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186-155
STATE OF ALASKA RECEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION MAY 31017 APPLICATION FOR SUNDRY APPROVALS lis j7g / 20 AAC 25.260 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ RepairlVe9 ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑+ • Perforate New Pool ❑ Re-enter Susp Well E] Alter Cesing 1-1 Other ReservofrAbandonment •� 2. Operator Name: 4. Current Well Class: 5. Permit to DNI Number. Hilcerp Alaska LLC Exploratory E3 Development 0166-155 3. Address: 3900 CrDr, Suite 1400 SVatigraphic E] Service © 6. All Number. Anchhooraagege Alaska 99503 What Regulation or Conservation Order govems well spacing in this pooi? C.O. 462.007 ✓ Will planned perforations require a spacing exception? Yes ❑ No Q ❑11(`X iC i IAIIT snl 2 �o ENDICOTT! ENDICOTr OIL ooecerr u.�. , Total Depth MD (ft): Total Depih TVD (8): EfterAive Depth MD: Effective Depth TVD;•" MPSP (psi): Plaga (i+;D,'.: f11,6D(y. Junk (MD): -1T 10.538' 11,655' 10,428' 900 11.655' Casing Length size MD TVD Hurst WA Collapse Conductor 161' 30" 161' 161' WA Surface 2,483' 13-318" 2,483' 2,483' 5,380pd NIA 2,6 d Production�P 6,037' 9-5/8" 6,037 5,739' fi,970psi 4,780psi Production 4,896' 9-5l8" 10,933' 9,789' 81 If 5,090 sl p Liner 1,095' T' 11,778' 10,538' 8.160ps1 7,020pd Perforation Depth MD (0): Perfaralicn Depth ND (8): Tubing Size: Tubing Grade: ArPing MD (ft} 4'1!2" 12.61 L•801 TDS 10,614 3-1/2" 9.2/L-W/TDS 11,188 See Attached Schematic See Attached Schematic 2-7/A" 6.4/L -80I WA Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 11,188' 9-5/8"X4-1/2"TIW HBBP,7"x3-11T TIW HBBP, T'x 3-1/2"Otis M&7'x 10,614'MD/9,513'TVD,11,186'MD19,994TVD, 11.365'6rD' 10,1 1/2" Oti$WD and 4-1l2" SSSV 70TVD&f1430'MDl 10,228TVD and 1,51TMQ' 1,612'TVD , 12. Attachments: Proposal Summary � Wellbore schematic �j 13. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch u Exploratory ❑ Stratigraphic ❑ Development Q Service ❑ 14. Estimated Dale for 15. Well Status atter proposed work: Commencing Operations: 6/18/2017 O!L%i WINJ ❑ WDSPL ❑ � Suspended 16. Verbal Approval: Date: GAS ' - WAG ❑� L $ i7 ❑ G6TOR ❑ L✓_I`_ - Commission Representative: SPLUO ❑ GINJ EJOp Shutdown ElAbandoned ❑ 17 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorizetl Meme: Bo York Contact Name;T Authorized T81e: Operations Manager Tffor Wellmanan loc I- -y3 �� Corded Email: _/ Aulharizetl Signature: "~-' "` Date: 5/26ZO17 Contact Phone: 717.8449 COMMISSION USE ONLY Condaions of approve C>u otify Commission so that a representative may witness Sundry Number. 3 k7- 22( �(/ Plug Integrity ❑ BOP Test Ll Mechanical Integrity Ted E3Location Clearance El Other. Post Initial Injection MIT Req'd? Yes ❑ No ❑� Spacing Exception Required? Yes ❑ No ER/ Subsequent Form Required: 0 O APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 6 _ �P a aua ror i z MOMMS Prom the date of approval. -__""" m ' ( ��Attya�cchments in nuplicata �WPA C . 7 7 ff Aaaoro Aloka Lb Decompletion Well: END 3-23 Date: 05/30/2017 Current Bottom Hole Pressure: 4,498 psi @ 10,000' TVD (BHP Survey 03/13/17; EMW = 8.65 ppg Maximum Expected BHP: 4,498 psi @ 10,000' TVD (BHP Survey 03/13/17; EMW = 8.65 ppg) Current Shut-in Tbg Pressure: 900 psi Max. Predicted Surf Pressure: 900 psi (Max tbg pr ssure recorded w/o plug in tailed) � Brief Well Summary: A14. AW P 64Lc-. -a te G-7- /7 The Endicott 3-23 well was drilled in 1986 and completed in September of 1987. The well was completed as a 5d�ultizone producer from the K3A and Upper sub zones in the Kekituk formation. The well developed TxIA communication in 2005 and has a secondary seal failure of the IC hanger. The TxIA communication and the �C, limited economic benefit that the well has remaining is the reasoning that the well has been along term shut in ` since 2005. 'r CA'&r. 7'Ar (ofr Owi-,/ rt1`f p ars lb flow 74rS nail 1j•c%>!C.( < 10 objective: '4pr v cwttr yvt of .�' 9"l� lk f nt,} re*%6 fa ta^(^'H f,�vv/•( anis i Gar i Ze AS c o perfor {res %ir In , �G 1f7 Ce The objective is to use t e ASR #1 to perfor a reservoir aban onmen of the curve formations exposed and to decomplete the well in preparation for sidetracking the well with the Innovation Rig. Saftev Note: Many wells at Endicott have high H2S readings (>250ppm) in the gas lift or gas injection system. The Endicott 3- 23 well has not flowed since 2005 so accurate sampling has not been obtained but standard precautions and an additional section in the Sundry Review Meeting should be highlighted to handle potential H2S, especially ✓ during the circ out and loading of the well. Brief Procedure: Pre -Ria Procedure E -Line 1. RU SL. Pressure test PCE to 250psi low/2000psi high. 2. MU tbg punch toolstring, RIH and punch tubing tail from #10,628'-10,632' md. a. Correlation Log: Tubing Tally dated 09/23/87. b. Well was drifted on 1/25/17 w/ a 3.75" gauge ring to 10,624' md. See WSR for full details. ✓ 3. MU jet cutter, RIH, and jet cut tubing mid joint in the first full joint above GLM #1 at ±10,445' md. a. Note any T/I/O changes in the WSR. 4. RD EL. Operations & Pumping S. Clear and level pad area in front of well. Spot rig mats and containment. 6. RD well house and flowlines. Clear and level area around well. 7. RU Little Red Services Pump. Setup reverse out skid and 500 bbl returns tank and additional upright tanks as needed. 8. Pressure test lines to 3,000 psi. API Number: 1645-00-00tatus: Pad: Start Da2017 Rig: OWellName:e:CEND3 oval Req Date Reg. Approval Rec'vd: t(907) Contacts 777-8398 Permit to Drill Number:Engineer:ellman (907) 777-8449 (0) -9533ll Enginehola (907) 777-8412 fo) -8228 (M) AFE Number: I WellEZ Input Required: I Yes Current Bottom Hole Pressure: 4,498 psi @ 10,000' TVD (BHP Survey 03/13/17; EMW = 8.65 ppg Maximum Expected BHP: 4,498 psi @ 10,000' TVD (BHP Survey 03/13/17; EMW = 8.65 ppg) Current Shut-in Tbg Pressure: 900 psi Max. Predicted Surf Pressure: 900 psi (Max tbg pr ssure recorded w/o plug in tailed) � Brief Well Summary: A14. AW P 64Lc-. -a te G-7- /7 The Endicott 3-23 well was drilled in 1986 and completed in September of 1987. The well was completed as a 5d�ultizone producer from the K3A and Upper sub zones in the Kekituk formation. The well developed TxIA communication in 2005 and has a secondary seal failure of the IC hanger. The TxIA communication and the �C, limited economic benefit that the well has remaining is the reasoning that the well has been along term shut in ` since 2005. 'r CA'&r. 7'Ar (ofr Owi-,/ rt1`f p ars lb flow 74rS nail 1j•c%>!C.( < 10 objective: '4pr v cwttr yvt of .�' 9"l� lk f nt,} re*%6 fa ta^(^'H f,�vv/•( anis i Gar i Ze AS c o perfor {res %ir In , �G 1f7 Ce The objective is to use t e ASR #1 to perfor a reservoir aban onmen of the curve formations exposed and to decomplete the well in preparation for sidetracking the well with the Innovation Rig. Saftev Note: Many wells at Endicott have high H2S readings (>250ppm) in the gas lift or gas injection system. The Endicott 3- 23 well has not flowed since 2005 so accurate sampling has not been obtained but standard precautions and an additional section in the Sundry Review Meeting should be highlighted to handle potential H2S, especially ✓ during the circ out and loading of the well. Brief Procedure: Pre -Ria Procedure E -Line 1. RU SL. Pressure test PCE to 250psi low/2000psi high. 2. MU tbg punch toolstring, RIH and punch tubing tail from #10,628'-10,632' md. a. Correlation Log: Tubing Tally dated 09/23/87. b. Well was drifted on 1/25/17 w/ a 3.75" gauge ring to 10,624' md. See WSR for full details. ✓ 3. MU jet cutter, RIH, and jet cut tubing mid joint in the first full joint above GLM #1 at ±10,445' md. a. Note any T/I/O changes in the WSR. 4. RD EL. Operations & Pumping S. Clear and level pad area in front of well. Spot rig mats and containment. 6. RD well house and flowlines. Clear and level area around well. 7. RU Little Red Services Pump. Setup reverse out skid and 500 bbl returns tank and additional upright tanks as needed. 8. Pressure test lines to 3,000 psi. UDecompletion ru7M,,,v.,k..ir Well: END 3-23 Date: 05/30/2017 9. Forward circulate at least one wellbore volume with 8.8 ppg brine down the tubing (thru tubing cut @ ±10,445' md), taking returns up the annulus to the 500 bbi returns tank. (i a. Annular volume from cut @ 10,445'= 560bbls G,ry �� b. Tbg volume to the cut @ 10,445'= 159bbls C. Total volume = 719bbls �✓ 10. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH or diesel. 11. RD Little Red Services Pump and reverse out skid. 12. RU crane. Set BPV. NO Tree. NU 13-5/8" DOPE. RD crane. 13. NU DOPE house. Spot mud boat. WO Rig Procedure: 14. MIRU Hilcorp ASR #1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. 15. Pull BPV. Bleed any pressure off tubing and casing. 16. Kill well w/ 8.8 ppg brine as needed. Set TWC. 17. Test DOPE to 250 psi Low/ 3,000 psi High, annular to 250 psi Low/ 2,500 psi High (hold each Qli ram/valve and test for 5 -min). Record accumulator pre -charge pressures and chart tests. r(Y a. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015. u7 b. Notify AOGCC 24 hrs in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VOR rams on 3-1/2" & 4-1/2" test joints. '18. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) a. Notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. b. With stack out of the test path, test choke manifold per standard procedure c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well, Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 19. Pull TWC. Bleed any pressure off tubing and casing to 500 bbl returns tank. Kill well w/ 8.8 ppg brine as needed. 20. MU 4-1/2" landing joint (TDS) and BOLDS. 21. Pull over string weight (PUW's were not recorded during the original completion in 1987) on tubing hanger to confirm free. LD tubing hanger. a. 10,445' of 4-1/2" tubing=131.6k # dry / 113.9k # buoyed in 8.8ppg brine. b. Contingency: (If a rolling test was conducted.) L MU new hanger or test plug to the completion tubing. Re -land hanger (or test plug) in tubing head. Test DOPE per standard procedure. C. Contingency:1If the tubing hanger will not pull and it is determined to be a pulling capacity limitation vs. a partial tubing cut) i. RU Casing jack Hydraulics to the ASR#1 control Panel. Set pressure relief high point as 2,038 psi (equates to -230.4k # or 80% of yield strength). ry UDecompletion Hac , Alaska. LG Well: END 3-23 Date: 05/30/2017 ii. Yield strength of 4-1/2", 12.6#, L-80 = 288k #, and the Mannesmann TDS connections = 288k #. iii. Cycle jacks up and down to ensure proper function (dry run without being connected to L' hanger). j 3 iv. Set Casing Jack pressure to 1,415 psi (160,000 lbs). Slowly pressure up on jacks. Hold for 0 5 min. v. If hanger does not unseat, increase pressure in 10k # (`88psi) increments holding for 5 min between pressure increases. Note: do not exceed 2,038 psi (230,400 #). If unmoved contact Ops Engineer for further discussion. 22. RU Spoolers and continue to pull 4-1/2" tubing from cut at ±10,445', and lay down the same in singles. a. From 0-1,512' there are two 34" control lines (balance and control line) to the OTIS BVN nipple. 23. PU 3-1/2" workstring and MU 9-5/8" mill and casing scraper assembly. 24. TIH to above tubing stub and reciprocate around the following depths: ±10,400' & ±8,300' and (around the cement retainer set depths). POOH. a. Note the PUW's from the bottom to be used for setting the shear pins on the retainers to be used. 25. MU 9-5/8" cement retainer BHA and RIH to ±10,400' Md. a. Confirm shear pin setting for release from the retainer with the service hand prior to TIH. b. Typical overpull to release from retainer is set to 50k# but can be adjusted. C, 26. Set cement retainer at ±10.400' md. I b/q v 0 a. Rotate the workstring to the right as per the tool service representative for minimum number of turns fully set the retainer. 27. Unsting from the retainer, pick up 20 and conduct an n t MIT (charted oh—g 2�4a�ing to 3000psi for 30min. )� Ga'S.I t 5; 28. Sting into the retainer. Line up pumps and obtain injectivity test down the workstring up to Sbpm. �.c° 29. Unsting from the retainer. 30. Begin mixing cement and pump 65bbis of !S-8p-1?g Class G cement through the workstring. Once the cement is almost to the retainer, come down on the pumps and sting back into the retainer and pump the cement into the formation. When 7 bbls from fully displacing all cement, come down on pumps, unsting from retainer and then allow final 7bbls to U -Tube out of the pipe. 31. PU 200' above the retainer and reverse circulate with 8.8ppg brine as needed until clean returns are observed. POOH. a. The TOC should be= 26' above the retainer. 32. RU E -Line unit. MU 9-5/8" CIBP toolstring. ,(Qj 33. RIH and log a CCL pass from ±8,700' to 7,700' Md. Set 9-5/8" CIBP at ±8,370' Md. 1�t 34. POOH and RD E -Line unit. V335. MU cement retainer/perfgun BHA. a. Confirm shear pin setting for pressure required to fire guns with tool service technician. f-ZAW^111-36. TIH and set retainer at ±!,32W m a. Set depth to be adjusted based on the CCL log run with E -Line to ensure not set across a collar. F 37. Pressure up the tubing to fire 4-5/8" guns from ±8,330'-8,340' Md. 38. Line up and pump down the workstring to confirm injectivity thru the perforations for -1 bbl. 39. Unsting from the retainer. 40. Begin mixing cement, pump g9WI of 15APp9 Class G cement into the workstring. Once the cement is almost to the retainer, come down on pumps and sting back into the retainer. Continue pumping and squeeze the cement through the retainer into the formation. When 2 bbls from fully H namra Alaska, IL Decompletion Well: END 3-23 Date: 05/30/2017 displacing all cement, come down on pumps, unsting from retainer and PU ±15'. Allow final 2bbls to U -Tube out of the pipe. a. If the formation locks up, unsting from the retainer, and circulate out the remaining cement. 41. While still located with the stinger±15' above the retainer, reverse circulate as needed until clean returns are observed. POOH. a. Alternative way to clean workstring of cement is to launch foam ball and chase with 8.8ppg brine. Method to be determined following the first cement job. 42. POOH while laying down the 3-1/2" workstring. 43. PU 4-1/2" kill string and TIH to±3,000' md. 44. RU Pump Truck. Freeze Protect down back side (± 35 bbls. to 500') and allow to U-tube. 45. Land tubing in hanger. RILDS. Lay down landing joint. 46. Set BPV. Test tubing hanger to 250/5,000 psi thru test port. 47. RD Hilcorp ASR #1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. Post -Rig Procedure: 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. Pull BPV. Set TWC. ND BOPE. 3. NU existing 4-1/8" 5,000# tree. Test tree to 250/5,000 psi. Pull TWC. RD crane. 4. Move 500 bbl returns tank and rig mats to next well location. S. Replace fA& OA pressure gauges if removed. 6. Turn well over to production. RU well house and flowlines. Attachments: I. As -built Schematic 2. Proposed Schematic 3. BOPE Schematic 4. FWD Circ to Kill Tank Flow Diagram 5. REV Circ to Kill Tank Flow Diagram 6. Bleed to Pits Flow Diagram 7. Blank RWO Changes Form OiigirallBE=55.5'/BFE=jfa8' i SG 9 70 11 12 DIU - Endicott Well: END 3-23 SCHEMATIC Last Completed: 9/25/1987 TUBING DETAIL JEWELRY DETAIL - 75 PTD: 186-155 TU.HEAD -- 7" x 3-1/2" Otis WD Packer --- -- ---- CIW 11,436' OpENHOLE/LEMENTDETAIL FMC 30' Driven NATION DETAIL 13-3/8" 3,255 cu. ft Permafrost, 233 cu. It, 11,447 2-7/8" WLEG, (2.441" ID, Bottom @11,443' Permafrost Lop job In 17-1/2!' Hole I deg. 7,460 9-5/8" 575 cu. ft Class "G" in 121/4" Hole - 7" 365 cu. R. pass "G" in 8-1/2" Hole rt: 28 Deg. @ 11,007' 11,048' 11054' CASING DETAIL 91895' Wt/Grade/Conn ID ToP Btm BPF N/A N/A Surf 161 N/q 72 / L-80 / Bt_12347 9,964' Surt 2,483' 0.1481 47 / NT80S / NSCC 8.681 Surf 6,037' 0.0732 471 N795HS I Ntrf-___-. 11,130 _ TUBING DETAIL JEWELRY DETAIL _ 1s m �1 22 lei 24 25 2F 7" - 75 23 11,430' 7" x 3-1/2" Otis WD Packer ,��-,7�p 16 24 11,436' 2-7/8"X Nip (2313"ID) {� n 17 25 11,439' 2-7/8" X Nip 2.313" IDj f� 18 26 11,447 2-7/8" WLEG, (2.441" ID, Bottom @11,443' 11,018' 11,032' 9,864' PERFORATION DETAIL - Sands T UPSZ FIII _ 1s m �1 22 lei 24 25 2F 7" TO=11,77$ (ND)/TO=10,ILV(M) SAFETY NOTE - PETE) = 11,659 (W) OTE-PETE)=11,659(MD)/ PBTD= 1Q428'(7VD) API: 5E)-029-21645-00-00 MM91RevisedBT.DH4/10/20j7 rage 230-260 ppm on A/Land Completed -9/25/1987 ll requires a SSSV. Possible tubing from packer squeeze (1 - tubing, finer andjewel Revised BY: DH 4/10/2017 (Mp) Btm (MD) Top (TVD) Btm (TVD) FT Date Status UPSZ Fill 111007' 11,013' 9,854' 91859' 6 9/19/2001 Open UPSZ FIII 11,018' 11,032' 9,864' 9,876' 14 9/79/2001 Open UPSZ FIII 11,048' 11054' 9,890' 91895' 6 9/15/2001 Open UPSZ FII 13,300 1I,132' 91936' 9,964' 32 9/21/1987 Open UPSZ Fit 11,110 11,130 9,945' 91962' 20 11/08/1998 Open UPSZF1 11,150' 11,158' 9,980 91987' 8 9/22/1987 Open 53A4 11,224' 11,258' 10,045' 10,075' 34 9/21/1987 Open 53A3 14266 1 11,304' 1 10,082' 10,116' 38 1 9/21/1987 1 Open 53A2 11,340 1 11,354' 1 10,148 10,160 14 1 9/21/1987 I Open GENERALWELLINFO TO=11,77$ (ND)/TO=10,ILV(M) SAFETY NOTE - PETE) = 11,659 (W) OTE-PETE)=11,659(MD)/ PBTD= 1Q428'(7VD) API: 5E)-029-21645-00-00 MM91RevisedBT.DH4/10/20j7 rage 230-260 ppm on A/Land Completed -9/25/1987 ll requires a SSSV. Possible tubing from packer squeeze (1 - tubing, finer andjewel Revised BY: DH 4/10/2017 DIU We - Endicott END 3-23 SCHEMATIC PROPOSED Last )Completed: 9/25/1987 I[ileorp Ahsk% T,r,c .__ _ PTD: 186-155 TREE&WELLHEAD -- OPEN HOLE / CEMENT DETAIL Original KBE =55,5/BFE=16.8' ^Tree �iJ TOC@ 310 301' 6 9-5/8"0 Mn ID= 2.313' 017,176 72 to 14 15 18 17 �s 4 119 'p b Size I Type I Wt/Grade/Conn I ID 8.681 3Qjkjj] 13-3/8ermafrost, 233 cu. ft.op'ob in 17-1/2"Hole9-5/8"ss 1 "G" in 12-1/4" Hole7"ss 9-5/8" Cemen[ Retainer/Pert Gun "G" in 8-1/2" Hole Btm I BPF TUBING DETAIL 4-1/2" Tuhing126/L-80/TDS Surf :a rrvr JEWELRY DETAIL No Depth Item 1 ±%32CY 9-5/8" Cemen[ Retainer/Pert Gun 2 18,370' 9-5/8"CIBP 3 11011400' 9-5/8" Cement Retainer 4 10,436' ST1:POrt=O,Dev=31, VN=Dumm ,TVA 9,360', Date= 4-10-2005 5 10,542' 4.1/2" Otis XA Sliding Sleeve, (3.813' ID) 6 10,599' TIW Seal Assembly 7 10,614' 9-5/8"X4-1/2" TIW HBBP Packer w/latch,(3.928'ID) 8 10,624' 4-1/2" x 3-1/2" XU, (2.992" ID) 9 10,683 9-5/8"x7" Baker Liner Hanger 10 11,079' 3-1/2" Otis Ported Nip (2.66' ID) 11 11,091' 3-1/2" Blast lcints (4) 69.25' long) 12 13 11,166' 11,176' 7"x3-1/2"TIW HBBP Packer 2-7/8" X Nip (2.313" ID) 14 11,182' 7-7/8" X Nip (2.313" ID) 15 11,188 2-7/8" WLEG, 2.441" ID), Bottom @11,189' 16 11,355' 7" x.3-1/2' Otis WD Packer 17 11,371' 2-7/8" X Nip (2.313" ID) 18 11,374' 2-7/8" X Nip (2.313" ID) 19 11,377' 2-7/8" W LEG, (2.441" ID), Bottom @11,378' 20 11,430' 7"X3 - "x3 -21 21 11,436' 2-7/8" X Nip (2,313" ID) 22 23 11,439' 11,442' 2-7/8" X Ni (2.313" IN 2-7/8" W LEG, (2.441" V. Botinm 0 11 4aY PFBGnrlel'IAM ncreu Sands Top (MD) MD Eltm ( ) Tap (TVD) Btm (Tv0-) FT Date Status 18,210' 36,220 6 Future Future UPSZ FIII 11,007' 11,013' 9,854' 9,859' 6 9/19/2001 Closed UPSZ FIII 11,018' 11,032' 9,864' 9,876' 14 9/19/2001 Closed UPSZ FIII 11,048' 11,054' 9,890' 9,895' 6 9/15/2001 Closed UPSZ FII 11110(y 11,132' 9,936' 9,964' 32 9/21/1987 Closed UPSZ FII 11,110' 11,130' 9,945' 9,962' 20 11/08/1998 Closed UPSZ Fi 11,150' 11,158' 9,980' 9,987' 8 9/22/1987 Closed S3A4 11,224' 11,258' 10,045' 10,075' 34 9/21/1987 Closed 5303 11,266' 11,304' 1 10,082' 10,116' 38 9/21/1987 Closed 53A211,340 11,354' SQ 148' 101160' 14 9/21/1987 Closed 53A11 11,390' 1 11,414' 1 10,192' 10,214' 24 9/21/1987 ---- GENERAL WELL INFO SAFETY NOTE: API: 50 -029 -21645 -OD -00 H2S readings average 230-260 ppm on A/L and 7" 1 Completed -9/25/1987 gas injectors. Well requires a SSSV. Possible TO=11,778' (MD) / TO=10,538'(TVD) cement sheath in tubing from packer squeeze (1- PBTD=11,655 (MD) / PeID= SQ42ff(IW) 5-1998). Chrome tubing, liner endjewelry. Revised By: TTW 5/22/2017 f • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 a.Well Status: Oil❑ Gas❑ SPLUG ❑ Other ❑ Abandoned ❑✓ ' Suspended❑ 1 b.Well Class: 20AAC 25.105 20AAC 25.110 Development Q • Exploratory ❑ GINJ ❑ WINJ ❑ WAGE WDSPL❑ No.of Completions: _0 Service ❑ Stratigraphic Test ❑ 2.Operator Name: 6. Date omp.,Susp.,or 14. Permit to Drill Number/ Sundry: Hilcorp Alaska,LLC Aband.: 8/25/2017 • 186-155/317-221 3.Address: . :: - ..added: 15.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 August 20, 1986 50-029-21645-00-00' 4a.Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 2759'FSL,769'FEL,Sec 8,T11 N, R17E, UM,AK • September 13, 1986 DIU SDI 3-23 • Top of Productive Interval: 9. Ref Elevations: KB: 40.2' • 17. Field/Pool(s): N/A GL: 13.7 BF: 16.2' Endicott/Endicott Oil Pool • Total Depth: 10.Plug Back Depth MD/TVD: 18.Property Designation: 3565'SNL,989'WEL,Sec 5,T11 N, R17E, UM,AK • 8,279'MD/7,537'TVD • ADL047502 • 4b.Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 270273 • y- 5970976 • Zone- 3 • 11,783'MD/10,542'TVD • N/A TPI: x- y- Zone- 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 270178 y- 5975179 Zone- 3 N/A 1,536'MD/1,536'TVD 5.Directional or Inclination Survey: Yes LI (attached) No ❑✓ 13.Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) N/A 22. Logs Obtained: List all logs run and,pursuant to AS 31.05.030 and 20 AAC 25.071,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first.Types of logs to be listed include,but are not limited to:mud log,spontaneous potential, gamma ray,caliper, resistivity, porosity,magnetic resonance,dipmeter,formation tester,temperature,cement evaluation,casing collar locator,jewelry,and perforation N/A RECEIVED Acronyms may be used.Attach a separate page if necessary ;;616.0 JPt", A ,3'`$ NOV 1 3 2017 ADCC 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD FT. PULLED 30" N/A N/A Surface 161' Surface 161' Driven Driven 13-3/8" 72# L-80 Surface 2,483' Surface 2,483' 17-1/2" 3255 ft3 9-5/8" 47# NT80 Surface 8,279' Surface 7,537' 12-1/4" 575 ft3 24.Open to production or injection? Yes ❑ No Q 25.TUBING RECORD If Yes, list each interval open(MD/TVD of Top and Bottom; Perforation SIZE DEPTH SET(MD) PACKER SET(MDlTVD) Size and Number; Date Perfd): N/A {{ R*tooNe0 • 26.ACID,FRACTURE,CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes ENo E. 8 jz5/17 if Per 20 AAC 25.283(i)(2)attach electronic and printed information DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): N/A N/A Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: Test Period ♦ Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 24-Hour Rate •• •Form 10-407 Revised 5/2017 /Q,-,7 CONTINUED ON PAGE 2 Submit ORIGINIAL only i l Z" c'Y 1 272• 7 RBDRIS I* !+!rte r I ' 7+117 ,4-b- — 2' f7 • • 28.CORE DATA Conventional Core(s): Yes ❑ No Q Sidewall Cores: Yes ❑ No If Yes, list formations and intervals cored(MD/TVD, From/To),and summarize lithology and presence of oil,gas or water(submit separate pages with this form, if needed).Submit detailed descriptions,core chips, photographs,and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No Q Permafrost-Top Surface Surface If yes, list intervals and formations tested,briefly summarizing test results. Permafrost-Base 1,536' 1,536' Attach separate pages to this form, if needed,and submit detailed test Top of Productive Interval N/A information, including reports, per 20 AAC 25.071. Toy° Irk I b,loB(v D;l$2 T �c � }uk 11,000 ok,39.Li Formation at total depth: N/A 1 l�83 10 St t2 31. List of Attachments: Wellbore Schematic, Decomplete Reports. Information to be attached includes,but is not limited to:summary of daily operations,wellbore schematic,directional or inclination survey,core analysis, paleontological report,production or well test results,per 20 AAC 25.070. 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Paul Mazzolini Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: cdingerp.cofll AuthorizedJ L/ Contact Phone: 777.8389 Signature: �� /•/ Date: [ 13 l7,, 7 INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed.All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC,no matter when the analyses are conducted. Item la: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class-Service wells:Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation, or Other. Item 4b: TPI(Top of Producing Interval). Item 9: The Kelly Bushing,Ground Level,and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 19: Report the Division of Oil&Gas/Division of Mining Land and Water: Plan of Operations(LO/Region YY-123), Land Use Permit(LAS 12345), and/or Easement(ADL 123456)number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and,pursuant to AS 31.05.030,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26.(Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift, Rod Pump, Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box.Pursuant to 20 AAC 25.071,submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results, including, but not limited to:porosity, permeability,fluid saturation,fluid composition,fluid fluorescence,vitrinite reflectance,geochemical,or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070,attach to this form:well schematic diagram,summary of daily well operations,directional or inclination survey,and other tests as required including,but not limited to:core analysis,paleontological report,production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only . . DIU - Endicott 14Well: END 3-23 SCHEMATIC Abandoned: 8/25/17 Hilcorp Alaska,LLC PTD: 186-155 TREE&WELLHEAD OPEN HOLE/CEMENT DETAIL Tree CIW 30" Driven Original KBE=55.5'/BFE=16.8' Wellhead FMC 13-3/8" 3,255 cu.ft.Permafrost,233 cu.ft. WELL INCLINATION DETAIL Permafrost top job in 17-1/2"Hole KO30'411 [ L P @ 3,478' 9-5/8" 575 Cu.ft.Class"G"in 12-1/4"Hole Max Hole Angle=38 deg.@ 7,460' 7" 365 Cu.ft.Class"G"in 8-1/2"Hole Max angle at Top Perf:28 Deg.@ 11,007' CASING DETAIL 3/8" Size Type Wt/Grade/Conn ID Top Btm BPF 30" Conductor N/A N/A Surf 161 N/A 13-3/8" Surface 72/L-80/Btrc. 12.347 Surf 2,483' 0.1481 9-5/8" Production 47/NT8OS/NSCC 8.681 Surf 6,037' 0.0732 TOW @8,279' 9-5/8" Production 47/NT95HS/NSCC . 8.681 . 6,037' 10,933' 0.0732 TOC @ BOW @ 8,296' 7" Liner 29/L-80/Btrc. 6.184 10,683' 11,778' 0.0371 8,302' .41/4 TUBING DETAIL ' 1 4-1/2" Tubing 12.6/L-80/Vam Top 3.958 Surf 2,950' 0.0152 JEWELRY DETAIL TOC@ No Depth Item 10,170' . : .4.a c; TbgCut 1 8,326.5' 9-5/8"Cement Retainer/Perf Gun 10,406' . , 3 2 8,423' 9-5/8"HES CIBP ‹'ri 3 10,376' 9-5/8"HES Cement Retainer 5 4 10,436' ST 1:Port=0,Dev=31,VIv=Dummy,TVD=9,360',Date=4-10-2005 ' • s` .r 5 10,542' 4-1/2"Otis XA Sliding Sleeve,(3.813'ID) s �.� r�' 4 6 6 10,599' TIW Seal Assembly '4,�411. ,, .' *t,. `• r a," 7 10,614' 9-5/8"X 4-1/2"TIW HBBP Packer w/latch,(3.928"ID) OMNI r r; 7 8 10,624' 4-1/2"x 3-1/2"XO,(2.992"ID) r °• i* t.�- ' 9 10,683' 9-5/8"x 7"Baker Liner Hanger t • ,,, 10 11,079' 3-1/2"Otis Ported Nip(2.66'ID) '.1.' 1, • �. Si.- a 11 11,091' 3-1/2"Blast Joints(4)(69.25'long) ,1r ;':' 1 .,;,q' 12 11,166' 7"x 3-1/2"TIW HBBP Packer 13 11,176' 2-7/8"X Nip(2.313"ID) 14 11,182' 2-7/8"X Nip(2.313"ID) , • 15 11,188 2-7/8"WLEG,(2.441"ID),Bottom @11,189' 16 11,365' 7"x 3-1/2"Otis WD Packer - .T 17 11,371' 2-7/8"X Nip(2.313"ID) ,e„'4*to18 11,374' 2-7/8"X Nip(2.313"ID) 9-5/8" , : V 19 11,377' 2-7/8"WLEG,(2.441"ID),Bottom @11,378' ,,,,. . 10 20 11,430' 7"x 3-1/2"Otis WD Packer 11 21 11,436' 2-7/8"X Nip(2.313"ID) 22 11,439' 2-7/8"X Nip(2.313"ID) 23 11,442' 2-7/8"WLEG,(2.441"ID),Bottom @11,443' PERFORATION DETAIL \ . , 12 Sands Top Btm(MD) Top(TVD) Btm(TVD) FT Date Status 13 (MD) ,', [ w 14 8,328' 8,338' 7,580' 7,588' 6 6/25/2017 Closed „.,.$44 .I 15 UPSZ FIll 11,007' 11,013' 9,854' 9,859' 6 9/19/2001 Closed UPSZ FIll 11,018' 11,032' 9,864' 9,876' 14 9/19/2001 Closed ;. i.. .= UPSZ FIll 11,048' 11,054' 9,890' 9,895' 6 9/15/2001 Closed Ora ' 4 16 UPSZ FII 11,100' 11,132' 9,936' 9,964' 32 9/21/1987 Closed I 4 70.4,, i: it 17 UPSZ FII 11,110' 11,130' 9,945' 9,962' 20 11/08/1998 Closed 1sUPSZ Fl 11,150' 11,158' _ 9,980' 9,987' 8 9/22/1987 Closed __ S3A4 11,224' 11,258' 10,045' 10,075' 34 9/21/1987 Closed_ S3A3 11,266' 11,304' 10,082' 10,116' 38 9/21/1987 Closed 10"7410;t4 t 20, S3A2 11,340' 11,354' 10,148' 10,160' 14 9/21/1987 Closed 4, 21 S3A1 11,390' 11,414' 10,192' 10,214' 24 9/21/1987 Open ; ` e 22 ' r;'e1 23 GENERAL WELL INFO SAFETY NOTE: ' API:50-029-21645-00-00 H2S readings average 230-260 ppm on A/L and 7" „1,34,2 2.' Completed-9/25/1987 gas injectors.Well requires a SSSV.Possible TD=11,783'(MD)/TD=10,543(TVD) cement sheath in tubing from packer squeeze(1- PBTD=8,240'(MD)/PBTD=7,508'(TVD) 5-1998).Chrome tubing,liner and jewelry. Revised By:TDF 7/6/2017 • 11 Hilcorp Energy Company Composite Report Well Name: END 3-23 Field: County/State: (LAT/LONG): avation(RKB): API#: Spud Date: Job Name: 1722056-END 3-23 Reservoir Abandon&Decomp Contractor AFE#: AFE$: MiltigiVERMISPENEMMEMBPSOMMONalliiiiiBiaiMWtitumniary /. 6/14/2017 ***WELL SHUT IN UPON ARRIVAL*** (Eline tbg punch&cut Pre rwo) MIRU ELINE. RIH W/ELINE TOOLS&4'OF TUBING PUNCHER. PUNCH TUBING OVER INTERVAL 10626-10632'(CCL TO TOP SHOT:6.7',CCL STOP DEPTH: 10621.3') **CONTINUED ON I5-JUNE-2017** 6/15/2017 **CONTINUED FROM 14-JUN-2017** RIH W/ELINE TOOLS&3.475"JET CUTTER. CUT TUBING AT 10406',MIDDLE OF 1ST FULL JNT.ABOVE GLM#1 (CCL TO CUTTER:8.5',CCL STOP DEPTH:10397.5')STRANDED ARMOR WHILE POOH W/JET CUTTER. REPAIRED ARMOR AND FINISHED POOH WITH TOOLS WELL LEFT SHUT IN-NOTIFIED PAD OP OF DEPARTURE-SIGNED OUT AT SECURITY ***JOB COMPLETE*** 6/17/2017 Electrician Sean Logan Disconnected Fire and Gas Alarms, Roads and Pads Hauled off 120 bbl.8.4 ppg Brine to B-50,Removed Pipe Racks,Peak super Sucker Cleaning Pits pit 3 has about 1 ft.Frac Sand on Bottom,Break and Lay over Derrick,Nipple down bope stack to four Bolts, Rig down and remove Hydraulic hoses from bop and cat walk,ASRC Crane Remove Rig Floor and well House load on Trailer,Nipple down bope stack,Nipple up Production Tree,Test Hanger Void to 5,000 psi,Tee Bar and Remove BPV,Install TWC Valve,Well Support Fill Tree with Diesel Test Tree Flanges to 5,000 psi(Good Test),Clear and Clean Location, Rig Move Haul ASR Rig and Equipment to Endicott,Rig crews meet w/safety rep Thad Eby and Endicott Field Foreman Jeff Staley for Endicott orientation and to conduct the IWS monthly safety meeting 6/18/2017 Continue to R/U on well 03-23 w/ASR#1.Remove production tree from wellhead,replace w/11"BOP stack and N/U.Adjust rig mats to place 8x15half mats into place between well 03-23 and the two wells on either side of 03-23.Spot mud boat and mud pit trailer into place.Crane on location to remove production tree,spot working well house into position over the BOP stack,and place rig floor in operational position.,Continue to R/U on END well 03-23.Hi-Torque all BOPE studs until secure,Adjust working well house as needed to give appropriate angle for catwalk to spot into place w/floor.Swap out loader for larger loader to handle catwalk and position into place. Roads and pads on location w/grey lock x flange connection for flow cross.R/U all fluid lines.,Finish Nipple up Bop's, Rig up Hyd Lines to Stack,Sundry Safety Meeting with ASR Crew, Went over Plan for word and Procedure on Endicott 3-23,Ordered 290 bbl.9.2 ppg Brine and Potable water for Toilets and Sinks,Electricians on location Rigging and Connecting High Line Power to Rig,Scott Richards on location Connecting and Bump Testing Fire and Gas Alarms in pits,Cellar and Rig Floor,High Pressure Kill Line hose,Metal End of hose Connection is Split(Brand new Hose) Tool pusher Went to Milne point,Retrieved Spare Hose out of A-pad Conex,Fill pits with 250 bbl.9.2 ppg brine Lay out 100 ft.high pressure hard line to flow back tank and Hammer Connection up Tight, Pad Operator was Called,Open IA Valve to Tank and Bleed off Gas for 15 min,Well head Rep John Morrow on Location Bleed Gas Pressure off Tubing through BPV,Once gas was bleed off Tee bar and Remove BPV and Install TWC Valve in Hanger Profile,Hang Cap string Sheave in Derrick and spot Spooler into Place,Grease Choke Manifold Valves and Manuals on Kill and Choke side of the Mud Cross, Installed New high Pressure Kill Hose on Stack,R/U Test Equipment Shell Test Bope to 3,000 psi 5 min(Good Test)Test bop Rams and Valves 250/3,000 psi Annular,250,2,500 psi,Perform Test 1&2 Tested High on test 3 Leaking checking and Chasing Slow Bleed off Found Pin Holes in High Pressure Jumper Hose From Derrick Valve to Test Joint, Break and lay down and Replace Hose, 6/19/2017 Continue to test BOPE,searching for pressure bleed in the system.Open pressure transmitter and find broken bladder within transmitter.Replace bladder and continue to attempt pressure test.Continue to see 50psi leak over 2-3mins,Attempt to make the system as small as possible and eliminate potential leak sources„lsolate system so that a visual verification can be made on all potential leak sources.Determine leak must be down hole. Pull TWC and inspect seals. Re-set TWC and test,(failed test).M/U landing joint to TBG hanger and test down landing JNT to see if TWC threads are leaking.(failed test),Close pipe rams and attempt to test TBG hanger utilizing the landing joint to isolate the potential TWC leak path.(failed test)Failure rate the same for both tests.Decide to reduce the test volume smaller by testing directly against the exterior of the kill manifold closing valves(K3, K5,K7,and Pump valve 4)still leaking.,Reduce test volume again by double blocking kill manifold valves K3, K4,K5,K6,and using the pressure transmitter as an end cap on K8,eliminating the rig pump manifold entirely.(Failed test).Close needle valve on test pump hose and remove all hoses from test pump to ensure no leaks through pump.(failed test),Reduce test volume again by removing test transmitter from kill manifold and hooking up directly to test pump.(failed test)Purge all hydraulic lines from chart recorder to pressure transmitter.Test directly against transmitter.(failed test),R/U Wellhead Rep Greg Ruge's test pump to pressure transmitter and pressure up against chart recorder.(failed test).,Remove chart recorder and replace w/needle gauge.Needle gauge holding solid pressure.Contact I-rig expediter and have back up chart recorder sent to Endicott.NOTE:ASR chart recorder re-calibrated on 06/12/17 by ACMS in Deadhorse.Crews continue to clean rig.,R/U Test Recorder,Test Equipment Shell Test Bope to 3,000 psi 5 min(Good Test)Test bop Rams and Valves 250/3,000 psi Annular,250,2,500 • ' Test Joints 4-1/2 and 3-1/2(AOGCC Jeff Jones Waived to Witness Bope Test on 6-17-17 @ . 9am,Y'e ' • '• • • • •• - ••e• C Valve from Hanger Void,Make up 4-1/2 Landing joint into Hanger BOLDS,open IA no Pressure,Pull hanger to the rig Floor Unset Hanger at 90k free pull 132k,Break and lay down Tubing Hanger and Landing Joint,Tie off Control Lines to Spooler,Trip out of the hole lay down 4-1/2 TDS Tubing F/Surface to 1,512 ft.37'Joints Spooled up Control Line,Lay down SSSV,Pulled Total of 54'Joints of 4-1/2 TDS, 6'ft.Cross over Pup, Layed Down 16'Joints Vam Top Tubing • 4110 6/20/2017 Continue to POOH WI 4-1/2"TBG f/-2800'md to surface.265 JNTS of 4.5"TBG,1 Cut JNT=20'11",2 x 10'pups,2'crossover pup,5 GLM's,1 SSSV,24 cross collar clamps.,Clean and clear rig floor,swap over pipe handling equipment f/4.5"to 3.5".Top off hole to verify fluid depth.27bbls to fill=-370'md.Load and strap 1 row of 3.5"work string.Strap Baker fishing tools,M/U and RIH w/Baker Fishing bull nose 9-5/8"scraper BHA on 3.5"work string,f/surface to -1700'md(58 JNTS).Having to run slower due to fluid running over the top of each joint at higher speeds.,Trip in the hole 9-5/8 CSG Scraper on 3.5 RTS-8 work string F/1,700 ft.to 3,950ft.Having to run slower due to fluid running over the top of each joint at higher speeds.Returns are very Gas up with a heady oil mix,R/U Circulating Hose to Flow back tank,Circulate Oil Cap off of well bore to Tank,Pump Rate of 3bpm at 1,000 psi Tbg,Pumped 50 bbl.to tank,Switch over to Pits Circulate through the gas Buster until Clean Returns Total of 92 Bbl.Pumped,Trip in the hole 9-5/8 CSG Scraper on 3.5 RTS-8 work string Ft 3,950ft.to 8,400 ft.Reciprocate Work String at 8,300 ft.P/U/W=70k D/W/N=40k 6/21/2017 Continue to RIH w/Baker 9-5/8"scraper BHA on 3.5"work string N-8400'md to 10,418'md.Tag up on TBG stump setting down 5klbs.P/U and verify tag depth(10,418'md).Pull wiping rubber and fill hole until fluid level can be seen.POOH watching to ensure fluid level is dropping as we pull.(Fluid level falling, not swabbing the hole).,Elevators locking on pipe,set ring appears to be wedging on Vam Ace tapered tool joint.Trouble shoot.Unable to get elevators to release from tool joint so that we can break out joint.Lower elevators to floor level and push slips w/carriage to release.Increase set ring contact area on tapered tool joint.(No success).Service elevators as per manufacturers instructions.Elevators functioning properly again.,Continue to POOH w/9-5/8"scraper BHA on 3.5"work string f/-10,300'md to-4400'md.,Service Rig Check Fluids and Grease,Rig Engine Cummins is over heating Installed portable Heater Trunk Blow Cool Air on Generator„Continue POOH w/9-5/8"scraper BHA on 3.5"work string f/4400 FT.to 3,950 ft..Rig Generator is over Heating shut Down Call Endicott Mechanics Brian&Mike, Rig Fan Clutch is out on Rig Carrier engine.,Endicott Mechanics'Removed old Clutch Fan From Rig Carrier Engine„Drove to Milne point VMS Shop Retrieved Spare Fan Clutch,Drove back to Endicott,Endicott Mechanics'on Location Installed New Fan Clutch in Cummins,Continue POOH wt 9-5/8"scraper BHA on 3.5"work string fl 3,950 ft.to-1800'md. 6/22/2017 Continue to POOH w/Baker 9-5/8"scraper BHA fl-1800'md to surface.UD BHA and crossovers in prep to ship back to Baker Fishing.Do not top off hole fill once out of hole to allow for faster trip in hole w/Halliburton cement retainer.,M/U Halliburton cement retainer as per Halliburton Rep on location. Ensure brass shear bolt has been drilled out to reduce the tensile rating ft 50klbs to 30klbs.Discuss running procedure w/hands RIH.,RIH w/Halliburton cement retainer on 3.5"9.2ppf RTS-8 work string f/surface to 8,558'md. Easy in and out of the slips,monitoring hook load/drag on the way in hole.,Service Rig Check Fluids and Grease,Continued RIH wI Halliburton cement retainer on 3.5"RTS-8 work string f/8,558'ft.to 10,376,Rig up to Circulate through Swivel F/10,360 to 10,380, Wash and Reciprocate Work string at 2bpm 1240psi P/U/W=89K D/NNV=57K,Set Cement Retainer at 10,376 ft.Rotate pipe 35 turns o the right,Pulled up in 10k increment's Shear out at 122k pulled up 10ft.rotate another 25 turns to the right,set comfirm,Closed pipe rams P/T Casing 3,000 psi(Test Failed) Engineer paul chan was call decision was made to test casing 1,500 psi charted min,AOGCC Guv Schwartz.was notified Decision wasmado_to_Pioreed with cementing,JSA w/Schlumberger IWS Company man,Halliburton Rep,stabbed back into Retainer,P/T Lines 1,500 t 4,000 psi Attempt to injection rate of 2.5 bpm at 3,500 psi,Schlumberger Pumped 10 bbl.fresh water at 1.8 bpm at 185 psi,mix and Batch Class G cement at 15.8 ppg un sting from retainer Pump 67 bbl.cement down tubing,sting back into retainer pump 58 bbl.Pull up and Un sting Letting 10 bbl 15.8 ppg u-tube and place cement on top of retainer,Lay down 7 joints 10,170ft.,R/U Reverse Circulate Pump 80 bbl.to the pits swapped over to drill cuttings tank till Clean returns,Break and lay down all service lines,Trip out of the hole lay down 3.5 RTS-8 Work String ff 10,170 ft.to 8,500 ft. 6/23/2017 Continue to POOH w/Halliburton cement retainer running tool on 3.5"work string f/-8500'md to surface. Pollard E-line on location @ 12:00pm in prep for drift run and setting EZ Drill Retainer.,Clean and clear rig floor,R/U Pollard E-line in prep for drift run and setting EZ Drill Retainer.,RIH wt Pollard E-line drift assembly consisting of 8.125"gauge ring on 10'junk basket,down to 8700'md to verify hole is clear for setting 9-5/8"EZ Drill Retainer.,POOH w/Pollard E-line drift assembly,R/D drift BHA,M/U Halliburton 9-5/8"EZ Drill Retainer w/wire line adapter setting kit and casing collar locator.,RIH wt Halliburton 9-5/8"EZ Drill Retainer w/wire line adapter setting kit and casing collar locator on E-line.,Service Rig Check Fluid and Grease,RIH w/Halliburton 9-5/8"EZ Drill Retainer w/wire line adapter setting kit and casing collar locator on E-line. ASR Rig RKB 16.3,Original RKB of 36.91 adjusted 20.61 Set Top of CIBP at 8,423 BTM at 8,426,Pooh R/D Pollard E-Line,Tested 9-5/8 Casing ft 8423 ft.to Surface 3,000 psi 30 min Charted(Good Test),JSA Halliburton Reps,IWS Hands Company Man,Pick up 10ft.Perf Gun,and 9-5/8 Cement Retainer,Tl H 10ft.Perf Gun 9-5/8 Cement Retainer on 3.5 RTS-8 Work String to 5,940 ft. 6/24/2017 Continue to RIH w1 Halliburton Drill Gun and FasDrill retainer BHA on 3.5"work string ft 5940'md to Halliburton bridge plug.Tag bridge plug 18'into jnt 282 and(8440'md ORKB). P/U/W=70klbs,S/O/W=50klbs,Calculate FasDrill retainer setting depth to ensure we leave adequate room for I-rig to set whipstock. Perform PJSM wt Halliburton,and rig crew for setting retainer,pressure testing,and firing guns.,Set FasDrill retainer @ 8326.5'md by rotating 30 times to the right,P/U in 10kIb increments to set sealing elements.At 120klbs hookload,see indication of shear.Rotate another 35 times to the right to release from mandrel.Set down on retainer w/25klbs,close annular and test annulus to 1000psi f/5mins. Hold pressure on annulus and pressure up TBG to 3000psi,hold for 1 min and then dump pressure.Guns fire after 5min,Monitor TBG for pressure,TBG stagnant.Perform injectivity test by pumping©0.5BPM=I850psi, 1 BPM=2450psi,PJSM w/SLB,Halliburton,rig crew,to discuss cement pumping plan.Calculate max pump pressure allowable for squeezing cement.Set SLB trips at 3200psi,Fill lines w/fresh water and pressure test to 250psi low,4000psi high.Pressure bleeding off.Trouble shoot leak.SLB change out seal on pump valve.Pressure up again and note bleed off,chase down leak to Halliburton valve on the IA.Close wellhead IA valve to isolate.(Good Test),Blend mix water and batch up cement to 15.8ppg.Space out so cement retainer running tool stinger is 10'md above the top of retainer.,Close annular and pump 10bbI fresh water lead followed by 15bbls of 15.8ppg class G cement,chased with 5bbls of fresh water. Hold back pressure with choke while circulating cement into pipe to reduce cement from falling down hole.Displace cement w/52.9bbls of 9.2ppg brine prior to shutting down pumps and closing choke.At this point cement is 5bbls from exiting the stinger on Halliburton's running tool.,Set down into retainer with stinger,setting 10klbs on retainer,wellhead pressure increased as we stung into retainer giving good indication seals on stinger are holding.Squeeze 5bbls of fresh water followed by 11 bbls of 15.8ppg class G cement into perforations.Pump©1 BPM=2300psi.TBG pressure didn't fluctuate much while squeezing.Monitor annulus,no pressure seen.,Un-sting from retainer with choke open and allow 4bbls of cement inside TBG to U-tube into annulus.Slowly pull out wI JNTS 279,278,277,leaving stinger--30'md above TOC.,Reverse circulate @ 5BPM=900psi f/120bbIs,cement seen @ 70bbls away,cleaned up quickly after 90bbls away,continued to circulate 30bbls to ensure pipe is clean.Shut down,monitor well.Well stagnant.RID SLB cement.,POOH w/Halliburton cement retainer running tool on 3.5"work string f/-8240'md,Service Rig Check Fluids Grease,POOH w/Halliburton cement retainer running tool on 3.5"RTS-8 work string f/8240 ft.to 5940 ft.,ASR Rig shut down Trouble shoot Problem, Damaged Ethernet cable was Cut between Drillers console and TCL,Changed out Cable,POOH w/Halliburton cement retainer running tool on 3.5" RTS-8 work string f/5940 ft.to Surface,Lay down Halliburton Retainer setting tool,Changed out Handling Equipment f/3.5 to 4.5,Load and Tally 3,000 ft.4.5 Vam Top Tubing on pipe racks,TIH 4.5 Vam Top Tubing 75 joints(2,950 ft.)(Tubing was ran open ended with no shoe Attached),Make up landing joint into Hanger,Land hanger RILDS,Break out Landing joint lay down same. 6/25/2017 LRS on location to pump freeze protect. Pump 35bbls of diesel down the TBG,line up and allow to U-tube f/30mins.No pressure on TBG or IA. Dean Norris on location to set BPV.,Begin R/D M/O process,re-locating ASR from Endicott to Milne Point. • Hilcorp Energy Company Composite Report Well Name: END 3-23A Field: County/State: ,Alaska (LAT/LONG): avation(RKB): 26.5 API#: Spud Date: 8/25/2017 Job Name: 1712313D END 3-23A Drilling Contractor Innovation AFE#: AFE$: * orma 8/7/2017 Begin R/D and prep rig for Barge to Endicott.R/D/UD Mud Line/CMT Line.Stand pipe Manifold.R/D/UD Kelly Hose.Clean Cutting tank area.Prep for TD Removal.Prep for service loop/Spinners removal.;House keep and organize through out the rig.R/D Derrick Camera.Weather protest exposed rams/cylinders on TD.;RD Service Loop bundle. R/D UD Spinners-Secure Trolly.Disconnect Derrick Electric Cables.Check Derrick A-Leg bolt Tq.R/U Derrick Std SRL's. R/D Derrick Assist/Geronimo Lines on Roof.;Stage Top Drive Cradle.Begin UD Top Drive;PJSM,Secure extend frame to top drive and raise top drive.Set cradle under top drive.Lower top drive into cradle and secure same. R/U blocks to cradle,lift and stage on floor,secure w/chains.;Blow down water system, chain down smoke shack on roof.Remove beaver slide from sub.;PJSM,R/U Bridal lines for derrick scope down.Scope derrick down,Install transport locking pins.Disconnect top drive carrier f/blocks.Secure carrier.;Empty water tanks,suck out boiler,vac out and clean sumps.Cleanout rig vac unit.Hang blocks, R/U,unstring blocks.Continue to prep modules to move,remove interconnect jumpers,flip up roof caps 8/8/2017 Continue to R/D and Prep Modules for move.Disconnect camp I shop power.Jack motor module,attach dolly,move forward and stage.Jack and move mud module,install jeep.Jack pipe shed and move out.Disconnect camp/shop power.Make ramp over utila-door at pad entrance.Jack and move catwalk.Spot crane and remove center windwall,then DS/ODS V-door windwalls.;Remove top drive from rig floor and stage on trailer.Spot derrick stand on mat board.Move Cat Walk,Pipe Shed,Pit Mod,Power Mod to F-Pad.Trouble shoot hyd issue with Derrick Rams.;Trouble shoot rig move HPU.Solve problem.Lay over derrick onto stand.Un pin and remove derrick wind wall with crane,lower down finger wind wall assembly,place on trailer.;Two cranes perform derrick lift and set on prepared lowboy for transport to barge.;Pull sub off of well.(Foot stompers).Line up down the pad,(Rotate foot stompers)Peak truck took possession of sub, began moving sub to F pad barge landing.3 truck convoy.Derrick,sub,TD stand. 8/9/2017 Load barge at Milne Point F Pad landing.Innovation sub base,derrick,top drive,TD stand,derrick wind walls.;Details:Set barge transition rig mats.Spot plywood,timbers for smooth runway on ramp.Load sub base onto barge.Position as per Marine Surveyor.Prep deck and weld down stops.Remove sub;draw bar,and stow.Load wind wall top drive trailer next.Load derrick stand derrick board trailer,load derrick trailer.Secure all loads as per barge personnel.Remove barge transition mats.;Barge depart 16:30 hrs.Daylight crew mobilized to MPI for billeting.They will receive the barge,and assist in off loading.;Night crew continued to prepare modules on Milne side for load out.Secure all lines,hoses,loose tools.Place un-needed drilling equipment on trailers to be stored on D pad.Anti seize treat all;exposed connections and protect with bags.Night crew organized and cleaned up drillings connex's on C pad.Install magnetic tarps on openings around generator module.Secure drilling connex shelves.;Barge arrived at Endicott @ 02:30 hrs.Tie off and secure fast with two dozers.Set mats, and off load first barge run.10 hour run with wind at his back.Off loading at report time. 8/10/2017 Barge run#1 arrived MPI @ 0200 hrs.Secured and made fast with two dozers. Welders cut away module bracing. Remove tie downs,and load securements from wind wall,top drive. Install draw bar on sub.Off load sub.Secure forklift,welding machine,dunnage on barge.Barge pushed back out @ 08:00 hrs.Sub base was taken to SDI well 3-23A.;Production shut in producing adjacent wells.Final rig mat placement on well.Remove rear sub base tires.R/U front sub base yoke.Rig down rear sub base yoke.Spot sub over well.;Closed in wells brought back on line.Tie onto derrick with crane.Pin derrick wind wall,and racking system back in place.Day crew attend Endicott Island orientation class 17:30 hours.;Foss barge arrive back @ Milne Pt.landing @ 17:00 hours. Attempt to land,unable to hold position due to high easterly winds.Skipper pulled offshore 1 mile and anchored.Wait on wind direction.;Milne side:Crew wire wheeling rust spots on sub connex,and paint primer.Clean up,organize electrical connex on D-pad.Add oil to pipe shed cold start.Ensure all modules are ready to travel.;Wind shifted to South.Barge pulled in @ 03:30 hrs.Held fast with dozers.PJSM:Set metal transition plates.Load Doosan loader on stern.Position Pipe shed on back deck.Place prefab wheel chocks. 8/11/2017 Load Foss barge @ Milne F Pad landing.After the pipe shed was loaded,the trailer with hot house was spotted,catwalk/cattle chute module placed on the bow.Welders secured pre fab wheel and frame;deck braces as per Marine Eng.All loads securely lashed down to deck.Barge departed @ 08:30 hrs.Arrive MPI Endicott @ 1700 hrs.Off loaded and released by 18:30 hrs.;SIMOPS: Daylight crew on SDI:Re-rig hydraulic hoses on floor.Set sub base out riggers. Safety out toe board/wind sock.Rig up and pin mast raising cylinders.Raise derrick,pin in place. Rig down;mast cylinders.Install floor plates.Hoist top drive to floor and secure.Install wind walls. Rig up tugger and man rider lines.Rig up and pin tool slide.Route power cords in derrick,plug in.;Rig modules spotted on SDI.Pipe shed&catwalk modules placed into rig footprint. Night crew billeted in Milne camp.Day crew billeted on Endicott MPI.;High Northerly winds prevented barge from docking as of report time.Barge anchored off Oliktok point. 8/12/2017 Both crews assigned to daylight shift.One crew in Endicott working on sub base:Hoist and set upper service loop termination on racking board.Pick up and set mud line and cement stand pipes.;Make up mud manifold and bleeder lines.Prepare cellar for nipple up.Load pipe shed with 5"drill pipe.Final connections made in derrick to service loop at board.All pig tails connected&secured.;Rig up Kelly and cement hoses on floor.Set service loop in finger block.Second crew billeted in Milne:Generator module work,change out valves on steam system to globe valves.Conduct full parts;inventory on mud pumps.Clean and organize welding/truck shop.Organize pups and XO's staged in D-Pad yard.Pick up trash,broken pallets etc..around Innovation warm storage steel building.;Winds continued unabated out of the NE @ 25 to 30 knots.Foss barge holding fast on anchor off Oliktok point.No rig crew activity during night shift. • • 8/13/2017 The high winds continued through the day.Foss barge remains securely anchored off Oiktok Pt.Endicott Crew activity:General housekeeping through out sub base and pipeshed modules.Install tugger;line guides.Load more 5"pipe into pipe shed.Strap and tally.Tighten koomey line to stop some minor oil leaks. Check Koomey system precharge.Good.Nipple down tree.Nipple up companion flange;on annulus valves.Check thread profile in tubing hanger.TDS threads, good.Nipple DSA to wellhead.Nipple up BOPE stack.Torque all stack flanges.Hook up koomey lines.Secure stack.Rig up;choke and kill lines.Pressure wash cattle chute.Milne Pt.crew activity:Change out generator on office trailer.Check torque on all electrical connections in MCC drive house.Continue to clean and;organize D-Pad yard,both the rig assigned area,and the general materials inventory.Complete welding stairway for over the flow lines behind sub. Seal weld out the vent for compressor room.;Continue to clean and organize welding shop walls,and inventory on C Pad.;WOW.No rig activity on Night shift. Both crews working daylights until the barge begins running again.One tool pusher and one DSM stationed on Endicott,one Tool Pusher and one DSM in Milne.;5 to 6 foot rolling waves with white caps out of the North at report time. 8/14/2017 Foss barge held position all day,anchored off Oliktok Pt.Crew in Milne:Mobilize equipment for Endicott.Adjust and tighten brackets on door closures,Gen module. Filter gear oil on Mud pump#2;Complete task of tightening all wire connections and lugs in motor/pump MCC room.Load flatbed with new stairs for rig to transport to SDI.Measure and design new modifications for mud mixing hopper.;lnspect and grease drag chain in pits.Organize and re-stock new pump parts.Continued to police up trash,sticks on D pad.Separate scrap steel from good steel in yard. Complete task of;un-loading tangled piping of various sizes from pipe bunk,welders stash. Crew in Endicott:Scope out all rams and hydraulic cylinders to assist in emptying hydraulic tank for welding.On going;pressure washing of sub base and catwalk modules.Rig down tool slide steam heater.Weatherize exposed outside rams with insulation.Remove top drive shot pin assembly for scheduled P.M.Empty;and clean out hydraulic tank.Assist welder with hydraulic tank modifications.Re-install top drive shot pin assembly. Prepare new steam heater mount for tool slide.Ready hydraulic tank for fluid.;Check torque values on pipe shed storm clamps.Good.Rig up cuttings tank hootch.Off load 5"DP On location 299 joints DS 50,75 joints NC 50.;No crew activity.The weather began to lay down @ 20:00 hrs.Barge call out scheduled for 07:00 hrs,Tuesday the 15th. 8/15/2017 Foss tug and barge arrived©Milne Pt.F-Pad landing 07:00,Secure barge,begin loading 07:45.Load mud pits module,office camp,on barge for Endicott. Finished loading 11:30.Barge held @ landing;due to low water.Milne Pt.Crew After loading the barge,cont..cleaning D-pad,separate out quality steel from scrap iron,organization throughout pad as needed.;Endicott crew:Rig up bell nipple guide.Fill hydraulic tank.Secure BOPE.Install interconnect cushions where possible.Vacuum truck sucked out storm water from modules.Prepare to receive;Mud Pit module. The tug was able to depart from the Milne Pt. landing at report time. No rig activity.One crew remains in Milne,second crew billeted in Endicott.Both working day lights. 8/16/2017 Foss tug and barge floated free from Milne landing 06:00 hrs.Travel to MPI,arrive 14:30 hours.Vessel approached landing,and decided to reverse out due to building seas and 25 to 30 knot winds.;Relocate to lee side of Cross Island,2hour transit.Anchor up and WOW.Milne crew:Loader operator,welder, roughnecks,deconstruct rusted out well house,scrap out.Cut up and scrap out un-usable;metal.Compact and fill two metal dumpsters for transport.Final trash and stick removal on D-Pad grounds.Attach delineators to ends of 12x12's for vehicle safety in yard.Separate;and organize piping(construction grade), by size and length in pipe bunk,and pipe racks.Gather up XO's,float shoes,float collars,and stage on racks,(more legacy equipment).;Final preparation for Generator module,test run cold start,hydraulics system,tie down all loose items for barge run.;Endicott crew activity:Fabricate tool slide steam heater mount. hang new heater,Begin plumbing in same.Complete storm water removal from rig modules,cuttings tank.Create/update drilling;procedures.Set remaining rig mats.Welder worked on cuttings tank modification.Change out U bolts on top drive accumulator.Obtain oil samples on sub,catwalk,pipe shed HPU's.;Foss Tug and barge sat on anchor off Cross Island.Winds remained© 30 knts out of the East.Chaotic seas in front of the landing. Welder and two helpers finish cuttings tank modifications on;lnnovation rig.Crew on Milne side complete preparations on Generator module for next barge run.;No rig activity last 6 hours. From 02:00 hrs to 06:00 hrs the wind went from 30 to 15 knots.Waves decreased from 5'to 2.5'.Weather improving. 8/17/2017 Endicott crew activity:Continue pressure washing,cleaning,housekeeping on rig.Set herculite. Build dock for oil drum storage,berm in.Set stairway over production flow lines.;Barge run#3.Barge landed 11:30 hrs.Endicott.Made fast.Assisted by 50'vessel the"Legacy",to counteract river current.Welder remove metal stops.Unload camp module,mud pits module.;Take both to SDI and stage mud pits to side,and position office camp in place.Welder and crew dress of barge deck.Barge departed 14:00 hrs. Rig crew clean generator side of mud pit module.;Milne crew activity:Crew switched to night shift.Service Doosan rig loader.Complete D-pad project of organizing.Foss Tug and barge arrived in Milne 22:00 hrs.Secured with Peak dozers.;Generator module loaded. Welder secured load with prefabricated metal stops.Done welding @ 01:30.Barge released.Remained grounded at landing.Tub began washing out underneath barge to float free.;02:30. Continued to attempt to free barge.Barge still hard aground at report time.. 8/18/2017 Foss Tug and Barge SBB-V floated free from Milne landing 09:30 hrs.Head to Endicott MPI.Milne crew mobilized from Milne main camp,drove to Endicott, and billeted in MPI camp.Both crews now in End.;Mark out chalk lines for pit and generator modules SDI Innovation foot print.Remove shaker motor#1,and begin to dress off shaker.Stage 3 light plants,place transition mats on edge of rig mats.;Barge arrived MPI landing 17:00 hrs.Secured with lines to the dozers. Lay out steel transition mats,welder cut away steel stops.Off load generator module,tow to SDI with sow.Stage gen.module.;Welder dressed barge deck smooth,clean deck.Remove welding equipment,bottles,pumps for ballast leveling. Barge backed away 22:00 hrs.;Pull cattle chute away from sub base. Position generator and pit modules.Spot cattle chute in place.Spot in pipe shed.Spot in pit module.;Position generator module.Very short distance for the truck to maneuver. Had to un hook and re-position a number of times.Haul off the two D9's that were stationed at the barge landing MPI.;Secure all landings, hook up interconnects.Begin working on rig acceptance checklist. 8/19/2017 Take on water and fuel to rig. Fill boilers and stage up. Charge rig air system. Torque shaker motor to frame. Plug in electrical interconnects,assist welder with cuttings box defuser mod.;Notify security of non-permit confined space entry to pits. Inspect pit suctions,gun lines and agitators. Charge batteries and fire up generators. Swap from cold start power to C32 gens.;PJSM,String up blocks. String first two sheaves then re-adjust pulling sock(snake)to prevent hang ups while traveling through sheaves. Continue string up with no issues.;PJSM,R/U TDS.Slip on one row and 34 wraps onto drum. Install dead man clamp. Rig down block hanging lines.Rig up to top drive,position on table.Rig up derrick climber assist,Geronimo line.;Begin filling hotwell tank and boilers with water.Begin bringing boilers up to pressure 20 psi increments.AOGCC witness notification sent via email©08:45 hrs.Inspector will witness.;Position top drive,and carrier over rotary table.Raise TD out of carrier.Remove 4 black iron braces from carrier,lay down via beaver slide,lay down carrier off rig floor. Begin to align top drive:with top drive trolley.Lay out herculite,set cuttings box,berm in.;Pin TD in place. Prepare to scope derrick.Trouble shoot extension cylinders.Unable to bleed off cylinder pressure.Safety wire tie pin retainers for trolley.Hook up service loop.Test drag chain.;Test valves on gun lines,pump through pop offs,transfer fluid between pits,test PVT's.Plumb in heater above beaver slide door.Hook up secondary crown-o-matic.Work on rig acceptance checklist. • • 8/20/2017 Continue hooking up service loop to TDS. Hook up cooling lines. Spot Canrig shack and power up same. Spot flowback tank. Continue putting steam throughout rig(good). Cont prep to scope.;Power up TDS. Hydraulic leak around quill shaft. Troubleshoot leak. Pin trolley extend cylinders,retract same.;PJSM,Rig up bridle line,Scope derrick with no issues.Bridle down.Plug in mast lights. Pin and secure same.Bring xo's and handling equipment to rig floor. Rig up CanRig mudloggers.;Bring accumulator on line.Build 500 bbls 8.5 ppg brine in pits.;Rig up install bales,link tilt clamps on top drive.Shut down hydraulics to top drive.Rotate handler by hand 3 turns.Turn on hydraulics,function TD,good.Determined that this re-aligned internal;seals of top drive. Reason:Long term horizontal storage,cure:stand the TD up after it arrives on location.;Accept rig 18:00 hrs.Make up Kelly hose to top drive.Stage BOPE test equipment.C/O rollers on pipe spinners,full derrick inspection,top drive inspection.Run TD up and down for final adjust.;Obtain measurements to LPR's UPR's Annular preventer,and mark test joint,4.5"with donut.Pull BPV.Set TWC.M/U test equip,XO's to TJ.Set TJ donut below LPR's,close annular. Pump;through choke line against kill line valve on mez.Slow leak at low pressure. LID TJ to test below blinds and to eliminate air.;Close blinds.Pressure up thru choke line to kill line valve on mezzanine.Slow leak at low pressure.Close valves 5,7,8,held low pressure. Pressure up to 4000 psi,observe leak blind ram door seals.;Attempt to re-tighten.Already tight.Blow down stack.Service chokes 11,12,13.;Open blind ram doors for inspection.Found Driller side door seal blown into ram cavity.Replace seals Tighten doors back up.Fill stack with water.P/U 4.5"TJ.Fill stack. Shell test.250/4000 good;Mount spinner roller assembly,clean out cellar box.;Daily fluid hauled to 2-02:0 bbls,Total to 2-02:0 bbls. Daily fluid to Milne G&I:0 bbls,Total to G&I:0 bbls. Daily fluid to PBU G&I:0 bbls,Total to PBU G&I:0 bbls;Daily water from Duck Is.lake:1500 bbls,Total from Duck Is.lake: 1500 bbls. 8/21/2017 Inspect test equipment and walk lines. PJSM,testing BOP's. Test BOP equipment 250/4000 psi w/5 min hold. Chart and record same.F/P dart,target"T" her choke and mezz kill.;Drawdown Test-Start 3050 psi,drawdown 1650 psi, 19 sec 200 psi inc,72 sec full charge. 6 bottle avg=2325 psi. AOGCC witness test-Jeff Jones;R/D test equipment. Pull TWC. Flood and P/T flowback line from IA. Test line 300/2000 psi(good).;Circulate out freeze protect with 70°8.6 ppg brine. Circ a total of 300 bbls to flowback tank. Stg up to 6 bpm,415 ICP w/FCP 260 psi. Shut in and blowdown lines.;R/U WOT double stack power tongs and handling equipment. M/U xo's and landing jt to hanger.BOLDS and pull hanger to rig floor(63k up w/no overpull). B/O and L/D same.;PJSM.Crew change.Inspect and adjust hydraulic pressure on pipe skate.;Lay down kill string.4.5"12.6#Vam Top with Weatherford. Lay down 21 joints.Having trouble with electric"soft start module"for 100 horse motor assigned to skate.Main breaker tripped.Stop.;Electrician located a new electric starter in Deadhorse,Retrieve,install&test run.Wired in new start/stop system.SIMOPS:Clean out cellar,organize cellar for pack off change out.;Original soft start was faulty,indicating false over load message. New starter was a standard mechanical starter that required some rewiring to run.Electrician timed out.Mechanic arrived.;PJSM.P/U 10'pup joint.Torque quill into pup.Set slips on pup,Hang top drive slip 12 wraps onto drum.SIMOPS:Mechanic completed final set up for skate operations.;PJSM.Continue laying down 4.5"12.6#Vam Top'slick'kill string.Joint 22 to 75.Note: Loaded 600 barrels 9.5 ppg milling fluid in pits.;Rig down Weatherford casing equipment.Set test plug. Begin to nipple down BOP stack to replace 9.625"pack off.;Daily fluid hauled to 2-02:0 bbls,Total to 2-02:0 bbls. Daily fluid to Milne G&I:0 bbls,Total to G&I:0 bbls. Daily fluid to PBU G&I:0 bbls,Total to PBU G&I:0 bbls;Daily fluid hauled to snow melt tank:300 bbls.Total to snow melt tank:300 bbls. Daily water from Duck Is.lake:150 bbls,Total from Duck Is.lake:1650 bbls. 8/22/2017 N/D BOP equipment. Bleed OA(150 psi)off to atmosphere. Remove catch can,drain hoses,riser,choke and kill lines.Break wellhead connections w/bridge crane. Stg BOP back.;Work wellhead free,remove"B"section and stg back. M/U packer running tool T/5"DP.;RIH and"J"into packoff. Stage up working up/dn in 5k increments to 40k max,heat flange with hammers(no go).S/O and un"J"running tool;Remove most plastic and graphite packing from between packoff and wellhead profile. Tarp and heat wellhead w/steam. "J"back into packoff and pull free @ 30k. Remove packoff.;Clean and inspect used wellhead equipment(good).Install test plug.;N/U wellhead and test new packoff 500/3000 psi w/5/15 min hold(good). Witnessed by DSM.;N/U BOP,R/U choke and kill lines,install drip pan,flow line jet and fillup line,secure stack.;M/U 5"test joint,flood lines and stack with fresh water.Test upper 2 7/8"x 5"VBR to 250 psi for 5 min,attempt hi pressure test to 4000 psi,with pressure bleed off.;Note:have to close bag and pressure up to 100-150 psi to push test plug into profile with 5 inches of movement to bttm out.;Troubleshoot pressure drop,Observe slight drip from I/A valve,bleed off pressure,pull test plug,inspect seal,set plug and attempt to test,continues to leak,;observed another leak on HCR target tee flange,bleed off pressure and tighten same. Pull test plug.Notify wellhead rep© Milne point for another test plug seal.;PJSM,close blind ram,pressure up and test 9 5/8"casing to 3000 psi for 30 min charted,good test.Bleed off pressure, open blind ram. 6.8 bbls pumped,6.8 bbls bled back.;Install 2 new bleed valves on test pump.With wellhead rep on location @ 02:45,C/O test plug seal.Install test plug w/5" test jt,fill stack with water.Close upper VBR.pressure to 4000 psi.;Continues to leak out I/A,bleed off pressure,pull test plug, new seal damaged,C/O test plug and run same,pull test plug,seal damaged exactly as previous seal w/small cut same location.;Drain stack,Pull and inspect LDS,good,re-install LDS, C/O test plug seal,set test plug,fill stack.Test upper ram to 250 psi.;;Hauled 6 bbls cuttings to G&I for total=6 bbls Hauled 110 bbls to snow melt tank for a total=410 bbls Hauled 150 bbls H2O from DI lake for a total=1800 bbls 8/23/2017 Attempt 4000 psi high test on upper VBR's(Fail). Test Plug leaking. Pull plug,seals damaged on dual seal plug. Replace with"0"ring seals and run back in hole. Attempt high test again(fail).;Troubleshoot,determined mezzanine kill leaking. Service mezz kill and attempt test(fail). Discuss with drilling team. Decision made to N/D and inspect wellhead for damage and rebuild mezz kill;Pull test plug(found 9 significant damage points on seals). Damage correlated with lock down screws.;Isolate and bleed down koomey. Drain stack,N/D pollution pan,riser,choke and kill lines.Part stack from wellhead and stage back. Inspect,Found LDS profile to be sharp and very slight deformation;Visually verify that lock down screws were fully out(good). Dress lock down profile(chamfer edge)inside wellhead. M/U single seal test plug dressed with new"D"seal. RIH and watch plug landout;Inspect plug while landed out in wellhead. Found 3 small rubber slivers cut from lockdown screw profile. Pull plug. Found significant damage(failed seal)from profile toward drawworks.;Re-dress profiles. Rotate plug 1/4 turn. Noticed 1"port below lock down profile(1"port-Plugged)was inline with damage on seals and had sharp edge. Chamfer 1"port profile.;Set test plug and inspect. Found small piece of rubber seal rolled off into 1"port. Pull plug.Moderate damage to seal inline with drawworks.No other damage observed;Dress 1"port. Set test plug with no damage to seal going in and slight damage when removing. Dress 1"port. Replace damage test seal with new "D"seal and install same. No damage noted to seals.;B/0 landing jt and LID same.;N/U BOP equipment. M/U choke and kill lines. Tighten connection flanges. 4 point stack and center same. Install flow riser and air up seals. Charge koomey lines.;R/U BOP test equip. Test wellhead flange,upr,lwr VBR's w/ 5"test jt. No failures. 250/4000 w/5 min hold. Chart and record same. Mezz kill,choke and kill line flanges included in vbr test;R/D test equipment,blow down lines.Install 9"ID wear bushing.RI 4 LDS.Clean and clear rig floor.Seal cellar drip pan,ready rig floor to P/U BHA C/O catwalk hyd pump breaker.;PJSM,M/U 8 1/2"mill tooth bit,8.5"csg scraper,2-8 1/2"WM mills, 19 jts 5"HWDP=605.13,Drift and single in the hole w/ 5"DS50 DP f/605'to 1550';Continue to single in the hole w/5"DS50 DP f/1550'to 3662',draworks encoder fault while P/U single f/catwalk causing drum brakes to set,fouling drlg line on drum. Note:fill pipe @ 2490';PJSM,M/U top drive,hang off blocks,unspool fouled drilling line f/drum,inspect and re-spool line back onto drum,remove block hang line.Recalibrate blocks. B/O TD.;Continue to single in the hole w/5"DS50 DP f/3662'to 4435' Correct displacement TIH.;Rig electrician C/O draworks encoder;;Hauled 0 bbls cuttings to G&I for total=6 bbls Hauled 0 bbls to snow melt tank fora total=410 bbls Hauled 0 bbls H2O from DI lake for a total=1800 bbls • • • 8/24/2017 Change out encoder on drawworks. Attempt to test run TDS thru derrick full power. Blackout rig(only 1 gen online). Put 2 gens online. Fix line on drum. Re- test new ecoder(good).;Continue RIH Fl 4471'-T/8206'MD wl cleanout assy picking up DS-50 singles drifted from shed.;Wash down F/8206'-T/tag depth of 8222'MD. Set dn 5k on TOC @ 8222'MD. Drill cmt F/8222'-T/8302'MD. Saw several stalls F/8235'-8245'MD wt 13k to 18k tq.;Consistently saw 10- 17k overpulls after stalling. Saw rubber debris @ btm's up Ft 8222'MD along with good cmt cuttings. Drilled cmt w/5-12k wob,550 gpm, 1220 psi,60 rpm, 9k tq.;Attempt to verify set dn competency w/only 22k before wash dn slow.;P/U and displace w/hi vis spacer pill followed by 9.5 ppg LSND. Rotate and recip pipe while displacing. Reduce rate 3 bpm,and set dn with no rotary 30k dn wt(good set dn). Count pipe(good);Obtain SPR's and parameters. Monitor well (static),pump dry job and POOH F/8302'-T/6641'MD. 174k dn,212k up.;Continue POOH ft 6641'to 605'@ HWDP.Rack 9 stds HWDP.Pull remaining BHA,L/D scraper,bit sub and 8 1/2"VM1 bit. Close blind ram. Correct displacement on trip out.;Clear rig floor.Ready rig floor ft P/U WS.Load tools to rig floor,install short mouse hole,C/O tong dies.;PJSM with Baker rep, DD,MWD,DSM and rig crew for handling WS.M/U W/S BHA per baker rep,8.5"window mill,8.375"lower WM mill,2-8.5"upper WM mills, 1 jt 5"HWDP. Scribe f/shear bolt up HW.;Calculate slide hi side ft scribe.P/U Gen II WS slide WI bttm trip anchor using hoist,verify 3 shear scews installed and set @ 20k shear.Remove shipping bolt,set WS in hole,;install stop bar,openblind ram,set bar stop on rotary table.M/U Mill to slide with 45k brass shear bolt,install snap ring,remove stop bar,lower assy in the hole carefully.M/U DM collar.;Offset @ 41.20 deg,M/U TM collar,flt sub, UBHO sub,check orientation.M/U 1 std HWDP,top drive.Shallow hole test MWD,good,RIH with 7 stds HWDP,string magnet,1 std HWDP,string magnet=674.44';TIH with 5"stds DP f/674'to 3306'@ 60 fpm,easy in and out of slips. Fill pipe @ 2560';;Hauled 0 bbls cuttings to G&I for total=6 bbls Hauled 705 bbls to snow melt tank for a total=1115 bbls Hauled 150 bbls H2O from DI lake for a total=1950 bbls 8/25/2017 Continue RIH Ft 3189'-T/8220'MD. 60 fUmin. Easy on/off slips.;Wash dn Ft 8220'to 8290' @ 415 gpm,1165 psi, 219k up,177k do(no pump). Orient TF 20L. Slack off with final TF @ 26 LOHS. Set on depth @ 8302'MD. Good shear on anchor F/177k-T/146k.;Attempt pull test anchor(no overpull)up wt 173k(4k loss). 45k bolt sheared with anchor set. Set dn on top of whipstock on depth. Verify anchor set with 1l k right hand tq stall on whipstock lug.;P/U and establish parameters. Mill window-TOW @ 8279',BOW @ 8296'MD. 415 gpm,1140 psi,56%flow, 100 rpm,8.6k tq off,9.2k on. New formation depths �/ alculated From ctr of window @ 8287.5'.;Drill new formation confirmed by mudloggers F/8287.5'-T/8318'MD. 100 rpm,up to 15k tq on,8.5k tq off,415 V gpm,1140 psi. Backream slide every 5'. Clean window.;Early samples from loggers showed cmt,predominantly claystone w/siltstone. 210#total metal so ,\ w far. No notable gas @ btm's up or drilling new formation. Pump 20 bbl hi vis sweep.;Sweep back on time,no real increase,some sand and silt.Continue to condition mud for FIT,550 gpm,1800 psi @ 8287 until good 9.5 ppg MW in/out. Flush choke and kill lines. "p \ Obtain SPR.;R/U to perform FIT, Perform FIT to 12 ppq EMW wt existing 9.5 ppq MW. Pump 2.4 bbs,apply 984 psi,10 sec 960 psi,5 min 895 psi,bleed off pressure,2.2 bbls bled back,open UPR;FIow check well,static,pump 20 bbl dry job.POOH ft 8287'to 653'@ string magnets. Correct displacement POOH.;PJSM,cleanoff and LID string magnets,L/D 1 jt HWDP,rack back 9 stds HWDP, In MWD tool and window mills.Window mill 318"under gauge. Lower WM mill 1/4"under gauge,2 upper WM mill in gauge.;74 lbs of metal recovered from string magnets.;Load out tools,cleanup rig floor, drain stack,BO 4 LDS,pull 9"ID wear bushing,M/U stack jet tool,jet stack and flush kill and choke lines. Install 9"ID wear bushing,RI 4 LDS.;;;Daily losses to formation 0 bbls for a total=0 bbls Metal recovered from milling operations=320 lbs.;Hauled 0 bbls cuttings to G&I for total=6 bbls Hauled 0 bbls to snow melt tank for a total=1115 bbls Hauled 300 bbls H2O from DI lake for a total=2250 bbls AO 4 1 f - S A l 2. .--11.11c II Debra Oudean Hilcorp Alaska, LLC 1e eaEIVED 3800 p Alaska, L Drive, Suite 100 E Anchorage, AK 99503 Tele: 907 777-8337 DATA LOGGED Mkiwp M;eAAAJA. Fax: 907 777-8510 \01t/2011 OCT 24 2017 E-mail: doudean@hilcorp.com iviK BENDER AOGCC DATE 10/24/2017 To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL SDI 03-23 186-155 Prints: Thermal Multigate Decay Three Detector CD 1: P END3-23 TMD3D 22FEB17.pdf 2/23/2017 953 AM PDF Document 2,291 KB iit.1 END3-23 TMD3D 22FEB17_img.tiff 2/23/2017 9:53 AM TIFF File 4,191 KB END3-23 TMD3D_22FEB17_MainPass.las 2/23/2017 9:53 AM LAS File 668 KB END3-23 TMD3D 22FEB17_Repeat.las 2/23/2017 9:53 AM LAS File 778 KB Please include current contact information if different from above. SCANNEt f- t-s 2 8 ;013 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: /1)AQ ,, Date: ‘A‘C-1.55 Oh Nolan Hilcorp Alaska, C GeoTech 3800 Centerpoint Drive, Suite 100 RECEIVED Anchorage, AK 99503 Tele: 907 777-8308 IA 4AV-1 ffilenrp klaNks,IJA Fax: 907 777-8510 JUL 19 2017 E-mail: snolan@hilcorp.com AOGCC DATE 07/19/17 To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL SCANNED AUG 0 8 ? I', SDI 03-23 Prints: CCL\1.56" Puncher, HNS\3.475" Powercutter, HMX CD 1: Hilcorp SDI 03-23 PUNCHER_1511N 17 7/512017 1:25PM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received ey�� � Date: STATE OF ALASKA AKA OIL AND GAS CONSERVATION COI•SSION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon LI Plug Perforations LI Fracture Stimulate LJ Pull Tubing LJ Operations shutdown LJ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑I erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other:Reservoir Abandonment ❑., 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska LLC Development ❑l Exploratory ❑ 186-155 3.Address: 3800 Centerpoint Dr,Suite 1400 Anchorage, Stratigraphic❑ Service ❑ 6.API Number: AK 99503 50-029-21645-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0047502 DUCK IS UNIT SDI 3-23 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A ENDICOTT/ ENDICOTT OIL 11.Present Well Condition Summary: Total Depth measured 11,783 feet Plugs measured 8,240&10,170 C E I V E D true vertical 10,543 feet Junk measured N/A ee 10,614, 11,166, ,JUL 1 4 2017 Effective Depth measured 8,240 feet Packer measured 11,365&11,430 feet ��f'�(�j'�t 9,513,9,994, JGC true vertical 7,508 feet true vertical 10,170&10,228 fee Casing Length Size MD TVD Burst Collapse Conductor 161' 30" 161' 161' N/A N/A Surface 2,483' 13-3/8" 2,483' 2,483' 5,380psi 2,670psi Production 6,037' 9-5/8" 6,037' 5,739' 6,870psi 4,760psi Production 4,896' 9-5/8" 10,933' 9,789' 8,150psi 5,090psi Liner 1,095' 7" 11,778' 10,538' 8,160psi 7,020psi Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6/L-80/TDS 2,950' 2,950' 9-5/8"X 4-1/2"TIW HBBP 7"x 3-1/2"TIW HBBP Packers and SSSV(type,MD and TVD) (2)7"x 3-1/2"Otis WD&7" N/A See Above N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A SCANNED JUL3 10 Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 0 Subsequent to operation: 0 0 0 0 0 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory Development Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP Q, SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: "A i'51 317-221 S1 Authorized Name: Bo York /` ' Contact Name: Taylor Wellman' ki 01 Authorized Title: Operations Manager `�f Contact Email: twellman(C7hiIcorp.conn N1Tw1'11 Authorized Signature: Date Contact Phone: 777-8449 Form 10 101 'cviaccb'" 017 Submit Original Only 4 006.7 1L— %/1•/7 RBDMS L UL 1 7 2017 ' H H . • DIU - Endicott Well: END 3-23 SCHEMATIC Last Completed: 9/25/1987 Hilcorp Alaska,LLC PTD: 186-155 TREE&WELLHEAD OPEN HOLE/CEMENT DETAIL _ Tree CIW 30" Driven Original KBE=55.5'/BFE=16.8' Wellhead FMC 3,255 cu.ft.Permafrost,233 cu.ft. WELL INCLINATION DETAIL 13-3/8" permafrost top job in 17-1/2"Hole LKOP @ 3,478' 9-5/8,, 5/8" 575 cu.ft.Class"G"in 12-1/4"Hole 30 Max Hole Angle=38 deg.@ 7,460' 7" 365 cu.ft.Class"G"in 8-1/2"Hole Max angle at Top Perf:28 Deg.@ 11,007' CASING DETAIL 13-3/8" Size Type Wt/Grade/Conn ID Top Btm BPF 30" Conductor N/A N/A Surf 161 N/A 13-3/8" Surface 72/L-80/Btrc. 12.347 Surf 2,483' 0.1481 9-5/8" Production 47/NT8OS/NSCC 8.681 Surf 6,037' 0.0732 9-5/8" Production 47/NT95HS/NSCC 8.681 6,037' 10,933' 0.0732 TOC @ 7" Liner 29/L-80/Btrc. 6.184 10,683' 11,778' 0.0371 8,240' TUBING DETAIL 1 4-1/2" Tubing 12.6/L-80/Vam Top 3.958 Surf 2,950' 0.0152 JEWELRY DETAIL 2 TOC@ No Depth Item 10,170' ,.r . ., .. . '0 . Thg Cut 1 8,326.5' 9-5/8"Cement Retainer/Perf Gun 1 *+" 30,406' 2 8,423' 9-5/8"HES CIBP g72 `' ' 1 ,'' 3 10,376' 9-5/8"HES Cement Retainer " te' j 4 "",,r,,,....-4,.'" .- �,� , ,,, 5 4 10,436' ST 1:Port=0,Dev=31,VIv=Dummy,TVD=9,360',Date=4-10-2005 '''''I'''' :I:*TN, 5 10,542' 4-1/2"Otis XA Sliding Sleeve,(3.813'ID) .-' "' ki. " 6 6 10,599' TIW Seal Assembly .', ..;1.1t: 1 m ''^ r ` 7 10,614' 9-5/8"X 4-1/2"TIW HBBP Packer w/latch,(3.928"ID) *t 4 Yaw- 7 8 10,624' 4-1/2"x 3-1/2"XO,(2.992"ID) � i 4 * J 9 10,683' 9-5/8"x 7"Baker Liner Hanger ~ :"4'14'r,"eb °r 10 11,079' 3-1/2"Otis Ported Nip(2.66'ID) 1x . 7 4448 11 11,091' 3-1/2"Blast Joints(4)(69.25'long) ''� "4,41,1.44% 12 11,166' 7"x 3-112"TIW HBBP Packer c� , ,'' 13 11,176' 2-7/8"X Nip(2.313"ID) , 0`,4 r 9 14 11,182' 2-7/8"X Nip(2.313"ID) i4, °" 15 11,188 2-7/8"WLEG,(2.441"ID),Bottom @11,189' X,' t 16 11,365' 7"x 3-1/2"Otis WD Packer ;�' 17 11,371' 2-7/8"X Nip(2.313"ID) 44 ?"4 18 11,374' 2-7/8"X Nip(2.313"ID) 9-5/8"+ 19 11,377' 2-7/8"WLEG,(2.441"ID),Bottom @11,378' ,„,,t s` .," 20 11,430' 7"x 3-1/2"Otis WD Packer 410 21 11,436' 2-7/8"X Nip(2.313"ID) 141/4 = 11 22 11,439' 2-7/8"X Nip(2.313"ID) a 23 11,442' 2-7/8"WLEG,(2.441"ID),Bottom @11,443' .14 PERFORATION DETAIL 4, 12 Sands Top 1ct2 (MD) Btm(MD) Top(ND) Btm(TVD) FT Date Status ' 14 8,328' 8,338' 7,580' 7,588' 6 6/25/2017 Closed f 0*. 15 UPSZ FIll 11,007' 11,013' 9,854' 9,859' 6 9/19/2001 Closed UPSZ FIII 11,018' 11,032' 9,864' 9,876' 14 9/19/2001 Closed ++ UPSZ FIll 11,048' 11,054' 9,890' 9,895' 6 9/15/2001 Closed '► 16 UPSZ FII 11,100' 11,132' 9,936' 9,964' 32 9/21/1987 Closed ,,, 17 UPSZ FII 11,110' 11,130' 9,945' 9,962' 20 11/08/1998 Closed 4 ; ' r*° 19 UPSZ Fl 11,150' 11,158' 9,980' 9,987' 8 9/22/1987 Closed r .t,,,,Lx., S3A4 11,224' 11,258' 10,045' 10,075' 34 9/21/1987 Closed ', C''K0*'r'" `'`' S3A3 11,266' 11,304' 10,082' 10,116' 38 9/21/1987 Closed il.�+ 20 S3A2 11,340' 11,354' 10,148' 10,160' 14 9/21/1987 Closed 21 S3A1 11,390' 11,414' 10,192' 10,214' 24 9/21/1987 Open i *' ; 23 GENERAL WELL INFO SAFETY NOTE: �x'1;: API:50-029-21645-00-00 H2S readings average 230-260 ppm on A/Land 7"Lai►�i i' Completed-9/25/1987 gas injectors.Well requires a SSSV.Possible TD=11,783'(MD)/TD=10,543'(TVD) cement sheath in tubing from packer squeeze(1- PBTD=8,240'(MD)/PBTD=7,508'(TVD) 5-1998).Chrome tubing,liner and jewelry. Revised By:TDF 7/6/2017 • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date END 3-23 Eline 50-029-21645-00-00 186-155 6/15/17 6/25/17 Daily Operations: ',:, t � 6/14/2017-Wednesday MIRU ELINE. RIH W/ ELINE TOOLS &4' OF TUBING PUNCHER. PUNCH TUBING OVER INTERVAL 10,628'-10,632' (CCL TO TOP SHOT: 6.7', CCL STOP DEPTH: 10,621.3') 6/15/2017-Thursday RIH W/ ELINE TOOLS & 3.475"JET CUTTER. CUT TUBING AT 10406', MIDDLE OF 1ST FULL JNT. ABOVE GLM #1 (CCL TO CUTTER: 8.5', CCL STOP DEPTH: 10397.5') STRANDED ARMOR WHILE POOH W/JET CUTTER. REPAIRED ARMOR AND FINISHED POOH WITH TOOLS. WELL LE' SHUT IN. 6/16/2017- Friday No activity to report. 6/17/2017-Saturday Electrician Sean Logan Disconnected Fire and Gas Alarms, Roads and Pads Hauled off 120 bbl. 8.4 ppg Brine to B-50, Removed Pipe Racks, Peak super Sucker Cleaning Pits pit 3 has about 1 ft. Frac Sand on Bottom. Break and Lay over Derrick, Nipple down bope stack to four Bolts, Rig down and remove Hydraulic hoses from bop and cat walk;ASRC Crane Remove Rig Floor and well House load on Trailer, Nipple down bope stack, Nipple up Production Tree;Test Hanger Void to 5,000 psi,Tee Bar and Remove BPV, Install TWC Valve, Well Support Fill Tree with Diesel Test Tree Flanges to 5,000 psi (Good Test). Clear and Clean Location, Rig Move Haul ASR Rig and Equipment to Endicott. Rig crews meet w/safety rep Thad Eby and Endicott Field Foreman Jeff Staley for Endicott orientation and to conduct the IWS monthly safety meeting 6/18/2017-Sunday R/U on well 03-23 w/ASR#1. Remove production tree from wellhead, replace w/ 11" BOP stack and N/U. Adjust rig mats to place 8'x15' half mats into place between well 03-23 and the two wells on either side of 03-23. Spot mud boat and mud pit trailer into place. Crane on location to remove production tree, spot working well house into position over the BOP stack, and place rig floor in operational position. Continue to R/U on END well 03-23. Hi-Torque all BOPE studs until secure, Adjust working well house as needed to give appropriate angle for catwalk to spot into place w/floor. Swap out loader for larger loader to handle catwalk and position into place. Roads and pads on location w/grey lock x flange connection for flow cross. R/U all fluid lines. Finish Nipple up Bop's, Rig up Hyd Lines to Stack. Sundry Safety Meeting with ASR Crew, Went over Plan for word and Procedure on Endicott 3-23, Ordered 290 bbl. 9.2 ppg Brine and Potable water for Toilets and Sinks. Electricians on location Rigging and Connecting High Line Power to Rig, Scott Richards on location Connecting and Bump Testing Fire and Gas Alarms in pits, Cellar and Rig Floor. High Pressure Kill Line hose, Metal End of hose Connection is Split (Brand new Hose) Tool pusher Went to Milne point, Retrieved Spare Hose out of A-pad Conex, Fill pits with 250 bbl. 9.2 ppg brine Lay out 100 '. high pressure hard line to flow back tank and Hammer Connection up Tight, Pad Operator was Called, Open IA Valve to Tank and Bleed off Gas for 15 min. Well head Rep John Morrow on Location Bleed Gas Pressure off Tubing through BPV, Once gas was bleed off Tee bar and Remove BPV and Install TWC Valve in Hanger Profile, Hang Cap string Sheave in Derrick and spot Spooler into Place. Grease Choke Manifold Valves and Manuals on Kill and Choke side of the Mud Cross, Installed New high Pressure Kill Hose on Stack. R/U Test Equipment Shell Test Bope to 3,000psi 5 min (Good Test)Test bop Rams and Valves 250/3,000psi Annular,250,2,500psi, Perform Test 1&2 Tested High on test 3 Leaking checking and Chasing Slow Bleed off Found Pin Holes in High Pressure Jumper Hose From Derrick Valve to Test Joint, Break and lay down and Replace Hose. • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date END 3-23 Eline 50-029-21645-00-00 186-155 6/15/17 6/25/17 Daily Operations. �•; ;3. � 6/19/2017- Monday Continue to test BOPE, searching for pressure bleed in the system. Open pressure transmitter and find broken bladder within transmitter. Replace bladder and continue to attempt pressure test. Continue to see 50psi leak over 2-3mins, Attempt to make the system as small as possible and eliminate potential leak sources.;lsolate system so that a visual verification can be made on all potential leak sources. Determine leak must be down hole. Pull TWC and inspect seals. Re- set TWC and test, (failed test). M/U landing joint to TBG hanger and test down landing JNT to see if TWC threads are leaking. (failed test);Close pipe rams and attempt to test TBG hanger utilizing the landing joint to isolate the potential TWC leak path. (failed test) Failure rate the same for both tests. Decide to reduce the test volume smaller by testing directly against the exterior of the kill manifold closing valves (K3, K5, K7, and Pump valve 4) still leaking. Reduce test volume again by double blocking kill manifold valves K3, K4, K5, K6, and using the pressure transmitter as an end cap on K8, eliminating the rig pump manifold entirely. (Failed test). Close needle valve on test pump hose and remove all hoses from test pump to ensure no leaks through pump. (failed test). Reduce test volume again by removing test transmitter from kill manifold and hooking up directly to test pump. (failed test) Purge all hydraulic lines from chart recorder to pressure transmitter.Test directly against transmitter. (failed test). R/U Wellhead Rep Greg Ruge's test pump to pressure transmitter and pressure up against chart recorder. (failed test). Remove chart recorder and replace w/ needle gauge. Needle gauge holding solid pressure. Contact I-rig expediter and have back up chart recorder sent to Endicott. NOTE: ASR chart recorder re-calibrated on 06/12/17 by ACMS in Deadhorse. Crews continue to clean rig. R/U Test Recorder,Test Equipment Shell Test Bope to 3,000psi 5 min (Good Test)Test bop Rams and Valves 250/3,000psi Annular,250,2,500psi,Test Joints 4-1/2 and 3-1/2 (AOGCC Jeff Jones Waived to Witness Bope Test on 6-17-17 @ 5.59am);Well Head Rep Jonny Morrow Tee bar Removed TWC Valve from Hanger Void;Make up 4-1/2 Landing joint into Hanger BOLDS, open IA no Pressure, Pull hanger to the rig Floor Unset Hanger at 90k free pull 132k Break and lay down Tubing Hanger and Landing Joint,Tie off Control Lines to Spooler;Trip out of the hole lay down 4-1/2 TDS Tubing F/Surface to 1,512 '. 37'Joints Spooled up Control Line, Lay down SSSV, Pulled Total of 54'Joints of 4-1/2 TDS, 6". Cross over Pup, Layed Down 16'Joints Vam Top Tubing. 6/20/2017-Tuesday Continue to POOH w/4-1/2" TBG f/ 2,800'md to surface. Cut JNT= 20' 11". Clean and clear rig floor, swap over pipe handling equipment f/4.5" to 3.5".Top off hole to verify fluid depth. 27bbls to fill ="370' md. Load and strap 1 row of 3.5" work string. Strap Baker fishing tools M/U and RIH w/ Baker Fishing bull nose 9-5/8" scraper BHA on 3.5" work string, f/ surface to -1,700'md (58 JNTS). Having to run slower due to fluid running over the top of each joint at higher speeds.Trip in the hole 9-5/8 CSG Scraper on 3.5 RTS-8 work string F/1,700 '.to 3,950'. Having to run slower due to fluid running over the top of each joint at higher speeds. Returns are very Gas up with a heady oil mix R/U Circulating Hose to Flow back tank, Circulate Oil Cap off of well bore to Tank, Pump Rate of 3bpm at 1,000psi Tbg, Pumped 50 bbl to tank, Switch over to Pits Circulate through the gas Buster until Clean Returns Total of 92 Bbl. Pumped Trip in the hole 9-5/8 CSG Scraper on 3.5 RTS- 8 work string F/3,950'. to 8,400 '. Reciprocate Work String at 8,300 '. P/U/W= 70k D/W/N=40k • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date END 3-23 Eline 50-029-21645-00-00 186-155 6/15/17 6/25/17 Daily Operations; _'; 6/21/2017-Wednesday Continue to RIH w/ Baker 9-5/8" scraper BHA on 3.5" work string f/—8,400'md to 10,418'md.Tag up on TBG stump setting down 5klbs. P/U and verify tag depth (10,418'md). Pull wiping rubber and fill hole until fluid level can be seen. POOH watching to ensure fluid level is dropping as we pull. (Fluid level falling, not swabbing the hole). Elevators locking on pipe, set ring appears to be wedging on Vam Ace tapered tool joint.Trouble shoot. Unable to get elevators to release from tool joint so that we can break out joint. Lower elevators to floor level and push slips w/carriage to release. Increase set ring contact area on tapered tool joint. (No success). Service elevators as per manufacturers instructions. Elevators functioning properly again. Continue to POOH w/9-5/8" scraper BHA on 3.5" work string f/"10,300'md to —4,400'md. Service Rig Check Fluids and Grease, Rig Engine Cummins is over heating Installed portable Heater Trunk Blow Cool Air on Generator,. Continue POOH w/9-5/8" scraper BHA on 3.5" work string f/4,400' to 3,950'. Rig Generator is over Heating shut Down Call Endicott Mechanics Brian & Mike, Rig Fan Clutch is out on Rig Carrier engine. Endicott Mechanics' Removed old Clutch Fan From Rig Carrier Engine,. Drove to Milne point VMS Shop Retrieved Spare Fan Clutch, Drove back to Endicott. Endicott Mechanics' on Location Installed New Fan Clutch in Cummins. Continue POOH w/9-5/8" scraper BHA on 3.5" work string f/ 3,950' to —1,800'md. 6/22/2017-Thursday Continue to POOH w/ Baker 9-5/8" scraper BHA f/"1,800'md to surface. L/D BHA and crossovers in prep to ship back to Baker Fishing. Do not top off hole fill once out of hole to allow for faster trip in hole w/ Halliburton cement retainer. M/U Halliburton cement retainer as per Halliburton Rep on location. Ensure brass shear bolt has been drilled out to reduce the tensile rating f/50klbs to 30klbs. Discuss running procedure w/hands RIH. RIH w/ Halliburton cement retainer on 3.5" 9.2ppf RTS-8 work string f/surface to 8,558'md. Easy in and out of the slips, monitoring hook load/drag on the way in hole. Service Rig Check Fluids and Grease. Continued RIH w/ Halliburton cement retainer on 3.5" RTS-8 work string f/8,558'to 10,376'. Rig up to Circulate through Swivel F/10,360' to 10,380', Wash and Reciprocate Work string at 2bpm /240psi P/U/W=89K D/N/W=57K. Set Cement Retainer at 10,376' Rotate pipe 35 turns o the right, Pulled up in 10k increment's Shear out at 122k pulled up 10' rotate another 25 turns to the right, set comfirm. Closed pipe rams P/T Casing 3,000psi (Test Failed) Engineer paul chan was call decision was made to test casing 1,500psi charted min,AOGCC Guy Schwartz. was notified Decision was made to Proceed with cementing.JSA w/Schlumberger IWS Company man, Halliburton Rep, stabbed back into Retainer, P/T Lines 1,500/4,000psi Attempt to injection rate of 2.5 bpm at 3,500psi. Schlumberger Pumped 10 bbl.fresh water at 1.8 bpm at 185psi, mix and Batch Class G cement at 15.8 ppg un sting from retainer Pump 67 bbl. cement down tubing, sting back into retainer pump 58 bbl. Pull up and Un sting Letting 10 bbl 15.8 ppg u-tube and place cement on top of retainer, Lay down 7 joints 10,170' R/U Reverse Circulate Pump 80 bbl.to the pits swapped over to drill cuttings tank till Clean returns,Break and lay down all service lines.Trip out of the hole lay down 3.5 RTS-8 Work String f/ 10,170' to 8,500'. • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date END 3-23 Eline 50-029-21645-00-00 186-155 6/15/17 6/25/17 Daily Operations: ;0-- 6/23/2017- Friday Continue to POOH w/ Halliburton cement retainer running tool on 3.5" work string f/"8500'md to surface. Pollard E-line on location @ 12:00pm in prep for drift run and setting EZ Drill Retainer. Clean and clear rig floor, R/U Pollard E-line in prep for drift run and setting EZ Drill Retainer. RIH w/ Pollard E-line drift assembly consisting of 8.125" gauge ring on 10'junk basket, down to 8700'md to verify hole is clear for setting 9-5/8" EZ Drill Retainer. POOH w/ Pollard E-line drift assembly, R/D drift BHA, M/U Halliburton 9-5/8" EZ Drill Retainer w/wire line adapter setting kit and casing collar locator. RIH w/ Halliburton 9-5/8" EZ Drill Retainer w/wire line adapter setting kit and casing collar locator on E-line. Service Rig Check Fluid and Grease. RIH w/ Halliburton 9-5/8" EZ Drill Retainer w/wire line adapter setting kit and casing collar locator on E- line. ASR Rig RKB 16.3, Original RKB of 36.91 adjusted 20.61 Set Top of CIBP at 8,423 BTM at 8,426, Pooh R/D Pollard E-Line. Tested 9-5/8 Casing f/8423' to Surface 3,000psi 30 min Charted (Good Test).JSA Halliburton Reps, IWS Hands Company Man, Pick up 10' Perf Gun, and 9-5/8 Cement Retainer.TIH 10' Perf Gun 9-5/8 Cement Retainer on 3.5 RTS-8 Work String to 5,940' • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date END 3-23 Eline 50-029-21645-00-00 186-155 6/15/17 6/25/17 Daily Operations. 6/24/2017-Saturday Continue to RIH w/ Halliburton Drill Gun and FasDrill retainer BHA on 3.5" work string f/5940'md to Halliburton bridge plug.Tag bridge plug 18' into jnt 282 and (8,440'md ORKB). P/U/W= 70klbs, S/O/W= 50klbs. Calculate FasDrill retainer setting depth to ensure we leave adequate room for I-rig to set whipstock. Perform PJSM w/ Halliburton, and rig crew for setting retainer, pressure testing, and firing guns. Set FasDrill retainer @ 8326.5'md by rotating 30 times to the right, P/U in 10kIb increments to set sealing elements.At 120klbs hookload, see indication of shear. Rotate another 35 times to the right to release from mandrel. Set down on retainer w/25klbs, close annular and test annulus to 1,000psi f/5mins. Hold pressure on annulus and pressure up TBG to 3000psi, hold for 1min and then dump pressure. Guns fire after 5min. Monitor TBG for pressure,TBG stagnant. Perform injectivity test by pumping @ 0.5BPM = 1,850psi, 1BPM= 2,450psi. PJSM w/SLB, Halliburton, rig crew,to discuss cement pumping plan. Calculate max pump pressure allowable for squeezing cement. Set SLB trips at 3200psi. Fill lines w/fresh water and pressure test to 250psi low,4,000psi high. Pressure bleeding off.Trouble shoot leak. SLB change out seal on pump valve. Pressure up again and note bleed off, chase down leak to Halliburton valve on the IA. Close wellhead IA valve to isolate. (Good Test). Blend mix water and batch up cement to 15.8ppg. Space out so cement retainer running tool stinger is 10'md above the top of retainer. Close annular and pump 10bbI fresh water lead followed by 15bbls of 15.8ppg class G cement, chased with 5bbls of fresh water. Hold back pressure with choke while circulating cement into pipe to reduce cement from falling down hole. Displace cement w/52.9bbls of 9.2ppg brine prior to shutting down pumps and closing choke. At this point cement is 5bbls from exiting the stinger on Halliburton's running tool. Set down into retainer with stinger, setting 10klbs on retainer, wellhead pressure increased as we stung into retainer giving good indication seals on stinger are holding. Squeeze 5bbls of fresh water followed by 11bbls of 15.8ppg class G cement into perforations. Pump @ 1BPM = 2,300psi.TBG pressure didn't fluctuate much while squeezing. Monitor annulus, no pressure seen. Un-sting from retainer with choke open and allow 4bbls of cement inside TBG to U-tube into annulus. Slowly pull out w/JNTS 279, 278, 277, leaving stinger"30'md above TOC. Reverse circulate @ 5BPM= 900psi f/ 120bbls, cement seen @ 70bbls away, cleaned up quickly after 90bbls away, continued to circulate 30bbls to ensure pipe is clean. Shut down, monitor well. Well stagnant. R/D SLB cement. POOH w/ Halliburton cement retainer running tool on 3.5" work string f/ '8,240'md.Service Rig Check Fluids Grease. POOH w/ Halliburton cement retainer running tool on 3.5" RTS-8 work string f/8,240' to 5,940' ASR Rig shut down . Changed out Handling Equipment f/3.5 to 4.5, Load and Tally 3,000' 4.5 Vam Top Tubing on pipe racks.TIH 4.5 Vam Top Tubing 75 joints (2,950') (Tubing was ran open ended with no shoe Attached). Make up landing joint into Hanger, Land hanger RILDS, Break out Landing joint lay down same.Trouble shoot Problem, Damaged Problem, Damaged Ethernet cable was Cut between Drillers console and TCL, Changed out Cable. POOH w/ Halliburton cement retainer running tool on 3.5" RTS-8 work string f/5,940' to Surface, Lay down Halliburton Retainer setting tool. 6/25/2017-Sunday LRS on location to pump freeze protect. Pump 35bbls of diesel down the TBG, line up and allow to U-tube f/30mins. No pressure on TBG or IA. Dean Norris on location to set BPV. Begin R/D M/O process, re-locating ASR from Endicott to Milne Point. 6/26/2017- Monday No activity to report. 6/27/2017-Tuesday No activity to report. • • • y \�� �j�tsA THE STATE Alaska Oil and Gas 44' 's-���- `,4 ofALASKA c Conservation Commission '' ',"A -- ��',�' L1Z�7 f>E �� 333 West Seventh Avenue ''' 7 t ' GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 wh Main: 907.279.1433 0FALAS�� Fax: 907.276.7542 www.aogcc.alaska.gov Bo York Operations Manager Hilcorp Alaska, LLC SCANNED J LI r, . 4 f, 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 Re: Endicott Field,Endicott Oil Pool,DIU SDI 3-23 Permit to Drill Number: 186-155 Sundry Number: 317-221 Dear Mr. York: 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, Cathy P. oerster Chair DATED this ety of June, 2017. RBDMS \,',in - 7 2017 • • RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MAY 312017 O7 8'j APPLICATION FOR SUNDRY APPROVALS / '7 20 AAC 25.280 AOG CC 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 Q• Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other. Reservoir Abandonment •2r 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska LLC • Exploratory 0 Development Q• 186-155 ' 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ 6.API Number ❑ Service Anchorage Alaska 99503 50-029-21645-00-00 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? C.O. 462.007 / Will planned perforations require a spacing exception? Yes ❑ No 0 DUCK IS UNIT SDI 3-23 ' 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0047502 ' ENDICOTT/ENDICOTT OIL • 11. PRESENT WELL CONDITION SUMMARY Total Depth JMD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 111,778',fid,7-17 10,538' 11,655' 10,428' 900 11,655' N/A Casing Length Size MD TVD Burst Collapse Conductor 161' 30" 161' 161' N/A N/A Surface 2,483' 13-3/8" 2,483' 2,483' 5,380psi 2,670P si Production 6,037' 9-5/8" 6,037' 5,739' 6,870psi 4,760psi Production 4,896' 9-5/8" 10,933' 9,789' 8,150psi P 5,090psi Liner 1,095' 7" 11,778' 10,538' 8,160psi 7,020psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(It): 4-1/2" 12.6/L-80/TDS 10,614 3-1/2" 9.2/L-80/TDS 11,166 See Attached Schematic See Attached Schematic 2-7/8" 6.4/L-80/N/A 11,188' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): 9-5/8"X 4-1/2"TIW HBBP,7"x 3-1/2"TIW HBBP,7"x 3-1/2"Otis WD&7"x 3. 10,614'MD/9,513'TVD, 11,166'MD/9,994'TVD,11,365'MD/10,170'TVD&11,430'MD/ 1/2"Otis WD and 4-1/2"SSSV 10,228'TVD and 1,512'MD/1,512'TVD 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: Commencing Operations: 6/16/2017 16.Verbal Approval: Date: GAS Q s•t7WAG ❑ S OR 111SPLUGded � /7 Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned 0 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: Bo York Contact Name: Taylor Wellman-77i Authorized Title: Operations Manager Contact Email: twellmanlahilcorp.com ��3 4(I3 Contact Phone: 777-8449 Authorized Signature: , ✓,,.. Date: 5/26/2017 COMMISSION USE ONLY Conditions of approval:4<otify Commission so that a representative may witness Sundry Number. k7- 221 Plug Integrity ❑ BOP Test [ Mechanical Integrity Test ❑ Location Clearance ❑ Other: >e 3660 ,e;4 go I,, 7:-_--s Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No R Subsequent Form Required: I 0 a y Cj RBDMS !:-- j.;�J - 7 2017 ,O APPROVED BY Approved by: / COMMISSIONER THE COMMISSION Date: 6_ e_ `7 Form 10-40 R vised 4/2017 Submit I-or Oa�rGppl�a�or�s alid for 12 months from the date of approval. Aff ents in Duplicate • n 0 Decompletion Well: END 3-23 Ililcora Alaska,LLQ Date:05/30/2017 Well Name: END 3-23 API Number: 50-029-21645-00-00 Current Status: LTSI Pad: Endicott Estimated Start Date: June 10, 2017 Rig: ASR#1, Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts 777-8398 Permit to Drill Number: 186-155 First Call Engineer: Taylor Wellman (907) 777-8449 (0) (907)947-9533 Second Call Engineer: Stan Porhola (907)777-8412 (0) (907) 331-8228 (M) AFE Number: WeIIEZ Input Required: Yes Current Bottom Hole Pressure: 4,498 psi @ 10,000' TVD (BHP Survey 03/13/17; EMW= 8.65 ppg) Maximum Expected BHP: 4,498 psi @ 10,000' TVD (BHP Survey 03/13/17; EMW= 8.65 ppg) Current Shut-In Tbg Pressure: 900 psi Max. Predicted Surf Pressure: 900 psi (Max tbg pressure recorded w/o plug in talled) L AN-- AS 19 (41--c.. ---- 6t-e_ c 5 6-7-/7 Brief Well Summary: The Endicott 3-23 well was drilled in 1986 and completed in September of 1987. The well was completed as a ultizone producer from the K3A and Upper sub zones in the Kekituk formation. The well developed TxIA �*„ , .,, communication in 2005 and has a secondary seal failure of the IC hanger. The TxIA communication and the limited economic benefit that the well has remaining is the reasoning tchat the well has been a long term/ shut in • since 2005. I CGlCc . rlir (or S«AGI gil`7`"Pit/il fp flaw 7'h,. Via ir`e/�(c' ` f 4 l�,M A , ate car ®f /' 9?%, e41,A, r4,j v�// for fed,,'/, fs('dvWd oaf., Obiective: (or r"pp re 0,1119, 1�i�0A' rrC fetal, 6.f// The objective is to use the ASR #1 to perform a reservoir abanaonmen of the curre formations exposed and o to decomplete the well in preparation for sidetracking the well with the Innovation Rig. Saftey Note: Many wells at Endicott have high H2S readings(>250ppm)in the gas lift or gas injection system. The Endicott 3- 23 well has not flowed since 2005 so accurate sampling has not been obtained but standard precautions and an additional section in the Sundry Review Meeting should be highlighted to handle potential H2S, especially during the circ out and loading of the well. Brief Procedure: Pre-Rig Procedure E-Line 1. RU SL. Pressure test PCE to 250psi low/2000psi high. 2. MU tbg punch toolstring, RIH and punch tubing tail from ±10,628'-10,632' md. a. Correlation Log:Tubing Tally dated 09/23/87. Ib. Well was drifted on 1/25/17 w/a 3.75” gauge ring to 10,624' md. See WSR for full details. 3. MU jet cutter, RIH, and jet cut tubing mid joint in the first full joint above GLM#1 at±10,445' md. a. Note any T/I/0 changes in the WSR. 4. RD EL. Operations& Pumping 5. Clear and level pad area in front of well.Spot rig mats and containment. 6. RD well house and flowlines. Clear and level area around well. 7. RU Little Red Services Pump.Setup reverse out skid and 500 bbl returns tank and additional upright tanks as needed. 8. Pressure test lines to 3,000 psi. II • • Decompletion Well: END 3-23 }Bleary Alaska,LU Date:05/30/2017 9. Forward circulate at least one wellbore volume with 8.8 ppg brine down the tubing(thru tubing cut @ ±10,445' md),taking returns up the annulus to the 500 bbl returns tank. ,A(� a. Annular volume from cut @ 10,445' =560bbls r %I.- b. Tbg volume to the cut @ 10,445'= 159bbls OAc. Total volume =719bbls v) 10. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH or diesel. 11. RD Little Red Services Pump and reverse out skid. 12. RU crane. Set BPV. ND Tree. NU 13-5/8" BOPE. RD crane. 13. NU BOPE house. Spot mud boat. WO Rig Procedure: 14. MIRU Hilcorp ASR#1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. 15. Pull BPV. Bleed any pressure off tubing and casing. 16. Kill well w/8.8 ppg brine as needed. Set TWC. i 17. Test BOPE to 250 psi Low/3,00.0 psi High, annular to 250 psi Low/2,500 psi High (hold each 0.)c V ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. v r a. Perform Test per ASR 1 BOP Test Procedure dated 11/03/2015. �r,7 b. Notify AOGCC 24 hrs in advance of BOP test. c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR rams on 3-1/2" &4-1/2" test joints. 18. Contingency: (If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on.) a. Notify Operations Engineer(Hilcorp), Mr.Guy Schwartz (AOGCC) and Mr.Jim Regg (AOGCC)via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. b. With stack out of the test path,test choke manifold per standard procedure 1,(„ c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor r4 Y the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d. Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed,test the remainder of the system following the normal test procedure (floor valves,gas detection,etc.) f. Record and report this test with notes in the remarks column that the tubing hanger/BPV profile/penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 19. Pull TWC. Bleed any pressure off tubing and casing to 500 bbl returns tank. Kill well w/8.8 ppg brine as needed. 20. MU 4-1/2" landing joint (TDS) and BOLDS. 21. Pull over string weight(PUW's were not recorded during the original completion in 1987)on tubing hanger to confirm free. LD tubing hanger. a. 10,445'of 4-1/2"tubing= 131.6k#dry/113.9k# buoyed in 8.8ppg brine. b. Contingency: (If a rolling test was conducted.) i. MU new hanger or test plug to the completion tubing. Re-land hanger(or test plug) in tubing head. Test BOPE per standard procedure. c. Contingenc If the tubing hanger will not pull and it is determined to be a pulling capacity limitation vs. a partial tubing cut) 61.4:,j- 4 i. RU Casing jack Hydraulics to the ASR#1 control Panel. Set pressure relief high point as 2,038 psi (equates to—230.4k#or 80%of yield strength). <ck-6' k.a 4'7 LA,A- • Decompletion Well: END 3-23 Hilcorp Alaska,LL Date:05/30/2017 ii. Yield strength of 4-1/2", 12.6#, L-80=288k#,and the Mannesmann TDS connections= 288k#. iii. Cycle jacks up and down to ensure proper function (dry run without being connected to hanger). ''4" 3 iv. Set Casing Jack pressure to 1,415 psi (160,000 lbs). Slowly pressure up on jacks. Hold for i ` U1 5 min. v v. If hanger does not unseat, increase pressure in 10k#("88psi) increments holding for 5 min between pressure increases. Note: do not exceed 2,038 psi (230,400#). If unmoved contact Ops Engineer for further discussion. 22. RU Spoolers and continue to pull 4-1/2" tubing from cut at±10,445',and lay down the same in singles. a. From 0—1,512'there are two%" control lines(balance and control line)to the OTIS BVN nipple. 23. PU 3-1/2"workstring and MU 9-5/8" mill and casing scraper assembly. 24. TIH to above tubing stub and reciprocate around the following depths: ±10,400' &±8,300' and (around the cement retainer set depths). POOH. a. Note the PUW's from the bottom to be used for setting the shear pins on the retainers to be used. 25. MU 9-5/8" cement retainer BHA and RIH to±10,400' md. a. Confirm shear pin setting for release from the retainer with the service hand prior to TIH. b. Typical overpull to release from retainer is set to 50k#but can be adjusted. C. ,,, 26. Set cement retainer at±10,400' md. ' •% v a. Rotate the workstring to the right as per the tool service representative for minimum number (cJ�� of turns fully set the retainer. 27. Unsting from the retainer, pick up 20' and conduct an MIT(charted) on the 9-5/8" casing to M"'� 3000psi for 30min. ,t r 28. Sting into the retainer. Line up pumps and obtain injectivity test down the workstring up to 5bpm. G;:ct 29. Unsting from the retainer. 30. Begin mixing cement and pump 65bbls of 15.8ppg Class G cement through the workstring. Once the cement is almost to the retainer,come down on the pumps and sting back into the retainer and pump the cement into the formation. When 7 bbls from fully displacing all cement, come down on pumps, unsting from retainer and then allow final 7bbls to U-Tube out of the pipe. 31. PU 200' above the retainer and reverse circulate with 8.8ppg brine as needed until clean returns are observed. POOH. a. The TOC should be—9f' above the retainer. 32. RU E-Line unit. MU 9-5/8" CIBP toolstring. ,. be 33. RIH and log a CCL pass from ±8,700'to 7,700' md. Set 9-5/8" CIBP at±8,370' md. 34. POOH and RD E-Line unit. cj tv 35. MU cement retainer/perf gun BHA. a. Confirm shear pin setting for pressure required to fire guns with tool service technician. r^ 36. TIH and set retainer at±8,32 f� re- a. Set depth to be adjusted based on the CCL log run with E-Line to ensure not set across a collar. 37. Pressure up the tubing to fire 4-5/8"guns from ±8,330'-8,340' md. te 31/‘ 38. Line up and pump down the workstring to confirm injectivity thru the perforations for-1 bbl. 39. Unsting from the retainer. 40. Begin mixing cement, pump±10bbls of 15.8ppg Class G cement into the workstring. Once the cement is almost to the retainer, come down on pumps and sting back into the retainer. Continue pumping and squeeze the cement through the retainer into the formation. When 2 bbls from fully • • Decompletion Well: END 3-23 FIilcora Alaska,Lb Date:05/30/2017 displacing all cement, come down on pumps, unsting from retainer and PU ±15'. Allow final 2bbls to U-Tube out of the pipe. a. If the formation locks up, unsting from the retainer, and circulate out the remaining cement. 41. While still located with the stinger±15'above the retainer, reverse circulate as needed until clean returns are observed. POOH. a. Alternative way to clean workstring of cement is to launch foam ball and chase with 8.8ppg brine. Method to be determined following the first cement job. 42. POOH while laying down the 3-1/2" workstring. 43. PU 4-1/2" kill string and TIH to±3,000' md. 44. RU Pump Truck. Freeze Protect down back side (±35 bbls.to 500')and allow to U-tube. 45. Land tubing in hanger. RILDS. Lay down landing joint. 46. Set BPV.Test tubing hanger to 250/5,000 psi thru test port. 47. RD Hilcorp ASR#1 WO Rig, ancillary equipment and lines to 500 bbl returns tank. Post-Rig Procedure: 1. RD mud boat. RD BOPE house. Move to next well location. 2. RU crane. Pull BPV. Set TWC. ND BOPE. 3. NU existing 4-1/8" 5,000#tree.Test tree to 250/5,000 psi. Pull TWC. RD crane. 4. Move 500 bbl returns tank and rig mats to next well location. 5. Replace IA&OA pressure gauges if removed. 6. Turn well over to production. RU well house and flowlines. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. BOPE Schematic 4. FWD Circ to Kill Tank Flow Diagram 5. REV Circ to Kill Tank Flow Diagram 6. Bleed to Pits Flow Diagram 7. Blank RWO Changes Form tii • DIU - Endicott • Well: END 3-23 SCHEMATIC Last Completed: 9/25/1987 13ilcorp Alaska,LLC a �` PTD: 186-155 TREE&WELLHEAD OPEN HOLE/CEMENT DETAIL 1 it r-" Tree CIW f 30" Driven Original KBE=55.5'/BFE=16.8' # S_C, Wellhead FMC 3,255 cu.ft.Permafrost,233 Cu.ft. YYWELL INCLINATION DETAIL 13-3/8" permafrost top job in 17-1/2"Hole KOP @ 3,478' 9-5/8" 575 Cu.ft.Class"G"in 12-1/4"Hole 30 Max Hole Angle=38 deg.@ 7,460' 7" 365 cu.ft.Class"G"in 8-1/2"Hole 1 -1 Max angle at Top Perf:28 Deg.@ 11,007' `{ CASING DETAIL 13-3/8" Size Type Wt/Grade/Conn ID Top Btm BPF A� 30" Conductor N/A N/A Surf 161 N/A 13-3/8" Surface 72/L-80/Btrc. 12.347 Surf 2,483' 0.1481 2 9-5/8" Production 47/NT8OS/NSCC 8.681 Surf 6,037' 0.0732 IF3 9-5/8" Production 47/NT95HS/NSCC 8.681 6,037' 10,933' 0.0732 %' 7" Liner 29/L-80/Btrc. 6.184 10,683' 11,778' 0.0371 A 4 TUBING DETAIL lAll 5 _4-1/2" Tubing 12.6/L-80/TDS 3.958 Surf 10,614' 0.0152 3-1/2" _ Tubing 9.2/L-80/TDS 2.992 10,614' 11,166' 0.0087 6 1° 2-7/8" Tubing 6.4/L-80/N/A 2.472 11,166' 11,188' 0.0058 � �J JEWELRY DETAIL j7 'i�� No Depth Item •0• 8 ��+'44 y''ptJ 1 1,512' 4-1/2"SSSV Landing Nip,(3.813"ID) GLM Detail:Camco/RK Latch/2" 2 4,204' ST 6:Port=16,Dev=19,VIv=Dome,TVD=4,190',Date=6-13-2005 s 3 6,830' ST 5:Port=20,Dev=36,VIv=S/O,TVD=6,384',Date=6-13-2005 4 8,644' ST 4:Port=0,Dev=35,VIv=Dummy,TVD=7,838',Date=4-10-2005 10 5 9,720' ST 3:Port=0,Dev=29,VIv=Dummy,TVD=8,746',Date=5-25-1998 3 6 10,292' ST 2:Port=0,Dev=31,VIv=Dummy,TVD=9,237,Date=5-25-1998 7 10,436' ST 1:Port=0,Dev=31,VIv=Dummy,TVD=9,360',Date=4-10-2005 11 8 10,542' 4-1/2"Otis XA Sliding Sleeve,(3.813'ID) pi-t--•,r. 9 10,599' TIW Seal Assembly 10 10,614' 9-5/8"X 4-1/2"TIW HBBP Packer w/latch,(3.928"ID) ' ' 12 --- 11 10,624' 44-1/2"x 3-1/2"XO,(2.992"ID) 12 10,683' 9-5/8"x 7"Baker Liner Hanger 13 11,079' 3-1/2"Otis Ported Nip(2.66'ID) 14 11,091' 3-1/2"Blast Joints(4)(69.25'long) 15 11,166' 7"x 3-1/2"TIW HBBP Packer 9-5/8" ii 16 11,176' 2-7/8"X Nip(2.313"ID) I 13 17 11,182' 2-7/8"X Nip(2.313"ID) 18 11,188 2-7/8"WLEG,(2.441"ID),Bottom @11,189' 14 19 11,365' 7"x 3-1/2"Otis WD Packer 20 11,371' 2-7/8"X Nip(2.313"ID) 21 11,374' 2-7/8"X Nip(2.313"ID) 22 11,377' 2-7/8"WLEG,(2.441"ID),Bottom @11,378' ►.i' ► (, 15 23 11,430' 7"x 3-1/2"Otis WD Packer Mn ID=2.313" 16 24 11,436' 2-7/8"X Nip(2.313"ID) @11,176 -------+1 1 17 25 11,439' 2-7/8"X Nip(2.313"ID) I 18 26 11,442' 2-7/8"WLEG,(2.441"ID),Bottom @11,443' PERFORATION DETAIL MOM WI 19 Sands Top Btm(MD) Top(TVD) Btm(TVD) FT Date Status (MD) 21 UPSZ FIll 11,007' 11,013' 9,854' 9,859' 6 9/19/2001 Open I I 22 UPSZ FIll 11,018' 11,032' 9,864' 9,876' 14 9/19/2001 Open UPSZ Fill 11,048' 11,054' 9,890' 9,895' 6 9/15/2001 Open it 23 UPSZ FII 11,100' 11,132' 9,936' 9,964' 32 9/21/1987 Open 24 UPSZ FII 11,110' 11,130' 9,945' 9,962' 20 11/08/1998 Open 25 UPSZ Fl 11,150' 11,158' 9,980' 9,987' 8 9/22/1987 Open 26 S3A4 11,224' 11,258' 10,045' 10,075' 34 9/21/1987 Open S3A3 11,266' 11,304' 10,082' 10,116' 38 9/21/1987 Open eg S3A2 11,340' 11,354' 10,148' 10,160' 14 9/21/1987 Open GENERAL WELL INFO SAFETY NOTE: TD=11,778'(MD)/TD=10,538'(TVD) PBTD=11,655'(MD)/PBTD=10,428(TVD) API:50-029-21645-00-00 H2S readings average 230-260 ppm on A/L and Completed-9/25/1987 gas injectors.Well requires a SSSV.Possible cement sheath in tubing from packer squeeze(1- 5-1998).Chrome tubing,liner and jewelry. Revised By:DH 4/10/2017 H0 DIU - Endicott • Well: END 3-23 SCHEMATIC PROPOSED Last Completed: 9/25/1987 Hilcorp Alaska,ILC PTD: 186-155 TREE&WELLHEAD OPEN HOLE/CEMENT DETAIL Tree CIW 30" Driven Original KBE=55.5'/BFE=16.8' Wellhead FMC 3,255 cu.ft.Permafrost,233 cu.ft. WELL INCLINATION DETAIL 13-3/8" Permafrost top job in 17-1/2"Hole KOP @ 3,478' 9-5/8" 575 cu.ft.Class"G"in 12-1/4"Hole 30 Max Hole Angle=38 deg.@ 7,460' g g 7" 365 cu.ft.Class"G"in 8-1/r Hole Max angle at Top Perf:28 Deg.@ 11,007' CASING DETAIL 133/8" 1b 8e' Size Type Wt/Grade/Conn ID Top Btm BPF 30" Conductor N/A N/A Surf 161 N/A 4.614.. - " 13-3/8" Surface 72/L-80/Btrc. 12.347 Surf 2,483' 0.1481 9-5/8" Production 47/NT80S/NSCC 8.681 Surf 6,037' 0.0732 / 4/ 9-5/8" Production 47/NT95HS/NSCC 8.681 6,037' 10,933' 0.0732 TOC @ / 7" Liner 29/L-80/Btrc. 6.184 10,683' 11,778' 0.0371 ±8,305' l TUBING DETAIL 4-1/2" Tubing 12.6/L-80/TDS 3.958 Surf ±3,000' 0.0152 '' 2 17 JEWELRY DETAIL TOC@ No Depth Item ±10,304' 1 ±8,320' 9-5/8"Cement Retainer/Pert Gun ±10,,.. • " 2 ±8,370' 9-5/8"CIBP - 1: 4 3 ±10,400' 9-5/8"Cement Retainer ,,- -,, 5 4 10,436' ST 1:Port=0,Dev=31,VIv=Dummy,TVD=9,360',Date=4-10-2005 5 10,542' 4-1/2"Otis XA Sliding Sleeve,(3.813'ID) 6 6 10,599' TIW Seal Assembly 7 10,614' 9-5/8"X 4-1/2"TIW HBBP Packer w/latch,(3.928"ID) 7 8 10,624' 4-1/2"x 3-1/2"XO,(2.992"ID) .. - 9 10,683' 9-5/8"x 7"Baker Liner Hanger 10 11,079' 3-1/2"Otis Ported Nip(2.66'ID) 8 11 11,091' 3-1/2"Blast Joints(4)(69.25'long) 12 11,166' 7"x 3-1/2"TIW HBBP Packer 13 11,176' 2-7/8"X Nip(2.313"ID) 9 14 11,182' 2-7/8"X Nip(2.313"ID) 15 11,188 2-7/8"WLEG,(2.441"ID),Bottom @11,189' 16 11,365' 7"x 3-1/2"Otis WD Packer 17 11,371' 2-7/8"X Nip(2.313"ID) 18 11,374' 2-7/8"X Nip(2.313"ID) 9-5/8" 11 19 11,377' 2-7/8"WLEG,(2.441"ID),Bottom @11,378' 1 10 20 11,430' 7"x 3-1/2"Otis WD Packer 21 11,436' 2-7/8"X Nip(2.313"ID) 11 22 11,439' 2-7/8"X Nip(2.313"ID) IA 23 11,442' 2-7/8"WLEG,(2.441"ID),Bottom @11,443' • PERFORATION DETAIL 12 Sands Top MnX2.313" 13 Btm(MD) Top(ND) Btm(ND) FT Date Status @11,176' I I 14 (MD) I. I ±8,210' ±8,220' 6 Future Future 15 UPSZ Fill 11,007' 11,013' 9,854' 9,859' 6 9/19/2001 Closed • UPSZ FIll 11,018' 11,032' 9,864' 9,876' 14 9/19/2001 Closed " 16 UPSZ FIll 11,048' 11,054' 9,890' 9,895' 6 9/15/2001 Closed UPSZ FII 11,100' 11,132' 9,936' 9,964' 32 9/21/1987 Closed I I 17 UPSZ FII 11,110' 11,130' 9,945' 9,962' 20 11/08/1998 Closed I I . 18 . 19 UPSZ Fl 11,150' 11,158' 9,980' 9,987' 8 9/22/1987 Closed S3A4 11,224' 11,258' 10,045' 10,075' 34 9/21/1987 Closed 2°1S3A3 11,266' 11,304' 10,082' 10,116' 38 9/21/1987 Closed x S3A2 11,340 11,354' 10,148' 10,160 14 9/21/1987 Closed 21 S3A1 11,390' 11,414' 10,192' 10,214' 24 9/21/1987 Open 22 rr...a• 23 GENERAL WELL INFO SAFETY NOTE: API:50-029-21645-00-00 H2S readings average 230-260 ppm on A/L and 7" ,' Completed-9/25/1987 gas injectors.Well requires a SSSV.Possible TD=11,778'(MD)/TD=10,538'(TVD) cement sheath in tubing from packer squeeze(1- PBTD=11,655'(MD)/PBTD=10,428'(TVD) 5-1998).Chrome tubing,liner and jewelry. Revised By:TTW 5/22/2017 III Milne Point 2016 ASR Rig ai uii.,,f�.: ��.a_t,�.I.r. Knight Oil Tools 130P 4 (`Stripping Head w r r►k_ay Shaffer ,s, . � . . 11" - 5000 I11 iff ill iii in fp iii III in ill _Atimaitst2 7/8" —5" VBR -_ Cf -u r , 4 ciao ' 11"` -� 000 ,._y Blind .O - 2" Kill Line _�_ m" 2" Choke Line rz„,") ,r.1, I Frir..nrun ::: i l a L - # ? -F iLU'i ISS kg( 0 ,N friliminfrgirt - ' Manual Manual :._ __ Manual HCR Updated 2/29/16 • 0 1 | ® §/ < D11 §� J#) . * _ ° A maa E . .a f `\ k § — E § ({ k q ; \ ) ) 3 ) a | < § 2 /..--gi@ co ow 1,04 . . .. . mi O \e ® \ \ P. §§ - \ §§ ) T I § CC4 � § 2 ƒD§ ) ...5 I,' '2 [ O S§ k ) < 93 gl. ,, ) $ A 8 .. lg. _ § } § ) ! 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I � � 0. -0 t v H .{� n (PijJa f�� Q.`' V 1 2 a C W ac m a o 13 CO T I .. -Grn g ay ,-f J-- g 0 1 ' 931 Y 3 -N- � g -N -t4- i N- -{a}- —RJ_ -N-— 1gal01 Li tie" 01 t . • • a) £ 2 \ k / ƒ w � ) cc wow _ D ) m0 ■ ■ E — 0m00 o c O c ■ -0 a) ? 222 / E 2 c( / a ■ 71 -a_ .E k 7 0 Ti 2 . « ° mJ § _ _ � o_ ED_ « g'c co a a)o• w 2 a) m ® « kmJ CI k \ cm I � _ / � . _ Uf o go CI _0 2 n 2 & a 2o.m 2 0_ c & - eL g/ gil - c & O 2/ § OS O 2O .c li c00 a) E « Ts o b13 6- ,.Z 7 / .E S cC o a) e o a. � � C co ig 13 a^ƒ la 43 c § c @ "0 Q9 C W 0 13 a) CU - 0c 11 0. / 0 cu O // �c co d 0. X � � § k O _ m Q eetin a) x 3 § a w % 2 0 . co k w 0 C0 W / � « .. 2 g a E a) -a E 0 CI) CO g > k o a V at 2 Cl) k 0 0 • Schwartz, Guy L (DOA) From: Taylor Wellman <twellman@hilcorp.com> Sent: Wednesday,June 07, 2017 3:48 PM To: Schwartz, Guy L(DOA) Cc: Bettis, Patricia K(DOA) Subject: RE: SDI 3-23 P &A for sidetrack(PTD 186-155) Attachments: END 3-23 tree and hangers-PDF.PDF Mr. Schwartz, Enclosed are some responses to your questions in red below. I'll send the other email request to question 2 for the MASP justification. If you would like any further information please let me know. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC—Ops Engineer: Endicott& Northstar Office: (907)777-8449 Cell: (907)947-9533 Email:twellman@hilcorp.com<mailto:twellman@hilcorp.com> From:Schwartz, Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent:Tuesday,June 06, 2017 9:55 AM To:Taylor Wellman Cc: Bettis, Patricia K(DOA) Subject: SDI 3-23 P &A for sidetrack(PTD 186-155) Taylor, Couple of questions for you. 1. Can you provide a wellhead drawing. Atta ed. ''t". 2. Since you are using SITP of 900 psi for MASP can you request that officially per 20 AAC 25.280 (b)(4). Email is ok.. I'll send this as a separate request in an email. 1:m;-- 3. -3. Why are you using the retainer/gun combo?Assume it is for placing cement in OH annulus to facilitate the window milling.(This is correct. The cement in the OH annulus is purely to attempt to support the window) 4. Need additional steps outlined for when the Innovation rig gets there to start sidetrack.. up till window is cut. lie, The steps post the ASR procedure would be as below. Note that these steps steps will be re-iterated in the drilling permit. yA.�Lii.1` y �•„ ,,.;. vti.., /`., S T )( 1. MIT casing to 1500psi. 2. RU Innovation—Set BPV, ND tree, NU BOP's, pull BPV, set TWC,test BOP's, pull TWC. 3. Pull 4-1/2” kill string 4. Set 9-5/8" storm packer .__--, 7 ,r ., ,_ ,_ 1 • 5. ND BOP's,change-out 9-5/8"casing pack-off, NU BOP's, BOP test 6. Pull 9-5/8" storm packer 7. MU whipstock/milling BHA(single run system). TIH and set whipstock on TOC on top of retainer and begin milling window. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at(907-793- 1226)or(Guy.schwartz@alaska.gov<mailto:Guy.schwartz@alaska.gov>). 2 • • End 3-23 6-6-17 Swab Valve CIW 4 1/16" 5K, manual gate valve, EE PSL2,PR2 MI AS PN 141522-31-02-01 —0,4$, Wing valve CIW FL-4 1/16" 5K, reverse actuating gate 0 0-6'0 valve, EE.PSL2,PR2 w/CIW r 03/03 actuator. Assy PN �� \� SSV CIW FL-4 1/16" 5K, oji v p o reverse actuating gate valve, EE.PSL2,PR2 w/CIW 03/03 c4tgr1-02-01 O r Assy PN Master CIW 4 1/16" 5K„ Note,this tbg HGr can be imir manual gate valve, EE plugged on top for BOPE PSL2,PR2 equipment testing P' n PN 141522-31-02-01 o v00 O O O, Tbg Hd adapter FMC 11" 5K Tbg Hgr- FMC 11 x4 W , L1 (fel Tbg 4 1/16" 5K, w/tea %" 1/2 w/41/2"TDS runing thread x 4%2"TDS control line preps. bottom, w/4" "H" BPV n Centralized PN prep and 2ea control ENTIIMmiNII ,141- 111." lines 1 r rioN _I_ ..•im 11 II II- ®1'7-- Till vii, � �• � o 0 0� - I- 111 i iio CseHer-133/8x95/8FMC ,,, mandrel casing hanger with Tbg Spool FMC =■oto , I :; "'p0i packoff assy 11" 5Kx135/83K: w/ 1!, mi Zea 2 1/16" 5K outs _ _ r 11 `:1311 _-. • • Schwartz, Guy L (DOA) From: Taylor Wellman <twellman@hilcorp.com> Sent: Wednesday,June 07,2017 8:20 AM To: Schwartz, Guy L(DOA) Cc: Bettis, Patricia K(DOA) Subject: END SDI 3-23 P&A for Sidetrack MASP Justification (PTD#186-155) Mr.Schwartz, For the proposed MASP calculation for the 10-403 application for well END SDI 3-23(PTD#186-155) is based on the stabilized wellhead pressure as an alternative to using the 0.1psi/gradient as outlined in 20 AAC 25.280(b)(4). The well has been shut in Nov 2005 and was secured with a PX plug in the tubing tail in Nov 2008. At the time of shut in the well was producing 99%WC. In Jan 2017 the tubing plug was pulled in order to complete diagnostics and logging for sidetrack evaluation. The tubing has been open to formation since Jan 2017 and the WHP has stabilized at 900psi. Therefore the proposed MASP for the reservoir abandonment is proposed to be 900psi. Please contact me with any questions or comments. Thank you, Taylor Taylor Wellman Hilcorp Alaska, LLC—Ops Engineer: Endicott&Northstar Office: (907)777-8449 Cell: (907)947-9533 Email:twellman@hilcorp.com • • Schwartz, Guy L (DOA) From: Schwartz,Guy L(DOA) Sent: Tuesday,June 06,2017 9:55 AM To: Taylor Wellman Cc: Bettis, Patricia K(DOA) Subject: SDI 3-23 P&A for sidetrack(PTD 186-155) Taylor, Couple of questions for you. 1) Can you provide a wellhead drawing. 2) Since you are using SITP of 900 psi for MASP can you request that officially per 20 AAC 25.280(b)(4). Email is ok.. 3) Why are you using the retainer/gun combo?Assume it is for placing cement in OH annulus to facilitate the window milling. 4) Need additional steps outlined for when the Innovation rig gets there to start sidetrack.. up till window is cut. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). 1 • • __..__._.. _-_._.-.-._._-_.-__-..._._.._._._____._._.____._ �_--- -_ ,N ., Thousand Cubic Feet of Gas ("MCF") per Day or Gas-Oil Ratio (MCF per Barrel) O O O O O O O O O O OO O O C O O O O O IN ei O. 00 ,-N O i cc lro�4 O0 -' �°t I E 1 Slob o O i y �� m Frog (13 4Or v -o U CGJ O jl -o u ++ o� o 0 ca Ota a` ct r v 600 E N �4P cif r M _1w 4 ; . o Lep; zit'O C ' � � -a r5 0. co vtc S 0- o Oe � t 0i L Z O c 1 °°z 4 E 2 __ o o E I o u a a` a __ ropy o 4 Q 3 3 3 Pr Q U U U -0 CU '. a j 66 V a) w__ sr 4P r p i P ' • • Sundry Application Plug for Re-drill Wells Work Flow This process is used to identify wells that are suspended for a very short time prior to being re- drilled. Those wells that are not re-drilled immediately are identified every 6 months and assigned a current status of"Suspended." Step Task Responsible 1 The initial reviewer will check to ensure that the "Plug for Redrill"box Geologist in the upper left corner of Form 10-403 is checked. If the "Abandon" or fr "Suspend" boxes are also checked, cross out that erroneous entry and initial it on both copies of the Form 10-403 (AOGCC's and operator's copies). 2 If the "Abandon" box is checked in Box 15 (Well Status after proposed Geologist fi work)the initial reviewer will cross out that erroneous entry and initial then ! it on both copies of the Form 10-403 (AOGCC's and operator's copies). I/ Instead, check the "Suspended"box and initial that change. Drilling Engineer The drilling engineers will serve as quality control for steps 1 and 2. (QC) 3 When the Stat Tech receives a Form 10-403 with a check in the "Plug Stat Tech for Redrill" box, they will enter the Typ_Work code "IPBRD" into the History tab for the well in RBDMS. This code automatically generates a comment in the well history that states "Intent: Plug for Redrill." 4 When the Stat Tech receives any Form 10-407, they will check the Stat Tech History tab in RBDMS for the "Intent: Plug for Redrill" code (IPBRD). If present and there is no evidence that a subsequent re-drill has been COMPLETED, the Stat Tech will assign a status of SUSPENDED to the well bore in RBDMS no matter what status is listed on the 10-407. The Stat Tech will also change the status on the 10-407 form to SUSPENDED, and date and initial this change. If the Stat Tech does not see the "Intent: Plug for Redrill" comment or code, they will enter the status listed on the Form 10-407 into RBDMS. 5 When the Form 10-407 for the redrill is received, the Stat Tech will Stat Tech change the original well's status from SUSPENDED to ABANDONED. 6 The first week of every January and July, the Stat Tech and one of the Stat Tech Geologists will check the "Well by Type Work Outstanding"user query Geologist in RBDMS to ensure that all of the Plug for Redrill wells have been handled properly. At this same time, they will also review the list of suspended wells for accuracy. • • RECEIVED Post Office Box 244027 Anchorage,AK 99524-4027 Hilcorp Alaska,LLC JUL 3 0 201`1 3800 Centerpoint Drive Suite 100 ACCAnchorage,AK 99503 Phone: 907/777-8300 Fax: 907/777.-8301 July 29, 2015 Commissioner Cathy Foerster Alaska Oil & Gas Conservation Commission g.6 333 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 3 - D-3 Re: Duck Island Unit Well Renaming Request Dear Commissioner Foerster, Hilcorp Alaska, LLC (HAK) requests a change to the naming convention of Duck Island Unit wells to remove the unused suffixes at the end of each well name. Well names currently include a forward slash "I" followed by an obsolete bottom hole location designator. HAK would like to retain the well number as well as the "A, B, C...." sidetrack designations but remove the "/suffix". For example, "DUCK IS UNIT SDI 1-09A/L21" would become "DUCK IS UNIT SDI 1-09A". The attached spreadsheet includes original and new names for all Duck Island wells. While performing the review of Duck Island well names, HAK found a single well, "DUCK IS UNIT SDI 4-20/M35" (PTD# 1861730), that should also be modified to include an "A" label to reflect the fact that the well is a sidetrack from the original "DUCK IS UNIT SDI 4-20/T34" (PTD # 1861500). The original wellbore, abandoned 10/13/1986, was sidetracked to a new bottom hole location completed on 9/9/1987. This well appears to be one of the first sidetracks performed at Endicott. While the bottom hole code was changed, no letter was added to reflect the sidetrack. "DUCK IS UNIT SDI 4-20A" is also included on the attached spreadsheet. Sincerely, Wyatt Rivard Well Integrity Engineer Hilcorp Alaska, LLC CC Dave Roby Victoria Loepp • Orig New I API_WeilNo I PermitNumberl WellName I WellNumber I WellNumber 50029219460600 2032160 DUCK IS UNIT SDI 3-17F/K30 3-17F 50029224630000 1940490 DUCK IS UNIT SDI 3-19/R28 3-19 50029217140000 1870330 DUCK IS UNIT SDI 3-21/L34 3-21 50029217149500 1980190 DUCK IS UNIT SDI 3-21AK35XX 3-21AXX 50029216450000 1861550 DUCK IS UNIT SDI 3-23/N32 3-23 50029221250000 1901820 DUCK IS UNIT SDI 3-25/M27 3-25 50029221250100 2010200 DUCK IS UNIT SDI 3-25A/N24 3-25A 50029221250200 2030210 DUCK IS UNIT SDI 3-25B/L27 3-25B 50029215860000 1860830 DUCK IS UNIT SDI 3-27/M33 3-27 50029221060000 1901560 DUCK IS UNIT SDI 3-29/J32 3-29 50029228380000 1972270 DUCK IS UNIT SDI 3-31/K32 3-31 50029216680000 1861800 DUCK IS UNIT SDI 3-33/K37 3-33 50029216680100 2032150 DUCK IS UNIT SDI 3-33A/J35 3-33A 50029217010000 1870200 DUCK IS UNIT SDI 3-35/136 3-35 50029225540000 1950510 DUCK IS UNIT SDI 3-37/L35 3-37 50029217640000 1871160 DUCK IS UNIT SDI 3-39/J39 3-39 50029217640100 1970910 DUCK IS UNIT SDI 3-39A/I37 3-39A 50029218780000 1881260 DUCK IS UNIT SDI 3-41/K39 3-41 50029224160000 1931700 DUCK IS UNIT SDI 3-43/P36 3-43 50029218110000 1880510 DUCK IS UNIT SDI 3-45/M39 3-45 50029215690000 1860640 DUCK IS UNIT SDI 3-47/Q35 3-47 50029217350000 1870600 DUCK IS UNIT SDI 3-49/140 3-49 50029217350200 1970570 DUCK IS UNIT SDI 3-49A/M40 3-49A 50029217359500 1950350 DUCK IS UNIT SDI 3-49AJ40XX 3-49AXX 50029217890000 1880220 DUCK IS UNIT SDI 4-02/Q28 4-02 50029219680000 1890860 DUCK IS UNIT SDI 4-04/T26 4-04 50029219680100 2090190 DUCK IS UNIT SDI 4-04A/T30 4-04A 50029217230000 1870430 DUCK IS UNIT SDI 4-06/Q32 4-06 50029217230100 1961660 DUCK IS UNIT SDI 4-06A/Q30 4-06A 50029216920000 1870080 DUCK IS UNIT SDI 4-08/P27 4-08 50029224640000 1940500 DUCK IS UNIT SDI 4-10/M28 4-10 50029224640100 2022380 DUCK IS UNIT SDI 4-10A/L28 4-10A 50029218630000 1881040 DUCK IS UNIT SDI 4-14/R34 4-14 50029218630100 2080120 DUCK IS UNIT SDI 4-14A/S-37 4-14A 50029218960000 1881490 DUCK IS UNIT SDI 4-18/S30 4-18 50029216400100 1861730 DUCK IS UNIT SDI 4-20/M35 4-20A 50029216400000 1861500 DUCK IS UNIT SDI 4-20/T34 4-20 50029218350000 1880720 DUCK IS UNIT SDI 4-26/034 4-26 50029218700000 1881110 DUCK IS UNIT SDI 4-28/N37 4-28 50029225590000 1950690 DUCK IS UNIT SDI 4-32/K38 4-32 50029227050000 1961550 DUCK IS UNIT SDI 4-34/038 4-34 50029224820000 1940740 DUCK IS UNIT SDI 4-38/K34 4-38 50029222650000 1920420 DUCK IS UNIT SDI 4-40/P43 4-40 50029217310000 1870560 DUCK IS UNIT SDI 4-42/P38 4-42 50029222540000 1920190 DUCK IS UNIT SDI 4-44/M44 4-44 50029222549500 1970470 DUCK IS UNIT SDI 4-44AM40XX 4-44AXX 50029219570000 1890690 DUCK IS UNIT SDI 4-46/N39 4-46 50029219720000 1890970 DUCK IS UNIT SDI 4-48/K43 4-48 50029219400000 1890440 DUCK IS UNIT SDI 4-50/K41 4-50 Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning. They are available in the original file, may be scanned during the rescan activity or are viewable by direct inspection of the file. 7~'7- / ~,.~.,%'*""~-"'~Well History File Identifier RESCAN DIGITAL DATA [] Color items: [] Diskettes, No. [] Grayscale items: [] Other, No/Type [] Poor Quality Originals: TOTAL PAGES: ~/~'-' NOTES: ORGANIZED BY: REN VINCENT SHERYL MARIA LOWELL Project Proofing OVERSIZED (Scannable) [] Maps: ther items scannable by large scanner OVERSIZED (Non-Scannable) .~Logs of various kinds [] Other [] Staff Proof By: Date: PROOFED BY: BEVERLY BREN VINCENT SHERYL MARIA LOWELL DATE: /SI PAGES: ~ / ,~a(at the time of scanning) SCANNED BY: BEVERLY Bi~'~HERYL MARIA LOWELL ReScanned (done) RESCANNEDBY: BEVERLY BREN VINCENT SHERYL MARIA LOWELL DATE; Is~ General Notes or Comments about this file: PAGES: Quality Checked (done) • • bp BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB -20 Post Office Box 196612 Anchorage, Alaska 99519 -6612 May 22, 2012 5 a S E P A c 0 L Mr. Jim Regg Alaska Oil and Gas Conservation Commission 3 333 West 7 Avenue l Anchora Alaska 99501 3 5' 9:31N- • Subject: Corrosion Inhibitor Treatments of Endicott Row 3 Dear Mr. Regg, Enclosed please find multiple copies of a spreadsheet with a list of wells from Endicott Row 3 that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, API and PTD numbers, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10 -404, Report of Sundry Operations. If you require any additional information, please contact me or my alternate, Gerald Murphy, at 659 -5102. Sincerely, Mehreen Vazir BPXA, Well Integrity Coordinator • • BP Exploration (Alaska) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10-404) Endicott Row 3 Date: 10/03/10 Corrosion Initial top of Vol. of cement Final top of Cement top off Corrosion inhibitor/ Well Name PTD # API # cement pumped cement date inhibitor sealant date ft bbls ft na gal END3 -01 / N -29 1861900 50029216780000 7.0 4.4 0.3 9/6/2010 1.70 10/3/2010 END3 -03 / J-33 1921210 50029223060000 8.0 6.1 0.3 9/6/2010 2.55 10/3/2010 END3 -05 / 0 -29 1861300 50029216240000 3.0 2.0 0.5 9/6/2010 3.40 10/3/2010 END3 -07A / L -29 1981470 50029219110100 2.0 0.5 0.3 9/6/2010 1.70 10/3/2010 END3 -09 / L -28A 1950190 50029217800100 0.1 NA 0.1 NA 1.00 10/3/2010 END3 -15 / K-33 1870940 50029217510000 0.1 NA 0.1 NA 1.00 10/3/2010 END3 -17F / K -30 2032160 50029219460600 1.5 0.5 0.5 9/6/2010 2.55 10/3/2010 END3 -19 / R -28 1940490 50029224630000 10.0 17.0 0.3 9/6/2010 1.70 10/3/2010 END3 -21 / L -34 1870330 50029217140000 23.0 14.5 1.1 9/6/2010 13.60 1013/2010 �� END3 -23 / N-32 1861550 50029216450000 1.5 1.0 0.5 9/6/2010 3.40 10/3/2010 END3 -27 / M-33 1860830 50029215860000 1.0 0.1 0.6 9/6/2010 2.55 10(2/2010 I END3 -29 / J-32 1901560 50029221060000 2.0 1.0 0.6 9/6/2010 3.40 10/2/2010 END3 -31 / K -32 1972270 50029228380000 2.0 3.0 0.5 9/6/2010 3.40 10/2/2010 END3 -33A / J -35 2032150 50029216680100 0.5 NA 0.5 NA 3.40 10/2/2010 END3 -35 / L -36 1870200 50029217010000 10.0 _ 7.0 0.4 9/6/2010 3.40 10(2/2010 END3-37 / L -35 1950510 50029225540000 8.0 7.3 0.3 9/6/2010 1.70 10/2/2010 END3 -39A /1-37 1970910 50029217640100 1.0 0.8 0.7 9/6/2010 3.40 10/2/2010 END3 -49A / M -40 1970570 50029217350200 0.4 NA 0.4 NA 1.70 10/2/2010 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown_ Stimulate_ Plugging _ Perforate _J~ AD-PERFS Pull tubing _ Alter casing _ Repair well _ 2. Name of Operator BP Exploration (Alaska), Inc. 3. Address P. O. Box 196612 Anchorage, AK 99519-6612 4. Location of well at surface 2519' FNL, 768' FEL, Sec. 08, T11 N, R17E, UM At top of productive interval 3769' FNL, 1013' FEL, Sec. 05, T11N, R17E, UM At effective depth 1422' FSL, 1010' FEL, Sec. 05, T11N, R17E, UM At total depth 1712' FSL, 976' FEL, Sec. 05, TllN, R17E, UM 5. Type of Well: Development __X Explorato~__ Stratigraphic__ Service__ (asp's 270273, 5970978) (asp's n/a) (asp's 270141, 5974926) (asp's 270183, 5975214) Other_ W ~ 6. Datum elevation (DF or KB feet~ c-.,j RKB 55 feet ~ ~ 7. Unit or Property name ~ ~ Duck Island Unit / Endicott 8. Well number ~ 3-23 / N-32 SDI 9. Permit number / approval number 186-155 10. APl number 50-029-21645 11. Field / Pool Endicott Oil Pool °I 12. Present well condition summary Total depth: measured true vertical 11778 feet Plugs (measured) 10538 feet Effective depth: measured 11143 feet Junk (measured) true vertical 9974 feet 2-7/8" X-Plug set @ 11170'. (05/16/1998) TD Tag @ 11143' WLM (07/07/2001) Casing Length Size Cemented Measured Depth True Vertical Depth Conductor 122' 30" Driven 161' 161' Surface 2443' 13-3/8" 3255 c.f. Permafrost 2482' 2482' Intermediate 10894' 9-5/8" 575 c.f. Class 'G' 10933' 9789' Liner 1096' 7" 365 c.f. Class 'G' 10682' - 11778' 9572' - 10538' Perforation depth: measured Open Perfs 11007 - 11013, 11018 - 11032, 11047 - 11054, 11100 - 11132, 11150 - 11158, Open Perfs below TBG Plug 11224 - 11258, 11266 - 11304, 11340 - 11354, 11390 - 11414. true vertical Open Perfs 9854'- 9859', 9864'- 9876', 9890'- 9896', 9936'- 9963', 9980'- 9987', Open Perfs below TBG Plug 10046- 10076, 10083- 10116, 10148- 10161, 10193- 10214. 4-1/2", 12.6#, L-80 TBG to 10614' MD. 3-1/2", 9.6#, L-80 Isolation Asemly f/10614' to 11166'. 3-1/2" Tubing tail @ 11189'. 9-5/8" x 4-1/2" TIW 'HB BPR' PKR @ 10614'. 7" x 3-1/2" TIW 'HB BPR' PKR @ 11166'. 7" OTIS 'WD' PKR's W/2-7/8" 'X' NIPPLES set @ 11365' & 11430'. 4-1/2" SSSV LN @ 1512'. 13. Stimulation or cement squeeze summary Intervals treated (measured) (see attached) Treatment description including volumes used and final pressure Tubing (size, grade, and measured depth) Packers & SSSV (type & measured depth) 14. Prior to well operation 09/01/2001 Subsequent to operation 09/21/2001 Representative Daily Averaqe Production or Iniection Data Oil-Bbl Gas-Mcr Water-Bbl Casing Pressure Tubing Pressure SHUT-IN 24 417 1412 GL 993 15. Attachments Copies of Logs and Surveys run __ Daily Report of Well Operations __ 16. Status of well classification as: Oil __ X Gas __ Suspended __ Service __ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ,~~,~//~ ~j~ Title: Technical Assistant DeWayne R. Schnorr Form 10-404 Rev 06/15/88 · Date September 26, 2001 Prepared by DeWayne R. Schnorr 564-5174 SUBMIT IN DUPLICATE 3-23/N-23 SDI Description of Work Completed NRWO OPERATIONS 05/23/2001 07/07/2001 08/31/2001 09/15/2001 SBHP/FBHP SURVEY: STATIC SURVEY PERF(ADD-PERF): PULL SSSV, DRIFT W/DUMMY GUN PERF(ADD-PERF): PERFORATION PERF(ADD-PERF): ADD-PERFS SUMMARY 05/23/01 PERFORMED SIBHPS W/SPARTEK GAUGES TVD MD WLM BHSIP BHSIT TIME 9800 11009 10970 4813.2 208.7 15MIN 9900 11123 11084 4857.0 211.0 60MIN 9800 11009 10970 4813.8 209.0 15MIN 07/07/01 PULLED SSSV. RAN 2.50" X 10' DUMMY GUN AS FAR AS 11143' WLM. 08/31/01 UNABLE TO SHOOT INTERVALS DUE A DOUBTFUL CORRELATION. JEWELRY LOG DONE. 09/15/01 PERFORATED 11048' - 11054', 11018' - 11032' AND 11007' - 11013' W/2.5" POWERJET 6 SPF, 60 DEGREE PHASING AND RANDOM ORIENTATION. Fluids Pumped 3 DIESEL FOR SURFACE EQUIP PRESSURE TEST (3 DIFFERENT TESTS) 3 TOTAL 09/15/2001 ADD-PERFS SUMMARY THE FOLLOWING INTERVALS WERE PERFORATED USING 2-1/2" POWERJET 6 SPF, 60 DEGREE PHASING, RANDOM ORIENTATION. 11007' - 11013' 11018' - 11032' 11048' - 11054' Page 1 MICROFILMED 9/11/00 Do ~o-r P~-,~cE ANY NEW MATERIAL UNDER THIS PAGE STATE OF ALASKA ALASK.; .... L AND GAS CONSERVATION COMMISSIC'~' REPORT O, SUNDRY WELL OPE,.ATIONS 1. Op6;~ttions?~oerformed:' Operation shutdown__ Stimulate X Plugging__ Perforate X Pull tubing__ Alter casing __ Repair well __ Other__ 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P. O. Box 196612, Anchora_c/e, Alaska 99519-6612 5. Type of Well: Development Exploratory Stratigraphic Service 4. Location of well at surface 2520' SNL, 769' WEL, Sec. 8, T11N, R 17E At top of productive interval 3769' SNL, 1013' WEL, Sec. 5, T11N, R17E At effective depth 3608' SNL, 1003' WEL, Sec. 5, T11N, R17E At total depth 3565' SNL, 989' WEL, Sec. 5, T11N, R17E 12. Present well condition summary Total depth: measured true vertical 11783 feet Plugs (measured) 10543 BKB feet 11158' MD Effective depth: measured 11686 feet Junk (measured) true vertical 10456 BKB feet 6. Datum elevation (DF or KB) KBE = 55.48 feet 7. Unit or Property name Duck Island Unit/Endicott 8. Well number 3-23/N-32 SDI 9. Permit number/approval nu.mb_,er, L, 7-482/92-169 ~ ~-- 10. APl number 50- 029-21645 11. Field/Pool Endicott Off Pool Casing Length Size Cemented Measured depth Structural BKB Conductor 122' 30" Driven 161' Surface 2443' 13 3/8" 3255 c.f. Permafrost 2482' Intermediate 10894' 9 5/8" 575 c.f. Class G 10933' Production Liner 1096' 7" 365 c.f. Class G 10682'- 11778' True 161' 2482' 9789' 9572'-10538' Perforation depth: measured 11100'-11132'; 11150'-11158' (open) 11224'-11258'; 11266'-113047 11340'-11354'(below straddle pkr) 11390' - 11414' (below "WD" pkr) true vertical (Subsea) 9881'-9909'; 9925'-9932' (open) 9991'-10021'; 10028'-10061? 10093'-10106' (below straddle pkr) 10138'- 10159' (below "WD" pkr) Tubing (size, grade, and measured depth) 4 1/2" 12.6# L-80 TDS & DSS to 10599'; 3 1/2" 9.2# L-80 TDS with 2 7/8" Tailpipe to 11189' Packers and SSSV (type and measured depth) 9 5/8" HB-BPR Packer at 10614? 7" HB-BP Packer at 11166'; 7" WD Packer at 11365' and 11430': 4 1/2" SSSV at 1512' 13. Stimulation or cement squeeze summary Reperforate 11,110-11,130' (11/8/98) Intervals treated (measured) Treatment description including volumes used and final pressure s~attached 14. Representative Daily Average Production or Iniection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation Subsequent to operation 34 26 272 0 287 n/a n/a n/a n/a n/a 15. Attachments Copies of Logs and Surveys run __ Daily Report of Well Operations X 16. Status of well classification as: Oil X Gas__ Suspended__ Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~ ~q4,/~ TitleTechni~l~_~_~i_~t~nt,v Form 10-404 Rev 06/'~5/88 Date 11/19/98 SUBMIT IN DL BPX Endicott Production Engineering Department Add Perforations DATE: 11/8/98 WELL N°: 3-23/N-32 BP EXPLORATION REP: Barba SERVICE COMPANY: SWS {DeckeR) DATE/TIME OPERATIONS SUMMARY OAP= 120 0815 0830 0945 1000 1030 1035 1040 1130 1135 1140 1200 1500 1555 1612 1620 1730 1815 1830 MIRU SWS SIWHP= 1400 IAP=1400 Call for grease truck to service swab valve Hold safety meeting. Arm gun. Pressure test, leaking up near grease head. Break-off and disarm gun. Lay down lubricator and change o-nngs on crossover. Pressure test, leaking up near grease head again. Break-off and disarm gun. Lay down lubricator. Found leak at head catcher. Rebuild head catcher. Pressure test and RIH with 2-1/2" HSD, 6 SPF, 20'. CCL to TS 3.7' Tie-in to pass #3 of the RST dated 28-Oct-98, which is 2' shallow to the DLL 9/12/86. Made -4.5 correction. Pack CCL @ 11104.4'. Shooting 11108-11128'(RST),saw good indication. POOH. Atsudace POP well RDMO PERFORATION SUMMARY: GUN INTERVAL(DLL) 1 11110-11130 RST DEPTH FEET ZONE 11108-11128 20 Fii All intervals were shot using 2 1/2" guns at 6 spf, 60 degree phasing and random orientation. ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT C-' SUNDRY WELL CPI' ..... rATIONS 1. Operations performed: Operation shutdown__ Stimulate X Plugging__ Pull tubing Alter casing Repair well Perforate__ Other X 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P. 0. Box 196612, Anchora.ae, Alaska 99519-6612 4. Location of well at surface 2520' SNL, 769' WEL, Sec. 8, T11N, R 17E At top of productive interval 3769' SNL, 1013' WEL, Sec. 5, T11N, R17E At effective depth 3608' SNL, 1003' WEL, Sec. 5, T11N, R17E At total depth 3565'SNL, 989' WEL, Sec. 5, T11N, R17E 5. Type of Well: Development .. Exploratory __ Stratigraphic Service 6. Datum elevation (DF or KB) KBE = 55.48 feet 7. Unit or Property name Duck Island Unit/Endicott 8. Well number 3-23/N-32 SDI 9. Permit numbedapproval number 10. APl number 50- O29-21645 11. Field/Pool Endicott Oil Pool 12. Present well Condition summary Total depth: measured Effective depth: Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: 11783 feet Plugs (measured) true vertical 10543 BKB feet 11158' MD measured 11686 feet Junk (measured) true vertical 10456 BKB feet Length Size Cemented Alaska Oil & (.~as Cons. Measured depth True ver~.~'~n BKB BKB 122' 30" Driven 161' 161' 2443' 13 3/8" 3255 c.f. Permafrost 2482' 2482' 10894' 9 5/8" 575 c.f. Class G 10933' 9789' 1096' 7" 365 c.f. Class G 10682'- 11778' 9572'- 10538' measured 11100'-11132'; 11150'-11158' (open) 11224'-11258'; 11266'-11304'; 11340'-11354'(below straddle pkr) 11390'- 11414' (below "WD" pkr) true vertical (Subsea) 9881'-9909'; 9925'-9932' (open) 9991'-10021'; 10028'-10061'; 10093'-10106' (below straddle pkr) 10138'-10159' (below "WD"pkr) Tubing (size, grade, and measured depth) 4 1/2;' 12.6# L-80 TDS & DSS to 10599'; 3 1/2" 9.2# L-80 TDS with 2 7/8" Tailpipe to 11189' Packers and SSSV (type and measured depth) 9 5/8" HB-BPR Packer at 10614'; 7" HB-BP Packer at 11166'; 7" WD Packer at 11365' and 11430': 4 1/2" SSSVat 1512' 13. Stimulation or cement squeeze summary Cement Cleanout(4/23/98) Set X-Plug in Tailpipe (5/16/98) Intervals treated (measured) Treatment description including volumes used and final pressure see attached 14. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation Subsequent to operation 285 3289 1910 0 330 34 26 272 0 287 15. Attachments Copies of Logs and Surveys run m Daily Report of Well Operations X 16. Status of well classification as: Oil X Gas__ Suspended__ Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed 'i, ~'~-~',¢~'.~,~%,-.-- --"~ Title Technical A-~-~i-~tant IV Form 10-404 Rev 06/15/8~ Date 06/03/98 SUBMIT IN DUPLICATE BPX Endicott Production Engineering Department DATE: 5-16-98 WELL N°: 3-23 / N-32 TYPE OF OPERATION: BP EXPLORATION REP: SERVICE COMPANY: OPERATIONS REPORT BROACH ECKSTEIN HES / LAWSON DATE/TIME 1330 1430 1615 1800 0700 0800 1000 1100 OPERATIONS SUMMARY RII-I w/8' X 2 1/8" STEM, K-JAR, 5' X 2 1/8" STEM, O J, SPANGS, 2.843 BROACH. BEAT FOR 45 MIN. FROM 10644' WLM TO 11656' WLM. POOH. CUT 50' OF WIRE. ADD 3' X 2 1/8" STEM. RIH w/2.843 BROACH. SET DOWN (_~ 10656' WLM. BEAT THROUGH CEMENT. DRIFT DOWN TO 10800' WLM. WORK AREA ~ 10620' TO 10690' WLM. POOH. RIH w/3 ½ GS. LATCH BLANKING SLEEVE (~. 11052' WLM. POOH w/ SLEEVE. LDFN. SIP: 2300 lA: 2150 OA: 150 5-17-98 MIRU. RII-I w/1 7/8" TS, 2 7/8" X-LINE, PRONG, 2 7/8" X-PLUG w/SAND .EXT.. PLUG SET ~ 11158' WLM. POOH. *NOTE: 2300 psi WELL WHEN PLUG WAS SET. UNABLE TO PRESSURE TEST PLUG DUE TO OPEN PERFS ABOVE. Rll-I w/3 Yz GS, 3 ~ PORTED SLEEVE. SLEEVE SET (~ 11057' WLM. POOH. RIH w/4 ½ X-LINE, PRONG, 4 ~ BBE (NBB-39). SSSV SET (.~ 1481' WLM. POOH. GOOD CLOSURE TEST. RD. SIP: 2300 lA: 2150 OA: 150 SUMMARY: BROACH CEMENT OBSTRUCTION IN TUBING. ID THROUGH OBSTRUCTION IS 2.843. PULL BLANKING SLEEVE. LDFN. SET 2 7/8" X-PLUG. SET 3 ½ PORTED SLEEVE. SET 4 ½ BBE. GOOD CLOSURE TEST. RD. SSSV: IN To: Endicott Production ineering - ~ cation'. Endicot. From: Hoffmann I Wendt ~ Operation: 3-23 - N-32 Cmt Clean-out Cost Code: N10323 - xxx Detail Code: Pkr Sqz - xxx Summary ,4pd/23 & 24, f££$ MIRU DS CTU #2 & Trico. Drop 7/8' ball to ddft coil. Had to make several attempts pumping coil volumes of seawater and Methanol to get ball to ball catch nozzle. Recovered a waxy paraffin like matedal in nozzle. RU HB&R to pump hot diesel through coil. Pumped 75 bbls of diesel. Attempt to rabbit coil w/7/8" ball after pumping diesel. No luck. Unable to recover ball after pumping several coil volumes of slick seawater. Tded RIH past new weld in coil while displacing w/seawater. Unable to recover ball. Launch 2,a 7/8" ball which successfully dislodged 1st ball. Recovered both balls and several small chunks of cement in ball catcher. Dropped 3rd bali to insure adequate passage through coil. No problem. MU Baker tool string and Ddlex motor wi' 3.705" OD Hughes" Black Ice" mill ( BHA # 1 ). Drill cement from 10525' to 10562'. Sweep and circulate hole clean. POH. Lay down BHA #1. Pick up 2-3/8" Ddlex motor assembly (BHA #2). RIH. Ddll cement in 3-1/2" from 10622' to 10687', fell through into carbolite. Ddll carbolite 10687' to 10714'. Sweep and POH. Lay down BHA #2. PU jet nozzle for FCO (BHA #3). RIH. Clean out carbo to 11164' ( top of plug ) and sweep hole clean w/FIo-Pro. Made short trip while sweeping hole clean. RIH and tag plug 9' higher @ 11155'. Flag pipe @ 11150' and POOH. Getting crude in returns to Trico. Plug appears to be out of nipple. RIH w/Baker fishing string. Sat down @ 11170'. Stack 3k on plug. POOH. Recovered 2 718" XX plug. Bullhead 16 bbls of methanol to FP tbg. Initial Well Status Siwhp lap 0ap GIp FIp Fit (Shut In) psi psi psi psi psi °F 0 320 180 2100 - - 4-23-98 Time Operation 1300 DS CTU # 2 on location with 16000' of 1.75" coil (CTV=36.5 bbls) Trico dgging up. Waiting on flowcross from deadhorse. 1600 MIRU DS. PT Trico hardline to 3000 psi. OK. 1800 MU Baker coil connector. 1820 Pull test coil connector to 20k. OK. 1840 Stab Lubricator and prepare to pump 7/8" ball to rabbit new coil. 1900 Held safety meeting to discuss muster area, scope of job, spills and communication. 1950 Decide to pick up lubricator for motor run 2028 Attempt to open SSV, panel won't work. Call for technician 2118 Pump ball with water to ddft coil through Tdco while waiting on technician (42 bbls) 2203 Break lubricator and recover ball. Ball not there. Install lubricator and pump more fluid (7 bbls) 2240 Valves leaking on tree. Bleeding well down to break lubricator and recover ball 2250 Still no ball. Stab back on, pump another coil volume. Ball rolling near top wrap (near weld), but won't come out. Possible damaged pipe or slag in weld. 2358 Open swab, RIH looking for damaged pipe I Time Depth Rate Ctp Whp Total Remarks ft bpm psi psi bbls 4/23 2358 0 Open swab, RIH looking for damaged pipe 4/24 0025 1377 300 300 Weld at goose neck. Pump and listen for ball. Can't hear ball on reel. Tdco having trouble with valves. Waiting. Operation: Endicott 3-23 Cmt Clean~ .... Page: 0100 1377 2.2 2950 317 60 sw Getting sand/paraffin solids back. Pump coil volume, Shut down, POH and listen for ball coming back over goose neck. Ball is still in reel. 0200 965 2.0 3100 320 Switch to MEOH to freeze protect coil. Ball is moving in the reel. 0222 965 37 m Ball moving. Ran out of Meoh. Wait on Meoh 0320 965 Begin pumping Meoh again. Ball movin9 again. Over the goose neck!! 0329 965 43 m POH 0400 0 Bleed down and break lubricator. Valves leaking!!! No Ball. Recovered greasy substance from nozzle 0430 0 15 m Stab on well and pump Meoh. Can't hear ball. Pump and listen for ball. Bleed down and break lubricator. 0520 0 Remove nozzle and recover ball plus a paraffin based "gunk" and mill scale. Wait on hot oil truck with diesel to clean coil. 0710 RU HB&R & PT. Isolate Trico and go directly down flowline 0735 0 1.8 3600 290 18 d Start Pumpin9 hot diesel down coil 0830 0 1.8 3800 308 57d Finished pumpin9 hot diesel. 0900 0 Install ball drop nozzle. 0915 0 PT lub to 2000 psi. OK. Place reel in ball drop position. 0930 0 2.5 3700 300 Launch 7/8' ball. Start pumping water to displace ball thru coil. 0948 0 0 300 300 41 sw Shut down pumps. Bleed lub. 1000 0 0 0 0 0 Unstab and check for ball. Ball still in coil somewhere ? 1020 0 2500 2 sw Stab lub and PT to 2500 psi. Ok. 1026 0 2.5 3700 300 Start pumping water to try and move ball. 1056 0 0 300 300 51 sw Stop pumping. Bleed lubricator. 1110 0 0 0 Unstab and check for ball. Ball not in nozzle. Break off nozzle. 1120 0 MU check valves and nozzle. 1130 0 3500 Stab lub and PT to 3500 psi. OK. 1137 Open swab valve. RIH w/coil past weld (~ 1200'. 1217 3244 2.0 1950 300 Start pumping seawater. 1230 3244 2.3 1875 300 POOH. 1300 0 0 175 250 73 sw Stop pumping seawater. OOH. Bleed lubricator. 1315 0 0 0 0 Unstab lub and break off nozzle. No ball in nozzle. Remove check valves. 1320 Install ball drop nozzle and stab lubricator. PT to 3500 psi. OK. 1337 0 Launch 7/8" brass ball. 1340 0 2.4 2600 315 Start displacing 2n~ ball w/seawater. 1354 0 0 320 310 36.3 sw Stop pumping seawater. Bleed lubricator. 1407 0 Unstab lub and break off nozzle. Found both balls in nozzle plus several small chunks of what appears to be cement. 1420 0 2000 300 1.5 sw Stab on and PT lub to 2000 psi. OK. 1433 0 2.5 2700 310 Launch 3r~ ball to insure coil is clear. Displace w/seawater 1448 0 0 320 305 35.3 sw Shut down pumping and bleed lubricator. 1500 0 0 0 0 Unstab lub and check nozzle. Found ball in nozzle. 1512 0 MU Baker tool string. PT to 4000 psi. OK. MU Drilex motor (BHA # 1 ). 1530 0 4000 4000 Stab lubricator and PT to 4000 psi. OK. 1550 0 0 180 315 Open swab valve and RIH w/BHA # 1. 1711 8100 0 256 315 Wtcheck= 15k. 1731 10300 0 320 300 Wtcheck= 20k. 1737 10525 295 305 Dry tag TOC @ 10518' ctmd. Correct to SL tag of 10525'. Flag pipe. POH. 1745 10470 2.6 3650 470 Put well on gas inj. Start pumping sea water for motor freespin coil pressure. RIH to mill. Acting stringy from 10470' down to TOC. Operation: Endicott 3-23 Cmt Clear ' Page: 1830 10568 2.2 2300 400 130 sw Switch to biozan for sweep 1833 10568 2.2 3000 400 7 fp Switch to water, lAP = 1960, OAP=200. Short tdp to 10525' and back to btm 1845 10580 2.8 3380 430 32 sw Pen Rate = 2 fpm 1910 10607 2.8 3000 454 99 sw Switch to flo pro 1916 10618 2.8 3700 460 7 fp Switch to water Prate = 2 fpm 1921 10622 Motor stall. Tag XO. Pick up and circulate sweep to nozzle 1926 10620 2.8 3250 540 37 sw FIo pro at nzl. Short tdp to 10525 and back to bottom. 1950 10620 2.2 1900 790 82 sw Chase out of hole. 2100 3050 0 0 498 235sw SDpump 2115 1500 0 465 2 m FP surface lines 2140 0 0 300 At surface, close well and bleed down 2230 Lay down BHA #1, pick up BHA #2. Pull test CTC = 20 k lbs. PT=BHA to _ 4000 psi. Pick up motor & BHA #2 2300 Load tubing and lubricator and PT to 4000 psi. Bleed down, open well. 2315 1650 1500 RIH IAP=1900, OAP=200 2330 1200 0.5 525 665 7 sw RIH, pumping at minimum rate with water 4/25 0057 10000 0.5 80 515 61 sw Wtchk= 20 klbs IAP=1350, OAP=IS0 0106 10525 0.5 80 515 67 sw Check flag and correct depth. Gas Lift rate = 2.2 mmscfd 0122 10621 1.8 1300 505 87 sw Motor Stall 0136 10621 1.8 1250 500 110 sw Working mill at 3-1/2' xo trying to establish pattern. Several motor stalls. 0145 10622 1.8 1340 490 126 sw Finally worked into 3-1/2" 0150 10626 1.8 1250 483 Pen Rate = 2 fpm 0200 10648 1.8 1525 490 160 sw Short Trip to 10615' and back to bottom. 0206 10648 1.8 1400 487 7 fp Switch to FIo Pro. Gas Lift rate = 1.6 mmscfd 0210 10652 1.8 2000 485 Back to water 0220 10662 1.8 2000 480 21 sw Switch to FIo Pro 0228 10666 1.8 2289 480 15 fp Switch to water 0248 10682 1.8 1500 480 36 sw Switch to FIo Pro 0255 10687 1.8 1900 460 10 fp Switch to water. Short tdp to xo, and back to bottom 0308 10714 1.8 1650 460 26 sw Seem to be in soft sand. Call it quits w/motor. Wait for sweep and prep to POH 0317 10705 1.8 1400 460 42sw POH 0436 3250 1.8 1480 460 195sw Switchto MEOH 0457 500 1.8 3800 460 38 m Freeze protect coil and shut down 0515 0 OOH, bleed down. Ice in lubricator and BOP's 0540 0 Lay down BHA #2. PU BHA #3 0600 0 Crew change out and w/o Meoh 0645 0 4 m PU BHA #3. Stab lubricator. PT to 4000 psi. 0740 0 1789 1730 Open well and RIH 0830 4350 0 550 RIH. Retumstoflowline 0852 7000 0 350 Wtchk = 15 k lbs 0915 9520 2.1 340 On line with water 0920 10000 2.1 1450 328 10 sw Wtchk = 22 k lbs 0927 10411 2.1 1650 344 27 sw Switch to FIo-Pro 0934 10645 2.7 2500 355 20 fp Wt chk = 23 k lbs Switch to water 0943 10767 2.7 3200 320 48sw Shorttdp. Clean pickup 0949 10802 2.7 2800 330 63 sw Short trip, clean pick up. Reciprocate through rio-pro sweep Operation: Endicott 3-23 Cmt Clear .... Page: 4 0955 10631 2.7 2900 330 80 sw Switch to FIo-Pro. FP @ nzl @ 136.5 bbls. Prate 20 fpm 1002 10824 2.2 4000 310 20 fp Switch to water Wtr (~ nzl (~159 1010 10892 2.7 4000 310 110 sw Shorttdp. Clean pick up 1016 10918 2.8 3150 330 130 sw Wtr (~ nzl, short trip to 10570', back in hole 1030 10779 2.8 3680 260 161 sw Switch to FIo-Pro FP (~ nzl (~ 237 1037 10929 2.2 4074 266 20 fp Switch to water Wtr (~ nzl (~159 IAP=1550, OAP=195, FLT = 83 1043 10967 2.4 3867 200 178 sw Short trip. Clean pick up 1051 11027 2.8 3475 245 200 sw Wtr (~ nzl, short trip to 10525' 1137 11164 2.8 3475 245 317sw Tag plug, shorttdp 1155 11164 2.4 3500 400 32 fp Switch to FIo-Pro 1207 11164 2.0 3500 599 On water, circ out fill 11155 2.2 3200 493 335 sw Tag 9' high, plug coming up hole?? WHP increased. Flag Pipe @ 11150 on Erad. 1330 6800 3.0 3000 475 SI gas lift to well. Getting crude back to Trico. It appears that X-plug may have come out of nipple profile or blanking sleeve shifted from ported nipple. 1425 500 2.5 2300. 450 651 sw Switch to methanol to FP coil. 1440 0 0 675 640 36 m Ooh w/coil. Bleed lubricator. RD Trico and replace micro-motion sensor on supply line. 1600 0 MU Baker fishing tool string. ( BHA # 4 ). 1650 0 Pull test coil connection to 15k. OK. 1735 0 PT BHA to 4000 psi. OK. 1815 0 4000 Stab lubricator and PT to 4000 psi. OK. 1830 0 516 750 Safer7 meeting with night crew. Open swab valve. RIH. 2021 10006 967 654 Wt check = 16.2k 2035 10600 992 646 Wt check = 18 k 2036 10600 0.4 1227 650 Hole a little sticky. Start pumping methanol (~ min rate 2040 10633 0.35 1230 660 Wt check = 18k 2045 10769 0.34 1250 687 Wt check = 18k 2050 11000 0.35 1250 700 Stop circ methanol. Wt check = 18.5k. Resume pumping. Saw slight bobble going through vicinity of ported nipple ( 2.350" ID ). 2056 11105 0 1000 700 Wt check = 19k w/o pumps on. Resume pumping. 2100 11170 0.5 1160 700 9 m Appearto be pushing plug downhole. Had 160 psi increase in coil pressure. SD pumps. Sat down @ 11170'. Stack 3k over. POOH. Up weight = 22k. Showing some drag coming through 3 1/2' tbg. Appear to have plug. 2230 0 694 OOH. SI swab and bleed lubricator. Recovered 2 7/8" XX-plug. 2300 0 LB Baker tools and XX-plug. 2330 0 2000 16 m Stab lubricator and PT to 2000 psi. OK. Bullhead Methanol to freeze protect well. 2400 RD DS CTU. Wing and choke leaking. Call out for well tender to service valves on tree. 4/26 0300 0 Finish rigging down DS and Trico flowcross. 0400 0 Leave location Final Well Status SIWHP lAP 0AP GLP FLP FLT psi psi psi psi psi °F 700 500 180 2100 250 - Operation: Endicott 3-23 Cmt Clear,' Page: 5 Fluid Summary 1827 Seawater w/friction reducer. 75 Diesel 202 Meoh. 178 FIo Pro 2282 Total Bottom Hole Assembly # 1 2-7/8" Motor & Mill Tool String Descriptions O.D. I.D. Length Comments Baker ct connector / Fishing Neck 3 1/8" 1.0" .95' Dual check valves. 3 1/8" 15/16" 1.56' Hydraulic Disconnect 3 3/8" 13/16" 1.54' 7/8" ball Circulating Sub 3 1/8" 9/16" 1.15' 5/8" ball Drilex 2 7/8" motor 2 7/8" 12.53' Mill (Hughes "Black Ice" PDC. Ser# 1900975 3.705" .55' Total Length 18.28' Bottom Hole Assembly # 2 2-3/8" Motor & Mill Tool String Descriptions O.D. I.D. Length Comments Baker ct connector / Fishing Neck 2.25 1.0" 1.38' Dual check valves. 2.125 13/16" 1.38' Hydraulic Disconnect 2.125 11/16" 1.56' 3/4" ball Circulating Sub 2.125 9/16" 1.02' 5/8" ball Ddlex 2 3/8" motor 2 3/8" 12.53' Mill (3 blade) 2.70" 2.01' Total Length 19.88' Bottom Hole Assembly # 3 2.125" Nozzle Tool String Descriptions O.D. I.D. Length Comments DS Roll On connector 1.75' 1.0" 0.20 '1.9" Fluted No-go XO 2.00 1.0" 0.375 Dual check valves. 2.125 1,0" 0.958 Straight Stinger 2.00 1.0" 5.00 2" Swid Nozzle 2.125 0.67 Total Length 7.203' Operation: Endicott 3-23 Cmt Clean,-'* Page: 6 Bottom Hole Assembly # 4 XX Plug Fishing Assembly Tool Stdng Descriptions O.D. I.D. Length Comments Baker CT Connector 2.250" 1.0" 1.37 Dual Flapper Checks 2.125" .80" 1.39 Baker Hydraulic Disconnect 2.125" .68" 1.57' Takes 3/4" ball XO 1 1/2" MT box X 1 1/4" R pin 2.125" .625" .47' Accelerator 2.125" .75" 6.97' XO 1 1/4" Reg box X 1 1/2" MT pin 2.125" 1.0" .46' Wt Bar 2.125" 1.00" 4.84' XO 1 1/2" MT box X 1 1/4" reg pin 2.125" .625" .34' Hydraulic Jars 2.125" .75" 5.48' GS Spear 2.125" 1.70' Total Length 25.59' ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT O SUNDRY WELL OPE: ,TIONS Jperafions performed: Operation shutdown__ Stimulate X Plugging__ Pull tubing Alter casing Repair well Perforate.m Other Name of Operator BP Exploration (Alaska)/nc. Address P. O. Box 196612, Anchora_oe, Alaska 99519-6612 4. Location of well at surface 2520' SNL, '769' WEL, Sec. 8, T11N, R17E At top of productive interval 3769'SNL, 1013' WEL, Sec. 5, T11N, R17E At effective depth 3608'SNL, 1003' WEL, Sec. 5, T11N, R17E At total depth 3565'SNL, 989' WEL, Sec. 5, T11N, R17E 5. Type of Well: Development .. Exploratory ~ Stratigraphic ~ Service 6. Datum elevation (DF or KB) KBE = 55.48 feet 7. Unit or Property name Duck Island Unit/Endicott 8. Well number 3-23/N-32 SD/ 9. Permit number/approval number 7-482/92-169 10. APl number 50- 029-21645 11. Field/Pool Endicott Oil Pool 12. Present well condition summary Total depth: measured Effective depth: Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: true vertical measured true vertical Length 11783 feet Plugs (measured) 10543 BKB feet 11686 feet Junk (measured) 10456 BKB feet Size Cemented Measured depth BKB True'vertiCal depth BKB 122' 30" Driven 161' 161' 2443' 13 3/8" 3255 c.f. Permafrost 2482' 2482' 10894' 9 5/8" 575 c.f. Class G 10933' 9789' 1096' 7" 365c. f. Class G 10682'- 11778' 9572'- 10538' measured 11100'-11132'; 11150'-11158' (open) 11224'-11258'; 11266'-11304'; 11340'-11354'(below straddle pkr) 11390' - 11414' (below "WD" pkr) true vertical (Subsea) 9881'-9909'; 9925'-9932' (open) 9991'-10021'; 10028'-10061'; 10093'-10106' (below straddle pkr) 10138'-10159' (below "WD" pkr) Tubing (size, grade, and measured depth) 4 1/2" 12.6# L-80 TDS & DSS to 10599'; 3 1/2" 9.2# L-80 TDS with 2 7/8" Tailpipe to 11189' Packers and SSSV (type and measured depth) 9 5/8" HB-BPR Packer at 10614'; 7" HB-BP Packer at 11166'; 7" WD Packer at 11365' and 11430': 4 1/2" SSSV at 1512' 13. Stimulation or cement squeeze summary LCM Squeeze 1/12/98; Packer Squeeze 1/5/98 Intervals treated (measured) 11100'-11132', 11224'-11258', 11340'-11354', 11150'-11158', 11266'-11304', 11390'-11414' Treatment description including volumes used and final pressure see attached 14. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcr Water-Bbl Casing Pressure Tubing Pressure Prior to well operation Subsequent to operation 285 N/A 3289 1910 0 330 15. Attachments Copies of Logs and Surveys run Daily Report of Well Operations × 16. Status of well classification as: Oil X Gas__ Suspended Service 17. I hereby certify that thee f~eg.0, ing is true.~.and correct to the best of my knowledge. .. . .. Form 10-404 ~06/15/88 Date 02/04/98 SUBMIT IN DUPLICATE To: Anchorage Engineering From: Powers/Clump Operation: 3-23 LCM Squeeze / t4-3~ Date: 1/2/98 Summary 1/2/98 RIH with 2" cementing nozzle. Fluid packed IA & tbg w/SW. Pumped 5 bbl batch of 25#LCM/40 ppg gel into straddle thru ported nipple. Slight increase in pressure - not much affect. Pumped 6 bbls second batch. Saw about 120 psig increase in well head pressure (also saw 100 psi increase on IA). FP tbg to 750'. Try again tomorrow if weather permits. 1/3/98 Weather day - Phase 2 blizzard 1/4/98 RIH with 2" cementing nozzle to 11070'. Pump 5 bbl 3ra LCM (50 ppb)/40 ppg gel batch. See increase in whp. Pump 6 bbl 4~' LCM(50 ppb) / 40 ppg gel batch. Circulate in and shut choke, build pressure to 1573 psig. Mix and pump 5th LCM (54 ppb ) / 40 ppg gel. Pressured up to 1690 psig. Lost 60 psi in 1630 psig. Jet down to x-plug (tagged 11120'- - from slippage). 1/2/98 (psig) (psig) (psig) (psig) (deg F) (psig) Il nOO I 1100' I 0 I 350 I I I 1/2/98 Time ~ Operation 8:00 Miru DS g6, 14,350' of 1-3/4" (cb/32.7 bbls). 9:21 MiruHB&RtolA. 10:26 HB&R pumping down IA. 4.5 BPM @ 2300 psig. Trying to PT lubricator and hard line and having fun. -38 degrees!!! 10:44 100 bbls pumped, 4.6 bpm @ 2000 psig, 800 on tbg. 11:11 246 bbls, 4.6 bpm @ 1950 psig. 11:20 PT lines to 4000 psig. Get lined up to recover meoh. 11:42 H B & R has 395 bbls pumped. 1750 psig @ 4.7 bpm. 12:03 Open swab and RIH w/coil. fit) (bpm) (psig) (psig) Obis) (bbls) 12:08 surf .75 1550 600 27 RIH 12:18 200 .75 32/0 Reset comp. Slow rate on IA to 3bpm. 12:45 2000 .6 810 369 13 HB & R up rate to 4.5 bpm. 13:08 5000 .5 870 447 24 Pumped 686 bbls. Ck-30, Up wt-10000 13:14 5400 .5 770 435 28 712 bbl down IA, slow rate to 2 bpm. 13:33 8000 .5 790 520 39 720 bbls down IA @ 0.4 bprn-650 psig. 14000 # up wt. 13:49 10000 .5 804 545 48 0.5 bpm -700 psi, up wt. 18000g. 14:08 11152 .5 776 541 57 Tag x-plug no corr. 24' shallow. Pumpers miru. 14:19 11078 0 520 521 62 25' above x-nipple. SD IA= 650 psi. 14:25 11078 .75 960 542 64 IA=700 (~ 0.4 bpm. 14:28 11078 1.5/.5 2130 574 69 IA=730 (~ 0.4 bpm. Short inj test. 15:17 11078 0.5 708 530 72 Batching up the LCM & 40 ppg gel. 15:38 11078 0.5 725 545 104 Switch HB & R over to diesel (~ min rate. 16:00 11070 1 1154 560 115 Switch to Meoh to FP soft lines. 16:03 11070 1/0 1'146 567 117.3 Shut-down. Isolate. Turn over to pumper. 7 bbls diesel away. 850 psig. 16:09 11070 1.5 2030 577 0/ On cmt pumper. 16:11 11070 0 508 523 5 PT hardline to 4000#. OK. 16:13 1.5 2780 562 3/0 Switch to LCM/Gel 16:16 1.5 5 Switch to SW. 16:20 2 3101 617 5 5 bbls warm water. 16:23 2 3122 615 11 915 psig pump pressure on IA. 16:25 2 3146 615 15 2 3163 625 25 925 psig 16:31 11070 2/1 3177 631 28 16:34 1 1282 604 31 925 psig (~ .33 bpm on IA 16:35 1 1282 609 32 16:37 1 - 1285 606 33 16:38 1 1291 617 34 16:40 1 1291 630 36 16:42 1/0.5 38 See nothing much. Reduce rate. 16:50 '0 40 Shut down for to mix next batch. 17:05 1 1153 530 0 Back on line to warm up. 17:11 2 1325 560 7/0 On LCM 17:14 2 3220 650 6/0 On KCL water. 17:17 2 3226 667 5 17:19 2 3264 675 10 17:28 2/1 1550 652 28 Slow rate. IA= 975 psig pp. 17:33 1 1490 658 33 No pressure increase. 17:35 11070 2 2900 729 36 Pooh. Start seeing slight increase. 17:40 10000 .5 960 795 46 Up rate on IA. (Saw about 100 psig incr) 17:51 8308 0/1.5 779 750 49/0 Off cmt pumper. On Meoh. 18:00 6600 1.5 886 2531 7 60 bbls diesel in IA. RD HB & R. 18:42 surf 1 1750 654 41 Coil is FP/finish FP the well. 18:51 1/0 328 369 46 Shut swab. Pump 2 bbls Meoh to sqz unit tank. 19:03 RD for night. 1/4/98 Time ~ Operation 12:30 Miru DS ~6, 14,350' of 1-3/4" (ctv 32.7 bbls). 12:50 PT lines to 4000 psig. lAP= 700 psi, OAP= 60 psig, & VVhp= 500 psig. 13:00 Open swab and RIH w/2' cmt nozzle & coil full of Meoh. II (ft)][ (bpm) ~ (psig)II (psig) Il (bbls)II Cobls) I 14:54 11090 15:35 11090 195914951 o I I Remarks RIH. Stop @ surface. Frozen reel chain. Rih again. Dowell pumper Miru. Chains slipping. Parked @ ported nipple. GeI-LCM ready. PT hardine to 4000 psig. 15:48 2900 614 10/0 Come on line w! SW 15:49 2 3250 650 2/0 On LCM. 15:52 2 3744 725 5!0 Switch to water. 15:57 2 3524 762 10 18880 pickup wt 16:04 1 1734 809 27.4 Slow rote to 1 bpm 16:08 1 1652 747 31 Should be out coil w/LCM 16:11 1 1668 778 35 Seeing small increase. 16:16 1/0 1050 1050 40 Looks good. lAP= 1100 psig. Mix up #2. 16:30 min 1269 924 40 Move some fluid. 16:37 2 3550 1144 0 On LCM. 16:42 1.8 3823 1094 6 Switch to water, 16:46 2 3753 1093 15.7 10 bbls of water. 16:55 2/1 3813 1062 31.3 16:56 1 1995 1081 33.7 Closing choke 16:59 1 2054 1203 36.6 3.6 out nozzle 17:06 1.5/0 3120 1573 46 Plateau at 1573 psi. Looked like leak off 1322 psig 17:10 0 1360 1322 Loosing pressure. Mix next batch. 17:25 min 1900 1570 55. 17:45 11063 min/1.6 2900 1204 62.5 OnLCM 17:48 11063 1.8 3800 968 5 17:51 1.5 3620 946 6 Switch to water 18:08 1.5/1.0 3170 1081 slow rote 18:10 1 2354 1104 33.2 18:11 1/0.5 1868 1310 35 Puh87fpmto 10911 18:17 10911 0.5 1815 1440 38 18:19 10911 0.5 1816 1512 39 LCM out nozzle 18:24 10911 0.5/0 2000 1731 41 Put ~ all behind pipe. 18:26 1729 1690 18:30 1688 !650 18:33 1668 1630 18:49 0.5/2 3800 1000 47/0 Jet tubing to plug while POOH 18:54 11120 2 3700 990 7 Tagged up. POOH 20:12 2200 2/1.5 3750 1000 187/0 SW to Methanol 21:00 Surf 0 1350 1350 46 RDFN [I Final Well Status I SIW'HP lAP OAP FLP FLT GLP (psig) II (psig)Il (psig)[I (psig)II (degF)[[ (psig)II I 1350 I ]550 I 70 I 350 I si I sz I bbls Fluids Summary 1/2 Down TBG. 253 2% KCL water 46 60/40 Meoh 11 LCM in 40 ppg gel. Down IA 791 FSW 60 Diesel 1/4 TBG. 375 2% KCL water 46 60/40 Meoh 17 LCM in 40 ppg gel BHA# 1 Tool String Description OD ID Length Comments DS ct connector. 2.0 0.10 Stinger 2.0 4.58 Squeeze nozzle 2.0 0.56 5.24' Total Length To: Anchorage Engineering From: Powers/Clump Operation: 3-23 PKR SQUEEZE ,/ . Date: 1/5/98 Summary 1/5/98 Rih w/2" cmt nozzle. Dry tag x-plug in tailpipe ~ 11152'. Correct odometer to drillers measurements and Pub to 11140'. Lay in 2550 lbs of 20/40. Tag sand top ~ 10673'. Mix and pump 6.7 bbls of Class G cmt. Lay in while trying to maintain 800 psig on IA w/choke. Pooh jetting w/ 2% KCL H20. FP coil and well to 1500'. Trap 600 psig on well. RDMO. Expected cmt top - 10575' in tbg and -10500' in IA. 1/5/98 (psig) (psig) (psig) (psig) (deg F) (psig) I 1 50 I 375 I 50 I 350 I si I si I 1/5/98 Time ~ Operation 7:30 Miru DS g6, 14,350' of 1-3/4" (ctv 32.7 bbls). 8:45 PT lubricator and hard line to 4000 psig. Line up to recover Meoh to SQZ unit tank. 9:15 Open swab & Rih after dropping VVhp to 712 psig. (ft) (bpm) (psig) (psig) Cobls) Cobls) 9:15 surf .35 721 940 53 RIH 10:39 10000 .35 708 720 64 17,500 # pickup 10:53 11150 - 725 795 - 68 19,500 # pickup 10:54 11160 .35 713 880 70.7 Correct depth to 11160' dd from 11140'. 11:29 .35 729 880 82 MI & Dowell rigging up. 12:00 11160 .5 763 985 94 Start FP soft line. 12:07 0 762 764 96.4 Done FP. 12:09 11152' 1 1425 768 96 Pumper on SW. 12:14 11152 1/0 800 800 101 Shutin &PT 12:16 1.7 797 2550 0 On gel. 12:18 1.5 769 2210 3/0 On slurry (.8 bbls lag) 12:24 1.75 772 2930 10/0 On gel 12:26 2 771 2049 3/0 On water. 12:28 2 782 2346 7 12:31 2 781 2450 10 12:34 2 779 2550 15 12:36 2 782 2560 20 12:37 11152 2/1 765 940 21 Pooh 100fpm. 12:40 10776 1 762 1152 25 12:42 10600 1 766 1271 27 Reduce to 60 fpm 12:45 10395 1 775 1404 30 Clean (~ nozzle 12:49 10166 1 776 1447 34 SW out nozzle. 12:50 10100 1/0 770 744 35 Shut down & wait on sand. 13:21 10087 1 776 1600 36 Move water for warm up 13:25 10087 1/0 788 787 41 Shut down, Rih for dry tag. 13:35 10647 0 775 770 41 19500 pickup. Rih 13:38 10673 Batch up cmt. 14:30 10135 1 Cmt up to wt. 15:15 10673 0 Rib for dr~ tag. 15:27 10673 Tag. Up wt= 19500# 15:29 10659 1.3 730 2015 IA=800psi. 15:34 10660 1.3 725 1920 0 On fresh H20 15:39 1.3 725 .1911 5/0 Oncement 15:43 10660 1.3 732- 2712 6.7 On fresh. 15:48 10660 1.3/1.7 735 2642 11 On SW. 15:50 10660 2.0 753 2620 16 up rate 15:53 2 762 3455 19 15:56 10660 2 757 3629 26 16:01 10660 1.3 750 1663 31 Slow rate. 16:03 10660 1.3 756 1800 32.7 Cmt out nozzle, shut choke, open IA ck. Try to keep 800 psi on IA. Pressuring up. Lay in & push cmt into IA @ 15 fpm. 16:05 10645 1.3 800 1815 34 lAP= 900 16:07 10600 1.3 _ 850 1830 36.6 Open choke on IA some more, lAP= 850. .16:09 10580 0/min 659 670 39.6 Shut choke. Shut down. Start circulation. 16:11 10570 mini1.8 672 3304 42 Dowell pump RDMO. 17:21 3500 1.8 596 2950 132/0 lAP= 700 psi. Switch to MEOH. 17:56 0 650 650 57 OOH trap whp. Shut Swab. RDMO 19:03 RD for night. (psig) IJ (psig)II (psig)II (psig)II (degF)II (psig)II I 600 I 75o I so I 350 I sx I SI I bbls Fluids Summary 258 2% KCL water 57 60/40 Meoh 10 Fresh H20 6 Gel Spacers 10 Dirty 20/40 sand volume 6.7 Class G Cement. CMT Properties Thickening Time: 5:54 min Fluid loss: Calculated API= 60 ml, Measured: 30 ml in 30 min ~ 170 deg F1 1000 psi DS ct connector. Stinger Squeeze nozzle Tool String Description OD BHA# 1 Length 2.0 0.10 2.0 4.58 2.0 0.56 Total Length 5.24' Comments STATE OF ALASKA ALASK '-")IL AND GAS CONSERVATION COMMISSI REPORT O, SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown__ Pull tubing__ Alter casing 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P. O. Box 196612, AnchoraQe, Alaska 99519-6612 4. Location of well at surface 2520' SNL, 769' WEL, Sec. 8, T11N, R17E At top of productive interval 3769'SNL, 1013' WEL, Sec. 5, T11N, R17E At effective depth 3608' SNL, 1003' WEL, Sec. 5, T11N, R17E At total depth 3565' SNL, 989' WEL, Sec. 5, T11N, R17E Stimulate X Plugging.__ Perforate__ Repair well Other__ 5. Type of Well: Development .. Exploratory __ Stratigraphic __ Service __ 6. Datum elevation (DF or KB) KBE = 55.48 feet 7. Unit or Property name Duck Island Unit/Endicott 8. Well number 3-23/N-32 SDI 9. Permit number/approval number 10. APl number 50- 029-21645 11. Field/Pool Endicott Off Pool 12. Present well condition summary Total depth: measured Effective depth: Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: true vertical measured true vertical Length 11783 feet Plugs (measured) 10543 BKB feet 11686 feet Junk (measured) 10456 BKB feet Size Cemented Measured depth Tcu..g!~t~..~/~B I depth BKB 122' 30" Driven 161' 161' 2443' 13 3/8" 3255 c.f. Permafrost 2482' 2482' 10894' 9 5/8" 575 c.f. Class G 10933' 9789' 1096' 7" 365 c.f. Class G 10682'- 11778' 9572'- 10538' measured 11100'-11132'; 11150'-11158' (open) 11224;11258'; 11266'-11304'; 11340'-11354'(below straddle pkr) 11390' - 11414' (below 'WD' pkr) true vertical (Subsea) 9881'-9909'; 9925'-9932' (open) 9991'-10021'; 10028'-10061'; 10093'-10106' (below straddle pkr) 10138'-10159' (below 'WD' pkr) Tubing (size, grade, and measured depth) 4 1/2" 12.6# L-80 TDS & DSS to 10599'; 3 1/2" 9.2# L-80 TDS with 2 7/8" Tailpipe to 11189' Packers and SSSV (type and measured depth) 9 5/8" HB-BPR Packer at 10614'; 7" HB-BP Packer at 11166'; 7" WD Packer at 11365' and 11430': 4 1/2" SSSV at 1512' 13. Stimulation or cement squeeze summary LCM Squeeze 1/12/98; Packer Squeeze 1/5/98 Intervals treated (measured) 11100'-11132', 11224'- 11258', 11340'- 11354', 11150'-11158', 11266'-11304', 11390'- 11414' 14. Treatment description including volumes used and final pressure see attached Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation 285 3289 1910 0 330 Subsequent to operation N/A 15. Attachments 16. Status of well classification as: Copies of Logs and Surveys run Daily Report of Well Operations X Oil X Gas__ Suspended 17. I hereby certify that thee foregoing is'{rue and correct to the best of my knowledge. · -/ / /" , Form 10-404 Rev~6/15/88 Service Date 02/04/98 SUBMIT IN DUPLICATE To: Anchorage Engineering From: Powers/Clump Operation: 3-23 LCM Squeeze / ~/-3% Date: 1/2/98 Summary 1/2/98 RIH with 2" cementing nozzle. Fluid packed IA & tbg w/SW. Pumped 5 bbl batch of 25#LCM/40 ppg gel into straddle thru ported nipple. Slight increase in pressure - not much affect. Pumped 6 bbls second batch. Saw about 120 psig increase in well head pressure (also saw 100 psi increase on IA). FP tbg to 750'. Try again tomorrow if weather permits. 1/3/98 Weather day - Phase 2 blizzard 1/4/98 RIH with 2" cementing nozzle to 11070'. Pump 5 bbl 3rd LCM (50 ppb)/40 ppg gel batch. See increase in whp. Pump 6 bbl 4th LCM(50 ppb) / 40 ppg gel batch. Circulate in and shut choke, build pressure to 1573 psig. Mix and pump 5th LCM (54 ppb ) / 40 ppg gel. Pressured up to 1690 psig. Lost 60 psi in 1630 psig. Jet down to x-plug (tagged 11120'- - from slippage). 1/2/98 (psig) (psig) (psig) (psig) (deg F) (psig) I I I 0 I 350 I I s, I 1/2/98 II Time II Operation 8:00 Miru DS ~, 14,350' of 1-3/4" (crv 32.7 bbls). 9:21 MiruHB&RtolA. 10:26 HB&R pumping down IA. 4.5 BPM @ 2300 psig. Trying to PT lubricator and hard line and having fun. -38 degrees!!! 10:44 100 bbls pumped, 4.6 bpm @ 2000 psig, 800 on tbg. 11:11 246 bbls, 4.6 bpm @ 1950 psig. 11:20 PT lines to 4000 psig. Get lined up to recover meoh. 11:42 HB & R has 395 bbls pumped. 1750 psig @ 4.7 bpm. 12:03 Open swab and RIH w/coil. (ft) (bpm) (psig) (psig) (bbls) (bbls) 12:08 surf .75 1550 600 27 RIH 12:18 200 .75 32/0 Fleset comp. Slow rate on IA to 3bpm. 12:45 2000 .6 810 369 13 HB & Fl up rate to 4.5 bpm. 13:08 5000 .5 870 447 24 Pumped 686 bbls. Ck-30, Up wt-10000 13:14 5400 .5 770 435 28 712 bbl down IA, slow rate to 2 bpm. 13:33 8000 .5 790 520 39 720 bbls down IA @ 0.4 bpm-650 psig. 14000 # up wt. 13:49 10000 .5 804 545 48 0.5 bpm -700 psi, up wt. 18000#. 14:08 11152 .5 776 541 57 Tag x-plug no corr. 24' shallow. Pumpers miru. 14:19 11078 0 520 521 62 25' above x-nipple. SD IA= 650 psi. 14:25 11078 .75 960 542 64 IA=700 @ 0.4 bpm. 14:28 11078 1.5/.5 2130 574 89 IA=730 @ 0.4 bpm. Short inj test. 15:17 11078 0.5 708 530 72 Batching up the LCM & 40 ppg gel. 15:38 11078 0.5 725 545 104 Switch HB & Ft over to diesel @ min rate. 16:00 11070 1 1154 560 115 Switch to Meoh to FP soft lines. 16:03 11070 1/0 1146 567 117.3 Shut-down. Isolate. Tum overto pumper. 7 bbls diesel away. 850 psig. 16:09 11070 1.5 2030 577 0/ On cmt pumper. 16:11 11070 0 508 523 5 PT hardline to 4000#. OK. 16:13 1.5 2780 562 3/0 Switch to LCM/Gel 16:16 1.5 5 Switch to SW. 16:20 2 3101 617 5 5 bbls warm water. 16:23 2 3122 615 11 915 psig pump pressure on IA. 16:25 2 3146 615 15 2 3163 625 25 925 psig 16:31 11070 2/1 3177 631 28 16:34 1 1282 604 31 925 psig (~ .33 bpm on IA 16:35 1 1282 609 32 16:37 1 1285 606 33 16:38 1 1291 617 34 16:40 1 1291 630 36 16:42 1/0.5 38 See nothing much. Reduce rate. 16:50 0 40 Shut down for to mix next batch. 17:05 1 1153 530 0 Back on line to warm up. 17:11 2 1325 560 7/0 On LCM 17:14 2 3220 650 6/0 On KCL water. 17:17 2 3226 667 5 17:19 2 3264 675 10 17:28 2/1 1550 652 28 Slow rate. IA= 975 psig pp. 17:33 1 1490 658 33 No pressure increase. 17:35 11070 2 2900 729 36 Pooh. Start seeing slight increase. 17:40 10000 .5 960 795 46 Up rate on IA. (Saw about 100 psig incr) 17:51 8308 0/1.5 779 750 49/0 Off cmt pumper. On Meoh. 18:00 '6600 1.5 886 2531 7 60 bbls diesel in IA. RD HB & R. 18:42 surf 1 1750 654 41 Coil is FP/finish FP the well. 18:51 1/0 328 369 46 Shut swab. Pump 2 bbls Meoh to sqz unit tank. 19:03 RD for night. 1/4/98 Time II Operation 12:30 Miru DS #8, 14,350' of 1-3/4" (ctv 32.7 bbls). 12:50 PT lines to 4000 psig. lAP= 700 psi, OAP= 60 psig, & Whp= 500 psig. 13:00 Open swab and RIH w/2" cmt nozzle & coil full of Meoh. II (foII (bpm) II (psig)II (psig)II (bbls)II (bbls) I 13:00 surf 0 530 495 RIH. Stop @ surface. Frozen reel chain. 13:29 Rih again. 14:00 9000 Dowell pumper Miru. 14:54 11090 961 495 Chains slipping. Parked @ ported nipple. 15:35 11090 959 495 0 GeI-LCM read),. PT hardine to 4000 psig. 15:48 2900 614 10/0 Come on line w/SW 15:49 2 3250 650 2/0 On LCM. 15:52 2 3744 725 5/0 Switch to water. 15:57 2 3524 762 10 18880 pickup wt 16:04 1 1734 809 27.4 Slow rate to 1 bpm 16:08 1 1652 747 31 Should be out coil w/LCM 16:11 1 1668 778 35 Seeing small increase. 16:16 1/0 1050 1050 40 Looks 9ood. lAP= 1100 psig. Mix up #2. 16:30 min 1269 924 40 Move some fluid. 16:37 2 3550 1144 0 On LCM. 16:42 1.8 3823 1094 6 Switch to water. 16:46 2 3753 1093 15.7 10 bbls of water. 16:55 2/1 3813 1062 31.3 16:56 1 1995 1081 33.7 Closing choke 16:59 1 2054 1203 36.6 3.6 out nozzle 17:06 1.5/0 3120 1573 46 Plateau at 1573 psi. Looked like leak off 1322 psi9 17:10 0 1360 1322 Loosing pressure. Mix next batch. 17:25 min 1900 1570 55. 17:45 11063 min/1.6 2900 1204 62.5 On LCM 17:48 11063 1.8 3800 968 5 17:51 1.5 3620 946 6 Switch to water 18:08 1.5/1.0 3170 1081 slow rate 18:10 1 2354 1104 33.2 18:11 1/0.5 1868 1310 35 Puh 87 fpm to 10911 18:17 10911 0.5 1815 1440 38 18:19 10911 0.5 1816 1512 39 LCM out nozzle 18:24 10911 0.5/0 2000 1731 41 Put,-,all behind pipe. 18:26 1729 1690 18:30 1688 !650 18:33 1668 1630 18:49 0.5/2 3800 1000 47/0 Jet tubing to plug while POOH 18:54 11120 2 3700 990 7 Tagged up. POOH 20:12 2200 2/1.5 3750 1000 187/0 SW to Methanol 21:00 Surf 0 1350 1350 46 RDFN (psig) (psig) (psig) (psig) (deg F) (psig) I 1350 I 1550 I 70 I 350 J SI I SI I bbls Fluids Summary 1/2 Down TBG. 253 2% KCL water 46 60/40 Meoh 11 LCM in 40 ppg gel. Down IA 791 FSW 60 Diesel 1/4 TBG. 375 2% KCL water 46 60/40 Meoh 17 LCM in 40 ppg gel Tool String Description OD BHA # 1 Length DS ct connector. 2.0 0.10 Stinger 2.0 4.58 Squeeze nozzle 2.0 0.56 Total Length 5.24' Comments To: Anchorage Engineering From: Powers/Clump Operation: 3-23 PKR SQUEEZE / Date: 1/5/98 Summary 1/5/98 Rih w/2" cmt nozzle. Dry tag x-plug in tailpipe ~ 11152'. Correct odometer to drillers measurements and Puh to 11140'. Lay in 2550 lbs of 20/40. Tag sand top ~ 10673'. Mix and pump 6.7 bbls of Class G cmt. Lay in while trying to maintain 800 psig on IA w/choke. Pooh jetting w/ 2% KCL 1-t20. FP coil and well to 1500'. Trap 600 psig on well. RDMO. Expected cmt top - 10575' in tbg and -10500' in IA. 1/5/98 (psig) (psig) (psig) (psig) (deg F) (psig) 11150113751 50 I 350 I SI I SI I 1/5/98 Time I1 Operation 7:30 Miru DS #6, 14,350' of 1-3/4" (ctv 32.7 bbls). 8:45 PT lubricator and hard line to 4000 psig. Line up to recover Meoh to SQZ unit tank. 9:15 Open swab & Rih after dropping Whp to 712 psig. (ft) (bpm) (psig) (psig) (bbls) (bbls) 9:15 surf .35 721 940 53 RIH 10:39 10000 .35 708 720 64 17,500 # pickup 10:53 11150 - 725 795 68 19,500 # pickup 10:54 11160 .35 713 880 70.7 Correct depth to 11160' dd from 11140'. 11:29 .35 729 880 82 MI & Dowell dggin9 up. 12:00 11160 .5 763 985 94 Start FP soft line. 12:07 0 762 764 96.4 Done FP. 12:09 11152 1 1425 768 96 Pumperon SW. 12:14 11152 1/0 800 800 101 Shut in & PT 12:16 1.7 797 2550 0 On gel. 12:18 1.5 769 2210 3/0 On slurry (.8 bbls lag) 12:24 1.75 772 2930 10/0 On gel 12:26 2 771 2049 3/0 On water. 12:28 2 782 2346 7 12:31 2 781 2450 10 12:34 2 779 2550 15 12:36 2 782 2560 20 12:37 11152 2/1 765 940 21 Pooh 100fpm. 12:40 10776 1 762 1152 25 12:42 10600 1 766 1271 27 Reduce to 60 fpm 12:45 10395 1 775 1404 30 Clean @ nozzle 12:49 10166 1 776 1447 34 SW out nozzle. 12:50 10100 1/0 770 744 35 Shut down & wait on sand. 13:21 10087 1 776 1600 36 Move water for warm up 13:25 10087 1/0 788 787 41 Shut down, Rih for dry tag. 13:35 10647 0 775 770 41 19500pickup. Rih 13:38 10673 Batch upcmt. 14:30 10135 1 Cmtuptowt. 15:15 10673 0 Rih fordr7ta9. 15:27 10673 Tag. Upwt= 19500# 15:29 10659 1.3 730 2015 IA= 800 psi. 15:34 10660 1.3 725 1920 0 Onfresh H20 15:39 1.3 725 1911 5/0 On cement 15:43 10660 1.3 732- 2712 6.7 Onfresh. 15:48 10660 1.3/1.7 735 2642 11 On SW. 15:50 10660 2.0 753 2620 16 up rate 15:53 2 762 3455 19 15:56 10660 2 757 3629 26 16:01 10660 1.3 750 1663 31 Slow rate. 16:03 10660 1.3 756 1800 32.7 Cmt out nozzle, shut choke, open IA ck. Try to keep 800 psi on IA. Pressuring up. Lay in & push cmt into IA (~ 15 fpm. 16:05 10645 1.3 800 1815 34 lAP= 900 16:07 10600 1.3 850 1830 36.6 Open choke on IA some more, lAP= 850. 16:09 10580 0/min 659 670 39.6 Shut choke. Shut down. Start circulation. 16:11 10570 mini1.8 672 3304 42 Dowellpump RDMO. 17:21 3500 1.8 596 2950 132/0 lAP= 700 psi. Switch to MEOH. 17:56 0 650 650 57 OOH trap whp. Shut Swab. RDMO 19:03 RD for night. (psig) (psig) (psig) (psig) (deg Ir) (psig) I 600 I 7so I so I 350 I si I sz I bbls Fluids Summary 258 2% KCL water 57 60/40 Meoh 10 Fresh H20 6 Gel Spacers 10 Dirty 20/40 sand volume 6.7 Class G Cement. CMT Properties Thickening Time: 5:54 min Fluid loss: Calculated API= 60 ml, Measured: 30 ml in 30 min ~ 170 deg F/1000 psi BHA# 1 Tool String Description DS ct connector. Stinger Squeeze nozzle OD ID Length Comments 2.0 0.10 2.0 4.58 2.0 0.56 5.24' Total Length ALASKA OIL & GAS CONSERVATION COMMISSION Attn. LARRY GRANT 3001 PORCUPINE DR. ANCHORAGE AK, 99501. USA Date: 7 December 1993 RE: Transmittal of Data ECC #: 5692.02 Data: PL Dear Sir/Madam, Reference: BP 3-23/N-32 ENDICOTT Enclosed, please find the data as described below: Prints/Films: 1 1 Sent by U.S. MAIL PLS FINAL BLUELINE PLS FINAL RF SEPIA Run # 1 Run ~ 1 Please sign and return to: Atlas Wireline Services Petrophysical Services 5600 B Street Suite 201 ~chorage, ~ 99518 Attn. Rodney D. Paulson Received by: ~~~ ~ Date: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISS,.. REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown __ Stimulate X Plugging Pull tubing Alter casing Repair well Perforatew Other 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P. 0. Box 196612, Anchorage, Alaska 99519-6612 5. Type of Well: Development Exploratory Stratigraphic Service 4. Location of well at surface 2520' SNL, 769' WEL, Sec. 8, T11N, R17E At top of productive interval 3769'SNL, 1013' WEL, Sec. 5, T11N, R17E At effective depth 3608'SNL, 1003' WEL, Sec. 5, T11N, R17E At total depth 3565' SNL, 989' WEL, Sec. 5, T11N, R 17E 12. Present well condition summary Total depth: measured true vertical Alaska Oil & Gas Cons. 6. Datum elevation (DF or KB) KBE = 55.48 feet 7. Unit or Property name Duck Island Unit/Endicott 8. Well number 3-23/N-32 SDI 9. Permit number/approval number 7-482/~?.~ ~(~- ~S 10. APl number 50- 029-21645 11. Field/Pool Endicott Oil Pool 11783feet 10543 BKBfeet Anchorage Plugs (measured) Effective depth: measured true vertical 11686feet 10456 BKBfeet Junk (measured) Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: Length Size Cemented Measured depth True ve~ depth BKB 122' 30" Driven 161' 161' 2443' 13 3/8" 3255 c.f. Permafrost 2482' 2482' 10894' 9 5/8" 575 c.f. Class G 10933' 9789' 1096' 7" 365c. f. Class G 10682'- 11778' 9572'- 10538' measured 11100'- 11132' 11224'- 11258' 11340'- 11354' 11150' - 11158' 11266'- 11304' 11390' - 11414' true vertical (Subsea) 9881'- 9909' 9991'- 10021' 10093'- 10106' 9925'-9932' 10028'- 10061' 10138'- 10159' Tubing (size, grade, and measured depth) 4 1/2" 12.6# L-80 TDS & DSS to 10599? 3 1/2" 9.2# L-80 TDS with 2 7/8" Tailpipe to 11189' Packers and SSSV (type and measured depth) 9 5/8" HB-BPR Packer at 10614'; 7" HB-BP Packer at 11166~ 7" WD Packer at 11365' and 11430'; 4 1/2" SSSV at 1512' 13. Stimulation or cement squeeze summary Scale inhibitor treatment Intervals treated (measured) 11100'-11132', 11224'- 11258', 11340'- 11354', 11150'-11158', 11266'-11304', 11390'- 11414' Treatment description including volumes used and final pressure 223Bbls scale inhibitor, lOOBbls seawater spacer w/ surfactant, 225Bbls CaCl water spacer, 712Bbls seawater overflush w/ surfactant, 152Bbls seawater tubi displacement and 20Bbls diesel to freeze protect FSIWHP=50 14. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation Subsequent to operation 1298 872 4603 0 374 1342 -/ 3771 5048 0 388 15. Attachments Copies of Logs and Surveys run Daily Report of Well Operations 16. Status of well classification as: Oil X Gas Suspended Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ~:/ ¢ ~ Technical Assistant II Form 10-404~ev 06/15/88 SUBMIT IN DU'PLIbATE BLUELINE AND SEPIA INFORMATION TO THE STATE ENDICO'i-F FIELD ONLY WELL NAME DATE INTERVALS ~,('-/~'/ 1-29/M-25 11/15/92'''/ 13100'-14069' ~..~'~ 1-49/P-21 11/19/92,.// 10600'-11200' ~,~../~' 2-06/J-22 1 0/25/92 ~' 1240'-12260' 2-58/S-09~'e .~'"Z. 11/1 5/92 "' 'i3900'-14328' ,~'--'/~'~' 3-01/N-29 11/9/92 - 11900'-12850' ~'-/$o 3-05/0-29 11/1 6/92 ..- 11300'-12400' 8~" ~ ? 3-21/L-34 11/1 6/92 -' 11950'-12742' ~o~'.../$-¢ 3-23/N-32 11/9/92 ,," 11050'-11664' oOoO.-Z;?.. 4-02/Q-28 ~,110/29/92 ~' 11800'-13000' 0/29/92 ./ 11800'-13000' LOG NAME RUN NO COMPANY NAME 4-40/P-43q,2.~/3..1 0/21/92 --" CPDK-10~3G~ CPDK-100,k~R/CC~LL NOISE/TEMP SURVEY PDK-100/GR/CCL PRODUCTION LOGGING (CALIPER SURVEY) PRODUCTION L~ING (CALIPER SURVEY) PRODUCTION LOGGING (CALIPER SURVEY) P~UCTION LOGGING (CALIPER SURVEY) JEWELRY LOG INJECTION PROFILE SURVEY 12550'-13570'-/ INJECTION PROFILE WARM BACK ATLAS WIRELINE ATLAS WIRELINE SCHLUMBEFiC~R ATLAS WIRELINE ATLAS WIRELINE ATLAS WIRELINE ATLAS WIRELINE ATLAS WIRELINE CAMCO CAMCO CAMCO R ECE/VED DEC 1 0 t992. Alaska 0ii & Gas Cons. CommissiOll Anchorage BLUELINE AND SEPIA INFORMATION TOTHE STATE ENDICO'i-i' FIELD ONLY WELL NAME DATE INTERVALS 7/26/92 ~ 12650'-13010' 2-64/U-10q~-~ 9/8/92 8750'-11300' 4-28/N-37 9/8/92 10950'-11280' 4-40/P-43 1 ?..~ L~ 'Z" 6/5/92 12600'-13605' LOG NAME Perforating Record Production Profile Log Perforating Record Perforating Record Leak Detection Survey (FLEXSTAK) Production Logging Services Production Profile Survey (FLEX STACK) Perforating Record, Jewelry Log SAG DELTA NORTH ONLY 2-32/SN-03 9/13/92 12860'-13266' Perforating Record STATE OF ALASKA ~: ALAoKA OIL AND GAS CONSERVATION COMMISS,~N 0 t I G i N A L -~ APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon __ Suspend Operation Shutdown __ Re-enter suspended well __ Alter casing__ Repair welt Plugging Time extension __ Stimulate X ..~'¢ fr, !'.:~, · Change approved program__ '--Pull tubing __ Variance__ Perforate __ Other 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P. O. Box 196612, Anchorage, Alaska 99519-6612 5. Type of Well: Development x Exploratory __ Stratigraphic __ Service 4. Location of well at surface 2520'SNL, 769' WEL, Sec. 8, T11N, R17E At top of productive interval 3769' SNL, 1013' WEL, Sec. 5, T11N, R17E RECEIVED At effective depth 3608' SNL, 1003' WEL, Sec. 5, T11N, R17E At total depth 3565' SNL, 989' WEL, Sec. 5, T11N, R17E 12. Present well condition summary Total depth: measured true vertical d U L - 1 IS92 Alaska 0il ° .~x Gas Cons. Oot~mission 11783 feet 10543 BKB feet Plugs (measured) 6. Datum elevation (DF or KB) KBE = 55.48 7. Unit or Property name Duck Island Unit/Endicott 8. Well number 3-23/N-32 SDI 9. Permit number 86-155 10. APl number 50- 029-21645 11. Field/Pool Endicott Oil Pool feet Effective depth: measured true vertical 11686 feet 10456 BKB feet Junk (measured) Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: Length 122' 2443' 10894' Size 30" 13 3/8" 9 5/8" Cemented Measured d~ TrueBw¢ical depth Driven 161' 161' 3255 c.f. Permafrost 2482' 2482' 575 c.f. Class G 10933' 9789' 1096' P' 365~ C~ss G 10682'-11778' measured 11100'-11132' 11224'-11258' 11340'-11354' 11150'-11158' 11266'-11304' 11390'-11414' 95 72' - 10538' true vertical (Subsea) 9881'- 9909' 9991'- 10021' 10093'- 10106' 9925'-9932' 10028'-10061' 10138'-10159' Tubing (size. grade, and measured depth) 4 1/2"1~6#L-80 TDS & DSSto 10599~3 1/2"9.2#L-80 TDS with 2 7/8"Tailp~e ~ 11189' Packers and SSSV (type and measured depth) 9 5/8" HB-BPR Packer at 10614'; 7" HB-BP Packer at 11166'; 7" WD Packer at 11365' and 11430'; 4 1/2" SSSV at 1512' 13. Attachments Description summary of proposal X Detailed operations program __ BOP sketch __ lZ~. Estimated date for commencing operation July, 1992 16. If proposal was verbally approved Name of approver Date approved 15. Status of well classification as: Oil X Gas__ Suspended__ Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed~~-/'Z~Z~ ¢--~~-* .~ Title Senior TechnicalAssistant II FOR COMMISSION USE ONLY Condifiohs of approval: Notify Commission so representative may witness Plug integrity_ BOP Test~ Location clearance __ Mechanical Integrity Test__ Subsequent form required 10- ~0 ~/ Original Signed By Approved by order of the Commission DaVid W. Johnston Form 10-403 Rev 06/15/88 bApproval No. Approved '_:op," ¢~-/~i? Returned Commissioner Date '7/~ / ~'.~ SUBMIT'IN TRIPLICATE ENDICOTT FIELD 3-23/N-32 Two of the three wells which were treated with Nalco's 91VM-057 scale inhibitor last year are likely to require retreatments this year, as originally planned. Designs for these retreatments have been prepared by Nalco, and are attached for your reference. Current plans are to arrange with Nalco to prepare and transport 58 drums of Nalco's 91VM-057 inhibitor from their Sugarland, Texas processing facility to Anchorage. The chemical will be stored until the specific retreatment time is finalized. Having this chemical available in Anchorage storage will enable us to respond quickly once Nalco confirms the need for retreatment. The two subject wells are 3-11/M-30 and 3-23/N-32. Recently analyzed residual returns for well 3-11/M-30 have shown a level of <3 ppm chemical in the production stream for the past two analyses. Cumulative produced water since the squeeze treatment should exceed the design volume within the next two months. The inhibitor volume pumped in 3-23/N-32 last August was limited to 15 drums due to chemical availability, for an estimated treatment life of less than one year. While residual analyses to date have remained at or near the 10 ppm effective level, a retreatment for this well is also likely for this year. The remaining well treated by Nalco, 3-33/K-37, still shows good residual returns, and should not require another treatment until next year. RECEIVED ~laska Oil & ~a~ ~,~ Anchorag~ 2652/DVT Nalco Scale Inhibitor Squeeze Procedure Well 3-23/N-32 Retreatment PRE-TREATM ENT OPERATIONS 1. Please contact J. D. Dyess in Anchorage at 696-4690 for the necessary arrangement to be made for the treatment and flowback analysis. 2. Obtain well test at normal recommended rate prior to treatment. Ensure WC sample is taken. SCALE INHIBITOR TREATMENT 1. Mix or obtain fluids as detailed on attached treatment fluids sheet. . MIRU for bullhead treatment. Pump the following without exceeding frac gradient. Avoid shutting down during the treatment. Evidence indicates that even brief shut-downs of 5-10 min have an adverse affect on the treatment. a. 17 drums Nalco oligomer scale inhibitor in 200 bbls seawater b. 100 bbl SW spacer c. 335 bbl 2% CaCI2,2H20 in SW d. 774 bbl SW ovedlush Displace to within 10 bbls of top perforation (approximately 172 bbls). Consider using SW for displacement and minor diesel freeze protection volume if GLT is available to return well to production. Note: Filter all fluids that are to enter the perfs to 3 p., preferably on the fly while pumping the job. 3. RDMO. Leave the well shut in for 24 hours. 4. POP well to test separator for 24 hrs. and arrange with Nalco to monitor returns. Nalco will pull brine samples for inhibitor flowback evaluation, per the following schedule. · Every 2 hrs for 1st 24 hrs · Every 6 hrs for next 24 hrs · Every 12 hrs next 48 hrs · Every 24 hrs next 3 days · Twice weekly for two weeks · Montly thereafter Nalco will mark each sample with date and time pulled and analyze the brine samples at the Endicott production lab. Please note on telex when the well is actually POP'd. . After the last 24 hr sample has been obtained (~8th day), set a DH corrosion coupon in the sliding sleeve (if possible) to monitor scale inhibitor effectiveness. POP at recommended rate and obtain a welltest. Ensure that a watercut sample is pulled during the test. 6. Pull the downhole coupon monthly, as operations permit, and inspect for scale deposition. 2652/DVT RECEiVXr' Alaska Oil & Gas Coi~s. Cornrr~iss~or' NALCO SCALE INHIBITION PROGRAM TREATMENT FLUID SUMMARY Well 3-23/N-32 Retreatment NALGO OLIGOMER. 91VM-057 Volume: 223 bbls Dilute 17 drums (935 gal) of Nalco's oligomer with 200 bbls of seawater in a stainless steel vac truck equipped with mixing paddles. Mix thoroughly. CaCI2.2H20 Volume: 335 bbis Add approximately 2378 lbs CaCI2 to seawater to make 392 bbls of 0.2% CaCI2. Adjust pH with NaOH to "-9. SEAWATER SPACER/OVERFLt)SH Add non-ionic surfactant to seawater. Volume: 774 bbls Ser vice Company BJ Halliburton Dowe II/Sch lu mbe rge r Product Name NE-18 Losud 300 F-75N Concentration O.2% 0.2% O.2% 2652/DVT STATE OF ALASKA ALAbrtA OIL AND GAS CONSERVATION COMMISS,uN REPORT OF SUNDRY WELL OPERATIONS" 1. Operations performed: Operation shutdown Stimulate X Plugging Pull tubing__ Alter casing Repair well Perforate Other 2. Name of Operator BP Exploration (Alaska) Inc. 3. Address P. O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 2520'SNL, 769' WEL, Sec. 8, T11N, R17E At top of productive interval 3769'SNL, 1013' WEL, Sec. 5, T11N, R17E At effective depth 3608' SNL, 1003' WEL, Sec. 5, T11N, R17E At total depth 3565' SNL, 989' WEL, Sec. 5, T11N, R17E 5. Type of Well: Development Exploratory Stratigraphic Service RECEIVED S E P ? t99 Alaska Oil & Gas Cons. Cornm~ss~en ;Anchorage 6. Datum elevation (DF or KB) KBE -- 55.48 feet 7. Unit or Property name Duck Island Unit/Endicott 8. Well number 3-23/N-32 SDI 9. Permit number/approval number 7-482/91-137 10. APl number 50- 029-21645 11. Field/Pool Endicott Oil Pool 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical 11783feet 10543 BKBfeet 11686feet 10456 BKBfeet Plugs (measured) Junk (measured) Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: Length Size Cemented Measured depth True ve~ depth BKB 122' 30" Driven 161' 161' 2443' 13 3/8" 3255 c.f. Permafrost 2482' 2482' 10894' 9 5/8" 575 c.f. Class G 10933' 9789' 1096' 7" 365 c.£ Class G 10682'-11778' 9572'-10538' measured 11100'-11132' 11224'-11258' 11340'-11354' 11150'-11158' 11266'-11304' 11390'-11414' true vertical (Subsea) 9881'-9909' 9991'-10021' 10093'-10106' 9925'-9932' 10028'-10061' 10138'-10159' Tubing (size, grade, and measured depth) 4 1/2"12.6#L-80 TDS & DSS to 10599~3 1/2"9.2#L-80 TDSwith 2 7/8'Tailp~eto 11189' Packers and SSSV (type and measured depth) 9 5/8" HB-BPR Packer at 10614'; 7" HB-BP Packer at 11166'; 7" WD Packer at 11365' and 11430'; 4 1/2" SSSV at 1512' 13. Stimulation or cement squeeze summary Scale inhibitor treatment Intervals treated (measured) 11224'- 11258', 11266'- 11304', 11340'- 11354', 11390'- 11414' 14. Treatment description including volumes used and final pressure 195 Bbls scale inhibitor, 100 bbls seawater spacer w/surfactant, 390 Bbls, Calcium chloride water spacer, 400 bbls seawater overflush FSWHP=375 psi Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation 1342 1282 2385 0 510 Subsequent to operation 1029 962 2401 0 451 15. Attachments Copies of Logs and Surveys run Daily Report of Well Operations 16. Status of well classification as: Oil X Gas__ Suspended__ Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed "~' /' /~-'~'~'~-~__ Title EndicottOperationsandProductionLeadEngineer Form 10-404 Rev 06/15/88 Date SUBMIT IN DUPLICATE John Boyle August, 20, Page 2 1991 WELL 1-67/T-20 11250'-11800' FUll BORE PRODUCTION LOGS SCHLUMBERGER WELL 2-64/U-10V' 13600'-14600' NJ. PROFILE STEP RATE SURVEY WELL 3-21/L-34 ',/ 12300'-1 2645' TEMPERATURE SURVEY WELL 3-23/N-32 v 1 0500'-11500' PRODUCTION LOC:~ING SERVICES ATLAS WIRELINE WELL 3-25/M-27V 13500'-13976' STATIC TEMPERATURE SURVEY C/WICk. 13000'-13964' v/ PRODUCTION PROFILE SURVEY WELL 4-08/P-27,/ 13000'-13250' STATIC TEMPERATURE SURVEY Sincerely, J~. Haas JLH/clt xc' File 6.10 2142/J LH/clt 7/31/91 RUN TWO 7/2-6/91 RUNONE 6/30/91 RUNONE 7/1 2/91 RUNONE 7/1 5/91 RUNONE 6/28/91 RUNONE 6/22/91 RUN ONE STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon __ Suspend __ Operation Shutdown __ Re-enter suspended well __ Alter casing__ Repair well__ Plugging __ Time extension__ Stimulate X Change approved program __ Pull tubing __ Variance __ Perforate __ Other __ 2. Name of Operator BP Exploration (Alaska) inc. 3. Address P. O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 2520'SNL, 769' WEL, Sec. 8, T11N, R17E At top of productive interval 3769' SNL, 1013' WEL, Sec. 5, T11N, R17E At effective depth 3608' SNL, 1003' WEL, Sec. 5, T11N, R17E At total depth 3565' SNL, 989' WEL, Sec. 5, T11N, R17E 5. Type of Well: Development X Exploratory __ Stratigraphic __ Service 6. Datum elevation (DF or KB) KBE = 55.48 feet 7. Unit or Property name Duck Island Unit/Endicott 8. Well number 3-23/N-32 SDI 9. Permit number 86-155 1~. Apl number i 50- 029-21645 12. Present well condition summary Total depth: measured true vertical Effective depth' measured true vertical Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: Length 11783 feet 10543 BKB feet 11686 feet 10456 BKB feet Size Plugs (measured) Junk (measured) Cemented 122' 2443' 1O894' 30" 13 3/8" 9 5/8" 11. Field/Pool Endicett Oil Pool Measured d~ TrueBKBve~ical depth Driven 161' 3255 c.f. Permafrost 2482' 575 c.f. Class G 10933' 161' 2482' 9789' 9572'- 10538' 1096' 7" 365~ C~ss G 10682'-11778' measured 11100'-11132' 11224'-11258' 11340'-11354' 11150'-11158' 11266'-11304' 11390'-11414' true vertical (Subsea) 9881'- 9909' 9991'- 10021' 10093'- 10106' 9925'-9932' 10028'-10061' 10138'-10159' Tubing (size, grade, and measured depth) 4 1/2"1Z6#L-80 TDS & DSS ~ 10599~3 1/2"9.2#L-80 TDS with 2 7/8"Tailp~eto 11189' Packers and SSSV (type and measured depth) 9 5/8" HB-BPR Packer at 10614'; 7" HB-BP Packer at 11166'; 7" WD Packer at 11365' and 11430'; 4 1/2" SSSV at 1512' 13. Attachments Description summary of proposal__ Detailed operations program X BOP sketch X / 14. Estimated date for commencing operation I 15. Status of well classification as: May 15, 1991 16. If proposal was verbally approved Oil X Gas ~ Suspended Name of approver Date approved Service 17. I hereby certify that the foregoing is true and correct to the best bf my knowledge. Title Endicott Res. Studies and Dev. Lead Engr. Date FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Plug integrity BOP Test__ Location clearance Mechanical Integrity Test__ Subsequent form required 10- 0RIG!N~t $~.GN£D BY Approved by order of the Commission LONNIF C SN~,ITH J Approval No. ~,/~/'~ ~ Commissioner ,,kpprovea Cup¥ Returned Form 10-403 Rev 06/15/88 Date ,._~"-~--/ 0--~// SUBMIT IN TRIPLICATE 3-23/N-32 Scale Removal Program ACID TREATMENT Pre-Treatment Procedure Arrange with Production Coordinator to conduct a maximum rate pre- stimulation well test at fully open choke setting. Ensure the well has stabilized during the test pedod. Obtain wellhead sample. Coordinate with service company to perform emulsion/sludge tests per AP! RP 42 to test for emulsion tendencies of produced fluids mixed with spent and unspent HCI/additives. Tests should be run with 16% HCI, utilizing ferdc ion concentration of 5000 ppm. Additives should be adjusted as required according to test results. Obtain three additional 1-quart samples of produced water for use as a baseline water composition measurement. This information will be necessary when evaluating produced fluid returns. MIRU slickline and puli SSSV. Make successive drift runs to within the nearest 0.1" to gauge scale accumulations within the production packer 2 7/8" tailpipe and the 2 7/8" WD packer tailpipes. RDMO slickline. · MIRU Camco or Western Atlas. RIH with 2-1/8 inch OD 36-arm caliper tool or the 1 11/16" caliper/FBS. Obtain a caliper profile of the liner diameter up to the tubing tail. POH. RDMO Camco. · Block SSV with fusible cap and shut-in well at choke and wing~*vaive;~ .Ne-te~-~ ~ wellhead and annulus pressures. !,!-~.' i'? ~:.? .~'~i-, ii'~:~ ~.'~.~'"' ' Treatment Preparation/Application ~ ~'~; ''~ ~'J''''- ~'. ;.~. ;~': ~.;~.:;~',,';~ ?~:~;.~ :. · Prepare treatment consisting of 1000 gallons 15% HCI, 110 gallons xylene, and corrosion inhibitor, sudactant, sequestering agent, emulsion breaker, and anti-sludge agent additives. Additive product designations and concentrations are summarized by vendor in the attachment. Ensure that treatment temperature is 120-140°F. This treatment volume should be adequate to dissolve any calcium carbonate present and to displace fluids in the treatment zone with an allowance for overflush into the perforations. The treatment zone should extend from the tubing tail (11189' md) down to the bottom of the 2B5 perforations (11414' md). · Have on hand sufficient diesel to be used as displacement fluids. · MIRU pump truck, vac truck, and CTU. Pressure test CTU and equipment to 4000 psi. Sample acid to ensure that iron concentration is less than 350 ppm. Treatment Pre Daratio n/A~)[~lication RIH with CTU/TEL and swirl nozzle. Note- assure that any potential scale accumulations within the tailpipe are accounted for when selecting an appropriate tubing end iocator. Tie in depth to tubing tail and locate nozzle at top of treatment zone (11069' md). · Pump ~30 bbl diesel down the tubing / coiled tubing annulus through the pump-in sub to ensure wellbore is liquid packed. Pump entire treatment with additives at a rate of 1-2 bpm, reciprocated at 10- 20 fpm over the treatment zone. Treatment fluid should be filtered through a nominal 3 micron filter during pumping. No diverting material is requested due to a confirmed cement channel in the well. · Displace all acid from the CT with diesel while finishing reciprocation, then POH. Leave the well shut-in for a 4 hour soak period. Once out of the hole with CT, rig down CTU. Close the master valve and open up the wing and choke. Pump 30 bbls of 2% NH4Cl containing 20 gallons of corrosion inhibitor and 3 gallons of surfactant down the flowline. Post-Treatment Pr¢cedure Return well to production following the 4 hour soak pedod at the same cho'ke setting as the previous logging survey. Attain wellhead samples as bottoms up arrives and continue to sample until the well cleans up. Forward these samples on to the service company lab and/or Chemlink for analyses. MIRU Camco or Western Atlas. Repeat caliper, flowmeter, and gamma ray surveys to evaluate acid treatment effectiveness. Replace SSSV. · Arrange with Production Coordinator to obtain maximum rate well test. Return well to production at recommended rate of 1400 bopd. if survey indicates that scale remains in liner, a mechanical removal program will be developed. 3-23/N-32 Scale Removal Program ACID TREATMENT (cont.) Acid Syql;em Additive Designation~ by Vendor Additive Dowell Halliburton ~ HCI/Xylene PAD DAD One Shot Corrosion Inhibitor 4 gal/Mgal A-250 3gal/Mgal HAl-85 4gal/Mgai Ci-25 Surfactant 0.2% F75N** 0-0.5% LOSURF 251 & 300* 4gal/Mgal NE-18 Sequestering Agent 25#/Mgal L-58 Emulsion Breaker 25#/Mgal Fercheck A 0-10 gal/Mgal W-54' 25#/Mgal Ferrotrol 210 Anti-Sludge Agent 0-10 gal/Mgai W-35' 0-12 gal/Mgal AS-5* None _. None 0-10 gal/Mgal Inflow-45* Notes: * Concentrations dictated by emulsion/sludge testing requirements .:. ** Doweil recommends use of F-40N sudactant when OSR is used and F-75N in all other cases B.O.P. STACK CONFIGURATION 13-5/8 IN. TRIPLE RAM STACK S000 PSI WP DRILLING ANNULAR PREVENTER I J I I PIPE RAMS 1 1 I i BLIND RAMS IN. KILL LINE J J DRILLING · ~ SPOOL GATE GATE J PIPE RAMS I ! HAND GATE 4 IN. CHOKE LINE HYD. ASST. GATE John Boyle Alaska Oil and Gas Conservation Commission Page Two WELL 2-34/P-14 LEAK DETECTION 9100'-10900' 3/3/91 RUNONE WELL 2-44/R-12 INJ 11900'-1 2340' 3/2/91 RUNONE WELL 3-11/M-30 SURF-1495' 3/28/91 RUN ONE WELL 3-23/N-32 PROD-F 11200'-11660' WELL 3-29/J-32 HRS 11950'-12700' SPINNER WELL 4-08/P-27 PROD-F 13000'-13710' 3/27/91 RUNONE 3/22/91 RUNONE 3/26/91 RUN ONE BP EXPLORATION February 9, 1990 BP Exploration (Alaska) Inc. 900 East Benson Boulevard RO, Box 196612 Anchorage. Alaska 99519-6612 (907) 561-5111 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Endicott Field - Bottom-Hole Pressure Reoorts Dear Sirs' .. Enclosed are Bottom Hole Pressure Reports for the following wells Well Name Date 1-01/J-19 1-6-90 -- 2-52/S-14 1-8-90 2-70/U-15 1-1 3-90 3-23/N-32 1-29-90 3-47/Q-35 12-26-89 4-04/T-26 12-30-89 4-18/S-30 1-7-90. ' 4-46/No39 1 2-29-89 if there are any questions regarding this data, please contact Jeanne Haas at 564-5225. Sincerely, eanne L. Haas JLH Enclosures ",i~¢.& Oil & Gas Cons. ~nct~or~3 cc' File: 76.13 · WELL 3-23/N-32 *PRODUCTION PROFILE LOG 11200' - 11500' Run No. ~ CAMCO WELL 4-18/S-30 *TEMPERATURE SURVEY 11480' - 12000' Run No. 1 CAMCO Sincerely, j~ne L. Haas JLH/Ims cc: File 06.10 BP EXPLORATION October 31, 1989 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 John Boyle Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Dear Mr. Boyle' Enclosed please find one sepia and one blueline print for the cased hole well logs run in the following Endicott wells: WELL 3-23/N-32 *PRODUCTION PROFILE Logged 1'0/13/89 Run 1 Logged by Camco WELL 4-04/T-26 *DUAL LATEROLOG MICROSPHERICALLY FOCUSED LOG Logged 9/13/89 Run 1 *SPECTRAL DENSITY DUAL SPACED NEUTRON LOG Logged 9/13/89 Run 1 *FORMATION TEST LOG Logged 9/14/89 Run 1 Logged by Halliburton Sincerely, Gregory (' ~.~a~ Oil & Gas Cons. Commissio[i GND/Ims ~ Anchorage cc: File 06.10 BP EXPLORATION BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 August 22, 1989 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Endicott Field - Bottom-Hole Pressure Reports Dear Sirs' Enclosed are Bottom Hole Pressure Reports for the following wells. All the wells except 5-03/SAGD-09 are located in the Endicott Reservoir. Well Name Date 1-39/P-17 (Upper) 06-19-89 1-39/P-17 (Lower) 06-19-89 1-47/Q-21 08-03-89 2-08/K-16 (Upper) 06-20-89 2-08/K-16 (Lower) 06-20-89 2-46/Q-15 06-21-89 ,· 2-46/Q-15 08-04-89 2-52/S-14 08-03-89 3-23/N-32 (Upper) 07-14-8 9 3-23/N-32 (Lower) 07- 14-8 9 4-08/P-27 (Upper) 06-16-89 4-08/P-27 (Lower) 06-16-89' 5-03/SAGD-09 08-1 1-89 Standard Alaska Production Company 900 East Benson BouJevara P-O. Box 196012 Anchorage, AJaska 99510-66i 2 December 6, 1988 STANDARD ALASKA PRODUCTION Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Sirs' Endicott F/eld - Bottom-Hole Pressure Report5 Enclosed are Bottom Hole Pressure Reports for the following wells in the Endicott Reservoir: Well Name 1-01/J-19 1-35/0-25 3-23/N-,32 3-45/M,-39 4-02/Q:28 4-08/p,27 4-28/~r-37 If there are any questions regarding Twyford at 564-440'I. this data, Date 11-19-88 11-19-88 11-1-88 11-2-88 1 1-5-88 11-22-88 11-25-88 please contact Loren JLH A unit of the original Standard Oil Company Founded in Cleveland, Ohio, in 1870, Sincerely, L. Haas · ,_~..,~. '~xi.~z,¢a.(:lil & fas Cons. Commission '-.'-.-~ gnch0rage Standard Alaska - Production Company 900 East Benson Boulevc o P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 STANDARD ALASKA P~ODUCTION November 21, 1988 John Boyle Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Endicott Well Log Information Dear Mr. Boyle: Enclosed please f'md one sepia and one blueline print for the cased hole well logs mn in the following Endicott well: WELL 3-23/N-32 *PRODUCTION PROFILE 11114'-11514' Run No. 1 Camco WELL 4-08/P-27 *PRODUCTION PROFILE 13000'-13600' Run No. 1 Camco Sincerely, ~illard Received By Date A unit of the original Standard Oil Company Founded in Cleveland, Ohio, in 1870. FEB 2, 1988 STANDARD ALASK.A PRODUCTION John Boyle Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Boyle: The following log information for Endicott wells is enclosed: 1 So~e~~and blueline print for: 3-32/N-32~. Run 1 Jan. 6, 1988 * Flowmeter Log Date Sincerely, Bruce St. Pierre A unit al the original Standard Oil Company Founded in Cleveland, Ohio, in 1870. Standard Alaskr-- Production Con ~ 900 East Benson ~,.?.vard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907~ ,561-5t 11 OCT 2, 1987 STANDARD ALASKA PRODUCTION William Van Alen Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Van Alen: The following log information for Endicott wells is enclosed: sepia print and 1 blueline print for: N-32 Run 1 September 21, 1987 * Completion Record Sincerely,/zp f r BrOc'e SL. Pierre Received b9 Date A unit of the or~gmoi Sto.ndord Oil Compor~y Founded in Cle, eJond Ohio in 1870 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operation performed: Operation shutdown I-I Stimulate CI Plugging [] Perforate [] Pull tubing [] Alter casing [] Other [] 2. Name of Operator Standard Alaska Production Company 3. Address P. O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 2520'SNL, 769' WEL, Sec. 8, T11N, R17E At top of productive interval 3769'SNL, 1013' WEL, Sec. 5, T11N, R17E At effective depth 3608' SNL, 1003' WEL, Sec. 5, T11N, R17E At total depth 3565' SNL, 989' WEL, Sec. 5, T11N, R17E 5. Datum elevation (DF or KB) KBE = 55,48 feet 6. Unit or Property name Duck Island Unit/Endicott 7. Well number 3-23/N-32 SD/ 8. Approval number 7-482 9. APl number 5 0 - 029-21645 10. Pool Endicott Pool 1. Present well condition summary Total depth: measured true vertical Effective depth: Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: measured true vertical Length BKB BKB 11783 feet 10542 feet 11686 feet 10455 feet Size Plugs (measured) Junk (measured) Cemented Measured depth See Attachment i measured 11100'-11132' 11224'-11258' 11340'-11354' 11150'- 11158' 11266'-11304' 11390'- 11414' true vertical (Subsea) 9881'-9909' 9991'-10021' 10093'-10106' 9925'-9932' 10028'-10061' 10138'-10159' Tubing (size, grade and measured depth) 4-1/2" 12.6~ L-80 TDS & DSS to 10599' True Vertical depth NasRa 0il & Gas Cons. C0mmiss[0~ Anchorage Packers and SSSV (type and measured depth) 9-5/8" TlWpacker @ 10614'; 7" TlWpacker @11171'; 7" WD packers @ 11365' and 11430'; 4-1/2" SSSV @ 1512' 2. Stimulation or cement squeeze summary Intervals treated (measured) Treatment description including volumes used and final pressure . Prior to well operation Subsequent to operation Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Not On Production Tubing Pressure 4. Attachments initial Perforating Summary X Daily Report of Well Operations J~ Copies of Logs and Surveys Run ~ 5. I hereby certify that the foregoing is true and correct to the best of my knowledge ~ '~'-o~,,o~- ~7 ~,-~ ~igned ~-., - ~'-'~ Title Division Drilling Engineer ~/ Form 10-404 Rev. 12-1-85 Date Subrflit in Duplicate Casing Structural Conductor Surface Intermed. Liner Length 161' 2482' 1 0933' 1095' Size 30" 1 3- 3/8" 9-5/8" ,, ATTACHMENT I 3-23/N-32 SDI Cemented Measured Depth True Vertical depth BKB Driven 1 61 ' 161' 3255 c.f. PF 2482' 2 4 8 2' 575 cu.ft. Class G + .75% CFR-2 + 0.12% HR-7 10933' 10683'- 11778' 365 CU.fl. Class G; .5% Halad 344 + .3% LWL 9789' 9572'-1 O54O' ENDICOTT WELL 3-23/N-32 SDI INITIAL PERFORATION SUMMARY The following intervals for initial oil production were perforated September 21, 1987 using Baker 5" drill pipe conveyed perforating guns at 4 s.p.f. 11100' - 11132' MD (Ref. DIL/SFL 09/12/86) 11150' - 11158' MD (Ref. DIL/SFL 09/12/86) 11224' - 11258' MD (Ref. DIL/SFL 09/12/86) 11266' - 11304' MD (Ref. DIL/SFL 09/12/86) 11340' - 11354' MD (Ref. DIL/SFL 09/12/86) 11390' - 11414' MD (Ref. DIL/SFL 09/12/86) A tubing and packer completion followed immediately thereafter. A lubricator was installed and tested to 3500 psi and a SSSV was set and tested in the ball valve nipple at 1512' on September 25, 1987 after the well was completed. LH/kb/1930D Rig: PAA #7 Well: 3-23/N-32 (SDI) Daily Drilling Report -- ENDICOTT September 21, 1987 at 0600 hrs API: 50-029-21645 STANDA,.qD ALASKA PF~ODUCTION Current Operation: Mud Type: Brine SURVEY MD 0600 Depth: 11,686' Day: 30 48-Hour Ftg: -' RIH with perforating guns. i-bO Accept rig at 2430 hours on 9-19-87. N/D tree. N/U and test BOPE. RIH and displace diesel. RIH to PBTD at 11686 ft. Filter brine. POH. RIH with perforating guns. WT: 9.6 VIS: PV: YP: FL: Solids: Temp: OF ANGLE DIRECTION TVD SECTION COORDINATES DLS STANDARD ALASKA PRODUCTION Rig: PAA #7 Well: 3-23/N-32 (SDI) Daily Drilling Report-- ENDICOTT September 22, 1987 at 0600 hrs API: 50-029-21645 0600 Depth: 11,686' Day: 31 24-Hour Ftg: -' Current Operation: POH. RIH with perforating guns' and space out. R/U flow manifold. Pressure up and fire guns. Flow oil to surface. Kill well with 9.6 ppg brine. Spot bridge sal pill. Filter brine. POH. Mud Type: Brine WT: 9.6 VIS: PV: YP: FL: Solids: Temp: OF SURVEY MD ANGLE DIRECTION qWD SECTION COORDINATES DLS Rig: PAA #7 Well: 3-23/N-32 (SDI) (' Daily Drilling Report -- ENDICOTT September 23, 1987 at 0600 hrs APl: 50-029-21645 STANDARD ALASKA PRODUCTION Current Operation: Mud Type: Brine 0600 Depth: 11,686' Day: 32 24-Hour Ftg: -' Run 4-1/2" completion. POH. L/D perforating guns. Run gauge ring and junk basket. RIH and set WD packer at 11,430 ft. RIH and set WD packer at 11,365. ft. Run 4-1/2" completion. WT: 9.6 VIS: PV: YP: FL: Solids: Temp: OF ANGLE DIRECTION TVD SECTION ~RDINATE$ DLS STANDARD ALASKA PRODUCTION Rig: PAA//7 Well: 3-23/N-32 (SDI) Daily Drilling Report -- ENDICOTT September 24, 1987 at 0600 hrs API: 50-029-21645 0600 Depth: 11,686' Day: 33 24-Hour Ftg: -' Current Operation: RIH with flow sleeve. RIH with 4-1/2" completion, space out and land in wellhead. N/D BOPE. N/U and test tree to 5000 psi. Pull dummy SSSV and set plug in tailpipe. Pressure up and'set packer with 3000 psi., Test annulus to 2500 psi. Open s.s., displace tubing to diesel, close s.s. Pull plug from tailpipe. Pull isolation sleeve. RIH with flow sleeve. Mud Type: Brine WT: 9.6 VIS: PV: YP: FL: Solids: Temp: OF SURVEY ..MD ANGLE DIRECTION TVD SECTION O2)O~A~$ DLS Rig: PAA #7 Well: 3-23/N-32 (SDI) Daily Drilling Report -- ENDICOTT September 25, 1987 at 0600 hrs API: 50-029-21645 STANDARD ALASKA PRODUCTION Current Operation: Mud Type: Brine 0600 Depth: 11,686' Day: 34 24-Hour Ftg: -' Rig released. Install flow sleeve. Run and test SSSV. Release rig at 1000 hours on 9-24-87. Move rig to 3-15/K-33. WT: 9.6 VIS: PV: YP: FL: Solids: Temp: OF ANGLE DIREr'I, ON TVD SECTION COORDINATES DLS STATE OF ALASKA ALAb,,A OIL AND GAS CONSERVATION COk .... ,SSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon ~ Suspend ~ Operation Shutdown [] Re-enter suspended well [] Alter casing Time extension © Change approved program .[] Plugging [] Stimulate [] Pull tubing ~ Amend order Q Perforate [~ Other fee 2. Name of Operator Standard Alaska Production Company 3. Address P. O. Box 196612, Anchorage, Alaska 99519-6612 4. Location of well at surface 2520' SNL, 769' WEL, Sec. 8, TllN, R17E At top of productive interval 3769' SNL, 1013' WEL, Sec. 5, TllN, R17E At effective depth 3608' SNL, 1003' WEL, Sec. 5, TllN, R17E At total depth 3565' SNL, 989' WEL, Sec. 5, TllN, R17E 5. Datum elevation (DF or KB) KBE = 55.48 6. Unit or Property name Duck Island Unit/Endicott 7. Well number 3-23/N-32 SDI 8. Permit number 86-155 9. APl number 50-029-21645 10. Pool E~dicott Pool 11. Present well condition summary Total depth: measured true vertical 11783 feet 10542 BKB feet Plugs (measured) Effective depth: measured 11686 feet true vertical 10455 BKB feet Junk (measured) Casing Length Size Structural Conductor 161' 30" Surface 2482 ' 13-3/8" Intermediate 10933 ' 9-5/8" Production Liner 1095' ?" Perforation depth: measured Cemented Measured depth Driven 3255 cu.ft. Permafrost 575 cu.ft. Class G + .75% CF2-2; 0.12% HR-7 161' 2482' 10933' 365 cu.ft. Glass G 10683'-11778' .5% Halad 344 + .3% LWL True Vertical depth BKB 161' 2482' 9789' 9572'-10540' true vertical RECEIVED Tubing (size, grade and measured depth) 1 Jt. 4-1/2" 12.6# L-80 TDS @ 80' JUL ~ 0 1987 Packers and SSSV (type and measured depth) None 12.Attachments Description summary of proposal Naska 0il & 6as Cons. Commissio~¢ Ar~orage Detailed operations program [] BOP sketch [] 13. Estimated date for commencing operation August 20, 1987 14. If proposal was verbally approved Name of approver Date approved li115 I hereby certify that the foregoing is true and correct to the best of my knowledge Conditions of approval Approved by Title Division Drillinq Enqineer Date 7/a ~./~ 7 Commission Use Only Notify commission so representative may witness I Approval [] Plug integrity [] BOP Test [] Location clearanceI No..,,7! ,~ · ¥,[~ ro ~....,., .... Commissioner the commission Date Form 10-403 Rev 12-1-85 1930D Submit in triplicate ENDICOTT ~]~LL 3-23/N-32 SDI INITIAL PERFORATION PROPOSAL We propose to perforate the following intervals for initial oil production using drill pipe conveyed perforating guns at 4 s.p.f, in August, 1987. 11100 - 11132 MD (Ref. DIL/SFL 09/12/86) 11150 - 11158 MD (Ref. DIL/SFL 09/12/86) 11224 - 11258 MD (Ref. DIL/SFL 09/12/86) 11266 - 11304 MD (Ref. DIL/SFL 09/12/86) 11340 - 11354 MD (Ref. DIL/SFL 09/12/86) 11390 - 11414 MD (Ref. DIL/SFL 09/12/86) After perforating, the guns will be removed and the well will be shut-in. We will then run a:tubing and packer completion. A lubricator will be installed and tested to 3500 psi and a SSSV will be set and tested in the ball valve nipple after the well is put on production. J~H/kb/1930D DUCK O uc ~< Standard Alasl~a Production Company 900 Eost Benson Boulevord P.O. Box 196612 Anchorage, Alaska 99519-6612 (9071 561-5111 Mr. Lonnie Smith Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Duck Island Unit/Endicott Wells Dear Mr. Smith, STANDAItU We are requesting that the AOGCC adopt dual designation for all well names in the Duck Island/Endicott Unit for operational and safety reasons. Dual designation lists the numeric surface location followed by an alpha-numeric bottom hole location. This will be indicated in future wells on Form 10-401 in Item Number 8. We also ask that wells drilled to date be referenced by this dual designation. For your use is a list of wells drilled to date. WELL NAME PERMIT NUMBER API NUMBER 1-5/0-20 (MPI) 1-27/P-20 (MPI) 1-29/M-25 (MPI) 1-35/0-25 (MPI) 1-41/0-23 (MPI) 1-47/Q-21 (MPI) 2-2/P-18 (MPI) 2-4/M-19 (MPI) 2-6/J-22 (MPI) 2-14/0-16 (MPI) 2-34/P-14 (MPI) 2-62/Q-17 (MPI) 3-1/N-29 (SDI) 3-5/0-29 (SDI) 3-21/L-34 (SDI) 3-23/N-32 (SDI) 3-27/M-33 (SDI) 3-33/K-37 (SDI) 3-35/L-36 (SDI) 3-47/Q-35 (SDI) 4-8/P-27 (SDI) 4-20/M-35 (SDI) (T-34 Redrill) 4-20/T-34 (SDI) (Abandoned) ! ~ ~,~ ~.fbnit of ti .... iginol Standard Oil C .... pany ~[ounded in Cleveland, Ohio, in 1870. 86-106 50-029-21605 87-9 50-029-21693 86-181 50-029-21669 86-184 50-029-21672 87-32 50-029-21713 86-131 50-029-21625 86-63 50-029-21568 86-82 50-029-21585 87-18 50-029-21699 86-149 50-029-21639 86-172 50-029-21662 86-158 50-029-21648 86-190 50-029-21678 86-130 50-029-21624 87-33 50-029-21714 86-155 50-029-21645 86-83 50-029-21586 86-180 50-029-21668 87-20 50-029-21701 86-64 50-029-21569 87-8 50-029-21692 86-173 50-029-21640-01 86-150 50-029-21640 We thank you for your assistance and should you have any questions, give me a call at 564-5007. Yours very truly, R. S. Allan Division Drilling Engineer RSA/MAW/pm/1664D cc: R. H. Reiley B. J. G. Vidrine I. R. Robertson D. Huxley B. Ross File 16.4 Endicott Development Standard Alasko ' '- Production Comf. 900 East Benson Bou,evord P.O. Box 196612 Anchorage. Alaska 99519-6612 1907.,' 564-51 I I STANDARD AL ..-~KA PRODUCTION October 8, 1986 William. Van Alen Alaska 0il & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Van Alen: The following log information for Endicott wells is enclosed: Run 1 DLL/LDT - CNL/NGT/SDT 2 magnetic tapes with listings: i __ Sincerely, Received by Date 0039E/26 LaUra FujikaW~ ~ - c.- OCT ~8~ ~' AJas~ Oil &A~c~lo~r~;~. CommJssio. A c,,~:t o! H~e or,gmol $~ondord O,I Co'~,pa,~y Fou-ded ,,, Cle,..elond C)h,a ,,~ 1870 Standard Alaska Production Cornpa 900 East Benson Bou :rd P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 564-5111 STANDARD ALASKA PRODUCTION September 30, 1986 William Van Alen Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Van Alen: The following log information for Endicott wells is enclosed: 1 sepia print and 1 blueline print: ~N-32 Run 1 September 23, 1986 o Recomputed CBT Sincerely, LAF:gh 0039E Laura Fuj ika~a Received by Date 0039E/24 A unit of the original Standard Oil Company Founded in Cleveland. Ohio, in 1870 Standard Alaska . Production Compe 900 East Benson Bo,_ ard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907i 564-5111 September 24, 1986 STANDARD ALASKA PRODUCTION William Van Alen Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mr. Van Alert: The following log information for Endicott wells is enclosed: N-32 Run 1 September 18, 1986 . Cement Bond Log LAF:sw 0377E Sincerely, Laura Received by Date A unit of the original Standard Oil Company Founded in Cleveland, Ohio, in 1870. Standard Alasl~a'-- Production CornF 900 Eosl Benson Bc,~,evord P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) ..564-511 ! September 23, 1986 STANDARD ALASKA PRODUCTION William Van Alen Alaska Oil & Gas Conservation Commission 3001 Porcupine drive Anchorage, Alaska 99501 Dear Mr. Van Alen: The following log information for Endicott wells is enclosed: 1 blueline and 1 sepia print of: . Dual Dipmeter ~' · CNL/LDT porosity u · CNL/LDT ~ ~a~-~ ~'~ · DLL - micro SFL ~-- · Array Sonic - · NGT Spectrometry .... Sincerely, Laura F~ LAF:sw 0377E Received by Date A u,~,~ of ;he or,ginoJ 5~,3ndord O,I Fo~.,,~ded ~ CJevelo.~d ©h,o ,n 1870 STATE OF ALASKA Completion Deferred ALASF.~. OIL AND GAS CONSERVATION, ..MMISSION Until Mid 198~-~. . WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well ¥~r/ OIL E~ GAS [] SUSPENDED [] ABANDONED [] SERVICE [] 2. Name of Operator 7. Permit Number Standard Alaska Production Company 86-1 5.5 3. Address 8. APl Number P.O. Box 196612, Anchorage, Alaska 99519-6612 5o- 029-21645 4. Location of well at surface!~,.--' r-~-'CATIONS1 9. Unit or Lease Name I 2520' SNL, 769' WEL, Sec. 8, TllN, R17E .i VER~iE~ ; Duck Island Unit/Endicott. . At Top Producing Interval ~*-'!/IU-/' 10. Well Number · Surf,~ ~ 3769' SNL, 1013' WEL, Sec. 5, TllN, R17E ~~i N-32 SDI At Total Depth.~.~~ 11. Field and Pool 3565' SNL, 989' WEL, Sec. 5, TllN, R17E Endicott Field 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. Endicott Oil Pool KBE = 55.48'I ADL 47502 12. Date Spudded 13. Date T.D. Reached 14. Date~Opmp., Susp. or Aband. I 15. Water Depth, if offshore 16. No. of Completions 8-20'86 9-13-86 ~ ~/~7/'9~I N/A feetMSL Deferred until ~ mid 1987 17. Total Depth (MD+TVD) 18. Plug Back Depth (MD+TVD) 19. Directional Survey I 20. Depth where SSSV set 21. Thickness of Permafrost 11783'MD 10542'TVD 11686'MD 10455'TVDYES [] NO []I None feetMD 1536' 22. Type Electric or Other Logs Run Array Sonic, NGT Spectrometry ;BT, Dual Dipmeter, CNL/LDT Porosity, CNL/LDT Raw Data, DLL - Micro SFL 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 30" Stru~;tural DrLve Pipe Surface 161' Drive 13-3/8" 72# L-80 But-=. Surface 2482' [7-1/2" 3255 cu. ft. Permafr,)st 9-5/8" 47# NTSOS Surface 57U0' L2-1/4" 9-5/8" 470 NT95HS 57100' 10933' L2-1/4" 575 cu.ft:'.Class 'G+.7.5%CFR-2 0.12% HR-' 7" 29# L-80 !06S3' 11778' 8-1/2" 365 cu.ft. Class G .5~gHALAD344+.3%LWL 24. Perforations open to Production (MD+TVD of Top and Bottom and 25. TUBING RECORD interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 4-1/2" L80T£S 79.40' None 12.60 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT& KIND OF MATERIAL USED 9-5/8" x Downsqueeze 9-5/8" x 13-3/8" 13-3/8" ~nnulus with 345 sx Permafrost % followed by 115 BBLS Dry Crude 27. PRODUCTION TEST Date First Production I Method of Operation (Flowing, gas lift, etc.) DateofTest Hours Tested PRODUCTION FOR OIL-BBL GAS-MCr WATER-BBL CHOKE SIZE IGAS-OILRATIO TEST PERIOD ~ FioTM Tubing Casing Pressure CALCULATED OIL-BBL GAS-MCr WATER-BBL OIL GRAVITY-APl (corr) Press. 24-HOUR RATE ~ 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. R C iVED OCT 2 o i986 Alaska Oil & Gas Cons. C;ommissiori Anchorage Form 10-407 Submit in duplicate Rev. 7-1-80 CONTINUED ON REVERSE SIDE 29. 30. GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. Top HRZ 10686' 9520 ' Put River 10982 ' 9777 ' Top Kekiktuk 11000' 9794 ' 31. LIST OF ATTACHMENTS 32. I hereby certify that the foregoing is true and correct to the best of my knowledge Division ~_~i_~'~' Drilling S'ig ned ~)- ~ , ~ Title Engineer Date /0//6/~ INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1' Classification of Service Wells' Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5' Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces 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 producing 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 SAPC Daily Drilling Report -- EIIDICOTT August 21, 1986 at 0600 hours Rig' PAA #7 Well' N-32 (3-23) AFE # 717514 API# 50-029-21 645 Current Operation' Trippi.ng 0600 Depth' 1202' Day' 1 24-Hour Ftg' 1054' Accept rig. Prepare for spudding. Spud well. Drill to 1202 ft. using surface gyro. Trip to change bit. MUD TYPE-SeaGel WT-9.2 VIS:230 PV-IO YP:65 FL'31.O SOLIDS-6 TEMP-50°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES DLS -1 428 1/4 ° N29E 428 2 1029 O. 0 1029 1193H- SAPC Daily Drilling Report -- ENDICOTT August 22, 1986 at 0600 hours Rig: PAA #7 Well' N-32 (3-23) AFE # 717514 API# 50-029-21 645 0600 Depth' 2500' Day' 2 24-Hour Ftg' 1298' Current Operation' RIH Trip bit. Drill to 2500 ft. using surface gyro. POH. Run 13-3/8" casing. RIH with stab-in on 5" drillpipe. MUD TYPE-SeaGel WT'9.6 VIS-120 PV'15 YP-40 FL'34.0 SOLIDS'9 TEMP-62°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES DLS 3 1438 0 °. 30' N6, 6E 4 1 999 0 °. 20' N41.5'E 5 2466 0 °. 45" N44.7E 1193H- Rig: PAA //7 Well' N-32 13-23) SAPC Daily Drilling Report -- ENDICOTT August 23, 1986 at 0600 hours AFE # 717514 API# 50-029-21645 0600 Depth' 2500' Day' 3 24-Hour Ftg' ' Current Operation' Testing BOPE. Cement 13-3/8" casing shoe at 2482 ft. No cement to surface, perform top job. Install starting head. N/U BOPE. Test BOPE. MUD TYPE-Sea Gel WT:9.7 VIS-47 PV-12 YP-30 FL'18 SOLIDS-9 TEMP'°F SURVEY MD ANGLE DIRECTIO~ TVD SECTION COORDINATES DLS · 1193H- SAPC Daily Drilling Report -- ENDICOTT August 24, 1986 at 0600 hours Rig' PAA #7 Well' N-32 (3-23) AFE # 717514 API# 50-029-21645 0600 Depth' 3630' Day' 4 24-Hour Ftg' ll30~ Current Operation- Dyna-drilling. Test BOPE. RIH and tag float collar. Test casing to 3000 psi. Drill FC, cement, FS, and l0 ft. new hole. Perform F.I.T. Drill 12-1/4" hole to 3500 ft. POH. RIH Dyna-drill to kick-off. IitUD TYPE-Sea Gel WT:9.5 VIS-55 PV-18 YP'24 FL'll.2 SOLIDS:8 TEMP.73°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES DLS l ] 93H' Rig- PAA #7 Well' N-32 (3-23) SAPC Daily Drilling Report -- ENDICOTT August 25, 1986 at 0600 hours AFE # 717514 API# 50-029-21645 Current Operation' Tripping. 0600 Depth' 4837' Day' 5 24-Hour Ftg: 1207' Dyna-drill 12-1/4" hole to 4197 ft. Trip bit. Dyna-drill 12-1/4" hole to 4837 ft. POH. MUD TYPE- WT:9.5 VIS'49 PV'15 YP'13 FL'lO SOLIDS'9 TEMP'76°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES DLS 1193H- SAPC Daily Drilling Report -- ENDICOTT August 26, 1986 at 0600 hours Rig: PAA //7 Well: N-32 13-23) AFE # 717514 API# 50-029-21645 Current Operation: Drill~ing. Trip bit. 0600 Depth: 5800' Day: 6 24-Hour Ftg: 963' Drill and survey 12-1/4" hole to 5800 ft. MUD TYPE-Sea Gel WT:9.8 VIS:40 PV:14 YP:ll FL:9.6 SOLIDS:Il TEMP: 85 °F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES DLS 19 4943 34.4 20 5133 34.6 21 5416 35.1 22 5607 35.3 N4W 4844 496 hi 496 N3.7W 5001 604 t4 603 N3.3W 5233 765 bi 765 N3.3W 5389 876 e4875 vd 17.30 vd 24.54 W 34.44 v~y 40.78 1193H: SAPC Daily Drilling Report -- ENDICOTT August 27, 1986 at 0600 hours Rig: PAA #7 Well' N-32 (3-23) AFE # 717514 API# 50-029-21645 0600 Depth .' 7075' Day: 7 24-Hour Ftg' 1275' Current Operation: Driiling.~ · Drill and survey 12-1/4" hole to 5856 ft. survey 12-1/4" hole to 7075 ft. Trip bit. Drill and MUD TYPE-Sea Gel WT:9.9 VIS:41 PV:13 YP:ll FL:9 SOLIDS:12 TEMP:83°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES DLS 23 5797 35.7 N2.6W 5544 986 985 46 25 61 75 35.9 N3.3W 5850 1 207 1205 55 27 6839 36 NO. 2E 6387 1 596 1 595 66 1193H: Ri 9: PAA #7 Well' 1'.1-32 (3-23) SAPC Daily Drilling Report -- ENDICOTT August 28, 1986 at 0600 hours AFE # 717514 API# 50-029-21645 Current Operation: Tripping. MUD TYPE-Sea Gel 0600 Depth: 7327' Day: 8 24-Hour Ftg ~2 Drill and survey 12-1/4" hole to 7157 ft. POH. P/U Dyna-drill and RIH. Dyna-drill to 7327 ft. POH. RIH with bit. WT:9.8+ VIS:39 PV:13 YP:7 FL:9 SOLIDS:Il TEMP:°F SURVEY MD 28 7091 ANGLE DIRECTION TVD SECTION COORDINATES __ 38.1 N5.1E 6588 1 747 N 1 747 W59 DLS 1193H: SAPC Daily Drilling Report -- ENDICOTT August 29, 1986 at 0600 hours Rig: PAA #7 Well' N-32 (3-23) AFE # 717514 API# 50-029-21645 0600 Depth' 7700' Day' 9 24-Hour Ftg' 373' Current Operation- Drilling:~ . Drill and survey 12-1/4""hole to 7470'. Trip bit. Drill and survey 12-1/4" hole to 7700 ft. MUD TYPE-Sea Gel WT'9.8 VIS'40 PV'13 YP-IO FL:8.8 SOLIDS-10 TEMP-78°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES DLS 29 7327 30 7593 37.3 N9.6W 6783 1897 N 1896 W65 37.8 N6.5W 6986 2053 ~ 2051 v~Y 87 1193H' SAPC Daily Drilling Report -- ENDICOTT August 30, 1986 at 0600 hours Rig- PAA #7 Well' N-32 (3-23) AFE # 717514 API# 50-029-21645 0600 Depth' 8050' Day' l0 24-Hour Ftg' 350' Current Operation- Drilling.. Drill and survey 12-1/4" hole to 7786 ft. Trip bit. Drill and survey to 8050 ft. MUD TYPE-Sea Gel WT:9.9 VIS'37 PV'12 YP-7 FL-7.4 SOLIDS'lO TEMP.86°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES 31 7783 36.9 N6.1W 7136 2167 ~d 2165 v~lO0 32 7965 37.6 N6.8W 7282 2278 rg 2275 WYl 1 2 DLS l193H- Rig- PAA #7 Well' N-32 (3-23) SAPC Daily Drilling Report -- ENDICOTT August 31, 1986 at 0600 hours AFE # 717514 API# 50-029-21645 0600 Depth' 8450' Day: ll 24-Hour Ftg: 400' Current Operation: Drilling.. ~ Drill and survey 12-1/4" hole to 8450 ft. MUD TYPE-Sea Gel WT-9.9 VIS'38 PV'12 YP-8 FL'7 SOLIDS'lO TEMP-90°F SURVEY MD ANGLE DIRECTION TVD SECTION 33 8157 37.1 N6.8W 7435 2394 34 8345 36 N6.5W 7586 2506 COORDINATES N239i 2502 vU126 vd139 1193H' DLS Ri§: PAA #7 Well: N-32 13-23) SAPC Daily Drilling Report -- ENDICOTT September l, 1986 at 0600 hours AFE # 717514 API# 50-029-21645 0600 Depth: 8825' Day: 12 24-Hour Ftg: 375' Current Operation: Drill-lng. Drill and survey 12-1/4" hole to 8825 ft. MUD TYPE-Sea Gel WT:9.9 VIS:39 PV:13 YP:ll FL:6.8 SOLIDS:lO TEMP: 100°F SURVEY MD ANGLE DIRECTION TVD SECTION 35 8533 34.9 N6.5W 7739 2614 COORDINATES N2610 ~lS1 1201H: DLS Rig: PAA #7 Well: N-32 (3-23) SAPC Daily Drilling Report -- ENDICOTT September 2, 1986 at 0600 hours AFE # 717514 API# 50-029-21645 0600 Depth: 9005' Day: 1 3 24-Hour Ftg: 180' Current Operation: Drilling., ~ Drill and survey 12-1/4" hole to 8887 ft. Trip bit. Drill and survey to 9005 ft. MUD TYPE-Sea Gel WT:9.9 VIS:37 PV:ll YP:7 FL:6 SOLIDS:lO TEMP:IO2°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES 36 8815 34.5 N7.5W 7971 2775 rd 2769 v~/1 71 1201H: DLS Rig: PAA #7 Well: N-32 (3-23) SAPC Daily ~rillin§ Report -- ENDICOTT September 3, 1986 at 0600 hours AFE # 717514 API# 50-029-2164-5 0600 Depth: 9355' Day: 14 24-Hour Ftg: 350' Current Operation: Drilling. Drill and survey 12-1/4" hole to 9355 ft. MUD TYPE-Sea Gel WT:9.9 VIS:38 PV:12 YP:8 FL:6.8 SOLIDS:lO TEMP:IOI°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES 37 9004 33.8 N7.5W 8127 2881 N 2870 v~} 185 1201H: DLS , 0237 Rig: PAA #7 Well' N'32 (.3-23) SAPC Daily Drilling Report -- ENDICOTT September 4, 1986 at 0600 hours AFE # 717514 API# 50-029-21645 Current Operation· Drilling, 0600 Depth' 9730' Day' 15 24-Hour Ftg' 375' Drill and survey 12-1/4°' hole to 9730 ft. MUD TYPE-Sea Gel WT-IO.O VIS-38 PV'12 YP'IO FL-6.8 SOLIDS'lO TEMP' 103 °F SURVEY MD ANGLE DIRECTION TVD SECTION 38 9288 32.7 N8.2W 8365 3036 39 '9477 31.2 N8.2W 8525 3136 COORDINATES 3029 3128 206 221 1201H' DLS 0.41 0.79 SAPC Daily Drilling Report -- ENDICOTT September 5, 1986 at 0600 hours Rig' PAA #7 Well' N-32 (3-23) AFE # 717514 API# 50-029-21645 Current Operation' POH. 0600 Depth' 9833' Day' 16 24-Hour Ftg' 103' Drill and survey 12-1/4" hole to 9741 ft. POH. Test BOPE. RIH. Drill ahead. Lost pump pressure. POH looking for washout. MUD TYPE-Sea Gel WT-IO VIS'39 PV-12 YP:8 FL-6.4 SOLIDS:lO TEMP:95°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES DLS 1201 H- SAPC Daily Drilling Report -- September 6, 1986 at 0600 ENDICOTT hours Rig' PAA #7 Well' N-32 (3-23 AFE # 717514 API# 50-029-21645 Current Operation' MUD TYPE-Sea Gel Drilling. POH. Found 10,085 ft. 0600 Depth' 10,085' Day' 17 24-Hour Ftg' 252' washout. RIH. Drill and WT'IO VIS'39 PV'12 YP.6 FL:6.7 survey 12-1/4" hole to SOLIDS'lO TEMP'IO1 °F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES DLS 41 9853 30.7 N7.SW 8850 3324 /x/3315 ~/248 0.78 1201H: Rig: PAA #7 Well' N-32 (3-23) SAPC Daily Drilling Report -- ENDICOTT September 7, 1986 at 0600 hours AFE # 717514 API# 50-029-21 645 0600 Depth' 10,625' Day' 18 24-Hour Ft§' 540' Current Operation' Drill'ing. Drill and survey 12-1/4" hole to 10,625'. MUD TYPE -Sea Gel WT:IO.2 VIS:44 PV-15 YP-13 FL'6.4 SOLIDS'12 TEMP.IO9°F SURVEY MD ANGLE 42 10043 31.7 43 10232 31.5 DIRECT ION TVD SECT ION NS. 1W 9013 3422 N4.4W 91 74 3521 COORDINATES ~d341 3 ~/3512 ~259 W267 1201H' DLS O. 84 0.22 SAPC Daily Drilling Report -- September 8, 1986 at 0600 ENDICOTT hours Rig: PAA #7 Well: N-32 (3-23) API# AFE # 717514 50-029-21645 Current Operati on.' 0600 Depth: 10,955' Day: 19 24-Hour Ftg: 330' POH to ru_n_~ casing. Drill and survey 12-1/4" hole to 10,955 ft. - casing depth. POH. MUD TYPE-Sea Gel WT'IO.2 VIS'45 PV'16 YP:14 FL-6.0 SOLIDS:12 TEMP:ll6°F SURVEY MD ANGLE DIRECTION TVD SECT ION COORDINATES DLS 44 10514 31.0 45 10703 30.2 46 10874 29.8 N3W 9415 3667 NO. 5W 9578 3763 N2E 9726 3849 3658 3754 ~3839 w276 ~u279 vU278 0.31 0.80 0.77 1201H: Ri 9' PAA #7 Well- N-32 (3-23) SAPC Daily Drilling Report -- ENDICOTT September 9, 1986 at 0600 hours AFE # 717514 API# 50-029-2! 645 0600 Depth' 10,955' Day' 20 24-Hour Ftg' ' Current Operation' Lay down ~1..2-1/4" BHA. Run 9-5/8" casing. Mix and pump cement. Bump plug O.K. Test BOPE. L/D 12-1/4" BHA. 9-5/8" shoe at 10,933 ft. MUD TYPE-Sea Gel WT'IO.2 VIS'46 PV-20 YP-18 FL'7.8 SOLIDS'12 TEMP'IO8°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES DLS 1201H' SAPC Daily Drilling Report -- ENDICOTT September 10, 1986 at 0600 hours Rig' PAA #7 Well' N-32 (3-23) AFE # 717514 API# 50-029-21645 0600 Depth- 11,200' Day' 2! 24-Hour Ftg' 245' Current Operation' Drilling... RIH 8-1/2" BHA. Tag cement at 10,808 ft. Test casing to 3000 psi. Drill float equipment and cement. Drill lO ft. of new hole. Conduct FIT. - EMW 13.5 ppg. Drill 8-1/2" ~ole to 11,200 ft. MUD TYPE-Sea Gel WT:IO VIS'40 PV-13 YP-11 FL-6.8 SOLIDS'lO TEMP-IO6°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES DLS 1201H' Rig: PAA #7 Well: N-32 13-23) SAPC Daily Drilling Report -- ENDICOTT September l l, 1986 at 0600 hours AFE # 71 7514 API# 50-029-21 645 0600 Depth: 11,495' Day: 22 24-Hour Ftg: 295' Current Operation: Drilling. Drill 8-1/2" hole to 11,403 ft. Trip bit. Drill to 11,495 ft. MUD TYPE-Sea Gel WT:IO VIS:44 PV:13 YP:12 FL:6.8 SOLIDS:Il TEMP:94°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES , , DLS 1201 H: Ri g' PAA #7 l,,- ~2 (3-23) ¥,~el 1 · ~ '~ SAPC Daily Drilling Report -- ENDICOTT September 12, 1~o86 at 0600 hours AFE # 71 7514 API# 50-029-21645 0600 Depth' 11,783' Day' 23 24-Hour Ftg' 288' Current Operation' Open hole logging. Drill 8-1/2" hole to 11,783 ft. TD. Run open hole logs. MUD TYPE-Sea Gel WT'IO VIS'39 PV'13 YP:9 FL-6.6 SOLIDS'Il TEMP'IO2°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES DLS 1 201 H' Rig: PAA #7 Well: N-32 (3-23) SAPC Daily Drilling Report -- ENDICOTT September 13, 1986 at 0600 hours AFE # 717514 API# 50-029-21645 0600 Depth: ll ,783' Day: 24 24-Hour Ftg: ' Current Operation: Rig repairs. Run open hole logs. Wi per trip. POH. Broke brake cooling line - repair same. MUD TYPE-Sea Gel WT:IO.5 VIS:54 PV:20 YP:16 FL:6.8 SOLIDS:Il TEMP:86°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES DLS 1201H: Ri g: PAA #7 Well: N-32 (3-23) SAPC Daily Drilling Report -- ENDICOTT September 14, 1986 at 0600 hours AFE # 717514 API# 50-029-21645 0600 Depth: 11,785' Day: 25 24-Hour Ftg: ' Current Operation: RIH. Run 7" liner. Mix and pump cement - bumped plug. POH. RIH for cleanout. MUD TYPE-Sea Gel WT:IO VIS:39 PV:12 YP:5 FL:6.8 SOLIDS:Il TEMP:°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDInaTES DLS 1201H: SAPC Daily Drilling Report -- ENDICOTT September 15, 1986 at 0600 hours Rig: PAA #7 ~ell' N-32 (3-23) AFE # 71 7514 API# 50-029-216z~5 0600 Depth' 11,753' Day' 26 24-Hour Ftg' ' Current Operation' Displacing to brine. RIH to clean out liner. Liner top at 10,682 ft. S~oe at 11,778 ft. Clean out liner. Test liner to 3000 psi. Displace well to 9.6 ppg brine. MUD TYPE-Salt Water WT'9.6 VIS'Brine PV' YP' FL' SOLIDS' TEMP'°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES DLS 1201H- SAPC Daily Drilling Report -- ENDICOTT September 16, 1986 at 0600 hours Ri g: PAA #7 Well: N-32 (3-23) AFE # 717514 API# 50-029-21645 0600 Depth: 11,686' Day: 27 24-Hour Ftg: ' Current Operation: Nipple up wellhead. Displace well to 9.6 ppg brine. Fill top 250 ft. with diesel. N/D BOP's. Run 1 it. 4-1/2" tubing on tubing hanger. Install -tubing head adaptor. MUD TYPE-Brine WT:9.6 VIS: PV: YP: FL: SOLIDS: TEMP:°F SURVEY MD ANGLE DIRECTION TVD SECTION COORDINATES DLS 1 201 H: SAPC Daily Drilling Report -- ENDICOTT September 17, 1986 at 0600 hours Ri g: PAA #7 Well: N-32 (3-23) AFE # 717514 API# 50-029-21645 0600 Depth: 11,686' Day: 28 24-Hour Ftg: ' Current Operation: Release rig.. N/U wellhead. Test adaptor flange to 5000 psi. from N-32 at 0900 hrs. 9/16/86. Release rig MUD TYPE- WT: VIS: PV: YP: FL: SOLIDS: TEMP:°F SURVEY MD ANGLE DIRECTION TVD SECTION _ COORDINATES DLS 1201H: SOHIO ALASKA PETROLEUM C~ PAD. N (4::5- 5. I1.17) N.:52 Controlled Drilling LES HENDERSON 333~552 Consultants, Inc. CON.~ .,,DLLED DRILLING CONSULT.&.,,,I'S, INC. ~,2~,~ ~.~s~:o" September 12, 1986 Mr. Brian Rose Sohio Alaska Petroleum Company Pouch 6-612 Anchorage, AK 99502 Magnetic Single Shot Survey Job No. 0886-022 Well N-32 (43-5-11 -17) Prudhoe Bay Field North Slope, Alaska Date of Survey: 08-22-86 to 09-08-86 Dear Mr. Rose: Please find enclosed the "Original" and six (6) copies of our Magnetic Single Shot Survey on the above well. The method used in calculating this survey was Radius of Curvature. The depth of the survey was 428 to 10874. Thank you for giving us this opportunity to be of service. Yours very truly, Controlled Dr~onsultants, Inc. C,W. Harrington Directional Supervisor I<t~ EL. EV 55..~t, 8 F"T, SURVE? [:,' !:-',, T E C L 0 S i,..I P. E S ,!'} I S T A N C E ?:::t N ti L. E i::'~SSUHE© VER'T!ERt .... 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':' :;~' ':_.:, '.f:: .;.{ e ¥, ',:- 6 4. 9 6:, , '! ::ii ':t'.; ::ii:, '" :i{."' 54. i 6 35 6 5607 $5 i 8 !5797:35 42 5986 35 54 6,t60 35 54 709i 38 6 73S7 ?.7 i~ 7782 36 54 7965 S7 36 S l 57 ~7 8345 SG 0 ,:.,..., ,.:, ..:, ..:, 4 88i5 34 30 9004 33 48 9288 32 42 947F 3i ~2 9664 29 24 9853 30 42 ! 0043 3 ~ 42 i02:32 31 30 '~ 0703 30 t2 10874 29 48 5232 .. ~'~ '""' 9 ~' "'~ 5696,99 5850 09 6 08 F.) 95 6387 76 69S6 48 '7 i 36 72 7282 39 '7' 43 ~ 02 7586 04 -' 7 TM 9 i 9 7971 03 ,:, 364 , 94 8525,31 885 0,35 901 2 9 i 73,84 9414,93 ':~7 ''-~ 5 '" D E 6 ,, 5488 , 564 t , 6~32,2E', N ,2 OE 65:33,,40 N 5,10E 693 ~., 0 7 08 ~ , 24. ~',.~ 7379 753 0,56 791 5 S 0'71 , 8309 8469, 86S i, 28 ~.~ 8794 s 957 9i18,36 N 4,40~.,.~ 9522, '?',64,7't N '¢'!)9~: s, 8 N '~ ....'~9'~.. ,.., 40 f'.~ 't',747 01 N 2::3'9i 08 N 2502 28 N 2769 2875 i 5 N S22 i 68 N S S '~ 5 35 34. t ~ 'I 3 ~5:3 'S 4 C L 0 S U D, ! S T A t..] C: E :,.,.. ,,,.; , 1 207 ,,,-.;. '''~ ':',.., t',t i 596 '"'" '~ t 74. 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I 7 8 3 :,Z 1 $ 7 4 ;7 2 05 3, 6 248 4'2 ~: ......... 4;;2 26 t i I 2 6 6 1 5 274 48 277,6 0 ,,.~ 279, :7, 7' 2. 7 9,23 D ~::' F' 'T H TRL ~,~ VERT I .CAL D E P T H 0 I 000 2 000 3000 ,-t; 000 50O0 6 000 7'000 8O00 '~000 10000 i 0874. r I 000, ;~'000, ~ 9 'B ,:i, :, 4891, 7310, 812,1.,. 8976 ~ 9726, I - 7 .....~-T ................ t t Standard Alaska Production Company 900 East Benson Boule P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 564-5111 STANDARD ALASKA PRODUCTION September 2, 1986 Mr. Mike Minder Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Dear Mi ke, I enclose three pad maps for Endicott Satellite Drilling Island. These maps show the gyroscopic surveys for the drilled wells Q-35, M-33, 0-29 and also the proposed well paths for the current well N-32 and our next well T-34. The maps are on a scale of 1" : 100'. Should you require any more information, do not hesitate to contact me. RSA/IRR/pm/1105D Enclosures cc' R. H. Reiley J. F. Gulick J. G. Vidrine T. O. Stagg File 16.4 Endicott Development R. S. Allan Di vi s i on Dri 11 ing Engi neer A unit of the original Standard Oil Company Founded in Cleveland, Ohio, in 1870. SUB-SURFA CE DIRECTIONAL SURVEY [~UIDANCE I~'IONTINUOUS ~"IOOL Oil & ~:s Cons. ^nchor~ge, Company STANDARD ALASKA PRODUCTION COMPANY Well Name 3-23/N-32 SDI (2520'SNL,769'WEL,SS,TllN,R17E) Field/Location ENDICOTT, NORTH SLOPE, ALASKA · Job Reference No. Date 71710 9/18/86 Loc3~3ed By: Computed By: BARBA KRUWELL GCT DIRECTIONAL SURVEY CUSTOMER LISTING F~R ST~NDA'RJ ALASKA PRODUCTION CO 3-23/N-3Z SOl ENDICOTT N~RTH SLOPE~fiLASKA SURVEY~"'ATE: 18-S~PT_ -~6 ENGINEER: METHODS OF CGMPUT4TiON TOOL LOCATION: T.ANGENTiAL- ~VERAGED INTERPOLATION: LINEAR VERTICAL SECTION: HGRZZ. DIST. PRgJEC'TSD C',= V T- ~T iON AN9 AZIMUT~ ONTO A TSRGET 6ZiMUTM gF NORTH 3 DEG 0 MiN WEST .COMPUTATI3N DATE: 23-SE'P.-85 PAGE STANDARO ALA.SKA PRODUCTION CD 3-23/N-32 .SD! ENDICOTT NORTH SLOPE,ALASKA TNT:RPOLATED VALU;S FOR EVEN 10.0 FEET OF 'TRUE SU6.-SEA MEASURED VERTICAL VERTICAL DEPTH OEPTH DEPTH COURSE DEVZA'TZON AZIMUTH DEG MiN DEG MIN MEASURE 0.00 0.00 -55.48 100.00 100.00 44.52 200.00 200.00 144.5.2 300.00 300.00 244.52 400.00 400.00 344.32 500.00 500.00 444.52 600.00 600,00 544.52 700.00 699,99 644.51 800.00 799,99 '744.51 900,00 899,.99 844.51 0 0 N 0 0 0 14 S 10 53 0 12 N 85 12 0 12 N 56 50 0 14 S 1 56 0 12 N 29 59 0 19 S 24 17 0 7 S 34 52 0 15 N 83 12 0 i6 S 58 16 V~RTICAL DOGLEG RECTAN SECTION SEVERITY NORTH/ FE:ET DEG/IO0 FEE lOOO.O0 999..99 944.51 ii00.00 1099.99 1044.51 1200.00 11199.99 1144.51 1300.00 1299.99 1244.51 1400.00 1399,99 1344,51 1500.00 1499.9'9 1444.51 1600.00 1599,98 1544.50 1700,00 16'99,97 1644..~9 1800.00 1799.97 1744,49 1900,00 1899.96 1844.48 1'7 S 45 30 16 S 4 14 15 S 12 29 14 S 29 44 12 N 68 i 21 N 32 2 39 N .3S 2~ 44 N 34 43 32 N 37 59 27 N 3 58 0.00 0.00 -0.12 O. 52 -0.36 O. 38 -0.1! 0.44 -0,24 0,47 -0.27 0.75 -0.33 0,. 83 · -0,79 1,64 -0,67 0.32 -0.80 0.. 12 2000,00 1999,96 1944,48 2100.00 2099,96 2044,48 2200,00 2199,96 2144.48 2300.00 2299,96 2244.48 2400,00 2399.95 2344,47 2500.00 2499.95 2444,47 2600,00 2599,95 2544.47 2700.00 2699.94 2644.46 2800.00 2799,92 2744,44 2900.00 2899,90 2844.42 0 29 N 25 9 0 ~, N 4~ 53 0 19 N 1 19 0 21 N 37 38 0 22 N 60 30 0 go N 36 22 0 32 N 18 50 0 49 N 13 11 1 14 N 4 3 I 13 N 3 13 -1.14 O. 08 .-1.60 0.11 -2.07 0.06 -2.50 0.5..1 .-2.61 0.34 -2.28 0.51 -1,59 O, 19 -0,~!~ 0.3~ 0.15 0.14 0.95 0.22 3000.00 2999.87 2944.39 3100.00 3099.84 3044,36 3200.00 3199,79 3144,31 3300.03 3299,72 3244.24 3400.00 3399.63 3344.15 3500.00 3499.57 3~44.09 3600.00 3599.36 3543.88 3700.00 3698.88 3643.40 3800,00 3797.96 3742.48 3900.00 3896.46 3840.98 ! ~'7 N 26 ~2 1 31 N 32 26 2 2 N 32 15 2 20 N 31 17 2 13 N 28 18 2 38 N 22 36 ~ 48 N 5 13 6 44 N 3 17 8 46 N 7 55 1! 10 N 8 43 1,77 0,14 2,04 0,93 2,20 0,84 2,78 1,28 3.02 0,48 3.41 i,ii 4.23 0,10 5.33 0.37 7,1'9 0.17 9.32 1.56 11.60 0,56. 13,70 0,73 16.13 0.63 19,28 0.17 22,73 0.24 25.,~4 3.57 31.98 1,53 41.73 2.80 55,13 2.21 72.30 2,35 . O, O, O, O, O, . . 2. 2. 3. 3. 4. 5. 7. 9. I1. 14. 16, 19. 23. 26, 32. 42. 56, 73. ATE OF SURVEY: 18-SEPT-86 ELLY BUSHING ELEVATION: 55,48 ~T ENGINEER.: 5ARBA O0 N 0.00 E 0..00 N 0 0 E 11 S 0.08 E 0.14 S 34 55 'E 37 S 0,13 W 0,39 S 19 49 W 12 S 0,20 W 0,23 S 60 14 W 24 S 0,07 ~ 0.25 S 16 46 F 2'7 S 0.02 W 0.27 S 3 33 31 S 0.~! E 0.52 S 52 37 77 'S 0.39 E 0..87 $ 26 5'9 E 64 S 0.62 E 0.89 S 44 19 :~ 75 S 1,08 E 1,.31 S 55 9 E 07 S 1,45 E 1,80 S 53 33 52 S 1,63 E 2,23 S 47 I E 99 S 1,56 E 2,53 S 38 1 E 43 S 1,45 E 2,83 S 30 46 55 S t,ll E 2,79 S 23 34 E 23 S 1,08 E 2,48 S 25 46 F 51 $ 1,68 E 2,26 $ 48 5 E 49 S 2,43 E 2,48 $ 78 42 E 32 N 3.09 E 75.10 N 84 9 E 12 N 3.29 E 3.48 N 71 9 E 95 N 3,40 E 3.,92 N 60 13 E .24 N 3,76 E 4,38 N 59 I0 E 40 N 3,68 E 4,39 N 56 56 ~ 99 N 3.91 E 4.93 N 52 36 E 25 N 4.39 E 5,46 N 53 29 E 68 N 5.00 E 6,20 N 53 38 ~ 51 N 5.31 E 6.97 N 49 40 ~ 63 N 5.61 E 7,95 N 44 54 5 50 N 5.80 E 9.48 N 37 41 ~ 64 N 5.82 E 11,26 N 31 8 E 96 N 6.61 ~= 13,67 N 28 55 _: 13 N 7.91 E 16,20 N 29 15 E 66 N 9,57 E 19.21 N 29 52 E 92 N 11,61 E 23,06 N 30 14 ~ 47 N 13,62 E 27,14 N 30 7 E 68 N 15 33 : 30 77 N 29 53 : 88 N 16.49 E 36.79 N 26 37 : 65 N 16,51 E 45,74 N 21 9 E O1 N 15,39 E 58,09 N 15 21 E 08 N 12,94 E 74.2! N 10 2 H GU'LAR COORDINATES HORiZ. DEP4RTUR~ SOUTH EAST/WEST DIST.. AZIMUTH T FEET FEET 'DEG MIN D DEPTH COMPUTAT ION STANDARD ALASKA PRODUCTION CO 3-23/N-32 SDZ ENDICOTT NORTH SLOPE,ALASKA Da'T=:~ £3-S. EP-$6 INTERPOLATED VALUES FOR EVEN '100 TRUE SUB-SE,~ ~EASUREO VERTICAL VERTICAL DEPTH DEPTH DEPTH 4000.00 3994.09 3938.6i 4100.00 4390.72 4035.24 4200.00 4186.14 ,4130.66 4300,00 4280,14 4224,66 4400,00 4372,77 4317.29 4500,00 4464,03 4408,55 4600,00 45'53,61 44'98,13 4700,00 4641.03 45~5,55 4800,00 4'725,84 4670,36 4900,00 4808,75 4753.27 5000,00 4891,26 4835,78 5100,00 4973,82 4918,34 5200,00 5056,11 5000,63 5300.00 5138.26 5082,78 5400.00 5220,31 5164,83 5500,00 5302.27 5246,79 5600,00 5384,16 5328,68 5700.00 5465,77 5410,29 5800,00 5547.07 5491,59 5900,00 5628,23 5572,75 6000,00 5709,29 5653,81 6100,00 5790.32 5734,84 6200,00 5871,44 5815,96 6300,00 5952.,94 5897,46 6400,00 6034.39 5978,91 6500,00 6115,52 6060,04 6600,00 6196.57 6141,09 6700,00 6277,75 6222,27 6800,00 6358,$9 6303,4i 6900,00 6439,93 6384.45 CDURS5 VERTICAL DEVIATION AZIMUTH SECTION DEG MIN DEG M, IN FEET 13 40 N 10 26 W 93,74 16 8 N 9 7 N !19.23 18 50 N 7 18 W 148.99 21 1 N 5 3.2 W 183,00 23 7 N 4 .45 W 220,63 25 14 N 4 3 W 261,50 27 34 N 3 45 W 305,92 30 33 N 3 38 W 354,44 33 15 N 3 31 W 407,40 34 19 N 3 18 W 463,31 34 24 N 3 4 W 519.81 34 25 N 2 52 W 576.23 34 ~3 N Z 37 W 633.05 34 49 N 2 3.5 W 690,07 34 56 N 2 31 W 747,22 .34 56 N 2 31 ~ 804,52 35 8 N 2 9 W 861,91 .35 32 N I 42 W 919,68 35 36 N i 26 W 977,90 35 53 N 1 35. W 1036,29 35 53 N 2 15 W 1094,85 35 48 N Z 57 W !1.53.44 35 34 N 3 29 W 1211,92 35 ZZ N 3 9 W 1269,86 35 37 N 2 7 W 1327,89 35 53 N 1 12 W 1386,32 35 46 N 0 35 W 1444,86 35 43 N 0 16 W 1503,19 35 46 N 0 24 E 1551,55 36 7 N 1 19 E i620,02 37 30 N 4 13 E 1679,53 37 56 N 5 51 E 1740,23 36 45 N 2 14 E 1800.72 36 11 N 6 4 W 1859,72 37 43 N 7 47 W 1919,62 37 57 N 7 2 W t9~0,97 37 26 N 6 29 W 2~4!.93 35 54 N 5 54 W 2102.37 36 48 N ~= 44. W 2162olt 37 15 N 5 57 W 2222.23 7000.00 6520.07 6464,59 7100,00 6599,06 6543.58 7200.09 6678.19 6622,71 7300.00 6758.87 6703.39 7400.00 6838,79 6783.31 7500.00 6917.61 6862,13 7600.00 6996.7~ 6941.30 7700.00 7076.3~ 7020,90 7800.00 7156.52 7101.04 7900.00 7236.38 71SO.~O ~EET O~ PAGE 2 DATE OF SURVEY: '18-S'EPT.-86 KELLY BUSHING ELEVATION: 55.48 FT ENGINEER: BARBA MEASURED DEPTH OOGLEG RECT.aNGULAR COORDINATES HORIZ. DEPARTURE SEVERITY NORTH/SOU:TH E~ST/WEST DIST. AZIMUTH DEGflO0 FEE'T FEET FEE'T DEG MIN 1,97 2.09 2,74 2,15 1,91 2,46 2 · 76 3,08 Z, 10 0,24 0,25 0,51 0., 14 0,25 0,18 0,12 0,28 0,44 0,19 0,36 0.47 0.51 0.69 0.52 0.85 0.62 0.35 0.27 0.33 1.27 2,73 0,89 6,09 4.09 1,17 1.04 0.50 0.71 0,44 0,78 94.35 N 119,65 N 149,21 N 183,08 N 220,58 N 261,35 N 305,67 N 354,10 N 406,95 N 462,76 N 9.23 E 94,80 N 5 35 E 4,84 E 119,75 N 2 19 E 0,42 E 149,21 N 0 9 E 3,26 W 183,11 N 1 1 W 6,62 W 2.20,68 N 1 43 w 9,73 W 261,53 N Z 7 12,74 W 305,94 N Z 23 15,86 W 354,45 N Z 33 W 19,17 W 407,40 N 2 41 W 22.52 ~ 463,31 N ,Z 47 W 519. 575. 632. 689 · 746. 803 · 860. 918. 976. 1035. 18 53 24 34 58 93 67 88 29 25,64 W 519,81 N 2 49 W 28,63 W 576,24 N 2 50 W 31,33 W 633,05 N 2 50 W 33.92 W 690.07 N 2 49 W 36.47 W 747.23 N Z 47 W 39.00 W 804,53 N 2 46 W 41o40 W 861,92 N 2 45 W ~3.33 W 919,69 N 2 42 W 44,91 W 977,92 N Z 37 W 46,35 W 1036,32 N Z 33 W 1093, 1152, 1IlO. 1268, 1326, 1384, 14z. 3. 150t. I560. i618. 82 35 7.3 58 54 96 54 93 37 96 48,32 W 1094,88 N 2 31 W 50,96 W 1153,48 N Z 31 W 54,35 W 1211,95 N 2 34 W 57.76 W 1269,89 N 2 36 W 60,48 W 1327,92 N 2 36 W 62,13 N 1386,35 N 2 34 ~ 62,96 W 1444,91 N 2 29 ~ 63,44 W 1503,26 N 2 25 W 63,38 N 1561,66 N 2 19 ~ 62.65 W 1620,17 N 2 12 W 1678.69 1739.77 1800.63 1859.50 1919.16 1980.18 2040.85 2101.03 2150,53 2220,42 59.99 W 1679,76 N 2 2 N 54,35 W 1740.61 N 1 47 W 48,30 W 1801,29 N 1 33 W 50,96 W 1860.30 N 1 34 W 59.00 W 1920,07 N 1 45 W 67,06 W 1981,31 N 1 56 W 74.18 ~ 2042,20 N 2 4 ~ 80,64 W 2102.58 N 2 11 W 86,66 W 2162.27 N 2 17 W 92.80 W 2222.36 N 2 23 W COMPUTATION DATE: 23.-SEP-86 PAGE 3 S'TANDARD ALASKA PRODUCTION CO 3-IS/N-32 'ENDICOTT NORTH SLOPE,ALASKA INTERPOLATED VALUES FOR TRUE MEASURED VERTICAL DEPTH DEPTH SUB-SEA 'VERTICAL DEPTH COURSE DEVIATION AZIMUTH DEG MiN OEG 8000.00 7315.85 8100.00 7395.53 8200.00 7475.71 8300.00 7556.36 8400.00 7637.60 5500.00 7719.43 8600.00 7801.48 8700.00 7883.54 8800.00 7966.19 8900.00 3049.01 7260.38 7340.05 74Z0..23 7500.35 7582.12 7663.95 7746.00 7828.16 7910.71 7993.53 37 16 N 6 4 W 37 0 N 5 49 W 36 32 N 6 8 W 35 55 N 6 13 W 35 22 N 6 5 W 34 50 N 6 8 W 34 53 N 6 7 W 34 33 N 6 26 ~ 34 10 N 6 33 W 33 59 N 6 29 W 9000.00 8132.04 9100.00 8215.46 9200.00 8299.34 9300.00 8383.66 9400.00 3468.52 9500.00 8554.06 9600.00 8640,30 9700.00 8727.43 9800.00 8814,~6 9900.00 8901.21 807,5.56 3,3 43 N' 6 57 W 8159.98 33 11 N 7 13 W 8243.85 32 46 N '7 44 W 83,28,18 32 16 N 8 14 W 8413.04 31 31 N 8 14 W 8498.58 30 48 N 8 35 W 8584.82 29 57 N 8 59 W 8671.95 28 55 N 8 53 W 8759.38 29 37 N 8 17 W 8845.72 30 50 N 7 27 W 10000.00 8986.80 101'00.00 9072.01 10200.00 9157.28 10300.00 9242.81 10400.00 9328..41 10500.00 9414.04 10600.00 9.499.97 10700.00 9586.31 10800.00 9672.87 10900.00 9759.76 8931.3Z 9018.53 9101.80 9187.33 9272.93 9358.55 9444.4~ 9530.83 9617.39 9704.28 11000.00 9847.20 9791.72 11100.00 9935.33 9879,85 11200.00 10023.46 9967.98 11300.00 10111.86 10056.38 11400.00 10200.62 10145.14 11500.00 10289.61 10234.13 11600.00 10378.73 10323.25 11700.00 10467.~6 10412.38 11783.00 10541.:~1 10486.33 31 21 N 6 45 W 31 38 N 5 48 W 31 21 N 5 23 W 31 ii N 5 17 W 31 6 N 4 ~8 W 30 57 N 3 25 W 30 36 N 2 32 W 30 6 N 1 0 W 2'9 50 N 0 43 E 29 29 N 2 15 E 28 28 N 4 41 E 28 7 N 5 24 E 28 0 N 5 44 E 27 11 N 6 30 E 27 8 N 6 37 .5 26 53 N 6 49 E 26 59 N 6 52 E ~6 59 N 6 52 EVEN 100 FEET OF DATE OF SURVEY: 18-SEPT-86 KELLY BUSHING ELEV.~TiON: 55.4~ 'FT ENGIN2ER: BARBA MEASURED DEPTH VERTICAL DOGLEG RECTANGULAR SECTION SEVERITY NORTH/SOUTH 'FEET DEG/IO0 FEET 2282.83 0.59 2280.77 N 2343.18 0.82 2340,87 N 2402.85 0.60 2400.30 N 2461,90 0.4'7 2459.09 N 2520.13 0.53 2517.07 N 2577.51 0.32 2574.21 N 2634.58 0.45 2631.04 N 2691,50 0.25 2687.71 N 2747.84 0.36 2743.79 N 2803.78 0.27 2799.47 N 2859.38 0.69 2914,41 0.57 2968.66 0.56 3,022.22 0.54 30'74,89 O.B1 3126.47 1.04 3175.81 !.'09 3225.63 0.41 32'73.95 1.56 3324.19 1.03 3375.76 0.69 3428.01 0.44 3480.20 0.48 3531.98 0.17 3583.55 0.69 3635.26 0.67 3686,42 O.BO 3736.87 1.06 3786.87 0,83 3836.20 0.92 3884.4! 1.22 3931.19 0.67 3977.91 0.69 4024.13 0,77 406~.60 0.33 4114.57 0.19 4159.27 0.60 4203.97 0.00 4241,05 0.00 CCORDINATE.S HOR!Z.. DEPARTURE EAS'T/WEST DIST. AZIMUTH FEET FEET DEG M!N 99,21 W 2282.92 N 2 29 W 105.43 W 2343.24 N Z 34 W 111.67 W 2402.89 N 2 39 W llB.11 W 2461.92 N 2 44 W 124.33 W 2520..14 N 2 49 W 130.44 W ,25'77.5.2 N 2 54 136.57 W 26.34.58 N 2 58 !42.79 W 2691.50 N 3 2 W 149.,22 W 2747.84 N 3 6 W 155.55 W 2803.79 N 3 10 W 2854.81 N 2909.55 N 2963.52 N 3016.76 N 3069.10 N 3:120.36 N 3170.36 N 3218.84 N 3266.84 N 3316.80 N 162.07 W 2859.41 N 3 14 W 168.88 W 2914.45 N 3 19 W 175.93 W 2968.73 N 3 23 W 183.44 W 3022,,33 N 3 28 W 191.07 W 3075.04 N 3 33 W 198.55 W 3126.67 N 3 3~ ~ 206.38 W 3177,.07 N 3 43 W 214.00 W 3225.94 N 3 48 W 221.34 W 3274.33 M 3 52 ~ 228.17 W 3324.64 N 3 56 W 3368.10 N 3420.12 N 3472.12 N 3523.71 N 3575.21 N 3626.70 N 3677.80 N 3728.23 N 3778.29 N 3827.76 N 234.61 240.30 245.36 25,0.15 254.81 258.48 261.15 262.77 262.~8 261.59 W 3376.26 N 3 59 W W 3428.55 N 4 1 W W 3480.78 N 4 2 W W 3532.58 N 4 3 W W 3584.28 N 4 4 W W 3635.90 N 4 4 ~' W 3687.06 N 4 3 ~, W 3737.48 N 4 1 W W 3787.42 N 3 58 W W 3836.68 N 3 54 N 3,876.18 3'923.25 3970.27 4016.81 4062.60 4107.90 4152.95 4197.99 4235.39 N 258.75 N 254.45 N 249.84 N 245.15 N 240.19 N 234.92 N 229.54 N 224.21 N 219.70 3884.81 N 3 49 W 3931.50 N 3 42 W 3978.13 N 3 36 ~ 4024.28 N 3 29 W 4069.69 N 3 23 W 4114.61 N 3 16 W 4159.29 N 3 9 W 4203.~7 N 3 3 W 424!.08 N 2 5~ W CGMPUTATI~N DATE: ~-S~P-~ PA~E 4 STANDARD ALASKA PRODUCTION CO 3-23/N-32 SOl ENDICOTT NORTH SLOPE,ALASK~ INTERP'OL~TED VALUES FOR TRUE SUB-SEA COURSE ~EASUREO VERTI~CAL VERTICAL DEV'IATiDN AZIMUTH DEPTH DEPTH DEPTH ~EG MiN DEG MiN 0.00 0.00 -55.48 0 0 N 0 0 1000.00 999.99 944.51 0 17 S 45 30 2000.00 1999.96 1944.&8 0 ,29 N 2.5 9 3000.00 2999.87 2944.39 1 27 N 26 32 4000.00 3994.09 3'9.38.51 13 40 N 10 26 5000.00 4891.26 4535.78 34 24 N 3 4 6000.00 5709.29 5553.$1 35 53 N 2 15 7000.00 6520.07 6&64.59 37 30 N 4 13 8000.00 7315.85 7260.38 37 16 N 6 4 9000.00 8132.04 8076.56 33 43 N 6 57 lO000.OO 3986.80 S931.32 31 21 N 6 45 ilOOO.OO 9847.20 9'791.72 28 28 N 4 41 11783.00 10541.81 10486.33 26 59 N 6 52 m 'vE N !000 VERTICAL DOGL SECTION SEVE FEET DEG/ DATE OF SURVEY: 18-SEPT-86 KELLY BUSHING ELEVATION: 55.48 FT ENGINEER: 5&R5~ T OF MEASURED DEDT EG RECTaNGULaR RITY NORTH/SOUTH 100 FEE'T E 0.00 O.O0 0.00 N E -1.14 0.08 1.07 S E 1.77 0.14 1.95 N ['_ !!.60 0.56 11.96 N W 93.74 1.97 94.35 N W 519.81 0.25 519.18 N W 109~.85 0.47 1093.82 N ~ 1679.53 2.73 1678.69 N W 2282.83 3.5'9 2280.77 N W 28,59.38 0.69 2854.81 N 3375.76 0.69 3368.10 N 3884.41 1.22 3876.18 N · ~24!. 08 0.00 4235.39 N COORDINATES HORIZ,. DEPARTURE EAST/WEST DIST. AZIMUTH F:ET~ FE~T O'EG MIN 0.00 E 0.00 N 0 0 E 1.4.5 E !.80 S 53 33 5 3.40 E 3.92 N' 60 13 E 6.61 E 13.67 N 28 55 E 9.23 E 94.80 N 5 35 ~ 25.64 W 519.81 N 2 49 48.32 W 1094.88 N' 2 31 59.99 W 1679.76 N 2 2 W 99.21 W 2282.92 N 2 29 W !62.07 W 2859.41 N 3 14 W 234.61 W 3376.26 N 3 59 W 258.75 W 3884.81 N 3 49 W 219.70 W 4£41.08 N 2 58 W COMPUTATZ'DN DATE: 23-SE?-$6 PAGE 5 STANDARD ALASKA PRDDUC'TION 3-23/N-32 SOI ENDICOTT NORTH SLOPE,ALASKA ZNTERPGLATED VALUES FOR TRUE SUB-SEA 'qEASURED VERTICAL VERTIC~.L DEPTH DEPTH 'DEPTH COURSE DEVIATZGN AZ'IMUTM DEG MIN DEG MiN 0.00 0.00 -55.48 55.48 55.48 0.00 155.48 155.48 100.00 255.48 255.4S 200.00 355.48 355.48 300.00 455,4.8 455,48 400,00 555.48 555.48 500.00 655.49 655.45 600.00 755,49 755,48. 700,00 855,49 855,48 $00,00 0 0 N 0 0 0 ? S 73 57 0 12 S 36 .36 0 12 N 6 12 0 14 S 62 2 0 9 N 65 20 0 18 S 82 2 0 '17 S 5 23 0 11 N 54 10 0 16 S 76 50 955.49 955.48 1055.49 10,55.48 1155.49 1155.48 '1255,49 1255,48 1355.49 1355.48 1455,49 1455,48 1555.50 1555.46 1655.50 1655.48 1755,51 1755,48 1855.51 1855,48 900.00 !000.00 1100.00 1200.00 1'300.00 1400.00 1500.00 1600.00 !700.00 1800,00 0 17 S 4'7 0 17 S 20 0 16 S 9 0 15 S 12 0 13 S 74 0 11 N 8 0 34 N 42 0 44 N 36 0 33 N 40 0 30 N 2 34 E 27 E 53 W 22 W 53 W 0 W 7 E 5 E 46 E 37 E 1955,52 1955,48 2055,52 2055,48 2155,52 2155,48 2255,52 2255,48 2355.52 2355.48 2455.53 2455,48 2555.53 2555.45 2655.54 2655.48 2755.55 2755.48 2855.5'7 2855.48 1900,00 2000,00 2100.00 2200,00 £300,OO 2400,00 2500.00 2600,00 2700,00 2800.00 0 29 0 17 0 5 0 23 0 19 0 26 0 33 0 39 1 8 1 16 N 4 4 E N 67 15 E N 78 38 W N 25 2 E N 63 44 E N 56 20 E N 21 59 E N 15 35 E N 5 1 E N 3235 2955.60 2955.43 3055.63 3055,48 3155.66 3155,48 3255.72 3255.48 3355.81 3355.48 3455.88 3455.48 3556.00 3555.48 3656.36 3655.48 3757.35 3755,4.3 3858.30 3855.48 2900.00 3000.00 3100.00 3200.00 3300.00 3400.00 3500.C0 3500.00 3700.00 3800,00 1 i 1 2 2 1 3 5 7 10 25 27 40 12 19 54 34 39 N 21 4 E N 32 12 E N 33 53 E N 32 21 E N 30 26 E N O 32 ~ N 3 55 W N 8 3 w EVEN 100 VER'TICAL SECTION ~EET 0.00 0.00 - 0..29 -0.23 -0.08 -0,39 .-0,18 -0.63 -0.72 -0.70 -0.98 -1.38 -!. 87 -2.32 -.2.63 -2.47 -1.94 -1.07 -0.16 0.56 1.39 2.00 2,05 2,51 2,92 -,23 3.84 4,76 6,26 8.40 10.59 !2,77 14.99 17.84 21,23 24,44 28.79 37,05 48.93 54,62 FEET O'F DOGLEG SEVS~iTY DEG/iO0 0,00 0.00 0,14 0,66 0,82 1,22 0,47 0,30 0,29 0,29 0.18 0.15 0.03 0.05 0.35 0.69 0.20 0.09 0.20 0.72 0.95 0.10 0.28 0,07 0.27 0.20 0.13 0,89 0.34 0,09 0,55 0.19 0.39 0.32 0.85 0,36 2.09 1.93 3.02 2.71 DATE OF SURVEY: 18-:SEPT-.86 KELLY BUSHING ELEVATION: 55.48 FT ENGINEER: BARBA SUB-SEA DEPTH .. RECTANGULAR COORDINATES HURIZ. DEPARTURE NORTH/SOU'TH EAST/WEST DIST. AZIMUTH FEET FEET FEET DEG MIN 0.00 N 0.00 E 0.00 N 0 0 E 0.00 N 0.00 E 0.00 N 90 0 E 0.29 S 0.00 W 0.29 S 0 6 W 0.25 S 0.28 W 0.37 S 48 1 W 0.08 S 0,00 ~ 0.08 S 2 54 W 0.39 S 0.01 W 0.39 S 1 23 0.17 S 0.21 E 0.28 S 51 0 0.61 S 0,44 E 0.75 S 35 37 E 0.70 S 0.47 E 0.84 S 33 42 E 0.66 S 0.88 E !.10 S 53 14 E 0,91 S 1,29 E 1,58 S 54 50 E 1,30 S 1,60 E 2,07 S 50 54 E 1,79 S 1,60 E 2,40 $ 41 46 E 2,24 S 1.50 E 2,70 S 33 5.1 E 2.56 S 1.28 E 2.87 S 26 31 E 2.42 S 1.00 E 2.62 S 22 24 E 1.87 S 1.37 E 2.32 S 36 14 E 0.96 S 2.09 E 2.30 S 55 15 E 0.02 S 2.82 E 2.82 $ 89 41 E 0.74 N 3.31 E 3.39 N 77 26 E 1.57 N 3.26 E 3.62 N 64 20 E 2.20 N 3.61 E 4.23 N 58 41 E 2.25 N 3,71 E 4,34 N 58 48 E 2,71 N 3.79 E 4,66 N 54 23 5 3,14 N 4,16 E 5,22 N 52 5'9 E 3.48 N 4.74 E 5.',38 N 53 41 F 4.11 N 5.1'7 E ,5.61 N 51 2'9 : 5.06 N 5.48 E 7.45 N 47 16 E 6,57 N 5,73 E 8,72 N 41 5 E 8,72 N 5,88 E 10.52 N 33 59 E 10.93 N 6.15 E 12.54 N 29 20 E 13.17 N 7.31 E 15.06 N 29 2 15.47 N 8.79 E 17.80 N 29 35 18.42 N 10.68 E 21.2'9 N 30 6 2!,9~ N 12.80 E 25.39 N 30 16 E 25.24 N i~.58 E 29.15 N 30 1 29,68 N 16.12_: 33.77 N 28 30 E 37,98 N 16.73 ~- 41.50 N 23 46 49,84 N 16.16 =_ 52,40 N 17 57 65,45 N 14.06 E 66.94 N 12 7 E COMPUTATION D;TE: 23-SEP-86 PAGE STANDARD ALASKA PROOUCTiON CO 3-23/N-32 SDi EN$ICOT'T NORTH SLOPE,ALASKA ZNTERP~LATE'D VA:LUES FOR EVEN 100 'FEET OF TRUE SUB-SEA MEASURED VERTICAL VERTICAL DEPTH DEPTH DEPTH COURSE DEVIATION AZIMUTH PEG MIN DEG MIN DATE DF SURVEY: iS-SEPT-86 3960,33 3955,48 3900,00 4063,39 4055,48 .4000.00 4167,69 4155,48 4100,00 4273.65 4255.48 4200°00 4381,22 4355,48 4300,00 4490,56 4455,48 4400,00 4602.11 4555,.48 4500.00 4716.82 4655.,48 4600.00 4835.60 4'755.48 4700.00 4956.62 4855.48 4800.00 12 44 N 10 6 W 1.5 13 N 9 42 W 17 54 N $ 14 W 20 26 N 5 50 W 22 45 N 4 54 W 25 0 N 4 5 W 2'7 38 N 3 45 W 31 3 N 3 37 W 33 52 N 3 28 W 34 24 N :3 8 W KELLY BUSHING ELEVATION: 55.48 FT ENGINEER: 8ARBA 5077.'7'9 4955.48 4900.00 5199.24 5055.48 5000.00 3320.9.8 5155.48 5!00.00 5442.92 5255.48 .5200.00 5564.93 5355.48 5300.00 5687.35 5455.48 5400.00 3810,.3,4 5555.48 5500.00 3933.64 5655,.48 5.600.00 6057.05 5755.48 5700.00 6180.38 5855.48 5500.00 34 20 N Z 5,8 N 34 43 N 2 37 W 34 50 N 2 34 W 34 57 N 2 31 W 35 4 N 2 ZO W 35 28 N 1 45 W 35 36 N 1 24 W 35 50 N 1 48 W 35 51 N 2 37 W 35 41 N 3 29 W SUB-SEA DEPTH 6303.11 5955.~8 5900.00 6425.97 6055.4~ 6000.00 6549.32 6155.48 6100.00 6672,57 6255.48 6200,00 6795.79 ~355.48 6300.00 6919.26 6455.48 6400.00 7044.82 6555.48 6500.00 7171.52 6655.48 6600.00 7295.79 6755.~8 670~.00 7421.15 6~55.48 680~.00 35 22 N 3 7 W 35 41 N 1 48 W 35 51 N 0 47 W 33 43 N 0 23 W 35 46 N 0 23 E 36 19 N 1 40 E 37 50 N 3 13 ~_ 37 23 N 4 24 E 36 8 N 5 51 W 37 53 N 7 42 '~ VER'TIC&L DOGLEG R'EC'TAN SECTION SEVERITY NORTH/ FEET .DEG/IO0 FEE 7547.94 6955.45 6900.00 76,73.83 7055.48 7000.00 7798.70 7155.48 7100.00 7924.04 7255.48 7200.00 8049.71 7355.48 7300.09 8174.79 7455.48 7400.$0 8298.92 7555.48 7500.00 8421.91 7655.~8 7600.00 8543.92 7755.48 7700.00 8665.79 7855.48 7800.00 37 39 N 6 40 W 37 5 N 5 59 W 36 48 N 5 ~4 W 37 21 N 6 1 W 37 11 N 5 53 W 36 34 N 6 4 W 35 56 N 6 13 W 35 14 ~ ~ 5 W 34 32 N 6 i0 W 34 40 ~ ~ gO N 84.70 2.91 83. 109.34 2.97 109, 138.82 3.29 139. 173,72 2., 35 173, 213.32 2.04 213. 257.49 2,38 257. 306.90 2.79 306. 363.06 2.77 362. ~27.12 1.32 426. 495.28 0.21 494. 563.70 0.26 563. 632.6.2 0.14 631. 702.06 0.20 701. 77,1.82 0.08 770. 841,73 0o~'7 840, 912,34 0.,56 911, 983,91 0.24 982. 10.56,02 0,55 1055, 1128,32 0,63 1127. 1200,50 0,90 1199, 1271.66 0.36 1270. 1343.03 0.73 1341. 1415.21 0.44 1413. 1487.19 0.23 1485. 1559,10 0,33 1557, 1631,34 !,67 1630, 1706.74 0.88 1706. 1783.64 4.54 1783. 1857.24 4.30 1857. 1932,56 0.43 1932, 2010.31 0.86 2009. 2086.65 0.80 2085. 2161.33 0.43 2159. 2236.81 0.30 2234. 2312.81 0.85 2310. 2387,84 0.45 2385, 2~61.26 0,50 245~, 2532.77 0.67 2329. 2602.57 0.45 259~. 2572.10 0.56 2568. SULAR COORDINATES HORIZ. SOUTH EAST/WEST DIST. T FEET FEET DEPARTURE ~ZIMUTH OEG MIN 39 N 10.90 E 86.08 83 N 6.44 E 110.02 11 N 1.82 E 139.12 83 N 2.33 W 173.83 30 N 6.00 W 213.38 35 N 9.45 W 257.52 65 N 12,80 W 306.92 69 N 16.40 W 363.07 64 N 20,37 W 427,12 68 N 24,32 W 495.28 N 7 16 E N 3 21 E N 0 44 E N 0 46 W N 1 36 W N Z 6 N 2 23 N 2 35 W N 2 44 W N 2 48 W O1 N 27,99 W 563,70 84 N 31.31 W 632,62 22 N 34,46 W 702,07 '91 N 37,55 W 771,82 76 N 40,61 W 841.74 3.3 N 43,10 W 912,35 90 N 45.07 W 983.93 Oi N 46.93 W 1056.05 25 N ~9,73 W 1128.36 34 N 53,65 W 1200,54 Z 5O W 2 50 N 2 48 W Z 47 W 2 45 W' 2 42 W 2 37 W 2 32 W 2 31 N 2 33 W 38 N 57,86 W 1271,69 67 N 61,01 W 1343,06 87 N 62,63 W 1415,26 91 N 63,34 W 1~87,26 92 N 63.40 W 1559,20 32 N 62,35 W 1631,51 06 N 57,63 W 1707.04 47 N 49.92 W 1784.17 14 N 50,66 W 1857,83 03 N 60.75 N 1932.99 N 2 36 W N 2 36 W N 2 32 W N Z 26 W N 2 19 W N 2 11 ~. N 1 56 L N 1 36 W N 1 33 W N 1 4~ ~ 37 N 70.52 W 2010.61 37 N 79.01 W 2086.86 76 N 86.58 W 2161.49 93 N 94.32 W 2236.92 62 N 102.35 W 2312.38 35 N I10.07 W 2387.88 46 N 118.04 W 2461.29 66 N 125,67 W 2532.78 16 N 133,13 W 2.502,57 40 N 140.62 W 2672.10 0 10 17 24 32 38 44 5O 55 0 COMPUTATION DA'TE: 23-SEP-86 PAG:.. 7 STANDARD ALASKA PRDDUC'TION CO 3-23/N-32 SDZ ENOICOTT NORTH SLOPE,ALASKA ~NTER'POLATED VALUES :FOR MEASURED DEPTH TRUE SU'B-SEA 'CC. URSE VERTICAL VERTICAL DEVIATION AZIMUTH DEPTH DER'TH DEG MIN DEG M!N 878'7.06 8907.80 9028.15 9147.77 9266.65 9384.71 9501.65 9617.50 9732.03 9846.90 7955.48 7900.00 34 12 N 6 34 80155.48 8000.00 33 58 N 6 30 8155.48 8!00.00 33 36 N 7 2 8255.48 8200.00 32 58 N 7 24 8355.48 8300.00 32 26 N 8 7 8455.48 8400.00 31 38 N 8 16 8555.48 8500.00 30 47 N 8 36 8655.48 3600.00 29 46 N 8 57 8755.48 8700.00 28 52 N 8 49 8855.48 8800.00 30 15 N 7 47 99 100 101 103 104 105 106 107 108 110 63.36 80.58 97.90 14.82 31.62 48.27 54.37 79.95 95.07 09.4g 8955.48 8900.00 31 I0 N 7 3 W 9055.48 9000.00 31 38 N 5 57 W 9155.48 9100.00 31 21 N 5 23 W 92.55.49 9200.01 31 10 N 5 15 W '9355.48 9300.00 31 6 N 4 20 W 9455.48 9400.00 30 ,45 N 3 ! fi 9555.48 9500.00 3,0 !! N 1 36 W 9655.48 9600.00 29 55 N 0 .24 ~ 9755.48 9700.00 29 30 N 2 10 E 9855.48 '9800.00 28 23 N 4 55 E 111 112 113 114 115 116 117 22.86 36.22 49.22 61.64 73.93 .86. ! 1 83.00 9955.45 9900.00 28 11 N 5 29 E 10055.48 i0000.00 27 52 N 5 46 E 10155.48 10100.00 27 25 N 6 11 E 10255.48 1020,0.,00 27 7 N 6 39 E 10355.48 t0300'.00 26 52 N 6 44 E 10455.48 10400.00 26 59 N 6 52 ~ 10541.81 10485.33 26 59 N 6 52 E DATE OF SURVEY: 18-SEPT-86 KELLY BUSHING ELEV'ATIO'N: 55.48 FT ENGINEER': B&R'BA EVEN 100 FEET OF SUB-SEA DEPTH VERTICAL DOGLEG RECTANGULAR SECTION SEVERITY NORTH/SOUTH FEET DEG/IO0 FEET COORDINATES HORIZ. DEPARTURE EAST/WES'T DIST. AZIMUTH FEE'T FEET DEG MIN 2740.59 2808.13 ;28'74.95 2940.4,2 300,4.45 3066.94 3127.31 3185.48 324!.00 3297.28 0.55 2736.58 N 0.21 2803.80 N 0.52 2870.30 N 0.63 293;5.43 N 0.56 2999.09 N 1.08 3061.19 N 1.02 3121.19 N 1.05 3178.96 N 0.39 3234.11 N 1.32 3290.03 N 148.39 W 2'740.60 N 3 6 W 156.0.4 W 2808.14 N 3 i1 W 163.97 W 2874.98 N 3 16 W 172.18 W 2940.47 N 3 21 W 180.89 W 3004.54 N 3 27 W 189,92 W 3067.08 N 3 33 198.68 W 3127.51 N 3 38 207.74 N 3185.74 N 3 44 W 216.38 W 3241.34 N 3 49 W 224.61 W 3297.69 N 3 54 W 3356.79 341'7.83 3479.11 3539.64 3599.99 3660 · Ol 3719.00 3776.90 3833.78 3888.85 3941.87 ~994 56 4046.63 4097.30 4147.66 4197.76 4241.08 0.63 3349.22 N 0.47 3409.98 N 0.48 3471o03 N 0.14 3531.35 N 0.85 3591.50 N 0.46 3651.41 N 0.90 3710.35 N 0.39 3768.30 N 0.89 3825.33 N 0.82 3880.65 N 0.49 3934.00 N 0.06 3987.14 N 0.75 4039.46 N 0.30 4090.50 N 0.28 4141.25 N 0.00 4191.73 N 0.00 4.235.39 N 232.32 W 335'7.27 N 3 58 W 23'9.26 W 3418.37 N 4 0 ~ 245.26 W 34'79.68 N 4 2 W 250.87 W 3540,25 N 4 3 W 25,6.13 W 3600.63 N 4 4 W 25'9.87 W 3660.65 N 4 4 ~ 262.3.5 W 3719.62 N 4 2 W 262.99 W 3777.46 N 3 39 W 261.68 W 3834.27 N 3 54 W 258.38 W 3889.24 N 3 4~ W 253.42 W 3942.16 N 3 41 W 248.13 W 3994.85 N 3 33 W 242.77 W 4046.75 N 3 26 W 235.94 W 4097.36 N 3 18 W 231.03 W 4147.69 N 3 11 W 224.97 W 4197.76 N 3 4 219.70 W 4241.08 N 2 58 k C'3MPUT,&Ti~N O~'T?.: 23-SEP-8~ 8 STANDARD ~LASK~ PRODUCTION ~0 3-2B/N-3Z SDt ENDICOTT NORTH SLOPE,ALASKA MARKER DRILLERS DEPTH ZNTERP3LATED VALUES FOR CHOSEN HORIZONS MEASURED DEPTH BELOW K5 I!783.00 FROM KB 10541.81 PAGE DATE g~ SURVEY: 18-SEeT-86 KELLY BUSHIN:G ELEVATION: ENGINEER: 5ARBA 5.5.46 FT SURFACE LOCA'TION AT ORIGIN: 2520 SNL, 769 WEL~ SEC 8~ TllN~ R17E TVD RECTANGULAR COORDINATES SUB-SEA NORTH/SOUTH EAST/WEST 10486.BB 4235.39 N 21g.70 W COMPUTATION DATE: 23-SEP-86 PAGE STAND&RD A:LASKA PRODUCTIDN CO 3-23/N-3Z ENDICOTT NORTH SLOPE,ALASKA STRAT ZG~qAP'H iC SUMMARY DATE OF SURVEY'.' 18-SEPT-S6 KELLY BUSHING ELEV~TTON: 'ENGINEER: BARB~ M A R K E R DRILLERS DEPTH MEASURED DEPTH BELOW KB 11783.00 'FROM KB 10541.81 ORIGIN= 2520 TV'D SUB-SEA 10486.33 SNL, SURFACE LOCATION AT 769 WEL, SEC $, 'TIIN, R17E RECrTANGULAR COORDINATES NORTH/SOUTH E~S'T/WEST .4235..39 N 219.70 W FINAL WELL LOCATION AT TD: 'TRUE SUB-SEA MEASURED VERTICAL VERTICAL DEPTH DEPTH 9EmTH H,GRIZONTAL CEPARTURE DISTANCE AZIMUTH F'EE'T DEG MIN FT !I783.00 10541.81 10486.33 4241.08 N 2 58 W SCHLUhlBEROER D I RECT I ONAL SURVEY' COMPANY STANDARD ALASKA PRODUCTION WELL 3-2B/N-82 SD I FIELD ENDICOTT COUNTRY USA RUN 1 DATE LOOOED 18 - SEP - 88 REFERENCE 000071710 WELL: 3-23/.N-32 SDI 'WEL S8 TllN R17E) (2520'SNL, , , , ._ .RIZONTAL PROJECTION NORTH SOOO SOOO 4000 9000 2000 ! 000 -1000 SOUTH -2000 -400O NEST REF 0000717!0 SCALE = l/fOOD IN/FT ~ : ~ ; ~ F- ~-'i .... ?"T"~-' !-'i" i-'~ ? ! : : ! ~ · i 'i'"?.?' i ! ! : , !'"t:"'? ~ .... ~ ~ ! i . 7' ! *: "~ ' ' ~"F"?"! ...... ~"'7'"!'"~ ' i' ~ ~ ~ ~ ! 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SCALEO IN VERTICAL OEPTHS HORIZ SCALE = 1/1000 IN/FT , TELI~=] Teleco Oilfield S~ ~~mmmmm~ 6116 Nielson Wa~, Anchorage, AK 99502 (907) 562-2646 September 9, 1986 ;s of Alaska Inc. JOB # 532 TAK STANDARD ALASKA PRODUCTION CO. WELL: 3-23/N-32 ENDICOTT SDI RIG: P.P.A. #7 Please find attaChed a copy of the computer calculated MWD directional surveys for the above mentioned well. We at Teleco appreciate this opportunity to provide service to Standard Alaska Production Company. Teleco is committed to providing the highest quality of service and we would welcome any comments or questions concerning these surveys or any of our other services. Sincerely, Pat Havard Field Service Supervisor PH/el Enclosures A ,,~,,N~T COMPANY TELECO OILFIELD SURVEYS JOB 532 SURVEY CALCULATIONS **************************************** Date Page 09/09/86 Company: S.A.P.C. Well: 3-23/N-32 Location: ENDICOTT SDI Rig: P.P.A. ~? TELECO Job # 532 TAK Grid Correction: Magnetic Declination: Total Correction: Proposed Direction: 0.00 degrees 31.50 degrees 31.50 degrees 357.00 degrees RADIUS OF CURVATURE CALCULATION **************************************** MEAS DIRECTION TRUE VERTICAL COORDINATES CLOSURE DOG LEG DEPTH INCL AZIMUTH BEARING VERT DEPTH SECTION N/S E/W DIST ANGLE SEVERITY feet deg deg deg/min feet feet feet feet feet deg deg/100' TIE INTO GYRO SURVEY @ 2466' 2466.00 0.7 44.7 N 44 42 E 2465.93 7.79 8.38N ll.02E 13.84 TELECO M.W.D. SURVEYS N 52.749E 0.000 3513.00 3.1 8.6 N 08 36 E 3512.52 31.72 33.00N 23.63E 40.59 N 35.601E 1.684 3607.00 5.0 359.9 N 00 06 W 3606.28 38.30 39.62N 24.12E 46.38 N 31.335E 2.119 3702.00 7.0 356.7 N 03 18 W 3700.75 48.23 49.54N 23.82E 54.97 N 25.685E 2;134 3434.00 2.1 28.4 N 28 24 E 3433.60 28.40 29.62N 22.50E 37.20 N 37.216E 0.149 3055.00 1.6 20.3 N 20 18 E 3054.80 17.55 18.49N 17.46E 25.43 N 43.360E 0.164 TELECO Job # 532 TAK 09/09/86 Page 2 , , MEAS D~RECT~ON TRUE VERTICAL' COORDINATES CLOSURE DOG LEG DEPTH INCL AZIMUTH BEARING VERT DEPTH SECTION N/S E/W DIST ANGLE SEVERITY feet deg deg deg/min feet feet feet feet feet deg deg/100 ' **************************************************************************************************** 3796.00 8.9 351.4 N 08 36 W 3793.84 '61.20 62.47N 22.48E 66.39 N 19.793E 2.164 3890.00 11.3 352.1 N 07 54 W 3886.38 77.62 78.78N 20.11E 81.31 N 14.324E 2.556 3985.00 13.6 349.3 N 10 42 W 3979.14 97.97 98.99N 16.80E 100.40 N 9.636E 2.502 4079.00 15.8 349.7 N 10 18 W 4070.06 121.62 122.44N 12.46E 123.07 N 5.811E 2.343 4281.00 20.7 354.2 N 05 48 W 4261.84 184.60 185.04N 3.60E 185.08 N 1.117E 2.522 4470.00 24.6 355.6 N 04 24 W 4436.23 257.32 257.52N 2.86W 257.54 N 0.637W 2.083 4659.00 29.4 356.7 N 03 18 W 4604.58 343.09 343.10N 8.62W 343.21 N 1.439W 2.553 4754.00 32.2 357.0 N 03 00 W 4686.17 391.72 391.67N 11.29W 391.83 N 1.652W 2.952 4943.00 34.4 356.0 N 04 00 W 4844.13 495.48 495.23N 17.62W 495.55 N 2.039W 1.200 5133.00 34.6 356.3 N 03 42 W 5000.72 603.09 602.61N 24.85W 603.12 N 2.362W 0.138 5416.00 35.1 356.7 N 03 18 W 5232.96 764.79 764.02N 34.72W 764.81 N 2.602W 0.194 5607.00 35.3 356.7 N 03 18 W 5389.04 874.90 873.95N 41.01W 874.91 N 2.687W 0.106 5797.00 35.7 357.4 N 02 36 W 5543.72 985.23 984.14N 46.69W 985.24 N 2.716W 0.300 5986.00 35.9 358.1 N 01 54 W 5697.01 1095.78 1094.61N 51.03W 1095.80 N 2.669W 0.241 6175.00 35.9 356.7 N 03 18 W 5850.11 1206.60 1205.32N 56.05W 1206.62 N 2.663W 0.435 6460.00 35.9 358.1 N 01 54 W 6080.97 1373.71 1372.26N 6839.00 35.9 0.2 N 00 12 E 6387.97 1595.77 1594.46N 63.63W 1373.73 66.93W 1595.86 N 2.655W 0.288 N 2.404W 0.325 TELECO Job # 532 TAK ..... 09/09/86 Page 3 MEAS DIRECTION TRUE VERTICAL COORDINATES CLOSURE DOG LEG DEPTH INCL AZIMUTH BEARING VERT DEPTH SECTION N/S E/W DIST ANGLE SEVERITY feet deg deg deg/min feet feet feet feet feet deg deg/100 ' **************************************************************************************************** 7091.00 38.1 5.1 N 05 06 E 6589.22 1746.64 1745.90N 59.92W 1746.92 N 1.966W 1.459 7337.00 37.3 350.4 N 09 36 W 6783.86 1896.65 1895.80N ~93.00 37 8 353 5 N 06 30 W 6986 82 2052 05 2050 27N 7782.00 36.9 353.9 N 06 06 W 7137.06 2166.52 2164.24N 7965.00 37.6 353.2 N 06 48 W 7282.73 2277.09 2274.31N 8157.00 37.1 353.2 N 06 48 W 7435.36 2393.33 2389.99N 8345.00 36.0 353.5 N 06 30 W 7586.39 2505.06 2501.19N 8533.00 34.9 353.9 N 06 06 W 7739.53 2613.91 2609.57N 8815.00 34.5 352.5 N 07 30 W 7971.38 2774.09 2768.97N 9004.00 33.8 352.5 N 07 30 W 8127.79 2879.87 2874.17N ~,~.88.00 32.7 351.8 N 08 12 W 8365.29 3035.03 3028.43N 9477.00 31.2 351.8 N 08 12 W 8525.65 3134.64 3127.43N 9664.00 29.4 351.1 N 08 54 W 8687.10 3228.54 3220.72N 9853.00 30.7 352.5 N 07 30 W 8850.69 3322.79 3314.39N 10043.00 31.7 354.9 N 05 06 W 9013.21 3421.04 3412.22N 10232.00 31.5 355.6 N 04 24 W 9174.19 3520.03 3510.91N 10514.00 31.0 357.0 N 03 00 W 9415.27 3666.31 3656.90N 65.81W 1896.94 N 87.66W 2052.14 N 100.24W 2166.56 N 112.68W 2277.10 N 126.42W 2393.33 N 139.38W 2505.07 N 151.35W 2613.95 N 170.36W 2774.21 N 184.15W 2880.07 N 205.42W 3035.39 N 219.63W 3135.13 N 233.66W 3229.19 N 247.16W 3323.60 N 257.96W 3421.96 N 266.16W 3520.99 N 275.60W 3667.27 N 1.988W 3.662 2.448W 0.763 2.652W 0.493 2.837W 0.447 3.028W 0.261 3.190W 0.593 3.319W 0.598 3.521W 0.316 3.666W 0.371 3.881W 0.410 4.017W 0.794 4.150W 0.981 4.265W 0.782 4.323W 0.840 4.335W 0.222 4.310W 0.313 TELECO Job # 532 TAK 09/09/86 Page 4 , MEAS DIRECTION TRUE VERTICAL COORDINATES CLOSURE DOG LEG DEPTH INCL AZIMUTH BEARING VERT DEPTH SECTION N/S E/W DIST ANGLE SEVERITY feet deg deg deg/min feet feet feet feet feet deg deg/100 f **************************************************************************************************** 10703.00 30.2 359.5 N 00 30 W 9577.95 3762.49 3753.05N 10874.00 29.8 2.0 N 02 00 E 9726 °04 3847.80 3838.54N 278.53W 3763.38 N 277.42W 3848.55 N 4.245W 0.795 4.134W 0.767 TELECO Oi 1 Fi eld Services VERT I CAL PROJECT I ON O. W LO W 0 2000 9000 4OOO 5OOO 8000 7O0O SO00 9000 10000 11000 1000 2000 9000 4000 5000 DODO 3- 2.~/~-32 -:.o~, !.o C,~'G _ _. ½ ! E~ o ~;~j~ ~_ ~:~ ........... t ~ B. LR,_^, # 7_ 1 , - ~370~ ~ ~..o,, _~_. ~- ......... °~'~--~ ........ ~_~--~ ........ sc:~cm ~ ._ . . I .... I · I Zgl5 ~, ~ ;O~:G .....1 t X L , :'--,--r'] -~:~ ............ i ' - ~'" I. . ~'.... ' - - VERTICAL SECTION (~t) TELECO Oil~i~ld PLAN VIEW S~rvic~s WEST (Ft) 4000 3200 2400 1600 800 0 0 800 720O 6400 58OO 4800 4ooo,~ -r n~ 3200z 2400 1600 800 Form to be inserted in each "Active" well folder to check for timely compliance with our regulations. PER~TOR, WELL NAME AND NUMBER Reports and Materials to be received by: Date Required Date Received Remarks Completion Report y~ /~ "~d'- ~ Well History S~ples .. ' Mud Log ~~~01 " ' Core Chips Core Description ~egisterea Survey ~at ~cZ~t~o~ S~e~ ,, Directional Survey / ~ -~ O--~A~ ~rill Stem Test Reports , Production ?est Reports Digitized Data MEMORA .- UM Sta"--of Alaska ALAS~A Oil, .~,~D GAS CONSERVATION CO~,~IS:.,~ON TO: C.V. C~~t~ti DATE: August 28, ]986 Chairma~f~/ v RLENO.: D.HRH.55 TH RU: FROM: Lonnie C. Smith-~'i TELEPHONE NO.: Commissioner SUBJECT: BOP Test SAPC PBU N'32 Harold R. Hawkins Permit No. 86-155 Petroleum Inspector Endicott Oil Pool Frida?7_, August 22 i986: I left ARCO drill site 7, subject of an6th~ ~r~Por't'' £gr Standard Alaska Production Company Endicott Field to witness a BOP test on Arctic Pool Rig 7. Saturday, August 23, 1986: I witnessed the BOP test on N-32. %"here was one fai%ure~ 'the ball floor valve. I filled out an AOGCC field report which is attached. In summary, the BOP test Arctic Pool 7 performed was satisfactory with the exception of the ball floor valve. SAPC is to call AOGCC when replaced or repaired, Attachment Tuesday,lAugust 26, 1986: Bill Struble of SAPC called to say the ~afetY fio0~ ball Valve was repaired and tested o.k. 02-001 A ( Rev 10-84) ACCUM[FLATOR SYSTEM Pit Gaug;.: 'flow j-io;~itor Gas' Detectors _ /"" _ _ OPE Stack %est PreSsure B . Annular Preventer___ Pipe Rams Blind ?,&ms [ .... ~.~._~ ~? Choke Line Valves ~ ~.~.~ F011 'Charge Pressure -. Pump incr. clos'.-Pres. 200 psJg -~ mi Full Charge Pressure Zttained: ~-~ Controls: Haster~. --. Remote __~ Blinds-switch cov~r Kelly and Floor Safety Valves . UpPer Kelly Test Press~re--t~ Lower Kelly Ball Type inside BOP Choke [!anifold -. No. Valves__/. ~- No. flanges~~ Adjustable Chokes__~__~. A~ Jif' ... iivdrau ica!l~ o__pe~-a t ed choke Test Pressure .... ~¢,::,'0 . Test Pressure 'TeSt Results: FaiIures~ -~-~~- Test T:i~:e. ~ hrso ____~- . ' ~' ~Repair o~ Replacement of failed equipment to be made within '~ days and inspe~:/* - . w . _ Co~ission office notified. ~." D~strtbutior~ orig. - cc - OPerator cc - Supervi~,r Standard Alaska Production Company 900 East Benson Boule~ P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 564-5111 STANDARD ALASKA PRODUCTION Mr. Mike Minder Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 August 15, 1986 Dear Mi ke, I enclose three pad maps for Endicott Satellite Drilling Island as you requested. The maps show the gyroscopic surveys for the drilled wells Q-35 and M-33 and also the proposed well paths for the current well 0-29 and our next well N-32. Should you require any further information, do not hesitate to contact me. RSA/IRR/pm/1045D Attachment CC' R. H. Reiley J. F. Gulick 2. G. Vidrine T. O. Stagg File 16.4 Endicott Development R. S. Allan Division Drilling Engineer A unit of the original Standard Oil Company Founded in Cleveland, Ohio, in 1870. August 15, 1986 Telecopy.- (907) 276-7542 Mr. R. S. Allan Division Drilling Engineer Standard Alaska Production Company P.O. Box 196612 Anchorage, Alaska 99519-6612 Re: Duck Island Unit N-32 SDI Standard Alaska-Production Company Permit No. 86-155 Sur. Loc. 2520'S5~, 769'%~L, Sec. 8, TllN, R17E, UM. Btnkhole Loc. 3496'SNL, 98!'WEL, Sec. 5, TllN, R17E, UM. Dear Mr. Allan: Enclosed is the approved application for permit to drill the above referenced well. The permit to drill does not indenm_ify you from the probable need to obtain additional permits required by laTM from other governmental agencies prior to commencing operations at the well site. To aid us in scheduling field work, please notify this office 24 hours prior to commencing installation of the blowout prevention equipment so that a representative of the Commission may be present to witness testing of the equipment before the surface casing shoe is drilled. ~ere a diverter system is required, please also notify this office 24 hours prior to commencing equipment installation so that the Commission may witness testing before drilling below the shoe of the conductor pipe. V~ry--)t ru~_~u~r.s, . C. V. Ch~e~on-' Ch~rm~n ~ BY ORDER OF THE COI~,fISSiON dtf Enclosure CC: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. Mr. Doug L. LowezTz ~ STATE OF ALASKA A~ow 3 , ALASKa-..)IL AND GAS CONSERVATION t ~,MMISSION slot 23 PERMIT TO DRILL 20 AAC 25.005 la. Type of work Drill ~ Redrill []1 lb. Type of well. Exploratory [] Stratigraphic Test Q Development Oil Re-Entry ~ Deepen~1 Service ~ Developement Gas ~, Single Zone ~ Multiple Zone ~ 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool Standard Alaska Production Company 56' AMSL feet Endicott Field Endicott Oil Pool 3. Address 6. Property Designation P,O. Box 196612 Anchorage Alaska 99519-661:). ADL 47502 4. Location of well at surface 7. Unit or property Name 11. Type Bond(see 20AAC 25.025) Duck Island Unit/Endicobt 252~t SNL _769 WEL,Sec8,TllN,~R17E top of product ve interval 8. Well nu ,tuber Number 3780 SNL 975 WEL,Sec5;TIZN,'R17E N - 32 SDI K00683449-G-14 At total depth 9. Approximate spud date Amount $200,000.00 3496 SNL 981' WEL,Sec5,TllN,R17E August ~18, 1986 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD andTVD) property line Surface 11788 MD ADL 47503 769 feet 48ft from M33 SDI feet 2560 10496 TVD feet 16. To be completed for deviated wells 34.4 o 17. Anticipated pressure (see 20 AAC 25.035 (e)(2)) Kickoff depth 3500 feet Maximum hole angle 0 Maximum surface 3900 psig At total depth (-rVD)9855 4840 psig 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 30" Str'~ctura] Driv=_ Pipe 105' Surface !161 161 Drive 17%,, 13-3/8" 72~ L-80 Butt. 2444 Surface ~2500 2500 3700 cu. ft. permafrost 12¼" 9-5/8" 47~ NT80S NCSS 5675 ~urface 5731 5500 320 cu. ft. Class G 12%" 9-5/8" 47# NT95H~ NCSS 519_~ 5731 10872 9741 !425 cu ft Class G. lsl 8~." 7" 29# L-80 Butt. 1166 10622 .11788 10496 293 cu. ft. Class G 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented Measured depth True Vertical depth Structural Conductor t." .: , Surface -~ ,, Intermediate .: t Production Liner ~-~d.~,,,,, ,,,~ ,.'* ...... ' Perforation depth: measured /:,l:~; ..... ~.., true vertical 20. Attachments Filing fee:~ Property plat ~ BOP Sketch ~ DiverterSketch [] Drilling programx~ Drilling fluid program ~ Timevs depth plot [] Refraction analysis [] Seabed report ~ 20AAC25.050 requirements 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signe~l , ~, Title Division Drilling Engineer Date ~ Commission Use Only _~_, APl number I Approval dateIeeecover letter Permit Number~ (~' (.fSb 50-- 0 L. fi -l~i g'-/J"I 08/15/86~ for other requirements Conditions of approval Samples required F'} Yes ~No Mud Icg required ~ Yes ,~.No Hydrogen sulfide measures ~ Yes_ ~ No Directional survey required ~ Yes ~ No Required wo~/~/~~ ,~ 5M; [] 10M; ?, 15M t_e~.~.. Other: by order of Approved byk F. ¢. k ...~ .~--~'~'~ Commissioner the commission Da Form 10-401 Rev. 12-1-85 ! / Submit, ~ triplicate PROPOSED DRILLING AND COMPLETION PROGRAM i~ELL ~)-23/N-~)2 Execute a row to row move from slot 4-20 and rig up on slot 3-23. Vertically drill 17-1/2 in. hole to 2500 ft. and cement 13-3/8 in. 72 lb/ft., L-80 buttress casing to surface. Pressure test casing. Install BOPE. Maximum BHP is 4840 psi at 9855 ft. TVDss. Maximum possible surface pressure is 3900 psi based on a full gas column. Drill out casing and 5 ft. of new hole and conduct formation leak off test. Vertically drill 12-1/4 in. hole to 3500 ft., then directionally drill to the intermediate casing point above the Kekiktuk formation. Run and cement 9-5/8 in. 47 lb/ft., NTSOS and NT95HS, NSCC casing. No abnormal pressure intervals are expected in the 12-1/4 in. hole section. Pressure test casing. Drill out casing shoe and 5 ft. of new hole and conduct formation leak off test. Drill 8-1/2 in. hole to TD. Run logs and RFT's. Run and cement 7 in. 29 lb/ft., L-80 buttress liner to TD with approximately 250 ft. of lap in the 9-5/8 in. casing. Clean out to float equipment. Test casing and lap to 3000 psi. Change over to NaCl packer fluid. Run one joint of 4-1/2 in. 12.6 lb/ft., L-80 TDS tubing on the tubing hanger, and land in the wellhead. Install 2-way check valve. Nipple. down BOPE. Install adaptor flange and master valve w~th blind flange complete with 1/2 in. NPT needle valve and test to 5000 psi. Move-off rig. Run CBT/VDL/GR/CCL in liner and gyroscopic survey from PBTD to surface. Downsqueeze the 13-3/8 in. X 9-5/8 in. annulus with Permafrost cement followed by a non-freezing fluid once rig is off location. Move rig on location in mid-1987 and complete with a wireline run and set 7 in. packer with 3-1/2 in. tailpipe followed by a 9-5/8 in. packer with 3-1/2 in. tailpipe run on 4-1/2 in. 12.6 lb/ft., L-80 TDS tubing with GLM's. A sub surface safety valve will be installed below base of permafrost. Install and test tree. Release rig. Perforate well with wireline run 2-1/8 in. thru-tubing guns once rig is off location and flow well to clean-up. IRR/pm/O997D TVD BKB MD BKB DRILLING PROG~ PROPOSED WI--LLRORE DIAGRAM WELL 3-23/N-32 161 FT 161 FT ~0 IN DRIVE PIPE NON FREEZING FLUID 5:36 FT 15:36 FT 600 FT ! 600 FT BASE PERMAFROST SUB SURFACE SAFETY VALVE 200OFT 2000 FT 250OFT 2500 FT TOP DOWNSQUEEZE CEMENT 13 3/8 IN 72"/FT L80 BUTT 3000 FT BOTTOM DOWNSQUEEZE CEMENT 5500 FT 5731FT 9 5/8 IN 47 ~/Fl NT80S NSCC 9872 FT 10512 FT 10572 FT TOP OF CEMENT SLIDING SLEEVE PACKER 10622 FT LINER TOP 9741FT 10872 FT De pt h per ope n hole log res ul ts 10081 FT 11285 FT 9 5/8 IN NSCC PACKER 47#/FT NT95HS 7 IN MARKER JOINT 11708 FT 7 IN PBTD 10496 FT 11788 FT 7 IN 29 #/FT LBO BUTT COMPLETION DELAYED UNTIL MID 1987. ,4-1/2 IN. 12.6 LB/FT LeOTDSTUBINGW/GLM'$. ~ · R~ PERFORATE WELL WITH 2-1/8 IN. THRU-TUBING GUNS~ 5/14/86 B.O.P. STACK CONFIGURATION 13-S/§ IN. TRIPLE RAM STACK SO00 PSI WP DRILLING ANNULAR PREVENTER I I ! i PIPE RAMS i I i I BLIND RAMS i :2 IN. KILL LINE GATE GATE DRILLING SPOOL i P I PE RAMS ! I 4 IN. CHOKE LINE ! GATE GATE / --. N=32 Days Drill 17-1/2 in. hole: 2.0 Run 13-3/8 in. casing: 1.0 Drill 12-1/4 in. hole: 2500 - 6000 ft ~, 685 ft/day: 6000 - 10872 ft (, 410 ft/day: 5.0 11.75 Run 9-5/8 in. casing: 2.5 Drill 8-I/2 in. hole (, 166 ft/day: 10872 - 11788 ft 5.5 Log (includes RFT's): Drill and evaluate: 29.25 days .. Run liner and cement: 3.0 Suspend: (Release Rig) Completion: 3.5 days Move in completion rig: 0.25 Rig up, install and test BOPE: Condition hole: Run wireline set packer/tailpipe in 7 in liner: Run completion tubing/9-5/8 in. packer: 0.75 0.75 0.50 1.0 continued on next page Install and test tree: 0.5 Release rig: Completion: 4.0 days Summary: Drill and evaluate: 29.2~$ days Completion: 7..5 days Total to drill and complete: 36.75 days ENDICECT DEVELOPMENT WELL 3-23/N-32 Departure to TD: 4308 ft. 11788 ft. MD 10496 ft. TVD BKB Departure to Target: 4024 ft. 11285 ft. MD 10081 ft. TVD N 3.0@W Slot 3-23 Surface Location: X = 270,'273 ft.; Y = 5,970,977 ft. 2520 ft. SNL; 769 ft. WEL Sec 8, TllN, R17E True North Grid NOTE: The nearest well to N-32 is M-33 located 48 ft. NE at slot 3-27 A well interseCtion with. well SI-DI1 will be encoutered with ~he planned wellbore courseline for N-32. _$25DU~88: [DRANO14]SIN32_CLOSAP_SHORT7. LIS; 1 Date: Search Radius= 8012 7 DEGREE LEAD LINE For proposed well~ SI-N32143- 5-11-17] Location = W-E S-N TVD(SBS) Top 270273~ 00 5970~77.00 -56.00 Bo%tom 269703.09 5974912.06 9955. 14 Note: Ail depths in ~eet Below Kell§ Boshing (BKB) --- Closest App~'oach A algsis --- 1-AUG-86 Time~~' 09: 43:38~ Closest Approach WELL IDENT /PROPOSED\ /NEARBY'~ TVD DEPART TVD DEPART C LOSE S T D I S T ANC E AO00-O000001 SI--1 0.0 O. 0 O, 0 O. 0 109.7 AO00--O000002 SI-2 0.0 O. 0 O. 0 0.0 202.6 A000-0000025 SI-25 0.0 O. 0 O. 0 0.0 10. 0 A000-0000026 SI-2~ 0.0 0.0 0.0 0.0 170.3 AO00--O00002S SI-28 0.0 O. 0 O. 0 O. 0 !77. 5 A000-0000049 SI-49 0.0 0.0 O. 0 0,0 ~59.9 AO00-O000050 SI-50 O. 0 O. 0 O. 0 O. 0 233. 3 A029-2028000 SI-DI1 6650.7 16'72. 9 '7412.6 2575.2 1396.6 A029-2028001 SI-DI2 4377.0 174,5 4822.9 1423.8 1441. 1 A02~-2064000 MISDiO 10011. I 3976, 1 10529.7 6608.2 7506.3 A029-2156900 SI-Q35 300.6 0.0 300.0 O. I i49.8 A029-2158600 SI-M33 80i.0 0.0 800.0 1.9 48.4 SUMMARY The ~ell mhich comes closest to the proposed well is' A029 - 21586 SI-M33 48.,4 ~eet 3500.0 ~eet Closest approach distance = KICK OFF ~or this run = Ve'rticm! InteT~section /PROPOSED'~ /NEARBY\ \VD DEPART !'VI} DEPART NOTE: THIS IS A DUMMY SLOT VERTICA:_ DISTANC£ ,,=98.° 4852.3 440.2 '~"~ ' , 2493.8 24'74 ENDICOTT MUD PROGRAM WELL 3-23/N-32 SDI Interval Mud Weight Viscosity Fluid Loss ' (pps) (sec/qt) (ml/30min) 0-2500 8.8-9.0 200-300 20-15 PH 8.5-9.0 Mud Type Components Generic Mud #6 seawater Durogel Gel tte Soda Ash Caustic Soda 2,500 - 10,873 10,873 - ll ,788 Set 13.3/8" casing 9.0-9.8 40-45 15-16 9.9 Set 9' 5/8" Casing 40-45 6 Hang 7" Liner 9,-5-10.0 9.0-10.0 Generic Mud #2 Seawater Ge 1 i te Maxpac VC-IO Caustic Soda Soda Ash Barite Generic Mud #2 Seawa te r Gelite Maxpac VC-IO Caustic Soda Soda Ash Barite IR/pk 1 O04D Fc,'P' .p'popc,'se~ s~e]. ].' 'Si ..... ~'v-~"~[.,'.~.3~,~,,,= .... 5 ...... J. ~--] 73... Da%e' i .... &UC~--Ci',6 Time' 09' .4.,.L-'!" 3S .:. d e: p t h s i n< .F' e e t B e 1 o m K: e ! .: q t:'~. ~¢ .s h i :',,. q ,: '~:~ .... . AO00-O000001 S! .... t O. 0 O. 0 AO00-OC;O0002 c'I',_, '-='~ 0.. O. O. 0 AO00"-O00'O025, ,.,"= I - 25 O. 0 r),,.. 0 AO00'-O00C¢ 026 S I --= '~o/' O. 0 O. 0 A000--0000028 SI-=.~,"~c~ O. 0 0.. 0 A000-'000004.9 Si-49 O. 0 O. 0 ,-,0 s-,.-0 ,.'00 0 S ! --D i I '7'139 i. 8 2 ! 80. 8 S l -- D 12 4 37 7. 0 1 '74. 5 M I SD l 0 l O01 i. I "' < ...... · . =.-: --,= 156900 ~'" ~0. 6 0 S I -P}33 801.. 0 O, 0 O. 0 ! 0.. ,,:',, ;- ~ . , ,.,. <.,' ! 74:'. O. 0 177. O. 0 t = O. O' g: 33. 3085 ....;' .=. 1398. 1430. 6 1430. &608. ~'~ 786e 0'. I 149. i. 9 .4$. NOTE: THIS I'S A DUMMY SLOT A0'29 -' 215:86' SI-M33 ":' .. i <,:3' Closest ap?':'aach Ois'baT.,ce = },,; i 4:.'.,~ OFF .~: :~,'- *',.. h :' s r. un -.- ,.48 4' Ceet 3500. 0 ¢:,~t AO00- 0000001 9l-i O. 0 O. 0 0. 0 O. 0 109. 7 AO00.-O000025 S1-25 O. 0 O. 0 O. 0 O. 0 ].0. O. AOOO-OOOOO2<B ":~. ..... l.'-=.~,"~ ¢- "'*,¢ ..... $1-28 0. 0 0. O 0. 0 0. 0 ~%O00-000004.9 AO00-OOOC~O 50 SI-'"D: :i 6650. 7 I6.72. ":~ SI-DI2 437'7. 0 1'74,. 5 4S22. 9 ~..423. 8 144::. I ¢:O29--2064.000 FJ I SD ! 0 ~ 0(~ i 1 I 3~76 't ]. ,,.-, ~,-x..:~ '7 6608. 2 -F 50"~. 3 Sl-G35 300~ ~,, '=I--~"~33~, [~r"~:i....,. . NOTE: THIS IS A DUMMY SLOT A029 - 21586 SI,-M33 C. ioses't: epF:"o¢:~ch dis'~.~'.nce = 48..'.4 .Peet i,i :.': C ~& OF F' {~ o 'r t h i s :- o n = 3 ::500. 0 '¢ e ~,-:, t POOL ARCTIC ALASKA RIG NO. 7 Mud Tank/Trip Tank Monitoring-Recording TOTCO, PITOMETER UNIT L-8 (PNEUMATIC) DRILLING RECORDER SYSTEM TOTCO, MODEL DR8WPT (E) RS {2) F DRILLER'S CONSOLE TOTCO "COMMAND" POOL ARCTIC ALASKA RIG NO. 7 MUD AND SOLIDS CONTROL EQUIPMENT Equipment Manufacturer Model Nominal Capacity Shaker Brandt Dual Double I000 gpm Desanders Tri Flow/Pioneer Mann-Design 2 each - TFI-126 screens 4 each - Pioneer 12" Economaster Cones 1000 gpm (each) Mudcleaners Brandt Double 8 each - 4" Cones 400 gpm (each) Centrifuge Oiltools Decanting, Type S-3-0 160 gpm Degasser SWACO Vacuum 1000 gpm Agitators Brandt 7 each- 5 h.p., 32" Impellers Hoppers Geosource 2 each - 1000 gpm S-800 Sidewinders The trip tank and mud tank sections each have one vertical pit level float indicator which are connected to the drilling recorder system that contains visual and audio warning devices located in the driller's console. MISC44:00027 ,, I I THI~ IS A PRO- PRIE'TARY OES~G r.,' OF REPROOU~TION OR U~ OF THIS DEaN IS PER- MI~BLE ONL~ IF A~HORI~O IN ISSUED STOCK FOR INFORMATION ONLY JFEET J,NcH~sl LENGTH I W ~"~ ~ % A~cf~o~a~, Alaska 1000 tDI~L. &CT~VD MUD 5'r'STCM 5~CTION F_.b~v'iTION ~n LEVEL ~ILL .JP L. IN~ ~ -'iT TOP I THIS IS A PRO- PRIETA~Y DESIGN OF P.A.A. REPRODUCTION OR U$E OF THIS DESIGN I$ PER- MIS~BLE ONLY IF AUTHORIZED IN Wllrl'lN~) BY P.A.~ ISSUED ~ !~ FOR INFORA,~TION ONLY OESC RIPTION -- I,--, I 2OO ~ 'C' SlrNt A~chm~g~. Alast- 9,9501 f ~1 ~I I b ........ ~'~"",'" ........... TESTING THE B.O.P. STACK WITH THE 13-1/8" x 4%" IF BOX X BOX, (THRU-BORE), TEST PLUG (FIG. 7) -. 1.) Make up the 13-1/8" x 4%" IF test plug to a stand of drill pipe. (Illustration 9) NOTE: Sometimes it is helpful to make a stand of heavy wall up to the bottom of the test plug in order to help energize the compression packing. 2.) Lower the ~est plug through the B.O.P. stack until it lands on the lowe~r load shoulder of the~ split unihead unit. 3.) Run in at least two of the lower set of lockdown screws 180° opposed to hold the test plug in place. This is so the drill pipe can be backed out in order to test the blind rams. NOTE: All lockdown screws can be run in if need to energize the compression packing on the test plug. 4.) Test the B.O.P. stack. 5.) Back out all lockdown screws which have been run in. 6.) Remove the test plug. 13-1/8" X 4-1/2" IF BOX X BOX (THRU-BORE) TEST PLUG TI-tIS END UP L FMC P.N. 48-261-082 REQ'D PART ~O. DESCRIPTION i~ 48-261-268 Test Plug .1 48-261-083 Body _ I 48-261-673 Compression Ring 4 79-040-074 Se% Screws _ I 48-081-529 Packing ti'I 51-092-001 2" Ball Check Figure #7 _. --(Part-number 48-261-082 continued on next page) FMC P.N. 48-261-082 continued REQ'D. pART NO. DEscR'IPTION 1 19-505-663 Coil Spring 1 25-411-356 Retaining Plate 1 25-411-357 Circ.-O-Lox Ring 2 48-180-027 Pipe Plug 1 52-304-013 Drlg. Pipe Sub. ILLUSTRATION 9 .O.P. STACK 3-5/8" 5000 WP 3-'5/-8" 3000 WP TESTING THE B.O.P. STACK WITH THE 13%" X 4%" IF BOX X BOX, (UPPER) , TEsT PLUG (FIG. 19) 1.) Make 'up the 13%" x 4%" IF test plug (upper) to a stand of drill pipe. (Illustration 13) NOTE: Sometimes it is helpful to make a stand of heavy wall 6p to the bottom of the test plug in order to help energize the compression Packing. 2.)- LOwer the test plug through the B.O.P. stack until it lands on the upper load shoulder of the split unihead unit. 3o) RUn in at least two of the upper set of lockdown screws ~.'~ ~180° opposed to hold the test plug in place. This is so . ~ ~ ~ .the drill pipe can be backed out in order to test the blind rams. NOTE: All lockdown screws can be run in if you need to energize the compression packing on the test plug. 4,) ~Test the B.O.P. stack. 5.). Back out all lockdown screws which have been run in. Remove the test plug. 13-1/2" X 4-1/2" IF BOX X BOX (UPPER) TEST PLUG IS END UP --L FMC P.N'. 48-261-068 REQ'D PART NO. DESCRIPTION i 48--26-1-067 Body - -1 4-8~261-671 Compression Ring 4 ~'9-040-074 Set Screw 1 82-741-117 Packing , 1 51..092-001 2" Ball Check 1~ t9r505-663 Coil Spring _ 1 25 411-356 Retaining Plate 1 - -25-411-357 Circ.-O-Lox Ring 2- '48~t80-027 Pipe Plug Figure # 19 ILLUSTRATION # 13 B.O.P. STACK ~5/8" 5000 WP 13-5/8" 3000 WP TESTING THE B.O.P. STACK WITH THE 10" X 4-1/2" IF BOX X BOX (COMBINATION) , TEST PLUG (FIG. 22A) 1.) Make up the 10" x 4%" IF test plug (combinatiOn) to a stand of drill pipe. 2.) Lower the test plug through the B.O-.'P. stack until it lands on the upper load shoulder of the tubing/casing head. 3.) Rin in at least two of the upper set of Iockdown screws 180° opposed to hold the test plug in place. This is so the drill pipe can be backed out in order to test the blind rams. 4.) Test the B.O.P. stack. 5.) Back out all the lockdown scres whichhave been run in. 6.) Remove the test plug. 10" CO_~4BINATION TEST PLUG AND BOWL PROTECTOR RUNNING/RETRIEVING ToOL THIS END UP FMC PART NO. 48-261-503 REQ'D PART NO. DESCRIPTION 1 48-261-504 BODY 1 48-085-833 BELT PACKING 1 48-180-025 PLUG, 1¼ L.P. 1 48-180-025 PLUG, 1¼ L P. _ 4 I 48-180-015 - PLUG, '½ L.P. 1 1-48-010-009 WRENCH (Figure #22A) - t i. '""~ B.O.P. STACK 1" 5000 WP 13-5/8" 3000 Wi STACK - 11" 5000 WP ~_ 11" 5000 WP 13-5/8" 3000 WP I Y- 197096S.47 ~ 7i0~170,1S 700~9'20.2409· ~4~S~'49.2799' 2S3S.2l 171,0S Z- ~70~63,!0 E- ~.67~4~,06 ~ Y- S970796.40 N- 780~8~9.43 X- 270181,~7 E- 467~47,32 3 ~ Y- 5970966.51 ~N- 7801871.22 70~19'20,2~42 4 ; Y-5970797.44 iN-X, 270191.51 E' 7801819"80 ~70~19'1B'5975" i 147~ 51' 48' '21'' < 2702'58" 845'69 467,50.34 '~ ' 5 Y= 59709~7,56 N= 7801871,59':70~19'20.2675"' ~ 147c51'4~.701&" 25~2.58 858,22 ' X= 27018~.69 E= 467~47.1t & Y= 5970798.49 N= 7B01820.17 70o19'18,6108' 147o51'4B.0321' 2701.02 835.78 X- 27020t.46 E= 467553.37 7 Y= 597096B.&O N, 7801871.95 70c19'20.2808' 147o51'48.4~24' 2531.23 848.31 X= 270193,64 E- 467~50. t3 ~ Y= 5970799,54 N= 7B0~820.54 70c19'18.6240' t47c51'47.7429" 2699.67 a25.a6 X= 270211.41 E= 467~56.39 9 Y= 5970969.65 N= 7~0t872.32 '70o19'20.2940" t47o~t'48, t232' 2529.87 B38,40 X= 270203.58 E= 467553. t6 10 Y' 5970800.58 N= 7801820.90 70°19'1B.6373~ t47°51'4~.4537' 2698.32 Bt5,95 X- 270221.35 E- 467~9.42 11 Y- 5970970.69 N- 7BO~B72,&9 70~'19'20.3073· 147'c~1'47.8340' 2528.52 82~.49 X- 2702[3.~3 E- 467~6.18 12 Y- 5970801.63 N- 7801821,27 70o19'18.6506' 147o~1'47.1645' 2696.97 B06.04 X- 270231.30 E- 467~62.44 13 Y- 5970971.74 N- 7801873.06 70o19'20"~3206· 147c51'47,5448' 2~27.17 818.~7 X- 270223,47 E- 467~9.21 . ~4 Y' 5970802.~7 N' 780182Z,64 70o19'18.6639, 147~51'46.8754' 269~.62 796.13 X' 270241.24 E' 467~65.47 15 Y' ~970972.79 N' 7B01873.43 70o19'20.33~8' 147°51'47.255~' 252~.82 80B.66 X- 270233.42 E' 467~62,2~ 16 Y' 5970803.72 N' 7801822.0~ ~0°19'~8.&772' 147°~1'46.~862' 2694.27 786.21 X' 2702~1.19 E' 467~6B.49 17 Y' 5970973.83 N' 7801873.80 70°19'20,3471' 147051'46.9664, 2~24,47 79B,75 X- 270243.36 E' 467~6~.26 lB Y' 5970B04.76 N' 7801B22.38 70°19']8.6904' 1~°51'46.2970' 2692,91 776.30 X- 270261,~3 E' 467~71.~2 ~9 Y' 5970974.B8 N' 7BOIB74.~6 70019'20.3604, 147°51 '46.6772' 2~23.12 788.83 X' 270253.~1 E' 467~6B.28 20 Y' 5970805.81 N' 7801B22.7~ 70019'1B",7037' ~47°51'46,007B' 2691.56 7&6.39 X- 270271.08 E' 467~74.~4 21 Y' 5970975.92 N' 7801~74.53 70~i9'20,3736' 147°51'46.38B0' 2~21.7~ 77B.92 X- 270263.2~ E' 467~7~.30 ~ I i i i i ~ ::~ '~ ~.'~ SDI PRO~SEO WELL L~ATI~ UST .,-.:- ~.. - , .~.~%~~ L~::'::~:.,~: ~.~: LOCATED IN SEC. ~ ' - ~::-.;, '~' P RE PARED FOR · * ~_ ~.., ::', ,...,' ~ ~_~~.~.~__ SHEET e of IO F.R. BELL & ASSOC. SCALE: N/A ~ ?~ss~~ ~ PRU DHOE BAY OFFICE i i I i i I I I- I I II I I I I~LL ~ ZONE' 3 UT~ JNE & UITITUDE l- ~70211,0~ E- 4&7~77.S6 23 Y- 5970976.97 N- 7801874.90 70o19'20.3869· 147°~l'A&.OgB9' 2520,41 7&9.01 X- 270273,20 E- 467~74.33 24 ~ Y- 5970B07,90 ~ N- 780182~.48 170c~9'~8,7~02~ ~147~1'4~,4294' :-'2~B~-86 746,~6 X= 270290 97 i E= 467580 ~9 ~ , . 26 ~Y- ~~-94 T~; ~0i~2~;'~5 i70~19;i~ 7435 , 14705-i'~:~6~""-l--26~'"~-1 .... 73-6~5 j X- 270300.9t E= 467~83,6t .......... 27 Y" ~970982.19 N" 7801876,74 70~19'20,4~-~~ 147°51'44.~529" 2513,&5 719.44 X- 270322,92 E- 467~B9,4~ 28 Y" ~970813.12 N= 7801825.32 70o19'18,7966" X- 270340,69 E- 467~95,71 29 Y" 5970983,24 N" 7801877,11 70019'20,466~" 147°51'44,3&37" 2512,30 ~ 709,~3 X= 270332,~7 E" 467592.4B I 30 Y" ~970814,17 N' 7B01B25.19 70o19*t8.B09B" 14~51'43,~43" 21~0,7~ ~IT,0B X" 2703~0,64 E" 467~98,74 31 Y- 5970984,2B N" 7BOIB77,4G 7~19'20,479B" ~47°~1'44,0745" 2~10,9~~' ~99,&2 X" 270342,B~ E" 467~95,50 32 Y' ~97081~,21 N" 7801826,06 70~9'IB,B231" 147~51'43,40~2" 2~79.40 X- 270360,~8 E= 467601,76 33 Y= ~97098~,33 N= 7BO1877,B~ 70o19'20.49.31" ~47°~1'43,78~3" 2509,~0 ~' X- 270352,76 E= 467~98,53 34 Y= 5970816,26 N- 7801826.43 70019' lB, B364· 147o51'43,1160" 2678.04 . ~67.26 [- 270370,53 E= 467604,79 35 Y- 5970986,37 N= 7801B78,21 70°19'20,5063" 147o51'43,4961" 250B,25 ~ ~79.79 X- 270362,70 E' 467601,~5 j 36 Y= 5970817,31 N= 7801826.80 70o19'18.8496· 147°51'42,B268" 267&,~9 X- 270380.47 E- 467607.81 37 Y., 5970987,42 N= 7~01878,58 70c19'20,5196· 147°51'43,20~9" 2~0~,19 ~69.18 X- 270372,65 E' 467604,~8 38 Y- ~970818,3~ N= 7801B27,t& 70olg'lB,B629· 147°51'42,~37~" 2~7~,34 ~47,43 ~- 270390,42 E- 4&7~10,~4 39 Y- 59709BB,46 N- 7B01~7~,95 70019'20,5329· 147°~1'42,9171" X- 270382,~9 E- 467607,~0 ~0 Y- 5970819,40 N- 7B01B27,53 70olg'lB,B762· 147o51'42.2484" 2&73,99 ~37,52 X- 270400,36 E= 467613.86 41 Y- 5970989,51 N- 7BOIB79.32 70o19'20.5461" 147°51'42.&286" 2504.1t ~- 270392,54 E- 467610,62 42 Y- ~970B20,44 N- 7~01~27,~0 70°1~'1l'BB94" / X- 270410,31 E- 467616,~8 ~ i SDI O SED WELL L ATION LIST .~~~-- LOCATED IN SEC. ",.T. "N., R. I7E. UMIAT M. 4C SOHIO ALASKA PETROLEUM CO. t:~?. ~-~~'~ F.R BELL B ASSOC ~o.~,.,~~ ~ SHEET 9 of IO ' ' SCALE' N/A '~~ss,~~~ PRUDHOE BAY OFRCE OE~WN IY' R.G.T. ~%~%~~ REV. O PRUDHOE ~Y, ALASKA CHECKED BY: l.E i i I -- 43 ~ ye 8970990.86 Ne 710il79.69 70019'20.~594' 14~S~'42.3394' 2S02.B4 640.~4 I* Z70402.49 E' 4676i3.&S 44 f* S97012S.49 Ne 7eO~e21.~7 70~J9'i'1.9027' S47°S~'41.67~' 267~.29 &17.69 X' 270420,2S E- 4676Z9.91 45 Y- ~97099Z.60 N- 710ZB80.06 70~19'20.5727' J47°51'42.0~02' 2501.49 630.23 ' X, 2704X2.43 E- 4676Z6.67 46 Y- ~970B22.~3 N- 7B01828.64 70~19'18.9260' ~ 147=~1'41.3809' ~ 26~9.9~ : X- 270430.20 E- 467622.93 ~ ~ 47 ~Y- 5970992.6~ N- 7801880.42 70~19'20.~86O' ~ 147c~1'4Z.7610'~.'2~00.[4 620.32 ~ X- 270422.38 E- 467619.70 ~ 48 Y- ~970823.~B N- 7B0182~.01 70c19'18.9292' ~ 147c~1'41.0917· ~6B.~ ...... X~ 270440.~5 E~ 46762~.96 49 Y- 5970993.69 N~ 7101B80.79 70°19'20.5992' ~47°51'4~.471l' 2498.71 610.40 X- 270432.32 E- 467622.72 SO Y' ~970824.62 N' 7801829,37 70~19'~B.942~' 147~1'40.B02~' 2667.23 ~ ~87.96 X~ 2704~0.09 E' 467&28,98 .. I SDI ~OPOSED WELL LOCATION LIST ~_~ 4~ _~, LOCATED IN SEC. 8,T. liN., R.I?E. UMIATM. ~~~~~~''~--'--~~ .J S O H I O ALASKA PE TROLE U M CO. ~S- ~1f4 ./~ Dew. NO. 116-85 PREPARED BY DATE'NOV. ~I.~%..~.~ ~ F.R BELL ~ A~OC ¢~.~[SSi~~~ SHEET ~of I0 · · SCALE ' ~~~ PRUOHOE BAY OFFICE ~w~ ~Y- R.~.T. REV. O PRUDHOE BAY, ALASKA , ~HECKED BY: ,v - DRW NO. SHEET REV. 0 IIG- 135 Iof I0 PLAT OF PROPOSED WELL LOCATIONS MPI Wells Loc(Ired In Sec.56, T.l?N.~R.16E.,Umiot M. SDi Wells Locofed In Sec. 8 ,T. II N.,R.17E.,Um'~o! M. PREPARED FOR SOHIO ALASKA PETROLEUM CO. PREPAR ED BY F.R. BELL & ASSO.C. PRUDHOE BAY OFFICE PRUDHOE BAY, ALASKA DATE'- NOV. 13, 1985 SCALE: I";I MILE DRAWN BY: R.G.T. CHECKED'BY' B.E. 0000000000000 / 27 29 31 33 35 37 o o o o o o 8 ~ ~ ~.",~.,.__ ,, Z 4 6 8 I0 IZ 14 16 18 20Z2~4Z$ 0000000000000 Ze 30 3~ ~4~e 38 4o42 44 4648 ~)o 000 000000' ~ O_..F S-URV'EYOR I kearby certify that -- licereedl~ l~ractice lam Property regietered end lend surveying in the State of Iocet' For the Well ~urnbers ehOwn above. All end that el/ dimensions and details are Correct. Indieetee w,II I~di¢,tee C~l¢tla/td Sacfil~corner Indicates I~r~e~dlc~ler Offiet Distance Ind~etel Per~e.Mic~ler Offlef (~er~ndicul~ els/eKe ~eriafm each ~1) PLAT OF SDI PROPOSED WELL LOCATIONS OCaTED IN IEC. e, T, II N.~ R. I? E, UMIAT M, DRW. NO. 116-a5 SHEET 7' of Ia REV. 0 PREPAJ~ ED FOR SOHIO ALASKA PETROLEUM CO. F.R. BELL & ASSOC. PRUDHoEBAy OFFICE PRUDHOE Bay, ALASK.4 DATE: #O¥. 13, 1115 SCALE'- I". e;O' C ECK T. SZ VOR W .T. PmM S ITEM Afl, ROVE DATE . 8. (3) Admin ?2 f- · /". I%-~ (~ 9 tShru 13) 10. (10 and~ 12. 13. (4) Casg ~.~~ ~, ,~-~ (14 thru 22) Company f~/C Lease & Well No. YES NO Is the permit fee attached ......................................... ~ Is well to be located in a defined pool .................... Is well located proper distance from property iine ...... ' . Is well located proper distance from other mlls ........ o Is sufficient undedicated acreage available in this pool ' Is roll to be deviated and is wellbore plat included ....... ' Is operator the only affected party ..................... Can pemit be approved before fifteen-day wait ...................... ~_~ 14. 15. 16. 17. 18. 19. 20. 21. 22. Does operator have a bond in force .................................. Is a conservation order needed ...................................... Is administrative approval needed ................................... Is the lease number appropriate ..................................... Does the well have a unique name and number ......................... Is conductor string provided ........................................ Will surface casing protect fresh water zones ....................... Is enough cement used to circulate on conductor and surface ......... Will cement tie in surface and intermediate or production strings ... Will cement cover all known productive horizons ..................... Will all casing give adequate safety in collapse, tension and burst.. Is this well to be kicked off from an existing wellbore ............. Is old wellbore abandonment procedure included on 10-403 ............ Is adequate wellbore separation proposed .............. '. ............. (5) BOPE (23 thru 28) (6) OTIIER 'fi,/9, (29 thru 31) (6) Add: 23. 24. 25. 26. 27. 28. For 29. 30. 31. ~....~ g- l~-~r(~ 32. Is a diverter system required ....................................... Is the drilling fluid program schematic and list of equipment adequate Are necessary diagrams and descriptions of~d~_~_~-r~_nd BOPE attached. Does BOPE have sufficient pressure rating - Test to $,~e~:,/~,~:,~ psig .. Does the choke nmnifold comply w/AP1 RP-53 (May 84)... f .............. Is the presence of H2S gas probable ................................. exploratory and Stratigraphic wells: Are data presented on potential overpressure zones? ................. Are seismic analysis data presented on shallbw gas zones ............ 'If an offshore loc., are survey results of seabed conditions presented Additional requirements ............................................. Geolo~f: Fmgineering: ,, , rev: 07/18/86 6.01]. POOL INITIAL CLASS STATUS GEO. AREA UNIT , NO. ON/OFF SHORE Well History File APPENDIX Information of detailed nature that is not padiculady germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information, of this nature is accumulated at the end of the file under APPENDIX, . No special 'effort has been made to chronologically organize this category of information. * ALASKA COMPUTING CENTER * ....... SCHLUMBERGER ....... ~a.~a Oil a ~'-~ Gons, ¢ommi~io, COMPANY NAME : BP Exploration (Alaska), Inc. WELL NA~E : 3 - 23 / N -32 FIELD NAME : Endicott BOROUGH : NORTH SLOPE STATE : ALASKA API ~ER : 500292164500 REFERENCE NO : 97560 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: **** REEL HEADER **** SERVICE NAFiE : EDIT DATE : 97/12/11 ORIGIN : FLIC REEL NAME : 97560 CONTINUATION # : PREVIOUS REEL : COM~TT : BP EXPLORATION, 3-23/N-32, ENDICOTT, API# 50-029-21645-00 **** TAPE HEADER **** SERVICE NA~E : EDIT DATE : 97/12/11 ORIGIN : FLIC TAPE NACRE : 97560 CONTINUATION # : 1 PREVIOUS TAPE : COF~4ENT : BP EXPLORATION, 3-23/N-32, ENDICOTT, API# 50-029-21645-00 TAPE HEADER ENDICOTT CASED HOLE WIRELINE LOGS WELL NAi~E: 3-23/N-32 API NUMBER: 500292164500 OPERATOR: BP EXPLORATION (ALASKA) LOGGING COMPANY: SCHLUMBERGER WELL SERVICES TAPE CREATION DATE: Il-DEC-97 JOB NUMBER: 97560 LOGGING ENGINEER: D. PALFiER OPERATOR WITNESS: G. McBRIDE SURFACE LOCATION SECTION: 8 TOWNSHIP: 1 iN RANGE: 17E F1FL : 252 0 FSL : FEL: 769 FWL: ELEVATION(FT FROM MSL O) KELLY BUSHING: 55.50 DERRICK FLOOR: 54.80 GROUND LEVEL: 14.50 WELL CASING RECORD OPEN HOLE CASING DRILLERS CASING BIT SIZE (IN) SIZE (IN) DEPTH (FT) WEIGHT (LB/FT) 1ST STRING 7 . 000 12107.0 35.20 2ND STRING 3RD STRING PRODUCTION STRING CURVE SHIFT DATA - ALL PASSES TO STANDARD (M~ASURED DEPTH) LIS Tape Verification Listing Schlumberger Alaska Computing Center BASELINE CURVE FOR SHIFTS LDWG TOOL CODE: LDWG CURVE CODE: GR RUN NUMBER: PASS NUAIBER : DATE LOGGED: LOGGING COMPANY: BASELINE DEPTH .............. 88888 0 11327 5 11303 5 11295 0 11285 5 11270 0 11264 0 11257 0 11250 5 11235 0 11230 0 11218 0 11217 5 11209 5 11204 0 11190 0 11158 0 11145.5 11133.0 11091.0 11088.0 11071.0 11067.5 11057.0 11056.5 11052.5 11050.5 100.0 $ 11-DEC-1997 11:54 .......... EQUIVALENT UNSHIFTEDDEPTH .......... 88890.0 11297.0 11267.0 11253.0 11217.5 11158.0 11090.0 11070.0 11054.5 97.5 88886.5 11326.0 11303.0 11286.0 11271.5 11258.0 11236.5 11232.5 11220.5 11211.0 11205.0 11191.0 11144.0 11134.0 11091.0 11068.5 11056.0 11053.0 11051.5 101.0 This file contains the cased hole LDWG edit for BP Exploration well 3-23/N-32. There are 3 baseline passes and an average pass. The raw data is also included. The depth adjustments shown above reflect cased hole GR to open hole BCS GR and cased hole SIGM to open hole GR. All other RST curves were carried with the SIGM shifts. *** NOTE *** The extremely high gamma ray recorded in casing due to scale. This made comparison between the baseline GR and the logged GR difficult. $ $ PAGE: LIS Tape Verification Listing Schlumberger Alaska Computing Center il-DEC-1997 11:54 PAGE: **** FILE HEADER **** FILE NAME : EDIT .001 SERVICE - FLIC VERSION : O01CO1 DATE · 97/12/11 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE HEADER FILE NUMBER: 1 EDITED CURVES Depth shifted and clipped curves for each pass in separate files. PASS NO?4BER : 1 DEPTH INCREMENT: 0.5000 FILE SUMMARY LDWG TOOL CODE START DEPTH STOP DEPTH GRCH 11344.0 11049.0 RST 11344.0 11049.0 $ CURVE SHIFT DATA - PASS TO PASS (I4EASURED DEPTH) BASELINE CURVE FOR SHIFTS LDWG CURVE CODE: GR PASS NUMBER: BASELINE DEPTH $ .......... EQUIVALENT UNSHIFTED DEPTH .......... GRCH RST .............. REMARKS: This file contains RST/TDT Pass #1 (Base Pass #1). pass to pass shifts were applied to this data. $ LIS FORMAT DATA No ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 88 4 66 1 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: TYPE REPR CODE VALUE 5 66 6 73 7 65 8 68 0.5 9 65 FT 11 66 11 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 0 ** SET TYPE - CHAN ** NAM~ SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DEPT FT 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 NBAC RST CPS 1116941 00 000 O0 0 1 1 1 4 68 0000000000 FBAC RST CPS 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 SBNA FIL CU 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 SFNA FIL CU 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 SBFA FIL CU 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 SFFA FIL CU 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 TRAT FIL 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 IRAT FIL 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 CIRNFIL 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 CIRF FIL 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 BSAL RST PPK 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 SIBF RST CU 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 TPHI R2P PU-S 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 SFFC RST CU 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 SFNC RST CU 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 SIGM R2P CU 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 DSIG RST CU 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 SIBH R2P CU 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 GRCH RST GAPI 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 TENS RST LB 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 CCL RST V 1116941 O0 000 O0 0 1 1 1 4 68 0000000000 ** DATA ** DEPT. 11346.000 NBAC.RST -999.250 FBAC.RST -999.250 SBNA.FIL SFNA.FIL -999.250 SBFA.FIL -999.250 SFFA.FIL -999.250 TRAT. FIL IRAT. FIL -999.250 CIRN. FIL -999.250 CIRF. FIL -999.250 BSAL.RST SIBF. RST -999.250 TPHI.R2P -999.250 SFFC.RST -999.250 SFNC.RST SIGM. R2P -999.250 DSIG.RST -999.250 SIBH.R2P -999.250 GRCH.RST TENS.RST -999.250 CCL.RST -999.250 -999.250 -999.250 -999.250 -999.250 1108.731 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: DEPT. 11046.500 ArBAC.RST SFNA.FIL -999.250 SBFA.FIL IRAT. FIL -999.250 CIRN. FIL SIBF.RST -999.250 TPHI.R2P SIGM. R2P -999.250 DSIG.RST TENS.RST -999.250 CCL.RST -999.250 FBAC.RST -999.250 SFFA.FIL -999.250 CIRF. FIL -999.250 SFFC.RST -999.250 SIBH.R2P -999.250 -999.250 SBNA.FIL -999.250 TRAT. FIL -999.250 BSAL.RST -999.250 SFNC.RST -999.250 GRCH.RST -999.250 -999.250 -999.250 -999.250 12811.896 ** END OF DATA ** **** FILE TRAILER **** FILE NAM~ : EDIT .001 SERVICE : FLIC VERSION : O01CO1 mATE · 97/12/11 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** FILE HEADER **** FILE NAME : EDIT .002 SERVICE : FLIC VERSION : O01CO1 DATE : 97/12/11 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE HEADER FILE NUM~ER: 2 EDITED CURVES Depth shifted and clipped curves for each pass in separate files. PASS NUMBER: 2 DEPTH INCREMENT: 0.5000 FILE SUP~r~Y LDWG TOOL CODE START DEPTH STOP DEPTH GRCH 11349.0 11095.0 RST 11349.0 11095.0 $ CURVE SHIFT DATA - PASS TO PASS (MEASURED DEPTH) BASELINE CURVE FOR SHIFTS LDWG CURVE CODE: GRCH PASS NUM~ER: 1 .......... EQUIVALENT UNSHIFTEDDEPTH .......... LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: BASELINE DEPTH 88888 0 11329 0 11317 5 11302 0 11297 0 11290 5 11273 0 11270 0 11266 0 11260 5 11245 5 11231 0 11219 0 11218 5 11204 5 11203 0 11194 5 11190 5 11170 0 11164 0 11159.0 11145.5 11133.0 11130.5 11113.0 11111.0 11100.0 100.0 $ GRCH RST 88889.0 88886.5 11303.0 11292.5 11272.5 11269.0 11263.0 11247.0 11218.5 11204.5 11194.0 11163.5 11130.0 11112.5 99.5 11327.5 11316.0 11296.5 11274.0 11267.0 11246.5 11233.0 11220.5 11203.5 11191.0 11169.5 11157.5 11143.5 11134.0 11112.5 11102.5 102.5 REMARKS: This file contains RST/TDT Pass #2 (Base Pass #2). The depth shifts shown above relect GRCH Pass #2 to GRCH Pass #1 and SIGM Pass #2 to SIGM Pass #1. $ LIS FORMAT DATA ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** TYPE REPR CODE VALUE i 66 0 2 66 0 3 73 88 4 66 1 5 66 6 73 7 65 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: TYPE REPR CODE VALUE 8 68 0.5 9 65 FT 11 66 11 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 1 ** SET TYPE - CHAN ** NA~E SERVUNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DEPT FT 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 lV-BAC RST CPS 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 FBAC RST CPS 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 SBNA FIL CU 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 SFNA FIL CU 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 SBFA FIL CU 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 SFFA FIL CU 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 TRAT FIL 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 IRAT FIL 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 CIRNFIL 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 CIRF FIL 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 BSALRST PPK 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 SIBF RST CU 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 TPHI R2P PU-S 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 SFFC RST CU 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 SFNC RST CU 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 SIGM R2P CU 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 DSIG RST CU 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 SIBH R2P CU 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 GRCH RST GAPI 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 TENS RST LB 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 CCL RST V 1116941 O0 000 O0 0 2 1 1 4 68 0000000000 ** DATA ** DEPT. 11350.000 NBAC. RST -999.250 FBAC.RST -999.250 SBNA.FIL SFNA.FIL -999.250 SBFA.FIL -999.250 SFFA.FIL -999.250 TRAT.FIL IRAT. FIL -999.250 CIRN. FIL -999.250 CIRF. FIL -999.250 BSAL.RST SIBF. RST -999.250 TPHI.R2P -999.250 SFFC.RST -999.250 SFNC.RST SIGM. R2P -999.250 DSIG.RST -999.250 SIBH.R2P -999.250 GRCH.RST TENS.RST -999.250 CCL.RST -999.250 -999.250 -999.250 -999.250 -999.250 1168.843 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: DEPT. SFNA.FIL IRAT.FIL SIBF.RST SIGM. R2P TENS.RST 11094 500 -999 250 -999 250 -999 250 -999 250 -999 250 NBAC.RST SBFA.FIL CIRN. FIL TPHI.R2P DSIG.RST CCL.RST -999.250 FBAC. RST -999.250 SFFA.FIL -999.250 CIRF.FIL -999.250 SFFC.RST -999.250 SIBH.R2P -999.250 -999.250 SBNA.FIL -999.250 TRAT. FIL -999.250 BSAL.RST -999.250 SFNC.RST -999.250 GRCH. RST -999.250 -999.250 -999.250 -999.250 1356.967 ** END OF DATA ** **** FILE TRAILER **** FILE NAlViE : EDIT .002 SERVICE · FLIC VERSION : O01CO1 DATE : 97/12/11 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** FILE HEADER **** FILE NAME : EDIT .003 SERVICE · FLIC VERSION : O01CO1 DATE · 97/12/11 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE HEADER FILE NIIF1BER: 3 EDITED CURVES Depth shifted and clipped curves for each pass in separate files. PASS NUMBER: 3 DEPTH INCRE~IENT: 0.5000 FILE SUF~La~Y LDWG TOOL CODE START DEPTH STOP DEPTH GRCH 11346.0 11051.0 RST 11346.0 11051 . 0 $ CURVE SHIFT DATA - PASS TO PASS (FiEASURED DEPTH) BASELINE CURVE FOR SHIFTS LDWG CURVE CODE: GRCH PASS NUAIBER : 1 .......... EQUIVALENT UNSHIFTED DEPTH .......... BASELINE DEPTH GRCH RST LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 88888 0 11330 5 11317 0 11304 0 11297 5 11285 0 11273 5 11270 5 11264 0 11263 5 11257 0 11245 5 11229 0 11222 0 11218 5 11216.0 11203.5 11196.0 11192.5 11191.0 11179.5 11172.0 11164.0 11153.0 11145.5 11133.0 11130.0 11111.0 11100.5 11094.0 11091.0 11086.0 11083.5 11076.0 11073.0 11072.0 11060.5 11054.0 11051.0 100.0 $ 88890.0 88886.5 11329.0 11316.0 11303.0 11299.5 11287.0 11276.5 11266.5 11247.5 11218.5 11192.0 11179.5 11164.0 11129.5 11090.0 11071.0 11058.5 98.0 11285.5 11271.5 11265.0 11258.5 11246.5 11231.5 11224.5 11220.5 11218.5 11204.5 11197.5 11191.5 11172.0 11152.0 11144.0 11134.0 11113.0 11103.0 11096.5 11089.5 11086.0 11078.0 11074.0 11054.0 11052.0 101.0 ~S: This file contains RST/TDT Pass #3 (Base Pass #3). The depth shifts shown above relect GRCH Pass #3 to GRCH Pass #1 and SIGM Pass #3 to SIGM Pass #1. $ LIS FORMAT DATA LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 10 ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE- 64EB ** TYPE REPR CODE VALUE 1 2 3 4 5 66 6 73 7 65 8 68 9 65 11 66 12 68 13 66 14 65 15 66 16 66 0 66 66 0 66 0 73 88 66 1 0.5 FT 11 0 FT 68 1 1 ** SET TYPE - CHAN ** NAME SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DEPT FT 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 NBAC RST CPS 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 FBAC RST CPS 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 SBNA FIL CU 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 SFNA FIL CU 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 SBFA FIL CU 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 SFFA FIL CU 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 TRAT FIL 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 IRAT FIL 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 CIRNFIL 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 CIRF FIL 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 BSALRST PPK 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 SIBF RST CU 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 TPHI R2P PU-S 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 SFFC RST CU 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 SFNC RST CU 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 SIGM R2P CU 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 DSIG RST CU 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 SIBH R2P CU 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 GRCH RST GAPI 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 TENS RST LB 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 CCL RST V 1116941 O0 000 O0 0 3 1 1 4 68 0000000000 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 11 ** DATA ** DEPT. SFNA. FIL IRAT. FIL SIBF. RST SIGM. R2P TENS. RST 11348 000 -999 250 -999 250 -999 250 -999 250 -999 250 NBAC.RST SBFA.FIL CIRN. FIL TPHI.R2P DSIG.RST CCL.RST DEPT. 11049.000 NBAC.RST SFNA.FIL -999.250 SBFA.FIL IRAT. FIL -999.250 CIRN. FIL SIBF. RST -999.250 TPHI.R2P SIGM. R2P -999.250 DSIG.RST TENS.RST -999.250 CCL.RST -999.250 FBAC.RST -999.250 SFFA.FIL -999.250 CIRF. FIL -999.250 SFFC.RST -999.250 SIBH.R2P -999.250 -999.250 FBAC.RST -999.250 SFFA.FIL -999.250 CIRF. FIL -999.250 SFFC.RST -999.250 SIBH.R2P -999.250 -999.250 SBNA.FIL -999.250 TRAT. FIL -999.250 BSAL.RST -999.250 SFNC.RST -999.250 GRCH. RST -999.250 SBNA.FIL -999.250 TRAT. FIL -999.250 BSAL.RST -999.250 SFNC.RST -999.250 GRCH. RST -999.250 -999.250 -999.250 -999.250 1271.842 -999.250 -999.250 -999.250 -999.250 16957.789 ** END OF DATA ** **** FILE TRAILER **** FILE NAME : EDIT .003 SERVICE : FLIC VERSION . O01CO1 DATE : 97/12/11 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** FILE HEADER **** FILE NAME : EDIT .004 SERVICE : FLIC VERSION : O01CO1 DATE : 97/12/11 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE HEADER FILE NUMBER: 4 AVERAGED CURVES Pulsed Neutron: Unaveraged edited Pass 1 Gamma Ray and backround counts; arithmetic average of edited static baseline passes for all other curves. DEPTH INCREMENT 0.5000 PASSES INCLUDED IN AVERAGE LDWG TOOL CODE PASS NUMBERS RST 1, 2, 3 $ LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 12 REMARKS: The arithmetic average of passes 1, 2 & 3 was computed after all depth shifts and clipping was applied. $ LIS FORMAT DATA ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 80 4 66 1 5 66 6 73 7 65 8 68 0.5 9 65 FT 11 66 12 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 1 ** SET TYPE - CHAN ** NA~iE SERVUNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DEPT FT 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 NBAC RST CPS 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 FBAC RST CPS 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SBNA RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SFNA RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SBFA RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SFFA RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 TRAT RSAV 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 IRAT RSAV 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 CIRN RSAV 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 CIRF RSAV 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 BSALRSAV PPK 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SIBF RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 TPHI RSAV PU-S 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SFFC RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SFNC RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SIGM RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 12 REMARKS: The arithmetic average of passes 1, 2 & 3 was computed after all depth shifts and clipping was applied. $ LIS FORMAT DATA ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 8O 4 66 1 5 66 6 73 7 65 8 68 0.5 9 65 FT 11 66 12 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 1 ** SET TYPE - CHAN ** NAME SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUM~ SAMP ELE~ CODE (HEX) DEPT FT 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 NBAC RST CPS 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 FBAC RST CPS 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SBNA RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SFNA RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SBFA RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SFFA RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 TRAT RSAV 1116941 O0 - 000 O0 0 4 1 1 4 68 0000000000 IRAT RSAV 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 CIRN RSAV 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 CIRF RSAV 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 BSAL RSAV PPK 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SIBF RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 TPHI RSAV PU-S 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SFFC RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SFNC RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SIGM RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 13 NAM~ SERV UNIT SERVICE API API API API FILE NUM~ NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DSIG RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 SIBH RSAV CU 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 GRCHRST GAPI 1116941 O0 000 O0 0 4 1 1 4 68 0000000000 ** DATA ** DEPT. 11346.000 NBAC. RST -999.250 FBAC.RST -999.250 SBNA.RSAV -999.250 SFNA.RSAV -999.250 SBFA.RSAV -999.250 SFFA.RSAV -999.250 TRAT.RSAV -999.250 IRAT. RSAV -999.250 CIRN. RSAV -999.250 CIRF.RSAV -999.250 BSAL.RSAV -999.250 SIBF.RSAV -999.250 TPHI.RSAV -999.250 SFFC.RSAV -999.250 SFNC.RSAV -999.250 SIGM. RSAV -999.250 DSIG.RSAV -999.250 SIBH.RSAV -999.250 GRCH. RST 1108.731 DEPT. 11046.500 NBAC. RST -999.250 FBAC.RST -999.250 SBNA.RSAV -999.250 SFNA.RSAV -999.250 SBFA.RSAV -999.250 SFFA.RSAV -999.250 TRAT. RSAV -999.250 IRAT. RSAV -999.250 CIRN. RSAV -999.250 CIRF.RSAV -999.250 BSAL.RSAV -999.250 SIBF. RSAV -999. 250 TPHI. RSAV -999. 250 SFFC. RSAV -999. 250 SFNC. RSAV -999. 250 SIGM. RSAV -999.250 DSIG.RSAV -999.250 SIBH.RSAV -999.250 GRCH. RST 12811.896 ** END OF DATA ** **** FILE TRAILER **** FILE NAME : EDIT .004 SERVICE : FLIC VERSION : O01CO1 DATE : 97/12/11 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** FILE HEADER **** FILE NA~E : EDIT .005 SERVICE : FLIC VERSION : O01CO1 DATE : 97/12/11 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE HEADER FILE AU]FiBER 5 RAW CURVES Curves and log header data for each pass in separate files; raw background pass in last file LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 14 PASS NUFIBER: 1 DEPTH INCREMENT: 0.5000 FILE SUMMARY V~NDOR TOOL CODE START DEPTH RST 11357.5 $ LOG HEADER DATA STOP DEPTH 11001.0 DATE LOGGED '. SOFTWARE VERSION: TIME LOGGER ON BOTTOM: TD DRILLER (FT) : TD LOGGER (FT) : TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT) : LOGGING SPEED (FPHR) : DEPTH CONTROL USED (YES/NO): TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE RST RESERVOIR SATURATION RST RESERVOIR SATURATION RST RESERVOIR SATURATION $ BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLERS CASING DEPTH (FT): LOGGERS CASING DEPTH (FT) : BOREHOLE CONDITIONS FLUID TYPE: FLUID DENSITY (LB/G): SURFACE TEMPERATURE (DEGF) : BOTTOM HOLE TEMPERATURE (DEGF) : FLUID SALINITY (PPM) : FLUID LEVEL (FT) : FLUID RATE AT WELLHEAD (BPM): WATER CUTS (PCT) : GAS~OIL RATIO '. CHOKE (DEG) : NEUTRON TOOL TOOL TYPE (EPITHERMAL OR THERMAL): MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): 28-0CT-97 8B1-129 1130 28-0CT-97 11352.0 11350.0 11100.0 11340.0 1800.0 NO TOOL NUMBER ........... ~H-22 CPLT-B RST-A 12107.0 PRODUCED FLUIDS THERMAL SANDSTONE 2.65 BLUELINE COUNT RATE NORMALIZATION IN OIL ZONE TOP NORMALIZING WINDOW (FT): BASE NORMALIZING WINDOW (F~: LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 15 BLUELINE COUNT RATE SCALES SET BY FIELD ENGINEER FAR COUNT RATE LOW SCALE (CPS): FAR COUNT RATE HIGH SCALE (CPS): NEAR COUNT RATE LOW SCALE (CPS): NEAR COUNT RATE HIGH SCALE (CPS): TOOL STANDOFF (IN): REMARKS: THIS FILE CONTAINS THE RAW DATA FOR PASS #1. TIED INTO SWS CBL 18-SEP-86 WELL SHUT-IN FOR ONE YEAR PRIOR TO LOGGING 3 PASSES MADE RST USED TO GIVE TDT P EQUIVELANT LOG _ NOTE:CASING ZONED TO BE SUM OF CASING AND TUBING WEIGHT FOR CORRECT SIGMA IN 2 7/8", 3.5" AND BLAST JOING EXTREMELY HIGH RSTRECORDED IN CASING DUE TO SCALE. $ LIS FORMAT DATA ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 380 4 66 1 $ 66 6 73 7 65 8 68 0.5 9 65 FT 11 66 2 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 1 ** SET TYPE - CHAN ** NAME SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELE~ CODE (HEX) DEPT FT 1116941 O0 000 O0 0 $ 1 1 4 68 0000000000 CS PS1 F/HR 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 TENS PS1 LB 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 NPHVPS1 V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 16 NAME SERV UNIT SERVICE API API API API FILE NUM~ NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUM~ SAMP ELEM CODE (HEX) NPDE PS1 V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 NSCE PS1 V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 CRRA PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 NSCR PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 AQTMPS1 S 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 CHV PS1 V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 CPSV PS1 V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 CP2V PS1 V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 CM2V PSi V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 RCFR PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 RCLC PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 RCRC PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 RCAKPS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 RTDF PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 FPHVPS1 V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 FPDE PS1 V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 FSCE PS1 V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 FSCR PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 AQTF PS1 S 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SF6P PS1 PSIG 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 HVPV PS1 V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 BMCU PS1 UA 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 GDCU PSl MA 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 EXCU PS1 UA 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 NBEF PS1 UA 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 FBEF PS1 UA 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 NPGF PSI 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 FPGF PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 BSTR PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 BSPR PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 MARC PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 XHV PS1 V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 XPSV PS1 V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 XP2V PS1 V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 XM2V PS1 V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 RXFR PSl 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 RXLC PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 RXRC PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 RXAKPS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SHCU PS1 MA 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 BSAL PS1 PPK 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 BSAL SIG PPK 1116941 O0 000 O0 0 ·5 1 1 4 68 0000000000 CIRNPS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 CIRF PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 CIRNFIL 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 CIRF FIL 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 DSIG PS1 CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 FBAC PS1 CPS 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 IRAT PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 II{AT FIL 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 NBAC PS1 CPS 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 17 NAME SERV UNIT SERVICE API API API API FILE NUMB NUM~ SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) SFNA PSi CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SFFA PS1 CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SBNA PS1 CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SBFA PSi CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SFNA SIG CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SFFA SIG CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SBNA SIG CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SBFA SIG CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SFNA FIL CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SFFA FIL CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SBNA FIL CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SBFA FIL CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SIBF PS1 CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SFNC PS1 CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SFFC PS1 CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SIGM PS1 CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SIBF SIG CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SIGM SIG CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SIGM R2P CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 SIBH R2P CU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 TRAT PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 TRAT SIG 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 TRAT FIL 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 GR PS1 GAPI 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 RDIX PSl 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 CRNI PS1 K~Z 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 CRFI PS1 KHZ 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 RSCS PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 CTM PS1 DEGC 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 XTM PS1 DEGC 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 TAV PS1 KV 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 FICU PS1 AMP 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 CACU PS1 AMP 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 BUST PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 BUSP PS1 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 RSXS PSI 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 TPHI PS1 PU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 TPHI SIG PU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 TPHI R2P PU 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 CCLC PS1 V 1116941 O0 000 O0 0 5 1 1 4 68 0000000000 ** DATA ** DEPT. 11355.000 CS.PS1 918.395 TENS.PS1 1394.000 NPHV. PS1 NPDE. PS1 1558.419 NSCE. PS1 2.326 CRRA.PS1 2.054 NSCR.PS1 AQTM. PS1 0.661 CHV. PS1 202.792 CPSV. PSl 5.060 CP2V. PS1 C~2V. PS1 -12.231 RCFR.PS1 0.000 RCLC. PS1 0.000 RCRC. PS1 RCAK. PS1 0.000 RTDF.PS1 0.000 FPHV. PS1 1535.646 FPDE. PS1 FSCE. PS1 1.830 FSCR.PS1 0.168 AQTF. PS1 0.661 SF6P. PS1 1569.825 0.322 12.187 0.000 1508.637 178.474 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 18 HVPV. PS1 NBEF. PS1 BSTR. PS1 XP5V. PS1 RXLC. PS1 BSAL. PS1 CIRN. FIL IRAT. PS1 SFFA. PSl SFFA. SIG SFFA. FIL SFNC. PS1 SIGM. SIG TRAT. SIG CRNI. PS1 XTM. PS1 BUST. PS1 TPHI. SIG 160.889 28.394 12.966 5.060 0 000 -999 250 -999 250 -999 250 -999 250 -999 250 -999 250 -999.250 -999.250 -999.250 452.516 101.074 0.000 -999.250 BMCU. PS1 FBEF. PS1 BSPR.PS1 XP2V. PS1 RXRC. PS1 BSAL.SIG CIRF. FIL IRAT. FIL SBNA.PS1 SBNA.SIG SBNA.FIL SFFC. PS1 SIGM. R2P TRAT. FIL CRFI.PS1 TAV. PS1 BUSP. PS1 TPHI.R2P DEPT. 11040.000 CS.PS1 NPDE. PS1 1561.204 NSCE.PS1 AQTM. PS1 1.763 CHV. PS1 CM2V. PS1 -12.178 RCFR.PS1 RCAK. PS1 0.000 RTDF. PS1 FSCE. PS1 1.958 FSCR.PS1 HVPV. PS1 160.931 BMCU. PS1 NBEF. PS1 27.444 FBEF. PS1 BSTR.PS1 14.017 BSPR.PS1 XPSV. PS1 5.052 XP2V. PS1 PC&LC.PSi 0.000 RXRC. PS1 BSAL.PS1 74.373 BSAL.SIG CIRN. FIL 0.590 CIRF. FIL IRAT. PS1 0.445 IRAT. FIL SFFA.PSl 22.428 SBNA.PS1 SFFA.SIG 0.862 SBNA.SIG SFFA.FIL 20.355 SBNA.FIL SFNC.PS1 21.126 SFFC. PS1 SIGM. SIG 0.496 SIGM. R2P TRAT. SIG 0.016 TRAT. FIL CRNI.PS1 445.098 CRFI.PS1 XTM. PS1 100.889 TAV. PS1 BUST.PSi 0.000 BUSP. PS1 TPHI.SIG 0.623 TPHI.R2P 32.812 GDCU. PSl 58.329 NPGF. PS1 1.202 MARC. PSi 12.085 J~42V. PS1 0.000 RXAK. PS1 -999.250 CIRN. PS1 -999.250 DSIG.PS1 -999.250 NBAC. PS1 -999.250 SBFA.PS1 -999.250 SBFA.SIG -999.250 SBFA.FIL -999.250 SIGM. PS1 -999.250 SIBH.R2P -999.250 GR.PS1 220.284 RSCS.PS1 94.744 FICU. PS1 0.000 RSXS.PS1 -999.250 CCLC. PS1 908.052 2 509 202 550 0 000 0 000 0 095 31 570 60 234 1.136 12.066 0.000 1.806 1.608 0.446 60.440 2.529 61.150 17.808 17.014 0.830 202.795 95.002 0.000 22.900 TENS.PSi CRRA.PS1 CP5V. PS1 RCLC. PS1 FPHV. PS1 AQTF. PS1 GDCU. PS1 NPGF. PS1 MARC. PSI XM2V. PS1 RXAK. PS1 CIRN. PS1 DSIG. PS1 NBAC. PS1 SBFA.PS1 SBFA.SIG SBFA.FIL SIGM. PS1 SIBH. R2P GR.PSl RSCS.PS1 FICU. PS1 RSXS.PS1 CCLC. PS1 59.028 0.998 0.000 -12.250 0.000 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 1108.731 8459.000 2.285 8878.000 0.005 1599.000 2.195 5.066 0.000 1536.459 1. 763 59. 887 1. 017 0.000 -12.249 1.000 0.554 1.888 5907.375 51.499 3.619 51.566 17.831 75.278 635.948 8463.000 2.288 8878.000 0.001 EXCU. PS1 FPGF. PS1 XHV. PSl RXFR.PS1 SHCU. PS1 CIRF. PS1 FBAC. PS1 SFNA.PS1 SFNA.SIG SFNA.FIL $IBF. PS1 SIBF. SIG TRAT. PS1 RDIX. PS1 CTM. PS1 CACU. PS1 TPHI.PS1 NPHV. PS1 NSCR.PS1 CP2V. PS1 RCRC. PS1 FPDE.PS1 SF6P.PS1 EXCU. PS1 FPGF. PS1 XHV. PS1 RXFR.PS1 SHCU. PS1 CIRF. PS1 FBAC. PS1 SFNA.PS1 SFNA.SIG SFNA.FIL SIBF. PS1 SIBF. SIG TRAT. PS1 RDIX. PS1 CTM. PS1 CACU. PSi TPHI.PS1 4 734 1 006 201 581 0 000 58 535 -999 250 -999 250 -999 250 -999.250 -999.250 -999.250 -999.250 -999.250 8820.000 104.004 2.554 -999.250 1573.895 -0.002 12.212 0.000 1513.711 181.579 4.530 1.020 201.531 0.000 44.844 1.488 24389.301 29.338 0.711 26.950 48.748 0 674 0 830 27066 000 101 563 2 543 18 238 ** END OF DATA ** LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 19 **** FILE TRAILER **** FILE NAM~ : EDIT .005 SERVICE : FLIC VERSION : O01CO1 DATE : 97/12/11 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** FILE HEADER **** FILE NAME : EDIT .006 SERVICE : FLIC VERSION : O01CO1 DATE : 97/12/11 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE HEADER FILE~ER 6 RAW CURVES Curves and log header data for each pass in separate files; raw background pass in last file PASS NUMBER: 2 DEPTH INCREMF2F~: 0.5000 FILE StC4M_ARY VENDOR TOOL CODE START DEPTH RST $ LOG HEADER DATA DATE LOGGED: 113612.5 SOFTWARE VERSION: TIldE LOGGER ON BOTTOM: TD DRILLER (FT) : TD LOGGER (FT) : TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT) : LOGGING SPEED (FPHR): DEPTH CONTROL USED (YES/NO): STOP DEPTH 11060.0 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE RST RESERVOIR SATURATION RST RESERVOIR SATURATION RST RESERVOIR SATURATION $ BOREHOLE AND CASING DATA 28-0CT-97 8B1-129 1130 28-0CT-97 11352.0 11350.0 11100.0 11340.0 1800.0 NO TOOL NUMBER ........... FiH-22 CPLT-B RST-A LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 2O OPEN HOLE BIT SIZE (IN): DRILLERS CASING DEPTH (FT): LOGGERS CASING DEPTH (FT): 12107.0 BOREHOLE CONDITIONS FLUID TYPE: FLUID DENSITY (LB/G): SURFACE TEMPERATURE (DEGF) : BOTTOM HOLE TEMPERATURE (DEGF) : FLUID SALINITY (PPM) : FLUID LEVEL (FT) : FLUID RATE AT WELLHEAD (BPM) : WATER CUTS (PCT) : GAS~OIL RATIO: CHOKE (DEG) : PRODUCED FLUIDS NEUTRON TOOL TOOL TYPE (EPITHERMAL OR THERMAL): MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): THERMAL SANDSTONE 2.65 BLUELINE COUNT RATE NORMALIZATION IN OIL ZONE TOP NORMALIZING WINDOW (FT): BASE NORMALIZING WINDOW (FT): BLUELINE COUNT RATE SCALES SET BY FIELD ENGINEER FAR COUNT RATE LOW SCALE (CPS): FAR COUNT RATE HIGH SCALE (CPS): NEJh~ COUNT RATE LOW SCALE (CPS): NEAR COUNT RATE HIGH SCALE (CPS) : TOOL STANDOFF (IN): REMARKS: THIS FILE CONTAINS THE RAW DATA FOR PASS #2. TIED INTO SWS CBL 18-SEP-86 WELL SHUT-IN FOR ONE YEAR PRIOR TO LOGGING 3 PASSES MADE RST USED TO GIVE TDT P EQUIVELANT LOG NOTE:CASING ZONED TO BE SUM OF CASING AND TUBING WEIGHT FOR CORRECT SIGMA IN 2 7/8", 3.5" AND BLAST JOING EXTREMELY HIGH RSTRECORDED IN CASING DUE TO SCALE. $ LIS FORMAT DATA LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 21 ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 380 4 66 1 5 66 6 73 7 65 8 68 0.5 9 65 FT 11 66 2 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 1 ** SET TYPE - CHAN ** NA~E SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DEPT FT 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 CS PS2F/HR 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 TENS PS2 LB 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 NPHVPS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 NPDE PS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 NSCE PS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 CRRA PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 NSCR PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 AQTMPS2 S 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 CHV PS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 CP5V PS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 CP2V PS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 CM2V PS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 RCFR PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 RCLC PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 RCRC PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 RCAKPS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 RTDF PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 FPHVPS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 FPDE PS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 FSCE PS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 FSCR PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 AQTF PS2 S 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SF6P PS2 PSIG 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 HVPV PS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 BMCU PS2 UA 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 22 NAME SERVUNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELE~ CODE (HEX) GDCU PS2 MA 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 EXCU PS2 UA 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 NBEF PS2 UA 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 FBEF PS2 UA 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 NPGF PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 FPGF PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 BSTR PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 BSPR PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 MARC PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 XHV PS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 XPSV PS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 XP2V PS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 X~2V PS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 RXFR PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 RXLC PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 R32RC PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 RXAKPS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SHCU PS2 MA 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 BSAL PS2 PPK 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 BSAL SIG PPK 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 CIRNPS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 CIRF PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 CIRNFIL 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 CIRF FIL 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 DSIG PS2 CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 FBAC PS2 CPS 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 IRAT PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 IRAT FIL 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 NBAC PS2 CPS 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SFNA PS2 CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SFFA PS2 CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SBNA PS2 CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SBFA PS2 CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SFNA SIG CU 1116941 O0 000 O0 0 6 i 1 4 68 0000000000 SFFA SIG CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SBNA SIG CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SBFA SIG CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SFlVAFIL CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SFFA FIL CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SBNA FIL CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SBFA FIL CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SIBF PS2 CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SFNC PS2 CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SFFC PS2 CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SIGM PS2 CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SIBF SIG CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SIGM SIG CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SIGM R2P CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 SIBH R2P CU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 TRAT PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 TRAT SIG 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 23 NAME SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) TRAT FIL 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 GR PS2 GAPI 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 RDIX PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 CRNI PS2 KHZ 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 CRFI PS2 KHZ 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 RSCS PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 CTM PS2 DEGC 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 XTM PS2 DEGC 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 TAV PS2 KV 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 FICU PS2 AMP 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 CACU PS2 AMP 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 BUST PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 BUSP PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 RSXS PS2 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 TPHI PS2 PU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 TPHI SIG PU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 TPHI R2P PU 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 CCLC PS2 V 1116941 O0 000 O0 0 6 1 1 4 68 0000000000 ** DATA ** DEPT. NPDE.PS2 AQTM. PS2 CM2V. PS2 RCAK.PS2 FSCE. PS2 HVPV. PS2 NBEF. PS2 BSTR.PS2 XPSV. PS2 RXLC. PS2 BSAL.PS2 CIRN. FIL IRAT. PS2 SFFA.PS2 SFFA.SIG SFFA.FIL SFNC.PS2 SIGM. SIG TRAT. SIG CRNI.PS2 XTM. PS2 BUST. PS2 TPHI.SIG 11355.000 1562.768 0.661 -12.093 2.000 1.944 160.645 28.627 12.156 5.050 0.000 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999 250 -999 250 459 147 101 074 0 000 -999 250 CS.PS2 885.016 TENS.PS2 1356.000 NPHV. PS2 NSCE. PS2 2.518 CRRA.PS2 2.044 NSCR.PS2 CHV. PS2 202.792 CPSV. PS2 5.069 CP2V. PS2 RCFR.PS2 0.000 RCLC. PS2 0.000 RCRC. PS2 RTDF. PS2 0.000 FPHV. PS2 1518.556 FPDE. PS2 FSCR.PS2 -0.019 AQTF. PS2 0.661 SF6P. PS2 BMCU. PS2 33.398 GDCU. PS2 60.012 EXCU. PS2 FBEF. PS2 58.507 NPGF. PS2 0.998 FPGF. PS2 BSPR.PS2 1.144 MARC. PS2 0.000 XHV. PS2 XP2V. PS2 12.056 XM2V. PS2 -12.231 RXFR.PS2 RXRC. PS2 0.000 R3fAK. PS2 0.000 SHCU. PS2 BSAL.SIG -999.250 CIRN. PS2 -999.250 CIRF. PS2 CIRF. FIL -999.250 DSIG.PS2 -999.250 FBAC. PS2 IRAT. FIL -999.250 NBAC. PS2 -999.250 SFNA.PS2 SBNA.PS2 -999.250 SBFA.PS2 -999.250 SFNA.SIG SBNA.SIG -999.250 SBFA.SIG -999.250 SFNA.FIL SBNA.FIL -999.250 SBFA.FIL -999.250 SIBF. PS2 SFFC.PS2 -999.250 SIGM. PS2 -999.250 SIBF. SIG SIGM. R2P -999.250 SIBH.R2P -999.250 TRAT. PS2 TRAT. FIL -999.250 GR.PS2 1168.843 RDIX. PS2 CRFI.PS2 224.661 RSCS.PS2 8463.000 CTM. PS2 TAV. PS2 95.031 FICU. PS2 2.300 CACU. PS2 BUSP. PS2 0.000 RSXS.PS2 8878.000 TPHI.PS2 TPHI.R2P -999.250 CCLC. PS2 0.000 1574.708 0.065 12.217 0.000 1511.537 181.800 4.340 1.008 201.581 0.000 41.950 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 31881.000 102.051 2.554 -999.250 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 24 DEPT. 11060.000 CS.PS2 NPDE. PS2 1561.814 NSCE. PS2 AQTM. PS2 2.424 CHV. PS2 CM2V. PS2 -12.186 RCFR.PS2 RCAK. PS2 1.000 RTDF.PS2 FSCE. PS2 1.960 FSCR.PS2 HVPV. PS2 160.986 BMCU. PS2 NBEF.PS2 27.873 FBEF. PS2 BSTR.PS2 13.233 BSPR.PS2 XPSV. PS2 5.053 XP2V. PS2 RXLC. PS2 0.000 RXRC. PS2 BSAL.PS2 166.988 BSAL.SIG CIRN. FIL 0.325 CIRF. FIL IRAT. PS2 0.316 IRAT. FIL SFFA.PS2 22.980 SBNA.PS2 SFFA.SIG 0.644 SBNA.SIG SFFA.FIL 22.620 SBNA.FIL SFNC. PS2 24.322 SFFC. PS2 SIGM. SIG 0.441 SIGM. R2P TRAT. SIG 0.017 TRAT.FIL CRNI.PS2 458.798 CRFI.PS2 XTM. PS2 100.993 TAV. PS2 BUST. PS2 0.000 BUSP. PS2 TPHI.SIG 0.727 TPHI.R2P 905.131 2 515 202 732 0 000 0 000 0 074 32 373 63 771 1 120 12 067 0.000 8.203 1.363 0.320 82.304 2.689 82.947 20.752 19.806 0.820 200.531 94.988 0.000 25.420 TENS. PS2 CRRA.PS2 CPSV. PS2 RCLC. PS2 FPHV. PS2 AQTF. PS2 GDCU. PS2 NPGF. PS2 MARC. PS2 X~2V. PS2 RXAK. PS2 CIRN. PS2 DSIG.PS2 NBAC. PS2 SBFA.PS2 SBFA.SIG SBFA.FIL SIGM. PS2 SIBH. R2P GR.PS2 RSCS.PS2 FICU. PS2 RSXS.PS2 CCLC. PS2 1575.000 2.288 5.055 0.000 1524.659 2.424 60.121 1.005 0.000 -12.235 0.000 0.315 2. 466 2661. 989 74.584 4.043 70.023 20 516 111 001 15057 188 8463 000 2 299 8878 000 -999 250 NPHV. PS2 NSCR.PS2 CP2V. PS2 RCRC. PS2 FPDE. PS2 SF6P. PS2 EXCU. PS2 FPGF. PS2 XHV. PS2 RXFR.PS2 SHCU. PS2 CIRF. PS2 FBAC. PS2 SFNA.PS2 SFNA.SIG SFNA.FIL $IBF. PS2 SIBF. SIG TRAT. PS2 RDIX. PS2 CTM. PS2 CACU. PS2 TPHI.PS2 1573.488 -0. 068 12.180 O. 000 1511.460 183.514 4.313 0.996 201.573 0.000 44.790 1.240 4458.288 28. 035 O. 787 28. 612 85.354 3 442 0 788 48877 000 101 685 2 543 20 400 ** END OF DATA ** **** FILE TRAILER **** FILE NA~IE : EDIT .006 SERVICE : FLIC VERSION : O01CO1 DATE : 97/12/11 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** FILE HEADER **** FILE NAME : EDIT .007 SERVICE : FLIC VERSION : O01CO1 DATE : 97/12/11 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : FILE HEADER FILE NOMBER RAW CURVES LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 25 Curves and log header data for each pass in separate files; raw background pass in last file PASS NUMBER: 3 DEPTH INCREMF29T: 0.5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH RST $ LOG HEADER DATA DATE LOGGED: 11359.5 SOFTWARE VERSION: TIME LOGGER ON BOTTOM: TD DRILLER (FT) : TD LOGGER (FT) : TOP LOG INTERVAL (FT) : BOTTOM LOG INTERVAL (FT) : LOGGING SPEED (FPHR) : DEPTH CONTROL USED (YES/NO): STOP DEPTH .......... 11016.5 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE RST RESERVOIR SATURATION RST RESERVOIR SATURATION RST RESERVOIR SATURATION $ BOREHOLEAND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLERS CASING DEPTH (FT): LOGGERS CASING DEPTH (FT): BOREHOLE CONDITIONS FLUID TYPE: FLUID DENSITY (LB/G): SURFACE TEMPERATURE (DEGF) : BOTTOM HOLE TEMPERATURE (DEGF) : FLUID SALINITY (PPM) : FLUID LEVEL (FT) : FLUID RATE AT WELLH~ (BPM) : WATER CUTS (PCT) : GAS~OIL RATIO: CHOKE (DEG) : NEUTRON TOOL TOOL TYPE (EPITHERMAL OR THERMAL): MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): 28-0CT-97 8B1-129 1130 28-0CT-97 11352.0 11350.0 11100.0 11340.0 1800.0 NO TOOL NUMBER CPLT-B RST-A 12107.0 PRODUCED FLUIDS THERMAL SANDSTONE 2.65 BLUELINE COUNT RATE NORMALIZATION IN OIL ZONE TOP NORMALIZING WINDOW (FT) '. BASE NORMALIZING WINDOW (FT): LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 26 BLUELINE COUNT RATE SCALES SET BY FIELD ENGINEER FAR COUNT RATE LOW SCALE (CPS): FAR COUNT RATE HIGH SCALE (CPS): NEAR COUNT RATE LOW SCALE (CPS): NEAR COUNT RATE HIGH SCALE (CPS): TOOL STANDOFF (IN): REMARKS: THIS FILE CONTAINS THE RAW DATA FOR PASS #3. TIED INTO SWS CBL 18-SEP-86 WELL SHUT-IN FOR ONE YEAR PRIOR TO LOGGING 3 PASSES MADE RST USED TO GIVE TDT P EQUIVELANT LOG _ NOTE:CASING ZONED TO BE SUM OF CASING AND TUBING WEIGHT FOR CORRECT SIGMA IN 2 7/8", 3.5" AND BLAST JOING EXTREMELY HIGH RSTRECORDED IN CASING DUE TO SCALE. $ LIS FORMAT DATA ** DATA FORMAT SPECIFICATION RECORD ** ** SET TYPE - 64EB ** TYPE REPR CODE VALUE 1 66 0 2 66 0 3 73 380 4 66 1 5 66 6 73 7 65 8 68 O. 5 9 65 FT 11 66 2 12 68 13 66 0 14 65 FT 15 66 68 16 66 1 0 66 1 ** SET TYPE - CHAN ** NAME SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP ELEM CODE (HEX) DEPT FT 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 CS PS3 F/HR 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 TENS PS3 LB 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 27 NAFiE SERV UNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP EL~4 CODE (HEX) NPHVPS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 NPDE PS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 NSCE PS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 CRRA PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 NSCR PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 AQTMPS3 S 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 CHV PS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 CPSV PS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 CP2V PS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 CM2V PS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 RCFR PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 RCLC PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 RCRC PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 RCAKPS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 RTDF PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 FPHVPS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 FPDE PS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 FSCE PS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 FSCR PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 AQTF PS3 S 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SF6P PS3 PSIG 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 HVPV PS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 BMCUPS3 UA 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 GDCU PS3 MA 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 EXCU PS3 UA 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 NBEF PS3 UA 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 FBEF PS3 UA 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 NPGF PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 FPGF PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 BSTR PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 BSPR PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 MARC PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 3C~V PS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 XPSV PS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 XP2V PS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 ~2V PS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 RXFR PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 RXLC PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 RXRC PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 RXAKPS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SHCU PS3 MA 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 BSAL PS3 PPK 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 BSAL $IG PPK 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 CIRNPS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 CIRF PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 CIRNFIL 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 CIRFFIL 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 DSIG PS3 CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 FBAC PS3 CPS 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 IRAT PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 IRAT FIL 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 28 NA~E SERVUNIT SERVICE API API API API FILE NUMB NUMB SIZE REPR PROCESS ID ORDER # LOG TYPE CLASS MOD NUMB SAMP EL~4 CODE (HEX) NBAC PS3 CPS 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SFNA PS3 CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SFFA PS3 CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SBNA PS3 CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SBFA PS3 CU 1116941 O0 000 00 0 7 1 1 4 68 0000000000 SFNA SIG CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SFFA SIG CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SBNA SIG CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SBFA SIG CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SFNA FIL CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SFFA FIL CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SBNA FIL CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SBFA FIL CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SIBF PS3 CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SFNC PS3 CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SFFC PS3 CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SIGM PS3 CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SIBF SIG CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SIGM SIG CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SIGM R2P CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 SIBH R2P CU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 TRAT PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 TRAT SIG 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 TRAT FIL 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 GR PS3 GAPI 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 RDIX PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 CRNI PS3 KHZ 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 CRFI PS3 tfHZ 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 RSCS PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 CTM PS3 DEGC 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 XTM PS3 DEGC 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 TAV PS3 KV 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 FICU PS3 AMP 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 CACU PS3 AMP 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 BUST PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 BUSP PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 RSXS PS3 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 TPHI PS3 PU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 TPHI SIG PU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 TPHI R2P PU 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 CCLC PS3 V 1116941 O0 000 O0 0 7 1 1 4 68 0000000000 ** DATA ** DEPT. 11355.000 CS.PS3 879.293 TENS.PS3 1386.000 NPBV. PS3 NPDE.PS3 1561.929 NSCE. PS3 2.523 CRRA.PS3 2.011 NSCR.PS3 AQTM. PS3 0.661 CHV. PS3 202.792 CP5V. PS3 5.060 CP2V. PS3 CM2V. PS3 -12.211 RCFR.PS3 0.000 RCLC. PS3 0.000 RCRC.PS3 RCAK. PS3 0.000 RTDF. PS3 0.000 FPHV. PS3 1533.204 FPDE. PS3 1574.708 -0.082 12.217 0.000 1512.567 LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 29 FSCE. PS3 1.956 FSCR.PS3 HVPV. PS3 160.889 BMCU. PS3 NBEF. PS3 29.455 FBEF. PS3 BSTR. PS3 12.083 BSPR.PS3 XPSV. PS3 5.050 XP2V. PS3 RXLC. PS3 0.000 RXRC. PS3 BSAL.PS3 -999.250 BSAL.SIG CIRN. FIL -999.250 CIRF.FIL IRAT. PS3 -999.250 IRAT. FIL SFFA.PS3 -999.250 SBNA.PS3 SFFA.SIG -999.250 SBNA.SIG SFFA.FIL -999.250 SBNA.FIL SFNC.PS3 -999.250 SFFC. PS3 SIGM. SIG -999.250 SIGM. R2P TRAT. SIG -999.250 TRAT. FIL CRNI.PS3 462.490 CRFI.PS3 XTM. PS3 101.074 TAV. PS3 BUST. PS3 0.000 BUSP. PS3 TPHI.SIG -999.250 TPHI.R2P DEPT. 11040.000 CS. PS3 NPDE. PS3 1563.722 NSCE. PS3 AQTM. PS3 1.983 CHV. PS3 CM2V. PS3 -12.198 RCFR.PS3 RCAK. PS3 2.000 RTDF. PS3 FSCE. PS3 1.953 FSCR.PS3 HVPV. PS3 160.990 BMCU. PS3 NBEF. PS3 27.893 FBEF. PS3 BSTR.PS3 12.976 BSPR.PS3 XPSV. PS3 5.053 XP2V. PS3 RXLC. PS3 0.000 RXRC. PS3 BSAL.PS3 74.038 BSAL.SIG CIRN. FIL 0.768 CIRF. FIL IRAT. PS3 0.435 IRAT. FIL SFFA.PS3 15.380 SBNA.PS3 SFFA.SIG 0.397 SBNA.SIG SFFA.FIL 16.692 SBNA.FIL SFNC.PS3 14.425 SFFC.PS3 SIGM. SIG 0.393 SIGM. R2P TRAT. SIG 0.014 TRAT.FIL CRNI.PS3 441.943 CRFI.PS3 XTM. PS3 101.024 TAV. PS3 BUST. PS3 0.000 BUSP.PS3 TPHI.SIG 0.570 TPHI.R2P -0.036 AQTF. PS3 33.691 GDCU. PS3 59.225 NPGF. PS3 1.101 MARC. PS3 12.100 ~M2V. PS3 0.000 RXAK. PS3 -999.250 CIRN. PS3 -999.250 DSIG.PS3 -999.250 NBAC. PS3 -999.250 SBFA.PS3 -999.250 SBFA.SIG -999.250 SBFA.FIL -999.250 SIGM. PS3 -999.250 SIBH.R2P -999.250 GR.PS3 230.017 RSCS.PS3 95.031 FICU. PS3 0.000 RSXS.PS3 -999.250 CCLC. PS3 912.314 TENS.PS3 2.517 CRRA.PS3 202.712 CPSV. PS3 0.000 RCLC. PS3 0.000 FPHV. PS3 0.140 AQTF. PS3 31.792 GDCU. PS3 60.709 NPGF. PS3 1.199 MARC. PS3 12.068 2~$2V. PS3 0.000 RXAK. PS3 1.829 CIRN. PS3 2.084 DSIG.PS3 0.438 NBAC. PS3 55.533 SBFA.PS3 2.497 SBFA.SIG 60.842 SBFA.FIL 14.278 SIGM. PS3 13.633 SIBH.R2P 0.837 GR.PS3 203.048 RSCS.PS3 95.002 FICU. PS3 0.000 RSXS.PS3 22.927 CCLC. PS3 0.661 59.684 1.005 0.000 -12.250 0.000 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 -999.250 1271.842 8459.000 2.314 8878.000 0.000 1540.000 2.177 5.060 0.000 1531.577 1.763 60.159 1.004 0.000 -12.229 1.000 0.783 2.308 6133. 463 47. 657 3.860 52.289 14.164 74.707 635.723 8463.000 2.289 8878.00O -0.009 SF6P. PS3 EXCU. PS3 FPGF. PS3 XHV. PS3 RXFR.PS3 SHCU. PS3 CIRF. PS3 FBAC.PS3 SFNA.PS3 SFNA.SIG SFNA.FIL SIBF. PS3 SIBF. SIG TRAT. PS3 RDIX.PS3 CTM. PS3 CACU. PS3 TPHI.PS3 NPHV. PS3 NSCR.PS3 CP2V. PS3 RCRC. PS3 FPDE. PS3 SF6P.PS3 EXCU. PS3 FPGF. PS3 XHV. PS3 RXFR.PS3 SHCU. PS3 CIRF. PS3 FBAC. PS3 SFNA.PS3 SFNA.SIG SFNA.FIL SIBF. PS3 SIBF. SIG TRAT. PS3 RDIX. PS3 CTM. PS3 CACU. PS3 TPHI.PS3 183. 591 3.156 1. 011 201. 581 O. 000 42. 926 - 999. 250 -999.250 -999. 250 - 999. 250 -999.250 -999.250 -999.250 - 999. 250 52269. 000 1 O1. 563 2.549 -999.250 1574. 708 -0.105 12.217 O. 000 1514. 665 184. 685 4. 489 1. 013 201 ~ 573 O. 000 46. 055 2.201 26029. 848 18. 469 0.379 19.289 48. 622 O. 683 O. 847 70779. 000 102. 051 2.547 19.310 ** END OF DATA ** LIS Tape Verification Listing Schlumberger Alaska Computing Center 11-DEC-1997 11:54 PAGE: 30 **** FILE TRAILER **** FILE NAM~ : EDIT .007 SERVICE : FLIC VERSION : O01CO1 DATE : 97/12/11 MAX REC SIZE : 1024 FILE TYPE : LO LAST FILE : **** TAPE TRAILER **** SERVICE NAME : EDIT DATE : 97/12/11 ORIGIN : FLIC TAPE NAM~ : 97560 CONTINUATION # : 1 PREVIOUS TAPE : COMmeNT : BP EXPLORATION, 3-23/N-32, ENDICOTT, API# 50-029-21645-00 **** REEL TRAILER **** SERVICE NAM~ : EDIT DATE : 97/12/11 ORIGIN : FLIC REEL NAM~ : 97560 CONTINUATION # : PREVIOUS REEL : COf~4FJ~T : BP EXPLORATION, 3-23/N-32, ENDICOTT, API# 50-029-21645-00 MI.CI OFIL E D LI'S TA?E VER'IFiCATION L'iST!NG RECEIVED OCT 2 0 1986 Oil & Gas Cons. Oommission ,VP OlO.M02 Vc-RiFICAT'r~''..~.~,~ LiST.~"NG PAGE, 1 ;..= R V lC E NAM= :'_:DIT )ATE :861101 3 ~RI,GiN : ',EEL NAME :142675 'ONTiNUATirJN ~ :01 'OMM~NTS :LIBRARY T~P~ .-,. TAP HEft,DER ...... ;ERVICE NAME :EDIT )ATE ::36110/ 3 )RIGiN :0000 'APE NAME :1703 :O'NTZNUATIDN :~¢ :01 ~REVZOUS TAPE : ;0M~4~NT$ :LIBRARY TAP ,--,. FILr-. .HcAOFR_ -,--,- :ILE NAME :EDIT .00! ~ERVi":,,.,,_ NAME .' tERSION # : )ATE : 4AXiMUM LENGTH : 1024 :ILE TYPE : =REVIOUS FILE : ',--,- iNFORMATiON RECORDS '""' ~NEM CONTENTS UNIT TYPE CATE SIZE CODE CN : STANDARD ALASKA,PRODUCTION Cn~,~, 000 000 030 065 NN : 3-23/N-32 SDI 000 000 014 065 FN : ENDICOTT 000 000 008 065 RANG: 17E 000 000 004 055 TOWN: lin coo 0o0 004 065 SECT: 8 000 000 002 065 COUN: NORTH qL~'" ~ ~P~ 000 000 012 065 STAT: ALASKA 000 gO0 006 065 CTRY: USA 000 000 003 065 MNEM CONTENTS UNLIT TY~ CATE qi= , ~ =E CODE PRES: E 000 000 001 065 .,-.,- COMMENTS-,- tO8 NUMBER AT '2CC: 71703 ,'UN ~,$N,=~ DAT~ Ln"GEO"~'-..',', · ~'~,.~ SEP. 8,5 · DP: T HALSTEA"" ;&SING 'YPE F'LUi 3 )ENSiT'f ~ISCOSZT,f ~H ;LUiD LOSS '!AT RI X. SANDS T3NF:~: : 9.525" ? 10933' - BIT SiZE : 8.5" TD 11783' : GENERIC 2 = IO.C LS/G R~ = 1.150 ~ 65 DF = 4~.0 S RMF = 0.482 ~ 65 OF = it.0 RMC = 0.713 ~ 65 P~ = 5.8 C3 RM .g'T ~HT = 0.406 ,B 197 O~ 40TE ::~;= iN ORDER TO :GIVE THE BEST SE'T DF LOG 'DATA PDSSi~LE~ TH~ REPEAT FiL~ DATA ON THE 9LL/LDT/NGT FROM 11240.0 - 11!80.0 WAS SPLICED iNTO TH ~,. ,~SS ~EC~U~,~ 0= ~ LARGE PULL. THE ,~U~LiTY OF THE GGR'S~ CGR'S AND SP FROM THE MAiN PASS WeRE VER,f GOOD AND NO REPEAT DATA .VP OIO.H02 VERi~ICATIO~ LISTIN~ PAGE 3 NAS SPLICED iNTO T~E~!. THE SDT DATA ~,~S NCT SPLICED --TOTAL MaIN PASS USED. -' :x ::= -,--,- THIS DATA H.&S~:EEN DF-PTH SHTFT;D~. _ - DOES N3T iSV:RLAYS.. ,;I;LD. PR'NTS..~ -,-'" ~' "' ~:= '".- -,- ~- --,.-,-.,--,- ~LL D~TA 4AS D~PTq.. SHi~T:D_ TC~ THE DUAL LATERLOG, . ::: SCHLUMBERGER LOGS INCLUDED Wi'TM TulS MAGNETIC ::~ DUAL ~TERLJS (DLL) -'- ATA ~VAiLA~L~: 11792' TO 10934' .,.-'- ~RRAY .SONZC LOG (SnT)~ -'- " 11780' T.D 10934 -~- ,. uATA AVAILABLE: ' "'.,. LITHO DENSITY COMPENSAT:3_ LOG (LDT) -,-"' :;~ COMPENSA'T~D NEUTRON L~G (LDT) -'- ~=ATA AVAILABLE' 11972' TC 10934' :~ NATURAL GAMMA TOOL (NGT) ~;~ DATh AVAILabLE: 11732' T~ 10'934' YP OlO.~OZ V~IFICATION LISTING P~GE '¢ DATA FORMAT 'NTRY ~ L. OC K.S RECORD TYP -' 0 )A'TUM S PE ~NEM SERV ID )EFT ~GR LOT ~GR LOT :ALi LOT ~HLI5 LOT )RHO LOT gRAT LDT ~NRA LOT qPHI LDT }PHl LOT ~EF LDT ~CNL LOT :CNL LOT ~SHV LOT .SHV LOT ~SS LOT ~lLS LOT _L LOT ~.U LOT ~S LOT LiTr~ LOT SSi LDT 3S2 LDT T E N S L D'T SGR NGT .,~'GR NGT POTA NGT POTA VOL THOR NGT URAN NGT W 1 N G N G T W2NG NGT CIFICATIGN ICE SERVICE .SIZE 1 1 1 BLOCKS UNIT AP1 AP1 AP1 LOG TYPE CLASS FT O0 000 O0 GAPZ O0 310 01 GAPl O0 3i0 O1 IN O0 280 O1 G/C3 O0 350. 02 G/C3 O0 356 O0 420 O1 O0 000 O0 ~O O0 890 O0 PU O0 890 O0 O0 358 CPS O0 330 31 CPS O0 330 30 v O0 000 O0 V O0 000 O0 OOO O0 O0 OOO O0 C~S O0 35~ CPS O0 354 O1 CPS O0 354 O1 CPS O0 35~ Ot CPS O0 000 O0 CPS O0 000 OC L5 O0 635 21 GAPI O0 310 Ol GAPt O0 310 Ol ~U O0 719 50 PU O0 719 50 P~M O0 790 50 PPM O0 7~2 5.0 CPS O0 310 O.! CPS O0 310 O! 73 APl miL M 0 C N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 O 0 ENTRY 0 1 5O .lin i 0 SIZE SPL 4 1 4 1 4 t 4 1 4 i 4 I 4 1 4 1 4 1 4 4 I 1 4 1 4 ! 4 i 4 I 4 1 ¢ i 4 1 4 t 4 i 4 1 4 1 R E P R CODE 68 68 68 68 68 68 68 68 68 68 68 68 PROCESS (OCTAL) 00000000000000 O0000eO0000000 00000000000000 OOOO00OO000000 00000000000000 00000000000000 00000000000000 00000000000000 00000000000000 00000000000000 00000000000000 00000000000000 00000000000000 00000000000000 00000000000000 68 00000000000000 68 00000000000000 88 00000000000000 68 00000000000000 68 O0000000000OO0 68 00000000000000 68 00000000000000 68 00000000000000 00000000000000 68 00000000000000 68 00000000000000 68 00000000000000 68 00000000000000 68 00000000000000 68 00000000000000 68 00000000000000 00000000000000 ~VP OlO.H02 VERI~ICATISN LiSTiNG ~3NG NGT CPS O0 310 Ol !4NG NOT CoS O0 310 Ol 0 IENG NGT CPS O0 310 0t 0 'ENS NGT LE O0 635 £1 :S NGT =/HR, O0 635 ~"1 ,GR DLL GAPI O0 310 Ol 0 .LD SLL ~HMM O0 220 '10 .LS DLL ~HMH O0 220 O~ ;P DLL NV O0 010 O1 lVl DLL ~,,V O0 000 O0 0 )VO DLL MY O0 000 OD O )i0 DLL dA O0 000 O0 ;VO DLL MV O0 030 O0 0 ;IO DLL gA O0 O00 00 0 'ENS gLL L~3 OS 635 21 0 )T SDT US/F O0 520 ~:0 0 )'TL SDT US/F O0 520 80 0 .SDT SDT US/~ O0 5£0 80 0 .DTL SDT US/F O0 520 80 0 )TCO SOT US/F O0 000 O0 0 )TSM SDT US/F O0 530 1~ 0 )TST SDT US O0 000 O0 0 ~R SDT GAPZ O0 310 01 0 FENS SD'T L~ O0 635 21 0 )EPT 11818.5000 SG2 -'~99.2300 CSR (HOB -999.2500 DRHD -999. 2500 NR&T ~'PHI -999. 2500 DPHI -999. 2500 PEF :CNL -999,2500 SSHV -999,2500 LSH¥ ~LS -999.2500 LL -999.2500 LU .ITH -999.2500 SSi -9'99 ..2500 SS2 SGR -999.2500 CG'~q -9'99.2500 PDTA fHOR -'999.2500 UR AN -999. ,2500 WiNG ~3NG -999,2500 W4NG -999.2500 W5NG 3S -999.2~00 SGR -999.2500 LLD SP -999.2500 OVI -999.2300 DVO SVO -999.2,500 SIO -9'99.2500 TENS DTL .-999.2500 LSDT -99'9. 2500 LDTL 3TSM -999,2500 DTST -999.2500 GR DEPT 11800,0000 SGR 117.8125 CGR RHOB 2.:3535 ORMJ 0. 1313 NRAT NPHI 59.4727 OPm! 17,9199 PEF FCNL 322.2:500 SSHV t2.50. 0000 LSHV ~LS 0.0151 LL 219.7500 LU L!TH 145.7500 SSt 2~9. 5000 SS2 SGR 11'7.8,125 CGR 93.8750 PDTA THOR 20.7656 bRAN 3.3594 WiNG ~3:NG 60. 4063 W4NG 31. 9844 WENG CS 1990.0000 SGR I17:.~i25 L:LD SP -101.8750 DV1 3. 5469 DVO 4 4 4 4 4 4 4 4 4 4 4 I 68 00000000000000 i 68 00000000000000 i 5~ 00000000000000 ! SS 00000000000000 I 68 O00OO000000000 i 5;~ OOOO0000000000 I 68 SO000000000000 i 56 00000000000000 i 68 DO000000000000 1 58 00000000000000 1 68 00000000000000 1 68 00000000000000 1 68 00000000000000 I 68 00000000000000 1 68 00000000000000 1 68 O0000'O00OO0000 1 65 00000000000000 i ~8 00000000000000 i 6~ 00000000000000 I 68 00000000000000 1 63 00000000000000 I 6~ 00000000000000 1 68 00000000000000 i 6~ 00000000000000 4.3 2.0 1185.0 367.0 340.7 i.! 366.0 20.1 15.8 0.~ 7 50 515 '7,52 000 000 5OO 23O 000 406 208 CALl 8.0703 RNR& 4.5859 NCNL 1478.0000 QSS 0.0840 LS 403.5000 TENS 5068.0000 P~TA 0.0112 W2NG 187.1250 TENS 5058.0000 LLS 0.0619 OiO 17.9531 -999.2500 CALI -999.2500 -999.2500 RNRA -999,2500 -999.2500 NCNL -999.2500 -999.2500 QSS '-999.2500 -999.2500 LS -9'99.2500 -999.2500 TENS -999.2500 -999.2500 POTA -999.2500 -999.2500 W2NG -999.2500 -999.2,500 TENS -999.2500 -999.2500 LLS '-999.2500 -999.2,500 DIO -999.2500 -999.2500 ':DT -999.2500 -999.2500 DTCO .-999.2500 110.8125 T~NS -999.2500 VO 0.0:369 GlO ,TL 80.3750 LSDT ~TSM 141.0000 DTST ~EPT 11700.0000 :HO5 2.3066 JPMI 15.4297 :CNL 2384.0000 SS~V iLS -0.0015 LL .iTH 132.6250 SSi ;GR 35.2500 CSR 'HOR 3.0820 ORAN i3NG 22.5594 :S i743.0000 SGR ;P -101.8750 CV1 ;VO 16,3281 SIO )IL 96.5000 LSDT )TSM 140.0000 STST )EPT 11600,0000 :SGR ~HOB 2,3125 DRH9 ~PHi 17,0410 DPHi :CNL 2298.0000 SShV aLS 0.0295 LL .ITH 133,8750 SSi ~GR 21.9062 CGR [HOR 2.3750 ORAN ~3NG 15.5'313 W4NG :S 1747,0000 SGR ~P -97,0625 OVI ~VO 4,6914 GlO ]TL 81.3750 LSDT )TSM 136.0000 OTST }EPT 11500.0000 SGR qH05 2.2871 DRHO ~PHi 18.6523 OPHI :CNL 2058.0000 SSHV ~LS -0.0029 LL .ITH 138.3,750 S,S1 ~GR 33,6875 CGR FHOR 4.1562 ORAN ~3NG 13.3438 W4NG :S 1746.0000 SGR SP -99,5000 OVi ~V 0 2.1621 SI 0 DTiL 80.5000 LSDT ]TSM 135.0000 DTST DEPT 1!400.0000 SGR RHOB 2. 2598 DRHO ~PHI 39,1113 DPMi =CNL 1085,0000 SSHV ~ S - O. 0059 LL 5575.0000 T:NS 79.5750 LDTL 223,0000 G~ 33,2300 CSR 0,0034 NRAT 20,7031 1262,0000 LSMV i37,~000 LW 206,0000 SS2 2!.~375 PSTA 1,8711 WiNG 6,9570 WSNG 35.2500 LLD 1'9.2~56 ~VO 2~3.7500 'T~NS 94,1250 LOTL 2t7,0000 GR 21.9062 CGR 0.0083 N~A'T 20.3125 PEF 1264.0000 LSHV I90.3750 LU 208.6250 SS2 18,3125 POTA 0,5054 WiNG 2.9121 W:SNG 21,9062 LLD 6,4492 OVO 535.5000 TENS 79.8750 LOT~L 216.0000 GR 33. 6875 CGR -0.0010 NRAT 21.9238 P~F 1265.0000 LSHV 193. 1250 LO 204.5000 SS2 25- 7813 POTA 1.1!23 WiNG 3.8125 WSNG 33.6875 LLD 3.1133 DVO 778. 5000 TENS 80. 1250 LOTL 216.0000 GR 53.1362 CiSR 0.0156 NRAT 23,.5940 OEF 1265.0000 LS~V 208,6250 LO 5 055. 0000 DT $0.2500 gTCO Ii0,812~ TENS ~I.:375 tALl 1,8086 RNRA !,7~32 NCNL !!67.0000 :CSS 326.0000 LS 309.5000 TENS 0.6836 POT~ 109,3125 WZNG 1.9873 T~NS 53.1974 LLS 13.9922 OlO 6340,0000 DT 110,5000 DTCO 30,0781 TENS 18.3125 CALl 1.9111 RNRA 1.9745 NCNL 1188.0000 QSS 318,7500 tS 307.0000 TENS 0,5859 POTA 70,8125 WZNG 2.9121 TENS 9.5757 LLS 4,8711 6160,0000 OT 80.5000 DTCO 18,7188 TENS 25.7813 CALI 2.01'76 RNRA 1.8906 NCNL 1190.0000 DSS 335.0000 LS 307.7500 TENS 0,6836 POTA 110.5625 W£NG 5,7:188 TENS 2.8?60 LLS 2.0~40 OlO 5908'0000 DT $i,0000 gTCO 34,7:188 TENS 29.5938 CALl 3.3105 RNRA 1.9180 NCNL i19'!.0000 QSS 359.5000 LS 31.7500 77.0000 4512.0000 8,9844 1,8672 4452.0000 0.0156 350,5000 6340,0000 0,0068 53.6563 63~0,0000 83.4654 234.1250 80,5250 78,0000 $47Z,0000 8,9052 1,9736 4536.0000 0,0298 349,7500 6150,0000 0.0059 35.9062 6160,0000 12,7044 452.7500 82,9375 79.0000 5448,0000 8,9375 2,1'797 4488,0000 0.0166 360,5000 5912,0000 0.0068 51,4688 5908.0000 4,02'74 645,0000 80,6875 79.0000 5220.0000 g,9219 3,7441 4064,0000 0,0~54 35~,5000 ITH la5.7500 SSi GR 55.1562 CGR nOR 4.5586 3NG 24.31£5 S 1740.0000 :P -80.3625 ,¥0 24.5623 SiO ITL 88.0000 ~TSM i42.0000 STST IEPT I!300.0000 SGR :HO~ 2.1973 iPHi 26.3137 DPHI :CNL 1284.0000 SSMV iLS 0.01.32 LL .iTH 17~.5000 ;GR 43.1562 CGR 'HOR 5.3234 URAN ~3NG 28.8906 ~4N~ :$ 1793.0000 ~P '-76.0000 ~VO 12.4219 $I0 }TL 95.~000 LSPT }ISM 172.0000 DT$i }EPT llZO0.O000 ~HOB Z.52i5 DRHC %PHI 19.0918 :CNL 1826.0000 SSHV ~LS 0.0024 iLL ,iTH 78.3750 ~GR 32.6875 CGR [HOR 7.9258 URAN ~3NG 27.1094 W4N~ :S 1871'0000 ~P -53.:5625 DV.I ~VO 9.1719 }TL 89.6250 LSD'T }TSM 124.0000 DTST D~PT lllO0.O000 SGR ~HOS 2.5137 . DRHO ~PHI 14.5508 DPH! :CNL 2250.0000 SS~V QL$ 0.0366 LL .i'TH 83.6~75 SS1 SGR 66.1875 CGR tHOR 8.0781 URA~ ~3NG 35 · 062.5 W4~G 2S 1767.0000 SP --52.9687 DV'I sro 6.4S~4 SIO D'TL 97.6250 LSDT DTSM 133.0000 DTST 216.1250 29.5938 3. 7.731'3 35.1562 28.468~ i45 :87. 1250 226. OOO0 ~+3. !562 0.03~2 27.294~ 1265.0000 246.1250 225.5000 28.7500 2.0215 43.1562 i 9. 0469 315.7300 94.8750 233.0000 52.6875 0.0093 7.7637 t261.0000 128.0000 196.7500 35.12 50 0.3'740 5.2109 52.6875 12.5859 371.50 O0 118.6250 207,0000 66.1875 8.2031 1265.0000 132.3750 197. 1250 45.9687 2. g340 12. 0234 66.1875 44 Z · Z 500 ~7.5000 211.0000 SS2 P2tTA WSNG T~NS LCTL GR CGR NRAT PEF LSHV LU SSZ POTA WINS WSNG LLD DVO TENS LOTL GR CGR NRAT PEF LSHV LU .SS2 POTA WiNG WSNG LLD OVO TENS LDTL GR CGR NRAT PEF LSHV LU SS2 POT~ WiNG WSNG LLO 9VO TENS LOTL GR 314.:5050 0.8301 183.7500 4.~633 174.6905 21.1719 615~.0000 87.2500 77.0,525 28.7500 2.3508 1.9809 i190.0000 406.7500 '322.7500 0.5371 i~i.2500 4.~164 52.6650 !3,8437 6084.0000 98.0000 37.0938 35.1250 2.2656 1190.0000 235.6250 286.5000 1.2695 178.2500 5.2109 25.4160 9.0313 5998.0000 93.3750 32.0625 45.9687 1.7832 2.1'719 1!90.0000 233.8750 284.0000 1.0254 209.3750 8.0156 15.4689 6.=313 5932.0000 115.5000 63.0313 TENS W 2 N S TEN S LLS OlO DT DTCG TENS CALi RN R A NCNL LS TENS P~TA WZNG TENS LLS D!O CT DTCO TENS CALl RNR& NCNL QSS LS T E N S P 0 T A W2NG T E N S LLS D ! 0 DT DTCO T~NS CAL?. NCNL qSS LS 'TENS POT.~ W ZNG T E N S LLS O T TEN S 6184.0000 0.00~3 90.437~ 6184.0000 245.1272 !07.B750 88.8125 86.0000 5~32~ · 0000 9.0313 2.6406 3392.0000 0.0674 449.5000 588B.0000 0.0054 63.5625 6084.0000 57.0253 234.0000 95.2500 100,0000 5100.0000 9.3438 2.2051 4028.0000 0.0083 245.87150 5872.0000 0.0127 92.7500 5988.0000 35.8092 316,2500 76.7500 75.0000 5280.0000 9.3906 1.8047 4062.0000 0.0171 249.5000 5932.0000 0.0103 98.1875 5932.0000 21.2657 375.7500 96.4375 79.0000 5112.0000 VP 010 ~i02 VEP~IFI£~TIJN' ~ ~- EP7 11000.0000 HS5 2.732& P~i 15.4297 D~I CNL 2006.0000 SS~V :LS -0.0122 LL ITH 42.4688 SS1 GR iI~.2500 CGR HOR 14.0625 URAN 13N~ 51.2500 ~4NG ,S 1790.0000 ;P -44.~563 ;VO 5.73~ SiO )TL 91.6875 LS3T )ISM 12~.0000 CTST )EPT 10900.0000 SGR [HO5 2.7910 ORH2 iPHi 4'7.1191 3FHi :CNL 465,2500 SSHV ILS 0.0347 LL .ITm 10.5859 SSI ~GR 132.5000 CG~ ~R 9.7~22 URAN ~3NG 68.2500 W4NG ;$ 2306.0000 SGR ~P -99.5525 DVl ~VO 0.0688 SiO )TL 52.0625 LSDT )TSM 1~8.0000 DTST )EFT 10896.0000 SGR ~H05 2.8770 ~RH8 4PHI 41.9434 DPHI :CNL 480.7500 SSHV ~LS 0.0283 LL ITM 9.'7~22 SS1 ~GR 151.2500 CGR FHOR 11.9375 UR~N ~3NG 51,1250 W4NG ]S 2306.0000 SGR ~P -I02,5000 DVl ~VO 0,0659 SIO )TL 53.~875 LSDT ]ISM 168,0000 ~TST ,,,,, FILE TRAILER ...... :ILE NAME :EDIT ,001 ~ERVICE NAME : ~ERSION ~ : }ATE : qAXiMUM LENGTH : 1024 =iLE TYPE : ~ ~00 CGR 0.0373 F, RAT -5.1270 12~4.0000 LSHV 37.4375 LU 1~2.6250 SS2 ~.1575 P~TA 4.2187 WiNG 8.0391 11~.2500 LLQ 9.17i9 4~6.7500 T~NS ~.6250 LDTL 207.0000 132.5000 CGR -0.3931 NRAT -9.5938 1256.0000 LSHV 44.7813 LU 57,7500 S.$2 68.7500 POTA 453 WiNG 8,0313 WSNG 132,5000 LLD 1,4141 DVO 2322.0000 TENS 54.8'750 LDTL ZZ$.0000 151,2500 CGR -0.3813 NRAT -13,8672 PEF 1267.0000 LSHV 40.9687 LU 57,9062 SS2 74,0000 PS'TA 10.8516 WiNG 18,0469 WSNS 151,2500 LLO 1.4053 DVO 2334.0000 TENS 55.3'750 LDTL 224.0000 GR ~ 1~75 1,8643 3.2441 1191,0000 177,1250 247,2500 2,3926 425.0000 13,052~ 1,5.903~ 7,57a2 6072.0000 90.2500 82.9375 65,7530 3.7715 ~'9.7813 1192,0000 109.3125 $3.5625 2.,1484 453. 7500 12. 0469 0,2929 0.3086 5940,0000 ,55.0000 1£8.1250 74,0000 3 · 4883 34,0938 1191,0000 104,1875 81,1250 1,9531 488.2500 1'7,0469 0,3046 0,3203 5940.0000 55.6250 i 37,7 50 0 CALl RNRA NCNL QSS LS TENS POTA WZNG TENS LLS OIO OT DTC~ TENS CALl RNRA NCNL QSS LS TENS P3TA W2NG TENS LLS D !0 DT DTCO TENS CALI RNR'A NCNL QSS LS TENS POT:a, W2NG TENS LLS DIO DT DTC 0 TENS 9.6641 i.8t15 3634.0000 0.0283 176.0000 5'920.0000 0.0239 191.8750 6072.0000 20.0608 398,7500 93,6875 74,0000 5192,0000 9,2109 3,86~3 1798,0000 -0,0947 99,4375 5940,0000 0,0215 211,7500 5940,0000 0,1485 937,5000 63.3125 56.0000 5020,0000 9.2031 3,4082 1639,0000 -0,0840 93,1250 5940.0000 0,0195 245,6250 5940.0000 0.14'78 935.5000 63,8125 56.0000 5024,0080 EXT~ FiL2 NAME : FILE MEAD:R_ -,--,- LE NAME :EDIT ;:RVICE NAME : 'ERSiON m : IAXiMUM LENGTH : :ZLE TYPE >REVZOU$ FILE : .002 1024 DATA FORMAT :NTRY ~LOCKS )ATUM SPECIFICATION qNEH SERVICE SERVICE iD ORDER m ),E PT 4 S F L D L L RECORD TYPE 2 1,5 0 5LOCKS UNIT FT ,SHMM DATA DEPT DEPT DEPT DEPT DEPT DEPT OEPT OEPT DEPT DEPT DEPT 11810,0000 11800,1660 1i700,1660 11600,16.60 11500,1660 1i400,1660 11300,1660 11200,!560 II100,1660 11000,1660 10900,!660 MSFL MSFL MSFL MSFL MSFL MSFL MSFL MSFL MS FL ~,SFL APl LOG O0 O0 ,SIZE I 1 I ! 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