Weatherford International, Surface Logging Systems
Wellsite Procedures and Operations
5-1-GL-GL-SUL-00009
Document Number
Originators Allan Robinson, Rebecca Pollard David Hawker, Karen Vogt, Rev 1.0 Mar 2013
Approval No of Pages 278
Wellsite Procedures and
Operations Manual
Revision Tracking
Rev
Date
Notes
Updated By
Reviewed By
X.0 Nov 2011 Tech Writer Edit K. Williams
X.1 Oct 2012 Content review. Manual structure and syntax
edit. M. Black
X.2 Jan 2013 Content Review T. Baughman
Publisher: Weatherford SLS
5200 N. Sam Houston Pkwy W., Suite 500
Houston TX 77086, USA
PHN: +1 832.375.6800
Weatherford Operating Manual
Terms and Conditions of Use
A. The materials contained in this Weatherford Operating Manual are protected by copyright, trademark, and other forms of proprietary rights. Nothing contained herein shall be construed as conferring any license or right to use or practice any copyright, trademark, patent or other forms of proprietary rights. This Operating Manual may not be copied or converted to any mechanical, electronic, or machine-readable form, in whole or in part, without Weatherford’s consent.
B. This Operating Manual is not intended to address every issue that may arise in the course of operations of the device described therein or the planning of same. Each well and each job are unique and have numerous variables. Experience and other specialized training can complement the materials used in this Operating Manual.
C. Weatherford makes no representation as to the accuracy or completeness of the materials in this Operating Manual. All materials are provided “AS IS” WITHOUT WARRANTY OF ANY KIND WHATSOEVER, EITHER EXPRESS OR IMPLIED, INCLUDING BUT NOT LIMITED TO, THE IMPLIED WARRANTIES OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR NON-INFRINGEMENT. Weatherford expressly disclaims all responsibility for the consequences, direct, indirect, consequential, or otherwise, of any errors or omissions in the materials.
D. This information is confidential and proprietary property of Weatherford. Do not disclose to unauthorized parties. Do not use except as permitted by Weatherford. Copyright 2013 Weatherford. All rights reserved.
Table of Contents
Page
1 RIGS AND THEIR EQUIPMENT ... 18
1.1
ROTARY DRILLING RIGS ... 18
1.2
LAND RIGS ... 18
1.3
OFFSHORE DRILLING VESSELS ... 19
1.3.1 Barges ... 20
1.3.2 Jack-Up Rigs ... 20
1.3.3 Semi-Submersible Rigs ... 21
1.3.4 Drillships ... 22
1.3.5 Platforms ... 23
2 ROTARY RIG COMPONENTS ... 24
2.1
OVERVIEW ... 24
2.2
THE HOISTING SYSTEM ... 25
2.2.1 Providing Rotation to the Drillstring and Bit ... 27
2.2.1.1
Kelly and Swivel ... 27
2.2.1.2
Top Drive Units ... 29
2.2.2 Lifting Equipment ... 30
2.2.2.1
Bails and Elevators ... 31
2.2.2.2
Slips ... 32
2.2.2.3
Tongs ... 32
2.2.2.4
Power Tongs and Pipe Spinners ... 32
2.2.2.5
Chain Wrench ... 33
2.3
THE CIRCULATING SYSTEM ... 33
2.3.1 Mud Conditioning Equipment ... 36
2.3.2 Rig Pumps ... 39
2.4
DRILL BIT AND DRILLSTRING ... 40
2.4.1 Drag Bits ... 40
2.4.2 Roller Tri-Cone Bit ... 40
2.4.2.1
Bit Terminology ... 41
2.4.2.2
IADC Bit Classification ... 41
2.4.2.3
Cone Action ... 42
2.4.2.4
Bearing Types ... 42
2.4.2.5
Teeth... 43
2.4.2.6
Operating Requirements ... 43
2.4.3 Diamond and Polycrystalline Diamond Compact (PDC) Bits ... 44
2.4.4 Grading of Bits ... 45
2.4.4.1
TBG System of Bit Grading ... 45
2.4.4.2
The IADC Bit Grading System ... 45
2.4.5 The Drillstring ... 46
2.4.6 Drillpipe ... 46
2.4.7 Drill Collars ... 47
2.4.8 The Bottomhole Assembly ... 48
2.4.8.1
Stabilizers ... 48
2.4.8.2
Reamers ... 49
2.4.8.3
Hole Opener... 49
2.4.8.4
Cross Over Sub ... 50
2.4.8.5
Rotary Drilling Jar... 50
2.4.8.6
Shock Sub ... 51
2.5.1 Kick and Blowout ... 52
2.5.2 BOP Stack ... 52
2.5.3 Closing the Well ... 53
2.5.3.1
Annular Preventer ... 53
2.5.3.2
Ram Type Preventers ... 54
2.5.3.2.1 Pipe or Casing Rams ... 54
2.5.3.2.2 Blind or Shear Rams ... 55
2.5.3.3
Closing BOPs ... 55
2.5.3.3.1 Accumulators... 55
2.5.4 Control Panel ... 56
2.5.5 Positioning Rams ... 57
2.5.5.1
Kill Lines ... 58
2.5.5.2
The Diverter ... 59
2.5.6 Inside BOPs ... 60
2.5.6.1
Surface Shutoff Valves ... 60
2.5.6.2
Downhole Check Valves ... 60
2.5.7 Rotating BOPs (RBOPs) ... 60
3 THE DRILLING FLUID ... 62
3.1
PURPOSES OF THE DRILLING FLUID ... 62
3.1.1 Cooling and Lubrication ... 62
3.1.2 Bottom Hole Cleaning ... 62
3.1.3 Control of Subsurface Pressures ... 62
3.1.4 Line the Wellbore ... 63
3.1.5 Support the Drillstring ... 63
3.1.6 Cuttings Removal and Release ... 63
3.1.7 Transmit Hydraulic Horsepower to the Bit ... 64
3.1.8 Hole Stability ... 64
3.1.9 Formation Protection and Evaluation ... 64
3.2
COMMON DRILLING FLUIDS ... 64
3.2.1 Air-Gas Drilling Fluid ... 65
3.2.1.1
Advantages ... 65
3.2.1.2
Disadvantages ... 65
3.2.2 Foam or Aerated Fluids ... 66
3.2.3 Water-Based Muds ... 66
3.2.3.1
Advantages ... 66
3.2.3.2
Disadvantages ... 66
3.2.4 Oil-Emulsion Muds ... 67
3.2.5 Oil-Based Muds ... 67
3.2.5.1
Advantages ... 67
3.2.5.2
Disadvantages ... 67
3.3
BASIC MUD RHEOLOGY ... 68
3.3.1 Mud Density ... 68
3.3.2 Mud Viscosity ... 68
3.3.3 Gel Strength ... 69
3.3.4 High versus Low Viscosity and Gel Strength ... 70
3.3.5 Filtrate / Fluid Loss ... 70
3.3.6 Filter Cake ... 70
3.3.8 Mud Salinity ... 71
4 SUBSURFACE PRESSURES ... 72
4.1
UNDERBALANCE VERSUS OVERBALANCE ... 73
4.2
PORE PRESSURE ... 74
4.3
HYDROSTATIC PRESSURE ... 74
4.4
PRESSURE GRADIENT ... 75
4.5
APPARENT AND EFFECTIVE MUD WEIGHT ... 75
5 DRILLING A WELL ... 77
5.1
THE WELL BORE ... 77
5.1.1 Starting Point ... 77
5.1.2 Surface Hole ... 78
5.1.3 Intermediate Hole ... 79
5.1.4 Total Depth ... 80
5.2
DRILLING AND MAKING HOLE ... 81
5.2.1 Pipe Tally ... 81
5.2.2 Drill Breaks and Flow Checks ... 82
5.2.3 Reaming ... 82
5.2.4 Circulating ... 83
5.3
CORING ... 83
5.3.1 Purpose ... 83
5.3.2 Coring Methods ... 84
5.3.3 Core Barrel Assembly ... 84
5.3.4 Retrieval and Handling Operations ... 86
5.4
TRIPPING ... 86
5.4.1 Trip Speed ... 86
5.4.2 Pulling out of Hole (POOH / POH) ... 87
5.4.3 Running in Hole (RIH) ... 89
5.4.4 Monitoring Displacements ... 90
5.4.5 Hookload ... 90
5.4.6 Strapping and Rabbiting the Pipe ... 92
5.5
CASING AND CEMENTING ... 92
5.5.1 Purpose ... 92
5.5.2 Types of Casing ... 92
5.5.3 Surface Equipment ... 93
5.5.4 Subsurface Equipment ... 94
5.5.5 Preparing to Run Casing ... 95
5.5.6 Running Casing ... 95
5.5.7 Cementing Operation ... 97
5.5.8 Other Applications ... 98
5.6
PRESSURE TESTS ... 99
5.6.1 Leak Off and Formation Integrity Tests ... 99
5.6.2 Repeat Formation Testing ... 100
5.6.3 Drill Stem Testing ... 101
5.6.3.1
Performing a Drill Stem Test ... 102
6 WIRELINE LOGGING ... 104
6.1
CALIPER LOGS ... 104
6.2
SPONTANEOUS POTENTIAL LOGS ... 105
6.3.1 Lateral Focus Log ... 106
6.3.2 Induction Log ... 106
6.3.3 Microresistivity Log ... 106
6.4
RADIOACTIVITY LOGS ... 106
6.4.1 Gamma Ray Logs ... 106
6.4.2 Neutron Logs ... 107
6.4.3 Density Logs... 107
6.5
ACOUSTIC LOGS ... 107
6.6
TYPICAL LOGGING RUNS ... 108
7 DEVIATION CONTROL ... 109
7.1
COMMON CAUSES OF DEVIATION ... 109
7.1.1 Interbedded Lithology / Drillability ... 109
7.1.2 Formation Dip ... 110
7.1.3 Faults ... 110
7.1.4 Poor Drilling Practices ... 110
7.2
PROBLEMS ASSOCIATED WITH DEVIATION ... 111
7.2.1 Doglegs and Keyseats ... 111
7.2.2 Ledges ... 112
7.2.3 Stuck Pipe ... 112
7.2.4 Increased Torque / Drag and Drillpipe Fatigue ... 113
7.2.5 Casing and Cementing ... 113
7.3
PREVENTION OF DEVIATION ... 113
7.3.1 Pendulum Effect ... 113
7.3.2 Pendulum Assembly ... 115
7.3.3 Packed-Hole Assembly ... 116
7.3.4 Packed Pendulum Assembly ... 117
7.3.5 Stabilizers and Reamers ... 118
7.3.6 Drilling Procedures ... 119
8 DIRECTIONAL AND HORIZONTAL DRILLING ... 120
8.1
REASONS FOR DIRECTIONAL DRILLING ... 120
8.2
SURVEYS / CALCULATIONS ... 121
8.2.1 Survey Methods ... 121
8.2.1.1
Single-Shot Surveys ... 121
8.2.1.2
Multi-Shot Surveys ... 121
8.2.1.3
Gyroscopic Surveys ... 121
8.2.1.4
Measurement While Drilling (MWD) ... 121
8.2.2 Survey Measurements ... 122
8.2.3 Survey Calculation Methods ... 122
8.2.3.1
Radius of Curvature ... 122
8.2.3.2
Minimum Curvature ... 123
8.2.4 Directional Drilling Terminology ... 123
8.3
DRILLING TECHNIQUES ... 125
8.3.1 Well Profiles ... 125
8.3.2 Drilling Stages ... 126
8.3.3 Whipstocks, Motors and Techniques ... 127
8.3.3.1
Whipstocks ... 127
8.3.3.2
Downhole Motors and Bent Subs ... 128
8.3.3.3
Rotating and Sliding ... 129
8.4
HORIZONTAL DRILLING ... 129
8.4.1 Classification ... 130
8.4.2 Horizontal Drilling Considerations ... 131
8.4.2.1
Radius Effects ... 131
8.4.2.2
Reversed Drillstring Design ... 131
8.4.2.3
Drillpipe Fatigue ... 132
8.4.2.4
Hole Cleaning ... 132
8.4.2.5
Use of Top Drives ... 132
8.4.2.6
Casing and Cementing ... 132
8.4.2.7
Formation Considerations ... 133
8.4.2.8
Formation Evaluation ... 133
8.4.2.9
Gas Behavior / Well Control ... 133
9 DRILLING PROBLEMS ... 134
9.1
FORMATION PROBLEMS AND HOLE STABILITY... 134
9.1.1 Fractures ... 134
9.1.1.1
Associated Problems ... 134
9.1.1.2
Drilling Fractured Formations ... 134
9.1.2 Shales ... 135
9.1.2.1
Reactive Shales ... 135
9.1.2.2
Overpressured Shales ... 136
9.1.3 Surface Formations ... 136
9.1.4 Salt Sections ... 137
9.1.5 Coal Beds ... 137
9.1.6 Anhydrite / Gypsum Formations ... 137
9.2
LOST CIRCULATION ... 138
9.2.1 Occurrences ... 138
9.2.2 Detection ... 138
9.2.3 Problems ... 139
9.2.4 Prevention ... 139
9.2.5 Remedies ... 140
9.3
KICKS AND BLOWOUTS ... 140
9.3.1 Causes of Kicks ... 140
9.3.2 Kick Warning Signs ... 141
9.3.3 Indications of Kicks While Drilling ... 141
9.3.4 Indicators While Tripping ... 142
9.3.5 Flow Checks ... 143
9.4
STUCK PIPE ... 144
9.4.1 Hole Pack Off or Bridge ... 144
9.4.2 Differential Sticking ... 145
9.4.3 Wellbore Geometry ... 146
9.4.3.1
Stuck Pipe during RIH ... 147
9.4.3.2
Stuck Pipe during POH ... 147
9.4.4 Rotary Drilling Jars ... 148
9.4.4.1
Hydraulic Jars ... 149
9.4.4.2
Mechanical Jars ... 149
9.4.4.3
Jar Accelerator ... 149
9.4.5 Fish—Cause and Indication ... 150
9.4.6 Fishing Equipment ... 151
9.5
DRILLSTRING VIBRATIONS ... 154
9.5.2 Axial Vibration ... 156
9.5.3 Lateral Vibration ... 158
9.6
WASHOUTS ... 161
9.6.1 Drillstring Washouts ... 161
9.6.2 Hole Washouts ... 161
10 UNDERBALANCED DRILLING ... 163
10.1 BENEFITS AND LIMITATIONS OF UNDERBALANCED DRILLING ... 163
10.2 UNDERBALANCED DRILLING FLUIDS ... 164
10.2.1 Gas and Air Drilling... 164
10.2.1.1 Advantages ... 164
10.2.1.2 Disadvantages ... 164
10.2.1.3 Equipment... 165
10.2.1.4 Drilling Operations ... 165
10.2.1.5 Drilling problems ... 165
10.2.2 Mist Drilling ... 166
10.2.2.1 Advantages ... 166
10.2.2.2 Disadvantages ... 166
10.2.3 Foam Drilling ... 166
10.2.3.1 Advantages ... 167
10.2.3.2 Disadvantages ... 167
10.2.4 Aerated Mud Drilling ... 167
10.2.4.1 Advantages ... 167
10.2.4.2 Disadvantages ... 167
10.2.5 Mud Drilling ... 168
10.2.5.1 Advantages ... 168
10.2.5.2 Disadvantages ... 168
10.3 UBD EQUIPMENT AND PROCEDURES ... 168
10.3.1 Rotating Heads ... 168
10.3.2 Closed Circulating and Separating Systems ... 170
10.3.3 Blooie Line and Sample Catcher ... 170
10.3.4 Gas Measurement ... 171
10.4 COILED TUBING UNITS ... 172
10.4.1 Components ... 172
10.4.2 Drilling Applications ... 173
10.4.3 Advantages and Disadvantages ... 173
11 ROCKS AND RESERVOIRS ... 175
11.1 INTRODUCTORY PETROLOGY ... 175
11.1.1 Igneous ... 175
11.1.2 Metamorphic... 175
11.1.3 Sedimentary ... 175
11.1.3.1 Sediment Classification ... 176
11.1.3.2 Compaction and Cementation ... 177
11.1.3.3 Clastic Rock Types ... 177
11.1.3.4 Chemical and Organic Rock Types ... 178
11.2 PETROLEUM GEOLOGY ... 178
11.2.1 Petroleum Generation ... 178
11.2.2 Maturation of Petroleum ... 179
11.2.3 Petroleum Migration ... 180
11.2.5 Secondary Migration ... 182
11.2.6 Hydrocarbon Traps ... 182
11.2.6.1 Stratigraphic Traps ... 182
11.2.7 Types of Structural Traps ... 184
11.2.7.1 Fold Related... 184
11.2.7.2 Fault Related ... 184
11.2.7.3 Dome Related ... 185
11.3 PETROLEUM COMPOSITION ... 186
11.3.1 Saturated Hydrocarbons or Alkanes ... 186
11.3.1.1 Paraffins ... 187
11.3.1.2 Naphthenes... 188
11.3.2 Unsaturated Hydrocarbons or Aromatics ... 189
11.3.3 API Gravity Classification ... 189
11.4 RESERVOIR CHARACTERISTICS ... 190
11.4.1 Porosity ... 190
11.4.1.1 Sandstones ... 190
11.4.1.2 Limestones ... 191
11.4.2 Permeability ... 191
11.4.3 Water Saturation ... 192
11.4.4 Reservoir Zones, Contacts and Terminology ... 192
12 MUD LOGGING—INSTRUMENTATION AND INTERPRETATION... 194
12.1 DEPTH AND RATE OF PENETRATION ... 194
12.1.1 The Geolograph ... 194
12.1.2 Crown Sheave ... 196
12.1.3 Drawworks Sensor ... 197
12.1.4 Heave Compensation ... 197
12.1.5 Rate of Penetration (ROP) ... 200
12.1.5.1 Bit Selection ... 201
12.1.5.2 Rotary speed (RPM) ... 201
12.1.5.3 Weight on Bit (WOB or FOB) ... 201
12.1.5.4 Differential Pressure ... 202
12.1.5.5 Hydraulics and Bottomhole Cleaning ... 202
12.1.5.6 Bit Wear ... 203
12.1.5.7 Lithology ... 203
12.1.5.8 Depth ... 203
12.1.5.9 Formation Pressure ... 203
12.1.6 Drilling Breaks ... 203
12.1.7 Controlled Drilling ... 205
12.2 HOOKLOAD AND WEIGHT ON BIT ... 206
12.2.1 Load or Pancake Cell ... 207
12.2.2 Strain Gauge ... 207
12.2.3 Weight on Bit ... 208
12.2.4 Hookload, Drag and Overpull ... 209
12.3 ROTARY SPEED AND ROTARY TORQUE ... 211
12.3.1 Rotary Speed ... 211
12.3.2 Rotary Torque... 212
12.3.2.1 Formation Evaluation and Fracture Identification ... 214
12.3.2.2 Sticking Pipe ... 215
12.3.3 Torsional Vibrations ... 215
12.5 ANNULAR OR CASING PRESSURE ... 219
12.6 PUMP RATE AND OUTPUT ... 220
12.6.1 Rig Pumps ... 220
12.6.2 Pump Output Calculation ... 221
12.6.2.1 Triplex Pump ... 221
12.6.2.2 Duplex Pump ... 222
12.6.3 Lag Calculations ... 222
12.6.3.1 Annular volume calculations in barrels ... 225
12.6.3.2 Annular volume calculations in cubic meters ... 225
12.6.3.3 Lag Checks ... 225
12.6.3.4 Standard Conversions for Lag Calculations ... 226
12.7 FLOWRATE AND PIT LEVELS ... 226
13 MUDLOGGING PROCEDURES ... 229
13.1 CUTTINGS DESCRIPTIONS ... 229
13.1.1 Rock Type and Classification ... 229
13.1.2 Color ... 229
13.1.3 Texture ... 230
13.1.3.1 Carbonate Rocks ... 230
13.1.3.2 Siliceous Rocks ... 230
13.1.3.3 Argillaceous Rocks ... 231
13.1.3.4 Carbonaceous Rocks ... 231
13.1.4 Cement and Matrix ... 232
13.1.5 Hardness ... 232
13.1.6 Fossils and Accessory Minerals... 232
13.1.7 Sedimentary Structures ... 232
13.1.8 Porosity ... 232
13.1.8.1 Siliceous rocks ... 232
13.1.8.2 Carbonate rocks ... 233
13.1.9 Chemical Tests ... 233
13.1.9.1 Hydrochloric Acid (HCl) - Effervescence ... 233
13.1.9.2 Hydrochloric Acid (HCl) - Oil Reaction ... 233
13.1.9.3 Swelling ... 233
13.1.9.4 Sulfate Test ... 234
13.1.9.5 Chloride Test ... 234
13.1.9.6 Alizarin Red Test... 234
13.1.9.7 Cement Test ... 234
13.2 OIL SHOWS ... 235
13.2.1 Odor ... 235
13.2.2 Oil Staining and Bleeding ... 235
13.2.3 Fluorescence ... 235
13.2.4 Sample Preparation ... 236
13.2.5 Contaminants ... 236
13.2.6 Color and Brightness ... 237
13.2.7 Fluorescence Distribution ... 237
13.2.7.1 Solvent Cut ... 238
13.2.7.2 Residue ... 239
13.2.7.3 Sampling the Mud ... 239
13.2.8 Quantitative Fluorescence Technique™ (QFT) ... 239
13.3 CUTTINGS BULK DENSITY ... 241
13.5 SHALE FACTOR ... 245
13.6 CALCIMETRY ... 247
13.7 ENHANCED HOLE MONITORING ... 248
13.7.1 Consequences of Poor Stability or Poor Hole Cleaning ... 249
13.7.2 Problems of Measuring Actual Cuttings Volume ... 249
13.7.3 Volume of Vessel ... 250
13.7.4 Measurement of Cuttings / Hour ... 250
13.7.5 Correction to Total Volume ... 251
13.7.6 Theoretical Cuttings Volume ... 252
13.7.7 Actual / Theoretical Cuttings Volume Ratio ... 253
13.7.8 Recording, Evaluating and Reporting ... 254
13.7.8.1 Plotting the Data ... 255
13.8 HIGH RESOLUTION TRIP MONITORING ... 256
13.8.1 Theory and Benefits... 256
13.8.2 Procedure ... 257
13.8.2.1 Theoretical Hookload ... 257
13.8.2.2 System and Data Preparation ... 257
13.8.3 Interpretation ... 258
13.8.4 Benefits to the Operator ... 261
13.9 DST PROCEDURES ... 261
13.9.1 Water Cushion ... 262
13.9.2 Test String Components ... 262
13.9.3 Testing Procedures ... 267
List of Figures
Figure 1: Land Rig—Derrick Being Assembled ... 18
Figure 2: Land Rig—Operational ... 19
Figure 3: Jack-up Rig ... 21
Figure 4: Semi-Submersible Rig ... 22
Figure 5: The Hoisting System—Supported By the Derrick ... 25
Figure 6: The Drawworks and Fast Line ... 26
Figure 7: Traveling Block Suspended by Drilling Line in Derrick ... 26
Figure 8: Kelly Bushing Located into Rotary Table Master Bushing ... 28
Figure 9: Top Drive Unit ... 29
Figure 10: Pipe Deck and V-Door ... 31
Figure 11: Connecting the Elevators and Using the Slips ... 31
Figure 12: Slips ... 32
Figure 13: Breaking a Pipe Connection with Tongs ... 33
Figure 14: Top of Mud Pit System ... 34
Figure 15: The Circulating System ... 35
Figure 16: Shaker Box ... 36
Figure 17: Mud Conditioning System and Pit Setup ... 37
Figure 18: Desander / Desilter Hydroclone ... 38
Figure 19: Rig Pump—Triplex... 39
Figure 20: Tri-cone Milled Tooth Bit ... 40
Figure 21: Tri-Cone Bit—Terminology ... 41
Figure 22: Diamond Bit and PDC Bit ... 44
Figure 23: Drill Collar Types—Square, Spiral and Smooth ... 48
Figure 24: Stabilizers ... 49
Figure 25: 3-Point Near-Bit Reamer... 49
Figure 26: Mechanical Jar Operation ... 51
Figure 27: Annular Preventer ... 53
Figure 28: Annular Preventer and Ram Preventers ... 54
Figure 29: Accumulator Bottle Volumes ... 56
Figure 30: BOP Control Panel ... 57
Figure 31: Simple BOP Stack Schematic ... 58
Figure 32: Choke Manifold ... 59
Figure 33: Mud Balance ... 68
Figure 35: Fann Viscometer or V-G Meter for Measuring Gel Strength ... 69
Figure 36: Land Rig Blowout ... 72
Figure 37: Offshore Blowout (Deepwater Horizon Rig) ... 73
Figure 38: Christmas Tree ... 81
Figure 39: Core Barrel ... 85
Figure 40: Trip Tank ... 87
Figure 41: Determining Maximum Running Speed vs. Given Swab Pressure ... 89
Figure 42: Sample Trip Sheet ... 91
Figure 43: Centralizer and Wall Cake Scratcher ... 94
Figure 44: Monitoring Mud Returns and Displacements ... 96
Figure 45: Cementing Operation ... 98
Figure 46: Leak Off Test ... 99
Figure 47: Drill Stem Testing (DST) ... 102
Figure 48: Wireline Logging Company Sondes ... 104
Figure 49: E-log Sondes ... 108
Figure 50: Hole Deviation due to Interbedded Lithology ... 109
Figure 51: Hole Deviation Due to Formation Dip ... 110
Figure 52: Varying Types of Faulting ... 110
Figure 53: Dogleg and Keyseat... 111
Figure 54: Ledges ... 112
Figure 55: Pendulum Force and Formation Resistance ... 114
Figure 56: Pendulum Assemblies—Slick and with Stabilizers ... 115
Figure 57: Packed-hole Assemblies ... 116
Figure 58: Packed Pendulum Assembly ... 118
Figure 59: Determining Curvature ... 123
Figure 60: Directional Drilling Terminology ... 125
Figure 61: Drilling Profiles—Shallow Deflection, S-Curve and Deep Deflection ... 126
Figure 62: Whipstock ... 127
Figure 63: Downhole Motor and Bent Sub ... 128
Figure 64: Classification of Horizontal Wells ... 130
Figure 65: Differential Sticking ... 146
Figure 66: Stuck Pipe during RIH ... 147
Figure 67: Stuck Pipe During POH ... 148
Figure 68: Hydraulic Jars ... 149
Figure 70: Overshot ... 152
Figure 71: Wireline Spear ... 153
Figure 72: Torsional Vibration ... 155
Figure 73: Axial Vibration ... 157
Figure 74: Lateral Vibration ... 159
Figure 75: Rotating Head ... 169
Figure 76: Blooie Line ... 170
Figure 77: Gas Measurement from Separator ... 171
Figure 78: Gas Measurement from Blooie Line ... 171
Figure 79: Coiled Tubing Unit ... 172
Figure 80: Traps Formed by Fancies Change and Pinchout ... 183
Figure 81: Trap Formed by Carbonate Reef ... 183
Figure 82: Trap Formed by Aolian Reef ... 183
Figure 83: Stratigraphic Traps ... 184
Figure 84: Fold Related Structural Trap ... 184
Figure 85: Graben Structure ... 185
Figure 86: Anticlinal Trap ... 185
Figure 87: Traps Associated with Salt Dome ... 186
Figure 88: Geolograph ... 195
Figure 89: Geolograph Tracks—Tag Bottom and Drill Ahead ... 196
Figure 90: Crown Sheave Depth Sensor ... 197
Figure 91: Schematic of Riser Tensioning and Compensation ... 198
Figure 92: Heave Compensation ... 199
Figure 93: Schematic showing Travel Block compensation ... 200
Figure 94: Drill Rate vs. RPM and Drill Rate vs. WOB ... 202
Figure 95: Positive and Negative Drilling Breaks ... 204
Figure 96: Load Cell ... 207
Figure 97: Strain Gauge ... 208
Figure 98: WOB and Drill Collar Weight ... 209
Figure 99: Hookload—Overpull and Drag ... 210
Figure 100: Torque Clamp ... 212
Figure 101: Example of Torque Conversion (ft / lb to amps) ... 213
Figure 102: Changes in Torque Character with Formation ... 214
Figure 103: Sticking Pipe ... 215
Figure 105: Proximity Sensor on Mud Pump ... 220
Figure 106: Example Well Profile for Lag Calculation ... 224
Figure 107: Flow Paddle ... 226
Figure 108: Ultrasonic Sensor and Delaval Float Sensor ... 227
Figure 109: Measuring the Meniscus ... 242
Figure 110: Measure Consistently on the Meniscus ... 242
Figure 111: Density Column and Graph of Density vs. Depth ... 244
Figure 112: Shale Factor ... 246
Figure 113: Measuring CEC—a. Water Spreading From Sample, b. Test Complete ... 247
Figure 114: Auto Calcimeter Kit ... 247
Figure 115: Calcimetry Result— Limestone vs. Dolomite Dissolve Time ... 248
Figure 116: Cuttings Collected With Vessel in Three Positions ... 251
Figure 117: Sample Monitoring Record Sheet ... 256
Figure 118: Trip Out Plot—Hookload vs. Depth ... 259
Figure 119: Trip Out Plot—Problem Section ... 260
Figure 120: Trip In Plot—Hookload vs. Depth ... 260
List of Tables
Table 1: IADC Bit Classification ... 41
Table 2: TBG Grading of Bits ... 45
Table 3: IADC Bit Grading System ... 45
Table 4: Kick Warning Signs for Lost Circulation, Transitional and Pressured Zones ... 141
Table 5: Gas and Air Drilling Problems ... 165
Table 6: Components of Coiled Tubing Units ... 172
Table 7: Sediment Classification Based on Depositional Environment ... 176
Table 8: Sediment Classification Based on Material Origin ... 177
Table 9: Clastic Rock Types ... 177
Table 10: Main Types of Chemical and Organic Rocks... 178
Table 11: Straight Chained Alkanes ... 187
Table 12: Branched or Iso Chained Alkanes ... 188
Table 13: Closed Chained Alkanes - Naphthenes ... 188
Table 14: Aromatics—Benzene and Toluene ... 189
Table 15: Measurement of Standpipe Pressure ... 218
Table 16: Conditions Affecting Standpipe Pressure ... 218
Table 17: Determining Triplex Pump Output ... 221
Table 18: Determining Duplex Pump Output ... 222
Table 19: Benefits of Lag Calculations ... 223
Table 20: Crystal Sizes ... 230
Table 21: Grain Sizes ... 230
1 RIGS AND THEIR EQUIPMENT
1.1 ROTARY DRILLING RIGS
In the early days of petroleum exploration and production, wells were drilled with cable tool rigs. Percussive drilling was the technique used, where a hardened bit suspended on a cable was repeatedly dropped onto the bottom of the hole. The constant pounding broke up the formation, deepening the hole in the process.
The drawbacks to the cable tool rig included limited depth capabilities, very slow drilling rates, and incontrollable subsurface formation pressures.
Modern drilling uses a rotary drilling method that provides faster drilling rates, much greater depth capabilities, offshore drilling, and safe control of subsurface pressures.
1.2 LAND RIGS
Land rigs are designed around a cantilever mast principle, providing easy transportation and quick assembly. The mast or derrick is transported to the drill site in sections, assembled on the ground (Figure 1) and then raised to a vertical position by using the rig’s hoisting system (the drawworks).
Figure 2: Land Rig—Operational
On a land rig, the blowout preventers (BOPs) are positioned directly beneath the rig floor, connecting the floor to the wellhead.
1.3 OFFSHORE DRILLING VESSELS
Drilling offshore obviously requires a completely self-contained vessel, in terms of drilling requirements and accommodation for personnel. Situated in remote, hostile locations, they are much more costly to operate and require more sophisticated safety measures because water separates the wellhead from the actual rig.
There are different types of offshore rigs and their use principally depends on the depth of water they operate in. Temporary installations (that can move from location to location) used for exploratory drilling can be supported by the seabed or they can be floating and anchored in position. Permanent installations, or platforms, are required for production wells.
1.3.1 Barges
Barges are small, flat-bottomed vessels that can only be used in very shallow waters such as deltas, swamps, lagoons and shallow lakes. They can be either be submerged and rest on the bottom, or float depending on water depth.
1.3.2 Jack-Up Rigs
Jack-up rigs are mobile vessels suitable for drilling in shallow seawater depths. They consist of a fixed hull or platform, supported by a number of legs (typically three) that stand on the seafloor.
To move a jack-up rig, the legs can be raised so the rig floats on its hull, enabling it to be towed into position by barges. This makes the vessel top-heavy and unstable during towing. To avoid capsizing, calm waters and slow towing speeds are essential. After being towed to the required position, the legs are lowered to the seabed, creating a stable structure unaffected by wave motion.
BOPs are mounted underneath the rig floor and a large conductor pipe driven into the seafloor connects the well to the rig and allows drilling fluid to be circulated.
In the jack-up example in Figure 3, it can be seen that drilling has not yet started as there is no conductor pipe in place.
Figure 3: Jack-up Rig
1.3.3 Semi-Submersible Rigs
Semi-submersible rigs (semi-subs) are floating rigs that are more suitable for drilling in deeper waters than jack-up rigs.
The deck is supported by a number of legs or columns. In subsea, these columns are supported by pontoons that can be solitary or connected. Pontoons and columns are used to ballast and stabilize the rig. This substructure sits below the sea surface, avoiding the surface turbulence, which makes them more stable than drillships and more suited to drilling in rough seas.
Pontoons are fitted with thrusters for position adjustment or self-propulsion, but they are generally moved into position by seagoing tugs, with the thrusters being used to assist in the final positioning of the rig. After being correctly positioned, the semi-sub is anchored in place. In deeper waters, the thrusters can be used to maintain position through an automated location monitor.
Unlike with the jack-up, BOPs for semi-subs are located on the seabed and mounted on conductor pipe set into the seafloor. Positioning BOPs is not easy and achieved with the assistance of underwater
cameras or remotely operated vehicles (ROVs). This allows the well to remain secure if the rig is forced to abandon the location.
A large flexible telescopic steel pipe called a marine riser connects a BOP to a rig, enabling drilling fluid to be circulated and the drillstring to be guided into the well.
Figure 4: Semi-Submersible Rig
1.3.4 Drillships
Drillships can drill in deeper water. They are generally self-propelled and easily transported to the drilling location. They are extremely mobile, but generally less stable than semi-subs and are not able to drill in rougher seas. A drillship can be anchored or its position maintained by automated thruster systems. A drillship has the same subsea equipment as a semi-sub, with the BOPs mounted on the seabed. To compensate for movement of the drillship (or semi-sub), a marine riser includes a telescopic joint to allow for vertical movement. A ball joint at the seafloor allows for horizontal motion.
The length of the riser is often the limiting factor in deep water drilling because it is subjected to too much bending and stress.
1.3.5 Platforms
Platforms are permanently fixed structures installed where mobility is not required. This is typically when multiple wells are drilled to develop and produce a field. Platforms can be of two designs:
Piled Platform. A piled platform consists of a steel jacket that is pinned to the seabed and supports the deck structure. A piled platform is stable in bad weather, but is not mobile. They are usually constructed in separate sections that can be towed to position and constructed in place.
Gravity Platform. A gravity platform is constructed from concrete, steel, or a combination of both. It has a cellular base, providing ballast and storage, with vertical columns supporting the deck structure. A gravity platform is normally fully constructed and then towed to the location and ballasted into position.
2 ROTARY RIG COMPONENTS
2.1 OVERVIEW
A modern rotary drilling rig consists of five principle components: 1. Drill bit and drillstring
2. Fluid circulating system 3. Hoisting system 4. Power system
5. Blowout prevention system
The term rotary comes from the physical movement of the drillstring and bit, applying a rotary cutting action to the rock at the bottom of the hole. Rotation can be provided at surface or by motors positioned in the drillstring downhole. The drillstring (1) consists of hollow steel pipe allowing drilling fluid to be transported into the hole. The pipe is typically a combination of a standard drillpipe, but thicker and with a heavier drillpipe and a larger diameter, with heavy drill collars immediately above the bit.
This is all supported from the derrick with vertical movement (in and out of the hole) provided by the drawworks, crown block, and traveling block (3) (Figure 5). Rotation of the drillstring, at surface, is applied in one of two ways: either by a rotary table, bushings, and kelly, or by a top drive unit.
The drilling fluid, commonly referred to as drilling mud, is stored in mud tanks or pits. From here, the mud can be pumped through the standpipe to the kelly, swivel where it can enter the kelly, and subsequently the drillpipe. The mud can then pass all the way to the bit before returning to surface through the annulus—the space between the wall of the borehole and the drillstring. On return to surface, the mud is passed through several pieces of equipment to remove the drilled rock chips or cuttings, before completing the cycle and returning to the mud tanks (2) (Figure 15).
Formations in the shallower part of the wellbore are usually protected by a large diameter steel tubing or casing which is cemented into place. The annulus that the mud now passes through on its way back to surface is now the space between the inside of the casing and the outside of the drillstring. Attached to the top of the casing is the BOP stack (5), a series of valves and seals that can be used to close off the annulus or wellbore to control large subsurface pressures.
All of the equipment described above is operated by a central power system (4), which also supplies the general power required for electrical lighting and service company equipment. Typically, this power source is through a central diesel-electric power plant.
2.2 THE HOISTING SYSTEM
Figure 5: The Hoisting System—Supported By the Derrick The complete hoisting system has several basic functions:
Supporting the weight of the drillstring, possibly up to several hundred tons. Lifting the drillstring in and out of the hole.
Maintaining the force or weight applied to the bit during drilling.
The derrick supports the weight of the drillstring at all times, whether the drillstring is suspended from the crown block or supported temporarily in the rotary table. The size and strength of the derrick is the limiting factor for the weight of the drillpipe that can be supported and also the depth that the rig is capable of drilling to.
The height of the derrick determines the length of the pipe sections that can housed when the drillstring must be pulled from the hole. During this operation, the pipe is normally broken down into double or triple stands—two or three individual lengths or joints of pipe.
During the drilling operation, the kelly and drillstring are supported from the traveling block through the traveling hook. This is connected to the drawworks through a simple pulley system (Figure 5).
A steel cable, the drilling line, is spooled on a large reel at the drawworks where it can be drawn in or let out, depending on whether an upward or downward motion of the traveling block is required (Figure 6).
Figure 6: The Drawworks and Fast Line
From the drawworks, the drilling line passes up to a stationary set of pulleys, called the crown block, situated at the top of the derrick. The cable is repeatedly passed between a series of wheels, or sheaves, and attaches to the traveling block suspended in the derrick (Figure 7); the traveling block is usually supported by a number of lines, typically 8 to 12.
The drilling line is then passed from the crown block to an anchor where the cable is securely clamped. This length of drilling line is referred to as the deadline, and the deadline anchor is typically located to one side of rig floor (Figure 5). From the deadline anchor, the drilling line passes to a storage reel to one side of the rig, where extra drilling line is stored.
The drilling line is commonly referred to as the fast line for the length running from the drawworks to the crown block. This is because the first sheave it is spooled around is generally larger than the others and is known as the fast sheave.
The use of the drilling line, or wear, is recorded in terms of the load moved over a given distance. For example, 1 ton-mile means that the line has moved a 1-ton weight a distance of 1 mile. Similarly, a measurement of 1kN-km means that the line has moved 1000 newtons a distance of 1 kilometer. This record allows the drilling crew to determine when the drilling line must be replaced by a new length of cable.
The slip and cut procedure requires the traveling block to be lowered to the drill floor so that there is no load on the drilling line. The line is released at the deadline anchor so that new line can be fed or slipped through. The line is tensioned by feeding it through the pulley system and pulling the old line out from the drawworks. This old line can be removed or cut and the new length of cable tensioned and anchored again at the deadline anchor. This procedure allows for even wear on the drilling line as it is used.
The drawworks has a heavy-duty braking system allowing for the speed to be controlled or resisted when moving the pipe into the hole. During the drilling operation, the drawworks also allows for control or adjustment of the proportion of the string weight supported by the derrick and the bottom of the hole. This equates to the weight or force that is applied to the bit. This can then be adjusted according to the hardness of the formation and the weight required to produce failure of the formation and to allow penetration or deepening of the hole to proceed.
2.2.1 Providing Rotation to the Drillstring and Bit
2.2.1.1 Kelly and Swivel
The kelly is a hollow length of steel normally around 12 or 13m, square or hexagonal, through which drilling fluid enters the drillpipe.
The top of the drillstring is connected to the kelly by a kelly sub (or saver sub). This sub, relatively cheaper to replace than the kelly, saves wear on the connecting threads of the kelly, which passes through a rotary kelly bushing mounted and locked into master bushings that are set into the rotary table (Figure 8).
Figure 8: Kelly Bushing Located into Rotary Table Master Bushing
Free vertical movement of the kelly, whether rotating or static, is possible through the bushing, allowing upward and downward movement of the drillstring as drilling progresses. Rollers within the bushing facilitate this movement and minimize the wear on the kelly. The shape of the kelly, commonly 4 or 6 sided, fits exactly into the bushing so if the bushing rotates, the kelly rotates.
Because the bushing is locked into the rotary table, rotation of the table (electrically or mechanically) rotates the bushing, the kelly and the drillpipe. When the kelly is lifted from the hole to expose the drillpipe, the kelly bushings are lifted with the kelly.
Between the kelly and the hook is an assembly known as the swivel. The swivel supports the kelly but does not rotate as the kelly rotates; it prevents the hook and traveling block from rotating and twisting the drilling line as the string is rotated. The swivel is also the point at which the drilling fluid enters the drillstring, through an attachment known as a gooseneck connected to the kelly hose carrying the drilling fluid.
A safety valve is located at the top of the kelly called the kelly cock. This cock can be manually closed if the well is flowing due to high subsurface formation pressure. This prevents backpressure from entering, and perhaps damaging, the kelly swivel.
2.2.1.2 Top Drive Units
On more recent rigs, the rotary drive and swivel are combined into a single top drive system (TDS), which can be electrically or hydraulically operated. The drillstring connects directly into the top drive unit where rotation is applied and where drilling fluid enters the string through a similar swivel and gooseneck assembly. Because rotation is applied directly to the top of the drillstring, there is no requirement for a kelly and rotary bushing.
Figure 9: Top Drive Unit
The advantage of a top drive over the conventional kelly system is primarily one of time and cost. As drilling progresses with a kelly system, only single lengths or joints can be added to the drillstring. This connection process requires the kelly being broken off from the drillstring, picking up and attaching the new joint of pipe to the kelly, then reattaching the new pipe and kelly back to the drillstring.
With a top drive unit, this operation is much simpler because the pipe is connected directly to the unit and it enables a stand of drillpipe (equivalent to 3 single joints of pipe) to be picked up and added to the drillstring at any time. A complete stand of drillpipe can be drilled continuously, so only one connection is required for every three joints.
The overall time required to make connections is less for rigs possessing top drive units. This means a big saving in cost, especially for large land rigs or offshore rigs where the daily cost of hiring the rig is much more expensive.
Another important advantage of a top drive unit is when the drillstring is being lifted in or out of the hole (tripping). The conventional kelly is not used when tripping pipe, it is set aside on the rig floor in what is called the rathole, bails and elevators are used to lift the drillstring. If the pipe becomes stuck during the trip, circulation of drilling fluid might be required to free the pipe. With a top drive unit, elevators lift the pipe but they are suspended directly beneath the top drive unit (Figure 9). It is a very quick procedure to attach the top drive unit to the drillstring so that circulation of drilling fluid and rotation of the pipe is possible almost immediately. In most circumstances, this minimizes the potential problem and reduces the time required to solve it.
If tripping on a rig using a kelly system it can take 5-10 minutes before fluid circulation can be achieved as the kelly would need to be picked up from the rathole and attached to the drillstring first. During this time, the sticking of the pipe may become worse.
2.2.2 Lifting Equipment
Drillpipe is stored on the pipe deck, located to the side of the rig. When pipe must be added to the drillstring the joint is picked up from the pipe deck by a winch. The winch pulls the pipe up a ramp that connects the pipedeck to the drill floor, known as the v-door (Figure 10).
The blocks are then lowered and the joint of pipe is picked up in the elevators. When picked up, the joint of pipe is lowered into the mousehole in the drillfloor (a hole drilled into the surface sediments and lined with tubular) where it is ready for use when the next connection is made. Note that different elevators are used to pick up collars or casing tubular.
Figure 10: Pipe Deck and V-Door 2.2.2.1 Bails and Elevators
These are used to lift the pipe into position or remove it when the connection is broken. Elevators are simple clamps placed and closed around the stem of the pipe. As the elevators are lifted, they move up the pipe until they come against the wider tool joint so the pipe can be lifted.
Figure 11: Connecting the Elevators and Using the Slips
Elevators are suspended from the traveling block by links or bails, so vertical movement is applied from the drawworks. Elevators are of specific sizes and designs to accommodate pipe of different diameter, casing joints, and drill collars.
2.2.2.2 Slips
While connections are being made or broken, the drillstring must be suspended and supported in the rotary table to prevent it from falling down the hole. This is achieved by using slips, which are tapered or wedge-shaped dies held together in a frame with handles (Figure 11 and Figure 12).
Figure 12: Slips
The slips are placed around the stem of the pipe and lowered along with the pipe into the master bushings where they become set, meaning fully supporting the weight of the drillstring in the rotary table.
2.2.2.3 Tongs
These are used to tighten or loosen connections between sections of pipe. These wrenches are suspended on cables from the derrick and attached to the cathead on the drawworks by a chain through which tension can be applied.
Two tongs are used and placed on either side of the connection or joint. The lower tong holds the drillstring in place below the joint. The upper tong, by pulling on the chain, loosens or breaks the connection or in the opposite direction, tightens or makes the connection. When making the connection, a gauge on the chain allows the correct amount of torque to be applied.
2.2.2.4 Power Tongs and Pipe Spinners
These pneumatically powered wrenches enable rapid spinning of the pipe when making or breaking connections. Tongs are used to apply final torque when making the connection and to initially loosen the joint when breaking the connection.
Figure 13: Breaking a Pipe Connection with Tongs 2.2.2.5 Chain Wrench
If pneumatic wrenches are not available, spinning the pipe must be done manually with a chain wrench. Chain is wrapped around the pipe, clasped and gripped by the wrench. Spinning the pipe is done by physically walking around the pipe while it is gripped and held by the wrench.
2.3 THE CIRCULATING SYSTEM
There are many ways in which mud aids the drilling process and, in fact, is a vital component to the successful drilling of a well. The most important functions are as follows:
To cool and lubricate the drill bit and drillstring to minimize wear, prolong life and reduce costs. To remove drilled rock fragments or cuttings from the hole. This keeps the annulus clear and allows
examination at surface for formation evaluation.
To balance high fluid pressures that can be present in formations and to minimize the potential for kicks or blowouts. The safety of rig personnel and of the rig is of paramount importance.
To stabilize the wellbore and formations that have been drilled.
For more details on the types of drilling mud and its functions, see Section 3 Drilling Fluid.
Creating drilling mud is similar to cooking, with many ingredients going into the system. Each ingredient or additive has a function.
The mud is built and stored in mud tanks or pits; gratings cover the pits and creating walkways and allowing access points to place mud logging sensors (Figure 14). These pits are named depending on their specific function. Typically, they are one of the following:
Suction Pit—Where the mud is taken by the rig pumps to begin its journey to the drillstring. This is the live or active pit, lined up to the actual wellbore.
Reserve or Settling Pit—For holding additional mud volume, generally not part of the active system. Shaker Pit—A tank situated directly beneath the shale shakers. A sand trap is normally an integral
part of the shaker pit. It allows as much fine material, sand and silt, to settle from the mud system and be removed.
Trip Tank—A small tank designed to monitor small mud displacements. Situations that require this include tripping the drillstring out of the hole and monitoring a well kick.
Slug Pit—A tank to make up small volumes of special mud for specific operations during the drilling of a well.
Figure 14: Top of Mud Pit System
The number of pits required on a rig depends on the size and the depth of the well being drilled, and on the volume of mud required to fill that hole. Typically, 4 to 6 tanks are used, but for larger wells and platforms this number can increase to 16 or more.
From the mud tanks, the mud is pumped through an upright standpipe fixed to the side of the derrick, through a gooseneck into the connected kelly hose. From the kelly hose, the mud passes through another gooseneck and through the swivel into the kelly, where it is forced down the inside of the drillstring.
Exiting the drillstring through the bit, the mud returns to the surface through the annulus, which is the space between the wellbore wall / casing and the outside of the drillstring (Figure 15).
Figure 15: The Circulating System
For offshore wells, a further conduit must be positioned to allow mud to be circulated from the seabed to the rig.
This is done through a large conductor pipe or marine riser:
Conductor—A pipe driven into the seafloor, providing a conduit to the BOP stack situated beneath the rig floor on jack-ups and platforms.
Marine Riser—A pipe connected to the top of the BOP stack located on the seabed on semi-subs and drillships, providing a conduit to the rig. The riser incorporates a telescopic or slip joint that allows for rig heave, adjusting the vertical position of the rig.
2.3.1 Mud Conditioning Equipment
Solids control is vital in maintaining efficient drilling operations. High mud solids increase mud density and viscosity, leading to higher chemical-treating costs, poor hydraulics and increased pumping pressures. With increased solids, the mud becomes increasingly abrasive and increases wear on the drill string, wellbore and surface equipment. It becomes more difficult to remove solids from the mud as the solids content increases.
Drilling mud surfacing from the wellbore contains cuttings, sand and other solids, and probably gas, all of which must be removed before the mud can be re-circulated in the well. Mud treatment clays and chemicals must also be added to maintain the required properties. These functions require special equipment.
When exiting the wellbore at the surface, the mud is drawn off at the bell nipple and directed along a flowline to a shaker box (also called a header box or possum belly). The shaker box is where the mud logger positions a gas trap and mud monitoring sensors to analyze the mud returning from the hole (Figure 16).
Figure 16: Shaker Box
Gates in the shaker box regulate the flow of mud onto the shale shaker. Sloped and vibrating mesh screens (normally two) separate the drilled cuttings from the drilling mud, which passes through screens into the sand trap or shaker pit. The mud can then be returned to the main pit system where the circulating cycle can start again.
The screens can be changed so the size of the mesh is appropriate to the size of the cuttings to be removed. Normally, a coarser screen is positioned above a finer screen. The vibration motion of the screens improves the separation of mud from the cuttings. Samples for geological analysis are collected at this point.
With environmental concerns an important consideration, the cuttings separated at the shale shaker are collected in tanks so they can be transported to sites where they can be cleaned of residual mud or chemicals and deposited. Additional equipment is put into the circulating system before the mud returns to the mud tanks (Figure 17).
Figure 17: Mud Conditioning System and Pit Setup
If the mud is particularly gaseous, it is passed through a degasser, a large tank with an agitator to force the release of gas from the mud.
After passing through the shale shakers, there can still be very fine solid material such as silt or sand grains that must be removed. The mud first drops into a sand trap after passing through the shakers. This is a conical or tapered chamber incorporated within the shaker pit, where the mud’s flowrate is reduced, allowing solids to separate and settle. The bottom of the trap is sloped so the settling particles fall to the base where they are collected and discarded. If these particles do not settle out when the mud passes through the sand trap, the mud must pass through additional solids control equipment before returning it to the mud tanks.
A desander (Figure 18), when used in addition to the shale shaker, removes most of the abrasive solids which reduces wear on the mud pumps, surface equipment, drill string and bit. A desilter, which removes even finer material from the mud, is also used with the shale shaker and desander. Both of these use a hydroclone to separate out the solids.
Figure 18: Desander / Desilter Hydroclone
To remove large amounts of clay solids suspended in the mud, additional centrifuges are used. When the mud is cleaned, it can be returned to the mud tanks for re-circulating. A centrifuge consists of a high-speed rotating, cone-shaped drum and a screw conveyor that moves the coarse particles in the drum to the discharge port and back to the mud system. It is often used when the mud weight must be significantly reduced, rather than adding liquid and increasing the volume.
The centrifuge can also remove glass or plastic beads that are used to improve lubrication or to reduce density in underbalanced applications.
Fine grains are very abrasive and damaging to equipment such as pumps, drillstring and bits. The control of fine grains is important in controlling the density of the mud. If solids were allowed to remain and build up in the mud, its density increases.
One further step to prepare the mud for recirculation is performed by a degasser, which separates and vents large volumes of entrained gas to a flare line. Re-circulating gas-cut mud can be hazardous, reduces pumping efficiency, and lowers hydrostatic pressure. Hydrostatic pressure is required to balance the formation pressure.
A mud-gas separator safely handles high-pressure gas and flow from a well when a kick occurs. A vacuum degasser is more appropriate for separating entrained gas, which may resemble foaming on the surface of the mud (gas cut mud).
2.3.2 Rig Pumps
Most rigs have two rig pumps to circulate the mud under pressure through the system. Smaller rigs drilling shallower holes may only require one; large offshore rigs may have three and include a booster pump connected to the riser. Rig pumps can be of two types:
Duplex Pumps—These possess two cylinders, or chambers, each of which discharges drilling fluid on forward and backward motion of the pump stroke. As the mud is discharged on one side of the piston, the cylinder is filled up from the other side. As the piston returns, this mud is now discharged, with the previously discharged side now being refilled behind the piston.
Triplex Pumps—These possess three cylinders. Unlike the duplex pump, mud is discharged on the forward stroke in each cylinder only, leaving the cylinder behind the piston empty. As the piston returns on the backward part of the stroke, mud refills the chamber. This mud is again discharged on the forward part of the pump stroke.
2.4 DRILL BIT AND DRILLSTRING
2.4.1 Drag Bits
The drag bits have hard-faced blades rather than distributed cutters that are an integral part of the bit and rotate as one with the drillstring. They have a tendency to produce high drilling torque and are also prone to drilling crooked holes.
Penetration is achieved with a scraping action using low force (weight on bit or WOB) and high rotation speed (revolutions per minute or RPM). They are only suitable for drilling soft and unconsolidated formations, and lack the hardness and wear resistance required for consolidated formations.
2.4.2 Roller Tri-Cone Bit
Early bits possessed two cones that had no interaction or meshing, these were prone to balling (where drilled cuttings collect and consolidate around the bit) in soft formations. These were superseded by the tri-cone bit, the most common type used in modern drilling (Figure 20). These possess 3 cones, which are intermeshing and therefore self-cleaning, with rows of cutters on each cone.
Cutters are of two principle types: milled teeth (Figure 20) or tungsten carbide inserts (TCI), and can be of varying size and hardness according to the lithology expected. A lot of heat is generated by friction during drilling and this heat must be dissipated. Cooling, together with lubrication, is an important function of the drilling fluid. This exits the drillstring through ports in the bit that are called jets or nozzles; one jet is positioned above each cone.
Jets are replaceable and can be of varying size, the smaller the jet, the greater the velocity and force of the mud exiting the bit. Jet sizes are expressed in millimeters or in 32nds of an inch. If no jet is set into the port, it is known as an open jet (the size is one inch, that is, thirty-two 32nds).
Roller bits are classified by a system developed by the International Association of Drilling Contractors (IADC), where most have a 3 digit IADC code to describe the series, type and design (Table 1). The following are examples:
Hughes ATM22: IADC code 517—Soft chisel type TCI bit, softest in the range, with friction-sealed journal bearings and gauge-protected.
Reed MHP13G: IADC code 137—Soft milled tooth bit, moderately hard in the range, with friction-sealed journal bearings and gauge-protected.
Some bits have a fourth category to describe additional features about the bit. Examples include air application (A) bits, centre jets (C), deviation control (D), extra gauge (E), horizontal steering (H), standard steel tooth bit (S), chisel shaped inserts (X), conical shaped inserts (Y).
2.4.2.1 Bit Terminology
Figure 21 illustrates the naming convention for the various parts of tri-cone bits.
Figure 21: Tri-Cone Bit—Terminology 2.4.2.2 IADC Bit Classification
Table 1: IADC Bit Classification
Series
Type of cutting structure
1 Soft Milled Tooth
2 Medium 3 Hard
4 Very soft Chisel Tungsten
Carbide Insert 5 Soft
6 Medium Conical
7 Hard 8 Very hard
Type
Degree of hardness of cutting
structure
1-4 1 – softest 4 – hardest
Design Option
Bearing design and gauge protection
1 Standard product 2 Air drilling 3 Gauge protected 4 Sealed bearing
5 Gauge protected and sealed bearing 6 Friction, sealed journal bearing
7 Friction, sealed journal bearing, gauge protected 8 Directional
9 Other 2.4.2.3 Cone Action
As cones roll on the bottom of the hole, a sliding action gouges and scrapes the formation. Cones have more than one rolling center because of the number and alignment of cutter rows, but this is restrained by the weight of the drill collars acting on the bit.
Rotation is around the bit center-line so that the teeth must slide and scrape as they roll. This action is minimized in the design of the hard bits (by having no cone offset) to reduce wear, but action is still not pure rolling.
The sliding action produces a controlled tearing, gouging, and scraping action on the formation, leading to fast and efficient chip removal. For soft formations, the scraping action is enhanced by offsetting the cones. This leads to faster drilling and the amount of scraping action depends on the degree of offset. Soft formation bits may have an offset of 1/4 or 1/8 inch in medium bits, and no offset for hard bits.
2.4.2.4 Bearing Types
Unsealed—These are grease-filled and exposed. Their life is short because they are exposed to metal fatigue and abrasion from solids.
Sealed and self-lubricating—Metal fatigue still exists, but abrasion from solids is eliminated as long as there is a seal.
Sealed journal bearings—These have a longer life, but wear can come from seizure of the sliding metal-to-metal surfaces on the bottom side of bearings. If the seal fails, drilling mud leaks into the bearing, displacing the grease. Overheating causes rapid failure of the bearing. The bearing has a pressure compensation system that minimizes the pressure differential between the bearing and the mud column pressure.
2.4.2.5 Teeth
The size, shape and separation of teeth affect the efficiency of the bit in a formation of varying hardness. The tooth design also determines the size and form of the drilled cuttings produced and used for formation evaluation.
For soft formations, the teeth are typically long, slender, and widely spaced. The longer teeth allow deeper penetration into the soft formation. This deeper penetration is maintained as the teeth become worn by making the teeth as slender as possible. The wide spacing prevents the soft formation from balling or packing between the teeth. The cutting action is one of gouging and scraping and the cuttings typically produced are large and freshly broken.
Bearing size and strength are restricted in soft formation bits depending on the size of the teeth. This normally does not produce a problem because only low weights or force must be applied to the bit to achieve formation failure and penetration.
For formations of medium hardness, shorter and broader teeth are used. Deep penetration is limited by the formation hardness so that longer teeth are unnecessary. The length is such that as much penetration as possible is achieved. At the same time, wear caused by the firmer formation is kept to a minimum. Wide spacing allows for efficient cleaning even though balling is not as important as in a soft formation. For hard formations, short and broad teeth produce a crushing and chipping action rather than scraping and gouging. The drilled cuttings are smaller, more rounded, crushed and ground. Tooth spacing is not required for cleaning because cuttings are smaller with a lower concentration or volume, resulting from lower penetration rates.
Increased life in hard and abrasive formations can be produced by hard-facing the milled steel teeth or by using tungsten carbide inserts (TCIs). For harder formations, fewer and smaller teeth facilitate larger and stronger bearings that can withstand the higher forces that cause failure.
2.4.2.6 Operating Requirements
Hard and abrasive formations require a higher force or weight on bit (WOB) to be applied to the bit. The greater weight impacts the bearings so a corresponding lower RPM is applied to minimize bearing wear. To prevent impact failure or cracking of insert cutters, the WOB required is slightly lower for an equivalent TCI bit.
Softer formations require lower weight on bit to achieve penetration, therefore higher RPM can be applied. Similar parameters are required for tooth and TCI bits. Too much weight being applied could break the longer teeth or inserts.
Generally, rate of penetration (ROP) is faster with more weight applied to the bit and/or higher RPM, but too much weight can have detrimental effects such as bit balling in softer formations, failure of roller bearings, seizure of journal bearings, and breakage of teeth or inserts.