Wellsite procedure and operationo

WELLSITE PROCEDURES AND OPERATIONS

Version 3.0 March 2001

David Hawker Karen Vogt

Allan Robinson (sections 11.8 and 11.9)

Corporate Mission To be a worldwide leader in providing drilling and geological monitoring solutions to the oil and gas

industry, by utilizing innovative technologies and delivering exceptional customer service.

DATALOG WELLSITE OPERATIONS MANUAL, Version 3.0, issued March 2001


1

CONTENTS

1 RIGS AND THEIR EQUIPMENT ...................................................................................................................... 9 1.1 ROTARY DRILLING RIGS.................................................................................................................................... 9

1.1.1 Land Rigs .................................................................................................................................................. 9 1.1.2 Offshore drilling vessels............................................................................................................................ 9

Barges ............................................................................................................................................................. 9 Jack-Up Rigs ................................................................................................................................................... 9 Semi-Submersible Rigs ................................................................................................................................. 10 Drillships....................................................................................................................................................... 10 Platforms ....................................................................................................................................................... 10

1.1.3 Land Rig Examples ................................................................................................................................. 11 1.1.4 Jack Up Example .................................................................................................................................... 13 1.1.5 Semi-Submersible Example..................................................................................................................... 14

2 ROTARY RIG COMPONENTS ....................................................................................................................... 15 2.1 THE HOISTING SYSTEM................................................................................................................................... 16

2.1.1 Providing Rotation to the Drillstring and Bit ......................................................................................... 18 Kelly and Swivel ........................................................................................................................................... 18 Top Drive Units ............................................................................................................................................ 19

2.1.2 Lifting Equipment.................................................................................................................................... 20 Bails and Elevators........................................................................................................................................ 20 Slips............................................................................................................................................................... 21 Tongs............................................................................................................................................................. 21 Power Tongs and Pipe Spinners.................................................................................................................... 21 Chain Wrench................................................................................................................................................ 21

2.2 THE CIRCULATING SYSTEM ............................................................................................................................ 23 2.2.1 Solids Control Equipment ....................................................................................................................... 25

2.3 DRILL BIT AND DRILLSTRING.......................................................................................................................... 29 2.3.1 Drag Bits................................................................................................................................................. 29 2.3.2 Roller Tri-Cone Bits................................................................................................................................ 29

Bit Terminology............................................................................................................................................ 30 IADC Bit Classification ................................................................................................................................ 30 Cone Action .................................................................................................................................................. 31 Bearing Types ............................................................................................................................................... 31 Teeth ............................................................................................................................................................. 31 Operating requirements ................................................................................................................................. 32

2.3.3 Diamond and Polycrystalline Diamond Compact (PDC) bits ................................................................ 33 2.3.4 Grading Of Bits....................................................................................................................................... 34

The IADC bit grading system........................................................................................................................ 34 2.3.6 The Drillstring......................................................................................................................................... 35 2.3.7 Drillpipe.................................................................................................................................................. 35 2.3.8 Drill Collars............................................................................................................................................ 36 2.3.9 The Bottom Hole Assembly (BHA) .......................................................................................................... 37

Stabilizers...................................................................................................................................................... 37 Reamers......................................................................................................................................................... 37 Hole Opener .................................................................................................................................................. 38 Cross Over Sub ............................................................................................................................................. 38 Jars ................................................................................................................................................................ 38 Shock Sub.................................................................................................................................................... 39

2.4 BLOW OUT PREVENTION SYSTEM................................................................................................................... 40 2.4.1 BOP Stack ............................................................................................................................................... 40 2.4.2 Closing the well....................................................................................................................................... 41



2

Annular Preventer ......................................................................................................................................... 41 Ram Type Preventers .................................................................................................................................... 41

2.4.3 Closing the preventers ............................................................................................................................ 42 Accumulators ................................................................................................................................................ 43 Control Panel................................................................................................................................................. 43 Positioning of the rams.................................................................................................................................. 44 Kill Lines....................................................................................................................................................... 44 The Diverter .................................................................................................................................................. 45

2.4.4 Inside Blowout Preventers ...................................................................................................................... 46 Surface Shut Off Valves................................................................................................................................ 46 Downhole Check Valves ............................................................................................................................... 46

2.4.5 Rotating BOPs ........................................................................................................................................ 46 3 THE DRILLING FLUID.................................................................................................................................... 48

3.1 PURPOSES OF THE DRILLING FLUID ................................................................................................................. 48 3.1.1 Cool and Lubricate the Bit and Drillstring............................................................................................. 48 3.1.2 Bottom Hole Cleaning............................................................................................................................. 48 3.1.3 Control Subsurface Pressures................................................................................................................. 48 3.1.4 Line the Hole with Filter Cake................................................................................................................ 49 3.1.5 Help Support the Weight of the Drillstring ............................................................................................. 49 3.1.6 Cuttings Removal and Release................................................................................................................ 49 3.1.7 Transmit Hydraulic Horsepower to the Bit............................................................................................. 49 3.1.8 Hole Stability .......................................................................................................................................... 50 3.1.9 Formation Protection and Evaluation .................................................................................................... 50

3.2 COMMON DRILLING FLUIDS ............................................................................................................................ 51 3.2.1 Air/Gas.................................................................................................................................................... 51 3.2.2 Foam or Aerated Fluids.......................................................................................................................... 51 3.2.3 Water-Base Muds.................................................................................................................................... 52 3.2.4 Oil-Emulsion Muds ................................................................................................................................. 52 3.2.5 Oil-Base Muds ........................................................................................................................................ 53

3.3 BASIC MUD RHEOLOGY .................................................................................................................................. 54 3.3.1 Mud Density ............................................................................................................................................ 54 3.3.2 Mud Viscosity.......................................................................................................................................... 54 3.3.3 Gel Strength ............................................................................................................................................ 55 3.3.4 High vs. Low Viscosity and Gel Strength................................................................................................ 55 3.3.5 Filtrate/Fluid Loss .................................................................................................................................. 55 3.3.6 Filter Cake .............................................................................................................................................. 56 3.3.7 Mud pH Level.......................................................................................................................................... 56 3.3.8 Mud Salinity ............................................................................................................................................ 56

4 DRILLING A WELL.......................................................................................................................................... 57 4.1 WELL BALANCE.............................................................................................................................................. 57

4.1.1 Underbalance versus Overbalance ......................................................................................................... 57 4.2 THE WELL BORE............................................................................................................................................. 59

4.2.1 Starting Point .......................................................................................................................................... 59 4.2.2 Surface Hole............................................................................................................................................ 59 4.2.3 Intermediate Hole ................................................................................................................................... 60 4.2.4 Total Depth ............................................................................................................................................. 61

4.3 DRILLING AND MAKING HOLE......................................................................................................................... 63 4.3.1 Pipe Tally ................................................................................................................................................ 63 4.3.2 Drill Breaks and Flow Checks ................................................................................................................ 63 4.3.3 Reaming .................................................................................................................................................. 64 4.3.4 Circulating .............................................................................................................................................. 64

4.4 CORING........................................................................................................................................................... 66 4.4.1 Purpose ................................................................................................................................................... 66



3

4.4.2 Coring Methods ...................................................................................................................................... 66 4.4.3 Core Barrel Assembly ............................................................................................................................. 67 4.4.4 Retrieval and Handling Operations ........................................................................................................ 67

4.5 TRIPPING......................................................................................................................................................... 69 4.5.1 Trip Speed ............................................................................................................................................... 69 4.5.2 Pulling Out of Hole................................................................................................................................. 69 4.5.3 Swabbing................................................................................................................................................. 70 4.5.4 Running In Hole...................................................................................................................................... 71 4.5.5 Monitoring Displacements ...................................................................................................................... 72 4.5.6 Hook Load............................................................................................................................................... 72 4.5.7 Strapping and Rabbiting the Pipe........................................................................................................... 73

4.6 ELECTRICAL LOGGING .................................................................................................................................... 74 4.6.1 Formation Evaluation............................................................................................................................. 74 4.6.2 Hole Condition........................................................................................................................................ 75

4.7 CASING AND CEMENTING................................................................................................................................ 77 4.7.1 Purpose ................................................................................................................................................... 77 4.7.2 Types of Casing....................................................................................................................................... 77 4.7.3 Surface Equipment .................................................................................................................................. 78 4.7.4 Subsurface Equipment ............................................................................................................................ 78 4.7.5 Preparing to Run Casing ........................................................................................................................ 79 4.7.6 Running Casing....................................................................................................................................... 80 4.7.7 Cementing Operation.............................................................................................................................. 81 4.7.8 Other Applications .................................................................................................................................. 82

4.8 PRESSURE TESTS ............................................................................................................................................ 83 4.8.1 Leak-Off and Formation Integrity Tests.................................................................................................. 83 4.8.2 Repeat Formation Testing....................................................................................................................... 84 4.8.3 Drill Stem Testing ................................................................................................................................... 85

Performing a Drill Stem Test ........................................................................................................................ 86 5 DEVIATION CONTROL................................................................................................................................... 87

5.1 COMMON CAUSES OF DEVIATION ................................................................................................................... 87 5.1.1 Interbedded Lithology / Drillability ........................................................................................................ 87 5.1.2 Formation Dip ........................................................................................................................................ 87 5.1.3 Faults ...................................................................................................................................................... 88 5.1.4 Poor Drilling Practices........................................................................................................................... 88

5.2 PROBLEMS ASSOCIATED WITH DEVIATION...................................................................................................... 89 5.2.1 Doglegs and Keyseats ............................................................................................................................. 89 5.2.2 Ledges ..................................................................................................................................................... 90 5.2.3 Stuck Pipe ............................................................................................................................................... 90 5.2.4 Increased Torque/Drag and Drill Pipe Fatigue ..................................................................................... 90 5.2.5 Casing and Cementing ............................................................................................................................ 91

5.3 PREVENTION OF DEVIATION............................................................................................................................ 92 5.3.1 Pendulum Effect ...................................................................................................................................... 92 5.3.2 Pendulum Assembly ................................................................................................................................ 92 5.3.3 Packed-Hole Assembly............................................................................................................................ 93 5.3.4 Packed Pendulum Assembly.................................................................................................................... 94 5.3.5 Stabilizers and Reamers.......................................................................................................................... 94 5.3.6 Drilling Procedures ................................................................................................................................ 95

6 DIRECTIONAL AND HORIZONTAL DRILLING ....................................................................................... 96 6.1 REASONS FOR DIRECTIONAL DRILLING ........................................................................................................... 96 6.2 SURVEYS/CALCULATIONS............................................................................................................................... 98

6.2.1 Survey Methods....................................................................................................................................... 98 Single-Shot Surveys ...................................................................................................................................... 98 Multi-Shot Surveys........................................................................................................................................ 98



4

Gyroscopic Surveys....................................................................................................................................... 98 Measurement While Drilling (MWD) ........................................................................................................... 98

6.2.2 Survey Measurements ............................................................................................................................. 99 6.2.3 Survey Calculation Methods ................................................................................................................... 99

Radius of Curvature ...................................................................................................................................... 99 Minimum Curvature .................................................................................................................................... 100

6.2.4 Directional Drilling Terminology ......................................................................................................... 101 6.3 DRILLING TECHNIQUES ................................................................................................................................. 103

6.3.1 Well Profiles.......................................................................................................................................... 103 Shallow Deflection Profile .......................................................................................................................... 103 S-Curve Profile............................................................................................................................................ 103 Deep Deflection Profile............................................................................................................................... 103

6.3.2 Drilling Stages ...................................................................................................................................... 104 6.3.3 Whipstocks, Motors and Techniques..................................................................................................... 105

Whipstocks.................................................................................................................................................. 105 Downhole Motors and Bent Subs................................................................................................................ 105 Rotating and Sliding.................................................................................................................................... 106 Jetting.......................................................................................................................................................... 106

6.4 HORIZONTAL DRILLING................................................................................................................................. 107 6.4.1 Classification ........................................................................................................................................ 107 6.4.2 Horizontal Drilling Considerations ...................................................................................................... 108

Radius Effects ............................................................................................................................................. 108 Reversed Drill String Design ...................................................................................................................... 108 Drill Pipe Fatigue ........................................................................................................................................ 109 Hole Cleaning.............................................................................................................................................. 109 Use of Top Drives ....................................................................................................................................... 110 Casing and Cementing................................................................................................................................. 110 Formation Considerations ........................................................................................................................... 110 Formation Evaluation.................................................................................................................................. 111 Gas Behaviour/Well Control ....................................................................................................................... 111

7 DRILLING PROBLEMS ................................................................................................................................. 112 7.1 FORMATION PROBLEMS AND HOLE STABILITY.............................................................................................. 112

7.1.1 Fractures............................................................................................................................................... 112 Associated Problems ................................................................................................................................... 112 Drilling Fractured Formations..................................................................................................................... 113

7.1.2 Shales .................................................................................................................................................... 113 Reactive Shales ........................................................................................................................................... 113 Overpressured Shales .................................................................................................................................. 114

7.1.3 Surface Formations............................................................................................................................... 115 7.1.4 Salt Sections .......................................................................................................................................... 115 7.1.5 Coal Beds .............................................................................................................................................. 115 7.1.6 Anhydrite/Gypsum Formations ............................................................................................................. 116

7.2 LOST CIRCULATION....................................................................................................................................... 117 7.2.1 Occurrences .......................................................................................................................................... 117 7.2.2 Detection ............................................................................................................................................... 117 7.2.3 Problems ............................................................................................................................................... 118 7.2.4 Prevention ............................................................................................................................................. 118 7.2.5 Remedies ............................................................................................................................................... 119

7.3 KICKS AND BLOWOUTS ................................................................................................................................. 120 7.3.1 Causes Of Kicks .................................................................................................................................... 120 7.3.2 Kick Warning Signs............................................................................................................................... 121 7.3.3 Indications Of Kicks While Drilling...................................................................................................... 122 7.3.4 Indicators While Tripping ..................................................................................................................... 123 7.3.5 Flowchecks............................................................................................................................................ 124



5

7.4 STUCK PIPE................................................................................................................................................... 125 7.4.1 Hole Pack-Off or Bridge ....................................................................................................................... 125

Sloughing or Caving of Reactive or Pressured Shales ................................................................................ 125 Fractured or Unconsolidated Formations .................................................................................................... 126 Settling Cuttings and Cuttings Beds ............................................................................................................ 126 Cement or Junk ........................................................................................................................................... 126 Mobile Salt.................................................................................................................................................. 126

7.4.2 Differential Sticking .............................................................................................................................. 127 7.4.3 Wellbore Geometry ............................................................................................................................... 128 7.4.4 Rotary Drilling Jars .............................................................................................................................. 129

Hydraulic Jars ............................................................................................................................................. 129 Mechanical Jars........................................................................................................................................... 130 Jar Accelerator ............................................................................................................................................ 130

7.4.5 Fish – Cause and Indication ................................................................................................................. 130 7.4.6 Fishing Equipment ................................................................................................................................ 131

Junk Basket ................................................................................................................................................. 131 Fishing Magnet............................................................................................................................................ 131 Impression Block ........................................................................................................................................ 132 Milling Tools............................................................................................................................................... 132 Overshots .................................................................................................................................................... 132 Spears.......................................................................................................................................................... 132 Washover Pipe ............................................................................................................................................ 133 Free-Point Indicator .................................................................................................................................... 133 Jars and Accelerators................................................................................................................................... 133 Safety Joints and Bumper Subs ................................................................................................................... 133

7.5 DRILL STRING VIBRATIONS........................................................................................................................... 134 7.5.1 Torsional Vibration............................................................................................................................... 134 7.5.2 Axial Vibration...................................................................................................................................... 135 7.5.3 Lateral Vibration .................................................................................................................................. 137

7.6 WASHOUTS ................................................................................................................................................... 139 7.6.1 Drill String Washouts............................................................................................................................ 139 7.6.2 Hole Washouts ...................................................................................................................................... 139

8 UNDERBALANCED DRILLING ................................................................................................................... 141 8.1 BENEFITS AND LIMITATIONS OF UNDERBALANCED DRILLING ....................................................................... 142 8.2 UNDERBALANCED DRILLING FLUIDS............................................................................................................. 143

8.2.1 Gas & Air Drilling ................................................................................................................................ 143 Advantages and Disadvantages ................................................................................................................... 143 Equipment ................................................................................................................................................... 143 Drilling Operations...................................................................................................................................... 144 Drilling Problems ........................................................................................................................................ 144

8.2.2 Mist ....................................................................................................................................................... 145 8.2.3 Foam ..................................................................................................................................................... 145 8.2.4 Aerated Mud.......................................................................................................................................... 146 8.2.5 Mud ....................................................................................................................................................... 146

8.3 EQUIPMENT AND PROCEDURES ..................................................................................................................... 148 8.3.1 Rotating Heads...................................................................................................................................... 148 8.3.2 Closed Circulating and Separating Systems ......................................................................................... 148 8.3.3 Blooie Line and Sample Catcher .......................................................................................................... 149 8.3.4 Gas Measurement ................................................................................................................................. 149

8.4 COILED TUBING UNITS.................................................................................................................................. 151 8.4.1 Components........................................................................................................................................... 151 8.4.2 Drilling Applications............................................................................................................................. 152 8.4.3 Advantages and Disadvantages ............................................................................................................ 152



6

9 ROCKS AND RESERVOIRS.......................................................................................................................... 154 9.1 INTRODUCTORY PETROLOGY ........................................................................................................................ 154

9.1.1 Igneous.................................................................................................................................................. 154 9.1.2 Metamorphic ......................................................................................................................................... 154 9.1.3 Sedimentary........................................................................................................................................... 154

Sediment Classification............................................................................................................................... 155 Compaction and Cementation ..................................................................................................................... 156 Clastic Rock Types ..................................................................................................................................... 156 Chemical and Organic Rock Types ............................................................................................................. 157

9.2 PETROLEUM GEOLOGY ................................................................................................................................. 158 9.2.1 Petroleum Generation........................................................................................................................... 158 9.2.2 Maturation of Petroleum....................................................................................................................... 159 9.2.3 Petroleum Migration............................................................................................................................. 160 9.2.4 Primary Migration ................................................................................................................................ 160 9.2.5 Secondary Migration ............................................................................................................................ 161 9.2.6 Hydrocarbon Traps............................................................................................................................... 162

Stratigraphic Traps...................................................................................................................................... 162 Structural Traps........................................................................................................................................... 163

9.3 PETROLEUM COMPOSITION ........................................................................................................................... 165 9.3.1 Saturated Hydrocarbons or Alkanes..................................................................................................... 165

Paraffin........................................................................................................................................................ 165 Naphthenes.................................................................................................................................................. 167

9.3.2 Unsaturated Hydrocarbons or Aromatics............................................................................................. 167 9.3.3 API Gravity Classification .................................................................................................................... 168

9.4 RESERVOIR CHARACTERISTICS ..................................................................................................................... 169 9.4.1 Porosity ................................................................................................................................................. 169

Sandstones................................................................................................................................................... 169 Limestones .................................................................................................................................................. 169

9.4.2 Permeability .......................................................................................................................................... 170 9.4.3 Water Saturation ................................................................................................................................... 170 9.4.4 Reservoir Zones, Contacts and Terminology ........................................................................................ 171

10 MUD LOGGING - INSTRUMENTATION AND INTERPRETATION................................................... 172 10.1 DEPTH AND RATE OF PENETRATION............................................................................................................ 172

10.1.1 The Geolograph .................................................................................................................................. 172 10.1.2 Depth Wheel........................................................................................................................................ 173 10.1.3 Crown Sheave ..................................................................................................................................... 173 10.1.4 Drawworks Sensor .............................................................................................................................. 174 10.1.5 Heave Compensation .......................................................................................................................... 174 10.1.6 Rate of Penetration ............................................................................................................................. 177

Bit Selection................................................................................................................................................ 177 Rotary Speed (RPM)................................................................................................................................... 177 Weight on Bit (WOB or FOB) .................................................................................................................... 177 Differential Pressure.................................................................................................................................... 178 Hydraulics and Bottom Hole Cleaning........................................................................................................ 178 Bit Wear ...................................................................................................................................................... 179 Lithology..................................................................................................................................................... 179 Depth........................................................................................................................................................... 179 Formation Pressure...................................................................................................................................... 179

10.1.7 Drilling Breaks.................................................................................................................................... 179 10.1.8 Controlled Drilling ............................................................................................................................. 181

10.2 HOOKLOAD AND WEIGHT ON BIT................................................................................................................ 183 10.2.1 Load or Pancake Cell ......................................................................................................................... 183 10.2.2 Strain Gauge ....................................................................................................................................... 184



7

10.2.3 Weight on Bit....................................................................................................................................... 184 10.2.4 Hookload, Drag and Overpull ........................................................................................................... 185

10.3 ROTARY SPEED AND ROTARY TORQUE....................................................................................................... 187 10.3.1 Rotary Speed ....................................................................................................................................... 187 10.3.2 Rotary Torque ..................................................................................................................................... 187 10.3.3 Formation evaluation and fracture identification............................................................................... 189 10.3.4 Sticking Pipe ....................................................................................................................................... 189 10.3.5 Torsional Vibrations ........................................................................................................................... 190

10.4 PUMP OR STANDPIPE PRESSURE.................................................................................................................. 191 10.5 ANNULAR OR CASING PRESSURE ................................................................................................................ 194 10.6 PUMP RATE AND OUTPUT ........................................................................................................................... 195

10.6.1 Pump Output Calculation ................................................................................................................... 196 10.6.2 Lag Calculations................................................................................................................................. 197

10.7 FLOWRATE AND PIT LEVELS ....................................................................................................................... 201 11 MUDLOGGING PROCEDURES ................................................................................................................. 203

11.1 CUTTINGS DESCRIPTIONS............................................................................................................................ 203 11.1.1 Rock Type and Classification.............................................................................................................. 203 11.1.2 Color ................................................................................................................................................... 203 11.1.3 Texture ................................................................................................................................................ 204

Carbonate Rocks ......................................................................................................................................... 204 Siliceous Rocks ........................................................................................................................................... 204 Argillaceous Rocks ..................................................................................................................................... 205 Carbonaceous Rocks ................................................................................................................................... 205

11.1.4 Cement and Matrix.............................................................................................................................. 205 11.1.5 Hardness ............................................................................................................................................. 205 11.1.6 Fossils and Accessory Minerals.......................................................................................................... 205 11.1.7 Sedimentary Structures ....................................................................................................................... 206 11.1.8 Porosity ............................................................................................................................................... 206

Siliceous Rocks ........................................................................................................................................... 206 Carbonate Rocks ......................................................................................................................................... 206

11.1.9 Chemical Tests .................................................................................................................................... 206 HCl Effervescence....................................................................................................................................... 206 HCl Oil Reaction......................................................................................................................................... 206 Swelling....................................................................................................................................................... 207 Sulphate Test – Gypsum and Anhydrite ...................................................................................................... 207 Chloride Test............................................................................................................................................... 208 Alizarin Red ................................................................................................................................................ 208 Cement Test ................................................................................................................................................ 208

11.2 OIL SHOWS ................................................................................................................................................. 209 11.2.1 Odour .................................................................................................................................................. 209 11.2.2 Oil Staining and Bleeding................................................................................................................... 209 11.2.3 Fluorescence ....................................................................................................................................... 209

Sample Preparation ..................................................................................................................................... 210 Contaminants............................................................................................................................................... 210 Colour and Brightness................................................................................................................................. 211 Fluorescence Distribution ........................................................................................................................... 211 Solvent Cut.................................................................................................................................................. 212 Residue........................................................................................................................................................ 213 Sampling the mud........................................................................................................................................ 213

11.2.4 Quantitative Fluorescence TechniqueTM ............................................................................................. 213 11.3 CUTTINGS BULK DENSITY........................................................................................................................... 216 11.4 SHALE DENSITY .......................................................................................................................................... 218 11.5 SHALE FACTOR ........................................................................................................................................... 220 11.6 CALCIMETRY .............................................................................................................................................. 221



8

11.7 ENHANCED HOLE MONITORING .................................................................................................................. 223 11.7.1 Consequences of poor stability / poor hole cleaning .......................................................................... 223 11.7.2 Problems of Measuring Actual Cuttings Volume................................................................................ 223

Are all the cuttings being collected? ........................................................................................................... 224 What about mud volume?............................................................................................................................ 224 How accurate is the unit of measurement for a period of an hour? ............................................................. 224

11.7.3 Volume of Vessel ................................................................................................................................. 224 11.7.4 Measurement of Cuttings/Hour........................................................................................................... 225 11.7.5 Correction to Total Volume ................................................................................................................ 225 11.7.6 Theoretical Cuttings Volume............................................................................................................... 227 11.7.7 Actual/Theoretical Cuttings Volume Ratio ......................................................................................... 228 11.7.8 Recording, Evaluating and Reporting ................................................................................................ 228

11.8 HIGH RESOLUTION TRIP MONITORING ........................................................................................................ 232 11.8.1 Theory and Benefits ............................................................................................................................ 232 11.8.2 Procedure............................................................................................................................................ 232

Theoretical Hookload.................................................................................................................................. 233 System and Data Preparation ...................................................................................................................... 233

11.8.3 Interpretation ...................................................................................................................................... 233 11.8.4 Benefits to the Operator...................................................................................................................... 236

11.9 DST PROCEDURES...................................................................................................................................... 237 11.9.1 Water Cushion..................................................................................................................................... 237 11.9.2 Test String Components ...................................................................................................................... 237 11.9.3 Testing Procedures ............................................................................................................................. 241



9

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. The technique used was percussive drilling where a hardened bit, suspended on a cable, was repeatedly dropped onto the bottom of the hole. The constant pounding would break up the formation, deepening the hole in the process. The drawbacks to the cable tool rig were limited depth capabilities, very slow drilling rates and no way to control subsurface formation pressures. Modern drilling uses a rotary drilling method providing faster drilling rates, much greater depth capabilities, offshore drilling, and the safe control of subsurface pressures.

1.1.1 Land Rigs Land rigs are typically 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, then raised to a vertical position by using the rigs hoisting system (drawworks). Blow out preventers are positioned directly beneath the rig floor, connecting the floor to the well head. This allows drilling fluid to be circulated and pipe to be lifted in and out of the well.

1.1.2 Offshore drilling vessels Drilling offshore obviously requires a completely self-contained vessel, not only in terms of drilling requirements, but also in terms of accommodation for personnel. Situated in remote, hostile locations, they are much more costly to operate and require more sophisticated safety measures since 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 that they are required to operate in. Temporary installations (that can move from location to location) used for exploratory drilling, can either be supported by the seabed or they can be floating and anchored in positioned. Permanent installations, or platforms, are required for production wells.

Barges

These are small, flat-bottomed vessels that can only be used in very shallow waters such as deltas, swamps, lagoons and shallow lakes.

Jack-Up Rigs

These are mobile vessel suitable for drilling in shallow seawater depths. They consist of a fixed hull or platform, which is supported on by a number of legs, typically 3, that stand on the seafloor. To move a jack-up rig, the legs can be raised so that the rig floats on its hull enabling it to be towed into position by barges. This makes the vessel very top heavy and unstable during towing, so that calm waters and slow towing speeds are essential to avoid capsize. Once in the required position, the legs



10

can be lowered to the seabed creating a very stable structure unaffected by wave motion. The blow out preventers are mounted underneath the rig floor, so that a large conductor pipe, driven into the seafloor, is required to connect the well to the rig and allow drilling fluid to be circulated.

Semi-Submersible Rigs

“Semi-subs” are floating rigs that are suitable for drilling in deeper waters than jack-ups. The deck is supported by a number of legs or columns. Subsea, these columns are supported by pontoons which can be solitary or connected. Both pontoons and columns are utilized to ballast and stabilize the rig. This substructure sits below the sea surface, avoiding the worst, surface turbulence of the water. This makes them more stable than drillships and therefore more suited to drilling in rough seas. The pontoons are fitted with thrusters for position adjustment or self- propulsion, but they are generally moved into position by sea going tugs, with the thrusters being used to assist in the final positioning of the rig. Once correctly positioned, the semi-submersible is anchored in place, although in deeper waters the thrusters may be used to maintain position by way of an automated location monitor. Unlike the jack-up, blowout preventers are located on the seabed, mounted on conductor pipe that has been set into the seafloor. Positioning of the BOP’s is very tricky and achieved with the assistance of underwater cameras or remotely operated vehicles (ROV’s). This allows the well to be left secure should the rig be forced to abandon the location. A large flexible, telescopic steel pipe, called the marine riser, connects the BOP’s to the rig, enabling drilling fluid to be circulated and the drillstring to be guided into the well.

Drillships

Drillships are capable of drilling in deeper water. They are generally self propelled and therefore easily transported to the drilling location. They are extremely mobile, but generally less stable than semi-submersibles and therefore not able to drill in rougher seas. A drillship can be anchored, or position maintained by automated thruster systems. The drillship has exactly the same subsea equipment as a semi-submersible, with the BOP’s mounted on the seabed. To compensate for movement of the drillship (also semi-submersibles), the 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, before it becomes subjected to too much bending and stress.

Platforms

Platforms are permanently fixed structures installed where mobility is not required. This is typically when multiple wells are going to be drilled to develop and produce a field. Platforms can be of two designs, piled or gravity structures. A piled platform consists of a steel jacket, which is pinned to the seabed and supports the deck structure. This type of platform is stable in very bad weather conditions, but is not very mobile. They are usually constructed in separate sections that can be individually towed to position and constructed in place. Gravity type platforms are constructed from concrete, steel or a combination of both. They have a cellular base, providing both ballast and storage, with vertical columns supporting the deck structure. They are normally constructed in their entirety, then towed to the location and ballasted into position.



11

1.1.3 Land Rig Examples

…..before the mast has been raised into position



12



13

1.1.4 Jack Up Example

3 Supporting legs are most typical. Note, here, that drilling has not yet started, since there is no conductor pipe in place.



14

1.1.5 Semi-Submersible Example



15

2 ROTARY RIG COMPONENTS The modern rotary drilling rig, whatever the type, consists of 5 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 will typically be a combination of ‘standard’ drillpipe, thicker, heavier drillpipe and larger diameter, 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). 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, via 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). Formations in the shallower part of the wellbore are usually protected by large diameter steel tubing, or casing, which is cemented into place. The annulus that the mud now passes through on it’s 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 blowout preventer stack (5), a series of valves and seals that can be used to close off the annulus or wellbore in order to control large subsurface pressures. All of the equipment described above is operated by a central power system (4), which will also supply the general power required for electrical lighting, service company equipment etc. Typically, this power source is by way of a central diesel-electric power plant.



16

2.1 The Hoisting System

The complete hoisting system has several basic functions: -

• Supporting the weight of the drillstring, possibly up to several hundred tonnes. • 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 to the weight of drillpipe that can be supported and therefore the depth that the rig is capable of drilling to. The height of the derrick will determine the length of the pipe sections that can housed when the drillstring has to be pulled from the hole. During this operation, the pipe will normally be broken down into double or triple stands (2 or 3 individual lengths, or joints, of pipe). During the drilling operation, the kelly and drillstring are supported from the traveling block by way of the traveling hook. This is connected to the drawworks by way of a simple pulley system. 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. 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. Here, the cable is repeatedly passed between a series of wheels, or sheaves, and the

Crown block

Dead line

Dead line anchor Drawworks drum

Drill line or Fast line

Travelling block

Hook

Fast sheave

The hoisting system supported by the derrick



17

traveling block suspended in the derrick, so that the traveling block will be suspended 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 dead line, and the deadline anchor is typically located to one side of rig floor. 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 that it is spooled around is generally larger than the others and known as the fast sheave.

The usage 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 kilometre. This record allows the drilling crew to determine when the drilling line needs to 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 dead line anchor so that new line can be fed, or slipped, through. The line is tensioned by feeding it through the pulley system and pulling

Drawworks Drum

Fast line up to crown block

Bushings

Kelly

Elevators

Travelling block

Hook

Kelly hose



18

the old line out from the drawworks. This old line can be removed, or cut, and the new length of cable tensioned and anchored once more at the dead line anchor. This procedure allows for even wear on the drilling line as it is used. The drawworks have 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 that is supported by the derrick and that which is supported by the bottom of the hole. This equates to the weight, or force, that is applied to the bit, and thus can be adjusted according to the hardness of the formation and the weight required in order to produce failure of the formation, and allow penetration, or deepening of the hole to proceed.

2.1.1 Providing Rotation to the Drillstring and Bit

Kelly and Swivel The kelly is a hollow length of steel, normally around 12 or 13m in length, either square or hexagonal, through which drilling fluid can enter the drillpipe. The top of the drillstring is connected to the kelly by a kelly sub (or saver sub). This sub, being 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. Free vertical movement of the kelly is possible through the bushing, allowing upward and downward movement of the drillstring. Rollers within the bushing facilitate this movement and, again, minimize the wear on the kelly. The shape of the kelly (commonly 4 or 6 sided) fits exactly into the bushing so that, if the bushing rotates, the kelly rotates. Since the bushing is locked into the rotary table, rotation of the table (either electrically or mechanically) will rotate the bushing and therefore the kelly and drillpipe. Vertical movement is still possible even if the kelly is rotating. When the kelly is lifted from the ‘hole’ to expose the drillpipe, the kelly bushings are lifted along with the kelly. Between the kelly and the hook is an assembly known as the swivel. This supports the kelly but does not rotate as the kelly rotates. This 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. This ‘kelly cock’ can be manually closed in the event of the well flowing due to high, subsurface, formation pressure. This prevents back pressure from entering, and perhaps damaging, the kelly swivel.

kelly

kelly bushings

rotary table

drillpipe joint in mousehole



19

Top Drive Units On more recent rigs, the rotary drive and swivel are combined into a single top drive unit, which may be electrically or hydraulically operated. The drillstring now 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. Since rotation is now applied directly to the top of the drillstring, there is no requirement for a kelly and rotary bushing.

The advantage of a top drive unit over the conventional kelly system is primarily one of time and cost. With the kelly, as drilling progresses, 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 re-attaching the new pipe and kelly back to the drillstring. With a top drive unit, this operation is not only made much simpler by the fact that pipe is connected directly to the unit, but it also enables a stand of drillpipe (equivalent to 3 single joints of pipe) to be picked up and added to the drillstring at any one time. A complete stand of drillpipe can therefore be drilled continuously, so that only one connection is required for every three that would be required with a kelly. Overall time required to make ‘connections’ is therefore much 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 the top drive unit is during tripping operations, when the drillstring is being lifted in or

out of the hole. The conventional kelly is not used when tripping pipe. It is set aside on the rig floor in what is called the ‘rat-hole’. Bails and elevators are then used to lift the drillstring. If the pipe was to become stuck during the trip, circulation of drilling fluid may be required to free the pipe. In order to achieve this, the kelly would have to be picked up from the rat-hole and attached to the drillstring, a process that may take as long as 5 or 10 minutes during which time, the ‘sticking’ of the pipe may become worse. With a top drive unit, elevators are again used to lift the pipe, but these are

Travelling Block

Elevators

Top Drive

Drillpipe ‘ingress”



20

suspended beneath the top drive unit. It is therefore 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 that may be required to resolve it.

2.1.2 Lifting Equipment The procedures of tripping, lifting the pipe in and out of the hole, and making connections, adding new lengths of drillpipe to the drillstring in order to drill deeper, have already been introduced. Handling of the pipe during these operations requires the use of specialized pieces of equipment. To pull a stand of drillpipe from the hole, the elevators are clamped around the pipe. When the blocks are raised, the elevators rest beneath the larger diameter tool joint so that the pipe can be lifted. When the stand is completely above the rotary table, slips will be held around the pipe as it is slowly lowered. The slips will wedge firmly in the rotary table, clasping the pipe. The total weight of the string is now supported by the rotary table. The stand above the table can now be removed from the string and set aside. Firstly, the tool joint connection is broken with two sets of tongs, one positioned beneath the tool joint holding the pipe steady, the second positioned above the tool joint. This is connected by a chain, which is pulled in at the cathead, breaking the connection. The stand is quickly unscrewed by

using a pipe spinner, so that it is free and hanging from the elevators. The stand is racked to one side of the derrick and held in position by placing the top of the stand in a rack known as ‘fingers’. This operation is performed by the derrickman who works up in the derrick on a platform known as the monkey board.

Bails and Elevators These are used to lift the pipe into position or remove it when the connection has been broken. The elevators are simply clamps that are placed and closed around the ‘stem’ of the pipe. As the elevators are lifted, they will move up the pipe until they come against the wider tool joint so that the pipe can be lifted. The elevators are suspended from the traveling block by links or bails, so that vertical movement is applied from the drawworks. Elevators are of

bails

elevators

slips

racked drillpipe

monkey board and fingers



21

specific sizes and designs to accommodate pipe of different diameter, casing joints and drill collars.

Slips While connections are being made or broken, the drillstring has to be suspended and supported in the rotary table to prevent it from fallen down the hole. This is achieved by using slips, tapered or wedged shaped dies held together in a frame with handles. These are placed around the ‘stem’ of the pipe and lowered, along with the pipe, into the master bushings where they become ‘set’, fully supporting the weight of the drillstring in the rotary table.

Tongs These are used to tighten or loosen the 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, being placed on either side of the connection or joint. The lower tong will hold the drillstring in place below the joint and the upper tong, by pulling on the chain, will loosen or break the connection or in the opposite direction, tighten or make the connection. When making the connection, a gauge on the chain allows the correct amount of torque to be applied.

Power Tongs and Pipe Spinners These are pneumatically powered ‘wrenches’ enabling rapid spinning of the pipe during the making or breaking of connections. Tongs will be used to apply final torque when making the connection and to initially loosen the joint when breaking the connection.

Chain Wrench If pneumatic wrenches are not available, spinning of the pipe has to be done manually by way of a chain wrench. Chain is wrapped around the pipe, clasped and gripped by the wrench. Spinning of the pipe is done by physically

walking around the pipe while it is gripped and held by the wrench. When pipe has to be added in order to drill further, it is picked up from the pipe deck to one side of the rig. A winch is used to pull the pipe up so that is resting vertically against the “v-door”, a ramp that joins the pipe deck to the rig floor. The blocks can then be lowered and the joint of pipe picked up in the elevators (different elevators are used to pick up collars or casing tubular). Once picked up, the joint of

Slips

chain to cathead

pipe spinner

tongs

Breaking tool joint to make a connection



22

pipe is lowered into the mousehole (a hole drilled into the surface sediments and lined with tubular) where it is ready for use when the next connection is to be made.

rig floor

“v-doors”

pipe deck

casing joints



23

2.2 The Circulating System We have already seen how the drilling fluid, commonly called mud, enters the drillstring through the kelly or top drive unit. There are many ways in which the mud aids the drilling process and, in fact, is a vital component to the successful drilling of a well. The most important functions are: - • To cool and lubricate the drill bit and drillstring in order to minimize wear, prolong their life and

reduce costs. • To remove the drilled rock fragments, or cuttings from the hole. This not only keeps the annulus

clear but also allows examination at surface for formation evaluation. • To balance high fluid pressures that may be present in some formations and minimizing the

potential of kicks or blowouts. The safety of the rigs personnel and of the rig itself is of paramount importance in any drilling operation.

• To stabilize the wellbore and formations that have already been drilled. Types of drilling mud and it’s function will be discussed in more detail in section 4.



24

Creating a drilling mud is almost like cooking, with many ingredients or additives going into the system, each having a particular function to perform. The mud is ‘built’ and stored in mud tanks or pits. Different names are given to individual pits depending on their specific function. Typically, they may be called: - Premix Pit Where additional chemicals are added and mixed into the mud system.

Suction Pit The pit where mud is taken by the rig pumps to begin it’s journey to the drillstring. This is the ‘live’ or ‘active’ pit, lined up to the actual wellbore.

Reserve Pit Or Settling Pit. Additional mud volume, generally not part of the ‘active’

system.

Shaker Pit This is the tank situated directly beneath the shale shakers. A sand trap is normally an integral part of the shaker pit. It’s purpose is to allow as much fine material, sand and silt, to settle out from the mud system and be removed.

Trip Tank A smaller tank, used 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 used to make up small volumes of ‘special’ mud that may be

required for specific operations during the drilling of a well.

The number of the pits required will depend on the size and the depth of the well being drilled, and thus on the volume of mud required to fill that hole. Typically, 4 to 6 tanks may be used, but for larger wells and platforms, this number may increase to 16 or more. From it’s storage in 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, through the swivel into the kelly from where it is forced down the inside of the drillstring. Exiting the drillstring through the bit, the mud then returns to surface by way of the annulus (the space between the wellbore wall/casing and the outside of the drillstring).

Pit level sensor

Mud agitator

Grating covering



25

In the case of offshore wells, a further conduit has to be positioned to allow mud to be circulated from the seabed to the rig. This is done by way of 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 jackups and platforms. Marine Riser A pipe connected to the top of the BOP stack which is located on the seabed on semi-

submersibles 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.

2.2.1 Solids Control Equipment Solids control is vital in maintaining efficient drilling operations. High mud solids increase the 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 is suitable for recirculating in the well. Mud treatment clays and chemicals must also be added from time to time to maintain the required properties. All of these functions require special equipment. Once exiting the wellbore at 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). This is where the mud logger will position a gas trap and mud monitoring sensors to analyze the mud returning from the hole.

Gates in the shaker box regulate the flow of mud onto the shale shaker. Here, sloped, vibrating mesh screens (normally two) separate the drilled cuttings from the drilling mud, which is allowed to pass through the 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 over again. The screens can be changed so that the size of the mesh

SHALE SHAKER

Shaker box with gas trap and mud parameter sensors

Mud return flowline



26

is appropriate to the size of the cuttings needing to be removed. Normally, a coarser screen is positioned above a finer screen. The vibration motion of the screens improves the separation of the mud from the cuttings. Samples for geological analysis will be collected at this point. With environmental concerns an important consideration, the cuttings separated at the shale shaker are collected in tanks so that they can be easily transported to sites where they can be thoroughly cleaned of any residual mud or chemicals and deposited. Additional equipment is often put into the circulating system before the mud reaches the mud tanks. If the mud is particularly gaseous, it may be 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 may still be very fine solid material such as silt or sand grains that have to be removed from the mud. 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 muds flowrate is reduced allowing solids to separate and settle. The bottom of the trap is sloped so that the settling particles fall to the base where they collect and can discarded. If these particles do not settle out when the mud passes through the sand trap, it will be necessary, before returning it to the mud tanks, to pass the mud through additional solids control equipment.

premix pit

mixing hopper

centrifuge

desilter

desander

degasser

return flowline

shaker box

shale shaker

sand trap shaker pit

reserve & settling pits

suction or active pit

suction line to rig pump



27

A desander, when used in addition to the shale shaker, removes most of the abrasive solids, thereby reducing wear on the mud pumps, surface equipment, drill string and bit. Also used in conjunction with the shale shaker and desander is a desilter, which removes even finer material from the mud. Desanders and desilters separate solids in a hydroclone, a cone-shaped separator in which the fluid rotates and causes the solids to separate by centrifugal force. The drilling fluid flows upward, in a helical motion, through conical chambers, where solid particles are thrown outward from the drilling fluid. At the same time, water passes downward through the chamber, carrying away the solid particles removed from the mud.

Additional centrifuges may also be used in order to remove large amounts of clay solids suspended in the mud. Once 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 has to be significantly reduced, rather than adding liquid and increasing the volume. The centrifuge may also be used to remove glass or plastic beads that have been used to improve lubrication or to reduce density in underbalanced applications. This ‘solids control’ performed by the surface equipment is a very important aspect of maintaining the mud. Fine grains would obviously be very abrasive and damaging to equipment such as pumps, drillstring and bit etc. It is also important in controlling the density of the mud. If

solids were allowed to remain and build up in the mud, it’s density would increase as a result. One further step that may be required to prepare the drilling mud for recirculation is performed by a degasser, which separates and vents large volumes of entrained gas to a flare line. Recirculating gas-cut mud can be hazardous and will reduce pumping efficiency and lower the hydrostatic pressure 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). Most rigs have two rig pumps to circulate the mud under pressure around the entire system. Smaller rigs drilling shallower holes may only require one. Rig pumps can be of two types: -

mud inlet

water and solid discharge

clean mud A hydroclone



28

Duplex Pumps These possess 2 cylinders, or chambers, each of which discharges drilling fluid on both forward and backward motion of the pump stroke. As the mud is being discharged on one side of the piston, the cylinder is being filled up from the other side of the piston. As the piston returns, this mud will now be discharged, with the previously discharged side now being refilled behind the piston.

Triplex Pumps These possess 3 cylinders. Only the duplex pump, mud is only discharged on the forward

stroke. In each cylinder, mud is discharged by the pushing motion of the piston on the forward part of the stroke, leaving the cylinder behind the piston empty. As the piston returns on the backward part of the stroke, mud re-fills the chamber. This mud will again be discharged on the forward part of the pump stroke.

TRIPLEX PUMP CHAMBER & PISTON



29

2.3 Drill Bit and Drillstring

2.3.1 Drag Bits These 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 (RPM). They are only really suitable for drilling soft, unconsolidated formations, lacking the hardness and wear resistance required for consolidated formations.

2.3.2 Roller Tri-Cone Bits Early bits possessed 2 cones that had no interaction, or meshing, and were therefore prone to balling (where drilled cuttings collect and consolidate, or ball, around the bit) in soft formations. These were

superceded by the Tri-Cone bit, the most common bit type used in modern drilling. These possess 3 cones, which are intermeshing and therefore self-cleaning, with rows of cutters on each cone. The cutters are of two principle types, either milled teeth or tungsten carbide inserts (TCI), and can be of varying size and hardness according to the lithologies expected. A lot of heat is generated by friction during drilling and this heat has to 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. They 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 either expressed in millimetres 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, i.e. thirty two 32nds). Roller bits are classified by a system developed by the

International Association of Drilling Contractors (IADC): Most roller bits would therefore have a 3 digit IADC Code. For example: 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,

friction sealed journal bearings and gauge protected.

Tri-cone tooth bit



30

Certain bits may also have a 4th 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).

Bit Terminology

Tri-cone button bit (tungsten carbide inserts)

IADC Bit Classification

1 Soft 2 Medium 3 Hard

Milled Tooth

4 Very soft 5 Soft

Chisel

6 Medium 7 Hard

Series Type of cutting structure

8 Very hard

Conical

Tungsten Carbide Insert

Type Degree of hardness of cutting structure

1-4 1 – softest 4 – hardest

1 Standard product 2 Air drilling 3 Gauge protected 4 Sealed bearing 5 Gauge protected and sealed bearing

Design Option Bearing design and gauge protection

6 Friction, sealed journal bearing

shank

nozzle boss

jet or nozzle

sculptured inserts

cone heel row

inner heel row

middle row

Shirt tail

bit leg

shoulder

cone nose



31

7 Friction, sealed journal bearing, gauge protected 8 Directional

9 Other

Cone Action As cones roll on the bottom of the hole, a sliding action is produced that gouges and scrapes the formation. Cones have more than one rolling centre due to number and alignment of cutter rows, but this is restrained by the weight of the drill collars acting on the bit. Rotation will therefore be around the bit centre-line so that the teeth must slide and scrape as they roll. This action is minimized in the design of 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”, 1/8” in medium bits, none for hard bits.

Bearing Types Unsealed These are grease filled and exposed. Their life is therefore short since

they are exposed to both metal fatigue and to 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 much longer life, but wear may come from seizure of the

sliding metal to metal surfaces on the bottom side of bearings. If the seal fails, drilling mud will leak into the bearing, displacing the grease. Overheating will cause 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.

Teeth

inner heel row

heel row

middle row

nose row

jet or nozzle



32

The size, shape and separation of the teeth affect the efficiency, or performance, of the bit in formations of varying hardness. The tooth design will also determine the size and form of the drilled cuttings produced and subsequently used for formation evaluation. For soft formations, the teeth are typically long, slender and widely spaced. The longer teeth allow for 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 will be large and freshly broken. Bearing size and strength is necessarily restricted in soft formation bits owing to the size of the teeth. This normally does not produce a problem since only low weights or force need to be applied to the bit to achieve formation failure and penetration. For formations of medium hardness, shorter, 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 while, 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 such an important consideration as in the soft formation. For drilling in hard formations, short, broad teeth produce a crushing and chipping action rather than scraping and gouging. The drilled cuttings will be smaller, more rounded, crushed and ground. Tooth spacing is not required for cleaning since cuttings are smaller, with a lower concentration, or volume, resulting from lower penetration rates. Increased life in hard, abrasive formations can be produced by hard facing the milled steel teeth or by using tungsten carbide inserts (TCI). For harder formations, fewer and smaller teeth facilitate larger, stronger bearings that can withstand the higher forces that may cause failure.

Operating requirements Hard, abrasive formations require a higher force (weight on bit or WOB) being applied to the bit. The greater weight would obviously impact on the bearings, so that a corresponding lower RPM is applied, in order to minimize bearing wear. The WOB required is slightly lower for an equivalent TCI bit to prevent impact failure or cracking of the insert cutters. Softer formations require lower weight on bit in order to achieve penetration, therefore higher RPM can be applied. Similar parameters are required for both tooth and TCI bits. Too much weight being applied could actually break the longer teeth or inserts. Generally, penetration rate (ROP) is faster with more weight applied to the bit and /or higher RPM, but too much weight can have detrimental affects such as bit balling in softer formations, failure of roller bearings, seizure of journal bearings, and breakage of teeth or inserts.



33

2.3.3 Diamond and Polycrystalline Diamond Compact (PDC) bits These bits have a long life since the cutters are obviously very hard and there are no bearings or moveable parts. Natural industrial diamonds are hand set into geometric designs that cover the bottom of the bit, allowing for breakage and redundancy. They also channel the mud flow from the bit, allowing for cooling and cuttings removal. With PDC bits, polycrystalline diamonds are mounted into tungsten carbide. The diamond actually does the drilling, or cutting, with the tungsten carbide providing strength and rigidity. Diamond cutters start out sharp and they wear sharp, whereas most cutters become dull with wear. This and their longer life makes them extremely cost effective for deep drilling in hard, abrasive formations. Since they have no moving parts, they are economic when high rotary speeds (perhaps above the limits of roller bearings) are produced when drilling with mud motors or turbines. They do have a long life, although ROP’s are generally slower. The overall footage, or meters achieved by the bit has to justify the much higher cost of diamond bits. The cutting action of diamond bits is more of a shearing or grinding type action. This produces cuttings that are much finer than those produced by tri-cone bits, often appearing as a very fine rock flour, and sometimes, even being thermally changed (metamorphosed) by the high frictional heat generated. This does not make the bit conducive to formation evaluation, since the structure and form of the lithology has been destroyed to a large degree. At the same time, they are unresponsive to lithological changes (changes in ROP is normally the first indication of a lithology change) therefore, again, they are not so well suited to geological interpretation. Diamond bits have different operational requirements to tri-cone bits. They typically have a slightly smaller gauge (diameter) than the hole size in order to reduce wear on trips in and out of the hole. Optimum performance is achieved with lower WOB’s and the highest RPM possible, together with high mud velocities across the face of the bit. Before drilling ahead with a new bit, it should be ‘patterned’. In other words, the profile of the bottom of the hole must match that of the bit. This is done by very slowly increasing the WOB before the start of drilling, so that the profile of the bit is cut into the bottom of the hole.

Diamond Bit PDC Bit



34

2.3.4 Grading Of Bits Roller bits can be simply graded by the condition of the teeth (or inserts) and bearings, and also by the gauge or diameter of the bit. This is known as the TBG grading, with teeth and bearings graded on a scale of 1 to 8. (T)eeth 1 - virtually as new 8 - completely worn (B)earings 1 - as new 8 - complete failure (G)auge IG - in gauge or the measurement of the degree of undergauge i.e. 1/8 inch or 2mm This is a very basic grading system that gives little additional or qualifying information about the bits condition. For example, the inner and outer rows of cutters may have different degrees of wear, but this system can only facilitate one recording. A more sophisticated and informative grading is provided by the IADC system.

The IADC bit grading system

Cutting Structure Bearing condition

Gauge Remarks

Inner rows

Outer rows

Major dulling characteristics

Location of major dulling

Other dulling characteristics

Reason pulled

0 – 8 linear scale 0 – no wear 2 - 25% 4 - 50% 6 - 75% 8 - 100%

BC – broken cone BT – broken teeth CC – cracked cone CR – cored CT – chipped teeth ER – erosion JD – junk damage LC – lost cone LT – lost teeth PB – pinched bit PN – plugged nozzle RG – rounded gauge RO – ring out SD – shirttail damage WO – washed out WT – worn teeth

Rollers: N – nose M – middle row H – heel row A – all rows Cone 1, 2, 3 Fixed Cutters: C – cone N – nose T – taper S – shoulder G – gauge A – all areas

No – Sealed Bearings: 0 – 8 0 – as new 8 – life gone Sealed Bearings: E – effective F – failed

I – in gauge Undergauge measured to the nearest 1/16 inch

Same codes as major dulling characteristics

BHA – change BHA DMF – downhole motor failure DSF – drill string failure DST – drill stem test LOG – run logs CD – condition mud CP – core point DP – drill plug FM – formation change HP – hole problems HR – hours on bit PP – pump pressure PR – penetration rate TD – total depth (or casing point) TQ – torque TW – twist off WC – weather conditions



35

2.3.6 The Drillstring Very simply, the drillstring is made up of drill pipe and drill collars, with a number of smaller, additional components, connecting the surface systems to the drill bit. The main purposes of the drillstring are: -

• Provide a conduit from the surface to the bit so that drilling fluid can be conducted under pressure.

• Transmit rotation, that is applied at surface, to the bit. • Transmit force, or weight, to the bit so that failure of the formation is more easily achieved. • Provide the means to lower and raise the drill bit in the wellbore.

All connections from the swivel to the upper kelly are made with left-hand threads whereas all connections from the lower kelly to the drill bit are made with a right hand thread. With rotation of the drillstring to the right during drilling, connections will tend to tighten rather than loosen or back off. All tubular sizes, whether drillpipe, drill collars or casing, are standardized by the American Petroleum Institute (API) by way of the outside diameter (OD) of the tube.

2.3.7 Drillpipe This comprises the main component, in terms of length, of the drillstring. Each length (referred to as a single or a joint) of drillpipe, constructed of steel, is commonly either 10 or 15m in length. Each end of the pipe has a tapered tool joint, either male or female, that is welded or shrunk on so that lengths of pipe can be easily screwed together. The ‘shoulder’ around the tool joint is enlarged or upset to provide extra strength to the connections. The drillpipe is available in various diameters (OD) although the most commonly used is 5 inches or 127mm. The inside diameter (ID) of the drillpipe will vary depending on the weight per unit length of the pipe. The larger the weight, the smaller the ID. Commonly, the drillpipe (for OD 127mm) used is 19.5 lb/ft or 29.1 kg/m: This gives OD 5” or 127mm ID 4.28” or 108.7mm Drillpipe is also available in different grades of steel giving different degrees of strength, where ‘D’ is the weakest and ‘S’ the strongest. Heavy or thicker walled drillpipe is normally called ‘heavy-weight’ drillpipe. This heavier pipe is situated above the drill collars in the drillstring to provide extra weight and stability. As with ‘standard’ drillpipe, heavy-weight is available in different OD’s and varying ID’s depending on the weight of the steel. Heavy-weight drillpipe will differ in appearance from standard drillpipe in that they have longer tool joints.



36

Commonly, the weight (for OD 127mm) used is 49.3 lb/ft or 73.5 kg/m This gives OD 5” or 127mm ID 3” or 76.2mm Notice that the heavy-weight drillpipe has the same OD as the standard drillpipe, and as we shall see, the same ID as the drill collars.

2.3.8 Drill Collars Drill collars are rigid, thick walled, heavy lengths of pipe that go to make up the main part of the Bottom Hole Assembly, positioned between the drillpipe and the bit. Collars have several important functions: -

• Provide weight for the bit. • Provide the strength required so that the collars are always in compression. • Provide weight to ensure that the drillpipe is always held in tension to avoid buckling. • Provide rigidity or stiffness so that hole direction is maintained. • Produce a pendulum effect, allowing near vertical holes to be drilled.

As with drillpipe, drill collars are available in several diameters (OD) with the ID diameter variable due to varying weights of steel. Typically, the ID is similar to that of the heavy-weight drillpipe, close to 3” or 76mm.

The weight applied to the bit must come from the drill collars only. If the weight applied to the bit was to exceed the total weight of the drill collars, the extra weight would be coming from the drillpipe which would be subject to buckling and twist-off (breaking) at the tool joints. The weight of the collars acting directly on the bit has two main consequences: -

• The tendency for the string to hang vertically due to the weight and gravity. The heavier the drill collars, the more likely it is that the bit will not deviate from a vertical position.

• The weight acting upon the bit will stabilize it, making it more likely that the hole

being drilled will follow the path of the section just drilled i.e. maintaining hole direction. This bit stabilization also allows for even distribution of the load across the cutting structure of the bit. This prevents the bit from wandering or migrating

Square drill collar Spiral drill collar Smooth drill collar



37

from a central position, ensuring a straight, properly sized or gauged hole, even bit wear and faster penetration rates.

The maintaining of the hole direction is assisted not only by the weight and stiffness of the drill collars at the base of the drillstring, but will also be greatly assisted if the OD of the collars is only slightly smaller than the bit diameter or actual hole size. This is known as a ‘packed-hole assembly’. A problem with this type of arrangement is that the collar part of the drillstring will be very prone to differential sticking, where the pipe becomes stuck in the filter cake covering the borehole wall. The risk of this is minimized by utilizing a number of different designs in the sectioning, or grooving, of the collars to reduce the surface area of the drill collar that is in contact with the wellbore. Thus, collars may be round, square or eliptically sectioned, spirally grooved etc.

2.3.9 The Bottom Hole Assembly (BHA) This is the name applied to the drill collars and any other tools incorporated with them, including the bit. The drillstring is therefore made up of the drillpipe (heavy-weight drillpipe is normally distinguished as well) and the BHA.

Stabilizers These are a short length of pipe, or sub, positioned between the drill collars in order to centralize them and maintain a straight hole and, by way of a scraping action, they maintain a full sized, or gauged, hole. The full gauge is provided by ‘ribs’ or blades mounted on a mandrel. These may be made from solid rubber or aluminium, or more typically, they are made from steel with tungsten carbide inserts on the facing edges. Stabilizers can be categorized into rotating or non-rotating blades, with the ribs or blades being generally spiral or straight.

Reamers Roller Reamers will ream the hole just behind the bit and perform a similar function to the stabilizers in that they stabilize the assembly and help maintain a full gauge hole. They are more typically used when

problems are being experienced in maintaining a full gauged hole, particularly in abrasive formations, when the bit is worn undergauge. Similarly, they may be used if key seats or ledges are known to exist in the borehole. The number and position of reaming ‘blades’ will categorize the type of reamer. For

3-point near-bit reamer



38

example, with three blades, it is termed a 3-point reamer. If they are positioned towards the base of the sub (as shown), it will be termed a 3-point near-bit reamer. A stabilizer reamer will have the blades positioned centrally in the sub. Under Reamers are also placed directly behind the bit to ream the hole and maintain full gauge or enlarge the hole. The reaming or cutting action is by way of rotating cones located on collapsible arms. These are opened and held out during drilling by the pressure of the mud passing through the tool. This enables the tool to pass through a narrow diameter hole section, then open up and drill a wider hole.

Hole Opener This is a similar tool to the under reamer, in that a cutting action is provided by rotating cones in order to enlarge a hole. Unlike the under reamer however, the cones are in a fixed position so that the hole opener has to be able to pass through the ‘previous’ hole diameter. They are therefore generally used on surface hole sections to widen the hole where large hole diameters are required.

Cross Over Sub A small length of pipe enabling drillpipe and/or collars of different diameters and threads to be connected together.

Jars A mechanically or hydraulically operated device to provide a high impact ‘hammer’ blow to the drillstring downhole, in the event that it becomes stuck. Jars are designed specifically for drilling or fishing (retrieval of part of the drillstring left downhole) operations. Should the drill string become stuck and incapable of being freed with normal working (i.e., upward and downward movement) of the pipe or by pulling on the pipe without exceeding drill string and surface equipment limitations, then rotary drilling jars will be used. Rotary drilling jars are tools designed to strike heavy-impact hammer blows, in an upward or downward direction, to the drill string. The direction in which the jar is activated depends upon the pipe movement when it became stuck. A downward blow is struck if the pipe was stationary or moving upwards. An upward blow will be struck if the drill string was moving downwards. The majority of stuck pipe situations result from an upward moving, or stationary, pipe so that, typically, downward jarring is required. To free the pipe, the jar needs to be situated above the stuck point so, typically, jars will be situated in the upper apart of the bottom hole assembly, certainly above stabilizers and other tools most prone to sticking. Jars can be hydraulically or mechanically triggered, but both work on the same principle. That is, the jar consists of an outer barrel which is attached to the drill string below (the stuck pipe) and an inner mandrel which, attached to the free string above, can slide, delivering rapid upward or downward acceleration and force.

• Hydraulic jars operate on a time delay produced by the release of hydraulic fluid. As the mandrel

is extended, the hydraulic fluid is released slowly through a small opening. Over several minutes, opening continues but is restricted by the hydraulic metering. The fluid channel then increases in



39

diameter allowing rapid flow and unrestricted, rapid opening of the jar, known as its stroke. At the end of the stroke, typically 8 inches, a tremendous blow is delivered by the rapid deceleration of the drill string above the jars which were accelerating through the stroke.

Stuck Pipe

Jar Cocks

DrillString isRaised

DrillString isSlackedOff

Jar Latch Trips

8”Drop

Impact is Delivered

GravityAcceleratesBHA Mass

Step 1 Step 2 Step 3

• Mechanical jars deliver the hammer blow by the same acceleration/deceleration of the jars, but

the triggering mechanism is by a pre-set tension with no time delay once the jar has been cocked. • A jar accelerator may be set above the rotary jars, typically within the heavy-weight drill pipe, to

intensify the blow delivered by the jars. Upward strain compresses a charge of fluid or gas (commonly nitrogen) and, when the rotary jar trips, the expansion of fluid or gas in the accelerator amplifies the jarring effect. A jar accelerator offers the advantages of confining movement to the drill collar—or close to the stuck point—and minimizing shock on the drill string and surface equipment by cushioning rebounds through the compression of fluid or gas.

If jarring is unable to free the stuck pipe, the only recourse is to back off the pipe that is still free. This may be achieved by simply twisting off, or unscrewing, the free pipe; or by determining the free point with a wireline tool, then running an explosive charge, on wireline, to blow the string apart. The remaining stuck pipe now has to be either retrieved, removed or avoided before drilling can continue.

Shock Sub This will be positioned close behind the bit where hard formations cause the bit to bounce on the bottom of the hole. They are designed to absorb the impact from this bouncing in order to prevent damaging the remaining part of the drillstring. This may be done by way of springs or rubber packing.



40

2.4 Blow Out Prevention System During normal drilling operations, the hydrostatic pressure, at any depth, exerted by the column of drilling fluid inside the well exceeds the pressure exerted by the formation fluids. Thus, the flow of formation fluids (influx or kick) into the wellbore is prevented. Should, however, the pressure due to the formation fluid exceed the hydrostatic pressure of the mud column, the formation fluid, be it water, gas or oil, will be able to feed into the wellbore. This is known as a kick. A kick is defined as an influx of formation fluid into the wellbore that can be controlled at surface. When this flow of formation fluid becomes uncontrollable at surface, the kick becomes a blowout.

2.4.1 BOP Stack To prevent the occurrence of a blowout, there needs to be a way of ‘closing’ or shutting off the wellbore so that the flow of formation fluid remains under control. This is possible with a blowout prevention system (BOP), an arrangement of preventers, valves and spools that sit atop the wellhead. This arrangement is commonly referred to as the stack. The BOP stack must be able to: -

• Close the top of the wellbore to prevent fluid from escaping to surface and risking an explosion.

• Release fluids from the wellbore under safely controlled conditions. • Enable drilling fluid to be pumped into the well, under controlled conditions, to balance

wellbore pressures and prevent further influx (kill the well). • Allow movement of the drillstring.

The size and arrangement of the BOP stack will be determined by the hazards expected and the protection required, together with the size and type of pipe being used. The basic requirements of the BOP stack means: -

• There must be sufficient casing in the hole to provide a firm anchor for the stack. • It must be possible to close off the well completely, whether there is pipe in the hole or

not. • Closing the well must be a simple and rapid procedure easily understood and performed

by the drilling personnel. • There must be controllable lines through which pressure can be bled off safely. • There must be a means to circulate fluid through the drillstring or annulus so that

formation fluid can be removed from the wellbore, and so that higher density mud can be circulated to balance the formation pressure and control the well.

There are additional requirements in the case of floating rigs, where the BOP stack will be situated on the seabed. Should the rig have to temporarily abandon the well, there must be means to shut the well in completely, by hanging off or shearing any pipe in the hole. The marine riser can then be detached from



41

the wellhead, allowing the rig to move away to a safe location but able to return and re-enter the well at a later time. During normal operations, the marine riser will be subjected to lateral movement due to the water current. The attachment of the riser to the stack must therefore be by way of a ‘ball joint’ to prevent movement of the stack. BOPs have various pressure ratings established by the American Petroleum Institute (API). This will be based upon the lowest pressure rating of a particular item in the stack such as a preventer, casing head or other fitting. A suitably rated BOP can therefore be installed depending on the rating of the casing and expected formation pressures below the casing seat. BOPs commonly used have ratings of 5, 10 or 20000 psi.

2.4.2 Closing the well This is achieved with preventers or rams, enabling the annulus to be closed off or the complete wellbore to be closed off, with or without pipe in the hole.

Annular Preventer This is a reinforced rubber seal, or packer, that surrounds the wellbore. When pressure is applied it will close around the pipe, sealing off the annulus. The annular preventer has the advantage that with pressure progressively applied, it will close in on any size of pipe or any shape. The wellbore can therefore be closed in regardless of whether the kelly, drillpipe or drill collars are passing through the stack. This adaptability does not, however, extend to spiral drill collars or tools such as stabilizers where the shape is irregular. The annular preventer also allows for slow rotation or vertical movement of the drillstring while the annulus remains closed off. This allows for pipe to be tripped in (“snubbing) or out (stripping) of the hole while the well is still under a controlled condition. Most annular preventers are also able to seal across an open wellbore, but this will shorten the life of the packer and should be avoided.

Ram Type Preventers These differ from the annular preventer in that the rubber sealing element is comparitively rigid and will seal around pre-designated shapes. They are made to seal around specific objects (pipe and casing rams) or over an open hole (blind rams). They can be equipped with shearing blades that can cut through drillpipe or casing and still have the ability to seal an open hole (shear/blind rams).



42

Pipe or Casing Rams Here, the rubber faces of the ram are moulded to match the outside diameter of specifically sized pipe. The rams can therefore close around that specific drillpipe exactly, closing off the annulus. If more than one size of drillpipe is being used, the BOP stack must include pipe rams for each size of pipe in the hole. Blind or Shear Rams These rams, closing from opposite sides, will close off the complete borehole when there is no drillpipe in the hole. If there is pipe in the hole, the rams will crush it or cut through it if equipped with shear blades (shear rams). Shear rams are more typically used in subsea stacks so that, if pipe is in the hole, the well can be completely closed off should the well have to be temporarily abandoned. Blind rams are more typically used in stacks situated under the drillfloor.

2.4.3 Closing the preventers The preventers are closed hydraulically with hydraulic fluid supplied under pressure. If the stacks are accessible, i.e. on land rigs and jack-ups, the rams can also be closed manually. The basic components to a preventer closing system are: • Pumps providing a source of pressure. • A source of power to drive the pumps. • Suitable hydraulic fluid to open and close the preventers. • A control system to direct and control the fluid. • A source of pressure when normal sources fail. • Backup sources of power. There has to be means to store the hydraulic fluid under pressure and a means of the delivering it to the preventers. To be taken into account is the fact that different preventers require different operating pressures and preventers of different sizes will require varying amounts of fluid for opening and closing.

Ram preventors

Annular preventor



43

Accumulators Accumulator bottles provide the means to store, under pressure, the full amount of hydraulic fluid required to operate all of the BOP components and effect rapid preventer closure. Several accumulator bottles can be linked together to provide the necessary volume. The accumulator bottles are pre-charged with compressed nitrogen (typically 750 to 1000 psi). When hydraulic fluid is forced into the bottle, by way of air or electrically powered pumps, the nitrogen is compressed thereby increasing the pressure. Typically, to ensure BOP operation, a closing unit will have more than one pressure source in case of failure. Similarly, if air or electrical

pumps are being used in the closing unit, there will be more than one source of air, more than one source of electricity etc. There should always be a backup. The operating pressure of the accumulator is typically 1500 to 3000 psi. A minimum operating pressure of 1200 psi is normally assumed. These pressures will determine the amount of hydraulic fluid that can be supplied from each bottle and from this, the number of bottles needed to supply the full amount of fluid to operate the BOP can be determined. e.g. A. Precharge volume of bottle = 40 litres, precharge pressure = 1000 psi

B. Max Fluid Charge pressure = 3000 psi volume of N2 = 1000 x 40 / 3000 =13.33 litres C. Minimum Operating Pressure = 1200 psi volume of N2 = 1000 x 40 / 1200 =33.33 litres Therefore, the amount of usable hydraulic fluid in each accumulator bottle = 33.33 - 13.33 = 20 litres A hydraulic control manifold, consisting of regulators and valves, controls the direction of flow of the high pressure hydraulic fluid. The fluid will be directed to the correct ram or preventer and the regulators will reduce the pressure of the hydraulic fluid from the accumulator operating pressure to the operating pressure of the preventer (typically in the region of 500 to 1500 psi). All components to the closing system; pressure source, accumulators, control manifold, master control panel, should be located a safe distance from the wellbore.

Control Panel Typically, there will be more than one control panel. The master panel will be located on the drill floor convenient to the driller (typically in the doghouse). An auxiliary panel will be placed in a safe area so that, should the driller’s panel fail and the accumulator panel not be reachable, the well can still be safely controlled.

A B C Accumulator bottles



44

The control panel is air operated and will typically provide gauges to show air pressure to the control panel and pressures throughout the system such as accumulator, air supply manifold and annular preventer. The panel will also typically include preventer control valves to open or close preventers, valves to open or close the choke and kill lines and a pressure control valve to adjust the pressure of the annular pressure.

Positioning of the rams Typically, one annular preventer will be placed at the top of the stack. The best arrangement for the remaining rams depend on the operations that may need to be carried out. The possibilities are that blind rams are sited above all pipe rams, below all pipe rams or between pipe rams. The

operations possible are then governed by the fact that blind rams cannot shut off the well if pipe is in the hole. With blind rams in the lower position, the well can be closed if no pipe is in the hole and all other rams can be repaired or replaced if required. In case of blowout with pipe out of the hole, the well can be closed and pressure reduction achieved by lubricating mud into the well below the rams. With an annular preventer above, drillpipe can be stripped into the well by holding pressure when the blind ram is opened. A disadvantage is that drillpipe cannot be hung off on pipe rams and the well killed by circulation through the drillstring. With blind rams in the upper position, lower pipe rams can be closed with pipe in the hole, allowing the blind rams to be replaced with pipe rams. This will minimize wear on the lower pipe rams with the upper rams taking the additional wear as a result of working the drillstring with rams closed. Drillpipe can also be hung from the any of the pipe rams, backed off and the well completely closed by the blind rams. The main disadvantage is that the blind rams cannot be used as a ‘master’ valve allowing for changing or repair of rams above.

Kill Lines The placement or configuration of the rams will affect the positioning of the kill lines. These will be located directly beneath one or more of the rams, so that when the rams are closed, fluid and pressure can be bled off under control (choke line). The choke line is routed to the choke manifold where pressures can be monitored. An adjustable choke allows for the ‘back pressure’ being applied to the well to be adjusted in order to maintain control. They also allow for an alternative way of pumping drilling mud or cement into the wellbore should it not be possible to circulate through the kelly and drillstring (kill line). The kill line will normally be lined up to the rig pumps, but a ‘remote’ kill line may often be employed in order to use an auxiliary high pressure pump. Although preventers may have side outlets for the attachment of choke and kill lines, separate drilling spools are often used. This is a drill-through fitting that fits between the preventers creating extra space



45

(which may be required in order to hang off pipe and have enough room for tool joints between the rams) and allowing for the attachment of the kill lines. On floating rigs, when the BOP stack is on the seabed, the choke and kill lines are attached to opposite sides of the marine riser. The lines have to flexible at the top and the bottom of the riser to allow for movement and heave.

The Diverter A diverter is typically employed before the installation of a BOP stack. The diverter, installed directly beneath the normal bell nipple and flowline assembly, is a low pressure system. It’s purpose is to direct any well flow or kick away from the rig and personnel, providing a degree of protection prior to setting the casing string that the BOP stack will be mounted on. The diverter system is only designed to handle low pressures. It is designed to pack off or close around the kelly or drillpipe and direct the flow away. If it were attempted to control high pressures, or completely shut in the well, the likely result would be uncontrolled flow and breakdown of formations around the shallow casing or conductor pipe. The use of a diverter is essential in offshore drilling.

FLOWLINE

ANNULAR PREVENTOR

BLIND/SHEAR RAMS

PIPE RAMS

PIPE RAMS

PIPE RAMS

CASING HEAD

CHOKE + KILL LINES

Simple BOP stack schematic

Choke Manifold



46

2.4.4 Inside Blowout Preventers Complete blowout prevention is only achieved when both the annulus and the inside of the drillpipe are closed off. The preventers and rams so far described primarily close off the annulus. Blind rams only close off open holes without drillpipe and shear rams cut the drillpipe rather than closing off. Inside BOPs are pieces of equipment that can close off the inside of the drillpipe. There are two main types:

1. Manual shut off valves employed at the surface. 2. Automatic check valves situated in the drillstring downhole

Surface Shut Off Valves Kelly Safety Valve This is installed on the lower end of the kelly, with different sizes available for

all sizes of pipe. Kelly Cock This is installed between the swivel and the kelly Drillpipe Safety Valve This is manually screwed, or stabbed, into open drillpipe held in slips. This

allows for quick shut off should backflow occur during tripping when the kelly is racked.

Downhole Check Valves Drop-in Check Valve This can be sited at any position in the drillstring, requiring a landing sub. If

there is danger of a blowout, the valve is pumped down the string, lands in the sub and provides continuous protection. This should be employed before shearing drillpipe so that the drillpipe is protected against flow up the pipe.

Drillpipe Float Valve This can be positioned directly above the bit to prevent backflow into the

drillstring, providing instantaneous shut off against pressures and fluid flow. Some floats have vented flappers allowing shut-in pressures to be accurately monitored.

2.4.5 Rotating BOPs Otherwise known as a rotating control head, the function of the rotating BOP is specifically as a rotating flow diverter, which is mounted on the top of a normal BOP stack. Simply, the RBOP allows vertical movement and rotation of the drillstring while a rubber ‘stripper’ seals around and rotates with the string, allowing flow to be contained and diverted. This type of unit has obvious advantages for underbalanced drilling, when drilling with high pressures or, increasingly, for enhanced safety, RBOPs are being used in normal drilling applications. While well pressures are contained by the rubber seal around the drillstring or kelly, flow is diverted by way of a steel bowl and bearing assembly. The bearing assembly enables the inner part to rotate with the drillstring while the outer part is stationary with the bowl.



47

Seals are typically of two types: - 1. A cone shaped rubber that seals around the drillstring. The ID of the seal is slightly smaller than the

OD of the pipe so that the seal stretches to provide an exact seal around the pipe. No hydraulic pressure is required to complete the seal since the pressure is provided by wellbore pressures acting on the cone rubber. The rubber is therefore self-sealing, the higher the wellbore pressure the greater the seal.

2. A packer type seal requiring an external hydraulic pressure source to inflate the rubber and provide a

seal. A seal will be given as long as the hydraulic pressure is greater than the wellbore pressure. The huge advantage of the rotating BOP is that, since rotation and vertical movement are possible while an annular seal is present, drilling can commence while a flowing well is being safely controlled. The assembly is easily installed, and the rubbers easily inspected and replaced with minimum loss of time. If the wellbore pressure approaches the maximum capability of the RBOP (typically 1500 to 2500psi), the well should be controlled conventionally using the BOP preventers. NB For further information on well control equipment and well control procedures, refer to Datalog’s WELL CONTROL and BLOWOUT PREVENTION manual.



48

3 THE DRILLING FLUID 3.1 Purposes of the Drilling Fluid Drilling fluids have the obvious functions of removing drilled rock chips, or cuttings out of the wellbore, and of cooling and lubricating the bit and drill string. In fact, the mud system has many other functions and is central to virtually all of the operations throughout the drilling of a well. It is very important that the drilling fluid is able to perform all of these functions efficiently.

3.1.1 Cool and Lubricate the Bit and Drillstring The drilling action and rotation of the drill string generates considerable heat at the bit and throughout the drill string due to friction. This heat is absorbed by the drilling fluid and released, to a degree, at the surface. Drilling fluid further reduces the heat by lubricating the bit and drill string to reduce the friction. Basic mud types provide moderate lubrication, but oil emulsion mud systems, coupled with various emulsifying agents, increase lubrication significantly, while, at the same time, reducing torque, increasing bit and bearing life, and reducing pump pressure through reduced friction.

3.1.2 Bottom Hole Cleaning Drilling fluid flows through the bit nozzles to jettison cuttings out from under the bit and carry them up through the annulus to surface. This serves to keep cuttings clear of the bottom hole and prevent bit balling (i.e., cuttings building up and clogging the bit), thereby prolonging bit life and increasing drilling efficiency. The effectiveness of the drilling fluid in this process depends on factors such as velocity and impact of the mud as it leaves the nozzles, mud density and viscosity.

3.1.3 Control Subsurface Pressures Minimal mud weight is optimum for fast drilling rates and to minimize the risk of damaging formations and losing circulation. However, in conventional drilling, the mud must also be of sufficient density to protect the well against subsurface formation pressures and to maintain stability of the wellbore. The pressure exerted at the bottom of the hole, due to the overlying weight of the static vertical column of drilling fluid, is known as the mud hydrostatic pressure. If the mud hydrostatic pressure is equal to the formation fluid pressure, the well is said to be at balance. If the pressures are not equal, then fluids (either formation fluid or drilling fluid) will flow in the direction of lower pressure. If the hydrostatic pressure is less than the formation pressure, the well is underbalanced and therefore subject to influxes of formation fluid that could lead to well kicks and, ultimately, blowouts. If the hydrostatic pressure is greater than the formation pressure, the well is overbalanced and protected against influxes of formation fluid into the wellbore. Too great an overbalance, however, while controlling formation fluid pressure, can lead to the flushing of drilling mud into the formation, or even to the fracture of weaker formations, resulting in lost circulation.



49

3.1.4 Line the Hole with Filter Cake As the hole is being drilled, filtrate (i.e., the liquid portion of drilling fluid) invades permeable formations. As it does so, solid particles within the mud will be left on the borehole wall. These particles will build up to line the borehole with a thin, impermeable layer of filter cake that will consolidate the formation and minimize further fluid loss. The mud's filter-caking ability can be improved by adding bentonite (thereby increasing the reactive mud solids) and chemical thinners (thereby improving solids distribution). Starch or other fluid-loss control additives may also be required to reduce fluid loss. Note that excessive water-loss can result in an excessively thick filter cake, thereby reducing the diameter of thhole and increasing the possibility of stuck pipe or swabbing the hole when removing the pipe. It can also lead to deep invasion of the formation by the drilling mud, resulting in the loss of initial gas shows and making it difficult to interpret electric logs.

3.1.5 Help Support the Weight of the Drillstring The derrick and blocks must support the increasing weight of the drill string as drilling proceeds deeper. Through displacement, the drill string is buoyed up by the drilling fluid, thereby reducing the total weight that the surface equipment must support. Therefore, increasing mud density and viscosity can considerably reduce surface load at deeper depths.

3.1.6 Cuttings Removal and Release Cuttings need to be removed from the well to prevent loading the annulus and to allow for free movement and rotation of the drillstring. They also need to reach the surface and be released in such a condition as to allow for geological interpretation of the downhole lithology. Cuttings slip (i.e., cuttings falling) occurs because the density of the cuttings is greater than the density of the drilling fluid. Therefore, to ensure that cuttings are lifted through the annulus during circulation and yet remain suspended when circulation is stopped, drilling fluids must be thixotropic (i.e., possess gelling properties). When circulating, thixotropic drilling fluids are liquid, allowing them to carry cuttings to the surface. When not circulating, thixotropic drilling fluids will gel, or thicken, to suspend cuttings and prevent them from slipping and settling around the bit. Gel strength must be low enough to release the cuttings and entrained gas at the surface, to minimize swabbing when the pipe is pulled, and to resume circulation without causing high pump pressure.

3.1.7 Transmit Hydraulic Horsepower to the Bit The drilling fluid transmits the hydraulic horsepower delivered by the pumps at the surface to the drill bit. The circulation rate of the drilling fluid should be such that optimum power is used to clean the face of the hole ahead of the drill bit. Hydraulics are considerably influenced by the flow properties of the drilling fluid, such as density, viscosity, flow rate and fluid velocity. The amount of hydraulic



50

horsepower expended at the bit determines the degree to which hydraulics are optimized, whether for bottom hole cleaning or laminar flow optimization.

3.1.8 Hole Stability Drilling fluids serve to prevent erosion and collapse of the wellbore. When drilling porous and permeable formations, the hydrostatic pressure of the drilling fluid column helps prevent unconsolidated formations (e.g., sand) from falling into the hole. For swelling and sloughing shales, oil-base mud is preferred since, unlike water, oil will not be absorbed by the clays. Water-base mud can be used if treated with Ca/K/Asphalt compounds. To prevent the dissolving of salt sections, salt-saturated or oil-base mud can be used to prevent taking the salt into solution.

3.1.9 Formation Protection and Evaluation Achieving optimum values of all drilling fluid properties is necessary to offer maximum protection of the formation. Yet sometimes these values must be sacrificed, to a degree, in order to gain maximum knowledge of the formations penetrated. Oil-based drilling fluids can be effective in keeping water out of a producing formation. However, in gas zones, it may be more damaging than a salt-water fluid. To some degree, salt-water and high-calcium fluids have been effectively used to minimize formation damage. The type of flow pattern present in the annulus can facilitate or minimize cuttings damage and erosion. Smooth laminar flow is preferred to chaotic turbulent flow. This not only protects the cuttings, but also minimizes erosion of the well-bore wall as well as reducing circulating pressures. As well, the penetration rate may have to be sacrificed to gain valuable reservoir information. This is known as controlled drilling, where parameters are controlled in order to determine those changes that are due to formation changes.



51

3.2 Common Drilling Fluids Drilling Fluids are circulating mediums used to carry drilled cuttings out from under the drill bit, into the outer annulus and up to the surface. The various fluids that may be used in rotary drilling are:

air - gas foam/aerated fluids water-base muds oil emulsion muds oil-base muds

A typical circulating system of a rotary drilling rig was described and illustrated in Section 2.2.

3.2.1 Air/Gas Using compressed air, natural gas, inert gas or mixtures with water has an economic advantage in hard rock areas where there is little chance of encountering large quantities of water.

Advantages • fastest penetration rate of any drilling fluid • more footage per bit • more near gauge and less-deviated holes • continuous formation tests (high-pressure formations excluded) • cleaner cores • better cement jobs • better completion jobs • no danger of lost circulation • no reaction with shale

Disadvantages • no structural properties to transport cuttings (solely dependent on annular

velocity) • combustible with other gases (possibility of downhole explosions and

fire) • pipe corrosion • finely crushed cuttings and uneven release (making analysis difficult) • no pressure control (permitting caving or requiring additional equipment) • no filter cake • influx of formation water (creating mud rings and causing stuck pipe) • no buoyancy to help support the drill string (increasing hook weight) • no cooling or lubrication

3.2.2 Foam or Aerated Fluids Foam fluids are made by injecting water and foaming agents into an air or gas stream to create a viscous and stable foam. They can also be made by injecting a gel-base mud containing a foaming agent. The cuttings transport capacity of viscous foams is dependent more on viscosity than on annular velocity.



52

Aerated fluids are made by injecting air or gas into a gel-base mud. They are used to reduce hydrostatic pressure (thereby preventing the loss of circulation in low-pressure formations) and to increase the rate of penetration.

3.2.3 Water-Base Muds Water-base muds consist of a continuous phase of water in which clay and other solids (reactive and inert solids) are suspended. Fresh water is used most often. It is commonly available, inexpensive, easy to control even when loaded with solids, and provides the best liquid for formation evaluation. Salt water is commonly used in offshore drilling operations due to its accessibility. Saturated salt water is used in drilling salt sections in order to stabilize the formation and reduce hole washout. Reactive solids are commercial clays and incorporated hydratable clays and shales from drilled formations, which are held in suspension in the water phase. These solids can be enriched by adding clays, improved through chemical treatment, and damaged by contamination. Inert solids are chemically inactive solids, which are held in suspension in the water phase. These solids include inert drilled solids (such as limestone, dolomite and sand), and mud-density control solids such as barite and galena. Some water-base muds can be classified as inhibited muds. Chemicals are added to the drilling fluid to prevent sensitive shale from swelling in reaction to the filtrate, which in turn impairs the permeability of a productive zone with excessive clay deposits. It is also used for sloughing, gumbo, tight hole and stuck pipe conditions. Salt is a mud inhibitor that can be used effectively in reducing shale reactivity. These muds are particularly effective in preventing drilling problems due to heaving (swelling) shales. Native mud is a combination of drilled solids suspended in water. As drilling continues, the mud is chemically treated to achieve special properties.

Advantages • increased drillability when using fresh water (drillability increases with increasing water loss and with decreasing density and viscosity)

• less expensive than oil-base muds Disadvantages • potential formation damage

• subject to contamination • adversely affected by high temperatures

3.2.4 Oil-Emulsion Muds Oil-emulsion muds are water-base muds that contain emulsified oil dispersed, or suspended, in a continuous phase of water. Oil-emulsion muds are less expensive than oil-base muds, while still providing many of the benefits of oil-base muds.



53

3.2.5 Oil-Base Muds Oil-base muds consist of a continuous phase of oil in which clay and other solids are suspended. With invert-emulsion muds, water is suspended in a continuous phase of oil. Oil-base muds are used in special drilling operations, such as drilling in extremely high temperatures, drilling in water-sensitive formations where water-base muds cannot be used, and in penetrating productive zones that may be damaged by water-base muds.

Advantages • minimizes formation damage • prevents clay hydration • provides better lubrication (reducing torque, drag and pipe sticking) • minimizes drill string corrosion • high temperature stability

Disadvantages • susceptible to water contamination, aeration and foaming

• flammable • significantly more expensive than water-base muds • dirty and hazardous • environmentally unfriendly (due to spillage and disposal)

In recent years, mineral oils have gradually been replacing traditional petroleum as the base for mud systems. While providing much the same properties and drilling advantages, they are friendly to the environment and to the rig personnel who have to handle the mud.



54

3.3 Basic Mud Rheology

3.3.1 Mud Density Mud density is the single-most important factor in controlling formation pressure throughout the wellbore. For a balanced well, the formation pressure must not exceed the hydrostatic pressure exerted by the mud column.

SI Units Hydrostatic Pressure (KPa) = Hole Depth (m) x Mud Density (kg/m ) x 0.009813 Imperial Units Hydrostatic Pressure (psi) = Hole Depth (ft) x Mud Density (lb / gal) x 0.052

Barite is the standard solid used to increase mud density. For optimum thinning or reduction in density, weighted muds are usually chemically treated. When chemicals no longer work, water can be added to reduce mud density and restore lost water. Centrifuges can also be used to remove excessive solid particles from the mud. Mud density is measured with a mud balance, shown right, where the weight of an exact volume of mud, minus any air bubbles or drilled solids, is determined.

3.3.2 Mud Viscosity Mud viscosity measures the drilling mud's resistance to flow (i.e., the internal resistance due to the attraction of the liquid molecules); the greater the resistance, the higher the viscosity. Viscosity therefore describes the thickness of mud in motion, and must be high enough for the mud to keep the bottom hole clean and carry cuttings to the surface. It is important to note, however, that lower viscosity levels allow for higher rates of penetration. As well, lower-viscosity drilling muds result in lower equivalent circulating densities (i.e., the measured increase in bottom hole pressure due to frictional pressure losses that occur when mud is circulated).



55

A simple measure of viscosity, the funnel viscosity, is made by the derrickman using a Marsh Funnel. The measurement is simply the number of seconds required for the fluid (1 quart) to flow through a calibrated orifice. Rotational viscometers, shown below, are used to provide a more accurate rheological measurement, by measuring the shear stresses resulting from various applied shear rates.

3.3.3 Gel Strength Gel strength measures the attractive forces of suspended particles when the fluid is static. It therefore determines the ability of the drilling fluid to develop a gel structure, or thicken, as soon as it stops moving. Its purpose is to hold cuttings and mud solids in suspension when circulation is stopped so that they do not sink and settle around the bit or bottom hole assembly, or lead to uneven distribution and patchy mud which would result in poor hydraulics and erratic pressure. The gel strength must be low enough to release the cuttings and entrained gas at the surface, minimize swabbing when the pipe is pulled (thereby preventing an under-balanced condition), and resume circulation without high pump pressure (which can fracture a weak formation). Gel strength can be reduced by reducing solids content or by adding an appropriate deflocculant.

3.3.4 High vs. Low Viscosity and Gel Strength

High viscosity and gel strength leads to:

• higher pressure in order to break circulation

• higher swab and surge pressures • higher annular pressure losses • better retention of gas and cuttings. Low viscosity and gel strength leads to:

• poor removal of cuttings and hole cleaning

• poor suspension of cuttings and solids when circulation is halted.

3.3.5 Filtrate/Fluid Loss Fluid loss is measured to determine the volume of filtrate (i.e., the liquid portion of the drilling mud that enters permeable formations next to the borehole). Excessive fluid loss can dehydrate the drilling mud, in which case it must be treated to restore it to its proper balance. Depending upon the chemical



56

composition of the filtrate and the formations, high-fluid loss can cause hole problems (pipe sticking or washouts) and damage the productive formation by blocking pores and pore-throats. Chemical thinners or other additives, such as bentonite, can reduce fluid loss.

3.3.6 Filter Cake The filter cake is a layer of drilling mud solids deposited on the borehole walls as filtrate enters permeable formations in an overbalanced well. By lining the permeable sections of the borehole, the filter cake helps to consolidate the formation, prevent further fluid invasion and minimize fluid loss. In extremely permeable formations, the mud solids may not be large enough to line the borehole wall. In these exceptional cases, the mud solids may enter the formation and block the pore throats, consequently damaging the permeability of the formation. A thin, hard filter cake is preferable to a thick, soft filter cake. An excessively large filter cake reduces the diameter of the hole and increases the possibility of stuck pipe or swabbing the hole when removing the pipe. In general, the higher the fluid loss, the thicker the resulting filter cake.

3.3.7 Mud pH Level The pH level of drilling mud should be monitored in order to maintain sufficient alkalinity and reduce pipe corrosion. Caustic soda is often added to increase and/or maintain the pH level. A further benefit of monitoring the mud pH is the detection of hydrogen sulphide gas or, at least, its former presence. Scavengers, such as copper carbonate, zinc compounds and iron derivatives, are added to drilling mud for the purpose of combining or reacting with H2S should it enter the borehole. This results in the formation of sulphide compounds and the release of hydrogen ions. The hydrogen ions increase the acidity of the mud resulting in a drop in the pH level. Thus, by monitoring the pH of the mud, it can be seen that H2S had entered the borehole but that the scavengers have been successful in removing it before the mud reached surface.

3.3.8 Mud Salinity A significant change in mud salinity, when no salt additives have been used to treat the mud, signals penetration of a salt formation. The saline content of the drilling mud can then be increased to stabilize the salt formation and reduce hole washout as a result of the salt formation going into solution (i.e., dissolving in the drilling mud). Salt-water muds must be saturated, preferably, with the same type of formation salt. Minor fluctuations can indicate influxes of formation fluid and are therefore a valid indicator of changes in formation pressure. NB for details on fluid model types, such as Bingham and Newtonian, together with fluid hydraulic theory and formulae, refer to Datalog’s DRILLING FLUID HYDRAULICS manual.



57

4 DRILLING A WELL 4.1 Well Balance The hydrostatic pressure of the drilling fluid column exerted against the borehole wall helps prevent unconsolidated or overpressured formations from caving into the hole. This pressure also helps to prevent kicks (i.e., the controllable flow of formation fluids into the wellbore resulting in displaced drilling mud at the surface) and blowouts (i.e., uncontrolled flow of formation fluids into the wellbore).

4.1.1 Underbalance versus Overbalance If the hydrostatic pressure is equal to the formation fluid pressure, the well is at balance. An overbalance exists when the mud hydrostatic is greater than the formation pressure. In permeable formations, an overbalance can result in invasion of the formation (i.e., drilling fluids enter the formation, displacing formation fluids away from the wellbore). In very permeable formations or when the overbalance is excessive, flushing can occur ahead of the bit before the formation is drilled. This may result in no show, or gas response, being seen from a potential productive formation. An important consideration, especially in long-hole sections, is that whereas the mud hydrostatic may provide a marginal overbalance against high- pressure formations at the bottom of the hole, it may be imposing an excessive pressure against

shallower, weaker formations. This may lead to formation damage, and in the worst scenario, may even fracture the formation. Once fracture has occurred, drilling fluid will flow freely into the formation. Such lost circulation may lead to the loss of hydrostatic head in the annulus. This is not only costly, but may result in an underbalanced situation lower in the hole where a kick is then a very real danger. Such a situation of lost circulation and a kick occurring simultaneously can easily lead to an underground blowout. Underbalance occurs when the hydrostatic pressure is lower than the formation pressure. This may allow an influx, or flow, of formation fluids into the wellbore which may, in turn, result in a kick. This influx will be large, or more rapid, where there is good permeability and/or high formation pressure. Where formations are impermeable, the formation fluid is unable to flow freely. In this situation, the differential pressure will result in the fracturing and caving of the formation. This will then not only lead to an increase of formation fluid entering the drilling mud, but also to loading of the annulus with cuttings, squeezing of the hole (leading to tight hole or stuck pipe problems) and to difficult cuttings analysis since they are coming from further up the hole as well as from the formation being drilled.



58

Underbalanced drilling can dramatically improve penetration rates. In fact, with the appropriate surface equipment, underbalanced drilling has several benefits, including limited formation and reservoir damage, no lost circulation or differential sticking, no flushing of formations, and, in effect, a continual formation test.



59

4.2 The Well Bore

4.2.1 Starting Point Once a drilling rig has been positioned, whether it be a land rig or offshore vessel, the drilling operation is ready to commence. Typically, a wide conductor pipe, up to 36” in diameter, will be forcibly driven into the surface sediments by repeated hammer blows. The sediments can then be drilled out from the inside of the conductor pipe with returns and cuttings circulated via a divertor. Driving the pipe, rather than drilling a hole first, will prevent the surface sediments from being washed out and weakening the foundations of the rig. A firm anchor is therefore provided for the installation of the blowout preventers. On jackup rigs, this provides an immediate link between the wellbore and the rig and BOP stack. Alternatively, the hole may be drilled first before running conductor pipe. When the surface formation is first penetrated by the bit, the well is said to have been spudded. The hole may be drilled ‘in one go’ with a large bit or it may be drilled first with a smaller bit and then re-drilled with a larger diameter hole opener. Offshore floating rigs will drill this first hole section ‘open’, allowing the seawater to act as the drilling fluid and return the drilled cuttings to the seabed. Before drilling can go any further the hole must be sealed off to provide a closed system. This will then allow a drilling fluid to be continually recycled and drilled cuttings collected and examined. A wide diameter pipe, equivalent to the conductor pipe but now called casing, will be run into and down to the bottom of the drilled hole. A cement mixture will then be pumped into the casing and forcibly displaced so that it fills the space between the casing and the formation. Once this cement has set, the well is ‘sealed’ so that when drilling recommences, the drilling fluid as well as any formation fluid will be safely returned to the surface via the inside of the casing. Again, once set, this casing will prevent any collapse of the surface sediments, which may typically be weak and unconsolidated, providing a firm foundation and a firm anchor on which to position the blowout preventers. In general, the BOP stack will be installed once the casing has been set, although in some cases, operators will wait until the surface hole has been drilled and casing set. In the case of jackup rigs and land rigs, the BOP’s are installed directly beneath the rig floor. A flow line will then be connected to return drilling mud and cuttings to the surface circulation system. In the case of offshore floating rigs, the BOP stack is installed on the seabed where the casing strings terminate. A marine riser, which includes a telescopic or slip joint to allow for vertical movement of the rig due to tidal and heave motion, will link the BOP stack to the rig completing the closed system. A divertor is always installed as part of the surface flowline system, so that, if the well can not be controlled by the BOP’s, and returns are reaching surface, gas can be directed safely away from the rig.

4.2.2 Surface Hole This hole section will be drilled to a pre-determined depth and again sealed off by running casing to the bottom of the hole and cementing it in place. The base of the casing, or shoe, will generally be the weakest part of the next hole section simply because it is the shallowest point and subject to the least



60

overburden and compaction. The depth and lithology to which the surface hole is drilled and the casing set is therefore very critical (this applies to any casing point). The lithology should be consolidated, homogeneous and with low permeability. The competence of this lithology must provide sufficient fracture strength to drill the next hole section with a sufficient safety margin over any formation pressures expected (see Leak Off Tests; Fracture Pressure; Kick Tolerance). The surface hole will be of wide diameter and will normally drill quite rapidly since the surface sediments will not be too compact or consolidated. A large volume of cuttings will therefore be continually produced. To ensure that these cuttings are removed from the annulus and so to prevent them blocking or impeding the movement and rotation of drillstring and bit, viscous sweeps will be made at regular intervals. This simply involves a volume of thick, viscous drilling mud being circulated around the entire hole. The viscosity of the mud enables it to lift and carry all of the cuttings out of the hole. The surface hole will normally be completed with just one drill bit. If the bit should wear out however, it will have to be replaced by lifting the entire drillstring out of the hole (tripping). This is done by breaking the drillpipe into lengths of 3 (triple stand) or 2 (double stand) joints, depending on the size of the derrick. Once the hole section has been completed and before the casing string is set in place, the Operator will normally require the hole to be logged with electrical tools in order to gain specific information about the wellbore and lithology. These tools are run into the hole on a thin wire and are therefore termed wireline tools. The wireline tools are very expensive but the wire can only be subjected to a certain amount of load before it would snap. Therefore, before logging, a wiper trip will be performed. This operation is to ensure that the hole is clean and not closing in at any point. It involves raising the drillstring part way out of the hole or until the bit is out of the open hole and inside the previous casing. The bit will then be run back into the bottom to determine the condition of the hole. Any tight spots will have to be corrected. Minor problems can be corrected simply by working the pipe up and down over the tight spot; circulating at the same time will help to clean tighter sections. If the hole is so tight or undergauge, it may seriously restrict the movement of the pipe or even not allow the bit to pass at all. In this situation, the tight section will have to be effectively re-drilled or reamed with full circulation and rotation. When the bit reaches the bottom of the hole, a bottoms-up circulation will be performed. This ensures that any cuttings that may have fallen, or have been dislodged during the hole cleaning, to the bottom of the hole (fill) are lifted and circulated out of the hole. This will enable the logging tools to be run all the way to the bottom of the hole. Once the hole section has been logged, casing can be run and cemented in position. The main purposes of the surface casing are again to provide a firm and competent anchor for the BOP equipment; to protect formations from further erosion; to seal off fresh water aquifers from any contamination; to prevent collapse of unconsolidated formations; to seal off any subnormal or overpressured formations. Before drilling ahead with the next hole section, the BOP stack and casing will be pressure tested to ensure that there is full integrity and that all prevention equipment is fully functional.

4.2.3 Intermediate Hole Before this hole section can be started, rubber plugs and cement remaining from the cementing of the previous casing will have to be drilled out before new lithology is encountered. Just a small interval of the next hole section will then be drilled, typically 5 to 10 metres, and then a pressure test performed.



61

This Leak Off or Formation Integrity Test will determine the integrity of the cement bond and also enable us to determine the fracture pressure of the formation at the shoe. This tells us to know the maximum pressure that can be exerted on the wellbore without fracturing that formation, a situation that has to be avoided at all costs. Exactly the same procedures will be followed as outlined above, i.e. drilling, tripping, logging, casing and cementing. The exact number of hole sections will be dependent on several factors: • Depth, fracture pressure and kick tolerence of the previous casing shoe. • Hole/formation problems that may be encountered such as zones of lost circulation, unstable

formations, abnormal formation pressures, pipe sticking problems. • Change of mud type to a system that may be unsuitable or damaging to particular formations. All of these situations may result in an intermediate string of casing being set to seal off a particular interval. Each subsequent casing string will be run from the surface, inside the previous casing, to the bottom of the hole. This new string may be cemented all the way back to surface, but it is normal to cement it back to the inside of the previous casing which is already cemented back to surface.

4.2.4 Total Depth As the total depth (TD) of the well is approached, any casing that may need to be run will normally be run into the hole on drillpipe and hung from a hanger inside of the previous casing. In this situation, it will be termed a liner, but procedures for cementing and testing will be exactly the same as for any casing string. Obviously, as the well becomes deeper, the casing requirements become much more expensive if it were to be run all the way back to surface. Situations vary, but the well may be drilled through a prospective production zone to the well’s TD, or it may be drilled to just above the production zone and the liner set in place. This situation would enable any problem zones previously encountered to be sealed off and the production zone isolated; it would allow the mud system to be changed or modified specifically for the zone of interest in terms of formation and production protection and pressures expected. Depending on operator requirements and on indications when drilling into the zone of interest, eg rapid drilling to indicate porosity, gas or oil shows from the drilling fluid, the interval may or may not be cored. Cutting and preserving a core of the reservoir interval allows much more precise laboratory analysis to be carried out regarding the productivity and economical potential of the reservoir. Cutting a core requires the use of a specialized core bit that will cut around and leave a central core of rock, typically around 10cm in diameter, intact. As the bit cuts down and deepens the well, this core will move up into a special sleeve and core barrel that will hold the core. At the end of the coring operation, the core will be held in the barrel and it has to broken off from the bottom of the wellbore by physically lifting the string until the core snaps off. This is a very important operation to ensure that the core is retained and does not fall out from the barrel.



62

At TD, the well will again be logged with wireline tools. A fuller array of evaluating tools may be run if the zone of interest shows good hydrocarbon potential. If a core hasn’t been cut, sidewall cores may be cut with a wireline tool from specific depths of interest. If the zone shows producing potential, the well may be production tested with a drillstem test (DST). A production casing string will be run to the bottom of the hole and cemented in place. This casing can then be perforated at specific depth intervals that correspond to the zone of interest. The casing will have been displaced to a specialized fluid or brine, the density of which will allow formation fluids, including oil and gas, to flow into the wellbore. Testing equipment, known as a christmas tree will be installed at the surface to measure and determine the reservoir pressure and flow rates. Once all work has been completed, the well will be plugged with cement to isolate any open hole or production zones from the surface. If there is no reservoir potential, the well will be abandoned; if there is potential the well will be suspended to allow for further analysis and testing to be completed.



63

4.3 Drilling and Making Hole The drilling operation involves lowering the drill pipe into the hole and applying sufficient weight for the drill bit to break down the formation. During drilling, the drill string is rotated by a rotary table or top drive while drilling fluid is circulated down the pipe, through the bit and back up the hole to the surface carrying drilled cuttings. As drilling progresses, joints (or stands when using a top drive unit) of drillpipe have to be continually added to the top of the drillstring, by making a connection. Circulation is temporarily stopped and the drill string set within slips held in the rotary table, to expose the top pipe joint. Tongs are used to unscrew the kelly from the drill string, a new pipe joint is connected to the kelly, and then the kelly and new pipe are connected to the drill string using a pipe spinner and tongs. Once these connections have been made, the drill string is lowered back into the hole and drilling resumes. When the bit wears out, it must be replaced by tripping the entire drill string out of the hole.

4.3.1 Pipe Tally To ensure that the depth is being accurately monitored, it is important to record the pipe length before it is run into the hole (pipe tally), and regularly check this length with the recorded depth at kelly down intervals (i.e., the point at which the kelly has been drilled down to its fullest extent). If using a kelly, the drilled depth is equal to the Bottom hole Assembly + Pipe Length + Kelly Length. If using a top drive, the drilled depth is equal to the Bottom hole Assembly + Pipe Length. Each length of pipe will be measured, to an accuracy of 2 decimal places, before it is added to the string and run into the hole. These lengths are recorded by the driller, in a pipe tally book, and a cumulative total maintained. The mud logger should keep an independent record of the pipe lengths and total, so that pipe tallies can be cross-checked to avoid errors. So that depths can be easily referenced at a later stage, it is an important practice for the mudlogger to record or mark down the kelly down depth on all realtime charts.

4.3.2 Drill Breaks and Flow Checks A drilling break is a sudden increase in the drill bit's rate of penetration. This may result simply from a formation change, but sometimes indicates that the bit has penetrated a high-pressure zone and thus warns of the possibility of a kick. A flow check is a method of determining whether a kick has occurred. The mud pumps are stopped for a short period to see whether mud continues to flow out of the hole. If it does, a kick may be occurring, with the formation fluids entering the wellbore and displacing mud from the annulus at the surface. The flow check may be performed by visually inspecting the annulus through the rotary table, or by directing the mud returns to the trip tank and observing the mud level.



64

The drilling speed, or penetration rate (ROP) directly impacts drilling costs, and is one of the major factors in determining the efficiency and overall cost of a drilling operation. However, a well cannot simply be drilled at maximum speed to minimize costs. To optimize drilling operations, a well should be drilled as fast as prudently possible, with due precaution to maintain hole stability, to allow sufficient time for hole cleaning and to ensure continual well and personnel safety. Adherence to drilling procedures is essential in optimizing drilling operations. Drilling procedures are documented from knowledge and experience drilling wells under various conditions. They set forth the requirements for safe, routine drilling operations, and provide corrective measures for problems encountered while drilling. Because drilling conditions vary from one oil field to another, drilling procedures should be supplemented with records from offset wells (i.e., other wells in the area) which have been drilled successfully.

4.3.3 Reaming Reaming is performed to open an under-gauge hole to its original full-gauge size. Reaming may be required as a result of under-gauge drilling in abrasive formations or excessive wear on drilling bits. Reaming is also performed to open surface pilot holes, to open ratholes left after coring (i.e., a smaller-diameter hole than the main hole), and to remove doglegs (i.e., a sharp bend in the wellbore, keyseats (i.e., an under-gauge channel or groove cut in the side of the borehole that results from the pipe rotating on a dogleg), and ledges (i.e., an irregularity caused by penetrating alternating hard and soft formations, where the soft formation is washed out and changes the hole diameter). Reaming may be performed to prevent an under-gauge hole from pinching a new bit. A reamer is the tool used to smooth the wall of a well, enlarge the hole to full-gauge size, help stabilize the bit, straighten the wellbore if kinks or doglegs are encountered, and drill directionally. Most reamers used today have roller cutters in alignment with the axis of the reamer body, which provides a rolling action as the reamer is rotated. The risk of hole deviation can be minimized by selecting the proper weight on bit and rotation speed. While the bit weight is normally a compromise between a penetration rate, bit wear and deviation control, the rotation speed should be controlled by the bit size and type and the formations to be drilled.

4.3.4 Circulating Circulating is the process of pumping drilling fluid out of the mud pits, down the drill string, up the annulus and back to the mud pits, and is a continual process while drilling. Circulating, while not drilling, may be performed to clean the hole of drill cuttings, to condition the drilling mud ensuring it retains optimum properties, or to remove excessive gas from the mud. The most common circulating operations are performed for the following purposes: • to circulate out drilling breaks which may be an indication that a high pressured zone has been

penetrated



65

• to circulate out samples that correspond to drilling changes (ROP, torque) which may indicate that a

potential zone of interest or coring point has been reached. • prior to running casing and cementing, to condition the mud, ensure the hole is clean (so that the

casing won't stick) and to remove filter cake (to ensure good contact between the cement and borehole wall).

• prior to running wireline tools, to ensure that the hole is clean and the tools won't become stuck.



66

4.4 Coring

4.4.1 Purpose Coring is an operation performed to cut and retrieve a cylindrical rock sample, or core, from a potentially productive formation of interest for laboratory analysis. Through coring, it is possible to recover an intact core sample that retains more formation properties and fluids than drilled cuttings. Coring may be performed for precise formation and structural evaluation or, more specifically, to retrieve core for reservoir evaluation. While coring is an expensive operation to perform, it provides valuable information for determining porosity, permeability, lithology, fluid content, angle of dip, geological age and hydrocarbon-producing potential.

4.4.2 Coring Methods Conventional coring requires tripping the drill string out of the hole. The core bit and barrel assembly is attached to the bottom of the drill string and run into the hole. Conventional coring is performed in much the same way as drilling, but more carefully and slowly. Any vigorous or sudden change in the drill string rotation can cause the core to break and fall into the hole or to jam in the barrel, thereby preventing any further coring. The drill string must then be tripped out of the hole in order to recover the core. After the core is drilled, the whole assembly is tripped out of the hole to retrieve the core. Conventional coring requires expensive equipment and costly rig time. With this method, there is an increased risk of swabbing in formation fluids when tripping out, and there is the danger to personnel should poisonous gas be released at the surface. Conventional core samples usually range from 2-5 inches (50-125 mm) in diameter and from 30, 60 or 90 feet (10, 20 or 30 meters) in length. Their size makes them difficult to handle. Sidewall coring is a technique by which, core samples are obtained from the wellbore wall in a formation that has already been drilled but not yet cased. It offers the advantage that many cores can be taken at precise depths using one tool. A sidewall coring gun containing sample ports at the intervals required for testing is lowered on wireline. An explosive charge fires up to thirty hollow bullets into the formation. The bullets are then pulled back into the gun along with the core samples. The gun is then lifted out of the hole on wireline. Sidewall core samples usually range from ¾-1¼ inches (20-30 mm) in diameter and from ¾-4 inches (20 to 100 mm) in length. Because samples may be contaminated with filtrate, sidewall coring is not as effective as conventional coring for determining porosity, permeability or fluid saturation. A further disadvantage is that weak or friable formations may be "shattered" by the bullet, preventing good core samples being retrieved. Newer tools avoid this problem by individually "drilling" the core samples rather than using the bullet technique. This method is also necessary to retrieve core samples from very hard lithologies that are otherwise impenetrable with the bullet.



67

4.4.3 Core Barrel Assembly The core barrel is a tubular device installed at the bottom of the drill string. The conventional core barrel actually has two barrels. A non-rotating, thin-walled, inner core barrel captures and holds the core after it travels through the core bit. A heavy, thick-walled, outer core barrel protects the inner barrel and takes the place of the bottom-most drill collar. Unlike a drill bit, the core bit does not drill out the center portion of the hole. Instead, it allows the center portion (i.e., the core) to pass through a round opening in the center of the bit and into the core barrel. Diamond-bit core barrels have consistently proven their durability, cutting reliability and recovery capability. Today, they are used almost exclusively in both conventional and wireline coring. Drilling mud is initially circulated through the inner barrel. Just prior to coring, a metal ball is dropped down the drill string to engage a check valve. The check valve closes, thereby diverting mud flow from the inner barrel to the outer barrel so that it does not erode or displace core from the inner barrel. The drilling mud is then discharged through water courses in the bit.

A rabbit, or core marker, is a metal device, placed in the inner core barrel before coring. When all of the core has been removed from the core barrel, the rabbit, or core marker, falls out indicating that the barrel is empty.

4.4.4 Retrieval and Handling Operations When a sufficient amount of core has been cut, the core barrel is lifted, causing the rock to break off and leaving the core trapped inside the inner core barrel. In conventional core recovery, when the core barrel arrives at the surface, it is usually hung in the derrick and specially designed tongs are used to grip the core for recovery in sections. Once the core has been completely removed from the barrel, it is measured. If the recovered core length is shorter than the cored interval, it can be assumed that the shortage has been lost at the bottom of the hole. Immediately after measuring, core sections are wiped clean (not washed) to remove drilling fluid, then rapidly sealed in foil and wax and placed in boxes for shipping to the laboratory.

Outer Core Barrel

Rabbit

Metal Ball

Check Valve

Inner Core Barrel

Core Bit

Water Courses



68

This practice prevents contamination as well as loss of gas and other formation fluids. Boxes are pre-marked with the box number (1 of n), the core number, top and bottom indicators and sample interval. Most commonly, today, fibre glass or aluminum sleeves are used to contain the core as coring proceeds. This simplifies the core recovery procedure. The sleeve containing the core is removed at the surface and is immediately ready for shipping. The sleeve may be kept complete or cut up into sections with each end sealed (e.g., using heat-shrinking caps).



69

4.5 Tripping Tripping refers to hoisting the drill string out of the wellbore (tripping out or pulling out) and then returning it to the wellbore (tripping in or running in). Tripping is performed to change the drill bit or the bottom hole assembly. Tripping is also performed at casing points (depths at which casing is set), coring points (depths at which core samples are taken) and upon reaching the well's total depth. Wiper trips, or dummy trips, are performed to clean the hole during long-hole sections (thus ensuring there are no tight spots, sloughing shale, etc. that may result in tight hole problems if left unchecked). A set number of stands are pulled out of the hole and then run back to the bottom to resume drilling. Sometimes, the drill pipe is pulled back into the previous casing and then run back to bottom of the hole. Such "clean up" trips are also made before running wireline tools and prior to running casing.

4.5.1 Trip Speed The drill string should be tripped at the fastest, safe running speed. Because drilling ceases for the duration of the trip, the objective is to trip only when necessary and as quickly as possible in order to minimize costs while ensuring proper well maintenance and personnel safety. Excessive tripping speeds cause swabbing and pressure surges, which in turn can cause severe hole problems and loss of pressure control. The maximum safe trip speed can be determined by calculating and preparing a tripping speed table using reliable data and omitting excessive safety factors. The actual tripping speed should then be monitored by measuring the speed of the middle joint of the drill string in a stand.

4.5.2 Pulling Out of Hole The main concern when pulling pipe out of the hole is to avoid fluid influxes that may result in a kick. This will result from a reduction in hydrostatic pressure as a result of not maintaining the mud level in the annulus and/or causing excessive swabbing pressures. When the drill pipe is pulled from the hole, the mud level in the annulus will drop by an amount equal to the volume of steel of removed pipe. This drop in mud level obviously reduces the vertical height of the mud column, resulting in a lower hydrostatic pressure at the bottom of the hole. To avoid the bottom hole pressure falling below the formation pressure (which will result in an influx), it is critically important that the mud level in the annulus be kept full (i.e., mud is pumped into the hole to replace the volume of steel as pipe is removed). A small pump circulates mud between the trip tank and the wellhead to top up the hole as pipe is lifted from the hole. The trip tank is a small mud tank used to accurately measure small changes in mud level as the hole is filled. The volume of mud pumped into the hole (i.e., drop in trip tank level) must equal the volume of steel removed. This may be done continuously as pipe is lifted or, more typically, the mud



70

level is topped up after very five stands of drill pipe and then individually for stands of heavy-weight drill pipe and drill collars (due to the larger steel volume per unit length).

Owing to their thickness, the most critical time for keeping the hole full occurs when pulling the drill collars since they have a large steel volume per unit length. Each stand pulled therefore results in a much greater drop in mud level than that resulting from one stand of drill pipe. For example, approximately 0.1m3 of mud is required to replace one stand of standard 5" drill pipe, whereas close to 0.8m3 is required to replace one stand of 8" drill collars. It is normal safe practice, especially when using spiral drill collars, to perform a flow check prior to pulling

the drill collars out of the hole, to ensure that the well is static (i.e., not flowing) since the preventers cannot close effectively around the collars.

4.5.3 Swabbing When drill pipe is lifted vertically, the surrounding mud will move as a result of two processes. Firstly, due to mud’s viscosity, it will tend to “stick” and lift with the pipe. Subsequently, the mud will drop to fill the void left as the pipe is lifted. The resulting mud movements cause frictional pressure losses that reduce the mud hydrostatic. This may result in a temporary condition of underbalance that will allow formation fluid to influx. Swabbing increases with higher mud weight, higher viscosity, lower annular clearance and faster pipe running speeds. The pressure losses occur throughout the annulus with a cumulative reduction in pressure at the bottom of the hole. The reduction is therefore greatest when the pipe is first pulled off bottom. Added to this is the further "piston" effect, which is greatest around the drill collars (i.e., where there is the smallest annular clearance). It is therefore normal practice to pull the first five or ten stands very slowly to keep swabbing to a minimum as the drill pipe is being pulled through formations which have not yet had enough time for sufficient filter cake to build up. It is also normal practice to maintain a trip margin. This means maintaining a mud weight that, even with the swabbing pressure reduction, provides a hydrostatic pressure greater than the formation pressure. This can be determined for a maximum running speed, for which the swab pressure can be calculated.

Looking down into an offshore triptank



71

Using appropriate software, the maximum running speed (X) to avoid exceeding a given swab pressure (Y) can be determined.

4.5.4 Running In Hole Mud is normally displaced directly to the suction pit when drill pipe is run in the hole, and, as with pulling out, it is equally important to ensure that the correct volume of mud is displaced for the pipe run in the hole. If too much mud is displaced, the well may be flowing; if not enough mud is displaced, the well may be losing mud. Unlike lifting pipe, when drill pipe is run in the hole, the resulting mud movement and frictional pressure loss leads to an increase or surge in the hydrostatic pressure. Surge pressure is calculated in the same way as swab pressure. Surge pressure can result in formation damage, but, ultimately, may cause the formation to fracture. This would result in lost circulation, loss in hydrostatic head and, finally, a kick. The other important difference from pulling out is that, initially, the pipe is empty. If the drill string is not filled, it is susceptible to potential collapse since there is nothing to balance the pressure imposed by the mud in the annulus. Normally, the drill pipe will fill naturally as it is run in, from mud entering through the bit nozzles. If too much displaced mud is seen (i.e., greater than the open displacement), it may be due to any or a combination of small nozzles, dense or viscous mud, or running in too fast. If this occurs, it is important that the driller be notified so that he can first check that the well is not flowing, then secondly, fill the drill string, and perhaps subsequently, reduce the running speed. Naturally, if the nozzles become blocked, or plugged, with cuttings, mud is unable to enter the drill string, so that a closed displacement is seen (i.e., steel volume plus internal capacity). Again, the driller should be notified so that he can attempt to pump and unplug the nozzles before proceeding with the trip. Closed displacement will also be seen if a float is intentionally placed in the drill string. This is a one-way valve that allows circulation but does not allow mud to pass up through it. Floats are often used

Pipe Speed

Pressure

X

Y



72

when expensive equipment such as mud motors and measurement-while-drilling (MWD) tools are used in the drill string to prevent mud and cuttings from entering and damaging them. When a float is used, the drill pipe will obviously not fill by itself, so the trip should be stopped at regular intervals to enable the driller to fill the pipe with mud. Typically, the driller will continue pumping until the mud is circulating up the annulus to ensure that the drill pipe is completely full. At the point of breaking circulation, the pump pressure (which would have been slowly increasing as the drill string filled) will show a sharp increase. Because the static drilling fluid would have thickened, or gelled, a higher than normal pressure may be required to break circulation. When circulation commences following a trip into the hole, a distinct gas peak, called trip gas, will be recorded upon reaching bottoms up (i.e., the time it takes to circulate the mud from the bit to the surface). Trip gas originates from a number of different mechanisms: • repeated swabbing of formation fluids when the drill pipe was initially pulled from the hole • accumulation of cuttings at the bottom of the hole that will subsequently liberate gas when circulated

to the surface • fluid diffusion when the mud is static during the trip, especially from the bottom of the hole where a

filter cake has not built up sufficiently Naturally, the lower the pressure differential (i.e., hydrostatic versus formation pressure) and the more gaseous the formations, the larger the volume of trip gas. It is often accompanied by an increase in flow rate from the hole.

4.5.5 Monitoring Displacements Mud displacement should be calculated from the pipe volume before tripping. Accurate trip sheets should be maintained to record actual displacement and make necessary adjustments as tripping proceeds. Any deviations recorded by mud loggers should be reported immediately to the driller. An example Trip Sheet is shown over the page: -

4.5.6 Hook Load Hook load is the weight of the drill string suspended by the hook. As drilling proceeds deeper, the hook must support increasing string weight. Through displacement, the drill string is buoyed up by the drilling fluid, thereby reducing the total weight that the hook must support. When tripping in or out, the buoyancy factor of the drilling fluid must be taken into consideration. The denser the drilling mud, the greater the buoyancy effect and the lighter the apparent weight of the drill string. When tripping out, the resistance of the drilling mud makes the actual hook load greater than the string weight. When tripping in, part of the string weight will be supported by the mud, making the hook load lighter than the actual string weight.



73

If tight spots or sections are encountered, the change in hook load depends on whether the pipe is being tripped out or tripped in. When tripping out, additional resistance must be overcome in order to lift the pipe. This additional hook load is termed overpull. When tripping in, a portion of the string weight will be supported by the tight spot, so that the measured hook load will decrease. This is known as drag.

DATE: 12 SEP 97 HOLE SIZE: 311mm BOTTOM HOLE ASSEMBLY SIZE LNTH DISP/m TOTAL BIT RUN NUMBER: 10 HOLE DEPTH: 2500m DC 1 203 300 0.028 8.4 m3 DC 2 BIT TYPE: HTC ATM22 CASING SIZE: 339mm HWDP 127 250 0.0094 2.3 m3 RUN IN / PULL OUT: IN SHOE DEPTH: 1800m DP 1 127 1950 0.0042 8.2 m3 DP 2 STAND NO.

CALCULATED DISPLACEMENT

ACTUAL DISPLACEMENT

CUMULATIVE CALC. DISPL .

CUMULATIVE ACT DISPL .

DIFFERENCE

DC 1 0.84 1.0 0.84 1.0 + 0.16 DC 2 0.84 0.8 1.68 1.8 + 0.12 DC 3 0.84 0.6 2.52 2.4 - 0.12 DC 4 0.84 0.8 3.36 3.2 - 0.16

DC 10 0.84 0.9 8.40 8.5 + 0.10 HW 1 0.46 0.4 8.86 8.9 + 0.04 HW 2 0.46 0.5 9.32 9.4 + 0.08

DP 5 0.63 0.6 11.33 11.4 + 0.07 DP 10 0.63 0.6 11.96 12.0 + 0.04 DP 15 0.63 0.7 12.59 12.7 + 0.11

DP 55 0.63 0.7 17.64 18.0 + 0.36 DP 60 0.63 0.7 18.27 18.7 + 0.43 DP 65 0.63 0.7 18.90 19.4 + 0.50

Final Displacement for Trip: Calculated 18.9 m3 Actual Returns 19.4 m3

4.5.7 Strapping and Rabbiting the Pipe Strapping the pipe refers to manually measuring each stand of drill pipe as it is pulled from the hole. Strapping is performed to confirm the pipe tally and actual hole depth. Rabbiting the pipe refers to cleaning debris from the inside of the drill pipe by dropping a rabbit (usually wooden) down the vertical length of the pipe. Rabbiting is performed more often when using expensive downhole tools such as motors and measurement-while-drilling (MWD) instruments.



74

4.6 Electrical Logging After each section of the hole is drilled (prior to running casing) and at the total depth of the well, a variety of electrical, or wireline, logs can be run in order to obtain information concerning formation or reservoir evaluation or hole condition. Several electrical tools, or sondes, can be connected together and run in the hole on a wireline from a specially designed unit. Various common types of logs are briefly described below.

4.6.1 Formation Evaluation Gamma Ray The gamma ray is primarily to determine lithology and correlate formation tops

in adjacent wells. Gamma measures the natural radioactivity of the rocks by detecting elements such as Uranium, Thorium and Potassium.

Gamma is used to determine the shale content of sands since shale possesses a higher content of radioactive material. Shale free sandstones and carbonates, typically, have low gamma readings although certain mineralogies such as K-feldspars, micas and glauconite may increase the values.

Resistivity Resistivity measures the resistance of a formation to conducting electricity and is

used to determine the type of fluid occupying a rock's pore space, the relative saturation levels of oil and water in formations, and the mobility of the fluid.

Measurements are taken at different amounts of penetration into a formation, typically 30, 60 and 90cm. The deeper measurements are likely to be a more true indication of fluid type since they are unlikely to be affected by mud filtrate invasion. Comparisons of the 3 measurements can also be an indicator of relative permeability. Resistivity increases with the presence of oil, since it is non-conductive. It can therefore be used to determine the degree of water saturation (Sw) and hydrocarbon-water contacts.

Sonic The sonic tool measures the transit time of a compressional sound wave, per unit

length, in a vertical direction adjacent to the borehole. The transit time (microsec/m) is the reciprocal of the sound waves velocity and is a function of matrix and porosity. As porosity decreases, so too, does the sonic transit times. Hence, as a direct indicator of porosity and compaction, the sonic is an excellent tool for determining undercompacted and overpressured zones.



75

Spontaneous Potential measures the electrical potential of the formation (i.e., current flows between formation waters of different salinity). It can be used to determine lithology, formation water resistivity and aids well correlation.

Density The formation density log determines the electron density of a formation by

bombarding it with gamma rays. These collide with formation electrons and suffer an energy loss. The number of returning particles is a direct function of the bulk density of the formation.

Typically, the density log is only run through zones of interest, rather than the

entire length of the borehole. Otherwise, as a direct indicator of compaction, the density log is an excellent tool in overpressure evaluation.

Neutron Porosity The neutron log measures the concentration of hydrogen ions in a formation. The

formation is bombarded with neutrons, which suffer an energy loss on collision with nuclei. The greatest energy loss occurs on collision with hydrogen atoms since they are a similar size.

Since hydrogen is concentrated within the fluid, whether water or hydrocarbon, the measurement is a function of porosity (although clay lattice-bound water cannot be distinguished from pore water).

Where gas is present, the hydrogen concentration decreases and results in the “gas effect”, a significant drop in the neutron porosity.

4.6.2 Hole Condition Caliper Log Most holes are not drilled true-gauge (i.e., to bit diameter). They are often

enlarged as a result of a bit drilling off borehole center, hole washout and/or sloughing shale.

A caliper log, which records hole diameter by depth, is run to determine variations in hole gauge. The caliper tool has two legs or pads that track along the wellbore wall as the wireline is pulled out. The caliper log provides a hole profile indicating hole enlargements and reductions. It is important to know the hole size/gauge in order to calculate cement volumes more accurately and determine the affect that variations have on other electronic logs. Excessive hole enlargements signal caving or washouts. Reduced diameters signal filter cake build-up in permeable formations.



76

Free-Point Log If the drill string becomes stuck when pulling it from the hole, the free point (i.e., the area above the stuck point) can be determined using a free-point indicator.

The free-point indicator is run on wireline into the wellbore. As the drill string is pulled and turned, the electromagnetic fields of free pipe and stuck pipe, which differ, are recorded by the indicator and registered on a metering device at the surface.

By backing off (i.e., unscrewing the free pipe from the stuck pipe), the free pipe can then be pulled from the wellbore. The stuck pipe, or fish, remaining in the hole can be washed over and recovered or retrieved using various fishing tools.

Cement Bond Log A cement bond log is an acoustic, or sonic, log used to verify the integrity

(quality and hardness) of the cement bond between the casing and the formation. It is based on the concept that sound travels faster through cement than through air. Therefore, well-bonded cement transmits an acoustic signal quickly, and poorly bonded cement transmits a signal slowly.



77

4.7 Casing and Cementing

4.7.1 Purpose An essential operation in drilling an oil or gas well is to periodically line the hole with steel pipe, or casing. Successively smaller-diameter lengths of steel pipe are either screwed or welded (in the case of large conductor pipe) together to form a continuous tube to the desired depth. Once installed, this casing is cemented in place to provide additional support and a pressure-tight seal. Casing in a well has a number of functions: • Prevent formations from caving into the hole • Isolate unstable or problem formations (high-pressure zones; aquifers, gas zones, weak zones, etc.) • Protect productive formations • Provide greater kick tolerance (the deeper the casing, the greater the fracture pressure of the formation

the casing is set in, meaning higher formation pressures can be controlled as the well is deepened) • Allow for production testing • Serve as an attachment for surface equipment and artificial lift equipment

4.7.2 Types of Casing One or more of the following types of casing is required in every well: Conductor pipe is a short string installed to protect surface sediments from erosion by drilling

fluids. It raises the drilling fluid high enough to be returned to the mud pits and prevents washing out around the base of the rig. When shallow gas sands are anticipated, it can serve as the attachment for a blowout preventer.

Surface casing is set to protect fresh-water formations and prevent loose formations from caving

into the hole. It also serves as an anchor for the blowout preventer to forestall problems with abnormal pressure zones. The casing must be strong enough to support a blowout preventer, and to withstand gas or fluid pressures that might be encountered as drilling proceeds below this casing.

Surface casing should be set deep enough, in a strong, consolidated formation with a fracture gradient high enough to support the maximum mud weight that will be needed to drill to the next casing setting point.

Intermediate casing is primarily used to protect the hole against lost circulation. It is run to seal off

weak zones that may break down as heavier mud weight is needed to control higher formation pressures as the well is drilled deeper.

It may also be set below high pressure formations so that lighter mud weights can be used when drilling proceeds.



78

Liner string is run in a deep hole to prevent lost circulation in weak upper zones while drilling with normal weighted mud to control normal-pressure formations at deeper intervals. Liners protect against downhole blowouts into normal-pressure formations when drilling abnormal pressure zones.

Unlike casing which is run from the surface to a given depth and overlaps the previous casing, liner is suspended from the bottom of the previous casing by a hanger and run to the bottom of the hole. Liner string offers a cost advantage due to its shorter length; however, a tie-back string is sometimes run after the hole is drilled to total depth to connect the liner to the surface.

Production casing is the last casing string in a well, usually set immediately above or through the

producing formation. It isolates the oil or gas from undesirable fluid in the producing formation and from other formations penetrated by the wellbore. It serves as the protective housing for the tubing and other equipment used in a well.

4.7.3 Surface Equipment As with the standard drillpipe equipment, elevators, casing tongs and casing spinners are designed for specific casing diameters, in order to lift the casing joints and connect to each other at the correct torque. The most common type of cement mixing system is the jet type. Water is forced through a reduced section of line at high velocity and cement is added from a hopper above. Cement pumps are used to control the pressure and the rate of displacement during mixing. Once the cement has been pumped down into the casing, rig pumps will be used to pump mud and displace the cement from inside the casing to the annulus. A cementing head, or retainer head, is an accessory attached to the top of the casing to facilitate cementing the casing. It has passages for cement slurry, and retainer chambers for cementing wiper plugs, so that mud, slurry and plugs can all be pumped consecutively in one continual operation.

4.7.4 Subsurface Equipment A guide shoe, or shoe collar, is a short, concrete-filled, cylindrical section of steel placed at the end of the casing string. This guides the casing into the hole, past any obstructions and minimizing the risk of the casing from becoming caught up on irregularities in the borehole as it is lowered. A float collar is usually installed between the first and second joint of casing. It is equipped with a check valve assembly, which allows downward movement of fluid, but prevents upward movement. In this way, it prevents mud from entering the casing as it is being lowered into the hole, thereby floating the casing into the wellbore and decreasing the load on the blocks and derrick. It also prevents cement from backing up into the casing during the cementing operation and after it has been displaced. Variations may include float collars that allow partial filling of the casing with mud as it is lowered into the wellbore, and collars that combine both the guiding and floating apparatus.



79

Wiper plugs are rubber plugs that are used to separate cement and drilling fluid as they are pumped down the casing during cementing. The bottom plug, which is pumped ahead of the cement, wipes residual drilling mud from the inside casing walls and prevents the drilling mud below it from contaminating the cement. The top plug, which is released after the calculated volume of cement has been pumped, wipes residue cement from the inside casing walls and prevents the drilling mud above it from contaminating the cement.

Centralizers are secured around the casing at regular intervals to hold the casing away from the wellbore walls. Centering the casing in the hole allows for a more uniform cement sheath to form around the pipe. A scratcher is a stiff-wired device fastened to the outside of the casing that is used to condition the hole for cementing. By rotating or moving the casing string up and down as it run into the hole, the scratcher removes mud cake from the wellbore walls so that the cement can bond solidly to the formation. A liner hanger is a circular, frictional-gripping assembly of slips and packing rings used to suspend liner string from the bottom of the previous casing. Using a liner hanger saves on the expense of running casing all the way back to the surface.

4.7.5 Preparing to Run Casing Before casing is run into the hole, an electric log is run to confirm the bottom hole formation for setting the casing shoe, and to confirm the hole depth so that the exact length of casing can be run. A caliper log is also run to determine the hole diameter and the volume of cement required. Cement will be pumped to fill the annulus, and into the previous casing. Typically, an extra 25% volume may be pumped to allow for error and losses to the formation. Before running casing, drilling mud is circulated to remove cuttings and excess filter cake from the hole, to condition the hole and to condition the mud to ensure uniform properties. Failure to condition the hole thoroughly and treat the mud properly can lead to stuck pipe, poor cementing, extra well costs for cement squeeze work, and even re-drilling the hole.

Wall cake scratcher

Centralizer



80

When conditioning the hole, drilling mud should be pumped around at least twice while weight, viscosity and fluid loss properties are recorded. If mud treatment appears necessary, circulation while slowly rotating and working the pipe must be maintained until the mud fluid is in suitable condition for running casing.

4.7.6 Running Casing As casing is run, it is periodically filled with drilling mud, unless automatic fill-up float equipment is used. If it wasn’t filled while running in, the hydrostatic pressure of the mud column acting on the outside of the casing would cause it to collapse. Using a light-weight filling line with a quick-opening valve, each joint is filled while the next length is picked up and prepared for stabbing. Because it is usually not possible to fill a joint completely, it is common practice to stop running casing every five to ten joints and fill completely. It is crucial that the mud displacements are accurately monitored for the whole duration of the casing run. Because the casing tubular is effectively closed ended, together with very small annular clearance, surge pressures while running casing will be large. To minimize this, the casing joints are run in at a very slow speed, but if the surge pressure was great enough, weaker formations could be fractured resulting in loss of drilling mud to the formation. Not only might fracturing the formation result in a poor cement job, it might also result in a blowout if sufficient mud is lost from the annulus to reduce the mud hydrostatic below the formation pressure of a permeable formation elsewhere in the wellbore. Therefore, mud returns and displacements are closely monitored for any indication of losses to the formation.

The volume of fluid displaced from the hole, as each joint of casing is added to the string, should be equal to the closed displacement (i.e. the casing O.D.) of the casing. Final volume gains in the suction pit should be equal to the volume of steel (i.e., open displacement) that has been run into the well, if there has been no fluid loss.

Run 5 joints of casing – Closed end displacement

Fill casing string

Final displacement = steel volume

Mud level in surface pit

Time



81

Provided proper mud returns are obtained, it is usually possible to run the casing all the way into the hole before attempting circulation. When establishing circulation, care must be taken not to run the pump too fast as the casing is lowered, so as to minimize pressure surges. If there is any indication of lost returns, the pumping rate should be reduced immediately. Circulating drilling mud through the casing after reaching bottom serves two important functions. One is to test the surface piping system. Another is to condition the mud in the hole, and to flush out cuttings and filter cake prior to cementing. Circulation time will extend for as long as required to condition the mud, and the casing is reciprocated and/or rotated, with or without scratchers, throughout circulation. Minimum adequate circulation before cementing distributes a volume of fluid equal to the volume inside the casing and annulus.

4.7.7 Cementing Operation Cementing is a process of mixing and displacing a cement slurry (dry cement mixed with water) into the annulus (i.e., between the casing and the open hole). By bonding the casing to the formation, cementing serves several valuable purposes: • Protects the productive formation • Helps control blowouts from high-pressure zones • Seals off lost-circulation or other troublesome formations prior to drilling deeper • Helps support the casing • Prevents casing corrosion Generally, 10 - 15 barrels of water is pumped into the hole before pumping cement slurry. The water acts as a flushing agent and provides a spacer between the drilling mud and the slurry. The water also helps to remove any remaining filter cake and flushes mud ahead of the cement, thereby lessening contamination. To prepare for cementing, the cementing head is installed on the top casing joint. A discharge line from the cementing pump is attached to the cementing head so that the slurry can be circulated. A bottom wiper plug is placed in the cementing head, followed by the top wiper plug. As the cement slurry from the pump discharge reaches the cementing head, the bottom plug travels down the casing ahead of the slurry. Once the calculated volume of cement has been pumped, a retainer pin is pulled to release the top wiper plug from the cementing head (A). The plugs and cement are pumped to the bottom of the casing by the mud/rig pumps. The bottom plug seats in the float collar (B). Mud continues to be pumped in order to displace the cement, which passes through the open valve in the float collar, out the guide shoe and into the annulus. Meanwhile, the casing is reciprocated and/or rotated to help displace the mud. Again, it is important to monitor pit levels through this operation to ensure that the much denser cement slurry is not being lost to the formation (i.e. pit level should remain level as displacement is taking place). When all of the cement has been displaced from inside the casing, the top plug seats (bumps) on top of the bottom plug held in the float collar (C). At this point, the pump pressure increases immediately since no mud can get past the solid top plug (i.e. mud is being pumped into a closed space). The pump is then



82

immediately shut down and the pressure is bled off. With the pressure released from the casing, the valve in the float collar closes to keep cement from backing up in the casing. It is important to release the pressure on the casing before the cement sets, as such pressure will cause the casing to bulge. If the cement is allowed to set, then the casing will pull away from the hardened cement when the pressure is released, thereby loosening the bond. Cement should be displaced quickly to create turbulence in the annulus and to remove the maximum amount of mud cake as possible. However, excessive pressure on the casing and surface connection can cause a rupture, excessive flow (or pressure) in the annulus can lead to formation breakdown and result in lost circulation, and excessive flow in the annulus can cause mud waste through overflow.

4.7.8 Other Applications • Secondary cementing operations are performed as part of well servicing and workover. • During cementing, the cement can fail to rise uniformly between the casing and the borehole wall,

leaving spaces devoid of cement. This is called cement channeling. Cement channeling can be rectified by performing a secondary cementing operation called a cement squeeze. Here, cement is pumped behind the casing under high pressure to re-cement channeled areas or to block off an uncemented formation. It can be performed to isolate a producing formation, seal off water or repair casing leaks.

• Secondary cementing can also be performed to plug-back a well to another producing formation

(and change testing zones), to plug a dry hole (and abandon the well), and to plug-back a hole in order to sidetrack.

A Pump cement and plugs

Bottom Plug

Cement

Top Plug

B Bottom plug seats in float

collar

C Cement is displaced until the plugs bump



83

4.8 Pressure Tests

4.8.1 Leak-Off and Formation Integrity Tests A Leak-Off Test (LOT) is performed to determine the integrity of a cement bond, and in doing so, determines the formation fracture pressure directly below the casing seat (i.e., in the first formation after the casing shoe). The zone directly beneath the casing seat is assumed to be the weakest point in the next hole section, since it is the shallowest depth. Therefore, LOTs are usually performed after the casing has been set and a small interval of the next section has been drilled. Before conducting an LOT, blowout preventers must be installed and the well must be closed-in. A small volume of mud is pumped slowly to gradually pressurize the casing; the surface pressure rises as this mud is pumped in. As pressure increases, if the cement bond holds, as is intended, then the formation will be first to fracture. As fracture commences, mud will start to leak into the formation, and the rate of pressure increase drops off. When a decrease in pressure is recorded, the test is complete. Three pressure stages are evident, and it is the operators decision as to which one will be taken as the pressure on which to base subsequent calculations: 1. Leak-Off Pressure, which is the pressure at which fluid first starts to inject into the formation at the

start of fracture. This will be seen as a slight drop in the rate that the pressure is increasing. At this point, the pump rate should be reduced.

2. Rupture Pressure, which is the maximum pressure the formation can sustain before irreversible

fracture occurs. This will be determined by a sharp drop in the pressure being applied, and pumping should be halted.

3. If no more pressure is applied at this point, most formations will recover to a certain degree, and the

Propogation Pressure is determined when the pressure becomes stable again.

Mud volume pumped / Time

Surface Pressure

2

1

3



84

The major disadvantage of the LOT is that the formation is actually being fractured and weakened during the test, and the risk is that it may be permanently weakened or that a fracture may be opened. The formation will generally recover to the propogation pressure, but in reality, this means that the fracture pressure has effectively been lowered, and the pressure capabilities for the next hole section have been lessened. When the formation at the casing shoe is fractured like this, there are two pressures acting on the formation causing the fracture, namely, the hydrostatic pressure due to the mud column and the pressure that is being applied from the surface. Therefore, Fracture Pressure = Mud Hydrostatic at shoe + Applied Surface (shut-in) Pressure The use of this type of LOT is typically restricted to wildcat wells, for example, in an area where little is known about the fracture gradient and expected formation pressures. Where offset data is available and fracture/formation pressures are known, a Formation (or Pressure) Integrity Test (FIT or PIT) is typically performed. This test is carried out in the same way as a leak-off test, but the expected pressures and required maximum are known, so a predetermined surface pressure can be applied and held. This predetermined pressure is gauged from offset well data and is determined so as to be sufficient for the largest pressure anticipated during the next hole section. There is a built-in safety margin in performing a FIT since the formation is not actually fractured during the test.

4.8.2 Repeat Formation Testing Repeat formation testing, or wireline formation testing, is a quick and inexpensive way to sample formation fluids and measure hydrostatic and flow pressure at specific depths. Repeat formation testing provides the information required to predict formation productivity and to plan more sophisticated formation tests, such as drill stem tests. Repeat formation tests can be run in open holes or cased holes (i.e., through perforated production liners), and multiple tests can be performed during one trip in the hole. A spring mechanism in the RFT tool holds a pad firmly against the sidewall to form a hydraulic seal from drilling mud in the wellbore, and a piston creates a vacuum in a test chamber. Formation fluids enter the tool chamber through an open valve. The initial shut-in pressure is registered. The test chamber valve is then opened to allow the formation fluids to flow into it. A recorder logs the rate at which the test chamber is filled, then the final shut-in pressure is recorded. Because test chambers can hold only a minute amount of formation fluids, a second sample chamber can be opened to draw more formation fluids.



85

4.8.3 Drill Stem Testing Drill stem testing is conducted to record formation pressures and flow rates over large intervals of interest, and to gather formation fluid samples in order to determine the potential productivity of a reservoir formation. Drill stem tests can be run in open holes or cased holes (i.e., through production liners which can be perforated to allow formation fluids to flow into the annulus). Bottom hole Drill Stem Tests are performed with a single packer that is set above the formation of interest. This will isolate the zone between the packer and the bottom of the hole. This type of test minimizes the formation's exposure time to drilling fluid (because only one test can be run) and, therefore, the potential for formation damage. Straddle Drill Stem Tests, with dual packers, allow zones further up the hole to be tested. One set of packers is set above the formation of interest, and the other below, thereby straddling the formation and isolating it for testing. This type of test offers the advantage that multiple tests can be run on the same trip into the hole and reducing costs. However, there is greater potential for formation damage due to extended exposure to drilling fluid during multiple tests. Tools employed in drill stem tests include the following: - Packers are expandable rubber sleeves that are used to isolate the formation of interest.

When they expand, they form a seal against the wellbore wall, which prevents formation fluids from flowing through the annulus.

Perforated Pipe allows the formation fluid to enter the drill stem during the flow periods of the

test and flow to the surface where they can be collected, stored or burned off. Shut-in Valve controls the flow of fluid into the drill stem over a series of open-flow and shut-

in periods. When closed, the shut-in valve stops the flow of formation fluid. When open, the shut-in valve allows the formation fluid to flow.

Outside Recorder is set close to the perforated interval, with the pressure sensor on the outside of

the drill string between the upper and lower packer. It measures pressure changes in the formation of interest during the test period, and provides the most accurate indication of reservoir pressure.

Inside Recorder is set inside the DST assembly in order to measure the pressure of fluid entering

through the perforated interval into the DST tool. The fluid recorder, or flow recorder, is set above the shut-in valve, with the pressure sensor inside the drill string, and measures the hydrostatic pressure of the fluid recovery. A fourth, optional, recorder (called a below straddle recorder) is set below the bottom packer on straddle tests to measure how well the bottom packer seat holds.



86

Performing a Drill Stem Test Drilling mud is circulated and conditioned to ensure that the hole is clean and to reduce the possibility of cuttings or other debris damaging the DST tool. The DST tool is typically run into position on drill pipe. A cushion of water or compressed gas may be placed in the drill stem to support the drill stem against mud pressure until the test starts. When the DST tool is in place, the packer is set to form a seal (usually by applying weight on the packer) and the shut-in valve is opened. The cushion, if any, is bled off slowly to allow formation fluids to flow gradually into the drill stem and prevent formation damage caused by an abrupt flow. The wellbore is monitored throughout the DST for pressure changes that warn of poor packer seating. Most DSTs encompass two (and sometimes three) flow and shut-in periods. The first flow and shut-in period, which is the shortest, clears out any pressure pockets in the wellbore and removes mud from the drill stem. The second and third flow and shut-in periods run longer than the first. The purpose of the flow periods is to monitor the flow rate and changes in pressure. The shut-in periods serve to record formation pressure.

where: i = initial HP = Hydrostatic Pressure PFP = Pre-Flow Pressure f = final SIP = Shut-In Pressure FP = Flow Pressure

When the DST is complete, the shut-in valve is closed to trap a fresh, clean sample of formation fluid and the DST tool is unseated. Formation fluid is reverse-circulated out of the drill stem to prevent spillage while tripping out. The drill string and DST tool are carefully tripped out of the hole, and the fluid sample and graphs are retrieved. Information obtained in performing a DST includes reservoir pressure, permeability, pressure depletion rates (volume and production rate) and gas, oil and water contacts. The saved sample provides valuable information on fluid saturation, viscosity, contaminants and harmful gases.

Final Shut-in Period

Main Flow Period

Initial Shut-In Period

Time

Pressure

iHP

fPFP

fHP

iFP

fFP

iPFP

iSIPfSIP



87

5 DEVIATION CONTROL A large proportion of wells are drilled from a location directly above the target reservoir. Therefore, in order for a well to successfully reach the target, it must be drilled vertically, or very close to vertically. In practice, there are many factors which make it very difficult to maintain a perfectly vertical well. A small degree of departure is normally acceptable, but obviously, the further the well deviates from the planned trajectory, the more chance there is of the well missing the target zone. This is a time-consuming and costly error since the well will either require expensive downhole tools to steer it back to its original course, or it will have to be re-drilled to hit the target. Formation considerations such as hardness, structure and dip, are obvious factors in a well drifting off course. So too, are bottom hole assembly design (collars, stabilizers) and the weight applied to the bit. The more the applied weight, the more the drill string is inclined to bend, directing the bit away from the vertical. Softer formations, typically, result in fewer deviation problems since less weight is applied and the string will "hang" vertically under its own weight. 5.1 Common Causes of Deviation

5.1.1 Interbedded Lithology / Drillability

Interbedded lithology (i.e., alternating hard and soft formations) makes it difficult to maintain hole angle because hard and soft formations have different drillabilities, causing the bit to deflect off-course (similar to light deflecting when passing from air to water).

Associated problems with alternating lithologies are the formation of ledges in hard formations and washed out sections in weaker formations.

5.1.2 Formation Dip

Formation dip (i.e., the angle at which a formation's surface inclines away from the horizontal) can cause a hole to deviate. In high-dipping formations, bedding planes and boundaries provide a natural, and easier, course for the bit to follow, so that it tends to drift down dip.

With shallower-dipping formations, the bit tends to drift in the up-dip direction.



88

5.1.3 Faults Drilling through faults (i.e., a break in the formation where rock on one side of the break is displaced upward, downward or laterally relative to the rock on the other side) may cause a hole to deviate from vertical.

This may result from rocks of different drillabilities being juxtaposed, or from the fault plane itself since coarse brecciated material, or gauge, may deflect the bit from its original course.

5.1.4 Poor Drilling Practices

Excessive weight on bit accentuates a bit's tendency to drift. Applying more weight on bit may compensate for using a wrong bit, a worn bit or bit balling, in terms of maintaining penetration rate, but the increased weight may cause the bit to drift off-course, as a result of the drill string bending and re-directing the bit.

Excessive clearance between undersized drill collars and the borehole wall makes it possible for the bit to move laterally. Such movement can be prevented using stabilizers and full gauge tools (i.e., the same diameter as the hole) that stabilize the string and keep it centralized. If the bottom hole assembly is not stabilized, the bit is more easily deflected, thereby creating a deviated hole. The more rigid the bottom hole assembly, the more likely a vertical path can be maintained. The less rigid the bottom hole assembly, then excessive weight may cause the pipe to bend, deflecting the bit.

Rotating the drill pipe off bottom for extended periods of time may also cause hole deviation, since sections of the hole may become enlarged, allowing the bit to follow another path.



89

5.2 Problems Associated with Deviation Obviously, the most critical problem associated with deviation is missing the target zone, but many drilling and operational problems may result that, ultimately, lead to a higher cost of drilling the well due to the extra time required to correct the problem.

5.2.1 Doglegs and Keyseats

Hole deviation is expressed in terms of the angle of inclination away from the vertical. Whenever there is a change in direction, a dogleg results. A dogleg is a "bend" in the wellbore that creates an unnatural course for the drill string to follow. The rate at which the hole angle changes is therefore more important in determining the severity of a dogleg.

Doglegs can be identified by regular hole-deviation surveys and by extra torque and weight requirements caused by the restriction of pipe movement.

If left uncorrected, doglegs can lead to further hole problems such as the formation of keyseats and ledges, which in turn can result in more severe problems such as stuck pipe and pipe failure.

Where a dogleg is severe and uncorrected, a keyseat may develop. Drill pipe is in tension and will try to straighten when passing through a dogleg. This results in a lateral force on the drill pipe that forces it into the wellbore wall. Rotation of the drill string, under tension, will result in a groove being cut into the formation. The picture shown above illustrates the formation of a keyeat.



90

When the drill string is subsequently pulled from the hole, drill collars will not pass through the groove and the drill string will become stuck.

A keyseat will, typically, only form in soft to medium-hard formations, and the speed at which a keyseat forms depends upon the severity of the dogleg and the lateral force acting on the drill pipe. This lateral force is directly related to the weight of the drill string below the dogleg.

5.2.2 Ledges

Ledges may result from a succession of micro doglegs that form when drilling through interbedded hard and soft formation. The soft formations wash out, whereas the hard formations remain in gauge.

This, again, creates an irregular path for the drill string to pass through and may result in full-gauge tools, such as stabilizers, becoming stuck under the ledges when the drill string is pulled from the hole.

A number of problems can result if doglegs, keyseats and ledges are present in the wellbore.

5.2.3 Stuck Pipe Drillstrings, casing, even wireline tools, are all subject to potential sticking through these geometric causes: -

• Stiff assemblies are not able to bend through a dogleg.

• Drill collars can become stuck beneath a keyseat, while stabilizers and large tool joints can become stuck beneath ledges.

• As well, there is increased sloughing of the hole when wearing a dogleg or keyseat, with falling

material leading to a danger of pack-off around collars and tools.

• Casing may become stuck when attempting to pass through a dogleg.

• Logging tools may also become stuck beneath keyseats or ledges.

5.2.4 Increased Torque/Drag and Drill Pipe Fatigue • There is increased stress when pulling the drill pipe through the restrictions.

• Where the drill pipe is forced into the wall of a dogleg, the stress is greater on the outside of the

pipe bend than on the inner bend. As the pipe is rotated, each "part" of the pipe is alternating between minimum and maximum tension, cause fatigue failure.



91

• When drilling a deviated hole, the drill pipe rides on the borehole wall which causes additional friction from the increased contact area. As the hole angle increases, more torque is required to rotate the pipe in order to overcome the resistance. When the pipe is being pulled, increased overpull is required to lift the pipe and overcome the drag of the pipe.

5.2.5 Casing and Cementing

• As well as the potential of sticking, casing may be damaged and weakened on passing through a dogleg.

• Where casing is tight against the wall of a bend, cement will not be able to circulate between the

casing and wellbore wall, thereby preventing a good bond.

• Once set, the inside of the casing may become worn when drilling/tripping proceeds, since the drill pipe will again be forced against the inside bend.



92

5.3 Prevention of Deviation

5.3.1 Pendulum Effect The pendulum effect is the tendency of the drill string to hang in a vertical position due to the force of gravity. If the hole deviates from the vertical, the bit and the drill collar lie on the low side of the hole and seek to return to vertical unless an opposing force prevents them from doing so. Three forces are at work on the bottom of the drill string to restore the pendulum to a vertical position: • The pendulum force supplied by the weight of the drill

collars between the bit and the first point of contact with the borehole wall, called the point of tangency. The higher the point of tangency, the longer the pendulum and the greater the tendency of the drill string to return to vertical.

• The axial load supplied by the weight of the drill

collars, which affects the pendulum force. A greater load will cause the bottom of the string to bend closer to the bit. The point of tangency will be lower, and the pendulum force will be reduced.

• The formation resistance to the pendulum force and the

axial load. The formation resistance is a combination of two forces – one parallel to the hole axis and another perpendicular to the hole axis).

When equilibrium exists (i.e., the pendulum force equals the formation resistance), the hole will drill straight, though inclined. If the pendulum force is greater, the hole angle will decrease. If the formation resistance is greater, the hole angle will increase.

5.3.2 Pendulum Assembly

Working on the pendulum effect principal, the pendulum assembly is typically used for drilling soft, unconsolidated formations in the surface hole when fast penetration rates can be maintained while running a lighter bit weight. It can also be used as a corrective measure to reduce angle when deviation exceeds the set maximum. When the pendulum assembly is composed of just bit and drill collars, it is typically known as a slick assembly.

Pendulum

Pendulum Force

Formation Resistance to Pendulum Force

Point of Tangency

Formation Resistance to Axial Load

Axial Load



93

The assembly may also include one or more stabilizers installed in the drill string. For maximum pendulum force, one stabilizer is positioned as high as possible above the bit without allowing the drill collars between the stabilizer and the bit to touch the borehole wall. This stabilizer controls deviation. A second stabilizer can be added higher up the drill string to reduce lateral force on the first stabilizer and prevent it from digging into the borehole wall.

Use of a pendulum assembly does not guarantee prevention of doglegs. Even when there is equilibrium, the pendulum assembly is free to move from side to side in a washed-out, soft formation until lateral movement is stopped by the drill collars when they come in contact with the borehole wall.

5.3.3 Packed-Hole Assembly

Wells are commonly drilled with some type of packed-hole assembly, because it allows maximum weight to be applied to the bit for faster penetration. A properly designed packed-hole assembly has several benefits: - • Reduces the rate of hole angle change

(thereby preventing doglegs) • Improves bit performance and bit life (by

forcing it to rotate on its true axis) • Improves hole conditions for drilling,

logging and running casing • Allows more drilling weight to be applied

when drilling crooked-hole formations (i.e., formations known to cause deviation problems).

Characteristics of the packed-hole assembly include: • Three-point stabilizer placement to ensure that a straight course is maintained by the bit. • Stiffness in the assembly is provided by using drill collars of maximum possible diameter. • Sufficient stabilizer blade contact with the wellbore wall, to ensure that the bit and collars are

centralized, yet preventing wall erosion.

Severe Medium Mild

Stab

Stab

Stab

Stab

Stab

Stab

Stab

Stab/Reamer Stab

2 Stabs



94

The number of stabilizers used, and their placement in the bottom hole assembly, depends on the severity of the crooked-hole tendencies of the formation. As crooked-hole tendencies become more severe, additional stabilizers are required directly above the bit to prevent bit deviation. Typical packed-hole assemblies, for varying severity in crooked-hole condition, are illustrated in the diagram above.

5.3.4 Packed Pendulum Assembly Packed-hole assemblies are used to minimize the rate of hole angle change, although there will always, likely, be some amount of deviation. Pendulum assemblies are used to reduce total hole angle. If total hole deviation must be reduced and a packed-hole assembly will be required after reducing hole angle, the packed pendulum assembly should be used. In the packed pendulum assembly, pendulum-length collars are placed below the regular packed-hole assembly. When hole deviation has dropped to the required angle, the pendulum collars can be replaced by the original packed-hole assembly again. Only the length of the pendulum collars needs to be reamed prior to resuming normal drilling. If a vibration dampening device is used in the packed pendulum assembly, it should remain in its original "packed-hole" assembly position, typically above the middle stabilizer point.

5.3.5 Stabilizers and Reamers

Stabilizers are used to stabilize the bit and the drill collars in the hole. When properly stabilized, optimum drilling weight can be applied to the bit, thereby forcing it to rotate on its true axis and drill straight ahead without sudden angle changes. Fewer bits will be used and the rate of penetration will increase. Stabilizer blades should be as close to bit size as possible. Drilling hard formations requires more durable stabilizers, and only a small wall contact area is necessary. A larger wall contact area is required for softer formations and for severe crooked-hole formations. The tungsten carbide blades may be short or long (i.e., small or larger contact area) and either straight or spiral. Blades are typically welded or integral, rotating with the drill string. A non-rotating rubber sleeve stabilizer is often used for its advantage of not cutting into and damaging formations, but it has a short life and no reaming capability.

Roller reamers are used primarily for maintaining hole gauge in very hard formations. Set behind the bit, reamers effectively "re-drill" the formation to maintain hole diameter, extend bit life and prevent



95

problems with sticking. They are also used for additional stabilization in hard formations. However, their limited wall contact area prohibits them from being highly effective stabilizers in most instances and, in soft formations, reamer cutters penetrate the borehole wall which reduces stabilization and can increase bit deviation. Reamers are run between the bit and the drill collars, and should be as close to bit size as possible. Reamer cutters must be selected to match the formation being drilled.

5.3.6 Drilling Procedures If deviation is a problem, or if a deviated well is being drilled, further practices in addition to the make-up of the bottom hole assembly can be adopted.

• Perform regular wiper trips, with keyseat wipers to open up developing keyseats. • Ream back to bottom on bit trips to eliminate or minimize the severity of doglegs and developing

keyseats. • Avoid sharp changes in bit weight, which, due to the variable bend in the drill pipe, can result in

doglegs. If weight needs to be reduced to straighten a hole, the reduction should be gradual to prevent a sudden change in direction.

• Conduct regular surveys to monitor the rate of change in angle and occurrence of doglegs.



96

6 DIRECTIONAL AND HORIZONTAL DRILLING 6.1 Reasons for Directional Drilling Directional drilling is the intentional deviation of a wellbore from vertical. Though wellbores are normally drilled vertically, it is sometimes necessary or advantageous to drill the wellbore at an angle from vertical. Recent technological developments have made this an important component of modern drilling, enabling inaccessible resources to be successfully exploited from a given horizontal and vertical distance away from the rig location. Missed Target If the target is going to be missed with the current well path, directional drilling serves to redirect the borehole to the productive formation.

Sidetracking and Straightening Directional drilling can be performed as a remedial operation, either to sidetrack an obstruction (e.g., lost pipe and tools, cemented or plugged-back well) by deviating the wellbore around the obstruction, or to bring the wellbore back to vertical by straightening out crooked holes.

Structural Dip

If the formation structure and dip are going to make it very difficult to maintain a vertical well, it may be quicker (and cheaper) to offset the rig and allow the well to drift naturally towards the target. The borehole can then be steered, or directed, at the latter stages of the well in order to reach the target.

Fault Drilling

Directional drilling can be used to deflect the borehole and eliminate the hazard of drilling a vertical well through a steeply inclined fault plane which could slip and shear the casing.

Enter Target Formation at a Particular Point or Angle

Directional drilling makes it possible to penetrate the target at a particular point or angle, thereby opening up the maximum amount of the reservoir.

Reach Inaccessible Location

Remote rig location, together with directional drilling, makes it possible to reach an otherwise inaccessible location in a producing formation (such as below a municipality, mountainous terrain or swamp land, or when land access is denied).

Drill Out Under Water



97

When a productive formation lies under water, directional drilling allows the borehole to be drilled out under water from land. Even though directional drilling is expensive, this would lower the cost of the well since offshore drilling is very expensive.

Offshore Drilling

Directional drilling is commonly used in offshore drilling because a number of wells can be drilled from a single platform. This simplifies production techniques and gathering systems, two major factors governing the economic feasibility of offshore drilling programs.

Salt Dome Drilling

Directional drilling is also used to overcome the problems of salt dome drilling in order to reach the productive formation which often lies underneath the overhanging cap of the dome.

Relief Wells

Relief wells was the first application of directional drilling, and is still used today. Relief wells are drilled nearby and deflected into a well that is out of control, making it possible to bring the wild well, or gusher, under control.



98

6.2 Surveys/Calculations

6.2.1 Survey Methods

Single-Shot Surveys

A single-shot survey recording provides a single record of the drift angle, or inclination, and (compass) direction of the hole. The single-shot survey instrument is run, on wireline, down through the drill pipe during a temporary halt to drilling operations. A photograph is taken of a compass reading, the drift direction and the number of degrees the hole is off vertical at the current depth. The tool is pulled back to surface and the picture retrieved. Using this information and allowing for declination (i.e., the difference between magnetic and true North), the amount of drill string rotation required to position the face of the deflection tool in the desired direction can be determined. The information from successive surveys makes it possible to determine well trajectory, deviation and doglegs.

Multi-Shot Surveys

A multi-shot survey is normally run before each deviated hole section is cased. The multi-shot survey instrument is also run on wireline, down through the drill pipe, and landed inside a non-magnetic drill collar. Photographs of the compass reading are taken at regular time intervals as both the pipe and survey instrument are pulled from the hole. The time and depth of each photograph are manually recorded at the surface and this information is used to analyze the survey film, which provides multiple readings of drift angle and direction.

Gyroscopic Surveys A gyroscopic survey is used to record single or multi-shot surveys in cased holes. The gyroscope's pointer is set towards a known direction and all hole directions are referenced from this known direction. Unlike magnetic surveying instruments, the gyroscope reads true direction and is not affected by magnetic irregularities that may be caused by casing or other ferrous metals.

Measurement While Drilling (MWD)

Downhole motors are typically used to kick off a directional hole or when major directional adjustments are required. Measurement while drilling can be performed to obtain a rapid recording of drift angle and direction of the hole.



99

The drill pipe is held stationary, so that the measured depth of the tool is known. The tool is triggered by pressure changes as the pumps are turned on and off, and the survey data is recorded at the surface. This is much quicker than halting operations and running a single-shot survey tool on wireline and, therefore, can be done regularly, typically after every joint has been drilled.

6.2.2 Survey Measurements Most directional information is derived from two simple measurements: -

Azimuth The direction of the wellbore at the given survey point, in degrees (0°-359°) clockwise from true North.

Inclination Also known as drift angle or angle of deviation. Expressed in degrees, it is the

angle at which the wellbore deviates from the vertical at the given survey point. Using the survey results (i.e., azimuth and inclination) together with the measured depth (i.e., from the pipe tally), it is possible to determine true vertical depth, build angle, dogleg severity and closure. For information on these terms, see the section on Terminology.

Dogleg severity considers the average hole angle, the inclination and directional variation over

the course length. It is typically expressed in terms of degrees/100 feet (of drilled length).

Being a result of both inclination and directional change, dogleg severity will increase, for a given directional change, as inclination increases. To avoid severe doglegs, it is therefore advisable to alter inclination and direction independently of each other if possible.

6.2.3 Survey Calculation Methods Two methods, Radius of Curvature and Minimum Curvature, are accepted as being the most accurate survey calculation methods and are typically used throughout the industry. Both assume that a smooth curve, or arc, is produced between successive survey points and both require the use of a computer for efficient application at the well site.

Radius of Curvature

The Radius of Curvature calculation method assumes that the well path, between successive survey points, is that of a smooth curve describing the segment of a sphere. The exact dimensions of the sphere are determined by the directional vectors (i.e., survey points) and the distance between the survey points (i.e., course length).



100

This method, as with the Minimum Curvature method, is subject to error with increased course lengths and with the occurrence of severe doglegs between survey points. However, the degree of error, for both methods, is far less than that resulting from other calculation methods such as the Tangential or Balanced Tangential.

Minimum Curvature For a given interval, or course length, the Minimum Curvature calculation method takes the inclination (I) and direction (A) measurements for the survey points bounding the interval. From these starting points, this method then produces a smooth arc of minimum curvature to determine the wellbore projectory between the two survey points. The circular arc is defined by a ratio factor (RF) determined from the dogleg (DL) and is produced as a result of minimizing the total curvature between the constraints given by the survey points.

I2

I1

A1

DL

A2

N N

S

EW

RF = (360/(πDL))*(1- cosDL)/sinDL ∆TVD = (∆MD/2)(cosI1 + cos I2)*RF ∆North = (∆MD/2)(sinA1 + sinA2)*RF ∆East = (∆MD/2)(sinI1sinA1 + sinI2sinA2)*RF



101

6.2.4 Directional Drilling Terminology Angle of Build The degree of change of inclination, expressed in degrees over a specified

distance (e.g., 2°/100 feet). Azimuth The current direction of the wellbore at the survey depth, expressed in degrees

(0°-359°) clockwise from true North. Bottom hole Location The true vertical depth and closure at total depth. Build Section The interval over which the desired hole angle is built. Closure The horizontal distance and direction to any specified point in the hole (e.g.,

3000 ft N60°E). Note that at the bottom of the hole, this equates to the departure and drift direction.

Constant Angle Section The interval over which the desired hole angle is maintained constant. Course Length The measured length between successive survey points. Declination The difference between true North and magnetic North. Departure The horizontal distance the wellbore deviates from the vertical reference point.

Dogleg Severity Describes the average hole angle, the inclination and directional variation over

the course length, expressed in degrees/100 ft (of drilled length). Drift Direction The overall direction of the wellbore, relative to the reference point, from North.

Inclination The angle at which a wellbore deviates from the vertical, expressed in degrees. Kick Off Point The depth the deviated hole starts taking the well path away from the vertical.

Measured Depth The total length of the wellbore.

Monels Monel steel is a nickel-base alloy containing copper, iron, manganese, silicon

and carbon, often used in nonmagnetic drill collars (NMDC).

Target The planned point at which the productive formation will be penetrated.

Total Depth The maximum depth reached by the wellbore. True Vertical Depth The depth of the wellbore measured from the surface straight down to the bottom

of the hole. The true vertical depth of the wellbore will always be smaller than the measured depth in directionally drilled wellbores.

Wellhead The normal reference point, at surface, for departure and drift direction.



102

Schematic of Directional Drilling Terminology

Drift direction attotal depth

Azimuth

Wellhead

Survey Pt A

PlanView

Closure angle and distanceat Survey Point B

Departure distanceat total depth

N B

Target Radiusvertical

InclinationConstant Angle Section

Build SectionTrueVerticalDepth

Vertical Section

Kick Off Point

Survey Pt A

VerticalProfile



103

6.3 Drilling Techniques

6.3.1 Well Profiles There are three primary directional drilling profiles that may be pre-planned for a well's course. Note that in the case of course corrections, there could be many variations from the planned profile.

Shallow Deflection Profile The shallow deflection profile is characterized by initial deflection at a shallow depth. When the desired inclination and azimuth is achieved, the hole is cased to protect the build-up section. The hole angle is then maintained in order to reach the target. This profile is used primarily for moderate-depth drilling where no intermediate casing is required. It is also used to drill deeper wells requiring a larger lateral displacement. Most directional wells are planned with this profile.

S-Curve Profile

The S-curve profile is also characterized by initial deflection at a shallow depth with casing isolating the build-up section. The angle of deviation is maintained until most of the desired lateral displacement has been drilled. The hole angle is then reduced and/or returned to vertical in order to reach the target. Intermediate casing may often be set when the final reduction in angle has been achieved.

Deep Deflection Profile

The deep deflection profile is characterized by initial deflection well below the surface casing, and the hole angle is then maintained in order to reach the target.



104

6.3.2 Drilling Stages There are four main stages to consider in drilling a directional well. Kick Off This is point at which the wellbore is first taken away from the

vertical. It can be achieved through various techniques such as the use of jetting, whipstocks, motors and bent subs.

Build Section Following on from kick off, the inclination of the wellbore is

increased to the desired deflection angle. This is typically achieved through the use of motors and/or bent subs.

It is very important that severe angle changes and the creation of doglegs are avoided.

Further control on the angle change can be obtained through the use of stiff drill collars, the diameter, position and spacing of stabilizers, and the control of drilling parameters (WOB and RPM).

Constant Angle Section Once the desired deflection angle has been achieved in the build

section, constant trajectory must be maintained to take the wellbore to the target.

Stiff assemblies are used to continue drilling along the same trajectory, "locking" the course and achieving optimum penetration rate.

Dropping Angle This may be required if the wellbore is heading over the top of

the target.

Reducing angle can be achieved by varying the position of stabilizers (fulcrum) and the stiffness of the assembly, allowing the pendulum effect to drop angle. Reducing the weight on bit also helps to reduce angle.

A steering assembly, using a motor, may have to be used for final course corrections to ensure that the target is successfully reached.



105

6.3.3 Whipstocks, Motors and Techniques Achieving kick off can be achieved by a number of different techniques: -.

Whipstocks Whipstocking is the oldest method, typically used when jetting, but largely replaced by the use of downhole motors, which provide better dogleg control and maintain a full-gauge hole. The standard removable whipstock is used to initiate the deflection and direction of the well, sidetrack cement plugs and straighten crooked holes. It consists of a long inverted steel wedge that is concave on one side to hold and guide the whipstock drilling assembly. It also has a chisel point at the bottom to prevent the tool from turning, and a heavy collar at the top to help withdraw the tool from the hole. The circulating whipstock is run, set and drilled in a manner similar to the standard whipstock. However, drilling fluids are prevented from flowing through the bit and diverted to flow through the bottom of the whipstock. This allows the bridge formed to be washed through and to more effectively circulate the cuttings out of the hole, ensuring a clean bottom hole. The permanent-casing whipstock is designed to remain in the well permanently. It is mostly used to bypass collapsed casing or junk in the hole, or to reenter existing wells.

Downhole Motors and Bent Subs The downhole motor, with a bent sub, is the most widely used deflection tool. It is driven by drilling mud flowing down the drillstring to produce rotary power downhole, thus eliminating the need for rotating the drill stem from the surface. With no drill string rotation, the well will be deviated in the direction of the oriented bent sub.

The turbine is one type of downhole motor. It's stationary stator deflects the flow of drilling fluid to the rotor which is locked to the drive shaft and thus transmits the rotary action to the bit. Turbines are generally higher speed, lower torque motors as compared to positive displacement motors. A screen is placed between the kelly and the drill pipe to prevent foreign material from being pumped through the turbine and causing motor damage or failure. The turbine should not be used if lost circulation material is added to the mud system, since the screen cannot be used.

The positive displacement motor (PDM) operates similarly to the turbine, but runs at a lower RPM for a given mud volume, and is more commonly used. Its rotor is

motor

bent sub



106

displaced and turned by the pressure of the drilling fluid column, which powers the drive shaft and generates the rotational force that turns the bit. A positive displacement motor can be used if lost circulation material is added to the mud system. The bent sub is used to impart a constant deflection to the bit. It is a short, cylindrical device installed between the bottom drill collar and the downhole motor. The hydraulic bent sub can be locked into position for straight drilling, or unlocked and reset for directional drilling, when the bit will follow the orientation of the sub in a continuous, smooth arc. The rotation generated by the motors is determined by the circulating flow rate. For example, if one rotation is achieved for every eight litres of fluid passing through the motor, a flow rate of 1.6 m3/min. (1600 litres) will produce an RPM of 200.

Rotating and Sliding

A combination of sliding (i.e., bit rotation by downhole motor only) and rotating (i.e., additional surface rotation) can be used to deflect the hole. When sliding, with rotation only supplied by the motor, penetration rates are typically slower, increasing cost. If the well path is as desired, rotation can also be supplied from the surface, providing faster penetration rates. Additional rotation often has the effect of reducing build angle.

Jetting Jetting is an effective method of deviating holes in soft formations. An angle building assembly and jet deflection bit are run to the bottom of the hole and oriented in the desired direction. Typically, all but one of the nozzles will be blocked off or substantially reduced in size. Circulating drilling fluid, on exiting the bit, is therefore directed, predominantly, in one direction. With applied weight on bit and high-rate circulation, the fluid jetted from the large/open nozzle erodes one side of the hole so that the hole is deflected away from vertical. A problem associated with this procedure is the creation of doglegs. This should be determined before drilling ahead, with severe doglegs removed by reaming.



107

6.4 Horizontal Drilling There are many reasons to drill horizontally through a reservoir, principally due to formation characteristics and in order to maximize production. • Produce from thin formations, which are uneconomical to produce with vertical wells. A horizontal

well will have an increased area of contact with the reservoir, thereby increasing the productivity index.

• Produce from reservoirs where vertical permeability exceeds horizontal permeability. • Provide more formation and reservoir information over the extent of a reservoir. • Access isolated zones within irregular reservoirs. • Penetrate vertical fractures. • Increase production from low-pressure or tight reservoirs. • Limit contamination from unwanted fluids by keeping the well profile in the oil zone, above the

oil/water contact. • Delay the onset of water or gas production since a horizontal well will create a lower pressure

gradient and drawdown when producing. • Reduce the number of wells required to develop a reservoir. A number of horizontal "drain holes" can

be drilled from one vertical well. A large number of singular, vertical wells would be required to "open up" the same area of reservoir.

6.4.1 Classification Many definitions have been given to determine what classifies as a horizontal well and to describe the well profile. Here, we will distinguish a horizontal well as being greater than 86° inclination from the vertical, as opposed to a highly deviated well of over 80°. Horizontal wells can also be characterized by the rate of build over the build section of the well (radius), the resulting length of the build section (horizontal distance over which the well is taken from a vertical to horizontal trajectory), or even the length of the horizontal section (reach). However, as technology and experience in horizontal drilling improve, these categories tend to change over relatively short periods of time. The diagram below illustrates the concept of short, medium and long radius wells.



108

Short-radius wells obviously achieve the horizontal profile over a very short distance and will typically be used where the operator has acreage limitations to the length of the well drilled. A typical value may be a radius of less than 60 feet (18m) produced by a build rate of between 1°-4° per foot. Angled knuckle joints are used to achieve this type of build, but obviously, the more severe the build, then the shorter the horizontal section will be.

Medium-radius wells (e.g. build rate 8°-20°/100 feet, radius of 100-200m) can be steered with motors but, typically, have the limitation that the drill string cannot be effectively rotated through the build section.

Long-radius wells are used when a much longer horizontal section is required and where the operator has the necessary offset distance (wellhead to target) over which to build angle. Steering assemblies can be used and alternated with additional surface rotation to make course corrections in order to improve drilling rates. Long radius horizontal wells may have a build angle of as little as 1°/100 feet, and, today, extended reaches of several kilometers are possible.

6.4.2 Horizontal Drilling Considerations

Radius Effects Short and medium radius wells obviously require a shorter horizontal displacement and can, therefore, be drilled more quickly than long-radius wells. However, the inability to rotate in the build section, without exceeding the endurance limits of the drill string, restricts the flexibility of the wellbore profile and has a major impact on bottom hole assembly design, mud properties and hydraulics.

Reversed Drill String Design

The main considerations are: • Transmitting weight to the bit

• Reducing torque and drag

• Not exceeding stress limits, causing pipe failure.



109

Drill collars placed conventionally above the bit are only a disadvantage in horizontal sections since they will not add weight to the bit but will increase torque and drag. They are therefore placed in the vertical section of the well, providing the weight and reducing torque and drag. Heavy-weight drill pipe is typically used in the build section of the well since it is able to withstand the compressional forces and axial loading that would buckle conventional drill pipe. For the same reason, heavy-weight drill pipe is typically used for short horizontal sections since it is designed to withstand compressional forces and is able to transfer high weights through to the bit.

Drill pipe can withstand compressional forces in the horizontal section and can transmit weight to the bit without buckling (this would simply not be possible in a vertical well). This is due to the gravitational force, which pulls the drill pipe against the low side of the hole, providing support and stabilization. At the same time, torque and drag that would result from drill collars, is reduced.

Essentially then, this "reversed" profile maximizes weight in the vertical section, and minimizes weight in the horizontal section, thereby reducing torque and drag while still transmitting weight to the bit.

Drill Pipe Fatigue

Increased torque and drag requirements in horizontal drilling subject the drillstring to higher loads than would be present in vertical wells. Some of the main factors to consider are:

• Higher pick-up weights. • Higher torsional loads. • High tensional force on drill pipe in build sections.

• Rotating off bottom so that heavy-weight drill pipe in the build section is held in tension rather

than compression. • Severity of doglegs.

Hole Cleaning

Drilled cuttings will naturally tend to rest on the floor of the wellbore in horizontal sections, forming cuttings beds that will restrict pipe movement, thereby increasing drag and leading to stuck pipe.

Several steps can be taken to prevent this:

• High annular velocities, producing turbulent flow in the horizontal section (rig pumps must be able

to deliver the high flow rates in order to achieve this). • Efficient surface equipment to keep mud solids content to a minimum. • Typically high threshold but low yield-point mud.



110

• Circulating when tripping out of the hole.

Use of Top Drives

The use of top drives provides many advantages over conventional kelly systems in the drilling of horizontal wells:

The advantages of using a top drive include:

• Higher pick-up loads. • The ability to rotate while tripping, reducing load and hoisting requirements. • The ability to circulate while tripping out of the hole, improving hole cleaning. • The ability to ream in both directions.

Casing and Cementing The main considerations with respect to casing and cementing in horizontal drilling are: • Reduced capability to rotate and reciprocate the casing. • Severe doglegs and high drag may prevent casing from being run. • Effective centralization for the casing is required to achieve good overall annular bonding and to

prevent cement channeling. • The risk of poor mud displacement, leading to contamination of the cement.

Formation Considerations

The main formation considerations in horizontal drilling are: • The adverse affect on hole direction (i.e., causing unwanted deviation) caused by different

drillabilities, formation dip, etc. • Hole stability, with weak, unconsolidated formation falling into the hole • Reactive shales cause a significant problem in horizontal wells (conventional practices such as

high density muds, mud with low fluid loss; the use of oil-base mud; the use of top drives, all help to minimize this problem)

• Formation dip and strength in relation to wellbore trajectory.



111

Formation Evaluation

The main considerations with respect to formation evaluation in horizontal drilling are: • The use of MWD (so that non-magnetic drill collars are the only collars to be found in the

horizontal section) and LWD. • Wireline tools, obviously, cannot be run along a horizontal section. Typically they will be drill-

pipe conveyed. That is, they will be latched inside the drill string with the wire run through a "window". The drill string can then be run to the bottom of the hole with the wireline tools, then the well logged as stands are pulled from the hole.

Gas Behaviour/Well Control

The main considerations with respect to gas behaviour and well control in horizontal drilling are: • There will be no gas expansion until gas enters the vertical section; expansion and the resulting

kick, displacing mud at the surface, may then happen very rapidly. • Influxes of gas will migrate and accumulate in higher areas of the horizontal section (e.g., deviated

crests, washed out hole enlargements), requiring high annular velocities to displace, and slow pump rates once the gas is in the vertical section and subject to expansion.



112

7 DRILLING PROBLEMS 7.1 Formation Problems and Hole Stability

7.1.1 Fractures

While fractures can occur naturally in any formation, they are more common in harder, more consolidated formations, as well as in and around faulted areas or other areas subjected to natural forces and stress.

Fractures range from microscopic sizes to widths exceeding 1/8 inch (3mm), with well-ordered to random orientations. Older, harder formations at deeper depths tend to be more highly fractured than younger, softer formations at shallower depths.

Associated Problems

Lost Circulation Lost circulation below the surface casing in normally pressured formations may be caused by naturally occurring fractures in formations with subnormal pore fluid pressure. If, as drilling proceeds, no drilling fluid or cuttings are returned to the surface, they are most likely being lost to the fractured zone. Sloughing, Increased Cuttings Formation particles in fractured formations have a tendency to fall into the hole, thereby increasing the volume of cuttings. The volume and size of formation particles that fall into the hole depends upon the hole size, hole inclination, angle of formation dip and extent of fracturing. Typically, they can be recognized as being larger than normal drilled cuttings. Hole fill (i.e., cuttings accumulating at the bottom of the hole), may be seen after connections. Inhibited Rotation, Sticking Pipe As the hole fills with an excessive volume of cuttings, rotation of the drill pipe is inhibited. If these cuttings are not removed from the hole and carried to the surface, the drill pipe can become stuck, thus stopping further rotation and blocking circulation (pack off). Enlarged Hole, Reduced Annular Velocity, Hole Cleaning Drilling through fractured, unstable formations invariably results in enlarged holes which, in turn causes reduced annular velocity and requires additional hole cleaning. Keyseating, Ledges, Deviation Fractured formations can create problem-causing ledges and, depending upon the hole inclination and deviation, the formation of keyseats. These can lead to subsequent problems of higher drag and pick-up weight, and sticking pipe.



113

Erratic Torque

Fractured cavings falling into the hole will act against the rotation of the drill pipe, leading to higher and erratic torque. In extreme cases, rotation my be completely stalled with the built-up torque in the drill string, presenting the danger of twisting off, or breaking, the pipe.

Drilling Fractured Formations

Control Rate of Penetration

The rate of penetration must be controlled when drilling fractured formations to minimize the volume of sloughing material.

Work and Clean Hole

As well, adequate time must be allowed for complete hole cleaning to remove the cuttings from the bottom of the hole. Good mud properties and viscous mud sweeps are important to keep the hole clean. Careful reaming during trips will help clean the fractured zone.

Increase Mud Weight

A good quality filter cake can provide support to some fractured zones, but in highly fractured formations where continuous, extra-heavy sloughing is encountered, increasing the mud weight can be effective in holding back sloughing and stabilizing the fractured formation.

Avoid Pressure Surges

Pressure surges can add to, or increase, fracturing. Therefore, it is important to slow tripping speeds when the bottom hole assembly passes through a fractured zone, and start and stop the pump slowly.

Dump Cement

Typically, fractured zones are likely to stabilize after a period of time. If, after taking all of the above measures, the hole still does not stabilize, a final recourse is the use of cement. Dumping cement can seal and stabilize the fractured formation, thereby preventing further problems.

7.1.2 Shales

Reactive Shales

Swelling (i.e., absorbing filtrate from drilling fluid) is typically a tendency of younger, shallower shales. As shales swell, they separate into small particles that may fall into the wellbore. This results in heaving (i.e., the partial or complete collapse of the wellbore walls) and causes tight hole conditions, increased pipe drag on connections, sticking pipe and the formation of ledges.



114

Selecting the appropriate drilling fluid will minimize shale reactivity and swelling. Mud inhibitors (such as salt or lime) and oil-based muds are the most effective drilling fluids for controlling swelling.

By increasing the rate of penetration, it is sometimes possible to drill through a sensitive shale section and complete operations before swelling and heaving occurs. However, fast drilling through a thick interval, without good hole cleaning, can result in severe hole stability problems.

Tight hole sections caused by swelling shales should be reamed and cleaned. Depending upon the sensitivity of the shales, it may be necessary to ream and clean more than once as drilling proceeds deeper. In order to prevent pipe from sticking, the upper hole should be clean and free of heaving before the bit is worked deeper into the problem shale section.

More sensitive shale sections require periodic wiper trips to ensure the hole is not closing around the drill pipe above the drill collars.

If severe shale problems persist, the hole may have to be cased off to prevent losing the hole. The standard practice is to condition the hole, pull out, run logs and then run the bit back to the bottom of the hole for a clean-out trip, ensuring that the hole is in a condition to allow casing to be run.

Overpressured Shales

Overpressured shales possess a higher than normal pore fluid pressure for the depth of their occurrence. Although there are many different mechanisms that can lead to this, it typically results from incomplete compaction and de-watering when formation fluids are "squeezed" from the formation due to the overlying overburden as the shale sediments are buried.

The shales therefore retain an abnormally large amount of formation fluid. The increased volume of fluid will support part of the overburden weight, normally supported by the rock matrix, resulting in a higher pore pressure. If this pressure exceeds the mud hydrostatic pressure, the fluid will try to escape from the shale. Since this is prevented by the shales impermeability, the higher pressure will cause fracturing of shale, allowing fragments (or cavings) to break away and fall into the borehole.

Caving shales will lead to hole fill (i.e., accumulated cavings at the bottom of the hole) after trips and connections.

Tight hole problems, due to pressure exerted by the shale and due to cavings falling in and around the drill string, lead to increased rotary torque while drilling, and increased overpull required to lift the pipe for connections and trips.

As the shale fractures and breaks away, gas will be released. An increase in the gas level, the presence of connection gas or the presence of gas-cut mud may therefore be an indication of overpressured shale and the requirement to increase the mud weight.

Increasing the mud weight is the most effective method of controlling undercompacted and overpressured shale sections.

NB Refer to Datalog’s ABNORMAL PRESSURE ANALYSIS manual for more information on occurrences, causes and detection of overpressured shales.



115

7.1.3 Surface Formations Drilling formations at shallower depths can result in a number of different problems and operational considerations. Surface formations are often loose and unconsolidated, therefore highly susceptible to caving and collapse. Gravel and boulders in conglomerate-type formations present hard obstacles against drilling and can often deflect the bit, creating deviation problems. Even without any associated problems, the large size of surface holes results in a large volume of cuttings that require very efficient hydraulics and surface equipment to lift and remove cuttings from the wellbore. As mentioned previously, shales at a shallow depth, especially in offshore basins, are particularly prone to swelling, creating an additional problem. Shallow gas-bearing formations are a further drilling hazard. Upon encountering shallow, pressured gas, there is very little warning before the gas reaches the surface. With deeper gas kicks, there is normally some delay between the time when mud is seen being displaced at the surface (i.e., flow and pit volume increase) and when the gas reaches the surface, allowing the well to be safely closed in and controlled. With shallow wells, typically light water-based systems are being used, providing very little balance against pressured gas which will expand and reach the surface very rapidly. This situation requires extreme vigilance from the drilling crew and mud loggers to avoid a very dangerous situation. Fresh-water reservoirs present a different kind of problem. With overpressured aquifers, we have the associated problem of kicks. However, reservoirs may also be underpressured with the associated problems of lost circulation. Equally important is the fact that these aquifers may be the water supply for a particular community, so, at all costs, must not be contaminated by the drilling operations. To prevent the drilling mud from invading the aquifer, the aquifer should be quickly cased off for protection against all subsequent drilling operations.

7.1.4 Salt Sections If salt sections are drilled using an incorrect drilling fluid (e.g., fresh-water mud), the salt will dissolve in the mud. This will result in washed-out sections where cuttings can accumulate and cause hole problems. Thus, a salt-saturated or oil-based mud must always be used to drill salt sections. Salt can be very mobile or plastic (i.e., behave much like a fluid) and build up pressure against the borehole and drill pipe. This in turn can cause stuck and damaged pipe. To prevent such problems, it is important to regularly work the drill pipe and circulate often when drilling salt sections. Higher mud weight will help in holding the salt back, but should the pipe become completely stuck, a common recourse is to spot fresh water in order to dissolve the salt and free the pipe.

7.1.5 Coal Beds Coal beds are generally fractured formations. As a result, sloughing and its associated problems are typically encountered when a coal bed is penetrated. The procedures for drilling a coal bed are the same as drilling a fractured formation (i.e., thorough hole cleaning and maintenance).



116

7.1.6 Anhydrite/Gypsum Formations Anhydrite, especially, and gypsum, create a major challenge for the mud engineer. They increase the viscosity and the gel strength of the mud. This alters the flow properties and hydraulics of the mud, leads to increased circulating, swab and surge pressures, and creates a handling problem at the surface in that the mud will "gum up" surface equipment.



117

7.2 Lost Circulation Lost circulation, the loss of drilling fluid to the formation, is one of the most critical problems that can be encountered in rotary drilling. A partial loss of drilling fluid to the formation does not have immediately serious consequences that will prevent drilling from continuing. However, the consequences become more severe if the rate of loss increases or if circulation is lost completely:

• Loss of hydrostatic head that may allow fluids to flow into the wellbore from other formations (underground blowout).

• Formation damage (i.e., loss of permeability as mud solids and possibly cuttings are deposited, which not only leads to the possibility of poor wireline data but may damage the production potential of a zone of interest).

• Increased costs as mud is lost and must be replaced and time is required to correct the product.

• Associated drilling problems.

7.2.1 Occurrences There are many situations, naturally occurring and/or drilling induced, that can lead to circulation being lost:

• Shallow, weak, unconsolidated sands.

• Naturally fractured or cavernous formations.

• Depleted reservoirs or sub-normally pressured formations where mud density exceeds formation pressure.

• Formations weakened or fractured by drilling operations (i.e., excessive mud densities and

circulating pressure, pressure surges or increases when running pipe in the hole or when shutting in the well).

7.2.2 Detection Warning of a potential lost circulation zone may be given by an increase in the rate of penetration. This may be due to a weaker, unconsolidated formation or an extremely porous or cavernous formation. Fractures can frequently be detected by a sudden increase in the rate of penetration, accompanied by higher, erratic torque.



118

Lost circulation will initially be detected by a reduction in the amount of mud flowing from the hole, along with a reduction in pressure. If the situation continues or worsens, the mud level in the suction pit will gradually fall as mud is lost. In the more severe scenario, there will be a total absence of mud returns from the hole.

7.2.3 Problems The worst scenario is that, as drilling fluid is lost to the formation, the height of the mud column in the annulus drops, thereby reducing the hydrostatic pressure. The drop in hydrostatic pressure may allow fluids to flow into the annulus from another formation (i.e., a kick). The well is now kicking at one depth and losing circulation at another depth. The formation fluids may flow between the two intervals, resulting in an underground blowout. This uncontrollable flow of fluids, subsurface, is a very critical situation that is difficult to remedy. Other consequences include:

• Formation damage.

• Increased cost of the well as a result of the time taken to solve the situation and the cost of the mud lost.

• Change in mud properties or circulation rates to control lost circulation may reduce drilling

efficiency, again adding time and increasing cost

• Differential sticking in or above the zone of lost circulation, due to the lack of mud in the annulus.

7.2.4 Prevention

The first prevention is to avoid being the cause of the lost circulation as a result of fracturing a formation.

Thus, Leak-Off or Formation Integrity Tests are performed beneath each casing shoe prior to drilling a new section. From this test, the fracture pressure of the formation at the shoe can be determined. This formation is regarded as being the weakest that the well will encounter in the next hole section, because it is at the shallowest depth. However, weaker formations may be encountered.

With the fracture pressure known, the maximum mud weight and shut-in pressure (without fracturing the formation) can be easily determined. These values should not be exceeded when drilling the next hole section.

If deeper formations have a fluid pressure that will require a mud weight greater than the fracture pressure in order to balance them, the well will typically be cased before encountering the overpressured formation. This protects the shallower formations and allows greater mud weights to be used in the deeper part of the well.

Following on from this, routine prevention is by way of the mud weight. It should be low enough so as not to fracture or weaken formations, while still balancing formations of higher pressures.



119

Tripping procedures, principally for a controlled pipe running speed, should also be followed to avoid excessive pressure surges.

7.2.5 Remedies

Should lost circulation occur, a number of procedures can be adopted to minimize and, hopefully, prevent further losses:

• Reduce the mud weight (but still maintaining balance against other formations). • Reduce circulating rate (this reduces the equivalent circulating density, but there should still be

sufficient annular velocity to remove cuttings and maintain bottom hole cleaning). • Increase the mud viscosity (a thicker mud will reduce the rate of loss).

These parameters, or a combination thereof, can only be altered within certain limits. If these modifications fail to stop, or sufficiently reduce, the lost circulation, then LCM (lost circulation material such as wood fibre, nut shells, cotton seed hulls, seashells, cellophane or asphalt) can be added to the mud.

Typically pumped in slugs, or pills, the LCM not only thickens the mud but will tend to "plug up" any fractures that are causing the loss of mud.

If none of these procedures work sufficiently, a final recourse is to pump cement into the fractured zone. This will hopefully seal the formation, preventing further loss of circulation and allow drilling to continue.

During lost circulation prevention, the priority is to do whatever is necessary to avoid a complete loss of hydrostatic head that may result in an underground blowout. If this is occurring, water will be continually pumped into the annulus in order to maintain a sufficient level.



120

7.3 Kicks and Blowouts A kick is an influx of formation fluid into the wellbore that can be controlled at surface. For this two occur, two criteria must be met: -

• The formation pressure must exceed the wellbore or annular pressure. Fluids will always flow in the direction of decreasing or least pressure.

• The formation must be permeable in order for the formation fluids to flow.

A blowout results when the flow of formation fluids cannot be controlled at surface.

• An underground blowout occurs when there is an uncontrollable flow of fluids between two formations. In other words, one formation is kicking while, at the same time, another formation is loosing circulation.

• A surface blowout occurs when the well cannot be shut in to prevent the flow of fluids at surface.

7.3.1 Causes Of Kicks

• Not keeping the hole full when tripping out of hole

When pipe is pulled from the hole, mud must be pumped into the hole to replace the steel volume removed. If not, the mud level in the hole will drop, leading to a reduction in the overall mud hydrostatic pressure. Keeping the hole full is extremely critical when pulling drill collars owing to the large steel volume.

• Reducing annular pressure through swabbing

Frictional forces resulting from the mud movement caused by lifting pipe, reduce the annular pressure. This is most critical at the beginning of a trip when the well is balanced by mud hydrostatic and when swab pressures are greatest.

• Lost circulation

If drilling fluid is being lost to a formation, it can lead to drop in mud level in the wellbore and reduced hydrostatic pressure.

• Excessive ROP when drilling through gaseous sands

If too much gas is allowed into the annulus, especially as it rises and starts expanding, it will cause a reduction in the annular pressure.



121

• Underpressured formations

May be subject to fracture and lost circulation, which could result in a loss of hydrostatic head in the annulus.

• Overpressured formations

Naturally, if formation pressure exceeds the annular pressure, then a kick may result.

7.3.2 Kick Warning Signs Before an influx or kick actually occurs, there are a number of signs and indications that can give possible warnings that conditions exist for such an event to occur or, indeed, that such an event is about to take place.

Lost circulation zones Large surge pressures should result in closer attention to possible signs

of fracture and lost circulation. Weaker, fractured formations may be identified by higher ROP’s and higher, erratic torque

Reduced mud returns, identified from a reduction in mud flow and decreasing pit volume, indicate a loss of fluids to the formation.

Transitional zones Increasing ROP and decreasing drilling exponent trend.

Increasing gas levels. Appearance of connection gas. Hole instability indications, tight hole, drilling torque, overpull and drag. Increasing mud temperature. Increased cuttings volume, cavings, reduced shale density.

Sealed overpressured bodies Immediate drill break resulting from the pressure differential and the

higher porosity.



122

7.3.3 Indications Of Kicks While Drilling The following influx indicators are listed in the typical order that they would become apparent by surface measurements.

• Gradually decreasing Pump Pressure

There may also be an associated increase in the Pump Rate.

The drop in pump pressure is a direct result of lower density formation fluids entering the wellbore, reducing the overall mud hydrostatic. The pressure drop will be most significant with gas and worsened as gas expansion takes place. The initial pressure drop may be slow and gradual, but the longer the kick goes undetected, the more “exponential” the drop in pressure.

• Increased mud flow from annulus, followed by…..

• An associated increase in mud pit levels

As formation fluids enter the borehole, an equivalent volume of mud will, necessarily, be displaced from the annulus at the surface. This is in addition to the mud volume being circulated so that the mud flow rate will show an increase.

In the case of a gas influx, mud displacement will increase dramatically as gas expansion takes place

As the influx continues…….

• Variations in Hookload/WOB

Although certainly not a primary indicator, these indications may be seen as the buoyancy effect on the string is modified.

If the influx reaches surface….

• Contaminated mud, especially gas cut

Reduced mud density. Change in chloride content (typically increase). Associated gas response. Pressure indicators such as cavings, increased mud temperature.



123

7.3.4 Indicators While Tripping

• Insufficient Hole Fill

When tripping out of hole, the hole is not taking enough mud fill to compensate for the pipe volume that has been pulled from the hole. This may indicate that a kick has been swabbed into the hole, or that mud is being lost to the formation.

• A “wet trip”

Where the influx and pressure, beneath the string, prevents mud from draining from the string as it is lifted.

• Swabbing

Excessive swabbing can be identified through the change in trip tank volume as individual stands of pipe are being lifted. The trip tank may be seen to initially gain mud before the mud level drops in the hole to allow fill to take place.

• Pit Gain

A continual increase in trip tank level clearly shows that a kick is taking place.

• Mud Flow

Similarly, mud flowing at surface indicates an influx. Flow may also result from swabbed fluids that are migrating and expanding in the annulus. This in itself, may be sufficient to reduce hydrostatic further to allow an influx to take place.

• Hole Fill

Excessive hole fill (at the bottom of the hole) after a trip may show caving from an overpressured or unstable hole.

• Pinched Bit

A warning rather than an indicator, a pinched bit may be an indication of tight, under-gauged hole resulting from overpressure.

Every precaution (i.e. monitoring the well before pulling out, minimizing swabbing, flow checks) is taken to avoid taking a kick during a trip:

• Well control is more difficult if the bit is out of the hole or above the depth of influx. • The well cannot be shut in (pipe or annular rams) if drill collars are passing through the BOP’s.



124

7.3.5 Flowchecks A flow check, to determine whether the well is static or is flowing, is normally conducted in one of two ways:

• By actually looking down through the rotary table, into the wellhead, and visually determining if the well is flowing.

• By lining the wellhead up to the trip tank and monitoring the level for any change.

They are typically conducted at the following occasions:

• Significant drill breaks • Any kick indication while drilling, especially changes in mud flow • Prior to slugging the pipe before pulling out of hole • After the first few stands have been pulled, to check that swabbing has not induced flow. • When the bit is at the shoe • Prior to pulling drill collars through the BOP’s • Constant monitoring (trip tank) while out of the hole

If the well is flowing, the well will be shut in NB For more details on kick detection and well control, refer to Datalog’s BLOWOUT PREVENTION AND WELL CONTROL manual.



125

7.4 Stuck Pipe The term tight hole is applied to situations when the movement of the drill string, whether rotary or vertical, is restricted due to downhole events or forces. It will typically be recognized by increased and erratic rotary torque, increased overpull to lift the pipe, or increased weight or drag when lowering the pipe. When the drill pipe is unable to be lifted from the hole, the pipe is then stuck. This, depending upon the particular sticking mechanism, may be accompanied by the inability to lower the pipe, rotate the pipe or continue circulation. Stuck pipe causes can be broadly classified under three main mechanisms: • Hole pack-off or bridge • Differential sticking • Wellbore geometry.

7.4.1 Hole Pack-Off or Bridge

Hole pack-off occurs when small formation solids fall into the wellbore, settling and filling the annular space around the drill string (typically around wider drill collars or full-gauge tools such as stabilizers), so that the annulus finally becomes packed off, sticking the pipe.

The term bridge is typically reserved for larger material that falls into the wellbore and becomes jammed between the drill string and the wellbore, sticking the pipe. There are several potential causes of pack-off or bridge: -

Sloughing or Caving of Reactive or Pressured Shales

Water-sensitive shale absorbs water, swells, breaks apart and falls into the wellbore. This can be prevented by using inhibited muds to minimize the reaction, or oil-base muds that do not contain water. If it is occurring, it can be recognized by increased mud viscosity, increases in torque and drag, the presence of balled soft clay or gumbo, the presence of hydrated or swollen cuttings, and pressure surges when breaking circulation.

Overpressured shale fractures and caves into the wellbore. This can be prevented by increasing the mud weight to balance the formation pressure. Normal pressure-trend indicators and the presence of larger volumes of bigger shale cavings should be monitored to detect its occurrence.

Mechanical stresses, due to tectonic loading and/or wellbore orientation, can also lead to shale fracturing and caving.



126

Fractured or Unconsolidated Formations

Fractured formations such as limestone, coal, together with fault zones, are naturally weak and will collapse into the wellbore when penetrated. Increases in the rate of penetration together with higher, erratic torque may indicate drilling into a fractured zone. Subsequent signs may be drag and overpull, large blocky cavings and associated gas. Fractures can stabilize with time but hole cleaning, careful reaming and avoiding pressure surges can help to control the problem. Unconsolidated formations, such as surface sediments and loose sand, may also fall into the wellbore, packing off or bridging the drill string.

Settling Cuttings and Cuttings Beds

When circulation is halted, cuttings may slip in the mud, settling around tools, such as stabilizers. Significant settling may lead to pack-off and may occur if the cuttings have not been removed effectively due to one or a combination of large cuttings volume, insufficient annular velocity or poor suspension due to mud rheology.

In deviated wells, cuttings may settle on the low side of the wellbore to form a cuttings bed. This bed may be dragged upwards by the bottom hole assembly and tools, or it may slip down the hole, both giving a potential for pack off.

Cement or Junk

Cement from the casing shoe or plugs may become unstable and fall into the wellbore, packing off or bridging the drill string.

Tools or other junk falling into the wellbore, due to poor housekeeping on the rig floor or downhole equipment failure, may result in packing or bridging off the drill string.

Mobile Salt

Salt formations can be extremely plastic and mobile and will move around and squeeze in on the wellbore due to the overburden weight above. It can therefore close-in and "grab" the drill string, causing stuck pipe.

This will typically occur when pulling out of the hole or after extended periods with the drill string out of the hole. Movement would have to be very rapid for this to occur when drilling, but rare events do occur.

Minimization or prevention is through using a mud system and weight that prevents the closure and through frequent wiper or reaming trips to maintain hole condition.



127

7.4.2 Differential Sticking

Differential sticking can result when a permeable formation, with formation pressure less than hydrostatic pressure (i.e. overbalanced), is penetrated. A filter cake will build up on the permeable zone due to normal water loss. A high rate of water loss will lead to a thick filter cake building up more rapidly. Where there is drill string contact with the wellbore wall, the pressure differential will hold the pipe against it. Situations such as a deviated well and a poor or unstabilized bottom hole assembly can lead to this contact area being greater. Where the contact area exists and the drill string becomes stationary (during connections, surveys, downtime, etc.), static filter cake builds up adding to the thickness and a low pressure area develops behind the pipe contact area.

This differential sticking force, together with the thick filter cake, leads to the pipe becoming stuck, preventing vertical movement and rotation of the drill string. Circulating will be unaffected.

Typically, other than recognizing low-pressured, permeable zones, the only indication of differential sticking will be increased overpull when lifting the pipe. There may be very little warning before the pipe is stuck.

PermeableZoneFP<HYD

Side View Top View

Low PressureZone

Initial Water LossAnd Filter Cake

PressureDifferential

Static Filter Cake



128

7.4.3 Wellbore Geometry

Stuck pipe can occur where a combination of wellbore geometry and changes in wellbore direction, together with the bottom hole assembly stiffness and arrangement of tools such as stabilizers, prevent the drill string from passing through a section of the wellbore.

Problem areas may be identified by erratic torque while drilling, but typically, sticking occurs when either pulling pipe out of the hole (POH) or running pipe into the hole (RIH).

Stuck Pipe During RIH

After a deviated section, with the possibility of doglegs, has been drilled with a specific angle building assembly, the bottom hole assembly will typically be changed to continue the straight section of the well. A stiff bottom hole assembly may not be flexible enough to pass through the section, with stabilizers in the assembly becoming hung up in opposing sections of the wellbore, preventing the drill string from being lowered further.

If abrasive formations have been drilled and bits are lifted from the hole in an under-gauge condition, then the bottom section of the hole will be under-gauge and a new bit will jam if it is attempted to run to bottom. If down-weight is registered when entering this section, the drill string should not be forced down. Rather, the bottom section of the hole should be carefully reamed and opened up to the full-hole size.

Stuck Pipe During POH

Stuck pipe typically occurs when pulling pipe out of the hole due to the following:

• The occurrence of severe doglegs together with a stiff

assembly that is unable to negotiate the change in direction. • If keyseats result from a dogleg situation, drill collars will jam

beneath the keyseat when pulling pipe from the hole. • Ledges resulting from interbedded hard and soft formations or

from fractured zones. • Micro-doglegs formed from repeated hole direction changes

when interbedded hard and soft formations have been drilled.

Stuck Pipe Stuck Pipe

Stuck Pipe

Stuck Pipe



129

7.4.4 Rotary Drilling Jars Should the drill string become stuck and incapable of being freed with normal working (i.e., upward and downward movement) of the pipe, or by pulling on the pipe without exceeding drill string and surface equipment limits of overpull, then rotary drilling jars will be used. These are designed to strike heavy-impact hammer blows, in an upward or downward direction, to the drill string. The direction in which the jar is activated depends upon the pipe movement when it became stuck. A downward blow is struck if the pipe was stationary or moving upwards. An upward blow will be struck if the drill string was moving downwards. The majority of stuck pipe situations result from an upward moving, or stationary, pipe so that, typically, downward jarring is required. To free the pipe, the jar needs to be situated above the stuck point so, typically, jars will be situated in the upper apart of the bottom hole assembly, certainly above stabilizers and other tools most prone to sticking. Jars can be hydraulically or mechanically triggered, but both work on the same principle. That is, the jar consists of an outer barrel, which is attached to the drill string below (the stuck pipe) and an inner mandrel which, attached to the free string above, can slide, delivering rapid upward or downward acceleration and force.

Hydraulic Jars

Hydraulic jars operate on a time delay produced by the release of hydraulic fluid. As the mandrel is extended, the hydraulic fluid is released slowly through a small opening. Over several minutes, opening continues but is restricted by the hydraulic metering. The fluid channel then increases in diameter allowing rapid flow and unrestricted, rapid opening of the jar, known as its stroke. At the end of the stroke, typically 8 inches, a tremendous blow is delivered by the rapid deceleration of the drill string above the jars which were accelerating through the stroke.

Stuck Pipe

Jar Cocks

Drill String is Raised

Drill String is Slacked Off

Jar Latch Trips

8” Drop

Impact is Delivered

Gravity Accelerates BHA Mass

Step 1 Step 2 Step 3



130

Mechanical Jars

Mechanical jars deliver the hammer blow by the same acceleration/deceleration of the jars and free the drill string, but the triggering mechanism is by a pre-set tension with no time delay once the jar has been cocked.

Jar Accelerator

A jar accelerator may be set above the rotary jars, typically within the heavy-weight drill pipe, to intensify the blow delivered by the jars. Upward strain compresses a charge of fluid or gas (commonly nitrogen) and, when the rotary jar trips, the expansion of fluid or gas in the accelerator amplifies the jarring effect. A jar accelerator offers the advantages of confining movement to the drill collar—or close to the stuck point—and minimizing shock on the drill string and surface equipment by cushioning rebounds through the compression of fluid or gas.

If jarring is unable to free the stuck pipe, the only recourse is to back off the free pipe. This may be achieved by simply twisting off, or unscrewing, the free pipe; or by determining the free point with a wireline tool, then running an explosive charge, on wireline, to blow the string apart.

The remaining stuck pipe now has to be retrieved, removed or avoided before drilling can continue. There are three common recourses:

• Use washover or overshot assemblies to "drill" through the zone around the stuck pipe and then

retrieve the pipe (see the next section on Fishing). • Use milling or grinding bits to "drill" down through the stuck pipe. • Plug back with cement and sidetrack around the stuck pipe.

7.4.5 Fish – Cause and Indication A fish is any undesirable object in the wellbore that must be recovered before drilling can proceed. The process of recovering a fish from the wellbore is called fishing. It is an important operation that requires special equipment attached to the drill string and then lowered into the hole to engage and retrieve the fish. If a fish cannot be recovered, it will be necessary to cement off the fish and sidetrack the hole. There are several possible causes of such fish: -

Pipe Failure Metal fatigue can cause the drill pipe, drill collars, casing or tubing to twist off (i.e., break apart). All pipe and other equipment below the break must be fished out of the hole before drilling can proceed. Depending upon where the twist off occurs, this can be identified by a drop in drill string weight and pump pressure.



131

Stuck Pipe Drill pipe, drill collars, casing or tubing stuck in the hole may inadvertently break off due to excessive overpull while trying to free it. In other cases, it may be necessary to deliberately twist off the stuck pipe in order to free it. All pipe and other equipment below the break must be fished out of the hole before drilling can proceed.

Bit Failure Mechanical failure of bit parts can cause cones, cutters or bearings to break off

and remain on the bottom of the hole. This can obviously be identified by the inability to drill.

Junk Falling Junk includes tools (such as wrenches, nuts and bolts) and other relatively small

objects (such as wireline sidewall core plates) that fall into the hole and must be fished out before drilling can proceed. Sometimes, a small quantity of debris may be grinded by the bit, but if the junk could cause damage to a bit, it should be fished from the hole.

Broken Wireline If too much strain is imposed, wireline cable can break causing lost cable and

wireline tools, which must be fished out before logging or other drilling operations can proceed.

7.4.6 Fishing Equipment Junk lost in the hole can be retrieved using one of the following tools:

Junk Basket

A junk basket is positioned immediately above the bit to collect junk, which could damage the bit. To collect junk from the bottom of the hole, the bit is lowered to just "off bottom", the pumps are switched on to lift the junk, then stopped to allow the junk to fall down into the basket. This will be repeated several times and then the drill string is lifted to the surface to determine whether all of the junk has been removed.

A Reverse Circulation junk basket, also positioned immediately above the bit, uses reverse circulation to create a vacuum so that junk is swept towards the bottom of the hole and then sucked up inside the tool.

A Finger-type or Poor-boy junk basket uses finger-like catchers to gather and trap junk. Weight is applied to the tool which causes the beveled fingers to bend inwards and trap the junk inside.

A Core-type junk basket is a device in a fishing string that cuts a core around the fish to be retrieved. It has two sets of catchers: one to break off the core, and another to hold the core and fish when the basket is pulled up.

Fishing Magnet Designed to recover metallic junk, These can be permanent or run on wireline. They have passageways for drilling mud to circulate. Skirts are fitted to prevent junk from knocking off while tripping out of the hole.



132

Fishing for lost pipe, rather than small pieces of junk, obviously requires different procedures: -

Impression Block

An impression block is a block with lead or other relatively soft material on the bottom which is used to determine the condition of the top of a fish that has been lost in the well. It is run into the hole on the bottom of the drill pipe or tubing and, after circulation, set down on the fish. Weight is then applied, thus making an impression of the top of the fish. The block is retrieved and the impression is examined. The impression is a mirror image of the top of the fish and indicates the position of the fish in the hole (i.e., whether it is centered or off to one side). From this information, the correct fishing tool can be selected.

Milling Tools

A mill is a downhole tool with rough, sharp, extremely hard surfaces for removing metal by grinding or cutting. If the top of a fish has been badly damaged, the surface can be dressed, or repaired, by milling (i.e., cutting or grinding away rough edges). This ensures the selected fishing tool will be able to firmly grip the fish.

Milling tools are also used to mill stuck fish that cannot be retrieved by conventional methods. A junk mill is a specific type of mill commonly used to grind up larger objects in the hole.

Overshots

An overshot is an externally gripping fishing tool used to retrieve lost pipe when there is sufficient annular clearance to grip the fish from the outside.

The overshot is attached to the bottom of the tubing or drill string and lowered down the hole over the lost pipe. A friction device in the overshot, usually either a basket or a spiral grapple, firmly grips the pipe, allowing the fish to be pulled from the hole.

Spears

A spear is an internally gripping fishing tool used to retrieve lost pipe when there is insufficient annular clearance to permit the use of an overshot (e.g. casing or large drill collars lost in tight holes). The spear is attached to the bottom of the drill string and lowered down the hole into the lost pipe. When weight or torque (or both) are applied to the drill string, slips in the spear expand and tightly grip the inside of the pipe. Then the string, spear and lost pipe are pulled to the surface.



133

A wireline spear is a special type of spear used to fish wireline that has broken off. The wireline spear is fitted with prongs that are used to catch and recover the lost wireline.

Washover Pipe

Washover pipe is large-diameter pipe run down, and rotated around, the outside of stuck drill pipe or tubing. The washover pipe cleans the annulus of cuttings and mud solids in order to free the stuck pipe before fishing.

Free-Point Indicator

If the drill stem becomes stuck when pulling it from the hole, the free point (i.e., the area above the stuck point) can be determined using a free-point indicator.

The free-point indicator is run on wireline into the wellbore. As the drill string is pulled and turned, the electromagnetic fields of free pipe and stuck pipe, which differ, are recorded by the indicator and registered on a metering device at the surface.

By backing off (i.e., unscrewing the free pipe from the stuck pipe), the free pipe can then be pulled from the wellbore. The stuck pipe, or fish, remaining in the hole can be washed over and recovered or retrieved using various fishing tools.

Jars and Accelerators

As when drilling, fishing jars are used to strike heavy blows against stuck pipe or other fish gripped by an overshot in order to jar it loose. In a fishing string, the fishing jar is set immediately above the fishing tool.

A jar accelerator may be set above the rotary jar in a fishing string to intensify the blow. Upward strain compresses a charge of fluid or gas and, when the rotary jar trips, the expansion of fluid or gas in the accelerator amplifies the jarring effect.

Safety Joints and Bumper Subs

Safety joints are coarse-threaded joints set at any desired point in a fishing string (usually directly above the fishing tool). In the event that a fish cannot be pulled and the fishing tool cannot be freed, the safety joint can be easily released by rotating the fishing string counter-clockwise. However, the fish that still has to be retrieved from the hole now includes the fishing tool and safety joint. Bumper subs are expansion joints set above the safety joint in the fishing string. In the event of a stuck fish, bumper subs transmit a sharp upward or downward blow to release the fishing tool and fish. They can also be used when drilling in sticking or heaving formations where they can deliver downward blows to keep pipe from sticking and to free it when it becomes stuck.



134

7.5 Drill String Vibrations It is a widely accepted fact that downhole vibrations can cause premature wear, or even failure of the drill string and bit. Recently, this understanding has been expanded to encompass the relationship between certain discrete types of downhole vibration and specific equipment damage. Vibration detection has revealed that vibrations are always present to some degree, but can be especially bad in difficult drilling environments (e.g. hard formations, steep angle wells) and this is a major cause of bit and drill string failure. There are three principal types of drill string vibration recognized: – Torsional Vibration variable pipe rotation, torque vs RPM Axial Vibration up and down the string, bit bounce Lateral Vibration off centre rotation, side to side whirl

7.5.1 Torsional Vibration Torsional vibration occurs when the rotation of the drill string is slowed down (or stopped) at the bottom and released when the torque overcomes the friction resisting string rotation. The main effect, as seen at surface, is an opposite variation of torque and RPM readings; in other words, high torque – low RPM, low torque – high RPM. The significance of this relationship is the accompanying alternation of acceleration and deceleration of the BHA and bit, and repeated twisting of the more flexible drillpipe section. The most severe form of this vibration produces “stick slip” behavior of the BHA and bit. This is defined as the bit and BHA coming to a complete halt, until the twisting of the drillpipe section by the surface drive motor produces sufficient force, as torque, to overcome the resistance, as friction, to bit and BHA rotation. The bit then spins free at a vastly accelerated rate to that seen at surface, before slowing back down to the observed speed as the its energy is dissipated. Some degree of torsional vibration is unavoidable as it begins as soon as the string begins to rotate. During lowering of the assembly to bottom, the drive system (TDS or rotary table) generates a torsional wave that propagates to the bit. Depending on the time for the bit to impact on bottom, the torsional disturbance reflects (often more than once) from the bit, which is undergoing a steady acceleration. These reflections cause propagating torque pulses along the string. Once bit contact is made with bottom, the bit RPM decelerates and a much more severe torque pulse travels to the top, where an RPM decrease can be observed.



135

Problems include the following: -

• Damage to, or fatigue failure of bit cutting elements through variable RPM and cutter load. • Reduced ROP • Connection fatigue and premature failure of drillstring, BHA and downhole tools. • Washouts, twist-offs • Fishing trips and replacements. • Easily generated with PDC bits, due to the lack of moving parts (i.e. cones and bearings). • Increased Costs!

Torsional vibrations are often present, to some degree, but are considerably worse in the following environments: -

• Hard drilling regions • Hard, abrasive lithologies • High angle, deviated wells

Contributing factors include: -

• Bit type – PDC bits generate high levels of friction to initiate the “stick” phase. • Hole angle – more pronounced oscillations in higher hole angles. • BHA weight and stability – control the torsional mode of the string. • Mud lubricity – greater lubricity will reduce friction; harder to “stick”, easier to “slip”.

Once torsional vibration has been identified through high frequency surface torque analysis, or through downhole tools, remedial action includes: -

• Increase RPM, either at surface or downhole (motor or turbine), incrementally, until the condition has been eradicated.

• Reduce WOB. There is a critical rotary speed, at the bit, above which self-sustaining torsional vibration becomes minimal. When drilling with PDC bits, that critical rotary speed lies in the range of 150-220 RPM, a difficult to achieve value without the use of downhole motors or turbines. It is recommended to attempt to reduce the amplitude and frequency of the torsional stick slip oscillations, first, by increasing the RPM since, reducing WOB usually has the effect of reducing ROP. Both methods have been shown, however, to be equally effective, and it may even be necessary to adjust both parameters in a serious situation.

7.5.2 Axial Vibration Axial vibration appears during the drilling operation in two forms:

• Vertical vibration while the bit is still in contact with the formation. • Bit bounce when contact is repeatedly lost as the bit bounces on and off bottom.



136

Like torsional vibrations, axial vibrations are present during all phases of the drilling operation. The axial vibration phase in the drillstring is produced by the initial impact of the bit with the formation on bottom. The amplitude of these initial vibrations generally decreases to a background level unless it is interrupted by bit bouncing or another such disturbance. The initial bit bounce is triggered by an excessive impact speed when lowering to bottom. Its amplitude can therefore be lowered considerably by simply lowering the bit to bottom more smoothly. It can, however, also be triggered by a change in lithology (which could give rise to impulsive forces on the bit), excessive or uneven bit wear, or torsional and lateral vibration exciting the situation. Increases in axial vibration are often accompanied by stick slip, sudden increases in changes in WOB and rapid increases in bit RPM. The harder the formation, then, typically, the higher the frequency of axial vibration at the bit. Impulses sent through the drillstring generate correspondingly higher amplitudes of axial vibration energy. Problems include: -

• Broken or rapidly worn bits, BHA failures • Reduced ROP • Impact inducing other vibration modes

Axial vibrations are most common: -

• In hard drilling regions. • In vertical wells where propagation of energy, along the string, is easier. • When drilling with tri-cone bits – less contact area, moving parts.

Some degree of axial vibration is common, but it is likely to be a problem in the same kind of harsh drilling environments as torsional vibration. Contributing factors include: -

• Lithology hardness • Bit type (tri-cone) • Hole angle – deviated holes dampen axial vibration through contact with the string. • BHA length • Fluid viscosity

Axial vibrations can be recognized through the following: -

• Erratic WOB, amplitude increasing with the severity of vibration. • Obvious surface vibration or shaking. • During bit bounce, variations with SPP as the bit loses and regains contact with bottom with high

frequency. Once identified, remedial action includes: -

• Lowering the bit to bottom slowly and smoothly.



137

• Reduce WOB, adjust RPM. • Use of PDC bits, shock subs.

WOB should be adjusted first, but this, in turn, is dependant on the formation type: - In a soft formation such as sandstone, increasing the WOB even slightly will increase the amplitude and frequency of axial vibration. Increasing RPM will have the effect of reducing the severity of any torsional vibration, which may be present concurrently with the axial. This would be effective as it is often torsional behavior that induces axial vibration in the first place, notably in harder lithologies. The use of PDC bits reduces axial excitement when compared with tri-cone bits, but is not as effective as the use of a shock sub which should be installed just behind the bit (and motor if present).

7.5.3 Lateral Vibration The theoretical “spinning string” of a perfect drilling assembly in a vertical hole, is known as axisymmetric motion, i.e. symmetrical motion around an axis. Lateral vibration is contrary to this and is defined as non- central rotation of the bit, and/or BHA, causing lateral impacts with the sides of the wellbore. The rotation of the drillstring generates and maintains this motion. The resulting eccentricity causes a dynamic imbalance, which generates torsional, axial, and lateral vibration. It can take three forms, each more severe than the previous: -

• Bit Whirl describes an off-centre bit rotation, which is especially common with PDC bits.

• Forward BHA Whirl describes off-centre BHA rotation, with its centre line rotating in the same direction as the drillstring rotation, i.e. clockwise.

• Backward BHA Whirl occurs where the borehole wall friction causes the centre line rotation to become anti-clockwise, opposite to the rotation of the drillstring.

When trying to visualise the mechanism of lateral vibration or “whirl”, a popular analogy is that of the motion of a skipping rope held and turned in a vertical position, but this motion would obviously be greatly exaggerated due to the constriction of the wellbore. Initiation of lateral vibration normally takes higher loads and stresses than would be necessary to induce torsional or axial vibrations. It is thought, however, that lateral vibration is initiated by either torsional or axial vibration, and can eventually be more destructive than both of them, a fact exacerbated by its difficulty to detect. Problems include: -

• Reduced ROP • Premature bit wear



138

• Uneven string/stabilizer wear - abrading away the metal of the tools due to impact against the wellbore or casing.

• BHA washouts and twist offs • Borehole enlargement, hole instability, casing damage • Lateral impacts inducing other vibrations

Common occurrences are: -

• Alternating lithologies • Vertical wells – easier to stimulate the whirl motion (virtually impossible in deviated wells due

to the effect of gravity). Contributing factors include: -

• Bit type – PDC bits will more easily move off-centre to initiate whirl. • BHA stability and centralization • Lithology (alternating hardness) • Bit profiling when commencing with a new bit.

Bit whirl is much more difficult to detect, with confidence, than torsional and axial vibration, especially as it would often occur in conjunction with the other types.

• High erratic torque will be seen, but torque oscillations may not be as regularly cyclic as torsional stick slip.

• Combination of torsional and axial vibrations may indicate whirl. Lateral vibration should appear as high frequency hookload variations coupled with torque oscillations. Vibration periods would be much shorter and less cyclic than in torsional stick slip. If these conditions were being met, whirling would be suggested.

Although difficult to detect, it is fair to assume that, in a vertical well, with little centralization of the BHA, using a PDC bit through alternating lithologies and with torsional and axial vibration present, that whirl is present at the bit and/or BHA! Remedial action includes: -

• Reduce RPM, change WOB (increase for forward BHA whirl, decrease for backward BHA whirl).

• Use “anti-whirl” bits that have been modified for both enhanced stability and direction. • Packed assemblies and centralization of the BHA.

In order to eliminate lateral vibration, action would have to be taken to reduce both torsional and axial vibration. Whirling does not seem to occur unless these vibrations are first being generated. NB for greater detail, refer to Datalog’s SURFACE VIBRATION, MONITORING AND ANALYSIS manual.



139

7.6 Washouts

7.6.1 Drill String Washouts

A drill string washout is any hole or crack in the drill string caused by corrosion, fatigue or failure of the drill string.

Typical causes and contributing factors include:

• Poor equipment handling • Deviated holes and doglegs • Running drill pipe in compression • Incorrect make-up torque of tool joints • Corrosive mud or gases • Vibrations or slip/stick conditions • Erratic torque • High loads, jarring.

Typical indications are: - • Pipe inspections, especially in high-risk wells, can identify weakened areas. The pipe can then be

replaced before failure occurs.

• A gradual loss of hydrostatic pressure can signal a drill string washout occurring as drilling fluid leaks out of the drill string into the annulus. If left unattended, the pressure drop will accelerate as the washout becomes more severe.

7.6.2 Hole Washouts

These occur where the annulus becomes enlarged. It is very important to know actual hole diameter and presence of washouts in order to calculate the exact volume of cement required to set casing in place. Caliper logs are run with wireline to determine the exact hole diameter with depth. Hole washouts can be caused by:

• Weak or unconsolidated formations caving into the hole • Sloughing shales • Fractured zones caving into the hole • Weaker zones beneath casing shoes • Dipping or structurally weak formations • Deviated wells creating "orientation" weakness.

The condition can be worsened by hole erosion due to high annular velocities and turbulent flow; abrasion caused by a high-solids content in the mud; repeated movement of the drill string causing physical corrosion; and also swab and surge pressures.



140

Washouts can be determined exactly by their effect on the lag time. A washout creates a larger annular volume that requires more pump strokes to circulate from the hole. Therefore, if the actual lag time is greater than the calculated time, a washout exists. This may be determined from actual lag checks, from gas responses due to formation change or connection gas, etc. Another indication of the hole washing out may be an increased volume of cuttings.



141

8 UNDERBALANCED DRILLING Underbalanced drilling is defined as deliberately drilling a formation where the pressure exceeds the hydrostatic pressure exerted by the drilling fluid column. The drilling fluid may be conventional water-base or oil-base mud (termed flow drilling), aerated mud or foam, or gas such as air, nitrogen or methane. Primarily, underbalanced drilling is used to improve the penetration rate, minimize lost circulation and protect the producing formations. Ultimately, underbalanced drilling is used when the overall cost of drilling the well and producing the reservoir is reduced. If it becomes more expensive than conventional drilling, it is of limited benefit. However, underbalanced drilling maximizes the rate of penetration, and eliminates the potential for lost circulation and differential sticking. Using the proper equipment, certain wells can be drilled underbalanced, thereby providing the overall advantages of reduced drilling costs and improved production. It is imperative that all safety equipment is fully functioning and personnel take all necessary safety precautions (as is true for all forms of drilling operations) because kicks are more severe and therefore more dangerous when drilling underbalanced.



142

8.1 Benefits and Limitations of Underbalanced Drilling

Underbalanced drilling offers numerous benefits over conventional drilling to provide the ultimate advantages of reduced drilling costs and improved production. The primary benefits include: -

• Dramatically improved drilling rates. • Improved ability to maintain a vertical hole in hard rock formations (without having to reducing

WOB and RPM as in conventional drilling). • Minimized risk of lost circulation. • Prevention of differential sticking. • Protecting the reservoir from formation damage by preventing fluid invasion and thereby limiting

mechanical plugging of pores/permeability and plugging from hydrated clays/shales.

Underbalanced drilling cannot be expected to turn around every low-producing or never-before-producing well. There are limitations, as well as several circumstances under which a well should never be drilled underbalanced.

• UBD should not be used when drilling weak formations that could easily collapse if they are not

supported by the mud column. • Fractured, dipping formations are naturally susceptible to collapse, and UBD increases this

tendency. • Thick coal beds are typically fractured and weak, and will collapse or wash out when drilled

underbalanced. As well, they may produce water, which will adversely affect air/gas drilling. • UBD should also not be used to drill overpressured or thick shales, or mobile salt sections. • Underbalanced drilling in shallow, high-pressure zones can easily allow too large or too rapid an

influx of formation fluids into the wellbore which, in turn, will result in the severest and most dangerous type of kick.



143

8.2 Underbalanced Drilling Fluids The drilling fluids used in underbalanced drilling fall into the following classifications:

• Gas (i.e., air, natural gas, nitrogen, other gases) • Gas with mist • Foam with gas • Aerated water, mud or oil, using one of the gases • Oil, water, invert or direct emulsions, mud (i.e., conventional drilling fluids applied to provide

hydrostatic pressure less than formation pressure)

8.2.1 Gas & Air Drilling

Advantages and Disadvantages

Since its inception, gas drilling has been undertaken to increase the rate of penetration in hard rock formations. With the introduction of the air hammer, it has become possible to drill a straight hole in hard-rock, crooked-hole country using a simple pendulum assembly equipped with a hammer and slow rotation.

Advantages • maximum ROP

• reduced cost to drill lost circulation zones • reduced drilling fluid costs • improved well performance • no corrosion (N2)

Disadvantages • water wet formations

• cost (especially N2, large diameter holes) • no wellbore support • possibility of downhole fires (when using air) • poor cuttings quality for evaluation (very fine and intermittent)

Equipment

The drill string used for gas drilling is much the same as for mud drilling. However, the drill pipe must be strong enough to withstand the weight and shocks normally supported and absorbed by drilling mud. As well, dried mud inside the drill pipe may loosen and plug an air bit or hammer, and the drill pipe may leak when returned to mud service.

Air drilling bits generally resemble mud drill bits, and have an open orifice to minimize pressure drop through the bit.

Sample catchers are used to gather cuttings samples to aid the geologist in evaluating the well. Cuttings, however, are typically of poor quality because they are very fine (virtually powder) and do not always arrive at the surface evenly distributed.



144

Drilling Operations

Gas and air drilling operations typically fall into three general categories, depending upon the amount of moisture produced from the formations:

• Dry gas (nitrogen or methane) is best used for "weeping" formations that dry very quickly and will

not cause mud rings. For more information on mud rings, see Gas & Air Drilling Problems below. • Gas saturated with moisture from the mist pump will expand below the bit and carry formation

moisture to the surface in droplets. This prevents the system from losing energy by absorbing formation water to its saturation point.

• A light mist with a heavier than normal concentration of foam will not wet the side of the hole

excessively, but will help dry dampness in the hole, thereby avoiding mud rings from forming.

Drilling Problems

Mud Rings When the formation is damp from water or oil, cuttings may form a "mud" that, due to poor hole cleaning, is deposited against the side of the hole. This tends to form rings of mud that can become larger and restrict the air flow, causing an increase in pressure and the possibility of downhole fires and stuck pipe.

Mud rings can be removed by adding detergents to the drilling fluid.

Floating Beds At high drilling rates, or with low gas volumes, cuttings are carried to the top of

the collars where the annular area increases and the annular velocity drops to a point where it cannot lift the cuttings. This forms a floating cuttings bed that drops back to bottom as fill on connections when air-flow is stopped. Floating beds may also occur opposite a washout where the annulus is larger.

Floating beds can be removed by increasing the flow rate, briefly, before making a connection, in order to lift the cuttings. Thus, in terms of cuttings, the geologist sees nothing while the joint is being drilled, but receives all the cuttings at once when the flow rate is increased, making analysis very difficult.

Fires When using air, drilling into gas or oil bearing zones, leads to the possibility of

fires, either downhole or at the surface.

The use of nitrogen or methane eliminates this, since there is no oxygen for combustion.

Tight Hole Tight hole problems commonly extend from mud-rings and floating beds. It is

important to keep the gas circulating and continue working the drill pipe to minimize such build ups.

Weeping Formations Low permeability formations will "weep" fluid, which in turn leads to bit balling

and/or the forming of mud rings. Weeping may stop when adjacent fluids are depleted.



145

Nitrogen or Methane, since they are so dry, are particularly effective at drying a damp or weeping formation.

Key Seats Since gas drilling is typically done in hard-rock dipping formations, key seating,

while not common, does occur.

8.2.2 Mist

A mist is formed by suspending fluid droplets within an air, or gas, stream. The particular fluid, whether water, mud, or even oil, depends on local lithologies and conditions. For example, water droplets may lead to reaction, swelling and destabilizing of shale, but the use of mud or water with polymers may prevent this. However, misting slows the penetration rate and requires more air volume and, sometimes, more injection pressure. The use of injection pumps and misting agents add to the cost of mist drilling.

Advantages • can drill in wet formations

• represses downhole fires Disadvantages • lower drilling rate than air/gas

• requires more air volume and injection pressure • dampness may allow corrosion • water in hole may cause shale instability • no wellbore support

8.2.3 Foam

Whereas mist has liquid droplets suspended in a continuous gas phase, foam is a two-phase fluid with gas bubbles suspended in a liquid phase.

Foam is typically used because it is not affected by formation fluid influxes to the extent of air or gas, and because it has extremely efficient cuttings-lift and hole-cleaning characteristics.

Foam quality is a term used to describe the proportion of gas to liquid.

For example, a foam quality of 0.80 would contain 80% gas. (Above 0.97, i.e., 97% gas, the fluid would be termed a mist.) The liquid phase of a foam liquid contains a surfactant, or soap foaming agent, that helps to bind the fluid together and prevent the gas phase from separating from the fluid system.



146

Advantages • fluid lifting capacity, able to lift and remove large influxes of formation liquids (e.g., water)

• excellent cuttings sample/lift/removal (compared to air/mist) due to its viscosity, requiring lower velocity

• needs less gas than air/gas/mist Disadvantages • wets the formation, although minimized with additives

• corrosion if mixing with air • disposal concerns (requires more surface equipment) • high cost because the foam is not reusable and must be constantly

generated

8.2.4 Aerated Mud

The term aerated fluid is given to a two-phase fluid with a foam quality of less than 0.55 (i.e., 55% gas).

Aerated mud was developed to reduce lost circulation, when using conventional muds, by reducing hydrostatic pressure. The single most critical problem with aerated mud, however, is pressure surges. Aerated must is thus best suited for drilling hard rock formations that will not immediately cave in reaction to pressure and velocity changes.

Any conventional drilling fluid, whether water, brine, oil or mud, can be aerated with gas, be it air, nitrogen or methane. Thus, an aerated fluid maintains the benefits of the original fluid, such as viscosity, hole cleaning, filter cake, inhibition, etc., while reducing the potential for lost circulation.

Advantages • properties (e.g., density, filter cake, inhibited muds) • pressure control • reduced risk of lost circulation

Disadvantages • pressure surges

• corrosion (with certain drilling fluids) • additional cost of equipment and gas generation

8.2.5 Mud

Any conventional drilling fluid can be used in underbalanced drilling, provided it is capable of handling the formation fluids without destroying its own properties or creating uncontrollable situations on the surface or other unacceptable contamination.

Conventional drilling fluids, when the hydrostatic pressure is less than the formation pressure, will result in underbalanced drilling with the principal benefits of improved penetration rates, reduced formation damage (since mud will not invade the formation) and minimal risk of lost circulation.

The term flow drilling is used when underbalanced drilling, and formation properties such as permeability, lead to continual influxes (i.e., the well is flowing as it is being drilled).



147

Advantages • increased rate of penetration • less formation damage • better productivity • reduced lost circulation • real-time testing of zone productivity

Other advantages and disadvantages really depend upon the type of drilling fluid being used. For example, oil-base systems have surface handling disadvantages, but such advantages as lubrication, minimal formation damage, etc. Salt systems are extremely corrosive, but can be used in higher pressures than fresh water. Water-base mud systems are inexpensive and easily modified, but are subject to solids control and separation of oil.



148

8.3 Equipment and Procedures

8.3.1 Rotating Heads

Mounted above the normal BOP stack, a rotating head is the blowout prevention device used to close off the annular space around the kelly or drill pipe. It effectively seals the annulus when the pipe is rotating or moving vertically. This makes it possible to drill ahead even if the well is flowing and there is pressure in the annulus that the weight of the drilling fluid is not overcoming.

A rotating head specifically functions as a rotating flow diverter. Sealing elements rotate with the drill string while a housing (i.e., steel bowl) and bearing assembly control the flow, either by diverting or containing it.

The critical components of a rotating head design are the means by which the seal is effected around the irregular surfaces of the drill string, and the bearing assembly by which the inner race rotates with the drill string while the outer race is stationary with the bowl. There are two basic rotating head designs:

• A stretch-fit/self-actuating stripper rubber, with an inside diameter smaller than the outside

diameter of the drill pipe, seals around the drill string while mounted to a component of the inner race of the bearing assembly. Wellbore pressures apply vector forces against the cone-shaped profile of the stripper rubber, making it self-actuating (i.e., no external hydraulic pressure is required).

• An inflatable bladder or spherical packer, inflated or actuated by hydraulic pressure, seals around

the drill string when the hydraulic pressure behind the packer elastomeric is greater than the wellbore pressure. While the hydraulic pressure can be regulated manually or automatically, this design may require a on-site operator while the tool is in use.

Rotating heads have been used successfully for years. They are small, relatively light-weight, and have a low profile. They are simple to install on the rig, easy to use, and easy to repair (e.g., quick replacement of stripper rubbers, bearings and seals).

8.3.2 Closed Circulating and Separating Systems

Underbalanced drilling in H2S bearing reservoirs has led to the development of the closed system to prevent fumes and gas from escaping to the atmosphere from the flow line and mud/gas separators.

Kelly driver

Bearing assembly

Bottom rubber

Bowl

Top rubber



149

Under a normal open separator system, the gas is broken out in a separator and sent to the flare line while the mud is sent to the shale shaker.

Under a closed system, the gas, oil and cuttings are separated in a separator and only the mud is sent to the conventional open mud pits. Under a totally closed system, the mud is also sent to closed mud tanks and kept enclosed until the pump suction.

8.3.3 Blooie Line and Sample Catcher

The blooie, or blooey, line is the line used for taking returns when drilling with air, mist or foam. It is installed directly under the rotating head. For air, gas or mist drilling, it terminates at a flare pit, carrying the return gas or air, cuttings and any liquids to disposal.

The blooie line is normally a low-pressure line with any required choking done with the choke manifold on the flow line. A pressure rating of 150 psi (1,034 KPa) is typically sufficient for the line and all tied-in components.

Fluid normally moves through the blooie line at extremely high velocities because the gas phase of the circulating fluid is undergoing rapid expansion. Therefore, the blooie line should be kept as straight as possible and changes in direction in the line should only be made when necessitated by location/size limitations.

As with conventional drilling, samples of cuttings must be gathered during underbalanced drilling to aid the geologist or mud logger in formation evaluation.

For air, gas or mist drilling, the sample catcher will consist of a small diameter nipple or pipe fixed to the bottom of the blooie line. The sample pipe is open to, and extends up inside, the blooie line. An angle iron extension diverts cuttings into the catcher. A valve on the sample pipe outside the blooie line can then be opened to collect cuttings in a sample bag.

8.3.4 Gas Measurement

If a separator is being used in the surface treatment system, gas measurement is a simple attachment to draw off gas samples. The arrangement will be one of a specially designed filter, pressure regulator (to reduce pressure to approximately 10 psi) and normal drop-out jar and drier, shown below, attached to a valve outlet on the separator.



150

Gas Sample LineRegulatorFilter Drop-Out

Jar &Drier

Separator

Drainage

If sampling from the blooie line, a sample port and tube is placed on the low side of the blooie line and angled away from the air flow (to avoid being filled with cuttings). To this, the normal gas sample line is attached. Filters are very important to prevent dust from entering the gas detectors. If a lot of formation water is present in the returning flow, an additional chamber can be installed to collect and dispose of the liquid.

Flow

Gas Sample to Unit

Blooie Line

Collected Liquid

Filter

Shut off valve

Sample Port



151

8.4 Coiled Tubing Units

8.4.1 Components

Injector Head The injector head is used to reel the tubing into and out of the hole, and to support the weight of the tubing and downhole tools. Today's largest injector heads weigh several tons and can pull loads up to 200,000 lbs. (90,000 kg).

Tubing Reel The tubing reel is a spool, typically 6 ft. (2 metres) central diameter, used to reel

up to 26,000 ft (7,930 metres) lengths of tubing. Reel diameter is normally chosen to minimize coiling diameter (i.e., the ratio of tubing diameter to bending diameter).

Goose Neck This is an arced or curved guide that feeds the coiled tubing from the tubing reel

into the injector head.

Blowout Preventers Coiled tubing blowout presenters allow the tubing to be reeled into and out of the hole at pressures up to 10,000 psi (68,940 KPa). Very similar to conventional blowout preventers, they consist of pipe and blind rams to close the well, and slip rams to support tubing sheared by tubing cutters.

Hydraulic Power-Pack Consisting of a diesel engine, hydraulic pumps and hydraulic pressure

control, this powers the reel, injector, fluid pumps and other rig equipment.



152

Control Console The control console contains all of the gauges and controls required to operate and monitor the rig; to lift or run the coiled tubing, to alter the speed, to monitor wellhead pressure, etc.

8.4.2 Drilling Applications

Coiled-tubing drilling can be effectively applied in re-entering vertical wells to achieve further penetration, as well as in re-entering horizontal/directional wells to laterally drain reserves from the hole.

Coiled tubing offers a cost-effective method for drilling observation and delineation wells, due to its fast running speed. Due to its typically smaller diametrical size, coiled tubing is ideally suited to drilling slim-hole production and injection wells.

Given that underbalanced drilling can be performed safely with coiled tubing, there are several applications where a conventional rig can be used to drill most of the hole and a coiled-tubing rig can then be used to drill critical zones:

• Drilling in or below lost-circulation zones • Coring pay zones • Underbalanced drilling through pay zones

8.4.3 Advantages and Disadvantages

The use of coiled tubing in open-hole, slim-hole drilling applications offers the following advantages: • Reduces costs due to the smaller size and automated features of the coiled-tubing rig, requires less

mobilization time, a smaller site and less site preparation time. • Reduces drill string tripping time and associated costs because continuous tubing eliminates the

need for drill-string connections, and reduces stuck pipe incidents. • Since coiled tubing can be run safely in and out of a live well, underbalanced drilling with coiled

tubing minimizes formation damage, increases rate of penetration and eliminates differential sticking.

• Simplifies well-control techniques and helps maintain good hole conditions because coiled tubing

allows for continuous circulation (while tripping and while drilling).

Coiled tubing drilling does not offer all the answers to drilling problems.Some disadvantages of coiled tubing drilling are:

• Coiled tubing cannot be rotated, so requires expensive downhole motors and orientation tools to

provide rotation and enable drilling.



153

• Coiled-tubing drilling is limited to small-size holes due to restrictive rig capabilities and difficulties associated with large outside-diameter coiled tubing and limited torque capacity.

• Coiled-tubing drilling is limited to relatively shallow holes due to the size and weight restrictions

of the tubing reel and reel trailer (as opposed to the mechanical strength of the tubing). • Coiled-tubing drilling is a relatively new technique, requiring considerable development and

industry experience before the technology becomes more widespread. • Coiled-tubing rigs, equipment and accessories are expensive. • Coiled-tubing rigs cannot run or pull casing, and also require conventional rigs for well

preparation, unsetting production packers, etc.



154

9 ROCKS AND RESERVOIRS 9.1 Introductory Petrology Petrology, the study of rocks in respect to their origin and to their physical and chemical properties, classifies rock types into three categories: -

9.1.1 Igneous Igneous rocks result from the cooling down and solidification of molten magma that originates from within the earth’s core.

• Extrusive igneous rocks are formed when the magma cools after being ejected to the earth’s surface as lava.

• Intrusuve igneous rocks form when the magma does not reach the earth’s surface but cools

within the earth’s crust. The igneous rock that results will be dependent on the chemical composition of the magma and upon the rate of cooling.

• Extrusive rocks, such as Basalt, cool rapidly and will therefore be fine grained, since crystals do not have sufficient time to grow to any degree, and typically glassy in texture.

• Intrusive rocks such as Granite cool at a much slower rate so that crystal size will be larger and

the texture more granular.

9.1.2 Metamorphic Metamorphic rocks are formed from the transformation of existing igneous or sedimentary rocks as a result of extreme heat and pressure. This metamorphism will change the mineral, structural and textural characteristics of the original rock. Examples include:

• Shale being altered to Slate • Sandstone being altered to Quartzite • Limestone being altered to Marble

9.1.3 Sedimentary The factors combining to the formation of sedimentary rocks are those of erosion, transportation and deposition.



155

Erosion of the existing landmass can be caused by several processes: -

• Mechanical weathering due to water, wind, ice and temperature changes. • Chemical weathering by the dissolving of soluble minerals into water.

Transportation of the eroded rock fragments (clastics) and dissolved chemicals can be carried out by several agents, such as water (streams, rivers, waves), wind or ice. Deposition will occur when the transportation agent no longer has the energy required to carry the fragments. Thus: -

• Aeolian deposits will form when the wind drops it’s load. • Alluvial deposits form where rivers drop their load (changes in gradient, river bends, entry into

lakes, flood plains). • Deltaic deposits are left where rivers pass into deltas or estuaries • Marine deposits are left where particles are carried out into deeper water.

Naturally, another factor in the deposition of material is the size and weight of fragments. Where the transportation agent is loosing energy, the larger, heavier fragments will be deposited first, whereas the smaller, lighter fragments will be retained longer so that a gradation of sediments results. As well as the size of fragments, the shape also tells of their transportational history. Those deposited near to the original source will not only be larger, but they will also tend to be angular and sharp. Those fragments carried for longer distances will be subject to prolonged wear or erosion during their transportation so that fragments will tend to be smaller, smoother and rounded.

Sediment Classification Sediments can be classified according to their depositional environment. The following is an example of such a classification: -

Aeolian Terrestrial

Alluvial

Deltaic Transtional

Pro-Deltaic Neritic (shallow, shelf) Bathyal (continental slope) Marine

Abyssal (deep ocean floor)



156

The sediments within these groups can be classified on the basis of the origin of the material: -

Where the consituent components are eroded and transported fragments (clastics) of pre-existing rocks or minerals

Clastics Transported shell fragments may also be grouped in this category

Chemical precipitates Formed by evaporation of surface water or by the crystallization of dissolved salts

Organic In situ accumulations of organic debris such as shells, skeletal fragments, plant remains

Compaction and Cementation Once the sediments have been deposited, they will be subject to burial, compaction, and often cementation, to form given sedimentary rock types. This process comes as a result of more and more sediments being deposited on top of existing ones. When they are originally deposited, the sediments will contain quite a large quantity of ground water. As they become buried, the accumulating weight of the overlying sediments (known as the overburden) will compact the sediments, squeezing out the ground water. This degree of compaction will increase as the overburden increases, consolidating the sediments into what we can call rocks. As the groundwater is squeezed out, minerals that were in solution will be left behind to bind and cement the clastic fragments, further solidifying the rocks.

Clastic Rock Types These are characterized by the size of the clastic material making up the rock: -

> 256 mm boulder Breccia (angular) or Conglomerate (rounded)

64 - 256mm cobble “

4 - 64mm pebble “

2 - 4mm granule “ 1/16 - 2mm sand Sandstone 1/256 - 1/16mm Silt Siltstone < 1/256mm clay Claystone or Shale



157

Chemical and Organic Rock Types

Carbonates Limestone Dolomite

Chert Chemical

Evaporites Gypsum Anhydrite Salt

Limestone Coquina, Reef

Diatomaceous Earth Organic

Coal



158

9.2 Petroleum Geology Petroleum is the term applied to hydrocarbons occurring within the earth’s crust, whether in the form of gas, liquid or solid. In terms of petroleum exploration, sedimentary rocks, in particularly sedimentary basins, contain all commercially viable acculumulations of petroleum. This is simply because sedimentary rocks contain the source material required for hydrocarbon generation and sedimentary rocks possess the characteristics that are required for hydrocarbons to accumulate.

9.2.1 Petroleum Generation Although it is accepted that petroleum has an organic origin, there are many unanswered questions as to the actual processes involved in the conversion of the organic material into hydrocarbons. Firstly, we need to determine the source of the organic material. In doing so, we have to consider that organic debris will decompose in the presence of oxygen. In order for a source material to ‘survive’ long enough to form petroleum, we are looking for deposition to take place in a largely anaerobic environment. On land, the source of organic material is dead vegetation (of far greater significance than animal life) but, obviously, in normal circumstances, this vegetation will decompose in the oxygen rich atmosphere. In subaqueous environments such as bogs and swamps, this material may accumulate in sufficiently large quantities to decompose and be preserved as peat. Under increasing pressure and temperature due to burial and compaction, water and gas will be expelled from the peat to leave coal. Natural gas, or methane, is a common by-product associated with this process. Although typically a low yield source of petroleum, coal as a source of methane has nevertheless been successfully exploited in the United States and is a growing area of exploration in other parts of the world, including Europe and Canada. In the marine environment, by far the greatest sources of organic debris are micro-organisms such as plankton plants (eg algae) and animals (eg foraminifera). Not only are these present in large quantities but they are extremely rich in organic compounds such as proteins and lipids which, being rich in carbon and hydrogen, are an excellent source material for the generation of petroleum. As these organisms die and fall to the seafloor, they are buried along with inorganic material such as clay, silt or sand sediments. For any possibility of petroleum to be generated from this source, certain optimum criteria have to be met:

• Early diagenetic oxidation of the organic material must be prevented. • This may be achieved by rapid burial and sedimentation or by a near anaerobic environment in

the depositional waters.

• There must be a source of inorganic sediments that will ensure rapid burial and preservation of the organic material.



159

• The ideal sediment will be very fine grained clay or silt, since this will provide closely packed, impermeable sediments that will not allow the passage of oxygen bearing pore waters.

• The basin has to remain ‘in situ’ long enough to allow a sufficient thickness of the organic source

material to be deposited.

• The deposition of sediments and resulting subsistence of the basin must be such that normal burial, compaction and diagenesis of the sediments occur.

• With normal compaction, water contained within the pore spaces of the sediments will be

squeezed out (de-watering) so that the sediments become increasingly compact and impermeable. This will provide a seal for the organic source material and prevent any ingress of oxygen carrying water. (Note that the de-watering process, later in the burial history of the sediments, may also provide the means for primary migration as will be discussed later)

9.2.2 Maturation of Petroleum We have already seen that the ideal environment for petroleum generation is the rapid burial of a large quantity of organic material within an oxygen deficient environment of inorganic clay material. If the environment were totally anaerobic, bacterial breakdown would likely produce methane and hydrogen sulphide. However, with an initial quantity of oxygen dissolved within the pore water, the breakdown will result in the production of carbon dioxide, water, and light hydrocarbons. Any free oxygen would be used up by this initial decay of part of the organic material and by the bacteria involved in this process. Once free oxygen is removed, the remaining organic material has a good potential of being converted to hydrocarbons (through kerogen). The exact mechanism for this alteration is not fully understood, but it seems likely that a combination of processes may be involved.

• Bacterial decay will continue until the bacteria can no longer survive in the conditions of increasing temperature and pressure as burial proceeds.

• Low temperature thermal degradation in the later stages of diagenesis (less than 50 to 65 °C).

• Catalytic reactions caused by metals or minerals contained in the pore water may lead to the

further breaking down of the organic material.

• Radioactive decay has also been considered as a factor in this process due to the amount of energy that is released during the decay of reactive elements and also due to the fact that significant source rocks are often dark, fine clays that have an extremely high radioactive content.

• As temperature (and pressure) increases with continued burial, thermal processing or cracking is

generally accepted as being the main process of breaking down the organic material into smaller and smaller hydrocarbons. This process will occur later on in burial where the higher



160

temperatures of above 50 to 65 °C lead to catagenesis, rather than diagenesis, of the sediments. The exact depth that this occurs will depend on local geothermal gradients.

As the organic material is being broken down and transformed during diagenesis, organic matter (biopolymers) is transformed into geopolymers known as kerogen. The exact nature and composition of the kerogen will be dependent on the composition of the original organic material. With continued burial and temperature increase, the resulting thermal breakdown and later cracking during catagenesis will generate hydrocarbons from the kerogen. A liquid or oil window, a temperature range during which petroleum generation can take place, will determine the success of this process. This will be dependent on the burial depth and local geothermal gradient. If the temperature is too low, thermal cracking will not take place. If it is too high, the process will be too extreme, and whereas light hydrocarbons and gas may result, heavier hydrocarbons may well be ‘cooked’ and ‘carbonized’ to a solid residue. This process, known as metagenesis, is thought to commence from temperatures of around 200 °C. Maximum petroleum generation, within the oil window, occurs within the approximate temperature range of 100 to 180 °C.

9.2.3 Petroleum Migration Clearly, since reservoirs are found in porous and permeable rocks such as sandstones or limestones, yet, as we have seen, petroleum develops in source rocks such as clay, there has to have been a migration of the petroleum. It is generally agreed that hydrocarbons would have been formed in the source rock before migration takes place, so that it is the hydrocarbons and not the source material that migrates. The question has been raised, however, as to how this migration could take place because the clay sediments, would, by this time, be largely impermeable. How this can be possible will be illustrated, but it is worth noting, that even during migration, if the hydrocarbons are still within the oil window, regarding the temperature of the formation through which they are traveling, thermal cracking and hydrocarbon development may still occur. If this is possible, then perhaps it is still possible for migration to take place before full maturation has occurred, with continued thermal cracking producing hydrocarbons during migration.

9.2.4 Primary Migration As hydrocarbon generation is taking place during burial, so to are the clay sediments becoming compacted with a resulting reduction in pore size and increasing impermeability. For this reduction in pore size to occur, pore water has to be ejected from the pore spaces. This dewatering, or squeezing out of pore water is a normal process during compaction. Impermeability develops, not so much due to the lack of communication or connection between pores, but due to that fact that the connections between the pores are so microscopically small.



161

If hydrocarbon migration is to occur along with the dewatering process (which is the natural assumption as to the method of primary migration), then there has to be some mechanism that will increase the permeability of the clay sediments allowing fluid flow. This mechanism comes with continued diagenesis of the clay when greater burial has been achieved. During the late diagenesis and catagenesis of the sediments, there is a natural conversion of clay minerals (smectite to illite), due to cation exchange, resulting in bound water being freed from the mineral structure or lattice. This process accelerates with increased temperature, being greatest during catagenesis over a similar temperature range to the oil window, i.e. when greatest petroleum generation is occurring. The cation exchange may even be a further source of energy to assist in the generation process. The increase in water volume, due to the cation exchange, will result in an increase in the fluid pressure within the pores i.e. overpressure. This will result in fracturing of the matrix producing the fissile characteristics that are recognized in clay and shale. This texture or structure, a network of microfractures, facilitates the migration of pore fluid and hydrocarbons out of the overpressured sediments towards normally pressured, permeable and porous formations. The physical process of the migration of the hydrocarbons within this aqueous phase is likely to be as a combination of discrete globules, in suspension or in solution. Movement, initially, will tend to be vertically in the direction of decreasing pressure. However, lines of weakness, such as fractures, bedding, porous interbeds, providing greater permeability than the ‘vertical permeability’ across the sediments, will facilitate lateral migration.

9.2.5 Secondary Migration This secondary process is the migration of the hydrocarbons within a permeable and porous body (i.e. sandstone or carbonate). Movement will tend to be in the direction of fluid movement along local or regional pressure gradients. A further driving force is given by the natural buoyant rise of the lighter petroleum within the heavier pore waters. Resisting this flow are capillary pressures imposed by the passing of oil globules or gas bubbles through the pore-throat diameters. For as long as there is a pressure differential, and ‘permeable openings’ or weaknesses such as fractures, migration will take place. Ultimately, migration will continue until an impassable barrier is met and the petroleum is forced to accumulate into a pool or reservoir. Secondary migration, relative density and gravity, and the relative ease by which gas and oil will pass through pore throats will result in hydrocarbon gas settling above the oil, so that the natural progression with depth through a reservoir is gas above oil above water. It should be noted that these contacts are not an ‘absolute’ boundary between only gas or only oil or only water. There is always likely to be some water content within the pore spaces. Contacts are likely to be gradational, rather than sharp, boundaries and are an indication of the predominant phase (gas, oil or water) in the vertical section.



162

9.2.6 Hydrocarbon Traps As detailed above, in order for a hydrocarbon pool to accumulate, there has to be a barrier preventing ongoing migration. This will be produced by geological conditions causing complete retention or, at the very least, only allowing negligible leakage or escape. A trap can be defined as a geometric arrangement of rock that permits significant accumulation of petroleum in the subsurface. Essential components to the trap are the reservoir rock itself and the occurrence of effective seals.

Stratigraphic Traps Stratigraphic traps result from a lateral stratigraphic change that prevents continued migration of the hydrocarbons. Primary Stratigraphic Traps result when the lateral change occurs as a result of a contemporaneous change in the depositional environment (1-3), or as a result of buried depositional relief (4-5): -

1. Where there is a lateral facies change within the same body. This may occur in the depositional environment or may be as a result of later cementation or crystallization.

2. Where bodies of sand form lenses or lenticular deposits within impermeable sediments - this may

be typical of a braided river channel.

3. Pinch outs forming where sediments are being deposited against an existing shelf or depositional surface, typical of deltaic or shoreline environments.

4. Carbonate reefs

5. Aolian dunes

FACIES CHANGE PINCH OUT

AOLIAN REEF CARBONATE REEF



163

Stratigraphic Traps are commonly associated with unconformable changes occurring after deposition and sedimentation has taken place. There are number of possible trap occurrences, including truncation of reservoir beds (A), onlaps onto unconformities (B), buried erosional relief, etc: - Secondary Stratigraphic Traps can result from post-depositional alteration of rocks. Examples include: -

• Porosity occlusion – for example, cementation in a reservoir rock may result in a loss of porosity that, in an updip location, could result in an effective seal.

• Porosity enhancement, such as dolomitization of low permeability limestones may improve

reservoir quality.

Structural Traps Fold Related Folding of reservoir-type rocks, overlain by seal rocks, often results in hydrocarbon traps. Anticlinal traps are a common form, where a permeable and porous sand body has been upfolded, allowing hydrocarbons to migrate to the crest of the fold and be trapped by overlying impermeable sediments. Similar traps may be formed where the sand body is of uneven thicknesses, allowing hydrocarbons to accumulate in the thicker parts of the body. If the crest of laterally short folds does not have sufficient amplitute to hold all of the hydrocarbons migrating into the trap, then an spill-over will result.

A

B



164

Fault Related Traps may be associated with many types of faults. The simplest form is where a dipping reservoir body is juxtaposed against an impermeable body providing a lateral seal or closure. Obviously, this type of trap still requires the sand body to be overlain by an impermeable formation providing the vertical seal, and it now requires that the fault zone does not provide a path for the hydrocarbons to escape. In fact, the fault gauge itself may provide the lateral seal. Graben structures may provide lateral seals on both sides of the reservoir rock. Anticlinal traps may also be associated with faulting, particularly with thrust or rotational faults. Dome Related A variety of traps can be associated with intrusions of material into overlying strata. This intrusion will drag strata as it rises so that beds dip away from the crest in all directions. For reservoir rocks adjacent to the dome, this will result in an effective updip seal. This type of trap is most commonly associated with salt domes, but similar features will be produced by igneous intrusions or by shale diapirs.



165

9.3 Petroleum Composition Petroleum is the term that is applied to any hydrocarbon, whether gas, liquid, or solid, that occurs naturally in the earth’s crust. As well as hydrocarbons, petroleum may also contain variable but minor amounts of impurities, such as carbon dioxide, sulphur and nitrogen. In liquid form, petroleum is typically referred to as crude oil, which may be composed of a complex mixture of hydrocarbons varying in molecular size and weight. When recovered to surface, the hydrocarbon compounds can be separated through refining and distillation to yield a variety of petroleum products. By definition, hydrocarbon compounds are those that consist of hydrogen and carbon atoms. These compounds, the simplest of which are the hydrocarbon gases, can be classified into 2 types, depending on the molecular bonding of the carbon atoms.

1. Saturated Hydrocarbons compounds that possess one single covalent bond between the carbon atoms

2. Unsaturated Hydrocarbons compounds possessing double bonds between the carbon atoms NB A covalent bond results from the simultaneous attraction of two nuclei for a shared pair of

bonding electrons. A double covalent bond occurs when two pairs of electrons are shared by two atoms.

9.3.1 Saturated Hydrocarbons or Alkanes These compounds consist of short chains of carbon atoms saturated with hydrocarbon atoms that occupy all available carbon bond positions. The carbon atom chains may be straight, branched or cyclic, giving rise to 3 series of alkanes. The straight and branched series are known as Paraffins and the cyclic series as Naphthenes.

Paraffin Paraffin is the most common form of hydrocarbon, whether found in liquid crude oil or in a gaseous state. The group includes two of the alkane series, the straight and branched-chained carbon atoms. The straight chained, or normal, alkanes are given by the following general formula: Cn H2n + 2 Where n ranges from 1 to 10, the paraffin members are methane (C1), ethane (C2), propane (C3), butane (C4), pentane (C5), hexane (C6), heptane (C7), octane (C8), nonane (C9) and decane (C10).



166

Chromatographic gas analysis at wellsite usually extends from methane through pentane, since heavier members of the series will, typically, remain in a liquid state at surface pressure and therefore be undetectable as a gas. Minor amounts of hexane can sometimes be detected but requires a longer analysis time. Certainly, at normal surface temperature and pressure, methane through butane will exist as gases and are easily detected. At ambient pressure, pentane condenses into a liquid state at a boiling point of 36 °C, so depending on the temperature of the circulating mud, is normally extracted as a gas. Ambient temperature will control whether part, or all of the pentane re-condenses back to liquid form and goes undetected. The branched, or iso, chain series of alkanes within the paraffin group are given by the same general formula as the straight chained series. They contain four or more carbon atoms, therefore ‘commence’ from iso-butane through to the heavier hydrocarbons.

Structure Name Abbreviation Formula

Methane C1 CH4 Ethane C2 C2H6 Propane C3 C3H8 Normal Butane nC4 C4H10 Normal Pentane nC5 C5H12

Structure Name Abbreviation Formula

Iso Butane iC4 C4H10 Iso Pentane iC5 C5H12



167

Naphthenes Naphthene is the name given to the third group of the alkane series. Carbon atoms in this group are closed chained and again saturated with hydrogen atoms occupying every available bond position. The names already given to the paraffin series are prefixed with ‘cyclo’ to distinguish the naphthene series i.e. cyclopropane, cyclobutane, and have the general formula: -

Cn H2n

Typically associated with higher density crude oils, only cyclopropane and cyclobutane normally remain in the gaseous state at surface pressure and temperature. Unfortunately, since the molecular weight is so similar, they are analyzed by typical wellsite chromatograph columns as if they were propane or butane from the paraffin series.

9.3.2 Unsaturated Hydrocarbons or Aromatics Similar to cyclo-alkanes or naphthenes, the aromatic series comprises closed chained carbon atoms. Unlike the alkanes however, the aromatics are not hydrogen saturated, i.e. hydrogen atoms do not occupy every available bond. The series is usually only a minor component to crude oils, but the most common aromatic, benzene, is present in most petroleum compounds. The series has the general formula Cn H2n - 6, with Benzene being C6H6 Benzene is the simplest aromatic compound, a closed chain, or ring, of six carbon atoms. Alternating single and double covalent bonds links the carbon atoms. This ‘benzene ring’ forms the basis of further compounds in the aromatic series. Since the carbon atoms are unsaturated, bonds unoccupied by hydrogen atoms are free to be taken up by further carbon atoms. Thus, outside of the closed ring, as

Structure Name Formula

Cyclopropane C3H6 Cyclobutane C4H8 Cyclopentane C5H10



168

shown in Figure 2.5, further aromatics such as toluene (one benzene ring + one CH3) comprise one or more benzene ring together with one or more CH3 ‘elements’ occupying the free bonds. Benzene is extremely soluble, in fact this group is often referred to as the soluble hydrocarbon group. It has been identified that this can provide a very useful evaluation parameter, in that it is more subject to fluid movements and can therefore be an indication as to the proximity to a hydrocarbon source.

9.3.3 API Gravity Classification A classification of crude oil, based on the density or specific gravity (gm/cc) of the oil, is defined by the American Petroleum Institute (API) and widely used. High API gravity oils have a high content of the gasoline hydrocarbons (C4 to C10). The API gravity is defined, at 16 °C and atmospheric pressure, by the following formula: - API = 141.5 - 131.5 SG The greater the API rating, then the lighter the oil. The API rating can be visually approximated by the colour of the oil or by the colour of the fluorescence under ultra-violet light (see section 11.2). NB For more information on hydrocarbon classification and evaluation, refer to Datalog’s HYDROCARBON EVALUATION and INTERPRETATION manual.

Benzene C6H6 Toluene C6H5CH3



169

9.4 Reservoir Characteristics A reservoir can be defined as an accumulation of oil, gas or water within the pore spaces of a rock. For a reservoir (hydrocarbon) to be commercially viable, firstly there must be a sufficient volume of hydrocarbons and, secondly, it has to be possible to remove or extract the hydrocarbons from the rock. The principle characteristics that a reservoir or petroleum engineer will be looking at when assessing the commercial prospect of a reservoir are: - porosity permeability water saturation

9.4.1 Porosity Porosity is defined as the total void space, or pore space, within a rock and is generally expressed as a percentage, mathematically, by: - porosity (∅ ) = pore volume (void space) x 100 bulk volume Absolute porosity is the term given to the volume of void space that is occupied by fluids, including water, oil or gas, since some of the pore space can be occupied by matrix or cement. This would represent the maximum volume available to hydrocarbons. Most reservoirs are either sandstones or carbonates, which have different porosity characteristics and are subject to different changes.

Sandstones Initial (intergranular) porosity will be largely dependent on the sorting (variability in size) and shape of the grains. Maximum porosity will be achieved when the grains are rounded and all one size. Void space will be lost if the size is variable and if the grains are angular. This initial porosity will be subject to further reduction due to cementation and compaction or by further, secondary cementation.

Limestones Porosity is possible through a number of mechanisms. Firstly, the carbonate may be granular or crystalline with porosity being either inter- or intra- (within the particles as a result of solution). Porosity may exist along joints, bedding planes or fractures. Cementation and compaction, as with sandstones, will serve to reduce porosity. Leaching will increase porosity with acidic waters leaching grains and attacking lines of weakness. Processes such as secondary cementation, recrystallization or dolomitization will reduce porosity, often with irregularly shaped voids, or vugs, resulting.



170

Porosity is only accurately determinable from laboratory core analysis but can be visually estimated at wellsite by examination under the microscope (changes in penetration rate and gas may assist a comparative estimation) and described in the following fashion: - poor < 6 % medium 6 - 12 % fair 12 -18 % good 18 - 24 % excellent > 24 % For more details on porosity types and determination, refer to section 11.1

9.4.2 Permeability The permeability of a reservoir rock describes the quality of communication between pore spaces and is a measure of the ability of a fluid to flow through the connected spaces. Permeability will be effected by the sizes of the pore throats, the degree of tortuosity (linearity of connections), the fluid type and viscosity. Again, it can be accurately determined by laboratory core analysis but can only be estimated at the wellsite. The laboratory measurement is a measure of the volume of fluid (of known viscosity) that will pass through a known volume of rock in a given time when subject to a given pressure differential. A permeability of 1 Darcy is equal to 1cm3 of a fluid with viscosity 1 cP, flowing through 1cm3 of rock in 1 second, under a pressure of 1atmosphere!! Reservoir permeabilities are typically measured in millidarcies (md). Wellsite estimations can be determined by comparing the gas measured in the ditchline to the cuttings gas. ie a comparison of the gas that is able to escape from the rock during transport to the surface to the gas that is retained within the volume of rock. This will also provide a qualitive indication of the porosity.

9.4.3 Water Saturation We have seen how original marine sediments, when deposited, are saturated with the water from the depositional environment and that during burial and compaction, this ‘connate’ water is squeezed out as the sediments are dewatered. During primary hydrocarbon migration, any hydrocarbons generated will move with this water, following a decreasing pressure gradient, into a reservoir rock. Secondary migration within the reservoir will separate the oil, gas and water, due to buoyancy forces amongst others, displacing the original pore fluid of the reservoir rock.



171

Water saturation is a measure of the amount of water contained within the pore spaces of the reservoir rock and is expressed as a percentage of the total pore volume available. If the pore spaces were to be totally occupied by water, the saturation (Sw) would be 100%. Obviously, the lower the water saturation is, the higher the volume of hydrocarbons.

9.4.4 Reservoir Zones, Contacts and Terminology Separation during secondary migration, as a result of relative specific gravities and buoyancy, gives rise to gas (upper), oil and water (lower) zones. The contacts between these zones will be gradational rather than immediate, so that the zones are generally used to refer to the majority component and that which can be produced. There will always be mixing of the different fluids.

i.e. There will, typically, be a certain degree of pore water in all parts of the reservoir Gas will be held in solution within oil and water There are likely to be oil droplets in gas or water zones. Gas accumulated at top of the reservoir is often referred to as the gas cap. If a gas cap exists, then the oil beneath will generally be saturated with gas. The oil would then be said to have a high GOR, or gas oil ratio. If the oil has the capability of absorbing more gas, it is referred to as being unsaturated. The amount of gas in solution is dependent on the pressure and temperature conditions. When the oil is brought to surface, with lowering of pressure, the gas would break out of solution and be present as gas. Condensate describes the condition of hydrocarbons being present as gas in the reservoir, but condensing to a liquid when brought to surface. This is typically evident with the heavier hydrocarbon gases, C4 and greater. Dry gas is a term given to gas, which is composed predominantly of methane. It may often be associated with bacterial breakdown; deep high temperature thermal cracking of oil or kerogen; or even pressure generated, so may not be a productive accumulation. If a potential hydrocarbon bearing zone, on testing, produces sufficient water to make the zone unproductive, it is known as wet. This is not to be confused with the term wet gas, referring to a gas consisting of significant proportions of the heavier hydrocarbons, C3, C4 or C5.



172

10 MUD LOGGING - INSTRUMENTATION AND INTERPRETATION

This section is intended to provide a guide to the main mud logging tools and parameters, what the mud logging engineer is looking for, and how measurements can be interpreted in terms of changing drilling or geological conditions. Further detail on the mud logging sensors and equipment can be found in Datalog’s FIELD TRAINING manual. 10.1 Depth and Rate of Penetration Knowing the current depth of the bit at any time during drilling and other operations is obviously of paramount importance. It provides the principle source against which all other values and data sources are referenced. During drilling, it allows the depth of formation and downhole changes to be accurately determined; it allows for accurate pressure calculations; the rate of change of the bit depth (ROP) enables lithological changes and changes in drilling conditions to be identified. During tripping, knowing the depth and rate of change (running speed) enables fluid displacements and induced pressures to be accurately determined and monitored. It enables casing strings to be set at specifically determined points and for productive zones to be accurately located and tested.

10.1.1 The Geolograph Rigs track and record the depth by measuring the vertical movement of the traveling block. Traditionally, a thin cable attached to the traveling block is connected to a Geolograph recorder, a drum that is rotating at a known rate. As the blocks move up or down a specific distance (typically 1 foot or 1/5th of a metre), a pen will be triggered so that a tick mark will be recorded on the Geolograph chart. Although simple and robust, the Geolograph is only operated during drilling. Block movement during tripping operations is too fast so that the Geolograph has to be disengaged. The driller will have to re-engage it when the bit has been run back to the bottom of the hole. The driller determines the exact moment that the drill bit ‘tags’ bottom by a change in the weight indicator. This occurs since a portion of the string weight becomes supported by the bottom of the hole as opposed to being supported totally by the traveling block and hook. A slight increase in pump pressure will also normally be seen as the bit touches the bottom of the hole. At this point the driller will normally hold the bit just ‘off’ bottom, slowly rotating, and zero his weight indicator (so that the entire string weight is known to be supported by the hook, with none resting on the bottom) as well as engaging the geolograph. Before drilling ahead with full WOB, the WOB is typically increased gradually so that the new bit profile can be cut into the bottom of the hole.



173

10.1.2 Depth Wheel The depth wheel utilizes the same Geolograph line that is used by the rig. The line is run through two specifically sized wheels in an S-shape. As the blocks are moved up or down, the vertical movement of the line will cause the wheels to rotate. One rotation of the main wheel will signify a known vertical movement, typically 0.2m, and will send a signal to the computer so that the movement is recorded. The depth wheel is accompanied by an on/off bottom switch, typically air activated and tied into the driller’s switch. Thus, when the driller engages or disengages the Geolograph, a signal will also be sent to our computer to signify the bit being on or off movement. This sensor is easily installed, reliable and accurate, but has the major disadvantage that it is totally dependent on the rig’s depth monitoring system and on the driller engaging and disengaging it. Since the system is disengaged when the bit is off bottom, it means that we are unable to track the depth during tripping operations. Most operators insist that we monitor and record depth independently from the rig, so Datalog have two other depth systems that are typically used.

10.1.3 Crown Sheave The crown sheave sensor is a totally independent depth monitoring system. It comprises a number of metallic targets positioned around the fast sheave wheel at the crown block, together with two proximity sensors to detect the targets. The sensors are positioned so that they are offset in relation to the targets. This will produce a specific sequence of sensor activation that enables the computer to determine in which direction the wheel is turning and therefore whether the traveling block is moving up or down. The advantage of the crown sensor is that the movement of the blocks is monitored at all times, not just when drilling is taking place. Tripping of pipe and running of casing strings can therefore be tracked so that mud displacements can be monitored and induced pressures can be accurately calculated.

Tag bottom Lift off, tag bottom and set WOB Gradually increase WOB and profile the bit Drill ahead

Bit Position WOB / Hookload Pump Pressure

Time



174

The system works in conjunction with the hookload sensor, from which it will determine when the drillstring is ‘set in’ or ‘lifted out’ of the slips. The computer can therefore distinguish between when the traveling block and the bit are moving and when only the blocks are moving.

10.1.4 Drawworks Sensor The drawworks sensor is again independent of the rig system and monitors the movement of the blocks at all times. It therefore has all the advantages of the crown depth sensor. Whereas the crown sensor monitors the movement of the blocks by the rotation induced in the sheave wheel around which the drill line passes, the drawworks sensor monitors the movement where the drill line terminates at the drawworks. Here, the drill line is wrapped around a rotating drum controlled by the driller; for the blocks to be lowered, line has to be let out from the drum; to raise the blocks, the drum has to take in the drill line. By measuring the rotation of the drum, the vertical movement of the blocks, whether up or down, can be determined very accurately. One advantage of the drawworks sensor over the crown sheave sensor is that the mudlogger does not have to clamber up to the top of the derrick with targets, sensors, tools and cable !

10.1.5 Heave Compensation When working on floating offshore rigs (drillship or semi-submersible), tidal and heave variations have to be accounted for in order to determine the true depth of the hole. Datalog accomplishes this by installing transducers on the drilling motion compensator and on the riser tensioners, in order to measure their extension or compression in response to heave movement. From this, the change in the rig’s position (height) relative to the bottom of the hole, or seabed, can be determined and corrected for.

offset proximity sensors

equi-distant targets

fast sheave

drill (fast) line



175

Since the rig is floating, it will move up and down along with the heave or swell motion of the sea. As we know, the rig is connected to the BOP stack on the seabed by the marine riser. Obviously then, the riser has to be prevented from the same vertical movement. This is achieved by a number of pneumatically activated tension units that hold the riser at a constant tension. The rig is able to move up and down, in relation to the riser, by the installation of a telescopic, or slip-, joint that forms the uppermost part of the riser assembly. The riser tension lines are connected to the outer barrel of the slip joint, whereas, the inner joint that moves up and down in relation to the outer barrel, is connected to the rigs diverter. Likewise, when the rig is moving up and down, the drillstring must be prevented from a similar movement so that the bit is not constantly being lifted off and crashed back to bottom. This would obviously result in damage to the bit and the drillstring. The objective is to maintain the position of the drillstring in relation to the seabed and the bottom of the hole, keeping constant weight on bit during drilling, while the rig is moving

up and down with heave.

Riser tension unit Riser tension lines

To guideline tensioners

Guide sheaves

Heave

Outer slip-joint

Inner slip-joint

Tension lines to guidebase

Lines to guide base on seabed

Schematic showing riser tensioning and compensation,together with relative movements during an upward heave.



176

This type of compensation is most commonly achieved through a traveling block compensator situated between the traveling block and the hook supporting the drillstring. As the rig moves up and down, the compensator cylinders will retract or extend. In doing so…

• The position of the blocks remains the same relative to the rotary table, but moves in relation to the seabed.

• The hook remains in the same position relative to the seabed and the bottom of the hole, but

the position in relation to the rotary table is changed. Traveling block compensation may be by way of one or two compensating pistons (the schematic illustrates a double piston system. The other type of mechanism is crown block compensation, where the position of the entire crown adjusts to compensate for the movement of the rig. Here, both the traveling block and hook will remain in the same position relative to the seabed and the bottom of the hole.

Schematic showing Travel Block compensation

a

a

b

b

c

crown block

travelling block

compensator cylinder

piston

hook

upper swell

lower swell

seabed

R.T.

R.T.

drilling line



177

10.1.6 Rate of Penetration The rate at which the well is being drilled provides one of the most important parameters recorded during the drilling operation. The units of measurement may be in terms of the depth gained over a given time interval (eg m/hr, ft/hr) or in terms of the length of time taken to drill a given depth interval (eg min/m). for example, 60 m/hr = 1.0 min/m, 30 m/hr = 2.0 min/m There are many factors that can affect the ROP, including: -

Bit Selection As seen in the bit classification in section 2.3, bits have different degrees of hardness, together with teeth or tungsten carbide inserts of different size, shape and hardness. All of these things will determine the bit’s effectiveness in drilling through different lithologies. Obviously, the harder the formation, then the harder the bit should be. Softer formations will not require such a hard bit, and better penetration rates will be achieved with longer, slender teeth. The harder the formation, the shorter and broader the teeth should be. Bit selection will be based upon previous bit records and cost records from nearby wells and the lithologies expected. It is clear then, that when drilling an interval with one particular type of bit, different lithologies will be readily identified by changes in penetration. ROP is therefore the first line of attack in formation evaluation for geologists and mud loggers. Unfortunately, diamond and PDC bits are generally unresponsive to lithological changes, achieving constant penetration rates for long drilling periods.

Rotary Speed (RPM) The simple rule is that if RPM is increased, then the ROP will increase. In soft formations, the ROP is directly proportional to RPM and shows a linear increase. In hard formations, however, the rate of ROP increase is non-linear and will decrease as RPM increases. The exception is, again, with diamond or PDC bits when, even in hard formations, ROP will increase linearly with rotary speed.

Weight on Bit (WOB or FOB) The weight, or force, that is applied to the bit will also affect the penetration rate. In general, the relationship is again linear, with ROP doubling if the WOB is doubled. This relationship does not hold true for low bit weights in hard formations, where an increase in WOB will not produce the same increase in ROP.



178

Differential Pressure This is the difference between the formation pressure and the pressure due to the weight of the vertical column of drilling fluid (mud hydrostatic pressure). When these two pressures are equal, the well is said to be at balance. When the mud hydrostatic pressure is greater than the formation pressure, then the well is overbalanced. Similarly, the well is underbalanced if the formation pressure is the greater of the two. The greater the overbalance, the slower the penetration rate. Typically then, the higher the mud weight, the slower the ROP. Similarly, if the formation pressure increases, the ROP will increase. ‘Conventional’ drilling will try to maintain a sufficient overbalance to avoid influxes of formation fluids into the wellbore, while at the same time keeping the overbalance to a minimum so as to obtain the maximum penetration rates possible. On the other hand, it has been shown that underbalanced drilling, whether with a conventional liquid drilling fluid or using systems such as air, foam or aerated mud, can dramatically increase penetration rate and reduce drilling costs.

Hydraulics and Bottom Hole Cleaning Clearing the newly drilled cuttings from the bottom of the hole and away from the bit is very important in maintaining optimum penetration rates. If bottom hole cleaning is not effective, cuttings may ‘ball up’ and clog the underside of the bit, diminishing the contact between the cutting surfaces of the bit and the bottom of the hole (bit balling). This would obviously have a detrimental effect on ROP. The effect of differential pressure has already been shown. A further factor during drilling is that the equivalent circulating density (an increase over the mud density measured at surface), due to frictional pressure losses in the annulus, will further increase the pressure differential. As well as by an increase in the actual mud density, these pressure losses will increase if the flow rate increases (increasing the velocity of the drilling fluid in the annulus) or if the flow regime is turbulent as opposed to laminar, or if the annulus is loaded with cuttings.

RPM WOB

ROP ROP Drill Rate vs RPM Drill Rate vs WOB

soft formation

soft formation

hard formation hard formation



179

Bit Wear As the bit becomes worn from continual drilling, penetration rates will obviously decrease. This change in penetration rate is one of the primary considerations in determining when a bit should be ‘pulled’ from the hole and replaced.

Lithology As already mentioned, penetration rate is one of the primary interpretative tools used by the geologist and mud logger in recognizing formation changes. However, all of the above factors that can affect the ROP have to be taken into consideration when determining the cause of a change. If none of these factors can explain an increase or decrease in ROP, then the change has to be as a result of a change in the formation properties. Properties affecting ROP include mineralogy and hardness (harder - slower), porosity (greater - faster), consolidation versus cementation (well cemented - slower), mineral inclusions such as pyrite or chert (slower), etc.

Depth With depth and greater overburden, lithologies become more compacted, resulting in reduced porosity. As the proportion of rock matrix increases, lithologies become harder to drill with depth.

Formation Pressure As we have seen, higher formation pressure, resulting in a greater pressure differential, leads to slower ROP. At the same time, high formation pressures result from formations retaining or possessing an abnormally high proportion of fluid. This necessarily results in higher porosity, which also leads to increased ROP. ROP as a lithological indicator is a valuable aid to well correlation. When plotted on a mudlog, with ROP increasing to the left, it can often be used as a direct correlation with gamma measurements taken by wireline tools.

10.1.7 Drilling Breaks A sharp increase in the rate of penetration is known as a drilling break (likewise, a reduction is known as a reverse or negative drilling break) and it is the responsibility of both the mudlogger and the driller to identify such breaks as quickly as possible. When the mudlogger identifies a drilling break, he or she should notify the driller immediately and also make a record that this has been done.



180

The significance of a sharp drilling break is that if the change in ROP was not due to a change in drilling parameters such as WOB or RPM, then it has to be due to a formation change. It may simply be due to a lithological change (softer, less consolidated, weaker or no cement, greater porosity etc), in which case the mudlogger should ‘lag the break’ and collect additional cuttings, when they arrive at surface, in order to identify the change. However, what always has to be considered as a possibility is that a drilling break resulting from an increase in porosity may also signify an increase in formation pressure that could lead to an influx of formation fluids (in other words, a kick) into the wellbore. It is usually standard and safe drilling practice to ‘flow check’ an unexplained drilling break so as to determine whether the well is indeed taking a kick. This requires the driller to stop drilling, lift the bit off bottom and stop circulating, then to monitor the well for any signs of flow. This can be done by the driller physically observing the mud, through the rotary table, at the top of the annulus, or by directing the mud return line to the trip tank and see whether any mud is gained in the tank. If the mud level in the annulus is seen to rise, the well is flowing with mud being displaced from the top of the well due to the influx at the bottom of the hole. Likewise, if the mud is directed to the trip tank and the level is seen to rise (after ‘run off’ from the surface lines has been accounted for), the well is flowing. At this point, the well will be shut in (closing the annular preventor) in order to control the influx. Similarly, a drilling break due to an unconsolidated formation, particularly shallow sands, may be a prelude to drilling fluid being lost to that formation. The consequences of such lost circulation will be detailed in section 6, but again, observing the mud level in the annulus by performing a flow check will determine whether the mud level is dropping as mud seeps away into the formation downhole.

Limestone Stringer

Sandstone Stringer

Sandstone Stringer

Lithology Interpretation Rate of Penetration Block/Bit Position

fast slow Increasing depth

negative drillbreak

positive drillbreak

positive drillbreak time



181

10.1.8 Controlled Drilling In addition to safety considerations (which are of paramount importance) and the objective of reaching the target, one of the most important factors in the drilling of wells is the cost. The operational costs of drilling rigs, service company personnel and products/equipment are very expensive, so that the least time it takes to drill the well, the more economic it will be. The exceptions are contracts between operator (the oil company) and contractor (the drilling company) that are on a turn-key basis. Here, the contractor will determine a cost for the whole well operation, which will normally include all of the service operations as well, rather than a daily cost. Except for unforeseen events or problems, the main criteria that affects the duration of a well will be how long it takes to drill the hole - other operations such as casing and logging take a given period of time and cannot really be made any faster. Therefore, all of the factors affecting the ROP detailed above, will be taken into consideration and optimized in order to provide the fastest drilling as possible while maintaining safety and hole condition. The most suitable bits will be selected for expected lithology, optimum weight and rotary speeds will be utilized, mud weight will be carefully monitored and maintained, hydraulics programs will be carefully designed etc. There are several considerations that have to be balanced with drilling as fast as possible: -

• Personnel safety, particularly during connections and tripping operations when heavy equipment and pipe is being handled, and especially with inexperienced personnel.

• Hole stability has to be maintained. When drilling holes very quickly, the risk of collapse is very

high. This may result in stuck, or lost pipe, and certainly time and cost to repair the damage.

• Effective hole cleaning to avoid loading the annulus with cuttings, particularly in large surface holes.

• Maintaining the mud system and properties, controlling the amount of solids retained by the

mud.

• Maintenance of surface equipment.

• High pressures induced by fast tripping speeds (see swab and surge pressures in section 4). Certain situations will necessitate the control of the drilling rate (controlled drilling): -

• Determining specific formation tops, casing points, coring points, etc

• While drilling surface holes. Soft formations and large bit size (higher weight can be applied) can lead to very fast drilling rates but can also lead to: -

• Hole collapse from loose, unconsolidated formations.



182

• Overloading the annulus with cuttings. This is typically controlled by regularly sweeping the hole with viscous mud that will lift and remove all cuttings from the annulus.

• Hole problems from soft surface clays particularly in offshore drilling. • Poor solids control due to the amount of formation solids and the limitations of surface

equipment.

• Directional drilling, to ensure that the correct angle and direction is achieved. Maintaining good hole stability is also achieved by good drilling practices, particularly in formations such as loose sands, soft clays, salts etc

• Working the pipe up and down and cleaning the hole after each single or stand is drilled; this ensures that the wellbore is stable and not closing in or collapsing.

• Regular wiper trips - tripping the pipe partially out of the hole or to the previous casing point

before drilling ahead also helps to clean the hole and maintain stability.



183

10.2 Hookload and Weight on Bit Knowing the weight of the drillstring that is supported by the hook and traveling block enables us to determine important information when drilling or running pipe. The total weight of the drillstring (BHA and drillpipe) is known as the string weight. This is easily determined by multiplying the density of the string component, kg/m or lbs/ft, by the length of each section. A sensor that is attached to the drill line supporting the traveling block and hook measures this weight. This is known as the hookload (i.e. we are measuring the load on the hook). When the string is off bottom and not moving, the hookload is equal to the effective string weight since the hook is supporting the entire weight of the string. The effective string weight will be slightly different to the calculated or theoretical string weight owing to the buoyancy factor of the mud. When the bit touches the bottom of the hole, some of the load is taken off of the hook and part of the string weight will now be supported by the bottom of the hole. This is known as the weight on bit. string weight = hookload + weight on bit The weight that is transferred from the hook support, to the bottom of the hole, is controlled by the driller. He operates a brake from which he can control the release of drill line from the drawworks, thereby raising or lowering the block and hook. By lowering the blocks when the bit is on bottom, more of the string weight will be transferred to the bottom of the hole, therefore we will see an increase in the weight on bit. As we saw in the previous section, increasing the WOB will produce a faster drilling rate. Datalog measures the hookload by detecting changes in tension on the drill line due to the different load.

10.2.1 Load or Pancake Cell The drill line, or rather the deadline section of the drill line between the crown block and dead line anchor, is held in tension across the load cell. Changes in tension on the line result in a force being applied from a central point against a diaphragm, filled internally with hydraulic fluid. The changes in line tension are then hydraulically transmitted to a pressure transducer where the measurement is taken from.

drill line

load cell

diaphragm

FRONT SIDE

hydraulic attachment



184

In many cases, however, the rig will already have a load cell and hydraulic system in place so that we are able to connect our pressure transducer and hydraulic hose directly to the existing system. The disadvantage then, of course, is that any hydraulic leaks in either system will affect the other one. By utilizing our own load cell, we will be independent from the rigs own weight monitoring system. A leak in the system will be detectable in the same way as any other hydraulic pressure sensor. When leaking, the hydraulic fluid does not fill the entire system, so that changes in pressure on the diaphragm will not be immediately transmitted by the hydraulic fluid. There will be a delay before any change is recognized, response to changes will be slower or dampened, and the maximum response will be lower. The system is measuring hookload, therefore a leak in the system will be seen as a drop in the hookload, but if we are drilling at the time, the leak will also be seen as an increase in the WOB.

10.2.2 Strain Gauge The principal of the strain gauge is similar to the load cell, in that changes in the tension on the drill line are used to determine the load or weight. Rather than a hydraulic system however, the change is determined electronically. The tension on the drill line causes a steel bar to bend. On each side of the bar, metallic strips will bend also, resulting in a different resistance being produced on either side of the bar. This produces a potential difference across the bar, which can be measured and converted to a current loop signal.

10.2.3 Weight on Bit Knowing the hookload, and therefore the WOB, obviously enables the driller to control the amount of weight or force that he applies to bit, either keeping it constant or making changes. From a logging point of view, it enables the mud logger to determine whether or not changes in the rate of penetration are due to a change in the WOB. Changes in WOB will affect penetration rate, bit wear and directional control. There are two principle controls to the maximum weight that can be applied to the bit: -

• The manufacturer’s bit specifications should be recognized in order to prevent bit or bearing failure, and not exceed the limitations of the bit.

• The overall weight of the drill collars provides the weight, and also limits the weight, that can be

applied to the bit. The drill collar weight (after buoyancy in the drilling mud is accounted for) must always exceed the WOB. This ensures that the drill collars are always in compression whereas the drillpipe is always in tension.



185

The point where compressional stress changes to tensional stress, is known as the neutral point and this must always be located in the drill collars.

If the WOB exceeded the weight of the drill collars, then part of this weight would be coming from the drillpipe. The neutral point would now be situated in the drillpipe and that section of pipe would be in compression along with the drill collars. Drillpipe is not strong enough to withstand compressional forces and would be prone to buckling and to excessive wear on the pipe and joints leading to likely collapse and failure.

10.2.4 Hookload, Drag and Overpull Hookload is an important parameter in identifying tight spots in the hole. These may be caused by a number of factors including undergauge hole, ledges formed by hard stringers, doglegs and key seats, swelling clays, high pressured formations caving and closing in on the wellbore, etc. When pipe is being raised or lowered, the bouyancy factor of the drilling fluid has to be taken into consideration, since it will either supporting or resisting pipe movement. In order to lift the pipe, the mud resists pipe movement, so this resistance has to be overcome. The resulting hookload is therefore

greater than the actual string weight. When the pipe is being lowered, part of the string weight will be supported by the mud so that the hookload will be less than the actual string weight. If tight spots or sections are encountered, the change seen in the ‘effective’ hookload depends on whether the pipe is being raised or lowered.

• When being raised, additional resistance has to be overcome in order to lift the pipe. This additional hookload is termed overpull.

• When the string is being lowered, what happens in effect is that part of the string weight will be

supported by the tight spot, so that the measured hookload will decrease. This is known as drag.

compression

tension

compression

neutral pt

DC Weight < WOB DC Weight > WOB



186

Other factors that should be considered when monitoring hookload and WOB include: - • Drag and overpull will, virtually always, be seen in deviated and horizontal wells, since much of the

drillstring will be ‘lying’ against the wellbore. This, again, will support part of the string weight when running in the hole, and friction will resist the string being lifted when coming out of the hole. The degree of overpull and drag will, nevertheless, normally produce a constant trend, deviations from which will be an indication of tight spots.

• For the same reason as detailed above, when the string is lying against the wellbore in deviated wells,

weight will not be transferred through to the bit as in vertical wells. The weight being indicated at surface, will not be the same as the actual weight that is being applied at the bit. This will limit the effectiveness of any calculations that include WOB. For example, a drilling exponent trend, used to determine the drillability of formations and identify changes in formation pressure, can be unreliable since the WOB that is partly responsible for the drill rates achieved, is not accurately known.

• The use of floats or “inside BOP’s” placed inside the drillstring will affect it’s buoyancy since mud is

prevented from entering the string when the pipe is being run in the hole. This is analogous to the different buoyancy effects on a hollow object as opposed to a solid one.

string in slips string lifted

Tripping out of hole

decreased depth, stands pulled

theoretical string weight

overpull

Tripping into hole

string in slips string lifted

drag

theoretical string weight

increase depth, stands run

Actual hookload

Actual hookload



187

10.3 Rotary Speed and Rotary Torque

10.3.1 Rotary Speed Rotation can be applied to the bit from the surface or from downhole turbine motors. Surface rotation can be provided through the rotary table and kelly, or through power swivels or top drives (see section 2.1). The rotary speed (revolutions per minute or RPM) is measured by a proximity sensor that detects a metallic target attached to the rotary table, rotary drive shaft or rotating element of the top drive. A pulse, or signal, is produced each time the target passes the sensor. Rotation applied from downhole motors, or turbines, is dependent on the flowrate of the mud passing through the motor. The faster the flowrate, the more rotations are produced.

For example, if a turbine generates 1 rotation for every 10 litres of fluid that passes through it (0.1 revs/litre): -

Circulating flowrate = 1.5 m3/min (1500 litres/min) Therefore, the mud motor RPM = 1500 x 0.1 = 150 RPM Mud motor RPM is therefore determined numerically, from multiplying a factor (revolutions per unit volume of fluid – this number can be provided by the motor operator) by the flowrate measured at surface (pump speed x pump capacity). Depending on the type, size, strength and the type of bearing assembly, bits have specific ranges of rotation to prolong bit life and achieve optimum penetration. A change in RPM has a direct effect on the penetration rate, as already described. From a mud logging point of view, monitoring the rotary speed enables the mud logger to determine whether or not changes in the rate of penetration are due to changes in RPM.

10.3.2 Rotary Torque Torque is a measure of the force required to produce a given rotation of the bit and string. There is a direct relationship in that the torque will increase if the rotary speed is increased. Similarly, slower rotary speeds will see lower torque. Measurement of the torque will vary depending on what type of power source drives the rotary system. Rotary tables may be electrically or mechanically driven. Top drives may be electrically or hydraulically driven. With electrical systems, the torque is represented

Torque Clamp



188

by the amount of electrical current that is required to drive the table. It is determined with a simple torque clamp that measures the magnetic field induced around the power cable. With mechanically driven rotary tables, the tension produced in the rotary drive chain changes as the torque changes. This tension is simply measured with a pressure transducer (the principle is the same as the load cell measuring the changes in tension on the drill line in order to determine hookload. A standard hydraulic pressure transducer is all that is required to measure torque in hydraulically driven systems. The unit of measurement of rotary torque is the force that is applied against the distance moved, for example, Newton Metre (Nm) or Foot Pounds (ft lbs). If an electrical measurement is obtained, the torque can be expressed in terms of current (Amperes), or it can be converted to a force-distance unit. However, this conversion is non-linear and will vary from rig to rig depending on the power and rotary equipment. A conversion table, or graph (see below), can be obtained by the toolpusher or rig mechanic.

All other conditions being the same, rotary torque will increase with depth since the length of drillstring and therefore contact with the wellbore increases. Friction acts against the rotation, so that with more pipe-wall contact, more force is required to produce the same rotation. A change in rotary torque is a measure of the change in frictional forces acting against the rotation and may result from mechanical changes, mechanical failure or downhole changes. Different types of bit and cutting surfaces also result in different torque measurements (in terms of maximum, minimum and frequency), but nevertheless, torque provides very useful information both in terms of formation evaluation and hole condition. It is therefore important that changes in torque are evaluated and the cause determined. Increases in torque may be seen as a result of: -

• Increase in WOB • Increase in RPM • Bit wear

amps

ft lbs

5000

10000

15000

20000

25000

100 200 300 400 500 600

15

30

50

57.5 49

Example of Torque conversion (ftlbs per amp)



189

• Worn or failed bearings • Loss of cones • Poor bottom hole cleaning resulting in bit balling • Tight hole, pipe sticking. In this situation, sticking pipe can lead to high torque, even

stalling of the rotary table, and the risk of string failure, or twist-off, is significant. • Increases in formation pressure • Hole deviation • Fractures, typically leading to high, erratic torque.

10.3.3 Formation evaluation and fracture identification Changes in torque character may also be seen as a result of lithology changes such as hardness, abrasiveness, granularity etc, but the exact change will also depend on the type of bit. For example, a toothed tri -cone bit suited to softer formations would generally show lower and relatively consistent torque when drilling a claystone, whereas a cemented sand stringer would normally result in higher and more erratic torque (see example on the right). A PDC bit, on the other hand, may show completely different torque patterns and such a pronounced change may not be seen. Torque is also a useful tool in the identification of fractures. These are very difficult to identify with wireline or LWD (logging while drilling) tools, but easily identified through drilling and mud logging fractures. There are several applications or benefits in identifying fractures:

• Potential of lost circulation • Possible associated high pressure gas • Enhanced production possibilities

Typically, fractures can be identified through the torque increasing and often becoming more erratic (greater amplitude, or the difference between the maximum and minimum torque). The exact change will be dependent on the size of the fracture, the nature of any infil and it’s inclination to the wellbore. In addition to the change in torque, a fracture will also result in higher, possibly more erratic, ROP. Seeing these two changes, the mud logger has been alerted to the possibility of lost circulation, associated gas and possibly even a kick, so will be monitoring for any indications of these events.

10.3.4 Sticking Pipe Increasing torque is often an early indication of tight hole situations since there is increased friction and resistance to pipe/bit rotation. The normal relationship between torque and RPM is a direct one, i.e. both will increase or decrease simultaneously.

torque



190

This will lead to an increase in torque as more force is required to maintain the rotation. If the situation worsens, the rotation may slow down or even stall completely. When rotation is prevented to this degree, an inverse relationship between the rotary speed and torque will be seen, since higher force or torque will be required in order to get the string rotating again. This situation is analogous to a high force being required to move a stationary object but once moving, a lesser force is required to maintain momentum. The problem that may occur from this situation, very high torque and stalling rotary, is twisting off of the bit or part of the drillstring, i.e. the torque may be high enough to break a connection.

10.3.5 Torsional Vibrations Torsional vibrations in the drillstring can be extremely damaging to the string and bit and require high resolution monitoring of surface torque to detect. High frequency and high amplitude oscillations can be detected to indicate the occurrence of torsional vibration. Torsional vibration occurs when the rotation of the string is slowed down, or stopped, at the bottom, then released as torque builds up to a level that is sufficient to overcome the friction resisting the string rotation. Associated with this behaviour is the alternating acceleration and deceleration of the BHA and bit, with repeated twisting of the more flexible drillpipe section. Stick slip is the severest form, where the bit and BHA come to a complete halt until twisting of the drillpipe by the surface motor produces sufficient torque to free the pipe. The bit then spins free at a vastly accelerated rate, then gradually slowing down to the speed observed at surface as the energy is dissipated. Such vibrations are common when drilling in hard, abrasive lithologies, especially if the hole is deviated and more common when drilling with tri-cone bits. They are extremely detrimental to the drilling operation, leading to fatigue, damage or failure to bit cutters, drillstring, BHA and downhole tools; reduced ROP, washouts or twist offs, costly fishing trips and equipment replacement.

increasing torque

rotary stalling

Rotary Speed Rotary Torque

Time



191

10.4 Pump or Standpipe Pressure The circulation system can be considered as a closed system and in order to move the drilling fluid around that system requires force. This force is delivered by the pumps, which are set to run at a specific power rate (horsepower) and the result will be a produced pressure loss. Horsepower is a function of pressure loss, and as the mud moves around the system, drops in pressure will occur as a result of friction. Since the system is effectively a closed system, the pressure produced by the pump as a function of the power being delivered will be equal to the sum of the pressure losses occurring around the system.

Standpipe pressure = Total System Pressure Loss = Pressure lost through surface lines + Pressure lost inside the drillstring

+ Pressure lost in the annulus + Pressure lost at the bit The pressure is measured by a hydraulic transducer that is normally located on an ‘end valve’ situated on a manifold at the base of the standpipe. This ‘valve’ is known as a knock-on head because it has to be fully tightened with the aid of a sledge hammer! Inside the knock-on head, a rubber diaphragm separates the circulating mud from hydraulic fluid. Changes in the pressure will act on the diaphragm and these changes are transmitted hydraulically to the pressure transducer.

Normal units of measurement are KPa kilo Pascal PSI pounds per square inch kg/cm2 kilogram per square centimetre 1 psi = 6.894 KPa = 0.0703 kg/cm2 = 0.0689 bars The pressure rating of the standpipe sensor is typically 5 to 10000 psi (approx 35 to 70000 KPa) The measured standpipe pressure is dependant on a number of parameters: -

• Density of the mud The higher the density, the higher the pressure

• Mud viscosity The higher the viscosity, the higher the pressure



192

• Flowrate The faster the flowrate and annular velocity of the mud, the

higher the pressure

• Depth Pressure will increase with depth since annular and drillstring sections are increasing, therefore increasing frictional pressure losses

• Pipe and hole diameters The smaller the diameters, the larger the pressure

• Bit nozzles or TFA The smaller the nozzles or flow area of the bit, the larger the

pressure

• Efficiency of pumps and surface equipment - any leaks will cause a drop in standpipe pressure If the above conditions are kept constant while drilling, the standpipe pressure will show a very gradual increase as drilling proceeds and the hole is deepened. Changes in standpipe pressure may be caused by the following conditions: - • Loss of circulation If mud is being lost to a permeable or fractured formation, there

will be a reduction in pressure. • Gas cut mud If a large quantity of gas is held in the mud and not removed at surface, there will be a reduction in pressure as a function of the reduced mud density. • Influx of formation fluid In the event of a kick, an initial increase in pump pressure may

be seen. This will be followed by a gradual decrease as the influx feeds in and rises in the annulus. This is a function of the influx (in particular, a gas influx) reducing the mud weight and hydrostatic pressure in the annulus.

• Plugged or washed out nozzles Causing an immediate, dramatic increase or decrease. • Washout in the drillstring A hole or crack that results in a gradual decrease. The pressure decreases more rapidly as the size of the washout increases. • Bit or pipe twist off This will cause an immediate, dramatic drop due to the large

larger flow area in comparison to the nozzles. • Hole packing off If the walls of the wellbore are closing in on the drillstring, restricting circulation, a pressure increase will result. • Mud Condition If mud density and/or viscosity is not consistent throughout the system, erratic pump pressure may be seen. This ‘patchiness’



193

may be as a result of poor surface treatment; variable solids content; remnants of viscous or hi/low density mud pills. Similarly, muds may be prone to aeration or foaming, causing drops in pump pressure.

• Downhole tools Failing or malfunctioning tools such as motors or MWD tools will result in pressure spikes or erratic pressure. High torque will also cause pressure spikes from such downhole tools. • Increased ROP A significant increase in ROP will load the annulus with more

cuttings leading to a pressure increase. • Increased WOB This is a function of the bit being ‘buried’ more into the bottom

of the hole, restricting the flow of mud from the bit nozzles. At the start of a new bit run, a sequence of changes in the pump pressure will be seen: -

• A gradual increase as the pipe is filled, following the last part of the trip, and circulation is established.

• An increase in pressure as the bit comes on bottom and weight is applied.

• Pressure will slowly increase towards the bottoms up time as cuttings, that have settled at the

bottom of hole, arrive at surface.

• Conversely, if there is a large amount of trip gas, a reduction in pressure may be seen.

• After bottoms up, the pressure should drop (or increase) back to a normal “background” level.

• During the initial part of the bit run, a gradual decrease may be seen as the temperature of the mud increases and any gelling of the mud, while it was static, is broken down with a resulting reduction in viscosity.



194

10.5 Annular or Casing Pressure Pressure on the annular side of the wellbore (as opposed to the standpipe pressure monitoring the pressure inside the drillstring) needs to monitored in the following operations: -

• Shut in pressure during well control • Casing pressure tests • Leak Off or Formation Integrity tests • Formation pressures during well testing

An identical type of hydraulic pressure transducer, typically in the range of 10 to 20000 psi is used to read the pressure on the annulus. The sensor is normally located at a point on the choke manifold so that pressures can be monitored when the well is shut in and opened up to the choke line. During a well control situation, where an influx of formation fluid into the wellbore has occurred due to formation pressure exceeding the hydrostatic pressure of the mud column (this may have been caused by an increase in formation pressure or by a reduction in mud hydrostatic), it is important to know the pressures on both the annulus and the drillstring. Thus, knowing the shut-in drillpipe pressure (SIDPP) and the shut-in casing pressure (SICP) allows the following information to be determined: -

• Formation pressure and mudweight required to control the well (kill mudweight) • Kill circulation pressure requirements • Monitoring of pressures as the influx is removed from the wellbore • The size and type (ie gas, water, oil) of influx



195

10.6 Pump Rate and Output The volumetric output of the pump, and the rate at which mud is being pumped into and around the wellbore, is an important parameter in drilling and logging procedures. The stroke or pump rate (typically strokes per minute or SPM) is easily measurable by any pump stroke counter. This may be a proximity sensor (as shown below) or some form of a rod/microswitch that is activated by each stroking motion of the pump. Rig pumps can either be triplex or duplex types: - Triplex pumps (as shown above) have three chambers from which mud is displaced on the forward stroke of the piston only. The volume of mud displaced on each stroke (pump volume) is dependent on the diameter of the liner that holds the mud and the stroke length of the piston displacing the mud. This, effectively, gives a cylindrical volume equal to the volume of the chamber. The movement of the pistons is such that, at any one time, they are at different points of their stroke ensuring a continuous output of mud, i.e. when one piston is at the end of the forward stroke having emptied the liner and displaced the mud, another piston is at the end of the backward stroke having it’s liner refilled with mud; the third piston will be at an intermediate point. Duplex pumps have only two chambers, but have a reciprocating action, displacing mud on both the forward and backward stroke of the piston. As the piston moves forward displacing mud from the liner, mud is refilling the liner behind the piston. This mud will then be displaced on the backward stroke. The volume of the piston rod therefore reduces the actual volume of mud displaced from the liner on the backward stroke.



196

10.6.1 Pump Output Calculation Cylinder Volume = ππππ.r2.L

Pie, radius to diameter conversion, unit conversions and the number of chambers are all accounted for in the following equations:

Triplex Pump These possess 3 pistons/cylinders, but only displace mud on the forward stroke. Pump Output can be determined in the following units: -

m3/stroke = 0.785 x D2 x L where D = pump liner diameter (m) L = stroke length (m)

bbls/stroke = D2 x L where D = inches 12352.8 L = inches gallons/stroke = 0.010198 D2 L D = inches L = inches litres/stroke = 0.0386 D2 L D = inches L = inches Duplex Pump These possess 2 pistons/cylinders, with output on forward and backward stroke. The piston volume reduces the output volume on the backward stroke. Pump Output = Forward Output + Backward Output

Forward Output = 0.785 x D2 x L where D = pump liner diameter (m) L = stroke length (m) Backward Output = 0.785(D2 – d2) x L where d = piston diameter (m) Or: gallons/stroke = 0.0136 x ((D2 – (d2/2) x L where D = liner diameter (in) d = piston diamter (in) L = stroke length (in) litres/stroke = 0.0515 x ((D2 – (d2/2) x L all units are inches



197

The pump outputs calculated are for one stroke and assuming that the pumps are 100% efficient. In practice, this is not so, and the actual efficiency of the pumps can usually be ascertained from the driller, derrickman or toolpusher. Typical figures are 95 – 97% efficiency. Then,

Pump Output / stroke = pump output x efficiency Pump Output / minute = pump output x efficiency x SPM

10.6.2 Lag Calculations Now that we know the volume of mud displaced by each stroke of the pump, if we know the volume of the wellbore, we can calculate how many pump strokes will be required to move the mud around the entire system. In the same way, if we know the pump rate, we can also determine the time that this will take. The length of time that the drilling fluid, or mud, takes to be circulated from the surface to the bottom of the hole and back to the surface again is known as the total circulation time. This time can be broken down into two components, the downtime (surface to bit) and the lag time (bit to surface). Total Circulation Time = Downtime + Lag Time This information benefits several important applications: - Lagging Samples By knowing how long it will take for the mud to be pumped from the bottom of

the hole to the surface (lag time), we can determine exactly when specific samples will reach surface, or, similarly, determine the exact depth that specific samples correlate to. This is the principle tool in lithological interpretation since the cuttings and gas sampled at surface can be directly related to a given depth and perhaps confirmed by any changes in penetration rate or torque when that depth interval was drilled.

Such lagging of samples should always be based on the strokes required rather than the time, since the pump rate may change. If the pump rate were to be increased, the lag time would obviously decrease.

Hole Washouts If the observed lag time is greater than the calculated lag time (this can be

determined by actual lag checks or by the appearance of gas corresponding to lithological changes that are indicated by a change in ROP at a given depth), then it can be deduced that the hole size is greater in places than the actual size of the bit. Such hole washouts can typically occur beneath casing seats or in unconsolidated formations that are easily eroded by the action of pipe movement or mud circulation.



198

Spotting Pills Knowing the output of the pump and the volume of the drillstring and annular sections enables the driller to determine exactly the number of pump strokes required to ‘spot’ special ‘pills’ of fluid at precise positions anywhere in the wellbore.

Cement Jobs Firstly, the occurrence of washouts and the overall profile of the hole will be

determined precisely with an electrical caliper log so as to calculate the volume of cement required to fill the annulus around the casing. When this volume of cement has been pumped down into the casing, the precise number of strokes required to displace that cement has to be known.

Well Control Knowing the precise position of the kill mud and related changes in pressure is a

critical part of safely controlling kicks. We therefore need to know exactly the number of pump strokes required for the kill mud to reach the bit, the casing shoe and surface.

Down Strokes = Drillstring Capacity / Pump Output (per stroke) Lag Strokes = Annular Volume / Pump Output (per stroke) These strokes can then be expressed in terms of the time required by comparison with the stroke rate of the pumps: - Downtime = Down Strokes / Pump Rate Lagtime = Lag Strokes / Pump Rate The first stage in these calculations is the determination of how many string and annular sections there are: - In the following well profile example, you can see that there are 3 separate annular sections (assuming that the drillpipe and heavy-weight have the same outside diameter) and 3 separate drillstring sections. Lag Strokes = Total Annular Volume / Pump Output Down Strokes = Total Drillstring Capacity / Pump Output The calculation of these volumes is then based upon simple geometry, i.e. calculating the volume of cylinders: -

• Drillstring Capacity is the volume of the cylinder defined by the length of the section and by the internal diameter of that section of pipe.

• Annular volume is the difference in the volume between 2 cylinders. The larger cylinder is that

defined by the length and either the hole diameter or casing internal diameter. The smaller cylinder is that defined by the length and the outside diameter of the pipe.



199

So, where OD = “hole diameter” or “inside diameter” of casing ID = “outer diameter” of drillpipe/collars Annular Volume Calculations in Barrels BBLS = OD2 - ID2 x L D in inches 1029.4 L in feet BBLS = OD2 - ID2 x L D in inches 313.76 L in metres Annular Volume Calculations in Cubic Metres M3 = OD2 - ID2 x L D in inches 1973.5 L in metres M3 = OD2 - ID2 x L D in mm 1273223 L in metres

M3 = 0.785 (OD2 - ID2) x L All units in metres The same formulae would be used for calculating the drillstring capacities, but here: - OD would represent the internal diameter of the pipe ID would be equal to 0.

Annular Sections Drillstring Sections

Casing ID – Drillpipe OD

Hole Diameter – Drillpipe OD

Assuming that the standard and heavy weight drillpipe have the same OD’s

Hole Diameter – Drill Collar OD

Drillpipe ID

Heavy Weight ID

Drill Collar ID



200

Lag Checks The lag can be checked by adding a tracer to the mud, in the top of the drillpipe when a connection is made. The precise number of strokes (down plus lag) for the tracer to arrive back at surface, are known, so these can be counted as circulation proceeds. If the tracer arrives back at surface after this number of strokes has passed, then there is an enlargement in the hole, due to a washout or due to being overgauge. Tracers may include gasoline, with the lag check requiring the identification of a gas response on the return to surface, or they may be visual tracers such as flagging tape, rice, dye, etc. Before putting anything into the string that will be pumped into the hole, such lag checks should always be confirmed with the operator. Standard Conversions 1 inch = 25.4mm 1 metre = 3.2808 ft 1 foot = 0.3048 m

1 m3 = 6.2897 bbls 1 m3 = 1000 litres

1 bbl = 42 US gallons

1 bbl = 159 litres 1 bbl = 0.1589 m3

1 US gallon = 3.7853 litres 1 litre = 0.264 US gallons



201

10.7 Flowrate and Pit Levels As previously stated, the circulating system can considered as a closed system and the rate that mud exits the annulus should be the same as the rate that the mud enters the drillstring. We have already seen how the flowrate into the hole, via the pump, standpipe and drillstring, is determined from the pump rate and the pump capacity: - Flowrate Q = SPM x Pump Capacity x Efficiency The flowrate out of the hole is typically determined in the flowline, which connects the wellhead to the shaker box. Typically, the deflection of a paddle, or the speed of a turbine, is used to determine the flowrate. Rather than an actual volume rate determination, the measurement is usually done qualitatively. For example, when using a flow paddle, full deflection would represent 100% flow and zero deflection, with the paddle at rest, obviously represents zero flow. For a given constant pump rate, the flowrate out of the hole (MFO) should also remain a constant. Should there be any change in fluid flow downhole, this parameter is a primary indicator. For example: - A reduction in MFO – fluid loss to fractures, lost circulation An increase in MFO – formation fluid influx, kick Pit (mud tank) levels are monitored for a similar reason, primarily. With no changes in pump rate, the volume of mud in the tanks (lined up to the hole, the active or suction part of the pit system) will only drop according to the volume required to occupy the newly drilled hole. Any deviation from this trend can again indicate a change in conditions downhole, either a drop in mud volume indicating a mud loss to the formation, or a pit volume increase indicating a formation fluid influx. Pit volumes are monitored by way of two types of sensor, ultrasonic or delaval floats. The ultra sonic sensors are mounted on top of the pit gratings sending sonic pulses, which reflect back from the mud surface to the sensor. The two way signal is processed and calibrated in terms of distance from the sensor, which, in turn, can be converted to the equivalent mud volume. The operator has to be



202

careful about the placement of the sensor, avoiding locations that would produce a turbulent mud surface and erratic signals, such as proximity to flowline ingresses or agitators. Delavals consist of a float, mounted on a steel “pole”, that rises and falls with the changes in mud height. As it does so, it passes magnetic sensors inside the pole – these determine the position of the float, the height of which is calibrated to the equivalent mud volume.

As well as being a primary indicator of mud losses or fluid influxes while drilling, pit levels are also monitored in many other operations, for example: -

• Mud displacements during trips in and out of the hole. • Mud displacements while running casing, ensuring no mud is lost due to pressure surges

breaking down the formation. • Mud displacements while pumping cement, again to ensure the heavy cement is not causing a

formation breakdown, resulting in mud loss. The mud logger must also be aware of many other causes of changes in mud level, to avoid making false alarms and to identify errors in mud movement which could result in surface leaks and environmental contamination: -

• Additions of new base fluid (water, diesel, oil, etc) or chemicals. • Transfers between pits or from an outside source. • Valves being left open in error. • Surface line volume (flow back into pits when pumps are turned off; filling the lines when pumps

are switched on). • Similar changes when surface equipment, such as centrifuge and desilters are switched on or off. • Apparent change when agitators are switched on or off. • Wave motion on offshore floating rigs. • Reballasting, or trimming, offshore floaters.



203

11 MUDLOGGING PROCEDURES 11.1 Cuttings Descriptions After sample preparation, including sifting and washing, cuttings should be viewed, on a tray, under a microscope using white light. The sample should be viewed, initially, while it is still wet, to accurately describe colors. Cuttings descriptions should follow a standard format, as detailed below. Note, abbreviations are not used for the purposes of this manual, since operators often have different requirements over their use. The order of a full cuttings description should be:

1. Rock type and classification 2. Color (and/or lustre) 3. Texture, including size, shape, sorting 4. Cement or matrix 5. Hardness 6. Fossils and accessory minerals 7. Sedimentary structures 8. Porosity 9. Oil shows

11.1.1 Rock Type and Classification i.e. Carbonate rocks such as limestone, dolomite, marl Siliceous rocks such as siltstone, sandstone, sand, chert Argillaceous rocks such as claystone, clay, shale, marl Carbonaceous rocks such as coal, lignite, anthracite Textural classification, if possible, should be included, such as lithic, oolitic, grainstone, packstone, etc.

11.1.2 Color This may describe the mass effect of all constituents, or describe specifics such as grain or crystal color, cement color, etc. Proper color charts should be used, so that all descriptions are consistent between different personnel. Qualifiers such as dark, light, medium, translucent, etc should be used according to such charts. Colors may also be described for a specific pattern such as mottled, spotty, banded, etc. Carbonaceous rock descriptions should also include the lustre, which can be described as dull, earthy, shiny, vitreous or sub-vitreous.



204

11.1.3 Texture

Carbonate Rocks This should include crystal size and shape, together with any other significant texture: -

Crystal Size (mm) Classification 1 – 2 very coarse 0.5 – 1 coarse 0.25 – 0.5 medium 0.125 – 0.25 fine 0.063 – 0.125 very fine 0.004 – 0.063 micro-crystalline < 0.004 crypto-crystalline

Crystal shape includes euhedral, sub-euhedral, anhedral, fibrous. Other textures include waxy, vitreous, amorphous, earthy, sucrosic, chalky, vuggy, stylolitic.

Siliceous Rocks This should include grain size, shape according to sphericity or roundness, and the degree of sorting: - Grain Size (mm) Classification

1 – 2 very coarse 0.5 – 1 coarse 0.25 – 0.5 medium 0.125 – 0.25 fine 0.063 – 0.125 very fine 0.002 – 0.063 silt < 0.002 clay/shale

Sphericity compares the surface area of the grain to the surface area of a sphere of the same volume. In practice, this describes the axial comparison. Elongate One axis considerably longer than the other Sub elongate Sub spherical Spherical Axis of similar lengths Roundness describes how smooth, or angular, the edges of the grain are.

Angular sharp, no wear Sub angular Sub rounded Rounded Well rounded no original faces or edges, just smooth curves



205

Sorting compares the distribution of varying grains and includes all of the above textural comparisons. Descriptions include poor sorted, moderately well sorted, well sorted.

Argillaceous Rocks Textures, here, include amorphous, blocky, sub blocky, fissile, sub fissile, dispersive, splintery.

Carbonaceous Rocks Texture descriptions for carbonaceous rocks include fracture type or cleating: - Angular, conchoidal, sub conchoidal, uneven, cleating.

11.1.4 Cement and Matrix Cement is a chemical precipitate deposited around grains, or as growths on grains. Cements may be siliceous, calcareous, dolomitic, quartzic, anhydritic, gypsiferous or pyretic and can be qualified with the degree of cementing, such as unconsolidated, poorly cemented, moderately well cemented or well cemented. Matrix is small grains or infil that are mechanically deposited between grains. The matrix may be argillaceous, calcaraeous, dolomitic, gypsiferous, kaolinitic or silty. Carbonaceous rocks may also include argillaceous, bituminous, pyritic, sooty, sandy, silty, waxy.

11.1.5 Hardness This describes the overall hardness of a rock, rather than the hardness of individual grains, for example. Descriptions include: - soft, firm, moderately hard, hard, very hard

loose, friable, brittle indurable (resistance to breakdown), poor, moderate or well indurated

plastic, poor, moderately or well compacted (argillaceous)

11.1.6 Fossils and Accessory Minerals Fossils may include algae, bryozoa, echinoids, foraminifera, ostracods, molluscs, sponges, coral, plant remains, oolites. Accessories may include anhydrite, glauconite, pyrite, biotite, chert, feldspar, lignite, siderite, olivine, halite, gypsum, kaolinite, sulphur, argillaceous, calcareous, siliceous, etc



206

11.1.7 Sedimentary Structures Generally, these would be difficult to identify in drilled cuttings, but may include laminations, micro-laminations or bands.

11.1.8 Porosity This should include an estimation of the percentage porosity and the types of porosity present.

Siliceous Rocks Porosity, here, may be: -

Intergranular - none (tight), poor, fair, good, excellent Moldic - resulting from the leaching of soluble grains Fracture

Carbonate Rocks Porosity types include: - Inter-crystalline Inter-particle, inter-oolitic Inter-granular Moldic, pel-moldic Vuggy, where the pore space is generally larger than particle or crystal size. Fracture

11.1.9 Chemical Tests

HCl Effervescence A quick test can be made, with dilute (10%) hydrochloric acid, to distinguish between calcite and dolomite. Separate the cuttings from the sample tray, placing in a porcelain spot tray. Add a few drops to the sample and view the results: - Calcite Immediate and violent effervescence, completely dissolving the sample Dolomite Delayed and slow effervescence, increasing on heating the sample Mixture Intermediate reaction

HCl Oil Reaction If oil is present, large bubbles will form on a cutting when it is immersed in dilute HCl.



207

Swelling Significant swelling, or flaking, in water is characteristic of montmorillonite or smectite clays, distinguishing them from kaolinites and illites. On adding distilled water, swelling can be described as follows: - Non swelling No break up Hygroturgid Random swelling Hygroclastic Swelling into irregular pieces Hygrofissile Swelling into flakes (flaking) Cryptofissile Sweeling into flakes after adding dilute HCl Swelling clays will also tend to be soft and sticky (although oil-base and inhibitive mud systems will prevent swelling) making sample washing very difficult. Dispersed clay will often result in sample preparation making description very difficult.

Sulphate Test – Gypsum and Anhydrite To determine the presence of gypsum or anhydrite, use the following procedure: -

• Crush 2g of washed, dried, sample and place in a test tube • Add 5ml of dilute 10% HCl • Heat • Filter off residue and place in clean test tube • Add approximately 10 drops of Barium Chloride (BaCl2)

If a white precipitate forms, then the sample is indeed a sulphate, either gypsum or anhydrite. To distinguish between the two, it should first be noted that gypsum is not so common in the subsurface, therefore, the sample will typically be anhydrite. Also, anhydrite is commonly associated with dolomite. However, to confirm the distinction, use the following procedure: -

• Heat the same residue until evaporation begins • Leave for 15 minutes

If the sample is gypsum, fine fibrous crystals will form.



208

Chloride Test To confirm the presence of salt, or Halite (NaCl), the logger can, if he chooses, taste it! If not, the following test can be used: - Crush 2g of washed and dried sample, place in test tube Heat in distilled water and filter off the residue Place the residue in a clean test tube Add 10 drops of Silver Nitrate (AgNO3) If a white precipitate forms, then chlorides are confirmed.

Alizarin Red This is another test to distinguish calcite and dolomite. This can simply be dropped on to cuttings samples – if calcite is present, it will turn a deep red. Everything else remains uncoloured.

Cement Test After drilling through casing shoes at the start of a new hole section, it is useful to confirm the presence of cement. As it is alkaline, this can be done by adding phenolpthalien (a pH indicator) after washing the sample. If “cuttings” turn a bright purple, then they are cement.



209

11.2 Oil Shows Evaluation of oil shows, in the cuttings, include the description of odour, staining, bleeding, fluorescence, leach tests, residues, etc.

11.2.1 Odour The smell should be described in the range faint, fair to strong, since this would normally distinguish between condensates, light oils and heavy oils.

11.2.2 Oil Staining and Bleeding Typically, if bleeding is seen in the drilled cuttings, it is an indication of a tight formation since the hydrocarbons have been retained. Good permeability would typically result in most hydrocarbons being flushed. Oil staining is more representative of porosity and oil distribution. Descriptions of the staining should include color and distribution. Heavier oil stains trend to be a dark brown, while lighter oil stains tend to be light to colorless. Live, volatile oil will smoke and smell when held in a flame; the flame will typically turn blue. The amount of oil staining should be characterized in terms of none, rare, common, abundant etc, and the distribution described as spotty, patchy, streaky or uniform. Dead or residual oil is typically characterized by a dark or black asphaltic residue. The presence of solid hydrocarbons such as tars and waxes should be recorded. These bituminous deposits, recognized by their black, often opaque appearance, nodular or specked occurrence, brittle appearance but plastic texture, may be indicative of residual oil deposits or may be an indication of a potential source rock. Either way, their appearance is important and should be noted.

11.2.3 Fluorescence When crude oils are exposed to ultra-violet light, aromatic molecules absorb the radiation and, in doing so, are excited to a higher energy state. The molecules return to their original condition by releasing this energy through electromagnetic radiation. This is what is known as fluorescence. The fluorescence is assessed in terms of concentration, it’s colour and intensity, in order to evaluate the oil type and production potential. However, there are limitations to this process, making it at best, a qualitative assessment: - • Results are subjective, not only in the consistency and accuracy to which the test is performed but,

also, to any deficiency in colour perception of the geologist. Many other materials fluoresce and these have to be eliminated by the geologist and not mistaken as oil fluorescence.



210

• Only a small proportion of the fluorescence resulting from the exposure to UV light is actually

visible to the naked eye. Much of the emissions actually fall in the ultra-violet range of the spectrum and so will go undetected by the conventional technique, thus adding further to the tests’ subjectivity.

• Due to time constraints, complete testing will only be done on a handful of cuttings. The main test

will be confined to what is visible on the surface of the cuttings and to what may leached through a solvent cut. This test is not, therefore, necessarily representative of the full amount of oil in the formation.

Sample Preparation The cuttings should be washed and immediately viewed (volatile components will be lost as the sample is sat waiting to be viewed – fluorescence should be the first property to be checked in a new sample).

• Sample trays should be clean and free from contaminants (note that even some types of tissue paper used for drying may fluoresce, making the geologist’s job more difficult).

• The cuttings must be cleaned of any drilling fluid that may still be coating the grains.

If an oil based mud is being used, samples of the base fluid, whether oil, diesel or base oil, together with the actual mud sample, should be collected routinely so that their background fluorescence can be compared to fluorescence emanating from the sample. Typically, diesel and other base fluids exhibit only a dull brown fluorescence if at all. However, oil obviously has a high solubility for hydrocarbons that originate from the formation. Oil will remain dissolved within the drilling fluid unlike gases that will be liberated either immediately or subsequently. This additional component will add to the fluorescence of the drilling fluid and do so for the remainder of the well and even move onto further wells should the mud be re-used. The background fluorescence of the mud can therefore change, so that it is crucial that regular samples be viewed in order to identify ‘fresh’ shows. Firstly, view the sample quickly under the microscope for indications of oil staining, residual deposits or even bubbling gas. Any cuttings with obvious staining should be separated and viewed under the UV fluoroscope.

Contaminants Many contaminant materials or minerals will fluoresce in addition to hydrocarbons. The geologist must therefore be very vigilant in identifying relevant oil fluorescence and separating individual cuttings for further testing. Mineral fluorescence should be easily identifiable by viewing the cuttings under the microscope, but if an error is made minerals will give no solvent cut. Minerals Carbonates typically show a yellow to brown fluorescence.

Anhydrite or gypsum give a grey blue fluorescence. Contaminants pipe dope (gold, bluish white depending on composition), diesel or base oil, mud

additives, some rubbers and plastics



211

After identifying the hydrocarbon bearing cuttings, separate them and place into spot dishes for more thorough examination and testing under UV light.

• During this separation, the cuttings should not be touched by hand so as to prevent contamination.

• Before testing with solvent, the cuttings should preferably be dry since any coating of

water may prevent the solvent from penetrating the lithology effectively. If the sample is tested wet, alcohol can be used with the solvent to remove the water and allow the solvent to ‘get to work’.

Colour and Brightness Colour enables an approximation to be made of the oil gravity whereas the brightness (reduction or dulling) can be an indication of the presence of water. A less bright, or duller fluorescence may be indication of a water bearing formation. If, for example, a bright bluish fluorescence has been observed through a reservoir section, then exhibits a duller intensity, it is likely that the well has passed through the oil/water contact. In terms of fluorescence colour, an approximation can be made to the oil gravity.

• The lower the API gravity (higher density), the darker and less intense the fluorescence.

• Very high gravity oils and condensates may not fluoresce at all in the visible spectrum. Typically observed fluorescence, in relation to the API degree, are listed below: - Oil Bright fluorescence, colours ranging with API gravity Very low gravity red brown, low intensity, typically not visible Low API gravity red brown to orange brown, low intensity Medium API gravity gold, green, cream to yellow High API gravity blue white, blue

Condensate Bright, violet fluorescence, often speckled, violet Often not visible since fluorescence is completely in the ultra-violet

Fluorescence Distribution An estimation of the percentage of florescence observed in both the entire sample and in the particular reservoir rock alone, should be made, along with the type of distribution. Firstly, the distribution should be described in terms of rare, common or abundant and then qualified by adjectives such as even, uniform, patchy, pin-point, etc.



212

As well as the percentage of cuttings fluorescing in the complete sample, the geologist should estimate the percentage of reservoir cuttings, alone, that exhibit fluorescence. This is very difficult in practice but a very important distinction, especially when the zone is first penetrated. It is meaningless and misleading to say that the sample has 10% fluorescence if only 20% of the sample is made up of the reservoir rock. In this particular instance, 50% of the reservoir rock is fluorescing, much more exciting news than the reported 10%!

Solvent Cut Solvents, such as di-chloroethane, are used to yield information about the fluid mobility and permeability. The test is conducted very simply by adding a few drops of the solvent directly onto the isolated cutting (while the sample is being viewed under the UV fluoroscope). The solvent effectively leaches the cutting, taking the oil into solution and removing it from the cutting. This may allow for better determination of the fluorescence color since there is no obstruction or interference from the cutting. • Speed of the cut The speed and nature of the cut reflects the oil solubility, permeability and overall fluid mobility. A rough rule of thumb is that the faster the cut, the lighter the oil, since it is more readily taken into solution and removed. A heavier, viscous oil will clearly move more slowly.

Instant cut High gravity oils Slow cut Low gravity oils

Permeability also has an important bearing in the speed of the cut. The poorer the permeability, the slower the cut. Inter-related factors such as quality of permeability, oil viscosity and solubility, leading to overall fluid mobility, will all contribute to the speed of the cut. Cut speed should be described as slow, moderately fast, fast, instantaneous. • Nature of the cut The nature of the cut is the way in which the oil is leached from the cutting and can be observed by the pattern of the dis-coloured solvent (from the oil) spreading from the cutting.

Uniform blooming Good permeability and oil mobility. Streaming Low mobility due to limited permeability and/or high viscosity.

If no cut has been observed with the addition of solvent, then various procedures can be used to try to ‘force’ the cut: - Typically, the cutting is crushed to assist in freeing the oil. This also has the benefit that we are ensuring that we see all the oil contained in the cutting. The crush cut should then be described in the same way as the solvent cut.



213

If a wet sample was used: Use a solvent / alcohol combination in case water was obstructing the

solvent. Repeat using a dry sample. Add hydrochloric acid.

Residue Observation of any residue remaining after the solvent tests is an important conclusion to the procedure. After the solvent has rapidly evaporated, any oil that has been leached from the cutting will remain behind as a residue in the sample Plate. This obviously provides an opportunity to determine the true natural color of the oil away from the background color of the cutting. The natural color (i.e. viewed under natural light), fluorescence color, intensity and amount (poor, fair, good) should all be included in the final show report, since this will be a final evaluation of the oil density and quantity contained in the cutting.

Sampling the mud The reason for, and benefits of, continually checking the fluorescence given by oil based muds has already been discussed in that the drilling fluid, having high mutual solubility for other oils, will retain oil released from a reservoir rock and therefore lead to additional and changing fluorescence. It is also worth mentioning that water based and other muds should be checked for any oil that has been released from the cuttings by the normal liberated mechanism. In this case, the reservoir oil will not dissolve in the mud but will remain ‘separate’ so that it can be sampled and tested for fluorescence in the same way as oil retained in the drilled cuttings. It may help the process by mixing the mud with clean water to separate and lift the oil, which can then be skimmed off from the surface and checked for natural colour and fluorescence.

11.2.4 Quantitative Fluorescence TechniqueTM QFTTM is a patented and licensed wellsite procedure developed by Texaco. It is used to provide a quantitative measurement of the fluorescence and relating this to the concentration of oil that may be contained within a sample. QFTTM reduces or eliminates potential errors inherent in the conventional fluorescence process: - • Firstly, the error that can result from subjective descriptions. • Secondly, the fact that much of the fluorescence resulting from hydrocarbons falls outside of the

electro-magnetic range detected by the human eye. Not only does this mean that any fluorescence that is visible is merely a fraction of the actual energy emission and therefore not wholly representative but, it may also mean that some hydrocarbon occurrences may go completely undetected, especially with very light oils and condensates.



214

QFTTM is performed with a portable fluorometer that accurately measures the intensity of the fluorescence produced by the oil in a given sample. The intensity is proportional to the quantity of oil in the sample and can be plotted to demonstrate a depth based profile of oil concentration. The procedure is as follows: - • A washed, air dried sample of drilled cuttings or core is ground to a powder. • Drying should not be done at high temperature since volatiles will be lost. • A fixed quantity (whether by weight or by volume) is taken and an organic solvent, typically heptane,

is added in order to extract any oil. • After mixing and agitating the sample mixture, the solvent and any oil is filtered off. • The solvent-oil mixture is then placed in the fluorometer to determine the fluorescence intensity,

indicative of the oil content of the sample. The resulting QFT™ measurement is one of oil concentration within a given volume of rock. The producing zones are therefore, typically, those showing the highest measurement above background and therefore the main concentration of oil. For one particular oil, this is certainly true. However, this quantitative result is dependant on oil type since different oils will fluoresce at different levels for a given ultra-violet wavelength. In other words, for a given volume of oil, a higher reading will be generated from a heavier oil. This technique certainly removes any inaccuracies through erroneous or subjective analysis, and has proven to be a very accurate and reliable tool in the detection of hydrocarbon bearing zones, even when using oil-base muds. However, as with any testing of cuttings from a continually changing environment, there are limitations to the process that the user has to be aware of. • Since the fluorescence measurement is being related to a given volume of rock in order to determine

oil concentration, it has to be asked how representative are the cuttings to the reservoir formation? The presence of varying amounts of cavings or non-producing lithology will affect the accuracy of QFT™.

• How much oil has been retained by the cuttings? If the zone has been flushed ahead of the bit, then

the hydrocarbon content in the resulting cuttings is reduced. If the formation is extremely permeable, much of the oil (especially light oil and condensates) will have been liberated to drilling fluid and go undetected in the cuttings.

• Over-washing of samples may lead to oil effectively being leached from the cuttings. • Coal and similar hydrocarbons possess aromatics that will give QFT™ responses. Obviously, these

can be identified through cuttings analysis and gas responses.



215

• Mud contamination. Oil based muds, although exhibiting low fluorescence in a clean condition, will

retain and recycle hydrocarbons, leading to a continually increasing background measurement of QFT™, much in the same way as chromatographic background contamination. Similarly, mud contaminants such as pipe dope and asphalt type additives will give QFT™ responses.

• Fluorescence intensity is not linear across the ‘liquid spectrum’. A given quantity of low API crude

oil will result in a significantly higher intensity than the same concentration of high API crude or condensate. There may therefore be a question as to whether a change in fluorescence measurement is caused by an increase in the quantity of oil or as a result of a change in composition. Typically, however, when drilling a particular reservoir section, it can be reasonably assumed that a peak in fluorescence intensity reflects the maximum oil concentration.

• QFTTM is a measure of quantity but gives no information as to production potential.



216

11.3 Cuttings Bulk Density Whilst drilling a well, bulk density measurements are made in order to determine the Overburden Gradient. Measurements can be made every 5 or 10m, or whatever the sample interval is. Obviously, the more frequent the measurements, the more accurate the gradient will be. A simple displacement technique can be used to determine bulk density, and, as long as the engineer is precise and consistent, the data quality is typically satisfactory for overburden calculations. The technique is described below: -

• Cuttings need to be washed (to remove drilling mud) and “towel” dried to remove excess water. • Obvious cavings should be removed so that the sample selected is representative of the drilled

interval.

• Accurately weigh a sample of 1 or 2 grams, for example. Obviously, the larger the sample size, the smaller any error.

• With distilled water, fill a 10cc graduated cylinder to exactly 5cc (so that there is sufficient

volume to submerge all the cuttings but not too much so that the cylinder overflows). There will be a substantial meniscus on the water surface, so be consistent and take the measurement either from the top, or bottom, of the meniscus.

• Carefully drop the cuttings

into the cylinder, being mindful of splashes and trapped bubbles.

• Lightly tap the side of the

cylinder to release any trapped bubbles and to help splashes, on the side of the cylinder, run back into the water.

• Read the new level of the

water, again being consistent with where, on the meniscus, you take the reading.

From these measurements: -

bulk density (SG or gm/cc) = weight of sample (gm) volume of displaced water (cc)

5

6 1.1cc



217

For example, if 2.00 gm of sample displaced 1.10 cc of distilled water: - Bulk density = 2.00 / 1.10 = 1.82 gm/cc Sources of error in this method include the following: -

• Poor quality drilled cuttings • Shale hydration or reactivity with mud • Sample not representative of drilled interval • Inaccuracy in weighing • Inaccuracy/Inconsistency in determination of water displacement • Eye level not being parallel to water meniscus • Trapped bubbles, within bulk sample, increasing water volume



218

11.4 Shale Density Shale density can be monitored to detect the onset of transitional pressure increases through shale or clay intervals.

• With depth, shale density shows a normally increasing trend due to increased compaction and reduced porosity and fluid volume in comparison to the matrix content.

• Through a transitional zone, as pressure gradually increases and compaction rate decreases, shale

density will show a corresponding gradual decrease to the normal trend. With careful selection of the shale cuttings, shale density can be measured by the same technique used to determine bulk density, through weight and water displacement. However, a more accurate method is through a graduated density column.

• Here, typically, a fluid of known concentration is mixed with distilled water in such a fashion that the resulting compound has a gradual change in concentration with depth.

• Glass beads of exact density mark this gradational change.

• A number of shale cuttings, carefully selected, are dropped into the column, and the depth at

which they settle, representing their density, is recorded. • A graph of density vs depth is used, for each shale cutting, as shown below, to determine an

average shale density value. Both methods, requiring careful selection of individual shale cuttings, are extremely user intensive and subject to error. The graduated column method requires the following considerations:

1.6 1.8 2.0 2.2 2.4 2.6 2.8 gm/cc

1.6 2.2 2.5 2.7

1.8

2.0



219

• Above all – user consistency! • Flat cuttings should be avoided, because they will float on the surface. • Cuttings with obvious fractures/fissures should be avoided because they will contain air. • Cuttings of equal size and shape should be selected if possible. • Cuttings should be dried quickly with absorbent paper to remove excess water from washing, but

avoiding prolonged delay where they would dry out. • Sometimes, the cuttings take a long time to settle completely. During this time, they may actually

absorb the fluid, changing their original density. In this case, after a certain time (30 seconds for example) has elapsed, the depth should be read at that point.

• The 2 fluids in the column will slowly mix further over time, so the graph should be re-plotted on

a regular (daily) basis to ensure it’s accuracy. Datalog uses Sodium Polytungstate (2.89 g/cc) to make the graduated density column because it is non-toxic, simple to handle and easy to recover. Instructions to make the column are as follows: -

• Use Sodium Polytungstate (SPT) and distilled water. • Use glass density beads, ranging from slightly heavier than the lighter water to slightly lighter

than the SPT, e.g. 1.2 to 2.8 g/cc. • Use a glass or plastic graduated cylinder (250ml).

• Pour SPT up to the 125ml level. • Pour the distilled water on top, in small amounts so as not to over dilute the mixture. • The supplier instructions are as follows - Stir the center area of the cylinder until a mixed zone of

15-30ml is generated. This is done by tilting the cylinder to about 15 degrees off horizontal and straightening to the vertical quite rapidly, at the same time rotating the cylinder on its own axis. Ten or 15 tilts should generate the mixed zone.

• In practice, for shale density, a larger mixed zone needs to be generated, so this procedure can be repeated, with additional water if necessary, to produce the larger interval.

• Add the beads, heavier to lighter, allowing each to settle before adding the next one. Determine whether the graduated mixed zone is sufficiently large and linear – if not, again, more stirring and tilting may be required to improve the mixing.

• Seal the top of the cylinder (either a cap or plastic wrap) to minimize evaporation.

• If the solution turns blue, it has come into reducing agents such as sulfides. The density should not be affected, so unless it is too dark, the column can still be used. If it is too dark, a few drops of hydrogen peroxide can be added to return the solution to it’s original color.



220

11.5 Shale Factor With normal diagenesis and burial, smectite clay transforms to illite, through a cationic exchange as clay dehydration takes place and water is released.

A reduction in CEC (cation exchange capacity) will be seen with depth, corresponding to the reduction in smectite and increase in illite content. Similar to the technique used to determine the bentonite content in the drilling fluid, an approximation to CEC is achieved by using methylene blue to determine the shale factor. The shale factor will normally decrease with depth as the amount of illite increases. Undercompacted clays in overpressured zones are typified by the fact that they have been unable to dehydrate properly, thus the smectite content is unusually high. This would lead to an increase in the shale factor, going against the normally increasing

trend. Conversely, the higher temperature in an overpressured zone may actually speed up the process of cation exchange and clay transformation so that the shale factor would show a more rapid decrease. These two trend indicators make the shale factor a difficult parameter to use and to rely on as a pressure indicator. In addition, the methodology to determine the shale factor is extremely user intensive and open to large user error. The technique required is as follows: -

• Select dry and representative shale cuttings

• Grind to a fine powder

• Weigh a ½ gram sample, add distilled water and a few drops of sulphuric acid

• Heat and stir

• Add methylene blue, drop by drop, from a pipette.

• Take a drop of the mixture and place on filter paper.

• The normal indication is if the water spreads and the blue remains centralized (upper example).

• When the blue spreads and a light blue aureole forms around it (lower example), record the

volume of methylene blue added. Whether this actual volume is taken as the recording, or some calculation from it, the volume of methylene blue required represents the changing CEC.

Undercompaction

Sh. Factor



221

11.6 Calcimetry The following procedure is used to determine, for carbonates, the relative proportions of calcium carbonate (limestone) and magnesium carbonate (dolomite). This is an important aid to identifying changes and formation tops through carbonate sequences. Apparatus includes a pressure module and transducer, sample jar, magnetic stirrer, syringe and acid, mortar and pestle. Hydrochloric acid is added to a ground carbonate sample in a closed vessel. The resulting reaction, as the carbonate is dissolved, causes a pressure change which is monitored and analyzed. The limestone component will dissolve almost immediately (~ 30 seconds) whereas any dolomite component will require a much longer time to dissolve (depending on amount, but this could be anything from 5 to 30 minutes). This is the basis of distinction between the two components: - The test is controlled and operated through the QLOG software. Calibration is the first requirement: - • Calibrate the Injection Pressure - this needs to be done so that the pressure change caused by acid

injection is ignored during the analysis of sample reactions. Select Calibrate - Inject to start the run, then inject the acid, normally 20cc. When the pressure stops increasing, the reaction is complete, click on Stop. The inject pressure will then be recorded in Setup-Settings.

DOL LST



222

• Calibrate for 100% Limestone (i.e. pure CaCO3). Ensure the vessel is clean of acid and dry. Place the limestone, normally 1gm, in the vessel, ensuring it is sealed. Click Start, the status will read Inject, Wait. Inject the acid, the status will change to Run. When the reaction is complete (normally around 30sec) click on Stop. If the pressure on the display goes off scale, wait for about 1min before stopping. Click on Calib 100% Sample and confirm. The highest pressure recorded will be stored in Setup - Settings as Carbonate Pressure. You should repeat the process to ensure the calibration is accurate.

• Calibrate for 50% Limestone / 50% Dolomite - again, ensure that the vessel is clean, dry and

sealed, with the acid ready to inject. Follow the same procedure as above to run the sample. When the reaction is complete (you will have to extend the sample run time in Setup - Settings), click on Stop. Click on Calib 50/50% Sample and confirm.

Analyzing Samples Samples are analyzed using the same procedure, same sample weight and volume of acid. Once a sample run has been completed, you have the option of accepting the software calibrations and automatic analysis, or overriding this and doing your own analysis. Automatic - once the run is complete, select Analyse - Perform Analysis. The %’s will then be determined automatically based on the calibration settings and displayed in a sub menu. Manual - select Analyse - Select Break. Immediately move your mouse to the point on the curve that you consider to be the ‘break point’ between the limestone and dolomite reactions (effectively, you are overriding the ‘slope’ in the automatic calibration) and click the left hand mouse. Now you should run Perform Analysis as above.



223

11.7 Enhanced Hole Monitoring Enhanced hole monitoring, through the analysis of cuttings volume, can help to evaluate hole condition and stability and identify potential hole problems such as formation caving or poor hole cleaning. This can help to minimize or avoid potential hole problems, optimize drill rates and overall, reduce the cost of the drilling program. If drilling at a constant rate, the volume of cuttings exiting the wellbore should be equal to the cylindrical volume (hole diameter x depth) over any given interval. If the actual volume is larger than this, then poor hole stability is being indicated. This may result from a number of situations such as:

• structural caving • pressure caving • loose friable formations • fractured zones • deviated or horizontal wells with problems associated with formation bedding orientation,

erosional wear of drillstring through high angled zones, doglegs, etc. If the actual cuttings volume is less than the calculated volume, then poor hole cleaning is being indicated with cuttings, physically, not being removed from the wellbore. This is becoming increasingly critical in high angle, horizontal and extended reach wells where cuttings transport and removal is an important factor in the ability to drill the well.

11.7.1 Consequences of poor stability / poor hole cleaning

• Higher levels of torque and drag • Stuck pipe through pack off • Restricting flow in horizontal wells • Increased load on circulating equipment • Increased wear on drilling equipment • Complicates geological interpretation • Causes time delays and increases costs

11.7.2 Problems of Measuring Actual Cuttings Volume This simply requires catching the cuttings in a vessel as they come across the shale shakers and recording the volume of cuttings collected over a given time period. The parameter is measured in terms of BARRELS per HOUR. Although this sounds simple enough, it does create some practical problems:



224

Are all the cuttings being collected? • For a given shaker, does the vessel cover the entire length or just a portion? • If the vessel only covers a portion of the shaker, is the cuttings flow evenly distributed or

concentrated at the edges for example? • If more than one shaker being used? • Is the same amount of flow occurring over all shakers? • Do the shakers have the same screen sizes? • Finer particles are missed, since they pass through the shakers and will collect in the sand trap or be

removed by desilters, desanders and centrifuges.

What about mud volume? Depending on the fluid type and it’s viscosity, and also on grain size, mud creates a coating over the cuttings. Thus, a proportion of the measured volume is actually due to mud rather than cuttings.

How accurate is the unit of measurement for a period of an hour? Depending on how large the vessel is and how many cuttings are being produced from the wellbore, the vessel will most likely fill up in less than an hour. The time difference is easily corrected for i.e. if the vessel fills up in 15 minutes, multiply the volume by 4 to determine the equivalent volume per hour. However, some inaccuracies remain: • The error caused by mud volume being included will be increased when extrapolated over an hour. • If the vessel does not collect ALL cuttings from ALL shakers, then errors in extrapolating to a total

cuttings volume will again be increased when extrapolated over an hour. The final result is therefore a semi-quantitative measurement, although not an exact one. However, the continuous measurement will provide meaningful trends against which deviations can be evaluated in turns of hole condition and hole cleaning. Comparing against a theoretical cuttings volume will again only be semi-quantitative because of the limitations of the actual measurement, but deviations in the differential between the two values can again be evaluated effectively in terms of hole monitoring.

11.7.3 Volume of Vessel This has to be known in terms of Barrels, so may require unit conversion. If the volume of the vessel is known in US gallons, divide by 42 to give the equivalent in barrels. If the volume of the vessel is known in imperial gallons, divide by 34.739 to give the equivalent barrels. If the volume of the vessel is known in litres, divide by 159 to give the equivalent in barrels. (1 litre = 0.2642 gallons) For example, a 15 gallon drum would be equal to 0.3571 BBLS



225

11.7.4 Measurement of Cuttings/Hour This has to be an ongoing, continual, measurement, with volume extrapolated to record the measurement in terms of BBLS/HR. Depending on the size of the vessel and volume of cuttings determining how quickly it fills, there are two ways to practically do this: 1. In most situations, the more likely technique is to measure the time required to fill one vessel and

convert to the equivalent volume per hour.

For example, using the 15 gallon drum, it takes 10 minutes to fill….

Actual volume collected = 0.3571 BBLS x (60/10) = 2.143 BBLS/HR 2. If the vessel is filling up quickly, then extrapolating to the total volume over an hour would

produce a larger degree of area. Therefore, it would be better to time how long it takes to fill a multiple number of vessels. This would require having two vessels so that they can be quickly swapped over, rather than losing cuttings when a single vessel is being emptied.

Again, using the 15 gallon drum, in a large hole section with faster drill rates, the vessel is filling every 2 to 3 minutes. For 5 vessels, the time taken is 13 minutes….. Actual volume collected = 5 x 0.3571 x (60/13) = 8.241 BBLS/HR

11.7.5 Correction to Total Volume Once it has been determined, the cuttings volume per hour needs to be corrected to determine the total cuttings volume coming over the shakers. This has to be done as accurately as possible according to the given situation on location. For example, if two shakers are operating at the same rate with the same screens, then the volume recorded for one shaker can simply be doubled. If the vessel does not cover the entirety of the one shaker screen, then estimate the percentage of cuttings that are being collected. This may be done visually, especially if the cuttings are concentrated in one section of the shaker, but the accuracy could be improved by a series of tests at the commencement of hole sections. Record the volume collected over the various shaker sections, i.e. if the vessel covers a 1/3rd of the shaker width, then record the volume coming over each of the 3 sections. The section with the best cuttings flow should be the one used for the ongoing measurement and the percentage of cuttings for that section can be determined.



226

For example, the following times were taken to fill the 15 gallon drum in the 3 positions across the shakers: Volume in position A = 0.3571 x 60/7.5 = 2.847 BBLS/HR Volume in position B = 0.3571 x 60/22 = 0.974 BBLS/HR Volume in position C = 0.3571 x 60/6 = 3.571 BBLS/HR Total Volume collected = 2.847 + 0.974 + 3.571 = 7.392 BBLS Position C has the best cuttings flow….. Percentage cuttings in position C = (3.571/7.392) x 100 = 48.31% Correction Factor for measured volume = (100/48.31) = 2.07 In this example then, TOTAL VOLUME FOR ONE SHAKER = VOLUME COLLECTED X 2.07 Example, 5 vessels are filled in a time of 11 minutes: Cuttings Volume per hour = (5 x 0.3571) x (60/11) x 2.07 = 20.16 BBLS/HR

7 min 30sec 6 mins 22 mins

Upper screen Lower Screen Cuttings collecting vessel in the 3 positions

A B C



227

11.7.6 Theoretical Cuttings Volume This is simply the product of hole length x bit diameter, in other words the volume of the wellbore cylinder. Volume of cylinder = π r2 x h where r = radius of cylinder h = length of cylinder If volume units are BBLS, then the following formula makes life a little easier: Volume (BBLS) = (bit diameter)2 x length of hole section bit diameter = inches

1029.46 hole length = feet The following table illustrates the calculated cuttings volume (BBLS/HR) that would be generated from varying hole sizes at different ROP’s.

20 FT/HR

50 FT/HR

100 FT/HR

200 FT/HR

16” HOLE

4.97

12.43

24.87

49.73

12 ¼” HOLE

2.92

7.29

14.58

29.15

8 ½” HOLE

1.40

3.51

7.02

14.04

6” HOLE

0.70

1.75

3.50

7.00

Obviously, the cuttings volume being measured is lagged data, so this has to be equated to the theoretical volume drilled real-time. For example, while drilling an 8 ½” hole, the 15 gallon drum takes 9 minutes to fill, the actual time period being 10:33am – 10:42am. The lagged depth at this time was 7042.4 to 7047.7ft. Actual Volume = 0.3571 x 60/9 = 2.38 BBLS/HR Drilled interval (lagged) between 10:33 and 10:42 is 7042.4 – 7047.7 ft = 5.3 ft Calculated Volume = (8.52/1029.46) x 5.3 x (60/9) = 2.48 BBLS/HR



228

11.7.7 Actual/Theoretical Cuttings Volume Ratio As previously explained, the procedure results in a semi-quantitative measurement and a semi-quantitative comparison. The two values are unlikely to be the same for the following reasons:

• Errors caused when extrapolating vessel volume to total volume at shakers • Very fine solids passing through the shaker screens and not being collected • Mud coating the cuttings increasing the measured volume. This is likely to be more

significant with smaller cuttings (larger surface area), therefore in smaller holes, with smaller tooth/button sizes or PDC bits.

Nevertheless, the actual cuttings volume measurement and changes in the relationship to the theoretical volume still provide a very useful determination of changes in hole condition, stability and cleaning. It is useful to express the relationship in terms of a ratio so that deviations, which would indicate a relative increase/decrease in cuttings exiting the hole, can clearly be seen. From the example above: Ratio Actual/Theoretical Cuttings Volume = 2.38 / 2.48 ….. ATCV Ratio = 0.96 A value of 1 obviously represents a perfect relationship, but in reality this is unlikely due to the errors detailed above. For example: If fine solids are being lost through the shaker screens, a normal “background” ATCV ratio will be < 1 If mud coating increases the measured volume, a normal “background” ATCV ratio will be > 1

11.7.8 Recording, Evaluating and Reporting To be a useful parameter, the data needs to be recorded, calculated and evaluated on a real-time basis. This means that once one measurement has been made, i.e. the collecting vessel has filled up, the time taken must be recorded. The vessel should be emptied and the whole process begins again immediately. A worksheet must now be completed with measurements, calculations and observations. See the example provided. As well as the information already described, the following have also been included in the worksheet:



229

Flowrate, since an increase in FR will reduce the apparent volume of cuttings Mud Weight and Viscosity, since these parameters affect cuttings lift and hole cleaning. Lithology is obviously a critical factor in cuttings removal and caving. The following information should be considered: • Friable lithologies prone to instability • Fractured lithologies prone to instability • Abnormally pressured shales prone to caving • Higher density lithologies, especially limestone, dolomite, anhydrite etc more difficult to lift and

prone to settling • Clays taken into suspension and not recorded; fine silt/sand passing through shaker screens The lithology section should also be used to describe the Cuttings/Cavings, with the following information being considered: • Size and shape of shale cavings

Long, concave, or fissile pressure cavings Large, blocky, fractured cavings..pressure or structural caving

• Cause and origin of cavings • Other cavings, loose, unconsolidated formations, structurally/orientation related etc • Size of cuttings – heavier to lift, prone to settling, coated with more mud A Comments/Observations is included to add any additional pertinent information that can be evaluated from the procedure. The following points illustrate some of the criteria that should be considered by the mud logging engineers when evaluating the cuttings volume data: • Long hole sections require much more conditioning to prevent instability and sloughing. • High angled or build sections may be prone to “erosional” sloughing of formations through impact

from the drillstring. • High angled or build sections may be more prone to cuttings settling and forming beds on the

underside of the hole. During hole cleaning circulation intervals, the critical angle may be able to be determined from an increase in cuttings volume over a given section.

• Horizontal and extended reach hole sections are also more prone to cuttings settling in beds, where

cuttings transportation may be similar to a river bed, rolling on the “floor” rather than actually being lifted by the mud flowing in the annulus.

• On directional wells, the mud flow in the annulus is effected by whether the drilling is through rotary

or sliding. Cuttings lift and hole cleaning will be less effective when sliding and no turbulence is created by the rotating string.



230

• The effect of caving/sloughing should be monitored during reaming or back reaming, working stuck pipe etc.

• Periods of downtime or halted circulation will lead to cuttings settling and perhaps temporarily

reduced hole cleaning due to the cuttings volume. • Extended periods of high penetration rates will also lead to a loaded annulus, increased frictional

pressure losses and less capacity for effective hole cleaning.

• During circulating periods, the dropping trend in cuttings volume can be used to determine the optimum time required for hole cleaning. This will maximize the time available for drilling with optimum ROP’s.

Plotting the Data A spreadsheet can be used to plot the data. Both time and depth based plots should be produced, since, in many situations, the actual depth is not actually relevant to the flow of cuttings, e.g. when the hole is being circulated clean, when reaming is taking place, if cuttings beds are reducing hole cleaning at a high angled hole section etc. Data to be plotted: Actual Cuttings Volume Theoretical Cuttings Volume ATCV Ratio A time based plot can be produced, on a daily basis, directly from the data recorded on the worksheet. Annotations should be used to report change in operations or parameters etc Depth based plots can be created for regular depth intervals, for each hole section or particular sections of the well such as build sections, extended reach sections etc.



231

ENHANCED HOLE MONITORING RECORD SHEET OPERATOR: ______________________________ WELL NAME: ___________________________

VESSEL VOLUME: HOLE SECTION: BIT NUMBER: BHA NUMBER:

Vessel Number

Time to

Fill

Lagged Depth

Actual Volume

BBLS/HR

Theoretical Volume

BBLS/HR

ATCV Ratio

Operation Flow Rate

MW Lithology Comments/ Observations

1

2

3

4

5

6

7

8

9

10



232

11.8 High Resolution Trip Monitoring The techniques and principles described were developed by Allan Robinson

11.8.1 Theory and Benefits This technique has been implemented as an aid to assessing the hole condition while being drilled. The aim is to ascertain whether or not a routine wiper trip should proceed back to the last casing shoe or only as far back as some other (deeper) point in the well. The technique uses data gathered on previous trips and wiper trips to help decide which scenario is best. In the course of drilling a well, it is normal to perform periodic wiper trips to ensure that the section of hole behind the bit is in a good enough condition to allow the bit to be pulled successfully back to surface when it needs changing. Clearly, unnecessary time spent tripping is time not spent drilling and the amount of time lost to tripping can become significant during the course of a well. When a bit is being pulled out or run back in hole, there will always be a difference between the actual hookload and theoretical hookload. The greater this difference, the more problematic the hole condition. The technique utilizes theoretical and actual hookload data, together with the bit position, to monitor the overpull while tripping in or out of the hole. This data is then processed and presented in a graphical form allowing the client to see accurately those sections of the hole that have caused problems and those that were problem free. Clearly, if one or more trips are problem free, then the client can decide that the need for wiper trips is minimal, allowing increased footage to be drilled between wiper trips or reducing distance the bit is to be pulled back to during a wiper trip (or even a combination of the two). Thus, the time spent making trips is reduced, allowing more rig time spent on bottom drilling. Clearly the opposite also applies and hole sections that were previously considered okay may actually be unstable and require more attention than was previously thought. Again this should still result in a net saving of time and money, as problems such as stuck pipe, or worse, are avoided by implementing preventative measures based upon evidence gathered by accurately monitoring the trips.

11.8.2 Procedure Clearly, when attempting to accurately monitor weights during a trip, the sensors have to be functioning properly. The following parameters are essential: -

Hookload must be accurate. Depth has to be tracking properly with the system going in and out of slips properly. Mud weight has to be correct, to allow for the buoyancy of the drill string. Theoretical hookload has to be correct.



233

Theoretical Hookload Attention needs to be paid to the theoretical hookload. In order to ensure that this is correct, it is necessary to put the right string OD’s and ID’s in the equipment table. For example 5” DP has a nominal OD of 128mm and ID of 107mm. These values are nominal since they do not take into account the increased thickness at the tool joints. 19.5 lb/ft 5” DP actually weighs more than this when the tool joints are taken into account e.g. 19.5 lb/ft G Class pipe actually weighs in the region of 21-22 lb/ft. In order to take this into account for the theoretical hookload, it is necessary to increase the OD of the pipe to 130-131mm (depending upon type). Do not reduce the ID as this will affect the real time hydraulics calculations when drilling, increasing the pressure loss inside the drill string. The easiest way to ensure the theoretical hookload is correct right is to have the driller rotate off bottom (in a situation where it is known that there is zero drag) and then to make adjustments to the OD until the actual and theoretical hookloads give the same value.

System and Data Preparation Before the trip commences, the system needs to be specifically prepared to gather the data. The time database should be set to gather data at the higher resolution of 15 seconds, so change the Time Interval, in the Equipment Table, to15. DBtime needs to be shut down and restarted for the change to take effect (don’t forget to set it back to 60 seconds after the trip! Once the trip is over and the rig is back to drilling, export the time database and process it. This is done using the las command. The parameters that need to be exported are hookload, theoretical hookload and bit position for the entire duration of the trip. Once this is done the database needs to be imported into a spreadsheet (EXCEL) and converted to a pseudo depth database. This is done by deleting the time reference column (col A0) and replacing it with the bit depth column. It is then an easy matter to calculate the overpull/drag at any instant by simply subtracting the actual hookload from the theoretical hookload. These parameters can then be plotted, against bit position or depth, in an excel chart (see examples). Please note that the theoretical and actual hookloads will vary during a trip in if it is performed with a closed end string and the string is not filled too often.

11.8.3 Interpretation

When the plots have been created, it is relatively easy to identify hole sections that are problem free and those that require attention.



234

On a quick look level, the spacing of the data point provides a clue to a problem. Many data points at a given depth (or a cluster around a range of depths) indicate that the bit was static or didn’t move very far over a period of time. Widely spaced points indicate that the bit moved through the section relatively freely.

On a more detailed level, specific problem depths can be identified with the corresponding overpull and or drag. These depths can be identified and assessed as to whether they continue to cause problems on successive trips. If this is the case, then the drillers can be informed as to when they should expect a problem. The scale of each problem can also be predicted with a degree of accuracy i.e. if a tight section is encountered at the same depth and is overcome by backreaming just one joint before continuing, and this happens on subsequent trips, then personnel know how to overcome the problem as a matter of course during subsequent trips rather than overdoing the backreaming on problem free formations. Example In this example, the trip data from TD of 1960m back to the casing shoe at 517m is displayed. It can be seen that there were problems encountered on the way out between TD and 1500m. From 1500m to the shoe there were no problems. Of the problem section, closer inspection reveals that the depths 1795m to 1755m and 1725m to 1690m required backreaming. There were also problems encountered at 1550m and 1525m. On the trip back in there were no problems until 1525m where it was necessary to wash and ream. The trip in then went problem free down to 1925m, where again it was necessary to wash and ream, this time down to bottom.

500 1000 1500 2000

0

20

40

-20 40

80

120

160

Hookload (Tonnes) Theo. Hkld (Tonnes)

Overpull (Tonnes)

Depth (m)

TRIP OUT



235

40

80

120

160


1500 1600 1700 1800 1900 1950

0

20

40

-20

Overpull (Tonnes)

Depth (m)

TRIP OUT

160


40

Overpull (Tonnes) TRIP IN

0

20

-20 40

80

120

1500 1600 1700 1800 1900Depth (m)



236

11.8.4 Benefits to the Operator

By monitoring the trip in this fashion, the client knew when to expect possible trouble during the trip in (the trip out was processed and ready prior to the run back in hole), at the earliest 1525m. This problem was duly encountered. This depth had actually been identified as a problem on previous wiper trips and it actually became routine to break circulation and wash one single down at 1525m. The other problems on the way out were not encountered during the run in hole. Extra problems were however encountered during the last 30m of the run in hole. This meant that the hole was essentially in good shape from the shoe to 1500m and from 1550m to 1920m. The bulk of the initial problems encountered while pulling out of hole appeared to have been sorted out by the backreaming and did not reoccur on the way in. Please note that this had been typical of the well based upon previous wiper trips. The monitoring of previous trips had already resulted in the operator decision not to pull all the way back to the shoe during a wiper trip. The operator could also assume that washing to bottom would probably have alleviated the problem encountered during the last 30m of the trip. The trip data revealed that the problem at 1525m was reoccurring and easily overcome. Based on this information, the client decided to increase the footage drilled between wiper trips (350m) and to only wipe back to 1500m, leaving the other 1000m between the shoe and 1500m alone. As the drilled depth increased further, the decision was made to wipe only the last 350m to 400m drilled every 350m. The problem at 1525m was considered small enough to leave alone and tackle only during bit trips. By having an accurate picture of problematic sections, the client was able to make the decision to cut down the frequency between wiper trips and to reduce the depth pulled back to, yet still be confident that the untouched section of the hole was in good shape (based upon plots from previous trips). This of course resulted in more time on bottom drilling, ultimately saving money.



237

11.9 DST Procedures Information provided by Allan Robinson The Drill Stem Test (DST) has been an industry standard for many years, although it is only since the 1950’s that the techniques and principles used today were originally developed. The main purpose of performing a DST tends to be similar for all wells once a zone of interest has been identified after drilling. That is, to identify formation fluids (hydrocarbons, etc.), measure temperature and pressure, measure productivity, to recover fluid samples for analysis and to assess completion efficiency. This section outlines the typical operations during a DST in cased hole. Please note that variations in abbreviations for tools may occur on different jobs. Care should be taken to find out what tool does what and how it is supposed to operate. The following is based upon the nomenclature used by Schlumberger Flowpetrol denoted by *.

11.9.1 Water Cushion Prior to running the DST string in hole, it is necessary to decide what size water cushion is required. This is a column of water (or other fluid of a known density) that partially fills the inside of the test string. The height of the column depends upon how much pressure the operator wishes to exert upon the formation during the test, normally dependant on the anticipated formation pressure. The water cushion pressure should be less than the formation pressure in order to induce the test zone to flow. For example, if the formation pressure at 3500m is expected to be hydrostatic (0.433 psi/ft), then an absolute pressure of around 5000 psi can be anticipated. In order to get the test zone to flow, the water cushion pressure should be less than 5000 psi, 3800 psi (1200 psi underbalanced) for instance. This is equivalent to a column of water 2675m high. In order to attain this pressure, the first 2675m of the DST string would be filled with water during the run in hole. The rest of the tubing would be run dry. In this case, if the formation was perforated and the pressure really was 5000 psi, then the water cushion would account for 3800 psi and the shut in pressure at surface would be 1200 psi (assuming that no fluid of a density different to water entered the hole during the test e.g. brine).

11.9.2 Test String Components The diagram over the page illustrates a typical Downhole Test String. From the bottom, the main components are as follows: - TCP Guns These are the Tubing Conveyed Perforating Guns. This type, here, are 4 spf or 4

shots per foot. The bullets themselves are shaped metal that punch a hole through the casing. They are fired by dropping a bar from surface onto the Firing Head located in the test string above the guns (see Firing Head).

Safety Spacer Simply a spacing joint between the guns and the firing head.



238

Firing Head This is the point of impact for the bar, which has been dropped from surface. The bar hits the firing head, rupturing the back of it. During the run in hole, the interior of all of the string below the Firing Head is at atmospheric pressure i.e. surface pressure. When the bar ruptures the back of the Firing Head, communication is established between the section below the head (atmospheric pressure) and the section above the head (hydrostatic pressure exerted by the water cushion). This pressure differential drives the firing pin into the charges, firing the bullets. This system, requiring a differential pressure, in theory ensures that the guns cannot be fired on or near surface even if the back of the firing head was accidentally ruptured while rigging up, etc.

Gun Drop Sub This sub allows the TCP guns to be unlatched after firing and dropped to the

bottom of the hole, if the operator chooses to do so. Reasons for this vary but are normally to allow the injection of fluids into the formation, after perforating at times when the guns would be in the way, e.g. nitrogen injection, or to allow a logging tool to pass out of the bottom of the DST string to log the perforated zone (e.g. a flow spinner). This saves time by dispensing with a trip out of hole (tubing trips are usually slower than drill pipe trips since the tubing is so much more flexible and therefore ‘wobbles’ a lot more in the mast during a trip). The guns can be retrieved later.

Positreive Packer This tool isolates the section to be tested, from the rest of the annulus. Once in

place, there is no communication between these two sections. The Positreive Packer is similar to a PosiTest* Packer, the difference being that the Positreive Packer incorporates an extra section that stops the packer from being pumped out of the hole during periods when the tubing pressure exceeds the annular pressure. Both types of packer are set in the same way. Prior to having weight applied to them they are rotated clockwise. This rotation causes a J shaped pin to catch on the side of the hole, or casing, which activates a set of slips which extend and grip the side of the hole or casing. With the packer now unable to move further down the hole, weight can be applied to compress the rubber body of the packer and seal off the lower section of the hole. With the Positreive Packer, an extra set of slips are present above the rubber section, pointing in the opposite direction to the lower slips, i.e. designed to stop upward movement. If a situation occurs, whereby the pressure in the tubing is higher than that in the annulus, the differential pressure, tubing to annulus, would normally tend to pump the packer upwards. However, the differential pressure in the case of the Positreive Packer, activates the upper slips, forcing them out to grip the hole or casing and thus preventing any upward movement. When the pressure within the tubing has abated (by bleeding off), the pressure differential will be reversed, i.e. annulus to tubing, and the upper slips will retract.

Safety Joint In the event that, after the test, the packer will not disengage, even after jarring,

the safety joint can be backed off (unscrewed) from the stuck section, allowing the rest of the string to be pulled back to surface and a fishing assembly, with more powerful jars, to be picked up.

Hydraulic Jar Before unscrewing the Safety Joint, a certain amount of jarring can be tried out

in an attempt to free a stuck packer.



239

Section : DST STRINGClient : OILCOField : COWSWell : WELL #1 Report No: DST#1

Rig: OILRIG Date:

DOWNHOLE TEST STRING DIAGRAMDEPTH TO

TOOL DESCRIPTION O.D. I.D. THREADS LENGTH BOTTOMInchesInches METERS METERS

Flowhead 3.00 4 1/2" IF Pin 0.00X-Over 6.50 2.25 0.68 0.68

2 7/8" EUE Box2 7/8" EUE Tubing 2.88 2.44 2742.65

2 7/8" EUE Pin 2742.35X-Over 4.75 2.38 0.60 2742.95

3 1/2" IF BoxFull Open Slip Joint 5.00 2.25 8.88

3 1/2" IF Pin 2751.833 1/2" IF Box

3 1/2" Drill Pipe 15,5 #/ft 10 Stands 3.50 2.76 284.693 1/2" IF Pin 3036.523 1/2" IF Box

3 1/2" Drill Pipe 13,3 #/ft 8 Stands 3.50 2.76 226.613 1/2" IF Pin 3263.133 1/2" IF Box

Single Shot Reversing Valve (SHORT) 5.00 2.25 1.06Disc : P PAP: 3100 psi 3 1/2" IF Pin 3264.19Radioactive Marker Sub 5.00 2.44 3 1/2" IF Box / 3 1/2" IF Pin 0.46 3264.65

3 1/2" IF Box3 1/2" Drill Pipe 13,3 #/ft 1 Stand 3.50 2.76 28.35

3 1/2" IF Pin 3293.003 1/2" IF Box

Muli-Cycle Circulating Valve (MCCV) 5.00 2.25 1.883 1/2" IF Pin 3294.883 1/2" IF Box

3 1/2" Drill Pipe 13,3 #/ft 1 Stand 3.50 2.76 28.253 1/2" IF Pin 3323.133 1/2" IF Box

DGA-Datalatch 5.00 2.25 6.873 1/2" IF Pin 3330.003 1/2" IF Box

PCT with Hold Open Module (HOOP) 5.00 2.25 6.78 PAP : 1600 psi 3 1/2" IF Pin 3336.78

3 1/2" IF BoxHydrostatic Reference Tool (HRT) 5.00 2.25 1.72

3 1/2" IF Pin 3338.503 1/2" IF Box

Hydraulic Jar 5.00 2.25 2.233 1/2" IF Pin 3340.743 1/2" IF Box

Safety Joint 5.00 2.25 0.523 1/2" IF Pin 3341.26

X-Over 5.00 2.25 0.32 3341.582 7/8" EUE Box

Positreive Packer 5.92 2.44 1.982 7/8" EUE Pin 3343.562 7/8" EUE Box

2 7/8" EUE Tubing 2.88 2.44 9.532 7/8" EUE Pin 3353.09

Debris Sub 2.88 2.44 2 7/8" EUE Box / Pin 0.28 3353.372 7/8" EUE Box

Gun Drop Sub TCR-B 2.88 2.44 0.762 7/8" EUE Pin 3354.132 7/8" EUE Box

2 7/8" EUE Tubing 2.88 2.44 9.702 7/8" EUE Pin 3363.832 7/8" EUE Box

Firing Head BHF-C 2.88 2.44 1.472 3/8" Mod. Reg Pin 3365.302 3/8" Mod. Reg Box

Safety Spacer 4.50 N/A 4.702 3/8" Mod. Reg Pin 3370.002 3/8" Mod. Reg Box

TCP Guns 4 spf 4.50 N/A 73.002 3/8" Mod. Reg Pin 3443.00

PIP TAG DEPTH : 3264,42 m Fig 1

��



240

HRT and PCT The HRT, or Hydrostatic Reference Tool, is run to measure the hydrostatic pressure from the annulus as the tools are run in hole. It is a companion tool for the Pressure Control Tester tool (PCT) and they must be run together unless a Pressure Operated Reference Tool (PORT) is run instead. The HRT tool is open during the run in hole, passing the hydrostatic pressure it experiences to the PCT via ports connecting the two tools. Once the packer is set, the HRT is set or closed at the same time by compression. Shortening the HRT closes the ports that were in communication with the PCT. As such, the hydrostatic pressure becomes trapped within the PCT tool, inside a chamber, which is full of nitrogen now being compressed. Since the HRT is now closed, any future changes in pressure in the annulus will not be transmitted to the PCT nitrogen chamber via the HRT. The pressure in this chamber acts as the PCT tools reference pressure and holds the PCT tool closed (At surface the nitrogen on its own holds the tool closed. At depth the hydrostatic compressing the nitrogen pressure holds it closed). The PCT has its own port open to the annulus. Any future changes in annular pressure are received by this port. This port is also in communication with the mechanism that holds the tool closed and acts in the opposite direction to the chamber containing the nitrogen and hydrostatic pressure. When the annular pressure is increased above the hydrostatic pressure that existed when the HRT was set, pressure begins to be exerted on the opening mechanism of the PCT. The PCT valve will only open when the annular pressure is increased above a certain pre-set threshold level above hydrostatic, in this case 1500 psi. This is due to the fact that the pressure holding the tool closed is directly related to the hydrostatic pressure. (It follows therefore that the PCT opening pressure remains the same pressure above hydrostatic at all depths). To close the PCT valve the extra pressure applied to the annulus needs only to be bled off.

Hold Open Module A HOOP is included in the example shown. This is a tool that allows the PCT valve to be held open without pressuring up the annulus. This tool essentially indexes how many times the PCT valve is opened in closed. After a pre-set number of cycles, opening and closing the PCT valve, the HOOP will kick in and keep the PCT valve open.

In addition to having valves, these tools also contain temperature and pressure gauges which measure the temperature and pressure above and below the PCT valve inside the tubing (to allow pressure build ups to be recorded when the PCT valve is closed) as well as in the annulus. DGA-Datalatch This is a data acquisition tool that is constantly gathering data during a test. It

has a battery operated recorder which is recovered once the tool is back on surface. In addition to this, it also has the facility to allow a wireline to be run in and attached to it during a test and thus transmit real-time data back to surface.

MCCV The Multi-Cycle Circulating Valve is a reclosable tubing pressure operated

reverse circulating valve. The tool will remain passive until it is activated by pressure within the tubing. It does this by detecting a pressure differential of 500 psi between the tubing and the annulus. As soon as the pressure within the tubing is 500 psi higher than the pressure in the annulus, the tool will start cycling. Each cycle has three positions, closed, open (annulus to tubing) to allow reverse circulation, open (tubing to annulus) to allow normal circulation, then back to



241

closed. The tool will cycle 6 or 12 times, depending upon how it was set up on surface, before finally remaining open in the reverse circulating position. Once the 500 psi pressure differential has activated the tool, it will move through a cycle every time the direction of flow changes, by means of a series of ports on the tool body with forward and backward facing flapper valves and another port connecting the annulus to a mandrel within the tool. Variations in the pressure between the tubing and annulus, due to flow direction, are exerted upon the internal mandrel via the port open to the annulus. This causes the mandrel to move up and down within the tool. When the pressure is greatest in the annulus, the mandrel is pushed down and vice versa. The mandrel, itself, has a port which lines up with one of the tool body ports with flapper valves, depending upon whether or not the mandrel is up or down. When it is down, it is aligned with a port that will only allow fluid to enter the tool (reverse circulating) etc. When the mandrel is midway in the tool, and aligned with neither flapper port, the tool is closed. Please note that merely shutting off the pumps, for example, will not close the tool. The tool has to be cycled round to the closed position.

Radioactive Marker Sub This is used to correlate the depth of the test tools. Once the

tools are considered to be in position, a wireline is run down the inside of the test string. The wireline picks up the radioactive material and the wireline depth is compared with the reported depth based upon the running tally. If there is a difference, then the string is spaced out with pup joints, subs, etc, on surface, to tie in with the wireline depth.

SHORT This is another circulating valve, the Single-Shot Hydrostatic Overpressure

Reversing Valve, a simple annulus pressure operated valve. Once opened, it cannot be closed. It has a mandrel within it and two chambers, at atmospheric pressure, above and below the mandrel. On the outside, together with circulating ports, is a rupture disk, separating the lower atmospheric chamber and the annulus. Different disks can be used for different anticipated pressures. Under normal conditions, the mandrel is acting as a seal, blocking communication between the tubing, the circulating ports and the annulus. If the pressure in the annulus reaches a point that ruptures the disk, then the lower atmospheric pressure chamber attains annulus pressure, while the upper chamber remains at atmospheric. This pressure differential between the two chambers forces the mandrel up, allowing the annulus to communicate with the tubing via the circulating ports. Natural, accidental, overpressuring of the annulus can open this valve.

11.9.3 Testing Procedures Once the DST string is run in hole, it is necessary to ensure that the guns are in the exact position required to perforate the casing across the desired section. This is done by setting the string in slips, running a wireline down the inside of the string and correlating the depth of the Radioactive Marker Sub with the wireline depth. The desired sub depth should match the wireline depth. If there is any difference between the two the DST string is spaced out with pup joints, etc, until the difference is eliminated.



242

As soon as the string is correctly positioned, the Packer can be set, sealing off the test zone from the rest of the hole. This also closes the HRT and seals off the PCT reference chamber from the annulus. The Flowhead can now be installed. With the string set in the desired position and all the surface equipment ready, preparations can be made to fire the guns. Before firing the guns, it is necessary to open the PCT valve, in this case, by increasing the pressure in the annulus by at least 1500 psi. Care should be taken to ensure that the PCT valve is open. If it is not then the bar that is dropped to rupture the Firing Head will only make it as far as the PCT valve and the casing will not be perforated. (It may be advisable to run a wireline down the inside of the test string, beyond the depth where the PCT valve is located, just to check that the valve is in fact open before dropping the bar). Once it is confirmed that the PCT valve is open, it is possible to drop the bar. It should take only a couple of minutes for the bar to reach the Firing Head (approx 750 m/min). As the guns fire, it may be possible to see a little “ripple” on the annulus pressure gauges on surface. It may also be possible to hear them fire by putting your ear against the tubing at surface. Once the guns have fired, the casing should be perforated and the fluids within the formation will be in communication with the tubing. The pressure these fluids are under will be passed on to whatever is inside the tubing. This pressure equalisation manifests itself on surface as a blow. As fluids, liquid or gas, enter the tubing, they displace the water cushion, pushing it up the tubing. This, in turn, pushes air out of the tubing, which can be diverted via a manifold to a simple bucket of water. The displaced air will be seen as a stream of bubbles coming out of the end of the hose. The more vigorous the bubbles, the faster the fluid influx. It should be noted, that there will be a short delay between the guns firing and any bubbles being seen on surface, depending upon depth. Once the bubbles stop, then the pressure differential between the tubing and the formation should be zero. Under ideal conditions the air bubbles will not stop and the water cushion, followed by formation fluids, will flow back to surface. If the formation fluid pressure is great enough, the fluids will continue to flow to surface on their own. During a test, if these fluids are hydrocarbon gases, they can be burnt at the flare. If it is water or oil, then it can be stored in a tank. If there are no fluids in the formation, then naturally nothing will flow to surface. Similarly, if the permeability of the formation prohibits fluid movement, then despite these fluids being under pressure, they will not flow. In this latter case, bottom hole gauges should still be able to measure the formation fluid pressure during a shut in period. Sometimes during a DST, no bubbles will be seen on surface. There are a number of possible reasons for this: -

• It could be that there are no fluids able to enter the tubing. Either they just don’t exist, or are unable to leave the formation due to poor porosity and or permeability.

• The PCT valve may have malfunctioned and may not be open, in which case, it would have

impeded the progress of the bar to the firing head and, as such, the guns may not have gone off.

In order to verify this, a slickline can be run down the tubing and into the testing BHA. If it cannot pass beyond the PCT valve, then the valve is closed. The bar can be recovered and attempts made to fire the guns again, after trying to open the PCT valve.



243

• The water cushion may have been too great. If the pressure exerted by the water cushion was greater than the formation pressure, then no flow will occur. It is, however, possible to try and reduce the water cushion pressure, and so attempt to reduce the pressure imbalance, by removing water from the tubing.

This is done by using a swabbing unit, a small wireline unit with a slickline instead of the usual wireline. On the end of the wireline, a tool is attached (basically a long bar) with swabbing cups on the end. These cups are made of rubber and fit exactly inside the tubing (all of which should have been drifted, prior to running in hole, to check that the cups will fit all the way down to the BHA). Once the fluid level is tagged inside the tubing (seen as a drop in weight or tension on the slickline as the cups hit the water), the bar and cups are allowed to sink below the fluid level e.g. 100m. This depth is known as the bite. Once a desired bite size is made, the slickline is pulled out of hole as fast as possible. Once on surface, a proportion of the water taken in the bite should still be above the cups. This volume is measured and the new height of water in the tubing can be calculated and, of course, the new pressure being exerted on the formation. The deeper the swabbing unit has to go, the more difficult swabbing becomes, until a point is reached whereby all of the bite is lost around the sides of the cups before the tool is on surface. If the pressure differential is too large, it is often quicker to pull everything out of the hole and rerun the tubing with a much smaller or even no water cushion.

Please note that this section is only a basic guide to DST’s and many variations for the tools exist. An alternative to using tubing, racked back in the mast during trips, is to contract a coiled tubing unit to perform the testing. These have the distinct advantage of being able to vary the size of the water cushion at any point in the operation.



1

Wellsite procedure and operationo

Documents

Transcript of Wellsite procedure and operationo