Drilling Engineering Fundamentals

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Drilling Engineering Fundamentals

Associate Professor Jorge H.B. Sampaio Jr., PhD

Curtin University of Technology

Department of Petroleum Engineering

[email protected]

April 3, 2007


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Contents

1 Introduction 11

1.1 Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

1.2 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111.3 Drilling Rig Types . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

1.4 Personnel at Rig Site . . . . . . . . . . . . . . . . . . . . . . . . . 15

1.5 Miscellaneous . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

2 Rotary Drilling System 21

2.1 Power System . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

2.1.1 Energy, Work, and Efficiency . . . . . . . . . . . . . . . . 26

2.2 Hoisting System . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

2.2.1 The Derrick . . . . . . . . . . . . . . . . . . . . . . . . . . 210

2.2.2 The Drawworks . . . . . . . . . . . . . . . . . . . . . . . . 211

2.2.3 The Block & Tackle . . . . . . . . . . . . . . . . . . . . . . 212

2.2.4 Load Applied to the Derrick . . . . . . . . . . . . . . . . . 216

2.3 Drilling Fluid Circulation System . . . . . . . . . . . . . . . . . . 218

2.3.1 Mud Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . 220

2.3.2 Solids Control Equipment . . . . . . . . . . . . . . . . . . 2252.3.3 Treatment and Mixing Equipment . . . . . . . . . . . . . . 230

2.4 The Rotary System . . . . . . . . . . . . . . . . . . . . . . . . . . 233

2.4.1 Swivel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 233

2.4.2 Kelly, Kelly Valves, and Kelly Saver Sub . . . . . . . . . . 233

2.4.3 Rotary Table and Components . . . . . . . . . . . . . . . 236

2.5 Well Control System . . . . . . . . . . . . . . . . . . . . . . . . . 238

2.6 Well Monitoring System . . . . . . . . . . . . . . . . . . . . . . . 243

3 Drillstring Tubulars and Equipment 31

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Curtin University of TechnologyDepartment of Petroleum Engineering

Master of Petroleum Well EngineeringDrilling Engineering Fundamentals

3.1 Drill Pipes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

3.1.1 Drill Pipe Elevator . . . . . . . . . . . . . . . . . . . . . . 35

3.2 Drill Collars . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

3.3 Heavy Wall Drill Pipes . . . . . . . . . . . . . . . . . . . . . . . . 36

3.4 Special Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

3.4.1 Stabilizers . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

3.4.2 Reamers . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

3.4.3 Holeopeners . . . . . . . . . . . . . . . . . . . . . . . . . 39

3.5 Connections Makeup and Breakout . . . . . . . . . . . . . . . 310

3.5.1 Maximum Height of Tool Joint Shoulders . . . . . . . . . . 311

3.5.2 Makeup Torque . . . . . . . . . . . . . . . . . . . . . . . 313

3.6 Drill Bit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 313

3.7 Other Drillstring Equipment . . . . . . . . . . . . . . . . . . . . . 314

3.7.1 Top Drive . . . . . . . . . . . . . . . . . . . . . . . . . . . 314

3.7.2 Bottom Hole Motors . . . . . . . . . . . . . . . . . . . . . 315

4 Introduction to Hydraulics 41

4.1 Hydrostatic Pressure . . . . . . . . . . . . . . . . . . . . . . . . . 41

4.1.1 Hydrostatic Pressure for Incompressible Fluids . . . . . . 42

4.1.2 Hydrostatic Pressure for Compressible Fluids . . . . . . . 44

4.2 Buoyancy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

5 Drillstring Design 51

5.1 Length of Drill Collars Neutral Point Calculation . . . . . . . . . 51

5.2 Design for Tensile Force, Torque, Burst, and Collapse . . . . . . 56

5.2.1 Maximum Tensile Force . . . . . . . . . . . . . . . . . . . 565.2.2 Maximum Torque . . . . . . . . . . . . . . . . . . . . . . . 59

5.2.3 Internal (Burst) and External (Collapse) Pressures . . . . 510

5.2.4 Drillstring Elongation . . . . . . . . . . . . . . . . . . . . 512

6 Drilling Hydraulics 61

6.1 Mass and Energy Balance . . . . . . . . . . . . . . . . . . . . . . 61

6.1.1 Mass Conservation . . . . . . . . . . . . . . . . . . . . . 62

6.1.2 Energy Conservation . . . . . . . . . . . . . . . . . . . . 63

6.2 Flow Through Bit Nozzles . . . . . . . . . . . . . . . . . . . . . . 66


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6.2.1 Pressure Drop Across the Bit . . . . . . . . . . . . . . . . 66

6.2.2 Hydraulic Power Across the Bit . . . . . . . . . . . . . . . 68

6.2.3 Impact Force of the Jets . . . . . . . . . . . . . . . . . . . 68

6.3 Required Hydraulic Power . . . . . . . . . . . . . . . . . . . . . . 610

6.4 Bit Hydraulics Optimization . . . . . . . . . . . . . . . . . . . . . 611

6.4.1 Nozzle Size Selection Criteria . . . . . . . . . . . . . . . . 613

6.4.2 Graphical Analysis . . . . . . . . . . . . . . . . . . . . . . 616

7 Introduction to Drilling Fluids 71

7.1 Functions of Drilling Fluids . . . . . . . . . . . . . . . . . . . . . . 71

7.2 Types of Drilling Fluid . . . . . . . . . . . . . . . . . . . . . . . . 727.2.1 WaterBase Fluids . . . . . . . . . . . . . . . . . . . . . . 73

7.2.2 OilBase Muds . . . . . . . . . . . . . . . . . . . . . . . . 76

7.2.3 Synthetic Fluids . . . . . . . . . . . . . . . . . . . . . . . 77

7.2.4 Aerated Fluids . . . . . . . . . . . . . . . . . . . . . . . . 77

7.3 Laboratory Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

7.3.1 WaterBase Mud Tests . . . . . . . . . . . . . . . . . . . 77

7.3.2 Oil-Base Mud Testing . . . . . . . . . . . . . . . . . . . . 712

7.4 Fluid Density and Viscosity Calculations . . . . . . . . . . . . . . 713

7.4.1 Density Calculations . . . . . . . . . . . . . . . . . . . . . 714

7.4.2 Density Treatment . . . . . . . . . . . . . . . . . . . . . . 715

7.4.3 Initial Viscosity Treatment . . . . . . . . . . . . . . . . . . 719

8 Rheology and Rheometry 81

8.1 Rheological Classification of Fluids . . . . . . . . . . . . . . . . . 81

8.2 Rheometry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 848.2.1 Viscosity of Newtonian Fluids . . . . . . . . . . . . . . . . 85

8.2.2 Parameters of BinghamPlastic Model Fluids . . . . . . . 85

8.2.3 Parameters of PowerLaw Model Fluids . . . . . . . . . . 85

8.2.4 Gel Strength . . . . . . . . . . . . . . . . . . . . . . . . . 86

9 Flow in Pipes and Annuli 91

9.1 Laminar Flow in Pipes and Annuli . . . . . . . . . . . . . . . . . . 91

9.1.1 Equilibrium Equations . . . . . . . . . . . . . . . . . . . . 92

9.1.2 Continuity Equations . . . . . . . . . . . . . . . . . . . . . 93


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9.1.3 Newtonian Flow in Pipes Poiseuilles Equation . . . . . 95

9.1.4 Newtonian Flow in Concentric Annuli Lambs Equation . 96

9.1.5 Slot Approximation for Newtonian Fluids . . . . . . . . . . 99

9.1.6 Pressure Drop Gradient for NonNewtonian Fluids . . . . 910

9.2 Turbulent Flow in Pipes and Annuli . . . . . . . . . . . . . . . . . 912

9.2.1 Turbulent Flow of Newtonian Fluids in Pipes . . . . . . . . 912

9.2.2 Criterion for Laminar Transition Turbulent Flow . . . . 919

9.2.3 Other Geometries Turbulent Flow in Annuli (Newtonian) 920

9.2.4 Turbulent Flow for NonNewtonian Fluids . . . . . . . . . 922

10 Drilling Bits 10110.1 Drill Bit Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

10.1.1 Roller Cone Bit . . . . . . . . . . . . . . . . . . . . . . . . 102

10.1.2 Air Drilling Bits . . . . . . . . . . . . . . . . . . . . . . . . 108

10.1.3 Fixed Cutter Bits (Drag Bits) . . . . . . . . . . . . . . . . . 108

10.2 Bit Classification . . . . . . . . . . . . . . . . . . . . . . . . . . . 1015

10.2.1 PDC Bit Classification System . . . . . . . . . . . . . . . 1018

10.3 Drill Bit Selection and Evaluation . . . . . . . . . . . . . . . . . . 1020

10.3.1 Tooth Wear . . . . . . . . . . . . . . . . . . . . . . . . . . 1021

10.3.2 Bearing Wear . . . . . . . . . . . . . . . . . . . . . . . . . 1021

10.3.3 Gage Wear . . . . . . . . . . . . . . . . . . . . . . . . . . 1022

10.4 Factors that Affect the Rate Of Penetration . . . . . . . . . . . . . 1022

10.4.1 Bit Type . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1022

10.4.2 Formation Characteristics . . . . . . . . . . . . . . . . . . 1022

10.4.3 Drilling Fluid Properties . . . . . . . . . . . . . . . . . . . 1023

10.4.4 Operating Conditions . . . . . . . . . . . . . . . . . . . . 1025

A Drill Pipe Dimensions (as in API RP7C) A1


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List of Figures

1.1 Rig Classification. . . . . . . . . . . . . . . . . . . . . . . . . . . 13

2.1 Typical rig components. . . . . . . . . . . . . . . . . . . . . . . . 21

2.2 A simplified drillstring. . . . . . . . . . . . . . . . . . . . . . . . . 23

2.3 Making a connection. . . . . . . . . . . . . . . . . . . . . . . . . 24

2.4 Rig crew setting the slips. . . . . . . . . . . . . . . . . . . . . . . 24

2.5 Removing one stand of drillstring. . . . . . . . . . . . . . . . . . . 25

2.6 Typical hoisting system. . . . . . . . . . . . . . . . . . . . . . . . 29

2.7 Stand of doubles along the mast. . . . . . . . . . . . . . . . . . . 210

2.8 Onshore rig drawworks. . . . . . . . . . . . . . . . . . . . . . . . 211

2.9 Brake belts and magnification linkage. . . . . . . . . . . . . . . . 2112.10 Drawworks schematics. . . . . . . . . . . . . . . . . . . . . . . . 212

2.11 Forces acting in the blocktackle. . . . . . . . . . . . . . . . . . . 213

2.12 Derrick floor plan. . . . . . . . . . . . . . . . . . . . . . . . . . . . 217

2.13 A swivel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 219

2.14 Rig circulation system. . . . . . . . . . . . . . . . . . . . . . . . . 220

2.15 Duplex pumps. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 222

2.16 Triplex pumps. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 222

2.17 Surge dampener. . . . . . . . . . . . . . . . . . . . . . . . . . . . 224

2.18 Solids control system. . . . . . . . . . . . . . . . . . . . . . . . . 225

2.19 Shale shaker configurations. . . . . . . . . . . . . . . . . . . . . 226

2.20 A twoscreen shale shaker. . . . . . . . . . . . . . . . . . . . . . 226

2.21 A vacuum chamber degasser. . . . . . . . . . . . . . . . . . . . . 227

2.22 Flow path in a hydrocyclone. . . . . . . . . . . . . . . . . . . . . 228

2.23 Solid control equipment. . . . . . . . . . . . . . . . . . . . . . . . 228

2.24 Particle size classification. . . . . . . . . . . . . . . . . . . . . . . 229

2.25 Internal view of a centrifuge. . . . . . . . . . . . . . . . . . . . . . 230

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2.26 Mud cleaner. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 231

2.27 Mud agitator. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 231

2.28 Mud gun. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 232

2.29 Mud hopper. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 232

2.30 Cut views of a swivel. . . . . . . . . . . . . . . . . . . . . . . . . 234

2.31 A square kelly and a hexagonal kelly. . . . . . . . . . . . . . . . . 235

2.32 A kelly valve. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 235

2.33 Kelly bushings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 236

2.34 Master bushings ([a] and [b]), and casing bushing (c). . . . . . . 236

2.35 Kelly bushing and master bushing. . . . . . . . . . . . . . . . . . 237

2.36 Drillpipe slip (detail when set in the master bushing). . . . . . . . 237

2.37 DC slips, safety collar, and casing slips. . . . . . . . . . . . . . . 238

2.38 A rotary table. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 238

2.39 BOP stacks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 239

2.40 Annular BOPs (a and b) and an inside BOP (c) . . . . . . . . . . 240

2.41 BOP: (a) blind and pipe rams, (b) shear rams. . . . . . . . . . . . 241

2.42 BOP accumulators and control panels. . . . . . . . . . . . . . . . 242

2.43 Choke manifold. . . . . . . . . . . . . . . . . . . . . . . . . . . . 242

2.44 Weight indicator (a) and a deadline anchor (b). . . . . . . . . . . 244

2.45 Drilling control console. . . . . . . . . . . . . . . . . . . . . . . . 244

3.1 Typical rotary drillstring. . . . . . . . . . . . . . . . . . . . . . . . 32

3.2 Typical tool joint designs. (A) Internal upset DP with fullholeshrinkgrip TJ, (B) External upset DP with internalflush shrinkgrip TJ, (C) External upset DP with flashweld unitized TJ, (D)Externalinternal upset DP with Hydrillpressure welded TJ. . 33

3.3 A DP elevator and the links to the hook body. . . . . . . . . . . . 35

3.4 A spiraled and a slick drill collars. . . . . . . . . . . . . . . . . . . 36

3.5 Spiraled DC crosssection. . . . . . . . . . . . . . . . . . . . . . 36

3.6 A DC elevator. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

3.8 Heavy wall drill pipes. . . . . . . . . . . . . . . . . . . . . . . . . 37

3.9 Some Stabilizers: (a) integral, (b) interchangeable, (c) nonrotating,(d) replaceable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

3.10 A roller reamer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

3.11 A fixed holeopener. . . . . . . . . . . . . . . . . . . . . . . . . . 39


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3.12 Manual tongs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 310

3.13 Tongs in position to makeup a connection. . . . . . . . . . . . . 311

3.14 A spinner. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 312

3.15 Tongs position during makeup. . . . . . . . . . . . . . . . . . . . 312

3.16 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 312

3.17 An electrical top drive. . . . . . . . . . . . . . . . . . . . . . . . . 314

3.18 A bottom hole turbine. . . . . . . . . . . . . . . . . . . . . . . . . 315

3.19 A bottom hole PDM. . . . . . . . . . . . . . . . . . . . . . . . . . 315

4.1 Stress state about a point in a fluid. . . . . . . . . . . . . . . . . . 41

4.2 Real gas deviation factor. . . . . . . . . . . . . . . . . . . . . . . 454.3 Drillstring schematics for Example 12. . . . . . . . . . . . . . . . 49

5.1 Assumption 1 pressure contributes to buckling. . . . . . . . . . 52

5.2 Assumption 2 pressure does not contribute to buckling. . . . . 54

6.1 Mass balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

6.2 Schematic of a circulation system. . . . . . . . . . . . . . . . . . 65

6.3 Longitudinal cut of bit nozzles. (Courtesy SPE) . . . . . . . . . . 66

6.4 Pressure drop across the bit. . . . . . . . . . . . . . . . . . . . . 67

6.5 Jet impact force. . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

6.6 Line of maximum hydraulic power. . . . . . . . . . . . . . . . . . 616

6.7 Additional hydraulic constraints. . . . . . . . . . . . . . . . . . . . 617

6.8 Ideal surface operational parameters. . . . . . . . . . . . . . . . 618

6.9 Path of optimum hydraulics. . . . . . . . . . . . . . . . . . . . . . 619

6.10 Frictional pressure drop lines. . . . . . . . . . . . . . . . . . . . . 620

6.11 Graph for Example 27. . . . . . . . . . . . . . . . . . . . . . . . . 621

7.1 A mud balance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

7.2 A Marsh funnel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

7.3 A rotational viscometer (rheometer). . . . . . . . . . . . . . . . . 79

7.4 A API filter press. . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

7.5 A HTHP filter press. . . . . . . . . . . . . . . . . . . . . . . . . . 79

7.6 Sand content sieve. . . . . . . . . . . . . . . . . . . . . . . . . . 710

7.7 Retort. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 710

7.8 Methyl blue capacity test kit. . . . . . . . . . . . . . . . . . . . . . 711


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7.9 A pH meter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 711

7.10 A titration kit. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 712

7.11 A permeameter kit. . . . . . . . . . . . . . . . . . . . . . . . . . . 712

7.12 An aniline point kit. . . . . . . . . . . . . . . . . . . . . . . . . . . 713

7.13 Electrical stability tester. . . . . . . . . . . . . . . . . . . . . . . . 713

7.14 Clay performance for viscosity. . . . . . . . . . . . . . . . . . . . 721

8.1 Typical graph of Newtonian fluids. . . . . . . . . . . . . . . . . . . 82

8.2 Typical graph of Bingham-plastic fluids. . . . . . . . . . . . . . . 83

8.3 Typical graphs of powerlaw fluids. . . . . . . . . . . . . . . . . . 83

8.4 Arrangement of a rotational viscometer. . . . . . . . . . . . . . . 84

9.1 Velocity profiles of laminar flow. . . . . . . . . . . . . . . . . . . . 93

9.2 Velocity profile of laminar flow in a slot. . . . . . . . . . . . . . . . 94

9.3 Slot approximation of an annulus. . . . . . . . . . . . . . . . . . . 99

9.4 Fluid particle flowing in a pipe. . . . . . . . . . . . . . . . . . . . 914

9.5 Stanton chart. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 915

9.6 Selection of the correct pressure drop value. . . . . . . . . . . . 919

10.1 Typical roller cone bits. . . . . . . . . . . . . . . . . . . . . . . . . 102

10.2 Cut view of a roller cone bits. . . . . . . . . . . . . . . . . . . . . 103

10.3 Cut view of a nonsealed bearing bit. . . . . . . . . . . . . . . . 104

10.4 A sealed bearing bit. . . . . . . . . . . . . . . . . . . . . . . . . . 105

10.5 Cut view of a roller bearing cone. . . . . . . . . . . . . . . . . . . 105

10.6 Cut view of a journal bearing cone. . . . . . . . . . . . . . . . . . 106

10.7 Geometry of bit cones. . . . . . . . . . . . . . . . . . . . . . . . . 107

10.8 Cone offsets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108

10.9 Air drilling bits. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109

10.10Steel blade drag bits. . . . . . . . . . . . . . . . . . . . . . . . . . 1010

10.11A diamond bit. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1010

10.12Schematic and nomenclature of diamond bit. . . . . . . . . . . . 1011

10.13PDC bits. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1013

10.14Schematic and nomenclature of a PDC bit. . . . . . . . . . . . . 1014

10.15Nozzles in a PDC bit. . . . . . . . . . . . . . . . . . . . . . . . . 1014

10.16Back rake and side rake angles in PDC bits. . . . . . . . . . . . . 1014


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10.17IADC roller cone bit classification chart. . . . . . . . . . . . . . . 1016

10.18Tooth wear diagram for milled tooth bits. . . . . . . . . . . . . . . 1021

10.19Correlation between rock strength and threshold WOB. . . . . . 1023

10.20Variation of ROP with different fluid properties. . . . . . . . . . . 1024

10.21Effect of differential pressure in the ROP. . . . . . . . . . . . . . . 1025

10.22Exponential relationship between of differential pressure and ROP.1026

10.23Effect of WOB (a) and rotary speed (b) in the ROP. . . . . . . . . 1026


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List of Tables

2.1 Heating values of fuels. . . . . . . . . . . . . . . . . . . . . . . . 26

2.2 Blocktackle efficiency ($\eta=0.96$). . . . . . . . . . . . . . . . 214

10.1 IADC codes for roller cone bits. . . . . . . . . . . . . . . . . . . . 1017

10.2 Range for IADC bit profile. . . . . . . . . . . . . . . . . . . . . . . 1019

10.3 Range for IADC bit hydraulic design. . . . . . . . . . . . . . . . . 1019

10.4 Range for IADC cutter size and density. . . . . . . . . . . . . . . 1020

A.1 New Drill Pipe Dimensional Data . . . . . . . . . . . . . . . . . . A2

A.2 New Drill Pipe Torsional and Tensile Data. Courtesy API . . . . . A3

A.3 New Drill Pipe Collapse and Internal Pressure Data. Courtesy APIA4

A.4 Premium Drill Pipe Torsional and Tensile Data. Courtesy API . . A5

A.5 Premium Drill Pipe Collapse and Internal Pressure Data. Cour-tesy API . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A6

xi


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Chapter 1

Introduction

1.1 Objectives

The purpose of this text is to give students an introduction to the principles andsome recommended procedures practiced in drilling engineering. All chaptersin general contain a theoretical introduction, examples, and exercises. Refer-ences for further readings are given at the end of the text. Necessary equationsand procedures to solve the exercises are presented throughout the text.

1.2 General

When a drilling project is commenced, two goals govern its aspects. The firstis to build the well according to its purpose and in a safe manner (i.e, avoidingpersonal injuries and avoiding technical problems). The second is to completeit with minimum cost. Thereto the overall costs of the well during its lifetime inconjunction with the field development aspects shall be minimized. The overallcost minimization, or optimization, may influence the location from where thewell is drilled (e.g., an extended reach onshore or above reservoir offshore),the drilling technology applied (e.g., conventional or slimhole drilling, over-balanced or underbalanced, vertical or horizontal, etc), and which evaluationprocedures are run to gather subsurface information to optimize future wells.On the other hand, the optimization is influenced by logistics, environmentalregulations, etc.

To build a hole, different drilling technologies have been invented:

Percussion drilling

Cable drilling Pennsylvanian drilling Drillstring

* With mud Quick percussion drilling

CHAPTER 1Introduction to Drilling

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* Without mud Canadian drilling

Rotating drilling

Full cross-section drilling

* Surface driven

Rotary bit

Rotary nozzle

* 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.


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Figure 1.1: Rig Classification.

1.3 Drilling Rig Types

The diagram in Figure 1.1 shows a general classification of rotary drilling rigs.Several pictures of the different types of rigs are presented in Figures (a) to (l)below.

(a) Jackknife rig. (b) Portable mast.


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(c) A cantilever rig on a barge. (d) A selfcontained plat-form.

(e) A tender assisted platform. (f) A submersible platform.

(g) A JackUp rig (h) Semisubmersible vessel.


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(i) A drillship (j) A tensionleg platform.

(k) Caisson vessel (also called sparbuoy).

(l) Diagram of a sparbuoy.

1.4 Personnel at Rig Site

This section describes the crew requirements and tasks of some individual crewmembers at the rig site.

People directly involved in drilling a well are employed either by the operatingcompany, the drilling contractor, or one of the service and supply companies.The operating company is the owner of the lease/block and principal user of theservices 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


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may exist, to drill and produce from it. Usually, when a well has to be drilled,an auction is run by the operator and various drilling contractors are invitedto place their bid. Since drilling contractors are companies that perform theactual drilling of the well, their main job is to drill a hole to the depth/locationand specifications set by the operator. Along with hiring a drilling contractor,the operator usually employs various service and supply companies to performlogging, cementing, or any other special operations, including maintaining thedrilling fluid in its planed condition.

Most drilling crews consist of a tool pusher, a driller, a derrickman, a mudlogger, and two or three rotary helpers (also called floormen or roughnecks).Along with this basic crew configuration the operator sends usually a represen-tative, called company man to the rig. For offshore operations the crews usuallyconsist of many more employees.

Tool Pusher: The tool pusher supervises all drilling operations and is the lead-ing man of the drilling contractor on location. Along with this supervisionduties, he has to coordinate company and contractor affairs. Two or threecrews operate 24/7, and it is a responsibility of the Tool Pusher to super-vise and coordinate these crews.

Company Man: The company man is in direct charge of all companys activi-ties on the rig site. He is responsible for the drilling strategy as well as thesupplies and services in need. His decisions directly effect the progressof the well.

Driller: The driller operates the drilling machinery on the rig floor and is theoverall supervisor of all floormen. He reports directly to the tool pusherand is the person who is most closely involved in the drilling process. Heoperates, from his position at the control console, the rig floor brakes,switches, levers, and all other related controls that influence the drillingparameters. In case of a kick he is the first person to take action bymoving the bit off bottom and closing the BOP.

Derrick Man: The derrickman works on the socalled monkeyboard, a smallplatform up in the derrick, usually about 90 ft above the rotary table. Whena connection is made or during tripping operations he is handling andguiding the upper end of the pipe. During drilling operations the derrick-man is responsible for maintaining and repairing the pumps and otherequipment as well as keeping tabs on the drilling fluid.

Floormen: During tripping, the rotary helpers are responsible for handling thelower end of the drill pipe as well as operating tongs and wrenches tomake or break up a connection. During other times, they also maintainequipment, keep it clean, do painting and in general help where ever helpis needed.

Mud Engineer, Mud Logger: The service company who provides the mud al-most always sends a mud engineer and a mud logger to the rig site. They


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are constantly responsible for logging what is happening in the hole aswell as maintaining the proper mud conditions.

1.5 Miscellaneous

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

Shallow well: 5 000m

With the help of advanced technologies in MWD/LWD and extended reach

drilling techniques, horizontal departures of more than10000 m are possibletoday (e.g.,Wytch Farm).


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Chapter 2

Rotary Drilling System

The most common drilling rigs in use today are rotary drilling rigs. Their maintasks are to create rotation of the drillstring and facilities to advance and lift thedrillstring, casings, and special equipment into and out of the hole drilled. Themain components of a rotary drilling rig can be seen in Figure 2.1.

Figure 2.1: Typical rig components.

Since the rig rate (rental cost of the rig) is one of the most influencing costfactors to the total cost of a well, careful selection of the proper type and ca-pacity is vital for a successful drilling project.

CHAPTER 2Rotary Drilling Systems

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For all rigs, the depth of the planned well determines basic rig requirementslike hoisting capacity, power system, circulation system (mud pressure, mudstream, mud cleaning), and the pressure control system. The selection of themost costefficient rig involves both quantitative and qualitative considerations.The most important rig systems are:

1. Power system,

2. Hoisting system,

3. Drilling fluid circulation system,

4. Rotary system,

5. Derrick and substructure,

6. Well control system,

7. Well monitoring system.

The proper way to calculate the various requirements is discussed below. Thequalitative aspects involve technical design, appropriate expertise and trainingof the drilling crew, contractors track record, and logistics handling.

For offshore rigs, factors like water depth, expected sea, winds, and currentsconditions, and location (supply time) have to be considered.

It should be understood that rig rates are not only influenced by the rigtype but they are also strongly dependent on by the current market situation(oil price, drilling activity, rig availability, location, etc). Therefore, for the rigselection, basic rig requirements are determined first. Then drilling contractorsare contacted for offers of a proposed spud date (date at which drilling operationcommences) and alternative spud dates. This flexibility to schedule the spuddate may reduce rig rates considerably.

Before describe the various rig systems listed above, it is important to un-derstand the drilling process. In rotary drilling, the rock is destroyed by theaction of rotation and axial force applied to a drilling bit. The bit acts on the soil

destroying the rock, whose cuttings must be removed from the bottom of theborehole in order to continue drilling.

The drilling bit is located at the end of a drill string which is composed of drillpipes(also called joints or singles), drill collars, and other specialized drillingtools connected end to end by threads to the total length of the drill string, whichroughly corresponds to the current depth of the borehole. Drill collars are thickwalled tubes responsible for applying the axial force at the bit. Rotation at thebit is usually obtained by rotating the whole drill string from the surface. (SeeFigure 2.2.)

The lower portion of the drill string, composed of drill collars and special-ized drilling tools, are called bottom hole assembly (BHA). A large variety ofbit models and designs are available in industry. The choice of the right bit,


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Figure 2.2: A simplified drillstring.

based on the characteristics of the formations to be drilled, and the right pa-rameters (weight on bit and rotary speed) are the two most basic problems thedrilling engineer faces during drilling planning and drilling operation. The cut-tings created by the bit action are lifted to the surface by the drilling fluid, whichis continuously pumped from the surface to the bottom through inside of thehollow drill string. At the bit, the drilling fluid is forced through nozzles in a fluid

jet action which removes the cuttings from under the bit. The fluid returns tothe surface carrying the cuttings, through the annular space between the drillstring and the borehole. The carrying capacity of the drilling fluid is an impor-tant characteristics of the drilling fluid. Other important characteristics are thecapacity to prevent formation fluids from entering in the borehole, and the ca-

pacity to maintain the stability of the borehole wall. At the surface, the cuttingsare separated from the drilling fluid by several solid removal equipment. Thedrilling fluid accumulates in a series of tanks where it receives the necessarytreatment. From the last tank in this series, the drilling mud is picked up by thesystem of pumps and pumped again down the hole.

As drilling progresses, new joints are added to the top of the drill string in-creasing its length, in an operation called connection. The diagram in Figure 2.3depicts the process of adding a new joint to the drill string.

During the drilling of the length of the kelly, a new joint is picked from the

pipe rack and stabbed into the mousehole using rig lift equipment. At the kellydown, the kelly is pulled out of the hole. A pipe slips (see figure 2.4) is used totransfer the weight of the drillstring from the hook to the master bushing. The


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Figure 2.3: Making a connection.

Figure 2.4: Rig crew setting the slips.

connection at the first tool joint is broken and the kelly is swang and stabbedonto the joint in the mousehole. The new joint is stabbed on and connected tothe top of the drillstring. The drillstring is picked up to remove the slips and thedrillstring is lowered until the kelly bushing fits the master bushing. Then drillingis reinitiated.

As the bit gets dull, a round trip is performed to bring the dull bit to thesurface and replace it by a new one. A round trip is performed also to changethe BHA. The drillstring is also removed to run a casing string. The operationis done by removing stands of two (doubles), three (thribbles) or even four(fourbles) joints connected, and stacking them upright in the rig. During trips,

the kelly and swivel is stabbed into the rathole". The diagram in Figure 2.5depicts the process of removing a stand of the drillstring. The process repeatsuntil the whole drillstring is out of the hole. Then the drill string is run again into


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Figure 2.5: Removing one stand of drillstring.

the hole and drilling continues. The process to run the drillstring into the holeis exactly the reverse of that shown in Figure 2.5.

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 whilecontinuously circulating with drilling mud. Such a trip, called wiper trip, is carriedout to clean the hole from remaining cuttings that may have settled along theopenhole section.

2.1 Power System

The power system of a rotary drilling rig has to supply power to items 2 to 7 inthe list above. In addition, the system must provide power for pumps in general,rig light, air compressors, etc. Since the largest power consumers on a rotarydrilling rig are the hoisting, the circulation system, and the rotary system, thesecomponents determine mainly the total power requirements. During typicaldrilling operations, the hoisting and the rotary systems are not operated at thesame time. Therefore the same engines can be used to perform both functions.

Drilling rig power systems are classified as direct drive type and electrictype. In both cases, the sources of energy are diesel fueled engines. In thedirect drive type, internal combustion engines supply mechanical power to the

rig. Most rigs use one to three engines to power the drawworks and rotary table.Power is usually transmitted to the elements by gears, chains, belts, clutches,and torque converters. The engines are usually rated between 400 hp and


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800 hp. The power is used primarily to turn the drill string, pump the drillingfluid, and raise the drillstring. Engines also power generators that supply theelectricity used on and around the rig. Usually there are two generator setsin the rig. The rig can run with one of these units but it would run close tomaximum output at night. The second provides for backup and allows for otheroptions. These engines are generally rated at 300 hp to 350 hp. Rigs may alsoemploy one or two engines to power the drilling fluid pumps. Total output variesfrom 300 hp to 800 hp. In the electric type, several diesel engines are used togenerate electricity (DC and AC at various voltage levels) that are transmitted tothe various rig systems. DC electric motors are compact and powerful, and canoperate in a wide range of power and torque. There is considerable flexibility ofequipment placement, allowing better space utilization and weight distribution.This is extremely important in offshore rigs. As guideline, power requirementsfor most onshore rigs are between 1,000 to 3,000 hp. Offshore rigs in general

use much more power.

The performance of a rig power system is characterized by the output horse-power, torque, and fuel consumption for various engine speeds. These threeparameters are related by the efficiency of each system.

2.1.1 Energy, Work, and Efficiency

The energy consumed by the engines comes from burning fuels. Table 2.1

presents the heating values for some types of fuels used in internal combustionengines.

The engine transforms the chemical energy of the fuel into work. No enginecan transform totally the chemical energy into work. Most of the energy thatenters the engine is lost as heat. The thermal efficiency Et of a machine isdefined as the ratio of the workWgenerated to the chemical energy consumedQ:

Et =W

Q .

Evidently, in order to perform this calculation, we must use the same unitsboth to the work and to the chemical energy. Important conversion factors are:

1 BTU = 778.17 lbf/ft,

Table 2.1: Heating values of fuels.Fuel Type Heating Value Density

(BTU/lbm) (lbm/gal)Diesel 19000 7.2

Gasoline 20000 6.6

Butane (liquid) 21000 4.7Methane (gas) 24000


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1 cal = 4.1868 Joule = 4.1868 N m,

1 BTU = 252 cal.

Engines are normally rated by the powerPthey can deliver at a given work-ing regime. Power if defined as the rate work is performed, that is work per unitof time. If Qis the rate of chemical energy consumed by the machine (chemicalenergy per unit of time), we can rewrite the expression for the thermal efficiencyas:

Et =P

Q.

To calculate Q we need to know the type of fuel and the rate of fuel con-sumption in mass per unit time. (Consumption of gaseous fuels is normallygiven in mass per unit time, but consumption for liquid fuels is normally given in

volume per unit time. In the latter, we need to know the density of the fluid.)

A system produces mechanical work when the sole result of the processcould be the raising of a weight (most time limited by its efficiency). In thiscase, the workWdone by the system is given by

W =F h ,

whereF is the weight and h is the height. Since power is the rate the work isproduced, if we take the time derivative of the work we obtain power:

P=dW

dt =Fdh

dt =F v ,

whereP is power, and v the velocity (assuming Fconstant). When a rotatingmachine is operating (an internal combustion engine or an electrical motor, forexample), we cannot measure its power, but we can measure its rotating speed(normally in RPM) and the torque at the shaft. This is normally performedin a machine called dynamometer. The expression relating power to angularvelocity and torque is:

P = T ,

where is the angular velocity (in radians per unit of time) and T is the torque.

A common unit of power is the hp (horse power). One hp is the powerrequired to raise a weight of 33,000 lbf by one foot in one minute:

1 hp = 33, 000lbf ft

min = 550

lbf ft

s .

ForTin ft lbf andNin RPM we have:

N[RPM]

rad/s

30 RPM

T[ft lbf]

1 hp

550 lbf ft/s

=P[hp].

that is

P[hp] =N[RPM]T[ft lbf]

5252 .


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When the rig is operated at environments with nonstandard temperatures(85F) or at high altitudes, the mechanical horsepower requirements have to becorrected. The correction should follow the American Petroleum Institute (API)standard 7B-llC:

1. Deduction of 3% of the standard brake horsepower for each 1000 ft ofaltitude above mean sea level.

2. Deduction of 1% of the standard brake horsepower for each 10Frise orfall in temperature above or below 85F.

Example 1: A diesel engine gives an output torque of 1740 ft lbf at an enginespeed of 1200 RPM. If the fuel consumption rate was 31.5 gal/hr, what is theoutput power and the overall efficiency of the engine.

Solution:

The power delivered at the given regime is:

P =1200 RPM 1740 ft lbf

5252 = 397.5 hp

Diesel is consumed at 31.5 gal/hr. From Table 2.1 we have:

Q= 31.5gal

hr 7.2lbm

gal 19000 BTU

lbm = 4, 309, 200 BTU/hr

Converting to hp, results in:

Q= 4, 309, 200BTU

hr 778.17 lbf ft

BTU 1 hr

3600 s 1 hp

550 lbf ft/s= 1693.6 hp

The thermal efficiency is:

Et=P

Q = 397.5

1693.6= 23.5%

2.2 Hoisting System

The hoisting system is used to raise, lower, and suspend equipment in the well(e.g., drillstring, casing, etc). The hoisting equipment itself consists of: (SeeFigure 2.6.)

derrick (not shown),


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Figure 2.6: Typical hoisting system.

draw works,

fast line,

crown block,

traveling block,

dead line,

deal line anchor,

storage reel,

hook.

The drilling line (wire rope) is usually braided steel cable varying from 1 inchto13/4 inches in diameter. It is wound around a reel or drum in the drawworks.

Power (torque and rotation) is transmitted to the drawworks, allowing the drillingline in or out. The hoisting systems is composed by the derrick, the drawworks,and the block-tackle system.


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Figure 2.7: Stand of doubles along the mast.

2.2.1 The Derrick

The derrick or mast is a steel tower.1 The purpose of the derrick is to pro-vide height to raise and lower the drillstring (and also casing) out and into theborehole.

Derricks are rated by the API according to their height and their ability towithstand wind and compressive loads. API has published standards for theparticular specifications. The higher the derrick is, the longer stands it canhandle, which in turn reduces the tripping time. Derricks are designed to handletwo, three, or four joints.

The derrick stands above the derrick floor. The derrick floor is the stagewhere several surface drilling operations occur. At the derrick floor are located

the drawworks, the drillers console, the drillers house (or doghouse), therotary table, the drilling fluid manifold, and several other tools to operate thedrillstring. The space below the derrick floor is the substructure. The height ofthe substructure should be enough to accommodate the well control equipment.(See Figure 2.1.) At about 3/4 of the height of the derrick is located a platformcalled monkey board. This platform is used to operate the drillstring standsduring trip operations. During drillstring trips, the stands are kept stood in in themast, held by fingers in the derrick rack near the monkey board, as shown inFigure 2.7.

1If the tower is jacked up, it is called mast. If the tower is erected on the site, it is calledderrick.


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Figure 2.8: Onshore rig drawworks.

Figure 2.9: Brake belts and magnification linkage.

2.2.2 The Drawworks

The drawworks provides hoisting and braking power required to handle theheavy equipments in the borehole. It is is composed of a wire rope drum,mechanical and hydraulic brakes, the transmission, and the cathead (smallwinches operated by hand or remotely to provide hoisting and pulling powerto operate small loads and tools in the derrick area). Figure 2.8 shows a typicalonshore rig drawworks.

The reelingin of the drilling line is powered by an electric motor or Dieselengine, and the reelingout is powered by gravity. To control the reeling out,

mechanical brakes and auxiliary hydraulic or magnetic brakes are used, whichdissipates the energy required to reduce the speed and/or stop the downwardmovement of the suspended equipment. (See Figure 2.9.)


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Figure 2.10: Drawworks schematics.

The drawworks take power from Diesel engines or electrical motors, and anassembly of gears and clutches reduces the rotary speed to power the drumand the various catheads. A schematic of the internal mechanisms of a draw-

works is shown in Figure 2.10. As shown in the schematics, the drum surfacehas a helical groove to accommodate the drilling line without causing excessivestress and stain. This also helps the drilling line to lay neatly when reeled in.

2.2.3 The Block & Tackle

The drawworks, although very powerful, cannot provide the pull required toraise the heavy drillstring. The required pull is obtained with a system of pulleys.

The drilling line coming from the drawworks, called fast line, goes over apulley system mounted at the top of the derrick, called the crown block, anddown to another pulley system called the traveling block. The assembly ofcrown block, traveling block and drilling line is called block-tackle. The numberof linesnof a tackle is twice the number of (active) pulleys in the traveling block.The last line of the tackle is called dead lineand is anchored to the derrick floor,close to one of its legs. Below and connected to the traveling block is a hookto which drilling equipment can be hung. As the drilling line is reeled in or outof the drawworks, the traveling block rises and lowers along the derrick. Thisraises and lowers the equipment in the well. The block-tackle system provides

a mechanical advantageto the drawworks, and reduces the total load appliedto the derrick. We will be interested in calculating the fast line force Ff(providedby the drawworks) required to raise a weight Win the hook, and the total load


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Figure 2.11: Forces acting in the blocktackle.

applied to the rig and its distribution on the derrick floor.

2.2.3.1 Mechanical advantage and Efficiency

The mechanical advantageAMof the blocktackle is defined as the ratio of theloadW in the hook to the tensile force on the fast lineFf:

AM=W

Ff.

For an ideal, frictionless system, the tension in the drilling line is the samethroughout the system, so that W = n Ff. (See Figure 2.11.) Therefore, theideal mechanical advantage is equal to the number of lines strung through thetraveling block:

(AM)ideal = n .

In a real pulley, however, the tensile forces in the cable or rope in a pulleyare not identical. IfFiand Foare the input and output tensile forces of the ropein the pulley, the efficiency of a real pulley is given by the following ratio:

=FoFi

.

We will assume that all pulleys in the hoisting system have the same ef-ficiency, and we want to calculate the mechanical advantage of a real pulleysystem. IfFf is the force in the fast line, the force F1 in the line over the first

pulley (in the crown block) is given by

F1=Ff .


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The force in the line over the second pulley (in the traveling block) is

F2 = F1=2Ff .

Using the same reasoning over and over, the force in the ith line is

Fi=iFf .

The total loadWacting in the hook is equal to the sum of the forces in eachline of the traveling block. This means that the load W is given by

W =F1+ F2+ + Fn= (+ 2 + + n)Ff .

It can be easily shown that the expression between parenthesis can be writ-ten as

n+11 .

Therefore we have:

W = n+1

1 Ff .

Consequently, the real mechanical advantage is given by:

AM=W

Ff=

n+11 .

The overall efficiency Eof the system of pulleys is defined as the ratio ofthe real mechanical advantage to the ideal mechanical advantage:

E= AM

(AM)ideal=

n+1n(1 ) . (2.1)

If the efficiency of the pulleys is known, Blocktackle overall efficiency Ecan be calculated using Expression 2.1. A typical value for the efficiency ofballbearing pulleys is = 0.96. Table 2.2 shows the calculated and industryaverage overall efficiency for the usual number of lines.

Table 2.2: Blocktackle efficiency ($\eta=0.96$).n E Eave6 0.869 0.8748 0.836 0.841

10 0.804 0.81012 0.775 0.77016 0.746 0.740

Therefore, if Eis known, the fast line force Ffrequired to rise a load W is

given byFf=

W

nE (2.2)


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2.2.3.2 Hook Power

For an ideal blocktackle system, the input power (provided by the drawworks)

is equal to the output or hook power (available to move the borehole equip-ments). In this case, the power delivered by the drawworks is equal to the forcein the fast lineFftimes the velocity of the fast linevf, and the power developedat the hook is equal to the force in the hookWtimes the velocity of the travelingblockvb. That is

Pd = Ffvf=W vb= Ph .

Since for the ideal casen Ff=W, we have that

vb=vf

n ,

that is, the velocity of the block is n times slower than the velocity of the fastline, and this is valid also for the real case. Considering the Equation (2.2)

Ff= W

n E (2.3)

2.2

which represents the real relationship between the force in the fast line andthe weight in the hook, and multiplying both sides by vfwe obtain:

Ffvf=Pd=W vf

n E =W vb

E =Ph

E ,

Pd =Ph

E ,

which represents the real relationship between the power delivered by the draw-works and the power available in the hook, where Eis the overall efficiency ofthe blocktackle system.

Example 2: A rig must hoist a load of 300,000 lbf. The drawworks can pro-vide a maximum input power to the blocktackle system of as 500 hp. Eightlines are strung between the crown block and traveling block. Calculate (1) thetension in the fast line when upward motion is impending, (2) the maximumhook horsepower, (3) the maximum hoisting speed.

Solution:

UsingE= 0.841(average efficiency for n = 8) we have:

(1) Ff= W

n E =

300, 000 lbf

8

0.841 Ff= 44, 590 lbf

(2) Pd= 500 hp =Ph

E =

Ph0.841

Ph= 421 hp


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(3) Ph = 421 hp

550 lbf ft/s

1 hp

= 231, 550 lbf ft/s =W vb= 300, 000 lbf vb

vb=231, 550 lbf ft/s

300, 000 lbf vb= 0.772 ft/s = 46.3 ft/min

2.2.4 Load Applied to the Derrick

The total load applied to the derrick,FDis equal to the load in the hook plus theforce acting in the dead line plus the force acting in the fast line:

FD =W+ Ff+ Fd.

The worst scenario for the force in the fast line is that for the real case. FromSection 2.2.3.1 the force in the fast line is:

Ff= W

n E (2.4)

2.2

For the dead line, however, the worst scenario (largest force) is that of idealcase. In this case, the force in the dead line is:

Fd = Wn .

Therefore, the total load applied to the derrick is:

FD =W+ W

n E+

W

n =

(n+ 1)E+ 1

n E W .

The total load FD, however, is not evenly distributed over all legs of thederrick. In a conventional derrick, the drawworks is usually located betweentwo of the legs of the derrick. (See Figure 2.12.) The dead line, however must

be anchored close to one of the remaining two legs.2

From this configuration the load in each leg is:

Leg A : W

4 +

W

n =

n+ 4

4n W ,

Leg B : W

4 ,

Legs C and D : W

4 +

W

2nE =

nE+ 2

4nE W .

2The side of the derrick opposite to the drawworks is called Vgate. This area must be keptfree to allow pipe handling. Therefore, the dead line cannot be anchored between legs A andB.


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Figure 2.12: Derrick floor plan.

Evidently, the less loaded leg is leg B. We can determine under which con-ditions the load in leg A is greater then the load in legs C and D:

n+ 4

4n W >

nE+ 2

4nE W E >0.5.

Since the efficiency E is usually greater than 0.5, leg A will be the mostloaded leg, and very likely it will be the first to fail in the event of an excessiveload is applied to the hook. If a derrick is designed to support a maximumnominal load Lmax, each leg can support

Lmax4

. Therefore, the maximum hookload that the derrick can support for a given line arrangement is

Lmax4

=n+ 4

4n Wmax Wmax=

n

n+ 4Lmax.

The equivalent derrick load, FDE, is defined as four times the load in themost loaded leg. For the derrick configuration above, the equivalent derrick

load is

FDE=n+ 4

n W .

The equivalent derrick load (which depends on the number of lines) must beless than the nominal capacity of the derrick.

The derrick efficiency factor, ED is defined as the ratio of the total loadapplied to the derrick to the equivalent derrick load:

ED = FD

FDE=

(n+1)E+1n E

Wn+4

n W

=(n+ 1)E+ 1

(n+ 4)E

.


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Example 3: For the data of Example 2, calculate (1) the actual derrick load,(2) the equivalent derrick load, and (3) the derrick efficient factor.

Solution:

(1) The actual derrick load is given by

FD =(n+ 1)E+ 1

n E W=

(8 + 1) 0.841 + 18 0.841 300, 000 = 382, 000 lbf

(2) The equivalent derrick load is given by

FDE=n+ 4

n W =

8 + 4

8 300, 000 = 450, 000lbf

(3) The derrick efficiency factor is

ED = FDFDE

=382, 000

450, 000= 85%

2.3 Drilling Fluid Circulation System

The drilling fluid plays several functions in the drilling process. The most impor-tant are:

1. clean the rock fragments from beneath the bit and carry them to surface,

2. exert sufficient hydrostatic pressure against the formation to prevent for-mation fluids from flowing into the well,

3. maintain stability of the borehole walls,

4. cool and lubricate the drillstring and bit.

Drilling fluid is forced to circulate in the hole at various pressures and flow rates.

Drilling fluid is stored in steel tanks located beside the rig. Powerful pumpsforce the drilling fluid through surface high pressure connections to a set ofvalves called pump manifold, located at the derrick floor. From the manifold,the fluid goes up the rig within a pipe called standpipe to approximately 1/3 ofthe height of the mast. From there the drilling fluid flows through a flexible highpressure hose to the top of the drillstring. The flexible hose allows the fluid toflow continuously as the drillstring moves up and down during normal drillingoperations.

The fluid enters in the drillstring through a special piece of equipment calledswivel(Figure 2.13) located at the top of the kelly. The swivel permits rotating

the drillstring while the fluid is pumped through the drillstring.3 The drilling fluid

3See Section 2.4.1 for details.


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Figure 2.13: A swivel.

then flows down the rotating drillstring and jets out through nozzles in the drill bitat the bottom of the hole. The drilling fluid picks the rock cuttings generated bythe drill bit action on the formation. The drilling fluid then flows up the borehole

through the annular space between the rotating drillstring and borehole wall.At the top of the well (and above the tank level, the drilling fluid flows through

the flow lineto a series of screens called the shale shaker. The shale shakeris designed to separate the cuttings from the drilling mud. Other devices arealso used to clean the drilling fluid before it flows back into the drilling fluid pits.Figure 2.14 depicts the process described above.

The principal components of the mud circulation system are:

1. pits or tanks,

2. pumps,

3. flow line,

4. solids and contaminants removal equipment,

5. treatment and mixing equipment,

6. surface piping and valves,

7. the drillstring.

The tanks (3 or 4 settling tank, mixing tank(s), suction tank) are made ofsteel sheet. They contain a safe excess (neither to big nor to small) of the


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Figure 2.14: Rig circulation system.

total volume of the borehole. In the case of loss of circulation, this excess willprovide the well with drilling fluid while the corrective measures are taken. Thenumber of active tanks depends on the current depth of the hole (bypassesallow to isolate one or more tanks.) The tanks will allow enough retaining timeso that much of the solids brought from the hole can be removed from the fluid.

2.3.1 Mud Pumps

The great majority of the pumps used in drilling operations are reciprocat-ing positive displacement pumps (PDP). Advantages of the reciprocating PDPwhen compared to centrifugal pumps are:

ability to pump fluids with high abrasive solids contents and with largesolid particles,

easy to operate and maintain,

sturdy and reliable,

ability to operate in a wide range of pressure and flow rate.


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Centrifugal pumps are very sensitive to abrasive solid contents mud, and donot offer a wide range of operation compared to PDP.

PDP are composed of two major parts, namely:

Power end: receives power from engines and transform the rotating movementinto reciprocating movement.

Fluid end: converts the reciprocating power into pressure and flow rate.

The efficiencyEmof the power end, that is the efficiency with which rotating me-chanical power is transformed in reciprocating mechanical power is of the orderof 90%. The efficiencyEv of the fluid end (also called volumetric efficiency),that is, the efficiency that the reciprocating mechanical power is transformed

into hydraulic power, can be as high as 100%.

Rigs normally have two or three PDPs. During drilling of shallow portions ofthe hole, when the diameter is large, the two PDPs are connected in parallel toprovide the highest flow rate necessary to clean the borehole. As the boreholedeepens, less flow rate and higher pressure are required. In this case, normallyonly one PDP is used while the other is in standby or in preventive maintenance.The great flexibility in the pressure and flow rate is obtained with the possibilityof changing the diameters of the pair pistonliner. The flow rate depends onthe following parameters:

stroke lengthLS(normally fixed),

liner diameterdL,

rod diameterdR(for duplex PDP only),

pump speedN(normally given in strokes/minute),

volumetric efficiencyEVof the pump.

In addition, thepump factor Fp is defined as the total volume displaced by thepump in one stroke.

There are two types of PDP: double-action duplex pump, and single-actiontriplex pump. Triplex PDPs, due to several advantages, (less bulky, less pres-sure fluctuation, cheaper to buy and to maintain, etc,) has taking place of theduplex PDPs in both onshore and offshore rigs.

2.3.1.1 Duplex PDP

The duplex mud pump consists of two doubleaction cylinders (see Figure 2.16-a). This means that drilling mud is pumped with the forward and backwardmovement of the barrel.


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(a) Piston scheme (double action). (b) A duplex unit.

Figure 2.15: Duplex pumps.

(a) Piston scheme (single action). (b) A Triplex unit.

Figure 2.16: Triplex pumps.

For a duplex pump (2 doubleaction cylinders) the pump factor is given by:

Fp=

2

2d2L d2R

LSEV .

A typical duplex pump is shown in Figure 2.16-b.

2.3.1.2 Triplex PDP

The triplex mud pump consists of three singleaction cylinders (see Figure ??-a). This means that drilling mud is pumped only in the forward movement of the

barrel.

For a triplex pump the pump factor is given by:

Fp=3

4d2LLSEV .

A typical triplex pump is shown in Figure ??-b.

2.3.1.3 Pump Flow Rate

For both types of PDP, the flow rate is calculated from:

q= N Fp .


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ForNin strokes per minute (spm), dL,dR, andLSin inches,Fpin in3, andq

in gallons per minute (gpm) we have:

q=

1

231 N Fp .

Note that in this particular formulation, the volumetric efficiency of the pump isincluded in the pump factor.

2.3.1.4 Pump Power

Pumps convert mechanical power into hydraulic power. From the definition ofpower we can write:

P=F v .

In its motion, the piston exerts a force on the fluid that is equal to the pressuredifferential in the piston ptimes the area A of the piston, and the velocityv isequal to the flow rateqdivided by the areaA, that is

PH= (p A) q

A= p q . (2.5)

ForPHin hp,pin psi, and qin gpm we have:

PH= p q

1714.29. (2.6)

Example 4: Compute the pump factor in gallons per stroke and in barrels perstroke for a triplex pump having 5.5 in liners and 16 in stroke length, with avolumetric efficiency of 90%. At N = 76spm, the pressure differential betweenthe input and the output of the pump is 2400 psi. Calculate the hydraulic powertransferred to the fluid, and the required mechanical power of the pump if Emis78%.

Solution:

The pump factor (triplex pump) in in3 per stroke is:

Fp=3

4 5.52 16 90% = 1026 in3

Converting to gallons per stroke and to barrels per stroke gives:

Fp= 10261

231= 4.44gps = 4.44 1

42= 0.1058bps

The flow rate atN= 76spm is:

q=N Fp= 78spm 4.44gps = 337.44gpm


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The hydraulic power transferred to the fluid is:

PH= 2400psi 334.44gpm

1714.29 = 468hp

To calculate the mechanical power required by the pump we must considerthe efficiencies:

P= 468hp 190%

178%

= 667hp

2.3.1.5 Surge Dampeners

Due to the reciprocating action of the PDPs, the output flow rate of the pumppresents a pulsation (caused by the changing speed of the pistons as theymove along the liners). This pulsation is detrimental to the surface and down-hole equipment (particularly with MWD pulse telemetry system). To decreasethe pulsation,surge dampenersare used at the output of each pump. A flexiblediaphragm creates a chamber filled with nitrogen at high pressure. The fluctu-ation of pressure is compensated by a change in the volume of the chamber.The schematic of a typical surge dampener is shown in Figure 2.17.

A relief valve located in the pump discharge line prevents line rupture incase the pump is started against a closed valve.

Figure 2.17: Surge dampener.


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2.3.2 Solids Control Equipment

The purpose of the solids control equipment is to reduce to a minimum the

amount of inert solids and gases in the drilling fluid. They are:

1. Shale shakers,

2. Degassers,

3. Desanders (hydrocyclones),

4. Desilters (hydrocyclones),

5. Centrifuges,

6. Mud cleaners.

Figure 2.18 shows a sketch of a typical solids control system (for unweightedfluid). Fine particles of inactive solids are continuously added to the fluid dur-ing drilling. These solids increase the density of the fluid and also the frictionpressure drop, but do not contribute to the carrying capacity of the fluid. Theamount of inert solids must be kept as low as possible.

Figure 2.18: Solids control system.


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Figure 2.19: Shale shaker configurations.

Figure 2.20: A twoscreen shale shaker.

2.3.2.1 Shale Shakers

The shale shaker removes the coarse solids (cuttings) generated during drilling.It is located at the end of the flow line. It constitutes of one or more vibratingscreens in the range of 10 to 150 mesh over which the mud passes before it is

fed to the mud pits. (See Figure 2.19.)The screens are vibrated by eccentric heavy cylinders connected to electric

motors. The vibration promotes an efficient separation without loss of fluid.Figure 2.20 shows a typical twoscreen shale shaker.

2.3.2.2 Degassers

Gases that might enter the fluid must also be removed. Even when the fluid isoverbalanced, the gas contained in the rock cut by the bit will enter the fluid and

must be removed. The degasser removes gas from the gas cut fluid by creatinga vacuum in a vacuum chamber. The fluid flows down an inclined flat surfaceas a thin layer. The vacuum enlarges and coalesce the bubbles. Degassed


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Figure 2.21: A vacuum chamber degasser.

fluid is draw from chamber by a fluid jet located at the discharge line. A typicaldegasser diagram is shown in Figure 2.21.

2.3.2.3 Hydrocyclones (Desanders and Desilters)

Hydrocyclones are simple devices with no internal moving parts. The drillingfluid enters the device through a tangential opening in the cylindrical section,impelled by a centrifugal pump. The centrifugal force generated by the whirlingmotion pushes the solid particles towards the internal wall of the inverted cone.As the whirling flux moves downwards the rotating speed increased and thediameters decreases. The fluid free of solid particles is squeezed out of theflow and swirls upwards in a vortex motion, leaving the hydrocyclone from theupper exit. The solids leave the hydrocyclone from the apex of the cone (under-flow). For maximum efficiency, the discharge from the apex exit of hydrocycloneshould be in a spray in the shape of a hollow cone rather than a rope shape.

Figure 2.22 shows the fluid/solids paths in a hydrocyclone.

Hydrocyclones are classified according to the size of the particles removedas desanders (cut point in the 4045m size range) or desilters (cut point inthe 1020m size range). At the cut point of a hydrocyclone 50% of the parti-cles of that size is discarded. The desander is a set of two or three 8in or 10inhydrocyclones, and are positioned after the shale shaker and the degasser (ifused). The desilter is a set of eight to twelve 4in or 5in hydrocyclones. It re-moves particles that can not be removed by the desander. Figures 2.23 showsa desander (a), and a desilter (b). Note the size and number of hydrocyclonesin each case.

A typical drilling solid particle distribution and particle size range classifica-tion are shown in the diagram in Figure 2.24.


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Figure 2.22: Flow path in a hydrocyclone.

(a) Desander. (b) Desilter.

Figure 2.23: Solid control equipment.


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Figure 2.24: Particle size classification.

2.3.2.4 Centrifuges

The centrifuge is a solids control equipment which separates particles evensmaller, which can not be removed by the hydrocyclones. It consists of a rotat-ing coneshape drum, with a screw conveyor. (See Figure 2.25.) Drilling fluid isfed through the hollow conveyor. The drum rotates at a high speed and createsa centrifugal force that causes the heavier solids to decant. The screw rotatesin the same direction of the drum but at a slight slower speed, pushing the solidstoward the discharge line. The colloidal suspension exits the drum through theoverflow ports. The drums are enclosed in an external, nonrotating casing notshown in the figure.

2.3.2.5 Mud Cleaners

Inert solids in weighted fluid (drilling fluid with weight material like barite, ironoxide, etc) can not be treated with hydrocyclones alone because the particlesizes of the weighting material are within the operational range of desandersand desilters. 4 This is shown in the diagram in Figure 2.24, which includes theparticle size distribution of typical industrial barite used in drilling fluids.

Amud cleaner is a desilter unit in which the underflow is further processedby a fine vibrating screen, mounted directly under the cones. The mud cleaner

separates the low density inert solids (undesirable) from the high density weight-

4Weighting material are relatively expensive additives, which must be saved.


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Figure 2.25: Internal view of a centrifuge.

ing particles. (See Figure 2.26-a.)

Hydrocyclones discriminate light particles from heavy particles. Bentoniteare lighter than formation solids because they are of colloidal size (although ofthe same density). Barite particles are smaller than formation solids becausethey are denser.

The desilter removes the barite and the formation solids particles in the un-derflow, leaving only a clean mud with bentonite particles in a colloidal suspen-

sion in the overflow. The thick slurry in the underflow goes to the fine screen,which separate the large (low density) particles (formation solids) from the small(high density) barite particles, thus conserving weighting agent and the liquidphase but at the same time returning many fine solids to the active system.The thick barite rich slurry is treated with dilution and mixed with the clean mud(colloidal bentonite). The resulting mud is treated to the right density and vis-cosity and recirculates in the hole. A diagram of a mud cleaner is shown inFigure 2.26-b.

Mud cleaners are used mainly with oil and syntheticbase fluids where theliquid discharge from the cone cannot be discharged, either for environmental

or economic reasons. It may also be used with weighted waterbase fluids toconserve barite and the liquid phase.

2.3.3 Treatment and Mixing Equipment

Drilling fluid is usually a suspension of clay (sodium bentonite) in water. Higherdensity fluids can be obtained by adding finely granulated (fine sand to silt size

see Figure 2.24) barite (BaSO4). Various chemicals or additives are also

used in different situations. The drilling fluid continuous phase is usually water(freshwater or brine) called waterbase fluids. When the continuous phase isoil (emulsion of water in oil) it is called oilbase fluid. The basic drilling fluids


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(a) Unit of a mud cleaner (b) Principle of the mud cleaner.

Figure 2.26: Mud cleaner.

(a)

Figure 2.27: Mud agitator.

physical properties are density, viscosity, and filtrate. Fresh water density is

8.37 pounds per gallon (ppg). Bentonite adds viscosity to the fluids and alsoincreases the density to about 9 to 10 ppg. Higher density (15 to 20 ppg) isobtained with barite, iron oxide, or any other dense fine ground material.

Water base fluids are normally made at the rig site (oil base mud and syn-thetic fluids are normally manufactured in a drilling fluid plant). Special treat-ment and mixing equipment exists for this purpose. Tank agitators, mud guns,mixing hoppers, and other equipment are used for these purposes.

Tank agitators or blenders (Figure 2.27-a) are located in the mud tanks tohomogenize the fluid in the tank. They help to keep the various suspendedmaterial homogeneously distributed in the tank by forcing toroidal and whirl

motions of the fluid in the tank. (See Figure 2.27-b.)

Mud guns are mounted in gimbals at the side of the tanks, which allow aim-


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Figure 2.28: Mud gun.

(a) (b)

Figure 2.29: Mud hopper.

ing a mud jet to any point in the tank. They help to homogenize the propertiesof two tanks, and spread liquid additives in a large area of the tank (from apre-mixed tank). (See Figure 2.28.) Centrifugal pumps power the mud guns.

The mixing hopper (see Figure 2.29) allows adding powder substances and

additives in the mud system. The hopper is connected to a Venturi pipe. Mudis circulated by centrifugal pumps and passes in the Venturi at high speed,sucking the substance into the system.


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2.4 The Rotary System

The rotary system is the set of equipments necessary to promote the rotation

of the bit. The bit must be mechanically and hydraulically connected to the rig.This connection is made by the drillstring. The purpose of the drillstring is totransmit axial force, torque, and drilling fluid (hydraulic power) to the bit. Thebasic drillstring is composed of the following components:

Swivel,

Kelly and accessories,

Rotary table and components,

Drillstring tubulars (drill pipe, drill collars, etc.),

Drill bit.

Several other components and equipment can be connected to the drillstring toperform several tasks and to lend to the drillstring special features.

2.4.1 Swivel

The swivel is suspended by the hook of the traveling block and allows the drill-string to rotate as drilli

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