Prassl w l_-_drilling_engineer

Drilling Engineering

Dipl.-Ing. Wolfgang F. Prassl

Curtin University of Technology

Curtin University of Technology Master of Petroleum Engineering
Department of Petroleum Engineering Drilling Engineering

Contents

1 Introduction 1
1.1 Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.2 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.3 Personal at rig site . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1.4 Miscellaneous . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

2 Rotary Drilling Rig 5
2.1 Rig Power System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
2.2 Hoisting System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.2.1 Derrick . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
2.2.2 Block and Tackle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
2.2.3 Drawworks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
2.3 Rig Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
2.4 Circulation System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
2.4.1 Mud Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
2.5 The rotary System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
2.5.1 Swivel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
2.5.2 Kelly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
2.5.3 Rotary Drive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
2.6 Drilling Cost Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
2.6.1 Drilling Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
2.6.2 Drilling Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

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2.6.3 Tripping Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
2.7 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

3 Geomechanics 59
3.1 Geology Prediction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
3.2 Pore pressure Prediction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
3.2.1 Hydrostatic Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
3.3 Fracture Gradient Prediction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
3.3.1 Interpretation of Field Data . . . . . . . . . . . . . . . . . . . . . . . . . . 72
3.4 Mud Weight Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74
3.5 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

4 Drilling Hydraulics 81
4.1 Hydrostatic Pressure Inside the Wellbore . . . . . . . . . . . . . . . . . . . . . . . 82
4.2 Types of Fluid Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84
4.3 Rheological Classiﬁcation of Fluids . . . . . . . . . . . . . . . . . . . . . . . . . . 87
4.4 Laminar Flow in Pipes and Annuli . . . . . . . . . . . . . . . . . . . . . . . . . . 90
4.5 Turbulent Flow in Pipes and Annuli . . . . . . . . . . . . . . . . . . . . . . . . . . 92
4.6 Pressure Drop Across Surface Connections . . . . . . . . . . . . . . . . . . . . . . 101
4.7 Pressure Drop Across Bit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102
4.8 Initiating Circulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103
4.9 Optimization of Bit Hydraulics . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103
4.10 Particle Slip Velocity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107
4.11 Surge and Swab Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109
4.12 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111

5 Drilling Bits 113
5.1 Drill Bit Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113
5.1.1 Roller Cone Bit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113
5.1.2 Fixed Cutter Bit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120

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5.1.3 Coring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125
5.2 Drill Bit Classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127
5.2.1 Roller Bit Classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127
5.2.2 Drag Bit Classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129
5.3 Drill Bit Selection and Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 130
5.3.1 Tooth Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131
5.3.2 Bearing Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131
5.3.3 Gauge Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132
5.4 Factors that Affect the Rate Of Penetration . . . . . . . . . . . . . . . . . . . . . 132
5.4.1 Bit Type . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132
5.4.2 Formation Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . 132
5.4.3 Drilling Fluid Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133
5.4.4 Operating Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135
5.4.5 Bit Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138
5.4.6 Bit Hydraulics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138
5.5 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

6 Drillstring Design 145
6.1 Drill Pipe Classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146
6.2 Calculation of Neutral Point . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148
6.3 Drillstring Design Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149
6.3.1 Tension . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149
6.3.2 Collapse . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 160
6.3.3 Biaxial Loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 162
6.3.4 Shock Loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 163
6.3.5 Torsion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 163
6.4 Drillpipe Bending resulting from Tonging Operations . . . . . . . . . . . . . . . . 164
6.5 Selecting Drill Collar Weights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167
6.6 Stretch of Drillpipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167
6.7 Critical Rotary Speeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168

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6.8 Bottom Hole Assembly Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 169
6.9 Placement of Stabilizers and Reamers . . . . . . . . . . . . . . . . . . . . . . . . . 170
6.9.1 Building Assemblies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 182
6.9.2 Holding Assemblies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 182
6.9.3 Dropping Assemblies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 182
6.9.4 WOB Increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 182
6.10 Dogleg Severity Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 183
6.11 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 185

7 Drilling Fluid 191
7.1 Functions of Drilling Mud . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 191
7.2 Types of Drilling Mud . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 192
7.2.1 Water-base Muds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 193
7.2.2 Oil-base Muds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 195
7.3 Mud Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 196
7.4 Recommended Mud Flow Properties . . . . . . . . . . . . . . . . . . . . . . . . . 203
7.5 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 204

8 Casing Design 207
8.1 Casing Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 207
8.1.1 Conductor Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 207
8.1.2 Surface Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 208
8.1.3 Intermediate Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 208
8.1.4 Production Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 208
8.1.5 Liners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 209
8.2 Casing Setting Depths . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 210
8.3 Casing Connections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 211
8.4 API Casing Performance Properties . . . . . . . . . . . . . . . . . . . . . . . . . . 215
8.5 General Casing Design Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . 238
8.6 Graphical Method for Casing Design . . . . . . . . . . . . . . . . . . . . . . . . . 240

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8.7 Maximum Load Casing Design for Intermediate Casing . . . . . . . . . . . . . . . 244
8.8 Casing Centralizer Spacings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 244
8.9 Stretch in Casing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 246
8.10 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 249

9 Directional Drilling and Deviation Control 251
9.1 Mayor Types of Wellbore Trajectories . . . . . . . . . . . . . . . . . . . . . . . . . 262
9.2 Trajectory Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 267
9.3 Calculating the Survey of a Well . . . . . . . . . . . . . . . . . . . . . . . . . . . . 268
9.3.1 Average angle method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 271
9.3.2 Radius of curvature method . . . . . . . . . . . . . . . . . . . . . . . . . . 273
9.3.3 Minimum Curvature Method . . . . . . . . . . . . . . . . . . . . . . . . . . 273
9.4 Dogleg Severity Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 274
9.5 Deflection Tools and Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . 275
9.5.1 Natural Formation Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . 278
9.5.2 Hydraulic Method (Jetting) . . . . . . . . . . . . . . . . . . . . . . . . . . 278
9.5.3 Mechanical Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 279
9.6 While Drilling Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 284
9.6.1 Measurement While Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . 284
9.6.2 Logging While Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 285
9.6.3 Data Transfer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 285
9.7 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 286

10 Borehole Problems 289
10.1 Differential Pipe Sticking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 289
10.2 Free Point Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 291
10.3 Freeing Differentially Stuck Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . 292
10.3.1 Spotting Organic Fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . 292
10.3.2 Hydrostatic Pressure Reduction . . . . . . . . . . . . . . . . . . . . . . . . 292
10.3.3 Backoff Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 294

CHAPTER 0 Page v


10.4 Lost Circulation Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 294
10.5 Keyseats . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 296
10.6 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 297

11 Kick Control and Blowout Prevention 301
11.1 Blowout Preventer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 302
11.1.1 Ram preventers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 304
11.1.2 Annular preventers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 306
11.2 Well Control Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 311
11.3 Length and Density of Kick . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 313
11.4 Kick Tolerance and Kill Mud Weight . . . . . . . . . . . . . . . . . . . . . . . . . 314
11.5 Pump Pressure Schedules for Well Control Operations . . . . . . . . . . . . . . . . 315
11.6 Kick Removal – Two Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 316
11.6.1 Wait-and-weight method . . . . . . . . . . . . . . . . . . . . . . . . . . . . 317
11.6.2 Driller’s method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 318
11.7 Equations Required to Perform Dynamic or Polymer Kill . . . . . . . . . . . . . . 320
11.8 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 324

12 Cementing 325
12.1 Functions of Cement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 325
12.2 Properties of Cement Slurry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 327
12.2.1 Physical Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 328
12.3 Cement Additives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 329
12.3.1 Extenders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 333
12.3.2 Accelerators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 333
12.3.3 Retarders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 333
12.3.4 Weighting Material . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 335
12.3.5 Fluid Loss Material . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 335
12.3.6 Dispersants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 336
12.4 Primary Cementing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 340

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12.5 Liner Cementing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 346
12.6 Squeeze Cementing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 346
12.7 Plugback Cementing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 349
12.8 Examples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 351

CHAPTER 0 Page vii


Chapter 1

Introduction

1.1 Objectives

This text aims to give students an in-
troduction to the principles and some
recommended procedures practiced
in drilling engineering. All chapters
contain a theoretical introduction, as
well as examples and exercises. Ref-
erences for further readings are given
at the end of this text. Necessary
equations and procedures to solve the
exercises are presented through out
the text.

1.2 General

When a drilling project is com-
menced, two goals are governing all
aspects of it. The first is to realize
the well in a safe manner (personal
injuries, technical problems) and ac-
cording to its purpose, the second
one is to complete it with minimum
cost. Thereto the overall costs of the
well during its lifetime in conjunction
with the field development aspects
shall be minimized. This optimiza-
tion may influence where the well is
Figure 1.1: Rotary Drilling Process
CHAPTER 1 Page 1


drilled (onshore - extended reach or oﬀshore above reservoir), the drilling technology applied (con-
ventional or slim-hole drilling) as well as which evaluation procedures are run to gather subsurface
information to optimize future wells.
For making hole, diﬀerent technologies have been invented.

Drilling technology
Percussion drilling
Rope -> “Pennsylvanian drilling”
Drillstring
With mud -> Quick percussion drilling
Without mud -> “Canadian drilling”
Rotating bit
Full cross-section drilling
Surface driven
Rotary drilling
Rotary nozzle drilling
Subsurface driven
Turbine drilling
Positive displacement motor drilling
Electro motor drilling
Annular drilling
Diamond coring
Shot drilling
Special techniques
Abrasive jet drilling
Cavitating jet drilling
Electric arc and plasma drilling
Electric beam drilling
Electric disintegration drilling
Explosive drilling
Flame jet drilling
Implosion drilling
Laser drilling
REAM drilling
Replaceable cutterhead drilling
Rocket Exhaust drilling
Spark drilling
Subterrene drilling
Terra drilling
Thermal-mechanical drilling
Thermocorer drilling

Throughout this text, rotary drilling technology is discussed exclusively.

CHAPTER 1 Page 2


1.3 Personal at rig site

This section describes the crew requirements and tasks of some individual crew members at the
rig site.
The people directly involved in drilling a well are employed either by the operating company, the
drilling contractor or one of the service and supply companies. Out of the companies involved,
the operating company is the owner and principal user of the services provided by the drilling
contractor and the different service companies.
To drill an oil or gas well, the operating company (or simply called operator) acquires the right
from the land owner under which the prospective reservoir may exist, to drill and produce from it.
Usual, when a well has to be drilled, a tender is run by the operator and various drilling contractors
are invited to place their bid. Since drilling contractors are companies that perform the actual
drilling of the well, their main job is to drill a hole to the depth/location and specifications set
by the operator. Along with hiring a drilling contractor ,the operator usually employs various
service and supply companies to perform logging, cementing or other special operations as well as
maintaining the mud in its planed condition.
Most drilling crews consist of a tool pusher, a driller, a derrickman, a mud logger and two or three
rotary helpers (also called floormen or roughnecks). Along with this basic crew configuration the
operator sends usually a representative, called company man to the rig. For offshore operations
the crews usually consist of many more employees.

Tool Pusher
The tool pusher supervises all drilling operations and is the leading man of the drilling contractor
on location. Along with this supervision duties, he has to co-ordinate company and contractor
affairs.

Company Man
The company man is in direct charge of all the company’s activities on the rig site. He is responsible
for the drilling strategy as well as the supplies and services in need. His decisions directly effect
the progress of the well.

Driller
The driller operates the drilling machinery on the rig floor and is the overall supervisor of all
floormen. He is directly responsible to the tool pusher and is the person who is most closely
involved in the drilling process. He manipulates from his position at the control console on the
rig floor brakes, switches, levers and other related controls that influence the drilling parameters.
In case of a kick he is the first person to take action by moving the bit off bottom and close the
BOP.

CHAPTER 1 Page 3


Derrick Man
The derrickman works on the so-called monkeyboard, a small platform up in the derrick, usually
about 90 [ft] above the rotary table. When a connection is made or during tripping operations he
is handling and guiding the upper end of the pipe. During drilling operations the derrickman is
responsible for maintaining and repairing the pumps and other equipment as well as keeping tabs
on the drilling fluid.

Floor Men
During tripping, the rotary helpers are responsible for handling the lower end of the drill pipe as
well as operating tongs and wrenches to make or break a connection. During other times, they
also maintain equipment, keep it clean, do painting and in general help where ever help is needed.

Mud Engineer, Mud Logger
The service company who provides the mud almost always sends a mud engineer and a mud logger
to the rig site. They are constantly responsible for logging what is happening in the hole as well
as maintaining the propper mud conditions.

1.4 Miscellaneous
According to a wells final depth, it can be classified into:

Shallow well: < 2,000 [m]

Conventional well: 2,000 [m] - 3,500 [m]

Deep well: 3,500 [m] - 5,000 [m]

Ultra deep well: > 5,000 [m]

With the help of advanced technologies in MWD/LWD and extended reach drilling techniques
horizontal departures of 10,000+ [m] are possible today (Wytch Farm).

CHAPTER 1 Page 4


Chapter 2

Rotary Drilling Rig

The most common drilling rigs in use today are rotary drilling rigs. Their main tasks are to create
rotation of the drillstring and facilities to advance and lift the drillstring as well as casings and
special equipment into and out of the hole drilled. The main components of a rotary drilling rig
can be seen in picture 2.1.
Since the rig rate (rental cost of
the rig) is one of the most inﬂuenc-
ing cost factors to the total cost
of a well, careful selection of the
proper type and capacity is vital
for a successful drilling project.
For all rigs, the depth of the
planned well determines basic rig
requirements like hoisting capac-
ity, power system, circulation sys-
tem (mud pressure, mud stream,
mud cleaning), as well as the pres-
sure control system. The se-
lection of the most cost-eﬃcient
rig involves both quantitative and
qualitative considerations. Of the
quantitative considerations, the
rig power system, the hoisting sys-
tem, the circulation system, the
rotary system, the derrick and
substructure as well as the pres-
sure control system are the most
important ones. How to calculate
the various requirements is dis-
cussed below. The qualitative as-

CHAPTER 2 Figure 2.1: Rotary Drilling Rig Page 5


pects involve technical design, appropriate expertise and training of the drilling crew, contractor’s
track record and logistics handling.
In general, rotary rigs can be distinguished into:

Land rigs:
conventional rigs:
small land rigs,
medium land rigs,
large land rigs,
mobile rigs:
portable mast,
jacknife,

Offshore rigs:
bottom anchored rigs:
artificial island,
TLP,
submersible,
jackup,
concrete-structured, etc.,
floating rigs:
drillship,
semi-submersible,
barge.

For offshore rigs, factors like water depth, expected sea states, winds and currents as well as
location (supply time) have to be considered as well.
It should be understood that rig rates are not only influenced by the rig type but they are also
strongly dependent on by the current market situation (oil price, drilling activity, rig availabilities,
location, etc.). Therefore for the rig selection basic rig requirements are determined first. Then
drilling contractors are contacted for offers for a proposed spud date (date at which drilling
operation commences) as well as for alternative spud dates. This flexibility to schedule the spud
date may reduce rig rates considerably.

2.1 Rig Power System
The power system of a rotary drilling rig has to supply the following main components: (1) rotary
system, (2) hoisting system and (3) drilling fluid circulation system. In addition, auxiliaries like
the blowout preventer, boiler-feed water pumps, rig lighting system, etc. have to be powered.
Since the largest power consumers on a rotary drilling rig are the hoisting and the circulation
system, these components determine mainly the total power requirements. At ordinary drilling

CHAPTER 2 Page 6


operations, the hoisting (lifting and lowering of the drillstring, casings, etc.) and the circulation
system are not operated at the same time. Therefore the same engines can be engaged to perform
both functions.
The power itself is either generated at the rig site using internal-combustion diesel engines, or
taken as electric power supply from existing power lines. The raw power is then transmitted to
the operating equipment via: (1) mechanical drives, (2) direct current (DC) or (3) alternating
current (AC) applying a silicon-controlled rectifier (SCR). Most of the newer rigs using the AC-
SCR systems. As guideline, power requirements for most rigs are between 1,000 to 3,000 [hp].
The rig power system’s performance is characterised by the output horsepower, torque and fuel
consumption for various engine speeds. These parameters are calculated with equations 2.1 to 2.4:

ω.T
P = (2.1)
33, 000

Qi = 0.000393.Wf .ρd .H (2.2)

P
Et = (2.3)
Qi

ω = 2.π.N (2.4)

where:

P [hp] ... shaft power developed by engine
ω [rad/min] ... angular velocity of the shaft
N [rev./min] ... shaft speed
T [ft-lbf] ... out-put torque
Qi [hp] ... heat energy consumption by engine
Wf [gal/hr] ... fuel consumption
H [BTU/lbm] ... heating value (diesel: 19,000 [BTU/lbm])
Et [1] ... overall power system efficiency
ρd [lbm/gal] ... density of fuel (diesel: 7.2 [lbm/gal])
33,000 ... conversion factor (ft-lbf/min/hp)

When the rig is operated at environments with non-standard temperatures (85 [F]) or at high
altitudes, the mechanical horsepower requirements have to be modified. This modification is
according to API standard 7B-11C:

(a) Deduction of 3 % of the standard brake horsepower for each 1,000 [ft] rise

CHAPTER 2 Page 7


in altitude above mean sea level,
◦
(b) Deduction of 1 % of the standard brake horsepower for each 10 rise
or fall in temperature above or below 85 [F], respectively.

2.2 Hoisting System

The main task of the hoisting system is to lower and raise the drillstring, casings, and other
subsurface equipment into or out of the well.
The hoisting equipment itself consists of: (1)draw works, (2) fast line, (3) crown block, (4) travel-
ling block, (5) dead line, (6) deal line anchor, (7) storage reel, (8) hook and (9) derrick, see sketch
2.2.

Figure 2.2: Hoisting system

CHAPTER 2 Page 8


Making a connection

With the phrase “Making a connection”, the periodic process of adding a new joint of drillpipe to
the drillstring as the hole deepens is referred. This process can be seen in ﬁgure 2.3.

Figure 2.3: Making a connection

Making a trip

With the phrase “Making a trip”, the process of moving the drillstring out of the hole, change
the bit or alter the bottom-hole assembly, and lower the drillstring again into the hole is referred.
The process of tripping out is sketched at ﬁgure 2.5.

Figure 2.4: Sketch of slips for drill pipe(a), drill collar(b) and casing(c)

CHAPTER 2 Page 9


Figure 2.5: Tripping Out

Figure 2.6: Lifting pipe at the rig ﬂoor

CHAPTER 2 Page 10


Sometimes the drillstring is not completely run out of the hole. It is just lifted up to the top of the
open-hole section and then lowered back again while continuously circulating with drilling mud.
Such a trip, called “wiper trip”, is carried out to clean the hole from remaining cuttings that may
have settled along the open-hole section.

Figure 2.7: Sketch of a drill pipe spinner

2.2.1 Derrick

Derricks are classiﬁed (or rated) by the American Petroleum Institute (API) according to their
height as well as their ability to withstand wind and compressive loads. API has published
standards for the particular speciﬁcations.
The higher the derrick is, the longer stands it can handle which in turn reduces the tripping time.
Derricks that are capable to handle stands of two, three or four joints are called to be able to pull
“doubles”, “thribbles”, or “fourbles” respectively.

CHAPTER 2 Page 11


Figure 2.8: Storage of doubles inside the derrick

2.2.2 Block and Tackle

The crown block, the travelling block and the drilling line comprise the block and tackle which
permits the handling of large loads. To lift and lower the heavy loads into and out of the borehole,
the drilling line is strung multiple times between the crown and the travelling block, see sketch
2.11.
When no friction is assumed in the travelling and the crown block (constant tension in the drilling
line), the hook load W creates a load to the drawworks with is equal the load in the fast line Ff
which in turn depends on the number the line is strung n between the travelling and the crown
block. This is expressed with:

W = n.Ff (2.5)

CHAPTER 2 Page 12


Figure 2.9: Sketch of load-distribution over derrick

Figure 2.10: Brakes

The input power Pi of the block and tackle is equal to the drawworks load Ff times the velocity
of the fast line νf .

Pi = Ff .νf (2.6)

CHAPTER 2 Page 13


Figure 2.11: Block and tackle

The output power or “hook power” Ph is given by the hook load times the velocity of the travelling
block.

Ph = W.νb (2.7)

Figure 2.12: Efficiency factors for different tacklings

Drilling line:
The drilling line is a wire rope that is made of strands wounded around a steel core. It ranges in
diameter from 1 to 2 [in]. Its classification is based on the type of core, the number of strands
2
wrapped around the core, and the number of individual wires per strand. Examples of it can be
see in figure 2.13.

CHAPTER 2 Page 14


Figure 2.13: Drilling Line

Since the drilling line is constantly under biaxial load of tension and bending, its service life is
to be evaluated using a rating called “ton-mile”. By definition, a ton-mile is the amount of work
needed to move a 1-ton load over a distance of 1 mile.
When the drilling line has reached a specific ton-mile limit, which is mainly due to round trips,
setting casings, coring and drilling, it is removed from service. The ton-mile wear can be estimated
by:

Round Trip:

D. (Ls + D) .We D. Wb + WC 2
TR = + (2.8)
10, 560, 000 2, 640, 000

where:

Wb [lb] ... effective weight of travelling assembly
Ls [ft] ... length of a drillpipe stand
We [lb/ft] ... effective weight per foot of drillpipe
D [ft] ... hole depth
WC [lb] ... effective weight of drill collar assembly
less the effective weight of the same length of drillpipe

It should be noted that the ton-miles are independent of the number of lines strung.

CHAPTER 2 Page 15


The ton-mile service of the drilling line is given for various activities according to:

Drilling operation: (drilling a section from depth d1 to d2 ) which accounts for:

1. drill ahead a length of kelly

2. pull up length of kelly

3. ream ahead a length of kelly

4. pull up a length of kelly

5. pull kelly in rathole

6. pick up a single (or double)

7. lower drill string in hole

8. pick up kelly and drill ahead

Td = 3. (TR at d2 − TR at d1 ) (2.9)

Coring operation: which accounts for:

1. core ahead a length of core barrel

2. pull up length of kelly

3. put kelly in rathole

4. pick up a single joint of drillpipe

5. lower drill string in hole

6. pick up kelly

Tc = 2. (TR2 − TR1 ) (2.10)

where:

TR2 [ton-mile] ... work done for one round trip at depth d2 where coring stopped
TR1 [tin-mile] ... work done for one round trip at depth d1 where coring started.

CHAPTER 2 Page 16


Running Casing:

D. (Lcs + D) .Wcs D.Wb
Tsc = 0.5. + (2.11)
10, 560, 000 2, 640, 000

where:

Lcs [ft] ... length of casing joint
Wcs [lbm/ft] ... effective weight of casing in mud

The drilling line is subjected to most severe wear at the following two points:

1. The so called “pickup points”, which are at the top of the crown block sheaves and at the
bottom of the travelling block sheaves during tripping operations.

2. The so called “lap point”, which is located where a new layer or lap of wire begins on the
drum of the drawworks.

It is common practice that before the entire drilling line is replaced, the location of the pickup
points and the lap point are varied over different positions of the drilling line by slipping and/or
cutting the line.
A properly designed slipping-cut program ensures that the drilling line is maintained in good
condition and its wear is spread evenly over its length.
To slip the drilling line, the dead-line anchor has to be loosened and a few feet of new line is slipped
from the storage reel. Cutting off the drilling line requires that the line on the drawworks reel
is loosened. Since cutting takes longer and the drawworks reel comprise some additional storage,
the drilling line is usually slipped multiple times before it is cut. The length the drilling line is
slipped has to be properly calculated so that after slipping, the same part of the line, which was
used before at a pickup point or lap point, is not used again as a pickup point or lap point.
When selecting a drilling line, a “design factor” for the line is applied to compensate for wear
and shock loading. API’s recommendation for a minimum design factor (DF ) is 3 for hoisting
operations and 2 for setting casing or pulling on stuck pipe operations. The design factor of the
drilling line is calculated by:

Nominal Strength of Wire Rope [lb]
DF = (2.12)
Fast Line Load [lb]

CHAPTER 2 Page 17


Figure 2.14: Nominal breaking strength of 6 X 19 classiﬁcation rope, bright (uncoated) or drawn-
galvanized wire, (IWRC)

2.2.3 Drawworks

The purpose of the drawworks is to provide the hoisting and breaking power to lift and lower the
heavy weights of drillstring and casings. The drawworks itself consists of: (1) Drum, (2) Brakes,
(3) Transmission and (4) Catheads, see ﬁgure 2.15.
The drum provides the movement of the drilling line which in turn lifts and lowers the travelling
block and consequently lifts or lowers the loads on the hook. The breaking torque, supplied by
the drum, has to be strong enough to be able to stop and hold the heavy loads of the drilling
line when lowered at high speed. The power required by the drawworks can be calculated when
considering the fast line load and fast line speed. In this way:

νf = n.νb (2.13)

W.νb
Ph = (2.14)
33, 000.E

where:

Ph [hp] ... drum power output
νf [ft/min] ... velocity of the fast line
νb [ft/min] ... velocity of the travelling block
W [lb] ... hook load

CHAPTER 2 Page 18


n [1] ... number of lines strung
E [1] ... power efficiency of the block and tackle system

Figure 2.15: Drawworks

The input power to the drawworks is influenced by the efficiency of the chain drive and the shafts
inside the drawworks. This is expressed with:

K. (1 − K n )
E= (2.15)
n. (1 − K)

where:

K [1] ... sheave and line efficiency, K = 0.9615 is an often used value.

When lowering the hook load, the efficiency factor and fast line load are determined by:

CHAPTER 2 Page 19


n.K n . (1 − K)
ELowering = (2.16)
1 − Kn

W.K −n . (1 − K)
Ff −Lowering = (2.17)
1 − Kn

where:

Ff [lbf] ... tension in the fast line

2.3 Rig Selection
Following parameters are used to determine the minimum criteria to select a suitable drilling rig:

(1) Static tension in the fast line when upward motion is impending
(2) Maximum hook horsepower
(3) Maximum hoisting speed
(4) Actual derrick load
(5) Maximum equivalent derrick load
(6) Derrick eﬃciency factor

They can be calculated by following equations:

Pi = Ff .νf (2.18)

Ph
νb = (2.19)
W

1 + E + E.n
Fd = .W (2.20)
E.n

n+4
Fde = .W (2.21)
n

Fd E.(n + 1) + 1
Ed = = (2.22)
Fde E.(n + 4)

where:

CHAPTER 2 Page 20


Fd [lbf] ... load applied to derrick, sum of the hook load,
tension in the dead line and tension in the fast line
Fde [lbf] ... maximum equivalent derrick load, equal to
four times the maximum leg load
Ed [1] ... derrick eﬃciency factor

CHAPTER 2 Page 21


2.4 Circulation System

The principle components of the mud circulation system are: (1) mud pumps, (2) ﬂowlines, (3)
drillpipe, (4) nozzles, (5) mud pids and tanks (settling tank, mixing tank, suction tank), (6) mud
mixing equipment (mud mixing hopper) and (7) contaminant removal equipment (shale shaker,
desander, desilter, degasser), see sketch 2.16.

Figure 2.16: Circulation system

CHAPTER 2 Page 22


The flow of circulated drilling mud can be described as from the mud pit (storage of mud) via the
mud mixing hopper, where various additives like weighting material etc. can be mixed into the
mud, or the suction line to the mud pumps. At the mud pumps the mud is pressured up to the
required mud pressure value. From the mud pumps the mud is pushed through the stand pipe (a
pipe fixed mounted at the derrick), the rotary hose (flexible connection that allows the fed of the
mud into the vertically moving drillstring), via the swivel into the drillstring. Inside the drillstring
(kelly, drillpipe, drill collar) the mud flows down to the bit where it is forced through the nozzles
to act against the bottom of the hole. From the bottom of the well the mud rises up the annuli
(drill collar, drillpipe) and the mud line (mud return line) which is located above the BOP. From
the mud line the mud is fed to the mud cleaning system consisting of shale shakers, settlement
tank, de-sander and de-silter. After cleaning the mud, the circulation circle is closed when the
mud returns to the mud pit.

Figure 2.17: Sketch of mud pit

CHAPTER 2 Page 23


Figure 2.18: Mixing hopper

2.4.1 Mud Pumps

Nowadays there are two types of mud pumps in use (duplex pump, triplex pump), both equipped
with reciprocating positive-displacement pistons. The amount of mud and the pressure the mud
pumps release the mud to the circulation system are controlled via changing of pump liners and
pistons as well as control of the speed [stroke/minute] the pump is moving.

Duplex Mud Pump

The duplex mud pump consists of two cylinders and is double-acting. This means that drilling
mud is pumped with the forward and backward movement of the barrel. The pump displacement
on the forward movement of the piston is given by:

π 2
Ff d = .d .Ls (2.23)
4 l
On the backward movement of the piston, the volume is displaced:

π 2 π π
.dl .Ls − .d2 .Ls = .(d2 − d2 ).Ls
r (2.24)
4 4 4 l r

Thus the total displacement per complete pump cycle is:

CHAPTER 2 Page 24


Figure 2.19: Duplex mud pump

Figure 2.20: Duplex mud pump - Pumping Scheme

π 2 π π
.dl .Ls + .(d2 − d2 ).Ls = .Ls .(2.d2 − d2 )
l r l r (2.25)
4 4 4
Since duplex mud pumps are equipped with two cylinders, and assuming a volumetric eﬃciency
Ev , the total pump displacement per cycle is given by:

π
Fp = .Ls 2.d2 − d2 .Ev
l r (2.26)
2

Triplex Mud Pump

The triplex mud pump consists of three cylinders and is single-acting. The pump displacement
per cylinder for one complete cycle is given by:

π 2
.d .Ls (2.27)
4 l
Thus the triplex mud pump, having a volumetric eﬃciency Ev has a total mud displacement of
Fp per complete cycle.

CHAPTER 2 Page 25


3.π
Fp = .Ls .d2 .Ev
l (2.28)
4

where:

Fp [in2 /cycle] ... pump displacement (also called “pump factor”)
Ev [1] ... volumetric eﬃciency (90 ÷ 100 %)
Ls [in] ... stroke length
dr [in] ... piston rod diameter
dl [in] ... liner diameter

Figure 2.21: Triplex mud pump

Figure 2.22: Triplex mud pump - Pumping Scheme

The triplex pumps are generally lighter and more compact than the duplex pumps and their
output pressure pulsations are not as large. Because of this and since triplex pumps are cheaper
to operate, modern rigs are most often equipped with triplex mud pumps.

The the ﬂow rate of the pump [in2 /min] can be calculated with:

CHAPTER 2 Page 26


q = N.Fp (2.29)

where:

N [cycles/min] ... number of cycles per minute

The overall efficiency of a mud pump is the product of the mechanical and the volumetric efficiency.
The mechanical efficiency is often assumed to be 90% and is related to the efficiency of the prime
mover itself and the linkage to the pump drive shaft. The volumetric efficiency of a mud pump
with adequately charged suction system can be as high as 100%. Therefore most manufactures
rate their pumps with a total efficiency of 90% (mechanical efficiency: 90%, volumetric efficiency:
100%).

Note that per revolution, the duplex pump makes two cycles (double-acting) where the triplex
pump completes one cycle (single-acting).
The terms “cycle” and “stroke” are applied interchangeably in the industry and refer to one
complete pump revolution.

Pumps are generally rated according to their:

1. Hydraulic power,

2. Maximum pressure,

3. Maximum flow rate.

Since the inlet pressure is essentially atmospheric pressure, the increase of mud pressure due to
the mud pump is approximately equal the discharge pressure.
The hydraulic power [hp] provided by the mud pump can be calculated as:

∆p.q
PH = (2.30)
1, 714

where:

∆p [psi] ... pump discharge pressure
q [gal/min] ... pump discharge flow rate

CHAPTER 2 Page 27


At a given hydraulic power level, the maximum discharge pressure and the flow rate can be varied
by changing the stroke rate as well as the liner seize. A smaller liner will allow the operator to
obtain a higher pump pressure but at a lower flow rate. Pressures above 3,500 [psi] are applied
seldomly since they cause a significant increase in maintenance problems.
In practice, especially at shallow, large diameter section, more pumps are often used simultaneously
to feed the mud circulation system with the required total mud flow and intake pressure. For this
reason the various mud pumps are connected in parallel and operated with the same output
pressure. The individual mud streams are added to compute the total one.

Between the mud pumps and the drillstring so called “surge chambers”, see figure 2.23, are
installed. Their main task is to dampen the pressure pulses, created by the mud pumps.

Figure 2.23: Surge chamber

Furthermore a “discharge line” containing a relief valve is assembled before the mud reaches the
stand pipe, thus in case the pump is started against a closed valve, line rapture is prevented.
When the mud returns to the surface, it is lead over shale shakers that are composed of one or
more vibrating screens over which the mud passes before it is feed to the mud pits.
The mud pits are required to hold an excess mud volume at the surface. Here fine cuttings can
settle and gas, that was not mechanically separated can be released further. In addition, in the
event of lost circulation, the lost mud can be replaced by mud from the surface pits.

CHAPTER 2 Page 28


Figure 2.24: Shale shaker

2.5 The rotary System

The function of the rotary system is to transmit
rotation to the drillstring and consequently rotate
the bit. During drilling operation, this rotation is
to the right.
The main parts of the rotary system are: (1) swivel,
(2) rotary hose, (3) kelly, (4) rotary drive (master
pushing, kelly pushing), (5) rotary table and (6)
drillstring, see sketch 2.25.

2.5.1 Swivel

The swivel which established a connection between
hook and kelly, has to be constructed extremely ro-
bust since it has to carry the total drillstring weight
and at the same time, provide a high pressure seal
(connection between ﬂexible, non-rotating rotary
hose and the rotation kelly).

2.5.2 Kelly

The kelly has a square or hexagonal cross-section
and provides the rotation of the drillstring. Since
Figure 2.25: Rotary system
CHAPTER 2 Page 29


the kelly is made of high quality, treated steel, it
is an expensive part of the drillstring. Thus to prevent the kelly from excessive wear caused by
making and breaking connections, a kelly sub is mounted at the bottom end of it. To prevent
possible backward ﬂow of the mud in case of an kick, a kelly cock providing a backﬂow restriction
valve is often mounted between kelly and swivel.

Figure 2.26: Swivel

CHAPTER 2 Page 30


2.5.3 Rotary Drive

The rotary drive consists of master pushing and kelly pushing. The master pushing receives its
rotational momentum from the compound and drives the kelly pushing which in turn transfers
the rotation to the kelly.

Figure 2.27: Master and kelly pushing

Following equation can be applied to calculate the rotational power that is induced to the drill-
string:

T.N
PR = (2.31)
5, 250

where:

PR [hp] ... rotational power induced to the drillstring
T [ft-lb] ... rotary torque induced to the drillstring
N [rpm] ... rotation speed

Prior to drilling, the estimation of induced rotational torque is diﬃcult since it comprises a com-
bination of the torque at the bit as well as torque losses at the drillstring, following empirical
relation has been developed:

CHAPTER 2 Page 31


PR = F.N (2.32)

The torque factor is approximated with 1.5 for wells with MD smaller than 10,000 [ft], 1.75 for
wells with MD of 10,000 to 15,000 [ft] and 2.0 for wells with MD larger than 15,000 [ft].

The volume contained and displaced by the drillstring can be calculated as:
Capacity of drillpipe or drill collar:

d2
Vp = (2.33)
1, 029.4

Capacity of the annulus behind drillpipe or drill collar:

(d2 − d2 )
2 1
Va = (2.34)
1, 029.4

Displacement of drillpipe or drill collar:

(d2 − d2 )
1
Vs = (2.35)
1, 029.4

where:

d [in] ... inside diameter of drillpipe or drill collar
d1 [in] ... outside diameter of drillpipe or drill collar
d2 [in] ... hole diameter
V [bbl/ft] ... capacity of drillpipe, collar or annulus

2.6 Drilling Cost Analysis
To estimate the cost of realizing a well as well as to perform economical evaluation of the drilling
project, before commencing the project, a so called AFE (Authority For Expenditure) has to be
prepared and signed of by the operator. Within the AFE all cost items are listed as they are
known or can be estimated at the planning stage. During drilling, a close follow up of the actual
cost and a comparison with the estimated (and authorized) ones are done on a daily bases.
When preparing an AFE, diﬀerent completions and objectives (dry hole, with casing and comple-
tion, etc) can be included to cost-estimate diﬀerent scenarios.
Generally, an AFE consists of the following major groups:

CHAPTER 2 Page 32


(1) Wellsite preparation,
(2) Rig mobilization and rigging up,
(3) Rig Rental,
(4) Drilling Mud,
(5) Bits and Tools,
(6) Casings,
(7) Formation evaluation

The listed cost items and their spread are different at each company and can be different within
one company (onshore-offshore, various locations, etc.).
Along with the well plan (well proposal) a operational schedule as well as a schedule of expected
daily costs has to be prepared.
In the following simple methods to estimate the drilling costs as well as, the drilling and tripping
times are given.

2.6.1 Drilling Costs

On of the most basic estimations of drilling costs is given by:

Cb + Cr (tb + tc + tt )
Cf = (2.36)
D

where:

Cf [$/ft] ... cost per unit depth
Cb [$] ... cost of bit
Cr [$/hr] ... fixed operating cost of rig per unit time
D [ft] ... depth drilled
tb [hr] ... total rotation time during the bit run
tc [hr] ... total non-rotating time during the bit run
tt [hr] ... trip time

It has been found that drilling cost generally tend to increase exponentially with depth. Thus,
when curve-fitting and correlation methods are applied, it is convenient to assume a relationship
between drilling cost C and depth D as in equation 2.37:

C = a.eb.D (2.37)

The constants a and b depend primary on the well location.

CHAPTER 2 Page 33


2.6.2 Drilling Time

The drilling time can be estimated based on experience and historical penetration rates. Note that
the penetration rate depends on: (1) type of bit used, (2) wear of bit used, (3) drilling parameters
applied (WOB, RPM), (4) hydraulics applied (hydraulic impact force due to mud flow through
nozzles), (5) effectiveness of cuttings removal, (6) formation strength and (7) formation type.
Therefore an analytic prediction of the rate of penetration (ROP) is impossible. Estimations are
generally based on the assumption of similar parameters and historic ROPs.
To estimate the drilling time, the so called “penetration rate equation”, equation 2.38, is analyzed.

dD
= K.ea2 .D (2.38)
dt

When the historical values of depth [ft] versus ROP [ft/hr] are plotted on a semilogarithmic graph
paper (depth on linear scale), a straight line best-fit of the equation:

1
td = .e2.203.a2 .D (2.39)
2.303.a2 .K

estimates the drilling time. Here a2 is the reciprocal of the change in depth per log cycle of the
fitted straight line, K is the value of ROP at the surface (intercept of fitted straight line at depth
= 0 ft).
The depth that can be drilled with each individual bit depends on (1) bit condition when inserted,
(2) drilling parameters, (3) rock strength and (4) rock abrasiveness. Estimations of possible
footages between trips can be obtained from historical data or applying equation 2.40:

1
D= .ln 2.303a2 .L.tb + 22.303.a2 .Di (2.40)
2.303.a2

where:

Di [ft] ... depth of the last trip
D [ft] ... depth of the next trip

All other parameters are defined as above.

2.6.3 Tripping Time

Tripping time is also a major contributor to the total time spent for drilling a well. Tripping can
be either scheduled (change of bit, reach of casing point, scheduled well-cleaning circulation) or

CHAPTER 2 Page 34


on-scheduled, due to troubles. Types of troubles, their origin and possible actions are discussed
in a later chapter.
Following relationship can be applied to estimate the tripping time to change the bit. Thus the
operations of trip out, change bit, trip in are included:

ts
tt = 2. .D (2.41)
ls

where:

tt [hr] ... required time for round trip
ts [hr] ... average time required to handle one stand
D [ft or m] ... length of drillstring to trip
ls [ft or m] ... average length of one stand

The term “stand” refers to the joints of drillpipe left connected and placed inside the derrick
during tripping. Depending on the derrick seize, one stand consists mostly of three, sometimes
four drillpipes. In this way during tripping only each third (fourth) connection has to be broken
and made up for tripping.

CHAPTER 2 Page 35


2.7 Examples

1. The output torque and speed of a diesel engine is 1,650 [ft-lbf] and 800 [rpm] respectively.
Calculate the brake horsepower and overall engine efficiency when the diesel consumption rate is
15.7 [gal/hr]. What is the fuel consumption for a 24 hr working day?

2. When drilling at 7,000 [ft] with an assembly consisting of 500 [ft] drill collars (8 [in] OD, 2.5
[in] ID, 154 [lbm/ft]) on a 5 [in], 19.5 [lbm/ft] , a 10.0 [ppg] drilling mud is used. What are the
ton-miles applying following assumptions (one joint of casing is 40 [ft], travelling block assembly
weights 28,000 [lbm], each stand is 93 [ft] long) when:

(a) Running 7 [in], 29 [lbm/ft] casing,
(b) Coring from 7,000 [ft] to 7,080 [ft],
(c) Drilling from 7,000 [ft] to 7,200 [ft],
(d) Making a round-trip at 7,000 [ft]?

3. The rig’s drawworks can provide a maximum power of 800 [hp]. To lift the calculated load of
200,000 [lb], 10 lines are strung between the crown block and the traveling block. The lead line is
anchored to a derrick leg on one side of the v-door. What is the:

(a) Static tension in the fast line,
(b) Maximum hook horsepower available,
(c) Maximum hoisting speed,
(d) Derrick load when upward motion is impending,
(e) Maximum equivalent derrick load,
(f) Derrick efficiency factor?

4. After circulation the drillstring is recognized to be stuck. For pulling the drillstring, following
equipment data have to be considered: derrick can support a maximum equivalent derrick load of
500,000 [lbf], the drilling line strength is 51,200 [lbf], the maximum tension load of the drillpipe
is 396,000 [lbf]. 8 lines are strung between the crown block and the traveling block, for pulling to
free the stuck pipe, a safety factor of 2.0 is to be applied for the derrick, the drillpipe as well as
the drilling line. What is the maximum force the driller can pull to try to free the pipe?

5. To run 425,000 [lb] of casing on a 10-line system, a 1.125 [in], 6x19 extra improved plow steel
drilling line is used. When K is assumed to be 0.9615, does this configuration meet a safety factor
requirement for the ropes of 2.0? What is the maximum load that can be run meeting the safety
factor?

CHAPTER 2 Page 36


6. A drillstring of 300,000 [lb] is used in a well where the rig has sufficient horsepower to run
the string at a minimum rate of 93 [ft/min]. The hoisting system has 8 lines between the crown
block and the travelling block, the mechanical drive of the rig has following configuration: Engine
no. 1: (4 shafts, 3 chains), engine no. 2: (5 shafts, 4 chains), engine no. 3: (6 shafts, 5 chains).
Thus the total elements of engine 1 is 7, of engine 2 9 and of engine 3 11. When the efficiencies of
each shaft, chain and sheave pair is 0.98 and 0.75 for the torque converter, what is the minimum
acceptable input horsepower and fast line velocity?

7. A triplex pump is operating at 120 [cycles/min] and discharging the mud at 3,000 [psig]. When
the pump has installed a 6 [in] liner operating with 11 [in] strokes, what are the:

(a) Pump factor in [gal/cycles] when 100 %
volumetric efficiency is assumed,
(b) Flow rate in [gal/min],
(c) Pump power development?

8. A drillstring consists of 9,000 [ft] 5 [in], 19,5 [lbm/ft] drillpipe, and 1,000 [ft] of 8 [in] OD, 3
[in] ID drill collars. What is the:

(a) Capacity of the drillpipe in [bbl],
(b) Capacity of the drill collars in [bbl],
(c) Number of pump cycles required to pump surface mud to the bit
(duplex pump, 6 [in] liners, 2.5 [in] rods, 16 [in] strokes,
pumping at 85 % volumetric efficiency),
(d) Displacement of drillpipes in [bbl/ft],
(e) Displacement of drill collars in [bbl/ft],
(f) Loss in fluid level in the hole if 10 stands (thribbles) drillpipe
are pulled without filling the hole (casing 10.05 [in] ID),
(g) Change in fluid level in the pit when the hole is filled after
pulling 10 stands of drillpipe. The pit is 8 [ft] wide and
20 [ft] long.

9. A diesel engine gives an output torque of 1,740 [ft-lbf] at an engine speed of 1,200 [rpm]. The
rig is operated in Mexico at an altitude of 1,430 [ft] above MSL at a average temperature of 28
◦
C. When the fuel consumption rate is 31.8 [gal/hr], what is the output power and the overall
efficiency of the engine?
10. A rig must hoist a load of 320,000 [lb]. The drawworks can provide an input power to the
block and tackle system as high as 500 [hp]. Eight lines are strung between the crown block and
the travelling block. Calculate:

CHAPTER 2 Page 37


(a) Static tension in the fast line,
(b) Maximum hook horse power,
(c) Maximum hoisting speed,
(d) Effective derrick load,
(e) Maximum equivalent derrick load,
(f) Derrick efficiency factor.

11. The weight of the travelling block and hook is 23,500 [lb], the total well depth equals 10,000
[ft]. A drillpipe of OD 5 [in], ID 4.276 [in], 19.5 [lb/ft] and 500 [ft] of drill collar OD 8 [in], ID 2- 13
16
[in], 150 [lb/ft] comprise the drillstring. The hole was drilled with a mud weight of 75 [lb/ft3 ]. steel
weight: 489.5 [lb/ft3 ], line and sheave efficiency factor = 0.9615, block and tackle efficiency=0.81.
Calculate:

(a) Weight of the drill string in air and in mud,
(b) Hook load,
(c) Dead line and fast line load,
(d) Dynamic crown load,
(e) Design factor for wire line for running drill string,

CHAPTER 2 Page 38


Chapter 3

Geomechanics

The knowledge of the formations to penetrate, their strength properties as well as their behaviour
when in contact with various drilling fluids is essential to properly plan and complete a successful
drilling project. Parameters like pore pressure and formation strength determine aspects like:

1. Choice of mud weight profile,

2. Determination of casing setting depths,

3. Design of optimal casing strings,

4. Selection of the drill bit,

5. Cementing additives and procedures.

The way how the formations react to drilling mud influences the selection of mud additives,
borehole stability and therefore well control aspects.
Within drilling, it is common to express pressures as gradients. With this concept, the hydrostatic
pressure can be given as equivalent density which is independent of the depth and thus makes its
comprehension and correlations of various concepts easier. On the other hand, when gradients
are applied, it has to be always kept in mind that they are referred to a specific depth. Knowing
this reference depth is essential to compute back the corresponding downhole pressures. Within
drilling engineering, the drilling floor or rotary table (RKB) is the most often used reference depth.
Geologists and geophysicists generally prefer to use their data in reference to ground floor or mean
sea level (MSL).
To correct data expressed in RKB to MSL or do the reverse, following equations can be applied:

CHAPTER 3 Page 39


Correct RKB to MSL reference:

D
dM SL = dRKB . (3.1)
D − hRKB

Convert MSL data to RKB:

D − hRKB
dRKB = dM SL . (3.2)
D

Another common problem is when data
referenced to one RKB (e.g. rig used
to drill the wildcat well) has to be ap-
plied for further/later calculations (e.g.
drilling development wells from a pro-
duction platform). Here the data have
to be corrected from RKB1 to RKB2 .

Correct from RKB1 to RKB2 :

D − ∆h
dRKB2 = dRKB1 . (3.3) Figure 3.1: Pore pressure and fracture gradient profile
D
for different offshore rigs (semisub and jackup)

where:

D [m or ft] ... total depth of point of interest in reference to RKB
hRKB [m or ft] ... height of RKB above MSL
∆h [m or ft] ... difference of elevation of RKB1 to RKB2

CHAPTER 3 Page 40


3.1 Geology Prediction

Normally when a well is to be drilled, the drilling en-
gineer is supplied from the geology department (or the
geologist within the project team) with a sequence of
predicted subsurface formations, their characteristics
and markers, as well as knowledge about where special
care has to be taken. Geologists draw this information
from studying the local geology (deposition history),
seismic mappings (2D or 3D surveys) and perform well
to well correlations (geological maps). Whenever new
information is gained (due to drilling and evaluation
of a new well or further geophysical measurements)
these maps are updated. A typical geological profile
supplied to the drilling engineer is sketched with figure
3.2 which is based on seismic profiles (figure 3.3).

3.2 Pore pressure Prediction

To understand the local subsurface pressure regimes,
the geologic processes along with the depositional his-
tory and tectonic abnormalities have to be studied.
When the well is located within shallow sediments that
were laid down slowly within a deltaic depositional en-
vironment, the subsurface formation pressures can be
assumed to be hydrostatic.

Figure 3.2: Typical geological profile to
plan a well
3.2.1 Hydrostatic Pressure

By definition, a hydrostatic pressure is developed due
to the own weight of a fluid at a certain depth. This
relationship is expressed as:

p = ρ.g.h = 9.81.ρ.h (3.4)

Or in field units:

p = 0.052.ρf l .D (3.5)

where:

CHAPTER 3 Page 41


ρf l [ppg] ... density of the fluid causing hydrostatic pressure
ρ [kg/m3 ] ... average fluid density
D [ft] ... depth at which hydrostatic pressure occurs (TVD)
h [m] ... vertical height of column of liquid
p [psi] ... hydrostatic pressure
g [m/s2 ] ... acceleration due to gravity

Figure 3.3: Seismic record to determine the subsurface structure

When the weight of the solid particles buried are supported by grain-to-grain contacts and the with
the particles buried water has free hydraulic contact to the surface, the formation is considered
as hydrostatically pressured. As it can be seen, the formation pressure, when hydrostatically
pressured, depends only on the density of the formation fluid (usually in the range of 1.00 [g/cm3 ]
to 1.08 [g/cm3 ], see table 3.4) and the depth in TVD.

CHAPTER 3 Page 42


Figure 3.4: Water density in relation to salinity at 20 ◦ C

When the burial depth increases, the overlaying pressure (overburden stress) increases. This
decreases the pore space between the grains and thus the porosity of the formation.

The overburden stress can be calculated
assuming an average bulk density ρb
of the overlaying formations applying
equation 3.6:

D
σob = ρb .g.dD (3.6)
0

The average bulk density is normally
found by integration of the density log
readings. When density logs were not
run (e.g. at shallow formations), sonic
log correlation methods, together with
lithology and mineralogical evaluations
are applied to determine ρb
During burial of the sediments, forma-
tion water is constantly expelled due to
the reduction of formation porosity, see
fig 3.6.
As long as formation water can be ex-
pelled, the formations are hydrostatic Figure 3.5: Porosity profile with increasing depth
(or normally) pressured.

When drilling a well, formations are often encountered that are under a different pressure regime.
These formations are named to be “abnormally pressured”. Abnormal pressures can be positive
(actual formation pressures are higher than hydrostatic pressure) or negative (actual formation
pressures are lower than hydrostatic pressure). Sometimes the term “subnormal pressure” is used

CHAPTER 3 Page 43


when the formation pressure is lower than the hydrostatic one.

Figure 3.6: Volume of fluid expelled during compaction of an argillaceous sediment

Some mechanisms that lead to abnormally pressured formations are:

1. Compaction effects,
2. Aquathermal expansion,
3. Diagenetic effects,
4. Differential density effects (Osmosis),
5. Fluid migration effects,
6. Evaporite Deposits,
7. Organic matter transformation,
8. Tectonics,
9. Connection to depleted reservoirs,
10. Others.

From the various effects mentioned above, the compaction one is considered to be often the
governing one and hence is discussed in more detail below.
As mentioned above, while burying of the sediments, formation water is expelled with increasing
depth and temperatures due to reduction in pore space and diagenesis of the rock materials. As
long as the permeability and the effective porosity of the rock is high enough so that the formation
water can escape as quickly as the natural compaction takes place, the formations are normally
pressured. The (vertical) pressures acting inside formations can be modelled as:

σob = σz + p (3.7)

where:

CHAPTER 3 Page 44


σob [psi] ... overburden stress
σz [psi] ... vertical stress supported by the grain-to-grain connections
p [psi] ... formation pore pressure

When the formation water can not escape as quickly as the pore space is reduced, it is trapped
inside the formations. In this scenario, the increasing overburden stress will pressurize the forma-
tion water and the formation will become abnormally pressured. In this situation, the porosity
of the formation will not follow the natural compaction trend (porosity at abnormally pressured
formations will be higher than at normally pressured ones). Along with the higher porosity, the
bulk density as well as the formation resistivity will be lower at abnormally pressured formations.
These circumstances are often applied to detect and estimate the abnormal formation pressures.
The bulk density [ppg] of a formation is estimated by equation 3.8:

ρb = ρg .(1 − φ) + ρf l .φ (3.8)

where:

ρg [ppg] ... grain density
ρf l [ppg] ... formation ﬂuid density
φ [1] ... total porosity of the formation

Figure 3.7: Average bulk density change in sediments

As it can be seen from ﬁgure 3.7, an average bulk density of 2.31 [g/cm3] (equal to 1 [psi/ft]) can
be assumed for deep wells as approximation.

CHAPTER 3 Page 45


In areas of frequent drilling activities or where formation evaluation is carried out extensively, the
natural trend of bulk density change with depth is known.
For shale formations that follow the natural compaction trend, it has been observed that the
porosity change with depth can be described using below relationship:

φ = φo .e−K.Ds (3.9)

where:

φ [1] ... porosity at depth of interest
φo [1] ... porosity at the surface
K [ft−1 ] ... porosity decline constant, specific for each location
Ds [ft] ... depth of interest (TVD)

When equation 3.9 is substituted in equation 3.8 and equation 3.6 and after integration the
overburden stress profile is found for an offshore well as:

0.052
σob = 0.052.ρsw .Dw + 0.052.ρg .Dg − .(ρg − ρf l ).φo .(1 − e−K.Dg ) (3.10)
K

where:

Dg [ft] ... depth of sediment from sea bottom
ρsw [ppg] ... sea water density

Thus when the overburden stress profile is known, the depth where the abnormal pressure starts
is given and with the shape of the profile, it is determined at which depth the matrix stress is
equal to the matrix stress at the abnormal formation pressure (“matrix point”), see figure 3.8.
Now, the normal formation pressure at the matrix point is calculated by equation 3.5 and the
matrix stress with equation 3.7. Applying the assumption that the matrix stress is equal at the
matrix point with the one at the abnormal formation pressure, and when the overburden stress
at the abnormal formation pressure is calculated with equation 3.10, the abnormal formation
pressure is found when rearranging equation 3.7.
The actual measurement of formation pore pressure is very expensive and possible only after the
formations have been drilled. In this respect, pore pressures have to be estimated before drilling to
properly plan the mud weights, casing setting depths, casing design, etc. as well as being closely
monitored during drilling.

CHAPTER 3 Page 46


Figure 3.8: Overburden stress profile for abnormal formation pressure

To estimate the pore pressure and most important, define where abnormal pore pressures are to be
expected, porosity logs and seismic measurements are applied most often. As mentioned before,
shale formations tend to follow a defined porosity reduction trend with increasing depth. When
this trend is interrupted, abnormally pressured formations are to be expected. To knowledge of
its depths are importment since they may lead to a necessary setting of casing and weighting up
the mud system. The amount of how much the mud weight has to be increased depends on the
amount of abnormal pressure expected and the contingency of the well.

CHAPTER 3 Page 47


Abnormal pressure detection while drilling

When the well is in progress and abnormal formation pressures are expected, various parameters
are observed and cross-plotted. Some of these while drilling detection methods are:

(a) Penetration rate,
(b) “d” exponent,
(c) Sigmalog,
(d) Various drilling rate normalisations,
(e) Torque measurements,
(f) Overpull and drag,
(g) Hole fill,
(h) Pit level – differential flow – pump pressure,
(i) Measurements while drilling,
(j) Mud gas,
(k) Mud density,
(l) Mud temperature,
(m) Mud resistivity,
(n) Lithology,
(o) Shale density,
(p) Shale factor (CEC),
(q) Shape, size and abundance of cuttings,
(r) Cuttings gas,
(s) X-ray diffraction,
(t) Oil show analyzer,
(u) Nuclear magnetic resonance.

d-exponent
It has been observed that when the same formation is drilled applying the same drilling parameters
(WOB, RPM, hydraulics, etc.), a change in rate of penetration is caused by the change of differ-
ential pressure (borehole pressure - formation pressure). Here an increase of differential pressure
(a decrease of formation pressure) causes a decrease of ROP, a decrease of differential pressure (in-
crease of formation pressure) an increase of ROP. Applying this observation to abnormal formation
pressure detection, the so called “d-exponent” was developed.

R
log10 60.N
d= 12.W
(3.11)
log10 106 .D

where:

R [ft/hr] ... penetration rate
N [rev./min] ... rotation speed

CHAPTER 3 Page 48


W [lb] ... weight on bit
D [in] ... hole seize

R
The term 60.N
is always less than 1 and represents penetration in feet per drilling table rotation.
Wile drilling is in progress, a d-exponent log is been drawn. Any decrease of the d-exponent value
in an argillaceous sequence is commonly interpreted with the respective degree of undercompaction
and associated with abnormal pressure. Practice has shown that the d-exponent is not sufficient to
conclude for abnormal pressured formations. The equation determining the d-exponent assumes
a constant mud weight. In practice, mud weight is changed during the well proceeds. Since a
change in mud weight results in a change of d-exponent, a new trend line for each mud weight has
to be established, which needs the drilling of a few tenth of feet. To account for this effect, the so
called “corrected d-exponent” dc was developed:

ρf l
dc = d. (3.12)
ρeqv

where:

d ... d-exponent calculated with equation 3.11
ρf l [ppg] ... formation fluid density for the hydrostatic gradient in the region
ρeqv [ppg] ... mud weight

Abnormal pressure evaluation

After an abnormal pressure is detected or the well is completed, various wireline log measurements
are used to evaluate the amount of overpressures present. Among the most common ones are:

(a) Resistivity, conductivity log,
(b) Sonic log,
(c) Density log,
(d) Neutron porosity log,
(e) Gamma ray, spectrometer,
(f) Velocity survey or checkshot,
(g) Vertical seismic profile.

With these log measurements trend lines are established and the amount the values deviate at
the abnormally pressured formations from the trend line are applied to determine the value of
overpressure. Sketches of how deviations of the trend lines for the individual wireline logs are
shown in figure 3.9.
Methods to evaluate the amount of overpressures are:

CHAPTER 3 Page 49


Figure 3.9: Schematic responses of wireline logs in an undercompacted zone

1. Equivalent depth method,

2. Ratio method,

3. Eaton method,

3.3 Fracture Gradient Prediction

3.3.1 Interpretation of Field Data

Leak-off data
Normally, after a casing is set and cemented, a so called leak-off test (LOT) is performed. The main
issue of a LOT is to check the strength of the formation at the casing shoe. With this knowledge,
the maximum kick pressure allowed that does not fracture the formation is determined. It is also
the key parameter in stress modelling and borehole integrity evaluation.
Sometimes the test is not continued until leak-off (especially when oil based muds are used) and
the formation is only pressured up until a certain value. This test is called formation integrity text
(FIT). In this way, when fracture strength is evaluated, it is important to distinguish LOT data
and FIT data. The pressure where fractures are initiated is commonly called leak-off pressure and
when referred to the individual depth, named fracture gradient.
Since casings are often set into competent shale formations and the LOT are carried out at them,
but on the other hand lost circulation often takes place in permeable sandstone formations, the
evaluation of LOT data to determine fracture gradients should be carried out by separating the

CHAPTER 3 Page 50


data into two groups, one concerning the competent shale formations with higher fracture gradients
and a second one for permeable sandstone (coal, chalk, etc.) formations exhibiting weaker fracture
gradients.
When LOT data are evaluated, a considerable spread is often found. It is common practice to
first plot the LOT values vs. depth and check how well they correlate. When the spread of LOT
values is to large to define a correlation line, the “effective stress concept” can be applied.

Effective stresses
The effective stress concept states that the stress in the rock matrix is equal the total stress minus
the pore pressure. This is expressed in equation 3.13:

σef f = σt − Po (3.13)

Horizontal stresses
When the borehole is vertical, as well as a hydrostatic stress state is assumed, the LOT values
can be expressed as:

LOT = 2.σa − Po (3.14)

where:

LOT [psi] ... leak-off test value
σa [psi] ... average horizontal stress
Po [psi] ... pore pressure

Since when the LOT is carried out, the pore pressure is known or measured as well, the horizontal
stress can be evaluated by equation 3.15:

LOT − Po
σa = (3.15)
2

The horizontal stress as derived above can also be used for a correlation when plotted vs. depth.

Influence of hole inclination
Since formations are generally not isotropic or even under a hydrostatic stress state which was
assumed above, fracture gradients do normally depend on the inclination of the borehole. To
account for this, the coupling of the fracture gradient of an inclined hole with a vertical one can
be modeled by equation 3.16:

CHAPTER 3 Page 51


1 ∗
Pwf (θ) = Pwf (0) + .(Po − Po ). sin2 θ (3.16)
3
where:

Pwf (θ) [psi] ... fracture gradient at α inclined borehole
Pwf (0) [psi] ... fracture gradient at vertical borehole
Po [psi] ... pore pressure at specific depth
∗
Po [psi] ... pore pressure constant
θ [rad] ... borehole inclination

Fracture gradients at shallow depth
The determination of fracture gradients for shallow depth is often difficult since very little data
exists. This is due to the circumstance that at shallow depth, blowout preventers are often
not installed and thus no pressure testing can be carried out. Especially at offshore wells, the
knowledge of shallow fracture gradients are important since the margin between pore pressure and
fracture gradient is narrow and the danger of shallow gas pockets exists. As practice shows, the
spread of fracture gradients are larger at shallow depths and decrease with depth.

3.4 Mud Weight Planning
Selecting the correct mud weight for drilling the individual sections comprises a key factor to
realize a in-gauge hole and avoid various borehole problems.
Too low mud weight may result in collapse and fill problems (well cleaning), while too high mud
weight may result in mud losses or pipe sticking. Practice has also shown that excessive variations
in mud weight may lead to borehole failure (fatigue type effect), thus a more constant mud weight
program should be aimed for. Along with a more constant mud weight program, the equivalent
circulation density (ECD) as well as the surge and swab pressures shall be kept within limits.
Washouts of the borehole are sometimes caused by jet actions of the bit nozzles but also sometimes
by to low mud weight causing a breakdown of the borehole wall. A higher mud weight will therefore
balance the rock stresses better and tend to keep the borehole more in-gauge.
A decease in hole diameter is often due to swelling (clay swelling) requiring wiper trips or back-
reaming. This necessity is sometimes reduced by higher mud weights.
An increased mud weight increases the danger of becoming differential stuck at permeable for-
mations. Therefore mud weight shall not be chosen to be to high. However, what is sometimes
believed to be a differentially stuck drillstring is sometimes due to a borehole collapse which packs
the hole around the bottom-hole assembly. A lower mud weight also causes breakouts of shale
layers leaving sand formations in-gauge, see figure 3.10. This can increase the danger of getting
differential stuck at the exposed sand stringers.

CHAPTER 3 Page 52


Thus when considering the danger of differential sticking, it is recommended to keep the mud
weight below a certain value but it shall not be as low as possible.
The same is true for lost circulation problems.
As long as the mud weight is kept below a
critical value, lost circulation will not occur.
It is often argued that to have a as high as
possible rate of penetration, the mud weight
shall be kept as close as possible to the for-
mation pressure gradient plus a safety mar-
gin of around 100 [psi]. Although it is true
that a small reduction in mud weight increases
the penetration rate, but this increases has to
be weighted against the possible induction of
hole problems and additional lost time.
Figure 3.10: Partial collapse in mixed lithology
A higher mud weight requires the use of more
mud additives which makes the well more ex-
pensive, but it was found that these extra costs are usually neglectable.
When drilling within areas where the subsurface pressure regimes are not well known, it is often
argued that a lower mud weight easies the detection of abnormal pressures. In some locations, a
practice called “drilling for a kick” was applied to detect overpressured formations. For this, a
relatively low mud weight was applied until a kick was detected (pressure gradient at this depth
was equal to the used mud weight) and handling the kick, the mud weight was increased. Therefore
and since a higher mud weight also suppresses high gas readings, the mud weight of exploration
wells are often designed to be lighter than the ones for development wells.
Based on all these considera-
tions, the “median line con-
cept” is recommended gen-
erally for mud weight plan-
ning.

Thereto, the mid-point be-
tween the fracture pressure
and the pore pressure defines
the borehole pressure that
is equal to the ideal in-situ
stress. Maintaining the mud
pressure close to this level
causes least disturbances on
the borehole wall.
Figure 3.11: Effects of varying the borehole pressure

CHAPTER 3 Page 53


This principle is sketched in figure 3.11 and
mathematically found with equation 3.17:

Pwf + Po
σa = (3.17)
2
where:

σa [psi] ... average horizontal
in-situ stress
Pwf [psi] ... fracture stress
Po [psi] ... pore pressure

An application of this principle is shown in figure
3.12:

Experience had shown that new drilling fluid
exacerbates fracturing/lost circulation and leak-
off tests applying used drilling muds give higher
leak-off values than when carried out with new
ones. Therefore it is a good practice that, when
the mud weight has to be changed after setting
casing, drilling is usually started with a lower Figure 3.12: Pressure gradients for a well
mud weight. After drilling about 100 [m] below
the casing shoe, the mud weight is then gradu-
ally increased to the desired value.
Furthermore it should be noticed that within an open-hole section, the mud weight shall only be
increased and not decreased since tight hole may result. An increase of mud weight in steps of
0.05 [g/cm3] is good practice and in convenience of the mud engineer.

CHAPTER 3 Page 54


3.5 Examples

CHAPTER 3 Page 55


CHAPTER 3 Page 56


Chapter 4

Drilling Hydraulics

To realize a safe, efficient and cost-effective drilling project, drilling hydraulics, also known as rig
hydraulics, play an important role. The different aspects that make up optimum rig hydraulics
are:

1. Hydraulic energy impact on the bit,
2. Friction pressure losses through the surface equipment, drillstring, annuli and drill bit,
3. Efficient hole cleaning,
4. Nozzle selection and,
5. Produced pump pressure.

Some of the drilling problems that are due to improperly designed drilling hydraulics are failure of
sufficient hole cleaning leaving cuttings in the hole and lead to stuck pipe, lost circulation causing
kicks and slow penetration rates.
To understand the various dependencies of efficient drilling hydraulics, the hydrostatic pressure
inside the wellbore, types of fluid flow, criteria of fluid flow and commonly used fluid types for
different drilling operations are discussed. By understanding these concepts various aspects of the
design of the hydraulics system like

1. Pressure losses (surface equipment, drillstring, bit, annulus),
2. Bit nozzle seize selection,
3. Surge and swab pressure due to drillstring movement,
4. Optimization of bit hydraulics,
5. Carrying capacity of the drilling fluid.

are discussed further on.

CHAPTER 4 Page 57


4.1 Hydrostatic Pressure Inside the Wellbore
For oil well applications, the fluid may be mud, foam, mist, air or natural gas. For a complex fluid
column consisting of multiple fluids, the hydrostatic pressure is given in field units by:

n
p = 0.052. ρm . (Di − Di−1 ) (4.1)
i=1

where:

ρmi [ppg] ... mud weight of the ith fluid column

When gas is present in the well, the hydrostatic pressure developed by the gas column is calculated
with:

M.(D−Do )

p = po .e (
1,544.z. Tf +460 ) (4.2)

where:

z [1] ... real gas deviation factor
po [psi] ... surface pressure
D [ft] ... total depth (TVD)
Tf [F] ... bottom hole temperature of the formation

The molecular weight M of the gas is found as:

80.3.z. (T + 460) .ρg
M= (4.3)
p

where:

ρg [ppg] ... density of the gas
T [F] ... average gas density

For practical purposes, the hydrostatics due to a complex fluid column are converted to an equiva-
lent single-fluid hydrostatic pressure. To do this, all individual hydrostatic pressures are summed

CHAPTER 4 Page 58


up for a specific depth pd and then converted to an equivalent mud weight ρe [ppg] that would
cause the same hydrostatic pressure.

pd
ρe = (4.4)
0.052.D

Therefore the equivalent mud weight has to be always referenced to a specific depth.
As the mud is used to transport the cuttings from the bottom of the hole to the surface and
penetrated formations often contain a certain amount of formation gas, the mud column at the
annulus is usually mixed with solids and gas. This alters the weight of the mud at the annulus.
The new average mud weight ρm of a mixture containing mud and solids can be calculated as:

n n n
i=1 mi i+1 ρi .Vi
ρm = n = n = ρi .fi (4.5)
i=1 Vi i=1 Vi i=1

where:

mi [lbm] ... mass of component i
Vi [gal] ... volume of component i
ρi [ppg] ... density of component i
fi [1] ... volume fraction of component i

I should be noted that only solids that are suspended within the mud do alter the mud weight.
Settled particles do not affect the hydrostatic pressure.
If gas is present in the mud column as well, the density of the gas component is a function of the
depth and will decrease with decreasing pressure. In this way, the density of mud containing gas
is decreasing with decreasing depth.
When the gas-liquid mixture is highly pressured (e.g. deep section of the well), the variation of
the gas density can be ignored and the average mud density containing gas calculated with:

(ρf + M.Nν ) .p
ρ = ρf .(1 − fg ) + ρg .fg = (4.6)
p + z.Nν .R.T

where:

z.Nν . R.T
p
fg = (4.7)
1 + z.Nν . R.T
p

CHAPTER 4 Page 59


fg [1] ... volume fraction of gas
ρg [ppg] ... density of gas
Nν [# moles] ... moles of gas dispersed in one gallon of mud

When the variation of gas density can not be ignored (e.g. shallow depth), the equation 4.8 has
to be solved by iteration to compute the change in pressure:

p2 − p1 z.Nν .R.T p2
D2 − D1 = + . ln (4.8)
0.052. (ρf + M.Nν ) 0.052. (ρf + M.Nν ) p1

where:
p2 +p1
z is calculated at p = 2

It is essential to understand that well control and the safety of drilling operations are strongly
depended on the maintenance of proper hydrostatic pressure. This pressure is needed to counter-
balance the formation pressure. In case the hydrostatic pressure in the borehole is higher than the
formation pressure, the situation is called “over-balanced”. This prevents kicks (fluid flow from the
formation into the borehole) and causes at permeable formations an intrusion of some mud (water
component) into the formation. The intrusion is stopped by the built up of mud cake that seals
off permeable formations. On the other hand, the hydrostatic pressure inside the borehole must
not be higher than the fracture pressure of the formations penetrated since this would fracture
the formation artificially, cause loss of circulation and lead to well control problems. To obtain
maximum penetration rates the hydrostatic pressure should be kept as close as practical to the
formation pressure since a higher differential pressure (hydrostatic pressure - formation pressure)
leads to worst cutting removal from the bottom of the well. Due to this circumstance, underbal-
anced drilling techniques have been developed that use air, foam or mist as drilling fluids. Here
the formation pressure is higher than the hydrostatic pressure caused by the mud and thus the
well is constantly kicking. With underbalanced drilling techniques much higher penetration rates
are possible but well control can be a problem. Therefore underbalanced drilling is prohibited by
some governments and/or in some areas.

4.2 Types of Fluid Flow
Since multiple aspects of drilling and completion operations require the understanding of how fluid
moves through pipes, fittings and annulus, the knowledge of basic fluid flow patterns is essential.
Generally, fluid movement can be described as laminar, turbulent or in transition between laminar
and turbulent.
It should be understood that rotation and vibrations influence the rheological properties of drilling
fluids. Also the pulsing of the mud pumps cause variations in the flow rates as well as the mean
flow rates. Furthermore changing solid content influences the actual mud density and its plastic
viscosity.

CHAPTER 4 Page 60


Figure 4.1: Real gas factor z
CHAPTER 4 Page 61


Fluid movement, when laminar flow is present, can be described as in layers or “laminae”. Here at
all times the direction of fluid particle movement is parallel to each other and along the direction
of flow. In this way no mixture or interchange of fluid particles from one layer to another takes
place. At turbulent flow behavior, which develops at higher average flow velocities, secondary
irregularities such as vortices and eddys are imposed to the flow. This causes a chaotic particle
movement and thus no orderly shear between fluid layers is present.
The so called “Reynolds number” is often used to distinguish the different flow patterns. Af-
ter defining the current flow pattern, different equations are applied to calculate the respective
pressure drops.

For the flow through pipes, the Reynolds number is determined with:

928.ρm .ν.di
NRe = (4.9)
µ

q, [gal/min] 17.16. (q, [bbl/min])
ν= 2
= (4.10)
2.448.di d2i

and for the flow through annuli:

928.ρm .ν.de
NRe = (4.11)
µ

q, [gal/min] 17.16. (q, [bbl/min])
ν= = (4.12)
2.448. (d2 − d1 )
2 2
d2 − d2
2 1

de = 0.816. (d2 − d1 ) (4.13)

where:

ρ [ppg] ... fluid density
di [in] ... inside pipe diameter
ν [ft/sec] ... mean fluid velocity
µ [cp] ... fluid viscosity
de [in] ... equivalent diameter of annulus
d2 [in] ... internal diameter of outer pipe or borehole
d1 [in] ... external diameter of inner pipe

The different flow patterns are then characterised considering the Reynolds number. Normally
the Reynolds number 2,320 distinguishes the laminar and turbulent flow behavior, for drilling
purposes a value of 2,000 is applied instead. Furthermore it is assumed that turbulent flow is fully

CHAPTER 4 Page 62


developed at Reynolds numbers of 4,000 and above, thus the range of 2,000 to 4,000 is named
transition flow:

NRe < 2, 000 ... laminar flow
2, 000 < NRe < 4, 000 ... transition flow
NRe > 4, 000 ... turbulent flow

4.3 Rheological Classification of Fluids
All fluids encountered in drilling and production operations can be characterized as either “New-
tonian” fluids or “Non-Newtonian” ones. Newtonian fluids, like water, gases and thin oils (high
API gravity) show a direct proportional relationship between the shear stress τ and the shear rate
γ, assuming pressure and temperature are kept constant. They are mathematically defined by:
˙

−dνr
τ = µ. = µ.γ
˙ (4.14)
dr

where:

τ [dyne/cm2] ... shear stress
γ
˙ [1/sec] ... shear rate for laminar flow within circular pipe
µ [p] ... absolute viscosity [poise]

A plot of τ vs. −dνr produces a straight line that
dr
passes through the origin and has a slop of µ.
Most fluids encountered at drilling operations like
drilling muds, cement slurries, heavy oil and gelled
fracturing fluids do not show this direct relationship
between shear stress and shear rate. They are char-
acterized as Non-Newtonian fluids. To describe the
behavior of Non-Newtonian fluids, various models
like the “Bingham plastic fluid model”, the “Power-
law fluid model” and “Time-dependent fluid mod-
els” were developed where the Bingham and Power-
law models are called “Time-independent fluid
model” as well. The time dependence mentioned
here concerns the change of viscosity by the dura- Figure 4.2: Newtonian flow model
tion of shear. It is common to subdivide the time-
depended models into “Thixotropic fluid models”
and the“Rheopectic fluid models”.

CHAPTER 4 Page 63


It shall be understood that all the models men-
tioned above are based on different assumptions
that are hardly valid for all drilling operations, thus
they are valid to a certain extend only.
The Bingham and Power-law fluid models are de-
scribed mathematically by:

Bingham plastic fluid model:

−dνr
τ = τ y + µp = τy + µp .γ
˙ (4.15)
dr
Figure 4.3: Sketch of Bingham fluid model
Power-law fluid model:

n
−dνr
τ = K. = K.γ n
˙ (4.16)
dr

where:

τy [lbf/100 ft2 ] ... yield point
µp [cp] ... plastic viscosity
n [1] ... flow behavior index
K [1] ... consistency index.

A plot of shear stress vs. shear rate for the Bingham
model will result in a straight line, see sketch 4.3.
In contrary to Newtonian fluids, Bingham fluids do
have a yield point τy and it takes a defined shear
stress (τt ) to initiate flow. Above τy , τ and γ are
proportional defined by the viscosity, re-named to
plastic viscosity µp
The characteristics of the Power-law fluid model is
sketched in 4.4. This plot is done on a log-log scale
and results in a straight line. Here the slope deter-
mines the flow behavior index n and the intercept
with the vertical, the value of the consistency index
(logK). Figure 4.4: Sketch of Power-law fluid model
The flow behavior index, that ranges from 0 to
1.0 declares the degree of Non-Newtonian behav-

CHAPTER 4 Page 64


ior, where n = 1.0 indicates a Newtonian fluid. The consistency index K on the other hand gives
the thickness (viscosity) of the fluid where, the larger K, the thicker (more viscous) the fluid is.
To determine the rheological properties of a par-
ticular fluid, a rotational viscometer with six stan-
dard speeds and variable speed settings is used com-
monly. In field applications, out of these speeds just
two are normally used (300 and 600 [rpm]) since
they are sufficient to determine the required prop-
erties.
Following equations are applied to define the pa-
rameters of the individual fluid:

Newtonian fluid model:

300
µa = .θN (4.17)
N

5.066
γ=
˙ .N (4.18)
r2

Bingham plastic fluid model:

300
µp = θ600 − θ300 = . (θN2 − θN1 ) (4.19)
N 2 − N1 Figure 4.5: Viscometer

5.066 479.τy 3.174
γ=
˙ .N + . −1 (4.20)
r2 µp r2

N1
τy = θ300 − µp = θN1 − µp . (4.21)
300

τgel = θmax at N = 3 rpm (4.22)

Power-law fluid model:

θN2
θ600 log θN1
n = 3.322. log = (4.23)
θ300 log N2
N1

CHAPTER 4 Page 65


510.θ300 510.θN
K= n
= (4.24)
511 (1.703.N )n

1
2
rn
γ = 0.2094.N.
˙ (4.25)
n. 1
2 − 1
2
n
r1 n
r2

where:

r2 [in] ... rotor radius
r1 [in] ... bob radius
r [in] ... any radius between r1 and r2
θN [1] ... dial reading of the viscometer at speed N
N [rpm] ... speed of rotation of the outer cylinder

4.4 Laminar Flow in Pipes and Annuli
For drilling operations the fluid flow of mud and cement slurries are most important.
When laminar flowing pattern occurs, the following set of equations can be applied to calculate
the friction pressure drop [psi], the shear rate at the pipe wall and the circulation bottom hole
pressure for the different flow models:

Newtonian Fluid model:
Flow through pipe:

D.µ.ν
∆pf = (4.26)
1, 500.d2
i

96.ν
γw =
˙ (4.27)
di

Flow through annulus:

D.µ.ν
∆pf = (4.28)
1, 000. (d2 − d1 )2

144.ν
γw =
˙ (4.29)
d2 − d1

CHAPTER 4 Page 66


Bingham Plastic Fluid Model:
Flow through pipe:

D.µ.ν D.τy
∆pf = 2
+ (4.30)
1, 500.di 225.di

96.ν τy
γw =
˙ + 159.7. (4.31)
di µp


D.µ.ν D.τy
∆pf = 2 + (4.32)
1, 000. (d2 − d1 ) 200. (d2 − d1 )

144.ν τy
γw =
˙ + 239.5. (4.33)
d2 − d1 µp

Power-law Fluid Model:
Flow through pipe:

1 n
D.K.ν n 3+ n
∆pf = . (4.34)
144, 000.d1+n
i 0.0416

24.ν 1
γw =
˙ . 3+ (4.35)
di n


1 n
D.K.ν n 2+ n
∆pf = . (4.36)
144, 000.(d2 − d1 )1+n 0.0208

48.ν 1
γw =
˙ . 2+ (4.37)
d2 − d1 n

When comparing the mean velocity ν with the so called “critical velocity”, denoted by νc (νcan ,
νcp ), the fluid flow pattern can also be determined. This classification is given by:

ν < νc ... laminar flow
ν > νc ... turbulent flow

CHAPTER 4 Page 67


The critical velocities are calculated for the different models as:

Flow through pipe, νcp in [ft/sec]:

1.078.µp + 1.078. µ2 + 12.34.ρm .d2 .τy
p i
νcp = (4.38)
ρm .di

Flow through annulus, νcan in [ft/sec]:

1.078.µp + 1.078. µ2 + 9.256.ρm . (d2 − d1 )2 .τy
p
νcan = (4.39)
ρm . (d2 − d1 )

Flow through pipe, νcp in [ft/min]:

1 n
5.82.104 .K 2−n
1.6 3.n + 1 2−n
νcp = . .( ) (4.40)
ρm di 4.n

Flow through annulus, νcan in [ft/min]:

1 n
3.878.104 .K 2−n
2.4 2.n + 1 2−n
νcan = . .( ) (4.41)
ρm d2 − d1 3.n

4.5 Turbulent Flow in Pipes and Annuli

To describe the flow behaviour, friction pressure loss and shear rate at the pipe wall for laminar
flow, analytic equations are applied. For turbulent fluid flow behavior, analytic models to calculate
these parameters are extremely difficult to derive. Therefore, various concepts that describe their
behavior are used in the industry.
The concept based on the dimensionless quantity called “Friction factor” is the most widely applied
correlation technique. Following equation can be used to determine the friction factor for fully
developed turbulent flow pattern:

1 1.255
√ = −4. log 0.269. + √ (4.42)
f d NRe . f

where:

CHAPTER 4 Page 68


[in] ... absolute roughness of pipe, see table 4.6
d
[1] ... relative roughness of pipe

Figure 4.6: Absolute pipe roughness for several types of circular pipes

To solve this equation for f , iteration techniques have to be applied . The friction factor can also
be obtained from ﬁgure 4.7.

Figure 4.7: Friction factor for turbulent ﬂow

CHAPTER 4 Page 69


In drilling operations, the relative roughness is oft assumed to be insignificant (usually less than
0.0004) which reduces equation 4.42 to equation 4.43 (smooth pipes):

1
√ = 4. log NRe . f − 0.395 (4.43)
f

For smooth pipes and turbulent flow ( d = 0 and 2, 100 ≤ NRe ≤ 100, 000), the friction factor can
be estimated by:

0.0791
f= 0.25
(4.44)
NRe

The pressure drop at turbulent flow pattern is then computed for the different flow models when
replacing di with the equivalent diameter de = 0.816 (d2 − d1 ).
When the friction factor is computed, the pressure drops for the individual flow models can be
calculated.

Newtonian Fluid Model:

f.ρm .ν 2 ρm .ν 1.75 .µ0.25
0.75
ρ0.75 .q 1.75 .µ0.25
∆pf = D. ≈ D. 1.25
≈ D. m
(4.45)
25, 8.di 1, 800.di 8, 624.d4.75i

For fluids that are described by the Bingham fluid model it is more difficult to predict the flow
pattern (laminar-turbulent). Therefore the so called “Hedstron number” NHe was introduced. In
general, the Hedstron number can be correlated with the critical Reynolds number by:

NHe = (NRe )25
c (4.46)

Applying this theory, a turbulent flow pattern exist when NRe > (NRe )c when the Newtonian
viscosity µ is replaced by the plastic viscosity µp .
The correlation between the Hedstron number and the critical Reynolds number, shown in figure
4.8, is based on solving simultaneously equation 4.47 and 4.48:

τy
NHe τw
= 3 (4.47)
16, 800 τy
1− τw

CHAPTER 4 Page 70


4
τy τy
1 − 4.
3 τw
+ 1.
3 τw
(NRe )c = (4.48)
τy
8. τw

where:

37, 100.ρm .τy .d2
i
NHe = (4.49)
µ2
p

Figure 4.8: Correlation of Reynolds number and Hedstron number

When it is identified that the flow is turbulent and the Reynolds number is computed, figure 4.7
can be used to determine the friction factor f and equation 4.45 to calculate the pressure drop.

For fluids that behave according to the power-law fluid model, an empirical friction factor corre-
lation based on the flow behaviour index n is used. This correlation gives for:

CHAPTER 4 Page 71


Flow through pipe:

1 n
K.d1−n
i 3+ n
µa = . (4.50)
96.ν 1−n 0.0416

n
89, 100.ρm .ν 2−n 0.0416.di
NRe = . 1 (4.51)
K 3+ n


n
K. (d2 − d1 )1−n 2+ n 1
µa = . (4.52)
144.ν 1−n 0.0208

n
109, 000.ρm .ν 2−n 0.0208. (d2 − d1 )
NRe = . 1 (4.53)
K 2+ n

where:

µa [cp] ... apparent Newtonian viscosity

NRe > (NRe )c ... turbulent flow

This Reynolds number is then compared with the critical Reynolds number, which is depended
on the flow behaviour index n and should be obtained from figure 4.9 as a starting point of the
turbulent flow line for the given n, resulting in:
Instead of using figure 4.9, equation 4.54 can be applied to determine the friction factor iteratively:

1 4.0 n 0.395
= 0.75 . log NRe .f 1− 2 − 1.2 (4.54)
f n n

When the friction factor f is calculated, the corresponding pressure drop can be calculated with
equation 4.45.

CHAPTER 4 Page 72


Figure 4.9: Friction factor for Power-Law fluid model

4.6 Pressure Drop Across Surface Connections
The pressure drop in surface connections comprise the pressure drops along the standpipe, the
rotary hose, swivel and kelly. Since different rigs do use different equipment, the total pressure
loss at the surface equipment can only be estimated. This is performed with equation 4.55:

(∆pf )se = E.ρ0.8 .q 1.8 .µ0.2
m p (4.55)

where:

(∆pf )se [psi] ... pressure loss through total surface equipment
q [gpm] ... flow rate
E [1] ... constant depending on the type of surface equipment
used, see figure 4.10

CHAPTER 4 Page 73


Another approach is to determine the equivalent length of drillpipe for each surface equipment
and then use the equations presented in the last section to determine the surface pressure loss.
Figure 4.11 gives the equivalent lengths of the different equipment parts.

Figure 4.10: Groups of surface equipment

Figure 4.11: Equivalent drillpipe lengths for surface equipment

4.7 Pressure Drop Across Bit

The pressure drop across the bit is mainly due to the change of fluid velocities in the nozzles.
To increase the penetration rate, when the mud flows through the nozzles its speed is increased
drastically which causes a high impact force when the mud hits the bottom of the hole. This
high fluid speed on the other hand causes a relative high pressure loss. This pressure loss is very
sensitive to the nozzle seize. The bit pressure drop itself can be calculated with:

q 2 .ρm
(∆pf )B = (4.56)
12, 032.Cd .A2
2
T

where:

q 3.π
AT = 0.32. = . (dn )2 (4.57)
νn 4

CHAPTER 4 Page 74


1, 238. (∆pf )B
ν n = Cd (4.58)
ρm

4.AT
dn = 32. (4.59)
3.π

AT [in2 ] ... total nozzle area
dn [1/32] ... jet nozzle seize
νn [ft/sec] ... mean nozzle velocity
q [gpm] ... flow rate
ρm [ppg] ... mud density
Cd [1] ... discharge coefficient, depending on the nozzle type and
size (commonly Cd = 0.95)

4.8 Initiating Circulation

All the equations to calculate the individual pressure drops presented above assume a non-
thixotropic behavior of the mud. In reality, an additional pressure drop is observed when cir-
culation is started due to the thixotropic structures which have to be broken down. This initial
phase of addition pressure drop may last for one full circulation cycle. The additional pressure
drop can be estimated applying the gel strength τg of the drilling mud as:
For flow through pipes:

τg
(∆pf )p = D. (4.60)
300.di

For flow through annuli:

τg
(∆pf )an = D (4.61)
300. (d2 − d1 )

where:

τg [lbf/100 ft2 ] ... gel strength of the drilling mud

CHAPTER 4 Page 75


4.9 Optimization of Bit Hydraulics

The penetration rate in many formations is roughly proportional to the hydraulic horsepower
expended at the bit. To drill most efficiently hydraulic programs are designed for maximum
bottom hole cleaning (how much bottom hole cleaning is necessary to reach maximum penetration
rate) combined with maximum bottom hole cleaning based on the surface hydraulic horsepower
availability. For this reason, mud rheology, hydraulics (individual pressure drops) and bit nozzle
selection are the parameters to consider for drilling optimization. To optimize drilling hydraulics,
different approaches can be made. The hydraulics can be designed to either optimize the nozzle
velocity, the bit hydraulic horsepower or to optimize the jet impact force.
The total pressure drop at the circulation system is the summation of the pressure drop at the bit
and the pressure drop through the rest of the circulation system.

pmax = (∆pf )B + (∆pf )d (4.62)

where:

(∆pf )d = (∆pf )se + (∆pf )dp + (∆pf )dc + (∆pf )dca + (∆pf )dpa (4.63)

This relation can be seen in figure 4.12 (to be drawn) for changing flow rates.

Figure 4.12: Hydraulics Optimization

CHAPTER 4 Page 76


The pressure drop across the bit can be written as:

Hydraulic horsepower:

1
(∆pf )B−opt = pmax − (∆pf )d−opt = pmax − .pmax (4.64)
1+m
Jet impact force:

2
(∆pf )B−opt = pmax − (∆pf )d−opt = pmax − .pmax (4.65)
2+m
where:

m [1] ... slope of the parasitic pressure loss (∆pf )d vs. flow rate

Theoretically m = 1.75 but in general it is better to determine m from field data than assuming
this value.
When plotting flow rate vs. pressure on a log-log plot, the optimum design is found at the
intersection between the path of optimum hydraulics and the (∆pf )d line for either of the criteria
mentioned above.
Having determined the optimum design, the optimum pump flow rate, optimum nozzle area and
corresponding pressure losses can be calculated:

(qopt )2 .ρm
(AT )opt = 2
(4.66)
12, 032.Cd . (∆pf )B−opt

4. (AT )opt
(dn )opt = 32. (4.67)
3.π

Optimum hydraulic horsepower and jet impact force are given with:

(∆pf )B−opt .qopt
(hp)opt = (4.68)
1, 714

(Fj )opt = 0.01823.Cd .qopt . ρm . (∆pf )B−opt (4.69)

The optimum nozzle area leads to the respective nozzle selection. Nozzles for drilling bits are given
1 n
32
[in] seizes thus the calculated nozzle area has to be converted into 32 [in]. Knowing n (has to

CHAPTER 4 Page 77


be an integer and is commonly rounded down to ensure the nozzle velocity) and the amount of
nozzles to use, the individual seizes are found.
The so called “specific hydraulic horsepower” is defined as hydraulic horsepower per unit borehole
cross-section.

4.hp
(hp)spec = (4.70)
π.d2
BH

The optimization as discussed above is performed for regular intervals (e.g. 1,000 [ft]) and is
included in the drilling program. In practice, computer programs are available in the industry
that perform these hydraulic optimization calculations.

4.10 Particle Slip Velocity
The annular flow of the drilling fluid carrying drilling cuttings and a certain amount of gas to the
surface, is disturbed by frictional and centrifugal forces caused by the rotation of the drillstring.
In practice, when it is noticed that inefficient hole cleaning is present, either the mud flow rate is
increased or the effective viscosity of the mud is increased or both adjustments are performed.
To estimate the slip velocity of the cuttings, following correlation methods were developed empir-
ically and are widely accepted and used in the industry:

Moore’s Correlation:

1−n n
K d2 − d1 2+ n 1
µa = . . (4.71)
144 ν an 0.0208

for NRp > 300:

ρs − ρm
ν sl = 1.54. ds . (4.72)
ρm

for NRp < 3:

d2
ν sl = 82.87. s
. (ρs − ρm ) (4.73)
µa

for 3 ≤ NRp < 300:

2.90.ds . (ρs − ρm )0.667
ν sl = (4.74)
ρm .µ0.333
0.333
a

CHAPTER 4 Page 78


where:

928.ρm .ν sl .ds
NR p = (4.75)
µa

τg
ds = (4.76)
10.4. (ρs − ρm )

µa [cp] ... apparent Newtonian viscosity
ds [in] ... drilling cuttings diameter
NR p [1] ... particle Reynolds number
ν sl [ft/sec] ... particle slip velocity
ρs [ppg] ... cuttings density
τg [lbf/100 ft2 ] ... gel strength required to suspend a particle of diameter ds

Chien’s Correlation:
The correlation equations determined by Chien are similar to the ones defined by Moore. For
clay-water muds, he recommends the usage of the apparent viscosity.

τy .ds
µa = µp + 5. (4.77)
νa

The correlation is performed as:
for NRp < 100:
 
µa  36, 800.ds ρ s − ρm 
ν sl = 0.0075. . 2 . + 1 − 1 (4.78)
ρm .ds µa ρm
ρm .ds

for NRp > 100:

d2
ν sl = 1.44. s
(ρs − ρm ) (4.79)
µa

The so called “transportation velocity” ν T is defined as the difference between the mean annular
velocity ν an and the slip velocity ν sl . The “transportation ratio” FT given by:

νT
FT = (4.80)
ν an

CHAPTER 4 Page 79


determines whether the cuttings are transported to the surface (FT is positive) or not and provides
a relative measure of the carrying capability of the drilling mud.
To have proper hole cleaning and with the knowledge of the transport velocity, a minimum mean
annular velocity can be determined. This minimum mean annular velocity has to be calculated at
the annulus with the maximum cross-section area and in this way determines the minimum pump
rate. As a rule of thumb, a minimum mean annular velocity of 3 [ft/sec] is often applied.

4.11 Surge and Swab Pressure
When running tubulars in a hole filled with drilling mud so called “surge pressures” and “swab
pressures” are created. The surge pressure is an increase of the pressure in front of the tubulars
when run into the well, the swab pressure is a pressure reduction behind the tubular when pulled
out of the well. Excessive surge or swab pressures have to be avoided since they can lead to
problems like:

1. Pressure reduction due to swab can cause a kick,

2. Pressure increase due to surge pressure can fracture weaker formation and cause lost circu-
lation which in turn can cause a kick,

3. Swab pressure increases the intake of formation gas (trip gas) which in turn can decrease
the hydrostatic pressure.

The parameters that determine surge and swab pressures are: mud rheological properties, tubular
velocity, tubular and hole geometry. The mean annular fluid velocity caused by tubular movement
is by definition positive when moved upward and negative when moved downward. It is calculated
for:
closed tubulars:

d2
p
ν an−closed = νp . 0.45 + 2 (4.81)
dh − d2
p

open tubulars:

d2 − d2
p i
ν an−open = νp . 0.45 + (4.82)
d2 − d2 + d2
h p i

νmax = 1.5.ν an (4.83)

The corresponding pressure drop is calculated assuming the power-law model and the correspond-
ing factors n and K:

CHAPTER 4 Page 80


n
2.4.νmax 2.n + 1 K.D
(∆pf ) = . . (4.84)
dh − dp 3.n 300. (dh − dp )

where:

νp [ft/min] ... tubular velocities
dh [in] ... diameter of the borehole
dp [in] ... outer diameter of the drillpipe or drill collar
di [in] ... inner diameter of the drillpipe or drill collar
D [ft] ... total pipe length

CHAPTER 4 Page 81


4.12 Examples
1. To cement a casing string at a depth of 8,500 [ft] the used 10 [ppg] drilling mud is to be
displaced from the annulus by a 600 [ft] preflush of 9 [ppg] mud, 1,800 [ft] of 12.5 [ppg] filler
cement and 1,600 [ft] of 16.0 [ppg] high-strength cement. After the high-strength cement, brine
with 8.5 [ppg] is pumped as spacer. Compute the:

(a) Minimum pump pressure required to completely
displace the casing,
(b) Equivalent mud weight at 8,500 [ft] after the cement
has been displaced completely from the casing.

2. A non-Newtonian fluid is measured by a rotation viscosimeter giving readings of 22 at 300
[rpm] and 39 at 600 [rpm] respectively. When the fluid is characterised by the Bingham plastic
fluid model, µp and τy is to be determined, when the power-law model is applied, the consistency
and flow behavior index have to be computed.

3. A fluid characterized by the Bingham plastic fluid model has a yield point of 12 [lbf/ 100 ft]
and a plastic viscosity of 50 [cp]. When the flow pattern is laminar, the pressure drop due to
friction at 8,000 [ft] is to be computed for a:

(a) flow rate of 50 [gpm] through a drillstring
with 3.826 [in] ID,
(b) flow rate of 90 [gpm] through a 10 X 7 [in]
annulus.

4. When drilling a well to 1,000 [ft], a Bingham plastic fluid with a yield point of 5 [lbf/ 100 ft]
and plastic viscosity of 25 [cp] is applied. Using following additional information (Ldp = 1, 000
[ft], di = 3.826 [in], d1 = 4.5 [in], d2 = 6.5 [in], q = 500 [gpm], d = 0) calculate the:

(a) Flow pattern in the drillpipe,
(b) Flow pattern in the annulus opposite the drillpipe,
(c) Frictional pressure loss in the drillpipe,
(d) Frictional pressure loss in the annulus.

5. Assuming the same mean flow velocities and a power-law fluid model with a consistency index
of 200 [eq cp] and flow behavior index of 0.75, calculate the same values at in example 4.

CHAPTER 4 Page 82


6. A jet bit shall produce a 800 [psi] pressure drop through the nozzles when circulating 900 [gpm]
of 10 [ppg] drilling mud. Select 3 nozzles that produce this pressure drop and calculate the jet
velocity of the mud.

7. A 11.75 [in] casing with a closed end is lowered into a 12.25 [in] hole at a rate of 1.5 [ft/sec].
What is the equivalent density below the bottom joint at 7,000 [ft] when the hole is filled with a
10.5 [ppg] mud having a viscosity of 2.5 [cp]?

8. When drilling with a 10 [ppg] mud and a bit, using three 12 [in] nozzles, the pump pressure
32
at a flow rate of 500 [gpm] is 3,000 [psi]. When the frow rate is dropped to 250 [gpm], a pump
pressure of 800 [psi] is recorded. The minimum flow rate to lift the cuttings is determined as 240
[gpm], the maximum allowable surface pressure is 3,000 [psi]. The pump itself is rated at 1,000
[hp] and exhibits an overall efficiency of 90 %. Compute the:

(a) Proper operating conditions and bit nozzle sizes for
maximum bit horsepower for the next bit run¿,
(b) Bit horsepower required to obtain the conditions selected,
(c) Jet impact force obtained at the conditions selected,
(d) Jet nozzle velocity obtained at the conditions selected.

CHAPTER 4 Page 83


CHAPTER 4 Page 84


Chapter 5

Drilling Bits

Drill bit selection is in general a complicated process but, when performed properly, has a major
impact on the total well cost. First in this chapter, the different types of drill bits are discussed.
Then, applying their classification and wear considerations, a drill bit selection is presented.
Finally, various parameters that influence the rate of penetration are discussed.

5.1 Drill Bit Types

5.1.1 Roller Cone Bit

Roller cone bits comprise one, two or three cones having teeth sticking out of them. A roller cone
bit with three cones is the most often applied type of drilling bit. Typical roller cone bits are
shown in figure 5.1.
The cutting action of this bit can be described as follows: when the bit is rotated at the bottom
of the hole, the teeth are pressed onto the formation below the bit and applies a force exceeding
the compressive strength of the rock. This is sketched in figure 5.2.
Some of the advantages of roller cone bits over fixed cutter bits are:

(a) Can handle rough drilling conditions,
(b) Less expensive than fixed cutter bits,
(c) Are more sensitive to the amount of pressure overbalance and thus
better indicator of overpressure formations,

The gauge of the hole drilled by roller cone bits is maintained by the outside cutters which
are also known as “gauge cutters”. These teeth are very vulnerable to wear that increases in
abrasive sandstone formations. When the gauge cutters are worn out, the consequent hole drilled

CHAPTER 5 Page 85


is undergauge. Cones are commonly heat treaded and made of NiMo-steel, teeth are sometimes
made of NiCrMo-steel.

Figure 5.1: Typical roller cone bits

Offset
The “offset” of the cones of rolling cutter bits determine to some extend the drilling action. As
it can be seen in the figure 5.3, the offset of the bit declare how much the axis of the cones are
out of being centered. This offset causes the cones to stop periodically rotating and scrap the
hole similar to the cutting action of a drag bit. The the an increased offset increases the wear
of the drill bit, common values for offsets are 4◦ , for use in soft formations to zero degrees for
applications in extremely hard formations.

The shape of the cones are determined by the offset and the journal-angle. The journal-angle
itself influences:

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Figure 5.2: Cutting action of roller cone drill bits

CHAPTER 5 Page 87


1. Cutting depth of the teeth, small journal-angle causes to high cutting depth that might lead
to teeth cleaning problems.

2. Teeth high and distance of the teeth-rows, small journal-angle leads to larger teeth, common:
39 - 42◦ : soft formations, 43 - 45◦ : medium formations, 45 - 50◦ : hard formations.

3. Inner cone-angle, larger journal-angle means a smaller inner cone-angle, thus the cones can
reach closer to the center of the bit which prevents the creation of a “center core”.

4. Outer cone-angle and outer cutting length.

5. Hight of the gauge cutters, larger journal-angle leads to higher gauge cutters.

6. Available space for bearings, small journal-angle allows stronger bearings construction.

7. Dimension of the bit-feet, larger journal-angle leads to larger bit-feet but smaller cones. The
bit-feet are welded together and construct the cylindrical bit-body.

8. Cone-shape and cone-seize.

The bearings used within a bit can be: (1) roller-
bearings, (2) ball-bearings and (3) sliding-bearings.
Here ball-bearings carry the axial loads along the
journal, roller-bearings support the radial loads, are
charged mostly and wear first. Sliding-bearings sup-
port the axial loads when the ball-bearings are worn
out. At larger bit diameters, ball-bearings are com-
monly replaced by sliding-bearings.

Mill Tooth Bit

At mill tooth bits, which are also known as steel tooth
bits, the teeth are milled out of the same body the
cones consist of. These bits are very robust and tol-
erate severe drilling conditions but wear out relatively
quickly. From this reason they are not well suited for
deeper wells where tripping constitutes a large time
factor. Typical mill tooth bits are shown in figure 5.4.
Figure 5.3: Roller cone bit offset

Insert Bit

Insert bits, also called tungsten carbide bits, have teeth made of tungsten carbide which are fitted
on the cone bodies. Typical insert bits are shown in figure 5.5. These bits do not tolerate shock
loadings but they can drill long sections before being worn out. In general, insert bits of the same
bit seize are more expensive than mill tooth bits.

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Figure 5.4: Typical mill tooth bits

Figure 5.5: Typical insert bits

CHAPTER 5 Page 89


A new technology of insert bits coats the teeth with a layer of diamond. These bits, also known as
tungsten carbide insert bits (TCI), exhibit a signiﬁcantly improved bit life in abrasive formations.

5.1.2 Fixed Cutter Bit

Fixed cutter or drag bits have no moving parts (e.g. bearings) and can drill very long hole sections
when the proper drilling conditions are given. They exhibit higher bit rotation times (time the
bit is cutting rock) at hard, abrasive formations. Diamond bits allow higher bit rotations which
are given when downhole motors are applied. As a rule of thumb, the advantages of diamond bits
over roller bits increase as the depth increases and the borehole diameter decreases.
Some of the disadvantages of the diamond bits compared to roller bits are:

(a) Sensitive to steel at bottom of borehole (lost junk),
(b) Have to be run in carefully, borehole has to be washed clean
(c) Normally high torques are introduced,
(d) Sensitive to fragile and fractured formations,
(e) Get easier stuck at selling formations,
(f) Higher price.

Figure 5.6: Cutting action of a drag bit

Polycrystalline Diamond Compact Bit

Polycrystalline diamond compact (PDC) bits have an industrially manufactured diamond disk
mounted on a tungsten carbide stud. Typical PDC bits are shown in ﬁgure 5.7. Although these

CHAPTER 5 Page 90


bits are very expensive, under the propper drilling conditions, they can drill very fast for long
distances. Thus they are most often applied for offshore drilling (high rig rates) and deep wells
(tripping time).
The PDC bit itself consists of a steel
body where the tungsten carbide studs
are mounted on steel pegs which are fit
into holes of the body. Bits that are con-
structed from molded tungsten carbide
are also called “matrix body bits”. Ma-
trix body bits are more expensive than
PDC bits but they exhibit less wear (e.g
loss of teeth in hole).
PDC bits are manufactured in many
different shapes that determine their
behavior to rather drill directional or
straight trajectories. The different
shapes of the PDC bits also govern
the amount, profile and seize of cutters
mounted on the surface.

Polycrystalline Diamond Bit
Figure 5.7: Typical PDC bits
Polycrystalline diamond (PCD) bits consist of industrially manufactured, temperature stable di-
amonds that are mounted directly into the bit matrix.

Natural Diamond Bit

Natural diamond bits wear out the rock at the bottom of the hole by producing very small cuttings
known as “rock flour”. Typical natural diamond bits are shown in figure 5.8. These bits can drill
the hardest rocks (highest compressive strength) but they drill relatively slowly and are very
expensive. For this reason they are used at very hard and very abrasive formations which would
destroy other types of bits before making reasonable drilling progress. Diamonds used for these
bits are naturally occurring industrial-grade ones. The diamonds are mounted with an exposure
of 1/100 to 1/1000 [mm], having diamond seizes of 1 to 100 [St/ct]. Impregnated diamond bits
have diamond-splints (seize > 100 [St/ct]) mixed into their matrix-body. Thus when the bit wears
out (body wears), new diamonds-splints out of the body become exposed and the bit stays sharp.

Fishtail Bit

This type of bit was developed at the early days of oil well drilling and look, when viewed from
the side, somewhat like a fishtail. They are only applicable at soft formations where they establish

CHAPTER 5 Page 91


drilling progress by scraping the rock. They have a tendency to walk, exhibit a low performance
and often drill not in-gauge. Their advantages are that they can be re-shaped, they demand low
pump rates and are cheap.

Figure 5.8: Typical natural diamond bits

Following rules of thumb are to be considered to drill different formations:

Very Soft Formation: Very Hard Formation:

Offset: big, high influence no, low influence

Tooth hight: high, high influence low

Hydraulics: low diameter nozzles, low influence
high impact force,
high influence

Bearings: function of applied WOB, high grades/qualities
low influence high influence

Lubrication: low influence high influence,
own lubricant reservoir

Bit shape: Mill tooth bit -> Insert bit -> Diamond bit

CHAPTER 5 Page 92


5.1.3 Coring

Core Drilling

For core drilling so called core bits, which have a ring shaped structure with natural or industrial
diamond cutters mounted on it, are applied. The coring cutting process us sketched in ﬁgure 5.9.

Figure 5.9: Coring with coring bit

Drilling with core bits leave a column of rock sticking up in the middle of the bit which is picked
up by a device called “core barrel”. This core barrel holds the core and recovers it to the surface.

CHAPTER 5 Page 93


Although core bits sometimes drill faster than normal bits in the same formation since less rock
is to be destroy, the additional tripping time to retrieve the cores makes core drilling a costly
operation.

Side Wall Coring

As alternative to drilling for a core, side wall coring provides rock samples that are smaller than
common cores but in general large enough to allow geologists or reservoir engineers to evaluate
the particular formation parameters.

5.2 Drill Bit Classification
Drill bits are classified by IADC (International Association of Drilling Contractor) to identify
similar bit types made from different manufacturers.

5.2.1 Roller Bit Classification

The bit classification in use up to 1972 applied three digits, the new one applies four. The first
three digits of the old classification remained basically unchanged (although come modifications
and extensions were proposed in the mean time), the additional fourth letter provides in general
information about the bit characteristics.

First digit
The numbers 1, 2 and 3 designate steel tooth bits and correspond to increasing formation hardness.

1: soft formations with low compressive strength and high drillability
2: medium to medium hard formations with high compressive strength
3: Hard semi-abrasive and abrasive formations

The numbers 4, 5, 6, 7 and 8 designate bits with tungsten carbide inserts and also correspond to
increasing formation hardness.

4: soft formations with low compressive strength and high drillability
5: soft to medium formations with low compressive strength
6: medium hard formations with high compressive strength
7: hard semi-abrasive and abrasive formations
8: extremely hard and abrasive formations

CHAPTER 5 Page 94


Second digit
The numbers 1, 2, 3 and 4 denote a sub-classification of the formation hardness in each of the
eight classes determined by the first digit.

Third digit
Defines the type of bearing and specifies the presence or absence of gauge protection by tungsten
carbide inserts.

1: standard roller bearing
2: roller bearing, air cooled
3: roller bearing, gage protected
4: sealed roller bearing
5: sealed roller bearing, gage protected
6: sealed friction bearing
7: sealed friction bearing, gage protected

Fourth digit

A: air application, journal bearing bits with air circulation nozzles
B: special bearing seal, application at high RPM
C: center jet
D: deviation control
E: extended jets
G: extra gauge/body protection
H: horizontal/steering application
J: jet deflection
L: lug pads, pads very close to gage diameter
M: motor application, special design for use on downhole motors
S: standard steel tooth model
T: two-cone bits, sometimes used for deviation control and penetration rate
W: enhanced cutting structure
X: chisel tooth insert
Y: conical tooth insert
Z: other insert shape

5.2.2 Drag Bit Classification

The new classification, introduced 1981, also uses four digits.

CHAPTER 5 Page 95


First digit
The letters D, M, S, T and O define the type of cutter (1) and the body material.

D: Natural diamond matrix body
M: Matrix body PDC
S: Steel body PDC
T: TSP matrix body
O: Other

A new classification uses only M for matrix and S for steel body construction.

Second digit
The numbers 1 to 9 define the bit profile, where G denotes gauge hight and C cone hight respec-
tively.

1: G high, C high
2: G high, C medium
3: G high, C low
4: G medium, C high
5: G medium, C medium
6: G medium, C low
7: G low, C high
8: G low, C medium
9: G low, C low

Third digit
The numbers 1 to 9 define the hydraulic design:

(a) Fluid exit (changeable jets, fixed ports, open throat),
(b) Cutter distribution (bladed, ribbed, open-faced),

1: changeable jets, bladed
2: fixed ports, bladed
3: open throat, bladed
4: changeable jets, ribbed
5: fixed ports, ribbed
6: open throat, ribbed

CHAPTER 5 Page 96


7: changeable jets, open faced
8: fixed ports, open face
9: open throat, open face

The letters R, X and O may replace the numbers 6 or 9 (that correspond to most diamond and
TSR bits).

Fourth digit
The numbers 0 to 9 denote the cutter size and density.

0: impregnated
1: density light, size large
2: density medium, size large
3: density heavy, size large
4: density light, size medium
5: density medium, size medium
6: density heavy, size medium
7: density light, size small
8: density medium, size small
9: density heavy, size small

5.3 Drill Bit Selection and Evaluation
Since a well is drilled only once and each well penetrated the formations at different locations with
different drilling parameters, a selection of a “best bit” can not be performed. The next best way
to find an “optimum bit” is to compare bit performances of drilling bits when they were run under
similar conditions. Then a cost-per-foot value of each bit application can be calculated. Along
with this criteria, the individual bit wear are evaluated. This knowledge is applied to the well
that is to be drilled (length, inclination, drillability, abrasiveness, etc. of the different sections).
In practice, when the well is planned, bits that have been used previously in this area (by this
drilling team) are evaluated according to their applicability. Sometimes when a bit manufacturer
has developed a new bit, he introduces it to the industry with an expected minimum performance.
Thus, when such a new bit is applied and the proposed performance is met (usually better than
ones of already applied bits), the operator has increased his pool of possible bits to use for future
wells. In case the performance proposed by the manufacturer is not met, agreements that the bit
is given at reduced cost to the operator are common.
Another way of bit evaluation is the determination of the specific energy using equation 5.1. Here
the cutting-performance of various bits are compared to each other. For this, the mechanical

CHAPTER 5 Page 97


energy of the bit is related to the drilled rock volume. It should be noted that a bit selection
considering the specific energy may not lead to the finding of the most economic bit.

240.Bd .n
Espec = (5.1)
dbit .ROP

In all practical cases, to evaluate previously applied bits, the so called bit records are studied.
These bit records include all available information (bit seize, type, manufactures, nozzles used,
rotation time, applied WOB, applied RPM, etc.) about the bits applied within drilled wells.

5.3.1 Tooth Wear

With tooth wear, the reduction of tooth hight is graded after a bit was run. The grading is
reported in nearest eighth, thus a bit which teeth are worn out to half of its original hight, is worn
4
8
and reported as T-4. Normally the tooth wear of a bit is not even distributed over the bit, some
teeth are worn more than others, some are broken out. Broken teeth are generally remarked as
“BT”. The reported wear is an average one based on the most severely worn teeth. Reporting of
the tooth wear is possible when the teeth are measured before and after the bit was run.
In general, tooth wear has no direct relationship with the drilling rate realizable.
For insert bits, tooth wear occurs, due to the hardness of the teeth, as breaking or losing of them.
Thus a T-4 graded insert bit may have half of its teeth broken or lost.

Figure 5.10: Tooth wear for milled tooth bits

5.3.2 Bearing Wear

Evaluation of bearing wear in the field is difficult since the bit would need to be disassembled for
inspection. Thus it is mainly determined if the bearings are in takt or failed. Failed bearings can
result in that the cones are stuck (no rotation possible) or that they are worn out and the bearings
itself are exposed. The classification is similar to the tooth wear, using a B instead of T. Thus a
bit which bearings are worn to 7 is marked as B-7.
8

Often the bearing wear is reported based on the total bit running hours. Thus, when a bit is
expected to have a rotation time of 40 hours and was rotating on bottom for 10 hours, the bearing
wear is reported as B-2.

CHAPTER 5 Page 98


5.3.3 Gauge Wear

When the gauge teeth of a bit are worn, the drilled hole will be under-gauge with may lead to
damage of the next bit. Measurement of the gauge wear is performed with the help of a ringe
gauge and a ruler. The loss of diameter in [in] is reported as the nearest eighth, denoting with the
letter O for “out of gauge”. In this way, a bit which diameter is reduced by 0.5 [in] is reported as
G-O-4 (4 since 4 [in]). When the bit is in-gauge, it is reported using the letter I.
8

In addition to the wear gradings listed above, the bit record commonly includes a column of
comments. Here the bit conditions are commonly remarked.

5.4 Factors that Affect the Rate Of Penetration

Although through out the text, various aspects that influence the ROP are mentioned when
appropriate, the following considerations are often applied to determine the drilling parameters
recommended.

5.4.1 Bit Type

The type of bit applied to drill a certain formation has a large impact on the achieved penetration
rate. Roller cutting bits with long teeth exhibit commonly the highest penetration rates but they
are only applicable at soft formations. At hard formations where drag bits dominate, the realised
ROP is mainly a function of seize and amount of cutters along with an optimum combination of
drilling parameters.

5.4.2 Formation Characteristics

The most important formation properties that determine the penetration rate are the elastic limit
and the ultimate rock strength. To estimate the strength of a formation, the shear strength by
the Mohr failure criteria is often used.
When drilling is initiated, a threshold force or bit weight W t has to be overcome. This threshold
d
force can be found when plotting drilling rates as a function of bit weight per diameter and then
extrapolated back to zero drilling rate.
Another formation property that has a large influence to the realized ROP is its permeability. At
rocks with high permeability, the drilling mud is forces into the rock ahead of the bottom of the
hole and thus reduces the differential pressure.
Other rock properties like its abrasiveness and gummy clay minerals content contribute indirectly
to the ROP by influencing the drilling bit (wear, dulling, etc.).

CHAPTER 5 Page 99


Figure 5.11: Threshold force to initiate drilling in different formations

5.4.3 Drilling Fluid Properties

From the various drilling fluid properties, following were identified as influencing the penetration
rate:

(a) drilling fluid density,
(b) rheological flow properties,
(c) filtration characteristics,
(d) solids content and distribution,
(e) chemical composition.

It was found that penetration rate decreases with increasing fluid density, viscosity and solids
content and increases with increasing filtration rate. This is mainly caused by influencing the
differential pressure at the bottom of the hole. The drilling fluid viscosity on the other hand
controls the pressure losses along the drillstring and thus the available hydraulic impact force at
the bit. It has also been found that the content of solids particles with a seize less than 1 [µm]
(colloid seize) do influence the ROP dramatically since they are plugging of filtration below the
bit.
As it can be seen in figure 5.13, the penetration rate is largely dependent on the differential
pressure. It should be noted that a change in differential pressure when it is low causes a large

CHAPTER 5 Page 100


Figure 5.12: Variation of penetration rate with different mud properties

change in ROP, when the differential pressure is high, a change of it influences the penetration
rate only slightly.
The effective differential pressure at the bottom of the hole does not only have an influence to
the cutting action, it also influences the chip removal and therefore the cleaning of the bottom
hole. When plotting a ROP relation on a semilog scale, a straight line can be interpolated that
estimates the penetration rate for various overbalances, see figure 5.14.
Figure 5.14 can be described with equation 5.2:

R
log = −m.(pbh − pf ) (5.2)
R0

where:

R [ft/hr] ... penetration rate with particular overbalance
R0 [ft/hr] ... penetration rate with zero overbalance
m [1] ... slope of the correlation line
pbh [psi] ... bottom hole pressure in the borehole
pf [psi] ... formation fluid pressure

CHAPTER 5 Page 101


Figure 5.13: Eﬀect of overbalance on drilling rate in Indiana limestone for clay/water mud and
1.25 [in] roller cutting bit

Figure 5.14: Exponential relationship between penetration rate and overbalance for roller cutting
bits

When the overbalance is expressed with the equivalent circulation mud density ρc and the pore
pressure gradient gp (both [ppg]) using equation 5.3, and the factor 0.052.m as a4 , the change of
penetration rate can be estimated due to the change of mud weight by applying equation 5.4.

CHAPTER 5 Page 102


(pbh − pf ) = 0.052.D.(ρc − gp ) (5.3)

R
log = a4 .D.(gp − ρc ) (5.4)
R0

5.4.4 Operating Conditions

A change of operating conditions, the applied drilling parameters WOB and rotation speed, are
sketched in ﬁgure 5.15 and 5.16.

Figure 5.15: Typical responses of ROP for changing rotation speeds

Figure 5.16: Typical responses of ROP for changing WOBs

CHAPTER 5 Page 103


The decreased ROP, when WOB is increased (section d-e at figure ??) is called “bit floundering”
and is attributed to less efficient bottom hole cleaning.
A so called “Drill-off-test” can be applied to determine the drillability of a homogenous formation
and to optimize the applied drilling parameters. To carry out a drill-off-test, the maximum WOB
is applied along with a constant RPM. Then the time until the bit drills free is counted. When this
procedure is repeated with various speeds, a WOB-time diagram can be developed, repeating the
procedure with various WOBs, the optimum WOB-RPM combinations can be found. It should
be noted that the drill-off-test has to be carried out within a homogenous formation and since it
takes a relatively long time, it is performed very seldom.

5.4.5 Bit Wear

As the bit is worn during drilling, the penetration rate decreases. This reduction of ROP is
generally less severe for insert bits as for milled tooth bits.

5.4.6 Bit Hydraulics

Practice has shown that effective bit hydraulics can improve the penetration rate dramatically.
The enhanced jetting action promotes a better cleaning of the teeth as well as the bottom of the
hole. To improve the cleaning capacity of the bit extended nozzles are often applied where the
discharging nozzle ends are closer to the hole bottom. When extended nozzles are mounted on
the drilling bit, a center jet must also be used to prevent bit balling in soft formations.
As discussed with well hydraulics, hydraulic horsepower, jet impact force and nozzle velocities are
the criteria to optimize hydraulics. When a low WOB is applied and drilling rates are low, the
required hydraulics for efficient hole cleaning is small. When the WOB is increased and the well
is drilled faster, efficient hydraulic programs have to be followed to realize the higher penetration
rates.

CHAPTER 5 Page 104


5.5 Examples

CHAPTER 5 Page 105


CHAPTER 5 Page 106


Chapter 6

Drillstring Design

The drillstring constitutes the connection between the rig and the drill bit. The main compo-
nents of the drill string are: (1) kelly, (2) drillpipe, (3) drill collar and (4) drilling bit.
Along with these main components, heavy-weight drillpipe, jars, stabilizers, reamers and various
subs (kelly sub, bit sub, shock sub, cross-over sub, etc.) are connected to establish a properly
designed drillstring.

Figure 6.1: Drillstring components

CHAPTER 6 Page 107


Some problems that can arise due to improper design of the drillstring are twistoffs, collapse
failures or washouts.
In general, the drillstring provides multiple functions like:

1. Imposes required weight on the bit

2. Transmits rotary motion from the kelly to the drill bit

3. Provides a two way fluid conduit from the rig to the drill bit

4. Medium to lower and raise the drill bit in the hole

5. Stabilizes the bottom hole assembly (BHA) and minimizes vibrations

6. Permits pressure and formation fluid testing through the drillstring

7. Allows through-pipe running of formation evaluation tools when they can not be run in the
open hole

The following sections discusses various design criteria like determination of appropriate length
and grade of drill pipe as well as drill collars, placement of stabilizers and reamers, dogleg severity
analysis and calculation of critical rotary speeds.

6.1 Drill Pipe Classification
Grades of drillpipe
API steel grades for drill pipe:

Steel grade Min.Yield [psi] Max.Yield [psi] Min.Tensil [psi]
E75 75,000 105,000 100,000
X95 95,000 125,000 105,000
G105 105,000 135,000 115,000
S135 135,000 165,000 145,000

Non-API special H2 S Steel for drill pipes:

Steel grade Min.Yield [psi] Max.Yield [psi] Min.Tensil [psi]
DP-80 VH 80,000 95,000 95,000
DP-95 VH 95,000 110,000 105,000
MW-CE-75 75,000 90,000 95,000
MW-CX-95 95,000 110,000 105,000

CHAPTER 6 Page 108


Common diameters of drillpipe are: 2-3/8, 2-7/8, 3-1/2, 4, 4-1/2, 5, 5-1/2, 6-5/8 [in], where the
5 [in] drillpipe is the most often used one.

The length of one drillpipe is according to APT ranges:

Range 1 18 to 22 [ft]

All size, weights and grades are classified according to their use as:

Class I white band new pipe, everything nominal
Premium class two white bands reductions generally up to 80%
Class II yellow band reductions generally up to 70%
Class III orange band any imperfections or damages exceeding class II

The different classes are also used to reduce the nominal yield strength where following wear
assumptions are made:

Premium wear rate: 20%,
Class II wear rate: 20%,
Class III wear rate: 37.5%,

The end of drillpipes can be manufactured geometrically different. The female portion of the tool
joint is called “box”, the male portion “pin”. The portion of the drillpipe to which the tool joint
is attached has a larger wall-thickness than the rest of the drillpipe and is called “upset”. The
upset can be shaped as: internal upset (IU), external upset (EU) and internal and external upset
(IEU), see figure 6.2.

Figure 6.2: Geometric ending of drillpipe

CHAPTER 6 Page 109


Tool joints are manufactures as regular, full hole and internal flush.
So called heavy weight drillpipe or heavy wall drillpipe are often applied in between drillpipe
and drill collars. They are manufactured with outside diameters ranging from 3-1/2 [in] to 5 [in]
and are used to reduce the sharp change of cross-area and stiffness from drillpipe to drill collars
which otherwise leads to fatigue failure.

6.2 Calculation of Neutral Point
When the drillstring is low-
ered into the borehole, the total
length of the drillstring is under
tension due to its own weight
which is partly counterbalanced
by the buoyancy. To drill a well,
the rock beneath the bit has to
be destroyed. Part of this de-
struction force is obtained by
a certain amount of weight on
bit (WOB) which forces the bit
against the rock. Therefore
during drilling, the lower part
of the drill string is set under
compression, leaving the upper
part of it still under tension.
According to Lubinski, the neu-
tral point is defined as point
along the drillstring where it is
divided into two parts, an up-
per part, being suspended from
the elevators and which is un-
der tension as well as a lower
part that generates the appro-
priate WOB and is under com-
pression.
Due to the geometrical shape of
the drillstring (length/diameter
ratio), it has a tendency to
buckle. To reduce this buckling
tendency, it is aimed to design
the drillstring in such a way
that the neutral point is located
inside drilling collars. This de- Figure 6.3: Sketch of buckling tendency of drillstring

CHAPTER 6 Page 110


sign criteria is often used to evaluate the length of required collars. Taking these considerations
into account, the neutral point can be calculated for different scenarios as:
In the absence of mud (drilling with air as drilling fluid):

W OB
ln = (6.1)
12.Ws

In the presence of drilling mud:

W OB
ln = (6.2)
12. (Ws − ρs .As )

When differential pressure is considered as well, the neutral point is found at:

W OB
ln = (6.3)
12. (Ws − ρe .Ae + ρi .Ai )

where:

ln [ft] ... distance of neutral point from the bottom of the hole
W OB [lbm] ... weight on bit applied
Ws [lbm/in] ... average weight in air of the tube per unit length
ρs [lbm/in3 ] ... density of tubing
As [in2 ] ... cross-sectional area of the tubing wall
ρe [lbm/in3 ] ... density of mud in the annulus
Ae [in2 ] ... area corresponding to tubing OD
ρi [lbm/in3 ] ... density of mud in the tubing
Ai [in2 ] ... area corresponding to tubing ID

6.3 Drillstring Design Calculations

As mentioned above, to prevent the drillstring from buckling, the neutral point must be placed
inside the drilling collars.
Other influencing factors for the drillstring design are: depth and seize of the well, applied mud
weights, desired safety factors, minimum margin of overpull, desired drillpipe seize and class as
well as applied WOB. The design itself is based on meeting tension, collapse, shock loading and
torsion requirements.

CHAPTER 6 Page 111


6.3.1 Tension

The total weight when the drillstring is suspended into the borehole is carried by the top joint of
the string. This weight [lb] is given by:

P = (Ldp .Wdp + Lhw .Whw + Ldc .Wdc ) .BF (6.4)

where:

L [ft] ... total length of the individual tubular
W [lb/ft] ... nominal weight of the individual tubular
BF [1] ... buoyancy factor

Figure 6.4: Table of drillpipe properties

CHAPTER 6 Page 112


with the indices dp for drillpipe, hw for heavy-weight drillpipe and dc for drill collar.

The buoyancy factor BF , assuming that the drillstring is not lowered empty (ρsteel = 65.5 [ppg]),
can be computed as:

ρmud
BF = 1− (6.5)
ρsteel

Figure 6.5: Table of drillpipe properties con.

Ordinary, a safety factor of 0.9 is applied to calculate the maximum allowed yield strength Pa
from the drillpipe yield strength Pt , which is taken from tables 6.4 through 6.9:

Pa = 0.9.Pt (6.6)

CHAPTER 6 Page 113


or when the class wear rate is applied:

Pa = Pt .(1 − wear rate) (6.7)


Having the maximum allowed yield strength and the total weight carried, the so called margin of
overpull (MOP) is deﬁned by the diﬀerence of them:

M OP = Pa − P (6.8)

Knowing the MOP is important in case of stuck pipe when an additional pulling force has to
be applied to free the drillstring. In practice, the determined margin of overpull must not be
exceeded since the drillpipe would fail otherwise. Typical values of MOPs requirements for drillpipe
selections are in the range from 50,000 to 100,000 [lbf].

CHAPTER 6 Page 114



Using equations 6.4 and 6.6, the drillstring safety factor can be calculated as:

Pa 0.9.Pt
SF = = (6.9)
P (Ldp .Wdp + Lhw .Whw + Ldc .Wdc ) .BF

In this way, the length of the drillpipe can be expressed as:

0.9.Pt Whw Wcd
Ldp = − .Lhw − .Ldc (6.10)
SF.Wdp .BF Wdp Wdp

or

0.9.Pt − M OP Whw Wcd
Ldp = − .Lhw − .Ldc (6.11)
Wdp .BF Wdp Wdp

CHAPTER 6 Page 115


In practice, the drillstring consists of drillpipes with various grades. This configuration is called
tapered string. The different grades required are determined by first taking the lightest grade
and calculating the maximum useable length as bottom section. Successively, stronger grades are
added to the drillstring as the well is drilled deeper.


6.3.2 Collapse

Collapse (plastic deformation) of a tubular is caused when the differential pressure acting on the
tubular exceeds the so called collapse pressure of the tubular. In case of oil-well drilling the
differential pressure is caused by the different pressures inside and outside of the tubular.
A practical situation when collapse of drillpipe can occur is during a drill stem test (DST). Here,
to lower the pressure that is applied against the formation to be tested, the drillstring is run
partially empty causing a lower hydrostatic pressure.

CHAPTER 6 Page 116



The resulting differential pressure can be calculated prior to opening the DST tool, knowing the
length of the fluid inside the drillstring Y [ft], a total length of the drillstring L [ft] and the
densities ρ1 [ppg] of the fluid outside the drillpipe and ρ2 [ppg] of the fluid inside drillpipe. Note
that both Y and L are in TVD.

L.ρ1 (L − Y ) .ρ2
∆p = − (6.12)
19.251 19.251

When the drillpipe is completely empty (ρ2 ∼ 0) the differential pressure is found to be:
=

L.ρ1
∆p = (6.13)
19.251

When the fluids inside and outside the drillpipe are the same(ρ1 = ρ2 = ρ), the differential pressure
is:

CHAPTER 6 Page 117


Y.ρ
∆p = (6.14)
19.251
Having calculated the differential pressure, a safety factor for collapse can be computed. Therefore
the collapse resistance pcol is divided by the collapse pressure ∆p.

pcol
SF = (6.15)
∆p

6.3.3 Biaxial Loading

Under normal drilling conditions, the drillstring is subjected to both tension and collapse loading
at the same time. This is expressed as biaxial loading. It is recognized that the tension loading of
the drillpipe causes a reduction of the collapse resistance. This can be evaluated using fig. 6.10.
Since figure 6.10 shows the general description of a biaxial loading behavior, it can be applied
when collapse or burst pressure is combined with either tension or compression of the drillpipe.

Figure 6.10: Biaxial stress diagram

The correction procedure consists of the following steps:

1. At the depth where the collapse or burst pressure is acting calculate the tension or compres-
sion of the drillpipe.
T
2. Then the value ( Ap ).Ym .100 can be computed.

CHAPTER 6 Page 118


3. The ﬁg. 6.10 is entered at the horizontal axis using above value.

4. Going vertically from this value, the ellipse curve is to be intersected
Pca
5. From this intersection, going horizontally to the vertical axis gives the value for Pco
.100.

6. The adjusted pressure strength of the pipe is found with equation 6.16:.

Pca
Pca = Pco . (6.16)
Pco

where:

Pca [psi] ... adjusted collapse pressure
Pco [psi] ... simple collapse pressure

Instead of using ﬁg. 6.10, the corrected collapse or burst resistance can be computed with:
 
T 2 T
 Ap Ap 
Pca = Pco  1 − 0.75. − 0.5.  (6.17)
Ym Ym

6.3.4 Shock Loading

When the movement of the drillpipe is suddenly stopped (e.g. by setting slips), shock loads
develop that compromise an additional tensile force. This force is expressed as:

Fs = 3, 200.Wdp (6.18)

where:

Wdp [lbf/ft] ... weight of the drillpipe per unit length
Fs [lbf] ... shock loading force

6.3.5 Torsion

When making or breaking connections as well as when torques are applied during drilling opera-
tions, the minimum torsional yield strength of the drillpipe must not be exceeded. The minimum
torsional yield strength of a tubular is calculated as:

CHAPTER 6 Page 119


0.096167.J.Ym
Q= (6.19)
do

During drilling operations the drillstring is subjected to torsion and tension at the same time.
Therefore the minimum torsional yield strength, as calculated above, has to be reduced to:

0.096167.J P2
Qr = . Ym −
2 (6.20)
do A2

where:

Q [lb-ft] ... minimum torsional yield strength
Qr [lb-ft] ... minimum torsional yield strength under tension
J [in4 ] ... polar moment of inertia, J = 32 . (d4 − d4 )
π
o i
Ym [psi] ... minimum unit yield strength
do [in] ... outside diameter of drillpipe
di [in] ... inside diameter of drillpipe
P [lb] ... total load in tension
A [in2 ] ... cross-section area

Note that the nominal drillpipe weights, given in tables 6.4 through 6.9, are meant to be used
for classiﬁcation. To estimate the total weight of the drillpipe section of the drillstring, tool joint
weights have to be included as well.

6.4 Drillpipe Bending resulting from Tonging Operations

During making and breaking of a connection, the tool joint should be kept as close as possible
to the rotary slips to minimize bending of the pipe. The maximum recommended makeup or
breakout torque depends on the drillpipe or drill collar as well as the joint type. Knowing them,
the maximum hight that the tool joint can be placed above the rotary slips is deﬁned. The
maximum height itself is therefore governed by:

1. Minimum yield strength of the pipe,

2. Maximum recommended makeup torque of the connection,

3. Tong handle length,

4. Angle of separation between the tongs to makeup and breakout a connection, see sketch
6.11,

CHAPTER 6 Page 120


Figure 6.11: Tongs for making connections

and can be calculated for diﬀerent tongs (see sketch
6.11) as: for tongs at 90◦ :

I
0.053.Ym .LT . C
Hmax = (6.21)
T
for and tongs at 180◦ :

I
0.038.Ym .LT . C
Hmax = (6.22)
T

T = P.LT (6.23)

where:

Hmax [ft] ... maximum hight of tool
joint shoulder above
the rotary slips
Ym [psi] ... minimum tensile yield
stress of pipe
LT [ft] ... length of tong arm
I
C
[in3 ] ... section modulus of
pipe, see table 6.12
T [lbf-ft] ... makeup torque applied
to tool joint
P [lbf] ... line pull Figure 6.12: Section modulus values of
drillpipe

CHAPTER 6 Page 121


6.5 Selecting Drill Collar Weights
The maximum permissible drilling bit weight
W OBmax that can be applied without bending the
drillstring is calculated as:

W OBmax = (1 − F ) .BF. cos θ.Wdc .Ldc (6.24)

where

W OBmax [lb] ... maximum permissible WOB without bending the drillpipe
F [1] ... longitudinal friction between drillstring and borehole wall
BF [1] ... buoyancy factor, see equation 6.5
θ [◦ ] ... inclination from vertical
Wdc [lb/ft] ... nominal weight of drill collars
Ldc [ft] ... total length of drill collars

For each bit, the bit manufacturer recommends a range for operating WOBs and operating RPMs.
Practically, the WOB applied during drilling is determined by the bit, the formations penetrated,
the trajectory to be drilled and experience with previous BHA performances. Out of these consid-
erations, WOBs and RPMs to drill various formations are planned and the drillstring is checked
for buckling. Note that the equation above is derived for absence of stabilizers. Ordinary, sta-
bilizers are part of common bottom hole assemblies (BHA). Where they are placed determine
the turning behaviour of the drillstring. Fig 6.13 gives some stabilizer conﬁgurations and their
expected behaviors.

Figure 6.13: BHA conﬁgurations

CHAPTER 6 Page 122


6.6 Stretch of Drillpipe
The elongation or stretch of the drillstring is caused by pulling the string as well as due to its own
weight. The amount of stretch itself depends on: the amount of pull, the length of the drillstring,
the elasticity of the materials and the various cross-section areas. The elongations are found as:
due to weight carried:

P.L
e1 = (6.25)
735, 444.Wdp

due to its own weight:

L2
e2 = . (65.44 − 1.44.ρm ) (6.26)
9.625.107
where:

e1 , e2 [in] ... drillstring stretches
P [lb] ... weight carried
Wdp [lb/ft] ... weight of drillpipe
ρm [ppg] ... mud weight
L [ft] ... length of drillpipe

To calculate the total stretch of the drillpipe, both stretches (e1 and e2 ) have to be added.

6.7 Critical Rotary Speeds
Rotating the drillstring at critical rotary speeds causes vibrations which lead to excessive wear,
rapid deterioration, crooked drillpipe and fatigue failure.
In general, critical rotary speeds depend on length, seize and makeup of of the drillstring. The
caused vibrations can be distinguished into:

1. Vibration in nodes. Here the pipe between each joint vibrates.

2. Vibration of the total drillstring. Here the vibration is classiﬁed as a spring pendulum one.

Equation 6.27 calculates the critical rotation speed for vibration type 1:

4, 760, 000
RP M = . d2 − d2
o i (6.27)
l2

CHAPTER 6 Page 123


and equation 6.28 is used to estimate the critical rotation speed for vibration type 2:

258, 000
RP M = (6.28)
L
where:

l [in] ... length of single pipe
do [in] ... outside diameter of drillpipe
di [in] ... inside diameter of drillpipe
L [ft] ... total length of the drillstring

The critical rotation speeds calculated above are accurate to about 15%. In this way, rotation
within ± 15% of these speeds have to be avoided.
Special care has to be taken to avoid rotary speeds that are close to the critical rotation speeds
of vibration type 1 and vibration type 2. Their coexistence can lead to severe damages.

6.8 Bottom Hole Assembly Design
The physical properties of the various downhole components of the BHA have a significant effect
on how the bit will drill. In most drilling situations, the bottom 100 to 300 [ft] of the bottom hole
assembly has the greatest influence on its behavior. The construction of the bottom hole assembly
can be as simple as consisting of a drill bit, collars, and drill pipe, or may be as complicated as
including a drill bit, stabilizers, collars of different sizes and materials, heavy-weight drill pipe,
drill pipe etc.

Drill Collars:

Drill collars are the predominant components of the bottom hole assembly. The primary function
of the drill collars is to be able to apply weight to the bit without buckling the drill pipe. Since
the collars are under compression, they will tend to bend under the applied load. The amount of
bending will depend on the material and the dimensions of the collar.
The shape of the drill collar may have a circular or square cross section. A string of square collars
provides good rigidity and wear resistance, but it is expensive, has high maintenance costs for
certain conditions and may become stuck in key-seated dog-leg. Typically, standard and spiral
drill collars with external grooves cut into their profile may be used to reduce the contact area
between the BHA and the formation.
In deviated holes the total weight of the drill collars is not applied to the bit. Part of that weight
is applied to the wall of the hole depending on the amount of deviation. The actual weight on bit
is a function of cos α where α is the angle of inclination.

CHAPTER 6 Page 124


Stabilizers:

Stabilizers are fairly short subs with blades attached to the external surface. By providing support
to the bottom hole assembly at certain points they can be used to control the trajectory of the
well. Drilling straight or directional holes requires proper positioning of the stabilizers in the
bottom hole assembly. It is important to note that the position of the first stabilizer and the
clearance between the wall of the hole and the stabilizers has a considerable effect in controlling
the hole trajectory.
Stabilizers can be grouped into rotating blade stabilizers and non-rotation blade ones. A rotating
blade stabilizer can have a straight blade or spiral blade configuration. In either case the blades
may be short or long. The spiral blades can give 360◦ contact with the bore hole. All rotating
blades stabilizers have good reaming ability and good wear life. Non rotating rubber sleeve
stabilizers are used to centralize the drill collars, where the rubber sleeve allows the string to rotate
while the sleeve remains stationary. Since the sleeve is stationary, it acts like a drill bushing and
does not dig or damage the wall of the hole. It is most effective in hard formation.

6.9 Placement of Stabilizers and Reamers

In the previous section the maximum WOB that doesn’t cause the drillstring to buckle was
calculated. To prevent buckling when higher WOBs have to be applied, as well as to steer the well
into certain directions, both stabilizers and reamers are placed within the drillstring configuration.

Figure 6.14: Charts to obtain stabilizer spacing

CHAPTER 6 Page 125


Here they act as fulcrums. Stabilizers are slightly under-gauge, their function is to center the
drillstring. Reamers on the other hand ensure that the hole is drilled in-gauge.

Figure 6.15: Charts to obtain stabilizer spacing con.

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The ideal location of various stabilizers depend on the desired behavior of the drill string (drop-
ping, building, holding angle, see sketch 6.13). The different configurations give the BHAs their
individual name. In general, a stabilizer is placed such that the lowest sag point in the drill collar
section is very close to the borehole wall without touching it.

Figure 6.22: Chart for the solution of borehole inclination problems

6.9.1 Building Assemblies

This type of assembly is usually run in a directional well after the initial kick-off has been achieved
using a deflection tool. A single stabilizer placed above the bit will cause building. The addition
of further stabilizer(s) will modify the rate of build to match the required well trajectory. If the
near bit stabilizer becomes under-gauge, the side force reduces. The amount of weight on bit
applied to these assemblies will also affect their building tendencies. Normally the higher the bit
weight the higher the building tendency.

CHAPTER 6 Page 133


6.9.2 Holding Assemblies

Once the inclination has been built to the required angle, the tangential section of the well is
drilled using a holding assembly. Holding assemblies do not maintain inclination angle; rather,
they minimize angle build or drop.
Minimal tilt angle at the bit, as well as stiffness of the bottom hole assembly near the bit helps
maintain inclination angle. Change in weight on bit does not affect the directional behavior of this
type of assembly and so optimum weight on bit can be applied to achieve maximum penetration
rates.

6.9.3 Dropping Assemblies

The application of a dropping assembly is that when the inclination has been increased beyond
the intending trajectory and must be reduced to bring the well back on course. Normally these
BHA configurations are more effective in high angled holes. If the hole angle does not decrease,
the weight on bit can be reduced with use of these assemblies, although this will also reduce the
penetration rate.

6.9.4 WOB Increase

Since stabilizers reduce the drillstring tendency to buckle, larger WOBs can be applied. It is
common to express the possible increase in WOB as a percentage of the maximum allowed WOB
without stabilizers. For commonly encountered borehole seizes figure 6.13 can be applied to
derive the proper position of a stabilizer and the resulting bit weight increase when the maximum
allowable WOB without stabilizer is known. This figure is also applied to compare the data to
plan for with practically established data using other combinations of drill collar seize, bit weight,
borehole seize, borehole inclination and formation dip.
In practice, since the ideal position of the stabilizer is based on a particular scenario and the BHAs
are not always changed when the trajectory of the well changes, a compromise when designing the
BHA has to be formed. Therefore the stabilizer is placed between the ideal position, as derived
above and about 10% closer to the bit. When very light weight on bit is run (nonpacked holes),
the stabilizer position should not be closer than 5% to the bit than the ideal position, as it is
calculated above.

6.10 Dogleg Severity Analysis
Dogleg severity is defined as total curvature of the wellbore per 100 [ft] and is expressed with the
unit [◦ /100 ft].
Most of drillpipe failure is caused by fatigue wear, which occurs due to of cycle bending stresses
and axial stresses when the drillpipe under load rotates along a sharp bend (dogleg).

CHAPTER 6 Page 134


Since the drilling fatigue is based on the combination of bending and axial stresses as well as
tension in the drillpipe, fatigue danger is highest in the upmost part of the drillstring. Therefore
shallow, sharp bends of the trajectory of deep wells are to be avoided. In these situations rotation
oﬀ bottom (no WOB) increases the danger of fatigue wear since the weight of the drill collars
increase the tension load.
To calculate the maximum permissible dogleg severity, equations 6.31 is used:

π
I= . d4 − d4
o i (6.29)
64

T
K= (6.30)
E.I

432, 000 σb tanh (K.L)
C= . . (6.31)
π E.D K.L

where:

C [◦ /100 ft] ... maximum permissible dogleg severity
T [lb] ... buoyant weight suspended below the dogleg
(including tool joints)
E [psi] ... Young’s modulus (steel: E = 30.106 [psi])
I [in4 ] ... drillpipe moment of inertia
do [in] ... drillpipe outside diameter
di [in] ... drillpipe inside diameter
σb [psi] ... maximum permissible bending stress
D [in] ... drillpipe outer diameter
L [in] ... half the distance between tool joints
(for range 2 drillpipe: 180 [in])

Using the buoyant tensile stress σt [psi], the maximum permissible bending stress σb [psi] can be
found for diﬀerent grades of drillpipe.

T
σt = (6.32)
A

Grade E75 drillpipe:

10 0.6
σb = 19, 500 − .σt − 2
. (σt − 33, 500)2 (6.33)
67 670

Grade S135 drillpipe:

CHAPTER 6 Page 135


σt
σb = 20, 000 1 − (6.34)
145, 000

where:

A [in2 ] ... cross-sectional area of drillpipe wall

As discussed above, the maximum permissible dogleg severity changes with depth. Therefore a
chart showing maximum permissible dogleg severity on the x-axis and the depth on the y-axis
should be included in the well plan. A sample of such a plot is shown in ﬁgure 6.23.

Figure 6.23: Maximum Dogleg Proﬁle

Since lateral loading of tool joints can also create damage to the drillpipe, Lubinski recommended
a maximum lateral load limit of 2,000 [lb] which is expected to not cause damage. Taking lateral
loads F [lbf] into account, the maximum permissible dogleg severity CL [◦ /100 ft] can be calculated
as:

108, 000.F
CL = (6.35)
π.L.T

CHAPTER 6 Page 136


6.11 Examples

1. To drill a well to a depth of 13,500 [ft] using a 5 [in], 19.5 [lb/ft], 4.276 [in] ID grade E and grade
X95 new drillpipe. The total length and weight of the drill collars and heavy-weight drillpipe are
984 [ft] and 157,374 [lb] respectively. The maximum expected mud weight at 12,000 [ft] is 12.5
[ppg]. Calculate the:

(a) Maximum length of each grade of drillpipe that can be used
if a MOP of 50,000 [lb] is to be maintained for the lower grade,
(b) MOP of the heavier grade.

2. A WOB of 50,000 [lb] is to be put on a 12- 1 [in] bit at a depth of 10,000 [ft]. As assemble, 8
4
[in] OD, 3 [in] ID, 147 [lb/ft] drill collars are connected to 5 [in], 19.5 [lb/ft] drillpipe. The applied
mud weight is 12.5 [ppg]. What is the required length of drill collars to drill a:

(a) Vertical hole,
(b) Deviated hole with θ = 45◦

3. To run a 4.5 [in] OD liner weighting 50,000 [lb] to 10,000 [ft], a 5 [in] drillpipe, 19.5 [lb/ft],
grade E premium class is used. What is the total stretch of the 8,500 [ft] long drillpipe when the
mud weight is 12.5 [ppg]?

4. Determine the bit weight of the problem data when:
Established data: 7 [in] drill collar OD, 40,000 [lb] WOB, 9 [in] hole seize, 10◦ inclination;
Problem data: 11 [in] drill collar OD, 12 [in] hole seize, 10◦ inclination.

5. What is the ideal stabilizer spacing and percent more bit weight for 8 [in] OD, 3 [in] ID
drill collars when 50,000 [lb] WOB shall be applied on a 12- 1 bit at a depth of 10,000 [ft]? The
4
equilibrium angle exists and is kept at 6◦ .

6. A 10,000 [ft] drillstring consists of 9,700 [ft] 5 [in] OD, 4.276 [in] ID, 19.5 [lb/ft], premium
grade E drillpipe and 300 [ft] of 8 [in] OD, 3 [in] ID, 147 [lb/ft] drill collars. The used drilling
mud weight is 12.5 [ppg] and the applied WOB is 45,000 [lb]. What is the maximum permissible
dogleg severity of the drillpipe at 3,000 [ft]?

CHAPTER 6 Page 137


7. A drillstring has to be designed using grade E, G and S, premium pipes with OD 5 [in], ID
4.276 [in]. The drill collar used is OD 7 [in], ID 2.5 [in], mud weight applied is 15 [ppg]. When
a minimum of 100,000 [lb] MOP is required, how deep can be drilled? What is the MOP when
drilling at 25,000 [ft]?

CHAPTER 6 Page 138


Chapter 7

Drilling Fluid

Drilling fluid or also called drilling mud is a mixture of water, oil, clay and various chemicals.
Within drilling it performs various functions and contributes with a large portion to the total well
costs. In this way the mud system (or mud program) has to be carefully designed to ensure a
successful drilling project.

7.1 Functions of Drilling Mud

As mentioned above, the drilling mud serves many purposes which may not all be achieved simul-
taneously for all parts of the well. In this way an individual prioritizing has to followed. Below is
a summery of some main mud functions:

1. The mud has to transport the drilling cuttings from the bottom of the hole to the surface.
For this, a high mud circulation velocity, a high mud density and a high mud viscosity are
favorable.

2. Once the cuttings are at the surface, efficient mud cleaning (separation of cuttings, formation
gas, etc. from the mud) has to be possible applying a reasonable amount of cleaning equip-
ment. For further circulation, mud pumps allow ordinary a maximum of 2% sand content
without showing excessive wear.

3. The mud has to cool and lubricate the drilling bit as well as the drilling string to minimize
its wear. Adding of bentonite, oil and various emulsifying agents as well as graphite favors
the cooling capability.

4. At overbalanced drilling, the mud has to seal off permeable formations by forming an im-
permeable, relatively thin mud cake at the borehole wall of the permeable formations. This
capability can be obtained by adding of bentonite and chemical treatment of the mud which
enhances deflocculation and solids distribution.

CHAPTER 7 Page 139


5. Commonly, the mud has to create an overbalanced drilling condition to control the formation
pressure. Mud weight is increased with additives like barite to create a hydrostatic pressure
inside the well which is slightly higher than the formation pressure. Normally, an overbalance
of 100 to 200 [psi] has proven to be adequate to establish safe drilling.

6. Capability to hold drilling cuttings in suspension when circulation is interrupted. Failure of
this capability would allow the cuttings to move down the hole, settle at favorable places
and block the drillstring. This thixotropic capability depends on the individual gel strength
of the drilling mud.

7. To create a buoyance force to partly support the weight of the drillstring and casing string.
The buoyance force is strongly depended on the mud weight used. An increase in mud weight
that increases the buoyance results in smaller surface equipment requirements.

8. Reduce formation damage of various horizons penetrated. The borehole should be drilled
in-gauge (borehole seize = drill bit seize) and either cave-ins (logging and stuck pipe) or wash-
outs (possible cementing problems) avoided. Also the invasion of mud and small cuttings
into the formation or chemical reaction of the mud with the formation have to be avoided
since these would induce a positive skin effect and reduce later production rates.

9. The drilling mud should be neural to the proposed logs run and thus allow to obtain accurate
information about the formations penetrated.

10. The drilling fluid has to transmit the hydraulic horsepower to the bit and allow maximum
penetration rates.

11. The mud system should minimize the torque and drag of the drillstring to decrease wear
and possible failure as well as stuck pipe.

12. For the usage of while drilling tools, the mud should be able to carry the measurement signal
(e.g. as mud pulses).

7.2 Types of Drilling Mud
Out of these different functions, the composition of a particular mud system does depend on
the actual requirements of the individual well or well section. Wells are drilled through different
formations that require different mud properties to achieve optimum penetrations and stable
borehole conditions. Therefore economics, component and additives availability, temperature and
contamination are just a few of the major factors that determine the design of a particular mud
program.
All the possible mixtures that form drilling mud can be generally characterised by the following
system. Further sub-classifications do exist.

CHAPTER 7 Page 140


1. Water based muds

(a) Clear water and native mud
(b) Inhibitive water-based mud – calcium muds
(c) Dispersed muds – lignosulphonate muds
(d) Nondispersed muds – KCL/polymer muds
(e) Flocculated muds
(f) Salt-saturated muds

2. Oil-base muds

3. Emulsion muds

(a) Oil-in-water emulsions
(b) Water-in-oil emulsions

4. Aerated muds

(a) Air
(b) Natural gas
(c) Mist, foam, or aerated muds

7.2.1 Water-base Muds

The term water-base mud refers to any drilling fluid where the continuous phase, in which some
materials are in suspension and others are dissolved, is water. Thus any water-base mud system
consists of a water phase, inert solids, a reactive solids phase and chemical additives. Each of
these parts contribute to the overall mud properties. The individual contributions are:

water: create initial viscosity.

inert solids (low-gravity solids like sand and chert and high-gravity solids like
barite and lead sulfides): produce required mud weight.

reactive solids (low-gravity solids like bentonite and attapulgite clays):
cause further viscosity and yield point.

chemical additives (mud thinners like phosphate, chrome, lignosulphonate, lignites,
and surfactants, and mud thickeners like lime, cement and
polymers): aid to control viscosity, yield point, gel strength,
fluid loss, pH-value, filtration behavior.

CHAPTER 7 Page 141


To control corrosion, hydrogen embrittlement and the solubility of Ca2+ and Mg2+ , a high pH
value is required and can be controlled with caustic (NaOH).

Clear Water and Native Muds
To drill compact formations which are normally pressured (formation pressure equals hydrostatic
pressure caused by formation fluids), fresh water and salt-saturated water can be used as drilling
mud. As the name indicates, native muds are a mixture of water and clays or shales from the
cuttings drilled. Here the clays or shales are dissolved by the water and returned to the surface.
Clear water and native muds are the cheapest mud systems since no additional material to form
the mud is needed. They are also environmentally best accepted.

Inhibitive water-base Mud – Calcium Muds
When swelling and hydration of clays and shales are expected, inhibitive water-base muds can be
applied. Calcium muds are best suited to penetrate horizons that contain gypsum and hydrite. A
subclassification of inhibitive water-base muds distinguishes seawater muds, saturated saltwater
muds, lime muds and gypsum muds.

Dispersed Muds – Lignosulphonate Muds
Dispersed muds are used when the mud has to have following characteristics: relative high mud
weight (larger than 14 [ppg]), used at moderately high formation temperatures, low filtration loss
required and high tolerance for contamination by drilling solids.
Some of the disadvantages when using dispersed muds are: heaving of shales and causing formation
damage due to dispersant of formation clays in the presence of lignosulphonate.
Dispersed mud systems consist of: fresh or salty water, bentonite, lignosulphonate, caustic soda
and colloidal polymers (carboxy methyl cellulose or stabilized starch). In general, these mud
systems exhibit better control of viscosity, a higher solids tolerance and a better control of filtration
than nondispersed muds.

Nondispersed Muds – KCL/Polymer Muds
To drill water sensitive and sloughing shales such as productive sands which are prone to formation
damage, fresh water nondispersed muds are applied. Commonly, nondispersed muds are associated
with low mud weights and low solid concentrations.
Nondispersed mud systems consist of: fresh water or brine, potassium chloride (KCl), inhibiting
polymer, viscosifier, stabilized starch or carboxy methyl cellulose, caustic soda and lubricants.

CHAPTER 7 Page 142


Low-solids polymer mud systems are widespread in the industry since they offer advantages like
increased penetration rate, hole stability, shear thinning ability, hole cleaning with maximum
hydraulics and lower equivalent circulation density over conventional deflocculated muds. With
all these advantages, they also have disadvantages like instability at temperatures above 250 [F],
irreversible absorption of the polymer on clay, a higher dilution and an adequate solids removal
equipment is required as well as they are more corrosive.

Flocculated Muds
Flocculated muds posses generally a dynamic increase in filtration, viscosity and gel strength.
Flocculation refers to a thickening of the mud due to edge-to-edge and edge-to-face association
of clay particles. The flocculation is commonly caused by high active solids concentration, high
electrolyte concentration and high temperature. To reduce the flocculating tendency of the mud,
chemical additives, also called deflocculants or thinners are used. Thinners like phosphates, tan-
nins, lignins and lignosulphonate are applied to lower the yield point and gel strength. When
deflocculants are added, the pH-value is controlled by NaOH.

Salt-saturated Muds
Salt-saturated muds are used to drill through salt domes and salt sections. These mud systems are
saturated with sodium chloride (NaCL) that prevents severe hole enlargements due to washouts
of the salt formations. Swelling of bentonitic shales is controlled by adding of polymer.

7.2.2 Oil-base Muds

Opposite to water-base muds where water is the continuous phase, at oil-base mud systems crude
or diesel oil forms the continuous phase in the water-in-oil emulsion. In this way oil-base mud can
have as little as 3% to 5% or as much as 20% to 40% (invert emulsions) water content. Oil-base
mud systems are applied when:

1. Drilling sensitive production zones or problem shales,

2. Drilling salt sections and formations that contain hydrogen sulfide,

3. Danger of stuck pipe problems,

4. Drilling at bottom hole temperatures that are permissable by water-base muds.

Low-gravity solids content has to be monitored closely when drilling with oil-base muds since
at this environment solids do not hydrate which causes low-gravity solids contents to exceed
acceptable levels often. This results in reduction of penetration rate, formation damage and
increase in risk of differential sticking.

CHAPTER 7 Page 143


Since oil-base muds contain substantially less colloidal particles, they exhibit a spurt fluid loss.
Due to the higher filtration rates, the monitoring of high-pressure high-temperature filtration as
well as the drilling conditions are important to ensure that excessive filtration or filter cake buildup
does not lead to problems.

7.3 Mud Calculations
The fundamental properties to describe a drilling mud are:

1. Mud weight,

2. Plastic viscosity,

3. Yield point,

4. Gel strength,

5. Filtrate and filter cake,

6. pH-value.

The procedures and equations to calculate the rheological properties like the plastic viscosity, the
yield point and the gel strength were discussed at drilling hydraulics. In the following, the reaming
mud characteristics and their measurement in the field are elaborated.

pH Determination
The pH-vale is defined as negative logarithm of the hydrogen ion content of a solution (pH =
− log[H+ ]). In this way, an increase of the concentration of H+ ions decreases the pH-value and a
decrease of H+ ions increases the pH-value. When the pH-value is known, it is determined whether
the mud is acidic (OH− < H+ thus pH-value < 7) or alkaline (OH− > H+ , thus pH-value > 7). A
pH-value of 7 indicates a neutral mud.
Measuring the pH-value of a fluid is either performed with the help of a pH-meter or a special
pH-paper which changes color according to the pH-value determined.
The OH− concentration within a solution, at a given pH-value, is defined by:

H+ OH − = 1.0.10−4 (7.1)

or:

OH − = 10(pH−14) (7.2)

CHAPTER 7 Page 144


To change a solution’s pH-value from pH-value1 to pH-value2 , a OH− concentration change of

∆ OH − = 10(pH2 −14) − 10(pH1 −14) (7.3)

is required.

Mud Weight Calculation
The mud weight or mud density is determined by the volumes and types of solids added to the
mud system. Therefore to compute the correct mud density, an accurate knowledge of all volumes
and densities of additives added to the mud system is required. The following equations can be
used to calculate the mud weight. Commonly added materials, together with their densities, are
given in table 7.1.

mi
Vi = (7.4)
ρi

m1 + m2 + ... + mn
ρ= (7.5)
V1 + V2 + ... + Vn

Figure 7.1: Common Mud Additives

Density Control Computation
The ﬁnal mud volume after changing the mud weight from ρ1 to ρ2 is computed with:

ρB − ρ 1
V2 = V1 . (7.6)
ρB − ρ2

CHAPTER 7 Page 145


In practice, since excess storage capacity is not available and to limit the amount of added, costly
weighting material, before the density is increase (e.g. by adding barite), some mud volume is
discarded from the circulation system. In this situation, equation 7.7 calculates the volume the
existing mud has to be reduced to before weighting material is added:

ρB − ρ 2
V1 = V2 . (7.7)
ρB − ρ1

With the knowledge of the volumes, the densities of the original mud and the weighting material,
the weight of barite required is given by:

mB = 42. (V2 − V1 ) .ρB (7.8)

where:

mB [lbm] ... weight of API barite
ρB [ppg] ... density of API barite
ρ1 [ppg] ... density of original mud before weighting
ρ2 [ppg] ... density of ﬁnal mud after weighting
V1 [bbl] ... volume of original mud before weighting
V2 [bbl] ... volume of ﬁnal mud after weighting

Due to the barite’s extremely large surface area, barite has the tendency to adsorb a large amount
of water from the mud system and thus increases the viscosity of the drilling mud.
This thickening is avoided when not only barite but also a minimum amount of water, to wet the
barite, is added simultaneously. A common practice is to add 1 [gal] of water for each added 100
[lbm] of barite. To take this extra water into account and when assuming that original mud is
discarded before weighting, following equations give the volume of original mud and the amount
of barite required:

 
ρB 1+ρw .VwB
1+ρB .VwB
− ρ2
V1 =   (7.9)
ρB 1+ρw .VwB
1+ρB .VwB
− ρ1

42.ρB
mB = . (V2 − V1 ) (7.10)
1 + ρB .VwB

where:

VwB [gal/lb] ... volume of water added with barite
ρw [ppg] ... density of water added with barite

CHAPTER 7 Page 146


When the concentration of low-gravity solids should be kept to a minimum value (see comments
before), it is cheaper to reduce them by dilution before weighting the original mud with barite.
The following equations are applied to calculate the corrected volume of the original mud V1 , the
volume of the dilution water Vw , the mass of the weighting material m2 and the obtained final
mud volume V2 after weighting:

fc2
V1 = V2 . (7.11)
fc1

(ρB − ρ2 ) .V2 − (ρB − ρ1 ) .V1
Vw = (7.12)
(ρB − ρw )

mB = 42. (V2 − V1 − Vw ) .ρB (7.13)

Solids Control for Weighted Muds
Solids control in general is the separation of drilling fluid, heavy solids and lighter components. To
perform this separation, centrifuges are used along with other surface equipment, see description
of the circulation system. In the following, the function of the centrifuge shall be evaluated to
some extend.
After degasification and run over various screens as well as a separation tank to discard formation
gas and cuttings from the mud, the mud is fed into a centrifuge. The centrifuge discharges at an
“underflow” a high-density slurry (ρu ) containing API barite, and at an “overflow” a low-density
slurry (ρo ) containing low-gravity solids, water and some chemicals. The overflow with its low-
density slurry is discarded from the circulation system, the underflow with the high-density slurry
is returned to the active mud system.
With equation 7.14 the flow rate of the underflow is computed as:

qm . (ρm − ρo ) − qw1 . (ρo − ρw )
qu = (7.14)
(ρu − ρo )

where:

ρu [ppg] ... density of the underflow slurry
ρo [ppg] ... density of the overflow slurry
qu [gpm] ... underflow flow rate
qw1 [gpm] ... flow rate of dilution water entering the centrifuge
qm [gpm] ... flow rate of drilling fluid entering the centrifuge
ρm [ppg] ... density of drilling fluid entering the centrifuge
ρw [ppg] ... density of dilution water entering the centrifuge

CHAPTER 7 Page 147


Figure 7.2: Sketch of a hydrocyclone

After separation in the centrifuge, the volume fractions of the mud fum , of the dilution water fuw
and the API barite fuB in the underflow are calculated by:

ρB − ρ u
fum = (7.15)
ρB − ρm + qw1 . (ρB − ρw )
qm

qw1
fuw = fum . (7.16)
qm

qw1
fuB = 1 − fum − fuw = 1 − fum − fum . (7.17)
qm

Having the individual fractions of the underflow and the flow rates of the old mud, the rates of
dilution water and the API barite are given by the product of the individual fractions and the
underflow flow rate.
The fraction of the old mud that returns to the mud stream is therefore found as:

CHAPTER 7 Page 148


qu .fum
fm = (7.18)
qm

To maintain the desired mud concentration [lb/bbl] at the mixing pit, the individual mass rates
of the mud additives are calculated as:

(1 − fm ) (qm − qu .fum )
wi = ci .qm . = ci (7.19)
42 42

where:

qm [gal/min] ... flow rate of the mud
qu [gal/min] ... flow rate of the underflow
ci [lb/bbl] ... desired concentration of the ith additive
of the mud stream
42 [gal/bbl] ... conversion [gal] -> [bbl]

Figure 7.3: Sketch of a mud-cleaner

To keep the density of the mud leaving the mixing pit equal to the density of the mud feeded to
the centrifuge, the required water flow rate and the mass rate of API barite are computed with:

CHAPTER 7 Page 149


n
qm . (ρB − ρm ) − qu . (ρB − ρu ) − wc ρB
ρc
−1 − i=1 wi . ρB
ρi
−1
qw2 = (7.20)
(ρB − ρw )

n
wc wi
wB = qm − qu − qw2 − − .ρB (7.21)
ρc i=1
ρi

where:

wc [lbm/min] ... mass flow rate of clay and deflocculant
ρc [ppg] ... density of clay and deflocculant

7.4 Recommended Mud Flow Properties

In the following, empirical correlations to compute the recommended upper and lower limits of the
plastic viscosity and the yield point are given in table 7.4. It should be noted that all correlations
below are based on mud densities only.

Figure 7.4: Limits of plastic viscosity and yield point

The recommended maximum total solids percentage fST and the percentage of low-gravity solids
flg are computed with:

CHAPTER 7 Page 150


fST = 2.917.ρm − 14.17 (7.22)

100. (8.33 − ρm + 26.67.fST )
flg = (7.23)
13.3
where:


CHAPTER 7 Page 151


7.5 Examples
1. The pH-value of a drilling fluid is to be raised from 8 to 11.5. What is the amount of caustic,
having a molecular weight of 40 required?

2. When 150 [lbm] of API barite, 40 [lbm] of bentonite and 1 [bbl] of water are mixed, what is
the resulting density?

3. When 70 [lbm] of calcium chloride is mixed with 1 [bbl] of water, what is the resulting density?

4. 700 [bbl] of mud have to be increased in density from 13 [ppg] to 15 [ppg] by adding of API
barite. Since the mud thickness has to be maintained, 1 [gal] of water is added with every 100 [lb]
of barite. Calculate the total amount of water and barite required when there is no limitation in
the final volume.

5. When 1,000 [bbl] of mud have to be increased from 10 [ppg] to 13 [ppg] mud weight by adding
API barite, the total volume is limited to 1,000 [bbl]. How much old mud has to be discarded and
what is the weight of the added API barite?

6. Using the data from example 5., the volume fraction of low-gravity solids must be reduced
from 0.06 to 0.035 by adding water. Compute the API barite and water to be added as well as
the amount of old mud to be discarded.

7. A centrifuge is fed by a 15 [ppg] mud and 8.33 [ppg] dilution water at rates of 30 [gpm] and 15
[gpm] respectively. The overflow has a density of 11 [ppg], the underflow 25 [ppg]. Assuming that
the mud contains 30 [lb/bbl] bentonite and 15 [lb/bbl] deflocculant, determine the rates to add
bentonite, deflocculant, water and API barite to maintain the mud properties at the mixing pit.

CHAPTER 7 Page 152


Chapter 8

Casing Design

Casing costs compromise one of the largest cost items of the drilling project. Therefore propper
planning of casing setting depths and casing selection is vital to realise a cost effective and safe
well. The casings themselves fulfill multiple functions that can be summarized as:

1. Isolate porous formations with different fluid-pressure regimes from contaminating the pay
zone,

2. Prevent near surface fresh water zones from contamination with drilling mud,

3. Protect the hole from caving in,

4. Provide a connection and support of the wellhead equipment,

5. Provide exact dimensions for running testing, completion and production subsurface equip-
ment.

8.1 Casing Types
According to the different functions, the total casing program consists of different casings strings.

8.1.1 Conductor Casing

The function of the conductor is to enable circulation of the drilling fluid to the shale shakers
without eroding the surface sediments directly below the rig foundation. The conductor prevents
the subsequent casings from corrosion and may partly support the wellhead weight.
Commonly a diverter is installed on top of the conductor casing to divert an unexpected inflow of
formation fluids into the wellbore away from the rig-site and the personal.
Conductor setting depths are in the range of 150 to 600 [ft], their seizes range from 36 to 20 [in].

CHAPTER 8 Page 153


8.1.2 Surface Casing

The function of the surface casing is to prevent cave
in of unconsolidated, weak near-surface formations as
well as protect the shallow, freshwater sands from con-
tamination with drilling mud. As the conductors, sur-
face casing protects the subsequent casings from cor-
rosion.
Before the surface casing is set, no blow out preventers
(BOP) are installed. After setting the surface casing
and installing the wellhead, a BOP is available to han-
dle kicks when drilling the intermediate hole section.
Surface casing setting depths are in the range from
300 to 5,000 [ft], their diameters range from 24 to 17-
1
2
[in]. Note that the surface casing setting depth is
often determined by government or company policy
and not selected due to technical reasoning.

8.1.3 Intermediate Casing

The intermediate casing string is a purely technical
casing. One or more may be necessary to handle
abnormal formation pressures, unstable shale forma-
tions, lost circulation or cave-in zones. An intermedi-
ate casing may also be necessary to realize the planned
mud weight proﬁle. When for example an abnormally
pressured formation is encountered, it may have to
be protected by an intermediate casing so when for-
mation pressure of the formations below is normal, a
lower mud weight can be applied. Intermediate casing
diameters range from 17- 1 to 9- 5 [in].
2 8

8.1.4 Production Casing

The production casing is set through the prospective
production zone(s). This casing string protects the
environment in case of production tubing failure and
permits the tubing string to be maintained or replaced Figure 8.1: Casing program
during the production life. Commonly production cas-
ing and production liners have gas-tight connections,
their diameters range from 9- 5 to 5 [in]. A production
8
casing diameter of 7 [in] is encountered often.

CHAPTER 8 Page 154


8.1.5 Liners

To save cost, the casing installed sometimes doesn’t reach
until the surface but finishes within the previous string.
Such a casing configuration is called liner. A liner is
mounted on a so called “liner hanger” to the previous
casing string, see sketch 8.2. Commonly the liner head is
several hundred feet into the previous casing to enable a
good cement seal.
Various typical casing programs are shown in sketch 8.5.
To develop a casing program, first the various casing set-
ting depths have to be determined. Since the primary
reason to drill a well is to produce hydrocarbons out
of a reservoir, the final casing inside diameters have to
be large enough to allow for the forecasted completion
and production schemes. Factors like completion type
(open hole, cased hole, monobore production, etc.), ex-
pected amount of production (production tubing seize),
expected production forecast (e.g. need of gas-lift, etc.)
and seize of evaluation tools to be run have to be consid-
ered. In general, for production purposes the well diam-
eters shall be as large as possible. On the other hand, as
small as possible hole seizes reduces the total cost of the
well since:

1. drilling times are faster, Figure 8.2: Liner
2. less mud has to be used (purchase and disposal of
mud),

3. smaller mud equipment can be used (cleaning, pumps, etc.),

4. smaller casings can be used (cheaper, higher strength at same grade),

5. smaller rig can be applied (lighter casings, smaller mud volume),

6. rig site can be smaller (especially important offshore and platform types like TLP where
weights are limited).

Out of this reason a technology called slim-hole drilling was developed.

CHAPTER 8 Page 155


8.2 Casing Setting Depths

In general, the casing setting depths calcu-
lation starts at the bottom of the well with
the minimum required hole seize (often pro-
vided by the production department). After
determination of the hole seize to drill and ap-
plying the corresponding mud weight, a kick
(normally gas kick, volume and pressure com-
pany depended) is assumed and it is calcu-
lated where, when the kick is circulated out,
the pressure of the kick would fracture the for-
mation. This is the highest depth the previ-
ous casing could be set to handle the assumed
kick. Having the setting depth of the previous
casing, the propper corresponding hole seize
is determined using chart 8.3. From here on,
the same procedure is applied to find the next
casing setting depth and so on until the depth
of the surface casing is reached. As mentioned
before, the setting depth of the surface casing
is normally determined by government or lo-
cal regulations.
The procedure described above gives the
cheapest, since shortest casing strings possi-
ble. In practice it is often required to have
the ability to drill deeper than the planned
well depth. To provide this flexibility casing
strings are run deeper than calculated by the
previously described procedure.
Up to now, casing setting depths determina-
tion was only based on the fracture gradi-
ents of the different formations and the mud
weights of the different sections. The forma-
tions to be drilled themselves are also influ-
encing the casing setting depths determina-
tions. It is often required to seal off a porous
formation before drilling deeper, or to isolate
various sensitive formations like salt. As com-
mon practice a casing is normally set into a
competent (shale) formation.
When drilling within an area where the geol-
ogy and formation properties are well known,
Figure 8.3: Common Casing Bit Combinations
CHAPTER 8 Page 156


the casing setting depths and design can be optimised taking the considerations discussed above
into account. At locations where the formations are not well known or overpressures can be ex-
pected, additional strings have to be planned for. These additional strings may be necessary to
seal off overpressured formations or handle various unexpected situations.
When running the casings into the borehole, a so called casing tally is produced that keeps track
of all casings (types, details) and casing equipment (centralisers, scratchers, etc.) that is actually
lowered into the well.
When the casing setting depths are finally established, the individual casing strings are to be
designed.

8.3 Casing Connections
Casings used for oil and gas wells have to be equipped with connections that can be made up
easily and are leakproof. The casing joints itself are manufactures in different types that fulfill
different requirements. Threaded connections are rated according to their “joint efficiency”. The
joint efficiency is defined as the ration between tensile strength of the joint and the tensile strength
of the body. API casing joint types are:

Figure 8.4: API Connectors

1. Short-Round-Thread: as long-round thread, offer no pressure seal at internal pressures,
threaded surfaces get further separated.
2. Long-Round-Thread: greater strength than short-round threads, often applied since re-
liable, easy and cheap, joint efficiency greater than at short-round threads but less than
100%.

CHAPTER 8 Page 157


3. Buttress-Thread: offers a nearly 100% joint efficiency, is not 100% leakproof.

4. Extreme-Line: design is an integral joint (box is matched on the pipe wall), pipe wall
must be thicker near the ends of the casing to provide the necessary strength, OD of this
connection is significantly lower than of others and half as many threaded, connections exist,
metal-to-metal seal, much more expensive.

Since round-threads have eight threads per [in], they are sometimes called API 8-Round threads
as well.

Figure 8.5: Typical Casing Programs

Along with these API connection types, other ones offering premium features are applied in the
industry. Some of these special features are:

1. Flush joints for maximum clearance.

2. Smooth bores through connectors for reduced turbulence.

3. Threads designed for fast make-up with low tendency to cross-thread.

4. Multiple metal-to-metal seals for enhanced pressure integrity.

5. Multiple shoulders for enhanced torque strength.

6. High compressive strengths for special loading situations.

7. Resilient rings for secondary pressure seals and connector corrosion protection.

CHAPTER 8 Page 158


As drillpipes, casings are manufactured in different length ranges:

Range 1 16 to 25 [ft],

8.4 API Casing Performance Properties
The American Petroleum Institute (API) has developed internationally accepted standards for
oilfield tubulars and summarised them in bulletins that contain the minimum performance prop-
erties and equations to compute these properties. It should be understood that these properties
are guidelines (minimum requirements), for casing design calculations, the exact strength values
provided by the individual manufacture shall be applied.
A casing is defined by:

1. Casing outside diameter (OD),

2. Weight per unit length (this determines the wall thickness),

3. Grade of steel,

4. Type of coupling,

5. Length of joint.

To determine the strength of various casing materials, API has designated defined grades. The
grading code consists of a letter followed by a number where the number gives the minimum yield
strength of the material in thousands of [psi], the number is an arbitrary one (e.g. N-80). For wells
that require very high tensile strength, collapse resistance or better corrosion resistance, non-API
casings are used by the industry as well.
Tables 8.6 through 8.21 list API and some non-API ones as well as gives the minimum performance
properties of them. To calculate the individual properties following equations can be applied:

Yield strength collapse pressure:

do
t
−1
py = 2.σy do 2
(8.1)
(t)

do
Above equation is valid up to where t
intersects ( dto )yp and thus the plastic deformation starts.
( dto )yp is calculated as:

CHAPTER 8 Page 159


Figure 8.6: Casing Properties

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Figure 8.7: Casing Properties con.

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(FA − 2)2 + 8 FB + FC
σy
+ (FA − 2)
do
= (8.2)
t yp 2. FB + FC
σy

Plastic collapse pressure:

FA
pp = σy do
− FB − FC (8.3)
t

do
The plastic collapse pressure equation given above is valid for t
values in the range of ( dto )yp to
( dto )pT , which is calculated as:

do σy . (FA − FF )
= (8.4)
t pT FC + σy . (FB − FG )

Transition collapse pressure:

F
pT = σy do
− FG (8.5)
t

do
The transition collapse pressure equation given above is valid for t
values in the range of ( dto )pT
to ( dto )T E , which is calculated as:

FB
do 2+ FA
= (8.6)
t TE 3. FB
FA

Elastic collapse pressure:

49.95.106
pE = 2 (8.7)
do
t
. do
t
−1

do
The elastic collapse pressure equation given above is valid for t
values shown in table x.

Collapse pressure under axial tension stress:

CHAPTER 8 Page 176


σa
σya = 1 − 0.75 (σa − σy )2 − 0.50. .σy (8.8)
σy

Pipe body yield strength

Wp = 0.7854. d2 − d2 σy
o i (8.9)

Round thread casing joint strength - short & long threads & couplings:
Lesser of

Wj = 0.95.Aip .σup (8.10)

and

0.74.d−0.59 .σup
o σy
Wj = 0.95.Aip .Le + (8.11)
0.5.Le + 0.141.do Le + 0.141.do

Buttress thread casing joint strength:
Lesser of

σy
Wj = 0.95.Ap .σup . 1.008 − 0.0396. 1.083 − (8.12)
σup

and

Wj = 0.95.Ac .σuc (8.13)

Casing types can be normally identiﬁed by their nominal weight, which are based on 20 [ft] length
of threaded and coupled casing joint. They can are calculated as:

Nominal casing weight:

Wn = 10.68. (do − t) .t + 0.0722.d2
o (8.14)

The plain end casing weight is deﬁned as the weight of the casing joint without inclusion of threads
and couplings.

CHAPTER 8 Page 177


Plain end casing weight:

Wpe = 10.68. (do − t) .t (8.15)

where for all equations above,

do [in] ... tubular outside diameter
t [in] ... tubular wall thickness
σy [psi] ... minimum yield pressure of tubular
σya [psi] ... yield strength of axial stress equivalent grade
σa [psi] ... axial stress-tension (positive)
FA ... correlation factor, given in table 8.22

or:
FA = 2.8762 + 0.10679.10−5 .σy + 0.21301.10−10 .σy − 0.53132.10−16 .σy
2 3
(8.16)

FB ... correlation factor, given in table 8.22

or:
FB = 0.026233 + 0.50609.10−6 .σy (8.17)

FC ... correlation factor, given in table 8.22

or:
FC = −465.93 + 0.030867.σy − 0.140483.10−7 .σy + 0.36989.10−13 .σy
2 3
(8.18)

FF ... correlation factor, given in table 8.22

or:
46.95.106 . (3FB /FA /2 + FB /FA )3
FF = (8.19)
σy . (3FB /FA /2 + FB /FA − FB /FA ) . (1 − 3FB /FA /2 + FB /FA )2

FG ... correlation factor, given in table 8.22

CHAPTER 8 Page 178


or:
FF .FG
FG = (8.20)
FA

Figure 8.22: Empirical coeﬃcients for collapse pressure calculations

Aip [in2 ] ... cross-sectional area of the tubular wall under
the last perfect thread
Ap [in2 ] ... cross-sectional area of plain end tubular
Ac [in2 ] ... cross-sectional area of coupling
Le [in] ... engaged thread length
σup [psi] ... minimum ultimate strength of tubular
σuc [psi] ... minimum ultimate strength of coupling

8.5 General Casing Design Criteria
Casing design itself is an optimization process to ﬁnd the cheapest casing string that is strong
enough to withstand the occurring loads over time. The design itself is therefore depended on:

CHAPTER 8 Page 179


1. Loading conditions during life of well (drilling phase, completion procedures, workover op-
erations, and operation phase),

2. strength of the formation at the casing shoe (assumed fracture pressure during planning and
verified by the formation integrity test),

3. availability and real price of individual casing strings,

4. expected deterioration of the casing due to production and expected completion fluid set-
tlement.

It should be noted that the loading conditions are subjective and based on company policies,
governmental regulations and best practices. Regarding real casing prices, casing types currently
on stock and general availability (purchase of manufacturing lot) can have a major selection
implication.
Similar to the drillstring, casings are normally designed for burst, collapse, tension, shock loads
and biaxial stresses. Different safety margins or safety factors are demanded by company policies
or government regulations and have to be satisfied.
To calculate the burst and collapse pressure the casing has to be designed for, the differential
pressure (outside pressure - inside pressure) is determined for the worst case to appear.
For burst pressure, the maximum formation pressure anticipated while drilling the next section is
assumed. Thus the highest burst pressure is expected to be at the top of the casing and least at
the casing shoe (hydrostatic pressure at annulus to counterbalance). When the production tubing
is assumed to leak gas to the casing, this burst pressure profile is reversed.
For collapse pressure, it is assumed that the mud inside the casing is lost to a weak or fractured
formation below. Thus the collapse pressure is due to the hydrostatic pressure of the fluid outside
the casing and therefore maximum at the casing shoe and zero at the casing top. In this way the
collapse pressure can be calculated with:

pc = 0.052.ρout .D (8.21)

The tensile forces acting on the casing are due to its weight, bending forces and shock loading at
landing. It should be noted that at highly deviated wells, landing the casing is only possible when
run partly or totally empty. This is also called “floating the casing in”. Here the casing, when
run, is closed at the shoe and its inside is not filled with mud. This causes a buoyancy to such
an extend that the casing may has to be forced into the well. The casing dimensions where the
buoyancy counterbalances the casing weight is given by:

π π
ρst .g.h. d2 − d2 .
o i = ρm .g.h.d2 .
o (8.22)
4 4

d2 − d2
o i ρm
= (8.23)
d2
o ρst

CHAPTER 8 Page 180


For tensile loading, the topmost joint is considered as the weakest one since it carries all the casing
weight.
When casings have to carry inner strings as well (conductor, surface and intermediate casing),
they are subjective to compression loads. Thus production casings and casings where liners are
below are free from these loads.
Since the casing is in general subjected to a combination of external pressures and its own weight,
they are under a biaxial stress regime. This will reduce the collapse resistance of the casing.
The amount of collapse resistance reduction can be calculated with the methods described for
drillstring calculation.
In addition to the general casing loads discussed above, casings are also subjected to bending with
tongs, slip crushing, wear due to rotation of the drillstring and running tools into the hole as well
as corrosion and fatigue.
As mentioned above, the actual loadings of the casings have to be lower than the individual casing
strengths. This is often expressed with safety factors. Applying propper safety factors account
for the uncertainty in estimation the real loadings as well as the change of casing properties over
the lifetime of the well. Commonly chosen safety factors are:

Collapse strength: 0.85 - 1.125
Joint strength: 1.60 - 1.80
Plain-end yield strength: 1.25
Internal yield pressure: 1.0

In practice, sophisticated casing design computer programs are available in companies that allow
complex casing loading scenarios and the design of casing strings with various casing pipes (diﬀer-
ent grades) as well as variable diameters for one casing string. Such casings are generally referred
to as “combination string”.

8.6 Graphical Method for Casing Design
The graphical method to select casings with the suitable grades, weights and section lengths is the
most often applied one. Here, the individual loads (burst, collapse and tensions) are represented
as graphs on a pressure vs. depth diagram. The minimum strength values of the individual casing
sections are drawn as vertical lines where the suitable ones have to be to the right of the respective
loads (stronger). In this way, the depth where the minimum safety (load and casing minimum
strength are closest) can be easily spotted and the respective factors calculated.
To construct the diagram, following procedures can be applied:

CHAPTER 8 Page 181


Burst line:

1. Calculate the external pressure due to an assumed fluid column of 0.465 [psi/ft] (salt-
saturated completion fluid),

2. Calculate the internal pressure due to the maximum anticipated pressures when drilling the
next section,

3. Calculate the burst pressure pb as the difference between the external and the internal
pressures,

pb = pf − (T D − CSD) .Gf − 0.053.ρm .CSD (8.24)

where:

pf [ft] ... maximum anticipated formation pressure to drill next section
TD [ft] ... total depth (TVD)
CSD [ft] ... casing setting depth (TVD)
Gf [psi/ft] ... formation fluid gradient
ρm [ppg ... mud density

In this way the burst pressure at the surface is calculated as:

pb = pf − T D.Gf (8.25)

4. On the pressure vs. depth graph draw a stright line between the maximum Burst pressure
at the casing top and the minimum burst pressure at the casing shoe,

5. Select from tables 8.6 through 8.21 casings with burst resistance above the burst loading
line,

6. Draw the vertical lines of the casings with the individual grades,

7. The individual intersections of the burst loading line and the casing burst resistances deter-
mine the depths from which upwards the casing grades can be used.

Collapse line:

1. Calculate the external and internal pressure due to the mud columns outside and inside the
casing,

2. Calculate the collapse pressure pc as the difference between the external and the internal
pressures,

CHAPTER 8 Page 182


3. On the pressure vs. depth graph draw a stright line between the maximum collapse pressure
at the casing shoe and the zero at the casing top,

4. Select from tables 8.6 through 8.21 casings with collapse resistance above the collapse loading
line,

5. Draw the vertical lines of the casings with the individual grades,

6. The individual intersections of the collapse loading line and the casing collapse resistances
determine the depths up to the casing grades can be used.

Tensile line:

1. Calculate the weight of the casing string in air,

2. Calculate the buoyancy force,

3. Calculate the bending force with equation 8.26 when designing the casing for a deviated
hole,

BF = 63.do Wcs .θ (8.26)

where:

BF [lbf] ... bending force
θ [◦ ] ... change of angle in deviation
Wcs [lb/ft] ... nominal weight of casing Wcs = 3.46.Acs

4. Calculate shock loads due to setting of the casing using equation 6.18 by replacing Wdp with
Wcs ,

5. Draw tensile loading on the pressure vs. depth graph,

6. Select casings from table x that have higher body yield strength than the tensile loading,

Having drawn all three major design criteria within one plot, a combined casing sting that is
strong enough at all depth can be selected. Finally check that the joint strengths are larger the
the calculated tensile loading.

Note that this procedure for casing design considers strength criteria only and is not optimized
for real casing costs. Thus a stronger casing might be preferred since it is cheaper (availability,
etc.) than a weaker one.

CHAPTER 8 Page 183


Figure 8.23: Sketch of graphical design of a casing string

8.7 Maximum Load Casing Design for Intermediate Cas-
ing
The load criteria assumed above are based on a 100 % empty casing (collapse) and a 100 % gas-kick
ﬁlled (burst) one respectively. These are very conservative assumptions that lead to over-design
causing unnecessary high cost of the casing string. If standard drilling procedures and precautions
are followed, these assumptions are not to be expected. When drilling into a weak or fractured
formation that causes lost circulation, the remaining ﬂuid hight can be estimated with:

0.465.CSD
L= (8.27)
ρm .19.25

where:

ρm [ppg] ... weight of mud used to drill next section.

For this reason the casing is supported in the inside by the hydrostatic pressure of the remaining
mud column of length L.

CHAPTER 8 Page 184


In case of burst, the conservative assumption can be relaxed with the assumption that the gas-kick
will fill between 40% to 60% of the hole before the well is shut in and steps to circulate the kick
out are taken. Modern kick detection systems detect kicks of 20 [bbl] and below (depending on
the hole seize) and thus the assumption above could be even more relaxed.

8.8 Casing Centralizer Spacings

To have a centered casing string which is essential for proper cementing and to lower dragging
forces when running the casing, so called centralizers are placed along the casing string. The
clearance (distance between casing OD and wall) is called “standoff”. The centralizer spacing
should be sufficient enough to provide a minimum standoff but excessive use of them do induce
additional drag, can disturb the cement flow and, last but not least, add to the well costs.

Figure 8.24: Casing centralizers

In normal oilfield services, following equations are used:

(W F )b = Wcs + 0.0408. ρmi .d2 − ρmo .d2
i o (8.28)

T = 0.0408.T V D. ρmi .d2 − ρmo .d2 . cos θ.Wcs .S
i o (8.29)

CHAPTER 8 Page 185


F
CS = (8.30)
0.0175.T.DLS + (W F )b . sin θ

CS
F = 2.T. sin DLS. + (W F )b .CS. sin θ (8.31)
2

where:

F [lbf] ... force on each centralizer
CS [ft] ... spacing of centralizer
Wcs [lb/ft] ... nominal weight of casing
θ [◦ ] ... average inclination angle near the centralizer
T [lbf] ... tension in the casing at centralizer
TV D [ft] ... true vertical depth to the casing shoe
ρmi [ppg] ... mud weight inside the casing
ρmo [ppg] ... mud weight outside the casing
S [ft] ... distance of the centralizer from the casing shoe.
DLS [◦ /100 ft] ... dogleg severity
di [in] ... inside diameter of the casing
do [in] ... outside diameter of the casing
S [ft] ... distance of casing shoe to particular centralizer

To control vertical travel of the centralizers, casing couplings or various types of attached stops
are applied.

8.9 Stretch in Casing
The elongation or stretch of tubular material resulting from pulling forces and its own weight is
part of the design calculation. As it can easily be understood, the amount of stretch depends on
the amount of pull, the length of the tubular, the elasticity of the material and its cross-sectional
area. Following equations can be applied to calculate the tubular elongation:
Tubular freely suspended in ﬂuid:

W2 + W3 W3
∆Lt = ∆L1 + ∆L2 + ∆L3 + F1 . + F2 . +
W1 W2
W1 W1 + W2
C1 . [Ls1 .Ls2 + (Ls1 + Ls2 ) .Ls3 ] − C2 L2 .
s2 + L2 .
s3 (8.32)
W2 W3

The tension stresses along the casing string after setting and cementing are given by:

CHAPTER 8 Page 186


ρm
Wt = 1− . (w1 .L1 + w2 .L2 + ... + wn .Ln ) (8.33)
ρs

L1 L 2 Ln
Lo = 1.36.10−6 .Wt + + ... + (8.34)
w1 w2 wn

Ls = 4.0.10−7 .σt .L (8.35)

where:

∆Lt [in] ... total axial stretch or contraction
∆L1 [in] ... stretch corresponding to length Ls1
F1 [in] ... free stretch factor corresponding to length Ls1
Wn [lbs] ... weight of the nth string
wn [lb/ft] ... weight of nth section above top of cement
Ln [ft] ... length of nth section above top of cement
Wt [lbs] ... total load below top of cement
Ls [in] ... stretch corresponding to tension σt
σt [psi] ... tension stress desired to be left at top of cement
Lo [in] ... distance required to lower top of casing for
zero stress at top of cement
Ld [in] ... distance to lower top of casing for a desired stress
at the top of cement

The factors ∆Ln and Fn are obtained from ﬁgure x where:

C1 = 1.20177.10−7 for salt water
C1 = 1.50869.10−7 for common mud
C1 =0 for air.
C2 = 2.00294.10−7 for salt water
C2 = 2.51448.10−7 for common mud
C2 =0 for air.

L = L1 + L2 + ... + Ln (8.36)

L d = Lo − L s (8.37)

Single-weight string suspended in mud:

CHAPTER 8 Page 187


Lo = 1.1085.10−5 . (D − L ) (8.38)

where:

D [ft] ... total depth of the well or length of the string
L [ft] ... length of casing below top of cement.

CHAPTER 8 Page 188


8.10 Examples
1. A 20 [in] conductor pipe is set in a 26 [in] hole at 400 [ft]. The mud weights for this well are
8.69 [ppg] to drill the conductor and 8.96 [ppg] for the next section, a 17- 1 [in] hole reaching 6,250
2
[ft]. Design the conductor using 0.85 for collapse safety factor, 1.1 for burst safety factor and 1.8
for the tension safety factor.

2. Continuing from example 1, design the 13- 3 [in] intermediate casing which is run until 6,250
8
[ft]. The next hole section is drilled with a 9.8 [ppg] mud to a depth of 10,000 [ft].

3. Continue from example 1 and 2, the 9- 5 [in] casing, set at 10,000 [ft] is to be designed. Thereto
8
a kick at 13,000 [ft] causes from a formation pressure of 0.57 [psi/ft] is assumed. The mud weight
used to drill until 13,000 [ft] is 11.5 [ppg], the maximum dogleg severity at the hole is 3 [◦ / 100
ft]. Following casings shall be assumed to be available for this well:

Grade: Weight [lb/ft] Collapse [psi] Burst [psi]
C-75 43.5 3,750 5,930
L-80 47.0 4,750 6,870
C-95 53.5 7,330 9,410

4. Re-design the 9- 5 [in] casing applying the released assumptions that a remaining mud is left
8
inside the hole and the kick ﬁlls the well bore to 50 % before shut in.

5. A well is to be drilled to 10,000 [ft] MD (4,200 [ft] TVD). At the gradual dogleg of the section
6,020 [ft] with an inclination of 38◦ and a direction of N3◦ and 6,220 [ft], showing an inclination
of 46◦ and a direction of N7E◦ , a centralizer is to be placed. To maintain a standoﬀ of 1 [in]
while bearing a wall force of 1,100 [lbf], the centralizer spacing is to be designed. ρmo = 12 [ppg],
ρmi = 15 [ppg], Wcs = 53 [lb/ft], do = 9.625 [in], di = 8.535 [in]

CHAPTER 8 Page 189


CHAPTER 8 Page 190


Chapter 9

Directional Drilling and Deviation
Control

A well is declared as a directional one when it follows a predescribed traverse or trajectory to
intersect specific targets. Figure 9.1 through 9.8 illustrates different situations when directional
well trajectories are planned for.

They can be necessary when:

1. Reaching a target which is below inaccessible or restricted areas such as a mountain, a highly
populated area, a national park, etc.,

2. Multiple wells have to be drilled from one offshore platform to deplete large portions of a
reservoir from one structure,

3. Side tracking has to be done around a fish,

4. Fault drilling is necessary,

5. Salt dome drilling takes place,

6. Drilling a relief well to intersect a blowout well,

7. Sidetracking from an old well to explore different horizons and/or directions.

CHAPTER 9 Page 191


Figure 9.1: Directional wells

Figure 9.2: Directional wells con.

CHAPTER 9 Page 192




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CHAPTER 9 Page 195



While drilling, many factors influence the trajectory of the bore hole. Some of them are easy to
control, others may be difficult to estimate. Amount the difficult ones to predict is the so called
“bit walk” that may occur in certain formations and does not follow a general trend.
To plan a well’s trajectory, to follow up the drilled one as well as to correlate its deviation from the
plan, the trajectory is generally displayed in a horizontal view and a vertical view. The horizontal
view projects the trajectory to a plain that has the N-S and E-W directions as their axis and the
rotary table at its center. The vertical or section view shows the trajectory projected to a vertical
cross-section defined by the rotary table and the target.

CHAPTER 9 Page 196


Figure 9.9: Deﬁnitions of trajectory

CHAPTER 9 Page 197


In the following, various trajectory types, bottom hole assembly (BHA) designs to realize them
and some important concepts like dogleg severity are discussed.

9.1 Mayor Types of Wellbore Trajectories
The first step of planning a directional well is to identify where the target (targets) are located in
respect to the rig location. For drilling, the origin of the trajectory is taken from the rotary table.
Thus the location of the target, which is mostly determined by the production department in
UTM or Lat/Long coordinates, has to be re-calculated into “Northing” and “Easting” in respect
to the rotary table. The depth of the target, which can be referenced to ground level, mean sea
level or water table, has to be referenced to the rotary table as well. Note that the rotary table
hight is specific to a particular rig and when an old well has to be re-entered or sidetracks drilled,
the survey of the old well is referenced to the rotary table hight of the rig it was drilled with which
can be different from the one use later on.
When these identifications and corrections are done, the trajectory is planned so that the specified
target is reached from the surface location. The views of the planned trajectory show and contain
values for the location of the rotary table, the kick of point(s), the end of build point(s), the drop
down point(s), the end of drop point(s) as well as the target in TVD (true vertical depth), MD
(measured depth), inclination, azimuth and horizontal departure. Apart from these “significant
points” a survey is created that lists the values mentioned above as a sequence of points that have
a constant MD difference (or are closer when needed, e.g. at turning intervals).
Following basic, 2-D types of trajectories have been established by the industry for practical
realizations:

1. Build-and-hold trajectory,

2. Build-and-hold-and-build (double build) trajectories,

3. Build-and-hold-and-drop (S) trajectories,

4. Build-and-partial drop-and hold (modified S) trajectory.

At type 1 trajectories, the well is kicked of at a specified depth, inclination is build up until a
certain amount (end of build) and kept until the target is reached. This type of profile is often
applied when a large horizontal displacement is required at relatively shallow target depths. Since
there are no major changes in inclination or azimuth after the build-up section is completed, there
are fewer directional problems with this profile, such as dog-leg, key seats, etc..
At type 2 trajectories, the well is kicked of at a specified depth and inclination is build up until a
certain amount (end of build). Then this inclination is hold until a second kick of point is reached,
inclination is built up again to a certain amount (end of build) and kept until the target is reached.
This type of trajectory is preferred for relative large horizontal displacements which are achieved
at the first holding section. This holding section is commonly designed with an inclination angle of

CHAPTER 9 Page 198


Figure 9.10: Different types of basic (2D) trajectories

between 30 to 40◦ since within these values, close control over the trajectory-progress is convenient.
After the second building interval horizontal or nearly horizontal wells are often planned for.
certain amount (end of build) and kept until the drop down point is reached. From the drop
down point until the end of drop point the inclination is reduced to zero degrees and the well
is continued until the target is hit vertically. Here an extra torque and drag are expected due
to the additional bend. This type of profile is used when the target is deep but the horizontal
displacement is relatively small. It also has applications when completing a well that intersects
multiple producing zones, or in drilling relief-well where it is necessary to run parallel with the
blowing well.
certain amount (end of build) and kept until the drop down point. From the drop down point
until the end of drop point the inclination is reduced but differently to type 3 trajectories, not to
zero degrees. Then the inclination is kept until the target is intercepted. The applications and
characteristics of this well type are similar to the ones of type 3.
Along with these basic trajectory types, so called catenary trajectories (designed to minimize
torque and drag) and general 3D trajectories that turn in space are common practice today.
For the trajectory planning itself, following rule of thumbs should be kept in mind:

1. The build-and-hold type is the least expensive one of all trajectory types and easiest to drill.

CHAPTER 9 Page 199


2. For a given TVD and horizontal departure of a target, the higher the kick of point, the
smaller the slant angles, less build up and reduced total MD is necessary to reach the target.

3. If reasonable, designing the slant angle between 30◦ and 40◦ is good practice.

4. Slant angles smaller than 15◦ are to be avoided since they are difficult to control.

5. A deep kick-off point has certain disadvantages : (1) formation will probably be harder and
less responsive to deflection, (2) more tripping time is needed to change out BHAs during
side tracking, (3) build-up rate is more difficult to control.

Figure 9.11: Classification of build up section according to the applied build up rate

Before different trajectory types and survey calculation methods are discussed, various often used
terms need to be defined. Below definitions assume the RKB position to be at the center of the
chosen coordination system.

Northing: Horizontal distance between one survey point and the RKB,
measured to the North. A distance to the South is generally
denoted as being negative.

Easting: Horizontal distance between one survey point and the RKB,
measured to the East. A distance to the West is generally
denoted as being negative.

True Vertical Depth: Vertical distance of one survey point to the RKB.

CHAPTER 9 Page 200


Horizontal Departure: Horizontal distance between one survey point and the RKB,
at the level of the survey point.

Azimuth: Horizontal angle (0 - 2.π), measured clockwise from the
true North to the tangent of the trajectory at this survey point.

Inclination: Angle between the vertical component of the tangent of the
trajectory at the survey point and the vertical axis.
Thus a vertical well as an inclination of 0, a horizontal
well an inclination of π .
2

Measured Depth: Actual length of the trajectory, starting at the RKB up to the
survey point.

Vertical Section: Horizontal departure of the survey point projected to the vertical
view. In this way the vertical section is always smaller or equal
to the horizontal departure.

Figure 9.12: Sketch of uncertainty ellipses along a directional well

CHAPTER 9 Page 201


9.2 Trajectory Calculation
In the following, calculations for the radius of curvature (r1 ), the maximum inclination angle (θ),
the measured depth and horizontal departure for the buildup intervals as well as the measured
depth and horizontal departure for the holding intervals are presented for diﬀerent basic trajectory
types.
Build-and-Hold Trajectory
This type of trajectory is most common in the industry whenever applicable. Figure 9.10 shows
this type of trajectory where X3 < r1 . TVD and the horizontal departure of the target are denoted
with D3 and X3 respectively, TVD of the kick of point is given by D1 . All other parameters are
calculated by the following equations:
Radius of curvature:

180 1
r1 = . (9.1)
π q

where:

q [◦ /ft] ... build up rate or inclination angle buildup
r1 [ft] ... radius of curvature

Maximum inclination angle (θ in [◦ ]):

 
r1 r1 − X3
θ = sin−1   − tan−1 (9.2)
2 2 D3 − D1
(r1 − X3 ) + (D3 − D1 )

Measured depth and horizontal departure along the buildup are computed with:

θi
(DMi )Build = D1 + (9.3)
q

(Xi )Build = r1 (1 − cos θi ) (9.4)

where, θi = θ at the end of build

Di
θi = sin−1 (9.5)
D1 + r1

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Along the holding interval, the measured depth and horizontal departure are:

θ Di − D1 − r1 . sin θ
(DMi )Hold = D1 + + (9.6)
q cos θ

(Xi )Hold = r1 . (1 − cos θ) + (Di − D1 − r1 . sin θ) tan θ (9.7)

where:

Di [ft] ... vertical depth at point i along the buildup or holding interval

Build-Hold-and-Drop (S) Trajectory
The maximum inclination angles can be calculated by following equations:
for r1 + r2 > X4 :

D4 − D1 r1 + r 2 D4 − D1
θ = tan−1 . − cos−1 . sin tan−1 . (9.8)
r1 + r2 − X4 D4 − D1 r1 + r2 − X4

and for r1 + r2 < X4 :

D4 − D1 r1 + r 2 D4 − D1
θ = 180 − tan−1 − cos−1 . sin tan−1 . (9.9)
X4 − (r1 + r2 ) D4 − D1 X4 − (r1 + r2 )

When replacing X4 by X5 + r2 .(1 − cos θ ) and D4 by D5 + r2 . sin θ , the equations above can be
used to calculate the modiﬁed S type trajectory.

9.3 Calculating the Survey of a Well

When drilling a well, inclination, azimuth and MD are measured at various so called “survey
stations”. This is done with survey tools to check the actual traverse of the well. These mea-
surements are then used for (a) estimation of the real trajectory path, (b) comparison with the
planned well trajectory and (c) planning necessary steps to re-direct the well to reach the desired
location.

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Figure 9.13: Sketch of a Single shot and Multishot tool
CHAPTER 9 Page 204


Figure 9.14: Sketch of a gyroscope

The tools to measure the inclination and azimuth at the survey stations can be as simple as
dropping tools (totco, measures only inclination, thus only used for vertical wells) like single (one
measurement per tool run) or multishot magnetic instruments and gyroscopes, or sophisticated
measurement while drilling tools that are assembled within the drillstring (close to the bit) and
nearly continuously measure the desired directional parameters or logging while drilling tools
that also make measurements of the formations penetrated for online trajectory re-designing (e.g.
following a geological horizon).

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The direction angles obtained by magnetic tools must be corrected for true north and the gyroscope
corrected for drift since the magnetic north does not coincides with the true north. Figure 9.15
shows a map of these correction angles for various locations. With these corrected azimuth and
inclination values, a so called full survey (containing TVD, horizontal departure, etc.) is calculated.

Figure 9.15: Declination map

To obtain the full survey from MD, inclination and azimuth, various methods that depend on
diﬀerent models are proposed in the literature. Below is a list of the most popular ones:

1. Acceleration method
2. Average angle method
3. Angle-averaging method
4. Backward station method
5. Balanced tangential method
6. Circular arc method
7. Compensated acceleration method
8. Mercury method
9. Minimum curvature method
10. Quadratic method
11. Radius of curvature method
12. Secant method
13. Tangential method
14. Terminal angle method
15. Trapezoidal method
16. Vector averaging method

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From the diﬀerent methods listed above, the minimum curvature and the radius of curvature
methods are considered to be the most accurate ones. The tangential method is the simplest one
to use but gives inaccurate results.

9.3.1 Average angle method

αi + αi−1 i − i−1
Li = DMi . sin . cos (9.10)
2 2

αi + αi−1 i − i−1
Mi = DMi . sin . sin (9.11)
2 2

αi + αi−1
Di = DMi . cos (9.12)
2

where:

α [◦ ] ... hole angle
[radian] ... azimuth
DMi [ft] ... measured depth between two survey stations
Li [ft] ... north/south coordinate between the two stations
Mi [ft] ... east/west coordinate between the two stations

The total north/south and east/west coordinates and the TVD value are computed with:

n
Ln = Li (9.13)
i=1

n
Mn = Mi (9.14)
i=1

n
Dn = Di (9.15)
i=1

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9.3.2 Radius of curvature method
DM i
Mi = . [sin αi−1 .sin i−1 + sin αi − sin i ] .Fi (9.16)
2

DMi
Li = . [sin αi−1 .sin i−1 + sin αi − cos i ] .Fi (9.17)
2

DMi
Di = . [cos αi−1 . cos αi ] .Fi (9.18)
2

where:

2 βi
Fi = [radians] tan [degrees] (9.19)
βi 2

β = cos−1 {cos [(α2 − α1 ) − {sin α1 . sin α2 . [1 − cos ( 2 − 1 )]}]} (9.20)

β [radian] ... curvature or the dogleg
F [1] ... ratio factor used to smooth the wellbore between
the two survey stations
α1 [◦ ] ... inclination at station 1
α2 [◦ ] ... inclination at station 2
1 [◦ ] ... azimuth at station 1
2 [◦ ] ... azimuth at station 2

When β < 0.25 [radians], F can be set to 1.0

9.3.3 Minimum Curvature Method
DMi
Li = .[sin 1 . cos α1 + sin α2 . cos 2 ].RF (9.21)
2

DMi
Mi = .[sin α1 . sin 1 + sin α2 . sin 2 ].RF (9.22)
2

DMi
Di = .[sin 1 + cos α2 . cos 2 ].RF (9.23)
2

360 DL
RF = . tan (9.24)
π.DL 2

CHAPTER 9 Page 208


cos(DL) = cos(α2 − α1 ) − sin α1 . sin α2 . (1 − cos( 2 − 1 )) (9.25)

where:

DL [◦ /100 ft] ... dog leg

9.4 Dogleg Severity Calculations
By definition, a dogleg is a sudden change of inclination and/or direction of a well’s trajectory.
For description purpose, the change is usually expressed in a 100-[ft] interval ([◦ / 100 ft]) and
called “dogleg severity”. As it has been seen in practice, large dogleg severities can lead to failure
of drillpipe, drill collar or tool joints as well as create so called “keyseats” which result in stuck
drillstrings.
To obtain the dogleg severity, the survey calculated with one of the methods described above is
used along with following equations:

∆α ∆ α + αN
β = 2. sin−1 . sin2 + sin2 . sin2 (9.26)
2 2 2

or:

β ≈ cos−1 (cos ∆ . sin αN . sin α + cos α. cos αN ) (9.27)

β
δ= .100 (9.28)
Lc

where:

δ [◦ /100 ft] ... dogleg severity
β [◦ ] ... total angle of change (turn)
αN [◦ ] ... new inclination
∆ [◦ ] ... change in azimuth
∆α [◦ ] ... change in inclination
Lc [ft] ... length over which change of trajectory occurs

Note: To reduce the wear-effect of large dogleg severities, the add of multiple steel or rubber
drillpipe protectors which are cylindrical pieces, having an outside diameter equal to the outside
diameter of the tool joints, have proven to be efficient.

CHAPTER 9 Page 209


9.5 Deflection Tools and Techniques
The methods presented above calculate the trajectory path of the well as it is drilled. The actual
trajectory is constantly compared with the planned one and in case the actual one is going of course
(which it always does to some extend), correction steps to bring the trajectory on course again have
to be taken. To correct the course of the well in case of minor deflections, an experienced driller can
vary the individual drilling parameters (WOB, RPM, etc.) to adjust for the of-going trajectory.
In case the trajectory is largely of course, a deflection tool has to be run and drilling in sliding
mode (e.g. positive displacement motor (PDM)) carried out to make the necessary correction. To
determine the direction the well is drilled in sliding mode, the bottom hole assembly containing
the deflection tool is rotated from the surface by rotating the whole drill string. Then, either a so
called “Ragland vector diagram” or the following equations are applied to compute the tool face
orientation. The computational results have shown to be more accurate than the graphical one
gained from the Ragland vector diagram. The tool face angle is given by:

cos α. cos β − cos βN sin αN . sin ∆
γ = cos−1 = sin−1 (9.29)
sin α. sin β sin β

The new inclination and direction angles are:

αN = cos−1 (cos α. cos β − sin α. sin β. cos γ) (9.30)

tan β. tan γ
∆ = tan−1 (9.31)
sin α + tan β. cos α. cos γ

where for γ is right of high side of the borehole:

N = +∆ (9.32)

and for γ is left of high side of the borehole:

N = −∆ (9.33)

where:

N [◦ ] ... new direction of the trajectory
αN [◦ ] ... new inclination of the trajectory

Although rotary assemblies can be designed to alter the path of the wellbore, there are certain
circumstances where it is necessary to use special deflection tools, for example kicking-off and

CHAPTER 9 Page 210


sidetracking. These special tools include jetting bits, whipstocks, and downhole motors with a
deflection device which will be discussed in the following section.
In drilling operations, the bit is forced under weight and rotation to cut a certain diameter hole.
As the bit penetrates along the vertical axis, it also moves laterally. This movement can range
from very small to considerable displacement. This displacement can be represented in three
dimensions.
Directional drilling is to cause the bit to deviate in a controlled manner. The various methods
used to induce the bit to build, drop and turn can be classed into mechanical and hydraulic
methods besides the natural formation effects. Mechanical techniques include whipstocks, bottom
hole assemblies, and down hole motors with bending device.

Figure 9.16: Different methods to deflect the trajectory of a borehole

9.5.1 Natural Formation Effects

The formations encountered when drilling oil wells are very rarely homogeneous and isotropic.
One is more likely to find a sequence of different layers, with each layer having its own drillability
characteristics. The bit may have to drill through alternating layers of hard and soft rocks.
Furthermore, these strata may not be lying evenly in horizontal beds but instead be dipping at
some angle. The geology may be further complicated by faulting and folding of the strata.

CHAPTER 9 Page 211


As the bit drills across a formation boundary, it will tend to be deflected from its original course.
Experience has shown that where the formations are steeply dipping (greater than about 60◦ ) the
bit tends to drill parallel with the bedding planes. Where the formation dip is less steep, the bit
tends to drill at right angles to the bedding planes. In addition to changes in inclination there
may also be changes in direction in which case the bit will tend to walk. Under normal rotary
drilling, the bit will tend to walk to the right, but with a downhole motor the effect of reactive
torque may force it to the left. Drilling parameters such as: weight on bit, RPM, and hydraulics,
will also affect the amount of deviation.

9.5.2 Hydraulic Method (Jetting)

This method of changing the trajectory of a wellbore requires the use of a jetting bit to wash
away the formation. Water or drilling mud is pumped through a large jet that is oriented in the
direction of the desired trajectory change.
Jetting is a technique best suited to soft-medium formation in which the compressive strength
is relatively low and hydraulic power can be used to wash away a pocket of the formation to
initiate deflection. The amount of inclination produced is also related to the type of bottom hole
assembly used with the jetting bits. There are two commercial bits especially designed for the
jetting technique. One is a two-cone bit with an extended jet replacing the third cone and the
second one is a conventional three cone bit with two small and one large “big eye” jet. The actual
design of the jetting process is a function of hole size, pump capacity, expected formation hardness,
and the desired bit cleaning efficiency while drilling.
Compared to trajectory deflection using a whipstock or downhole motors, jetting is the most
approximate method. On any particular run, the bit is mounted on an assembly, which includes
an orienting sub and a full-gauge stabilizer near the bit. Once the bit touches the bottom, the large
nozzle is oriented in the required direction. Maximum circulation rate is used to begin washing
without rotating the drill string. The pipe is worked up and down with continuous jetting, until
a pocket is washed away. At this stage the drill string can be rotated to ream out the pocket
and continue building angle as more weight is applied to the bit. Surveys are taken frequently to
ensure that the inclination and direction are correct.
Advantages of this method are: (1) several attempts can be made to initiate deflection without
pulling out of the hole, (2) a full gauge hole can be drilled from the beginning.
Disadvantages of this method are: (1) the technique is limited to soft-medium formations,
(2) severe dog-legs can occur if the jetting is not carefully controlled, (3) on smaller rigs there may
not be enough pump capacity to wash away the formation.
In summary, jetting is a very cost-efficient giving that kicking-off takes place under suitable geo-
logical conditions. In general it requires a good directional monitoring.

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9.5.3 Mechanical Methods

All mechanical methods rely on the application of an appropriate side force which causes the bit
to deviate. When the imposed side force on the bit is positive, an angle is build up, when it is
negative, the force drops the angle. Common mechanical techniques used to deflect the bit are:
whipstocks , downhole motors with bending device, and bottom hole assembly.

Whipstocks

The whipstock method to devi-
ate a bit is the oldest technique
and, if properly used, the most
reliable one. In comparison
with other alternative methods,
it is the most time consuming
one.
A whipstock can be as simple
as a kick-off sub at the end of a
conductor pipe or casing, or it
can be a more sophisticated re-
trievable jetting whipstock. Al-
though there are a number of
variations all whipstocks work
on the principle of creating a
curvature.
The successful use of a whip-
stock is largely a matter of
knowing when to run a whip-
stock in relation to other me-
chanical or hydraulic devices.
In today’s industry, the whip-
stock is predominately used
for sidetracking out the casing
pipe, which is called “casing
whipstock”. A whipstock can
also be used to side-track out
the open hole when hydraulic
jetting or running a mud mo-
tor fails to deviate the well.
When whipstock is used in an
open hole it is called “open hole
whipstock”. Figure 9.17: Deflection with a Whipstock

CHAPTER 9 Page 213


A whipstock can be described as a steel wedge with a chisel shaped point at the bottom. This
chisel shape prevents the whipstock from turning when drilling begins. The whipstock, that is
run down hole, is attached to the lower end of the drill string by means of a shear pin. It is either
set on the bottom or anchored and locked in a packer which was previously installed in a casing
string.
A modern whipstock has a tapered concave groove, called the tool face, which helps in orienting
the whipstock. Once it is installed down hole, it guides the bit or the mill against the casing or
the open hole wall to drill in the desired direction.

Open Hole Whipstock Running Procedures

The procedures for running the whipstock can be summarized as follows:

1. A whipstock is to be selected according to the wedge needed to effect the desired deflection.

2. A bit that is small enough to fit in the hole with the chosen whipstock is selected.

3. The whipstock is attached to the bottom of the drillstring by means of a shear pin.

4. Having run into the hole, the drillstring is rotated according to the survey information, until
the tool-face of the whipstock is oriented in the desired direction.

5. By applying enough weight, the chisel point is set firmly into the formation or cement plug
to prevent the whipstock from rotating.

6. Additional weight is applied to shear the pin that holds the drill collar to the wedge. Rotation
can then begin.

7. A small diameter pilot hole is drilled to a depth of about 15 [ft] below the toe of the whipstock
at which point the whipstock-stop reaches the top collar of the whipstock.

8. The pilot hole is then surveyed to make sure that it has been drilled in the right direction.

9. After the pilot hole has been surveyed, the bit and the whipstock are tripped out.

10. A hole opener is then run to ream out the pilot hole to the full size hole.

Casing Whipstock Running Procedures

The running steps for a casing whipstock can be summarized as:

1. The casing whipstock packer with anchor device is run to the kick-off point.

2. The alignment key is oriented using a gyro survey, so that the whipstock will land in a
unique position, where the side track is needed.

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3. The casing packer is set to provide a base for the whipstock.

4. The whipstock is attached to a starting mill by means of a shear pin and run in hole.

5. The whipstock is landed in the pre-oriented packer by means of a lock-sub (mule-shoe
stinger), and thereby oriented in the desired direction.

6. Weight is applied to break the shear pin thereby freeing the starting mill off the whipstock.
The string is then rotated to mill the casing to create the window.

7. Once the window has been cut, the mill is replaced by a smaller sidetracking bit which is
forced by the whipstock through the window outside the casing. A pilot hole can then be
drilled.

8. After drilling the pilot hole, the bottom hole assembly is pulled out and replaced by an
assembly of string and watermelon mills to make the window large enough to accommodate
a conventional bottom hole assembly.

The whipstock’s biggest advantage is that it provides a controlled hole curvature at the onset,
while distributing the side force over the length of the whipstock body. Whipstocks can also be
run at any depth in any kind of rock although they are best suited for use in very hard rock where
jetting and mud motor deflecting techniques are generally ineffective.
The main disadvantage of the whipstock is the necessity to drill the pilot hole and then trip out
to change the smaller bit to one of the wellbore diameter.

Downhole Motor With Bending Device

The most common deflection technique currently in use involves running a downhole motor which
drives the bit without rotating the drill string. Two different types of downhole motors have been
developed, the positive displacement mud motor and the mud turbine. To create a change in the
trajectory, downhole motors require a deflection device. The deflection is provided either by a
special sub placed above the motor, called a bent sub, or by introducing a deflection at the bottom
section or below the motor. The latter is known as steerable bottom hole assembly.

Bent Sub

A bent sub is about two feet long having the axis of the lower pin connection machined slightly
off vertical. The amount of this so called “offset angle” varies between 0.5 and 3.0◦ . The direction
in which the tool is deflected, called “tool face”, is marked by a reference line on the outer surface
of the sub. The bent sub itself is connected to a motor below it and to an orienting sub above it.
Once the assembly is run to the bottom of the hole, the bent sub is oriented using the orienting
sub and a survey tool. After orientation, mud circulation is started which initiates the operation
of the mud motor and drives the bit without rotating the drill string. The amount of deflection

CHAPTER 9 Page 215


produced is mainly a function of the offset, the length and stiffness of the motor, and the hardness
of the formation.
Typically, this type of assembly is engaged in drilling until the hole inclination reaches about 20◦ .
At this point the motor and the bent sub are pulled out of the hole, and the building rotary
assembly is engaged to complete the building section of the hole.

Steerable Bottom Hole Assembly

The increased application of downhole motors and turbines as deflection tools has led to the
concept of having an adjustable component with the bottom hole assembly that is capable of
altering the well path without having to pull out of the hole in order to change the bottom hole
assembly. Such a steerable drilling system is comprised of a bit, a steerable motor, MWD tools
and stabilizing unit(s).
The three categories of commercially available steerable systems are: (1) adjustable bent sub
above the motor, (2) motor housing with one or two bends, and (3) offset stabilizer on motor.
1. Adjustable bent sub above motor: The conventional bent subs with fixed angle have the
disadvantage that they cannot be run in the hole in a straight position coaxial to the string axis
and therefore, cannot be used in rotary drilling. Thus, the advantage of a down hole adjustable
deflection device is that it can be run in the hole coaxially and the required amount of deflection
can be controlled from the surface. This makes directional drilling more efficient and less time
consuming.
The multi-angle bent-sub associated with a downhole motor allows for drilling of the complete
build up zone and of the constant angle zone with the same bottom hole assembly. Here the bent
sub angle is controlled from the surface.
The adjustable bent sub consists of an upper and a lower sub that are connected by an offset
conical swiveling joint. The axis of the conical joint is tilted with respect to the main axis of the
tool. The lower sub is constructed so that it is able to rotate at an angle that is slightly offset
from the vertical axis. Initially the tool is made up so that the upper and the lower subs are
aligned. When the lower sub is rotated it becomes locked in such a position that the two subs
are offset by a small amount, thereby forming a bend in the BHA. Further rotation increases the
size of the bend. The size of the bend reaches maximum when half revolution is made after five
actuations. Further rotation decreases the angle gradually back to the straight position after five
more actuations to make a complete revolution.
The lower sub has ten possible positions to adopt and it actuates from one position to the next by
a hydraulic device. The actuator creates a temporary surge of pressure that is transmitted to a
shaft that turns the lower sub. At the end of the pressure surge, the lower sub is locked into that
position until the next surge. The drill string must be lifted off bottom while changing the angle
of the bent sub. Flow rate is adjusted to provide the necessary increase in pressure to actuate the
tool. Once in position, the mud pump is shut down and the lower sub is locked into this position.
It is therefore, possible to operate the tool remotely from the rig floor.

CHAPTER 9 Page 216


2. Motor housing with one or two bends: when the deflecting device is placed on the top
of a downhole motor, it introduces the deflection at a distance far enough from the bit to create
a considerable bit offset. The amount of bit offset introduced by the bent subs prohibits rotating
of the drill-string. Under this circumstance drilling proceeds in sliding or orienting mode only.
Building a bent house at the lower end of a positive displacement motor itself introduces a deflec-
tion which is much closer to the bit and therefore, more effective than what is possible with the
bent sub on the top of the motor. This means that a bent housing will provide a larger turn than
a bent sub of similar size and deflection.
The bent housing motor assembly can be used in steering mode as well as in rotary mode because
the initial bit side loading created by the small bit offset rotates with the drilling string thereby
negating its deviating effect.
The bit offset in the bent house assembly can be reduced further without affecting the bit tilt angle
by introducing a second tilt in the opposite direction to the first one. Here the body of the motor
is brought back into a position aligning with the borehole axis. When the rotary table is engaged
while the downhole motor is in the hole, bit offset is negated and the assembly drills straight
ahead to maintain inclination and direction. Such a deflecting unit is known as double-tilted
universal joint housing (DTU). The DTU joint housing develops a minimum bit offset to give the
navigation drilling system a full steering capability. A bit angle of 0.25 to 0.78◦ is adequate to
provide directional control using the DTU.
The rotation of the bending motor housing for straight hole drilling causes a slightly over gauged
hole and that creates a “step” when the drilling switches from rotary to orient mode or vice versa.
Therefore, the smaller the bit offset, the less the bit will cut with its side, and the smaller the
size of the step. Cutting with the bit face extends bit life and optimizes the rate of penetration.
Similarly, by keeping the motor concentric to the hole, rotary drilling proceeds smoothly without
excessive rotational bending to the assembly.
A limitation with all steerable systems is that the stabilizers hang on to the hole wall at a step,
and hence reduce the weight on bit. Although this step can happen with a conventional rotary
assembly, it is more common with steerable systems because the diameter of the hole drilled in
rotary mode is slightly larger than the part drilled in orienting mood. The magnitude of this step
depends on the formation hardness, stability and the build rate of the system. To minimize the
step problem, the near bit stabilizer should be under-gauged and should have shallow nose heel
angles. The step size can be further reduced by minimizing the build rate of the system.
3. Offset Stabilizer on Motor: The positive displacement motor can use either a bent sub
above the motor or have the housing (bend housing) below it. Mud turbines are restricted to the
use of the bent sub where the design of the turbine prohibits manufacture of a bent housing.
The deflection below the turbine is provided by a special stabilizer with an under-gauge blade,
known as offset stabilizer, and is located on the turbine near the bit. The under-gauge blade is
considered to be the tool face. It is oriented in the same way as the bent sub and the bent house.
When the drill-string is not rotated, the turbine drives the bit along a predefined course which is
given by the under-gauge blade orientation.

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The greater the stabilizer offset (higher under-gauge blade), the greater the rate of build, but the
amount of offset is limited.
Once the wellbore is brought back onto the planned trajectory, the drillstring can be rotated.
Rotating the offset stabilizer results in a slightly over-gauge hole.

9.6 While Drilling Techniques

With “while drilling techniques”, the direction of the wellbore, condition of the drillstring as well
as the formations that have been penetrated can be measured and the measurements transferred
to the rig-site while drilling. While drilling sensors are typically mounted at the BHA as close
as possible to the bit. Depending on the drillstring configuration, the distance between the bit
and the measuring devices can be as little as 10 [ft]. In this way, the measurements taken are
somewhat behind the bit and depending on the penetration rate, are recorded with some lag-time.
While drilling systems generally consist of (a) a power system, (b) measuring sensors and (c) a
telemetry system for data transfer. The power system can be either based on a battery, a turbine
or a combination of them. Batteries have the advantage that no circulation is needed to carry out
measurements, thus while tripping, control logs can be run.

9.6.1 Measurement While Drilling

The term “measurement while drilling” (MWD) refers to the while drilling measurement of di-
rectional parameters (MD, inclination, azimuth) as well as certain drilling parameters like WOB,
downhole torque, temperature, etc. The sensor to perform these measurements are three orthogo-
nal fluxgate magnetometers and three accelerometers. The use of gyroscope navigated MWD offers
significant benefits over navigation sensors. They offer greater accuracy and are not susceptible
to inference from magnetic fields.
The drilling parameters measured with MWD tools are aimed to increase the drilling efficiency
(stick-slip), be applied to detect abnormal formation pressures or any kind of hole problems.
Most MWD tools can operate at tool-temperatures up to 150 ◦ C, some sensor work up to 175 ◦ C.
It should be noted that the tool-temperatures are generally about 20 ◦ C less than the formation
temperatures, measured by wireline logs which is caused by the cooling effect of mud circulation.
Downhole pressures create less problems for MWD tools than downhole temperatures. Most MWD
tools are designed to withstand up to 20,000 [psi] which is rarely encountered.
MWD tools are most sensitive to shock and vibrations. Torsional shock, created by stick-slip have
been found to be able to cause tool failure, lateral shocks which can be magnitudes higher than
axial shocks, can be reduced by the use of jars.
Normally sensors measure MWD shock loads constantly and transmit them to the rick. There the
driller can manipulate the drilling parameters to keep them in acceptable limits.

CHAPTER 9 Page 218


9.6.2 Logging While Drilling

The term “logging while drilling” (LWD) refers to the while drilling measurements of wireline
equivalent parameters like resistivity, porosity, density and sonic logs. When these parameters are
known, “geosteering” can be performed where the trajectory of the well is “re-designed” according
to the actual formation’s position and shape.

9.6.3 Data Transfer

Since the amount of data measured by while drilling techniques can be large, mostly not all
measurements are continuously transferred to the rig. Data that are not transferred are commonly
stored and retrieved at the following trip. Several different systems have been developed to transfer
the measured data to the surface, the “mud pulse telemetry” is the by far most often applied on.
Three different mud pulse systems are commercially available today:

1. Positive pulse system: creates a momentary flow restriction (higher pressure than the drilling
mud volume) in the drillpipe.

2. Negative pulse system: creates a pressure pulse lower than that of the mud volume by
venting a small amount of high pressure drillstring mud from the drillpipe of the annulus.

3. Continuous wave system: creates a carrier frequency that is transmitted through the mud
and encoded data using phase shifts of the carrier.

From the systems listed above, the positive pulse telemetry is the most often applied one since it
is easiest to achieve even for extended reach wells.
When the signals reach the surface, they are retrieved by transducers that are located on the
standpipe and send to computers at the site for further evaluation.
The data transmitted are overlayed with noise where the mud pumps are the main source. Other
parameters that influence the “signal to noise range” are: what mud type and bit type are in use,
the length of the well and the drilling parameters applied itself.

CHAPTER 9 Page 219


9.7 Examples
1. Calculate a build-and-hold trajectory to reach a target at 10,000 [ft] TVD and 2,600 [ft]
horizontal departure. The kick oﬀ point shall be set to 1,500 [ft] and a build rate of 2 [◦ / 100
ft] applied. Compute the: radius of curvature, maximum inclination angle, measured depth and
horizontal departure at the end of build as well as the measured depth and horizontal departure
at 8,000 [ft].

2. When the inclination has changed from 5◦ to 7◦ together with a change of direction from N90E
to S82E over an interval of 75 [ft], what is the dogleg severity?

3. After going of course the trajectory has to be changed in inclination from 4◦ to 6◦ as well as
in direction from 15◦ to 35◦ over the next 70 [ft], what is the tool-face setting and the expected
dogleg severity?

CHAPTER 9 Page 220


Chapter 10

Borehole Problems

It has been observed that the drilling mud is the
source of most encountered hole problems and
drilling hazards. Therefore proper control of the
drilling fluid properties is essential to achieve the
drilling objective without running into problems
like:

1. Blowouts,

2. Lost circulation,

3. Stuck pipe (differential, keyseats, etc.),

4. Heaving shale,

5. Hole enlargements.

Some of the problems mentioned above are dis- Figure 10.1: Sketch of borehole when drilling
cussed in the following, kick detection, removal and through soft and hard formations
blowout control is presented in the proceeding chap-
ter.

10.1 Differential Pipe Sticking
In general the drillpipe gets stuck in the hole due to various reasons. Some of them are:

1. Keyseating,

2. Pressure differential between formation and borehole,

CHAPTER 10 Page 221


3. Bit and drill collar balling,

4. Foreign objects or junk in the borehole,

5. Sloughing formations (heaving shales),

6. Improper solids removal leaving cuttings above the bit or drill collar.

A drillstring is called differential stuck when it is motionless and forced against a permeable for-
mation (mud cake) due to excessive differential pressure (overbalance). In this situation, sketched
in figure 10.2, a section of the drillstring is pressed into the mud cake and literally glued to the
borehole wall.

Figure 10.2: Differentially Stuck Drillstring

Danger of becoming differentially stuck is high when the drillstring is static in the hole for an
extended time and thick mud cakes are present. It should be noted that the force that “glues”
the drillstring on to the borehole wall and is given by equation 10.1, increases with time.

CHAPTER 10 Page 222


Fst = 12.hf .tmc . (ph − pf ) .f (10.1)

When the borehole is in-gauge, the term A = hf .tmc is expressed by:

2 2
d2 d2 d2 − tmc
A = 2.hf . − tmc − − tmc . (10.2)
2 2 d2 − d1

for

d1 d2 − tmc
tmc ≤ ≤ (10.3)
2 2
where:

Fst [lbf] ... force necessary to free pipe
hf [ft] ... formation thickness
tcm [in] ... thickness of mud cake
ph [psi] ... hydrostatic pressure in the borehole
pf [psi] ... formation pressure
f [1] ... friction factor, function of time,
d1 [in] ... outer diameter of the drillstring where it is stuck
d2 [in] ... borehole diameter where pipe is stuck
12 [in/ft] ... conversion factor [in] -> [ft]

The friction factor f depends on the composition of the mud cake, variation of the contact between
drillstring and mud cake and the time since the drillstring got stuck. The value of the friction
factor ranges from 0.2 to 0.6.
To minimize the danger of getting differentially stuck, following precautions should be applied:

1. Minimize the differential pressure (overbalance) between borehole pressure and formation
pressure,

2. Maintain efficient control of the mud properties,

3. Minimize the contact area between drillstring and borehole,

4. Minimize the non-rotating time of the drillstring,

5. Minimize the friction factor.

The contact area between the drillstring and the borehole can be minimized by:

CHAPTER 10 Page 223


1. Using stabilizers on the drill collars,

2. Using grooved or noncircular drill collars,

3. Using drill collars with external upset,

4. Minimize ﬁlter cake thickness through proper design of the drilling mud.

The friction factor can be minimized by using low water-loss muds, oil-base muds and walnut
hulls.

10.2 Free Point Calculation
In order to take actions to free the pipe, the knowledge of the depth where the drillstring is stuck,
also called “free point”, is vital. Two methods are available to verify the free point location:
(a) measurement of the drillstring stretch, measured at the surface when the string is pull with a
certain amount of overpull and, (b) usage of so called “free point indicators”. Free point indicators,
which are either strain gauge probes or subsurface probes, are special gauge tools that measure
the strain in the drillstring.
To compute the free point based on the drillpipe stretch, only measurements taken at the derrick
are required. The procedure is summarized as:

1. Pulling the drillstring with normal hook load and mark a reference point X1 on the pipe.

2. Pull the drillstring with additional 20,000 to 40,000 [lbf], a force F that causes a stretch of
the free portion of the drillstring. At the reference point-level, mark the drill pipe for X2 .
The stretch in [in] is given by X2 − X1 . Note that the applied overpull force must not exceed
the yield strength of the pipe or the joints.

3. Use equation 10.4 to compute the free point location:

735, 294. (X2 − X1 ) .Wdp
Lst = (10.4)
F
where:

Lst [ft] ... length of free portion of the pipe, depth of free point
Wdp [lb/ft] ... nominal weight of drillpipe
F [lbf] ... additional force (overpull)

As it can be seen, equation 10.4 accounts for the stretch of the drillpipe only.

CHAPTER 10 Page 224


10.3 Freeing Differentially Stuck Pipe
When the location of the free point is verified, following methods to free the drillstring are possible
and should be tried in the order they are listed below.

10.3.1 Spotting Organic Fluids

A mixture of diesel and surfactants is pumped to the location where the drillstring is stuck. This
is performed by pumping the mixture through the drillstring and up the annulus to the free point
depth. Since the mixture is meant to reduce the thickness of the mud cake and the friction factor,
sufficient time has to be allowed so that the mixture can be dissolved and the mud cake destroyed.
While spotting, the drillstring is worked continuously to free the drillstring.

10.3.2 Hydrostatic Pressure Reduction

This method aims to create a pressure differential between the inside of the drillpipe and the
annulus by pumping lower density fluid into the drillpipe. Since the hydrostatic pressure from
the fluid inside the drillpipe and from the annulus have to be the same at the bottom of the hole,
the mud level at the annulus as well as the pressure at the free point are reduced. The amount
of low density fluid to be pumped into the drillstring and the resulting maximum drillpipe gauge
pressures are given by:

Lst .Vdp pp Van ρo
Vo = . ρm − . 1+ . 1− (10.5)
ρm − ρo 0.052.Lst Vdp ρm

Vo
(pdp )max = 0.052. . (ρm − ρo ) (10.6)
Vdp

The fluid level drop in the annulus [ft] can be computed with:

pp
∆F L = Lst − (10.7)
0.052.ρm

The equivalent mud weight during this bleed-off procedure is found as:

(pdp )max − pdp
ρ e = ρm − (10.8)
0.052.Lst . 1+ Van
Vdp
. 1− ρo
ρm

where:

Vdp [bbl/ft] ... capacity of drillpipe

CHAPTER 10 Page 225


Van [bbl/ft] ... capacity of annulus
pp [psi] ... pore pressure
pdp [psi] ... pressure within the drillpipe,
measured at the surface
(pdp )max [psi] ... maximum drillpipe pressure
ρo [ppg] ... density of fluid pumped down
Vo [bbl] ... volume of the fluid pumped down
Lst [ft] ... length of the drillstring
D [ft] ... total depth of the well (MD)

It should be noted that precautions have to be taken that formations above the free point do not
kick due to the pressure reduction of the annulus.
As alternative procedure to the method described above, the low density fluid can be pumped
into both, the drillpipe and the annulus. Here the volumes of low density fluid required to reduce
the differential pressure Vo and the volume of mud Vm required to pump behind the low density
fluid are determined by:

pp
− Lst .ρm
Vo = Van . 0.052 (10.9)
ρo − ρm

Vm = Vdp .Lst + Van . (D − Lst ) (10.10)

10.3.3 Backoff Operations

When all attempts to free the stuck drillstring failed, backoff operations are the last alternative.
By backoff operations parting the drillstring above the free point, recovering the free part of the
drillstring and fishing the remaining, stuck part of the string are understood.

Parting of the Drillstring
Nowadays four different methods are applied to part the drillstring:

1. Unscrew the pipe at a selective threaded joint above the stuck point using a prima cord
explosive run on a electric wireline.

2. Chemical cut - An electrical wireline tool and procedure that uses a propellant and a chem-
ical, halogen fluoride, to burn a series of holes in the pipe thereby weakening it so that it
easily pulls apart with a slight pull.

CHAPTER 10 Page 226


3. Jet cut - A cut made by an explosive sharped with a concave face and formed in a circle. It
is also run and fired on an electric line.

4. Mechanical cut - A cut made with a set of knives installed in a tool and run on a small
diameter work string.

After the drillstring is separated, fishing operations can commence. First so called “lead impression
blocks” are run to check how the fish’s surface looks alike. Afterwards special catching tools like
ones listed below are run.

1. Overshot dressed with basket grapple,

2. Overshot dressed with spiral grapple,

3. Taper tap,

4. Box tap, etc.

When the fishing operations are not successful, the well has to be plugged back leaving the fish
in the hole. Subsequent operations are sidetracking or, depending on the well economics and
objectives, abandoning. Note that when “while running tools” are mounted on the drillstring,
they are lost in the hole which can jeopardize the drilling project economics.

10.4 Lost Circulation Control
Out of the problems encountered when drilling a well, lost circulation is the most common one.
By definition, lost circulation is the complete or partial loss of drilling fluid into formation(s).
Typical formations where lost circulation are prone to occur are:

1. Natural or induced fractured formations,

2. Faulted, jointed or fissure formations,

3. Vugular or cavernous formations,

4. Coarsely permeable unconsolidated formations.

Methods to identify and locate zone of lost circulation are:

1. Spinner survey,

2. Temperature survey,

3. Radioactive tracer survey,

CHAPTER 10 Page 227


4. Hot wire survey,

5. Pressure transducer survey.

Lost circulation material is added to the drilling mud to bridge-oﬀ the large openings of the
formations and thus help control it. Table 10.3 list some of the most commonly used lost circulation
additives.

Figure 10.3: Common used additives for lost circulation

CHAPTER 10 Page 228


10.5 Keyseats

Figure 10.4: Diﬀerent keyseat scenarios

CHAPTER 10 Page 229


10.6 Examples
1. In a 9,500 [ft] hole the drillstring is stuck at 8,000 [ft]. What is the volume of oil required
to pump through the drillstring to free the pipe when the pore pressure is estimated to be 4,300
[psi] at the stuck depth. Following further well data are available: ρm = 12 [ppg], ρo = 8 [ppg],
Vdp = 0.0178 [bbl/ft], Van = 0.0544 [bbl/ft].

2. Determine the density, length and type of kick using the following information: Vk = 20 [bbl],
Ldc = 900 [ft], ρm = 9.6 [ppg], d2 = 9.875 [in], d1c = 7.785 [in], dip = 4.2 [in], pc = 720 [psi],
pdp = 520 [psi].

1
3. When drilling a 8- 2 [in] hole, a kick is taken at 9,500 [ft]. After shutting in, the stabilized
drillpipe pressure and the casing shut-in pressure are found to be 300 [psi] and 600 [psi] respectively.
The recorded pit gain is 20 [bbl], pre-kick information contain: dh = 8.5 [in], ddc = 3.0 [in],
ddp = 4.276 [in], Ldc = 600 [ft], Ddc = 8 [in], Ddp = 5 [in], ρm = 11 [ppg], (pp )str=60 = 2, 000 [psi],
(pp )str=30 = 500 [psi]. Applying the wait-and-weight method, compute the:

(a) Bottom hole pressure,
(b) Kill mud weight,
(c) Standpipe pressure at start of circulation of
heavier mud,
(d) Final circulation pressure,
(e) Time required to replace the contents of the drillstring
with the kill mud,
(f) Total time required to replace the contents of the
well with kill mud,
(g) Total number of strokes required assuming that the
pump factor is 0.15 [bbl/stroke],
(h) Maximum casing pressure when the kick reaches the surface,
(i) Expected pit gain as the top of the kick reaches the surface.

CHAPTER 10 Page 230


Chapter 11

Kick Control and Blowout Prevention

A kick is defined as flow of formation fluids or gas into the wellbore, a blowout is the uncontrolled
release of the fluid or gas, gained through the kick. A blowout can take place at the surface or
into another formation (underground blowout). Formation fluids that enter the wellbore can be
crude oil or brine, gas entered can be any kind of naturally occurring gas. During a kick, drilling
mud is displaced by the fluid or gas entering the borehole. To detect a kick, this is one of the
easiest warning signs, others are discussed below. Some causes of kicks may be:

1. Lost circulation, thus reduction of hydrostatic pressure,
2. Abnormally high pressured horizons drilled with to low mud weight,
3. Reduction of hydrostatic pressure while swabbing,
4. Failure to keep the borehole full of drilling fluid while tripping out.

A well control system permits:

1. Detecting a kick,
2. Closing the well at the surface,
3. Circulating the well under pressure to remove the formation fluids and increase the mud
density,
4. Moving the drillstring under pressure,
5. Diverting the flow away from the rig personnel and equipment.

To prevent a well from blowing out, it is essential to detect a kick as soon as possible. Especially at
wildcat wells and wells drilled in areas of abnormal formation pressures, the various kick detection
parameters have to be observed continuously.

Kick Detection Parameters

CHAPTER 11 Page 231


1. Gain in pit volume,

2. Increase in mud return flow rate while circulating at constant rate,

3. Mud return even when the pumps are shut down,

4. Well is taking less (tripping in) or giving more (tripping out) mud than calculated,

5. Increase in drilling rate,

6. Decrease in the circulation pressure,

7. Increase of the chloride content of the mud,

8. Increase of trip, connection or background gas.

It should be noted that some of these parameters alone are sufficient to indicate a kick (e.g. pit
gain), others (e.g. reduction of chloride content) are additional observations and should only be
used as kick detection when multiple other kick detecting observations are present as well. Small
trip tanks have proven to provide the best means of monitoring hole fill-up volume. Trip tanks
usually hold 10 to 15 [bbl] and have 1 [bbl] gauge markers. On the site, the top of the gravity-feed
trip tank must be slightly lower than the bell nipple to prevent mud from being lost to the flow
line. In case that a trip tank is not installed, hole fill-up volume should be determined by counting
pump strokes each time the hole is filled.

11.1 Blowout Preventer

When a kick is detected at the surface, a device called “blowout preventers” (BOP) is used to stop
the fluid flow from the well. To cover all possible scenarios and handle different kick situations,
different BOPs are collectively attached to the well head. This series of BOPs is also called “BOP
stack”. A typical BOP stack configuration is shown in figure 11.1.
The BOP stack should enable the rig personnel to perform following actions when a kick is shut
in:

1. BOP must be capable to terminate flow from the well under all drilling conditions.

2. When the drillstring is in the hole, movement of the string without releasing well pressure
must be possible.

3. BOP stack must allow fluid circulation through the well annulus under pressure.

To achieve these objectives, a series of so called “ram preventers” and “annular preventers” are
combined.

CHAPTER 11 Page 232


Figure 11.1: Typical BOP stack conﬁguration

11.1.1 Ram preventers

Ram preventers consist of two packing
elements on opposite sides that close the
well by moving toward each other.

Pipe Rams

Pipe rams have semicircular open-
ings which match the diameter of the
drillpipe seize for which they are de-
signed. Thus when the drillpipe seize
is changed during the well, the closing
elements of the pipe rams have to be Figure 11.2: Ram Preventer
changed as well. When the drillstring
consists of drillpipe with more than one
diameter seize, additional ram preventers have to be used in the BOP stack.

CHAPTER 11 Page 233


Blind Rams

Blind rams can close the well when there is no drillpipe in the hole. When blind rams are activated
while drillpipe is in the well, the drillpipe will be flattened but the flow of the well will not be
closed in.
Shear rams are special designed blind rams that cut the drillpipe. When the shear rams are closed
and drillpipe is in the hole, the pipe will be separated, the lower part will drop into the hole and
the flow of the well will stop. Thus shear rams are activated in emergencies only when all pipe
rams and annular preventers failed.

Figure 11.3: Sketch of a rotational cut through a BOP

11.1.2 Annular preventers

Annular preventer or also called bag type preventer, close the flow of the well with a ring of
synthetic rubber that contracts in the fluid passage. Annular preventers are designed in such a
way that when they are closed, the pressure in the annulus helps to keep it closed.
The primary method of closing both ram and annular preventers is hydraulically by accumulators.
In case the hydraulic system fails, the ram preventers have a screw-type locking device that can
be applied to close them.

CHAPTER 11 Page 234


The accumulator has to be capable to sup-
ply sufficient pressure fluid to close all pre-
venter units in the BOP stack. The accu-
mulator itself is equipped with a pressure
regulating system that allows to adjust the
closing pressure on the preventers. This is
necessary when pipe has to be “stripped”
into the hole (lower drillstring when the
BOP is closed). When a kick is detected
during a trip, it is recommended to strip
back to bottom and thus allow for efficient
circulation of the entire well. Stripping
itself is easiest when the well is shut in
with annular preventers. When the surface
well pressure is too large, stripping must
be carried out with two pipe ram preven-
ters. Thereto the upper and lower rams are
opened and closed alternating as the tool
joints are lowered through the BOP stack.
In this way, the two pipe ram preventers Figure 11.4: Annular Preventer
applied for stripping must be far enough
apart so that a tool joint fits between them. This space is provided by a drilling spool that is
mounted between them. Drilling spools are also applied to permit the attachment of high pres-
sure flowlines to a given point at the stack. Since drilling spools are assembled permanently, their
inside diameter must be large enough so that the next casing seizes fit through them.
The high pressure flowlines that are connected to the drilling spools allow to pump into the
annulus or release fluid from the annulus while the BOP is closed. A conduct applied to pump
into the annulus is called “kill line”. Pumping fluid into the annulus is performed only under
special circumstances and is not part of normal well control operations.
The conducts applied to release fluid from the annulus may be called “choke line”, “diverter line”
or simply “flow line”. Normally, the circulation of a kick is performed through an adjustable
choke. This is necessary since sufficient pressure must be held against the well so that the bottom
hole pressure is maintained slightly above the formation pressure. A mud gas separator permits
any produced formation gas to be vented.
The BOP stack itself is attached to the casing via a so called “casing head” (or “Breaden head”).
The casing head is welded on the first string of casing which is cemented.
Which preventers are assembled to a BOP stack and in which sequence vary considerably from
location to location. At offshore wells, it is common to have double the amount of preventers
compared to onshore for backup purposes. Normally a particular arrangement is named from the
casing head upwards. A typical combination is SRSRRA where:

S: Spool,
R: Pipe ram preventer,

CHAPTER 11 Page 235


A: Annular preventer,

Figure 11.5: More Typical BOP Stacks

CHAPTER 11 Page 236


When the drillstring is in the hole, only the annular flow is stopped by the BOP. To prevent the
flow inside the drillpipe, various devices like a kelly cock or internal BOPs can be applied. When
kelly cocks are mounted in the drillstring, an upper and a lower kelly cock is needed since the
lower position might be not accessible in an emergency.
In addition to the controls of the preventers at the BOP stack, a control panel is placed on the
rig floor close to the drillers position.

Figure 11.6: Operating the chokes at the drilling floor

In the following, methods to circulate a kick out of the borehole are discussed.

11.2 Well Control Operations

To be able to circulate out a detected kick, a minimum amount of information is required. Some
of this information is obtained prior to the kick and concerns the equipment in use and operations
performed, other information is gathered after the kick is shut-in the borehole.

CHAPTER 11 Page 237


Pre-kick information:

1. Maximum allowable casing pressure (pressure rating of the BOP and burst strength of the
casing),

2. Capacity [bbl/ft] of the drillpipe, the drill collars, and annuli,

3. Volume of active mud circulation system,

4. Fracture gradient of the drilled formation,

5. Reduced circulation rate and pressure,

6. Pump factor and eﬃciency.

After a kick is detected and the well shut-in, the following parameters are obtained:

Post-kick information:

1. Stabilized shut-in casing pressure,

2. Stabilized shut-in drillpipe pressure,

3. Pit gain (is assumed to be equal the kick volume),

4. TVD and MD depth of the bottom of the hole.

Figure 11.7: Shutting in a kick

CHAPTER 11 Page 238


Having all the information at hand, following parameters are determined before attempting to
circulate out the kick:

1. Density (determines type) and length of kick,

2. Mud weight required to stop well from kicking,

3. Number of pump strokes to pump a volume from surface to bit and from bit to choke,

4. Volume of weighted mud to kill well,

5. Quantity of weighting material (e.g. barite) required to weight up the drilling fluid,

6. Accurate initial circulation drillpipe pressure,

7. Accurate final circulation drillpipe pressure,

8. Drillpipe pressure reduction schedule (for wait-and-weight method).

11.3 Length and Density of Kick

To determine the type of kick taken (oil, water, gas), the density of the gained fluid (kick density)
has to be estimated. This is achieved by combining the observed drillpipe pdp and the casing
pressure pc as well as the gain in pit volume. Equation 11.1 calculates the kick density [ppg]:

pc − pdp
ρk = ρ m − (11.1)
0.052.Lk

To solve this equation, the kick length Lk [ft], which is estimated by the pit gain and the geomet-
rical configuration of the drillstring and the diameter of the borehole, has to be computed first.
For a pit gain Vk smaller or equal the annulus volume of the drill collars (Van )dc , the length of the
kick is found by equation 11.2:

Lk = Vk . (Van )dc (11.2)

For a pit gain Vk larger than the annulus volume of the drill collars (Van )dc equation 11.3 has to
be used.

Ldc
Lk = Ldc + Vk − . (Van )dp (11.3)
(Van )dc

where:

CHAPTER 11 Page 239


(Van )cd [ft/bbl] ... annular capacity of the borehole at the drill collars
Ldc [ft] ... total length of the drill collars
(Van )dp [ft/bbl] ... annular capacity of the borehole at the drillpipe
Vk [bbl] ... kick volume, pit gain
Pc [psi] ... initial stabilized casing pressure
Pdp [psi] ... initial stabilized drillpipe pressure

Knowing the kick density, the so called kick gradient gradk [psi/ft] is often applied to identify the
type of kick. The kick gradient is computed as:

gradk = 0.052.ρk (11.4)

where:

ρk [ppg] ... kick density

Thus:

gradk < 0.3 ... gas kick
0.3 < gradk < 0.4 ... oil and gas mixture
gradk > 0.4 ... water kick
gradk > 8.33 ... salt water kick

11.4 Kick Tolerance and Kill Mud Weight

The kick tolerance determines the ability to control a kick at the current situation without frac-
turing a formation and causing lost circulation.
By definition, the kick tolerance is the difference between the maximum pore pressure of any
formation penetrated and causing the kick, and the drilling mud weight at this depth. This is
mathematically expressed as:

Tk = (ρe − ρm ) (11.5)

To establish safe drilling condition, it should be ensured that the kick tolerance is never below 1
[ppg]. The kill mud weight is defined as the mud weight required to stop a well from kicking and
can be computed by:

CHAPTER 11 Page 240


pdp
ρkm = ρm + (11.6)
0.052.D

The equivalent mud density at the casing seat is found as:

pc
ρe = + ρm (11.7)
0.052.Dc

where:

Dc [ft] ... casing setting depth

11.5 Pump Pressure Schedules for Well Control Opera-
tions

When killing a well, the bottom hole pressure of the well must be maintained equal to or higher
than the formation pressure which caused the kick. When this is not established, the well would
be constantly kicking, thus constantly gaining formation ﬂuid or gas.
To maintain this required bottom hole pressure, the circulation pressure to remove the kick has
to be calculated as planned pump rate for kick removal. Normally, the pump rate to circulate
out a kick is half the drilling pump rate. It is common practice to calculate the required circu-
lation pressure since the required bottom hole pressure is not directly measurable. The required
circulation pressure can be found as:

pdpf f = pdp + ∆pp − ∆pdpf = pdpf − ∆pdpf (11.8)

where:

∆pp
∆pdpf = (ρkm − ρm ) . 0.052.D − (11.9)
ρm

This enables the calculation of the total number of pump strokes required to pump the kill mud
to the bit:

Ldp .Vdp + Ldc .Vdc
fstr = (11.10)
Fp

where:

CHAPTER 11 Page 241


pdpf f [psi] ... final circulation drillpipe pressure
∆pdpf [psi] ... change in total drillpipe pressure required
to maintain the bottom hole pressure constant
∆pp [psi] ... routinely measured circulation pump pressure
Fp [bbl/stroke] ... pump factor
Ldp [ft] ... length of drillpipe
Ldc [ft] ... length of drill collars
Vdc [bbl/ft] ... capacity of drill collar

The number of strokes pumped and the circulation drillpipe pressure are linearly related. This
can be seen with equation 11.11:

pdpf − pdpf f
dpn = pdpf − .Str (11.11)
fstr

where:

Str [# strokes] ... intermediate pump strokes

11.6 Kick Removal – Two Methods
In general, two methods to circulate a kick out are applied most often:

1. Driller’s method,

2. Wait-and-weight method.

At the wait-and-weight method, the well is closed-in once a kick is detected and the post-kick
information is obtained. Next, the kill mud weight is determined, the weighted mud is prepared
and then circulated in to kill the well. During this operation, the drillpipe pressure is checked
according to the pressure schedule which has to be prepared before the circulation starts.
When the driller’s method is applied to kill the well, the whole process is divided into two steps.
First, the annulus fluid containing the kick is displaced with the help of an adjustable choke.
Normally, circulation is continued so that all kick fluids are removed. Then, as a second step, the
weighted mud is pumped through the drillstring and the annulus by a complete circulation.
The driller’s methods offers following advantages compared to the weight-and-weight method:

1. Circulation starts immediately,

CHAPTER 11 Page 242


2. Suﬃcient time is given to weighting up the mud.

The disadvantages of the driller’s method compared to the wait-and-weight method are:

1. Maximum surface pressure and pressure at the casing shoe are higher,

2. Surface equipment is subjected to higher pressures for a longer time.

11.6.1 Wait-and-weight method

pbh = pdp + 0.052.ρm .D (11.12)

Vk .pbh
G= (11.13)
pmax
√
b2 + 4.c + b
pmax = (11.14)
2

pdp .Vdp . (Van )dp
b= + 0.052.ρkm .D1 (11.15)
D

c = 0.052.ρkm .Vk . (Van )dp .pbh (11.16)

where:

pbh [psi] ... bottom hole pressure
G [bbl] ... pit volume increase when top of kick reaches the depth of interest
pmax [psi] ... maximum casing pressure
Vdp [bbl] ... inside drillpipe capacity
(Van )dp [ft/bbl] ... annular capacity opposite the drillpipe
D1 [ft] ... depth to the point where kick severity calculation is required
ρm [ppg] ... kill mud weight
D [ft] ... total depth of the well

CHAPTER 11 Page 243


11.6.2 Driller’s method

All equations of the wait-and-weight method are applicable provided that the constants b and c
are computed with:

b = pdp + 0.052.ρm .D1 (11.17)

c = 0.052.ρm .Vk . (Van )dp .pbh (11.18)

Figure 11.8: Pressure scheme while circulating a kick out

11.7 Equations Required to Perform Dynamic or Polymer
Kill
The techniques described so far are applied to circulate a kick out. Although utmost care is
always taken, sometimes a blowout occurs and has to be killed. Depending on the conditions of
the surface equipment after the blowout occurred, two methods are possible to kill the blowout.
The ﬁrst and when possible, preferred one, is a “surface kill”. When a surface kill is not possible,
a directional well (relief well) has to be drilled to intersect the blowing one and an attempt to kill
the well from the reservoir is made.
When drilling a relief well, a so called “dynamic or polymer killing” procedure is applied. This
involves pumping a lighter ﬂuid (usually water) into the relief well until a breakthrough to the

CHAPTER 11 Page 244


blowing well occurs. In this way a hydrodynamic connection between the relief and the blowing
well is established. Afterwards, the density of the ﬂuid pumped into the relief well is increased so
that the well can be controlled hydrostatically.

Figure 11.9: Sketch of a relief well concept

The equations for calculating the required tubular seize, injection rates, horsepower requirements,
etc. for the relief well and the dynamic kill are presented below. The subscripts b is used for the
blowing well and r for the relief well.

(∆pf )b .d5eb
qb = (11.19)
11.41.fb .Lb .ρf b

CHAPTER 11 Page 245


d5 = (dob − dib )3 . (dob − dib )2
eb (11.20)

0.25
fb = 2 (11.21)
dh
2. log + 1.14

(∆pf )b = pb − phb (11.22)

qb
qr = (11.23)
ηe

hp = 0.0245.qr .psr (11.24)

The minimum tubular seize of the relief well:

d5
er
2
11.41.qr .Lr .ρf r
> (11.25)
fr (∆pf )r

d5 = (dor − dir )3 . (dor − dir )2
er (11.26)

(∆pf )r = psr + phr − pf rac (11.27)

Wsb + (Aan )b .R.phb
(pmax )b = (11.28)
(Ap )b + (Aan )b

1 d2
R= − ib
(11.29)
2. ln dob dob − d2
2
ib
dib

(pf rac − pb ) .k.h
qmax = − 2
(11.30)
1,688.φ.µ.ct .rw
101, 664.β.µ. ln k.t
− 2.s

qb [bbl/min] ... ﬂow rate needed in the blowout well
qr [bbl/min] ... injection rate needed in the relief well
hp [hp] ... pumping power requirement
(pmax )b [psi] ... maximum allowable bottom hole pressure
Aan [in2 ] ... area of annulus
Ap [in2 ] ... area of drillpipe
ct [1/psi] ... total isothermal compressibility

CHAPTER 11 Page 246


d [in] ... hole or casing inside diameter
de [in] ... equivalent pipe diameter
dh [in] ... hydraulic diameter (= (do − di ))
di [in] ... outside diameter of the inside pipe
do [in] ... inside diameter of the outside pipe
f [1] ... friction factor
h [ft] ... net pay thickness
k [md] ... formation permeability
L [ft] ... length of pipe
p [psi] ... required bottom hole pressure
pf [psi] ... required friction pressure drop
pf rac [psi] ... fracture pressure of formation
ph [psi] ... hydrostatic head of fluids
ps [psi] ... maximum allowable surface injection pressure
pmax [psi] ... maximum allowable bottom hole pressure
∆pf [psi] ... maximum allowable friction pressure drop
q [bbl/min] ... frow rate or injection rate
qmax [bbl/min] ... maximum allowable injection rate through formation
R [1] ... ratio of friction drag on drillstring to total fraction
rw [ft] ... wellbore radius in relief well
s [1] ... skin factor of relief well
t [min] ... pumping time
Ws [lb] ... weight of drillstring in air
ρf [ppg] ... density of kill fluid
µ [cp] ... viscosity of injected fluids
φ [%] ... formation porosity
β [RB/STB] ... formation volume factor of injected fluids
[in] ... ripe roughness factor, 0.00065
ηe [%] ... efficiency

Normally, relief well killing operations are carried out by companies specialized in killing blowouts.
The same is valid for a surface kill of a blowout.

CHAPTER 11 Page 247


11.8 Examples

CHAPTER 11 Page 248


Chapter 12

Cementing

Cementing an oil or gas well comprises the displacement of cement slurry down the drillstring,
tubing or casing to a predefined section of the annulus of the well. The cement slurry itself
typically contains water, portland cement and various additives. The actual composition varies
from application to application.
Different cement slurry placement techniques are:

1. primary cementing,
2. liner cementing,
3. squeeze cementing,
4. plug back cementing.

12.1 Functions of Cement
The functions of the different cement jobs differ according to the various objectives. The list below
gives of some main objectives for the different cement jobs.

Primary Cement

1. Isolate a hydrocarbon bearing formation from other formations,
2. Protect and secure the casing in the well,
3. Prevent caving of the hole,
4. Provide a firm seal and anchor for the wellhead equipment,
5. Protect casing from corrosion by sulfate rich formation waters.

CHAPTER 12 Page 249


Liner Cement

1. Case off open hole below a long intermediate casing,

2. Case off open hole resulting from casing stuck at the bottom,

3. Case off previous open-hole completion in order to control water, gas or sand,

4. Case off zones of lost circulation or high pressure zones encountered during drilling,

Squeeze Cement

1. Reduce water-oil, water-gas, or gas-oil ratios,

2. Shut off a zone that is been depleted, is not economical to produce or whose production will
be delayed until the more promising zones in the same borehole are depleted,

3. Isolate a zone before perforating for production or stimulation,

4. Supplement a faulty primary cement job,

5. Repair casing or joint leaks, spit or parted casing,

6. Stop lost circulation in an open hole while drilling.

Plug Back Cement

1. Shut off bottom hole water production,

2. Abandon permanently deeper zones,

3. Completing a zone uphole,

4. Place a cement bridge plug,

5. Set plug to provide a seat for directional tools like whipstock,

6. Set plug in unintentionally deviated well when vertical trajectory is intended. After setting
the plug the vertical hole is continued.

7. Set plug through keyseat portion of the well and redrill it.

CHAPTER 12 Page 250


12.2 Properties of Cement Slurry

API has defined standard classes (Class A to Class H) as well as standard types of cement used
within oil and gas wells. The standard types are:

1. Ordinary,

2. Moderate sulfate-resistant,

3. High sulfate-resistant,

the standard classes are defined as:

1. Class A: Intended depth range for usage: surface to 6,000 [ft], when special properties are
not required, available in ordinary type only.

2. Class B: Intended depth range for usage: surface to 6,000 [ft], when conditions require
moderate to high sulfate-resistance, available as moderate and high sulfate-resistance types.

3. Class C: Intended depth range for usage: surface to 6,000 [ft], when condition require high
early strength, available in ordinary, moderate and high sulfate-resistance types.

4. Class D: Intended depth range for usage: 6,000 to 10,000 [ft], at moderately high temper-
atures and pressures conditions, available in moderate and high sulfate-resistance types.

5. Class E: Intended depth range for usage: 10,000 to 14,000 [ft], at high temperature and
pressure conditions, available in moderate and high sulfate-resistance types.

6. Class F: Intended depth range for usage: 10,000 to 16,000 [ft], at extremely high tempera-
ture and pressure conditions, available in moderate and high sulfate-resistance types.

7. Class G: Intended as basic cement in the depth range: surface to 8,000 [ft], when used
with accelerators and retarders covers wide range of temperatures and pressures, no other
additions than calcium sulfate, water or both are to be blended with the clinker, available
in moderate and high sulfate-resistance types.

8. Class H: Intended as basic cement in the depth range: surface to 8,000 [ft], when used
with accelerators and retarders covers wide range of temperatures and pressures, no other
additions than calcium sulfate, water or both are to be blended with the clinker, available
in moderate sulfate-resistance type only.

Cement properties include the chemical, physical and rheological characteristics of the cement.
The rheological properties of cement slurries are generally the same as the ones of the drilling
fluids discussed in previous sections. The chemical properties and requirements of API cement
types are given in table 12.1, some physical properties are provided in table 12.2 as well.

CHAPTER 12 Page 251


Figure 12.1: Chemical requirements of API cement types

12.2.1 Physical Properties

The physical properties of cement and cement slurries include:

1. Thickening time,

2. Fineness,

3. Water content,

4. Slurry density,

5. Compressive strength,

CHAPTER 12 Page 252


6. Fluid loss,

7. Yield,

8. Bottom hole temperature.

Figure 12.2: Physical requirements of API cement types

In general, it can be said that the physical properties are manipulated to fulﬁll speciﬁed purposes.

CHAPTER 12 Page 253


Slurry density

To minimize the danger of fracturing the formations, lost circulation or kicks, the cement slurry
density should be the same as the drilling fluid density at cementing operations. The following
equation gives the slurry density ρcs in [ppg]:

[lb] Cement + [lb] Water + [lb] Additive
ρcs = (12.1)
[gal] Cement + [gal] Water + [gal] Additive

To compute the absolute volume of solid constituents, the equation 12.2 is applied:

lb of Material
gal = (12.2)
(8.34 ppg)(s.g. of Material)

Yield

By definition, the yield is the volume of cement slurry obtained when mixing one sack of cement
with a specified amount of water as well as other additives. Note that one sack cement (94 [lb]
sack) contains 1 [ft3 ] bulk volume and 0.48 [ft3 ] absolute volume. To compute the yield in [ft3 ],
equation 12.3 is applied:

[gal] Cement + [gal] Water + [gal] Additive
Yield = (12.3)
7.48 gal
ft3

Thickening Time

The length of time the cement slurry is pumpable is also called “thickening time”. To control the
thickening time, adding of setting time retarders, a reduction of rapidly hydrating components and
an adjustment of the cement fineness is performed. When the time it takes to properly place the
cement slurry at the predetermined annulus interval (mixing and displacement time), including a
safety factor, exceeds the thickening time, parts of the cement will remain in the tubular used to
pump down the cement slurry. To determine the mixing and displacement times, equations 12.4
and 12.5 applied:

Volume of Dry Cement
Tm = (12.4)
Mixing Rate

Amount of Fluid Required to Displace Top Plug
Td = (12.5)
Displacement Rate

CHAPTER 12 Page 254


Compressive Strength

To hold the casing in place, enable support capability of the surface wellhead equipment and with-
stand the differential pressures across the cement-formation interface, the compressive strength of
the set and hardened cement has to be high enough. As general practice, 500 [psi] of compres-
sive strength has to be developed by the hardening cement before any other downhole operation
commences. The time it takes the cement to reach this minimum compressive strength is often
referenced as “wait on cement” (WOC). During this time, other routine surface service operations
are usually carried out. The support capability of the cement is given by:

F = 0.969.Sc .do .H (12.6)

where:

F [lbf] ... support capability
Sc [psi] ... compressive strength of cement
do [in] ... outside diameter of casing
H [ft] ... hight of cement column

12.3 Cement Additives
Main component of all cement slurries for oil and gas well cementing is “Portland cement”. It is
produced according to API specifications by taking raw material like limestone, clay or shale, and
iron ore. After mixing and grinding, they are fed into a kiln where they are melt into a substance
called “cement clinker”. This clinker is then ground into a powdery mixture and combined with
small amounts of gypsum or other components.

To better fit the individual well requirements, the properties of the cement slurry and hardened
cement have to be adjusted. Therefore, certain cement additives are mixed into the slurry. The
additives can be grouped according to their functionality into:

1. Extenders,

2. Accelerators,

3. Retarders,

4. Weighting material,

5. Fluid loss or filtration control material,

6. Dispersants or thinners.

CHAPTER 12 Page 255


The individual properties of some cementing additives are shown in table 12.3 and 12.3.

Figure 12.3: Properties of cement additives

CHAPTER 12 Page 256


Figure 12.4: Properties of cement additives con.

12.3.1 Extenders

Extenders are used to increase the volume of the cement slurry gained per sack cement (yield).
This is done by allowing an adding of extra water to the slurry. In turn, this extra water reduces
the density of the cement slurry. Commonly used extenders that reduce the density of the slurry
are low-speciﬁc gravity solids like:

CHAPTER 12 Page 257


1. Bentonite,

2. Diatomaceous earth,

3. Solid hydrocarbons,

4. Expanded perlite,

5. Natural pozzolans,

6. Silica,

7. Chemical extenders (liquid or solid silicate).

12.3.2 Accelerators

To reduce the thickening time as well as increase the rate of early strength and thus reduce
the WOC time, accelerators are added to the cement slurries. When cementing shallow, low
temperature section of wells, accelerators are often essential. Commonly applied accelerators are:

1. Sodium chloride,

2. Calcium chloride,

3. Hemihydrate form of gypsum ,

4. Potassium chloride,

5. Sodium silicate,

6. Sea water for mixing.

12.3.3 Retarders

In contrary to the accelerators, retarders are added to cement slurries to prolong the thickening
time and decrease the rate of early strength development. Deflocculants discussed as drilling fluids
additives tend to delay the setting of cement, thus they are applied as retarders.

1. Calcium lignosulfate at very low concentrations,

2. Calcium-sodium lignosulfate used with high concentration of bentonite,

3. Sodium tetraborate decahydrate (borax) used as a catalyst for the deflocculants,

4. Carboxymethyl hydroxyethyl cellulose.

CHAPTER 12 Page 258


12.3.4 Weighting Material

Weighting material are cement ad-
ditives that are capable of in-
creasing the density of the cement
slurry. Commonly used weighting
materials are high-specific gravity
solids like:

1. Barite,

2. Ottawa sand,

3. Hematite,

4. Ilmenite.

Figure 12.5: Cement classification according to its weight

12.3.5 Fluid Loss Material

Fluid loss material is added to the cement slurry to help minimize the loss of water from the
slurry into the formations. During displacement and cement setting, a differential pressure across
permeable formations and the cement does develop which causes a reduction of water in the slurry
that is lost into the formations. Commonly added fluid loss materials are:

1. Latex,

2. Bentonite with a dispersant,

3. Various organic polymers,

4. Attapulgite,

5. Carboxymethyl hydroxyethyl cellulose.

CHAPTER 12 Page 259


12.3.6 Dispersants

Dispersants are added to thin the cement
slurry. This causes a reduction of slurry vis-
cosity and is achieved without adding of extra
water. Commonly applied thinners are:

1. Calcium lignosulfate,

2. Sodium chloride,

3. Certain long chain polymers.

The water requirement of mixing API cement
and some additives are shown in table 12.6.
To obtain the required density of the cement
slurry by adding high-speciﬁc gravity material
(per 94 [lb] sack of cement), the equation 12.7
can be applied:

94.ρcs2
8.34.γc
+ ρcs2 .Vwc − 94
Madditive = 8.34.Vwa
100
+ 1− ρcs2
8.34.γa
− ρcs2 .Vwa
100
(12.7)
When blending materials with saltwater, ideal
mixing rules do not apply. Therefore to cal-
culate the yield weight of bentonite, the water
requirements and the weight of NaCl or CaCl2
to obtain a speciﬁc concentration of chlorides
and bentonite, following equations have to be
applied:

Vcs
Sacks of Cement = (12.8) Figure 12.6: Water requirements for mixing ce-
Yield
ment slurries

% Bentonite
MB = .94. (Sacks of Cement)
100
(12.9)

W
C
. (Sacks of Cement)
Vw = (12.10)
42

CHAPTER 12 Page 260


% Chlorides
MChlorides = .94. (Sacks of Cement) (12.11)
100

94. (% Chloride)
% Chloride/Wt. of Water = (12.12)
8.34. W
C
+ 94. (% Chloride/100)

% Bentonite 94. (% Chloride/100) + 8.34. W
C
Yield = 0.47975 + 0.56846. + (12.13)
100 62.4.γChlorides

where:

Vwa [gal/sack] ... water requirement for additive
Vwc [gal/sack] ... water requirement for cement
γa [s.g.] ... specific gravity of additive
γc [s.g.] ... specific gravity of cement
ρcs2 [ppg] ... density of weighted slurry
Madditive [lb/sack] ... weight of additive required to raise the density to ρcs2
Vcs [ft3 ] ... slurry volume
W
C
[gal/sack] ... water/cement ratio
γchlorides [s.g.] ... specific gravity of salt water as per percent chlorides
MB [lb] ... weight of bentonite to be added
Mchlorides [lb] ... weight of chlorides to be added

yield [ft3 /sack]
% Cloride is the % NaCl or % CaCl2 by weight of cement
% Bentonite ie % bentonite by weight of cement
Specific gravities with respect to various concentrations of NaCl and CaCl2 are shown in tables
12.7 and 12.8.

CHAPTER 12 Page 261


Figure 12.7: Speciﬁc gravities of NaCl solutions at 68◦ F

Figure 12.8: Speciﬁc gravities of CaCl2 solutions at 68◦ F

CHAPTER 12 Page 262


12.4 Primary Cementing
The first step when performing a primary ce-
menting job is to calculate the volume of ce-
ment and cement slurry required to fill the an-
nulus interval that has to be cemented. The ce-
ment volume is calculated by estimating the vol-
ume between the casing and the borehole wall at
the selected interval. When the borehole is in-
gauge this volume is straight forward to calcu-
late. When washouts and other gauge variations
are present, the hole diameter has to be checked
with a caliper log and an average borehole diam-
eter calculated. This is done by applying equa-
tion 12.14.
Other parameters that have to be computed be-
fore the cement job commences are:

1. Determination of the quantities of cement
and additives,
2. Thickening time,
3. Displacement volume,
4. Differential forces,
5. Annular velocities, etc.

Once these parameters are known, displacement
rates, type and amount of spacers and preflushes,
the displacement process itself and the appropri-
ate cement slurry composition as well as mixing
procedures have to be designed. For example,
in most drilling operations laminar flow behav-
ior is desired, for displacing the cement slurry,
turbulent flow is the preferred one. Having this
in mind, the corresponding pumping rate can be
computed applying the power-law flow model.

1
dav = . (d2 .L1 + d2 .L2 + ... + d2 .Ln )
Lt 1 2 n

(12.14)
where:
Figure 12.9: Primary cementing procedure
CHAPTER 12 Page 263


Lt [ft] ... total depth
dn [in] ... diameter of the nth section
Ln [ft] ... length of the nth section

In conventional primary cementing the cement is displaced through the casing. In order to avoid
contamination of the cement with mud, a so called “spacer” is placed between them. The spacer
in front of the cement, which is also called “preflush”, is commonly water. Water is often chosen
since it is easy to obtain, it can be put in turbulent flow condition at relatively low circulation
rates and it does not affect the setting time of the cement. The column of water pumped ahead
of the cement causes a desired reduction of hydrostatic pressure in the annulus. The volume of
the spacer is given by:

∆ph
Vspacer = Aan . (12.15)
0.292. (ρm − ρw )
where:

Vspacer [bbl] ... volume of spacer (water)
Aan [ft3 /ft] ... annular capacity
∆ph [psi] ... reduction of hydrostatic pressure

To calculate the pump rate
to displace the spacer in tur-
bulent flow, the Newtonian
flow model is used.
The procedure of primary
cementing is described as fol-
lows:
To perform the primary ce-
menting job, a device called
“cement head” or “plug con-
tainer”, see figure 12.10, is
mounted on the top joint of
the casing which is hanging
in the elevator. This ce-
ment head serves as connec-
tion from the cement pumps
to the casing. Inside the ce-
ment head, a bottom wiper
plug and a top wiper plug,
see figure 12.11, are placed. Figure 12.10: Cement Heads, (A) Double plug, (B) Single plug

When the cement job is car-
ried out, the bottom plug is released first. It wipes mud off the inside of the casing and keeps

CHAPTER 12 Page 264


the preflush separated from the cement slurry.When the total amount of cement slurry is pumped
through the cement head, the top plug is released.

When the bottom plug reaches the float collar, it
stops and while continuing pumping, the pump
pressure increases.At a certain pressure the di-
aphragm of the bottom plug ruptures and the
cement slurry can flow through the open valve
in the collar, out the guide shoe and into the an-
nular space between the casing and the borehole.
During this flow, the casing is often reciprocated
or rotated to help displace the mud. When the
top plug moves down the casing, it wipes cement
off the inside walls. It also prevents the mixing
of the cement slurry with the displacement fluid
behind it. Since the top plug is solid, once it
lands on top of the bottom plug, flow stops and
the pressure rises. This increase of pressure in-
dicates that the cement is fully in place and the
pumps are bled off. When the pressure inside Figure 12.11: Wiper plugs
the casing is released, the valve in the float col-
lar closes and keeps the cement from flowing back up the casing

Figure 12.12: Wiper plugs while cementing

Pressure in the casing should be released before the cement sets since it causes the casing to
bulg. When the pressure is released after the cement starts to set, the casing pulls away from the
hardening cement and looses the bond.

CHAPTER 12 Page 265


Figure 12.13: Process of primary cementing in multiple stages

CHAPTER 12 Page 266


12.5 Liner Cementing
Liner cementing constitutes one of the most difficult ce-
menting operations. To perform it successfully following
individual processes are to be completed:

1. Running the liner on drillpipe,

2. Pumping the cement slurry through the drillpipe
and the liner,

3. Displace the cement slurry behind the liner up to
just above the liner hanger.

The equipment used to perform a liner cementing job
includes: a float shoe, a float collar, a landing collar, the
liner, the liner hanger, liner setting sleeve and setting
tools, the swivel assembly and liner wipe plug as well as
a pump down plug.
Sometimes it is necessary to extend a liner back to the
surface in order to complete the well. This casing type
is also known as “tieback liner”. When the liner is ex-
tended back but not until the surface, the casing is called
“stub liner”. To repair a leaking liner top, a stub liner is
installed usually.

12.6 Squeeze Cementing
Under squeeze cementing, the process of forcing a cement
slurry under pressure into a confined interval of the well
behind a casing is understood. A squeeze cementing job
may be necessary during drilling, at completing the well
or as workover after the well is completed and/or pro-
ducing.
The main influence to the success of squeeze cementing
operations is how good the cement slurry is placed into
the interval that is to be squeezed off. Normally, the
interval (e.g. perforations) is treated with an acid wash
or matrix acidizing using hydrochloric acid to clean the
surfaces before the job is performed.

Figure 12.14: Liner Hanger
CHAPTER 12 Page 267


To perform a squeeze cement job, three different methods can
be applied:

1. Bradenhead method,
2. Packer squeeze method,
3. Hesitation squeeze method.

To perform a squeeze cement job with the Bradenhead method,
the following procedure has to be completed:

1. Running the drillpipe to just above the perforations
where the cement has to be squeezed in,
2. Displace cement from the drillpipe,
3. Close the pipe rams and apply a precalculated pressure
from the surface to squeeze off the perforations.

When using the packer squeeze method, either a retrievable
squeeze packer or a cement retainer is applied. First the
packer is run to just above the interval that has to be squeezed
off. Afterwards surface pressure is subjected to the tubing or
drillpipe. This provides a close control of the squeeze cement Figure 12.15: Sketch of Braden-
slurry during squeezing. In contrary to the retrievable packer head Squeeze Cementing
which is run on drillpipe, the retainer packer is run on wireline.

Figure 12.16: Sketch of squeeze cementing with retrievable packer

CHAPTER 12 Page 268


At the hesitation squeeze method, the cement is squeezed into the desired section with relatively
low pressure while pumping intermittently. The cement is slowly dehydrating and increasing
in viscosity during the non-pumping cycle. This method is used most often to squeeze off low
permeable zones.

12.7 Plugback Cementing

Two different methods for plug cementing operations are encountered in practice: (a) the plugback
cementing and (b) spotting a cement plug at any desired depth of the well. The most common
type, plugback cementing, is used to plug back and abandon deeper zones. Spotting plug ce-
menting is usually performed in open hole sections. To design the spacer and cement slurry, the
same considerations and equations as for primary cementing operations are applied. For the pug
cementing operations a balanced plug techniques that requires pumping a preflush and a spacer
behind the cement, is most often carried out. When the hight of the spacer inside the tubing is
equal to the hight of the preflush, the cement plug is placed balanced.
Cement requirement, water volume to be pumped behind the slurry to balance the plug, plug
length before the pipe is retrieved from the slurry as well as mud volume for pipe displacement
are computed with:

Lplug .Vh
Sacks = (12.16)
Yield

Vdp .Vsa
Vsb = (12.17)
Van

where:

Vdp [ft3 ] ... volume of drillpipe
Van [ft3 ] ... volume of annulus

Sacks.Yield
Lw = (12.18)
Van + Vdp

where:

Vdp [ft3 /ft] ... capacity of drillpipe
Van [ft3 /ft] ... capacity of annulus

CHAPTER 12 Page 269


Vmd = (Ldp − Lw ) .Vdp − Vsb (12.19)

where:

Lplug [ft] ... length of desired plug
Vh [ft3 /ft] ... capacity of hole
Vsa [bbl] ... spacer volume ahead of slurry
Vsb [bbl] ... spacer volume behind of slurry
Vmd [bbl] ... volume of mud to displace pipe

CHAPTER 12 Page 270


12.8 Examples

1. Cement Class A containing 4 % bentonite is to be mixed. The normal water content of Class
A cement is 46 %, for each added percent of bentonite, 5.3 % of water has to be added. The
specific gravities of cement and bentonite are found to be 3.13 and 2.65 respectively. The weight
of bentonite, the total percent of water to be added as well as the volume of water to be mixed
with one sack of cement, the slurry yield and the slurry density have to be computed.

2. A 7 [in], 29 [lb/ft], N-80 casing has to be cemented in a 9.75 [in] hole for the length of 9,000 [ft].
A 60 [ft] shoe track is to be used and cementing carried out with a Class G, 15.4 [ppg] cement. The
plastic viscosity and the yield point of the cement are 50 [cp] and 10 [lb/ 100 ft] respectively. The
cement is pumped with a duplex pump, having a 18 [in] stroke, a 6.5 [in] liner and a 2.5 [in] rod,
and is operating at 60 [rpm] with an efficiency of 90 %. The water requirement of Class G cement
is 5 [gal/sack] with the slurry volume of 1.15 [ft3/sack]. Since the cement is to be prevented from
contamination with the previously used 11.6 [ppg] drilling mud, 30 [bbl] of fresh water are pumped
as preflush spacer. For cement mixing, a truck with a mixing capacity of 30 [sacks/min] is used.
Calculate the:

(a) Quantity of cement required,
(b) Volume of mixing water,
(c) Total time for the job, allowing 15 minutes for
the release of plug,
(d) Pressure differential prior to pumping the plug,
(e) Flow velocity in the casing and the type of flow,
(f) Flow velocity in the annulus and the type of flow.

3. A 5 [in] OD, 18 [lb/ft] liner (including hanger and float) is to be cemented in a 6- 1 [in] hole for
4
a length of 2,000 [ft]. The liner is run in on a 2- 7 [in], 10.4 [lb/ft] drillpipe to the liner landing
8
collar at 11,540 [ft]. The total well depth is 11,600 [ft], the liner-wipe plug at 9,615 [ft] and the
top of the liner at 9,600 [ft]. Calculate the:

(a) Sacks of Class E cement required if the
yield is 1.15 [ft3/sack],
(b) Displacement to the liner plug,
(c) Displacement from the liner plug to the landing collar.

4. Within a 6- 1 [in] hole a 300 [ft] plug is to be placed at 9,000 [ft] using a 2- 3 [in], 4.6 [lb/ft]
2 8
tubing. When 15 [bbl] of water are to be pumped ahead of the slurry that has a yield of 1.5
[ft3/sack], compute the:

CHAPTER 12 Page 271


(a) Sacks of cement required,
(b) Volume of water to be pumped behind the slurry,
(c) Amount of mud required to displace the spacer
to the balanced point.

CHAPTER 12 Page 272


Bibliography

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