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182-042
PLUGGING & LocATION 'CLEARANCE REPORT State of Alaska · · . · ALASKA OIL & ~AS 'CONSERVATION COMMISSION PTD No. Lease Memorandum To" File': API Well N-me· ' 'Location Abnd Date Completed spud: ~!.%!~ , , · . Note casing size, wt, depth, cmt vol, '&.procedure. ~~ ~" s~'.'~ ~:~0 ~ . . Per~ inte~als -'~ops:' 4~'$%'-:~ -- &~ Review the well file, and' comment on plugging, well head status, and location clearance - provide loc. clear, code. Plugs: o~ ~u~ Ioo&~ ~LZ~L'-8~O', O~4 Pu~G ~9~B-~C~ ~/IooS~~ . - . . i Well head Cut off: ~)% .' Marker post or plate: ~;A. Location 'Clear.ce: ~ ] a Conclusions: Code ~__ Signed Date PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., CIRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area January 20, 1983 File: A-JFS-021-83 State of Alaska AlaskaOil and Gas. Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: SRS TERN A NO. 1 Pursuant to regulations, accompanying this letter are the core samples required for the subject well. The samples were not included in our 9/14/82 submission of data due to analyses that were underway at our Oklahoma offices. The samples, taken at 1 foot intervals, cover the entire interval cored in this well from 5680' to 5737' RKB. This~offering is complete with the exception of samples from 5712' and 5720' RKB. For reasons unknown, these misSing~samples were not furnished us for~transmittal'to you. Please acknowledge receipt of these samples by signing and dating one copy of this~letter at the~time of delivery. If you should need further information, please call us at 279-0606. . F. Settle ager JFS/NEP: mm' Received this' ' day of January, 19'83, bY PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., CIRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area January 12, 1983 File: A-JFS-010-83 CERTIFIED #P13 1753577 RETURN RECEIPT REQUESTED State of Alaska AlaskaOil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 ATTN: MS. FRAN JONES RE: SRS TERN A NO. 1 Dear Ms. Jones: Per your conversation this day with Mr. Neal Porter, tabulated below are the.re- corded single shot surveys, for the subject well. We apologize for any inConven- ience our oversight may have caused. Should you need any further information, please contact us at 279'0606. DATE DEPTH ANGLE 'DATE ~'DEPTH ''ANGLE 7./7/82 501 7/8 1202 7/12 . 2821 7/12 3501 7/13 4068 7/16 4520 7/18 5660 7/20 61277 / J. F. Settle Area Manager JFS/TEM:kd 0 1 1/2° 1 1/4° 3/4° 1° 1 1/2° 1 1/2° 7/21 6601 1 1/4° 7/22 7216 2 1/4° 7/27 8288 1 1/4° 7/28 8553 1 1/4° 7/29 8803 1° 7/31 9246 1/2° 8/3 9519 1° RECEIVED JAN 1 41983 Alaska Oi~ & ~as Cons,, Com,'niss~on PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., ClRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area January 7, 1983 File: A-JFS-003-83 State of Alaska AOGCC 3001 Porcupine Drive Anchorage, Alaska 99501 RE: SRS,'TERN A NO. 1 .~ Pursuant to regulations, accompanying this letter are the core samples required for the subject well. The samples were not included in our earlier submission of data due to analyses that were underway at our Oklahoma offices. The core samples being provided are the plugs that were prepared by Core Lab. They are encased in lead foil with screens at each end. The samples are numbered 1-56 and correspond to depths of 5680' - 5735' at one foot intervals. For unknown reasons, numbers 1.8, 19, 23 and 32 were not sent 'to us. It is felt that the absence of these samples does not reduce the completeness of the ~data. Please acknowledge receipt, of these samples by signing and datirg one copy of this letter at the time of delivery. If you should need further information, please call us at 279-0606. JFS/TEM: kd Alaska PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., CtRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area September 14, 1982 File: A-JFS-376-82 State of Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: SRS TERN A NO. 1 Pursuant to 20AAC25.070(3) and 20AAC25.536(b), accompanying this letter are the data required for the subject well. These include the following: 1, Form 10-407 2. Mud log both blue line and sepia copies. 3. Core and sidewall core descriptions. 4. Drilling cuttings samples. 5. Composite log prints, sepias and digitized tape. At this time we are unable to provide samples of the cores taken .from the well. Due to the unconsolodated nature of the~Beluga formation, it was necessary to core using a plastic liner to insure cOre recovery. The encased core and Core Lab'plug samples were forwarded to our Oklahoma office for further analysis. Our people there have indicated that they will require approximately one month to secure the, samples we have requested. We will forward the samples as soon as they are received and will keep you advised as we have information available. Please acknowledge receipt of the data listed above by signing and dating one copy of this letter at the time of delivery. If you need further information, please call us at 279-0606. JFS/TEM:kd RECEIVED Rece±ved th-is .... day of September, 1982, Alaska 0il & Gas Cons. commission Anchorage 1. Status of Well Classification of Service Well OIL [] GAS [] SUSPENDED [] ABANDONED:I~ SERVICE [] 2. Name of Operator 7. Permit Number Phillips Petroleum Company 82-42 · 3. Address B. APl Number _ 2525 C Street~ Suite 508, Anchorage~ Alaska 99503 so- 733-20353 - 4. Location of well at surface 9. Unit or Lease Name 636' FWL 585' FNL Sec 19-10N-10W SM' SRS Tern A At Top Producing Interval Same 10. Well Number At Total Depth Same 11. Field and Pool ~Wildcat 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. RKB 84' MSL ADC 59343 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. J 15. Water Depth, if offshore 116. No. of Completions · July 3, 1982 August 2, 1982 August 28~ 1982I 86 feet MSLI NA _17. Total Depth (MD+TVD) 18.Plug Back Depth (MD+TVD): 19. Directional Survey i 20. Depth where SSSV set 21. Thickness of Permafrost 9519 straight ho.~.e 200 v YES ~ NO []I NA feet MD NA 22. Type Electric or Other Logs Run DIL-SP-GR, BHC-GR, FDC-CNL-GR HDT 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SiZE WT. PER FT. GRADE TOP BOTTOM HOLESIZE CEMENTING RECORD AMOUNT PULLED '30" 0 238 none none 178, 20" 133 J-55 0 470 26" 500 sx G/gel + 500 G 180' 13 3/8" 72 L-80 0 1236 17~" 500 sx G/gel + 300 G 185' 9 5/8" 47 SS/C-95 0 4086 12¼" 450 sx G 370' 7" 32 N-80 0 6763 8½" 275 sx G/gel + 100 G 570' 24. Perforations op~,-; t~ Prcduct",c.r~ (MD+TVD of Top and Bottom and 25. TUBING RECORD interval, size and number)~-- ~-5;~'{~._~ SIZE DEPTH SET (MD) PACKER SET (MD). 6250-6256, 6184-6190, 6158-6175,6070-6084, , 6034-6038, 59'72-5980, 5938-5946, 5900-5918, ... ' 5868-5874, 5592-5602, 5260-5264, 5230-5236, 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 5172-5178, 5142-5146,. 5102-5106, ~.4934,4962~ DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED See attachment 2 . . 27. PRODUCTION TEST Date First Production I Method of Operation (Flowing, gas lift, etc.) I Date of Test Hours Tested PRODUCTION FOR OI L-BBL GAS-MCF WATER-BBL CHOKE~SIZE GAS-OIL RATIO , TEST PI~RIOD ~ Flow Tubing Casing Pressure CALCULATED.~ OIL.-BBL GAS-MCF WATER-BBL OIL GRAVITY-APl (corr) Press. 24-HOUR RATE I~ " . , ,. "28. · ' CORE DATA · Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. See attachment 1 SEP 16 i982 '. , i~: A!:.~:ka 0il & Gas Cons. C0mmfssi0m A~.chora§~ ~ , STATE OF ALASKA t :,¢:.__ ALASK~ -tAND GAS CONSERVATION _~ v~MISSION ~ WELL COMPLETi N OR RECOMPLETION REPORT AND LOG Form 10-407 Submit in duplicate Rev. 7-1-80 CONTINUED ON REVERSE SIDE 29. 30. GEOLOGIC MARKERS ~: '~.' ,:'~'. '.:::7'. ,,, NAME . Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. Sterling Fm. See attachment 2 Cook Inlet Sand mbr. 4260' (-4176" Beluga Fm. 14970' (-4886" Tyonek Fm. !9100' (-8916 ' ~ 31. LISI OF ATTACHMENI$ 1. Core & Sidewall Description. 2. Testing Summary. 3. Detailed Well History. 32. I hereby cer~fy that the f'ore~going is true and corr~:t to the best of my knowledge 'Sign~'~'/'~~~~JJ. F/' ' ~~~/' ~ . Settle Tit,e Area Manager Date Seotember 14,1982 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 cQmpleted 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 '.2_8: If no cores taken, indicate "none". Form 10-407 September 14, 1982 File: A-JFS-376-82 Attachment 2 Attachment to AOGCC Form 10-407 (Well Completion...Report) for SRS Tern A No. 1 detailing items 26 and 30. Test Number: 1 Interval: 6250-6256, 6184-6190, 6158-6175, 6070-6084, 6034v6038, 5972-5980, 5938- 5946, 5900-5918, 5868-5874. Flow Number: 1 Cushion Fluid: Water, air Stimulation: None Date and Time Tool Opened: 8-10-82, 1110 hours Flow Time: 1 hr. 12 min. Choke: 64/64 IHP 2801 ~IFP 1912 FFP 2188 FSIP 2238 Fluid Recovery: None Test Number: 2 Interval: As above Flow Number: 1 Cushion Fluid: Nitrogen Stimulation: 10 bbls 7~% HCL, 20 bble 7½% HCL-i~% HF (Mud. Acid). Date and Time Tool Opened: 8-12-82, 205i hours Flow Time: 16 hrs. 12 min. Choke: 64/64 IMP 3936 IFP 2273 FYP 692 FSIP --- Fluid Recovery: Water, gas, sand Comments: Well intermittently unloaded and attempted to clean up. Three instan- taneous rates were measured with limited separator time. The rates were 475 MCFD @0640 hrs, 544 MCFD @0700 hrs, 347 MCFD @0826 hrs. WHFP= 50 psig WHFT= 60°F gas gravity .559. No water rate was measured. Flow Number: 2 Cushion Fluid: Nitrogen Stimulation: None Date and Time Tool Opened: 8-12-82, 1725 hours Flow Time: 9 hrs. 53 min. Choke: 64/64 IHP 2813 IFP 1656 FFP 620 FSIP 2367 Fluid Recovery: Water, gas, sand Comments: Well flowed as above. It was not possible to get the well into the separator due to the sand production. Test Number: 3 Interval: 6158-6175, 6070-6084 No test, tools plugged Test Number: 4 Interval: 5592-5602 Flow Number: 1 Cushion Fluid: Nitrogen Stimulation: None Date and Time Tool Opened: 8-18-82, 1944 hours Flow Time: 8 hrs. 46 min. Choke: 64/64 September 14, 1982 File: A-JFS-376-82 IHIP 3123 IFP 1122 FFP 2355 FSIP 2355 Fluid Recovery: Water, gas, sand Comments: Unable to turn to separator due to sand production Flow Number: 2 Cushion Fluid: Nitrogen Stimulation: 3 bbls HCL, 7 bbls Mud Acid Date and Time Tool Opened: 8-19-82, 0718 hours Flow Time: 11 hrs. 57 min. Choke 64/64 IHIP 3055 IFP 1108 FFP 2362 FSIP 2362 Fluid Recovery: Water, gas, sand Comments: Well flowed as above Test Number: 5 Interval: 5230-5236, 5260-5264 No test, tools plugged Test Number: 6 Interval: 5172-5178, 5142-5146, 5102-5106 No test, tools plugged Test Number: 7 Interval: 4934-4962 Flow Number: 1 Cushion Fluid: Nitrogen Stimulation: None Date and Time Tool Opened: 8-23-82, 1349 hours Flow Time: 4 hrs. 41 min. Choke: 16/64 No pressure data obtained - gauges failed Fluid Recovery: Water Comments: Well did not flow to surface. Tubing was~found to be full of water on reverse out. A second test of this interval was attempted, but the down hole tool plugged with sand. Oil &. Gas Cons. Commissiort SRS T , A-I CORE DESCRIPTIONS COOK I , ALAS}~ ATTAC,-W~NT I SAMPLE # CORE ~1 Core Cut Into PVC Pipe Therefore Samples Are At Approx. 2.5' Intervals Recovered 30' No Apparent Dip In Any Samples 1-12 5680-5682.5 1-11 5682.5-568~.5 1-10 5684.5-5687.0 1-9 5687.0-5698.9 1-8 5689.9-5692.7 1-7 5692.7-5695.7 1-6 5695.7-5698.5 1-5 5698.5-5701.2 1-4 5701.2-5704.3 1-3 5704.3-5707.1 1-2 5707.1-5709.6 1-1 5709.6-5710 ! Claystone; s&ndy, gr, large amt. of swel%ing, 27% por, frac.. Coal; black, friable, 27 % por, frac. Coal; A.A.; 27 % por, frac. Siltstone; gr-buff, sandy, some swelling clays; 28 %, non-fr~ Shale; black, w/coal partings; 27 % por, frac. Siltstone; gr-buff, sandy, very high amount swelling clay; por, non frac. Coal; black, Woody; 31% por, non frac. Coal; A.A.; 309% por, non frac. Sandstone; buff, woody, very fine grained, mod. hard 22 % poz non frac. Coal; A.A., 28 % por, frac. Siltstone, gr, coaly, vhd, mgr 25 % por, frac. Sandstone, fgr, sb md, sft, sl cal, 26 % por, non frac. SA>~LE # .CORE #2 Core Cut Into PVC Pipe, Samples At = 2.5' Intervals Recovered 27', 1.5' Of Core Extruded On Drilling Floor 2-11 5710-5711.8 Coal; black, blocky fracture, 26 % por, non frac. 2-10 5711.8-5714.3 2-9 5714.3-5717.1 2-~ 5717.1-5718.6 Coal; A.A.; 31% por, frac. Sandstone; fine gr, buff, some clay matrix, sub ang; 24~% fra Sandstone; A.A., 25 %, frac. ._2-7~ ,~:.~-. 57:!8.6-5720.3, v.~. _---Sandstone; v fine gr, sl bedded, coaly;~ 28 % por,:;hO~-~-~6~9-- 2-6 5720.3-5722.6 Sandstone, A.A., strong petroliferous odor, 28 % pot, non fra, 2-5 5722.6-5725.2 Sandstone, A.A., 28.%, frac. 2-4 5725.2-5728.0 2-3 5728.0-5730.7 2-2 5730.7-5733.2 2-1 5733.2-5736.2 Sandstone, A.A., gas present hissing from cut in PVC, 28 % P~ non frac. Sandstone; A.A. gas present hissing from cut in PVC, 28'% po~ non frac. Siltstone; fine grained, buff, v hard, 27 % por, frac. Siltstone, A.A., 28. % por, frac. ~~~ Total 3 of open air space in PVC pipe associated with gas presen~ I 6 i~82 Gas Cons, Coinmissil PHILLIPS' S.R.S. TERN A(/1 SIDEWALL SAMPLES AUGUST 5, 1982 DEPTH (FT. RKB) 1' 9244 2.~ 9184 3. 7875 4. 7742 5. 7680 6. 7524 7. 7302 8. 6726 9. 6724 10. 6648 11. 6490 12. 6426 13. 14. DESCRIPTION Not recovered. Sand, unconsolidated; very fine-grained to fine- grained; poorly to moderately sorted; subangular; quartz 25%, feldspar, lithics; abundant clay matrix. Medium gray. Not recovered. Coal; black; blocky; conchoidal to straight fracture vitreous to subvitreous luster. Sandstone, loosely consolidated; very fine-grained; poorly sorted; quartz, clear --40%, feldspar, black grains, lithics, minor muscovite; subangular; abun- dant clay mtx. Appears porous and highly pez-meable. May contain detrital coaly particles. Gray. Not recovered. Clay, soft, light gray; sandy, silty (grains "float" in matrix); swells in water; slightly calcareous. Clay, silty, cohesive and~plastic; dark-medium gray; nonswelling; noncalcareous. · Clay, silty, cohesive, plastic; dark-medium gray; slight swelling tendency; noncalcareous. Sandstone, firm when dry; swelling clay matrix, disaggregates when moistened. Very fine-grained; subangular; predominately quartz, feldspar, black grains ¢5%. Slightly calcareous. Medium- light gray. Poorly sorted. Sandstone, coaly; firm when dry; clay matrix swells, disaggregates when wet. Fine-grained to very SE~ ~L ~ ~,~]2 fine-grained; angular-subangular; very poorly sorted. Predominately feldspar, quartz, !ithics; A!~sk~t0il & Gas Cons, C0mmis$i0p with coal streaks. Medium gray. 6298 Clay, very silty, semiconso!idated; clay mixture does not swell i.n water. Noncalcareous. >ri cr o.-._.i caseous. Medium gray. PHILLIPS' S.I.S. TER~' .~'] SIDE-~'ALL S~M~LES AUG~£I PAGE 2 5, 1982 DESCRIPTION 15. 6254 Not recovered. 16. 6252 17. 6185 Clay, silty, with coal streaks; moderately firm. Noncalcareous, nonswelling; micromicaeous. Medium gray. 18. 6167 Sand, slightly consolidated, soft, with small amount clay matrix. Fine-grained to medium- grained, angular-subangular, poorly sorted; quartzose, feldspathic. Clay matrix nonswelling. Noncalcareous. Highly porous and appears permeable. Medium gray. 19. 6162 Sand; slightly consolidated, soft, with moderate amount clay matrix. Fine-grained to medium- grained, angular-subangular; poorly sorted. Feld- spar, quartz, lithics. Noncalcareous. .Clay mtx. has slight tendency to swell when wet; partially disaggregates when moistened. Medium gray. 20. 6138 Not recovered. 21. 6110 Il II 22. 6081 Sand, slightly consolidated, soft, with clay matrix. Fine-grained to very fine-graimed; angular-subangular, poorly sorted. Predom. feldspar, lithics. Clay matrix swells when wet; sand disaggregates when wet. Medium gray. 23. 6078 Not recovered. 24. 6036 25. 5978 Clay, firm; medium dark gray; non-silty; non- swelling; non-calcareous. 26. 5972 27. 28. Sandstone, moderately consolidated, clay matrix. Fine-grained to very fine-grained; subangular; poorly-moderately poorly sorted; feldspar, lithics. Clay matrix swells strongly when wet, disaggregating sample. Medium gray. Noncalcareous. 5940 R~~V~ Siltstone, very clayey, moderately firm. Medium gray. Clay matrix swells when wet. Noncalcareous. 5910 Not recovered. A]~tska 0i[ &. Gas Cons, · PHILLIPS' S.R.S. TEP~ 61 SIDEWALL SAMPLES AUGUST 5, 1982 PAGE 3 DEPTH (FT. RKB) 29. 5906 30~' 5870 31. 5664 32. 5598 33. 5596 34. 5417 35. 5263 36. 5244 37. 5234 38. 5178 39. 5146 40. 41. 42. DESCRIPTION Siltstone, very clayey, moderately firm. Medium gray. Slightly calcareous. Cla3 matrix swells strongly when moistened causing.immediate disintegration of sample. Claystone, silty, firm; medium gray; ndncalcareous. Moderate swelling when moistened. Sandstone, moderately consolidated, firm, medium- light gray. Very fine-grained; angular-su%angular; poorly sorted. Quartz, feldspar, black grains (some possibly coal), grey lithics. Clay matrix abundant, swells with water contact. Noncalcareous, Claystone, silty, firm, dark-medium gray; non- calcareous. Nonswelling. Claystone as above except slight swelling tendency in acidified water (swelling is not accompanied by evaluation of gas). Not recovered. Coal; black, soft, earthy texture; laminated. Sandstone, clayey; fine-grained to very fine- grained; poorly sorted; angular-subangular; quartz, feldspar, gray lithics. Clay mstrix swells when moistened, disaggregating sample. Non-calcareous. Medium gray. Siltstone, clayey; dark bluish gray; firm; non-. calcareous; sloughs and swells slightly whe~ moistened. Claystone; medium gray; firm, slightly plastic; 'nonswelling. Claystone, mod. firm; dark bluish gray; non- swelling, non-calcareous. 5120t~)~C~ Siltstone, clay matrix; medium gray, loses '~ ~/~.~ cohesion in water without swelling (firm when ....· c'~ dry). 'g~P f 6 ~)~?,~;~Not recovered.- 5106 '-q~O~Ot.~,,y Siltstone; ve~ clayey; med. gray; ve~' fi~ to " .... fi~, strongly swelling when wet. 43. 5060 ~;ot recovered. PHILLIPS' S.R.S. TEF~~ ~'"1 SIDEWALL SAMPLES AUg~T 5, 1982 PAGE 4 (See Note B) 44. DEPTH (FT. RKB) 5007 45~ 4950 DESCRIPTION Claystone, mod. fi_tm; silty, sandy; dark gray; abundant fine coaly particles. Swells when wet. Noncalcareous. Sand, slightly consolidated, fine-grained to medium-grained. Subrounded to subangular, well sprted to moderately well sorted. Quartz, plagioclase, gray lithics, biotite, potassium feldspar (?), and green lithics; small % clay matrix. Loses cohesion with addition of water. Noncalcareous. Very porous, permeable. NOTES: A. Ail samples fired. When gun was brought up, 15 bullets were missing and presumably stayed in the formation. Schlumberger engineer Scott Scheid stated that tool had not been pulled hard enough to break cables; he felt it was more likely that bullets entered formation with so little resistance that the cables broke at that time. B. Sample 44 was inadvertently knocked off tool as it was raised to drill floor and was recovered from top of BOP stack. Schlumberger engineer saw it fall and -ID'd it as No. 44. .GEOHAZARDS GEOPHYSICAL ADDENDUM SURVEYS FOR THE .SRS, PROJECT COOK INLET, ALASKA, PHI LLI PS FOR PETROLEUM MAY 1982 COMPANY RECEIVED NORTHERN TECHNICAL SERVICES ~,'q,Y.t ! 19~2 A~$ka 0J! & Gas Cons. Commissior~ ANCHORAGE, ALASKA Anc.horag~ NORTHERN TECHNICAL SERVICES 750 WEST 2ND AVENUE, SUITE 100 · ANCHORAGE, ALASKA99501 (9O7) 276-4302 May 6, 1982 Phillips Petroleum Company 2525 C Street, Suite 508 Anchorage, Alaska 99503 Attention: Mr. J'.F. Settle Area Manager Re: Geohazards Report Addendum Geophysical Surveys for the SRS Project Cook Inlet, Alaska Enclosed are six copies of our Geohazards Report Addendum, Geophysical Surveys for the SRS Project, Cook Inlet, Alaska. understand that the Addendum is to.~suppl, ement your drilling permit application. We The Report Addendum was prepared in response to your letter dated April 13, 1982. We~.~.~also have enclosed geophysical records from the November 1982 survey. Should you have any questions regarding this report, pl'ease give me a call. Sincerely, NORTHERN TECHNICAL SERVICES William D. Pyle Senior Associate WDP/gam Enclosure 024-017 GEOHAZARDS ADDENDUM GEOPHYSICAL SURVEYS FOR THE SRS PROJECT COOK INLET, ALASKA INTRODUCTION We are pleased to submit this Geohazards Addendum Report which is an addendum to our Geophysical Surveys Report for the SRS Project, Cook Inlet, Alaska. The survey area boundary is shown on Figure 1, Location Map. The original report was dated September 30, 1980. Both the original report and this Addendum Report contain the results of investigations made to identify possible geohazards within an area of proposed offshore drilling in Cook Inlet. A proposed SRS Tern A No.. 1 Well will be located within the investigation area at a location 560 feet north and 520 feet west from section lines of Section 19, Township 10 North, Range 10 West in Cook Inlet (see Figure 2). We understand that the Penrod 96 jack-up drilling platform will be used ~for drilling the proposed well. SCOPE The~scope of this Addendum Report is to update our previous report. The updating was based upon a review of geophysical record~s obtained .~by Phillips Petroleum Compan~I during a November 1982 Survey. Copies of geophysical records obtained during the Survey are enclosed. A post plot of geophysical survey line locations is shown on Figure 2. We also obtained pertinent information through interviews with state and federal government agency personnel who are familiar with .the SRS area. State 8N LOCATION MAP' II I = 4 miles Figure 1. PURPOSE The purpose of the original report, and this updating effort, was to investigate the SRS area in Cook Inlet for possible geohazards which could affect exploration drilling activities at the selected well location. The types of geohazards which were considered in this investigation were: o Shallow faulting o Offset sediments o Offset near-surface bedrock o Sediment instability o Slumping o Sliding o Mobile bedforms o Gas-charged sediments o Bright spots o Bubble columns o Signal return loss Also included in the investigation was consideration of other possible site-specific ..geohazards such as foundatio;~ conditions and sea floor obstructions. RESULTS Our investigation r.evealed only three types of potential geOhazards within the SRS project area in Cook Inlet. The first type of geohazard is mobile bedforms which are typical of similar bedforms elsewhere in upper and lower Cook Inlet. The tidal currents in the SRS project area are of sufficient velocity to cause formation of standing sediment waves within some portions of the area. It has been our experience that standing sediment waves in Cook Inlet are generally limited to specific zones. While individual wave forms indicate mobility i.e., they appear asymetrical in section, standing sediment wave zones occur in relatively constant locations from year to year. The relative stability of sand wave zones in Cook Inlet was verified by comparison of data from two geophysical surveys conducted for Phillips Petroleum Company in September 1980 and November 1981. Other investigators also have verified that "sand wave" zones are generally stable in Cook Inlet (Bouma, 1977; Bouma, 1977; Bouma, 1978, Mahmood, 1981 and Whitney, 1979). A second geohazard identified in the SRS project area is the potential for scour~of unconsolidated sediments by tidal currents. Tidal currents tend to scour unconsolidated sediments adjacent to platform legs elsewhere in Cook Inlet. This scouring may result in decreased lateral support for structures placed in the Inlet. The third type of geohazard identified in the SRS project area is sea floor obstructions. Large boulders and bedrock outcrops were observed as obstructions standing in relief above the sea floor. Such obstructions could present platform stability problems during placement. Foundation conditions appear to be good for end-bearing support systems within most of the SRS project area.. Platform legs are not likely to penetrate more than a few feet into the dense unconsolidated sediments during set-up and~drilling operations. Glacial till and bedrock probably underlie the unconsolidated surficial sediments. Neither of these materials should be penetrated to any significant degree by the Penrod 96 platform legs. No evidence of shallow faulting; sediment slumping or sliding; or gas-charged sediments was observed on any of the geophysical survey records in the SRS project area. CONCLUSIONS AND RECOMMENDATIONS Selection of the proposed drilling location within the SRS project area has been made specifically to minimize or avoid each of the geohazards described above. For example, the drilling platform will be located outside zones of mobile bedforms which avoids having to deal with the possible hazard of sediment waves. The proposed well will be located where little or no unconsolidated sediment exists. The Penrod 96 drilling platform legs do not require lateral support from unconsolidated' sediments. This minimizes problems associated with potential scour and associated decreases ~in lateral support. Careful selection of final drilling platform location has avoided areas having high concentration of sea floor obstructions. As a result, problems associated with such Obstructions will be minimal. Regional hazards such as volcanism and seismic activity have not been included in this investigation. This, in part,, is because of the location-specific consideration of this Addendum report, and because other drilling platforms have operated safely for over 20 years in the same region. o-0-o REFERENCES Bouma, A.H., Hampton, M.A., and Orlando, R.C., "Sand Waves and Other Bedforms in Lower Cook Inlet, Alaska", Marine Geotechnology, Vol. 2, 1977, pp. 291-308. Bouma,-A.H., Hampton, M.A., and Wennekens, M.P., "Large Dunes and Other Bedforms in Lower Cook Inlet, Alaska", Offshore Technology Conference, Paper No. OTC 2737, Vol. 1, 1977, pp. 79-90. Bouma, A.H., Hampton, M.A., Rappeport, M.L., Whitney, J.W., Teleki, P.G., Orlando, R.C., and Torresan, M.E., "Movement of Sand Waves in Lower Cook Inlet, Alaska", Offshore Technology Conference, Paper No. OTC 3311, Vol. 4, 1978, pp. 2271-2284. Mahmood, A., Ehler, C.J. and Cilweck, B.A., ".Sand Waves in Lower Cook Inlet, Alaska", Journal of the Geotechnical Engineering Division, Proceedings of the American Society of Civil Engineers, Vol. 107, No. G.T.10, 1981, pp. 1293-1307. Whitney, J.W., Noonan, W.G., Bouma, A.H., Hampton, M.A., and Thurston, D., "Lower Cook Inlet, Alaska: Do Those Large Sand Waves Migrate?", Offshore Technology Conference, Paper No. OTC 3484, Vol. 1, 1979, pp. 1071-1082. PERSONAL COMMUNICATIONS Hanson, James. Chief State Geophysicist, Alaska State Division of Geological and Geophysical Survey, 1982. Krause, Kerwin. Alaska State Division of Geological and Geophysical Survey, 1982. PERSONAL COMMUNICATIONS, Continued Reger, Richard. Alaska State Division of Geological and Geophysical Survey, 1982. Riley, James. U.S. Geological Survey, 1982. Updike, Randy. Chief Geo-Hazards, Alaska State Division of Geological and Geophysical Survey, 1982. Van Allen, William. Alaska State Division of Geological and Geophysical Survey, 1982. DAILY REPORT DETAILED LEASE SRS Tern 'A' WELL NO. 1 SHEET NO. 1 DATE TOTAL DEPTH 6-24-82 0 6-25-82 0 6-26-82 0 6-27-82 0 6-28-82 0 6-29-82 0 6-30-82 0 7-01-82 0 7-02-82 0 NATURE OF WORK PERFORMED Penrod Rig 96 positioned on location at 0230 hrs 6/23/82. Jump divers and inspect cans. Support OK. Release tugs. Start pre-loading legs. Well API Number is 50-733-20353. 8 hours pre-loading legs. 3 hours skid rig into location. 13 hours rigging up and offloading 30" from boat. PU and weld 30" 196 (.625 wall) drive pipe (DP) tag mud line at slack tide. Distance RF to mud line (MfL) 170'. Spud drive pipe. PU hammer. DP moving and bowing in tidal current. Secure top of DP with winches and CSG guide. Tidal currents caused severe movement of DP breaking winch lines and damaging CGS guide. At slack tide PU DP and survey damage. Bottom 2 jts (80') of DP missing. Recover 5 jts of DP. RD damaged CSG guide frame. Begin repair of guide frame and support structure Continue repair of CSG guide frame. Divers conducted bottom survey. Locate 2 its of 30" DP still stuck in mud listing at 45 degree angle. Divers attached lines to top of DP from traveling block. Pull 60,000# unable to move. Held strain. 30" parted about 6' below ML. Recover 2 damaged joints~of DP. Rigging up to run 30" 1" wall DP. Finished repairing, casing guide and BOP deck at Whites Yard in Kenai. Moved to rig. Now installing casing guide and BOP deck. All repairs 90% complete. Complete installation of ~casing guide frame with bracing. Move rig over slot 2. Welding 30" x 1" wall drive pipe joints together. WO Low slack tide to stab drive pipe and begin driving. Have 218' of 30" OD x 1" Wall pipe welded together. It is 170' from RF to ML. Waited on slack tide - drive 30" to 71' below mud line with 276 max BPF. Bottom 30" at 241' Rotary table. Nippled up 30". Now rigging up to drill. DAILY REPORT DETAILED LEASE SRS Tern 'A' WELL NO. 1 SHEET NO. 2 TOTAL DATE DEPTH 7-03-82 237 7-04-82 480 7-05-82 480 7-06-82 480 7-07-82 480 7-08-82 1247 7-09-82 1247 NATURE OF WORK PERFORMED RKB ~fW 9.0 Vis 200 WL16. Spudded well 0100 hrs 7/3/82. Drill 76' in 3 hrs bit No 1 26'LOSC3AJ. RKB MW 9.0 Vis 160 WL16. Drill 243' in 4 hours. Flow line plugged periodically with gravel. Bit No 1 319'/7 hours, cond. 2-1-I. Rig up and start running 20" casing. RKB ~B~ 9.1 Vis 160 WL 15. Ran 12 Jts of 20" 133# J-55 BTC casing. Set float shoe at 470' RKB (309' BOF). Stab in float collar set 428' RKB.· Gray type DJ-S casing housing set at 192' RKB (31'BOF), Stab DP into float collar. Circ hole clean. Pump 30 BFW flush ahead of 12.9 PPG lead slurry composed of 500 SX of 'G' cement mixed with 2.5 percent PHG and 2% CACL and .75% CFR-2L in sea water. Tail in with 500 SX of 'G' cement mixed with 2% CACL and .75% CFR-2L in sea water to a 15.9 PPG density. Had good returns through job. Cement back to surface. Displace cement in 20" x 30" annulus above DJ-S housing with sea water. Displace sea water with 1½% sugar water solution. COOH with DP. Pull 1½" hydril TBG out of 20 x 30 annulus. WOC. PBTD 428. WOC 14 hours. Slack off 20" casing. Cut 20" and 30" off at BOP deck. Center 20" in 30" with wedges. Weld on gray 20"-2M starting head. Nippling up 20"-2M diverter system. RKB 0'/24 hrs. MW 8.9 Vis 68 WL 13. 24 hours nippling up 20" diverter system. RKB 767'/24 hr M~ 8.8 Vis 69 WL 12 Bit No. 2 17½"S3'S~Depth in/out 428'/1247' 767'/4 hrs. Formation Sd, Gravel and coal. Finish nippling up diverter. GIH w/bit. Drill out 20" float collar and shoe with sea water. Drill to 1247' RKB with mud. Surveys 0~ at 501' and 1° at 1202' RKB. C&CM POH to run 13-3/8" casing. RKB Run 29 jts 13-3/8" 72# L-80 BTC Csg. Set csg at 1236' RKB (1066' BOF). Cemented with 500 sks 12.9 PPG lead slurry and tail with 300 sks 15.9 PPG slurry. Lost returns while pnmping end of tail slurry and had partial returns during displacement. Did not bump plug. Washed cement contaminated mud out of hanger. Rigging down 20~' diwerter and rebuilding flow line. DAILY REPORT DETAILED LEASE SRS Tern 'A' WELL NO. 1 SHEET NO. 3 TOTAL DATE DEPTH NATURE OF WORK PERFORMED- 7-10-82 1247 Nippling up Wellhead and Bope. 7-11-82 1247 RKB Complete Bope Installation, test same. Drill Cement out of 13-3/8 and wash to bottom. 7-12-82 2970 7-13-82 4095 RKB 1723'/10 Hrs. MW 8.8. Vis 45. WL 12.4 survey at 2821' - 1-½ degrees. Well location is 636' ~L and 585' FNL. Section 19-10N-lOW, SM. Latitude 60 degrees 56' 54.987" N Longitude 151 degrees 07' 41.401" W. RKB 1125' Past 24 hours. ~ 9.0. VIS 44. WL 12.2. Making short trip to condition hole. 7-14-82 4095 7-i5-82 4095 0' /24 hours. MW 9.1 VIS 55 WL 8.4 Condition mud and hole. RU & run combination ~tSFL ~- BHC -- GR -- SP from TD back to base of 13-3/8". GIH w/bit & condition hole. COOH and start rigging up to run, 9-~5/8'' CSG. 0'./24 hrs. Ran 9-5/8 Csg. Set 4086' RKB. Cement w/450 SX neat class "G" WOC 7-16-82 4095 RKB 0'/24 hrs. ~g~ 9.1 VIS 44 WL 9.0 RD BOP. Set Csg slips and pack off. NU BOP.. Run BOP test and test csg to 5000 psi. LD 12~g" & PU 8½" drilling assembly. GIH. 7-17-82 4975 880'/24 hrs. ~I 10.0 Vis 38 WL 7. Survey 1° at 4520. 7-18-82 5680 COOH to core TD 5680. 705'/24 hrs. MW 10.3 Vis 43 ~7L 6.2. 7-19-82 5713 Coring TD 5713. 33'/24 hrs. MW 10.4 Vis 51WL 5.2. Cut and recover 30' core.''GiH to cUE c0r~N0. 2, '~ 7-20-82 6227 7-21-82 6597 Drlg. ~ 10.4 Visc 44 WL 5.I Cut and recover core No. 2. GIH with bit and DA. Drlg. ~q 10.4 Vis 44 ~.~ 4.8 Survey 1½° at.6277. Trip for bit. DA 7-22-82 7206 Drlg. ~fi~ 10.4 Vis 42 WL 4.8 Survey 1° at 6601. ~E~E~~ 18 hrs drlg 6 hrs survey and tripping. DAILY REPORT DETAILED LEASE SRS Tern 'A' WELL NO. 1 SHEET NO. 4 TOTAL DATE DEPTH ' 7-23-82 7630 7-24-82 7915 7-25-82 7915 7-26-82 .7915 7-27-82 7942 7-28-82 8288 7-29-82 8553 7-30-82 8803 7-31-82 9128 8-01-82 9306 8-02-82 9498 8-03-82 9529 8-04-82 9529 8-05-82 9529 NATURE OF WORK PERFORMED PTD 7630. Drlg. ~ 10.4 Vis 43 WL 4.4 Survey 2¼° at 7219". Drill to 7218' Trip for bit. DA. PTD 7915. RU to log. 285'/24 hrs. MW 10.5 Vis 49 ~3.8 PTD 7915, RIH w/magnet to fish 2 lost cones. MW 10.4 Vis 45 WL 4.6 Ran logs. PTD 7915. COOH w/mill. MW 10.4 Vis 46 WL 4.6 Made 2 runs with magnet, recover 1 cone. GIH w/mill. PTD 7942. RIH with new bit. 27'/24 hrs. MW 10.4 VIS 46 WL 4.6. Slow drilling due to lost cone. Made trip with junk basket and recovered the cone. PTD 8288. GIH MW 10.4 Vis 44 WL 4.8 Survey 1¼° at 8288. Trip for bit. PTD 8553. GIH w/bit No. 15. MW 10.4 Vis 46 WL 4.6 Survey 1¼° at 8553. Trip for bit. PTD 8803. GIH with bit No 16. MW 10.4 Vis 44 WL 5.2 Survey 1° at 8803'. Trip for bit. Ran BOP test. PTD 9128. Drilling MW 10.4 Vis 44 I4I, 4.8 GIH DA PTD 9206. Drilling MW 10.4 Vis 43 WL 5.2 Survey 0.5° at 9246'. DT 9256 Trip for bit. PTD 9498. Drilling MW 10.4 Vis 44 IlL 4.8 GIH w/ bit No. 18. DA PTD 9529. Logging MW 10.4 Vis'45 WL 4.6. ReaCh TD of 9529 at 0715 Hrs '8/2/82. C&CM & COOH to log. PTD 9529. Running RFT Tool MW 10.4 Vis 42 14I, 5.8 Survey 1° at 9519'. Ran HDT and velocity survey. GIH and condition hole and mud. COOH to continue logging. PTD 9529. PU Tbg to plug back MW 10.4 Vis 40 WL 6.2 Ran RFT Tool. Got pressure data but unable to secure formation samples. Ran SWC gun. Shot 45 Recover 30. RD Schlumberger. DALLY REPORT DETAILED LEASE SRS Tern 'A' WELL NO. 1 SHEET NO. 5 TOTAL DATE DEPTH NATURE OF WORK PERFORMED 8-06-82 6973 OTD 8-07-82 9529 PBTD 6973. COOH to run casing. MW 10.4 Vis 46 WL 6.0 Place 100 Sx neat cement open hole plug to isolate Tyonek formation from 9222 back to 8970. Lay another 100 Sx isolation OH plug at 7207 back to 6973. C&CM. PBTD 6680. Mud 10.4 Vis 43 WL 7.0 Ran 166 jts 7" 32# L-80 8Rd casing set @ 6763, Cemented w/275 Sx Blended,cement.plusl00Sx Reg. Pumped plug to 6680 @ 0300 8-8-82. 8-08-82 WOC. Nipple down BOP. Land & cut of 7" casing. Re-nipple up BOP's. Change out 5" rams to 3½. 8-09-82 PBTD 8-10-82 6680 PBTD 8-11-82 6680 PBTD 8-!2-82 6680 Test BOP's, PU, GIH w/ 208 jts 3~ Butt tubing, hydro test to 5000 psi, tagged plug at 6680. Test casing to 1500 psi, circ. & cond. mud. Start COH w/tubing. OTD 9529 PBTD 6680. Mud Wt 10.4 Vis 47 k~ 5.8 Present Operation GIH w/test tool. COH w/tubing. Ran Schlumb. CBL Log, top cement 3830. Perf. inter- val #1 49PF Net 87' as follows: Run #1 6250-6256, 6184-6190, 6165-6175. Run #2 6158-6165, 6070-6084, 6034-6038. Run #3 5972-5980, 5938-5946, 5868-5874. Run #4 5900-5918. Pick up test tool, start in hole w/3½ tubing. OTD 9529 PBTD-6680 MW 10.4 Vis 45 WL 6.0 Complete trip in hole with Howco test tool for DST #1. 5868-6190, Packer set at 5800', open tool for initial flow - 10 min, slight blow for 5 min, dead for 5 min. Shut in for 61 min, open for flow period '63 min with no blow at surface. Shut in tool - terminated test. COOH. 'Test results -: IHP'3061, IFP 1871, FFP 2187, Shut in 61 min. ISIP 2280 PSI, FSIP 2501 PSI, Open 63 min. IFP 2222 PSI, FFP 2480 PSI, FHP 3047, Temperature 107°. Prepare to acidize and retest. OTD 9529 PBTD 6680 MW 10.4 Vis 44 WL 6 Present operation preparing to spot acid. Lay down test tool. GIH with bit scraper clean out sand bridge 6125-6201. Circulate bottoms up. ~COH, make up and go in hole with test tool for DST #2. Will acidize prior to testing. Correction on report of Aug. 11, 1982 - Test interval reported 6190-5868 - should be 6256-5868. DAILY REPORT DETAILED LEASE SRS TERN A WELL NO. 1 SHEET NO. 6 DATE TOTAL DEPTH NATURE OF WORK PERFORMED 8-13-82 PBTD 6680 Acidized test interval as follows, spearheaded with 420 gals 7½% HCL, followed with 840 gals 7½% HCL, 1½% Hydrofluoric. Spotted the 7½ HCL across perfs for 30 mins, then moved the mud acid across perfs. Pulled packer up to 5848 and reset. Displaced mud out of tubing to APR valve at 5822 with nitrogen, closed circ port. Open test tool, pressure acid to 3500 PSI. Uncertain if acid went into formation. Wait on acid 30 mins. Open well to flow on 24/64 choke. Bled off nitrogen from 3500 to 1800 PSI in 41 mins.* Press build up to 1850 PSI. Open well to flow on various chokes up to 24/64, press dropped from 1850 PSI to slight blow through bubble hose with choke closed. In 90 mins pressure increased to 310 PSI. Open well on 24/64 choke to clean up. Pressure varied from 100-500 PSI with intermittent surges of mud. Nitrogen cut acid water and some gas that would burn intermittently at flare. At 0600 the gas increased to a more steady burn at flare. Measured gas flow of' 475 MCFD with some clean up fluid - 25,000 PPm chlorides pH 7 6% sediment. Will continue to clean up well. *After line which reads "...1800 PSI in 41 mins" insert the following line - "Shut in for ISIP at surface for 75 mins. 8-14-82 PBTD 6680 OTD 9529 Flowing well to clean up. W/erratic tubing pressures 80-200 PSI on fully open choke, unloading mud and excessive amounts of sand. Shut in well @ 0300 8-15-82 for BHP. Unable to measure flow rate due to mud and sand. 8-15-82 PBTD 6680 Finish shut in period, kill well, start out of hole w/ test tool. 8-16-82 Finish COOH w/ test tool, GIH w/bit and scraper Wash & drill'sand bridgers 5870-6598, Plan to isolate Perf interval 6070-6084, ~6158-6175 and test same. 8-17-82 Finish COOH with bit and scraper, ran Howco bridge plug set at 6180, Howco retainer set at 6054, dis- placed mud out of tubing with nitrogen. Sting into retainer, flow back nitrogren cushion. Well open 10 hours on open choke, with no flow, very slight gas vapor at surface. Prepare to acidize. DAILY REPORT DETAILED LEASE SRS TERN A WELL NO. 1 SHEET NO. 7 TOTAL DATE DEPTH .8-18-82 PBTD 6680 8-19-82 PBTD 6680 8-20-82 NATURE OF WORK PERFORMED Mud 10.4, Vis 42, WL 6.0. Testing Perfs (6070-84, 6158-75) 1 hr. 0 press on tubing. Very slight gas blow at surface. Acidized same interval w/924 gal, 7½% HCL, 1134 gal mud acid (7½% HCL - 1½% HF). Initial pump in pressure 2300 PSI @ IBPM, Final press 1600 PSI, IBPM. Job complete @ 1030. Displaced mud out of tubing w/nitrogen, displacement press 2700 PSI Open to flow back nitrogen cushion at 1202 hrs. Tubing pressure dropped to 0 in 1 hr (1300 hrs). No gas or fluid to surface. Well open 8 hrs, w/no flow, completely dead. Presently preparing to test next interval 5592-5602. Field readings on Howco press recorders. First flow period: IHP 3344.5 PSI, IFP 1178.4 PSI, FFP 1178.4 PSI. After acid job - IFP 1056.0 PSI, FFP 1300.7, FHP 3327.0 PSI. Mud Wt 10.4, Vis 41, %~ 6. Set BP @ 5800. Perfor- ated 4SPF 5592-5602 10'. Set packer @ 5577. Made weekly BOP test. GIH w/ testing equipment, displace mud out of tubing w/ nitrogen. Set into packer, unload nitrogen, initial press 2480 PSI @ 1944 hrs, Bleed to 0 at 2032 hrs. GTS at 2035 hrs. Very slight amount of gas, too small to measure, well unloaded intermittant surges of fluid 2200-0200 hrs. Dead. 2 hrs PU out of packer, reversed tubing. Loaded tubing w/ 126 gal 7½% HCL, 294 gal 7½% HCL 1½% HF w/ water spacer before and after. Displaced to Btm of tubing. Set into packer. Pumped into formation, initial press 1300 PSI at 1BPM. Final press 900 at 1BPM. Job complete at 0557 hrs. Produced fluid check: chlorides 5940 PPM, P.H. 7-8, Wt 8.7. Displace tubing with nitrogen, set into packer at 071~ hrs. Flow back nitrogen 1P 2480 to 0 tubing pressure at 0758 with slight amount of gas to surface. 1015 started unloading small amount of fluid with very small amount of gas. Well open total of 12 hours. Flowing rate of water 3.19 Bbls/day with gas too small to measure. Kill well. COOH with tubing'. '~Perf. 5230-36, 5260-64 4SPF 10' net. Set packer 5220. Present operation preparing to GIH with tubing to tes~ Test flow pressure field readings (Howco recorder): 1HP 3117.2, 1FP 1125.9, FFP 2365.09. After acid treatment: 1FP 1129.9, FFP 2365.09, FHP 3082.2, Field check on produced water: chlorides 9410 PPM PH 7 to 8, WT 8.3 plus DAILY REPORT DETAILED LEASE DATE 8-21-82 8-22-82 8-23-82 SRS TERN A TOTAL DEPTH 8-24-82 WELL NO. 1 SHEET NO. 8 NATURE OF WORK PERFORMBD Test interval No. 4 5230-36, 5260-64. Had very small amount of gas to surface, barely enough to sustain flame. No fluid to surface. Tool open for flow period 1414 hours to 2030 hours. Acidized with 126 gallons 7½% HCL, 294 gallons HF, initial pump pressure 2000 PSI - final 1100 PSI at 1 BPM. Tool open for 8½ hours. Small amount of gas. Not enough to sustain constant flame. Terminated test. COOH. Field'readings Howco recorder - interval 5230-36, 5260-64 IHP 2879.4 IFP 348.5 PSI FFP 540.3 PSI. After acid job - IFP 122.0 FFP 122.0 FHP 2879.4 Tool plugged. Perf test interval No. 5. 5102-06, 5142-46, 5172-78 4SPF set packer at 5090. Displaced tubing with nitrogen. Well open for flow period 8~ hours. No fluid or gas to surface. Acidized with 210 gallo 7½% HCL/420 Gallons 7½% HCL - 1½% HF. Initial pump pressure 1200 PSI, final 600 PSI at 1 BPM. Dis- place tubing with nitrogen, well open 4½ hours on 64/64 choke with no flow of any gas or fluid to surface. Terminated test. Preparing to test in- terval No. 6 4934-4962. Field readings on Howco recorder for interval 5102- 5178 IHP - 2802.5 PSI IFP - 441.7 FFP 652.7 Chart shows intermittent plugging. After acid job - IFP 388.7 PSI, FFP 477.1 PSI, FHP 2802.5 Chart showed plugging. Intervals tested. No. 1 5868-6256 388' Gross No. 2 6070-6158 105' Gross No. 3 5592-5602 10' Gross No. 4 5230-5264 34' Gross No. 5 5102-5178 76' Gross 87 net 31 net 10 net 10 net 14 net No. 6 will be 4934-4962 28' Gross 28 net Perf 4934-4962 4SPF 28'. Set'packer~at 4914. GIH with 'tubing test tools, displace tubing with nitrogen, displacement pressure 2300 PSI. Flow back nitrogen cushion from 2300 PSI to 0 pressure in 45 mins at 1446 hours. Open to flow 3 hours 45 mins with no fluid or gas to surface at 1830. Pick up out of packer to reverse circ, tubing was full of water, reversed out approx 40 Bbl$ of slightly gas cut formation water. Chlorides 200 ppm PH 8. COOH with tubing. Clocks on recorders were stopped. Reran tubing and tools to retest for BHP. DAILY REPORT DETAILED LEASE SRS TERN A WELL NO. 1 SHEET NO. 9 DATE TOTAL DEPTH NATURE OF WORK PERFORMED 8-25-82 8-26-82 8-27-82 8-28-82 8-29-82 8-30-82 Well open to flow 3 hrs. No flow indications at surface. Pulled out of packer. Loaded tubing with water. Unable to pump into formation at 4000 PSI. Terminated testing. COOH. Lay down test equipment. GIH open ended. Spotted 20 sax cement. Plug top of retainer at 4914. Proceeding to P and A. Lay down 3½ tubing, nipple down BOP's. Cut off 7" at 570'. Start pulling 7" casing. P & A operations. Cut 9 5/8" at 370', 13 3/8 at 185'. Spotted 200 sx class "G" cement plug at 670' RKB. Tag top of cement at 295'. Top too low. Spot another 70 sx plug at 295. Presently cutting 20" casing. PTD 0 Well plugged. Cut and retrieved 20 and 30 inch casings with no problems. Finish laying down equipment and prepare for move. Rig released at 1430 hours 8/28/82. This is the final report for the subject well. Suggested form to be inserted in each "Active" well folder to check for timely compliance with our regulations. ' -oporto,, Well Name and Number ' Reports and Materials to be received by: Required Date Received Remarks ...C°mpleti°n . Report.Yes Well History Yes ?_/ ............ ' · ,. -s~s 7~.~.,~ _'5 - , , , ~u~ ~,~ ,.. \/~s'-"PI _ Core Chips :e ~ , Core Description 7 C~3 ?"-':N -"~ ~''' 0 K , , RegistereS Survey Plat ~/ _. ....... .,,.,: ............ ~_..., ., Inclznatzon su~ey ' '~..: Dire~ional~ey ~'Yl ,.,.Drill St~ Test Re~s y~'$ ...... MEMOR/ NDUM of Alaska TO: Commi s s ioner FROM' Edgar W Petroleum Inspector ALASKA O~L AND GAS CONSERVATION COMMISSION C, DATE: C. terton September 15, 1982 Ch a i~m~ n FILE NO: 108A/3 TELEPHONE NO: SUBJECT: Witness Plug and Abandonmen on Phillips SRS Tern A #I Penrod 96 Upper Cook Inlet Sec. 19, T10N, R10W, SM Permit No. #82-42 Tuesday.,. August 24,_ 1982 - I traveled via ERA Helicopter from Anchorage to Phillips SRS Tern A No. 1, Penrod 96 to witness a plug and abandonment. When I arrived at the rig they were in the process of reversing the cement out of the drill pipe. The top of the retainer was at 4,914 (Cook Inlet zone). The 7" casing was cut at 570', the 9 5/8" casing was cut at 370', the 13 3/8" casing was cut at 185' (all depths RKB), There was a cement plug laid from inside the 7" to above the 9 5/8M stub (plug 670' to 200' RKB or .500' to 30'below mud line. The above cement plug was tested with 10,000 pounds spudded on top of the plug. (See attached drawings). There is an attached drawing of the cut off and cement plug. I filled out the AoOoGoC.C. plug and abandonment report which is attached. In summary, I witnessed the plug and abandonment on Phillips SRS Tern No. A #1, Penrod 96 Drilling Company. 02-O01A(Rev.lO/79) O&G #6 4/80 STATE ~)F ALASKA OIL & GAS C©NSERVATION COMMISi,~ Plug & Abandonment Report ON Operator Company Repr Date Drilling Permit Lease No.~FR~ 'Tg~,,,'%' Well No. ~L Sec. Total Depth ~"'..~"QL.'5' Elevation i7o/~ ~'~,~ I~,~: Mud Casing: Drive Pipe "O.D. Set at ;2~/ Ft. w/ Conductor "O.D. @ 4 6~ Ft. Surface [ .~,, ~/~,' "O.D. @ /D ~f Ft. Intermediate "O.D. Ft. Production ~/ "O.D. @ &7:6~ Ft. Plugging Data: 2. Open hole isolation plug er ora ,on 4. Annulus plugs (if any): 5. Casing stub plugs: 6. Surface plug: Casing removal: "casing cut at ~' ~/~ ' . ,.~<' ?-:-: "casing cut at ~0 ' "casing cut at ] ~'3 Inspector/s: PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., CIRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area September 1, 1982 File: A-JFS-359-82 CERTIFIED #P13 1753569 RETURN RECEIPT REQUESTED Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: SRS TERN A NO. 1 Attached, in duplicate, is Form 10-403 (Sundry Notices .... Subsequent Report) con- cerning the plugging and abandonment of the subject well. This is the final Form 10-403 for the well. If you have any questions, please call us at 279-0606, JFS/TEM:kd Attachments - 2 . ALASK' '")IL AND GAS SERVATIOh' 9MMISSION ,SUHDRY('4OTICES AND REPOt( "'S OH WELLS DRILLING WELL COMPLETED WELL D OTHER N~me of Operator Phillips Petroleum Company 3. Address 2525 C Street, Suite 508, Anchorage, Alaska 99503 Location of Well 636 FWL & 585 FNL Sec 19-10N-10W, SM 5. Elevation in feet (indicate KB, DF, etc.) 84 12. 6. Lease Designation and Serial No. ADC 59343 7. Permit NO. 82-42 APl Number 50- 733-20353 Unit or I, ease Name SRS Tern A 10. Well Number 11. Field and Pool Wildcat Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: SUBSEOUENT REPORT OF:: (Submit in Triplicate) . (Submit in Duplicate) Perforate [] Alter Casing [] Perforations [] Altering Casing Stimulate [] Abandon r-] Stimulation [~ Abandonment Repair Well [] Change Plans [] Repairs Made [] Other Pull Tubing [] Other . [~ Pulling Tubing [] (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting an~ proposed work, for Abandonment see 20 AAC 25.105-170}. The well was abandoned as follows: 4914' RKB 4914 '-4826' RKB 570 ' RKB 370 ' RKB EZSV at Cement 7" casing cut at 9 5/8" casing cut at Cement covering 7" casing 7" stub 9 5/8" casing 400 ' BOF 200 ' BOF 9 5/8" stub and 13 3/8" casing 670'-295' RKB 500'-125' BOF Plug depth witnessed by Mr. Ed Sipple 13 3[8," .~.as$~g""-cut ~ 185 ' RKB 15 ' ,.BOF- 'cement covering 13 3/8" casing 295'-200' RKB do ~ C= ~e~i-125 ' -30: BOF 20" casing cut at 180' RKB i.}5' ~/sy I0' BOF 30" casing cut at 178' RKB 8' BOF All operations were completed and the rig released at ~%~i~ Sugust 28, 198'2... SEP 0 9 1982 ., Alaska 0il & Gas,, ,.,.~...~,,,.C°ns' Oo,nrnJss/or) Signed ~'~'~7'~/~ /-'(~T. F. Settle Title Area Manager below for Commission use ~-O'ndhions of Approval, if any: Date 9/1/82 By Order of · '- 22roi'ed by,__ CO?,MISSIOhJER lhe Commission ._ - :.,;m 10-4'03 Rev. 7-1-80 Submd "IntenT,otiS" mr. T~p;icale and "Subsequent Reporls" in Duplicate PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., CIRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area CERTIFIED P'I3 '1175357,1 ~ September 7, 1982 File: A-JFS-364-82 Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: SRS TERN A NO. 1 Pursuant to regulation 20 AAC 25.070(a)(2), attached is the August, 1982, "Monthly Report of Drilling...Operations",~ (Form 10-404) for the subject Well. This consti- tutes the final report for the well as it was plugged and abandoned during August. If you have any questions, please call us at 279-0606. J. F. Settle Area Manager JFS/TEM:kd Attachments - 2 RECEIVED SEP 0 ? 1982 Alaska 0il & Gas Cons. Commission Anchorage '"' - , STATE Or: ALASKA ~ ALASKA AND GAS CONSERVATION C(]( ,,VIlSSION MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS · Drilling well ~] Workover operation [] 2. Name of operator 7. Permit No. Phillips Petroleum Company 82-42 3. Address 8. APl Number 2525 C Street, Suite 508, Anchorage, Alaska 99503 50- 733-20353 4. Location of Well at surface 636' FWL & 585' FNL Sec 19 I0N 10W SM 5. Elevation in feet (indicate KB, DF, etc.) 84' :EKB 6. Lease Designation and Serial No. ADL 59343* 9. Unit or Lease Name SRS Tern A 10. Well No. 11. Field and Pool Wildcat *Conoco lease in SRS Drilling Unit operated by Phillips For the Month of. August ,19 82 2. Depth at end of month, footage drilled, fishing jobs, directional drilling problems, spud date, remarks Depth at month end 0, well plugged and abandoned. 8~" hole was drilled from 9128' to 9519'. Well was plugged back with 2 cement plugs, set at 9222' to 8970' and 7207' to 6973'. After testing, the' well was abandoned. Please see the attached form 10-403's as previously submitted for further plugging details. 13. Casing or liner run and quantities of cement, results of pressur9 tests 7" 32# N-80 casing was set from 6763' to surface. It was cememted with 275 sax class'G with .75% prehydrated gel, followed by 100 sax class G neat. The casing was internally tested to 1500 psi. 14. Coring resume and brief description 15. Logs run and depth where run The following logs were run: 1. DIL-BHC - Sonic - SP - GR 2. FDC-CNL - GR - Cal 3. HDT Bottom 9529 9532 9532 Depths Top 7600 S EP 0 9 1982 7675 4085~lasKa 0ii & Gas Cons. C0mn Anchorage 3 6. DST data, perforating data, shows of H2S, miscellaneous data Drill stem tests were run over the following intervals: DST #1 6250-6256 6184-6190 6158-6175 6070-6084 6034-6038 5972-5980 5938-5946 5900-5918 5868-5874 DST #2 Same interval DST #3 6158-6175, 6070-6084 DST #4 5592-5602 DST #5 5230-5236, 5260-5264 DST #6 5172-5178, 5142-5146, 5102-5106 DST #7 4934-4962 Further information is u~vai!ab!e at this t~e. 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. NOTE--Rgor; on(thi; f~rm is re~t~lired for each calendar month, regardless of the status of operations, and must be filed in duplicate with the Alaska Oil and Gas Conservation Commission by the 15th of the succeeding month, unless otherwise directed. Form 10-404 Rev. 7-1-80 Submit in duplicate ssi0r STATE OF ALASKA ALASKA ~,,. _ AND GAS CONSERVATION c/r3,. MISSION SUNDRY K. JTICES AND REPOR1%. ON WELLS DRILLING WELL COMPLETED WELL r-I OTHER [-I 2. Name of Operator 7. Permit No. Phillips Petroleum Company . 82-42 3. Address 8. APl Number -. 2525 'C' .S~reet, Suite '508, Anchorage, AK 99503 ' s0-733-20353 4. Location of Well ' 636 FWL & 585 FNL Sec 19L10N-10W, SM 5. Elevation in feet {indicate KB, DF, etc.) 84 6. Lease Designation and Serial No. ADC 59343 9. Unit or Lease Name SRS Tern A 10. Well Number 11. Field and Pool Wildcat 12. Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: SUBS'EQUENT REPORT OF: (Submit in Triplicate) (Submit in Duplicate) Perforate [] Alter Casing [] · Perforations [] Altering Casing Stimulate [] Abandon [] Stimulation [] Abandonment Repair Well [] Change Plans· '~ Repairs Made [] Other Pull Tubing [] Other [] Pulling Tubing D {Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) [] [] 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). Drilling was completed at a total depth of 9519'. Two (2) open hole plugs were set in the wellbore. The lower plug, 100 sax of class G cement, was set from 9222' to an estimated top of 8970'. The upper plug, another 100 sax of class G cement, was set from 7207' to 6973'. The top plug depth was verified by drill pipe measurement. 7" 32# N80 casing was set from 6763' to surface. The casing was cemented with 275 sax class G cement containing .75% prehydrated gel followed by 100 sax of class G neat. The top of the cement was determined via CBL log as 3830'. The well was perforated and tested in the following intervals: 6250-6256, 6184-6190, 6158-6175, 6070-6084', 6034-6038, 5972-5980, 5938-5946, 5900-5918, 5868-5874, 5592-5602, 5260-5264, 5230-5236, 5172-5178, 5142-5146, 5102-5106, and 4934-4962. All perforations were 4JSPF at 90° phasing. F6rther details on these will follow under separate cover. Halliburton EZSV cement retainers are at 6180, 6050, 5800, 5577, 5220, '5090,"and 4914. The retainer at 5090 has a 15 sax class G plug above it and the retainer at 4914 has a 20 sax class G plug above it. RECEIVED ' S£P 0 9 ]982 Alaska 0il & Gas Cons. Commission Signed ' Title Area ManaRer Anchorage Date 8/25/82 The e below for Commission use ions of Approval, if any: By Order o! Approved by COMMISSIONER ~he Commission Date Form 10-403 Rev. 7-14~0 Submit "Intentions" in T[~phcate and "Subsequent Reports" in Duplicate STATE OF ALASKA ALASK~ IL AND GAS CONSERVATION (~' ,VIMISSION SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL [] COMPLETED WELL [] 2. Name of Operator Phillips Petroleum Company 3. Address 2525 C Street, Suite 508, Anchorage, Alaska 99503 4. Location of Well 636 FWL & 585 FNL Sec 19-10N-lOW, SM 5. Elevation in feet (indicate KB, DF, etc.) 84 12. 6. Lease Designation and Serial No. ADC 59343 OTHER 7. Permit No. 82-42 8. APl Number so- 733-20353 9. Unit or Lease Name SRS Tern A 10. Well Number 11. Field and Pool Wildcat Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO' SUBSEQUENT REPORT OF: (Submit in Triplicate) (Submit in Duplicate) Perforate [] Alter Casing [] Perforations [] Altering Casing Stimulate [] Abandon [] Stimulation r-'l Abandonment Repair Well [] Change Plans [] Repairs Made I--I Other Pull Tubing [] Other [] Pulling Tubing [] (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). The well was abandoned as follows: EZSV at Cement 7" casing cut at 9 5/8" casing cut at Cement covering 7" casing 7" stub 9 5/8" casing 9 5/8" stub and 13 3/8" casing 670'-295' RKB Plug depth witnessed by Mr. Ed Sipple 13 3/8" casing cut at 185' RKB Cement covering 13 3/8" casing 295'-200' RKB 20" casing cut at 180' RKB 30" casing cut at 178' RKB 4914' RKB 4914'-4826' RKB .. 570' RKB 400' BOF 370' RKB 200' BOF 500'-125' BOF 15' BOF '125'-30' BOF 10' BOF 8' BOF 1982. All operations were completed and the rig released at 1430 hours Aug~ I VED SEP 0 ? 1982 !T 14. Ihere~~correct to the best of my knowledge. Signed -~'~- ~~~ F. Settle Title Area Manager below for CommisSion use ~-~itions of Approval if any: AJaska 0il & Gas Cons. Commission Date 9/1/82 By Order of Approved by COMMISSIONER the Commission Form 10-403 Date Rev. 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., ClRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area August 25, 1982 File: A-JFS-352-82 CERTIFIED P13-1753567 RETURN RECEIPT REQUESTED Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: SRS TERN A #1 Attached in duplicate is Form 10-403 (Sundry Notices...Subsequent Report) concerning the open hole plugging, casing, perforating and testing of the subject well. If you have any questions, p~ease call us at 279-0606. /~//J. F. Settle Area Manager JFS/TEM:mm Attachment RE E!VED Alaska 0il & Sas Cons, Commission Anchorage ~ STATE Of ALASKA (~] ALASKA ,- AND GAS CONSERVATION C .MISSION SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL COMPLETED WELL [] OTHER [] 2. Name of Operator Phillips Petroleum Company 3. Address 2525 'C' Street, Suite 508, Anchorage, AK 99503 REC~!VED~ 4. Location of Well " · 2 4982 636 FWL & 585 FNL Sec 19-10N-10W, SM Alaska Oil& GasCons. Corem, anchorage 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. 84 I ADC 59343 12. Check Appropriate Box To Indicate Nature of Notice, Report, or NOTICE OF INTENTION TO: (Submit in Triplicate) Perforate [] Alter Casing [] ~ Perforations Stimulate [] Abandon [] Stimulation Repair Well [] Change Plans [] Repairs Made Pull Tubing [] Other [] Pulling Tubing 7. Permit No. 82-42 8. APl Number 50- 733-20353 9. Unit or Lease Name SRS Tern A 10. Well Number 51]. Field and Pool sion Wildcat )ther Data SUBSEQUENT REPORT OF: (Submit in Duplicate) [] Altering Casing [] Abandonment (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) [] [] Other o [] 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). Drilling was completed at a total depth of 9519'. Two (2) open hole plugs were set in the wellbore. The lower plug, 100 sax of class G cement, was set from 9222' to an estimated top of 8970'. The upper plug, another 100 sax of class G cement, was set from 7207' to 6973'. The top plug depth was verified by drill pipe measurement. 7" 32# N80 casing was set from 6763' to surface. The casing was cemented with 275 sax class G cement containing .75% prehydrated gel followed by 100 sax of class G neat. The top of the cement was determined via CBL log as 3830'. The well was perforated and tested in the following intervals: 6250-6256, 6184-6190, 6158-6175, 6070-6084, 6034-6038, 5972-5980, 5938-5946, 5900-5918, 5868-5874, 5592-5602, 5260-5264, 5230-5236, 5172-5178, 5142-5146, 5102-5106, and 4934-4962. All perforations were 4.JSPF at 90° phasing. F6rther details on these will follow under separate cover. Halliburton EZSV cement retainers are at 6180, 6050, 5800, 5577, 5220;: .... The retainer at 5090 has a 15 sax class G plug above it and the retaine~'-~--'~"-]~ a 20 sax class G plug above it. 14. I here~/~lS~tify~nd correct to the best of my knowledge. Signed _- _ _ - -- _,_ . _ - Title Area Manager ~bel_ow for Co_m__rnissio_n use ~tions of Approval, if any: Date 8/25/82 Approved by COMMISSIONER By Order of the Commission Date - i Form 10-403 Rev. 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., CIRI BLDG. SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area August 25, 1982 File: A-JFS-357-82 CERTIFIED P13 1753568 RETURN RECEIPT REQUESTED Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: SRS TERN A #1 Attached is a print of the computed HDT log for the subject well. In accordance with 20 AAC 25.537(b), please treat this information as confidential. If you have any questions, please call us at 279-0606. ettle ~Area Manager .JFS/TEM:mm Attachment t £C£1V£D AUG 2 ~ ]982 Alaska 0il & Gas Cons. Commission Anchorage PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., CIRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area August 6, 1982 File: A-JFS-337-82 Alaska Oil & Gas Conservation Commission 3001 Porcupine-Drive Anchorage, AK 99501 RE: SRS TERN 'A' NO 1 Attached in triplicate is Form 10-403 (Sundry Notice...) outlining our proposed plans for perforating, testing and abandoning the subject well. This work is expected to begin about:.'8/O9/82 and be finished about 8/21/82. If you have any questions, please call. JFS/NEP:mm Attachment Received August 9, 1982 by ..-, ~ ~,~,. SIGNED BY LOItNIE C.; SMITH RECEIVED ~L STATE OF ALASKA (~, ALASKA AND GAS CONSERVATION C ,,MISSION SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL COMPLETED WELL [] 2. Name of Operator Phillips Petroleum Company 3. Address 2525 'C' Street, Suite 508, Anchorage, AK 99503 4. Location of Well 636 FWL & 585 FNL Sec 19-10N-10W, SM 5. Elevation in feet (indicate KB, DF, etc.) 84 6. Lease Designation and Serial No. ADC 59343 OTHER [] 7. Permit No. 82-42 8. APl Number 50- 733-20353 9. Unit or Lease Name SRS Tern A lO. Well Number 11. Field and Pool Wildcat 12. Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: SUBSEQUENT REPORT OF: (Submit in Triplicate) (Submit in Duplicate) Perforate ~ Alter Casing [] ~ Perforations [] Altering Casing [] Stimulate [] Abandon ~ Stimulation [] Abandonment [] Repair Well [] Change Plans [] Repairs Made [] Other [] Pull Tubing [] Other [] Pulling Tubing [] (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). Propose perforating and drill stem testing zones of interest in this well and then plugging and abandoning same. After each interval within a given formation is tested, a permanent bridge plug will be placed for isolation. To isolate different formations open to the well bore, we propose setting a permanent b~ldge plug (BP) and placing 50'+ of cement on top of the BP. After that we propose to cut the 7" csg off at 400' BOF (520' RKB)+. A cement plug will be placed to extend 100' above and below the 7" stub. 15,000# weight will be placed on this plug. The 9 5/8" would be cut at 200' BOF (370' RKB) and cement placed 100' below the stub, and 150' above the 9 5/8" stub. The 13 3/8" will be backed out of mud line suspension at 22'-BOF. Then the 20" and 30" will be cut 'off at the mudline and the rig moved off. RECEIVE[) Subsequer, t Work Reported on Form No.~~ Date~ ,~f~,~ '~ q' 1-3 ~ AUG 9 i982 Alas~,a 0il & Gas Cons. Commission Anchorage 14. I hereby c~y that the f~;~g is true a~correct to the best of my knowledge. Signed F. Settle Title Area Manager The spa~w for Commission use Con~l~fis of Approval, if any: Date 8/06/82 Approved by Approved Copy Returned ~-- COMMISSIONER the Commission Date Form 10-403 Rev, 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., CIRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area August 5, 1982 File: A-JFS-335-82 CERTIFIED P 13-1753564 RETURN RECEIPT REQUESTED Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: SRS TERN 'A' NO 1 This is to confirm our verbal request to change our drilling depth and 7" casing setting point on. the subject well. Form 10-403, in triplicate, accompanies this letter giving the details of the changes requested. Verbal approval to proceed as outlined in the Sundry Notice was given our Mr. Neal Porter by your Mr. Jim Trimble on 8/04/82. ~-~J. F. Settle Area Manager JFS/NEP: mm Attachments AUG - 9 1982 Alaska Oil & Gas Cons. Commission Anchorage C~L STATE OF ALASKA ~' ALASKA AND GAS CONSERVATION CO ,,vllSSION SUNDRY NOTICES AND REPORTS ON WELLS 1. DRILLING WELL~] COMPLETED WELL [] OTHER 2. Name of Operator 7. Permit No. Phillips Petroleum Company 82-42 3. Address 8. APl Number 2525 'C' Street, Suite 508, Anchorage, AK 99503 50- 733-20353 4. Location of Well 9. Unit or Lease Name SRS TERN 'A' 636' FWL & 585' FNL Sec 19-10N-10W, SM 5. Elevation in feet (indicate KB, DF, etc.) 84 6. Lease Designation and Serial No. ADL 59343 10. Well Number 1 11. Field and Pool Wildcat 12. (Submit in Triplicate) Perforate [] Alter Casing [] ~ Perforations Stimulate [] Abandon [] Stimulation Repair Well [] Change Plans ~] Repairs Made Pull Tubing [] Other [] Pulling Tubing (Note: Report multiple completions on Form 10-407 with a submitted Form 10-407 for each completion.) Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: SUBSEQUENT REPORT OF: (Submit in Duplicate) [] Altering Casing [] Abandonment [] Other [] [] [] 13. Describe Proposed or Completed Operations (Clearly state all pertinent details and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25.105-170). Propose to: 1. Discontinue drilling at 9259' RKB instead of 10,000' originally ~ permitted for. 2. Set open hole cement plug above the Tyonek formation to isolate it from Beluga formation above. Log top of Tyonek is 9118' RKB. Plug would be set from 9250' back to 8950' (100 Sx neat plug). 3. Set secondary cement plug in open hole at 7200' back to 6900' (100 Sx neat plug). 4. Set 7" 32# L80 casing as long string in the interval 6700'-±100' RKB rather than 10,000' originally contemplated. Cement 7" all the way back into the 9 5/8 intermediate casing which set at 4086 RKB. Verbal approval to proceed as outlined above was given by your Mr. Jim Trimble to Mr. Neal Porter on 8/04/82. Subsequent Work Reported on Form No.'~0'~/03 Dated 14. I hereby certify tha e fore oing is true and correct to the best of my knowledge. ,t,e Sr. AUG - 9 i982 Alas~ra 0il & Gas Cons. Commission Anchorage Date 8/05/82 Conditions of Approval, if any: [~Y [0~'II[ g, S~t]'H COMMISSIONER Approved by. Approved Copy Returned . By Order ot the Commission Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate Form 10-403 Rev. 7-1-80 PHILLIPS pETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., CIRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area August 5, 1982 File: A-JFS-333-82 CERTIFIED P13-1753562 RETURN RECEIPT REQUESTED Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: SRS TERN 'A' NO 1 Attached for your information and file are field prints of the following logs: . 1. DIL-SP-GR /2. Bulk D-GR / 3. BHC-GR v/4. CNL-FDC-GR 5. HDT from 9529 back to 7600' (2" & 5" scale) from 9532 back to 7600' (2" & 5" scale) from 9490 back to 7600' (2" & 5" scale) from 9532 back to 7600' (2" & 5" scale) from 9532 back to 4085' (5" scale only) In accordance with 20 AAC 25,537 (b), please treat the information tendered herewith as confidential. Final prints (plus sepias) will be submitted following completion 0f drilling activity. J. F. Settle Area Manager ,IFS/NE?: mm At t achmen t s cc Gordon Frisch - Denver PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., CIRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area August 4, 1982 File: A-JFS-332-82 CERTIFIED NO. P-13-1753558 RETURN RECEIPT REQUESTED Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: PHILLIPS SRS TERN A NO. 1 Pursuant to regulation 20AAC25.,070 (a)(2), attached is JulY, 1982, "Monthly Report of Drilling .... Operations," (Form 10-404) for the subject well. If you have any questions, please call us at 279-0606. JFS/NEP:kd Attachment cc: SRS I.G. RECEIVED AUG - 5 ]982 Alaska Oil & Gas Cons. Commission Anchorage STATE OF ALASKA ~ ALASKA ~.AND GAS CONSERVATION CC~ ~IISSION MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS · Drilling well Workover operation [] 2. Name of operator Phillips Petroleum Company 3. Address 2525 C Street, Suite 508, Anchorage, Alaska 99503 4. Location of Well at surface 636' FWL & 585' FNL Sec 19 I0N i0W SM 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. 84' RKBI ADL 59343* 7. Permit No. 82-42 8. APl Number 50- 733-20353 9. Unit or Lease Name SRS Tern A 10. Well No. 11. Field and Pool Wildcat *Conoco lease in SRS Drilling Unit o)erated by Phillips For the Month of July ,19 82 12. Depth at end of month, footage drilled, fishing jobs, directional drilling problems, spud date, remarks Well was spudded July 3, 1982 and was drilled to a total depth of 9128' at month.end. Hole sizes and total depths drilled during the month were 26" 480' 17~" 1247' -- ) 2 -- , 12¼" -4095' 8~" . , a - 9128' 13. Casing or liner run and quantities of cement, results of pressure tests The following casing strings were set during the month. Size & Grade Depth Cement Pressure Test 30" drive pipe 238'RKB None None 20" 133# J-55 470'RKB 500sx class G/2.5% gel None 500sx class G neat 13 3/8" 72# L-80 1236'RKB 500sx class G/2.5% gel 12.8# equivalent (cont. after #16) 14. Coring resume and brief description Two cores were cut during the month. Core 1, 5680'-5710', cut and recovered 30'. Core 2, 5713'-5740', cut and recovered 27'. Lithological descriptions are not available at. this time. 15. Logs run and depth where run The following logs were run during the month. No logs were run in the 26" and 17~"2 holes 12¼" hole Run 1 DISFL-SP-BHC-GR-cal 4078'-925' 8½" hole Run 1 DIL, SSL, BHC, SP, GR, cal 7913'- 3780' 2 FDC, CNL, NGT, cal 7915'-4085' 3 Prox Micro Log 7915'-4085' 16. DST data, perforating data, shows of H2S, miscellaneous data RECEIVED · '""~ -~ l,,~OZ No testing was done during the month. 13 a. 300sx class G neat Alaska 0ii & Gas Cons, Commissio~ A. churage 9 5/8" 47# SS~5/~-95 4086'RKB 450sx class G neat 13.0# equivalent 17. I hereb~rtify that the foregoing is~nd correct to the best of my knowledge. SIGNED Settle TITLE Area Manager DATE 8-3-82 NO crt on this form is required for each calendar month, regardless of the status of operations, and must be filed in duplicate with the Alaska Oil ~J~ias Conservation Commission by the 15th of the succeeding month, unless otherwise directed. Form 10~,04 Rev. 7-1-80 Submit in duplicate PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., CIRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area July 30, 1982 File: A-JFS-324-82 CERTIFIED P13-1753556 RETURN RECEIPT REQUESTED Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: SRS TERN 'A' NO 1 Attached for your information and file are 2" and 5" scale field prints of the following logs: 1. DIL-SP-GR 2. PROX-ML 3. BHC-GR 4. CNL-FDC-GR from 7913 back to'3780' from 7915 back to 4085' from 7913 back to 3780' from 7915 back to 4085' In accordance with 20 AAC 25,537 (b), please treat the information tendered herewith as confidential. Final prints (plus sepias).ii.~wit~l be submitted following completion of drilling activity. JFS/NEP: mm Attachments cc Letter Only to Gordon Frisch - Denver £CE!VED Alaska Oil & 6a$ Cons. 4nChorag~ bf~tTfll/S$iOi.1 PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., CIRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area CERTIFIED #P13 1753561 RETURN RECEIPT REQUESTED JulY 16,, 1982 File: A-JFS-319-82 Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Re: SRS Tern 'A' No. 1 This i.s to confirm verbal notice this'date given your Mr. Trimb!e by our Mr. Porter that a 3-1/16" -- 5000 psi W~ va!ve was installed 7/I5/82 on the bleed line leg of the choke manifold as~directed in your Field Inspection Report of ~7/10/82. This valve was tested to 5000 psi following installation. Very trulY yours, ~ .F. Settle Area Manager JFS/NEP/j h ~ MEMOR't NDUM St ,e of ';~ASKA OIL AND GAS CONSERVATION COMMISSION TO: C. '~a~terton THRU: Lonnie C Commi s sione r Alaska DATE: July 13, 1982 FILE NO: 103/B TELEPHONE NO: FROM: J. K. Trimbl~-- Petroleum Eng~nee r SUBJECT: Inspection of the Diverte r System Penrod 96, Phillips SRS Tern A-l, Sec. 19,"T10N, R10W, SM. Thursd_a.y, Ju!¥~ 8, 1982 - I left Anchorage at 8:15 a.m. by ERA ~eiicopter, arriVing on the Penrod 96 at 8:45 a.m. I inspected the diverter system and everything was in proper order. I did not witness testing as Phillips was running 13 3/8" casing during my visit. A 2000 psi diverter and a drilling spool with 8" outlets was used. The hydraulic control valv~ would open when the diverter closed. See the attached diverter schematic. I returned to Anchorage at 2: 00 p.m. In summry, I inspected the diverter system on the Penrod 9'6 and found the system satisfactory. 02-00 IA(Rev.10/79) MEMOR ,NDUM of Alaska ALASKA OIL AND GAS CONSERVATION COMMISSION TO: Co ~rton Cha T~U: Lonnie C. Smith Commi s sione r FROM: j. K. Trimbl~ Petroleum Engfneer DATE: July 13, 1982 FILE NO: 103/A TELEPHONE NO: SUBJECT: Witness of BOPE Test Phil lips' SRS Tern A-1 Sec. 19, T10N, R10W, SM, F~nrod 96, Jack-up Rig Permit No. 82-42 Satu. r.day, July 10i 1982- I left Anchorage via ERA ~elicopters arriving on the Penrod 96 at 11:15 a.m. for the purpose of witnessing the BOPE tests. Due to a decision to move the position of the blind rams to second from the top and other organizational activities tests started, at 5:50 p.m., finishing at 8:58 p.m. There ~re no leaks in preventers or va 1 ~ s. .~i requested that a valve be added to the choke manifold /blee~ line and that covers be put on the blind ram controls at the remote stations on the rig floor and in the quarters area. These remote controls also require the operation of an air valve handle simultaneously with the operation of the preventer or valve controls. See the attached schematic of the Penrod 96 choke manifold. The choke manifold is not strictly API and the instructions to Phillips and Penrod Drilling are also to provide double valves immediately ~stream of the two manual chokes prior to drilling another ~I1 under Commission jurisdiction. ~~~re are mitigating factors for the .lack of double valvin~ immediately upstream of the manual chokes in that for 5000 psi service, which is the usage for SRS Tern A-i, ~ that there is an extra manual choke and that there are 5000 psi valves downstream of the chokes. Consequently, it ~as decided, that the present coafiguration, with the addition of a second valve on the bleed line, would be allowed for this weI1 only. This was confirmed during a meeting July 12, 1982 between C. v. Chatterton, L. C., Smith, and J. K. Trimble of this office, Neal Porter of Phillips and A. C. Louviere of Penrod Drilling. Spnday., July !.1~.. 1.98.2 - I witnessed a leak off test on the shoe of the 13 3/8" and returned to Anchorage at 10:00 a.m. In summary, I witnessed the BOPE tests on Phillips SRS Tern A-1 and except for the change to be made in the cho"ke manifold, tests were satisfactory. 02-001/%(Rev.10/79) Ala Oil and Gas Co ..... u~Llon Co7~ ~on Field Inspcction of Bl~,:ou~ Pucvo. nkion Equipment Inspector Operator Date 7--~O--~ ~ Represenhativo~~_ Nell. ~.~ --~~ ~'( Drilling Con%r;[c[or ~~~~ Location, General Wel 1. Sign -_ .-.~. General itousekecping ~eserve pit_ ~~ BOPE Stad~ Annular Preventer Pipe Rams Blind Rams Choke Lb~e Valves H.C.R. Valve Kill Line Valves C~eck Valve Test Pressure PeN:tit # ~ ACC~P~J~R SYSTE74 Full Cha-ge Pressure .... Z~~ psig Press~e After Clost~c. ] ~ ~O ps!.g 200 psig A~ve Pred~arge Atta.ined: ~..min ~s( Full Olarge Pressure Attained: ~ __ min~s~ ConSols: Master }temo~a_~, Blinis z~.;itd~ cover~~ Kelly and Ficcr o~ ..... ~y Valves Up~r I<ell]~~.. Test pressur~ Ball Ty~'e ~ Test Pressure ~oke [~anL~_old~%e,. ~ Pressure No. Valves No. flanges Adj~t~le Chokes ~li,'drauJ cai. ].y operated chd~e .[eot Results: '--- Repair or Replac~nent of failed ~x]uipnen~. to be m~ie wi"i~in ~ days and I~[mctor/C~mission office notified. cc - Field O~rahor/SlllL'~rvisor Y--; ~--~ Drillin De t Su"=rin~-endent " cc - - -g - P · ~ - _ ....... PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., CIRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area July 9, 1982 File: A-JFS-312-82 CERTIFIED #P13 1753551 RETURN RECEIPT REQUESTED Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: SRS TERN 'A' NO. 1 Pursuant to 20AAC25.005 (c)(2), attached is a certified plat showing the precise surface location of the subject exploratory well. tie Area Manager JFS/NEP:kd cC: T. J. Jobin W/attachment C..FjelstuI W/attachment file SRS I. 'G. ISEC£!VED JUL I 21982 Alaska Oil & ~a~ Cons. Commission ncl~orage 14 23 26 13 24 25 19 35 36 TION T9N I I AS-BUILT SRS UNIT TERN 'A LAT. = 60o56' 54'. 99" LONG. =151 007'4 I. 40" X = 299~ 426 ! WELL No. I 21 22 30 29 28 27 32 I SCALE I" = I MILE CEIVED CERTIFICATE OF SURVEYOR I hereby certify thor I om properly registered ond licensed to proctice Iond surveying in the Store of Alosko (]nd thor this pl(]t represents o Ioc(]fion survey mode by me or under my direct supervision ond th(]t (]11 ,det(]ils ore correct. ,/ '-' ,,, f, - ,,, * ' ,, , ',.,,,,;f DATE SURVEYOR" JUL 1 21982 Alaska Oil & Gas Cons, CommisSion Anchorage, AS-BUILT WELL LOCATION SRS UNIT TERN A WELL NO. I LOCATED IN SECTION 19, T ION, R IOW, S.M., AK. FOR PHILLIPS PETROLEM COMPANY BY BESS E, EPPS & POTTS ANCHORAGE, ALASKA 349- 6451 PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., ClRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area July 2, 1982 FILE: A-JFS-306-82 CERTIFIED NO. P13-1753550 RETURN RECEIPT REQUESTED Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: PHILLIPS SRS TERN A NO. 1 Pursuant to regulation 20AAC25,070 (a) (2), attached is June, 1982, "Monthly Report of Drilling...Operations," (Form 10-404) for the subject well. This is the initial report. If you have any questions, please call us at 279-0606. J. F. S~ nager JFS/N~/m~ Attachment cc: SRS I.G. RECEIVED J U L - 6 1982 Alaska Oil & Gas Cons. ComrilJssJorl Anchorage - STATE OF ALASKA ' ALASKA(~ ~,ND GAS CONSERVATION CO( ISSION MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS · Drilling well ~] Workover operation [] 2. Name of operator 7, Permit No. Phillips Petroleum Co. 82-42 3. Address 8. APl Number 2525 "C" Street, Suite 508, Anchorage, AK 99503 50-733-20353 4. Location of Well atsurface 587' FNL* & 643' FWL* Sec 19-10N-10W, SM * as placed survey will be made soon 5. Elevation in feet (indicate KB, DF, etc.) 84' RKB 6. Lease Designation and Serial No. ADL 59343* 9. Unit or Lease Name SRS Tern A 10. Well No. 11. Field and Pool Wildcat *Conoco lease in SRS Drilling Unit operated by Phillips For the Month of June ,19 82 ~12. Depth at end of month, footage drilled, fishing jobs, directional drilling problems, spud date, remarks Depth 0. Positioned rig on location 6/23/82. Provision rig. structural casing at month end. Rig up to drive 30" 13. Casing or liner run and quantities of cement, results of pressur9 tests t4. Coring resume and brief description 15. Logs run and depth where run 16. DST data, perforating data, shows of H2S, miscellaneous data JUL-6 i98'2 Alaska 0il & Gas Cons. Commission Anchorage 7.1 her~,.~ertify thaty~j~ing i~ tru,~d correct to the best of my knowledge. ~SIG Settle TITHE Area Manager DATE July 2 1982 NC~--Report on this form is required for each calendar month, regardless of the status of operations, and must be filed in duplicate with the Alaska Oil and Gas Conservation Commission by the 15th of the succeeding month, unless otherwise directed. Form 10-404 Rev. 7-1-80 Submit in duplicate ~ay 13, 1982 Mr. J. F. Settle Area Manager Phillips Petroleum Company 2525 O Street, Suite 505 Anchorage, Alaska 99503 Phil lips Petroleur~ Company Pemit Ho. 82-42 Sur. Loc, 5$0'FI~L, $~.0*FI~L, Sec 19, TI0t/, R10W, Btmhole Loc. 560'FNL, 520'FWL, Sec 19, TION, R10W, Dear Ur. Settle; Enclosed is the approved application for pemit to drill the above referenced well. Well ssmples and a mud 1o~ are required. An inclination survey is required as per 20 AAC 25.050(b)(5). If available, a tape eontsinlng the dtt~ltized log information shall be subr~itted on all lo~s for copyin~ except expertraental logs, velocity surveys and dieter surveys, ~ny rivers in Alaska and their draina/~e syst~s have. been classified as important for the spawning or migration of anadr~mus fish. Operations in these areas are subject to AS 16.0.§.$?0 and the repletions pr~ulgated thereunder (Title 5, Alaska A~tn.ist~ative Code). Prior to c~encing operations you may be contacted by tho Habitat ~ordtnator's Office, Department of Fish and Ga~e. Pollution of any waters of the State is prohibited by AS 46, Chapter 3, Article ? and the regulations promulgated thereunder (Title 18, Alaska Administrative Code, Chapter 70) and by the Federal Water PollutiOn Control Act, as amended. Prior to commencing operations you may be contacted by a representative of the Department of Environmental Conservation. To aid us in scheduling field work, we would appreciate your notifying this office within 48 hours after the well is spudded. ~e would al so like to be notified so that a representative of the Commission may be present to ~itness Mr. J. F. Settl -2- SES Tern A No, 1 t~/ay 1:3, 1982 testing of blowout preventer equipment before surface casing Shoe ts drilled. In the event of suspension or abandonment, please give this office adequate advanoe notification so that we may have a wi tness' present. Very truly yours, C. V. Chatterton Chairman of BY ORDER O~ THE CO~l$SION Alaska Oil and Gas Conservation Comission ~ne 1 osure Department of Fish & Game, Habitat Section w/o enel. Department of Environmental Conservation w/o encl. CrC:be STATE OF ALASKA ALASK/( IL AND GAS CONSERVATION ~' VIMISSION PERMIT TO DRILL 20 AAC 25.005 la. Type of work. DRILL REDRILL DEEPEN lb. Type of well 2. Name of operator PHILLIPS PETROLEUM COMPANY 3. Address 2525 "C" gtreet.. Suite 508 4. Location of well at surface 560' FNL & 520' FWL Sec 19-10N-10W-SM At,top of proposed producing interval Same At total depth EXPLORATORY ~] DEVELOPMENT OIL [] DEVELOPMENT GAS [] SERVICE [] STRATIGRAPHIC [-] SINGLE ZONE I'-I MULTIPLE ZONE [] S~me Anchorage, Alaska 99503 5. Elevation in feet (indicate KB, DF etc.) I 6. Lease designation and serial no. RW~ 9~' abn.vm NT.T.W J AnT, 5q343 12. Bond information (see 20 AAC 25.025) Type ]~3 ~n~_t- Surety and/or number 13. Distance and direction from nearest town 14. Distance to nearest property or lease line Unit Bndr¥ 17. Number of ~cres in lease miles _.~TN_ E 27 16. Proposed depth (MD & TVD) 10, O00BOF (MD&TVD) feet 2'560 19. If deviated (see 20 AAC 25.050) KICK OFF POINT NA feet. MAXIMUM HOLE ANGLE NA SIZE Casing Weight 21 ...... Hole 36 26 1'7.5 30 20 13.375 9.625 7 12.25 8.5 196 133 72 47 .8231 feet, 20. Anticipated pressures o I (see 20 AAC 25.035 (c) (2) Proposed Casing, Liner and. Cementing Program CASING AND LINER Grade /Coupling! Length B Weld 1250 K I~Tc 1450 L I~TC 11200 .c/ss L ILTC 110200 SETTING DEPTH MD TOP TVD RKB ~ RKB RKB ~RKB 9. Unit or lease name SRS/Tern 'A' 10. Well number ] 11. Field and pool Semi-Wildcat Amount 15. Distance t6 nea-r~st ~rR~~ddr we,. /; 30,7 feet 18, Approximate spud date ! June, !982 AR{~ psig@ O ! Surface 5600 psigL~0,000 ft. TD (TVD) QUANTITY OF CEMENT (include stage data) 1000 Sx ~ ~r,]le~ 1000 Sx 800 Sx 400 Sx MD BOTTOM TVD 25o', 250 4501 450' ].200 1!200 300 Sx or 1,50/,250. 32 22.' Describe proposed program: 4200 .! 4200 0200 ~110200' See Attachment for detailed program. ,, P, ECEIVEb [,,'7/:i? ,~: 6,lc:'~2 A!aska Oil & Gas Cons. Commissio~ 23. I hereby cej;t~y that the foregoing, is true and_corOt to the best of my knowledge SIGNED - F. Settle TITLE Area Manager The sp~;~ow for Commission use' CONDITIONS OF APPROVAL Samples required Mud log required I Directional Survey required I APl number eYES ~]NO ~YES []NO t •YES [~NO -. Ap I t ' ' Permit number ~ ~ % J~/~2 I SEE COVER LETTER FOR OTHER REQUIREMENTS b~ order of the Commission / Form 10-401 Submit in triplicate Rev. 7-1-80 'PROPOSED / WELL No.I I /18. 560' FNL & 520' FWL- 2:5 24/ ~ , _ ,/ / / / Tg.N' ~/~ ~/~ V4 0 i/= I MLLW DATUM SCALE IN MILES I" = I MILE FROM U.S.G.S. ia 65t$60 SCALE MAPS KENAI (D-4) AND C.&G.S. 8.555 × X x RECEIVE M.H.W.. ~ka Oil & 6as Cons. Coa M.L.L.W · O' /~c,horag~ ' BOTTOM LINE · 80'- 90' RIG. TYPE - JACKUP SRS UNIT TERN A WELL No. I EXPLORATORY DRILLING PROJECT North Cook Inlet Alaska n~.ss~o~ Miles SSE of Tyonek Village Phillips Petroleum Company 2525 C STREET SUITE 508 ANCHORAGE, ALASKA Dote; 1/25/82 ,ol ,, I ,, I,-, I.- i ,, 4- -- _L I I- -- -I- -- - I RI ---I I I I I ,, I 10 II 12 ADL 159554 32 I 33 ADL 59548 AOL b9542 ..-.L .......... AOL [59541 EXPLORATORY DRILLING PROJECT SRS- DRILLING UNIT NORTH COOK INLET ALASKA ....... Phillips Petroleum Company - Operator 2525 C STREET SUITE 508 ANCHORAGE ~ ALASKA Date: 1/25/82 Scale: I/2"= I MILE · ,, i ttachment I SURFACE TESTING EQUIPMENT Surface testing equipment will be arranged as follows: KILL LI SURFACE TEST STEAM INLET ADJUSTABLE CHOKE HEAT EXCHANGER SURFACE SAFETY VALVE POSITIVE MANUAL · CHOKE OUTLET GAS LINE DATA ADJUSTABLE CHOKE HEADER .... . TEST LAB WIRELINE UNIT ,I [] PRODUCTION P! OIL O GAS D STEAM l'-'] WATER O AIR GAS METER SEPARATOR PUMP OIL METER OUTLET FLARE BURNER RIG WATER PUMP The equipment will include as required*: 1, 1.5 MM BTU/hr..Steam heat exchanger. 5000.psis:W, P. 1 3-phase Horizontal.Separator 1440 WP, 80 MMSCF/day and 10,000 BOPD Capacity 2 Centrifugal transfer pumps, 10,000 BPD capacity with explosion-proof motor. 2 CB-12 Burners capable of burning 12,000 BPD per burner. 1 100 bbl. Cylindrical Test Tank, 50 psig WP w/sight glass, relief valves and level switches'. 1 Data Header, 5,000 psi W.P., complete with sampling and date recording 1 Choke manifold w/an adjustable choke and a positive choke, 5,000 psi W.P. Substitutions, deletions or additions will be made based on drilling experience. E C ": 'P=;i L I',~ £ "=--ADAPIER -'---BAR DROP SUB ' FLO '.TEE' -_'--J-~-- ~.-:;-MANIFdLD ] ~i? - '". "~(~.~-~;'~-F LOW ' ~_~ . ' ~" tildE' _._J-<-'PRESSURE BALANCED '' __.~-'~--MAST ER VALVE - ~_,,~,~ ...: . · .m..~o,,L~ ~,~:.'-...:-- .....' · ... · o ' ~ REVERSE SUB ~ rOUA~ c~os~, ,, i o.,~J , REVEflSE PORIS CIRCULATION L~''" . . C:~.~,~.?G s,o 6 CHOKE lootu~LT (OPIIONIL). i~IYOflOSPRIIIO T[ STIR o~J~BY- PAss ~OR~S ,~._~ ~IAP 1YP[) . - ~HYDR~UL lC JAR [~--VR SAFETY JOINT' L,O~'' BT-PASS PORTS =~/NCHOR PIPE'.AF[TY JOINT ~ ~B.T. P~.~SUR[ N[CORDER DST TOOL HOOK-UP' · Oil & Gas Cons. Attachment I-i Page 2 ...J Attachment F ' DIASEAL M'(';_OST CIRCULA("'ION MATERIAL TECHNICAL SERVICES DIVISION · BARTLESVILLE, OKLAHOMA DIASEAL M Pattern For A Successful Squeeze .This report concerns test results on the use of Diaseal M high water loss slurries in the Gulf Coast area. In the past year over 100 Diaseal M squeeze jobs were run to combat lost circUlation in the Gulf Coast area. The results indicate it is possible to obtain a successful squeeze job every time if the proper procedure is followed. The following analysis of 36 representative tests clearly shows the importance of starting a squeeze job with an adequate volume of slurry. No. Of No. Of Squeezes Successes Slurry Volume 8 2 Less than that of open hole. 10 5 Equal to that of open hole. 10 8 Slightly more than that of open hole 8 8 At-least double that of operr hole. As can be seen from the foregoing a successful squeeze can be virtually assured .by using a slurry volume at least twice that of the open hole to be squeezed, or a minimum of 100 bbL Under these conditions, the following procedure should be followed: 1. Mix slurry according to Table, adding Diaseai.M, barite and lost circulation material in order. This mixture of inert materials has the highest possible waterloSs of any known weighted lost circulation slurry of which we know, in any kind of water. A mixing truck is desirable. Trademark FORMULA FOR PREPARING ONE BARREL DIASEAL M WEIGHTED SLURRY WITH FRESH WATER, BAY OR SEAWATER Density DIASEAL M Barite* Water Lb./Gal. Lb. Sack Sack BBL. 9 50 1.00 0 .87 10 50 1.00 0.6 .84 11 47 .94 1.2 .80 12 42 .84 1.8 .77 13 38 .76 2.3 .74 14 ......... 34 .... 6.8 2.9 . .70 15 31 .62 3.5 .67 16 28 .56 4.0 .63 17 25 .50 4.6 ,60 18 22 .44 5.2 .56 19 17 .34 5.8 .52 EXAMPLE i00 bbl. of 14 lb./gal. DIASEAL M slurry requires 68 sacks DIASEAL M, 290 sacks barite, 70 bbl. water and nut shells if desired. (25 lb./bbl, of nut shells can be used ir4 the above formulations without change. If water absorbing los1 circulation materials are added, the slurry viscosity will increase. This slurry is effective without conven- tional lost circulation materials.) *If saturated salt water is used, barite must bE decreased 0.6 sack per barrel. 0877 (3) Attachment 2. Place bottom of drill pipe far enough into casing to displace all of slurry into open hole and bottom of casing. Do not squeeze through bit openings less than 5/8" diameter with lost circulation .rna~terial in 'slurry. Squeezing open ended is desirable. 3. Pick up slUrry'with pump truck and displace it out of drill pipe with mud. Half of slurry will be in open hole, and equal amount will be in casing below drill pipe. When slurry starts out of drill pipe, · blowout preventers should be closed. Make sure annulus is full. If RTTS tool is used, it should be set. This prevents migration. When slurry hits open hole, slow pump down to 1/2 to 3/4 bbl./min. 4. After drill Pipe is cleared; stage slurry into formation, a few barrels ~it a time, pumping at a · rate of 1/4 bbl./min., hesitating for several minutes. Continue this cycle until pressure begins to build. Expect initial pressure build-ups and'bleedoffs. A final holding pressure of 300-900 psi is desirable. 5. Hold pressure for two hours before releasing and resuming operations. . _Ream out cake in open hole. Excess slurry willnot contaminate mud system, nor will it PlUg hole permanently like cement or materials that react chemically. A~ mud is c!,culated zones, the highly permeable Diaseal M cake is covered by a mud cake of Iow permeability. This is the "icing on the cake", the final seal off. If the above procedure is followed with no deviation, and enough slurry volume is used, the Di~Seal M squeeze can be expected to be virtually 100% successful. DRILLING SPECIALTIES COMPANY BARTLE SVILLE. O K LAH O MA 74 O 04 This bulletin reports accurate and reliable information to the best of ourknowledge, Drilling Specialties Company assumes no obligation or liability for the use of the information presented herein. (4~ Attachment F ( f' Page 1 LOST CIRCULATION PROCEDURE DIASEAL M is never added to the drilling mud nor is it slurried as a pill in drilling mud. It is always mixed with fresh, salty, or salt saturated water. It is always pumped as a separate pill but is preceded and followed by drilling mud. The amount to be used varies from 25 to 200 barrels depending upon the amount of open hole and experience in the area. Some operators use twice the open hole volume as a guide. Conventional lost circulation material such as nuthulls or fibers can be added to the slurry. Successful jobs have been done with and without the addition of these conventional lost circulation materials. Ten lb/ bbl of fibrous material such as KWIK-SEAL or twenty lb/bbl of medium nut hulls such as NUT-PLUG are recommended. The general procedure for using DIASEAL M when circulation is lost is as follows: 1. Pull off bottom or just about the loss zone, put the kelly back on and continue to work the pipe. 2. Mix the slurry as conditions dictate. If pill is to be. mixed in suction pit, run necessary amount of water into pit with guns on pit. As water fills suction pit, begin opening sacks of DIASEAL M and mix contents with water by maximum agitation from guns. As slurry becomes viscous, begin addition of lost circulation material. If DIASEAL M slurry is already mixed and being held in readiness in standby pit, agitate vigorously, add lost circulation material if it has not already been added. Slurry is ready for use when thoroughly mixed and agitated. 3. When mixing is complete, pump the mixture in the hole and displace the slurry from the pipe with mud. 4. Pull up above the casing shoe and fill the hole with mud through the fill-up line. 5. If the hole does not fill with one foot of mud out of pits, mix another pit of DIASEAL M slurry, and repeat procedure. 6. If the hole does fill, proceed as follows: a. For depths less than 7000 feet, close the pipe rams, pump slowly through the fill-up line at 0-300 psi and squeeze, and hold available pressure for 10 minutes. b. For depths more than 7000 feet, or when a squeeze pressure cannot be established, wait two hours; then if the hole will stand full, go to bottom and drill. ~ttachment F {' age 2 DIASEAL M slurries can be put in place through the bit nozzles. In the Texas Panhandle, mud losses have been sealed by pulling off bottom, pumping down a premixed DIASEAL M slurry of 25 to 50 barrels followed by mud. This restores circulation and drilling is continued. Exact procedures and safety measures must be dictated by hole conditions. In a sticky,' unstable hole, the bit would be pulled to the bottom of the last casing string. In normal holes, the bit would be pulled several stands off bottom as it would in the case of short rig repairs. Chances for success are greatest when the bit is placed closest to, but above, the point of lost circulation. Attachment E Page 1 HOLE "FILL-UP" PROCEDURE The following procedure should be followed to insure the accurate measurement of the fluid volume required to "fill up" while tripping. The driller on tour is to make a written record using the Fill-Up Report Form to be kept on a permanent basis. A. If rig has trip tank, hole fill-up procedure to be followed is: 1. Before trip, circulate bottoms up, fill trip tank, and calculate total fill up for amount of mud to be used. 2. After slug has been pumped, pull 5 stands, observing fluid level in hole for swabbing. Stop and observe hole for flow and make sure hole is static, then fill hole and record volume. NOTE: First fill-up may be a little short due to slug falling. 3. Fill hole every 5 stands and observe for correct fill up and record volume. 4. After 15 stands have been pulled and correct fill up is evident, install stripping rubber. 5. Continue pulling pipe, fill hole every 5 stands and record each fill up. 6. When pulling drill collars, fill hole after every stand and record each fill up. 7. The blind/shear rams should be closed one time each trip out of the hole as an operational check after bit is above rotary table. CAUTION: If hole is not taking correct amount of fluid back to bottom and circulate' bottoms up. B. If rig does not have trip tank, fill up procedure is:. ..... ~:'::'~<~ Oil 1.. Before trip, circulate bottoms up and calculate total fi~~ for amount' of mud to be used. 2. After slug has been.pumped., open slug valves on slug tank, and pits so that mud level will equalize into slug tank, No. 1 suction tank, and No. 2 suction tank. 3. Drain "Possum Belly" (tank in front of shale shaker) and pull first stand slowly while observing fluid level in hole for swabbing. After two stands, stop and observe hole for flow, continue to come out of hole until 5 stands have been pulled. 4. Close suction on No. 1 suction pit, open valve on slug tank and fill hole until flow light comes on. Count the number of pump strokes required, allow 2 or 3 extra strokes, stop pump and reco~d .... number of strokes. Measure inches of fluid pumped out of the Attachment E slug tank and into hole. If the hole did not take the correct amount of fluid, find out why~ 5. Fill hole every 5 stands and observe for correct fill up and record volume. 6. After 15 stands have been pulled and correct fill up is evident, install stripping rubber. 7. Continue pulling pipe, fill hole every 5 stands and record each fill up. 8. When pulling drill collars, fill hole after every stand and record each fill up. 9.. The blind rams should be closed one time each trip out of the hole as an operational check after bit is above rotary table. CAUTION: If hole is not taking correct amount of fluid, go back to bottom and circulate bottoms up. GENERAL NOTE: When a 100% wet or partially wet string is pulled, use a mud saver and route returns to drilling nipple (NOT flow line). Hole fill up required will be same for wet or dry string by following this procedure. Fill up line is to be installed only in drilling nipple below flow line takeoff. Date: Time: ;HOLE FILL-UP REPORT ( Depth: Stadd No. of Fil'l-Up Stand No. of Fill-Up Type Stands , Volume Type Stands Volume 1 31 2 32 3 33 4 34 , ,, 5 35 6, 36 7 37 . . 8 38 9, 39 , 10 40 11 , 41 12 42 13 43 14 44 ~15 .... 45 _ 17 47 .18 · , 48 , _ 19 49 , , _ 20 50 21 51 22 52 ' 23 53 24 54 25 55 26 56 27 57 , 28. . 58 , , _ _ , , 29 59 I'~ ~'~', ~ ~/~ 30 60 ~'~ ~-" ' Cl.,~ . , . PROPOSED MUD PROGRAM The following table shows the mud program we propose to use to drill with: Interval Weight (B.O.F.) (pp~) Viscosity Filtrate (sec/Qt) (M1/30Min) 0-250' N/A N/A No control Mud Type Sea water (SW) with occasional Pre-hydrated Gel (PHG) slugs to sweep hole. SpOt 150 viscosity PHG in hole prior to runn%ng 30", 20" and 13-3/8" casing. 250'-1000' 8.5-9.0 40-60 No control Ditto 250'-1000' system 1000 '-4000 ' 9.0-9.5 40-50 15 A low-s°lids non-dispersed fresh water system will be used made up as'follows: 1. Gel will be used for building viscosity. 2. AddDrispac for~filtrate control. Use Drispac Super-Lo when barite additions are required. 3. Use Caustic Soda to control pH. 4. Use Soda Ash tO control calcium ion below 500 ppm. 5. Add Barite as required for weight control. 6. Use Soltex as required to reduce torque & drag & stabilize shales & coals. 7. Use Desco as required to control theology & to convert to semi-dispersed system as dictated by mud weight require~ 8. Use desilters/desanders & 150/200 mesh screens on shaker. Use mud cleaner as desilter. 4000' - T.D. 10.2-10.6 45-55 5-9 Ditto 1000' - 4000' system, except: 1. Build mud weight to 10.2 before drilling Sterling sands. 2. As mud weight requirements increase, use centrifuge in combination with previously listed mechanical solids control equipment to maintain low-solids mud. PROPOSED MUD PROGRAM Sometimes hole problems develop while drilling that require the mud to be specially treated to overcome these problems. The program we would employ in various situations are discussed below: Stuck Pipe - In separate mud tank, mix anionic surface active agent and spot across. the.interval.where pipe is stuck. Move "fresh" fluid mix across interval at 15/20 minute intervals. Circulation Losses - A. Partial loss - Add lost circulation materials (LCM) such as hulls, cellophane, nut shells, sawdust, mica, fibers, directly into mud system and circulate by passing solids control equipmentuntil full' returns are established. B. Complete loss - In'aseparate.mud tank, mix a volume equal to twice the probable volume. of the lost circulation interval of Diaseal M, Barite, LCM and water. Spot over lost circulation interval with regular mud. FilZ hole through fill up line if possible. If possible, let stand 2 hours and go back to drilling. If not possible to fill hole, mix and spot another batch and try again. Hydrogen Sulfide - If H2S is encountered, add zinc carbonate direCtly to mud system and keep pH of mud system mn 9.5 - 10.5 pH range with caustic soda. H2S highly unlikely. BHT 250°F. - Use lignites in place of lignosulfonates to disperse system. Continue to use Drispac for filtrate control in combination with Desco. Temperature .above 150°F unlikely. Foaming - If foaming becomes a problem, add aluminum stearate at .1 - .2 ppb concentration directly · to mud system. Bit Balling- If bit balling conditions are encountered, add MD at 0.02 - 0.04% by volume concentration directly to mud system. Attachment C ACTIVE ANDRESERVEMUD SYSTEM The following table indicates the amounts of liquid mud weexpect to have in the active and reserve mud tanks while drilling each section of the hole. The capacity of the rig will be the final determinant as to active and reserve volumes. Interval Active Tanks BOF Barrels 0 -~ 250' 600 250 - 1000' 600 1000 - 4000' 1000 4000 - T.D. 1200 Liquid Mud Volumes Reserve Tanks Barrels 441 441 441 441 ONBOARD MUD STOCK We propose to maintain a mud product inventory onboard the drill vessel as set ~ forthbelow..while drilling this exploratory well. Product Quantity Remarks ........ Sacks .......... Regular: Gel 500 Drispac 80 Caustic Soda 40 Soda Ash 80 Soltex 300 Desco 100 Barite 6,000 Lignosulfonate 0-180 Sack storage Sack storage Sack storage Sack storage Sack storage Sack Storage 2,100 sack & 3,900 bulk storage Sack storage Special: Surfactant 100 Nut shells 250 Myca 250 Diaseal M 150 Zinc Carbonate 40 Lignite 0 Aluminum Stearate 40 MD 5 Sack storage - use for stuck pipe only Sack storage - use for lost circ. only Sack storage - use for lost circ. only Sack storage - use for lost circ. only Sack storage - use for H~S only Sack storage - use for high BHT only Sack storage - use for foaming only _Drum storage - use for bit balling only STJPPLIER MUD STOCKONSHORE Mud supplier will maintain, at their Kenai onshore stock point, a supply of the mud pro~cts listed above in. quantities-:sufficient~to buildtwo-hole volumes. These materials will be committed strictly to this well for emergency use if required. Page 3 Product Name Mil-Gel Mil-Bar Bicarb of Soda Caustic Soda Desco Defoam Diaseal M Drispac Kwik-Seal Lime Mil,Mica Unical Soda Ash Soltex Nut-Plug Zeogel Zinc Carbonate .... ~. ~ttachment C 'MUD MATERIAL DESCRIPTION 'Description Concentration Sodium montmorillonite 10 - 20 ppB Barium sulfate Sodium'bicarbonate 0 - 700 ppB .1 - 1..5 ppB Sodium hydroxide Organic thinner Aluminum Stearate Diatomaceous Earth Polyanionic cellulose powder .1 - 3 ppB .25 - 3 ppB .25 - 1 ppB 0 - 50 ppB .1 - 2 ppB Granule, flakes & fibers Calcium hydroxide powder 5 - 50 ppB .5 - 8 ppB Micaflakes Ferrochrome Iignosulfonate SodiuTM Carbonate Sodium Asphalt Sulfonate Liquid Triglycerides and alcohols Organic Material Attapulgite Clay Zinc Carbonate 2 - 15 ppB 1 - 4 ppB .5 - 2 ppB 2 - 6 ppB .02 - .04% 5 - 50 ppB 5 - 25 ppB .5 - 8 ppB Function Viscosity & filtration control Density Cement Contamination pH Control Rheology Control Defoamer Lost Circulation Viscosity & filtration control Lost Circulation Alk. Control & flocculation Seepage Rheology Control Treat calcium Shale control Lubricant for bit balling Lost Circulation Salt Water Viscosity H2S Control Page 4 WELL KICK CONTROL PROCEDURES Attachment D Page 1 It is imperative that everyone involved with the drilling of a wildcat well know how to properly control well kicks so there will be no unnecessary hazards to life and property. Procedures for various kick situations outlined below are to be used as a guide in controlling the well. The Anchorage office is to be consulted as soon as practical when a kick occurs. A. Precautions for Drillin~ Without B.O.P.E. B. O. P. E. will not be used while drilling the hole from 0' to 250' BOF because offset well information indicates no shallow drilling hazards are present. However, the following general precautions and contingency plan will be followed should gas be encountered while drilling this portion of the hole. 1. 300 to 500 barrels of 10.0 to 11.0 lb/gal mud will be mixed and placed in readily available storage. 2. The return of fluids at the well head shall be continuously monitored, if possible, while the hole is being drilled. 3.~ Mooring of supply boats alongside the drilling vessel will be minimized during these operations. 4. If the well begins to flow, the mud in storage will be pumped down the drill string. At this stage, all personnel will be alerted tO assume their respective stations in preparation for combating the kick. 5. Following are general procedures to follow: a. Motorman shut down all engines and snuff all exhausts. b. Barge operator extinguish all flames. c. Personnel standby to evacuate upon orders from supervisor. B. Handlin$ Kicks While Drilling with Diverter t.-..-The diversion~system is being installed to provide a control capability if pressure sufficient to frac the formation is encountered while drilling.from.20" casing shoe at 250' ± BOF to the 13-3/8" casing set point at 1,000' ± BOF. 2. The diversion system shall be used anytime underground blow-out conditions exist while drilling the hole section mentioned above. Attachment D Page 2 3. The sequence of operational steps to be taken by the driller when pit gains and/or gas-cut mud is detected ~depends on which of the following situations is applicable. a. If drilling operations are underway, the driller should: 1) Shut the mud pump down and pick up the kelly such that when diverter is closed, the sealing element will be in the middle of a joint of drill pipe. This will allow the pipe to be moved up and down periodically during the control period. 2) Actuate the diverter/vent valve control and have the appropriate valve on the 2-way vent header closed. 3) Check to see that all diversionary equipment is functioning as designed and desired (surface pressure.upon the 20" must be kept as near zero as possible). 4) Proceed to build mud volume of sufficient weight and volume to control the flow and keep the hole full. 5) As soon as control is regained (as judged by emissions from vent line), the diver~ter/vent line valve control can be~ actuated to open the diverter and close the main vent valve. · Shut down mud pump and observe mud in bell nipple. If no movement, go back to drilling. If movement, go back to Step 2 above. b. If tripping operations are underway, the driller should: 1) Install inside BOP in drill pipe and attempt to get as much drill pipe back in hole as possible before closing the diverter. 2) Same as Step a. 3). After diverter is closed, strip drill pipe · . .through a.heavily lubricated-diverter as long as it can safely be done. 3) If able to get back to bottom with drill string: a) Resume circulation with same mud weight as used while drilling. b) After control effected, open diverter and build mud weight 0.3 ppg and circulate around using same pumping rate as used while drilling before attempting to trip again. 4) If unable to get back to bottom with drill string: a) Same as .Step a. 4). b) Same as Step a. 5). E£EIVE ) Oil & Gas Cons. tmchorag~ Attachment D Page 3 c. If out of the hole, the driller should: 1) Same as Step a. 2) 2) Same as Step a. 3) 3) Wait for flow to dissipate to the point that top kill procedures can be employed. (Potential pressure at 20" shoe based on drilling depth and mud weight when flow/blow occurred dictates whether or not the vent line valve can be'closed while the diverter is sealing the drill string/20" annulus so that top job procedures can be performed. This decision will have to be based on circumstantial evidence.) C. Kick While Drillin~ With B.O.P. Stack Installed 1. During normal drilling operations the attached IMCO Practical Kick Control Method will be Used. See Figure 1. 2. Figure No. 2 will be posted in the doghouse with a clear plastic cover. Data required on the form will be updated once each tour. Attachment D Page 4 3. Pull kelly out of rotary table upon first indication of a gain in mud in fl~e working pits. 4. Stop mud pump(s). If annulus mud continues to flow close the Mydril. Leave choke cloased (the casing setting depth and casing burst rating preclude kick pressures fracturing the formation at casing shoe or bursting the casing at the surface). 5. Immediately observe the B.O.P. stack for leakage. 6. Slowly reciprocate the drill string the full length of a joint without passing a tool joint through the Hydril to prevent differential sticking. Continue slow reciprocation and follow steps outlined in the Practical Kick Control Worksheet. D. Kicks While Tripping 1. Part way out of the hole: If a kick occurs while part way out of or into the hole, make every effort to'get as close to bottom as possible. When a drill pipe float or back-pressure valve is not being used, install abackpressure valve or inside preventer. Strip in the hole through the Hydril. Adjust closing pressure on the preventer so it closes lightly around the drill pipe and allows a small leak. Regulate the volume of fluid that is bled from the hole so that it corresponds as nearly as possible with the volume that would be displaced by lowering the drill pipe into the hole. ~(See page 5 for displacement volumes.) "' When a kick occurs while tripping, the original mud weight is capable of balancing the formation pressure when hole is circulated from bottom. If the .drill string can belowered to bottom, circulate out using_the same pumping rate that was used while'drillin~.. Use the procedure of the following section for handling trip gas. After regaining control, increase mud weight .3 ppg and circulate around before starting out of the hole. Should the shut-in casing pressure become excessive or other events prevent running the drill pipe to bottom, the mud weight should be raiSed and the hole circulated out.in the manner recommended for handling a kick while on bottom, except for the following changes: a) Substitute the circulating depth for total depth in order to determine the required mud weight. b) The shut-in standpipe pressure used to determine the required mud weight should be the pump pressure required to just open the float or inside preventer. Gas Cons, CommissJo~ Attachment D Page' 5 ' 2. Almost out of the hole: If the kick occurs when the drill collars are being handled, install a safety valve or inside preventer. Open the choke lines and close the Hydril. Immediate steps must be taken to prevent the collars from blowing out of the hole. Before pressure is allowed to build up under the Hydril, the collars should be securely chained down using an upside down collar clamp or other means. Shut the well in only after the collars have been securely chained or otherwise fastened down. Then proceed to build mud weight and circulate it around using the procedurerecommended for handling a kick while on bottom, except: a) Substitute the circulating depth for total depth in order to determine the required mud weight. b) The shut-in standpipe pressure used to determine the required mud weight should be the pump pressure required to just open the float or insidepreventer. 3. Completely out of the hole: If a kick occurs when out of the hole, close the blind rams. After closing in a well that has kicked while out of the hole, it is necessary to resort to a tedious top kill method in order to reduce the pressure to the point where drill pipe can be stripped into the hole. This involves alternately pumping in slugs of heavy mud, waiting for the system to invert, bleeding out light mud or gas and then repeating the process. E. Circulating Tri~ Gas If trip gas is expected or suspected in enough volume to cause a kick when it nears the surface, the following procedure should be used: 1. Establish a normal circulation rate upon reaching bottom after a trip. 2. Read and record the pump pressure, at this normal circulation rate. 3. Divert the mud returns through an open choke line by clOsing the Hydri!, or, if a rotating head is being used, by closing the outlet. 4. Maintain constant circulation rate at the normal value established in Step 1. Oil & Gas.~ ... ,, Cons, Attachment D Page 6 5. Choke the mud returns from the annulus only as required to maintain the normal drill pipe circulating pressure. Allow at least a second per thousand feet of depth for casing pressure to be reflected on the standpipe guage. 6. ~intain this pressure control until the hole is purged of gas slugs. . . 7. The pit level may rise due to gas expansion when a ~correct procedure is being followed. Do not attempt to hold a constant pit level. Mud gains of 100 barrels or more are not uncommon when a lot of trip gas is present. DISPLACEMENT'VOLUMES' &' COLLAPSE ' RATING ~ OF ' DRILL ' PIPE Size (Inches) Nominal' ~Displacement ~Weight" : Rumning~Dry. ~#/Foot ~'BblS/90'~Stand API Collapse Rating. Grade~ E '",,," '" (p'si)*' · · 3.5 13'3 1.09 14,110 .. 4.5 16.6 1.80 10,390 5.0 19.5 2.19 10,000 Collapse values are minimum with no safety factor · CAPACITY 'OF 'DRILL 'P IPE' & 'DRILL' COLLARS Drill 'Pipe ' 'Drill' Collars Size. (Inches) Weight Capacity. size. (Inches) Weight 'Nominal' ''#/FoOt''gal'S/foot .... OD'X'ID' Capacity. ''.'#/FOot' '' gals/foot 3.5 - 13.'9 -- .3'13 :~; 4 3/4 x 2 49.6 4.5 .16.6 .597 6 '1/2 x 2'3/4 89.1' 5.0 19.5 .747 8 x 3 147 --162 .309 .. .366 5.0 50.0- .366 ..... 9 X 3 191.9 '..366 DEPTH Figure 2 IMCO FORM 946 3/78 · PUMP NO. I= "x "El DPX rlTPX "rlDPX F'iTPX PUMP N0.2: "x WEIGHT; .... ppg IN ,, ppg0UT : NG: SIZE= "OD "ID MAXIMUM BURST PRESSURE = '~ · MIN. FRACTURE GRADIENT= ppg lit,., iULAR CAPACITY--- .... bpf :)RILL PIPE :SIZE=, CAPACITY = "OD ppf bpf PPf · psi bp 'bp fl TJ ft DRILL COLLARS:SIZE= "ODx ft II HOLE SIZE= ,, PUMP NO. , f! (TVD) PUMP PRESSURE INFORMATION PRESSURE PUMP RATE FLOW RATE (psi) ($pm) (bpm) · . DP DP DC DC OD AND WEIGHT OR TYPE RATE OUT · (~ec/std) 3000 I I I I I I I I I I I I I i ! I ~ I I I t ~ ; I I ~ t I il i i I I i I i l ! ! , t , MAXIMIlM ALLOWABLE Ii IIIlillllll!lIIJlllllllilltllllllllltllllll Jllll .... Illlllllll-IllllI III IIIII Jtllllllllllllllltll iltT] CASING PRESSURE IIIitl I iiiiiiIlllllllllltl Itl I illlIIIII IIIII IIIII ' · ~ lllllllllllltlllltllllllil!llllllllltlllllltlltlllI ~ illtlllllllllltitllllillIl~Jltlllllltllllllltllltl! n w' lllllllllllllllllllllllillllllllllllllllillllllllll ,,,- IIIIIIIIIIIII1'1111111111111111111111111111111111111 ,..,,si r-i FORMATION ~ Itl I I Iilllllltlllllllltltlllllllllllllllll Jllll · ~ 2,,,~1111111 I III I I I Il I Jtll I I III Itl tl J I I Il ! I III I11111 II II ~ V~l Itll II iii iiiiii11 lllllllllll 11 II It1111Jlllililj · .., I,,-,,~] ~., ,,,,,,,,., ,,,,,,',,,, ItJ J J J JJ JJ J J,,,,,' ,, ii,J',)~ ' ,,.,~ I!111111 Illllllll II II I Il Itlllllllll ,~ I I I I i I I I I I I I I i I I I I I I I." ~ ~ ~n ~.~-~l~J.. ~ illl]llllllilllllllllIIItllllli ' ' ..,. I I I I I I I I I ! I i I I I.I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I ¢=! II:l'J: J~'J~'J/lll= t'~l= MIlD WEIGH ~ IIlIlllllillllllllIllllllllllllillIliIllI Illlllllll ........ ~ _ IllllllllllllliIlllIlllllllllllllllIlllllllIlll. llll Jt,~. USED DURING TEST ~- ]oooll i Iii i i1 tlt i tii j i i il i i i ti i i i ii I I t IIi i i III I III i I IJ] .fL///-L,~ ,"~ ' ~ IlltlliliiIiiiIliIliiiiilIiiifiiiliiiililiiiiliiiiI 2j El ~T?,.~ ,., JyIINIMUM FRACTUR K III!1111t 1] . ~: !i11111 II III II IIIIlllllllltlllllllllllllItlllltllll ~ m0a FFI~GE OF GRAPH, ' J I i_i I i I i.I I ii t-I I I I I i I I I I I I I i I I I I I I i I I I I I t I I [ i I I I I I i I t;1_~Jd~; TI4E TWIt POINT~ · . _ . . ,, :' ,,~,,,j .......... - - - I'l 1'1 ll"l !'11 I I I I Il ! I I tl I ! I I I I I I I I I I I II I II I I I I! I I I II - ~1~':g i ~ . lllll"""'"'lllJ"JJlJlJlJJlJJlJl1; JlllJJlllJlJl ~F~',i~l~M~(~ CASING PRE, II!1111111 II E oI ! I I t I I I II I I I ! I'1 I I I I I ! I I t I I I I I ! i I i i i I I I I I I t i i i I i i I i SURE AT MUD WEIGHT IN US 9 10 11 12 13 14 15 16 17 18 19 COPYRIGHT · 1978 MUD WEIGHT, ppg By IMCO SERVICES. A Divisi~ HALLIBURTON Company Alt Rights Reserved 379 ' .A' ;" (secJstd) TRIP INFORMATION DISPL. DISPL. (bbl/std) (stk/std) Figure 1 IMCO Services A Division of HALLIBURTON Company 2400 west Loop South, R O. Box 22605 Houston. Texas 77027 AJC 713 671-4800 WELL LOCATION DATE CIRCULATION NO. I 2 3 4 PRACTICAL KICK CONTROL A B C D TIME OF DAY SHUT-IN DRILL SHUT-IN CASING MAXIMUM ALLOWABLE PIPE PRESSURE (psi) PRESSURE (psi) CASING PRESSURE (psi) ;I" "~/'~ -~1'" I~1'c''' ' I,,I~ I III MUD WEIGHT (ppg) PIT GAIN (bbl) REDUCED REDUCED PUMP PRESSURE (psi) PUMP RATE (spin) I II IIIIII I IIIII I II III IIII I I a/,~oo,~ !.~1~ I-,.!'!-.!~cI-~i~°i III . I If I 4~ RECORD I -~ 51CALCU LATE~ KILL PUMP NUMBER PUMP DISPLACEMENT DEPTH (ft) (bps) TRUE VERTICAL DEPTH (fl) CASING OPEN-HOLE DRILL PIPE ANNULAR DEPTH (ft) LENGTH (ft) CAPACITY (bpf) CAPACITY (bpf) TRUE VERTICAL MUD WEIGHT DEPTH' INCREASE SHUT-IN DRILL PIPE PRESSURE MUD WEIGHT INCREASE MUD WEIGHT DRILL PIPE CAPACITY lCALCULAT~ ~ (: ~! CALCU'LA~rEI.~ ANNULAR CAPACITY ANNULAR CAPACITY 3C ~ 3B · PUMP DISPLACEMENT KILL MUD WEIGHT DEPTH SURFACE-TO-BIT STROKES I· 3B PUMP DISPLACEMENT DEPTH Dr, ~,, ~. OPEN-HOLE LENGTH PUMP .l~a,~,l~ ~ BOTTOMS-UP STROKES, OPEN-HOLE SURFACE-TO-BITsTROKES ' :'::~i~Ul~(~'-:' ~:'~ STROI~L/~~ ~.~i~l~.10/~rAL STROKES COPYRIGHT © 1979 by IMCO SERVICES, A Division of HALLIBURTON Company All Rights Reserved. 11 I SELECT NEW MUD WEIGHT ALCULATE 14 CALCULATE il,B + 2C SHUT-IN DRILL REDUCED PIPE PRESSURE PUMP PRESSURE NEW MUD WEIGHT OLD MUD WEIGHT !6D KILL MUD WEIGHT REDUCED PUMP PRESSURE 11D NEW MUD WEIGHT 14D '" ' "1 I-,.i ix1.052_ i MUD WEIGHT TRUE VE'RTICAL DIFFERENCE DEPTH 15D 13D PRESSURE NEW REDUCED ADJUSTMENT PUMP PRESSURE ~:12D INITIAL STANDPIPE PRESSURE -,--, :~ 13D NEVV REDUCED PUMP PRESSURE i 14D ',' MUD WEIGHT DIFFERENCE --,~! 150 PRESSURE ADJUSTMENT ~ 16D ~ ~ ~,~:~.~ ......... ~.~.,~-~ FINAL STANDPIP[ PRESSURE i 71 / i IPLOT ON GRAPHTHE ' ~ STANDPIPE PRESSURE SCHEDULE=~ ...... 2500~~~__~ ~-~~ .... , ..... r'.,~, ...... ~'~,~,' '~i:~.--':'~"~"~%'~'~'~:~, INITIAL STANDPIPE~ STROKES ~ ~~:~-t'"'":'-~i i ~ ] I ~ . ~ .... "L'"r'r'. .... ~.L~Z'-T-i~-~ PRESSx, RE , ,, -- '~ 9 ~T ~ ~oo ~~~__~ ......_;~._~__~_t__; ................. ~ .................... ' ~. ................ ~ ~ ~ ~ .......... ' i o . ,ooo , oo ooo PUMP STROKES 21 EXTEND I~lHORIZONTAL FROM FINAL LINE ,,~. STANDPIPE ,, PRESSURE RIGHT EDGE OR 10D TO OF GRAPH TOTAL STROKE 100 STROKE INTERVALS 0 STROKES 100 STROKES 200 STROKES 600 STROKES 300 STROKES 400 STROKES 500 STROKES 800 STROKES 900 STROKES I IIIII 700 STROKES 1200 STROKES 1000 STROKES 1100 STROKES 1500 STROKES 1600 STROKES 1300 STROKES 1700 STROKES 1800 STROKES 1400 STROKES 1900 STROKES REDUCED PUMP RATE KILL PUMP NUMBER CHOKE TO PRESSURE BUT KEEP FLOW RATE SCHEDULE CONSTANT 251 261 EXCEED ~ ~ MAXIMUM ALLOWABLE CASING PRESSURE TOTAL STROKES AFTER YOU ~ ~. KEEP ~. PRESSURE AT HAVE PUMPED CONSTANT SURFACE-TO-BIT FINAL STANDPIPE STROKES PRESSURE I YOU HAVE 9D UNTIL KICK OR "~ ABOVE SHOE PUMPED UNTIL KICK OUT NEW MUD WEIGHT OPEN-HOLE STROKES REACHES SURFACE IMCO WHEN 28 DETECT NEW MUD WEIGHT TIME OF DAY 301 RECORD, !"~ '~ , MUD WEIGHT SHUT-IN DRILL PIPE PRESSURE PIT GAIN 31 29C 29D IS SHUT-IN CASING PRESSURE 13D REDUCED '~' PUMP PRESSURE MAXIMUM ALLOWABLI CASING PRESSURE REDUCED ' PUMP RATE 'ANOTHER I ,s I II II CIRCULATION IN THE HEADING OF WORKSHEET VALUES ii IN 29 AND 30 TO LINES 1AND 2 ON woR ,SHEE'I':' THE NEW WORKSHEET THE INFORMATION AND DATA CONTAINED HEREIN AND ~LL INTERPRETATIOn. IS A?;D/OR '~3OMMF~'~ ~.T~ON':~ ~.~,CE ?~ ~;C-~>~CT ON '~>~?~'~.' ~-~. PRINTED IN U,S,A. SRS TERN Attachment A Casing (1 &2) Size and. Grade 30" B Weight 20" K-55 13-3/8" L-80 9-5/8" SS95 C-95 ' 7" L-80 . (Lb/ft) .196* 133' 72* 47* 32* Type of Threads Weld BTC BTC BTC LTC Hole Size (In.) 26 17½ 12¼ 8% Setting Depth (Ft.BOF) 50-100 250 1000 40O0 10,000 Casing Top .:(Ft. BOF) CASING'PROGRAM'AND DESIGN'CONDITION! Fracture Pres. @ Shoe (psi) (3) "· · 'MUd' Pressures _ Outside, Inside 'fsi/f t, 4'6s .,~ (. 468 Cement Top ' {Ft,BOF) (4) (4) NA 287 812 2800 7000 .494 (1) Ail casing except the structural casing will be new pipe meeting API standards. .551 {psi/ft) ..468 .468 .494 .551 .551 '''CalCUlated'MaX$'L6ad Collapse .(psi) 24-47 177 543 1955 5600 . · . . Tension · < lOOO#) 49-58 : 6O ,86 198 326 Burst (psi) (5) None 176 771 2700 4600 AP I' Minimum' Rat ing s' Collapse Tension Burst (psi) ~10001b . (psi). N/A N/A 1500~ 2123 ·3060 2670~, 1650 5380 5080 1273 8150 661 9060 N/A:: 8600 · (2) The 20", 13-3/8", 9-5/8" and 7" casing strings will be inspected to detect transverse and longitudinal defects, determine wall thickness pipe eccentricity, grade uniformity and thread condition. ; ' CalC.'Load / A,P,I. Ratin~ Collapse Tension IBurst .% _ .%. _ %. N/A 12 2O 39 65 N/A 28 16 49 N/A 6 14 33 51 . (3) All formation fracture pressures shown above are based on a fracture gradient of .7 psi<ft, from RKB (200 ft. AOF) to TD (4) casing will be cemented at least 500 ft. above shoe or any hydrocarbon bearing zone. (5) Maximum anticipated'surface pressure and method used to determine same: ,( A. The maximum surface pressure possible is conservatively estimated to :be!4600 psia at 10,000' T.D. B. Criteria used to determine' surface pre,ssure: ~? 1. The mud weights used in drilling the' Shell State #1 drilled in Sec..~4, iON, llW, and Shell· State #2 (Sec. 2, 9N, llW) were considered, as was our experience in drilling the Ste. rling and Beluga formations in.ithe North Cook Inlet Unit· These data formed the basis for our selection of mud-weight required ~o drill these 'same formations at the propos~ site. -.~ 2. A bottom hole pressure based upon these estimated mud weights was ca.!culated:. i-' - .The maximum anticipated sUrface pressure was calculated assuming a i~ gravit~ gas gradient from the bottqm to the ~op of the hole, · * These casing far exceed requirements, but are being used to reduce our stock of~,itubular goods· , Burst. and collapse ratings and percentages are applicable to the lower grado, of:pipe employed 5x't this string. .· PHILLIPS J~TROLEUM COMPANY- LOG QUAL('" CHECK LIST (Please print one letter or char,~[er per space; abbreviate if necessary) SECTION I - GENERAL INFORMATION I (To be filled out by Phillips representative) DATE M D Y APl NO. I WELL NAME AND NUMBER PHILLIPS OFFICE T.D. DRILLER t I I I I i WELL LOCATION I I I I I I I I I I I I COUNTRY STATE OR PROVINCE (Complete A and/or B) I I I I * RUN NUMBER FIELD I I I I I I I COUNTY OR PARISH t I I I I I I I I A. Section Township Range Surface location B. Longitude' Deg. Min. LatitUde · Deg. Min. ELEVATION AND HOLE DATA I Sec. E/W __ Sec. N/S Perm. Datum K.B. Elev. D.F. Elev. @ FT/M FT/M FT/M Hole Deviated r-~ Straight ~ Maximum Hole Angle Drilling Measured From Deg. @ FT/M Tight Spot/Dog Leg Depths Casing (O.D.) IN/CM @ FT/M Bit Size IN/CM General hole condition MUD DATA ] A mud sample will be collected just prior to stopping circulation. For an air drilled hole, if there is liquid in the hole, measure that liquid resistivity if it is possible to retrieve a sample. TYPE TIME AND DATE CIRCULATION STOPPED J I I I J j M D Y BARITE IN MUD (24 hr clock) DENSITY VISCOSITY YES / NO pH WATER LOSS SALINITY g/cc - lb/gal ppm CI LOGS TRIP DEPTH FT/M VERTICAL HORIZONTAL SPECIAL INSTRUCTIONS TO BE RUN NO. FROM TO SCALE SCALE AND UNITS , * For Dipmeters specify: a. Anticipated Dips b. Do you want structural OMax. OMin. and/or stratigraphic dip. FORM 10128-S 11-81 survey. Physical evidence of this should be included with paper logs and film. All tools should be checked going in the hole. 2. Shop calibrations should be included on film and the date since last cai bration should be no more than one month from the cur- rent date. 3. All logs will be recorded on magnetic tape and mailed to the 5. Record time off bottom. '6. Log depths will be measured from K.B. 7. No tool protection insurance. 8 Date last cable marking. I M D · I ~ I Y Phillips regional office. FAILURE MAX MAX GENERIC COMPANY LOGGING * * DATE LAST· OR LOST ACTUAL FT/M COST TIME OFF TEMPERATURE DEG. F/C DEPTH LOG TOOL FPH TIME LOGGED $ BOTTOM SPEED MPH Y N 1 2 3 FT/M SERVICE ABBREVN. SHOP CHECK M D Y * I I I I I I I I I I I I I I I I I ] I ~ I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I i i I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I i I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I ! I I I I I I I I I I I I I I J I J I I I I I I I I I I I I I I I I I I I I I I I I I J I J I I I I I I I I I I I I I I I I I I I I I I I I I J I J I I I I I I I I EXTRA CHARGES (specify) I I I Check appropriate box CHECK LIST GENERAL YES NO N/A TOTAL .................................................. .u o ..... .u_.u I----I I---1 I---'l I I I I Rm,Rmf,Rmc & corresponding temperatures measured & recorded. . 2. Maximum BHT recorded on each trip for all 3 thermometers. I--I [--I F--I 3. Appropriate logging scales chosen (or prescribed by Phillips). I---II--I i---I 4. Backup galvos used so that all curves are recorded over the hole. I---1I--] ~ 5. Pre-job operational check of all tools. [--] [] I---I 6. Tool performance checked going in the hole. I---I[---I I---I 7. Calibration checks and all zeros properly recorded befOre and after logging.' I--I I--I r--I 8. Previous run overlapped by 200' or to casing shoe. i---II--] i----I 9. 300' repeat section run, preferably over zone of interest (where applicable, memorizer out for 100' and memorizer in for200'). [---] [---II--~ 10. Memorized curves within 6" of curve to which they are memorized. I--I I--] r--] 11. Field heading completely filled out. i--I I--I [--I 12. All scales, scale changes, shifts, etc. clearly marked on film and heading. F--I r--I i--] 13. visual quality acceptable; developing, printing, etc. ~ [~] ~1--I 14. Loggi ipeeds conform to Service Co. and/or Phillips specifications Iii I---]I---I ('3 0 O) · ~1~ . * * Maximum logging speeds: Ind. Elec. or Dual Ind. Laterolog or Dual LL. Pad Devices: MSFL, ML & MLL PL Radioactive tools Sonic or acoustic tools 6000 FPH 4000 FPH 2500 FPH 1800 FPH 1800 FPH 240O FPH * Account for lOst time under remarks. 15. 16. 7. 18. 31. 34. 35. 43. 44. 45. 46. 47. 48. 40. 50. 51. CHECKLIST (' SP ( SP curve normal with no noise, magnetism or other spurious anomaly. Shifts made in constant SP zones (shales). (DO NOT attempt to continuously correct SP base line). SP ground checked and/or SP rerun with current off (Check yes only if abnormal appearance on normal run). Welders and unnecessary power turned off during logging; cathodic protection off. INDUCTION-ELECTRIC AND DUAL-INDUCTION 19. Stand off used and recorded on heading. 20. Shoulder bed resistivity correction used and recorded on heading. 21. Skin effect correction recorded at bottom of log showing step on curve before pickup. 22. Calibration results within 2 m-mhos. 23. All curves have peaks at same depth (memorization check) 24. Repeat sections agree. 25. Conductivity not negative. 26. Sonde errors not changed while logging and agree with shop sonde errors. LATEROLOG AND DUAL LATEROLOG 27. Calibration within 2 ohm-m. RXO LOGS (ML, MLL, PL, MSFL, DIELECTRIC) 28. Caliper does not stair-step. 29. Mud log recorded. 30. Pad condition OK after survey. SONIC OR ACOUSTIC LOGS Centralizers used and properly placed. All recorded values greater than 40 micro-seconds. No excessive noise or cycle skipping. Repeat sections agree. Overlap 300' into casing. Casing reads 57 micro-seconds in unbonded sections. GAMMA RAY LOG (inc. SPECTRAL) 36. Statistics not over one log division. COMPENSATED DENSITY 37. In gauge hole, correction less than _ .03 gm/cc. (If mud cake is thin) 38. Statistical variations evident but not greater than 0.05 gm/cc. 39. Repeat sections agree to within _+ .03 gm/cc. 40. Caliper checked and recorded in casing. SIDEWALL NEUTRON OR COMPENSATED NEUTRON 41. Repeat sections agree within _+ 1.5 p.u.. 42. Caliper checked and recorded in casing. DIPMETER Correlations visible on all four curves. Both caliper checked in casing and recorded. Rotation evident (but not more than 3 turns/100 ft). Deviation and hole drift compare with drillers data. Pads in good condition after survey. FORMATION TESTING "Tie- in" log recorded for zones of interest. Recorded hydrostatic pressure approximately equals calculated hydrostatic pressure. Pressure test data, test recovery and interpretation data included on the log. A copy of the gauge calibration included on the log. 3. YES NO N/A IENGINEER'S REMARKS Note: Explain all items checke, Explain all lost time. Explain all shop checks more than one month old. Explain depth discrepancies between logging trips and previous runs if greater than 1.5 feet. Explain any curves that are merged or recomputed. SERVICE COMPANY LOG UNIT NO. CITY I ENGINEER I I I I I I I I I I I I I I I I I I SECTION III - JOB EVALUATION I(Tobe completed by Phillips representative) I ~ I Trips in Hole I ~ I Tool logging time(Hrs) I I I M D Y M D Y [ ] I [ I [ I i I M D Y I i i i I [ I D Y I ~ I Tool failure time Time / Date service company notified Time / Date arrived on location Time / Date logging started Time t Date service completed ] i I I I i (24 hr. clock) Type and serial no. of equipment that failed. I · I I I I I I I I I I I I I I Rating of Service (0, poor- 5, first rate)' Tools r--] Crew ~ All items checked NO in Section II were discussed with you to your satisfaction. Comments · Yes[--] Phillips Representative On completion send this form to: Director Well. Log Analysis Section 290 Frank Phillips Building Bartlesville, Oklahoma 74004 I Date JACKUP DRILL RIG DRILLING PROCEDURE 1~ Make up 30" drive pipe as illustrated in Attachment M. 2. Install driving head, lower to ocean floor at low slack tide and drive 30" to point of refusal or 200 blows per foot. If penetration is less than 50' BOF, pick up 26" bit and drill pilot hole to 100' BOF. Then drive to 90 - 100' BOF. Cut off as required and nipple up flow line and install drain at moon pool level. 3. Pick up 26" bit and BHA. Drill 26" hole to 450 ± RKB (290' BOF) with sea water and viscous (200 sec/qt.) mud sweeps at 30' intervals. 4. Fill hole with viscous mud after reaching 20" casing point. 5. Rig up to run 20" i33#, K-55 BTC casing as folloWs: a. Casing will be made up per .Attachment'N. Space'out'such that: (1) 20" casing housing will.be located below'mudline the correct distance suchthat.when i3"3/8'' is'landed on 20" casing housing, the 13L3/8".tie back sub will be 10 - 15.' below mudline, · . and (2) a 20" casing collar will'notbe at or 'immediately below ,, where 20" casing head must be installed in'moon pool area. There will be enoughrat hole~below the shoe to provide this flexibility. b. When casing has been run' to 250'~ ± 10' BOF, hand off. at rotary table in slip type elevator-spider. e c. GIH with plug catcher .and stab-in sub on DP and stab into collar.· Cement 20". as follows:.. a. Break circulation and circulate hole clean, then 'pump in' . . p~e~luah. (1) b. Pump in 500 sx of Class G cement mixed with 129 barrels of 2.5% pre-hydrated brine gel-inlet water mixture at a slurry weight of 12.8 ppg. c. Tail it with 500 sx of Class G cement mixed with 60 barrels of inlet water mixture at a slurry weight of 15.8 ppg. · . d. Drop'top plug· (no bottom plug will be used). e. Displace cement to plug catcher using inlet water. During displacement,·do not exceed 1500 psi pumP pressure. Calculate displacement volume required to bumP plug. BumP plug easy. Pressure up to 1500 psi maximum. ·Release pressure slowly. Check for back flow. If okay, pull stab-in out· of float collar. · Again check for back flow. If0kay, COOH w/Dp. f. Pickup macaroni tubing. Run macaroni down·to mudline susPension level and circulate cement out· of 20" X 30" annulUs·. ·Fill annulus w/sugar water. Then drain 20" X 30" annulUs above moon pool area and flush out with fresh water. 7. After cement samples are hard, release tension on 207'. Cut off· 30" conductor and 20" casing stubS as directed and inStall Gray Oil Tool's 20"-2000 slip-on wellhead. After 20"head installed, install drilling spool and 20"~diverter, diverter lines with full open'hydraulically/ · . pneumatically operated wing valves, bell nipple and flowline. Test BOPE, wellhead and casing in accordance with Attachment~K. 8. Install extended bowl protector in wellhead. *Pick up 17~1/2'' bit and BHA. GIH and drill out float collar and shoe and cement below shoe. (2) 9. Drill 17-1/2" hole to 1250' RKB (1050 BOF). This allows about 50' of rat hole below 13-3/8" setting depth. Circulate and condition hole for running 13-3/8" casing. 10. Pull bowl protector and run 13-3/8", 72#/ft., L-80 BTC casing as follows: a. Casing will be made up per Attachment O b. Run casing to 1200' RKB (1000' BOF). Space out casing such that when 13-3/8" DJ-MSR mudline casing hanger is set in 20" DJ-S wellhead housing there will be no 13-3/8" casing collar in close proximity to 20" surface wellhead. c. GIH with plug catcher and stab-in sub on DP and stab into float collar. 11. Cement 13-3/8" as follows: a. Break circulation and circUlate hole clean. b. Pump 30 BFW preflush. Pump in 500 sx of Class G cement mixed with 129 barrels of 2.5% pre-hydrated bentonite gel-fresh water mixture at slurry weight of 12.8 ppg as lead slurry. c. Tail in with 300 sx of Class G cement mixed with 36 barrels of 2% calcium chloride-fresh water mixture at 15.8 ppg slurry weight. · . d. Drop'to~. plug (no'bottom plug~will be.used).' ' e.. Displace cementto .Plug catcher using~mud. 'During disPlacement, do not exceed 1500 ~psi~Pump pressure, ~CalCulatedisPlacement . . · . volume required'to bumP ~plug. ~BumP Plug' easy. 'PreSsure uP'to · , · 1500 psi pump pressure. Release pressure sloWly.~ 'Check ~or back.flow. If okay, Pull stab-in'sub out of .float'collar. Check for back .flow. If okay, COOH with DP. (3) f. Rotate 13-3/8" eight (8) turns to the right to open the ports in the circulating sub above mudline hanger. Break circulation with water and circulate cement out of 20" x 13-3/8" annulus above this point. After annulus cleared of cement, close circulating ports by opposite rotation. After closing ports, drain annulus above BOPE/wellhead and flush again with clear water. 12. Part the wellhead at 20"-2000# flange. Pick up wellhead/diverter and prepare to install Gray Type WE casing hanger around 13-3/8". 13. Pick up 10,000# weight on 13-3/8"."Set'casing slips in wellhead bowl. Slack off 13-3/8" into wellhead slips. After casing slips have taken the weight, tighten packoff assembly. Then cut 13-3/8" off 6-3/4" above 20" wellhead flange. (Save this piece for abandonment) Nipple down diverter and drilling spool assembly. Dress stub and install 20" x 13-3/8" packoff. Install Gray's 20"-2M x 13-5/8" - 5M spool, 2-13-5/8" 5M x ditto wellheads and nipple up to Penrod's 13-5/8" x 10M double gate B0P and 13-5/8" - 5M bag BOPE. 14. Test BOPE, wellhead, packoff and casing in accordance with Attachment K. 15. Trim off extended bowl protector t° correct length and re-install in wellhead. 16. Pick up 12-1/4" bit and BHA. GIH and drill out float collar and shoe and cement below shoe. Circulate and dispose of cement contaminated mud. Displace inlet water mud with'fresh water. Build fresh water mud per attachment C and displace fresh water. Build mud weight to 9.5 ppg. 17. Drill 20' - 40' of new hole. Then conduct formation bleed-off test perAttachment L. (4) 18. Drill 12-1/4" hole to 4250' RKB (4050' BOF) ±. Plan is to set 9-5/8" before drilling any potential pay sands. 19. Circulate and condition hole for running logs. Run logs as directed. 20. Following ~ogging operations, condition hole to run 9-5/8" mixed string of 47#/ft., C95 and SS95 BTC casing. Pull wear bushing. Run casing as follows: a. Casing string will be made up per Attachment P. b. Run casing to 4,200' RKB (4000' BOF) ±. Space out casing such that when 9-5/8" DJ-MRR mudline casing hanger is set in 13-3/8" sub sea hanger there will be no 9-5/8" casing collar in close proximity to the bottom 13-5/8" - 5000 surface casing head. c. Check periodically to see that automatic fill up equipment is functioning properly. Supplement by filling from top as required. Drop float equipment tripping ball to actuate check valves. 21. Cement 9-5/8" as follows to obtain minimum of 1,000' of cement above shoe. a. Break circulation and circulate hole clean. b. Pump 30 BFW preflush and release bottom plug. Pump in 200 sx of Class G cement mixed with '24 barrels of fresh water at slurry weight of 15.8 ppg. c. Drop top plug. d. Displace cement to float collar. Calculate displacement volume required to bump plug. Do not over-displace if plug has not bumped when calculated volume has been pumped. Bump plug easy. Pressure up to 2000 psi. Release pressure slowly. Check for back flow. If okay, and if cement circulated, proceed to Step "e" below. If back flow occurs, hold 1000 psi on casing till surface (5) samples set. Then rig down cementing equipment. e. 1. Rotate 9-5/8" eight (8) turns to right to open ports in circulating sub above 9-5/8" sub sea hanger. Circulate out any cement in 13-3J8" x 9-5/8" annulus using water. After annulus clear, close circulating ports with opposite rotation. 2. Drain annulus above BOPE/WH and flush with fresh water regardless if it was necessary or not to take Step 1. 22 Part wellhead at bottom 13-3/8" -5000# flange. Pick up wellhead/BOPE and prepare to install Gray type "W" casing hanger around 9-5/8". 23. Pick up 6500# weight on 9-5/8". Set casing slips in wellhead bowl. . Slack off 9-5/8" into wellhead slips. Cut 9-5/8" off 6-3/4" above 13-5/8" wellhead flange. Dress stub and install Gray Type CWC-P 13-3/8" x 9-5/8" packoff. Install new ring gasket and button up wellhead. 24. Test BOPE, wellhead, packoff and casing in accordance with Attachment K. 25. Trim off extended bowl protector to correct length and re-install in wellhead. 26. Pick up 8-1/2" bit and BHA. GIH and drill out float collar and shoe and cement below shoe. Circulateand condition cement contaminated mud. 27. Drill 20' - 40' of new hole. Then conduct formation bleed-off test per Attachment L. 28. Drill 8-1/2" hole to 10,200' RKB (10,000' BOF) ± or as directed. 29. Circulate and condition hole for running logs. Run logs as directed. (6) 30. Following logging operations, condition hole to run 7" casing or P & A as directed following interpretation of logs. If casing to be run, proceed to Step 31. If well to be P & A, proceed to Step 41. 31. Pull wear bushing. Run 7", 32#, L-80 LTC casing as follows: a. Casing string will be made up per Attachment Q. b. Run casing to 10,200' RKB (10,000' BOF) ±. Space out casing such that when 7" DJ-MRN mudline casing hanger is set in 9-5/8" sub sea hanger there will be no 7" casing collar in close proximity to the bottom flange on the top 13-5/8"-5000 wellhead. c. Check periodically while casing is being run to see that automatic fill up equipment is functioning properly. Supplement as required. Drop float equipment tripping ball to actuate check valves. 32. Cement 7" as~follows: a. Break circulation and circulate hole clean. b. Pump 10 BFW preflush and pump first stage. Cement slurry information and volume will be furnished following log analysis. c. Drop separatiDg plug and displace to float collar. Figure displacement and bump plug easy. Pressure up to 1500 psi and slowly release pressure. Check for back flow. d. Drop stage collar tripping plug and chase to stage collar with joint of drill pipe on sand line. Retrieve sand line and apply pressure to open. stage collar. e. When stage collar opens, break circulation and circulate out excess first stage slurry and clean up hole. f. When clean returns obtained, cement second, stage as directed. (7). g. When second stage cement mixed, drop stage collar shutoff plug and displace with mud. When shutoff plug seats, pressure up 1000 psi over final pumping pressure. Release pressure slowly and check for closure of stage collar. If okay, rig down. If back flow occurs, reapply closing pressure and recheck. If necessary, hold pressure equal to final shut down pressure until surface samples are hard. While WOC, flush out wellhead/BOPE. 33. Part wellhead at bottom of top 13-3/8"-5000# wellhead. Pick up top wellhead/BOPE and prepare to install Gray type '~" casing hanger around 7". 34. Pick up 4500# weight on 7". Set casing slips in wellhead bowl. Slack off 9-5/8" into wellhead slips. Cut 7" off 6" above 13-5/8" wellhead flange. Dress stub and install Gray type CWC-P 13-3/8" x 7" packoff. Install new ring gasket and button up wellhead. 35. Test BOPE, wellhead, packoff and casing in accordance with ~Attachment K. 36. Trim off extended bowl protector to correct length and re-install in wellhead. 37. Pick up casing scraper and 5-7/8" bit and GIH and drill out.stage collar plugs. Circulate and.condition mud to top of 7" float collar. Retest casing. COOH. 38. Runcorrelation log and proceed to perforate and test as outlined in Attachment H. 39. Zones will be tested from bottom up. After.well is'~tested,~Permanent bridge plug(s) ~will be set above perforated inter~als. A 50'.neat cement plug will be set above each bridge .plug, (8) 40. After uppermost bridge plus (BP)' is set, it must be tested by placing 15,000# weight on BP before placing cement on top. After top BP w/ cement cap placed, nipple down BOPE. 41. If 7" casing was run, pull as follows: a. Remove top 13-5/8" -5000 wellhead and 7" packoff. b. Cut 7" with mechanical cutter at 400' BOF. GIH w/spear and pull 7II. c. GIH w/DP into 7" and spot enough cement to fill 7" casing 100' below stub and 9-5/8" casing 100' above stub. d. Pull Up 100' above 7" stub and circulate to dress off top of plug and get hole clean. COOH and go to step 43. 42. If 7" was not run, proceed as follows: a. Place 100' open hole cement plug between Sterling and Beluga formations. b. Place 100' cement plug at 9-5/8" shoe such that 50' of plug is below and above said shoe. c. Proceed to step 43. 43. Pull 9-5/8" as follows: a. Remove the 13-5/8" x 5000# wellhead that was second from top. Then remove 9-5/8" packoff. b. GIH w/DP and mech~nica! cutter to top of cement plug at 300'± BOF. Tag and test plug by putting 15,000# on plug. If okay, go to Step "c". If not, replug, then go to "c". c. COOH to 200' BOF. Cut 9-5/8". COOH and run spear and pull 9-5/8". d. GIH w/DP into 9-5/8" and lay 100' cement plug below 9-5/8" stub and 150' plug above 9-5/8" stub into the 13-3/8". · e. ·Pull up. to. 50! BOF and dress off plug and circulate hole clean. (9) 44. Pull 13-3/8" as follows: a. Remove the 13-5/8"-5000 x 20" -2000 wellhead. Then remove the 13-3/8" packoff. Run piece of 13-3/8" cut off when pipe set originally and weld to 13-3/8" stub sticking up. b. Rotate 13-3/8" twelve (12) turns to right to release tieback sub. Pick up and retrieve 13-3/8". 45. Pull 20" as follows: a. Remove 20"packoff and then cut 20"-2000# wellhead off. b. GIH w/mechanical cutter and cut 20" at mudline and pull same. 46. Pull 30" as.follows: a. GIH w/mechanical cutter and cut 30" at mudline and pull same. 47. Jackdown rig and move off location. , (10) Well Name: Location: DRILLING PROSPECTUS SRS Tern A No. 1 560' FNL and 520' FWL Section 19-T10N-R10N-SM Water Depth: 85 feet MLLW Rig Type Jackup T.D.:: 10,000'± ~D BOF MLLW - RKB: 100' ± GENERAL OPERATIONAL PROCEDURES SAFETY PROGRAM 1. Safety is the first consideration of all working men. 2. It is the responsibility of all Phillips' supervisors to continually observe the operation of men and equipment in order to Create a safe working environment and to make all concerned safety conscious. 3. Supervisors'must attend and participate inthe weekly safety meetings and see to it that daily safety meetings are conducted. It is also a wise precaution to see that a short safety meeting is held prior to the commencement of any non-routine operation and beginning of each tour, 4. Have meetings with the diving team and the diving team leader. Discuss the work to be done, how to do it, and, if the divers think they can do the job, go ahead..If the divers do not think they can do the job in question, for safety reasons, do not insist. Consult the next team; maybe they are confident that the job can be done. If a diver thinks he-can'do a job, he usually can, and safely too. 5. Check persons arriving onboard for sickness. The incoming crews can bring dysentery, grippe, flu ~and many communicable diseases on board. Do not let a sick man stay on board and expose everyone. 6. Safety is everyone's business. Let us work together to have a safe operation, make arrangements for relief crews. This also applies to the work boats on long anchor handling jobs. 7. When the supply boat drops anchor and backs into discharge or receives cargo, it will back under the crane, but will stand off as far as possible from the rig. Personnel baskets will be u.sed only for emergency transfers of personnel. RECE~VE~ ~'~nchoraga 8. The contract helicopter will be equipped with navigational aids to permit emergency transportation during IFR conditions. There will be no sling loading except when absolutely necessary. DAILY DRILLING REPORT A verbal report following the format of Exhibit A covering the period from 0600 hours one day to 0600 hours the next will be telephoned by the Phillips Drilling Supervisor on the rig to the Phillips Drilling Superintendent in Anchorage at 0700 hours each day. A scrambler shall be utilized to report confidential information on oil and/or gas shows, geological data, DST data, perforations and production tests. When reporting letters of the alphabet or numbers, use a quasi-military system for alphabetical letters, e.g. A-Alpha or Andy, B-Bravo or Bob, etc., and report numbers individually, e.g. 921 should be reported as nine-two-one, not nine hundred twenty-one. Each morning, report the total cost incurred on this drilling project during the past 24 hours. OTHER REPORTS Ail written reports Called for shall be sent to the Anchorage Office on Wednesday of each week. IADC DRILLING REPORT The Phillips Supervisor on the rig shall insist that the Penrod Drilling Contractor personnel fill out the subject report comPletely and ~. Two copies of said report are to be submitted to the Anchorage office. MATERIAL HANDLING AND EXPEDITING Drilling Contractor will maintain a record of all Phillips Petroleum Company material coming on board and they will issue a material transfer for all materials (except mud and additives) used on the rig. The trans- fers will be signed by the Phillips Supervisor on the rig. This is a must. Cargo manifests will be made for any equipment taken aboard .or off the rig via helicopter. .~ A written Material Requisition system will be followed for procurement of parts, tools and supplies for Phillips. These requisitions will be pre-numbered and prepared in triplicate by the Phillips Supervisor on the rig and two copies sent to the Material Expediter in the Kenai Office. The expediter will send one copy back to the rig at the time the material is shipped. It is the Phillips Supervisor's responsibility to avoid making verbal material orders by anticipating material requirements sufficiently in advance for a written requisition system to function effectively. Phillips' Supervisor on the rig will be responsible for regulation of boat traffic and proper handling and accounting of all incoming and outgoing materials. (2) CURTAILMENT OF CRITICAL OPERATIONS Listed below are the limits in which critical operations will be curtailed. Critical Operation 1. Run casing - start if forecast & present condition is less than ....... 2. Drill-stem testing - start if'fore- cast & present condition is less than .. Test tools will not be opened at night. Wind Velocity Wave Hei~h 50 kts 25 fee 50 kts 25 fee 3. Logging and wireline operations -- start if forecast & present condition is less than ........................ ... 50 kts 25 fee MUD PROGRAM A copy of the Mud Program (Attachment C) shall be kept at the rig for ready reference by the mud engineer, contractor tool pusher and the Phillips Supervisor on the rig. ThisPhillips Supervisor is responsible for having the mud engineer: 1. Keep him informed on.quality and quantity of mud in the system and the stock of mud and chemicals on hand as well as the daily maintenance cost. 2, Maintain the mud and mud conditioning and monitoring equipment in conformance with the program. 3. Maintain surveillance on the drill pipe corrosion rate. The Phillips Supervisor on the rig is responsible for having the drilling contractor: 1. Follow the hole fill-up procedure outlined in Attachment E when making a trip; 2. Record mud.weight and viscosity at the shakers at. the pump suction every 15 minutes while drilling ahead 'or circulating in open hole with gas cut mud; 3. BeCome knowledgeable on the Phillips Diaseal M squeeze procedure (Attachment F) for sealing off lost circulation zones. KICK CONTROL PROCEDURES Kick Control procedures are shown in Attachment D. Appropriate precautions and procedures are given for kick control during various phases of drilling operations and should be displayed at places convenient for the driller and rig supervisor. (3) HYDROGEN SULFIDE OPERATIONS PLAN Hydrogen sulfide is not expected. Therefore, no H2s contingency plan is provided. DRILLING BREAKS If a drilling break occurs'(double rate of penetration) the following procedure will be followed: 1. Drill not more than 5'. 2. Pick up off bottom. 3. Notify Phillips Drilling Supervisor & Geologist and Penrod Senior Pusher on the rig. 4. Shut down pumps and check flow nipple for flow or .loss. 5. 'If well flows close Hydril, choke and kill line valves. Record drill pipe pressure as well as casing pressure each five minutes until drill pipe pressure becomes static. 6. If well does not flow, Geologist will determine if break warrants circulating bottoms up. CASING RUNNING AND CEMENTING REPORT The Phillips Supervisor .is responsible for preparation and submission of a copy of the Casing Running and Cementing Report (Attachment R)~following a casing job. 'A Carbon copy shall be retained at, the location. CORING PROGRAM Core points will be picked by the Phillips Geologist. Full diameter cores are anticipated to be taken. Use a Christensen 6-3/4" x 4" x 60' core barrel with 8,1'/2~..diamond~core head during coringoperations. Use near bit stabilizer and another stabilizer at the top of the barrel. The Phillips supervisor is to be present when the core is pulled. The cores will be analyzed by Core Lab in Anchorage. Materials for "canning" the cores will be supplied by Core Lab. Sidewall cores may be taken using Schlumberger following the running of open hole.logs as directed by the Phillips Geologist. The Phillips Geologist is responsible for distributing core samples to Core Lab and Alaska Oil and Gas Conservation Commission. (4) LOGGING FBOGRAM · , The following open hole logs will be run at each casing point below the 13-3/8" casing. 1. Dual Induction Laterolog (DIL) - Spherically Focused Log (SFL) with SP, GR, caliper, Microspherically focused log (MSFL) may be run over hydrocarbon bearing zones. · . . 2. Borehole Compensated Sonic Log with integrated travel.'time, samma ray, and caliper. (UR to be run' all the Way back'to mud' line on first logging'run)' 3. Compensated Neutron and.FormationDensity'Log,with'gamma ray and caliper. 4. Long Spaced Sonic Log ~/ GR'. BHC Sonic w/GR may be run also. 5. Four-arm Continuous Dipmeter. NOTE: 1. All logs are to be run from T&D.'to casing.shOe. 'The service company will'supply .PhillipS.with .three'field prints.and.three final prints plus' one sepia'of'each.log. A digital library tape and.dipmeter tape will also be provided. Logging operations.will be supervisedby, the Phillips Geologist.and/or Engineer on board. .The.Phillips Geologist is responsible'for'distribUtion of the log prints.and log tapes. However, two' (2)'Copies of all field prints shall be prOcured'by Phillips Supervisor or Engineer and sent to the Anchorage Office. 'HOLE'AND'CASING'PROGRAM The following table presents the proposed~Hole and Casing'Programfor the well: Hole· Size ' '.' I~ches 36 or drive 26' 17-1/2 . 12-1/4" 8-1/2". · .Casing .. · < size' a~d' Grade 30" .625' wall Gr.B 20" .K-55 13=3/8" L-80 . 9-5/8" C&S-95 7" L-80 . Weight . '" (Lb/ft.),' . 1.96 133 72 47 32. 'Type.of. ''Threads' Weld BTC BTC BTC . LTC · Settimg ...... · 'pepthii 50 - 100' 250 + 1000 _+ 4000 _+ · (10,000 +_) (5) Anticipate your cement needs far in advanCe so that adequate supplies will be on board when needed. The proposed cementing will be as shown in Attachment G. The proposed volume and additives could vary depending on hole conditions. DEVIATION PROGRAM A "straight" hole is planned and is to be drilled in accordance with the following specifications: Well Depth RKB Maximum Distance Between surve¥,s Max. Deviation From Vertical Max. Change of Angle Between Surveys 1 - 200 Water & Air Column '200 - 450 100' 450 - 1200 300' and/or @ bit 1200 - 4200 500' and/or @ bit 4200 - T. D. 500' and/or @ bit N/A 1° 2° 5° 8° N/A l°/100' l°/100' or 2°/300' 1 1/2°/100, or 2 1/2°/500' 1 1/2°/100' or 2 t/2°/500' A "Go-Devil" non-magnetic single shot survey instrument may be used to determine hole deviation to 13-3/8 inch casing setting depth. After 13-3/8 inch casing is set, a magnetic single shot survey instrument will be used to determine hole angle (inclination) and direction (azimuth). The azimuth shall be reported as recorded by the instrument and also as corrected to Lambert-Grid NOrth. If it becomes necessary to. deliberately correct the course and/or angle of thehole, magnetic single shot surveys shall be taken at 30' intervals and ~ngle change shall be limited to 2°/30' and 3-1/2°/100'. DRILL STEM TESTING PROGRAM Possible zones of interest will be selected by the on board geologist for testing. The decision.to test will be made following consultation with Denver Exploration and. Anchorage Production Offices. The Phillips Supervisor on rig will direct the testing operation in accordance with the general procedure outlined on Attachment H. Attachment I illustrates the test string. WELL HEAD SYSTEM AND BOP SYSTEM A. No diverter need be employed on the 30" conductor pipe while drilling to the 20" casing point (250'BOF) because wellbore conditions do not require it. Two wells (Shell SRS State No..1 and 2) have already been drilled in the near vicinity on the same structure and in the same lithological sequence and no shallow drilling hazards were encountered. Once 20" is set, a diverter will be used to drill to 13-3/8" casing point (1000'BOF) although no shallow drilling hazards are likely for reasons given above. (6) B. A surface well head and BOP system (conforming to API RP53) together with a mudline casing suspension system will be employed after 13-3/8" is set at 1000' BOF. The BOP system will consist of~a 10,000 psi double gate unit and one (1) 5000 psi Hydril annular preventer. Attachment J illustrates the BOPE, well head and mudline suspension equipment. Control equipment and operating procedures are discussed also. BOPE AND CASING TESTING'REQUIREMENT 1. BOPE Testing'Requirements Ail BOPE equipment will be tested prior to and upon installation, prior to. drilling out a casing shoe, following repairs that require breaking a pressure Seal assembly,' and not less than once a week. The weekly test will be made the first trip out of the hole after 12:01 a.m. each Tuesday. Attachment K outlines the procedure to test BOPE. The table below shows the pressure requirements for each test operation. .Test Operation · ' Pipe ' R~ams Annular ''Ch0ke"&'Kill'Lines Test Stump (Prior to Instal- lation) 3,500 3,500 3,500 Initial Installation & after Ram~Change 3,500 3,500 3,500 Before Drilling 20"shoe & Weekly Test of Diverter N/A 250 500 Before Drilling 13-3/8" Shoe and Weekly Test of BOP 3,500 2,500 3,500 Before Drilling 9-5/8" Shoe and Weekly Test to T.D. 5,700 2,500 5,700 Before testing in 7" 5,700 2,500 5,700 2. Casing Testing Procedures and Pressure Requirementsare outlined in Attachment K. WELL LOG'QUALITY'CONTROL'CHECKLIST' (FORM' 10128) The Phillips Representative (Geologist or Engineer) present during logging operation is responsible for obtaining top quality logs. As an adjunct to this responsibility, the Phillips Representative will in cooperation with the loggingserviCe, engineer complete the subject logging checklist (Attachment B) and submit the completed form together.with two (2) copies of the field prints of the logs to the Anchorage Office. (7) _MUD. LOGy PORE PRESSURE PLOT & "D" EXPONENT PLOTS The Phillips Supervisor will obtain two copies of the Mud Log, Pore Pressure Plot and "D" Exponent Plots. Retain one copy and submit one copy to Anchorage office. DRILLING MUDREPORT The Phillips Supervisor on the rig shall submit to the Phillips Drilling Superintendent, the weekly accumulation of the Daily Drilling Mud Reports prepared by the mud engineer. Said report will show the daily mud additions and the cost thereof. SERVICE TICKETS The Phillips Supervisor on the rig is responsible for requiringfield service tickets from all contractors performing work and for examination of all said tickets for completeness and accuracy. The Phillips Supervisor is to sign only those tickets that satisfy these criteria. On tickets that do not meet these criteria which cannot be resolved at that time, make an appropriate statement on the ticket and initial same. MUD LOGGING A mud log will be maintained from the spud to T.D. The Phillips geologist will supervise the routine activities of the mud logging contractor. In addition to the parameters always logged, the mud logger will monitor the following parameters: Pore Pressure 'D' exponent plot The Phillips Supervisor shall closely monitor the results of the above special checks in cooperation with the geologist so a safe, controlled drilling program can be achieved. Due to the number and character of drilling cutting samples required on this well, two mud loggers will be working'per shift early in the life of the hole. As the penetration rate declines with increasing depth, a point will be reached where one of the mud loggers can be released. This determination will be made by the Phillips geologist. S~2~PLING PROGRA/~ The mud logger will catch samples as directed by Phillips' geologist. Phillips' geologist is responsible for distributing samples to the Alaska Oil and Gas Conservation Commission. (8) FORMATION BLEED-OFF TESTS A formation bleed-off test will be conducted after drilling less than 50 feet outside the 13-3/8" casing shoe. Subsequent tests will be carried out when deemed necessary. The test procedure is outlined in Attachment L. CHANGES Phillips Petroleum Company reserves the right to make any changes to this program at any time. Prior to making any procedural changes, Alaska Oil and Gas Conservation Commission approval must be obtained. (9) Exhibit "A" Phillips Petroleum Company Anchorage Ama [ C .... DAILY DRILLING REPORT D'ilY O'iilng I Da~psI~73ceIReport No. PPCo. Supervisor(s) DRLG Contractor I WellDaily Cost I Cum Cost Bit No. Size Type Serial No. Jets Depth In Depth Out Footage Hours T-B-G , Remarks · Rotan Standpipe Uner BTMS Bit No. WOB RPM Torque Press PMP No. Size SPM GPM AVDC AVDP AV Riser Up Time BHA Length Ft. MW VlSC. PV YP WL FC Ph % Sd. % SOL Catt ALK % OIL HTIHP--WL/FC CHLORIDES GELS ECD I Mud Cost (24 Hr.) $ Mud C~st (Cum) $ Pit Vol. BBLS Hole Vol: BBLS Mud/Chemical Used (24 Hr.) FORM Est PP Shale D - Mud Wt. In/Out Mud 'F In/Out Chlorides In/Out Mud Log Data ILast Casing Leak Off Isl°w Pump Size MD TVD Buret Test PPG SPM GPM PSI [ Last BOP Test I Last BOP Drill I Shutin Time ! Last pVT I'"Barite I Cement Fuel I Dflll Water i Casing Jar SN. Cum. Hrs. Run: Shock Sub. SN. Cum. Hrs.: Time Hours Report Detail (use back of sheet if additional space is needed) ~Chora~o' - ~" Weather · Wind DIr. Wind Vel. Temp. ~F *F CF Sky Vis. Miles BAR Data Personnel on Rig: ~ntractor P~O Othem Total PROPOSED 560' FNL & 520' FWL' ) / / , , ~~o ' 9.N / '" ..... I sA ~/z V4 0 MLLW DATUM SCALE IN MILES I" -- I MILE FROM U.S.G.S. i~ 65~:~60 SCALE MAPS KENAI (D-4) AND C,&G.S. Kusto;,n~3 ' _ ~~.' ~LOCAT4ON i ~ ~ ~ ~ ~ U.S'S. ALASKA MAP VICINITY MAP SCALE IN MILES 0 25 50 M.H.W. · 20.2:' M.L.L.W · O~ · BOT?O¥ ,U~E · ,qO'~- ~0' Gas Cons. Com RIG. TYPE - JACKUP i SRS UNIT TERN A WELL No. I EXPLORATORY DRILLING PROJECT North Cook Inlet Alosko 8 Miles SSE of Tyonek Villoge Phillips PetrOleum Compony 2525 C STREET SUITE 508 ANCHORAGE, ALASKA . Dote: 1/25/82 PHILLIPS PETROLEUM COMPANY ANCHORAGE, ALASKA 99503 2525 C ST., CIRI BLDG., SUITE 508 PHONE: 907 279-0606 TELEX: 090 26555 EXPLORATION AND PRODUCTION GROUP Anchorage Area CERTIFIED NO. P316-248-015 RETURN RECEIPT REQUESTED March 22, 1982 File: A-JFS-135-82 Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: SRS Tern A No. 1 - Sec. 19-10N-lOW, SM Attached, in triplicate, is an Application for Permit to Drill the subject exploratory well. Our tentative plans would be to start drilling this well in late May or early June, 1982 when the rig is scheduled to arrive from the shipyard. If you have any questions concerning our proposed program, please give us a call at 907-279-0606. JFs/m~P/t~ct Attachment RECEIVED Oil & 6as Cons, Com,rniss.~0lI BLEED-OFF TEST PROCEDURE ttachment L 1. After drilling 20' - 40' of new hole below the casing shoe, pull up above the casing shoe. 2. Close BOP and pump down drill pipe at 1/2 BPM. 3. Measure and record the cumulative volume pumped and plot against the drill pipe pressure during the test until the bleed-off pressure is reached. Do'not exceed calculated maximum'test pressure. 4. Shut the pump downand record the instantaneous shut-in pressure. Shut-in for 10 minutes and record the pressure decline on 1-minute intervals. 5. Release the pressure and record the volume of mud recovered. Isolate the shaker tank and use it to measure the volume recovered. Compare the volume recovered to the volume pumped. 6. Record the observed bleed-off pressure on the tour sheets. Complete the~bleed-off test report. Send the report and pressure plot to the Anchorage office. (1) BLEED-OFF TEST REPORT Attachment L Well Name & No. Pump Type Mud Wt Casing Size Open Hole TD Date Time Liner Size Stroke Length Vol BPS PV YP Gels WT Grade Shoe Depth "' ·Volume " '". . ' ..... i~olume .... i~olume . 'i'. · iTime iPump~ed~ Pressure ,..'iTime P.umped ?ressure. 'i i!T'ime .Pumped iPressure · · . · . · , . · ~ ,,, ', ~ ~ · ,, _ · . ,,,,,,, , · . ,,, - ~ , - . ,,,,,, · · · . · . · . . · . · ...... . . , . · . . Volume ~ecovered after releasing pressure: bbls. Observed bleed-off pressure: psi. Equivalent Mud Weights and Gradients: A. At Casing Shoe: E. M. W' = Actual Mud Wt. + (bleed off pressure ) (0.052 x casing shoe TVD) E.M.W. @ Csg. Shoe = #/gal. Equivalent Gradient =-~5"2 x E.' M. ~. = B. At TD: (if significantly deeper than casing shoe) psi/ft. E M. W. = Actual Mud Wt. + (bleed off Pressure ) ~,~ ~ (0.052 x Open hole TVD) '~"~ '~'f(a Oil & Gas Cons, c:,-~- E M. W. ~ TD= #/gal ~"::~' ' ',' '~""~'~' ""' Equivalent Gradient = .052 x E. M. W. = psi/ft. (f ~adeyes for~/ Handling Two/Joint these Remove after tjI. Padeyes joint ,make Att~f~_nt M 40' + its.Of 30" 196~! Grade'B Smls Line pipe (1) )'(~) (1) (1) 30" x .750 Wall Grade B Drive JACKUP 20" CASING STRING Attachment N 40' +_- 20"; 133# K55 BTC Casing (1) (1) (1) · (1) . Gray Type DJ-S Casing Housing-Plabe 20' + 5' belc~ mudline (1) (li (1) (1) · Stab-in Float Collar (1) Conventional Float Shoe Torque BTC Pipe to ~ mark center Three (3) Centralfzers will be spaced as follows: 1 - 7.5' above shoe 1- Top of 2nd and 5th joints Thread lock all connections on bottom.three (3) joints ~3 3/~". CAS~ STR~ Attac3unent O 13 3/8" - ?2# L80 BTC (1) casing (1) (1) (1) . Gray 18 3/8" O.D. x 13 3/8" Type bJ-MSR mudline casing hanger (Box x Box) with Gray type DJ circulating assembly (1) (1) Stab-in float collar 40' + ~~ BTC pi~ tO ~ mark center ~read 1~ all ~~ions on ~tt~ ~r~ (3) join~ N~e (9) ~n~alizers will ~ s~~ as folly: 1- 7.5' ~ve sh~ 1 ea~- top of jolts 2, 5, 8, 11, 14, 17, 20 ~ 23. Attachment P ' ~'5/8" '47# C-95 BTC Csg-- 2350'+2' Gray 13 3/8"'x 9 5/8" type DJ-T mudline casing hanger with Gray 'type DJ circulating.assembly 9-5/8" 47# SS-95 BTC 'Csg - 1850'_+ Automatic fill float collar 40' + 47~,SS-95.~TC Au~natic fill float shoe ~read lock all connections on bottc~n three joints. DO NOT TACK ~,D C-9.~ Place centralizers: 1 - 7.5' above shoe and 1 on 2nd,. 5th, 8th & llth jolt Attadmmant Q ' .7" 32%, L-80 LTC casing Gray 9 5/8" x 7" type DJ-MRN mudline casing hanger with Gray Type DJ circulating assembly Automatic fill float collar 2 jts. of 32#, L-80 LTC casing Automatic fill float shoe · . . Thread lock all connections on bottom three (3) joints. Torque for 32#-N LTC is 6,720 ft-lbs. : .. Centralizers will be placed as follows: 1 - 7.5' above shoe; 1 every 120' +_ thru pay zone(s) and every 200' + thru non-pay zones to be cemented. · CASIi:G AND CEMENTING REPORT RUNNING Lease & Elock Number '~ Well Number Date Date Region & Area Contractor & Rig CASING DESCRIPTION (BOTTOM TO TOP) quantity Size Make or Model Weight Grade Thread Length Total Length. Casing Run RKB To Casing Hanger Seat Casing Setting Depth (,Feet RKB) Centralizers and Accessor. ies. (Make, Typ. e..&..Depth) ,, CEMENTING DETAILS Date Circulation Time I Start I Stop Preflush (Amount & Type) Cementing Time I Start Stop ..... Total Total Lead-in Cement (Amount, .Type, Additives & Mix Fluid) Slurry. Weisht.. Samples Tail-in Cement (Amount, Type, Additives & Mix Fluid Top Cement Plug I Pumped To feet @ INCLUDE ADDITIONAL INFORMATION ON BACK I Averase ps,,i Attachment K BLOWOUT PREVENTION EQUIPMENT TEST PROCEDURES The blowout preventer stack shall be tested at the following times: (a) On Test stump prior to installation; 70% of r~ted working pressure (b) (c) for blind rams, pipe rams, valves and Hydrils. ..~ Immediately after installation: 50% of rated working pressure for all pipe rams, valves, and ~ydrils. The blind rams will be tested .... to 13-3/8" casing test pressure. . / Weekly on the first trip out of hole after 0001 hours Tuesday: 70% of the minimum internal yield pressure of the exposed casing for pipe rams, valves and Hydrils. The Hydril test will be limited to 50% of working pressure. However, blind rams shall only be tested prior to drilling out casing to casing test pressure. Each BOP control system shall alternately be used from week to week. (d) After any repairs or on reinstallation after pulling; 70% of working pressure for any item replaced or repaired. The remainder of the stack'will be tested to the applicable weekly test pressures. (e) Prior to starting well test program; 50% of BOPE working pressure or expected surface shut in pressure, whichever is highest, for blind rams, pipe rams, choke/kill lines and valves. The be limited to 50% of working pressure. Actuation tests of blind rams will be performed while out of the hole, once each trip, unless several trips are made in a 24 hour period then once each 24 hours. NOTE: Ail preventers to be tested will be tested at a low pressure of 200-300 psi for 3-5 mins. prior to high pressure testing. (1) ('~'~.ttachment K At time of installation of BOP stack, all valves in the choke manifold should~~ be tested to 50% rated working pressure against the closed gate. ~~f~ During weekly BOP test, all valves on choke manifold will be closed and tested to ram test pressure. The Kelly cock, safety valve and inside BOP shall be tested at same time and at the same pressure as BOP tests. SAFETY PRECAUTIONS: One pumping unit operator is to be stationed at the high pressure pumping unit. The operator remains at this station until all testing has been completed. The operator is to be in Continuous contact via the telephone provided at the unit. The Phillips Supervisor and the Drilling Contractor Supervisor onboard will be the only personnel who will go into the test area to inspect for leaks when the equipment involved is under pressure. The rig crew are to stay clear of the area until such time that both the Phillips Supervisor and the contractor's supervisor have contacted the pumping unit operator and all three have agreed that all pressure has been released and that there is no pressure remaining in the system, trapped or otherwise. The rig crews may then go into the area to repair leaks or work as directed. Ail lines, swings, and connections that are used in the testing of the blowout preventers are to be adequately secured in place. Pressure is to be released only thrOugh the pressure release lines that arevented back into the pump unit tanks. The lines are clamped down as well as being fitted with swivels to direct the flow into either of the two unit tanks. (2) REQUIRED B.O.P.E. TEST PRESSURES: Test Operation Test Stump (Prior to Installation Initial Installation & After Ram Change Weekly Test Below 20" casing Before Drilling 13-3/8" Shoe and Weekly Test Before. Drilling 9-5/8" Shoe and Weekly Test to T.D. Before Testing in 7" Rams Annular Attachment K age 3 ~hoke & Kill Lines 7,000 3,500 7,000 5,000 2,500 5,000 NA 250 500 3,500 2,500 3,500 5,700 2,500 5,700 5,700 2,500 5,700 CASING AND BLIND RAM TEST The casing strings will be tested simultaneously with the blind rams. After pulling test plug from wellhead close blind rams and test to required pressure listed below for 30 minutes. REQUIRED TEST PRESSURES: 13-3/8" 9-5/8" Casing K-55 L80 SS95 & C95 7" L80 133 lb/ft 72 lb/ft 4'7 lb/ft 32 lb/ft Casing & Blind Test Pressure 2,000 psi 3,500 psi 5,700 psi 5,700 psi ~".~ttachment J BOPE OPERATING PROCEDURES & SCHEMATIC DIAGRAMS A. DIVERTER INSTALLATION AND OPERATIONAL PROCEDURE Installation Procedure 1. A 2000 WP diverter will be used when drilling from 250' to 1,000' BOF; i.e., from 20" casing seat to 13-3/8" casing point. 2. The diverter~ will be nippled up on top of 20" wellhead as illustrated in Drawing No. 1. 3. A drilling spool with 12" side outlet will be employed between diverter and ri~er/wellhead. 4. A 2000 WP normally closed full-open type automatic valve will be emploYed on the drilling spool outlet. The valve will be controlled hydraulically and be tied into the same hydraulic control that serves the diverter. When hydraulic force is applied to close the diverter, the automatic valve will open fully. 5. The vent line downstream of the automatic vent valve will be tied into two 10" diversionary vent lines so that any emission can be made down wind of the rig. ValVes will be installed on each diversionary line for control'purposes. B. BOPE INSTALLATIONAL PROCEDURES & SCHEMATIC DIAGRAMS ~, 1. The BOPE stack will be installed after the 13-3/8" casing installation and cementing. BOPE will be~in place for the remainder of the program. Drawing No. 2 illustrates BOPE arrangement. 2. Ail pipe rams will be at a size to fit the drill pipe in use and the bore of all BOPE and spools will permit the running of the largest tools that the casing below the preventers can accommodate. 3. Ail BOPE will be equipped with: a. A hydraulic actuating system that provides sufficient accumulator capacity to close all blowout prevention equipment units With a 50 percent operating fluid reserve at 200 psi above the required precharge pressure when all BOP's are closed w/primary power off. A high pressure nitrogen or accumulator back-up system will be provided, with sufficient capacity to close all blowout preventers and hold them closed. Locking devices will be provided on the ram type preventers. b. Two control stations, one at the driller's stat'ion and one remote away from rig floor. ~ ~[ ~ ~ V i:~ ~'i~ Attachment J 4. The kill lines and chokes on BOP will have at least two control valves. 5. The choke manifold will be installed as shown on Drawing No. 3. 6. Ail valves, pipe and fittings that can be exposed to pressure from the Wellbore will. be of a pressure rating at least equal to that of the blowout prevention equipment. 7. A top kelly cock will be installed below the swivel, and another will be installed at the bottom of the kelly and s° designed that it can be run through blowout preventers. 8. A back-pressure valve shall be used in the drill string while drilling into potentially over-pressured zones. 9. An inside blowout preventer and a full opening drill string safety valve in the open position will be on the rig floor at all' times while drilling operations are being conducted. Valves will be on the rig floor to fit all pipe that is in the drill string. A safety valve will be available on the rig floor to fit the casing string as it is being run in the hole. 10. The bore hole shall be kept full of mud at all times. To assure early detection and thereby early reaction to swabbing, lost circulation or influx of formation fluids, the following mud system monitoring equipment (with derrick floor indicators) will be installed and used throughout the period of drilling after setting and cementing the conductor' (13~3/8'') casing. a. Recording mud pit level indicator to determine mud pit volume gains and losses. This indicator shall include a warning device. b. Mud volume measuring device for accurately determining mud volumes required to fill hole on trips. c. Mud return Or "full hole indicator". d. Gas-detecting equipment to monitor the drilling mud returns. , 11. Ail. BOPE and associated equipment Will be installed, tested and operated in accordance with Alaska Oil and Gas Conservation Commission Regulation 20.AAC. 25.035. (API RP 53) (2) -, OPTIONAL. EQUIPMENT · FILL--UP LINE KILL L.INE BLIND RAMS' EMERGENCY. KILL. L.INE PIPE RAMS · CHOKE OP'T'ION t t~! ' mm mmm m -- em Immm~ mm mi DOUBLE PREVENTF_r~ OPTION BLIND RAMS PIPE RAMS O ION IIBII OR MAY.BE SUBSTITUTED ., "1 CHOKE OPTION I . .. SUBSTi~TED - NOTES: 1. · · m i m i SER. 1500 HYDRIL. GK SER. I 500 RAM--TYPE BOP 311 SER. 1500 VALVE SER. 1500 DRIL. LING SPOOL. 3~" SER. 15ooix ~,mm SER. 1500 STEEl. TEE 2II SERo 1500 VALVE ;ZI1 MUD PRB:SSURE GAUGE: I 3II S£R. 15001X ~.m~ SE~. 1500 STEEL. CROSS : ' I , ; 2II SERI 500 AD J, CHOKE I 2II SER. 15001ADJ. CHOKE ON 2;;SER. 1~00 RISER VALVE ON SIDE OLrTI.~T OF 2Im SER. 1500 STEEL TEE ADAPTER. 2I1 ~ER, 1500 X 3 I/ 16I' I0,C~00 I.e WP,..~R OTHER 'IA.GE MAT,,IG ,.,,.-r (~ I 0,000 CB WP RmrMo'rE CHOKE HYDRAUL,C CHO,<E. aS00 '" WP OR BET'TEaI @ 3II SER. I500~CHECK VALVE i sooo PSI'WP oR BL~'TER C~.AMP HUBS MAY BE SUBSTITUTED FOR FLANGES I ONE ADJUSTABLE CHOKE MAY BE REPLACED I. 3,' VALVES MAY BE E IT~I~ER HAND OR POWER · OPERATED BUT', IF POWER OPERATED. THE V~kLVES FLANGED TO THE B0~ RUN MUST BE CAPABLE OF' BEING OPENED AND CLOSED MANUALLYC~R CLOSE ON POWER FAILLLRE AND BE CAPABLE OF BEING OPENED MANUALLY I PHILLIPS PETROLEUM COMPANY ! 5000 PSI WORKING PRESSURE BI. OWOUT P~EVENTER HOOK-UP ,, (SERIES I S00 .FLANGES OR .BETTER) · REV 6/73 FIGURE NO. 5 Atta~t J Page ~ "5'PI(A5 SURFACE for J;KZKUP RIG" 43 'BORE · , .. 35 : 2! 5 46 ~2 15 .. . . ,. .,. ~!~-, 20'O,D, CASING 13-~ O.D. CASING . 5,000 MAXIMUM SERVICE'PRESS g-$~*O.D.CASING ' FOR: PHILLIPS PETROLEUM CO.'. '- .tL..~:~ 7"O.D. CASING-' ~w. x.~ ~.~~ s~ GRAY TOOL COMPANY ,.' ,:,,..--W, I0.000. TEST_ GRAY. WELL HEAD-E QUIPMENT. ~,~:~i:~ n;,~ ~, ~, ' ' 20~13%'x9{~7' QD. ASSEMBLY ~?~s. Co~ ,1 lol I -, ' . ' ' .... ' ' I ] ! " ' ' ': '-!~ I .... I ' '1 ' .: ..... -'--' - · ?*,,~ ~- ' I - . -- o~u~o ~o. -~- ~ E 15891 ' - !, I I I I.-. 1004 ' I I I .: .o '-/ · : o. · o · · o · o · o · Attachment Typical Mudline Suspension Sys~ for Jackup Rig ( :tachment G CEMENTING PROGRAM A. 30 INCH STRUCTURAL CASING - SET 100' BOF The 30 inch string will be cemented back to ocean floor with 500 Sacks Class "G" and 2.5% pre-hydrated salt-gel mixed with salt water followed with 500 sacks Class "G" cement mixed with sea water. Lead-in cement properties will be as follows: Yield ~ 1.94 cu. ft. slurry per sack Density - 12.8 lbs. per gal. slurry Tail-in cement slurry properties will be as follows: Yield - 1.15 cu. ft. slurry per sack .Density - 15.8 lbs. per gal. slurry B. 20 INCH CONDUCTOR STRING - 250' BOF The 20 inch string will be cemented back to ocean floor with 500 sacks Class "G" and 2.5% pre-hydrated gel mixed with sea water, followed with 500 sacks Class "G" cement mixed with sea water. Lead-in cement slurry properties will be as follows: Yield - 1.94 cu. ft. slurry per sack Density - 12.8 lbs. per gal. slurry Tail-in cement slurry properties will be as follows: Yield - 1.15 cu. ft. slurry per sack DenSity - 15.8 lbs. per gal. C. 13-3/8 INCH SURFACE STRING - 1000' BOF The 13-3/8 inch string will be cemented back to ocean .floor with 500 sacks Class "G" cement mixed with 2.5% pre-hydrated gel and fresh water,~ followed with 300 sacks Class "G" cement mixed with 2% CaCL fresh water. Slurry volume requirements premised on 100% excess in open hole section. Lead-in cement slurry properties will be as follows: Yield - 1.94 cu. ft. slurry per sack Density - 12.8 lbs. per gal. slurry Tail-in cement slurry properties will be as follows: Yield - 1.15 cu. ft. slurry per sack Density - 15.8 lbs. per gal. D. 9-5/'8 INCH INTERMEDIATE STRING - 4,000' BOF The 9-5/8 inch string will be cemented at least 500 feet above upper- most possible hydrocarbon bearing zone. Phillips' Anchorage office will furnish the cementing program and procedure prior to reaching casing point. A tail or main slurry, depending on whether or not zonal coverage is required, consisting of 400 sx of Class !'G" cement mixed with fresh water will be pumped to obtain at least 1,000' of coverage above the 9-5/8" shoe. Tail in or main cement properties will be as follows: Yield - 1.15 cu. ft. slurry per sack Density - 15.8 lbs. per. gal. NOTE: Additives will be added to each slurry to obtain adequate pumpability time. The amount of additives will be determined by lab tests prior to cementing using actual conditions. E. 7INCH PRODUCTION CASING - T.D. The 7 inch casing will be cemented with Class "G" cement mixed with a friction reducer, retarder and fresh water. The volume will be determined by caliper survey in open hole and adequate to place a minimum of 500' above any hydro-carbon bearing zone. A two stage job will probably be required to do this, unless we elect to use an ultra-light weight slurry, e.g. 10.75 ppg. Tail cement properties will be as follows: Yield - 1.18 cu. ft. per sack Density - 15.6 lbs. per gal. of slurry Phillips' Anchorage office will furnish the cementing program and procedure prior to reaching casing point. NOTE: Additives will.be added to slurry to obtain adequate.pumpability time.. The amount/type of additives will be determined by lab tests prior to cementing using actual conditions. F. CEMENT SURVEYS AND REPAIR If there are indications of improper cement jobs on the surface, intermediate and production casing strings, either a temperature log or cement bond log will be run to verify that they have been adequately cemented. In the event remedial cementing is indicated, a sundry notice will be submitted outlining our suggested remedial program. (2) Attachment H DRILLSTEM TESTING PROCEDURES A. PREPARATION 1. Notify Alaska Oil and Gas Conservation Commission at least 48 'hours prior to testing. 2. Ail anti-pollution equipment should be checked to make sure it is operational. 3. Ail safety equipment on vessel should be checked and repaired as required; i.e. H2S gas masks, resuscitors, and fire extinguishers. 4. The testing procedure will be reviewed by the drilling supervisor. 5. Blowout preventers and annular preventers are to be tested to Phillips specifications prior to perforating and testing operations B. PERFORATING THE WELL 1. Hole will be filled with an overbalanced~fluid. The fluid in the hole will be at least the equivalent circulating density (ECD) of the mud which safely drilled test zone. 2. Prior to arming guns, the rig radio Operator will notify the .supply vessel and switch-off all rig. transmitters. It will be acceptable to monitor marine VHF; however, all transmission on rig and supply boats radios is prohibited. 3. Prior to arming guns, all electrical equipment which could' accidently fire gun will be switched off. (i.e. electric welding machines, etc.) 4. R. U. Schlumberger to perforate zone. Arm and run specified perforating gun through BOP. 5. Radio and electrical equipment can be returned to normal service when perforating gun is 500 feet below ocean floor. ~'"~tachment H 6. During perforating operations the driller or driller's assistant will observe hole for possible flow back. 7. Perforate specified zone. COOH with spent gun. Ail electrical 'equipment and radio equipment (except emergency) will be switched off before spent gun is pulled through BOP's. Once gun is on the catwalk and disarmed, the electrical equipment and radios can be returned to normal service. C. TESTING THE WELL 1. A pretest meeting on board the rig will be conducted by Phillips Test Engineer. Ail supervisory personnel of the drilling con- tractor and involved service companies are to be in attendance. The test program will be presented by the Phillips engineer and questions will be floored and clarification of the test procedure will be discussed. 2. Welding will not be permitted except by expressed written consent of Phillips Drilling Supervisor. 3. Ail anti-pollution equipment will be checked again. 4. The radio operator will notify helicopter and supply boat to the fact flaring/burning of hydrocarbons will be in progress. 5. Only explosion proof electrical equipment is to be in commission on the rig floor, moon pool, cellar deck, and main deck. 6. Prior to testing, surface equipment will be arranged as shown in Attachment "I" and tested as follows: a. Burners will be tested by contract test crew. Repairs made as required followed by retesting. b. The surface test valve manifold lines to the choke as well as the chokes, will be tested to their rated working pressure. c. Ail surface lines downstream of chokes to separator and/or heater are to be tested to the working pressure of the separator. (2) ( Attachment H d. The heater and separator will be filled with water and tested to 1/2 their working pressure. 7. The DST assembly to be used is shown in Attachment I-2. Drill pipe will be used for testing. The drillpipe will be used in the event jarring is required to unseat packer. 8. Prior to utilizing drill pipe as a test string, the cleaning, inspection and lubrication procedure will be followed: a. Clean drill pipe threads preferably by steam cleaning. b. Inspect shoulders for cuts and repair if necessary. c. Thoroughly dope connections using a high quality thread lubricant. d. In order to minimize time, the test should be anticipated two trips prior to COOH to test, in order for each connection to be broken, inspected, and doped prior to DST. 9. Prior to conducting the first DST, the test string must be internally tested to the maximum pressure anticipated during the test. This can be accomplished by running a full water cushion and pressure testing against a downh°le test valve or by hydrotesting. Subsequent tests can be conducted utilizing either external connection tests (Gatorhawk) or internal tests. 10. Run test string as shown in Attachment I-1 as appropriate, and set packer 50-80' above perforations. Space out to have surface test tree n'ear drill floor. 11. The hole will now be ready to commence DST. During DST, the annulus pressure will be monitored by the driller by means of a recently calibrated pressure gauge. Every increase of 100 psi pressure or drop'of 50 psi on the annulus requires immediate notification of the Phillips Testing Engineer and Drilling Supervisor. (3) Attachment H 12. The basic flowing and shut in procedure for testing will be conducted as follows: a. Initial flow 15 minutes b. Initial shut in 2 hours. Shut in at surface c. Clean up at maximum flow of well or at maximum capacity of separator 10 hours. d. Shut in for 12 hours. Shut in at surface e. Flow at 1/4 rate in Step C for 6 hours. f. Shut in for 9 hours. Shut in at surface. g. Flow at 1/2 rate in Step C for 6 hours. h. Shut in for 9 hours, shUt in at surface. i. Flow at 3/4 rate in Step C for 6 hours. j. Shut in for 9 hours. Shut in at surface. k. Flow at rate in Step C for 6 hours. 1. Shut in for 9 hours. Shut in at surface. NOTE: During DST's the rig floor, moon pool, shale shaker house and mud room will be checked for hydrocarbon fumes using a hand held gas sniffer. If rig equipped with gas alarms, everyone should be advised of the alarm procedure. ALL ALARM SYSTEMS ARE TO BE TESTED prior to commencing the DST. Throughout test period, a testing service operator will be stationed on the rig floor. Specific flow rates, times, and surface data points will be given for each zone. 13. Upon completion of testing sequence, test fluids will be reversed out through the test choke manifold. 14. Pulling test string is to be done slowly to prevent swabbing of the perforations. The test string will be retrieved as follows: a.Prior tO releasing packer, fill up drilling nipple and trip tank. (4) Attachment H b. Release packer while observing hole. c. Fill up drill nipple and record the amount of fillup; check for flow. d. Pull slowly out of hole. Fill hole every 5 stands to top of the drill collars. e. Pull one stand of DC. Fillup - check for flow. Repeat this for each stand of DC's. f. Lay down test tools and recover gauges. D. TOOL REPAIR AND MAINTENANCE 1. When running a series of DST's, on each trip out of the hole, the test string should be broken at different joints so that all connections on the test string are inspected and redoped every third trip. 2. Two test tools will be used alternately. The test tool that is out of hole shall be serviced and made ready to use on next test. 3. The downhole test valve should have a new valve and seat replaced as required by inspection. Regardless of condition, the test valve will be field serviced after each DST. 4. The test packer shall be field Serviced after each DST. 5. The reverse circulating valves shall be field'serviced after each DST. 6. The SSTT shall be field'serviced and function tested through the console after each DST~ 7. Hole fluid densities possibly can be reduced after the first DST is performed in the same formational test interval. The Phillips Test Engineer will provide the Drilling Supervisor the formation reservoir pressure determined from the DST data. (5) ALASKA OIL AND ~CAS CONSERVATION COMMISSION Bruce Baker, State-Federal Coordinator Division of Policy Development and Planning Lonnie C. Smith Commissloner- October 15, 1981 Shel 1 Oil Company's Exploration Plan and Environment Report Tern Prospect We have reviewed those parts of the subject documents which are within our areas of expertise. The Exploration Plan and the Environmental Report (prepared by Woodward-Clyde Consultants) do not include a drilling program, therefore we are unable to comment as to the adequacy of the size, weight, grade, connections, setting depths, and cementing plans for the casing string, however, these data will be furnished in the Application for Permit to Drill. Appendix 3 of the Exploration Plan provides a description of the rig and rig components. The major drilling equipment, as listed, appears adequate to drill the proposed exploratory well at the Tern prospect location. Based on our knowledge of that area, 5000 psi rated BOPE should be adequate; however, a diverter system is not included in the list of major equipment. We consider a diverter system essential on all exploratory wells and it is a USGS require~nt; therefore, we presume the USGS will require one as part of the drilling program. Under the Critical Operations Curtailment Plan, item (2) reads as follows~ "Drilling into formations anticipated to be abnormally pressured." Based on our knowledge of the area, this prospect is well outside of the abnormally pressured area, therefore the reason-for the statement is not clear. If abnormally pressured formations are anticipated, 5000 psi BOPE is not adequate. CHECK LIST FOR NEW WELL PERMITS ITeM APPROVE ~ DATE ........ /~ thru ~5 Company 1. Is the permit fee attached. . . . . 2. Is well to be located in a ~iiJ'''' ' ''' '''''''''''''pool.'.'''.............. 3. Is well located proper distance from property l~ne ........ 4. Is well located proper distance from other wells ....... thl; 5. Is sufficient .undedicated acreage available in Pool .' 6. Is well to be deviated and is well bore plat included 7. Is oper'ator the only affected party ........... .,..... 8. Can permit be approved before ten-day wait ..-.-...... (3> Admin ~/6X~--'":~%4~~- 9. (~ thru ~5 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. (4) Casg ~~ ¥/7f~ (12 thru 20) 21. 22. 23. 24. BOPE ~ q/?/MZ (21 thru '24) 25. (5) Add: ::::: Lease & Well No. ~3/~~ . YES NO ~ REMARKS / Does operator have a bond in force ~ . ..... Is conductor string provided Is enough c~ment 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 surface casing protect fresh water zones ....................... 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 well bore separation proposed ........................... Is a diverter syst required em ................... ................... Are necessary diagrams of diverter and BOP equipment attached ....... Does BOPE have sufficient pressure rating - Test to ~o~o psig .. ~ . ~Does the choke manifold comply w/API RP-53 (Feb.78) .................. · Additional requirements ' Geology: Engi~ne~.%ng: cs l_! EW WVA - ..... rev(01/13~82 INITIAL I 'GEO. UNIT ON/OFF POOL CLASS STATUSI AREA NO. SHORE , Well Histo.ry 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. ~ REEL HEADER ** SERVICE NAME ISERVZC DATE 182/08/ 4 REEL NAME tREEL ZD CONTINUA?ION # 101 PREVIOUS REEL l COMMENTS :REEL COMMENTS ** TAPE HEADER ~ SERVICE NAME :SERVIC DATE :82/08/ 4 ORIGIN 1[070 TAPE NAME 165425 CONTINUATION # 101 PREVIOUS TAPE : COMMENTS :TAPE COMMENTS ** FILE HEADER FILE NAME ISERVIC,O0! SERVICE NAME VERSION # DATE I MAXIMUM LENGTH I 1024 FILE TYPE PREVIOUS FILE INFORMATION RECORDS MNEM CONTENTS PH CN I SR!bblPsS PETROLEUM CO. WN I TERN A-! FN WILDCAT RANG~ 10W TOWNI 1ON SECTI 19 COUNI KENAI STATI ALASKA CTRYI U.S,A. MNEM CONTENTS ** RECORD TYPE-:.047-.. ~- ~.~ _.~ .~ _.= . ~* COMMENTS ** .... ~~~~~~~--~ ~ ~__.~ .__.~-~::~~ ~;'::.c~.- c:./~:~-, ~..~::~ c>,.~... :,~.. / ,:.: .'~; _ COMPANY = PHILLIPS PETROb'EU~ WELL = SRS TERN FIELD = WILDCAT COUNTY = KENAI STATE = ALASKA JOB NUMBER AT ACCI 10707,65425 RUN #3, DATE LOGGEDI bDPl JR BOTTOM DEPTH TOP DEPTH CASING BIT SIZE TYPE FLUID = 9528 FT, sa 7600 FT. = 9 5/8 :1:1~, 4086 'FT, = 8 5 IN · = L~W S~IDS, NONDISPERsED'~:i:':'>' >~ :i' : : : DENSITY VISCOSITY FLUZD bOSS R~ AT BHT MATRIX LIMESTONE = 10,0 :: 44.0 $ "100 = 1,940 ~ ~.690 ~ 67,0 = 2 ,4~0 ** DATA FORMAT RECORD ** ENTRY BLOCKS TYPE4 SXZf. 9 DATUM SPEC~XCATION BLOCKS ID ORDER ~ LOG T~.PE :_CLA&:~:::~OD~:,,~ ::'NO.:~ ':.,.': ~':.:'-':-:-:::: -:'. bg~g:~ ........ :. .... -, '.C~:~:E:':~- ;:::..'.::, : ..... ..-.. ..... OEP T FT 0 0 :'"0-: '0 '?~ '0'~` ~:: :::: -'::/ -: :::' ~:~ ~::: ' ':~ "":'-~:~: .;~:.:..~,~....:.~:.:_~::.. ~:? .:::~...:_,.::: :...: ~:: SFLU ILM DIL XLD DXL SP DIL GR DIL NPHI FDN RHOB FDN GR FDN CALX FDN DRHO FDN NRAT FDN NCNL FDN FCNb FDN DT BHC GR SP CAbI BHC BHC DATA DEPT SP GR NCNb SP DEPT SP NCNb SP DEPT SP GR NCNb SP DEPT SP GR NCNb SP D£PT SP GR NCNb SP DEPT SP GR NCNb SP DEPT SP GR NCNb $P DEPT SP GR NCNb SP 9547 -999 -999 -999 -999 9.5oo 378O ,-19 9400 -23 69 2458 -23 9300 9200 -2 2~49 27 9100 4O 76 2074 4O 9OO0 2168 52 8900 50 68 2291 50 GAPI 60 MV 60 IN 7 0000 2500 2500 0 5o°o 0000 0430 3750 0000 0430 0000 6680 7344 0000 6680 0000 7900 5625 0000 7900 0000 0186 9800 1250 0186 000 75 : ooo 61 0000 0000 0552 0000 6041 6875 5000 6041 SFLU GR CALl FCNb CALl SFLU GR CALl FCNb CALl SFLU OR CAbZ FCNb CALl SFLU GR CALl FCNb CALI SFLU GR CALl FCNb CALl $FbU ALI FCNL CALI SFLU GR CALl FCNb CALl SFLU R ~ALI FCNb CALI -999,2500 ibm -999 - 99 9 ' 2-5 O0 .... D:R'H0 "999,2 500 DT -999':2500 1875 60 I6 DRHO 2712: 6 6406-NPH:~ 7891 ' 6250 23,8281 49, 142~:0000-244i 0028 7969 J ~ :J 0 0-000 DEPT SP NC~L SP DEPT SP SP SP GR NCNb SP D£PT SP GR DEPT SP NCNb SP D£PT $P GR NCNb SP DE:PT SP GR NCNb SP D£P? SP GR NCNb SP D£P? SP GR NCNb SP 8800 94 75 2060 94 8700 110 72 198 8600 8500 134 61 2288 134 8400 149 49 1512 8300 156 68 2444 156 8200 2283 158 0000 SFLU 8423 GR 1250 CALI 0000 FCNL 8423 CAL! 0000 5FLU 95GR 46~ CALI 5000 7954 CALI 0000 SFLU 52 5 GR 51~6 CAb! 2500 FCNL 5215 CALI 0000 &FLU 2583 GR 6748 CALI 1250 FCNb 2583 CALI 0000 SFLU 4170 Ga 7 CALl 2t~O FC 50 Nb 4170 CALl 0000 SFLU CALl 0000 FCNb 34~3 CALl 0000 SFLU 036 GR 500 CALl 4063 FCNb 7036 CALl O000 SFGU 1250 Ga 1250 CALl 0000 FCNL 1250 CALl eooo.oo i 282 CAb! 12,7661 73~5-000. _ 2253 41 10 * 129-4' 6o, 5 t:3 47 305,3750 8 ~77:47 8 584,000:0- 7~ 4341:: 7 ~'0078' 9; 4i41' 666,5000 8 ;9 732 DEPT NCNb SP DEPT SP GR NCNb SP DEPT SP GR NCNb SP DEPT SP GR NCNb SP SP NCNb SP DEPT SP NCNb DEPT SP NCNb SP DEPT SP NCNb SP DEPT SP NCNb SP 7900 152 65 2900 152 7800 169 77 2164 169 7700 169 61 3170 169 7600 190, 1968, 190, 7500 165 -999 -999 165 7400 184 -999 -999 184 7300 .197 999 -999 197 7200 192 -999 -999 192 7100 190 -999 19 0000 SFLU 7461 GR 5000 CALl 0000 FCNL 7461 CALI 0000 SFLU 0 6 CALl 0000 FCNb 4026 CALl 0000 SF[,U 3824 GR 7173 CALl 0000 FCNL 3824 CALl 0000 SFLU 5000 GR~ 8750 CAEI 0000 FCNE 5000 CALl 0000 SFLU 1250 GR 2500 CALI 2500 FCNb 1250 CALX 0000 SFLU 8750 GE 2500 CALl 2500 FCNL 8750 CALl 0000 SFLU 2500 OR 2500 CALl 2500 FCNb 2500 CALl 0000 SFLU 7500 GR 2500 CALl 2500 FCN~ 75O0 CALl 0000 SFLU 5000 OR 2500 CALl 2500 FCNL 5000 CALl 13 67 lO 98~ 10 48 15180 · 9999 :' ..-, .:65,::2.7:~.~: _ ,.. e'DOO0 : - : ~ :: --.:: L:':: :' / " -96899 5625-.-NPMt- , :,::' ~. ---.-.- -999.;<,R50.0 - :..R:HO8 :-9~9;.,2500,:: .~;::.: ,~ : :.-.:: :-- . 2500-'DRHO' "999 25.0 6563 ~ --~' ' - - ?' .... ..... ' ': -::-:' :' ". ........ '-' ' -999 2500" DRHO ':~ :?:::~99'9~';:2500-':"NRA;T':: .... 64 4375 : :NPH-I 79~:,.:2500 · RHOB -999:~..::250.~.0-~. : .... ... -9~9 2500 D'RHO -99~ 2500 · 7734 ' ' : : ': :"" '~' =-':: --':: ::'~ :":' 37 6875 NPHI- :-:~:._.~99,9'*:2500: R. HOB~: 9 500-. :::- - .~., ' -999 250'0 DR'HO :~ "--"999',::'250::O~:~:N~AT: - "'999:':'~'5~:0:0 '<' "':~:' ...... : : -999 2500 bT~: 10 5938- ::' ':' '::"": :~ -~: ' ' "--~ '::~-"-' ':' : -: 99~:2500 DRHO: 2500_ 2656 - ' :: -: '": ::: : :":'-' :~- · ::::: :- .:::.:,::- :._; ~ ~ ::,_-::-:.~: ::.'.:: .:~ :. · .,: - . DEP? ?000 GR -9 NC~L -999 SP 190 DEPT 6900 SP 2O3 GR -999 NCNb -999 SP 203 DEPT 6800 SP 190 GR -999 NCNb -999 SP i90 DEPT 6700 SP 20; GR -99 NCNb -999 se 205 DEPT 6600 SP ~9! OR - 99 NCNb -999 SP 191 DEPT 6500 SP 192 GR -999 NCNb -999 SP 192 DEPT 6400 SP 1 6 GR -9;9 NCNb -999 SP 186 DEPT 6]00 SP . 10 GR 999 NCNb -999 SP 210 DEPT 6200 SP 192 GR -999 NCNL -999 SP 192 0000 SFLU 8750 GR 2500 CAb! 2500 FCNb 8'75o CALl 0000 SFLU 6250 GR 2500 CALl 2500 FCNL 6250 CALI 0000 SFLU 8750 GR 2500 CALI 2500 FCNb 8750 CALl 0000 SFLU O0 CALl 2500 FCNb ! 250 CAL! 0000 ~FLU 0000 GR 2500 CALX 2500 FCNb 0000 CALl 0000 SFLU 2500 GR 2500 CAb! 2500 FCNG 2500 CALl 0000 SFLU 6250 GR 2500 CALI 2500 FCNL 6250 CALl 0000 SFLU 0000 GR 2500 CALI 2500 FCNb 0000 CALI 0000 SFLU 2500 GR 2500 CAbI 2500 FCNb 2500 CALX 1¸2 7i -999 -99~ 7 53 -999 -99.~ 6 . 62 ' 999 -99~ I0 5 8:75-0~: NP'H-I- .:. 2500 DRHO 2500 2500 -999 ~2500: :-'DRHO:::' ':-:: '1'9:99'~':25'00:: -:N::RAT: :: :-::~9:99':~::::: :::-::::::-.' :< -;':::" : ::: ' -999,2500 D:T-: , :::: t!O .50. ::G:R-,:::., :65:':i875: ,. <:-: : ..... : - -999 2500 DR~O~ -999 2500 D~ : ~? . :99 ,:!.8 75:.: :::GR: : 6~00:00::::::: ::- 46-1875 N..PH~:: : =9: 50.0::-:..R:HO-B: :,: ~9:99:,.:.:2:50:0.: ::., ::: -..: ..... . _ -999;2500 'DR-HO- .... ~'~;9'99~250':0:- :: NR'AT:::' ": ' ::":;~'99:9'a 0::0:': : ::: ::::':' :: ' ~ 2_500 ,8047 ': ':"-: ':--:' ' ':'': ':"' :"':-: '::' ':: ....::' ' 54,593.8 :.--N,PHI-,:_ ~_ _~;~99~.~2500.~ :~.BOB~ .:. ~999.~5,00::.- :, .-_... -999- ,2500' :"DRHO ~ -- :::- '' 999.2500 8;3984 "- ' ' -:" ; ':-,:::F::":-,:::':~.--. DEPT 8P GR DEPT ~CNb SP DEPT SP GR NCNb 8P DEPT SP NCNb DEPT SP NCNb DEPT GR NCNb SP 8P GR NCNb SP D£PT SP GR NCNb D£PT NCNb SP 6100,0000 SrbU 210,0000 GR '999,2500 CALl '999,2500 rCNb 210,0000 CALl 6000 0000 206 2500 -999 2500 -999 250O 206 2500 59O0 0000 185 00~0 -999 25 0 -999 2500 185 0000 5800 0000 199 2500 -999 2500 -999 2500 199 2500 5700 0000 210 250O -999 2500 -999 2500 210 2500 56O0 0000 192 0000 -999 2500 -999 2500 192 0000 5500 0000 20 7 0 -99~ 50 25OO -99~ 2500 20 75OO 5400 0000 19~ 7500 - 2500 99 -999 2500 192 7500 5300 0000 5OO 202 ~500 -999 -999 2500 202 250O GR CALl FC~b CA I 8FLU GR CALl FCNL CALl SFLU GR CALl FCNb CAbI SFbU GR CALl FCNb CALf $FLU GR CALl CAb! &FLU GR CALl FCNb CAb! 8FbU GR CALl CALl SFbU GR CALl FCNb CAbI 99:9, 5703 -999 2'500 ?0 ~ I ~:2500:-::, ,5~I3- 11 :':': .5:000': 9~ . 99 ~ .250.0: 1875: j { :. 250:0 -99~ 2500 .OEP? DEPT GR NCNb SP DEPT SP NCNb SP DEPT SP OR NCNb SP GR NCNb SP DE:PT SP NCNb SP DEPT SP GR NCNb SP NCNb 5200,0000 SFLU 199,0000 GR -999'2500 CALI -999,2500 FCNL 199;0000 CALl 9100 0000 oooo - 2500 -999 2500 186 0000 SFLU CALl FCNb CALl 5000 0000 $FLU 176~6250 GE .-999,2500 CALI 999,2500 FCNb 176,6250 CALI 4900 0000 214 6250 -999 2500 -999 2500 214 6250 4800 0000 187 ~000 -999 500 "999 2500 187 0000 4700 0000 187 2500 -999 2500 -999 2500 187 2500 4600 0000 2500 "'999 2500 179 2500 4)~ 0000 5OOO -999 2500 5000 4400 0000 212 O0 -999 I~00 -999 2500 2i2 7500 SFLU OR CAbI FCNb CALl SFLU GR CALI FCNb CALI $FLU GR CAbI FCNb CALI SFLU GR CALl FCNb CAb! SFLU GR CALI FCNL CALl $FbU GR CALl FCNb CALI 12 12 6'1 ,-:99~ 4 62 -999 -99~ !0 7 73 6 25-00 DR~O'-' ::'- :': 9-:~:i:: ~':': ,~:, '," 25 O0 O~ 484'4 2500 4453 875O: 2500" 2500 :' 25'00 2500 3984 25:00 :' 2500 35'16 ~25.00 _ ~2~1 9062 - 2500 - 2500 DEPT, 4300 Sp · .9187 GE 99 NCNL -999 SP i87 DEPT 4200 SP 198 GE -999 NCNL -999 SP DEPT 4100 SP 207 GR -999 NCNb -999 SP 207 DEPT 4000 SP 248 GR -999 DEPT 3900 SP 259 GE -999 NCNb -999 SP 259 0000 SFLU 3750 GR 2500 CALl 2500 FCNb 3750 CALI 0000 SFLU 750O GR 2500 CALl 2500 FCN6 7500 CALI 0000 SFLU 50 GR 2500 rCNb 1250 CALI 0000 SFLU 0000 OR 2500 CALI 2500 FCNL 0000 CAS! 0000 8FLU 5000 GR 2500 CALl 2500 FCNb 5000 C.AL! DEPT 3:~4~,0000, ,5FLU ,SP 6 ,0000 OR GR ,,99 2500 CALI NCNb '999,2500 FCNb SP 264,0000 CALI 52500: .:!DT.:~ :::::.:: -99.:~ 25'00 .... 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