-80, R-3 LT&C casing thru Baker guide shoe at 5380' with 550 sacks Meal construction cement. Landed casing in Baash-Ross FL casinghead and installed Baash- Ross FIX packing. Installed OCT 8"-3000 x 6"-3000 tubinghead. Reinstalled and tested same BOP assembly. 7-2 6202 Plug 5337' Measured in 4-3/4" bit on Baker casing scraper to plug at 5337'. Ran Schlumberger Gamma-Collar log. Perforated five Schlumberger Jets at 5257',, then tested 'WSO OK with dry 2-3/8" EU tubing and Howco tester set at 5171'. Recovered 33 lineal ft. of mud .in 60 minute test. Perforated 41 Schlumberger Jets from 5262-5272'. Union Oil Co. of Calif., Operator Kenai Unit $43-9 Page 3 Da De~ 1.963 T. est:~t9 ,rval Period IP PP PSI Remarks 5262-5272' 120 rain 15105 1855 2250 trace of mud. test. No free water. Gas to surface in 2 min. Plowed dry gas with Tool open throughout 7-5 6202 Plug 5337 Hung 2-3/8" EU tubing at 5250' with top of Otis type "A" sliding side door at 5226', top of Otis Type "S" position $1 nonported choke landing nipple at 5238' and midpoint of Baker Model "N-I" mechanically set production packer at 5241'. Changed mud to water thru side door and swabbed to flow. Plowed dry gas to stack until clean. S! - 1960%. Rig released 6 AM, July 5, 1963. 7-6 to 8-16 S~anding. 8-17 Installed Otis "PS" blanking mandrel in Otis "S" nipple and bled off all surface pressure. Dumped one barrel of florescent red dyed alcohol down tubing. Type "A" side door closed. LOW MASS GAS ANALYSIS Component Amount; mol~ Hydrogen 0.47 HRS 0.00 NH5 0.00 so2 o.oo Methane 98.65 Ethane 0.51 Propane 0. &8 I s obutane 0.00 N Butane 0.05 I s opentane 0.00 N Pentane 0.00 Hexanes 0.06 Benze ne 0.00 Toluene 0.00 100.00 Average mol weight 16.22 Specific grav,ity Above calculated on an air-and .water-free basis Water ~. 28 Air 7.24 o.s6O UNITED STATES DEPARTMENT OF THE INTERIOR GEOLOGIC, AL SURVEY LESSEE'$ MONTHLY REPORT OF OPERATIONS Sta~ ........... ~ ................. ~ .... KenaJ~m~ ............ F/dd ....... 8~.erlJJ~.G~ .......................................... The fo~wi~ ~ a w~t rein of oper~ and pro~n (i~l~i~ d~ a~ produd~ ~) for t~ ~ of ...................... ~y ......................................... , ]9~ .................................................................................................. ~ge~'s add. ss....ZR~.~...D.e~[$~.e.t .................... : ...................... ~~ny...~.~.~n..Q~...~.s...~[...~[~.a.~.D~.~.. ~ ~ ..................................... .... ................... ............. .................. ,, .......... P~e ...... BRo~.~y..6=~Z~i ...................................................................... ~s ~ ..... ~z.~[.~~g.er ................ ~..~"'~ .... Idlltlltltfllllllllllllllllltlllllllltllllltlllllllltlll O~llllllltlllllllllltt$tllllllllllllllllll lllltllllll IIllllOIt~ltlJlllJtllll Itlllll I II1111 II Illlllllllltlllttlllllllllllllllllllllllllllllllllllllllltllllllltllllll IIIIIlllllll tlllllllllllltllllllllltif Slc.~.o', ~. ~: w=~, DAYs ~ ~ : Cu.~.orO~ ~ O~.s~ ~ B~o~ ~(~.~~ut~.~ ..: ..... : ..... : .... , , ~= ~=, ...... : ...... ~ ............ ~ ...... , ............. , ........... , .......... , .... I I I I ~ I I I I I I Sec 9 ,I 5~ ,I~ ~ 43~ ,' ',' ,,' I ~one ,I Inzl~ll~ BOPE, NE ss [/4 I I I I i '1 ! ! , ! , ! ! ! ! ! ! I I ' , : ,' ,: found top cern ent at 5337'.: Obtained WSO:at 5257'!. Jet perorated 4 - 1/2" hpf 5262~5272: and teste~t perfs With HCT~I. Total flow time 2 hqhrs, ,bowed dryigas at e~ttmated i3,000-5,000M CF/D rate. , , , , , Hung 2-3[/8" t~bing at 5~50' withlpacker i~t 5241'. Shut well in and re eas rig 3:00 AM, j y, 5. , ; | I I I I Ran oponTflowlpotonttal ost on Ir 25. I I I I I I I KLLL{VLU ! I , ' ' 'AUG 198"3 I I I I I ' ' ' ~ , ~ Pe~:.ro!eum I I ; . I ' : ~ ' ' D~,{sion Of Mine~ on:l Min~r<~l~ ! I I I I Il ,' ', ,' Alc~o, D~pt. ~f Naturcd Resourcgj;. I I I ~1' ....... I ~ I I I I I ! t I I I I I I I 1 I I I I I I I I I I I I I I I I I I I I ~ I I I I I ! I I I I t J t I I I I I J I I I I I I I I I I J t I I I I I I I I I ~ t I I I I I I I I I I t I I I I ! I I I L l .................. 4 ...... ,. ........... .*. ................... ~..., NoTz.--- There were .......... ~.Q. ...................................... runs or sales o! oil; ........................... .~..Q .............................................. M cu. ft. of gas sold: ..................... ~.Q. ............... ; .......................... runs or sales o! gasoline during the month. (Write "no" where applicable.) Ncn's. -- Report on'this form is required for each calendar month, regarc~ss o! the status o! operations, and must be filed in dupli- cate with the supervisor by the 6th of the succeeding month, unless otherwise directed by the supervisor. 10 9 8 7 6 ' 10 9 8 7 6 11 3 4 5 6 7 8 910~ ~ 4. ~, 6 7 8. 9 10~:~,'--~-? 3 ,~ 6 6 7 8 91( Forth ~-331a (Feb. ! ..... i--~l ...... I ...... I I I i i i I I i i I i ,( (SUBMIT IN TRIPLICATE) UNITED STATES DEPARTMENT OF THE INTERIOR GEOLOGICAL SURVEY Budg~ Bureau No~ 42-R358.4. Approval expires 12-31-60. u-..o .... A-_~~ ....... U~it ........ ~ .............. SUNDRY NOTICES AND REPORTS ON WELLS NOTICE OF INTENTION TO CHANGE PLANS ....................... I ...... SUBSEQUENT REPORT OF SHOOTING OR ACIDIZING ................. { ..... NOTICE OF INTENTION TO TEST WATER SHUT-OFF .............. I...... =..,ou,.~ REPORT OF ALTERING CASING ....................... { ..... NOTICE OF INTENTION TO RE-DRILL OR REPAIR WELL ......... / ...... SUBSEQUENT REPORT OF RE-DRILENG OR REPAIR ................ I ..... NOTICE OF INTENTION TO SHOOT OR ACIDIZE .................. I ...... SUBSEQUENT REPORT OF ABANDONMENT .......................... I ..... NOTICE OF INTENTION TO PULL OR ALTER CASING .............. I ...... SUPPLEMENTARY WELL HISTORY ................................... I ..... NOTICE OF INTENTION TO ABANDON WELL ...................... t ...... 1 ~_~_~ ................ ~ ....................... t__~__ (INDICATE ABOVE BY CHECK MARK NATURE OF REPORT, NOTICE, OR OTHER DATA) ............ ~_20 .............................................. 19~_~__ Well No. ~, ........ is located {~__ ft. from__ ~line and __5~,__ ft. from~ line of sec ..... m_ ..... .... ~_~~_~~~.~____,~ ............ ~ ........... s~~ .......... .... ~~ ...................... ~;~~;~,~ ......................... ~, .................... The elevation of the derric~ floor above s~ level i~ __2~__ ft. DETAILS OF WORK I understand that this plan of work must receive approval in writing by the (~eological ~urvey before operations may be commenced. Company -- '~i-~-~~-~' -~ ............................................................................. Address ..... 2805_~_~ ................. .................. ~ii~.,__~ ................. ................... ~-~-6t~ ................... Title __.l;tiIit~_M~~ ....................... GPO 862040 COMPLETION REPORT OPERATOR: Union Oil Company of California FIELD: Sterling Gas Field WELL: KENAI UNIT ~43-9 LOCATION: 2421.6' north and 527.5' west from the southeast comer of Section 9, Township 5 north, Range 10 west, Seward Meridian, Alaska. ELEVATION: Ground 234.93' Kelly bushing: 246.63' All depths were measured from K.B. CONTRACTOR: Santa Pe Drilling Company EQUIPMENT: All equipment trailer mounted. Mast: 94', 210,0005 Hopper Drawworks: Hopper Model C..3fXTA double main drum powered by one GM C 6-110 diesel engine through Allison Torquematic transmission Pumps: 1 - National C-250 (7-1/4" x 15") powered by 2 twin GM C 6- 71 diesel engines 1 - Halliburton AC (4-1/2" x 10") mud mixing pump powered by 1 GM C 3-71 diesel engine Drill pipe: Drill tubing 3-1/2", 9.3~ Pittsburg, special Acme thread N-80, Eli, R-2 with tubing couplings for tool Joints Drill~collars: 18 - 4-3/4" x 30' Reed extra hole. STARTED DRILLING: COMPLETED DRI~G: June 19, 1963 July 5, 1963 STATUS: Shut in gas well. A. G. Hilton District Engineer lily 23, 1963 Harold Lltu District Superimudent 280~ Deuali Stzeet ~d ~ ~; 1963 tn conoi~~u of mile of t~ sub]~C ~lch s~les-~ld, Thank ~ou tot ~oUr cooperecion .'in volunteering ~he emsple cut ~he Sterling dtecovery ~ell. Hey 22. 1963 such a nmn~ as to p~ .the. ~t' bounda~ it ~ 1,500 hat i~on the 2) A caq,lete set' of ~ell lanp..~ .and .core chips .h not sreater th~ 10' Lntervalo.vLll be ~'for the. Sttteo Forth 9-381 a (Feb. 1951) (SUBMIT IN TRIPLICATE) UNITED STATES DEPARTMENT OF THE INTERIOR GEOLOGICAL SURVEY Budget Bureau No. 42-R358.4. Approval expir~s 12-31-60. SUNDRY NOTICES AND REPORTS ON WELLS (INDICATE ABOVE BY CHECK MARK NATURE OF REPORT, NOTICE, OR OTHER DATA) The elevation of the derrick floor above sea level is __~;~$___ ft. ~i~~, DETAILS OF WORK (State names oF and expected depths to objective sands; show sizes, weights,~ and lengths of proposed casings; indicate mudding jobs, cement- inf points, and all other important proposed work) I understand that this plan of work must receive approval in writin~ by the Geological -~-urvey before operations may be commenced. Company "~, _~ ......... * ..... * ", .... - ............................................... .... ~ ~t-~~,~-~-~,.~~ .......................... Address , ../~ .~ / --/ Title ;- ~ . .... ......... ~l~.-~a:~~ ................ GPO ~6 20~0 APPLICATION FOR PERMIT TO DRILL, DEEPEN OR PLUG BACK APPLICATION TO DRILL NAME OF COMPANY OR OPERATOR Address Union O_i! 2805 Denali Street DEEPEN [] PLUG BACK CI DATE May 15, 1963 DESCRIPTION OF %VELL AND LEASE Name of lease F e doral_Lease.A- 0 g 8 0 6 3 XVell location (give footage from section lines) 1Veil number ] Elevation (ground) Kena! Unit ~43-9 Section--township--range or 1)locl~ & survey Distance, in~iTe's?%-n'~' di~-e~'tTon-f~n~-~earest town or post office Nearest ulsr. ance Irom proposea rotation to property or lease line: feet Appm~!ma~ly_550 Proposed depth: [ Rotary or cable tools 6,500' 1 Number of acres in l~se: 1,878 Distance from proposed location to nearest drilling, completed or applied--for well on the same lease: ............ [~p~o~.--date wogk will starl Number of wells on lease, including this well, completed in or drilling to this reservoir: feet None If lease, purchased with one o~ more wells drilled, from whom purchased: Name Address Status of bond Oil No. B-73310 dated 8_-3-60 fgr, $)~,q,qO0, ~xecuted by Union 0tl Pacific Ins, co, as Burety, filed BLM ,anchorages, ' Remarks: (If this is au application to deepen or plug back, briefly describe work to be done, ~ivin~ present producin~ zone and expected new producing zone) 1. Drill 12~" hole to approximately 1,200'. 2. Run and cement 8-5/8" casing to I, 200'~, using sufficient cement to fill annulus 3. Install and test BOP E. 4.. Drill 7-5/8" hole to 6,500' TD and run logs. 5. If warranted, run and cement 5~" casing below base of deepest attractive sand, 6. Make ~.~O tests and determine productivity of gas sands. 7. House and shut well in. Blowout prevention equipment: Double hydraulic Shaffer, GK Hydril CERTIFICATE: I, the undersigned, state that I am the Di~i* Mgr.- of thel~iiiOn Oil -~,. ~,~ California (company), and that I am author~ed by said comply to make this report; and that this report was pre- pared ~der my supervision and d~ection and that the facts st~ ere~ are true, co omplete to ~ignat~e ' ~ ~ Permit Number: 6 3-1 ] ~ -May 22, 1963 Approval Date: . ~/ .~, . Approved By: ,~//~ Petroleum Geologist Notice: Before sending in this form be sure that you have given all information requested. Much unnecessary correspond- ence will thus be avoided. See Instruction on Reverse Side of Form Alaska Oil and Gas Conservation Commission Application to Drill, Deepen or Plug Back Form No. P.1 Authorized by Order No. 1 Effective October 1, 1958 : -r, -, ~ ~ ~ %./ .'~'. ~ -.,9 ~'~ ~ ~ ~'~ ~...~ UNION OIL COMPANY OF CALIFORNIA, ,~",~: OPE RAT OR '-'-'.:' K ENAI UNIT ~.,~ PROPOSED KENAI UNIT 979 SCALE: I": 4~0' 5- 20-63
