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
TITLE
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: „ ƒ ‚ • € Issued by P. Magarini
E. Monaci C. Lanzetta A. Galletta
28/06/99 28/06/99 28/06/99
REVISIONS PREP'D CHK'D APPR'D
INDEX
1.
INTRODUCTION
8
1.1. Purpose of the document 8
1.2. implementation 8
1.3. UPDATING, AMENDMENT, CONTROL & DEROGATION 8
2.
WEATHER PREDICTION
9
3.
DOCUMENTATION
10
3.1. Reporting 10
3.1.1. Well Site Reports 10
3.1.2. Other Well Site Reports 11
3.2. Contractor Performance 11
3.3. Report Distribution 12
4.
SUMMARY OF OPERATIONS (Land Rig or Jack-Ups)
13
4.1. Conductor Pipe Installation 13
4.1.1. Pile Hammers 13
4.1.2. Final Refusal Depth 18
4.1.3. Conductor Pipe Connections 19
4.1.4. 30" CP Driving Procedure 23
4.1.5. Drilling And Cementing CP 30
4.2. Drilling 26" Hole 31
4.2.1. Cluster Wells 31
4.2.2. Single Well 32
4.2.3. Single Well Using Pilot Hole Technique 33
4.3. Drilling 171/2” Hole 34 4.4. Drilling 121/4” Hole 36 4.5. Drilling 81/ 2” Hole 37 4.6. RUNNING OF 7” CASING 37 4.7. RUNNING OF 7” LINER 38
4.8. Drilling Slim Hole (57/8” or 6”) 38
4.9. General GUIDELINES 38
4.10. Top Drive Drilling SystemS 40
4.10.1. Drilling Ahead In HP/HT Formations 40
5.
SUMMARY OF OPERATIONS (Semi-Submersible)
43
5.1. BOP Stack equipment 43
5.1.1. Wellhead Connector 45
5.1.2. BOP Rams 45
5.1.3. Annular Preventer 48
5.2.1. BOP Control System 49
5.2.2. Subsea Pods 54
5.2.3. Accumulators 54
5.3. RISER AND DIVERTER SYSTEM 54
5.3.1. Riser Joints 55
5.3.2. Riser Coupling 56
5.3.3. Slip Joint 56
5.3.4. Tensioning System 56
5.3.5. Lower Flex Joints 58
5.3.6. Diverter System 58
5.4. RUNNING THE BOP ANd RISER SYSTEM 61
5.4.1. BOP Stack And Riser Preparation 61
5.4.2. Running The Bop And Riser 62
5.4.3. Landing The BOP Stack 63
5.4.4. Testing The BOP Stack 63
6.
DRILLING MUD
64
6.1. General 64
6.2. Mud properties 64
6.3. Safety actions 65
6.4. Drilling with Oil-Based Mud 66
6.5. Minimum stock requirements 67
7.
TRIPPING AND FILL-UP PROCEDURES
68
7.1. General PROCEDURES 68
7.2. Tripping with a top drive 71
7.3. Flow checkS 71
8.
DRILLING STRING DESIGN/STABILISATION
72
8.1. STRAIGHT HOLE DRILLING 72
8.2. Dog-Leg And Key Seat Problems 72
8.2.1. Drill Pipe Fatigue 72
8.2.2. Stuck Pipe 73
8.2.3. Logging 73
8.2.4. Running casing 73
8.2.5. Cementing 73
8.2.6. Casing Wear While Drilling 73
8.2.7. Production Problems 73
8.3. HOLE ANGLE CONTROL 75
8.3.1. Packed Hole Theory 75
8.3.2. Pendulum Theory 76
8.4. DESIGNING A PACKED HOLE ASSEMBLY 76
8.4.1. Length Of Tool Assembly 76
8.4.2. Stiffness 76
8.4.3. Clearance 78
8.4.4. Wall Support and Length of Contact Tool 78
8.5. PACKED BOTTOM HOLE ASSEMBLIES 78
8.7. REDUCED BIT WEIGHT 81
8.8. DRILL STRING DESIGN 82
8.9. BOTTOM HOLE ASSEMBLY Buckling 85
8.10. SUMMARY RECOMMENDATIONS FOR STABILISATION 87
8.11. OPERATING LIMITS OF DRILL PIPE 89
8.12. GENERAL GUIDELINES 90
9.
DIRECTIONAL DRILLING
91
9.1. TERMINOLOGY AND CONVENTIONS 91
9.2. CO-ORDINATE SYSTEMS 93
9.2.1. Universal Transverse Of Mercator (UTM) 93
9.2.2. Geographical Co-ordinates 94
9.3. RIG/TARGET LOCATIONS AND HORIZONTAL DISPLACEMENT 96
9.3.1. Horizontal Displacement 96
9.3.2. Target Direction 97
9.3.3. Convergence 97
9.4. HIGH SIDE OF THE HOLE AND TOOL FACE 98
9.4.1. Magnetic Surveys 99
9.4.2. Gyroscopic Surveys 101
9.4.3. Survey Calculation Methods 103
9.4.4. Drilling Directional Wells 105
9.4.5. Dog Leg Severity 110
10. CORING
112
10.1. CORE BARREL TYPES AND USES 112
10.1.1. Wireline 112
10.1.2. Marine Core Barrels 112
10.1.3. Rubber Sleeve 112
10.1.4. Conventional Core Barrel 112
10.1.5. Inner Tubes 114
10.1.6. Modified Barrels 114
10.2. GENERAL GUIDELINES 116
10.3. CORING PROCEDURES 117
10.3.1. Operating Instructions 117
10.3.2. Preparing for Coring 118
10.3.3. Starting of the Coring Operation 119
10.3.4. Possible Cause Of Pump Pressure Changes 120
10.3.5. Breaking Core (Making A Connection Or Pulling Barrel) 120
10.3.6. Recovery of the Core 121
10.4. Coring In Deviated Holes 123
10.4.1. Stabilisation of the Outer Barrel 123
10.4.2. Stabilisation of the Inner Barrel 123
10.4.3. Stabilisation of the Drill Collar Assembly 123
11. LEAK OFF TEST PROCEDURE
124
11.1. TEST PROCEDURE 125
12.1. Responsibilities 128
12.1.1. Casing Check List 129
12.1.2. Preparation For Casing Running And Cementing 129
12.1.3. Installation Patterns (For Mechanical Cementing Aids) 133
12.1.4. Preliminary Operations 137
12.1.5. Running Procedure 138
12.1.6. Casing Operations With A Top Drive 140
12.2. CRA CASING OPERATIONS 140
12.2.1. Preliminary operations 141
12.2.2. Handling and running CRA tubulars 141
12.3. CEMENTING AND DISPLACEMENT PROCEDURE 143
12.3.1. Single Or First Stage 143
12.3.2. Dual Or Second Stage 147
12.3.3. Double Stage Cementing In Deep Wells 150
12.4. Mudline Suspension Procedures 151
12.4.1. Cementing 20" Surface Casing (With Inner Strings) 151
12.4.2. Cementing Casings With Plugs 152
12.5. Post-Cementing Operations 152
12.6. Squeezing 153
12.7. LINERS 154
12.7.1. Preliminary Preparations 154
12.7.2. Running And Setting 155
12.7.3. Cementing 156
13. LOGGING
157
13.1. Logging While Drilling (LWD) COnsiderations 157
13.1.1. Advantages Of Using LWD 157
13.1.2. Onshore Planning 157
13.1.3. Rig Planning 158
13.1.4. Contractor Advanced Knowledge 158
13.1.5. Rig Monitoring System Requirements 158
13.1.6. Shock Mechanisms That Can Cause Lwd Tool Failure: 158
13.1.7. Solutions To Shock Problems: 158
13.2. Wireline logging 159
13.2.1. General Guidelines 159
13.2.2. Preparations 160
13.2.3. Quality Control 160
13.2.4. Handling Explosives 161
13.2.5. Handling Radioactive Sources 162
13.2.6. Logging Tool Fishing (overstripping method) 163
14. WELL ABANDONMENT
165
14.1. Temporary Abandonment 165
14.1.1. During Drilling Operations 165
14.1.2. During Production Operations 165
14.2. PERMANENT ABANDONMENT 166
14.2.1. Plugging 166
14.2.2. Plugging Programme 166
14.2.3. Plugging procedure 167
14.3. Casing cutting/retrieving 168
14.3.2. Stub Termination (Below A Casing String) 168
15. SURFACE WELLHEAD
169
15.1.1. PRELIMINARY CHECKS 169
15.2. BASE FLANGE INSTALLATION 169
15.2.1. Welding Procedure 169
15.2.2. Safety 171
15.2.3. Pressure Testing 171
15.2.4. Slips Installation 171
15.2.5. Casing Preparation 172
15.2.6. Primary And Secondary Packing Installation 172
15.2.7. Casing Spool Installation 173
15.3. RECOMMENDED FLANGE BOLT TORQUE 174
15.3.1. Slips Installation 177
15.3.2. Casing Preparation 177
15.3.3. Primary And Secondary Packing Installation 177
15.3.4. Tubing Spool Installation 178
15.3.5. Primary And Secondary Packing Group Test 179
15.4. COMPACT WELLHEAD 189
15.5. MUDLINE SUSPENSION 193
15.5.1. General Guidelines 196
15.5.2. Temporary Abandonment Procedure. 200
16. DRILLING PROBLEMS
201
16.1. STUCK PIPE 201
16.1.1. Differential Sticking 201
16.2. STICKING DUE TO HOLE RESTRICTION 202
16.3. STICKING DUE TO CAVING HOLE 203
16.3.1. Sticking Due To Hole Irregularities And/Or Change In BHA 204
16.4. OIL PILLS 205
16.4.1. Light Oil Pills 205
16.4.2. Heavy Oil Pills 205
16.4.3. Acid Pills 206
16.4.4. Free Point Location 206
16.4.5. Measuring The Pipe Stretch 207
16.4.6. Location By Free Point Indicating Tool 207
16.4.7. Back-Off Procedure 208
16.5. FISHING 209
16.5.1. Inventory Of Fishing Tools 209
16.5.2. Preparation 210 16.5.3. Fishing Assembly 212 16.6. FISHING PROCEDURES 212 16.6.1. Overshot 212 16.6.2. Releasing Spear 213 16.6.3. Taper Tap 213 16.6.4. Junk Basket 214 16.6.5. Fishing Magnet 214 16.7. Milling Procedure 214 16.8. Jarring Procedure 216
17. LOST CIRCULATION
217
17.1. Loss PREVENTIVE MEASURES 217
17.1.1. REMEDIAL ACTION (WHILE DRILLING) 218
17.2. Use of DOB AND DOBC PILLS 218
17.3. REMEDIAL ACTION (WHILE TRIPPING) 219
1. INTRODUCTION
1.1. PURPOSE 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-Agip’s 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-Agip’s 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.
2. WEATHER
PREDICTION
Weather 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.
3. DOCUMENTATION
3.1. REPORTING 3.1.1. 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 Initial Activity Report
• ARPO 02/A Daily Report (Drilling)
• ARPO 03/A Casing Running Report (General Data)
• ARPO 03/B Casing Running Report (Job Data)
• ARPO 04/A Cementing Job Report (General Data)
• ARPO 04/B Cementing Job Report (Job Data)
• ARPO 05 Bit Record
• ARPO 06 Waste Disposal Management Report
• ARPO 13 Well Problem Report
• ARPO 20/A Well Situation Report (Well) • ARPO 20/B Well Situation Report (Wellhead)
• FB 01 Contractor Service and Equipment Evaluation
• FB 02 Contractor Performance Evaluation
3.1.2. Other Well Site Reports BOP Sketch
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:
• String schematic • Component description • Outside diameter • Inside diameter • Capacity • Lengths • Depths. 3.2. 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 contractor’s operations or at the end of the well, whichever is applicable.
3.3. REPORT DISTRIBUTION
The following chart details the destination of, frequency and times that reports need to be distributed.
Form Freq. Period/ Rig Base Peit Arpo Teap Stap Others
Delay Cont Comp
ARPO-01 Each
Rig Start ofactivity I R/A R*/F R* F
ARPO-02/A Daily 1 Day I/A R* R* R R/F
ARPO-03/A Each Job With ARPO-02/A I/A R R* R* F ARPO-03/B Each Job With ARPO-02/A I/A R R* R* F ARPO-04/A Each Job With ARPO-02/A I/A R R* R* F ARPO-04/B Each Job With ARPO-02/A I/A R R* R* F
ARPO-05 End ofphase 1 Day I/A R R* F
ARPO-06 I/A R*
ARPO-13 activityOn 1 Day I/A R* R*
ARPO-20/A After job End ofphase I/A
ARPO-20/B After job End ofwell I/A R
FB-01 activityOn 1 Day I A R R* R/F
FB-02 Months6 7 Days I R/A R R*/F
Legend: A Approve
F File
I Issue
R Receive
R* Receive for relevant action
4.
SUMMARY OF OPERATIONS (Land Rig or Jack-Ups)
4.1. 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 Affiliate’s 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. Model Energy E (ft lbs) Ram Weight Wr (lbs) Hammer Weight Wh (lbs)* Blows/Min EWh D 22 39,700 4,850 11,200 42 - 60 3.6 D 22-02 24,500 - 48,500 4,850 11,400 38 - 54 4.3 D 30 23,800 -54,250 6,600 12,300 39 - 60 4.2 D 30-02 33,700 - 66,100 6,600 13,150 38 - 54 4.8 D 36-02 38,000 - 83,100 7,900 17,700 37 - 53 4.7 D 44 43,500 -87,000 9,500 22,300 37 - 56 3.9 D 46-02 48,400 - 105,000 10,120 19,900 37 - 53 5.3 D 55 62,500 - 117,000 12,100 26,300 36 - 47 4.4 D 62-02 78,000 - 162,000 14,000 17,900 35 - 50 5.8
* This is without any accessories - Add approx 25% of the total weight for accessories. Table 4.A - Delmag Diesel Hammer Specifications
Pipe Size And Hammer Size
Wall Thickness Blows Per ft: D 22 D 30 D 44
20 x .312 Normal Maximum 20 x .375 Normal 65 - 70 Maximum 90 20 x .500 Normal 65 - 90 55 - 80 Maximum 120 110 20 x .750 Normal 100 - 150 100 - 120 Maximum 160 140 20 x 1.00 Normal 140 - 180 120 - 150 Maximum 200 170 24 x .500 Normal 90 - 110 80 - 100 Maximum 150 140 24 x .625 Normal 100 - 120 90 - 110 Maximum 170 160 24 x .750 Normal 120 - 150 110 - 140 Maximum 200 180 24 x 1.00 Normal 150 - 200 150 - 180 Maximum 250 200 26 x .500 Normal 100 - 150 90 - 100 Maximum 200 170 26 x .750 Normal 150 - 180 110 - 150 Maximum 250 200 26 x 1.00 Normal 200 - 220 175 - 200 Maximum 300 250 30 x .500 Normal 150 - 200 100 - 150 Maximum 250 200 30 x .625 Normal 200 - 225 140 - 175 100 - 130 Maximum 275 250 150 30 x .750 Normal 250 - 300 150 - 200 130 - 160 Maximum 350 300 180 30 x 1.00 Normal 300 - 350 200 - 300 150 - 200 Maximum 400 350 250 36 x .500 Normal 160 - 210 120 - 170 Maximum 260 220 36 x .625 Normal 210 - 235 120 - 140 Maximum 280 160 36 x .750 Normal 260 - 310 200 - 250 150 - 170 Maximum 360 350 190 36 x 1.00 Normal 320 - 360 250 - 350 180 - 210 Maximum 425 400 280 *48 x .750 Normal 170 - 180 Maximum 200 *48 x 1.00 Normal 180 - 200 Maximum 300 * With adapter
The Frank’s 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 system’s 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.
and table 4.c shows a Frank’s Hydrohammer Type S-90.
Figure 4.B - Frank’s S-90 Hydrohammer A D B E C
S-90 Specifications
Max. pile energy/blow 90 kNm
66,000ft lbs
Min pile energy/blow 3 kNm
2,200ft lbs
Blow Rate (max. energy) 50lb/min
PEW Ratio 8.2 kNm/t
2.8ft lbs/lbs Weights
Ram 4.5t
10,000lbs
Hammer (in air) 9.2t
20,300lbs
Flat-bottom anvil 0.8t
1,800lbs
Pile sleeve incl. ballast 4.2t
9,300lbs
Total weight in air 14.2t
31,400lbs
Total weight submerged 11t
24,300lbs Dimensions
Outside Dia. of hammer (A) 610m
24ins
Length of hammer (B) 7,880 m
310ins
Sleeve for piles up to OD (C) 915m
36ins Length of the hammer with sleeve and ballast (E) 9,900mm
390ins Hydraulic Data
Operating Pressure 280bar
4,000psi
Max. pressure 350bar
5,000psi
Oil Flow 220l/min
58gal/min
Power Pack 140KW
Hydraulic hose (ID) 32mm
1.25ins
4.1.2. Final Refusal Depth
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 pre-determined 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 = Minimum driving depth (m) from seabed
E = Elevation (m) distance from bell nipple and sea level
H = Water depth (m)
df = Maximum mud weight (kg/l) to be used GOVhi = integrated density of sediments (kg/dm3/10m)
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.
4.1.3. 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, re-usable 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 high-pressure housing extension connector, with an internal high-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 re-usable 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.
Squnch Joint Quick Thread Connector
Figure 4.C - Squnch Joints and Quick Connectors
Pipe OD (ins) Pipe Wall Thickness (ins) Connector OD (ins) Connector ID (ins) Tension Capacity (kips) Bending Capacity (kips ft) Internal Pressure (psi) Weight Pin & Box
(lbs)
30 1.00 31.63 27.50 4,600 2,800 4,670 625
36 1.50 36.81 31.75 10,000 5,250 3,900 1,000
38 2.00 39.50 31.10 13,500 12,000 4,000 2,300
42 1.00 43.63 39.50 7,063 4,730 2,300 1,523
Table 4.E - RL-4 Rapid Lock Conductor Connector Standard Specifications (For Selected Pin and Box Sets)
Positive Stop Load Shoulder (Drive Shoulder)
Stab Guide
O - Ring Seal On Box (Two O - Ring Seals May Be Used For Improved Fatigue Resistence)
9° Stab Angle
Stab Guide
Elevator Shoulder Broad Shoulder For Heavy Driving
Two-Step Contured Nose For Easy Stabbing
O - Ring Seal On
Self-Energizing, Single Load Shoulder Snap Ring For Fast, Positive Makeup
Release Port
Anti Rotation Pin/Slot Wide Elevator Shoulder For Easy Handling
4.1.4. 30" CP Driving Procedure Material Requirements
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.
• 171/ 2” bits.
• 171/
2” stabs as per BHA program.
• 121/
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) Inspect materials as per the above list.
2) Mixing mud (this operation is to be started as soon as the rig is in operating condition). 3) Rig up for driving operations on the 30" conductor pipe.
Running Procedure, if a quick joint system is used:
1) The length of each joint will be 12-15m (40-50ft) approximately, unless using non-standard specification. The driving shoe shall be built as per figure 4.d with a 45o internal bevel on the lower end.
2) Each joint will be lifted on to the rig floor with a side door elevator, 30” x 150t. 3) Each joint will be run in hole with a hydraulic clamp, 30” x 250t.
4) The casing string will be hung of on the slips with a hydraulic clamp, 30” x 250t. Running Procedure, if a welded joint system is used:
1) The 30" conductor pipe end has to be checked in order to ensure this is a maximum angle of 30o for welding operations.
2) The length of each joint will be 12-15m (40-50ft) approximately, unless non standard specification. The driving shoe shall be built as per figure 4.d with a 45o internal bevel on the lower end.
3) 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.
4) A 31" false rotary table, to ensure better pipe stabbing, shall be positioned on top of the rotary table (Refer to figure 4.f)
5) 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.
6) 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.
7) Pick up the next joint and add to the shoe joint. The connection is obtained by welding the pipe ends.
8) Pick up another conductor pipe with the travelling block, cut and remove the pad eyes on the shoe joint.
9) Lower the string until the conductor pipe shoe reaches the bottom of the cellar or the sea bed, if on a Jack-Up.
10) With the travelling block and the slings, pick-up and stab the pipe hammer onto the last joint.
11) Begin driving operations on the conductor pipe, closely monitoring the first blows as the penetration may be very high.
12) Stop hammering once the pad eyes are about 0.5m above the 31" false rotary table. Do not remove the pad eyes.
13) Remove the pipe hammer.
14) Pick-up the next joint, make the connection, remove the pad eyes and lifting eye on previous joint and continue driving operations.
15) Continue until the planned penetration or the maximum blowing energy is reached (Refer to the Drilling Programme).
Note: If the maximum blowing energy is reached before the requested penetration, proceed as follows:
1) Remove the hammer.
2) Install two pad eyes on the 30” CP joint 0.5m above the spider deck level. 3) Suspend the conductor pipe at rig substructure with four slings.
4) Cut the 30” CP about 1.5m above spider deck level and remove the cut section. 5) Remove the 31" false rotary table.
6) Run a 26" bit + 3 x 9" DC + HW-DP and wash the conductor pipe down to 0.5m above the present CP shoe.
7) Pull the bit out of the hole. 8) Install the 31" false rotary.
9) Pick up the cut section of conductor pipe and weld it on to the 30” CP string. 10) Disconnect the suspension slings and cut the pad eyes.
11) 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.
12) 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.
13) 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).
14) 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.
4.1.5. Drilling And Cementing CP
1) 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.
2) 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.
3) 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 Jack-Ups) 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.
4) 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. 5) 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.
6) 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).
7) 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.
8) Cut the 30" CP at the specified depth below rotary table according to the Drilling Programme and make up the diverter assembly.
9) Install the bell nipple and diverter assembly.
10) 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) Gradually build up to maximum pump rate and record the pressure.
c) Open the diverter packer.
4.2. DRILLING 26" HOLE 4.2.1. Cluster Wells
1) 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.
2) Run the 26" bit + float valve + BHA, specified in the Drilling Programme.
3) Test the diverter function by circulating with drilling water. Test the lines, all relative valves and operating functions.
4) Locate the top of the fill inside the 30” conductor, record and report the depth.
5) 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.
6) Run a ‘Gyroscope’ inside the 30" conductor and perform a directional survey.
7) Run a 26" bit with a 91/2" 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°)
8) 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.
9) 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.
10) 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.
11) Displace the open hole with high viscosity mud (80-100sec Funnel viscosity) and pull out of the hole to run the 20" casing.
12) Take a directional survey as per the ‘Directional Control & Surveying Procedures’. 13) If a pilot hole is required to nudge the hole, due to drillability problems with the
formation or to kick-off above the 20” shoe depth, drill the section with a 171/2” bit and
91/2” drilling turbine. At the 20” casing depth, spot a pill and pull-out.
14) Open the hole to 26” until 9-10m (30ft) of 171/2” pocket remains.
15) 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.
16) Pick up enough drill pipe to reach the planned casing shoe depth with stinger and stand back in the derrick.
17) 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.
18) Cement the 20" casing as per cementing section. Wait on cement.
19) Remove the bell nipple and diverter assembly, cut and recover the 20" casing above the cellar deck level as per the Drilling Programme.
20) Weld on the bottom base flange and test it.
21) 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
previously taken directional survey.
22) Install the high pressure riser drilling spool, BOP stack and test them as per the ‘Well Control Policy STAP P1M6150-7)’.
23) 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. 50-60m3 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.
2) 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) Close the diverter around the drill pipe and circulate through diverter lines. Record the time to operate the functions.
c) Gradually build up to the max. pump rate and record the pressure. d) Open the diverter packing.
Note: 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 .
4) Drill the 26" hole down to the planned depth as per the Drilling Programme.
5) 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.
6) At 26" hole TD, circulate a volume of mud equal to the capacity of the drilled section. 7) Perform a wiper trip to the 30" shoe and back to bottom again. Clean out any fill and
circulate to condition the mud.
8) Take a directional survey with a single shot 10m below the 30" shoe then every 150m to the 26" hole TD.
9) Run and cement the 20" casing as per the Casing Running and Cementing section. Wait on cement.
10) Remove bell nipple and diverter assembly.
11) Cut and recover the 20" casing above celler level or spider deck level In offshore operations whith Jack-Ups as per the rig specifications.
12) Weld on the bottom base flange and test it.
13) Install the drilling spool, BOP stack and test them as per the ‘Well Control Policy STAP P1M6150-7).
4.2.3. Single Well Using Pilot Hole Technique
1) Prior to drilling out the 30" shoe, mix approx. 50-60m3 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.
2) Run a 26" bit + float valve + BHA + 1 stand of DP and perform diverter function test: a) Fill up the well with water.
b) Close the diverter around the drill pipe and circulate through diverter lines. Record the time to operate the functions.
c) Gradually build up to the maximum pump rate and record the pressure. d) Open the diverter packing.
Note: 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.
4) Drill out the 30" shoe and circulate to clean out the hole. Pull the 26" bit. 5) Run a bit size between 121/4“ to 171/2 + Float Valve + BHA.
6) Drill the pilot hole to the 20" casing point with the following procedure: a) Limit penetration rate to one joint per hour.
b) Limit pump rate to 1,000l/m for first two joints below the shoe then increase the pump rate as per the Hydraulic Programme.
c) Stop drilling and monitor for any significant show. Circulate any gas show to surface.
d) While pulling out of the hole if swabbing occurs, run back to bottom and circulate until control is re-established.
e) 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).
7) The pilot hole should be 9-10m (30ft) deeper than 20" casing setting depth.
8) Take a directional survey with a single shot 10m (30ft) below the 30" CP shoe and at every 150m (500ft) to TD.
9) 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.
10) 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.
11) Run and cement the 20" casing with an inner string as per the Cementing section 12. Wait on cement.
12) Remove bell nipple and diverter assembly.
13) Cut and recover the 20" casing above celler level or spider deck level In offshore operations whith Jack-Ups as per the rig specifications.
14) Weld on the bottom base flange and test it.
15) Install the drilling spool, BOP stack and test them as per the Well Control Policy STAP P1M6150-7).
4.3. DRILLING 171/2” HOLE
1) Run a 171/
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.
2) Drill 5m (15ft) of new hole, condition the mud and perform a leak off test (Refer to section 11).
3) Resume drilling with the 171/2“ bit using the proper BHA for either a vertical or deviated
hole (Refer to section 8.1).
4) Drill the 171/2" hole down to KOP (if in a deviated hole phase) and change the BHA for
the build up. If a well is to be vertical, drill the 171/2" hole to the casing point.
5) Drilling parameters and hydraulics will be in accordance with the Contractor Directional Operator’s instructions (if present) or as per the Drilling Programme. Mud and bits will be as per the Drilling Programme.
6) Take a directional surveys using a MWD tool and/or single shot.
7) At the 133/8” 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.
8) Run electrical logs as per the Geological Programme.
9) Run a bit to bottom to check the hole, circulate to condition the mud and pull out of the hole to run the 133/8” casing.
10) Run and cement the single or dual stage 13 3/
8” casing (Refer to the Casing Running
and Cementing section 12). Wait on cement.
11) Hang the 133/8” 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 133/8" casing.
12) Pick up the BOP stack.
13) Nipple up the first intermediate casing spool and test it. 14) Lay down the BOP stack.
15) Install the drilling spool, 133/8” 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.
Note: If a mud line suspension system is being used, (Refer to section 12.4).
Note: Use the highest grade of 5" DP or HWDP when testing with a cup tester. table 4.f gives the specifications for Class 1 drill pipe.
API Units SI Units DP (in) Weight (lbs/ft) Grade API Units Max. Tensile Load (lbs) Rated Load (80% Load ) (lbs) DP (mm) Weight (Kg/m) Grade SI Units Max. Tensile Load (daN) Rated Load (80% Load) (daN) 5 19.5 E-75 395,595 316,476 127 29 E-75 176,000 140,800 5 19.5 X-95 501,087 400,870 127 29 X-95 223,000 178,400 5 25.6 E-75 530,144 424,115 127 38 E-75 239,900 191,920 5 19.5 G-105 553,633 442,906 127 29 G-105 246,400 197,120 5 25.6 X-95 671,515 537,212 127 38 X-95 298,800 239,040 5 50.0 HWDP 690,750 552,600 127 74.4 HWDP 307,000 245,600 5 19.5 S-135 712,070 569,656 127 29 S-135 316,900 253,520 5 25.6 G-105 742,201 593,761 127 38 G-105 330,300 264,240 5 25.6 S-135 954,259 763,407 127 38 S-135 424,600 339,680
4.4. DRILLING 121/4” HOLE
1) Run a 121/
4” bit and BHA. Drill out the 171/2” 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.
2) Drill 5m (15ft) of new hole, condition the mud and perform a leak off test (Refer to section 11).
3) Resume drilling with the 121/4”bit using the proper BHA for a vertical or deviated hole.
4) Drill the 121/
4” hole down to KOP and, if in a deviated hole phase, change the BHA for
the build up. If the well is to be vertical, drill the 121/4”hole to the casing point.
5) The drilling parameters and hydraulics will be in accordance with the Contractor Directional Operator’s instructions (if present) otherwise follow the mud and bits drilling parameters as per the Drilling Programme.
6) Take a directional survey using a MWD tool and/or single shot.
7) At the 95/8” casing point, circulate the shakers clean, make a wiper trip to the 133/8”
casing shoe and then run to bottom reaming any tight spots. Circulate to condition the mud and pull out of the hole.
8) Run electrical logs as per the Geological Programme.
9) Run the bit to bottom to control the hole, circulate to condition the mud and pull out of the hole for running the 95/8” casing.
10) Run and cement in the single or dual stage 95/8” casing (Refer to the Casing Running
and Cementing section 12.1.5). Wait on cement.
11) Hang the 95/8” 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 required, and cut the 95/8” casing.
12) Pick up the BOP stack.
13) Nipple up the intermediate casing spool and test it. 14) Lay down the BOP stack.
15) 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.
4.5. DRILLING 81/2” HOLE
1) Run a 81/
2” bit and BHA. Drill out the 133/8” 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.
2) Drill 5m of new hole, condition the mud and perform a leak off test (Refer to section 11).
3) Resume drilling with the 81/2” bit using the proper BHA for a vertical or deviated hole.
4) Drill the 81/
2” hole down to KOP and, if in a deviated hole phase, change the BHA for
the build up. If the well is vertical, drill the 81/2” hole to the casing point.
5) Drilling parameters and hydraulics will be in accordance with the Contractor Directional Operator’s instructions (if present) otherwise the mud, bits and drilling parameters will be as per the Drilling Programme.
6) Take a directional surveys using a MWD tool and/or single shot.
7) At the 81/2” casing point, circulate the shakers clean, make a wiper trip to the 95/8”
casing shoe and then run to bottom reaming any tight spots. Circulate to condition mud and pull out of the hole.
8) Run electrical logs as per the Geological Programme.
9) 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.
Note: 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.
4.6. RUNNING OF 7” CASING
1) Run and cement in the single or dual stage 7" casing (Refer to the Casing Running and Cementing section 12). Wait on cement.
2) 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.
3) Remove the BOP stack.
4) Nipple up the tubing spool and test it.
5) Re-install the BOP stack replacing the 5” lower pipe rams with 5” variables or 31/2”
4.7. RUNNING OF 7” LINER
1) Check the inside diameter and rated load of the drill pipe.
2) Run the 7” liner checking the weight and circulate the liner capacity after the making up of hanger to check the setting tool seal.
3) Set the liner as per the Manufacturer’s Procedure or as per section 12.7.
4) 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.
5) Pull ten stands, circulate and wait on cement. Circulate, pull the setting tool out of the hole using a spinner.
6) Run a 81/2” bit to the liner top, clean free of cement and circulate. Perform a seal test of
liner PBR and pull out of the hole.
7) Replace the 5” upper pipe rams with 31/2” 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) Run a 57/8” or 6” bit and drill out the cementing equipment in the 7” liner or casing.
2) Drill 5m of new hole, condition the mud and perform a leak of test, if required.
3) Drill the 57/8” or 6” hole to the planned depth following the specified Mud and Hydraulic
Programme.
4) 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.
5) Run logs as per the Geological Programme.
4.9. GENERAL GUIDELINES
1) All depth measurements will be referenced to RKB (rotary kelly bushing).
2) A stock of diesel oil, enough for five days of operations, must always be kept on the rig
3) 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.
4) 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.
• 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.
5) Five stands of heavy weight drill pipe must be installed between drill collars and drill pipe.
6) 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.
7) 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.
8) Fishing operations or major changes in the BHA configuration must be discussed first with the operations base and approval obtained.
9) Directional surveys must be performed as per the ‘Directional Control & Surveying Procedures’
10) 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.
11) A 41/2” IF or 31/2” IF pin, threaded circulating head, a kelly cock and a chicksan line,
must be always present on the rig floor ready for use.
12) 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 Company’s approval before starting operations.
13) 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.
14) 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.
15) 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.
4.10. 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) Make-up a kelly cock (15,000psi) to the single in the mouse-hole. The valve is to be in the open position.
2) Make-up the single onto the top drive.
3) Drill the single and break out above the kelly cock. 4) Pick-up a new single with another kelly cock (15,000psi). 5) Break out and lay down the kelly cock in the string.
Note: The kelly cock should be tested to the maximum anticipated surface pressure each time it is used.
5.
SUMMARY OF OPERATIONS (Semi-Submersible)
5.1. 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
183/4" - 10,000 and 15,000psi WP
163/4" - 10,000 and 15,000psi WP
b) Two stack systems
211/4" - 2,000 and 3,000psi WP
135/8" - 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 135/8" 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 preventer 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.
5.1.1. Wellhead Connector
The wellhead connector profile must obviously match that of the subsea wellhead. In Eni-Agip 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 hang-off 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.
Variable Rams
In order to provide more flexibility and perhaps avoid having to pull the stack to change pipe rams when drilling is to continue with 31/2" 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’.
5.2. FAIL SAFE VALVES
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 90o 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.
