ENI - Drilling Procedures Manual

ARPO

ENI S.p.A. Agip Division

ORGANISING DEPARTMENT

TYPE OF ACTIVITY'

ISSUING DEPT.

DOC. TYPE

REFER TO SECTION N.

PAGE.

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234

STAP TITLE

P

1

M

6140

DRILLING PROCEDURES MANUAL

DISTRIBUTION LIST Eni - Agip Division Italian Districts Eni - Agip Division Affiliated Companies Eni - Agip Division Headquarter Drilling & Completion Units STAP Archive Eni - Agip Division Headquarter Subsurface Geology Units Eni - Agip Division Headquarter Reservoir Units Eni - Agip Division Headquarter Coordination Units for Italian Activities Eni - Agip Division Headquarter Coordination Units for Foreign Activities

NOTE: The present document is available in Eni Agip Intranet (http://wwwarpo.in.agip.it) and a CD-Rom version can also be distributed (requests will be addressed to STAP Dept. in Eni - Agip Division Headquarter) Date of issue: Issued by P. Magarini E. Monaci 28/06/99 REVISIONS PREP'D C. Lanzetta 28/06/99 CHK'D A. Galletta 28/06/99 APPR'D 28/06/99

The present document is CONFIDENTIAL and it is property of AGIP It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given

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REVISION STAP-P-1-M-6140 0

INDEX1. INTRODUCTION1.1. 1.2. 1.3. Purpose of the document implementation UPDATING, AMENDMENT, CONTROL & DEROGATION

88 8 8

2. 3.

WEATHER PREDICTION DOCUMENTATION3.1. Reporting 3.1.1. Well Site Reports 3.1.2. Other Well Site Reports Contractor Performance Report Distribution

9 1010 10 11 11 12

3.2. 3.3.

4.

SUMMARY OF OPERATIONS (Land Rig or Jack-Ups)4.1. Conductor Pipe Installation 4.1.1. Pile Hammers 4.1.2. Final Refusal Depth 4.1.3. Conductor Pipe Connections 4.1.4. 30" CP Driving Procedure 4.1.5. Drilling And Cementing CP Drilling 26" Hole 4.2.1. Cluster Wells 4.2.2. Single Well 4.2.3. Single Well Using Pilot Hole Technique Drilling 17 /2 Hole Drilling 12 /4 Hole Drilling 8 /2 Hole RUNNING OF 7 CASING RUNNING OF 7 LINER Drilling Slim Hole (5 /8 or 6) General GUIDELINES7 1 1 1

1313 13 18 19 23 30 31 31 32 33 34 36 37 37 38 38 38 40 40

4.2.

4.3. 4.4. 4.5. 4.6. 4.7. 4.8. 4.9.

4.10. Top Drive Drilling SystemS 4.10.1. Drilling Ahead In HP/HT Formations

5.

SUMMARY OF OPERATIONS (Semi-Submersible)5.1. BOP Stack equipment 5.1.1. Wellhead Connector 5.1.2. BOP Rams 5.1.3. Annular Preventer Fail Safe Valves

4343 45 45 48 49

5.2.

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ENI S.p.A. Agip Division5.2.1. 5.2.2. 5.2.3. 5.3.

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REVISION STAP-P-1-M-6140 049 54 54 54 55 56 56 56 58 58 61 61 62 63 63

BOP Control System Subsea Pods Accumulators

RISER AND DIVERTER SYSTEM 5.3.1. Riser Joints 5.3.2. Riser Coupling 5.3.3. Slip Joint 5.3.4. Tensioning System 5.3.5. Lower Flex Joints 5.3.6. Diverter System RUNNING THE BOP ANd RISER SYSTEM 5.4.1. BOP Stack And Riser Preparation 5.4.2. Running The Bop And Riser 5.4.3. Landing The BOP Stack 5.4.4. Testing The BOP Stack

5.4.

6.

DRILLING MUD6.1. 6.2. 6.3. 6.4. 6.5. General Mud properties Safety actions Drilling with Oil-Based Mud Minimum stock requirements

6464 64 65 66 67

7.

TRIPPING AND FILL-UP PROCEDURES7.1. 7.2. 7.3. General PROCEDURES Tripping with a top drive Flow checkS

6868 71 71

8.

DRILLING STRING DESIGN/STABILISATION8.1. 8.2. STRAIGHT HOLE DRILLING Dog-Leg And Key Seat Problems 8.2.1. Drill Pipe Fatigue 8.2.2. Stuck Pipe 8.2.3. Logging 8.2.4. Running casing 8.2.5. Cementing 8.2.6. Casing Wear While Drilling 8.2.7. Production Problems HOLE ANGLE CONTROL 8.3.1. Packed Hole Theory 8.3.2. Pendulum Theory DESIGNING A PACKED HOLE ASSEMBLY 8.4.1. Length Of Tool Assembly 8.4.2. Stiffness 8.4.3. Clearance 8.4.4. Wall Support and Length of Contact Tool PACKED BOTTOM HOLE ASSEMBLIES PENDULUM BOTTOM HOLE ASSEMBLIES

7272 72 72 73 73 73 73 73 73 75 75 76 76 76 76 78 78 78 80

8.3.

8.4.

8.5. 8.6.

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ENI S.p.A. Agip Division8.7. 8.8. 8.9. REDUCED BIT WEIGHT DRILL STRING DESIGN

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REVISION STAP-P-1-M-6140 081 82 85 87 89 90

BOTTOM HOLE ASSEMBLY Buckling

8.10. SUMMARY RECOMMENDATIONS FOR STABILISATION 8.11. OPERATING LIMITS OF DRILL PIPE 8.12. GENERAL GUIDELINES

9.

DIRECTIONAL DRILLING9.1. 9.2. TERMINOLOGY AND CONVENTIONS CO-ORDINATE SYSTEMS 9.2.1. Universal Transverse Of Mercator (UTM) 9.2.2. Geographical Co-ordinates RIG/TARGET LOCATIONS AND HORIZONTAL DISPLACEMENT 9.3.1. Horizontal Displacement 9.3.2. Target Direction 9.3.3. Convergence HIGH SIDE OF THE HOLE AND TOOL FACE 9.4.1. Magnetic Surveys 9.4.2. Gyroscopic Surveys 9.4.3. Survey Calculation Methods 9.4.4. Drilling Directional Wells 9.4.5. Dog Leg Severity

9191 93 93 94 96 96 97 97 98 99 101 103 105 110

9.3.

9.4.

10. CORING10.1. CORE BARREL TYPES AND USES 10.1.1. Wireline 10.1.2. Marine Core Barrels 10.1.3. Rubber Sleeve 10.1.4. Conventional Core Barrel 10.1.5. Inner Tubes 10.1.6. Modified Barrels 10.2. GENERAL GUIDELINES 10.3. CORING PROCEDURES 10.3.1. Operating Instructions 10.3.2. Preparing for Coring 10.3.3. Starting of the Coring Operation 10.3.4. Possible Cause Of Pump Pressure Changes 10.3.5. Breaking Core (Making A Connection Or Pulling Barrel) 10.3.6. Recovery of the Core 10.4. Coring In Deviated Holes 10.4.1. Stabilisation of the Outer Barrel 10.4.2. Stabilisation of the Inner Barrel 10.4.3. Stabilisation of the Drill Collar Assembly

112112 112 112 112 112 114 114 116 117 117 118 119 120 120 121 123 123 123 123

11. LEAK OFF TEST PROCEDURE11.1. TEST PROCEDURE

124125

12. CASING RUNNING AND CEMENTING

128

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REVISION STAP-P-1-M-6140 0128 129 129 133 137 138 140 140 141 141 143 143 147 150 151 151 152 152 153 154 154 155 156

12.1. Responsibilities 12.1.1. Casing Check List 12.1.2. Preparation For Casing Running And Cementing 12.1.3. Installation Patterns (For Mechanical Cementing Aids) 12.1.4. Preliminary Operations 12.1.5. Running Procedure 12.1.6. Casing Operations With A Top Drive 12.2. CRA CASING OPERATIONS 12.2.1. Preliminary operations 12.2.2. Handling and running CRA tubulars 12.3. CEMENTING AND DISPLACEMENT PROCEDURE 12.3.1. Single Or First Stage 12.3.2. Dual Or Second Stage 12.3.3. Double Stage Cementing In Deep Wells 12.4. Mudline Suspension Procedures 12.4.1. Cementing 20" Surface Casing (With Inner Strings) 12.4.2. Cementing Casings With Plugs 12.5. Post-Cementing Operations 12.6. Squeezing 12.7. LINERS 12.7.1. Preliminary Preparations 12.7.2. Running And Setting 12.7.3. Cementing

13. LOGGING13.1. Logging While Drilling (LWD) COnsiderations 13.1.1. Advantages Of Using LWD 13.1.2. Onshore Planning 13.1.3. Rig Planning 13.1.4. Contractor Advanced Knowledge 13.1.5. Rig Monitoring System Requirements 13.1.6. Shock Mechanisms That Can Cause Lwd Tool Failure: 13.1.7. Solutions To Shock Problems: 13.2. Wireline logging 13.2.1. General Guidelines 13.2.2. Preparations 13.2.3. Quality Control 13.2.4. Handling Explosives 13.2.5. Handling Radioactive Sources 13.2.6. Logging Tool Fishing (overstripping method)

157157 157 157 158 158 158 158 158 159 159 160 160 161 162 163

14. WELL ABANDONMENT14.1. Temporary Abandonment 14.1.1. During Drilling Operations 14.1.2. During Production Operations 14.2. PERMANENT ABANDONMENT 14.2.1. Plugging 14.2.2. Plugging Programme 14.2.3. Plugging procedure 14.3. Casing cutting/retrieving 14.3.1. Stub Termination (Inside A Casing String)

165165 165 165 166 166 166 167 168 168

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ENI S.p.A. Agip Division14.3.2.

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Stub Termination (Below A Casing String)

15. SURFACE WELLHEAD15.1.1. PRELIMINARY CHECKS 15.2. BASE FLANGE INSTALLATION 15.2.1. Welding Procedure 15.2.2. Safety 15.2.3. Pressure Testing 15.2.4. Slips Installation 15.2.5. Casing Preparation 15.2.6. Primary And Secondary Packing Installation 15.2.7. Casing Spool Installation 15.3. RECOMMENDED FLANGE BOLT TORQUE 15.3.1. Slips Installation 15.3.2. Casing Preparation 15.3.3. Primary And Secondary Packing Installation 15.3.4. Tubing Spool Installation 15.3.5. Primary And Secondary Packing Group Test 15.4. COMPACT WELLHEAD 15.5. MUDLINE SUSPENSION 15.5.1. General Guidelines 15.5.2. Temporary Abandonment Procedure.

169169 169 169 171 171 171 172 172 173 174 177 177 177 178 179 189 193 196 200

16. DRILLING PROBLEMS16.1. STUCK PIPE 16.1.1. Differential Sticking 16.2. STICKING DUE TO HOLE RESTRICTION 16.3. STICKING DUE TO CAVING HOLE 16.3.1. Sticking Due To Hole Irregularities And/Or Change In BHA 16.4. OIL PILLS 16.4.1. Light Oil Pills 16.4.2. Heavy Oil Pills 16.4.3. Acid Pills 16.4.4. Free Point Location 16.4.5. Measuring The Pipe Stretch 16.4.6. Location By Free Point Indicating Tool 16.4.7. Back-Off Procedure 16.5. FISHING 16.5.1. Inventory Of Fishing Tools 16.5.2. Preparation 16.5.3. Fishing Assembly 16.6. FISHING PROCEDURES 16.6.1. Overshot 16.6.2. Releasing Spear 16.6.3. Taper Tap 16.6.4. Junk Basket 16.6.5. Fishing Magnet 16.7. Milling Procedure 16.8. Jarring Procedure

201201 201 202 203 204 205 205 205 206 206 207 207 208 209 209 210 212 212 212 213 213 214 214 214 216

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ENI S.p.A. Agip Division 17. LOST CIRCULATION

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217217 218 218 219 219

17.1. Loss PREVENTIVE MEASURES 17.1.1. REMEDIAL ACTION (WHILE DRILLING) 17.2. Use of DOB AND DOBC PILLS 17.3. REMEDIAL ACTION (WHILE TRIPPING) 17.4. Use of LCM PILLS

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REVISION STAP-P-1-M-6140

1.1.1.

INTRODUCTIONPURPOSE OF THE DOCUMENT The purpose of this manual is to define Eni-Agip Division and Affiliates policies and procedures for general drilling operations. These are based on the contents of the Drilling Design Manual. The purpose of the manual is to guide technicians and engineers, involved in Eni-Agips Drilling world-wide activities, through the procedures and the technical specifications which are part of the corporate standards. Such corporate standards define the requirements, methodologies and rules that enable to operate uniformly and in compliance with the corporate Company principles. This, however, still enables each individual Affiliated Company the capability to operate according to local laws or particular environmental situations. The final aim is to improve performance and efficiency in terms of safety, quality and costs, while providing all personnel involved in Drilling & Completion activities with common guidelines in all areas world-wide where Eni-Agip operates.

1.2.

IMPLEMENTATION The policies included in this manual apply to all Eni-Agip Division and Affiliates operations. All supervisory and technical personnel engaged in Eni-Agips drilling, completion and workover operations are expected to make themselves familiar with these and comply with the policies and procedures specified and contained in this manual.

1.3.

UPDATING, AMENDMENT, CONTROL & DEROGATION This manual is a live controlled document and, as such, it will only be amended and improved by the Corporate Company, in accordance with the development of Eni-Agip Division and Affiliates operational experience. Accordingly, it will be the responsibility of everyone concerned in the use and application of this manual to review the policies and related procedures on an ongoing basis. Locally dictated derogations from the policies and procedures herein shall be approved solely in writing by the Manager of the local Drilling and Completion Department (D&C Dept.) after the District/Affiliate Manager and the Corporate Drilling & Completion Standards Department in Eni-Agip Division Head Office have been advised in writing. The Corporate Drilling & Completion Standards Department will consider such approved derogations for future amendments and improvements of the manual, when the updating of the document will be advisable.

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2.

WEATHER PREDICTIONWeather data for rig locations are required to predict rig downtime, the effects on rig moving, towing and establishing the rig on location. During drilling operations, a forecasting service is mandatory in remote areas or where hostile weather conditions may be expected, e.g. tropical storms. Operating in cold water environments requires additional forecasting due to the possibility of experiencing freezing conditions or mobile ice flows. The site-specific information can be obtained from a certified meteorological and oceanographic consulting company. To predict weather conditions, the consulting company must be provided with the well location latitude and longitude or lease block number, the water depth and expected drilling period. The weather information required is wind, wave and current specifics for 80% weather (normal condition), the one year storm, the 10 year storm and the 100 year storm during the given drilling season. Further information may be necessary in particular situations or to meet local regulations.

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3.3.1. 3.1.1.

DOCUMENTATIONREPORTING Well Site Reports It is vitally important that the operation process is fully recorded and documented in a consistent format, therefore, standard feed-back or report forms with relevant filling instructions for ensuring a consistent and homogeneous method will be used in technical data reporting of world wide activities. It will be the responsibility of the ENI-AGIP and Affiliates Drilling And Completion Supervisor to ensure the correct filling in and forwarding of the appropriate forms/reports to the Company Base (Drilling Manager/Superintendent). The reports necessary for drilling operations are: ARPO 01 ARPO 02/A ARPO 03/A ARPO 03/B ARPO 04/A ARPO 04/B ARPO 05 ARPO 06 ARPO 13 ARPO 20/A ARPO 20/B FB 01 FB 02 Initial Activity Report Daily Report (Drilling) Casing Running Report (General Data) Casing Running Report (Job Data) Cementing Job Report (General Data) Cementing Job Report (Job Data) Bit Record Waste Disposal Management Report Well Problem Report Well Situation Report (Well) Well Situation Report (Wellhead) Contractor Service and Equipment Evaluation Contractor Performance Evaluation

Example copies of these reports are included in Appendix A.

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ENI S.p.A. Agip Division3.1.2. Other Well Site Reports BOP Sketch

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After the BOP stack has been installed, the Drilling And Completion Supervisor shall produce a sketch of the BOP including the size and location of the rams and the depths referred to RKB and send it with the BOP Test Report. BOP Test Report During every BOP test, the Drilling And Completion Supervisor shall prepare a report on the test results. Cement Bond Evaluation from CBL-VDL-CET In the description of a CBL-VDL or CET, the Drilling And Completion Supervisor shall fill in a report form with the following: Cementing job summary Log evaluation Remarks.

This report shall be attached to the copy of the appropriate log considered. Well Test String Sketch If well testing operations are conducted, every test string shall be recorded in a sketch with the data as listed below, in addition to the general well test data report: 3.2. String schematic Component description Outside diameter Inside diameter Capacity Lengths Depths.

CONTRACTOR PERFORMANCE There are two forms for the reporting of contractors performance. Report FB-01 is for reporting of malfunctions and failures in services and equipment. Report FB-02 is for documenting a contractors performance in relationship to the contract conditions. These should be completed giving an explanation of problems encountered and suggestions for performance improvement. Both of these forms must be completed in a timely manner at the end of the contractors operations or at the end of the well, whichever is applicable. Copies of the these reports are included in Appendix A.

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ENI S.p.A. Agip Division3.3. REPORT DISTRIBUTION

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The following chart details the destination of, frequency and times that reports need to be distributed.Form Freq. Period/ Delay ARPO-01 ARPO-02/A ARPO-03/A Each Rig Daily Each Job Each Job Each Job Each Job End of phase Start of activity 1 Day With ARPO02/A With ARPO02/A With ARPO02/A With ARPO02/A 1 Day Cont I Rig Comp R/A I/A I/A R*/F R* R R* R* R* R R* F R/F F Base Peit Arpo Teap Stap Others

ARPO-03/B

I/A

R

R*

R*

F

ARPO-04/A

I/A

R

R*

R*

F

ARPO-04/B

I/A I/A I/A

R R R* R*

R* R*

R*

F F

ARPO-05 ARPO-06 ARPO-13 ARPO-20/A ARPO-20/B FB-01 FB-02

On activity After job After job On activity 6 Months

1 Day End of phase End of well 1 Day 7 Days I

I/A I/A I/A A I

R*

R R R/A R* R R/F R*/F

Legend:

A F I R R*

Approve File Issue Receive Receive for relevant action Table 3.A- Report Form Distribution Chart

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4.4.1.

SUMMARY OF OPERATIONS (Land Rig or Jack-Ups)CONDUCTOR PIPE INSTALLATION Conductor Pipe (CP) is necessary to provide a riser and flow path for drilling mud from the well to the surface pit system. The outside diameter and the wall thickness of conductor pipe should be chosen according to previous experiences in the area and the selected casing profile. 30 OD x 1. wall thickness Fe42C has been selected as the Eni-Agip Division and Affiliates standard for world-wide exploration and development drilling activities, only if this CP is unsatisfactory should alternatives be considered. CP can be installed either by driving with a pile hammer or by pre-drilling a hole and cementing.

4.1.1.

Pile Hammers Diesel pile hammers (Refer to figure 4.a) are used for surface driving operations on conductor pipe. The driving depth of the conductor pipe is a function of the sediments in the ground. The most common used system is the Delmag - D44 or D46 which has a hammer weight of 18t with a variable delivery fuel pump. table 4.a, shows the specifications of others types of Delmag Hammers. The Manufacturer's Operating Procedures must be followed when planning driving operations. table 4.b, shows the normal and maximum blows/ft for different CPs and different hammer sizes. Ram Weight Wr (lbs)4,850 4,850 6,600 6,600 7,900 9,500 10,120 12,100 14,000

ModelD 22 D 22-02 D 30 D 30-02 D 36-02 D 44 D 46-02 D 55 D 62-02

Energy E (ft lbs)39,700 24,500 - 48,500 23,800 -54,250 33,700 - 66,100 38,000 - 83,100 43,500 -87,000 48,400 - 105,000 62,500 - 117,000 78,000 - 162,000

Hammer Weight Wh (lbs)*11,200 11,400 12,300 13,150 17,700 22,300 19,900 26,300 17,900

Blows/Min42 - 60 38 - 54 39 - 60 38 - 54 37 - 53 37 - 56 37 - 53 36 - 47 35 - 50

EWh3.6 4.3 4.2 4.8 4.7 3.9 5.3 4.4 5.8

* This is without any accessories - Add approx 25% of the total weight for accessories. Table 4.A - Delmag Diesel Hammer Specifications

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Figure 4.A- Typical Diesel Pile Hammer

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Pipe Size And Wall Thickness20 x .312 20 x .375 20 x .500 20 x .750 20 x 1.00 24 x .500 24 x .625 24 x .750 24 x 1.00 26 x .500 26 x .750 26 x 1.00 30 x .500 30 x .625 30 x .750 30 x 1.00 36 x .500 36 x .625 36 x .750 36 x 1.00 *48 x .750 *48 x 1.00 * With adapter

Blows Per ft:Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum Normal Maximum

D 2265 - 70 90 65 - 90 120 100 - 150 160 140 - 180 200 90 - 110 150 100 - 120 170 120 - 150 200 150 - 200 250 100 - 150 200 150 - 180 250 200 - 220 300 150 - 200 250 200 - 225 275 250 - 300 350 300 - 350 400 160 - 210 260 210 - 235 280 260 - 310 360 320 - 360 425

Hammer Size D 30

D 44

55 - 80 110 100 - 120 140 120 - 150 170 80 - 100 140 90 - 110 160 110 - 140 180 150 - 180 200 90 - 100 170 110 - 150 200 175 - 200 250 100 - 150 200 140 - 175 250 150 - 200 300 200 - 300 350 120 - 170 220

100 - 130 150 130 - 160 180 150 - 200 250

200 - 250 350 250 - 350 400

120 - 140 160 150 - 170 190 180 - 210 280 170 - 180 200 180 - 200 300

Table 4.B - Blows/ft for Various CPs and Hammers

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The Franks Hydrohammer is an intelligent hammer due to the sophisticated electronic control design. This control system is capable of regulating the energy for each impact. The net energy applied to the pile, which is measured during every blow, is monitored and can be regulated from the maximum to 5% or less. Since the measure of energy is precisely known, the force applied to the pile can be accurately computed. One particularly unique advantage of the Hydrohammer is the control systems ability to shut off the ram automatically if the pile starts to run ahead of the hammer in soft soils, e.g. due to: The hammer is not positioned correctly on the pile. Stroke rate becoming too high. Blow energy is too high.

Other advantages unique to this hydraulic hammer are: It can operate at any angle, even horizontally. It has an optional printer available to produce a report of the piling operation. It can be used onshore or offshore, in air or submerged under water.A

B

E

and table 4.c shows a Franks Hydrohammer Type S-90.

D

C

Figure 4.B - Franks S-90 Hydrohammer

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S-90 Specifications Max. pile energy/blow Min pile energy/blow Blow Rate (max. energy) PEW Ratio Weights Ram Hammer (in air) Flat-bottom anvil Pile sleeve incl. ballast Total weight in air Total weight submerged 4.5t 10,000lbs 9.2t 20,300lbs 0.8t 1,800lbs 4.2t 9,300lbs 14.2t 31,400lbs 11t 24,300lbs Dimensions Outside Dia. of hammer (A) Length of hammer (B) Sleeve for piles up to OD (C) Length of the hammer with sleeve and ballast (E) 610m 24ins 7,880 m 310ins 915m 36ins 9,900mm 390ins 280bar 4,000psi 350bar 5,000psi 220l/min 58gal/min 140KW 32mm 1.25ins Table 4.C - Franks S-90 Hydrohammer 90 kNm 66,000ft lbs 3 kNm 2,200ft lbs 50lb/min 8.2 kNm/t 2.8ft lbs/lbs

Hydraulic Data Operating Pressure Max. pressure Oil Flow Power Pack Hydraulic hose (ID)

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ENI S.p.A. Agip Division4.1.2. Final Refusal Depth

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The following procedure details the determination of final refusal depth. 1) When the driving depth of the conductor pipe is not specified in the Drilling Programme, the final depth of the driving is the refusal depth. The refusal value generally used is 1,000-1,100 blows/metre. Local experience could dictate a different refusal value. The driving depth can be predetermined by conducting soil boring analysis. Examine offset well data for depths and potential problems in order to determine if the CP depth is adequate. 2) The driving depth of the conductor pipe which is specified in the Drilling Programme is established with the following formula: Hi = [df x (E+H) - 103 x H]/[1.03 - df + 0.67 x (GOVhi - 1.03)] where: Hi E H df = = = = Minimum driving depth (m) from seabed Elevation (m) distance from bell nipple and sea level Water depth (m) Maximum mud weight (kg/l) to be used integrated density of sediments (kg/dm /10m)3

GOVhi =

If the refusal depth does not meet this value, internal washing may be required. CP internal washing might be necessary several times before reaching the planned depth. 3) It should be noted that if there is a high refusal value in very hard formations, the CP shoe could collapse.

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Conductor Pipe Connections Conductor pipe joints installed on land rigs, are usually connected by welding bevelled prepared ends of the pipes together. This is a time consuming operation that requires an average of three hours per joint. On a Jack-up, to reduce the time of the operations and when it is practicable, driveable threaded quick connectors (i.e. the RL-4) and driveable squnch joint connectors such as the Fast Realising Joint (i.e. the ALT-2), should be used. a) A Squnch Joint (Refer to figure 4.c) is a threadless automatic mechanical lock/release connection that makes up without rotation. The extremely strong weight-set connection is well suited for connecting large diameter conductor joints, and connecting the casing to the wellhead housing extension. The type ALT-2 (Refer to table 4.d) heavy-duty squnch joint is used for pipe joins generally up to 36 OD, but larger sizes are available. It is easily stabbed, driveable, reusable and can be released mechanically. It is suitable for the severest conditions above the mud line and can be used below the mud line when the conductor is driven into place. The 20 ALT-2 is an ideal highpressure housing extension connector, with an internal pressure rating of up to 5,000psi. The type ST-2 standard duty squnch joint (Refer to table 4.d) is not a driveable connector. It is used to connect pipe joints up to 30 OD, and is run into a pre-drilled hole and cemented in place. It is recommended for use above the mud line and is reusable and mechanically released. b) The Quick Thread Connection RL-4 (Refer to Table) is a very rigid connection for conductor and casing connections and requires just one-quarter turn for full make up. The helix angle of the patented, interlocking thread form, in combination with other connector geometries creates a preload force between the pin and box. The 30 and larger RL-4 conductor connectors have a generous shoulder for efficient driving. Four identical threads 90 apart make-up simultaneously. The thread interface is tapered at 4 per ft of diameter. The connector box has four slots cut on the OD, close to the shoulder of the box and the connector pin has four recessed grooves cut on its OD adjacent to the slots on the box. To activate the anti-rotation tab, a 90 incision is made with the impact tool into the anti-rotation slot. A strip of metal is bent into the recessed groove in the pin which provides a positive mechanical lock. It does not need power tongs for make-up and is releasable and reusable. It has a high 9 stab angle with dual stab guides. A negative 5 backrake thread interlock reduces belling tendency. The standard specifications for some selected pin and box sets are shown in table 4.d.

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Squnch Joint Connectors

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Table 4.D - Squnch Joint Connectors (continued)

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Squnch Joint

Quick Thread Connector

Broad Shoulder For Heavy Driving

Positive Stop Load Shoulder (Drive Shoulder) Stab Guide

Two-Step Contured Nose For Easy Stabbing

O - Ring Seal On

Self-Energizing, Single Load Shoulder Snap Ring For Fast, Positive Makeup Release Port

O - Ring Seal On Box (Two O - Ring Seals May Be Used For Improved Fatigue Resistence)

9 Stab Angle

Anti Rotation Pin/Slot

Wide Elevator Shoulder For Easy HandlingStab Guide

Elevator Shoulder

Figure 4.C - Squnch Joints and Quick Connectors

Pipe OD (ins) 30 36 38 42

Pipe Wall Connector Connector Thickness OD ID (ins) (ins) (ins) 1.00 31.63 27.50 1.50 2.00 1.00 36.81 39.50 43.63 31.75 31.10 39.50

Tension Capacity (kips) 4,600 10,000 13,500 7,063

Bending Capacity (kips ft) 2,800 5,250 12,000 4,730

Internal Pressure (psi) 4,670 3,900 4,000 2,300

Weight Pin & Box (lbs) 625 1,000 2,300 1,523

Table 4.E - RL-4 Rapid Lock Conductor Connector Standard Specifications (For Selected Pin and Box Sets)

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ENI S.p.A. Agip Division4.1.4. 30" CP Driving Procedure Material Requirements

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The following materials shall be available on the rig upon arrival on location: 30" conductor pipes as per the Drilling Programme (squnch joints, rapid lock connectors or welded preparation). Pile hammer. Equipment for handling joints. Welding machine, if using welded connections. 26" bits. 26" stabs as per the BHA program. 20" casing. 20" casing equipment (shoe, etc.). Plate for 5" DP (inner-string). 20" cementing plug (for emergency). 20" circulating head. 1 17 /2 bits. 1 17 /2 stabs as per BHA program. 1 12 /4 bit and stabs for pilot hole, if necessary. Sufficient cement for a 20" cementing job. Material for light slurry, if needed. Mud materials enough to drill a 26" hole, plus materials for mixing kill mud. LCM materials. Sealing adapter assembly for 20 casing cementing job (with 20" 5" DP centralisers). Wellhead equipment for 20" casing.

If quick joint is to be used, the following equipment shall be available: Hydraulic tong 30 type Joy AA -X. Two hydraulic clamp 30 250t. Side door elevator. Hydraulic power unit.

During the installation of the drilling rig, the following operations shall be carried out: 1) 2) 3) Inspect materials as per the above list. Mixing mud (this operation is to be started as soon as the rig is in operating condition). Rig up for driving operations on the 30" conductor pipe.

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Running Procedure, if a quick joint system is used: 1) The length of each joint will be 12-15m (40-50ft) approximately, unless using nono standard specification. The driving shoe shall be built as per figure 4.d with a 45 internal bevel on the lower end. Each joint will be lifted on to the rig floor with a side door elevator, 30 x 150t. Each joint will be run in hole with a hydraulic clamp, 30 x 250t. The casing string will be hung of on the slips with a hydraulic clamp, 30 x 250t.

2) 3) 4)

Running Procedure, if a welded joint system is used: 1) 2) The 30" conductor pipe end has to be checked in order to ensure this is a maximum o angle of 30 for welding operations. The length of each joint will be 12-15m (40-50ft) approximately, unless non standard o specification. The driving shoe shall be built as per figure 4.d with a 45 internal bevel on the lower end. Each joint of CP will have two pad eyes installed appropriately dimensioned and welded 1.5m below the upper end (Refer to figure 4.e ) and one lifting eye welded close to the lower end to permit easy handling with the rig crane. Do not weld on pad eyes if internal or external elevators are available. A 31" false rotary table, to ensure better pipe stabbing, shall be positioned on top of the rotary table (Refer to figure 4.f) The diesel pipe hammer shall be positioned on the rig floor prior to driving operations and all equipment shall be inspected. Every conductor pipe joint shall be measured and marked. Pick up the shoe joint with the travelling block (Refer to figure 4.g), cut and remove the lifting eye, run the joint through the 31" false rotary table. Land the joint on the pad eyes. Pick up the next joint and add to the shoe joint. The connection is obtained by welding the pipe ends. Pick up another conductor pipe with the travelling block, cut and remove the pad eyes on the shoe joint. Lower the string until the conductor pipe shoe reaches the bottom of the cellar or the sea bed, if on a Jack-Up. With the travelling block and the slings, pick-up and stab the pipe hammer onto the last joint. Begin driving operations on the conductor pipe, closely monitoring the first blows as the penetration may be very high. Stop hammering once the pad eyes are about 0.5m above the 31" false rotary table. Do not remove the pad eyes. Remove the pipe hammer. Pick-up the next joint, make the connection, remove the pad eyes and lifting eye on previous joint and continue driving operations. Continue until the planned penetration or the maximum blowing energy is reached (Refer to the Drilling Programme).

3)

4) 5)

6)

7) 8) 9) 10) 11) 12) 13) 14) 15)

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Figure 4.D - Drive Shoe

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Figure 4.E - CP Pad Eyes

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Figure 4.F - False Rotary Table

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Figure 4.G - CP Handling Rig Up

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If the maximum blowing energy is reached before the requested penetration, proceed as follows: Remove the hammer. Install two pad eyes on the 30 CP joint 0.5m above the spider deck level. Suspend the conductor pipe at rig substructure with four slings. Cut the 30 CP about 1.5m above spider deck level and remove the cut section. Remove the 31" false rotary table. Run a 26" bit + 3 x 9" DC + HW-DP and wash the conductor pipe down to 0.5m above the present CP shoe. Pull the bit out of the hole. Install the 31" false rotary. Pick up the cut section of conductor pipe and weld it on to the 30 CP string. Disconnect the suspension slings and cut the pad eyes. Pick up the pile hammer and resume driving operations again until the planned depth is reached. This CP internal washing operation may be repeated several times before reaching the planned depth. Cut the 30" conductor pipe at a specific depth (according to the drilling programme) below the rotary table and install the riser bell nipple and diverter assembly. Lay down the 31" false rotary from the rig floor. Install two pad eyes on the CP just above spider deck level and anchor the conductor pipe with four slings to the rig substructure (if required). Jack-up drilling in deep water, often experience problems with conductor pipe tensioning. Normal cables and turnbuckles are not sufficient for the wind, wave, current and temperature conditions which can cause movement when constant tension must be maintained. To resolve these conductor pipe tensioning problems, a multiple hydraulic cylinder tensioning system may be used.

12)

13) 14)

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2)

3)

4)

5)

6) 7) 8) 9) 10)

Run a 26" bit + float valve + 36" Hole Opener + 1 x 9" Monel DC + 1 x 9" Spiral DC + 5" HWDP + 5" DPs; in offshore operations whith Jack-Ups down to the seabed and measure the water depth. Drill to the depth of the first two joints using high viscosity mud (80-120 seconds Funnel viscosity) and at a very slow pump rate, in offshore operation whith Jack-Ups space out in order to avoid pulling the bit above the mud line at the first connection and. Drill the remaining 36" hole down to the a planned depth (with min WOB and at a higher pump rate) pumping fresh water (sea water in offshore operations whith JackUps) and a high viscosity mud cushion (at least 20-30 bbls every connection). Pump mud at a low flow rate if the well doesn't take fluid. At TD circulate the hole clean, displace the hole with gel mud (50% excess over open hole volume) and make a wiper trip; in offshore operations whith Jack-Ups make a wiper trip to the sea bed paying attention not to pull the bit above the mud line. Run back to bottom. If any fill is found, repeat the previous step otherwise displace the hole with gel mud (100% excess over theoretical hole volume). Take a directional survey and pull the 26" bit + 36" HO. Run the 30" x 1" thick CP and cement it in the hole using an inner string and sealing adapter (Refer to the Casing Running and Cementing section). Install two pad eyes on the CP just above the spider deck level and anchor the conductor pipe with four slings to the rig substructure, if required. Cut the 30" CP at the specified depth below rotary table according to the Drilling Programme and make up the diverter assembly. Install the bell nipple and diverter assembly. Run the 26" bit and perform a diverter function test from the driller's panel and remote station as follows: a) Close the diverter around drill pipe and circulate through both diverter lines. b) c) Gradually build up to maximum pump rate and record the pressure. Open the diverter packer. If a mud line suspension system is used, Refer to section 12.4.

Note:

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8)

9)

10)

11) 12) 13)

14) 15)

16) 17)

18) 19)

Run a 26 bit and perform a function test; in offshore operations whith Jack-Ups before fill the riser with seawater and check the level. Run the 26" bit + float valve + BHA, specified in the Drilling Programme. Test the diverter function by circulating with drilling water. Test the lines, all relative valves and operating functions. Locate the top of the fill inside the 30 conductor, record and report the depth. Clean out the 30" CP with high viscosity mud at a starting pump rate of 3,000l/m reduced to 500l/m when reaching the proximity of the 30" shoe. Run a Gyroscope inside the 30" conductor and perform a directional survey. 1 Run a 26" bit with a 9 /2" Downhole Motor and drill to the 20" casing depth according to the programme, allowing a 9-10 m (30 ft) pocket below the 20" shoe. It is advisable to use the nudging hole technique in this phase (max. drift angle is 3) Start drilling using high viscosity mud with reduced parameters (i.e.: Q = 1000l/m, WOB = 0.3t, rpm = 100-120) for the first two joints, in order to prevent under washing of the nearby casing. Increase the pump rate as per the Drilling Programme down to the planned 26 hole depth. While drilling, the mud viscosity must be kept at high values as per the Mud Programme while keeping the mud density as low as possible. The desilter and desander must be kept in operation. Conduct a wiper trip to the 30" shoe and, if it is good, circulate the hole volume reciprocating the drill string. If an overpull or fill occurs at the bottom, ream the concerned hole section again. Displace the open hole with high viscosity mud (80-100sec Funnel viscosity) and pull out of the hole to run the 20" casing. Take a directional survey as per the Directional Control & Surveying Procedures. If a pilot hole is required to nudge the hole, due to drillability problems with the 1 formation or to kick-off above the 20 shoe depth, drill the section with a 17 /2 bit and 1 9 /2 drilling turbine. At the 20 casing depth, spot a pill and pull-out. 1 Open the hole to 26 until 9-10m (30ft) of 17 /2 pocket remains. Perform a check trip to the 30 shoe and back to bottom, clean out any fill and spot viscous mud in the open hole section prior to pulling out of hole for running the 20 casing. Pick up enough drill pipe to reach the planned casing shoe depth with stinger and stand back in the derrick. Run the 20" casing, and then run the inner string. Insert the stinger in the casing shoe and circulate for 10 mins max. to test the stinger seals, checking the casing/DP annulus level. Cement the 20" casing as per cementing section. Wait on cement. Remove the bell nipple and diverter assembly, cut and recover the 20" casing above the cellar deck level as per the Drilling Programme. Weld on the bottom base flange and test it. As soon as the cement samples are hard, run a Gyroscope survey inside the 20" casing from top of the cement to surface. This will be used as the tie-in to any

20) 21)

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22) 23)

previously taken directional survey. Install the high pressure riser drilling spool, BOP stack and test them as per the Well Control Policy STAP P1M6150-7). If skidding the derrick for the next hole, cover the previous welded flange with a plate to prevent any objects dropping into the hole.

4.2.2.

Single Well 1) Prior to drilling out the 30 CP shoe, mix approx. 50-60m of kill mud at 1.4 SG to be ready for use if encountering shallow gas; in offshore operations whith Jack-Ups fill the 30 riser with sea water and check the level. Run a 26" bit + float valve + BHA + 1 stand of DP and perform a diverter function test, i.e.: a) Fill up the well with water. b) c) d) Note: 4) 5) Close the diverter around the drill pipe and circulate through diverter lines. Record the time to operate the functions. Gradually build up to the max. pump rate and record the pressure. Open the diverter packing. The diverter system is not a blow-out preventer and is not designed to hold pressure, but only to direct flow far from the rig . Drill the 26" hole down to the planned depth as per the Drilling Programme. Begin drilling with an unweighted gelled mud with reduced parameters (Q = 1000l/m, WOB = 0-3 t, rpm =100-120) for the first two joints, then increase the pump rate as per the Drilling Programme. At 26" hole TD, circulate a volume of mud equal to the capacity of the drilled section. Perform a wiper trip to the 30" shoe and back to bottom again. Clean out any fill and circulate to condition the mud. Take a directional survey with a single shot 10m below the 30" shoe then every 150m to the 26" hole TD. Run and cement the 20" casing as per the Casing Running and Cementing section. Wait on cement. Remove bell nipple and diverter assembly. Cut and recover the 20" casing above celler level or spider deck level In offshore operations whith Jack-Ups as per the rig specifications. Weld on the bottom base flange and test it. Install the drilling spool, BOP stack and test them as per the Well Control Policy STAP P1M6150-7).3

2)

6) 7) 8) 9) 10) 11) 12) 13)

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Single Well Using Pilot Hole Technique 1) Prior to drilling out the 30" shoe, mix approx. 50-60m of kill mud at 1.4SG to be used in case of encountering shallow gas; in offshore operations whith Jack-Ups fill the 30 riser with sea water and check the level. Run a 26" bit + float valve + BHA + 1 stand of DP and perform diverter function test: a) Fill up the well with water. b) c) d) Note: 4) 5) 6) Close the diverter around the drill pipe and circulate through diverter lines. Record the time to operate the functions. Gradually build up to the maximum pump rate and record the pressure. Open the diverter packing. The diverter system is not a blow-out preventer and is not designed to hold pressure, but only to direct flow far from the rig. Drill out the 30" shoe and circulate to clean out the hole. Pull the 26" bit. 1 1 Run a bit size between 12 /4 to 17 /2 + Float Valve + BHA. Drill the pilot hole to the 20" casing point with the following procedure: a) Limit penetration rate to one joint per hour. b) c) d) e) Limit pump rate to 1,000l/m for first two joints below the shoe then increase the pump rate as per the Hydraulic Programme. Stop drilling and monitor for any significant show. Circulate any gas show to surface. While pulling out of the hole if swabbing occurs, run back to bottom and circulate until control is re-established. Continually observe returns from the annulus. If there are partial losses, cease drilling and circulate the hole clean before recommencing drilling operations (Refer to loss circulation remedial operations, section 17).3

2)

7) 8) 9) 10)

11) 12) 13) 14) 15) Note:

The pilot hole should be 9-10m (30ft) deeper than 20" casing setting depth. Take a directional survey with a single shot 10m (30ft) below the 30" CP shoe and at every 150m (500ft) to TD. Perform a wiper trip to the 30" shoe and back to bottom again. Clean out any fill and circulate to condition the mud. Pull out of the hole. Run a 26 bit with BHA and enlarge the pilot hole to the casing point and perform a check trip to the 30 shoe then back to bottom. Clean out any fill and spot viscous mud in the open hole section prior to pulling out of hole for running the 20 casing. Run and cement the 20" casing with an inner string as per the Cementing section 12. Wait on cement. Remove bell nipple and diverter assembly. Cut and recover the 20" casing above celler level or spider deck level In offshore operations whith Jack-Ups as per the rig specifications. Weld on the bottom base flange and test it. Install the drilling spool, BOP stack and test them as per the Well Control Policy STAP P1M6150-7). If a mud line suspension system is being used, refer to section 15.5.

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2) 3) 4) 5)

6) 7)

8) 9) 10) 11)

12) 13) 14) 15)

Run a 17 /2 " bit and BHA. Drill out the 20 float collar, cement, casing shoe and wash down to the rat hole TD. If it is planned to drill a long section, install a well head bore hole protector into the base flange. Drill 5m (15ft) of new hole, condition the mud and perform a leak off test (Refer to section 11). 1 Resume drilling with the 17 /2 bit using the proper BHA for either a vertical or deviated hole (Refer to section 8.1). 1 Drill the 17 /2" hole down to KOP (if in a deviated hole phase) and change the BHA for 1 the build up. If a well is to be vertical, drill the 17 /2" hole to the casing point. Drilling parameters and hydraulics will be in accordance with the Contractor Directional Operators instructions (if present) or as per the Drilling Programme. Mud and bits will be as per the Drilling Programme. Take a directional surveys using a MWD tool and/or single shot. 3 At the 13 /8 casing point, circulate the shakers clean. Make a wiper trip to the 20" casing shoe. Run to bottom reaming any tight spots, circulate to condition the mud and pull out of the hole. Run electrical logs as per the Geological Programme. Run a bit to bottom to check the hole, circulate to condition the mud and pull out of the 3 hole to run the 13 /8 casing. 3 Run and cement the single or dual stage 13 /8 casing (Refer to the Casing Running and Cementing section 12). Wait on cement. 3 Hang the 13 /8 casing on the bottom flange giving it additional tensile load calculated as per the Casing Design Manual (STAP P1M6110-8.3.4), if required, and cut the 3 13 /8" casing. Pick up the BOP stack. Nipple up the first intermediate casing spool and test it. Lay down the BOP stack. 3 Install the drilling spool, 13 /8 BOP stack and test as per the Well Control Policy STAP P1M6150-7). or install a wellhead protection cap and skid the rig as per the skidding sequence, if drilling cluster wells. If a mud line suspension system is being used, (Refer to section 12.4). Use the highest grade of 5" DP or HWDP when testing with a cup tester.

1

Note: Note:

table 4.f gives the specifications for Class 1 drill pipe.

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API Units DP (in) 5 5 5 5 5 5 5 5 5 Weight (lbs/ft) 19.5 19.5 25.6 19.5 25.6 50.0 19.5 25.6 25.6 Grade E-75 X-95 E-75 G-105 X-95 HWDP S-135 G-105 S-135API Units Max. Tensile Load (lbs) Rated Load (80% Load ) (lbs)

SI Units DP (mm) 127 127 127 127 127 127 127 127 127 Weight (Kg/m) 29 29 38 29 38 74.4 29 38 38 Grade E-75 X-95 E-75 G-105 X-95 HWDP S-135 G-105 S-135SI Units Max. Tensile Load (daN) Rated Load (80% Load) (daN)

395,595 501,087 530,144 553,633 671,515 690,750 712,070 742,201 954,259

316,476 400,870 424,115 442,906 537,212 552,600 569,656 593,761 763,407

176,000 223,000 239,900 246,400 298,800 307,000 316,900 330,300 424,600

140,800 178,400 191,920 197,120 239,040 245,600 253,520 264,240 339,680

Table 4.F - Class 1 Drill Pipe Specifications

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2) 3) 4) 5)

6) 7)

8) 9) 10) 11)

12) 13) 14) 15)

Run a 12 /4 bit and BHA. Drill out the 17 /2 float collar, cement, casing shoe and wash down to the rat hole TD. If it is planned to drill a long section, install a wellhead bore hole protector into the first casing spool. Drill 5m (15ft) of new hole, condition the mud and perform a leak off test (Refer to section 11). 1 Resume drilling with the 12 /4 bit using the proper BHA for a vertical or deviated hole. 1 Drill the 12 /4 hole down to KOP and, if in a deviated hole phase, change the BHA for 1 the build up. If the well is to be vertical, drill the 12 /4 hole to the casing point. The drilling parameters and hydraulics will be in accordance with the Contractor Directional Operators instructions (if present) otherwise follow the mud and bits drilling parameters as per the Drilling Programme. Take a directional survey using a MWD tool and/or single shot. 5 3 At the 9 /8 casing point, circulate the shakers clean, make a wiper trip to the 13 /8 casing shoe and then run to bottom reaming any tight spots. Circulate to condition the mud and pull out of the hole. Run electrical logs as per the Geological Programme. Run the bit to bottom to control the hole, circulate to condition the mud and pull out of 5 the hole for running the 9 /8 casing. 5 Run and cement in the single or dual stage 9 /8 casing (Refer to the Casing Running and Cementing section 12.1.5). Wait on cement. 5 Hang the 9 /8 casing on the first intermediate casing spool giving it the additional tensile load calculated as per the Casing Design Manual (STAP P1M6110-8.3.4), if 5 required, and cut the 9 /8 casing. Pick up the BOP stack. Nipple up the intermediate casing spool and test it. Lay down the BOP stack. Install the drilling spool and BOP stack and test as per the Well Control Policy STAP P1M6150-7) or install a well head protection cap and skid the rig as per skidding sequence, if on cluster wells.

1

1

Note:

If a mud line suspension system is being used(Refer to section 12.4).

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2) 3) 4) 5)

6) 7)

8) 9)

Run a 8 /2 bit and BHA. Drill out the 13 /8 float collar, cement and casing shoe then wash down to the rat hole TD. If it is planned to drill a long section, install a wellhead bore hole protector into the second drilling spool. Drill 5m of new hole, condition the mud and perform a leak off test (Refer to section 11). 1 Resume drilling with the 8 /2 bit using the proper BHA for a vertical or deviated hole. 1 Drill the 8 /2 hole down to KOP and, if in a deviated hole phase, change the BHA for 1 the build up. If the well is vertical, drill the 8 /2 hole to the casing point. Drilling parameters and hydraulics will be in accordance with the Contractor Directional Operators instructions (if present) otherwise the mud, bits and drilling parameters will be as per the Drilling Programme. Take a directional surveys using a MWD tool and/or single shot. 1 5 At the 8 /2 casing point, circulate the shakers clean, make a wiper trip to the 9 /8 casing shoe and then run to bottom reaming any tight spots. Circulate to condition mud and pull out of the hole. Run electrical logs as per the Geological Programme. Run the bit to bottom to control the hole, circulate to condition the mud and pull out of the hole for running the 7" casing. A 7 liner or casing will be run only if required due to drilling problems before reaching the scheduled TD of well or if well tests have to be performed.

1

3

Note:

4.6.

RUNNING OF 7 CASING 1) 2) Run and cement in the single or dual stage 7" casing (Refer to the Casing Running and Cementing section 12). Wait on cement. Hang the 7" casing on the second intermediate casing spool giving it the additional tensile load calculated as per the Casing Design Manual (STAP P1M6110-8.3.4), if required, and cut the 7" casing. Remove the BOP stack. Nipple up the tubing spool and test it. 1 Re-install the BOP stack replacing the 5 lower pipe rams with 5 variables or 3 /2 rams and test them as per the Well Control Policy STAP P1M6150-7).

3) 4) 5)

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Check the inside diameter and rated load of the drill pipe. Run the 7 liner checking the weight and circulate the liner capacity after the making up of hanger to check the setting tool seal. Set the liner as per the Manufacturers Procedure or as per section 12.7. Cement as per the Casing Running and Cementing section 12, pull the stinger out of the liner, circulate out the excess cement and condition the mud. Pull ten stands, circulate and wait on cement. Circulate, pull the setting tool out of the hole using a spinner. 1 Run a 8 /2 bit to the liner top, clean free of cement and circulate. Perform a seal test of liner PBR and pull out of the hole. 1 Replace the 5 upper pipe rams with 3 /2 rams and test the BOP stack as per the Well Control Policy STAP P1M6150-7)

4.8.

DRILLING SLIM HOLE (57/8 OR 6) 1) 2) 3) 4) 5) Run a 5 /8 or 6 bit and drill out the cementing equipment in the 7 liner or casing. Drill 5m of new hole, condition the mud and perform a leak of test, if required. 7 Drill the 5 /8 or 6 hole to the planned depth following the specified Mud and Hydraulic Programme. At TD make a wiper trip up to the 7 casing shoe, run to bottom again and circulate to condition the mud. Pull out of the hole. Run logs as per the Geological Programme.7

4.9.

GENERAL GUIDELINES 1) 2) 3) All depth measurements will be referenced to RKB (rotary kelly bushing). A stock of diesel oil, enough for five days of operations, must always be kept on the rig A stock of barite (usually 100t is accepted as the minimum stock level calculated on the basis of the estimated overpressure development, refer to section 6.5) must be kept on the rig all time during drilling operations. BHA equipment and drill pipe must be inspected by non-destructive tests, as specified in the drilling rig contract, by the drilling contractor and any time as required by the ENI-AGIP representative. For severe or particular difficult drilling conditions refer to the Drill String/Bottom Hole Assembly Monitoring Procedures For Severe or Particular Drilling Condition (STAP-M-1-M-5008). As a general rule, the following guidelines should be used: Before the start of the Drilling Contract and every 1,500 rotating hours thereafter, all Drill Pipe bodies shall be ultrasonically inspected. They can be replaced by another previously inspected string to allow the NDT. Heavy weight drill pipe bodies shall be ultrasonically inspected every 3,000 rotating hours. They also may be replaced by previously inspected pipe to allow NDT.

4)

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5) 6)

7)

8) 9) 10) 11) 12)

13)

14) 15)

Before the start of the Drilling Contract and every 300 rotating hours, thereafter, all drill collars, drill-stem-subs and heavy weight drill pipe thread connections shall be magnetically inspected. They also may be replaced by previously inspected pipe to allow NDT. All stabilisers shall also be inspected every 300 hours as above. After 200-300 drilling hours (depending on the severity of work) remove four stands of 5 DP from the top of the BHA and replace them with new ones. The removed DP must be sent to the Contractor s workshop for inspection. Five stands of heavy weight drill pipe must be installed between drill collars and drill pipe. A float valve or a flapper valve, preferably the vented type, shall be placed immediately above the bit while drilling pilot holes and larger holes as per the Well Control Policy Manual (STAP P1M6150-9.3.1). A vented type allows easy recording of the shut in drill pipe pressure. A kelly cock shall be run both above and below the kelly. If using a top drive system, two inside BOPs; one Hydraulically Remote Operated and one Manually Operated, shall be used. Fishing operations or major changes in the BHA configuration must be discussed first with the operations base and approval obtained. Directional surveys must be performed as per the Directional Control & Surveying Procedures Blind or shear rams must be closed every time that tools are out of the hole. Record the distance between the rotary table and the BOPs. 1 1 A 4 /2 IF or 3 /2 IF pin, threaded circulating head, a kelly cock and a chicksan line, must be always present on the rig floor ready for use. For the BOP Testing Procedure, refer to section 5.4.4 BOP and Casing Tests. The drilling contractor shall be requested to submit a written procedure for BOP testing prepared specifically for the type of equipment installed on the rig, and obtain the Companys approval before starting operations. When a drilling jar is used, never drill past the last two metres of kelly. This practice allows cocking of the jar if pipe becomes stuck on the bottom. This also applies to top drive drilling systems. All tools run in hole must be measured and recorded for length, ID, OD, and a simple sketch provided and always available on the rig. When a PDC bit is used to drill out plugs and floating equipment, it is recommended to use a bit saver floating equipment and a non rotating plug set.

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TOP DRIVE DRILLING SYSTEMS The Top Drive Drilling System (Refer to figure 4.h and figure 4.i) consists of a drilling drive motor that connects directly to the top of the drill string. The motor, which provides the similar torques and speeds found in most independent rotary drive systems, is mounted to the rig's conventional swivel and is most commonly a DC drilling motor but hydraulic versions are also available. The drill pipe is rotated by the motor through reduction gearing. The swivel attaches to the travelling block and supports the string weight during hoisting operations. A unique pipe-handler system, consisting of a torque wrench and a conventional elevator, assists pipe-handling operations during make up and tripping. The elevator links and elevator are supported on a shoulder located on the extended swivel stem. These systems provide the same power as the rotary table without compromising the efficiency of the conventional hoisting equipment. However they save much time especially in drilling and reaming operations. as described below.

4.10.1. Drilling Ahead In HP/HT Formations The intention of this procedure is to maintain full pressure control during drilling operations and have the bit as close as possible to bottom in case a kick should occur. At the same time have the kelly valve close to the rotary table in order to carry out jobs which require a tool joint near the rotary table, e.g. installation of high pressure circulation lines, wireline lubricator, etc. The recommended procedure is: 1) 2) 3) 4) 5) Note: Make-up a kelly cock (15,000psi) to the single in the mouse-hole. The valve is to be in the open position. Make-up the single onto the top drive. Drill the single and break out above the kelly cock. Pick-up a new single with another kelly cock (15,000psi). Break out and lay down the kelly cock in the string. The kelly cock should be tested to the maximum anticipated surface pressure each time it is used.

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Figure 4.H - Typical Top Drive System

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Figure 4.I - Safety Valve Actuator System

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5.5.1.

SUMMARY OF OPERATIONS (Semi-Submersible)BOP STACK EQUIPMENT Floating drilling rigs may be equipped with either a one stack or a two stack BOP system. The two stack system is a combination of a 2,000 or 3,000psi large bore stack and a 5,000, 10,000 or 15,000psi stack. A one stack system is either a 10,000 or 15,000psi system. The following list gives the common sizes and various configurations: a) Single stack systems 18 /4" - 10,000 and 15,000psi WP 16 /4" - 10,000 and 15,000psi WP b) Two stack systems 21 /4" - 2,000 and 3,000psi WP 13 /8" - 5,000, 10,000 and 15,000psi WP c) Configurations 4 rams and 2 annulars 4 rams and 1 annular 3 rams and 1 or 2 annulars The most common configuration consists of a 13 /8" single stack system with 4 rams and 2 annulars (Refer to figure 5.a). This configuration is used in this section as an example to describe BOP equipment bearing in mind that same principles apply to all types. A conventional BOP stack consists of two sections, the lower which contains: Wellhead connector Ram preventers One annular preventer5 5 1 3 3

and the upper part which contains: Hydraulic connector Annular preventer Control system pods Flex joint to the top of which the riser is connected.

This upper part is referred to as the lower marine riser package (LMRP), the term stack being applied to the lower part. If it ever needs to be repaired during the course of the well, the package can be retrieved with the riser leaving the stack in position on the wellhead.

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Figure 5.A - Common BOP Stack Arrangement

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ENI S.p.A. Agip Division5.1.1. Wellhead Connector

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The wellhead connector profile must obviously match that of the subsea wellhead. In EniAgip Division and Affiliates use the most common profiles which are Vetco H4 and the Cameron Collet. 5.1.2. BOP Rams Besides being able to seal off the annulus around the drill pipe, the pipe rams can also support the weight of the drilling string if it needs to be hung-off. The maximum hang-off capacity is in the region of 600,000lbs (280t), depending upon ram and pipe size. To hangoff the string securely, the rams must be able to be locked in the closed position without risk of accidental opening. Cameron The Cameron U-type preventers use a wedge-lock device (Refer to figure 5.b) to accomplish this feature. It consists of a tapered wedge, hydraulically operated, which moves behind the tail rod of the ram operating piston when the ram is in the closed position. Since it can only move when ram lock pressure is applied and the ram is fully closed, all the ram lock cylinders on the stack are connected to just two common control lines, lock and unlock. Ram lock pressure is activated from the surface as an independent command. A pressure balance system is fitted to each ram lock cylinder to eliminate the possibility of seawater hydrostatic pressure opening the wedge-lock in the event that the closing pressure is lost. Shaffer On a Shaffer type LWS or SL rams, the locking device is actuated automatically whenever the ram is closed. This is called the Posilock, this system (Refer to figure 5.c) uses segments that move out radially from the ram piston and lock into a groove in the circumference of the opening cylinder whenever the ram is closed. When hydraulic closing pressure is applied, the complete piston assembly moves inward and pushes the ram toward the wellbore. With the ram closed, the closing pressure then forces a locking piston inside the main piston to move further inwards and force out the segments. A spring holds the locking piston in this position so that the segments are kept locked in the groove even if closing pressure is lost. When hydraulic opening pressure is applied, the locking cone is forced outward and this allows the locking segments to retract back into the main piston which is then free to move outwards and open the rams. Hydril On a Hydril preventer the ram lock device, called Multiple Position Locking (MPL), operates automatically through movement of ram pistons.

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Figure 5.B - Cameron 'U' Type Ram Lock Mechanism

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Figure 5.C - Shaffer 'Posilock' Ram Lock Mechanism

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ENI S.p.A. Agip DivisionVariable Rams

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In order to provide more flexibility and perhaps avoid having to pull the stack to change pipe 1 rams when drilling is to continue with 3 /2" drill pipes, variable bore pipe rams can be used. These are available in a variety of size ranges. They are capable also of being used for hang-off purpose though the weight they can support depends on the size of pipe they are closed around. However, variable bore rams are not recommended for stripping operations or for high temperature application. Blind/Shear Rams All subsea stacks contain blind/shear rams. These are designed to cut through pipe and then seal off the wellbore completely. For the location of the blind/shear rams and pipe rams refer to Eni-Agip Division and Affiliates Well Control Policy. 5.1.3. Annular Preventer When operating any annular blow-out preventer subsea, the hydrostatic pressure of the drilling fluid column in the marine riser exerts an opening force on the blow-out preventer. Therefore, the closing pressure required is equal to the surface installation closing pressure plus a compensating pressure to account for the opening force exerted by the drilling fluid column. On the Hydril GL preventer, which is primarily designed for subsea operations, a secondary chamber is used to compensate for the effects of subsea operations. The area of the secondary chamber is equal to the area acted on by the hydrostatic pressure of the drilling fluid column. The secondary chamber should be hooked up using one of three techniques. Two of the hook up techniques require adjustment of the closing pressure. The third hook up techniques requires the secondary chamber to be connected to the marine riser by mean of a surge absorber, so that the opening force exerted by the drilling fluid column is automatically counter balanced. Choke And Kill Line Outlets The two or more outlets on the stack are usually referred to as the choke and kill line outlets and is terminology taken from land drilling operations. For floating drilling the functions of each line are interchangeable since they are manifolded at the rig floor to both the rig pumps and the well control choke. For the position of the outlets on the stack, refer to the Eni-Agip Division and Affiliates Well Control Policy in the Well Control Policy Manual.

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These valves are usually mounted in pairs on both the choke and kill lines. They are opened hydraulically from the surface (0.6galls of fluid is typically required) but once the opening pressure is released, spring force automatically forces the gate valve closed. In deep water operations, the hydrostatic head of fluid in the opening line tends to open the valve. Some designs counter this be incorporating a system which transmits seawater hydrostatic pressure to an oil chamber on the spring side of the piston to compensate for this effect. Other designs have separate pressure-assist closing lines, figure 5.d shows a Cameron type AF fail-safe valve. Due to space limitation, the innermost valve on the stack is usually a 90 type with a flow target to avoid fluid or sand cutting. The outer valve is normal straight through and must be bi-directional, i.e. able to hold pressure from on top as well as below for testing the choke and kill lines. 5.2.1. BOP Control System The simplest form of BOP control is to assign a hydraulic line direct to each individual function. This presents little problem on land rigs where the large number of control lines required can be easily handled and the distance the control fluid has to travel is not great. On a subsea stack, this direct control is impractical, too many individual lines would be needed and the pressure drop inside them would be too great for the reaction time to be acceptable. For this reason, other systems have been developed based on the idea of using one main hydraulic line through which power fluid is sent to the stack and for pilot valves located on the stack to direct it to the various functions on command from the surface. These commands can be easily transmitted to the pilot valves either hydraulically, electrically or acoustically.o

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ENI S.p.A. Agip Divisiona)

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Hydraulic Control Systems

The main components of a hydraulic control system are shown in figure 5.e. A master hydraulic power unit supplies fluid to both pilot and hydraulic lines via accumulator bottles. The stack can be controlled from this unit or from a remote control panel on the rig floor or an electric mini panel usually located in the rig office. Pilot and operating fluid is provided to stack via one of two hose bundles each of which terminates in a Pressure Operating Device (conventionally termed yellow or blue pod) mounted on the lower marine riser package. The pods are identical, one providing complete backup for the other, either one being selected for use from the control panels. A typical 3 hose bundle is made up of a 1" supply hose for the power fluid and up to 64 x /16" hoses for the pilot fluid. Inside each pod the pilot lines terminate at pilot valves, each of which is connected to the common power fluid supply. When a particular stack function command is selected, pilot fluid pressure is directed down a pilot line to the corresponding pilot valve. This valve opens to allow the operating fluid to pass through it and then via a shuttle valve to the operating cylinder. The shuttle valves, which are mounted on the stack, allow the fluid to flow to the operating cylinder from the one selected pod only. The operating fluid is stored in the accumulator bottles at 3,000psi. This pressure is too high for normal operation of the annulars or rams and so the control pods contains regulators in order that closing pressure can be controlled as required (usually from 0 to 1,500psi), though higher if the situation demands it. The subsea regulator is controlled from surface via a pilot line and another line returns to a panel gauge and gives the readback operating pressure downstream of the regulator. Each control pod is mounted in a receptacle on the lower riser package and can usually be retrieved independently if repairs become necessary. Whilst the stack is being run, the hose bundle is fed out from a power driven reel which is equipped with a manifold so that control of 5 or 6 stack functions can still be maintained during running. Once the stack has been landed and sufficient hose run out, a special junction box on the reel enables a quick connection to be made between the pod and the hydraulic unit. Some of the hydraulic power fluid is stored in accumulators located on the stack in order to reduce closing times and also to provide a surge chamber effect for the annular preventers. All the operating fluid on the low pressure side of a function is eventually vented to the sea via the pilot valves. This, therefore, necessitates the use of environmentally friendly fluid which must also inhibit corrosion and bacterial growth as well as being compatible with anti-freeze additives. Large volume of fluid are prepared and stored near the hydraulic unit and are transferred automatically to the accumulators by electrically driven triplex pumps whenever accumulator pressure falls below a preset level. The pilot fluid circuit is closed. A turbine type flow meter mounted on the hydraulic unit measures the volume of hydraulic fluid used every time a function is operated. This can indicate for example whether or not a ram is closing fully or if there is a leak somewhere in the system. Apart from the close and open positions, it is also possible to place a function in block position. In this position, the lines carrying pilot pressure to the pilot valves have a vented spring action in the pilot valves which shuts off the power fluid supply and vents both sides of the operating piston.

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Figure 5.D - Fail Safe Valve

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Figure 5.E - Hydraulic Control System

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Electro-Hydraulic Control Systems

The object of the BOP control system is to move sufficient power fluid, at the required pressure, to the operating cylinder in the minimum time possibly. For very long lengths of hose bundles (over 2,000ft or 600m), friction losses inside the small pilot lines result in unacceptably long reaction times. If the diameter of these lines is increased, the hose bundle would be too bulky to handle so an alternative to a purely hydraulic control system is needed for deep water operations. This is satisfied by electro-hydraulic systems in which the hydraulic pilot valves are operated by electrical solenoid valves in the control pods through lines from surface. High pressure is taken from the main power line in the pod under control of the solenoid valve and is used as pilot pressure to open the pilot valve and thus allow regulated power fluid through to the operating cylinder. A further refinement to this system reduces all the separate electrical lines in the hose bundle to only two, down which coded multiplexed signals are transmitted. A multiplex package in the control pod decodes these signals and activates the corresponding solenoid valve. c) Acoustic Control System

Although in both the control systems described above, redundancy is assured through the use of two identical control pods, a further fully independent system is sometimes desired for complete back-up for contingency. To suit this requirement, acoustic control systems have been designed which can operate certain selected vital stack functions even if the rig is forced off location and, therefore, is not physically attached to the wellhead. This system basically uses a portable battery powered surface control unit connected to either a hull mounted or portable acoustic transducer to transmit an acoustic signal to a receiver on the stack. The receiver and the battery powered subsea control unit respond to the signal and transmit a reply back to the surface. A subsea valve package on the stack interfaces the acoustic and primary hydraulic systems via shuttle valves. It contain solenoid valves powered by the subsea battery pack (rechargeable only on surface) and pilot valves. Pilot fluid, provided from a separate pilot fluid accumulator with power fluid, is stored in a separate bank of stack mounted accumulator bottles. These store fluid at 3,000psi and can be recharged via the primary control system. The valve package contains no subsea regulator, hence, the 3,000psi is applied directly to the operating piston. A secure coded signalling system and noise rejection circuit eliminate the possibility of a function being executed by accident. To improve signal reception on the stack, two subsea transducer are mounted on long horizontal arms which swing down automatically on opposite sides of the BOP stack when it is lowered. The transmission range for such a system is in the order of one mile or 2km.

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As already described, the pods contain the regulators and pilot valves required to direct the hydraulic fluid to the various stack functions. The retrievable type is the most commonly used by the industry. The retrievable male portion of the pod contains all the pod valves, regulators and the hose bundle junction box. Should a pod valve, regulator or hose bundle malfunction, it is quicker and, hence, less costly to retrieve the pod than to retrieve the riser and the lower marine riser package. 5.2.3. Accumulators Accumulators are used to store hydraulic fluid under pressure. As much accumulator volume as possible is located on the subsea stack in order to reduce operating time and also to enable them to act as a surge chamber for the annular preventers. Surface accumulators are pre-charged with nitrogen to 1,000psi (70kg/cm ). Subsea 2 accumulators should be precharged with nitrogen to 1,000psi (70kg/cm ) + 45psi per 100ft 2 (10.3kg/cm per 100m) of water depth to compensate for the hydrostatic head of sea water. For total accumulator volume refer to the Eni-Agip Well Control Policy. 5.3. RISER AND DIVERTER SYSTEM The riser system provides communication between the wellhead and the rig floor in order for tools to be guided into the well and provide a return path for mud to surface. A riser systems consists of a number of elements: a) b) c) d) e) Diverter System Slip Joint Riser sections Lower Flex Joint or Ball Joint Riser Coupling2

The most important single parameter in the design and operation of a marine riser is the tension applied at the top of the riser. This tension is provided by a system of pneumatichydraulic pistons attached to wire ropes which are in turn attached to the outer barrel of the slip joint. The tension is conveyed through the outer barrel, into the riser string and down to the ocean floor where it is attached to the wellhead. The slip joint, or telescopic joint, allows the riser to change length as the vessel heaves, as the depth changes due to tides, or when the vessel moves laterally away from the wellhead. To reduce the bending moments in the riser and, therefore the induced stresses, a lower flex or ball joint is attached to the top of the BOP stack and an upper ball joint, called the diverter ball joint, is located below the diverter on top of the inner barrel of the slip joint.

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The diverter and the diverter ball joint are attached between the underside of the drilling floor and the riser slip joint inner barrel. The drill string and drilling tools are inserted into the riser through the diverter which also contains the flowlines for circulating the drilling mud. All risers have integral choke and kill lines. These are permanently attached to the riser joints and recessed into support flanges for protection. Some risers are also fitted with mud booster lines. These enter the riser immediately above the ball joint and are used to increase the velocity of the mud inside the riser when drilling with a relatively slow pump rate. The riser is used to run the BOP stack which weighs several hundred thousand pounds. This is a delicate operation and is usually performed only in calm weather conditions. While running the BOP, the motion compensator cannot be used so the BOP and riser are forced to move in time with heave the of the vessel. Landing the BOP is obviously a delicate task under these circumstances. All telescopic joints, flex/ball joint adapters and riser joints to be run must have a thorough magnaflux inspection of the riser couplings and pipe to coupling welds before being used. The telescopic joint tensioner ring and the riser handling tools should also be inspected by magnaflux. Welding on riser couplings, riser pipe, choke/kill lines or choke/kill line stab subs is strictly prohibited. 5.3.1. Riser Joints Riser joints are constructed of seamless pipe, usually 50ft (15m) long, but a selection of pup joints are available so that the total length of the riser can be adjusted to suit any water depth. The pipe material and wall thickness are usually chosen based on the water depth in which 7 1 the vessel will be operating. In shallow water /16" or /2" wall thickness riser made of X-52 1 5 steel is commonly used. Higher strength materials such as /2" to /8" wall X-65 steel are used in deep water to withstand the higher stresses imposed by high riser tensions. Buoyancy can be added to the riser to reduce the tension applied. It is usually added for water depths beyond 1,000ft (300m). With buoyancy added the effective outer diameter of the riser is 38-44 and, hence increases the amount of storage space required on the rig. High strength risers are also required to reduce the risk of collapsing in deep water applications when it becomes evacuated or filled with gas. One option to prevent this is to insert a mechanical fill-up valve into the riser string which will fill the riser with seawater if it becomes evacuated. There are common riser sizes that correspond to the wellhead system and BOP stack bore size being used. They are classified by their OD, e.g.:

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Wellhead System 13 /8 16 /4 18 /4 21 /41 3 3 5

Riser Outer Diameter 16 18 /8 21 24 5

Table 5.A - Riser Joint/Wellhead Sizes 5.3.2. Riser Coupling There are many styles of riser coupling available with different methods for preloading the connector. The most important function of the preload is to maintain rigidity in the joint and preclude mechanical shifting in the presence of alternating bending loads. Alternating loading will cause less stress if the connector is working within the preload region, thus increasing fatigue life. Improper preloading and inadequate maintenance are the main causes of riser failures. 5.3.3. Slip Joint The slip joint, or telescopic joint consists of an outer barrel connected to the riser with a polished steel inner barrel connected to the diverter ball joint. Rubber packing elements seal the annular space between the two barrels whilst still allowing the inner barrel to scope up and down. The packing is usually actuated by air and/or hydraulic fluid pressure which is adjusted so that a small amount of mud is able to leak past the seal to provide lubrication. Split packings are used so that if a serious wear occurs they can be replaced without having to remove the inner barrel. Some slip joints have dual packers with the second packer being used as a back-up and, while diverting, can be energised to assist in sealing around the inner barrel. The slip joint is rated to the working pressure of the diverter but when the diverter is used it will most likely leak unless the packer pressure has been increased. The telescopic joint is a weak link in the diverter system and needs to be continuously monitored when diverting. A large ring to which the riser tensioner lines are attached is able to slide over the outer barrel and butts against a flange on top of the barrel. When tension is applied the ring bears against the flange to support the riser. 5.3.4. Tensioning System Riser tension is provided by a system of hydraulic pistons (tensioners) pressurised by compressed air. Large air accumulators are used to provide a soft spring effect. The air acts against the hydraulic fluid with almost constant pressure so that the tension in the wire rope remains constant over the stroke. From the tensioners the wire ropes run over sheaves and is turned to the outer barrel of the slip joint (Refer to figure 5.f).

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Figure 5.F - Riser Tensioning System

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As the vessel heaves downward, the angle of the wire rope with the vertical grows thus reducing the vertical component of the tension and vice versa when it moves upward. For this reason the sheaves are placed as close as possible to the path of the riser so that the cable will be nearly vertical. Further more the sheaves are pivoted so they can follow the angle of the wire rope as the riser moves about in the moonpool due to the vessel motion. As the wire rope passes over the sheaves on the tensioners, fatigue occurs. At regular intervals, depending on the severity of the sea state, each tensioner must be shut down and the wire line slipped so that the fatigued section is removed. 5.3.5. Lower Flex Joints The Flex Joint contains an elastomeric element (consisting of spherical layers of steel laminates and elastomeric pads) which is held in compression and flexes under shear. The advantages of the flex joint over a ball joint is that it requires no lubrication and no pressure balancing. The increased bending moment caused by the stiffness of flex joints causes an insignificant increase on bending stress in the riser pipe. The flex joint can deflect in any direction up to a max of 10 . 5.3.6. Diverter System a) Diverter System The subsea diverter system is an integral part of the marine riser system. Diverter mechanism consists primarily of a packing insert that can seal on drill pipe (or open hole with an insert plug), a control system, two flow lines, a ball joint and valving. The Regan (Hughes Offshore) KFD diverter is the most common system used on today's rigs. There are three basic models: KFDG (Gimble) which is used on rigs that do not have an upper ball joint. KFDH (Housing) used on many vessels having limited room between the main deck and the rotary floor. KFDS (Seal) which has its housing permanently mounted through or below the rotary beams.o

The H and S models come in reduced bore par or full bore designs. Each of these diverters is rated to 500psi working pressure. The housing on all three of these diverters are restrained from moving upwards by locking dogs or downwards by a shoulder or lower dogs. The diverter is designed to seal on pipe by pressuring up an outer packer which in turn squeezes on an insert packer. Manufacturers do not 1 recommend the closing of the packer on any pipe smaller than 4 /2 diameter. An insert plug should be installed when the pipe is not in the hole. The outer packer may rupture if closed without the insert being in place.

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ENI S.p.A. Agip Divisionb) Ball joint

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Most floating rigs utilise an upper ball joint located directly below the diverter. In this position it carries little load and its working tensile load is only the weight of the inner barrel of the slip joint. Due to this reduced operating load, the ball and soc

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