Wellsite Procedures and Operations Manual
Wellsite Procedures and Operations Originators Approval
David Hawker, Karen Vogt, Allan Robinson, Rebecca Pollard
Document Number 5-1-GL-GL-SUL-00009 Rev 1.0
Mar 2013
No of Pages 278
Weatherford International, Surface Logging Systems
Revision Tracking Rev
Date
Notes
Updated By
X.0
Nov 2011
Tech Writer Edit
K. Williams
X.1
Oct 2012
Content review. Manual structure and syntax edit.
M. Black
X.2
Jan 2013
Content Review
T. Baughman
1.0
Mar 2013
Format Review
K. Williams
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5-1-GL-GL-SUL-00009 (Mar 2013)
Reviewed By
J. Ortiz
Wellsite Procedures & Operations Manual
Publisher: Weatherford SLS 5200 N. Sam Houston Pkwy W., Suite 500 Houston TX 77086, USA PHN: +1 832.375.6800 Weatherford Operating Manual Terms and Conditions of Use A.
The materials contained in this Weatherford Operating Manual are protected by copyright, trademark, and other forms of proprietary rights. Nothing contained herein shall be construed as conferring any license or right to use or practice any copyright, trademark, patent or other forms of proprietary rights. This Operating Manual may not be copied or converted to any mechanical, electronic, or machine-readable form, in whole or in part, without Weatherford’s consent.
B.
This Operating Manual is not intended to address every issue that may arise in the course of operations of the device described therein or the planning of same. Each well and each job are unique and have numerous variables. Experience and other specialized training can complement the materials used in this Operating Manual.
C. Weatherford makes no representation as to the accuracy or completeness of the materials in this Operating Manual. All materials are provided “AS IS” WITHOUT WARRANTY OF ANY KIND WHATSOEVER, EITHER EXPRESS OR IMPLIED, INCLUDING BUT NOT LIMITED TO, THE IMPLIED WARRANTIES OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR NON-INFRINGEMENT. Weatherford expressly disclaims all responsibility for the consequences, direct, indirect, consequential, or otherwise, of any errors or omissions in the materials. D. This information is confidential and proprietary property of Weatherford. Do not disclose to unauthorized parties. Do not use except as permitted by Weatherford. Copyright 2013 Weatherford. All rights reserved. Document Number: 5-1-GL-GL-SUL-00009
Wellsite Procedures & Operations Manual
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Table of Contents 1
RIGS AND THEIR EQUIPMENT ............................................................................................... 18 1.1 1.2 1.3
2
Page
ROTARY DRILLING RIGS ............................................................................................ 18 LAND RIGS ...................................................................................................................18 OFFSHORE DRILLING VESSELS ................................................................................ 19 1.3.1 Barges .....................................................................................................................20 1.3.2 Jack-Up Rigs ...........................................................................................................20 1.3.3 Semi-Submersible Rigs ........................................................................................... 21 1.3.4 Drillships ..................................................................................................................22 1.3.5 Platforms .................................................................................................................23
ROTARY RIG COMPONENTS ................................................................................................. 24 2.1 2.2
OVERVIEW ...................................................................................................................24 THE HOISTING SYSTEM ............................................................................................. 25 2.2.1 Providing Rotation to the Drillstring and Bit .............................................................. 27 2.2.1.1 Kelly and Swivel ........................................................................................... 27 2.2.1.2 Top Drive Units ............................................................................................ 29 2.2.2 Lifting Equipment ..................................................................................................... 30 2.2.2.1 Bails and Elevators ...................................................................................... 31 2.2.2.2 Slips .............................................................................................................32 2.2.2.3 Tongs ...........................................................................................................32 2.2.2.4 Power Tongs and Pipe Spinners .................................................................. 32 2.2.2.5 Chain Wrench .............................................................................................. 33 2.3 THE CIRCULATING SYSTEM ...................................................................................... 33 2.3.1 Mud Conditioning Equipment ................................................................................... 36 2.3.2 Rig Pumps ...............................................................................................................39 2.4 DRILL BIT AND DRILLSTRING ..................................................................................... 40 2.4.1 Drag Bits..................................................................................................................40 2.4.2 Roller Tri-Cone Bit ................................................................................................... 40 2.4.2.1 Bit Terminology ............................................................................................ 41 2.4.2.2 IADC Bit Classification ................................................................................. 41 2.4.2.3 Cone Action ................................................................................................. 42 2.4.2.4 Bearing Types .............................................................................................. 42 2.4.2.5 Teeth............................................................................................................ 43 2.4.2.6 Operating Requirements .............................................................................. 43 2.4.3 Diamond and Polycrystalline Diamond Compact (PDC) Bits .................................... 44 2.4.4 Grading of Bits ......................................................................................................... 45 2.4.4.1 TBG System of Bit Grading .......................................................................... 45 2.4.4.2 The IADC Bit Grading System ...................................................................... 45 2.4.5 The Drillstring .......................................................................................................... 46 2.4.6 Drillpipe ...................................................................................................................46 2.4.7 Drill Collars ..............................................................................................................47 2.4.8 The Bottomhole Assembly ....................................................................................... 48 2.4.8.1 Stabilizers .................................................................................................... 48 2.4.8.2 Reamers ...................................................................................................... 49 2.4.8.3 Hole Opener................................................................................................. 49 2.4.8.4 Cross Over Sub ........................................................................................... 50 2.4.8.5 Rotary Drilling Jar......................................................................................... 50 2.4.8.6 Shock Sub ................................................................................................... 51 2.5 BLOWOUT PREVENTION (BOP) SYSTEM .................................................................. 52 Page 4 of 278
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2.5.1 Kick and Blowout ..................................................................................................... 52 2.5.2 BOP Stack ............................................................................................................... 52 2.5.3 Closing the Well ...................................................................................................... 53 2.5.3.1 Annular Preventer ........................................................................................ 53 2.5.3.2 Ram Type Preventers .................................................................................. 54 2.5.3.2.1 Pipe or Casing Rams......................................................................................... 54 2.5.3.2.2 Blind or Shear Rams ......................................................................................... 55 2.5.3.3 Closing BOPs .............................................................................................. 55 2.5.3.3.1 Accumulators..................................................................................................... 55 2.5.4 Control Panel........................................................................................................... 56 2.5.5 Positioning Rams .................................................................................................... 57 2.5.5.1 Kill Lines ...................................................................................................... 58 2.5.5.2 The Diverter ................................................................................................. 59 2.5.6 Inside BOPs ............................................................................................................ 60 2.5.6.1 Surface Shutoff Valves ................................................................................ 60 2.5.6.2 Downhole Check Valves .............................................................................. 60 2.5.7 Rotating BOPs (RBOPs) ......................................................................................... 60 3
THE DRILLING FLUID ............................................................................................................. 62 3.1
PURPOSES OF THE DRILLING FLUID ........................................................................ 62 3.1.1 Cooling and Lubrication ........................................................................................... 62 3.1.2 Bottom Hole Cleaning.............................................................................................. 62 3.1.3 Control of Subsurface Pressures ............................................................................. 62 3.1.4 Line the Wellbore .................................................................................................... 63 3.1.5 Support the Drillstring .............................................................................................. 63 3.1.6 Cuttings Removal and Release ............................................................................... 63 3.1.7 Transmit Hydraulic Horsepower to the Bit ................................................................ 64 3.1.8 Hole Stability ........................................................................................................... 64 3.1.9 Formation Protection and Evaluation ....................................................................... 64 3.2 COMMON DRILLING FLUIDS ...................................................................................... 64 3.2.1 Air-Gas Drilling Fluid................................................................................................ 65 3.2.1.1 Advantages .................................................................................................. 65 3.2.1.2 Disadvantages ............................................................................................. 65 3.2.2 Foam or Aerated Fluids ........................................................................................... 66 3.2.3 Water-Based Muds .................................................................................................. 66 3.2.3.1 Advantages .................................................................................................. 66 3.2.3.2 Disadvantages ............................................................................................. 66 3.2.4 Oil-Emulsion Muds .................................................................................................. 67 3.2.5 Oil-Based Muds ....................................................................................................... 67 3.2.5.1 Advantages .................................................................................................. 67 3.2.5.2 Disadvantages ............................................................................................. 67 3.3 BASIC MUD RHEOLOGY ............................................................................................. 68 3.3.1 Mud Density ............................................................................................................ 68 3.3.2 Mud Viscosity .......................................................................................................... 68 3.3.3 Gel Strength ............................................................................................................ 69 3.3.4 High versus Low Viscosity and Gel Strength ........................................................... 70 3.3.5 Filtrate / Fluid Loss .................................................................................................. 70 3.3.6 Filter Cake ............................................................................................................... 70 3.3.7 Mud pH.................................................................................................................... 71 Wellsite Procedures & Operations Manual
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3.3.8 4
SUBSURFACE PRESSURES .................................................................................................. 72 4.1 4.2 4.3 4.4 4.5
5
Mud Salinity .............................................................................................................71
UNDERBALANCE VERSUS OVERBALANCE .............................................................. 73 PORE PRESSURE ....................................................................................................... 74 HYDROSTATIC PRESSURE ........................................................................................ 74 PRESSURE GRADIENT ............................................................................................... 75 APPARENT AND EFFECTIVE MUD WEIGHT .............................................................. 75
DRILLING A WELL ..................................................................................................................77 5.1
THE WELL BORE ......................................................................................................... 77 5.1.1 Starting Point ........................................................................................................... 77 5.1.2 Surface Hole ............................................................................................................78 5.1.3 Intermediate Hole .................................................................................................... 79 5.1.4 Total Depth ..............................................................................................................80 5.2 DRILLING AND MAKING HOLE.................................................................................... 81 5.2.1 Pipe Tally.................................................................................................................81 5.2.2 Drill Breaks and Flow Checks .................................................................................. 82 5.2.3 Reaming ..................................................................................................................82 5.2.4 Circulating ............................................................................................................... 83 5.3 CORING ........................................................................................................................83 5.3.1 Purpose ...................................................................................................................83 5.3.2 Coring Methods ....................................................................................................... 84 5.3.3 Core Barrel Assembly .............................................................................................. 84 5.3.4 Retrieval and Handling Operations .......................................................................... 86 5.4 TRIPPING .....................................................................................................................86 5.4.1 Trip Speed ............................................................................................................... 86 5.4.2 Pulling out of Hole (POOH / POH) ........................................................................... 87 5.4.3 Running in Hole (RIH).............................................................................................. 89 5.4.4 Monitoring Displacements ....................................................................................... 90 5.4.5 Hookload .................................................................................................................90 5.4.6 Strapping and Rabbiting the Pipe ............................................................................ 92 5.5 CASING AND CEMENTING .......................................................................................... 92 5.5.1 Purpose ...................................................................................................................92 5.5.2 Types of Casing....................................................................................................... 92 5.5.3 Surface Equipment .................................................................................................. 93 5.5.4 Subsurface Equipment ............................................................................................ 94 5.5.5 Preparing to Run Casing ......................................................................................... 95 5.5.6 Running Casing ....................................................................................................... 95 5.5.7 Cementing Operation............................................................................................... 97 5.5.8 Other Applications ................................................................................................... 98 5.6 PRESSURE TESTS ...................................................................................................... 99 5.6.1 Leak Off and Formation Integrity Tests .................................................................... 99 5.6.2 Repeat Formation Testing ..................................................................................... 100 5.6.3 Drill Stem Testing .................................................................................................. 101 5.6.3.1 Performing a Drill Stem Test ...................................................................... 102 6
WIRELINE LOGGING ............................................................................................................ 104 6.1 6.2 6.3
CALIPER LOGS .......................................................................................................... 104 SPONTANEOUS POTENTIAL LOGS ......................................................................... 105 RESISTIVITY LOGS ................................................................................................... 105
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6.3.1 Lateral Focus Log .................................................................................................. 106 6.3.2 Induction Log ......................................................................................................... 106 6.3.3 Microresistivity Log ................................................................................................ 106 6.4 RADIOACTIVITY LOGS .............................................................................................. 106 6.4.1 Gamma Ray Logs ................................................................................................. 106 6.4.2 Neutron Logs ......................................................................................................... 107 6.4.3 Density Logs.......................................................................................................... 107 6.5 ACOUSTIC LOGS....................................................................................................... 107 6.6 TYPICAL LOGGING RUNS......................................................................................... 108 7
DEVIATION CONTROL.......................................................................................................... 109 7.1
COMMON CAUSES OF DEVIATION .......................................................................... 109 7.1.1 Interbedded Lithology / Drillability .......................................................................... 109 7.1.2 Formation Dip ........................................................................................................ 110 7.1.3 Faults .................................................................................................................... 110 7.1.4 Poor Drilling Practices ........................................................................................... 110 7.2 PROBLEMS ASSOCIATED WITH DEVIATION .......................................................... 111 7.2.1 Doglegs and Keyseats........................................................................................... 111 7.2.2 Ledges .................................................................................................................. 112 7.2.3 Stuck Pipe ............................................................................................................. 112 7.2.4 Increased Torque / Drag and Drillpipe Fatigue ...................................................... 113 7.2.5 Casing and Cementing .......................................................................................... 113 7.3 PREVENTION OF DEVIATION ................................................................................... 113 7.3.1 Pendulum Effect .................................................................................................... 113 7.3.2 Pendulum Assembly .............................................................................................. 115 7.3.3 Packed-Hole Assembly ......................................................................................... 116 7.3.4 Packed Pendulum Assembly ................................................................................. 117 7.3.5 Stabilizers and Reamers ....................................................................................... 118 7.3.6 Drilling Procedures ................................................................................................ 119 8
DIRECTIONAL AND HORIZONTAL DRILLING ..................................................................... 120 8.1 8.2
REASONS FOR DIRECTIONAL DRILLING ................................................................ 120 SURVEYS / CALCULATIONS ..................................................................................... 121 8.2.1 Survey Methods .................................................................................................... 121 8.2.1.1 Single-Shot Surveys .................................................................................. 121 8.2.1.2 Multi-Shot Surveys ..................................................................................... 121 8.2.1.3 Gyroscopic Surveys ................................................................................... 121 8.2.1.4 Measurement While Drilling (MWD) ........................................................... 121 8.2.2 Survey Measurements........................................................................................... 122 8.2.3 Survey Calculation Methods .................................................................................. 122 8.2.3.1 Radius of Curvature ................................................................................... 122 8.2.3.2 Minimum Curvature.................................................................................... 123 8.2.4 Directional Drilling Terminology ............................................................................. 123 8.3 DRILLING TECHNIQUES ........................................................................................... 125 8.3.1 Well Profiles .......................................................................................................... 125 8.3.2 Drilling Stages ....................................................................................................... 126 8.3.3 Whipstocks, Motors and Techniques ..................................................................... 127 8.3.3.1 Whipstocks ................................................................................................ 127 8.3.3.2 Downhole Motors and Bent Subs ............................................................... 128 8.3.3.3 Rotating and Sliding ................................................................................... 129 8.3.3.4 Jetting ........................................................................................................ 129 Wellsite Procedures & Operations Manual
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8.4
9
HORIZONTAL DRILLING ............................................................................................ 129 8.4.1 Classification ......................................................................................................... 130 8.4.2 Horizontal Drilling Considerations .......................................................................... 131 8.4.2.1 Radius Effects ............................................................................................ 131 8.4.2.2 Reversed Drillstring Design ........................................................................ 131 8.4.2.3 Drillpipe Fatigue ......................................................................................... 132 8.4.2.4 Hole Cleaning ............................................................................................ 132 8.4.2.5 Use of Top Drives ...................................................................................... 132 8.4.2.6 Casing and Cementing ............................................................................... 132 8.4.2.7 Formation Considerations .......................................................................... 133 8.4.2.8 Formation Evaluation ................................................................................. 133 8.4.2.9 Gas Behavior / Well Control ....................................................................... 133
DRILLING PROBLEMS .......................................................................................................... 134 9.1
FORMATION PROBLEMS AND HOLE STABILITY..................................................... 134 9.1.1 Fractures ............................................................................................................... 134 9.1.1.1 Associated Problems ................................................................................. 134 9.1.1.2 Drilling Fractured Formations ..................................................................... 134 9.1.2 Shales ................................................................................................................... 135 9.1.2.1 Reactive Shales ......................................................................................... 135 9.1.2.2 Overpressured Shales ............................................................................... 136 9.1.3 Surface Formations ............................................................................................... 136 9.1.4 Salt Sections ......................................................................................................... 137 9.1.5 Coal Beds .............................................................................................................. 137 9.1.6 Anhydrite / Gypsum Formations ............................................................................ 137 9.2 LOST CIRCULATION .................................................................................................. 138 9.2.1 Occurrences .......................................................................................................... 138 9.2.2 Detection ............................................................................................................... 138 9.2.3 Problems ............................................................................................................... 139 9.2.4 Prevention ............................................................................................................. 139 9.2.5 Remedies .............................................................................................................. 140 9.3 KICKS AND BLOWOUTS ............................................................................................ 140 9.3.1 Causes of Kicks ..................................................................................................... 140 9.3.2 Kick Warning Signs ............................................................................................... 141 9.3.3 Indications of Kicks While Drilling .......................................................................... 141 9.3.4 Indicators While Tripping ....................................................................................... 142 9.3.5 Flow Checks .......................................................................................................... 143 9.4 STUCK PIPE ............................................................................................................... 144 9.4.1 Hole Pack Off or Bridge ......................................................................................... 144 9.4.2 Differential Sticking ................................................................................................ 145 9.4.3 Wellbore Geometry ................................................................................................ 146 9.4.3.1 Stuck Pipe during RIH ................................................................................ 147 9.4.3.2 Stuck Pipe during POH .............................................................................. 147 9.4.4 Rotary Drilling Jars ................................................................................................ 148 9.4.4.1 Hydraulic Jars ............................................................................................ 149 9.4.4.2 Mechanical Jars ......................................................................................... 149 9.4.4.3 Jar Accelerator ........................................................................................... 149 9.4.5 Fish—Cause and Indication ................................................................................... 150 9.4.6 Fishing Equipment ................................................................................................. 151 9.5 DRILLSTRING VIBRATIONS ...................................................................................... 154 9.5.1 Torsional Vibration ................................................................................................. 155 Page 8 of 278
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9.5.2 Axial Vibration ....................................................................................................... 156 9.5.3 Lateral Vibration .................................................................................................... 158 9.6 WASHOUTS ............................................................................................................... 161 9.6.1 Drillstring Washouts............................................................................................... 161 9.6.2 Hole Washouts ...................................................................................................... 161 10 UNDERBALANCED DRILLING ............................................................................................. 163 10.1 BENEFITS AND LIMITATIONS OF UNDERBALANCED DRILLING ........................... 163 10.2 UNDERBALANCED DRILLING FLUIDS ..................................................................... 164 10.2.1 Gas and Air Drilling................................................................................................ 164 10.2.1.1 Advantages ................................................................................................ 164 10.2.1.2 Disadvantages ........................................................................................... 164 10.2.1.3 Equipment.................................................................................................. 165 10.2.1.4 Drilling Operations ..................................................................................... 165 10.2.1.5 Drilling problems ........................................................................................ 165 10.2.2 Mist Drilling ............................................................................................................ 166 10.2.2.1 Advantages ................................................................................................ 166 10.2.2.2 Disadvantages ........................................................................................... 166 10.2.3 Foam Drilling ......................................................................................................... 166 10.2.3.1 Advantages ................................................................................................ 167 10.2.3.2 Disadvantages ........................................................................................... 167 10.2.4 Aerated Mud Drilling .............................................................................................. 167 10.2.4.1 Advantages ................................................................................................ 167 10.2.4.2 Disadvantages ........................................................................................... 167 10.2.5 Mud Drilling ........................................................................................................... 168 10.2.5.1 Advantages ................................................................................................ 168 10.2.5.2 Disadvantages ........................................................................................... 168 10.3 UBD EQUIPMENT AND PROCEDURES .................................................................... 168 10.3.1 Rotating Heads...................................................................................................... 168 10.3.2 Closed Circulating and Separating Systems .......................................................... 170 10.3.3 Blooie Line and Sample Catcher ........................................................................... 170 10.3.4 Gas Measurement ................................................................................................. 171 10.4 COILED TUBING UNITS ............................................................................................. 172 10.4.1 Components .......................................................................................................... 172 10.4.2 Drilling Applications ............................................................................................... 173 10.4.3 Advantages and Disadvantages ............................................................................ 173 11 ROCKS AND RESERVOIRS .................................................................................................. 175 11.1 INTRODUCTORY PETROLOGY ................................................................................ 175 11.1.1 Igneous ................................................................................................................. 175 11.1.2 Metamorphic.......................................................................................................... 175 11.1.3 Sedimentary .......................................................................................................... 175 11.1.3.1 Sediment Classification .............................................................................. 176 11.1.3.2 Compaction and Cementation .................................................................... 177 11.1.3.3 Clastic Rock Types .................................................................................... 177 11.1.3.4 Chemical and Organic Rock Types ............................................................ 178 11.2 PETROLEUM GEOLOGY ........................................................................................... 178 11.2.1 Petroleum Generation ........................................................................................... 178 11.2.2 Maturation of Petroleum ........................................................................................ 179 11.2.3 Petroleum Migration .............................................................................................. 180 11.2.4 Primary Migration .................................................................................................. 181 Wellsite Procedures & Operations Manual
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11.2.5 Secondary Migration .............................................................................................. 182 11.2.6 Hydrocarbon Traps ................................................................................................ 182 11.2.6.1 Stratigraphic Traps ..................................................................................... 182 11.2.7 Types of Structural Traps ...................................................................................... 184 11.2.7.1 Fold Related............................................................................................... 184 11.2.7.2 Fault Related.............................................................................................. 184 11.2.7.3 Dome Related ............................................................................................ 185 11.3 PETROLEUM COMPOSITION .................................................................................... 186 11.3.1 Saturated Hydrocarbons or Alkanes ...................................................................... 186 11.3.1.1 Paraffins..................................................................................................... 187 11.3.1.2 Naphthenes................................................................................................ 188 11.3.2 Unsaturated Hydrocarbons or Aromatics ............................................................... 189 11.3.3 API Gravity Classification ...................................................................................... 189 11.4 RESERVOIR CHARACTERISTICS ............................................................................. 190 11.4.1 Porosity ................................................................................................................. 190 11.4.1.1 Sandstones ................................................................................................ 190 11.4.1.2 Limestones ................................................................................................ 191 11.4.2 Permeability ........................................................................................................... 191 11.4.3 Water Saturation.................................................................................................... 192 11.4.4 Reservoir Zones, Contacts and Terminology ......................................................... 192 12 MUD LOGGING—INSTRUMENTATION AND INTERPRETATION........................................ 194 12.1 DEPTH AND RATE OF PENETRATION ..................................................................... 194 12.1.1 The Geolograph..................................................................................................... 194 12.1.2 Crown Sheave ....................................................................................................... 196 12.1.3 Drawworks Sensor ................................................................................................ 197 12.1.4 Heave Compensation ............................................................................................ 197 12.1.5 Rate of Penetration (ROP) ..................................................................................... 200 12.1.5.1 Bit Selection ............................................................................................... 201 12.1.5.2 Rotary speed (RPM) .................................................................................. 201 12.1.5.3 Weight on Bit (WOB or FOB) ..................................................................... 201 12.1.5.4 Differential Pressure................................................................................... 202 12.1.5.5 Hydraulics and Bottomhole Cleaning ......................................................... 202 12.1.5.6 Bit Wear ..................................................................................................... 203 12.1.5.7 Lithology .................................................................................................... 203 12.1.5.8 Depth ......................................................................................................... 203 12.1.5.9 Formation Pressure.................................................................................... 203 12.1.6 Drilling Breaks ....................................................................................................... 203 12.1.7 Controlled Drilling .................................................................................................. 205 12.2 HOOKLOAD AND WEIGHT ON BIT............................................................................ 206 12.2.1 Load or Pancake Cell ............................................................................................ 207 12.2.2 Strain Gauge ......................................................................................................... 207 12.2.3 Weight on Bit ......................................................................................................... 208 12.2.4 Hookload, Drag and Overpull................................................................................. 209 12.3 ROTARY SPEED AND ROTARY TORQUE ................................................................ 211 12.3.1 Rotary Speed ........................................................................................................ 211 12.3.2 Rotary Torque........................................................................................................ 212 12.3.2.1 Formation Evaluation and Fracture Identification ....................................... 214 12.3.2.2 Sticking Pipe .............................................................................................. 215 12.3.3 Torsional Vibrations ............................................................................................... 215 12.4 PUMP OR STANDPIPE PRESSURE .......................................................................... 216 Page 10 of 278
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12.5 ANNULAR OR CASING PRESSURE .......................................................................... 219 12.6 PUMP RATE AND OUTPUT ....................................................................................... 220 12.6.1 Rig Pumps ............................................................................................................. 220 12.6.2 Pump Output Calculation ....................................................................................... 221 12.6.2.1 Triplex Pump.............................................................................................. 221 12.6.2.2 Duplex Pump ............................................................................................. 222 12.6.3 Lag Calculations .................................................................................................... 222 12.6.3.1 Annular volume calculations in barrels ....................................................... 225 12.6.3.2 Annular volume calculations in cubic meters .............................................. 225 12.6.3.3 Lag Checks ................................................................................................ 225 12.6.3.4 Standard Conversions for Lag Calculations ............................................... 226 12.7 FLOWRATE AND PIT LEVELS ................................................................................... 226 13 MUDLOGGING PROCEDURES ............................................................................................. 229 13.1 CUTTINGS DESCRIPTIONS ...................................................................................... 229 13.1.1 Rock Type and Classification ................................................................................ 229 13.1.2 Color ..................................................................................................................... 229 13.1.3 Texture .................................................................................................................. 230 13.1.3.1 Carbonate Rocks ....................................................................................... 230 13.1.3.2 Siliceous Rocks ......................................................................................... 230 13.1.3.3 Argillaceous Rocks .................................................................................... 231 13.1.3.4 Carbonaceous Rocks ................................................................................. 231 13.1.4 Cement and Matrix ................................................................................................ 232 13.1.5 Hardness ............................................................................................................... 232 13.1.6 Fossils and Accessory Minerals............................................................................. 232 13.1.7 Sedimentary Structures ......................................................................................... 232 13.1.8 Porosity ................................................................................................................. 232 13.1.8.1 Siliceous rocks ........................................................................................... 232 13.1.8.2 Carbonate rocks ........................................................................................ 233 13.1.9 Chemical Tests...................................................................................................... 233 13.1.9.1 Hydrochloric Acid (HCl) - Effervescence .................................................... 233 13.1.9.2 Hydrochloric Acid (HCl) - Oil Reaction ....................................................... 233 13.1.9.3 Swelling ..................................................................................................... 233 13.1.9.4 Sulfate Test................................................................................................ 234 13.1.9.5 Chloride Test ............................................................................................. 234 13.1.9.6 Alizarin Red Test........................................................................................ 234 13.1.9.7 Cement Test .............................................................................................. 234 13.2 OIL SHOWS................................................................................................................ 235 13.2.1 Odor ...................................................................................................................... 235 13.2.2 Oil Staining and Bleeding ...................................................................................... 235 13.2.3 Fluorescence ......................................................................................................... 235 13.2.4 Sample Preparation ............................................................................................... 236 13.2.5 Contaminants ........................................................................................................ 236 13.2.6 Color and Brightness ............................................................................................. 237 13.2.7 Fluorescence Distribution ...................................................................................... 237 13.2.7.1 Solvent Cut ................................................................................................ 238 13.2.7.2 Residue ..................................................................................................... 239 13.2.7.3 Sampling the Mud ...................................................................................... 239 13.2.8 Quantitative Fluorescence Technique™ (QFT)...................................................... 239 13.3 CUTTINGS BULK DENSITY ....................................................................................... 241 13.4 SHALE DENSITY ........................................................................................................ 243 Wellsite Procedures & Operations Manual
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13.5 SHALE FACTOR ......................................................................................................... 245 13.6 CALCIMETRY ............................................................................................................. 247 13.7 ENHANCED HOLE MONITORING.............................................................................. 248 13.7.1 Consequences of Poor Stability or Poor Hole Cleaning ......................................... 249 13.7.2 Problems of Measuring Actual Cuttings Volume .................................................... 249 13.7.3 Volume of Vessel................................................................................................... 250 13.7.4 Measurement of Cuttings / Hour ............................................................................ 250 13.7.5 Correction to Total Volume .................................................................................... 251 13.7.6 Theoretical Cuttings Volume .................................................................................. 252 13.7.7 Actual / Theoretical Cuttings Volume Ratio ............................................................ 253 13.7.8 Recording, Evaluating and Reporting .................................................................... 254 13.7.8.1 Plotting the Data ........................................................................................ 255 13.8 HIGH RESOLUTION TRIP MONITORING .................................................................. 256 13.8.1 Theory and Benefits............................................................................................... 256 13.8.2 Procedure .............................................................................................................. 257 13.8.2.1 Theoretical Hookload ................................................................................. 257 13.8.2.2 System and Data Preparation .................................................................... 257 13.8.3 Interpretation ......................................................................................................... 258 13.8.4 Benefits to the Operator......................................................................................... 261 13.9 DST PROCEDURES ................................................................................................... 261 13.9.1 Water Cushion ....................................................................................................... 262 13.9.2 Test String Components ........................................................................................ 262 13.9.3 Testing Procedures ............................................................................................... 267 14 ABBREVIATIONS .................................................................................................................. 270
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List of Figures Figure 1: Land Rig—Derrick Being Assembled .................................................................................. 18 Figure 2: Land Rig—Operational ....................................................................................................... 19 Figure 3: Jack-up Rig ........................................................................................................................ 21 Figure 4: Semi-Submersible Rig ........................................................................................................ 22 Figure 5: The Hoisting System—Supported By the Derrick ................................................................ 25 Figure 6: The Drawworks and Fast Line ............................................................................................ 26 Figure 7: Traveling Block Suspended by Drilling Line in Derrick ........................................................ 26 Figure 8: Kelly Bushing Located into Rotary Table Master Bushing ................................................... 28 Figure 9: Top Drive Unit..................................................................................................................... 29 Figure 10: Pipe Deck and V-Door ...................................................................................................... 31 Figure 11: Connecting the Elevators and Using the Slips .................................................................. 31 Figure 12: Slips ................................................................................................................................. 32 Figure 13: Breaking a Pipe Connection with Tongs ........................................................................... 33 Figure 14: Top of Mud Pit System ..................................................................................................... 34 Figure 15: The Circulating System ..................................................................................................... 35 Figure 16: Shaker Box ....................................................................................................................... 36 Figure 17: Mud Conditioning System and Pit Setup ........................................................................... 37 Figure 18: Desander / Desilter Hydroclone ........................................................................................ 38 Figure 19: Rig Pump—Triplex............................................................................................................ 39 Figure 20: Tri-cone Milled Tooth Bit ................................................................................................... 40 Figure 21: Tri-Cone Bit—Terminology ............................................................................................... 41 Figure 22: Diamond Bit and PDC Bit.................................................................................................. 44 Figure 23: Drill Collar Types—Square, Spiral and Smooth ................................................................ 48 Figure 24: Stabilizers ......................................................................................................................... 49 Figure 25: 3-Point Near-Bit Reamer................................................................................................... 49 Figure 26: Mechanical Jar Operation ................................................................................................. 51 Figure 27: Annular Preventer ............................................................................................................. 53 Figure 28: Annular Preventer and Ram Preventers ........................................................................... 54 Figure 29: Accumulator Bottle Volumes ............................................................................................. 56 Figure 30: BOP Control Panel ........................................................................................................... 57 Figure 31: Simple BOP Stack Schematic ........................................................................................... 58 Figure 32: Choke Manifold ................................................................................................................. 59 Figure 33: Mud Balance..................................................................................................................... 68 Figure 34: Marsh Funnel.................................................................................................................... 69 Wellsite Procedures & Operations Manual
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Figure 35: Fann Viscometer or V-G Meter for Measuring Gel Strength .............................................. 69 Figure 36: Land Rig Blowout .............................................................................................................. 72 Figure 37: Offshore Blowout (Deepwater Horizon Rig) ...................................................................... 73 Figure 38: Christmas Tree ................................................................................................................. 81 Figure 39: Core Barrel ....................................................................................................................... 85 Figure 40: Trip Tank .......................................................................................................................... 87 Figure 41: Determining Maximum Running Speed vs. Given Swab Pressure .................................... 89 Figure 42: Sample Trip Sheet ............................................................................................................ 91 Figure 43: Centralizer and Wall Cake Scratcher ................................................................................ 94 Figure 44: Monitoring Mud Returns and Displacements ..................................................................... 96 Figure 45: Cementing Operation ........................................................................................................ 98 Figure 46: Leak Off Test .................................................................................................................... 99 Figure 47: Drill Stem Testing (DST) ................................................................................................. 102 Figure 48: Wireline Logging Company Sondes ................................................................................ 104 Figure 49: E-log Sondes .................................................................................................................. 108 Figure 50: Hole Deviation due to Interbedded Lithology ................................................................... 109 Figure 51: Hole Deviation Due to Formation Dip .............................................................................. 110 Figure 52: Varying Types of Faulting ............................................................................................... 110 Figure 53: Dogleg and Keyseat........................................................................................................ 111 Figure 54: Ledges ............................................................................................................................ 112 Figure 55: Pendulum Force and Formation Resistance ................................................................... 114 Figure 56: Pendulum Assemblies—Slick and with Stabilizers .......................................................... 115 Figure 57: Packed-hole Assemblies ................................................................................................. 116 Figure 58: Packed Pendulum Assembly .......................................................................................... 118 Figure 59: Determining Curvature .................................................................................................... 123 Figure 60: Directional Drilling Terminology ...................................................................................... 125 Figure 61: Drilling Profiles—Shallow Deflection, S-Curve and Deep Deflection ............................... 126 Figure 62: Whipstock ....................................................................................................................... 127 Figure 63: Downhole Motor and Bent Sub ....................................................................................... 128 Figure 64: Classification of Horizontal Wells .................................................................................... 130 Figure 65: Differential Sticking ......................................................................................................... 146 Figure 66: Stuck Pipe during RIH..................................................................................................... 147 Figure 67: Stuck Pipe During POH .................................................................................................. 148 Figure 68: Hydraulic Jars ................................................................................................................. 149 Figure 69: Milling Tools .................................................................................................................... 152 Page 14 of 278
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Figure 70: Overshot ......................................................................................................................... 152 Figure 71: Wireline Spear ................................................................................................................ 153 Figure 72: Torsional Vibration .......................................................................................................... 155 Figure 73: Axial Vibration................................................................................................................. 157 Figure 74: Lateral Vibration ............................................................................................................. 159 Figure 75: Rotating Head................................................................................................................. 169 Figure 76: Blooie Line ...................................................................................................................... 170 Figure 77: Gas Measurement from Separator.................................................................................. 171 Figure 78: Gas Measurement from Blooie Line ................................................................................ 171 Figure 79: Coiled Tubing Unit .......................................................................................................... 172 Figure 80: Traps Formed by Fancies Change and Pinchout ............................................................ 183 Figure 81: Trap Formed by Carbonate Reef .................................................................................... 183 Figure 82: Trap Formed by Aolian Reef ........................................................................................... 183 Figure 83: Stratigraphic Traps ......................................................................................................... 184 Figure 84: Fold Related Structural Trap ........................................................................................... 184 Figure 85: Graben Structure ............................................................................................................ 185 Figure 86: Anticlinal Trap ................................................................................................................. 185 Figure 87: Traps Associated with Salt Dome ................................................................................... 186 Figure 88: Geolograph ..................................................................................................................... 195 Figure 89: Geolograph Tracks—Tag Bottom and Drill Ahead .......................................................... 196 Figure 90: Crown Sheave Depth Sensor ......................................................................................... 197 Figure 91: Schematic of Riser Tensioning and Compensation ......................................................... 198 Figure 92: Heave Compensation ..................................................................................................... 199 Figure 93: Schematic showing Travel Block compensation ............................................................. 200 Figure 94: Drill Rate vs. RPM and Drill Rate vs. WOB ..................................................................... 202 Figure 95: Positive and Negative Drilling Breaks ............................................................................. 204 Figure 96: Load Cell ........................................................................................................................ 207 Figure 97: Strain Gauge .................................................................................................................. 208 Figure 98: WOB and Drill Collar Weight ........................................................................................... 209 Figure 99: Hookload—Overpull and Drag ........................................................................................ 210 Figure 100: Torque Clamp ............................................................................................................... 212 Figure 101: Example of Torque Conversion (ft / lb to amps) ............................................................ 213 Figure 102: Changes in Torque Character with Formation ............................................................... 214 Figure 103: Sticking Pipe ................................................................................................................. 215 Figure 104: Hydraulic Transducer on Standpipe .............................................................................. 217 Wellsite Procedures & Operations Manual
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Figure 105: Proximity Sensor on Mud Pump .................................................................................... 220 Figure 106: Example Well Profile for Lag Calculation ...................................................................... 224 Figure 107: Flow Paddle .................................................................................................................. 226 Figure 108: Ultrasonic Sensor and Delaval Float Sensor ................................................................. 227 Figure 109: Measuring the Meniscus ............................................................................................... 242 Figure 110: Measure Consistently on the Meniscus ......................................................................... 242 Figure 111: Density Column and Graph of Density vs. Depth .......................................................... 244 Figure 112: Shale Factor ................................................................................................................. 246 Figure 113: Measuring CEC—a. Water Spreading From Sample, b. Test Complete........................ 247 Figure 114: Auto Calcimeter Kit ....................................................................................................... 247 Figure 115: Calcimetry Result— Limestone vs. Dolomite Dissolve Time ......................................... 248 Figure 116: Cuttings Collected With Vessel in Three Positions ........................................................ 251 Figure 117: Sample Monitoring Record Sheet ................................................................................. 256 Figure 118: Trip Out Plot—Hookload vs. Depth ............................................................................... 259 Figure 119: Trip Out Plot—Problem Section .................................................................................... 260 Figure 120: Trip In Plot—Hookload vs. Depth .................................................................................. 260 Figure 121: Downhole Test String Diagram ..................................................................................... 264
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List of Tables Table 1: IADC Bit Classification ......................................................................................................... 41 Table 2: TBG Grading of Bits ............................................................................................................. 45 Table 3: IADC Bit Grading System .................................................................................................... 45 Table 4: Kick Warning Signs for Lost Circulation, Transitional and Pressured Zones ...................... 141 Table 5: Gas and Air Drilling Problems ............................................................................................ 165 Table 6: Components of Coiled Tubing Units................................................................................... 172 Table 7: Sediment Classification Based on Depositional Environment............................................. 176 Table 8: Sediment Classification Based on Material Origin .............................................................. 177 Table 9: Clastic Rock Types ............................................................................................................ 177 Table 10: Main Types of Chemical and Organic Rocks.................................................................... 178 Table 11: Straight Chained Alkanes ................................................................................................ 187 Table 12: Branched or Iso Chained Alkanes .................................................................................... 188 Table 13: Closed Chained Alkanes - Naphthenes............................................................................ 188 Table 14: Aromatics—Benzene and Toluene................................................................................... 189 Table 15: Measurement of Standpipe Pressure ............................................................................... 218 Table 16: Conditions Affecting Standpipe Pressure ......................................................................... 218 Table 17: Determining Triplex Pump Output .................................................................................... 221 Table 18: Determining Duplex Pump Output.................................................................................... 222 Table 19: Benefits of Lag Calculations............................................................................................. 223 Table 20: Crystal Sizes .................................................................................................................... 230 Table 21: Grain Sizes ...................................................................................................................... 230 Table 22: Cuttings Volume with Varying Hole Sizes and Different ROPs ......................................... 253
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1 RIGS AND THEIR EQUIPMENT 1.1
ROTARY DRILLING RIGS In the early days of petroleum exploration and production, wells were drilled with cable tool rigs. Percussive drilling was the technique used, where a hardened bit suspended on a cable was repeatedly dropped onto the bottom of the hole. The constant pounding broke up the formation, deepening the hole in the process. The drawbacks to the cable tool rig included limited depth capabilities, very slow drilling rates, and incontrollable subsurface formation pressures. Modern drilling uses a rotary drilling method that provides faster drilling rates, much greater depth capabilities, offshore drilling, and safe control of subsurface pressures.
1.2
LAND RIGS Land rigs are designed around a cantilever mast principle, providing easy transportation and quick assembly. The mast or derrick is transported to the drill site in sections, assembled on the ground (Figure 1) and then raised to a vertical position by using the rig’s hoisting system (the drawworks).
Figure 1: Land Rig—Derrick Being Assembled
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Figure 2: Land Rig—Operational
On a land rig, the blowout preventers (BOPs) are positioned directly beneath the rig floor, connecting the floor to the wellhead.
1.3
OFFSHORE DRILLING VESSELS Drilling offshore obviously requires a completely self-contained vessel, in terms of drilling requirements and accommodation for personnel. Situated in remote, hostile locations, they are much more costly to operate and require more sophisticated safety measures because water separates the wellhead from the actual rig. There are different types of offshore rigs and their use principally depends on the depth of water they operate in. Temporary installations (that can move from location to location) used for exploratory drilling can be supported by the seabed or they can be floating and anchored in position. Permanent installations, or platforms, are required for production wells.
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1.3.1
Barges Barges are small, flat-bottomed vessels that can only be used in very shallow waters such as deltas, swamps, lagoons and shallow lakes. They can be either be submerged and rest on the bottom, or float depending on water depth.
1.3.2
Jack-Up Rigs Jack-up rigs are mobile vessels suitable for drilling in shallow seawater depths. They consist of a fixed hull or platform, supported by a number of legs (typically three) that stand on the seafloor. To move a jack-up rig, the legs can be raised so the rig floats on its hull, enabling it to be towed into position by barges. This makes the vessel top-heavy and unstable during towing. To avoid capsizing, calm waters and slow towing speeds are essential. After being towed to the required position, the legs are lowered to the seabed, creating a stable structure unaffected by wave motion. BOPs are mounted underneath the rig floor and a large conductor pipe driven into the seafloor connects the well to the rig and allows drilling fluid to be circulated. In the jack-up example in Figure 3, it can be seen that drilling has not yet started as there is no conductor pipe in place.
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Figure 3: Jack-up Rig
1.3.3
Semi-Submersible Rigs Semi-submersible rigs (semi-subs) are floating rigs that are more suitable for drilling in deeper waters than jack-up rigs. The deck is supported by a number of legs or columns. In subsea, these columns are supported by pontoons that can be solitary or connected. Pontoons and columns are used to ballast and stabilize the rig. This substructure sits below the sea surface, avoiding the surface turbulence, which makes them more stable than drillships and more suited to drilling in rough seas. Pontoons are fitted with thrusters for position adjustment or self-propulsion, but they are generally moved into position by seagoing tugs, with the thrusters being used to assist in the final positioning of the rig. After being correctly positioned, the semi-sub is anchored in place. In deeper waters, the thrusters can be used to maintain position through an automated location monitor. Unlike with the jack-up, BOPs for semi-subs are located on the seabed and mounted on conductor pipe set into the seafloor. Positioning BOPs is not easy and achieved with the assistance of underwater
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cameras or remotely operated vehicles (ROVs). This allows the well to remain secure if the rig is forced to abandon the location. A large flexible telescopic steel pipe called a marine riser connects a BOP to a rig, enabling drilling fluid to be circulated and the drillstring to be guided into the well.
Figure 4: Semi-Submersible Rig
1.3.4
Drillships Drillships can drill in deeper water. They are generally self-propelled and easily transported to the drilling location. They are extremely mobile, but generally less stable than semi-subs and are not able to drill in rougher seas. A drillship can be anchored or its position maintained by automated thruster systems. A drillship has the same subsea equipment as a semi-sub, with the BOPs mounted on the seabed. To compensate for movement of the drillship (or semi-sub), a marine riser includes a telescopic joint to allow for vertical movement. A ball joint at the seafloor allows for horizontal motion.
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The length of the riser is often the limiting factor in deep water drilling because it is subjected to too much bending and stress.
1.3.5
Platforms Platforms are permanently fixed structures installed where mobility is not required. This is typically when multiple wells are drilled to develop and produce a field. Platforms can be of two designs:
Piled Platform. A piled platform consists of a steel jacket that is pinned to the seabed and supports the deck structure. A piled platform is stable in bad weather, but is not mobile. They are usually constructed in separate sections that can be towed to position and constructed in place.
Gravity Platform. A gravity platform is constructed from concrete, steel, or a combination of both. It has a cellular base, providing ballast and storage, with vertical columns supporting the deck structure. A gravity platform is normally fully constructed and then towed to the location and ballasted into position.
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2 ROTARY RIG COMPONENTS 2.1
OVERVIEW A modern rotary drilling rig consists of five principle components: 1. Drill bit and drillstring 2. Fluid circulating system 3. Hoisting system 4. Power system 5. Blowout prevention system The term rotary comes from the physical movement of the drillstring and bit, applying a rotary cutting action to the rock at the bottom of the hole. Rotation can be provided at surface or by motors positioned in the drillstring downhole. The drillstring (1) consists of hollow steel pipe allowing drilling fluid to be transported into the hole. The pipe is typically a combination of a standard drillpipe, but thicker and with a heavier drillpipe and a larger diameter, with heavy drill collars immediately above the bit. This is all supported from the derrick with vertical movement (in and out of the hole) provided by the drawworks, crown block, and traveling block (3) (Figure 5). Rotation of the drillstring, at surface, is applied in one of two ways: either by a rotary table, bushings, and kelly, or by a top drive unit. The drilling fluid, commonly referred to as drilling mud, is stored in mud tanks or pits. From here, the mud can be pumped through the standpipe to the kelly, swivel where it can enter the kelly, and subsequently the drillpipe. The mud can then pass all the way to the bit before returning to surface through the annulus—the space between the wall of the borehole and the drillstring. On return to surface, the mud is passed through several pieces of equipment to remove the drilled rock chips or cuttings, before completing the cycle and returning to the mud tanks (2) (Figure 15). Formations in the shallower part of the wellbore are usually protected by a large diameter steel tubing or casing which is cemented into place. The annulus that the mud now passes through on its way back to surface is now the space between the inside of the casing and the outside of the drillstring. Attached to the top of the casing is the BOP stack (5), a series of valves and seals that can be used to close off the annulus or wellbore to control large subsurface pressures. All of the equipment described above is operated by a central power system (4), which also supplies the general power required for electrical lighting and service company equipment. Typically, this power source is through a central diesel-electric power plant.
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2.2
THE HOISTING SYSTEM
Figure 5: The Hoisting System—Supported By the Derrick
The complete hoisting system has several basic functions:
Supporting the weight of the drillstring, possibly up to several hundred tons.
Lifting the drillstring in and out of the hole.
Maintaining the force or weight applied to the bit during drilling.
The derrick supports the weight of the drillstring at all times, whether the drillstring is suspended from the crown block or supported temporarily in the rotary table. The size and strength of the derrick is the limiting factor for the weight of the drillpipe that can be supported and also the depth that the rig is capable of drilling to. The height of the derrick determines the length of the pipe sections that can housed when the drillstring must be pulled from the hole. During this operation, the pipe is normally broken down into double or triple stands—two or three individual lengths or joints of pipe. During the drilling operation, the kelly and drillstring are supported from the traveling block through the traveling hook. This is connected to the drawworks through a simple pulley system (Figure 5). A steel cable, the drilling line, is spooled on a large reel at the drawworks where it can be drawn in or let out, depending on whether an upward or downward motion of the traveling block is required (Figure 6). Wellsite Procedures & Operations Manual
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Figure 6: The Drawworks and Fast Line
From the drawworks, the drilling line passes up to a stationary set of pulleys, called the crown block, situated at the top of the derrick. The cable is repeatedly passed between a series of wheels, or sheaves, and attaches to the traveling block suspended in the derrick (Figure 7); the traveling block is usually supported by a number of lines, typically 8 to 12.
Figure 7: Traveling Block Suspended by Drilling Line in Derrick
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The drilling line is then passed from the crown block to an anchor where the cable is securely clamped. This length of drilling line is referred to as the deadline, and the deadline anchor is typically located to one side of rig floor (Figure 5). From the deadline anchor, the drilling line passes to a storage reel to one side of the rig, where extra drilling line is stored. The drilling line is commonly referred to as the fast line for the length running from the drawworks to the crown block. This is because the first sheave it is spooled around is generally larger than the others and is known as the fast sheave. The use of the drilling line, or wear, is recorded in terms of the load moved over a given distance. For example, 1 ton-mile means that the line has moved a 1-ton weight a distance of 1 mile. Similarly, a measurement of 1kN-km means that the line has moved 1000 newtons a distance of 1 kilometer. This record allows the drilling crew to determine when the drilling line must be replaced by a new length of cable. The slip and cut procedure requires the traveling block to be lowered to the drill floor so that there is no load on the drilling line. The line is released at the deadline anchor so that new line can be fed or slipped through. The line is tensioned by feeding it through the pulley system and pulling the old line out from the drawworks. This old line can be removed or cut and the new length of cable tensioned and anchored again at the deadline anchor. This procedure allows for even wear on the drilling line as it is used. The drawworks has a heavy-duty braking system allowing for the speed to be controlled or resisted when moving the pipe into the hole. During the drilling operation, the drawworks also allows for control or adjustment of the proportion of the string weight supported by the derrick and the bottom of the hole. This equates to the weight or force that is applied to the bit. This can then be adjusted according to the hardness of the formation and the weight required to produce failure of the formation and to allow penetration or deepening of the hole to proceed.
2.2.1
Providing Rotation to the Drillstring and Bit
2.2.1.1
Kelly and Swivel
The kelly is a hollow length of steel normally around 12 or 13m, square or hexagonal, through which drilling fluid enters the drillpipe. The top of the drillstring is connected to the kelly by a kelly sub (or saver sub). This sub, relatively cheaper to replace than the kelly, saves wear on the connecting threads of the kelly, which passes through a rotary kelly bushing mounted and locked into master bushings that are set into the rotary table (Figure 8).
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Figure 8: Kelly Bushing Located into Rotary Table Master Bushing
Free vertical movement of the kelly, whether rotating or static, is possible through the bushing, allowing upward and downward movement of the drillstring as drilling progresses. Rollers within the bushing facilitate this movement and minimize the wear on the kelly. The shape of the kelly, commonly 4 or 6 sided, fits exactly into the bushing so if the bushing rotates, the kelly rotates. Because the bushing is locked into the rotary table, rotation of the table (electrically or mechanically) rotates the bushing, the kelly and the drillpipe. When the kelly is lifted from the hole to expose the drillpipe, the kelly bushings are lifted with the kelly. Between the kelly and the hook is an assembly known as the swivel. The swivel supports the kelly but does not rotate as the kelly rotates; it prevents the hook and traveling block from rotating and twisting the drilling line as the string is rotated. The swivel is also the point at which the drilling fluid enters the drillstring, through an attachment known as a gooseneck connected to the kelly hose carrying the drilling fluid. A safety valve is located at the top of the kelly called the kelly cock. This cock can be manually closed if the well is flowing due to high subsurface formation pressure. This prevents backpressure from entering, and perhaps damaging, the kelly swivel.
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2.2.1.2
Top Drive Units
On more recent rigs, the rotary drive and swivel are combined into a single top drive system (TDS), which can be electrically or hydraulically operated. The drillstring connects directly into the top drive unit where rotation is applied and where drilling fluid enters the string through a similar swivel and gooseneck assembly. Because rotation is applied directly to the top of the drillstring, there is no requirement for a kelly and rotary bushing.
Figure 9: Top Drive Unit
The advantage of a top drive over the conventional kelly system is primarily one of time and cost. As drilling progresses with a kelly system, only single lengths or joints can be added to the drillstring. This connection process requires the kelly being broken off from the drillstring, picking up and attaching the new joint of pipe to the kelly, then reattaching the new pipe and kelly back to the drillstring.
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With a top drive unit, this operation is much simpler because the pipe is connected directly to the unit and it enables a stand of drillpipe (equivalent to 3 single joints of pipe) to be picked up and added to the drillstring at any time. A complete stand of drillpipe can be drilled continuously, so only one connection is required for every three joints. The overall time required to make connections is less for rigs possessing top drive units. This means a big saving in cost, especially for large land rigs or offshore rigs where the daily cost of hiring the rig is much more expensive. Another important advantage of a top drive unit is when the drillstring is being lifted in or out of the hole (tripping). The conventional kelly is not used when tripping pipe, it is set aside on the rig floor in what is called the rathole, bails and elevators are used to lift the drillstring. If the pipe becomes stuck during the trip, circulation of drilling fluid might be required to free the pipe. With a top drive unit, elevators lift the pipe but they are suspended directly beneath the top drive unit (Figure 9). It is a very quick procedure to attach the top drive unit to the drillstring so that circulation of drilling fluid and rotation of the pipe is possible almost immediately. In most circumstances, this minimizes the potential problem and reduces the time required to solve it. If tripping on a rig using a kelly system it can take 5-10 minutes before fluid circulation can be achieved as the kelly would need to be picked up from the rathole and attached to the drillstring first. During this time, the sticking of the pipe may become worse.
2.2.2
Lifting Equipment Drillpipe is stored on the pipe deck, located to the side of the rig. When pipe must be added to the drillstring the joint is picked up from the pipe deck by a winch. The winch pulls the pipe up a ramp that connects the pipedeck to the drill floor, known as the v-door (Figure 10). The blocks are then lowered and the joint of pipe is picked up in the elevators. When picked up, the joint of pipe is lowered into the mousehole in the drillfloor (a hole drilled into the surface sediments and lined with tubular) where it is ready for use when the next connection is made. Note that different elevators are used to pick up collars or casing tubular.
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Figure 10: Pipe Deck and V-Door
2.2.2.1
Bails and Elevators
These are used to lift the pipe into position or remove it when the connection is broken. Elevators are simple clamps placed and closed around the stem of the pipe. As the elevators are lifted, they move up the pipe until they come against the wider tool joint so the pipe can be lifted.
Figure 11: Connecting the Elevators and Using the Slips
Elevators are suspended from the traveling block by links or bails, so vertical movement is applied from the drawworks. Elevators are of specific sizes and designs to accommodate pipe of different diameter, casing joints, and drill collars. Wellsite Procedures & Operations Manual
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2.2.2.2
Slips
While connections are being made or broken, the drillstring must be suspended and supported in the rotary table to prevent it from falling down the hole. This is achieved by using slips, which are tapered or wedge-shaped dies held together in a frame with handles (Figure 11 and Figure 12).
Figure 12: Slips
The slips are placed around the stem of the pipe and lowered along with the pipe into the master bushings where they become set, meaning fully supporting the weight of the drillstring in the rotary table. 2.2.2.3
Tongs
These are used to tighten or loosen connections between sections of pipe. These wrenches are suspended on cables from the derrick and attached to the cathead on the drawworks by a chain through which tension can be applied. Two tongs are used and placed on either side of the connection or joint. The lower tong holds the drillstring in place below the joint. The upper tong, by pulling on the chain, loosens or breaks the connection or in the opposite direction, tightens or makes the connection. When making the connection, a gauge on the chain allows the correct amount of torque to be applied. 2.2.2.4
Power Tongs and Pipe Spinners
These pneumatically powered wrenches enable rapid spinning of the pipe when making or breaking connections. Tongs are used to apply final torque when making the connection and to initially loosen the joint when breaking the connection.
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Figure 13: Breaking a Pipe Connection with Tongs
2.2.2.5
Chain Wrench
If pneumatic wrenches are not available, spinning the pipe must be done manually with a chain wrench. Chain is wrapped around the pipe, clasped and gripped by the wrench. Spinning the pipe is done by physically walking around the pipe while it is gripped and held by the wrench.
2.3
THE CIRCULATING SYSTEM There are many ways in which mud aids the drilling process and, in fact, is a vital component to the successful drilling of a well. The most important functions are as follows:
To cool and lubricate the drill bit and drillstring to minimize wear, prolong life and reduce costs.
To remove drilled rock fragments or cuttings from the hole. This keeps the annulus clear and allows examination at surface for formation evaluation.
To balance high fluid pressures that can be present in formations and to minimize the potential for kicks or blowouts. The safety of rig personnel and of the rig is of paramount importance.
To stabilize the wellbore and formations that have been drilled.
For more details on the types of drilling mud and its functions, see Section 3 Drilling Fluid. Creating drilling mud is similar to cooking, with many ingredients going into the system. Each ingredient or additive has a function. The mud is built and stored in mud tanks or pits; gratings cover the pits and creating walkways and allowing access points to place mud logging sensors (Figure 14). These pits are named depending on their specific function. Typically, they are one of the following:
Premix Pit—Where additional chemicals are added and mixed into the mud system.
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Suction Pit—Where the mud is taken by the rig pumps to begin its journey to the drillstring. This is the live or active pit, lined up to the actual wellbore.
Reserve or Settling Pit—For holding additional mud volume, generally not part of the active system.
Shaker Pit—A tank situated directly beneath the shale shakers. A sand trap is normally an integral part of the shaker pit. It allows as much fine material, sand and silt, to settle from the mud system and be removed.
Trip Tank—A small tank designed to monitor small mud displacements. Situations that require this include tripping the drillstring out of the hole and monitoring a well kick.
Slug Pit—A tank to make up small volumes of special mud for specific operations during the drilling of a well.
Figure 14: Top of Mud Pit System
The number of pits required on a rig depends on the size and the depth of the well being drilled, and on the volume of mud required to fill that hole. Typically, 4 to 6 tanks are used, but for larger wells and platforms this number can increase to 16 or more. From the mud tanks, the mud is pumped through an upright standpipe fixed to the side of the derrick, through a gooseneck into the connected kelly hose. From the kelly hose, the mud passes through another gooseneck and through the swivel into the kelly, where it is forced down the inside of the drillstring. Page 34 of 278
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Exiting the drillstring through the bit, the mud returns to the surface through the annulus, which is the space between the wellbore wall / casing and the outside of the drillstring (Figure 15).
Figure 15: The Circulating System
For offshore wells, a further conduit must be positioned to allow mud to be circulated from the seabed to the rig. This is done through a large conductor pipe or marine riser:
Conductor—A pipe driven into the seafloor, providing a conduit to the BOP stack situated beneath the rig floor on jack-ups and platforms.
Marine Riser—A pipe connected to the top of the BOP stack located on the seabed on semi-subs and drillships, providing a conduit to the rig. The riser incorporates a telescopic or slip joint that allows for rig heave, adjusting the vertical position of the rig.
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2.3.1
Mud Conditioning Equipment Solids control is vital in maintaining efficient drilling operations. High mud solids increase mud density and viscosity, leading to higher chemical-treating costs, poor hydraulics and increased pumping pressures. With increased solids, the mud becomes increasingly abrasive and increases wear on the drill string, wellbore and surface equipment. It becomes more difficult to remove solids from the mud as the solids content increases. Drilling mud surfacing from the wellbore contains cuttings, sand and other solids, and probably gas, all of which must be removed before the mud can be re-circulated in the well. Mud treatment clays and chemicals must also be added to maintain the required properties. These functions require special equipment. When exiting the wellbore at the surface, the mud is drawn off at the bell nipple and directed along a flowline to a shaker box (also called a header box or possum belly). The shaker box is where the mud logger positions a gas trap and mud monitoring sensors to analyze the mud returning from the hole (Figure 16).
Figure 16: Shaker Box
Gates in the shaker box regulate the flow of mud onto the shale shaker. Sloped and vibrating mesh screens (normally two) separate the drilled cuttings from the drilling mud, which passes through screens into the sand trap or shaker pit. The mud can then be returned to the main pit system where the circulating cycle can start again.
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The screens can be changed so the size of the mesh is appropriate to the size of the cuttings to be removed. Normally, a coarser screen is positioned above a finer screen. The vibration motion of the screens improves the separation of mud from the cuttings. Samples for geological analysis are collected at this point. With environmental concerns an important consideration, the cuttings separated at the shale shaker are collected in tanks so they can be transported to sites where they can be cleaned of residual mud or chemicals and deposited. Additional equipment is put into the circulating system before the mud returns to the mud tanks (Figure 17).
Figure 17: Mud Conditioning System and Pit Setup
If the mud is particularly gaseous, it is passed through a degasser, a large tank with an agitator to force the release of gas from the mud.
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After passing through the shale shakers, there can still be very fine solid material such as silt or sand grains that must be removed. The mud first drops into a sand trap after passing through the shakers. This is a conical or tapered chamber incorporated within the shaker pit, where the mud’s flowrate is reduced, allowing solids to separate and settle. The bottom of the trap is sloped so the settling particles fall to the base where they are collected and discarded. If these particles do not settle out when the mud passes through the sand trap, the mud must pass through additional solids control equipment before returning it to the mud tanks. A desander (Figure 18), when used in addition to the shale shaker, removes most of the abrasive solids which reduces wear on the mud pumps, surface equipment, drill string and bit. A desilter, which removes even finer material from the mud, is also used with the shale shaker and desander. Both of these use a hydroclone to separate out the solids.
Figure 18: Desander / Desilter Hydroclone
To remove large amounts of clay solids suspended in the mud, additional centrifuges are used. When the mud is cleaned, it can be returned to the mud tanks for re-circulating. A centrifuge consists of a highspeed rotating, cone-shaped drum and a screw conveyor that moves the coarse particles in the drum to the discharge port and back to the mud system. It is often used when the mud weight must be significantly reduced, rather than adding liquid and increasing the volume. The centrifuge can also remove glass or plastic beads that are used to improve lubrication or to reduce density in underbalanced applications. Fine grains are very abrasive and damaging to equipment such as pumps, drillstring and bits. The control of fine grains is important in controlling the density of the mud. If solids were allowed to remain and build up in the mud, its density increases. Page 38 of 278
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One further step to prepare the mud for recirculation is performed by a degasser, which separates and vents large volumes of entrained gas to a flare line. Re-circulating gas-cut mud can be hazardous, reduces pumping efficiency, and lowers hydrostatic pressure. Hydrostatic pressure is required to balance the formation pressure. A mud-gas separator safely handles high-pressure gas and flow from a well when a kick occurs. A vacuum degasser is more appropriate for separating entrained gas, which may resemble foaming on the surface of the mud (gas cut mud).
2.3.2
Rig Pumps Most rigs have two rig pumps to circulate the mud under pressure through the system. Smaller rigs drilling shallower holes may only require one; large offshore rigs may have three and include a booster pump connected to the riser. Rig pumps can be of two types:
Duplex Pumps—These possess two cylinders, or chambers, each of which discharges drilling fluid on forward and backward motion of the pump stroke. As the mud is discharged on one side of the piston, the cylinder is filled up from the other side. As the piston returns, this mud is now discharged, with the previously discharged side now being refilled behind the piston.
Triplex Pumps—These possess three cylinders. Unlike the duplex pump, mud is discharged on the forward stroke in each cylinder only, leaving the cylinder behind the piston empty. As the piston returns on the backward part of the stroke, mud refills the chamber. This mud is again discharged on the forward part of the pump stroke.
Figure 19: Rig Pump—Triplex
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2.4 2.4.1
DRILL BIT AND DRILLSTRING Drag Bits The drag bits have hard-faced blades rather than distributed cutters that are an integral part of the bit and rotate as one with the drillstring. They have a tendency to produce high drilling torque and are also prone to drilling crooked holes. Penetration is achieved with a scraping action using low force (weight on bit or WOB) and high rotation speed (revolutions per minute or RPM). They are only suitable for drilling soft and unconsolidated formations, and lack the hardness and wear resistance required for consolidated formations.
2.4.2
Roller Tri-Cone Bit Early bits possessed two cones that had no interaction or meshing, these were prone to balling (where drilled cuttings collect and consolidate around the bit) in soft formations. These were superseded by the tri-cone bit, the most common type used in modern drilling (Figure 20). These possess 3 cones, which are intermeshing and therefore self-cleaning, with rows of cutters on each cone. Cutters are of two principle types: milled teeth (Figure 20) or tungsten carbide inserts (TCI), and can be of varying size and hardness according to the lithology expected. A lot of heat is generated by friction during drilling and this heat must be dissipated. Cooling, together with lubrication, is an important function of the drilling fluid. This exits the drillstring through ports in the bit that are called jets or nozzles; one jet is positioned above each cone. Jets are replaceable and can be of varying size, the smaller the jet, the greater the velocity and force of the mud exiting the bit. Jet sizes are expressed in millimeters or in 32nds of an inch. If no jet is set into the port, it is known as an open jet (the size is one inch, that is, thirty-two 32nds).
Figure 20: Tri-cone Milled Tooth Bit
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Roller bits are classified by a system developed by the International Association of Drilling Contractors (IADC), where most have a 3 digit IADC code to describe the series, type and design (Table 1). The following are examples:
Hughes ATM22: IADC code 517—Soft chisel type TCI bit, softest in the range, with friction-sealed journal bearings and gauge-protected.
Reed MHP13G: IADC code 137—Soft milled tooth bit, moderately hard in the range, with frictionsealed journal bearings and gauge-protected.
Some bits have a fourth category to describe additional features about the bit. Examples include air application (A) bits, centre jets (C), deviation control (D), extra gauge (E), horizontal steering (H), standard steel tooth bit (S), chisel shaped inserts (X), conical shaped inserts (Y). 2.4.2.1
Bit Terminology
Figure 21 illustrates the naming convention for the various parts of tri-cone bits.
Figure 21: Tri-Cone Bit—Terminology
2.4.2.2
IADC Bit Classification
Table 1: IADC Bit Classification
Series Type of cutting structure
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1
Soft
2
Medium
3
Hard
4
Very soft
5
Soft
6
Medium
7
Hard
8
Very hard
Milled Tooth
Chisel
Tungsten Carbide Insert
Conical
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Type Degree of hardness of cutting structure Design Option Bearing design and gauge protection
2.4.2.3
1-4
1 – softest 4 – hardest
1
Standard product
2
Air drilling
3
Gauge protected
4
Sealed bearing
5
Gauge protected and sealed bearing
6
Friction, sealed journal bearing
7
Friction, sealed journal bearing, gauge protected
8
Directional
9
Other
Cone Action
As cones roll on the bottom of the hole, a sliding action gouges and scrapes the formation. Cones have more than one rolling center because of the number and alignment of cutter rows, but this is restrained by the weight of the drill collars acting on the bit. Rotation is around the bit center-line so that the teeth must slide and scrape as they roll. This action is minimized in the design of the hard bits (by having no cone offset) to reduce wear, but action is still not pure rolling. The sliding action produces a controlled tearing, gouging, and scraping action on the formation, leading to fast and efficient chip removal. For soft formations, the scraping action is enhanced by offsetting the cones. This leads to faster drilling and the amount of scraping action depends on the degree of offset. Soft formation bits may have an offset of 1/4 or 1/8 inch in medium bits, and no offset for hard bits. 2.4.2.4
Bearing Types
Unsealed—These are grease-filled and exposed. Their life is short because they are exposed to metal fatigue and abrasion from solids.
Sealed and self-lubricating—Metal fatigue still exists, but abrasion from solids is eliminated as long as there is a seal.
Sealed journal bearings—These have a longer life, but wear can come from seizure of the sliding metal-to-metal surfaces on the bottom side of bearings. If the seal fails, drilling mud leaks into the bearing, displacing the grease. Overheating causes rapid failure of the bearing. The bearing has a pressure compensation system that minimizes the pressure differential between the bearing and the mud column pressure.
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2.4.2.5
Teeth
The size, shape and separation of teeth affect the efficiency of the bit in a formation of varying hardness. The tooth design also determines the size and form of the drilled cuttings produced and used for formation evaluation. For soft formations, the teeth are typically long, slender, and widely spaced. The longer teeth allow deeper penetration into the soft formation. This deeper penetration is maintained as the teeth become worn by making the teeth as slender as possible. The wide spacing prevents the soft formation from balling or packing between the teeth. The cutting action is one of gouging and scraping and the cuttings typically produced are large and freshly broken. Bearing size and strength are restricted in soft formation bits depending on the size of the teeth. This normally does not produce a problem because only low weights or force must be applied to the bit to achieve formation failure and penetration. For formations of medium hardness, shorter and broader teeth are used. Deep penetration is limited by the formation hardness so that longer teeth are unnecessary. The length is such that as much penetration as possible is achieved. At the same time, wear caused by the firmer formation is kept to a minimum. Wide spacing allows for efficient cleaning even though balling is not as important as in a soft formation. For hard formations, short and broad teeth produce a crushing and chipping action rather than scraping and gouging. The drilled cuttings are smaller, more rounded, crushed and ground. Tooth spacing is not required for cleaning because cuttings are smaller with a lower concentration or volume, resulting from lower penetration rates. Increased life in hard and abrasive formations can be produced by hard-facing the milled steel teeth or by using tungsten carbide inserts (TCIs). For harder formations, fewer and smaller teeth facilitate larger and stronger bearings that can withstand the higher forces that cause failure. 2.4.2.6
Operating Requirements
Hard and abrasive formations require a higher force or weight on bit (WOB) to be applied to the bit. The greater weight impacts the bearings so a corresponding lower RPM is applied to minimize bearing wear. To prevent impact failure or cracking of insert cutters, the WOB required is slightly lower for an equivalent TCI bit. Softer formations require lower weight on bit to achieve penetration, therefore higher RPM can be applied. Similar parameters are required for tooth and TCI bits. Too much weight being applied could break the longer teeth or inserts. Generally, rate of penetration (ROP) is faster with more weight applied to the bit and/or higher RPM, but too much weight can have detrimental effects such as bit balling in softer formations, failure of roller bearings, seizure of journal bearings, and breakage of teeth or inserts.
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2.4.3
Diamond and Polycrystalline Diamond Compact (PDC) Bits These bits have long lives because the cutters are hard and there are no bearings or moveable parts (Figure 22). For breakage and redundancy, natural industrial diamonds are set into geometric designs that cover the bottom of the bit. For cooling and cuttings removal, they also channel the mudflow from the bit. 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.
Figure 22: Diamond Bit and PDC Bit
Diamond cutters start and end sharp even after wear when most cutters become dull. This and their longer life make them extremely cost-effective for deep drilling in hard and abrasive formations. Because they have no moving parts, they are economical when high rotary speeds (perhaps above the limits of roller bearings) are produced when drilling with mud motors or turbines. They do have long lives, although ROPs are generally slower. The overall footage or meters achieved by the bit must justify the much higher cost of diamond bits. The cutting action of diamond bits is a shearing or grinding 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, because the structure and form of the lithology is destroyed to a large degree. At the same time, these bits are less sensitive to picking up lithological changes because changes in ROP are not as marked as with tri-cone bit, they are not well suited to geological interpretation. Diamond bits have different operational requirements from tri-cone bits. They typically have a slightly smaller gauge (diameter) than the hole size to reduce wear on trips in and out of the hole. Optimum Page 44 of 278
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performance is achieved with lower WOBs 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 the profile of the bit is cut into the bottom of the hole.
2.4.4
Grading of Bits Bits are always graded for wear before changing out.
2.4.4.1
TBG System of Bit Grading
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 TBG (teeth-bearing-gauge) grading, with teeth and bearings graded on a scale of 1 to 8: Table 2: TBG Grading of Bits
(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 such as 1/8 inch or 2mm
This is a basic grading system that gives little additional or qualifying information about bit condition. For example, the inner and outer rows of cutters might have different degrees of wear, but this system can only facilitate one recording. 2.4.4.2
The IADC Bit Grading System
A more sophisticated and informative grading is provided by the IADC system. Table 3: IADC Bit Grading System
Cutting Structure Inner rows
Outer rows
Bearing condition
Major dulling characteristics
Location of major dulling
0 – 8 linear scale
BC – broken cone
Rollers:
0 – no wear
BT – broken teeth
N – nose
2 - 25%
CC – cracked cone
M – middle row
4 - 50%
CR – cored
H – heel row
6 - 75%
CT – chipped teeth
A – all rows
8 - 100%
ER – erosion
Cone 1, 2, 3
JD – junk damage
Fixed Cutters:
LC – lost cone
C – cone
LT – lost teeth
N – nose
PB – pinched bit
T – taper
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No – Sealed Bearings: 0–8 0 – as new 8 – life gone
Gauge
I – in gauge Undergauge measured to the nearest 1/16 inch
Remarks Other dulling characteristics
Reason pulled
Same codes as major dulling characteristics
BHA – change BHA
Sealed Bearings:
DMF – downhole motor failure DSF – drill string failure DST – drill stem test LOG – run logs CD – condition mud
E – effective
CP – core point
F – failed
DP – drill plug FM – formation
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Cutting Structure
Bearing condition
Gauge
Remarks
PN – plugged nozzle
S – shoulder
change
RG – rounded gauge
G – gauge
HP – hole problems
RO – ring out
A – all areas
HR – hours on bit
SD – shirttail damage
PP – pump pressure
WO – washed out
PR – penetration rate
WT – worn teeth
TD – total depth (or casing point) TQ – torque TW – twist off WC – weather conditions
2.4.5
The Drillstring The drillstring is made up of drillpipe and drill collars, with a number of smaller additional components that connect the surface systems to the drill bit. The following are the main purposes of the drillstring:
Provide a conduit from the surface to the bit so the 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 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; all connections from the lower kelly to the drill bit are made with right-hand threads. With rotation of the drillstring to the right during drilling, connections tend to tighten rather than loosen or back off. Tubular sizes, including drillpipe, drill collars, and casing, are standardized by the American Petroleum Institute (API) to indicate the outside diameter (OD) of the tube.
2.4.6
Drillpipe In terms of length, this comprises the main component of the drillstring. Each length of drillpipe (referred to as a single or a joint) is constructed of steel and is commonly around 10m, but can be up to 15m. Each end of the pipe has a tapered tool joint, male or female, that is welded or shrunk on so lengths of pipe can be screwed together. The shoulder around the tool joint is enlarged or upset to provide extra strength to connections. The drillpipe is available in various outside diameters (OD) although the most commonly used is 5 in. or 127 mm. The inside diameter (ID) of the drillpipe depends on the weight per unit length of the pipe. The higher the weight of the drillpipe, the smaller the ID will be. The drillpipe commonly used (for OD 127 mm), is 19.5 lb/ft or 29.1 kg/m. This gives:
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An OD of 5 in. or 127 mm
An ID of 4.28 in. or 108.7 mm
Drillpipe is 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 heavyweight drillpipe. This heavier pipe is situated above drill collars in the drillstring to provide extra weight and stability. As with standard drillpipe, heavyweight is available in different ODs and varying IDs depending on the weight of the steel. Heavyweight drillpipe differs in appearance from standard drillpipe in that it has longer tool joints. The heavyweight drillpipe commonly used (for OD 127mm), is 49.3 lb / ft or 73.5 kg / m. This gives:
An OD of 5 in. or 127 mm
An ID of 3 in. or 76.2 mm
Heavyweight drillpipe has the same OD as standard drillpipe and the same ID as drill collars.
2.4.7
Drill Collars Drill collars are rigid, thick-walled and heavy lengths of pipe that make up the main part of the bottomhole assembly positioned between drillpipe and bit. Collars have several important functions:
Provide weight for the bit.
Provide strength so collars are in compression.
Provide weight to ensure the drillpipe is held in tension to avoid buckling.
Provide rigidity or stiffness so 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 varying because of varying weights of steel. Typically, the ID is similar to that of heavyweight drillpipe, i.e. close to 3 in. or 76 mm. The weight applied to the bit must come from drill collars. If the weight applied exceeds the total weight of the drill collars, the extra weight will be provided by the drillpipe, which will then buckle and twist off (breaking) at tool joints. Drillpipe must always be held in tension. The weight of the drill collars acting directly on the bit has two main consequences:
The tendency for the string to hang vertically because of the weight and gravity. The heavier the drill collars, the more likely it is that the bit does not deviate from a vertical position.
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The weight acting upon the bit stabilizes it, making it more likely that the hole being drilled follows
the path of the section just drilled (such as 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 from a central position, ensuring a straight and properly sized or gauged hole, even bit wear and faster penetration rates. The maintenance of borehole direction is assisted not only by the weight and stiffness of the drill collars at the base of the drillstring, but also 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 is prone to differential sticking, where the pipe becomes stuck in the filter cake covering the borehole wall. This is minimized by using designs in the sectioning or grooving of the collars to reduce the surface area of the drill collar in contact with the wellbore. Thus, collars can be round, square, or elliptically sectioned, spirally grooved, and so on (Figure 23).
Figure 23: Drill Collar Types—Square, Spiral and Smooth
2.4.8
The Bottomhole Assembly The bottomhole assembly (BHA) is the name applied to drill collars and tools incorporated with them, including the bit. The drillstring is made up of the drillpipe (heavyweight drillpipe is normally distinguished as well) and the BHA.
2.4.8.1
Stabilizers
These are short lengths of pipe that are positioned between drill collars to centralize them and maintain a straight hole. Through a scraping action, they maintain a full sized or gauged hole.
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The full gauge is provided by ribs or blades mounted on a mandrel (Figure 24). These can be made from solid rubber or aluminum. 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.
Figure 24: Stabilizers
2.4.8.2
Reamers
Roller reamers ream the hole just behind the bit and perform a similar function to stabilizers because they stabilize the assembly and help maintain a full gauge hole. Reamers are typically used when problems are 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 categorize the type of reamer. For example, with three blades, it is a 3-point reamer. If blades are positioned toward the base of the sub (Figure 25), it is a 3-point near-bit reamer. A stabilizer reamer has the blades positioned centrally in the sub.
Figure 25: 3-Point Near-Bit Reamer
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 occurs through 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. 2.4.8.3
Hole Opener
This is a similar tool to the under-reamer in that a cutting action is provided by rotating cones to enlarge a hole. However, unlike the under-reamer, the cones are in a fixed position, so the hole opener must be Wellsite Procedures & Operations Manual
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able to pass through the previous hole diameter. Therefore, they are generally used on a surface hole section to widen the hole where large-hole diameters are required. 2.4.8.4
Cross Over Sub
This is a small length of pipe enabling drillpipe and / or collars of different diameters and threads to be connected together. 2.4.8.5
Rotary Drilling Jar
This is a mechanically or hydraulically operated device that provides a high impact hammer blow to the drillstring downhole if it becomes stuck. Jars are designed for drilling or fishing (retrieval of part of the drillstring left downhole) operations. If the drill string becomes stuck and incapable of being freed with normal working of the pipe (such as upward and downward movement) or by pulling on the pipe without exceeding drill string and surface equipment limitations, a rotary drilling jar is used. A jar strikes heavy-impact hammer blows, in an upward or downward direction, to the drillstring. The direction in which the jar is activated depends on the pipe movement when it became stuck. A downward blow is struck if the pipe was stationary or moving upwards. An upward blow is struck if the drill string was moving downwards. Most stuck pipe situations result from an upward moving or stationary pipe. Typically, downward jarring is required. To free the pipe the jar must be situated above the stuck point, so a jar is usually placed in the upper part of the bottomhole assembly, above stabilizers and other tools prone to sticking. A jar can be hydraulically or mechanically triggered, the design is different but triggering works on the same principle. That is, the jar consists of an outer barrel attached to the drillstring 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 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. Mechanical jars deliver the hammer blow by the same acceleration / deceleration of the jars, but the triggering mechanism is by a preset tension with no time delay when the jar is cocked (Figure 26).
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Figure 26: Mechanical Jar Operation
A jar accelerator can be set above rotary jars, typically within the heavyweight 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 confines movement to the drill collar—or close to the stuck point—and minimizes shock on the drill string and surface equipment by cushioning rebounds through the compression of fluid or gas. If jarring cannot 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 a wireline to blow the string apart. The remaining stuck pipe must be retrieved, removed, or avoided before drilling can continue. 2.4.8.6
Shock Sub
This is positioned close behind the bit. Hard formations cause the bit to bounce on the bottom of the hole. The shock sub will absorb the impact from this bouncing to prevent damaging the remaining part of the drillstring. This can be done by springs or rubber packing.
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2.5
BLOWOUT PREVENTION (BOP) SYSTEM The following explains blowouts and how to prevent them.
2.5.1
Kick and Blowout 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. If the formation fluid pressure exceeds the hydrostatic pressure of the mud column, the formation fluid (water, gas or oil) can feed into the wellbore. This is known as a kick. A kick is 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.
2.5.2
BOP Stack To prevent a blowout, there must be a way to close or shut off the wellbore so that the influx of formation fluid remains under control. This is possible with a blowout prevention (BOP) system, an arrangement of preventers, valves and spools that sit on top of 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 is determined by the hazards expected and the protection required, together with the size and type of pipe being used. The following are the basic requirements of the BOP stack:
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, rapid procedure, easily understood and performed by 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 higher density mud can be circulated to balance the formation
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pressure and control the well. There are additional requirements in the case of floating rigs, where the BOP stack is situated on the seabed. If the rig must temporarily abandon the well, there must be means to shut the well completely by hanging off or shearing pipe in the hole. The marine riser can then be detached from the wellhead, allowing the rig to move away to a safe location but able to return and reenter the well. During normal operations, the marine riser is subjected to lateral movement because of water current. The riser must be attached to the stack through the ball joint to prevent movement of the stack. BOPs have pressure ratings established by the American Petroleum Institute (API). They are based on the lowest pressure rating of an item in the stack such as a preventer, casing head or other fitting. A suitably rated BOP can be installed depending on the rating of the casing and expected formation pressures below the casing seat. BOPs commonly have ratings of 5,000, 10,000, or 20,000 psi.
2.5.3
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.
2.5.3.1
Annular Preventer
This is a reinforced rubber seal or packer that surrounds the wellbore (Figure 27). When pressure is applied, the seal or packer closes around the pipe, sealing off the annulus.
Figure 27: Annular Preventer
An annular preventer has the advantage that with pressure progressively applied to it; it will close in on any size or shape of pipe. The wellbore can therefore be closed in regardless of whether the kelly, drillpipe, or drill collars are passing through the stack. However, this adaptability does not extend to spiral Wellsite Procedures & Operations Manual
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drill collars or tools such as stabilizers where the shape is irregular. Most annular preventers can also seal across an open wellbore, but this shortens the life of the packer and should be avoided. The annular preventer also allows for slow rotation or vertical movement of the drillstring while the annulus remains closed off. This allows pipe to be tripped in (snubbing) or out (stripping) of the hole while the well is under a controlled condition. 2.5.3.2
Ram Type Preventers
A ram type preventer differs from an annular preventer in that the rubber sealing element is comparatively rigid and seals around designated shapes. They are made to seal around specific objects (pipe and casing rams) or seal an open hole (blind rams). They can be equipped with shearing blades that can cut through the drillpipe or casing and still have the ability to seal an open hole (shear / blind rams).
Figure 28: Annular Preventer and Ram Preventers
2.5.3.2.1
Pipe or Casing Rams
The rubber faces of the ram are shaped to match the outside diameter of specifically sized pipe. The rams can 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.
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2.5.3.2.2
Blind or Shear Rams
These rams, closing from opposite sides, close off the complete borehole when no pipe is in the hole. If pipe is in the hole, the rams crush it or cut through it if equipped with shear blades (shear rams). Shear rams are typically used in subsea stacks so if pipe is in the hole, the well can be completely closed off if the well must be temporarily abandoned. Blind rams are typically used in stacks situated under the drillfloor. 2.5.3.3
Closing BOPs
BOPs 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 of a preventer closing system are:
Pumps to provide 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 must be means to store the hydraulic fluid under pressure and to deliver it to the BOPs. Different BOPs require different operating pressures and BOPs of different sizes require varying amounts of fluid for opening and closing. 2.5.3.3.1
Accumulators
Accumulator bottles store, under pressure, the full amount of hydraulic fluid required to operate all BOP components and cause rapid BOP closure. Several accumulator bottles can be linked to provide the necessary volume. The accumulator bottles are charged with compressed nitrogen (typically 750 to 1000 psi). When hydraulic fluid is forced into the bottle through air or electrically powered pumps, the nitrogen is compressed, increasing the pressure. To ensure BOP operation, a closing unit has more than one pressure source in case of failure. Similarly, if air or electrical pumps are used in the closing unit, there is more than one source of air, more than one source of electricity, and so on. 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 determine the amount of hydraulic fluid that can be supplied from each bottle. From this, the number of bottles needed to supply the full amount of fluid to operate the BOP can be determined. Wellsite Procedures & Operations Manual
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For example:
Figure 29: Accumulator Bottle Volumes
A hydraulic control manifold consisting of regulators and valves controls the direction of flow of the highpressure hydraulic fluid. The fluid is directed to the correct ram or BOP. The regulators reduce the pressure of the hydraulic fluid from the accumulator operating pressure to the operating pressure of the BOP (typically in the region of 500 to 1500 psi). All components for the closing system—pressure source, accumulators, control manifold, master control panel—should be a safe distance from the wellbore.
2.5.4
Control Panel Typically, there is more than one control panel for the BOPs. The master panel is located on the drill floor convenient to the driller, typically in the doghouse (Figure 30). An auxiliary panel is placed in a safe area so if the driller’s panel fails, the well can still be controlled.
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Figure 30: BOP Control Panel
The control panel is air-operated and provides gauges to show air pressure to the control panel itself and pressures throughout the system (such as accumulator, air supply manifold, and annular preventer). The panel also includes control valves to open or close BOPs, valves to open or close the choke, and kill lines and a pressure control valve to adjust the annular pressure.
2.5.5
Positioning Rams One annular preventer is placed at the top of the stack. The best arrangement for the remaining rams depends on the drilling operations 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.
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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 minimizes 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 blind rams cannot be used as a master valve allowing for changing or repair of rams above. 2.5.5.1
Kill Lines
The placement or configuration of rams affects the positioning of kill lines. These are located directly beneath rams, so when rams are closed, fluid and pressure can be bled off under control through the choke line (Figure 31).
Figure 31: Simple BOP Stack Schematic
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The choke line is routed to the choke manifold where pressures can be monitored (Figure 32). An adjustable choke allows for the backpressure applied to the well to be adjusted to maintain control. The kill line is an alternative way of pumping drilling mud or cement into the wellbore if it is not possible to circulate through the kelly and drillstring. The kill line is normally lined up to the rig pumps, but a remote kill line is often employed to use an auxiliary high pressure pump.
Figure 32: Choke Manifold
Although preventers can 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 preventers, creating extra space (which may be required to hang off pipe and have enough room for tool joints between the rams) and allowing for the attachment of 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 must flexible at the top and the bottom of the riser to allow for movement and heave. 2.5.5.2
The Diverter
A diverter is typically employed before the installation of a BOP stack; it is essential in offshore drilling. The diverter, installed beneath the normal bell nipple and flowline assembly, is a low-pressure system. It directs well flow or a kick away from the rig and personnel, providing protection before setting the casing string that the BOP stack is mounted on. The diverter system can only handle low pressures. It packs-off or closes around the kelly or drillpipe and directs the flow away. If it were used to try to control high pressures, or to shut the well, the likely result would be uncontrolled flow and breakdown of formations around the shallow casing or conductor pipe.
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2.5.6
Inside BOPs Complete blowout prevention is only achieved when the annulus and the inside of the drillpipe are closed off. The preventers and rams primarily close off the annulus. Blind rams close off open holes without drillpipe, and shear rams cut the drillpipe rather than closing off. Inside BOPs are used to close off the inside of the drillpipe. There are two main types. 1. Manual shutoff valves employed at the surface. 2. Automatic check valves situated in the drillstring downhole.
2.5.6.1
Surface Shutoff Valves
There are various types of surface shutoff valves
Kelly Safety Valve—This is installed on the lower end of the kelly, with 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 shutoff is backflow occurs during tripping when the kelly is racked.
2.5.6.2
Downhole Check Valves
Drop-in Check Valve—This can be located at any position in the drillstring, it just requires 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 the drillpipe is protected against flow up the pipe.
Drillpipe Float Valve—This can be positioned 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.
2.5.7
Rotating BOPs (RBOPs) Otherwise known as a rotating control head, a rotating BOP (RBOP) is a rotating flow diverter mounted on the top of a normal BOP stack. An 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 unit has advantages for underbalanced and controlled pressure drilling. When drilling with high pressures or for enhanced safety, RBOPs are used in normal drilling applications. While well pressures are contained by the rubber seal around the drillstring or kelly, flow is diverted through 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. There are two types of seals:
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A cone-shaped rubber—This seals around the drillstring. The ID of the seal is smaller than the OD of the pipe so the seal stretches to provide an exact seal around the pipe. No hydraulic pressure is required to complete the seal because the pressure is provided by wellbore pressures acting on the cone rubber. The rubber is therefore self-sealing, and the higher the wellbore pressure, the greater the seal.
A packer type seal—This requires an external hydraulic pressure source to inflate the rubber and provide a seal. A seal is made as long as the hydraulic pressure is greater than the wellbore pressure.
The advantage of the RBOP is that because 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 using the BOP preventers. For further information on well control equipment and well control procedures, see the Weatherford Well Control and Blowout Prevention Manual.
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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 drillstring. In fact, the mud system has many other functions and is central to virtually all operations throughout the drilling of a well. It is very important that the drilling fluid can perform these functions efficiently.
3.1.1
Cooling and Lubrication The drilling action and rotation of the drill string generates considerable heat at the bit and throughout the drill string because of 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 drillstring to reduce the friction. Basic mud types provide moderate lubrication, but oil emulsion mud systems and 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 keeps cuttings clear of the bottom hole and prevents bit balling (that is, 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 of Subsurface Pressures Minimal mud weight is important for fast drilling rates and to minimize the risk of damaging formations and losing circulation. However, in conventional drilling, the mud must also have 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 because of 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, fluids (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 subject to influxes of formation fluid that 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, while controlling formation fluid pressure, can
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lead to the flushing of drilling mud into the formation, or can even fracture of weaker formations, resulting in lost circulation.
3.1.4
Line the Wellbore As the hole is drilled, filtrate (that is, the liquid portion of drilling fluid) invades permeable formations. As it does, solid particles in the mud are left on the borehole wall. These particles build up to line the borehole with a thin, impermeable layer of filter cake that consolidates the formation and minimizes further fluid loss. The mud's filter-caking ability can be improved by adding bentonite (increasing the reactive mud solids) and chemical thinners (improving solids distribution). Starch or other fluid-loss control additives may also be required to reduce fluid loss. Excessive water loss can result in an excessively thick filter cake, reducing the diameter of the hole 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
Support 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, 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 must be removed from the well to prevent loading the annulus and to allow for free movement and rotation of the drillstring. The cuttings must reach the surface and be released in such a condition as to allow for geological interpretation of the downhole lithology. Cuttings slip (cuttings falling back down the well annulus) occurs because the density of the cuttings is greater than the density of the drilling fluid. To ensure cuttings are lifted through the annulus during circulation and remain suspended when circulation stops, drilling fluids must be thixotropic (that is, possess gelling properties). When circulating, thixotropic drilling fluids are liquid, allowing them to carry cuttings to the surface. When not circulating, thixotropic drilling fluids 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.
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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. Drilling hydraulics is considerably influenced by the flow properties of the drilling fluid, such as density, viscosity, flow rate, and fluid velocity. The amount of hydraulic horsepower expended at the bit determines the degree to which hydraulics is 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 (for example, sand) from falling into the hole. For swelling and sloughing shales, oil-base mud is preferred because unlike water, oil is not absorbed by the clays. Water-based mud can be used if treated with calcium, potassium and 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, 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 protects the cuttings, minimizes erosion of the wellbore wall, and reduces circulating pressures. In addition, the penetration rate might need to be sacrificed to gain valuable reservoir information. This is known as controlled drilling, where parameters are controlled to determine the changes due to the geology.
3.2
COMMON DRILLING FLUIDS Drilling Fluids are circulating mediums used to carry drilled cuttings out from the drill bit, into the outer annulus and up to the surface. Fluids used in rotary drilling are:
Air-gas.
Foam / aerated fluids.
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Water-based muds.
Oil emulsion muds.
Oil-based muds.
A typical circulating system of a rotary drilling rig is illustrated in Figure 15.
3.2.1
Air-Gas Drilling Fluid Using compressed air, natural gas, inert gas, or mixtures with water has an economic advantage in hardrock areas where there is little chance of encountering large quantities of water.
3.2.1.1
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
3.2.1.2
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
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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 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 depends more on viscosity than annular velocity. Aerated fluids are made by injecting air or gas into a gel-base mud. They reduce hydrostatic pressure (preventing the loss of circulation in low-pressure formations) and increase the rate of penetration.
3.2.3
Water-Based Muds Water-based muds consist of a continuous phase of water in which clay and other solids (reactive and inert solids) are suspended. Fresh water is often used, it is commonly available, inexpensive and 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 because of its accessibility. Saturated salt water is used in drilling salt sections to stabilize the formation and reduce hole washout. Reactive solids are commercial clays and incorporated hydratable clays and shales from drilled formations that 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 that 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-based muds are classified as inhibited muds. In this case 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.
3.2.3.1
Advantages
Increased drillability when using fresh water (drillability increases with increasing water loss and with decreasing density and viscosity)
3.2.3.2
Less expensive than oil-based muds Disadvantages
Potential formation damage
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3.2.4
Subject to contamination
Adversely affected by high temperatures
Oil-Emulsion Muds Oil-emulsion muds contain emulsified oil that is dispersed, or suspended, in a continuous phase of water. These are less expensive than oil-based muds, while still providing the benefits.
3.2.5
Oil-Based Muds Oil-based 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-based muds are used in special drilling operations, such as drilling in extremely high temperatures, drilling in water-sensitive formations where water-based muds cannot be used, and in productive zones that may be damaged by water-based muds.
3.2.5.1
Advantages
Minimizes formation damage
Prevents clay hydration
Provides better lubrication (reducing torque, drag and pipe sticking)
Minimizes drill string corrosion
High temperature stability
3.2.5.2
Disadvantages
Susceptible to water contamination, aeration, and foaming
Flammable
Significantly more expensive than water-based muds
Dirty and hazardous
Environmentally unfriendly (because of spillage and disposal)
In recent years, mineral oils have gradually replaced 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 handle the mud.
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3.3 3.3.1
BASIC MUD RHEOLOGY 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 (see Section 4 Subsurface Pressures). Barite is the standard solid used to increase mud density. For optimum thinning or reduction in fluid 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 remove excessive solid particles from the mud. Mud density is measured with a mud balance (Figure 33), where the weight of an exact volume of mud, minus air bubbles or drilled solids, is determined:
Figure 33: Mud Balance
3.3.2
Mud Viscosity Mud viscosity measures the drilling mud's resistance to flow (that is the internal resistance because of the attraction of the liquid molecules); the greater the resistance, the higher the viscosity. Viscosity therefore describes the thickness of the mud in motion and must be high enough for the mud to keep the bottom hole clean, and carry cuttings to the surface. However, lower viscosity levels allow for higher rates of penetration. Lower-viscosity drilling muds also result in lower equivalent circulating densities (that is, the measured increase in bottom hole pressure because of frictional pressure losses that occur when mud is circulated).
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A simple measure of viscosity used at wellsite is funnel viscosity. The measurement is made using a Marsh funnel. The measurement is the number of seconds required for the fluid (1 quart) to flow through a calibrated orifice. Rotational viscometers provide a more accurate rheological measurement by measuring shear stresses resulting from various applied shear rates.
Figure 34: Marsh Funnel
3.3.3
Gel Strength Gel strength measures the attractive forces of suspended particles when the fluid is static. It 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 they do not sink and settle around the bit or bottomhole 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). The gel strength is usually measured with a Fann Viscometer or V-G Meter (Figure 35).
Figure 35: Fann Viscometer or V-G Meter for Measuring Gel Strength Gel strength can be reduced by reducing solids content or by adding an appropriate thinning agent, known as a deflocculant. Wellsite Procedures & Operations Manual
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3.3.4
High versus Low Viscosity and Gel Strength High viscosity and gel strength lead to:
Higher pressure to break circulation.
Higher swab and surge pressures.
Higher annular pressure losses.
Better retention of gas and cuttings.
Low viscosity and gel strength lead to:
3.3.5
Poor removal of cuttings and hole cleaning.
Poor suspension of cuttings and solids when circulation is halted.
Filtrate / Fluid Loss Filtrate is the liquid portion of the drilling mud that enters permeable formations next to the borehole. Fluid loss is measured to determine the volume of filtrate. Excessive fluid loss can dehydrate the drilling mud; if this happens, the mud must be treated to restore. Depending upon the chemical composition of the filtrate and the formations, high fluid loss can cause hole problems such as pipe sticking (Section 7.4) or washouts (Section 7.6) 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 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 cases, the mud solids may enter the formation and block the pore throats instead, therefore 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.
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3.3.7
Mud pH The pH level of drilling mud should be monitored 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 sulfide (H2S) gas or, at least, its former presence. Scavengers, such as copper carbonate, zinc compounds, and iron derivatives are added to drilling mud to combine or react with H2S if it enters the borehole. This results in the formation of other sulfide 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 is possible to tell if H2S has entered the borehole, but the scavengers removed it before the mud reached surface.
3.3.8
Mud Salinity A significant change in mud salinity (when not caused by mud additives) 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 of salinity can indicate influxes of formation fluid and indicate changes in formation pressure. For details on fluid model types, such as Bingham and Newtonian and fluid hydraulic theory and formulae, see the Weatherford Drilling Fluid Hydraulics Manual.
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4 SUBSURFACE PRESSURES The hydrostatic pressure of the drilling fluid column exerted against the borehole wall helps prevent unconsolidated or over pressured formations from caving into the hole. This pressure also helps prevent kicks, which are the controllable flow of formation fluids into the wellbore resulting in displaced drilling mud at the surface and blowouts (Figure 36 and Figure 37), uncontrolled flow of formation fluids into the wellbore.
Figure 36: Land Rig Blowout
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Figure 37: Offshore Blowout (Deepwater Horizon Rig)
4.1
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 pressure 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. When fracture has occurred, drilling fluid flows 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.
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Underbalance occurs when the hydrostatic pressure is lower than the formation pressure. This may allow an influx 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 results in the fracturing and caving of the formation. This not only leads to an increase of formation fluid entering the drilling mud, but also to loading of the annulus with cuttings. This can in turn lead to tight-hole or stuck pipe problems and difficulties in knowing the depth that cuttings are actually from. 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.
4.2
PORE PRESSURE Pore pressure is the pressure exerted by the fluid contained in the pore space of the rock and is the strict meaning of what is generally referred to as formation pressure. All rocks have porosity to some extent. If permeability also exists and formation pressure is greater than mud hydrostatic pressure, a kick occurs. In impermeable formations, excessive pore pressure is confined and produces sloughing or caving.
4.3
HYDROSTATIC PRESSURE Hydrostatic pressure is the pressure that exists because of mud weight and vertical depth of the column of fluid. The size and shape of the fluid column have no effect.
Or
Hydrostatic Pressure (psi) = 0.0519 x MW (lbs/gal) x TVD (feet)
Or
Hydrostatic Pressure (bars) = 0.0981 x MW (g/cc) x TVD (meters)
Where:
Hydrostatic Pressure (kPa) = 0.0098 x MW (Kg/m3 ) x TVD (meters)
MW = Mud Density TVD = True Vertical Depth
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4.4
PRESSURE GRADIENT Pressure gradient is the rate of change of hydrostatic pressure with depth for a unit of fluid weight. That is,
Pressure Gradient =
P = 0.0519 x MW TVD
The pressure gradient for fresh water (MW= 8.33 lbs/gal):
Pressure Gradient (fresh water) = 8.33 x 0.0519 = 0.432 psi/ft
The pressure gradient for typical formation water (MW = 8.6 lbs/gal):
Pressure Gradient (formation water) = 8.6 x 0.0519 = 0.446 psi/ft
The value 8.6 lbs / gal (ppg) is an average used worldwide, but may not fit local conditions. However, this value should be used until a local value is determined.
4.5
APPARENT AND EFFECTIVE MUD WEIGHT The mud weight measured at the pits is the apparent mud weight going into the hole, and exerts a hydrostatic pressure equal to the hydrostatic pressure. This is a static pressure. But if the mud is circulated, additional pressure is placed against the formation because of frictional effects in the mud. This additional pressure, called effective mud weight (EMW) or effective circulating density (ECD), can be estimated by calculating the pressure loss in the annulus using Bingham’s power law, or modified power law formulae. Bingham’s formula for calculating ECD is:
Where:
Pressure Loss (psi) =
PV x V x L YP x L + 2 60000 x (dh − dp) 200 x (dh − dp)
L = section length (ft) YP = yield point (lb / 100 ft2) (dh-dp) = hole diameter minus pipe outside diameter (inches) PV = plastic viscosity (centipoise) V = annular velocity in laminar flow (ft / min) In calculating the ECD, each section of the annulus should be considered separately and losses summed to total loss. Weatherford mud logging software calculates the ECD using the power law formula. The effective mud weight, EMW, or effective circulating density, ECD, is the equivalent mud weight for the sum of the hydrostatic pressure plus the pressure loss in the annulus. Wellsite Procedures & Operations Manual
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ECD = MW +
Total annular pressure loss (0.0519 x TVD)
Therefore, the Bottomhole Circulating Pressure (BHCP) is:
BHCP = ECD x 0.0519 x TVD
When pipe is pulled out of the hole, the pressure on the formation is reduced by an amount of similar magnitude to the pressure loss in the annulus. That is:
Where:
MWe = MW −
pressure loss (0.0519 x TVD)
Mwe = equivalent weight during POOH A safe rule of thumb is to use an actual mud weight required to balance the formation pressure and add to this a mud weight equivalent to twice the annular pressure loss. That is:
Mud Weight for safe trip = MW + 2 x �
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pressure loss � (0.0519 x TVD)
Wellsite Procedures & Operations Manual
5 DRILLING A WELL 5.1 5.1.1
THE WELL BORE Starting Point When a drilling rig is positioned, whether it is a land rig or offshore vessel, the drilling operation is ready to commence. Typically, a wide conductor pipe, up to 36 inch in diameter, is 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 diverter. Driving the pipe, rather than drilling a hole first, prevents 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 BOPs. On jack-up 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 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 allows 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, is run into and down to the bottom of the drilled hole. A cement mixture is then pumped into the casing and forcibly displaced so that it fills the space between the casing and the formation. When this cement has set, the well is sealed so that when drilling recommences, the drilling fluid as well as any formation fluid is safely returned to the surface via the inside of the casing. Again, when set, this casing prevents 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 BOPs. In general, the BOP stack is installed when the casing is set, although in some cases, operators wait until the surface hole is drilled and casing set. In the case of jack-up rigs and land rigs, the BOPs are installed directly beneath the rig floor. A flow line is then 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 because of tidal and heave motion, links the BOP stack to the rig completing the closed system. A diverter
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is always installed as part of the surface flowline system, so that, if the well cannot be controlled by the BOPs, and returns are reaching surface, gas can be directed safely away from the rig.
5.1.2
Surface Hole This hole section is drilled to a 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, is generally the weakest part of the next hole section simply because it is the shallowest point and subject to the least overburden and compaction. The depth and lithology to which the surface hole is drilled and the casing set is therefore critical. The lithology where casing is set 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 Section 5.6 Pressure Tests). The surface hole is of wide diameter and normally drills quite rapidly because the surface sediments are not too compact or consolidated. A large volume of cuttings is therefore continually produced. To ensure these cuttings are removed from the annulus and so to prevent them blocking or impeding the movement and rotation of drillstring and bit, viscous mud sweeps are 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 is normally completed with just one drill bit. If the bit should wear out however, it is replaced by lifting the entire drillstring out of the hole (tripping, see Section 5.4). 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. When the hole section is completed and before the casing string is set in place, the operator normally requires the hole to be logged with electrical tools 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 is performed. This operation ensures 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 is then run back into the bottom to determine the condition of the hole. If any tight spots are encountered, they can often be corrected simply by working the pipe up and down through the tight section; circulating at the same time helps the cleaning. If the hole is really 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 need 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 is performed. This ensures that any cuttings that may have fallen, or have been dislodged during the hole cleaning, to the bottom of the hole
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are lifted and circulated out of the hole. This enables the logging tools to be run all the way to the bottom of the hole. Once the hole section is logged, casing can be run and cemented in position. The main purposes of the surface casing are:
Provide a firm and competent anchor for the BOP equipment.
Protect formations from further erosion.
Seal off fresh water aquifers from any contamination.
Prevent collapse of unconsolidated formations.
Seal off any subnormal or over-pressured formations.
Before drilling ahead with the next hole section, the BOP stack and casing are pressure tested to ensure there is full integrity and that all prevention equipment is fully functional.
5.1.3
Intermediate Hole Before this section can be started, rubber plugs and cement remaining from the cementing of the previous casing must be drilled out before new lithology is encountered. Just a small interval of the next hole section is then drilled, typically 5-to-10 meters, and then a pressure test performed. This Leak Off Test (LOT) or Formation Integrity Test (FIT) determines the integrity of the cement bond and also allows determination of the fracture pressure of the formation at the shoe. The fracture pressure is the maximum pressure that can be exerted on the wellbore without fracturing that formation, a situation that must be avoided at all costs. Exactly the same procedures are followed as in the surface hole, such as drilling, tripping, logging, casing and cementing. The exact number of hole sections a well has is dependent on several factors, such as:
Depth, fracture pressure and kick tolerance 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 is 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 cemented back to surface.
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5.1.4
Total Depth As the total depth (TD) of the well is approached, any casing that may need to be run is normally run into the hole on drillpipe and hung from a hanger inside of the previous casing. In this situation, it is termed a liner, but procedures for cementing and testing are 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, for example, 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 cuts around and leaves a central core of rock, typically around 10cm in diameter, intact. As the bit cuts down and deepens the well, this core moves up into a special sleeve and core barrel that holds the core. At the end of the coring operation, the core is held in the barrel and it must break 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 the core is retained and does not fall out from the barrel (See Section 5.3.1). At TD, wireline tools are run. 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 is 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 (See Section 13.9). The production casing will be displaced to a specialized fluid or brine, the density of which allows formation fluids, including oil and gas, to flow into the wellbore. Testing equipment, known as a Christmas tree is installed at the surface to measure and determine the reservoir pressure and flow rates.
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Figure 38: Christmas Tree
When all work is completed, the well is plugged with cement to isolate any open hole or production zones from the surface. If there is no reservoir potential, the well is abandoned; if there is potential the well is suspended to allow for further analysis and testing to be completed.
5.2
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 drillstring 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 are 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. When 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 drillstring out of the hole.
5.2.1
Pipe Tally To ensure the depth is being accurately monitored, it is important to record the pipe length before it is run into the hole, and regularly check this length with the recorded depth at kelly down intervals. The kelly down point is when the kelly is drilled down to its fullest extent. If using a kelly, the drilled depth is equal to the Bottomhole Assembly + Pipe Length + Kelly Length. If using a top drive, the drilled depth is equal to the Bottomhole Assembly + Pipe Length.
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Each length of pipe is measured, to an accuracy of 2 decimal places, before it is added to the string and run into the hole. The driller records pipe lengths and total cumulative length in a pipe tally kept in the driller’s doghouse. The mud logger should keep an independent record of the pipe lengths and total, so that pipe tallies can be crosschecked to avoid errors. So that depths can be easily referenced at a later stage, it is an important practice for the mud logger to record or mark down the kelly down depth on all real-time charts in the mud logging unit.
5.2.2
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. 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 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 (that is, other wells in the area) which have been drilled successfully.
5.2.3
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 (that is, a smaller-diameter hole than the main hole), and to remove doglegs, keyseats (that is, an under-gauge channel or groove cut in the side of the borehole that results from the pipe rotating on a dogleg), and
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ledges (that is, 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 an appropriate 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.
5.2.4
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 gas from drilling breaks which may be an indication that a high pressured zone is penetrated.
To circulate out samples that correspond to drilling changes (ROP, torque), which may indicate that a potential zone of interest or coring point is reached.
Before 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).
5.3 5.3.1
Before running wireline tools, to ensure the hole is clean and the tools won’t become stuck.
CORING 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.
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While coring is an expensive operation to perform, it provides valuable information for determining: porosity, permeability, lithology, fluid content, formation dip, geological age and hydrocarbon-producing potential.
5.3.2
Coring Methods Conventional coring requires tripping the drillstring out of the hole. The core bit and barrel assembly is attached to the bottom of the drillstring 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 drillstring must then be tripped out of the hole 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 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 3/4 to 1 1/4 inches (20-30 mm) in diameter and from 3/4 to 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.
5.3.3
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
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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 (Figure 39). Unlike a drill bit, the core bit does not drill out the center portion of the hole. Instead, it allows the center portion (that is, 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 before 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 watercourses in the bit. A rabbit, or core marker, is a metal device, placed in the inner core barrel before coring. When the core is removed from the core barrel, the rabbit, or core marker, falls out indicating that the barrel has been completely emptied.
Figure 39: Core Barrel
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5.3.4
Retrieval and Handling Operations When a sufficient amount of core is 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. When the core is 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 is 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. This practice prevents contamination as well as loss of gas and other formation fluids. Boxes are usually pre-marked with the box number (i.e. 1 of n), the core number, top and bottom indicators and sample interval. Most commonly, today, fiberglass 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 once cut and ends sealed is immediately ready for shipping. .
5.4
TRIPPING Tripping refers to hoisting the drillstring 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 bottomhole 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. This ensures there are no tight spots, sloughing shale, and so on, 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 shoe and then run back to bottom of the hole. Such clean up trips are also made before running wireline tools and before running casing.
5.4.1
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 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.
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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.
5.4.2
Pulling out of Hole (POOH / POH) The main concern when pulling the pipe out of the hole is to avoid fluid influxes that may result in a kick. This results 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 out of the hole, the mud level in the annulus drops 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 bottomhole 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. To achieve this mud is pumped into the hole at intervals 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 narrow mud tank used to accurately measure small changes in mud level as the hole is filled (Figure 40).
Figure 40: Trip Tank
The volume of mud pumped into the hole is the drop in trip tank level, this must equal the volume of steel removed. This may be done continuously as pipe is lifted or, more typically, the mud level is topped up after very five stands of drill pipe and then for every stand of heavyweight drill pipe and drill collars due to the larger steel volume per unit length. Wellsite Procedures & Operations Manual
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Owing to their thickness, the most critical time for keeping the hole full occurs when pulling the drill collars because 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 0.1 3
3
m of mud is required to replace one stand of standard 5 in. drill pipe, whereas close to 0.8 m is required to replace one stand of 8 in. drill collars. It is normal safe practice, especially when using spiral drill collars, to perform a flow check before pulling the drill collars out of the hole, to ensure the well is static and not flowing, because the preventers cannot close effectively around the collars. When the drill pipe is lifted vertically, the surrounding mud moves as a result of two processes. Firstly, because of mud’s viscosity, it tends to stick and lift with the pipe. Subsequently, the mud drops to fill the void left as the pipe is lifted. The resulting mud movement causes frictional pressure losses that reduce the mud hydrostatic pressure, called swabbing. This may result in a temporary condition of underbalance that allows formation fluid to influx. This 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, 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. Using appropriate software, the maximum running speed (X) to avoid exceeding a given swab pressure (Y) can be determined (Figure 41).
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Figure 41: Determining Maximum Running Speed vs. Given Swab Pressure
5.4.3
Running in Hole (RIH) 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 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. An important difference from pulling out is that on running in, initially the pipe is empty. When the drillstring is not filled, it is susceptible to potential collapse because there is nothing to balance the pressure imposed by the mud in the annulus. Normally, as the drill pipe is run in, mud will enter through the bit nozzles and fill the pipe. If too much displaced mud is seen in the trip tank (that is, greater than the open displacement), it may be because of any one, or a combination of the following: small nozzles in the bit, dense or viscous mud or running in too fast. If too much mud is being displaced it is important that the driller be notified so that checks can be made to ensure the well is not flowing, secondly fill the drillstring, and perhaps subsequently reduce the running speed. Naturally, if the nozzles become blocked or plugged, with cuttings, mud is unable to enter the drillstring a closed displacement is seen (that is, steel volume plus internal capacity). Again, the driller should be notified so that attempts can be made to pump and unplug the nozzles before continuing with the trip. Closed displacement is also 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 when expensive
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equipment such as mud motors and measurement-while-drilling (MWD) tools are used in the drillstring to prevent mud and cuttings from entering and damaging them. When a float is used, the drill pipe does not obviously fill by itself, so the trip should be stopped at regular intervals to enable the driller to fill the pipe with mud. At the point of breaking circulation, the pump pressure, which would have been slowly increasing as the drillstring filled, will show a sharp increase. The static drilling fluid in the hole 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, is recorded upon reaching bottoms up, which is the time it takes to circulate the mud from the bit to the surface. Trip gas originates from 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 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.
The lower the pressure differential between hydrostatic pressure versus formation pressure along with the more gaseous the formation, the larger the volume of trip gas. Trip gas is often accompanied by an increase in flow rate from the hole.
5.4.4
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. Refer to Figure 42 for an example Trip Sheet.
5.4.5
Hookload Hookload is the weight of the drillstring suspended by the hook. As drilling proceeds, the hook must support increasing string weight. Through displacement, the drillstring 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.
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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 is supported by the mud, making the hook load lighter than the actual string weight. If tight spots or sections are encountered, the change in hookload depends on whether the pipe is being tripped out or tripped in. When tripping out, additional resistance must be overcome to lift the pipe. This additional hookload is termed overpull. When tripping in, a portion of the string weight is supported by the tight spot, so that the measured hook load decreases. This is known as drag. DATE: 12 SEP 97 HOLE SIZE: 311mm BOTTOM HOLE ASSEMBLY BIT RUN NUMBER:
10
BIT TYPE: HTC ATM22 RUN IN / PULL OUT: IN
SIZE 203
HOLE DEPTH: 2500m DC 1 DC 2 CASING SIZE: 339mm HWDP 127 SHOE DEPTH: 1800m DP 1 127 DP 2
LNTH DISP / m TOTAL 300 0.028 8.4 m3 250 1950
0.0094 2.3 m3 0.0042 8.2 m3
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
Figure 42: Sample Trip Sheet
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5.4.6
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.
5.5 5.5.1
CASING AND CEMENTING Purpose An essential operation when 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. When 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:
Prevents formations from caving into the hole.
Isolate unstable or problem formations such as high-pressure zones, aquifers, gas zones, weak zones.
Protects productive formations.
Provides 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.
5.5.2
Allows for production testing.
Serve as an attachment for surface equipment and artificial lift equipment.
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 BOP.
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 BOP to forestall problems with abnormal pressure
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zones. The casing must be strong enough to support a BOP, 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 is 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 a 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.
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 because of its shorter length; however, a tieback 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.
5.5.3
Surface Equipment Elevators, casing tongs and casing spinners are designed for specific casing diameters, 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. When the cement is pumped down into the casing, rig pumps are 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.
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5.5.4
Subsurface Equipment A guide shoe (or shoe collar) is a short, concrete-filled, cylindrical section of steel placed at the bottom end of the casing string. This guides the casing into the hole, past any obstructions therefore 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, thus preventing mud from entering the casing as it is being lowered into the hole. This enables 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 is 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. 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 is 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 (Figure 43). Centering the casing in the hole allows for a more uniform cement sheath to form around the pipe.
Figure 43: Centralizer and Wall Cake Scratcher
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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.
5.5.5
Preparing to Run Casing Before running casing, drilling mud is circulated to remove cuttings and excess filter cake from the hole; this conditions the hole and conditions 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. 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. Before casing is run into the hole, an electric log is run to confirm the bottomhole formation for setting the casing shoe, and to confirm hole depth so that the exact length of casing can be run. A caliper log is also run to determine hole diameter and the volume of cement required. Cement is 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.
5.5.6
Running Casing As casing is run, it is periodically filled with drilling mud unless automatic fill-up float equipment is used. If not 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 lightweight filling line with a quick-opening valve, each joint is filled from drill floor 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. Due to the fact that the casing tubular is effectively close-ended, together with very small annular clearance, surge pressures while running casing are large. To minimize this, the casing joints are run in at a very slow speed; surge pressure can cause weaker formations to fracture 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
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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 (Figure 44).
Figure 44: Monitoring Mud Returns and Displacements
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 of the casing. Final volume gains in the suction pit should be equal to the volume of steel only (open displacement) that is run into the well, if there is no fluid loss. 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 before cementing. Circulation time extends for as long as required to condition the mud; the casing is reciprocated (moved up and down) 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. Page 96 of 278
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5.5.7
Cementing Operation Cementing is a process of mixing and displacing a cement slurry consisting of dry cement mixed with water, into the annulus, i.e. the space 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 before drilling deepe.r
Helps support the casing.
Prevents casing corrosion.
Generally, 10 – 15 barrels of water are 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 a 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. When the calculated volume of cement is pumped, a retainer pin is pulled to release the top wiper plug from the cementing head (A). Refer to Figure 45. 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). Refer to Figure 45. Mud continues to be pumped 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 the much denser cement slurry is not being lost to the formation.
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Figure 45: Cementing Operation
When all of the cement is displaced from inside the casing, the top plug seats (bumps) on top of the bottom plug held in the float collar (C). Refer to Figure 45. At this point, the pump pressure increases immediately because no mud can get past the solid top plug (that is, mud is being pumped into a closed space). The pump is then 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 the pressure causes 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.
5.5.8
Other Applications
Secondary cementing operations are performed as part of well servicing and workover. 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 to sidetrack.
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. This channeling can be rectified by performing a secondary cementing operation called a cement squeeze. In this case, 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
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casing leaks.
5.6 5.6.1
PRESSURE TESTS 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 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 because it is the shallowest depth. Therefore, LOTs are usually performed after the casing is set and a small interval of the next section is drilled. Before conducting a LOT, BOPs 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 is first to fracture. As fracture commences, mud starts to leak into the formation, and the rate of pressure increase drops off. When a decrease in pressure is recorded, the test is complete.
Figure 46: Leak Off Test
Figure 46 illustrates the three pressure stages; it is the well operator’s decision as to which one is taken as the pressure on which to base subsequent calculations: 1. Leak off pressure—is the pressure at which fluid first starts to inject into the formation at the start of fracture. This is seen as a slight drop in the rate that the pressure is increasing. At this point, the pump rate should be reduced.
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2. Rupture pressure—the maximum pressure the formation can sustain before irreversible fracture occurs. This is 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 recover to a certain degree, and the propagation pressure is determined when the pressure becomes stable again. 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 generally recovers from the propagation 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, firstly the hydrostatic pressure because of the mud column and secondly 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 because the formation is not actually fractured during the test.
5.6.2
Repeat Formation Testing Repeat formation testing (RFT), 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 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
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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 and then the final shut-in pressure is recorded. Because test chambers can hold only a tiny amount of formation fluid, a second sample chamber can be opened to draw more formation fluids.
5.6.3
Drill Stem Testing Drill stem testing (DST) is conducted to record formation pressures and flow rates over large intervals of interest and to gather formation fluid samples to determine the potential productivity of a reservoir formation. Drill stem tests can be run in open holes or cased holes through production liners which can be perforated to allow formation fluids to flow into the annulus. Bottomhole DSTs are performed with a single packer that is set above the formation of interest. This isolates 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 minimizes the potential for formation damage. Straddle drillstem 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 therefore keep costs down. However, there is greater potential for formation damage because of extended exposure to drilling fluid during multiple tests. Tools employed in DSTs include the following:
Packers—these are expandable rubber sleeves 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 then 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 drillstring 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 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
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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. 5.6.3.1
Performing a Drill Stem Test
Drilling mud is circulated and conditioned to ensure 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 drillpipe. 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 (Figure 47). 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.
Figure 47: Drill Stem Testing (DST)
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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 drillstring 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. Drillstem testing procedures are detailed more fully in Section 13.9.
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6 WIRELINE LOGGING Mud logging and core analysis are direct methods of formation evaluation. Wireline well logging is the indirect analysis of downhole features by electronic methods. To log a well by wireline (actually conductor line), an instrument called a sonde is put on bottom, and a recorder plots a graph at the surface as the sonde is raised to the surface.
Figure 48: Wireline Logging Company Sondes
The numerous logs offered by wireline companies today gather data in many different ways under many different conditions. Many, but not all, logging devices can be run in a single sonde in one wireline trip. A specific combination of logs is usually chosen for the types of formation data needed. Correlation between the curves gives a clear picture of lithology, porosity, permeability, and saturation up and down the wellbore. Caliper logs, spontaneous potential logs, resistivity logs, radioactivity logs, or acoustic logs may be included in a typical logging run.
6.1
CALIPER LOGS A caliper is a tool that measures diameter. A caliper logging sonde measures the inner diameter of the borehole. Arms, springs, or pads are held against the sidewall as the device is pulled out of the hole by wireline. Changes in borehole diameter move the arms in and out and send signals to the surface. Wellbore diameter may vary widely because of lateral bit movement, caving formations, mud cake, or flexure (rock bowing into the wellbore because of overburden stress). Excessive hole enlargements indicate that caving or washouts are present. Reduced hole diameters indicate filter cake build-up in permeable formations. It is important to know the hole size / gauge to calculate cement volumes accurately and determine the effect that variations will have on other electronic logs.
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6.2
SPONTANEOUS POTENTIAL LOGS The spontaneous potential, or SP, log is the most common and widely run log. It records the weak, natural electrical currents that flow in formations adjacent to the wellbore. Most minerals are nonconductors when dry. However some, like salt, are excellent conductors when dissolved in water. When a layer of rock or mud cake separates two areas of differing salt content, a weak current flows from the higher salt concentration to the lower. Usually drilling fluids contain less salt than formation fluids, which may be very salty. As freshwater filtrate invades a permeable formation, spontaneous potential causes weak current to flow from the uninvaded to the invaded zone. More importantly, current flows from the uninvaded rock into the wellbore through any impermeable formation, such as shale, above and below the permeable layer. The SP curve is recorded in millivolts against depth. This value is useful in calculating the formation water resistivity (Rw). The SP log can be visually interpreted to show formation bed boundaries and thickness, as well as relative permeability of formation rocks. It is also used in well correlation. Because the SP log is so simple to obtain and provides such basic information, it is included in almost every logging run.
6.3
RESISTIVITY LOGS Resistivity logs record the resistance of a formation to the flow of electricity through it. Conductivity is the inverse of resistivity. Resistivity is expressed in ohm-meters, conductivity in mhos / meter. Some well log formulas use resistivity while others use conductivity. However, all of these formulas describe the same thing: the flow of electrical current. Resistance to this flow depends on:
How much water the formation can hold.
How freely the water can move.
How saturated the formation is with water rather than hydrocarbons.
In this way, resistivity is directly related to other formation characteristics. High porosity, high permeability, and high water saturation will present low resistivity. The presence of oil and gas (and dense rock types) will present high resistivity, because hydrocarbons are poor conductors. If well logs show a formation to be very porous and permeable but also to be highly resistive, then it can be inferred that it holds petroleum. Resistivity logs can therefore be used to determine the degree of water saturation (Sw) and hydrocarbon-water contacts. Resistivity measurements are usually taken at different depths of penetration into a formation, typically 30, 60 and 90 cm. The depth of investigation is controlled by the spacing of electrodes on the sonde. The deeper measurements are likely to be a more true indication of fluid type as they are unlikely to be Wellsite Procedures & Operations Manual
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affected by mud filtrate invasion. Comparisons of the three measurements can also be an indicator of relative permeability. Common resistivity logs include the lateral focus log, the induction log, and the microresistivity log.
6.3.1
Lateral Focus Log The lateral focus log uses a sonde that sends current outward through the rock in a specific pattern. A set of guard electrodes in the sonde focus current sideways into a flat sheet. As the sonde is raised, the sheet of current passes through formation rock. Differences in formation characteristics change the flow of current through the sheet and these changes are logged at the surface.
6.3.2
Induction Log The induction log involves inducing a current in the formation beds. The sonde sets up a doughnutshaped magnetic field around the wellbore, which generates a current monitored by instruments at the surface. As the sonde is raised through formations, changes in the current are logged. Like the lateral focus log, the induction log is very accurate for investigating thin formation beds.
6.3.3
Microresistivity Log The microresistivity log is designed to show resistivities very close to the wellbore. It has two curves: one showing resistivity in mud cake, the other showing resistivity less than one-half foot away in the formation. When the two curves are not identical, an invaded zone is indicated and a possible reservoir is found. Porosity and permeability can be calculated from the microresistivity curves.
6.4
RADIOACTIVITY LOGS Just as resistivity logs record natural and induced electrical currents, radioactivity logs record natural and induced radioactivity. Traces of radioactive elements are deposited in formation sediments. Over time, water leaches them out of porous, permeable rock, such as limestone and clean sandstone, but cannot wash them out of impermeable formations, such as shale and clay-filled sands.
6.4.1
Gamma Ray Logs Gamma ray logs show radiation from these impermeable formations. The gamma ray sonde contains a gamma ray detector, such as a Geiger counter. This tool measures the natural radioactivity of the rocks by detecting elements such as uranium, thorium, and potassium, and is therefore used as a shale indicator. Shale free sandstones and carbonates, typically, have low gamma readings although certain mineralogies such as K-feldspars, micas and glauconite may increase the values. The gamma ray log is useful for correlation with the neutron log.
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6.4.2
Neutron Logs The neutron log measures the concentration of hydrogen ions in a formation. A radioactive source is loaded into the sonde and sent downhole. As neutron radiation bombards the rock around the wellbore and the rock gives off gamma rays from the neutrons it has absorbed. The greatest energy loss occurs on collision with hydrogen atoms, due to the fact that they are of a similar size. Because 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. Some sondes measure the levels of both gamma rays and unabsorbed neutrons. Other neutron logs can be calibrated to the gamma rays emitted by certain elements such as hydrogen, carbon, oxygen, chlorine, silicon, or calcium. The detected amounts of these elements give information about water and hydrocarbon saturations, salt content, and rock types. All neutron logs give good porosity readings.
6.4.3
Density Logs The density log, like the neutron log, uses radiation bombardment but uses gamma rays instead of neutrons. 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. Bulk density is the total density of a rock, reflecting rock matrix density, fluid density and pore space volume. The denser, or less porous, a formation is the more gamma rays it absorbs. On the other hand, the more porous a formation is the less rock there is to stop gamma rays. Mathematical formulas for such figures as porosity, hydrocarbon density, and oil-shale yield can be solved with data taken from density curves. As a direct indicator of compaction, the density log is an excellent tool in overpressure evaluation. Typically, the density log is only run through zones of interest, rather than the entire length of the borehole.
6.5
ACOUSTIC LOGS Sound travels through dense rock more quickly than through lighter, more porous rock. The acoustic log, also called the sonic log, shows differences in travel times of sound pulses sent through formation beds. Shale and clay, as well as porous rock, slow down the pulses. Using information about formation types from other logs, porosity can be determined from acoustic logs. This type of log is also used to verify the integrity (quality and hardness) of the cement bond between casing and the formation.
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6.6
TYPICAL LOGGING RUNS A wide variety of logs can be taken using a single sonde, but a specific combination is usually chosen for the types of formation data needed. Correlation between the curves gives a clear picture of lithology, porosity, permeability, and saturation up and down the wellbore. Figure 49 is a picture of E-log sondes ready to be picked up and made up for a logging job.
Figure 49: E-log Sondes
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7 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 because the well either requires expensive downhole tools to steer it back to its original course, or it must 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 bottomhole 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 because less weight is applied and the string hangs vertically under its own weight.
7.1 7.1.1
COMMON CAUSES OF DEVIATION Interbedded Lithology / Drillability Interbedded lithology (that is, 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.
Figure 50: Hole Deviation due to Interbedded Lithology
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7.1.2
Formation Dip Formation dip (that is, 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 (Figure 51).
Figure 51: Hole Deviation Due to Formation Dip
7.1.3
Faults Drilling through faulted zones, where the formation rock on one side of the break is displaced upward, downward or laterally relative to the rock on the other side (Figure 52) may cause a hole to deviate from vertical. This may result from rocks of different drillabilities being juxtaposed or from the fault plane itself where coarse brecciated material, or fault gouge may deflect the bit from its original course.
Figure 52: Varying Types of Faulting
7.1.4
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 drillstring bending. 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 (that is, the same diameter as the hole) that stabilize the string and keep it centralized.
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If the bottomhole 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 bottomhole 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, this may cause sections of the hole to become enlarged and allow the bit to follow another path.
7.2
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 and lead to a higher cost of drilling the well because of the extra time required to correct the problem.
7.2.1
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 (Figure 53). The rate at which the hole angle changes is therefore important in determining the severity of a dogleg.
Figure 53: Dogleg and Keyseat
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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 tries 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 drillstring, under tension, results in a groove being cut into the formation. Figure 53 illustrates the formation of a keyseat. A keyseat typically only forms 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.
7.2.2
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 (Figure 54) creating an irregular path for the drill string to pass through; it may result in full-gauge tools, such as stabilizers, becoming stuck under the ledges when the drill string is pulled from the hole.
Figure 54: Ledges
7.2.3
Stuck Pipe Drillstrings, casing, even wireline tools, are all subject to potential sticking through these geometric features due to:
Stiff bottomhole 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
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stuck beneath ledges.
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.
7.2.4
Casing may become stuck when attempting to pass through a dogleg.
Logging tools may also become stuck beneath keyseats or ledges.
Increased Torque / Drag and Drillpipe 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.
When drilling a deviated hole, the drillpipe 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 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.
7.2.5
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 is not be able to circulate between the casing and wellbore wall, thereby preventing a good bond.
When set, the inside of the casing may become worn when drilling / tripping proceeds, because the drill pipe is again forced against the inside bend.
7.3 7.3.1
PREVENTION OF DEVIATION Pendulum Effect The pendulum effect is the tendency of the drillstring to hang in a vertical position because of the force of gravity. If the hole deviates from the vertical, the bit and drill collars 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 drillstring 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 (Figure 55). The higher the point of tangency, the longer the pendulum and the greater the tendency of the drillstring to return to vertical.
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The axial load supplied by the weight of the drill collars, which affects the pendulum force. A greater load causes the bottom of the string to bend closer to the bit. The point of tangency is lower, and the pendulum force is 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.
Figure 55: Pendulum Force and Formation Resistance
When equilibrium exists (that is, the pendulum force equals the formation resistance), the hole drills straight, though inclined. If the pendulum force is greater, the hole angle decreases. If the formation resistance is greater, the hole angle increases.
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7.3.2
Pendulum Assembly Working on the pendulum effect principal, the pendulum bottomhole 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. A pendulum assembly 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 (Figure 56).
Figure 56: Pendulum Assemblies—Slick and with Stabilizers
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. Wellsite Procedures & Operations Manual
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7.3.3
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 (that is, formations known to cause deviation problems).
Figure 57: Packed-hole Assemblies
Characteristics of the packed-hole assembly include:
Three-point stabilizer placement to ensure 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 the bit and collars are centralized, yet preventing wall erosion.
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The number of stabilizers used, and their placement in the bottomhole 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 Figure 57.
7.3.4
Packed Pendulum Assembly Packed-hole assemblies are used to minimize the rate of hole angle change, although it is always likely to have 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 is 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 must be reamed before 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.
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Figure 58: Packed Pendulum Assembly
7.3.5
Stabilizers and Reamers Stabilizers are used to stabilize the bit and the drill collars in the hole. When properly stabilized, optimumdrilling 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 are used and the rate of penetration increases. 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 (that is, 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.
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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 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.
7.3.6
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, because of the variable bend in the drill pipe, can result in doglegs. If weight must 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.
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8 DIRECTIONAL AND HORIZONTAL DRILLING 8.1
REASONS FOR DIRECTIONAL DRILLING Directional drilling is the intentional deviation of a wellbore from vertical. Although 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 (for example, 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 toward the target. The borehole can then be steered, or directed, at the latter stages of the well 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—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 because offshore drilling is very expensive.
Offshore drilling—Directional drilling is common when drilling offshore because a number of wells can then 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 to reach the productive formation which often lies underneath the overhanging cap of the dome.
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Relief wells—these wells were the first application of directional drilling, and are 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.
8.2
SURVEYS / CALCULATIONS
8.2.1
Survey Methods
8.2.1.1
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 drillpipe 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 (that is, 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. 8.2.1.2
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. 8.2.1.3
Gyroscopic Surveys
A gyroscopic survey is used to record single or multi-shot surveys in cased holes. The gyroscope's pointer is set toward 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. 8.2.1.4
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. Wellsite Procedures & Operations Manual
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The drillpipe 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 method 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 is drilled.
8.2.2
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 (that is, azimuth and inclination) together with the measured depth (that is, from the pipe tally), it is possible to determine true vertical depth, build angle, dogleg severity and closure. For information on these terms, see Section 8.2.4 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 increases, 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.
8.2.3
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.
8.2.3.1
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 (that is, survey points) and the distance between the survey points (that is, course length). 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.
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8.2.3.2
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 (Figure 59). 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.
Figure 59: Determining Curvature
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 8.2.4
Directional Drilling Terminology See Figure 60.
Angle of Build—The degree of change of inclination, expressed in degrees over a specified distance (for example, 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.
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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 (for example, 3000 ft N60°E). 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 is 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 is always smaller than the measured depth in directionally drilled wellbores.
Wellhead—The normal reference point, at surface, for departure and drift direction.
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Figure 60: Directional Drilling Terminology
8.3 8.3.1
DRILLING TECHNIQUES Well Profiles There are three primary directional drilling profiles that may be pre-planned for a wellbore's course (Figure 61).
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Figure 61: Drilling Profiles—Shallow Deflection, S-Curve and Deep Deflection
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 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 is drilled. The hole angle is then reduced and / or returned to vertical to reach the target. Intermediate casing may often be set when the final reduction in angle is 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 to reach the target.
8.3.2
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).
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Constant Angle Section—When the desired deflection angle is 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 the target is successfully reached.
8.3.3
Whipstocks, Motors and Techniques Achieving kick off can be achieved by a number of different techniques:
8.3.3.1
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 (Figure 62).
Figure 62: Whipstock
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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. 8.3.3.2
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 drillstring rotation, the well is deviated in the direction of the oriented bent sub (Figure 63).
Figure 63: Downhole Motor and Bent Sub
The turbine is one type of downhole motor. Its 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, because 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 displaced and turned by the pressure of the Page 128 of 278
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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 follows 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 liters of fluid passing through the motor, a flow rate of 1.6 m3 / min. (1600 liters) produces an RPM of 200. 8.3.3.3
Rotating and Sliding
A combination of sliding (that is, bit rotation by downhole motor only) and rotating (that is, 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. 8.3.3.4
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 is 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.
8.4
HORIZONTAL DRILLING There are many reasons to drill horizontally through a reservoir:
Produce from thin formations, which are uneconomical to produce with vertical wells. A horizontal well has 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.
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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 because a horizontal well creates 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.
8.4.1
Classification Many definitions have been given to determine what classifies as a horizontal well and to describe the well profile. Here, a horizontal well being greater than 86° inclination from the vertical is distinguished as horizontal, 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. Figure 64 illustrates the concept of short, medium, and long radius wells.
Figure 64: Classification of Horizontal Wells
Short-radius wells achieve the horizontal profile over a very short distance and are typically 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 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 is.
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Medium-radius wells (for example 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 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.
8.4.2
Horizontal Drilling Considerations
8.4.2.1
Radius Effects
Short and medium radius wells obviously require a shorter horizontal displacement and therefore drill 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. 8.4.2.2
Reversed Drillstring Design
The main considerations are.
Transmitting weight to the bit
Reducing torque and drag.
Not exceeding stress limits, causing pipe failure.
Drill collars placed conventionally above the bit are a disadvantage in horizontal sections because they do not add weight to the bit and they increase torque and drag. They are therefore placed in the vertical section of the well, providing the weight and reducing torque and drag. Heavyweight drill pipe is typically used in the build section of the well because it can withstand the compression forces and axial loading that would buckle conventional drill pipe. For the same reason, heavyweight drill pipe is typically used for short horizontal sections because it is designed to withstand compression forces and can transfer high weights through to the bit. Drillpipe can withstand compression 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 because of 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 the 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.
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8.4.2.3
Drillpipe 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.
8.4.2.4
Severity of doglegs. Hole Cleaning
Drilled cuttings naturally tend to rest on the floor of the wellbore in horizontal sections forming cuttings beds that 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 to achieve this).
Efficient surface equipment to keep mud solids content to a minimum.
Typically high threshold but low yield-point mud.
Circulating when tripping out of the hole.
8.4.2.5
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.
8.4.2.6
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.
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Effective centralization for the casing is required to achieve good overall annular bonding and to prevent cement channeling.
8.4.2.7
The risk of poor mud displacement, leading to contamination of the cement. Formation Considerations
The main formation considerations in horizontal drilling are:
The adverse effect on hole direction (that is, causing unwanted deviation) caused by different drillabilities, formation dip, and so on.
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.
8.4.2.8
Formation dip and strength in relation to wellbore trajectory. 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 are drill pipe conveyed. That is, they are latched inside the drillstring with the wire run through a window. The drillstring 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.
8.4.2.9
Gas Behavior / Well Control
The main considerations with respect to gas behavior and well control in horizontal drilling are:
There is 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 migrate and accumulate in higher areas of the horizontal section (for example, deviated crests, washed out hole enlargements), requiring high annular velocities to displace, and slow pump rates when the gas is in the vertical section and subject to expansion.
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9 DRILLING PROBLEMS 9.1
FORMATION PROBLEMS AND HOLE STABILITY
9.1.1
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. 1
Fractures range from microscopic sizes to widths exceeding /8 inch (3mm) and can be well-ordered to random orientations. Older, harder formations at deeper depths tend to be more highly fractured than younger, softer formations at shallower depths. 9.1.1.1
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 (that is, 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 drillpipe is inhibited. If these cuttings are not removed from the hole and carried to the surface, the drillpipe can become stuck, thus stopping further rotation and blocking circulation (pack off).
Enlarged Hole, Reduced Annular Velocity, and 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.
Erratic Torque—Fractured cavings falling into the hole will act against the rotation of the drillpipe, leading to higher and erratic torque. In extreme cases, rotation may be completely stalled with the built-up torque in the drillstring, presenting the danger of twisting off, or breaking, the pipe.
9.1.1.2
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.
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Work and Clean Hole—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 bottomhole 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.
9.1.2
Shales
9.1.2.1
Reactive Shales
Swelling (that is, 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 (that is, 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. 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. 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 drillpipe 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.
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9.1.2.2
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 shale’s impermeability, the higher pressure will cause fracturing of shale, allowing fragments (or cavings) to break away and fall into the borehole. These cavings will lead to hole fill (that is, 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 drillstring, 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 over-pressured shale and the requirement to increase the mud weight. Increasing the mud weight is the most effective method of controlling under-compacted and overpressured shale sections.
NOTE 9.1.3
For more information on occurrences, causes, and detection of over-pressured shales, see the Weatherford Well Control manual.
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, and are 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, which creates 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 (that is, flow and pit
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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 used, providing very little balance against pressured gas, which expands and reaches the surface very rapidly. This situation requires extreme vigilance from the drilling crew and mud loggers to avoid a very dangerous situation. Freshwater reservoirs present a different kind of problem. With over-pressured aquifers, there is the associated problem of kicks. However, reservoirs may also be under pressured 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 they 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.
9.1.4
Salt Sections If salt sections are drilled using an incorrect drilling fluid (for example, 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 (that is, behave much like a fluid) and build up pressure against the borehole and drillpipe. This, in turn, can cause stuck and damaged pipe. To prevent such problems, it is important to regularly work the drillpipe 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.
9.1.5
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; they require thorough hole cleaning and maintenance.
9.1.6
Anhydrite / Gypsum Formations Anhydrite especially, and gypsum create a major challenge for the mud engineer. Both anhydrite and gypsum increase the viscosity and the gel strength of the mud. This alters the flow properties and hydraulics of the mud, leading to increased circulating swab and surge pressures, and creates a handling problem at the surface in that the mud will gum up surface equipment.
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9.2
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, including:
Loss of hydrostatic head that may allow fluids to flow into the wellbore from other formations (underground blowout).
Formation damage through the loss of permeability as mud solids and possibly cuttings are deposited. This not only leads to the possibility of poor wireline data but may damage the production potential of a zone of interest.
9.2.1
Increased costs as mud is lost and must be replaced and time is required to correct the product.
Associated drilling problems.
Occurrences There are many situations, naturally occurring and / or drilling induced, that can lead to circulation being lost, including:
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 when drilling, due to excessive mud densities and circulating pressure, pressure surges or increases when running pipe in the hole or when shutting in the well.
9.2.2
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. 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.
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9.2.3
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, that is, 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.
9.2.4
Differential sticking in or above the zone of lost circulation, due to the lack of mud in the annulus.
Prevention The first step in prevention is to avoid 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 over-pressured 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. Tripping procedures, principally for a controlled pipe running speed, should also be followed to avoid excessive pressure surges.
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9.2.5
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 maintain balance against other formations.
Reduce circulating rate; this reduces the equivalent circulating density (ECD), but there should still be sufficient annular velocity to remove cuttings and maintain bottomhole cleaning.
Increase the mud viscosity as 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 lost circulation material (LCM) such as wood fiber, nutshells, cottonseed 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.
9.3
KICKS AND BLOWOUTS A kick is an influx of formation fluid into the wellbore that can be controlled at surface. For a kick to 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 losing circulation.
9.3.1
A surface blowout occurs when the well cannot be shut in to prevent the flow of fluids at surface.
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,
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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. Under-pressured formations—May be subject to fracture and lost circulation, which could result in a
loss of hydrostatic head in the annulus. Over-pressured formations—If formation pressure exceeds the annular pressure, then a kick may
result.
9.3.2
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. Table 4: Kick Warning Signs for Lost Circulation, Transitional and Pressured Zones
Lost circulation zones
Transitional zones
Sealed overpressured bodies 9.3.3
•
Large surge pressures should result in closer attention to possible signs of fracture and lost circulation.
•
Weaker, fractured formations may be identified by higher ROPs and higher, erratic torque.
•
Reduced mud returns, identified from a reduction in mudflow and decreasing pit volume, indicate a loss of fluids to the formation.
•
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.
•
Immediate drill break resulting from the pressure differential and the higher porosity.
Indications of Kicks While Drilling The following influx indicators are listed in the typical order that would become apparent by surface measurements.
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1. 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. 2. Increased mud flow from annulus, followed by, 3. 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 mudflow 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: 4. 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: 5. Contaminated mud, especially gas cut exhibits:
9.3.4
o
Reduced mud density.
o
Change in chloride content (typically increase).
o
Associated gas response.
o
Pressure indicators such as cavings, increased mud temperature.
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 is pulled from the hole. This may indicate that a kick is swabbed into the hole, or that mud is being lost to the formation.
A Wet Trip—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.
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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, undergauged hole resulting from overpressure.
Every precaution (that is, monitoring the well before pulling out, minimizing swabbing, and flow checks) is taken to avoid taking a kick during a trip because:
9.3.5
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 BOPs.
Flow Checks A flow check, which determines 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.
Flow checks are typically conducted at:
Significant drill breaks.
Any kick indication while drilling, especially changes in mud flow.
Prior to slugging the pipe before taking 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 BOPs.
Constant monitoring (trip tank) while out of the hole.
If the well is flowing, the well will be shut in.
NOTE
For more details on kick detection and well control, see the Blowout Prevention and Well Control Manual.
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9.4
STUCK PIPE The term tight hole is applied to situations when the movement of the drillstring, 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 drillpipe 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:
9.4.1
Hole packoff or bridge
Differential sticking
Wellbore geometry
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 drillstring (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 drillstring 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 can fracture and cave 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.
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,
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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 drillstring.
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 bottomhole 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 drillstring. 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 drillstring.
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 drillstring, causing stuck pipe. This will typically occur when pulling out of the hole or after extended periods with the drillstring 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.
9.4.2
Differential Sticking Differential sticking can result when a permeable formation, with formation pressure less than hydrostatic pressure (that is, 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.
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Where there is drillstring 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 bottomhole assembly can lead to this contact area being greater. Where the contact area exists and the drillstring becomes stationary (during connections, surveys, downtime, and so on), static filter cake builds up, adding to the thickness, and a low-pressure area develops behind the pipe contact area (Figure 65).
Figure 65: Differential Sticking
This differential sticking force, together with the thick filter cake, leads to the pipe becoming stuck, preventing vertical movement and rotation of the drillstring. 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.
9.4.3
Wellbore Geometry Stuck pipe can occur where a combination of wellbore geometry and changes in wellbore direction, together with the bottomhole assembly stiffness and arrangement of tools such as stabilizers, prevent the drillstring 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).
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9.4.3.1
Stuck Pipe during RIH
After a deviated section is drilled with a specific angle building assembly, the bottomhole assembly will then typically be changed to continue the straight section of the well. The stiff bottomhole assembly may not be flexible enough to pass through the deviated section and stabilizers in the assembly can become hung up in opposing sections of the wellbore, preventing the drillstring from being lowered further (Figure 66).
Figure 66: Stuck Pipe during RIH
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 drillstring should not be forced down. Rather, the bottom section of the hole should be carefully reamed and opened up to the full-hole size. 9.4.3.2
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.
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Figure 67: Stuck Pipe During POH
9.4.4
Rotary Drilling Jars Should the drillstring become stuck and incapable of being freed with normal working (that is, upward and downward movement) of the pipe, or by pulling on the pipe without exceeding drillstring and surface equipment limits of overpull, and then rotary drilling jars will be used. These are designed to strike heavy-impact hammer blows, in an upward or downward direction, to the drillstring. 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 drillstring 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 must be situated above the stuck point so, typically, jars will be situated in the upper apart of the bottomhole 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 drillstring 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.
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9.4.4.1
Hydraulic Jars
Figure 68: 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 drillstring above the jars which were accelerating through the stroke. 9.4.4.2
Mechanical Jars
Mechanical jars deliver the hammer blow by the same acceleration / deceleration of the jars and free the drillstring, but the triggering mechanism is by a pre-set tension with no time delay when the jar is cocked. 9.4.4.3
Jar Accelerator
A jar accelerator may be set above the rotary jars, typically within the heavyweight drillpipe, 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 drillstring and surface equipment by cushioning rebounds through the compression of fluid or gas.
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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 must 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.
9.4.5
Use milling or grinding bits to drill down through the stuck pipe.
Plug back with cement and sidetrack around the stuck pipe.
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 drillstring 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 (that is, break apart). All pipes and other equipment below the break must be fished out of the hole before drilling can proceed. The point of twist off can be identified by a drop in drill string weight and pump pressure.
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 pipes 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.
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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.
9.4.6
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 and then stopped to allow the junk to fall down into the basket. This will be repeated several times and then the drillstring is lifted to the surface to determine whether all of the junk is removed. A reverse circulation junk basket, also positioned immediately above the bit, uses reverse circulation to create a vacuum so that junk is swept toward 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. 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 is lost in the well. It is run into the hole on the bottom of the drillpipe 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.
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The impression is a mirror image of the top of the fish and indicates the position of the fish in the hole (that is, 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 (Figure 69). If the top of a fish is badly damaged, the surface can be dressed, or repaired, by milling (that is, cutting or grinding away rough edges). This ensures the selected fishing tool will be able to firmly grip the fish.
Figure 69: Milling Tools
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 (Figure 70).
Figure 70: Overshot
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The overshot is attached to the bottom of the tubing or drillstring 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 (such as casing or large drill collars lost in tight holes). The spear is attached to the bottom of the drillstring and lowered down the hole into the lost pipe. When weight or torque (or both) are applied to the drillstring, 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. 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 (Figure 71).
Figure 71: Wireline Spear
Washover Pipe Washover pipe is large-diameter pipe run down, and rotated around the outside of stuck drillpipe 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 drillstring becomes stuck when pulling it from the hole, the free point (that is, 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 drillstring 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.
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By backing off (that is, 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 must 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.
9.5
DRILLSTRING VIBRATIONS It is a widely accepted fact that downhole vibrations can cause premature wear, or even failure of the drillstring and bit. This understanding has now 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 such as hard formations and steep angle wells. This is a major cause of bit and drillstring failure. There are three principal types of drillstring vibration recognized:
Torsional Vibration—Variable pipe rotation, torque versus RPM
Axial Vibration—Up and down the string, bit bounce
Lateral Vibration—Off center rotation, side to side whirl
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9.5.1
Torsional Vibration Torsional vibration occurs when the rotation of the drillstring is slowed down (or stopped) at the bottom of the hole 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 and low RPM, low torque and 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.
Figure 72: Torsional Vibration
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 top drive system (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. When 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. Problems include the following: Damage to, or fatigue failure of bit cutting elements through variable RPM and cutter load. Wellsite Procedures & Operations Manual 5-1-GL-GL-SUL-00009 (Mar 2013) Page 155 of 278
Reduced ROP
Connection fatigue and premature failure of drillstring, BHA and downhole tools.
Washouts, twist-offs
Fishing trips and replacements.
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.
When torsional vibration is 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 is 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.
9.5.2
Axial Vibration Axial vibration appears during the drilling operation in two forms:
Vertical vibration while the bit is still in contact with the formation.
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Bit bounce when contact is repeatedly lost as the bit bounces on and off bottom.
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 (Figure 73). 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 is, typically, the higher the frequency of axial vibration at the bit. Impulses sent through the drillstring generate correspondingly higher amplitudes of axial vibration energy.
Figure 73: Axial Vibration
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.
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In vertical wells where propagation of energy along the string is easier.
When drilling with tri-cone bits as less contact area and 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 in standpipe pressure (SPP) are seen as the bit loses and regains contact with bottom with high frequency.
When identified, remedial action includes:
Lowering the bit to bottom slowly and smoothly.
Reduce WOB, adjust RPM.
Use of PDC bits, shock subs.
WOB should be adjusted first, but this, in turn, is dependent 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).
9.5.3
Lateral Vibration The theoretical spinning string of a perfect drilling assembly in a vertical hole is known as axisymmetric motion, that is, symmetrical motion around an axis.
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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 (Figure 74).
Figure 74: Lateral Vibration
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—an off-center bit rotation, which is especially common with PDC bits.
Forward BHA Whirl—Off-center BHA rotation, with its center line rotating in the same direction as the drillstring rotation, that is, clockwise.
Backward BHA Whirl—Occurs where the borehole wall friction causes the center line rotation to become anti-clockwise, opposite to the rotation of the drillstring.
When trying to visualize 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.
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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, and casing damage.
Lateral impacts inducing other vibrations.
Common occurrences are:
Alternating lithologies.
Vertical wells—easier to stimulate the whirl motion. It is virtually impossible in deviated wells due to the effect of gravity.
Contributing factors include:
Bit type—PDC bits will more easily move off-center 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, the whirl is present at the bit and / or BHA. Remedial action includes:
Reduce RPM, change WOB. Increase WOB 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.
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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.
NOTE 9.6 9.6.1
For more details, see the Surface Vibration, Monitoring, and Analysis Manual.
WASHOUTS Drillstring Washouts A drillstring washout is any hole or crack in the drillstring caused by corrosion, fatigue, or failure of the drillstring. Typical causes and contributing factors include:
Poor equipment handling.
Deviated holes and doglegs.
Running drillpipe in compression rather than tension.
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 drillstring washout occurring as drilling fluid leaks out of the drillstring into the annulus. If left unattended, the pressure drop will accelerate as the washout becomes more severe.
9.6.2
Hole Washouts These occur where the annulus becomes enlarged. It is very important to know actual borehole diameter and presence of washouts 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.
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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 drillstring causing physical corrosion; and also swab and surge pressures. 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, and so on. Another indication of the hole washing out may be an increased volume of cuttings.
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10 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.
10.1 BENEFITS AND LIMITATIONS OF UNDERBALANCED DRILLING Underbalanced drilling (UBD) 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.
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Thick coal beds are typically fractured and weak, and will collapse or wash out when drilled underbalanced. They may also produce water, which will adversely affect air / gas drilling.
UBD should also not be used to drill over-pressured 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.
10.2 UNDERBALANCED DRILLING FLUIDS The drilling fluids used in underbalanced drilling fall into the following classifications:
Gas (that is, air, natural gas, nitrogen, or other gases).
Gas with mist.
Foam with gas.
Aerated water, mud or oil, using one of the gases.
Oil, water, invert or direct emulsion muds (that is, conventional drilling fluids applied to provide hydrostatic pressure less than formation pressure).
10.2.1 Gas and Air Drilling Since its inception, gas drilling is 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. 10.2.1.1 Advantages
Maximum ROP
Reduced cost to drill lost circulation zones
Reduced drilling fluid costs
Improved well performance
No corrosion (N2)
10.2.1.2 Disadvantages
Water wet formations
Cost. Nitrogen can be expensive if used, especially when drilling large diameter holes.
Possibility of downhole fires, when using air
No wellbore support
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10.2.1.3 Equipment The drillstring used for gas drilling is much the same as for mud drilling. However, the drillpipe must be strong enough to withstand the weight and shocks normally supported and absorbed by drilling mud. Dried mud inside the drillpipe may loosen and plug an air bit or hammer, and the drillpipe may leak when returned to mud service. Air drilling bits generally resemble mud drill bits, but have an open orifice to minimize pressure drop through the bit. Sample catchers are used to gather cuttings samples to aid the mud loggers 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. 10.2.1.4 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 (Table 5).
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.
10.2.1.5 Drilling problems Table 5: Gas and Air Drilling Problems
Problem
Description
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 airflow, 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 airflow 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 mud logger 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.
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Problem
Description
Fires
Drilling into gas or oil bearing zones using air, leads to the possibility of fires, either downhole or at the surface. The use of nitrogen or methane eliminates this, because 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 drillpipe 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. 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.
10.2.2 Mist Drilling 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. 10.2.2.1 Advantages
Can drill in wet formations
Represses downhole fires
10.2.2.2 Disadvantages
Lower drilling rate than air / gas
Requires more air volume and injection pressure
Dampness may allow corrosion
No wellbore support
10.2.3 Foam Drilling 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. Page 166 of 278
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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, that is, 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. 10.2.3.1 Advantages
Fluid lifting capacity; it is able to lift and remove large influxes of formation liquids (for example, water).
Excellent cuttings sample / lift / removal (compared to air / mist) due to its viscosity, requiring lower velocity.
Needs less gas than air / gas / mist.
10.2.3.2 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.
10.2.4 Aerated Mud Drilling The term aerated fluid is given to a two-phase fluid with a foam quality of less than 0.55 (that is, 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 mud is therefore 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. An aerated fluid maintains the benefits of the original fluid, such as viscosity, hole cleaning, filter cake, inhibition, and so on, while reducing the potential for lost circulation. 10.2.4.1 Advantages
Mud Properties (for example, density, filter cake, inhibited muds)
Pressure control
Reduced risk of lost circulation
10.2.4.2 Disadvantages
Pressure surges
Corrosion (with certain drilling fluids)
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Additional cost of equipment and gas generation
10.2.5 Mud Drilling 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 (that is, the well is flowing as it is being drilled). Advantages and disadvantages really depend upon the type of drilling fluid being used, but generally: 10.2.5.1 Advantages
Increased rate of penetration
Less formation damage
Better productivity
Reduced lost circulation
Real-time testing of zone productivity
10.2.5.2 Disadvantages
Surface handling.
Salt systems are extremely corrosive, but can be used in higher pressures than fresh water.
Water-base mud systems are subject to solids control and separation of oil, but inexpensive and easily modified.
10.3 UBD EQUIPMENT AND PROCEDURES 10.3.1 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 drillpipe. 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 drillstring while a housing (that is, steel bowl) and bearing assembly control the flow, either by diverting or containing it. Page 168 of 278
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Figure 75: Rotating Head
The critical components of a rotating head design are the means by which the seal is affected around the irregular surfaces of the drillstring, and the bearing assembly, by which the inner race rotates with the drillstring 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 drillpipe, it seals around the drillstring 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 (that is, no external hydraulic pressure is required).
An inflatable bladder or spherical packer inflated or actuated by hydraulic pressure. This seals around the drillstring 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 an on-site operator while the tool is in use.
Rotating heads have been used successfully for years. They are small, relatively lightweight, and have a low profile. They are simple to install on the rig, easy to use, and easy to repair (for example, quick replacement of stripper rubbers, bearings, and seals).
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10.3.2 Closed Circulating and Separating Systems Underbalanced drilling in hydrogen sulfide (H2S) bearing reservoirs has led to the development of the closed system to prevent fumes and gas from escaping to the atmosphere from the flowline and mud / gas separators. 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.
10.3.3 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 (Figure 76). The blooie line is normally a low-pressure line with any required choking done with the choke manifold on the flowline. A pressure rating of 150 psi (1034 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.
Figure 76: Blooie Line
As with conventional drilling, samples of cuttings must be gathered during underbalanced drilling to aid the geologist or mud logger in formation evaluation.
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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.
10.3.4 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 dropout jar and drier, attached to a valve outlet on the separator (Figure 77).
Separator
Filter
Regulator
Drop-Out Jar & Drier
Gas Sample Line
Drainage
Figure 77: Gas Measurement from Separator
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 airflow (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 (Figure 78). Blooie Line
Flow Sample
Shut off valve
Filter Gas Sample to Unit
Collected Liquid Figure 78: Gas Measurement from Blooie Line
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10.4 COILED TUBING UNITS 10.4.1 Components Table 6: Components of Coiled Tubing Units
Component
Description
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 meters) central diameter, used to reel up to 26,000 ft. (7930 meters) lengths of tubing. Reel diameter is normally chosen to minimize coiling diameter (that is, 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.
BOPs
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 BOPs, they consist of pipe and blind rams to close the well, and slip rams to support tubing sheared by tubing cutters.
Hydraulic PowerPack
Consisting of a diesel engine, hydraulic pumps, and hydraulic pressure control, this powers the reel, injector, fluid pumps, and other rig equipment.
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, and so on.
Figure 79: Coiled Tubing Unit
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10.4.2 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 slimhole 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
10.4.3 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 drillstring 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.
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.
Coiled-tubing drilling is a relatively new technique, requiring considerable development and industry
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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, unsettling production packers, and so on.
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11 ROCKS AND RESERVOIRS 11.1 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; igneous, metamorphic and sedimentary.
11.1.1 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.
Intrusive igneous rocks form when the magma does not reach the earth’s surface but cools within the earth’s crust.
The igneous rocks that result 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.
11.1.2 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.
11.1.3 Sedimentary The factors combining to the formation of sedimentary rocks are those of erosion, transportation and deposition. Erosion of the existing landmass can be caused by several processes:
Mechanical weathering due to water, wind, ice and temperature changes.
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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, and 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 its load.
Alluvial deposits form where rivers drop their load, due to 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 losing 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 transportation 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. 11.1.3.1 Sediment Classification Sediments can be classified according to their depositional environment. Table 7 is an example of such a classification: Table 7: Sediment Classification Based on Depositional Environment
Terrestrial Transitional
Aeolian Alluvial Deltaic Pro-Deltaic Neritic (shallow, shelf)
Marine
Bathyal (continental slope) Abyssal (deep ocean floor)
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The sediments within these groups can be classified on the basis of the origin of the material: Table 8: Sediment Classification Based on Material Origin
Clastics
Where the constituent components are eroded and transported fragments (clastics) of pre-existing rocks or minerals Transported shell fragments may also be grouped in this category
Chemical precipitates Organic
Formed by evaporation of surface water or by the crystallization of dissolved salts In situ accumulations of organic debris such as shells, skeletal fragments, plant remains
11.1.3.2 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 first 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. 11.1.3.3 Clastic Rock Types These are characterized by the size of the clastic material making up the rock. Table 9: Clastic Rock Types
> 256 mm
boulder
Breccia (angular) or Conglomerate (rounded)
64 - 256mm
cobble
Breccia (angular) or Conglomerate (rounded)
4 - 64mm
pebble
Breccia (angular) or Conglomerate (rounded)
2 - 4mm
granule
Breccia (angular) or Conglomerate (rounded)
1/16 - 2mm
sand
Sandstone
1/256 - 1/16mm
Silt
Siltstone
< 1/256mm
clay
Claystone or Shale
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11.1.3.4 Chemical and Organic Rock Types Table 10: Main Types of Chemical and Organic Rocks
Carbonates
Limestone Dolomite
Chert
Chemical
Organic
Evaporites
Gypsum Anhydrite Salt
Limestone
Coquina, Reef
Diatomaceous Earth Coal
11.2 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 accumulations 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.
11.2.1 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 microorganisms such as plankton plants (for example, algae) and animals (for example, foraminifera). Not only are these present in Page 178 of 278
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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.
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 must 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
The de-watering process, later in the burial history of the sediments, may also provide the means for primary migration. See Section 11.2.4.
11.2.2 Maturation of Petroleum We have 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 sulfide. 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. When free oxygen is removed, the remaining organic material has a good potential of being converted to hydrocarbons (via 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
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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 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 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 temperature 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.
11.2.3 Petroleum Migration Clearly, since reservoirs are found in porous and permeable rocks such as sandstone or limestone, yet, petroleum develops in source rocks such as clay, there must 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 is raised, however, as to how this migration could take place because the clay sediments, would, by this time, be largely impermeable. Page 180 of 278
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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.
11.2.4 Primary Migration Primary migration is defined as the expulsion of hydrocarbons from the source rock into carrier beds. As hydrocarbon generation is taking place during burial, so too 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 must 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. 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 must 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 is 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, 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 cation exchange, will result in an increase in the fluid pressure within the pores, that is, 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 over-pressured sediments toward 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.
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11.2.5 Secondary Migration Secondary migration is defined as movement of hydrocarbons through a carrier rock to a reservoir. This secondary process is the migration of the hydrocarbons within a permeable and porous body (that is, 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. As long as a pressure differential and permeable openings or weaknesses, such as fractures exist, 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 along with 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.
11.2.6 Hydrocarbon Traps As detailed above, in order for a hydrocarbon pool to accumulate, there must 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 rocks themselves and the occurrence of effective seals. 11.2.6.1 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 faces change within the same body. This may occur in the depositional environment or may be as a result of later cementation or crystallization (Figure 80). 2. Where bodies of sand form lenses or lenticular deposits within impermeable sediments—this may be typical of a braided river channel. Page 182 of 278
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3. Pinch outs forming where sediments are being deposited against an existing shelf or depositional surface, typical of deltaic or shoreline environments (Figure 80).
Figure 80: Traps Formed by Fancies Change and Pinchout
4. Carbonate reefs
Figure 81: Trap Formed by Carbonate Reef
5. Aeolian dunes
Figure 82: Trap Formed by Aolian Reef
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, Figure 83 (A), onlaps onto unconformities Figure 83 (B), buried erosional relief, and so on.
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Figure 83: Stratigraphic Traps
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—Dolomitization of low permeability limestone for example, may improve reservoir quality.
11.2.7 Types of Structural Traps 11.2.7.1 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 is upfolded, allowing hydrocarbons to migrate to the crest of the fold and be trapped by overlying impermeable sediments (Figure 84).
Figure 84: Fold Related Structural Trap
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 amplitude to hold all of the hydrocarbons migrating into the trap, then a spillover will result. 11.2.7.2 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.
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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 (Figure 85).
Figure 85: Graben Structure
Anticlinal traps may also be associated with faulting, particularly with thrust or rotational faults (Figure 86).
Figure 86: Anticlinal Trap
11.2.7.3 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 (Figure 87), but similar features will be produced by igneous intrusions or by shale diapirs.
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Figure 87: Traps Associated with Salt Dome
11.3 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, sulfur, 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 two types, depending on the molecular bonding of the carbon atoms.
Saturated Hydrocarbons—Compounds that possess one single covalent bond between the carbon atoms
Unsaturated Hydrocarbons—Compounds possessing double bonds between the carbon atoms
NOTE
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.
11.3.1 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 three series of alkanes. The straight and branched series are known as paraffins and the cyclic series as naphthenes.
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11.3.1.1 Paraffins 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:
Where n ranges from 1 to 10
Cn H2n+2
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). Chromatographic gas analysis at wellsite usually extends from methane through to pentane; 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. Table 11: Straight Chained Alkanes
Structure Formula
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Name
Formula
Methane
C1
CH4
Ethane
C2
C2H6
Propane
C3
C3H8
Normal Butane
nC4
C4H10
Normal Pentane
nC5
C5H12
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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. Table 12: Branched or Iso Chained Alkanes
Structure Formula
Name
Abbreviation
Iso Butane
iC4
C4H10
Iso Pentane
iC5
C5H12
11.3.1.2 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 given to the paraffin series are prefixed with cyclo to distinguish the naphthene series that is, cyclopropane, cyclobutane, and have the general formula:
Table 13: Closed Chained Alkanes - Naphthenes
Cn H2n
Structure Formula
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Name
Formula
Cyclopropane
C3H6
Cyclobutane
C4H8
Cyclopentane
C5H10
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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.
11.3.2 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, that is, 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
Benzene is the simplest aromatic compound (C6H6); it’s a closed chain, or ring, of six carbon atoms, with alternating single and double covalent bonds links the carbon atoms (Table 14). 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 shown in Table 14, 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. Table 14: Aromatics—Benzene and Toluene
Benzene C6H6
Toluene C6H5CH3
Benzene is extremely soluble; in fact this group is often referred to as the soluble hydrocarbon group. It is 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.
11.3.3 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.
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High API gravity oils have a high content of the gasoline hydrocarbons (C4 to C10). The API gravity is defined, at 16° Celsius (60° Fahrenheit) and atmospheric pressure, by the following formula:
API Gravity =
141.5 − 131.5 Speci�ic Gravity at 60℉
The greater the API rating is, the lighter the oil. The API rating can be visually approximated by the color of the oil or by the color of the fluorescence under ultra-violet light (refer to Section 13.2 Oil Shows for more detail).
NOTE
For more information on hydrocarbon classification and evaluation, see the Hydrocarbon Evaluation and Interpretation Manual.
11.4 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 must 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.
11.4.1 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. 11.4.1.1 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 Page 190 of 278
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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. 11.4.1.2 Limestones Porosity is possible through a number of mechanisms. Firstly, the carbonate may be granular or crystalline with porosity being either intergranular (between granules) or intragranular (within granules 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. Porosity can only be accurately determined 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 %
11.4.2 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 affected by the sizes of the pore throats, the degree of tortuosity (linearity of connections), the fluid type, and viscosity. Permeability can only be accurately determined by laboratory core analysis, but can 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. 3
3
A permeability of 1 darcy is equal to 1cm of a fluid with viscosity 1 cP, flowing through 1cm of rock in 1 second, under a pressure of 1 atmosphere. Reservoir permeabilities are typically measured in millidarcies (md). Wellsite estimations can be determined by comparing the gas measured in the header box by standard gas trap to the cuttings gas, a comparison of the gas that can escape from the rock during transport to the
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surface to the gas that is retained within the volume of rock. This will also provide a qualitative indication of the porosity.
11.4.3 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 hydrocarbon migration, any hydrocarbons generated will move with this water, following a decreasing pressure gradient, into a reservoir rock. 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. 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.
11.4.4 Reservoir Zones, Contacts and Terminology Separation during secondary migration, as a result of relative specific gravities and buoyancy, gives rise to gas (upper) and 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. That is:
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 gas oil ratio (GOR). 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.
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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.
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12 MUD LOGGING—INSTRUMENTATION AND INTERPRETATION This section is intended to provide a guide to the main mud logging tools and parameters; what the mud logger 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 the Field Training manual.
12.1 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 bit 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.
12.1.1 The Geolograph Drilling 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 meter), a pen will be triggered and a tick mark will be recorded on the geolograph chart (Figure 88).
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Figure 88: Geolograph
Although simple and robust, the geolograph is only operated during drilling. Block movement during tripping operations is so fast that the Geolograph must be disengaged. The driller re-engages it when the bit is 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 (Figure 89).
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Figure 89: Geolograph Tracks—Tag Bottom and Drill Ahead
12.1.2 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. 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.
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Figure 90: Crown Sheave Depth Sensor
12.1.3 Drawworks Sensor The drawworks sensor is independent of the rig system and monitors the movement of the blocks at all times. The 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 must be let out from the drum; to raise the blocks, the drum must 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 mud logger does not have to climb up to the top of the derrick with targets, sensors, tools, and cable.
12.1.4 Heave Compensation When working on floating offshore rigs (drillship or semi-sub), tidal and heave variations have to be accounted for to determine the true depth of the hole. This is accomplished by installing transducers on the drilling motion compensator (Figure 91) and on the riser tensioners to measure their extension or compression in response to heave movement (Figure 91). 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. 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
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must 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 can 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.
Figure 91: Schematic of Riser Tensioning and Compensation
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Figure 92: Heave Compensation
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. This type of compensation is most commonly achieved through a traveling block compensator situated between the traveling block and the hook supporting the drillstring (Figure 92). 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 (Figure 93 illustrates a double piston system).
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Figure 93: Schematic showing Travel Block compensation
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.
12.1.5 Rate of Penetration (ROP) 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 (for example, m / hr, ft / hr) or in terms of the length of time taken to drill a given depth interval (for example, min / m). For example: 60 m / hr = 1.0 min / m, 30 m / hr = 2.0 min / m 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. Page 200 of 278
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There are many factors that can affect the ROP, including:
Bit selection.
Rotary speed (RPM).
Weight on bit (WOB).
Differential pressure.
Hydraulics.
Bit wear.
Lithology.
Depth.
Formation pressure.
12.1.5.1 Bit Selection As described in Section 2.4 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. 12.1.5.2 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 (Figure 94). The exception is, again, with diamond or PDC bits when, even in hard formations, ROP will increase linearly with rotary speed. 12.1.5.3 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 (Figure 94).
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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.
Drill Rate vs. RPM
Drill Rate vs. WOB
Figure 94: Drill Rate vs. RPM and Drill Rate vs. WOB
12.1.5.4 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. (See Section 4 Subsurface Pressures) The greater the overbalance is, 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 is 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. 12.1.5.5 Hydraulics and Bottomhole 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 bottomhole 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 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. Page 202 of 278
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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. 12.1.5.6 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. 12.1.5.7 Lithology As mentioned, penetration rate is one of the primary interpretative tools used by the geologist and mud logger in recognizing formation changes. However, as described here, many factors can affect the ROP and 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 must be as a result of a change in lithology. 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), and so on. 12.1.5.8 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. 12.1.5.9 Formation Pressure 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, and therefore higher porosity, which leads to increased ROP.
12.1.6 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 (Figure 95). It is the responsibility of both the mud logger and the driller to identify such breaks as quickly as possible. When the mud logger identifies a positive drilling break, he or she should notify the driller immediately and also make a record that this is done.
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Figure 95: Positive and Negative Drilling Breaks
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 must be due to a formation change. It may simply be due to a lithological change (softer, less consolidated, weaker or no cement, greater porosity, and so on), in which case, the mud logger should lag the break and collect additional cuttings when they arrive at surface in order to identify the change. However, what always must 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 is accounted for), the well is flowing. At this point, the well will be shut in (closing the annular preventer) to control the influx. Page 204 of 278
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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 are detailed in Section 9.2, 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.
12.1.7 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 turnkey 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 ROP will be taken into consideration and optimized to provide the fastest drilling as possible while maintaining safety and borehole 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, and so on. 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 must 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.
Certain situations will necessitate the control of the drilling rate (controlled drilling):
Determining specific formation tops, casing points, and coring points.
While drilling surface holes. Soft formations and large bit size on which higher weight can be applied, can lead to very fast drilling rates but can also lead to:
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o
Hole collapse from loose, unconsolidated formations.
o
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.
o
Hole problems from soft surface clays, particularly in offshore drilling.
o
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, and so on.
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.
12.2 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 (bottomhole assembly 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 (that is, 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 described in the previous section, increasing the WOB will produce a faster drilling rate. Weatherford measures the hookload by detecting changes in tension on the drill line due to the different load, by use of a load/pancake cell or strain gauge. Page 206 of 278
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12.2.1 Load or Pancake Cell The drill line, or rather the deadline section of the drill line between the crown block and deadline 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 (Figure 96).
Figure 96: Load Cell
In many cases, however, the rig will have a load cell and hydraulic system in place so that we are able to connect our mud logging 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.
12.2.2 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.
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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.
Figure 97: Strain Gauge
12.2.3 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 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.
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 (Figure 98).
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Figure 98: WOB and Drill Collar Weight
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.
12.2.4 Hookload, Drag and Overpull Hookload is an important parameter in identifying tight spots in the hole.
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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, and so on. When pipe is being raised or lowered, the buoyancy factor of the drilling fluid must be taken into consideration, since it will either support or resist pipe movement. To lift the pipe, the mud resists pipe movement, so this resistance must 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 (Figure 99).
When being raised, additional resistance must be overcome 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.
Figure 99: Hookload—Overpull and Drag
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
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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 BOPs placed inside the drillstring will affect its 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.
12.3 ROTARY SPEED AND ROTARY TORQUE 12.3.1 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. The rotary speed (revolutions per minute or RPM) is measured by a proximity switch 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 liters of fluid that passes through it (0.1 revs / liter), and circulating flowrate is 1.5 m3 / min (1500 liters / min). Then:
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 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. Wellsite Procedures & Operations Manual
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12.3.2 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 by the amount of electrical current that is required to drive the table. It is determined with a simple torque clamp (Figure 100) that measures the magnetic field induced around the power cable.
Figure 100: Torque Clamp
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 meter (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 (Figure 101), can be obtained by the toolpusher or rig mechanic.
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Figure 101: Example of Torque Conversion (ft / lb to amps)
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.
Worn or failed bearings.
Loss of cones.
Poor bottomhole 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
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Fractures, typically leading to high, erratic torque
12.3.2.1 Formation Evaluation and Fracture Identification Changes in torque character may also be seen as a result of lithology changes such as hardness, abrasiveness, or granularity, 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 (Figure 102).
Figure 102: Changes in Torque Character with Formation
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 parameters. 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, and its inclination to the wellbore.
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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 is alerted to the possibility of lost circulation, associated gas, and possibly even a kick, so will be monitoring for indications of these events. 12.3.2.2 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, that is, both will increase or decrease simultaneously. 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 to get the string rotating again (Figure 103). This situation is analogous to a high force being required to move a stationary object, but when 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, that is, the torque may be high enough to break a connection.
Figure 103: Sticking Pipe
12.3.3 Torsional Vibrations Torsional vibrations (see Section 9.5.1) 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. Wellsite Procedures & Operations Manual
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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 behavior 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.
12.4 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 =
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Pressure lost through surface lines + Pressure lost inside the drillstring + Pressure lost in the annulus + Pressure lost at the bit
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Figure 104: Hydraulic Transducer on Standpipe
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 (Figure 104). This valve is known as a knock-on head because it must be fully tightened with the aid of a sled. Inside the knock-on head, a rubber diaphragm separates the circulating mud from hydraulic fluid. Changes in the pressure act on the diaphragm. These changes are transmitted hydraulically to the pressure transducer. Normal units of measurement are:
KPa: kilo Pascal
PSI: pounds per square inch
Kg / cm : kilogram per square centimeter
1 psi = 6.894 KPa = 0.0703 kg / cm = 0.0689 bars
2
2
The pressure rating of the standpipe sensor is typically 5 to 10,000 psi (approx. 35 to 70 000 KPa).
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The measured standpipe pressure is dependent on a number of parameters: Table 15: Measurement of Standpipe Pressure
Parameter
Description
Density of the mud
The higher the density, the higher the pressure.
Mud viscosity
The higher the viscosity, the higher the pressure.
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 total flow area (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 conditions in Table 15 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 conditions in Table 16: Table 16: Conditions Affecting Standpipe Pressure
Pressure Condition
Description
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.
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Pressure Condition
Description
Mud Condition
If mud density and / or viscosity are not consistent throughout the system, erratic pump pressure may be seen. This patchiness 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 toward 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 gelling of the mud, while it was static, is broken down with a resulting reduction in viscosity.
12.5 ANNULAR OR CASING PRESSURE Pressure on the annular side of the wellbore (as opposed to the standpipe pressure monitoring the pressure inside the drillstring) must be 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 20,000 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. Wellsite Procedures & Operations Manual
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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. By knowing the shut-in drillpipe pressure (SIDPP) and the shut-in casing pressure (SICP), the following can be determined:
Formation pressure and mud weight required to control the well (kill mud weight).
Kill circulation pressure requirements.
Monitoring of pressures as the influx is removed from the wellbore.
The size and type (such as, gas, water, oil) of influx.
12.6 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 switch (as shown in Figure 105) or some form of a rod / microswitch that is activated by each stroking motion of the pump.
Figure 105: Proximity Sensor on Mud Pump
12.6.1 Rig Pumps Rig pumps can either be triplex or duplex types.
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Triplex pumps (as shown in Figure 19) 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 three pistons is such that, at any one time, they are at different points of their stroke ensuring a continuous output of mud. That is, 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 its 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.
12.6.2 Pump Output Calculation Pump cylinder volume = πr 2 h
Pie, radius to diameter conversion, unit conversions and the number of chambers are all accounted for in the equations in Table 17 and Table 18. 12.6.2.1 Triplex Pump These possess 3 pistons / cylinders, but only displace mud on the forward stroke. Pump output can be determined in the units indicated in Table 17: Table 17: Determining Triplex Pump Output
Formula
Units
Bbls/stroke = 0.000243 x D2 x L
D = Pump liner diameter, inches L = Stroke length, inches
Liters/stroke = 0.0386 x D2 x L
D = inches L = inches
Gals/stroke = 0.010198 x D2 x L (Alternatively multiply bbls/stroke by 42) Liters/stroke = 0.000002356 x D2 x L
D = inches L = inches
D = mm L = mm
For meters3/stroke, divide liters per stroke by 1000
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12.6.2.2 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 Table 18: Determining Duplex Pump Output
Formula
Units
Bbls/stroke = 0.000162 x ( 2 x D2 − d2 ) x L
D = pump liner diameter (inches) L = stroke length (inches) d = rod diameter (inches)
Gals /stroke = 0.0068 x (2 x D2 − d2 ) x L
D = inches L = inches d = inches
Liters/stroke = 0.0515 x (D2 − d2 / 2) x L
D = inches L = inches d = inches
2 x( D2 − d2 ) Liters/stroke = � � xL 636500
D = mm L = mm d = mm
For meters3/stroke, divide liters per stroke by 1000
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 to 97% efficiency. For example; a pump output of 0.0038 bbls / stroke at 95% efficiency:
Pump output = 0.0038 x 12.6.3 Lag Calculations
95 = 0.00361 bbls / stroke 100
Pump output per minute = 0.00361 x SPM
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).
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Total circulation time = downtime + lag time
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This information benefits several important applications: Table 19: Benefits of Lag Calculations
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.
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 is pumped down into the casing, the precise number of strokes required to displace that cement must 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 = Lag strokes =
drillstring capacity pump output (per stroke)
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 =
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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 well profile example in Figure 106, there are 3 separate annular sections (assuming that the drillpipe and heavyweight have the same outside diameter) and 3 separate drillstring sections. The calculation of annular and drillstring capacity is then based upon simple geometry, 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.
Figure 106: Example Well Profile for Lag Calculation
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Where: ID = hole diameter or inside diameter of casing, drillpipe. OD = outer diameter of drillpipe / collars. 12.6.3.1 Annular volume calculations in barrels
OD2 − ID 2 bbls = xL 1029.4
Diameter (D) in inches Length (L) in feet
OD2 − ID 2 bbls = xL 313.76
Diameter (D) in inches Length (L) in meters
12.6.3.2 Annular volume calculations in cubic meters
M3 =
OD2 − ID 2 xL 1973.5
Diameter (D) in inches Length (L) in feet
M3 =
OD2 − ID 2 xL 1273223
Diameter (D) in mm Length (L) in meters
M 3 = 0.785 (OD2 − ID2 ) x L
Diameter (D) in meters Length (L) in meters
The same formulae would be used for calculating the drillstring capacities; but here OD would represent the internal diameter of the pipe and ID would be equal to 0. 12.6.3.3 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 numbers 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, and dye. Before putting anything into the string that will be pumped into the hole, such lag checks should always be confirmed with the operator. Wellsite Procedures & Operations Manual
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12.6.3.4 Standard Conversions for Lag Calculations
1 inch = 25.4 mm
1 meter = 3.2808 ft
1 foot = 0.3048 m
1 m3 = 6.2897 bbls
1 m3 = 1000 liters
1 bbl = 42 US gallons
1 bbl = 159 liters
1 bbl = 0.1589 m3
1 US gallon = 3.7853 liters
1 liter = 0.264 US gallons
12.7 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 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 pump ef�iciency
The flowrate out of the hole is typically determined in the flowline, which connects the wellhead to the header box. Typically, the deflection of a paddle (Figure 107) located on top on the flowline, or the speed of a turbine, is used to determine the flowrate.
Figure 107: Flow Paddle
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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 0% flow. For a given constant pump rate, the mud 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 indicates fluid loss to fractures, lost circulation.
An increase in MFO indicates 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.
Figure 108: Ultrasonic Sensor and Delaval Float Sensor
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 mud logger must be 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. Delaval sensors 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.
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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 false alarms and to identify errors in mud movement which could result in surface leaks and environmental contamination, such as:
Additions of new base fluid (water, diesel, oil, and so on) 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 floating rigs.
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13 MUDLOGGING PROCEDURES 13.1 CUTTINGS DESCRIPTIONS After sample preparation, 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. The order of a full cuttings description should be: 1. Rock type and classification 2. Color (and / or luster) 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
13.1.1 Rock Type and Classification The following are examples of rock types:
Carbonate rocks such as limestone, dolomite and marl
Siliceous rocks such as siltstone, sandstone, sand and chert
Argillaceous rocks such as claystone, clay, shale and marl
Carbonaceous rocks such as coal, lignite, and anthracite.
If possible, textural classification should be included (such as, lithic, oolitic, grainstone, packstone, and so on).
13.1.2 Color This may describe the mass effect of all constituents or describe specifics such as grain or crystal color, cement color, and so on.
Proper color charts should be used so that all descriptions are consistent between different personnel.
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Qualifiers such as dark, light, medium, translucent and so on, should be used according to such charts.
Colors may also describe a specific pattern such as mottled, spotty, or banded.
Carbonaceous rock descriptions should also include the luster, which can be described as dull, earthy, shiny, vitreous, or sub-vitreous.
13.1.3 Texture 13.1.3.1 Carbonate Rocks This should include crystal size and shape, together with any other significant texture: Table 20: Crystal Sizes
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, and fibrous. Other textures include waxy, vitreous, amorphous, earthy, sucrosic, chalky, vuggy, and stylolitic. 13.1.3.2 Siliceous Rocks This should include grain size, shape according to sphericity or roundness, and the degree of sorting: Table 21: Grain Sizes
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
0.004 – 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
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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
Sorting compares the distribution of varying grains and includes all of the above textural comparisons. Descriptions include poor sorted, moderately well sorted, and well sorted. 13.1.3.3 Argillaceous Rocks Textures include the following:
Amorphous
Blocky
Sub-blocky
Fissile
Sub-fissile
Dispersive
Splintery
13.1.3.4 Carbonaceous Rocks Texture descriptions for carbonaceous rocks include fracture type or cleating:
Angular
Conchoidal
Sub-conchoidal
Uneven
Cleating
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13.1.4 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 composed of small grains or infill that is mechanically deposited between grains. The matrix may be argillaceous, calcareous, dolomitic, gypsiferous, kaolinitic, or silty. Carbonaceous rocks may also include argillaceous, bituminous, pyritic, sooty, sandy, silty, and waxy.
13.1.5 Hardness This describes the overall hardness of a rock, rather than the hardness of individual grains. Descriptions for hardness 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).
13.1.6 Fossils and Accessory Minerals Fossils may include algae, bryozoa, echinoids, foraminifera, ostracods, molluscs, sponges, coral, plant remains, or oolites. Accessories may include anhydrite, glauconite, pyrite, biotite, chert, feldspar, lignite, siderite, olivine, halite, gypsum, kaolinite, sulphur, argillaceous, calcareous, and siliceous.
13.1.7 Sedimentary Structures Generally, these would be difficult to identify in drilled cuttings, but may include laminations, microlaminations or bands.
13.1.8 Porosity This should include an estimation of the percentage porosity and the types of porosity present. 13.1.8.1 Siliceous rocks Porosity may include the following:
Intergranular—none (tight), poor, fair, good, and excellent.
Moldic—resulting from the leaching of soluble grains.
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Fracture.
13.1.8.2 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.
13.1.9 Chemical Tests 13.1.9.1 Hydrochloric Acid (HCl) - Effervescence A quick test can be made with dilute (10%) hydrochloric acid to distinguish between calcite and dolomite. 1. Separate the cuttings from the sample tray, placing it in a porcelain spot tray. 2. Add a few drops to the sample. 3. 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
13.1.9.2 Hydrochloric Acid (HCl) - Oil Reaction If oil is present, large bubbles form on a cutting when it is immersed in dilute HCl. 13.1.9.3 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 the following:
Nonswelling—No break up.
Hygroturgid—Random swelling.
Hygroclastic—Swelling into irregular pieces.
Hygrofissile—Swelling into flakes (flaking).
Cryptofissile—Swelling into flakes after adding dilute HCl.
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Swelling clays also tend to be soft and sticky (although oil-base and inhibitive mud systems prevent swelling) making sample washing very difficult. Dispersed clay often results in sample preparation making description also very difficult. 13.1.9.4 Sulfate Test To determine the presence of gypsum or anhydrite, perform the following: 1. Crush 2g of washed and dried sample, and place in a test tube. 2. Add 5ml of dilute 10% HCl. 3. Heat. 4. Filter off residue and place in clean test tube. 5. Add approximately 10 drops of barium chloride (BaCl2). If a white precipitate forms, then the sample is a sulfate, either gypsum or anhydrite. To distinguish between the two, it should first be noted that gypsum is not common in the subsurface; therefore, the sample is usually an anhydrite. Anhydrite is commonly associated with dolomite. To confirm the distinction, perform the following: 1. Heat the same residue until evaporation begins. 2. Leave for 15 minutes. If the sample is gypsum, fine fibrous crystals forms. 13.1.9.5 Chloride Test 1. Crush 2g of washed and dried sample, and place in test tube. 2. Heat in distilled water and filter off the residue. 3. Place the residue in a clean test tube. 4. Add 10 drops of silver nitrate (AgNO3). If a white precipitate forms, then chlorides are confirmed. 13.1.9.6 Alizarin Red Test This is another test to distinguish calcite and dolomite. This can simply be dropped on to cuttings samples. If calcite is present, it turns into a deep red; all other grains remain uncolored. 13.1.9.7 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 phenolphthalein (a pH indicator) after washing the sample. If cuttings turn into a bright purple, then they are cement.
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13.2 OIL SHOWS Evaluation of oil show in the cuttings includes the description of odor, staining, bleeding, fluorescence, leach tests, residues, and so on.
13.2.1 Odor The smell should be described in the range of faint and fair to strong since this normally distinguishes among condensates, light oils, and heavy oils.
13.2.2 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 typically results 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 tend to be a dark brown, while lighter oil stains tend to be light to colorless. Live, volatile oil smokes and smells when held in a flame. The flame typically turns blue. The amount of oil staining should be characterized in terms of none, rare, common, and abundant and so on, 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 and often opaque appearance, nodular or specked occurrence, and brittle appearance but plastic texture, may be indicative of residual oil deposits or a potential source rock. Either way, their appearance is important and should be noted.
13.2.3 Fluorescence When crude oils are exposed to ultra-violet light, aromatic molecules absorb the radiation and become 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. To evaluate the oil type and production potential, the fluorescence is assessed in terms of concentration, color, and intensity. However, there are limitations to this process making it 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 color perception of the mud logger. Many other materials fluoresce and these have to be eliminated by the mud logger and not mistaken as oil fluorescence.
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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 fall in the ultra-violet range of the spectrum and goes undetected by the conventional technique, adding further to the tests’ subjectivity.
Because of time constraints, complete testing is only done on a handful of cuttings. The main test is confined to what is visible on the surface of the cuttings and to what may be leached through a solvent cut. This test is not necessarily representative of the full amount of oil in the formation.
13.2.4 Sample Preparation The cuttings should be washed and immediately viewed. Volatile components are 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. Even some types of tissue paper used for drying may fluoresce, making the mud logger’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 has a high solubility for hydrocarbons that originate from the formation. Oil remains dissolved within the drilling fluid, unlike gases that are liberated either immediately or subsequently. This additional component adds to the fluorescence of the drilling fluid and 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 change, so it is crucial that regular samples be viewed 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.
13.2.5 Contaminants Many contaminant materials or minerals fluoresce in addition to hydrocarbons. The mud logger must 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 give no solvent cut.
Minerals—Carbonates typically show a yellow to brown fluorescence.
Anhydrite or gypsum—Give a grey blue fluorescence.
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Contaminants—Pipe dope (gold, bluish white depending on composition), diesel or base oil, mud
additives, some rubbers, and plastics. 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 perform its functions.
13.2.6 Color and Brightness Color 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. For example, if a bright bluish fluorescence is observed through a reservoir section and exhibits a duller intensity, it is likely that the well has passed through the oil / water contact. In terms of fluorescence color, 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.
In relation to the API degree, typically observed fluorescence is listed in the following: Oil—Bright fluorescence, colors ranging with API gravity.
o
Very low gravity—Red brown, low intensity, and typically not visible.
o
Low API gravity—Red brown to orange brown and low intensity.
o
Medium API gravity—Gold, green, and cream to yellow.
o
High API gravity—Blue white and blue. Condensate—Bright, violet fluorescence, often speckled, and violet. Often not visible since fluorescence is completely in the ultra-violet.
13.2.7 Fluorescence Distribution An estimation of the percentage of florescence is 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, and so on. Wellsite Procedures & Operations Manual
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The mud logger should estimate the percentage of reservoir cuttings alone that exhibit fluorescence as well as the percentage of cuttings fluorescing in the complete sample. 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, better news than the reported 10%. 13.2.7.1 Solvent Cut Solvents, such as dichloroethane, 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. Heavier, viscous oil will move more slowly. o
Instant cut—High gravity oils
o
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, and 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 discolored solvent (from the oil) spreading from the cutting. o
Uniform blooming—Good permeability and oil mobility
o
Streaming—Low mobility due to limited permeability and / or high viscosity
If no cut is 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 all the oil contained in the cutting is ensured to be seen. The crush cut should then be described in the same way as the solvent cut. If a wet sample is used, perform the following: 1. Use a solvent / alcohol combination in case of water obstructing the solvent. Page 238 of 278
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2. Repeat using a dry sample. 3. Add hydrochloric acid. 13.2.7.2 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 is 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. 13.2.7.3 Sampling the Mud The reason for and benefits of continually checking the fluorescence given by oil-based muds has been discussed in Section 13.2.4. The drilling fluid, having high mutual solubility for other oils, retains oil released from a reservoir rock, and therefore leads to additional and changing fluorescence. Non oil-based muds should be checked for any oil that is released from the cuttings by the normal liberated mechanism. In this case, the reservoir oil does not dissolve in the mud but remains separate so 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 color and fluorescence.
13.2.8 Quantitative Fluorescence Technique™ (QFT) QFT 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. QFT reduces or eliminates potential errors inherent in the conventional fluorescence process:
The error that can result from subjective descriptions.
The fact that much of the fluorescence resulting from hydrocarbons falls outside of the electromagnetic 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.
QFT 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. Wellsite Procedures & Operations Manual
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The procedure is as follows: 1. Grind a washed and air-dried sample of drilled cuttings or core to a powder. 2. Do not dry at a high temperature since volatiles are lost. 3. Take a fixed quantity (whether by weight or by volume) and add an organic solvent, typically heptane, to extract any oil. 4. After mixing and agitating the sample mixture, filter off the solvent and any oil. 5. Place the solvent-oil mixture 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 typically those showing the highest measurement above background and therefore the main concentration of oil. However, this quantitative result is dependent 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 is generated from 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 must be aware of.
Since the fluorescence measurement is being related to a given volume of rock to determine oil concentration, it must 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 is retained by the cuttings? If the zone is 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) are 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. These can be identified through cuttings analysis and gas responses.
Mud contamination. Oil-based muds, although exhibiting low fluorescence in a clean condition, retains and recycles 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.
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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.
QFT is a measure of quantity but gives no information as to production potential.
13.3 CUTTINGS BULK DENSITY While drilling a well, bulk density measurements are made to determine the overburden gradient. Measurements can be made every 5 or 10m, or whatever the sample interval is. The more frequent the measurements, the more accurate the gradient is. A simple displacement technique can be used to determine bulk density, and, as long as the mud logger/data engineer is precise and consistent, the data quality is typically satisfactory for overburden calculations. The technique is described below: 1. Wash cuttings to remove drilling mud and towel dry to remove excess water. 2. Remove obvious cavings so that the sample selected is representative of the drilled interval. 3. Accurately weigh a sample of 1 or 2 grams, for example. Obviously, the larger the sample size, the smaller any error. 4. Fill a 10cc graduated cylinder with distilled water 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 (Figure 109).
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Figure 109: Measuring the Meniscus
5. Carefully drop the cuttings into the cylinder, being mindful of splashes and trapped bubbles. 6. 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. 7. Read the new level of the water, again being consistent with where on the meniscus you take the reading (Figure 110).
Figure 110: Measure Consistently on the Meniscus
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The formula for bulk density calculation is:
As an example:
𝐵𝑢𝑙𝑘 𝑑𝑒𝑛𝑠𝑖𝑡𝑦 (𝑆𝐺 𝑜𝑟 𝑔𝑚/𝑐𝑐) =
𝑤𝑒𝑖𝑔ℎ𝑡 𝑜𝑓 𝑠𝑎𝑚𝑝𝑙𝑒 (𝑔𝑚) 𝑣𝑜𝑙𝑢𝑚𝑒 𝑜𝑓 𝑑𝑖𝑠𝑝𝑙𝑎𝑐𝑒𝑑 𝑤𝑎𝑡𝑒𝑟 (𝑐𝑐)
If 2.00 gm of sample displaced 1.10 cc of distilled water:
Bulk density =
2.00 = 1.82 gm/cc 1.10
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.
13.4 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. 1. 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. 2. Glass beads of exact density mark this gradational change.
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3. A number of carefully selected shale cuttings are dropped into the column, and the depth at which they settle denotes their density. 4. To determine an average shale density value, a graph of density versus depth is used (for each shale cutting), as in Figure 111.
Figure 111: Density Column and Graph of Density vs. Depth
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:
Above all—user consistency.
Avoid flat cuttings because they float on the surface.
Avoid cuttings with obvious fractures / fissures because they contain air.
Select cuttings of equal size and shape, if possible.
Dry cuttings 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, read the depth at that point.
The 2 fluids in the column will slowly mix further over time, so re-plot the graph on a regular (daily) basis to ensure its accuracy.
Weatherford 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. To make the column, you will need: Page 244 of 278
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Sodium polytungstate (SPT) and distilled water.
Glass density beads, ranging from slightly heavier than the lighter water to slightly lighter than the SPT, for example. 1.2 to 2.8 g / cc. Glass or plastic graduated cylinder (250ml).
To setup the column: 1. Pour SPT up to the 125ml level. 2. Pour the distilled water on top, in small amounts so as not to over dilute the mixture. The supplier instructions are as follows o
Stir the center area of the cylinder until a mixed zone of 15-30ml is generated.
o
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.
o
Ten or 15 tilts should generate the mixed zone.
3. In practice, for shale density, a larger mixed zone must be generated, so this procedure can be repeated, with additional water if necessary, to produce the larger interval. 4. 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. 5. Seal the top of the cylinder (either a cap or plastic wrap) to minimize evaporation. 6. If the solution turns blue, it has come into contact with 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 its original color.
13.5 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 cation exchange capacity (CEC) is 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 normally decreases with depth as the amount of illite increases. Undercompacted clays in over-pressured 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 (Figure 112). Wellsite Procedures & Operations Manual
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Figure 112: Shale Factor
Conversely, the higher temperature in an over-pressured 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: 1. Select dry and representative shale cuttings. 2. Grind to a fine powder. 3. Weigh a 1/2 gram sample, add distilled water and a few drops of sulfuric acid. 4. Heat and stir. 5. Add methylene blue, drop by drop, from a pipette. 6. Take a drop of the mixture and place on filter paper. 7. The normal indication is if the water spreads and the blue remains centralized (Figure 113a). 8. When the blue spreads and a light blue aureole forms around it, record the volume of methylene blue added (Figure 113b). Whether this actual volume is taken as the recording, or some calculation from it, the volume of methylene blue required represents the changing CEC.
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Figure 113: Measuring CEC—a. Water Spreading From Sample, b. Test Complete
13.6 CALCIMETRY The procedure described in this section 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.
Figure 114: Auto Calcimeter Kit
Apparatus includes a reaction chamber 110V power cord, USB wireless PC keyboard and mouse, mortar, syringes, magnetic stirrer, and scale. Wellsite Procedures & Operations Manual
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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:
Figure 115: Calcimetry Result— Limestone vs. Dolomite Dissolve Time
13.7 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 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 the following:
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, and so on.
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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 becomes 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.
13.7.1 Consequences of Poor Stability or 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
13.7.2 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: Are all the cuttings being collected?
o
For a given shaker, does the vessel cover the entire length or just a portion?
o
If the vessel only covers a portion of the shaker, is the cuttings flow evenly distributed or concentrated at the edges, for example?
o
Is more than one shaker being used?
o
Is the same amount of flow occurring over all shakers?
o
Do the shakers have the same screen sizes?
o
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 its 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?
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Depending on how large the vessel is and how many cuttings are being produced from the wellbore, the vessel most likely fills up in less than an hour. The time difference is easily corrected. For example, if the vessel fills up in 15 minutes, multiply the volume by 4 to determine the equivalent volume per hour. However, some inaccuracies remain: o
The error caused by mud volume being included will be increased when extrapolated over an hour.
o
If the vessel does not collect ALL cuttings from ALL shakers, then errors in extrapolating to a total cuttings volume are again increased when extrapolated over an hour.
The final result is a semi-quantitative measurement, although not an exact one. However, the continuous measurement provides meaningful trends against which deviations can be evaluated in turns of hole condition and hole cleaning. Comparing against a theoretical cuttings volume is 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.
13.7.3 Volume of Vessel This must be known in terms of barrels, and it 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 liters, divide by 159 to give the equivalent in barrels. (1 liters = 0.2642 gallons)
For example, a 15-gallon drum would be equal to 0.3571 bbls.
13.7.4 Measurement of Cuttings / Hour This must 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 Page 250 of 278
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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
13.7.5 Correction to Total Volume The cuttings volume per hour will need to be corrected to determine the total cuttings volume coming over the shakers. This must 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 shaker sections (i.e. if the vessel covers a 1/3rd of the shaker width), and then record the volume coming over each section. 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. As an example, Figure 116 illustrates times taken fill the 15-gallon drum in the 3 positions across the shakers:
Figure 116: Cuttings Collected With Vessel in Three Positions
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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 For example, if 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
13.7.6 Theoretical Cuttings Volume This is simply the product of hole length x bit diameter, or the volume of the wellbore cylinder.
Where:
Volume of a cylinder = π r 2 x h
r = radius of cylinder h = length of cylinder
If volume units are bbls, then the following formula should be very helpful:
Where:
Volume (bbls) =
(bit diameter)2 x length of hole section 1029.46
bit diameter = inches hole length = feet
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Table 22 illustrates the calculated cuttings volume (BBLS / HR) that is generated from varying hole sizes at different ROPs. Table 22: Cuttings Volume with Varying Hole Sizes and Different ROPs
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
The cuttings volume being measured is lagged data, so this must 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 10:33 am – 10:42 am. 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
13.7.7 Actual / Theoretical Cuttings Volume Ratio As previously explained, the procedure results in a semi-quantitative measurement and a semiquantitative 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 represents a perfect relationship, but in reality this is unlikely because of the errors detailed above. Wellsite Procedures & Operations Manual
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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.
13.7.8 Recording, Evaluating and Reporting To be a useful parameter, the data must be recorded, calculated, and evaluated on a real-time basis. This means that when one measurement is made, such as the collecting vessel has filled, 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. Refer to the example provided in Figure 117. In addition to the information described, the following have also been included in the worksheet:
Flowrate—An increase in FR reduces the apparent volume of cuttings.
Mud Weight and Viscosity—These parameters affect cuttings lift and hole cleaning.
Lithology—A critical factor in cuttings removal and caving. The following information should be considered: o
Friable lithologies prone to instability.
o
Fractured lithologies prone to instability.
o
Abnormally pressured shales prone to caving.
o
Higher density lithologies, especially limestone, dolomite, and anhydrite etc, are more difficult to lift and prone to settling.
o
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 and large, blocky, fractured cavings, pressure or structural caving.
Cause and origin of cavings.
Other cavings—From loose, unconsolidated formations, structurally / orientation related.
Size of cuttings—Heavier to lift, prone to settling, coated with more mud.
A Comment / Observations column 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 loggers when evaluating the cuttings volume data: Page 254 of 278
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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 affected 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.
The effect of caving / sloughing should be monitored during reaming or back reaming, working stuck pipe.
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 ROPs.
13.7.8.1 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. For example, 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. 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. Use annotations to report change in operations or parameters. Wellsite Procedures & Operations Manual
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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, and so on.
Figure 117: Sample Monitoring Record Sheet
13.8 HIGH RESOLUTION TRIP MONITORING 13.8.1 Theory and Benefits This technique is 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 Page 256 of 278
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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). Therefore, 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.
13.8.2 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 must be tracking properly with the system going in and out of slips properly.
Mud weight must be correct, to allow for the buoyancy of the drill string.
Theoretical hookload must be correct.
13.8.2.1 Theoretical Hookload Attention must be paid to the theoretical hookload. In order to ensure that this is correct, it is necessary to ensure that the correct string ODs and IDs are in the equipment table. For example, 5” drillpipe 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” drillpipe actually weighs more than this when the tool joints are taken into account, for example 19.5 lb / ft G Class pipe actually weighs in the region of 21-22 lb / ft. 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. 13.8.2.2 System and Data Preparation Before the trip commences, the system must be specifically prepared to gather the data. Wellsite Procedures & Operations Manual
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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, to 15. DBtime must be shut down and restarted for the change to take effect (don’t forget to set it back to 60 seconds after the trip! When 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. When this is done the database must 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). Theoretical and actual hookloads vary during a trip in if it is performed with a closed end string and the string is not filled too often.
13.8.3 Interpretation When the plots have been created, it is relatively easy to identify hole sections that are problem free and those that require attention. 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 back reaming 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 back reaming on problem free formations.
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Figure 118: Trip Out Plot—Hookload vs. Depth
In Figure 118, 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. The problem section is illustrated in more detail in Figure 119; this reveals that the depths 1795m to 1755m and 1725m to 1690m required back reaming. There were also problems encountered at 1550m and 1525m. On the trip back in (Figure 120), 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.
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Figure 119: Trip Out Plot—Problem Section
Figure 120: Trip In Plot—Hookload vs. Depth
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13.8.4 Benefits to the Operator By monitoring the trip in this way, 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 back reaming and did not reoccur on the way in. This was typical of the well based on previous wiper trips. The monitoring of previous trips had 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.
13.9 DST PROCEDURES The Drill Stem Test (DST) has been an industry standard for many years, although it is only since the 1950s that the techniques and principles used today were originally developed. The main purpose of performing a DST tends to be similar for all wells when a zone of interest is identified after drilling. That is, to identify formation fluids (hydrocarbons, and so on.), 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. Variations in abbreviations for tools occur on different jobs. Care should be taken to find out what tool, does what and how it operates. The following is based upon the nomenclature used by Schlumberger Flowpetrol denoted by *. Wellsite Procedures & Operations Manual
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13.9.1 Water Cushion Before 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, this is 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 2675 m 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, such as brine).
13.9.2 Test String Components Figure 121 illustrates a typical Downhole Test String. From the bottom, the main components are as follows:
TCP Guns—These are the tubing conveyed perforating guns. The type in the example 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 (refer to Firing Head).
Safety Spacer—Simply a spacing joint between the guns and the firing head.
Firing Head—This is the point of impact for the bar, which is 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.
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
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way, such as nitrogen injection, or to allow a logging tool to pass out of the bottom of the DST string to log the perforated zone (for example, a flow spinner). This saves time by dispensing with a trip out of hole (tubing trips are usually slower than drillpipe 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.
Positrieve Packer—This tool isolates the section to be tested from the rest of the annulus. When in place, there is no communication between these two sections. The Positrieve packer is similar to a PosiTest* packer, the difference being that the Positrieve 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. Before 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 Positrieve 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 Positrieve 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.
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Rig: OILRIG
Section : DST STRING
Client : OILCO Field : COWS Well : WELL #1
Report No: DST#1 Date:
DOWNHOLE TEST STRING DIAGRAM
TOOL
DESCRIPTION
O.D. I.D. InchesInches
Flowhead
3.00
X-Over
6.50
2.25
2 7/8" EUE Tubing
2.88
2.44
X-Over
4.75
2.38
Full Open Slip Joint
5.00
2.25
3 1/2" Drill Pipe
15,5 #/ft 10 Stands
3.50
2.76
3 1/2" Drill Pipe
13,3 #/ft 8 Stands
3.50
2.76
Single Shot Reversing Valve (SHORT) Disc : P PAP: 3100 psi Radioactive Marker Sub
5.00
2.25
3 1/2" Drill Pipe
3.50
13,3 #/ft 1 Stand
5.00
Muli-Cycle Circulating Valve (MCCV)
5.00
3 1/2" Drill Pipe
3.50
13,3 #/ft 1 Stand
DGA-Datalatch
5.00
PCT with Hold Open Module (HOOP) PAP : 1600 psi
5.00
Hydrostatic Reference Tool (HRT)
5.00
Hydraulic Jar
5.00
Safety Joint
5.00
X-Over
5.00
Positreive Packer
5.92
2 7/8" EUE Tubing
2.88
Debris Sub
2.88
Gun Drop Sub TCR-B
2.88
2 7/8" EUE Tubing
2.88
Firing Head
2.88
BHF-C
Safety Spacer
4.50
TCP Guns
4.50
4 spf
PIP TAG DEPTH : 3264,42 m
THREADS
4 1/2" IF Pin 2 7/8" EUE Box 2 7/8" EUE Pin 3 1/2" IF Box 3 1/2" IF Pin 3 1/2" IF Box 3 1/2" IF Pin 3 1/2" IF Box 3 1/2" IF Pin 3 1/2" IF Box
3 1/2" IF Pin 2.44 3 1/2" IF Box / 3 1/2" IF Pin 3 1/2" IF Box 2.76 3 1/2" IF Pin 3 1/2" IF Box 2.25 3 1/2" IF Pin 3 1/2" IF Box 2.76 3 1/2" IF Pin 3 1/2" IF Box 2.25 3 1/2" IF Pin 3 1/2" IF Box 2.25 3 1/2" IF Pin 3 1/2" IF Box 2.25 3 1/2" IF Pin 3 1/2" IF Box 2.25 3 1/2" IF Pin 3 1/2" IF Box 2.25 3 1/2" IF Pin 2.25 2 7/8" EUE Box 2.44 2 7/8" EUE Pin 2 7/8" EUE Box 2.44 2 7/8" EUE Pin 2.44 2 7/8" EUE Box / Pin 2 7/8" EUE Box 2.44 2 7/8" EUE Pin 2 7/8" EUE Box 2.44 2 7/8" EUE Pin 2 7/8" EUE Box 2.44 2 3/8" Mod. Reg Pin 2 3/8" Mod. Reg Box N/A 2 3/8" Mod. Reg Pin 2 3/8" Mod. Reg Box N/A 2 3/8" Mod. Reg Pin
Fig 1
LENGTH METERS
0.68 2742.65 0.60 8.88 284.69 226.61 1.06 0.46 28.35 1.88 28.25 6.87 6.78 1.72 2.23 0.52 0.32 1.98 9.53 0.28 0.76 9.70 1.47 4.70 73.00
DEPTH TO BOTTOM METERS
0.00 0.68
2742.35 2742.95 2751.83 3036.52 3263.13 3264.19 3264.65 3293.00 3294.88 3323.13 3330.00 3336.78 3338.50 3340.74 3341.26 3341.58 3343.56 3353.09 3353.37 3354.13 3363.83 3365.30 3370.00 3443.00
(
Figure 121: Downhole Test String Diagram
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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. When 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 (HOOP)—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 and closed. After a pre-set number of cycles of 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 when 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.
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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 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. When 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), and so on. When the mandrel is midway in the tool, and aligned with neither flapper port, the tool is closed. Shutting off the pumps, for example, will not close the tool. The tool must be cycled round to the closed position.
Radioactive Marker Sub—This is used to correlate the depth of the test tools. When 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, 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. When 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.
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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.
13.9.3 Testing Procedures 1. When 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 until the difference is eliminated. 2. 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. 3. With the string set in the desired position and all 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). 4. When 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. 5. When 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 equalization manifests itself on surface as a blow. 6. 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. When the bubbles stop, then the pressure differential between the tubing and the formation should be zero. Wellsite Procedures & Operations Manual
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7. 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, bottomhole gauges should still be able to measure the formation fluid pressure during a shut in period. 8. Sometimes during a DST, no bubbles will be seen on surface. There are a number of possible reasons for this: o
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.
o
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. 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.
o
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). When 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, such as 100m. This depth is known as the bite. When a desired bite size is made, the slickline is pulled out of hole as fast as possible. When 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.
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The deeper the swabbing unit must 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. This section is only a basic guide to DSTs. 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.
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14 ABBREVIATIONS Word
Abbreviation
Word
Abbreviation
about
abt
become (-ing)
bcm
above
abv
bed
bd
absent
abs
bedded
bdd
abundant
abd, abnt
bedding
bdg
accumulation
accum
Belemnites
Belm, belm
acicular
acic
bioclastics
biocl
after
aft
bioherm (-al)
bioh
agglomerate
aglm
biomicrite
biomi
aggregate
agg
biosparite
biosp
algae, algal
Alg, alg
biostrom (-al)
biost
allochem
allo
biotite
biot
altered
alt
bioturbated
bioturb
alternating
altg
blade (-ed)
bld
amber
amb
blocky
blky
ammonite
amm
blue (-ish)
bl, blsh
amorphous
amor
bored (-ing)
bor
amount
amt
botryoid (-al)
bot
Amphipora
Amph
bottom
btm
and
&
boulder
bldr
andesite (-ic)
Andes, andes
boundstone
Bdst
angular
ang
brachiopod
Brach, brach
anhedral
anhed, ahd
brackish
brak
anhydrite (-ic)
anhy
branching
brhg
anthracite
Anthr
break
brk
aphanitic
aph
breccia (-ted)
brec
apparent
apr
bright
brt
appears
aprs, ap
brittle
brit
approximate
aprox, apprx
brown
brn
aragonite
arag
bryozoa
Bry, bry
arenaceous
aren
bubble
bubl
argillaceous
arg
buff
bu
argillite
argl
burrow (-ed)
bur
arkose (-ic)
Ark, ark
calcarenite
Clcar, clcar
as above
a/a
calcareous
calc
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Word
Abbreviation
Word
Abbreviation
asphalt (ic)
asph
calcilutite
Clclt, clclt
assemblage
assem
calcirudite
Clcrd, clcrd
associated
assoc
calcisiltite
Clslt, clslt
at
@
calcisphere
clcsp
authigenic
authg
calcite (-ic)
calctc, calc
average
av
caliche
cche
band
bnd
carbonaceous
carb
banded
bndd, bnd
carbonized
cb
barite
bar
cavern (-ous)
cav
basalt (-ic)
Bas, bas
caving
cvg
basement
bm, bsmt
cement (-ed, -ing)
cmt
cephalopod
Ceph, ceph
cross
x
chalcedony (-ic)
chal
cross-bedded
x-bd
chalk (-y)
Chk, chky
cross-laminated
x-lam
charophyte
Char, char
cross-stratified
x-strat
chert (-y)
Cht, cht
crumpled
crpld
chitin (-ous)
Chit, chit
cryptocrystalline
crpxln
chlorite (-ic)
Chlor, chlor
crystal (-line)
xl, xln
chocolate
choc
cube, cubic
cub
circulate (-ion)
circ
cuttings
ctgs
clastic
clas
dark (-er)
dk, dkr
clay (-ey)
Cl, cl
dead
dd
claystone
Clst
debris
deb
clean
cln
decrease (-ing)
decr
clear
clr
dense
dns
cleavage
clvg
depauperate
depau
cluster
clus
description
descr
coal
c
detrital
detr
coarse
crs
devitrified
devit
coated (-ing)
cotd, cotg
diabase
Db, db
coated grains
cotd gn
diagenesis (-etic)
diagn
cobble
cbl
diameter
dia
color (-ed)
col
disseminated
dissem
common
com
distillate
dist
compact
cpct
dolomite (-ic)
Dol, dol
compare
cf
dominant (-ly)
dom
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Word
Abbreviation
Word
Abbreviation
concentric
cncn
drill stem test
DST
conchoidal
conch
drilling
drlg
concretion (-ary)
conc
drusy
dru
conglomerate (-ic)
Cgl, cgl
earthy
ea
conodont
Cono
east
E
considerable
cons
echinoid
Ech, ech
consolidated
consol
elevation
elev
conspicuous
conspic
elongate
elong
contact
ctc
embedded
embd
contamination (-ed)
contam
equant
eqnt
content
cont
equivalent
equiv
contorted
cntrt
euhedral
euhd
coquina (-oid)
Coq, coqid
euxinic
eux
coral, coralline
Cor, corln
evaporite (-itic)
Evap, evap
core
c, ¢
excellent
ex
covered
cov
exposed
exp
cream
crm
extraclast (-ic)
exclas
crenulated
cren
extremely
extr
crinkled
crnk
extrusive
Exv, exv
crinoid (-al)
Crin, crinal
facet
fac
faint
fnt
granite
Grt
fair
fr
granite wash
G.W.
fault (-ed)
flt
granule (-ar)
gran
fauna
fau
grapestone
grapst
feet, foot
ft
graptolite
Grap, grap
feldspar (-athic)
fspar
gravel
grv
fenestra (-al)
fen
gray, grey (-ish)
gry, grysh
ferruginous
ferr
graywacke
Gwke, gwke
fibrous
fibr
greasy
gsy
fine (-ly)
f, fnly
green (-ish)
gn, gnsh
fissile
fis
grit (-ty)
gt
flaggy
flg
gypsum (-iferous)
gyp
flake, flaky
flk
hackly
hkl
flat
fl
halite (-iferous)
Hal, hal
floating
fltg
hard
hd
flora
flo
heavy
hvy
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Word
Abbreviation
Word
Abbreviation
fluorescence (-ent)
fluor
hematite (-ic)
hem
foliated
fol
heterogeneous
hetr
foraminifer (-al)
Foram, foram
Heterostegina
Het, het
formation
fm
high (-ly)
hi
fossil (-iferous)
foss
homogeneous
hom
fracture (-d)
frac
horizontal
hor
fragment (-al)
frag
hydrocarbon
hydc
frequent
freq
igneous rock (igneous)
Ig
fresh
frs
impression
imp
friable
fri
in part
I.P.
fringe (-ing)
frg
inch
in
frosted
fros
inclusion (-ded)
incl
fucoid (-al)
fuc
increasing
incr
fusulinid
Fus, fus
indistinct
indst
gabbro
Gab, gab
indurated
ind
gas
g
Inocreamus
Inoc
gastropod
Gast, gast
insoluble
insl
generally
gen
interbedded
intbd
geopetal
gept
intercalated
intercal
gilsonite
gil
intercrystalline
intxln
glass (-y)
glas
intergranular
intgran
glauconite (-itic)
glauc, glau
intergrown
intgn
Globigerina (-inal)
Glob, glob
interlaminated
intlam
gloss (-y)
Glos, glos
interparticle
intpar
gneiss (-ic)
Gns, gns
intersticies (-itial)
inst
good
gd
interval
intvl
grading
grad, grd
intraclast (-ic)
intclas
grain (-s, -ed)
gr
intraparticle
intrapar
grainstone
Grst
intrusive rock, intrusive
intr
invertebrate
invtb
member
mbr
iridescent
irid
meniscus
men
ironstone
Fe-st
metamorphic (-osed)
meta
irregular (-ly)
irr
mica (-ceous)
mic
isopachous
iso
micrite (-ic)
Micr, micr
jasper
jasp
microcrystalline
microxln
joint (-ed, -ing)
jt
microfossil (ferous)
microfos
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Word
Abbreviation
Word
Abbreviation
kaolin (-itic)
kao
micrograined
micgr
lacustrine
lac
micro-oolite
microol
lamina (-tions),(-ated)
lam
micropore,(-osity)
micropor
large
lge
microspar
microspr
laterite (-itic)
lat
microstylolite
microstyl
lavender
lav
middle
Mid
layer
lyr
miliolid
Milid, milid
leached
lchd
milky
mky
lens
len
mineral (-ized)
min
light
lt
minor
mnr
lignite (-itic)
Lig, lig
moderate
mod
limestone
Ls
mold (-ic)
mol
limonite (-itic)
lim
mollusc
Moll, moll
limy
lmy
mosaic
mos
lithic
lit
mottled
mott
lithographic
lithgr
mud (-dy)
md, mdy
lithology (-ic)
lith
mudstone
Mdst
little
ltl
muscovite
musc
littoral
litt
nacreous
nac
local
loc
no sample
n.s.
long
lg
no show
n/s
loose
lse
nodules (-ar)
nod
lower
l
north
N
lustre
lstr
novaculite
Novac, novac
lutite
lut
numerous
num
macrofossil
macrofos
occasional
occ
magnetite, magnetic
mag
ochre
och
manganese (-iferous)
mn
odor
od
marble
Mbl, mbl
oil
o, O
marine
marn
olive
olv
marl (-y)
Mrl, mrl
olivine
olvn
marlstone
Mrlst
oncolite (-oidal)
Onc, onc
maroon
mar
ooid (-al)
oo
massive
mass
oolicast (-ic)
ooc
material
mat
oolite (-itic)
ool
matrix
mtrx
oomold (-ic)
oomol
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Word
Abbreviation
Word
Abbreviation
maximum
max
opaque
op
medium
m, med
orange (-ish)
or, orsh
Orbitolina
Orbit, orbit
predominant (-ly)
pred
organic
org
preserved
pres
orthoclase
orth
primary
prim
orthoquartzite
o-qtz
probable (-ly)
prob
ostracod
Ostr, ostr
production
prod
overgrowth
ovgth
prominent
prom
oxidized
ox
pseudo-
ps
oyster
oyst
pseudo oolite (-ic)
psool
packstone
Pkst
pumice-stone
Pst
paper (-y)
pap
purple
purp
part (-ly)
pt
pyrite (-itized, -tic)
pyr
particle
par
pyrobitumen
pybit
parting
ptg
pyroclastic
pyrcl
parts per million
ppm
pyroxene
pyrxn
patch (-y)
pch
quartz (-ose)
qtz
pebble (-ly)
pbl
quartzite (-ic)
qtzt
pelecypod
Pelec, pelec
radial (-ating)
rad
pellet (-al)
pel
radiaxial
Radax
pelletoid (-al)
peld
range
rng
pendular (-ous)
pend
rare
r
pentamerus
pent
recemented
recem
permeability (-able)
k, perm
recovery (-ered)
rec
petroleum, petroliferous
pet
recrystallized
rexlzd
phlogopite
phlog
red (-ish)
rd, rdsh
phosphate (-atic)
phos
reef (-oid)
rf
phreatic
phr
remains
rem
phyllite, phyllitic
Phyl, phyl
renaicis
ren
pink
pk
replaced (-ment)
rep, repl
pinkish
pkish
residue (-ual)
res
pin-point (porosity)
p.p.
resinous
rsns
pisoid (-al)
piso
rhomb (-ic)
rhb
pisolite, pisolitic
pisol
ripple
rpl
pitted
pit
rock
rk
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Word
Abbreviation
Word
Abbreviation
plagioclase
plag
round (-ed)
rnd, rndd
plant
plt
rounded, frosted, pitted
r.f.p.
plastic
plas
rubble (-bly)
rbl
platy
plty
rudistid
rud
polish, polished
pol
saccharoidal
sacc
pollen
poln
salt (-y)
sa
polygonal
poly
salt and pepper
s&p
poor (-ly)
p
salt water
S.W.
porcelaneous
porcel
same as above
a.a.
porosity, porous
por
sample
spl
porphyry
prphy
sand (-y)
sd, sdy
possible (-ly)
poss
sandstone
Sst
saturation (-ated)
sat
stain, (-ed, -ing)
stn
scarce
scs
stalactitic
stal
scattered
scat
strata (-ified)
strat
schist (-ose)
Sch, sch
streak (-ed)
strk
scolecodont
Scol
streaming
stmg
secondary
sec
striated
stri
sediment (-ary)
sed
stringer
strgr
selenite
sel
stromatolite (-itic)
stromlt
shale (-ly)
Sh, sh
stromatoporoid
Strom
shell
shl
structure
str
shelter porosity
shlt por
styliolina
styl
show
shw
stylolite (-itic)
styl
siderite (-itic)
sid
sub
sb
sidewall core
S.W.C.
subangular
sbang
silica (-iceous)
sil
sublithic
sblit
silky
slky
subrounded
sbrndd
silt (-y)
slt
sucrosic
suc
siltstone
Sltst
sugary
sug
similar
sim
sulphur, sulphurous
Su, su
size
sz
superficial oolite (-ic)
spfool
skeletal
skel
surface
surf
slabby
slb
syntaxial
syn
slate (-y)
Sl, sl
syringopora
syring
slickenside (-d)
slick
tabular (-ate)
tab
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Word
Abbreviation
Word
Abbreviation
slight (-ly)
sli
tan
tn
small
sml
tension
tns
smooth
sm
tentaculites
tent
soft
sft
terriginous
ter
solenpore
solen
texture (-d)
tex
solitary
sol
thamnopora
tham
solution, soluble
sol
thick
thk
somewhat
smwt
thin
thn
sorted (-ing)
srt, srtg
thin section
T.S.
south
S
thin-bedded
t.b.
spar (-ry)
spr
throughout
thru
sparse (-ly)
sps, spsly
tight
ti
speck (-led)
spkld
top
tp
sphaerocodium
sphaer
tough
tgh
sphalerite
sphal
trace
tr
spherule (-itic)
spher
translucent
trnsl
spicule (-ar)
spic
transparent
trnsp
splintery
splin
trilobite
Tril
sponge
spg
tripoli (-itic)
trip
spore
spo
tube (-ular)
tub
spotted (-y)
sptd, spty
tuff (-aceous)
Tf, tf
type (-ical)
typ
vug (-gy)
vug
unconformity
unconf
wackestone
Wkst
unconsolidated
uncons
washed residue
w.r.
underlying
undly
water
wtr
uniform
uni
wavy
wvy
upper
U, u
waxy
wxy
vadose
vad
weak
wk
variation (able)
var
weathered
wthd
varicolored
varic
well
wl
variegated
vgt
west
W
varved
vrvd
white
wh
vein (-ing, -ed)
vn
with
w/
veinlet
vnlet
without
w/o
vermillon
verm
wood
wd
vertebrate
vrtb
yellow (ish)
yel, yelsh
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Word
Abbreviation
Word
Abbreviation
vertical
vert
zeolite
zeo
very
v
zircon
zr
very poor sample
v.p.s.
zone
zn
vesicular
ves
violet
vi
visible
vis
vitreous (-ified)
vit
volatile
volat
volcanic rock, volcanic volc
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