ARPO
ENI S.p.A. Agip Division
ORGANISING DEPARTMENT
TYPE OF ACTIVITY'
ISSUING DEPT.
DOC. TYPE
REFER TO SECTION N.
PAGE.
1
OF
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
ARPO
ENI S.p.A. Agip Division
IDENTIFICATION CODE
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2 OF 234
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.
ARPO
ENI S.p.A. Agip Division5.2.1. 5.2.2. 5.2.3. 5.3.
IDENTIFICATION CODE
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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.
ARPO
ENI S.p.A. Agip Division8.7. 8.8. 8.9. REDUCED BIT WEIGHT DRILL
STRING DESIGN
IDENTIFICATION CODE
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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
ARPO
ENI S.p.A. Agip Division14.3.2.
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140 0168
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
ARPO
ENI S.p.A. Agip Division 17. LOST CIRCULATION
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140 0
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
ARPO
ENI S.p.A. Agip Division
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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.
ARPO
ENI S.p.A. Agip Division
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140
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.
ARPO
ENI S.p.A. Agip Division
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REVISION STAP-P-1-M-6140
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.
ARPO
ENI S.p.A. Agip Division3.1.2. Other Well Site Reports BOP
Sketch
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140 0
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.
ARPO
ENI S.p.A. Agip Division3.3. REPORT DISTRIBUTION
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140 0
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
ARPO
ENI S.p.A. Agip Division
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140
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
ARPO
ENI S.p.A. Agip Division
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REVISION STAP-P-1-M-6140 0
Figure 4.A- Typical Diesel Pile Hammer
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ENI S.p.A. Agip Division
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REVISION STAP-P-1-M-6140 0
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
ARPO
ENI S.p.A. Agip Division
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REVISION STAP-P-1-M-6140 0
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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ENI S.p.A. Agip Division
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REVISION STAP-P-1-M-6140 0
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)
ARPO
ENI S.p.A. Agip Division4.1.2. Final Refusal Depth
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140 0
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.
ARPO
ENI S.p.A. Agip Division4.1.3.
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140 0
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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ENI S.p.A. Agip Division
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REVISION STAP-P-1-M-6140 0
Squnch Joint Connectors
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ENI S.p.A. Agip Division
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REVISION STAP-P-1-M-6140 0
Table 4.D - Squnch Joint Connectors (continued)
ARPO
ENI S.p.A. Agip Division
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REVISION STAP-P-1-M-6140 0
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)
ARPO
ENI S.p.A. Agip Division4.1.4. 30" CP Driving Procedure Material
Requirements
IDENTIFICATION CODE
PAGE
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REVISION STAP-P-1-M-6140 0
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.
ARPO
ENI S.p.A. Agip Division
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140 0
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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ENI S.p.A. Agip Division
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REVISION STAP-P-1-M-6140 0
Figure 4.D - Drive Shoe
ARPO
ENI S.p.A. Agip Division
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REVISION STAP-P-1-M-6140 0
Figure 4.E - CP Pad Eyes
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ENI S.p.A. Agip Division
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REVISION STAP-P-1-M-6140 0
Figure 4.F - False Rotary Table
ARPO
ENI S.p.A. Agip Division
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REVISION STAP-P-1-M-6140 0
Figure 4.G - CP Handling Rig Up
ARPO
ENI S.p.A. Agip DivisionNote: 1) 2) 3) 4) 5) 6) 7) 8) 9) 10)
11)
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140 0
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)
ARPO
ENI S.p.A. Agip Division4.1.5. Drilling And Cementing CP 1)
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140 0
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:
ARPO
ENI S.p.A. Agip Division4.2. 4.2.1. DRILLING 26" HOLE Cluster
Wells 1) 2) 3) 4) 5) 6) 7)
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140 0
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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REVISION STAP-P-1-M-6140 0
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)
ARPO
ENI S.p.A. Agip Division4.2.3.
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140 0
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.
ARPO
ENI S.p.A. Agip Division4.3. DRILLING 171/2 HOLE 1)
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140 0
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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ENI S.p.A. Agip Division
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REVISION STAP-P-1-M-6140 0
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
ARPO
ENI S.p.A. Agip Division4.4. DRILLING 121/4 HOLE 1)
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140 0
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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ENI S.p.A. Agip Division4.5. DRILLING 81/2 HOLE 1)
IDENTIFICATION CODE
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REVISION STAP-P-1-M-6140 0
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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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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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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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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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