drillnet 1.7 user's manual

DrillNET Drilling Engineering Integrated Analysis Package

Version 1.7.5

User’s Manual Rev. 0

© 2006-2010 Petris Technology, Inc. PetrisWINDS is a registered trademark of Petris Technology, Inc.

Portions of this software are covered under US Patent No. 6,792,431. Other patents pending.

ii DrillNET 1.7.5 User's Manual, r 0 Copyright © 2006-2010 Petris Technology, Inc.

Petris Technology, Inc.

Main Website: www.petris.com Visit the websites below for more

information regarding product sales and technical support.

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Copyrights Copyright ©2006-2010 by Petris Technology, Inc. All rights reserved. The contents of this document and of the software it describes are the property of Petris Technology, Inc., and are copyrighted. No part of this document may be copied, distributed, transmitted, transcribed, stored in a retrieval system, disclosed to third parties, or translated into any language, in any form, or by any means, electronic, magnetic, manual, or otherwise, without the express written consent of Petris Technology, Inc.

Printed in the United States of America

First printing May 2010,

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PetrisWINDS is a trademark of Petris Technology, Inc., in the United States and other countries. Other parties’ trademarks or service marks are the property of their respective owners, and should be treated as such.

Disclaimer

Instructions and descriptions contained in this document are accurate as of the document’s first printing. Succeeding products and documents are subject to change without notice. Petris Technology, Inc., assumes no liability for damages incurred directly or indirectly from errors or omissions in this document, or from discrepancies between the product and this document. Any parameters that the customer uses beyond those indicated in this document may have unpredictable results.

Documentation

Lee Chu Greg Deskins Alastair Doyle David Jones Chuan Luo Samantha Royder

Last Revision

August 2, 2010

1. CONTENTS

DrillNET 1.7.5 User's Manual, r 0 iii

Copyright © 2006-2010 Petris Technology, Inc.

1. Introduction ............................................................................................................................. 1 1.1 What is DrillNET? ..................................................................................................................................... 1

1.2 Features of DrillNET ................................................................................................................................. 2

1.3 Engineering Models ................................................................................................................................... 2

2. Getting Started ........................................................................................................................ 5 2.1 Installing the Program .............................................................................................................................. 5

2.2 Removing the Program ............................................................................................................................. 5

2.3 Starting the Program ................................................................................................................................. 5

3. Basic Program Operation ....................................................................................................... 7 3.1 Layout of DrillNET’s Main Window ....................................................................................................... 7

3.2 Common Input Pages ................................................................................................................................ 9 3.2.1 Typical Project Page .................................................................................................................. 10 3.2.2 Typical Survey Page .................................................................................................................. 10 3.2.3 Typical Tubulars Page ............................................................................................................... 16 3.2.4 Typical Wellbore Page .............................................................................................................. 19 3.2.5 Typical Formation Page ............................................................................................................. 20

3.3 Typical Output Page ................................................................................................................................ 22 3.3.1 Graphs/Tables Window ............................................................................................................. 23

3.4 Menus ........................................................................................................................................................ 24 3.4.1 File Menu ................................................................................................................................... 24 3.4.2 Edit Menu (Tables) .................................................................................................................... 26 3.4.3 Edit Menu (Graphs) ................................................................................................................... 26 3.4.4 View Menu ................................................................................................................................ 27 3.4.5 Models Menu ............................................................................................................................. 29 3.4.6 Tools Menu ................................................................................................................................ 29 3.4.7 Options Menu ............................................................................................................................ 29 3.4.8 Help Menu ................................................................................................................................. 30

4. DrillNET Engineering Models ............................................................................................. 31

5. Pore Pressure Prediction Model .......................................................................................... 35 5.1 Input .......................................................................................................................................................... 35

5.1.1 General Page .............................................................................................................................. 35

5.2 Output ....................................................................................................................................................... 40

6. Wellbore Stability Model ..................................................................................................... 43 6.1 Input .......................................................................................................................................................... 43

6.1.1 Project Page ............................................................................................................................... 43 6.1.2 Survey Page ............................................................................................................................... 43 6.1.3 Formation Page .......................................................................................................................... 43 6.1.4 General Page .............................................................................................................................. 46

6.2 Output ....................................................................................................................................................... 49

6.3 Special Functions ..................................................................................................................................... 50 6.3.1 Tool-Bar Icons ........................................................................................................................... 50 6.3.2 Sensitivity Analysis Window..................................................................................................... 50 6.3.3 Single-Depth Analysis Window ................................................................................................ 52

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7. Well Planning/Projection Model ......................................................................................... 55 7.1 Input .......................................................................................................................................................... 55

7.1.1 Project Data Window ................................................................................................................. 55 7.1.2 Application Window .................................................................................................................. 58

7.2 Output/Special Functions ........................................................................................................................ 62 7.2.1 Tool-Bar Icons ........................................................................................................................... 62 7.2.2 3D Path View Window .............................................................................................................. 62 7.2.3 Well Path Design Wizard .......................................................................................................... 64 7.2.4 Special Applications Window ................................................................................................... 65 7.2.5 Parameter Estimate Utility Window .......................................................................................... 68 7.2.6 Truncate Design Results Window ............................................................................................. 70 7.2.7 Edit Complete Survey Window ................................................................................................. 71

8. Anti-Collision Analysis Model ............................................................................................. 73 8.1 Input .......................................................................................................................................................... 73

8.1.1 Project Page ............................................................................................................................... 73 8.1.2 Trajectories Page ....................................................................................................................... 73

8.2 Output ....................................................................................................................................................... 75 8.2.1 Traveling Cylinder Plot Window ............................................................................................... 75 8.2.2 Spider Plot Window ................................................................................................................... 76 8.2.3 3D Closeness Plot Window ....................................................................................................... 76 8.2.4 Well Collision Check Window .................................................................................................. 77 8.2.5 Proximity Analysis Window ...................................................................................................... 79

8.3 Special Functions ..................................................................................................................................... 81 8.3.1 Tool-Bar Icons ........................................................................................................................... 81 8.3.2 My Survey Tools Database Window ......................................................................................... 81

9. Casing Stress Check Model .................................................................................................. 83 9.1 Input .......................................................................................................................................................... 83

9.1.1 Project Page ............................................................................................................................... 83 9.1.2 Survey Page ............................................................................................................................... 83 9.1.3 Formation Page .......................................................................................................................... 83 9.1.4 Muds Page ................................................................................................................................. 84 9.1.5 Casing String Page ..................................................................................................................... 85

9.2 Output ....................................................................................................................................................... 92 9.2.1 Output for Margin Analysis ....................................................................................................... 92 9.2.2 Output for Casing Verification .................................................................................................. 93

9.3 Special Functions ..................................................................................................................................... 94 9.3.1 Preferences Window .................................................................................................................. 94 9.3.2 Shoe Advisor Window ............................................................................................................. 103

10. Wellbore Cementing Model ............................................................................................... 105 10.1 Input ........................................................................................................................................................ 105

10.1.1 Project Page ............................................................................................................................. 105 10.1.2 Survey Page ............................................................................................................................. 105 10.1.3 Tubulars Page .......................................................................................................................... 105 10.1.4 Wellbore Page .......................................................................................................................... 105 10.1.5 Formation Page ........................................................................................................................ 105 10.1.6 Fluids Page .............................................................................................................................. 106 10.1.7 Operation Page ........................................................................................................................ 108

10.2 Output ..................................................................................................................................................... 109

10.3 Special Functions ................................................................................................................................... 110

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10.3.1 Tool-Bar Icons ......................................................................................................................... 110 10.3.2 Cementing Utilities .................................................................................................................. 110 10.3.3 Fann Viscometer Calculator .................................................................................................... 112 10.3.4 Rheological Parameter Estimator ............................................................................................ 113 10.3.5 Animation Window ................................................................................................................. 113

11. Casing Wear Model ............................................................................................................ 117 11.1 Input ........................................................................................................................................................ 117

11.1.1 Project Page ............................................................................................................................. 117 11.1.2 Survey Page ............................................................................................................................. 117 11.1.3 Wellbore Page .......................................................................................................................... 117 11.1.4 Operation Page ........................................................................................................................ 118 11.1.5 Wear Factor Page ..................................................................................................................... 120 11.1.6 Preferences Page ...................................................................................................................... 122

11.2 Output ..................................................................................................................................................... 123

11.3 Special Functions ................................................................................................................................... 124 11.3.1 Tool-Bar Icons ......................................................................................................................... 124 11.3.2 Wear Factor Expert System ..................................................................................................... 124 11.3.3 Wear Factor Database .............................................................................................................. 124 11.3.4 Field Wear Match Window ..................................................................................................... 125 11.3.5 Casing Wear Schematic Window ............................................................................................ 126 11.3.6 Riser Strength Analysis Window ............................................................................................. 127

12. Centralizer Design Model................................................................................................... 129 12.1 Input ........................................................................................................................................................ 129

12.1.1 Project Page ............................................................................................................................. 129 12.1.2 Survey Page ............................................................................................................................. 129 12.1.3 Tubulars Page .......................................................................................................................... 129 12.1.4 Wellbore Page .......................................................................................................................... 129 12.1.5 Operation Page ........................................................................................................................ 131

12.2 Output ..................................................................................................................................................... 133

12.3 Sensitivity Analysis Window ................................................................................................................. 137

13. Torque & Drag for Liner Cementing Model .................................................................... 138 13.1 Input ........................................................................................................................................................ 138

13.1.1 Project Page ............................................................................................................................. 138 13.1.2 Survey Page ............................................................................................................................. 138 13.1.3 Tubulars Page .......................................................................................................................... 138 13.1.4 Wellbore Page .......................................................................................................................... 138 13.1.5 Operation Page ........................................................................................................................ 139

13.2 Output ..................................................................................................................................................... 140 13.2.1 Sensitivity Analysis Window................................................................................................... 142 13.2.2 Animation Window ................................................................................................................. 144 13.2.3 Utilities .................................................................................................................................... 145

14. Torque & Drag for Drillstring Model ............................................................................... 147 14.1 Input ........................................................................................................................................................ 147

14.1.1 Project Page ............................................................................................................................. 147 14.1.2 Survey Page ............................................................................................................................. 147 14.1.3 Tubulars Page .......................................................................................................................... 147 14.1.4 Wellbore Page .......................................................................................................................... 147 14.1.5 Parameters Page ....................................................................................................................... 148

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14.1.6 Preferences Page ...................................................................................................................... 149

14.2 Special Functions ................................................................................................................................... 152 14.2.1 Tool-Bar Icons ......................................................................................................................... 152 14.2.2 Sensitivity Analysis Window................................................................................................... 152 14.2.3 Margin Analysis Window ........................................................................................................ 154 14.2.4 Buckling Analysis Window ..................................................................................................... 155 14.2.5 Sheave Analysis Window ........................................................................................................ 156

15. Drill-String Life Model ....................................................................................................... 159 15.1 Input ........................................................................................................................................................ 159

15.1.1 Project Page ............................................................................................................................. 159 15.1.2 Survey Page ............................................................................................................................. 159 15.1.3 Tubulars Page .......................................................................................................................... 159 15.1.4 Wellbore Page .......................................................................................................................... 159 15.1.5 Operation Page ........................................................................................................................ 160 15.1.6 Preferences Page ...................................................................................................................... 161

15.2 Output ..................................................................................................................................................... 162

15.3 Special Functions ................................................................................................................................... 163 15.3.1 Tool-Bar Icons ......................................................................................................................... 163 15.3.2 Single-Span Drill String Fatigue Analysis ............................................................................... 163 15.3.3 Crack-Growth Analysis ........................................................................................................... 164

16. Triaxial Stresses Model ...................................................................................................... 167 16.1 Input ........................................................................................................................................................ 167

16.1.1 Project Page ............................................................................................................................. 167 16.1.2 Survey Page ............................................................................................................................. 167 16.1.3 Tubulars Page .......................................................................................................................... 167 16.1.4 Loads Page ............................................................................................................................... 167

16.2 Output ..................................................................................................................................................... 168

16.3 Special Functions ................................................................................................................................... 169 16.3.1 Tool-Bar Icons ......................................................................................................................... 169 16.3.2 Single Point Stress Analysis Window ..................................................................................... 169 16.3.3 Drill String Stress Analysis Window ....................................................................................... 172

17. Hydraulics for Normal Circulation Model ....................................................................... 175 17.1 Input ........................................................................................................................................................ 175

17.1.1 Project Page ............................................................................................................................. 175 17.1.2 Survey Page ............................................................................................................................. 175 17.1.3 Tubulars Page .......................................................................................................................... 175 17.1.4 Wellbore Page .......................................................................................................................... 175 17.1.5 Formation Page ........................................................................................................................ 175 17.1.6 Fluid Page ................................................................................................................................ 176 17.1.7 Drilling Page ............................................................................................................................ 178

17.2 Output ..................................................................................................................................................... 179 17.2.1 Hydraulics Graphs ................................................................................................................... 180

17.3 Special Functions ................................................................................................................................... 183 17.3.1 Tool-Bar Icons ......................................................................................................................... 183 17.3.2 Estimate Flow Exponent Utility .............................................................................................. 184 17.3.3 Sensitivity Window ................................................................................................................. 185

18. Hydraulics for Surge/Swab Model .................................................................................... 187 18.1 Input ........................................................................................................................................................ 187

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18.1.1 Project Page ............................................................................................................................. 187 18.1.2 Survey Page ............................................................................................................................. 187 18.1.3 Tubulars Page .......................................................................................................................... 187 18.1.4 Wellbore Page .......................................................................................................................... 187 18.1.5 Formation Page ........................................................................................................................ 187 18.1.6 Parameters Page ....................................................................................................................... 188

18.2 Output ..................................................................................................................................................... 189

18.3 Special Functions ................................................................................................................................... 190 18.3.1 Tool-Bar Icons ......................................................................................................................... 190 18.3.2 Sensitivity Window ................................................................................................................. 190

19. Hydraulics for Underbalanced Drilling ............................................................................ 193 19.1 Background ............................................................................................................................................ 193

19.2 New Features of DrillNET .................................................................................................................... 193

19.3 General Features .................................................................................................................................... 194

19.4 Input ........................................................................................................................................................ 194 19.4.1 Project Page ............................................................................................................................. 194 19.4.2 Survey Page ............................................................................................................................. 195 19.4.3 Tubulars Page .......................................................................................................................... 195 19.4.4 Wellbore Page .......................................................................................................................... 195 19.4.5 Formation Page ........................................................................................................................ 195 19.4.6 Influx/Parasite String ............................................................................................................... 195 19.4.7 Drilling Page ............................................................................................................................ 196 19.4.8 Fluid Page ................................................................................................................................ 198

19.5 Output ..................................................................................................................................................... 201

20. Hydraulics for HTHP Wells ............................................................................................... 207 20.1 Input ........................................................................................................................................................ 207

20.1.1 Project Page ............................................................................................................................. 207 20.1.2 Survey Page ............................................................................................................................. 207 20.1.3 Tubulars Page .......................................................................................................................... 207 20.1.4 Wellbore Page .......................................................................................................................... 207 20.1.5 Formation Page ........................................................................................................................ 208 20.1.6 Drilling/Thermal Page ............................................................................................................. 208 20.1.7 Fluid Page ................................................................................................................................ 209

20.2 Output ..................................................................................................................................................... 214

20.3 Special Functions ................................................................................................................................... 219 20.3.1 Tool-Bar Icon .......................................................................................................................... 219

21. Dynamic Kill for Slim Holes Model .................................................................................. 221 21.1 Input ........................................................................................................................................................ 221

21.1.1 Project Page ............................................................................................................................. 221 21.1.2 Survey Page ............................................................................................................................. 221 21.1.3 Tubulars Page .......................................................................................................................... 221 21.1.4 Wellbore Page .......................................................................................................................... 221 21.1.5 Formation Page ........................................................................................................................ 221 21.1.6 Parameters Page ....................................................................................................................... 222

21.2 Output ..................................................................................................................................................... 223 21.2.1 Single Curve Kill Chart ........................................................................................................... 223 21.2.2 Multiple Curve Kill Chart ........................................................................................................ 225

21.3 Special Functions ................................................................................................................................... 226

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21.3.1 Tool-Bar Icons ......................................................................................................................... 226

22. Wellbore Thermal Simulation Model ............................................................................... 227 22.1 Input ........................................................................................................................................................ 227

22.1.1 Project Page ............................................................................................................................. 227 22.1.2 Survey Page ............................................................................................................................. 227 22.1.3 Tubulars Page .......................................................................................................................... 227 22.1.4 Wellbore Page .......................................................................................................................... 227 22.1.5 Formation Page ........................................................................................................................ 227 22.1.6 Parameters Page ....................................................................................................................... 230 22.1.7 Schedule Page .......................................................................................................................... 232 22.1.8 Casing Page ............................................................................................................................. 233

22.2 Output ..................................................................................................................................................... 234 22.2.1 Thermal Analysis Window ...................................................................................................... 236

23. Killsheet Application Model............................................................................................... 239 23.1 Options Pane .......................................................................................................................................... 239

23.2 Input/Output .......................................................................................................................................... 242 23.2.1 Pre-Recorded Info Page ........................................................................................................... 242 23.2.2 Survey Page ............................................................................................................................. 242 23.2.3 Capacities Page ........................................................................................................................ 243 23.2.4 Kick/Kill Page ......................................................................................................................... 244 23.2.5 Worksheet Page ....................................................................................................................... 245

23.3 Special Functions ................................................................................................................................... 246 23.3.1 Tool-Bar Icons ......................................................................................................................... 246 23.3.2 Worksheet Report .................................................................................................................... 246

24. Kick Simulation Model ....................................................................................................... 249 24.1 Input ........................................................................................................................................................ 249

24.1.1 Project Page ............................................................................................................................. 249 24.1.2 Survey Page ............................................................................................................................. 249 24.1.3 Tubulars Page .......................................................................................................................... 249 24.1.4 Wellbore Page .......................................................................................................................... 249 24.1.5 Formation Page ........................................................................................................................ 249 24.1.6 Operation Page ........................................................................................................................ 250 24.1.7 Parameters Page ....................................................................................................................... 253

24.2 Output ..................................................................................................................................................... 254

24.3 Special Functions ................................................................................................................................... 254 24.3.1 Calculation Monitor Panel ....................................................................................................... 254 24.3.2 Tool-Bar Icons ......................................................................................................................... 255 24.3.3 Animation Window ................................................................................................................. 255 24.3.4 Sensitivity Analysis Window................................................................................................... 256

25. User Databases .................................................................................................................... 257 25.1 Galaxy Database .................................................................................................................................... 257

25.1.1 Benefits .................................................................................................................................... 257 25.1.2 Local or Central Galaxy Database ........................................................................................... 257 25.1.3 Managing Galaxy .................................................................................................................... 262 25.1.4 Importing Data from Earlier Versions of Galaxy .................................................................... 264

25.2 Tubular Database .................................................................................................................................. 264

25.3 My Fluids ................................................................................................................................................ 266

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25.4 My BHAs ................................................................................................................................................ 268

25.5 My S-N Curves ....................................................................................................................................... 270

25.6 My Survey Tools .................................................................................................................................... 271

26. Utilities and Program Settings ........................................................................................... 275 26.1 DrillNET’s Free Utilities ....................................................................................................................... 275

26.1.1 Running a Utility ..................................................................................................................... 275 26.1.2 Example Free Utility – Pipe Buckling ..................................................................................... 275 26.1.3 Example Free Utility – Build Rate and Turn Rate ................................................................... 276

26.2 2D Well Planner Utility ......................................................................................................................... 276

26.3 Tortuosity Utility ................................................................................................................................... 278 26.3.1 Background .............................................................................................................................. 278

26.4 Well Schematic Window ....................................................................................................................... 281

26.5 Units Selection Window ......................................................................................................................... 282

26.6 Model Options Window......................................................................................................................... 283

26.7 General Options Window ...................................................................................................................... 284 26.7.1 View Page ................................................................................................................................ 284 26.7.2 Input Page ................................................................................................................................ 284 26.7.3 Graphs Page ............................................................................................................................. 285 26.7.4 Printouts/Reports Page ............................................................................................................. 286

26.8 MS Office Report Maker ...................................................................................................................... 286

27. Program Licenses ................................................................................................................ 289 27.1 Viewing License Status .......................................................................................................................... 289

27.2 Borrowing License Keys ........................................................................................................................ 290

27.3 User setup to be able to borrow licenses .............................................................................................. 292

28. Theoretical Background ..................................................................................................... 293 28.1 Pore Pressure Prediction ....................................................................................................................... 293

28.1.1 Causes of abnormal pressure ................................................................................................... 294 28.1.2 Porosity calculation ................................................................................................................. 294 28.1.3 Methods for Estimating Pore Pressure ..................................................................................... 295 28.1.4 Bulk Density Measurements .................................................................................................... 295 28.1.5 Modified d-exponent ............................................................................................................... 296 28.1.6 Wireline data Measurements ................................................................................................... 298 28.1.7 Resistivity ................................................................................................................................ 298 28.1.8 Interval Transit Time ............................................................................................................... 299 28.1.9 Pennebaker............................................................................................................................... 300

28.2 Wellbore Stability Model ...................................................................................................................... 301 28.2.1 Basic Assumptions .................................................................................................................. 301 28.2.2 Failure Criteria ......................................................................................................................... 303 28.2.3 Mud/Shale Interaction ............................................................................................................. 303 28.2.4 Nomenclature for Wellbore Stability ....................................................................................... 303

28.3 Well Planning/Projection Model .......................................................................................................... 304

28.4 Casing Stress Check Model ................................................................................................................... 306 28.4.1 Casing Verification Concepts .................................................................................................. 306 28.4.2 Performing a Casing Verification ............................................................................................ 307 28.4.3 Casing Margin Analysis .......................................................................................................... 308 28.4.4 Casing Verification Calculations ............................................................................................. 309 28.4.5 Conventions and Nomenclature for Casing Models ................................................................ 311

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28.4.6 Basic Concepts for Casing Design ........................................................................................... 314 28.4.7 Comments on Application of Casing Stress Check Model ...................................................... 317

28.5 Wellbore Cementing Model .................................................................................................................. 317

28.6 Casing Wear Model ............................................................................................................................... 318 28.6.1 Volumetric Wear Rate of Casing ............................................................................................. 318 28.6.2 Wear Depth and Volume ......................................................................................................... 319 28.6.3 Nonlinear Correction Factors................................................................................................... 319 28.6.4 Wear in Seafloor Components ................................................................................................. 321 28.6.5 Adding Tortuosity .................................................................................................................... 322 28.6.6 Burst and Collapse of Worn Casing ........................................................................................ 322 28.6.7 Drill-Pipe Protector Requirements ........................................................................................... 323

28.7 Centralizer Design ................................................................................................................................. 324 28.7.1 Approach ................................................................................................................................. 324 28.7.2 Casing Deflection Models ....................................................................................................... 324 28.7.3 Centralizer Compression ......................................................................................................... 325 28.7.4 Rigid/Positive Centralizers ...................................................................................................... 326 28.7.5 Casing Stand-Off ..................................................................................................................... 326 28.7.6 Frictional Force When Running Casing .................................................................................. 326 28.7.7 Adding Tortuosity .................................................................................................................... 327

28.8 Torque & Drag for Liner Cementing Model ....................................................................................... 327

28.9 Torque & Drag for Drillstring Model .................................................................................................. 330 28.9.1 Torque and Drag Model ........................................................................................................... 330 28.9.2 Applying the Model to a Drill String ....................................................................................... 332 28.9.3 Buckling Modes ....................................................................................................................... 333 28.9.4 Which Buckling Criterion Should I Use? ................................................................................ 334 28.9.5 Which Buckling Model Should I Use? .................................................................................... 334

28.10 Drill-String Life Model .......................................................................................................................... 335 28.10.1 Approach to Modeling Fatigue ................................................................................................ 335 28.10.2 Drill-Pipe Bending Under Axial Tension ................................................................................ 336 28.10.3 Drill-Pipe Bending Under Axial Compression ........................................................................ 337 28.10.4 Drill-String Fatigue Damage ................................................................................................... 337 28.10.5 Drill-Pipe/Collar Crack-Growth Model ................................................................................... 338 28.10.6 Inspection Sensitivity and Reliability ...................................................................................... 338

28.11 Triaxial Stresses Model ......................................................................................................................... 339 28.11.1 Tubing Stresses ........................................................................................................................ 339 28.11.2 Triaxial Stress Equations ......................................................................................................... 340 28.11.3 Biaxial Stress Equations .......................................................................................................... 341 28.11.4 API Stress Equations ............................................................................................................... 341

28.12 Hydraulics for Normal Circulation Model .......................................................................................... 341 28.12.1 Fluid Rheology Models ........................................................................................................... 341 28.12.2 Flow and Pressure Drop Calculations ...................................................................................... 343 28.12.3 Slip Velocity and Cuttings Transport ...................................................................................... 346 28.12.4 Hydraulics and Well Planning ................................................................................................. 346

28.13 Hydraulics for Surge/Swab Model ....................................................................................................... 346

28.14 Hydraulics for Underbalanced Drilling ............................................................................................... 347 28.14.1 Definitions ............................................................................................................................... 347 28.14.2 Fluid Rheology Models ........................................................................................................... 347 28.14.3 Foam Flow Equations .............................................................................................................. 350 28.14.4 Influx Modeling ....................................................................................................................... 353 28.14.5 Cuttings-Carrying Capacity ..................................................................................................... 353

28.15 Hydraulics for HTHP Wells .................................................................................................................. 355 28.15.1 Fluid Models ............................................................................................................................ 355

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28.16 Flow and Pressure Drop Calculations .................................................................................................. 356

28.17 Slip Velocity and Cuttings Transport .................................................................................................. 359

28.18 Well Planning ......................................................................................................................................... 360

28.19 Cuttings Transport Ratio ...................................................................................................................... 360

28.20 Effects of Temperature and Pressure on Viscosity ............................................................................. 360

28.21 Dynamic Kill for Slim Holes Model ..................................................................................................... 362

28.22 Wellbore Thermal Simulation .............................................................................................................. 363 28.22.1 Wellbore Description ............................................................................................................... 363 28.22.2 Numerical Grid ........................................................................................................................ 363 28.22.3 Solids Properties ...................................................................................................................... 364 28.22.4 Liquid Injection, Production, and Circulation ......................................................................... 364 28.22.5 Gas Circulation ........................................................................................................................ 365 28.22.6 Two-Phase Steam Production and Injection ............................................................................ 366 28.22.7 Surface Mud Tank ................................................................................................................... 367

28.23 Well Control Models .............................................................................................................................. 368 28.23.1 Approach to Well Control ....................................................................................................... 368 28.23.2 Well Kill Methods ................................................................................................................... 369 28.23.3 Reservoir Model ...................................................................................................................... 369 28.23.4 Drill-Pipe Model ...................................................................................................................... 370 28.23.5 Annulus Model ........................................................................................................................ 370 28.23.6 Single-Bubble Model ............................................................................................................... 371 28.23.7 Two-Phase Flow Model ........................................................................................................... 371 28.23.8 Two-Phase Flow Correlations ................................................................................................. 372

29. Additional References ......................................................................................................... 377

30. Getting Help ........................................................................................................................ 381 30.1 Contacting Petris ................................................................................................................................... 381

30.2 Reporting Problems ............................................................................................................................... 381

Revision History

Rev. Date Of Issue Author Scope

00 02-Aug-2010 Samantha Royder Initial creation from previous 1.7.4documentation with no changes from version 1.7.4 to 1.7.5.

DrillNET 1.7.5 User's Manual, r 0 1 Copyright © 2006-2010 Petris Technology, Inc.

111. INTRODUCTION

1.1 What is DrillNET? DrillNET™ is an advanced drilling and completion engineering software platform developed by Petris Technology. It represents a new integration of the industry-leading drilling and completion software suite previously developed by Maurer Technology into an efficient package with more power than ever. This new program package makes well engineering easier than ever by combining an intuitive, easy-to-use software design with all the advanced functions and features from several world-class programs released previously by Maurer.

A wide variety of problems can arise while planning and conducting drilling, completion, and workover operations including problems with

Designing complex well paths

Checking for wellbore collisions

Verifying casing performance

Torque and drag in the borehole

Difficulties running casing strings

Designing cement pump schedules

Fatigue life in complex wellbores

Designing hydraulics for managed-pressure drilling applications

Estimating temperatures in wellbores

Well control

and many other difficulties.

CHAPTER 1: INTRODUCTION

2 DrillNET 1.7.5 User's Manual, r 0 Copyright © 2006-2010 Petris Technology, Inc.

DrillNET is the oil and gas industry’s easiest to use integrated software package for helping you to solve all these problems and more.

DrillNET is written for use with Microsoft Windows XP or later versions.

1.2 Features of DrillNET DrillNET incorporates all the benefits of Maurer’s and Petris’ years of experience in developing powerful and easy-to-use software for drilling and completion engineers. The DrillNET platform is very user-friendly and intuitive. Data input is simple, and the program provides assistance along the way with messages describing which information is missing. Several databases are supplied to help you enter data efficiently. Data-file management is simple, and options for customizing graphics and producing professional-style printouts are included.

Another important feature in DrillNET is the comprehensive help detailed in the DrillNET User’s Manual. The manual contains descriptions and instructions on how to use the software and can be launched by clicking .

1.3 Engineering Models DrillNET includes a complete and integrated suite of drilling and completion applications for use in the office and at the rig. The Engineering Models are listed below and described in Section 4. Those models marked with a check in the first column () are available for release in the current version of the program. Other models listed are being added to DrillNET and will be available for release soon.

CHAPTER 1: INTRODUCTION

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DrillNET’s Engineering Models Model Primary Application Wellbore Stability

Pore Pressure Prediction Determines formation pore pressures from seismic stacking data

Advanced Wellbore Stability Analyzes mechanical/chemical stability of vertical or inclined wellbores

Well Planning

Well Planning/Projection Generates 2D and 3D wellpaths

Anti-Collision Performs collision analyses between multiple well paths

Casing

Casing Stress Check Performs casing verifications

Wellbore Cementing Analyzes multistage fluid placement in a wellbore

Casing Wear Predicts wear in casing and risers

Centralizer Design Calculates spacing of centralizers for casing in directional wells

Torque & Drag for Liner Cementing Calculates torque and axial loads on a liner while cementing

Tubular Mechanics

Torque & Drag for Drillstring Analyzes torque, drag and buckling of drill strings

Drill-String Life Predicts fatigue damage of drill strings

Triaxial Stresses Calculates limits for burst/collapse pressure and equivalent stresses

Wellbore Hydraulics

Hydraulics for Normal Circulation Evaluates fluid hydraulics for drilling and completion operations

Hydraulics for Surge/Swab Evaluates fluid hydraulics for surge and swab pipe movements

Hydraulics for Underbalanced Drilling Designs and monitors managed-pressure drilling and completion operations

Hydraulics for HTHP Wells Calculates impact of high pressures and temperatures on mud rheology

Dynamic Kill for Slim Holes Analyzes hydraulics and well control in slim annuli

Wellbore Thermal Simulation Predicts down-hole temperature distributions

Well Control Killsheet Application Calculates kill information and prepares a drill-pipe pressure schedule

Kick Simulation Describes complex multiphase flow that develops as a gas influx is circulated out of a well

These Engineering Models are currently available in DrillNET. Other models will be added soon.


222. GETTING STARTED

2.1 Installing the Program To install DrillNET, insert the program CD into your drive. If the installation program does not begin running automatically, follow these steps:

1. Open Windows Explorer and view the contents of the CD. Open the folder “Programs” and double-click the file “setup.exe.”

2. Follow the on-screen instructions.

During set up, a new program folder (e.g., “C:\Program Files\Petris\DrillNET 1.0”) will be created (depending on the version number installed and whether it is a demo or purchased version) with the shortcut to DrillNET.

2.2 Removing the Program To remove DrillNET from your computer, access the Windows Add/Remove Programs feature by running

Settings Control Panel “Add/Remove Programs” and selecting DrillNET from the list of programs currently installed on your computer. Using this procedure clears the library registry in the Windows system folder and erases the corresponding library files that are not stored in the DrillNET directory.

2.3 Starting the Program To launch DrillNET, select it from the Programs menu under Programs. Basic operation of DrillNET and its key features are described in Section 3. Design and operation of each Engineering Model are described in Sections 1–24. Several customizable databases containing data on tubulars and fluids are provided to make program operation more efficient; these are described in Section 25. Various utilities and special option windows are described in Section 26. Procedures for obtaining and installing program licenses are listed in Section 27. Theoretical background for the engineering models is summarized in Section 28. For additional assistance with the program, contact Petris using information presented in Section 30.


333. BASIC PROGRAM OPERATION

3.1 Layout of DrillNET’s Main Window DrillNET’s interface provides several powerful options to simplify your well planning. The main window includes several separate divisions (called “panes”) that help you quickly select options and displays.

1) Menu Bar. Functions of DrillNET’s menus are described in Section 3.4.

2) Tool Bar. Tool-bar icons can be used to quickly access commonly used functions. Two groups of icons are presented—standard icons available in all DrillNET windows are on the left section of the toolbar. Icons in the right-most group are specific to the engineering model or function currently selected. Standard icons include:

New Project. Clears all input data.

Open Project. Activates the Open File window for browsing your system for DrillNET project files (*.XML files). To open and review/edit wells from the Galaxy Well Database, click on a well project in the Galaxy Database pane, or select “Galaxy Database” from the File menu.

Save. Saves all input data to the current project *.XML file. If the project is new, the Save As... window is activated automatically.

CHAPTER 3: BASIC PROGRAM OPERATION


Print. Prints the current window (input or output). A drop-down menu will be presented for selecting input data, a summary report of results, or a complete report of results.

View Input. Used to return to the input pages for reviewing and modifying input data after the results have been calculated and displayed.

View Output. Launches the calculations based on the current input data and automatically displays the corresponding results.

Tortuosity Window. Opens the Tortuosity window for adding imperfections to the survey so that it is more representative of real wells. See Section 26.3. (Only available when the Survey page is open.)

2D Well Planner. Opens the 2D Well Planner window for quickly creating wellpath surveys for use in planning analyses. See Section 26.2. (Only available when the Survey page is open.)

Calculate Survey. After survey data are entered or modified on the Survey page, click this icon to update all the columns in the survey table. This will also generate or refresh the survey graph on the right side of the page. (Only available when the Survey page is open.)

Well Schematic. Opens a utility window that displays the relative diameter with depth of the wellbore and drill string in several formats.

Units. Opens the Units Selection window (see Section 26.5). You can select default English units, default metric (SI) units, or any custom combination of standard or nonstandard English and SI units.

Help. Opens the on-line Help system directly to a description of the current window.

Calculator. Pops up the Windows utility calculator for quick arithmetic.

3) Galaxy Database Pane. The Galaxy Well Database makes it easy to handle large volumes of drilling and completion data. The database is based on the Microsoft Access platform, and is designed to allow accessing data from other external databases with the use of Petris’ Data Transfer Module.

There are several advantages to using Galaxy to organize your project data. See Section 25.1 for more information.

4) Page Tabs. Most input and output windows are displayed on multiple pages. Switching between these pages is simple—just click on the corresponding tab. On each input tab, the small circle on the left side of each tab is like a traffic signal light. A red light indicates that data entry is not complete on that page. A green light on all tabs means that all required data have been entered and that the calculation sequence may be launched by clicking .

Note that the tab traffic light may not change from red to green until the tab is redrawn (by selecting another tab, pressing [F9], or clicking “Refresh” from the View menu).

5) Input/Output Window Pane. This section of the main window is the primary work area for DrillNET. After an engineering model is selected (from the Engineering Models pane), the corresponding input windows will be displayed. You won’t have to review data you don’t need for this specific operation. After you’ve entered all required input data, the traffic light on the tabs turn green. You can now calculate and display results in this same pane by clicking .

6) Engineering Models Pane. Use the Engineering Models pane to select each type of analysis desired. This pane is similar to Windows Explorer. Common models are grouped in categories with a or next to each heading. Click to open that category and display all options available. Click to close a group. You can also click the model name to toggle opened/closed the category group.

The model option currently selected is highlighted in the Engineering Models pane:




Status of Models

Models for which licenses have been purchased are active. Active models and purchased models that have expired are displayed in black text:

Models without licenses (and those not yet available in this version of DrillNET) are inactive and displayed in gray text:

Details of your license status and expiration dates are provided under Help “License…” Contact Petris to purchase or update licenses for any inactive models.

Note: If the Engineering Pane is closed along with the Galaxy and Report Maker Panes, a new menu (“Models”) will be displayed to allow you to switch between engineering models.

7) Report Maker Pane. An important feature of DrillNET is how easy it is to compare and display integrated results from various analyses of well design. After calculations are completed, you can click on various report options in the Report Maker pane to open a special output window that displays several types of analyses side by side.

Clicking on “Model Report” allows you to generate reports for the current engineering model in Microsoft Office format: a Word document, an Excel spreadsheet, or PowerPoint slides.

The “Drilling Report” option is available for hydraulics for normal circulation, torque and drag, and triaxial stresses models only. This report allow you to view integrated report (graphs and tabulated data) compiled from results from the three models. Triaxial stresses analysis requires drill pipe internal and external pressures, which are output from hydraulics calculations, and axial loads which are from torque and drag analysis. To obtain a meaningful set of integrated results, you must first run hydraulics analysis, then torque and drag analysis, and then triaxial stresses.

Note that internal pressures, external pressures and axial loads for the triaxial stresses model can also be entered directly by the user if the hydraulics and/or torque and drag models are not available.

8) Message Board Pane. A variety of useful error messages are displayed on the Message Board including:

1. Required data that have not yet been entered

2. Values that are out of the expected range (ID>OD, etc.)

These are listed on the Message Board along with their location in the program. This information is very useful for troubleshooting when entering input parameters. Double-click the message to go directly to the location (page tab) where the error occurred.

3.2 Common Input Pages The platform for DrillNET is designed to be user-friendly and easy to learn. Most Engineering Models share very similar input windows. Each of the common input pages is described in this section.



3.2.1 Typical Project Page

1) Menu Bar. Functions of the menus are described in Section 3.4.

2) Tool Bar. Tool-bar icons can be used to quickly access commonly used functions. See Section 3.1.

3) Page Tabs. Switching between input pages for entering or checking data is simple – just click on the corresponding tab. The small circle on the left side of each tab is like a traffic signal light. A red light indicates that data entry is not complete on that page. A green light on all tabs means that all required data have been entered and that the calculation sequence may be launched by clicking .

Note that the tab traffic light may not change from red to green until the tab is redrawn (by selecting another tab, pressing [F9], or clicking “Refresh” from the View menu).

4) Project Documentation. These data provide specific information about the project to identify the company, project name, well location, date, and miscellaneous comments. This information is displayed on printed results. Any of these items may be left blank if desired. The function of the program is not affected.

3.2.2 Typical Survey Page A wellbore survey is required that describes wellbore inclination and azimuth with depth. These data can be entered (1) manually, (2) by pasting from an Excel spreadsheet (or other source), or (3) imported from the Galaxy Database, an existing project file (*.XML), or Petris survey file (*.SDI).




West

South

North

East

TVD

Azimuth ofVertical Section

1) Survey Icons. On the main icon tool bar (see Section 3.1) are three icons for use in creating, editing and refreshing the survey data. These are only active when the Survey page is open.

Tortuosity Window. Opens the Tortuosity window for adding imperfections to the survey so that it is more representative of real wells. See Section 26.3.

2D Well Planner. Opens the 2D Well Planner window for quickly creating new wellpath surveys for use in planning analyses. Newly created surveys can be automatically copied into the Survey Data table. See Section 26.2.

Calculate Survey. After survey data are entered or modified, click this icon to update all the calculated columns in the survey table (those with yellow backgrounds). This will also refresh the survey graph on the right side of the page.

2) Azimuth of Vertical Section. A section view is a side view of the well path. A section view graph will vary in shape and magnitude depending on the azimuth of the vertical section (VS) (the angle of rotation between the VS plane and the vertical plane parallel to the NS axis, positive for clockwise). The azimuth of the VS plane is a reference value and is not related to the azimuth of any survey point.

Within the survey table (in column 8) VS values are calculated and listed. These refer to the trajectory that is projected on a specific VS plane. The VS value of each survey point is the horizontal distance (projection)



between that survey point and the start point on the VS plane. Therefore, it is obvious that VS values are dependent on the orientation of the VS plane.

Horizontal displacement (HD) (column 7) of a survey point is the true horizontal distance between the survey point and the start point and is independent of azimuth angle of the vertical section. For two-dimensional well trajectories, when the VS plane is the vertical plane defined by a vertical line through the start point and the end point of the trajectory, HD values are identical with VS values. This special azimuth is always used as the default value for the azimuth of the vertical section as listed on the bottom of the Survey page. You can input any VS plan angle and recalculate the survey by clicking , [F9], or selecting “Refresh” from the View menu.

3) Well Trajectory Name. The trajectory name from the Galaxy Database (see Section 25.1) is displayed (if available). This field cannot be edited on the Survey page.

If the survey is new, you can add a trajectory name by opening the Project Data window in the Well Planning/Projection model (see Section 7.1.1).

4) Survey Data Table. A variety of options are provided for entering wellbore survey data. Data may be entered manually, copied and pasted from an Excel spreadsheet (or other source), or imported from the Galaxy Database, an existing survey file (*.SDI), or a DrillNET *.XML file.

Wellbore survey data are entered into the first three columns of the table. Column 1 is Measured Depth of the survey point. Column 2 is Inclination Angle at that depth. Column 3 is Azimuth Angle at that depth. Columns 4–11 are calculated from columns 1–3 (except for the first row, which TVD, NS and EW can be entered directly). The yellow background on these columns denotes they cannot be entered or edited by the user.

Entering Survey Data

Importing Surveys

Several methods are provided for importing survey data, including Petris survey files (*.SDI), other DrillNET project files (*.XML), delimited text files (*.TXT), and the Galaxy database. To import data, right-click over the survey table and select “Import” or “Get Survey from Galaxy Database” from the pop-up menu. (Import options are described under the Survey Table Edit menu below.)

Copying from Excel

To copy from a spreadsheet application (e.g., Excel), assemble the data in the spreadsheet in three columns in the correct order. Select the range of interest and copy to the clipboard (control+C). Go back to DrillNET, right-click over MD in row 1, and select “Paste” from the pop-up menu.

Manual Data Entry

You can input any number of survey positions in the table. When first opened, the survey table has 200 rows. To add additional rows (or remove existing rows), right-click over the survey table to open the Edit menu.

Survey depth in row 1 should be 0 feet (or 0 meters). Survey depths must be in increasing order (i.e., descending down the hole).

To enter survey data, click on the appropriate box in the spreadsheet table. The most straightforward technique for data entry is to type the number and then press <Enter>. This will automatically shift the cursor position to the next white cell. (Again, note that you cannot enter data into yellow cells.)

The standard Windows key combinations can also be used to copy, paste or move individual entries or blocks of cells in the survey table. Control+C will copy the selected entry (ies); control+V will paste; control+X will remove the entry to the Clipboard. Note that you can copy individual entries only to individual cells, not to a block of cells.

Editing Entries

When editing survey data, the arrow keys are the easiest way to navigate within the table. The up/down arrow keys are used to move up or down within a single column. [Tab] also moves the cursor one cell to the right.




After an arrow key or the mouse is used to move to the cell of interest, the default edit mode for that cell is the overwrite edit mode. Type any number or a decimal point, and the old value will be erased and replaced by the new number.

The number edit mode allows changing individual digits in the cell entry. Double-click on the entry to activate the blue highlight on the cell. Cancel the blue highlight by clicking inside it or using the right or left arrow key. After the blue highlight is removed, single digits can be erased (using backspace or delete keys) and new digits added.

Calculating/Refreshing the Survey

After survey data are entered or modified, click the Calculate Survey icon (or [F9]) for calculating columns 4–11 in the data table. This will also generate or refresh the survey graph on the right half of the screen. Of course, survey data are recalculated automatically during the main calculation sequence (after you click ).

Errors

Calculating will also check the data for errors. These are reported on the Message Board. If you are told an error has occurred, but nothing is displayed on the Message Board, refresh the screen by clicking [F9] or selecting “Refresh” from the View menu. The message should now be displayed.

Survey Table Edit Menu

You can save, print, import, and edit the survey table by opening the pop-up edit menu. Right-click over the table to open the menu and then select the desired option.

1. “Cut” removes the contents of the selected cell(s) to the Clipboard.

2. “Copy” places a copy of the selected cell(s) to the Clipboard.

3. “Paste” copies the Clipboard contents to the data table starting at the current position of the cursor.

4. “Clear” deletes the contents of the selected cell(s).

5. “Insert Row(s)” inserts a blank row directly above the cursor. If cells from multiple rows are highlighted, that number of new rows will be inserted above the uppermost highlighted row.

6. “Delete Row(s)” deletes all rows of the current data table that have any cells selected. It does not matter whether only one cell, multiple cells, or the entire row is selected.

7. “Append Row(s)” is used to add new rows to the end of the data table. The default number of rows is 200 for the survey table. This limit can be increased as needed.

8. “Print Table…” will print only the current data table. The print control window pops up for selecting a specific printer. If the table contains more than 10 columns, a message will pop up to warn you about over-crowding, and will then proceed to the Print Preview window.

9. “Print Preview Table…” opens the Print Preview window with the current data table displayed. If the layout is satisfactory, click the print icon in the window to send the document to your default printer.

10. “Display in Separate Window” is a useful way to increase visibility of data tables while entering data. Select this option to open a new window that contains only the current data table. You can maximize the new window to see all (or most) of the rows without needing to scroll horizontally. When you close the new window, the changes you made are transferred automatically to the corresponding input page.

11. “Import…” allows you to select a file to pull survey data into the table. Options for four file formats are provided. You can:

Copy only the survey data from another DrillNET project file by importing an *.XML file.



Import from a WITSML *.XML file

Import an existing standard Petris survey data file (*.SDI) created with another Maurer program.

Import a delimited text file received from a service company or other source. After you select the text file, a preview window is opened for you to specify the data layout and confirm that the settings are correct (see figure below).

12. “Export…” allows you to save the survey as a DrillNET project file (*.XML), a Petris standard survey file (*.SDI), a WITSML XML file or as a TXT file.

13. “Get Survey from Galaxy Database” opens a window for you to explore the Galaxy Database and select a particular survey. The data are then copied to the Survey page.

14. “Save Survey to Galaxy Database” opens a pop-up window for you to name the survey. This well project will then be displayed in the Galaxy Database pane.

15. “Import WITSML Survey” allows survey data to be imported from a .xml file.

16. “Export WITSML Survey” allows the export of survey data to a .xml file.

5) Survey Data Graph. Survey data entered in the table are plotted graphically in one of three formats chosen by the user. Options, which include 3D view, dogleg severity with depth, inclination angle with depth, are selected by clicking the tabs at the bottom of the graph area. These plots are very helpful for spotting errors in the survey data.




Survey Graph Edit Menu

You can save, print and edit the survey graph in various ways by opening the pop-up edit menu. Right-click over the graph area to open the menu and then select the desired option.

1. “Save Picture As…” allows you to save the current graph for opening in other applications. A variety of graphic formats are provided as options (gif, jpg, wmf, etc.).

2. “Print Picture…” will print only the current graph. The print control window pops up for selecting a specific printer.

3. “Print Preview Picture…” opens the Print Preview window with the current data table displayed. If the layout is satisfactory, click the print icon in the window to send the document to your default printer.

4. “Copy” copies the current graph to the Windows Clipboard.

5. “Add Text Box” creates a text box within the graph that can be moved and resized. Click inside the new text box to add text. Right-click on the text box to format the text. Resize text boxes by moving your cursor

over the borders of the box. The cursor changes shape for each function: to move the box, to raise/lower the lower border of the box, and to move the right border to the right or left.

6. “Delete Text Box” removes the current text box from the graph.

7. “Display in Separate Window” is a useful tool for reviewing graphs. Select this option to open a new window that contains only the current graph. Close the new window to return to DrillNET.

8. “Options” opens a submenu with various options for changing the format of the survey graph. Currently selected options are checked. Click any option to select or unselect it.

9. “Rotate around vertical axis” rotates the survey cube one complete revolution about the vertical axis. You can rotate the cube in small increments by clicking on the horizontal scroll bar below the graph.

10. “Rotate around horizontal axis” rotates the survey cube one complete revolution about the horizontal axis. You can rotate the cube in small increments by clicking on the vertical scroll bar to the right of the graph.



3.2.3 Typical Tubulars Page

1) Drill-String Data Table. The drill string placed in the well must be specified in detail. The first row is the first section that would be inserted into the hole (i.e., the BHA, collars, etc.). Other sections of drill pipe should be entered in order proceeding up to the surface.

For components indicated as “BHA” in column 1 (applicable in some hydraulics models), specify the total pressure drop through that component of the downhole assembly. Otherwise, pressure drop will be calculated based solely on ID/OD of the assembly.

Order of Data Entry

The default setting is to enter tubular data starting from the deepest BHA component in row 1 and proceeding uphole to the surface. If you prefer, the order can be reversed by selecting Options menu “General Options” “Input” tab.

Effects of Tool Joints

If you want to account for the influence of tool joints on pressure drop in the annulus, check “Tooljoint effects” on the Drilling

A BL

Tooljoint Contact % = * 100(A+B)

L

Tooljoint Contact %




page. This will open columns for you to enter Tooljoint OD and ID and Tooljoint Contact % for each section of the drill string.

Editing the Tubular Data Table

An Edit menu can be accessed by right-clicking over the tubular data table. Options on this pop-up menu are:







7. “Append Row(s)…” is used to add new rows to the end of the data table. The default number of rows is 100 for most data tables. This limit can be increased as needed.

8. “Print Table…” will print only the current data table or graph. The print control window pops up for selecting a specific printer. If the table contains more than 10 columns, a message will pop up to warn you about over-crowding, and will then proceed to the Print Preview window.


10. “Display in Separate Window” opens a new window with the data table alone.

11. “Import from Tubular Database…” opens the Tubular Database (see section 22.2) for importing dimensions and properties of OCTG. Click to select the appropriate row before opening the database.

12. “My BHAs…” opens a customizable database of standard BHAs and properties. These can be selected and the data copied into the Tubular Data table. See Section 22.4.

13. “My S-N Curves…” opens a customizable database of pipe fatigue curves. These can be reviewed and the data automatically selected from a drop-down list in the column “S-N Curve” (displayed when Drill String Life model is selected). See Section 22.5.

14. “Typical Density and Young’s Modulus…” opens a pop-up reference window that lists density and Young’s modulus for several common tubular materials. (Note: Density and Young’s modulus are not required for every Engineering Model.)

15. “Calculate Body Yield Strengths…” is provided for quickly estimating tensile and torsion limits. Change any default input parameters as required. Click [Calculate] to calculate yield strengths. Click [Accept] to export these values to the Tubular Data table. (Note: Tensile and torsion limits are not required for every Engineering Model.)



16. “Final Tubular Section Length…” is provided to calculate the complementary final length of drill pipe required to achieve TMD. The last row entered in the table describes drill pipe in the uppermost section of the well when the bit is at the depth of interest. The length of drill pipe for this section should only be enough to complete the string to the depth of interest (which may be at any depth). Within the Final Section Length Calculator utility, enter the MD of interest where the bit will be located. The required length of drill pipe to complete the string will be calculated automatically. Click [Apply] to export the result to the Tubular Data Table.

17. “Import WITSML Tubular” allows tubulars data to be imported from a .xml file.

18. “Export WITSML Tubular” allows the export of tubular data to a .xml files.

2) Drill-String Graph. The tubular data entered in the table are shown schematically. This plot can be useful for spotting errors in the tubular data. You can also view the rows singly or in small groups to improve visibility. To view a single component, select that row in the table by clicking on the row number.

Click on one (or more) row(s) to view that component(s) alone in the graph

Editing the Graph

The Edit menu can be accessed easily by right-clicking over the graph. Options on this pop-up menu are described in Section 3.4.

3) Bit Nozzles. For hydraulics models, data describing the bit nozzles are used to calculate the pressure drop across the bit. Select “Input nozzle sizes” and specify in the table the size of each nozzle. A utility is provided for calculating bit nozzle sizes (see below) by right-clicking over the nozzle table and selecting “Nozzle Combinations…”.

If total flow area (TFA) is known, it can be entered directly. Select “Input nozzle TFA” and enter the value in the text box. If no bit, select “No bit.” The flow area will be assigned a value corresponding to the first BHA component from the Tubular Data table (i.e., the BHA ID).

Bit Nozzle Combination Window

This utility window provides a quick estimate of nozzle combinations to provide a given TFA. If you input a value for TFA in the upper right corner, a variety of nozzle combinations (shown as “Default Combinations”) will be displayed in the table. You can select any of these for export by clicking on the chosen row and then clicking [Apply Selected Default].

The Trial and Error option allows you to enter any combination of nozzles in the white cells. The TFA is calculated and displayed below the table. If you want to keep the results, click [Apply Trial and Error].




3.2.4 Typical Wellbore Page

1) Wellbore Data Table. Geometry along the wellbore must be precisely specified. ID is required for each section of the annulus. If casing ID is unknown, access the online Lookup Table by right-clicking over the table and selecting “Import from Tubular Database…” from the pop-up menu.

If wellbore data are saved with a well project in the Galaxy database, these can be imported by selecting “Get Wellbore from Galaxy Database.”

Friction factor is required for some Engineering Models. A reference Friction Factor Table with typical values can be viewed by right-clicking and selecting “Friction Factor Table.”

2) Wellbore Data Graph. The wellbore data entered in the table are shown schematically. This plot can be useful for spotting errors in the data. You can also view the rows singly to improve visibility. To view a single component, select that row in the table by clicking on the row number.



3.2.5 Typical Formation Page If pore- and fracture-pressure limits are of interest for hydraulics analysis, these data are entered on the Formation page. If you prefer to not consider pore/fracture data, the Formation page can be turned off by selecting Options menu “General Options” “Input” tab.

1) Pore and Frac Pressure Gradient Table. Enter as many rows as required to specify TVD, pore pressure and frac pressure. Some models also require formation temperature. Techniques for entering and editing data are similar to those described for the Survey Data table (see Section 3.2.2).

Pore and fracture pressures may be entered as pressures (columns 2 and 4) or as gradients (columns 3 and 5). To change options, open the Input Options window (Options menu “General Options” “Input” tab).

After you select your preferred option, enter data into the white cells; corresponding data in the yellow cells will be calculated automatically.

Importing Data

Several methods are provided for importing formation data, including well log ASCII standard (*.LAS) files, other DrillNET project files (*.XML), and from the Galaxy database. To import data, right-click over the




formation table and select “Import” or “Get Formation Data from Galaxy” from the pop-up menu. (Import options are described below under the Formation Table Edit menu.)

Copying from Excel

To copy from a spreadsheet application (e.g., Excel), assemble the data in the spreadsheet in columns. Copy the data column by column into DrillNET. Select the source range of interest and copy to the clipboard (control+C). Go back to DrillNET, right-click on the appropriate cell in row 1, and select “Paste” from the pop-up menu.

Formation Table Edit Menu

1. You can save, print, import, and edit the formation table in several ways by opening the pop-up edit menu. Right-click over the table to open the menu and then select the desired option.“Cut” removes the contents of the selected cell(s) to the Clipboard.






7. “Append Row(s)” is used to add new rows to the end of the data table. The default number of rows is 100 for most data tables. This limit can be increased as needed.



10. “Display in Separate Window” is a useful tool for increasing visibility of data tables while entering data. Select this option to open a new window that contains only the current data table. You can maximize the new window to see all (or most) of the rows without needing to scroll horizontally. When you close the new window, the changes you made are transferred automatically to the corresponding input page.

11. “Estimate” opens a window to estimate pore pressure, overburden, horizontal maximum stress, fracture gradient based on TVD, and temperature. This utility is only available with the Casing Stress Check model (see Section 9.1.3).

12. “Import…” allows you to select a file to copy formation data into the table. Options for three file formats are provided. You can:

Copy only the formation data from another DrillNET project file by opening an *.XML file.

Import an *.LAS log file (which is a delimited text file) received from a service company or other source. After you browse and select the *.LAS source file, a preview window is opened for you to specify the data layout and confirm that the settings are correct (see figure below).

Import a WITSML .XML file



13. “Export…” allows you to save the current formation data set separately as a DrillNET project file (*.XML), which can later be imported into other DrillNET projects. . Data can also be exported to a WITSML .XML file.

14. “Get Formation from Galaxy Database” opens a window for you to explore the Galaxy Database and select a particular formation data set. The data are then copied to the Formation page.

15. “Save Formation to Galaxy Database” opens a pop-up window for you to select the database project. If you enter a new name, a new well database object will be created. This well will then be displayed in the Galaxy Database pane.

2) Pore and Frac Pressure Graphs. Depth and gradient data in the Formation Data table are plotted for inspection. Both pressure with depth and pressure gradient with depth are shown; click the corresponding tab at the bottom of the graph.

Right-click over the graph to access options for saving, printing, adding a text box, and exporting the graph to Excel.

3) Pressure Margins. Trip and kill margins function as safety factors for avoiding exceeding pore or fracture limits. Typical values range from about 0.5 to 1.0 ppg above pore pressure or below frac pressure (0.026 to 0.052 psi/ft or 0.6 to 1.2 kPa/m). Exact values you enter depend on how accurately formation behavior can be predicted. These margins will be plotted in corresponding graphs as more restricted limits within those defined by pore/frac pressures.

3.3 Typical Output Page Output from engineering models is displayed in tables and graphs. The output is launched in most cases by clicking after all input data are entered (the traffic lights on the tabs are all green). Specific formats vary depending on the

engineering model in use. For most analyses, three types of output are displayed:

Tab 1 – Summary results in tables and text boxes that list critical forces, pressures, etc. and depths at which they occur.

Tab 2 – A combination graph and table window that provides all basic results (see example below).




Tab 3 (and higher) – Other special graphic results are displayed to highlight and compare various aspects of the analysis.

3.3.1 Graphs/Tables Window

1) Output Graphs. A variety of standard output graphs are displayed for review. Options available are listed in the Display Graph(s) box on the right. Click on a graph title to view that graph.

Editing Graphs


2) Display Graph(s). Available graphs are listed with currently displayed graphs highlighted in blue. You can select any combinations of graphs to be displayed simultaneously. Selection features are the same as in Windows Explorer:

If you click on a graph title, that graph will be displayed alone.

If you hold down the [Control] key while you click the mouse, each graph you click will be added to those already displayed.



If you hold down the [Shift] key while you click the mouse, the complete range of graphs between the points you click will be added to the display.

3) Output Tables. All output data for the current Engineering Model are presented in one or more tables.

Right-click over the table to access options for copying, previewing, printing, and displaying the table in a separate window.

3.4 Menus

3.4.1 File Menu

1. “New” clears all input pages for creating a new project. Same as .

2. “Open...” opens a dialog box for exploring your computer for project files with the extension “*.XML” or for existing project files for individual Maurer programs. Same as .

3. “Save” replaces the previous version of the project file with the current

modified data. Same as .

4. “Save As...” saves the current version of the project data file under a different name. A dialog box is opened for you to specify the drive, directory, and name of the project file.

5. “Galaxy Database” provides access to create and delete well data records to DrillNET’s online Galaxy Database. To view and edit wells currently in the database, click on the Galaxy Database pane. Benefits and operation of the Galaxy Database are described in Section 25.1.

6. “Page Setup...” provides options for selecting paper size, orientation and

margins. Make any adjustments to your page layout before you select “Print.”

7. “Print” provides options for printing input or output data currently displayed. First, select one of the three primary print options (as shown). Within the Print pop-up window that follows, select the preferred printer before you click [OK]. You can preview the print job before you send it to the printer by selecting “Print Preview” on the File menu. Same as .




8. “Print Preview” allows you to preview the print job before it is sent to the printer. First, select one of the three primary print options (as shown above under “Print”). The Print Preview window will be displayed (see figure at right) with the formatted print job. To print the results as displayed, click the icon in the window. (Note that the print icon in the Print Preview window will print directly to your default printer. To select another printer, close the Print Preview window and select Print from within DrillNET’s main window.)

9. “Create MS Office Reports…” allows you to save input and output results in any or each of three formats that can be opened immediately as a Microsoft Word document (graphs and tables), an Excel workbook, (tables) or a PowerPoint presentation (graphs). This feature is described in Section 26.8.

10. The names of up to nine of the most recently accessed project files are displayed. Click any of the files names to immediately open that project.

11. “Exit” concludes the current session. DrillNET will prompt for saving input files if data have been changed and not yet saved.



3.4.2 Edit Menu (Tables) The Edit menu contains commands for use when working inside data tables and graphs. Note that these options can also be accessed by right-clicking inside any data table or graph. (Note: Options will sometimes appear on the Edit menu that are specific to the currently selected data table or graph.)

The typical Edit menu for data tables includes:







7. “Append Row(s)” is used to add new rows to the end of the data table. The default number of rows is 100 for most data tables. The number of rows can be increased/decreased as needed.



10. “Display in Separate Window…” is a useful tool for increasing visibility of data tables while entering data. Select this option to open a new window that contains only the current data table. You can maximize the new window to see all (or most) of the columns without needing to scroll horizontally. When you close the new window, the changes you made are transferred automatically to the corresponding input page.

3.4.3 Edit Menu (Graphs) The Edit menu displays different options when a graph is selected. This menu is most easily accessed by right-clicking over the graph of interest.

1. “Save Graph As...” opens a window for saving the current graph file. A variety of graph file formats are available.

2. “Print Graph…” will print only the current graph. The print control window pops up for selecting a specific printer.

3. “Print Preview Graph…” opens the Print Preview window with the current graph displayed. If the layout is satisfactory, click the print icon in the window to send the document to your default printer.

4. “Copy” places a copy of the selected graph on the Clipboard.




5. “Add Text Box” creates a text box within the graph that can be moved and resized. Click inside the new text box to add text. Right-click on the text box to format the text. Resize text boxes by moving your cursor over the borders of the box. The cursor changes shape for each function: to move the

box, to raise/lower the lower border of the box, and to move the right border to the right or left.

6. “Delete Text Box” removes the currently selected text box from the graph.

7. “Display in Separate Window” is a useful tool for easier review of graphs. Select this option to open a new larger window that contains only the current graph(s).

8. Export to Excel…exports the graphic to Excel

3.4.4 View Menu The View menu contains commands for changing the main display.

1. “Input” displays the main input window of the selected Engineering Model for entering and editing input data. Used to return to the input pages after a calculation sequence. Same as .

2. “Output” calculates the results for the current Engineering Model and displays corresponding output graphs and tables. Same as .

3. “Refresh” is used to recalculate and replot data after any changes are made. Calculations are automatically updated prior to displaying results. Use “Refresh” only if you want to remain in the current input window. Same as [F9].

4. “Well Schematic” opens a utility window that displays the relative diameter with depth of the wellbore and drill

string. See Section 26.4. Same as .

5. “Wall Plot” displays a preview of the wall plot of the survey data (see figure below). To print the results as displayed, click the icon in the window. The print icon in the Well Print Preview window will print directly to your default printer. To select another printer and/or change paper size or orientation (portrait or landscape), close the Wall Plot window and select “Page Setup…” from the File menu. After the printer and paper size are selected, return to the Wall Plot window and review the updated preview. When the display is correct, click .



6. “Panes” selects (displays) or unselects (hides) sections of the DrillNET window. You can hide any pane not being used; this will increase available screen space. Panes can also be closed manually by clicking on the right end of the pane title bar. Pane sizes can then be adjusted by grabbing and moving their borders. See Section 3.1 for more information.




3.4.5 Models Menu The Models menu is an alternative method to select the current Engineering Model. This menu has the same function and contains the same list as the Engineering Models pane (see Section 3.1). The Models Menu is not displayed unless the Engineering Models pane on the left side of the DrillNET window is closed by the user.

Closing the three panes (Galaxy Database, Engineering Models and Report Maker) will provide more room on the display for the main input/output, and this may be desirable on smaller monitors.

Models that are not available because they have not been purchased or have not been released yet (See Section1.3 are displayed as disabled options.

3.4.6 Tools Menu The Tools menu provides options for opening various utilities and databases. The first option (“Tubular Database…”) is always displayed. Other options are presented on the menu that are specific to the currently selected Engineering Model.

1. “Tubular Database…” allows you to review and edit the on-line Tubular Database by adding, removing or changing entries in the data tables. See Section 25.2.

2. Other options are displayed that are specific tools for each Engineering Model.

3.4.7 Options Menu The Options menu includes:

1. “Units” “Custom…,” “English,” or “Metric” selects the system of units for input/output displays and printouts. “Custom” opens the Units Selection window (see Section 26.5) for selecting nonstandard English or metric units, or a custom combination of English and metric units. Same

as . “English” selects the default English system of units. “Metric” selects the default S.I. system of units. At the top of the units window you can select whether a thousands separator and/or trailing zeroes are displayed.

2. “Language” displays options for selecting the language for all displays in DrillNET. Petris language databases must be specially purchased for this option to be available. The language options are English, Chinese, Russian or Spanish.

Casing Stress Check

Wellbore Cementing

Drill-String Life

Dynamic Kill for Slim Holes

Hydraulics for Normal Circulation

Killsheet Application

Hydraulics for Surge/Swab

Drill-String Torque/DragTriaxial StressesWell Planning/Projection



3. “Model Options…” opens a window for selecting various display options for the current Engineering Model. This menu option will be inactive if there are no options associated with the current Model. See Section 26.6.

4. “General Options…” allows you to select global options for input and output displays. The last tab (“Printouts/Reports”) allows you to load a logo graphic for your company which will be displayed on all printed results. See Section 26.7.

3.4.8 Help Menu The Help menu provides information for obtaining additional assistance with DrillNET and presents various parameters describing the computer.

1. “Help Topics...” launches the DrillNET Help system from the introduction. Alternatively, click or [F1] to open Help to information specifically describing the currently displayed screen.

2. “Assistance...” opens a pop-up box which displays Petris’ address, phone number, e-mail address and other information. Use these contacts to obtain additional help with the program. See Section 30.1.

3. “Maurer Software on Web” provides a link to our web site for more information describing our software and on-line applications.

4. “License…” opens the License Status window that summarizes your current status for licenses for Engineering Models. From here you can request new licenses or renewals. After you have received licenses, you can activate corresponding models. See Section 27.

5. “About...” opens the About pop-up box, which displays the version number of DrillNET along with the program disclaimer.

a


444. DRILLNET ENGINEERING MODELS

Engineering Models included in DrillNET address almost all aspects of well design, drilling and completion. Features of each are summarized below. Their status and availability in DrillNET are described in Section 1.3.

Wellbore Stability

1. Pore Pressure Prediction can make use of 5 different methods to predict pore pressure. The method selected will depend on the input data available to the user. The 5 options use bulk density, modified d-exponent, resistivity, internal transit time or seismic stacking velocity data - Pennabaker plots. The various models can help identify abnormal pressure sequences which deviate from normal compaction trends and these results all form the more accurate selection of casing-seat depths.

2. Wellbore Stability analyzes mechanical/chemical stability of vertical or inclined wellbores and can be used prior to actual field operations. A linear poroelasticity model is used to predict wellbore stability and ranges for stable mud weights or wellbore pressures. Stability designs of critical parameters are also provided.

Well Planning

3. Well Planning/Projection is a very sophisticated software application for generating wellbore surveys. This model manipulates well trajectory data including: survey data input, survey data editing, well path planning, and well path projection. The model helps you: (1) design well paths during the well-planning stage, (2) project well paths to determine if targets can be achieved using existing BHAs, (3) determine build rates needed to hit targets, (4) determine if well paths remain within legal or defined boundaries, and (5) print/graph data for daily morning reports (including wall-plots).

4. Anti-Collision performs a collision analysis between multiple well paths. Tools for anti-collision analysis range from relatively simple (Well Collision Check; 3D Closeness Graph) to more complex (Well Proximity Analysis; Anti-collision Analysis for Multiple Wells). Analyses can account for measurement uncertainties and errors in survey tools and instrumentation.

Casing

5. Casing Stress Check is primarily designed to run casing verifications, i.e., to compare the resistance of a casing column design to the physical stresses that the column is likely to experience. A variety of potential stress factors can be considered. Rules used to calculate stresses can be saved in a customized profile, thus making it easier to address your company’s policies.

6. Wellbore Cementing comprehensively analyzes the complex phenomena of multistage fluid placement in a wellbore. Although originally designed for cementing, the program can be used for any multistage fluid pumping operation in a wellbore. The well-recognized U-tubing phenomenon (free fall) is addressed, along with ECD and pressure at the bottom of the hole. A variety of potential problems with formation break-down and of low to no returns can be avoided by using this model at the planning stage.

7. Casing Wear is a unique and powerful engineering model for calculating and monitoring the progression of wear due to rotary contact of drill pipe with casing, riser, and other downhole elements. The model was originally developed under sponsorship of the ground-breaking joint-industry project DEA-42 – Casing Wear Technology. It accurately predicts the location and magnitude of wear in casing/riser strings for both onshore and offshore geometries.

8. Centralizer Design calculates centralizer spacing to provide sufficient stand-off between casing strings and the wellbore wall. Casing centralizers are designed for use on the casing string to prevent it from contacting the wellbore wall and to provide sufficient stand-off between the casing and wellbore wall, so that cement slurry displaces the drilling mud in the wellbore annulus during cementing operations.

9. Liner Cementing calculates torque and tension/compression loads (drag) on a liner while cementing. During cementing when cement is in the liner and has not yet flowed around the liner shoe, excessive torque loading can occur. An increased down-thrust load occurs since cement is usually heavier than mud or preflush outside the casing. This situation can damage a rotary and/or reciprocation liner hanger and may

CHAPTER 4: DRILLNET ENGINEERING MODELS


prevent rotation or reciprocation of the liner. Torques and tension loads can be determined to prevent this occurrence.

Tubular Mechanics

10. Drill-String Torque/Drag analyzes the complex phenomena of axial and torsional loads, and the development of torque and drag (and buckling) of drill pipe as it is run into and out of the hole. It also calculates operational safety margins to prevent damage to the drill string. For compressive loads, the onset of (1) sinusoidal buckling, (2) helical buckling, and (3) pipe yield are indicated. This model is widely used for designing and monitoring operations in deviated, horizontal and extended-reach wells. It can also be applied to casing, liners, or tubing-string applications.

11. Drill-String Life predicts drill-string fatigue damage. Two mechanical models are provided: (1) fatigue and (2) crack-growth models. The fatigue model calculates drill-pipe bending stress and predicts build-rate/dogleg limits, fatigue damage and rotation limits of drill-string tubulars. Fatigue failure is considered to occur when cumulative fatigue damage exceeds 100%. The crack-growth model is based on correlations of drill-string tubulars by Exxon, and predicts the inspection intervals to prevent fatigue failure.

12. Triaxial Stresses calculates limits for burst and collapse pressures and equivalent stresses for a pipe body. The model calculates limits for burst and collapse pressures and equivalent stresses for a pipe body by three different approaches: (1) triaxial, (2) biaxial, and (3) API. The program also performs triaxial stress sensitivity analysis for the factors of internal and external pressure, doglegs, and D/t (diameter to wall thickness) ratios.

Wellbore Hydraulics

13. Hydraulics for Normal Circulation comprehensively evaluates fluid hydraulics for drilling, completion, and workover operations. The model covers almost all aspects of hydraulics, including pressure drop and flow regime, equivalent circulating density (ECD), nozzle selection, hole-cleaning efficiency, and volumetric displacement. A variety of potential problems and sources of confusion (whether the formation will break down, whether a kick will occur, what the optimum nozzle area is, etc.) can be easily analyzed and defined.

14. Hydraulics for Surge/Swab calculates the effects of surge and swab on annular pressures and ECD at the bottom of the hole.. The model allows you to determine the allowable range of drill-string tripping speeds to avoid circulation problems and formation break-down.

15. Hydraulics for Underbalanced Drilling is used to design and monitor managed-pressure drilling and completion operations. Features of this powerful hydraulics model include: calculates velocity, pressure and density profiles; models coiled-tubing operations; handles 3D wellbores; considers fluid influxes and parasite strings; designs jet subs for optimized flow rates; and includes pressure-matching window for calibrating input parameters with field data. The model can be used to design hydraulics for air, gas, aerated fluid, foam or mud.

16. Hydraulics for HTHP Wells is used for detailed analysis of wellbore hydraulics and improved drilling operations for high-temperature/high-pressure (HTHP) wells. The model calculates pressure profiles and frictional pressure losses along the mud circulating path, and mud rheological parameters inside and outside the drill string. Output from this model also compares temperature- and pressure-corrected values with non-corrected values.

17. Dynamic Kill for Slim Holes addresses the special concerns for safe hydraulics and well control in slim annuli. Conventional well-control techniques are based on the assumption that annular pressure losses are a small fraction of total circulating pressure losses. This assumption is often not valid in slim-hole wells due to high friction pressure losses for fluid flow in the annulus. This model includes correlations for calculating pressure drops in slim annuli. Dynamic well kill utilizes increases in ECD to overcome flowing formation pressure by quickly increasing the pump rate or rotary speed. The model generates a multiple-curve kill chart for a range of ECD changes.

18. Multiphase Flow Production calculates oil, water, and gas production rate, as well as pressure drop along the wellbore, based on wellbore configuration and reservoir properties. Production rate is calculated by solving reservoir and wellbore flow equations simultaneously. Results include pressure profiles along the

CHAPTER 4: DRILLNET ENGINEERING MODELS



wellbore, the liquid hold-up distribution, gas and liquid velocities, and flow regime map along the wellbore. It can be used for (1) velocity string design, (2) nodal analysis, and (3) gas-lift calculations. The model describes complex multiphase flow in reservoir, wellbore, choke, and surface pipe lines.

19. Wellbore Thermal Simulation is a downhole thermal simulation model for predicting temperatures in the well and surrounding formation. The model accounts for natural and forced convection, conduction within the wellbore, as well as heat conduction within the surrounding rock formation. A variety of well operations can be modeled including (1) liquid or steam injection, (2) liquid or steam production, (3) forward and reverse circulation with liquid and (4) forward circulation with gas.

Well Control

20. Killsheet Application is designed for well-control analysis for 3D wellbores (vertical and horizontal) for land and offshore applications. It includes both the Driller’s method and Engineer’s method (wait and weight). The model calculates all kill information and prepares a drill-pipe pressure schedule. Effects such as wellbore deviation, subsea BOP stacks, tapered drill strings, kill-mud weight margins, and circulating drill-pipe margins are included. The model also includes a simplified mode for use in training situations.

21. Kick Simulation describes complex multiphase flow that develops as a gas influx is circulated out of a well. It handles both the Driller’s and Engineer’s well-control methods and incorporates Bingham-plastic and power-law fluid models for frictional pressure calculations. The model calculates kill-mud weight, the drill-pipe pressure schedule, and the kill sheet. It predicts pressure changes and ECDs at the choke, casing shoe, wellhead, at the end of the well, and at any other specific point you specify (e.g., entrance to horizontal section). Maximum ECD along the wellbore is also calculated and compared with the pore- and fracture-pressure gradients. These results are useful for determining whether well-control equipment is adequate, along with kick tolerance.


555. PORE PRESSURE PREDICTION MODEL

Being able to determine and predict abnormal formation pressures is very important for drilling engineers, as being aware of the potential depths where abnormal pressures may be encountered can assist in the planning for proposed casing strings and will also ensure that a well is drilled both safely and economically. Failure to predict abnormally high formation pressures can result in fluid influx into the borehole, stuck pipe and in extreme cases kicks, blowouts and the loss of a well.

The DrillNET Pore Pressure modulel can be used to predict formation pressure. There are 5 different methods that can be used to predict pore pressure, and the method selected will depend on the input data available to the user. The different options available are detailed in this chapter.

The Pore Pressure Prediction option can be selected from beneath the MODELS, WELLBORE STABILITY options.

5.1 Input The input page for the Pore Pressure Prediction option is very similar to other typical DrillNET input pages. Until valid data values have been input, the standard DrillNET traffic light system operates with the tab(s) showing a red icon until the required data entry has been completed.

5.1.1 General Page

1) Pore Pressure Prediction Method Selection. Select the method to fit the porosity related data set you have available for predicting pore pressure. There are 5 different options available, selectable from the drop down list.

CHAPTER 5: PORE PRESSURE PREDICTION MODULE


Bulk Density. This prediction method can be used when cutting density data from mud logging services is available. Input data parameters are the Sediment depth and cuttings Bulk Density. In general terms, if the cuttings density decreases with increasing depth within a shale sequence, this would indicate that the cuttings contain more fluid and are less matrix supported. In this situation the shale could potentially be over pressured.

Modified d-Exponent. This prediction method can be used when actual drilling exponent data is available. This is derived from the drilling parameters Weight on bit (WOB), Rotary Speed (RPM), Mud Weight (MW), Rate of Penetration (ROP) and Bit Size. In an over pressured zone that is more fluid supported, the drill rate will usually increase resulting in a decrease in the d-exponent. A decreasing d-exponent is normally indicative of a potential increase in pore pressure.

Resistivity. This prediction method can be used when resistivity data from well logging services is available. Input data parameters are the Sediment Depth and Shale Conductivity. In areas with a potentially high pore pressure, the formation will be less compacted and more porous. This will result in a higher conductivity than normal due to the fluids present within the formation. In general, shallow formations containing more fluids will have a higher conductivity than deeper formations that are more matrix supported.

Interval Transit Time. This prediction method can be used when processed pre or post-drilling seismic data is available. Input data parameters are the Sediment Depth and Interval Transit Time. The Interval Transit time is a measurement of sound travel time over a set interval of formation. The sound speed will differ between formations that are porous and contain more fluids than a more compact less porous formation. Higher Interval Transit Time values will indicate more porous formations which may potentially be over pressured.




Pennebaker. This prediction method can be used when raw pre-drilling seismic data is available. Input data parameters are the Two-way Travel Time and VMS Speed.

As well as being able to estimate the pore pressure, the Pennebaker option also allows the Fracture Gradient to be calculated.

In all data input options, the units of measure can be changed as required using Options > Units, where either Custom, English or Metric units of measure can be selected for each parameter.

2) Correlation selection. Depending on the prediction method selected, there are different correlations available to process the data: (Options taken from the Red Book). e.g. Bulk Density displays

3) Parameters selection. Depending on the selected prediction method selected, different sets of parameters are needed. Select default, model, or data option depending on the availability of data. e.g. Bulk Density displays

Estimation Method Correlations Available Parameters

Bulk Density Boatman Pore Fluid Density Sediment Grain Density Porosity Decline Constant

Modified d-Exponent Rehm-McClendon Zamora

Pore Fluid Density d-Exponent Increase Constant

Resistivity Eaton Hottman-Johnson, US Gulf Coast Matthew-Kelly, South Texas Frio Trend Matthew-Kelly, South Texas Wilcox Trend Matthew-Kelly, South Texas Vicksburg Trend Matthew-Kelly, Louisiana Gulf Coast Fertl-Pilkington-Reynolds, South China Sea

Pore Fluid Density Shale Conductivity Decline Constant

Interval Transit Time Eaton Pore Fluid Density



Pennebaker Bell, US Gulf Coast Bell, West Texas Delaware Herring, North Sea Hottman-Johnson, US Gulf Coast Matthew-Kelly, South Texas Frio Trend Matthew-Kelly, South Texas Wilcox Trend

Pore Fluid ITT Matrix ITT a Matrix ITT b Porosity Decline Constant

Pennebaker Pennebaker Stress Ratio Pore Fluid Density ITT decline power-law index Depth threshold

4) Abnormal Pore Pressure Zone. There are two methods that can be used to create the Abnormal Pore Pressure depth ranges. These techniques are common to all of the Pore Pressure Prediction methods.

1. Enter Abnormal Pore Pressure Zones depth ranges manually in the table.

2. Select the particular points of interest graphically from the input graph by using the left mouse button and dragging a rectangle to enclose the points.

3. Once the zone has been selected, right click with the mouse, and from the popup menu select the option Refresh to update graph. Once refreshed, any abnormal pressure zones will display as red data points.




1. Multiple abnormal pore pressure zones can be defined either by specifying the depth range of interest or by selecting the points graphically. In this example a second zone has been outlined at a shallower depth that may indicate another abnormal zone.

5) Data Input. Data can be entered in the Data Input tables using the keyboard or cutting and pasting from spreadsheets or text files. Once valid input data has been entered, the General tab traffic light should turn green automatically . Alternatively press F9 to display the data values graphically.

6) Input Graphic. Input Graphic shows the data entered in the Input Data tables.

The following image shows typical date input and the input graphic when using the Bulk Density method for Pore Pressure prediction.



Once the required data has been input, click on the View Output icon to process the data and display the results.

5.2 Output




7) Analysis Output. The analysis table will show the predicted pore pressure for the entered depth range. Depending on the prediction method selected, this table may show more columns to include Porosity, Shale Resistivity, Vertical Overburden Stress and predicted Fracture Pressure.

8) Graphic Output. The resulting Predicted Pore Pressure curve is displayed in green for the depth ranges with normal pore pressures and in red for areas with predicted abnormal pore pressures. If the Pennebaker prediction method is used, the output graph will also show the predicted Fracture Pressure.

The following show typical example output using the different Pore Pressure prediction methods. The resultant output will vary if any of the correlation and parameters available within each Pore Pressure prediction option are changed.

Bulk Density

Modified d-Exponent

Resistivity



Interval Transit Time

Pennebaker


666. WELLBORE STABILITY MODEL

A wide variety of problems may occur during drilling/completion operations due to borehole instability. These include problems with:

High torque and drag

Bridging and fill

Stuck pipe

Directional control

Slow penetration rate

High mud costs

Cementing failures

Difficulty running and interpreting logs

Lost circulation

The Wellbore Stability model analyzes mechanical/chemical stability of vertical or inclined wellbores and can be used prior to actual field operations. A linear poroelasticity model is used to predict wellbore stability and ranges for stable mud weights or wellbore pressures. Stability designs of critical parameters are also provided.

6.1 Input

6.1.1 Project Page The Project input page for the Wellbore Stability model is very similar to the typical DrillNET Project page. See Section 3.2.1.

6.1.2 Survey Page The Survey input page for the Wellbore Stability model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

6.1.3 Formation Page The Formation input page for the Wellbore Stability model is similar to the typical DrillNET Formation page. See Section 3.2.5. There are important differences, however. For wellbore stability, more data are shown in the table than for other models that include formation data. For example, the upper table is as shown for the Hydraulics for Normal Circulation model; the lower table shows the additional parameters needed for Wellbore Stability.

Parameters in Typical Formation Data Table

CHAPTER 6: WELLBORE STABILITY MODEL


Parameters in Formation Data Table for Wellbore Stability

Formation Parameters

If a density log is unavailable, a rule of thumb of 1.0 to 1.1 psi/ft is generally a good approximation for Overburden Stress Gradient. In tectonically inactive areas, such as a young deltaic sedimentary basin, the effective Horizontal Stresses tend to be approximately equal and are related to vertical stress by Poisson’s ratio:

ffVminHmaxH pp1

The table shows horizontal stress gradients for several active drilling areas, assuming a normal pressure zone is present and = 0.25.

Drilling Area Horizontal Stress (psi/ft)

West Texas 0.622 Gulf of Mexico Coast 0.643 North Sea 0.635 Malaysia 0.628 Mackenzie Delta 0.628 West Africa 0.628 Anadarko Basin 0.622 Rocky Mountains 0.624 California 0.626

Azimuth of Maximum Horizontal Stress. This angle is between north and the direction of maximum horizontal stress (see figure). It is measured from north clockwise.

Pop-Up Estimation Utilities

Right-click over the Formation Data Table to access the pop-up menu. In addition to the standard features available for the Formation Data Table (see Section 3.2.5), several utilities are available under the option “Estimate” for help entering values in the table.

1. Pore Pressure Estimate – calculates pore pressures based on a constant gradient/fluid density or based on empirical data from various drilling areas around the world. Open the utility by selecting it from the right-click menu. Select a gradient from the drop-down list for existing areas, or enter a value for constant fluid gradient or constant fluid density. Click [Calculate] to display the corresponding pore pressure distribution in the table. To export these data to the main Formation Data table, click [Apply].

2. Overburden Estimate – calculates overburden pressure based on a constant

West

South

North

East

Vertical H max

Azimuth of H max




gradient/bulk density or based on one of several empirical correlations (Amoco, Bell, Eaton, Gardner or Pennebaker). Select to enter a value for constant gradient/bulk density or select a correlation. Eaton’s correlation and Gardner’s correlation apply to various drilling areas. Some correlations require additional input parameters. After all quantities are entered, click [Calculate] to display the corresponding overburden distribution in the table. To export these data to the main Formation Data table, click [Apply].

3. Horizontal Maximum Stress Estimate – calculates horizontal maximum stress based on a constant gradient, average of overburden and horizontal minimum stress, constant tectonic effect, or constant percentage in anisotropy. Within the utility, select to enter a constant value or select to use average of overburden and horizontal minimum stress. Click [Calculate] to display the corresponding horizontal maximum stress distribution in the table. To export these data to the main Formation Data table, click [Apply].

4. Horizontal Minimum Stress Estimate – calculates horizontal minimum stress based on a constant gradient; an estimate method (using the matrix stress coefficient, Poisson’s ratio, or internal friction angle); or on an empirical correlation (Christman1, Eaton2, Hubbert-Willis3, MacPherson4-Berry, Matthews-Kelly or Pennebaker). Select to enter a value for constant gradient/bulk density or select a correlation. Eaton’s correlation and Matthews-Kelly correlation apply to several drilling areas. Some correlations require additional input data. Click [Calculate] to display the corresponding horizontal minimum stress distribution in the table. To export these data to the main Formation Data table, click [Apply].

5. Geothermal Temperature Estimate – calculates a complete geothermal temperature profile based on the surface temperature and a geothermal gradient that you specify.

Within these Estimate windows, after you select models and enter (or select) required parameters, click [Calculate] to fill in the table within the window. After you review the data, you can export all the data to the Formation Data Table by clicking [Apply]. Click [Cancel] to close the estimate window and return to the Formation Data Table without changes.



6.1.4 General Page

1) Rock Properties Table. This table lists rock properties by depth for formations along the wellbore. Note that it is not necessary to list data for all formations from the surface to the bottom of the wellbore. Only those formations in your Zone of Interest need to be described. Above the table, enter the vertical depth for the top of the first formation listed in the table.

Poisson’s Ratio. Measured values for consolidated sedimentary rocks vary from 0.18 to 0.27 (see table).

Poisson’s Ratio Tensile Strength Shale 0.20–0.47 (psi) (MPa) Siltstone 0.25 Shale 14.5–1450 0.1–10 Limestone 0.16–0.23 Siltstone N/A N/A Sandstone 0.17–0.3 Limestone 725–2900 5–20 Sandstone 522–3626 3.6–25

Tensile Strength. Typical tensile strengths for common rock types are shown in the table above. Normally, tensile strength does not have a significant impact.

Internal Friction Angle. The relationship between cohesive strength, uniaxial compressive strength and internal friction angle is:

sin1

cosS2C 0

0




Wellbore Wall

Collapse Area

where C0 is uniaxial compressive strength and S0 is cohesion.

Internal Friction Angle (deg) Shale 15–65 Siltstone 50.2 Limestone 35–60 Sandstone 20–70

Cohesive/Compressive Strength. The relationship between cohesive strength, uniaxial compressive strength and internal friction angle is presented above. Only one of the two strengths (cohesive or uniaxial compressive) is required. Select one parameter and enter a representative value. Typical values are presented in the table.

Rock Type Cohesion Uniaxial Compression

(psi) (MPa) (psi) (MPa) Shale 41–2901 0.28–20 691–32,927 2–227 Siltstone 725 5 3626–5512 25–38 Limestone 493–7253 3.4–50 6910–37,569 20–259 Sandstone 12–5947 0.08–41 73–37,279 0.5–257

Allowable Breakout Width is the circumferential angle of the allowable collapse area at the wellbore wall. This concept is based on the observation that an isolated local compression failure (=0) does not necessarily lead to wellbore instability. Usually is no larger than 90. If a value for the breakout width is not specified, a default value of 0 will be used.

Biot’s Poroelasticity Constant, , is defined as:

SK

K1

where K and Ks are the bulk modulus of the solid skeleton and interpore material, respectively. Values of this parameter range between 0 and 1. From Neville Price’s result, for most rocks, Biot’s parameter is between 0.95 and 0.97. The default value in this program is 0.96.

Shale Activity, or water activity of shale, can be thought of as the “escape tendency” of pore fluid in shale. It is defined as the ratio of the fugacity of water in a shale system to the fugacity of pure water. Values for water activity for some shales are listed in the table.

Shale Type Water

Activity Activity

Index Pierre 0.96 4.5 Wellington 0.96 4.5 Pleistocene (GoM) 0.89 3.7 Oligocene 0.88 3.6 Cretaceous (North Sea) 0.80 2.8 Cretaceous (North USA) 0.72 2.1 Kimmeridge (North Sea) 0.62 1.4

Membrane Efficiency. Highly compacted, clay-rich shales, when in contact with water, can provide a non-ideal semi-permeable membrane which is permeable to water and, to a lesser extent, to hydrated solutes. The membrane generates an osmotic pressure which is different from that predicted for an ideal semi-permeable membrane system. Membrane efficiency describes the effectiveness of the semi (non-ideal) membrane system and is defined as:



0vJpredictedosmotic

observedosmotic

P

P

where Jv is the net flux of solution across the membrane. Reported values of membrane efficiency range from 0.01 to 0.2. Both mud and shale affect membrane efficiency.

2) Zone of Interest. Specify the MD range of interest for the current calculation sequence. Calculated results based on multiple depths will be displayed for the range you define. The lower bound is also the initial MD displayed in the Safe Mud Weight output windows (see Sections 6.3.2 and 6.3.3). True vertical depths (TVDs) of the upper and lower bounds are calculated automatically.

3) Drilling Conditions. Select Permeable Mud Cake when the mud cake is assumed to be permeable. Unselect Permeable Mud Cake where the mud cake is assumed to be perfect (impermeable). Biot’s Poroelasticity Parameter is required for permeable mud cakes.

Mud Salt Concentration. Mud/water activity can be thought of as the “escape tendency” of the water phase in drilling fluid. It is defined as the ratio of the fugacity of water in a system to the fugacity of pure water. There is an inverse relationship between solute concentration and water activity.

Water activity values for several common salt solutions are listed in the table (from Hale and Mody (19935)).

Salt Conc. (%) w/w

Water Activity CaCl2 NaCl KCl

0 1.00 1.00 1.004 0.99 0.98 0.986 0.98 0.97 0.978 0.97 0.95 0.97

10 0.95 0.93 0.9612 0.93 0.92 0.9614 0.91 0.90 0.9316 0.89 0.88 0.9218 0.86 0.85 0.9120 0.83 0.83 0.8922 0.80 0.80 0.8824 0.76 0.78 0.8626 0.72 0.75 0.8428 0.6830 0.6432 0.5934 0.5536 0.5038 0.4440 0.39

4) Calculation Options. The Mohr-Coulomb criterion is the most commonly used criterion to define the collapse of rock. It can be expressed in terms of principal stresses as:

sin1

cosS2p

sin1

sin1p 0

f3f1

where and S0 are internal friction angle and cohesion of the rock, respectively. The second term on the right is simply uniaxial compressive strength of the rock. The Drucker-Prager criterion is expressed in terms of principal stresses as

foct0oct pm

where 0 and m are material parameters. By definition




3

213

232

221

oct

,

3321

oct

When using this criterion, one has three choices of the parameters:

Innersin39cosS6,sin39sin6m

Middlesin3cosS22,sin3sin22m

Outersin3cosS22,sin3sin22m

200

2

00

00

The main property of the Mohr-Coulomb criterion is its insensitivity with respect to the principal intermediary component. The Drucker-Prager criterion does not introduce any dissymmetry. Out of the four criteria, the inner and middle Drucker-Prager criteria predict similar results and are too conservative. The outer Drucker-Prager is the least conservative. Generally speaking, the Mohr-Coulomb is recommended as the most realistic.

Safe Mud Weight Lower Bound. In most situations (i.e., overbalanced drilling), engineers want to maintain mud pressure higher than pore pressure. Consequently, pore pressure is almost always used as the lower bound for safe mud weight. In other cases, such as underbalanced drilling or if engineers want to see the pure mathematical solution, select “none” for lower bound.

Safe Mud Weight Upper Bound. This limit was added at the suggestion of previous users. Most engineers believe that mud pressure should not exceed fracture pressure (which is often thought to be the same or very close to the minimum horizontal stress). This limit can serve as a type of safety factor so that an upper bound could be defined because the rock mechanics solution may indicate a very high maximum safe mud weight.

6.2 Output Output for the Wellbore Stability Model includes results under two tabs:

1. Summary – Displays values for key wellbore stability parameters and results

2. Graphs/Tables – A typical DrillNET multi-featured output display allowing selection of individual or multiple graphs (see Section 3.3). Quantities shown on the output graphs and tables can include pore pressure, overburden stress, horizontal maximum stress, and horizontal minimum stress. You can select/unselect any of the these by accessing the Output Options window through the Options menu “Model Options.”

3. Stability Chart – a multiparameter graph of significant wellbore stability results. All important information is combined for display. The defined rock formations are shown in the background. The expanded wellbore trajectory is plotted with the same scale in TVD and horizontal displacement to show the effect of well inclination. Rock properties (friction angle, cohesion, tensile strength), pore pressure, in-situ stresses, direction of horizontal maximum stress, and safe mud weight are all plotted against TVD. The chart makes it is easy to see how well angle, rock properties, and formation pressure/stresses affect the range of safe mud weights.



6.3 Special Functions

6.3.1 Tool-Bar Icons Special tool-bar icons are provided when the Wellbore Stability Model is selected. The special icons include:

Sensitivity Analysis. Opens the Sensitivity Analysis window (see Section 6.3.2) for quickly gauging the impact of changes in a wide variety of parameters on safe mud weight for the entire wellbore.

Single-Depth Analysis. Opens the Single-Depth Analysis window (see Section 6.3.3) for calculating detailed results for safe mud weight for a single depth along the wellbore.

6.3.2 Sensitivity Analysis Window The Sensitivity Analysis window is a secondary output window used to analyze the relative impact of changes in

individual parameters while other parameters remain constant. This window is accessed by clicking or selecting “Sensitivity Analysis” from the Tools menu.

The Sensitivity Analysis window calculates safe mud weight for a specific depth. The range of stable mud weights is shown in an X-Y area graphic format. The green area indicates stable mud weights with wellbore inclination (0–90º). A variety of parameters can be changed to immediately gauge the impact on the stable mud weight envelope. The parameters are listed on three tabs (page 1 = General; page 2 = Pore Pressure/In-situ Stresses; page 3 = Rock Properties). Any parameter shown can be varied independently by clicking the spinner . After each click, the program will recalculate the safe mud weight range and then update the graph. Click [Restore] to reset all parameters to their default values (the values you assigned in the Formation Data table in the input window).




Sensitivity Analysis – Page 1

Sensitivity Analysis – Page 3

From this sensitivity analysis window, users will be able to quickly find how a selected parameter or a selected option affects the range of safe mud weights (as a function of well inclination or as a function of well azimuth). This may be used as a convenient wellbore stability design tool.



6.3.3 Single-Depth Analysis Window The Single-Depth Analysis window also calculates safe mud weight for a specific depth. The range of stable mud weights are shown in an X-Y area graphic format and listed in a detailed table. These output data are more detailed for a single depth than those provided in the Sensitivity Analysis window (see Section 6.3.2).

The area between the green and blue lines represents stable mud weights with wellbore inclinations of 0–90º. A variety of parameters can be changed to immediately gauge the impact on the stable mud weight envelope. The parameters are listed on three tabs (page 1 = General; page 2 = Pore Pressure/In-situ Stresses; page 3 = Rock Properties). Any parameter shown can be changed independently by clicking on the existing number and entering a new value. Click [Calculate] to update the graph and table after you make any changes to the data.

Single-Depth Analysis – Page 1



The purpose of this utility is to present a more detailed description of safe mud weight window for a specific depth. Data in this window can be either from the main input window or completely new data. Therefore, this can be used as independent tool to perform wellbore stability analysis for a single depth.

1 Christman, S. (1973). Offshore fracture gradients. Journal of Petroleum Technology, pages 910–914. 2 Eaton, B. A. (1969). Fracture gradient prediction and its application in oilfield operations. Journal of Petroleum Technology, pages 1353–1360. 3 Hubbert, M. K. and G., W. D. (1957). Mechanics of hydraulic fracturing. Society of Petroleum Engineers Journal, Transactions of AIME, 210:153–168. 4 MacPherson, L. A. and Berry, L. N. (1972). Prediction of fracture gradients. Log Analyst, 12. 5 Hale, A.H. and Mody, F.K., 1993: “Mechanism for Wellbore Stabilization With Lime-Based Muds,” SPE/IADC 25706, presented at 1993 SPE/IADC Drilling Conference, Amsterdam, February 23–25.


777. WELL PLANNING/PROJECTION MODEL

Although the Well Planning/Projection model is easy to use, it is a sophisticated software application for generating wellbore surveys. This model manipulates well trajectory data including: survey creation, survey data input, survey data editing, well path planning, and well path projection. The model helps you: (1) design well paths during the well-planning stage, (2) project well paths to determine if targets can be achieved using existing BHAs, (3) determine build rates needed to hit targets, (4) determine if well paths remain within legal or defined boundaries, and (5) print/graph data for daily morning reports (including wall-plots).

7.1 Input

7.1.1 Project Data Window The Project Data window for the Well Planning/Projection model is different from DrillNET’s typical Project page (see Section 3.2.1). For this model, project data are accessed in a separate window that is opened by clicking from the Well Planning/Projection model main window. The Project Data window is organized under two tabs: Trajectories and General.

Trajectories Page

The Trajectories page is used to manage all open trajectories that may be used in the project as the start for the next section, or as a basis for comparison. Up to 30 different trajectories may be selected and entered for comparison.

In Design Trajectory

One trajectory must be selected as the primary active survey by checking it in the column “In Design.” Data from this trajectory will be filled in the survey table of the design window and its last survey station will be used as the current start for next section design in the Applications window (see Section 7.1.2).

CHAPTER 7: WELL PLANNING/PROJECTION MODEL


Active Trajectories

Trajectories that are selected as “active” will be displayed in 2D and 3D survey plots along with the single “in design” trajectory. If a trajectory in the table is not selected as active, it will remain listed in the table but not be shown in plots.

From Galaxy Database Trajectories

If the column “From Galaxy” is checked on a row, you can then access a well project from the DrillNET Galaxy database (see Section 25.1). After you check the third column, column 4 (“Well Name”) and column 5 (“Trajectory Name”) become drop-down lists that allow you to select any trajectory currently in the database. (Note: you cannot edit the Galaxy database from this window.)

Importing Trajectories

If “From Galaxy” is not checked, then you can import a new trajectory from a survey file. First, select “Active” on the next open row in the trajectory table. Then, click the [Import…] button at the bottom of the page to import data from existing survey files (*.SDI, *.TXT, or *.XML formats). Data will be imported into the current active row of the table (where the cursor is positioned). Options for importing survey files are described in detail in Section 3.2.2.

Defining New Trajectories

To specify a new trajectory, select “Active” on the next open row in the trajectory table. Then, enter data in that row, including trajectory name and start coordinates. Select “In Design” if you want these start coordinates to be used as the start of the next section of well to be designed.

Viewing and Exporting Trajectories

Click the [View…] button to view the currently selected survey data in a table in a separate window. You cannot edit the survey data from this window.

You can export a survey to a file (*.SDI or *.XML format) by clicking [Export…]. Petris-formatted survey files (*.SDI files) can be opened by other MTI software based on the Visual Basic 6 platform.

Sidetracks

The Sidetrack feature is used to truncate (trim back) an existing survey from a specified point. First, select the survey to be truncated by clicking on its row. Then click [Sidetrack…] to open the Sidetrack window (see below).




Fill in the sidetrack MD in the box. The survey data shown in the table will automatically be trimmed back to the sidetrack depth you specified.

Click [Restore] to undo the survey truncation, that is, to restore the survey to its original complete condition. Click [Cancel] to close this sidetrack window without keeping changes. Click [OK] to export the truncated survey back to the Trajectories page in the Project Data window. Select this modified survey as the “In Design” survey to use it as the start point for the new well section.

General Page

The General page within the Well Planning/Projection Project Data window displays information for documenting the project, along with coordinates for one or more targets to be intersected by the well path. Project Information is saved and displayed on other Project pages for documentation. Target data are entered here and can be used to store several targets together to better organize the project. These targets will be listed for quick selection in the drop-down box on the Applications page (see Section 7.1.2). Casing data are retrieved from the standard Wellbore input page (see Section 3.2.4) and displayed here for the purpose of annotating the wall plot. These casing data may not be edited here.



7.1.2 Application Window The Application Window is the primary design tool in DrillNET for creating simple or complex well paths. There are no tabs separating pages of input data as in other DrillNET engineering models; all types of well trajectories are created on this multi-function page.

1) Well Plan Current Start. Geometric coordinates of the start of the next section of the well path are automatically displayed. After you have calculated one section of the well path, the start coordinates are defined as the end of the previous well path and cannot be changed. (Cells displayed in DrillNET with a yellow background cannot be edited by the user.)

Start Coordinates for New Wells

If the well path is new, coordinates for the start position of the first section will be set to zero for all values by default. If you prefer to specify non-zero starting coordinates for a new well, define the trajectory by opening the Project Data window (see Section 7.1.1). Enter a new trajectory name and specify the coordinates. A trajectory selected as “In Design” will be displayed in the Applications window after you close the Project Data window.




Adding New Sections onto Existing Wells

To add to an existing well, first open the Project Data window and enter the existing trajectory into the table by selecting it from the Galaxy Database or by importing it from an existing survey file. Any trajectory specified as “In Design” in the well planning Project Data window will be displayed as the current start for the new well path section.

2) Well Plan Design Tools. A range of powerful design options are available under the “Design Tool” drop-down box. Basic tools for designing well paths fall into two categories: 2D and 3D.

For 2D (constant azimuth) well plans, four types of basic shapes are provided: (1) build section and hold direction (“J” shape), (2) build section and drop (“S” shape), and (3) build section followed by a second build section and (4) single projection. The single projection tool is used to design a simple uniform section of wellbore with a constant build rate throughout. Select whether the target is specified by MD, inclination, or TVD. Next, enter the build rate.

For 3D (changing azimuth) well plans, five methods of 3D projection are provided: (1) single projection, (2) curved section only, (3) curved section with a given alignment, (4) curved section, straight section and curved section, and (5) landing at a specified depth.

Design Tool Definitions

Click help next to the design tool drop-down box to open the Design Tool Definitions window (below). The definition of parameters required to precisely specify each well type are shown for reference. Click on a tool name in the upper left corner to display an illustration of that well path design and the corresponding parameters.

Abbreviations include:

Azi = azimuth

BR = build rate (rate of change in inclination)

DL = dog leg (total rate of change in direction, including inclination and azimuth)

HD = horizontal displacement

Inc = inclination

L = length

MD = measured depth

TFO = tool-face orientation

TR = turning rate (rate of change in azimuth)

TVD = true vertical depth

VS = vertical section

?



West

South

North

East

TVD

Azimuth ofVertical Section

3) Well Plan View Pane. After any section of the well is designed and the plan data calculated, the new well path is displayed in the two view panes. The left graph is the Plan View, which shows the well path as viewed from overhead looking down (that is, no depth information). The right graph is the Section View, which is a side view projection of the well path rotated to the vertical plane with the default azimuth of vertical section (azimuth angle is given in the graph title).

The default azimuth angle (called “Azimuth of Target” in the Edit menu) is determined by constructing a vertical plane that intersects a line that passes through both the start point and target.

To select a different azimuth angle, choose “Azimuth of Vertical Section” “Other…” in the pop-up Edit menu. A box is displayed for entering a new azimuth angle.

Editing the Survey Graphs

The Plan and Section View graphs can be copied and printed, as well as opened as a separate window for easier viewing. Right-click the mouse over the graph to open the Edit menu. Select “Display in Separate Window” to open a new window that is easy to review. Options on this pop-up menu are described in Section 3.4.

4) Well Plan Next Target. To specify the location of the next target to be intersected by the wellbore, first select between two options for specifying the end point of the section currently being designed (NS/EW or polar coordinates). The NS/EW option uses compass direction, where the surface location is the coordinate origin. The polar option is to specify horizontal displacement (HD) and azimuth. After selecting your preferred option, enter the required location data in the text boxes.




+N/-S

Dis

tWest

South

North

East

VerticalTarget

TVD

+E/-W Distance

Azimuth

Input Coordinate

System

Horiz Displacemt(HD)

5) Well Plan Existing Targets. If you specified one or more sets of target coordinates in the Project Data window (in the Targets table on the General page (Section 7.1.1)), these optional targets will be displayed in the drop-down box. If you select a target from the list, the corresponding coordinates will be filled in. This feature makes it easier to select and compare among multiple targets of interest. Targets on the list may represent required targets in the user’s well design plan.

6) Well Plan Design Parameters. Basic well-plan geometric parameters are entered in these boxes. The parameters listed and the number of unknowns will vary depending on the current model design tool (see ). For most 2D tools, two of the geometric parameters are selected as unknowns. DrillNET will vary these two parameters until it converges on a solution. Enter values (or estimates) for the remaining constants.

Click to create the well plan section after all design parameters are entered. If the current values will not converge on a solution (regardless of the values of the unknowns), a message will pop up (“No solution exists for the input parameters”). For

these cases, change the constants as required and click again. To

visualize which constants are preventing convergence, click to open the Wizard window (see Section 7.2.2).

Note that you can undo the newly created section by clicking . This feature allows you to try several combinations of parameters as desired.

7) Well Plan Cut-Point Table. The well plan table presents a summary of the well path survey as it is generated throughout the entire design process. This abbreviated survey consists of “cut points,” that is, essential survey data where well path direction changes or a build section stops or starts. After each design is created, the new cut points are appended to the table. To convert the survey data to a normal detailed survey, use the function Edit Complete Survey (see Section 7.2.7) by right-clicking over the table.

Well-plan data for each survey station depth are presented in 12 columns, along with another column for comments. Use the horizontal scroll bar to view all columns. These data may not be edited here (except for the right-most column “Comments”).

Edit Menu for Cut-Point Table

Right-click over the cut-point table to open its special edit menu and then select the desired option. Options for editing survey data are not available here. To edit the survey, open the “Edit Complete Survey” window.


2. “Print Table…” will print only the current data table. The print control window pops up for selecting a specific printer.


4. “Display in Separate Window” opens a new window that contains only the current data table. You can maximize the new window to see all (or most) of the rows without needing to scroll horizontally.

5. “Truncate Design Results…” opens a window that allows you to cut away (discard) the lower section of the well path for designing kick-off points for sidetracks. See Section 7.2.6.

6. “Edit Complete Survey…” opens a window with the entire survey displayed (including cut points and all fill-in survey positions). In this window, all survey parameters can be edited as desired. See Section 7.2.7.



7. “Export…” allows you to save the survey displayed in the cut-point table separately as a DrillNET project file (*.XML) or as a Petris survey file (*.SDI) for importing in other DrillNET projects and Petris software.

Designing the Well Path in Sections

To develop a complete well plan in multiple stages, enter specifications for start/end points on the design page.

Click to generate the next section. Survey points will be added below those already in the table, that is, the well path sections will be “threaded” together. To clear the most recently designed section of the well plan from the table, click undo .

7.2 Output/Special Functions

7.2.1 Tool-Bar Icons Special tool-bar icons are provided when the Well Planning/Projection Model is selected. These are displayed on the right side of the tool bar and include:

Project Data. Opens the Well Planning/Projection Project Data window (see Section 7.1.1) for entering basic project identification and for selecting trajectories for display.

Make Design. Calculates a new well path section based on current input parameters. Results are displayed in the table at the bottom of the Application window.

Undo Design. Removes the latest (most recently calculated) well path from the table and returns the Application window to its previous settings. Only functions after a design has been calculated by clicking “Make Design.”

Redo Design. Restores the previously undone well path. Only functions after a design has been calculated by clicking “Make Design” and then removed by clicking “Undo.”

Design Wizard. The wizard (see Section 7.2.2) is a useful graphical tool for discovering which parametric values are preventing the well path from being calculated successfully. In many cases, first estimates for well path design constants entered will not converge on a solution, regardless of the values the computer assigns to the two unknown quantities. If a solution cannot be devised, a message (“No solution exists for the input parameters”) will pop up after you click “Make Design.” To more quickly discover why the well path cannot be calculated, go to the Wizard and change the lengths of the segments, displacement of the end point, etc., to determine values that are “in the ball park” (relatively close to a valid solution).

3D Path View. Opens the 3D Path View window (see Section 7.2.2) for viewing the current well plan along with all other trajectories currently selected in the Project Data window.

Example. Automatically fills in a set of input values for illustration of well path types. After you select a design type from the drop-down box, click the “Example” icon to fill in values, and then click “Make Design” to create the example well plan.

Special Applications. Opens a special window (see Section 7.2.4) with advanced design tools for (1) designing a 2D trajectory that passes through an array of targets points and (2) designing a 2D trajectory that passes through an array of pay zone beds.

Parameter Estimate. Opens the Parameter Estimate Utility window (see Section 7.2.5) for rapid calculation of build rate, TFO, and other critical parameters. A variety of utilities are provided for users.

7.2.2 3D Path View Window After any section of the well is designed and the well plan calculated, the new well path may be viewed in several graphical formats. One special option is the 3D View, which is accessed by clicking . This option shows the well path inside an isometric cube with N/S and E/W projections also plotted. Up to 30 trajectories may be viewed




together in the graph. Every trajectory marked as “Active” in the Project Data window (see Section 7.1.1) is shown and labeled.

The cube can be rotated in space to provide the best view possible. To rotate the cube about the vertical axis, click on the bottom scroll bar. To rotate the cube about the horizontal axis, click on the right scroll bar.

Survey Graph Edit Menu

You can save, print and edit the survey graph in various ways by opening the pop-up edit menu. Right-click over the graph area to open the menu and then select the desired option.

1. “Save Picture As…” allows you to save the current graph for opening in other applications. A variety of graphic formats are provided as options (gif, jpg, wmf, etc.).

2. “Print Picture…” will print only the current graph. The print control window pops up for selecting a specific printer.

3. “Print Preview Picture…” opens the Print Preview window with the current data table displayed. If the layout is satisfactory, click the print icon in the window to send the document to your default printer.

4. “Copy” copies the current graph to the Windows Clipboard.

5. “Add Text Box” creates a text box within the graph that can be moved and resized. Click inside the new text box to add text. Right-click on the text box to format the text. Resize text boxes by moving your cursor



over the borders of the box. The cursor changes shape for each function: to move the box, to raise/lower the lower border of the box, and to move the right border to the right or left.

6. “Delete Text Box” removes the current text box from the graph.

7. “Display in Separate Window...” is inactive in this option.

8. “Display” allows specific well paths to either be viewed or hidden. Well paths to view or hide are selected from the list of available wells.

9. “Focus on” allows one specific well to be viewed as a selected well and all other wells are shown as greyed out well paths in the GUI.

10. “Options” opens a submenu with various options for changing the display of the survey graph. Currently selected options are checked. Click any option to select (or unselect) it.

11. “Rotate around vertical axis” rotates the survey cube one complete revolution about the vertical axis. (Note that the cube can be rotated incrementally by clicking on the scroll bars.)

12. “Rotate around horizontal axis” rotates the survey cube one complete revolution about the horizontal axis.

7.2.3 Well Path Design Wizard The Well Path Design Wizard window is an aid in determining reasonable (feasible) design parameters for entering into the well-plan parameters tables for 2D design tools on the Applications window (see Section 7.1.2). The Wizard

is opened by clicking the icon. Note that the Wizard is for 2D well paths and is not available for all well path

designs. The icon will be displayed as disabled ( ) when the Wizard is not available.

When you are creating new sections of well paths in the Application window, sometimes the first set of parameter constants you enter (including well section lengths, build rates, and inclinations) do not lead to a solution. After you

enter values and click the make design icon , the program may respond with the message “No solution exists for the input parameters.” Sometimes it becomes obvious after consideration why the well cannot be assembled as specified (for example, the length of an inclined/horizontal section you specified does not provide enough space for




a turning section). For other cases, it is more challenging to understand why a solution is impossible. The Wizard can be used to visualize the well components and determine approximate geometric constants that will lead to a valid solution.

1) Wizard Graphics Window. Click on and move the well straight sections (the lines) and the turning rates (the circles). Assemble the well path components into the approximate orientation of the desired well path. Click and drag on the end of a line or the edge of a circle to change its length or size. Move the end of a line to change its inclination. As you manually change parts of the well path, numeric values in the boxes are updated automatically.

2) Wizard Parameters Table. When the Wizard is first opened, values in the table are taken from the Applications window. These numeric values are automatically updated as you modify the shapes and lines in the graphics window. Values for these parameters can also be entered directly into the table. The graphics shapes will then automatically reflect any newly entered values.

The text boxes in the “Coordinates” section display the horizontal displacement and vertical displacement of the target, and location (x and y represent the horizontal and vertical coordinates, respectively) of the movable end point of any straight line section when the user drags that movable point.

After you have completed a well path design, click [Apply] to export the current values back to the well plan design window.

7.2.4 Special Applications Window The Special Applications window provides new advanced tools for well plan design. They are separated from the basic 2D and 3D tools used in the Applications window because they are non-standard tools not available in all well

plan design programs. This special design window is accessed by clicking the icon.



2D Point Targets

The 2D Point Targets design tool can be used to design a 2D trajectory that passes through an array of targets specified by the user. The design is constrained to lie in a single plane (i.e., constant azimuth). For each target, you must specify a minimum dogleg (DL) each curved section. When a curved section is constructed between two points, normally there can be an infinite number of solutions for the curve corresponding to different DL severities. Smaller DL’s mean a larger turning radius. Since drillers usually do not prefer an unnecessarily long curve section, a specified minimum DL helps limit the range of possible curved sections.

Click help next to the “Select Application” drop-down list to open the Design Tool Definitions window which defines parameters needed for this tool.

?




2D Dipping Bed Pay Zones

The special 2D Dipping Bed Pay Zones design tool can be used to create a 2D trajectory passing through an array of pay zone targets. In the table you specify dip angle of each bed, entry point location, and hold distance. Minimum dogleg (DL) values give lower bounds for dogleg severity for each curved section.

Click help next to the “Select Application” drop-down list to open the Design Tool Definitions window which defines parameters needed for this tool.

Editing the Graphs

The Plan and Section View graphs can be copied and printed, as well as opened as a separate window for easier viewing. Right-click the mouse over the graph to open the Edit menu. Select “Display in Separate Window” to open a new window that is easy to review. Options on this pop-up menu are described in Section 3.4.

?



7.2.5 Parameter Estimate Utility Window

BHA Build Rate (Baker Hughes INTEQ)

The BHA Build Rate utility is based on the assumption that the BHA drills along a circular arc, and is used to calculate the radius of this arc. Tilt angle of the bit axis, with respect to the drillstring axis, , is equivalent to the angle formed by lines drawn perpendicular to the top/bottom stabilizer segment (L1), and the bottom stabilizer/bit segment (L2). This calculated dogleg based on BHA geometry is termed “Geometric DL.”

Bit geometric factor (BGF) is an experimentally determined ratio. It is affected by bit type, formation, and inclination. If the tool is actually drilling along a circular path, BGF is 1.

BHA Total Build Rate (DL) = BGF x Geometric DL

1) Parameter Estimate Utility Select Function. Nine estimation utilities are provided with the Well Planning/Projection model. Click the select button to bring that utility to the top of the stack.

2) Parameter Estimate Utility Input Parameters. All parameters required for the estimation calculation should be entered in the white text boxes. After all entries are complete, press [Calculate].

3) Parameter Estimate Utility Results. Results of the calculations within each utility are presented in yellow output boxes. These data may not be edited.

4) Parameter Estimate Utility Control Buttons. [Example] fills in a set of input data into the current utility to illustrate its use. (The example data are for illustration only and should not be considered as preferred values.) Click [Calculate] after all required input data are entered in the white text boxes on the current page. After calculation, results will be presented in the yellow box(es). [Close] returns to the Application window of the Well Planning/Projection model.

2D Build Rate

This utility provides a quick estimation of inclination build or drop rates in two dimensions. The user inputs both start and end points for inclination and TVD .




2D Turn Rates with Fixed Inclination

This utility calculates turning azimuth and turning rate to bypass an obstacle with a given horizontal offset. Inclination of the path remains the same, which means that the path remains in a horizontal or inclined plane. The user can execute a projection twice so that the path turns back and aligns with the original path.

Build Rate and Turn Rate vs TFO

The BR (inclination build rate) and TR (azimuth turn rate) are calculated if the DL (BHA total build rate), current inclination, and TFO (tool-face orientation) are known. This utility also outputs a table varied with inclination.

TFO and Turn Rate vs Inclination

The TR (azimuthal turn rate) and TFO (tool-face orientation) may be calculated if the DL (BHA total build rate), BR (inclination build rate), and current inclination are known. This utility also presents a table that is current inclination versus TR and TFO.

TFO and Dogleg

This utility helps estimate input data for a 3D projection with the oriented BHA method. The user provides the starting and ending points, and the program calculates the estimated TFO and DL.

TFO and TVD

This utility is similar to the previous utility (TFO and Dogleg). For this case, the user inputs the dogleg and the program calculates TVD for the end point.

Inclination (Inclined Pay Zone)

For a pay-zone formation with a dip angle, final inclination for a horizontal well should be adjusted to keep the wellbore in the pay zone. Formation dip angle, down dip azimuth, and wellbore azimuth determine the final wellbore inclination.

Azimuth (Block Coordinate System)

This utility is used to calculate azimuth angles in block coordinate systems (see figure). If the distance from the start point is to the block North and East lines, enter positive input values. If distance from the point is to the block South and West lines, enter negative input values.

After entering all required data, press [Calculate]. The resultant azimuth angle will be displayed at the bottom of the page.

Calculating Wellbore Inclination in an Inclined Pay Zone

Pay ZoneInc

Formation Dip Angle

Azi = Down Dip Azimuth– Wellbore Azimuth

Azimuth

Surface

Target

Block North Line (+)

Blo

ck East L

ine (+

)Blo

ck W

est

Lin

e (-

)

Block South Line (-)

Block Coordinates

Side Turn with Constant Inclination

Inc

Start Point

EndPoint



7.2.6 Truncate Design Results Window A well path survey displayed in the Application window (see Section 7.1.2) can be viewed and truncated to allow sidetracking the well from a shallower depth as required. The Truncate Design Results window is accessed by right-clicking over the Cut-Point Table on the bottom of the Application window and selecting “Truncate Design Results…” from the pop-up menu.

To truncate the current survey, enter a new final MD in the box in the lower left corner. Click [Truncate] to delete all survey stations below that MD. Click [Restore] to undo the changes and display the complete original survey. Click [OK] to close this window and export your truncated survey back to the Application page for further editing as needed.




7.2.7 Edit Complete Survey Window A newly created or imported well path survey can be edited as required. The Edit Complete Survey window is accessed by right-clicking over the Cut-Point Table on the bottom of the Application Window and selecting “Edit Complete Survey…” from the pop-up menu.

Any parameter can be edited by entering new values or pasting values copied from another source.

Survey Tie-In

New or imported survey data can be “tied into” another existing survey. Selecting a tie-in station allows you to specify exact coordinates for TVD, N/S, and E/W at that survey station depth. After selecting one tie-in station, enter the new desired values for TVD, N/S, and E/W. Then select “Calculate” from the pop-up menu to recalculate the table based on the new tie-in station.

Edit Menu for Edit Complete Survey Table

Right-click over the survey table to open its special edit menu and then select the desired option.





5. “Insert Row(s)” inserts a blank row directly above the row the cursor is positioned in. To insert multiple rows, select cells from as many rows as desired before you open the edit menu.

6. “Delete Row(s)” deletes all rows of the current data table that have any cells selected. It does not matter whether only one cell,



multiple cells, or the entire row is selected.

7. “Append Row(s)” is used to add new rows to the end of the data table. The default number of rows is 100 for most data tables. The number of rows can be increased/decreased as needed.

8. “Print Table…” will print only the current data table. The print control window pops up for selecting a specific printer.


10. “Display in Separate Window” (not available here since window is already separate).

11. “Calculate All” refreshes the survey table by recalculating all values after any entries are added or changed.

12. “Calculate Survey Station…” opens a utility window for calculating all survey parameters for a MD or TVD that falls between existing survey stations listed in the table. Within the pop-up window, enter either MD or TVD and other values will be calculated and displayed automatically.

13. “Insert Survey Station…” allows you to add a new survey position at a specific MD. To use this feature, first click on the row immediately below where the new station will be inserted. Then right-click to open this feature. Fill in the new MD and click [OK]. The new survey station will be added to the table and all values on that row calculated and filled in.

14. “Export…” allows you to save the survey displayed in the cut-point table separately as a DrillNET project file (*.XML),as a Petris standard survey file (*.SDI) for importing in other DrillNET projects , as a (*.TXT) file or as a WITSML (*.XML) file.


888. ANTI-COLLISION ANALYSIS MODEL

An anti-collision analysis is performed to calculate the distance from each point along a reference well to the closest point on one or more offset wells. Prime reasons for performing an anti-collision analysis include:

Ensuring a consistent method is used to evaluate and reduce collision risks between wells

Establishing a common procedure for developing multi-well sites which takes into account actual well trajectories of new and existing wells

Establishing a logical procedure that discriminates between interference from completed/producing wells and plugged/abandoned/uncompleted wells

Tools in DrillNET for anti-collision analysis range from relatively simple (Traveling Cylinder Plot; Spider Plot; 3D Closeness Plot) to more complex (Well Collision Check; Well Proximity Analysis). Analyses can take into account measurement uncertainties and errors in survey tools and instrumentation.

If you have created a new well plan and/or opened an existing survey, these data are immediately available in the anti-collision windows. If wells other than (or in addition to) the plan and survey well paths are desired, you have the option to open and import existing wells from inside the anti-collision windows.

8.1 Input

8.1.1 Project Page The Project input page for the Anti-Collision Analysis model is very similar to the typical DrillNET Project page. See Section 3.2.1.

8.1.2 Trajectories Page The Trajectories page is used to open trajectories that you can then compare for collision avoidance within the current project. As many different trajectories as desired may be opened and displayed in the table. Note that you cannot create trajectories here. They must be previously created and saved to a file by, for example, the Well Planning/Projection model (Section 7), the 2D Well Planner utility (Section 26.2), or via importing or manual entry into the Survey page (Section 3.2.2).

Wellbore Separation

Radius of Uncertainty

Target WellCurrent Well

CHAPTER 8: ANTI-COLLISION ANALYSIS MODEL


Active Trajectories

Trajectories that are listed and the table and selected as “active” will be shown in all anti-collision analysis windows. If a trajectory in the table is not selected as active, it will remain listed here in the table but not be shown in other anti-collision windows. Prior to importing a trajectory into the table, make that row active first.

From Galaxy Database Trajectories

If the column “From Galaxy” is checked on a row, you can then access a well project from the DrillNET Galaxy database (see Section 25.1). After you check the second column, column 3 (“Well Name”) and column 4 (“Trajectory Name”) become drop-down lists that allow you to select any trajectory currently in the database.

Importing Trajectories

If “From Galaxy” is not checked, then you can import a new trajectory from a survey file. First, select “Active” on the next open row in the trajectory table. Then, right-click on the new row and select “Import Survey…” from the pop-up menu. This will open a file window to browse your computer for existing survey files (*.SDI, *.TXT, or *.XML formats). Data will be imported into the current active row of the table (where the cursor is positioned). Options for importing survey files are described in detail in Section 3.2.2.

Reviewing Trajectories

You can view a trajectory by right-clicking on its row and selecting “View Trajectory…” from the pop-up menu. A new graph window will be opened that displays the survey data in a table and a 3D view of the well path. You can resize the window or grab and move the dividing bar over to enlarge the 3D view.

After a trajectory is listed in the table, you can select the survey tool (and corresponding survey accuracy) assigned to that trajectory. For imported surveys, you can also change the wellhead location coordinates. As in other DrillNET windows, cells with a yellow background cannot be edited by the user.




Hole Size

In column 9, hole size is listed. The hole OD you enter here is applied along the entire wellbore in the calculation of wellbore proximity (Section 8.2.5) and in the Spider Plot (Section 8.2.2). Many users enter the top hole size as a conservative value for use in calculating wellbore proximity.

Survey Tool Selection

After a well is drilled, survey data recorded for that well will always have some level of uncertainty associated with them. In cases where trajectories are relatively close, it is critical to quantify and account for uncertainty to avoid collisions. Uncertainty is assigned each trajectory by selecting a specific survey tool that measured (will measure) these survey data. Survey tool uncertainty data are stored in the My Survey Tools database (see Section 8.3.2). Datasets in this customizable database are selected from the drop-down box in the column labeled “Survey Tool.”

8.2 Output

8.2.1 Traveling Cylinder Plot Window A Traveling Cylinder plot is commonly used to display polar positions of offset wells from the center of the plan (reference) well path. This approach may be compared to a disk running down the reference well path which intercepts the offset well paths as they run through the plane of the disc. The disk is perpendicular to the axis of the reference well path. The traveling cylinder approach calculates distance from the offset well path to the reference well path. A primary benefit is that trajectory intercepts can be detected even when the well paths approach one another perpendicularly.

To open the Traveling Cylinder Plot window, select “Traveling Cylinder Plot…” from the Tools menu or click the

icon. All trajectories selected as “Active” on the Trajectories page will be displayed for selection.

Click on the spinner arrows next to the MD text box to move up or down the plan well. The increment for each jump is set in the box “Interval.” You can also enter a specific value of MD to jump to that depth immediately.



You can adjust the largest radius of the plot (shown on the vertical scales on the sides of the graph) by changing the value in the box “Radius.” You can also change the well path serving as the center point of reference by clicking another well path from those listed. After you make any changes, the graph is automatically updated.

The large data points (circles) on each well path indicate the current point of intersection of the traveling plane with the offset well.

8.2.2 Spider Plot Window The Spider Plot is basically a plan view of all the active well trajectories. Depth of the horizontal “slice” being viewed is set by the user in the “TVD” box.

To open the Spider Plot window, select “Spider Plot…” from the Tools menu or click the icon. All trajectories selected as “Active” on the Trajectories page will be displayed.

Click on the spinner arrows to the right of TVD to move in 100-ft jumps down the well path (or any other interval you enter). Hold your mouse button down to move rapidly down the well path.

Survey measurement error at the current TVD is shown to scale by a small circle around each trajectory. The Survey Tool Error for any trajectory can be selected on the Trajectories page (see Section 8.1.2) from the drop-down list. This defines the measurement error displayed on the graph.

8.2.3 3D Closeness Plot Window

To open the 3D Closeness Plot window, select “3D Closeness Plot…” from the Tools menu or click the icon. All trajectories selected as “Active” on the Trajectories page will be displayed.




The 3D Closeness Plot is a simple graphical anti-collision analysis that shows the depth and distance where the current plan (reference) trajectory and each of the active trajectories are closest. For example, the closest point between the plan trajectory (“Trajectory 7”) and “Trajectory 3” (red) is at measured depth of 7500 ft in the plan trajectory. The corresponding closest distance is 3950 ft.

You can select another plan reference well by clicking its name in the list. The 3D Closeness Plot will be updated automatically.

8.2.4 Well Collision Check Window The Well Collision Check window allows you to quickly analyze well-path collision potential in detail. This feature addresses two well-path trajectories at a time and does not take into account uncertainties due to survey tool measurement errors. (Use the “Spider Plot” (Section 8.2.2) or “Proximity Analysis” (Section 8.2.5) to account for measurement errors and uncertainty.) To open this window, select “Well Collision Check…” from the Tools menu or click the icon. All trajectories selected as “Active” on the Trajectories page will be available for selection.



1) Well Collision Check Primary and Secondary Trajectories. Select two well paths to be compared for collision potential by clicking them from the respective lists of active trajectories. Either all or a portion of each trajectory can be compared for collision. Click [Entire trajectory] to fill in that well’s TMD and check the complete trajectory. (This is the default setting when the window is opened.) Alternatively, you can enter values for From MD and To MD to check only a portion of either well path.

Wellhead location is shown for both selected trajectories. You cannot edit these locations here. Return to the Trajectories page (see Section 8.1.2) to change wellhead position.

2) Well Collision Check Table and Graph. After the collision check is performed (by clicking [Calculate]), MD coordinates will be listed for both wells when the distance between the two wellbore centers is less than the Safe Distance you specify. Data will be displayed only if the distance is less than the criterion.

Each row in the table contains coordinates for the Primary Trajectory (columns 1–4) and Secondary Trajectory (columns 6–9). The exact distance separating the wellbore centers at that position is shown in the center column. Note that errors in survey data are not considered here.

These collision results are also shown in a graph, which can be viewed by clicking the second tab above the table. Every point where the distance between the two wells is less than the specified minimum safe distance will be indicated with a red data point. MD is given for each well, so it is straightforward to




determine the position of these points.

3) Well Collision Check Parameters. Minimum Safe Distance is the threshold for reporting wellbore proximity in the results table. Only MD positions for the two wells that are found to be in closer proximity than the Minimum Safe Distance will be listed in the table.

Check Interval is the depth interval between calculation points. The smaller the MD Check Interval, the more time required for calculation. Also note that, if the Safe Distance is greater than the MD Check Interval, more than one listing for a specific MD may appear in the table.

4) Well Collision Check Control Buttons. [Calculate] is used to start the calculation sequence after the wellbore trajectories are specified. In some cases, the calculation may take a long time, depending on the MD Check Interval you selected. If the calculation sequence is stalled or moving very slowly, you can click [Stop] to halt the calculation. (You may need to click [Stop] twice to end the process.) Enter a larger Check Interval and restart the calculation.

8.2.5 Proximity Analysis Window A complete analysis of wellbore collision potential is provided in the Well Proximity Analysis window. This window is used for comparing the entire well path for two wells while accounting for survey measurement uncertainty and applying a safety factor. To open this window, select “Proximity Analysis…” from the Tools menu or click the icon. All trajectories selected as “Active” on the Trajectories page will be displayed.

1) Well Proximity Trajectory Selection. Select the well trajectories to be compared for collision by selecting from the two lists (“Primary Trajectory” and “Secondary Trajectory”). Either all or a portion of each trajectory can be



compared. Click [Entire trajectory] to check the complete trajectory to TMD (this is the default setting). Otherwise, enter the From MD and To MD to check only a portion of one or both well paths.

Survey data for each well has uncertainty associated with it. This is accounted for in the proximity analysis. Survey tool uncertainty data are selected on the Trajectories page (see Section 8.1.2). These survey data are listed in the My Survey Tools database (see Section 8.3.2). Hole size you entered on the Trajectories page is applied along the entire wellbore in calculation of wellbore proximity.

2) Well Proximity Data Table and Graph. After the collision check is performed (by clicking [Calculate]), MD intervals will be listed for both wells for the complete intervals you specify. The distance separating the wellbores at each position is shown in the “Minimum Distance” column. Rows will be listed with the MD of the primary trajectory incremented by the check interval (every 20 ft in the example). The MD where the secondary well is closest will be described in the same row.

To view a summary of the tabulated analysis, scroll over to view the right-most column (column 22) entitled “Status.” Here is displayed the text “Safe,” “Danger,” “Alert,” or “Collision.” To rapidly review the entire well path, scroll down the table while viewing the Status column.

Click the second tab above the table to view a graph of the results.

3) Well Proximity Factors. Check interval is the calculation increment for MD in the reference well that is used to check well proximity. The program will calculate the distance from each point on the primary trajectory to every other check interval point on the secondary trajectory. Thus, the check interval defines the total number of calculations required. A small check interval can result in a long total calculation time.

Alert Factor is applied to the calculated wellbore proximity as a safety factor to provide an advanced warning for guarding against wellbore collision. This approach is used by some companies and refined via probabilistic analysis to define alert factors for specific fields. A typical value for alert factor is 1.5.

Danger Factor is used in conjunction with Alert Factor as an initial warning regarding the potential for wellbore collision. This serves as a second (less stringent) safety factor and is often assigned a value of 2.0.

Alert Factor and Danger Factor curves are plotted on the results graph. When the curve of minimum distance (see figure above) crosses inside one of these thresholds, additional analysis may be warranted for that depth range.

4) Well Proximity Control Buttons. Click [Calculate] to update the anti-collision calculations. Note that the calculation check interval you enter defines the total number of calculations required and has a significant impact on calculation time. If the calculations are too slow or become stalled, click [Stop] (this button appears during the calculation sequence). You may need to click [Stop] twice to abort the calculation. Then, increase the calculation interval or reduce the range of MD considered, and click [Calculate] again.





8.3.1 Tool-Bar Icons Special tool-bar icons are provided on the right side of the tool bar when the Anti-Collision Analysis model is selected. The special icons include:

Traveling Cylinder. Opens the Traveling Cylinder Plot window (see Section 8.2.1) which displays polar positions of offset wells from the center of the plan (reference) well path.

Spider Plot. Opens the Spider Plot window (see Section 8.2.2) which displays a plan view of all the active well trajectories.

3D Closeness. Opens the 3D Closeness Plot window (see Section 8.2.3) which displays a graph that shows the depth and distance where the current plan (reference) trajectory and each of the active trajectories are closest.

Well Collision Check. Opens the Well Collision Check window (see Section 8.2.4) for analyzing well-path collision potential in detail. Only points where there is potential for collision are displayed in the results.

Proximity Analysis. Opens the Proximity Analysis window (see Section 8.2.5) for comparing the entire well path for two wells while accounting for survey measurement uncertainty and applying a safety factor.

My Survey Tools. Opens the My Survey Tools Database window (see Section 8.3.2) for selecting a set of data defining survey tool error for the current anti-collision analysis.

8.3.2 My Survey Tools Database Window A database of survey tools is provided for specifying measurement uncertainty with a range of tools. To open this window to review available survey tools and error data, select “My Survey Tools…” from the Tools menu or click the icon.

To edit existing data or add a dataset for another tool, click [Database Editor] in the lower left corner.

The My Survey Tools database is described in detail in Section 25.6.


999. CASING STRESS CHECK MODEL

The Casing Stress Check model is primarily designed to run casing verifications, i.e., to compare the resistance of a casing column design to the physical stresses that the column is likely to experience. A variety of potential stress factors can be considered. Rules used to calculate stresses can be saved in a customized profile, thus making it easier to address your company’s policies.

9.1 Input

9.1.1 Project Page The Project input page for the Casing Stress Check model is very similar to the typical DrillNET Project page. See Section 3.2.1.

9.1.2 Survey Page The Survey input page for the Casing Stress Check model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

9.1.3 Formation Page The Formation input page for the Casing Stress Check model is very similar to the typical DrillNET Formation page. See Section 3.2.5.

CHAPTER 9: CASING STRESS CHECK MODEL


9.1.4 Muds Page

1) Mud Gradient Entry Options. Mud gradients can be either entered manually or calculated by the program based on overbalance data. The mud gradient table at the bottom of the page is locked if you switch to the “Calculate” mode for mud gradients. Calculation of mud gradients makes use of overbalances and underbalances. Mud gradient at a given TVD is:

mud gradient = pore gradient + overbalance

where the overbalance can also be negative (underbalance). Over/underbalances are entered manually in the data table near the top of the page.

2) Overbalance Data Table. Use this table if you prefer to calculate mud gradients from pore gradients. If you want to enter a single value for the whole trajectory, enter a value only in the overbalance cell, and do not enter a depth. Even if you want to enter many overbalances with different values with depth, leave the depth field empty on the last row: DrillNET will adjust the last interval to the bottom of trajectory. (Depth must be entered explicitly on the previous rows.)

This table always includes a column for MD. Drilling fluids are a typical drilling parameter (unlike fracture and pore gradients, which are associated with formation data). Consequently, MD is most often available for drilling fluids.

The Overbalances data table is disabled whenever you switch to the manual mode for mud gradients.

3) Mud Gradient Data Table. This table is locked unless you select “Enter manually.” When the calculate option is selected, calculated gradients are displayed.




4) Mud Gradient Graphs. Graphs are displayed for mud gradients and for overbalance data. Click on the tabs at the bottom of the graph area to switch parameters. Note that the mud gradient graph also includes pore gradients (as entered on the Formation page).

Editing the Graphs

The mud gradient graphs can be opened as a separate window for easier viewing, as well as copied and printed. Right-click your mouse over the graph to open the Edit menu. Select “Display in Separate Window” to open a new window that is easy to review. Click “Export to Excel” if you want to further analyze the data. Options on this pop-up menu are described in Section 3.4.

9.1.5 Casing String Page

1) Onshore/Offshore Environment. Select or unselect the Offshore option. Verification rules can differ according to the well location.

Surface BOP or Subsea BOP: for offshore wells allows you to specify whether the wellhead is positioned on the surface or at the sea bed. For onshore wells, this is set automatically to surface.

Air Gap/RKB Elevation. The RKB (rotary kelly bushing) elevation is specified with respect to the ground level (for onshore wells), and to mean sea level (for offshore wells). For offshore wells, this elevation is



commonly called “air gap.” This quantity is used for offshore wells with subsea wellheads to calculate the casing top depth (air gap + water depth).

Ground Level Elevation applies to onshore wells only and represents the ground level elevation with respect to mean sea level (MSL). Currently, this parameter is for documentation purposes only. All depths are referred to RKB elevation. If different well elevations were introduced (such as sea level and ground level), this number would be involved into switching depths from one elevation datum to another.

The button [Refresh BOP] is used to set the correct position of the wellhead after you change well types.

2) New Drilling Phase Below Last Casing Shoe. This option reflects a subtle issue regarding the correspondence between casing shoes and wellbores (“drilling phases”). The bottom of the trajectory is given by the deviation profile (surveys) and represents the path to be drilled. As a general rule, the last shoe is not necessarily positioned at the bottom of the trajectory. If this is true, there are two ways that the well could have been drilled:

1. The last shoe and its corresponding casing string were run in the last drilling phase. The shoe was not positioned at the bottom of the phase based on an explicit decision (to leave a rat hole at bottom), or because of some drilling problem (for example, the last portion collapsed). For these cases, there are as many drilling phases as casing shoes. No drilling took place after the last shoe was set.

2. The portion of trajectory below the last shoes was drilled after the shoe was set as a new drilling phase, and was left without casing. For this case, we have one more drilling phase than shoe.

This option allows you to differentiate between these scenarios. This has consequences when you run the Margin Analysis (see Section 28.4.3), for which results are related more to drilling phases than to casing shoes.

It is interesting to note that, inside a casing design program, the priority between wellbores and casing shoes is reversed. That is, we ask you to enter casing shoe depths, making an implicit assumption that these shoe depths also represent the wellbore (drilling phase) bottom depths. We actually infer wellbore bottom depths from casing shoe depths.

3) Casing String Data Table. Data for casing strings include the casing shoe depth (displayed as TVD and MD); verification rule (surface, intermediate, or production); string type (casing, liner, immediate tie-back, or subsequent tie-back); bump-plug pressure (for tension verification); and string top depth (displayed as TVD and MD), useful especially for liners or for offshore wells with sub-sea wellheads.

Casing type includes the verification rule (surface, intermediate, or production) and string type (casing, liner, immediate tie-back, or subsequent tie-back). The model provides three different verification rules: surface, intermediate and production. Stress factors for burst and collapse (not for tension) change for the different rules, as well as stress calculation rules. The verification rule cannot be set explicitly for tie-backs. The model’s “profile verification” implies that tie-backs can never be verified by themselves. Instead, a verification is always run on either casing or liners (i.e., on the bottom-hole columns). When you verify a liner, the program looks for a tie-back on either that same liner, or for tie-backs run on top of other liners in previous wellbores. Tie-backs can be included in the verification profile (or skipped) according to the verification rule and to the sequence in which casing strings are run in the well (see Section 28.4.2).

Tie-backs can be either subsequent or immediate. A tie-back can only be added behind a liner. To add a tie-back, right-click on a liner row; a pop-up menu will appear with options. All string types are initially set by default to intermediate casing except surface casing in the first row. For a casing (except for surface casing), you can switch to a liner by clicking the drop-down list and selecting liner. For this case, a dialog box will appear for entering the liner top depth. For liners, you can switch back to a casing; or add to the liner either a subsequent or immediate tie-back. For tie-backs you can remove it or change its type from immediate to subsequent (and vice versa). Whether a tie-back is subsequent or immediate is relevant for verifications. You can remove a casing or a liner via the right-click menu. If you remove a liner that includes a tie-back, the tie-back will be removed.




Shoe Depth includes both TVD and MD. MD cannot be modified in this table directly (as indicated by yellow background). Values of MD can be changed by changing the corresponding TVD. If you would like to change them directly, double-click the cell, enter the value on pop-up windows, and then select [Apply]. Only casings and liners have a shoe depth. The concept of a shoe does not apply to tie-backs. Note that all depths are referred to RKB.

Top Depth also is displayed as TVD and MD. This column can be explicitly set only for top MD of liners. For casings and tie-backs, this field displays the BOP depth (zero for onshore wells and offshore wells with surface wellhead; air gap + water depth for offshore wells with sub-sea wellhead). When you change a casing to liner, you will be required to enter the top depth of the liner. To enter or change top depth for a liner directly, double-click on the top MD cell. Enter a new value and then press <Enter> to have the corresponding TVD calculated. You can also double-click on the top TVD cell and enter a new value in the pop-up window.

Bump-plug pressure is relevant for tension verifications. From bump-plug pressure, a bump-plug tension is calculated, according to the following formula:

(bump-plug tension) = (bump-plug pressure) * (maximum internal section area)

4) Conductor Pipe TVD. The conductor pipe is the large pipe run first into the well, and is usually driven into the ground. Most engineers would agree that, because there is no drilling, conductor pipe cannot be considered a true casing column. Verification criteria could be specified for a conductor pipe; however, DrillNET does not include any verification function for conductor pipes. The program uses these depth data only as references in output graphs.

5) Shoe Advisor. See Section 9.3.2.

6) Casing-String Graph. The casing strings entered in the table are shown schematically. This plot can be useful for spotting errors in the data. You can also view the rows singly or in small groups to improve visibility. To view a single component, select that row in the table by clicking on the row number.

Editing the Graph


7) Casing Data Tables. The lower section of the Casing String page provides a set of six tabbed pages that refer to the casing column currently selected (highlighted) in the upper table.

Casing Data Tab

Each column in the Casing Data table can include one or more portions (called segments). Each segment has a unique bottom. Casing properties displayed in the table are:

Each segment has a Bottom MD of its own. Bottom TVD is automatically calculated after you enter bottom MD. Bottom depth of the last segment (bottom of the string) can be left empty, since the program will set it to the string bottom depth (casing shoe depth for casings and liners, liner top depth for tie-backs). If you want to directly enter TVD, double-click on the TVD cell; a pop-up window will provide a box to enter the new TVD. After MD is calculated and displayed in the box, click [Apply] to export the values to the Casing Data table.



OD: used for identification, as well as to calculate the bending effect in tension analysis according to the formula: dogleg * OD * linear weight

ID: also used to calculate bump-plug tension from bump-plug pressure

Linear Weight: used to calculate string weight in tension analyses. Also used to calculate bending effect on tension, according to the formula: dogleg * OD * linear weight

Steel Grade (in casing body): for documentation

Thread Type: for documentation

Joint ID: usually less than the body ID

Burst Resistance: resistance to internal stress, as stated by the manufacturer.

Collapse Resistance: resistance to external stress

Tension Resistance: resistance to tension. It uses units of force

Burst, Collapse and Tension Design Factors: these are coefficients (unitless). When designing a casing string, drilling engineers do not accept literally casing nominal resistance quoted by casing manufacturers. As a safety measure, nominal resistances are usually decreased slightly by dividing them by coefficients greater than 1.0. These coefficients are usually called design factors. Design factors can always be entered manually as casing properties. Default design factors can be set in the Preferences window in either of two ways: (1) you can enter a default design factor for burst, one for collapse and one for tension; or (2) as a more comprehensive approach, design factors can be related to casing yield strength. You can declare ranges of yield strength, and then set the default design factors to apply for burst, collapse and stress inside each range.

Collapse (Internal) Tab

For burst and collapse verifications, the acting load is the net difference between an internal and external load. Collapse internal load depends on internal fluid conditions. There are three basic ways to enter fluid conditions:

1. Manual data entry. Select “Input internal fluid” and enter the data in the table on the left side of the window.

2. Input thief zone data. If this option is selected, the table “Fluid” is locked and several boxes are opened under “Thief Zone Analysis.” You then enter thief zone TVD, pore gradient at the thief zone, and heaviest mud in next phase. If the casing column is the last phase and the checkbox “New drilling phase below last shoe” is not selected, you cannot input thief zone data.

Thief Zone TVD. Enter a depth between the current and next shoe depth. The program will retrieve the heaviest mud gradient in the next phase and pore gradient at the thief zone. After thief zone TVD, pore gradient and mud gradient are available, a fluid level can be calculated.

Pore gradient at thief zone. Pore gradient at the thief zone depth can be entered manually.

Heaviest mud in next phase. The heaviest mud gradient found/expected in the next phase. This can also be adjusted manually.

Calculated fluid level. This is:

thief zone TVD * (1 – thief zone pore gradient/maximum mud gradient)

When this option is selected, collapse internal fluid is:

Bottom TVD Fluid Gradient Fluid level 0 Shoe TVD Heaviest mud gradient in next phase




3. Mud level lower than shoe. Users can make certain that the fluid level will be lower than shoe depth or all of the mud lost.

When this option is selected, collapse internal fluid is:

Bottom TVD Fluid Gradient Shoe TVD 0

Collapse (External) Tab

Collapse external conditions are those contributing to collapse external pressure. DrillNET has a built-in rule for collapse external pressures, which is described in the Preferences window (see Section 9.3.1). This built-in rule depends on the verification rule applied to the casing (surface or intermediate/production). For surface conditions, the rule also takes into account wellhead position (whether on surface or subsea). For intermediate or production verifications, the built-in rule is fairly simple, and states that collapse external pressure depends on mud gradient at the shoe. (Note that, above a liner hanger, this involves reading the mud gradient at the previous shoe. The plotted curve of collapse external pressure will typically show a horizontal step at a liner hanger TVD).

Whichever verification rule is applied to the casing column, the program offers the option to bypass the general rule. Instead, you can enter a set of fluid gradients to describe fluid conditions outside the casing responsible for collapse external pressure. These external fluids behave in a way very similar to internal fluids used for internal collapse pressure analysis.

To summarize, two models are available to describe collapse external conditions. Either you accept the built-in rule, or you enter a set of external fluids. The built-in rule means “mud pressure at shoe” for intermediate and production verifications. It takes into consideration several more factors in surface verification. The built-in rule cannot be customized to take into account additional factors. Instead, external fluids are entered manually and can be adjusted as required.

Clicking “Use external fluids” activates the small area on the right of the screen, displaying data referring to external fluids. The primary difference with respect to internal fluids used in internal collapse analysis is that here you can also enter a surface annular pressure.

Burst (Internal) Tab (for Surface/Intermediate Columns)

Net burst pressure is a combination of internal and external pressure. DrillNET displays in separate panels factors controlling internal and external burst pressure. The window for burst internal conditions is different for a surface/intermediate verification versus a production verification.

The basic model for burst internal conditions states that: (1) at shoe depth, burst internal pressure is the fracture pressure, i.e., pressure derived from calculating fracture gradient at the shoe by the shoe TVD; and (2) above shoe depth, internal burst pressure decreases gradually, due the presence of a fluid (usually gas) inside the column. Pressure at the wellhead will be pressure at the shoe minus pressure exerted by the column of fluid inside the column.



This simple model can be made more complex in various ways by adding constraints to the way pressure is calculated both at the shoe and wellhead. Below are two examples of limitations (for burst internal pressure at wellhead):

1. It is not necessary to take into consideration the full column of gas above the shoe, but only a portion of it.

2. Whatever results the calculation yields, internal burst pressure at the wellhead cannot be less than a fixed threshold.

As for burst pressure at the shoe, the only relevant alternative to the fracture-pressure rule is a comparison with pressure at the shoe that is generated by a kick.

Some data in this window are automatically retrieved, and cannot be changed (for example, fracture gradient at the shoe and resulting fracture pressure at the shoe). Influx fluid gradient (density of fluid found inside the column) can be changed or can be left locked according to your preferences. The whole set of data for the kick pressure calculation will be disabled or enabled, according to your preference settings.

Fracture pressure at wellhead is, basically, fracture pressure at the shoe minus pressure exerted by the overhanging column of gas. Should the figures not match, you should check your preferences—you may have configured the program to take into consideration only a fixed percentage of this pressure. Also note that, if you set a lower threshold for pressure at the wellhead and calculated pressure is actually less than this pressure, the field still displays calculated pressure (i.e., the field content is not affected by the threshold). Casing verification, however, will account for it.

Influx fluid gradient. Influx fluid is the fluid inside the column whose density is responsible for the difference in pressure between the shoe and wellhead. This fluid is often assumed to be gas. You can set a default value in Preferences, and you can also prevent users from entering a different value.

Data for the pore method. Enter kick TVD and press <Enter>; the program will display the default pore gradient. You can also enter a different pore gradient (click on the second cell and type the desired value). If you entered a pore gradient and want to revert to the default gradient, click on the button in the third cell. Kick pressure at the shoe (fourth column) is calculated as follows:

(pore pressure at kick TVD) – (kick TVD – shoe TVD) * (influx fluid gradient)

that is, pressure at bottom, minus pressure of the overhanging column of fluid (as usual). Note in this case we do not apply the percentage, even if it specified in the preferences. Also note that the Kick TVD is assumed to be greater than the shoe TVD. Finally, kick pressure at the wellhead is also calculated in the standard way (kick pressure at shoe minus pressure of the overhanging fluid column). In this case the percentage (if specified) is taken into consideration.

If the pore method is enabled, DrillNET, while running the verifications, compares kick pressure at shoe with fracture pressure at the shoe. If kick pressure is less than fracture pressure, kick pressure is assumed as internal burst pressure at the shoe.

Burst (Internal) Tab (for Production Columns)

Stress factors taken into consideration for production verifications are: reservoir TVD and pore gradient at this TVD; a “formation fluid” gradient; and a “packer fluid” gradient. Internal burst pressures at the shoe and wellhead are calculated as follows:

(pressure at wellhead) = (pore gradient at reservoir TVD) * (reservoir TVD) – (formation fluid gradient) * (wellbore TVD – casing top TVD)




i.e., pore pressure at the reservoir minus the pressure exerted by a column of formation fluid expanding from the wellbore bottom TVD up to the BOP.

Pressure at the shoe is calculated as follows:

(pressure at shoe) = (pressure at wellhead) + (wellbore TVD) * (packer fluid gradient)

Note that in both cases we do not use the simple shoe TVD, but the wellbore bottom TVD. Wellbore bottom TVD for the last casing column could be greater than the corresponding shoe TVD, as the wellbore could extend deeper than the casing column.

Burst (External) Tab

This panel is similar to the panel for collapse external conditions. Users choose between accepting a built-in rule or entering a set of external fluids. External fluids are enabled by clicking “Use external fluids” and behave similarly to external and internal fluids for collapse. Click “Apply the General Rule” to apply DrillNET’s built-in rule (for surface casing only).

If users choose the option “Use external fluids,” they must enter values for “Surface annulus pressure” and “External fluid.”

Kick Tolerance Tab

Kick tolerance is used to define the maximum kick volume that can be safely controlled by any well-control method with constant BHP without fracturing the formation below the last casing shoe. Kick tolerance could be the subject for a program all by itself. However, in some approaches, kick tolerance is also considered as a part of casing design, and is therefore addressed in this model.

A kick generally occurs below the last casing shoe, and most often at the bottom of the open hole. In any case, the portion of the wellbore considered when evaluating a kick starts at a shoe depth and continues as far as the bottom of the open hole. As open hole depths are never entered explicitly in DrillNET, it is assumed that the wellbore extends as far as the next shoe (for the last shoe, we can go as far as the trajectory bottom). Finally, users must enter the OD of the open hole and the BHA. DrillNET automatically retrieves the fracture gradient below current shoe, the mud gradient at TD and the pore gradient at TD. All these gradients can be adjusted manually to simulate different situations.

Given all these data, DrillNET calculates:

1. Annular capacity (the difference between the area of the open hole and area of the BHA)

2. Maximum influx height, whose formula is relatively complex. The calculation is split into two steps. First, we calculate an intermediate result:

C = (shoeVD * (FracGrad@Shoe – MudGrad@TD) + TD * (MudGrad@TD – PoreGrad@TD)) / (MudGrad@TD – InfluxFluidGrad)

Maximum influx height is then calculated as:



MaxInfluxHeight = C * (shoeVd * FracGrad@Shoe) / (TD * PoreGrad@TD)

3. Maximum influx TVD will be:

MaxInfluxTVD = TD – MaxInfluxHeight

4. The final step is to calculate MDs corresponding to total depth TVD and maximum influx TVD (since we must calculate a volume, we cannot rely on TVDs – we need MDs). Maximum kick volume is:

MaxKickVol = (KickMD – MaxInfluxMD) * AnnularCap

where Kick MD is the MD corresponding to TVD at total depth.

9.2 Output

9.2.1 Output for Margin Analysis If you launch Casing Stress Check calculations by clicking from the Project, Survey, Formation, or Muds input pages, the Margin Analysis results are displayed (see below). If you launch output from the Casing String input page, the Casing Verification results will be displayed (see Section 9.2.2).

A theoretical discussion of casing stress margin analysis is presented in Section 28.4.3.

Output for the Casing Stress Check model includes results under three tabs:

1. Summary – Displays values for key hydraulics parameters

2. Graphs/Tables – A typical DrillNET multi-featured output display allowing selection of individual or multiple graphs (see Section 3.3)

3. Casing Schematic – The casing program shown as a vertical well




9.2.2 Output for Casing Verification The Casing Verification output window is displayed after you click while the Casing String input data page (see Section 9.1.5) is displayed. (The Margin Analysis output (see Section 9.2.1) is displayed if you view output starting from any of the other four input pages.)

A theoretical discussion of casing verification analysis is presented in Section 28.4.2.

Output for the Casing Stress Check model includes results under four tabs:


2. Graphs/Tables – A typical DrillNET multi-featured output display allowing selection of individual or multiple graphs (see below and Section 3.3)

3. Safety Factor – Displays a table with calculated and required design factors for every section of the casing string

4. Casing Schematic – The casing program shown as a vertical well




9.3.1 Preferences Window

General Information

The Casing Stress Check model is designed to be highly flexible. User preferences are used to dictate how the program performs casing verifications. The complete set of preferences can be saved as a policy file, thereby providing a stable environment of rules that reflect (for example) your company’s procedures.

The Preferences window allows you to edit two different types of data: (1) preferences for your current project, and (2) your company policy (saved in the template file “CasingCK.pol”). The current preferences affect only the current session. The template preference (company policy) affects only new sessions. You can switch from one set of data to the other as needed.

There are seven control buttons in every preference window with the following functions:

1. “Default” – Restores initial example preferences provided with the program. DrillNET is supplied with a default preference set to provide a starting point and a “safety net” for emergencies, such as the template file and data file being lost.

2. “Save as Policy” – Saves all currently preferences as company policy. Overwrites the template file “CasingCK.pol” with the current preferences. (Note: Do not delete the file “CasingCK.pol”.)




3. “Reset to Policy” – Resets all preferences to your current company policy. Loads preference data from the template file “CasingCK.pol” and replaces all current preferences. You must click [Apply] to accept these preferences into the current project.

4. “Save as” – Saves all current preferences to a user file with extension “*.CCK.”

5. “Open” – Opens a window to browse for existing sets of preferences.

6. “Apply” – Closes the Preferences window and accepts all current preferences into the current project.

7. “Cancel” – Closes the Preferences window without changing preferences in the current project.

Surface Page

This first tab in the Preferences window, “Surface,” displays criteria for calculation of burst and collapse stresses under the “surface” condition. (See Section 28.4.5 for a definition of these terms.)

DrillNET considers two types of wellheads: surface wellhead and subsea wellhead. Rules for each option are similar.

For burst internal pressure at the wellhead, you can enter a fixed value or to let the program calculate the pressure. For calculated values, input a value of influx fluid gradient and check (or uncheck) “Locked.” If “Locked” is selected, this influx fluid gradient will be used in every case to calculate internal fluid pressure. If “Locked” is not selected, you can change it to any influx fluid gradient in the input windows.

Next, check or uncheck the box “Never less than.” If this is selected, the greater of two pressures will be applied to the wellhead: (1) the value you input in the textbox or (2) the percentage * (fracture pressure at shoe minus internal fluid pressure).

Other rules for burst and collapse pressure that will be applied are listed on the page.

Intermediate Page

This “Intermediate” tab displays criteria for calculating burst and collapse stresses under the Intermediate condition. Unlike the surface condition, criteria in the intermediate casing section do not distinguish between surface and subsea wellheads.



For burst internal pressure at the wellhead, you can enter a fixed value or to let the program calculate the pressure. For calculated values, input a value of influx fluid gradient and check (or uncheck) “Locked.” If “Locked” is selected, this influx fluid gradient will be used in every case to calculate internal fluid pressure. If “Locked” is not selected, you can change it to any influx fluid gradient in the input windows.

Next, check or uncheck the box “Never less than.” If this is selected, the greater of two pressures will be applied to the wellhead: (1) the value you input in the textbox or (2) the percentage * (fracture pressure at shoe minus internal fluid pressure).

Burst internal pressure at shoe. Normally burst internal pressure at the shoe is set equal to fracture pressure at the shoe. If there may be a kick in the next phase, you can adjust burst internal pressure at the shoe via a comparison between fracture pressure at shoe and kick pore pressure. If you prefer this approach, check “Enable comparison between fracture pressure at shoe and kick pore pressure.”

Other rules for burst and collapse pressure that will be applied are listed on the page.

Production Page

Rules for production strings are identical to intermediate rules except for burst internal pressure. Recall that the verification profile is constructed differently under production conditions, as any tie-back (including subsequent tie-backs) would be considered as already run in hole, and so would behave like an immediate tie-back.




This Preferences page is only for your reference. To view actual values to be used in the calculation, open the Tubulars input page and select the production casing. The “Burst (Int.)” tab in the lower half of the window will display parameters for calculation of internal burst pressure.

Biaxial Effect Page

The biaxial effect is in essence an adjustment to casing resistance due to tension loads in the column. Calculation of biaxial effects on casing resistance is an extension of standard tension analysis. The concept behind this effect can be summarized as follows.

Any casing column is subject to a tension stress, which, at any point along the column, is dictated by the weight of the portion of column below that point. Tension is maximum at the top of the column (where it corresponds to column apparent weight) and is zero at the bottom of the column. Due to the effect of mud providing buoyancy to the column, a buoyancy effect for the casing column must be calculated. Applying this buoyancy effect leads to the tension in mud. In a graphic comparison, tension in mud will be linear and parallel to tension in air, located to the



left and offset from it by an amount corresponding to the buoyancy effect. It is clear that tension in mud at the bottom of the column will be negative.

The upper portion of the column, where the tension in mud is positive, is subject to a tension stress; the lower portion of the column, where the tension in mud is negative, is in compression. The presence of tension reduces the collapse performance of the pipe, and tension increases the burst performance. Compression has the opposite effects—compression increases collapse performance of the pipe and reduces burst performance.

Physically, when pipe is subject to a tension stress, it becomes longer and thinner. This same type of deformation is also produced by collapse stress, but is opposite to the effect of burst stress. That is why tension reduces collapse resistance and increases burst resistance.

The mathematical model for the biaxial effect reflects the classical “biaxial ellipse” analysis of Holmquist and Nadia (Collapse of Deep Well Casing – API Drilling and Production Practice – 1939).

The steps involved in computing the corrected resistance are the following:

At each MD along the column, from the shoe up to the column top, take the tension in mud and divide it by the casing resistance to tension. Let the result be “x”. At each MD, calculate:

FcorrCollapse =

FcorrBurst =

Finally, at each depth along the column, multiply casing nominal resistance by its correction factor, as follows:

(Corrected Collapse Resistance) = FcorrCollapse (Nominal Collapse Resistance)

(Corrected Burst Resistance) = FcorrBurst (Nominal Burst Resistance)

On the Biaxial Effect page, the two check boxes allow you to specify if you want to apply the biaxial effect to the burst resistance and to the collapse resistance. (You can also unselect both of them to disable the calculation of the biaxial effects.) The model currently contains only one algorithm to calculate the biaxial effect (as described above).

2

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Design Factors Page

Design factors are coefficients used to decrease allowable casing nominal resistances quoted by the manufacturers. Few engineers accept casing nominal resistances as listed. It is usually believed that resistance values should be reduced, and this is most often done by dividing nominal resistance by a design factor (these are greater than unity since the resulting resistance (called “design resistance”) cannot be greater than nominal resistance). If a design factor is set at unity, this indicates that the nominal resistance is accepted without reduction.

When performing a stress analysis, the following relationship must be satisfied:

(nominal resistance) / (design factor) ≥ (maximum acting stress)

i.e., casing resistance, reduced according to the design factor, must be greater than maximum acting stress.

Safety Factor

We now define the concept of “safety factor.” Design factor and safety factor are not equivalent and should not be confused. The ratio between casing nominal resistance and maximum acting stress is the safety factor:

(safety factor) = (nominal resistance) / (maximum acting stress)

The previous relationship can be rewritten as:

(nominal resistance) / (maximum acting stress) ≥ (design factor)

Combining the two concepts yields:

(safety factor) ≥ (design factor)

So the design factor is, at the same, the minimum ratio that should exist between the full nominal resistance and maximum acting stress, so that the casing is verified.

The first relationship above also is key to understanding casing verification graphs. Whenever design factors differ, it is clear that casing nominal resistance and acting stress are not directly comparable. There are two ways to make them comparable on a graph: (1) divide nominal resistance by the design factors, or (2) multiply acting stress by the design factor. The second approach corresponds to yet another form of the relationship:

(nominal resistance) ≥ (maximum acting stress) (design factor)

where the right side could be called “design stress” (an increased stress considered for safety purposes).



The Casing Stress Check model allows you to apply design factors to graphs as you prefer, either decreasing nominal resistance, or increasing stress. We believe this is one of the most useful features. If desired, you can even display both resistance and stress uncorrected (just be aware of what you are doing).

Specifying Design Factors

A separate issue is how design factors are entered, and how they are associated with the rest of the data. Design factors are treated as casing properties. On the Casing String input page (see Section 9.1.5), select a casing (that is, select a row) in the upper table. Then click on the “Casing Data” tab in the lower table. The right-most three columns in the data table are the design factors for collapse, burst and tension.

Design factors can always be entered manually. The model includes two additional ways to automatically associate design factors with casing properties:

1. Use a default value. On the “Design Factors” page of the Preferences window, enter default design factors for burst, collapse and tension. These default values are used by the model if you don’t enter a design factor in the casing data table.

2. Automatically associate design factors with casing data through yield strength. On the lower half of this Preferences window, you can set ranges (e.g., from 55,000 to 110,000 psi) and to define a design factor to use inside that range. Based on the yield strength of the casing being verified, the model will associate the appropriate design factor.

Temperature Page

Temperature also impacts casing resistance. Casing resistance is usually expected to decrease as temperature rises above a certain threshold. In most cases, this effect is ignored since design factors are assigned to account for all other factors not explicitly addressed. If you prefer to ignore temperature effects on casing resistance, unselect the check box “Derate resistance for temperature” at the top of the page.

Three derating factors are used for burst, collapse and tension resistance, defined here as a percentage per degree. A typical value is 0.03%/ºF. You must also enter the threshold temperature—the temperature above which the effect on casing resistance is enabled (i.e., no effect is applied if temperature is below the threshold). A reasonable value for the threshold is 68ºF (20ºC).

Above threshold temperature, the effect is calculated as follows:

(corrected resistance) = (1 – (derating factor Δtemperature)) (nominal resistance)




where temperature is relevant temperature difference above the threshold at each depth. For production verifications, the temperature at the bottom of hole is applied to the whole column.

Limits of Temperature Derating

Several limitations apply to the analysis of temperature effects in the Casing Stress Check model. Unlike the biaxial effect, no separate safety factors are calculated for temperature. Corrected resistances are only calculated and plotted against nominal resistances. This allows users to compare nominal and corrected resistances, thus highlighting the impact of temperature.

In addition, the temperature effect automatically disables the biaxial effect (i.e., corrected resistances for the biaxial effect are not displayed, because too many graph would be required). If the temperature effect is enabled, casing resistances are automatically drawn using their nominal values (i.e., no design factors are applied, even if explicitly set by the user). In the results, values of all corrected resistances, including tension resistance, are displayed inside the burst and collapse table (lower left corner of the window).

Tension Page

Tension stress analysis is basically an analysis of casing stress due to its own weight. The primary calculation is column weight. Weight is maximum at the top of the column, and zero at the bottom (at the shoe). This concept of weight is called “tension in air.”

You can customize this analysis, enabling or disabling effects of bending on tension stress, although the analysis always includes the effect of buoyancy. These effects act as adjustments to simple tension weight.

The bending effect is an increase in tension stress that occurs when casing is run through a dogleg. Due to the curvature, the outer casing wall is subjected to additional tension stress. The bending effect on a casing segment in a dogleg is calculated as follows:

(dogleg) OD (linear weight)

Once you have the total weight (tension in air of a casing column), the effect of buoyancy would be calculated as:

buoyancy effect = (tension in air) (buoyancy factor)

where:

buoyancy factor = -1 (mud gradient at shoe) / (steel gradient)

This applies for a uniform casing column. When the casing column includes various sizes, use cross-section areas and pressure.



By applying buoyancy and bending effects to the tension in air, tension in mud is:

(tension in mud) = (tension in air) + (buoyancy effect) + (bending effect)

Users can select between two methods to calculate weight in air of a casing column:

1. MD method—do not take account of the effect of well trajectory on tension. Weight in air of a casing column is equal to real total weight of casing column in air (linear weight length).

2. TVD method—take into account the effect of well trajectory on tension. In a hole with doglegs and bends, the axial component of the weight force in casing contributes to tension. The sum of axial component of weight force needs to be derived in all of casing segments. The shorter the casing segment length used in the calculation, the closer the result is to the real tension; however, computing time will be longer. To address this issue, the program allow the user to input an interval of length for incrementally dividing the casing column. To have the shortest possible calculation time, check the box “Do not add any points.”

Gradients Page

On the Gradients page in the Preferences window, you can set the default mode for fracture and mud gradients so that, for example, mud gradients must be entered manually. These choices are not critical, since the general settings on the Formation and Mud input pages can always be changed during a session.




9.3.2 Shoe Advisor Window

A casing-shoe positioning assistant is provided. The following data are required to run the Shoe Advisor: pore and fracture gradients, depth of the last casing shoe, and two margins – kick and trip. The routine first applies margins to the gradients, thus getting “corrected” lines for both fracture and pore gradients. Then, starting from the last shoe depth, an upward path is derived, consisting of vertical and horizontal sections. One rises vertically until the corrected line of the fracture gradients is crossed. A casing shoe will be set at that depth. The Advisor then moves horizontally to the left until the corrected curve of the pore gradients is crossed. Starting from the point where this line is crossed, the Advisor moves upward again until the curve of the fracture gradients is crossed again, and so forth until the surface is reached.

Note that “corrected pore gradients” actually means “mud gradients.” Then, ignore for a moment the kick margin for the fracture gradients (which you can do at any point by entering 0 or leaving the field empty). In this case, the Shoe Advisor compares the fracture gradients and mud gradients. Shoes are set so as to maintain inside each wellbore (a portion of trajectory between two subsequent shoes) the minimum fracture gradient just above the mud gradient line for that wellbore. Now it can be readily seen how similar this concept is to the choke margin, which is one of the three indices calculated by the margin analysis. It can be interesting to compare Shoe Advisor predictions with the post verification represented by the choke margin calculation.

Trip Margin is the correction applied to the pore gradients in the Shoe Advisor. The corrected pore gradients (pore gradients + trip margin) actually function as planned mud gradients. In this sense, trip margin is very similar to the overbalance. Mud densities are often chosen to provide an acceptable trip margin above the anticipated formation pore pressures to allow for reductions in effective mud weight caused by upward pipe movement during tripping operations. Trip margins in effect function as safety factors. Typical values for trip and kill margins range from about 0.5 to 1.0 ppg above pore pressure or below frac pressure (0.026 to 0.052 psi/ft or 0.6 to 1.2 kPa/m). Exact values depend on how accurately formation behavior can be predicted.

Kick Margin is a margin (safety factor) to be subtracted from the true fracture gradient line, to obtain a design fracture gradient line. If no kick margin were used, it would be impossible to take a kick at the casing-setting depth without causing a fracture and a possible underground blowout.


110010. WELLBORE CEMENTING MODEL

The Wellbore Cementing model comprehensively analyzes the complex phenomena of multistage fluid placement in a wellbore. Although originally designed for cementing, the program can be used for any multistage fluid pumping operation in a wellbore. The well-recognized U-tubing phenomenon (free fall) is addressed, along with ECD and pressure at the bottom of the hole. A variety of potential problems with formation break-down and of low to no returns can be avoided by using this model at the planning stage.

10.1 Input

10.1.1 Project Page The Project input page for the Wellbore Cementing model is very similar to the typical DrillNET Project page. See Section 3.2.1.

10.1.2 Survey Page The Survey input page for the Wellbore Cementing model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

10.1.3 Tubulars Page The Tubulars input page for the Wellbore Cementing model is very similar to the typical DrillNET Tubulars page. See Section 3.2.3.

10.1.4 Wellbore Page The Wellbore input page for the Wellbore Cementing model is very similar to the typical DrillNET Wellbore page. See Section 3.2.4.

10.1.5 Formation Page The Formation input page for the Wellbore Cementing model is very similar to the typical DrillNET Formation page. See Section 3.2.5.

CHAPTER 10: WELLBORE CEMENTING MODEL


10.1.6 Fluids Page

1) Fluid Data Table. Properties for each fluid stage to be pumped are specified in this table. Up to 15 fluid stages may be entered. A name and/or description of the fluid is entered in the first column. Fluids must be arranged in the correct order; that is, the item at the top of the list is the native fluid/mud, and the other fluids are arranged in the order they are to be pumped.

Indicate which fluids are cement by checking them in the “Cement Slurry” column. Slurries are treated differently since they are a solid/liquid two-phase fluid. A different algorithm is used to calculate frictional losses with slurries.

After fluid rheology is selected from the drop-down box (four choices: Newtonian, Bingham plastic, power-law, and Herschel-Bulkley), columns for other pertinent parameters are automatically made active (white background) or deactive (gray background). Colors may be assigned to each fluid stage. These are used when displaying the wellbore schematic with current or final fluid positions, and for the pumping animation feature.

Rheology Models

Four fluid models are provided. (See Section 28.12.1 for additional theoretical discussion.) Common fluids include:

1. Newtonian. These are fluids in which shear stress is directly proportional to shear rate. Examples of Newtonian fluids are water, air, nitrogen, glycerin, and light oil. A single parameter, viscosity, characterizes these fluids.




2. Most drilling/completion fluids are non-Newtonian, with shear stress not directly proportional to shear rate. Fluids are shear thinning when they have less viscosity at higher shear rates than at lower shear rates.

3. Bingham Plastic. This is the most common rheological model for drilling muds. These fluids have a linear shear-stress/shear-rate ratio once a threshold shear stress is exceeded. Two parameters, plastic viscosity and yield point, are used to characterize these fluids. Because these constants are determined between specified shear rates of 500 to 1000 sec-1, this model characterizes fluids in the higher shear-rate range.

4. Power Law. This model applies to shear-thinning or pseudoplastic fluids. Shear stress versus shear rate is a straight line when plotted on a log/log scale. Two constants, n and K, are determined from data at any two speeds. (See Section 28.12.1 for a definition of these constants.)

5. Herschel-Bulkley. This model, similar to the power-law model, applies to shear-thinning or pseudoplastic drilling fluids. It also incorporates a threshold shear stress (yield point). Consequently, the Herschel-Bulkley model can be considered a hybrid combination of the Bingham-plastic and power-law models. Herschel-Bulkley was developed based on the observation that many typical drilling fluids exhibit both a yield stress and shear thinning.

At high shear rates, these fluid models represent a typical drilling fluid reasonably well. Differences between models are most pronounced at low rates of shear.

Editing the Fluid Data Table

An Edit menu can be accessed easily by right-clicking over the data table. Options on this pop-up menu are:

1. “Print Table…” provides options for printing the table currently displayed. Within the pop-up window that follows, select the preferred printer before you click [OK]. You can preview the print job before you send it to the printer by selecting “Print Preview.”

2. “Print Preview Table…” allows you to preview the print job before it is sent to the printer. To print the results as displayed in the Print Preview, click the icon in the window.

3. “Insert a New Fluid” will move down all rows in the table below the cursor to make room for a new row. Note that the table is limited to a maximum of 15 pumping stages.

4. “Delete a Fluid” will delete the current row of data and move the lower rows up to fill the empty row. Note that the table is limited to a maximum of 15 pumping stages.

5. “Fann Viscometer Calculator..” provides a utility to estimate rheology based on Fann Viscometer readings. See Section 10.3.

6. “Rheological Parameter Estimator..” provides a graph of properties of typical field muds for use in selecting representative rheology parameters. See Section 10.3.4.

7. “My Fluids…” opens the customizable fluids database. See Section 25.3.

8. “Get Fluids from Utilities” See section 10.3.2 for details

2) Pumping Schedule Data Table. Pump schedules are displayed separately for each fluid. Enter the fluid volume and the pump rate for each fluid; the computer will calculate pumping time and cumulative time. To change to another fluid, select the fluid by clicking on the corresponding row in the Fluid Data table.

To designate shut-in periods, first enter zero for both volume and pump rate; then enter time for shut-in. Any rate input for the native fluid/mud will be ignored.

Editing the Table

Right-click over the table to open the Edit menu. This provides options for copying entries, printing, and adding/deleting rows. Select “Display in Separate Window” to open the table in a new large window, making review and editing easier.



10.1.7 Operation Page

1) Cementing Operation/Calculation Options. Select whether the pumping operation is forward circulation (pumped down the drill pipe and up the annulus) or reverse circulation (pumped down the annulus and up the drill pipe).

Pipe/Formation Safety Check

The pipe/formation safety check option is a useful feature based on our customers’ request that the program automatically check for dangerous pressure conditions along the entire wellbore, including both pore/frac pressure limits at all exposed formation and collapse/burst limits of the casing. Previously, only the selected zone of interest was rigorously checked during each run. If several zones were potential sites of lost circulation, fracing, etc., multiple runs of the model were required.

The safety-check feature monitors pressures throughout the job at multiple intervals along the flow path. The minimum and maximum formation and casing pressures that occur at any time during the pumping operation are stored in memory. Results of the pipe and formation safety check are summarized in two additional graphs (tubing burst and collapse pressures; and a pressure profile with minimum and maximum pressures in the annulus) and one additional table (summarizes data from both graphs). These special output screens are displayed along with the five standard graphs and tables in the output window (see Section 10.2).

The disadvantage of selecting this Safety Check option is a longer run time. A significantly larger number of calculations must be performed to chart pressures throughout the job at multiple depths. Therefore, if there is




clearly no need to perform pressure checks all along the flow path, you can deselect the option to speed the calculation process and make the output screen less crowded.

2) Surface Line Data. The effective length and ID of the surface line from the pump to the wellhead should be entered in these boxes. These parameters are used to calculate pressure drop between the pump and wellhead.

3) Free-Fall Control Tool. If a device to control free fall is implemented, check “Free-fall control tool present.” Then enter the depth and total flow area (TFA) of the control device.

4) Casing Shoe and Points of Interest. The deepest casing shoe and the MD of one, two or three points of interest are entered in these boxes. A point of interest is a depth for which DrillNET will calculate and display ECDs and pressure changes throughout the pumping operation in the table. (For other depths considered in any detail, only the maximum/minimum pressures are recorded.) The bottom of the hole is often selected as a zone of interest.

Note: to display ECDs and/or pressures for zones of interest 2 and/or 3, you must select these options for output display in the Model Options window (see Section 26.6).

5) Back-Pressure Schedule. Select between options for manual input or calculated back-pressure schedule. Choosing manual input activates the time/pressure table below. Fill in your planned back-pressure schedule.

Note: If the back-pressure table is activated and no data are entered in the table, back pressure is set as zero throughout the job.

The calculated schedule is optimized so that the back pressure will just be sufficient to prevent free fall. To calculate a schedule, select “Calculate to prevent free-fall.” If you then select “Manual input,” the calculated schedule will be displayed in the table and can be edited as desired.

10.2 Output Output for the Wellbore Cementing Model includes results under two tabs:



Within the Graphs/Tables window (see below) five graphs and one table are normally displayed. If you select “Perform pipe/formation safety check,” two additional graphs and a second table are added to the display to include safety check results.




10.3.1 Tool-Bar Icons Special tool-bar icons are provided when the Wellbore Cementing Model is selected. The special icons include:

Cementing Utilities. Opens the Cementing Volume Calculators (see Section 10.3.2) for determining wellbore and cement volumes.

Cement Animation. Opens the Cementing Animation window (see Section 10.3.5) that generates a simulation of the multistage pumping operation.

10.3.2 Cementing Utilities Three convenient utilities for cementing volume calculations are accessed by clicking the icon or selecting “Utilities” from the Tools menu. After the window is opened, select the utility of interest from the three options shown in the drop-down list.

Volume Calculation

This utility is used to calculate fluid volumes inside the casing or in the annulus between any two depths. The current wellbore hole and casing geometry is shown schematically. The primary zone of interest (selected on the Operation page) is indicated on the schematic with a red “O” (at 12,550 ft in the figure).

There are three methods to select an interval for calculation of volume:

1. Select MDs at major transitions from the drop-down list

2. Type the depths into the MD box (this is allowed if you leave the drop-down boxes set to “Point 1” and “Point 2”

3. Click directly on the graphic. The first click selects Point 1; the second selects Point 2.

Enter a depth of zero to start the interval from the surface. Click [Calculate] after you enter or modify depths in the text boxes.

After two depths are selected, the interval will be shown in the wellbore schematic as a colored zone. Blue represents the interval inside tubing; green is the selected annular section.




Calculated results are shown in the lower right corner. Shown are TVD of the two depths and volumes of fluid inside the tubing and in the annulus.

Equivalent Hole ID

This utility window is used to calculate an average equivalent hole ID when annular volume is known. This will allow you to estimate an ID to account for washouts and other hole irregularities.

Enter the upper and lower MDs of the interval by selecting them from the list of major transitions in the wellbore, or by typing them directly into the MD boxes. Click [Calculate] after data are entered. Equivalent hole ID will be displayed at the bottom of the page.

Balanced Cement Plug

This third utility is designed to quickly calculate fluid volumes for spacer and a cement plug. Input the spacer length and cement plug length. The box regarding pipe position will include or remove the pipe-body volume from the calculation, as appropriate.



10.3.3 Fann Viscometer Calculator A utility is provided for calculating fluid rheological parameters from Fann viscometer readings. This is accessed by right-clicking on the Fluid Data table on the Fluid page. To use the utility:

1. Right-click over the row corresponding to the fluid of interest

2. Select “Fann Viscometer Calculator” from the pop-up menu

3. Open the drop-down box at the top to select how many speeds are available (2, 4, 6 or 8 speeds)

4. Enter the data for each speed in the corresponding box

5. Click [Calculate]

6. View the results in the yellow boxes in the right side of the window

7. Compare the fit of the models to the data by clicking on the “Graph” tab and note your preference

8. Click [Accept] to export the results to the current row of the Fluid Data table on the Fluids page; or click [Cancel] to discard the results and close the window

9. After you have returned to the Fluid page, you will find that rheology data for all four models are entered in the table. Select your preferred model from the drop-down list in column 5. If you change rheology models, the rheology constants will still be available.




10.3.4 Rheological Parameter Estimator A utility is provided for estimating typical PV and YP for field muds. This is accessed by right-clicking on the Fluid Data table on the Fluid page. A graph of PV and YP is presented based on data from typical field muds. To find an estimate for your drilling fluid, enter the current mud weight. Click [Estimate] to display numeric values taken from the curves at your mud weight. Click [Accept] to export the results to the current row of the Fluid Data table on the Fluids page (see Section 10.1.6). Click [Cancel] to discard the results and close the window.

10.3.5 Animation Window The Animation window is a secondary output window that generates a simulation of the multistage pumping operation. The position of each fluid front can be compared throughout the planned operation. This window is accessed by clicking or by selecting “Animation” from the Tools menu.



Flow Animation Tab

1) Wellbore Schematic with Fluid Fronts. Positions of fluid stages are shown in the wellbore schematic. To show

a snapshot of fluid positions at any particular time, (1) run the animation (click and allow the entire

operation to be completed or press at any point, or (2) directly enter a specific time to display in the Show Fluid at Time (see ).

If you enter a time manually, the flow regimes (plug, laminar, or turbulent flow) at that point in the operation will be displayed on the left half of the schematic. These are defined in the Flow Regime Legend (see ).

2) Animation Manual Step Control. Simulation of the multistage pumping operation can be advanced automatically or manually. Manual control allows you to focus on details for particular points during the procedure. First, enter a time step (increment) in the Time Step box. Click to advance to the next time step. Click to return to the previous time step. Click to skip to the end of the operation. Click to return to the start of the operation.

3) Animation Speed Slide. Allows the animation speed to be decreased or increased by moving the slider control

to either to or icon respectively.

4) Animation Control Buttons. Select to begin the animation sequence. During the simulation, the [Pause] and [Quit] buttons become available for halting the simulation at any depths of interest. If you click [Pause], the animation can be continued from that point by clicking [Continue].

5) Pressure Graph. Pressure at the point of interest (POI) is plotted as the job progresses. The POI is assigned on the Operation input page. If “Hide formation page tab” is not checked on the General Options window (Section 26.7), pore and fracture pressure lines will be displayed in the pressure graph. These will clearly illustrate periods during the job, if any, when formation limits were exceeded.




6) Animation Color Legend. The color legend defines the color of each fluid as it moves through the well during the animation. Fluid colors may be modified on the Fluids input page.

7) Animation Monitor Panel. The monitor panel within the Animation window displays values for each critical parameter during the simulation. Values for each time step are continuously updated along with the graph. Click

or use the manual step control () to freeze the displayed data for more careful analysis at any time of interest during the pumping process. The data in the monitor panel may not be edited from this screen.

Note: POI = Point of Interest, as defined on the Operation page.

8) Flow Regime Legend. This table presents the legend for fluid flow regimes depicted in the left side of the wellbore schematic. To activate the display of flow regimes check the Flow Regime check box.The Flow Regime display can be seen at any stage, including whilst running the animation.

Hydrostatic Pressure (Graph) Tab

The second tab in the Animation window presents a graph of wellbore pressure at a specific time. You can specify the time by halting the animation as desired, or directly entering the time between the step control buttons on the Flow Animation tab. After you enter a time, click [Redraw] and return to this Hydrostatic Pressure (Graph) tab.

Editing the Hydrostatic Pressure Graph

The Edit menu can be accessed easily by right-clicking over the graph. Options on this pop-up menu are described in Section 3.4. In addition to opening a separate larger window, you can export the graph to Excel along with its data for further analysis.

Hydrostatic Pressure (Table) Tab

The third tab in the Animation window presents a table of wellbore pressures at a specific time. You can specify the time by halting the animation as desired, or directly entering the time between the step control buttons on the Flow Animation tab. After you enter a time, click [Redraw] and return to this tab.


1111

Wear Groove

Drill Pipe

Tool Joint

Casing

Tension

11. CASING WEAR MODEL

Petris’ Casing Wear model is the industry’s most widely used engineering tool for calculating and monitoring the progression of material wear due to rotary contact of drill pipe with casing, riser, and other downhole elements. This unique program was originally developed by Maurer Technology under sponsorship of the joint-industry project DEA-42 – Casing Wear Technology. The model accurately predicts the location and magnitude of wear in casing and riser strings for both onshore and offshore geometries. It predicts volumetric casing wear by:

1. Calculating the energy imparted by rotating tool joints to the casing wall along the casing string(s) and

2. Dividing this by the amount of energy required to wear away a unit volume of casing material.

Lateral forces along the drill string press the tool joint against the casing, and are a combination of gravity, buoyancy, tension, stiffness, and hole trajectory geometry. Depth of the wear groove at each point along the casing is calculated from volumetric wear.

A critical element in the mathematical model that evolved from theoretical development of a useful algorithm for casing wear is the “wear factor.” This empirically-derived quantity represents the energy required to remove a unit volume of casing material for a given set of physical conditions (casing/tool-joint material and geometry, drilling fluid, solids content, etc.). It was determined during the development project that wear factor cannot be reliably predicted for new materials based on simple material properties. Rather, it must be measured under controlled laboratory conditions. Wear-factor data were measured and are incorporated into the program from an extensive variety of laboratory tests conducted as part of the DEA-42 project. Evaluation and application of the appropriate wear factor is the crucial element that allows the model to become a practical and accurate engineering tool.

11.1 Input

11.1.1 Project Page The Project input page for the Casing Wear model is very similar to the typical DrillNET Project page. See Section 3.2.1.

11.1.2 Survey Page The Survey input page for the Casing Wear model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

11.1.3 Wellbore Page The Wellbore input page for the Casing Wear model is very similar to the typical DrillNET Wellbore page. See Section 3.2.4.

CHAPTER 11: CASING WEAR MODEL



1) Tool-Joint Parameters. Specify the geometry of the drill-string tool joints in the upper section of the drill pipe. These quantities have a direct impact on casing wear. The final (deepest) survey depth is displayed for reference. To edit this value, open the Survey page (see Section 3.2.2).

The Tool joint contact length is the length of joint making contact with the wellbore or casing on a single length of drillpipe. The following defines the length based on the illustration below.

0 <=tool joint contact length < = tool joint length ( A + B)

Pipe Protector Parameters. The number and position of pipe protectors that will prevent excessive wear are calculated and displayed in a special graph in the output window. A description of the protector model is presented in Section 28.6.7. Enter design values for: Maximum Lateral Load per Protector – maximum load to be supported by each pipe protector to avoid damage to the protector; and Maximum Lateral Load per Tool Joint – maximum load a tool joint can bear before a pipe protector is desired.




2) Operation Table. Any number of drilling operations can be specified in the table. Each row represents a single sub-operation for which the operating mode and speeds can be considered constant.

In the first column, select the appropriate drilling operational mode from the three options provided. Input parameters required will change to reflect each selected operation.

Drill – For this case, initial casing wear is zero if the casing is new. Wear will be accumulated as the specified interval is drilled. In previous versions of the casing wear model, “Redrill” was another option for those cases where previous casing wear existed, i.e., wear from previous drilling operations. This is now combined into the “Drill” mode since the program automatically tracks multiple operations in turn, accumulating casing wear as appropriate.

Ream – Here the initial wear is wear accumulated during previous drilling operations. Practically speaking, reaming upward is drilling with negative bit weight.

Rotate Off Bottom – This is rotation of the drill string for a specified time without weight on bit or upward/downward movement. If the specified stroke length is less than a joint span, then the program will concentrate the wear at one position. If stroke length is greater than a joint span, then wear is calculated as normal (all rotating time/sliding distance is averaged over the entire string).

For all these operations, wear is based on the previous operation’s wear result. For example, the second operation (the second row in the Operation table) is based on and accumulated with the first operation’s wear results. The first operation (row 1 in the Operation table) is based on the current wear history data in the Wear Log Data table on the Wear Factor page (see Section 11.1.5).

Section Start and End MD specify the starting and ending positions of the bit for the operation specified. ROP, RPM and WOB control the volume and magnitude of sliding contact between the tool joint and casing.

For each row of the Operation Table, the Tubulars for Operation Table (see ) must be completed. The active row (for which tubulars are displayed below) is shown with blue text in column 1.

3) Tubulars for Operation Table. Every sub-operation listed in the Operation Table (see ) must have a set of tubulars specified for it. Correspondingly, the contents of the Tubulars for Operation table change depending on which row is selected in the Operation Table. The current row is indicated by blue text in the Operation Table in column 1 as well as listed in the title of the Tubulars for Operation table (“Tubulars – for operation row: 5”).

For each operation row, enter tubulars to be used during that sub-operation. The right-most column, “Description,” is optional.



11.1.5 Wear Factor Page

1) Wear Factor Selection. You can select the number of wear factors to be used for each wear analysis based on your preferences and the data available. Depending on the information describing the wellbore conditions and which (if any) field measurements are available, the analysis can be simple (a single wear factor for the entire well) or more complicated (a different wear factor for various sections of the well).

Above the wear-factor table, select one of three basic options for casing wear factors:

1. Assign a single wear factor for the entire well. Click “Single wear factor” and enter a wear factor in the box.

2. Assign wear factors that vary along the well from the top down. Click “Input along riser/casing” and define the length of each section for each wear factor in the wear factor table starting from the surface. This option is used for riser/casing strings with multiple sections, especially with different materials, so that wear factor can vary for each section as needed.

3. Assign wear factors that vary along the well from the bottom up. Click “Input along drillstring” and define the length of each section for each wear factor in the wear factor table starting from the bit. This is useful if the user prefers to have wear factor track different types of tool joints.

Consider Drill Pipe Contact with Casing. The algorithm now accounts for wear caused by contact with the body of the drill pipe (that is, in addition to the tool joint). When drill pipe under high tension loads passes through a section of the wellpath that is sufficiently sharply curved, the drill pipe body can contact the convex




side of the casing. Thus, the resultant wear rate of the casing will be affected not only by the characteristics of the tool joints, but by the wear characteristics of the drill pipe body as well.

The effect of drill pipe contacting and wearing the casing can be accounted for by calculating and applying an effective wear factor of the section(s) of drill string where both tool joints and drill pipe body contact the casing. This effective wear factor will be intermediate to the wear factors for the tool joint and for the drill pipe body.

Note that the Wear factor for drill pipe body is defined separately in the box immediately above the [Expert System] button. The wear factor for the drill pipe body is also used for flex-joint wear, for cases where the riser/casing string contains a flex-joint section.

Unselect this option if you want to ignore instances where the body of the drill pipe contacts casing/riser.

2) Wear Factor Expert System. As an aid in the selection of the best wear factor(s), an Expert System is incorporated into DrillNET. The Expert System captures a large portion of laboratory test results conducted during the DEA-42 project. A series of options allows you to quickly determine suggested wear factors. See Section 11.3.2.

3) Wear Factor Database. The Wear Factor Database provides more comprehensive results from DEA-42 laboratory testing. The extensive database covers a broad range of drilling conditions and casing/tool-joint combinations for engineers to compare. See Section 11.3.3.

4) Set Casing Liner. After casing wear is calculated, you can return to the Wear Factor page and enter a new casing or liner string.

Select “Set to new casing” to remove all calculated wear from the string. This can be used when you want to calculate wear based on a new casing string.

Select “Set liner or side track” to enter a depth for a new string. Below the liner top or side-track point, casing wear will be set to zero and the program will prepare a new wear log data set. The MD range of this new data set is from surface point MD to liner top or side track point MD. If you click [Apply], this new set of wear log data will be exported to the “Previous” Wear Log Data table as the new initial condition for the drilling operations listed.

5) Wear Log Data Tables. Wear history data with depth are shown for review. Two sets of wear history data are displayed for easy “before and after” comparison. These are referred to as “Previous” and “Results.”

Drill Pipe Contact with Casing

Tool

JointTool

Joint



Either data set can be modified by opening a new file by right-clicking and selecting “Open Previous Wear Log File..”. You can also enter or change data directly in the table. To edit Current or Previous wear-history data or enter new data, click on or move the cursor to the row and cell of interest and type in new data. The first three columns (with yellow background) are not editable. These are based on the survey positions and other important transition points in the wellbore geometry. Cells with white background may be changed as desired.

If you enter a new wall thickness at any depth, the corresponding Wear % will be calculated and updated automatically. Rows cannot be inserted or deleted from the Wear Log Data tables.

6) Update Previous Wear. After a calculation of casing wear is completed, you can return to the input window to review wear before and after the run (in the Wear Log Data table “Previous” and “Results,” respectively). If you want the output saved into the file permanently, click [Update Previous Wear] to copy the “Results” table into the “Previous” table.

11.1.6 Preferences Page

1) Buckling Model Options. Select one of the three models provided for estimating sinusoidal and helical buckling criteria. The models produce different results based on different assumptions used in their respective derivations. A discussion of these models is presented in Section 28.9.3.

2) Burst and Collapse Strength Models. Three models (the Biaxial, API and OTS equations) are provided for calculating burst and collapse strength of worn casing. The default selection is the biaxial model. See Section 28.6.6 for a discussion of these models.




3) Torque/Drag Options for Wear. Select “Helical buckling friction force considered” to account for compressional forces due to helical buckling. The radial component of these forces pushes the string against the borehole wall. This extra side force causes added friction. If the force is large, the string may be subjected to additional wear.

Select “Bending stiffness considered” to account for the impact of drill-pipe stiffness on the onset of buckling in curved sections of the wellbore. The conventional soft-string torque and drag model (Johancsik et al., 1983) assumes that loads on the drill string result solely from effects of gravity and drill-string frictional drag resulting from the contact of the drill string with the wall of the hole in a directional wellbore. If you uncheck this option, the program uses the soft-string model (i.e., pipe stiffness will not affect the calculation). For directional wellbores with a short radius and a drill string with high bending stiffness, additional normal force between the wellbore and the drill string could be significant, and this bending stiffness effect should not be neglected. To account for drill-string stiffness, check this option to include bending stiffness in torque and drag calculations (which impact wear).

11.2 Output Output for the Casing Wear model includes results under three tabs:

1. Summary – Displays values for key buckling parameters


3. Casing Wear Chart – A multiparameter comparison of casing/riser wear with depth (see below)




11.3.1 Tool-Bar Icons Special tool-bar icons are provided when the Casing Wear Model is selected. These include:

Field Wear Match. Opens the Field Wear Match window (see Section 11.3.4) for calculating/calibrating wear factors based on field measurements of casing wear.

Casing Wear Schematic. Opens the Casing/Riser Wear Schematic window (see Section 11.3.5) for reviewing the magnitude of wear along the entire casing and/or riser string.

Riser Strength Analysis. Opens the Riser Strength Analysis window (see Section 11.3.6) for displaying a special set of output graphs for considering burst and collapse of a riser string with a wear groove.

11.3.2 Wear Factor Expert System As mentioned previously, a critical element in the mathematical model for casing wear is the “wear factor.” This is an empirically-derived quantity that represents the energy required to remove a unit volume of casing material for a given set of conditions (casing/tool-joint geometry, drilling fluid, solids content, etc.). It was determined during the development project that wear factors cannot be reliably predicted based on specifying material properties and operational parameters. Wear-factor data were measured via standard laboratory testing conducted as part of the DEA-42 project along with later data from private testing for individual manufacturers.

As an aid to DrillNET users in the selection of the best range of wear factors, an Expert System is incorporated into the program. The Expert System captures a large portion of laboratory test results conducted during the DEA-42 project. This is accessed by clicking [Expert system] on the Wear Factor page (see Section 11.1.5).

Within the Expert System window, select the tool-joint material, drilling fluids, additives, lubricants and other pertinent parameters. A range of wear factors derived from laboratory data and a suggested value are displayed for every combination of drilling conditions listed. This utility is for viewing only; data may not be edited or exported back to the input window.

11.3.3 Wear Factor Database The Wear Factor Database provides a summary listing of wear factor measurements from DEA-42 laboratory testing along with various results from later tests sponsored by tool-joint hardbanding and casing manufacturers. The extensive database covers a broad range of drilling conditions and casing/tool-joint combinations. Engineers can review data from multiple tests for a given set of conditions, as well as review test results on unusual hardbanding and other products.

The database is accessed by clicking [Database] on the Wear Factor page (see Section 11.1.5). The Wear Factor Database is designed for viewing only; data may not be edited or directly exported back to the input window.




11.3.4 Field Wear Match Window The Wear Factor Field Match window is a special utility used to calculate/calibrate wear factors based on field measurements of casing/riser wear. Wear factors can be back-calculated based on past drilling operations and field

measurements of wear depth for any location on a well. This window is accessed by clicking the icon or selecting “Field Wear Match…” from the Tools menu.

At the top of the window, first enter a depth for which measured wear depth is available. This is the “point of interest.” The results displayed in yellow cells will be updated automatically for that MD. Casing wear results shown here are based on the current input data on the input pages.



Next, in the lower portion of the window, enter the measured wear depth corresponding to the current depth of interest. An effective wear factor is then automatically calculated and displayed in the yellow text box at the bottom.

If the wear depth you enter is equal to or greater than the casing wall (i.e., 100% wear), the wear factor calculated and displayed is the minimum wear factor required to wear through the casing exactly at the end of the prescribed operation. Therefore, the actual field wear factor may have been greater than the effective wear factor displayed.

11.3.5 Casing Wear Schematic Window The Casing Wear Schematic window is a secondary output window used to view the wear profile of the complete

riser and casing string. This window is accessed by clicking the icon or selecting “Wear Schematic…” from the Tools menu.




1) Wear Graph. A scaled plot of wear % with depth is presented. Since wear often correlates with doglegs in the wellpath, inclination and local dogleg with depth are also displayed. This wear schematic may depict the entire well, the riser, or the casing only. Select the display in the upper right section of the window.

You can select a depth of interest by clicking the mouse over the graph. Position and click the mouse pointer at one or more depths of interest. Data corresponding to these depths will be added and displayed in the data tables at the bottom of this window.

2) Wear Schematic Single Depth Results. Wear results for a specific depth are shown in the yellow boxes. Any measured depth (MDs) of interest can be selected, its parameters reviewed, and summary results entered into the Summary Table at the bottom of the window.

Select MD’s by (1) clicking the mouse pointer over the wear schematic (the MD will be updated in the text box automatically) or (2) typing a MD into the box directly. After typing in a new MD, press <Enter> to select that depth and update the parameter boxes.

As the mouse pointer is moved over the wear schematic graph area (), the MD box will be updated to display the current depth of the pointer position. At any depth of interest, click the mouse to select that MD. To add the currently displayed dataset to the summary table, click [Add to Table]. Parameters associated with that depth are now displayed in ascending order in the table.

3) Wear Schematic Summary Table. Wear summary data for several depths of interest can be selected and collected in the Summary Table. Each time a new depth is selected by clicking on the wear schematic or by typing in a MD and clicking [Apply], data for that depth will be added to the table. Click [Clear] to clear all rows of the Summary Table.

Right-click over the table to access the additional options: copy the table; print the table; or view as a separate window.

11.3.6 Riser Strength Analysis Window A special set of output windows is provided for analyzing riser strength. The impact of a wear groove is considered as it affects burst and collapse. The user can select a preferred model on the Preferences page (see Section 11.1.6).

This feature is available only when you have input riser data, and is accessed by clicking the icon or selecting “Riser Strength…” from the Tools menu.



Results of calculations for the current input parameters are displayed graphically in six windows. These may be reviewed in any order by double-clicking on a plot to maximize it. Output presentations include:

1. Collapse Failure in Riser. This graph shows how collapse strength of the riser (at the depth you specify) is be degraded by wear. The worst case is assumed, such that mud weight in the riser is zero (the riser is evacuated). Failure is predicted at the point where the external hydrostatic pressure (red line) equals or exceeds the derated collapse strength. Change the MD of Interest at the bottom of the window.

2. Collapse Failure at Bottom of Riser. This graph shows how collapse strength of the riser at the bottom is degraded by wear. Here, the worst-case position at the bottom of the riser is always considered, and mud weight of the column of fluid in the riser is as you specify in the lower part of the window. Collapse strength of worn riser is calculated based on one of three models you selected on the Preferences page (see Section 11.1.6).

3. Minimum Fluid Height in Riser (collapse failure). The minimum fluid height required to keep the riser from collapsing is shown to increase as riser wear increases.

4. Burst Failure in Riser. This window shows how burst strength of the riser (at the depth you specify) would be degraded by wear.

5. Burst Failure at Bottom of Riser. This graph shows how burst strength of the riser at the bottom is degraded by wear. Here, the worst-case position at the bottom of the riser is always considered, and mud weight of the column of fluid in the riser is as you specify.

6. Maximum Mud Weight in Riser (burst failure). As another way to consider burst failure, this graph shows how maximum permissible mud weight would be decreased by wear. As before, the analysis corresponds to the location (depth of interest) along the riser you specify.

At the bottom of the window you can change the depth of interest and mud weight under consideration. Click [Calculate] to update the graphs after you change any parameter.


112212. CENTRALIZER DESIGN MODEL The Casing Centralization Model is an accurate engineering program for computing centralizer spacing to provide sufficient stand-off between casing strings and the wellbore wall.

Casing centralization is important to achieve a good cementing job. A casing string tends to contact the wellbore wall in an inclined wellbore, or even in a vertical wellbore, due to gravity and the axial tension along the casing string. Casing centralizers are designed for use on the casing string to prevent the casing from touching the wellbore wall and to provide sufficient stand-off between the casing and wellbore wall, so that the cement slurry displaces the drilling mud in the wellbore annulus during the cementing operation. The casing centralization program to help engineers design the most efficient spacing for centralizers.

The program describes the complex concepts of tubular bending in a 3-D wellbore. The mathematical model consists of tubular bending analysis and centralizer displacement calculations. The model is suitable for 3-D wellbores (vertical, inclined, and horizontal) for both onshore and offshore applications. It also calculates running casing into wellbores. The program allows the user to select either the fixed-end or hinged-end models to analyze casing deflection.

The program also allows you to select the equal spacing or minimum stand-off design. Bow-spring and rigid (positive) centralizers can be used together. The program predicts actual stand-off between the casing and wellbore wall for equal-spacing designs, and predicts required spacings for minimum stand-off designs. It also predicts hook loads for running casing into the well. It also presents a single-span casing analysis for straight and curved wellbore sections. The single-span analysis describes the concepts of casing deflection, stand-off, and the effect of spacing, axial tension and fluid density on casing stand-off.

12.1 Input

12.1.1 Project Page The Project input page for the Centralizer Design model is very similar to the typical DrillNET Project page. See Section 3.2.1.

12.1.2 Survey Page The Survey input page for the Centralizer Design model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

12.1.3 Tubulars Page The Tubulars input page for the Centralizer Design model is very similar to the typical DrillNET Tubulars page. See Section 3.2.2.

The data input beneath tubular will be the casing string and any drillpipe that may be used to run the string if it for example a liner that will be hung off at the base of an existing section of casing or in the case of an offshore location it may be drillpipe used to run the casing to the casing hanger located at the seabed. If the casing will extend to surface then the tubular section will contain just the casing string to be run. The “Description,” column, although optional, helps distinguish between different casing sections in the output.

12.1.4 Wellbore Page The Wellbore input page for the Centralizer Design model is very similar to the typical DrillNET Wellbore page. See Section 3.2.4.

In addition, there is the option to include a value for the Friction Factor. Friction along the wellbore must be specified so that torque and drag can be calculated. An ID and friction factor is required for each section. If friction factor is unknown, by right clicking within the Wellbore page, the Friction Factor option can be selected from the option list.

CHAPTER 12: CENTRALIZER DESIGN


A reference window is provided for estimating friction factor for a range of conditions. Review the table of representative values presented. Choose the most appropriate value(s) based on the area of operations and anticipated field conditions. “Actual Friction Factors” are those reported by operators and service companies for operations in real wells. “Predictive Friction Factors” have been increased to account for differences between drag predicted in smooth planned wellpaths and that observed in real wells. Apply the predictive friction factors at the planning stage when only planned (smooth) well surveys are used.





1) Casing Deflection Model. Select one of two models for casing deflection. The primary difference between the models is the boundary conditions at the centralizer/casing contacts. The Lee, Smith & Tighe model was the first mathematical treatment developed and is based on the simplifying assumption that the casing/centralizer support point behaves as a hinge. No bending moments are transferred down the casing string across the support point. Stiffness of the casing is assumed to play no role at the centralizer. Although this assumption simplifies the math, bending moments are transferred across real casing. The Juvkam-Wold & Wu model was later developed to treat the casing string as fixed at the centralizer, with bending moments transferred across the interface.

The Lee, Smith & Tighe is a simpler model and would be expected to yield conservative results. The Juvkam-Wold & Wu model is considered to be more accurate.

2) Centralizers. Select the option “Minimum Stand-Off” if you want to calculate the centralizer spacing required to maintain casing stand-off above your limit along the entire string.

Casing Length (normalized)

Cas

ing

Def

lect

ion

(nor

mal

ized

)

Hinged Ends

Fixed Ends



Select the option “Equal Spacing” if you want to input values for centralizer spacing and then determine the casing stand-off resulting from this design.

In the centralizer data table, specify whether centralizers are present in each section of the tubular string. In sections in which they are present, select the type of centralizer from the drop-down list provided. The centralizer can either be a Spring Bow or a Rigid centralizer.

Select None if no centralizers are used on that section of the tubular string;

Select Spring Bow for bow-spring centralizers;

Select Rigid if the centralizer is a solid construction fixed on the casing.

For each option, appropriate parameters will become active (their backgrounds will turn from gray to white).

Input the Spacing between centralizers, the Restoring Force, which is the maximum spring force the centralizer can provide to lift the casing off the wellbore wall; the Starting Force required to start moving the centralizer in the well (i.e., overcome static friction), and the Rigid Blade OD, as required.

Stand-Off Ratio is required for Minimum Stand-Off calculations. This is the ratio of calculated stand-off compared to that of a perfectly centered casing. A stand-off ratio of 100% means the casing is centered; a stand-off ratio of 0% means the casing is touching the borehole wall. Enter the minimum value you will accept in the table. A typical value would be in the order of 70%.




The Inside and Outside Fluid will usually be drilling fluid or mud as the inside fluid and cement as the outside fluid.

3) Bending Stiffness Select whether to include the effect of bending stiffness in the torque and drag calculations. This effect is normally very small and neglected. In some applications, it is useful to compare torque and drag with and without the contribution of bending stiffness. This can gauge whether reducing pipe stiffness would be an effective approach to reducing torque and drag.

On completion of the data entry and as long as all tab icons are green, click on the View Output icon to process the data and generate the output graphs and tables.

12.2 Output Output for the Centralizer Design model includes results under two tabs:

Summary – Displays input parameters



Graphs/Tables – A typical DrillNET multi-featured output display allowing selection of individual or multiple graphs (see Section 3.3) and display tables of data.

Output presentations when “Minimum Stand-Off” is the selected mode of calculation include:

1. Centralizer Spacing Graph. This graph displays a plot of recommended centralizer spacing for the entire casing string. (Note that zero spacing denotes no centralizers needed.)




2. Hook Load During Rnning Casing Graph. This graph displays a dynamic plot of hook loads at the surface when the bottom of the casing is at each MD along the well.

3. Load on String When Cementing Graph. This graph displays a snap-shot plot of axial loads along the casing string during cementing.

4. Centralizer Spacing versus MD Table. This table displays the data plotted in Graph 1.



5. Hook Load versus Casing Bottom MD Table. This table displays the data plotted in Graph 2.

6. Load on String versus MD Table. This table displays the data plotted in Graph 3.

When “Equal Spacing” is the selected mode of calculation, Graph 1 is changed to Centralizer Stand-Off Ratio.




12.3 Sensitivity Analysis Window The Sensitivity Analysis window is a secondary output window used to analyze the relative impact of changes in individual parameters while other parameters remain constant. This type of analysis can be very useful for determining which parameter(s) are of critical importance for a specific operation, so that careful monitoring might be required, more precise measurements will need to be obtained, etc., to ensure the success of the planned field operation. Conversely, other parameters may be found to have little impact and not require rigorous optimization. This window is accessed by clicking .

1) Sensitivity Parameters. Select one parameter to be varied while others are held constant. Enter in the table the range over which the parameter of interest will be varied (i.e., white cells in Range Low End and Range High End). Base-case constants for the other parameters are assigned default values corresponding to those assigned within the current project file. You can change any parameter to a different value within this window without impacting the project data in the main input window.

2) Graph Type Option. Select a Graph Type option: (1) Static for a snapshot of loads when the BHA is at the depth of interest or (2) Dynamic for varying the selected parameter across its range with the BHA at the bottom.

3) Fluid Weight, Friction Factor and Adjusted Weight Prompts. These drop-down boxes recall and fill in parameters for each defined section of the wellbore. If you click on any of the wellbore sections listed in the drop-down boxes, the corresponding parameter will be copied from the main input window into the Sensitivity Parameter input table.

4) Sensitivity Output Tables and Graphs. When the sensitivity analysis is performed, the parameter under consideration is varied across its range in 10% increments and a calculation completed at each step. Results for each step are recorded in the output table in 11 rows. Sensitivity results are also summarized in two graphs, one for current life and one reference graph of previous life.

Click Calculate to perform calculations on the selected input data and Print to print the input, output results and graphs.


113313. TORQUE & DRAG FOR LINER CEMENTING MODEL

The Torque & Drag for Liner Cementing Model, was developed by Maurer Engineering Inc. as part of the DEA-44 joint-industry project to “Develop and Evaluate Horizontal Well Technology.” The application is a premier engineering program for computing torque and axial load on the string when cementing liners and is used for designing and monitoring operations in deviated, horizontal and extended-reach wells. The program calculates torque and tension/compression loads (drag) on a liner while cementing. During cementing, where cement is in the liner and has not yet flowed around the liner shoe, excessive torque loading can occur. An increased down-thrust load occurs since the cement is heavier than the mud or preflush on the outside of the casing. This situation can damage a rotary and/or reciprocation liner hanger and may prevent rotation and/or reciprocation of the liner. Torques and tension loads can be determined by Torque & Drag for Liner Cementing to prevent this occurrence.

The program is useful for:

Designing the liner string

Preventing liner connection failures

Monitoring liner torque and tension loads

Designing connections for horizontal wells

13.1 Input

13.1.1 Project Page The Project input page for the Torque & Drag for Liner Cementing model is very similar to the typical DrillNET Project page. See Section 3.2.1.

13.1.2 Survey Page The Survey input page for the Torque & Drag for Liner Cementing model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

13.1.3 Tubulars Page The Tubulars input page for the Torque & Drag for Liner Cementing model is very similar to the typical DrillNET Tubulars page. See Section 3.2.3.

13.1.4 Wellbore Page The Wellbore input page for the Torque & Drag for Liner Cementing odel is very similar to the typical DrillNET Wellbore page. See Section 3.2.4.

CHAPTER 13: TORQUE & DRAG FOR LINER CEMENTING MODEL




1) Operation Mode. Select one primary operating mode that describes the movement of the tubular string during the cementing operation.

2) Bending Stiffness. Check “Include Bending Stiffness” to account for the impact of tubular bending stiffness on the bending tubular in curved sections of the wellbore. The conventional soft-string torque and drag model (Johancsik et al., 1983) assumes that loads on the tubular string result solely from effects of gravity and tubular string frictional drag resulting from the contact of the tubular string with the wall of the hole in a directional wellbore. If you uncheck this option, the program uses the soft-string model (i.e., tubular stiffness will not affect the calculation). For directional wellbores with a short radius and a drill string with high bending stiffness, additional normal force between the wellbore and the tubular string could be significant, and this bending stiffness effect should not be neglected. To account for tubular string stiffness, check this option to include the impact of bending stiffness on stress.

Note: the meaning of “impact” is “effect”

3) Friction factor with Cement. Cement differs from other drilling fluids in that it has a higher weight and viscosity, and contains considerably more solid materials in suspension. This results in extra torque and drag as



the cement passes through the shoe and enters the annulus. A higher friction factor is used to model this effect during calculating the friction force between the tubular and wellbore in a cement slurry. Enter a value larger than normal to account for this effect.

4) Liner Motion. Axial and rotary velocity of the tubular string affects hook load when cementing. Enter values for Running Speed (axial reciprocation velocity with respect to the wellbore) and Rotary Speed as indicated at the rotary table.

5) Point Of Interest. “Point of Interest” includes three parts: Fluid of interest, Injection percentage, and Well section of interest.

Fluid of interest is one of the pumped fluids.

Injection percentage (%) is the percentage of the volume of pumped fluid to the total volume of the fluid

Well section of interest allows selection of one of the different well sections.

6) Fluid. Cementing fluids to be pumped during the complete operation. Input the Fluid Type (Mud or Cement), Weight and Volume, the Pumping Rate, a brief Description and final choose a colour from the pull down list for the fluid which will be used in the animation option.

7) Centralizers. To achieve a good cementing job and produce a good cement shell between the casing and wellbore wall, the centralizers (casing centralizers) are used to lift the casing up from the annulus and maintain a certain stand-off between the casing and wellbore wall. In this section, users can input casing centralizers information.

13.2 Output Output for the Torque & Drag for Liner Cementing model includes results under two tabs:

Summary – Displays input parameters




Graphs/Tables – A typical DrillNET multi-featured output display allowing selection of individual or multiple graphs (see Section 3.3) and display tables of data.

Output presentations when “Reciprocation and Rotation” is the selected mode of operation include:

Graphical output

Load on String versus (Reciprocation And Rotation). This graph displays a plot of hook load (pick up and slack off) as the liner is reciprocated and rotated while cementing or while mud and cement stages are being pumped into the liner and annulus.

Torque (Reciprocation And Rotation). The torque experienced by each section of the string is compared for the cementing operation.

Torque on Top of Upper Pipe. This dynamic-style graph shows a history of torque at the top of the liner (or other section of the string) for pick up and slack off throughout the complete pumping operation.

Load on String and on Top of Upper Pipe. . This dynamic-style graph shows a history of pick-up and slack-off loads at the top of the liner (or other section of the string) throughout the complete pumping operation.

Tabular output

Load on String vs MD (table). The data shown in graphs 1 and 2 are presented in tabular format.

Maximum Load on String And Torque

o Maximum Load on String is the maximum axial load on specified string section during pumping fluids.



o Maximum Torque on String is the maximum torque in specified string section during pumping fluids.

Load on String And Toque vs Pumping Time. The data shown in graphs 3 and 4 are presented in tabular format.

If the Operation Model on the Operation tab is set to use Reciprocation Only or Rotation Only

the Display Graphs(s) output option reflects the change in the Operation Model selected.

13.2.1 Sensitivity Analysis Window The Sensitivity Analysis window is a secondary output window used to analyze the relative impact of changes in individual parameters while other parameters remain constant. This type of analysis can be very useful for determining which parameter(s) are of critical importance for a specific operation, so that careful monitoring might be required, more precise measurements will need to be obtained, etc., to ensure the success of the planned field operation. Conversely, other parameters may be found to have little impact and not require rigorous optimization.

This window is accessed by clicking or selecting “Sensitivity Analysis” from the Tools menu.




1) Torque/Drag Sensitivity Output Table and Graphs. Sensitivity results are summarized in two graphs.

These show the results for each step. To perform the sensitivity analysis, the parameter under consideration is varied across its range in10% increments and a calculation performed at each step. Results for each step are recorded in the output table in 11 rows.

Editing the Sensitivity Graphs

The Edit menu can be accessed easily by right-clicking over any graph. Options on this pop-up menu are described in Section 3.4. In addition to opening a separate window containing one graph, you can export a graph to Excel along with its data for further analysis.

2) Graphics Type. Dynamic or Maximum

Selected Graph Type option: 1) Maxinum for maximum load vs. measured depth along the tubular string at a specific time and condition, or 2) Dynamic for surface load history vs. measured depth of the BHA during complete slack-off/pick-up operations.

3) Operating Mode. Choose from Reciprocation only, Rotation only or Reciprocation and Rotation.

4) Sensitivity Parameters. Select one parameter to be varied while others are held constant. Enter the minimum and maximum values for the range of variation for the selected parameter. Base-case constants will be used for the other parameters, which are assigned default values corresponding to those assigned on the current main input pages.



To analyze sensitivity, the parameter under consideration is varied across the defined range in increments and a calculation performed at each step.

5) Friction Factor and Adjusted Weight Prompts. These drop-down boxes assist in recalling friction-factor and adjusted-weight data for individual sections of the drill string. If you click on any of the string sections listed, the corresponding friction factor or adjusted pipe weight will be copied from the main window into the Sensitivity Variable input table.

13.2.2 Animation Window The Animation window is a secondary output window used to view a simulation of the cementing process.

Here you can review the expected and torques at the top of the liner string as the operation progresses. This window is accessed by clicking.

1) Animation Parameter Table. The values of time, fluid volume pumped, and torque are shown in the table and

updated for each time step of the animation. In the first column, you may choose any of the strings you defined on the Tubulars page. Loads and torques will be displayed for the selected string.

2) Animation Wellbore Schematic. The schematic shows a simulation of the process of pumping all fluids into the wellbore. Different colors in the casing and annulus are used to show each fluid stage. The legend that defines the current colour assignments is shown in the animation fluid color box.




3) Animation Control Buttons. [Start] begins a new animation sequence with the first fluid stage just entering the well. Click [Pause] to freeze the animation at the current time step. Click [Continue] to proceed with the animation. [Stop] will halt the current animation.

4) Animation Graphs. Loads and torques at the top of the liner are displayed in graphs and continuously updated as the animation progresses.

5) Animation Speed. The speed of the animation can be set anywhere from real-time speed (speed = 1) to 10 times faster than real time (speed = 10).

6) Animation Fluid Colors. This table is a legend for the wellbore schematic fluid colours and weights. The fluid colours can be changed in the Operation input tab if required.

13.2.3 Utilities The utilities are accessed by clicking the icon or selecting “Utility” from the Tools menu. In Torque & Drag for Liner Cementing the utility can be used to calculate fluid volumes inside the casing or in the annulus between any two depths. The current wellbore hole and casing geometry is shown schematically.

There are three methods to select an interval for calculation of volume:

Select MDs at major transitions from the drop-down list

Type the depths into the MD box (this is allowed if you leave the drop-down boxes set to “Point 1” and “Point 2”

Click directly on the graphic. The first click selects Point 1; the second selects Point 2.



Enter a depth of zero to start the interval from the surface. Click [Calculate] after you enter or modify depths in the text boxes.

After two depths are selected, the interval will be shown in the wellbore schematic as a coloured zone. Blue represents the interval inside tubing; green is the selected annular section.

Calculated results are shown in the lower right corner. Shown are TVD of the two depths and volumes of fluid inside the tubing and in the annulus.


114414. TORQUE & DRAG FOR DRILLSTRING MODEL

The Torque & Drag for Drill-String model analyzes the complex phenomena of axial and torsional loads, and the development of torque and drag (and buckling) of drill pipe as it is run into and out of the hole. For compressive loads, the onset of (1) sinusoidal buckling, (2) helical buckling, and (3) pipe yield are indicated. This model is widely used for designing and monitoring operations in deviated, horizontal and extended-reach wells. It can also be applied to casing, liners, or tubing-string applications.

14.1 Input

14.1.1 Project Page The Project input page for the Torque & Drag for Drill-String model is very similar to the typical DrillNET Project page. See Section 3.2.1.

14.1.2 Survey Page The Survey input page for the Torque & Drag for Drill-String model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

14.1.3 Tubulars Page The Tubulars input page for the Torque & Drag for Drill-String model is very similar to the typical DrillNET Tubulars page. See Section 3.2.3.

14.1.4 Wellbore Page The Wellbore input page for the Torque & Drag for Drill-String model is very similar to the typical DrillNET Wellbore page. See Section 3.2.4.

CHAPTER 14: TORQUE & DRAG FOR DRILLSTRING MODEL


14.1.5 Parameters Page

1) Torque/Drag Operational Modes. String rotation has a dramatic impact on torque and drag. Axial friction can become very small if the pipe is rotated while it is moved into the well. This occurs because frictional drag acts in a direction opposite to the velocity vector of a point on the surface of the drill pipe. If the pipe is both rotating and moving axially, velocity of the pipe relative to the hole is a combination of two vector quantities—axial velocity and rotational velocity. More discussion is presented in Section 28.9.1.

Boundary conditions at the bottom of the string will depend on the operation being simulated. When the string is going into the hole (slack off or drill), the bottom of the string is in compression. When the string is coming out of the hole (pick up), the bottom of the string is in tension. For drilling or string rotation, a positive value of torsion at the bottom of the string will simulate torque from the bit and BHA. Following are factors that affect bottom boundary conditions for each operation simulated.

Pick-up with Rotation Drag: +BHA drag Torque: +BHA torque

Pick-up without Rotation Drag: +BHA drag

Slack-off with Rotation Drag: -BHA drag Torque: +BHA torque

Slack-off without Rotation Drag: -BHA drag

Drill with Rotation Drag: -BHA drag – weight on bit Torque: +BHA torque + torque on bit

Drill without Rotation Drag: -BHA drag – weight on bit Rotation off Bottom Torque: +BHA torque




2) Depth of Operation. The starting and ending depths define the operating range for the current analysis. This range will impact the data displayed in the output graphs. In output graphs and tables that describe conditions at the BHA or surface, results will be displayed only for this defined depth range. Other output displays summarize loading conditions all along the drill string and will include data from the surface (depth = 0) to the End Point MD.

3) Torque/Drag BHA Loads. Enter operational parameters and loads at the bottom-hole assembly. BHA torque and drag values are usually either engineering judgments or are based on the difference in surface readings between a slick drill string and one containing the BHA or similar assemblies. These values are primarily used with stabilizers or logging tools that go into the hole collapsed and are withdrawn with arms extended.

BHA torque and drag are boundary conditions at the bottom of the drill string. They represent starting points for the calculation of torque and drag, which proceeds upward along the drill string from the BHA.

4) Traveling Assembly Weight and Mud Weight. Mud weight affects buoyancy of the drill string and hook load at surface. Weight of the traveling assembly is a tare weight that is subtracted from hook load to derive actual string weight.

5) Torque/Drag Tripping and Drilling Speeds. Axial and rotary velocity of the string affects hook load when drilling or tripping. Enter all four parameters if you will evaluate both drilling and tripping operations. Otherwise, you may leave the parameters blank (zero) that are not needed. If the selected operation is tripping/drilling with rotation, and string RPM is input as zero, then the torque increment along with drill string will be zero.




1) Buckling Model Options. Select one of the three models provided for estimating sinusoidal and helical buckling criteria. The models produce different results based on different assumptions used in their respective derivations. A discussion of these models is presented in Section 28.9.4.

2) Torque/Drag Design Factors. Design factors are included in the calculation of tension and torsion strength limits. These are the ratio of pipe strength to load. For example, design factors of 2.0 imply that the working limits will be set at one-half the ultimate tension and torsion limits.

Select “Helical buckling friction force considered” to account for compressional forces due to helical buckling. The radial component of these forces pushes the string against the borehole wall. This extra side force causes added friction. If the force is large, the string may be subjected to lock-up.

Select “Bending stiffness considered” to account for the impact of drill-pipe stiffness on the onset of buckling in curved sections of the wellbore. The conventional soft-string torque and drag model (Johancsik et al., 1983) assumes that loads on the drill string result solely from effects of gravity and drill-string frictional drag resulting from the contact of the drill string with the wall of the hole in a directional wellbore. If you uncheck this option, the program uses the soft-string model (i.e., pipe stiffness will not affect the calculation). For directional wellbores with a short radius and a drill string with high bending stiffness, additional normal force between the wellbore and the drill string could be significant, and this bending stiffness effect should not be neglected. To account for drill-string stiffness, check this option to include bending stiffness in torque and drag calculations.

Output for the Drill String Torque/Drag Model includes results under three tabs:

1. Summary – Displays values for key buckling parameters


3. Torque & Drag Chart – A multi-parameter comparison of torque/drag results with depth (see below)




User may now select which curves will be displayed in the Torque & Drag chart by clicking on the legend below any of the chart tracks and selecting which curves will be displayed. This can be useful when curves either overlap or are very close together resulting in obscured information. Simply click in any of the boxes in the legend beneath each track to turn off specific curves from the display.

All curves displayed. SO w/o Rot curve will not be displayed

After choosing the required curves, the Torque & Drag curve will just display only the selected items allowing users to generate output showing just the curves of interest.

Torque & Drag Chart after specific curves have been selected for display.



Torque/Drag Output Formats

Two principal formats are used to display data:

A static “snapshot” format. Load vs. measured depth along the drill string at a specific time and condition (that is, a snapshot of loads on the string when the BHA is at a depth of interest)

A dynamic operations format. Surface and BHA load history vs. measured depth of the BHA during complete slack-off/pick-up operations (that is, a load history at the surface)

For example, output presentations on the Graphs/Tables tab when “Drill with rotation” is the selected mode of operation include:

Axial Drag – Drill with Rotation. This static-format graph displays a plot of load conditions when the BHA is at the depth of interest (i.e., end point MD).

Axial Torque – Drill with Rotation. This static-format graph displays a plot of torque load conditions along the entire string when the BHA is at the depth of interest.

Hook Load – Drill with Rotation. This dynamic-format graph displays a plot of hook load as the BHA moves over the entire range of operation specified on the Operation page.

Surface Torque – Drill with Rotation. This dynamic-format graph displays a plot of torque at the surface as the BHA moves over the entire range of operation specified on the Operation page.

Static Calculation Table. This table summarizes torque and drag conditions and buckling limits along the entire string when the BHA is at the depth of interest (i.e., end point MD).

Dynamic Calculation Table. This table summarizes hook loads and surface torques at each depth over the entire range of operation specified on the Operation page.

Note that the titles of the individual graphs and tables change to reflect the operating mode currently selected.


14.2.1 Tool-Bar Icons Special tool-bar icons are provided when the Drill String Torque/Drag Model is selected. The special icons include:

Sensitivity Analysis. Opens the Sensitivity Analysis window (see Section 14.2.2) for analyzing the relative impact of changes in individual parameters while other parameters remain constant.

Margin Analysis. Opens the Operating Margin window (see Section �) for analyzing the range of safe operational loads (torques and bit weights) and how pipe stresses develop as loads are increased.

Buckling Analysis. Opens the Buckling Analysis window (see Section 14.2.4) for reviewing the accumulation of buckling as the operation you specified progresses. You can also increase/decrease bit load to gauge the impact on buckling.

Sheave Analysis. Opens a utility window (see Section 14.2.5) used to calculate sheave efficiency based on weight indicator readings and loads.

14.2.2 Sensitivity Analysis Window The Sensitivity Analysis window is a secondary output window used to analyze the relative impact of changes in individual parameters while other parameters remain constant. This type of analysis can be very useful for determining which parameter(s) are of critical importance for a specific operation, so that careful monitoring might be required, more precise measurements will need to be obtained, etc., to ensure the success of the planned field operation. Conversely, other parameters may be found to have little impact and not require rigorous optimization.

This window is accessed by clicking or selecting “Sensitivity Analysis” from the Tools menu.




1) Torque/Drag Sensitivity Output Table and Graphs. Sensitivity results are summarized in two graphs. The graphs can be either a snapshot view of drag and torque along the drill string for three sensitivity parameter values (low, middle, and high) when the BHA is at the end point MD, or a “Hook load and surface torque” view of loads and torques at the surface versus the selected sensitivity parameter. These are selected under “Calculate.”



2) Torque/Drag Sensitivity Variable. Select one parameter under “Calculation Settings” to be varied while others are held constant. Enter the minimum and maximum values for the range of variation for the selected parameter. Base-case constants will be used for the other parameters, which are assigned default values corresponding to those assigned on the current main input pages.

To analyze sensitivity, the parameter under consideration is varied across the defined range in increments and a calculation performed at each step.

3) Friction Factor and Adjusted Weight Prompts. These drop-down boxes assist in recalling friction-factor and adjusted-weight data for individual sections of the drill string. If you click on any of the string sections listed,



the corresponding friction factor or adjusted pipe weight will be copied from the main window into the Sensitivity Variable input table.

14.2.3 Margin Analysis Window The Margin Analysis window is a useful tool for increasing an engineer’s understanding of the range of safe loads (torques and bit weights) and how pipe stresses develop as loads are increased. After the specific mode and parameter under consideration are selected, the program calculates the pipe condition at the initial low loading. Then, torque or bit weight is added incrementally until one of the mechanical limits is exceeded. The graph is rapidly updated after each calculation increment, resulting in an animated display. The location on the string where the limit was exceeded is indicated by text at the top of the window. The Operating Margin Analysis window is accessed by clicking or selecting “Margin Analysis” from the Tools menu.

1) Operating Margin Results. After all input data are entered (all parameters in white boxes), click [Calculate] to begin the animation sequence. After the animation is concluded, the first point of contact with the limit curve is described (string element, depth, and load) in the text box at the top of the window. Corresponding conditions at the surface and at the bit are summarized in the output table above the [Calculate] button.

The graph displays the limits defined for the drill string and the current loading condition of the string. As calculations are performed, the drill-string curve (blue) will gradually move toward the right (for tension and torsion) or toward the left (for buckling) until it contacts the limit curve.

2) Margin Checking Option. Four different quantities may be considered, with from one to three options available for any individual operating mode. Select one of the available parameters and click [Calculate] to perform the analysis.

3) Operating Margin Boundary Conditions. Starting boundary conditions of torque or drag, or torque and drag should be specified. The data can be started at zero if you don’t know the proper value.

Torque increment or axial load increment is the value by which the torque or weight is increased for each calculation during the calculation series. A low increment will result in a longer animation sequence.




14.2.4 Buckling Analysis Window The Operation Animation window is used to visualize and evaluate the development of buckling modes throughout the coiled-tubing operation. A second function in this window can be used to gauge the impact of increasing/decreasing weight on bottom. This window is opened by clicking or selecting “Buckling Analysis” from the Tools menu.

Operation Animation

Operation Animation presents a dynamic simulation of buckling and surface load conditions along the string as the drill string is tripped into the wellbore. A 2D view of the survey on the right shows the location of the BHA and the current buckling condition of the string.

[Begin] clears the data from the graphs and begins the run with the drill string at the surface. [Pause] halts the simulation at the current depth. [Continue] is used after a pause to restart the simulation at the same depth. [Stop] is used to end the simulation at any point.

You can change the load on the BHA (i.e., bit weight) between runs by entering a new value in the “Bottom load” box.

Bottom Load Variation

The Bottom Load Variation analysis is used to evaluate the impact of changes in WOB on the buckling condition of the drill string. This function can be used to determine how much reserve capacity for WOB is available before the string begins to yield (or equipment capacity is exceeded).

Surface load, bottom load (WOB), and weight increment are displayed. Bottom load will increase (or decrease) one increment every time you click . Bottom load and weight increment can also be edited directly (as indicated by white background). The graphs are automatically updated each time the parameters are changed.



14.2.5 Sheave Analysis Window A special utility is provided for calculating sheave efficiency based on weight-indicator readings and actual loads, or calculating actual pick-up and slack-off loads based on weight-indicator readings and sheave efficiency. This window is opened by clicking or by selecting “Sheave Analysis…” from the Tools menu.

Sheave Efficiency Calculator

If weight indicator readings are known along with actual pick-up or slack-off loads, the Sheave Efficiency Calculator can be used to estimate sheave efficiency. This parameter ranges from 0 to 1, and is the ratio of weight being lifted by a single sheave divided by the total force (including friction) to raise it. For a frictionless sheave, e = 1. API based its calculation on e = 0.96. Another researcher, Crake (19826), used e = 0.97.

Select the number of lines in the block from the drop-down box. Select “Friction” or “Frictionless” depending on your preference. For the frictionless case, the deadline is stationary, and vibration on the rig is assumed to eliminate any residual friction on the deadline sheave. The deadline sheave does typically move slightly due to vibration, deadline stretch, and deadline sag. This movement causes some rotation of the deadline sheave and results in some friction (this is the “friction” case).

After all parameters are entered, press [Calculate].




Weight Indicator Reading

If weight indicator readings are known along with sheave efficiency, the Weight Indicator Reading Calculator can be used to estimate actual pick-up and slack-off loads. Select the number of lines in the block from the drop-down box. Select “Friction” or “Frictionless” depending on your preference. For the frictionless case, the deadline is stationary, and vibration on the rig is assumed to eliminate any residual friction on the deadline sheave. The deadline sheave does typically move slightly due to vibration, deadline stretch, and deadline sag. This movement causes some rotation of the deadline sheave and results in some friction (this is the “friction” case).

After all parameters are entered, press [Calculate]. Click [Sensitivity Graph] to view the relationship between sheave efficiency and actual loads.

Illustration

A schematic is shown that summarizes the definitions of parameters used in sheave calculations.

6 Crake, W.S., 1982: “Fitting Drilling Rigs to Their Job… Whether the Rig is Old or New,” Oil & Gas Journal, October 15.


115515. DRILL-STRING LIFE MODEL

The Drill-String Life model predicts drill-string fatigue damage. Two mechanical models are provided: fatigue and crack-growth models. The fatigue model calculates drill-pipe bending stress and predicts build-rate/dogleg limits, fatigue damage and rotation limits of drill-string tubulars. Fatigue failure is considered to occur when cumulative fatigue damage exceeds 100%. The crack-growth model is based on correlations of drill-string tubulars by Exxon, and predicts the inspection intervals to prevent fatigue failure.

15.1 Input

15.1.1 Project Page The Project input page for the Drill-String Life model is very similar to the typical DrillNET Project page. See Section 3.2.1.

15.1.2 Survey Page The Survey input page for the Drill-String Life model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

15.1.3 Tubulars Page The Tubulars input page for the Drill-String Life model is very similar to the typical DrillNET Tubulars page. See Section 3.2.3. The primary difference is that the tubular data table is changed for entering fatigue data. Column 9 becomes a drop-down list for selecting materials from the S-N curve database (see Section 25.5).

15.1.4 Wellbore Page The Wellbore input page for the Drill-String Life model is very similar to the typical DrillNET Wellbore page. See Section 3.2.4.

CHAPTER 15: DRILL-STRING LIFE MODEL



1) Drill String Life Operation Table. Enter data describing the operational procedures that place cyclical and bending stresses on the string as it is run into the hole. Each row of the table defines operations for a range of depths, with the lowest depth for that section listed in the “Bottom MD” column.

In the example shown above, the drill pipe is run (tripped) from surface to 3,500 ft MD with no rotation (row 1); then run from 3,500 to 4,000 at 40 ft/hr, 100 rpm, and a WOB of 20,000 lb (row 2).

Fluid corrosivity is a critical element for fatigue. Enter a Corrosion Factor for each section. Values range from 0 to 1, with 1 indicating no effects of corrosion on fatigue life. Suggested values are shown by clicking [Corrosion Factor] below the table.

2) Drill-String Life History Data Table. Drill-string joints are listed in the table as you specify. For each joint, enter the fatigue life previously consumed by field operations.

Apply Joint Span

To initialize the table, click [Apply Joint Span] to fill in a row for every pipe joint based on the joint span length and cumulative length you specified on the Tubulars page. After the data are entered in the table, you can edit the joint length entries if necessary. After any modifications are made, click [Refresh] to update the table.




Initialize Life

To enter initial values for “Previous Used Life,” you can manually enter data row by row. If the same value applies to a range of joints, click [Initialize Life]. This opens a window to specify which range of joints and the initial value of consumed fatigue life.

Update Used Life

[Update Used Life] is used to permanently add the fatigue life consumed by the current operation to the life history for each joint. Values displayed in the “Current Used Life” column, which include previous history and new fatigue, are moved over into the “Previous Used Life” column. Save the project file to have the new total fatigue life be recalled as the previous life for the next run.

Editing the Table

Right-click over the table to open the Edit menu. This provides options for copying entries, printing, and adding/deleting rows. Select “Display in Separate Window” to open the table in a new large window, making review and editing easier.


1) Buckling Model Options. Three buckling models are provided. See Section 28.9.4 for a description. When the string is subjected to helical buckling, axial forces will be affected, along with stress along the string. This in turn impacts fatigue life.



2) Helical Buckling and Bending Stiffness. Select “Consider helical buckling friction force” to account for compressional forces due to helical buckling. The radial component of these forces pushes the string against the borehole wall. This extra side force causes added friction and stress.

Select “Consider bending stiffness” to account for the impact of drill-pipe stiffness on the onset of buckling in curved sections of the wellbore. The conventional soft-string torque and drag model (Johancsik et al., 1983) assumes that loads on the drill string result solely from effects of gravity and drill-string frictional drag resulting from the contact of the drill string with the wall of the hole in a directional wellbore. If you uncheck this option, the program uses the soft-string model (i.e., pipe stiffness will not affect the calculation). For directional wellbores with a short radius and a drill string with high bending stiffness, additional normal force between the wellbore and the drill string could be significant, and this bending stiffness effect should not be neglected. To account for drill-string stiffness, check this option to include the impact of bending stiffness on stress.

15.2 Output Output for the Drill String Life Model includes results under two tabs:


2. Graphs/Tables – A typical DrillNET multi-featured output display allowing selection of individual or multiple graphs (see below). See Section 3.3 for a description of options for displaying and editing this window.





15.3.1 Tool-Bar Icons Special tool-bar icons are provided when the Drill String Life Model is selected. The special icons include:

Single-Span Analysis. Opens the Single-Span Drill String Fatigue Analysis window (see Section 15.3.2) for analyzing dogleg and rotation limits for a single joint of pipe.

Crack-Growth Analysis. Opens the Crack-Growth Analysis window (see Section 15.3.3) for predicting crack-inspection intervals for a single joint of pipe.

15.3.2 Single-Span Drill String Fatigue Analysis The main input/output window in the Drill String Life Model tracks and predicts fatigue-life damage for an entire drill string based on a specific well and operational procedure. Other more basic engineering analyses can also be performed. The single-span analysis considers the dogleg and rotation limits for a single joint of drill pipe. A wellbore survey is not required. This feature is performed by clicking or by selecting “Single-Span Fatigue Analysis…” from the Tools menu.

1) Single-Span Fatigue Model Selection. Select Dogleg limit (no fatigue) to calculate critical doglegs (when the pipe can be rotated an infinite number of cycles without fatigue failure) and contact doglegs (when the pipe body contacts the wall of the wellbore for inputting maximum axial load).

Rotation limit (total failure) is used to determine the number of pipe rotations in a wellbore with a specified build rate (i.e., dogleg) that will bring the pipe to fatigue failure. If infinite life is predicted for a specific loading condition, a value of 108 rotations is assigned for the table and graph displays.



2) Single-Span Output Table and Graph. After you enter all input data, click [Calculate] to update the table and graph. The maximum axial load you specified (right-most column in the Wellbore/Operation Data table) is the upper limit; rows represent 10% increments across the range.

You can select compression or tension as the X axis by clicking your preference below the graph.

Editing the Graph

The Single-Span Fatigue graph can be opened as a separate window for easier viewing, as well as copied and printed. Right-click your mouse over the graph to open the Edit menu. Select “Display in Separate Window” to open a new window that is easy to review. Click “Export to Excel” if you want to further analyze the data. Options on this pop-up menu are described in Section 3.4.

3) Single-Span Drill Pipe Data Table. Enter data for the single pipe joint being analyzed. Select a pipe grade from the pull-down list. The options shown in the list are taken from the My S-N Curves database. The mechanical parameters for that pipe are shown in the Pipe Material table in the lower right corner of the window.

Click [S-N Curves] to open the My S-N Curves database (see Section 25.5) for reviewing and defining mechanical and fatigue behavior of pipe materials.

4) Single-Span Wellbore/Operation Data Table. Enter wellbore and operational data for the single-joint analysis.

15.3.3 Crack-Growth Analysis The Crack-Growth model can also be used to predict crack-inspection intervals for a single joint of pipe. A wellbore survey is not required. This feature is performed by clicking or by selecting “Crack-Growth Analysis” from the Tools menu.




1) Crack-Growth Model Selection. You can select compression or tension as the X axis for the crack-growth analysis by clicking your preference.

When magnetic particle inspection (MPI) is used to inspect drill-string connections, the probability of detecting cracks is low (see figure). Consequently, the calculated inspection interval for drill-string connections is usually reduced by a factor of 6 to achieve about a 99% probability of detecting existing cracks.

Note that all tooljoint inspection results are based on an inspection factor of 6. (This cannot be changed by the user.)

Additional discussion is presented in Section 28.10.6.

2) Crack-Growth Output Table and Graph. After you enter all input data, click [Calculate] to update the table and graph. The maximum axial load you specified (first column in the Wellbore/Operation Data table) is the upper limit; rows represent 10% increments across the range.

Editing the Graph

The Crack-Growth Analysis graph can be opened as a separate window for easier viewing, as well as copied and printed. Right-click your mouse over the graph to open the Edit menu. Select “Display in Separate Window” to open a new window that is easy to review. Click “Export to Excel” if you want to further analyze the data. Options on this pop-up menu are described in Section 3.4.

3) Crack-Growth Drill Pipe Data Table. Enter data for the single pipe joint being analyzed. Select a pipe grade from the pull-down list. The mechanical parameters for that pipe are shown in the Pipe Material table in the lower right corner of the window.

4) Crack-Growth Wellbore/Operation Data Table. Enter wellbore and operational data for the single-joint analysis.

Accuracy of Flaw Detection (Dale, 1989)

0.040

Flaw Depth (in.)

Pro

bab

ility

of

Det

ect

ion

(%

)

0

20

40

60

80

100

0.080.02 0.100.06

MPI(Connections)

EMI(OD Surface)

EMI(ID Surface)


0.040

Flaw Depth (in.)

Pro

bab

ility

of

Det

ect

ion

(%

)

0

20

40

60

80

100

0.080.02 0.100.06

MPI(Connections)

EMI(OD Surface)

EMI(ID Surface)


116616. TRIAXIAL STRESSES MODEL

The Triaxial Stresses model calculates limits for burst and collapse pressures and equivalent stresses for a pipe body. Three pressure limit models are evaluated by the program: (1) triaxial, (2) biaxial, and (3) API. The program also performs triaxial stress sensitivity analysis for the factors of internal and external pressure, doglegs, and D/t (diameter/wall thickness) ratios.

16.1 Input

16.1.1 Project Page The Project input page for the Triaxial Stresses model is very similar to the typical DrillNET Project page. See Section 3.2.1.

16.1.2 Survey Page The Survey input page for the Triaxial Stresses model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

16.1.3 Tubulars Page The Tubulars input page for the Triaxial Stresses model is very similar to the typical DrillNET Tubulars page. See Section 3.2.3.

16.1.4 Loads Page

CHAPTER 16: TRIAXIAL STRESSES MODEL


The Loads page in the Triaxial Stresses Model displays loading conditions (pressures and axial forces) for every depth. These data are then used to construct an equivalent stress chart for the entire string. Data in the Loads table may be input manually. Another option is to have the program input the data automatically (see below).

Automatically Populating the Load Table

To have the program automatically populate the table with pressure and axial load data, complete the following steps:

1. Open the Drill String Torque/Drag Model, and open or create a wellbore survey. Fill in all required parameters, and calculate torque/drag results by clicking . Axial loading at each survey point is now available in DrillNET.

2. Open the Hydraulics for Normal Circulation Model and fill in all parameters that are not already displayed. Calculate hydraulics results by clicking . Pressure data are now available.

3. Return to the Triaxial Stresses Model. All required data will now be shown in the Load table. Any of these values may be edited or deleted, as desired.

16.2 Output Output for the Triaxial Stresses Model includes results under two tabs:

1. Summary – Displays values for key stresses

2. Graphs/Tables – A typical DrillNET multi-featured output display allowing selection of individual or multiple graphs (see below). See Section 3.3 for a description of options for displaying and working with this window.





16.3.1 Tool-Bar Icons Special tool-bar icons are provided when the Triaxial Stresses Model is selected. The special icons include:

Single Point Stress Analysis. Opens the Single Point Stress Analysis window (see Section 16.3.2) for analyzing equivalent stresses for a single set of pressure and load conditions.

Drill String Stress Analysis. Opens the Drill String Stress Analysis window (see Section 16.3.3) for analyzing the complete drill string as specified.

16.3.2 Single Point Stress Analysis Window The Single Point Stress Analysis window is a powerful utility for comprehensively analyzing stress states at a single set of conditions. No survey is required. Data are entered that define the tubular to be analyzed, and basic results are displayed on the lower half of the window after the calculation is performed. This window is accessed by clicking

or by selecting “Single Point Stress Analysis…” from the Tools menu.

Tubulars Tab

1) Single-Point Tube Data. Tubing properties (material and geometry) are specified here. The Tubular Database is available to quickly import data on common pipes. The first step is to click on the drop-down box next to Pipe Class and select from the options. After you select a class, the drop-down list of ODs is then automatically opened for you to select. After you click on the desired OD, the on-line tubular database will be opened showing common pipes for easy selection (see figure below). Select a row in the database table by clicking on it. Next, click [OK] above the table to import that row (ID, pipe strength and Young’s modulus). Otherwise, click [Cancel] and enter these values manually.



Data boxes on the right side (“Calculation Parameters”) describe the stress environment in the well. Enter internal and external pressures, axial loads on the string, bending stresses (i.e., doglegs), and an appropriate safety factor for loading. The default safety factor is 1.0.

2) Single-Point General Triaxial Output. Resultant stresses in the tubular are shown here. If the tubing is under bending stress, minimum, average, and maximum stresses can be compared. (If there is no bending, then minimum = average = maximum stress.) Allowable axial stress and load are based on cross-sectional area, material yield strength, and safety factor.

3) Single-Point Burst and Collapse Operational Pressures. Burst and collapse limits are compared for the three calculation approaches (triaxial, biaxial and API). More information is presented in Section 28.11.




Biaxial, Triaxial and API Graph Tab

1) Biaxial, Triaxial and API Stress Graph. Biaxial and API limit curves are displayed. Move the pointer within the graph area to explore the effects of changing stresses and pressures. While moving the cursor within the graph, the data in the cursor coordinate boxes under “Operational Pressure” are updated. Burst pressure limits and collapse pressure limits are only affected by the axial stress. The pressure text box reflects only the cursor’s Y-coordinate. If there is a solution, the value will be displayed on the screen; otherwise, “NA” is displayed in the output box.

When the tension or compression force is too large, there is no solution. If solutions exist, the red circles (for biaxial) and/or black circles (for triaxial) are displayed on the graph to indicate the minimum yield pressure at current axial stress (i.e., cursor’s X-coordinate). If both biaxial and triaxial models have the same solution, the circle will be cyan.

Double-click on the graph area to colorize the stress limits. Click again to return to the default display.

Tubing Status at the current position of the cursor is summarized in the lower right section of the window. These safety conditions are constantly updated with respect to the cursor location. If the stress environment is within the limits (with safety factor applied) for the models, the condition is labeled “Safe.”

2) Biaxial Input Data. The top boxes, “External Pressure” (for burst) and “Internal Pressure” (for collapse) apply to triaxial stress calculations only. The input box “Axial Force” relates to the cursor location. If you enter a number directly, the cursor is moved to that position.

These input data can be modified independently within this Stress window. Other input data (tube OD, material, etc.) can only be modified within the Tubulars window.

3) Cursor Coordinates. The mouse pointer becomes a cross-hair pointer within the graph area. The coordinates of the current location (X = axial stress; Y = pressure) are displayed numerically here. These coordinates are updated whenever the cursor remains stationary for a few moments.



4) Operational Pressures. Burst and collapse pressure limits with the biaxial, API and triaxial models are displayed here numerically when the cross-hair pointer is moved within the graph area.

Sensitivity Analysis Tab

1) Sensitivity Table. Sensitivity data are displayed numerically after calculation. The range of variation defined in the Sensitivity Parameters table () is divided into 20 equal increments. Review the entire table (21 rows) by clicking on the table scroll bar.

2) Sensitivity Parameters. Select one parameter to be varied (while others are held constant). The range columns will become active for the selected parameter. Enter the range of variation in the white cells (or accept the default values). Note that yellow cells may not be edited within this window. To change baseline data, you need to close this window and return to the Tubulars page.

After you modify any range of variation, click [Calculate] to update the table and graph.

3) Sensitivity Graph. A graph of the parametric trends is presented based on the current calculation. The graph is automatically updated after [Calculate] is clicked.

Editing the Sensitivity Graph

The Edit menu can be accessed easily by right-clicking over the graph. Options on this pop-up menu are described in Section 3.4. In addition to opening a separate window containing only the graph, you can export a graph to Excel along with its data for further analysis.

16.3.3 Drill String Stress Analysis Window The Drill String Stress Analysis window is another utility provided for analyzing stress states. This feature shows stresses along the entire string. This window is accessed by clicking or by selecting “Drill String Stress Analysis…” from the Tools menu.

1 2 3




The stress state for the complete drill string is shown as a connected series of points. No input data are required within this window. All parameters are taken from the Tubulars and Loads input pages.

You can review the variation in stress loading for every section of the drill string by selecting each range in turn from the drop-down list in the upper right corner. The entire string is always displayed; the MD range currently selected is shown as a thicker section of the curve.

Editing the Graph

The stress graph can be copied and printed, as well as opened as a separate window for easier viewing. Right-click the mouse over the graph to open the Edit menu. Select “Display in Separate Window” to open a new window that is easy to review. Options on this pop-up menu are described in Section 3.4.


117717. HYDRAULICS FOR NORMAL CIRCULATION MODEL

The Hydraulics for Normal Circulation model comprehensively evaluates fluid hydraulics for drilling, completion, and workover operations. The model covers almost all aspects of hydraulics, including pressure drop and flow regime, equivalent circulating density (ECD), nozzle selection, hole-cleaning efficiency, and volumetric displacement. A variety of potential problems and sources of confusion (whether the formation will break down, whether a kick will occur, what the optimum nozzle area is, etc.) can be easily analyzed and defined.

17.1 Input

17.1.1 Project Page The Project input page for the Hydraulics for Normal Circulation model is very similar to the typical DrillNET Project page. See Section 3.2.1.

17.1.2 Survey Page The Survey input page for the Hydraulics for Normal Circulation model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

17.1.3 Tubulars Page The Tubulars input page for the Hydraulics for Normal Circulation model is very similar to the typical DrillNET Tubulars page. See Section 3.2.3.

17.1.4 Wellbore Page The Wellbore input page for the Hydraulics for Normal Circulation model is very similar to the typical DrillNET Wellbore page. See Section 3.2.4.

17.1.5 Formation Page The Formation input page for the Hydraulics for Normal Circulation model is very similar to the typical DrillNET Formation page. See Section 3.2.5.

CHAPTER 17: HYDRAULICS FOR NORMAL CIRCULATION MODEL


17.1.6 Fluid Page

1) Fluid Parameters. Enter flow rate and mud weight to be used in the hydraulics analysis.

Estimate Flow Rate

A utility is provided to help with rheology consisting of a flow rate estimation based on pump rate. If the volumetric flow rate is not known, click [Estimate Flow Rate…] to calculate flow rate based on pump geometry and stroke rate. In the utility, fill data into the white cells. Results will be calculated automatically and displayed in the yellow cells. Click [Apply] to export the results back to the Fluid page.

2) My Fluids. A database of fluid properties is provided. My Fluids can be customized to provide easy access to your company’s or your customer’s common drilling fluids. See Section 25.3.

3) Fluid Rheology. Select the mud rheology model that best describes the fluid to be used. Four fluid models are provided. Additional theoretical discussion is presented in Section 28.12.1. Rheology models include:





Most drilling fluids are non-Newtonian, with shear stress not directly proportional to shear rate. Fluids are shear thinning when they have less viscosity at higher shear rates than at lower shear rates.

2. Bingham Plastic. This is the most common rheological model for drilling muds. These fluids exhibit a linear shear-stress/shear-rate ratio once a threshold shear stress is exceeded. Two parameters, plastic viscosity and yield point, are used to characterize these fluids. Because these constants are determined between the specified shear rates of 500 to 1000 sec-1, this model characterizes fluids in the higher shear-rate range.

3. Power Law. This model applies to shear-thinning or pseudo plastic drilling fluids. Shear stress versus shear rate is a straight line when plotted on a log/log scale. Two constants, n and K, are determined from data at any two speeds. (See Section 28.12.1 for a definition of these constants.)

4. Herschel Bulkley. This model, similar to the power-law model, applies to shear-thinning or pseudo plastic drilling fluids. It also incorporates a threshold shear stress (yield point). Consequently, the Herschel-Bulkley model can be considered a hybrid combination of the Bingham-plastic and power-law models. Herschel-Bulkley was developed based on the observation that many typical drilling fluids exhibit both a yield stress and shear thinning.

At high shear rates, all three of these fluid models represent a typical drilling fluid reasonably well. Differences between models are most pronounced at low rates of shear.

The exact rheological parameters that are required vary depending on the rheology model selected. Text labels automatically change to reflect the current model.

Viscometer Readings

If Fann Viscometer readings are available, these can be quickly converted to rheological constants. Click “Viscometer readings” and select the number of rotation speeds from the list in the drop-down box. From these you can calculate parameters required for Newtonian, Bingham plastic, Power law or Herschel-Bulkley models.



17.1.7 Drilling Page

1) Cuttings Analysis. Hole cleaning is strongly impacted by the size of the cuttings and the rate of cuttings production. Several investigators have proposed empirical correlations for estimating cuttings slip velocity. Two widely accepted correlations (the Moore and the Chien) are included for modeling cuttings slip velocity. For a discussion on the derivation of these correlations, see Section 28.12.3.

2) Surface Equipment Type. A basic description of typical surface equipment is used to estimate the pressure drop in the flow path prior to the fluid entering the well. Select one of the four conventional cases for standard rig operations. Click [Equipment Specifications] or the icon for a description of the four conventional cases.

3) Jet Bit Nozzle Size Selection. Minimum pump rate is used to set the lower limit for the range of flow rates within which the optimized flow rate will be determined. Select a minimum flow rate based on practical considerations (and rules of thumb). Maximum pump pressure sets the upper limit for flow rates that may be considered in the analysis. Maximum pump HP, Pump efficiency and Flow exponent define pump capacity. These are used to calculate the maximum flow rate available for this pump equipment.




Click [Estimate Flow Exponent…] or the icon for help with assigning a value to flow exponent. See Section 17.3.1.

Select which hydraulics parameter is to be optimized – maximum jet impact force or maximum hydraulic power.

There are two common design parameters in optimizing jet bit hydraulics: (1) bit hydraulic horsepower, and (2) jet impact force. Some operators prefer to select bit nozzle sizes so that jet impact force is maximized rather than bit hydraulic horsepower. However, neither of these criteria has been proven superior in all cases because there is relatively little difference between them. If hydraulic horsepower is maximized, jet impact force will be within 90% of its maximum (and vice versa).

More discussion is presented in Bourgoyne et al. (1986).

4) Drill String Movement. Rotation speed can have a large influence on pressure loss. The hydraulics correlations are different for an eccentric annulus (versus a centered drill string) by selecting “Eccentric pipe”. Select “Tooljoint effects” if you want to account for the influence of tool joints on pressure drop in the annulus. This option opens columns for Tool-Joint OD/ID and Contact % for each section of the drill string. TJ contact % is defined as shown below.

17.2 Output Output for the Hydraulics for Normal Circulation Model includes results under four tabs:

Summary – Displays values for key hydraulics parameters

Graphs/Tables – A typical DrillNET multi-featured output display allowing selection of individual or multiple graphs (see Section 3.3)

Flow Details – Each row in this table represents a section of uniform geometry (constant ID for pipe or constant OD/ID for annulus). Flow velocity, pressure loss, and flow pattern are all constants for each section shown in the table.

Hydraulics Chart – A multiparameter comparison of hydraulics results with depth (see below)

A BL

Tooljoint Contact % = * 100(A+B)

L

Tooljoint Contact %



17.2.1 Hydraulics Graphs Graphs/Tables tab – allows users to select one or multiple hydraulics-related graphs for viewing. A hydraulics details table is also provided.

A user may select a single graph (the default) for display. For example, in the image below, the Cuttings Concentration in Suspension is displayed.

Optionally, a user may select multiple graphs, using the standard Windows CTRL+click function. A sample is shown below.




Hydraulics Chart tab. This provides a side-by-side comparison of multiple parameters over a common depth range.

Hydraulics Chart Pressure data displayed as either Pressures or Gradients

A new option has been included beneath the Options Model Options… which allows Pressure data on the Hydraulics Chart output to be displayed either as a pressure or gradient.

The parameter “Show Pressure Gradient in Flow Chart” is not checked by default as shown below:



The resultant output on the Hydraulics Chart output displays Pressure data as shown:

When the “Show Pressure Gradient in Flow Chart” is checked as shown here:




the resultant output on the Hydraulics Chart output displays Pressure data as shown below:

As with all input and output, the units of measure displayed and used can be customized by the user using the Options Units option.


17.3.1 Tool-Bar Icons Special tool-bar icons are provided when the Hydraulics for Normal Circulation Model is selected. The special icons include:

My Fluids. Opens the My Fluids database (see Section 25.3) for reviewing and importing fluid data into the data tables.



Equipment Specifications. Opens a window with summaries of generic surface equipment types as required on the Drilling page.

Estimate Flow Rate. Opens the Estimate Flow Rate window (see Section 17.1.6) which provides help with determining a value for flow rate based on pump rate.

Estimate Flow Exponent. Opens the Estimate Flow Exponent Utility (see Section 17.3.2) for help with calculating a flow exponent for use in nozzle design.

Sensitivity Analysis. Opens the Sensitivity Analysis window (see Section 17.3.3) for analyzing the relative impact of changes in individual hydraulics parameters while other parameters remain constant.

17.3.2 Estimate Flow Exponent Utility A utility is provided on the Drilling input page to help calculate a flow exponent for use in bit nozzle design. The flow exponent is used to construct a power-law type curve to approximate the data for parasitic pressure losses (i.e., system pressure loss not including that across the bit) and flow rates. This flow exponent is used in bit nozzle selection calculations.

Use Pump Pressure Data

Click the button “Estimate Flow Exponent…” to open the utility. Two methods are provided to estimate the flow exponent. If pump pressure data recorded at high pump rate and low pump rate are available, then the method “Use Pump Pressure Data” should be used. This page is shown below. Enter measured pump and pressure data as indicated. Then enter bit nozzle sizes into the table on the right. Press [Calculate] to calculate a flow exponent. To export the result to the Drilling page, click [Apply].

Use Current Project Data

When pump pressure data recorded at high and low pump rates are not available, the second method (“Use Current Project Data”) can be used. This uses current input data to calculate parasitic pressure losses over a range of flow rate values. (Consequently, this method is available only when the input data are ready to run.) It then performs a power-law regression analysis to find the flow exponent value that best fits the data pairs. The range of flow rate you select may have a significant effect on the estimated flow exponent value. There is no general rule for defining this flow rate range; the user should always specify the range that is appropriate for the rheology model you selected (or will select) in the input window.

Press [Calculate] to calculate a flow exponent. To export the result to the Drilling page, click [Apply].




17.3.3 Sensitivity Window The Sensitivity Analysis window is a secondary output window used to analyze the relative impact of changes in individual parameters while other parameters remain constant. This type of analysis can be very useful for determining which parameter(s) are of critical importance for a specific operation, so that careful monitoring might be required, more precise measurements will need to be obtained, etc., to ensure the success of the planned field operation. Conversely, other parameters may be found to have little impact and not require rigorous optimization. This window is accessed by clicking or selecting “Sensitivity Analysis…” from the Tools menu.

Select one parameter under “Calculation Settings” to be varied while others are held constant. Enter the minimum and maximum values for the range of variation for the selected parameter. Base-case constants will be used for the other parameters, which are assigned default values corresponding to those assigned on the current main input pages.



To analyze sensitivity, the parameter under consideration is varied across the defined range in small increments and a calculation performed at each step.

To reduce the number of graphs displayed together, unselect options under “Display Graph(s)”. After you make any changes to the options, click [Calculate] to update the display.

Click [Print] to select a printer for printing a summary including all graphs displayed.




118818. HYDRAULICS FOR SURGE/SWAB MODEL

The Hydraulics for Surge/Swab model evaluates conventional fluid hydraulics for pipe tripping operations. During tripping, pipe run into the wellbore may generate large surge pressures inside the hole which can lead to lost circulation and formation fracture. On the other hand, when pipe is pulled out rapidly, it may generate swab pressures that can lead to kicks and blowouts. This model calculates the effects of pipe design and tripping speed on surge and swab pressures to avoid problems when RIH and POOH.

18.1 Input

18.1.1 Project Page The Project input page for the Hydraulics for Surge/Swab model is very similar to the typical DrillNET Project page. See Section 3.2.1.

18.1.2 Survey Page The Survey input page for the Hydraulics for Surge/Swab model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

18.1.3 Tubulars Page The Tubulars input page for the Hydraulics for Surge/Swab model is very similar to the typical DrillNET Tubulars page. See Section 3.2.3.

18.1.4 Wellbore Page The Wellbore input page for the Hydraulics for Surge/Swab model is very similar to the typical DrillNET Wellbore page. See Section 3.2.4.

18.1.5 Formation Page The Formation input page for the Hydraulics for Surge/Swab model is very similar to the typical DrillNET Formation page. See Section 3.2.5.

CHAPTER 18: HYDRAULICS FOR SURGE/SWAB MODEL



1) Surge/Swab Fluid Parameters. Enter mud weight to be used in the hydraulics analysis.

Select the mud rheology model that best describes the fluid to be used. Four fluid models are provided. Additional theoretical discussion is presented in Section 28.12.1. Rheology models include:




3. Power Law. This model applies to shear-thinning or pseudoplastic drilling fluids. Shear stress versus shear rate is a straight line when plotted on a log/log scale. Two constants, n and K, are determined from data at any two speeds. (See Section 28.12.1 for a definition of these constants.)

4. Herschel Bulkley. This model, similar to the power-law model, applies to shear-thinning or pseudoplastic drilling fluids. It also incorporates a threshold shear stress (yield point). Consequently, the Herschel-Bulkley model can be considered a hybrid combination of the Bingham-plastic and power-law models.




Herschel-Bulkley was developed based on the observation that many typical drilling fluids exhibit both a yield stress and shear thinning.

At high shear rates, all three of these fluid models represent a typical drilling fluid reasonably well. Differences between models are most pronounced at low rates of shear.


Viscosity Data

If values are not known for the required rheological constants, Fann viscometer readings can be entered to characterize the rheology of the wellbore fluid. Select “Viscometer readings” and select the number of rotation speeds from the list in the drop-down box. The Fann data you enter will be used to calculate parameters required for Newtonian, Bingham plastic, power law or Herschel-Bulkley fluid models.


3) Surge/Swab Drill String Movement. Tripping speed can have a large influence on pressure losses during RIH and POOH. Select whether the pipe is tripped open or closed.

Note that the influence of changes in pipe end conditions and tripping speed can be compared easily on the

Surge/Swab Sensitivity window by clicking (see Section 18.3.2).

18.2 Output Output for the Hydraulics for Surge/Swab Model includes results under two tabs:

1. Summary – Displays surge and swab pressures for key positions

2. Graphs/Tables – A typical DrillNET multi-featured output display allowing selection of individual or multiple graphs (see below). See Section 3.3 for a description of options for displaying and working with this window.

Note – Maximum Allowable Tripping Speed is the maximum run in/out speed to avoid problems with fracture and pore pressure. Above this limit, pressure at the casing shoe or bottom of the hole would exceed fracture pressure while running in hole, or be less than pore pressure while pulling out of hole. If the maximum allowable tripping speed is reported as 0 ft/min, then wellbore pressures are already outside the pore/frac pressure limits before the influence of pipe movement is accounted for.




18.3.1 Tool-Bar Icons Special tool-bar icons are provided when the Hydraulics for Surge/Swab Model is selected. The special icons include:


Sensitivity Analysis. Opens the Sensitivity Analysis window (see Section 18.3.2) for analyzing the relative impact of changes in individual hydraulics parameters while other parameters remain constant.

18.3.2 Sensitivity Window The Sensitivity Analysis window in the Hydraulics for Surge/Swab model is a special output window used to quickly analyze and compare the relative impact of tripping speed and pipe end condition while other parameters remain constant. This window is accessed by clicking or by selecting “Sensitivity Analysis…” from the Tools menu.




Enter the minimum and maximum values for the tripping speed. Other wellbore and hydraulics parameters are held constant at the values you entered on the current main input pages.

After you make any changes to the input options, click [Calculate] to update the graph and table.

Editing the Sensitivity Graph

The Edit menu can be accessed easily by right-clicking over the graph. Options on this pop-up menu are described in Section 3.4. In addition to printing the current graph, you can export the graph to Excel along with its data for further analysis.


119919. HYDRAULICS FOR UNDERBALANCED DRILLING

19.1 Background Hydraulics for Underbalanced Drilling (UBD), the Air/Mist/Foam Hydraulics Model, was originally developed by Maurer Technology Inc. as part of the DEA-101 joint-industry project on Air/Mist/Foam and Underbalanced Drilling Technology. UBD is the industry’s most comprehensive and easiest to use engineering program for calculating hydraulics for underbalanced fluids. The program is used worldwide for designing and monitoring underbalanced drilling and completion operations.

Foam has been used in the petroleum industry for decades. It has proven to be effective and economic as a circulating fluid for hole cleaning and drilling operations. It is also used in hydraulic fracturing because of its favorable viscosity. Important advantages of foam drilling over conventional mud drilling include higher penetration rates, higher cuttings transport ratios, and decreased formation damage. In areas with low bottom-hole pressure or where water for drilling fluid is scarce, the use of a lighter fluid, such as foam, is required.

Despite the advantages, the complex and unique flow mechanisms active in foam operations are often confusing to drilling operators with regard to the optimum combination of liquid and gas injection rates. Solutions to other questions also remain unclear, such as how to predict bottom-hole pressure and how to monitor and modify controllable parameters to obtain optimized results. Foam drilling design methods have largely depended on field operational charts or on calculations using a mainframe computer. Over the last 20 years, extensive research on foam rheological behavior and factors affecting foam circulation in oil wells has made it possible to create a comprehensive computer application to meet the demands of foam drilling design.

MTI/Petris developed UBD based on existing foam rheology models and steady-state mechanical energy balance equations. The object of this effort is to formulate the foam-flow problem and utilize numerical techniques to solve compressible non-Newtonian flow in a three-dimensional wellbore. Equations of state describing pressure, volume, and temperature interactions of compressible foam are included. Flow regimes ranging from laminar to turbulent are considered. Analytical approaches based on input and design methods similar to sensitivity analyses are incorporated into the program.

Air and other gases have also been used to drill oil and gas wells throughout the world. One of the most important factors to consider in designing an air, gas, or aerated-fluid drilling operation is the volume of air necessary to do the work. The program uses the air/mist flow equation and a standard air velocity to ensure hole cleaning of 3000 ft/minute (or a value defined by the user) to calculate volume requirements for air and gas drilling.

UBD can also be used for conventional planning and hydraulics analysis for mud drilling.

19.2 New Features of DrillNET UBD has been completely upgraded and enhanced. The “look and feel” of the program is user-friendly and intuitive. Convenient icons and tabs can be used to quickly navigate through the entire program. File management is simple, and options for customizing graphics and producing professional-style printouts are included.

Several important features have been added to version 3. These include:

A completely updated input/output interface

CHAPTER 19: HYDRAULICS FOR UNDERBALANCED DRILLING


A utility to assist in estimating fluid influx rates from the formation using a PI calculation

An enhanced database of drill pipe, drill collars, and casing (drill pipe data are provided by Grant Prideco and casing data are provided by Lone Star Steel)

A convenient 2D Well Planner utility has been added to quickly create wellpath surveys for simple or complicated wells for use in planning analyses

Output can be exported directly as a Microsoft Word document, Excel workbook, and/or PowerPoint presentation

Two types of help systems are now available. Conventional on-line help explains program operation and structure,

and provides basic theoretical background. Special Engineering Help has also been added. Click next to any parameter where it appears for additional information and descriptions of hydraulics parameters and models. Close the engineering help window by clicking anywhere on the screen.

19.3 General Features UBD is a critical component in the leading-edge underbalanced drilling/completion design software developed by MTI. Important technical features of the model include:

Two-phase flow correlations are provided that give more accurate results for compressible flow

Parasite strings and jet subs may be incorporated

Minimum oxygen requirements for combustion can e calculated for each set of conditions

Calculates a variety of profiles: (1) pressure; (2) foam quality (air/gas volume fraction); (3) mixture density; (4) annular velocities of mixture and cuttings; (5) cuttings transport ratio; (6) friction factor; (7) gas deviation (Z) factor

An Operation Design window allows varying all controllable parameters to see how they affect pressures, annular velocities of foam and cuttings, foam quality and annular density

Provides options for three rheology models to describe foams

Provides 5 models to describe two-phase flows

Provides data describing 64 common gas types and their properties. For multi-component gases, a utility window can be used to select from 64 gas components to form a gas mixture. Molecular weight of the mixture will be automatically calculated according to the percentage of each gas component.

Calculates the proper combination of gas/liquid injection rates to achieve the desired foam quality at the surface.

Drill-string and casing data can be imported directly from the on-line database, which can be modified within UBD or in Microsoft Access.

Results, data, and graphs can be output to screen, printer, and disk file.

Supports English and metric units, as well as custom combinations of units (bit size in inches, depth in meters, etc.).

19.4 Input

19.4.1 Project Page The Project input page for the Hydraulics for Underbalanced Drilling model is very similar to the typical DrillNET Project page. See Section 3.2.1.




19.4.2 Survey Page The Survey input page for the Hydraulics for Underbalanced Drilling model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

19.4.3 Tubulars Page The Tubulars input page for the Hydraulics for Underbalanced Drilling model is very similar to the typical DrillNET Tubulars page. See Section 3.2.3.

19.4.4 Wellbore Page The Wellbore input page for the Hydraulics for Underbalanced Drilling model is very similar to the typical DrillNET Wellbore page. See Section 3.2.4.

19.4.5 Formation Page The Formation input page for the Hydraulics for Underbalanced Drilling model is very similar to the typical DrillNET Formation page. See Section 3.2.5.

19.4.6 Influx/Parasite String Up to 50 sets of Formation Influx or Parasite String data may be input. Enter all required data in the table to describe each influx. If the influx is entirely gas, enter zero as the oil influx rate on that row. Check the available option

if data is to be input or if not required select and the option will greyed out.



19.4.7 Drilling Page The Drilling input page for the Hydraulics for Underbalanced Drilling allows input of Motor/BHA, Cuttings and Surface Equipment data.

1) Motor/BHA Data. Pressure drops across the motor (if included) and the BHA are difficult to calculate and very specific to the equipment selected. For accurate results, it is better to enter a measured value for pressure drop as prescribed by the manufacturer. Enter equipment-specific data in the text boxes.

The default option is “Not available”. If you wish to use the pressure drop data select the Available option.

2) Cuttings Data. Cuttings type is used to analyze cuttings-lifting velocity. Select “No Slip” if you wish to assume that the cuttings are completely lifted by the circulating fluid (no slipping is occurring and cuttings are not falling out of the fluid). The Shale/limestone and Sandstone options allow selection of formations with varying cuttings densities.

Rate of penetration, Cuttings density, and Cuttings size are used to calculate the weight and rate of production of individual rock cuttings that must be lifted to the surface by the circulating fluid. Hole-cleaning efficiency is summarized in the output graphs.

3) Surface Equipments Data. Surface Annular Restriction Data. The final stage of the circulation path is specified here so that pressure drop may be calculated. Click [Surface foam quality] to fill in an estimate of




Surface foam quality based on the choke pressure, fluid/gas injection rates currently entered and the Rig type. There are four rig types that can be selected from the pull down list.

Type 1 40 ft of 3 in. I.D. Standpipe

45 ft of 2 in. I.D. Hose

4 ft of 2 in. I.D. Swivel

40 ft of 2-1/4 in. I.D. Kelly







5 ft of 2-1/2 in. I.D. Swivel





40 ft of 4 in. I.D. Kelly

If you need help calculating foam quality at the surface, click [Analysis…] to open the Annular Foam Quality window (below). Within this window: (1) type in the range of gas injection rates that would be practical to implement; (2) enter the desired foam quality at the top of the annulus; and (3) click [Calculate]. Gas injection rates will be paired with corresponding liquid injection rates that will achieve the foam quality you specified. The output may be viewed as a graph of trends (shown here) or as numerical results directly from the data table.



19.4.8 Fluid Page The Fluid input page for the Hydraulics for Underbalanced Drilling allows input of Injection, Base Liquid, Gas and Flow Model data.

1) Injection Data. Enter the injection rate for liquid and gas. Click [Assistance…] for help with fluid design. This opens the Fluid Velocity Required for Hole Cleaning window (see figure below). This window allows you to quickly estimate gas and/or liquid injection rates that will keep the hole clean. When this window is accessed, data are shown based on what is currently entered on the Fluid page. Click [Calculate] to show an updated estimate of gas and liquid injection rates. Calculation parameters shown with a yellow background cannot be changed here since they impact several aspects. Return to the Fluid page, make changes as desired, and then re-open this Assistance window.

2) Base Liquid Data. Enter properties describing the liquid that is used to form




the aerated fluid, mist, or foam.

3) Gas Data. Properties of several gases commonly used in underbalanced drilling may be selected from the drop-down list. Selecting one of these gases will update the gas properties. If you prefer, you may enter gas properties directly.

Click [Gas Analysis…] to calculate properties for a Multi-component mixture of gases.

1) Gas Component Data Table. Describe the specific combination of gases to be used as circulation fluid. First, click on the list above the table to select the first component, then click on to populate the table with data for that gas. The other parameter you must enter is the volume percentage of this component in the overall mixture (Mole Percent). Enter other gas components until the Cumulative Percent reaches 100%. After all data has been entered, click [Apply] to update the values on the Fluid page. Components can be removed from the table using the option.

2) Gas Mixture Properties. Composite properties for the gases you specify are shown in these boxes. Type in a Gas Mixture Name (optional).

3) Gas Analysis Control Buttons. Click [Example] to see an example gas mixture, [Clear] to clear all data fields, [Apply] to update the data on the Fluids page, or [Cancel] to exit from the Gas Analysis option without exporting results.



4) Jet Sub. Is a drill string device located above the drill bit with a nozzle to allow some drilling fluid to bypass the drill bit directly to the annulus. Click on the check box if a Jet Sub is present, and specify the Jet Sub depth (measured depth) and the ID of the nozzle.

5) Gas Law. Is a mathematical model for gas which takes into account the gas molecular interactions that makes it deviate from the behavior of an ideal gas. Select from either the Engineering model which uses the factor (Z) to describe how a gas deviates from an ideal gas, or the Virial model which uses a Taylor expansion series to describe how a gas deviates from an ideal gas.

6) Flow Model Select Foam flow for foamed fluids or Multi-phase flow for aerated fluids or mists. Model options will be enabled or disabled as appropriate depending on the flow type selected.

For foams, select one model to describe hydraulics (Bingham Plastic, Power Law, or Chevron’s model). Chevron’s model is based on the assumption that the foam behaves as a Bingham plastic fluid with a constant yield point. These models are discussed in the Theoretical Basis section later in this chapter.

For multiphase fluid operations, select one of the models provided. Several multiphase flow correlations are available for predicting tubing/annulus pressure drops. Although each of these gives good results under some conditions (such as for stable flow in oil wells), none of them is accurate across the range of flow rates, GORs and water cuts found in oil and gas wells.

Beggs-Brill7 and Duns-Ros recognize both slippage phenomena and flow regimes. Gray was originally derived from vertical gas condensate wells. Hagedorn-Brown was obtained from field data for pipe sizes ranging from 1–4 inches OD and considers the slippage effect. The most recent correlation is the Hasan-Kabir. Newer methods go further in eliminating empirical relationships. In particular, boundaries of the different flow regimes are defined using mechanistic considerations.

Generally, traditional correlations that give good results in oil wells can give poor results in gas wells. Newer mechanistic correlations give reasonable results in both oil and gas wells.




19.5 Output Once data input in complete, press the View Output icon to generate the application output in both graphical and tabular format. The initial Summary screen is displayed, with a tab option to view Graphs/Tables.

1) Menu Bar. Functions of the menus are described in Section 3.4.

2) Tool-Bar Icons. Tool-bar icons can be used to quickly access commonly used functions.

3) Output Graphs and Tables. Results of calculations for the current input parameters are displayed both graphically and in tabular format.

Output data may be reviewed in any order, and by double-clicking on a graphical image it can be enlarged and viewed on a full screen.

Graphical outputs can be viewed individually, or multiple graphics can be viewed on one screen by selecting from the list using either the Ctrl or Shift key.



Graphical ouput presentaions include:

Pressure Profile

Pressure Profile. This pressure profile is essential for determining wellbore pressure in the annulus in relation to fracture and pore pressures. The graph also shows required injection pressure.

Annular Velocity Profile

Because of the nature of foam flow, in most cases the velocity of the foam is highest close to the surface in the annulus where the air has expanded.

The algorithm for calculating cuttings velocity is based on an assumption of a vertical (or near vertical) wellbore. Results for deviated sections of the wellbore may not be accurate.




Foam Quality

Drillers applying underbalanced fluid systems are very interested in foam quality since this parameter controls the cuttings-lifting ability of the foam. Experience dictates maintaining the foam quality above approximately 0.55 (55%) at the hole bottom.

Mixture Density

Density of lightweight fluids is strongly impacted by depth (i.e., pressure)

Cuttings Transport Ratio

Cuttings transport ratio is defined as the cuttings velocity divided by the mean annular velocity. It is a good measure of the carrying capacity of the drilling fluid.



Fanning Friction Factor

Friction factors are available for engineers interested in hydraulics parameters beyond pressure predictions.

Gas Deviation Factor

The gas deviation factor Z is a measure of the divergence of the fluid behavior from the ideal gas law.

Tabulated Data

A number of different tabular data viewing options are available. These are:

Profile




Cuttings Transport

Flow Pattern

Gas Deviation.

7 Brill, J.P. and Beggs, H.D., 1991: Two-Phase Flow in Pipes, Sixth Edition, January.


220020. HYDRAULICS FOR HTHP WELLS

Rheological properties of drilling fluids are usually considered to be independent of pressure and temperature. In many cases, this is a good approximation. For shallow wells, temperature changes are not large, and hence, rheological variations with temperature are small. Also, many wells have a large gap between pore and fracture pressure, so errors in estimation of dynamic circulation pressure have no significant consequences for integrity or kick probability. However, for wells with small margins between pore and fracture pressure, careful analysis of the effects of temperature and pressure on wellbore hydraulics and the potential for kicks is needed.

Hydraulics for HTHP Wells was developed to address the industry’s need for detailed analysis of wellbore hydraulics and improved drilling operations for high-temperature/high-pressure wells. The program calculates pressure profiles and frictional pressure losses along the mud circulating path, and mud rheological parameters inside and outside the drill string. Output from this model also compares corrected values with non-corrected values.

Hydraulics for HTHP Wells calculates mud hydraulics by taking into account the variation in rheological parameters as related to temperature and pressure. Important technical features of the Hydraulics for HTHP Wells Wellbore Hydraulics Model include:

Models both water-base mud and oil-base mud with and without asphalt

Provides different rheology models including Bingham plastic and power-law models

Allows users to manually input rheological parameters as functions of temperature and pressure

Allows different input data formats for data readings obtained from different types of field viscometers

Provides API-suggested rheological parameter corrections if viscometer readings are not available

Calculates pressure profiles, frictional pressure losses, and rheological parameters along the mud circulating path

Compares results calculated based on corrected and non-corrected rheological parameters

20.1 Input

20.1.1 Project Page The Project input page for the Hydraulics for HTHP Wells model is very similar to the typical DrillNET Project page. See Section 3.2.1.

20.1.2 Survey Page The Survey input page for the Hydraulics for HTHP Wells model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

20.1.3 Tubulars Page The Tubulars input page for the Hydraulics for HTHP Wells model is very similar to the typical DrillNET Tubulars page. See Section 3.2.3.

20.1.4 Wellbore Page The Wellbore input page for the Hydraulics for HTHP Wells model is very similar to the typical DrillNET Wellbore page. See Section 3.2.4.

CHAPTER 20: HYDRAULICS FOR HTHP WELLS


20.1.5 Formation Page The Formation input page for the Hydraulics for HTHP Wells model is very similar to the typical DrillNET Formation page. See Section 3.2.5.

20.1.6 Drilling/Thermal Page To accurately calculate wellbore hydraulics, mud rheology should be evaluated as accurately as possible at different locations along the circulation path. This depends on accurate input data for formation temperatures and fluid temperatures at various locations. This temperature data can be entered manually into the Drilling Thermal page

1) Thermal Data Table. Temperature profiles inside and outside of the drill string may be modeled using another Petris DrillNET program, Wellbore Thermal Simulation. Thermal data are entered into the first three columns of the table. Column 1 is Measured Depth along the wellbore. Column 2 is Fluid Temperature Inside the Drillstring at that depth. Column 3 is Fluid Temperature Outside the Drillstring at that depth. Column 4, Formation Temperature, can be either calculated using a geothermal gradient or input manually.

You can input up to 200 temperature data points in the table. Measured depth in row 1 should be 0 feet (or 0 meters). Measured depths must be in increasing order (i.e., descending down the hole).

2) Drilling Data Table. Drilling data required for hydraulics calculations include flow rate of the drilling fluid, mud weight, rate of penetration, cuttings size and cuttings density.

3) Thermal Data Graph. This graph normally contains three plots: (1) temperature profile inside the drillstring; (2) temperature profile outside the drillstring; and (3) formation temperature profile.




20.1.7 Fluid Page

The Fluid Page contains the most important input data for Hydraulics for HTHP Wells. This page provides options for different mud types, rheology models, data options, and data sources. One of the rheology models for the drilling fluid is selected. To calculate hydraulics accurately, Hydraulics for HTHP Wells models take into account variation in rheological parameters with temperature and pressure instead of assuming they are constant.

Values of rheological parameters for the rheology models are normally determined by laboratory test data. These data normally consist of readings from a Fann viscometer. You can either input values of rheological parameters into data tables beneath the Rheology Parameters tab if the values are known, or input viscometer readings into the Viscometer Readings table.

1) FluidType. Select the mud type for this project.

2) Rheology Model Options. The selection of rheology model will activate the data input tables to accept corresponding values of rheological parameters. If the Bingham plastic model is selected, the corresponding rheological parameters are plastic viscosity and yield point. If the power-law model is selected, the corresponding rheological parameters are flow behavior index and consistency index.

3) Data Input Options. If the Rheological parameter values option is selected, you can manually input the rheological parameter data as a function of temperature and pressure into the data tables. If the Viscometer



readings option is selected, the viscometer readings table will become active for viscometer reading input. Then, viscometer readings will be used by the program to calculate parameters in the rheological parameter tables.

4) Data Source Options. This selection depends on what type of viscometer was used to obtain the viscometer readings. Using a different viscometer will provide viscometer readings with more or less coverage of temperature and pressure ranges. For example, Fann 70 provides readings for temperatures from 0 to 475°F, and pressures from 0 to 20,000 psi.

5) Viscometer Readings Table. Readings from viscometer tests are input here. The first two columns are temperatures and pressures. The remaining six columns contain viscometer readings at different rotation speeds from 3 rpm to 600 rpm.

6) Rheological Parameter Tables. If the Bingham plastic model is selected, these two tables are used to input (or display after calculation) plastic viscosity and yield point; if the power-law model is selected, these tables display consistency index (K) and flow behavior index (n).

Manually input values into the tables if known. If values are not known, these tables will be filled in according to the values in the Viscometer Readings table and the API factor function.




7) Calculate Rheology Parameter Values. Beneath the Viscometer Readings table is the option to calculate the Rheology Parameter Values, which are in turn used to update the Rheology Parameter tables in the second tab page. Users have the option to either apply or cancel the changes.

Beneath the Rheology Parameters table there are two options to Extrapolate or View Graphs.



Extrapolate option

For calculating hydraulics of HTHP wells, viscosity of the drilling fluid should be determined at downhole conditions. However, corrections can be made to surface conditions. API Correction Factors are average viscosity ratios obtained from measurements with a variety of drilling fluids. These viscosity ratios are the ratio of viscosity measured under high temperatures and pressures to those measured under ambient conditions at the surface. To determine the API corrected downhole viscosity, first find the correction factor for the anticipated downhole temperature and pressure, and then multiply viscosity at surface conditions by the correction factor.




1) API Mud Type. Select one of the mud types provided to view the effects of temperature and pressure.

2) API Data Input. Enter values for temperature and pressure for which the correction factor is to be determined.

3) API Result. The corresponding numeric value for correction factor is displayed.

4) API Graph Control Buttons. [Interpolate] is used to calculate the API correction factor at a specific temperature and pressure. A red dot will appear within the graph marking the specified data point.Clicking More Info … displays

5) API Correction Factor Graph. This displays the correction factor trend and the correction factor corresponding to the temperature and pressure of interest. Mud type affects the shape of the graph. For example, the correlation for water-base mud is not a function of pressure; consequently, only one curve is plotted. If an oil-base mud is selected, several curves will be displayed (2-D display) because the correlation factor is a function of both temperature and pressure.

The View Graphs opens a new window that displays the impact of temperature and pressure on rheology.



20.2 Output In addition to choose what graphs to generate, output for the Hydraulics for HTHP Wells includes the option to compare results from normal hydraulics operation.

The summary provides a summary of the input data and output data under current conditions as well as those under normal hydraulics drilling conditions if the appropriate output option is selected.

Pressure Profile. This graph shows the pressure profile along the wellbore inside and outside the drillstring. The pressure profile is calculated based on the temperature- and pressure-corrected rheological parameters.




Pressure Loss. This graph shows the frictional pressure profile along the wellbore inside and outside the drillstring. The frictional pressure profile is calculated based on corrected rheological parameters.

Annular Equivalent Circulating Density. This graph shows equivalent circulating density along the circulation path. Unlike normal mud weight, this quantity takes frictional pressure into account.




Cuttings Transport Ratio. The carrying capacity of the drilling fluid is summarized as reflected in the cuttings transport ratio, the ratio between the average cuttings velocity divided by the average fluid velocity. For a ratio approaching unity, there is no slippage of the cuttings.

Cuttings Settling Velocity. This parameter, also known as the slip velocity, relates cuttings and fluid velocity. For a settling velocity of zero, the cuttings are fully transported by the fluid.

If the Bingham plastic model is selected for hydraulics calculations, this graph shows plastic viscosity with measured depth inside and outside the drillstring. If the power-law model is selected, this graph shows



consistency index as a function of measured depth inside and outside the drillstring.?????????

If the Bingham plastic model is selected for hydraulics calculations, this graph shows yield point as a function of measured depth inside and outside the drillstring. If the power-law model is selected, this graph shows flow behavior index as a function of measured depth inside and outside the drillstring. For purposes of comparison, the constant yield point or flow-behavior index can also be shown in this graph if needed.

Mud Weight. This graph shows mud weight with measured depth.




Tabulated Results. All calculated hydraulics variables and rheological parameters are tabulated as functions of measured depth along the wellbore.


20.3.1 Tool-Bar Icon

Calculate and Extrapolate API Factors

This provides the same functionality as the Extrapolate option previously documented beneath the Fluid tab.


221121. DYNAMIC KILL FOR SLIM HOLES MODEL

The Dynamic Kill for Slim Holes model addresses the special concerns for safe hydraulics and well control in slim annuli. Conventional well-control techniques are based on the assumption that annular pressure losses are a small fraction of total circulating pressure losses. This assumption is often not valid in slim-hole wells due to high friction pressure losses for fluid flow in the annulus.

To address these issues, special hydraulics correlations were developed for pressure losses in slim annuli. Actual hole size is not the critical factor, but rather the size of the annular gap.

High frictional losses in the annulus, even at slow circulating rates, are the primary complication for slim-hole well control. Because of this, dynamic well kill has been implemented as an alternative in certain drilling situations. This method calls for utilizing increases in ECD to overcome flowing formation pressure by quickly increasing the pump rate or rotary speed.

21.1 Input

21.1.1 Project Page The Project input page for the Dynamic Kill for Slim Holes model is very similar to the typical DrillNET Project page. See Section 3.2.1.

21.1.2 Survey Page The Survey input page for the Dynamic Kill for Slim Holes model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

21.1.3 Tubulars Page The Tubulars input page for the Dynamic Kill for Slim Holes model is very similar to the typical DrillNET Tubulars page. See Section 3.2.3.

21.1.4 Wellbore Page The Wellbore input page for the Dynamic Kill for Slim Holes model is very similar to the typical DrillNET Wellbore page. See Section 3.2.4.

21.1.5 Formation Page The Formation input page for the Dynamic Kill for Slim Holes model is very similar to the typical DrillNET Formation page. See Section 3.2.5.

CHAPTER 21: DYNAMIC KILL FOR SLIM HOLE MODEL



1) Fluid Parameters. Enter flow rate and mud weight to be used in the hydraulics analysis.

Select the mud rheology model that best describes the fluid to be used. Four fluid models are provided. Additional theoretical discussion is presented in Section 28.12.1. Rheology models include:





4. Herschel Bulkley. This model, similar to the power-law model, applies to shear-thinning or pseudoplastic drilling fluids. It also incorporates a threshold shear stress (yield point). Consequently, the Herschel-Bulkley model can be considered a hybrid combination of the Bingham-plastic and




power-law models. Herschel-Bulkley was developed based on the observation that many typical drilling fluids exhibit both a yield stress and shear thinning.

Note that the slim-hole correlations are not available for the Herschel-Bulkley model. Consequently, this rheology model is not available for slim annuli.

At high shear rates, all of these fluid models represent a typical drilling fluid reasonably well. Differences between models are most pronounced at low rates of shear.


Viscometer Readings

If Fann Viscometer readings are available, these can be quickly converted to rheological constants. Click “Viscometer readings” and select the number of rotation speeds from the list in the drop-down box. From these you can calculate parameters required for Newtonian, Bingham plastic, Power law or Herschel-Bulkley models.


3) Drillpipe/Annulus Slim-Hole Options. The Dynamic Kill model is based on correlations for calculating pressure drops in slim annuli. The slim-hole hydraulics correlations can be corrected for an eccentric annulus (versus a centered drill string).

Dynamic kill, which entails adjusting flow rate to change the pressure drop, is an option for increasing pressure at the formation face to maintain control of the well. ECDs in slim-hole wells can be adjusted by varying flow rate since pressure losses in the annulus are a significant proportion of overall pressure drop. Select Use slim-hole correlations to use the slim-hole hydraulics correlations. Otherwise, conventional correlations are used as in the Hydraulics for Normal Circulation Model (see Section 17). The option of using conventional hydraulics models here in the Dynamic Kill for Slim Holes model is provided should you wish to compare the impact of the slim geometry.

The slim-hole hydraulics correlations can also corrected for an eccentric annulus (versus a centered drill string) by selecting Eccentric pipe.

21.2 Output Output for the Dynamic Kill for Slim Holes Model is presented as a Kill Chart in a new window. ECDs in slim-hole wells can be adjusted in the field since pressure losses in the annulus are a significant proportion of overall pressure drop. “Dynamic kill,” which entails adjusting flow rate (or pipe rotation speed) to change pressure drop, is an option for increasing pressure at the formation face to maintain control of the well.

Click on any input page to open the Kill Chart output window. This utility is powerful for comparing results of changes in flow rate, mud weight, and pipe rotation on bottom-hole ECD.

21.2.1 Single Curve Kill Chart The first tab provides options for designing and reviewing a specific curve for a range of operational conditions to be applied during a dynamic kill operation.



To design a Single-Curve Dynamic Kill Chart:

1. Select primary objective type as “ECD value” or “ECD change.”

2. Enter desired ECD value or change.

3. Under “Calculation Options,” select one parameter to remain fixed – mud weight, flow rate, or pipe rotation rate.

4. Change any values for minimum, maximum and interval as desired.

5. Click [Calculate] to generate a new graph and table.

6. Review trends in the graph.

The red line represents combinations of X and Y values (along with the other constant parameter) that will produce the ECD change you specified. The blue dot represents current conditions at current ECD (that is, before the ECD is changed) based on data you entered on the main input pages.

Editing the Graph

The Kill Chart graph can be opened as a separate window for easier viewing, as well as copied and printed. Right-click your mouse over the graph to open the Edit menu. Select “Display in Separate Window” to open a new window that is easy to review. Click “Export to Excel” if you want to further analyze the data. Options on this pop-up menu are described in Section 3.4.




21.2.2 Multiple Curve Kill Chart The second tab on the Dynamic Kill output window provides options for designing and reviewing a family of curves for comparing a range of operational conditions for a dynamic kill operation.

To design a Multiple-Curve Dynamic Kill Chart:

1. Set the range for ECD changes by entering from (minimum change), to (maximum change), and with interval (ECD increment between each curve). Note that a maximum of 14 curves can be displayed together.

2. Under “Calculation Options,” select one parameter to remain fixed – mud weight, flow rate, or pipe rotation rate.

3. Change any values for the other two parameters for minimum, maximum and interval as desired.

4. Click [Calculate] to generate a new graph and table.

Each line in the graph represents combinations of values (along with the other constant parameter) that will produce each ECD change as noted. The blue dot represents current conditions at current ECD (that is, before the ECD is changed) based on data you entered on the main input pages.

The table will show a result only when both varying parameters are within the assigned range. For example, flow rate range in the figure above is set as 0–500 gpm. However, only flow rates from 90–240 gpm produce ECD changes in the desired ranges for this case. Consequently, rows outside this range are not displayed.

Editing the Graph

The Kill Chart graph can be opened as a separate window for easier viewing, as well as copied and printed. Right-click your mouse over the graph to open the Edit menu. Select “Display in Separate Window” to open a new window that is easy to review. Click “Export to Excel” if you want to analyze the data independently. Options on this pop-up menu are described in Section 3.4.




21.3.1 Tool-Bar Icons A special tool-bar icon is provided when the Dynamic Kill for Slim Holes Model is selected.



222222. WELLBORE THERMAL SIMULATION MODEL

Wellbore Thermal Simulation is a thermal model for improving the prediction of temperatures downhole in a wellbore. The model accounts for natural and forced convection, conduction within the wellbore, as well as heat conduction within the surrounding rock formation. A wide variety of well flow operations can be modeled (see Section 22.1.6) including

Liquid or steam injection

Liquid or steam production

Forward and reverse circulation through the wellbore with liquid

Forward circulation through the wellbore with gas

The model handles boreholes of any inclination from vertical to horizontal, and graphically shows temperatures in tubing, annulus, and other selected locations surrounding the wellbore. It calculates temperature gradients in multilayer rock formations accounting for heat conduction from the wellbore flow stream and rock formations. The model also addresses mixing and cooling in the surface fluid tanks for circulation operations.

22.1 Input

22.1.1 Project Page The Project input page for the Wellbore Thermal Simulation model is very similar to the typical DrillNET Project page. See Section 3.2.1.

22.1.2 Survey Page The Survey input page for the Wellbore Thermal Simulation model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

22.1.3 Tubulars Page The Tubulars input page for the Wellbore Thermal Simulation model is very similar to the typical DrillNET Tubulars page. See Section 3.2.3.

22.1.4 Wellbore Page The Wellbore input page for the Wellbore Thermal Simulation model is very similar to the typical DrillNET Wellbore page. See Section 3.2.4.

22.1.5 Formation Page The Formation input page for the Wellbore Thermal Simulation model is similar to the typical DrillNET Formation page (see Section 3.2.5). However, for this model, formation pressure data are not of interest. Rather, formation thermal properties are entered into the table.

CHAPTER 22: WELLBORE THERMAL SIMULATION MODEL


1) Rock Thermal Properties Table. Enter as many rows as required to specify rock layers along the wellbore. TVD in column 1 is the bottom depth of the current layer. Techniques for entering and editing data are similar to those described for the Survey Data table (see Section 3.2.2).

Specify the rock layers through which the wellbore passes. Row 1 is the surface material. Proceed in order down the hole. See the table at right for representative thermal data for several common formation materials.

Temperatures and Gradients

Formation data may be entered as either temperatures or as temperature gradients. Enter one of these quantities and the corresponding value (shown with a yellow background) will be calculated automatically.

To select your preference, access the Options menu and select “General Options…” Under the “Input” tab, select your preferred quantity.

Typical Material Thermal Properties Material Density

(lb/ft3)Conductivity

(BTU/hr-ft-°F) Heat Capacity(BTU/lb-°F)

Shale 140.0 0.920 0.30 Granite 164.9 1.630 0.20 Limestone 154.9 0.750 0.22 Sandstone 139.3 1.080 0.17 Soil 91.0 0.740 0.21 Coal 84.3 0.150 0.30 Cement 131.1 0.840 0.21 Ice 57.0 1.280 0.46 Salt 134.8 3.470 0.21 Water 62.4 0.350 1.00 Basalt 98.6 1.160 0.21




Representative temperatures and temper-ature gradients for several drilling areas around the world are shown in the chart.

Importing Data

Several methods are provided for importing formation data, including other DrillNET project files (*.XML), and from the Galaxy database. To import data, right-click over the formation table and select “Import” or “Get Formation Data from Galaxy” from the pop-up menu.

Copying from Excel

To copy from a spreadsheet application (e.g., Excel), assemble the data in the spreadsheet in columns. Copy the data column by column into DrillNET. Select the source range of interest and copy to the clipboard (control+C). Go back to DrillNET, right-click on the appropriate cell in row 1, and select “Paste” from the pop-up menu.

Formation Table Edit Menu

You can save, print, import, and edit the formation table in several ways by opening the pop-up edit menu. Right-click over the table to open the menu and then select the desired option. See Section 3.2.5.

After you make any changes to the data, click [F9] or select “Refresh” from the View menu to redraw the graphs.

2) Formation Temperature Graphs. Temperature and temperature gradient data in the Rock Thermal Properties Data table are plotted for inspection. Both temperature with depth and temperature gradient with depth are shown; click the corresponding tab at the bottom of the graph.

Right-click over the graph to access options for saving, printing, adding a text box, and exporting the graph to Excel.

3) Surface Temperature. Specify the undisturbed geothermal temperature at the surface. Representative temperatures and gradients for several drilling areas around the world are shown in above.

Geothermal Temperature Gradients(°F/100 ft)

California 1.34Germany 1.81Canada 1.36Wyoming 0.78Oklahoma 0.77Nigeria

fresh water 0.60salt water 2.30

Depth (ft)T

empe

ratu

re (

°F)

2000 12,00010,000800060000 40000

150

200

250

100 Nigeria – fresh water

Nigeria

–sa

lt wat

er

Oklahoma

Wyoming

Canada

Germany

California




1) Thermal Simulation Operation Options. Select one of nine operating modes that characterize fluid flow. Each mode selected defines specific flow and thermal boundary conditions for your analysis.

1. Liquid Forward Circulation: Predicts temperatures for operations based on conventional forward circulation with liquid. Fluid enters the well at the surface, travels down the production tubing (or drill string), and returns up the annulus to the surface.

2. Liquid Reverse Circulation: Predicts temperatures for operations based on reverse circulation with liquid. Fluid enters the well at the surface, travels down the annulus, and returns up the production tubing to the surface.

3. Liquid Injection: Predicts temperatures for fluid injection. Fluid enters the well at the surface, travels down the production tubing (or drill string), and flows into the rock formation with no flow in the annulus.

4. Liquid Production with Tubing: Predicts temperatures for fluid production. Fluid enters the well at the bottom and travels up the production tubing to the surface with no flow in the annulus.

5. Liquid Production without Tubing: Predicts temperatures for fluid production. Fluid enters the well at the bottom and travels up the open hole and/or casing to the surface.

6. Gas Forward Circulation: Predicts temperatures and pressures for operations based on forward circulation with gas. Gas enters the well at the surface, travels down the production tubing (or drill string), and returns up the annulus.




7. Steam Production with Tubing: Predicts temperatures and pressures for two-phase steam production. Steam enters the well at the bottom and travels up the production tubing to the surface with no flow in the annulus.

8. Steam Production without Tubing: Predicts temperatures and pressures for two-phase steam production. Steam enters the well at the bottom and travels up the open hole and/or casing to the surface.

9. Steam Injection: Predicts temperatures and pressures for two-phase steam injection. Steam enters the well at the surface, travels down the production tubing (or drill string), and flows into the rock formation with no flow in the annulus.

2) Steam Properties. If the flow operation involves steam injection or production, you need to specify steam properties. If available, enter the steam quality at the inlet. Quality is the volume ratio of the fluid occupied by the gas phase. For example, a quality of 0.95 describes a two-phase fluid composed of 95% vapor and 5% liquid by volume.

If steam quality is not known, enter inlet pressure of the produced or injected steam.

3) Temperature at Inlet for Circulation. When the operation includes fluid circulation, fluid temperature at the inlet will normally change as the operation progresses. Circulated fluids return to the surface mud tank and are mixed with fluid in the tank. Fluid temperature in the tank for these cases is then different from ambient temperature. Heat transfer will also occur between the tank and its environment. DrillNET can predict final temperature of the mixed fluid in the tank based on these input parameters.

Select “Single Pass” if you prefer to ignore the impact of mixing and heat transfer from/to the fluid at the surface. The fluid will be treated as if it were circulated only once through the well. Fluid temperature at the inlet will remain as you prescribed in the Operation Schedule table on the Schedule page (see Section 22.1.7).

Select “Tank Mixed” to model the impact of temperature changes in the mud tank due to fluid mixing and heat transfer to/from the environment. Next, enter the parameters that describe the thermal environment in the surface tank.

Note that these input parameters are disabled if the operation does not include circulation.



22.1.7 Schedule Page

1) Fluids Initially in Tubing and Annulus Table. Specify the fluids present in the production tubing (or drill string) and in the annulus prior to the beginning of the operation. These fluids are assumed to be at geothermal temperature as the operation begins.

Four fluid rheology models are provided: (1) Newtonian, (2) Bingham plastic, (3) power-law and (4) Herschel-Buckley. Click on the drop-down list in the Rheology column. Parameters required for each model will become active in the table after you select a model. A description and comparison of the rheology models is presented in Section 28.12.1.

2) Operational Schedule Table. Specify the fluid pumping (circulation, production, injection) operating schedule in detail. Each fluid being pumped or produced is described in a separate row. If there is additional fluid influx from the formation during any phase of the operation, check column 7 and then enter the fluid identification number of the influx. These identification numbers refer to the fluids listed in the Influx Fluids table (see ) at the bottom of the Schedule page.

The Flow Period for each stage, listed in column 4, is the cumulative flow time as the overall operation progresses.

3) Influx Fluids Table. Any additional fluids introduced into the flow from the formation are specified here. Temperature as the fluid enters the wellbore, flow rate, density, and a rheological characterization are required. The row number (listed to the left of the table) is used to identify each influx fluid in the Operational Schedule table (see ).




22.1.8 Casing Page

1) Onshore/Offshore Environment. Select or unselect the Offshore option. Data requirements differ according to the well location.

Air Gap/Water Depth. The RKB (rotary kelly bushing) elevation is specified with respect to the ground level (for onshore wells), and to mean sea level (for offshore wells). For offshore wells, this elevation is commonly called the “air gap.” This quantity is used for offshore wells with subsea wellheads to calculate the casing top depth (air gap + water depth).

Subsea BOP: for offshore wells allows you to specify whether the wellhead is positioned on the surface or at the sea bed. For onshore wells, this is set automatically to surface.

2) Riser Strings Table. Describe the geometry and thermal properties of the riser string(s). Thermal properties for typical materials can be imported by right-clicking over the table to open the Material Thermal Properties database. Other options for adding/deleting rows and printing the table are provided on the right-click pop-up menu.

3) Casing Strings Table. Data for casing strings include the casing shoe depth (displayed as TVD and MD); string type (casing, liner, immediate tie-back, or subsequent tie-back); and string top depth (displayed as TVD and MD), useful especially for liners or for offshore wells with sub-sea wellheads.

Tie-backs, either subsequent or immediate, can be added to the table. A tie-back can only be added behind a liner. To add a tie-back, right-click on a liner row; a pop-up menu will appear with options. All string types are initially set by default to intermediate casing except surface casing in the first row. For a casing (except for surface casing), you can switch to a liner by clicking the drop-down list and selecting liner. For this case, a



dialog box will appear for entering the liner top depth. For liners, you can switch back to a casing; or add to the liner either a subsequent or immediate tie-back. For tie-backs, you can remove it or change its type from immediate to subsequent (and vice versa). You can remove a casing or a liner via the right-click menu. If you remove a liner that includes a tie-back, the tie-back will be removed.

Shoe Depth includes both TVD and MD. TVD cannot be modified in this table directly (as indicated by yellow background). If you want to change TVD directly, double-click the cell, enter the value into the pop-up window, and then select [Apply]. Only casings and liners have a shoe depth.

Top Depth also is displayed as TVD and MD. This column can be explicitly set only for top MD of liners. For casings and tie-backs, this field displays the BOP depth (zero for onshore wells and offshore wells with surface wellhead; air gap + water depth for offshore wells with sub-sea wellhead). When you change a casing to liner, you will be required to enter the top depth of the liner. To enter or change top depth for a liner directly, double-click on the top MD cell. Enter a new value and then press <Enter> to have the corresponding TVD calculated. You can also double-click on the top TVD cell and enter a new value in the pop-up window.

Enter thermal properties for each tubing material. To access a database of typical properties, right-click over the table and open the Material Thermal Database. In this window, select representative data for any of several common materials. These data may be imported from the database by selecting the row and then clicking [Accept].

4) Diameter of Surface Hole. This value is used to define the outer limit of the radial zone where casing and cement may be present. Beyond this distance from the center of the well only rock formation is assumed to be present.

22.2 Output Output for the Wellbore Thermal Simulation model includes results under three tabs:

1. Summary – Displays key input and output values

2. Graphs/Tables – A typical DrillNET multi-featured output display allowing selection of graph and table displays (see below). See Section 3.3 for a description of options for displaying and working with this window.

3. Thermal Analysis – An interactive window that allows you to review the complete thermal distribution at the end of the flow period (see Section 22.2.1).



22.2.1 Thermal Analysis Window

1) Thermal Analysis Depth Graph. This graph presents a schematic of the wellbore that shows the (1) casing program along with cement columns and (2) color-coded temperature of the fluid in the wellbore with depth. The flow time corresponding to these results is the end of the complete flow schedule as specified on the Schedule page (see Section 22.1.7). If you want to view another time, return to the Schedule page and adjust the final time period in the input data.

In addition to depicting wellbore geometry and temperature profile, this graph allows you to point and select any specific depth and radial position for detailed temperature results. Move the mouse cursor over the graph area. At any depth and radius of interest, click the mouse to select that position. The current position of the cursor is shown in the “Cursor Position” box. The most recently selected depth and radius is shown as the “Selected Position.” Results in the figures and tables will be updated automatically to reflect the selected position radius and MD.

2) Radial Temperature Profile Table and Graph. This table and graph display temperature gradient as a function of radius from the center of the wellbore. The MD position is constant for these data. The depth of interest is selected by clicking on the wellbore graph and is shown under “Selected Position.”

3) Thermal Analysis Depth Selection. You can select and review the temperature profile at any depth or radial position in great detail by selecting it with the mouse cursor. Click on the wellbore schematic at the depth and radius of interest. The “Cursor Position” box shows where the mouse is currently pointing. After you click, the




“Selected Position” box displays and retains the position you clicked on. After the mouse is clicked, the tables and graphs on the right side of the page are automatically updated to show data at that depth and radius.

4) MD Temperature Profile Table and Graph. This table and graph display temperature as a function of depth. The radial position from the center of the wellbore is constant for these data. The radius of interest is selected by clicking on the wellbore graph and shown under “Selected Position.”


223323. KILLSHEET APPLICATION MODEL

The Killsheet Application is designed for well-control analysis for 3D wellbores (vertical and horizontal) for land and offshore applications. It includes both the Driller’s method and Engineer’s method (wait and weight). The model calculates all kill information and prepares a drill-pipe pressure schedule. Effects such as wellbore deviation, subsea BOP stacks, tapered drill strings, kill-mud weight margins, and circulating drill-pipe margins are included. The model also includes a simplified mode for use in training.

Important features of the Killsheet Application include:

Calculates important kill information such as kill-mud weight, initial circulating pressure (ICP), final circulating pressure (FCP), influx information, required barite, pump strokes, volumes, and circulation time for filling each drill-string and annular section during the kill procedure

Generates a kill chart graph that can be copied, saved, and printed

All input, output, and options are visible in one window, allowing the user to see the impact of any changes to data or options immediately

Generates a one-page worksheet report containing all data and the kill chart based on an Excel template

23.1 Options Pane The Killsheet Options Pane includes several options for program operation. These selections may be changed at any time. To recalculate and update results after changes, press [F9] or select “Refresh” from the View menu.

CHAPTER 23: KILLSHEET APPLICATION MODEL


1) Killsheet Models. Basic program options include “School training” and “Field application.” When you select “School training,” the program is simpler to operate because less input data are required for generating the kill sheet.

Differences between “School training” and “Field application” include:

1. Deviated wellbores are easier for students to specify. When the “Deviated well” option is selected,

a. Students input only three deviation parameters (TVDs for kick-off, end of build, and open hole) on the Pre-recorded Info page.

b. Field application users must input a complete wellbore survey on the Survey page.

2. The wellbore and drill string are easier for students to specify.

a. For students, the Wellbore description table (on the Pre-recorded Info page) is fixed as three sections (riser, casing and open hole) and the Drill String description table (on the Capacities page) is fixed as four sections (Drill Collar 1, Drill Collar 2, HWDP and Drill Pipe).

b. Field application users can specify any number of sections of wellbore and drill string in the tables.

2) Well/BOP Options.

Deviated Well. If selected, a wellbore survey must be entered. A complete wellbore survey is required if the program mode is “Field application.”. If “School training” is selected, a highly abbreviated survey is entered on the “Pre-recorded info” page. If “Deviated well” is not selected, a vertical well is assumed with final TVD defined in the Wellbore table on the Pre-recorded Info page.

Subsea BOP. When this is selected, fluid weight in choke/kill line(s) and choke/kill volume are required. In addition, the slow pump-rate data table (top of Pre-recorded Info page) will contain two extra columns related to choke/kill line(s).

3) Kill Procedure Options. Displays kill schedules (table and chart) for driller’s method or wait and weight method. These are the most common fluid circulation-type well control methods. These practices are conducted to maintain a constant BHP during the fluid circulation program.

For the Driller’s Method, mud weight is not increased as the kick is circulated out. At the end of this procedure, there is still pressure at both the inlet to the drill pipe and at the choke. The Driller's method is a fluid circulation practice typically used to displace formation fluid influx from the wellbore annuli. The BHA nozzle is positioned at the designated kill depth. In cases where the circulated fluid density is lower than the required kill-weight density, this pumping program will not result in hydrostatic pressure balance of the well. However, when performed properly, this method ensures that fluid in the wellbore will be of uniform density when the process is complete. After circulation is completed, the surface pressure is combined with the hydrostatic pressure exerted by the pumped-fluid column, providing a check to confirm the required kill-weight fluid density.

For the Wait and Weight Method (also called the Engineer’s method), the well is shut in and the mud weight necessary to kill the well is determined. Mud weight in the pit is raised to this value, and then the kick is circulated out. At the conclusion of this process, both drill pipe and choke pressure are atmospheric when circulation stops. As with Driller’s method, the Wait and Weight method is conducted with the BHA at the designated kill depth. After this circulation stage, static surface pressure in both the drill string and wellbore annulus should be zero.




Comparison of Kill Methods (IADC, 1992) Method Advantages Disadvantages

Driller’s Method

Circulation can be started almost immediately

Simpler

Fewer calculations required

KWM can be mixed to uniform density while first circulation is being completed

Does not require special modifications in directional wells with tapered strings

Minimum of two circulations (more time)

Higher annulus pressures

More wear on choke and gas-handling equipment

Wait and Weight

Minimum of one circulation (less time)

Lower annulus pressures

Less wear on choke and gas-handling equipment

Circulation must wait to start until KWM has been mixed

More complex

More calculations required

Requires special modifications in directional wells with tapered strings

4) Primary Parameter Options. Selects which parameter is plotted as the X-axis on the Kill Chart on the Worksheet page. That parameter is also displayed on the first column of the table with whole integer values (if possible).

5) Pressure Schedule Options.

Modified for Tapered Drillstring. The drill-pipe pressure schedule must be modified when using a tapered drill string. This is true also if the wait and weight method is employed in directional holes. In these wells, a barrel or cubic meter of mud does not occupy the same vertical height at every depth along the string since the cross-sectional area changes with depth. Therefore, hydrostatic pressure reduction is not linear with volume pumped (Watson et al., 2003). A straight-line assumption for a well with a tapered drillstring could under-balance the hole and invite a secondary kick. The same situation exists when small-diameter drill collars are beneath otherwise consistent drill pipe, but the effect is small enough in most cases to allow using a convenient schedule.

HMW Surface to Bit only. With this option is selected, the kill chart only displays the section for the heavy weight mud (HWM) traveling from surface to bit. This section is not a straight line when the well is deviated and/or a tapered drillstring is used. This section can be displayed by itself to more clearly illustrate the effects of wellbore deviation and tapered drillstrings.

6) Additional Margin On Options.

Kill Mud Weight. This allows you to enter a kill mud weight margin on the bottom of the Worksheet page. As the program recalculates (refreshes), the final circulating pressure will be recalculated (the last horizontal section on the kill chart will be modified).

CDPP (Circulating Drill Pipe Pressure). If this option is selected, you can enter a CDPP margin on the bottom of the Worksheet page. As the program recalculates, all drill-pipe pressure schedules will be updated (the curve on the kill chart will be modified).



23.2 Input/Output

23.2.1 Pre-Recorded Info Page

1) General Data. This identifying information will be shown on the printouts. Any or all of these entries may be left blank if desired.

2) Slow Pump Rate Data Table. You can input data for one, two or three pumps and then select the active pump from the drop-down list below the table.

3) Well Data. Fluid weight in choke/kill line(s) is required only when the option “Subsea BOP” is selected.

4) Wellbore Data Table. Wellbore tubulars are described in this table. When the program option is “School training,” this wellbore table contains only three sections: riser, casing, and open hole.

When “Field application” is selected, any number of wellbore sections can be entered. Note, however, that the last two rows must be the deepest casing and open hole, respectively.

23.2.2 Survey Page When the primary Model option is “Field application,” the Survey input page for the Killsheet Application model is very similar to the typical DrillNET Survey page. See Section 3.2.2.




When the primary Model option is “School training,” the Survey page only displays the data corresponding to lengths and depths entered on the Pre-Recorded Info page. For these cases, the survey data cannot be modified on this page.

23.2.3 Capacities Page

1) Drill String Data Table. The drill string must be specified in detail. The first row is the deepest section of the string. Other sections of the string should be entered in order proceeding up to the surface.

Length, OD, and ID are required for each section. If any data are missing, that row will not be considered in the analysis. The required length of the last section (in the last row) that will complete the drill string to the surface is calculated automatically and displayed in the table whenever [Refresh] is selected from the View menu (or press F9).

Use the Edit menu to copy and paste entries, and to insert rows into or delete rows from the table.

2) Wellbore Transitions Schematic. A special graph window is available for viewing the wellbore transitions (that is, changes in flow area) and fluid capacities. Since this plot is only designed to compare the fluid capacities of the drill string and annulus sections, it does not reflect the well trajectory.



Editing the Graph


3) Annulus Data Table. This table summarizes all locations of changes in flow area in the annulus due to changes in ID of the wellbore and/or OD of the drill string. These data are all calculated and may not be edited here. These data are displayed in the Wellbore Transitions Schematic.

23.2.4 Kick/Kill Page

1) Recorded Kick Information. These data are recorded after the kick occurs. SIDPP directly measures the underbalance between formation pressure and hydrostatic pressure of the mud in the drillstring and is the most important parameter. It is directly related to calculation of kill-mud weight, ICP, and FCP.

Values for pit gain and SICP are used in determining density and nature of the formation influx.

2) Calculated Kill Information. All the information here is calculated from the pre-recorded data and kick data.

Formation Influx. These data include the size, nature, and maximum allowable size of the formation influx.

MAASP. Maximum Allowable Annular Surface Pressures are calculated here for the applied pressure from shoe integrity or leak-off test only. Note that the MAASP is different for the present mud (pre-kick) and the kill mud (post-kick).




Kill Data. Kill-mud weight, ICP, and FCP are essential for constructing the drill-pipe pressure schedule and kill chart.

Barite. Required volume and addition rate of barite are shown.

Pump Strokes, Pumped Volumes, Pumping Time. These data represent the key points on the kill chart.

All results are calculated and updated after you select “Refresh” from the View menu (or click F9).

23.2.5 Worksheet Page

1) Worksheet Data Table. The table summarizes the final schedule for killing the well. The first column in the table will be the selected “Primary parameter” option and is displayed with integer values (when possible).

Right-click over the table for options for copying and printing the data, and displaying the table in a separate window.

2) Kill Chart. This graph displays the pressure schedule for killing the well. The X-axis can be pump time, strokes, or volume and will correspond to the “Primary parameter” option currently selected on the Program Options pane (see Section 23.1).



Editing the Graph

The Kill Chart graph can be opened as a separate window for easier viewing, as well as copied and printed. Right-click your mouse over the graph to open the Edit menu. Select “Display in Separate Window” to open a new window that is easy to review. Options on this pop-up menu are described in Section 3.4.

3) Margins. In field operations, some operators incorporate a trip margin for kill-mud weight before killing the well, or add another increment to the ICP backpressure during the control procedure. Although this practice is generally discouraged because it adds extra pressure to the last casing shoe, the program provides this option to illustrate the effect on the pressure schedule.


23.3.1 Tool-Bar Icons Special tool-bar icons are provided when the Killsheet Application Model is selected. The special icons include:

Worksheet Report. Opens the Worksheet Report in Excel (see Section 23.3.2) that provides a convenient summary of the well kill sheet.

23.3.2 Worksheet Report After the Kill Sheet has been calculated, an advanced feature is provided for creating a summary report that is directly exported to Excel. To generate the Report (see next page), click on the icon toolbar or select “Worksheet Report” from the Tools menu.

Within Excel, you can edit report text as required, print the report and/or copy/paste the report into other applications.




Well name: BOP stack:Location: Well type:Completed by: Kill procedure:Report date:

Pressure: 980.0 psi12.00 ppg @Slow rate: 45.0 stk/min

Casing Shoe Capacity: 0.0975 bbl/stk6.094 in Efficiency: 0.950 %17480.0 ft True output: 0.0926 bbl/stk17480.0 ft

Leakoff test EMW: 15.61 ppg Active surface pits: 718.5 bblChoke/kill line: 38.5 bbl

8.500 in Drill-string 260.0 bbl19000.0 ft Annulus 157.1 bbl19000.0 ft Total active fluid system: 1174.1 bbl

250 psi Pit gain: 68 bbl420 psi

1356.6 ft Surface to bit: 2806.6 stk9.59 ppg Bit to casing shoe: 823.2 stk

Casing shoe to surface: 1288.8 stk955.5 bbl Total: 4918.7 stk12.45 ppg45.0 stk/min Surface to bit: 260.0 bbl4.17 bbl/min Bit to casing shoe: 76.3 bbl1174.0 psi Casing shoe to surface: 119.4 bbl1307.4 psi Total: 455.6 bbl

3278.2 psi Surface to bit: 62.4 min2866.6 psi Bit to casing shoe: 18.3 min

Casing shoe to surface: 28.6 min347.0 sacks Total: 109.3 min0.8 sacks/min

Strokes Volume Time Pressurebbl min psi

2112.0 195.6 46.9 1174.02259.8 209.3 50.2 1180.32407.5 223.0 53.5 1186.52555.2 236.7 56.8 1192.72702.9 250.4 60.1 1199.02850.6 264.0 63.3 1205.22998.3 277.7 66.6 1211.43146.1 291.4 69.9 1217.73293.8 305.1 73.2 1223.93441.5 318.8 76.5 1230.23589.2 332.5 79.8 1236.43736.9 346.1 83.0 1242.63884.6 359.8 86.3 1248.94032.4 373.5 89.6 1255.14180.1 387.2 92.9 1261.44327.8 400.9 96.2 1267.64475.5 414.5 99.5 1273.84623.2 428.2 102.7 1280.14770.9 441.9 106.0 1286.34918.7 455.6 109.3 1297.2

KICK/KILL DATA

Shut-in casing pressure:

Formation InfluxLength:

Maximum allowable volume:Type:

w/ present mud:w/ kill mud:

Kill rate speed:Kill circulation rate:Initial circulating pressure:Final circulating pressure:

Kill mud weight:

Present mud weight:

TVD:

Open HoleDiameter:MD:

ID:MD:TVD:

WELL CONTROL WORKSHEET

General Information

Kill Pump

Hazelnut H-34

PRE-RECORDED INFORMATION

Section 34-D-25John Hatcher8/1/2006

MAASP to Fracture Formation @Shoe

PRESSURE SCHEDULE

Recorded Kick Information

Calculated Kill Information

Saltwater influx

Shut-in drill-pipe pressure:

Addition rate during circulation:

Circulation Time

Density:

Well Data

Options

BariteRequired (@100lbm/sk):

Pump Strokes

Mud Volumes

SubseaDeviatedDriller's Method

Volume/Capacities


224424. KICK SIMULATION MODEL

The Kick Simulation Model is a powerful and easy-to-use engineering tool for comprehensively evaluating well-control procedures after a gas kick is taken while drilling. Well control is one of the most critical aspects of drilling operations. Improper handling of kicks can result in blowouts with potential loss of equipment and even life.

The model describes the complex multiphase flow that develops as a gas influx is circulated out of a well. The model is suitable for 3D wellbores (vertical and horizontal) for inland and offshore applications. It handles both the Driller’s and Engineer’s well-control methods and incorporates Bingham-plastic and power-law fluid models for frictional pressure calculations. The program also allows you to select either a single-bubble model (water-base mud only) or one of three two-phase flow correlations for handling gas migration in the wellbore. It takes into account the effect of gas solubility when oil-base mud is used.

The program calculates kill-mud weight, the drill-pipe pressure schedule, and the kill sheet. It predicts pressure changes and equivalent circulating densities (ECDs) at the choke, casing shoe, wellhead, and at the end of the well. Maximum ECD along the wellbore is also calculated and compared with pore- and fracture-pressure gradients. These results are very useful for determining whether equipment is adequate, along with kick tolerance.

24.1 Input

24.1.1 Project Page The Project input page for the Kick Simulation model is very similar to the typical DrillNET Project page. See Section 3.2.1.

24.1.2 Survey Page The Survey input page for the Kick Simulation model is very similar to the typical DrillNET Survey page. See Section 3.2.2.

24.1.3 Tubulars Page The Tubulars input page for the Kick Simulation model is very similar to the typical DrillNET Tubulars page. See Section 3.2.3.

24.1.4 Wellbore Page The Wellbore input page for the Kick Simulation model is very similar to the typical DrillNET Wellbore page. See Section 3.2.4.

24.1.5 Formation Page The Formation input page for the Kick Simulation model is very similar to the typical DrillNET Formation page. See Section 3.2.5.

CHAPTER 24: KICK SIMULATION MODEL



1) Kill Procedure. The most common fluid circulation-based well control programs are the Driller’s method and the “Wait and Weight” method. These practices are conducted to maintain a constant BHP during the fluid circulation program.

For the Driller's Method, mud weight is not increased as the kick is circulated out. At the end of this procedure, there is still pressure at both the inlet to the drill pipe and at the choke. The Driller’s method is a fluid circulation practice typically used to displace formation fluid influx from the wellbore annuli. The BHA nozzle is positioned at the designated kill depth. In cases where the circulated fluid density is lower than the required kill-weight density, this pumping program will not result in hydrostatic pressure balance of the well. However, when performed properly, this method ensures that fluid in the wellbore will be of uniform density when the process is complete. After circulation is completed, the surface pressure is combined with the hydrostatic pressure exerted by the pumped-fluid column, providing a check to confirm the required kill-weight fluid density.

For the Wait and Weight Method (also called the Engineer’s method), the well is shut in and the mud weight necessary to kill the well is determined. Mud weight in the pit is raised to this kill value, and then the kick is circulated out. At the conclusion of this process, both drill pipe and choke pressure are atmospheric when circulation is stopped. As with the Driller’s method, the Wait and Weight method is conducted with the BHA at the designated kill depth. After this circulation stage, static surface pressure in both the drill string and wellbore annulus should be zero.




Comparison of Kill Methods (IADC, 1992)

Method Advantages Disadvantages

Driller’s Method

Circulation can be started almost immediately

Simpler

Fewer calculations required

KWM can be mixed to uniform density while first circulation is being completed

Does not require special modifications in directional wells with tapered strings

Minimum of two circulations (more time)

Higher annulus pressures

More wear on choke and gas-handling equipment

Wait and Weight

Minimum of one circulation (less time)

Lower annulus pressures

Less wear on choke and gas-handling equipment

Circulation must wait to start until KWM has been mixed

More complex

More calculations required

Requires special modifications in directional wells with tapered strings

2) Well and BOP Type. Three well options for BOP design are provided:

Onshore Well – This option will handle all types of wells (vertical, directional, horizontal, extended-reach, etc.) on land-based rigs.

Offshore Well with Surface BOP – For this offshore option, the program models the well similarly to an onshore well except with a riser present.

Offshore Well with Subsea BOP – Here the MD of the subsea BOP is equal to the MD of the riser. You can select choke lines and/or kill lines by checking and specifying their sizes.

3) Shut-In Data. These data are used to calculate the volume of gas that has been kicked by the formation. SIDPP = shut-in drill pipe pressure; SICP = shut-in casing pressure.

4) Pump Data. Enter the pump output factor describing fluid volume produced for each pump stroke. Click [Help] to open a special pump volume estimator (see figure) if pump output is not known.

SCR (Slow Circulation Rate) is the flow rate to be used during the kill operation. Pump pressure @ SCR is also critical for well control design.

5) Simulation Type.

BHP = Formation Pressure + Margin. This option is for well control based on a constant BHP (bottom-hole pressure). Previous users of this module asked MTI to add the option to maintain an underbalance during well control or a slight overbalance as a safety factor. For this option, enter the preferred margin in the box below. Enter a negative value for pressure for maintaining underbalanced conditions during well control.

Use Drill Pipe Pressure in Standard Kill Sheet. Many engineers believe that drill-pipe pressure will equal CDPP (circulating drill-pipe pressure) in a standard kill sheet if BHP = formation pressure. However, because there are frictional pressure losses in the annulus and drill pipe, and because the well may not be vertical, this assumption is not correct. If drill-pipe pressure follows the CDPP in a standard kill-sheet calculation, BHP will change when kill mud is pumped into the well, and BHP will rise above formation pressure. With this approach, conventional well control is always safe.



6) Point of Interest/Casing Shoe. An option is provided for you to specify another MD along the borehole where pressures will be closely monitored throughout the well-control pumping procedure. Pressure/ECD histories are displayed in the output graphs for several specific positions including the bottom of the hole, casing shoe, drill pipe, choke, and this special depth of interest you define.

Depth of the casing shoe is required so that pressures and ECDs can be calculated for that depth for the well-control procedure. Note that pressures are always checked at the bottom of the hole.

7) Surface Volume Data. Enter fluid volumes as required. Surface fluid volume (which includes volume in active pits and surface lines) is used to calculate the number of sacks of barite required along with other additives.

8) Leak-Off Test. A leak-off test (LOT) helps determine fracture pressure of the open formation, and is usually conducted immediately after drilling below a new casing shoe. During the LOT, the well is shut in and fluid is pumped to gradually increase pressure at the formation face. At some point, fluid will enter the formation through permeable paths in the rock or by fracturing the rock. LOT results define maximum mud weight that may be applied to the well.

Enter data from LOT results as shown. After you enter or change the value of LOT pressure, mud weight or

shoe depth, click to refresh the value for maximum allowable mud weight (MAMW). This information is provided to the user only as a reference basis for comparison with kill mud weight. Normally, kill mud weight should be less than MAMW to avoid fracturing the formation. However, the program allows users to set kill mud weight to any value desired.





1) Rheology Model. Select the mud rheology model that best describes the fluid to be used. Three fluid models are provided. (Additional theoretical discussion is presented in Section 28.12.1.) Rheology models include:


Note: to specify a Newtonian fluid in the Kick Simulation model, select the Bingham-plastic model and set yield point = 0.


2. Bingham Plastic. This is the most common rheological model for drilling muds. These fluids exhibit a linear shear-stress/shear-rate ratio once a threshold shear stress is exceeded. Two parameters, plastic viscosity and yield point, are used to characterize these fluids. Because these constants are determined between specified shear rates of 500 to 1000/sec, this model characterizes fluids in the higher shear-rate range.




At high shear rates, both Bingham plastic and power-law fluid models represent a typical drilling fluid reasonably well. Differences between models are most pronounced at low rates of shear.

The exact rheological parameters that are required vary depending on the rheology model you select. Text labels automatically change to reflect the current model.

2) Current Mud Properties. Enter parameters describing the mud that was present in the well when the kick occurred.

3) Mud Type. Select either water base or oil base for mud type. The Single-Bubble two-phase flow model is not available for oil-base muds. See Section 28.23.6 for more discussion.

4) Two-Phase Flow Models. Four models are incorporated into DrillNET for calculating two-phase flow hydraulics for the mixture of a gas kick and the original mud. These are described in more detail in Section 28.23.7. The choice of multiphase correlation model is a matter of experience and intuition. Various input parameters required for the Beggs-Brill, Hasan-Kabir, and Hagedorn-Brown models are not measurable, and must be estimated by the user. The single-bubble model yields the highest choke pressure, and in most cases represents the worst-case scenario.

An excellent source of help with model selection is the Sensitivity Analysis window (see Section 24.3.4). This

window, accessed by clicking , shows brief results for all four two-phase models. This allows you to gauge how critical the choice of model is for your specific conditions.

5) Kill Mud Properties. Input parameters for the mud to be circulated to kill the well and pump out the kick. Click [Estimate] below Mud Weight to have the program provide an estimate for the required kill mud. This estimate is based on the well survey, wellbore description, drill pipe, current mud weight, and shut-in data.

You may add a small margin to the estimated value of kill-mud weight prior to calculating the well-control results.

6) Gas Influx Data. Describe the formation gas that forms the kick volume. If gas properties are not known, click [Default] to automatically enter typical values for gas and formation parameters. Note that surface tension is required for the multiphase correlations.

ROP (rate of penetration) is used to calculate the rate at which new producing formation is being exposed to the wellbore (and contributing to the kick volume).

24.2 Output Output for the Kick Simulation Model includes results under two tabs:

1. Summary – Displays values for key hydraulics parameters for well control

2. Graphs/Tables – A typical DrillNET multi-featured output display allowing selection of individual or multiple graphs (see Section 3.3 for general discussion)


24.3.1 Calculation Monitor Panel The output window is loaded automatically after the calculations are completed (after you enter required input parameters and click ). As results are being calculated, the Calculation Monitor panel (at right) is displayed. This display provides you a preview of the basic well control process, when gas influx rates are halted, what magnitude of gas flow rates are expected as the kick is circulated out, as well as several other engineering issues. Note that elapsed time is displayed in the second entry to help you correlate relative time scales.




24.3.2 Tool-Bar Icons Two special tool-bar icons are provided when the Kick Simulation Model is selected. These are:

Animation of Well Control. Opens the Animation window (see Section 24.3.3) for viewing a simulation of the multistage pumping operation to control the well. (Only available after output results have been calculated.)

Sensitivity Analysis for Two-Phase Flow Models. Opens the Sensitivity Analysis window (see Section 24.3.4) for comparing the four two-phase flow models. (Only available after output results have been calculated.)

24.3.3 Animation Window The Animation window is a secondary output window used to view a simulation of the pumping operation for circulating a gas kick out of the well.

1) Animation Graph. Positions of fluid fronts for the multistage well-control pumping operation are displayed for the entire process.

2) Animation Manual Step Control. The simulation of the well-control operation can be advanced automatically or manually. Manual control allows you to focus on details for particular points during the procedure. For a standard well-control animation, the process is broken into 1-minute intervals during the kick, and into appropriate time intervals during the kill process.

to advance to the next time step

to return to the previous time step

to skip to the end of the operation

to return to the beginning



The value in the Time Step box above can be adjusted to adjust the speed of the process. For example, if you enter 0.5 in the time step box, each click of will move the operation ahead 0.5 hr.

Select [Start] to begin the animation sequence from the point where the kick is entering the wellbore. During the simulation, the [Pause] and [Stop] buttons become available for halting the simulation at any points of interest. If you click [Pause], the animation can be continued from that point by clicking [Resume].

3) Animation Fluid Pattern. The color legend defines the color of each fluid as it moves through the well during the animation. Fluid colors cannot be changed by the user.

4) Animation Monitor Panel. The monitor panel within the Animation window displays values for each critical parameter during the simulation. Values for each time step are updated along with the graph. Click [Pause] or use the manual step control to freeze the displayed data for more careful analysis at any time of interest during the well-control process.

24.3.4 Sensitivity Analysis Window The Sensitivity Analysis window is a secondary output window used to compare the four two-phase flow models. The flow model used in the main calculation sequence is selected on the Operation page. Results shown on this page simultaneously compare all four models (three models for oil-base muds). This display is very useful for

gauging how critical the choice of model is for your specific conditions. This window is accessed by clicking after the output window has been calculated and loaded.

Select which parameter is displayed on the Y-axis. After a different parameter is selected, the Sensitivity Graph will be redrawn automatically.

Select “Four Models” to display results for the complete set of four two-phase flow models (see Section 28.23.8). If you select “Three Models,” the single-bubble model will be removed. The single-bubble model yields the highest choke pressure, and in most cases represents the worst-case scenario.


225525. USER DATABASES

25.1 Galaxy Database The Galaxy Well Database makes it easy to handle large volumes of drilling and completion data. The database (previously released for use with other Maurer software) is based on the Microsoft Access platform, and is designed to store both well-based data and project-based data. Galaxy’s data model is extendable, which makes it easy to access data from other external databases with the use of our Data Transfer Module.

25.1.1 Benefits Use of the Galaxy Well Database is optional. However, it can be a very practical tool for quickly importing data received from the field in digital form. Benefits of the Galaxy Database include:

1. You can store all your data in one dataset with a pre-defined data structure. This makes it much easier to maintain and edit than individual DrillNET project files (*.XML).

2. In the Galaxy Database pane, all data are organized and displayed in an Explorer tree view. (Standard DrillNET project files are accessed from a standard File Open window without any indication of relationships between them.)

3. Wells in the database can have multiple projects (surveys) associated with each well. This makes it very convenient to perform and compare engineering analysis for a variety of trajectories under one well record.

25.1.2 Local or Central Galaxy Database The Galaxy database can be configured to be either a Local or Central database. By default the database will be local. The option to specify the setup of the database can be found beneath Options Galaxy Database

A Central Database can be configured to use only SQL Server. The following details explain how to configure a SQL Server 2005 system.

1. Login as administrator on the server where SQL server is installed

2. Open Start All Programs Microsoft SQL Server 2005 SQL Server Management Studio

3. In the Object explorer on the left hand side, expand the server Databases

CHAPTER 25: USER DATABASES


4. Right click on Databases and select New Database, a window pops up, type the name of the database, in this example DrillNet. Choose the proper path to create the data and log files, in this example all the SQL server data files are created under E:\MSSQL\Data folder.

5. Click OK to create the database.

6. Highlight the newly created database in the object explorer and click on “New Query” button right above the Object Explorer




7. Once clicked, a new window appears on the right hand side. Now click on File Open File and browse to the location where you have copied the Create_Galaxy3_SQLServer.sql file and open it. Click on Execute button (red exclamation) to execute the script. If no errors, Command(s) completed successfully message appears in the bottom frame.

8. Check to see if the objects have been created by clicking on the tables



9. DrillNet application recommends Windows authentication, so as a system administrator on the SQL database server, right click on DrillNet Security users and pick New User. Below is an example adding Jay fu as a user. Give the username as fu, login name as PETRIS\fu for windows authentication and the database role membership as db_owner. Click OK to create the user in this database.




10. This concludes creating the central SQL server database for Drillnet. Next step is to configure the connection in DrillNet application. Open Drillnet application and navigate to Options Galaxy Database Configuration

11. A new window called Galaxy Database Configuration opens up, fill in the information for server name, pick user windows integrated security radio button and enter the database name. In our example we created the database as drillnet. Below is the screen shot with the proper entries.

12. Click on Test Connection button to test the connection information. If successful, a window with Galaxy is connected successful” appears, if not an error message is displayed.



25.1.3 Managing Galaxy Current wells in the database are viewed by browsing the Galaxy Database pane (above the Engineering Models pane). If this pane (see figure) is not visible, select Galaxy Database from the View menu. The Explorer tree can be expanded and compressed by clicking on the well names.

Opening Wells

To open a Galaxy well, click on its name in the Galaxy Database pane. This opens the well’s Well Information window (see below). Within this window, you can enter descriptive information describing the well location and rig. Five tabbed pages are presented. The second through fifth pages show the trajectories for this well graphically in 3D, plan and section views (all trajectories shown together); and in a table (select each trajectory in turn from the drop-down list).

To edit a well project, click a project listed below the well in the explorer tree in the Galaxy Database pane. This opens the Galaxy Project Information page (below) for that project. This window allows you to enter the survey, tubulars, wellbore, and formation data that pertain to this project. The design of these input window is the same as the engineering models. See Section 3.2 for a description of these windows.

Survey, wellbore and formation data can be imported directly from Galaxy into the Engineering Model input pages. Within the data tables on the Survey, Wellbore or Formation pages, right-click over the data table to open the Edit menu. Select the Galaxy import option to populate that table with data.




Saving to Galaxy

It is important to remember that Galaxy Database information (saved in an Access database) is distinct from DrillNET project data (saved in a separate *.XML file). To help avoid confusion, the file management icons on

the toolbar ( and ) only work for DrillNET projects. Consequently, these are not active when the Galaxy database is open. To save information entered into Galaxy, select “Galaxy Database” “Save…” from the File menu. You can then select an existing well project name (to overwrite), or enter a new well project name (to create a new record).

Creating New Wells

To create new wells, select “Galaxy Database” “Save…” from the File menu. In the pop-up window, enter a new name in the Well Name box and a new project name in the Project Name box. Select [Save] to close the window. The new well is then displayed in the Galaxy Database pane.

Adding Projects to Existing Wells

To add new projects to existing wells, select “Galaxy Database” “Save…” from the File menu. In the pop-up window, select the well name of interest and enter a new project name in the Project Name box. Select [Save] to close the window.



Deleting Wells

To delete a well or project that is in the database, open the Galaxy Database Manager window (see figure). Click on the well name and click [Delete] to remove the well and all associated projects. Click on a project name to delete a single project while leaving the well intact.

25.1.4 Importing Data from Earlier Versions of Galaxy Data stored previously in earlier versions of GALAXY database can easily be transferred into DrillNET’s Well Database by running a simple utility (MTIDBTran.exe). This file was installed into the same folder as the Well Database (default location = C:\Program Files\Petris).

25.2 Tubular Database An extensive on-line database of casing and tubing dimensions and properties is provided. ODs, IDs, and metallurgical properties for a wide variety of tubulars can be directly imported into DrillNET’s data tables. The lookup database is also customizable so that users can add their own drill pipe and casing.

Accessing Tubular Data

To access the online database, right-click over the data tables on the Tubulars or Wellbore pages. Select “Import from Tubular Database…” from the pop-up menu. Before accessing the database, position the cursor anywhere on the row into which the data are to be imported (that is, click on a cell in the row). Within the Tubular Database window (below), select the Pipe Class and OD from the drop-down boxes. Then review the available entries and click on your selection. Click [Apply] to export data from the selected row to the DrillNET input table you were previously editing. Only corresponding rows in the input tables will be overwritten. Any information entered in other columns (descriptions, lengths, comments, etc.) will not be changed after importing data from the database.

If you want to view or print the complete table, click [Copy Table] and paste the data into Excel.

Editing the Tubular Database

Use the Tubular Database Editor to add, remove or change individual entries in the lookup table. The Editor is accessed by clicking [Database Editor] in the lower left corner.




Any cell displayed in white can be edited. Right-click over the table to copy or paste entries, and to add or remove entire rows from the table. You can copy data from another source (e.g., Excel spreadsheet) and paste to a range of cells. Position the cursor in the left most cell and select “Paste” from the pop-up menu.

You can also add new classes of tubulars to the database. Right-click on the list of pipe classes or select “Add Table” from the Edit menu and a new table will be added to the list. You can also remove entire classes of tubulars including default tables supplied with the program. For example, to remove the coiled tubing table, select it by clicking “Coiled Tubing” in the list. Then select “Delete Table” from the Edit menu. Note that these deletions are permanent. You may wish to maintain a backup copy of the original database in another folder.

Database Menu

The Database menu in the Tubular Database Editor provides functions for opening other versions of the tubular database and saving changes. Menu options are:

1. “Open” lets you browse for other versions of the tubular database. Note that you can only open and edit database files named “Looktbl.mdb.” This option can be used to edit other special versions of the database that are in progress or intended for special applications only. See more discussion below under “Managing Additional Custom Databases.”

2. “Save” permanently saves any changes you made to the database since you opened the Tubular Database Editor. Note that changes cannot be undone after they are saved.

3. “Close” closes the current database and clears the data from the editor.

4. “Exit” closes the Tubular Database Editor and returns to DrillNET. You will be asked whether or not to save changes (if any changes were made to the database and not yet saved).

Edit Menu

The Edit menu in the Tubular Database Editor provides several functions for editing individual entries in one of the tubular tables, as well as adding or deleting entire tables from the database. Menu options are:







5. “Insert Row” inserts a new blank row directly above the row the cursor is positioned in.

6. “Delete Row” deletes all rows of the current data table that have any cells selected. It does not matter whether only one cell, multiple cells, or the entire row is selected.

7. “Add Table” adds a new table to the list on the left. You can then add data to the table and save. This option is available only when you click on the list.

8. “Delete Table” deletes the currently selected tubular table from the list. This option is available only when you click on the list.

Managing Additional Custom Databases

In some cases users will prefer to maintain more than one copy of the DrillNET tubular database. For example, you might want to build a one or more abbreviated databases specific to particular projects, or need to start modifying the database for use only at a future date, or for other reasons.

The most straightforward approach to working on a customized in-progress database is to place a copy of the default database (“C:\Program Files\Petris\Looktbl.mdb”) into another folder (but keep the same filename). You can then open the Tubular Database Editor and edit your custom version by selecting “Open” from the Database menu. Make all changes as desired and save after one or more editing sessions. When DrillNET is run, it will continue to access the original version of the database stored in the Petris folder (see note below).

Finally, when you are ready to access your custom database from DrillNET, copy it back into the Petris folder (with name “Looktbl.mdb”).

NOTE The feature “Import from Lookup Table” in DrillNET (on the pop-up menu when editing tubular and wellbore data tables) always accesses the file:

“C:\Program Files\Petris\Looktbl.mdb”

This name cannot be changed by the user. The path was specified when you installed DrillNET. To access data from another customized lookup table, you must replace the default file with your new version in the same root folder and give it the same name. If you do not wish to delete the original database file during this process, rename it (for example, “Looktbl default.mdb”) before you transfer your custom database file.

WARNING Do not edit DrillNET database files with any program (including MS Access) other than DrillNET’s Tubular Database Editor. Doing so may change the database structure and make the database unusable by DrillNET.

25.3 My Fluids Three special databases are provided to simplify the process of data entry. These store custom data describing drilling fluids (this section), standard bottom-hole assemblies (“My BHAs,” Section 25.4) and fatigue life data (“My S-N Curves,” Section 25.5). Users can enter and store their favorite data sets for immediate access for all DrillNET projects.

The My Fluids database is opened from any hydraulics model for quickly entering rheology data. Right-click over the row of interest and select “My Fluids…” from the pop-up menu to open the My Fluids window (below). Another option is to click the icon . To enter appropriate rheology data, select a fluid from the list, review the data, and click [Apply] to import these data into the current row in the hydraulics table.




Editing My Fluids Database

To change data or add/delete fluids from My Fluids, click [Database Editor] on the lower left corner of the My Fluids window. This opens the database editor (below).

Enter as much data as are available. To characterize rheology, you can enter (1) Fann data or (2) rheological constants or (3) both. Any parameters can be left blank if not known or not needed. If you import a fluid from the database into DrillNET and a critical parameter is missing, you will of course need to enter it manually into DrillNET at that time.



25.4 My BHAs Three special databases are provided to simplify the process of data entry. These store custom data describing drilling fluids (“My Fluids,” Section 25.3), standard bottom-hole assemblies (this section) and fatigue life data (“My S-N Curves,” Section 25.5). Users can enter and store their favorite data sets for immediate access for all DrillNET projects.

The My BHAs database is opened from any model for quickly entering drill-string data. Right-click over the row of interest in the tubular or wellbore table and select “My BHAs…” from the pop-up menu to open the My BHAs window (below). To import tubular data from My BHAs, select an item from the list, review the data, and click [Apply Equivalent Tubulars] to import the data displayed in the upper table. The concept of “Equivalent Tubulars” saves space and reduces confusion by reducing many smaller components in a BHA to only a few equivalent components, each with an average set of properties.

Editing My BHAs Database

To change data or add/delete BHAs from the database, click [Database Editor] on the lower left corner of the My BHAs window. This opens the database editor (below).




My BHAs is used to store and recall dimensional data for tubulars tables. Though it is called My BHAs, this database can be used to store a collection of sections for any drill-string data.

Entering Simple BHAs

If the BHA design data is simple enough to use in its original version (that is, without converting it to equivalent tubular sections), then enter the BHA data directly into the upper table (“Equivalent Tubulars”).

Converting Complex BHAs to Equivalent Tubulars

Real BHA designs often contain many BHA components and can become cumbersome to enter row by row into DrillNET (especially more than once). And in most situations, specific size details of most BHA components do not have a discernable effect on hydraulics/mechanics calculations.

One of the special functions of My BHAs is to allow users to not only store their data, but then to convert their detailed BHAs into one or more “equivalent” BHA sections. This allows the BHA to be summarized by a few simple sections that are saved to the database. This conversion to equivalent sections is performed in the editor window.

To convert a complex BHA dataset to a simpler listing consisting of only a few equivalent sections:

1. Enter the complete summary BHA data in the lower table, leaving the table above empty for the moment.

2. Review the BHA sections to decide how best to divide the BHA components into several groups (each group will represent several consecutive data rows).

3. For each group, select (highlight) all the included data rows and click [Add Selected Rows as New Section].

4. The program will convert these components into one pipe section of simple geometry (with the cumulative length and all other properties weight-averaged) and populate the data to the upper table.

After this process is complete for all the groups, the original BHA data will have been converted to a dataset with much simpler geometry that is ready to be exported to the Tubulars table.



25.5 My S-N Curves Three special databases are provided to simplify the process of data entry. These store custom data describing drilling fluids (“My Fluids,” Section 25.3), standard bottom-hole assemblies (“My BHAs,” Section 25.4) and fatigue life data (this section). Users can enter and store their favorite data sets for immediate access for all DrillNET projects.

My S-N Curves is an online database of fatigue data for drill pipe. This information is required in the Drill String Life model (see Section 15). In engineering applications characterized by high-cycle metal fatigue, materials performance is commonly characterized by an “S-N curve,” also known as a Wöhler curve. This is a graph of the magnitude of a cyclical stress (S) to which the pipe is subjected against the corresponding number of cycles to failure (N).

In DrillNET, S-N data are selected from a drop-down list in the Tubulars input table (column 9; see figure). To review the S-N data, open My S-N Curves database (below). This is accessed by right-clicking over the Tubulars table and selecting “My S-N Curves…” from the Edit menu.

Editing the S-N Curve Database

The S-N Curve database is provided with seven default S-N data sets for drill pipe including steel, titanium, aluminum and beryllium copper. These data sets are protected (locked) and cannot be changed by the user. However, you can add any number of new data sets. These will also appear in the drop-down list for selection in the Tubulars table.

To add S-N Curve data, click [Database Editor] in the lower left corner of the My S-N Curves window. This opens the S-N Database Editor window (below). Next, click [New] in the lower left corner to enter the first new data set. The background color for the data cells is changed to white. You can now enter data as desired. It is important that you name the data set. The name you enter will appear in the drop-down list for selecting this material on the Tubulars page.




To save new or modified S-N data, click on another data set in the upper left corner. You will then be asked whether to save the changes. After the data are saved, reselect your new data set to see the new (updated) graph display. After you have confirmed that the data set is correct and complete, close the database window by clicking [Close] in the lower right corner.

25.6 My Survey Tools Another special user database, My Survey Tools, stores data describing survey tool measurement error. This is required when conducting a wellbore Anti-Collision Analysis (see Section 8). Users can enter and store any number of data sets for various survey tools.

In DrillNET, Survey Tool Error datasets are selected from a drop-down list on the Trajectories page (see Section 8.1.2) on the input table (column 10; see figure). To review the survey error data, open My Survey Tools database (see below). This is accessed by selecting “My Survey Tools…” from the Tools menu, or clicking the icon.



1) Survey Tool Name. A database of survey tools is available for specifying measurement uncertainty for a range of tools. Click on a tool name in the list under Existing Tools on the left of the window. The “Description” text box displays text and comments to help identify that specific tool.

Select “Default tool” if you want the current tool to entered as the survey tool for new trajectories and projects. You can later select another tool; the default tool is only the starting point.

2) Survey Tool Accuracy Parameters. Three error models are provided for defining survey measurement uncertainty. Data can be entered for any or all of these error models. Their basis is described below.

1. Error Cone. This model assumes a uniform error sphere exists around each survey measurement. The model is empirically based on field data or testing comparisons of bottom-hole positions calculated from various instruments. Sphere size at each depth is calculated as follows:

1000

errortoolsurveyMDnobservatiopreviousatradiusSphere

Starting error around the wellbore is the well error plus the well radius. The survey tool error coefficient is considered to be constant and applied across the entire interval.

2. Systematic Error. This model, based on work by Wolff and de Wardt (19818), is a statistical treatment of the distribution of errors caused by internal and external influences. Major causes of error were demonstrated to be systematic (i.e., errors occur consistently in one vector direction) from one survey reading to the next. Random error sources are ignored; these are assumed to be small and tend to cancel out over a large number of survey measurements. Mathematical methods applied by Wolff and de Wardt have become standard within the industry, but some of the example coefficient values and weightings are not appropriate for modern directional survey instruments (e.g., MWD and rate gyroscopes).

Six coefficients are used in the Systematic Error model, including:

Relative Depth Error: There is an error in measurement of depth along the hole. Depth error is accumulated from pipe tally measurements, stretch for pipe tool runs, and by wireline measurement errors for cable tool runs.

Misalignment Error: This error is associated with tool centralization in the borehole/casing. Misalignment affects both inclination and azimuth, and is derived from sensor axis and tool centralizer misalignment.




True Inclination Error: There are errors in inclination measurements. These can be caused by weight-induced effects on pipe running gear, and are sensitive to inclination.

Compass Reference Error: There is error in the azimuth reference. This will be comprised of declination for magnetic tools or foresight for gyroscopes.

Drill-String Magnetization Error: Magnetization of the drill string can cause errors in magnetic azimuth. This error increases at higher inclinations and east/west azimuth.

Gyrocompass Error: Errors in gyroscope azimuth readings caused by gimbal drift increases exponentially at higher inclinations.

3. Inclination/Error Grid. Some engineers believe that systematic error coefficients and weighting factors are not adequate for modern solid-state magnetic instruments and for rate gyroscopes. Instead, they prefer an empirical approach. The Inclination/Error table can be used to define error models for more complex downhole instruments. Inclination error characteristics for each inclination angle range can be obtained from the manufacturers and entered into the tables.

Editing the Survey Tool Database

My Survey Tools database is provided with 11 default data sets comprising a variety of survey tools. You can change existing error data and add/delete datasets as desired. Any new datasets will then appear in the drop-down list for selection on the Trajectories page.

To change or add survey tool data, click [Database Editor] in the lower left corner of the My Survey Tools window (above). This opens the My Survey Tool Database Editor window (below). Click [New] in the lower left corner to enter the first new data set. It is important that you name the data set. The tool name should be as short as possible since it will be displayed in column headings in the anti-collision windows.

Click [Remove] to delete the current tool from the database.

To save new or modified Survey Tool data, click on another dataset in the upper left corner. You will then be prompted whether to save the changes. After you have confirmed that the data are correct and complete, close the database editor window by clicking [Close] in the lower right corner.

8 Wolff, C.J.M, and J.P. de Wardt, 1981: “Borehole Position Uncertainty – Analysis of Measuring Methods and Derivation of Systematic Error Model,” SPE 9223, JPT, December.


226626. UTILITIES AND PROGRAM SETTINGS

26.1 DrillNET’s Free Utilities DrillNET includes several useful calculation utilities for drilling engineers. These free utilities are always available regardless of the status of your program licenses. These utilities are similar to several of the most popular tools from Petris’ widely used Driller’s Toolkit™ software package. The current version of DrillNET includes 10 free utilities (see figure).

During the over 25 years MTI helped the Oil & Gas Drilling Community solve engineering problems, they collected a large variety of drilling engineering tools that are commonly used in the industry. Many of these were packaged into our easy-to-use platform Driller’s Toolkit™. This simple, easy-to-use resource increases our customers’ efficiency at the rig and in the office, and is available as a separate program for desktop and Pocket PC.

26.1.1 Running a Utility To access DrillNET’s free utilities, scroll to the top of the Engineering Models explorer list. This pane is similar to Windows Explorer. Common models are grouped in categories with a or next to each heading. Click to open that category and display all options available. Click to close a category.

Click on “UTILITIES” to open the list of utility subgroups. Then open the subgroup heading of interest to display the names of the separate utilities. Click on the name of the utility to open it.

The design of the free utilities is intuitive and easy to understand. Within the utility window, enter data into the text boxes with a white background. After all data are entered, results are calculated and displayed, most often in text boxes or tables with a yellow background.

26.1.2 Example Free Utility – Pipe Buckling

An example utility (TUBULAR MECHANICS Pipe Buckling) is shown below. This calculates sinusoidal and helical buckling limits for a pipe in a straight section of hole. (Discussion of buckling limits is presented in Section 28.9.3.) After you enter all input data (use the tab key to jump from box to box), click [Calculate] to display the critical buckling loads on the right side of the window.

CHAPTER 26: UTILITIES AND PROGRAM SETTINGS


The [Example] button will enter default data into the boxes for a quick introduction to that utility’s function.

26.1.3 Example Free Utility – Build Rate and Turn Rate The utility WELL PLANNING “Build Rate & Turn Rate” is shown below. This tool is used to investigate general relationships and interdependence between build rate, turn rate and tool-face orientation (TFO). This utility allows you to estimate the maximum turn rate that can be achieved with a given TFO or inclination angle.

26.2 2D Well Planner Utility The 2D Well Planner is a free utility that can be used to create simple surveys for customers who do not have a license for the Well Planning/Projection model (Section 7). The 2D Well Planner can rapidly create a two-dimensional (constant azimuth) survey for use in planning and analysis. This utility is only available from the Survey page (listed as the second tab for most models) and is accessed by clicking the icon.

Free Utility – Pipe Buckling Limit Calculation

Free Utility – Build Rate and Turn Rate Calculation




1) 2D Plan Options. Three basic directional wellpath types are provided: (1) build and hold (a simple inclined or horizontal well), (2) build and drop (an S-shaped trajectory), and (3) build and build (an extended-reach well with a tangent section). Geometric parameters required for the well plan vary depending on the option selected. The wellpath shown in the graphic defines the geometric parameters of the current model.

2) 2D Plan Start and Target. Specify the start point and target point of the wellpath. Two format options are provided: (1) TVD (true vertical depth) along with North/South and East/West distances, or (2) TVD along with horizontal displacement and azimuth direction (polar coordinates).

3) 2D Plan Parameters. After you specify the target position, several basic geometric parameters must be entered. Obviously, an infinite number of wellpaths could be used to connect the surface and target locations. To develop a practical solution, you must specify most of the geometric parameters.

For a Build and Hold trajectory, you must specify three of the following: (1) inclination 1 (from surface to KOP), (2) length 1, (3) build rate 1, (4) inclination 2 (from the end of the curve to TMD) and/or (5) length 2.

For Build and Drop and Build and Build trajectories, specify six of the following: (1) inclination 1 (from surface to the first KOP), (2) length 1, (3) build rate 1, (4) inclination 2 (the tangent section), (5) length 2, (6) build rate 2 (the second curve section), (7) inclination 3 (from the end of the curve to TMD), and/or (8) length 3.

4) 2D Plan Calculated Survey Table. After all required geometric parameters are entered, click [Calculate]. The calculated survey will be displayed in this survey table. The 2D Plan survey table includes only essential points defining the wellpath, that is, where the inclination and/or build rate change. Additional survey stations can be added to the survey as it is exported to the Survey page.

5) 2D Plan Output Options. After the survey is calculated, it is ready to be exported back into the Survey page for use in the analysis. It is useful to “fill in” the survey so that survey stations are regularly spaced along the entire

2 3

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1



survey. Specify the interval between survey stations for straight sections and curve sections. Additional stations will be added after you click [Accept].

The default interval between inserted stations is 100 ft.

6) 2D Plan Control Buttons. Click [Calculate] after all input geometric parameters are entered. If possible, the values of the two unknown parameters will be calculated and the new survey displayed. When you are satisfied with the results, click [Accept] to complete the survey with incremental survey stations and to export the results to the Survey page. [Example] fills in a set of default input data for learning how the utility operates. [Cancel] closes the 2D Planner utility without exporting any data.

“Cannot build 2D shape” Error

It is not uncommon that the set of parameter constants that you enter (including well section lengths, build rates, and inclinations) does not lead to a solution. After [Calculate] is pressed, the program may respond with an error message. It is usually obvious after closer consideration why the well cannot be assembled as specified (for example, the length you assigned for an inclined/horizontal section does not provide enough space (displacement) for a turning section). When these errors occur, carefully visualize the well shape and consider why a solution is mathematically not possible. Then change one or more parameters accordingly and recalculate.

Note: Within the Well Planning/Projection model, another helpful utility (Well Plan Design Wizard (see Section 7.2.2)) is provided to help you determine why your well plan is not converging.

26.3 Tortuosity Utility The Tortuosity utility is provided to provide a simple method to adjust a newly created survey (which is completely smooth) so that it better represents surveys in the real world. This utility is only available from the Survey page and is accessed by clicking the icon.

26.3.1 Background When wells are being planned, engineering analyses of operational parameters such as casing wear, torque and drag, etc. can be highly useful for highlighting potential trouble and the best means to minimize it. One disadvantage of analyses at the planning stage is that the surveys are hypothetical and are generated mathematically from geometric considerations (kick-off point, build rate, well-path shape, etc.). As such, they are ideal, smooth curves. Real wells, on the other hand, contain doglegs and other irregularities that increase torque and drag and casing wear. When ideal smooth surveys are input into the Engineering Models, predicted values are lower (sometimes significantly) than those that would be expected in typical field wells.

A simple technique originally developed by Exxon is incorporated in the program to modify survey data so that conditions are more representative of real wells. Tortuosity can be added to the wellpath; that is, a small-amplitude periodic variation (undulation) with a given period (or cycle length) is added to both inclination and azimuth angles.

Amplitude of the tortuosity (maximum value in degrees of the sine-wave variation) is chosen according to local conditions. Dr. Russell Hall9 of MTI (who originally developed the casing-wear algorithm) recommends an amplitude of 0.7º as a typical starting point. After the tortuosity amplitude is set, the original survey data are then modified (“tortured”) by adding the corresponding sinusoidally varying dogleg to each survey point. These modified data can then be exported to the Survey page and used to predict torque and drag and casing wear in a manner more representative of field wells.




1) Tortuosity Survey Data Table. The values initially appearing in this table are copied from the Survey page. After tortuosity is added to inclination and azimuth, the adjusted values will appear in this table for review. Data cannot be edited within the table. To make changes to any survey station, return to the Survey page (click [Apply] or [Cancel]).

Right-click over the table to access options for copying, previewing, printing, and displaying the table in a separate window.

2) Tortuosity Graph. The impact of adding tortuosity to the survey is immediately displayed in the tortuosity graph. Both the original (untortured) and the tortured surveys are shown.

Editing Graphs

The Edit menu can be accessed easily by right-clicking over the graph. Options on this pop-up menu (see figure) are described in Section 3.4.

3) Tortuosity Zone Parameters. The survey can be divided into as many as five zones (for example: (1) surface to KOP, (2) first build section, (3) first tangent section, (4) second build section, (5) second tangent section...). Each zone can be assigned a different amplitude and/or period for its distributed tortuosity. The bottom MD in the last zone should always be the maximum survey depth.

When the wellbore survey is a combination of measured and planned data, you should add tortuosity only to the planned section(s). To do this, enter an amplitude of 0 for the zones with measured survey data; these zones will then remain unmodified as tortuosity is added.

1 2

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Select Sinusoidal or Random for the general method to modify the survey. Sinusoidal tortuosity adds a regular, sinusoidally-varying dogleg to inclination and azimuth. Random tortuosity adds a “random” dogleg (that is, based on a more complicated waveform) to inclination and azimuth.

Tortuosity Amplitude

Amplitude is the maximum dogleg added to the survey data. Exxon reported that they used a tortuosity amplitude of 1°. Dr. Russell Hall of MTI has found 0.7° to be typical. Some experience with rotary-steerable systems has been reported recently. Schlumberger (Luo et al., 200310) reported that they found that amplitudes of 0.35° in casing and 0.5° in open hole produced a good match to results obtained in wells drilled with rotary-steerable systems.

Tortuosity Period

The Period is the length of one sine-wave cycle to be superimposed onto the survey. This value is generally greater than the distance between survey data points. Note that, in selecting the tortuosity period, a potential problem needs to be avoided. If the untortured survey data are equally spaced and the tortuosity period is assigned a value such that the measured depth of each survey station is n·/2 (where n is any integer), then after calculation the survey data will remain untortured (the value of the tortuosity sine function will be zero exactly at every station, thereby not affecting the data).

This means that the tortuosity period should not be assigned a value that is 2/n (2, 1, ⅔, ½, etc.) times the distance between survey stations. It is recommended that be at least five times greater than the interval between survey stations.

Insert Survey Stations is used if the survey depths are too widely spaced for a reasonable tortuosity period. Click “Insert Stations” to add stations to the existing survey. The default interval between inserted stations is 100 ft.

4) Tortuosity Control Buttons. There are several command buttons at the bottom of the Tortuosity Window. [Calculate] tortures the original survey data, and both the survey data table and tortuosity graph display the tortured survey. [Restore] resets the data to the original survey. [Print Preview] opens the preview window with both the survey table and graph displayed. [Apply] exports the tortured survey data to the Survey page. [Cancel] closes the Tortuosity window without any changes to the survey data.




26.4 Well Schematic Window

A special view window, the Well Schematic, is provided for reviewing the drill string and casing/open hole as currently entered on the Tubulars and Wellbore pages. The graph displays relative diameter with depth of the wellbore and drill string to help you check for errors. This window is opened by clicking any time after the input data are entered. Alternatively, select “Well Schematic” from the View menu.

Within the Well Schematic window, several viewing options (wellbore only, drill string only, etc.) are provided in the drop-down list at the top (see figure).

Editing the Schematic

The Edit menu can be accessed easily by right-clicking over the schematic graph. You can save, print, copy and add text boxes to the graph. Options on this pop-up menu are described in Section 3.4.



26.5 Units Selection Window

1) Units Window Menus. The File menu is used to open and save custom systems of units.

1. “Open” browses your computer for existing custom units files. Custom systems of units are stored as *.UNI files and normally placed in the C:\Program Files\Petris root folder for ready access by all Petris programs.

2. “Save” stores the current custom system of units with changes. If any changes are made to the default English or SI systems of units by selecting another option from one or more pull-down boxes or changing the decimal display format, the new custom system will need to be saved for future use.

3. “Save As…” is used when a new combination of units is designed, and you wish to save it separately, rather than overwriting the previous custom system.

4. “Undo Changes” restores all unit settings to those when the window was first opened.

5. “Apply & Return” closes the units window and applies these units settings to all DrillNET windows and printouts.

6. “Cancel” closes the units window without saving or applying any changes to units settings.

2) Numeric Display Options. Select “Display thousands separator” below the table to display large numbers with separators to group the digits (1,000,000 instead of 1000000, etc.). The symbol used reflects your current global settings. To edit your

global numeric format options, go to Settings Control Panel Regional and Language Settings Regional Options [Customize].

Select “Display soft decimal digits” below the table to hide trailing zeroes in all numeric displays. When soft digits are selected, decimal portions of numbers will

31

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Hard Decimal Digits

Soft Decimal Digits




be displayed only if they are not zero. The maximum number of decimal digits displayed is set in the “Format” column of the Units table.

3) Units Quantity Table. Physical parameters and currently assigned units for each quantity are displayed in the units table. You cannot edit this section of the table directly (as indicated by the yellow background). Allowable options for each quantity are accessed by pulling down the drop-down box attached to each quantity in the second column (“Units”).

4) Units Display Format Table. You can adjust the number of decimal digits displayed for each parameter. The number of zeroes typed after the decimal point for each quantity will be used as standard for the input entries and for printouts. To change a display format, add or remove zeroes after the decimal place as desired.

You can enable soft decimal digits by selecting that option below the table. A soft digit is displayed only if required (if not equal to zero).

5) System of Units Selection Buttons. These buttons select entire systems of units, which then appear in the table, and in DrillNET screens, graphs and printouts.

When selected, the name of the custom system of units is displayed above the units table (“MyCustom.uni” in the figure above).

26.6 Model Options Window The Model Options window is accessed under the Options menu. This window is not shown for every Engineering Model. When available, this option opens a window for selecting parameters and features for output windows for the current Engineering Model.

An example Model Options window is shown for the Hydraulics for Normal Circulation model. You can select or unselect various parameters to customize the output graphs and tables as desired.

Model Options Window



26.7 General Options Window

26.7.1 View Page

Select the uppermost option to avoid viewing the “splash” screen that is briefly displayed every time the program is opened.

The “Display” section of the page can be used to select (display) or unselect (hide) sections of the DrillNET window (called “panes”). This performs the same function as View menu “Panes.” You can hide any pane not being used by unselecting it; this will increase available screen space. Panes can also be closed by clicking on the right end of any pane’s title bar.

Pane sizes can be adjusted by grabbing and moving their borders. See Section 3.1 for more information.

26.7.2 Input Page

The “Tubulars” section of the page is used to select your preferred order for entering data in the Tubular Data table. The default order of entry is bottom-up, that is, with the bit component in row 1. In this way, the complementary




length of drill pipe to exactly fill the hole is listed in the last row. If preferred, you can select option 2 for top-down entry, with the bit component listed in the last row of the table.

Wellbore data describing the casing, liner, open hole geometry are always entered top-down according to standard industry practice.

The “Formation” section of the page sets options for data entry on the Formation input page, which is displayed for most hydraulics-based models. If pore and fracture pressure data are not available or not of interest, you can unselect this option and the Formation page will not be displayed.

26.7.3 Graphs Page

Specify how data are delimited

Tubular Data Option 1 –Enter Data Bottom-Up

Tubular Data Option 2 –Enter Data Top-Down

Wellbore Data are Entered Top-Down



The Graphs page allows you to customize the format of standard output graphs displayed in DrillNET. You can change

Text fonts, sizes and styles (“Fonts” tab)

Legend placement, grid lines, and plot fill color (“Background” tab)

Whether symbols are displayed on the trend lines (“Style” tab)

26.7.4 Printouts/Reports Page

The Printouts/Reports page sets global options for all printed reports. Under “Company Logo” you can select a graphic image to be added to printouts. Windows metafiles (*.wmf) work well for logos that include white space since they allow different background colors to show through (i.e., they are transparent).

Under “Survey Data,” select whether you want printouts to include a listing of the survey data (which is often several pages in length).

26.8 MS Office Report Maker The MS Office Report Maker is a convenient utility for quickly building a Word document, Excel spreadsheet and/or PowerPoint presentation with results from DrillNET. This option provides you a ready source of material for professional-style reports that you can modify or copy/paste into other documents as needed.

Open the report maker after you have calculated results with any Engineering Model by selecting “Create MS Office Reports…” from the File menu. The dialog box shown below will be displayed.

Select one or more output formats: a Word document (which includes input/output tables and output graphs), an Excel spreadsheet (which includes input/output tables), and/or a PowerPoint presentation (which includes output graphs).




Note that Office Reports are not saved automatically. When you create a report, the new document will be left open on your desktop. Go to the Word document, Excel spreadsheet or PowerPoint presentation, review it, and save it as desired.

9 Hall, Russell, 2002: “Offshore Wear Model: Part 1 – Define the Problem,” DEA-137 Report, May. 10 Luo, Yuejin, Kaiwan Barucha, Samuel Robello and Bajwa Faris, 2003: “A Simple, Practical Approach Provides a Technique for Calibrating Tortuosity Factors,” Oil & Gas Journal, September.


2277Model Status

ActiveModels

InactiveModels

27. PROGRAM LICENSES 27.1 Viewing License Status DrillNET includes options for running a wide variety of Engineering Models. These are described in Section 4. Depending on your choices when the program was purchased, your copy of DrillNET may not have an active license for every model. Models that are active are shown in black text within the Engineering Models pane list.

To view your license status and expiration dates in detail select Help “License…”. The License Window lists all Engineering Models, their status and expiration dates.

To obtain new or additional DrillNET license keys, please contact your local Petris office for assistance.

As well as checking license information from the Help option, information detailing module version numbers can also be viewed. If you click on Help “About …”. , the following screen will be displayed. The overall DrillNET version number is near the top of the screen, next to the name “DrillNET”. In the table, you can view the version number for each of the engineering modules of the DrillNET system. When asking for support, it is best to report the overall version number, as well as the version number of the specific module for which you have a question.

CHAPTER 27: PROGRAM LICENSES


27.2 Borrowing License Keys From FLEXlm version 9.2, the feature of borrowing licenses was introduced. The purpose of this option is to allow users to temporarily take licenses from a license server to another workstation. The other workstation could be for example a laptop which is no longer connected to the network and operating at a location away from the main license server.

The length of the time that a license can be borrowed can be selected when the feature is checked out, and the license can either be returned to the main license server once the temporary borrow period has finished, or the user borrowing the license can manually return the license when they return to base and are physically back on the main license server network.

In order to use the BORROW option, the license file must contain an entry like the example below

FEATURE CEMENT petris 1.5 10-oct-2009 1 BORROW SIGN="0263 6F73 17D0

7655 8E86 3606 D5CA E88C AF18 F1CF 1100 88B9 8123 3BC9 958A

AC22 314C 629D 3733 6D05 32C3"

In order to use the BORROW option, the FLEXlm license will need to be setup in license server mode as detailed in Chapter 3 of the DrillNET 1.x Installation Guide – Configuring a License Server System.

When the DrillNET software is run on the license server node, you can check to see what licenses are available for users to borrow by selecting the option Help License

From this option, you can check to see what modules you are licensed to use, how many license you have available, how many can be borrowed and how many are currently being borrowed.




When working on a client node (i.e. any node other than the license server) if you want to BORROW some license keys to work away from the regular network and license server, select the option Help License…

Select the Borrow License… option.

Select the products that you want to BORROW the license keys for, the return date from the date pull down lists and finally click on Confirm Borrow.



With the licenses successfully borrowed, the Borrowed Licenses column will show the number of licenses that are currently being borrowed. The Return License… option will also now be available to use, and license keys can be returned to the server when no longer required.

To return the license key select the Return License… option, select the license key(s) to be returned and then click on Confirm Return to return the license to the license server.

If the license keys are not manually returned, they will automatically time out once the date and time goes beyond the Return Date and Time that was chosen when the license was borrowed

27.3 User setup to be able to borrow licenses In order to borrow a FLEXlm license the user running DrillNET cannot be configured as a “Restricted User”. The user must either have admin privileges or alternatively be defined as a normal user. The user account used during the DrillNET installation process has to be the same as used to load and run DrillNET in order to use the borrow option.


228828. THEORETICAL BACKGROUND

28.1 Pore Pressure Prediction One of the most critical parameters considered by a drilling engineer when planning and drilling a deep well is fluid pore pressures within the formations being drilled. Safety dictates that the wellbore pressure (at any depth) be maintained between naturally occurring pressure of the formation fluids and the maximum wellbore pressure that the formation can withstand without fracture.

The drilling engineer must determine whether abnormal pressures are expected. If they are, the depths at which fluid pressures diverge from normal and the magnitudes of the pressures must be estimated. Significant attention is given to this problem, which reflects both the importance of this analysis and the difficulties that have been experienced in establishing a method to accurately provide this information when it is urgently needed.

When detritus material is carried by rivers to the sea and released from suspension and deposited, the sediments formed are initially unconsolidated and uncompacted and have a relatively high porosity and permeability. The seawater mixed with these sediments remains in fluid communication with the sea and is at hydrostatic pressure. Once deposition has occurred, the weight of the solid particles is supported at grain-to-grain contact points and the settled solids have no influence on the hydrostatic fluid pressure below. Thus, hydrostatic pressure of the fluid contained within the pore spaces of the sediments depends only on the fluid density. With greater burial depth as deposition continues, the previously deposited rock grains are subjected to increased load through the grain-to-grain contact points. This causes realignment of the grains to a closer spacing, resulting in a more compacted, lower-porosity sediment. As compaction occurs, water is expelled continually from the decreasing pore space.11 When formation pore pressure is approximately equal to theoretical hydrostatic pressure for the given vertical depth, formation pressure is said to be normal. Normal pore pressure for a given area is usually expressed in terms of the hydrostatic gradient. Some typical pressure gradients for areas that have seen considerable drilling activities are detailed below.

Pressure Equivalent Gradient Water Density (psi/ft) (g/cc) West Texas 0.433 1.000 Gulf of Mexico coastline 0.465 1.074 North Sea 0.452 1.044 Malaysia 0.442 1.021 Mackenzie Delta 0.442 1.021 West Africa 0.442 1.021 Anadarko Basin 0.433 1.000 Rocky Mountains 0.436 1.007 California 0.439 1.014 A normal pore pressure would correspond to the hydrostatic gradient of a column of fresh or saline water. The normal pressure at any depth working in standard English units can be derived from the equation

P = 0.0519D

where P pressure in psi

fluid density in ppg

D depth in ft

If the formation fluid was fresh water at 8.35 ppg, then at 10,000 ft we could for example expect a normal formation pressure of 4334 psi. If for any reason the pressure was in fact higher than this theoretical value then it would be considered to be an abnormal pressure.

CHAPTER 28: THEORETICAL BACKGROUND


In the oil industry, estimated pore pressure is usually measured in pounds per square inch (psi), but is converted to equivalent mud weight and measured in pounds per gallon (ppg) to more easily determine the mud weight required to prevent the fluid or gas from escaping and causing a blowout or wellbore failure.

28.1.1 Causes of abnormal pressure In many instances, formation pressure is encountered that is greater than the normal pressure for that depth. The term abnormal formation pressure is used to describe formation pressures that are greater than normal. Abnormally low formation pressures are also encountered, and the term subnormal formation pressure is used to describe these pressures.

Abnormal pressures i.e. formation pressures greater than normal pressures can potentially cause serious drilling problems. There are many causes of abnormal pressure, and all will potentially require some means of sealing or control within the formation which may involve casing the offending zone, or increasing the mud weight used whilst drilling to hold back the abnormal pressures.

One of the primary and best understood causes of abnormal pressure is undercompaction. During the burial process, if the pore fluids cannot escape (dewater) at an efficient rate due to a low permeability overlying formation, then the formation will become under-compacted with a resultant abnormally high formation pressure.

A secondary cause of abnormal pressure is the burial history. The process of dewatering and expulsion of pore water can be further triggered by hydrocarbon maturation, clay diagenesis and thermal effects. These unloading mechanisms can introduce abnormal pressure in the formation of pore spaces as the rock matrix constrains the increased pore fluid volume. Unloading can be caused by tectonic episodes or erosion.

Another cause of abnormal pressure may be the lateral migration of fluids along fault planes or through an interconnecting network of porous reservoirs and faults into a structural trap where the pressures at the crest of the trap may well exhibit abnormally high values.

The upward flow of fluids from a deep reservoir to a more shallow formation can result in a shallow formation becoming abnormally pressured. When this happens the shallow formation is said to be charged. This can be caused by fluids migration along a fault line, flowing outside of the casing on an adjoining well, or flowing from depth in an adjoining well into a shallower formation. In all cases the results can be catastrophic and many severe blowouts have occurred when a shallow charged formation was encountered unexpectedly. This scenario can be particularly common above old fields.

28.1.2 Porosity calculation Pore water expands with increasing burial depth and increased temperature, whilst the pore space is reduced by increasing geostatic load. Therefore, normal formation pressure can only be maintained if a path of sufficient permeability exists to allow formation water to readily escape. As long as the pore water can escape as quickly as required by the natural compaction rate, the pore pressure will remain at hydrostatic pressure. However, if the water flow path is blocked or severely restricted, the increasing overburden stress will cause pressurization of the pore water above hydrostatic pressure. The pore volume will also remain greater than normal for the given burial depth. The normal loss of permeability through compaction of fine-grained sediments, such as shale or evaporates, may create a seal that would permit abnormal pressure to develop. The bulk density at a given depth is related to the grain density g the pore fluid density and the porosity as follows12

1

Change in bulk density with burial depth is related primarily to the change in sediment porosity with compaction. Grain densities of the common minerals found in sedimentary deposits do not vary greatly and usually can be assumed constant at a representative average value which is also true for pore fluid density. Porosity can be expressed in terms of average bulk density in the equation




This equation allows average bulk density data read from well logs to be expressed easily in terms of average porosity for any assumed grain density and fluid density. If these average porosity values are plotted vs depth on semilog paper, a good straight line trend is usually obtained. The equation of this line is given by

Where 0 is the surface porosity, K is the porosity decline constant and Ds is the depth below the surface of the sediments.

28.1.3 Methods for Estimating Pore Pressure Most methods for detecting and estimating abnormal formation pressures are based on the fact that formations with abnormal pressure also tend to be less compacted and have a higher porosity than similar formations with normal pressure at the same burial depth. Thus, any measurement that reflects changes in formation porosity also can be used to detect abnormal pressure13. Generally, the porosity-dependent parameter is measured and plotted as a function of depth.

If formations are normal, the porosity-dependent parameter should have an easily recognizable trend (“normal trend”) because of the decreased porosity with increased depth of burial and compaction. A departure from the normal pressure trend signals a probable transition into abnormal pressure. The upper portion of the region of abnormal pressure is commonly called the transition zone. Detection of the depth at which this departure occurs is critical because casing must be set in the well before excessively pressured permeable zones can be drilled safely.

Two basic approaches are used to make a quantitative estimate of formation pressure from plots of a porosity-dependent parameter with depth. One approach is based on the assumption that similar formations having the same value of a porosity-dependent variable are under the same effective matrix stress. Thus, the matrix stress state of an abnormally pressured formation at a particular depth is the same as the matrix stress state of a more shallow normally pressured formation (which gives the same measured value of the porosity-dependent parameter). However, due to variations in compaction history and geology, there is no consistent normal trend across different zones of formation.

The second approach for calculating formation pressure from a porosity-dependent parameter is based on empirical correlations. Empirical correlations are generally thought to be more accurate than assuming that matrix stresses are equivalent at depths having equal values for the porosity-dependent parameter. The difficulty with the empirical approach is that considerable data must be available for the area of interest before an empirical correlation can be developed. In practice, correlations are readily available only in well-developed regions or through exploratory wells.

Techniques for detecting and estimating abnormal formation pressure are classified as (1) predictive methods, (2) methods applicable while drilling, and (3) verification methods. Initial wildcat well planning must incorporate formation pressure information obtained by a predictive method. Initial estimates are updated during drilling operations, and after drilling the target interval , the formation pressure estimates are checked again before casing is set using various formation evaluation methods.

Estimates of formation pore pressure made before drilling are based primarily on (1) correlation of available data from nearby wells and (2) seismic data.

28.1.4 Bulk Density Measurements A continuous evaluation of formation rock fragments whilst drilling can provide valuable information about subsurface formations. If data from previously drilled wells is available, it can be used to estimate formation pore pressures for new wells drilled in the same vicinity which may encounter the same or similar formations. Cuttings bulk densities can be obtained using a variety of techniques including (1) a mercury pump, (2) a mud balance, or (3) a variable-density liquid column. Irrespective as to which technique is used, the end result will be an approximate bulk density value for shale cuttings throughout the well.

Shale density is a porosity-dependent parameter that is often plotted vs. depth to estimate formation pressure. When the bulk density of a cutting composed of pure shale falls significantly below the normal pressure trend line for shale, abnormal pressure is indicated. One approach to determine formation pressure makes use of an empirically



developed departure curve called the Boatman relationship14, where Formation Pressure Gradient (psi/ft) is plotted against Shale Density Difference (shn-sh) in g/cm3. A mathematical model of the normal compaction trend for the bulk density of shale cuttings can be developed by substituting the exponential porosity expression defined by

for porosity in the equation

1

After rearranging terms, this substitution yields

where ρ is the shale density for the normally pressured shales. The grain density of pure shale is 2.65. The average pore fluid density ρ can be found from lookup tables, and the constants and K can be based on shale-cutting bulk density measurements made in the normally pressured formations. In practice, the normal trend is picked up visually and extrapolated mathematically to find , K and “normal values” of cuttings bulk density at desired depth. Then shale density Difference is calculated based on the expected normal density to obtain abnormal pressure readings from the Boatman correlation.

28.1.5 Modified d-exponent As drilling progresses into a transition zone of normal and abnormal formation pressure, variations in rock properties and bit performance often provide many indirect indications of changes in formation pressure. To detect these changes, drilling parameters related to bit performance are monitored continuously and recorded by surface instruments. In addition, many variables associated with the drilling fluid and rock fragments being circulated from the well are also monitored.

If the wellbore pressure is inadvertently allowed to fall below the pore pressure in a permeable formation, this can result in a kick and an influx of formation fluids into the well. In this situation, when well control operations are initiated, the shut in drillpipe pressure will provide a direct and accurate indication of the formation pressure.

Changes in bit behavior can be detected through measurements made at the surface, and the most common parameters measured include (1) penetration rate, (2) hook load, (3) rotary speed, and (4) torque. Drilling fluid properties are also monitored as this can have an influence on penetration rates. The bit penetration rate usually changes significantly with formation type, and in general tends to decrease in a given type of formation with increasing depth. However, when a transition zone into abnormal pressure is encountered this normal trend is altered. Just above the transition zone to a higher formation pore pressure gradient, a hard, often limey formation is frequently encountered and this will drill at a lower than normal drill rate. It is thought that these formations are extremely low permeability formations that form the pressure seal for the abnormal pressure gradients. These seals may vary in thickness from a few feet to several hundred feet. Just below this abnormal pressure caprock, the normal penetration rate trend reverses, and an increase in penetration rate with depth may be observed.

Many drilling variables other than formation type and formation pore pressure can affect the rate of penetration, and some of these additional parameters are (1) bit type, (2) bit size, (3) bit nozzle sizes, (4) bit wear, (5) weight on bit, (6) rotary speed, (7) mud type, (8) mud density, (9) effective mud viscosity, (10) solids content and size distribution in the mud, (11) pump pressure, and (12) pump rate. Changes in the variables affecting penetration rate can mask the effect of changing lithology or increasing formation pore pressure. It is therefore often difficult to detect formation pressure changes using just penetration rate data, and other indicators should be used in conjunction when predicting formation pressure.

When mill tooth bits are used, the effect of tooth wear can influence penetration rate during each bit run. When other drilling variables are not changing, the effect of bit dulling can be partially compensated for by establishing the expected normal trend from past bit performance in normal pressured formations. In some cases, because of tooth wear, the penetration rate will decrease with increasing depth in the transition zone at a much lower rate than anticipated. Changes in other drilling variables can cause similar effects and be misinterpreted as a pressure increase. In particular changes in bit type make changing pore pressure difficult to detect from penetration rate data.




Empirical models of the rotary drilling process have been proposed to mathematically compensate for the effects of changes in the more important variables affecting penetration rate. One of the first empirical models was published by Bingham15, and Bourgoyne16. The former model normalizes penetration rate R, for the effect of change in weight on bit, W, rotary speed, N, and bit diameter, db, through the calculation if a d-exponent defined by

d =

where units of measure were R – ft/hr, N – rpm, W – k-lbf and db – in.

The d-exponent equation can be used to detect the transition from normal to abnormal pressure if the drilling fluid density is held constant. This technique involves the plotting of d obtained in a given type of low permeability formation as a function of depth. Shale is nearly always the formation type selected, and drilling data obtained in other formations types can simply be omitted from the calculation. In normally pressured formations the d-exponent tends to increase with depth, but after abnormally pressured formations are encountered, a departure from the normal pressure trend occurs in which the d-exponent increases less rapidly with depth. In many cases a complete trend reversal occurs and the d-exponent actually decreases with depth.

In 1971, Rehm and McClendon17 proposed modifying the d-exponent to correct for the effect of mud-density changes as well as changes in weight on bit, bit diameter and rotary speed. This modified d-exponent was computed using

=

Where n is the mud density equivalent to a normal formation pore pressure gradient and e is the equivalent mud density at the bit while circulating.

The modified d-exponent is often used for a quantitative estimate of formation pore pressure gradient as well as for the qualitative detection of abnormal formation pressure. Numerous empirical correlations have been developed in addition to the equivalent matrix stress concept.

Rehm and McClendon recommend using linear scales for both depth and dmod values when constructing a graph to estimate formation pore pressure quantitatively. A straight-line normal pressure trend line having intercept (dmod)0

and slope m is assumed such that

According to the authors, the value of slope m is fairly constant (m=0.000038 ft-1) with changes in geologic age. The following empirical relation was presented for the observed departure of the dmod plot and the formation pressure gradient, gp

7.65 16.5

where (dmod)n is the value of dmod read from the normal pressure trend line at the depth of interest. In this equation gp is given in equivalent mud density units of lbm/gal.

Zamora18 recommends using a linear scale for depth but a logarithmic scale for dc values when constructing a graph to estimate formation pore pressure quantitatively. A straight-line normal pressure trend line having intercept

and exponent m is assumed such that

Zamora reports that the slope of the normal pressure trend line varied only slightly and without apparent regard to location or geological age with an m value of 0.000039 ft-1. Zamora used the following empirical relation for the observed departure on the plot and the formation pressure gradient gp .

where is the normal pressure gradient for the area.



28.1.6 Wireline data Measurements The decision of when to stop drilling and cement casing in a well before proceeding with deeper drilling operations is a key decision in both the technical and economic success of a drilling venture. If casing is set too high, an extra unplanned string may be required later in order to reach planned objectives which will result in increased costs. If casing is however not set when required, it may result in an underground blowout which may necessitate plugging and abandoning the well.

Prior to setting casing the open borehole is generally logged with conventional wireline devices to provide permanent records of the formation penetrated prior to running casing. Empirical methods have been developed for estimating formation pressure from some of the porosity-dependent parameters measured by a well-logging sonde. The porosity-dependent formation parameters usually obtained from well logs for the estimation of formation pore pressure are either (1) interval transit time or (2) conductivity.

Pore pressure plots constructed using porosity dependent formation parameters obtained from logging data include only points obtained in “pure” shales. Criteria that can be applied in selecting the more pure shales from the logging data include.

1. Minimal base line values of spontaneous potentials with essentially no fluctuations.

2. Maximum values of gamma ray counts.

3. Maximum conductivity (minimum resistivity) values with a small and constant separation between the shallow and deep radius of investigation devices.

4. Maximum values of interval transit time.

5. Use of values obtained in shales having a thickness of 20 ft or more.

It is often difficult to find a sufficient number of shale points in the shallow normally pressured formations to establish the normal pressure trend line with data from a single well. Published average trend lines for areas of active drilling obtained from a large number of wells provide a useful guide in interpreting the small amount of normal pressure data available in pure shale on a given well.

28.1.7 Resistivity Well logging devices that measure formation conductivity or resistivity (the reciprocal of conductivity) are used on almost every well drilled. Since the data are almost always readily available, conductivity is the most common porosity-dependent parameter used in the estimation of pore pressure from well logs. The term formation factor 19,

, generally is used to refer to the ratio of the resistivity of the water-saturated formation , to the resistivity of the water . The formation factor 20 can also be expressed in terms of a conductivity ratio 21.

The relation between formation factor F and porosity has been defined empirically by

/

Where the exponent m varies between 1.4 and 3.0. An average value of 2.0 generally is used in practice when laboratory data are not available.

Formation conductivity or varies with lithology, water salinity, and temperature as well as porosity. To avoid changes caused by lithology, only values obtained in essentially pure shales are used. Shales containing some limestone are avoided because of the large effect of the limestone fraction on observed conductivity. The effect of changes in salinity and temperature can be taken into account in the calculation of the formation factor through use of the correct in-situ value if the water conductivity or resistivity for the given temperature and salinity at the depth of interest.

Formation conductivity or resistivity near the borehole is also affected significantly by exposure to the drilling fluid. Even though shale formations are relatively impermeable to the invasion of mud filtrate, changes in the shale




properties generally occur as a result of chemical interaction between the drilling fluid and the borehole wall. Sections of the borehole composed of highly water sensitive shales give different log readings on logging runs made at different times. This problem can be minimized by using a well logging device with a deep radius of investigation.

A mathematical model of the normal compaction trend for shale formation factor can be obtained by substituting the exponential porosity equation defined by

for porosity in

/

After rearrangement of terms, this substitution yields

ln ln

The constants and K must be chosen on the basis of conductivity data obtained in normally pressured formations in the area of interest.

In practice, however, as water conductivity or resistivity changes with depth, and is not readily available, it is assumed to be constant and the normal compaction trend conductivity becomes:

ln

Where ln ln and . Of course, K1 and K2 must be chosen on conductivity/resistivity data in normally pressured formations by data fitting.

Region-dependant correlations are used to calculated formation pressure based on the ratio of measured conductivity/resistivity to “normal conductivity/resistivity” of the extrapolated normal trend. When shale conductivity falls significantly above the extrapolated normal trend values, the presence of abnormal pressure is indicated.

Hottman and Johnson22 presented one of the first empirical relationships between measured formation pressure in permeable sandstones and the adjacent layer shale resistivity while Matthew and Kelley 23 , 24 published similar correlations for the South Texas and Louisiana gulf coast.

28.1.8 Interval Transit Time When planning development wells, emphasis is placed on data from previous drilling experiences in the area. For wildcat wells, only seismic data may be available. To estimate formation pore pressure from seismic data, the average acoustic velocity as a function of depth must be determined. For convenience, the reciprocal of velocity, or interval transit time (ITT), is generally displayed.

The observed ITT, , is a porosity dependent parameter that varies with porosity according to the following relation

1

where ma is the ITT in the rock matrix and fl is the ITT in the pore fluid. Since transit times are greater for fluids than for solids, the observed transit time in rock increases with increasing porosity.

When plotting a porosity-dependent parameter vs. depth to estimate formation pore pressure, it is desirable to use a mathematical model to extrapolate a normal pressure trend (observed in shallow sediments) to deeper depths, where the formations are abnormally pressured. Often a linear, exponential, or power-law relationship is assumed so the normal pressure trend can be plotted as a straight line on cartesian, semilog, or log-log graph paper. In some cases, an acceptable straight-line trend will not be observed for any of these approaches, and a more complex model must be used.

A mathematical model of the normal compaction trend for ITT can be developed by substituting the exponential porosity expression defined by25.



for porosity in

1

After rearrangement of terms, this substitution yields

ln

The normal pressure relationship of average observed sediment travel time , and depth D, is complicated by the fact that matrix transit time �ma also varies with porosity. This variance results from compaction effects on shale matrix travel time. Values for can vary from 167 s/ft for uncompacted shale to 62 s/ft for highly compacted shales. In addition, formation changes with depth can also cause changes in both matrix travel time and the normal compaction constants and K. These problems can be resolved if sufficient normal pressure data are available.

The procedure for estimation of formation pressure from seismic-derived ITT data (e.g. Pennebaker method26) is essentially the same as that use with log-derived ITT data. The primary difference is that with well log data only shale formation data is included, but with seismic data, the lithology cannot be determined accurately enough for this to be done, and therefore average ITT’s for all formations present must be used.

The geologic age of the shale sediments has been found to affect the normal pressure relationship between ITT and depth. Older sediments that have had a longer time for compaction to occur result in an upward shift in the normal pressure trend line. Similarly, younger sediments result in a downward shift in the normal pressure trend line.

When the shale ITT falls significantly above the normal pressure trend line near the formation of interest, abnormal formation pressure is indicated. Hottman and Johnson27 presented one of the first empirical relationships between measure formation pressures in permeable sandstones and adjacent shales, and this correlation is still widely used today in parts of the Louisiana gulf coast area. Mathews and Kelly28, 29published similar correlations for the Frio, Wilcox, and Vicksburg trends of the Texas gulf coast area, and more recent authors have developed similar correlations for the North Sea and South China Sea areas.

28.1.9 Pennebaker Pennebaker30 plots are normally used to determine formation pore pressures from seismic stacking velocity data. The Pennebaker plot is a graph of depth versus seismic wave velocity (expressed as interval transit time (ITT) in units of microseconds per feet). Pennebaker assumes that ITT has power-law dependence on depth in normal compaction trend. With logarithmic scaling, the normal shale velocity (transit time) compaction trend should follow roughly a straight line. Any divergence (or velocity changes) from this normal compaction line in shales may be an indication of undercompaction and overpressure. Note that major lithological changes can also create large velocity changes that are not related to any overpressuring, and this technique should always utilize all available geological knowledge to constrain the interpretation.

Based on numerous well calibrations from various areas, it has been observed that the degree of overpressuring is directly proportional to the amount of velocity departure from the normal baseline. The primary purpose of a Pennebaker plot is therefore to allow setting a normal pressure baseline on the plot to quantify the depth and degree of possible overpressuring where velocity inversions occur.

For convenience, the reciprocal of velocity, or ITT, is generally displayed. The observed ITT, t, is a porosity-dependent parameter (i.e., it varies with porosity ). Since transit times are greater in fluids than in solids, the observed transit time through rock increases with increasing porosity.

When plotting a porosity-dependent parameter versus depth to estimate formation pore pressure, it is desirable to use a mathematical model to extrapolate a normal pressure trend (observed in shallow sediments) to deeper depths, where the formations are abnormally pressured. Often, a linear, exponential, or power-law relationship is assumed so that the normal pressure trend can be plotted as a straight line on Cartesian, semilog, or log/log paper. In some




cases, an acceptable straight-line trend will not be observed for any of these approaches, and a more complex model must be used.

According to the Pennebaker technique, abnormal pressures can be predicted by relating them to variations in stacking velocity.

Pennebaker observed that ITT (=ma(1-)+) not only has a power-law dependence on formation depth but also needs to be compensated by lithology, which in turn depends on compaction history. A correlation based on the depth of 100-S/ft ITT to characterize the effect was proposed and integrated into the estimation of formation pressure. In fact, a suite of correlations were used to also predict overburn pressure and fracture pressure.

According to Pennebaker’s correlation, fracture-pressure gradient can be calculated by the following formula.

where: pff = fracture pressure pf = pore pressure ob = vertical overburden stress F = fffective matrix stress ratio

Matrix stress ratio, K, and the overburden gradient, Og, were correlated with depth by Pennebaker. Along with the pore-pressure gradient (which is derived from the standard Pennebaker plot), these values are then used to estimate fracture-pressure gradient. Again the compaction history is used to calibrate the correlations.

28.2 Wellbore Stability Model Borehole stability models are generally comprised of two steps:

1. Determining the redistribution of the stress state around the borehole and

2. Predicting whether the borehole is stable

28.2.1 Basic Assumptions It is normally assumed that: (1) stresses around the borehole are under a plain strain condition; that is, the strain component along the borehole axis, z, is a constant for the whole region considered and is equal to that at the far field, z0, and (2) the formation (with or without pore fluid) is homogeneous and isotropic.

Coordinate System and Transposition of in-Situ Stress State

The coordinate system used in the analysis is shown at the right. The z-axis is parallel to the borehole axis and the x-axis lies in a horizontal plane. is inclination angle and is azimuth angle.

Before stress distribution around an inclined borehole can be determined, it is necessary to transpose the in-situ stress tensor relative to the borehole coordinate system. The transposed stress state is:

xx = Hmax sin2 + Hmin cos2

yy = cos2(Hmaxcos2 + Hminsin2) + vsin2

zz = sin2(Hmaxcos2 + Hminsin2) + vcos2

xy = cos sin cos(Hmax – Hmin)

yz = sin cos(v – Hmaxcos2 – Hminsin2)

zx = sin sin cos(Hmin – Hmax)

(x-axis lies in the horizontal plane)



Linear Poroelastic Model

Certain governing equations are used to determine the stress distribution around a borehole. These include equilibrium equations, compatibility equations, and constitutive equations. For linear elastic models, exact analytical solutions can be derived based on these equations.

It is known that for linear elastic models the maximum major principal stress occurs at the borehole wall and that failure is initiated there. Therefore, only the stress state at the wall is considered.

Perfect Mud Cake

Total stress components and pore pressure at the wall can be written as (McLean and Addis, 1990):

r = pw

fwxyyyxxfyyxx pph1

2112sin22cos)(2p

fwxyyyxxzzz pph1

212sin22cos)(2

)sincos(2 zxyzz

zr = 0

r = 0

(pf)near wellbore = pf + h(pw – pf)

where

)pp(ceunderbalanfor1

)pp(eoverbalancfor0h

fw

fw

Permeable Mud Cake

Fluid flow through pore spaces is assumed to obey Darcy’s law. Total stress components at the borehole wall are given as (Hsiao, 1988):

r = pw

fwBxyyyxxfyyxx pp1

212sin22cos)(2p

fwBxyyyxxzzz pp1

212sin22cos)(2

)sincos(2 zxyzz

zr = 0

r = 0

where B is Biot’s poroelasticity parameter:

material interpore of modulusbulk

skeleton solid of modulusbulk 1B




28.2.2 Failure Criteria

Tensile Failure Criteria

The criterion for tensile failure is simply whether minimum effective stress is less than strength of the formation (assuming compression is positive). Thus, failure occurs when

Tf3 p

where T is tensile strength of the rock.

Compressive Failure Criterion

The Mohr-Coulomb criterion is used to define failure of rock in compression. The criterion can be expressed in terms of principal stresses:

0f3f1 Ctanpp

or

0f Stanp

where is constant and C0 is uniaxial compressive strength of the rock. and C0 can be obtained from

sin1

sin1tan

sin1

cosS2C 0

0

where and S0 are internal friction angle and cohesive strength of the rock, respectively.

28.2.3 Mud/Shale Interaction To couple the mechanics and chemistry of mud/shale interaction, osmotic pressure caused by differences in chemical potential is associated with alteration in near-wellbore pore pressure:

shale

mud

woobservedfrenearwellbof a

aln

V

RT)p()p(

This alteration can be integrated into the original pure mechanical stress equations to determine the complete profile of the stress state.

28.2.4 Nomenclature for Wellbore Stability Compression is assumed as positive.

= (total) vertical/overburden in-situ stress

Hmax = (total) maximum horizontal in-situ stress

Hmin = (total) minimum horizontal in-situ stress

zxyzxy

zzyyxx

,,

,, = (total) in-situ stresses in global Cartesian wellbore coordinates

zyzr

zr

,,

,, = (total) stresses in local cylindrical wellbore coordinates

1 = greatest (total) principal stress



2 = intermediate (total) principal stress

3 = least (total) principal stress

-pf = effective/matrix stress

= normal stress

0 = semi-permeable membrane efficiency

= shear stress

pw = wellbore pressure

pf = far field formation pore pressure

(pf)near wellbore = near-wellbore formation pore pressure

= wellbore inclination angle

= wellbore azimuth angle

T = tensile strength of the rock

= Poisson’s ratio of the rock

= Mohr-Coulomb friction coefficient of the rock

C0 = uniaxial compression strength of the rock

= internal friction angle of the rock

S0 = cohesive strength of the rock

B = Biot’s poroelasticity parameter of the rock

R = universal gas constant

T = temperature

Vw = partial molar volume of water

amud = water activity of mud

ashale = water activity of shale

28.3 Well Planning/Projection Model Nomenclature for Well Planning

+E/-W East or West coordinates (negative values are west).

+N/-S North or South coordinates (negative values are south).

Azi or Azimuth Used to define a direction at a specific point. True north is defined as both 0 and 360° azimuth.

Bent Sub A short drillstring member of drill-collar stock, machined with one connection at a small specified angle with respect to the axis of the sub; used with a downhole motor to cause it to deviate from its normal direction.

BR or Build Rate Rate of change in inclination of a well path between data points. Units are the same as dogleg severity. Build rate can be positive or negative to show build or drop.

C. Dir. Closure Direction or Closure Azimuth

C. Dist. Closure Distance




Curvature Radius Length of radius equivalent to a particular arc of curvature.

Dip, Formation The angle between formation bedding planes and horizontal, measured in a vertical plane normal to the direction of strike.

DL, BHA Build Rate, Total Build Rate

Dogleg severity. The rate of change in the combination of both inclination and direction of a well path between data points. Standard units are °/100 ft or °/30 m.

Horizontal Projection Part of the working plot showing a plan or horizontal view of the hole or holes.

Horizontal Displacement

Horizontal distance of a given point in a well from an imaginary vertical line projected down from the surface location; also called drift.

Inc. or Inclination Angle

The angle between the centerline of a wellbore and a vertical axis. By definition, straight down toward the center of the earth is an inclination of zero. This angle can be measured in decimal degrees or in degrees:minutes:seconds. Maximum inclination is 180°; all inclination angles are positive.

MD Measured Depth below derrick floor, measured in the drilled hole with drillstring or wireline.

Oil-Field Format A format for indicating direction using true north or south as the principal reference with the degrees to the east or west from the true N/S axis being the secondary direction. The format is: [(principal direction) (degrees in) (secondary direction)] Examples: (N 33° E) and (S 67° W). The maximum number of degrees is 90 in any secondary direction. If this is exceeded, then the principal direction changes and the secondary direction is also redefined.

Orientation The process of positioning a deviation tool in specified radial alignment downhole.

Plan View A view of the well path as if looking straight down; a top view (similar to a road map). True north is always toward the top of the graph and east to the right.

Section View A view of the well path from the side when projected onto a vertical plane in a specified azimuth direction. A graph of the displacement of the well path in the direction of the azimuth versus TVD. Azimuth originates at the surface location.

Station A survey data point. Station length is the distance between stations. A survey is one data point. A well path is described by all of the data points; therefore, a well path survey is all data points surveyed.

Survey Data Inclination angle and direction of the wellbore at the MD of the survey instrument. These three data comprise a survey data point.

Tangent Section A straight (non-curving) section of a deviated hole with constant inclination, usually following a build section.

TFO Tool-face orientation angle. TFO is zero when the tool’s face is pointed up toward the high side of the borehole. A TFO of either -180° or +180° indicates the tool face is pointing down toward the low side of the borehole.

TI Tie-in flag. The (tie-in) survey station has new, precise coordinates for TVD, N/S, and E/W.

Traveling Cylinder Scan

An accurate pictorial representation at right angles to the well path at a particular depth, showing its position relative to the designed path or to other wells.

TR or Turn Rate Rate of change in azimuth of a well path between data points. Units are the same as dogleg severity. Turn rate can be positive or negative to show clockwise turning or counterclockwise turning.

TVD True vertical depth. Down is positive.



Vertical Section, Vertical Projection or Section View

Part of the working plot showing one view of the hole projected to a vertical section on a specified azimuth (usually the design azimuth) from location to target.

Walk, Left- or Right-Hand

The tendency of hole azimuth to gradually change counterclockwise or clockwise, respectively.

28.4 Casing Stress Check Model

28.4.1 Casing Verification Concepts Casing verification can encompass a broad range of analyses and can evaluate a variety of factors. DrillNET limits verification to the three principal stresses to which a casing column is subjected: burst, collapse, and tension stress.

Casing Stresses

A casing column is considered to experience a burst stress during a kick, when the BOPs are closed. A kick usually occurs in the open-hole portion of the well (below the last set shoe) and usually while drilling (consequently, close to the bottom). Burst stress is an insideoutside pressure.

A casing column is exposed to collapse stresses in ordinary drilling conditions, with open BOPs. Collapse stress is an outsideinside pressure. Tension stress is the load the casing experiences due to its own weight. Any lower portion of the column hangs from the portion above it. The last portion of the column (close to the bottom) has no tension stress. Tension is maximum, instead, for the section at the top which sustains the weight of the whole column.

Of the three principal stresses, tension stress is by far the least important. Most casing verifications usually concentrate on burst and collapse stresses. Note that tension is a weight, whereas burst and collapse are pressures. Both burst and collapse analyses calculate a separate internal and external pressure. The concept of internal and external does not apply to tension analysis. For tension, a concept of net or acting tension is derived from the column weight, taking into consideration buoyancy effects and bending effects.

Casing Resistance

Casing manufacturers declare the nominal resistances of the casing they mill (burst, collapse and tension). For burst and tension, resistances are usually declared separately for the casing body and the casing joint. As a safety measure, when resistances in the body and joint are different, DrillNET uses the lower of the two values.

Stress-to-Resistance Comparison

No casing verification is complete until acting stress and casing resistance are explicitly compared. Basically, a casing is verified if it is able to resist all three stresses, i.e., if its resistance is greater than the acting stresses. The problem is to determine how much greater the resistance must be. No company takes on face value casing nominal resistances as declared by the pipe manufacturer. Most companies, as a safety measure, do not simply require that resistance be greater than acting stress. Rather, they require that resistance be at least (for example) 1.2 times acting stress. This multiplier is called the design factor. For tension, most companies apply larger design factors, say 1.7 or 1.8. No one uses design factors less than 1.0, as this would indicate that one believes casing resistance is underestimated.

If design factors are greater than 1.0, a graph that displays nominal resistance against acting stress is useless. What should be compared is derated resistance against stress, or the full nominal resistance against an increased stress. A comparison of full nominal resistance to acting stress can actually be misleading, because it may lead the engineer to believe that a certain casing can resist in a specific circumstance, while it could actually fail.

The resistance-to-stress ratio (where “resistance” is the full nominal resistance and “stress” is the acting stress) is called the safety factor. Comparing this concept of safety factor with the above definition of design factor leads to the following final statement: A casing is verified if its safety factor, when under stress, is greater than the required design factor.




Other Concepts of Resistance

DrillNET includes two corrections to casing resistance: (1) the biaxial effect on burst and collapse resistance, and the effect of (high) temperatures on burst, collapse, and tension. For an explanation of how the corrections are derived, see Section 9.3.1.

Biaxial Effect

According to the theoretical model for biaxial stress (see Section 28.11.3), corrections to burst and collapse can even become greater than nominal resistance below the “neutral point” (the depth at which the tension in mud is zero). Some scientists don’t believe that such an increase in resistance actually occurs. For this reason, most engineers ignore the effect of tension on burst.

DrillNET does not consider the impact of the neutral point. In certain special cases, e.g., if the bending effect on tension is taken into consideration, a calculation of the neutral point would become impossible since one could have more than one neutral point, or no neutral point at all. Suppose for example the column enters a dogleg just above the theoretical yield point. For this case, tension in mud (which was close to zero) jumps again to the right, and no neutral point can be measured. Should the casing enter the dogleg just below the neutral point, then the line of the tension in mud could cross the y-axis of the graph twice, indicating multiple neutral points.

Apart from the discussion above, if a corrected resistance to burst and collapse is calculated to account for the biaxial effect, then a separate set of safety factors must also be calculated. There is no longer one resistance, but two: full nominal resistance, and corrected resistance for the biaxial effect. A casing might be verified considering its nominal resistance, but not verified considering corrected resistance.

For biaxial effect on resistance, safety factor (nominal resistance/acting stress) will be calculated as:

(corrected resistance) / (acting stress)

It is still true that safety factor calculated using corrected resistance must be greater than design factor. Design factor is a property associated with the casing, and is not affected by this discussion about corrected resistances. The two safety factors calculated above ought to be compared with the same design factor.

28.4.2 Performing a Casing Verification The first step in casing verification is to build up the verification profile. This process allows DrillNET to identify the portion of the casing profile exposed to the stress. If the column being verified is a liner, the program could include in the verification profile the column run in the previous phase (see next section).

Next the program merges the grid inherited from the Margin Analysis to this profile. All other relevant stress factors, such as the internal fluids for collapse, and if required, external fluids for collapse and burst, are then merged to the resulting grid. For tension stress analysis, a separate grid is built. For example, deviation data necessary to calculate the bending effect on tension are not relevant for burst and collapse. The data grid underlying the tension analysis is basically the result of a merge between the casing verification profile and deviation profile.

Constructing a Verification Profile

The verification profile is the casing profile exposed to stress in a given verification run. If the string being verified is a casing, then there is no casing profile to build—the verification profile is the casing itself. If the column is a liner, then the situation changes. The liner will be the column at the bottom of the verification profile, and DrillNET will search above the liner for other columns. If the liner has an immediate tie-back, then the situation is similar to a simple casing column—the verification profile will be made up of the liner plus the immediate tie-back on top. If the liner has no tie-backs, then DrillNET would include in the verification profile one or more columns run in the previous phase or wellbore (only for the portion above the liner hanger). In this way, a typical stepped verification profile would be constructed.

The process of identifying casing columns belonging to the verification profile is a reverse process that starts from the column whose verification is requested, and proceeds upwards. The search ends if a casing or immediate tie-back is encountered. If a liner is encountered, and it has no tie-backs, then the search proceeds, examining the casing columns run in the previous phase. Whenever subsequent tie-backs are encountered, the rule changes according to the verification condition:



1. Under the production verification rule, any tie-back behaves as an immediate tie-back, i.e., the tie-back is included in the verification profile and the search stops.

2. Under the intermediate verification condition, subsequent tie-backs might be skipped in verification and are not necessarily included in the verification profile. The rule is that a subsequent tie-back is skipped if it has a run sequence number greater than the column under verification, i.e., if it was run after that column, according to a chronological criterion.

A tie-back is always associated with a liner, and is always run after its corresponding liner. This means that if you are verifying an intermediate liner that has a subsequent tie-back on top of it, that tie-back will always be skipped in the construction of the verification profile. The portion of the verification profile above the liner hanger will not be the subsequent tie-back. Instead, above the liner hanger the verification profile will include a section of the column run in the previous phase. This is generally evident from the verification graphs, where the casing resistance changes abruptly above the liner hanger.

The run sequence number is not usually entered explicitly, as it is most often not necessary. If you have a casing profile made up of two casing columns, plus a liner (with or without tie-back), there is no need to specify in what order those columns were run in hole. But there can be more complicated cases. Consider the following: enter a casing plus two intermediate liners, and set a subsequent tie-back on top of the first liner. In this case, the run sequence could have been one of the following:

1. casing + liner (in phase two) + tie-back + liner (in phase three)

2. casing + liner (in phase two) + liner (in phase three) + tie-back

that is, you could have decided to run the second liner before running the tie-back. In that case, when verifying the second liner, the program would not be able to make the decision by itself. A pop-up window would be displayed, asking you to specify the run sequence numbers for the columns in question. In case 1 above, the tie-back (even if marked as subsequent), would be included in the verification profile, ending the search. In case 2, it would be skipped and the search would end with a verification profile made of two liners plus the surface casing (a three-step profile).

DrillNET displays the “Run Sequence Number” window whenever an uncertain situation is encountered. (Note that this window is not displayed unless necessary.)

28.4.3 Casing Margin Analysis Margin Analysis is essentially a verification of the casing-shoe setting depths. Required data, in addition to shoe depths, are formation gradients and mud gradients. The results of the verification are a set of indicators (choke margin, drilling balance and differential pressure, collectively called “margins”). It is worth noting that casing properties (sizes, weights, steel grades, thread types) are not involved in this verification. The only relevant casing property is casing shoe depth.

The margin analysis is not of critical importance for casing stress checking. It is actually an intermediate step toward verification. Results of a margin analysis are described below.

Choke Margin

Choke margin pressure (at a TVD) = (min frac gradient in wellbore) – (mud grad. at TVD) ) * (TVD of min frac pressure inside well)

The total number and bottom depth of the drilling phases are determined based on shoe data. Often, there will be as many phases as casing shoes. However, if the last shoe is not set at the bottom of the trajectory, there could be one more drilling phase. The structure of the wellbores cuts the well trajectory into slices, and each slice is considered separately. The program calculates fracture pressure (frac gradient by TVD) in each slice at each TVD. It searches for the minimum fracture pressure depth—the depth at which the minimum frac pressure is recorded. Note that the fracture gradient that yields the minimum fracture pressure is not necessarily the same as minimum fracture gradient inside the wellbore. We now have a minimum pressure frac gradient and a minimum frac pressure TVD. The minimum pressure gradient is compared at each depth with the mud gradient at each TVD; the result is then multiplied by the minimum frac pressure TVD, thus yielding a pressure. This pressure is then plotted by depth along the entire phase.




Choke margin is very similar to the concept used by the Shoe Advisor (see Section 9.3.2) to set shoe depths. Choke margin explicitly makes use of mud and fracture gradients (no corrections or design margins are involved).

Differential Pressure

differential press (at a TVD) = ((max mud grad inside well) – (pore grad. at TVD)) * TVD

As with choke margin, portions of the trajectory identified as different drilling phases are considered separately. Within each phase, the program searches for maximum mud gradient. Unlike with choke margin, no record is kept in this case of the depth at which the maximum value occurs.

Drilling Balance

drilling balance (at a TVD) = (mud grad. at TVD) – (pore grad. at TVD) * TVD

Drilling balance is a very simple comparison, depth by depth, of the mud and pore gradient along the trajectory.

Remarks on Margin Analysis

It should be noted that in many cases one will calculate mud gradients using a constant overbalance along the whole trajectory. The difference between mud and pore gradients along this trajectory would be constant for this case (and equal to the overbalance). Drilling balance pressure will be a straight line, with the overbalance defining its slope.

It is useful to plot together differential pressure and drilling overbalance because the two curves can generally be easily related to one another, the differential pressure showing “steps,” and joining the drilling balance at wellbore bottom depths. On the other hand, these calculations lose some of their distinctions (even overlapping one another) when manual mud gradients are used, and these mud gradients are constant along each drilling phase (in this case, the mud gradient and the maximum mud gradient coincide).

By far the most important of these three margins is the choke margin. However, the importance and role of margin analysis has been steadily decreasing during the last few years.

28.4.4 Casing Verification Calculations

Fracture Gradients

Frac gradients can be calculated as:

frac gradient = K * (geostatic gradient) + (1 – K) * (pore gradient)

Mud Gradients

Mud gradients can be calculated as:

mud gradient = pore gradient + overbalance

Margin Analysis

Choke margin pressure (at a TVD) = ((min frac grad in wellbore) – (mud grad at TVD)) * (TVD of min frac pressure in wellbore)

where: “minimum frac gradient” is the gradient yielding minimum frac pressure.

Differential press (at a TVD) = ((max mud grad in wellbore) – (pore grad at current TVD)) * TVD

Drilling balance (at a TVD) = ((mud grad at current TVD) – (pore grad at current TVD)) * TVD

Burst and Collapse Pressures under Surface Condition

With surface wellhead With sub-sea wellhead

Collapse internal pressure

At any point from wellhead to shoe depth: According to fluid levels

Burst and collapse

At wellhead: Zero (no pressure) Hydrostatic pressure of seawater1



external pressure At shoe depth: Mud pressure

Hydrostatic pressure of seawater2

Burst internal pressure

At wellhead: 1) set a fixed value (e.g., surface BOP working pressure); 2) calculate as fracture pressure at shoe, minus the pressure exerted by an influx fluid column expanding from shoe to wellhead3

At shoe depth: Fracture pressure at shoe

1. (water depth) * (pore gradient at sea bed) 2. (shoe TVD – air gap) * (pore gradient at sea bed) 3. a percentage can be applied to the resulting pressure; if lower than specified threshold, pressure can be set to the threshold value.

Burst and collapse external pressures can be alternately calculated based on external fluid conditions.

Burst and Collapse Pressures under Intermediate Condition


Collapse internal pressure

At any point from wellhead to shoe depth: According to fluid levels

Collapse external pressure

At any point from wellhead to shoe depth: Mud-at-shoe pressure1. Inside salt levels, if “plastic formation effect” is enabled, fracture pressure2


At wellhead: Burst pressure at shoe (see below), minus the pressure exerted by an influx fluid column expanding from shoe to wellhead3

At shoe depth: Fracture pressure at shoe; if kick/pore method is enabled, fracture pressure is compared with a kick pressure at shoe, and the lower pressure is used4

Burst external pressure

At any point from wellhead to shoe depth: Pore pressure5 Pore pressure (at sea bed, consider water depth only)6

1. Mud-at-shoe pressure is pressure at each TVD along a column, obtained by multiplying that TVD by the mud gradient at the casing shoe. Note that above a liner hanger, when verifying a casing or liner run in the previous phase, DrillNET will calculate this pressure using the mud gradient at the previous shoe. As a result, this typically generates a horizontal shift in collapse external pressure, at the height of the liner hanger.

2. Fracture pressure is pressure at each TVD, obtained by multiplying TVD by fracture gradient. Even if salt levels are detected, fracture pressure is used only if the “plastic formation effect” is enabled.

3. A percentage can be applied to the resulting pressure. No lower pressure threshold is available under the intermediate condition. 4. The kick/pore method assumes a kick was taken somewhere below the shoe. A kick TD is entered, and kick/pore pressure at TD is calculated. Then a kick pressure at the shoe is

calculated as: (kick pressure at TD) – (TD – (shoe TVD)) * (influx fluid gradient). The smaller pressure between kick pressure at the shoe and fracture pressure at the shoe, is assumed as burst internal pressure at the shoe.

5. Pore pressure is pressure at each TVD, multiplying TVD by pore gradient at that TVD. 6. Burst external pressure at the sea bed is calculated as: (water depth) * (pore gradient at sea bed), instead of: TVD * (pore gradient @ TVD)

Burst and collapse external pressures can be alternately calculated based on external fluid conditions.

Unlike surface conditions, most burst and collapse calculations under intermediate conditions involve examination of depths between the wellhead and shoe depth. This is true for example whenever fluid levels are involved. Burst external pressure can involve the full pore gradient profile. Collapse external pressure can involve, because of the plastic formation effect, at least some portions of the fracture gradient profile. Collapse external pressure, whenever a liner is involved, implies an evaluation of liner hanger depth. The mud-at-shoe above the liner hanger will usually not be the same mud as at the liner shoe (it will be the mud at the previous shoe, unless a tie-back is included in the profile, thus sheltering the previous column). Burst internal pressure alone is calculated through two simple values at the casing shoe and wellhead.

Ignore the collapse internal pressure, burst and collapse calculations, under surface conditions, only take into consideration two depths: wellhead and casing shoe.

Burst and Collapse Pressures under Production Condition

Under production condition, the rules for: collapse internal pressure, collapse external pressure and burst external pressure are the same adopted for the intermediate rule.



At wellhead: Pore pressure at reservoir, minus the formation fluid pressure at reservoir1

Pore pressure at reservoir, minus the pressure exerted by a column of formation fluid, expanding from shoe to wellhead2

At shoe depth: (Press at wellhead) + (packer fluid grad) * (shoe TVD – casingTopTVD) 1. (ReservoirPoreGrad – FormFluidGrad) * (ReservoirTVD) 2. (ReservoirPoreGrad * ReservoirTVD) – FormFluidGrad * (WellboreBottomTVD – CasingTopTVD)




Biaxial Effect

Steps involved in calculating corrected resistance follow. First, calculate tension in mud by subtracting the buoyancy effect from the tension in air. Next, examine the bending effect.

In the biaxial effect analysis, if you are considering the bending effect, calculate tension in mud for burst and collapse according to two different rules. The reason for this is that we expect the bending effect to result in a derating of casing resistance for both collapse and burst. The biaxial effect on casing resistance is opposite for collapse resistance and burst resistance, namely, the greater the tension, the smaller the collapse resistance, and the greater the burst resistance. To obtain an additional derating effect on casing resistance due to bending, you must: (1) add the bending effect to the tension in mud when you calculate the biaxial effect on collapse resistance; (2) deduct the bending effect from the tension in mud when you calculate the biaxial effect on burst resistance.

The process can be summarized as follows. Let TA be tension in air. Tension in mud (TM) is:

TM = TA + buoyancy effect

where buoyancy effect is negative.

There are two further concepts, a TMcoll (TM for collapse) and TMburst (TM for burst) defined as:

TMcoll = TM + bending effect

TMburst = TM – bending effect

where bending effect is always non-negative. At each MD along the column, from the shoe up to the column top, take each TM and divide it by the casing resistance to tension. Let the result be xcoll and xburst. At each MD, calculate correction factors:

FcorrCollapse = 2

xx34 coll2

coll

FcorrBurst = 2

xx34 burst2

burst

Finally, at each depth along the column, multiply casing nominal resistance by its correction factor:

(Corrected Collapse Resistance) = FcorrCollapse * (Nominal Collapse Resistance)

(Corrected Burst Resistance) = FcorrBurst * (Nominal Burst Resistance)

Safety Factors

Safety factors in the Casing Stress Check model are:

(nominal resistance) / (acting stress)

When a corrected resistance is used (such as when accounting for biaxial effect), safety factors are:

(corrected resistance) / (acting stress)

Effect of Temperature on Casing Resistance

Above threshold temperature, the effect is calculated as follows:

(corrected resistance) = (1 – (derating factor * ΔT)) * (nominal resistance)

where ΔT is the relevant temperature difference above the threshold at each depth.

28.4.5 Conventions and Nomenclature for Casing Models In the Casing Stress Check model, the terms “casing string,” “casing column,” and “casing section” are synonymous, meaning either a full casing, liner, or tie-back. The term “casing section” can be confusing, especially when casing properties are also involved. Readers may infer that we are speaking of some subdivision of a casing



string/column. Our preference when referring to whole columns (casing/liner/tie-back) will be the terms “string” or “column.”

When a casing string is not made up of one type of tubulars, we say it consists of many “segments.” A casing segment is a continuous portion of a casing string having homogeneous properties. A casing string is always made up of at least one segment.

Wellbore/Drilling Phases

A portion of a well drilled with a bit of a given diameter is called a “drilling phase” or a “wellbore.” Note that this concept has no reference to time. The definition of drilling phase as used here is purely geometrical. Apart from drilling problems ultimately involving the drilling of sidetracks, there is 1:1 correspondence between drilling phases and casing shoes. Each drilling phase is drilled to run a casing column through the wellbore, and at the bottom of the casing column there will be a casing shoe. The only exception to this rule is a production wellbore, that is, a complete drilling phase that remains without casing (open hole) below the last casing shoe. For this case, there is one more drilling phase than casing shoe.

Surface/Intermediate/Production

Casing verifications are usually performed in one of three different scenarios called “verification rules” or conditions. These scenarios encompass a set of physical stress factors which typically occur when running a surface casing column, an intermediate casing column, or a production casing column.

The surface verification rule will apply typically to the first casing column in a casing profile (the surface column). The intermediate rule will apply to the second, third, etc. column, down to the next to last. The production rule is intended especially for the last column. In DrillNET, users can apply any rule to any column. As a typical example, the production rule can be applied to the next to last column to allow running a production test.

Tie-Backs

Tie-backs are casing columns run on top of a liner. For cost or operational considerations, an engineer may decide to run a liner instead of a full casing column. Above the liner (from the liner hanger up to the BOPs), one can decide at a later time to run another column to lengthen the liner. This is called a tie-back. Thus, a tie-back is an anomalous column since it has no casing shoe. Moreover, it is not actually run in an open hole—it is run through an already cased column. Running a tie-back requires no drilling. Consequently, the 1:1 correspondence between casing shoes and wellbores is lost when tie-backs are present. However, it is obvious that a tie-back is associated with a liner, and each liner is, in turn, associated with a wellbore. So, we can refer to a “tie-back run into a phase/wellbore.” This means the tie-back associated with the liner run into that phase/wellbore.

In DrillNET, tie-backs can be defined as “immediate” or “subsequent.” An immediate tie-back is run in the well soon after the liner; a subsequent is run at a later time. The distinction between immediate and subsequent tie-backs is relevant for casing verification. For verification purposes, a full column made up of a liner plus an immediate tie-back always behaves exactly as a full casing column. The same is true if the tie-back is subsequent, but only under production conditions. Under intermediate conditions, a subsequent tie-back will most probably be ignored during the verification.

Conductor Pipe

The conductor pipe is the largest casing run first into the well and closest to the surface. It is usually hammered in the ground. Most engineers would agree that, since there is no drilling, the conductor pipe cannot be considered a true casing column. There can be some verification criteria for a conductor pipe; however, DrillNET does not include any verification functions for conductor pipes. In the program, conductor pipe is only shown in schematics.

Nomenclature for Casing Design

RKB Elevation: Distance from the rig’s kelly bushing to mean sea level.

Surface Casing: A large-diameter, relatively low-pressure pipe string set in shallow formations. First, the surface casing protects fresh-water aquifers onshore. Second, the surface casing provides minimal pressure integrity, and thus enables a diverter or perhaps a BOP to be attached to the top of the




surface casing string after it is successfully cemented in place. Third, the surface casing provides structural strength so that the remaining casing strings may be suspended inside the surface casing.

Intermediate Casing: A casing string that is generally set in place after the surface casing and before the production casing. The intermediate casing string provides protection against caving of weak or abnormally pressured formations and enables the use of drilling fluids of different density necessary for the control of lower formations.

Production Casing: A casing string that is set across the reservoir interval and within which primary completion components are installed.

Fracture Gradient: Pressures required to induce fractures in rock at a given depth.

Pore Gradient: Pressure of subsurface formation fluids, commonly expressed as density of fluid required in the wellbore to balance pore pressure. A normal gradient might require 9 ppg (1080 kg/m3), while a high pressure gradient might be 18 ppg (2160 kg/m3) or higher.

Mud Weight: The mass per unit volume of a drilling fluid. Weight is reported in lbm/gal (ppg), kg/m3 or g/cm3 (also specific gravity or SG), or lb/ft3. Mud weight controls hydrostatic pressure in a wellbore and prevents unwanted flow into the well. The weight of the mud also prevents collapse of casing and the open hole. Excessive mud weight can cause lost circulation by propagating fractures in the exposed rock.

Mud Gradient: Use of units of gradient (psi/ft) to express mud weight.

Overbalance: The amount of pressure in the wellbore that exceeds fluid pressure in the formation. This excess pressure is needed to prevent reservoir fluids (oil, gas, water) from entering the wellbore.

Underbalance: The amount of pressure exerted on a formation exposed in a wellbore below the internal fluid pressure of that formation. If sufficient porosity and permeability exist, formation fluids enter the wellbore. Drilling rate typically increases as an underbalanced condition is approached.

Trip Margin: Small amount of additional mud weight above that needed to balance formation pressure to overcome the pressure-reduction effects caused by swabbing when a trip out of the hole is made.

Kick Margin: Difference between mud weight and pressure exerted by the mud column in addition to anticipated surface pressures. If kick margin is not adequate, an underground blowout is likely if a severe influx is encountered.

Casing Shoe: The bottom of the casing string, including cement around it, or the equipment run at the bottom of the casing string.

Drilling Phase: A portion of an oil well drilled with a bit of a given diameter.

Choke Margin: Percent Increase in capacity from stage design for choke conditions.

Differential Pressure: In general, a comparison between fluid pressures outside and inside a pipe, a pressure vessel, before and after an obstruction in a flow path, or between two points along any fluid path, such as two points along the inside of a pipe or across a packer.

Burst Pressure: The theoretical internal pressure differential at which a joint of casing will fail. Burst pressure value is a key consideration in many well-control and contingency operations and is a major factor in the well design process.

Collapse Pressure: The pressure at which a tubular will catastrophically deform as a result of differential pressure acting from outside to inside. The collapse-pressure rating of perfectly round tubing is relatively high. However, when the tubing is even slightly oval, the differential pressure at which the tube will collapse may be significantly reduced.

Bending Effect: An increase in tension stress that occurs when the casing is run through a dogleg (a curved portion of the wellbore). Due to the curvature, the outer casing edge is subjected to additional stress.



28.4.6 Basic Concepts for Casing Design In general, each casing string is designed to withstand the most severe loading conditions anticipated during casing placement and the life of the well. Loading conditions considered include burst, collapse, and tension. Other loading conditions (such as bending or buckling) must also be considered in some situations. Because loading conditions tend to vary with depth, it is often possible to obtain a less expensive casing design with several different weights, grades, and couplings mixed in a single casing string.

Casing strings required to drill safely to the depth objective serve a different function than do production strings. Similarly, drilling conditions applicable for surface casing are different from those for intermediate casing or drilling liners. Thus, each type of casing string will have different design-load criteria. Criteria can also vary with the well environment and application. General design criteria are presented below for surface casing, intermediate casing, intermediate casing with a liner, and production casing.

Surface Casing

When surface casing is designed, the internal pressure loading condition used for burst design is based on an assumed well-control condition while circulating out a large kick. The maximum external pressure condition used for collapse design is based on a severe lost-circulation problem. The axial tension loading condition is based on an assumption of stuck casing while the casing is run into the hole before cementing operations.

Burst Design

Burst design should ensure that formation fracture pressure at the casing seat will be exceeded before casing burst pressure is reached (see figure). Thus, this design uses formation fracture as a safety pressure-release mechanism to ensure that casing rupture will not occur at the surface and not pose a safety risk to drilling personnel.

Design pressure at the casing seat is equal to fracture pressure plus a safety margin to allow for an injection pressure that is slightly greater than fracture pressure. Pressure within the casing is calculated assuming that all drilling fluid in the casing is lost to the fractured formation, leaving only formation gas in the casing. External pressure (backup pressure outside casing that helps resist burst) is assumed to be equal to normal formation pore pressure for the area. The beneficial effect of cement or higher-density mud outside the casing is ignored because of the possibility of both a locally poor cement bond and mud degradation that occurs over time. A safety factor is also used to provide an additional safety margin for possible casing damage during transportation and field handing of pipe.

The Casing Stress Check model provides flexible options for users. When checking burst pressure, the model will use normal formation pore pressure as the external pressure outside casing if you do not specify fluid outside casing. (Of course, you can specify fluid outside the casing by clicking the option “Use external fluids” on the “Burst (Ext.)” tab on the Casing String page.)

Collapse Design

Collapse design is based either on the most severe lost-circulation (thief) problem that is anticipated, or on the most severe collapse loading anticipated when the casing is run. In both cases, maximum possible external pressure that tends to cause casing collapse results from the drilling fluid that is in the hole when the casing is placed and cemented.

Beneficial effects of cement and possible mud degradation are ignored, but the detrimental effect of axial tension on collapse-pressure rating is considered. The beneficial effect of pressure inside the casing can also be taken into account by considering maximum possible depression of mud level inside the casing. A safety factor is generally applied to the design-loading condition to provide an additional safety margin.

Burst

p = fracture press +safety margin

Normal pressure

Gas

Gas kick

Collapse

Mud

Lost Circulation

Empty




If a severe lost-circulation zone is encountered near the bottom of the next interval of hole and no other permeable formations are present above the lost-circulation zone, the fluid (mud) level in the well can fall until the BHP is equal to the pore pressure of the lost-circulation zone. Equating the hydrostatic mud pressure to the pore pressure of the lost-circulation zone gives

0.052*MW* [(thief zone TVD) – (mud level)]

= 0.052 * (pore-pressure gradient of thief zone)* (thief zone TVD)

Minimum fluid level in the casing while it is placed in the well depends on field practices. The casing is usually filled with mud after each joint of casing is made up and run in the hole, and an internal casing pressure that is approximately equal to external casing pressure is maintained. However, in some cases the casing is floated in or run at least partially empty to reduce the maximum hook load before reaching bottom. If this practice is anticipated, maximum depth of the mud level in the casing must be compared to the depth calculated with the equation above, and the greater value must be used in the collapse-design calculations.

Tension Design

Tension design must take into account axial stress present (1) when the casing is run, (2) during cementing operations, (3) when the casing is landed in the slips, and (4) during subsequent drilling and production operations throughout the life of the well. In most casings, design load is based on the most extreme conditions that could occur when the casing is run. It is assumed that the casing might become stuck near the bottom and that a minimum acceptable amount of overpull (in excess of the hanging weight in mud) is required to work the casing free. A minimum safety factor is applied so that the design load will be dictated by the maximum load resulting from the use of either the safety factor or the overpull force, whichever is greater. The minimum overpull force tends to control the design in the upper potion of the casing string, and the minimum safety factor tends to control in the lower part of the casing string.

Once the casing design is completed, maximum axial stresses anticipated during cementing, casing landing, and subsequent drilling operations should also be checked to ensure that the design load is never exceeded.

In the design of a combination string of non-uniform wall thickness, the effect of buoyancy is most accurately included by use of the pressure/area method. Drilling fluid in the well when the casing is run is used to calculate hydrostatic pressure at each junction between sections of different wall thickness.

In directional wells, additional axial stress in the pipe body and connectors caused by bending should be added to the axial stress that results from casing weight and fluid hydrostatic pressure. The directional plan must be used to determine portions of the casing string that will be subjected to bending while the pipe is run. The lower portion of the casing string will have to travel past all the curved sections of the wellbore, but the upper sections of the string may not be subjected to any bending.

Intermediate Casing

Burst Design

The general procedure outlined for surface casing is also used for intermediate casing string. However, in some cases, burst-design requirements dictated by loading conditions shown in the figure are extremely expensive to meet, especially when the resulting high working pressure is in excess of the working pressure of the surface BOP stacks and choke manifolds for the available rigs. In this case, the operator may accept a slightly greater risk of loosing the well and select a less severe design load. The design load remains based on an underground blowout situation assumed to occur while a gas kick is circulated out. However, the acceptable mud loss from the casing is limited to the maximum amount that will cause the working pressure of the surface BOP stack and choke manifold to be reached. If the

Tension

F

1. Must sustain its own weight plus a safety factor

2. Must sustain minimum pulling force on pipe

Mud

Use pressure/area method to consider buoyancy

Burst

Gas

Normal formation pressure

Mud

Pmax

PmaxPinternal pressure

Mud gradient at next casing depth

external pressure

0.465 psi/ft

Gas gradient



existing surface equipment is to be retained, it is pointless to design the casing to have a higher working pressure than the surface equipment.

When the surface burst-pressure load is based on the working pressure of the surface equipment, Pmax, internal pressure at intermediate depths should be determined as shown in the figure.

It is assumed that the upper portion of casing is filled with mud and the lower portion of casing is filled with gas. Depth of the mud/gas interface, Dm, is determined with

Pmax=Pi– 0.052*MW*Dm – 0.052*(gas density)*(Dlc-Dm)

where Pi is injection pressure opposite the lost-circulation zone, and Dlc is depth of the lost-circulation zone. Dm is calculated by the following formula.

Dm = (Pi – Pmax)/(0.052*(MW – gas density)) – (gas density)* Dlc/(MW – gas density)

Collapse Design

Collapse design in intermediate casing is the same as in surface casing (see previous section).

Tension Design

Tension design in intermediate casing is the same as in surface casing (see previous section).

Intermediate Casing with a Liner

The burst-design-load criteria for intermediate casing on which a drilling liner will later be supported must be based on the fracture gradient below the liner. Burst design considers the intermediate casing and liner as a unit. All other design criteria for the intermediate casing are identical to those previously presented.

In DrillNET, if the string is an intermediate casing with a liner, the model must build a verification profile. If the liner itself is the string at the bottom of the verification profile, the model must consider other strings. If an immediate tie-back is present, the situation is similar to a simple casing string, and the model builds its verification profile that includes itself (the liner) and the relative immediate tie-back on top of it. If the liner does not have a tie-back, the model can build its verification profile that includes itself (the liner) and its previous phase or wellbore (only for the portion lying above the liner hanger). In this way, a typical step by step verification profile is developed. The search ends if a casing or an immediate tie-back is encountered.

Production Casing

Burst Design

Burst-design loading conditions are based on the assumption that the producing well has an initial shut-in BHP equal to the formation pore pressure and a gaseous produced fluid in the well. Production casing must be designed so that it will not fail if the tubing fails under these conditions. A tubing leak is assumed to be possible at any depth. It generally is also assumed that the density of the completion fluid in the casing above the packer is equal to the density of the mud left outside the casing. If a tubing leak occurs near the surface, the effect of the hydrostatic pressure of the completion fluid in the casing would negate the effect of external mud pressure on the casing. Mud degradation outside the casing is neglected because the formation pore pressure of exposed formation would nearly equal mud hydrostatic pressure.

Collapse Design

As shown in the figure, collapse design load for production casing is based on conditions late in the life of the reservoir, when reservoir pressure has been depleted to very low abandonment pressures. A leak in the tubing or packer could cause loss of completion fluid, so low internal pressure is not restricted only to the portion of the casing below the packer. Thus, for design purposes, the entire casing is considered empty. As before, fluid

Collapse

Tubing at negligible abandonment pressure

Leak in tubing causes loss of completion fluid

Mud density when casing was run

Depleted Formation

Burst

Completion fluid

Formation pressure

Production casing

Mud

Assume leak in tubing near surface

Assume gas in tubing




Riser/Casing

Load

Tool Joint

density outside the casing is assumed to be that of the mud in the well when the casing was run, and the beneficial effect of the cement is ignored.

Tension Design

In the absence of any unusual conditions, tension design load criteria for production casing are the same as for surface and intermediate casing. When unusual conditions are present, maximum stresses associated with these conditions must be checked to determine whether they exceed the design load in any portion of the string.

28.4.7 Comments on Application of Casing Stress Check Model The Casing Stress Check Model is not a full-function casing design program. It calculates stresses and checks the safety of a given casing design under given working conditions. The model is different from a conventional casing design program, although most of the concepts for casing design are used in DrillNET. The primary difference is that, while a casing design program must consider all working conditions, DrillNET only checks if the casing string is safe under the particular working conditions specified.

A second difference is the treatment of cost. A casing design program will take casing cost into consideration for designing a casing string, most typically with minimum cost as the target. Casing Stress Check does not consider cost. Another related difference is that a standard casing design program can allow users to view and select their design components from casing inventory databases.

28.5 Wellbore Cementing Model The phenomenon of free fall (or U-tubing) during fluid placement has long been recognized and investigated (e.g., Wahlmeier and Lam (198531); Beirute (198632)). To simulate free-fall phenomena during cementing operations, the dynamics of fluid movement inside the wellbore are first considered.

Fluids inside and outside casing in the wellbore are initially at rest. There is no frictional pressure drop. Hydrostatic pressure of fluids inside the casing, Ph-c, equals hydrostatic pressure in the annulus, Ph-a:

Ph-c = Ph-a

However, when cementing is begun, frictional pressure drops of the fluids must be taken into account. The static condition is replaced by dynamic equilibrium at the bottom of the hole. The following equation applies at the bottom of the hole:

Ph-c – Pf-c + Pwh = Ph-a + Pf-a

where:

Pf-c = frictional pressure drop in the casing

Pf-a = frictional pressure drop in the annulus

Pwh = wellhead pressure

When heavier fluids (such as cement) travel down the casing, Ph-c will gradually increase and wellhead pressure Pwh will decrease until the surface pressure reading goes to zero. Free fall then begins, and the fluids now seek their own flow rates (Qout > Qin) to maintain the pressure equilibrium. Consequently, the well goes on a vacuum.

After time, as heavy fluids travel further down the well (or around the shoe), or as lighter mud is pumped behind heavier fluids, Qout begins to decrease and falls below Qin as the casing is gradually refilled. Once the fluid level in the casing reaches the surface, wellhead pressure is again required to displace the fluids.

The calculation algorithm is based on (1) the assumption that pumped fluids are incompressible, (2) a mass balance, and (3) an energy balance equation. Note that frictional pressures due to fluid movement impact hydraulics by resisting (decreasing) the flow rate. Frictional pressure drops in the casing influence bottom-hole pressures differently from those in the annulus.



28.6 Casing Wear Model

28.6.1 Volumetric Wear Rate of Casing Rotating tool joints that are subjected to lateral loads will wear crescent (“moon-shaped”) grooves in casing/risers. The Casing Wear model calculates the volume of material worn away in the crescent wear groove and from this calculates depth of the wear groove.

The volume of casing worn away in a unit length of casing in time, t, by a rotating tool joint equals:

V = E/e (in3/ft)

where

E = energy input per unit length (in-lb/ft)

e = specific energy (in-lb/in3 = lb/in2 = psi)

Specific energy is defined as the amount of energy required to remove a unit volume of metal.

Frictional energy, E, imparted to the casing is:

E = f Flat D (in-lb/ft)

where

f = friction factor (dimensionless)

Flat = lateral load on tool joint per unit length (lb/ft)

D = sliding distance (in)

Combining these two equations shows that wear volume, V, equals:

V = f Flat D/e (in3/ft)

Total sliding distance, D, between the tool joint and casing equals:

D = N d t (in)

where

N = rotary speed (rpm)

d = tool-joint diameter (in)

t = contact time (min)

Contact time, t, equals:

DP

TJ

LROP

LSt (min)

where

S = drilling distance (ft)

LTJ = tool-joint length (ft)

ROP= rate of penetration (ft/hr)

LDP = drill-pipe joint length (ft)

Tool-joint lateral load per foot, Flat, is:

TJ

DPDPlat L

LFF (lb/ft)

where FDP is average lateral load on the drill pipe (lb/ft).

Wear factor, WF, controls wear efficiency and is defined as:




WF = f/e (in2/lb = 1/psi)

DrillNET calculates total wear volume by dividing the total distance drilled into discrete intervals and estimating wear in each interval as follows:

n

1iiVV

where iV is the incremental wear volume for each

incremental drilling distance.

28.6.2 Wear Depth and Volume Geometry of the crescent wear groove is a function of casing ID (R) and tool-joint OD (r), and depth of penetration into the casing wall (h). It is important to note that volume of the worn crescent increases nonlinearly with wear depth because the wear groove becomes wider as wear depth increases.

An example wear-depth/wear-volume relationship is shown above for a 6½-in. tool joint rotating in 9⅝-in., 47-lb/ft casing. The casing is completely worn through when the groove wear volume reaches 22.1 in3/ft.

28.6.3 Nonlinear Correction Factors Experimental results from a large number of laboratory casing and riser wear tests showed that wear factors (see Section 28.6.1) are not constant for a given set of test conditions, but decrease with increasing wear depth and approach an asymptotic value as wear exceeds about 40%. Wear factors reported and used in most calculations are the asymptotic values.

Summary data from several laboratory tests were compared (see upper figure) and showed that variation of the wear factor as casing wear accumulates follows a very similar pattern for different casing loads. All of these tests were performed under the same standard test conditions with N-80 casing, steel tool joints, and water-base mud with 7% sand.

Based on this body of laboratory tests, an empirical casing-wear correction factor was developed to account for the observed wear-factor/wear-depth relation-ship. The nonlinear correction factor is used in DrillNET calculations and increases casing-wear values below about 40% penetration depth to a value greater than would be calculated using the asymptotic wear factor.

The standard correction factor for casing wear ranging from 0 to 50% is plotted at the right. The correction factor for casing wear above 50% is taken as unity (that is, the data are not corrected).

++

Rr

– –h

0

0.1

0.2

0.3

0.4

0 5 10

Wear Volum

Wea

r D

epth

(in

.)

Typical relationship between depth an> 6½” tool joint> 9⅝” casing; 0.47” wall

0

1

2

3

4

5

6

7

8

0 10 20 30 40 50Casing Wear (%)

Co

rrec

tio

nF

acto

r

0

10

20

30

40

50

60

0 10 20 30 40 50Casing Wear (%)

Wea

r F

acto

r (1

0-1

0/p

si)

+

++ + + + + + +

C7 (5000 lb/ft)C12 (7000 lb/ft)C63 (3000 lb/ft)C73 (7000 lb/ft)

+



To obtain corrected or adjusted casing-wear percentages, casing wear calculated using the asymptotic value of wear factor is multiplied by the correction factor shown in the graph. Note that nonlinear correction is applied only to the final casing-wear results. Internal computations use the constant value of wear factor and are not affected by the nonlinear correction.




Tool Jt 2

Tool Jt 3

Tool Jt 1

Kink

DrillPipe

Tool Joint String and

Bead Model

28.6.4 Wear in Seafloor Components Models and concepts used in the wear model were further developed to accommodate the geometry of a seafloor installation of an offshore well. Wear is addressed in the: (1) flex joint and (2) lowest riser joint.

The intermediate casing hangs from the well-head assembly on the sea floor. Immediately above this point is the BOP assembly. This assembly is about 40 ft high and has an internal drift diameter of 18¾ inches.

Based on MTI's modeling, observations from the field, and reports from our customers, BOPs have shown no significant wear in recent operations. The apparent reason is that mounting skill has improved and BOPs are normally well aligned. Consequently, in the casing wear model it is assumed that there is no offset angle at the casing/BOP intersection (i.e., the BOP and intermediate casing are coaxial) and drill-string contact force is minimized.

The flex joint is connected above the BOP. Its purpose is to accommodate any offset in the axial direction of the lowest joint of the riser and the BOP, while transmitting a minimum bending moment to the BOP assembly.

The lowest joint of the riser is connected to the upper end of the flex joint. The riser/flex-joint/casing system is modeled in the program. Three observations can be noted for this geometry:

1. The drill pipe, which is under tension load, will make initial contact with the top of the intermediate casing string and the lower flange of the flex joint at the center of rotation.

2. The offset angle at the top of the casing is independent of the offset angle at the flex joint as long as the offset angle at the flex joint is greater than zero.

3. If the offset angle at the flex joint is zero, there will be no contact with either the flex joint or the top of the intermediate casing.

For very small flex-joint offset angles (less than 0.5º), it is possible for the drill pipe to contact the top of the casing and not contact the flex joint or riser.

A model for the flex joint in offshore operations (the “String and Bead Model”) was presented by Poss and Hall (199533). The flex-joint model assumes that drill-pipe body stiffness is negligible, and that the drill-pipe body can be modeled as a limp string and the tool joints as beads.

The distance between beads is the length of one joint of drill pipe. The diameter of each bead is equal to the difference in diameter of the tool joints and drill pipe body. Thus, for 30-ft long joints of 5-in. drill pipe with 6⅝-in. diameter tool joints, the distance between beads is 30 ft, and the diameter of each bead is 1⅝ inches. Thus, tool-joint/drill-pipe clearance is 13/16 inches.

It has been found that this model is a good representation of a drill string under tension, provided the tension load is greater than 20,000 lbf.

As shown in the figure, the angular direction of the drill pipe can change either at a tool joint (Tool Joint 2 or 3) or in between tool joints (on the pipe body between Tool Joints 2 and 3). The lateral load on each tool joint is the product of the tension in the string and the sine of the angle , which represents the change in direction of the string as it passes through the flex joint. In addition, the drill string is pressed against the apex at the hinge point by a force which is the product of the string tension and the sine of the change in direction of the string as it passes the apex.

Flex Joint

Upper Annular Preventer

LMRP Connector

Lower Annular Preventer

Blind Shear Ram

Upper Pipe Ram

Lower Choke Valves

Middle Pipe Ram

Lower Pipe Ram

Wellhead Connector

UpperChokeValves

KillValves



TT

F

A

B

C

D

The relation of these factors is:

AB = BC = T = Tension

BD = F = Lateral Load

BAD = = Offset Angle

The riser assembly may include a stress joint rather than a flex joint. A stress joint’s diameter is usually tapered. Within the program, a section of riser with a stepped OD can be used to simulate a tapered stress joint. To enter a tapered joint into DrillNET, divide the joint into several sections (an increment of 10 ft is suggested), each with a uniform dimension. Enter data for each position on successive rows in the Wellbore data table on the Wellbore page.

28.6.5 Adding Tortuosity When planning a well, surveys generated mathematically from geometric considerations (i.e., kick-off point, build rate, path shape, etc.) are smooth curves. In real wells, doglegs and other irregularities are always present that increase drag and normal forces. These irregularities increase casing wear and must be considered. Adding tortuosity is a method of making torque and drag predictions more realistic by modifying mathematically generated survey data. This method for adding tortuosity was developed by Exxon and reported to MTI by Dr. Rap Dawson.

To add tortuosity to the well survey, sinusoidal variation with a period length (cycle length) is added to both inclination and azimuth angles. This is of the form:

Tortuosity = T sin(2 MD/)

where

T = amplitude or tortuosity number (deg)

MD = measured depth of each survey position (ft)

= period length or cycle length (ft)

In addition, inclination angle is modified in the program so that it does not become less than zero, since negative inclination angles are not defined.

The amplitude or tortuosity number T of the sinusoidal variation is set according to hole conditions. Dr. Russell Hall of MTI has typically recommended T = 0.7º as a starting value.

The tortuosity period is the length of one sine-wave cycle of the undulation to be superimposed on the survey. This value is generally greater than the distance between survey data points. It is recommended that be at least five times greater than the interval between survey stations.

Tortuosity is added to a survey by accessing the Tortuosity Utility. See Section 26.3 for more details.

28.6.6 Burst and Collapse of Worn Casing Wear reduces wall thickness and consequently pressure capacity of riser and casing strings. From an engineering perspective, these crescent-shaped wear grooves complicate assessment of pressure capacity for worn riser. Three methods are included in the program to calculate burst and collapse limits of grooved riser/casing. Users can select any model they prefer.

Biaxial Equations

Casing burst pressure, Pi, and collapse pressure, Po, can be calculated according to Lame's equation for thick cylinders and the von Mises equation (Popov, 197634). This approach uses the conservative assumption of minimum casing wall thickness to estimate pressure capacity. Note that this model assumes no axial stress in the casing.




API Equations

API Bulletin 5C3, 1989, “Formulas and Calculations for Casing, Tubing, Drill Pipe and Line Pipe Properties”35 (see that publication for details) lists all API standard equations for burst pressure limits, and four collapse pressure range limits. This approach also uses minimum casing wall thickness to estimate pressure capacity.

OTS Equations

The biaxial and API equations both use the minimum wall thickness instead of considering the actual non-uniform wall for calculating burst and collapse pressures. The former approach results in an underestimation or overestimation of internal and external pressure capacities, depending on the conditions.

Song et al. (199236) of Oil Technology Services Inc. proposed a new method to calculate hoop stress of crescent-shaped worn casing using bipolar coordinates and a complex mathematical approach. Their equations account for pressure reinforcement from the remaining unworn casing wall. It is reported that OTS’s predictions agreed with experimental results.

Note that for crescent-shaped worn casing, a higher hoop stress can occur at either the inside or outside surface. Therefore, the von Mises equivalent stress must also be evaluated for both surfaces to obtain pressure capacities.

28.6.7 Drill-Pipe Protector Requirements Drill-pipe protectors are, in general, only required in areas where doglegs are high and where high lateral loads on tool joints cause excessive casing wear. The Casing Wear model calculates the number of pipe protectors required for each pipe joint of the drill string. The number of pipe protectors is determined based on tool-joint loads and design factors for the pipe protector. Proper use of pipe protectors can reduce rotating torque and casing wear. The number of pipe protectors needed for each joint of pipe is calculated as follows:

NPP = required number of pipe protectors per joint of drill pipe

FTJ-max = maximum lateral load on unprotected tool joint (i.e., if the lateral load of tool joint is less than FTJ-max, then no pipe protector is needed)

FPP = maximum design load that can be supported by each pipe protector

FTJ = lateral load per tool joint

If FTJ < FTJ-max, then NPP = 0 (i.e., no protectors needed)

If FTJ FTJ-max, then

1F

FN

PP

TJPP (truncate to integer)



Casing

Borehole

Compression of Centralizer

Deflection of Pipe

Rhole R

pipe

28.7 Centralizer Design

28.7.1 Approach The conceptual approach used to model the areas of interest in the well is shown in the figure based on an inclined wellbore section as an example. Casing in an inclined wellbore section tends to contact the lower side of the wellbore due to casing weight. This prevents drilling mud from being completely displaced by cement slurry when conducting the cementing job.

To achieve a good cementing job and produce a good cement shell between the casing and wellbore wall, the casing centralizers are used to lift the casing up and keep a certain stand-off between casing and wellbore wall.

There are generally two types of casing centralizers:

(1) bow-spring

(2) rigid/positive.

The minimum stand-off between the casing and wellbore wall depends on casing deflection and centralizer compression when bow-spring centralizers are used.

When a rigid/positive centralizer is used, minimum stand-off depends on casing deflection and the difference in wellbore size and centralizer blade diameter. However, casing deflection and centralizer compression are dependent on centralizer spacing along the casing. The program is then developed to calculate the casing stand-off and determine proper spacing of the centralizer.

28.7.2 Casing Deflection Models

Juvkam-Wold and Wu Model (Fixed Ends)

This model (Juvkam-Wold and Wu, 1992) considers the fixed-end boundary for one span of casing between two centralizers:

sinhu

u - coshu u

2

u

u

24

I E 384

L Ny

2

4

3

max




2p

2dp NN N

δγ sin T2 cos LwN nedp

oep γ cos L wN

δ

φφθθγ

2 sin

sin sin sincos 12211-

o

2

sin

sin

2/ sincos 212 21-

n

θθ

δ

θθγ

u = EI4

TL2

where ymax = Maximum casing deflection, in.

E = Young's modulus, psi

= Moment of inertia of pipe, in4

L = Centralizer spacing, in.

N = Total lateral load, lbf

Ndp = Lateral load in dogleg plane, lbf

Np = Lateral load in the plane perpendicular to dogleg plane, lbf

T = Axial tension load, lbf

we = Casing weight in mud, lb/ft

= Inclination angle, deg

= One-half the change in angle in borehole, deg

1, 2 = Wellbore inclination angles at the two centralizer locations

1, 2 = Wellbore azimuth angles at the two centralizer locations

Lee et al. Model (Hinged Ends)

This model (Lee et al., 1984) considers the hinged-end boundary for one span of casing between two centralizers:

ymax =

4

2

4

u24

5coshu

11

2

u

EI

NL

384

5

and N = L

TW 2e

2e

We = We L sin

Te = 2 T sin

where N = Lateral load, lb/in

28.7.3 Centralizer Compression Compression of a bow-spring centralizer causes a decrease in casing stand-off. The larger the lateral load acting on a bow-spring centralizer, the larger the compression of the centralizer, and the larger the decrease of casing stand-off.



T+T

+; +M+M

N

F=f·N

W T

M=F·R;

Stand-off decrease due to centralizer compression is usually a non-linear function of lateral load, especially when lateral load becomes very large. For properly spaced centralizers, lateral load is not very large and a linear relation between centralizer compression and lateral load can be used.

By employing minimum restoring force measured by the centralizer manufacturer according to API 10D specifications, centralizer compression yc may be:

yc )R(R3RF

Npb

where N = Lateral load on centralizer, lbf

RF = Minimum restoring force, lbf

Rb = Wellbore radius, in.

Rp = Casing outside radius, in.

28.7.4 Rigid/Positive Centralizers For a rigid/positive centralizer, instead of centralizer compression, the difference between wellbore size and rigid/positive centralizer blade causes a decrease of casing stand-off.

This difference yd is:

yd = Rb – Rr

where Rr = the blade radius of rigid/positive centralizer, in.

28.7.5 Casing Stand-Off Minimum casing stand-off in the wellbore is considered to occur in the middle of a casing span between two centralizers. Due to casing deflection, centralizer compression, or the difference in rigid/positive centralizer blades and wellbore sizes, the minimum casing stand-off will be:

Standoff = Rb – Rp – ymax – yc (for bow-spring type) or Standoff = Rb – Rp – ymax – yd (for rigid/positive type)

= Rr – Rp – ymax

28.7.6 Frictional Force When Running Casing For running casing, frictional force is calculated by considering the normal force acting between the casing and the wellbore wall, when a bow-spring type of centralizer is not used. The force is composed of 1) the effects of the casing weight, and 2) the effects of the compression or tension acting through the curved wellbore. The frictional force is the product of the normal force and the friction factor (the coefficient of friction). The effect of bending on the normal force in a curved wellbore is not considered. It is assumed that its contribution to the normal force is small.

The figure shows the free-body diagram of a single (unit) element of the casing for the frictional force model of running into the wellbore (Johancsik, et al., 1984).

The normal force, N, is calculated as:

N = sinwF(sin(F e

The frictional force on this element is:




NfFf

The axial load increment is then:

θ coswFF ef

When a bow-spring type centralizer is used, running force (API Spec.10D, 1986) is simply used to calculate frictional force.

Frictional force for each centralizer is:

RNF Ff

where RNF is the running force of a bow-spring centralizer, lbf.

Axial load increment remains:

θ coswFF ef

28.7.7 Adding Tortuosity When planning a well, surveys generated mathematically from geometric considerations (i.e., kick-off point, build rate, path shape, etc.) are smooth curves. In the real world, a well contains doglegs and other irregularities that increase drag and normal force. Adding tortuosity is a method of making torque and drag predictions more realistic by modifying the survey data This method for adding tortuosity was developed by Exxon and reported to MTI by Dr. Rap Dawson.

To add tortuosity to the well survey, sinusoidal variation with a period length (or cycle length) is added to both inclination and azimuth angles. This is of the form

Tortuosity = T sin(2 MD/)

where

T = amplitude or tortuosity number (degrees) MD = measured depth (ft) = period length or cycle length (ft)

In addition, inclination angle is modified in the program so that it does not become less than zero, since negative inclination angles are not permitted.

The amplitude or tortuosity number T of the sinusoidal variation is varied according to hole conditions. Dr. Russell Hall of MTI typically recommends T = 0.7º as a starting value.

The tortuosity period is the length of one sine-wave cycle of the undulation to be superimposed on the survey. This value is generally greater than the distance between survey data points. Note that, in selecting the tortuosity period, one potential problem needs to be avoided. If the untortured survey data are equally spaced and the tortuosity period is assigned a value such that the measured depth of each survey station is n·/2 (where n is any integer), then after calculation the survey data will remain untortured. For these specified cases, the value of the tortuosity multiplier (sin 2 MD/) will be zero exactly at every station.

This means that the tortuosity period should not be assigned a value that is 2/n (2, 1, ⅔, ½, etc.) times the distance between survey stations. It is recommended that be at least five times greater than the interval between survey stations.

28.8 Torque & Drag for Liner Cementing Model The basis of the torque and drag program is a mathematical model developed by Exxon Production Research (Johancsik et al., 1984) that assumes the loads on the casing string result solely from effects of gravity and frictional drag from contact of the casing string with the wall of the hole. These frictional forces are the products of the normal force acting between the casing string and the wellbore, and the friction factor. Two contributions to the normal



force are considered for this model: 1) the effects of gravity on the pipe, and 2) the effects of tension and compression acting through curvatures in the wellbore. Although pipe bending may make minor contributions to normal force, its effect is neglected in this model.

The model considers the casing string to be made up of short segments joined by connections which transmit tension, compression and torsion, but not bending moment. The basic equations of friction are applied to each segment, with the calculations starting at the bottom of the casing string and proceeding upward to the surface. Each short element thus contributes small increments of torque, axial tension, drag and weight. These forces and torques are summed to produce the total loads on the casing string.

Variables

On the right is a simple free-body diagram of a single element of the drill string. Parameters required for analyzing torque and drag include:

f = friction factor

F = axial friction force

M = torque

N = normal force

T = tension

R = effective radius of element

= inclination angle

= azimuth angle

= incremental values

W = weight (including buoyancy)

Derivation of Equations

Axial motion without rotation is considered in this derivation. In analyzing each segment, the first requirement is calculating the magnitude of the normal force, N:

22sinsin WTTN

The tension increment is then calculated as follows:

NfF

FcosWT

a

or NfcosWT a

In these equations, a plus sign is used for upward motion (meaning axial drag adds to the effect of gravity), and a minus for downward motion (meaning axial drag subtracts from the effect of gravity).

When the string is rotating, there is no contribution from friction force (f = 0), so the equation is reduced to

T = W cos

During rotation, drag contributes to the incremental torque as follows:

M = f N R

Multi-Element Cases

As the calculation proceeds along the drill string, T + T becomes T for the element above the present calculation point and T contributes to the overall sum of torque required for rotation. When completed, the analysis yields tensile and torsional loads as functions of depth all along the string.




VrVa

Vc

Fc

FaF

Velocity

Frictional Drag

VcVr

Va

Rotation

Axial Drag

N = Wall Contact Force

DownwardTravel

Vr = Resultant Velocity Component

Va = Axial Velocity Component

Vc = Circumferential Velocity Component

Direction of Drag

Simultaneous Rotation and Reciprocation

The torque and drag model was expanded to compute torque and drag while simultaneously reciprocating and rotating the casing string. When simultaneous rotation and reciprocation are considered, the definition of variables must be expanded to:

Fa = axial friction force

Fc = circumferential friction force

F = total frictional force = 2c

2a FF

Va = axial velocity of a point on the circumference of the pipe

Vc = circumferential velocity of a point on the circumference of the pipe

Vr = resultant velocity of a point on the circumference of the pipe = 2c

2a VV

D = pipe diameter

Liner with Bow Spring or Rigid Free-to-Rotate Centralizer

Because bow-spring centralizers and rigid free-to-rotate centralizers do not rotate with the liner, axial and circumferential friction forces are different due to different contact surfaces. Axial friction force is generated at the contact between centralizer and wellbore:

Fa = faN where fa is the friction coefficient between the centralizer and wellbore. Circumferential friction force

arises at the contact between liner and centralizer:

Fc = fcN

Liner with Rigid Fixed-on-Casing Centralizer or Without Centralizer

The relation between axial, circumferential, and resultant velocities of the drill string relative to the wall of the hole with simultaneous rotation and reciprocation is shown in the figure.

Axial friction typically becomes very small if the pipe is rotated while it is moved axially. This occurs because the frictional drag force acts in a direction opposite

to the velocity of a point on the surface of the drill pipe. If the pipe is both rotating and moving axially, the velocity of the pipe relative to the hole is a combination of two vector quantities: axial velocity, Va, and rotational velocity, Vc,

which is the circumferential velocity of a point on the surface of the pipe equals :

Vc = D·rpm

where D is the pipe diameter, and rpm is the rotary speed of the pipe. Va is either drilling rate or tripping speed.

Va and Vc are perpendicular, and their resultant velocity, Vr, is the vector sum of these two quantities.

2a

2c

2r VVV

The magnitude of frictional drag, F, is dependent only on the product of the coefficient of friction and the normal force, N, that pushes the pipe against the wall of the hole. Frictional drag acts in a direction opposite to the resultant velocity of the pipe relative to the hole wall. This frictional drag can be resolved into components in exactly the same manner as the velocity of the pipe. One component opposes axial motion, while the other opposes circumferential motion (as shown).



T+T

+; +M+M

N

F=f·N

W T

M=F·R;

Since the two triangles shown in the figure are similar, the axial drag force equals:

r

aa V

VFF

and the circumferential drag force, Fc, equals:

r

cc V

VFF

For example, if 5-inch pipe is rotated at 150 rpm and moved axially at a rate of 10 ft/min, axial friction will be reduced to 5% of the value it would have been without simultaneous rotation (Va = 10 ft/min., Vc = 196.4 ft/min., Vr = 196.6 ft/min., Va/Vr = 0.051). This shows the importance of using a top drive in horizontal wells where torque and drag are high.

28.9 Torque & Drag for Drillstring Model

28.9.1 Torque and Drag Model The torque and drag model was derived based on developments by Exxon Production Research (Johancsik et al., 198437) that assume that loads on the drill string result solely from effects of gravity and drill-string frictional drag from contact of the drill string with the wall of the hole. These frictional forces are the products of the normal force acting between the drill string and the wellbore, and the friction factor. Three contributions to the normal force are considered for this model:

1. Effects of gravity on the pipe

2. Effects of tension and compression acting through curvatures in the wellbore

3. Pipe bending

The model considers the drill string to be made up of short segments joined by connections which transmit tension, compression and torsion, but not bending moment. The basic equations of friction are applied to each segment, with the calculations starting at the bottom of the drill string and proceeding upward to the surface. Each short element thus contributes small increments of torque drag, axial drag and weight. These forces and torques are summed to produce the total loads on the drill string.

Variables

On the right is a simple free-body diagram of a single element of the drill string. Parameters required for analyzing torque and drag include:

f = friction factor

F = axial friction force

M = torque

N = normal force

T = tension

R = effective radius of element

= inclination angle

= azimuth angle

= incremental values

W = weight (including buoyancy)

Derivation of Equations

Axial motion without rotation is considered in this derivation. In analyzing each segment, the first requirement is calculating the magnitude of the normal force, N:




VcVr

Va

Rotation

Axial Drag

N = Wall Contact Force

DownwardTravel

Vr = Resultant Velocity Component

Va = Axial Velocity Component

Vc = Circumferential Velocity Component

Direction of Drag

22sinWTsinTN

The tension increment is then calculated as follows:

NfF

FcosWT

a

or NfcosWT a

In these equations, a plus sign is used for upward motion (meaning axial drag adds to the effect of gravity), and a minus for downward motion (meaning axial drag subtracts from the effect of gravity).

When the string is rotating, there is no contribution from friction force (f = 0), so the equation is reduced to

T = W cos

During rotation, drag contributes to the incremental torque as follows:

M = f N R

As the calculation proceeds along the drill string, T + T becomes T for the element above the present calculation point and T contributes to the overall sum of torque required for rotation. When completed, the analysis yields tensile and torsional loads as functions of depth all along the string.

Simultaneous Rotation and Reciprocation

When simultaneous rotation and reciprocation are considered, the definition of variables must be expanded to:

Fa = axial friction force

Fc = circumferential friction force

F = total frictional force = 2c

2a FF

Va = axial velocity of a point on the circumference of the pipe

Vc = circumferential velocity of a point on the circumference of the pipe

Vr = resultant velocity of a point on the circumference of the pipe = 2c

2a VV

D = pipe diameter

The relation between axial, circumferential, and resultant velocities of the drill string relative to the wall of the hole with simultaneous rotation and reciprocation is shown in the figure.

Axial friction typically becomes very small if the pipe is rotated while it is moved axially. This occurs because the frictional drag force acts in a direction opposite to the velocity of a point on the surface of the drill pipe. If the pipe is both rotating and moving axially, velocity of the pipe relative to the hole is a combination of two vector quantities: axial velocity, Va, and rotational velocity, Vc, which is the circumferential velocity of a point on the surface of the pipe given by:

Vc = D·rpm

where D is the pipe diameter, and rpm is the rotary speed of the pipe. Va is either drilling rate or tripping speed.

Va and Vc are perpendicular, and their resultant velocity, Vr, is the vector sum of these two quantities.

2a

2c

2r VVV



Magnitude of frictional drag, F, is dependent only on the product of the coefficient of friction and the normal force, N, that pushes the pipe against the wall of the hole. Frictional drag acts in a direction opposite to the resultant velocity of the pipe relative to the hole wall. This frictional drag can be resolved into components in exactly the same manner as the velocity of the pipe. One component opposes axial motion, while the other opposes circumferential motion (as shown).

Since the two triangles shown in the figure are similar, the axial drag force equals:

r

aa V

VFF

and the circumferential drag force, Fc, equals:

r

cc V

VFF

For example, if 5-inch pipe is rotated at 150 rpm and moved axially at a rate of 10 ft/min, axial friction will be reduced to 5% of the value it would have been without simultaneous rotation (Va = 10 ft/min., Vc = 196.4 ft/min., Vr = 196.6 ft/min., Va/Vr = 0.051). This shows the importance of using a top drive in horizontal wells where torque and drag are high.

28.9.2 Applying the Model to a Drill String To apply the mathematical model in a stepwise fashion as shown earlier, specific information must be designated for each element. Each group of parameters is discussed below as they relate to drill-string design and/or operation.

Physical Size and Weight

One critical aspect of physical size is length of the element. When a stepwise solution is applied, physical size is the size of each increment as the calculation proceeds up the drill string. Diameter of the element is needed as the moment arm in the incremental torque calculation. This is obtained from a physical description of the drill string. Weight of the element, adjusted for the effects of buoyancy, is part of the tensile force balance. This information can be derived from a physical description of the drill string and a value for mud weight in the wellbore.

Spatial Orientation

Spatial orientation refers to the values for inclination and azimuth angle at both ends of the element. These are obtained from wellbore survey data.

Nature of Motion

The nature of the string motion determines the effect of the drag force. If the string is moving up and not rotating, drag force adds to the weight component of tension. With downward motion and no rotation, drag force decreases the weight component. If the element is rotating, drag is assumed to have no effect on tensile force, but it does add to the total torque required to rotate the string.

In terms of field operations, upward motion with no rotation occurs when raising the string (i.e., picking up or coming out of the hole). Downward motion with no rotation corresponds to lowering the string (i.e., slacking off or going in the hole). The string is rotated prior to drilling (no weight on bit) and during drilling (with weight on bit).

Using a top drive, it is possible to rotate while moving either up or down. When rotating, most of the frictional drag acts in the circumferential direction, leaving very little to oppose axial motion of the pipe. In a deviated or horizontal well, this will allow a greater measured depth to be achieved before approaching yield load of the drill pipe.

Loads at Bottom of Each Element

Tensile and torsional loads at the lower end of the element must be known prior to calculation for that element. The model takes the increment of tension due to drag and weight and adds this to the tension found at the lower end of the element. The same process applies to calculation of torque. However, this information does not have to be supplied for every element because the method uses the value calculated for the upper end of the element as the

VrVa

Vc

Fc

FaF

Velocity

Frictional Drag




initial value at the lower end of the element above the one currently under consideration. Thus, boundary conditions for tensile load and torsional load at the bottom of the string are all that is required.

Boundary Conditions

Boundary conditions at the bottom of the string will depend on the operation being simulated. When the string is going into the hole (slack off or drill), the bottom of the string is in compression. When the string is coming out of the hole (pick up), the bottom of the string is in tension. For drilling or string rotation, a positive value of torsion at the bottom of the string will simulate torque from the bit and BHA.

Friction Factor

Friction factor is a very important parameter because it characterizes surface-to-surface interaction central to the model. Much effort has been expended to obtain and verify typical friction factors for predictive work. The exact friction factor applicable to any particular situation is a function of many things, including drilling fluid type and composition, formation type (in open hole), casing material and condition (in cased hole), and tool-joint material and condition (e.g., roughness or presence of hard-metal coating).

At a single point in time, mud type and composition in the well is constant but there may exist significant portions of both cased and open hole. As a consequence, it may be necessary to use two friction factors, one for the drill-string/casing interaction and one for the drill-string/formation interaction.

28.9.3 Buckling Modes Drag and buckling predictions are very useful for planning drilling/completion/ workover operations and avoiding problems in the field. Compressive loads required to initiate sinusoidal and helical buckling modes are indicated on slack-off plots. Tubing yield limit is also shown. The significance of these stages of buckling is described below.

Sinusoidal Buckling

As compressive force is increased on a length of tubing lying along the bottom of an inclined hole, a point is reached where the tubing will assume a sinusoidal configuration (basically a two-dimensional snake-like undulation) side to side across the bottom of the hole. The axial force required to initiate this first mode of buckling is calculated in using one of three models selected by the user (on the Preferences page).

Parameters that affect the sinusoidal buckling limit (axial load above which the pipe begins to buckle) include:

cross sectional area of pipe

Young’s modulus of pipe

moment of inertia of pipe cross section

radial clearance between pipe and borehole

pipe density

inclination of hole

Helical Buckling

If the compressive load is increased beyond the point where sinusoidal buckling occurs, helical buckling will eventually be initiated. In this buckling mode, the tubing forms a helix (spiral) against the wall of the hole (a three-dimensional shape like a stretched spring). The pitch of the helix decreases as compressive load is increased. Helical buckling begins when axial compressive force is about 1.4 times the value of the sinusoidal critical load (based on the assumption of a straight hole).



28.9.4 Which Buckling Criterion Should I Use? As indicated above, the smallest critical force is the compressive load that initiates sinusoidal buckling. Next is the critical compressive force that shifts the tubing from sinusoidal to helical buckling. Finally, axial load increases to the point where the tubing begins to yield. What is the safe upper limit for job planning?

Field experience with buckling has been reported by several authors and participants in MTI projects, especially with respect to CT operations. Newman et al. (198938) along with numerous authors since indicate that tubing can safely be pushed into a hole using compressive loads considerably in excess of the sinusoidal buckling limit. In the field cases reported, compressive forces greater than the sinusoidal limit have been used to push CT into inclined holes. A great number of field operations have also verified that compressive forces larger than the helical buckling limit can safely be used to push pipe into deviated holes.

The buckling yield criterion is normally significantly higher than the helical buckling limit. This condition is closely associated with lock up. After the drill pipe or CT locks up and just begins to yield, significant additional force may be placed on the string before it fails completely, but little additional penetration will be achieved. The yield limit with an appropriate safety factor is a practical upper bound for tubing forces. The design factor applied to the tubular limits is applied to the output graphs and should be based on practical experience.

Buckling criteria should be used carefully and as guides rather than as absolute indicators. Judgment based on experience, though sometimes expensive to acquire, is of great value when dealing with buckling and all its implications. Buckling itself does not imply failure, but it indicates the onset of a condition which may precipitate failure.

28.9.5 Which Buckling Model Should I Use? Three different models for calculating sinusoidal and helical buckling loads are provided. These include:

Sinusoidal Buckling Helical Buckling

1. Dawson/Paslay (Exxon) 39 1. Chen/Cheatham (Rice University) 40

2. Wu/Juvkam-Wold (Texas A&M) 41 2. Wu/Juvkam-Wold42

3. He/Kyllingstad (Rogaland Research) 43 3. He/Kyllingstad44 From a historical perspective, the Dawson/Paslay buckling model was developed first and published in 1984. It quickly became accepted and widely applied. Chen/Cheatham published their model for helical buckling in 1990. The other models were developed later (Wu/Juvkam-Wold and He/Kyllingstad were both published in 1993) and sought to examine and improve the assumptions and boundary conditions of the earlier models.

There are two primary areas where these buckling models differ.

Straight Wellbores

For straight wellbore sections (that is, wellbore sections where the inclination is not changing; for example, horizontal sections), the primary difference between the three models is the nature of the changing axial load in the load range between sinusoidal and helical buckling. The assumption made by Chen/Cheatham is that the axial load present between the

Normal forceagainst wall

0

Sinusoidal

Helical

Lock-Up

0

0

Input Force Transmitted Force

End View




N1

Cycles to Failure (log scale)

Str

ess

(lo

g s

cale

)S1

Original S/N Curve

Effect of Miner's Rule on S/N Curve (Bannantine et al., 1990)

N1

S/N Curve afterApplication of Stress

S1 for n1 Cycles

n1

N1

Cycles to Failure (log scale)

Str

ess

(lo

g s

cale

)S1

Original S/N Curve

Effect of Miner's Rule on S/N Curve (Bannantine et al., 1990)

N1

S/N Curve afterApplication of Stress

S1 for n1 Cycles

n1

development of sinusoidal buckling and the onset of helical buckling is constant. Since the load does actually increase between these two buckling modes, Chen/Cheatham used a constant value that is the average axial load during the helical buckling process.

Wu/Juvkam-Wold proposed that, rather than the average load, a linearly increasing load should be assumed for the helical buckling process. The result of this difference in assumptions is that Wu/Juvkam-Wold predicts a helical buckling limit that is about 30% higher than Chen/Cheatham. Again, note that this applies for straight sections.

The sinusoidal buckling load in a straight hole section is the same for all three buckling models.

Curved Wellbores

Buckling criteria in curved wellbore sections (where the inclination is changing) can be significantly different depending on the model selected. Tubing that is constrained in a curved wellbore is already bowed and will be supported against the bottom side of the curve. Much greater axial loads are required in curved wellbores to force the tubing to lift off the bottom of the hole and buckle. Dawson/Paslay and Chen/Cheatham do not consider the impact of curvature on the development of buckling.

Wu/Juvkam-Wold and He/Kyllingstad both consider the impact of wellbore curvature on the onset of buckling. Their analysis and experiments showed that, the larger the build rate, the larger the load to initiate buckling in curved wellbores with increasing inclination. Wu/Juvkam-Wold also model the increasing axial load between sinusoidal and helical buckling in curved wellbores, and consider the difference in length of the inner and outer curve of the casing. He/Kyllingstad assume a constant load (as did Chen/Cheatham) and ignore the length difference.

Comparison of Models

Due to the differences in these assumptions of axial loads and buckling in curved wellbores, buckling models in the Torque/Drag model can produce different results. This is especially true for helical buckling in curved sections with increasing inclination (going to horizontal, etc.). Generally, Chen/Cheatham will produce the lowest (most conservative) helical buckling load criterion, He/Kyllingstad a higher load, and Wu/Juvkam-Wold the highest.

In analyses of this type, engineers often tend to choose the most conservative model to “play it safe.” However, since the constraining effect of a curved wellbore can be very significant, it is most probable that Chen/Cheatham is too conservative in these instances; that is, the drill pipe or CT string can be subjected to much higher loads without buckling helically.

28.10 Drill-String Life Model

28.10.1 Approach to Modeling Fatigue The program models areas of interest in calculating maximum drill-string bending stress and employing S/N curves (stress versus cycles to failure) to predict fatigue damage. This approach is based on the assumption that bending stress is maximum at the middle of one jointed drill pipe when compressive axial load is applied. Alternatively, it is usually maximum next to the tool joint when tensile axial load is applied. Bending stress is treated the same along a curved wellbore for slick pipe without tool joints and is based only on the curvature of the wellbore. After a jointed drill-pipe body contacts the wellbore wall, maximum bending stress for compression loads is in the portion of drill pipe not in contact with the wellbore wall, whereas it is still located next to the tool joint for the tension load case.



When bending stress is less than the fatigue endurance limit, e, it is assumed that there is no fatigue damage. Tubular fatigue damage occurs only when the bending stress exceeds e. The fatigue endurance limit is the alternating stress for which failure occurs at 106–108 cycles (see upper figure) for engineering purposes. Fatigue damage is calculated by using each tubular’s S-N curve and applying the linear damage rule or Miner’s rule (see lower figure).

28.10.2 Drill-Pipe Bending Under Axial Tension

DrillNET’s basic drill-pipe bending model is based on Lubinski’s model (196145). For axial tension load without contact with the drill-pipe body, maximum bending stress occurs next to the tool joint (at x = 0):

q

)kLtanh(

kL)qC(

2

EDmaxb

or it may occur at the middle of one joint of drill pipe (at x = L) when the axial tension is small:

q

)kLsinh(

kL)qC(

2

EDmaxb

where:

E = Young’s modulus

D = drill-pipe OD

C = wellbore curvature

q = IEk

sinQ2

Q = effective weight/length

= average inclination angle

L = half the length of each joint

When axial tension is present, the drill-pipe body is pulled straighter and will eventually contact the wellbore wall when axial tension becomes sufficiently large. The first contact is a point contact. Maximum bending stress is always located next to the tool joint (at x = 0) for this case:

q

)kLsinh(

)1)kL(cosh(skL)qC(

2

ED 0maxb

where:

s0 = shear force at 0 (next to tool joint)

As axial tension continues to increase, the drill-pipe body point contact changes into arc contact, with a portion of drill pipe in the middle contacting the wellbore wall. Maximum bending stress still occurs next to the tool joint (at x = 0) and can be calculated using the above equation. However, the length of the portion not in contact must be determined by trial and error.

104

Cycles to Failure (cycles)

Alt

ern

ati

ng

Str

ess

(ks

i)

40

60

80

100

120

Example S/N Diagram

106103 105

S1000 = 110 ksi

Se = 60 ksiSn = 83 ksi

N = 2.4104 cycles




28.10.3 Drill-Pipe Bending Under Axial Compression

When axial compression loads are present without drill-pipe body contact, maximum bending stresses occur at the middle of the joint of drill pipe:

q

)kLsin(

kL)qC(

2

EDmaxb

As compression loads are increased, drill-pipe deflection increases and the drill-pipe body contacts the wellbore wall. The first type of contact is point contact. Maximum bending stress now occurs within the portion of the drill pipe not in contact with the wall:

bmax = Co2 cos(kL2) + so sin(kL2) – q

As axial compression load is further increased, the drill-pipe body contact changes from point into arc contact, with a portion of drill pipe in the middle of the joint contacting the wellbore wall. Maximum bending stress still occurs within the portion of the drill pipe not in contact with the wall. However, the length of the non-contact portion must be determined first by trial and error. Then, the equation above is used to calculate maximum bending stress.

28.10.4 Drill-String Fatigue Damage Provided the maximum bending stress of the drill string is less than the fatigue endurance limit, there is no fatigue damage. Drill-pipe maximum bending stress is affected by wellbore build rate/dogleg severity. The larger the wellbore build rate/dogleg severity, the larger the drill-pipe bending stress.

If maximum bending stress is set equal to the fatigue endurance limit, the permissible build rate/dogleg severity for no fatigue damage is then resolved. For axial tensile loads, the permissible build rate/dogleg is determined by:

qkL

)kLtanh(q

ED

2C e

where e = fatigue (endurance) limit.

When drill-pipe bending stress is larger than the fatigue endurance limit, fatigue damage occurs. According to current fatigue theory, the drill pipe does not fail from fatigue until the cumulative fatigue damage reaches unity. Drill-pipe fatigue damage is calculated as:

i

ii N

nD

where

ni = drill-pipe revolutions when maximum bending stress level is Si

Ni = cycles (revolutions) to failure of drill pipe at a bending stress level of Si

Cumulative fatigue damage is the sum of the fatigue damage from each previous bending stress:

3 4 5 6 7 82

Bending Cycles (10x cycles)

Ben

din

g S

tre

ss (

ksi

)

0

20

40

60

80

100

120

140

160

Grade S-135

Grade G

Grade E (J. Hansford)

Titanium (Ti-6Al-4V)

Titanium (Beta-C)

Aluminum (J. Hansford)

Beryllium Copper

Drillpipe Fatigue S/N Curves

3 4 5 6 7 82

Bending Cycles (10x cycles)

Ben

din

g S

tre

ss (

ksi

)

0

20

40

60

80

100

120

140

160

Grade S-135

Grade G

Grade E (J. Hansford)

Titanium (Ti-6Al-4V)

Titanium (Beta-C)

Aluminum (J. Hansford)

Beryllium Copper

Drillpipe Fatigue S/N Curves



i

ii N

nD

Drill-pipe fatigue failure then occurs when Di 1.

Several S-N curves are provided for drill-pipe fatigue damage calculations (see figure above). These are developed from published test data on full-scale drill pipes, or from modifying the small sample test results (Boyer, 198646) by considering the size effect. Pipe yield strength is used to define the highest point of the S/N curves at 1000 revolutions to failure.

Axial load (mean stress) and drilling fluid corrosion also need to be considered in modifying S-N curves to correctly calculate fatigue damage. Axial tension results in a lower S-N curve, while axial compression raises the S-N curve. The Goodman line is often used to modify the S-N curves for axial tensile loads. However, the benefit from compression loads is usually not considered, resulting in a conservative estimate of fatigue damage.

Drilling fluid corrosion also reduces the S-N curve value (see figure). The more corrosive the drilling fluid is, the more the reduction of the S-N curve. The lower the bending stress is, the larger the S-N curve value reduction. A 40% reduction was proposed by Lubinski47 for severe corrosive drilling fluid when calculating fatigue endurance limits. Reduction at other bending stress levels is considered linearly, with life decreasing as the bending stress is increased.

28.10.5 Drill-Pipe/Collar Crack-Growth Model Dale (198948 and 198849) with Exxon conducted fatigue-crack growth tests by cyclically loading notched specimens, and developed an analytical model which accurately predicts fatigue-crack growth under different loading conditions. Exxon’s model assumes an initial crack length (e.g., 0.050 inch) and calculates crack growth to failure when the crack penetrates the wall thickness. This model does not predict the time or number of cycles required to initiate a crack. It only calculates crack growth after a crack has been initiated.

The crack-growth correlation by Dale (198950) is used to predict inspection intervals:

n

c

o

o

o

d

dFN

where

N = fatigue-crack propagation life (cycles)

Fo = fatigue-crack propagation life constant

o = bending stress at pipe body or connection surface (psi)

do = pipe body diameter (in)

dc = diameter of pipe body, connection box or connection pin as appropriate (in)

n = fatigue-crack growth rate exponent

Fo and n were measured for various pipe materials, including API Grade E, API Grade X, API Grade G and S, and 4145 Mod Steel.

28.10.6 Inspection Sensitivity and Reliability

104

Cycles to Failure (cycles)

Alt

ern

atin

g S

tres

s

107103 105

Corrosion Fatigue

Effect of Environment on S/N Curve for Steel (Fuchs and Stephens, 1980)

108106

Pre-soak

Air

Vacuum




No reliable method exists to measure the amount of fatigue damage a component may have accumulated. Current technology is limited to inspecting the tubulars for fatigue cracks, and even when inspections are performed properly, they can still occasionally fail to detect small cracks. Most of the fatigue life of a tubular component will have been consumed by the time a crack has formed and grown large enough to be detected by inspection, so a fatigue crack, once detected, is cause for immediate rejection of the component.

Magnetic particle inspection (MPI) is used for the detection of surface and near-surface flaws in ferromagnetic materials. A magnetic field is applied to the specimen, either locally or overall, using a permanent magnet, electromagnet, flexible cables or hand-held probes. If the material is sound, most of the magnetic flux is concentrated below the material’s surface. However, if a flaw is present, such that it interacts with the magnetic field, the flux is distorted locally and leaks from the surface of the specimen in the region of the flaw. Fine magnetic particles applied to the surface of the specimen are attracted to the area of flux leakage, creating a visible indication of the flaw. The materials commonly used for this purpose are black iron particles and red or yellow iron oxides. In some cases, the iron particles are coated with a fluorescent material enabling them to be viewed under a UV lamp in darkened conditions. MPI is often used to inspect for cracking at welded joints and in areas identified as being susceptible to environmental cracking (e.g. stress corrosion cracking or hydrogen induced cracking), fatigue cracking or creep cracking.

When MPI is used to inspect drill-string connections, the probability of detecting cracks is low (see figure). Consequently, the calculated inspection interval for drill-string connections is usually reduced by a factor of 6 to achieve a 99% probability of detecting existing cracks.

It is important to understand how the drill string behaves under different operating conditions, because dynamic stresses that exist along the string affect its life and that of the bit. These stresses also affect drilling rate and possibly hole stability.

28.11 Triaxial Stresses Model

28.11.1 Tubing Stresses An element of material subjected to stresses σx, σy, and σz in three perpendicular directions is said to be in a state of triaxial stress. Tubes in wellbores subjected to both axial load and pressure (external and/or internal pressure) are under triaxial stress.

The generally accepted relationship for the influence of axial stress on collapse or burst is based on distortion energy theory. A closed triaxial design procedure was developed using Von Mises’ and Lame’s equations. Models included in DrillNET do not consider the impact of torsion.


0.040

Flaw Depth (in.)P

rob

ab

ility

of

De

tec

tio

n (

%)

0

20

40

60

80

100

0.080.02 0.100.06

MPI(Connections)

EMI(OD Surface)

EMI(ID Surface)


0.040

Flaw Depth (in.)P

rob

ab

ility

of

De

tec

tio

n (

%)

0

20

40

60

80

100

0.080.02 0.100.06

MPI(Connections)

EMI(OD Surface)

EMI(ID Surface)



Di

Do

t

Fa

Fa

Po

Pir

ha

Parameters that impact triaxial stress include:

E = elastic modulus (psi)

Do = pipe OD (in.)

Di = pipe ID (in.)

ro = pipe outside radius (in.)

ri = pipe inside radius (in.)

σs = yield stress (psi)

Fa = axial force (lb)

DL = dogleg (°/100 ft)

SF = safety factor

Pi = internal pressure (psi)

Po = external pressure (psi)

28.11.2 Triaxial Stress Equations Pipe thickness is

2

DDt io

Cross-sectional area of the pipe wall is

4

DDA

2i

2o

Average axial stress is

A

Faa

Maximum bending stress caused by a dogleg is

000,432

DDLE oDL

Minimum axial stress becomes

a-min = a – DL

Maximum axial stress is

a-max = a + DL

Maximum allowable axial stress is

SFa

SFa

and this maximum allowable axial stress is based on zero pressure and zero bending stress. After stress is converted to force, maximum allowable axial force is

Fa-SF = a-SF A

Positive Square-Root Solutions

Max Operating Pressure

Negative Square-Root Solution

Min Operating Pressure

Operating Pressure

Axial Stress

Min

Axi

al S

tres

s

Avg

Axi

al S

tres

s

Max

Axi

al S

tres

s




Burst pressure, Pi, and collapse pressure, Po, can be calculated according to Lame’s equation for a thick tube and Von Mises’ equation (Popov, 197651). Mathematically, there can be one, two, or no solutions for collapse pressure design. When bending stress is considered, both minimum and maximum axial stresses are used in collapse and burst calculations.

Note that when axial stress, σa, is replaced by σa-min and σa-max, both σa-min and σa-max can have a positive square-root solution. If this happens, the model uses the smaller of the two positive square-root solutions as the upper boundary for collapse design. In the same way, the program will take the larger value from two negative square-root solutions as the lower pressure boundary for collapse design.

Buckling phenomenon, especially helical buckling, will cause bending stresses. Buckling stress effects are not considered in the Triaxial Stresses model.

28.11.3 Biaxial Stress Equations Biaxial stress analysis is a simplified form of triaxial analysis. If we disregard the effect of internal pressure on collapse pressure design, i.e., Pi = 0, the triaxial collapse calculation is reduced to the biaxial collapse calculation. When Po = 0, the triaxial burst calculation is also reduced to the biaxial burst calculation.

28.11.4 API Stress Equations Equations for calculating tubing stress based on API’s guidelines are presented in API Bulletin 5C3, 1989, “Formulas and Calculations For Casing, Tubing, Drill Pipe and Line Pipe Properties.”52

28.12 Hydraulics for Normal Circulation Model

28.12.1 Fluid Rheology Models The rheological models most commonly used in the drilling/boring industry to describe fluid behavior are the Newtonian, Bingham plastic and power-law models. A lesser used hybrid model, the Herschel-Bulkley model, is also provided. These fluid models can be used to calculate frictional pressure drops, cuttings-carrying capacity, swab and surge pressures, etc. Fluid models provided in DrillNET are largely based on equations derived in Bourgoyne et al. (199153) and API Spec 10.



Newtonian Fluid Model

Newtonian fluids are those for which shear stress is directly proportional to shear rate. Examples of Newtonian fluids are water, air, nitrogen, glycerin, and light oil. A single parameter, viscosity, characterizes these fluids.

Newtonian fluid rheology is defined by the equation below and illustrated in the figure.

where:

= shear stress

µ = fluid viscosity

= shear rate

Bingham-Plastic Fluid Model

Many fluids used in drilling/completion operations are non-Newtonian, that is, with shear stress not directly proportional to shear rate. Fluids are often shear thinning, which indicates they have less viscosity at higher shear rates than at lower shear rates.

Bingham-plastic fluids are among the most common drilling muds. These fluids will not flow until the applied shear stress exceeds a certain minimum value known as the yield point (YP). After YP is exceeded, changes in shear stress are proportional to shear rate with the constant of proportionality called the plastic viscosity (PV). Thus, two parameters, PV and YP, are used to characterize these fluids. Because these constants are determined between specified shear rates of 500 to 1000 sec-1, this model is used to characterize fluids in the higher range of shear rates.

The Bingham-plastic rheology model is defined below and illustrated in the figure.

= p + y ; > y

= 0 ; y -y

= p – y ; < -y

where:

= shear stress

y = yield stress

µp = fluid viscosity

As shown in the figure, a threshold shear stress known as the yield point (y) must be exceeded before mud movement is initiated. The mud properties µp and y are calculated from 300- and 600-rpm readings of the viscometer as follows:

µp = 600 – 300

y = 300 – µp

where:

600, 300 = shear readings at 600 and 300 rpm

Power-Law Fluid Model

The power-law fluid model is another advanced rheology model used for shear-thinning or pseudoplastic drilling fluids. The relationship between

Kn=

Shear Rate, .

.

She

ar

Str

ess

,

Power-Law Model

n<1

=

Shear Rate, .

.

She

ar

Str

ess

,

Newtonian Model

p y

=

Shear Rate, .

p

.

She

ar S

tres

s,

Bingham Plastic Model

+

+y




shear stress and shear rate is an exponential function, that is, a straight line when plotted on a log/log scale. Two constants, n and K, are determined from data at any two speeds.

The power-law model is defined by:

= K n

where:

K = consistency index, in equivalent centipoise (see Bourgoyne et al., 1991)

n = flow behavior index, dimensionless

The power-law model can be used to represent a shear-thinning fluid (with n <1), a Newtonian fluid (with n = 0), or a shear-thickening fluid (with n > 1). Deviation of the flow-behavior index, n, from unity characterizes the degree to which the fluid is non-Newtonian.

Fluid properties n and K are calculated as follows:

300

600log32.3n

n

300

511

510K

(equivalent cp)

Occasionally, the consistency index is expressed in units of lbf·sn/ft2. The two units of consistency index can be related (at sea level) by:

1 lbf·sn/ft2 = 47,900 equivalent cp

Herschel-Bulkley Fluid Model

The Herschel-Bulkley model is another advanced rheology model used for shear-thinning or pseudoplastic drilling fluids. The relationship between shear stress and shear rate is an exponential function (similar to the power-law model). These fluids will not flow until the applied shear stress exceeds a certain minimum value known as the yield point (similar to the Bingham-plastic model). This model can thus be considered as a hybrid combination of the Bingham-plastic and power-law models.

A typical drilling fluid exhibits both a yield stress and shear thinning. At high shear rates, all models represent typical drilling fluids reasonably well. Differences between these models are most pronounced at low shear rates. It has been observed that a typical drilling fluid exhibits behavior intermediate between the Bingham-plastic and power-law models; therefore, the Herschel-Bulkley model was developed.

28.12.2 Flow and Pressure Drop Calculations

Newtonian Fluids

From a practical perspective, Newtonian fluids may be considered a special case of Bingham-plastic fluids. Equations for flow and pressure drop for Bingham-plastic fluids can be used with yield point (y) set to zero.

Bingham-Plastic Fluids

Calculation of frictional pressure drop for a pipe or annulus requires knowledge of the flow regime (laminar or turbulent). Fluid velocity is the first required calculation.

Mean Velocity

Mean fluid velocity is calculated for flow inside a pipe and through an annulus as follows.

For pipe flow:

2d448.2

Qv

Shear Rate, .

She

ar S

tres

s,

Herschel-Bulkley Model+y

Kn y= +.



For annular flow:

)dd(448.2

Qv

21

22

where:

v = mean velocity, ft/sec

Q = flow rate, gal/min

d = pipe diameter, in.

d2 = casing or hole ID, in.

d1 = drill string OD, in.

Critical Reynolds Number

The critical Reynolds number marks the transition from laminar flow to turbulent flow. The correlation between Hedstrom number (a common dimensionless parameter) and critical Reynolds number is shown in the figure. When yield stress (y) is zero (that is, Newtonian fluids), the critical Reynolds number is approximately 2100.

Reynolds Number

Reynolds number, NRe, is another common dimensionless fluid flow parameter. Values above the critical Reynolds number indicate that the flow is turbulent under the given conditions; values below the critical point indicate laminar flow.

Frictional pressure drop is then calculated for laminar flow (where NRe < Critical NRe) or for turbulent flow (NRe Critical NRe).

Power-Law Fluids

Before frictional pressure drop can be calculated for a power-law fluid, the critical Reynolds number must be determined so that flow regime can be determined.


The critical Reynolds number can be read from the chart for a given flow behavior index n as the point where the solid inclined line and the corresponding “n” curve intersect.

The data in this figure can be approximated by the following (Leitão et al., 1990):

Critical NRe = 4200 for n < 0.2

Critical NRe = 5960 – 8800 n for 0.2 n 0.45

Critical NRe = 2000 for n > 0.45

Special correlations are then used to calculate frictional pressure drop for power-law fluids.

Pressure Drop Across the Bit

Three assumptions are incorporated for calculating pressure drop across the drill bit:

1. The change in pressure due to change in elevation is negligible.

2. Upstream velocity is negligible compared to nozzle velocity.

3. Friction pressure drop across the nozzle is negligible.

Hedstrom Number103 104 106 107

Cri

tica

l Rey

no

lds

Nu

mb

er

103

104

105

105




Nozzle velocity equals

Tn A117.3

QV

where:

Vn = nozzle velocity, ft/sec


AT = total nozzle area, in2

Bit pressure drop equals

2T

2d

2

bAC032,12

QP

where Cd = discharge coefficient factor (recommended value = 0.95) (Bourgoyne et al., 199154).

The total pressure drop in the system is:

Ptot = Pp + Pa + Pb

where:

Pp = sum of pressure losses inside the pipe

Pa = sum of pressure losses in the annulus

Accordingly, pump horsepower (PHP) is

1714

QPPHP tot

Surface Equipment Pressure Loss

Surface equipment consists of the standpipe, hose, swivel wash pipe and gooseneck, and the kelly. Four common combinations of surface equipment are provided.

To estimate the overall pressure drop more closely, curves of surface equipment pressure losses versus flow rate for various combinations were developed based on a table in the Hydraulics Manual by Security Drill String Systems. Equations were generated to fit these curves.

For coiled-tubing operations, frictional pressure drop in the surface equipment is calculated from the length of the remaining tubing on the reel. Calculation dimensions will be taken from those in the topmost section of the drill string (coiled tubing).

Equivalent Circulating Density

Of particular importance is the equivalent circulating density (ECD) at a given depth. The ECD is the density of fluid that will have the same hydrostatic pressure as the circulating pressure.

)gal/lb(TVD052.0

PECD

where:

P = pressure at the point of interest, psi

TVD = true vertical depth, ft

Reynolds Number102 103 105 106

Fri

ctio

n F

acto

r

10-3

10-2

10-1

10-4

104

n=1.00.80.6

0.4

0.2



28.12.3 Slip Velocity and Cuttings Transport Removal of drilled rock/soil fragments from the annulus is one of the primary functions of the drilling mud. Particle slip velocity, which defines the rate at which a cutting of a given diameter and specific gravity settles out of the fluid, is often of concern to the drilling engineer. Unfortunately, accurate prediction is difficult because of the complex geometry and boundary conditions.

Two correlations are provided. It should be noted that these are valid only for vertical sections of the well. As hole angles begin to increase from vertical, cuttings transport efficiency begins to fall.

Moore Correlation

Moore proposed a procedure for determining the slip velocity through a mud system. His method involves obtaining the apparent Newtonian viscosity as follows:

0208.0

n/12

v

DD

144

Kμ

n-I

a

pha

where:

av = mean annular velocity

The particle Reynolds number is calculated, which requires slip velocity of the cuttings. Slip velocity is obtained using iterative techniques.

Chien Correlation

Chien’s correlation uses a similar calculation of an apparent Newtonian viscosity for use in the particle Reynolds number determination. Apparent viscosity is calculated using

a

sypa v

d5

The particle Reynolds number is calculated similarly to the Moore correlation and then used to determine the flow regime and slip velocity based on special correlations.

Both the Moore and Chien correlations may required several iterations before they converge on a solution.

28.12.4 Hydraulics and Well Planning For optimizing hydraulics, it is sometimes necessary to estimate pump operating conditions and nozzle sizes during the planning phase of the well. Data required for planning include the mud program, hole geometry, and assumed flow rate. The model is used to calculate the frictional pressure drop at various planning depths. Based on frictional pressure drop, the program calculates the optimum hydraulics with a criterion of either maximum jet impact force or maximum hydraulic horsepower.

Results of hydraulics optimization only indicate optimized total nozzle area. Since a jet bit may have two, three, or more nozzles, a large number of nozzle size combinations will closely approximate the optimized total nozzle area. The program calculates several potential combinations of nozzle diameters for two-, three-, four-, and five-nozzle designs. The area variance for each combination is also given.

28.13 Hydraulics for Surge/Swab Model The models used for calculating frictional pressure drops for normal circulation can also be applied to determine surge and swab pressures if the running speed of the drill pipe is known. Surge pressure is the pressure increase caused by pushing drill pipe into the well. Pressure decreases from withdrawing pipe from the well are called swab pressures.

For closed pipe, the estimated annular velocity is (Moore, 197455):




p21

22

21 v

dd

dAv

where:

v = average annular fluid velocity, ft/min

A = clinging constant (recommended value = 0.45)

vp = pipe running speed, ft/min

Moore suggested using maximum fluid velocity to account for acceleration and deceleration of the pipe. In general, maximum fluid velocity equals:

Vm = 1.5 v

Surge and swab pressures are calculated by substituting mean velocity in the frictional pressure drop equations in Section 28.12.2 with maximum fluid velocity.

28.14 Hydraulics for Underbalanced Drilling

28.14.1 Definitions Several common terms encountered in underbalanced drilling, especially foam drilling, are defined below.

1. Foam and mist drilling. Foam consists of fresh water, a surface-active agent (surfactant), and gas. Liquid in the foam fluid constitutes the continuous phase, with air dispersed as discontinuous bubbles. On the other hand, mist is a continuous gas phase containing discontinuous liquid droplets.

2. Foam quality. The ratio of volume percentage of gas to total fluid volume is termed foam quality. Since gas is compressible, foam quality depends on pressure and temperature.

3. Stiff foam. Stiff foam is comprised of a gel-base mud and surfactant combination with excellent hole-cleaning and wall-cake building characteristics. However, salt water or calcium causes gel to break down and ball up.

4. Stable foam. Stable foam is a regime in which liquid is the continuous phase and air (gas) is the discontinuous phase. Foam becomes unstable or is converted to mist when foam quality exceeds 96–97%.

5. Wet and dry foam. Low-quality foams are referred to as “wet” foams, while high-quality foams are called “dry” foams.

28.14.2 Fluid Rheology Models Rheological models most commonly used in the drilling/boring industry to describe fluid behavior are the Newtonian, Bingham-plastic and power-law models. These fluid models can be used to calculate frictional pressure drops, cuttings-carrying capacity, swab and surge pressures, etc. Fluid models provided in UBD are largely based on equations derived in Applied Drilling Engineering (Bourgoyne et al., 199156) and API SPEC 10.




where:

= shear stress

=

Shear Rate, .

.

She

ar

Str

ess

,

Newtonian Model




= shear rate



Bingham-plastic fluids are among the most common drilling muds. These fluids will not flow until the applied shear stress exceeds a certain minimum value known as the yield

point (YP). After YP is exceeded, changes in shear stress are proportional to shear rate with the constant of proportionality called plastic viscosity (PV). Thus, two parameters, PV and YP, are used to characterize these fluids. Because these constants are determined between specified shear rates of 500 to 1000 sec-1, this model is used to characterize fluids in the higher range of shear rates.

The Bingham-plastic rheology model is defined below and illustrated in the figure.

= p + y ; > y

= 0 ; y -y

= p – y ; < -y

where:

= shear stress

y = yield stress

µp = plastic viscosity

As shown in the figure, a threshold shear stress known as the yield point (y) must be exceeded before mud movement is initiated. Mud properties µp and y are calculated from 300- and 600-rpm readings of the viscometer as follows:

µp = 600 – 300

y = 300 – µp

where:



The power-law fluid model is another advanced rheology model used for shear-thinning or pseudoplastic drilling fluids. The relationship between shear stress and shear rate is an exponential function, that is, a straight line when plotted on a log/log scale. Two constants, n and K, are determined from data at any two speeds.


= K n

where:


p y

=

Shear Rate, .

p

.

She

ar S

tres

s,


+

+y

Kn=

Shear Rate, .

.

She

ar S

tres

s,

Power-Law Model

n<1





The power-law model can be used to represent a shear-thinning fluid (with n<1), a Newtonian fluid (with n=0), or a shear-thickening fluid (with n>1). Deviation of the flow-behavior index, n, from unity characterizes the degree to which the fluid is non-Newtonian.


300

600log32.3n

n300

511

510K

(equivalent cp)



Foam Models

Due to the unique complexity of foam flow, neither the Bingham-plastic nor power-law rheology models can be readily applied to foam. This has motivated many investigators to apply traditional non-Newtonian continuum rheological approaches with modifications to describe flow behavior of foams. Both theoretical treatment and experimental studies are ongoing.

One theoretical approach to the rheology of foam was presented by Einstein (190658). His foam viscosity equation for foam quality between 0 and 54% is:

f = (1.0 + 2.5 )

where:

f = viscosity of foam

= viscosity of base liquid

= foam quality (fraction)

Hatschek's (1910A & B59) equation for viscosity of bubble-interference foam for foam quality between 0 and 74% is:

f = (1.0 + 4.5 )

A second theory by Hatschek describes viscosity of foam caused by shear of the fluid between parallelepiped gas bubbles. Foam quality for this theory ranges from 75% to 100% and is expressed as:

f =

3/11

1

It should be noted that this equation does not apply at the limiting case of 100% foam quality.

Mitchell (196960) demonstrated that foam behaves as a Bingham-plastic fluid based on his experimental work in capillary tubes and empirically derived equations for foam viscosity.

f = (1.0 + 3.6 ) , 0 54%

f =

49.01

1 , 54% 100%

Again, this equation does not apply for pure gas flow. Krug presented plastic viscosities and yield strengths of foam as a function of foam quality.



Bayer et al. (197261) first formulated a foam rheological model from laboratory and pilot-scale experimental data. Their observations suggested that foam behaves like a Bingham-plastic fluid. Their study did not demonstrate a dependence of (shear stress yield) on liquid volume fraction or foam quality.

Sanghani and Ikoku (198362) experimentally studied foam rheology with a concentric annular viscometer that closely simulated actual hole conditions. They concluded that foam is a power-law pseudoplastic fluid with both flow behavior index n and flow consistency K, both of which are functions of foam quality.

Some researchers found that the power-law model was statistically superior to the Bingham-plastic model in correlating data. Other researchers’ data showed that foam more closely obeys the Bingham-plastic model. UBD includes three options for rheology models: Bingham plastic, Power-law, and Chevron's model. Chevron's model is described by Bayer et al. (197263).

28.14.3 Foam Flow Equations In the special case of a two-phase system such as foam, gas is finely and uniformly dispersed in the liquid phase, homogeneous fluid can be assumed, and no equation is required for the phase interface. Foam consists of a compressible component (gas) and an incompressible component (liquid). The incompressible component is easier to handle because of its constant density. Compressible gas requires much more attention, since its density depends on temperature and pressure.

Pressure is coupled with gas volume fractions through a friction factor. An improved version of Lord's (198164) pressure drop equation and Spoerker et al.'s (199165) method are used in the following derivation. Friction factor is calculated along the wellbore rather than assumed to be constant.

Equations of State

The relationship between the variation of density of a fluid with pressure and temperature is termed the equation of state. For engineering purposes, the most practical form of the equation of state for a real gas is called the Engineering Gas Law and is given by (Grovier and Aziz, 198766):

Vg = PM

ZRT

g

where:

Vg = specific volume of gas (ft3/lb)

Z = gas compressibility factor

Mg = molecular weight of gas (lbm/lb-mole)

R = gas constant, 10.73 (psia-ft3/lb-mole/°R)

T = absolute temperature (°R)

P = absolute pressure (psia)

Mechanical Energy Equations

Once the equations of state for foam have been established, the next step is to use the momentum and energy equations to analyze dynamic foam behavior. The mechanical energy equation may be considered either a consequence of the momentum equation or a reduced form of the total energy equation. For downward flow inside drill pipe, the differential mechanical energy balance equation is:

Dg

d(MD) f2u dp V

g

(VD) d g -

g

du u

c

2

cc

= 0

where

u = average velocity of the foam, ft/s

f = Fanning friction factor




g = acceleration due to gravity

gc = 32.2 (ft-lbm)/(lbf-s2)

MD = measured depth, ft

VD = vertical depth, ft

D = tubing ID, in.

Average velocity of foam, u, can be obtained using the continuity equation. In terms of specific volume, it can be expressed as:

u = cV = bcp

ac

where the coefficient, c, depends on mass flow rates and flow area.

After substituting, the differential mechanical energy balance takes the form:

pMD,F d(MD)

dpp

For upward flow in the annulus, the differential mechanical energy balance equation takes the form of:

0)D - (Dg

d(MD) f 2u - dp V

g

(VD) d g -

g

du u

phc

2

cc

where Dh = open-hole diameter, in.

Dp = drill-pipe OD, in.

Average velocity of foam in the annulus is also described by u = cV. However, the variable c for upward annular flow is different.

Substituting annular velocity into the above equation will yield the following differential mechanical energy balance for the upward annular flow:

p)DM,(Fd(MD)

dpA

Pressure Drop Across Nozzles – Foam Flow

To calculate pressure drop through a short constriction such as a bit nozzle (see figure), it generally is assumed that (1) the change in elevation is negligible, (2) velocity upstream of the nozzle is negligible, and (3) frictional pressure loss across the nozzle is negligible. Thus, the differential mechanical energy balance becomes

0 dp V g

du u

c

Substituting and integrating yields the following expression in field units:

ln a PPb 12 0U10 x 8.1P

P 2n

4-

1

2

where

P1 = pressure upstream of the nozzle

P2 = bottom-hole pressure

Bottom of Hole

Bit Nozzle

Un

P1

P2

U0



Un = nozzle velocity

Nozzle velocity Un is defined as

'bcP

ac'U

2n

The field expression above can be solved numerically to obtain pressure upstream of nozzle P1. Bottom-hole pressure P2 is calculated beforehand.

Pressure Drop Across Nozzle – Air/Mist Flow

Calculation of pressure drop across a nozzle for air/mist flow can be found in Lyon's Air and Gas Drilling Manual. To maximize air/gas turbulence at the cuttings surface, high-speed supersonic flow of air/mist must be maintained at the bit nozzles during normal drilling operations. Pressure drop across nozzles is calculated as follows:

a. Calculate bottom-hole pressure, Pb, using the equation for air/mist/foam flow

b. Assume pressure in the drill string above the bit, Pa, is maintained at a level

Pa b

1-k

k

P1k

2

where

k = ratio of specific heats for air (or gas)

Pb = magnitude of pressure in annulus at bottom of hole (lb/ft2 abs)

For this case, sonic or supersonic flow will exist across the bit nozzles. The expression above defines the critical pressure ratio. Flow of air/gas through nozzles is, therefore, governed by

G = 2/1

a

an

2/1

1-k

1k

T

PA

1 k

2

R

Sgk

where

G = weight rate of air/gas flow through nozzles (the system) (lb/sec)

S = specific gravity of gas (air is 1.0)

R = gas constant (53.3 ft-lb/lb-°R)

k = ratio of specific heats for air (or gas)

g = acceleration due to gravity (32.2 ft/sec2)

An = total area of bit nozzles, ft2

Pa = pressure in air (or gas) above bit nozzles, lb/ft2 abs

Ta = temperature of air (or gas) above bit nozzles, °R

If pressure ratio Pa/Pb is less than the critical ratio defined previously, the assumption of subsonic flow is justified. Flow of air/gas through nozzles (open orifices) is then governed by the expression

G = An

2/1

k

1-k

b

ab b 1

P

PP

1 - k

2gk

where b = Specific weight of air above bit (lb/ft3)




28.14.4 Influx Modeling One of the advantages of foam drilling is low BHP, which increases the rate of penetration. However, influxes of gas, water or oil can occur as a result of low BHP. These influxes will change the existing foam system, resulting in a change in the pressure profile inside the drill pipe as well as in the annulus.

Total liquid density may be calculated from rates and densities of injected liquid and those of water/oil influxes.

N

iiiooL ff

where:

o = density of inlet liquid

fo =

N

liio

o

qρ

q

fI =

N

liio

i

qρ

q

qo = liquid injection rate

qi = water/oil influx rate

N = number of water/oil influxes

Final liquid viscosity can be calculated in a similar fashion.

Molecular weight of the mixture of injected gas and influx gas can be calculated using weighting factors similar to those used for calculating liquid density and viscosity. That is

M

liigiogog fMfMM

where

Mgo = molecular weight of inlet gas

Mgi = molecular weight of influx gas

fo =

N

ligigo

go

mm

m

fI =

M

ligigo

gi

mm

m

mgo = mass rate of inlet gas

mgi = mass rate of influx gas

N = number of gas influxes

Equations of state for gas and upward annular foam flow should use these adjusted parameters for annular positions above the influx points.

28.14.5 Cuttings-Carrying Capacity

Cuttings Slip Velocity in Foam Flow



Another advantage of foam drilling is high cuttings-carrying capacity. For example, both yield point and plastic viscosity of Bingham-plastic foam will increase as foam quality is increased. This will increase effective viscosity of foam and enhance cuttings-carrying capacity. Particle slip velocity, which defines the rate at which a cutting of a given diameter and specific gravity settles out of the fluid, is also of concern to drilling engineers. UBD includes Moore's (Bourgoyne et al., 1986) correlation to determine slip velocity through a foam system.

Moore's correlation estimates apparent Newtonian viscosity as follows:

0208.0

n/12

U

DD

144

KnI-

a

phaμ

where Ua = mean annular velocity

The particle Reynolds number is:

a

sslfRe μ

dV928pN

where f = foam weight, lb/gal

Ds = particle diameter, in.

Vsl = slip velocity, ft/s

In the above equation, slip velocity Vsl is undetermined and must be obtained by iteration. For Reynolds numbers greater than 300, slip velocity is:

f

fsssl

d54.1V

where s = solid density, lb/gal

For Reynolds numbers of 3 or less, slip velocity becomes:

fs2

2s

sl μ

d87.82V

For Reynolds numbers between 3 and 300, an approximation of slip velocity is:

1/32

1/3f

3/2fss

slμ

d90.2V

Cuttings Slip Velocity in Air/Mist Flow

Cuttings slip velocity in air/mist flow is calculated using an equation derived by Gray (195867). For flat particles (shales and limestones), slip velocity is:

2/1

sssl 1

T371.0d6.1V

where s = cuttings density, lbm/ft3

T = local temperature, °R

P = local pressure, psia

For subrounded particles (sandstones), slip velocity is:

2/1

sssl 1

P

T0.371d1.2V




Cuttings Transport Ratio

Cuttings transport ratio is defined by:

a

slt U

V1F

For positive cuttings transport ratios, cuttings will be transported to the surface with more or less transport efficiency. For negative cuttings transport ratios, cuttings will accumulate and become concentrated in the annulus. Therefore, this is an excellent measure of the carrying capacity of a particular drilling mud.

Note that the slip velocity equations above are derived for vertical flow only.

28.15 Hydraulics for HTHP Wells

28.15.1 Fluid Models Rheological models most commonly used in the drilling/boring industry to describe fluid behavior are the Newtonian, Bingham plastic and power-law models. These fluid models can be used to calculate frictional pressure drops, cuttings-carrying capacity, swab and surge pressures, etc. Fluid models provided in HTHPFLOW are largely based on equations derived in Applied Drilling Engineering (Bourgoyne et al., 1991) and API SPEC 10.




where:

= shear stress


= shear rate



Bingham-plastic fluids are among the most common drilling muds. These fluids will not flow until the applied shear stress exceeds a certain minimum value known as the yield point (YP). After YP is exceeded, changes in shear stress are proportional to shear rate with the constant of proportionality called the plastic viscosity (PV). Thus, two parameters, PV and YP, are used to characterize these fluids. Because these constants are determined between specified shear rates of 500 to 1000 sec-1, this model is used to characterize fluids in the higher range of shear rates.

Bingham-plastic rheology model is defined below and illustrated in the figure.

= p + y ; > y

= 0 ; y -y

= p - y ; < -y

where:

= shear stress

=

Shear Rate, .

.S

hea

r S

tres

s,

Newtonian Model

p y

=

Shear Rate, .

p

.

She

ar S

tres

s,


+

+y



y = yield stress µp = fluid viscosity

As shown, a threshold shear stress known as the yield point (y) must be exceeded before mud movement is initiated. Mud properties µp and y are calculated from 300- and 600-rpm readings of the viscometer as follows:

µp = 600 – 300

y = 300 – µp

where:



The power-law fluid model is another advanced rheology model used for shear-thinning or pseudoplastic drilling fluids. The relationship between shear stress and shear rate is an exponential function, that is, a straight line when plotted on a log/log scale. Two constants, n and K, are determined from data at any two speeds.


= K n

where:



The power-law model can be used to represent a shear-thinning fluid (with n < 1), a Newtonian fluid (with n = 0), or a shear-thickening fluid (with n > 1). Deviation of the flow-behavior index, n, from unity characterizes the degree to which the fluid is non-Newtonian.


300

600log32.3n

)cpequivalent(511

510K

n

300



28.16 Flow and Pressure Drop Calculations Newtonian Fluids

From a practical perspective, Newtonian fluids may be considered a special case of Bingham-plastic fluids. Equations for flow and pressure-drop calculations for Bingham-plastic fluids can be used with yield point (y) set to zero.

Bingham-Plastic Fluids

Calculation of frictional pressure drop for a pipe or annulus requires knowledge of the flow regime (laminar or turbulent). Fluid velocity is the first required calculation.

Mean Velocity

Mean fluid velocity is calculated for flow inside a pipe and through an annulus as follows.

For pipe flow:

Kn=

Shear Rate, .

.

She

ar

Str

ess

,

Power-Law Model

n<1




2d448.2

Qv

For annular flow:

)dd(448.2

Qv

21

22

where: v = mean velocity, ft/sec Q = flow rate, gal/min d = pipe diameter, in. d2 = casing or hole ID, in. d1 = drill string OD, in.


Critical Reynolds number marks the transition from laminar flow to turbulent flow. The correlation between Hedstrom number (a common dimensionless parameter) and critical Reynolds number is shown in the figure. When yield stress (y) is zero (that is, Newtonian fluids), critical Reynolds number is approximately 2100.

Reynolds Number

Reynolds number, NRe, is another common dimensionless fluid flow parameter. Values above the critical Reynolds number indicate that the flow is turbulent under the given conditions; values below the critical point indicate laminar flow.

Frictional pressure drop is then calculated for laminar flow (where NRe < Critical NRe) or for turbulent flow (NRe Critical NRe).

Power-Law Fluids

Before frictional pressure drop can be calculated for a power-law fluid, the critical Reynolds number must be determined so that flow regime can be determined.


Critical Reynolds number can be read from the chart for a given flow behavior index n as the point where the solid inclined line and the corresponding “n” curve intersect.

Data in this figure can be approximated by the following (Leitão et al., 1990):

Critical NRe = 4200 for n < 0.2

Critical NRe = 5960 - 8800 n for 0.2 n 0.45

Hedstrom Number103 104 106 107

Cri

tica

l Rey

no

lds

Nu

mb

er

103

104

105

105

Reynolds Number102 103 105 106

Fri

cti

on

Fac

tor

10-3

10-2

10-1

10-4

104

n=1.00.80.6

0.4

0.2



Critical NRe = 2000 for n > 0.45

Special correlations are then used to calculate frictional pressure drop for power-law fluids.

Pressure Drop Across the Bit

Three assumptions are incorporated for calculating pressure drop across the drill bit:

1. The change in pressure due to change in elevation is negligible.

2. Upstream velocity is negligible compared to nozzle velocity.

3. Friction pressure drop across the nozzle is negligible.

Nozzle velocity equals

Tn A117.3

QV

where:

Vn = nozzle velocity, ft/sec


AT = total nozzle area, in2

Bit pressure drop equals

2T

2d

2

bAC032,12

QP

where Cd = discharge coefficient factor (recommended value = 0.95) (Bourgoyne et al., 1991).

Total pressure drop in the system is:

Ptot = Pp + Pa + Pb

where:

Pp = sum of pressure losses inside the pipe

Pa = sum of pressure losses in the annulus

Accordingly, pump horsepower (PHP) is

1714

QPPHP tot

Surge and Swab Pressures

The models used for calculating frictional pressure drops can also be applied to determine surge and swab pressures if the running speed of the drill pipe is known. Surge pressure is the pressure increase caused by pushing drill pipe into the well. Pressure decreases from withdrawing pipe from the well are called swab pressures.

For closed pipe, the estimated annular velocity is (Moore, 1974):

p21

22

21 v

dd

dAv

where:

v = average annular fluid velocity, ft/min A = clinging constant (recommended value = 0.45) vp = pipe running speed, ft/min




Moore suggested using maximum fluid velocity to account for acceleration and deceleration of the pipe. In general, maximum fluid velocity equals:

Vm = 1.5 v

Surge and swab pressures are calculated by substituting mean velocity in the previously presented frictional pressure drop equations with maximum fluid velocity.

Equivalent Circulating Density

Of particular importance is the equivalent circulating density (ECD) at a given depth. The ECD is the density of fluid that will have the same hydrostatic pressure as the circulating pressure.

)gal/lb(TVD052.0

PECD

where:

P = pressure at the point of interest, psi

TVD = true vertical depth, ft

28.17 Slip Velocity and Cuttings Transport Removal of drilled rock/soil fragments from the annulus is one of the primary functions of the drilling mud. Particle slip velocity, which defines the rate at which a cutting of a given diameter and specific gravity settles out of the fluid, is often of concern to the drilling engineer. Unfortunately, accurate prediction is difficult because of the complex geometry and boundary conditions.

Two correlations are provided in HTHPFLOW. It should be noted that these are valid only for vertical sections of the well. As hole angles begin to increase from vertical, cuttings transport efficiency begins to fall.

Moore Correlation

Moore proposed a procedure for determining the slip velocity through a mud system. His method involves obtaining apparent Newtonian viscosity as follows:

0208.0

n2

v

DD

144

K 1nI-

a

phaμ

where:

av = mean annular velocity

The particle Reynolds number is computed, which requires slip velocity of the cuttings. Slip velocity is obtained using iterative techniques.

Chien Correlation

Chien’s correlation uses a similar computation of an apparent Newtonian viscosity for use in the particle Reynolds number determination. Apparent viscosity is calculated using

a

sypa v

d5

The particle Reynolds number is calculated similarly to the Moore correlation and then used to determine flow regime and slip velocity based on special correlations.

Both the Moore and Chien correlations may required several iterations before they converge on a solution.



28.18 Well Planning For optimizing hydraulics, it is sometimes necessary to estimate pump operating conditions and nozzle sizes during the planning phase of the well. Data required for planning include the mud program, hole geometry, and assumed flow rate. The model is used to calculate frictional pressure drop at various planning depths. Based on frictional pressure drop, the program calculates the optimum hydraulics with a criterion of either maximum jet impact force or maximum hydraulic horsepower.

Results of hydraulics optimization only indicate optimized total nozzle area. Since a jet bit may have two, three, or more nozzles, a large number of nozzle size combinations will closely approximate the optimized total nozzle area. The program calculates several potential combinations of nozzle diameters for two-, three-, four-, and five-nozzle designs. The area variance for each combination is also given.

28.19 Cuttings Transport Ratio Cuttings transport ratio is defined by the following equation:

a

slt v

v1F

where:

vsl = slip velocity

For positive cuttings transport ratios, cuttings will be transported to the surface with more or less transport efficiency. For negative cuttings transport ratios, cuttings will become concentrated in the annulus. Therefore, this is an excellent measure of the carrying capacity of a particular drilling mud.

28.20 Effects of Temperature and Pressure on Viscosity Temperature Effect

As temperature increases, effective viscosity decreases. As a general rule, the effect of temperature is high for oil-based fluids containing asphalt, moderate for oil-based fluids with oil-wet inorganic solids as viscosifiers, and relatively low for water-based fluids.

Pressure Effect

As pressure increases, effective viscosity increases. As a general rule, the effect of pressure is greater for oil-based fluids with asphaltic viscosifier than those that use oil-wet inorganic solids as viscosifiers.

Correcting for Temperature and Pressure

Using viscosity based on surface conditions for calculating hydraulics may give erroneous results. For accuracy, viscosity of the drilling fluid should be determined at temperatures and pressures encountered in the well. This requires a high-temperature/high-pressure viscometer for data collection and a computer to analyze the data. Corrections can then be made to surface conditions.

Correction factors are average values obtained from measurements on various types of drilling fluids under conditions of high temperature and high pressure. Although the use of these correction factors will give good estimates, they are not as accurate as viscosities obtained by measurement under downhole conditions. The following figures show correction factors used with water-based fluids, oil-based fluids containing asphalt, and oil-based fluids containing oil-wet inorganic viscosifiers.




Downhole Viscosity Correction Factor (Water-Based Mud)

Downhole Viscosity Correction Factor (Oil Muds Containing Asphalt)

Temperature (°F)125 150 200 250 300

Co

rrec

tio

n F

acto

r

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1.1

Temperature (°F)150 200 250 350 400

Co

rrec

tio

n F

acto

r

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

0300

20,000 psi

16,000 psi12,000 psi8,000 psi4,000 psi

0 psi



Downhole Viscosity Correction Factor (Oil Muds Containing Oil-Wet Inorganic Viscosifiers)

28.21 Dynamic Kill for Slim Holes Model The basic challenge in slim-hole applications is that the smaller annular space means a given volume of gas kick will occupy a greater height. This greater height of lighter fluid will result in a greater reduction of hydrostatic pressure on the kicking formation.

Conventional well control techniques entail quick shut-in and then monitoring of drill-pipe and annular pressures while slowly circulating the kick out and increasing mud weight to prevent further kick influx. However, safe hydraulics and well control can be significantly affected by slim annuli. This problem has at least two facets:

1. Small annular capacity in a slim-hole well reduces kick tolerance and requires well-control systems to be capable of detecting kicks much smaller than conventional.

2. Conventional well-control techniques are based on the assumption that annular pressure losses are a small fraction of total circulating pressure losses. Thus, a slight overbalance can be maintained at the formation under static conditions, and ECDs while circulating can be kept safely below fracture gradients. This assumption is often not valid in slim-hole wells due to high friction pressure losses for fluid flow in the annulus.

After a well is shut in after a kick, formation pressure is balanced on the drill-pipe side by mud weight and shut-in drill-pipe pressure (SIDP). On the annulus side, pressure is balanced by the influx weight, mud weight and shut-in casing pressure (SICP). SICP will usually exceed SIDP due to the loss of hydrostatic head on the annulus side.

The wellbore pressure balance changes when the kick is circulated out after shut-in. Frictional loss in the drill pipe acts in the opposite direction to circulation pressure and mud weight. In the annulus, pressure from frictional losses acts in the same direction as influx weight, mud weight and choke pressure. The effects of friction during circulation cause an increase in pressure drop on both the drill-pipe side and annulus side. The magnitude of frictional loss is usually greater on the annulus side due to a slim (restricted) flow area.

High frictional losses in the annulus, even at slow circulating rates, are the primary complication for slim-hole well control. Because of this, dynamic well kill has been implemented as an alternative in certain situations. This method calls for utilizing increases in ECD to overcome flowing formation pressure by quickly increasing the pump rate or rotary speed.

Temperature (°F)150 200 250 350 400

Co

rrec

tio

n F

acto

r

0.5

1.0

1.5

2.0

2.5

3.0

3.5

0300

20,000 psi

16,000 psi

12,000 psi8,000 psi4,000 psi0 psi




Wellbore Soil

Temperature Nodes

Tk,1 Tk,2 Tk,3

RR

Cell Boundary

Mud rheology has a significant impact on the magnitude of frictional losses in the annulus. Drill-pipe rotation also impacts annular frictional losses. In some muds, the transition from laminar to turbulent flow is also marked by an increase in frictional loss.

Dynamic kill requires kick detection systems capable of detecting small kick volumes (often as small as 1 barrel). Kicks are most likely to occur when the pumps are shut down, such as during connections. Detecting influxes during these periods can be more difficult due to changing pit levels and flow rates. Effective slim-hole kick-detection systems must be able to track well status during periods of pump shut-down. In slim coring operations, swab pressures while removing the core barrel can be compensated for by circulating down the drill string via a lubricator system.

28.22 Wellbore Thermal Simulation

28.22.1 Wellbore Description Two basic wellbore fluid flow models are included in DrillNET’s thermal simulation model: (1) a well completion designed for production or injection; and (2) a well completion in which fluid is circulated. In the figures, the tube in the center is the production tubing or drill pipe; the casings outward in order are: production casing, intermediate casing, surface casing, conductor pipe, and finally borehole. Outside the borehole is rock formation.

28.22.2 Numerical Grid Three temperatures are calculated in the wellbore at each depth (see figure). Radial boundaries of mathematical cells are located at the well centerline, at the outside surface of the tubing or drill pipe, and at the first casing string (production casing). The location of the outer boundary of the third cell is the radial position outside of the wellbore/rock interface. The distance from the borehole wall to the outer boundary is equal to the distance from the outside of the first casing string to the borehole wall, i.e., the centerline of the third cell is located at the well and rock interface (the radial location of the third temperature node).

The first node corresponds to fluid in the tubing or drill pipe, which represents flowing production, injection or circulating fluid temperature, or simply a temperature near the center of the well during shut-in. The second node is for fluid in the annulus, which represents annular fluid temperature during circulation.

Cement

Annulus Fluid

Injected Fluid

Production/ Injection Model

Cement

Annulus Fluid

Circulated Fluid

Circulation Model



Heat conducted along the well axis in the wellbore is ignored. Axial step length is set as 200 ft (default value), or as specified by the user, and radial step length is generally a few inches to a few feet. Axial temperature gradients are much less than radial temperature gradients for most applications. Fluid and rock cells are selected for computing node temperatures.

For thermal modeling of horizontal and deviated holes, it is reasonable to assume that the trajectory of a wellbore is on a plane. It is only necessary to calculate temperature on a plane that is perpendicular to the trajectory plane.

28.22.3 Solids Properties Material properties of solids in and around a well must be determined to properly model heat flow. Modeled solids include cement, rock, and steel. Because thermal properties are often not significantly different between two types of the same general material, DrillNET uses only one set of properties each for cement and steel.

Thermal properties required are density, specific heat capacity, and thermal conductivity. All solids properties are treated as constants. The table lists the default properties initially assigned to each solid.

28.22.4 Liquid Injection, Production, and Circulation

Fluid Properties

Material properties of the fluids in a well strongly influence heat transfer between the well and rock. Fluid properties must be defined in a thermal simulation, including density, viscosity, specific heat capacity, and thermal conductivity.

Fluid viscosity strongly affects heat transfer by convection. The power-law and Bingham-plastic fluid models are used to calculate viscosity for non-Newtonian fluids present in most wells. Rheological properties of high-solids muds and weighted muds (specific gravity greater than 1.5) are approximately those of a Bingham fluid. Properties of low-solids muds and diluted muds are similar to those of a power-law fluid. Effective viscosity is defined as the ratio of shear stress to shear strain rate:

eff = K n-1 (power-law fluids)

eff = p + 0 (Bingham-plastic fluids)

where K is the consistency index, n is the power-law exponent, µp is plastic viscosity (or coefficient of rigidity), and o is yield point. Shear strain rate () can be calculated from fluid properties, fluid volume flow rate, and well geometry.

If viscometer readings R600, R300, R200, and R100 are the only rheological data available, effective viscosity may be calculated from these readings.

Temperature is an important variable for determining fluid viscosity. All fluid properties are assumed to be measured at 70°F (21°C). The impact of temperature changes on viscosity is automatically updated.

Specific heat capacity is used to determine sensible heat and energy accumulation in a fluid. The value of specific heat capacity for a particular fluid is related to the solids fraction in the fluid. It is assumed that all fluids are derived by adding solids to water.

Coupling Rock and Well

Thermal conductance must be formulated to describe transfer of heat between the wellbore and rock. When heat flows between the rock and well, it passes through various combinations of steel, cement, fluid, and rock. Conductance is calculated from well geometry and properties of these materials. Heat passes from temperature

Thermal Properties of Solids

Material Density(lbm/ft3)

Specific Heat Capacity

(BTU/lbm-F)

Thermal Conductivity

(BTU/hr-ft-F) Cement 104 0.20 0.60 Rock 140 0.30 0.92 Steel 490 0.11 26.1




z

g 2

T2

V2

P2

Constant Area Flow Cell

1

T1

V1

P1

nodes (j, 2) to (j, 3) through a composite radial system of various materials. The rate of heat flow through such a system may be written as:

q = U z T

where U is the thermal conductance.

Convection Coefficient

Convection in wellbore fluids can significantly influence the rate of heat transfer from a well to the surrounding rock formation. When fluid flows past a solid surface, heat transfer that occurs between fluid and solid surfaces is called convection heat transfer. The rate of heat transfer through a solid surface is:

q = h T

where T is the temperature difference between the fluid and solid, and h is the convection coefficient.

The rate of heat transferred across the annular region is increased by natural convection, which can be expressed in terms of an effective thermal conductivity, Keff.

Energy Balance in a Fluid Cell

Energy in a fluid cell must obey the first law of thermodynamics; that is, energy must balance. This law leads to an equation of the form:

1ni,jT = Aj, i

1ni,1jT

+ Bj, i 1ni,1jT

+ Cj, i 1n1i,jT + Dj, i

1n1i,jT + Ej, i (

ni,jT + n

i,1jT )+ Fj, i 1n

1i,1jT + Gj, i

1n1i,1jT

This equation can be written for every position of j, i in the wellbore to yield a system of simultaneous linear algebraic equations. Unknowns are temperatures at each node at time step n+1 for a total of 3Nz equations and unknowns, where Nz is the number of nodes in the vertical direction.

Energy Balance in a Rock Cell

Energy balance is also required for each cell containing rock. This requirement is met by:

1ni,jT = Aj, i

1ni,1jT

+ Bj, i 1ni,1jT

+ Cj, i 1n1i,jT + Dj, i

1n1i,jT + Ej, i

ni,jT

This equation may be applied to all nodes in the formation to produce a system of (Nr–3) Nz simultaneous algebraic equations, where Nr is the number of nodes in the radial direction. An equal number of unknowns exist for temperatures at the nodes.

As described in previous sections, these equations may be applied to every temperature node to form a system of simultaneous linear algebraic equations. These equations can be solved to find the new temperature at each new time step, n+1.

28.22.5 Gas Circulation The method for computing temperatures in the rock formation with gas circulation is similar to that discussed for fluid circulation. Fluid properties of gas are used in these calculations, including density, specific heat capacity, and convection coefficient.

Flow Variables

The flow of gas is described by three conservation laws of fluid mechanics: balance of mass, momentum, and energy. The figure illustrates the flow of gas in a constant area duct with cross-sectional area A and length z.

Mass flux density G is defined by:

G = v

Balance of momentum is expressed in the following form:



P2 – P1 + G(v2 – v1) + F + W = 0

An additional relation needed to solve the balance of momentum is the ideal gas law

P = RT

where R is the ideal gas constant.

Assuming a linear velocity and employing the method of residuals, the balance of momentum equation can be solved approximately for exit velocity, v2, using the quadratic formula. There are no real solutions for negative values of the determinant (b2–4ac). The physical sense of a negative determinant is that the flow has choked, i.e., there is not enough pressure to support the assumed mass flow rate. Either inlet pressure needs to be increased or flow rate decreased until the determinant is positive.

Air and Nitrogen Properties

Air and nitrogen are modeled as ideal gases. Properties are listed in the table.

Gas Properties

Gas Constant

(J/kg-K)

Specific Heat Capacity (J/kg-K)

Ratio of Specific Heats

Air 287.06 1004.0 1.40 Nitrogen 296.80 1038.3 1.40

Thermal conductivity is defined by the following relationship:

k = Pr

C p

where Cp is specific heat capacity, Pr the Prandl number, and µ is viscosity.

28.22.6 Two-Phase Steam Production and Injection

Flow Patterns

Vertical two-phase steam flow is categorized by regimes of flow geometry and velocity. There are four generally accepted categories of two-phase steam flow: bubble, slug, transition, and annular mist (see figure).

1. Bubble Flow

The pipe is almost completely filled with liquid (i.e., gas volume is small). Gas is distributed as small, random-size bubbles that rise at velocities dependent on their size. The gas phase has little effect on frictional pressure drop caused by liquid velocity.

2. Slug Flow

Gas bubbles coalesce to form larger, cap-shaped bubbles nearly spanning the pipe. Bubble velocity is greater than liquid velocity. Both gas and liquid phases have a significant effect on pressure drop.

3. Transition Flow

Flow Direction

Superficial Gas Velocity, Vgl (ft/sec)

Sup

erf

icia

l Wat

er V

eloc

ity,

Vsl

(ft/s

ec)

Annular Mist (liquid dispersed)

1.0 1000.1 10

10

0.1

1.0

Bubble (gas dispersed)

Slug (gas dispersed)

Transition (both phases dispersed)




A transition from continuous liquid phase to continuous gas phase occurs. Although liquid effects are important, the gas phase dominates behavior.

4. Annular-Mist Flow

The gas phase is completely dominant and the liquid phase is carried as droplets.

Determining Flow Regime

Flow regime limits are defined by empirically-derived dimensionless numbers. Limits for various flow regimes are:

Bubble flow: vsg/vns < (Lim)Bubble

Slug flow: vsg/vns < (Lim)Bubble vsD<(Lim)Slug

Transition flow: (Lim)Mist>vsD>(Lim)Slug

Mist flow: vsD>(Lim)Mist

Pressure-Drop Correlations for Two-Phase Flow

The basic equation used to predict pressure drop is the conservation of momentum for the mixture of two-phase steam:

p + Gg vg + Gw vw + W + F = 0

Phase Changes

Balance of energy provides the equation for determining phase changes. The energy equation for a two-phase mixture of gas and water has the following form:

0dzA

qzGcosgG

2

vhG

2

vh

2z

1zg

2g

gw

2w

w

where h is specific enthalpy, q is heat flux per unit length of pipe, and denotes the change in properties from inlet to exit of a flow element.

Temperature in Wellbore

The thermodynamic region where liquid water and vapor coexist is a two-phase region, and states of liquid and vapor are called saturated-liquid and saturated-vapor states. Gibb’s law of equilibrium requires that pressure and temperature cannot be independent variables in the two-phase region. Saturated temperature, Ts, is given by the following equation:

1i

c

6

1ii

cs

pln

plnB73.1

TT

Critical temperature Tc = 647.19°K and critical pressure pc = 220.88 bar.

28.22.7 Surface Mud Tank Circulated fluids return to the surface mud tank and are mixed with the fluid in the tank. Temperature of this mixed fluid is calculated by considering the balance of energy as follows:

dtCQCV

Tdt)CQCQ(C)QdtV(TT

2P22p

out2P22ppo



Fluid temperature in the tank is different from environmental temperature, and heat transfer will occur between the tank and its environment. Final temperature of the mixed fluid in the tank may be predicted by Sucec’s (198568) equation.

28.23 Well Control Models

28.23.1 Approach to Well Control The conceptual approach used to model the well circulation system is illustrated in the figure. Drilling fluid (i.e., original mud) is pumped into the drill pipe, flows through the bit, up the annulus, and exits through the choke. After an overpressured gas sand is penetrated, a gas kick may enter the wellbore, creating a region with a two-phase mixture. If oil-base mud is used, some of the gas will be dissolved in the mud. The rest of the gas remains as free gas if pressure is less than saturation pressure. The objective of the well-control operation is to circulate the gas out of the annulus through the choke while maintaining bottom-hole pressure (BHP) at formation pressure to prevent further gas influx. Gas can be circulated out by pumping either original drilling mud (i.e., driller’s method) or heavier kill mud (engineer’s method) (see Section 28.23.2).

After a gas kick has been recognized and the well shut in, two quantities should be determined:

1. Shut-in drill-pipe pressure (SIDPP)

2. Influx volume

Influx volume can be determined from a measurement of the gain in pit volume. Formation pressure is calculated based on the original mud weight (OMW) from the following equation:

Pi = SIDPP + 0.052 ρOMW TVD (psi)

Kill mud weight (KMW) is determined by:

TVD052.0

BHPKMW

(ppg)

BHP is maintained by adjusting the choke so that drill-pipe pressure follows a precalculated schedule.

A two-step procedure is used to simulate kick behavior in the annulus. The first step uses a model to simulate the gas kick process. The simulated kick is stopped when either pit gain reaches the specified value or the well is producing free gas before the specified pit gain is reached. The final result from this step is the gas distribution in the annulus, which will be used in the next step—the kill model. In practice, there is a shut-in period between the kick period and the kill period. However, the shut-in period is not modeled in the program.

The kick model assumes that the choke is wide open. The BHP is then determined by calculating hydrostatic and frictional pressure losses in the annulus. If the calculated BHP is smaller than formation pressure, gas will kick into the wellbore. The gas influx rate is determined from the reservoir model. BHP may increase or decrease due to the gas influx. This change in pressure will affect the influx rate. All these changes are reflected in the reservoir model.

In the kill model, it is assumed that BHP is always maintained at formation pressure. There is no additional gas influx during the kill process. When kill mud fills most of the annulus, BHP may have to be raised above formation pressure to overcome the increased frictional pressure loss. The kill model consists of two parts:

1. Calculating the drill-pipe pressure schedule (Drill Pipe Model)

2. Calculating pressure in the annulus (Annulus Model)

Original Mud Weight

Kill Mud

Two-Phase Flow




28.23.2 Well Kill Methods Once a kick has been identified, the influx stopped, and KMW has been calculated, the influx must be removed from the wellbore, and the original weight mud replaced by heavier kill mud. The most common and safest kill process involves circulation down the drill string and up the annulus while maintaining a constant BHP equal to or slightly higher than formation pressure. This allows circulation of the kick fluids and original mud from the wellbore with the kill mud without allowing any additional influx. This also minimizes pressure exerted along the wellbore.

Driller’s Method

The Driller’s Method is a constant-BHP circulation method used to circulate gas bubbles from a wellbore. Two complete circulations are required to kill a well while using this method. After a kick is detected, the well is shut in long enough to measure stabilized SIDPP, SICP, and pit gain. The kick fluids are then circulated from the wellbore with original mud, while pump rate is maintained at a predetermined kill rate. The circulating drill-pipe pressure is maintained at initial circulating pressure while the formation fluids are being circulated from the wellbore, after which the well is again shut in. Mud in the pits is weighted up to KMW and circulated around the wellbore at kill rate following the drill-pipe pressure schedule. When kill mud reaches the bit, final circulating pressure is maintained until the well is filled with kill mud.

Wait and Weight Method

The Wait and Weight method of well control will theoretically kill the well in one circulation. After a kick is detected, the well is shut in long enough to measure stabilized SIDPP, SICP, and pit gain. SIDPP is used to calculate KMW, and the mud in the surface pits is weighted up to that weight. The well remains shut in during the weighting process. As soon as kill mud is mixed, circulation of the well follows the pressure decline schedule. After kill mud reaches the bit, final circulating pressure is maintained until the entire wellbore is filled with kill mud.

28.23.3 Reservoir Model During the process of taking a kick into the wellbore, drilling continues at the current rate of penetration (ROP). An increasing portion of the formation is exposed, allowing increased gas flow. To model this dynamic flow process, the formation is divided into a series of segments of thickness hi equal to the ROP times the time step during which that segment was first exposed to the wellbore (Nickens, 198769). Each time step for which ROP is non-zero generates a new hi. Each segment generated is updated after each time step so that the total time of exposure of each segment is constantly increasing as the kick progresses.

Each segment is assumed to flow independently for the purpose of calculating total gas influx rate. Flow rate from the ith component is calculated from the radial flow equation:

BHPP35.50

)BHPP(khq

D

22ii

gi

where:

PD = 0.5 [ln(tD) + 0.81]

tD = 7.324 x 10-8

2wp

i

rC

tk

The total gas influx rate is then

)t(N

0igig qq

where

N(t) = total number of segments at time t

k = permeability, md

ti = exposure time of ith segment, seconds



Original Mud Weight

Kill Mud

Ph, OMW

Ph, KMW

Pf, OMW

Pf, KMW

Original Mud Weight

Kill Mud

Two-Phase Flow

φ = porosity, fraction

Cp = compressibility, psi-1

μ = gas viscosity, cp

rw = wellbore radius, ft

Pi = formation pressure, psi

BHP = bottom-hole pressure, psi

qg = gas influx rate, mcf/day

28.23.4 Drill-Pipe Model The drill string is defined here as the flow path from the mud pump (excluded) to the bit (included). It may consist of many sections of different cross-sectional areas. Calculation of the drill-pipe pressure schedule is straightforward. The following equations can be derived referring to the figure, and are based on the assumption that no gas enters the drill pipe.

Pdp = BHP – ΔPbit – Δ(Pf, OMW + Ph, OMW) – Δ(Pf, KMW + Ph, KMW)

During the kick period, BHP is calculated assuming the choke is wide open. During the kill period, BHP equals formation pressure.

Pressure loss across the bit is determined as:

2bit

2

bitA10859

qP

Frictional pressure loss inside the drill pipe and annulus is calculated using either the Bingham-plastic or power-law models. These two rheological models are described in Section 28.12.1.

28.23.5 Annulus Model The annulus is defined as the flow path from the bit to the surface, which consists of (1) the annular region between the drill pipe and the casing or formation, and (2) the choke line, which is a circular pipe. As with the drill string, the annulus may have many sections with different cross-sectional areas.

During the course of gas circulation, there could be as many as four sections of fluids in the annulus (see figure). The original mud weight (OMW) section preceding the kill mud does not mix with the gas in the two-phase region. The interface between them is distinct and never changes except by moving ahead. The two-phase mixture section includes the sections with both dissolved gas and free gas (true two-phase region) and with dissolved gas only (single phase, actually). The interface between the OMW and the two-phase mixture section below is constantly changing since the gas may slip relative to the average mixture velocity and dissolved gas may move ahead due to dispersion.

Pressure drops in the liquid regions are determined the same way as for drill pipe. Either the Bingham-plastic or power-law model is used for calculating frictional pressure loss.

Pressure drops in the two-phase section require special treatment. For water-base mud, two models are used for this section: (1) one treats the section as a single bubble and (2) the other as a two-phase bubble-flow region. For oil-base mud, only the two-phase flow model can be used.




Once pressure drop in the two-phase flow section ΔPtp is determined, pressure at the choke inlet can be calculated as:

Pchoke = BHP – Δ(Pf, KMW + Ph, KMW) – Δ(Pf, OMW + Ph, OMW) – ΔPtp

Pressure drop in the OMW section may include both the sections below and above the two-phase region depending on the circulation time. Pressure at other points of interest can be evaluated similarly.

28.23.6 Single-Bubble Model For the single-bubble model (LeBlanc and Lewis, 196770), gas is assumed to enter the wellbore at the bottom as an immiscible slug, retain constant composition, remain immiscible and undergo no phase change. This single bubble of gas stays at the bottom of the well when circulation begins. Length of the gas column is determined by the pressure and temperature at the bottom of the column. The single-bubble model applies only to water-base muds.

Pressure and temperature at the interface between the gas column and mud below is Pi and Ti, respectively. Gas volume is

ibhi P

ZT

ZT

PVV

from which the gas column length can be determined. Hydrostatic head or frictional pressure loss becomes readily available. V is measured by accounting for pit gain.

28.23.7 Two-Phase Flow Model During the kick and kill periods, gas and liquid flow simultaneously up the annulus. Gas may dissolve into or evolve from the liquid phase, depending on local pressure, temperature, and bubble-point pressure conditions. Furthermore, free gas may move faster relative to the mixture velocity due to gas slippage. To describe this complex two-phase flow problem, a two-phase flow model is required. Eight variables give a complete description of the system. These include gas and mud densities, liquid hold-up, gas and mud velocities, pressure, temperature, and gas solubility. Temperature distribution in the annulus is assumed to be known and constant throughout the process. Therefore, seven equations relating the remaining variables are required to obtain a solution.

The seven equations used to describe the one-dimensional mixture system in the annulus are based on the work of Santos (199171):

)v(x

)(t lll

]v)1[(x

])1[(t ggg

0x

P

x

P

x

P]v)1(v[

x0016.0]v)1(v[

t0016.0

hf

2gg

2llggll

),,,,,v,v( glllglg f

TZ

P361.0 gg

)R,T,P(B s

o,ll

)P,T,P(R bs f

where



λ = liquid holdup, fraction

t = time, seconds

ρl = liquid density, ppg

o,l = liquid density at surface conditions, ppg

ρg = gas density, ppg

vl = liquid velocity, ft/sec

vg = gas velocity, ft/sec

x = spatial dimension, ft

P = pressure, psi

Pb = bubble-point pressure, psi

g = specific gravity of gas

T = temperature, ºR

B = formation volume factor, rcf/scf

= mass transfer between liquid and gas phase, lbm/gal/sec

The first two equations above are the mass-balance equations for the mud and gas, respectively. The third is the momentum-balance equation for the gas/mud mixture, and the fourth is an empirical correlation for predicting liquid hold-up from velocities and liquid and gas properties. The fifth is the equation of state for the gas phase.

The third equation is used instead of separate momentum-balance equations for each phase because of the unknown nature of the interactive forces between the gas and mud phases. This formulation of separated gas/liquid flow is one form of the “drift flux” model.

The sixth equation is used to calculate liquid density utilizing the formation volume factor. For water-base muds, it is assumed that there is no gas dissolved in the liquid, the formation volume factor equals 1, and liquid density equals the density at surface conditions, which is constant. For oil-base muds, gas will either dissolve into or evolve from the liquid, thus decreasing or increasing liquid density. Formation volume factor is calculated via the Van Slyke and Huang equations (199072).

28.23.8 Two-Phase Flow Correlations Two-phase flow correlations are used in the model to predict gas slippage in the annulus during gas circulation. There are a number of correlations available in the industry. Three of these are incorporated into the model.

Beggs-Brill Correlation

This empirical correlation (Beggs and Brill, 197373) was developed from air/water two-phase flow experiments. It applies to pipes at all inclination angles.

Hagedorn-Brown Correlation

The correlation provided in DrillNET is actually a combination of two correlations: the Hagedorn-Brown correlation for slug flow and the Griffith correlation for bubble flow (Brown and Beggs, 197774). They apply only to vertical wells.

The flow regime is checked to determine whether to use the Hagedorn-Brown correlation or proceed to the Griffith correlation for bubble flow.

2e

2sgsl

3048.0d

)vv(22.0071.1A

If A < 0.13, then A = 0.13.




sgsl

sg

vv

vB

If (B–A) is positive or equal to zero, continue with the Hagedorn-Brown correlation. If (B–A) is negative, proceed with the Griffith correlation.

Hasan-Kabir Correlation

The Hasan and Kabir (199275) correlation is a more recent development in multiphase flow technology. It was established based on the hydrodynamic conditions and experimental observations. It applies to flow in annuli at inclinations up to 80º.

The figure shows a typical flow regime map for wellbores.

11 Athy, L. F. (1930). Density, porosity, and compaction of sedimentary rocks. AAPG Bulletin, 14:1–24. 12 Bourgoyne, A. T., Jr., Chenevert, M. E., Millheim, K. K., and Young, F. S., Jr. (1991). Applied Drilling Engineering, volume 2 of SPE Textbook Series, Chapter 6, SPE, 2nd edition. 13 Bourgoyne, A. T., Jr., Chenevert, M. E., Millheim, K. K., and Young, F. S., Jr. (1991). Applied Drilling Engineering, volume 2 of SPE Textbook Series, Chapter 6, SPE, 2nd edition. 14 Boatman, W. A., Jr. (1967). Measuring and using shale density to aid in drilling wells in high-pressure areas. Journal of Petroleum Technology, 19:1423–1429. 15 Bingham, M. G. (1965). A New Approach to Interpreting Rock Drillability. Petroleum Publishing Company. 16 Bourgoyne, A. T. and S., Y. F. (1974). A multiple regression approach to optimal drilling and abnormal pressure detection. Society of Petroleum Engineers Journal, Transactions of AIME, 257:371–384. 17 Rehm, W. A. and McClendon, M. T. (1971). Measurement of formation pressure from drilling data. In Annual Fall Meeting, 3601. SPE, SPE. 18 Zamora, M. (1972). Slide-rule correction aids ‘d’ exponent use. Oil and Gas Journal. 19 Matthews, W. R. and Kelly, J. (1967). How to predict formation pressure and fracture gradient. Oil and Gas Journal, 65:92–106. 20 Matthews, W. R. and Kelly, J. (1967). How to predict formation pressure and fracture gradient. Oil and Gas Journal, 65:92–106. 21 Matthews, W. R. and Kelly, J. (1967). How to predict formation pressure and fracture gradient. Oil and Gas Journal, 65:92–106. 22 Matthews, W. R. and Kelly, J. (1967). How to predict formation pressure and fracture gradient. Oil and Gas Journal, 65:92–106. 23 Matthews, W. R. and Kelly, J. (1967). How to predict formation pressure and fracture gradient. Oil and Gas Journal, 65:92–106. 24 Bourgoyne, A. T., Jr., Chenevert, M. E., Millheim, K. K., and Young, F. S., Jr. (1991). Applied Drilling Engineering, volume 2 of SPE Textbook Series, Chapter 6, SPE, 2nd edition. 25 Matthews, W. R. and Kelly, J. (1967). How to predict formation pressure and fracture gradient. Oil and Gas Journal, 65:92–106. 26 Pennebaker, E. S. (1968). An engineering interpretation of seismic data. In Annual Fall Meeting, 2165. SPE, SPE.

Dispersed Bubble

Bubbly

Slug or Churn

Annular

Barnea Transition

Superficial Gas Velocity (m/sec)

Sup

erfic

ial L

iqui

d V

eloc

ity (

m/s

ec)

0.02 0.1 1 10 1000.002

0.01

0.1

1

10



27 Matthews, W. R. and Kelly, J. (1967). How to predict formation pressure and fracture gradient. Oil and Gas Journal, 65:92–106. 28 Matthews, W. R. and Kelly, J. (1967). How to predict formation pressure and fracture gradient. Oil and Gas Journal, 65:92–106. 29 Bourgoyne, A. T., Jr., Chenevert, M. E., Millheim, K. K., and Young, F. S., Jr. (1991). Applied Drilling Engineering, volume 2 of SPE Textbook Series, Chapter 6, SPE, 2nd edition. 30 Pennebaker, E. S. (1968). An engineering interpretation of seismic data. In Annual Fall Meeting, 2165. SPE, SPE.

31 Wahlmeier, Mark and Lam, Simon, 1985: “Mathematical Algorithm Aids Analysis of U-Tubing During Slurry Placement,” Oil and Gas Journal, January 7. 32 Beirute, Robert M., 1986: “Predicting Free-Fall During Primary Cementing,” World Oil, Nov. 33 Poss, G.T. and Hall, R.W., Jr., 1995: “Subsea Drilling Riser Wear: A Case History,” SPE/IADC 29392, SPE/IADC Drilling Conference, Amsterdam, The Netherlands, February 28–March 2. 34 Popov, E.P., 1976: Mechanics of Materials, Prentice-Hall, Inc., New York, NY, pp. 557–567. 35 API Bulletin 5C3, 1989: “Formulas and Calculations for Casing, Drill Pipe and Line Pipe Properties,” published by the American Petroleum Institute. 36 Song, J.Z. et al., 1992: “The Internal Pressure Capacity of Crescent-Shaped Wear Casing,” IADC/SPE 23902, IADC/SPE Drilling Conference, New Orleans, LA, February 18–21. 37 Johancsik, C.A. et al., 1984: “Torque and Drag in Directional Wells—Prediction and Measurement,” SPE 11380, IADC/SPE Drilling Conference, New Orleans, LA, February 20–23. 38 Newman, Kenneth R., Corrigan, Mark and Cheatham, John B, Jr., 1989: “Safely Exceeding the ‘Critical Buckling Load’ in Highly Deviated Holes,” SPE 19229, Offshore Europe ’89, Aberdeen, September 5–8. 39 Dawson, Rapier and Paslay, P.R., 1984: “Drillpipe Buckling in Inclined Holes,” Journal of Petroleum Technology, October. 40 Chen, Y.C., Lin, Y.H. and Cheatham, J.B., 1989: “An Analysis of Tubing and Casing Buckling in Horizontal Wells,” OTC 6037, 21st Annual OTC, Houston, Texas, May 1–4. 41 Wu, Jiang and Juvkam-Wold, Hans C., 1993: “Frictional Drag Analysis for Helically Buckled Pipes in Extended Reach and Horizontal Wells,” presented at the Energy-Sources Conference & Exhibition, Houston, Texas, January 31–February 4.

Wu, Jiang and Juvkam-Wold, Hans C., 1993: “Preventing Helical Buckling of Pipes in Extended Reach and Horizontal Wells,” presented at the Energy-Sources Conference & Exhibition, Houston, Texas, January 31–February 4. 42 Wu, Jiang and Juvkam-Wold, Hans C., 1993: “Frictional Drag Analysis for Helically Buckled Pipes in Extended Reach and Horizontal Wells,” presented at the Energy-Sources Conference & Exhibition, Houston, Texas, January 31–February 4.

Wu, Jiang and Juvkam-Wold, Hans C., 1993: “Preventing Helical Buckling of Pipes in Extended Reach and Horizontal Wells,” presented at the Energy-Sources Conference & Exhibition, Houston, Texas, January 31–February 4. 43 He, Xiaojun and Kyllingstad, Age, 1993: “Helical Buckling and Lock-Up Conditions for Coiled Tubing in Curved Wells,” SPE 25370, presented at SPE Asia Pacific Oil & Gas Conference & Exhibition, Singapore, February 8–10. 44 He, Xiaojun and Kyllingstad, Age, 1993: “Helical Buckling and Lock-Up Conditions for Coiled Tubing in Curved Wells,” SPE 25370, presented at SPE Asia Pacific Oil & Gas Conference & Exhibition, Singapore, February 8–10. 45 Lubinski, A., 1961: “Maximum Permissible Dogleg in Rotary Boreholes,” Journal of Pet Tech, February. 46 Boyer, H.E., 1986: Atlas of Fatigue Curves, American Society of Metals, Metals Park, Ohio.




47 Lubinski, A., 1977: “Fatigue of Range 3 Drill Pipe,” Revue L'Inst. Francais du Pétrole, March. 48 Dale, B.A., 1989: “Inspection Interval Guidelines to Reduce Drillstring Failures,” SPE Drilling Engineering, September. 49 Dale, B.A., 1988: “An Experimental Investigation of Fatigue-Crack Growth in Drillstring Tubulars,” SPE Drilling Engineering, December. 50 Dale, B.A., 1989: “Inspection Interval Guidelines to Reduce Drillstring Failures,” SPE Drilling Engineering, September. 51 Popov, E.P., 1976: Mechanics of Materials, Prentice-Hall, Inc., New York, NY, pp. 557–567. 52 API Bulletin 5C3, 1989: “Formulas and Calculations for Casing, Drill Pipe and Line Pipe Properties,” published by the American Petroleum Institute. 53 Bourgoyne, A.T., et al., 1991: Applied Drilling Engineering, Richardson, Texas, Society of Petroleum Engineers. 54 Bourgoyne, A.T., et al., 1991: Applied Drilling Engineering, Richardson, Texas, Society of Petroleum Engineers. 55 Moore, Preston, 1974: Drilling Practices Manual, the Petroleum Publishing Company, Tulsa, Oklahoma. 56 Bourgoyne, A.T., et al., 1991: Applied Drilling Engineering, Richardson, Texas, Society of Petroleum Engineers. 57 Bourgoyne, A.T., et al., 1991: Applied Drilling Engineering, Richardson, Texas, Society of Petroleum Engineers. 58 Einstein, A., 1906: “Eine Neue Bestimmung der Molekuldimensionen,” Annalen der Physik 19, Ser. 5289. 59 Hatschek, E., 1910: “Die Viskosität der Dispersoide. I. Suspensoide,” Kolloid Z. 7, 301; and Hatschek, E., 1910: “Die Viskosität der Dispersoide. II. Suspensoide,” Kolloid Z. 8, 34. 60 Mitchell, B.J., 1969: “Viscosity of Foam,” Ph.D. dissertation, University of Oklahoma. 61 Bayer, A.H., Millhone, R.S. and Foote, R.W., 1972: “Flow Behavior of Foam as a Well Circulating Fluid,” SPE 3986, presented at the SPE 47th Annual Fall Meeting, San Antonio, Texas, October 2–5. 62 Sanghani, V. and Ikoku, C.U., 1983: “Rheology of Foam and Its Implications in Drilling and Cleanout Operations,” ASME AO-203, presented at the 1983 Energy-Sources Technology Conference and Exhibition held in Houston, Texas, January 30–February 3. 63 Bayer, A.H., Millhone, R.S. and Foote, R.W., 1972: “Flow Behavior of Foam as a Well Circulating Fluid,” SPE 3986, presented at the SPE 47th Annual Fall Meeting, San Antonio, Texas, October 2–5. 64 Lord, D.L., 1981: “Analysis of Dynamic and Static Foam Behavior,” JPT, January. 65Spoerker, H.F., Trepess, P., Valk¢, P. and Economides, M.J., 1991: “System Design for the Measurement of Downhole Dynamic Rheology for Foam Fracturing Fluid,” SPE 22840, presented at the SPE 66th Annual Meeting held in Dallas, Texas, October 6–9. 66 Grovier, G.W. and Aziz, K., 1987: The Flow of Complex Mixtures in Pipes, Robert E. Krieger Publishing Company, Malabar, Florida. 67 Gray, K.E., 1958: “The Cutting Capacity of Air at Pressures Above Atmospheric,” AIME 213, 180–185. 68 Sucec, J., 1985: Heat Transfer, Dubuque, Iowa. 69 Nickens, H.V., 1987: “A Dynamic Computer Model of a Kicking Well,” SPE Drilling Engineering, June. 70 LeBlanc, J.L. and Lewis, R.L., 1967: “A Mathematical Model of a Gas Kick,” SPE 1860, presented at SPE 42nd Annual Fall Meeting, Houston, Texas, October 1–4. 71 Santos, O.L.A., 1991: “Important Aspects of Well Control for Horizontal Drilling Including Deepwater Situations,” SPE/IADC 21993, presented at 1991 SPE/IADC Drilling Conference, Amsterdam, March.

Santos, O.L.A., 1991: “Well-Control Operations in Horizontal Wells,” SPE Drilling Engineering, June.



72 Van Slyke, D.C., Huang E.T.S., 1990: “Predicting Gas Kick Behavior in Oil-Based Drilling Fluids Using a PC-Based Dynamic Wellbore Model,” IADC/SPE 19972, presented at the 1990 IADC/SPE Drilling Conference held in Houston, Texas, February. 73 Beggs, H.D. and Brill, J.P., 1973: “A Study of Two-Phase Flow in Inclined Pipes,” Journal of Petroleum Technology, May. 74 Brown, K.E. and Beggs, H.D., 1977: “The Technology of Artificial Lift Methods,” Vol. 1, Published by Pennwell Books. 75 Hasan, A.R. and Kabir, C.S., 1992: “Two-Phase Flow in Vertical and Horizontal Annuli,” Int. J. Multiphase Flow, Vol. 18, No. 2, pp. 279–293.


229929. ADDITIONAL REFERENCES

Allan, P.D., 1994: “Nitrogen Drilling System for Gas Drilling Applications,” SPE 28320, presented at the SPE 69th Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 25–28.

Angel, R.R., 1957: “Volume Requirements for Air and Gas Drilling,” T.P. 4679 Transaction, Vol. 210, SPE of AIME, pg. 325–330.

API Spec. 10D, 1986: “Casing Centralizers,” Third Edition, API Dallas, February.

API Specification 10 (Spec 10), 1990: Specification for Materials and Testing for Well Cements, Fifth Edition, July 1.

Arnold, F.C., 1990: “Temperature Variation in a Circulating Wellbore Fluid,” J. Energy Resources Technology, Vol. 112, pg. 79–83.

Bannantine, J.A., Comer, J.J., and Handrock, J.L., 1990: Fundamentals of Metal Fatigue Analysis, Prentice Hall, Englewood Cliffs, New Jersey.

Barnea, D., 1987: “A Unified Model for Predicting Flow-Pattern Transitions for the Whole Range of Pipe Inclinations,” International Journal Multiphase Flow, Vol. 13, No. 1, pp. 1–12.

Bode, D.J., R.B. Noffke, and H.V. Nickens, Amoco Production Co., 1991: “Well-Control Methods and Practices in Small-Diameter Wellbores,” JPT, November.

Bourgoyne, A.T., Jr., et al., 1986: Applied Drilling Engineering, Richardson, Texas, Society of Petroleum Engineers. Caetano, E.F., Shoham O. and Brill, J.P., 1992: “Upward Vertical Two-Phase Flow Through an Annulus – Part II: Modeling Bubble, Slug, and Annular Flow,” Journal of Energy Resources Technology, Volume 114, March.

Caetano, E.F., Shoham, O. and Brill, J.P., 1992: “Upward Vertical Two-Phase Flow Through an Annulus – Part I: Single-Phase Friction Factor, Taylor Bubble Rise Velocity, and Flow Pattern Prediction,” Journal of Energy Resources Technology, Volume 114, March.

Carslow, H.S. and Jeager, J.C., 1959: Conduction of Heat in Solids, Oxford Press, London.

Chen, Y.C., Lin, Y.H. and Cheatham, J.B., 1989: “An Analysis of Tubing and Casing Buckling in Horizontal Wells,” OTC 6037, 21st Annual OTC, Houston, Texas, May 1-4. Dawson, Rapier and Paslay, P.R., 1984: “Drillpipe Buckling in Inclined Holes,” Journal of Petroleum Technology, October. Dellinger, T.B. et al., 1980: “Directional Technology Well Extend Drilling Reach,” Oil and Gas Journal, September 15.

Devereux, Steve, 1998: Practical Well Planning and Drilling, PennWell Publishing Company.

Dix, C. H. (1955). Seismic velocities from surface measurements. Geophysics, 20:68–86.

Dubler, A.E. and Hubbard, M.C., 1975: “A Model for Gas-Liquid Slug Flow in Horizontal and Near Horizontal Tubes,” Ind. Eng. Chem. Fund.

Fuchs, H.O. and Stephens, R.I., 1980: Metal Fatigue in Structures. New York: John Wiley and Sons.

Gebhardt, B., 1961: Heat Transfer, McGraw-Hill Book Co., New York.

Govier, G.W. and Azziz, K., 1977: The Flow of Complex Mixtures in Pipes, Robert E. Krieger Publishing Co., Huntington, New York.

Govier, G.W., and Onser, M.M., 1962: “The Horizontal Pipeline Flow of Air Water Mixtures,” Can. J. Chem. Eng. 40.93.

Govier, G.W., Sullivan, G.A., and Wood, R.K., 1961: Can. J. Chem. Eng. 39.67.

CHAPTER 29: ADDITIONAL REFERENCES


Guild, G.J., et al., 1982: “Drilling Extended Reach/High-Angle Wells Through Overpressured Shale Formation in the Central Graben Basin, Arbroath Field, Block 22/17, U.K. North Sea,” SPE/IADC 25749.

International Association of Drilling Contractors, 1992: Drilling Manual, Eleventh Edition.

Johancsik, C.A., Friesen, D.B., and Dawson, Rapier, 1988: “Torque and Drag in Directional Wells Production and Measurement,” Journal of Petroleum Technology, June.

Jordan, J. R. and Shirley, O. J. (1966). Application of drilling performance data to overpressure detection. Journal of Petroleum Technology, pages 1387–1399.

Juvkam-Wold, H.C. and Wu, J. 1992: “Casing Deflection and Centralizer Spacing Calculations,” SPEDE , pp. 268-274, December.

Karlsson, H., Brassfield, T., and Krueger, V., 1985: “Performance Drilling Optimization,” SPE/IADC 13474, presented at 1985 SPE/IADC Drilling Conference, 5–8 March, New Orleans, Louisiana.

Keller, H.H., Couch, E.J., and Berry, P.M., 1973: “Temperature Distributions in Circulating Mud Columns,” SPEJ, Vol. 13, pg. 23–30.

Kreith, Frank, 1967: Principles of Heat Transfer, International Textbook Co., Scranton, Pennsylvania.

Larsen, T.I., Pilehvari, A.A. and Azar, J.J., 1997: “Development of a New Cuttings-Transport Model for High-Angle Wellbores Including Horizontal Wells,” SPE Drilling & Completion, June.

Lee, H.K., Smith, R.C., and Tighe, R.E., 1986: “Optimal Spacing for Casing Centralizers,” SPEDE, pp. 122–130, April.

Leitão, H.C.F. et al., 1990: “General Computerized Well Control Kill Sheet for Drilling Operations with Graphical Display Capabilities,” SPE 20327, presented at the Fifth SPE Petroleum Computer Conference held in Denver, Colorado, June 25–28.

Lohuis, G. et al., 1991: “Coiled Tubing/Production Logging in Highly Deviated and Horizontal Wellbores,” CIM/AOSTRA 91-15, 1991 CIM/AOSTRA Conference, Banff, April 23–24.

Lyons, William C., 1984: Air and Gas Drilling Manual, Gulf Publishing Company.

Mitchell, R.F., 1980: “Downhole Temperature Prediction for Drilling Geothermal Wells,” Proc. Intl. Cont. on Geothermal Drilling and Completion Technology, 14.1–14.18.

Mitchell, R.F., 1982: “Advanced Wellbore Thermal Simulator GEOTEMP2,” Research Report, Submitted to Sandia Laboratories Under Contract 46-5670.

Moore, Preston, 1974: Drilling Practices Manual, the Petroleum Publishing Company, Tulsa, Oklahoma.Nelson, Erik B., 1990: Well Cementing, Vol 28, Chap 11, pg 14–17, Elsevier Science Pub B.V., The Netherlands.

Newman, Kenneth R., Corrigan, Mark and Cheatham, John B, Jr., 1989: “Safely Exceeding the ‘Critical Buckling Load’ in Highly Deviated Holes,” SPE 19229, Offshore Europe '89, Aberdeen, September 5–8.

O'Brian, P.L., et al., 1988: “An Experimental Study of Gas Solubility in Oil-Based Drilling Fluids,” SPE Drilling Engineering, March.

Okpobiri, G.A. and Ikoku, C.U., 1986: “Volumetric Requirements for Foam and Mist Drilling Operations,” SPE Drilling Engineering, February.

Orkiszowski, 1968: “Predicting Two-Phase Pressure Drops in Vertical Pipe,” Journal of Pet Tech, June.

Paslay, P.R. and Cernocky, E.P., 1991: “Bending Stress Magnification in Constant Curvature Doglegs With Impact on Drillstring and Casing,” SPE 22547, presented at 66th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, Dallas, Texas, October 6–9.

Ramey, H.J., Jr., 1962: “Wellbore Heat Transmission,” Journal of Petroleum Technology, Vol. 14, pg. 427–435.

Raymond, L.R., 1969: “Temperature Distribution in a Circulating Drilling Fluid,” Journal of Petroleum Technology, Vol. 21, pg. 333–341.

CHAPTER 29: ADDITIONAL REFERENCES



Reid, R.C., Prausnitz, J.M. and Poling, B.P., 1987: The Properties of Gases and Liquids, 4th Edition, McGraw-Hill, New York, NY.

Schubert, J.J., Juvkam-Wold, H.C., and Choe, J., 2003: “Well Control Procedures for Dual Gradient Drilling as Compared to Conventional Riser Drilling,” SPE 79880, presented at IADC/SPE Drilling Conference, Amsterdam, February 19–21.

Shook, R.A., Dech, J.A., Maurer, W.C., Matson, R.P., Mueller, D.T., Hopmann, M., Boonen, P., and Reeves, S.R., 1995: “Slim-Hole Drilling and Completion Barriers,” Gas Research Institute Report GRI-95/0182, May.

Smith, D.K., 1987: “Cementing,” Henry L. Doherty Memorial Fund of AIME, Chapter 4, NY & Richardson, TX.

Specification for Materials and Testing for Well Cements API Specification 10, fifth edition, July 1, 1990.

Spotts, M.F., 1978: Design of Machine Elements, Prentice-Hall, Inc., Englewood Cliffs, N.J.

Tragasser, A.F., Crawford, P.B., and Crawford, H.R., 1967: “A Method for Calculating Circulating Temperature,” JPT, Vol.19, pg. 1507–1512.

Watson, David, Terry Brittenham, and Preston L. Moore, 2003: Advanced Well Control, SPE Textbook Series Vol. 10, Richardson, Texas.

White, D.B. and Walton, I.C., 1990: “A Computer Model for Kicks in Water- and Oil-Based Muds,” IADC/SPE 19975, presented at the 1990 IADC/SPE Drilling Conference, Houston, Texas, February 27–March 2.

White, J.P. and Dawson, R., 1985: “Casing Wear: Laboratory Measurements and Field Predictions,” SPE 14325, 60th Annual Fall Technical Conference & Exhibition, Las Vegas, Nevada, September 22–25.

Willhite, G.P., 1967: “Overall Heat Transfer Coefficients in Steam and Hot Water Injection Wells,” JPT, Vol.19, pg. 607–615.

Wooley, G.B., 1980: “Computing Downhole Temperatures in Circulating, Injection, and Production Wells,” JPT, Vol. 32, pg. 1509–1522.

Wu, J., Chen, P., and Juvkam-Wold H.C., 1991: “Casing Centralization in Horizontal Wells,” Popular Horizontal, pp. 14–21, April/June.

Wu, Jiang and Juvkam-Wold, Hans C., 1993: “Preventing Helical Buckling of Pipes in Extended Reach and Horizontal Wells,” ASME Energy-Sources Conference & Exhibition, January 31-February 4. Wu, Jiang and Juvkam-Wold, Hans C., 1993: “Frictional Drag Analysis for Helically Buckled Pipes in Extended Reach and Horizontal Wells,” ASME Energy-Sources Conference & Exhibition, January 31-February 4. Yue, X.A., Kong, X.Y., and Chen, J.L., 1993: “Bingham Liquid-Solid Granular Mixture Flow Through a Vertical Pipe,” Proceedings of Second International Conference of Nonlinear Mechanics, Beijing, China.

Yue, X.A., Kong, X.Y., and Chen, J.L., 1993: “Constitutive Equations for Solid Phase in Liquid-Solid Mixture,” Proceedings of Second Inter. Conference of Nonlinear Mechanics, Beijing, China.

Zucrow, M.J. and Hoffmure, J.D., 1976: Gas Dynamics, John Wiley and Sons. Inc., New York


330030. GETTING HELP

30.1 Contacting Petris For additional assistance with operation or application of DrillNET, contact:

30.2 Reporting Problems DrillNET has been carefully checked before its release; however, software bugs are a fact of life. We appreciate your reporting any bugs you find and describing the input parameters and conditions selected when the problem occurred. Petris is also very appreciative of your comments and suggestions for improving DrillNET. Let us know if there are additional features you would like to see added to the program. Though it may not be feasible to incorporate every suggestion into the next version, many important improvements have been made to our programs based directly on suggestions from users.

If contacting us by email, please include a description of your computer’s hardware (processor) and operating system (version of Windows). Describe the steps and options you selected before the problem occurred. Send a copy of your project file (*.XML) as an attachment to the email.

If the error occurred while running the Casing Stress Check engineering model, also attach a copy of your preferences file (“CasingCK.pol” located in the DrillNET folder).

Technical Support Petris Technology, Inc.

1900 St. James Place, Suite 700 Houston, Texas 77056 U.S.A.

Tel: 713-403-8599

E-mail: [email protected] Web: http://www.petris.com

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