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W:^DΘWĞƌŵŝƚƚŽtŽƌŬ͘&ŝƌĞƵƉƌŝŐ͕ůŝŐŚƚƉůĂŶƚƐĂŶĚŚĞĂƚĞƌƐ͘WƌŝŵĞƉƵŵƉ͕ĨůƵŝĚƉĂĐŬĂůůƐƵƌĨĂĐĞůŝŶĞƐ͕ƐƚĂŶĚƉŝƉĞŵĂŶŝĨŽůĚ͕ĐŚŽŬĞ ŵĂŶŝĨŽůĚ͕KWƐƚĂĐŬΘƚĞƐƚũŽŝŶƚĨŽƌKWƚĞƐƚ͘^ƚĂƌƚKWdĞƐƚΛϮϱϬͬϮ͕ϲϬϬ͘dĞƐƚŶŶƵůĂƌΛϮϱϬͬϮ͕ϱϬϬ͘K'tŝƚŶĞƐƐǁĂŝǀĞĚ ϭϬͬϭϯͬϭϵΛϲ͗ϮϮWD͘ZhƚŽŶŐƐ͕ĂŝƌƐůŝƉƐĂŶĚŵŽǀĞĚŚĂŶĚůŝŶŐĞƋƵŝƉŵĞŶƚƚŽƌŝŐĨůŽŽƌƚŽƌŝŐĨůŽŽƌ͘hŶĂďůĞƚŽŐĞƚƉĂƐƐŝŶŐŚŝŐŚƚĞƐƚ ;Ϯ͕ϱϬϬͿŽŶŚŽŬĞDĂŶŝĨŽůĚsĂůǀĞηϭ͘ůĞĞĚƉƌĞƐƐƵƌĞƐ͘'ƌĞĂƐĞĂŶĚĐǇĐůĞDsηϭ͘ZĞƉĞĂƚƚĞƐƚͲ'ŽŽĚdĞƐƚ͘>ůŝŶĞƌĂŶĚƐƉŽƚƚĞĚƉŝƉĞ ŚĂŶĚůĞƌŽŶƌŝŐ͘hŶĂďůĞƚŽŐĞƚƉĂƐƐŝŶŐŚŝŐŚƚĞƐƚ;Ϯ͕ϱϬϬͿ,ZĐŚŽŬĞǀĂůǀĞ͘'ƌĞĂƐĞĂŶĚĐǇĐůĞ,ZĐŚŽŬĞǀĂůǀĞ͘ZĞƉĞĂƚƚĞƐƚͲ&Ăŝů͘KƉĞŶ ,ZsĂŶĚƉƵŵƉƚŚƌƵǀĂůǀĞƚŽĐůĞĂƌĚĞďƌŝƐ͘ůŽƐĞ,Zs͘ZĞƉĞĂƚƚĞƐƚͲ&/>͘ĂůůzĞůůŽǁũĂĐŬĞƚĨŽƌƌĞƉůĂĐĞŵĞŶƚǀĂůǀĞƐ͘DĞĐŚĂŶŝĐ ƌĞƉůĂĐĞƐďƌŽŬĞŶďĞůƚŽŶŵƵĚƉůĂŶƚĂŶĚƌĞƉĂŝƌĞĚƉŽǁĞƌƚŽĚƌŝůůĞƌƐZŝŐtĂƚĐŚƉĂŶĞů͘tĂŝƚŝŶŐŽŶƌĞƉůĂĐĞŵĞŶƚǀĂůǀĞƐƚŽĂƌƌŝǀĞ͘KϮ ŵĂŶƵĂůŬŝůůǀĂůǀĞƐ͕ŝŶƐŝĚĞŵĂŶƵĂůĐŚŽŬĞǀĂůǀĞĂŶĚ,ZǀĂůǀĞĨƌŽŵŵƵĚĐƌŽƐƐƉƌĞƉƉŝŶŐĨŽƌǀĂůǀĞƐƚŽĂƌƌŝǀĞŽŶƐŝƚĞ͘ZĞƉůĂĐĞŵĞŶƚ ǀĂůǀĞƐĨŽƌKWƐƚĂĐŬŽŶƐŝƚĞ͘DhϮŵĂŶƵĂůŬŝůůǀĂůǀĞƐ͕/ŶƐŝĚĞDĂŶƵĂůŚŽŬĞsĂůǀĞĂŶĚ,ZǀĂůǀĞƚŽŵƵĚĐƌŽƐƐ͘ZĞƐƵŵĞĂŶĚ ĐŽŵƉůĞƚĞKWƚĞƐƚŝŶŵŽƌŶŝŶŐ͘ůŽǁĚŽǁŶƉƵŵƉ͕ĂůůƐƵƌĨĂĐĞůŝŶĞƐ͕ƐƚĂŶĚƉŝƉĞŵĂŶŝĨŽůĚ͕ĐŚŽŬĞŵĂŶŝĨŽůĚ͕KWƐƚĂĐŬΘƚĞƐƚũŽŝŶƚ͘ ^&E͘ ĨŽƌϱΗϭϱηĐĂƐŝŶŐ͘ŽƌƌĞůĂƚĞĂŶĚƐĞƚ/WĂƚϱ͕ϰϮϱΖ͘WůƵŐƐĞƚǁŝƚŶĞƐƐĞĚďǇůůŝĞ^ĐŚŽĞƐƐůĞƌͲ>D͘t ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϵͬϯϬͬϭϵ ϭϭͬϮϯͬϮϭ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ ^hϮϰϯͲϬϰ ϱϬͲϭϯϯͲϮϬϰϴϵͲϬϬͲϬϬ ϭϵϵͲϬϱϱ ϭϬͬϮϬͬϮϬϭϵͲ^ƵŶĚĂǇ W:^DĂŶĚƉĞƌŵŝƚƚŽǁŽƌŬ͘&ŝƌĞƵƉƌŝŐ͕ŚĞĂƚĞƌƐ͕ůŝŐŚƚƉůĂŶƚƐĂŶĚǀĞƌŝĨǇϬƉƐŝŽŶƚŚĞǁĞůů͘Z/,ǁŝƚŚϮͲϯͬϴΗϰ͘ϲη>ͲϴϬƐƚĂŶĚƐŽƵƚŽĨƚŚĞ ĚĞƌƌŝĐŬĂŶĚůĂǇĚŽǁŶϯϰũŽŝŶƚƐ͘ZŝŐƐĞƌǀŝĐĞ͕ƌŝŐĚŽǁŶƉŝƚƐ͕ƉƌĞƉĨŽƌƌŝŐŵŽǀĞ͘Zͬh,ĂůůŝďƵƌƚŽŶͲůŝŶĞǁŝƚŚ>ĂŶĚϭ͘ϳϱΗKƐĂŵƉůĞ ĐĂƚĐŚĞƌ͘Z/,,ĂůůŝďƵƌƚŽŶͲůŝŶĞǁŝƚŚ>ĂŶĚϭ͘ϳϱΗKƐĂŵƉůĞĐĂƚĐŚĞƌ͘dĂŐĐĞŵĞŶƚƉůƵŐĂƚϭϲϴϳĨƚͲ'ŽŽĚĐĞŵĞŶƚ͕WKK,͘dĂŐ ǁŝƚŶĞƐƐĞĚďǇYƵŝŶŶ^ĂǁǇĞƌͲ>D͘Z/,,ĂůůŝďƵƌƚŽŶͲůŝŶĞǁŝƚŚ>ĂŶĚϱ͘ϲϭϬΗK>ĞŐĂĐǇŽŝůƚŽŽůƐďŝŐďŽǇƉůƵŐĨŽƌϳΗϮϵηĐĂƐŝŶŐ͘ ŽƌƌĞůĂƚĞĚĚĞƉƚŚĂŶĚƐĞƚƉůƵŐĂƚϭϲϬĨƚ͕WKK,ĂŶĚZ͘WůƵŐƐĞƚǁŝƚŶĞƐƐĞĚďǇYƵŝŶŶ^ĂǁǇĞƌͲ>D͘Z/,ǁŝƚŚt'ĂŶĚϮͲϯͬϴΗϰ͘ϲη>Ͳ ϴϬĂŶĚƚĂŐŐĞĚƉůƵŐĂƚϭϲϬĨƚ͘WŝĐŬƵƉϱĨƚĨŽƌĐĞŵĞŶƚŝŶŐ͘Zͬh,ĂůůŝďƵƌƚŽŶĐĞŵĞŶƚƵŶŝƚW:^D͕ƉƵŵƉϰ>ĨƌĞƐŚǁĂƚĞƌĂŶĚƉƌĞƐƐƵƌĞ ƚĞƐƚŝƌŽŶƚŽϳϱϬƉƐŝ͘WƵŵƉĞĚϲ͘ϯ>ŽĨϭϱ͘ϴηůĂƐƐ'ĐĞŵĞŶƚǁŝƚŚŐŽŽĚƌĞƚƵƌŶƐƚŽƐƵƌĨĂĐĞ͘WƵŵƉϬ͘ϱ>ĐŚĂƐĞƌŽĨĨƌĞƐŚǁĂƚĞƌƚŽ ĐůĞĂŶƉƵŵƉƐ͘ĞŵĞŶƚũŽďǁŝƚŶĞƐƐĞĚďǇYƵŝŶŶ^ĂǁǇĞƌͲ>D͘WKK,Ĩ ƌŽŵϭϱϱĨƚǁŝƚŚϮͲϯͬϴΗϰ͘ϲη>ͲϴϬĂƚϭĨƚͬƐĞĐ͕ůĂǇŝŶŐĚŽǁŶ ƐŝŶŐůĞƐ͘ZͬĂŶĚǁĂƐŚƵƉ,ĂůůŝďƵƌƚŽŶĐĞŵĞŶƚ͘WƌĞƉĨŽƌƌŝŐŵŽǀĞ͗sĂĐŽƵƚƉŝƚƐ͕ZͬŵƵĚƉƵŵƉΘƉŝƚƐ͕ƌĞŵŽǀĞŚĂŶĚƌĂŝůƐΘƌĂŝƐĞƌŝŐ ĨůŽŽƌ͕ƐĐŽƉĞĚŽǁŶĚĞƌƌŝĐŬ͕ĐůĞĂŶůŽĐĂƚŝŽŶ͕ůŽĂĚĂŶĚŽƌŐĂŶŝǌĞƚƌĂŝůĞƌƐ͘^ĞĐƵƌĞǁĞůů^&E͘ ϭϬͬϮϭͬϮϬϭϵͲDŽŶĚĂǇ W:^DĂŶĚƉĞƌŵŝƚƚŽǁŽƌŬ͕&ŝƌĞƵƉƌŝŐ͕ǀĞƌŝĨǇϬƉƐŝŽŶƚŚĞǁĞůů͖>ĂǇĚĞƌƌŝĐŬŽǀĞƌ͕ƵŶͲŚŽŽŬĂůůŚŽƐĞƐĂŶĚƉŽǁĞƌĐŽƌĚƐ͘ZͬKWƐƚĂĐŬ ĂŶĚŝŶƐƚĂůůŽƌŝŐŝŶĂůƚƌĞĞďĂĐŬŽŶƚŚĞǁĞůů͕ŝŶƐƚĂůůŐƌĂƚŝŶŐďĂĐŬŽǀĞƌĐĞůůĂƌ͘ĞŵĞŶƚǀŝƐƵĂůΕϱ&ƚĚŽǁŶĨƌŽŵǁĞůůŚĞĂĚ͘ZͬƌŝŐ ĐŽŶƚĂŝŶŵĞŶƚĂŶĚůŽĂĚĂůůĞƋƵŝƉŵĞŶƚŽŶtĞĂǀĞƌƌŽƐƚƌƵĐŬƐ͘WƵůůĞĚϮͲϯͬϴΗƵƚƚƌĞƐƐƚƵďŝŶŐEKZDĐŚĞĐŬĞĚĂŶĚƐĞŶƚƚŽdƵďŽƐĐŽƉĞ͘ ϭϬͬϭϴͬϮϬϭϵͲ&ƌŝĚĂǇ W:^DĂŶĚƉĞƌŵŝƚƚŽǁŽƌŬ͘&ŝƌĞƵƉƌŝŐ͕ůŝŐŚƚƉůĂŶƚƐĂŶĚŚĞĂƚĞƌƐ͘Zͬh,ĂůůŝďƵƚŽŶͲůŝŶĞĂŶĚϰϬĨƚĐĞŵĞŶƚĚƵŵƉďĂŝůĞƌ͘Z/,ĂŶĚdĂŐ /WĂƚϱ͕ϰϮϱĨƚWͬhƚŽϱ͕ϰϭϱĨƚĂŶĚĚƵŵƉĐĞŵĞŶƚ͘ϱĂĚĚŝƚŝŽŶĂůĚƵŵƉďĂŝůƌƵŶƐŵĂĚĞĂƚϱ͕ϰϬϱΖ͕ϱ͕ϯϵϱΖ͕ϱ͕ϯϴϱΖ͕ϱ͕ϯϳϱΖ͕ϱ͕ϯϲϱΖtK͘ 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I. Supervisor FROM:Matt Herrera SUBJECT: Surface Abandon Petroleum Inspector SCU 243B-04 Swanson River Field Hilcorp Alaska LLC PTD 1990550; Sundry 319-137 11/22/2021: I traveled to the Swanson River Field and met Hilcorp Engineer Nelson Alger and Production Operator Kraig McGhie. Went over approved Sundry paperwork for the surface abandonment well work on wells Soldotna Creek Unit (SCU) 243B-04. The Hilcorp representatives indicated work was at the point where all that was left was to excavate the well head and cut casing strings below grade. At the wellsite, I observed they were just beginning to excavate around the wellhead. Elevations had been determined for grade and required cutoff depth. Ambient temperatures were -20F, so they had to thaw ground area around well prior to excavating. I departed and returned home. 11/23/2021:I returned to SCU 243B-04 and met with Hilcorp Operator Kraig McGhie and went over progress on the excavation on SCU 243B-04. The wellhead had been cut below grade and they were awaiting witness by a BLM representative before mixing cement to top of the void in the inner tubing string. The cement on the outer strings was flush to surface cutoff and solid to the top of the casing stub and solid. Cutoff depth was well below required grade. The marker plate was sized to fit the outer edge of outermost casing and well information was verified. I departed location before BLM arrived. Photos of the completed surface abandonment work were provided by Hilcorp. Attachments: Photos (8) 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2022.02.14 14:32:03 -09'00' 2021-1123_Surface_Abandon_SCU_243B-04 Page 2 of 5 Surface Abandonment – SCU 243B-04 (PTD 1990550) Photos by AOGCC Inspector M. Herrera except as noted 11/23/2021 Wellhead Casing stub showing cutoff depth relative to grade 2021-1123_Surface_Abandon_SCU_243B-04 Page 3 of 5 Casing stub and tubing cement void 2021-1123_Surface_Abandon_SCU_243B-04 Page 4 of 5 Marker plate showing correct info and pre-weld fit 2021-1123_Surface_Abandon_SCU_243B-04 Page 5 of 5 Cement to surface after top- off; tubing and casing annuli; photo courtesy of Hilcorp Marker plate installed; photo courtesy of Hilcorp THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Tyonek Gas Pool, SCU 24313-04 Permit to Drill Number: 199-055 Sundry Number: 319-137 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, ssif8 e 1. C ielowski Commissioner DATED this 10 day of April, 2019. IBDMS-! � APP. 10 7019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED MAR 21 2019 0A06,60 yl i 1. Type of Request: Abandon ❑✓ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q • Stratigraphic ❑ Service ❑ 199-055 ` 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20489-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 716 8 CO 716.001 Will planned perforations require a spacing exception? Yes ❑ No 0 Soldotna Creek Unit (SCU) 2438-04 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA028997 ' Swanson River/ Tyonek Gas ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): Fish @ 6,070' 6,069' 5,610' 5,610' —2,083 psi 5,610' 3,81T Casing Length Size MD TVD Burst Collapse Structural Conductor 96' 13-3/8" 96' 96 3,450psi 1,950psi Surface 2,150' 7" 2,150' 2,150' 8,160psi 7,020psi Intermediate Production Liner 4,135' 5" 1 6,060' 6,059' 8,290psi 7,250psi Perforation Depth MID (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 2-3/8" 4.6R / L-80 5,401' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): FH Retrievable Pkr; N/A 5,237'MD 15,327'TVD; N/A 12. Attachments: Proposal Summary Q Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Exploratory ❑ Stratigraphic ❑ Development Service ❑ 14. Estimated Date for 15. Well Status after proposed work: May 1, 2019 Operations: OIL E]WINJ 11WDSPL E] Suspended 11Commencing GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned Q 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: Be York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramerfdlhdQQM-com / Contact Phone: 777-8420 � Authorized Signature: `� � - Date: `r � '-�('� COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ Location Clearance Test Mechanical Integrity El ssB��OP TTest Other: � 0 -,4- pkjv Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes No ` Subsequent Form Required: y T KV/APR ❑ O `(J 313DMS 19 2019 ' APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: ' p f 16 A Submit Form an Form 10-4 Revised 4/201 y Approved applica r li 1 ! !�Llo the date of approval. _ . -Attachments in Duplicate ,.00, n Hilmrp Alaska, LU Well Prognosis Well: SCU 2438-04 Date: 03/19/2019 Well Name: SCU 243B-04 API Number: 50-133-20489-00 Current Status: Shut -In Gas Well Leg: N/A Estimated Start Date: May 1, 2019 Rig: Rig 401 Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 199-055 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: - 2,642 psi @ 5,585' TVD (Based upon a 0.473 psi/ft gradient to the deepest open perforation) Maximum Expected BHP: - 2,642 psi @ 5,585' TVD (Based upon a normal gradient) Max. Potential Surface Pressure: - 2,083 psi (Based upon expected max. BHP and a 0.10 psi/ft gas gradient to surface) Brief Well Summary: Na 1,1911 /K&/711 1 /-Y"'A� SCU 2438-04 was drilled as a grass roots Tyonek gas well in July 1999. The 7" surface casing was cemented to surface. A 5" production liner was set in the subsequent 6" hole, to a depth of 6,060'. The liner was cemented with 150 Sx. of 15.8 ppg cement. The well was first perforated (8/10/99) in three Tyonek 59-2 intervals, but was unproductive. These 59-2 perforations were isolated with a posi-set bridge plug (set at 5,630'), with 20' of cement placed on top. The Tyonek 56-9 sand was perforated in September 1999, and was also unproductive. Note that the well had 3,000 ft of water on the interval when it was perforated. A December 2018 workover, attempted to add perforations to both the Tyonek 56-9 and 57-8 sands. Unfortunately after perforating the first interval in the 57- 8 sand, the 1-11/16" strip guns got stuck in the tubing while POOH. Fishing operations were unsuccessful and C~ the strip guns remain inside the tubing at -3,817' MD. Based upon no gas production from the most prospective intervals in the wellbore (the Tyonek 59-2 and 56-9 sands), Hilcorp has chosen not to complete the workover (to add perforations to the Tyonek 56-9 and 57-8 sands) started in December 2018. Furthermore, since the wellbore electric logs do not indicate any additional pay up - hole, the decision has been made to P&A the wellbore. / S 400 The purpose of this Sundry is to permanently P&A the SCU 243B-04 wellbore. Pre - Rig Work: 1. Provide 24 hour notice to the AOGCC that Plug and Abandonment of the wellbore will commence per AOGCC regulations 20 AAC 25.112 (h). Notify BLM of P&A as per 43 CFR 3160 G. 2. RU Pump Truck. RU on tubing and casing and conduct an IA pressure test to 2,500 psi on chart for 30 min. Bleed down pressure. C—) r- 3. 3. Bullhead 9.8 ppg brine down the tubing. ?f i fi wi I T- fA 6.,; , Workover Rig #401: 4. MIRU Rig401. Well Prognosis Well: SCU 24313-04 Hileara Alaska, Lb Date: 03/19/2019 5. Notify AOGCC and BLM 24 hours in advance of BOP test to extend the opportunity to witness. 6. Set back pressure valve. 7. ND wellhead, NU 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. 8. PU 2-3/8" tubing to release the FH 2-3/8" x 5" retrievable packer. 9. Once released, circulate the hole with 9.8 ppg kill weight fluid. kW 10. POOH w/ 2-3/8" tubing, laying down GLM and chemical injection mandrel, and racking back pipe. a. Note: "Fish" ("'15' of 1-11/16" strip guns) inside tubing @ ^3,817'. 11. If "Fish" is recovered while pulling tubing, go to Step 15. N� `I VE / 12. If "Fish" is not recovered while pulling tubing, go to Step 133 v` c k &Ar- L- 13. MIRU Slickline. RIH and tag "Fish". POOH. a. If "Fish" is below 5,425', RD Slickline and go to Step 15. b. If "Fish" is above 5,425', go to Step 14. 14. Proceed with Slickline fishing operations to recover Fish or to push Fish below 5,425'. Once Fish recovered (or pushed below 5,425'), RD Slickline and go to Step 15. 15. MIRU E -line. Pressure test lubricator to 3,000 psi 16. PU & RIH w/ 5" CIBP to 5,425' and set same. POOH. C� r 17. PU & RIH w/ Dump Bailer and dump bail 35' ofcement on top of CIBP f a. TOC @ - 51390' w 66 I,"4 18. POOH and RD E-line./� � PP,Ssu re- �� { •{-a Z-cXii �s 11,3 0 k .. CfcL_t Not • rilling records indicate that the 7" casing string was cemented to surface (no record of a bond log being run). In compliance with AOGCC regulations 20 AAC 25.112, a bridge plug with -450' of cement will be used to isolate the inside of the 7" casing / 5" liner top (100'+ below 7" casing shoe & 100'+ above liner top). An additional plug will be set at 160', with cement on top to surface. 19. PU & RIH w/ 5" CIBP on 2-3/8" tubing. q � 20. Set CIBP @ -2,260'. " - 21. PU tubing 5' and displace 450' of 15.8 ppg class G cement on top of the CIBP. a. Base of Cement on top of CIBP @ 2,260' (^'110' below 7" casing shoe). b. TOC @ -1,810' ("'115' above 5" liner top). 22. POOH w/ 2-3/8" tubing. WOC. 23. RU E -line. Pressure test lubricator to 3,000 psi. RIH and tag cement. Make sure TOC is above 1,825' (should be at ^'1,810'), to ensure at least 100' of cement extends above the 5" liner top. POOH & RD E -line. 24. PU & RIH w/ 7" CIBP on 2-3/8" tubing. 25. Set CIBP @ 160'. 26. PU tubing 5' and displace 160' of 15.8 ppg class G cement on top of the CIBP. a. TOC @ surface. 27. RD Cementers, WOC. 28. Place dry hole tree on well. 29. RDMO Workover Rig. Well Prognosis Well: SCU 24313-04 Hilmrp Alaska, LU Date: 03/ 19/2019 Post - Rig Abandonment Procedures: 30. Excavate cellar, cut off casing 3' below natural GL. 31. NotifyAOGCC_and BLM 48hrs in advance. 32. Create well abandonment marker per 20 AAC 25.120 and BLM Onshore Order No. 2 III.G.10. The following must be bead -welded directly to the marker plate: a. Hilcorp Alaska, LLC b. PTD: 199-055 c. Well Name: SCU 2436-04 d. API: 50-133-20489-00 33. Set maker plate pe 120 and BLM Onshore Order No. 2 III.G.10, collect GPS coordinates. 34. Photo document casing cut-off and Welded Plate install. ✓ 35. Backfill excavation, close out location. Com, Sck Attachments: Actual Schematic Proposed Schematic BOPE Schematic RWO Sundry Revision Change Form n Hil.m Alaska, LLC RKB to TBG Head = 16.5' TO = 6,070' MD / 6,069' TVD PBTD = 5,610' Vertical Well SCHEMATIC CASING DETAIL SWANSON RIVER FIELD SCU #2436-4 As Completed 12/30/18 Size Wt Grade Conn Top Bottom 13-3/8" 68# K-55 Weld Driven 96' 7" 29# L-80 Butt Surf 2,150- 5" 15# L-80 I TKC Butt 1,925' 6,060' TUBING DETAIL 2-" 4.6#-' L-80 Butt SC Surf 5,401' T/ 3/8" SS Mthanol Injection Line Surf 1,899' ¢ f&.. ?iK IEWELRY DETAII No. Depth Item 1 SPF 2-3/8" Tbg hgr w/Cameron "H" BPV profile 2 1,820' 2-3/8"Macco5MO-1GLMw/dummy valve 3 1,899' Macco 2-3/8" SMO -1 Chem Inj Mdrl w/600 psi chem inj valve 4 1,925' ZXP liner top packer 5 ±3,817' Fish --15' of 1-11/16" strip guns 6 5,283' Baker CMU Sliding Sleeve, F profile, 1.877" ID 7 5,327 FH 2-3/8" x 5" Retrievable Packer 8 5,367' 2-3/8" X nipple 9 5,401' Wireline Entry Guide 30 5,630' Posiset Bridge plug with 20' cement on top to 5610', 9/19/99 PERFORATION DETAIL )(MD) Btm(MD) Top(TVD) I Btm(TVD) SPF Ft Date Status 450' 5,464' 5,450' 5,464' 4 14 9/22/1999 Open 566' 5,585' 5,566' 5,585' 6 19 12/24/18 Open 650' 5,688' 5,650' 5,688' 4 38 8/10/1999 Abandon 9/19/99 691' 5,697' 5,691' 5,697' 4 6 8/11/1999 Abandon 9/19/99 700' 5,712' _ 5,700' 5,712' 4 12 8/12/1999 Abandon 9/19/99 DRAWN BY: TAB Updated by DMA 03-18-19 SWANSON RIVER FIELD 1litrnrp Alae4e.LLC PROPOSED SCHEMATIC SCLI#2438-4 As Completed 12/30/18 RKB to TBG Head = 16.5' TD = 6,070' MD / 6,069' TVD PBTD = 0' Vertical Well CASING DETAIL Size Wt Grade Conn Top Bottom 13-3/8" 68# K-55 Weld Driven 96' 7" 29# L-80 Butt Surf 2,150' 5" 15# L-80 I TKC Butt 1,925' 6,060' TUBING DETAIL 2-3/8" 1 4.6# 1 L-80 I Butt SC Surf 5,401' w/ 3/8" 5S Methanol Injection Line Surf d 1,899' JEWELRY DETAIL No. Depth Item 1 0' Top of Cement @ surface 2 160' CIBP 3 1,810' Top of Cement (115' above Liner Top) 4 1,925' ZXP liner top packer 5 2,150' 7" Casing Shoe 6 2,260' CIBP (110' below 7" casing shoe) 7 5,425' CIBP w/ 35' of cement on top -TOC @ ^5,390' 8 5,630' Posiset Bridge plug with 20' cement on top to 5610', 9/19/99 PERFORATION DETAIL )(MD) Btm(MD) Top(TVD) Btm(TVD) SPF I Ft Date Status ,450' 5,464' 5,450' 5,464' 4 14 9/22/1999 Abandoned .566' 5,585' 5,566' 5,585' 6 19 12/24/18 Abandoned .650' 5,688' 5,650' 5,688' 4 38 8/10/1999 Abandoned 9/19/99 691' 5,697' 5,691' 5,697' 4 6 8/11/1999 Abandoned 9/19/99 700' 5,712' 5,700' 5,712' 4 12 8/12/1999 Abandoned 9/19/99 DRAWN BY: TAB Updated by DMA 03-18-19 HILCORP ALASKA 7-1/16" 5M BOPE 7-1/16" SM 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 26-3/4" TALL, FLANGE TO FLANGE 7-1/16" SM DRILLING SPOOL W/2-1/16" 5M 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 SCU 243B-04 (PTD 199-055) 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 call' 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 -HA K Approved By initials AOGCC Written Approval Received (Person and Date) Approval: Prepared: Asset Team Operations Manager Date First call Operations Engineer Date STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS MAR 1 1 201 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdownLi Performed: Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ arforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: 2. Operator Hilcorp Alaska, LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development Q Exploratory ❑ Stratigraphic ❑ Service ❑ 199-055 3. Address: 3800 Cenlerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-133-20489-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: FEDA028997 Soldotna Creek Unit (SCU) 24313-04 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Swanson River/ Tyonek Gas 11. Present Well Condition Summary: Total Depth measured 6,070 feet Plugs measured 5,610 feet true vertical 6,069 feet Junk measured 3,817 (fish) feet Effective Depth measured 5,610 feet Packer measured 5,237 feet true vertical 5,610 feet true vertical 5,327 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 96' 13-3/8" 96' 96' 3,450psi 1,950psi Surface 2,150' 7" 2,150' 2,150' 8,160psi 7,020psi Intermediate Production Liner 4,135' 5.. 6,060' 6,0(55999, 8,290psi 7,250psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 1 Tubing (size, grade, measured and true vertical depth) 2-3/8" 4.16#/// L-80 5,401' MD 5,401' TVD N/A; N/A N/A Packers and SSSV (type, measured and true vertical depth) FH Retrievable Pkr 5,237' MD 5,327' TVD 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A •�j !_ - t T Treatment descriptions including volumes used and final pressure: N/A � (I 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 1 0 0 0 0 0 Subsequent to operation: 1 0 0 0 0 0 14. Attachments (required per 20 AAC 25.070, 25.071, a 25.283) 15. Well Class after work: Daily Report of Well Operations ❑' Exploratory❑ Development Q Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil LJ Gas j WDSPL Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 317-607 Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramerCdhilcoro.c0m Authorized Signature: Dale:'!J Contact Phone: 777-8420 Form 10-404 Revised 4/2017 �( %/ j ROM S -t* MAR 2 2 2019 Submit Original Only Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SCU 24313-04 50-133-20489-00 1 199-055 11/26/18 1 2/25/19 Daily Operations: 11/26/2018 - Monday SPOT EQUIPMENT, RIG UP .125 S/L. PRESSURE TEST TO 150OPSI TEST GOOD. RIH W/ 2" JDC TO 5363'KB W/T PULL PRONG WELL DID NOT GO ON VACCUME POOH - W/ PRONG. DISCUSS PLAN W/ BILLY A., RIH W/ 1.90" LIB TAG FLUID AT SURFACE POOH -TALK W/ BILLY DECIDE TO SWAB WELL TO1400'. RIH W/ 2 3/8 SWAB MANDREL AND CUPS (SEE SWAB REPORT). FLUID COMING IN THROUGH PLUG DECIDE TO PULL PLUG, RIH W/ 2 3/8 GS TO 5369'KB W/T POOH HANG UP ON F NIPPLE JAR UP TWICE COMES FREE. OOH W/ PLUG. RIH W/ 1.75" DD BAILER TO 5595'KB POOH - OOH THICK GREY MUD. LAY DOWN LUB FOR THE NIGHT. 11/27/2018 -Tuesday ARRIVE AT OFFCE JSA, PERMIT. REHEAD, PICK UP LUB, PRESSURE TEST TO 150OPSI (TEST GOOD), RIH W/ 2 3/8 SWAB MANDREL W/ CUPS - SEE SWAB REPORT Tag top of fluid at 80'. Left FL at 250' yesterday. Today we left FL at 1350'. So far we have swabbed 50 bbls total out of well. RIH W/ 1.75" DD BAILER TO 5593'KB POOH. We lost 2' compared to yesterdays tag. Rig lubricator down, secure well and clean up work area. Will tag top of fluid in the morning and town will make a decision on plan forward. 11/28/2018- Wednesday Arrive at office JSA, permit. Slip and cut 30' wire, retie rope socket, pressure test to 1,500psi (test good). RIH w/ 2-3/8" 9 swab mandrel and cups to tag fluid at 1,370'KB see swab report. Have mandrel w/ threaded btm sent out go to 2 mandrels split w/ 5' stem. RIH w/ 1.75" DD bailer tag fluid at 4,800'KB tag fill at 5,593'KB. POOH. Lay down LUB, secure well site, rehead. Clean up work area. 11/29/2018 - Thursday Arrive at office JSA permit. Pick up LUB, pressure test to 1,000psi, test good. RIH w/ tubing tail locator w/ 1.75" DD bailer tag fluid at 4,780'KB, tubing tail at 5,401'KB. And fill at 5,593'KB. POOH. RIH w/ 2 swab mandrels split w/ 5' stem (see swab report). Bottom set of cups getting torn up, top set fine. RIH w/ 1.75" DD bailer tag fluid at 5,340'KB and fill at 5,593'KB, wait 1 hour and tag again; tag fluid again at 5,330'KB after 30 min. Tag fluid at 5,330'KB after another 30 min. Swabbed total of 86.22 bbls out of well total. 12/23/2018 -Sunday Sign in. Mobe to location. PTW, JSA and SIMOPS with SLB N2 crew. Rig up hard lines and lubricator. PT to 250 psi low and 4,000 psi high, TP - 0 psi. RIH w/ 1-11/16" x 18.5' strip gun and tie into log sent from town. Run correlation log and send to town. Get ok to perf from 5,566.5' to 5,585' (18.5', half zone). Pressured tubing up to 1,450 psi spotted and attempted to fire gun. No pressure change. POOH and gun did not fire. Changed out det and sub. RIH w/ 1-11/16" x 18.5' strip gun and tie into log sent from town. Run correlation log. Spotted shot from 5,566.5'to 5,585' with 1,400 psi on well. Fired gun. After 5 min - 1,425 psi, 10 min - 1,500 psi and 15 min - 1,525 psi. Had as little trouble getting in tubing tail and at 3,220' tools became stuck and wouldn't go up or down. worked out way up to 2,200 lbs and pulled out of rope socket. POOH. Rig down lubricator. SL will be here in the morning to f' o s o t of h le. TP - 1,600 psi. ,yam 5-74 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SCU 24313-04 50-133-20489-00 199-055 11/26/18 1 2/25/19 Daily Operations: 12/24/2018 - Monday ARRIVE @SR JSA/TGSM TP - 1,640 psi. ARRIVE @ P & S START UNIT. BRAKES FROZEN UP GET HEATER. ON PAD CRANE ALREADY ON PAD WON'T START DO TO COLD USE LIGHT PLANT TO POWER. BLOCK HEATER AND BATERY CHARGER. RIG UP. P/T GOOD. RIH W/1-3/8" JDC TO 3,210KB W/T NO LATCH POOH CHECK TOOL. RIH W/2" JDC TO 3210KB W/T LATCH W/T HIT 2001 LICKS COME UP HOLE TO 3189KB W/T 3148KB - TP seemed to drop to 1500 psi when we made footage with fish. 3112KB W/T HIT 32 OJ LICKES COMES FREE POOH W/FISH. OOH W/E-LINE TOOL STRING OF 27" LEFT ON TOOL STRING ABOUT 15' LEFT IN HOLE. LAY DOWN RE HEAD DO TO ICE. RIH W/1.75 LIB TO 3136KB TAG FISH HARD DID NOT MOVE SJ FREE POOH SEE CLEAR IMPRESSION OF STRIP GUN ON WALL. Call town and discussed. Decision to shut down over Christmas and get tools ready to fish perf strip that is in the well (15'). Will send pic of LIB and bottom of strip gun. Rig down lubricator and secure well. 12/26/2018- Wednesday ARRIVE @ SR JSA/TGSM TP -1,500 psi. RIG UP CHECK TS P/T 3,000PSI (GOOD). RIH W/ 19' DRIVE DOWN BAILER W/OPEN SERRATED bottom TO 3,137'KB W/T 3,140'KB W/T 3,151'KB. W/T 3,166'KB 3,359'KB 3,812'KB W/T 3,814'KB W/T STOP MAKING HOLE, POOH W/ 9" OF STRIP GUN. RIH W/ 1.75" LIB TO 3,814113 TAG, POOH, MARKS NOT DEFINITIVE. RIH W/ 1.75" LIB TO 3,814'KB TAG POOH. RIH W/ 2 PRONG WIRE GRAB ON 4'1-1/4" STEM BAITED W/ 2" JDC TO 3,814'KB W/T NO bite. POOH, NO FISH. RIH W/ALLIGATOR GRAB baited ON 2" JDC TO 3,817'KB W/T LATCH HIT 1,500LB OJ LICK DEAD PULL UP TO 1,500LB SLIPS OFF. POOH, NO FISH. RIH W/ ALLIGATOR GRAB baited ON 2" JDC TO 3,817'KB W/T LATCH SLIPS OFF @ SOOLB. POOH NO FISH. OOH RIG DOWN HEAD TO SRU 41-15 TP - 1,400 psi. 12/29/2018-Saturday RIG OVER FROM SRU 14-15. WHILE RIGING UP BLOW HYDRO FILTER CALL FOR NEW FILTER. NEW FILTER ARRIVES. P/T 3,500PSI GOOD TP - 1,390. RIG W/ 2 PRONG GRAB ON 5'1-1/4" STEM BATED W/ 2" SB TO 3,817'KB W/T POOG TOOL SHED. RIH W/ 2" JD TO 3,811'KB. LATCH, GRAB PULL 200LB OVER GRAB SLIPS OFF, POOH W/GRAB NO FISH. RIH W/ ALLIGATOR GRAB BATED W/SB TO 5,817'KB W/T NO BITE. POOH, TOOL SHEARED RE-PIN. RIH W/ SAME TO (SEE FL @ 3,100'KB) 5,817'KB LATCH FISH HIT 1 500LB OJ LICK SLIPS OFF. POOH. NO FISH. RIH W/ 11' 1-3/4" DD BAILER W/ 1.9 BOTTOM TO 5,817'KB W/T NO GAIN. POOH. MAKES ON BOTTOM. ADD 5' STEM. 1600LB OJ LICK COMES FREE. POOH. 1" TIP BROKE OF GRAB. OOH. RIG DOWN. TP - 1,000 PSI. HEAD TO SHOP. 19 - Friday Evaluating for Coil Tubing 02/25/2019 - Monday Evaluated and decided to P&A well. SWANSON RIVER FIELD Hilmro Alaska, LLC SCHEMATIC SCU #24313-4 As Completed 12/30/18 RKB to TBG Head = 16.5' TD = 6,070' MD / 6,069' TVD PBTD = 5,610' Vertical Well CASING DETAIL Size Wt Grade Conn Top Bottom 13-3/8" 68# K-55 Weld Driven 96' 7" 29# L-80 Butt Surf 2,150' 5" 15# L-80 TKC Butt 1,925' 6,060' TUBING DETAIL 2-3/8"4.6# L-80 Butt SC Surf 5,401' SS Methanol Injection Line Surf 1,899' JEWELRY DETAIL No. Depth Item 1 SPF 2-3/8" Tbg hgr w/Cameron "H" BPV profile 2 1,820' 2-3/8"Macco SMO -1 GLM w/dummy valve 3 1,899' Macco 2-3/8" SMO -1 Chem Inj Mdrl w/600 psi chem inj valve 4 1,925' ZXP liner top packer 5 ±3,817' Fish --15'of 1-11/16"strip guns 6 5,283' Baker CMU Sliding Sleeve, F profile, 1.877" ID 7 5,327' FH 2-3/8" x 5" Retrievable Packer 8 5,367 2-3/8" X nipple 9 5,401' Wireline Entry Guide 10 5,630' 1 Posiset Bridge plug with 20' cement on top to 5610', 9/19/99 PERFORATION DETAIL )(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Ft Date Status 450' 5,464' 5,450' 1 5,464' 4 14 9/22/1999 Open 566' 5,585' 5,566' 5,585' 6 19 12/24/18 Open 650' 5,688' 5,650' 5,688' 4 38 8/10/1999 Abandon 9/19/99 691' 5,697' 5,691' 5,697' 4 6 8/11/1999 Abandon 9/19/99 700' 5,712' 5,700' 5,712' 4 12 8/12/1999 Abandon 9/19/99 DRAWN BY: TAB Updated by DMA 03-18-19 • SOF To • THE STATE Alaska Oil and Gas ofA LA S KA Conservation Commission _c 333 West Seventh Avenue - GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 r.�'. OF „••�� Main: 907.279.1433 ALAS Fax 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager SCANNED J41N 1 2,..A Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Swanson River Field, Tyonek Gas Pool, SCU 243B-04 Permit to Drill Number: 199-055 Sundry Number: 317-607 Dear Mr. Helgeson: Enclosed is the approved application for 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, Hollis S. French Chair l J DATED this t day of January, 2018. • • • RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION �� 2 $ 2017 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon El Plug Perforations❑ Fracture Stimulate El Repair Well ❑ A ns shutdown❑ Suspend 0 Perforate Q . Other Stimulate 0 Pull Tubing ❑ Change Approved Program 0 Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: CTCO/N2 ❑✓ • 2.Operator Name: 4.Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q. 199-055 • 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic 0 Service ❑ 6.API Number: Anchorage Alaska 99503 50-133-20489-00-00 ' 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 716&CO 716.001 ' • Will planned perforations require a spacing exception? Yes ❑ No 2Soldotna Creek Unit(SCU)243B-04 9.Property Designation(Lease Number): 10.Field/Pool(s): FEDA028997 ' Swanson River/Tyonek Gas • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 6,070' • 6,069' ' 5,610' 5,610' —2,135psi 5,610' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 96' 13-3/8" 96' 96' 3,450psi 1,950psi Surface 2,150' 7" 2,150' 2,150' 8,160psi 7,020psi Intermediate Production Liner 4,135' 5" 6,060' 6,059' 8,290psi 7,250psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 2-3/8" 4.6#/L-80 5,401' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): FH Retrievable Pkr;N/A 5,237'MD/5,327'TVD;N/A 12.Attachments: Proposal Summary Q Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch Q Exploratory 0 Stratigraphic ❑ Development Q• Service ❑ 14.Estimated Date for 15.Well Status after proposed work: January 20,2018 Commencing Operations: OIL ❑ WINJ ❑ WDSPL 0 Suspended ❑ 16.Verbal Approval: Date: GAS Q WAG 0 GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramerfcDhilcorn.com / Contact Phone: 777-8420 Authorized Signature: `Fy^ Date: ///z,62/1 7 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3n • (PO 7 Plug Integrity ❑ BOP Test 0 Mechanical Integrity Test ❑ Location Clearance ❑ Other: X: Pi (T--- rA- tj I S O r:% rj LI / 16 ?' -„,. Post Initial Injection MIT Req'd? Yes ❑ No ❑ c1:721-.7,3 V,— , Spacing Exception Required? Yes 0 No © Subsequent Form Required: /0•– 0 il APPROVED BY 118 Approved by: (4720—(2__(.._ COMMISSIONER THE COMMISSION Date: f 1L 61\i( JT IL I 4(L Submit Form and m 10-403 Revised 4/2017 pproved application is valid fottY��iii��T nnnllloiii��ttt R ttt��000�� royal. � �ments in Duplicate\/ ®��% /g . (, is • Well Prognosis Well: SCU 243B-4 Hilcorp Alaska,LLI Date:12/22/2017 Well Name: SCU 243B-4 API Number: 50-133-20489-00 Current Status: SI Gas Well Leg: N/A Estimated Start Date: January 20, 2018 Rig: E-line/Coil Tubing/ Nitrogen Unit Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 199-055 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (C) AFE Number: Maximum Expected BHP: —2,372 psi @ 5,428' TVD (Based on .437 psi/ft gradient to the deepest perforation. Max. Potential Surface Pressure: —2,135 psi @ 5,428' TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary SRU 243B-4 was drilled as a Tyonek grass roots gas producer in July 1999. The 7" surface casing was cemented to surface. A 5" production liner was set in a 6" hole at 6,060' and cemented with 150 Sx. of 15.8 ppg cement. The well was first shot in three intervals of the Tyonek formation (See schematic for depths) F/5,684' —5,712' but was unproductive. A plug was then set at 5,630' and 20' of cement was placed on top of it. The next zone perforated was 5,450—5,464'. The well had 3,000 ft of water on the interval when it was perfed. The purpose of this Sundry is to clean out/blow down this well and re-perforate the 56-9 sand without fluid on it, and to perforate and test three additional Tyonek Sands further hole (See table for depths). Safety Concerns • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. • Consider tank placement based on wind direction and current weather forecast(venting Nitrogen during this job). • Ensure all crews are aware of their stop job authority. Well Condition • Tagged fill with 1.78" GR @ 5,878'on 8/8/2017. • PX plug set in X-nipple @ 5,367'. Slick Line Pre Sundry Work • Pull PX plug @ 5,367'. o �•_ t1-- ✓ 'TC .S Liv I" 73t 5t Coil Tubing Procedure 1. MIRU Coiled Tubing, PT BOPE to 3,500 psi Hi 250 Low. Notify AOGCC 24 hrs. in advance of BOP test. • • Well Prognosis Well: SCU 2430-4 Hilcorp Alaska,LLI Date: 12/22/2017 2. RIH with 1.50" coil to 5,630' and tag plug. 3. RU N2 pumping unit. 4. Drop ball and come online with N2 and jet well dry. • Estimated volume of displaced 6% KCI is 25 bbls. 5. Once well is dry,verify desired surface pressure to leave on well with Operations Engineer. 6. POOH w/coil. LD BHA. 7. RD Coiled Tubing. E-Line Procedure 8. MIRU e-line and pressure control equipment. PT lubricator to 3,000 psi Hi 250 Low. 9. Adjust Nitrogen charge on well to achieve a 20% underbalance on the formation to be perforated. 10. Perforate and test the following sands one at a time with 1-11/16" strip guns 6 SPF perf guns (up to 12 SPF with 2 perf runs) starting with the deepest perf interval. Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt TY 56-9 5450 5468 5293 5307 18 TY 56-9 5473 5487 5316 5330 14 ✓ TY 57-8 5496 5517 5339 5360 21 TY 57-8 5548 5585 5398 5428 37 a. Proposed perfs also shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. d. Use Gamma/CCL to correlate. e. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. f. Conservation Order 716.001 defines the Tyonek Gas Pool as all intervals that correlate with the interval 5,304 feet MD to 10,085 feet MD in the Soldotna Creek Unit 41-4 well.All / of the perforations in table above fall within the defined SRU Tyonek Gas Pool, as ✓• currently defined. 11. POOH. 12. RD e-line. 13. Turn well over to production for testing. Note: Flowback-Once the well is perforated,the Nitrogen blanket will be flowed back and vented. Once hydrocarbons are detected,the perforated interval will be vented the shortest amount of time possible to confirm that the interval is capable of producing in economic paying quantities. This operation will be manned to minimize the amount of vented gas and once a commercial rate is established,the well will be either put into the system or shut in until it can be placed on line 1" through the facilities. Hilcorp anticipates that no more than 900 mcfd will be vented per interval and no more than 2 MMscf will be vented for all of the intervals contained in this Sundry Application. 14. Complete SVS testing per 20 AAC25.265 within 5 days of stable production. E-line Procedure(Contingency): 0 • Well Prognosis Well: SCU 243B-4 Hilcorp Alaska,LLI Date:12/22/2017 • If any zone produces sand and/or water or needs isolated • MIRU E-line, PT lubricator to 4,500 psi Hi 250 Low. • RIH and set isolation plug at depth above zone. Place 35'of cement on the plug to permanently abandon interval. • Jet dry with Coil Tubing and nitrogen if needed. • Perforate the next interval Attachments: 1. Actual and Proposed Well Schematics 2. Coil BOPE Schematic 3. CT Flow Diagrams(Forward and Reverse Jetting) 4. Blank RWO Change Form 5. Standard Well Procedure—N2 Operations • i • II Swanson River Field SCHEMATIC Well SCU#243B-4 Hilcorp Alaska,LLC As Completed 7/25/99 RKB to TBG Head=16.5' CASING AND TUBING DETAIL L SIZE WT GRADE CONN TOP BOTTOM 1 13-3/8"68 K-55 Weld Driven 96' Z 7" 29 L-80 Butt Surf 2150' 5" 15 L-80 TKC Butt 1925' 6060' Tubing: 2-3/8" 4.6 L-80 Butt SC Surf 5401' with 3/8" ss methanol injection line Surf 1899' ak4.: . �4 / ?�t 21`x " JEWELRY DETAIL NO. Depth Item 1 2-3/8"Tbg hgr w/Cameron"H"BPV profile h1Cl-' 'v 2 1820 2-3/8"Macco SMO-1 GLM w/dummy valve t5-6L 3 1899 Macco 2-3/8" SMO-1 Chem Inj Mdrl w/600 psi chem inj valve 4 1925 ZXP liner top packer 5 5283 Baker CMU Sliding Sleeve,F profile, 1.877"ID 6 5327 FH 2-3/8"x 5"Retrievable Packer 7 5367 2-3/8"X nipple, 1.875"ID w/PX Plug 08/08/17 8 5401 Wireline Entry Guide Sliding Sleeve 5 �� 9 5630 Posiset Bridge plug with 20' cement on top to 5610', ,inir6 at,- 9/19/99 7 8 cG-I PROPOSED PERFORATION DATA TOP BTM ZONE SPF DATE COMMENTS "�t V`M �'�� Gt1 5450 5464 56-9 Tyonek 4 9/22/99 — 5650 5688 59-2 Tyonek 4 8/10/99, abdnd 9/19/99 it 5691 5697 59-2 Tyonek 4 8/10/99, abdnd 9/19/99 L TD=6070' MD,6069' TVD 5700 5712 59-2 Tyonek 4 8/10/99, abdnd 9/19/99 Vertical Well SCU 243B-4 Schematic 08-16-17 DRAWN BY: TAB Updated by DMA 08-16-17 . n • SWANSON RIVER FIELD Hilcorp Alaska,LLC PROPOSED SCHEMATIC SC U #243B-4 As Completed 7/25/99 RKB to TBG Head =16.5' CASING DETAIL 1 Size Wt Grade Conn Top Bottom 13-3/8" 68# K-55 Weld Driven 96' 7" 29# L-80 Butt Surf 2,150' 5" 15# L-80 TKC Butt 1,925' 6,060' TUBING DETAIL 2-3/8" 4.6# L-80 Butt SC Surf 5,401' w/3/8"SS Methanol Injection Line Surf 1,899' JEWELRY DETAIL Ill No. Depth Item 2 1 2-3/8"Tbg hgr w/Cameron"H"BPV profile 2 1,820' 2-3/8"Macco SMO-1 GLM w/dummy valve 3 1,899' Macco 2-3/8"SMO-1 Chem lnj Mdrl w/600 psi chem inj valve Z LEI\4 4 1,925' ZXP liner top packer 5 5,283' Baker CMU Sliding Sleeve,F profile, 1.877"ID 6 5,327' FH 2-3/8"x 5"Retrievable Packer 7 5,367' 2-3/8"X nipple,1.875"ID w/PX Plug 08/08/17 8 5,401' Wireline Entry Guide 9 5,630' Posiset Bridge plug with 20'cement on top to 5610',9/19/99 PERFORATION DETAIL Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) SPF Ft Date Status TY 56-9 5,450' 5,464' 5,450' 5,464' 4 14 9/22/1999 TY 56-9 ±5,450' ±5,468' ±5,450' ±5,468' ±18 Proposed _ TBD TY 56-9 ±5,473' ±5,487' ±5,473' ±5,487' ±14 Proposed TBD TY 57-8 ±5,496' ±5,517' ±5,496' ±5,517' ±21 Proposed TBD TY 57-8 ±5,548' ±5,585' ±5,548' ±5,585' ±37 Proposed TBD TY 59-2 5,650' 5,688' 5,650' 5,688' 4 38 8/10/1999 Abanonded 9/19/99 TY 59-2 5,691' 5,697' 5,691' 5,697' 4 6 8/11/1999 Abanonded 9/19/99 TY 59-2 5,700' 5,712' 5,700' 5,712' 4 12 8/12/1999 Abanonded 9/19/99 Sliding Sleeve 5 >< X6 X 7 u 8 3-TY 56-9 }TY 57-8 WIPIPVIP _ - 9 - TY 59-2 L TD=6,070' MD/6,069'TVD Vertical Well DRAWN BY:TAB Updated by DMA 12-28-17 Swanson River 111 SCU 243B-04 12/22/2017 I1,1..,r1, ,i.,.t.e.I I.t j1.16.11.11161,.. I' ,1111444\ t 11.Nr-Tr 11 1611101, Coiled Tubing HR580 Injector Head&Gooseneck I7.10 �.1_.I Weight=12,850 lbs • IL rilliFy_ - u, 0 0 • 4-1/16"10K Conventional Stripper *III Mil • IIIM I 116 -41 5K C062 Lubricator WH PSI 2"1502 X2-1/16 10K rz, Flanged Valve 0 41 5K C062 x 4-1/16"10K Flange (Manual) 2-1/1610Kx2-1/16Ott�-, I 4-1/16"10K Combi BOP 10K Ranged Valve Top Set:Blind/Shear (Manual) i L.— m. . II'.tt -40 Second Set:Pipe/Slip :i'n.C. . .nm`l 4-1/16"10K Flow Cross —._ Manual 2x2 Valve 1:2"1502 x 2-1/16"10K Flange iCI4liONWP[0110 10 / Manual 2x2 Valve 2:2-1/16"10K x2-1/16"10K Flange Manual 2x2 Valve 3:2-1/16"10K x2-1/16"10K Flange Manua 2x2 Valve 4:2"1502 x 2-1/16"10K Flange .1111 4-1/16"10K x Wellhead Adapter Flange ill$1)I 11.1 I(fo 11(115 lip v' 1 1 Wellhead . 0 . g i 83 D 9 a ,1 V F M Q u Y ] VN 4 ' 3 Z Q m o t I ] O Z ] (n FI. 3] C 0 I- N : A U Z '' -a--, s oaaa a) CO • V Z 004 7-1 'e 0..) 1 ryry ,.g g g I ; N Z L. , V 1 0011 3 O Li c o E rcU L O d D I Ili i ..L' i IR 1111111 1111 '-1Ill1 0 JII!II■.N'.Sii.akJ kJ 'g: MI 411 IP 1.111 II = g a} o � Z 12 1.2I V d m • O e A V •A Sil' , 0 8 ;i 1 7 C 8 y6 eG la Or C o U N 0 0 ¢ Wel 0 g M 8 • • LII E= II . 3 U I— Z N 1 m O § ' i ~ L, g 3 O Z P O p F C v Z th Q V) €' D d s gtt Cl) A v t V y L • : A Z �$3 _. .. gLyy�� 11 i O cc V nn ku N Z N (n `0 C g( 0 Z v 0 U d - ill 1111 1111 1111 —"lilt 4) 111,II■1i;.!IFIL llAd ti ill 11111111 MI w 1 III o a ' _. ... ..J 3 0 0 1 0_ 0 I- c Iv am1 S O V •A 01111 so I .,____ \\,,,......0 Y I.8 . c to 0EL75 eq 0 O Z a� w8 lION e a e . 0 0 k � 0 a) k � C \ 6 g e c \ E \ 02 / / 2k ° E0 « � E — 2 St 2 \ § 2 0- E f / < / / � 7 � cil / 73 f0 / { a = § ./ n -0 ■ a) 2 e et CD CCI 2 >5 S / 2 � x c• 0 2J X / 0 k tIa. \ / / a) o § O /co co m = /� k 0 * CD a — Z CD % / a) U / / / #2 < .c E § 0 a = m O 2 ƒ . 2 � / } a a) \ o / § 2 -o & = co w0 c 3 t \ $ 0 2 a) @ § � % o o_ 5 0. ° \ ' 0 ■ ) xai w 0 / ¥ et & m .2 ® 0 2 k .2 w a) CO 2 iC.O 0 0 / 2 E .. 0 UU k RI a) E o & § e o e E / k < < / C3 0 \ • STANDARD WELL PROCEDURE Mem]) kla-la.i,,.t: NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets(formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher.Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 Pages NOT Scanned in this Well History File XHVZE This page identifies those items that were not scanned during the initial scanning project. They are available in the original file and viewable by direct inspection. /~-- OST_~' File Number of Well History File PAGES TO DELETE Complete RESCAN [] Color items - Pages: Grayscale, halftones, pictures, graphs, charts- Pages: Poor Quality Original- Pages: [] Other- Pages: DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED [] Logs of various kinds [] Other COMMENTS: Scanned by: Beverly Mildred Daretha~owell Date: ,~/? Is~, [] TO RE-SCAN Notes: Re-Scanned by: Bevedy Mildred Daretha Nathan Lowell Date: Is~ 199-055-0 Roll #1: Start: SOLDOTNA CK UNIT 243B-04 50- 133-20489-00 UNION OIL CO OF CALIFORNIA Stop Roll #2: Start Stop MD ~69_7_0 TVD 06069 Completion Date: ..... 9d_2_~/?.9 Completed Status: SUSP Current: T Name Interval Sent Received ~COMP RCD FINAL 5400-5570 9/22/99 CH 5 10/12/99 10/14/99 ~//COMP RCD I 5500-5910 8/10/99 CH 5 12/29/99 1/3/00 ...E'~ORRELATION LOG 1 5000-5980 8/3/99 CH 5 12/29/99 1/3/00 Mda'~U D I 4500-6070 OH 2 9/1/99 9/8/99 · .~ PEX-A1T/SP/GR FINAL BL(C) 3450-6066 OH 8/18/99 8/19/99 ~'"~EX-NDT/GR FINAL BL(C) 3450-6066 OH 8/18/99 8/19/99 ~POSIET PLUG FINAL 5400-5500 9/19/99 CH 5 10/12/99 10/14/99 R SRVY LSTNG BHI 0-6070 OH 10/19/99 10/21/99 T/C/D Wednesday~ June 20, 2001 Page l.of 1 Unocal Alaska Resources Unocal Corporation 909 West 9th Ave. Anchorage, AK 99519-6247 Tele: (907) 263-7889 Fax: (907) 263-7828 E-marl: childersd@.unocal, com UNOCAL Debra Childers Geotech Assistant DATA TRANSMITTAL December 29, 1999 To: Lori Taylor 3001 Porcupine Anchorage, AK 9950 Alaska Oil & Gas From' Debra Childers 909 W. 9th Avenue Anchorage, AK 99519-6247 Unocal Transmitting the following items: I:~,'i.~.~.,w,, ::.:,p~-:,¢.~L~TYPE~' :~i.~:SCALEt:LOG DATE:I a~mmVAL LOGGE~ ! ~P~St ~ 1 . SCU 243B~ CORRECTION LOG 5 INCH 8/3/99 ~ 5000-5980 1 Film :'S-CU-~B~ ...... ~-0~ RE~i~--~ 5 INCH 8/3/99 ~ 5~0:~9-80 1 B-Line ~2~B~-'~ -_~P~-~-~E~-~D 5 INCH 8/10/99 ~ 5500-5910 ........ 1 Film SCU 243B-4 COMPL~ION RECORD 5 INCH 8/10/99;5500-5910 1 B-Line SCU 31-08 COMPL~ION RECORD 5 INCH 11/5/99 ~ 100~-10560 1 B-Line ;~~, ~MM'~ ~A-~_M~~2~_ _ _~ I~H___~/JS_(9~.~_~420;.~7~_~ ~_ ~-~' ~-~_~-~(~ ~ scu 321-9 I CEMENT BOND LOG 5 INCH 8/24/99~9~0-10716 1 B-Line O~ ~*{co ~':~ ~ 'PL'O-S-~e '~E~ORD 5 INCH 7/31/99~9150-~4~ .......... F-~-~ - /' C ~ ~ 'S~U-'3~3-~ .... CUST'I~'S~' ~URvEY 5 INCH 9/~:8870-9428 1 B-Line · - P 6 ~ S.¢_U..32B-9 ....C0M~L~DN .B~O~D__ _5 I~¢~_ ........ 11~8/~9 :~8~:1~575 ............. L ..... B'~i~_ ..... ~ scu 32B-9 COMPL~ION RECORD 5 INCH 11/8/99 ~ 10385-10575 1 Film S~:8 ..... ~SM~L~iO~hEbb'R'E- ~c~ ....... ~g~9~0-0.~ 0'5~8 ............................ 1 Film ~/~' O ~ ~ S'C0-41A~ "C-0~PL~i0~ R~co~D 5 INCH 11~/99 9808:~65~¢ ................ ~--- --~-- - ~ SCU 43B-15 RD COMPL~ION RECORD 5 INCH g/1/99 7730~000 1 B-Line /~ SCD"~3BS' ' COMPE~ION RE~O-RS--~lNd~ ...... i~/~-~-2~0-i0-6b~ ....... ~- ..... ,eose r Received ~~~t&¢ I ~o'e: JAN 05 ~000 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG '1". Status of Well Classification of Service Well 2. Name of Operator 7. Pe~it Number~ ~~ Unocal Oil Company of California (UNOCAL) 99-55 3: Addre~ 8. APl Number 0CT 2 P. o. Box 196247, Anchorage, Ak 99519 50- 1~-20489 4. Loo~t~o. o~ ~, ~t ~"~1~ ..... 9. Unit o~ b~ ~ka Oil ~ 2003' FSL, 575' FEL, Sec. 4, T7N, Rgw, SM'[~~'~%-~ Soldotna Creek Unit AtTop Producing Intewal (5650') ~ ~10. Well Number Sec. 4, T.., ..W, ~t To~l Dep~ ~~}~~: ~ 1. Fiald and ~ool 2072' FSk, $15' FEk, Soc. 4, ~, B~W, SM $. ~leva~on in [eot {indimto KB, DF, otc.) ~ ~. koasa Desi~na~on and Sa~al ~o. Swanson ~or Fiel~onok 1 ~.7' KB~ A-028~7 17. Total Depth (MD+~D) 18. Plug Back Dep~ (MD+~D) 19. Direc~onal Su~ey I o. where SSSV set I ~'.T~'o*"~ of Permafrost 6070' MD/6069' ~D 5990'/5989' Yes: x No:I ~ feet MDI NA ~. Type Electric or Other Logs Run Array Induction/Neutro~Densi~/GR ,,, 23. CASING, LINER AND CEME~ING RECORD S~ING DEPTH MD CASING SIZE ~. PER ~. G~DE TOP BOSOM HOLE SIZE CEME~ING RECORD AMOUNT PULLED 13-3/8" 68¢ K-55 0 96' Driven 0 7" 29¢ L-80 0 2150' 8-1/2' 395sx-lead, 75 sx-tail 0 5" 15¢ bS0 1950' 6070' 6" 149 sx of 15.8 ppg 0 ~4. Pedorations open to Production (M~TVD of Top and BoSom and 25. TUBING RECORD intewal, size and number) SIZE DEPTH S~ (MD) PACKER S~ (MD) 2-~8" 5401' 5327' 5450'-5464' MD~VD 4 spf, 0.31' dia hole 26. ACID, F~CTURE, CEMENT SQUE~E, ~C. DE~H I~ERVAL (MD) AMOUNT & KIND OF MATERIAL USED All Peds below abdnd 9/19/99 with Posiset plug ~ 5630' and 20' of ~t 5650'-5688' MD~VD 4 spf, 0.31" dia hole 5691'-5697' MD~VD 4 spf, 0.31' dia hole 5700'-5712' MD'VD 4 sp', 0.31' dia hole nRi ii, iAL 27. PRODUCTION TEST ~ ~ ~t~ Rmt Pmduotion J M~od of Operation (Rowing, ~ li~, Non~, un~bl~ t~ flow ~ Iflowin9 to ,~m fo~ t~t Date of Te~t Houm Te~ted PRODUOTION FOR OIL-BBL ~AS-MOF WATER-BBL OHOKE 81ZE I ~A~-OIL ~TIO 9/2~1999 TE~T PERIOD => 0 0 MOF 0 NAI NA FIowTubin~ ~in~ Pms~um OAL~U~TE~ OIL-BBL ~A~-~OF WAT~-BBL OIL~VI~-API (oor0 Pre~. 0 24-HOUR ~TE => 0 0 MOF 0 28. OORE DATA Bd~f d~dption of litholo~y, poro~i~, fmotum~, ~pp~mnt dip~ ~nd pm~n~ of oil, ~ or w~t~r. ~ubmit ~m ohip~. None Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit in duplicate 29. 30. GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and l~me of each phase. Top Tyonek Fm. 5285 5285 ' , '31. LIST OF A'I-['ACHMENTS Wellbore schematic, Daily Summary of Rig Operations, Directional Survey Record 32. I hereby certify that the foregoing,is true and correct to the best of my knowledge Signed Title Drilling Manager Date ~ ~'~ INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on ali ............ " ty .l:?e.s pf.l.a~d~ ~..nd leases in Alaska. Item 1: Classi~cation of Semite Wells: eas injec~on, water injec~on, ste~ injec~on, air inje~on, salt water disposal, water supply for injec~on, obse~a~on, injection for in-si~ combus~on. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other space on this form and in any attachments. item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the productin intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 UNOCAL ) RKB to TBG Head - 16.5' 2 3 4 Sliding Sleeve SIZE WT Swans~ River Field Well SCU #243B-4 As Completed 7125/99 CASING AND TUBING DETAIL GRADE CONN TOP BOTTOM 13-3/8" 68 K-55 Weld Driven 96' 7" 29 L-80 Butt Surf 2150' 5" 15 L-80 TKC Butt 1925' Tubing: 2-3/8" 4.6 L-80 Butt SC Surf with 3/8" ss methanol injection line Surf 6060' 5401' 1899' JEWELRY DETAIL NO. Depth Item 2 1820 3 1899 4 1925 5 5283 6 5327 7 5367 8 5401 9 5630 2-3/8" Tbg hgr w/Cameron "H" BPV profile 2-3/8" Macco SMO-1 GLM w/dummy valve Macco 2-3/8" SMO-1 Chem Inj Mdrl w/600 psi chem inj valve ZXP liner top packer Baker CMU Sliding Sleeve, F profile, 1.877" ID FH 2-3/8" x 5" Retrievable Packer 2-3/8" X nipple, 1.875" ID Wireline Entry Guide Posiset Bridge plug with 20' cement on top to 5610', 9/19/99 · , TD -- 6070' MD, 6069' TVD Vertical Well TOP 545O 565O 5691 5700 PROPOSED PERFORATION DATA BTM ZONE SPF DATE COMMENTS 5464 56-9 Tyonek 4 9/22/99 5688 59-2 Tyonek 4 5697 59-2 Tyonek 4 5712 59-2 Tyonek 4 8/10/99, abdnd 9/19/99 8/10/99, abdnd 9/19/99 8/10/99, abdnd 9/19/99 SCU243B-4 actual 7-25-99 REVISED: 10/15/99 DRAWN BY: TAB UNOCAL Alaska Drilling Drilling Summary Report SCU #243B-4 7/7/99 to 9/22/99 7/7/99 to 7/11/99 Move rig from SRU #43A-15RD to SCU 243B-4. Accept rig at SCU #243B-4 at 15:30 on 7/11/99. NU diverter. 7/12/99 Function test diverter. RIH with 12-1/4" bit and tag fill at 37'. Drilled out conductor to 98'. 7/13/99 Circ hole clean, POOH and lay down 12-1/4" bit. RIH with 8-1/2" bit. Drilled from 98' to 1741'. 7/14/99 Drilled 8-1/2" hole from 1741' to 2160'. POOH for wiper trip. RIH wti 2160'. Drop multi-shot directional survey tool and POOH. 7/15/99 Finished POOH with 8-1/2" bit. Ran 7" 29# L-80 casing to 2150'. Pump 395 sx (141 bbl) of 12.8 ppg lead cement and 75 sx (15 bbl) of 15.8 ppg tail cement. Displaced with mud, land mandrel hanger and bumped plug to 3000 psi. Good returns with 45 bbl of good cement to surface. ND diverter, cut landing joint and remove same. Install tubinghead and packoff. Test packoff to 3000 psi. NU 7-1/16" BOP stack. 7/16/99 Pressure test BOPE, replace door seal on double gate and retest, OK. BOPE test witness waived by BLM and AOGCC. RIH with 6" bit. 7/17/99 Drill float collar @ 2063' and cement down to 2140'. Circ hole to new solids-free mud. Pressure test casing to 2000 psi. Drill float shoe at 2150' and new formation to 2170'. Perform leak-off test with surface pressure of 727 psi or 15.54 ppg EMW. Drill from 2170' to 2553'. 7/18/99 Drill from 2553' to 3984'. 7/19/99 Drill 6" hole from 3984' to 4738'. 7/20/99 Drill 6" hole from 4738' to 5536'. 7/21/99 Drill 6" hole from 5536' to 6070' TD. Drop Multi-shot directional survey tool and POOH. RU to run logs. 7/22/99 Log Platform Express Array Induction/Density/NeutronlGR from 6066' to 3450'. POOH and rig down Schlumberger. Change rams to 5" and test door seals. Run 5" 15#, L-80 TKC liner from 1940' to 6060'. 7/23/99 Pump 150 sx of 15.8 ppg cement while rotating liner. PU from liner top and circulate liner top and drill pipe clean. POOH with drill pipe. RIH and set ZXP liner top packer at 1925'. Pressure test liner top packer and liner to 2000 psi. 7/24/99 RIH with bit and scraper. Tag landing collar @ 5,975'. Clean pits. Change over to 6% KCL. POOH. Run 2-3/8" completion. 7/25/99 Continue to run 2-3/8" completion. Set packer @ 5,327'. Test packer and casing to 2000 psi. NU tree and test to 5,000 psi. Release rig @ 23:00 hrs. 8/10/99 RU Schlumberger. Perforate with 1-11/16" Enerjet guns. First gun run= 5684'-5688', 5691'-5697' and 5700'-5712'. Tubing pressure increased from 0 to 375 psi. Attempt to flow well and tubing pressure decreased to 0 psi. No sign of gas. Second gun run = 5650'-5684'. Tubing pressure increased from 0 psi to 300 psi. Flow well to tank a total of 7 bbl with tubing pressure declined to 0 psi. SI well. SITP built up to 180 psi after 7 hrs. 8/12/99 Install GLV in mandrel at 1820'. Gas lifted fluid from well with no sign of formation gas. SI well and evaluate alternatives. 9/19/99 9/21/99 9/22/99 RU Schlumberger E-line Unit. RIH with 1-11/16" PosiSet thru tubing bridge plug. Set plug at 5630'. Tag plug to confirm set. RIH with dump bailer and dump cement on top of plug from 5630' to 5610'. Pressure test cement and Posiset plug to 1500 psi. Pressure declined to 1410 psi in 30 minutes and then held steady at 1410 psi for I hour. Good test. RU Schlumberger perforating unit. Gas lifted fluid off well to 1820' and left 350 psi tubing pressure. Perforate with 1-11/16" Enerjet gun from 5450' to 5464'. Tubing pressure remained at 350 psi. Bled down pressure to 150 psi system, no apparent formation flow. Unload well with gas lift. Well unable to flow gas. Suspend operations pending evaluation of wellbore options. UNOCAL SCU 243B-4 SCU 243B-4 slot #1 Soldotna Creek Unit Kenai Peninsula, Alaska SURVEY LISTING by Baker Hughes INTEQ Your ref: EMS <0-6070> Our ref : svy6003 License : Date printed : 23-Ju1-1999 Date created : 23-Ju1-1999 Last revised : 23-Ju1-1999 Field is centred on n60 43 10.024,w150 51 4.527 Structure is centred on n60 43 29.766,w150 51 16.124 Slot location is n60 43 29.766,w150 51 16.124 Slot Grid coordinates are N 2457894.921, E 347017.322 Slot local coordinates are 0.00 N 0.00 E Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North UNOCAL SCU 243B-4,SCU 243B-4 Soldotna Creek Unit,Kenai Peninsula, Alaska Measured Inclin. Azimuth True Vert Depth Degrees Degrees Depth SURVEY LISTING Page 1 Your ref : EMS <0-6070> Last revised : 23-Ju1-1999 R E C TAN G U LA R Dogleg Vert C 0 0 R D I N A T E S Deg/lOOft Sect 0.00 0.00 0.00 0.00 0.00 N 0.00 E 0.00 0.00 127.00 0.31 144.96 127.00 0.28 S 0.20 E 0.24 -0.20 189.00 0.55 132.32 189.00 0.62 S 0.51 E 0.41 -0.51 250.00 0.38 143.84 250.00 0.98 S 0.85 E 0.32 -0.85 312.00 0.71 274.37 311.99 1.12 S 0.59 E 1.61 -0.59 373.00 0.81 286.55 372.99 0.96 S 0.20 W 0.31 0.20 433.00 0.94 289.76 432.98 0.68 S 1.07 W 0.23 1.07 555.00 0.70 299.26 554.97 0.03 N 2.66 W 0.23 2.66 678.00 0.78 292.04 677.96 0.71N 4.10 W 0.10 4.10 737.00 0.65 296.42 736.95 1.01N 4.77 W 0.24 4.77 799.00 0.51 305.59 798.95 1.32 N 5.31 W 0.27 5.31 861.00 0.29 300.85 860.95 1.56 N 5.67 W 0.36 5.67 922.00 0.18 257.42 921.95 1.62 N 5.89 W 0.33 5.89 984.00 0.18 220.00 983.95 1.53 N 6.05 W 0.19 6.05 1107.00 0.24 224.79 1106.95 1.20 N 6.36 W 0.05 6.36 1168.00 0.24 232.44 1167.95 1.03 N 6.55 W 0.05 6.55 1232.00 0.35 225.97 1231.95 0..81N 6.79 W 0.18 6.79 1294.00 0.33 218.94 1293.95 0.54 N 7.04 W 0.07 7.04 1358.00 0.42 205.09 1357.94 0.18 N 7.26 W 0.20 7.26 1421.00 0.48 210.01 1420.94 0.25 S 7.49 W 0.11 7.49 1485.00 0.53 221.83 1484.94 0.71S 7.82 W 0.18 7.82 1548.00 0.74 246.90 1547.94 1.08 S 8.39 W 0.55 8.39 1611.00 0.93 255.74 1610.93 1.37 S 9.26 W 0.36 9.26 1675.00 1.10 259.05 1674.92 1.61 S 10.36 W 0.28 10.36 1737.00 1.13 258.51 1736.91 1.85 S 11.55 W 0.05 11.55 1801.00 0.98 261.48 1800.90 2.06 S 12.71W 0.25 12.71 1864.00 0.87 263.46 1863.89 2.19 S 13.71W 0.18 13.71 1928.00 0.81 268.43 1927.88 2.26 S 14.65 W 0.15 14.65 1992.00 0.59 279.51 1991.88 2.22 S 15.43 W 0.40 15.43 2052.00 0.53 293.01 2051.87 2.06 S 15.99 W 0.24 15.99 2094.00 0.42 274.56 2093.87 1.97 S 16.32 W 0.45 16.32 2176.30 0.24 233.29 2176.17 2.05 S 16.76 W 0.35 16.76 2240.30 0.24 230.03 2240.17 2.21 S 16.97 W 0.02 16.97 2303.20 0.35 271.26 2303.07 2.29 S 17.26 W 0.37 17.26 2366.90 0.48 283.56 2366.77 2.23 S 17.71 W 0.25 17.71 2431.00 0.60 287.31 2430.87 2.06 S 18.30 W 0.20 18.30 2494.00 0.60 280.83 2493.86 1.90 S 18.94 W 0.11 18.94 2556.20 0.65 274.79 2556.06 1.81 S 19.61 W 0.13 19.61 2619.30 0.71 277.51 2619.15 1.73 S 20.35 W 0.11 20.35 2683.70 0.82 282.51 2683.55 1.58 S 21.20 W 0.20 21.20 2747.40 0.73 284.29 2747.24 1.38 S 22.03 W 0.15 22.03 2810.80 0.80 283.50 2810.64 1.18 S 22.86 W 0.11 22.86 2937.00 0.85 295.97 2936.82 0.56 S 24.55 W 0.15 24.55 3001.40 0.87 299.55 3001.22 0.11 S 25.41 W 0.09 25.41 3193.40 0.59 313.01 3193.20 1.28 N 27.40 W 0.17 27.40 3321.40 0.40 300.64 3321.20 1.96 N 28.27 W 0.17 28.27 3385.20 0.32 315.26 3384.99 2.20 N 28.58 W 0.19 28.58 3449.20 0.41 319.55 3448.99 2.50 N 28.86 W 0.15 28.86 3512.90 0.45 326.72 3512.69 2.88 N 29.14 W 0.11 29.14 3576.70 0.39 338.80 3576.49 3.29 N 29.36 W 0.17 29.36 All data is in feet unless otherwise stated. Coordinates from slot #1 and TVD from estimated rkb (154.00 Ft above mean sea level). Bottom hole distance is 79.98 on azimuth 330.11 degrees from wellhead. Vertical section is from wellhead on azimuth 270.00 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL SCU 243B-4,SCU 243B-4 Soldotna Creek Unit,Kenai Peninsula, Alaska Measured Inclin. Azimuth True Vert Depth Degrees Degrees Depth SURVEY LISTING Page 2 Your ref : EMS <0-6070> Last revised: 23-Ju1-1999 R E C TAN G U LA R Dogleg Vert C 0 0 R D I N A T E S Deg/lOOft Sect 3641.00 0.36 344.97 3640.79 3.69 N 29.49 W 0.08 29.49 3704.60 0.36 344.42 3704.39 4.08 N 29.60 W 0.01 29.60 3768.60 0.35 2.27 3768.39 4.47 N 29.64 W 0.17 29.64 3832.40 0.67 18.35 3832.18 5.02 N 29.52 W 0.54 29.52 3894.80 0.90 17.97 3894.58 5.83 N 29.25 W 0.37 29.25 3957.60 0.89 9.88 3957.37 6.78 N 29.02 W 0.20 29.02 4020.90 0.78 1.66 4020.66 7.69 N 28.92 W 0.26 28.92 4083.30 0.72 5.16 4083.06 8.51 N 28.87 W 0.12 28.87 4147.40 0.89 11.58 4147.15 9.40 N 28.73 W 0.30 28.73 4210.00 0.91 17.29 4209.74 10.35 N 28.49 W 0.15 28.49 4272.50 1.23 21.53 4272.23 11.45 N 28.10 W 0.53 28.10 4336.90 1.43 17.08 4336.62 12.86 N 27.61W 0.35 27.61 4400.60 1.41 13.44 4400.30 14.38 N 27.19 W 0.15 27.19 4464.30 1.12 13.51 4463.98 15.75 N 26.86 W 0.46 26.86 4526.80 1.07 18.07 4526.47 16.90 N 26.54 W 0.16 26.54 4590.70 0.95 10.80 4590.36 17.98 N 26.25 W 0.27 26.25 4654.60 0.78 8.22 4654.25 18.93 N 26.09 W 0.27 26.09 4718.00 0.99 4.58 4717.64 19.91 N 25.99 W 0.34 25.99 4780.60 0.95 0.62 4780.24 20.96 N 25.94 W 0.12 25.94 4843.10 1.05 353.44 4842.73 22.05 N 26.00 W 0.26 26.00 4905.90 1.10 355.61 4905.51 23.22 N 26.11W 0.10 26.11 4968.80 1.21 349.07 4968.40 24.48 N 26.28 W 0.27 26.28 5032.40 1.47 348.58 5031.98 25.94 N 26.57 W 0.41 26.57 5095.00 1.55 342.31 5094.56 27.53 N 26.99 W 0.29 26.99 5157.90 1.63 337.68 5157.44 29.17 N 27.59 W 0.24 27.59 5285.00 1.67 339.53 5284.49 32.58 N 28.92 W 0.05 28.92 5346.60 2.16 342.45 5346.05 34.52 N 29.58 W 0.81 29.58 5410.30 2.35 341.27 5409.70 36.91 N 30.37 W 0.31 30.37 5471.40 2.39 340.78 5470.75 39.30 N 31.19 W 0.07 31.19 5534.80 2.35 344.08 5534.10 41.79 N 31.98 W 0.22 31.98 5595.30 2.65 343.62 5594.54 44.33 N 32.71 W 0.50 32.71 5658.90 2.82 342.84 5658.07 47.23 N 33.59 W 0.27 33.59 5722.00 2.88 344.75 5721.09 50.25 N 34.46 W 0.18 34.46 5785.20 2.97 345.06 5784.20 53.36 N 35.30 W 0.14 35.30 5848.80 3.29 347.10 5847.71 56.73 N 36.14 W 0.53 36.14 5912.60 3.36 344.45 5911.40 60.32 N 37.05 W 0.26 37.05 5976.50 3.47 342.31 5975.19 63.96 N 38.14 W 0.26 38.14 6011.40 3.46 342.33 6010.03 65.97 N ' 38.78 W 0.03 38.78 6070.00 3.46 342.33 6068.52 69.34 N 39.85 W 0.00 39.85 NO SURVEY - Projection t All data is in feet unless otherwise stated. Coordinates from slot #1 and TVD from estimated rkb (154.00 Ft above mean sea level). Bottom hole distance is 79.98 on azimuth 330.11 degrees from wellhead. Vertical section is from wellhead on azimuth 270.00 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL SCU 243B-4,SCU 243B-4 Soldotna Creek Unit,Kenai Peninsula, Alaska SURVEY LISTING Page 3 Your ref : EMS <0-6070> Last revised : 23-Ju1-1999 Comments in wellpath MD TVD Rectangular Coords. Comment 6070.00 6068.52 69.34 N 39.85 W NO SURVEY - Projection to T.D. Casing positions in string 'A' Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing 0.00 0.00 O.OON O.OOE 2150.00 2149.87 1.99S 16.65W 7" Csg 0.00 0.00 O.OON O.OOE 110.00 110.00 0.21S 0.15E 13 3/8" Csg NO PROPOSAL Unocal Alaska Resources Unocal Corporation 909 West 9th Ave. Anchorage, AK 99519-6247 Tele: (907) 263-7889 Fax: (907) 265-7828 E-mai/: childersd@, unocal, corn UNOCAL Debra Childers Geotech Assistant DATA TRANSMITTAL October 12, 1999 To: Lori Taylor 3001 Porcupine Anchorage, AK 99501 Alaska Oil & Gas From: Debra Childers 909 W. 9th Avenue Anchorage, AK 99519-6247 Unocal Transmitting the following items: SCU 11-9 /Thermal Decay Time Log 5 INCH 9~/99 ~00-10690 1 B-Line AOGCC ,SCU 1i-9" . -$~ma~e~-Ti-~-Gg ....... 5 INCH ~ 9P/99 ~00-10690 1 Film ~ AOGCC SCU~3B-4 . 'C~i~e~)~n~$~.~- scu 243B-4 Completion Record 1 11/16" Enerjet 5 INCH 9/2N99 ~00-5570 1 Film AOGOC scu'243B-~ P-0~?e]'?]g920' Ce-~/,~-~-.'~ ......... ~-~jN_CR--'_~_/~__?~9(99_ 5~0.;550~__ L' ~'.' .... ~-- B:~]~$__~g-GC~c~-.~ SCU 243B-4 Posiset Plug 2~'_.~9~_eg~ SCU41B-g c0-m-~ietion Record / Gamma Ray/COL 5 INCH 9/15/99 5900-9335 1 B-Line AOGOC SOU 4!B-9 .... cemRlp~i~n_R~cgr~ (Ga~.~.~_R_~y!g~_ __5 INCH 9/15/99 5900-9335 1 Film AOGCC SCU 43A:15RD_ g.r~dg~._Pl~g_$_$~jng_~g~rd scU43A-!SR~ ..... g~i~ge~l~g s~.~i~.g_~e~d- ........ 5 INCH 6~25~99 7000-7200 1 Film AOGCC SCU 43B/!5' . 5z[a~g~_ug~og ~99~ ............ ~_IN~_H_ ........713/99 715o-824o_ ............ ) ....... B:Ljg~~gg_ _ scU 43B-15 Arr)~ I~gC~)g~$~ .................... 5 INCH 713199 7150-8240 1 Film AOGCC SCU 43B-15 ..Plaffg.[m_E~pr$ssw/_Ar~ay.~ndg_cti~n__Togl_ _~[.5 I~g~ ..... ]/3/_ ~9_7j~0:~4~o ..............~__ B-Line AOGCC scu 43B-15 .P_laffgrm_~xgr~.~(Srr~y_.l~.dgc~gn T001 .~. / ~I_~C_~ ...... ZI~I~ ~g;~2~_~ ........... _1_ _ Film AOGCC - .. RECEIVED Please acknowl~ signing and returning one copy of this transmiffal or FAX to (907) 263-7828. ,,~al~(a 0il & Gas Cons. Commission Anchorage Re: SCU #243B-4 Proposed Plugback Subject: Re: SCU #243B-4 Proposed Plugback Date: Mon, 13 Sep 1999 08:36:26 -0800 From: Blair Wondzell <blair_wondzell~admin.state.ak.us> Organization: State of Alaska, Dept of Admin, Oil & Gas To: "Billingsley, Tim-Contract" <billita@unocal.com> Tim, Thanks for the "heads-up". We agree this is a continuation of the PTD. look forward to getting the 407. Good Luck. Blair Wondzell We'll "Billingsley, Tim -Contract" wrote: <<recomp plan 9-8-99>> <<SCU243B-4 actual 7-25-99>> Blair, Present wellbore schematic and proposed reompletion plan is enclosed above. This will be a continuation of the approved Permit to Drill completion plan for this well. I will submit a 407 completion report when the perf/testing i s over. Thanks, Tim Billingsley 263-7659 Name: recomp plan 9-8-99.doc recomp plan 9-8-99.doc Type: Winword File (application/msword) Encoding: base64 Description: recomp plan 9-8-99 Name: SCU243B-4 actual 7-25-99.D0C SCU243B-4 actual 7-25-99.D0C Type: Winword File (application/msword) Encoding: base64 Description: SCU243B-4 actual 7-25-99 1 of 1 9/13/99 8:37 AM $CU #343B-4 Proposed Plugback Subject: SCU #243B-4 Proposed Plugback Date: Wed, 8 Sep 1999 15:04:38-0700 From: "Billingsley, Tim -Contract" <billita~unocal.com> To: "'Wondzell'" <blair wondzell~adrnin.state.ak.us> <<recomp plan 9-8-99>> <<SCU243B-4 actual 7-25-99>> Blair, Present wellbore schematic and proposed reompletion plan is enclosed above. This will be a continuation of the approved Permit to Drill completion plan for this well. I will submit a 407 completion report when the perf/testing is over. Thanks, Tim Billingsley 263-7659 ]~ Name: recomp plan 9-8-99.doc ..... i Type: Winword File (application/msword)I ~recomp plan v-zs-vv.aocI Encoding: base64 tDescription: recomp plan 9-8-99 Name: SCU243B-4 actual 7-25-99.DOC Type: Winword File (application/msword)l 243B-4 actual 7-25-99.DOCi ~ Encoding: base64 iDescnpt~on: SCU243B-4 actual 7-25-99 1 of 1 9/8/99 2:45 PM UNOCAL ) ._ jl SCU 243B-4 Plug 59-2 sand and Perf 56-9 Sand 918199 Proposed Recompletion Procedure SCU #243B-4 was perforated on 8/10/99 in the Tyonek 59-2 sand at 5650'-5712'. Unfortunately, this zone only produced water. The following is proposed to further test this well. 1) RU E-line unit and set PosiSet thru-tubing bridge plug at 5630'. 2) Batch mix cement and dump bail 20' of cement on top of bridge plug. 3) WOC for 24 hrs or longer. 4) Pressure test bridge plug to 1500 psi. 5) RU perforating unit and perforate Tyonek 56-9 sand at: 5450'-5464' 6) Flow test the 56-9 sand interval If the 56-9 sand will not flow sufficient rate of gas, possible additional perforations may be shot in the Tyonek 58-1 sand at 5544' to 5590'. Therefore, only a 20' cement cap up to 5610' on top of the bridge plug is proposed in step #1. recomp plan 9-8-99.doc I 9/8/99 UNOCAL ) RKB to TBG Head = 16.5' 2 3 4 Sliding Sleeve NO. SIZE WT Swanson River Field Well SCU #243B-4 As Completed 7/25/99 CASLNG AND TUBUNG DETAII, GRADE CON_.,~ TOP BOTTOM 13-3/8" 68 K-55 Weld Driven 96' 7" 29 L-80 Butt Surf 2150' 5" 15 L-80 TKC Butt 1925' Tubing: 2-3/8" 4.6 L-80 Butt SC Surf with 3/8" ss methanol injection line Surf 6060' 5401' 1899' JEWELRY DETAHJ Depth Item 1820 1899 1925 5283 5350 5380 5401 2-3/8" Tbg hgr w/Cameron "H" BPV profile 2-3/8" Macco SMO-1 GLM w/dummy valve Macco 2-3/8" SMO-1 Chem Inj Mdrl w/600 psi chem inj valve ZXP liner top packer Baker CMU Sliding Sleeve, F profile, 1.877" ID FH 2-3/8" x 5" Retrievable Packer 2-3/8" X nipple, 1.875" ID Wireline Entry Guide k TD = 6070' MD, 6069' TVD Vertical Well TOP 565O 5691 5700 PROPOSED PERFORATION DATA BTM ZONE SPF DATE COMMENTS 5688 59-2 Tyonek 4 8/10/99 5697 59-2 Tyonek 4 8/10/99 5712 59-2 Tyonek 4 8/10/99 SCU243B-4 actual 7-25-99.DOC REVISED: 9/8/99 DRAWN BY: TAB Unocal Alaska Resources Unocal Corporation 909 West 9th Ave. Anchorage. AK 99501 ?e/e; (¢07) 26~-7889 Fox: (¢~37) 263-7828 E-ma#: ch#dersd@unoca/, corn UNOCAL Debra Childers Geotech Ass/ston! DATA TRANSMITTAL August 18, 1999 To: Laurie Taylor 3001 Porcupine Anchorage, AK 99501 Alaska Oil & Gas From: Debra Childers 909 W. 9th Avenue Anchorage, AK 99519-6247 Unocal Transmitting the following items: SCU 2438-4 Platform Express Array Induction/SP 2/5 7/22/99 3450-6066 1 B-Line SCU 2438-4 Platform Express Array Induction/SP 2/5 7/22/99 3450-6066 1 Film sCU-24~3B-4 Platfoim ExPress-'De-n'sity~Neutr--o-n ...... 2/~5 .......... ~7-~2-2/-99~0'-6-0-6-6- ....... 1 B-Line SCU 2438-4 Platform Express Density/Neutron 2/5 7/22/99 3450-6066 1 Film ~- O~7 sBu 438-1'5 co-mlp!~tion Rec0~d ..............~ ..... 7/22/9-9--7-~-~8i~ -i- B-[in'~ ,~ SBU 438'15 Completion Record -5 ........7-/22/99' 7-30(~-8127 - 1-~=~1-~ SBU 438-15 Mudlog ' -- 6)30/99 7i70-8250 - B-Eine · SRU ~438-15 Mudlog 6/30i99- 7-17'0-8250 Please ac~eceipt by s~gning Received ~Y'.4 and returning one copy of this transmittal or FA)Cfa'k'~7) 963'-7828 - ' ~-"~'~ Date: Unocal Corporation P.O. Box 196247 Anchorage, AK 99501 Telephone (907) 263-7660 UNOCAL Dan Williamson Drilling Manager Commissioner Christenson: Friday, July 23, 1999 A~ ~- - Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Attn: Commissioner Robert N. Christenson Re: Surface Location Survey Plat ~ SwaB.son I:ti~/c,r I:i,-,I,4 ~ ~-.-~-~otn a' c-~e;k 'U ~'i~" #243~ Enclosed is the surveyed surface location plat for SCU #243B-4 as per 20 AAC 25.005(j). If there are any questions, please contact Tim Billingsley at 263-7659. Sincerely, /%,, Dan Williamson Drilling Manager Unooal Alaska RECEIVED 1999 ~,~a~,~ ~ ~^~,~,.,~',.~',ju"vv 5255.54 NE COR S4 Fnd. BLM COMPUTED WCMC S4 Existin9 SCU43A-4 61 O' FEL 2O49' FSL Surface Location Well 243B--4~ _ GRID N' 2457894.920 GRID E: 347017.305 ~ ,., LATITUDE' 60'45'29.766" i m LONGITUDE' 150'51'16.124" - __1 0 Surface Elev. 158 6' MSL L~ c~ Centerline 24" Dia. Flange inside 10' Dia. CSP o z SECTI ON 4 T7N, R9W, SEWARD MERIDIAN, ALASKA SE CORNER SECTION 4 SOUTH LINE SEC. , ir COMPUTED N89'14'58"W GRID N: ,__.,.,,,.,_ ~._., 1) Location of well site was accomplished using GRID E: 547566.564 static GPS techniques. LATITUDE: ~_~.~an'zk-¢'ln. n3q" 2) All dimensions are in LONGITUDE: 150'51'04.562" U.S. Survey feet and bearings are grid unless noted otherwise. 3) Surface location coordinates ~,.~%~ OF Al are referenced to NAD27 ~' "~\~/" ........ '?""'---..~,~. N6S Sro. "Audry" recovered, /~.~...~ 9 ~ .,..+...~,:~ 0 4) Cartesian coordinate values are in Alaska z.~: j:~:~ ~ TH State Plane Zone 4. ~. ~~ ¢° ./././,-~ ~ ~_7~ 5) Surface elevation is ~]'~'(.'l~"~)"l::l"'~'~L~,~'l~f~"~~ referenced to MSL based ~, ~'"'. 4928-S .'"L<~L-'~ on SRU 13-.3' Well Elev. Rle2pS(~r5t f .+¢O.~...,~1/~...~...~ according to Completion ~ - ,~- ....... v~-- · GRID ~I I, ~*'rsslo.~-_ ~%~ SE COR S9 6) Offsets to section lines determined 'lJ,~,,~,,~,~,'% Fnd. BLM from o partial retrocement of T7N, R9W shown hereon. DRAWN BY HS vlSCU243]}-4 WELL SURVEY 91-17-33 SFILDEITNA CREEK UNIT, ALASKA AFE ~134703 FIELD I3OOK NO. Surveyed by:. McLANE Consulting Group Box 468 Soldotna, AK 99669 SCALE 7/19/99 DRAWING NO. UNOCALe TON Y KNO WL ES, G 0 VERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 June 29. 1999 Dan Williamson Drilling Manager Unocal Corporation P O Box 196247 Anchorage, AK 99519-6247 Re: Soldotna Creek Unit 243 B-4 Unocal Corporation Permit No: 99-55 Sur Loc: 1943'FSL and 626'FEL. Sec. 04. T7N. R9W. SM Btmhole Loc. 1943'FSL and 626'FEL. Sec. 04. T7N? R9W. SM Dear Mr. Williamson: Enclosed is the approved application for permit to drill the above referenced well. The permit to drill does not exempt you from obtaining additional permits required bv law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Bloxvout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25 035. Sufficient notice (approximately 24 hours) must be given to allow a representative of the Commission to witness a test of BOPE installed prior to drilling new hole. Notice max' be given bx' contacting the Commission at 279-1433. · Robert N. Christcnson, P. E. Chairman BY ORDER OF THE COMMISSION dlffEnclosures CC: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage Alaska 99501-3192 Re~ THE APPLICATION OF Union Oil Company ) of California (Unocal)for an order granting ) an exception to the spacing requirements of ) 20 AAC 25.055(a)(4) to provide for the drilling ) of the Soldoma Creek Unit Well #243B-4 gas ) well to an undefined gas pool. ) Conservation Order No. 445 Well #243B-4 Soldoma Creek Unit June 14, 1999 IT APPEARING THAT: o Union Oil Company of California (Unocal) by letter dated May 24, 1999, requested an exception to the well spacing provisions of 20 AAC 25.055(a)(4). The exception would allow drilling the Soldotna Creek Unit (SCU) 243B-4 gas well to a bottomhole location that is closer than 1500 feet to a section line. The Commission published notice of opportunity, for public heating in the Anchorage Daily News on Mav 27, 1999, pursuant to 20 AAC 25.540. 3. No protests to the application were received. FINDINGS: 1. The SCU #243B-4 well will be drilled as a vertical hole from a surface location 1943' from the south line, 626' from the east line of Section 4, T7N, R9W, Seward Meridian. 2. Unocal is the owner and operator of all offsetting sections. 3. An exception to the well spacing provisions of 20 AAC 25.055(a)(4) is necessary to allow the drilling of this well. CONCLUSION: Granting a spacing exception to allow drilling of the SCU #243B-4 gas well will not result in waste nor jeopardize correlative rights. Conservation Order No. June 14. 1999 Page 2 NOW, THEREFORE, IT IS ORDERED: Unocal's application for exception to the well spacing provisions of 20 AAC 25.055 (a)(4) for the purpose of drilling the SCU #243B-4 is approved. DONE at Anchorage, Alaska and dated June 14. 1999. Robert N Christ Alaska Oil and Gas Conservation Commission Carn~ll60-echsli, Commissioner Alaska Oil and Gas Conservation Commission David W. Johnston, Commissioner -~~~ Alaska Oil anXGas Conserhation Commission AS 31.05.080 provides that within 20 davs after receipt of written notice of the entr?' of an order, a person affected by it may file ~Sth the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd da5' following the date of the order, or next working day ifa holiday or weekenck to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Conunission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the t~mal order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10m day after the application for reheating was filed). Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Soldotna Creek Unit ~243B-4 Union Oil Company of California (Unocal) by letter dated May 24, 1999, has requested an exception to the provisions of 20 AAC 25.055(a)(4) for the drilling of a vertical gas well to an undefined gas pool within the Soldotna Creek Unit. The exception would allow Unocal to drill the Soldotna Creek Unit No. 243B-4 well to a bottomhole location that is closer than 1500 feet to a section line. The well will be drilled as a vertical hole from a surface location 1943' from the south line, 626' from the east line, Section 4, T7N. R9W, Seward Meridian. A person who may be harmed if the requested order is issued may file a written protest prior to 4:00 PM, June 11, 1999, with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, and request a hearing on this matter. If the protest is timely filed and raises a substantial and material issue crucial to the to the Commission's determination, a hearing on the matter will be held at the above address at 9:00 AM on June 29, 1999, in conformance with 20 AAC 25.540. If no protest is filed, the Commission will consider the issuance of the order without a hearing. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Diana Fleck at 793-1221 before June 22, 1999. Cammy Oechsli Commissioner Published May 27, 1999 ADN AO 02914029 Unocal Corporation P.O. Box 196247 "· Anchorage, AK 99501 Telephone (907) 263-7660 UNOf. AL il Dan Williamson Drilling Manager Wednesday, May 19, 1999 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Attn: Re: Commissioner David Johnston Application for Permit to Drill (Form 10-401) Swanson River Field Soldotna Creek Unit #243B-4 Commissioner Johnston: Enclosed is the Application for Permit to Drill the SCU #243B-4 including two copies. This well will be a Tyonek gas producer drilled as a vertical well to a TD of 6000'. The proposed well will be drilled from the same pad as SCU #43A-4 with approximately 52' horizontal separation between the two wells. SCU #43A-4 is currently an active Hemlock/G zone producer, with perforations at 10,189'-10,445'. SCU #43A-4 is a vertical well down to the 6000' TD of the proposed SCU #243B-4. There is no history in the Swanson River Field of hydrogen sulfide gas being present in any of the formations that this SCU #243B-4 will encounter. The proposed SCU #243B-4 will be less than 1500' from a section line and a spacing exception request has been submitted as per spacing requirements described in 20AAC25.055(a)(3). An exact survey of the surface location will be provided when cellar and conductor driving has been completed. If there are any questions, please contact Dan Williamson at 263-7677 or Tim Billingsley at 263-7659. ,~,inc~rely, Dan Williamson Drilling Manager Unocal Alaska ORIGINAL ~ -~ STATE OF ALASKA ..... ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 la. Type of work Drill X Redrill I lb. Type of well Exploratory Stratigraphic Test Development Oil Re-entry DeepenI Service Development Gas X Single Zone Multiple Zone 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool Unocal 154' RKB est Swanson River Field 3. Address P.O. Box 196247 6. Property Designation Tyonek 59-2 Pool Anchorage. Ak 99519-6247 A-028997 4. Location of well at surface 7. Unit or Property Name 11. Type Bond (see 20AAC25.025) 1943' FSL and 626' FEL Sec. 4, T7N, R9W, SM Soldotna Creek Unit AK Statewide Oil & Gas Bond At top of productive interval Tyonek 8. Well Number Number Same 243B-4 U 62-9269 At total depth 9. Approximate spud date Amount Same 7/1/99 $200,000 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15 Proposed depth (MD and TVD) property line 52' (SCU #43A-4) 6000' MD 5906' No active 59-2 producers Lease 2560 acres 6000' TVD 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2) Kickoff depth feet Maximum hole angle 0° Maximum Surface 404 psig. At total depth (TVD) 2777 psig 18. Casing Setting Depth program size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD 13-3/8" 68 K-55 Weld 80' 0 0 80 80 Drive 8.5" 7" 29 L-80 Buttress 2150' 0 0 2150' 2150' 562 cuff Class G blend 6" 5" 15 L-80 TKC Butt 4050' 1950' 1950' 6000' 6000' 369 cuff Class G blend 19. To be completed for Redrill, Re-entry and Deepen Operations Present well condition summary Total depth: measured feet Plugs (measured) true verical feet ORIGINAL Effective Depth measured feet Junk (measured) true vertical feet Casing Length Size Cemented Measured Depth Ti'de~erTical~...: Structural Conductor Surface !'-~ '..-' Intermediate Production Perforation Depth' measured Anch0rag:~ true vertical 21.1 h~-'~c, ertify that th~f~?~oing is true and correct to the best of my knowledge ~/~~~ Signed ,"'~~/~ ~./~i~,.,~,,~F,,~,/~'~'/~I~ _ ~ Title: Drilling Manager Date Commission Use Only <~ ~;7 _,~ 50_/~,~'_, ~ ~,~ ~ ~ c/~' '~ ~ ¢-'_ for other requirements Conditions of approval Samples required Yes (~ Mud log required Yes_.~___.h~ Hydrogen Sulfide measures Yes ~ Dir~ional Survey required Yes Required working pressure for BOPE 2M ~--I~ 5M 10M 15M Other: ORIGINAL SIGNED-I~r by order of/. Approved by Robe~ N. Christens~ Commissioner the commission Date Form 10-401 Rev. 12-1-85 AFE#134703 Submit in triplicate 18 17 2O 29 p&$' AND : ~'I"ORAGE. · · 221-33 · ,.'*~; 32-33 -; ........ 14A-33 : , o'~--33 , 13~'34 ~ _ . .~ ~ ~ 24-33 ~ 1-4 - 21A-4 . o ~c~ AND . 4 ~1-5 ~2~-4~ 13-4 ~ 42~-5 ' 428-5 I ~-4 43A-4 J ! 4-4 DISPOSAL -S~- .... X ! 31-8 32'-8 312-9 GRAVEL a1-s ' ,. I ........ ! -'?' I · 14A-5 21-22 412-22 14-22 331-27 11 243-4 34-4 2 1-27 I J ~3 j 314-2~ 27 ...... SPILL EQUIP MENT~_.~~=~, .~' - --'r' ~ --..,-? 2!-34 .4-34 , \ \ ' I \ \ / I / / / / / I + - --.~ \ / I / / / /- / / / / i ~ ~ .... 7[-- LANDING STRIP 22-23 - 26 / 25 ~ Soldoma Creek Unit #243B-4 Proposed Location Plat Surface Location: 1943' FSL, 626' FEL, Sec 4, T7N, R9W, SM Proposed Bottomhole Locations: Same Section 32 Section 5 Section 8 Section 33 Section 4 SCU g43A4 Hemlock & G zone Producer 5Pr 2°'p°Ns°edrth w eg2;;;-~ ~_~ ~alPr°p°Swedel1 ~ SCU g243B-4 1943' Section 9 Section 34 Section 3 Section 10 ,0g = ,,I N p-eo~I mt. IAI o,L \ p~sodoJd au.~no S.vd IlOaX ol pgo}I IAIS 'Ak6}I 'NLL '~e aoS "-lSle:I ,9i59 "-IS2t ,g~761 :uo.rl~ao'-I oa.j.ms posodoM ~7-1itg'¢i5# fIDS lno.gg'-I al.tS tT-~tg~'~;# 1.mFl >IOOJD euloplog IIOAk slookI sSU~D posodo~d UNOCAL General Procedure 5/18/99 1 ) Drive two joints of 9-5/8" conductor to 80'. Weld starting head on conductor. 2) Move in Inlet Drilling Rig # CC-1 or equivalent. 3) Rig up diverter and lines. Function test divert valves. 4) Drill vertical 8-1/2" hole from surface to 2150' MD/2150' TVD. 5) Run 2150' of 7" 29# AB Modified Buttress casing. 6) Cement 7" casing with 562 cuft cement (100% excess). 7) ND diverter, install tubinghead, NU and test 5000 psi BOP stack. 8) Drill float equipment, cement and 10' of new formation and perform LOT. 9) Drill vertical 6" hole from 2150' to 6000' MDFFVD. 10) Log from 6000' TD to surface casing at 2150' with triple combo density/neutron/induction log. 11 ) Run 5" 15# L-80, TKC Buttress liner from 6000' to 1950' with 5" x 7" liner hanger. 12) Set hanger, release from hanger, re-engage drive spline to allow liner rotation. 13) Cement 5" liner from 6000' to top of liner at 1950' with 369 cuft based on 50% excess while rotating liner. 14) PU running tool to top of liner and circulate excess cement to surface. POOH with running tool. 15) RIH and set liner top packer. Pressure test liner and liner top to 2500 psi. POOH with drill pipe. 16) RIH with liner clean out assembly on 2-7/8" PAC drill pipe. Clean out liner to PBTD of 5920'. Displace well to 6% KCL. POOH with clean out assembly. 17) Run 2-3/8" completion tubing to 5400' with retrievable packer. Methanol injection mandrel will be at 1900' with 3/8" methanol line strapped to outside of tubing. 18) 19) 2O) 21) 22) Displace tubing to diesel, land hanger and set packer at 5350'. Pressure test annulus to 2500 psi. ND BOP stack, NU seal flange and tree. Test tree to 5000 psi. Move rig. RU flowline and methanol injection pump. RU E-line unit. Perforate Tyonek 59-2 sand with through-tubing guns at 5686'-5760' and flow test well. P ROC243B-4. DOC 1 5/18/99 Hazard Section Application for Permit to Drill SCU #243B-4 There are no known over-pressured intervals in the proposed drilling of SCU #243B-4 from surface to TD of 6000'MD/6000'TVD. Offset pressure information indicates the highest reservoir pressure gradient should be 2520 psi encountered at 5440' TVD for an EMW of 8.9 ppg. The proposed mud program of 9.5 ppg mud density will be sufficient to control the reservoir pressure down to 6000'. The surface hole will be drilled with a diverter so extra attention will be directed towards good drilling practices including slow trips out of the hole, accurate monitoring of trips with a trip sheet and keeping the hole full by circulating over it during trips. These practices will help avoid swabbing in a gas kick in the surface hole section. There has been no history of lost circulation while drilling with the proposed Iow mud densities at the relatively shallow depths of SCU #243B-4. Differential sticking should also be mitigated by the relatively Iow mud densities. Mud and Cuffings Disposal The mud from SCU #243B-4 will be disposed in the mud disposal well, SCU #-43- 4MD. The cuttings generated by drilling #243B-4 will be disposed in the solid waste facility at Swanson River Field. UNOCAL ) RKB to TBG Head = Swanson~liver Field Well SCU #243B-4 Proposed Grass Roots Well, 1999 CASING AND TUBING DETAIL SIZE WT GRADE CONN TOP BOTTOM 13-3/8" 68 K-55 Weld Surf' 80' Driven 7" 29 L-80 Butt Surf 2150' 5" 9.3 L-80 1950' 6000' Tubing: 2-3/8" 4.6 L-80 Surf with 3/8" ss methanol injection line Surf 5400' 1900' JEWELRY DETAIL NO. Depth Item 2 20OO 2-3/8" Tbg hgr w/Cameron "H" BPV proffie Macco 2-3/8" SMO-1 Chem Inj Mdrl w/1000 psi chem inj valve 5350 2-3/8" x 5" Retrievable Packer 5380 2-3/8" X nipple 5400 Tubing tail ~ , x TD = 6000' MD, 6000' TVD Vertical Well TOP 5472 5584 5686 PROPOSED PERFORATION DATA BTM ZONE SPF DATE COMMENTS 5546 56-9 Tyonek 5620 58-1 Tyonek 5760 59-2 Tyonek SCU243B-4SCHPROP2.DOC REVISED: 5/11/99 DRAWN BY: TAB UNOCAL Swan~0n River Field SCU #243B-4 Diverter Fill-up Annular BOP 13-5/8" 3000 psi · Flow One 10" divert line with 10" ball valve The divert line will be situated as straight as possible with vent being 100' or more from any ignition source. 13-3/8" Conductor I I The valve automatically opens when the diverter closes. This is a variance from 20AAC25.035. DIVERTER243B-4.DOC REVISED: 5/7/99 DRAWN BY: TAB Inlet Drilling Rig #CC-1 7-1/16" 5000 psi BOP Stack 7-1/16" Annular Preventer 5k psi Blind Rams 5k psi Pipe Rams 3-1/8" Kill Line ~ Drilling Spool I psi Pipe 5k Rams [X~ 7-1/16"" 5M ~1 TubinglheadF '" Casing 4-1/16" Choke Line 1 = HCR Valve 2 = Gate Valve Blowout Prevention Equipment Inlet Drilling Rig #CC-1 or Equivalent 7-1/16" BOP Equipment 1 ea 7-1/16" x 5000 psi wp single ram type preventer 1 ea 7-1/16"x 5000 psi wp double ram type preventer 1 ea 7-1/16"x 5000 psi wp annular preventer 1 ea 7-1/16" x 5000 psi wp drilling spool with 2 ea 4" side outlets (choke and kill), HCR and manual valves on choke line and two manual valves on kill line. 1 ea Koomey BOP control unit with 120 gallon volume tank, w/twelve 10-gallon accumulator bottles and nitrogen back-upsystem. 1 ea 5 station, remote control panel 1 ea 5,000 psi choke manifold with Cameron automatic hydraulic choke 3" - 10,000 psi with control choke panel. 1 lot Hydraulic pipe and fittings from manifold to BOP stack. Swanson River Well #SCU 243B-4 Bottomhole Pressure Information The following presents data used for calculation of anticipated surface presures (ASP) during drilling of the SCU 243B-4. The pore pressure gradient was estimated from the following information: BHP Depth Well psi TVD SCU 243-4 2575 5624 EMW, pp.q 8.8 SCU 243-4 2520 5440 8.9 SRU 242-16 1300 3161 7.9 Comment 8/61, initial BHP before production 8/61, initial BHP before production 9/89, initial BHP before production The fracture gradient at surface casing point was conservatively estimated at .80 psi/ft or 15.4 ppg. Casing Pore Casing Setting Fracture Pressure Mud Pore ASP Size Depth Gradient Gradient Weight Pressure Drilling (in.) (TVD ft) (Ibs/.qal~ (Ibs/_qal~ (Ib/_qal~ (psi) (psi) 7 2150 15.4 8.4 9.0 939 660 5 liner 6000 NA 8.9 9.5 2777 Procedure for Calculatinq Anticipated Surface Pressure While Drilling ASP is determined as the lesser of 1) surface pressure at breakdown of the formation at the casing seat (with gas bubble just below shoe and mud gradient above shoe) or 2) formation pore pressure at the next casing point less 1/4 gas gradient and 3/4 mud gradient to the surface as follows: 1) ASP = (FGx.052xD) - (MWx.052xD) : (15.4x.052x2150)- (9.5x.052x2150) = 660 psi OR 2) ASP = FPP - (0.1gas gradient xDx.25) - (MWx.052xDx.75) = 2777 - (.1x6000x.25) - (9.5x.052x6000x.75) = 2777 - 150 - 2200 = 404 psi Kick Tolerance for SCU #243B-4 With 9.5 ppg mud in the hole and a gas bubble in the well and an estimated shoe frac gradient of 15.4 ppg, the shoe will fail at 660 psi of surface preSSure ((15.4- 9.5)x.052x2150'). At the most vulnerable point for shoe failure when the gas bubble is just below the 7" casing shoe, the hydrostatic pressure situation will be as follows: + 660 psi max surface pressure without fracturing the shoe + 21,50' x .052 × 9.5 ppg mud in the surface casing = 1062 psi + Gas height (Hr) x 0.1 psi/ft gas bubble just below surface casing + (60_00'-2150'-Ht).z .052 x 9.5 mud below the. qas bubble .052 × 6000' TVD = 2777 psi estimated formation pressure Solving the above equation for Ht: 660 + 1062 + 0.1Ht + (6000'-2150'-Ht).494 = 2777 660 +1062 +0.1 Ht + 1902 - .494 Ht = 2777 847 = .394 Ht Ht: 2149' (TVD height of gas 'bubble just below shoe which will cause shoe fracture failure) The gas volume is 2149' x (.023 bbl/ft for a 3.5' Drill pipe x 6" annulus) = 49 bbl If the gas volume at the shoe is 49 bbl, then the original gas kick volume when it first entered the wellbore at 6000' TVD would be: P~ x Vi '-- P2 x V2 P1 = 9.5 x 6000' x .052 = 2964 psi hydrostatic pressure at TD V~ = X, unknown gas volume at TD P2 = (660 psi surf pressure w/o fracturing shoe) + (9.5 ppg x .052 x 2150') -- 1722 psi pressure at shoe Va --- 49 bbl gas bubble just below 7" shoe V~ =49 bbl x 1722 psi/2964 psi = 28 bbts kick tolerance at 6000' TVD. This size of kick should be able to be detected with close monitoring of the trip tank and with the help of a mudlogging unit which will be operating during the drilling of this well. 00121/99 $CLT tt243B-4 SCU #243B-4 Casing Design 7" Surface Casinq, 29# L-80, Buttress Worst case for burst is tubing leak near the surface after the well Burst = 6000'TVD x((8.9 formation x .052) - 0.1 gas grad)) = 2177 psi Worst case for collapse is if lost returns occur while drilling below Collapse - (8.4x.052x2150') -(2150' x .1 ) = 724 psi for full evacuation Tension = 29 x 2150' = 62,350# 5" 15#1 L-80, TKC buttress liner @ 6000' MD/TVD Tension = (6000'-1950') x 15#= 61K is completed. 29# rated @ 8160 psi for burst Safety Factor = 3.7 OK the 7" surface casing. 29# rated @ 7020 psi for clpse Safety Factor = 9.7 OK 29# rated for 676K Safety Factor = 10.8 OK Rated - 350K for body yield Safety Factor = 5.7 OK Worst case for collapse of the liner would be when the completion interval depletes and a formation with virgin pressure is behind pipe. Collapse = (8.9 x .052 x 6000') - 0 psi inside = 2777 psi (Unrealistic but worst case) Rated: 7250 psi for collapse Safety Factor 2.6 OK Worst case for burst would be a tubing leak with gas in the annulus, the effective burst pressure at the liner top at 1950' would be: Burst = (6000'x8.9 formation x .052) - (0.1 gas grad x1950') Rated = 8290 psi for burst - (8.4 x .052 x1950')= 1730 psi Safety Factor = 4.8 OK SCU #243B-4 Casing Specifications Proposed Casing . Surface Liner _ _ 7" 29#, L-80, AB mod Butt 5" 15#, L-80, TKC Buttress Joint Strength, K lbs 746 350 _ Body.Strength, K lbs 676 396 Burst Rating, psi 8,160 8,290 ._~oilapse Rating, psi 7,020 7,250 Max Torque, ft-lbs 12,000 7,700 _ Opt Makeup, ft-lbs to triangle 3,140 Min Make-up 6,000 2,900 CSGSPEC243B-4.XLS SCU 243B-4 Cementing Program 7" Surface Casing 8-1/2" hole @ 2150' MDFFVD Cement volume for surface casing: Lead cement Class G with additives at 12.9 ppg: 1650' x 0.127 cuft/ft (8-1/2" x 7") x 2.0 (100% excess) -- 419 cuft Tail Cement Class G with additives at 15.8 ppg: 500' (2150'-1650') x 0.127 cuft/ft x 2.0 (100% excess) - 127 cuft 80' float joints -- 80' x .2085 cuft/ft - 16 cuft Total Tail -- 143 cult Total cement = 419+143 = 562 cult 5" Liner 6" hole @ 6000' MD/6000' TVD, top of liner at 1950' MD Cement volume for liner based on open hole volume plus 50%, liner lap, and shoe joints. Estimated volume is: 3850' (6000' - 2150') x 0.0600 cuft/ft (6" x 5") x 1.50 - 347 cuft 200' liner lap @ 0.0722 cuft/ft = 14 cuft 80' shoe jts x 0.1059 cuft/ft (5" liner capacity) = 8 cuft Total Cement = 347 + 14 +8 = 369 cuft Class G cement @ 15.8 ppg with additives. UNOCAL DRILLING FLUIDS PROGRAM SWANSON RIVER WELL SRU 243B-4 OVERVIEW The SRU ~r243B-4 is a grass roots well in the Swanson River Field. Potential problems in the surface interval include gravel, coal and lost circulation. Maximize use of solids equipment in order to avoid overloading the system with sand. The production interval will be drilled-with a conventional Iow-solids non-dispersed mud system. A lubricant may be used if torque becomes a problem. 13 318" CONDUCTOR: (DRIVEN TO +/- 80') 8 1/2" SURFACE INTERVAL: (0- 2100' MD) A standard fresh water Gel/Gelex spud mud will be used in the surface hole. Initial funnel viscosity should be in the 100 - 125 sec./qt, range. Adjust viscosity as needed for large gravel zones. Lower fluid loss to 10cc's with Aquapac or Drispac LV prior to running casing. Lower gels if needed with Spersene. , , Fluid Properties- Surface Hole Density (PPG) Funnel Viscosity Yield Point Fluid Loss pH 8.6 - 9.0 100 - 125 sec/qt 20 - 40 N.C. - 10 cc/30 min 8.5-9.0 Evaluate the surface mud for possible use in the production interval. If unsuitable, plan on discarding and follow the plan listed below. CASED HOLE DISPLACEMENT TO LSND FLUID 1. Drill out intermediate casing plus 10' of new hole with existing mud system. 2. Clean pits and build new Iow-solids non-dispersed drilling fluid. . Displace well to LSND mud as follows. Pump 25 bbls fresh water with one drum Safekleen followed by 25 bbls water viscosified with 3 ppb FLO-VIS (weight up as needed with Barite for well control). Follow with the LSND fluid. . Pump at highest rate practical. Aggressively rotate and reciprocate pipe while displacing. Make sure bit is on bottom when leading edges of spacers and LSND fluid are at the bit. Calculate strokes and monitor returns at the flowline. Discard spacers until clean LSND returns are observed. Make sure all pits and lines are cleaned prior to adding additional fluid to the pits. (TM9909) (04/99) 6" PRODUCTION INTERVAL: (2300'-6000' MD) The 8 1/2" hole will be drilled with a LSND fluid. Control fluid loss at +/- 5 cc's with additions of Drispac and/or Resinex. Use barite for weighting up as needed. Add Soltex @ 2 PPB for coal stabilization. Run as fine of mesh shaker screens as possible. Centrifuge mud system both while drilling and during trips. Bit/BHA bailing from sticky clays can be treated with Drilling Detergent, DrilI-Kieen, SAPP and/or Nut Plug sweeps. Lubetex can be used to reduce torque and drag. Use Defoam-X if foaming becomes a problem. Drill to T.D. If hole conditions warrant, spot a viscous pill on bottom. Run and cement casing. Fluid Properties - Production Interval (LSND Fluid) Density Plastic Yield Gels Fluid Drill (PPG) Viscosity Point 10s/10m Loss pH Solids 9.0- 9.5 10- 16 15-20 10- 15 + 5 cc 8.5- 9.0 < 5% LOST CIRCULATION CONTINGENCY SEEPAGE LOSSES: For seepage losses add 5 - 10 PPB of Liquid Casing while drilling. MODERATE LOSSES: Mix 10 - 30 PPB of M-I Seal Fine & Medium while drilling and/or spot pills across loss zone. Check motor orifice and tool size restrictions. SEVERE LOSSES: For severe losses due to fractures, faults, rubble zones. Mix and spot a 40 bbl 50 PPB LCM pill with M-I Seal Medium, Coarse and Nut Plug Coarse. Pull up into casing shoe and squeeze pill into loss zone with 200 psi, shut in and watch for pressure bleed-off. When pressure holds for 15 minutes resume drilling. Prior to pumping coarse pills, check motor orifice and tools for size restrictions. NOTE: Liquid Casing will pass through 60-80 mesh screens. · Liquid Casing and OM Seal will lower pH rapidly - increase Caustic Soda additions accordingly. · At 6-8 ppb, Liquid Casing and OM Seal will raise YP significantly and PV about 3 cps. .. Volume Usa,g~ and Cost Estimate Interval Surface Production Total Volume 990 780 1750 Material Cost $4,000 $13,000 $17,000 Engineering $4,375 $6,250 $10,625 (TM9909) (04/99) Drilling Fluid System Description Inlet Drilling Rig #CC-1 Mud Pumps 1 ea PZ9 Gardner Denver, 3" x 5000 psi shear release valve and a 4" x 4000 psi gates bumper hose powered by a 398 TA Cat. 1 ea 214P Oilwell powered by twin 671 Detroit diesel engines. Mud Tank System (466 bbl Total Volume) Tank A- 88 bbl suction tank Tank B- 150 bbl middle tank Tank C- 172 bbl shaker tank Tank D- 27 bbl pill tank Tank E- 17 bbl centrifuge tank Tank F- 12 bbl sand trap Trip Tank- 35 bbl 501 bbl total Mud System Equipment 1 ea 1 ea 1 ea 1 ea 1 ea 3 ea Brandt dual tandem 800 gpm shale shakers Drilco See-FIo degasser 36" x 6' Poor Boy gas buster Pioneer eight cone desilter Pioneer Model S-800 mud hopper Medearis 3" revolving mud agitator guns 1 ea 1 ea 1 ea Pit level indicator with audio and visual alarms Fluid flow sensor Gas monitoring for H2S and LEL with sensors at rig floor, sub and shakers. MUD TAMKS ATTACHMENT E Unocal Corporation P.O. Box 196247 Anchorage, AK 99501 Telephone (907) 263-7660 UNO L Dan Williamson Ddlling Manager Wednesday, May 19, 1999 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Attn: Re: Commissioner David Johnston Application for Permit to Drill (Form 10-401 ) Swanson River Field Soldotna Creek Unit #243B-4 Commissioner Johnston: Enclosed is the Application for Permit to Drill the SCU #243B-4 including two copies. This well will be a Tyonek gas producer drilled as a vertical well to a TD of 6000'. The proposed well will be drilled from the same pad as SCU #43A-4 with approximately 52' horizontal separation between the two wells. SCU #43A-4 is currently an active Hemlock/G zone producer, with perforations at 10,189'-10,445'. SCU #43A-4 is a vertical well down to the 6000' TD of the proposed SCU #243B-4. There is no history in the Swanson River Field of hydrogen sulfide gas being present in any of the formations that this SCU #243B-4 will encounter. The proposed SCU #243B-4 will be less than 1500' from a section line and a spacing exception request has been submitted as per spacing requirements described in 20AAC25.055(a)(3). An exact survey of the surface location will be provided when cellar and conductor driving has been completed. If there are any questions, please contact Dan Williamson at 263-7677 or Tim Billingsley at 263-7659. Sincerely, Dan Williamson Drilling Manager Unocal Alaska -+ 14-9 18 T7 2O 5O 31 4 ti-5 13-4 j 42A-5 42~-5 I l : 41-28 ...,~NEE .......... ........43-28 ~ ~EHOUSE AND ~ORAGE- "4, 323,-9 'I'10'_0 I 314-4 ~ASTE DiSPOSaL _S~=- .... 3-~-4 FLd~R.E 23-4 ~ '43A-4 243-4 21-22 412-22 · 21.4.-4 ! _.43.-4 - n- - iF-- : , '..' 1-27 14-22 -.,,., ,q'~' -_~7 T.S. ' 22 ! -33 · ,.x.-; 32-331 14A-33 .'. 22-:33 13~34 2 !-27 23-F~27 ~14-27 27 SPILL 22-23 - 23. I / I I- l / /' i I -- ; ,4-34 i \ \ I / / / / / / 7 / / / / / / / ! ! Soldotna Creek Unit #243B-4 Proposed Location Plat Surface Location: 1943' FSL, 626' FEL, Sec 4, T7N, R9W, SM Proposed Bottomhole Locations: Same Section 32 Section 5 Section 8 Secdon 33 Section 4 SCU #43A4 Hemlock & G zone Producer 52' Northwest of ~ Proposed #243B-4 x% Propos,ed ~ SCU #24~B4 al Well 4-- 626' 1943' Section 9 Section 34 Section 3 Section 10 Proposed Grass Roots Well Soldoma Creek Unit #243B-4 Well Site Layout SCU #243B-4 Proposed Surface Location: 1943' FSL, 626' FEL, Sec 4, TTN, Rgw, SM Road to 43-4MD well SCU #243B4 Proposed To Main Road Rig Outline / "'7"~ SCU ,g43A-4 126' 1"=50' ~-' SCU 243 ~- ~4 UNOi:AL General Procedure 5/18/99 i 1) Drive two joints of 9-5/8" conductor to 80'. Weld starting head on conductor. 2) Move in Inlet Drilling Rig # CC-1 or equivalent. 3) Rig up diverter and lines. Function test divert valves. 4) Drill vertical 8-1/2" hole from surface to 2150' MD/2150' TVD. 5) Run 2150' of 7" 29# AB Modified Buttress casing. 6) Cement 7" casing with 562 cuft cement (100% excess). 7) ND diverter, install tubinghead, NU and test 5000 psi BOP stack. 8) Drill float equipment, cement and 10' of new formation and perform LOT. 9) Drill vertical 6" hole from 2150' to 6000' MD/TVD. 10) Log from 6000' TD to surface casing at 2150' with density/neutron/induction Icg. 11 ) Run 5" 15# L-80, TKC Buttress liner from 6000' to 1950' with 5" x 7" liner hanger. 12) Set hanger, release from hanger, re-engage drive spline to allow liner rotation. 13) Cement 5" liner from 6000' to top of liner at 1950' with 369 cuft based on 50% excess while rotating liner. 14) PU running tool to top of liner and circulate excess cement to surface. POOH with running tool. 15) RIH and set liner top packer. Pressure test liner and liner top to 2500 psi. POOH with drill pipe. 16) RIH with liner clean out assembly on 2-7/8" PAC drill pipe. Clean out liner to PBTD of 5920'. Displace well to 6% KCL. POOH with clean out assembly. 17) Run 2-3/8" completion tubing to 5400' with retrievable packer. Methanol injection mandrel will be at 1900' with 3/8" methanol line strapped to outside of tubing. 18) Displace tubing to diesel, land hanger and set packer at 5350'. 19) Pressure test annulus to 2500 psi. 20) ND BOP stack, NU seal flange and tree. Test tree to 5000 psi. Move rig. 21) RU flowline and methanol injection pump. 22) RU E-line unit. Perforate Tyonek 59-2 sand with through-tubing guns at 5686'-5760' and flow test well. triple combo PROC243B-4.DOC 1 5/18/99 Hazard Section Application for Permit to Drill SCU #243B-4 There are no known over-pressured intervals in the proposed drilling of SCU #243B-4 from surface to TD of 6000'MD/6000'-I-VD. Offset pressure information indicates the highest reservoir pressure gradient should be 2520 psi encountered at 5440' TVD for an EMW of 8.9 ppg. The proposed mud program of 9.5 ppg mud density will be sufficent to control the reservoir pressure down to 6000'. The surface hole will be drilled with a diverter so extra attention will be directed towards good drilling practices including slow trips out of the hole, accurate monitoring of trips with a trip sheet and keeping the hole full by circulating over it during trips. These practices will help avoid swabbing in a gas kick in the surface hole section. There has been no history of lost circulation while drilling with the proposed Iow mud densities at the relatively shallow depths of SCU #243B-4. Differential sticking should also be mitigated by the relatively Iow mud densities. Mud and Cuffings Disposal The mud from SCU #243B-4 will be disposed in the mud disposal well, SCU #-43- 4MD. The cuttings generated by drilling #243B-4 will be disposed in the solid waste facility at Swanson River Field. UNOCAL RKB to TBG Head = SIZE WT Swanso 'Sver Field Well sC~-~g243B-4 . Proposed Grass Roots Well, 1999 CASING AaND TUBING DETAIL GRADE CONN TOP BOTTOM 13-3/8" 68 7" 29 K-55 Weld Surf' 80' Driven L-80 Butt Surf 2150' 5" 9.3 L-80 1950' 6000' Tubing: 2-3/8" 4.6 L-80 Surf with 3/8" ss methanol injection line Surf 5400' 1900' JEWELRY DETAIL NO. Depth' Item 2-3/8" Tog hgr w/Cameron "H" BPV profile 2 2000 Macco 2-3/8" SMO-1 Chem Inj Mc[ri w/1000 psi chem inj valve 5350 2-3/8" x 5" Retrievable Packer 5380 2-3/8" X nipple 5400 Tubing tail TD = 6000' MD, 6000' TVD Vertical Well TOP 5472 5584 5686 PROPOSED PERFORATION DATA . BTM ZONE SPF DATE COMMENTS 5546 56-9 Tyonek 5620 58-1 Tyonek 5760 59-2 Tyonek SCU243B-4SCHPROP2.DOC REVISED: 5/11/99 DRAWN BY: TAB UNOCAL ) Swan~a River Field SCU #243B-4 Diverter Fill-up Annular BOP 13-5/8" 3000 psi Flow One 10" divert line with 10" ball valve 'The divert line will be situated as straight as possible with vent being 100' or more from any ignition source. 13-3/8" Conductor The valve automatically opens when the diverter closes. This is a variance from 20AAC25.035. DIVERTER243B-4.DOC REVISED: 517199 DRAWN BY: TA_B Inlet Drilling Rig #CC-1 7-1/16" 5000 psi BOP Stack 7-1/16" Annular Preventer 3-1/8" Kill Line ~ ' ' I 5k psi Blind Rams 5k psi Pipe Rams Drilling Spool psi Pipe Rams 5k 7-1/16 .... 5M Tubinglhead 7~ Casing 4-1/16" Choke Line 1 = HCR Valve 2 = Gate Valve Blowout Prevention Equipment Inlet Drilling Rig #CC-1 or Equivalent 7-1/16" BOP Equipment 1 ea 7-1/16" x 5000 psi wp single ram type preventer 1 ea 7-1/16"x 5000 psi wp double ram type preventer 1 ea 7-1/16"x 5000 psi wp annular preventer 1 ea 7-1/16"x 5000 psi wp drilling spool with 2 ea 4" side outlets (choke and kill), HCR and manual valves on choke line and two manual valves on kill line. 1 ea Koomey BOP control unit with 120 gallon volume tankl w/twelve 10-gallon accumulator bottles and nitrogen back-upsystem. 1 ea 5 station, remote control panel 1 ea 5,000 psi choke manifold with Cameron automatic hydraulic choke 3" - 10,000 psi with control choke panel. 1 lot Hydraulic pipe and fittings from manifold to BOP stack. Swanson River Well #SCU 243B-4 Bottomhole Pressure Information The following presents data used for calculation of anticipated surface presures (ASP) during drilling of the SCU 243B-4. The pore pressure gradient was estimated from the following information: BHP Depth Well psi TVD SCU 243-4 2575 5624 EMW, ppg 8.8 SCU 243-4 2520 5440 8.9 SRU 242-16 1300 3161 7.9 Comment 8/61, initial BHP before production 8/61, initial BHP before production 9/89, initial BHP before production The fracture gradient at surface casing point was conservatively estimated at .80 psi/ft or 15.4 ppg. Casing Pore Casing Setting Fracture Pressure Mud Pore ASP Size Depth Gradient Gradient Weight Pressure Drilling (in.) (TVD ft) (Ibs/clal) (Ibs/.qal) (Ib/.qal) (psi) (psi) 7 2150 15.4 8.4 9.0 939 660 5 liner 6000 NA 8.9 9.5 2777 Procedure for Calculatinq Anticipated Surface Pressure While Drillinq ASP is determined as the lesser of 1) surface pressure at breakdown of the formation at the casing seat (with gas bubble just below shoe and mud gradient above shoe) or 2) formation pore pressure at the next casing point less 1/4 gas gradient and 3/4 mud gradient to the surface as follows: 1) ASP = (FGx.052xD) - (MWx.052xD) = (15.4x.052x2150) - (9.5x.052x2150) = 660 psi OR 2) ASP = FPP ~ (0.1gas gradient xDx.25) - (MWx.052xDx.75) = 2777 - (. 1 x6000x.25) - (9.5x.052x6000x.75) = 2777 - 150 - 2200 = 404 psi Kick Tolerance for SCU #243B-4 With 9.5 ppg mud in the hole and a gas bubble in the well and an estimated shoe frac gradient of 15.4 ppg, the shoe will fail at 660 psi of surface pressure ((15.4- 9.5)x,052x2150'). At the most vulnerable point for shoe failure wl~en the gas bubble is just below the 7" casing shoe, the hydrostatic pressure situation will be as follows: + 660 psi max surface pressure without fracturing the shoe + 21,50' x .052 x 9.5 ppg mud in the surface casing = 1062 psi + Gas height (Hr) x 0.1 psi/ft gas bubble just below surface casing + (6.000'-2150'-Ht) x .052 x 9.5 mud below the qas bubble 9~x .052 X 6000' TVD -- 2777 psi estimated formation pressure Solving the above equation for Ht: 660 + 1062 + 0.1Ht + (6000'-2150'-Ht).494 = 2777 660 +1062 +0.1 Ht + 1902 - .494 Ht = 2777 847 = .394 Ht Ht = 2149' (TVD height of gas'bubble just below shoe which will cause shoe fracture failure) The gas volume is 2149' x (.023 bbVft for a 3.5' Drill pipe x 6" annulus) = 49 bbl If the gas volume at the shoe is 49 bbl, then the original gas kick volume when it first entered the wellbore at 6000' 'rvD would be: P~ xV~ = P2xVz P~ = 9.5 x 6000' x .052 = 2964 psi hydrostatic pressure at TD Vt = X, unknown gas volume at TD P2 = (660 psi surf pressure w/o fracturing shoe) + (9.5 ppg x .052 x 2150') = 1722 psi pressure at shoe V2 -- 49 bbl gas bubble just below 7" shoe V~ =49 bbl x 1722 psi/2964 psi = 28 bbls kick tolerance at 6000' TVD. This size of kick should be able to be detected with close monitoring of the trip tank and with the help of a mudlogging unit which will be operating during the drilling of this well. 06/21199 SCU ¢P_43B4 SCU #243B-4 Casing Design 7" Surface Casinq, 29# L-80, Buttress Worst case for burst is tubing leak near the surface after the well is completed. Burst = 6000'TVD x((8.9 formation x .052) - 0.1 gas grad)) 29# rated @ 8160 psi for burst = 2177 psi Safety Factor = 3.7 OK Worst case for collapse is if lost returns occur while drilling below the 7" surface casing. Collapse = (8.4x.052x2150') -(2150' x .1 ) = 724 psi for full evacuation Tension = 29 x 2150' = 62,350# 5" 15#, L-80, TKC buttress liner @ 6000' MD/TVD Tension = (6000'-1950') x 15#= 61K 29# rated @ 7020 psi for clpse Safety Factor = 9.7 OK 29# rated for 676K Safety Factor = 10.8 OK Rated = 350K for body yield Safety Factor = 5.7 OK Worst case for collapse of the liner would be when the completion interval depletes and a formation with virgin pressure is behind pipe. Collapse = (8.9 x .052 x 6000') - 0 psi inside = 2777 psi (Unrealistic but worst case) Rated = 7250 psi for collapse Safety Factor 2.6 OK Worst case for burst would be a tubing leak with gas in the annulus, the effective burst pressure at the liner top at 1950' would be: Burst = (6000'x8.9 formation x .052) - (0.1 gas grad x1950') Rated = 8290 psi for burst - (8.4 x .052 x1950')= 1730 psi Safety Factor = 4.8 OK SCU #243B-4 Casing Specifications Proposed Casing Surface Liner 7" 29#, L-80, AB mod Butt 5" 15#, L-80, TKC Buttress Joint Strength, K lbs 746 350 Body Strength, K lbs 676 396 Burst Rating, psi 8,160 8,290 Collapse Rating, psi 7,020 7,250 Max Torque, fi-lbs 12,000 7,700 Opt Makeup, ft-lbs to triangle 3,140 Min Make-up 6,000 2,900 CSGSPEC243B-4.XLS SCU 243B-4 Cementing Program 7" Surface Casinq 8-1/2" hole @ 2150' MDFFVD Cement volume for surface casing: Lead cement Class G with additives at 12.9 ppg: 1650' x 0.127 cuft/ft (8-1/2" x 7") x 2.0 (100% excess) = 419 cuft Tail Cement Class G with additives at 15.8 ppg: 500' (2150'-1650') x 0.127 cuft/ft x 2.0 (100% excess) = 127 cult 80' float joints = 80' x .2085 cuft/ft = 16 cuff Total Tail = 143 cult Total cement = 419+143 = 562 cult 5" Liner 6" hole @ 6000' MD/6000' TVD, top of liner at 1950' MD Cement volume for liner based on open hole volume plus 50%, liner lap, and shoe joints. Estimated volume is: 3850' (6000' - 2150') x 0.0600 cuft/ft (6"x 5") x 1.50 = 347 cuft 200' liner lap @ 0.0722 cuft/ft = 14 cult 80' shoe jts x 0.1059 cuft/ft (5" liner capacity) = 8 cult Total Cement = 347 + 14 +8 = 369 cult Class G cement @ 15.8 ppg with additives. UNOCAL DRILLING FLUIDS PROGRAM SWANSON RIVER WELL SRU 243B-4 OVERVIEVV The SRU ¢Y243B-4 is a grass roots well in the Swanson River Field. Potential problems in the surface interval include gravel, coal and lost circulation. Maximize use of solids equipment in order to avoid overloading the system with sand. The production interval will be ddlled with a conventional Iow-solids non-dispersed mud system. A lubricant may be used if torque becomes a problem. 13 3/8" CONDUCTOR: (DRIVEN TO +/- 80') 8 1/2" SURFACE INTERVAL: (0- 2100' MD) A standard fresh water Gel/Gelex spud mud will be used in the surface hole. Initial funnel viscosity should be in the 100 - 125 sec./qt, range. Adjust viscosity as needed for large gravel zones. Lower fluid loss to 10cc's with Aquapac or Drispac LV prior to running casing. Lower gels if needed with Spersene. Fluid Properties- Surface Hole · , . .,. Density (PPG) Funnel Viscosity Yield Point Fluid Loss pH 8.6 - 9.0 100 - 125 sec/qt 20 - 40 N.C. - 10 cc/30 rain 8.5-9.0 Evaluate the surface mud for possible use in the production interval. If unsuitable, plan on discarding and follow the plan listed below. CASED HOLE DISPLACEMENT TO LSND FLUID 1. Drill out intermediate casing plus 10' of new hole with existing mud system. o . Clean pits and build new Iow-solids non-dispersed drilling fluid. · Displace well to LSND mud as follows. Pump 25 bbls fresh water with one drum Safekleen followed by 25 bbls water viscosified with 3 ppb FLO-VlS (weight up as needed with Barite for well control). Follow with the LSND fluid. . Pump at highest rate practical. Aggressively rotate and reciprocate pipe while displacing. Make sure bit is on bottom when leading edges of spacers and LSND fluid are at the bit. Calculate strokes and monitor returns at the flowline. Discard spacers until clean LSND returns are observed. Make sure all pits and lines are cleaned prior to adding additional fluid to the pits. (TM9909) (04/99) 6" PRODUCTION INTERVAL: (2300'-6000' MD) The 8 1/2" hole will be drilled with a LSND fluid. Control fluid loss at +/- 5 cc's with additions of Ddspac and/or Resinex. Use barite for weighting up as needed. Add Soltex @ 2 PPB for coal stabilization. Run as fine of mesh shaker screens as possible. Centrifuge mud system both while drilling and during trips. Bit/BHA bailing from sticky clays can be treated with Ddlling Detergent, Drill-Kleen, SAPP and/or Nut Plug sweeps. Lubetex can be used to reduce torque and drag. Use Defoam-X if foaming becomes a problem. Drill to T.D. If hole conditions warrant, spot a viscous pill on bottom. Run and cement casing. Fluid Properties - Production Interval (LSND Fluid) Density Plastic yield Geis Fluid Ddll (PPG) , Viscosity Point 10s/10m Loss ., pH Solids 9.0-9.5 10- 16 15-20 10- 15 + 5 cc ~.5-9.0 < 5% , ,. LOST CIRCULATION CONTINGENCY SEEPAGE LOSSES: For seepage losses add 5 - 10 PPB of Liquid Casing while drilling. MODERATE LOSSES: Mix 10 - 30 PPB of M-I Seal Fine & Medium while drilling and/or spot pills across loss zone. Check motor orifice and tool size restrictions. SEVERE LOSSES: For severe losses due to fractures, faults, rubble zones. Mix and spot a 40 bbl 50 PPB LCM pill with M-I Seal Medium, Coarse and Nut Plug Coarse. Puli up into casing shoe and squeeze pill into loss zone with 200 psi, shut in and watch for pressure bleed-off. When pressure holds for 15 minutes resume drilling. Pdor to pumping coarse pills, check motor orifice and tools for size restrictions. NOTE: Liquid Casing will pass through 60-80 mesh screens. · Liquid Casing and OM Seal will lower pH rapidly -increase Caustic Soda additions accordingly. · At 6-8 ppb, Liquid Casing and OM Seal will raise YP significantly and PV about 3 cps. Volume Usa,g; and Cost Estimate ,. Interval Surface Production Total Volume 990 760 1750 Material Cost $4,000 $13,000 $17,000 Engineering $4,375 $6,250 $10,625 (TM9909) (04/99) Drilling Fluid System Description Inlet Drilling Rig #CC-1 Mud Pumps 1 ea PZ9 Gardner Denver, 3" x 5000 psi shear release valve and a 4" x 4000 psi gates bumper hose powered by a 398 TA Cat. 1 ea 214P Oilwell powered by twin 671 Detroit diesel engines. Mud Tank System (466 bbl Total Volume) Tank A- 88 bbl suction tank Tank B- 150 bbl middle tank Tank C- 172 bbl shaker tank Tank D- 27 bbl pill tank Tank E- 17 bbl centrifuge tank Tank F- 12 bbl sand trap Trip Tank- 35 bbl 501 bbl total Mud System Equipment 1 ea 1 ea 1 ea 1 ea 1 ea 3 ea Brandt dual tandem 800 gpm shale shakers Drilco See-FIo degasser 36"x 6' Poor Boy gas buster Pioneer eight cone desilter Pioneer Model S-800 mud hopper Medearis 3" revolving mud agitator guns 1 ea 1 ea 1 ea Pit level indicator with audio and visual alarms Fluid flow sensor Gas monitoring for H2S and LEL with sensors at rig floor, sub and shakers. MUD TANKS ATTACHMENT E _[. DATE INvoICE/CREDIT MEMO NO. ............... 17-MAY-99 DRILLPERMITSRU4 VOUCHER NO. 05993000236 FORM 4-2B181 (REV. 11-95)PRINTED IN U.S.A. " .......................... ]";~)-~LL-~"' VENDOR NO. 1031548 GROSS DISCOUNT 100.00 100.00 DATE I CHECK NO. 05-17-991 -200356~¢ NET 100.00 100.00 CITIBANK DELAWARE 62-20 A Subsidiary of Citicorp '",.' 311 ONE PENN'S WAY NEW CASTLE, DE 19720 Union Oil Company of California Accounts Payable Field Disbursing UNOCAL PayOne Hundred Dollars And 00 ******************************* 2005565 To the order of STATE OF ALASKA ALASKA OIL & GAS CONSERVATION COMMISSION 3001 PORCUPINE DR ANCHORAGE, AK 99501 "' 200 :~ 5 Date V 17-MAY- 9 9 Check Amount ** * 10 0.0 0 :~om above date. __ wellbore seg ann. disposal para req __ WELL PERMIT CHECKLIST FIELD & POOL ADMINISTRATION 1. APPR DATE ENGINEERING INIT CLASS ,~~ ,,/-4:~'~~'' GEOL AREA ~:~_~_~:~:~ UNIT# Permit fee attached ....................... 2. Lease number appropriate ................... 3. Unique well name and number .................. 4. Well located in a defined pool .................. 5. Well located proper distance from drilling unit boundary .... 6. Well located proper distance from other wells .......... 7. Sufficient acreage available in drilling unit.. 8. If deviated, is wellbore plat included..--.,,',-,,~. 9. Operator only affected party ................... 10. Operator has appropriate bond in force ............. 11. Permit can be issued without conservation order ........ 12. Permit can be issued without administrative approval ...... 13. Can permit be approved before 15-day wait ........... 14. Conductor string provided ................... (~ N 15. Surface casing protects all known USDWs ........... (,~ N 16. CMT vol adequate to circulate on conductor & surf csg ..... Q~ N 17. CMT vol adequate to tie-in long string to surf csg ........ .~.. N 18. CMT will cover all known productive horizons .......... C~ N 19. Casing designs adequate for C, T, B & permafrost ....... (~ N 20. Adequate tankage or reserve pit ................. ~ N 21. If a re-drill, has a 10-403 for abandonment been approved... 22. Adequate wellbore separation proposed ............. 23. If diverter required, does it meet regulations .......... 24. Drilling fluid program schematic & equip list adequate ..... 25. BOPEs, do they meet regulation ........ ' ........ 26. BOPE press rating appropriate; test to ~ OO~ psig. 27. Choke manifold complies w/APl RP-53 (May 84) ........ N 28. Work will occur without operation shutdown ........... 29. Is presence of H2S gas probable ................. Y (~ GEOLOGY 30. 31. 32. 34. ANNULAR DISPOSAL 35. APPR DATE Permit can be issued w/o hydrogen sulfide measures ..... ~YY N ~ ~:¢~ Data presented on potential overpressure zones ....... Y N . Seismic analysis of shallow gas zones ............. .. Seabed condition survey (if off-shore) ............. ,/ Contact name/phone for weekly progress reports [exploratory,~ly] Y N With proper cementing records, this plan (A) will contain waste in a suitable receiving zone; ....... Y N (B) will not contaminate freshwater; or~'drilling waste >..~'. Y N to surface; ....-~"' ~ _ ~ (C) will not impai~'fiechanical in--'tegrity of the well used'for disposal; Y N (D) will not d.,,am'age producing formation or impair recovery from a Y N pool; ana (E) will not circumvent 20 AAC 25.252 or 20 AAC 25.412. Y N ON/OFF SHORE (~/? .) GEOL~¢'~ ENGINEERING: UlC/Annular/ COMMISSION: JDH ~ / co Comments/Instructions: c:\msoffice\wordian\diana\checklist