The URL can be used to link to this page

Home My WebLink About181-004 Ima )roject Well History File Cover e XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ,// ~'//- ~ Y Well History File Identifier Color items: [] Grayscale items: [] Poor Quality Origi hals: [] Other: NOTES: BY: DIGITAL DATA OVERSIZED (Scannable) [] Diskettes, No. [] Other. No/Type r items scannable by large scanner OVERSIZED (Non-Scannable) BEVERLY ROBIN VINCENT-~ MARIA WINDY D/,,,~ of various kinds Project Proofing BY; .~ROBIN VINCENT SHERYL MARIA WINDY DATE; ~SI Scanning Preparation .,,/') x 30 = BY: BEVERLY ROB~ SHERYL MARIA WINDY + = TOTAL PAGES ,/~',~// Production Scanning Stage l PAGE COUNT FROM SCANNED FILE: BY: Stage 2 (SCANNING I$ COMPLETE AT THIS POINT UNLE~ SPECIAL ATTENTION IS REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY. GRAY$CALE OR COLOR IMAGES) PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: /~YES- NO IF NO IN STAGE '!, PAGE(S) DISCREPANCIES WERE FOUND: YES__ NO III IIIIIIIIIII II III F~ESCANNED BY; BEVERLY ROBIN VINCENT SHERYL MARIA WINDY DATE: /si General Notes or Comments about this file: Quality Checked 12110/02Rev3NOTScanned.wpd Memorandum State of Alaska Oil and Gas Conservation Commission To: Cancelled or Expired Permit Action EXAMPLE: Point McIntyre P2-36AXX API# 029-22801-95 This memo will remain at the front of the subject well file. Our adopted conventions for assigning APl numbers, permit numbers and well names did not specifically address expired or cancelled permits. This omission has caused some inconsistencies in the treatment of these kinds of applications for permit to ddil. Operators have asked us to adopt formal procedures for this class of permit application in order to prevent future database disparities. If a permit expires or is cancelled by an operator, the permit number of the subject permit will remain unchanged. The APl number and in some instances the well name reflect the number of preexisting redrills and or muitilaterals in a well. In order to prevent confusing a cancelled or expired permit with an active well or multilateral these case sensitive well identifiers will be changed for expired and cancelled applications for permits to ddll. The APl number for this cancelled or expired permit is modified so the eleven and twelfth digits is 95. The well name for a cancelled or expired permit is modified with an appended xx. These procedures are an addendum to the APl numbering methods described in AOGCC staff memorandum "Multi-lateral (weilbore segment) Ddlling Permit Procedures, revised December 29, 1995. AOGCC database has been changed to reflect these changes to this permit. Statistical Technician February 20¥ 1981' Mr. J. F. Settle D~strict Superintendent Phillips Petroleum Company P. O. Drawer 66 Kenai, Alaska 99611 Re= SRS Tern C No. 1 Phillips Petroleum Company Permit No. 81-4 Sur. Loc.: 500tFF. L, 1400tFSL, Sec 26, T10N, R11W, SM. Bottomhole Loc.: S A M E Dear Mr. Settle: .Enct~d is the approved appltcat/on for permit to dril'l the above '=eferenced well. well s~les and a mud log are required. A directional survey not 're, red. If~.':availabIe, a tape containing the digitized l~.~.!n'f~rm~.,...~'on sB~11 be submit~ed on all logs. £or copying eX. pt e~rtmen~l logs, velocity surveys and d~.pme~r sur- Many rivers in Alaska and their drainage systems, have been olassified a.~. ~_mportant for the Spawning or n~gr~:,.2ion of anadromous ~i'sh. O~eratio~s in these areas are' s~b~'ect to AS 16~."~0.870' a~d the regulations promulgated ~hereunder (Title 5, Alaska Administrative Code ). Prior to commencing operations ~.~ m~y. be. -con -ta~.oted.~ by ~he Habitat . .~oordinator ~:.8~ .o£-£ice ~~-~..o_n o£-any.'wate-rs of.- the State :is 'prohibited'bY AS ~~r.' 3, ~~le ?~...~. the-' =eq~. lat[0ns, pr°mu!ga~>th~reUnder :(~e. !~ AIa~. 'A~n~stra~ve.: :.Cgde', Chapter 70}."::&nd-.by' the F~leral - Na.~te~ -P01'~l~O~,.: control Act, -'. as amended. "-'~or. to . .- -..~ ,. · \ / / / ~'. J. F. Settle SRS Te~n C No. 1 -2- February 20, 1981 commencing operations you may be contacted by a representative of the.-' :'Department of ~nv~rone~.ntal Cons~rvation. Pursuant to. AS 38,40, Local Hire Under' State Leases, the, Alaska Department of Labor is being nottfied of He issuance of this permit to drill. ' To aid us in scheduling field work, we would .appreciate your' notifying this office witb/n 48 hours af,~er the well ,is spudded. We would also like to be no. lied so that a repre- sentative of the coam~ssion may be, present to Witness ,tes2ing o£ blowout preventer equipment before surface casing shoe is In the event of suspension or abandOnnmnt, .please. give this o£fic~ adequate advance notification so that ~e may have a witness present. PHILLIPS PETROLEUM KENAI, ALASKA 99611 DRAWER 66 PHONE: 907 776-8166 NATURAL RESOURCES GROUP Exploration and Production Kenai District CERTIFIED NO. 463848 RET~ RECEIPT REQUESTED January 27, 1981 File: P-JFS-34-81 COMPANY Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Drilling Permit Application SRS Tern "C" No. 1 Sec. 26- 10N- llW, SM Pursuant to the discussion held January .23, 1981, between your Messrs. Lonnie Smith, James Trimble and Blair Wondzell and our Mr. Neal Porter, this is to advise that we hereby wish to amend the subject application as follows: . Phillips rescinds its prior proposal not to employ a diverter on the 20" conductor while drilling from 250' to 1,000' BOF and agrees to use a diverter system pursuant to AO/GCC Regula- tion 20 AAC 25.035 (b)(i). A sketch of the diverter system specifying the equipment to be used' as well as the operational procedure for same, is attached. e Phillips rescinds its proposal to dress the final top hole c~t plug 100' BOF and hereby proposes to place cement such that the top plug top is 50' BOF instead. We realize this latter proposal is not in compliance with AD/GCC Regulation 20 AAC 25.105 (b) (2) and, therefore, this new proposal con- stitutes a request for a variance thereto. Phillips w~uld prefer to cut-off the surface, conductor and structural casing strings at or below the mudline rather than leave a stub above the mudline as a potential hazard for other marine interests. The only way to effect a cut at the mudline with a previously placed cement plug at the same point is to use explosives. For safety reasons, we prefer not to use explosives unless absolutely necessary. RECEIVED FEB - 2 1981 Alaska 0il & Gas Cons. Commission Anchorage , Page 2 Settle to AO/GCC January 27, 1981 If the cut is to be made at or below the mudline with a mechanical cutter, space (hole) is needed below the mudline because of the basic construction features of the cutter assembly. We prefer to have 50' of hole below the mudline in which to work the cutting assembly. Your approval of this procedural variance is respectfully requested. ~s/~p/so Attachments RECEIVED FEB - 2 1981 Oil & Gas Cons. Comml~lon DIVERTER INSTALI,ATION AND OPERATIONAL PRCCEDURE INSTALLATION PROCEDURE 1. A 500# WP or better diverter will be used when drilling from 250' to 1,000' BOF; i.e., from 20" casing seat to 13 3/8" casing point. . e . . Depending on rig type used, the diverter will be nippled up as follows: A. Floater - on top of marine riser after 20" casing set and subsea BOP and riser installed. B. Jackup - Either on top of 20" wellhead or on top of 13 5/8" surface BOP stack de.pending on space availability. A drilling spool with 6" minimum side outlet will be employed between diverter and riser/wellhead. A 500# WP or better normally closed full-open type~ automatic valve will be enployed 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 divert, r, the automatic valve will open fully. The vent line downstream of the automatic vent valve will be tied into two 6" diversionary vent lines so that any emission can be made down wind of the rig. A manual butterfly valve will be installed on each diversionary' line for control purposes. OPERATION-. PROCEDURE l. The diversion system is being installed to provide a control capability if pressure sufficient to frac the fonnation is encountered while drilling from 20" casing shoe at 250' + BOF to the 13 3/8" casing set point at 1,000 ' + BOF. . The diversion system shall be used anytime underground blc~-out con- ditions exist while drilling the hole section mentioned above. RECEIYED FEB - 2 1981 OPERATION PROCEDURE (cont' d) . 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 follc~ing 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 appro- priate 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 diverter/vent line valve control canl be actu- ated to open the diverter and close the main vent valve. Shut down mud pun~. and'observe mud in bell nipple. If no movement, go back to drilling. If movement, go back to Step 2. above. . RECEIVED FEB - 1981 If tripp..ing operations are underway, the driller should: 1. Install inside BOP in drill pipe and atteup_t to get as much drill pipe back in hole as possible before closing the di- verter. After diverter is closed, strip drill pipe through a heavily lubricated diverter as long as it can safely be done. 2. Same as Step A. 3. 3. If able to get back to bottom with drill string: a. Resum~ 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. (2) OPERATION PR~URE (.cont'd) 4. If unable to get back to bottom with drill string: a. Same as Step A. 4. b. Same as Step A. 5. Ce 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/blc~ 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 .perfozmed. This decision will have to be based on circumstantial evidence. ) (3) RECEIVED 4 ,) PHILLIPS PETROLEUM COMPANY KENAI, ALASKA 99611 DRAWER 66 PHONE: 907 776-8166 NATURAL RESOURCES GROUP Exploration and Production Kenai District CERTIFIED NO. 463849 RETURN RECEIPT REQUESTED January 27, 1981 File: P-JFS-36-81 Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AlaSka 99501 -- ~ .... . ~ ·.< . . I 4 ENG J I GEOL t 2 O~:OL I 3 .__ J ST:" T T=C -- I STAT I CONFER: .__ ............ FILF: Re: Drilling Permit Application dated 12/31/80 Phillips SRS Tern C No. 1 Sec. 26- 10N- llW, SM As promised in our letter of January 20, 1981, attached is a copy of Nortec's report describing the bottom con- ditions extant at our SRS exploratory prospect. Site 3, in this report, corresponds to the subject pro- posed drilling location. Sites 2 and 1 refer to proposed alternate drilling locations in Sections 25 and 24, res- pectively, in the same Township and Range. Based upon Nortec's appraisal, we are confident that a ~marine drilling rig can safely drill a well at the pro- posed location. Should you have any questions concerning Nortec's report, please advise us. J.F. Settle District Superintendent JFS/NEP/so Attachment RESULTS OF GEOPHYSICAL SURVEYS FOR THE SRS PROJECT COOK INLET, ALASKA Prepared for PHILLIPS PETROLEUM COMPANY Prepared by NORTHERN TECHNICAL SERVICES September 30, 1980 RESULTS OF GEOPHYSICAL SURVEYS FOR THE SRS PROJECT COOK INLET, ALASKA INTRODUCTION This report presents the results of a marine geophysical survey undertaken for the Phillips Petroleum Company to obtain surface and subsurface geologic and engineering information for the SRS 'Project in up~er Cook Inlet. This study examined t~ree sites (Figure 1) as possible locations for placement of a jack-up or floating drilling rig. These sites were: Site 1 - Lat. 60°56'49.922"N; Long. 151°08'14.532"W Site 2 - Lat. 60°55'58.914"N; Long. 151°09'16.848"W Site 3 - Lat. 60°55'30.554"N; Long. 151°09'51.223"W The various elements of the survey were designed to determine bathymetric, bottom and sub-bottom conditions in the vicinity of the three locations identified above. METHODS AND EQUIPMENT Survey operations were conducted from the vessel "Shamrock" on September 19-21, 1980. Navigational control was maintained utilizing a Motoro]~a Mini Ranger III radar ranging positioning system with. transponder stations located at Grey Cliffs (Lat. 60°49'45.088"N; Long. 150°57'32.017"W) and on the North Cook Inlet Platform (Lat. 61°04'36.38"N; Long. 150°56'55.63"W). A Klein 100 KHz Side Scan Sonar system was used to determine surficial bottom conditions _in the survey area. Sub-bottom information was obtained with an EG&G 200 joule high resolution "boomer" and a modified EG&G 1000 joule sparker system. An EPC Recorder was used to record these data. A Ross S200B fathometer provided a precision depth record, and a 36-inch diameter pipe dredge was used to obtain bottom samples. The overall configu- ration of the survey equipment is as shown on Figure 2. SURVEY RESULT~ General A total of seven survey lines were run as part of this effort. Navigational fixes were obtained at various locations along these survey lines and all analog records were annotated with a corresponding "event mark". Table 1 provides a summary of records obtained during the survey, and survey line and event mark locations are as indicated on Plate 1. Originals for all analog high resolution boomer, side scan sonar and fathometer records are also attached as a separate volume. TABLE 1. Summary of Survey Data Obtained Line Event Marks Boomer Side Scan Fathometer 1 1 - 20 Yes No No 4 32 - 40 Yes Yes No 5 42 - 55 Yes Yes No 6 56 - 78 Yes Yes Yes 7 79 - 102 Yes Yes Yes 8 103 - 115 Yes Yes Yes 9 116 - 137 Yes Yes .Yes High Resolution Sub-Bottom Profiling It was anticipated that some difficulty in obtaining useful sub-bottom information might be experienced due to the dense gravel-cobble nature of the bottom material; however, good penetration was achieved with both the 200 joule "boomer" (up to 40 msec two-way travel time) and the 1000 joule sparker (up to 60 msec). Assuming a sound velocity of 1.8 km/sec through these · sediments, this represents penetration to a depth of 54 m beneath the seafloor. Acoustic basement was noted up to 60 msec (approximately 54 m) below the seafloor west of Site 1. In the vicinity of the northern-most location (Site 1), the acoustic basement approach- es and often outcrops at the seafloor. This trend of basement at or very near the surface continues eastward of Site 1. South of Site 1, the acoustic basement is near the surface until it descends beneath 40 to 50 msec (approximately 35 to 45 m) of less consolidated material about 500 m north of Site 2. Both Sites 2 and 3 are situated in areas in which the overburden is of considerable thickness (greater than 20 msec or about 18 m), but occasionally significant discrete reflectors occur which probably represent glacial erratics. Acoustic basement identified in this survey probably represents the Kenai Formation, a group which ranges from loosely consolidated rock to very stiff or hard sediments'. Geophysical results and bottom samples from areas of outcrop (Site 1) indicate a slightly consolidated glacial deposit as the likely composition within the area covered in this survey. Overburden material probably consists of unconsolidated sand, gravel, cobbles and boulders overlain by an armor of winnowed cobble and boulders. These results generally agree with those of previous investigations in this area (Dames & Moore, 1974). Side Sca~ Sonar The side scan towfish was flooded with seawater during the ini- tial stages of the survey. Shipboard repairs to the system required blanking the signal from the portside channel. Records from the remaining (starboard) channel do, however, provide sufficient information to characterize general seafloor condi- tions at the three sites. Side scan records indicated considerable surface relief in the northern portion of the survey area with linear features expressed both east and west of Site 1. Northern regions of rough surface topography correspond to areas in which sub-bottom information indicated outcropping of basement material. South of Site 2, the surface appears smoother (scoured?) with occa- sional erratics present. Bottom Sampling Deployment of the 36-inch pipe dredge resulted in collection of a significant sample at only one location. The sample collected at Site 1 (Figure 3) consisted of 3 boulders, 15 cobbles and 5 gravel-sized rocks No material finer than gravel was recovered. The boulders exhibited sessile organisms attached to their surfaces, indicating they had remained relatively stationary on the seafloor. The cobbles and gravels all were smoothed and probably had experienced some degree of bed-load transport. Bottom material at this site is glacial and may represent both till (boulders) and outwash (cobbles and gravels) deposits. As indicated in Figure 4, one cobble-sized rock was recovered in two samplings at Site 2. No material was recovered from two dredge drags at Site 3. Dents and scrape marks on the side and lip of the dredge (see Figure 5) indicated a hard bottom of cobble to boulder-sized material at those sites where a significant sample was not obtained. Bath. ymetry Bathymetric data obtained from the Ross fathometer was cor- rected to Mean Lower Low Water (MLLW) and are summarized on Plate 2. Tidal corrections for these data are based on an average of predicted tides at the East Forelands and North Forelands (U.S. National Ocean Survey, 1980). Comparison of corrected bathymetric data from intersecting survey lines resulted in maximum errors of approximately 0.7 m (2 feet). Considering the seafloor roughness and inherent errors with use of predicted tides, bathymetric data indicated on Plate 2 is probably accurate to within + 1 m (+ 3 feet). Data from the recording fathometer verified results obtained with the side scan sonar and sub-bottom profiling systems. Considerable surface roughness was indicated in the northern · portions of t~e survey area, corresponding to regions of outcropping basement and numerous side scan targets. Relief of features noted in this area was 1.0 to 3.5 m, indica- ting numerous large rocks or perhaps occasional strike ridges. CONCLUSIONS i · Site 1 is situated in an area where acg._u_~tic basement appears to outcrop at the surface. This material is believed to be a dense, slightly consolidated glacial deposit of the Kenai Group. At Sites 2 and 3 this material is overlain by 20 msec (approximately 18 m) or more of unconsolidated sands, gravel, cobble, and boulders with a surface armor of winnowed cobble and boulders. · The seafloor at Site 1 exhibits considerable roughness, with relief on the order of 1.0 to 3.5 m. The seafloor at Sites 2 and 3 are generally smooth with occasional glacial erratics present. · Bottom sampling recovered material of gravel, cobble, and boulder size. Materials finer than gravel were not recovered. · Based upon the above conclusions, it is our opinion that the seafloor at Sites 1, 2, or 3 will provide more than adequate bearing strength for a jack-up drilling rig. However, leg penetration may be inadequate to develop sufficient shear strengths to offset horizontal current forces on the rig. Therefore, sandbagging should be considered. · The hard bottom conditions at Sites 1, 2, and 3 will pro- vide poor holding ground for anchoring a floater. If a floating rig is selected, care should be taken in selecting anchors and designing the mooring pattern. REFERENCE Dames & Moore, 1974. Detailed environmental analysis concerning a proposed liquefied natural gas project: Prepared for Pacific Alaska LNG Company. U. S. National Ocean Survey, 1980. Tide tables-1980-west coast of North and South America: U.S. Dept. of Commerce, annual publication. 14 " I 35 TION / PeOPCSED ,LDNO, I§1° 08' 14.§32"( I ! >,/ VICINITY MAP SCALE IN MILES 0 25 50 d I iNCH s ;M;LE FROM U.S.G.S ~:$$~560 SCALE MAPS BOTTOM LINE.90' RI(; TYPE -- JACK UP. OR FLOATER SRS TERN 'C' , EXPLORATORY DRILLING PROJECT North Cook Inlet 9.4-10.5 Miles SSE of Tyo~ek Phillips Petroleum Compony Dro wer 66 Kenoi ~ Alosko 99611 DATE August .;'7, 1980 Figure I. LOCATION MAP 16° '"20 VARIABLE 6o-loo, SPARKER OR j BOOMER ~ VESSE VARIABLE I00 - 200' ~)METER (I ft. below surface) INI -RANGER ANTENNA VARIABLE 100-150' SIDE SCAN SONAR TOW FISH HYDROPHONE STREAMER Figure 2. EQUIPMENT LAYOUT Figure 5. BOTTOM SAMPLE FROM SITE Figure 4. BOTTOM SAMPLE FROM SITE 2. Figure 5. , DENTS AND SCRAPES ON BOTTOM DREDGE FROM SAMPLING AT SITE 2 AND :~ PHILLIPS PETROLEUM KENAI, ALASKA 99611 DRAWER 66 PHONE: 907 776-8166 NATURAL RESOURCES GROUP Exploration and Production Kenai District CERTIFIED NO. 46 3847 RETURN RECEIPT REQUESTED January 20, 1981 File: P-JFS-27- 81 COMPANY Alaska Oil and Gas Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Drilling Permit Application Dated 12/31/80 Phillips - SRS Tern'C No. 1 Sec. 26- 10N- llW, SM This is to confirm verbal agreement reached January 19, 1981, in a conversation between your Mr. Jim Trimble and our Mr. / Neal Porter conoerning the subject application. Phillips will follow API RP,~as it relates to BOP equip- n~_nt and its use as required by AO/GC regulation 20 AAC 25.035 (a) (1). Please cc~sider thiS letter as an amendment in that regard to the subject application. Phillips will furnish, under separate cover, a copy of the report prepared for us by Northern TechniCal Services con- cerning the bottom conditions at the proposed drilling pros- pect site. Since we do not have an extra copy on hand, it will take about two weeks before another copy can be prepared and furnished to you. Attached is Phillips Draft No. 217706 in the amount of $100.00 payable to the Alaska Department of Revenue in full payment of the peri, it application prooessing fee required by 20 AAC 25.005 (c) (1). Please do not hesitate to call us if additional information is required. ~t Superintendent RECEIVED JAN2 Z 1981 JFS/NEP/SO Attachment Alaska 0tt & Gas Oons. Commission APPLICATION FOR PERMIT TO DRILL TABLE OF CONTENTS Transmittal Letter ............... See Tab 1 Alaska Oil & Gas Conservation Commission Form 10-401 ....... 2 Vicinity Map ..................... 3 Lease Map ....................... 4 Drilling Prospectus ............. ; . . . 5 General Operational Procedures ......... Page 1 - 10 Safety Program ............... Page 1 Drilling' Report & IADC Report.. ......... 2 Material Handling & Expediting ......... 2 Curtailment of critical Operations ....... 3 Mud Program .................. 4 Kick. Control Procedures ............. 4 Hydrogen Sulfide Operations Plan ........ 4 Drilling Breaks ................. 4 Casing Running & Cementing Report ..... . . . . 5 Coring Program ................. 5 Logging Program ................ 5 Hole and Casing Program ............. 6 Cementing Program ................ 6 Deviation Program ................ 6 Drill Stem Testing Program ........... 7 Wellhead and BOP System ............. 7 BOPE and Casing Testing Requirement...~ .... 8 Well Log Quality Control Checklist(Form 10128) . 8 ~d Log, Shale Density Log, Pore Pressure Plot & "D" Exl0onent Plots .......... 8 Drilling Mud Report ............... 9 Service Tickets ................. 9 MUd Logging ................... 9 Sampling Program ................ 9 Formation Bleed-Off Tests ........... 9 Hanging Off & Rig Abandonment (Floater only) . . 10 Changes .................... 10 Drilling Procedure Floater ................... See Tab 6 Jackup ....................... 7 Page 1 RECEIVED JAI', - 5 ] 81 ~aska Oil & Gas Cons, Commi$$1ol] Anchora~te TABLE OF CONTENTS ATTACHMENTS Casing Program and Design Conditions ........ Tab A Logging Checklist ................... B Mud Program ...................... C Kill Control Procedures ................ D ,. Fill-up Procedures ................... E Lost Circulation Procedures .............. F Cementing Program ................... G DST Procedures .................... H Testing Equipment ................... I BOPE Description & Operation Procedures ........ J BOPE and Casing TeSting Procedures .......... K Formation Bleed-Off Test ................ L Rig AbandoD3nent and Suspension Procedures . . . ~ . . . M Hanging-off Procedures-Appliqable to Floater Only . . . N 30 Inch Casing String ................. O 20 Inch Casing String ................. P 13 3/8 Inch Casing String ............... Q 9 5/8 Inch Casing String ....... ~ . ~ .. .... R · 7 Inch Liner ....... . .... % ....... S SSR Plug System .................... T Casing Running and Cementing Report . . . ~ ...... U Page 2 PHILLIPS PETROLEUM COMPANY KENAI, ALASKA 99611 DRAWER 66 PHONE: 907 776-8166 NATURAL RESOURCES GROUP Exploration and Production Kenai District CERTIFIED NO. 463836 RETURN RECEIPT REQUESTED DeCember 31, 1980 File: P-JFS-415-80 Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: SRS Tern C No. 1 - Sec. 26-10N-1iW, SM. Attached, in triplicate, is an Application for Permit to Drill the subject exploratory well. Our tentative plans would be to drill this well in April, 1981, if a suitable rig is available. If You have any questions concerning our pro- posed program, please give us a call at 907 - 776-8166. %..- ~isF~r~S~tttsleuperintendent JFS/NEP/so ~ ..... Attachment (3) g£C£1VED Alaeka Oil & ~as Cons. AnChorage C°rnrni$$iott. 'a. Type of work. STATE OF ALASKA ALASKA C~"JAND GAS CONSERVATION CCi" ")IISSION PERMIT TO DRILL 20 AAC 25.005 I DRILL [] I lb. Type of well EXPLORATORY [~ REDRILL [] I DEVELOPMENT OILI-] ' DEEPEI<I [] DEVELOPMENT GAS [] 2. Name of operator Phillips Petroleum Company SERVICE [] STRATIGRAPHtC [] SINGLE ZONE [] MULTIPLE ZONE [] 3. Address P.O. Drawer 66 Kenai, Alaska 99611 4. Location of well at surface 500' FEL & 1400' FSL At top of proposed producing interval Same At total depth Same Sec. 26 - 10N- llW- SM 5. Elevation in feet (indicate KB, DF etc.) 1~ 60' at:x3ye Mr,T:W 6. Lease designation and serial no. ADL 59351 9. Unit or lease name SRS TERN C 10. Well number 11. Field and pool 12. Bond information (see 20 AAC 25.025) Type Blanket Surety and/or number 41-00-524 Amount $200,000 13. Distance and direction from nearest town 26 miles 16. Proposed depth (MD & TVD) 10,000 ' BOF (MD & TVD) feet 14. Distance to nearest property or lease line 3 ,'880 feet 17. Number of acres in lease 2,560 19. If deviated (see 20 AAC 25.050) KICK OFF POINT feet. MAXIMUM HOLE ANGLE '120. Anticipated pressures oI (see 20 AAC 25.035 (c) !2) 15. Distance to nearest drilling or completed well 8,302 feet 18. Approximate spud date 4/15/81 4600 psig(~~ Surface 5600 .... psig~_10: 000ft. TD (TVD) 21 Proposed Casing, Liner and Cementing Program SIZE SETTING DEPTH QUANTITY OF CEMENT Hole 36 26 17 ½ 12 ¼ 8% Casing Weight 30 196 20 13 3/8 ,,,9 5/8 7 94 22. Describe proposed program: 36/40/4'7 K/N 32 N CASING AND LINER Grade X-42 H Coupling [, Length . 00 p c_ / z,000 ~3TC /4,000 ~Tc /Z0,000 MD TOP TVD RKB I100 ~ 100 RKB '100 I RKB - ~100 RKB ~,100 MD BOTTOM TVD RKB I 200 ~ I 350 RKB I 1,100 RKB I 4,100 RKB '110,100 (include stage data) .1000 sx lO00 sx 800 sx 400 sx 250 or 120/300 See Attachment for Detailed Program. RECEIVED. JAN I 5 1981 Alaska Oil & Gas Cons. Commissior~ Anchorage 23. I hereb tify that the f e ' g is tru an correct to the best of my knowledge SIGNED Settle _ TITLE District ._SIUperintendent The__~/below for Commission use CS~BJE~ TO amendments to original program dated January 20 and 27, 1981. CONDITIONS OF APPROVAL Samples required ]YES E]NO Permit number APPROVED BY Mud Icg required J~YES [[]NO A PP6°~12d~ 781 Directional Survey required I APl number []YES ~)~NO J 50--75'3 -- SEE COVER LETTER FOR OTHER REQUIREMENTS ,COMMISSIONER by order of the Commission DATE February 20, 1981 Form 10-401 Rev. 7-1-80 Submit in triplicate STATE OF ALASKA. ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Type of work. DR ILL [] REDRILL [] DEEPEI~ [] lb. Type of well EXPLORATORY J~ DEVELOPMENT OIL [] ' DEVELOPMENT GAS [] SERVICE [] STRATIGRAPHIC [] SINGLE ZONE [] MULTIPLE ZONE [] 2. Name of operator Phillips Petroleum Company 3. Address P.O. Drawer 66 Kenai, Alaska 99611 4. Location of well at surface 500' FEL & 1400' FSL At top of proposed producing interval Same At total depth Same Sec. 26 - I0N- llW- SM 5. Elevation in feet (indicate KB, DF etc.) ~ 60' abo~e HT,T;~ 6. Lease designation and serial no, ADL 59351 9. Unit or lease name SPaS ~N C 10. Well number 11. Field and pool Wildcat 15. Bond information (see 20 AAC 25.025) Type Bla_q~et Surety and/or number 41-00-524 AmountS200,000 13. Distance and direction from nearest town 14. Distance to nearest property or lease line 26 miles' 31'880 feet 16. Proposed depth (MD & TVD) 17. Number of acres in lease 10,000 ' BOF (MD & TVD) feet 2,560 ' 19. If deviated (see 20 AAC 25.050) 120. Anticipated pressures KICK OFF POINT feet. MAXIMUM HOLE ANGLE ol (see 20 AAC 25.035 (c) 15. Distance to nearest drilling or completed well 8,302 feet 18. Approximate spud date 4/15/81 4600 psig@ .. Surface 5600 ~psig@10: 000ft. TD (TVD) 21 Proposed Casing, Liner and Cementing Program SIZE 12 ¼ 8% Casing 30 20 13 3/8 9 5/8 7 Weight 196 94 54.5/72 36/40/4' 32 22. Describe proposed program: CASING AND LINER Grade /Couplingl Length Is l' zoo I I FTC I ,000 FTC I ,000 N DTC IlO, ooo SETTING DEPTH MD TOP TVD RKB I 100 . RKB 100 lo0 RKB . 100 RKB 100 MD BOTTOM TVD I 200 RKB I 350 RKB I 1,100 RKB ! 4,100 ",Z0,Z00 QUANTITY OF CEMENT {include stage data) 1000 sx 1000 sx 800 sx 400 sx 250 or 120/300 See Attachment for Detailed Program. 23, I hereby certify that the foregoing is true and correct to the best of my knowledge SIGNED J.F. Settle TITLE District Superintendent DATE The space below for Commission use CONDITIONS OF APPROVAL Samples required [-JYES J~]NO mit number APPROVED BY Mud log required OYES E~]NO Approval date Directional Survey required I APl number OYES I--] N O I 50-- SEE COVER LETTER FOR OTHER REQUIREMENTS .COMM ISSl ON ER DATE by order of {he Commission Form 10~401 Rev. 7-1-80 Submit in triplicate 90 VICINITY MAP SCALE IN MILES 0 25 50 ,, LAZ: So~o SCALE IN MILES I 3/4 I/, t/4 0 ~,, , I I INCH= I MILE FROM U.S.G.S 1:63j560 SCALE MAPS 'KENAI (D-4) AND C. 8 G.S. 8.555 o,-Y-----r/ × × X ~< ; BOTTOM LtNE= 90s . RIG TYPE-- JACK UP. OR FLOATER SRS TERN 'C' PROPOSED TOP AND BOTTOMHOLE · , LOCATIONS North ~ook Inlet Alaska 10.5 'Miles SS E of Tyonek Phillips Petroleum Company Drawer 66 Ke naI ~ Alaska 99611 DATE August 27, 1980 ! PPCO ADL )349 27 Phillips AD'L 59566 '23 Phillips ADL 59350 24 26_ Proposed Well Lat. 60° 55' 30.55" Long. 151009' 51.22" y = 2,531~928 x = · 292,86:3 Phillips . 35 _50C · ~et~~rr ole Um , , ADL 59351 z 0 Company 36 RIIW PHILLIPS ADL 59365 3O Phillips ADL 5934.7 31. RIOW' .. PROPOSED SURFACE AND SUBSURFACE WELL LOCATION SRS TERN ¢ LEASE Phillips Pefroleum. Comp(]ny Locefed in NEI/4~ SEI/4~ Sec. 26-~ TION~' RIIW~ UPPER COOK INLET~ ALASKA S. Uo BY BESSE, EPPS & POTTS · ANCHORAGE, ALASKA ~4976_~_12 ~ Well Name: Location: DRILLING PBOSP~ 'SRS Tern C No. 1 1400 ' FSL and 500 ' FEL Section 26 - T10N- RllW- SM Water Depth: 90 feet MLLW Type Unknown - either a ja ~ckup or a floater T.D.: + 10,000 TVDBOF 40' Assumed G~/,~ERAL OPF~RATIONAL PROCEDURES 1. Safety is the first consideration of all working men. 2~ It is the responsibility of all Phillips' supervisors to con- tinually obserVe the operation of men and equ. i~t in order to create a safe working environment and to make all concerned safety conscious. . e Supervisors must attend and participate in the weekly safety meetings and see ito it that daily safety meetings are oonducted. 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. Have meetings with the diving team and the diving team lead%er. 'Discuss the work to be done,, how to d6 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. . Check persons arriving onboard for sickness. The incoming crews can bring dysentery, grippe, flu and many conmunicable diseases on board. Do not let a sick man stay on board and expose everyone. . Safety is everyone's business. Let us all work together to have a safe operation, make arrangemehts for relief crews. ?his also applies to the work boats on long anchor handling jobs. e When the supply boat drops anchor and backs into discharge or receives cargo, it will back under ~he crane, but will stand off as far as possible from the rig. Personnel baskets will be used only for emergency personnel transfer. e The oontract helicopter will be equipped with navigational aids to permit emergency transportation during most conditions. There will be. no sling loading except when absolutely necessary. DA~,Y DRILLING REPORT A verbal report following the format of Exhibit A covering the period . frcm 0600 hours one day to 0600 hours the next will be telephoned by the Phillips Drilling Supervisor to the Drilling Superintendent at 0615 A scrambler shall be utilized to report confidential information on oil and/or gas shows, geological data, DST data, perforations and production 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. All written reports called for shall be sent to the Kenai Office on Wednesday. of each week.. IADC DRILLING REPORT The Phillips Supervisor .shall insist that the Drilling Contractor fill out the subject report _oo~le.t. ely_ and legibly_. Two copies of said report are to be submitted. : MATERIAL HANDLING ~ND 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. 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 requ. isitions will be pre-numbered and prepared in triplicate by the Phillips Supervisor and two cQpies sent to the Material Expediter in the Kenai Office. The expediter will send one copy back to the rig at the t~ ~he material is shipped. It is the Phillips Supervisor's responsibility to avoid m~king verbal material orders by antici.pating material requirements sufficiently in advance for a written requisition system to function effectively. Phillips' Supervisor will be responsible for regulation of boat traffic and proper handling and accounting of all incoming and outgoing materials. (2) ~TINiEN'I' OF CRITICAL OPERATIONS Listed belch, are the limits in which critical operations will be curtailed. A. If a floater type drilling vessel is used: Critical Operation Vessel Heave, Ft. Run BOP - Start if forecast & present oondition' is less than ........ Ball Joint Angles, Degrees 2. Run casing - start if forecast & present condition is less than ....... 5 1 e Drill-stem testing- start if fore- cast & present condition is less than... Test tools will not be opened at night. 5 1 4, Logging and wireline op~ations - - start if forecast & present condition is less than ........................... i1 5. Drilling - continue drilling if pre- sent condition is less than ............ 11 2 e 7. Cut off and recover casing - if pre- sen_t ~co_nditioD__is less ~than ...... , ..... POH into casing, hang off drill pipe' & WCW if forecast condition is equal to or greater than., ................... Prepare to disconnect, pull & lay dc~n riser if forecast condition is equal to or greater than ..................... 1! 2 11 5 15+ Be 2, If a jackup drilling 'rig is used, it is not as sensitive to weather conditions. Listed belcy~ are the critical ,operations which must be curtailed. Critical Operation Wind Velocity Wave Heiqht Run casing- start if forecast & present condition is less than ........ 50 kts. 25 feet Drill-st~n testing - start if fore- cast & present condition is less than... Test tools will not be opened at night. 50 kts. 25 feet Logging and wireline operations -- start if forecast & present condition is less than ............................ 50 kts. 25 feet. (3) A copy of the Mud Program (Attachment C) shall be kept at the rig for ready reference by the mud engineer, oontractor tool pusher and the Phillips Supervisor. The Phillips Supervisor is responsible for having the mud engineer: . 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 oonditioning and monitoring ~i~t in conformance with the program. 3. Maintain surveillance of the drill pipe corrosion rate. The Phillips Supervisor is responsible for having the drilling contractor: 1. Follow the hole fill-up procedure outlined in Attachment E when making a trip; . 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 OONTROL PROCEDURES _ Kick control procedures are shown in AtteSt D. Appropriate precautions a~d procedures are given for kick control during various phases of drilling operations and should be displayed at places convenient for the driller and Zig supervisor. · HYDROGEN SULFIDE OPERATIONS PIAN Hydrogen sulfide is not expected. However, if H2S is encountered, follow detailed procedures listed in the H2S Contingency Plan. DRILLING BREAKS · If a drilling break occurs '(.double rate of penetration) the following procedure will be followed: 1. Drill not more than 10' 2. 3. e Pick up off bottom. Notify Phillips Drilling SuPervisor, Geologist and Contractor Senior Pusher. Shut down pumps and check flow nipple for flow or loss. (4) Se On a jackup, if well flc~s close Hydril,. choke and kill line valves. On a floater, close hydril and kill line valve but leave choke line valve open to record casing pressure at the Surface at the choke. Record drill pipe pressure as well as 'casing pressure each five minutes until drill pipe pressure becomes static. 6. If well does not flc~, Geologist will determine .if break warrants circulating bottoms up. C~SING RUNNING AND CEMENTING REPORT The phillips Supervisor is responsible for preparation and submission of a copy of the subject report (Attachment .U) following a casing job. A carbon copy shall be retained at the location. CORING PRfXtRAM Core points wiiI be picked by the Phillips C~ologist. cores are anticipated to be taken. Full diameter Use a Christensen 6-3/4" x 4" x 60' core barrel with 8-1/2" diamond oore head during coring operations. Use near bit stabilizer and another stab- ilizer 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 AncPDrage. Materials for "canning" the cores will be supplied by Core Lab. Side~all cores may be taken using' Schlumberger following the running of open hole logs as directed by thc Phillips Geologis6. The Phillips Geologist is responsible for distributing core samples to Core Lab and Alaska Oil and Cas Conservation Comnission. The following open hole logs will be run at each casing point bel°w the 20" casing. 1. Microspherically focused log (MSFL) may be run over hydrocarbon bearing z~nes. Dual Induction Laterolog (DIL) - Spherically Focused Log (SFL) with SP, GR, caliper. 2. Borehole Compensated Sonic Log with J.ntegrated travel time, gan~a ray, and caliper. (GR to be run all the way back to mud line on first logging run.) 3. Compensated Neutron and Formation Density Log with gamma ray and caliper. (5) 4. Long Spaced Sonic Log. 5. Four.-arm Continuous Dipmeter. Ail 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 di ~pmeter tape will also be provided. Logging operations will be supervised by the Phillips Engineer and/or Geologist on board. The Phillips Geologist is responsible for distri- bution of the log prints and log tapes. HOLE AND CASING PROGRAM The follc~ing table presents the proposed Hole and Casing Program for the well: Hole Size Inches 36 or driw 26 17-1/2 (1) 12-1/4" 8-1/2" Casing Size and Grade 30" A.P.I. Gr. B 20" X-52 or K-55 · 13-3/8" K-55 / 9-5/8" K-55 7" N-80 Weight (Lb/ft) 196 94 54.5 36/40./47' 32 Type of TP~eads VetCO "Squnch" STC STC LTC Setting Depth (Ft. BOF) 50-100 ' 250 + 1000 + 4000 + · . D. (lO,, ooo +_) NOTE: (1) A 1.4-'3/4" hole will be drilled.and logged, then opened to 17-1/2" to accommodate the 13-3/8" casing string. CEDING PROGRAM Anticipate your cement needs far in advance so that adequate supplies will be on board when needed. R1ne proposed cementing will be as shcm~n in Attachment G. The proposed volume and additives could vary depending on ~ hol~conditi0ns. DIVIATION PROGRAM A "straight" hole is planned and is to be drilled in accordanCe with the following specifications: '(6) Well Depth RKB Maximum Distance Between Surveys Max. Deviation From VertiCal Max. Change of Angle 'Between surveys 1 - 150 Water & Air Column N/_A 150 - 400 100' 1° 400 - 1150 300 ' and/or @ bit 2° 1150 - 4150 500 ' and/or @ bit 5° 4150 - T.D. 500' and/or @ bit 8° lO/N/A 100 ' 1°/100' or 20/300 ' 1 1/20/100' or 2 1/2°~/500' 1 1/20/100' or 2 1/2v/500' A "G0zDevil"-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 instrumeant will be used to determine hole angle (inclination) and direction (azimuth). %he azimuth shall be reported as recorded by the instrument and also as corrected to Lambert-Grid North. If it beoomes necessary to deliberately oorrect the course and/or angle of the hole, magnetic single shot surveys shall be taken at 30' intervals and angle change shall be limited to 2o/30' and 3-1/2°/100'. DRILL STI~I TESTING P~. Possible. zones of interest will be selected by ~e on board geologist for testing. The decision to test will be made follOWing consultation with Denver Exploration and Kenai Production Offices. The Phillips Supervisor will direct the testing operation in accordance with the general procedure outlined on Attachment H. Attachment IA illustrates the general test string which will be implemented during the DST-if a floater is used. Attachment IB illustrates the test string if a jackup is used. WELL HEZkD SYSTEM AND BOP SYSTEM A. If a floater is used to drill the well, a subsea well head and BOP system will be used. %he B.O.P. system used will consist of two (2) 5000 psi or better double ga~e units and two (2) 5000 psi Hydril annular preventers. Attachment JA illustrates the B.O.P. and the subsea well head equipment. Control equipment and operating pro- cedures are also discus-bed. B. If a jackup is used to drill the well, a surface well head and B.O.P. system tog~[ther with a mudline caSing suspension system will. be em- ployed. The B.O.P. system will consist of two (2) 5000 psi or better single gate units or one (1) double gate unit an.~, one (1) 5000 psi or better Hydril annular 'preventer. Attachment~ illustrates the B.O.P., well head and mudline suspension equipment. Control equip- ment and operating Procedures are disCUssed., al.so, When a floater is fl~ed,' a'diver[er .is §on~etJ?es '~c~loi:~ On to~ of riser after, subsea BOPE'. is"'insfailed ." If a floa[er-is used','And' .it has ai'diverter, we will.employ it after.20'' is" setl .. ' : ' . .' ,'/." ~" '.'" ' '. "[ :'~'. ' -':.' t" ]' ]'. 'i J;..:.,. ~'-"',/ ~'~ If a~ jackup is.. Usedf to :,drill:this wei1,, nO diV~rt~r' will:be' 'employed bn....-:; .. 30" while drilling'to_ 20" csg. point. '..See.' Ceneral. Note;-~..~! .... i:'.~:. -..:.'-:.i~ ~ (7) Once 20" is set, surface BOPE will be employed on toD the extension from subsea casing hanger. GEneRAL NOTE: No diverter need be employed on the conductor pipe regard- less of type of drill vessel because wellbore conditions do not re- quire i%. 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 shallcx~ drilling hazards were enoountered. BOPE AND CASING TESTING RS~X3IRF~ le BOPE Testing Requirements All BOPE equipment will be tested prior to and upon installation, pri6r to drilling out a casing shoe, follc~ing 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 B.O.P.Ei. The table below shows the pressure requirements for each test operation. Test ..Operation Test Stump (Prior. to Installation) Initial Installation & after Ram Change Before Drilling 20" shoe & Weekly' Test Before Drilling 13 3/8" Shoe and Weekly Test Before Drilling 9 5/8"' Shoe and Weekly Te~t to. T.D. Before testing in 7" Pipe Rams Annular Choke & Kill Lines 3,500 3,500 3,500 3,500 3,500 3,500 1,000 1,000 1,000 '~:i. 2,000 2,000 2,000 3~000 2,500 3,000 5,000 2,500 5,000 2. Casing Testing Procedures and PreSsure Requ~ir~ts are outlined in Attachment K. WELL LOG QUALITY COk~fROL CHECKLIST (Form 10128) The Phillips Representative. (Fmgineer or Geologist)present during logging operation is responsible for obtaining top quality logs. As an adjunct to 'this responsibility, the Phillips' Representative will in cooperation 7ith the logging service engineer complete the subject logging checklist Attachment B) . and submit the completed form together with the field copy 'of the logs. LOG, SHALE DENSITY LOG, PORE PRESSURE PLOT & "D" EXPONENT PLOTS The Phillips Supervisor will obtain %~o copies of the Mud Log, Shale Density Log, Pore Pressure Plot and "D" Exponent Plots. Retain one'copy and submit one copy.. (8) DRILLING MUD REPOR~ %he Phillips Supervisor shall submit the weekly accumulation of the Daily Drilling Mhd Reports prepared by the mud engineer. Said report will shc~ the daily mud additions and the cost thereof. SERVICE TICKETS R~ne Phillips Supervisor is responsible for requiring field service tickets from all oontractors performing work and for examination of all said tickets for completeness and accuracy. Tne Phillips l 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. ~D LOGGING A mud log will be maintained from the spud to T.D. The Phillips geolo- gist 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: · Shale Density Log 'D' exponent plot H2S in the mud The Phillips SuperVisor shall clOsely monitor the results of· the above special checks in cooperation with the ge01~iSt so a safe, controlled drilling program can be achieved. Due to the number and character of drilling cutting sa~01es 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. SAMPLING PROGRAM The mud lOgger will catch samples as directed by Phillips.' geologist. Phillips' geologist is responsible for distributing samples %o the Alaska Oil and Gas Conservation Commission. , FORMATION BI,RED-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. (9) HANGING-OFF AND RIG ABANDONM~T 7 Applicable to Floater Operations Only. 1. Hangi...ng.-Off Drill Pip~. - If it is deemed neoessary to suspend drilling operations follc~ procedure outlined in Atta~t N. 2. Rig Abandonment & Suspension - ~ne procedure for rig abandor~ent and suspension is outlined in Attac~t M. Phillips Petroleum Con, any reserves the right to make any changes to this program at any time. Prior ~ making any procedural changes, Alaska Oil and Gas Conservation Con~ssion approval must be obtained. (lO) FLOATING DRILL RIG DRILLING PROCE. DURE 1. Rig up and run tent0orary guide base (TGB). Se Set TGB on spider beams and install Regan slope indicator. Fill compartments with 18 ppg mud and install manila rope flags on guide lines at 160' and make up guide lines to TGB. be Pick up TGB on running string made up as follows: Running tool, bumper sub and heavy weight drill pipe. Adjust guide line ten- sion to 2,000 lb. Ce Run TGB to sea floor at slack tide, slack off 1/2 of the travel of the bumper sub. Use diver to check inclination of TGB. If inclination exceeds 5° pick up and reset. Record the following depths (1) RKB to mean sea level; (2) RKB to sea bed, and (3) RKB to top of TGB. d. Adjust guide line tension to 2,500 lbs. and release running too1.' POOH. NOTE: Do not rotate pipe while running 'or pulling pipe to avoid guide line damage. 2. Drill 36" hole with 26"' bit and 36" hole opener to a total of 100' penetration with sea water. Clean~ hole every 30 feet with thick mud, load hole with thick mud, POOH., Prepare to run and cement 30" casing. 3. Rig up and run 30" made up per attachment "O" 1 4 · Set PGB on spider beams and install Regan slope indicator on Pernmnent. Guide Base (PGB). Run 30" and land 30" WH housing in PGB. Attach retainer ring· Install guide lines in PGB posts. be Run a drill pi.pe stinger with plug catcher on bottom of stinger below the running tool to within 5' of the 30" casing shoe and fill annulus between DP and casing with sea water. C. Latch running tool into 30"WH housing, pick up, spread spider beams, and run 30" with PGB attached with cementing string during Slack tide. de Set 30" on bottom. Using diver, check inclination of 30".t0 insure inclination of less than 1O. Hold 30" with motion com- pensator while cementing. 410- e NOTE: If for any reason 30" casing ~tops, the kelly can be picked and drill pipe connections can be made: The 30" can be circulated with sea water %o bottom, single by single, without 'getting the kelly through~ the rotary table. Circulate to bottom only. Cement 'the 30" conductor as fo llc~s: A. Mix and pump 500 sacks' Class "G" omment mixed with 2.5% pre- hydrated salt-gel-inlet water mixture at a slurry weight of 12.8 lbs/gal. B.. Follc~ with 500 Sa~ Class "G" nea%~ cement mixed with sea wager ~.~ t5.8 lb/gal. ~ C. Drop. top plug (no bottom plug will be used). D. DisplaCe cement to plug catcher using sea water. Do. not exceed 1500 psi. Calculate displacement volume required %o bump plug. Before reaching this volume, slow down pumps. After plug bumps, pressure to 2,000 psi and shear out. . Check for back flow. If none, release running %ool and pull DP stinger clear of housing. Wash off top of guide structure with sea water. COOH by chaining out. D~ Not Rotate DP. W.O.C. for 12 hours. 6. Make up 14 3/4" bit and BHA. Drill 14 3/4" hole to + 450' RKB (+ 290' BOF) with sea water and vis .cous mud sweeps at 30' inte~als. . kfter reachin%g 20" casing point, open hole to 26 inches.. Fill hole with high visoosity mud. Pick up to 30" Wellhead and displace mud out of 30" wellhead housing with sea water. POOH. 8' About slack tide, pick .up and run 20", K-55, 94 lb/ft STC'~cas~.' ~s' follows :~ a. Casing will be made as' per Attachment P-!... _Make up length should be such that when casing is hung, there will be a space the equiva- lent of one joint of casing between shoe and bottOm of hole. Note: Fill each joint of casing and drill pipe with sea water as it enters water level. b. Make up running tool into 20" WH housing and run 20" Casing on HWDP. c, Land in 30" housing and latch into place. Pull-test latch with 15,000 lbs. over weight of 20" casing~ string. d. Release running tool and COOH. e. G.I .H. w/plug catcher and stab-in sub on DP and stab into float collar. -11- e 10. 11. Se Cement the 20" casing string as follows: Break circulation and pump in 30 bbls. water preflush. Pump in 500 sx Class "G" cement with 2.5% pre-hydrated brine gel mixed with inlet water at a slurry weight of 12.8 lb/gal. c. Follow with 500 sx Class "G" cement mixed with sea water at a slurry weight of 15.8 lb/gal. d. Drop top plug (no bottom plug will be used). e. Displace cement to plug Catcher with sea water. Do not exceed 1500 psi pumping pressure. Calculate displacement volume re- quired to bump plug. Before pumPing this volume, slc~ pumps down. After plug bumps, release pressure and check for back- - flc~. If okay, COOH and W.O.C. for 12 hours. ~g rig and and rtnn pretested BOP stack, riser assembly and diverter (i,~f ~ so equipped).. (Attachment "J") Pressure test BOP's, casing, choke and kill lines as per Attachment "K"~ Pick up 14 3/4" bit and BHA. GIH to float collar. Build fresh water gel mud (8.5 - 9.0 ppg). Displace sea water from hole with .. 12. Drill 14' 3/4" hoi~ to 1,210' RKB (1050' BOF). rat hole below 13 3/8" setting depth. This allows 40 ' of 13. Circulate and condition hole for running open hole logs. as directed. Run logs 14. Of~n 14 3/4" hole to 17 1/2" to T.D. 13 3/8" casing. Condition hole for running 15. Pull wellhead seat protector and run 13 3/8", and Se be C~ Note: 54.5#/1, K-55 STC 72#, N-80 BTC casing as follows: Casing will be made upper Attachment Q-1. 13 3/8" running tool w/casing hanger and HowcoSSR plug set attached. (Attachment "T") Drill pipe to surface. Fill casing as it is being run. -12- 17. After casing landed, break circulation and circulate hole clean and rig up to cement casing. Cement the 13 3/8" casing string as follc~s: a. Pump 25 bbls. water and release bottom plug. b. Mix and pump 500 sacks of Class "G" cement m~xed with 2.5% pre-hydrated gel and .fresh water (12..8 ~/gal slurry welght~ c. Follcw with 300 sacks of Class "G" cement mixed with 2% CaCL fresh water (15.8 #/gal. slurry weight), d. Displace cement out of cementing lines to cementing head with water and release top plug. e~ Displace with mud~ Bump %op plug and pressure up %o 1500 psi. Do not pump more than 5 bbls. excess over calculated displace- ment volume. · fe Check for back flow. If it is necessary to keep pressure on casing while W.O.C., wash out BOP stack with water through kill line, close Hydril, actuate.casing .packoff, and pick up running string 6 inches. Wash out wellhead by pumping water doown ~nnning string and ~out choke line maintaining required, pressure on casing. DO NOT EXCEED 1000 psi pressure. g. If there is no flow back, actuate casing packoff, pick up running string 6 inches and wash out BOP by pumping through running string. Also wash out choke and kill lines with water. h. C.O.~O.H. and_ pick up wellhead jetting tool. GIH and thoroughly clean BOP stack and wellhead. 18. .Run test tool on drill pipe and oonduct BOPE test as per Attach- ment "K". Pressure test casing to 2,000 .psi after W.O.C, 19. Pull test tool and install wear bushing.' Pick 12 1/4" bit and. BHA, d/ill out 13 3/8" shoe and make 20'~ --~ 40:' of new hole. 21. Conduct Formation Bleed-off Test as per Attachment "L" .~ -13- 22. This allows 40' of rat hole 23. Drill 12 1/4" hole to 4,200" RKB. belc~ 9.5/8" setting depth. Circulate and condition hole for running logs. Run open hole logs as directed. 24. 25. 26. Condition hole to run 9 5/8" 36# and 40# K-55 STC and 47# C-95 BTC casing. Pull wear bushing. Run casing as follc~s: a. Casing string will be made up as per Attachment R-1. {Be sure to drop ball to actuate back pressure valve in float equipment prior to Step B. b. 9 5/8" running tool with easing hanger and Howco SSR plug set attached.' (Attachment "T") · c. Drill pipe to surface. d. Periodically check to see %ha% automatic fill eqhipment is working; if not, fill as it is being runl Circulate· hole clean and rig up to cement casing. Cement 9 5/8" casing string with enough cement to fill 1,000' above any hydrocarbon bearing zones above 9 5/8" shoe. The cementing will be performed as follows: a. Pump 30 bbls. water and release bottom plug. b. Mix and pump calculated amount cement as skated above (see Attachment "G"). c. DisplaCe cement out of ,cementing lines bo cementing head and release top plug. de e. Displace with mud. Bump top plug and pressure up to 1,500 psi. Do not pump more than 2 bbls. over calculated volume.. Check for flow back. If it is necessary to keep pressure on casing while W.O.C., do not al, low pressure to exceed 1,500 psi. f. Actuate packoff and pressure test to 3,000 psi. g. W.O.C. 12 hours. -14- 27. 28. 29. 30. 31. 32. 33. 34. With running tool still in place conduct BOPE test as per Attachmant "K". Pressure test casing to 3,000 psi after W.O.C. Install wear bushing. Pick 8 1/2" bit and BHA, drill out 9 5/8" shoe and make 20' - 40' of new hole. Conduct Formation Bleed-off Test as per Attachment "L". Drill 8 1/2" hole to T.D. Maintain a close check on mud parameters, shale densities, 'D' exponents and penetration rates while drilling this section of hole. Circulate and condition hole for open hole logs. Run open hole logs as directed by geologist. De,pending on log interpretation, either condition hole to run 7" casing or P&A as directed. If well to be P&A, go to step 40. Pull wear bushing and run 7", N-80, 32 #/ft2 LT&C casing as follc~s: a. Casing will be made per Attachn~nt S-1. b.~ Land casing with casing and 7" casing full bore running %ool. Conventional cementing head and plugs will be used. There should be the equ~ ivalent on one joint between shoe and bottom of hole. . c. Periodically check to see that automatic fill equipment is working; if not, ~ill pipe as it is being run. d. Drop ball to actuate back pressure valve and circulate hole clean. Cement 7" casing with enough cement to fill 500' above all hydro- carbon bearing zones above 7" shoe. The cementing will be performed as follc~s: a. Pump 10 BBLS. water preflush. b. Mix and pump calculated first stage cement as directed follow- . ing log analYsis. c. Drop separation plug and displace. d. 'Drop stage collar tripping plug and open stage collar. e. Circulate hole ~clean. When hole clean, cement second stage as directed. - 15- f. Drop stage collar closing plug and displace w/mud. go After closing stage collar, release pressure and check for flc~ back. If it is necessary to keep pressure on casing while W.O.C., hold final shutdown pressure until surface samples are set. h. Actuate packoff and test to 5,000 psi. 36. 37. 38. 39. 40. 41. W.O.C. 12 hours and conduct BOPE test as per Attachment "K". Pressure test casing to 5,000 psi and POOH. After logs are evaluated specific zones will be tested as per Attachment "H". The zones will be tested from bottom up. After well is tested, .permanent bridge plug(s) will be set above perforated interval(s). A 50 ft. cement plug will be spotted above each bridge plug. After uppermost B.P. is' set, it must be tested by placing 15,000 lb. of weight on the B.P. prior to placing cement plug on top. If a 7" casing string was run, pull as follows: a. Retrieve 7" packoff assembly. Cut 7" with multi-string cutter at 400' BOF. Retrieve 7" casing hanger and string. · b. R.I.H. w/open drill pipe into 7". and spot enough Class "G" cement w/2% CaC12 to fill 7" casing 100' below stub and 9 5/8" casing 100' above stub. c. Pull up 100! above 7', stub and circulate 1/2 hour to dreSs- off plug and clean hous. i.n~? ~P O.O.H~ C~ ~%o step' 41. ....~.4.~ If 7" casing was not run, proceed as follows: a. Place 100' open hole cement plug between Sterling formation and Beluga formation. b. Place 100' cement plug at 9 5/8" shoe such that 50' of plug is below and above shoe. c. Proceed to Step 41. 9 5/8" casing string will be pulled as follcws: a. Retrieve 9.5/8" packoff assembly. R.I.H. w/drill pipe and multi-string cutter. Tag..%op' cement plug and set 15,000 lb. on cement Plug for %est. If okay, go to b. If not, replug, then go to b. b. Cut 9 5/8" casing with multi-string cutter, at 200' BOF. Re- trieve 9 5/8" casing hanger and casing. -16- Ce d, eo R.I.H. w/open drill pipe in~o 9 5/8" and spot enough Class "G" cement w/2% CaCl2 to fill 9 5/8" casing 100' belc~ stub and 13 3/8" casing 150' above stub. Pull up to 100' BOF and circulate 1/2 hour to dress off plug and clean hoUSing. Displace hole with sea water and check for flow. Pull and lay down marine riser and BOP. 42. 43. 13 3/8", 20" and 30" casings will be pUlled as follows: a. Cut the 13 3/8", 20" and 30" casings simultaneously with multi-string ~cutter at least 15' BOF. b. Run in with wellhead retrieving tool and latch. Pull 13 3/8", 20" and 30" simultaneously. Retrieve anchors and move off location. -17- J~KUP DRILL RIG DRILLING PROCEDURE 1. Make up 30" drive pipe as illustrated in Attachment 0-2. . . , . Install driving head, lower to ocean floor at low slack tide and drive 30" to point of refusal or 200 blows per foot. If penetra- tion is less than 50' BOF, pick up 22" 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. Pick up 14 3/4" bit and BHA. Drill 14 3/4" hole to 450' RKB (290' BOF) with sea water and viscous (200 sec/qt. ) mud sweeps at 30' intervals. After pilot hole drilled, open hole to 26 inches, using same hole cleaning fluid. Fill hole with viscousmud after reaching 20" cas- ingpoin~' Rig up to run 20" a. , 94#, K-55 casing as follows: Casing will bemade .upper Attachment P-2. spaCe out such that: (1) 20" casing housing will be locatedbelow mudline the correct distance such that when 13 3/8" is landed on 20" casing housing, the 13 3/8" tie back sub will be 10 - 15' below mudline, and (2) a 20" casing collar will not be 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, hang off at rotary table in slip type elevator-spider. C. GIH with plug catcher and stab-in sub on DP and stab into float collar. -1- . Cement 20" as follows: a. Bre. ak circulation and pump in 30 BFW preflush. 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. Ce Tail in with 500 sx of Class G c~t mixed with 60 barrels of inlet water mixture at a slurry weight of 15.8 ppg. d. Drop to~p~ plug (no bottom plug will be used). e~ f~ Displace ~t to plug catcher using inlet water. During dis- placement, 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. If okay, COOH w/Dp. 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 %n~Don pool area and flush out with fresh water. 7. After cement samples are hard, release tension on 20". Cut off 30" conductor and 20" caSing stubs as directed and install Gray Oil Tool's 20"-2000 x 13 5/8"-5000 wellhead assembly. All wellhead equipment to be set at same time. After WH installed, install BOP stack, bell nipple and flow line. Test BOPE, wellhead and casing in accordance with~ Attachment K. ~ 8. Install extended bowl protector, in wellhead. Pick up 14 3/4" bit and BHA. GIH and drill out float collar and shoe and cement below shoe. Displace SW mud with fresh water. Build fresh water mud per Attachment C and displace fresh water. -2- 9. Drill 14 3/4" hole to 1210' RKB (1060 BOF). This allows about 40' of rat hole below 13 3/8" setting depth. 10. Circulate and condition hole for running open hole logs. Run logs as directed. 11. Open 14 3/4" hole to 17 1/2" to T.D. Circulate and condition hole for running 13 3/8" casing. ' 12. Pull bowl protector and run 13 3/8", 54.5#/ft., K-55 STC and 72#, N-80 BTC casing as follows: a. Casing will be made up per Attachment Q-2. .~ l- b. Run casing to 1160' 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. 13. Cement 13 3/8" as follows: a. Break circulation and circulate hole clean. b. Pump 30 BF~ 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 .top plug (no bottom plug will be used). e. Displace cement to plug catcher using mud. During displacement, do not exceed 1500 psi pump pressure. Calculate displacement volume required %o bump plug. Bump plug easy. Pressure up to 1500 psi pump pressure. Release pressure slowly. Check for -3- back flow. If okay, pull stab-in sub out of float oollar. Check for back flow. If okay, COOH with DP. 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 cir- culating ports by opposite rotation. After closing ports, drain annulus above BOPE/wellhead and flush again with clear water. 14. Part the wellhead at 20"-2000# flange. Pick up wellhead/BOPE and prepare to install Gray· type WE casing hanger around 13 3/8". 15. Pick up 8000# 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. Dress stub and install 20" x 13 3~8" packoff. Install new ring gasket and button up wellhead. 16. Test BOPE, wellhead, packoff and casing in accordance with Attach- ment K. 17. Trim off extended bowl Protector to correct length and re-install in wellhead. 18. Pick up 12 1/4" bit and BHA. GIH and drill out float collar and shoe and cement below shoe. Circulate and condition cement contam- inated mud. Build mud weight to 9.5 ppg. 19. Drill 20' - 40' of new hole. Then conduct formation bleed-off test per Attachment L. 20. Drill 12 1/4" hole to 4200' RKB (4040' BOF) +. Plan is to set 9 5/8" before drilling any potential pay sands. -4- 21. 22. 23. Circulate and condition hole for running logs. Run logs as directed. Following logging operations, condition hole to run 9 5/8", 36 and 40#/ft., K-55 STC and 47#, N-80 BTC casing. Pull wear bushing. Run casing as follows: a. Casing string will be made up per Attachment R-2. b. Run casing to 4,160' 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. Ce 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. Cement 9 5/8" as follows to obtain minimum of 1,000 above shoe. a. Break circulation and circulate hole clean. .o be 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. ee Displace cement to float~collar. Calculate displacement volume required %o bump plug. Do no% 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 "e". If back. flow occurs, hold 1000 psi on casing till surface samples set. Then rig down cementing equipment. le 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 3/8" x 9 5/8" annulus using water. After · annulus clear, 'close circulating po?ts with opposite rotation. . Drain annulus above BOPE/WH and flush with fresh water re- gardless if Step 1 was taken or not. -5- 24. Part wellhead at bottc~ 13 3/8"-5000# flange. Pick up wellhead/BOPE and prepare to install Gray type "W" casing hanger around 9 5/8". 25. Pick up 5000# 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. 26. Test BOPE, wellhead, packoff and casing in accordance with Attach, ment K. 27. Trim off extended bowl protector to Correct length and re-install in wellhead. 28. Pick up 8 1/2" bit .and BHA. GIH and drill out float collar and shoe and cement belOW shoe. Circulate and condition cement con- taminated .mud. 29. Drill 20 ' - 40 ' of new hole. Then conduct formation bleed-off test per Attachment L. 30. Drill 8 1/2" h°le to 10,200' RKB [10,040' BOF) + or as directed. 31. Circulate and condition hole for running logs. Run logs as directed. 32. 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 33. If well to be P & A, proceed to Step 43. 33. Pull wear bushing. Run 7", 32#, N-80 LTC.casing as follows: a. Casing string will be made upper At%achment S~2. b. Run casing to 10,160' 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. -6- Ce Check periodically while casing is being run to see that auto- matic fill up equi~nent is functioning properly. Supplement as required. Drop float equipment tripping ball to actuate check valves. 33. Cement 7" as follows: a. Break circulation and circulate hole clean. be Pump 10 BFW preflush and pump first stage. will be furnished following log analysis. Slurry formulation Ce Drop separating plug and displace to float collar. Fig~e dis-- placement and bump plug easy. Pressure up to 1500 psi and slowly release pressure. Check for back flow. de 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. ee f~ ge When stage collar opens, break circulation and circulate out excess first stage slurry and clean up hole. When clean returns obtained, cement second stage as directed. When second stage cea~ntmixed, drop stage collar shutoff plug and displace with mud. When shutoff plug seats, pressure up 1000 psi over final pu~ing pressure. Release pressure slowly and che~k 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 d~n pressure until surface samples are hard. While WOC, flush out wellhead/BOPE. 34. Part wellhead at bo%tom of top 13 3/8"-5000# wellheadl Pick up top wellhead/BOPE and prepare to install Gray type "W" casing hanger around 7". -7- 35. 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" wellhea~ flange. Dress stub and install Gray type ~C-P 13 3/8" x 7" packoff. Install new ring gasket and button up wellhead. 36. Test BOPE, wellhead, packoff and casing in accordance with Attach- ment K. 37. Trim off extended bowl protector to correct length and re-install in wellhead. 38. 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. 39. Run correlation log and proceed to perforate, and test as outlined in Attachment H. 40. Zones will be tested from bottomup. After well is tested, permanent bridge plug(s) will be set above perforated intervals. A 50' neat cement plug will be set above each b~idge plug. 41. After uppermost bridge plug (BP) is set, it must be tested by placing 15,000# weight on BP before Placing cement on top~ After top BP w/i cement cap placed, nipple down BOPE. 42. 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. GIHw/spear and pull 7". c. GIHw/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 44. -8- 43. If 7" was not run, proceed as follcws: 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 44. 44. Pull 9 5/8" as~ follows: a. R~move the 13 5/8" x 5000# wellhead that was second from top. Then remove 9 5/8" packoff. b. GIH w/DP and mechanical cutter to cement plug near 9 5/8" shoe. Tag and test plug by putting 15,000# on plug. If okay, go to "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 100' plug above 9 5/8" stub into the 13 3/8". e. Pull up to 100' BOF and dress off plug and circulate hole clean. 45. Pull 13 3/8" as follows: a. Remove' the 13 5/8"-5000 x 20"-2000 wellhead. Then remove the 13 3/8" packoff. b. Rotate 13 3/8" twelve (12) turns to right to release tieback sub. Pick, up and retrieve 13 3/8". c. GIH w/DP into 13 3/8" and spot enough cement to fill 13 3/8" casing 50' below the female portion of tieback left in hole. d. Pull up to top of tieback and dress off plug and circulate hole clean. -9- 46. Pull 20" as follows: a. Ramove 20" packoff and then cut 20"-2000# wellhead off. b. GIH w/ mechanical cuhter and cut 20" at mudline and pull san~. 47. Pull 30" as follows: a. GIH w/mechanical cutber and cut 30" at mudline and pull same. 48. Jackdown rig and move off locahion. SRs ?~' 0 NO. i ~ ~,~ Attachment ~ Casing Weight Type of Hole Setting Casing Cement · Fract]~; Mud Pressur. es Calculated M~. Load API-Minimum Ratings Calc. Load / A.P.I.., ,,R,,ating (1 & 2) Threads Size Depth Top Top Pres. @ O~ts"ide Inside Co~llap'se Tension ~rs~. Collapse ---T~e~nsion 'Burst Collapse Tension Burst Size, and Grade (Lb/R) (In.) (Ft.BOF) (Ft,BOF) (Ft.BOF) Shoe(psi) (Psi/ft) (psi/ft) (psi) (iOOO~) (psi) (psi) (iioooib) (psi) ~ (5) I I I I I I I I I I I I II I ....... I I I III I III ~ { .... I [ ~ I ..... 30" x-a2 i96 Vetco 36 5o-ioo o o NA · ~ S l .468 24-~'7 iO-20 None N/A N/A N/A N/A N/A N/A "Squnch" 20,, H-40 94 STC 26 ~50' O O ~S? .~6S .46S i77 ~5 i76 5~O / 5Si i530 34 13 3/8" K-55/ 54.5/72* STC/BTC 17½ 1000 O O 812 .&6S .494 543 55 77i ii30 5.47 ~730 48 iO 29 E-80 ,. 9 5/8" K-55/ 36/40/ STC/BTC i~ 4000 o ('4)- ~soo .~94 .55i 195'5 iSi 2700 2570 :~ ~ 3520 76 20 77 7" N-80 32 LT&C 8~ io,ooo o (4) · 7000 .55i ' .55i 5600 3~0 4600 8600 I 672 9060 65 ~8 5i , , , . , ,., . ,. ,, , ,,, , .,,. ,.,, ,, ,, , , , , . , , ,,, , . , , . , . . (i) Ail casing except the structural casing will be new pipe meeting iAPI Standards. ' 'l ~' [~ (2) The 20", 13 3/S", 9 5/8" and 7" casing strings will be inspected:~to detect transverse and longitudinal defects, deterkine wall thickness, pipe eccentricity, grade uniformity and thread condition. . (3) Ail formation fracture pressures shown above are based on a fracture gradient pf .7 psi/ft, from RKB (i6o ft. AOF).Ito 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 esti~lated to be 4600 psia at 10,OOO' T.D. B. Criteria used to determine surface pressure: 1. The mud weights used in drilling the Shell State #1 drilled in Sec. 24, 1ON, llW, and Shell State ~2 (Sec. 2, 9N, I1W) were considered, as was our experience in drilling the Sterling and Beluga formations in the .North Cook Inlet Unit. These data. formed the basis for 6ur selection of mud weight required to drill these same formations at the proposed site-. 2. A bottom hole pressure based upon these estimated mud weights was calculated. The maximum anticipated surface pressure was calculated assum- ing a .7 gravity gas gradient from the bottom to the top ofI the hole. * The 13 3/8", 72#, ~-80 and 9 5/8", ~7#, 0-95 are being used only to reduce our stock of tubular goods . BUrst and collapse ratings and percentages are applicable to the lower weights and grades of pipe employed in these s~rings. Attachment B Form 10128 2--74 PHILLIPS PETROLEUM comPaNY - LOG QUA'L, ITY CHECK LIST INSTRUCTIONS: This form consists of three sections. Section I -- General information should be completed by the Phillips Representative prior to ~. logging. During and after logging, Section II-- (Operations) should be completed by the Logging E~glneer. Section III should be ,~%, completed at the end of the job by the Phillips Representative. Both the Phillips Representative and the Logging Engineer should examine the complete form prior to logging BO that proper planning can be made io obtain the needed information and to assure good . log quality. Blanks which contain tick marks are to be keypunched on IBM cards. Please print one letter or character per space, abbreviate if necessary. SECTION I -- GENERAL INFORMATION (PHILLIPS REPRESENTATIVE) I ! I ! !, I ! ! ! I I I I i i i ,t t ! I I f I I i i i I ! I I ! ! i I i I I ! ! I ! ! ! ! I i 75 , , i ] RUN NUMBER LOCATION: Section . Township Range Surface location PERM`. DATUM MUDS TYPE HOLE ~'] DEVIATED K B ELEV. D F' ELEV, DRILLING MEAS, FR. LOGS MEAS. FROM ABOVE PERM. DATUM MUD FT. ~T. ,,. LOGS TO BE RUN FROM TO SCALES SPECIAL INSTRUCTIONS [ , '.' ,, ) .... sEcTION II- OPERATIONS (LOGGING ENGINEER) A. EQUIPMENT USED (Enter Tool Numbers to Right. ie I , ,4 ,S l Not14 ,3 , , I FAI LURE OR ~ DATE LAST LOST TIME SERVICE SONDE CARTRIDGE PANE/ MEMORIZER DETECTOR SOURCE OTHERS SHOP CHECK YES NO I 2 3 5 6 9 t0 ~3 ~4 - I? t8 2~ 22 2~I 26 29 30 33 34 39 40 411 BI]- I , , , , , I_ I , I , , , ! , I I 1 , ! ! I ! BI2 ! I i ! ! I i I i ! t ! i i .... I t .... t- -t-1'-i I ! i ! [ i [ l Bi3 , , , , ! , I I ' , , , , , ill I I I ' , I B,4 , ~ , , , , , , ~, , , , , , , , ~ , , , , , , , [ , [ , ~',~ , , , , , , , , , , , , , , , , , , , , , , , B,6 ~ ' , , , , , ! ~ , t , ! ! , ~ , B 17 i I ! I ! I I I I ! I I i i . i i i I ! ! I i i , t , Acceptable Abbreviations: -- ES DIP -- ML BHC SWN CST -- EL DIL NILL CDL CNL --FT 1ES --LL PML FDC DIP IEL DLL --PL SNP COR MAXIMUM LOGGING SPEEDS: Ind. Elec. or Dual Ind. Laterolog or Dual -- LL Pad Devices: ML & MLL 2,500 FPH PL 4,000 FPH 6,000 FPH 4,000 FPH Radioactive Tools: W/TC = 2 W/TC = 3 Sonic or Acoustic: 1800 FPH 1200 FPH 4000 FPH C.. CHECK LIST (Check only if YES is appropriate Col, 1. [~] (NOte to keypunch ~ punch· ! in column 2 thru .... ~ '- ~' '~ GENERAL Rm, Rmf, Rmc & corresponding temperatures measured & recorded. Maximum BHT recorded on each mn. Appropriate logging scales chbsen (or prescribed by PhillipS). Backup gal'vos used so that all' curves are recorded over the hole. Pre-job operational check of all tool~. ' Tool checked going in the hole. Calibration checks and all zeros·properly rec.9:ded before and after logging. ... · Previous mn overlapped by-200~or to casing shoe. - ....... 200trepeat section run, preferably over zone of interest (Memorizer out). .. Memorized curves within 6"of curve to which they are memorized. Field heading completely fill~'~'ut~ All scales, scale' charges, shifts, ere. clearly marked on film and heading. Visual quality acceptable; developing, printing, etc. Logging speeds conform to Service Co. and/Or Phillips speciflcations. Attachmen~ B - . . SP 16. ~ SP curve normal with no nolse, magnetism or other spurious anomaly. 17. [--] No resistive component to SP (Similarity of SP and SN curves). 18. [~] Shifts made in constant SP zones (shales). (DO NOT attempt to continuously correct SP base line). 19. [--] SP ground checked and/or SP rerun with current off (Check only if abnormal appearance on normal run). 20. [--] Welders and unnecessary power turned off during logging. INDUCTION-ELECTRIC AND DUAL-INDUCTION Stand off used and recorded on heading. · Shoulder bed resistivity correcrion used and recorded on heading, Skin effect correction recorded at bottom of log showing step on curve before pickup. Calibration results meet logging company tolerances. Surface calibration not over 1 month old. 'SN and reciprocated curve have peaks at same depth (memorization check). Proper response characteristics on all curves. '. Repeat sections agree. No negative SN. Conductivity not negative, except due to over compensation by memorizer (SBR) when going from low to high resistivity. SN < · 1 ohm-M in casing. Conductivity and reciprocated curve agree at low (~ 1.0_I'L. - M) and high values. . LATEROLOG AND DUAL LATEROLOG 33. [--] Calibration results meet logging company tolerances. 34. [~] Proper response characteristics on all curves. Col. PAD TYPE LOGS (ML, MLL, PL) 35. [-'] Calibration results meet logging company tolerances. 36, ~ Caliper checked in casing and recorded. __ ( :~ Mudlog. xecorde&-- .... . 38, [--] Pad condition OK after survey. 39. [-"q Proper response characteristics on all curves. SONIC OR ACOUSTIC LOGS 40. [~ Centralizers used. 41. [--~ Calibrations meet logging company tolerances. 42. [~] Proper response characteristics on all curves,. 43. ~ Ail recorded values greater than 40 micro-seconds. 44. ~ No excessive noise or cycle skipping. 45. [~ Repeat sections agree. 46. ~ Casing reads 57 micro-seconds. 47. [~ Calibrations meet logging company tolerances. 48. ~ Statistics not over one log division. 49. ~ Response characteristics normal. 50. [--] 5~. [~] 54. [~ 5:5. ['--] GAMMA RAY COMPENSATED DENSITY Calibrations meet logging company tolerances. In guage hole, correction less than _+ .03 gm/cc (If mud cake is thin). Statistical variations evident but not too large on density curve. Proper response characteristics on all curves. Repeat sections agree within + .03 gm/cc. Caliper checked and recorded in casing. SIDEWALL NEUTRON OR COMPENSATED NEUTRON 56. ~ Calibrations meet logging company tolerances. 57. [---] Proper response characteristics on all curves. 58. [] Repeat sections agree within + 1.5 p.u.. 59. [~ Caliper checked and recorded in casing (if applicable). DIPMETER 60. [7-] Calibrations meet logging company tolerances. 61. [~ Proper response characteristics on all curves. 62. [~] Sonde not rotating too fast (Not more than 3 turns/100 ft.). 63. [~ Deviation and hole drift compare with drillers data. REMARKS: (Explain all items NOT checked), SERVICK COST , · .. .. .. . _ TOTAL ., Signature Logging Engineer · Note: Enter 8 I · | I$ 14 115 16 17 18 [ , ] Total time on location Iii 20 NUMBERS OF EQUIPMENT THAT FAILED ! I t I I ,I t ! I I I t i t 21 -- JOB EVALUATION (PHILLIPS REPRESENTATIVE) all numbers to right, ie Total footage I No. of logs Rua Trips in hole Total logging time (HRS) ! I J Total footage logged Delay' in arriving at location (HRS) Elapsed time, from time notified until arrival at rig (HRS) Lost time due to tool failure (HRS) 12 l0 I 010 .! Not [210 ~ 0t0~ I . . I I I I ~ ! I ! I I * ( ! I * I * I I I t I I I I ! ! (Enteras II ,R,Pi4 12 ,I IAtP,2 ,7 ,2 , I etc.) ,, I RATING OF SERVICE -- (Enter X in appropriate box) 0 Good [~]Fair ~-~Poor ·" 65 66 67 All items in SECTION II not checked were discussed with you to your satisfaction. 68 69 COMMENTS: :;~. .- Signed Date Phillips Representative HELPFUL HINTS 1. Suspect all ::k'Purious variations like: Periodic effects, noise, steps, abrupt changes, angular points, vibration, constant reading over a long interval. Verify with a repeat. 2. Check correlation with near by wells and with local markers such aa salt or anhydrite, shale and water zone values. ,· 3. Calculate water saturation in a known water zone using each porosity device. 4. If a log is suspect don't hesitate to ask for a rerun with another tool. This is probably the last chance to get the log. · PP~POS~_~MUD PROGRAM The following table shows the mud program we propose to use to drill with: Interval Weight Viscosity Filtrate · (B.O.F. ) (ppg) (Sec/Qt) (M1/30Min) 0 - 250' N/A N/A No Control Sea Water (SW) with occasional Pre-hydrated Gel (PHG) slugs to sweep hole. Spot 150 visoosity PHG in hole prior, to run- ning 3~0" & 20" casing. ' ' 250' - 1000' 8.5-9.0 ~ 40-60';' No Control i000 '-4000' 9.0-9.5. 4000' - T.D. 10.2-10'.6. 45-55 40-50 15 A low-solids non-dispersed fresh water system will be used made up as follows: 'i 1. Gel and Flosal will be used for building viscosity. 2. use Soda Ash to control calcium" ion below 500 ppm. 3. Add Barite as required for weight control. 4. Use Soltex as required to reduce torque & drag and stabilize shales and coals. 5. Use desilters/desanders and 150/200 mesh screens on shaker. Use mud cleaner as desilter. A iow-solids non-dispersed fresh water system will be used made up as follows: 1. Gel and Flosal will be used for building viscosity. 2. Add Drispac for filtrate control. Use Drispa~. 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 rheology & to convert to semi-dispersed system as dictated by mud weight required. 8. Use desilters/desanders & 150/200 mesh screens on shaker. Use mud cleaner as. desilter. Ditto 1000 ' - 4000 ' system, except: 1. Build mud weight to 10.2 before drilling 'sterling sands. 2. As mud weight requirements increase, use centrifuge ;~ o3m- bination with previously listed mechanical solids control .equipment to maintain low-solids mud. Page 1 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 situatioD.~ are discussed below: Stuck Pipe - In separate mud tank, mix anionic surface active agent' and s~ot across. ' '- '. the intorval whe. re pipe is stuck. Move "fresh" fluid mix across J. nto~al at 15/20 minute intervals. · ~" '- "~. '-' ~ . · :.'- ' · Circulation Losses - A. Partial loss - Add lost circulation materials (L~) such as hulls, cellophane, nut shells, sawdust, mica, fibers, directly into mud system and circulate by passing solids control equipment until full returns are established. B. Complete loss - In a separate mud tank, mix a volume equal to twice the probable volume of the lost circulation interval of Diaseal M, Barite, II2M and water. Spot over lost circulation interval with regular mud. Fill 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 sysbsm in 9.5 - 10.5 pH range with caustic soda'. BHT) 250© F. - Use lignites in place of lignosulfonates to disperse system. Continue to use Drispac for filtrate control in combination with Desco. Foaming- If Tight Hole - foaming becomes a problem, add aluminum stearate at .1 - .2 ppb concentration directly · to mud system. If tight hole conditions are encountered, add Torq-Trim at 0.2 - 0.4 ppb concentration directly to mud system. Page 2 ACTIVE AND RESERVE, MUD SYSTEM.. Attachment C The .following table ~indicates ~the-amounts of" liquid-mud we- expect 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. Liquid Mud Volumes Interval Active Tanks Reserve Tanks BOF barrels ' barrels ' 0 - 250' 600 300 250 - 1000' .600 600 1000 - 4000' 1000 600 4000 - T.D. 1200 600 ONBOARD MUD STOCK We propose to maintain a mud product inventory onboard the drill vessel as set forth below while drilling this exploratory well. Product Quantity Remarks Shcks .......... Regular: Gel 500 Sack storage Flosal 80 Sack storage Drispac 80 Sack storage Caustic Soda 40 Sack storage Soda Ash 80 Sack storage Soltex 300 Sack storage Desco 100 Sack storage Barite 6,000 2,100 sack & 3,900 bulk storage Lignosulfonate 0-180 Sack storage _Special: Surfactant 100 Sack Nut shells 250 Sack Myca 250 Sack Diaseal M 150 Sack Zinc Carbonate 40 Sack Lignite 0 Sack Aluminum Stearate 40 Sack Torq-Trim 5 Drum storage-use for stuck pipe only storage-use for lost circ. only storage-use for lost circ. only storage-use for lost circ. only storage-use for H2S only storage-use for high BHT only storage-use for foaming only. storage-use for tight hole only SUPPLIER MUD STOCK ONSHORE Mud supplier will maintain, at their Kenai onshore stock point, a supply of the mud products listed above in quantities sufficient to build two hole volumes. These materials will be conrnitted strictly %o this well for emergency use if required. Page 3 Attachment C Product Name Aquagel Baroid Bicarb of Soda Caus~cSoda Desco Drispac Flosal Kwik-Seal Lime Micatex Q-Broxin SEa ~h Soltex Stabilite Torq-Trim Wall-nut Zeogel Zinc Carbonate ~Description Sodium montmorillonite Barium sul~ Sodium bicarbonate Sodium hydroxide Organic thinner Aluminum Stearate Diatomac~ Earth Polyanionic ' cel lulose pc~der Magnesium Silicate Granule', flakes & fibers Calcium hydroxide powder Micaflakes Ferrochrome lignosulfonate Sodium Carbonate Sodium Asphalt Sulfonate Organic phosphate Liquid Triglycerides and alcohols Organic Material Attapulgite Clay Zinc Carbonate Page 4 Concentration 10 - 20 ppB 0 - 700 ppB .1 - 1.5 ppB .1 - 3 ppB .25 - 3 ppB .25- 1 ppB 0 - 50 ppB .1- 2 ppB 1- 4 ppB 5 - 50 ppB · 5 - 8 ppB 2 - 15 ppB 1- 4 ppB · 5 - 2 ppB 2- 6 ppB .1 - .3 ppB 0 - 90 ppB 5- 50 ppB 5-25 ppB .5 - 8 ppB Function Viscosity & Filtration control Cement Contamination pH Control Control Lost Circu- lation Viscosity & Filtration Control ViScosity Oontrol Lost Circu- lation Alk. Control & floccula- tion Seepage Rheology Control Treat calcium Shale Control Cement Contamination Lubricant for Stuck pipe Lost Circu- lation Salt Water Viscosity H2S Control Attac~t D i WFLL KICK OONTPDL PROCEDURES It is imperative that. everyone..involved with._the, drilling_ . of a_wildcat well knc~ h~ to properly control well kicks so ,there will be no un- necessary hazards to life and property. Procedures for various kick situations outlined belc~ are to be used as a .guide in controlling the well. The Kenai Office is to be consulted as soon as practical when a kick occurs." · A. Precautions for Drillinq Without B.O.P.E. The B.O.P.F_,. will not be used while drilling the hole from 0' to 250' BOF because offset well information ·indicates no shallow drill- ing 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. . 2~ 300 to 500 barrels of 10.0 to 11.0 lb/gal mud will be mixed and placed_ in readily available storage. The return of fluids at the we llhead shall be 'con%in~ous'ly monitored, if possJ]ole, while the hole is being drilled. . . Mooring of supply boats alongside the drilling vessel will be minimized during these operations. If the well begins ~o flow, the mud in storage will be pumped. down the drill string. At this s_t~a~.'all _personnel will be alerted to assume their respective stations in preparation for winching the vessel off location if a floater is used or combating the kick if a jackup is used. .. A. Following are general Procedures to follow if a floater is used: 1. Motorman in engine room ready to shut down ventilation system. 2. Roustabout to watch for gas bubbles on the down- current side of the vessel. 3. Seamen to man U.D-current anchor winches. 4. Master' of vessel ready to issue orders to winch off. 5. Phillips and Contractor supervisors will issue orders for stations and duties of other personnel. 6. If the flow at the wellhead becomes uncontrollable, than the vessel will be moved off location immediately. The vessel will be moored in such a way that prevail- ing winds will carry any flow from the well away from the living areas and the engine room. The down-current anchors will be oonnected in such a manner that there are about 600. feet of wire left on the winch. This will allow the vessel to be moved off location without' disconnecting from the mooring lines. Be ' · Attachment D P.,age B. Follawing are general ~rocedures to 'follow if a jackup is used: 1.. ~.~%orman shut down all engines and snuff all exhausts. '2. Barge' operator extinguish all flames. 3. Personnel standby to evacuate upon orders from supervisor. Kick ~4hile; briltihgl' Qi%h .~'~,. ~-P.E~'--Ins~all~ ~ ~.~ 1. During normal 'drilling operations the attached IM~O Practical' Kick Control Method will be. used. .2. Figure No. 1 Will-be posted in the doghouse with a.clear plastic · ~ cover. Data req. uired on the form will .be updated once each tour. . . O[.PTH · PUMP h;O.l~ ".t 'ODPX [3TPX __ PUMP' NO.~: ..... ¥,'EIGHT:~ ,ppg IN ~~ ppg OUT -. 3: SIZE- ,"OD -_'lO ppf 'MAXIMU)4 BURST PRESSURE- __ psi k',tN. FRACTURE GRADIENT= ppg at It CAPACITY-' =_ b2f DRILL PiPE :SIZE"" "O0_~ ppf ~___TJ CAPACITY = ___ bpf. _11 · DRILL COLLARS:SIZE= '_'OD x_ .- "ID E SIZE= " Fig. 1 Attachment D Page 3 3. Pull kelly out of rotary table upon first indication of a gain in mud i~ the working pits. e Stop mud pump(s). If annulus mud continues bo flc~ close the Hydril. Leave choke closed (the casing setting depth and casing burst rating preclude kick pressures fracturing the formation at casing shoe or bursting the casing at the surface). 0 e Immediately observe the B.O.P. stack for leakage. 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 sbeps outlined in the Practical Kick Control Work- sheet. C. Kicks While Tripping !.. Part way out of the hole: If a kick occurs whil~ .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 a backpressure valve or inside preventer.. Strip in the hole through %he Hydril. Adjust cloSing pressure on the preventer so it closes lightly around the drill pipe and allcws 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 'be ~lowered %o botbom, circulate out using the same pumping rate that 'was used i whit&~- drilling. 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 receded for handling a kick %~nile on bottom, except for the following changes: Attachment D ~ge 4 1. Substitute the circulating depth for total depth in order to determine the required mud weight. 2. ' 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. 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. ~ate 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 dc~n 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 procedure reconmended for handling a kick while on bottcm, except: 1. Substitute the circulating depth for total depth in order to determine the .required mud weight. . The shut-in standpipe pressure used %o determine the required mud weight should be the pump., pressure required to ,just open the float or inside preventer. 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. ?his 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. D. Circulating Trip 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 punt0 pressure at this normal circulation rate. . Divert the mud returns through an open choke line by closing the Hydril, or, if a rotating head is being used, by closing the outlet. Attachment D ~$e 5 4. _Maintain constant circulation rate at %he normal value established in Step 1. Se Choke the mud returns from the annulus only as required to maintain %he normal drill pipe circulating pressure. Allow at least a second _Der thousand feet of depth for casing pressure to be reflected on %he standpipe gauge. e . Maintain %his pressure control until %he hole is purged of gas slugs. The pit level may rise due %o gas expansion when a correct procedure is being follc~ed, Do not attempt to hold a oonshant pit level. Mud gains of 100 barrels or more are not uncc~mon when a lot of trip gas is present. E. The Followin_g Ap~plies Only if a Floater 'is Used to Drill the Hole. 1. ~gency Procedures .Due to Weather If weather deteriorates beyond safe operating limits during kill procedures, the following procedure should be used: A. Displace annulus with 1 1/2 volumes of kill mud. B. Cement formation, bit, and collars into %he hole, C. PrePare to shear pipe and release riser. 2. Emergency Shear-off Procedures Follow these procedures if emergency shear-off is deemed necessary: A, Close Hydril preventer. B. Pick up.. pipe to tag bottom of Hydril rubber and clear tool joints from ram area, C. Close and lock middle pipe ram, D. Slack off to suppqrt DP on middle pipe ram. E. Close bottom pipe ram, F. Close shear rams. · G. Pull remainder of drill string. Attachment D ?,.a. ge 6 DISPLAC~CSbrf VOLUMFS & COLLAPSE RATING of DRILL PIPE Displacement API Collapse Size (Inches) Weight Running Dry Rating Grade E Nominal #/Foot Bbls/90 ' Star~ (psi) * 3.5 13.3 1.09 14 , 110 4.5 16.6 1, 80 10,390 5.0 19.5 2.19 10,000 *Collapse values are minimum with no safe~i factor CAPACITY OF DRILL PIPE & DRILL COT,TAPS Drill.- Pipe Drill'Collars Size (Inches) Weight Capacity Size (Inches) Weigh% NOminal #/Foot gals/foot OD x ID 3.5 13..3 ,313 4%3/4 x 2 4.5 16.6 .597 6 1/2 x 2 3/4 49 ..6 89.1 5.0 19.5 .747 8 x 3 147 Capacity gals/foot .162 .309 .366 5.0 50.0 .366 9 x 3 191.9 .366 '~~ WELL I1~ ,~.111/1~$ LOCATION ....... CIRCULATION NO. I 2 3 , PRACTICAL KICK CONTROL _ _ A B C D , I ",~c0',~ 1-~1,, ..... 1-~!~'~1 -~I:L____J -,.i:~ "_- __] TIME OF DAY SHUT-IN DRILL SHUT-IN CASING MAXIMUM ALLOWABLE PIPE PRESSURE (psi) PRESSURE (psi) CASING PRESSURE (psi) ~L,~co,ol-~i''~ -I--E__.2~.I~--]~1~° ! MUD WEIGHT (ppg) PIT GAIN (bbl) REDUCED REDUCED PUMP PRESSURE (psi) PUMP RATE (spT) ~1 ,~Co,~ -~1~, I-~i~ ~-___ ii.,IL_.~.~i~°~_ .'~| KILL PUMP NUMBER PUMP DISPLACEMENT DEPTH (ft) TRUE VERTICAL (bps) DEPTH (ft) ~l.,~co,°~i-,l~. I~1'~" .1-*~-~~ CASING OPEN-HOLE DRILL PIPE ANNULAR DEPTH (fl) LENGTH (fl) CAPACITY (bp f) CAPACITY (bpf) ~1~'~'~1--I 2o1~!'~ ..... .... 1,17 !=i~° '1 SHUT-IN DRILL TRUE VERTICAL MUD WEIGHT PIPE PRESSURE DEPTH INCREASE c~'C~~"' i~°i+P ~1... 1-~. ! ....... ( ...... ../ MUD WEIGHT MUD WEIGHT - KILL MUD WEIGHT INCREASE ~lc~'~l-~i'c l-xi~c . I," ~= P l DRILL PIPE DEPTH PUMP DISPLACEMENT SURFACE-TO-BIT CAPACITY STROKES olcx~c~,~l-, lxP I+13E~'I=- ~.. I ANNULAR DEPTH PUMP DISPLACEMENT BOTTOMS-UP CAPACITY STROKES , Ic~,'-'c~~l.~i~ i~1~I+i~I=P 1 ANNULAR" OPEN-HOLE'LENGTH PUMP I:JlSPLACEMENT OPEN-HOLE CAPACITY STROKES ,olc,,.~..,,.~i+ i~o . I+P' 1=i'oo 1 SURFACE-TO-BIT BOTTOM'S-UP TOTAL STROKES STROKES STROKES COPYRIGHT © 1978 by IMCO SERVICES, A Division of HALLIBURTON Company All Rights Reser'ved. L " "'I':~::::'~' ' NEW MUD ' .J_, '. ? i'2'': . SE ECT =l~ ', 121 CALCULATE! -~ 131CALCU LATE1 '"~ i1~ °,,i 14 /WEIGHT uH"~ 'RECORD + ~"IJI(IF .ECESSAR¥)i . - - . NEW MUD WEIGHT I',... I_+_l.c~ I=i""~" SHUT-IN DRILL REDUCED INITIAL STANDPIPE PIPE PRESSURE PUMP PRESSURE PRESSIIRE NEW MUD WEIGHT .... OLD MUD WEIGHT . '"' MUD WEIGHT : DIFFERENCE 8 ~o :: .... AT INITIAL STANDPIPE ~ PRESSURE - 1 REDUCED NEW REDUCED~ PUMP PRESSURE PUMP PRESSURE i-"" I-I~° -i~°I KILL MUD WEIGHT NEW MUD WEIGHT MUD WEIGHT- , DIFFERENCE I~1'° !+1 '",2o I=L::L__J TRUF. VEI~TICAL PRESSURE DEPTH ADJUSTMENT 1:+!''0 '~:1"-- 1 PRESSURE NEW REDUCED FINAL STANDPIPE ADJUSTMENT PUMP PRESSURE PRESSURE 2500 _ __ i iii · i .-.~, I _ i ir · -- sTANDPIPE PRE~S!jRE SCHEDULE · .' , I ~ , uJ 1500 n' n. LU 1000 Z 500 ~ 0 STROKES FINAL STANDPIPE SURFACE-TO-BIT PRESSURE STROKES ~ol'co..~o. I~l"'~o~,.~Ws° ~"i 21 0 500 1000 1500 2000 2500 PUMP STROKES TOTAL STROKES MUD WEIGHT DIFFERENCE MAY BE NEGATIVE. IF IT IS, PRESSURE ADJUSTMENT WILL ALSO BE NEGATIVE. 100 STROKE INTERVALS STROKES --' ' 100 STROKES - 200 STROKES 300 STROKES 4O0 STROKES - 500 STROKES__ 600 sTRoKES 700 S~rROKES 800 STROKES 900 STROKES 1000 STROKES 1100 STROKES 1200 STROKES 1300 STROKES 1400 STROKES 1500 STROKES 1600 STROKES - 1700 STROKES 1800 STROKES 1900 STROKES ' 23 IClRCULATING| I REDUCED PUMP RATE KILL PUMP NUMBER 24 ADJUST TO MATCH .4~1 PRESSURE CHOKE , ~[ SCHEDULE AFTER YOU STANDPIPE 16D ~ KEEP PRESSURE AT · . CONSTANT - SURFACE-TO-BIT FINAL STANDPIPE STROKES PRESSURE I°°"°'1 i~°" 1 ! I I ..... i 1 26 EXCEED ==~ =~ UNTIL KICK OR' YOU HAVE 1 OD ABOVE SHOE PUMPED .... ,==~ MAXlMLIJVl ALLOWABLE OPEN-HOLE CASING PRESSURE STROKES ~lo,.o.,~..;;i~to. Io.I ...,o~u~,C."l..ol,,o !~1' =~.~c~.:.s I TOTAL STROKES NEW MUD WEIGHT IMCO ~945 I :1' 1 i I ..... ' ~' ' 1~STOP,. c~os~, '¥ AND w.~. You., :;.:~.,~.. ,~ . ;~.. su.F~cE ! ~'' "1;?~' "uM"~' c.o~ ~ DETECT .' ' ' ~- .......... NEW MUD WEIG~ ........... ~ "" ...... " ' " SHUT-IN CASING MAXIMUM ALLOWABLE PIPE PRESSURE PRESSURE CASING PRESSURE - _ REDUCED REDUCED PUMP PRESSURE '-' PUMP RATE TIME OF DAY RECORD . _ 13~'B ' ' MUD WEIGHT PIT GAIN 31 1 IF PRESSURES I AREI ZERO I..~/ WELL NOT ZERO_ ~i ClRCULATIO~!ii' IS REQUIRED THE NUMBER U~LC!RCULAT,ON1 'N I THE HE^D,NG OFt WORKSHEET ii _ : LIN'~s ':' "' 1 AND2 WORKSHEET NEWVALUES I NECESSARY I NOTI CE:THE INFORMATION AND DATA CONTAINEO HEREIN AND ALL INTERFRETATIONS AND/OR RECOMMENDATIONS MADE IN CONNECTION THEREWITH, WHETHER PRESENTED ORALLY ,:NA W~I'r'TEN HEREIN Off. ELSEWHERE. HAVE BEEN CAREFULLY PREPAREO AND CON- SIDERED, ANY MAY BE U~ED IF THE U~ER $0 ELECTS. HOWE~zE~Io NO GUARANTEES OF ANY KINO ARE MADE OR INTENDED. AND ANY USER THEREOF AGREES THAT IMCO SERVICES SHALL NOT BE LIABLE FOR ANY DAMAGES, LOS~, COSTS OR EXPENSES RESULTING FROM THE U~E OF SAME EXCEPT WHEREDUE TO THE GROSS NEGLIGENCE OR WILLFUL MISCONOUCT OF IMCO SERVICES OR I'1~ AGENTS. IN THE PREPARATION OR FURNISHING OF ,SAME, HOLE "FILL-UP" PROCEDURE Attachment E Page 1 The follcwing procedure should be follc~ed to insure the accurate measure- n~nt of the fluid volume-required~_t~i-"fill up_" while ~.tripping~ The driller on tour is ~o 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 %oral fill UP for amount of mud to be used. 2. After slug has been pumped, .pull 5 stands, observing fl~uid level in hole for swabbing. Shod 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. ._~ae 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 oorrect amount of fluid, go back to bottom and circulate bottoms up. Be If rig does not have trip ta~k, -fill. up procedure is: 1. Before trip, circulate bottoms up and calculate total fill up for amount of mud to be~sed.. 2. After slug has been pumped, open slug valves on slug hank, and pits so that mud level will equalize into slug hank, No. 1 suc- tion tank, and No. 2 suction hank. 3. Drain "Possum Belly" (hank 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 ~ .equired, allow 2 or 3 extra strokes, stop pump and record number of strokes. Measure inches of fluid pun~ out of the 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. . Attachment E page 2 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/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, go · .... '.~ ~'-~ back to bottom and circulate bottoms up.. When a 100%.wet or partially wet string is pulled, use a mud saver and route returns to drilling nipple (NOT~ flc~ line). Hole fill up required will be same for we% or dry string by following this pro- 'cedure o Fill up line is to be installed only in drilling nipple below flow line takeoff. Date: T~e: Depth: S~3~d ' 'No. of'i' Fill-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 10 40 _ _ · j ....................... 11 41 12 42 ........ -.. . . 13. 43 ................. 14 44 ................... 15 45 ........ -- ...... , · 16 .46 ............ 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 3O 60 ............. __ -- _ . . -- ..-- JJ3$T CIIC[IATJON ?ROCFDURE Attachment F Page 1 D]7%$EALM is beret added to the drilling mud nor is it sll~r~ed as a · pill in drill.lng mod. It is always mixed with fresh, salty, or salt saturated water. It is always pumped as a separate pill but is preceded au~] follc~ed by drilling mod. The amount to be used varies from 25 to 200 barrels depending upon the awount of open hole ~]d experience in the area. Sca'ne operators ~se twice the open bole-voltme as a guide-. Conventional lost circu]ation maher~al such as nuthulls or fibers be added %o %he slurry. Successful jobs have ~en done with ~]d without the addition of these conventional lost c~x~u]ation materJ, als. Ten .lb/ bbl of fJJDrous material such as Baroid's Fi~ertex (Magcobar's Magco-FJber)' or tm~nLly ]b/bbl of. ~dium nut hulls such as Baroid's Wall Nut (Magco- bar's Tuf-Plug) are recormv~nded. T~e general procedure for using DIASEAL M When circulation is lost is as fol lc~qs: · 1. Pull_off bottcm or just above the loss ~zone, put the kelly .back on and continue to work the pipe. 2. Mix the slurry as conditions dictate. If pill is %0 be mixed in suction pit, run necessary amount of water into pit with guns on pit. As water fills suction pit, ~gJ~ opening sacks of DffASEAL M ~1 mix contents with water by ma~ agitation from guns. As slurry b~.comes viscous, begin addition of lost circulation ~terial. If DIASFAL M slurry is already mi×ed and being held in readiness in standby pit, agitate vigorouslY, add lost circulation material 'if it bas not already been added. Slurry is ready for use v~]en ughly mixed and agiLated'; % 3. When mixing ~s. co. nplete, pump the mixture in the bole and displace the slurry from the pipe with md ........ 4. Pull up above %be casing shoe and fill bbe hole with mod ~-]nrou~h the fi 11-up line. 5. If the hole does not fill with one foot of mod out of pits, mix another pit of DIASEAL M slurry, and repeat procedure. 6. If the hole does fill, proceed as foll~qs: . a. For depths less than 7000 feet, close the pipe rams, punp slc~,!y 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 w~en a squeeze pressure cannot be- established, wait two ho~s; %hen if the hole will stand full, go to bottom and drill. Attachment F Page 2 DIASEAL M slurries can be put in place through tt, e bit nozzles. In the Texas Panh~le, mud losses have been sealed by pulling off botEc~, put, tying dc~.~n a premixed DI3%$EAL M .slurry Qf 25 to 50 barrels foll~ed _by hud. This. restores circulation and drilling is oontinued. Exact procedua-es and safet~y m~_asures must be- dictated by hole co~iLions. In a st~cky, ~stable ho]e, t:]~ bit would be pulled to the boLLcrn of tile last casing string. In normal holes, the bit would be pulled several stands off bottom as it would in tfl0e case of short ~-ig repairs. Chances. for success are greatest ,risen the bit is placed c].osesL to, but ~vove, the point of lost circulation. · · D iASi AL. M* L'OS¥ '- Attachment F Page '3 DIASEAL M o Paltern Fo~ A Success[ul Squeeze This report concerns test resulls on lhe use of Diaseal M high waler loss slurries in the Gulf Coast area· in lhe past year over 100 Diaseal M squeeze- lobs ,,,.,ere run to combat losl circulation in the Gulf Coast area· The results indicale it is possible to bblain a successful squeeze job every lime if the proper procedure is followed. . "The following analysis of 36 representative tesls clearly shows the importance of starting a squeeze job with an adequa[e 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 thal of open hole 8 8 At leasl double that · of open hole. ,, · As can ~be seen from the foregoing a successful squeeze can be virtually assured by using a slurry volume at least twice lhat of lhe open hole to be squeezed, or a rn[nZmum o! ~00 bbl. Under these conditions lhe fo/lowing procedure should be ollowed: '. 1. Mix slurry according lo Table, adding Oiaseal M, battle and losl circulalion malerial in order. This mixlure ofinerl malerials has lhe highesl possible waterloss of any known welghled losl. circulalion slurry of which we know. in 'any kind of water. A FORMULA FOR PREPARING ONE BARREL DIASEAL M WEIGHTED SLURRY WITH FRESH WATER, BAY OR SEAWATER .. Density DIASEAL M Barite' Wale 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 .68 2.9 .70 15 31 .62 - · 3.5 .67 16 28 .56 4.0 17 25 .50 4,6 ". .60_ 18 22 .44 5.2 .SG i9 1'7 .34" 5.8 .52 EXAMPLE 100 bbl. of 14 lb./gal. DIASEAL M slurry require., sac~s DIASEAL M, 290 sacks b~rite. 70 bbl. and nut shells if desired. {25 lb./bbl, of nut shells can be useJ in the ab Iormulalions without change. If waler absorbing 1 circulation malerials are added, the slurry vlsco will increase. This slurry is effective without cony Iional lost circulation materials.) '11 saluraled salt water is used, barile must decreesed 0.6 sack per barrel. Attachment F Pa~e 4 _,Place bol~om gl drill pipe far enough inlo caslr, g )o dlsplace all o! slurry ~n.lo open hole and bollorn gl casing. Oo nol squeeze lh~ough b]! openings less lhan 5/8" d]ameler v,,ilh losl malerhl in slurry. Squeezing open ended is desirable. - ' 3. Pick up slurry with pump lrud< and displace il gu! o! drill plpe v.,iih mud. ]tall of slurry will be in open hole, and equ'al amouin~ v,,ill be in casing belo~ _ d~ill p~pe. When slurry slads oul o! drill pipe~ blowoul prevenlers should be dosed. K4ake sure annulus is full. i! [q-r-rS 1ool ~s used, il should be keL--Th~s pmvenls-miorat.k)n=-When-slurry hils ~pe.n ho. le, slow pump down to 1/2 Io 374 bbl.]m~n. · 4. Afler drill pipe is cleared, slage slurry i'nlo formation, a few b~rrels at a lime. pumping al a tale o! lY4 bbl./mln., hesil~Iing;for several_. minules. Conlinue" lhis Cycle unlil pressure begins 1o build. Expecl inillal pressu,e build-ups ;~nd bleedolls. A final holdlng p~ essure gl 300-900 psi is desirable. 5. 14old pressure for lwo hou,s before releasing and resumlng operalions. 6. Ream gu! cakein open hole. Excess slurry' willno! conl,a, mlnate fnud system, nbr ~.~iil i! plug hole permanenlly like cement or malerials thai teacl chemically. As mud is drculaled past porous zones, lhe highly per~neable Oia:,eal M cake is covered by a mud cake of low permeabilily. This is lhe "icing on lhe cake", lhe final seal oft I! the above procedure is'foll~wed with no devlalion, and enough slurry volume is used, the Diaseal M squeeze can be expecled ~o be vidu.ally 100% successful. ' DRILLING SPECI'ALTIES COI'VIPANY This bullelin tepods accu,ale and ,eliable inlo~mallon Io lhe besl o! our ~,nowl. edge. grilling Spec;allies Company ~ssurr, es no obllgalion or li~bilit7 for lhe use of lhe in!ormal;on p,eseqled here~n. o Attachment G A. 30 INCH STR~ 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 mixedwith 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 Density - 1.15 cu. ft. slurry per sack - 15.8 lbs. per gal. C. .13 3/8 INCH SURFACE STRING - 1000' BOF % The 13 3/8 inch string willbe 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. Slurryvolume 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 Density - 1.15 cu. ft. slurry per sack - 15.8 lbs. per gal. Page 1 Attachment G 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' Kenai office will furnish the cementing program and procedure prior to reaching casing point. A tail or main slurry, depending on whether or not zonal cover- age is required, consisting of 400 sx of Class "G" cement mixedwith fresh water will be puntoedt~-obtain at least 1,000,~ ofcoverage 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. Additives. will be added to each slurry to obtain adequate pump- ability time. The amo~mnt of additives will be determined by lab tests prior to cementing using actual conditions. E. 7 INCH PRODUCTION CASING - T.D. The 7 inch casing will be cemented with Class "G" cement mixed with a friction reduCer, retarder and freshwater. The volume will be determined by caliper survey in open hole and adequate to place a. minimum of 50_ 0' .above any h~dro-carbon bearing~__Z_o__ne. A two stage job will probably be required to do this,-~nless we elect to use an ultra-light weight slUrry, e.g. 10.75 ppg. Cement properties will be as follows: Yield Density - 1.18 cu.~ ft. per sack - 15.6 lbs. per gal. of slurry Phillips' Kenai office will furnish'the cementing program and pro- cedure prior to reaching casing point. 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 willbe 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. Page 2 ae S. DRILLST~4 TESTING PBOCED~ Attachment H Page 1 PREPARATION 1. Notify Alaska Oil and Gas Oonservation Gonmission at least 48 hours prior to testing. 2. All anti-pollution equipment should be checked %o make sure it is operational. 3. All safety equiPment on vessel should be checked and repaired as required; i.e. H2S gas masks, resUSci%ors, 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. P~RFORATING THE WEI.L 1. Hole will be filled wifh an overbalanced fluid. The fluid in the hole will be at least the equivalent circulating density (~CD) of the mud which safely drilled tes~ zone. 2. Prior to arming guns, .the rig radio operator will notify the supply vessel, ~nd switch-off all rig transmitters. It will be acceptable %o monitor marine VKF; however, all transmission of · field radio 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 c~n be returned %o normal service when perforating gun is 500 feet belc~ ocean floor. 0 7~ Attachment H page 2 During perforating operations the driller or driller's assistant will observe hole for possible flc~ back. Perforate specified zone. O00H with spent gun. All electrical equipment and radio equipment (except emergency) will be switched off before spent gun is pulled through BOP's. Once gun is on the ca%walk and disarmed, the electrical equipment and radios can be returned to normal service. Co TESTING THE WELL 1. A pretest meeting on board the rig will be conducted by Phillips Test Engineer. All Supervisory personnel of the drilling con- tractor and invOlved se~ice companies are %o 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. All anti-pollution equipment will be checked again. % 4. The radio operator will notify helicopter and supply boat to the fact flaring~urning 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 equi~E~_nt will be arranged as shown in Attachment "I" and tested as follc~s: Se 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. All surface lines downstream of chokes to separator and/or~ heater are to be tested %o the working pressure of the separator. 0 . 9, 10. Attachment H ~ge 3 d. The heater and separator will be filled with water and tested to 1/2 their working pressure. If ~eil drilled with floater, the subsea test tree Will be used and function-tes~d in the rotary t~ble. Disconnection of the tree will-als0 be checked prior to running in the hole. If a floater is used, the DST assembly to be used is shown in Attachment I-1. If a jackup is used, the DST assembly to ~e used is shc~n in Attachment I-2. Drillpipe will be used for testing. The drillpipe will be used in the event jarring is required to unseat packer. ~ Note: The Phillips Engineer, after consultation with the Phillips Drilling Supervisor and the senior Contract Toolpusher on board, will make the final decision on any procedural or kclui~t changes in the test program. Consultation on sensitive safety matters are to be the decision of the .Phillips Drilling Superintendent and/or District Superin- tendent on shore. Prior tO utilizing drill pipe as a test string, the cleaning, inspection and lubrication procedure will be follow, ed:· a. Clean drill pipe threads preferably by steam cleaning. b. Inspect shoulders for cuts and repair if necessa~t. c. Thoroughly dope connections using a high quality t~ead lubricant. d. In order to minimize time, the test should be anticipated two trips prior to OOOH to test, in order for each connection to be broken, inspected, and doped prior .to DST. 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 dc~nahole test valve. Subsequent tests can be conducted Utilizing either exterp~l connection tests (Gatorhawk) or internal tests. Attachment H Page 4 12. 13. Run test string as sh(~n in Attachment I-1 or 2, as appropriate, and set packer 50-80' above perforations. · If testing from a floater, space setting depth such that the subsea tree hanger is 5' above index pad. ThiS--will allow for a 5' expansion at the slip joint in the test string after the tree is landed, into wellhead. Lower subsea tree, land in well- head, and close pipe ra~s above kill line on slick joint. If testing frc~ a jackup, space out to have surface test tree near drill floor. 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 Bl~gineer and Drilling Super- visor. %~ne basic flc~ing and shut in procedUre for testing will be conduct~ 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 max~ 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 aG 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 h~urs. Shut in at surface. Attachment H Page 5 14. 15. k. Flc~ at ra~ .in Step C for 6 hours, 1. 'Shut in for 9 hours. Shut in at surface. During. DST's the rig floor,- moon pool, shale shaker house and mud rocm will be checked for hydrocarbon~ fum~g'-using' '-a hand held gas sniffer% If rig equipped with gas alarms, everyone should be advised of the alarm procedure. AIL ALARM SYSTEMS ARE TO BE TFSTED prior bo con~nencing the DST. ' Throughout test period, a testing service opera- tor will be stationed on the rig floor. The sub- sea test tree operator will stand by console dur- ing the shut in period. Specific flc~ rates, times, and surface data points will be given for each zone. Upon completion of testing sequence, test fluids will be reversed out through the test choke manifold~ '. .~ Pulling test string is to be done slc~ly to prevent swabbing of the perforations. The'test string will .be retrieved as follows: a. ' Prior to releasing packer, fill up drilling hippie and b. Release packer while observing hole. c. Fill up drill nipple and record ~e amount of fillup; check for flow. If a jackup is used, go to Step f. d. Pull landing string, fill up hole. e. Pull to subsea test tree, fill up hole, record. Check for flow - rig down or s tandback SSTT. f, Pull slowly out of hole, Fill hole every 5 stands bo top of the d~ill collars.. De Attachment H Pa. ge 6 g. Pull one stand of DC. Fillup - check for flow. Repeat this for each stand of DC's. h. Lay down test tools and recover gauges. TOOL REPAIR AND MAINTenANCE !- 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 thiMd: 2. .TWo,.test tools will~ be 'used ~alternately.~ The '.test 'tool that 'is.-Out Of hole shall be, sergiced. e . Se e . '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 se~iced after each DST. The test packer shall be field serviced after each DST. The reverse circulating valves Shall be field ~serviced after each DST. The SSTT shall be field serviced and function tested through the console after each DST. '. 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. SURFACE TESTIN~ Surface testing equipm.ent.,will be arranged as follows: Attaclm~mqt I Page 1 o .. ~ILL Lit,; . .. S1 [ Al4 I:,;L ET SURFACE 1ES1 1REE SURFACE SA; ElY I/.At,'UAL CHOKE ADJUSI/.BLE CHOKE. SI[A)40Ul! EI 1EST FL~,~ RE OATA ADJUSIABLE CHOKE 'l E ST LAB UNIT PRODUC1 ION D OIL GAS O S1 EX)4 WAIER O AIR S[P^RA1 OR PU)4P OIL !4El IR RIG A RIG ~'/A1 L g PU)41 R!ae equipment will include as r .equired*: 1.5 .MM BTU/hr. Indirect gas fired heater, 5000 psi W.P. ~ · 3-phase Horizontal Separa~°r 1440 WP, 80 ~SCF/day and 10,000 BOPD Capacity Centrifugal transfer pumps, 10,000 BPD capacity with explosion-proof motor. · CB'12; BurnerS-dapable 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 mJnifold w/an adjusts]pie choke and a positive choke, 5,000 psi W.P. *Substitutions, deletions or additions will be made based on drilling experience. Surface Test Tree · Control & Reel (L.V). FLm ,R D.S.T. BQUI PM~IXFF ,. _ . ®. Diver%e~ ; Mud Flow Line Attachment I-1 page 1 Flow LS~ae to Test Manifold <_ Co'nitS1 & Reel Running StrSmg Ri~er , ica%or Valve (optional) Armu 1 a.r Preventer Annular Preventer - .. . Pipe Rams - .. . Shear/Blind Rams Pipe Ram Wellhead 1 ~-4- Subsea Test Tree I '' 23 <,~ Choke Line Fluted Hanger, FIDATF~ D.S.T.-~QUIP~ (D.S.T. ASSF/V~L~) Attachment I-! ,Page 2 25,000 lbs (min. D.P. or Drl. Collars) Bar Drop or Pump Out Circ. Sub 1-Stand D.P. or Drl. Collars Circ. Sub (Pump_ out 1000 psi above Test Valve) .< 1 Stand D.P. (if sand' is an[icipateh).. Test Valve (A~mlus Conlr°lled) Jars RTTS Circ. Sub Test%Packer (Automatic "J" and Safety Joint) ........... Perforated Anchor- Big Hole (2 sections < Sperry Sun Hanger Sub (only if surface record53}g is used) · q- .... Sperry Sun Case (only if' surface recording is used) < ..... BT Case (blanked off) < Te.~,l~erature Case (b]anXed ( q-=--BAR DROP SUB J ' ' '--~f~--FLO TEE ,, I "-- ' DRILL PIPE'.'. .. ~~gP~ESSU~E ~ALVE --~EVE~SE CIRCULATION PORIS -- . ..... . . ~-qtYDnOSPRI)IG TESIER o ~J~BY- PASS PORTS ~~T P~[SS RE RECORDER J (~'P IYPE) :~--IAYDRAUL lC JA~ ~~VR SAFETY JOINT I DY-PASS PORTS · ~.~--ANCHOR PiP[ SAFETY ~OINT ~ ~ ~'~~ ~ ~ .... FLUSH JOiNTANCHOR ~ ;~--HI 500 l[UP[~AlURE J ~---B. T. P,,t[ SSURE RE CORDER t.~ (BLAhKED OFF} o-O JACKUP DST TOOL HOOK-UP Attachment I-2 Page 1 BOPE- - DESCRIPTION, OPERATING PROCEDURFS, Sf]iSMATIC DIAGRAM Attachment J Page 1 ae DESCRIPTION 1. The following list describes the BOPE planned for utilization during the drilling of this explorahory well from a floater. · BOP SECTION - BORE- DFPENDS ON RIG - ONE WRY.T, HEAD CONNi~L~iOR HYDRAULIC, 5,000 psi WP or BETTER · - FOUR RAM PREVEA~fF~S, (3 PIPE, ]. BLIND/SHEAR) - ONE _ANNIU3kR PREVENTER, 5,000 # WP - ONE FAILSAFE KILL VALVE, 2" ~[NIMUM, 5,000 # WP or BETI~R · -- ONE F~tLSAFE CHOKE VALVE, 2" MINLMI~.~4, 5,000 # WP or BEi~I~R ! ~ RISER PACKA~ SECTION - ONE RISER. CONNFLTOR, HYDRALV~,IC, 5,000 ~ WP or BETTFR - ONE ANNULAR PREVENTE~R, 5,000 # K~P (358.6 K~/SQ CM) - ONE BALL JOINT - ONE RISER ADAPTER WITH CONNECTOR PIN FOR I~qKNOWN SIZE OD RISER SYSTEM - ONE KILL LINE, 2" MINIMI~.,FLF~IBLE .lOOP, 5,000 # ~,.IP or BETTER - ONE CHOKE LINE, 3" MINIMUM, FLF~IBLE LOOP, 5,000 # WP or BETTER RISER SYSTEM , - OD AND WALT, THICt<ATESS PRES~Y .UNKNO~qN W~THk · . , KILL AI~D CHOKE LINES Ak~D HEAVY DUTY 'RISER CO!_~ECTORS. - SLIP jOINT, WITH SUFFICIENT STROKE FOR TIDAL PJLNGE .~ - ONE EXTRA BALL JOINT FOR USE BEL~ SLIP JOINT IF ~EDED. Attachment J Page 2 OONTROL SYSTEM CONTROT,LED FROM: DRIT,T,ER' S ODNSOLE ' (EL~TRIC) RSM(IfE CONSOLE (~,FC~RIC) HYDRAULIC MANIFOLD 100% REDUNDANCY (2 PODS, 2 HOSE REFiS) CONTROLS FOLLOWING FUNCTIONS: WF,,T .T ,~ CONNECTOR FOUR RAMS ANNULAR PRESSORE REGULAR ~~ ~v~ CHOKE VALv~ nM VALV~ RAM LOCKING MACHANISMS POD LATCHES BALL JOINT Rk-~~R RISER CONNECTOR Attachment J P..a~e 3 e The following list describes the BOPE planned for utilization d,mring the drilling of this exploratory well from a ja~kup. BOP S~CTION - BORE 13 5/8" MINIMUM - TWO RkM PREVENTERS (1 PIPE AND 1 BLIND) 5,000# WP or BETTER - ONE ANNULAR PREVENTER, 5,000# WP - DRILLING SPOOL W/2 - 2" or LARGER SIDE O~, 5,0009 WP - DOUBLE VALVING ON CHOKE AND .KILL LINES, 5,000# WP CONTROL SYST~4 HYDRAULIC RIG FLOOR CONTROL STATION RENDTE CONTROL STATION Attachment J 4 B. BOPE OPERATING PROCEDURES & SC~5F~TIC DIAGRAMS l. ~ne BOPE stack will be installed after the 20" casing installation and cementing. BOPE will be in place for the remainder of the pro- gram. Drawing No. 1 illustrates BOPE arrangement if a floater is used to drill well.- Drawing No. 2 illustrates BOPE arrangement if a jackup is used to drill well. '~ o All 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 accon~odate. · 3. Ail BOPE will be equip~ped with: Se A hydraulic actuating system that provides sufficient accumulator capacity to close all blowout prevention equipment units with a 50 percent operating fluid re- serve at 200 psi above the required precharge pressure when all BOP's are closed w/primary pc~er 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 station and one remote away from rig floor. 4. The kill and choke lines on a subsea BOP will have a fail safe valve located next to the BOP stack. Se The kill lines and chokes on either surface or subsea BOP will have at least two oontrol valves. 6. The choke manifold for floater and jackup will be ins%ailed as shc~n on Drawings No. 1 & 2 respectively. 0 . All 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. A top kelly_cock will be installed below the swivel, and another' will be ins%ailed at the bottom of the kelly and so designed that it can be run through blowout preventers. 9. A back-pressnre valve shall be used in the drill string while drill- ing into potentially over-pressured zones. Attachment J Page 5 B, BOPE 10. 11. OPERATING PROCEDURES & SCHEMATIC DIA~AMS, Cont'd. An inside blowout preventer and a full opening drill string safety valve in ~he open positionwillbe on the rig floor at all tim~S while drilling operations are being conducted. Valves will be on %he rig floor to fit all pipe that is in the drill string. A safe~¥ valve willbe available on the rig floor to fit the casing string as it is being run in the hole. 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 (20") 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 equipn~nt to monitor the dril]'ing mud returns. e. Hydrogen Sulfide sensing equipment capable of sensing a minimum of 5 ppm of H2S in air to monitor the drill- ing mud returns. This~ equipment shall include a war~- ing device. ~Alt BQ~ andasso~iatede~uiDment will be installed, tested and operatgd in accordance with AlaskaOll and C~s Conservation ~ion Regulation 20 AAC. 25.035. Attadm~ant J-1 Page 1 I Choke . . Mani fol~l -- .... ~ . · ... · i ' · · o - ..... Howc6 ,"' · - ~ - . Line - iCellar -- Deck Valves Subsea BOP Stack · I · : . . I. Test System : : · · a~d ..... -~. '. ' ,,' ' ' - · _ i ...... · '-""' _ ! S?~ · · ......... Stazdpipe · · ,, ,, o . ._. Kill Line : Test SysteJ. Flare I ; . No. 3 ] Rams Shear Choke Line ., . Drawing No. '1 B.O.P.E. Arrangement t I I I . . ','ErCO /6-$/4' /0,000 MSP. tYPE "T' 56-5 CASING HANGE&' ~4$SEMSLY 80.1115F4 ® 16-3/4"/C~000 &(E P. $G-5 HOUSING FF/L E~ T- HA /it© /:; UNNING THREAD--- ASSEMBLY NO. IIIBOF VETCO 16-$/4" x 9-5/8°-----~ SG-5 CASING HANGEf~ $O"~US/NG W/LEFT HAND RUNNING ASSEMBLY NO. 11068~ ' ,, ( ~U/DE '/G I M B,~ L ;U/DE 150246 ~s~-' :.'~Y NO II~¢~ Attachment Page 2 TYPICAL SUBS~WELLHEAD for FLOATING~G 6-3/8"MIN. 16-$/4"x F" I0,000 /VlSP T~'PE 'T' SG-5 CASING HANGER ASSEMB£ Y NO. 1115~9 ORIENTATION KEF 45' OUT OF PHASE 16 - 3/4 'x 13 -3/8 # 10,00(2 /14SP. TYPE 'T' SG-5 C.4SING H,~NGER ASSEMBLY NO. 1115~Y © © J-1 FOR MOUNTING T ~. GUID~ Ft~AME © © OPTIONAL EQUIPMENT FILL--UP LINE CONNECTION DOUBLE PREVENTER OPTION BLIND RAMS PIPE RAMS KILL BLIND RAMS, EMERGENCY. KiLL LINE PiPE RAMS · CHOKE OPTION CHOKE OPTION I I I 1 O ION ! ii OR MAY BE SUBSTITUTED CHOKE OPTION IIAl! MAY BE 1 I ! I I SUBSTITUTED CHOKE OPTION NOTES: I. ..® ® ® ® ® ® ® ® ® © @ @ @ 5000 SERo 1500 HYDRIL GK SER. 1500 RAM--TYPE BOP 3II SER. 1500 VALVE SER. !500 DRILLING SPOOL 3II SER. 1500iX 2II SER. 1500 STEEL TEE 2I1 SER. 1500 VALVE 2II MUD PRESSURE GAUGE 3I1 SER. 1500~X 2~1 SER. 1500 STEEL CROSS ~ 2tI SER 1 500 ADJ. CHOKE 2Ii SER. 1500 ADJ. CHOKE ON 2~ SER. 1500 RISER VALVE ON SIDE OUTLET OF 2~l SER, 1500 STEEL TEE ADAPTER e 2II SER. 1500 X 3 ~/ 16~ 10,000 LB WP~R O~ER F~NGE MATIN~ INLET ~ 10 ,000 LB WP REMOTE CHOKE HYDRAULIC CHOKE. 2500 LB WP OR BE~ER 3~l SER. 1500'CHECK VALVE PSI 'WP OR BETTER CLAMP HUBS MAY BE SUBSTITUTED FOR FLANGES ONE ADJUSTABLE CHOKE MAY BE REPLACED WITH A POSITIVE CHOKE VALVES MAY BE EITHER HAND OR POWER OPERATED BUT~ IF POWER OPERATED. THE VALVES FLANGED TO THE BOP RUN MUST BE CAPABLE OF BEING OPENED AND CLOSED MANUALLY OR CLOSE ON POWER FAILURE AND BE CAPABLE OF BEING OPENED MANUALLY PHILLIPS PETROLEUM COMPANY 5000 PSI WORKING PRESSURE. BLOWOUT PREVENTER HOOK-UP (SERIES 1500 FLANGES OR BETTER) FIGURE NO. 5 o, Attachment J-2 Page 2 "TYPICAL SURFACE for · · . / · . .- ~ . ' · .43,44 . . == ~ 10~ 15 . . ~ F~R. PHILLI S PETROLEUM CO. ',. , 7'OD. CASING. .... , , , ...... ~.*w. *No ..~z~Tz~ .Y GRAY TOOL COMPANY HOU~ON. ' ...... I~,0Oo TEST"GRAY WELL'"HEAD EQUIPMENT .... 20XI3~"xg~7" O.D. ASSEMBLY .......... . .............. FOR U~E WITHIN YOUR COM- PANY VF~ R~FERENCE TO A D DN. BY '~,~ -- _ c~ BY/,~ DRAWING NO. PROPOSALs SUBMI~ED. BY S E U~. ~ "AY BE COPIED OR ....... APP..~ E-ISBgI- DUPLICATED FOR SUCH USE. C F DATE 10-30-7~ ........... M IO04 Attachment J-2 Page 3 T~pical Mudline Suspension System for Jackup Rig · Attachment K Page 1 BLONOUT PREVENTION EQUIPMENT TEST PROCEDURES The blowout preventer stack shall be tested at the-following times: (a) On Test stump prior to installation; 70% of rated working pressure for blind/shear rams, pipe rams, valves and Hydrils. (b) ~iately after installation: 70% of rated working pressure for all pipe rams, valves, and Hydrils. The blind/shear rams will be tested to 20 inch casing test pressure. Weekly on the first trip out of hole after 0001 hours Tuesday: _~70o 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/shear 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; 70% of BOPE working pressure or expected surface shut in pressure, whichever is highest, forblind/ · shear rams, pipe rams, choke/kill lines and valves. The Hydril test will be limited %o 50% of Working .pressure. Actuation tests of blind/shear 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: All preventers robe,tested willbe tested at a low pressure of 200-300 psi for 3-5mins. prior to high pressure testing. AttacP~nent K Page 2 At time of installation of BOP stack, all valves in the choke manifold should be tested to 70% rated working pressure against the closed gate. 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. Initially test to 70% rated working pressure. Safety Precautions: One pumping unit operator is to be stationed at the high pressure pump- ing 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 ~nd 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. All 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 are vented 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. Attachment K Page 3 REQUIRED B.O.P.E. TEST PRESSURES: Te~t Operation Test Stump (Prior to Installa- tion) 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" Choke & Kill Lines 3,500 3,500 3,500 3,500 3,500 3,500 1,000 1,000 1,000 2,000 2,000 2,000 3,000 2,500 3,000 5,000 2,500 5,000 CASING ANDBLIND/SHEARRAMTEST The casing strings will be tested simultaneously with the blind/shear rams. After pulling test plug from wellhead close blind/shear rams and test to required pressure listed below for 30 minutes. REQUIRED TEST PRESSURES: casing Casing & Blind/Shear Test Pressure 20" H~40, 94 lb/ft 1,000 psi 13 3/8", K'55, 54.5 lb/ft 2,000 9 5/8", K-55, 36 lb/ft 2,500 7", N-80, 32' lb/st 5,000 BI. ~FmT~O~ TEST PRCC~DURE Attachment L Page 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~ ~ressure. 4. Shut the pump down and record the instantaneous shut-in pressure. Shut-in for 10 minutes and record the pressure decline on 1-minute intervals. e 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 %o the volume p ~%mlped. 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 Kenai Office. Attacl~nent L Page 2 B%EED-OFF TF~T RK~ORT Well Name & No. Date T~ne Liner Size Stroke Length Vol BPS ~d W% PV YP Gels Casing Size WT Grade Shoe Depth · . Open Hole TD MD TVD ~'V°lume I Volume VolUme .... Pumped Pressure _Time .Pumped Pressure T~e .PuH~_ed Pressure Volume recovered after releasing pressure: bbls. Observed bleed-off pressure: psi. ' ......... ~. Equivalent Mud Weights a~d Gradients: A. At Casing Shoe: E.M.W. = Actual Fnd Wt. + (bleed-off pressure ) (0.052 x casing shoe T~D ) o E.M.W. @ Csg. Shoe = ,~gal. Equiva!ent Gradient = .052 x E.M.W. = ps i/ft. B. At TD:' (if significantly deeper than casing shoe) E.M.W. = Actual ~d Wt. +~ (bleed-off m'essure ) (0.052 x Open hole TVD) E. M.W. @ TD = ~#/gal. Fquivalent Gradient = .052 x E.M.W. = psi/ft. R~,L~3{K S: TEMPORARY SUSPENSION of FLOATING DRILLING OPERATION and ABANDONMENT OF LOCATION Attachment M Page 1 The following Securing Procedure is presented for your use and informa- tion. The procedure should be used as a guide and not to be construed as a firm directive. The procedure considers only wind forces and no consideration has been given to sea conditions. As a general rule, the sea conditions will develop along with the weather. It is possible to have sea conditions which will at leash suspend operations when wind conditions are still favorable, but usually sea conditions will become bad as wind forces develop. The Phillips and Contractor Supervisors onboard must be the judge on when to execute the indicated procedure and how closely it should be followed. Consultation with Kenai office will be utilized when practical. Once the decision ho suspend operations is made, the SecUring Procedure to temporarily abandon the location shall be put into effect. When heave has increased to 10-15 feet, and weather is deteriorating, or upon development of unexpected winds of more than 50 knots, or winds of 60 knots or stronger are predicted, the following steps are to be taken: l. . Bit is ho be pulled into the casing, if possible, cement plug laid in casing if wellbore conditions warrant it, and drill pipe hung off in BOP ~er Attachment N. The decision ~o release the riser is to be made by the Phillips Drilling Supervisor after consultation with the Contractor Tool Pusher and vessel Captain and their offices where practical. Before the decision to release is made, consideration should be given to the weather forecast and present anchor tensions. 3. Release riser ah connector and try ho lay down enough riser to have ball joint into cellar deck.' . If forecasts indicate winds in excess of 65 knots, all efforts are to be made to lay down any pipe in the derrick. < If %he vessel begins moving off location, all guide lines are to be attached to guide line retrieving ropes. The ropes should be paid out as necessary. The decision to drop %he lines will be made by the Phillips Supervisor. The order of dropping the lines must be recorded in the drilling report. Attachment M Page 2 . In the event the vessel is robe evacuated, the order to do so must oome from either the Phillips or Contractor's office. If these offices cannot be contacted, the contractor's supervisor onboard is charged with giving the "Abandon Ship" order. Attachn~nt N Page 1 HANGING OF DRILL PIPE IN SUBSEABOP STACK WITH RISER l. Have suspension tool made up on installation tool and whole assembly made up onto drill pipe standing back in derrick. 0 Try to hang off with bit up in the casing. Keep a close watch on the weather and try to anticipate storms so you can be up into the casing in sufficient time. If, however, you have to hang off quickly, pull out of hole a minimumdistance of RKB-to-seabed plus one (1) more stand so the bit will not hit on bottombefore the suspension plug lands in the wellhead. GIH with suspension plug and land on bowl protector. Release by left hand rotation and OOOH. Close blind rams. Then standby to release riser as directed. e After storm danger is past, reconnect riser~ Then check for pres- sure under blind rams by opening choke line valves. If okay, then open blind rams and GIH and retrieve suspension tool and stand it back in derrick. Before going back to bottom, check for bit plugging by atten~ting to break circulation. Take appropriate action as dic- tated by circulation test. CAUTION: Tool will sometimes land in Hydril giving the impression that the %ool has landed correctly. It will drop shortly afterwards. Keep accurate measurements so that you know where you are. Attachment O-1 FLOATER 30 INCH CASING STRING 30" Housing welded ~o ~0" casing, heat' ~reat and cooled to specifications. ., 40 ft~ - 30, 625 Wall Grade B L.P · Vetco- ATD- SqunchJointAssemblywelded to 30 inch casing heat treated'and cooled to specifications. · 40 ft. -'30" .625'Wall Grade B L.P. Vetco - ATD- Squnch Joint Assemblywe!d as above. 40 ft ~- 30" 625 Wall Grade B L.P · · · · 30"..Conventional Float Shoe welded as above. · . All ~d eyes are welded and will be removed prior to running through 'permanent guide structure. o · Padeyes for/?/ Handling / v Two/Joint Remove these ' j%a .dlneYte~aef~ JACKUP 30" CASING STRING Attachment O-2 Vetco Type "ALT" Squnch Joint (1) 40' + - 30" x .625" Wall R-3 X-42 Line Pipe (2) (1) (2) (1) (2) (1) (2) ~ Vetco Type "R" Driveable' Connector (3) (2) (3) (2) 30" x .750 Wall Grade B Drive Shoe FLOATER 20 INCH CASING STRING Attachment P-1 Wellhead Housing welded to 20" csg., heat treated, and cooled t°o specs. WH Housing Extension - 20" O.D. x 20' length, ribbed 15' externally. Vetco Type ST Squnch Connector 6' - 20" H-40 94 lb/ft STC Csg ~ ~ · · 180' +- 20" H-40 94 lb/ft STC Csg Conventional Float Collar , 40' +- 20", H-40, '94 lb/ft, shOe joint Conventional Float Shoe Torque STC pipe to 5,800 foot-pounds. Three (3) Centralizers will be 'spaced as follows: 1 - 7.5' above shOe joint 1 - Top of 2nd and 5th joints. Thread lock all connections on bottom three (3) joints. JACKUP 20" CASING STRING Attachment P-2 40' +- 20", 94#, H-40 STC Casing (1) (1) (1) (1) Gray Type DJ-S Casing Housing-Pla~e 20' + 5' below mudline (1) (1) (1) (1) Stab-in Float Collar (1) Conventional Float Shoe Torque STC Pipe to 5,800 foot-pounds Three (3) Centralizers will be spaced as follows: 1- 7.5' above shoe 1 -'Top of 2nd and 5th joints Thread lock all co~ections on bottom three (3) joints Attachment Q-1 16 3/4" x 13 3/8" hanger & packoff 6' ~.13 3/8", 54.59, K-55 ST pup joint. Pin x pin 13 3/8" casings as follows: 880' - 54.5#, K-55 STC 80' - 72#, L-80 BTC Float Collar 40' + - 13 3/8", L-80, 72#/ft BTC Casing Float Shoe The float., shoe , float collar, and all couplings on the bo%tom three (3) joints of casing will be thread locked. TOrque 54.5~, K-55 STC pipe to 5,470 fc~t-pOunds.. · TOrque 72~, L-.80 BTC pipe to ~ mark. · . . Nine (9) 'Centralizers will be installed as follows: 1 - 7.5' above shoe. 1 each - top of 2nd, 5th, 8th, llth, 14th, 17th, 20th and 23rd joints. Attachn~nt Q-2 JACKUP 13 3/8'! CASING STRING 13 3/8" - 54.5#, K-55 STC Casing (1) (1) (1) (1) Gray 18 3/8" O.D. x 13 3/8" Type DJ-MSR mudline casing hanger (Box x Box) with Gray hype DJ circulating assembly 717' + of 13 3/8", 54.5#, K-55 STC ~asing and 260' + of 13 3/8", 72~ , L-80 BTC below Stab-in float collar 40' + 72#, L-80 BTC Float shoe Torque STC pipe to 5,470 foot-pounds Thread lock all connections on bottom three (3) joints Nine (9) Centralizers will be spaced as follows: 1 - 7.5' above shoe 1 each - top of joints 2, 5, 8, 11, 14, 17, 20 and 23. Attachment R-1 FLOATER 9 5/8 INCH CASING STRING 16 3/4" x 9 5/8" hanger & packoff 6' - 9 5/8", 36#, K-55 ST pup j6int pin x pin 9 5/8" casing as follows: 800' - 36#, K-55 STC 850' - 40#, K-55 STC 2,310' , 47#, C-95 BTC 1 Automatic Fill-up float collar. 40'_+--9 5/8", 47#/ft., C-95 BTC casing 1 Automatic fill-up float shoe The flo..at shoe, float collar and all couplings on the first three (3) joints of casing will be thread locked. NOTE: DO NOT WEI.D C-95 CASING. Place centralizers as follows: 1 - 7.5' above shoe 1 on top of 2nd, 5th, 8th and llth joints. Torque 47# BTC to ~mark Torque 40# KSTC to 4,860 foot-pounds Torque 36# KSTC to 4,230 foot-pounds Attachment R-2 JACKUP 9 5/8 INCH CASING STRING 160' + 36#, K-55 STC Gray 13 3/8"'x 9 5/8" type DJ-T mudline casing hanger with Gray. type DJ circulating assembly 9.5/8" casing as follows: 800' ~- 36#, K-55 STC~ 850' + - 40#, K-55 S~ 2,310' + - 47#, C-95 BTC Automatic fill float collar 40' + - 47#, C-95 BTC Automatic fill float shoe Torque 47# BTC to ~.mark; 40# K STC to 4,860 Ft.-Lbs.; & 36# K STC to 4,230 ft.-lbs. Thread lock all connections on bottom three joints. DO NOT TACK W~,D C-95 CSG. Place centralizers: 1 - 7.5' above shoe and 1 on 2nd, 5th, 8th & llth joints. Attachment S-1 FLOATER ]3~CH CASI]~G STRING 16 3/4" x 7" hanger & packoff 7" casing as follows: Top section- 3,800' - 7", 32#, N-80 LTC Mid Section - 2,500' - 7", 26#, K-55 STC BOttom Section - 3,620' - 7", 32#, N-80 LTC 1 Automatic fill-up float collar. 2 joints - 7", 32 #/ft., N-80 LTC casing 1 Automatic fill-up float shoe. All coUplings on first three (3) joints of casing will be thread locked. , Optimum make-up torque is 6,700 Ft.-Lbs. for 32~ N LTC · Optimum make-up torque is 3,640 Ft.-Lbs. for 26# K STC Centralizers will be installed as follows: 1 directly above shoe. 1 ~iately above, below and every 120' + throughoutpossible producing zones. 1 every 200'.+ through nonproductive zones robe cemented. Attachment S-2 JACKUP 7 INCH CASING STRING 4 + jts. of 32#, N-80 LTC casing Gray 9 5/8" x 7" type DJ-MRNmudline casing hanger with Gray Type DJ circulating assembly 7" casing as follows: Top Section - 3,800' - 32#, N-80 LTC Mid Section - 2,500' - 26#, K-55 STC Bottom Section - 3,620' - 32#, N-8~ LTC Automatic fill float collar 2 jts. of 32#, N-80 LTC casing Thread lock all connections on bottomthree (3) joints. Torque for 32# N LTC is 6,720 ft-lbs. ~nd for 26# K STC, it is 3,640 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 robe cemented. - Automatic fill float shoe Attachment T Page 1 · . TECHNICAL DATA SHEEI' .S.SR(Subsurfac¢ R¢tc2s¢)C. cmcnting Plug Method For Occnn Floor Complc~ion Subsea (ocean floor) complet)ohs now may use standard cementing techniques in which the cement slurry is pumped th~-ough a string of tubing or drill pipe smaller than t_he string being cemented. }-~alli- button's SSR Cementin. g Plug Method enables use of~ standard techniques and makes a higher success ratio possible. 'l'he system provides a means of wiping both pipe sizes a_nd it/; design separates cement slurry and displacing fluid. Also, drill pipe can replace the casing that otherwise would be run between the rig floor a_nd the ocean floor. The SSR Cementing Plug 'Method offers inc~:eased tel!ability, the major difference between it and o~her methods. The sequ'ence of operation's in the second phase does not depend upon manipulatJon of steel balls and shear pins. Instead, asturdy doublecollet releasing mechanism, triggeredbyastandard latch- dox~mplug arrangement, releases the top plug as the displacing phase begins. : Use of the Halliburton special ce!nenting head, which retains both the releasing ball and latch-down plug, allows continuous pumping of cement slurry or, later, displacing fluid during the full sequence of.the cementing process. , · The accompanying schei-natic drawings detail the sequence of operation. Fig. 1 shows liner in place with plugs installed at top of liner prior to beginning the actual cementing operation. - _;Z-- A set of releas, ing pins attaches the bottom plug to the top plug. A 1.TS-inch weighted plastic ball dropped through the drill pipe ahead jf the cement slurry separates the bottom plug from the lop plug. The ball passes through the top plug and lands on th~ bottom plug tension seat. An applied different_iai p~-essu~e of 1000 psi separates the bonom plug from the tod plug. · Ddi;ng se?ar~t~on0 p~essure is ~pp]ied directly to the I~o~'1om plug lens~on seat ~-~d has no effect on ~elcase of t)m lop plug. Fig. ~' illustrates how the tx0ttom.plug has been dSscharged from the ~op plug and has been seated on the :float collar {or float shoe). At this point° an inc~easeof approximately 300 to 500 psi in differen- tial pressure exposes portholes in the plug mandrel through which the.cement, ~].urry is pumped arotind the bottom plug ~'e]easing ball. A d°~ble col]et :releasing mechanism holds the lop plug Ln place. The double collet mechanism has a higher ~-eta_ining strength than the tensile strength, of the plug mandrel. The double collet me'chanism Attachment T Page 2 perrnils cJjcu]~lion through the plug at norn,.:d dis- placernent r~es prior to release of the top plug. A lr~ch-dovm plug is pumped down the tubl. ng or / drill pipe behind the slurry ~_nd into the lop plug where it latches. An applied, pa'essure (I$40 psi differential) shears the brass pins that restrain the sleeve. After the sleeve moves down, O~e col]et fingers move off the swivel shoulder lo allow the top plug to release. As sho'am in Fig. 3, the drill pip~ plug and ~op ce- menting plug no',,,, are free to move down the hole as a single unit. The top plug ]ands on the botlom plug to shut o~I in the conventional manner. ease & Block },~mber · · . At~d~ment U -lWe]l I',~ tuber Total Length Cas'_~n~ Run RKB to Casing H_an_ge~ . _ 'ialm_or__F. oAe_L_- +/_eigh_~_~ g_r a_aAc Th_r ~ a d n%L~z s~t~i~~_ (~t... ~K~) . ~e~tralizers~ and Accessories (Make,,~fpe, &Depth) CSw.culation Time C~TING DETAILS '1 :Preflush (Amount & Type) Lead--in Cement (3~~ount, Type, Additives & MSx ~uid) l Total Tot al S lurr.y ~!e_i~gh__t S anTol es I ] I Cement (Amount, Type, Additives & ~[ix Fluid) ~_7~__er_a_g e Cement Plug ]__~__~Pu ed To reel INCI,IIBE ADDITIF')lxl^I -I'W~'hr~,~^m*rr~,~ ~', _I42ver age psi - CHECK LIST FOR NEW WELL PERMITS Item Approve Date (1) Fee ~'~, /-&-~I (2) Loc. (3) ktmin. /~'L 1. Is the permit fee attached ........................................... 2. Is ~ell to be located in a defined pool ............................. Lease &weii No Remarks 5. Is mil located Uroper distance frcm other mils .......... 6. Is sufficient undedicated acreage available in this pool ./.~,,. 8 Is operator the only affected party ...... 9. Can permit be approved l:efore ten-day wait ., ....................... . · /,-}'~t . 10. Boos operator have a l~nd in force .......... , · · · ~ ~.,~' · 11. Is a conservation order needed ...................................... /._ 12. Is administrative approval needed ................................... · 13. Is corrtuctor string provided ................................... '....~~ 14. Is enough cement used to circulate on conductor and surface ........ ~ (4) ~ /,-/2,~ ! 15. Will c~ment tie in surface and intermediate or production strings .. ~ 6. Will c~nt: cover all known prcductive horizons .................... [r'~ 17. Will surface casing protect fresh water zones ......... ~ 18. Will ali casing give adequate safety in collapse, tension and burst..<~ (5)BOPE d~~ /'-/2~, 19. Does BOPE have sufficient pressure rating- Test to ~~ psig ~... Approval R~c~ded: ~, ~~.-=c=~ ~z~=w~ ~~f ~-~.~ ~~u~ ~ /E~'~' '- ' rev: 03/05/80 ~,,~,~.. .: _~},,,..~; ..... ANALOG RECORDS~ GEOPHYSICAL SURVEYS FOR THE SRS PROJECT COOK INLET, ALASKA Prepared for PHILLIPS PETROLEUM COMPANY KENAI, ALASKA '"-' NORTHERN TECHNICAL SERVICES ANCHORAGE, ALASKA · ANALOG RECORDS GEOPHYSICAL SURVEYS FOR THE SRS PROJECT COOK INLET, ALASKA Prepared for PHILLIPS PETROLEUM COMPANY Prepared by NORTHERN TECHNICAL SERVICES SePtember 30, 1980 .) CONTENTS HIGH RESOLUTION BOOMER (HRB) RECORDS Line 1 Line 4 Line 5 Line 6 Line 7 Line 8 Line 9 Event Marks Event Marks Event Marks Event Marks Event Marks Event Marks Event Marks 1- 20 32- 40 42- 55 56- 78 79-102 103-115 116-137 SIDE SCAN SONAR RECORDS Line 4 Line 5 Line 6 Line 7 Li ne 8 ~.. Line 9 Event Marks Event Marks Event Marks Event Marks EVent Marks Event Marks 32- 40 42- 55 56- 78 79-102 ~i~03-115 116-137 FAT}I~METER RECORDS Line 6 Line~7 Line 8 Line 9 Dredge Samples Event Marks Event Marks Event Marks Event Marks Event Marks 56- 78 79-102 103-115 116-137- 138-147 HIGH RESOLUTION BOOMER (HRB) RECORDS I · BOOMER LINE ~ 20 EVENT MARKS BOOMER LINE 4 EVENT ~JtRKS 3 2- 4 0 BOOMER LINE 5 EVENT MARKS 42-- 55 BOOMER LINE 6 EVENT MARKS 56-78 BOOMER LINE 7 EVENT MARKS 7 9-10 2 BOOMER LINE 8 - EVENT MARKS 103-115 BOOMER LINE 9 EVENT MARKS 116-13 7 SIDE SCAN SONAR RECORDS SIDE SCAN SONAR LINE 4 EVENT MARKS 32-40 SIDE SCAN SONAR. LINE 5 EVENT MARKS 4 2- 5 5 SIDE SCAN SONAR LINE 6 EVENT MARKS 56-78 SIDE SCAN SONAR LINE 7 EVENT MARKS 79-102 SIDE SCAN SONAR LINE 8 EVENT MARKS 103-115 SIDE SCAN SONAR LINE 9 EVENT MARKS 116-137 FATHOMETER RECORDS FATHOMETER LINE 6 EVENT MARKS 5 6- 7 8 END PROFILE 7 .AT' 1646 ~ EVENT MARK' 102 .> - -. · .- . · .EVENT MARK 101 ,j · . . - · EVENT MARK 115